Cost and Performance of PC and IGCC Plants 

for a Range of Carbon Dioxide Capture 

May 27, 2011

DOE/NETL-2011/1498
Carbon Dioxide Capture Sensitivity Analysis

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.
Carbon Dioxide Capture Sensitivity Analysis

Cost and Performance of PC and IGCC Plants for a 

Range of Carbon Dioxide Capture

DOE/NETL-2011/1498

May 27, 2011

NETL Contact:

Kristin Gerdes

Office of Program, Planning and Analysis

Prepared by:

Research and Development Solutions, LLC (RDS)

James B. Black, formerly of Parsons Corporation

John L. Haslbeck, formerly of Parsons Corporation

Andrew P. Jones, formerly of Science Applications International Corporation

Wayne L. Lundberg, formerly of Science Applications International Corporation

Vasant Shah, formerly of Parsons Corporation

Updated by:

Energy Sector Planning and Analysis (ESPA)

Allison Kyle, Booz Allen Hamilton

Eric Lewis, Booz Allen Hamilton

National Energy Technology Laboratory

www.netl.doe.gov
Carbon Dioxide Capture Sensitivity Analysis

Acknowledgments

This report was initially prepared by Research and Development Solutions, LLC (RDS) for the United 

States Department of Energy (DOE) National Energy Technology Laboratory (NETL). The report was 

updated by the Energy Sector Planning and Analysis (ESPA) for DOE NETL. This work was completed 

under DOE NETL Contract Number DE-FE0004001. This work was performed under ESPA Task 410.01.

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

staff, particularly:

Eric Grol, NETL Technical Monitor
Carbon Dioxide Capture Sensitivity Analysis

i

Table of Contents

TABLE OF CONTENTS ..............................................................................................................I

LIST OF EXHIBITS ..................................................................................................................III

LIST OF ACRONYMS AND ABBREVIATIONS....................................................................X

EXECUTIVE SUMMARY ...........................................................................................................1

PULVERIZED COAL PLANTS ..........................................................................................................1

IGCC PLANTS...............................................................................................................................3

RESULTS .......................................................................................................................................6

Performance ........................................................................................................................................................ 6

Economics............................................................................................................................................................ 8

Cost and Performance Summary ....................................................................................................................... 14

1. INTRODUCTION................................................................................................................19

1.1 STUDY BACKGROUND.....................................................................................................19

1.2 PROJECT OBJECTIVES......................................................................................................19

2. GENERAL EVALUATION BASIS...................................................................................21

2.1 SITE CHARACTERISTICS ..................................................................................................25

2.2 COAL CHARACTERISTICS AND COST...............................................................................27

2.3 DESIGN SORBENT COMPOSITION.....................................................................................31

2.4 ENVIRONMENTAL TARGETS ............................................................................................31

2.4.1 Supercritical PC Plant ........................................................................................................................ 32

2.4.2 GEE IGCC Plant................................................................................................................................. 33

2.4.3 Carbon Dioxide................................................................................................................................... 33

2.5 CAPACITY FACTOR .........................................................................................................34

2.6 RAW WATER WITHDRAWAL...........................................................................................35

2.7 COST ESTIMATING METHODOLOGY ................................................................................35

2.7.1 Capital Costs....................................................................................................................................... 35

2.7.2 System Code-of-Accounts.................................................................................................................... 37

2.7.3 CO2 Removal Plant Maturity .............................................................................................................. 37

2.7.4 Contracting Strategy ........................................................................................................................... 38

2.7.5 Estimate Scope .................................................................................................................................... 38

2.7.6 Capital Cost Assumptions ................................................................................................................... 38

2.7.7 Operations and Maintenance Costs .................................................................................................... 45

2.7.8 CO2 Transport, Storage and Monitoring............................................................................................. 46

2.7.9 Finance Structure, Discounted Cash Flow Analysis, and COE .......................................................... 50

2.8 IGCC STUDY COST ESTIMATES COMPARED TO INDUSTRY ESTIMATES ..........................54

3. CASE 1 - SUPERCRITICAL PC WITH VARIABLE CO2 CAPTURE........................57

3.1 SYSTEM DESCRIPTIONS...................................................................................................57

3.1.1 Coal and Sorbent Receiving and Storage............................................................................................ 57

3.1.2 Steam Generator and Ancillaries........................................................................................................ 57

3.1.3 NOx Control System............................................................................................................................. 60

3.1.4 Particulate Control ............................................................................................................................. 60

3.1.5 Flue Gas Desulfurization .................................................................................................................... 61

3.1.6 Flue Gas System/Stack ........................................................................................................................ 65

3.1.7 Carbon Dioxide Recovery Facility...................................................................................................... 65

3.1.8 Steam Turbine Generator System........................................................................................................ 69

3.1.9 Balance of Plant.................................................................................................................................. 70

3.1.10 Accessory Electric Plant ..................................................................................................................... 74

3.1.11 Instrumentation and Control............................................................................................................... 74

3.2 SUPERCRITICAL PC CO2 CAPTURE SENSITIVITY.............................................................74

3.2.1 CO2 Capture with Partial Bypass Performance Results ..................................................................... 77

3.2.2 Full CO2 Capture Performance Results............................................................................................ 117

3.2.3 Economic Analysis for the Supercritical PC Cases........................................................................... 151
Carbon Dioxide Capture Sensitivity Analysis

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3.2.4 Capital and Operating Cost Results.................................................................................................. 151

3.2.5 Supercritical PC Cost and Performance Summary........................................................................... 187

4. CASE 2 – GEE IGCC WITH VARIABLE CO2 CAPTURE.........................................189

4.1 GASIFIER BACKGROUND...............................................................................................190

4.2 PROCESS DESCRIPTION .................................................................................................192

4.2.1 Coal Receiving and Storage .............................................................................................................. 192

4.2.2 Coal Grinding and Slurry Preparation ............................................................................................. 192

4.2.3 Air Separation Unit (ASU) Choice and Integration .......................................................................... 193

4.2.4 Gasification....................................................................................................................................... 197

4.2.5 Raw Gas Cooling/Particulate Removal ............................................................................................ 197

4.2.6 Syngas Scrubber/Sour Water Stripper............................................................................................... 198

4.2.7 Water Gas Shift Reactors.................................................................................................................. 198

4.2.8 Mercury Removal.............................................................................................................................. 199

4.2.9 Acid Gas Removal (AGR) Process Selection..................................................................................... 200

4.2.10 CO2 Compression and Dehydration.................................................................................................. 208

4.2.11 Sulfur Recovery/Tail Gas Cleanup Process Selection....................................................................... 208

4.2.12 Slag Handling.................................................................................................................................... 211

4.2.13 Power Island ..................................................................................................................................... 212

4.2.14 Steam Generation Island................................................................................................................... 218

4.2.15 Accessory Electric Plant ................................................................................................................... 221

4.2.16 Instrumentation and Control............................................................................................................. 222

4.3 GEE IGCC CO2 CAPTURE SENSITIVITY .......................................................................222

4.3.1 IGCC Design 1 – Without Water Gas Shift....................................................................................... 224

4.3.2 IGCC Design 2 – Single Water Gas Shift Reactor............................................................................ 257

4.3.3 IGCC Design 3 – Two Water Gas Shift Reactors with Bypass.......................................................... 303

4.3.4 IGCC Design 4 – Two Water Gas Shift Reactors Without Bypass.................................................... 357

4.3.5 Economic Analysis for the GEE IGCC Cases................................................................................... 395

4.3.6 Capital and Operating Cost Results.................................................................................................. 395

4.3.7 GEE IGCC Cost and Performance Summary ................................................................................... 467

5. RESULTS ...........................................................................................................................469

5.2 PERFORMANCE..............................................................................................................469

5.2.1 Energy Efficiency .............................................................................................................................. 469

5.3 ECONOMICS ..................................................................................................................471

5.3.1 Total Overnight Cost......................................................................................................................... 471

5.3.2 Cost of Electricity.............................................................................................................................. 473

5.3.3 CO2 Avoided Costs............................................................................................................................ 476

5.4 COST AND PERFORMANCE SUMMARY...........................................................................478

5.4.1 Supercritical PC Cases ..................................................................................................................... 478

5.4.2 GEE IGCC Cases.............................................................................................................................. 479

5.4.3 SCPC and IGCC Comparisons ......................................................................................................... 479

APPENDIX A.............................................................................................................................483

Supercritical PC Cost Algorithms ................................................................................................................... 484

GEE IGCC Cost Algorithms............................................................................................................................ 489

6. REFERENCES...................................................................................................................495
Carbon Dioxide Capture Sensitivity Analysis

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List of Exhibits

Exhibit ES-1 Case 1 Supercritical PC Plant Configuration Summary .......................................................... 2

Exhibit ES-2 Case 2 GEE IGCC Plant Configuration Summary .................................................................. 4

Exhibit ES-3 Net Efficiency and Cost as a Function of WGS Bypass Ratio for 60% CO2 Removal with 

IGCC Design 3........................................................................................................................................ 5

Exhibit ES-4 Process Configurations for IGCC D2 ...................................................................................... 5

Exhibit ES-5 Process Configurations for IGCC D3 ...................................................................................... 6

Exhibit ES-6 Supercritical PC Net Plant Efficiency (HHV) ......................................................................... 7

Exhibit ES-7 IGCC Net Plant Efficiency (HHV).......................................................................................... 8

Exhibit ES-8 Supercritical PC Total Overnight Cost .................................................................................... 9

Exhibit ES-9 IGCC Total Overnight Cost ................................................................................................... 10

Exhibit ES-10 Supercritical PC Cost of Electricity..................................................................................... 11

Exhibit ES-11 IGCC Cost of Electricity...................................................................................................... 12

Exhibit ES-12 Supercritical PC CO2 Avoided Costs................................................................................... 13

Exhibit ES-13 IGCC CO2 Avoided Costs.................................................................................................... 14

Exhibit ES-14 Cost and Performance Results for the Supercritical PC Cases............................................ 16

Exhibit ES-15 Cost and Performance Results for the GEE IGCC Cases.................................................... 17

Exhibit 2-1 Case 1 Supercritical PC Plant Configuration Summary........................................................... 21

Exhibit 2-2 Case 2 GEE IGCC Plant Configuration Summary................................................................... 23

Exhibit 2-3 Net Efficiency and Cost as a Function of WGS Bypass Ratio for 60% CO2 Removal with 

IGCC Design 3...................................................................................................................................... 24

Exhibit 2-4 Process Configurations for IGCC D2 ....................................................................................... 24

Exhibit 2-5 Process Configurations for IGCC D3 ....................................................................................... 25

Exhibit 2-6 Site Ambient Conditions........................................................................................................... 26

Exhibit 2-7 Site Characteristics ................................................................................................................... 26

Exhibit 2-8 Design Coal .............................................................................................................................. 27

Exhibit 2-9 Probability Distribution of Mercury Concentration in the Illinois No. 6 Coal......................... 30

Exhibit 2-10 Sorbent Analysis..................................................................................................................... 31

Exhibit 2-11 Standards of Performance for Electric Utility Steam Generating Units................................. 32

Exhibit 2-12 Environmental Targets for PC Cases...................................................................................... 33

Exhibit 2-13 Environmental Targets for IGCC Cases................................................................................. 33

Exhibit 2-14 Capital Cost Levels and their Elements.................................................................................. 36

Exhibit 2-15 Features of an AACE Class 4 Cost Estimate.......................................................................... 37

Exhibit 2-16 AACE Guidelines for Process Contingency........................................................................... 41

Exhibit 2-17 TASC/TOC Factors................................................................................................................. 42

Exhibit 2-18 Owner‟s Costs Included in TOC............................................................................................. 43

Exhibit 2-19 CO2 Pipeline Specification ..................................................................................................... 47

Exhibit 2-20 Deep, Saline Aquifer Specification ........................................................................................ 48

Exhibit 2-21 Global Economic Assumptions .............................................................................................. 51

Exhibit 2-22 Financial Structure for Investor Owned Utility High Risk Projects....................................... 52

Exhibit 2-23 Capital Charge Factors for COE Equation ............................................................................. 53

Exhibit 3-1 Typical B&W Wet FGD Process Flow Diagram ..................................................................... 62

Exhibit 3-2 Wet Scrubber Arrangement ...................................................................................................... 63

Exhibit 3-3 Fluor Econamine FG PlusSM Typical Flow Diagram ............................................................... 67

Exhibit 3-4 CO2 Compressor Interstage Pressures ...................................................................................... 69

Exhibit 3-5 Supercritical PC Combustion Configuration Modeling Assumptions...................................... 76

Exhibit 3-6 Cases 1A Through 1D Process Block Flow Diagram, Supercritical PC with CO2 Capture 

Bypass................................................................................................................................................... 78
Carbon Dioxide Capture Sensitivity Analysis

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Exhibit 3-7 Case 1A Stream Table, Supercritical PC with 30% CO2 Capture............................................ 79

Exhibit 3-8 Case 1B Stream Table, Supercritical PC with 50% CO2 Capture ............................................ 81

Exhibit 3-9 Case 1C Stream Table, Supercritical PC with 70% CO2 Capture ............................................ 83

Exhibit 3-10 Case 1D Stream Table, Supercritical PC with 85% CO2 Capture.......................................... 85

Exhibit 3-11 Cases 1A Through 1D Performance Modeling Results.......................................................... 87

Exhibit 3-12 Cases 1A through 1D Estimated Air Emission Rates............................................................. 90

Exhibit 3-13 Cases 1A through 1D Carbon Balance ................................................................................... 91

Exhibit 3-14 Cases 1A through 1D Sulfur Balance..................................................................................... 91

Exhibit 3-15 Case 1A (30%) Water Balance ............................................................................................... 92

Exhibit 3-16 Case 1B (50%) Water Balance ............................................................................................... 92

Exhibit 3-17 Case 1C (70%) Water Balance ............................................................................................... 93

Exhibit 3-18 Case 1D (85%) Water Balance ............................................................................................... 93

Exhibit 3-19 Case 1A (30%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems95

Exhibit 3-20 Case 1A (30%) Heat and Mass Balance, Power Block Systems............................................ 96

Exhibit 3-21 Case 1B (50%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems 97

Exhibit 3-22 Case 1B (50%) Heat and Mass Balance, Power Block Systems............................................ 98

Exhibit 3-23 Case 1C (70%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems 99

Exhibit 3-24 Case 1C (70%) Heat and Mass Balance, Power Block Systems.......................................... 100

Exhibit 3-25 Case 1D (85%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

............................................................................................................................................................. 101

Exhibit 3-26 Case 1D (85%) Heat and Mass Balance, Power Block Systems.......................................... 102

Exhibit 3-27 Case 1A (30%) Energy Balance ........................................................................................... 103

Exhibit 3-28 Case 1B (50%) Energy Balance ........................................................................................... 104

Exhibit 3-29 Case 1C (70%) Energy Balance ........................................................................................... 105

Exhibit 3-30 Case 1D (85%) Energy Balance ........................................................................................... 106

Exhibit 3-31 Case 1A Energy Balance Sankey Diagram .......................................................................... 107

Exhibit 3-32 Case 1B Energy Balance Sankey Diagram........................................................................... 107

Exhibit 3-33 Case 1C Energy Balance Sankey Diagram........................................................................... 108

Exhibit 3-34 Case 1D Energy Balance Sankey Diagram .......................................................................... 108

Exhibit 3-35 Cases 1E through 1G Process Block Flow Diagram, Supercritical PC with CO2 Capture .. 118

Exhibit 3-36 Case 1E Stream Table, Supercritical PC with 90% CO2 Capture ........................................ 119

Exhibit 3-37 Case 1F Stream Table, Supercritical PC with 95% CO2 Capture......................................... 121

Exhibit 3-38 Case 1G Stream Table, Supercritical PC with 99% CO2 Capture........................................ 123

Exhibit 3-39 Cases 1E through 1G Performance Modeling Results ......................................................... 125

Exhibit 3-40 Cases 1E through 1G Estimated Air Emission Rates........................................................... 128

Exhibit 3-41 Cases 1E through 1G Carbon Balance.................................................................................. 129

Exhibit 3-42 Cases 1E through 1G Sulfur Balance ................................................................................... 129

Exhibit 3-43 Case 1E (90%) Water Balance ............................................................................................. 130

Exhibit 3-44 Case 1F (95%) Water Balance.............................................................................................. 130

Exhibit 3-45 Case 1G (99%) Water Balance ............................................................................................. 131

Exhibit 3-46 Case 1E (90%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

............................................................................................................................................................. 133

Exhibit 3-47 Case 1E (90%) Heat and Mass Balance, Power Block Systems .......................................... 134

Exhibit 3-48 Case 1F (95%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

............................................................................................................................................................. 135

Exhibit 3-49 Case 1F (95%) Heat and Mass Balance, Power Block Systems........................................... 136

Exhibit 3-50 Case 1G (99%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

............................................................................................................................................................. 137
Carbon Dioxide Capture Sensitivity Analysis

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Exhibit 3-51 Case 1G (99%) Heat and Mass Balance, Power Block Systems.......................................... 138

Exhibit 3-52 Case 1E (90%) Energy Balance............................................................................................ 139

Exhibit 3-53 Case 1F (95%) Energy Balance ............................................................................................ 140

Exhibit 3-54 Case 1G (99%) Energy Balance ........................................................................................... 141

Exhibit 3-55 Case 1E Energy Balance Sankey Diagram........................................................................... 142

Exhibit 3-56 Case 1F Energy Balance Sankey Diagram ........................................................................... 142

Exhibit 3-57 Case 1G Energy Balance Sankey Diagram .......................................................................... 143

Exhibit 3-58 Case 1A (30%) Capital Costs............................................................................................... 152

Exhibit 3-59 Case 1A Initial and Annual O&M Expenses........................................................................ 156

Exhibit 3-60 Case 1B (50%) Capital Costs ............................................................................................... 157

Exhibit 3-61 Case 1B Initial and Annual O&M Expenses........................................................................ 161

Exhibit 3-62 Case 1C (70%) Capital Costs ............................................................................................... 162

Exhibit 3-63 Case 1C Initial and Annual O&M Expenses........................................................................ 166

Exhibit 3-64 Case 1D (85%) Capital Costs............................................................................................... 167

Exhibit 3-65 Case 1D Initial and Annual O&M Expenses........................................................................ 171

Exhibit 3-66 Case 1E (90%) Capital Costs................................................................................................ 172

Exhibit 3-67 Case 1E Initial and Annual O&M Expenses ........................................................................ 176

Exhibit 3-68 Case 1F (95%) Capital Costs................................................................................................ 177

Exhibit 3-69 Case 1F Initial and Annual O&M Expenses......................................................................... 181

Exhibit 3-70 Case 1G (99%) Capital Costs............................................................................................... 182

Exhibit 3-71 Case 1G Initial and Annual O&M Expenses........................................................................ 186

Exhibit 3-72 Cost and Performance Results for the Supercritical PC Cases............................................. 187

Exhibit 4-1 Typical ASU Process Schematic ............................................................................................ 196

Exhibit 4-2 Flow Diagram for a Conventional AGR Unit......................................................................... 201

Exhibit 4-3 Common Chemical Reagents Used in AGR Processes.......................................................... 202

Exhibit 4-4 Physical Solvent AGR Process Simplified Flow Diagram..................................................... 204

Exhibit 4-5 Common Physical Solvents Used in AGR Processes............................................................. 204

Exhibit 4-6 Common Mixed Solvents Used in AGR Processes................................................................ 205

Exhibit 4-7 Equilibrium Solubility Data on H2S and CO2 in Various Solvents........................................ 206

Exhibit 4-8 Generic Two-Stage SelexolTM Process Flow Diagram............................................................ 208

Exhibit 4-9 Typical Three-Stage Claus Sulfur Plant ................................................................................. 210

Exhibit 4-10 Advanced F Class Combustion Turbine Performance Characteristics Using Natural Gas.. 213

Exhibit 4-11 Combustion Turbine Typical Scope of Supply .................................................................... 213

Exhibit 4-12 Typical Fuel Specification for F-Class Machines ................................................................ 216

Exhibit 4-13 Allowable Gas Fuel Contaminant Level for F-Class Machines........................................... 217

Exhibit 4-14 Case 2 GEE IGCC Plant Configuration Summary............................................................... 224

Exhibit 4-15 Case 2 D1A Process Block Flow Diagram, IGCC without WGS (0% CO2 Removal)........ 226

Exhibit 4-16 Case 2 D1A Stream Table, IGCC without CO2 Capture ...................................................... 227

Exhibit 4-17 Case 2 D1B Process Block Flow Diagram, IGCC without WGS (25% CO2 Removal)...... 229

Exhibit 4-18 Case 2 D1B Stream Table, IGCC with 25% CO2 Capture ................................................... 230

Exhibit 4-19 Case 2 D1 Performance Modeling Results........................................................................... 232

Exhibit 4-20 Case 2 D1 Estimated Air Emission Rates............................................................................. 234

Exhibit 4-21 Case 2 D1 Carbon Balance ................................................................................................... 235

Exhibit 4-22 Case 2 D1 Sulfur Balance..................................................................................................... 235

Exhibit 4-23 Case 2 D1A (0%) Water Balance ......................................................................................... 236

Exhibit 4-24 Case 2 D1B (25%) Water Balance ....................................................................................... 237

Exhibit 4-25 Case 2 D1A (0%) Heat and Mass Balance, GEE Gasifier and ASU.................................... 239

Exhibit 4-26 Case 2 D1A (0%) Heat and Mass Balance, Syngas Cleanup ............................................... 240
Carbon Dioxide Capture Sensitivity Analysis

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Exhibit 4-27 Case 2 D1A (0%) Heat and Mass Balance, Power Block .................................................... 241

Exhibit 4-28 Case 2 D1B (25%) Heat and Mass Balance, GEE Gasifier and ASU.................................. 242

Exhibit 4-29 Case 2 D1B (25%) Heat and Mass Balance, Syngas Cleanup ............................................. 243

Exhibit 4-30 Case 2 D1B (25%) Heat and Mass Balance, Power Block................................................... 244

Exhibit 4-31 Case 2 D1A (0%) Energy Balance ....................................................................................... 245

Exhibit 4-32 Case 2 D1B (25%) Energy Balance...................................................................................... 246

Exhibit 4-33 Case 2 D1A Energy Balance Sankey Diagram..................................................................... 247

Exhibit 4-34 Case 2 D1B Energy Balance Sankey Diagram..................................................................... 247

Exhibit 4-35 Case 2 D2 Process Block Flow Diagram, IGCC with Single WGS Reactor and Bypass.... 258

Exhibit 4-36 Case 2 D2A Stream Table, 25% CO2 Removal with Single WGS Bypass.......................... 259

Exhibit 4-37 Case 2 D2B Stream Table, 45% CO2 Capture with Single WGS Bypass............................ 261

Exhibit 4-38 Case 2 D2C Stream Table, 60% CO2 Capture with Single WGS Bypass............................ 263

Exhibit 4-39 Case 2 D2D Stream Table, 75% CO2 Capture with Single WGS Bypass............................ 265

Exhibit 4-40 Case 2 D2 Performance Modeling Results........................................................................... 267

Exhibit 4-41 Case 2 D2 Estimated Air Emission Rates............................................................................. 270

Exhibit 4-42 Case 2 D2 Carbon Balance ................................................................................................... 271

Exhibit 4-43 Case 2 D2 Sulfur Balance..................................................................................................... 271

Exhibit 4-44 Case 2 D2A (25%) Water Balance ....................................................................................... 272

Exhibit 4-45 Case 2 D2B (45%) Water Balance ....................................................................................... 273

Exhibit 4-46 Case 2 D2C (60%) Water Balance ....................................................................................... 274

Exhibit 4-47 Case 2 D2D (75%) Water Balance ....................................................................................... 275

Exhibit 4-48 Case 2 D2A (25%) Heat and Mass Balance, GEE Gasifier and ASU.................................. 277

Exhibit 4-49 Case 2 D2A (25%) Heat and Mass Balance, Syngas Cleanup ............................................. 278

Exhibit 4-50 Case 2 D2A (25%) Heat and Mass Balance, Power Block .................................................. 279

Exhibit 4-51 Case 2 D2B (45%) Heat and Mass Balance, GEE Gasifier and ASU.................................. 280

Exhibit 4-52 Case 2 D2B (45%) Heat and Mass Balance, Syngas Cleanup ............................................. 281

Exhibit 4-53 Case 2 D2B (45%) Heat and Mass Balance, Power Block................................................... 282

Exhibit 4-54 Case 2 D2C (60%) Heat and Mass Balance, GEE Gasifier and ASU.................................. 283

Exhibit 4-55 Case 2 D2C (60%) Heat and Mass Balance, Syngas Cleanup ............................................. 284

Exhibit 4-56 Case 2 D2C (60%) Heat and Mass Balance, Power Block................................................... 285

Exhibit 4-57 Case 2 D2D (75%) Heat and Mass Balance, GEE Gasifier and ASU.................................. 286

Exhibit 4-58 Case 2 D2D (75%) Heat and Mass Balance, Syngas Cleanup ............................................. 287

Exhibit 4-59 Case 2 D2D (75%) Heat and Mass Balance, Power Block .................................................. 288

Exhibit 4-60 Case 2 D2A (25%) Energy Balance ..................................................................................... 289

Exhibit 4-61 Case 2 D2B (45%) Energy Balance...................................................................................... 290

Exhibit 4-62 Case 2 D2C (60%) Energy Balance...................................................................................... 291

Exhibit 4-63 Case 2 D2D (75%) Energy Balance ..................................................................................... 292

Exhibit 4-64 Case 2 D2A Energy Balance Sankey Diagram..................................................................... 293

Exhibit 4-65 Case 2 D2B Energy Balance Sankey Diagram..................................................................... 293

Exhibit 4-66 Case 2 D2C Energy Balance Sankey Diagram..................................................................... 294

Exhibit 4-67 Case 2 D2D Energy Balance Sankey Diagram..................................................................... 294

Exhibit 4-68 Case 2 D3 Process Block Flow Diagram, IGCC with Two WGS Reactors and Bypass ..... 304

Exhibit 4-69 Case 2 D3A Stream Table, 25% CO2 Removal with Two WGS Bypass............................. 305

Exhibit 4-70 Case 2 D3B Stream Table, 45% CO2 Capture with Two WGS Bypass............................... 307

Exhibit 4-71 Case 2 D3C Stream Table, 60% CO2 Capture with Two WGS Bypass............................... 309

Exhibit 4-72 Case 2 D3D Stream Table, 75% CO2 Capture with Two WGS Bypass............................... 311

Exhibit 4-73 Case 2 D3E Stream Table, 85% CO2 Capture with Two WGS Bypass............................... 313

Exhibit 4-74 Case 2 D3 Performance Modeling Results........................................................................... 315
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Exhibit 4-75 Case 2 D3 Estimated Air Emission Rates............................................................................. 318

Exhibit 4-76 Case 2 D3 Carbon Balance ................................................................................................... 319

Exhibit 4-77 Case 2 D3 Sulfur Balance..................................................................................................... 319

Exhibit 4-78 Case 2 D3A (25%) Water Balance ....................................................................................... 320

Exhibit 4-79 Case 2 D3B (45%) Water Balance ....................................................................................... 321

Exhibit 4-80 Case 2 D3C (60%) Water Balance ....................................................................................... 322

Exhibit 4-81 Case 2 D3D (75%) Water Balance ....................................................................................... 323

Exhibit 4-82 Case 2 D3E (85%) Water Balance........................................................................................ 324

Exhibit 4-83 Case 2 D3A (25%) Heat and Mass Balance, GEE Gasifier and ASU.................................. 325

Exhibit 4-84 Case 2 D3A (25%) Heat and Mass Balance, Syngas Cleanup ............................................. 326

Exhibit 4-85 Case 2 D3A (25%) Heat and Mass Balance, Power Block .................................................. 327

Exhibit 4-86 Case 2 D3B (45%) Heat and Mass Balance, GEE Gasifier and ASU.................................. 328

Exhibit 4-87 Case 2 D3B (45%) Heat and Mass Balance, Syngas Cleanup ............................................. 329

Exhibit 4-88 Case 2 D3B (45%) Heat and Mass Balance, Power Block................................................... 330

Exhibit 4-89 Case 2 D3C (60%) Heat and Mass Balance, GEE Gasifier and ASU.................................. 331

Exhibit 4-90 Case 2 D3C (60%) Heat and Mass Balance, Syngas Cleanup ............................................. 332

Exhibit 4-91 Case 2 D3C (60%) Heat and Mass Balance, Power Block................................................... 333

Exhibit 4-92 Case 2 D3D (75%) Heat and Mass Balance, GEE Gasifier and ASU.................................. 334

Exhibit 4-93 Case 2 D3D (75%) Heat and Mass Balance, Syngas Cleanup ............................................. 335

Exhibit 4-94 Case 2 D3D (75%) Heat and Mass Balance, Power Block .................................................. 336

Exhibit 4-95 Case 2 D3E (85%) Heat and Mass Balance, GEE Gasifier and ASU .................................. 337

Exhibit 4-96 Case 2 D3E (85%) Heat and Mass Balance, Syngas Cleanup.............................................. 338

Exhibit 4-97 Case 2 D3E (85%) Heat and Mass Balance, Power Block................................................... 339

Exhibit 4-98 Case 2 D3A (25%) Energy Balance ..................................................................................... 341

Exhibit 4-99 Case 2 D3B (45%) Energy Balance...................................................................................... 342

Exhibit 4-100 Case 2 D3C (60%) Energy Balance.................................................................................... 343

Exhibit 4-101 Case 2 D3D (75%) Energy Balance ................................................................................... 344

Exhibit 4-102 Case 2 D3E (85%) Energy Balance.................................................................................... 345

Exhibit 4-103 Case 2 D3A Energy Balance Sankey Diagram................................................................... 346

Exhibit 4-104 Case 2 D3B Energy Balance Sankey Diagram................................................................... 346

Exhibit 4-105 Case 2 D3C Energy Balance Sankey Diagram................................................................... 347

Exhibit 4-106 Case 2 D3D Energy Balance Sankey Diagram................................................................... 347

Exhibit 4-107 Case 2 D3E Energy Balance Sankey Diagram................................................................... 348

Exhibit 4-108 Case 2 D4 Process Block Flow Diagram, IGCC with Two WGS Reactors....................... 358

Exhibit 4-109 Case 2 D4A Stream Table, 90% CO2 Removal.................................................................. 359

Exhibit 4-110 Case 2 D4B Stream Table, 95% CO2 Capture.................................................................... 361

Exhibit 4-111 Case 2 D4C Stream Table, 97% CO2 Capture.................................................................... 363

Exhibit 4-112 Case 2 D4 Performance Modeling Results......................................................................... 365

Exhibit 4-113 Case 2 D4 Estimated Air Emission Rates........................................................................... 368

Exhibit 4-114 Case 2 D4 Carbon Balance ................................................................................................. 369

Exhibit 4-115 Case 2 D4 Sulfur Balance................................................................................................... 369

Exhibit 4-116 Case 2 D4A (90%) Water Balance ..................................................................................... 370

Exhibit 4-117 Case 2 D4B (95%) Water Balance ..................................................................................... 371

Exhibit 4-118 Case 2 D4C (97%) Water Balance ..................................................................................... 372

Exhibit 4-119 Case 2 D4A (90%) Heat and Mass Balance, GEE Gasifier and ASU................................ 373

Exhibit 4-120 Case 2 D4A (90%) Heat and Mass Balance, Syngas Cleanup ........................................... 374

Exhibit 4-121 Case 2 D4A (90%) Heat and Mass Balance, Power Block ................................................ 375

Exhibit 4-122 Case 2 D4B (95%) Heat and Mass Balance, GEE Gasifier and ASU................................ 376
Carbon Dioxide Capture Sensitivity Analysis

viii

Exhibit 4-123 Case 2 D4B (95%) Heat and Mass Balance, Syngas Cleanup ........................................... 377

Exhibit 4-124 Case 2 D4B (95%) Heat and Mass Balance, Power Block................................................. 378

Exhibit 4-125 Case 2 D4C (97%) Heat and Mass Balance, GEE Gasifier and ASU................................ 379

Exhibit 4-126 Case 2 D4C (97%) Heat and Mass Balance, Syngas Cleanup ........................................... 380

Exhibit 4-127 Case 2 D4C (97%) Heat and Mass Balance, Power Block................................................. 381

Exhibit 4-128 Case 2 D4A (90%) Energy Balance ................................................................................... 383

Exhibit 4-129 Case 2 D4B (95%) Energy Balance.................................................................................... 384

Exhibit 4-130 Case 2 D4C (97%) Energy Balance.................................................................................... 385

Exhibit 4-131 Case 2 D4A Energy Balance Sankey Diagram................................................................... 386

Exhibit 4-132 Case 2 D4B Energy Balance Sankey Diagram................................................................... 386

Exhibit 4-133 Case 2 D4C Energy Balance Sankey Diagram................................................................... 387

Exhibit 4-134 Case 2 D1A (0%) Capital Costs ......................................................................................... 396

Exhibit 4-135 Case 2 D1A Initial and Annual O&M Expenses................................................................ 400

Exhibit 4-136 Case 2 D1B (25%) Capital Costs........................................................................................ 401

Exhibit 4-137 Case 2 D1B Initial and Annual O&M Expenses................................................................ 405

Exhibit 4-138 Case 2 D2A (25%) Capital Costs ....................................................................................... 406

Exhibit 4-139 Case 2 D2A Initial and Annual O&M Expenses................................................................ 410

Exhibit 4-140 Case 2 D2B (45%) Capital Costs........................................................................................ 411

Exhibit 4-141 Case 2 D2B Initial and Annual O&M Expenses................................................................ 415

Exhibit 4-142 Case 2 D2C (60%) Capital Costs........................................................................................ 416

Exhibit 4-143 Case 2 D2C Initial and Annual O&M Expenses................................................................ 420

Exhibit 4-144 Case 2 D2D (75%) Capital Costs ....................................................................................... 421

Exhibit 4-145 Case 2 D2D Initial and Annual O&M Expenses................................................................ 425

Exhibit 4-146 Case 2 D3A (25%) Capital Costs ....................................................................................... 426

Exhibit 4-147 Case 2 D3A Initial and Annual O&M Expenses................................................................ 430

Exhibit 4-148 Case 2 D3B (45%) Capital Costs........................................................................................ 431

Exhibit 4-149 Case 2 D3B Initial and Annual O&M Expenses................................................................ 435

Exhibit 4-150 Case 2 D3C (60%) Capital Costs........................................................................................ 436

Exhibit 4-151 Case 2 D3C Initial and Annual O&M Expenses................................................................ 440

Exhibit 4-152 Case 2 D3D (75%) Capital Costs ....................................................................................... 441

Exhibit 4-153 Case 2 D3D Initial and Annual O&M Expenses................................................................ 445

Exhibit 4-154 Case 2 D3E (85%) Capital Costs........................................................................................ 446

Exhibit 4-155 Case 2 D3E Initial and Annual O&M Expenses ................................................................ 450

Exhibit 4-156 Case 2 D4A (90%) Capital Costs ....................................................................................... 451

Exhibit 4-157 Case 2 D4A Initial and Annual O&M Expenses................................................................ 455

Exhibit 4-158 Case 2 D4B (95%) Capital Costs........................................................................................ 456

Exhibit 4-159 Case 2 D4B Initial and Annual O&M Expenses................................................................ 460

Exhibit 4-160 Case 2 D4C (97%) Capital Costs........................................................................................ 461

Exhibit 4-161 Case 2 D4C Initial and Annual O&M Expenses................................................................ 465

Exhibit 4-162 Cost and Performance Results for the GEE IGCC Cases................................................... 467

Exhibit 5-1 Net Plant HHV Efficiency for the Supercritical PC Cases..................................................... 470

Exhibit 5-2 Net Plant HHV Efficiency for the GEE IGCC Cases............................................................. 471

Exhibit 5-3 TOC for the Supercritical PC Cases....................................................................................... 472

Exhibit 5-4 TOC for the GEE IGCC Cases............................................................................................... 473

Exhibit 5-5 COE for the Supercritical PC Cases....................................................................................... 474

Exhibit 5-6 COE for the GEE IGCC Cases............................................................................................... 475

Exhibit 5-7 CO2 TS&M COE for the Supercritical PC Cases................................................................... 475

Exhibit 5-8 CO2 TS&M COE for the GEE IGCC Cases........................................................................... 476
Carbon Dioxide Capture Sensitivity Analysis

ix

Exhibit 5-9 CO2 Avoided Costs for the Supercritical PC Cases................................................................ 477

Exhibit 5-10 CO2 Avoided Costs for the GEE IGCC Cases...................................................................... 478

Exhibit 5-11 Cost and Performance Results for the Supercritical PC Cases............................................. 481

Exhibit 5-12 Cost and Performance Results for the GEE IGCC Cases..................................................... 482

Appendix A- 1 Supercritical PC CO2 Capture & Compression Cost, $000.............................................. 484

Appendix A- 2 Supercritical PC CO2 Capture & Compression Cost, $/kW............................................. 484

Appendix A- 3 Supercritical PC Total Overnight Cost, $000 ................................................................... 485

Appendix A- 4 Supercritical PC Total Overnight Cost, $/kW .................................................................. 485

Appendix A- 5 Supercritical PC Incremental Capital Cost, $000 ............................................................. 486

Appendix A- 6 Supercritical PC Incremental Capital Cost, $/kW ............................................................ 486

Appendix A- 7 Supercritical PC COE, mills/kWh .................................................................................... 487

Appendix A- 8 Supercritical PC Incremental COE, mills/kWh ................................................................ 487

Appendix A- 9 Supercritical PC Percent Increase in COE........................................................................ 488

Appendix A- 10 Supercritical PC CO2 Capture Avoided Costs................................................................ 488

Appendix A- 11 GEE IGCC CO2 Capture & Compression Cost, $000.................................................... 489

Appendix A- 12 GEE IGCC CO2 Capture & Compression Cost, $/kW................................................... 489

Appendix A- 13 GEE IGCC Total Overnight Cost, $000 ......................................................................... 490

Appendix A- 14 GEE IGCC Total Overnight Cost, $/kW ........................................................................ 490

Appendix A- 15 GEE IGCC Incremental Capital Cost, $000 ................................................................... 491

Appendix A- 16 GEE IGCC Incremental Capital Cost, $/kW .................................................................. 491

Appendix A- 17 GEE IGCC COE, mills/kWh .......................................................................................... 492

Appendix A- 18 GEE IGCC Incremental COE, mills/kWh ...................................................................... 492

Appendix A- 19 GEE IGCC Percent Increase in COE.............................................................................. 493

Appendix A- 20 GEE IGCC CO2 Capture Avoided Costs........................................................................ 493
Carbon Dioxide Capture Sensitivity Analysis

x

List of Acronyms and Abbreviations

AACE Association for the Advancement of Cost Engineering

acfm Actual cubic foot per minute

AEO Annual Energy Outlook

AGR Acid gas removal

AR As Received

ASU Air separation unit

BACT Best available control technology

BEC Bare erected cost

BFD Block flow diagram

BFW Boiler feed water

Btu British thermal unit

Btu/h British thermal unit per hour

Btu/kWh British thermal unit per kilowatt hour

Btu/lb British thermal unit per pound

CA California

CCF Capital Charge Factor

CCS Carbon Capture and Sequestration

CF Capacity factor

CFM Cubic feet per minute

CFR Code of Federal Regulations

CGE Cold gas efficiency

CH4 Methane

cm Centimeter

CO2 Carbon dioxide

CO2e Carbon dioxide equivalent

COE Cost of electricity

CoP ConocoPhillips

COS Carbonyl sulfide

CRP Conservation Reserve Program

CRT Cathode ray tube

CT Combustion turbine

CTG Combustion Turbine-Generator

CWT Cold water temperature

DCS Distributed control system

Dia. Diameter

DOE Department of Energy

EAF Equivalent availability factor

E-GasTM ConocoPhillips gasifier technology

EIA Energy Information Administration

EPA Environmental Protection Agency

EPC Engineer/Procure/Construct
Carbon Dioxide Capture Sensitivity Analysis

xi

EPCM Engineering/Procurement/Construction Management 

EPRI Electric Power Research Institute

FOAK First of a kind

ft Foot, Feet

GADS Generating Availability Data System 

gal Gallon

GDP Gross domestic product

GEE General Electric Energy

GHG Greenhouse gas

gpm Gallons per minute

GT Gas turbine

GW Gigawatt

GWP Global Warming Potential

h Hour

H2 Hydrogen

H2S Hydrogen sulfide

Hg Mercury

HHV Higher heating value

hp Horsepower

HP High pressure

HRSG Heat recovery steam generator

HVAC Heating, ventilating, and air conditioning

IGVs Inlet guide vanes

IGCC Integrated gasification combined cycle

IOU Investor-owned utility

IP Intermediate pressure

ISO International Standards Organization

kg/GJ Kilogram per gigajoule

kg/h Kilogram per hour

kJ Kilojoules

kJ/kg Kilojoules per kilogram

KO Knockout

kPa Kilopascal absolute

kV Kilovolt

kW Kilowatt

kWe Kilowatts electric

kWh Kilowatt-hour

kWt Kilowatts thermal

LAER Lowest Achievable Emission Rate

lb Pound

lb/h Pounds per hour

lb/MMBtu Pounds per million British thermal units

lb/MWh Pounds per megawatt hour
Carbon Dioxide Capture Sensitivity Analysis

xii

LFFn Levelization factor for category n fixed operating cost

LFVn Levelization factor for category n variable operating cost

LHV Lower heating value

LNB Low NOx burner

LP Low pressure

m Meters

MM$ Millions of Dollars

m/min Meters per minute

m

3

/min Cubic meter per minute

MDEA Methyldiethanolamine

MEA Monoethanolamine

MHz Megahertz

MMBtu Million British thermal units (also shown as 106 Btu)

MMBtu/h Million British thermal units (also shown as 106 Btu) per hour

MPa Megapascals

Mpg Miles per gallon

MW Megawatt

MWe Megawatts electric

MWh Megawatt-hour

NAAQS National ambient air quality standard

net-MWh Net megawatt-hour

NERC North American Electric Reliability Council

NETL National Energy Technology Laboratory

NGCC Natural gas combined cycle

NOx Oxides of nitrogen

NSPS New Source Performance Standards

NSR New Source Review

NREL National Renewable Energy Laboratory

O&M Operation and maintenance

OCFn Category n fixed operating cost for the initial year of operation

PC Pulverized coal

PM Particulate matter 

PM10 Particulate matter measuring 10 μm or less

POTW Publicly Owned Treatment Works

ppm Parts per million 

ppmd Parts per million, dry

ppmv Parts per million, volume

PRB Powder River Basin coal region

PSD Prevention of Significant Deterioration

psia Pounds per square inch absolute

psig Pounds per square inch gage

R&D Research and Development

RDS Research and Development Solutions, LLC
Carbon Dioxide Capture Sensitivity Analysis

xiii

SC Supercritical

SCR Selective catalytic reduction

SGS Sour gas shift

SO2 Sulfur dioxide

STG Steam turbine generator

SWS Sour water stripper

TASC Total As-Spent Capital

TBtu Trillion British thermal unit

TGTU Tail gas treating unit

TOC Total overnight cost

Tonne Metric Ton (1000 kg)

TPC Total plant cost

TPD Tons per day

TPH Tons per hour

TPI Total plant investment

TS&M Transport, storage and monitoring

TWh Terawatt-hour

USDA United States Department of Agriculture

vol% Volume percent

WGS Water gas shift

wt% Weight percent

$/AR ton Dollars per As Received ton

$/dry ton Dollars per dry ton

$/kW Dollars per kilowatt

$/MMBtu Dollars per million British thermal units

$/MMkJ Dollars per million kilojoule

$/MWh Dollars per Megawatt-hour

$/ton Dollars per ton

5-10s Fifty hour work weeks (5 days, 10 hours/day)
Carbon Dioxide Capture Sensitivity Analysis

xiv

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Carbon Dioxide Capture Sensitivity Analysis

1

Executive Summary

The objective of this study was to establish the cost and performance for a range of carbon 

dioxide (CO2) capture levels for new supercritical (SC) pulverized coal (PC) and integrated 

gasification combined cycle (IGCC) power plants. The SC PC cases (Case 1 series) utilize 

Fluor‟s Econamine FG PlusSM process for post-combustion CO2 capture via temperature swing 

absorption with a 30 wt% monoethanolamine (MEA) solution as the chemical solvent. The 

IGCC cases (Case 2 series) employ a slurry-fed, entrained-flow General Electric Energy (GEE) 

gasifier and leverage UOP‟s (formerly Universal Oil Products) two-stage SelexolTM process for 

bulk CO2 capture and selective hydrogen sulfide (H2S) removal via pressure swing absorption. 

The SelexolTM process uses dimethyl ether of polyethylene glycol (DEPG) as a physical solvent 

for pre-combustion capture. 

The CO2 capture sensitivity analysis includes an evaluation of the cost, performance, and 

environmental profile of these facilities while operating at 0 feet of elevation (ISO conditions) in 

the Illinois coal basin and firing Illinois #6 medium-sulfur bituminous coal. The study includes

compression of the captured CO2 to pipeline pressure of 15.2 MPa (2,215 psia), pipeline 

transport 80 kilometers (50 miles), storage in a saline formation at a depth of 1,239 meters (4,055 

ft), and monitoring for 80 years. The site will have appropriate access to rail transportation for 

delivery of coal. All local coal handling facilities are included in the design and cost estimation 

portion of this study. The assumed start-up date is 2015 and all cases are considered “first-of-akind” (FOAK). The methodology included performing steady-state simulations of the 

technology using the ASPEN Plus®(Aspen) modeling program. Each configuration was tailored 

to achieve a specific level of carbon capture. 

Pulverized Coal Plants

An Aspen model for a SC PC power plant, coupled with detailed simulations of the Econamine 

FG PlusSM process using Optimized Gas Treating‟s ProTreatTM, was utilized to evaluate the 

technical and economic performance of post-combustion CO2 capture in the following 

increments: 30, 50, 70, 85, 90, 95, and 99 percent capture. For control of nitrogen oxides (NOx) 

emissions, a combination of low-NOx burners (LNB) with overfire air (OFA) and a selective 

catalytic reduction (SCR) system is used. A fabric filter is employed to minimize particulate 

matter emissions. A wet limestone flue gas desulfurization (FGD) system, in conjunction with a 

sodium hydroxide polishing scrubber, is used to ensure that the flue gas entering the Econamine 

system has a sulfur dioxide (SO2) concentration of 10 ppmv or less. The SC PC descriptions

(herein referred to as Case 1) are summarized in Exhibit ES-1.
Carbon Dioxide Capture Sensitivity Analysis

2

Exhibit ES-1 Case 1 Supercritical PC Plant Configuration Summary

Case CO2

Capture

Intended 

Storage Boiler Steam psig/°F/°F Oxidant NOx Control Sulfur Control

1A 30%

Saline 

Formation

Wall-fired, 

PC 3500/1100/1100 Air LNB/OFA/SCR 0.07 lb/MMBtu

Wet FGD

0.1 lb/MMBtu

1B 50%

1C 70%

1D 85%

1E 90%

1F 95%

1G 99%

Optimized Gas Treating‟s rate-based ProTreatTM software was used to generate performance 

estimates for the Econamine FG PlusSM process. Initially, 90 percent CO2 removal was modeled 

by adjusting three key process parameters: (1) the MEA solution circulation rate; (2) the reboiler 

steam flow rate; and (3) the height of packing material in the absorption and stripping columns. 

For higher levels of CO2 removal (greater than 90 percent), the MEA and reboiler steam flow 

rates were increased, as well as the absorber/stripper column packing height.

Recent studies typically focus on 90 percent CO2 capture from coal-fired power plants, but for 

the cases in this study that focus on less than 90 percent, two options exist. The first option is to 

pass the entire flue gas stream through the amine scrubbing unit, but at reduced solvent 

circulation rates. The second is to maintain the same high solvent circulation rate and stripping 

steam requirement, but only treat a portion of the flue gas by bypassing part of the gas stream 

around the scrubber. A literature search was conducted to verify that less than 90 percent CO2

capture is most economical using a “slip-stream” (or bypass) approach. According to multiple 

peer-reviewed studies the slip-stream approach is indeed more cost-effective for lower degrees of 

capture [1, 2, 3]. The cost of CO2 capture with an amine scrubbing process is dependent on the 

volume of gas being treated, and a reduction in flue gas flow rate will: (1) decrease the quantity 

of energy consumed by flue gas blowers; (2) reduce the size of the CO2 absorption columns; and

(3) trim the cooling water requirement of the direct contact cooling system. As a result, the „slipstream‟approach for reduced levels of capture leads to lower capital and operating costs. 

Due to the range of CO2 capture levels analyzed in Case 1, the Econamine capital and operating 

costs vary for the seven cases. While a factored approach that relies on the quantity of CO2

captured for equipment sizing and cost estimation was employed, the cost estimates for the 

Econamine system were also developed based, in part, on output data from the ProTreatTM 

simulations. In particular, the ProTreatTM model output provided absorption and stripping 

column diameters for each case, which were used to determine the required number of 

absorption trains.

For this analysis, it was assumed that the maximum absorption column diameter is 20 meters (66 

feet), based on information released by Fluor [4]. As a result, cases that include carbon capture 

up to 70% are based on a single absorption and compression train. 
Carbon Dioxide Capture Sensitivity Analysis

3

IGCC Plants

An Aspen model for a GEE IGCC power plant, coupled with analysis of different process 

configurations (i.e., water gas shift bypass ratio and SelexolTM CO2 removal efficiency), was 

utilized to evaluate the technical and economic performance of pre-combustion CO2 capture for 

the following four plant designs:

Design 1 (D1) has no water gas shift (WGS) reactor. The minimum (0 percent) and 

maximum (25 percent) CO2 capture levels for this particular configuration are

modeled. The initial concept for D1 was to have a two-stage SelexolTM unit, and if no 

capture was desired, “turn off” the second stage (which would be dedicated for CO2

control). However due to the high degree of integration between the H2S and CO2

absorbers, it is not feasible to simply disable the second stage. Consequently, D1A (0

percent capture) employs a one-stage SelexolTM unit for H2S control, while D1B (25

percent capture) utilizes a two-stage SelexolTM unit to maximize CO2 capture from 

the unshifted syngas. 

Design 2 (D2) has one-stage of WGS, with CO2 capture ranging from 25 (upper limit 

from D1) to 75 percent (maximum achievable limit for this particular configuration). 

The different levels of CO2 capture were achieved by varying the WGS bypass ratio

and the two-stage SelexolTM CO2 removal efficiency. The separation efficiency of a 

physical solvent-based system such as the SelexolTM process is directly proportional 

to the concentration of CO2 in the syngas. Therefore, the level of CO2 capture can be 

manipulated by varying the extent of the water gas shift reaction. In Design 2, the 

amount of CO being converted to CO2 is varied by only shifting a portion of the 

syngas stream. The SelexolTM removal efficiency is changed by varying the solvent 

circulation rate, which changes the size and cost of the SelexolTM system. 

Design 3 (D3) has two-stages of WGS with CO2 capture ranging from 25 percent

(upper limit from D1) to the maximum achievable limit for this particular 

configuration (85 percent) by varying the WGS bypass ratio and the two-stage 

SelexolTM CO2 removal efficiency. The SelexolTM removal efficiency is changed by 

varying the solvent circulation rate, which changes the size and cost of the SelexolTM 

system. 

Design 4 (D4) has two-stages of WGS with no bypass (therefore the entire syngas 

stream is shifted) with CO2 capture ranging from 90 percent to 97 percent. To 

achieve greater than 90 percent CO2 removal, the two-stage SelexolTM CO2 removal 

efficiency is increased by raising the solvent circulation rate, which increases the size 

and cost of the SelexolTM system. 

The Case 2 IGCC design descriptions are summarized in Exhibit ES-2.
Carbon Dioxide Capture Sensitivity Analysis

4

Exhibit ES-2 Case 2 GEE IGCC Plant Configuration Summary

Case CO2

Capture

CO2

Separation

Intended 

Storage Gasifier Steam psig/°F/°F Oxidant WGS Sulfur Control

D1A 0% N/A N/A

GEE

Radiant 

Only

1800/1050/

1050

95 

mol% 

O2

N/A

Selexol

TM

D1B 25%

SelexolTM 

2

nd Stage

Saline 

Formation

N/A

D2A 25%

OneStage 

with 

Bypass

D2B 45%

D2C 60%

D2D 75%

D3A 25%

TwoStage 

with 

Bypass

D3B 45%

D3C 60%

D3D 75%

D3E 85%

D4A 90% TwoStage 

without 

Bypass

D4B 95%

D4C 97%

To determine the process configurations for less than 90 percent CO2 removal (IGCC D2 and 

D3), the WGS bypass ratio and SelexolTM CO2 removal efficiency were varied over a series of 

Aspen simulations of the entire GEE IGCC power plant to evaluate the impact on WGS and 

SelexolTM costs and net plant efficiency. As a starting point, the SelexolTM CO2 removal 

efficiency (92.4 percent) used to model 90 percent CO2 removal was fixed [5], and the WGS 

bypass ratio was adjusted to achieve the desired level of capture. The CO2 removal level was 

then held constant by decreasing both the WGS bypass ratio (i.e., routing more syngas through 

the WGS reactor(s)) and the SelexolTM CO2 removal efficiency. These step changes in the WGS 

bypass ratio lead to an increase in CO2 partial pressure, which relaxes the CO2 removal required 

by the SelexolTM process.

As shown in Exhibit ES-3, the cost of the WGS system decreases as the WGS bypass ratio 

increases since the quantity of syngas being shifted declines. The SelexolTM system cost 

increases with the WGS bypass ratio since a higher solvent circulation rate is required to 

maintain 60 percent CO2 removal as the CO2 partial pressure decreases. However, the total cost 

of the WGS and SelexolTM systems, which is dominated by the cost of the SelexolTM system, 

gradually increases with the WGS bypass ratio. Meanwhile, the net plant HHV efficiency passes 

through a maximum value over the range of WGS bypass ratios. As a result, the WGS bypass 

ratios and SelexolTM CO2 removal efficiencies used to model less than 90 percent CO2 removal 

in this study (IGCC D2 and D3) correspond to the maximum net plant HHV efficiency.
Carbon Dioxide Capture Sensitivity Analysis

5

Exhibit ES-3 Net Efficiency and Cost as a Function of WGS Bypass Ratio for 60% CO2 Removal 

with IGCC Design 3

3 4

34.2

34.4

34.6

34.8

3 5

35.2

35.4

35.6

35.8

3 6

$ 0

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

$140,000

$160,000

$180,000

0 0.1 0.2 0.3 0.4 0.5

Net Plant HHV Efficiency, %

Capital Cost, $000

WGS Bypass Ratio

Total Cost

Selexol Cost

WGS Cost

Efficiency

This procedure was repeated for each level of total CO2 removal analyzed for IGCC D2 and D3 

to determine the optimal WGS bypass ratio and SelexolTM CO2 removal efficiency for these 

intermediate capture points. Data for these optimal configurations are provided in Exhibit ES-4

and Exhibit ES-5 for IGCC D2 and D3, respectively. These results indicate that the SelexolTM 

CO2 removal efficiency increases with CO2 partial pressure, which is the expected trend with a

physical solvent-based system. 

Exhibit ES-4 Process Configurations for IGCC D2

Total CO2

Removal (%) WGS WGS Bypass Ratio (%)

SelexolTM CO2

Removal (%) PCO2 (psia)

25

One-Stage 

with Bypass

99.5 85.8 119.4

45 60 89 186.3

60 28.75 89.5 229.8

75 0 91 265.5
Carbon Dioxide Capture Sensitivity Analysis

6

Exhibit ES-5 Process Configurations for IGCC D3

Total CO2

Removal (%) WGS WGS Bypass Ratio (%)

SelexolTM CO2

Removal (%) PCO2 (psia)

25

Two-Stage 

with Bypass

99.75 86.31 119.7

45 69.4 90.04 186.5

60 45 90.1 230.1

75 21 90.4 264.3

85 5 90.52 289.3

A typical offering from a commercial catalyst vendor is a steam-to-dry gas (S:DG) molar ratio of 

0.3 at the outlet of the final WGS reactor. However, for lower levels of CO2 removal (IGCC D2 

and D3), this study uses a S:DG molar ratio of 0.25 at the outlet of the final WGS reactor. 

Operating with a lower S:DG ratio impedes the kinetics of carbon monoxide (CO) to CO2

conversion. Consequently, larger and more costly WGS reactors are required for a similar 

degree of conversion. Although a reduction in S:DG ratio requires a larger reactor volume (this 

analysis assumes a catalyst volume increase of 30 percent, and subsequently a 30 percent

increase in reactor cost), there is the benefit of shift steam savings. This steam can then be 

expanded through the steam turbine to produce additional power.

Thermal input to the IGCC plant is used to fully-load the combustion turbines. Any remaining 

energy in the combustion turbine exhaust is extracted to the maximum extent possible in a heat 

recovery steam generator in order to raise steam to generate additional power. The net power for 

the IGCC cases ranges from 523 to 622 MW. The span in net output is caused by the wide range

of CO2 capture imposed from case-to-case. The differences in auxiliary loads are primarily 

attributed to CO2 compression and the need for extraction steam in the WGS reactions, which 

reduces steam turbine output. 

Results 

The major results from the CO2 capture sensitivity analysis are discussed below in the following 

order:

Performance (efficiency)

Economics (total overnight cost, cost of electricity, and CO2 avoided cost)

Performance and Cost summary

Performance

Energy Efficiency

The net plant HHV efficiencies for the SC PC and GEE IGCC cases are presented in Exhibit 

ES-6 and Exhibit ES-7, respectively. As the CO2 capture requirement is increased for either 

plant type, PC or IGCC, there is an increase in the auxiliary power required to support the 
Carbon Dioxide Capture Sensitivity Analysis

7

capture equipment (either Econamine or SelexolTM) and the CO2 compressor trains. Further, 

more steam is consumed by the capture equipment, and by the WGS reactor(s) in the IGCC case, 

making less available for supply to the steam turbine. Both effects (higher auxiliary load and 

reduced steam supply to the turbine) detract from the net power produced by the plant per unit of 

coal energy input, as evidenced by the net plant HHV efficiency trends versus CO2 capture level. 

Exhibit ES-6 Supercritical PC Net Plant Efficiency (HHV)

0

1 0

2 0

3 0

4 0

Case 0 0% Case 1A 30% Case 1B 50% Case 1C 70% Case 1D 85% Case 1E 90% Case 1F 95% Case 1G 99%

39.3

35.2

32.9

30.6 28.9

28.2

27.5

25.7 Net Plant HHV Efficiency, %

Capture with Bypass Capture without Bypass
Carbon Dioxide Capture Sensitivity Analysis

8

Exhibit ES-7 IGCC Net Plant Efficiency (HHV)

0

10

20

30

40

D1A 0% D1B 25% D2A 25% D2B 45% D2C 60% D2D 75% D3A 25% D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% D4B 95% D4C 97%

39.0

38.4 38.4

36.8

35.5

34.3

38.4

36.7

35.5 34.2 33.4

32.6 31.8 31.5 Net Plant HHV Efficiency, %

No WGS One WGS w/ Bypass Two WGS w/ Bypass Two WGS w/o Bypass

Economics

Total Overnight Cost

All capital costs are presented as “overnight costs” expressed in June 2007 dollars. The capital 

costs are presented at the total overnight cost (TOC) level, which includes: (1) equipment 

(complete with initial chemical and catalyst loadings); (2) materials; (3) labor (direct and 

indirect); (4) engineering and construction management; (5) contingencies (process and project); 

and (6) owner‟s costs. The owner‟s costs, which are summarized in Exhibit 2-18, include 

preproduction costs, inventory capital, land costs, financing costs, taxes and insurances, and 

other owner‟s costs.

The TOC for the SC PC and GEE IGCC cases are presented in Exhibit ES-8 and Exhibit ES-9, 

respectively. These exhibits categorize the TOC into five categories: (1) bare erected cost; (2) 

engineering, home office, construction management (CM), and fees; (3) project contingency; (4) 

process contingency; and (5) owner‟s costs. 

The SC PC total overnight cost estimates apply to facilities designed with a fixed 550 MW net 

capacity. As the design is equipped for increased CO2 capture, moving from Case 1A through 

Case 1G, the TOC also increases as a result of the need for larger power plant components for 
Carbon Dioxide Capture Sensitivity Analysis

9

power generation to offset the auxiliary power and steam requirements of the CO2 capture and 

compression systems. Hence, the increase in installed TOC per net kW delivered. 

Exhibit ES-8 Supercritical PC Total Overnight Cost

0

500

1000

1500

2000

2500

3000

3500

4000

4500

Case 0 0% Case 1A 30% Case 1B 50% Case 1C 70% Case 1D 85% Case 1E 90% Case 1F 95% Case 1G 99%

2,025

2,541

2,808

3,075

3,400 3,484 3,572

3,744 TOC, $/kW

Owner's Costs

Process Contingency

Project Contingency

Engr., Home Office, CM, and Fee

Bare Erected Cost

Capture with Bypass Capture without Bypass

The IGCC total overnight cost estimates apply to facilities designed with a fixed gross 

combustion turbine capacity of 464 MW (total for two turbines). As the plant is equipped for 

increased CO2 capture, moving from Case 2 D1A through Case 2 D4C, the TOC also increases

as a result of the need for larger components for power generation, while still maintaining the 

required gas turbine output. Hence, the increase in installed TOC per net kW delivered. 
Carbon Dioxide Capture Sensitivity Analysis

10

Exhibit ES-9 IGCC Total Overnight Cost

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

D1A 0% D1B 25% D2A 25% D2B 45% D2C 60% D2D 75% D3A 25% D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% D4B 95% D4C 97%

2,447

2,724 2,726

2,891

3,019

3,161

2,727

2,897 3,024

3,160

3,253 3,335

3,453 3,501 TOC, $/kW

Owner's Costs

Process Contingency

Project Contingency

Engr., Home Office, CM, and Fee

Bare Erected Cost

No WGS One WGS w/ Bypass Two WGS w/ Bypass Two WGS w/o Bypass

Cost of Electricity

The revenue requirement figure-of-merit in this report is the cost of electricity (COE) expressed 

in mills/kWh (numerically equivalent to $/MWh). The capital expenditure and operational 

periods for the SC PC and IGCC power plants are 5 and 30 years, respectively. The costs 

associated with CO2 transportation, storage, and monitoring (TS&M) are included for all capture 

cases. All costs are expressed in June 2007 dollars, and the resulting COE is also expressed in 

June 2007 year dollars.

The COE for the SC PC and GEE IGCC cases are presented in Exhibit ES-10 and Exhibit ES-11, 

respectively. These exhibits show the COE divided into five categories: (1) capital costs; (2) 

fixed costs; (3) variable costs; (4) fuel costs; and (5) CO2 TS&M costs. 

The COE estimates are based on capacity factors of 85 percent and 80 percent for the SC PC and 

GEE IGCC cases, respectively.
Carbon Dioxide Capture Sensitivity Analysis

11

Exhibit ES-10 Supercritical PC Cost of Electricity

0

20

40

60

80

100

120

140

Case 0 0% Case 1A 30% Case 1B 50% Case 1C 70% Case 1D 85% Case 1E 90% Case 1F 95% Case 1G 99%

58.9

76.6

84.4

92.8

101.5 104.3 107.0

112.7 COE, mills/kWh

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs

Capture with Bypass Capture without Bypass
Carbon Dioxide Capture Sensitivity Analysis

12

Exhibit ES-11 IGCC Cost of Electricity

0

20

40

60

80

100

120

140

D1A 0% D1B 25% D2A 25% D2B 45% D2C 60% D2D 75% D3A 25% D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% D4B 95% D4C 97%

76.3

85.3 85.4

90.8

95.2

100.0

85.4

91.0

95.3 100.0

103.1

105.7 109.3 110.8 COE, mills/kWh

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs

No WGS One WGS w/ Bypass Two WGS w/ Bypass Two WGS w/o Bypass

CO2 Avoided Costs

The CO2 avoided cost was calculated as illustrated in Equation 1.

(1)

CO Emissions CO Emissions tonnes MWh

COE COE MWh

Avoided Cost

reference with removal

with removal reference

{ } /

{ } $ /

2 2

The CO2 avoided costs for the SC PC and GEE IGCC cases are presented in Exhibit ES-12 and 

Exhibit ES-13, respectively. The SC PC cases use the corresponding non-capture SC PC 

reference. The IGCC cases are presented both relative to the equivalent IGCC without carbon 

capture and SC PC without capture plants. For the SC PC plant, the CO2 avoided costs decrease 

as the CO2 capture level increases until reaching minimum values at 95 percent capture (Case 

1F). 
Carbon Dioxide Capture Sensitivity Analysis

13

Exhibit ES-12 Supercritical PC CO2 Avoided Costs 

$0

$20

$40

$60

$80

$100

$120

$140

Case 1A 30% Case 1B 50% Case 1C 70% Case 1D 85% Case 1E 90% Case 1F 95% Case 1G 99%

103

79

69 67 66 65 68 C O2 Avoided Cost, $/tonne

Capture with Bypass Capture without Bypass

The CO2 avoided costs for the GEE IGCC cases decrease as the CO2 capture level increases,

until reaching minimum values at 85 to 90 percent capture (Cases D3E and D4A). As a result, 

this analysis concludes that 85 to 90 percent is the optimal CO2 capture level for a GEE IGCC 

power plant. 
Carbon Dioxide Capture Sensitivity Analysis

14

Exhibit ES-13 IGCC CO2 Avoided Costs

$0

$20

$40

$60

$80

$100

$120

$140

D1B 25% D2A 25% D2B 45% D2C 60% D2D 75% D3A 25% D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% D4B 95% D4C 97%

129 128

93

79

71

128

94

80

71

67 66 67 67

49 49

45 43 42

49

45 44 42 42 43 45 46 C O2 Avoided Cost, $/tonne

Relative to SCPC w/o CCS

Relative to IGCC w/o CCS

No WGS One WGS w/ Bypass Two WGS w/ Bypass Two WGS w/o Bypass

Cost and Performance Summary

The following conclusions can be drawn from this analysis.

At all levels of carbon capture considered in this analysis, an IGCC plant will operate 

more efficiently than a SC PC plant. This higher efficiency results in lower fuel costs 

and reduced coal handling costs for the same level of power output.

At lower levels of CO2 capture, the COE of a SC PC plant is less than an IGCC plant. 

However this COE advantage begins to disappear as capture level increases. For CCS 

greater than approximately 90 percent, IGCC and SC PC have costs of electricity that are 

nearly equal. This same trend applies to plant capital costs (expressed in $/kW).

CO2 avoided costs, using analogous non-capture plants as reference, are substantially 

lower for IGCC than for SC PC, for all levels of capture. This is reflective of the 

relatively lower cost impact associated with adding CO2 controls to an IGCC plant 

compared to SC PC. However, the avoided CO2 costs for IGCC capture plants, using the 

SC PC non-capture reference plant, are higher due to the higher COE of non-capture 

IGCC plants. 
Carbon Dioxide Capture Sensitivity Analysis

15

CO2 avoided costs for SC PC plants are high for low levels of CCS, and then start to 

diminish as the capture increases. Gradually, a minimum is reached around 95% CCS, 

before costs start to rise again slightly. This suggests that if a SC PC plant will lay out 

the additional capital required to install CO2 controls, that equipment could be used most 

cost-effectively by capturing as much carbon dioxide as possible (up to about 95%).

CO2 avoided costs for IGCC (relative to an IGCC non-capture plant) are less volatile than 

SC PC over a wide range of capture. Although they generally decrease as the level of 

CCS increases (similar to SC PC), the spread between the high and low values is small 

relative to SC PC. Since an IGCC system is a more complex process, it better lends itself 

to optimization than a SC PC plant. To accommodate the specified level of CO2 capture, 

there were numerous variables that were manipulated simultaneously (including the 

number of water gas shift reactors, the amount of shift steam required, solvent circulation 

rate, and the syngas bypass rate) to minimize the cost and performance impact. The SC 

PC plant, although in most cases less expensive than IGCC, is a simpler process and 

therefore exhibits less potential for optimization. 

A summary of SC PC and IGCC plant costs and performance are shown in Exhibit ES-14 and 

Exhibit ES-15, respectively. 
Carbon Dioxide Capture Sensitivity Analysis

16

Exhibit ES-14 Cost and Performance Results for the Supercritical PC Cases 

Case 0 1A 1B 1C 1D 1E 1F 1G

CO2 Capture, % 0% 30% 50% 70% 85% 90% 95% 99%

Gross Power Output, MWe 580.4 601.5 618.2 637.8 654.8 661.3 667.9 679.6

Net Power Output, MWe 550.0 550.0 550.0 550.0 550.1 550.0 550.0 550.0

Net Plant Efficiency, % (HHV) 39.3 35.2 32.9 30.6 28.9 28.2 27.5 25.7

Net Plant Heat Rate, Btu/kWh (HHV) 8,687 9,695 10,379 11,151 11,819 12,083 12,400 13,269

Coal Flowrate (lb/hr) 409,550 457,066 489,316 525,764 557,283 569,672 584,578 625,561

Total CO2 Captured, lb/MWhnet NA 588 1,057 1,582 2,037 2,213 2,398 2,674

CO2 Capture & Compression Cost, $x1000 NA $190,138 $266,902 $336,794 $441,781 $463,389 $485,273 $516,797

Total Plant Cost, $x1000 $905,901 $1,138,688 $1,258,942 $1,378,696 $1,525,453 $1,562,889 $1,602,389 $1,678,914

Owner’s Costs, $x1000 $207,800 $258,649 $285,448 $312,458 $344,744 $353,249 $362,267 $380,090

Total Overnight Cost, $x1000 $1,113,701 $1,397,338 $1,544,390 $1,691,155 $1,870,197 $1,916,138 $1,964,657 $2,059,004

Total Overnight Cost, $/kW $2,025 $2,541 $2,808 $3,075 $3,400 $3,484 $3,572 $3,744

Total As-Spent Capital, $x1000 $1,262,937 $1,592,965 $1,760,604 $1,927,917 $2,132,024 $2,184,397 $2,239,708 $2,347,264

Total As-Spent Capital, $/kW $2,296 $2,896 $3,201 $3,505 $3,876 $3,972 $4,072 $4,268

CO2 Capital Cost Penaltya, $/kW NA $516 $783 $1,050 $1,375 $1,459 $1,548 $1,719

Cost of Electricityb, mills/kWh 58.90 76.64 84.38 92.75 101.49 104.29 107.00 112.65

COE CO2 Penaltya, mills/kWh NA 17.7 25.5 33.8 42.6 45.4 48.1 53.8

Percent increase in COEa, % NA 30.1 43.3 57.5 72.3 77.1 81.7 91.3

Cost of CO2 Avoideda, $/tonne NA 102.8 79.1 69.2 67.2 65.9 64.7 68.2

CO2 Emissions, lb/MMBtu 203.2 142.9 101.7 61.7 31.2 20.4 10.2 2.0

CO2 Emissions, lb/MWhnet 1,765 1,385 1,055 687 369 246 126 27

SO2 Emissions, lb/MMBtu 0.086 0.064 0.050 0.036 0.017 0.017 0.016 0.016

SO2 Emissions, lb/MWh 0.75 0.570 0.460 0.340 0.170 0.170 0.170 0.170

NOx Emissions, lb/MMBtu 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070

NOx Emissions, lb/MWh 0.608 0.621 0.646 0.673 0.695 0.703 0.715 0.752

PM Emissions, lb/MMBtu 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013

PM Emissions, lb/MWh 0.113 0.115 0.120 0.125 0.129 0.131 0.133 0.140

Hg Emissions, lb/TBtu 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14

Hg Emissions, lb/TWh 9.93 10.1 10.6 11.0 11.3 11.5 11.7 12.3

Raw Water Withdrawal, gpm 5,394 6,245 6,987 8,386 9,615 10,095 10,512 11,664

Raw Water Consumption, gpm 4,301 4,898 5,433 6,474 7,392 7,753 8,074 8,961

Raw Water Consumption, gal/MWhnet 469 534 593 706 806 846 881 978

a

 Relative to Case 0 (SC PC without capture from 2010 Bituminous Baseline study)

b

 Capacity factor is 85% for the SC PC cases
Carbon Dioxide Capture Sensitivity Analysis

17

Exhibit ES-15 Cost and Performance Results for the GEE IGCC Cases

Case 2-D1A 2-D1B 2-D2A 2-D2B 2-D2C 2-D2D 2-D3A 2-D3B 2-D3C 2-D3D 2-D3E 2-D4A 2-D4B 2-D4C

CO2 Capture, % 0% 25% 25% 45% 60% 75% 25% 45% 60% 75% 85% 90% 95% 97%

Gross Power Output, MWe 747.8 750.4 750.4 746.9 745.2 742.0 750.4 746.2 744.2 741.6 739.8 734.0 726.6 723.6

Net Power Output, MWe 622.0 607.2 607.0 590.8 578.4 563.9 607.0 590.0 577.4 563.8 554.5 543.2 528.5 522.9

Net Plant Efficiency, % (HHV) 39.0 38.4 38.4 36.8 35.5 34.3 38.4 36.7 35.5 34.2 33.4 32.6 31.8 31.5

Net Plant Heat Rate, Btu/kWh (HHV) 8,756 8,891 8,895 9,283 9,604 9,958 8,894 9,289 9,614 9,969 10,222 10,459 10,731 10,840

Coal Flowrate (lb/hr) 466,861 462,752 462,861 470,117 476,133 481,355 462,783 469,844 475,867 481,779 485,836 487,026 486,169 485,856

Total CO2 Captured, lb/MWhnet NA 425 430 809 1,127 1,476 429 810 1,125 1,467 1,710 1,899 2,159 2,269

CO2 Capture & Compression Cost, $x1000 0 $166,439 $166,741 $193,350 $212,092 $231,604 $167,196 $194,185 $212,378 $230,775 $242,919 $251,958 $264,505 $228,358

Total Plant Cost, $x1000 $1,235,944 $1,345,298 $1,346,066 $1,389,128 $1,419,771 $1,449,191 $1,346,380 $1,390,235 $1,419,640 $1,447,904 $1,465,871 $1,472,866 $1,483,871 $1,488,149

Owner’s Costs, $x1000 $286,161 $308,679 $308,860 $319,113 $326,535 $333,624 $308,914 $319,358 $326,551 $333,508 $337,972 $338,851 $341,323 $342,287

Total Overnight Cost, $x1000 $1,522,105 $1,653,977 $1,654,925 $1,708,241 $1,746,306 $1,782,815 $1,655,294 $1,709,592 $1,746,192 $1,781,411 $1,803,843 $1,811,717 $1,825,194 $1,830,436

Total Overnight Cost, $/kW $2,447 $2,724 $2,726 $2,891 $3,019 $3,161 $2,727 $2,897 $3,024 $3,160 $3,253 $3,335 $3,453 $3,501

Total As-Spent Capital, $x1000 $1,735,200 $1,885,534 $1,886,615 $1,947,394 $1,990,789 $2,032,409 $1,887,035 $1,948,935 $1,990,658 $2,030,809 $2,056,381 $2,065,358 $2,080,721 $2,086,697

Total As-Spent Capital, $/kW $2,790 $3,105 $3,108 $3,296 $3,442 $3,604 $3,109 $3,303 $3,447 $3,602 $3,709 $3,802 $3,937 $3,991

CO2 Capital Cost Penaltya, $/kW $0 $277 $279 $444 $572 $715 $280 $450 $577 $713 $806 $888 $1,007 $1,054

Cost of Electricityb, mills/kWh 76.3 85.3 85.4 90.8 95.2 100.0 85.4 91.0 95.3 100.0 103.1 105.7 109.3 110.8

COE CO2 Penaltya, mills/kWh NA 9.0 9.1 14.5 18.9 23.7 9.1 14.7 19.0 23.7 26.8 29.4 33.0 34.4

Percent increase in COEa, % NA 11.8% 11.9% 19.0% 24.7% 31.0% 12.0% 19.2% 24.9% 31.0% 35.1% 38.5% 43.3% 45.1%

Cost of CO2 Avoideda, $/tonne NA 48.7 48.6 44.9 43.1 42.5 48.7 45.4 43.6 42.5 41.7 42.7 45.2 46.0

CO2 Emissions, lb/MMBtu 196.8 147.8 147.3 108.8 78.9 49.7 147.3 108.8 79.2 49.7 30.1 19.7 10.4 6.5

CO2 Emissions, lb/MWhnet 1,723 1,314 1,310 1,010 758 495 1,310 1,011 762 496 308 206 112 71

SO2 Emissions, lb/MMBtu 0.005 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002

SO2 Emissions, lb/MWh 0.040 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020

NOx Emissions, lb/MMBtu 0.059 0.055 0.055 0.053 0.051 0.050 0.055 0.053 0.052 0.050 0.049 0.049 0.049 0.049

NOx Emissions, lb/MWh 0.430 0.397 0.397 0.390 0.384 0.379 0.397 0.391 0.385 0.379 0.375 0.376 0.380 0.382

PM Emissions, lb/MMBtu 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071

PM Emissions, lb/MWh 0.052 0.051 0.051 0.052 0.053 0.054 0.051 0.052 0.053 0.054 0.054 0.055 0.055 0.056

Hg Emissions, lb/TBtu 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571

Hg Emissions, lb/TWh 4.16 4.11 4.11 4.20 4.26 4.32 4.11 4.20 4.26 4.33 4.38 4.42 4.46 4.48

Raw Water Withdrawal, gpm 4,734 4,692 4,697 5,038 5,300 5,530 4,695 5,040 5,307 5,569 5,748 5,817 5,739 5,707

Raw Water Consumption, gpm 3,755 3,722 3,727 4,033 4,270 4,481 3,725 4,034 4,276 4,514 4,677 4,741 4,679 4,654

Raw Water Consumption, gal/MWhnet 362 368 368 410 443 477 368 410 444 480 506 524 531 534

a

 Relative to Case 2 D1A (0% CO2 capture)

b

 Capacity factor is 80% for the GEE IGCC cases
Carbon Dioxide Capture Sensitivity Analysis

18

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Carbon Dioxide Capture Sensitivity Analysis

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1. Introduction

1.1 Study Background

Coal-fired power plants account for approximately 50 percent of the power generation in the 

United States and approximately 80 percent of the greenhouse gas (GHG) emissions produced by 

the power generation sector [6]. Because coal-fired power generation is such a large contributor 

to both national energy security and overall GHG emissions, it is important to develop methods 

for reducing the carbon footprint of coal-fired power plants to mitigate environmental concerns 

while continuing to reliably satisfy power demand. The effects of GHG reduction in the power 

industry could even be felt in the transportation industry if plug-in hybrid electric vehicles, 

fueled by low-GHG power, play a larger role in the overall transportation fleet.

Levels of CO2 in the atmosphere have shown a steady rise from approximately 300 ppm in 1940 

to more than 390 ppm in 2010 [7]. At the same time, various studies have documented 

noticeable changes in the earth‟s climate during recent years, and model predictions suggest that 

CO2 levels play a role in these climate changes [8]. Given the potential implications surrounding 

global climate change and increasing concentrations of CO2 in the atmosphere, technology and 

policy options are being investigated for avoiding CO2 emissions. 

The U.S. Department of Energy (DOE) seeks to develop technology capable of capturing and 

sequestering 90 percent of the CO2 produced in pulverized coal (PC) and integrated gasification 

combined cycle (IGCC) power plants that can achieve a significantly lower cost of electricity 

relative to the conventional technology components portrayed in this analysis. 

1.2 Project Objectives

The study objective was to identify the optimal CO2 capture level at new SC PC and IGCC

power plants by employing state-of-the-art control technologies in multiple process 

configurations. 

The objective of Case 1 is to evaluate the technical and economic performance of a new SC PC 

power plant equipped with Econamine FG PlusSM for post-combustion CO2 capture in the 

following increments: 30, 50, 70, 85, 90, 95, and 99 percent capture. More detailed, predictive 

acid gas removal (AGR) modeling is utilized to more accurately represent the performance of the 

CO2 separation process, and to determine if an optimum level of control exists. This case also 

includes verification (via literature search) that less than 90 percent CO2 capture is most 

economical using a „slip-stream‟ approach.

The Case 2 objective is to evaluate the technical and economic performance of four designs for a 

new General Electric Energy (GEE) IGCC power plant with pre-combustion CO2 capture using a 

physical solvent-based SelexolTM system:

Design 1 (D1) has no water gas shift (WGS) reactor. The minimum (0 percent) and 

maximum (25 percent) CO2 capture levels for this particular configuration are
Carbon Dioxide Capture Sensitivity Analysis

20

modeled. Due to the high level of integration between the H2S and CO2 absorbers, it 

was not feasible to model no CO2 capture with a two-stage SelexolTM system. 

Consequently, D1A (0 percent capture) employs a one-stage SelexolTM unit for 

hydrogen sulfide (H2S) control, while D1B (25 percent capture) utilizes a two-stage 

SelexolTM unit to maximize CO2 capture from the unshifted syngas. D1 includes a 

carbonyl sulfide (COS) hydrolysis unit to treat the entire syngas stream.

Design 2 (D2) has one-stage WGS with CO2 capture ranging from 25 percent (upper 

limit from D1) to the maximum achievable limit for this particular configuration (75

percent) by varying the WGS bypass ratio and the two-stage SelexolTM CO2 removal 

efficiency. The SelexolTM removal efficiency is changed by varying the solvent 

circulation rate, which changes the size and cost of the SelexolTM system. The 

combined syngas stream (shifted and unshifted gas) is routed through a COS 

hydrolysis unit.

Design 3 (D3) has two-stage WGS with CO2 capture ranging from 25 percent (upper 

limit from D1) to the maximum achievable limit for this particular configuration (85

percent) by varying the WGS bypass ratio and the two-stage SelexolTM CO2 removal 

efficiency. The SelexolTM removal efficiency is changed by varying the solvent 

circulation rate, which changes the size and cost of the SelexolTM system. The WGS 

bypass stream passes through a COS hydrolysis unit.

Design 4 (D4) has two-stage WGS and no bypass with CO2 capture ranging from 90 

to 97 percent. To achieve greater than 90 percent CO2 removal, the two-stage 

SelexolTM CO2 removal efficiency is increased by raising the solvent circulation rate, 

which increases the size and cost of the SelexolTM system. D4 does not include a 

COS hydrolysis unit since sufficient COS to H2S conversion occurs across the two 

WGS reactors. 

The facilities will be located in the Illinois coal basin using high-sulfur bituminous Illinois No. 6 

coal as the feedstock to produce electric power. The study includes compression of the captured 

CO2 to pipeline pressure (2,215 psia), pipeline transport 80 kilometers (50 miles), storage in a 

saline formation at a depth of 1,239 meters (4,055 ft), and monitoring for 80 years. The site will 

have appropriate access to rail transportation for delivery of coal. All local coal handling 

facilities will be included in the design and cost estimation portion of this study.
Carbon Dioxide Capture Sensitivity Analysis

21

2. General Evaluation Basis

For Case 1, an Aspen model for a SC PC power plant, coupled with detailed simulations of the 

Econamine FG PlusSM process using Optimized Gas Treating‟s ProTreatTM, was utilized to 

evaluate the technical and economic performance of post-combustion CO2 capture in the 

following increments: 30, 50, 70, 85, 90, 95, and 99 percent capture. The Case 1 SC PC

descriptions are summarized in Exhibit 2-1.

Exhibit 2-1 Case 1 Supercritical PC Plant Configuration Summary

Case CO2

Capture

Intended 

Storage Boiler Steam psig/°F/°F Oxidant NOx Control Sulfur Control

1A 30%

Saline 

Formation

Wall-fired, 

PC 3500/1100/1100 Air LNB/OFA/SCR 0.07 lb/MMBtu

Wet FGD

0.1 lb/MMBtu

1B 50%

1C 70%

1D 85%

1E 90%

1F 95%

1G 99%

Optimized Gas Treating‟s rate-based ProTreatTM software was used to generate performance 

estimates for the Econamine FG PlusSM process. Initially, 90 percent CO2 removal was modeled 

by adjusting three key process parameters: (1) the circulation rate for the 30 wt% 

monoethanolamine (MEA) solution; (2) the reboiler steam flow rate; and (3) the height of 

packing material in the absorption and stripping columns. For greater than 90 percent CO2

removal, the MEA and reboiler steam flow rates were increased, while the packing height in the 

absorption and stripping columns was also raised to model 99 percent CO2 removal.

A literature search was conducted to verify that <90 percent CO2 capture is most economical 

using a “slip-stream” (or bypass) approach. Indeed, the slip-stream approach is more costeffective for <90 percent CO2 capture than removing reduced CO2 fractions from the entire flue 

gas stream, according to multiple peer-reviewed studies [1, 2, 3]. The cost of CO2 capture with 

the Econamine process is dependent on the volume of gas being treated and a reduction in flue 

gas flow rate will (1) decrease the quantity of energy consumed by flue gas blowers; (2) reduce 

the size of the CO2 absorption columns; (3) trim the cooling water requirement of the direct 

contact cooling system; and (4) decrease the amount of fan power required to increase flue gas 

temperature and plume buoyancy. As a result, the „slip-stream‟ approach for <90 percent CO2

capture leads to lower capital and operating costs. Consequently, less than 90 percent CO2

removal was modeled by bypassing a portion of the flue gas around the Econamine system. 

Thus, for these cases the inlet flue gas flow rate was adjusted in ProTreatTM, along with the MEA 

and reboiler steam flow rates, to simulate CO2 removals ranging from 30 percent to 85 percent. 
Carbon Dioxide Capture Sensitivity Analysis

22

For each case, the CO2 removal efficiency and reboiler steam duty obtained from ProTreatTM 

were incorporated into the complete SC PC power plant Aspen model to determine the coal feed 

rate required to maintain a net electric generation capacity of 550 MWe. This approach allows 

for an equitable comparison of the seven CO2 capture cases.

Due to the range of CO2 capture levels analyzed in Case 1, the Econamine capital and operating 

costs vary for the seven cases. While a factored approach that relies on the quantity of CO2

captured for equipment sizing and cost estimation was employed, the cost estimates for the 

Econamine system were also developed based, in part, on output data from the ProTreatTM 

simulations. In particular, the ProTreatTM model output provided absorption and stripping 

column diameters for each case, which were used to determine the required number of

absorption trains.

For this analysis, it was assumed that the maximum absorption column diameter is 20 meters, 

based on information released by Fluor [4]. As a result, cost estimates for three CO2 capture 

levels – 30 percent (1A), 50 percent (1B), and 70 percent (1C) – are based on a single absorption 

and compression train. To calculate the capital cost for a single absorption train, it was assumed 

that the absorption columns represent 40 percent of the total capital cost for a two-train 

Econamine system.

For Case 2, an Aspen model for a GEE IGCC power plant, coupled with analysis of different 

process configurations (i.e., water gas shift bypass ratio and SelexolTM CO2 removal efficiency), 

was utilized to evaluate the technical and economic performance of pre-combustion CO2 capture 

for the four plant designs:

D1 has no WGS reactor. The minimum (0 percent) and maximum (25 percent) CO2

capture levels for this particular configuration are modeled. Due to the high level of 

integration between the H2S and CO2 absorbers, it is not feasible to model no CO2

capture with a two-stage SelexolTM system. Consequently, D1A (0 percent capture) 

employs a one-stage SelexolTM unit for H2S control, while D1B (25 percent capture) 

utilizes a two-stage SelexolTM unit to maximize CO2 capture from the unshifted 

syngas. D1 includes a COS hydrolysis unit to treat the entire syngas stream.

D2 has one-stage WGS with CO2 capture ranging from 25 percent (upper limit from 

D1) to the maximum achievable limit for this particular configuration (75 percent) by 

varying the WGS bypass ratio and the two-stage SelexolTM CO2 removal efficiency. 

The SelexolTM removal efficiency is changed by varying the solvent circulation rate, 

which changes the size and cost of the SelexolTM system. The combined syngas 

stream (shifted and unshifted gas) is routed through a COS hydrolysis unit.

D3 has two-stage WGS with CO2 capture ranging from 25 percent (upper limit from 

D1) to the maximum achievable limit for this particular configuration (85 percent) by 

varying the WGS bypass ratio and the two-stage SelexolTM CO2 removal efficiency. 

The SelexolTM removal efficiency is changed by varying the solvent circulation rate, 

which changes the size and cost of the SelexolTM system. The WGS bypass stream 

passes through a COS hydrolysis unit.

D4 has two-stage WGS and no bypass with CO2 capture ranging from 90 to 97

percent. To achieve greater than 90 percent CO2 removal, the two-stage SelexolTM 
Carbon Dioxide Capture Sensitivity Analysis

23

CO2 removal efficiency is increased by raising the solvent circulation rate, which 

increases the size and cost of the SelexolTM system. D4 does not include a COS 

hydrolysis unit since sufficient COS to H2S conversion occurs across the two WGS 

reactors. 

The Case 2 IGCC design descriptions are summarized in Exhibit 2-2. 

Exhibit 2-2 Case 2 GEE IGCC Plant Configuration Summary

Case CO2

Capture

CO2

Separation

Intended 

Storage Gasifier Steam psig/°F/°F Oxidant WGS Sulfur Control

D1A 0% N/A N/A

GEE

Radiant 

Only

1800/1050/1050 95 mol% 

O2

N/A

SelexolTM

D1B 25%

SelexolTM 

2

nd Stage

Saline 

Formation

N/A

D2A 25%

One-Stage 

with 

bypass

D2B 45%

D2C 60%

D2D 75%

D3A 25%

Two-Stage 

with 

bypass

D3B 45%

D3C 60%

D3D 75%

D3E 85%

D4A 90% Two-Stage 

without 

bypass

D4B 95%

D4C 97%

To determine the process configurations for less than 90 percent CO2 removal (IGCC D2 and 

D3), the WGS bypass ratio and SelexolTM CO2 removal efficiency were varied over a series of 

Aspen simulations of the entire GEE IGCC power plant to evaluate the impact on WGS and 

SelexolTM costs and net plant efficiency. As a starting point, the SelexolTM CO2 removal 

efficiency (92.4 percent) used to model 90 percent CO2 removal was fixed [5], and the WGS 

bypass ratio was adjusted to achieve the desired level of capture. The CO2 removal level was 

then held constant by decreasing both the WGS bypass ratio (i.e., routing more syngas through 

the WGS reactor(s)) and the SelexolTM CO2 removal efficiency. These step changes in the WGS 

bypass ratio lead to an increase in CO2 partial pressure, which relaxes the CO2 removal required 

by the SelexolTM process.

As shown in Exhibit 2-3, the cost of the WGS system decreases as the WGS bypass ratio 

increases since the quantity of syngas being shifted declines. The SelexolTM system cost 

increases with the WGS bypass ratio since a higher solvent circulation rate is required to 

maintain 60 percent CO2 removal as the CO2 partial pressure at the SelexolTM inlet decreases. 

However, the total cost of the WGS and SelexolTM systems, which is dominated by the cost of 

the SelexolTM system, gradually increases with the WGS bypass ratio. Meanwhile, the net plant 
Carbon Dioxide Capture Sensitivity Analysis

24

higher heating value (HHV) efficiency passes through a maximum value over the range of WGS 

bypass ratios. As a result, the WGS bypass ratios and SelexolTM CO2 removal efficiencies used 

to model less than 90 percent CO2 removal in this study (IGCC D2 and D3) correspond to the 

maximum net plant HHV efficiency. 

Exhibit 2-3 Net Efficiency and Cost as a Function of WGS Bypass Ratio for 60% CO2 Removal with 

IGCC Design 3

3 4

34.2

34.4

34.6

34.8

3 5

35.2

35.4

35.6

35.8

3 6

$ 0

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

$140,000

$160,000

$180,000

0 0.1 0.2 0.3 0.4 0.5

Net Plant HHV Efficiency, %

Capital Cost, $000

WGS Bypass Ratio

Total Cost

Selexol Cost

WGS Cost

Efficiency

This procedure was repeated for each level of total CO2 removal analyzed for IGCC D2 and D3 

to determine the optimal WGS bypass ratio and SelexolTM CO2 removal efficiency for these 

intermediate capture points. Data for these optimal configurations is provided in Exhibit 2-4 and 

Exhibit 2-5 for IGCC D2 and D3, respectively. These results indicate that the SelexolTM CO2

removal efficiency increases with CO2 partial pressure, which is the expected trend with a 

physical solvent-based system. 

Exhibit 2-4 Process Configurations for IGCC D2

Total CO2

Removal (%) WGS WGS Bypass Ratio (%)

SelexolTM CO2

Removal (%) PCO2 (psia)

25

One-Stage 

with Bypass

99.5 85.8 119.4

45 60 89 186.3

60 28.75 89.5 229.8

75 0 91 265.5
Carbon Dioxide Capture Sensitivity Analysis

25

Exhibit 2-5 Process Configurations for IGCC D3

Total CO2

Removal (%) WGS WGS Bypass Ratio (%)

SelexolTM CO2

Removal (%) PCO2 (psia)

25

Two-Stage 

with Bypass

99.75 86.31 119.7

45 69.4 90.04 186.5

60 45 90.1 230.1

75 21 90.4 264.3

85 5 90.52 289.3

A typical offering from a commercial catalyst vendor is a S:DG molar ratio of 0.3 at the outlet of 

the final WGS reactor. However, for less than 90 percent CO2 capture (IGCC D2 and D3), this 

study uses a S:DG molar ratio of 0.25 at the outlet of the final WGS reactor. Operating with a 

lower S:DG ratio impedes the kinetics of CO to CO2 conversion. Consequently, larger and more 

costly WGS reactors are required for a similar degree of conversion. Although a reduction in 

S:DG ratio requires a larger reactor volume (this analysis assumes a volume increase of 30

percent, and subsequently a 30 percent increase in reactor cost), the benefit of steam savings –

which can then expanded through the steam turbine to produce additional power – is more than 

adequate to offset the increase in capital cost. 

Thermal input to the IGCC plant is used to fully-load the combustion turbines. Any remaining 

energy in the combustion turbine exhaust is extracted to the maximum extent possible in a heat 

recovery steam generator in order to raise steam to generate additional power. The net power for 

the IGCC cases ranges from 523 to 622 MW. The range in net output is caused by the wide 

variance of CO2 capture imposed from case-to-case. The differences in auxiliary loads are 

primarily attributed to CO2 compression and the need for extraction steam in the WGS reactions, 

which reduces steam turbine output. 

For each of the plant configurations in this study, an Aspen model was developed and used to 

generate material and energy balances. The material and energy balances were used as the basis 

for generating the capital and operating cost estimates. 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 provides details on the site characteristics, coal characteristics and 

costs, the study environmental targets, assumed capacity factor, raw water usage, and the cost

estimating methodology.

2.1 Site Characteristics

The SC PC and GEE IGCC plants are assumed to be located at a generic site in the midwestern 

United States. The ambient conditions, consistent with the International Standard Organization 

(ISO) [9], and site characteristics are presented in Exhibit 2-6 and Exhibit 2-7, respectively. 
Carbon Dioxide Capture Sensitivity Analysis

26

Exhibit 2-6 Site Ambient Conditions

Elevation, ft 0

Barometric Pressure, psia 14.696

Design Ambient Temperature, Dry Bulb, F 59

Design Ambient Temperature, Wet Bulb, F 51.5

Design Ambient Relative Humidity, % 60

Exhibit 2-7 Site Characteristics

Location Greenfield, midwestern United States1

Topography Level

Size, acres 300

Transportation Rail

Ash Disposal Off Site

Water Municipal (50%) / Groundwater (50%)

Access Land locked, having also access by train and highway

CO2

Compressed to 15.3 MPa (2,215 psia), transported 50 

miles and sequestered in a saline formation at a depth of 

4,055 feet

1 Champaign County, Illinois, is assumed for assessment of construction costs. 

The following design parameters will be considered site-specific, and will not be quantified for 

this study. Allowances for normal conditions and construction will be included in the cost 

estimates.

Flood plain considerations

Existing soil/site conditions

Water discharges and reuse

Rainfall/snowfall criteria

Seismic design

Buildings/enclosures

Fire protection

Local code height requirements

Noise regulations – Impact on site and surrounding area
Carbon Dioxide Capture Sensitivity Analysis

27

2.2 Coal Characteristics and Cost

The design coal characteristics are presented in Exhibit 2-8. All cases in this study were 

modeled using Illinois No. 6 bituminous coal.

Exhibit 2-8 Design Coal

Coal seam nomenclature Herrin (No. 6)

Coal name Illinois No. 6 

Mine Old Ben No. 26

ASTM D388 Rank High Volatile A Bituminous

Proximate Analysis As-Received Dry

Moisture 11.12% 0.00%

Volatile Matter 34.99% 39.37%

Ash 9.70% 10.91%

Fixed Carbon 44.19% 49.72%

Total 100.00% 100.00%

Ultimate Analysis As-Received Dry

Carbon 63.75% 71.73%

Hydrogen 4.50% 5.06%

Nitrogen 1.25% 1.41%

Sulfur 2.51% 2.82%

Chlorine 0.29% 0.33%

Ash 9.70% 10.91%

Moisture 11.12% 0.00%

Oxygen 6.88% 7.74%

Total 100.00% 100.00%

Reported Heating Value As-Received Dry

HHV (Btu/lb) 11,666 13,126

LHV (Btu/lb) 11,252 12,660

HHV (kJ/kg) 27,135 30,531

LHV (kJ/kg) 26,171 29,447
Carbon Dioxide Capture Sensitivity Analysis

28

Exhibit 2-8 Design Coal (continued)

Typical Ash Mineral Analysis

Silica SiO2 45.0%

Aluminum Oxide Al2O3 18.0%

Titanium Dioxide TiO2 1.0%

Iron Oxide Fe2O3 20.0%

Calcium Oxide CaO 7.0%

Magnesium Oxide MgO 1.0%

Sodium Oxide Na2O 0.6%

Potassium Oxide K2O 1.9%

Phosphorus Pentoxide P2O5 0.2%

Sulfur Trioxide SO3 3.5%

Undetermined 1.8%

Total 100.0%

Typical Ash Fusion Temperatures (°F)

Reducing

Initial – Limited deformation 1950 oF

Softening H=W 2030 oF

Hemispherical H=1/2W 2140 oF

Fluid 2150 oF

Oxidizing

Initial – Limited deformation 2250 oF

Softening H=W 2300 oF

Hemispherical H=1/2W 2430 oF

Fluid 2450 oF

Hardgrove Grindability Index 60 HGI
Carbon Dioxide Capture Sensitivity Analysis

29

Exhibit 2-8 Design Coal (continued)

Average Trace Element Composition of Coal Shipped by 

Illinois Mines, Dry basis, ppm

Trace Element Arithmetic

Mean

Standard 

Deviation

Arsenic As 7.5 8.1

Boron B 90 45

Beryllium Be 1.2 0.7

Cadmium Cd 0.5 0.9

Chlorine Cl 1671 1189

Cobalt Co 3.5 1.3

Chromium Cr 14 6

Copper Cu 9.2 2.5

Fluorine F 93 36

Mercury Hg 0.09 0.06

Lithium Li 9.4 7.1

Manganese Mn 38 32

Molybdenum Mo 8.4 5.7

Nickel Ni 14 5

Phosphorus Ph 87 83

Lead Pb 24 21

Tin Sb 0.9 0.7

Selenium Se 1.9 0.9

Thorium Th 1.5 0.4

Uranium Ur 2.2 1.9

Vanadium V 31 16

Zinc Zn 84.4 84.2

Note: Average trace element composition of coal shipped by Illinois mines is based on 34 

samples, 2004 Keystone Coal Industry Manual [10]

The mercury content in the Illinois No. 6 coal is reported as an arithmetic mean value of 

0.09 ppm (dry basis) with standard deviation of 0.06. Hence, as illustrated in Exhibit 2-9, there 

is a 50 percent probability that the mercury content in the Illinois No. 6 coal would not exceed 

0.09 ppm (dry basis), and 99.9 percent probability that the mercury content in the Illinois No. 6 

coal would not exceed 0.28 ppm (dry basis).
Carbon Dioxide Capture Sensitivity Analysis

30

Exhibit 2-9 Probability Distribution of Mercury Concentration in the Illinois No. 6 Coal

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 P:\X_GEMSET\0_GEMSET Fuels Price Database\Rev.0 Fuels\[IllinoisNo6 Mercury.xls] Rev. 00 11/21/05 10:55AM

Arithmetic Mean = 0.09 ppm db

Standard Deviation = 0.06 ppm db

Source: 2004 Keystone Coal Industry Manual, Mining Media Publication

For the cases in this study, coal mercury content was assumed to be equal to the arithmetic mean 

mercury concentration plus one standard deviation, or 0.15 ppmd. About 84 percent of the coal 

samples represented in Exhibit 2-9 have a mercury concentration equal to or less than 0.15

ppmd.

The coal cost used in this study is $1.55/GJ ($1.64/MMBtu) (2007 cost of coal in June 2007 

dollars). This cost was determined using the following information from the EIA 2008 AEO:

The 2007 minemouth cost of Illinois No. 6 in 2006 dollars, $32.66/tonne 

($29.63/ton), was obtained from Supplemental Table 112 of the EIA‟s 2008 AEO for 

eastern interior high-sulfur bituminous coal.

The cost of Illinois No. 6 coal was escalated to 2007 dollars using the gross domestic 

product (GDP) chain-type price index from AEO 2008, resulting in a price of 

$33.67/tonne ($30.55/ton) [11]. 

Transportation costs for Illinois No. 6 were estimated to be 25 percent of the minemouth cost 

based on the average transportation rate of the respective coals to the surrounding regions [12]. 

The final delivered costs for Illinois No. 6 coal used in the calculations is $42.09/tonne 

($38.18/ton) or $1.55/GJ ($1.64/MMBtu). (Note: The Illinois No. 6 coal cost of 

$1.6366/MMBtu was used in calculations, but only two decimal places are shown in the report.) 
Carbon Dioxide Capture Sensitivity Analysis

31

2.3 Design Sorbent Composition

Limestone from Greer Limestone mine in Morgantown, WV, is assumed as a design sorbent for 

the SC PC plant [13]. Sorbent is delivered to plant storage by truck. Limestone analysis is 

presented in Exhibit 2-10.

Exhibit 2-10 Sorbent Analysis

Supplier Greer Industries, Inc. Analysis, %

Calcium Carbonate CaCO3 80.40

Magnesium Carbonate MgCO3 3.50

Silica SiO2 10.32

Aluminum Oxide Al2O3 3.16

Iron Oxide Fe2O3 1.24

Sodium Oxide Na2O 0.23

Potassium Oxide K2O 0.72

Balance 0.43

Total 100.00

2.4 Environmental Targets

In setting the environmental targets, a number of factors were considered, including current 

emission regulations, regulation trends, results from recent permitting activities, and the status of 

current best available control technology (BACT).

The current federal regulation governing new fossil-fuel fired electric utility steam generating 

units is the New Source Performance Standards (NSPS) as amended in June 2007 and shown in 

Exhibit 2-11. This represents the minimum level of control that would be required for a new 

fossil energy plant [14]. Stationary combustion turbine emission limits are further defined in 40 

CFR Part 60, Subpart KKKK.

The new NSPS standards apply to units with the capacity to generate greater than 73 MW of 

power by burning fossil fuels, as well as cogeneration units that sell more than 25 MW of power 

and more than one-third of their potential output capacity to any utility power distribution 

system. In cases where both an emission limit and a percent reduction are presented, the unit has 

the option of meeting one or the other. All limits with the unit lb/MWh are based on gross power 

output.
Carbon Dioxide Capture Sensitivity Analysis

32

Exhibit 2-11 Standards of Performance for Electric Utility Steam Generating Units

Built, Reconstructed, or Modified After February 28, 2005

New Units Reconstructed Units Modified Units

Emission 

Limit

% 

Reduction

Emission 

Limit 

(lb/MMBtu)

% 

Reduction

Emission 

Limit

(lb/MMBtu)

% 

Reduction

PM 0.015 

lb/MMBtu 99.9 0.015 99.9 0.015 99.8

SO2 1.4 lb/MWh 95 0.15 95 0.15 90

NOx 1.0 lb/MWh N/A 0.11 N/A 0.15 N/A

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 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 (non-attainment areas). The Clean Air Act authorizes EPA 

to establish regulations to prevent significant deterioration of air quality due to emissions of any 

pollutant for which a national ambient air quality standard (NAAQS) has been promulgated. 

Environmental area designation varies by county and can be established only for a specific site 

location. Based on the EPA Green Book Non-attainment Area Map , relatively few areas in the 

midwestern United States are classified as “non-attainment”, and therefore BACT is chosen here 

rather than LAER [15]. 

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 study. For the purpose of this study, BACT was assumed to be adequate.

2.4.1 Supercritical PC Plant

The environmental approach for this study was to evaluate each case on the same regulatory 

design basis. A BACT approach was taken and used uniformly throughout the study. The 

BACT technologies assumed for this study meet the emission requirements of the 2006 NSPS. 

The emissions controls employed and the environmental targets are shown in Exhibit 2-12.

The environmental target represents the maximum allowable emissions. In some cases actual 

emissions are less than the target. For example, amine-based CO2 capture requires a polishing 

scrubber to reduce SO2 concentrations to less than 10 ppmv. As a result, the SO2 emissions are 

substantially less than the environmental target.
Carbon Dioxide Capture Sensitivity Analysis

33

Exhibit 2-12 Environmental Targets for PC Cases

Technology Pulverized Coal Boilers

Sulfur Control Technology Wet Limestone FGD

Sulfur Limits 98% efficiency or

≤ 0.10 lb SO2/106Btu

NOx Control Technology LNB w/OFA (or OFO) and SCR in 

air-based cases

NOx Limits 0.07 lb/106Btu

PM Control Technology Fabric Filter

PM Limits 99.8% or ≤ 0.015 lb/106Btu

Hg Control Technology Co-benefit capture

Hg Limits 90% removal

2.4.2 GEE IGCC Plant

The IGCC environmental targets were chosen to match the Electric Power Research Institute‟s

(EPRI) design basis for their CoalFleet for Tomorrow Initiative and are shown in Exhibit 2-13

[16]. EPRI notes that these are design targets and are not to be used for permitting values.

The BACT emission limits assumed for this study exceed the emission requirements of the NSPS 

as amended in June 2007 [14]. It is possible that state and local requirements could supersede 

NSPS or BACT and impose even more stringent requirements. 

Exhibit 2-13 Environmental Targets for IGCC Cases

Pollutant Environmental 

Target

NSPS 

Limit

Control 

Technology

NOx

15 ppm (dry) @ 

15% O2

1.0 

lb/MWh

Low-NOx burners 

and syngas 

nitrogen dilution

SO2 0.0128 lb/MMBtu 1.4 

lb/MWh SelexolTM or MDEA

Particulate 

Matter 

(Filterable) 

0.0071 lb/MMBtu 0.015 

lb/MMBtu

Quench and water 

scrubber

Mercury > 90% capture 20 x 10-6 

lb/MWh Carbon bed

2.4.3 Carbon Dioxide

CO2 is not currently regulated. However, the possibility exists that carbon limits will be imposed 

in the future, and this study examines cases that include a reduction in CO2 emissions. Because 
Carbon Dioxide Capture Sensitivity Analysis

34

the form of emission limits, should they be imposed, is not known, CO2 emissions are reported 

on both a lb/(gross) MWh and lb/(net) MWh basis in each emissions table.

For the SC PC cases, it is assumed that all of the fuel carbon is converted to CO2 in the flue gas. 

This study analyzes a wide range of CO2 removal efficiencies by bypassing a portion of the flue 

gas around the amine-based Econamine FG PlusSM process.

For the IGCC cases, this study analyzes a wide range of CO2 removal efficiencies, based on 

carbon input in the coal and excluding carbon that exits with the gasifier slag, by investigating 

various process configurations. Process parameters manipulated to control the level of total CO2

removal include the number of WGS reactors employed, WGS bypass ratio, S:DG ratio at the 

WGS outlet, and the SelexolTM CO2 removal efficiency. 

2.5 Capacity Factor

This study assumes that each new plant would be dispatched any time it is available and would 

be capable of generating maximum capacity when online; therefore, capacity factor and 

availability are equal. The availability for combustion cases was determined using the 

Generating Availability Data System (GADS) from the North American Electric Reliability 

Council (NERC) [17]. Since there are only two operating IGCC plants in North America, the 

same database was not useful for determining IGCC availability. Rather, input from EPRI and 

their work on the CoalFleet for Tomorrow Initiative were used to set the IGCC case capacity 

factor.

NERC defines an equivalent availability factor (EAF) as a measure of the plant capacity factor 

assuming there is always a demand for the output. The EAF accounts for planned and scheduled 

derated hours as well as seasonal derated hours. As such, the EAF matches this study‟s 

definition of capacity factor.

The average EAF for coal-fired plants in the 400–599 MW size range was 84.9 percent in 2004 

and averaged 83.9 percent from 2000 to 2004. Given that many of the plants in this size range 

are older, the EAF was rounded up to 85 percent and that value was used as the SC PC plant 

capacity factor.

EPRI examined the historical forced and scheduled outage times for IGCCs and concluded that 

the reliability factor (which looks at forced or unscheduled outage time only) for a single train 

IGCC (no spares) would be about 90 percent [18]. To get the availability factor, one has to 

deduct the scheduled outage time. In reality, the scheduled outage times could differ amongst 

the different gasifier technologies. However, the differences are relatively small and would have 

minimal impact on the capacity factor, so for this study it was assumed to be constant at a 30-day 

planned outage per year (or two 15-day outages). The planned outage would amount to 

8.2 percent of the year, so the availability factor would be (90 percent - 8.2 percent), or

81.8 percent.

There are four operating IGCC‟s worldwide that use a solid feedstock and are primarily power 

producers (Polk, Wabash, Buggenum, and Puertollano). A 2006 report by Higman et al. 

examined the reliability of these IGCC power generation units and concluded that typical annual 
Carbon Dioxide Capture Sensitivity Analysis

35

on-stream times are around 80 percent [19]. The capacity factor would be somewhat less than 

the on-stream time since most plants operate at less than full load for some portion of the 

operating year. Given the results of the EPRI study and the Higman paper, a capacity factor of 

80 percent was chosen for IGCC with no spare gasifier required.

The addition of CO2 capture was assumed not to impact the capacity factor even without 

redundant pipelines, wells, or subsurface infrastructure. This assumption was made to enable a 

comparison based on the impact of capital and variable operating costs only. Any reduction in 

assumed capacity factor would further increase the COE with CO2 capture.

2.6 Raw Water Withdrawal

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. Internal recycle water available from 

various sources like boiler feedwater blowdown and condensate from syngas 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 surface-water 

source for use in the plant. Raw water consumption is also accounted for and is defined as the 

portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or 

otherwise not returned to the water source it was withdrawn from.

Raw water withdrawal 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, boiler feedwater makeup, quench system makeup, and slag handling 

makeup. The difference between withdrawal and process water returned to the source is 

consumption. Consumption represents the overall impact of the process on the water source.

The largest consumer of raw water in all cases is cooling tower makeup. The plants included in 

this study use a conventional wet cooling tower. Boiler feedwater 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 sour water stripper (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.

2.7 Cost Estimating Methodology

The estimating methodology for capital costs, operations and maintenance costs, and CO2 TS&M 

costs are described below. The finance structure, basis for the discounted cash flow analysis, and 

first-year COE cost calculations are also described.

2.7.1 Capital Costs

As illustrated in Exhibit 2-14, this study reports capital cost at four levels: Bare Erected Cost 

(BEC), Total Plant Cost (TPC), Total Overnight Cost (TOC) and Total As-spent Capital (TASC). 

BEC, TPC and TOC are “overnight” costs and are expressed in “base-year” dollars. The base 
Carbon Dioxide Capture Sensitivity Analysis

36

year is the first year of capital expenditure, which for this study is assumed to be 2007. TASC is 

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

assumed to last five years for coal plants (2007 to 2012).

Exhibit 2-14 Capital Cost Levels and their Elements

process equipment

supporting facilities

direct and indirect labor

BEC

TPC

TOC

TASC

EPC contractor services

process contingency

project contingency

preproduction costs

inventory capital

financing costs

other owner’s costs

escalation during capital expenditure period

interest on debt during capital expenditure period

Bare Erected Cost

Total Plant Cost

Total Overnight Cost

Total As-Spent Cost

BEC, 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.

The 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 is not included in 

BEC. BEC is an overnight cost expressed in base-year (2007) dollars.

The TPC comprises the BEC plus the cost of services provided by the engineering, procurement 

and construction (EPC) contractor and project and process contingencies. 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. TPC is an overnight cost expressed in base-year 

(2007) dollars.

The TOC comprises the TPC plus owner‟s costs. TOC is an “overnight” cost, expressed in baseyear (2007) dollars and as such does not include escalation during construction or interest during 

construction. TOC is an overnight cost expressed in base-year (2007) dollars.

The 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. 
Carbon Dioxide Capture Sensitivity Analysis

37

Accordingly, TASC is expressed in mixed, current-year dollars over the capital expenditure 

period.

Cost Estimate Basis and Classification

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

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

Costs were further calibrated using a combination of adjusted vendor-furnished and actual cost 

data from recent design projects.

Recommended Practice 18R-97 of the Association for the Advancement of Cost Engineering 

International (AACE) describes a Cost Estimate Classification System as applied in Engineering, 

Procurement and Construction for the process industries [20].

Most techno-economic studies completed by NETL feature cost estimates intended for the 

purpose of a “Feasibility Study” (AACE Class 4). Exhibit 2-15 describes the characteristics of 

an AACE Class 4 Cost Estimate. Cost estimates in this study have an expected accuracy range 

of -15%/+30%.

Exhibit 2-15 Features of an AACE Class 4 Cost Estimate

Project 

Definition Typical Engineering Completed Expected Accuracy

1 to 15%

plant capacity, block schematics, indicated layout, 

process flow diagrams for main process systems, 

and preliminary engineered process and utility 

equipment lists

-15% to -30% on the low side, 

and -20% to +50% on the high 

side

2.7.2 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). 

2.7.3 CO2 Removal Plant Maturity 

The post-combustion CO2 removal technology for the PC capture cases is immature technology. 

This technology remains unproven at commercial scale in power generation applications. 

The pre-combustion CO2 removal technology for the IGCC capture cases has a stronger 

commercial experience base. Pre-combustion CO2 removal from syngas streams has been 

proven in chemical processes with similar conditions to that in IGCC plants, but has not been 

demonstrated in IGCC applications. While no commercial IGCC plant yet uses CO2 removal 
Carbon Dioxide Capture Sensitivity Analysis

38

technology in commercial service, there are currently IGCC plants with CO2 capture well along 

in the planning stages.

2.7.4 Contracting Strategy 

The estimates are based on an EPCM approach utilizing multiple subcontracts. This approach 

provides the Owner with greater control of the project, while minimizing, if not eliminating most 

of the risk premiums typically included in an Engineer/Procure/Construct (EPC) contract price. 

In a traditional lump sum EPC contract, the Contractor assumes all risk for performance, 

schedule, and cost. However, as a result of current market conditions, EPC contractors appear 

more reluctant to assume that overall level of risk. Rather, the current trend appears to be a 

modified EPC approach where much of the risk remains with the Owner. Where Contractors are 

willing to accept the risk in EPC type lump-sum arrangements, it is reflected in the project cost. 

In today‟s market, Contractor premiums for accepting these risks, particularly performance risk, 

can be substantial and increase the overall project costs dramatically. 

The EPCM approach used as the basis for the estimates here is anticipated to be the most cost 

effective approach for the Owner. While the Owner retains the risks, the risks become reduced 

with time, as there is better scope definition at the time of contract award(s).

2.7.5 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. 

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

and added to the COE.

2.7.6 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 bottoms-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.
Carbon Dioxide Capture Sensitivity Analysis

39

PAS presents information for eight separate regions. For this study, 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 perdiems 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. 

Costs are limited to within the “fence line,” terminating at the high voltage side of the 

main power transformers with the exception of costs included for TS&M, which are 

treated as an addition to COE.

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.

Price Fluctuations

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

substantially. Some reference quotes pre-dated the 2007 year cost basis while others were 

received post-2007. All vendor quotes used to develop these estimates were adjusted to June 

2007 dollars accounting for the price fluctuations. Adjustments of costs pre-dating 2007 

benefitted from a vendor survey of actual and projected pricing increases from 2004 through 

mid-2007 that WorleyParsons conducted for another project. The results of that survey were 

used to validate/recalibrate the corresponding escalation factors used in the conceptual 

estimating models. The more recent economic down turn has resulted in a reduction of 

commodity prices such that many price indices have similar values in January 2010 compared to 

June 2007. For example, the Chemical Engineering Plant Cost Index was 532.7 in June 2007 

and 532.9 in January 2010, and the Gross Domestic Product Chain-type Price Index was 106.7 

on July 1, 2007 and 110.0 on January 1, 2010. While these overall indices are nearly constant, it 

should be noted that the cost of individual equipment types may still deviate from the June 2007 

reference point.
Carbon Dioxide Capture Sensitivity Analysis

40

Exclusions

The capital cost estimate includes all anticipated costs for equipment and materials, installation 

labor, professional services (Engineering and Construction Management), and contingency. The 

following items are excluded from the capital costs:

All taxes, with the exception of payroll and property taxes (property taxes are included 

with the fixed O&M costs)

Site specific considerations – including, but not limited to, seismic zone, accessibility, 

local regulatory requirements, excessive rock, piles, laydown space, etc. 

Labor incentives in excess of 5-10s

Additional premiums associated with an EPC contracting approach

Contingency

Process and project contingencies are included in estimates to account for unknown costs that are 

omitted or unforeseen due to a lack of complete project definition and engineering. 

Contingencies are added because experience has shown that such costs are likely, and expected, 

to be incurred even though they cannot be explicitly determined at the time the estimate is 

prepared. 

Capital cost contingencies do not cover uncertainties or risks associated with:

scope changes

changes in labor availability or productivity

delays in equipment deliveries

changes in regulatory requirements

unexpected cost escalation

performance of the plant after startup (e.g., availability, efficiency)

Process Contingency

Process contingency is intended to compensate for uncertainty in cost estimates caused by 

performance uncertainties associated with the development status of a technology. Process 

contingencies are applied to each plant section based on its current technology status.

As shown in Exhibit 2-16, AACE International Recommended Practice 16R-90 provides 

guidelines for estimating process contingency based on EPRI philosophy [21].

Process contingencies have been applied to the estimates in this study as follows:

Slurry Prep and Feed – 5 percent on all IGCC cases

Gasifiers and Syngas Coolers – 15 percent on all IGCC cases – next-generation

commercial offering and integration with the power island

Two Stage Selexol – 20 percent on all IGCC capture cases - unproven technology at 

commercial scale in IGCC service
Carbon Dioxide Capture Sensitivity Analysis

41

Mercury Removal – 5 percent on all IGCC cases – minimal commercial scale experience 

in IGCC applications

CO2 Removal System – 20 percent on all PC cases - post-combustion process unproven 

at commercial scale for power plant applications

CTG – 5 percent on all IGCC non-capture cases – syngas firing and ASU integration; 10

percent on all IGCC capture cases – high hydrogen firing. 

Instrumentation and Controls – 5 percent on all IGCC accounts and 5 percent on the PC 

cases – integration issues

Exhibit 2-16 AACE Guidelines for Process Contingency

Technology Status

Process Contingency

(% of Associated Process Capital)

New concept with limited data 40+

Concept with bench-scale data 30-70

Small pilot plant data 20-35

Full-sized modules have been operated 5-20

Process is used commercially 0-10

Process contingency is typically not applied to costs that are set equal to a research goal or 

programmatic target since these values presume to reflect the total cost.

Project Contingency

AACE 16R-90 states that project contingency for a “budget-type” estimate (AACE Class 4 or 5) 

should be 15 to 30 percent of the sum of BEC, EPC fees and process contingency. This was 

used as a general guideline, but some project contingency values outside of this range occur 

based on WorleyParsons‟ in-house experience. 

Owner’s Costs

Exhibit 2-18 explains the estimation method for owner‟s costs. With some exceptions, the 

estimation method follows guidelines in Sections 12.4.7 to 12.4.12 of AACE International 

Recommended Practice No. 16R-90 [21]. The Electric Power Research Institute‟s “Technical 

Assessment Guide (TAG®) – Power Generation and Storage Technology Options” also has 

guidelines for estimating owner‟s costs. The EPRI and AACE guidelines are very similar. In 

instances where they differ, this study has sometimes adopted the EPRI approach.

Interest during construction and escalation during construction are not included as owner‟s costs 

but are factored into the COE and are included in TASC. These costs vary based on the capital 

expenditure period and the financing scenario. Ratios of TASC/TOC determined from the PSFM 

are used to account for escalation and interest during construction. Given TOC, TASC can be 

determined from the ratios given in Exhibit 2-17.
Carbon Dioxide Capture Sensitivity Analysis

42

Exhibit 2-17 TASC/TOC Factors

Finance Structure High Risk IOU Low Risk IOU

Capital Expenditure Period Five Years Five Years

TASC/TOC 1.140 1.134
Carbon Dioxide Capture Sensitivity Analysis

43

Exhibit 2-18 Owner’s Costs Included in TOC

Owner’s 

Cost Estimate Basis

Prepaid 

Royalties

Any technology royalties are assumed to be included in the associated equipment cost, and thus are not 

included as an owner’s cost.

Preproduction 

(Start-Up) 

Costs

6 months operating labor

1 month maintenance materials at full capacity

1 month non-fuel consumables at full capacity

1 month waste disposal 

25% of one month’s fuel cost at full capacity

2% of TPC

Compared to AACE 16R-90, this includes additional costs for operating labor (6 months versus 1 month) to 

cover the cost of training the plant operators, including their participation in startup, and involving them 

occasionally during the design and construction. AACE 16R-90 and EPRI TAG® differ on the amount of fuel 

cost to include; this estimate follows EPRI.

Working 

Capital

Although inventory capital (see below) is accounted for, no additional costs are included for working capital.

Inventory 

Capital

0.5% of TPC for spare parts

60 day supply (at full capacity) of fuel.

60 day supply (at full capacity) of non-fuel consumables (e.g., chemicals and catalysts) that are stored on 

site. Does not include catalysts and adsorbents that are batch replacements such as WGS, COS, and 

SCR catalysts and activated carbon.

AACE 16R-90 does not include an inventory cost for fuel, but EPRI TAG® does.

Land $3,000/acre (300 acres for IGCC and PC, 100 acres for NGCC)

Financing 

Cost

2.7% of TPC

This financing cost (not included by AACE 16R-90) covers the cost of securing financing, including fees and 

closing costs but not including interest during construction (or AFUDC). The ―rule of thumb‖ estimate (2.7% of 

TPC) is based on a 2008 private communication with a capital services firm.
Carbon Dioxide Capture Sensitivity Analysis

44

Owner’s 

Cost Estimate Basis

Other 

Owner’s 

Costs

15% of TPC

This additional lumped cost is not included by AACE 16R-90 or EPRI TAG®. The ―rule of thumb‖ estimate 

(15% of TPC) is based on a 2009 private communication with WorleyParsons. Significant deviation from this 

value is possible as it is very site and owner specific. The lumped cost includes:

- Preliminary feasibility studies, including a Front-End Engineering Design (FEED) study

- Economic development (costs for incentivizing local collaboration and support)

- Construction and/or improvement of roads and/or railroad spurs outside of site boundary

- Legal fees

- Permitting costs

- Owner’s engineering (staff paid by owner to give third-party advice and to help the owner oversee/evaluate 

the work of the EPC contractor and other contractors)

- Owner’s contingency (Sometimes called ―management reserve‖, these are funds to cover costs relating to 

delayed startup, fluctuations in equipment costs, unplanned labor incentives in excess of a five-day/tenhour-per-day work week. Owner’s contingency is NOT a part of project contingency.)

This lumped cost does NOT include:

- EPC Risk Premiums (Costs estimates are based on an Engineering Procurement Construction 

Management approach utilizing multiple subcontracts, in which the owner assumes project risks for 

performance, schedule and cost)

- Transmission interconnection: the cost of interconnecting with power transmission infrastructure beyond 

the plant busbar.

- Taxes on capital costs: all capital costs are assumed to be exempt from state and local taxes.

- Unusual site improvements: normal costs associated with improvements to the plant site are included in 

the bare erected cost, assuming that the site is level and requires no environmental remediation. Unusual 

costs associated with the following design parameters are excluded: flood plain considerations, existing 

soil/site conditions, water discharges and reuse, rainfall/snowfall criteria, seismic design, 

buildings/enclosures, fire protection, local code height requirements, noise regulations.
Carbon Dioxide Capture Sensitivity Analysis

45

2.7.7 Operations 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: 

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. 

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 $34.65/hour. The 

associated labor burden is estimated at 30 percent of the base labor rate. Taxes and insurance are 

included as fixed O&M costs totaling 2 percent of the TPC.

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.

Administrative and Support Labor

Labor administration and overhead charges are assessed at rate of 25 percent of the burdened 

O&M labor.

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. 
Carbon Dioxide Capture Sensitivity Analysis

46

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.

Waste Disposal

Waste quantities and disposal costs were determined/evaluated similarly to the consumables. In 

this study both slag from the IGCC cases and fly ash and bottom ash from the PC cases are 

considered a waste with a disposal cost of $17.89/tonne ($16.23/ton). The carbon used for 

mercury control in the IGCC cases is considered a hazardous waste with disposal cost of 

$926/tonne ($840/ton).

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 gypsum and sulfur, no credit was taken 

for their 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. Ash and slag are both potential by-products 

in certain markets, and in the absence of activated carbon injection in the PC cases, the fly ash 

would remain uncontaminated and have potential marketability. However, as stated above, the 

ash and slag are considered wastes in this study with a concomitant disposal cost.

2.7.8 CO2 Transport, Storage and Monitoring

The capital and operating costs for CO2 TS&M were independently estimated by NETL. Those 

costs were converted to a TS&M COE increment that was added to the plant COE.

CO2 TS&M was modeled based on the following assumptions:

CO2 is supplied to the pipeline at the plant fence line at a pressure of 15.3 MPa (2,215 

psia). The CO2 product gas composition varies in the cases presented, but is expected to 

meet the specification described in Exhibit 2-19 [22]. A glycol dryer located near the 

mid-point of the compression train is used to meet the moisture specification.
Carbon Dioxide Capture Sensitivity Analysis

47

Exhibit 2-19 CO2 Pipeline Specification

Parameter Units Parameter Value

Inlet Pressure MPa (psia) 15.3 (2,215)

Outlet Pressure MPa (psia) 10.4 (1,515)

Inlet Temperature °C (°F) 35 (95)

N2 Concentration ppmv < 300

O2 Concentration ppmv < 40

Ar Concentration ppmv < 10

H2O Concentration ppmv < 150

The CO2 is transported 80 km (50 miles) via pipeline to a geologic sequestration field for 

injection into a saline formation.

The CO2 is transported and injected as a SC fluid in order to avoid two-phase flow and 

achieve maximum efficiency [23]. The pipeline is assumed to have an outlet pressure 

(above the SC pressure) of 8.3 MPa (1,200 psia) with no recompression along the way. 

Accordingly, CO2 flow in the pipeline was modeled to determine the pipe diameter that 

results in a pressure drop of 6.9 MPa (1,000 psi) over an 80 km (50 mile) pipeline length

[24]. (Although not explored in this study, the use of boost compressors and a smaller 

pipeline diameter could possibly reduce capital costs for sufficiently long pipelines.) The 

diameter of the injection pipe will be of sufficient size that frictional losses during 

injection are minimal and no booster compression is required at the well-head in order to 

achieve an appropriate down-hole pressure, with hydrostatic head making up the 

difference between the injection and reservoir pressure.

The saline formation is at a depth of 1,236 m (4,055 ft) and has a permeability of 22 

millidarcy (md) (22 μm2) and formation pressure of 8.4 MPa (1,220 psig) [22]. This is 

considered an average storage site and requires roughly one injection well for each 9,360 

tonnes (10,320 short tons) of CO2 injected per day [22]. The assumed aquifer 

characteristics are tabulated in Exhibit 2-20.

The cost metrics utilized in this study provide a best estimate of TS&M costs for a “favorable” 

sequestration project, and may vary significantly based on variables such as terrain to be crossed 

by the pipeline, reservoir characteristics, and number of land owners from which sub-surface 

rights must be acquired. Raw capital and operating costs are derived from detailed cost metrics 

found in the literature, escalated to June 2007-year dollars using appropriate price indices. These 

costs were then verified against values quoted by industrial sources where possible. Where 

regulatory uncertainty exists or costs are undefined, such as liability costs and the acquisition of 

underground pore volume, analogous existing policies were used for representative cost 

scenarios.
Carbon Dioxide Capture Sensitivity Analysis

48

Exhibit 2-20 Deep, Saline Aquifer Specification

Parameter Units Base Case

Pressure MPa (psi) 8.4 (1,220)

Thickness m (ft) 161 (530)

Depth m (ft) 1,236 (4,055)

Permeability Md 22

Pipeline Distance km (miles) 80 (50)

Injection Rate per Well tonne (ton) CO2/day 9,360 (10,320)

The following sections describe the sources and methodology used for each metric.

TS&M Captial Costs

TS&M capital costs include both a 20 percent process contingency and 30 percent project

contingency. 

In several areas, such as Pore Volume Acquisition, Monitoring, and Liability, cost outlays occur 

over a longer time period, up to 100 years. In these cases a capital fund is established based on 

the net present value of the cost outlay, and this fund is then levelized similar to the other costs.

Transport Costs

CO2 transport costs are broken down into three categories: pipeline costs, related capital 

expenditures, and O&M costs.

Pipeline costs are derived from data published in the Oil and Gas Journal‟s (O&GJ) annual 

Pipeline Economics Report for existing natural gas, oil, and petroleum pipeline project costs 

from 1991 to 2003. These costs are expected to be analogous to the cost of building a CO2

pipeline, as noted in various studies [22, 23, 25]. The University of California performed a 

regression analysis to generate cost curves from the O&GJ data: (1) Pipeline Materials, (2) 

Direct Labor, (3) Indirect Costs, and (4) Right-of-way acquisition, with each represented as a 

function of pipeline length and diameter [25]. These cost curves were escalated to the June 2007 

year dollars used in this study.

Related capital expenditures were based on the findings of a previous study funded by 

DOE/NETL, Carbon Dioxide Sequestration in Saline Formations – Engineering and Economic 

Assessment [22]. This study utilized a similar basis for pipeline costs (O&GJ Pipeline cost data 

up to the year 2000) but added a CO2 surge tank and pipeline control system to the project. 

Transport O&M costs were assessed using metrics published in a second DOE/NETL sponsored 

report entitled Economic Evaluation of CO2 Storage and Sink Enhancement Options [23]. This 
Carbon Dioxide Capture Sensitivity Analysis

49

study was chosen due to the reporting of O&M costs in terms of pipeline length, whereas the 

other studies mentioned above either (a) do not report operating costs, or (b) report them in 

absolute terms for one pipeline, as opposed to as a length- or diameter-based metric. 

Storage Costs

Storage costs were divided into five categories: (1) Site Screening and Evaluation, (2) Injection 

Wells, (3) Injection Equipment, (4) O&M Costs, and (5) Pore Volume Acquisition. With the 

exception of Pore Volume Acquisition, all of the costs were obtained from Economic Evaluation 

of CO2 Storage and Sink Enhancement Options [23]. These costs include all of the costs 

associated with determining, developing, and maintaining a CO2 storage location, including site 

evaluation, well drilling, and the capital equipment required for distributing and injecting CO2.

Pore Volume Acquisition costs are the costs associated with acquiring rights to use the subsurface volume where the CO2 will be stored, i.e., the pore space in the geologic formation. 

These costs were based on recent research by Carnegie Mellon University, which examined 

existing sub-surface rights acquisition as it pertains to natural gas storage [26]. The regulatory 

uncertainty in this area combined with unknowns regarding the number and type (private or 

government) of property owners, require a number of “best engineering judgment” decisions to 

be made. In this study it was assumed that long-term lease rights were acquired from the 

property owners in the projected CO2 plume growth region for a nominal fee, and that an annual 

“rent” was paid when the plume reached each individual acre of their property for a period of up 

to 100 years from the injection start date. The present value of the life cycle pore volume costs 

are assessed at a 10 percent discount rate and a capital fund is set up to pay for these costs over 

the 100 year rent scenario.

Liability Protection

Liability Protection addresses the fact that if damages are caused by injection and long-term 

storage of CO2, the injecting party may bear financial liability. Several types of liability 

protection schemes have been suggested for CO2 storage, including Bonding, Insurance, and 

Federal Compensation Systems combined with either tort law (as with the Trans-Alaska Pipeline 

Fund), or with damage caps and preemption, as is used for nuclear energy under the Price 

Anderson Act [27]. However, at present, a specific liability regime has yet to be dictated either 

at a Federal or (to our knowledge) State level. However, certain state governments have enacted 

legislation, which assigns liability to the injecting party, either in perpetuity (Wyoming) or until 

ten years after the cessation of injection operations, pending reservoir integrity certification, at 

which time liability is turned over to the state (North Dakota and Louisiana) [28,29,30]. In the 

case of Louisiana, a trust fund totaling five million dollars is established over the first ten years 

(120 months) of injection operations for each injector. This fund is then used by the state for 

CO2 monitoring and, in the event of an at-fault incident, damage payments. 

Liability costs assume that a bond must be purchased before injection operations are permitted in 

order to establish the ability and good will of an injector to address damages where they are 

deemed liable. A figure of five million dollars was used for the bond based on the Louisiana

fund level. This bond level may be conservatively high, in that the Louisiana fund covers both 

liability and monitoring, but that fund also pertains to a certified reservoir where injection 
Carbon Dioxide Capture Sensitivity Analysis

50

operations have ceased, having a reduced risk compared to active operations. The bond cost was 

not escalated.

Monitoring Costs

Monitoring costs were evaluated based on the methodology set forth in the International Energy 

Agency (IEA) Greenhouse Gas (GHG) R&D Programme‟s Overview of Monitoring Projects for 

Geologic Storage Projects report [31]. In this scenario, operational monitoring of the CO2 plume 

occurs over 30 years (during plant operation) and closure monitoring occurs for the following 

fifty years (for a total of eighty years). Monitoring is via electromagnetic (EM) survey, gravity 

survey, and periodic seismic survey; EM and gravity surveys are ongoing while seismic survey 

occurs in years 1, 2, 5, 10, 15, 20, 25, and 30 during the operational period, then in years 40, 50, 

60, 70, and 80 after injection ceases.

2.7.9 Finance Structure, Discounted Cash Flow Analysis, and COE

The global economic assumptions are listed in Exhibit 2-21. 

Finance structures were chosen based on the assumed type of developer/owner (investor-owned 

utility (IOU) or independent power producer) and the assumed risk profile of the plant being 

assessed. For this study the owner/developer was assumed to be an IOU. Cases were considered

either high risk, with the inclusion of CO2 capture, or low risk, without CO2 capture. 

Exhibit 2-22 describes the high-risk and low-risk IOU finance structures that were assumed for 

this study. These finance structures were recommended in a 2008 NETL report based on 

interviews with project developers/owners, financial organizations and law firms [32].
Carbon Dioxide Capture Sensitivity Analysis

51

Exhibit 2-21 Global Economic Assumptions

Parameter Value

TAXES

Income Tax Rate 38% (Effective 34% Federal, 6% State)

Capital Depreciation 20 years, 150% declining balance

Investment Tax Credit 0%

Tax Holiday 0 years

CONTRACTING AND FINANCING TERMS

Contracting Strategy

Engineering Procurement Construction 

Management (owner assumes project risks for 

performance, schedule and cost)

Type of Debt Financing Non-Recourse (collateral that secures debt is 

limited to the real assets of the project)

Repayment Term of Debt 15 years

Grace Period on Debt Repayment 0 years

Debt Reserve Fund None

ANALYSIS TIME PERIODS

Capital Expenditure Period 5 Years

Operational Period 30 years

Economic Analysis Period (used for IRROE) 35 Years (capital expenditure period plus 

operational period)

TREATMENT OF CAPITAL COSTS

Capital Cost Escalation During Capital 

Expenditure Period (nominal annual rate) 3.6%1

Distribution of Total Overnight Capital over the 

Capital Expenditure Period (before escalation) 5-Year Period: 10%, 30%, 25%, 20%, 15%

Working Capital zero for all parameters

% of Total Overnight Capital that is Depreciated

100% (this assumption introduces a very small 

error even if a substantial amount of TOC is 

actually non-depreciable)

ESCALATION OF OPERATING REVENUES AND COSTS

Escalation of COE (revenue), O&M Costs, and 

Fuel Costs (nominal annual rate) 3.0%2

 

1 A nominal average annual rate of 3.6 percent is assumed for escalation of capital costs during construction. This 

rate is equivalent to the nominal average annual escalation rate for process plant construction costs between 1947 

and 2008 according to the Chemical Engineering Plant Cost Index.

2 An average annual inflation rate of 3.0 percent is assumed. This rate is equivalent to the average annual escalation 

rate between 1947 and 2008 for the U.S. Department of Labor's Producer Price Index for Finished Goods, the socalled "headline" index of the various Producer Price Indices. (The Producer Price Index for the Electric Power 

Generation Industry may be more applicable, but that data does not provide a long-term historical perspective since 

it only dates back to December 2003.)
Carbon Dioxide Capture Sensitivity Analysis

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Exhibit 2-22 Financial Structure for Investor Owned Utility High Risk Projects

Type of 

Security % of Total

Current 

(Nominal) Dollar 

Cost

Weighted 

Current 

(Nominal) Cost

After Tax 

Weighted Cost of 

Capital

Low Risk

Debt 50 4.5% 2.25%

Equity 50 12% 6%

Total 8.25% 7.39%

High Risk

Debt 45 5.5% 2.475%

Equity 55 12% 6.6%

Total 9.075% 8.13%

DCF Analysis and Cost of Electricity

The NETL Power Systems Financial Model (PSFM), a nominal-dollar3(current dollar) 

discounted cash flow (DCF) analysis tool, was used to calculate COE4. The COE is the revenue 

received by the generator per net megawatt-hour during the power plant‟s first year of operation,

assuming that the COE escalates thereafter at a nominal annual rate equal to the general 

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

plant. To calculate the COE, the PSFM was used to determine a “base-year” (2007) COE that, 

when escalated at an assumed nominal annual general inflation rate of 3 percent5, provided the 

stipulated internal rate of return on equity over the entire economic analysis period (capital 

expenditure period plus thirty years of operation). Since this analysis assumes that COE 

 

3

Since the analysis takes into account taxes and depreciation, a nominal dollar basis is preferred to properly reflect 

the interplay between depreciation and inflation.

4

For this calculation, “cost of electricity” is somewhat of a misnomer because from the power plant‟s perspective it 

is actually the “price” received for the electricity generated to achieve the stated IRROE. However, since the price 

paid for generation is ultimately charged to the end user, from the customer‟s perspective it is part of the cost of 

electricity.

5 This nominal escalation rate is equal to the average annual inflation rate between 1947 and 2008 for the U.S. 

Department of Labor‟s Producer Price Index for Finished Goods. This index was used instead of the Producer Price 

Index for the Electric Power Generation Industry because the Electric Power Index only dates back to December 

2003 and the Producer Price Index is considered the “headline” index for all of the various Producer Price Indices.
Carbon Dioxide Capture Sensitivity Analysis

53

increases over the economic analysis period at the nominal annual general inflation rate, it 

remains constant in real terms and the first-year COE is equivalent to the base-year COE when 

expressed in base-year (2007) dollars. Since 2007 is the first year of the capital expenditure 

period, it is also the base year for the economic analysis. Accordingly, it is convenient to report 

the results of the economic analysis in base-year (June 2007) dollars. 

Estimating COE with Capital Charge Factors

For scenarios that adhere to the global economic assumptions listed in Exhibit 2-21 and utilize 

the finance structure listed in Exhibit 2-22, the following simplified equation can be used to 

estimate COE as a function of TOC6, fixed O&M, variable O&M (including fuel), capacity 

factor and net output. The equation requires the application of the capital charge factors (CCF) 

listed in Exhibit 2-23. These CCFs are valid only for the global economic assumptions listed in 

Exhibit 2-21, the stated finance structure, and the stated capital expenditure period.

Exhibit 2-23 Capital Charge Factors for COE Equation

Finance

Structure

High Risk IOU Low Risk IOU

Capital Expenditure Period Five Years Five Years

Capital Charge Factor (CCF) 0.124 0.116

All factors in the COE equation are expressed in base-year dollars. The base year is the first year 

of capital expenditure, which for this study is assumed to be 2007. As shown in Exhibit 2-21, all 

factors (COE, O&M and fuel) are assumed to escalate at a nominal annual general inflation rate 

of 3.0 percent. Accordingly, all first-year costs (COE and O&M) are equivalent to base-year 

costs when expressed in base-year (2007) dollars.

 

6 Although TOC is used in the simplified COE equation, the CCF that multiplies it accounts for escalation during 

construction and interest during construction (along with other factors related to the recovery of capital costs). 
Carbon Dioxide Capture Sensitivity Analysis

54

where:

COE = revenue received by the generator ($/MWh, equivalent to mills/kWh) 

during the power plant‟s first year of operation (but expressed in baseyear dollars), assuming that the COE escalates thereafter at a nominal 

annual rate equal to the general inflation rate, i.e., that it remains constant 

in real terms over the operational period of the power plant.

CCF = capital charge factor taken from Exhibit 2-23 that matches the applicable 

finance structure and capital expenditure period

TOC = total overnight capital, expressed in base-year dollars

OCFIX = the sum of all fixed annual operating costs, expressed in base-year dollars

OCVAR = the sum of all variable annual operating costs, including fuel at 100

percent capacity factor, expressed in base-year dollars

CF = plant capacity factor, assumed to be constant over the operational period

MWH = annual net megawatt-hours of power generated at 100 percent capacity 

factor

2.8 IGCC STUDY COST ESTIMATES COMPARED TO INDUSTRY ESTIMATES

The estimated TOC for IGCC cases in this study ranges from $2,447 for IGCC with 0% capture 

to $3,501/kW for IGCC with 97% capture. Plant size ranges from 523 - 622 MW (net) for 0% 

and 97% capture plants, respectively. 

Within the power industry there are several power producers interested in pursuing construction 

of an IGCC plant. While these projects are still in the relatively early stages of development, 

some cost estimates have been published. Published estimates tend to be limited in detail, 

leaving it to the reader to speculate as to what is contained within the estimate. In November 

2007, the Indiana Utility Regulatory Commission approved Duke Energy‟s proposal to build an 

IGCC plant in Edwardsport, Indiana. The estimated cost to build the 630 MW plant is 

$4,472/kW in June 2007 dollars. Duke expects the plant to begin operation in 2012. Other 

published estimates for similar proposed non-CO2 capture gasification plants range from 
Carbon Dioxide Capture Sensitivity Analysis

55

$2,483/kW to $3,122/kW in June 2007 dollars. Corresponding plant sizes range form 770 - 600 

MW, respectively. Published estimates from similar CO2 capture facilities range from 

$4,581/kW to $5,408/kW, in June 2007 dollars, with sizes ranging from 400 to 580 MW 

[33,34,35,36].7 

Differences in Cost Estimates

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 side terminals of the Generator Step-up Transformers 

(GSUs). 

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 fenceline

Landfill for on-site waste (slag) disposal

Natural gas line for backup fuel provisions

Plant switchyard

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 to site

Costs of offsite storage

This report is based on a reasonably “standard” plant. No unusual or extraordinary process 

equipment is included such as:

Excessive water treatment equipment

Air-cooled condenser

 

7 Costs were adjusted to June 2007 using the Chemical Engineering Plant Cost Index
Carbon Dioxide Capture Sensitivity Analysis

56

Automated coal reclaim

Zero Liquid Discharge equipment

SCR catalyst (IGCC cases only)

For non-capture cases, which are likely the most appropriate comparison against industry 

published estimates, this report is based on plant equipment sized for non-capture only. None of 

the equipment is sized to accommodate a future conversion to CO2 capture. 

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-diems or bonuses have been included to attract and retain 

skilled craft labor.

Contracting Methodology

The estimates in this report are based on a competitively bid, multiple subcontract approach, 

often referred to as 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.
Carbon Dioxide Capture Sensitivity Analysis

57

3. Case 1 - Supercritical PC with Variable CO2 Capture

3.1 System Descriptions

The SC PC system descriptions are provided in the subsections below. 

3.1.1 Coal and Sorbent Receiving and Storage

The function of the coal portion of the Coal and Sorbent Receiving and Storage system is to 

provide the equipment required for unloading, conveying, preparing, and storing the fuel 

delivered to the plant. The scope of the system is from the coal conveyor receiving hoppers up 

to the coal storage silos. The system is designed to support short-term operation at maximum 

power output at the 5 percent over pressure/valves wide open (OP/VWO) condition (16 hours) 

and long-term operation of 90 days or more at the maximum continuous rating (MCR).

The scope of the sorbent receiving and storage systems includes truck roadways, turnarounds, 

unloading hoppers, conveyors, and the day storage bin.

Operation Description – The 3" x 0 bituminous Illinois No. 6 coal is delivered to the site by 

unit trains of 100-ton rail cars. Each unit train consists of 100, 100-ton rail cars. The unloading 

is done by a trestle bottom dumper, which unloads the coal to two receiving hoppers. Coal from 

each hopper is fed directly into a vibratory feeder. The 3" x 0 coal from the feeder is discharged 

onto a belt conveyor (No. 1). The coal is then transferred to a conveyor (No. 2) that transfers the 

coal to the reclaim area. The conveyor passes under a magnetic plate separator to remove tramp 

iron, and then to the reclaim pile. 

Coal from the reclaim pile is fed by two vibratory feeders, located under the pile, onto a belt 

conveyor (No. 3), which transfers the coal to the coal surge bin located in the crusher tower. The 

coal is reduced in size to 11⁄4" x 0 by the coal crusher. The coal is then transferred by conveyor 

(No. 4) to the transfer tower. In the transfer tower the coal is routed to the tripper that loads the 

coal into one of the parallel boiler silos.

Lime is delivered to the site using 23 tonne (25 ton) trucks and conveyed to storage. Lime is 

stored in a bulk storage lime silo. The lime is pneumatically conveyed to a day bin.

3.1.2 Steam Generator and Ancillaries 

The steam generator for the supercritical plant is a once-through, spiral-wound, Benson-boiler, 

wall-fired, balanced draft type unit with a water-cooled dry bottom furnace. It includes a 

superheater, reheater, economizer, and air heater.

It is assumed for the purposes of this study that the power plant is designed to be operated as a 

base-loaded unit but with some consideration for daily or weekly cycling, as can be cost 

effectively included in the base design.
Carbon Dioxide Capture Sensitivity Analysis

58

The combustion systems for supercritical steam conditions are equipped with low-NOx burners 

(LNBs) and overfire air (OFA).

3.1.2.1 Scope and General Arrangement

The steam generator comprises the following:

Once-through type steam 

generator

Low NOx Coal burners and 

light oil igniters/ warmup 

system

Startup circuit, including 

integral separators

Water-cooled furnace, dry 

bottom

Soot blower system Primary air (PA) fans

Two-stage superheater Air preheaters (Ljungstrom 

type)

Induced draft (ID) fans

Reheater Coal feeders and pulverizers Forced draft (FD) fans

Economizer Spray type desuperheater Overfire air system

The steam generator operates as follows:

3.1.2.2 Feedwater and Steam

Feedwater enters the bottom header of the economizer and passes upward through the 

economizer tube bank, through stringer tubes that support the primary superheater, and 

discharges to the economizer outlet headers. From the outlet headers, water flows to the furnace 

hopper inlet headers via external downcomers. Water then flows upward through the furnace 

hopper and furnace wall tubes. From the furnace, water flows to the steam water separator. 

During low load operation (operation below the critical point), the water from the separator is 

returned to the economizer inlet with the boiler recirculating pump. Operation at loads above the 

critical point is once through.

Steam flows from the separator through the furnace roof to the convection pass enclosure walls, 

primary superheater, through the first stage of water attemperation, to the furnace platens. From 

the platens, the steam flows through the second stage of attemperation and then to the 

intermediate superheater. The steam then flows to the final superheater and on to the outlet pipe 

terminal. Two stages of spray attemperation are used to provide tight temperature control in all 

high temperature sections during rapid load changes.

Steam returning from the turbine passes through the primary reheater surface, then through 

crossover piping containing inter-stage attemperation. The crossover piping feeds the steam to 

the final reheater banks and then out to the turbine. Inter-stage attemperation is used to provide 

outlet temperature control during load changes.

3.1.2.3 Air and Combustion Products

Combustion air from the FD fans is heated in Ljungstrom type air preheaters, recovering heat 

energy from the exhaust gases exiting the boiler. This air is distributed to the burner windbox as 
Carbon Dioxide Capture Sensitivity Analysis

59

secondary air. Air for conveying pulverized coal to the burners is supplied by the PA fans. This 

air is heated in the Ljungstrom type air preheaters to permit drying of the pulverized coal, and a 

portion of the air from the PA fans bypasses the air preheaters to be used for regulating the outlet 

coal/air temperature leaving the mills. 

The pulverized coal and air mixture flows to the coal nozzles at various elevations of the furnace. 

The hot combustion products rise to the top of the boiler and pass through the superheater and 

reheater sections. The gases then pass through the economizer and air preheater. The gases exit 

the steam generator at this point and flow to the Selective Catalytic Reduction (SCR) reactor, 

FGD system, fabric filter, ID fan, and stack.

3.1.2.4 Fuel Feed

The crushed coal is fed through feeders to each of the mills (pulverizers), where its size is 

reduced to approximately 72 percent passing 200 mesh with less than 0.5 percent remaining on 

50 mesh [37]. The pulverized coal exits each mill via the coal piping and is distributed to the 

coal nozzles in the furnace walls using air supplied by the PA fans.

3.1.2.5 Ash Removal

The furnace bottom comprises several hoppers, with a clinker grinder under each hopper. The 

hoppers are of welded steel construction, lined with refractory. The hopper design incorporates a 

water-filled seal trough around the upper periphery for cooling and sealing. Water and ash 

discharged from the hopper pass through the clinker grinder to an ash sluice system for 

conveyance to hydrobins, where the ash is dewatered before it is transferred to trucks for offsite 

disposal. The bottom ash from the boiler is fed into a clinker grinder. The clinker grinder is 

provided to break up any clinkers that may form. From the clinker grinders the bottom ash is 

sluiced to hydrobins for dewatering and offsite removal by truck. The steam generator 

incorporates fly ash hoppers under the economizer outlet and air heater outlet.

3.1.2.6 Burners

A boiler of this capacity employs approximately 24 to 36 coal nozzles arranged at multiple 

elevations. Each burner is designed as a low-NOx configuration, with staging of the coal 

combustion to minimize NOx formation. In addition, overfire air nozzles are provided to further 

stage combustion and thereby minimize NOx formation.

Oil-fired pilot torches are provided for each coal burner for ignition, warm-up and flame 

stabilization at startup and low loads.

3.1.2.7 Soot Blowers

The soot-blowing system utilizes an array of 50 to 150 retractable nozzles and lances that clean 

the furnace walls and convection surfaces with jets of high-pressure steam. The blowers are 

sequenced to provide an effective cleaning cycle depending on the coal quality and design of the 

furnace and convection surfaces. Electric motors drive the soot blowers through their cycles.
Carbon Dioxide Capture Sensitivity Analysis

60

3.1.3 NOx Control System 

The plant is designed to achieve the environmental target of 0.07 lb NOx/MMBtu. Two 

measures are taken to reduce the NOx. The first is a combination of low-NOx burners and the 

introduction of staged overfire air in the boiler. The low-NOx burners and overfire air reduce the 

emissions to about 0.2 lb/MMBtu. 

The second measure taken to reduce the NOx emissions is the installation of a SCR system prior 

to the air heater. SCR uses aqueous ammonia and a catalyst to reduce NOx to N2 and H2O. The 

SCR system consists of three subsystems: reactor vessel, ammonia storage and injection, and 

gas flow control. The SCR system is designed for 65 percent reduction with 2 ppmv ammonia 

slip at the end of the catalyst life. This, along with the low-NOx burners, achieves the emission 

limit of 0.07 lb/MMBtu.

The SCR capital costs are included with the boiler costs, as is the cost for the initial load of 

catalyst.

Selective non-catalytic reduction (SNCR) was considered for this application. However, with 

the installation of the low-NOx burners and overfire air system, the boiler exhaust gas contains 

relatively small amounts of NOx, which makes removal of the quantity of NOx with SNCR to 

reach the emissions limit of 0.07 lb/MMBtu difficult. SNCR works better in applications that 

contain medium to high quantities of NOx and require removal efficiencies in the range of 40 to 

60 percent. SCR, because of the catalyst used in the reaction, can achieve higher efficiencies 

with lower concentrations of NOx.

Operation Description – The reactor vessel is designed to allow proper retention time for the 

ammonia to contact the NOx in the boiler exhaust gas. Ammonia is injected into the gas 

immediately prior to entering the reactor vessel. The catalyst contained in the reactor vessel 

enhances the reaction between the ammonia and the NOx in the gas. Catalysts consist of various 

active materials such as titanium dioxide, vanadium pentoxide, and tungsten trioxide. The 

operating range for vanadium/titanium-based catalysts is 260 °C (500 F) to 455 °C (850 F). 

The boiler is equipped with economizer bypass to provide flue gas to the reactors at the desired 

temperature during periods of low flow rate, such as low load operation. Also included with the 

reactor vessel is soot-blowing equipment used for cleaning the catalyst.

The aqueous ammonia storage and injection system consists of the unloading facilities, bulk 

storage tank, vaporizers, dilution air skid, and injection grid.

The flue gas flow control consists of ductwork, dampers, and flow straightening devices required 

to route the boiler exhaust to the SCR reactor and then to the air heater. The economizer bypass 

and associated dampers for low load temperature control are also included.

3.1.4 Particulate Control 

A pulse-jet baghouse with air to cloth ratio of 3.5 ft/min is located after the air heater. The 

baghouse is provided with a spare compartment for off line cleaning to maintain the opacity at 10
Carbon Dioxide Capture Sensitivity Analysis

61

percent or less. The waste will be pneumatically conveyed to a waste storage silo with a 3-day 

storage capacity, which is in accordance with typical utility design.

Operation Description – The bag house is designed to achieve 99.8 percent removal efficiency 

and consists of two separate single-stage, in-line, and 10-compartment units. Each unit is a high 

air-to-cloth ratio design with a pulse-jet on-line cleaning system. The ash is collected on the 

outside of the 8 meter long bags, which are supported by steel cages. The dust cake is removed 

by a pulse of compressed air. The bag material is polyphenylensulfide (PPS) with an intrinsic 

Teflon (PTFE) coating [38]. Each compartment contains a number of gas passages with filter 

bags and heated ash hoppers supported by a rigid steel casing. The fabric filter is provided with 

necessary control devices, inlet gas distribution devices, insulators, inlet and outlet nozzles, 

expansion joints, and other items as required. The fabric filter reduces particulate loading in the 

stack gas to below the required levels.

3.1.5 Flue Gas Desulfurization 

3.1.5.1 Wet FGD Process 

The limestone-based, forced oxidation flue gas scrubbing system is designed to remove 98

percent of the SO2 from the flue gas. The design incorporates features which have been 

developed over many years of commercial operation and pilot work in utility flue gas cleaning.

Listed below are the major items that comprise the wet FGD portion of the tower systems. 

1. Limestone silos with weigh feeders, capable of supplying the required limestone to the 

slurry handling systems

2. Limestone preparation systems

3. Absorber

4. Cyclone separators, with spares sufficient to meet the requirements of the FGD absorber 

systems for gypsum slurry primary dewatering

5. Oxidation air compressors

6. Vacuum filter system

Exhibit 3-1 shows a typical wet FGD process flow diagram.
Carbon Dioxide Capture Sensitivity Analysis

62

Exhibit 3-1 Typical B&W Wet FGD Process Flow Diagram

Source: B&W Figure 
Carbon Dioxide Capture Sensitivity Analysis

63

3.1.5.2 Absorber Tower

Exhibit 3-2 shows a typical wet scrubber absorber tower arrangement. The absorber tower 

includes two gas distribution devices (trays), two spray headers of countercurrent absorber 

sprays, and a two-stage mist eliminator section. As the flue gas enters the absorber, it turns 

upward and is evenly distributed across the absorber cross-section by the absorber tray. 

Experience has shown that such a gas distribution device is needed to optimize SO2 removal. 

This experience parallels that of the electrostatic precipitator industry and their need for carefully 

designed gas distribution plates. In addition to providing an even gas flow for the main spray 

zone, the absorber tray also provides an area of intimate contact between the flue gas and 

limestone slurry.

The gas leaving the absorber tray passes through several countercurrent spray levels, which are 

supplied with recirculating slurry from the absorber's reaction tank, and continues through two

layers of Chevron type mist eliminators for water droplet removal before exiting the absorber 

tower through the outlet cone and outlet flue.

The in-situ oxidation system provides oxygen to the absorber reaction tank via an ambient air 

stream. This oxygen system forces calcium sulfite (CaSO3·1⁄2H2O) formed by the SO2 removal 

process to be oxidized to calcium sulfate (CaSO4·2H2O). 

Absorber recirculation pumps mounted on modularized base plates provide assemblies for easy 

installation. The assemblies can be bolted directly to concrete foundations. Four recirculation 

pumps are supplied. Three are required for operation at the normal operation design point. 

Exhibit 3-2 Wet Scrubber Arrangement

Normal Liquid Level

38‟-0

18‟-0 h

41‟-0 w

22‟-6 h

28‟-6 w

133‟-

104

58‟-0

Source: B&W Figure 
Carbon Dioxide Capture Sensitivity Analysis

64

3.1.5.3 Limestone Preparation System

The function of the limestone handling and reagent preparation system is to receive, store, 

convey, and grind the limestone delivered to the plant. The scope of the system is from the 

storage pile up to the limestone feed system. The system is designed to support continuous 

baseload operation. Truck roadways, turnarounds, and unloading hoppers are included in this 

reference plant design.

For the purposes of this conceptual design, limestone is assumed to be delivered to the plant by 

25-ton trucks. The limestone is unloaded onto a storage pile located above vibrating feeders. 

The limestone is fed onto belt conveyors via vibrating feeders and then to day bins equipped with 

vent filters. Each day bin supplies a 100 percent capacity size ball mill via a weigh feeder. The 

wet ball mill accepts the limestone and grinds the limestone to 90 to 95 percent passing 

325 mesh (44 microns). Water is added at the inlet to the ball mill to create limestone slurry. 

The reduced limestone slurry is then discharged into a mill slurry tank. Mill recycle pumps, two 

per tank, pump the limestone water slurry to an assembly of hydrocyclones and distribution 

boxes. The slurry is classified into several streams, based on suspended solids content and size 

distribution.

The hydrocyclone underflow with oversized limestone is directed back to the mill for further 

grinding. The hydrocyclone overflow with correctly sized limestone is routed to a reagent 

storage tank. Reagent distribution pumps direct slurry from the tank to the absorber module.

3.1.5.4 Gypsum Dewatering

Gypsum slurry is bled from the absorber by absorber blowdown pumps that feed a primary 

cyclone separator which concentrates the solids of the gypsum slurry stream. Hydrocyclone 

overflow is gravity fed to the back to the absorber. Hydrocyclone underflow is gravity fed to the 

vacuum filters. Each hydrocyclone is supplied with a valve network which can isolate flow to 

individual hydrocyclones. To reduce the suspended solids in the system, a small volume of the 

hydrocyclone overflow is pumped by two purge pumps (1 operating, 1 spare) to the wastewater 

treatment system. 

Cyclone separator underflow gravity flows to the belt vacuum filters for further dewatering. The 

gypsum is dewatered to 90 percent solids and washed to produce wallboard quality gypsum, 

which drops from the belt vacuum filters onto a conveying system. The vacuum receiver filtrate 

pumps pump the filtrate from the belt vacuum filters to the filtrate water tank. The filtrate water 

is recycled back to the FGD system by means of the filtrate water pumps.

One filtrate water tank is provided with minimum storage capacity of 4 hours of water usage by 

the absorber at full load normal operation. One wash tank for combined use of the mist 

eliminator wash system with a minimum storage capacity of 15 minutes is provided.

3.1.5.5 Mercury Removal

Removal of 90 percent of the mercury entering with the coal is achieved in a combination of 

equipment and processes. Since the Illinois No. 6 coal is relatively high in chlorine, most of the 

mercury entering with the coal will leave the boiler in an oxidized form (85-90 percent). The
Carbon Dioxide Capture Sensitivity Analysis

65

SCR system will further promote the oxidation of Hg. Some additional oxidation will occur in 

the airheater, and a small portion of the mercury (oxidized and elemental) will be captured with 

unburned carbon in the baghouse. The majority of the oxidized mercury will be captured in the 

wet scrubber. An inexpensive additive is injected into the wet scrubber to enhance mercury 

removal and inhibit any re-emission to achieve the 90 percent removal rate.

3.1.6 Flue Gas System/Stack

The flue gas from the air preheater will be sent to the absorbers. The gases enter the baghouse to 

collect the waste products and the fly ash. Flue gas exits the baghouse and enters the Induced 

Draft (ID) fan suction.

3.1.7 Carbon Dioxide Recovery Facility

The CO2 recovery facility consists of the Fluor Econamine FG PlusSM system followed by 

compression and drying. 

3.1.7.1 Econamine FG PlusSM

A Carbon Dioxide Recovery (CDR) facility is used to remove 30 to 99 percent of the CO2 in the 

flue gas exiting the FGD unit, purify it, and compress to a supercritical condition. The CDR is 

comprised of the flue gas supply, SO2 polishing, CO2 absorption, solvent stripping and 

reclaiming, and CO2 compression and drying.

The CO2 absorption/stripping/solvents reclaim process is based on the Fluor Econamine FG 

PlusSM technology [39]. A typical flow sheet is shown in Exhibit 3-3. The Econamine FG 

PlusSM process uses a formulation of monethanolamine (MEA) and a proprietary corrosion 

inhibitor to recover CO2 from the flue gas. This process is designed to recover high-purity CO2

from low-pressure streams that contain oxygen, such as flue gas from coal-fired power plants, 

gas turbine exhaust gas, and other waste gases.

SO2 Polishing and Flue Gas Cooling 

To prevent the accumulation of heat stable salts, the incoming flue gas must have an SO2

concentration of 10 ppmv or less. This is achieved by passing the gas exiting the FGD system

through an SO2 polishing step. The polishing step consists of a non-plugging, low-differentialpressure, spray-baffle-type scrubber using a 20 wt% solution of sodium hydroxide (NaOH). A 

removal efficiency of 80 to 85 percent is necessary to reduce SO2 emissions from the FGD outlet 

to 10 ppmv as required by the Econamine process. The polishing scrubber proposed for this 

application has been demonstrated in numerous industrial applications throughout the world and 

can achieve removal efficiencies of over 95 percent if necessary.

The polishing scrubber also serves as the flue gas cooling system. Cooling water from the PC

plant is used to reduce the temperature and hence moisture content of the saturated flue gas 

exiting the FGD system. Flue gas is cooled beyond the CO2 absorption process requirements to 
Carbon Dioxide Capture Sensitivity Analysis

66

32 °C (90 °F) to account for the subsequent temperature increase of about 17 °C (30 °F) in the 

flue gas blower. Downstream from the Polishing Scrubber flue gas pressure is boosted in the 

Flue Gas Blowers by approximately 0.014 MPa (2 psi) to overcome pressure drop in the CO2

absorber tower.

Circulating Water System

Cooling water is provided from the PC plant circulating water system and returned to the plant 

cooling tower. The CDR facility requires a significant amount of cooling water for flue gas 

cooling, water wash cooling, absorber intercooling, reflux condenser duty, reclaimer cooling, the 

lean solvent cooler, and CO2 compression interstage cooling. The cooling water requirements 

for the CDR facility range from 246 m

3

/min (65,000 gpm) to 1,314 m

3

/min (347,000 gpm).

CO2 Absorption 

The cooled flue gas enters the bottom of the CO2 Absorber and flows up through the tower 

countercurrent to a stream of lean MEA-based solvent (Econamine FG PlusSM). Depending on 

the case, 90 to 99 percent of the CO2 in the feed gas is absorbed into the lean solvent, and the rest 

leaves the top of the absorber section and flows into the water wash section of the tower. The 

lean solvent enters the top of the absorber, absorbs the CO2 from the flue gases, and leaves the 

bottom of the absorber with the absorbed CO2. 

Water Wash Section

The purpose of the Water Wash section is to minimize solvent losses due to mechanical 

entrainment and evaporation. The flue gas from the top of the CO2 Absorption section is 

contacted with a recirculating stream of water for the removal of most of the lean solvent. The 

scrubbed gases, along with unrecovered solvent, exit the top of the wash section for discharge to 

the atmosphere via the vent stack. The water stream from the bottom of the wash section is 

collected on a chimney tray. A portion of the water collected on the chimney tray spills over to 

the absorber section as water makeup for the amine with the remainder pumped via the Wash 

Water Pump and cooled by the Wash Water Cooler, and recirculated to the top of the CO2

Absorber. The wash water level is maintained by water makeup from the Wash Water Makeup 

Pump. 
Carbon Dioxide Capture Sensitivity Analysis

67

Exhibit 3-3 Fluor Econamine FG PlusSM Typical Flow Diagram
Carbon Dioxide Capture Sensitivity Analysis

68

Rich/Lean Amine Heat Exchange System

The rich solvent from the bottom of the CO2 Absorber is preheated by the lean solvent from the 

Solvent Stripper in the Rich Lean Solvent Exchanger. The heated rich solvent is routed to the 

Solvent Stripper for removal of the absorbed CO2. The stripped solvent from the bottom of the 

Solvent Stripper is pumped via the Hot Lean Solvent Pumps through the Rich Lean Exchanger to 

the Solvent Surge Tank. Prior to entering the Solvent Surge Tank, a slipstream of the lean 

solvent is pumped via the Solvent Filter Feed Pump through the Solvent Filter Package to 

prevent buildup of contaminants in the solution. From the Solvent Surge Tank the lean solvent is 

pumped via the Warm Lean Solvent Pumps to the Lean Solvent Cooler for further cooling, after 

which the cooled lean solvent is returned to the CO2 Absorber, completing the circulating solvent 

circuit.

Solvent Stripper

The purpose of the Solvent Stripper is to separate the CO2 from the rich solvent feed exiting the 

bottom of the CO2 Absorber. The rich solvent is collected on a chimney tray below the bottom 

packed section of the Solvent Stripper and routed to the Solvent Stripper Reboilers where the 

rich solvent is heated by steam, stripping the CO2 from the solution. Steam is provided from the 

LP section of the steam turbine at 0.51 MPa (74 psia) and 292 °C (557 °F). The hot wet vapor 

from the top of the stripper containing CO2, steam, and solvent vapor, is partially condensed in 

the Solvent Stripper Condenser by cross exchanging the hot wet vapor with cooling water. The 

partially condensed stream then flows to the Solvent Stripper Reflux Drum where the vapor and 

liquid are separated. The uncondensed CO2-rich gas is then delivered to the CO2 product 

compressor. The condensed liquid from the Solvent Stripper Reflux Drum is pumped via the 

Solvent Stripper Reflux Pumps where a portion of condensed overhead liquid is used as make-up 

water for the Water Wash section of the CO2 Absorber. The rest of the pumped liquid is routed 

back to the Solvent Stripper as reflux, which aids in limiting the amount of solvent vapors 

entering the stripper overhead system.

Solvent Stripper Reclaimer 

A small slipstream of the lean solvent from the Solvent Stripper bottoms is fed to the Solvent 

Stripper Reclaimer for the removal of high-boiling nonvolatile impurities (heat stable salts -

HSS), volatile acids and iron products from the circulating solvent solution. The solvent bound 

in the HSS is recovered by reaction with caustic and heating with steam. The solvent reclaimer 

system reduces corrosion, foaming and fouling in the solvent system. The reclaimed solvent is 

returned to the Solvent Stripper and the spent solvent is pumped via the Solvent Reclaimer Drain 

Pump to the Solvent Reclaimer Drain Tank.

Steam Condensate

Steam condensate from the Solvent Stripper Reclaimer accumulates in the Solvent Reclaimer 

Condensate Drum and is level controlled to the Solvent Reboiler Condensate Drum. Steam 

condensate from the Solvent Stripper Reboilers is also collected in the Solvent Reboiler 
Carbon Dioxide Capture Sensitivity Analysis

69

Condensate Drum and returned to the steam cycle between boiler feedwater heaters 4 and 5 via 

the Solvent Reboiler Condensate Pumps.

Corrosion Inhibitor System

A proprietary corrosion inhibitor is continuously injected into the CO2 Absorber rich solvent 

bottoms outlet line, the Solvent Stripper bottoms outlet line and the Solvent Stripper top tray. 

This constant injection is to help control the rate of corrosion throughout the CO2 recovery plant 

system.

Gas Compression and Drying System

In the compression section, the CO2 is compressed to 15.3 MPa (2,215 psia) by a six-stage 

centrifugal compressor. The discharge pressures of the stages were balanced to give reasonable 

power distribution and discharge temperatures across the various stages as shown in Exhibit 3-4.

Exhibit 3-4 CO2 Compressor Interstage Pressures

Stage Outlet Pressure, 

MPa (psia)

1 0.35 (51)

2 0.77 (112)

3 1.69 (245)

4 3.71 (538)

5 8.16 (1,184)

6 15.3 (2,215)

Power consumption for this large compressor was estimated assuming a polytropic efficiency of 

86 percent and mechanical efficiency of 98 percent. During compression to 15.3 MPa (2,215 

psia) in the multiple-stage, intercooled compressor, the CO2 stream is dehydrated to a dewpoint 

of -40 oC (-40 °F) with triethylene glycol. The virtually moisture-free supercritical CO2 stream is 

delivered to the plant battery limit as sequestration-ready. CO2 TS&M costs were estimated and 

included in COE using the methodology described in Section 2.7.

3.1.8 Steam Turbine Generator System

The steam turbine is a tandem compound type, consisting of HP-IP-two LP (double flow) 

sections enclosed in three casings, designed for condensing single reheat operation, and equipped 

with non-automatic extractions and four-flow exhaust. The turbine drives a hydrogen-cooled 

generator. The turbine has DC motor-operated lube oil pumps, and main lube oil pumps, which 
Carbon Dioxide Capture Sensitivity Analysis

70

are driven off the turbine shaft [40]. The exhaust pressure is 35.6 cm (1.4 in) Hg in the single 

pressure condenser. The condenser is two-shell, transverse, single pressure with divided 

waterbox for each shell. The steam turbine is designed for long-term operation (90 days or 

more) at MCR with throttle control valves 95 percent open. It is also capable of a short-term 

5 percent OP/VWO condition (16 hours).

Turbine bearings are lubricated by a closed-loop, water-cooled pressurized oil system. Turbine 

shafts are sealed against air in-leakage or steam blowout using a labyrinth gland arrangement 

connected to a low-pressure steam seal system. The generator stator is cooled with a closed-loop 

water system consisting of circulating pumps, shell and tube or plate and frame type heat 

exchangers, filters, and deionizers, all skid-mounted. The generator rotor is cooled with a 

hydrogen gas recirculation system using fans mounted on the generator rotor shaft. 

Operation Description – The turbine stop valves, control valves, reheat stop valves, and 

intercept valves are controlled by an electro-hydraulic control system. Main steam from the 

boiler passes through the stop valves and control valves and enters the turbine at 24.1 MPa/593

°C (3,500 psig/1,100 °F). The steam initially enters the turbine near the middle of the highpressure span, flows through the turbine, and returns to the boiler for reheating. The reheat 

steam flows through the reheat stop valves and intercept valves and enters the IP section at 593

°C (1,100 °F). After passing through the IP section, the steam enters a crossover pipe, which 

transports the steam to the two LP sections. The steam divides into four paths and flows through 

the LP sections exhausting downward into the condenser. 

The turbine is designed to operate at constant inlet steam pressure over the entire load range.

3.1.8.1 Supercritical Steam Turbine Cycle

The supercritical steam turbine is equipped with six non-automatic steam extractions, which 

along with the HP and IP section exhausts provide steam for four low pressure feedwater heaters, 

deaerator, and three high pressure feedwater heaters. All feedwater heaters (except the 

deaerator) are closed type. The condensate drains from the low pressure heater (#1 through #4) 

are cascaded to the condenser. The condensate drains from the high pressure heaters (#6 through 

#8) are cascaded to the deaerator. The deaerator storage tank provides suction to the boiler 

feedwater pumps. The deaerator is assumed to be placed at high elevation to assure sufficient 

Net Positive Suction Head (NPSH) for the feedwater pumps. Heater #7 is on cold reheat 

extraction and heater #8 is a heater above the reheat point (HARP).

3.1.9 Balance of Plant

The balance of plant components consist of the condensate, feedwater, main and reheat steam, 

extraction steam, ash handling, ducting and stack, waste treatment and miscellaneous systems as 

described below.

3.1.9.1 Condensate

The function of the condensate system is to pump condensate from the condenser hotwell to the 

deaerator, through the gland steam condenser and through the LP feedwater heaters. Each 
Carbon Dioxide Capture Sensitivity Analysis

71

system consists of one main condenser; one variable speed electric motor-driven vertical 

condensate pump with a 100 percent in-line spare; one gland steam condenser; four LP heaters; 

and one deaerator with storage tank.

Condensate is delivered to a common discharge header through two 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 downstream of the gland steam condenser to maintain 

minimum flow requirements for the gland steam condenser and the condensate pumps.

LP feedwater heaters 1 through 4 are 50 percent capacity, parallel flow, and are located in the 

condenser neck. All remaining feedwater heaters are 100 percent capacity shell and U-tube heat 

exchangers. Each LP feedwater heater is provided with inlet/outlet isolation valves and a full 

capacity bypass. LP feedwater heater drains cascade down to the next lowest extraction pressure 

heater and finally discharge into the condenser. Pneumatic level control valves control normal 

drain levels in the heaters. High heater level dump lines discharging to the condenser are 

provided for each heater for turbine water induction protection. Pneumatic level control valves 

control dump line flow.

3.1.9.2 Feedwater

The function of the feedwater system is to pump the feedwater from the deaerator storage tank(s)

through the HP feedwater heaters to the economizer. The SC plants have a single deaerator and 

use one turbine-driven boiler feedwater pump sized at 100 percent capacity (with a 100 percent 

spare) to pump feedwater through the HP feedwater heaters. One 25 percent motor-driven boiler 

feedwater pump for each application is provided for startup. The pumps are provided with inlet 

and outlet isolation valves, and individual minimum flow recirculation lines discharging back to 

the deaerator storage tank. The recirculation flow is controlled by automatic recirculation 

valves, which are a combination check valve in the main line and in the bypass, bypass control 

valve, and flow sensing element. The suction of the boiler feed pump is equipped with startup 

strainers, which are utilized during initial startup and following major outages or system 

maintenance.

Each HP feedwater heater is provided with inlet/outlet isolation valves and a full capacity 

bypass. Feedwater heater drains cascade down to the next lowest extraction pressure heater and 

finally discharge into the deaerator. Pneumatic level control valves control normal drain level in 

the heaters. High heater level dump lines discharging to the condenser are provided for each 

heater for turbine water induction protection. Dump line flow is controlled by pneumatic level 

control valves.

The deaerator is a horizontal, spray tray type with internal direct contact stainless steel vent 

condenser and storage tank. The boiler feed pump turbine is driven by main steam up to 

60 percent plant load. Above 60 percent load, extraction from the IP turbine exhaust provides 

steam to the boiler feed pump steam turbine.

3.1.9.3 Main and Reheat Steam

The function of the main steam system is to convey main steam from the boiler superheater 

outlet to the HP turbine stop valves. The function of the reheat system is to convey steam from 
Carbon Dioxide Capture Sensitivity Analysis

72

the HP turbine exhaust to the boiler reheater and from the boiler reheater outlet to the IP turbine 

stop valves.

Main steam exits the boiler superheater through a motor-operated stop/check valve and a motoroperated gate valve and is routed in a single line feeding the HP turbine. A branch line off the IP 

turbine exhaust feeds the boiler feed water pump turbine during unit operation starting at 

approximately 60 percent load.

Cold reheat steam exits the HP turbine, flows through a motor-operated isolation gate valve and 

a flow control valve, and enters the boiler reheater. Hot reheat steam exits the boiler reheater 

through a motor-operated gate valve and is routed to the IP turbine. 

3.1.9.4 Extraction Steam

The function of the extraction steam system is to convey steam from turbine extraction points to 

the feedwater heaters, deaerator, and CDR facility.

The turbine is protected from overspeed on turbine trip, from flash steam reverse flow from the 

heaters through the extraction piping to the turbine. This protection is provided by positive 

closing, balanced disc non-return valves located in all extraction lines except the lines to the LP 

feedwater heaters in the condenser neck. The extraction non-return valves are located only in 

horizontal runs of piping and as close to the turbine as possible.

The turbine trip signal automatically trips the non-return valves through relay dumps. The 

remote manual control for each heater level control system is used to release the non-return 

valves to normal check valve service when required to restart the system.

3.1.9.5 Circulating Water System

It is assumed that the plant is serviced by a public water facility and has access to groundwater 

for use as makeup cooling water with minimal pretreatment. All filtration and treatment of the 

circulating water are conducted on site. A mechanical draft, counter-flow cooling tower is 

provided for the circulating water heat sink. Two 50 percent circulating water pumps are 

provided. The circulating water system provides cooling water to the condenser, the CDR 

facility, and the auxiliary cooling water system.

The auxiliary cooling water system is a closed-loop system. Plate and frame heat exchangers 

with circulating water as the cooling medium are provided. This system provides cooling water 

to the lube oil coolers, turbine generator, boiler feed pumps, etc. All pumps, vacuum breakers, 

air release valves, instruments, controls, etc. are included for a complete operable system.

3.1.9.6 Ash Handling System

The function of the ash handling system is to provide the equipment required for conveying, 

preparing, storing, and disposing of the fly ash and bottom ash produced on a daily basis by the 

boiler. The scope of the system is from the bag house hoppers, air heater hopper collectors, and 

bottom ash hoppers to the hydrobins (for bottom ash) and truck filling stations (for fly ash). The 
Carbon Dioxide Capture Sensitivity Analysis

73

system is designed to support short-term operation at the 5 percent OP/VWO condition 

(16 hours) and long-term operation at the 100 percent guarantee point (90 days or more). 

The fly ash collected in the bag house and in the air heaters is conveyed to the fly ash storage 

silo. A pneumatic transport system using low-pressure air from a blower provides the transport 

mechanism for the fly ash. Fly ash is discharged through a wet unloader, which conditions the 

fly ash and conveys it through a telescopic unloading chute into a truck for disposal.

The bottom ash from the boiler is fed into a clinker grinder. The clinker grinder is provided to 

break up any clinkers that may form. From the clinker grinders the bottom ash is sluiced to 

hydrobins for dewatering and offsite removal by truck.

Ash from the economizer hoppers and pyrites (rejected from the coal pulverizers) is conveyed by 

hydraulic means (water) to the economizer/pyrites transfer tank. This material is then sluiced, on 

a periodic basis, to the hydrobins. 

3.1.9.7 Ducting and Stack

One stack is provided with a single fiberglass-reinforced plastic (FRP) liner. The stack is 

constructed of reinforced concrete. The stack is 152 m (500 ft) high for adequate particulate 

dispersion. The ID fans were sized large enough to allow for additional stack velocity to 

overcome the buoyancy losses resulting from colder than normal flue gas temperatures following

CO2 capture.

3.1.9.8 Waste Treatment/Miscellaneous Systems

An onsite water treatment facility treats all runoff, cleaning wastes, blowdown, and backwash to 

within the U.S. EPA standards for suspended solids, oil and grease, pH, and miscellaneous 

metals. Waste treatment equipment is housed in a separate building. The waste treatment 

system consists of a water collection basin, three raw waste pumps, an acid neutralization

system, an oxidation system, flocculation, clarification/thickening, and sludge dewatering. The 

water collection basin is a synthetic-membrane-lined earthen basin, which collects rainfall 

runoff, maintenance cleaning wastes, and backwash flows.

The raw waste is pumped to the treatment system at a controlled rate by the raw waste pumps. 

The neutralization system neutralizes the acidic wastewater with hydrated lime in a two-stage 

system, consisting of a lime storage silo/lime slurry makeup system, dry lime feeder, lime slurry 

tank, slurry tank mixer, and lime slurry feed pumps.

The oxidation system consists of an air compressor, which injects air through a sparger pipe into 

the second-stage neutralization tank. The flocculation tank is fiberglass with a variable speed 

agitator. A polymer dilution and feed system is also provided for flocculation. The clarifier is a 

plate-type, with the sludge pumped to the dewatering system. The sludge is dewatered in filter 

presses and disposed offsite. Trucking and disposal costs are included in the cost estimate. The 

filtrate from the sludge dewatering is returned to the raw waste sump.

Miscellaneous systems consisting of fuel oil, service air, instrument air, and service water are 

provided. A storage tank provides a supply of No. 2 fuel oil used for startup and for a small 
Carbon Dioxide Capture Sensitivity Analysis

74

auxiliary boiler. Fuel oil is delivered by truck. All truck roadways and unloading stations inside 

the fence area are provided.

3.1.9.9 Buildings and Structures

Foundations are provided for the support structures, pumps, tanks, and other plant components. 

The following buildings are included in the design basis:

Steam turbine building Fuel oil pump house Guard house

Boiler building Coal crusher building Runoff water pump house

Administration and service 

building

Continuous emissions 

monitoring building

Industrial waste treatment 

building

Makeup water and 

pretreatment building

Pump house and electrical 

equipment building FGD system buildings

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, required foundations, and standby equipment.

3.1.11 Instrumentation and Control

An integrated plant-wide control and monitoring distributed control system (DCS) is provided. 

The DCS is a redundant microprocessor-based, functionally distributed system. The control 

room houses an array of multiple video monitor and keyboard units. The monitor/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 provide 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 implemented as supervised manual, with operator selection of modular 

automation routines available.

3.2 Supercritical PC CO2 Capture Sensitivity

The evaluation scope included developing heat and mass balances and estimating plant 

performance on a common 550 MWe net output basis while firing bituminous Illinois No. 6 coal. 

Equipment lists were developed for each design to support plant capital and operating costs 

estimates. 
Carbon Dioxide Capture Sensitivity Analysis

75

The SC PC plants are assumed to be built on a “greenfield” site and utilize recirculating 

evaporative cooling systems for cycle heat rejection. Major systems for each plant (described in 

Section 3.1) include:

1. Steam Generator

2. Steam Turbine/Generator

3. Particulate control system

4. FGD system

5. SCR system

6. CO2 Recovery

7. Balance of Plant

Support facilities include coal handling (receiving, crushing, and storing), limestone handling 

(including receiving, crushing, storing, and feeding), solid waste disposal, circulating water 

system with evaporative mechanical draft cooling towers, wastewater treatment, and other 

ancillary systems equipment necessary for an efficient, highly available, and completely operable 

facility. 

The plant designs are based on using components suitable for a 30-year life, with provision for 

periodic maintenance and replacement of critical parts. All equipment is based on compliance

with the latest applicable codes and standards. ASME, ANSI, IEEE, NFPA, CAA, state 

regulations, and OSHA codes are all adhered to in the design approach.

The modeling assumptions that were used to generate the SC PC material and energy balances 

are summarized in Exhibit 3-5.

 
Carbon Dioxide Capture Sensitivity Analysis

76

Exhibit 3-5 Supercritical PC Combustion Configuration Modeling Assumptions

Case 1A Case 1B Case 1C Case 1D Case 1E Case 1F Case 1G

Throttle pressure, psig 3500 3500 3500 3500 3500 3500 3500

Throttle temperature, oF 1100 1100 1100 1100 1100 1100 1100

Reheat temperature, oF 1100 1100 1100 1100 1100 1100 1100

Condenser pressure, psia 0.98 0.98 0.98 0.98 0.98 0.98 0.98

Cooling water to condenser, oF 60 60 60 60 60 60 60

Cooling water from condenser, oF 80 80 80 80 80 80 80

Stack temperature saturation saturation saturation saturation saturation saturation saturation

Coal HHV (Illinois No. 6), Btu/lb 11,666 11,666 11,666 11,666 11,666 11,666 11,666

FGD efficiency 98% 98% 98% 98% 98% 98% 98%

SOx emissions, lb/MMBtu 0.1 0.1 0.1 0.1 0.1 0.1 0.1

SCR efficiency 86% 86% 86% 86% 86% 86% 86%

NOx emissions, lb/MMBtu 0.07 0.07 0.07 0.07 0.07 0.07 0.07

Ammonia slip (end of catalyst life), ppm 2 2 2 2 2 2 2

Baghouse efficiency 99.8% 99.8% 99.8% 99.8% 99.8% 99.8% 99.8%

Particulate emissions PM/PM10, lb/MMBtu 0.015 0.015 0.015 0.015 0.015 0.015 0.015 

Mercury removal, % 90 90 90 90 90 90 90

CO2 Capture Efficiency*, % 30 50 70 85 90 95 99

Product CO2 Condition, psia/°F 2215/95 2215/95 2215/95 2215/95 2215/95 2215/95 2215/95

* Percentage of CO2 removed from flue gas 
Carbon Dioxide Capture Sensitivity Analysis

77

3.2.1 CO2 Capture with Partial Bypass Performance Results

A process block flow diagram for Cases 1A through 1D is shown in Exhibit 3-6. These cases 

represent supercritical steam cycles with CO2 capture ranging from 30 to 85 percent. The 

corresponding stream tables are contained in Exhibit 3-7, Exhibit 3-8, Exhibit 3-9, and 

Exhibit 3-10 for 30, 50, 70, and 85 percent CO2 capture, respectively. A series of CO2 capture 

levels was developed by varying the volume of flue gas that bypasses the Econamine FG Plus®

system via Stream 18. Further, the MEA solvent circulation rate and reboiler steam flow rate 

were adjusted to account for the volume of flue gas treated. 

A literature search was conducted to verify that <90 percent CO2 capture is most economical 

using a slip-stream (or bypass) approach. Indeed, the „slip-stream‟ approach is more costeffective for <90 percent CO2 capture than removing reduced CO2 fractions from the entire flue 

gas stream, according to multiple peer-reviewed studies [1, 2, 3]. The cost of CO2 capture with 

the Econamine FG PlusSM process is dependent on the volume of gas being treated and a 

reduction in flue gas flow rate will (1) decrease the quantity of energy consumed by flue gas 

blowers; (2) reduce the size of the CO2 absorption columns; (3) trim the cooling water 

requirement of the direct contact cooling system; and (4) decrease the amount of fan power 

required to increase the flue gas temperature and plume buoyancy. As a result, the slip-stream 

approach for <90 percent CO2 capture leads to lower capital and operating costs. 

Overall performance for Cases 1A through 1D is summarized in Exhibit 3-11 which includes 

auxiliary power requirements.

Material and energy balance information, environmental performance and a major equipment list

are summarized in Sections 3.2.1.1 and 3.2.1.2.
Carbon Dioxide Capture Sensitivity Analysis

78

Exhibit 3-6 Cases 1A Through 1D Process Block Flow Diagram, Supercritical PC with CO2 Capture Bypass

Primary Air Fans

Baghouse FGD ID Fans

Stack gas

Stack

Gypsum Limestone Slurry

Oxidation Air Makeup Water

Bottom Ash Coal Feed

Infiltration air 8

1 2

Forced Draft Fans 3 4

6

5

7

Fly Ash

10 11 13 14

12 15 Pulverized Coal Boiler

SCR 16

Econamine FG+ 20

21 22

CO2 Compression 24 25 CO2 Product

Reboiler Steam Condensate Return

Steam Turbine

Condenser

9

19

18

17

23

Note: Block Flow Diagram is not in complete material balance. Only major process streams and equipment are shown.
Carbon Dioxide Capture Sensitivity Analysis

79

Exhibit 3-7 Case 1A Stream Table, Supercritical PC with 30% CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12 13

V-L Mole Fraction

A r 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 0.0000 0.0000

CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 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 0.0000 0.0000

H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 1.0000 1.0000

N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 0.0000 0.0000

O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 0.0000 0.0000

S O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 53,907 53,907 16,560 16,560 1,409 0 0 76,029 0 76,029 76,029 2,778 10,986

V-L Flowrate (kg/hr) 1,555,598 1,555,598 477,863 477,863 40,669 0 0 2,261,348 0 2,261,348 2,261,348 50,048 197,909

Solids Flowrate (kg/hr) 0 0 0 0 0 207,322 4,021 16,083 16,083 0 0 20,977 0

Temperature (°C) 15 19 15 25 15 15 15 177 15 177 188 15 15

Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 0.10 0.10

Enthalpy (kJ/kg)A 30.23 34.36 30.23 40.78 30.23 --- --- 335.07 --- 316.66 328.98 --- 62.80

Density (kg/m3) 1.2 1.3 1.2 1.3 1.2 --- --- 0.8 --- 0.8 0.8 --- 1,003.1

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 --- --- 29.743 --- 29.743 29.743 --- 18.015

V-L Flowrate (lbmol/hr) 118,845 118,845 36,508 36,508 3,107 0 0 167,616 0 167,616 167,616 6,125 24,219

V-L Flowrate (lb/hr) 3,429,506 3,429,506 1,053,508 1,053,508 89,660 0 0 4,985,419 0 4,985,419 4,985,419 110,337 436,316

Solids Flowrate (lb/hr) 0 0 0 0 0 457,066 8,864 35,457 35,457 0 0 46,247 0

Temperature (°F) 59 66 59 78 59 59 59 350 59 350 371 59 59

Pressure (psia) 14.7 15.3 14.7 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.3 15.0 14.7

Enthalpy (Btu/lb)A 13.0 14.8 13.0 17.5 13.0 --- --- 144.1 --- 136.1 141.4 --- 27.0

Density (lb/ft3) 0.076 0.078 0.076 0.081 0.076 --- --- 0.049 --- 0.049 0.051 --- 62.622

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

80

Exhibit 3-7 Case 1A Stream Table, Supercritical PC with 30% CO2 Capture (continued)

14 15 16 17 18 19 20 21 22 23 24 25

V-L Mole Fraction

A r 0.0092 0.0000 0.0081 0.0081 0.0081 0.0000 0.0000 0.0000 0.0092 0.0089 0.0000 0.0000

CO2 0.0003 0.0004 0.1347 0.1347 0.1347 0.0000 0.0000 0.0000 0.0161 0.1033 0.9873 1.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0099 0.9996 0.1549 0.1549 0.1549 1.0000 1.0000 1.0000 0.1747 0.1204 0.0127 0.0000

N2 0.7732 0.0000 0.6785 0.6785 0.6785 0.0000 0.0000 0.0000 0.7728 0.7414 0.0000 0.0000

O2 0.2074 0.0000 0.0238 0.0238 0.0238 0.0000 0.0000 0.0000 0.0271 0.0260 0.0000 0.0000

S O2 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 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 859 198 83,056 27,658 55,398 101,180 11,731 11,731 24,280 76,004 3,377 3,334

V-L Flowrate (kg/hr) 24,798 3,570 2,392,952 796,853 1,596,099 1,822,780 211,342 211,342 649,315 2,179,226 147,486 146,714

Solids Flowrate (kg/hr) 0 32,425 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 18 58 58 58 58 593 291 151 32 53 21 35

Pressure (MPa, abs) 0.10 0.10 0.10 0.10 0.10 24.23 0.51 0.92 0.10 0.10 0.16 15.27

Enthalpy (kJ/kg)A 32.81 --- 303.64 303.64 303.64 3,477.66 3,046.14 637.34 87.35 244.64 28.22 -212.35

Density (kg/m3) 1.2 --- 1.1 1.1 1.1 69.2 2.0 916.0 1.3 1.1 2.9 794.3

V-L Molecular Weight 28.857 --- 28.811 28.811 28.811 18.015 18.015 18.015 26.743 28.672 43.680 44.010

V-L Flowrate (lbmol/hr) 1,895 437 183,107 60,975 122,132 223,063 25,863 25,863 53,529 167,561 7,444 7,349

V-L Flowrate (lb/hr) 54,671 7,870 5,275,555 1,756,760 3,518,795 4,018,542 465,930 465,930 1,431,495 4,804,370 325,150 323,448

Solids Flowrate (lb/hr) 0 71,485 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 64 136 136 136 136 1,100 556 304 89 127 69 95

Pressure (psia) 15.0 14.8 14.8 14.8 14.8 3,514.7 73.5 133.6 14.8 14.8 23.5 2,214.5

Enthalpy (Btu/lb)A 14.1 --- 130.5 130.5 130.5 1,495.1 1,309.6 274.0 37.6 105.2 12.1 -91.3

Density (lb/ft3) 0.077 --- 0.067 0.067 0.067 4.319 0.123 57.184 0.078 0.067 0.183 49.586

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

81

Exhibit 3-8 Case 1B Stream Table, Supercritical PC with 50% CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12 13

V-L Mole Fraction

A r 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 0.0000 0.0000

CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 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 0.0000 0.0000

H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 1.0000 1.0000

N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 0.0000 0.0000

O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 0.0000 0.0000

S O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 57,711 57,711 17,728 17,728 1,509 0 0 81,394 0 81,394 81,394 2,958 11,774

V-L Flowrate (kg/hr) 1,665,360 1,665,360 511,581 511,581 43,539 0 0 2,420,907 0 2,420,907 2,420,907 53,296 212,114

Solids Flowrate (kg/hr) 0 0 0 0 0 221,950 4,304 17,218 17,218 0 0 22,456 0

Temperature (°C) 15 19 15 25 15 15 15 177 15 177 188 15 15

Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 0.10 0.10

Enthalpy (kJ/kg)A 30.23 34.36 30.23 40.78 30.23 --- --- 335.07 --- 316.66 328.98 --- 62.80

Density (kg/m3) 1.2 1.3 1.2 1.3 1.2 --- --- 0.8 --- 0.8 0.8 --- 1,003.1

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 --- --- 29.743 --- 29.743 29.743 --- 18.015

V-L Flowrate (lbmol/hr) 127,231 127,231 39,084 39,084 3,326 0 0 179,443 0 179,443 179,443 6,522 25,958

V-L Flowrate (lb/hr) 3,671,489 3,671,489 1,127,843 1,127,843 95,987 0 0 5,337,187 0 5,337,187 5,337,187 117,497 467,632

Solids Flowrate (lb/hr) 0 0 0 0 0 489,316 9,490 37,958 37,958 0 0 49,508 0

Temperature (°F) 59 66 59 78 59 59 59 350 59 350 371 59 59

Pressure (psia) 14.7 15.3 14.7 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.3 15.0 14.7

Enthalpy (Btu/lb)A 13.0 14.8 13.0 17.5 13.0 --- --- 144.1 --- 136.1 141.4 --- 27.0

Density (lb/ft3) 0.076 0.078 0.076 0.081 0.076 --- --- 0.049 --- 0.049 0.051 --- 62.622

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

82

Exhibit 3-8 Case 1B Stream Table, Supercritical PC with 50% CO2 Capture (continued)

14 15 16 17 18 19 20 21 22 23 24 25

V-L Mole Fraction

A r 0.0092 0.0000 0.0081 0.0081 0.0081 0.0000 0.0000 0.0000 0.0092 0.0094 0.0000 0.0000

CO2 0.0003 0.0004 0.1347 0.1347 0.1347 0.0000 0.0000 0.0000 0.0154 0.0784 0.9874 1.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0099 0.9996 0.1550 0.1550 0.1550 1.0000 1.0000 1.0000 0.1749 0.0946 0.0126 0.0000

N2 0.7732 0.0000 0.6785 0.6785 0.6785 0.0000 0.0000 0.0000 0.7734 0.7900 0.0000 0.0000

O2 0.2074 0.0000 0.0238 0.0238 0.0238 0.0000 0.0000 0.0000 0.0271 0.0277 0.0000 0.0000

S O2 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 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 907 212 88,902 49,429 39,472 108,299 21,169 21,169 43,359 76,353 6,069 5,992

V-L Flowrate (kg/hr) 26,187 3,829 2,561,398 1,424,137 1,137,261 1,951,032 381,357 381,357 1,158,952 2,179,503 265,093 263,713

Solids Flowrate (kg/hr) 0 34,712 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 18 58 58 58 58 593 291 151 32 48 21 35

Pressure (MPa, abs) 0.10 0.10 0.10 0.10 0.10 24.23 0.51 0.92 0.10 0.10 0.16 15.27

Enthalpy (kJ/kg)A 32.81 --- 303.63 303.63 303.63 3,477.66 3,046.14 637.34 87.38 199.38 28.23 -212.35

Density (kg/m3) 1.2 --- 1.1 1.1 1.1 69.2 2.0 916.0 1.3 1.1 2.9 794.3

V-L Molecular Weight 28.857 --- 28.812 28.812 28.812 18.015 18.015 18.015 26.729 28.545 43.682 44.010

V-L Flowrate (lbmol/hr) 2,001 468 195,994 108,973 87,021 238,758 46,669 46,669 95,590 168,330 13,379 13,210

V-L Flowrate (lb/hr) 57,733 8,443 5,646,915 3,139,685 2,507,230 4,301,289 840,749 840,749 2,555,051 4,804,981 584,429 581,387

Solids Flowrate (lb/hr) 0 76,527 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 64 136 136 136 136 1,100 556 304 89 118 69 95

Pressure (psia) 15.0 14.8 14.8 14.8 14.8 3,514.7 73.5 133.6 14.8 14.8 23.5 2,214.5

Enthalpy (Btu/lb)A 14.1 --- 130.5 130.5 130.5 1,495.1 1,309.6 274.0 37.6 85.7 12.1 -91.3

Density (lb/ft3) 0.077 --- 0.067 0.067 0.067 4.319 0.123 57.184 0.078 0.068 0.183 49.586

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

83

Exhibit 3-9 Case 1C Stream Table, Supercritical PC with 70% CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12 13

V-L Mole Fraction

A r 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 0.0000 0.0000

CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 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 0.0000 0.0000

H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 1.0000 1.0000

N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 0.0000 0.0000

O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 0.0000 0.0000

S O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 62,010 62,010 19,049 19,049 1,621 0 0 87,457 0 87,457 87,457 3,143 12,662

V-L Flowrate (kg/hr) 1,789,408 1,789,408 549,687 549,687 46,782 0 0 2,601,235 0 2,601,235 2,601,235 56,619 228,115

Solids Flowrate (kg/hr) 0 0 0 0 0 238,483 4,625 18,500 18,500 0 0 24,011 0

Temperature (°C) 15 19 15 25 15 15 15 177 15 177 188 15 15

Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 0.10 0.10

Enthalpy (kJ/kg)A 30.23 34.36 30.23 40.78 30.23 --- --- 335.07 --- 316.66 328.98 --- 62.80

Density (kg/m3) 1.2 1.3 1.2 1.3 1.2 --- --- 0.8 --- 0.8 0.8 --- 1,003.1

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 --- --- 29.743 --- 29.743 29.743 --- 18.015

V-L Flowrate (lbmol/hr) 136,708 136,708 41,995 41,995 3,574 0 0 192,809 0 192,809 192,809 6,929 27,916

V-L Flowrate (lb/hr) 3,944,969 3,944,969 1,211,853 1,211,853 103,136 0 0 5,734,741 0 5,734,741 5,734,741 124,823 502,908

Solids Flowrate (lb/hr) 0 0 0 0 0 525,764 10,196 40,786 40,786 0 0 52,935 0

Temperature (°F) 59 66 59 78 59 59 59 350 59 350 371 59 59

Pressure (psia) 14.7 15.3 14.7 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.3 15.0 14.7

Enthalpy (Btu/lb)A 13.0 14.8 13.0 17.5 13.0 --- --- 144.1 --- 136.1 141.4 --- 27.0

Density (lb/ft3) 0.076 0.078 0.076 0.081 0.076 --- --- 0.049 --- 0.049 0.051 --- 62.622

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

84

Exhibit 3-9 Case 1C Stream Table, Supercritical PC with 70% CO2 Capture (continued)

14 15 16 17 18 19 20 21 22 23 24 25

V-L Mole Fraction

A r 0.0092 0.0000 0.0081 0.0081 0.0081 0.0000 0.0000 0.0000 0.0092 0.0101 0.0000 0.0000

CO2 0.0003 0.0004 0.1347 0.1347 0.1347 0.0000 0.0000 0.0000 0.0160 0.0507 0.9873 1.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0099 0.9996 0.1550 0.1550 0.1550 1.0000 1.0000 1.0000 0.1748 0.0668 0.0127 0.0000

N2 0.7732 0.0000 0.6785 0.6785 0.6785 0.0000 0.0000 0.0000 0.7730 0.8429 0.0000 0.0000

O2 0.2074 0.0000 0.0238 0.0238 0.0238 0.0000 0.0000 0.0000 0.0271 0.0295 0.0000 0.0000

S O2 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 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 984 230 95,534 74,325 21,208 116,344 31,643 31,643 65,239 76,894 9,084 8,969

V-L Flowrate (kg/hr) 28,385 4,140 2,752,462 2,141,416 611,047 2,095,977 570,060 570,060 1,744,469 2,183,416 396,807 394,733

Solids Flowrate (kg/hr) 0 37,179 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 18 58 58 58 58 593 291 151 32 41 21 35

Pressure (MPa, abs) 0.10 0.10 0.10 0.10 0.10 24.23 0.51 0.92 0.10 0.10 0.16 15.27

Enthalpy (kJ/kg)A 32.81 --- 303.63 303.63 303.63 3,477.66 3,046.14 637.34 87.36 148.96 28.22 -212.35

Density (kg/m3) 1.2 --- 1.1 1.1 1.1 69.2 2.0 916.0 1.3 1.1 2.9 794.3

V-L Molecular Weight 28.857 --- 28.811 28.811 28.811 18.015 18.015 18.015 26.740 28.395 43.680 44.010

V-L Flowrate (lbmol/hr) 2,169 506 210,616 163,859 46,757 256,495 69,761 69,761 143,826 169,522 20,028 19,774

V-L Flowrate (lb/hr) 62,577 9,128 6,068,141 4,721,014 1,347,127 4,620,838 1,256,768 1,256,768 3,845,896 4,813,608 874,811 870,237

Solids Flowrate (lb/hr) 0 81,967 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 64 136 136 136 136 1,100 556 304 89 107 69 95

Pressure (psia) 15.0 14.8 14.8 14.8 14.8 3,514.7 73.5 133.6 14.8 14.8 23.5 2,214.5

Enthalpy (Btu/lb)A 14.1 --- 130.5 130.5 130.5 1,495.1 1,309.6 274.0 37.6 64.0 12.1 -91.3

Density (lb/ft3) 0.077 --- 0.067 0.067 0.067 4.319 0.123 57.184 0.078 0.069 0.183 49.586

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

85

Exhibit 3-10 Case 1D Stream Table, Supercritical PC with 85% CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12 13

V-L Mole Fraction

A r 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 0.0000 0.0000

CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 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 0.0000 0.0000

H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 1.0000 1.0000

N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 0.0000 0.0000

O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 0.0000 0.0000

S O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 65,727 65,727 20,191 20,191 1,718 0 0 92,700 0 92,700 92,700 3,389 13,388

V-L Flowrate (kg/hr) 1,896,682 1,896,682 582,641 582,641 49,586 0 0 2,757,177 0 2,757,177 2,757,177 61,050 241,185

Solids Flowrate (kg/hr) 0 0 0 0 0 252,779 4,902 19,609 19,609 0 0 25,555 0

Temperature (°C) 15 19 15 25 15 15 15 177 15 177 188 15 15

Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 0.10 0.10

Enthalpy (kJ/kg)A 30.23 34.36 30.23 40.78 30.23 --- --- 335.07 --- 316.66 328.98 --- 62.80

Density (kg/m3) 1.2 1.3 1.2 1.3 1.2 --- --- 0.8 --- 0.8 0.8 --- 1,003.1

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 --- --- 29.743 --- 29.743 29.743 --- 18.015

V-L Flowrate (lbmol/hr) 144,903 144,903 44,513 44,513 3,788 0 0 204,368 0 204,368 204,368 7,471 29,515

V-L Flowrate (lb/hr) 4,181,468 4,181,468 1,284,503 1,284,503 109,319 0 0 6,078,535 0 6,078,535 6,078,535 134,592 531,721

Solids Flowrate (lb/hr) 0 0 0 0 0 557,283 10,808 43,231 43,231 0 0 56,339 0

Temperature (°F) 59 66 59 78 59 59 59 350 59 350 371 59 59

Pressure (psia) 14.7 15.3 14.7 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.3 15.0 14.7

Enthalpy (Btu/lb)A 13.0 14.8 13.0 17.5 13.0 --- --- 144.1 --- 136.1 141.4 --- 27.0

Density (lb/ft3) 0.076 0.078 0.076 0.081 0.076 --- --- 0.049 --- 0.049 0.051 --- 62.622

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

86

Exhibit 3-10 Case 1D Stream Table, Supercritical PC with 85% CO2 Capture (continued)

14 15 16 17 18 19 20 21 22 23 24 25

V-L Mole Fraction

A r 0.0092 0.0000 0.0081 0.0081 0.0081 0.0000 0.0000 0.0000 0.0092 0.0106 0.0000 0.0000

CO2 0.0003 0.0004 0.1347 0.1347 0.1347 0.0000 0.0000 0.0000 0.0158 0.0270 0.9873 1.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0099 0.9996 0.1549 0.1549 0.1549 1.0000 1.0000 1.0000 0.1748 0.0453 0.0127 0.0000

N2 0.7732 0.0000 0.6785 0.6785 0.6785 0.0000 0.0000 0.0000 0.7731 0.8861 0.0000 0.0000

O2 0.2074 0.0000 0.0238 0.0238 0.0238 0.0000 0.0000 0.0000 0.0271 0.0311 0.0000 0.0000

S O2 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 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 1,047 244 101,266 95,595 5,671 123,302 40,669 40,669 83,895 77,537 11,696 11,548

V-L Flowrate (kg/hr) 30,210 4,400 2,917,608 2,754,222 163,386 2,221,322 732,658 732,658 2,243,114 2,189,783 510,904 508,236

Solids Flowrate (kg/hr) 0 39,513 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 18 58 58 58 58 593 291 151 32 35 21 35

Pressure (MPa, abs) 0.10 0.10 0.10 0.10 0.10 24.23 0.51 0.92 0.10 0.10 0.16 15.27

Enthalpy (kJ/kg)A 32.81 --- 303.64 303.64 303.64 3,477.66 3,046.14 637.34 87.36 107.94 28.22 -212.35

Density (kg/m3) 1.2 --- 1.1 1.1 1.1 69.2 2.0 916.0 1.3 1.1 2.9 794.3

V-L Molecular Weight 28.857 --- 28.811 28.811 28.811 18.015 18.015 18.015 26.737 28.242 43.681 44.010

V-L Flowrate (lbmol/hr) 2,308 538 223,253 210,751 12,502 271,835 89,659 89,659 184,958 170,939 25,786 25,460

V-L Flowrate (lb/hr) 66,601 9,700 6,432,224 6,072,019 360,205 4,897,176 1,615,234 1,615,234 4,945,220 4,827,645 1,126,351 1,120,468

Solids Flowrate (lb/hr) 0 87,111 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 64 136 136 136 136 1,100 556 304 89 94 69 95

Pressure (psia) 15.0 14.8 14.8 14.8 14.8 3,514.7 73.5 133.6 14.8 14.8 23.5 2,214.5

Enthalpy (Btu/lb)A 14.1 --- 130.5 130.5 130.5 1,495.1 1,309.6 274.0 37.6 46.4 12.1 -91.3

Density (lb/ft3) 0.077 --- 0.067 0.067 0.067 4.319 0.123 57.184 0.078 0.070 0.183 49.586

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

87

Exhibit 3-11 Cases 1A Through 1D Performance Modeling Results 

POWER SUMMARY (Gross Power at Generator 

Terminals, kWe)

Case 1A 

(30%)

Case 1B 

(50%)

Case 1C 

(70%)

Case 1D 

(85%)

Steam Turbine Power 601,500 618,200 637,800 654,800

AUXILIARY LOAD SUMMARY, kWe1

Coal Handling and Conveying 460 470 490 500

Limestone Handling & Reagent Preparation 1,010 1,080 1,160 1,230

Pulverizers 3,110 3,330 3,580 3,790

Ash Handling 590 640 680 720

Primary Air Fans 1,450 1,550 1,670 1,770

Forced Draft Fans 1,850 1,980 2,130 2,260

Induced Draft Fans 8,020 8,590 9,230 9,780

SCR 20 20 20 20

Baghouse 80 80 90 90

FGD Pumps and Agitators 3,310 3,550 3,810 4,040

Econamine FG Plus Auxiliaries 5,500 9,900 14,800 19,100

CO2 Compression 11,790 21,200 31,730 40,860

Econamine Condensate Pump 40 70 110 140

Miscellaneous Balance of Plant 2

2,000 2,000 2,000 2,000

Steam Turbine Auxiliaries 400 400 400 400

Condensate Pumps 720 680 630 590

Circulating Water Pumps 5,820 6,710 8,260 9,600

Cooling Tower Fans 3,400 3,920 4,820 5,610

Transformer Loss 1,940 2,040 2,150 2,250

TOTAL AUXILIARIES, kWe 51,510 68,210 87,760 104,750

NET POWER, kWe 549,990 549,990 550,040 550,050

Net Plant Efficiency, % (HHV) 35.2% 32.9% 30.6% 28.9%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 10,229 (9,695) 10,950 (10,379) 11,765 (11,151) 12,470 (11,819)

CONDENSER COOLING DUTY GJ/hr (106 Btu/hr) 2,164 (2,051) 2,037 (1,931) 1,900 (1,801) 1,783 (1,690)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr)3

207,322 (457,066) 221,950 (489,316) 238,483 (525,764) 252,779 (557,283)

Thermal Input, kWt 1,562,693 1,672,956 1,797,570 1,905,333

Raw Water Withdrawal, m3/min (gpm) 23.6 (6,245) 26.4 (6,987) 31.7 (8,386) 36.4 (9,615)

Raw Water Consumption, m3/min (gpm) 18.5 (4,898) 20.6 (5,433) 24.5 (6,474) 28.0 (7,392)

Notes: 1. Boiler feed pumps are turbine driven

2. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

3. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)
Carbon Dioxide Capture Sensitivity Analysis

88

3.2.1.1 Environmental Performance for Cases 1A through 1D

Each case was designed to meet presumptive BACT standards utilizing the emissions control 

processes described in Section 2.4. A summary of plant air emissions is presented in 

Exhibit 3-12.

SO2 emissions are controlled using a wet limestone forced oxidation FGD that achieves a 

removal efficiency of 98%. To avoid the formation of heat stable salts in the Econamine 

process, an SO2 polishing step is included to reduce the sulfur content to 10 ppm prior to the CO2

absorber, and the balance of the SO2 is absorbed by the MEA solution resulting in negligible 

stack emissions. The byproduct calcium sulfate is dewatered and stored on site. The wallboard 

grade material can potentially be marketed and sold, but since it is highly dependent on local 

market conditions, no byproduct credit was taken. The saturated flue gas exiting the FGD is 

vented through the plant stack.

Particulate emissions are controlled using a pulse jet fabric filter (baghouse) which operates at an 

efficiency of 99.8 percent. It was assumed that 20 percent of the ash exits the boiler as bottom 

ash and the remaining 80 percent exits the boiler in the flue gas [41].

Co-benefit capture of Hg in the fabric filter and FGD system was assumed to achieve a 90

percent capture rate [42]. The high chlorine content of the Illinois No. 6 coal and the SCR 

system will convert most of the Hg in the system to an oxidized state [43]. An inexpensive FGD 

system additive can be used to promote Hg capture if necessary, but was not included.

The carbon balance for the four cases is shown in Exhibit 3-13. The carbon input to the plant 

consists of carbon in the coal, limestone, and combustion and FGD forced oxidation air. 

CO2 capture efficiency is calculated as the pounds of CO2 captured divided by the pounds of CO2

produced. Most of the CO2 produced comes from coal combustion, but a small amount is 

formed in the FGD system. The sum of these two sources is the amount produced.

(Carbon in Sequestration Product) / (Carbon in the Coal + Net Carbon from Limestone) or

 88,274 / (291,355 + 4,206) *100 = 30% (Case 1A)

158,670 / (311,913 + 4,502) *100 = 50% (Case 1B) 

237,502 / (335,147 + 4,837) *100 = 70% (Case 1C) 

305,794 / (355,239 + 5,128) *100 = 85% (Case 1D)

Exhibit 3-14 shows the sulfur balance for the four cases. Sulfur input comes solely from the 

sulfur in the coal. Sulfur output is the gypsum sulfur byproduct, and the sulfur emitted in the 

stack gas. The total sulfur capture is represented by the following fraction:

(Sulfur byproduct/Sulfur in the coal) or

(11,227/11,456)*100 = 98.0% (Case 1A)

(12,019/12,264)*100 = 98.0% (Case 1B)

(12,914/13,178)*100 = 98.0% (Case 1C)

(13,688/13,968)*100 = 98.0% (Case 1D)

 
Carbon Dioxide Capture Sensitivity Analysis

89

The overall water balances for Case 1A, 1B, 1C, and 1D are shown in Exhibit 3-15, Exhibit 3-16, 

Exhibit 3-17, and Exhibit 3-18, respectively. Raw water is obtained from groundwater (50 

percent) and from municipal sources (50 percent). Water demand represents the total amount of 

water required for a particular process. Some water is recovered within the process and that 

water is reused as internal recycle. Raw water withdrawal is the difference between water 

demand and internal recycle. Process water discharged from the power plant is also accounted

for in this study. Raw water consumption represents raw water withdrawal less process water 

discharge.

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-19 through 

Exhibit 3-26.

Boiler and flue gas cleanup

Steam and feedwater

An overall plant energy balance is provided in tabular form for Case 1A, 1B, 1C, and 1D in 

Exhibit 3-27, Exhibit 3-28, Exhibit 3-29, and Exhibit 3-30, respectively. The power out is the 

steam turbine power after generator losses. In addition, energy balance Sankey diagrams are 

provided in Exhibit 3-31, Exhibit 3-32, Exhibit 3-33, and Exhibit 3-34 for Case 1A, 1B, 1C, and 

1D, respectively.
Carbon Dioxide Capture Sensitivity Analysis

90

Exhibit 3-12 Cases 1A through 1D Estimated Air Emission Rates

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

85% capacity factor

kg/MWh

(lb/MWh)

Case 1A Case 1B Case 1C Case 1D Case 1A Case 1B Case 1C Case 1D Case 1A Case 1B Case 1C Case 1D

SO2

0.028 

(0.064)

0.022 

(0.050)

0.015

(0.036)

0.007 

(0.017)

1,159

(1,278)

964 

(1,063)

740 

(816)

370 

(408)

0.259 

(0.570)

0.210 

(0.460)

0.156

(0.340)

0.076 

(0.170)

NOX

0.030 

(0.070)

0.030 

(0.070)

0.030 

(0.070)

0.030 

(0.070)

1,261 

(1,390)

1,350

(1,488)

1,450

(1,598)

1,537 

(1,694)

0.281 

(0.621)

0.293 

(0.646)

0.305 

(0.673)

0.315 

(0.695)

PM 0.006 

(0.0130)

0.006 

(0.0130)

0.006 

(0.0130)

0.006 

(0.0130)

234 

(258)

251 

(276)

269 

(297)

285 

(315)

0.052

(0.115)

0.054 

(0.120)

0.057 

(0.125)

0.059 

(0.129)

Hg 0.49x10-6

(1.14x10-6)

0.49x10-6

(1.14x10-6)

0.49x10-6

(1.14x10-6)

0.49x10-6

(1.14x10-6)

0.021 

(0.023)

0.022 

(0.024)

0.024 

(0.026)

0.025 

(0.028)

4.60x10-6

(10.1x10-6)

4.79x10-6

(10.6x10-6)

4.99x10-6

(11.0x10-6)

5.15x10-6

(11.3x10-6)

CO2

61.4 

(142.9)

43.7 

(101.7)

26.5 

(61.7)

13.4 

(31.2)

2,573,010

(2,836,258)

1,960,464

(2,161,042)

1,277,186 

(1,407,857)

684,813

(754,877)

574 

(1,267)

426 

(939)

269 

(593)

140 

(310)

CO2

net 628 (1,385) 479 (1,055) 312 (687) 167 (369)
Carbon Dioxide Capture Sensitivity Analysis

91

Exhibit 3-13 Cases 1A through 1D Carbon Balance

Carbon In, kg/hr (lb/hr)

Case 1A Case 1B Case 1C Case 1D

Coal 132,157

(291,355)

141,481

(311,913)

152,020

(335,147)

161,134

(355,239)

Air (CO2) 282 (622) 302 (666) 324 (715) 344 (758)

Limestone 2,129

(4,693)

2,279

(5,024)

2,436

(5,371)

2,593

(5,717)

Total 134,568

(296,670)

144,062

(317,603)

154,780

(341,233)

164,071

(361,714)

Carbon Out, kg/hr (lb/hr)

Stack Gas 94,308

(207,913)

71,856

(158,416)

46,812

(103,204)

25,100

(55,337)

CO2 Product 40,041

(88,274)

71,972

(158,670)

107,729

(237,502)

138,706

(305,794)

Gypsum 221 (487) 237 (522) 242 (534) 267 (589)

Convergence 

Tolerance* -2 (-4) -3 (-5) -3 (-7) -2 (-6)

Total 134,568

(296,670)

144,062 

(317,603)

154,780 

(341,233)

164,071 

(361,714)

Exhibit 3-14 Cases 1A through 1D Sulfur Balance

Sulfur In, kg/hr (lb/hr)

Case 1A Case 1B Case 1C Case 1D

Coal 5,196

(11,456)

5,563

(12,264)

5,977

(13,178)

6,336

(13,968)

Total 5,196

(11,456)

5,563

(12,264)

5,977

(13,178)

6,336

(13,968)

Sulfur Out, kg/hr (lb/hr)

Gypsum 5,092

(11,227)

5,452

(12,019)

5,858

(12,914)

6,209

(13,688)

Stack Gas 78 (172) 65 (143) 50 (110) 25 (55)

AGR 26 (57) 46 (102) 70 (154) 102 (224)

Convergence 

Tolerance* 0 (0) 0 (0) -1 (0) 0 (1)

Total 5,196 

(11,456)

5,563

(12,264)

5,977

(13,178)

6,336

(13,968)
Carbon Dioxide Capture Sensitivity Analysis

92

Exhibit 3-15 Case 1A (30%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Econamine 0.04 (10) 0.0 (0) 0.04 (10) 0.0 (0) 0.04 (10)

FGD Makeup 4.14 (1,093) 0.0 (0) 4.14 (1,093) 0.0 (0) 4.14 (1,093)

BFW Makeup 0.30 (80) 0.0 (0) 0.30 (80) 0.0 (0) 0.30 (80)

Cooling Tower 

Makeup 22.7 (5,990) 3.51 (928) 19.2 (5,062) 5.10 (1,347) 14.06 (3,715)

Total 27.2 (7,174) 3.51 (928) 23.6 (6,245) 5.10 (1,347) 18.5 (4,898)

Total, 

gal/MWhnet

783 101 681 147 534

Exhibit 3-16 Case 1B (50%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Econamine 0.07 (17) 0.0 (0) 0.07 (17) 0.0 (0) 0.07 (17)

FGD Makeup 4.43 (1,170) 0.0 (0) 4.43 (1,170) 0.0 (0) 4.43 (1,170)

BFW Makeup 0.33 (86) 0.0 (0) 0.33 (86) 0.0 (0) 0.33 (86)

Cooling Tower 

Makeup 26.2 (6,909) 4.53 (1,196) 21.6 (5,713) 5.9 (1,554) 15.75 (4,159)

Total 31.0 (8,183) 4.53 (1,196) 26.4 (6,987) 5.9 (1,554) 20.6 (5,433)

Total, 

gal/MWhnet

893 130 762 170 593
Carbon Dioxide Capture Sensitivity Analysis

93

Exhibit 3-17 Case 1C (70%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Econamine 0.10 (26) 0.0 (0) 0.10 (26) 0.0 (0) 0.10 (26)

FGD Makeup 4.75 (1,255) 0.0 (0) 4.75 (1,255) 0.0 (0) 4.75 (1,255)

BFW Makeup 0.35 (92) 0.0 (0) 0.35 (92) 0.0 (0) 0.35 (92)

Cooling Tower 

Makeup 32.2 (8,501) 5.64 (1,489) 26.5 (7,012) 7.2 (1,912) 19.31 (5,101)

Total 37.4 (9,875) 5.64 (1,489) 31.7 (8,386) 7.2 (1,912) 24.5 (6,474)

Total, 

gal/MWhnet

1,077 162 915 209 706

Exhibit 3-18 Case 1D (85%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Econamine 0.13 (33) 0.0 (0) 0.13 (33) 0.0 (0) 0.13 (33)

FGD Makeup 5.04 (1,333) 0.0 (0) 5.04 (1,333) 0.0 (0) 5.04 (1,333)

BFW Makeup 0.37 (98) 0.0 (0) 0.37 (98) 0.0 (0) 0.37 (98)

Cooling Tower 

Makeup 37.4 (9,882) 6.55 (1,731) 30.9 (8,151) 8.4 (2,222) 22.44 (5,929)

Total 42.9 (11,346) 6.55 (1,731) 36.4 (9,615) 8.4 (2,222) 28.0 (7,392)

Total, 

gal/MWhnet

1,238 189 1,049 242 806
Carbon Dioxide Capture Sensitivity Analysis

94

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Carbon Dioxide Capture Sensitivity Analysis

95

Exhibit 3-19 Case 1A (30%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Coal / Ash

Water

Steam

PAGES 1 OF 2 CO2 CAPTURE SENSITIVITY ANALYSIS CASE 1A (30%) SUPERCRITICAL PULVERIZED COAL BOILER AND GAS CLEANUP SYSTEMS DWG. NO. CCSA-HMB-CS-1A-PG-1

Pulverized Coal Boiler

AMMONIA SCR INFILTRATION AIR

AIR

AIR

COAL

ASH From Feedwater Heaters

Single Reheat To IP Turbine

Throttle Steam To HP Turbine

FGD

ASH

FORCED DRAFT FANS

PRIMARY AIR FANS

STACK 457,066 W 77.8 T 16.1 P 17.5 H

66.4 T 15.3 P 14.8 H

4,018,542 W 1,100.0 T 3,514.7 P 1,495.1 H 3,273,047 W 1,100.0 T 655.8 P 1,570.6 H

Single Reheat Extraction from HP Turbine 1,053,508 W 59.0 T 14.7 P 13.0 H

3,429,506 W 59.0 T 14.7 P 13.0 H

89,660 W 59.0 T 14.7 P 13.0 H

5,020,876 W 350.0 T 14.4 P 144.1 H

8,864 W

35,457 W

3,273,047 W 669.0 T 710.8 P 1,325.7 H

4,018,542 W 545.5 T 4,185.0 P 539.7 H

5

5,275,555 W 135.8 T 14.8 P 130.5 H

3

1 2

4

6

7

19 8 9 ID FANS 16 4,985,419 W 350.0 T 14.2 P 136.1 H

Gross Plant Power: 602 MWe Auxiliary Load: 52 MWe Net Plant Power: 550 MWe Net Plant Efficiency, HHV: 35.2% Net Plant Heat Rate: 9,695 BTU/KWe

Limestone Slurry

Flue Gas

OXIDATION AIR MAKE-UP WATER

LIMESTONE SLURRY GYPSUM

15 12

13 14 10 11

370.7 T 15.3 P 141.4 H 156,584 W 59.0 T 15.0 P

54,671 W 63.6 T 15.0 P 14.1 H 436,316 W 59.0 T 14.7 P -19.7 H

79,355 W 135.8 T 14.8 P

DOE/NETL SC PC PLANT CASE 1A STRIPPER

ABSORBER FLUE GAS Acid Gas

ECONAMINE FG+

ECONAMINE CONDENSATE

20

21 65,827 W

306.3 T 73.5 P 1,181.4 H 465,930 W 556.3 T 73.5 P 1,309.6 H

465,930 W 304.0 T 133.6 P 274.0 H

ECONAMINE STEAM

323,448 W 95.0 T 2,214.5 P -91.3 H

325,150 W 69.0 T 23.5 P 12.1 H 4,804,370 W 126.6 T 14.8 P 105.2 H CO2 COMPRESSION (INTERSTAGE COOLING)

CO2 PRODUCT

Baghouse

24 25

23

18 3,518,795 W

1,756,760 W

1,431,495 W 88.8 T 14.8 P 37.6 H 17 22

Ammonia

Carbon Dioxide Gypsum
Carbon Dioxide Capture Sensitivity Analysis

96

Exhibit 3-20 Case 1A (30%) Heat and Mass Balance, Power Block Systems

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Water

Steam

PAGES 2 OF 2 DWG. NO. CCSA-HMB-CS-1A-PG-2 CO2 CAPTURE SENSITIVITY ANALYSIS CASE 1A (30%) SUPERCRITICAL PULVERIZED COAL POWER BLOCK SYSTEMS

LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER HOT WELL To Boiler

BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR

Throttle Steam

Single Reheat Extraction From Boiler

GLAND SEAL CONDENSER

CONDENSATE PUMPS

4,018,542 W 1,100.0 T 3,514.7 P 1,495.1 H

2,900.0 P

227,935 W 803.0 T 211.9 P 1,426.5 H 489,880 W 665.2 T 700.8 P 1,324.1 H

Single Reheat Extraction to Boiler 3,273,047 W 669.0 T 710.8 P 1,325.7 H 710.8 P

1,115.5 P

224,757 W 763.9 T 990.5 P 1,367.9 H

710.8 P

710.8 P

221.9 P

75.0 P

75.0 P

298,978 W 556.3 T 73.5 P 1,309.6 H

126.1 T 2.0 P 1,085.8 H 1,850,820 W 101.1 T 1.0 P 1,009.9 H

2,793 W 212.0 T 14.7 P 180.3 H

29.0 P

11.4 P

4.5 P

101.4 T 250.0 P 70.4 H

2,793 W 674.7 T 75.0 P 1,368.1 H 2,504,281 W 101.1 T 1.0 P 69.5 H

2,504,281 W 102.8 T 245.0 P 71.8 H 2,504,281 W 123.8 T 240.0 P 92.7 H 308,204 W 112.8 T 1.4 P 81.1 H 259,980 W 133.8 T 2.5 P 102.0 H

2,504,281 W 235.0 T 225.0 P 204.0 H 942,573 W 321.8 T 91.9 P 292.3 H

2,504,281 W 190.2 T 230.0 P 158.9 H 714,637 W 398.7 T 243.6 P 373.7 H 224,757 W 513.3 T 765.9 P 503.8 H

4,018,542 W 388.7 T 4,195.0 P 368.3 H 4,018,542 W 503.3 T 4,190.0 P 491.4 H DEAERATOR

BOILER FEED PUMPS

4,018,542 W 545.5 T 4,185.0 P 539.7 H

19 3,273,047 W 1,100.0 T 655.8 P 1,570.6 H

106,862 W 200.2 T 11.6 P 168.4 H 198,466 W 161.0 T 4.9 P 129.2 H

2,504,281 W 151.0 T 235.0 P 119.8 H 145,944 W 583.9 T 70.0 P 1,323.5 H 106,862 W 370.1 T 25.0 P 1,224.0 H 91,603 W 216.1 T 10.4 P 1,154.1 H 61,514 W 156.0 T 4.3 P 1,117.1 H 48,224 W 128.8 T 2.2 P 1,054.6 H

2,900.0 P

2,918,947 W 556.3 T 73.5 P 1,309.6 H 2,154,039 W 556.3 T 73.5 P 1,309.6 H

2.3 P

2,900.0 P

Steam Turbine Makeup

40,185 W 59.0 T 14.7 P 27.5 H

311.8 T 4,200.0 P 289.5 H 4,018,542 W 302.9 T 70.0 P 272.8 H

3,301 W 674.7 T 75.0 P 1,368.1 H

Gross Plant Power: 602 MWe Auxiliary Load: 52 MWe Net Plant Power: 550 MWe Net Plant Efficiency, HHV: 35.2% Net Plant Heat Rate: 9,695 BTU/KWe FWH 4 FWH 3 FWH 2 FWH 1 FWH 8 FWH 7 FWH 6

4,985 W 674.7 T 75.0 P 1,368.1 H

DOE/NETL SC PC PLANT CASE 1A

465,930 W 304.0 T 133.6 P 274.0 H

ECONAMINE CONDENSATE

21

465,930 W 556.3 T 73.5 P 1,309.6 H ECONAMINE STEAM 20
Carbon Dioxide Capture Sensitivity Analysis

97

Exhibit 3-21 Case 1B (50%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

PAGES 1 OF 2 CO2 CAPTURE SENSITIVITY ANALYSIS CASE 1B (50%) SUPERCRITICAL PULVERIZED COAL BOILER AND GAS CLEANUP SYSTEMS DWG. NO. CCSA-HMB-CS-1B-PG-1

Pulverized Coal Boiler

AMMONIA SCR INFILTRATION AIR

AIR

AIR

COAL

ASH From Feedwater Heaters

Single Reheat To IP Turbine

Throttle Steam To HP Turbine

FGD

ASH

FORCED DRAFT FANS

PRIMARY AIR FANS

STACK 489,316 W 77.8 T 16.1 P 17.5 H

66.4 T 15.3 P 14.8 H

4,301,289 W 1,100.0 T 3,514.7 P 1,495.1 H 3,505,512 W 1,100.0 T 655.8 P 1,570.6 H

Single Reheat Extraction from HP Turbine 1,127,843 W 59.0 T 14.7 P 13.0 H

3,671,489 W 59.0 T 14.7 P 13.0 H

95,987 W 59.0 T 14.7 P 13.0 H

5,375,146 W 350.0 T 14.4 P 144.1 H

9,490 W

37,958 W

3,505,512 W 668.8 T 710.8 P 1,325.6 H

4,301,289 W 545.5 T 4,185.0 P 539.7 H

5

5,646,915 W 135.8 T 14.8 P 130.5 H

3

1 2

4

6

7

19 8 9 ID FANS 16 5,337,187 W 350.0 T 14.2 P 136.1 H

Gross Plant Power: 618 MWe Auxiliary Load: 68 MWe Net Plant Power: 550 MWe Net Plant Efficiency, HHV: 32.9% Net Plant Heat Rate: 10,379 BTU/KWe

OXIDATION AIR MAKE-UP WATER

LIMESTONE SLURRY GYPSUM 12 15

13 14 10 11

370.7 T 15.3 P 141.4 H 167,004 W 59.0 T 15.0 P

57,733 W 63.6 T 15.0 P 14.1 H 467,632 W 59.0 T 14.7 P 27.0 H

84,969 W 135.8 T 14.8 P

DOE/NETL SC PC PLANT CASE 1B STRIPPER

ABSORBER FLUE GAS Acid Gas

ECONAMINE FG+

ECONAMINE CONDENSATE

20

21 118,781 W

306.3 T 73.5 P 1,181.4 H 840,749 W 556.3 T 73.5 P 1,309.6 H

840,749 W 304.0 T 133.6 P 274.0 H

ECONAMINE STEAM

581,387 W 95.0 T 2,214.5 P -91.3 H

584,429 W 69.0 T 23.5 P 12.1 H 4,804,981 W 118.2 T 14.8 P 85.7 H CO2 COMPRESSION (INTERSTAGE COOLING)

CO2 PRODUCT

Baghouse

24 25

23

18 2,507,230 W

3,139,685 W

2,555,051 W 88.8 T 14.8 P 37.6 H 17 22

NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Coal / Ash

Water

Steam

Limestone Slurry

Flue Gas Ammonia

Carbon Dioxide Gypsum
Carbon Dioxide Capture Sensitivity Analysis

98

Exhibit 3-22 Case 1B (50%) Heat and Mass Balance, Power Block Systems

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Water

Steam

PAGES 2 OF 2 DWG. NO. CCSA-HMB-CS-1B-PG-2 CO2 CAPTURE SENSITIVITY ANALYSIS CASE 1B (50%) SUPERCRITICAL PULVERIZED COAL POWER BLOCK SYSTEMS

LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER HOT WELL To Boiler

BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR

Throttle Steam

Single Reheat Extraction From Boiler

GLAND SEAL CONDENSER

CONDENSATE PUMPS

4,301,289 W 1,100.0 T 3,514.7 P 1,495.1 H

2,900.0 P

243,973 W 803.0 T 211.9 P 1,426.5 H 524,348 W 665.2 T 700.8 P 1,324.1 H

Single Reheat Extraction to Boiler 3,505,512 W 668.8 T 710.8 P 1,325.6 H 710.8 P

1,115.5 P

240,571 W 763.9 T 990.5 P 1,367.9 H

710.8 P

710.8 P

221.9 P

75.0 P

75.0 P

321,036 W 556.3 T 73.5 P 1,309.6 H

126.1 T 2.0 P 1,085.8 H 1,699,649 W 101.1 T 1.0 P 1,009.9 H

2,793 W 212.0 T 14.7 P 180.3 H

29.0 P

11.4 P

4.5 P

101.4 T 250.0 P 70.4 H

2,793 W 674.7 T 75.0 P 1,368.1 H 2,359,988 W 101.1 T 1.0 P 69.5 H

2,359,988 W 102.8 T 245.0 P 71.8 H 2,359,988 W 123.8 T 240.0 P 92.7 H 290,196 W 112.8 T 1.4 P 81.2 H 244,921 W 133.8 T 2.5 P 102.0 H

2,359,988 W 235.0 T 225.0 P 204.0 H 1,008,893 W 321.8 T 91.9 P 292.3 H

2,359,988 W 190.2 T 230.0 P 158.9 H 764,920 W 398.7 T 243.6 P 373.7 H 240,571 W 513.3 T 765.9 P 503.8 H

4,301,289 W 388.7 T 4,195.0 P 368.3 H 4,301,289 W 503.3 T 4,190.0 P 491.4 H DEAERATOR

BOILER FEED PUMPS

4,301,289 W 545.5 T 4,185.0 P 539.7 H

19 3,505,512 W 1,100.0 T 655.8 P 1,570.6 H

100,705 W 200.2 T 11.6 P 168.4 H 187,031 W 161.0 T 4.9 P 129.2 H

2,359,988 W 151.0 T 235.0 P 119.8 H 134,673 W 586.2 T 70.0 P 1,324.6 H 100,705 W 370.1 T 25.0 P 1,224.0 H 86,325 W 216.1 T 10.4 P 1,154.1 H 57,890 W 156.0 T 4.3 P 1,118.4 H 45,275 W 128.8 T 2.2 P 1,054.6 H

2,900.0 P

3,146,645 W 556.3 T 73.5 P 1,309.6 H 1,984,860 W 556.3 T 73.5 P 1,309.6 H

2.3 P

2,900.0 P

Steam Turbine Makeup

43,013 W 59.0 T 14.7 P 27.5 H

311.8 T 4,200.0 P 289.5 H 4,301,289 W 302.9 T 70.0 P 272.8 H

3,301 W 674.7 T 75.0 P 1,368.1 H

Gross Plant Power: 618 MWe Auxiliary Load: 68 MWe Net Plant Power: 550 MWe Net Plant Efficiency, HHV: 32.9% Net Plant Heat Rate: 10,379 BTU/KWe FWH 4 FWH 3 FWH 2 FWH 1 FWH 8 FWH 7 FWH 6

4,985 W 674.7 T 75.0 P 1,368.1 H

DOE/NETL SC PC PLANT CASE 1B

840,749 W 304.0 T 133.6 P 274.0 H

ECONAMINE CONDENSATE

21

840,749 W 556.3 T 73.5 P 1,309.6 H ECONAMINE STEAM 20
Carbon Dioxide Capture Sensitivity Analysis

99

Exhibit 3-23 Case 1C (70%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

PAGES 1 OF 2 CO2 CAPTURE SENSITIVITY ANALYSIS CASE 1C (70%) SUPERCRITICAL PULVERIZED COAL BOILER AND GAS CLEANUP SYSTEMS DWG. NO. CCSA-HMB-CS-1C-PG-1

Pulverized Coal Boiler

AMMONIA SCR INFILTRATION AIR

AIR

AIR

COAL

ASH From Feedwater Heaters

Single Reheat To IP Turbine

Throttle Steam To HP Turbine

FGD

ASH

FORCED DRAFT FANS

PRIMARY AIR FANS

STACK 525,764 W 77.8 T 16.1 P 17.5 H

66.4 T 15.3 P 14.8 H

4,620,838 W 1,100.0 T 3,514.7 P 1,495.1 H 3,768,233 W 1,100.0 T 655.8 P 1,570.6 H

Single Reheat Extraction from HP Turbine 1,211,853 W 59.0 T 14.7 P 13.0 H

3,944,969 W 59.0 T 14.7 P 13.0 H

103,136 W 59.0 T 14.7 P 13.0 H

5,775,526 W 350.0 T 14.4 P 144.1 H

10,196 W

40,786 W

3,768,233 W 668.6 T 710.8 P 1,325.5 H

4,620,838 W 545.5 T 4,185.0 P 539.7 H

5

6,068,141 W 135.8 T 14.8 P 130.5 H

3

1 2

4

6

7

19 8 9 ID FANS 16 5,734,741 W 350.0 T 14.2 P 136.1 H

Gross Plant Power: 638 MWe Auxiliary Load: 88 MWe Net Plant Power: 550 MWe Net Plant Efficiency, HHV: 30.6% Net Plant Heat Rate: 11,151 BTU/KWe

OXIDATION AIR MAKE-UP WATER

LIMESTONE SLURRY GYPSUM

15 12

13 14 10 11

370.7 T 15.3 P 141.4 H 177,758 W 59.0 T 15.0 P

62,577 W 63.6 T 15.0 P 14.1 H 502,908 W 59.0 T 14.7 P 27.0 H

91,095 W 135.8 T 14.8 P

DOE/NETL SC PC PLANT CASE 1C STRIPPER

ABSORBER FLUE GAS Acid Gas

ECONAMINE FG+

ECONAMINE CONDENSATE

20

21 177,556 W

306.3 T 73.5 P 1,181.4 H 1,256,768 W 556.3 T 73.5 P 1,309.6 H

1,256,768 W 304.0 T 133.6 P 274.0 H

ECONAMINE STEAM

870,237 W 95.0 T 2,214.5 P -91.3 H

874,811 W 69.0 T 23.5 P 12.1 H 4,813,608 W 106.5 T 14.8 P 64.0 H CO2 COMPRESSION (INTERSTAGE COOLING)

CO2 PRODUCT

Baghouse

24 25

23

18 1,347,127 W

4,721,014 W

3,845,896 W 88.8 T 14.8 P 37.6 H 17 22

NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Coal / Ash

Water

Steam

Limestone Slurry

Flue Gas Ammonia

Carbon Dioxide Gypsum
Carbon Dioxide Capture Sensitivity Analysis

100

Exhibit 3-24 Case 1C (70%) Heat and Mass Balance, Power Block Systems

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Water

Steam

PAGES 2 OF 2 DWG. NO. CCSA-HMB-CS-1C-PG-2 CO2 CAPTURE SENSITIVITY ANALYSIS CASE 1C (70%) SUPERCRITICAL PULVERIZED COAL POWER BLOCK SYSTEMS

LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER HOT WELL To Boiler

BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR

Throttle Steam

Single Reheat Extraction From Boiler

GLAND SEAL CONDENSER

CONDENSATE PUMPS

4,620,838 W 1,100.0 T 3,514.7 P 1,495.1 H

2,900.0 P

262,098 W 803.0 T 211.9 P 1,426.5 H 563,303 W 665.2 T 700.8 P 1,324.1 H

Single Reheat Extraction to Boiler 3,768,233 W 668.6 T 710.8 P 1,325.5 H 710.8 P

1,115.5 P

258,444 W 763.9 T 990.5 P 1,367.9 H

710.8 P

710.8 P

221.9 P

75.0 P

75.0 P

344,936 W 556.3 T 73.5 P 1,309.6 H

126.1 T 2.0 P 1,085.8 H 1,536,049 W 101.1 T 1.0 P 1,009.9 H

2,793 W 212.0 T 14.7 P 180.3 H

29.0 P

11.4 P

4.5 P

101.4 T 250.0 P 70.4 H

2,793 W 674.7 T 75.0 P 1,368.1 H 2,204,019 W 101.1 T 1.0 P 69.5 H

2,204,019 W 102.9 T 245.0 P 71.9 H 2,204,019 W 123.8 T 240.0 P 92.7 H 270,731 W 112.9 T 1.4 P 81.3 H 228,644 W 133.8 T 2.5 P 102.0 H

2,204,019 W 235.0 T 225.0 P 204.0 H 1,083,845 W 321.8 T 91.9 P 292.3 H

2,204,019 W 190.2 T 230.0 P 158.9 H 821,746 W 398.7 T 243.6 P 373.7 H 258,444 W 513.3 T 765.9 P 503.8 H

4,620,838 W 388.7 T 4,195.0 P 368.3 H 4,620,838 W 503.3 T 4,190.0 P 491.4 H DEAERATOR

BOILER FEED PUMPS

4,620,838 W 545.5 T 4,185.0 P 539.7 H

19 3,768,233 W 1,100.0 T 655.8 P 1,570.6 H

94,050 W 200.2 T 11.6 P 168.4 H 174,670 W 161.0 T 4.9 P 129.2 H

2,204,019 W 151.0 T 235.0 P 119.8 H 122,415 W 589.3 T 70.0 P 1,326.1 H 94,050 W 370.1 T 25.0 P 1,224.0 H 80,620 W 216.1 T 10.4 P 1,154.1 H 53,974 W 156.0 T 4.3 P 1,120.1 H 42,087 W 128.8 T 2.2 P 1,054.6 H

2,900.0 P

3,403,499 W 556.3 T 73.5 P 1,309.6 H 1,801,795 W 556.3 T 73.5 P 1,309.6 H

2.3 P

2,900.0 P

Steam Turbine Makeup

46,208 W 59.0 T 14.7 P 27.5 H

311.8 T 4,200.0 P 289.5 H 4,620,838 W 302.9 T 70.0 P 272.8 H

3,301 W 674.7 T 75.0 P 1,368.1 H

Gross Plant Power: 638 MWe Auxiliary Load: 88 MWe Net Plant Power: 550 MWe Net Plant Efficiency, HHV: 30.6% Net Plant Heat Rate: 11,151 BTU/KWe FWH 4 FWH 3 FWH 2 FWH 1 FWH 8 FWH 7 FWH 6

4,985 W 674.7 T 75.0 P 1,368.1 H

DOE/NETL SC PC PLANT CASE 1C

1,256,768 W 304.0 T 133.6 P 274.0 H

ECONAMINE CONDENSATE

21

1,256,768 W 556.3 T 73.5 P 1,309.6 H ECONAMINE STEAM 20
Carbon Dioxide Capture Sensitivity Analysis

101

Exhibit 3-25 Case 1D (85%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

PAGES 1 OF 2 CO2 CAPTURE SENSITIVITY ANALYSIS CASE 1D (85%) SUPERCRITICAL PULVERIZED COAL BOILER AND GAS CLEANUP SYSTEMS DWG. NO. CCSA-HMB-CS-1D-PG-1

Pulverized Coal Boiler

AMMONIA SCR INFILTRATION AIR

AIR

AIR

COAL

ASH From Feedwater Heaters

Single Reheat To IP Turbine

Throttle Steam To HP Turbine

FGD

ASH

FORCED DRAFT FANS

PRIMARY AIR FANS

STACK 557,283 W 77.8 T 16.1 P 17.5 H

66.4 T 15.3 P 14.8 H

4,897,176 W 1,100.0 T 3,514.7 P 1,495.1 H 3,995,429 W 1,100.0 T 655.8 P 1,570.6 H

Single Reheat Extraction from HP Turbine 1,284,503 W 59.0 T 14.7 P 13.0 H

4,181,468 W 59.0 T 14.7 P 13.0 H

109,319 W 59.0 T 14.7 P 13.0 H

6,121,766 W 350.0 T 14.4 P 144.1 H

10,808 W

43,231 W

3,995,429 W 668.5 T 710.8 P 1,325.4 H

4,897,176 W 545.5 T 4,185.0 P 539.7 H

5

6,432,224 W 135.8 T 14.8 P 130.5 H

3

1 2

4

6

7

19 8 9 ID FANS 16 6,078,535 W 350.0 T 14.2 P 136.1 H

Gross Plant Power: 655 MWe Auxiliary Load: 105 MWe Net Plant Power: 550 MWe Net Plant Efficiency, HHV: 28.9% Net Plant Heat Rate: 11,819 BTU/KWe

OXIDATION AIR MAKE-UP WATER

LIMESTONE SLURRY GYPSUM 12 15

13 14 10 11

370.7 T 15.3 P 141.4 H 190,931 W 59.0 T 15.0 P

66,601 W 63.6 T 15.0 P 14.1 H 531,721 W 59.0 T 14.7 P 27.0 H

96,811 W 135.8 T 14.8 P

DOE/NETL SC PC PLANT CASE 1D STRIPPER

ABSORBER FLUE GAS Acid Gas

ECONAMINE FG+

ECONAMINE CONDENSATE

20

21 228,200 W

306.3 T 73.5 P 1,181.4 H 1,615,234 W 556.3 T 73.5 P 1,309.6 H

1,615,234 W 304.0 T 133.6 P 274.0 H

ECONAMINE STEAM

1,120,468 W 95.0 T 2,214.5 P -91.3 H

1,126,351 W 69.0 T 23.5 P 12.1 H 4,827,645 W 94.1 T 14.8 P 46.4 H CO2 COMPRESSION (INTERSTAGE COOLING)

CO2 PRODUCT

Baghouse

24 25

23

18

360,205 W

6,072,019 W

4,945,220 W 88.8 T 14.8 P 37.6 H 17 22

NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Coal / Ash

Water

Steam

Limestone Slurry

Flue Gas Ammonia

Carbon Dioxide Gypsum
Carbon Dioxide Capture Sensitivity Analysis

102

Exhibit 3-26 Case 1D (85%) Heat and Mass Balance, Power Block Systems

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Water

Steam

PAGES 2 OF 2 DWG. NO. CCSA-HMB-CS-1D-PG-2 CO2 CAPTURE SENSITIVITY ANALYSIS CASE 1D (85%) SUPERCRITICAL PULVERIZED COAL POWER BLOCK SYSTEMS

LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER HOT WELL To Boiler

BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR

Throttle Steam

Single Reheat Extraction From Boiler

GLAND SEAL CONDENSER

CONDENSATE PUMPS

4,897,176 W 1,100.0 T 3,514.7 P 1,495.1 H

2,900.0 P

277,772 W 803.0 T 211.9 P 1,426.5 H 596,990 W 665.2 T 700.8 P 1,324.1 H

Single Reheat Extraction to Boiler 3,995,429 W 668.5 T 710.8 P 1,325.4 H 710.8 P

1,115.5 P

273,899 W 763.9 T 990.5 P 1,367.9 H

710.8 P

710.8 P

221.9 P

75.0 P

75.0 P

365,495 W 556.3 T 73.5 P 1,309.6 H

126.1 T 2.0 P 1,085.8 H 1,395,745 W 101.1 T 1.0 P 1,009.9 H

2,793 W 212.0 T 14.7 P 180.3 H

29.0 P

11.4 P

4.5 P

101.4 T 250.0 P 70.4 H

2,793 W 674.7 T 75.0 P 1,368.1 H 2,070,355 W 101.1 T 1.0 P 69.5 H

2,070,355 W 103.0 T 245.0 P 72.0 H 2,070,355 W 123.8 T 240.0 P 92.7 H 254,050 W 113.0 T 1.4 P 81.4 H 214,694 W 133.8 T 2.5 P 102.0 H

2,070,355 W 235.0 T 225.0 P 204.0 H 1,148,661 W 321.8 T 91.9 P 292.3 H

2,070,355 W 190.2 T 230.0 P 158.9 H 870,889 W 398.7 T 243.6 P 373.7 H 273,899 W 513.3 T 765.9 P 503.8 H

4,897,176 W 388.7 T 4,195.0 P 368.3 H 4,897,176 W 503.3 T 4,190.0 P 491.4 H DEAERATOR

BOILER FEED PUMPS

4,897,176 W 545.5 T 4,185.0 P 539.7 H

19 3,995,429 W 1,100.0 T 655.8 P 1,570.6 H

88,346 W 200.2 T 11.6 P 168.4 H 164,077 W 161.0 T 4.9 P 129.2 H

2,070,355 W 151.0 T 235.0 P 119.8 H 111,897 W 592.4 T 70.0 P 1,327.7 H 88,346 W 370.1 T 25.0 P 1,224.0 H 75,731 W 216.1 T 10.4 P 1,154.1 H 50,617 W 156.0 T 4.3 P 1,121.8 H 39,355 W 128.8 T 2.2 P 1,054.6 H

2,900.0 P

3,625,538 W 556.3 T 73.5 P 1,309.6 H 1,644,810 W 556.3 T 73.5 P 1,309.6 H

2.3 P

2,900.0 P

Steam Turbine Makeup

48,972 W 59.0 T 14.7 P 27.5 H

311.8 T 4,200.0 P 289.5 H 4,897,176 W 302.9 T 70.0 P 272.8 H

3,301 W 674.7 T 75.0 P 1,368.1 H

Gross Plant Power: 655 MWe Auxiliary Load: 105 MWe Net Plant Power: 550 MWe Net Plant Efficiency, HHV: 28.9% Net Plant Heat Rate: 11,819 BTU/KWe FWH 4 FWH 3 FWH 2 FWH 1 FWH 8 FWH 7 FWH 6

4,985 W 674.7 T 75.0 P 1,368.1 H

DOE/NETL SC PC PLANT CASE 1D

1,615,234 W 304.0 T 133.6 P 274.0 H

ECONAMINE CONDENSATE

21

1,615,234 W 556.3 T 73.5 P 1,309.6 H ECONAMINE STEAM 20
Carbon Dioxide Capture Sensitivity Analysis

103

Exhibit 3-27 Case 1A (30%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,626 

(5,332) 4.7 (4.5) 5,630 (5,337)

Combustion Air 62.7 (59.4) 62.7 (59.4)

Raw Water Makeup 93.1 (88.3) 93.1 (88.3)

Limestone 0.46 (0.43) 0.46 (0.43)

Totals 5,626 

(5,332) 161.0 (152.6) 0.0 (0.0) 5,787 (5,485)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.5 (0.5) 0.5 (0.5)

Fly Ash + Gypsum 2.0 (1.9) 2.0 (1.9)

Flue Gas 533 (505) 533 (505)

CO2 -31 (-30) -31 (-30)

Cooling Tower* 2,384.4 (2,260.0) 2,384.4 

(2,260.0)

Process Losses** 917.8 (869.9) 917.8 

(869.9)

Net Power 1,980 

(1,877)

1,980 

(1,877)

Totals 0.0 (0.0) 3,807 (3,608) 1,980 

(1,877)

5,787 

(5,485)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and 

 Econamine cooling water.

** Process losses are estimated to match the heat input to the plant. 

 Process losses include losses from: steam turbine, combustion reactions, gas cooling,

 and Econamine steam.
Carbon Dioxide Capture Sensitivity Analysis

104

Exhibit 3-28 Case 1B (50%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 6,023 

(5,708) 5.0 (4.8) 6,028 (5,713)

Combustion Air 67.1 (63.6) 67.1 (63.6)

Raw Water Makeup 106.8 (101.3) 106.8 

(101.3)

Limestone 0.49 (0.46) 0.49 (0.46)

Totals 6,023 

(5,708) 179.5 (170.1) 0.0 (0.0) 6,202 (5,878)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.5 (0.5) 0.5 (0.5)

Fly Ash + Gypsum 2.2 (2.1) 2.2 (2.1)

Flue Gas 435 (412) 435 (412)

CO2 -56 (-53) -56 (-53)

Cooling Tower* 2,434.7 (2,307.7) 2,434.7 

(2,307.7)

Process Losses** 1,406.2 (1,332.8) 1,406.2 

(1,332.8)

Net Power 1,980 

(1,877)

1,980 

(1,877)

Totals 0.0 (0.0) 4,222 (4,002) 1,980 

(1,877)

6,202 

(5,878)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and 

 Econamine cooling water.

** Process losses are estimated to match the heat input to the plant. 

 Process losses include losses from: steam turbine, combustion reactions, gas cooling,

 and Econamine steam.
Carbon Dioxide Capture Sensitivity Analysis

105

Exhibit 3-29 Case 1C (70%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 6,471 

(6,134) 5.4 (5.1) 6,477 (6,139)

Combustion Air 72.1 (68.4) 72.1 (68.4)

Raw Water Makeup 130.3 (123.5) 130.3 

(123.5)

Limestone 0.52 (0.49) 0.52 (0.49)

Totals 6,471 

(6,134) 208.3 (197.4) 0.0 (0.0) 6,680 (6,331)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.6 (0.6) 0.6 (0.6)

Fly Ash + Gypsum 2.4 (2.2) 2.4 (2.2)

Flue Gas 325 (308) 325 (308)

CO2 -84 (-79) -84 (-79)

Cooling Tower* 2,777.1 (2,632.2) 2,777.1 

(2,632.2)

Process Losses** 1,677.9 (1,590.4) 1,677.9 

(1,590.4)

Net Power 1,980 

(1,877)

1,980 

(1,877)

Totals 0.0 (0.0) 4,699 (4,454) 1,980 

(1,877)

6,680 

(6,331)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and 

 Econamine cooling water.

** Process losses are estimated to match the heat input to the plant. 

 Process losses include losses from: steam turbine, combustion reactions, gas cooling,

 and Econamine steam.
Carbon Dioxide Capture Sensitivity Analysis

106

Exhibit 3-30 Case 1D (85%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 6,859 

(6,501) 5.7 (5.4) 6,865 (6,507)

Combustion Air 76.4 (72.5) 76.4 (72.5)

Raw Water Makeup 150.6 (142.7) 150.6 

(142.7)

Limestone 0.56 (0.53) 0.56 (0.53)

Totals 6,859 

(6,501) 233.3 (221.1) 0 (0) 7,092 (6,722)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.6 (0.6) 0.6 (0.6)

Fly Ash + Gypsum 2.5 (2.4) 2.5 (2.4)

Flue Gas 236 (224) 236 (224)

CO2 -108 (-102) -108 (-102)

Cooling Tower* 3,076.6 (2,916.1) 3,076.6 

(2,916.1)

Process Losses** 1,904.1 (1,804.8) 1,904.1 

(1,804.8)

Net Power 1,980 

(1,877)

1,980 

(1,877)

Totals 5,112 (4,846) 1,980 

(1,877)

7,092 

(6,722)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and 

 Econamine cooling water.

** Process losses are estimated to match the heat input to the plant. 

 Process losses include losses from: steam turbine, combustion reactions, gas cooling,

 and Econamine steam.
Carbon Dioxide Capture Sensitivity Analysis

107

Exhibit 3-31 Case 1A Energy Balance Sankey Diagram

Exhibit 3-32 Case 1B Energy Balance Sankey Diagram
Carbon Dioxide Capture Sensitivity Analysis

108

Exhibit 3-33 Case 1C Energy Balance Sankey Diagram

Exhibit 3-34 Case 1D Energy Balance Sankey Diagram
Carbon Dioxide Capture Sensitivity Analysis

109

3.2.1.2 Major Equipment List for Cases 1A through 1D 

Major equipment items for the CO2 capture bypass cases 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 3.2.4. 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. 

ACCOUNT 1 FUEL AND SORBENT HANDLING

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1A Case 1B Case 1C Case 1D (Spares)

1

Bottom Trestle Dumper and 

Receiving Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0)

3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

4 Transfer Tower No. 1 Enclosed N/A N/A N/A N/A 1 (0)

5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

6

As-Received Coal Sampling 

System Two-stage N/A N/A N/A N/A 1 (0)

7 Stacker/Reclaimer Traveling Linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

8 Reclaim Hopper N/A 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 54 tonne (60 ton) 2 (1)

9 Feeder Vibratory 172 tonne/hr (190 tph) 181 tonne/hr (200 tph) 200 tonne/hr (220 tph) 209 tonne/hr (230 tph) 2 (1)

10 Conveyor No. 3 Belt w/tripper 345 tonne/hr (380 tph) 363 tonne/hr (400 tph) 390 tonne/hr (430 tph) 417 tonne/hr (460 tph) 1 (0)

11 Crusher Tower N/A N/A N/A N/A N/A 1 (0)

12 Coal Surge Bin w/ Vent 

Filter Dual Outlet 172 tonne (190 ton) 181 tonne (200 ton) 200 tonne (220 ton) 209 tonne (230 ton) 2 (0)

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3 in x 0 - 1-1/4 in x 0)

8 cm x 0 - 3 cm x 0

(3 in x 0 - 1-1/4 in x 0)

8 cm x 0 - 3 cm x 0

(3 in x 0 - 1-1/4 in x 0)

8 cm x 0 - 3 cm x 0

(3 in x 0 - 1-1/4 in x 0)

2 (0)

14 As-Fired Coal Sampling 

System Swing Hammer N/A N/A N/A N/A 1 (1)

15 Conveyor No. 4 Belt w/tripper 345 tonne/hr (380 tph) 363 tonne/hr (400 tph) 390 tonne/hr (430 tph) 417 tonne/hr (460 tph) 1 (0)

16 Transfer Tower No. 2 Enclosed N/A N/A N/A N/A 1 (0)

17 Conveyor No. 5 Belt w/tripper 345 tonne/hr (380 tph) 363 tonne/hr (400 tph) 390 tonne/hr (430 tph) 417 tonne/hr (460 tph) 1 (0)

18 Coal Silo w/ Vent Filter and 

Slide Gates Field Erected 726 tonne (800 ton) 816 tonne (900 ton) 907 tonne (1,000 ton) 907 tonne (1,000 ton) 3 (0)

19 Limestone Truck Unloading

Hopper N/A 36 tonne (40 ton) 36 tonne (40 ton) 36 tonne (40 ton) 36 tonne (40 ton) 1 (0)

20 Limestone Feeder Belt 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 100 tonne/hr (110 tph) 109 tonne/hr (120 tph) 1 (0)

21 Limestone Conveyor No. L1 Belt 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 100 tonne/hr (110 tph) 109 tonne/hr (120 tph) 1 (0)

22 Limestone Reclaim Hopper N/A 18 tonne (20 ton) 18 tonne (20 ton) 18 tonne (20 ton) 18 tonne (20 ton) 1 (0)

23 Limestone Reclaim Feeder Belt 73 tonne/hr (80 tph) 73 tonne/hr (80 tph) 82 tonne/hr (90 tph) 82 tonne/hr (90 tph) 1 (0)

24 Limestone Conveyor No. L2 Belt 73 tonne/hr (80 tph) 73 tonne/hr (80 tph) 82 tonne/hr (90 tph) 82 tonne/hr (90 tph) 1 (0)

25 Limestone Day Bin w/ actuator 281 tonne (310 ton) 299 tonne (330 ton) 318 tonne (350 ton) 336 tonne (370 ton) 2 (0)
Carbon Dioxide Capture Sensitivity Analysis

110

ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1A Case 1B Case 1C Case 1D (Spares)

1 Coal Feeder Gravimetric 36 tonne/hr (40 tph) 36 tonne/hr (40 tph) 45 tonne/hr (50 tph) 45 tonne/hr (50 tph) 6 (0)

2 Coal Pulverizer Ball type or eq. 36 tonne/hr (40 tph) 36 tonne/hr (40 tph) 45 tonne/hr (50 tph) 45 tonne/hr (50 tph) 6 (0)

3 Limestone Weigh Feeder Gravimetric 23 tonne/hr (25 tph) 24 tonne/hr (27 tph) 26 tonne/hr (29 tph) 28 tonne/hr (31 tph) 1 (1)

4 Limestone Ball Mill Rotary 23 tonne/hr (25 tph) 24 tonne/hr (27 tph) 26 tonne/hr (29 tph) 28 tonne/hr (31 tph) 1 (1)

5

Limestone Mill Slurry 

Tank with Agitator N/A 87,064 liters (23,000 gal) 94,635 liters (25,000 gal) 98,421 liters (26,000 gal) 105,992 liters (28,000 gal) 1 (1)

6

Limestone Mill Recycle 

Pumps

Horizontal 

centrifugal

1,476 lpm @ 12m H2O 

(390 gpm @ 40 ft H2O)

1,552 lpm @ 12m H2O 

(410 gpm @ 40 ft H2O)

1,666 lpm @ 12m H2O 

(440 gpm @ 40 ft H2O)

1,779 lpm @ 12m H2O 

(470 gpm @ 40 ft H2O)

1 (1)

7 Hydroclone Classifier 4 active cyclones in 

a 5 cyclone bank

379 lpm (100 gpm) per 

cyclone

379 lpm (100 gpm) per 

cyclone

416 lpm (110 gpm) per 

cyclone

454 lpm (120 gpm) per 

cyclone

1 (1)

8 Distribution Box 2-way N/A N/A N/A N/A 1 (1)

9

Limestone Slurry Storage 

Tank with Agitator Field erected 499,674 liters (132,000 gal)

533,743 liters 

(141,000 gal)

571,597 liters 

(151,000 gal)

609,451 liters 

(161,000 gal)

1 (1)

10 Limestone Slurry Feed 

Pumps

Horizontal 

centrifugal

1,022 lpm @ 9m H2O 

(270 gpm @ 30 ft H2O)

1,098 lpm @ 9m H2O 

(290 gpm @ 30 ft H2O)

1,173 lpm @ 9m H2O 

(310 gpm @ 30 ft H2O)

1,249 lpm @ 9m H2O 

(330 gpm @ 30 ft H2O)

1 (1)

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1A Case 1B Case 1C Case 1D (Spares)

1

Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 1,203,761 liters (318,000 gal) 1,290,825 liters (341,000 gal) 1,385,461 liters (366,000 gal) 1,468,740 liters (388,000 gal)

2 (0)

2 Condensate Pumps Vertical canned 20,820 lpm @ 213 m H2O 

(5,500 gpm @ 700 ft H2O)

19,684 lpm @ 213 m H2O 

(5,200 gpm @ 700 ft H2O)

18,549 lpm @ 213 m H2O 

(4,900 gpm @ 700 ft H2O)

17,413 lpm @ 213 m H2O 

(4,600 gpm @ 700 ft H2O)

1 (1)

3

Deaerator and Storage 

Tank

Horizontal spray 

type

2,004,878 kg/hr (4,420,000 

lb/hr), 5 min. tank

2,145,946 kg/hr (4,731,000 

lb/hr), 5 min. tank

2,305,610 kg/hr (5,083,000 

lb/hr), 5 min. tank

2,443,502 kg/hr (5,387,000 

lb/hr), 5 min. tank

1 (0)

4

Boiler Feed 

Pump/Turbine

Barrel type, multistage, centrifugal33,690 lpm @ 3,505 m H2O 

(8,900 gpm @ 11,500 ft H2O)

35,961 lpm @ 3,505 m H2O 

(9,500 gpm @ 11,500 ft H2O)

38,611 lpm @ 3,505 m H2O 

(10,200 gpm @ 11,500 ft 

H2O)

40,882 lpm @ 3,505 m H2O 

(10,800 gpm @ 11,500 ft 

H2O)

1 (1)

5

Startup Boiler Feed 

Pump, Electric Motor 

Driven

Barrel type, multistage, centrifugal9,842 lpm @ 3,505 m H2O 

(2,600 gpm @ 11,500 ft H2O)

10,599 lpm @ 3,505 m H2O 

(2,800 gpm @ 11,500 ft H2O)

11,356 lpm @ 3,505 m H2O 

(3,000 gpm @ 11,500 ft H2O)

12,113 lpm @ 3,505 m H2O 

(3,200 gpm @ 11,500 ft 

H2O)

1 (0)

6

LP Feedwater Heater 

1A/1B Horizontal U-tube 625,957 kg/hr (1,380,000 lb/hr)

589,670 kg/hr 

(1,300,000 lb/hr)

548,847 kg/hr 

(1,210,000 lb/hr)

517,095 kg/hr 

(1,140,000 lb/hr)

2 (0)

7

LP Feedwater Heater 

2A/2B Horizontal U-tube 625,957 kg/hr (1,380,000 lb/hr)

589,670 kg/hr 

(1,300,000 lb/hr)

548,847 kg/hr 

(1,210,000 lb/hr)

517,095 kg/hr 

(1,140,000 lb/hr)

2 (0)

8

LP Feedwater Heater 

3A/3B Horizontal U-tube 625,957 kg/hr (1,380,000 lb/hr)

589,670 kg/hr 

(1,300,000 lb/hr)

548,847 kg/hr 

(1,210,000 lb/hr)

517,095 kg/hr 

(1,140,000 lb/hr)

2 (0)

9

LP Feedwater Heater 

4A/4B Horizontal U-tube 625,957 kg/hr (1,380,000 lb/hr)

589,670 kg/hr 

(1,300,000 lb/hr)

548,847 kg/hr 

(1,210,000 lb/hr)

517,095 kg/hr 

(1,140,000 lb/hr)

2 (0)

10 HP Feedwater Heater 

6

Horizontal U-tube 2,004,878 kg/hr 

(4,420,000 lb/hr)

2,145,492 kg/hr 

(4,730,000 lb/hr)

2,304,249 kg/hr 

(5,080,000 lb/hr)

2,444,863 kg/hr 

(5,390,000 lb/hr)

1 (0)

11 HP Feedwater Heater 

7

Horizontal U-tube 2,004,878 kg/hr 

(4,420,000 lb/hr)

2,145,492 kg/hr 

(4,730,000 lb/hr)

2,304,249 kg/hr 

(5,080,000 lb/hr)

2,444,863 kg/hr 

(5,390,000 lb/hr)

1 (0)

12 HP Feedwater heater 8 Horizontal U-tube 2,004,878 kg/hr 

(4,420,000 lb/hr)

2,145,492 kg/hr 

(4,730,000 lb/hr)

2,304,249 kg/hr 

(5,080,000 lb/hr)

2,444,863 kg/hr 

(5,390,000 lb/hr)

1 (0)
Carbon Dioxide Capture Sensitivity Analysis

111

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1A Case 1B Case 1C Case 1D (Spares)

13 Auxiliary Boiler Shop fabricated, 

water tube

18,144 kg/hr, 2.8 MPa, 343°C 

(40,000 lb/hr, 400 psig, 

650°F)

18,144 kg/hr, 2.8 MPa, 343°C 

(40,000 lb/hr, 400 psig, 

650°F)

18,144 kg/hr, 2.8 MPa, 343°C 

(40,000 lb/hr, 400 psig, 

650°F)

18,144 kg/hr, 2.8 MPa, 

343°C (40,000 lb/hr, 400 

psig, 650°F)

1 (0)

14 Fuel Oil System No. 2 fuel oil for 

light off 1,135,624 liter (300,000 gal) 1,135,624 liter (300,000 gal) 1,135,624 liter (300,000 gal) 1,135,624 liter (300,000 gal)

1 (0)

15 Service Air 

Compressors Flooded Screw 28 m3

/min @ 0.7 MPa 

(1,000 scfm @ 100 psig)

28 m3/min @ 0.7 MPa 

(1,000 scfm @ 100 psig)

28 m3/min @ 0.7 MPa 

(1,000 scfm @ 100 psig)

28 m3/min @ 0.7 MPa 

(1,000 scfm @ 100 psig)

2 (1)

16 Instrument Air Dryers Duplex, 

regenerative 28 m3

/min (1,000 scfm) 28 m3/min (1,000 scfm) 28 m3/min (1,000 scfm) 28 m3/min (1,000 scfm) 2 (1)

17 Closed Cycle Cooling 

Heat Exchangers Shell and tube 53 GJ/hr (50 MMBtu/hr) each

53 GJ/hr (50 MMBtu/hr) 

each

53 GJ/hr (50 MMBtu/hr) 

each

53 GJ/hr (50 MMBtu/hr) 

each

2 (0)

18 Closed Cycle Cooling 

Water Pumps

Horizontal 

centrifugal

20,820 lpm @ 30 m H2O 

(5,500 gpm @ 100 ft H2O)

20,820 lpm @ 30 m H2O 

(5,500 gpm @ 100 ft H2O)

20,820 lpm @ 30 m H2O 

(5,500 gpm @ 100 ft H2O)

20,820 lpm @ 30 m H2O 

(5,500 gpm @ 100 ft H2O)

2 (1)

19 Engine-Driven Fire 

Pump

Vertical turbine, 

diesel engine

3,785 lpm @ 88 m H2O 

(1,000 gpm @ 290 ft H2O)

3,785 lpm @ 88 m H2O 

(1,000 gpm @ 290 ft H2O)

3,785 lpm @ 88 m H2O 

(1,000 gpm @ 290 ft H2O)

3,785 lpm @ 88 m H2O 

(1,000 gpm @ 290 ft H2O)

1 (1)

20 Fire Service Booster 

Pump

Two-stage 

horizontal 

centrifugal

2,650 lpm @ 64 m H2O 

(700 gpm @ 210 ft H2O)

2,650 lpm @ 64 m H2O 

(700 gpm @ 210 ft H2O)

2,650 lpm @ 64 m H2O 

(700 gpm @ 210 ft H2O)

2,650 lpm @ 64 m H2O 

(700 gpm @ 210 ft H2O)

1 (1)

21 Raw Water Pumps Stainless steel, 

single suction

12,870 lpm @ 43 m H2O 

(3,400 gpm @ 140 ft H2O)

14,763 lpm @ 43 m H2O 

(3,900 gpm @ 140 ft H2O)

17,148 lpm @ 43 m H2O 

(4,530 gpm @ 140 ft H2O)

19,268 lpm @ 43 m H2O 

(5,090 gpm @ 140 ft H2O)

2 (1)

22 Filtered Water Pumps Stainless steel, 

single suction

568 lpm @ 49 m H2O 

(150 gpm @ 160 ft H2O)

644 lpm @ 49 m H2O 

(170 gpm @ 160 ft H2O)

719 lpm @ 49 m H2O 

(190 gpm @ 160 ft H2O)

757 lpm @ 49 m H2O 

(200 gpm @ 160 ft H2O)

2 (1)

23 Filtered Water Tank Vertical, cylindrical 560,241 liter (148,000 gal) 598,095 liter (158,000 gal) 681,374 liter (180,000 gal) 719,228 liter (190,000 gal) 1 (0)

24 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane 

assembly, 

electrodeionization 

unit

719 lpm (190 gpm) 795 lpm (210 gpm) 871 lpm (230 gpm) 946 lpm (250 gpm) 1 (1)

25 Liquid Waste 

Treatment System -- 10 years, 24-hour storm 10 years, 24-hour storm 10 years, 24-hour storm 10 years, 24-hour storm 1 (0)

ACCOUNT 4 BOILER AND ACCESSORIES

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1A Case 1B Case 1C Case 1D (Spares)

1 Boiler

Supercritical, drum, 

wall-fired, low NOx 

burners, overfire air

2,004,878 kg/hr steam @ 

25.5 MPa/602°C/602°C 

(4,420,000 lb/hr steam @ 

3,700 psig/1,115°F/1,115°F)

2,145,492 kg/hr steam @ 

25.5 MPa/602°C/602°C 

(4,730,000 lb/hr steam @ 

3,700 psig/1,115°F/1,115°F)

2,304,249 kg/hr steam @ 

25.5 MPa/602°C/602°C 

(5,080,000 lb/hr steam @ 

3,700 psig/1,115°F/1,115°F)

2,444,863 kg/hr steam @ 

25.5 MPa/602°C/602°C 

(5,390,000 lb/hr steam @ 

3,700 psig/1,115°F/1,115°F)

1 (0)

2 Primary Air Fan Centrifugal

262,630 kg/hr, 3,585 m3/min 

@ 123 cm WG (579,000 

lb/hr, 126,600 acfm @ 48 in. 

WG)

281,227 kg/hr, 3,840 m3/min 

@ 123 cm WG (620,000 

lb/hr, 135,600 acfm @ 48 in. 

WG)

302,546 kg/hr, 4,126 m3/min 

@ 123 cm WG (667,000 

lb/hr, 145,700 acfm @ 48 in. 

WG)

320,236 kg/hr, 4,372 m3/min 

@ 123 cm WG (706,000 

lb/hr, 154,400 acfm @ 48 in. 

WG)

2 (0)

3 Forced Draft Fan Centrifugal

855,475 kg/hr, 11,672 m3/min 

@ 51 cm WG (1,886,000 

lb/hr, 412,200 acfm @ 20 in. 

WG)

915,803 kg/hr, 12,496 m3/min 

@ 51 cm WG (2,019,000 

lb/hr, 441,300 acfm @ 20 in. 

WG)

984,295 kg/hr, 13,425 m3/min 

@ 51 cm WG (2,170,000 

lb/hr, 474,100 acfm @ 20 in. 

WG)

1,043,262 kg/hr, 14,232 

m

3

/min @ 51 cm WG 

(2,300,000 lb/hr, 502,600 

acfm @ 20 in. WG)

2 (0)

4 Induced Draft Fan Centrifugal

1,243,750 kg/hr, 26,618 

m

3

/min @ 91 cm WG 

(2,742,000 lb/hr, 940,000 

acfm @ 36 in. WG)

1,331,294 kg/hr, 28,495 

m

3

/min @ 91 cm WG 

(2,935,000 lb/hr, 1,006,300 

acfm @ 36 in. WG)

1,430,630 kg/hr, 30,619 

m

3

/min @ 91 cm WG 

(3,154,000 lb/hr, 1,081,300 

acfm @ 36 in. WG)

1,516,359 kg/hr, 32,454 

m

3

/min @ 91 cm WG 

(3,343,000 lb/hr, 1,146,100 

acfm @ 36 in. WG)

2 (0)
Carbon Dioxide Capture Sensitivity Analysis

112

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1A Case 1B Case 1C Case 1D (Spares)

5 SCR Reactor Vessel Space for spare 

layer

2,485,686 kg/hr 

(5,480,000 lb/hr)

2,662,587 kg/hr 

(5,870,000 lb/hr)

2,862,168 kg/hr 

(6,310,000 lb/hr)

3,034,533 kg/hr 

(6,690,000 lb/hr)

2 (0)

6 SCR Catalyst -- -- -- -- -- 3 (0)

7 Dilution Air Blower Centrifugal 45 m3

/min @ 108 cm WG 

(1,600 acfm @ 42 in. WG)

48 m3/min @ 108 cm WG 

(1,700 acfm @ 42 in. WG)

51 m3/min @ 108 cm WG 

(1,800 acfm @ 42 in. WG)

54 m3/min @ 108 cm WG 

(1,900 acfm @ 42 in. WG)

2 (1)

8 Ammonia Storage Horizontal tank 49,210 liter (13,000 gal) 52,996 liter (14,000 gal) 56,781 liter (15,000 gal) 60,567 liter (16,000 gal) 5 (0)

9 Ammonia Feed Pump Centrifugal 9 lpm @ 91 m H2O 

(2 gpm @ 300 ft H2O)

10 lpm @ 91 m H2O 

(3 gpm @ 300 ft H2O)

11 lpm @ 91 m H2O 

(3 gpm @ 300 ft H2O)

11 lpm @ 91 m H2O 

(3 gpm @ 300 ft H2O)

2 (1)

ACCOUNT 5 FLUE GAS CLEANUP

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1A Case 1B Case 1C Case 1D (Spares)

1 Fabric Filter

Single stage, high-ratio with 

pulse-jet online cleaning 

system

1,243,750 kg/hr (2,742,000 

lb/hr) 99.8% efficiency

1,331,294 kg/hr (2,935,000 

lb/hr) 99.8% efficiency

1,430,630 kg/hr (3,154,000 

lb/hr) 99.8% efficiency

1,516,359 kg/hr (3,343,000 

lb/hr) 99.8% efficiency

2 (0)

2 Absorber Module Counter-current open spray 41,059 m3

/min 

(1,450,000 acfm)

43,948 m3/min 

(1,552,000 acfm)

47,233 m

3

/min 

(1,668,000 acfm)

50,064 m3/min 

(1,768,000 acfm)

1 (0)

3 Recirculation Pumps Horizontal centrifugal 143,846 lpm @ 64 m H2O 

(38,000 gpm @ 210 ft H2O)

151,416 lpm @ 64 m H2O 

(40,000 gpm @ 210 ft H2O)

162,773 lpm @ 64 m H2O 

(43,000 gpm @ 210 ft H2O)

174,129 lpm @ 64 m H2O 

(46,000 gpm @ 210 ft H2O)

5 (1)

4 Bleed Pumps Horizontal centrifugal 4,505 lpm (1,190 gpm) at 

20 wt% solids

4,807 lpm (1,270 gpm) at 

20 wt% solids

5,148 lpm (1,360 gpm) at 

20 wt% solids

5,489 lpm (1,450 gpm) at 

20 wt% solids

2 (1)

5 Oxidation Air Blowers Centrifugal 184 m3

/min @ 0.3 MPa 

(6,500 acfm @ 42 psia)

194 m3/min @ 0.3 MPa 

(6,860 acfm @ 42 psia)

211 m3/min @ 0.3 MPa 

(7,440 acfm @ 42 psia)

224 m3/min @ 0.3 MPa 

(7,910 acfm @ 42 psia)

2 (1)

6 Agitators Side entering 50 hp 50 hp 50 hp 50 hp 5 (1)

7 Dewatering Cyclones Radial assembly, 5 units 

each

1,136 lpm (300 gpm) per 

cyclone

1,211 lpm (320 gpm) per 

cyclone

1,287 lpm (340 gpm) per 

cyclone

1,363 lpm (360 gpm) per 

cyclone

2 (0)

8 Vacuum Filter Belt Horizontal belt 35 tonne/hr (39 tph) of 50 

wt % slurry

38 tonne/hr (42 tph) of 50 

wt % slurry

41 tonne/hr (45 tph) of 50 

wt % slurry

44 tonne/hr (48 tph) of 50 

wt % slurry

2 (1)

9

Filtrate Water Return 

Pumps Horizontal centrifugal 681 lpm @ 12 m H2O (180 gpm @ 40 ft H2O)

719 lpm @ 12 m H2O 

(190 gpm @ 40 ft H2O)

795 lpm @ 12 m H2O 

(210 gpm @ 40 ft H2O)

833 lpm @ 12 m H2O 

(220 gpm @ 40 ft H2O)

1 (1)

10 Filtrate Water Return 

Storage Tank Vertical, lined 454,249 lpm (120,000 gal) 492,104 lpm (130,000 gal) 529,958 lpm (140,000 gal) 529,958 lpm (140,000 gal) 1 (1)

11 Process Makeup 

Water Pumps Horizontal centrifugal 454 lpm @ 21 m H2O (120 gpm @ 70 ft H2O)

492 lpm @ 21 m H2O 

(130 gpm @ 70 ft H2O)

530 lpm @ 21 m H2O 

(140 gpm @ 70 ft H2O)

568 lpm @ 21 m H2O 

(150 gpm @ 70 ft H2O)

1 (1)
Carbon Dioxide Capture Sensitivity Analysis

113

ACCOUNT 5B CARBON DIOXIDE RECOVERY 

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 

(Spares) 1A Case 1B Case 1C Case 1D*

1 Econamine FG Plus Amine-based CO2

capture technology

876,340 kg/h (1,932,000 

lb/h) 20.6 wt % CO2

concentration

1,566,708 kg/h (3,454,000 

lb/h) 20.6 wt % CO2

concentration

2,355,505 kg/h (5,193,000 

lb/h) 20.6 wt % CO2

concentration

1,514,999 kg/h (3,340,000 

lb/h) 20.6 wt % CO2

concentration

1 (0)

2

Econamine Condensate 

Pump Centrifugal 3,899 lpm @ 52 m H2O (1,030 gpm @ 170 ft H2O)

7,003 lpm @ 52 m H2O 

(1,850 gpm @ 170 ft H2O)

10,448 lpm @ 52 m H2O 

(2,760 gpm @ 170 ft H2O)

13,438 lpm @ 52 m H2O 

(3,550 gpm @ 170 ft H2O)

1 (1)

3 CO2 Compressor Centrifugal 161,385 kg/h @ 15.3 MPa 

(355,793 lb/h @ 2,215 psia)

290,084 kg/h @ 15.3 MPa 

(639,526 lb/h @ 2,215 psia)

434,206 kg/h @ 15.3 MPa 

(957,260 lb/h @ 2,215 psia)

279,530 kg/h @ 15.3 MPa 

(616,257 lb/h @ 2,215 psia)

1 (0)

* Case 1D is equipped with two operating CO2 absorption and compression trains, which is reflected in the design conditions.

ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES 

N/A

ACCOUNT 7 DUCTING AND STACK

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1A Case 1B Case 1C Case 1D (Spares)

1 Stack Reinforced concrete with FRP liner 152 m (500 ft) high x

5.7 m (19 ft) diameter

152 m (500 ft) high x

5.6 m (19 ft) diameter

152 m (500 ft) high x

5.6 m (18 ft) diameter

152 m (500 ft) high x

5.6 m (18 ft) diameter

1 (0)

ACCOUNT 8 STEAM TURBINE GENERATOR

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1A Case 1B Case 1C Case 1D (Spares)

1

Steam Turbine 

Generator

Commercially available, 

advanced steam turbine

633 MW 

24.1 MPa/593°C/593°C 

(3500 psig/ 1100°F/1100°F)

651 MW 

24.1 MPa/593°C/593°C 

(3500 psig/ 1100°F/1100°F)

671 MW 

24.1 MPa/593°C/593°C 

(3500 psig/ 1100°F/1100°F)

689 MW 

24.1 MPa/593°C/593°C 

(3500 psig/ 1100°F/1100°F)

1 (0)

2

Steam Turbine 

Generator

Hydrogen cooled, static 

excitation

700 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase

720 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase

750 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase

770 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase

1 (0)

3 Surface Condenser

Single pass, divided 

waterbox including vacuum 

pumps

2,384 GJ/hr (2,260 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 11°C 

(20°F)

2,237 GJ/hr (2,120 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 11°C 

(20°F)

2,089 GJ/hr (1,980 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 11°C 

(20°F)

1,962 GJ/hr (1,860 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 

11°C (20°F)

1 (0)
Carbon Dioxide Capture Sensitivity Analysis

114

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1A Case 1B Case 1C Case 1D (Spares)

1

Circulating Water 

Pumps Vertical, wet pit 583,000 lpm @ 30 m(154,000 gpm @ 100 ft)

673,800 lpm @ 30 m

(178,000 gpm @ 100 ft)

829,000 lpm @ 30 m

(219,000 gpm @ 100 ft)

965,300 lpm @ 30 m

(255,000 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 / 3260 GJ/hr 

(3090 MMBtu/hr) heat duty

11°C (51.5°F) wet bulb / 

16°C (60°F) CWT / 27°C 

(80°F) HWT / 3756 GJ/hr 

(3560 MMBtu/hr) heat duty

11°C (51.5°F) wet bulb / 

16°C (60°F) CWT / 27°C 

(80°F) HWT / 4621 GJ/hr 

(4380 MMBtu/hr) heat duty

11°C (51.5°F) wet bulb / 

16°C (60°F) CWT / 27°C 

(80°F) HWT / 5370 GJ/hr 

(5090 MMBtu/hr) heat duty

1 (0)

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1A Case 1B Case 1C Case 1D (Spares)

1

Economizer Hopper (part of boiler scope 

of supply) -- -- -- -- -- 4 (0)

2

Bottom Ash Hopper (part of boiler scope of 

supply) -- -- -- -- -- 2 (0)

3 Clinker Grinder -- 4.5 tonne/hr (5 tph) 4.5 tonne/hr (5 tph) 5.4 tonne/hr (6 tph) 5.4 tonne/hr (6 tph) 1 (1)

4

Pyrites Hopper (part of pulverizer scope of 

supply included with boiler) -- -- -- -- -- 6 (0)

5 Hydroejectors -- -- -- -- -- 12 (0)

6 Economizer/Pyrites Transfer Tank -- -- -- -- -- 1 (0)

7 Ash Sluice Pumps Vertical, wet pit 189 lpm @ 17 m H2O 

(50 gpm @ 56 ft H2O)

189 lpm @ 17 m H2O 

(50 gpm @ 56 ft H2O)

189 lpm @ 17 m H2O 

(50 gpm @ 56 ft H2O)

227 lpm @ 17 m H2O 

(60 gpm @ 56 ft H2O)

1 (1)

8 Ash Seal Water Pumps Vertical, wet pit 7,571 lpm @ 9 m H2O 

(2000 gpm @ 28 ft H2O)

7,571 lpm @ 9 m H2O 

(2000 gpm @ 28 ft H2O)

7,571 lpm @ 9 m H2O 

(2000 gpm @ 28 ft H2O)

7,571 lpm @ 9 m H2O 

(2000 gpm @ 28 ft H2O)

1 (1)

9 Hydrobins -- 189 lpm (50 gpm) 189 lpm (50 gpm) 189 lpm (50 gpm) 227 lpm (60 gpm) 1 (1)

10 Baghouse Hopper (part of baghouse 

scope of supply)

--

-- -- -- -- 24 (0)

11 Air Heater Hopper (part of boiler scope of 

supply)

--

-- -- -- -- 10 (0)

12 Air Blower -- 16 m3

/min @ 0.2 MPa 

(570 scfm @ 24 psi)

17 m3/min @ 0.2 MPa 

(610 scfm @ 24 psi)

19 m

3

/min @ 0.2 MPa 

(660 scfm @ 24 psi)

20 m3/min @ 0.2 MPa 

(690 scfm @ 24 psi)

1 (1)

13 Fly Ash Silo Reinforced 

concrete 544 tonne (1,200 ton) 590 tonne (1,300 ton) 590 tonne (1,300 ton) 635 tonne (1,400 ton) 2 (0)

14 Slide Gate Valves -- -- -- -- -- 2 (0)

15 Unloader -- -- -- -- -- 1 (0)

16 Telescoping Unloading Chute -- 100 tonne/hr (110 tph) 109 tonne/hr (120 tph) 118 tonne/hr (130 tph) 118 tonne/hr (130 tph) 1 (0)
Carbon Dioxide Capture Sensitivity Analysis

115

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1A Case 1B Case 1C Case 1D (Spares)

1 STG Transformer Oil-filled 24 kV/345 kV, 650 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 650 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 650 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 650 MVA, 

3-ph, 60 Hz

1 (0)

2 Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 55 MVA, 

3-ph, 60 Hz

24 kV/4.16 kV, 74 MVA, 

3-ph, 60 Hz

24 kV/4.16 kV, 95 MVA, 

3-ph, 60 Hz

24 kV/4.16 kV, 114 

MVA, 3-ph, 60 Hz

1 (1)

3 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 8 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 11 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 14 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 17 MVA, 

3-ph, 60 Hz

1 (1)

4

STG Isolated Phase Bus Duct 

and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 1 (0)

5 Medium Voltage Switchgear Metal Clad 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz 1 (1)

6 Low Voltage Switchgear Metal Enclosed 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz 1 (1)

7 Emergency Diesel Generator Sized for emergency 

shutdown

750 kW, 480 V, 3-ph, 60 

Hz

750 kW, 480 V, 3-ph, 60 

Hz

750 kW, 480 V, 3-ph, 60 

Hz

750 kW, 480 V, 3-ph, 60 

Hz

1 (0)

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1A Case 1B Case 1C Case 1D (Spares)

1 DCS - Main Control

Monitor/keyboard; Operator 

printer (laser color); 

Engineering printer (laser 

B&W)

Operator Stations/Printers 

and Engineering 

Stations/Printers

Operator Stations/Printers 

and Engineering 

Stations/Printers

Operator Stations/Printers 

and Engineering 

Stations/Printers

Operator Stations/Printers 

and Engineering 

Stations/Printers

1 (0)

2 DCS - Processor Microprocessor with 

redundant input/output N/A N/A N/A N/A 1 (0)

3 DCS - Data Highway Fiber optic Fully redundant,

25% spare

Fully redundant,

25% spare

Fully redundant,

25% spare

Fully redundant,

25% spare

1 (0)
Carbon Dioxide Capture Sensitivity Analysis

116

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Carbon Dioxide Capture Sensitivity Analysis

117

3.2.2 Full CO2 Capture Performance Results

A process block flow diagram for Cases 1E through 1G is shown in Exhibit 3-35. These cases 

represent supercritical steam cycles with CO2 capture ranging from 90 percent to 99 percent. 

The corresponding stream tables are contained in Exhibit 3-36, Exhibit 3-37, and Exhibit 3-38

for 90 percent, 95 percent, and 99 percent CO2 capture, respectively. 

Overall performance for Cases 1E through 1G is summarized in Exhibit 3-39 which includes 

auxiliary power requirements.

Material and energy balance information, environmental performance and a major equipment list

are summarized in Sections 3.2.2.1 and 3.2.2.2.
Carbon Dioxide Capture Sensitivity Analysis

118

Exhibit 3-35 Cases 1E through 1G Process Block Flow Diagram, Supercritical PC with CO2 Capture

Primary Air Fans

Baghouse FGD ID Fans

Stack gas

Stack

Gypsum Limestone Slurry

Oxidation Air Makeup Water

Bottom Ash Coal Feed

Infiltration air 8

1 2

Forced Draft Fans 3 4

6

5

7

Fly Ash

10 11 13 14

12 15 Pulverized Coal Boiler

SCR 16

Econamine FG+ 18

19

CO2 Compression 21 22 CO2 Product

Reboiler Steam Condensate Return

Steam Turbine

Condenser

9

17

20

Note: Block Flow Diagram is not in complete material balance. Only major process streams and equipment are shown.
Carbon Dioxide Capture Sensitivity Analysis

119

Exhibit 3-36 Case 1E Stream Table, Supercritical PC with 90% CO2 Capture

1 2 3 4 5 6 7 8 9 10 11

V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087

CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870

N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324

O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 67,188 67,188 20,639 20,639 1,757 0 0 94,760 0 94,760 94,760

V-L Flowrate (kg/hr) 1,938,845 1,938,845 595,593 595,593 50,689 0 0 2,818,469 0 2,818,469 2,818,469

Solids Flowrate (kg/hr) 0 0 0 0 0 258,399 5,011 20,045 20,045 0 0

Temperature (°C) 15 19 15 25 15 15 15 177 15 177 188

Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11

Enthalpy (kJ/kg)A

30.23 34.36 30.23 40.78 30.23 --- --- 335.07 --- 316.66 328.98

Density (kg/m3) 1.2 1.3 1.2 1.3 1.2 --- --- 0.8 --- 0.8 0.8

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 --- --- 29.743 --- 29.743 29.743

V-L Flowrate (lbmol/hr) 148,124 148,124 45,502 45,502 3,873 0 0 208,911 0 208,911 208,911

V-L Flowrate (lb/hr) 4,274,421 4,274,421 1,313,058 1,313,058 111,750 0 0 6,213,660 0 6,213,660 6,213,660

Solids Flowrate (lb/hr) 0 0 0 0 0 569,672 11,048 44,192 44,192 0 0

Temperature (°F) 59 66 59 78 59 59 59 350 59 350 371

Pressure (psia) 14.7 15.3 14.7 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.3

Enthalpy (Btu/lb)A

13.0 14.8 13.0 17.5 13.0 --- --- 144.1 --- 136.1 141.4

Density (lb/ft3) 0.076 0.078 0.076 0.081 0.076 --- --- 0.049 --- 0.049 0.051

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

120

Exhibit 3-36 Case 1E Stream Table, Supercritical PC with 90% CO2 Capture (continued)

12 13 14 15 16 17 18 19 20 21 22

V-L Mole Fraction

Ar 0.0000 0.0000 0.0092 0.0000 0.0081 0.0000 0.0000 0.0000 0.0108 0.0000 0.0000

CO2 0.0000 0.0000 0.0003 0.0004 0.1347 0.0000 0.0000 0.0000 0.0179 0.9874 1.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 1.0000 1.0000 0.0099 0.9996 0.1549 1.0000 1.0000 1.0000 0.0381 0.0126 0.0000

N2 0.0000 0.0000 0.7732 0.0000 0.6785 0.0000 0.0000 0.0000 0.9016 0.0000 0.0000

O2 0.0000 0.0000 0.2074 0.0000 0.0238 0.0000 0.0000 0.0000 0.0316 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

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 3,416 13,737 1,071 249 103,518 126,037 44,254 44,254 77,899 12,707 12,547

V-L Flowrate (kg/hr) 61,544 247,481 30,902 4,494 2,982,488 2,270,587 797,253 797,253 2,194,649 555,084 552,194

Solids Flowrate (kg/hr) 26,140 0 0 40,408 0 0 0 0 0 0 0

Temperature (°C) 15 15 18 58 58 593 291 151 32 21 35

Pressure (MPa, abs) 0.10 0.10 0.10 0.10 0.10 24.23 0.51 0.92 0.10 0.16 15.27

Enthalpy (kJ/kg)A

--- 62.80 32.81 --- 303.64 3,477.66 3,046.14 637.34 93.55 28.23 -212.35

Density (kg/m3) --- 1,003.1 1.2 --- 1.1 69.2 2.0 916.0 1.1 2.9 794.3

V-L Molecular Weight --- 18.015 28.857 --- 28.811 18.015 18.015 18.015 28.173 43.682 44.010

V-L Flowrate (lbmol/hr) 7,531 30,286 2,361 550 228,218 277,863 97,564 97,564 171,737 28,015 27,662

V-L Flowrate (lb/hr) 135,681 545,602 68,127 9,907 6,575,262 5,005,788 1,757,642 1,757,642 4,838,373 1,223,750 1,217,380

Solids Flowrate (lb/hr) 57,629 0 0 89,085 0 0 0 0 0 0 0

Temperature (°F) 59 59 64 136 136 1,100 556 304 89 69 95

Pressure (psia) 15.0 14.7 15.0 14.8 14.8 3,514.7 73.5 133.6 14.8 23.5 2,214.5

Enthalpy (Btu/lb)A

--- 27.0 14.1 --- 130.5 1,495.1 1,309.6 274.0 40.2 12.1 -91.3

Density (lb/ft3) --- 62.622 0.077 --- 0.067 4.319 0.123 57.184 0.071 0.183 49.586

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

121

Exhibit 3-37 Case 1F Stream Table, Supercritical PC with 95% CO2 Capture

1 2 3 4 5 6 7 8 9 10 11

V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087

CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870

N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324

O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 68,946 68,946 21,180 21,180 1,803 0 0 97,240 0 97,240 97,240

V-L Flowrate (kg/hr) 1,989,579 1,989,579 611,178 611,178 52,015 0 0 2,892,220 0 2,892,220 2,892,220

Solids Flowrate (kg/hr) 0 0 0 0 0 265,160 5,142 20,570 20,570 0 0

Temperature (°C) 15 19 15 25 15 15 15 177 15 177 188

Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11

Enthalpy (kJ/kg)A

30.23 34.36 30.23 40.78 30.23 --- --- 335.07 --- 316.66 328.98

Density (kg/m3) 1.2 1.3 1.2 1.3 1.2 --- --- 0.8 --- 0.8 0.8

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 --- --- 29.743 --- 29.743 29.743

V-L Flowrate (lbmol/hr) 152,000 152,000 46,693 46,693 3,974 0 0 214,378 0 214,378 214,378

V-L Flowrate (lb/hr) 4,386,271 4,386,271 1,347,417 1,347,417 114,674 0 0 6,376,254 0 6,376,254 6,376,254

Solids Flowrate (lb/hr) 0 0 0 0 0 584,578 11,337 45,348 45,348 0 0

Temperature (°F) 59 66 59 78 59 59 59 350 59 350 371

Pressure (psia) 14.7 15.3 14.7 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.3

Enthalpy (Btu/lb)A

13.0 14.8 13.0 17.5 13.0 --- --- 144.1 --- 136.1 141.4

Density (lb/ft3) 0.076 0.078 0.076 0.081 0.076 --- --- 0.049 --- 0.049 0.051

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

122

Exhibit 3-37 Case 1F Stream Table, Supercritical PC with 95% CO2 Capture (continued)

12 13 14 15 16 17 18 19 20 21 22

V-L Mole Fraction

Ar 0.0000 0.0000 0.0092 0.0000 0.0081 0.0000 0.0000 0.0000 0.0109 0.0000 0.0000

CO2 0.0000 0.0000 0.0003 0.0004 0.1347 0.0000 0.0000 0.0000 0.0090 0.9880 1.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 1.0000 1.0000 0.0099 0.9996 0.1550 1.0000 1.0000 1.0000 0.0381 0.0120 0.0000

N2 0.0000 0.0000 0.7732 0.0000 0.6785 0.0000 0.0000 0.0000 0.9101 0.0000 0.0000

O2 0.0000 0.0000 0.2074 0.0000 0.0238 0.0000 0.0000 0.0000 0.0319 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

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 3,444 14,163 1,100 256 106,227 129,327 48,990 48,990 79,194 13,755 13,591

V-L Flowrate (kg/hr) 62,046 255,146 31,733 4,612 3,060,557 2,329,868 882,562 882,562 2,220,106 601,089 598,124

Solids Flowrate (kg/hr) 26,844 0 0 41,485 0 0 0 0 0 0 0

Temperature (°C) 15 15 18 58 58 593 291 151 32 21 35

Pressure (MPa, abs) 0.10 0.10 0.10 0.10 0.10 24.23 0.51 0.92 0.10 0.16 15.27

Enthalpy (kJ/kg)A

--- 62.80 32.81 --- 303.64 3,477.66 3,046.14 637.34 93.94 27.89 -212.35

Density (kg/m3) --- 1,003.1 1.2 --- 1.1 69.2 2.0 916.0 1.1 2.9 794.3

V-L Molecular Weight --- 18.015 28.857 --- 28.811 18.015 18.015 18.015 28.034 43.699 44.010

V-L Flowrate (lbmol/hr) 7,593 31,223 2,424 564 234,191 285,118 108,004 108,004 174,593 30,325 29,962

V-L Flowrate (lb/hr) 136,788 562,500 69,960 10,168 6,747,374 5,136,479 1,945,717 1,945,717 4,894,497 1,325,174 1,318,637

Solids Flowrate (lb/hr) 59,180 0 0 91,460 0 0 0 0 0 0 0

Temperature (°F) 59 59 64 136 136 1,100 556 304 89 69 95

Pressure (psia) 15.0 14.7 15.0 14.8 14.8 3,514.7 73.5 133.6 14.8 23.5 2,214.5

Enthalpy (Btu/lb)A

--- 27.0 14.1 --- 130.5 1,495.1 1,309.6 274.0 40.4 12.0 -91.3

Density (lb/ft3) --- 62.622 0.077 --- 0.067 4.319 0.123 57.184 0.070 0.183 49.586

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

123

Exhibit 3-38 Case 1G Stream Table, Supercritical PC with 99% CO2 Capture

1 2 3 4 5 6 7 8 9 10 11

V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087

CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870

N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324

O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 73,780 73,780 22,664 22,664 1,929 0 0 104,057 0 104,057 104,057

V-L Flowrate (kg/hr) 2,129,062 2,129,062 654,026 654,026 55,662 0 0 3,094,985 0 3,094,985 3,094,985

Solids Flowrate (kg/hr) 0 0 0 0 0 283,750 5,503 22,012 22,012 0 0

Temperature (°C) 15 19 15 25 15 15 15 177 15 177 188

Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11

Enthalpy (kJ/kg)A

30.23 34.36 30.23 40.78 30.23 --- --- 335.07 --- 316.66 328.98

Density (kg/m3) 1.2 1.3 1.2 1.3 1.2 --- --- 0.8 --- 0.8 0.8

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 --- --- 29.743 --- 29.743 29.743

V-L Flowrate (lbmol/hr) 162,657 162,657 49,966 49,966 4,252 0 0 229,407 0 229,407 229,407

V-L Flowrate (lb/hr) 4,693,779 4,693,779 1,441,880 1,441,880 122,713 0 0 6,823,274 0 6,823,274 6,823,274

Solids Flowrate (lb/hr) 0 0 0 0 0 625,561 12,132 48,528 48,528 0 0

Temperature (°F) 59 66 59 78 59 59 59 350 59 350 371

Pressure (psia) 14.7 15.3 14.7 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.3

Enthalpy (Btu/lb)A

13.0 14.8 13.0 17.5 13.0 --- --- 144.1 --- 136.1 141.4

Density (lb/ft3) 0.076 0.078 0.076 0.081 0.076 --- --- 0.049 --- 0.049 0.051

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

124

Exhibit 3-38 Case 1G Stream Table, Supercritical PC with 99% CO2 Capture (continued)

12 13 14 15 16 17 18 19 20 21 22

V-L Mole Fraction

Ar 0.0000 0.0000 0.0092 0.0000 0.0081 0.0000 0.0000 0.0000 0.0109 0.0000 0.0000

CO2 0.0000 0.0000 0.0003 0.0004 0.1347 0.0000 0.0000 0.0000 0.0018 0.9885 1.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 1.0000 1.0000 0.0099 0.9995 0.1550 1.0000 1.0000 1.0000 0.0381 0.0115 0.0000

N2 0.0000 0.0000 0.7732 0.0000 0.6785 0.0000 0.0000 0.0000 0.9170 0.0000 0.0000

O2 0.0000 0.0000 0.2074 0.0000 0.0238 0.0000 0.0000 0.0000 0.0321 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

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 3,668 15,153 1,173 252 113,670 138,374 64,178 64,178 84,106 15,332 15,156

V-L Flowrate (kg/hr) 66,073 272,981 33,851 4,541 3,275,005 2,492,848 1,156,187 1,156,187 2,348,253 670,179 667,006

Solids Flowrate (kg/hr) 28,635 0 0 44,303 0 0 0 0 0 0 0

Temperature (°C) 15 15 18 58 58 593 291 151 32 21 35

Pressure (MPa, abs) 0.10 0.10 0.10 0.10 0.10 24.23 0.51 0.92 0.10 0.16 15.27

Enthalpy (kJ/kg)A

--- 62.80 32.81 --- 303.63 3,477.66 3,046.14 637.34 94.26 27.39 -212.35

Density (kg/m3) --- 1,003.1 1.2 --- 1.1 69.2 2.0 916.0 1.1 2.9 794.3

V-L Molecular Weight --- 18.015 28.857 --- 28.811 18.015 18.015 18.015 27.920 43.711 44.010

V-L Flowrate (lbmol/hr) 8,086 33,406 2,586 555 250,600 305,063 141,489 141,489 185,421 33,801 33,413

V-L Flowrate (lb/hr) 145,667 601,821 74,628 10,011 7,220,151 5,495,788 2,548,957 2,548,957 5,177,011 1,477,492 1,470,497

Solids Flowrate (lb/hr) 63,129 0 0 97,672 0 0 0 0 0 0 0

Temperature (°F) 59 59 64 136 136 1,100 556 304 89 69 95

Pressure (psia) 15.0 14.7 15.0 14.8 14.8 3,514.7 73.5 133.6 14.8 23.5 2,214.5

Enthalpy (Btu/lb)A

--- 27.0 14.1 --- 130.5 1,495.1 1,309.6 274.0 40.5 11.8 -91.3

Density (lb/ft3) --- 62.622 0.077 --- 0.067 4.319 0.123 57.184 0.070 0.183 49.586

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

125

Exhibit 3-39 Cases 1E through 1G Performance Modeling Results 

POWER SUMMARY (Gross Power at Generator 

Terminals, kWe)

Case 1E 

(90%)

Case 1F 

(95%)

Case 1G 

(99%)

Steam Turbine Power 661,300 667,900 679,600

AUXILIARY LOAD SUMMARY, kWe1

Coal Handling and Conveying 510 510 540

Limestone Handling & Reagent Preparation 1,260 1,290 1,380

Pulverizers 3,870 3,980 4,250

Ash Handling 740 760 810

Primary Air Fans 1,810 1,860 1,990

Forced Draft Fans 2,310 2,370 2,530

Induced Draft Fans 10,000 10,260 10,920

SCR 20 20 20

Baghouse 100 100 110

FGD Pumps and Agitators 4,130 4,240 4,540

Econamine FG Plus Auxiliaries 20,700 22,400 25,000

CO2 Compression 44,390 48,080 53,610

Econamine Condensate Pump 160 170 230

Miscellaneous Balance of Plant 2

2,000 2,000 2,000

Steam Turbine Auxiliaries 400 400 400

Condensate Pumps 580 550 470

Circulating Water Pumps 10,120 10,480 11,620

Cooling Tower Fans 5,910 6,150 6,820

Transformer Loss 2,280 2,320 2,390

TOTAL AUXILIARIES, kWe 111,290 117,940 129,630

NET POWER, kWe 550,010 549,960 549,970

Net Plant Efficiency, % (HHV) 28.2% 27.5% 25.7%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 12,748 (12,083) 13,083 (12,400) 14,000 (13,269)

CONDENSER COOLING DUTY GJ/hr (106 Btu/hr) 1,735 (1,645) 1,665 (1,578) 1,400 (1,327)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr)3258,399 (569,672) 265,160 (584,578) 283,750 (625,561)

Thermal Input, kWt 1,947,689 1,998,654 2,138,774

Raw Water Withdrawal, m3/min (gpm) 38.2 (10,095) 39.8 (10,512) 44.2 (11,664)

Raw Water Consumption, m

3

/min (gpm) 29.3 (7,753) 30.6 (8,074) 33.9 (8,961)

Notes: 1. Boiler feed pumps are turbine driven

2. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

3. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)
Carbon Dioxide Capture Sensitivity Analysis

126

3.2.2.1 Environmental Performance for Cases 1E through 1G

Each case was designed to meet presumptive BACT standards utilizing the emissions control 

processes described in Section 2.4. A summary of plant air emissions for Case 1E (90 percent), 

1F (95 percent), and 1G (99 percent) is presented in Exhibit 3-40.

SO2 emissions are controlled using a wet limestone forced oxidation FGD that achieves a 

removal efficiency of 98 percent. To avoid the formation of heat stable salts in the Econamine 

process, an SO2 polishing step is included to reduce the sulfur content to 10 ppm prior to the CO2

absorber, and the balance of the SO2 is absorbed by the MEA solution resulting in negligible 

stack emissions. The byproduct calcium sulfate is dewatered and stored on site. The wallboard 

grade material can potentially be marketed and sold, but since it is highly dependent on local 

market conditions, no byproduct credit was taken. The saturated flue gas exiting the FGD is 

vented through the plant stack.

Particulate emissions are controlled using a pulse jet fabric filter (baghouse) which operates at an 

efficiency of 99.8 percent. It was assumed that 20 percent of the ash exits the boiler as bottom 

ash and the remaining 80 percent exits the boiler in the flue gas [41].

Co-benefit capture of Hg in the fabric filter and FGD system was assumed to achieve a 90

percent capture rate [42]. The high chlorine content of the Illinois No. 6 coal and the SCR 

system will convert most of the Hg in the system to an oxidized state [43]. An inexpensive FGD 

system additive can be used to promote Hg capture if necessary, but was not included.

The carbon balance for the three cases is shown in Exhibit 3-41. The carbon input to the plant 

consists of carbon in the coal, limestone, and combustion and FGD forced oxidation air. 

CO2 capture efficiency is calculated as the pounds of CO2 captured divided by the pounds of CO2

produced. Most of the CO2 produced comes from coal combustion, but a small amount is 

formed in the FGD system. The sum of these two sources is the amount produced.

(Carbon in Sequestration Product) / (Carbon in the Coal + Net Carbon from Limestone) or

332,243 / (363,136 + 5,242) *100 = 90% (Case 1E)

359,878 / (372,638 + 5,378) *100 = 95% (Case 1F) 

401,323 / (398,762 + 5,756) *100 = 99% (Case 1G) 

Exhibit 3-42 shows the sulfur balance for the three cases. Sulfur input comes solely from the 

sulfur in the coal. Sulfur output is the gypsum sulfur byproduct, and the sulfur emitted in the 

stack gas. The total sulfur capture is represented by the following fraction:

(Sulfur byproduct/Sulfur in the coal) or

(13,993/14,278)*100 = 98.0% (Case 1E)

(14,359/14,652)*100 = 98.0% (Case 1F)

(15,366/15,679)*100 = 98.0% (Case 1G) 

The overall water balances for Case 1E, 1G, and 1F are shown in Exhibit 3-43, Exhibit 3-44, and 

Exhibit 3-45, respectively. Raw water is obtained from groundwater (50 percent) and from 

municipal sources (50 percent). Water demand represents the total amount of water required for 

a particular process. Some water is recovered within the process and that water is reused as 
Carbon Dioxide Capture Sensitivity Analysis

127

internal recycle. Raw water withdrawal is the difference between water demand and internal 

recycle. Process water discharged from the power plant is also accounted for in this study. Raw 

water consumption represents raw water withdrawal less process water discharge.

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-46 through 

Exhibit 3-51.

Boiler and flue gas cleanup

Steam and feedwater

An overall plant energy balance is provided in tabular form for Case 1E, 1F, and 1G in 

Exhibit 3-52, Exhibit 3-53, and Exhibit 3-54, respectively. The power out is the steam turbine 

power after generator losses. In addition, energy balance Sankey diagrams are provided in 

Exhibit 3-55, Exhibit 3-56, and Exhibit 3-57 for Case 1E, 1F, and 1G, respectively.
Carbon Dioxide Capture Sensitivity Analysis

128

Exhibit 3-40 Cases 1E through 1G Estimated Air Emission Rates

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

85% capacity factor

kg/MWh

(lb/MWh)

Case 1E Case 1F Case 1G Case 1E Case 1F Case 1G Case 1E Case 1F Case 1G

SO2

0.007 

(0.017)

0.007 

(0.016)

0.007 

(0.016)

372

(410) 378 (417) 402 (443) 0.076 (0.170) 0.076 (0.170) 0.079 (0.170)

NOX

0.030 

(0.070)

0.030 

(0.070)

0.030 

(0.070)

1,571 

(1,732)

1,612 

(1,777) 1,725 (1,902) 0.319 (0.703) 0.324 (0.715) 0.341 (0.752)

PM 0.006 

(0.013)

0.006 

(0.013)

0.006 

(0.013)

292 

(322) 299 (330) 320 (353) 0.059 (0.131) 0.060 (0.133) 0.063 (0.140)

Hg 0.49x10-6

(1.14x10-6)

0.49x10-6

(1.14x10-6)

0.49x10-6

(1.14x10-6)

0.026 

(0.028)

0.026 

(0.029) 0.028 (0.031) 5.21x10-6(11.5x10-6)

5.29x10-6

(11.7x10-6)

5.57x10-6

(12.3x10-6)

CO2

8.8

(20.4)

4.4

(10.2)

0.9

(2.0)

456,848 

(503,588)

234,401 

(258,383)

50,167 

(55,299)

93

(205)

47

(104)

10

(22)

CO2 net 112 (246) 57 (126) 12 (27)
Carbon Dioxide Capture Sensitivity Analysis

129

Exhibit 3-41 Cases 1E through 1G Carbon Balance

Carbon In, kg/hr (lb/hr)

Case 1E Case 1F Case 1G

Coal 164,716 

(363,136)

169,026 

(372,638)

180,876 

(398,762)

Air (CO2) 352 (775) 361 (795) 386 (851)

Limestone 2,652 (5,848) 2,724 (6,005) 2,906 (6,406)

Total 167,720

(369,759)

172,110 

(379,438)

184,168 

(406,019)

Carbon Out, kg/hr (lb/hr)

Stack Gas 16,745 

(36,916)

8,591 

(18,941) 1,839 (4,054)

CO2 Product 150,703 

(332,243)

163,238 

(359,878)

182,037 

(401,323)

Gypsum 275 (606) 284 (627) 295 (650)

Convergence 

Tolerance* -3 (-6) -3 (-7) -3 (-7)

Total 167,720 

(369,759)

172,110 

(379,438)

184,168 

(406,019)

Exhibit 3-42 Cases 1E through 1G Sulfur Balance

Sulfur In, kg/hr (lb/hr)

Case 1E Case 1F Case 1G

Coal 6,477 (14,278) 6,646 (14,652) 7,112 (15,679)

Total 6,477 (14,278) 6,646 (14,652) 7,112 (15,679)

Sulfur Out, kg/hr (lb/hr)

Gypsum 6,347 (13,993) 6,513 (14,359) 6,970 (15,366)

Stack Gas 25 (55) 25 (56) 27 (60)

AGR 104 (230) 107 (237) 115 (254)

Convergence

Tolerance* 1 (0) 1 (0) 0 (-1)

Total 6,477 (14,278) 6,646 (14,652) 7,112 (15,679)
Carbon Dioxide Capture Sensitivity Analysis

130

Exhibit 3-43 Case 1E (90%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Econamine 0.14 (36) 0.0 (0) 0.14 (36) 0.0 (0) 0.14 (36)

FGD Makeup 5.16 (1,363) 0.0 (0) 5.16 (1,363) 0.0 (0) 5.16 (1,363)

BFW Makeup 0.38 (100) 0.0 (0) 0.38 (100) 0.0 (0) 0.38 (100)

Cooling Tower 

Makeup 39.4 (10,415) 6.88 (1,818) 32.5 (8,597) 8.87 (2,342) 23.7 (6,254)

Total 45.1 (11,914) 6.88 (1,818) 38.2 (10,095) 8.87 (2,342) 29.3 (7,753)

Total, gal/MWhnet 1,300 198 1,101 256 846

Exhibit 3-44 Case 1F (95%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Econamine 0.15 (39) 0.0 (0) 0.15 (39) 0.0 (0) 0.15 (39)

FGD Makeup 5.29 (1,399) 0.0 (0) 5.29 (1,399) 0.0 (0) 5.29 (1,399)

BFW Makeup 0.39 (103) 0.0 (0) 0.39 (103) 0.0 (0) 0.39 (103)

Cooling Tower 

Makeup 41.0 (10,840) 7.07 (1,869) 34.0 (8,971) 9.23 (2,438) 24.7 (6,534)

Total 46.9 (12,380) 7.07 (1,869) 39.8 (10,512) 9.23 (2,438) 30.6 (8,074)

Total, gal/MWhnet 1,351 204 1,147 266 881
Carbon Dioxide Capture Sensitivity Analysis

131

Exhibit 3-45 Case 1G (99%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Econamine 0.16 (44) 0.0 (0) 0.16 (44) 0.0 (0) 0.16 (44)

FGD Makeup 5.66 (1,495) 0.0 (0) 5.66 (1,495) 0.0 (0) 5.66 (1,495)

BFW Makeup 0.42 (110) 0.0 (0) 0.42 (110) 0.0 (0) 0.42 (110)

Cooling Tower 

Makeup 45.5 (12,017) 7.58 (2,002) 37.9 (10,016) 10.2 (2,703) 27.7 (7,313)

Total 51.7 (13,666) 7.58 (2,002) 44.2 (11,664) 10.2 (2,703) 33.9 (8,961)

Total, gal/MWhnet 1,491 218 1,273 295 978
Carbon Dioxide Capture Sensitivity Analysis

132

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Carbon Dioxide Capture Sensitivity Analysis

133

Exhibit 3-46 Case 1E (90%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

PAGES 1 OF 2 CO2 CAPTURE SENSITIVITY ANALYSIS CASE 1E (90%) SUPERCRITICAL PULVERIZED COAL BOILER AND GAS CLEANUP SYSTEMS DWG. NO. CCSA-HMB-CS-1E-PG-1

Pulverized Coal Boiler

AMMONIA SCR INFILTRATION AIR

AIR

AIR

COAL

ASH From Feedwater Heaters

Single Reheat To IP Turbine

Throttle Steam To HP Turbine

FGD

ASH

FORCED DRAFT FANS

PRIMARY AIR FANS

STACK 569,672 W 77.8 T 16.1 P 17.5 H

66.4 T 15.3 P 14.8 H

5,005,788 W 1,100.0 T 3,514.7 P 1,495.1 H 4,084,726 W 1,100.0 T 655.8 P 1,570.6 H

Single Reheat Extraction from HP Turbine 1,313,058 W 59.0 T 14.7 P 13.0 H

4,274,421 W 59.0 T 14.7 P 13.0 H

111,750 W 59.0 T 14.7 P 13.0 H

6,257,852 W 350.0 T 14.4 P 144.1 H

11,048 W

44,192 W

4,084,726 W 668.5 T 710.8 P 1,325.4 H

5,005,788 W 545.5 T 4,185.0 P 539.7 H

5

6,575,262 W 135.8 T 14.8 P 130.5 H

3

1 2

4

6

7

17 8 9 ID FANS 16 6,213,660 W 350.0 T 14.2 P 136.1 H

Gross Plant Power: 661 MWe Auxiliary Load: 111 MWe Net Plant Power: 550 MWe Net Plant Efficiency, HHV: 28.2% Net Plant Heat Rate: 12,083 BTU/KWe

OXIDATION AIR MAKE-UP WATER

LIMESTONE SLURRY GYPSUM 12 15

13 14 10 11

370.7 T 15.3 P 141.4 H 193,310 W 59.0 T 15.0 P

68,127 W 63.6 T 15.0 P 14.1 H 545,602 W 59.0 T 14.7 P 27.0 H

98,992 W 135.8 T 14.8 P

STRIPPER

ABSORBER FLUE GAS Acid Gas

ECONAMINE FG+

ECONAMINE CONDENSATE

18

19 248,320 W

306.3 T 73.5 P 1,181.4 H 1,757,642 W 556.3 T 73.5 P 1,309.6 H

1,757,642 W 304.0 T 133.6 P 274.0 H

ECONAMINE STEAM

1,217,380 W 95.0 T 2,214.5 P -91.3 H

1,223,750 W 69.0 T 23.5 P 12.1 H 4,838,373 W 88.8 T 14.8 P 40.2 H CO2 COMPRESSION (INTERSTAGE COOLING)

CO2 PRODUCT

Baghouse

21 22 20

DOE/NETL SC PC PLANT CASE 1E

NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Coal / Ash

Water

Steam

Limestone Slurry

Flue Gas Ammonia

Carbon Dioxide Gypsum
Carbon Dioxide Capture Sensitivity Analysis

134

Exhibit 3-47 Case 1E (90%) Heat and Mass Balance, Power Block Systems

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Water

Steam

PAGES 2 OF 2 DWG. NO. CCSA-HMB-CS-1E-PG-2 CO2 CAPTURE SENSITIVITY ANALYSIS CASE 1E (90%) SUPERCRITICAL PULVERIZED COAL POWER BLOCK SYSTEMS

LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER HOT WELL To Boiler

BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR

Throttle Steam

Single Reheat Extraction From Boiler

GLAND SEAL CONDENSER

CONDENSATE PUMPS

5,005,788 W 1,100.0 T 3,514.7 P 1,495.1 H

2,900.0 P

283,933 W 803.0 T 211.9 P 1,426.5 H 610,230 W 665.2 T 700.8 P 1,324.1 H

Single Reheat Extraction to Boiler 4,084,726 W 668.5 T 710.8 P 1,325.4 H 710.8 P

1,115.5 P

279,974 W 763.9 T 990.5 P 1,367.9 H

710.8 P

710.8 P

221.9 P

75.0 P

75.0 P

373,617 W 556.3 T 73.5 P 1,309.6 H

126.1 T 2.0 P 1,085.8 H 1,339,314 W 101.1 T 1.0 P 1,009.9 H

2,793 W 212.0 T 14.7 P 180.3 H

29.0 P

11.4 P

4.5 P

101.4 T 250.0 P 70.4 H

2,793 W 674.7 T 75.0 P 1,368.1 H 2,016,400 W 101.1 T 1.0 P 69.5 H

2,016,400 W 103.1 T 245.0 P 72.1 H 2,016,400 W 123.8 T 240.0 P 92.7 H 247,316 W 113.1 T 1.4 P 81.4 H 209,064 W 133.8 T 2.5 P 102.0 H

2,016,400 W 235.0 T 225.0 P 204.0 H 1,174,137 W 321.8 T 91.9 P 292.3 H

2,016,400 W 190.2 T 230.0 P 158.9 H 890,204 W 398.7 T 243.6 P 373.7 H 279,974 W 513.3 T 765.9 P 503.8 H

5,005,788 W 388.7 T 4,195.0 P 368.3 H 5,005,788 W 503.3 T 4,190.0 P 491.4 H DEAERATOR

BOILER FEED PUMPS

5,005,788 W 545.5 T 4,185.0 P 539.7 H

17 4,084,726 W 1,100.0 T 655.8 P 1,570.6 H

86,044 W 200.2 T 11.6 P 168.4 H 159,801 W 161.0 T 4.9 P 129.2 H

2,016,400 W 151.0 T 235.0 P 119.8 H 107,667 W 593.9 T 70.0 P 1,328.4 H 86,044 W 370.1 T 25.0 P 1,224.0 H 73,757 W 216.1 T 10.4 P 1,154.1 H 49,263 W 156.0 T 4.3 P 1,122.6 H 38,253 W 128.8 T 2.2 P 1,054.6 H

2,900.0 P

3,712,905 W 556.3 T 73.5 P 1,309.6 H 1,581,645 W 556.3 T 73.5 P 1,309.6 H

2.3 P

2,900.0 P

Steam Turbine Makeup

50,058 W 59.0 T 14.7 P 27.5 H

311.8 T 4,200.0 P 289.5 H 5,005,788 W 302.9 T 70.0 P 272.8 H

3,301 W 674.7 T 75.0 P 1,368.1 H

Gross Plant Power: 661 MWe Auxiliary Load: 111 MWe Net Plant Power: 550 MWe Net Plant Efficiency, HHV: 28.2% Net Plant Heat Rate: 12,083 BTU/KWe FWH 4 FWH 3 FWH 2 FWH 1 FWH 8 FWH 7 FWH 6

4,985 W 674.7 T 75.0 P 1,368.1 H

DOE/NETL SC PC PLANT CASE 1E

1,757,642 W 304.0 T 133.6 P 274.0 H

ECONAMINE CONDENSATE

19

1,757,642 W 556.3 T 73.5 P 1,309.6 H ECONAMINE STEAM 18
Carbon Dioxide Capture Sensitivity Analysis

135

Exhibit 3-48 Case 1F (95%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

PAGES 1 OF 2 CO2 CAPTURE SENSITIVITY ANALYSIS CASE 1F (95%) SUPERCRITICAL PULVERIZED COAL BOILER AND GAS CLEANUP SYSTEMS DWG. NO.

CCSA-HMB-CS-1F-PG-1

Pulverized Coal Boiler

AMMONIA SCR INFILTRATION AIR

AIR

AIR

COAL

ASH From Feedwater Heaters

Single Reheat To IP Turbine

Throttle Steam To HP Turbine

FGD

ASH

FORCED DRAFT FANS

PRIMARY AIR FANS

STACK 584,578 W 77.8 T 16.1 P 17.5 H

66.4 T 15.3 P 14.8 H

5,136,479 W 1,100.0 T 3,514.7 P 1,495.1 H 4,192,175 W 1,100.0 T 655.8 P 1,570.6 H

Single Reheat Extraction from HP Turbine 1,347,417 W 59.0 T 14.7 P 13.0 H

4,386,271 W 59.0 T 14.7 P 13.0 H

114,674 W 59.0 T 14.7 P 13.0 H

6,421,602 W 350.0 T 14.4 P 144.1 H

11,337 W

45,348 W

4,192,175 W 668.4 T 710.8 P 1,325.4 H

5,136,479 W 545.5 T 4,185.0 P 539.7 H

5

6,747,374 W 135.8 T 14.8 P 130.5 H

3

1 2

4

6

7

17 8 9 ID FANS 16 6,376,254 W 350.0 T 14.2 P 136.1 H

Gross Plant Power: 668 MWe Auxiliary Load: 118 MWe Net Plant Power: 550 MWe Net Plant Efficiency, HHV: 27.5% Net Plant Heat Rate: 12,400 BTU/KWe

OXIDATION AIR MAKE-UP WATER

LIMESTONE SLURRY GYPSUM 12 15

13 14 10 11

370.7 T 15.3 P 141.4 H 195,968 W 59.0 T 15.0 P

69,960 W 63.6 T 15.0 P 14.1 H 562,500 W 59.0 T 14.7 P 27.0 H

101,628 W 135.8 T 14.8 P

STRIPPER

ABSORBER FLUE GAS Acid Gas

ECONAMINE FG+

ECONAMINE CONDENSATE

18

19 274,891 W

306.3 T 73.5 P 1,181.4 H 1,945,717 W 556.3 T 73.5 P 1,309.6 H

1,945,717 W 304.0 T 133.6 P 274.0 H

ECONAMINE STEAM

1,318,637 W 95.0 T 2,214.5 P -91.3 H

1,325,174 W 69.0 T 23.5 P 12.0 H 4,894,497 W 88.8 T 14.8 P 40.4 H CO2 COMPRESSION (INTERSTAGE COOLING)

CO2 PRODUCT

Baghouse

21 22 20

DOE/NETL SC PC PLANT CASE 1F

NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Coal / Ash

Water

Steam

Limestone Slurry

Flue Gas Ammonia

Carbon Dioxide Gypsum
Carbon Dioxide Capture Sensitivity Analysis

136

Exhibit 3-49 Case 1F (95%) Heat and Mass Balance, Power Block Systems

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Water

Steam

PAGES 2 OF 2 DWG. NO.

CCSA-HMB-CS-1F-PG-2 CO2 CAPTURE SENSITIVITY ANALYSIS CASE 1F (95%) SUPERCRITICAL PULVERIZED COAL POWER BLOCK SYSTEMS

LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER HOT WELL To Boiler

BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR

Throttle Steam

Single Reheat Extraction From Boiler

GLAND SEAL CONDENSER

CONDENSATE PUMPS

5,136,479 W 1,100.0 T 3,514.7 P 1,495.1 H

2,900.0 P

291,346 W 803.0 T 211.9 P 1,426.5 H 626,162 W 665.2 T 700.8 P 1,324.1 H

Single Reheat Extraction to Boiler 4,192,175 W 668.4 T 710.8 P 1,325.4 H 710.8 P

1,115.5 P

287,283 W 763.9 T 990.5 P 1,367.9 H

710.8 P

710.8 P

221.9 P

75.0 P

75.0 P

383,372 W 556.3 T 73.5 P 1,309.6 H

126.1 T 2.0 P 1,085.8 H 1,257,727 W 101.1 T 1.0 P 1,009.9 H

2,793 W 212.0 T 14.7 P 180.3 H

29.0 P

11.4 P

4.5 P

101.4 T 250.0 P 70.4 H

2,793 W 674.7 T 75.0 P 1,368.1 H 1,935,817 W 101.1 T 1.0 P 69.5 H

1,935,817 W 103.2 T 245.0 P 72.1 H 1,935,817 W 123.8 T 240.0 P 92.7 H 237,259 W 113.2 T 1.4 P 81.5 H 200,654 W 133.8 T 2.5 P 102.0 H

1,935,817 W 235.0 T 225.0 P 204.0 H 1,204,791 W 321.8 T 91.9 P 292.3 H

1,935,817 W 190.2 T 230.0 P 158.9 H 913,445 W 398.7 T 243.6 P 373.7 H 287,283 W 513.3 T 765.9 P 503.8 H

5,136,479 W 388.7 T 4,195.0 P 368.3 H 5,136,479 W 503.3 T 4,190.0 P 491.4 H DEAERATOR

BOILER FEED PUMPS

5,136,479 W 545.5 T 4,185.0 P 539.7 H

17 4,192,175 W 1,100.0 T 655.8 P 1,570.6 H

82,605 W 200.2 T 11.6 P 168.4 H 153,415 W 161.0 T 4.9 P 129.2 H

1,935,817 W 151.0 T 235.0 P 119.8 H 101,518 W 596.2 T 70.0 P 1,329.5 H 82,605 W 370.1 T 25.0 P 1,224.0 H 70,810 W 216.1 T 10.4 P 1,154.1 H 47,239 W 156.0 T 4.3 P 1,123.7 H 36,606 W 128.8 T 2.2 P 1,054.6 H

2,900.0 P

3,819,090 W 556.3 T 73.5 P 1,309.6 H 1,490,002 W 556.3 T 73.5 P 1,309.6 H

2.3 P

2,900.0 P

Steam Turbine Makeup

51,365 W 59.0 T 14.7 P 27.5 H

311.8 T 4,200.0 P 289.5 H 5,136,479 W 302.9 T 70.0 P 272.8 H

3,301 W 674.7 T 75.0 P 1,368.1 H

Gross Plant Power: 668 MWe Auxiliary Load: 118 MWe Net Plant Power: 550 MWe Net Plant Efficiency, HHV: 27.5% Net Plant Heat Rate: 12,400 BTU/KWe FWH 4 FWH 3 FWH 2 FWH 1 FWH 8 FWH 7 FWH 6

4,985 W 674.7 T 75.0 P 1,368.1 H

DOE/NETL SC PC PLANT CASE 1F

1,945,717 W 304.0 T 133.6 P 274.0 H

ECONAMINE CONDENSATE

19

1,945,717 W 556.3 T 73.5 P 1,309.6 H ECONAMINE STEAM 18
Carbon Dioxide Capture Sensitivity Analysis

137

Exhibit 3-50 Case 1G (99%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

PAGES 1 OF 2 CO2 CAPTURE SENSITIVITY ANALYSIS CASE 1G (99%) SUPERCRITICAL PULVERIZED COAL BOILER AND GAS CLEANUP SYSTEMS DWG. NO. CCSA-HMB-CS-1G-PG-1

Pulverized Coal Boiler

AMMONIA SCR INFILTRATION AIR

AIR

AIR

COAL

ASH From Feedwater Heaters

Single Reheat To IP Turbine

Throttle Steam To HP Turbine

FGD

ASH

FORCED DRAFT FANS

PRIMARY AIR FANS

STACK 625,561 W 77.8 T 16.1 P 17.5 H

66.4 T 15.3 P 14.8 H

5,495,788 W 1,100.0 T 3,514.7 P 1,495.1 H 4,487,587 W 1,100.0 T 655.8 P 1,570.6 H

Single Reheat Extraction from HP Turbine 1,441,880 W 59.0 T 14.7 P 13.0 H

4,693,779 W 59.0 T 14.7 P 13.0 H

122,713 W 59.0 T 14.7 P 13.0 H

6,871,802 W 350.0 T 14.4 P 144.1 H

12,132 W

48,528 W

4,487,587 W 668.3 T 710.8 P 1,325.3 H

5,495,788 W 545.5 T 4,185.0 P 539.7 H

5

7,220,151 W 135.8 T 14.8 P 130.5 H

3

1 2

4

6

7

17 8 9 ID FANS 16 6,823,274 W 350.0 T 14.2 P 136.1 H

Gross Plant Power: 680 MWe Auxiliary Load: 130 MWe Net Plant Power: 550 MWe Net Plant Efficiency, HHV: 25.7% Net Plant Heat Rate: 13,269 BTU/KWe

OXIDATION AIR MAKE-UP WATER

LIMESTONE SLURRY GYPSUM 12 15

13 14 10 11

370.7 T 15.3 P 141.4 H 208,796 W 59.0 T 15.0 P

74,628 W 63.6 T 15.0 P 14.1 H 601,821 W 59.0 T 14.7 P 27.0 H

107,683 W 135.8 T 14.8 P

STRIPPER

ABSORBER FLUE GAS Acid Gas

ECONAMINE FG+

ECONAMINE CONDENSATE

18

19 360,117 W

306.3 T 73.5 P 1,181.4 H 2,548,957 W 556.3 T 73.5 P 1,309.6 H

2,548,957 W 304.0 T 133.6 P 274.0 H

ECONAMINE STEAM

1,470,497 W 95.0 T 2,214.5 P -91.3 H

1,477,492 W 69.0 T 23.5 P 11.8 H 5,177,011 W 88.8 T 14.8 P 40.5 H CO2 COMPRESSION (INTERSTAGE COOLING)

CO2 PRODUCT

Baghouse

21 22 20

DOE/NETL SC PC PLANT CASE 1G

NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Coal / Ash

Water

Steam

Limestone Slurry

Flue Gas Ammonia

Carbon Dioxide Gypsum
Carbon Dioxide Capture Sensitivity Analysis

138

Exhibit 3-51 Case 1G (99%) Heat and Mass Balance, Power Block Systems

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Water

Steam

PAGES 2 OF 2 DWG. NO. CCSA-HMB-CS-1G-PG-2 CO2 CAPTURE SENSITIVITY ANALYSIS CASE 1G (99%) SUPERCRITICAL PULVERIZED COAL POWER BLOCK SYSTEMS

LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER HOT WELL To Boiler

BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR

Throttle Steam

Single Reheat Extraction From Boiler

GLAND SEAL CONDENSER

CONDENSATE PUMPS

5,495,788 W 1,100.0 T 3,514.7 P 1,495.1 H

2,900.0 P

311,726 W 803.0 T 211.9 P 1,426.5 H 669,964 W 665.2 T 700.8 P 1,324.1 H

Single Reheat Extraction to Boiler 4,487,587 W 668.3 T 710.8 P 1,325.3 H 710.8 P

1,115.5 P

307,380 W 763.9 T 990.5 P 1,367.9 H

710.8 P

710.8 P

221.9 P

75.0 P

75.0 P

410,390 W 556.3 T 73.5 P 1,309.6 H

126.1 T 2.0 P 1,085.8 H 962,587 W 101.1 T 1.0 P 1,009.9 H

2,793 W 212.0 T 14.7 P 180.3 H

29.0 P

11.4 P

4.5 P

101.4 T 250.0 P 70.4 H

2,793 W 674.7 T 75.0 P 1,368.1 H 1,633,566 W 101.1 T 1.0 P 69.5 H

1,633,566 W 103.5 T 245.0 P 72.5 H 1,633,566 W 123.8 T 240.0 P 92.7 H 199,538 W 113.5 T 1.4 P 81.8 H 169,110 W 133.8 T 2.5 P 102.0 H

1,633,566 W 235.0 T 225.0 P 204.0 H 1,289,069 W 321.8 T 91.9 P 292.3 H

1,633,566 W 190.2 T 230.0 P 158.9 H 977,343 W 398.7 T 243.6 P 373.7 H 307,380 W 513.3 T 765.9 P 503.8 H

5,495,788 W 388.7 T 4,195.0 P 368.3 H 5,495,788 W 503.3 T 4,190.0 P 491.4 H DEAERATOR

BOILER FEED PUMPS

5,495,788 W 545.5 T 4,185.0 P 539.7 H

17 4,487,587 W 1,100.0 T 655.8 P 1,570.6 H

69,707 W 200.2 T 11.6 P 168.4 H 129,461 W 161.0 T 4.9 P 129.2 H

1,633,566 W 151.0 T 235.0 P 119.8 H 79,154 W 607.6 T 70.0 P 1,335.2 H 69,707 W 370.1 T 25.0 P 1,224.0 H 59,754 W 216.1 T 10.4 P 1,154.1 H 39,649 W 157.3 T 4.3 P 1,129.3 H 30,427 W 128.8 T 2.2 P 1,054.6 H

2,900.0 P

4,116,486 W 556.3 T 73.5 P 1,309.6 H 1,157,139 W 556.3 T 73.5 P 1,309.6 H

2.3 P

2,900.0 P

Steam Turbine Makeup

54,958 W 59.0 T 14.7 P 27.5 H

311.8 T 4,200.0 P 289.5 H 5,495,788 W 302.9 T 70.0 P 272.8 H

3,301 W 674.7 T 75.0 P 1,368.1 H

Gross Plant Power: 680 MWe Auxiliary Load: 130 MWe Net Plant Power: 550 MWe Net Plant Efficiency, HHV: 25.7% Net Plant Heat Rate: 13,269 BTU/KWe FWH 4 FWH 3 FWH 2 FWH 1 FWH 8 FWH 7 FWH 6

4,985 W 674.7 T 75.0 P 1,368.1 H

DOE/NETL SC PC PLANT CASE 1G

2,548,957 W 304.0 T 133.6 P 274.0 H

ECONAMINE CONDENSATE

19

2,548,957 W 556.3 T 73.5 P 1,309.6 H ECONAMINE STEAM 18
Carbon Dioxide Capture Sensitivity Analysis

139

Exhibit 3-52 Case 1E (90%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 7,012 

(6,646) 5.9 (5.6) 7,018 (6,651)

Combustion Air 78.1 (74.1) 78.1 (74.1)

Raw Water Makeup 158.4 (150.1) 158.4 

(150.1)

Limestone 0.57 (0.54) 0.57 (0.54)

Totals 7,012 

(6,646) 243.0 (230.3) 0.0 (0.0) 7,255 (6,876)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.6 (0.6) 0.6 (0.6)

Fly Ash + Gypsum 2.6 (2.4) 2.6 (2.4)

Flue Gas 205 (195) 205 (195)

CO2 -117 (-111) -117 (-111)

Cooling Tower* 3,187.8 (3,021.4) 3,187.8 

(3,021.4)

Process Losses** 1,995.6 (1,891.5) 1,995.6 

(1,891.5)

Net Power 1,980 

(1,877)

1,980 

(1,877)

Totals 0.0 (0.0) 5,275 (4,999) 1,980 

(1,877)

7,255

(6,876)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and 

 Econamine cooling water.

** Process losses are estimated to match the heat input to the plant. 

 Process losses include losses from: steam turbine, combustion reactions, gas cooling,

 and Econamine steam.
Carbon Dioxide Capture Sensitivity Analysis

140

Exhibit 3-53 Case 1F (95%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 7,195 

(6,820) 6.0 (5.7) 7,201 (6,825)

Combustion Air 80.2 (76.0) 80.2 (76.0)

Raw Water Makeup 164.7 (156.1) 164.7 

(156.1)

Limestone 0.58 (0.55) 0.58 (0.55)

Totals 7,195 

(6,820) 251.5 (238.4) 0.0 (0.0) 7,447 (7,058)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.7 (0.6) 0.7 (0.6)

Fly Ash + Gypsum 2.6 (2.5) 2.6 (2.5)

Flue Gas 209 (198) 209 (198)

CO2 -127 (-120) -127 (-120)

Cooling Tower* 3,195.0 (3,028.3) 3,195.0 

(3,028.3)

Process Losses** 2,187.0 (2,072.8) 2,187.0 

(2,072.8)

Net Power 1,980 

(1,877)

1,980 

(1,877)

Totals 0.0 (0.0) 5,467 (5,182) 1,980 

(1,877)

7,447 

(7,058)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and 

 Econamine cooling water.

** Process losses are estimated to match the heat input to the plant. 

 Process losses include losses from: steam turbine, combustion reactions, gas cooling,

 and Econamine steam.
Carbon Dioxide Capture Sensitivity Analysis

141

Exhibit 3-54 Case 1G (99%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 7,700 

(7,298) 6.4 (6.1) 7,706 (7,304)

Combustion Air 85.8 (81.3) 85.8 (81.3)

Raw Water Makeup 182.2 (172.7) 182.2 

(172.7)

Limestone 0.62 (0.59) 0.62 (0.59)

Totals 7,700 

(7,298) 275.1 (260.7) 0.0 (0.0) 7,975 (7,559)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.7 (0.7) 0.7 (0.7)

Fly Ash + Gypsum 2.8 (2.7) 2.8 (2.7)

Flue Gas 221 (210) 221 (210)

CO2 -142 (-134) -142 (-134)

Cooling Tower* 3,125.1 (2,962.1) 3,125.1 

(2,962.1)

Process Losses** 2,786.4 (2,641.0) 2,786.4 

(2,641.0)

Net Power 1,980 

(1,877)

1,980 

(1,877)

Totals 0.0 (0.0) 5,995 (5,682) 1,980 

(1,877)

7,975 

(7,559)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and 

 Econamine cooling water.

** Process losses are estimated to match the heat input to the plant. 

 Process losses include losses from: steam turbine, combustion reactions, gas cooling,

 and Econamine steam.
Carbon Dioxide Capture Sensitivity Analysis

142

Exhibit 3-55 Case 1E Energy Balance Sankey Diagram

Exhibit 3-56 Case 1F Energy Balance Sankey Diagram
Carbon Dioxide Capture Sensitivity Analysis

143

Exhibit 3-57 Case 1G Energy Balance Sankey Diagram
Carbon Dioxide Capture Sensitivity Analysis

144

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Carbon Dioxide Capture Sensitivity Analysis

145

3.2.2.2 Major Equipment List for Cases 1E through 1G

Major equipment items for the CO2 capture without bypass cases 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 3.2.4. 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. 

ACCOUNT 1 FUEL AND SORBENT HANDLING

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1E Case 1F Case 1G (Spares)

1

Bottom Trestle Dumper with 

Receiving Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0)

3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

4 Transfer Tower No. 1 Enclosed N/A N/A N/A 1 (0)

5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

6

As-Received Coal Sampling 

System Two-stage N/A N/A N/A 1 (0)

7 Stacker/Reclaim Traveling Linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

8 Reclaim Hopper N/A 54 tonne (60 ton) 54 tonne (60 ton) 64 tonne (70 ton) 2 (1)

9 Feeder Vibratory 209 tonne/hr (230 tph) 218 tonne/hr (240 tph) 236 tonne/hr (260 tph) 2 (1)

10 Conveyor No. 3 Belt w/tripper 426 tonne/hr (470 tph) 435 tonne/hr (480 tph) 472 tonne/hr (520 tph) 1 (0)

11 Crusher Tower N/A N/A N/A N/A 1 (0)

12 Coal Surge Bin w/ Vent Filter Dual Outlet 209 tonne (230 ton) 218 tonne (240 ton) 236 tonne (260 ton) 2 (0)

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3 in x 0 - 1-1/4 in x 0)

8 cm x 0 - 3 cm x 0

(3 in x 0 - 1-1/4 in x 0)

8 cm x 0 - 3 cm x 0

(3 in x 0 - 1-1/4 in x 0) 2 (0)

14 As-Fired Coal Sampling 

System Swing Hammer N/A N/A N/A 1 (1)

15 Conveyor No. 4 Belt w/tripper 426 tonne/hr (470 tph) 435 tonne/hr (480 tph) 472 tonne/hr (520 tph) 1 (0)

16 Transfer Tower No. 2 Enclosed N/A N/A N/A 1 (0)

17 Conveyor No. 5 Belt w/tripper 426 tonne/hr (470 tph) 435 tonne/hr (480 tph) 472 tonne/hr (520 tph) 1 (0)

18 Coal Silo w/ Vent Filter and 

Slide Gates Field Erected 907 tonne (1,000 ton) 998 tonne (1,100 ton) 998 tonne (1,100 ton) 3 (0)

19 Limestone Truck Unloading 

Hopper N/A 36 tonne (40 ton) 36 tonne (40 ton) 36 tonne (40 ton) 1 (0)

20 Limestone Feeder Belt 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 118 tonne/hr (130 tph) 1 (0)

21 Limestone Conveyor No. L1 Belt 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 118 tonne/hr (130 tph) 1 (0)

22 Limestone Reclaim Hopper N/A 18 tonne (20 ton) 18 tonne (20 ton) 27 tonne (30 ton) 1 (0)

23 Limestone Reclaim Feeder Belt 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 1 (0)

24 Limestone Conveyor No. L2 Belt 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 1 (0)

25 Limestone Day Bin w/ actuator 345 tonne (380 ton) 354 tonne (390 ton) 381 tonne (420 ton) 2 (0)
Carbon Dioxide Capture Sensitivity Analysis

146

ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1E Case 1F Case 1G (Spares)

1 Coal Feeder Gravimetric 45 tonne/hr (50 tph) 45 tonne/hr (50 tph) 54 tonne/hr (60 tph) 6 (0)

2 Coal Pulverizer Ball type or eq. 45 tonne/hr (50 tph) 45 tonne/hr (50 tph) 54 tonne/hr (60 tph) 6 (0)

3 Limestone Weigh Feeder Gravimetric 29 tonne/hr (32 tph) 30 tonne/hr (33 tph) 32 tonne/hr (35 tph) 1 (1)

4 Limestone Ball Mill Rotary 29 tonne/hr (32 tph) 30 tonne/hr (33 tph) 32 tonne/hr (35 tph) 1 (1)

5

Limestone Mill Slurry 

Tank with Agitator N/A 109,777 liters (29,000 gal)

113,562 liters 

(30,000 gal)

121,133 liters 

(32,000 gal) 1 (1)

6

Limestone Mill Recycle 

Pumps

Horizontal 

centrifugal

1,855 lpm @ 12m H2O 

(490 gpm @ 40 ft H2O)

1,893 lpm @ 12m H2O 

(500 gpm @ 40 ft H2O)

2,006 lpm @ 12m H2O 

(530 gpm @ 40 ft H2O) 1 (1)

7 Hydroclone Classifier 4 active cyclones in 

a 5 cyclone bank

454 lpm (120 gpm) per 

cyclone

492 lpm (130 gpm) per 

cyclone

492 lpm (130 gpm) per 

cyclone 1 (1)

8 Distribution Box 2-way N/A N/A N/A 1 (1)

9

Limestone Slurry Storage 

Tank with Agitator Field erected 620,808 liters (164,000 gal)

639,735 liters 

(169,000 gal)

681,374 liters 

(180,000 gal) 1 (1)

10 Limestone Slurry Feed

Pumps

Horizontal 

centrifugal

1,287 lpm @ 9m H2O 

(340 gpm @ 30 ft H2O)

1,325 lpm @ 9m H2O 

(350 gpm @ 30 ft H2O)

1,401 lpm @ 9m H2O 

(370 gpm @ 30 ft H2O) 1 (1)

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1E Case 1F Case 1G (Spares)

1

Demineralized Water 

Storage Tank Vertical, cylindrical, outdoor 1,499,023 liters (396,000 gal) 1,540,663 liters (407,000 gal) 1,646,654 liters (435,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 17,034 lpm @ 213 m H2O 

(4,500 gpm @ 700 ft H2O)

16,277 lpm @ 213 m H2O 

(4,300 gpm @ 700 ft H2O)

13,627 lpm @ 213 m H2O 

(3,600 gpm @ 700 ft H2O)

1 (1)

3

Deaerator and Storage 

Tank Horizontal spray type 2,497,480 kg/hr (5,506,000 lb/hr), 5 min. tank

2,562,797 kg/hr (5,650,000 lb/hr), 

5 min. tank

2,741,966 kg/hr (6,045,000 lb/hr), 

5 min. tank

1 (0)

4

Boiler Feed 

Pump/Turbine

Barrel type, multi-stage, 

centrifugal

42,018 lpm @ 3,505 m H2O 

(11,100 gpm @ 11,500 ft H2O)

43,154 lpm @ 3,505 m H2O 

(11,400 gpm @ 11,500 ft H2O)

46,182 lpm @ 3,505 m H2O 

(12,200 gpm @ 11,500 ft H2O)

1 (1)

5

Startup Boiler Feed 

Pump, Electric Motor 

Driven

Barrel type, multi-stage, 

centrifugal

12,492 lpm @ 3,505 m H2O 

(3,300 gpm @ 11,500 ft H2O)

12,870 lpm @ 3,505 m H2O 

(3,400 gpm @ 11,500 ft H2O)

13,627 lpm @ 3,505 m H2O 

(3,600 gpm @ 11,500 ft H2O)

1 (0)

6

LP Feedwater Heater 

1A/1B Horizontal U-tube 503,488 kg/hr (1,110,000 lb/hr) 480,808 kg/hr (1,060,000 lb/hr) 408,233 kg/hr (900,000 lb/hr) 2 (0)

7

LP Feedwater Heater 

2A/2B Horizontal U-tube 503,488 kg/hr (1,110,000 lb/hr) 480,808 kg/hr (1,060,000 lb/hr) 408,233 kg/hr (900,000 lb/hr) 2 (0)

8

LP Feedwater Heater 

3A/3B Horizontal U-tube 503,488 kg/hr (1,110,000 lb/hr) 480,808 kg/hr (1,060,000 lb/hr) 408,233 kg/hr (900,000 lb/hr) 2 (0)

9

LP Feedwater Heater 

4A/4B Horizontal U-tube 503,488 kg/hr (1,110,000 lb/hr) 480,808 kg/hr (1,060,000 lb/hr) 408,233 kg/hr (900,000 lb/hr) 2 (0)

10 HP Feedwater Heater 

6

Horizontal U-tube 2,499,294 kg/hr (5,510,000 lb/hr) 2,562,797 kg/hr (5,650,000 lb/hr) 2,744,234 kg/hr (6,050,000 lb/hr) 1 (0)

11 HP Feedwater Heater 

7

Horizontal U-tube 2,499,294 kg/hr (5,510,000 lb/hr) 2,562,797 kg/hr (5,650,000 lb/hr) 2,744,234 kg/hr (6,050,000 lb/hr) 1 (0)

12 HP Feedwater heater 8 Horizontal U-tube 2,499,294 kg/hr (5,510,000 lb/hr) 2,562,797 kg/hr (5,650,000 lb/hr) 2,744,234 kg/hr (6,050,000 lb/hr) 1 (0)

13 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C 

(40,000 lb/hr, 400 psig, 650°F)

18,144 kg/hr, 2.8 MPa, 343°C 

(40,000 lb/hr, 400 psig, 650°F)

18,144 kg/hr, 2.8 MPa, 343°C 

(40,000 lb/hr, 400 psig, 650°F)

1 (0)
Carbon Dioxide Capture Sensitivity Analysis

147

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1E Case 1F Case 1G (Spares)

14 Fuel Oil System No. 2 fuel oil for light off 1,135,624 liter (300,000 gal) 1,135,624 liter (300,000 gal) 1,135,624 liter (300,000 gal) 1 (0)

15 Service Air 

Compressors Flooded Screw 28 m3

/min @ 0.7 MPa 

(1,000 scfm @ 100 psig)

28 m3/min @ 0.7 MPa 

(1,000 scfm @ 100 psig)

28 m3/min @ 0.7 MPa 

(1,000 scfm @ 100 psig)

2 (1)

16 Instrument Air Dryers Duplex, regenerative 28 m3

/min (1,000 scfm) 28 m3/min (1,000 scfm) 28 m3/min (1,000 scfm) 2 (1)

17 Closed Cylce Cooling 

Heat Exchangers Shell and tube 53 GJ/hr (50 MMBtu/hr) each 53 GJ/hr (50 MMBtu/hr) each 53 GJ/hr (50 MMBtu/hr) each 2 (0)

18 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 20,820 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O)

20,820 lpm @ 30 m H2O 

(5,500 gpm @ 100 ft H2O)

20,820 lpm @ 30 m H2O 

(5,500 gpm @ 100 ft H2O)

2 (1)

19 Engine-Driven Fire 

Pump Vertical turbine, diesel engine 3,785 lpm @ 88 m H2O (1,000 gpm @ 290 ft H2O)

3,785 lpm @ 88 m H2O 

(1,000 gpm @ 290 ft H2O)

3,785 lpm @ 88 m H2O 

(1,000 gpm @ 290 ft H2O)

1 (1)

20 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 64 m H2O 

(700 gpm @ 210 ft H2O)

2,650 lpm @ 64 m H2O 

(700 gpm @ 210 ft H2O)

2,650 lpm @ 64 m H2O 

(700 gpm @ 210 ft H2O)

1 (1)

21 Raw Water Pumps Stainless steel, single suction 20,101 lpm @ 43 m H2O 

(5,310 gpm @ 140 ft H2O)

20,933 lpm @ 43 m H2O 

(5,530 gpm @ 140 ft H2O)

23,280 lpm @ 43 m H2O 

(6,150 gpm @ 140 ft H2O)

2 (1)

22 Filtered Water Pumps Stainless steel, single suction 757 lpm @ 49 m H2O 

(200 gpm @ 160 ft H2O)

795 lpm @ 49 m H2O 

(210 gpm @ 160 ft H2O)

871 lpm @ 49 m H2O 

(230 gpm @ 160 ft H2O)

2 (1)

23 Filtered Water Tank Vertical, cylindrical 738,155 liter (195,000 gal) 760,868 liter (201,000 gal) 817,649 liter (216,000 gal) 1 (0)

24 Makeup Water 

Demineralizer

Multi-media filter, cartridge 

filter, RO membrane assembly, 

electrodeionization unit

984 lpm (260 gpm) 1,022 lpm (270 gpm) 1,098 lpm (290 gpm) 1 (1)

25 Liquid Waste 

Treatment System -- 10 years, 24-hour storm 10 years, 24-hour storm 10 years, 24-hour storm 1 (0)

ACCOUNT 4 BOILER AND ACCESSORIES

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1E Case 1F Case 1G (Spares)

1 Boiler

Supercritical, drum, 

wall-fired, low NOx 

burners, overfire air

2,499,294 kg/hr steam @ 25.5 

MPa/602°C/602°C 

(5,510,000 lb/hr steam @ 3,700 

psig/1,115°F/1,115°F)

2,562,797 kg/hr steam @ 25.5 

MPa/602°C/602°C 

(5,650,000 lb/hr steam @ 3,700 

psig/1,115°F/1,115°F)

2,744,234 kg/hr steam @ 25.5 

MPa/602°C/602°C 

(6,050,000 lb/hr steam @ 3,700 

psig/1,115°F/1,115°F)

1 (0)

2 Primary Air Fan Centrifugal

327,494 kg/hr, 4,468 m3/min @ 123 

cm WG (722,000 lb/hr, 157,800 acfm 

@ 48 in. WG)

336,112 kg/hr, 4,584 m3/min @ 123 cm 

WG (741,000 lb/hr, 161,900 acfm @ 

48 in. WG)

359,699 kg/hr, 4,907 m3/min @ 123 cm 

WG (793,000 lb/hr, 173,300 acfm @ 

48 in. WG)

2 (0)

3 Forced Draft Fan Centrifugal

1,066,396 kg/hr, 14,546 m3/min @ 51 

cm WG (2,351,000 lb/hr, 513,700 

acfm @ 20 in. WG)

1,094,065 kg/hr, 14,929 m3/min @ 51 

cm WG (2,412,000 lb/hr, 527,200 acfm 

@ 20 in. WG)

1,171,175 kg/hr, 15,974 m3/min @ 51 

cm WG (2,582,000 lb/hr, 564,100 acfm 

@ 20 in. WG)

2 (0)

4 Induced Draft Fan Centrifugal

1,550,379 kg/hr, 33,176 m3/min @ 91 

cm WG (3,418,000 lb/hr, 1,171,600 

acfm @ 36 in. WG)

1,590,748 kg/hr, 34,045 m3/min @ 91 

cm WG (3,507,000 lb/hr, 1,202,300 

acfm @ 36 in. WG)

1,702,332 kg/hr, 36,430 m3/min @ 91 

cm WG (3,753,000 lb/hr, 1,286,500 

acfm @ 36 in. WG)

2 (0)

5 SCR Reactor Vessel Space for spare layer 3,102,572 kg/hr (6,840,000 lb/hr) 3,179,683 kg/hr (7,010,000 lb/hr) 3,406,479 kg/hr (7,510,000 lb/hr) 2 (0)

6 SCR Catalyst -- -- -- -- 3 (0)

7 Dilution Air Blower Centrifugal 57 m3

/min @ 108 cm WG 

(2,000 acfm @ 42 in. WG)

57 m3/min @ 108 cm WG 

(2,000 acfm @ 42 in. WG)

62 m3/min @ 108 cm WG 

(2,200 acfm @ 42 in. WG)

2 (1)

8 Ammonia Storage Horizontal tank 60,567 liter (16,000 gal) 64,352 liter (17,000 gal) 68,137 liter (18,000 gal) 5 (0)

9 Ammonia Feed Pump Centrifugal 12 lpm @ 91 m H2O 

(3 gpm @ 300 ft H2O)

12 lpm @ 91 m H2O 

(3 gpm @ 300 ft H2O)

13 lpm @ 91 m H2O 

(3 gpm @ 300 ft H2O)

2 (1)
Carbon Dioxide Capture Sensitivity Analysis

148

ACCOUNT 5 FLUE GAS CLEANUP

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1E Case 1F Case 1G (Spares)

1 Fabric Filter Single stage, high-ratio with 

pulse-jet online cleaning system

1,550,379 kg/hr (3,418,000 

lb/hr) 99.8% efficiency

1,590,748 kg/hr (3,507,000 lb/hr) 

99.8% efficiency

1,702,332 kg/hr (3,753,000 

lb/hr) 99.8% efficiency

2 (0)

2 Absorber Module Counter-current open spray 51,169 m3

/min 

(1,807,000 acfm) 52,499 m3

/min (1,854,000 acfm) 56,181 m3

/min 

(1,984,000 acfm)

1 (0)

3 Recirculation Pumps Horizontal centrifugal 177,914 lpm @ 64 m H2O 

(47,000 gpm @ 210 ft H2O)

181,700 lpm @ 64 m H2O 

(48,000 gpm @ 210 ft H2O)

196,841 lpm @ 64 m H2O 

(52,000 gpm @ 210 ft H2O)

5 (1)

4 Bleed Pumps Horizontal centrifugal 5,602 lpm (1,480 gpm) at 20 

wt% solids

5,754 lpm (1,520 gpm) at 20 wt% 

solids

6,170 lpm (1,630 gpm) at 20 

wt% solids

2 (1)

5 Oxidation Air Blowers Centrifugal 229 m3

/min @ 0.3 MPa 

(8,100 acfm @ 42 psia)

235 m3/min @ 0.3 MPa 

(8,310 acfm @ 42 psia)

251 m3/min @ 0.3 MPa 

(8,870 acfm @ 42 psia)

2 (1)

6 Agitators Side entering 50 hp 50 hp 50 hp 5 (1)

7 Dewatering Cyclones Radial assembly, 5 units each 1,401 lpm (370 gpm) per 

cyclone 1,438 lpm (380 gpm) per cyclone 1,552 lpm (410 gpm) per cyclone

2 (0)

8 Vacuum Filter Belt Horizontal belt 44 tonne/hr (49 tph) of 50 wt 

% slurry

45 tonne/hr (50 tph) of 50 wt % 

slurry

49 tonne/hr (54 tph) of 50 wt % 

slurry

2 (1)

9

Filtrate Water Return 

Pumps Horizontal centrifugal 871 lpm @ 12 m H2O (230 gpm @ 40 ft H2O)

871 lpm @ 12 m H2O 

(230 gpm @ 40 ft H2O)

946 lpm @ 12 m H2O 

(250 gpm @ 40 ft H2O)

1 (1)

10 Filtrate Water Return 

Storage Tank Vertical, lined 567,812 lpm (150,000 gal) 567,812 lpm (150,000 gal) 605,666 lpm (160,000 gal) 1 (1)

11 Process Makeup 

Water Pumps Horizontal centrifugal 568 lpm @ 21 m H2O (150 gpm @ 70 ft H2O)

568 lpm @ 21 m H2O 

(150 gpm @ 70 ft H2O)

606 lpm @ 21 m H2O 

(160 gpm @ 70 ft H2O)

1 (1)

ACCOUNT 5B CARBON DIOXIDE RECOVERY 

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 

(Spares) 1E Case 1F Case 1G

1 Econamine FG Plus Amine-based CO2 capture 

technology

1,640,190 kg/h (3,616,000 lb/h) 

20.6 wt % CO2 concentration

1,683,281 kg/h (3,711,000 lb/h) 

20.6 wt % CO2 concentration

1,801,215 kg/h (3,971,000 lb/h) 

20.6 wt % CO2 concentration

2 (0)

2

Econamine 

Condensate Pump Centrifugal 14,650 lpm @ 52 m H2O (3,870 gpm @ 170 ft H2O)

16,202 lpm @ 52 m H2O 

(4,280 gpm @ 170 ft H2O)

21,236 lpm @ 52 m H2O 

(5,610 gpm @ 170 ft H2O)

1 (1)

3 CO2 Compressor Centrifugal 303,707 kg/h @ 15.3 MPa 

(669,559 lb/h @ 2,215 psia)

328,968 kg/h @ 15.3 MPa 

(725,250 lb/h @ 2,215 psia)

366,853 kg/h @ 15.3 MPa 

(808,773 lb/h @ 2,215 psia)

2 (0)

ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES 

N/A

ACCOUNT 7 DUCTING AND STACK

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1E Case 1F Case 1G (Spares)
Carbon Dioxide Capture Sensitivity Analysis

149

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1E Case 1F Case 1G (Spares)

1 Stack Reinforced concrete with FRP liner 152 m (500 ft) high x

5.6 m (18 ft) diameter

152 m (500 ft) high x

5.6 m (18 ft) diameter

152 m (500 ft) high x

5.8 m (19 ft) diameter

1 (0)

ACCOUNT 8 STEAM TURBINE GENERATOR

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1E Case 1F Case 1G (Spares)

1

Steam Turbine 

Generator

Commercially available, advanced 

steam turbine

696 MW 

24.1 MPa/593°C/593°C 

(3500 psig/ 1100°F/1100°F)

703 MW 

24.1 MPa/593°C/593°C 

(3500 psig/ 1100°F/1100°F)

715 MW 

24.1 MPa/593°C/593°C 

(3500 psig/ 1100°F/1100°F)

1 (0)

2

Steam Turbine 

Generator Hydrogen cooled, static excitation 770 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase

780 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

790 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

1 (0)

3 Surface Condenser Single pass, divided waterbox including 

vacuum pumps

1,910 GJ/hr (1,810 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), Water temperature rise 

11°C (20°F)

1,836 GJ/hr (1,740 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), Water temperature rise 

11°C (20°F)

1,540 GJ/hr (1,460 MMBtu/hr),

Inlet water temperature 16°C 

(60°F), Water temperature rise 

11°C (20°F)

1 (0)

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1E Case 1F Case 1G (Spares)

1

Circulating Water 

Pumps Vertical, wet pit 1,014,500 lpm @ 30 m(268,000 gpm @ 100 ft)

1,056,100 lpm @ 30 m

(279,000 gpm @ 100 ft)

1,173,500 lpm @ 30 m

(310,000 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 / 5666 GJ/hr 

(5370 MMBtu/hr) heat duty

11°C (51.5°F) wet bulb / 16°C (60°F) 

CWT / 27°C (80°F) HWT / 5898 GJ/hr 

(5590 MMBtu/hr) heat duty

11°C (51.5°F) wet bulb / 16°C (60°F) 

CWT / 27°C (80°F) HWT / 6531 GJ/hr 

(6190 MMBtu/hr) heat duty

1 (0)

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1E Case 1F Case 1G (Spares)

1

Economizer Hopper (part of boiler 

scope of supply) -- -- -- -- 4 (0)

2

Bottom Ash Hopper (part of boiler 

scope of supply) -- -- -- -- 2 (0)

3 Clinker Grinder -- 5.4 tonne/hr (6 tph) 5.4 tonne/hr (6 tph) 6.4 tonne/hr (7 tph) 1 (1)

4

Pyrites Hopper (part of pulverizer 

scope of supply included with 

boiler)

-- -- -- -- 6 (0)

5 Hydroejectors -- -- -- -- 12 (0)

6 Economizer /Pyrites Transfer Tank -- -- -- -- 1 (0)

7 Ash Sluice Pumps Vertical, wet pit 227 lpm @ 17 m H2O 

(60 gpm @ 56 ft H2O)

227 lpm @ 17 m H2O 

(60 gpm @ 56 ft H2O)

227 lpm @ 17 m H2O 

(60 gpm @ 56 ft H2O)

1 (1)

8 Ash Seal Water Pumps Vertical, wet pit 7,571 lpm @ 9 m H2O 

(2000 gpm @ 28 ft H2O)

7,571 lpm @ 9 m H2O 

(2000 gpm @ 28 ft H2O)

7,571 lpm @ 9 m H2O 

(2000 gpm @ 28 ft H2O)

1 (1)

9 Hydrobins -- 227 lpm (60 gpm) 227 lpm (60 gpm) 227 lpm (60 gpm) 1 (1)

10 Baghouse Hopper (part of 

baghouse scope of supply) -- -- -- --

24 (0)
Carbon Dioxide Capture Sensitivity Analysis

150

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1E Case 1F Case 1G (Spares)

11 Air Heater Hopper (part of boiler 

scope of supply) -- -- -- --

10 (0)

12 Air Blower --

20 m3/min @ 0.2 MPa 

(710 scfm @ 24 psi)

21 m

3

/min @ 0.2 MPa 

(730 scfm @ 24 psi)

22 m3/min @ 0.2 MPa 

(780 scfm @ 24 psi)

1 (1)

13 Fly Ash Silo Reinforced 

concrete 680 tonne (1,500 ton) 680 tonne (1,500 ton) 726 tonne (1,600 ton)

2 (0)

14 Slide Gate Valves -- -- -- -- 2 (0)

15 Unloader -- -- -- -- 1 (0)

16 Telescoping Unloading Chute -- 127 tonne/hr (140 tph) 127 tonne/hr (140 tph) 136 tonne/hr (150 tph) 1 (0)

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1E Case 1F Case 1G (Spares)

1 STG Transformer Oil-filled 24 kV/345 kV, 650 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 650 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 650 MVA, 

3-ph, 60 Hz

1 (0)

2 Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 121 MVA, 

3-ph, 60 Hz

24 kV/4.16 kV, 128 MVA, 

3-ph, 60 Hz

24 kV/4.16 kV, 141 MVA, 

3-ph, 60 Hz

1 (1)

3 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 18 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 19 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 21 MVA, 

3-ph, 60 Hz

1 (1)

4

STG Isolated Phase Bus Duct 

and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 1 (0)

5 Medium Voltage Switchgear Metal Clad 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz 1 (1)

6 Low Voltage Switchgear Metal Enclosed 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz 1 (1)

7 Emergency Diesel Generator Sized for emergency 

shutdown 750 kW, 480 V, 3-ph, 60 Hz 750 kW, 480 V, 3-ph, 60 Hz 750 kW, 480 V, 3-ph, 60 Hz 1 (0)

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment 

No. Description Type

Design Condition Opr Qty.

Case 1E Case 1F Case 1G (Spares)

1 DCS - Main Control

Monitor/keyboard; Operator 

printer (laser color); 

Engineering printer (laser 

B&W)

Operator Stations/Printers 

and Engineering 

Stations/Printers

Operator Stations/Printers 

and Engineering 

Stations/Printers

Operator Stations/Printers 

and Engineering 

Stations/Printers

1 (0)

2 DCS – Processor Microprocessor with 

redundant input/output N/A N/A N/A 1 (0)

3 DCS - Data Highway Fiber optic Fully redundant,

25% spare

Fully redundant,

25% spare

Fully redundant,

25% spare

1 (0)
Carbon Dioxide Capture Sensitivity Analysis

151

3.2.3 Economic Analysis for the Supercritical PC Cases

The capital and operating costs for Cases 1A through 1G are presented in Section 3.2.4. A cost 

and performance summary table (Exhibit 3-72) for the SC PC cases is shown in Section 3.2.5. 

Due to the range of CO2 capture levels analyzed in Case 1, the Econamine capital and operating 

costs vary for the seven cases. While a factored approach that relies on the quantity of CO2

captured for equipment sizing and cost estimation was employed, the cost estimates for the

Econamine system were also developed based, in part, on output data from the ProTreatTM 

simulations. In particular, the ProTreatTM model output provided absorption and stripping 

column diameters for each case, which were used to determine the required number of 

absorption trains.

For this analysis, it was assumed that the maximum absorption column diameter is 20 meters, 

based on information released by Fluor [4]. As a result, cost estimates for three CO2 capture 

levels – 30 percent (1A), 50 percent (1B), and 70 percent (1C) – are based on a single absorption 

and compression train. To calculate the capital cost for a single absorption train, it was assumed 

that the absorption columns represent 40 percent of the total capital cost for a two-train 

Econamine system.

3.2.4 Capital and Operating Cost Results

The capital and operating costs for Cases 1A through 1G are shown in Exhibit 3-58 through

Exhibit 3-71. The capital costs for each case include the TPC, the owner‟s costs, TOC, and the 

total as-spent capital TASC cost. The capital and operating cost estimating methodology is 

explained in Section 2.7.
Carbon Dioxide Capture Sensitivity Analysis

152

Exhibit 3-58 Case 1A (30%) Capital Costs 

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1A - Supercritical PC w/ 30% CO2 Capture x $1, 000

Plant Size: 549.99 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload 3,509 0 1,603 0 5,112 8.9% 456 0% 0 15.0% 835 6,404 12

1.2 Coal Stackout & Reclaim 4,535 0 1,028 0 5,563 8.8% 487 0% 0 15.0% 907 6,957 13

1.3 Coal Conveyors & Yd Crus 4,217 0 1,017 0 5,233 8.8% 459 0% 0 15.0% 854 6,546 12

1.4 Other Coal Handling 1,103 0 235 0 1,338 8.7% 117 0% 0 15.0% 218 1,674 3

1.5 Sorbent Receive & Unload 144 0 43 0 188 8.8% 17 0% 0 15.0% 31 235 0

1.6 Sorbent Stackout & Reclaim 2,328 0 427 0 2,755 8.7% 240 0% 0 15.0% 449 3,444 6

1.7 Sorbent Conveyors 831 180 204 0 1,214 8.7% 105 0% 0 15.0% 198 1,517 3

1.8 Other Sorbent Handling 502 118 263 0 883 8.8% 78 0% 0 15.0% 144 1,105 2

1.9 Coal & Sorbent Hnd.Foundations 0 4,315 5,444 0 9,759 9.3% 912 0% 0 15.0% 1,601 12,272 22

SUBTOTAL 1. $17,169 $4,613 $10,263 $0 $32,045 $2,871 $0 $5,237 $40,154 $73

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying 2,015 0 393 0 2,408 8.7% 210 0% 0 15.0% 393 3,011 5

2.2 Prepared Coal Storage & Feed 5,160 0 1,126 0 6,286 8.7% 550 0% 0 15.0% 1,025 7,861 14

2.3 Slurry Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.4 Misc. Coal Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.5 Sorbent Prep Equipment 3,958 171 822 0 4,951 8.7% 431 0% 0 15.0% 807 6,190 11

2.6 Sorbent Storage & Feed 477 0 183 0 660 8.9% 59 0% 0 15.0% 108 826 2

2.7 Sorbent Injection System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.8 Booster Air Supply System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.9 Coal & Sorbent Feed Foundation 0 507 425 0 932 9.2% 86 0% 0 15.0% 153 1,171 2

SUBTOTAL 2. $11,611 $678 $2,949 $0 $15,238 $1,336 $0 $2,486 $19,059 $35

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 18,673 0 6,032 0 24,704 8.8% 2,163 0% 0 15.0% 4,030 30,897 56

3.2 Water Makeup & Pretreating 4,471 0 1,439 0 5,910 9.4% 554 0% 0 20.0% 1,293 7,757 14

3.3 Other Feedwater Subsystems 5,717 0 2,416 0 8,132 8.9% 725 0% 0 15.0% 1,329 10,186 19

3.4 Service Water Systems 876 0 477 0 1,353 9.3% 126 0% 0 20.0% 296 1,775 3

3.5 Other Boiler Plant Systems 7,108 0 7,017 0 14,125 9.4% 1,325 0% 0 15.0% 2,318 17,768 32

3.6 FO Supply Sys & Nat Gas 259 0 324 0 583 9.3% 54 0% 0 15.0% 96 733 1

3.7 Waste Treatment Equipment 4,415 0 2,517 0 6,932 9.7% 671 0% 0 20.0% 1,521 9,124 17

3.8 Misc. Power Plant Equipment 2,750 0 840 0 3,590 9.6% 345 0% 0 20.0% 787 4,722 9

SUBTOTAL 3. $44,268 $0 $21,062 $0 $65,330 $5,963 $0 $11,668 $82,961 $151

4 PC BOILER & ACCESSORIES

4.1 PC Boiler 159,566 0 89,533 0 249,099 9.7% 24,128 0.0% 0 10.0% 27,323 300,549 546

4.2 SCR (w/4.1) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.3 Open 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.4 Boiler BoP (w/ID Fans) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.5 Primary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.6 Secondary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.7 Major Component Rigging 0 w/4.1 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.8 PC Foundations 0 w/14.1 w/14.1 0 0 0% 0 0% 0 0.0% 0 0 0

SUBTOTAL 4. $159,566 $0 $89,533 $0 $249,099 $24,128 $0 $27,323 $300,549 $546

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

153

Exhibit 3-58 Case 1A (30%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1A - Supercritical PC w/ 30% CO2 Capture x $1, 000

Plant Size: 549.99 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

5A FLUE GAS CLEANUP

5.1 Absorber Vessels & Accessories 68,203 0 14,683 0 82,886 9.5% 7,845 0% 0 10.0% 9,073 99,804 181

5.2 Other FGD 3,562 0 4,036 0 7,598 9.6% 732 0% 0 10.0% 833 9,163 17

5.3 Bag House & Accessories 17,113 0 10,860 0 27,973 9.6% 2,676 0% 0 10.0% 3,065 33,714 61

5.4 Other Particulate Removal Materials 1,121 0 1,199 0 2,320 9.6% 223 0% 0 10.0% 254 2,798 5

5.5 Gypsum Dewatering System 4,680 0 795 0 5,475 9.4% 517 0% 0 10.0% 599 6,592 12

5.6 Mercury Removal System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.7 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.8 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.9 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

SUBTOTAL 5A. $94,679 $0 $31,573 $0 $126,252 $11,993 $0 $13,825 $152,070 $276

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System 85,601 0 25,921 0 111,521 9.5% 10,584 20% 22,304 20.0% 28,882 173,291 315

5B.2 CO2 Compression & Drying 9,770 0 3,051 0 12,821 9.5% 1,217 0% 0 20.0% 2,808 16,846 31

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $95,371 $0 $28,972 $0 $124,343 $11,801 $22,304 $31,690 $190,138 $346

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.2 Combustion Turbine Accessories 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.3 Compressed Air Piping 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7 HRSG, DUCTING & STACK

7.1 Flue Gas Recycle Heat Exchanger N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

7.2 SCR System 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

7.3 Ductwork 8,711 0 5,597 0 14,308 8.7% 1,250 0% 0 15.0% 2,334 17,892 33

7.4 Stack 8,616 0 5,041 0 13,657 9.6% 1,305 0% 0 10.0% 1,496 16,458 30

7.9 HRSG, Duct & Stack Foundations 0 989 1,124 0 2,113 9.3% 197 0% 0 20.0% 462 2,771 5

SUBTOTAL 7. $17,327 $989 $11,762 $0 $30,078 $2,752 $0 $4,292 $37,121 $67

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories 51,572 0 6,843 0 58,415 9.6% 5,593 0% 0 10.0% 6,401 70,409 128

8.2 Turbine Plant Auxiliaries 347 0 744 0 1,091 9.7% 106 0% 0 10.0% 120 1,317 2

8.3 Condenser & Auxiliaries 5,594 0 2,084 0 7,678 9.5% 730 0% 0 10.0% 841 9,248 17

8.4 Steam Piping 16,109 0 7,943 0 24,052 8.3% 2,007 0% 0 15.0% 3,909 29,968 54

8.9 TG Foundations 0 1,093 1,726 0 2,819 9.4% 265 0% 0 20.0% 617 3,701 7

SUBTOTAL 8. $73,622 $1,093 $19,340 $0 $94,055 $8,701 $0 $11,887 $114,643 $208

9 COOLING WATER SYSTEM

9.1 Cooling Towers 9,453 0 2,944 0 12,396 9.5% 1,177 0% 0 10.0% 1,357 14,931 27

9.2 Circulating Water Pumps 1,555 0 119 0 1,674 8.6% 143 0% 0 10.0% 182 1,999 4

9.3 Circ. Water System Auxiliaries 454 0 61 0 515 9.4% 49 0% 0 10.0% 56 619 1

9.4 Circ. Water Piping 0 3,599 3,488 0 7,088 9.2% 653 0% 0 15.0% 1,161 8,902 16

9.5 Make-up Water System 439 0 587 0 1,026 9.5% 97 0% 0 15.0% 168 1,291 2

9.6 Component Cooling Water System 360 0 286 0 646 9.4% 61 0% 0 15.0% 106 812 1

9.9 Circ. Water System Foundations 0 2,226 3,537 0 5,763 9.4% 542 0% 0 20.0% 1,261 7,567 14

SUBTOTAL 9. $12,261 $5,826 $11,022 $0 $29,108 $2,722 $0 $4,292 $36,122 $66

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*
Carbon Dioxide Capture Sensitivity Analysis

154

Exhibit 3-58 Case 1A (30%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1A - Supercritical PC w/ 30% CO2 Capture x $1, 000

Plant Size: 549.99 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Ash Coolers N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.2 Cyclone Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.3 HGCU Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.4 High Temperature Ash Piping N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.5 Other Ash Recovery Equipment N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.6 Ash Storage Silos 611 0 1,882 0 2,492 9.7% 243 0% 0 10.0% 273 3,008 5

10.7 Ash Transport & Feed Equipment 3,953 0 4,049 0 8,002 9.5% 757 0% 0 10.0% 876 9,635 18

10.8 Misc. Ash Handling Equipment 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

10.9 Ash/Spent Sorbent Foundation 0 145 171 0 316 9.3% 29 0% 0 20.0% 69 415 1

SUBTOTAL 10. $4,564 $145 $6,102 $0 $10,811 $1,029 $0 $1,219 $13,058 $24

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment 1,601 0 260 0 1,861 9.3% 172 0% 0 7.5% 152 2,186 4

11.2 Station Service Equipment 3,457 0 1,136 0 4,594 9.6% 439 0% 0 7.5% 377 5,410 10

11.3 Switchgear & Motor Control 3,975 0 676 0 4,651 9.3% 431 0% 0 10.0% 508 5,589 10

11.4 Conduit & Cable Tray 0 2,492 8,617 0 11,109 9.6% 1,063 0% 0 15.0% 1,826 13,998 25

11.5 Wire & Cable 0 4,702 9,078 0 13,780 8.4% 1,161 0% 0 15.0% 2,241 17,183 31

11.6 Protective Equipment 260 0 885 0 1,146 9.8% 112 0% 0 10.0% 126 1,383 3

11.7 Standby Equipment 1,278 0 29 0 1,307 9.5% 124 0% 0 10.0% 143 1,574 3

11.8 Main Power Transformers 7,303 0 123 0 7,426 7.6% 564 0% 0 10.0% 799 8,789 16

11.9 Electrical Foundations 0 311 762 0 1,073 9.5% 102 0% 0 20.0% 235 1,410 3

SUBTOTAL 11. $17,875 $7,506 $21,566 $0 $46,947 $4,168 $0 $6,408 $57,523 $105

12 INSTRUMENTATION & CONTROL

12.1 PC Control Equipment w/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0

12.2 Combustion Turbine Control N/A 0 N/A 0 0 0% 0 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 0.0% 0 0 0

12.4 Other Major Component Control 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

12.5 Signal Processing Equipment W/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0

12.6 Control Boards, Panels & Racks 464 0 278 0 743 9.6% 71 0% 0 15.0% 122 936 2

12.7 Computer Accessories 4,689 0 819 0 5,508 9.5% 525 0% 0 10.0% 603 6,636 12

12.8 Instrument Wiring & Tubing 2,541 0 5,041 0 7,582 8.5% 646 0% 0 15.0% 1,234 9,462 17

12.9 Other I & C Equipment 1,325 0 3,007 0 4,332 9.7% 422 0% 0 10.0% 475 5,229 10

SUBTOTAL 12. $9,019 $0 $9,145 $0 $18,165 $1,664 $0 $2,435 $22,263 $40

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 52 1,047 0 1,099 9.9% 108 0% 0 20.0% 241 1,449 3

13.2 Site Improvements 0 1,737 2,158 0 3,895 9.8% 382 0% 0 20.0% 855 5,133 9

13.3 Site Facilities 3,113 0 3,070 0 6,184 9.8% 607 0% 0 20.0% 1,358 8,149 15

SUBTOTAL 13. $3,113 $1,790 $6,274 $0 $11,177 $1,098 $0 $2,455 $14,730 $27

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

155

Exhibit 3-58 Case 1A (30%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 1A - Supercritical PC w/ 30% CO2 Capture x $1, 000

Plant Size: 549.99 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Boiler Building 0 8,705 7,655 0 16,360 9.0% 1,469 0% 0 15.0% 2,674 20,504 37

14.2 Turbine Building 0 12,476 11,627 0 24,103 9.0% 2,170 0% 0 15.0% 3,941 30,214 55

14.3 Administration Building 0 623 659 0 1,281 9.1% 116 0% 0 15.0% 210 1,607 3

14.4 Circulation Water Pumphouse 0 106 84 0 191 8.9% 17 0% 0 15.0% 31 239 0

14.5 Water Treatment Buildings 0 585 533 0 1,118 9.0% 100 0% 0 15.0% 183 1,401 3

14.6 Machine Shop 0 417 280 0 696 8.9% 62 0% 0 15.0% 114 872 2

14.7 Warehouse 0 282 283 0 565 9.0% 51 0% 0 15.0% 92 709 1

14.8 Other Buildings & Structures 0 231 196 0 427 9.0% 38 0% 0 15.0% 70 535 1

14.9 Waste Treating Building & Str. 0 437 1,325 0 1,761 9.4% 166 0% 0 15.0% 289 2,217 4

SUBTOTAL 14. $0 $23,861 $22,643 $0 $46,504 $4,190 $0 $7,604 $58,298 $106

Total Cost $560,444 $46,499 $292,207 $0 $899,149 $84,415 $22,304 $132,820 $1,138,688 $2,070

Owner's Costs

Preproduction Costs

6 Months All Labor $8,797 $16

1 Month Maintenance Materials $1,124 $2

1 Month Non-fuel Consumables $853 $2

1 Month Waste Disposal $263 $0

25% of 1 Months Fuel Cost at 100% CF $1,593 $3

2% of TPC $22,774 $41

Total $35,403 $64

Inventory Capital

60 day supply of fuel and consumables at 100% CF $14,447 $26

0.5% of TPC (spare parts) $5,693 $10

Total $20,140 $37

Initial Cost for Catalyst and Chemicals $658 $1

Land $900 $2

Other Owner's Costs $170,803 $311

Financing Costs $30,745 $56

Total Overnight Costs (TOC) $1,397,338 $2,540.7

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $1,592,965 $2,896

Labor Bare 

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Project Cont.
Carbon Dioxide Capture Sensitivity Analysis

156

Exhibit 3-59 Case 1A Initial and Annual O&M Expenses

Case: Case 1A - Supercritical PC w/ 30% CO2 Capture

Plant Size (MWe): 549.99 Heat Rate (Btu/kWh): 9,695

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 85 CO2 Captured (TPD): 3881

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 11.3 11.3

Foreman 1.0 1.0

Lab Tech's etc. 2.0 2.0

TOTAL Operating Jobs 16.3 16.3

$ $/kW-net

Annual Operating Labor Cost (calc'd) $6,431,885 $11.695

Maintenance Labor Cost (calc'd) $7,644,005 $13.898

Administrative & Support Labor (calc'd) $3,518,973 $6.398

Property Taxes & Insurance $22,773,764 $41.408

TOTAL FIXED OPERATING COSTS $40,368,627 $73.399

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $11,466,008 0.00280

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 4,707 1.08 $0 $1,577,096 0.00039

Chemicals

 MU & WT Chem. (lb) 0 22,784 0.17 $0 $1,201,673 0.00029

 Limestone (ton) 0 555 21.63 $0 $3,724,204 0.00091

 Carbon (Hg Removal) (lb) 0 0 1.05 $0 $0 0.00000

 MEA Solvent (ton) 271 0.39 2249.89 $609,715 $272,030 0.00007

 Caustic Soda, NaOH (ton) 19 1.91 433.68 $8,305 $257,649 0.00006

 Sulfuric acid, H2SO4 (ton) 18 1.83 138.78 $2,536 $78,675 0.00002

 Corrosion Inhibitor 0 0 0.00 $37,484 $1,810 0.00000

 Activated C, MEA (lb) 0 459 1.05 $0 $149,561 0.00004

 Ammonia, 28% soln (ton) 0 17 129.80 $0 $677,925 0.00017

Subtotal Chemicals $658,040 $6,363,527 0.00155

Other

 Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

 SCR Catalyst Replacement (m3)w/equip. 0.42 5,775.94 $0 $759,439 0.00019

 Emission Penalties 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $759,439 0.00019

Waste Disposal

 Spent Mercury Catalyst (lb) 0 0 0.31 $0 $0 0.00000

 Flyash (ton) 0 425 16.23 $0 $2,142,442 0.00052

 Bottom Ash (ton) 0 106 16.23 $0 $535,611 0.00013

Subtotal Solid Waste Disposal $0 $2,678,053 0.00065

By-products & Emissions

 Gypsum (tons) 0 0 0.00 $0 $0 0.00000

 Sulfur (tons) 0 0 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 0.00000

TOTAL VARIABLE OPERATING COSTS $22,844,123 0.00558

Coal FUEL (tons) 164,544 5,485 38.19 $6,283,126 $64,977,999 0.01587

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

157

Exhibit 3-60 Case 1B (50%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1B - Supercritical PC w/ 50% CO2 Capture x $1, 000

Plant Size: 549.99 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload 3,661 0 1,672 0 5,333 8.9% 476 0% 0 15.0% 871 6,680 12

1.2 Coal Stackout & Reclaim 4,731 0 1,072 0 5,803 8.8% 508 0% 0 15.0% 947 7,258 13

1.3 Coal Conveyors & Yd Crus 4,399 0 1,061 0 5,459 8.8% 479 0% 0 15.0% 891 6,829 12

1.4 Other Coal Handling 1,151 0 245 0 1,396 8.7% 122 0% 0 15.0% 228 1,746 3

1.5 Sorbent Receive & Unload 151 0 45 0 196 8.8% 17 0% 0 15.0% 32 245 0

1.6 Sorbent Stackout & Reclaim 2,432 0 446 0 2,878 8.7% 251 0% 0 15.0% 469 3,598 7

1.7 Sorbent Conveyors 868 188 213 0 1,268 8.7% 110 0% 0 15.0% 207 1,585 3

1.8 Other Sorbent Handling 524 123 275 0 922 8.8% 82 0% 0 15.0% 151 1,154 2

1.9 Coal & Sorbent Hnd.Foundations 0 4,502 5,679 0 10,180 9.3% 952 0% 0 15.0% 1,670 12,802 23

SUBTOTAL 1. $17,916 $4,812 $10,708 $0 $33,436 $2,996 $0 $5,465 $41,896 $76

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying 2,108 0 411 0 2,519 8.7% 220 0% 0 15.0% 411 3,149 6

2.2 Prepared Coal Storage & Feed 5,397 0 1,178 0 6,576 8.7% 575 0% 0 15.0% 1,073 8,223 15

2.3 Slurry Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.4 Misc. Coal Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.5 Sorbent Prep Equipment 4,138 178 859 0 5,175 8.7% 451 0% 0 15.0% 844 6,470 12

2.6 Sorbent Storage & Feed 499 0 191 0 689 8.9% 61 0% 0 15.0% 113 863 2

2.7 Sorbent Injection System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.8 Booster Air Supply System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.9 Coal & Sorbent Feed Foundation 0 529 444 0 974 9.2% 90 0% 0 15.0% 160 1,223 2

SUBTOTAL 2. $12,142 $708 $3,084 $0 $15,933 $1,397 $0 $2,599 $19,929 $36

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 19,570 0 6,321 0 25,891 8.8% 2,267 0% 0 15.0% 4,224 32,382 59

3.2 Water Makeup & Pretreating 4,930 0 1,587 0 6,516 9.4% 611 0% 0 20.0% 1,425 8,553 16

3.3 Other Feedwater Subsystems 5,991 0 2,532 0 8,523 8.9% 760 0% 0 15.0% 1,392 10,675 19

3.4 Service Water Systems 966 0 526 0 1,492 9.3% 138 0% 0 20.0% 326 1,957 4

3.5 Other Boiler Plant Systems 7,480 0 7,385 0 14,864 9.4% 1,394 0% 0 15.0% 2,439 18,697 34

3.6 FO Supply Sys & Nat Gas 264 0 329 0 593 9.3% 55 0% 0 15.0% 97 745 1

3.7 Waste Treatment Equipment 4,493 0 2,561 0 7,055 9.7% 683 0% 0 20.0% 1,548 9,286 17

3.8 Misc. Power Plant Equipment 2,798 0 855 0 3,652 9.6% 351 0% 0 20.0% 801 4,803 9

SUBTOTAL 3. $46,491 $0 $22,096 $0 $68,586 $6,259 $0 $12,252 $87,098 $158

4 PC BOILER & ACCESSORIES

4.1 PC Boiler 167,291 0 93,867 0 261,158 9.7% 25,296 0.0% 0 10.0% 28,645 315,099 573

4.2 SCR (w/4.1) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.3 Open 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.4 Boiler BoP (w/ID Fans) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.5 Primary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.6 Secondary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.7 Major Component Rigging 0 w/4.1 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.8 PC Foundations 0 w/14.1 w/14.1 0 0 0% 0 0% 0 0.0% 0 0 0

SUBTOTAL 4. $167,291 $0 $93,867 $0 $261,158 $25,296 $0 $28,645 $315,099 $573

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

158

Exhibit 3-60 Case 1B (50%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1B - Supercritical PC w/ 50% CO2 Capture x $1, 000

Plant Size: 549.99 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

5A FLUE GAS CLEANUP

5.1 Absorber Vessels & Accessories 71,665 0 15,428 0 87,093 9.5% 8,243 0% 0 10.0% 9,534 104,869 191

5.2 Other FGD 3,743 0 4,241 0 7,984 9.6% 769 0% 0 10.0% 875 9,628 18

5.3 Bag House & Accessories 18,048 0 11,453 0 29,501 9.6% 2,822 0% 0 10.0% 3,232 35,555 65

5.4 Other Particulate Removal Materials 1,181 0 1,264 0 2,445 9.6% 235 0% 0 10.0% 268 2,948 5

5.5 Gypsum Dewatering System 4,883 0 829 0 5,712 9.4% 540 0% 0 10.0% 625 6,877 13

5.6 Mercury Removal System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.7 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.8 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.9 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

SUBTOTAL 5A. $99,519 $0 $33,216 $0 $132,734 $12,609 $0 $14,534 $159,878 $291

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System 120,357 0 36,445 0 156,802 9.5% 14,882 20% 31,360 20.0% 40,609 243,653 443

5B.2 CO2 Compression & Drying 13,483 0 4,211 0 17,695 9.5% 1,680 0% 0 20.0% 3,875 23,249 42

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $133,841 $0 $40,656 $0 $174,497 $16,562 $31,360 $44,484 $266,902 $485

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.2 Combustion Turbine Accessories 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.3 Compressed Air Piping 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7 HRSG, DUCTING & STACK

7.1 Flue Gas Recycle Heat Exchanger N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

7.2 SCR System 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

7.3 Ductwork 8,940 0 5,744 0 14,684 8.7% 1,282 0% 0 15.0% 2,395 18,361 33

7.4 Stack 8,575 0 5,018 0 13,593 9.6% 1,299 0% 0 10.0% 1,489 16,381 30

7.9 HRSG, Duct & Stack Foundations 0 998 1,134 0 2,132 9.3% 199 0% 0 20.0% 466 2,797 5

SUBTOTAL 7. $17,515 $998 $11,896 $0 $30,409 $2,780 $0 $4,350 $37,540 $68

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories 52,567 0 6,975 0 59,542 9.6% 5,701 0% 0 10.0% 6,524 71,767 130

8.2 Turbine Plant Auxiliaries 354 0 758 0 1,112 9.7% 108 0% 0 10.0% 122 1,342 2

8.3 Condenser & Auxiliaries 5,372 0 2,001 0 7,374 9.5% 701 0% 0 10.0% 807 8,882 16

8.4 Steam Piping 16,894 0 8,330 0 25,224 8.3% 2,105 0% 0 15.0% 4,099 31,429 57

8.9 TG Foundations 0 1,113 1,759 0 2,872 9.4% 270 0% 0 20.0% 628 3,770 7

SUBTOTAL 8. $75,187 $1,113 $19,824 $0 $96,124 $8,885 $0 $12,182 $117,190 $213

9 COOLING WATER SYSTEM

9.1 Cooling Towers 10,446 0 3,253 0 13,698 9.5% 1,300 0% 0 10.0% 1,500 16,499 30

9.2 Circulating Water Pumps 1,758 0 135 0 1,893 8.6% 162 0% 0 10.0% 205 2,260 4

9.3 Circ. Water System Auxiliaries 498 0 66 0 565 9.4% 53 0% 0 10.0% 62 680 1

9.4 Circ. Water Piping 0 3,949 3,827 0 7,777 9.2% 716 0% 0 15.0% 1,274 9,767 18

9.5 Make-up Water System 477 0 637 0 1,114 9.5% 106 0% 0 15.0% 183 1,403 3

9.6 Component Cooling Water System 395 0 314 0 709 9.4% 66 0% 0 15.0% 116 891 2

9.9 Circ. Water System Foundations 0 2,425 3,853 0 6,278 9.4% 591 0% 0 20.0% 1,374 8,243 15

SUBTOTAL 9. $13,574 $6,374 $12,086 $0 $32,034 $2,995 $0 $4,714 $39,743 $72

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*
Carbon Dioxide Capture Sensitivity Analysis

159

Exhibit 3-60 Case 1B (50%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1B - Supercritical PC w/ 50% CO2 Capture x $1, 000

Plant Size: 549.99 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Ash Coolers N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.2 Cyclone Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.3 HGCU Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.4 High Temperature Ash Piping N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.5 Other Ash Recovery Equipment N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.6 Ash Storage Silos 634 0 1,955 0 2,589 9.7% 252 0% 0 10.0% 284 3,126 6

10.7 Ash Transport & Feed Equipment 4,107 0 4,207 0 8,314 9.5% 786 0% 0 10.0% 910 10,010 18

10.8 Misc. Ash Handling Equipment 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

10.9 Ash/Spent Sorbent Foundation 0 151 178 0 328 9.3% 31 0% 0 20.0% 72 431 1

SUBTOTAL 10. $4,741 $151 $6,339 $0 $11,231 $1,069 $0 $1,266 $13,566 $25

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment 1,625 0 264 0 1,889 9.3% 175 0% 0 7.5% 155 2,219 4

11.2 Station Service Equipment 3,904 0 1,283 0 5,187 9.6% 496 0% 0 7.5% 426 6,109 11

11.3 Switchgear & Motor Control 4,488 0 763 0 5,251 9.3% 486 0% 0 10.0% 574 6,311 11

11.4 Conduit & Cable Tray 0 2,814 9,730 0 12,544 9.6% 1,200 0% 0 15.0% 2,062 15,806 29

11.5 Wire & Cable 0 5,310 10,250 0 15,560 8.4% 1,311 0% 0 15.0% 2,531 19,401 35

11.6 Protective Equipment 260 0 885 0 1,146 9.8% 112 0% 0 10.0% 126 1,383 3

11.7 Standby Equipment 1,294 0 30 0 1,323 9.5% 125 0% 0 10.0% 145 1,594 3

11.8 Main Power Transformers 7,399 0 125 0 7,524 7.6% 572 0% 0 10.0% 810 8,905 16

11.9 Electrical Foundations 0 317 777 0 1,093 9.5% 104 0% 0 20.0% 239 1,437 3

SUBTOTAL 11. $18,971 $8,440 $24,105 $0 $51,517 $4,581 $0 $7,067 $63,164 $115

12 INSTRUMENTATION & CONTROL

12.1 PC Control Equipment w/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0

12.2 Combustion Turbine Control N/A 0 N/A 0 0 0% 0 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 0.0% 0 0 0

12.4 Other Major Component Control 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

12.5 Signal Processing Equipment W/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0

12.6 Control Boards, Panels & Racks 481 0 288 0 770 9.6% 74 0% 0 15.0% 127 970 2

12.7 Computer Accessories 4,860 0 849 0 5,710 9.5% 544 0% 0 10.0% 625 6,879 13

12.8 Instrument Wiring & Tubing 2,634 0 5,226 0 7,860 8.5% 670 0% 0 15.0% 1,279 9,809 18

12.9 Other I & C Equipment 1,373 0 3,117 0 4,490 9.7% 437 0% 0 10.0% 493 5,420 10

SUBTOTAL 12. $9,349 $0 $9,480 $0 $18,830 $1,725 $0 $2,524 $23,078 $42

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 53 1,067 0 1,120 9.9% 110 0% 0 20.0% 246 1,477 3

13.2 Site Improvements 0 1,771 2,200 0 3,971 9.8% 390 0% 0 20.0% 872 5,233 10

13.3 Site Facilities 3,174 0 3,130 0 6,304 9.8% 619 0% 0 20.0% 1,384 8,307 15

SUBTOTAL 13. $3,174 $1,825 $6,396 $0 $11,395 $1,119 $0 $2,503 $15,016 $27

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

160

Exhibit 3-60 Case 1B (50%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 1B - Supercritical PC w/ 50% CO2 Capture x $1, 000

Plant Size: 549.99 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Boiler Building 0 8,747 7,692 0 16,439 9.0% 1,476 0% 0 15.0% 2,687 20,603 37

14.2 Turbine Building 0 12,572 11,717 0 24,289 9.0% 2,187 0% 0 15.0% 3,971 30,448 55

14.3 Administration Building 0 629 665 0 1,294 9.1% 117 0% 0 15.0% 212 1,623 3

14.4 Circulation Water Pumphouse 0 116 92 0 208 8.9% 19 0% 0 15.0% 34 260 0

14.5 Water Treatment Buildings 0 641 584 0 1,225 9.0% 110 0% 0 15.0% 200 1,534 3

14.6 Machine Shop 0 421 283 0 703 8.9% 62 0% 0 15.0% 115 880 2

14.7 Warehouse 0 285 286 0 571 9.0% 52 0% 0 15.0% 93 716 1

14.8 Other Buildings & Structures 0 233 198 0 431 9.0% 39 0% 0 15.0% 70 540 1

14.9 Waste Treating Building & Str. 0 441 1,338 0 1,778 9.4% 168 0% 0 15.0% 292 2,238 4

SUBTOTAL 14. $0 $24,083 $22,855 $0 $46,938 $4,229 $0 $7,675 $58,842 $107

Total Cost $619,709 $48,505 $316,606 $0 $984,820 $92,501 $31,360 $150,260 $1,258,942 $2,289

Owner's Costs

Preproduction Costs

6 Months All Labor $9,253 $17

1 Month Maintenance Materials $1,231 $2

1 Month Non-fuel Consumables $983 $2

1 Month Waste Disposal $281 $1

25% of 1 Months Fuel Cost at 100% CF $1,705 $3

2% of TPC $25,179 $46

Total $38,632 $70

Inventory Capital

60 day supply of fuel and consumables at 100% CF $15,606 $28

0.5% of TPC (spare parts) $6,295 $11

Total $21,900 $40

Initial Cost for Catalyst and Chemicals $1,183 $2

Land $900 $2

Other Owner's Costs $188,841 $343

Financing Costs $33,991 $62

Total Overnight Costs (TOC) $1,544,390 $2,808.0

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $1,760,604 $3,201

Labor Bare 

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Project Cont.
Carbon Dioxide Capture Sensitivity Analysis

161

Exhibit 3-61 Case 1B Initial and Annual O&M Expenses

Case: Case 1B - Supercritical PC w/ 50% CO2 Capture

Plant Size (MWe): 549.99 Heat Rate (Btu/kWh): 10,379

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 85 CO2 Captured (TPD): 6977

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 11.3 11.3

Foreman 1.0 1.0

Lab Tech's etc. 2.0 2.0

TOTAL Operating Jobs 16.3 16.3

$ $/kW-net

Annual Operating Labor Cost (calc'd) 6,431,885 11.69

Maintenance Labor Cost (calc'd) 8,372,328 15.22

Administrative & Support Labor (calc'd) 3,701,053 6.73

Property Taxes & Insurance $25,178,842 $45.781

TOTAL FIXED OPERATING COSTS $43,684,109 $79.427

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $12,558,493 0.00307

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 5,401 1.08 $0 $1,809,702 0.00044

Chemicals

 MU & WT Chem. (lb) 0 26,144 0.17 $0 $1,378,908 0.00034

 Limestone (ton) 0 594 21.63 $0 $3,986,773 0.00097

 Carbon (Hg Removal) (lb) 0 0 1.05 $0 $0 0.00000

 MEA Solvent (ton) 487 0.70 2249.89 $1,095,943 $488,964 0.00012

 Caustic Soda, NaOH (ton) 34 3.44 433.68 $14,927 $463,114 0.00011

 Sulfuric acid, H2SO4 (ton) 33 3.28 138.78 $4,558 $141,416 0.00003

 Corrosion Inhibitor 0 0 0.00 $67,376 $3,254 0.00000

 Activated C, MEA (lb) 0 825 1.05 $0 $268,831 0.00007

 Ammonia, 28% soln (ton) 0 18 129.80 $0 $725,759 0.00018

Subtotal Chemicals $1,182,804 $7,457,020 0.00182

Other

 Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

 SCR Catalyst Replacement (m3)w/equip. 0.42 5,775.94 $0 $759,439 0.00019

 Emission Penalties 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $759,439 0.00019

Waste Disposal

 Spent Mercury Catalyst (lb) 0 0 0.31 $0 $0 0.00000

 Flyash (ton) 0 456 16.23 $0 $2,293,612 0.00056

 Bottom Ash (ton) 0 114 16.23 $0 $573,403 0.00014

Subtotal Solid Waste Disposal $0 $2,867,015 0.00070

By-products & Emissions

 Gypsum (tons) 0 0 0.00 $0 $0 0.00000

 Sulfur (tons) 0 0 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 0.00000

TOTAL VARIABLE OPERATING COSTS $25,451,668 0.00621

Coal FUEL (tons) 176,154 5,872 38.19 $6,726,460 $69,562,807 0.01699

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

162

Exhibit 3-62 Case 1C (70%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1C - Supercritical PC w/ 70% CO2 Capture x $1, 000

Plant Size: 550.04 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload 3,828 0 1,748 0 5,576 8.9% 498 0% 0 15.0% 911 6,985 13

1.2 Coal Stackout & Reclaim 4,947 0 1,121 0 6,067 8.8% 531 0% 0 15.0% 990 7,588 14

1.3 Coal Conveyors & Yd Crus 4,599 0 1,109 0 5,708 8.8% 500 0% 0 15.0% 931 7,140 13

1.4 Other Coal Handling 1,203 0 257 0 1,460 8.7% 128 0% 0 15.0% 238 1,826 3

1.5 Sorbent Receive & Unload 157 0 47 0 205 8.8% 18 0% 0 15.0% 33 256 0

1.6 Sorbent Stackout & Reclaim 2,538 0 465 0 3,004 8.7% 262 0% 0 15.0% 490 3,755 7

1.7 Sorbent Conveyors 906 196 222 0 1,324 8.7% 115 0% 0 15.0% 216 1,654 3

1.8 Other Sorbent Handling 547 128 287 0 962 8.8% 85 0% 0 15.0% 157 1,204 2

1.9 Coal & Sorbent Hnd.Foundations 0 4,705 5,936 0 10,641 9.3% 995 0% 0 15.0% 1,745 13,381 24

SUBTOTAL 1. $18,725 $5,030 $11,192 $0 $34,946 $3,131 $0 $5,712 $43,789 $80

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying 2,210 0 431 0 2,641 8.7% 230 0% 0 15.0% 431 3,302 6

2.2 Prepared Coal Storage & Feed 5,659 0 1,235 0 6,895 8.7% 603 0% 0 15.0% 1,125 8,623 16

2.3 Slurry Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.4 Misc. Coal Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.5 Sorbent Prep Equipment 4,322 186 898 0 5,406 8.7% 471 0% 0 15.0% 881 6,758 12

2.6 Sorbent Storage & Feed 521 0 199 0 720 8.9% 64 0% 0 15.0% 118 902 2

2.7 Sorbent Injection System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.8 Booster Air Supply System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.9 Coal & Sorbent Feed Foundation 0 554 465 0 1,019 9.2% 94 0% 0 15.0% 167 1,280 2

SUBTOTAL 2. $12,712 $740 $3,228 $0 $16,681 $1,462 $0 $2,721 $20,864 $38

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 20,561 0 6,642 0 27,203 8.8% 2,382 0% 0 15.0% 4,438 34,023 62

3.2 Water Makeup & Pretreating 5,674 0 1,826 0 7,501 9.4% 703 0% 0 20.0% 1,641 9,845 18

3.3 Other Feedwater Subsystems 6,295 0 2,660 0 8,955 8.9% 798 0% 0 15.0% 1,463 11,216 20

3.4 Service Water Systems 1,112 0 605 0 1,717 9.3% 159 0% 0 20.0% 375 2,252 4

3.5 Other Boiler Plant Systems 7,893 0 7,792 0 15,685 9.4% 1,471 0% 0 15.0% 2,573 19,730 36

3.6 FO Supply Sys & Nat Gas 268 0 335 0 604 9.3% 56 0% 0 15.0% 99 759 1

3.7 Waste Treatment Equipment 4,577 0 2,609 0 7,187 9.7% 696 0% 0 20.0% 1,577 9,460 17

3.8 Misc. Power Plant Equipment 2,848 0 870 0 3,718 9.6% 357 0% 0 20.0% 815 4,890 9

SUBTOTAL 3. $49,229 $0 $23,341 $0 $72,570 $6,623 $0 $12,981 $92,174 $168

4 PC BOILER & ACCESSORIES

4.1 PC Boiler 175,837 0 98,662 0 274,499 9.7% 26,588 0.0% 0 10.0% 30,109 331,196 602

4.2 SCR (w/4.1) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.3 Open 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.4 Boiler BoP (w/ID Fans) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.5 Primary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.6 Secondary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.7 Major Component Rigging 0 w/4.1 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.8 PC Foundations 0 w/14.1 w/14.1 0 0 0% 0 0% 0 0.0% 0 0 0

SUBTOTAL 4. $175,837 $0 $98,662 $0 $274,499 $26,588 $0 $30,109 $331,196 $602

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

163

Exhibit 3-62 Case 1C (70%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1C - Supercritical PC w/ 70% CO2 Capture x $1, 000

Plant Size: 550.04 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

5A FLUE GAS CLEANUP

5.1 Absorber Vessels & Accessories 75,503 0 16,254 0 91,757 9.5% 8,684 0% 0 10.0% 10,044 110,485 201

5.2 Other FGD 3,943 0 4,468 0 8,411 9.6% 810 0% 0 10.0% 922 10,144 18

5.3 Bag House & Accessories 19,088 0 12,114 0 31,201 9.6% 2,984 0% 0 10.0% 3,419 37,604 68

5.4 Other Particulate Removal Materials 1,248 0 1,336 0 2,584 9.6% 249 0% 0 10.0% 283 3,116 6

5.5 Gypsum Dewatering System 5,096 0 866 0 5,961 9.4% 563 0% 0 10.0% 652 7,177 13

5.6 Mercury Removal System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.7 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.8 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.9 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

SUBTOTAL 5A. $104,877 $0 $35,037 $0 $139,914 $13,291 $0 $15,321 $168,526 $306

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System 152,043 0 46,040 0 198,083 9.5% 18,800 20% 39,617 20.0% 51,300 307,799 560

5B.2 CO2 Compression & Drying 16,816 0 5,252 0 22,068 9.5% 2,095 0% 0 20.0% 4,833 28,996 53

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $168,859 $0 $51,292 $0 $220,151 $20,895 $39,617 $56,132 $336,794 $612

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.2 Combustion Turbine Accessories 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.3 Compressed Air Piping 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7 HRSG, DUCTING & STACK

7.1 Flue Gas Recycle Heat Exchanger N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

7.2 SCR System 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

7.3 Ductwork 9,187 0 5,903 0 15,090 8.7% 1,318 0% 0 15.0% 2,461 18,870 34

7.4 Stack 8,521 0 4,986 0 13,507 9.6% 1,291 0% 0 10.0% 1,480 16,278 30

7.9 HRSG, Duct & Stack Foundations 0 1,008 1,145 0 2,153 9.3% 201 0% 0 20.0% 471 2,825 5

SUBTOTAL 7. $17,708 $1,008 $12,034 $0 $30,751 $2,809 $0 $4,412 $37,972 $69

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories 53,728 0 7,129 0 60,857 9.6% 5,827 0% 0 10.0% 6,668 73,353 133

8.2 Turbine Plant Auxiliaries 362 0 775 0 1,137 9.7% 110 0% 0 10.0% 125 1,372 2

8.3 Condenser & Auxiliaries 5,127 0 1,910 0 7,037 9.5% 669 0% 0 10.0% 771 8,477 15

8.4 Steam Piping 17,763 0 8,758 0 26,521 8.3% 2,213 0% 0 15.0% 4,310 33,045 60

8.9 TG Foundations 0 1,137 1,796 0 2,933 9.4% 276 0% 0 20.0% 642 3,851 7

SUBTOTAL 8. $76,980 $1,137 $20,369 $0 $98,486 $9,095 $0 $12,516 $120,098 $218

9 COOLING WATER SYSTEM

9.1 Cooling Towers 12,077 0 3,761 0 15,838 9.5% 1,504 0% 0 10.0% 1,734 19,076 35

9.2 Circulating Water Pumps 2,101 0 161 0 2,263 8.6% 193 0% 0 10.0% 246 2,702 5

9.3 Circ. Water System Auxiliaries 570 0 76 0 646 9.4% 61 0% 0 10.0% 71 778 1

9.4 Circ. Water Piping 0 4,519 4,380 0 8,899 9.2% 820 0% 0 15.0% 1,458 11,176 20

9.5 Make-up Water System 537 0 718 0 1,255 9.5% 119 0% 0 15.0% 206 1,580 3

9.6 Component Cooling Water System 452 0 359 0 811 9.4% 76 0% 0 15.0% 133 1,020 2

9.9 Circ. Water System Foundations 0 2,746 4,364 0 7,110 9.4% 669 0% 0 20.0% 1,556 9,335 17

SUBTOTAL 9. $15,738 $7,266 $13,818 $0 $36,821 $3,442 $0 $5,403 $45,666 $83

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*
Carbon Dioxide Capture Sensitivity Analysis

164

Exhibit 3-62 Case 1C (70%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1C - Supercritical PC w/ 70% CO2 Capture x $1, 000

Plant Size: 550.04 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Ash Coolers N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.2 Cyclone Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.3 HGCU Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.4 High Temperature Ash Piping N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.5 Other Ash Recovery Equipment N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.6 Ash Storage Silos 661 0 2,035 0 2,696 9.7% 263 0% 0 10.0% 296 3,254 6

10.7 Ash Transport & Feed Equipment 4,275 0 4,380 0 8,655 9.5% 819 0% 0 10.0% 947 10,421 19

10.8 Misc. Ash Handling Equipment 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

10.9 Ash/Spent Sorbent Foundation 0 157 185 0 342 9.3% 32 0% 0 20.0% 75 448 1

SUBTOTAL 10. $4,936 $157 $6,599 $0 $11,692 $1,113 $0 $1,318 $14,123 $26

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment 1,653 0 268 0 1,922 9.3% 178 0% 0 7.5% 157 2,257 4

11.2 Station Service Equipment 4,353 0 1,430 0 5,784 9.6% 553 0% 0 7.5% 475 6,812 12

11.3 Switchgear & Motor Control 5,005 0 851 0 5,856 9.3% 542 0% 0 10.0% 640 7,038 13

11.4 Conduit & Cable Tray 0 3,138 10,850 0 13,988 9.6% 1,339 0% 0 15.0% 2,299 17,626 32

11.5 Wire & Cable 0 5,921 11,430 0 17,351 8.4% 1,462 0% 0 15.0% 2,822 21,635 39

11.6 Protective Equipment 260 0 885 0 1,146 9.8% 112 0% 0 10.0% 126 1,383 3

11.7 Standby Equipment 1,312 0 30 0 1,342 9.5% 127 0% 0 10.0% 147 1,616 3

11.8 Main Power Transformers 7,541 0 127 0 7,668 7.6% 583 0% 0 10.0% 825 9,076 17

11.9 Electrical Foundations 0 324 793 0 1,117 9.5% 106 0% 0 20.0% 245 1,468 3

SUBTOTAL 11. $20,125 $9,383 $26,665 $0 $56,174 $5,002 $0 $7,736 $68,911 $125

12 INSTRUMENTATION & CONTROL

12.1 PC Control Equipment w/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0

12.2 Combustion Turbine Control N/A 0 N/A 0 0 0% 0 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 0.0% 0 0 0

12.4 Other Major Component Control 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

12.5 Signal Processing Equipment W/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0

12.6 Control Boards, Panels & Racks 497 0 298 0 795 9.6% 76 0% 0 15.0% 131 1,002 2

12.7 Computer Accessories 5,019 0 877 0 5,897 9.5% 562 0% 0 10.0% 646 7,104 13

12.8 Instrument Wiring & Tubing 2,721 0 5,397 0 8,118 8.5% 692 0% 0 15.0% 1,321 10,131 18

12.9 Other I & C Equipment 1,418 0 3,219 0 4,637 9.7% 452 0% 0 10.0% 509 5,598 10

SUBTOTAL 12. $9,656 $0 $9,791 $0 $19,447 $1,781 $0 $2,607 $23,835 $43

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 54 1,086 0 1,140 9.9% 112 0% 0 20.0% 251 1,503 3

13.2 Site Improvements 0 1,803 2,239 0 4,042 9.8% 397 0% 0 20.0% 888 5,326 10

13.3 Site Facilities 3,230 0 3,186 0 6,416 9.8% 630 0% 0 20.0% 1,409 8,455 15

SUBTOTAL 13. $3,230 $1,857 $6,510 $0 $11,598 $1,139 $0 $2,547 $15,284 $28

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

165

Exhibit 3-62 Case 1C (70%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 1C - Supercritical PC w/ 70% CO2 Capture x $1, 000

Plant Size: 550.04 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Boiler Building 0 8,786 7,726 0 16,512 9.0% 1,483 0% 0 15.0% 2,699 20,694 38

14.2 Turbine Building 0 12,661 11,800 0 24,462 9.0% 2,203 0% 0 15.0% 4,000 30,664 56

14.3 Administration Building 0 634 671 0 1,305 9.1% 118 0% 0 15.0% 214 1,637 3

14.4 Circulation Water Pumphouse 0 131 104 0 235 8.9% 21 0% 0 15.0% 38 295 1

14.5 Water Treatment Buildings 0 730 666 0 1,396 9.0% 125 0% 0 15.0% 228 1,749 3

14.6 Machine Shop 0 424 285 0 709 8.9% 63 0% 0 15.0% 116 888 2

14.7 Warehouse 0 288 288 0 576 9.0% 52 0% 0 15.0% 94 722 1

14.8 Other Buildings & Structures 0 235 200 0 435 9.0% 39 0% 0 15.0% 71 545 1

14.9 Waste Treating Building & Str. 0 447 1,356 0 1,803 9.4% 170 0% 0 15.0% 296 2,270 4

SUBTOTAL 14. $0 $24,336 $23,097 $0 $47,433 $4,274 $0 $7,756 $59,463 $108

Total Cost $678,613 $50,913 $341,637 $0 $1,071,164 $100,645 $39,617 $167,271 $1,378,696 $2,507

Owner's Costs

Preproduction Costs

6 Months All Labor $9,711 $18

1 Month Maintenance Materials $1,339 $2

1 Month Non-fuel Consumables $1,150 $2

1 Month Waste Disposal $302 $1

25% of 1 Months Fuel Cost at 100% CF $1,832 $3

2% of TPC $27,574 $50

Total $41,909 $76

Inventory Capital

60 day supply of fuel and consumables at 100% CF $16,956 $31

0.5% of TPC (spare parts) $6,893 $13

Total $23,850 $43

Initial Cost for Catalyst and Chemicals $1,770 $3

Land $900 $2

Other Owner's Costs $206,804 $376

Financing Costs $37,225 $68

Total Overnight Costs (TOC) $1,691,155 $3,074.6

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $1,927,917 $3,505

Labor Bare 

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Project Cont.
Carbon Dioxide Capture Sensitivity Analysis

166

Exhibit 3-63 Case 1C Initial and Annual O&M Expenses

Case: Case 1C - Supercritical PC w/ 70% CO2 Capture

Plant Size (MWe): 550.04 Heat Rate (Btu/kWh): 11,151

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 85 CO2 Captured (TPD): 10443

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 11.3 11.3

Foreman 1.0 1.0

Lab Tech's etc. 2.0 2.0

TOTAL Operating Jobs 16.3 16.3

$ $/kW-net

Annual Operating Labor Cost (calc'd) 6,431,885 11.69

Maintenance Labor Cost (calc'd) 9,106,367 16.56

Administrative & Support Labor (calc'd) 3,884,563 7.06

Property Taxes & Insurance $27,573,930 $50.131

TOTAL FIXED OPERATING COSTS $46,996,745 $85.442

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $13,659,550 0.00334

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 6,584 1.08 $0 $2,206,227 0.00054

Chemicals

 MU & WT Chem. (lb) 0 31,873 0.17 $0 $1,681,041 0.00041

 Limestone (ton) 0 635 21.63 $0 $4,262,785 0.00104

 Carbon (Hg Removal) (lb) 0 0 1.05 $0 $0 0.00000

 MEA Solvent (ton) 729 1.05 2249.89 $1,640,437 $731,895 0.00018

 Caustic Soda, NaOH (ton) 52 5.15 433.68 $22,343 $693,202 0.00017

 Sulfuric acid, H2SO4 (ton) 49 4.92 138.78 $6,823 $211,676 0.00005

 Corrosion Inhibitor 0 0 0.00 $100,851 $4,871 0.00000

 Activated C, MEA (lb) 0 1,235 1.05 $0 $402,393 0.00010

 Ammonia, 28% soln (ton) 0 19 129.80 $0 $779,819 0.00019

Subtotal Chemicals $1,770,454 $8,767,682 0.00214

Other

 Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

 SCR Catalyst Replacement (m3)w/equip. 0.42 5,775.94 $0 $759,439 0.00019

 Emission Penalties 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $759,439 0.00019

Waste Disposal

 Spent Mercury Catalyst (lb) 0 0 0.31 $0 $0 0.00000

 Flyash (ton) 0 489 16.23 $0 $2,464,457 0.00060

 Bottom Ash (ton) 0 122 16.23 $0 $616,114 0.00015

Subtotal Solid Waste Disposal $0 $3,080,571 0.00075

By-products & Emissions

 Gypsum (tons) 0 0 0.00 $0 $0 0.00000

 Sulfur (tons) 0 0 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 0.00000

TOTAL VARIABLE OPERATING COSTS $28,473,469 0.00695

Coal FUEL (tons) 189,275 6,309 38.19 $7,227,497 $74,744,361 0.01825

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

167

Exhibit 3-64 Case 1D (85%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1D - Supercritical PC w/ 85% CO2 Capture x $1, 000

Plant Size: 550.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload 3,968 0 1,813 0 5,781 8.9% 516 0% 0 15.0% 945 7,241 13

1.2 Coal Stackout & Reclaim 5,128 0 1,162 0 6,290 8.8% 551 0% 0 15.0% 1,026 7,867 14

1.3 Coal Conveyors & Yd Crus 4,768 0 1,150 0 5,918 8.8% 519 0% 0 15.0% 965 7,402 13

1.4 Other Coal Handling 1,247 0 266 0 1,513 8.7% 132 0% 0 15.0% 247 1,893 3

1.5 Sorbent Receive & Unload 164 0 49 0 213 8.8% 19 0% 0 15.0% 35 266 0

1.6 Sorbent Stackout & Reclaim 2,642 0 484 0 3,126 8.7% 272 0% 0 15.0% 510 3,908 7

1.7 Sorbent Conveyors 943 204 231 0 1,378 8.7% 119 0% 0 15.0% 225 1,721 3

1.8 Other Sorbent Handling 569 133 299 0 1,001 8.8% 89 0% 0 15.0% 163 1,253 2

1.9 Coal & Sorbent Hnd.Foundations 0 4,880 6,156 0 11,035 9.3% 1,032 0% 0 15.0% 1,810 13,877 25

SUBTOTAL 1. $19,429 $5,217 $11,609 $0 $36,255 $3,248 $0 $5,925 $45,429 $83

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying 2,297 0 448 0 2,745 8.7% 239 0% 0 15.0% 448 3,432 6

2.2 Prepared Coal Storage & Feed 5,881 0 1,284 0 7,165 8.7% 627 0% 0 15.0% 1,169 8,960 16

2.3 Slurry Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.4 Misc. Coal Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.5 Sorbent Prep Equipment 4,500 194 935 0 5,629 8.7% 490 0% 0 15.0% 918 7,037 13

2.6 Sorbent Storage & Feed 542 0 208 0 750 8.9% 67 0% 0 15.0% 122 939 2

2.7 Sorbent Injection System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.8 Booster Air Supply System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.9 Coal & Sorbent Feed Foundation 0 575 483 0 1,058 9.2% 97 0% 0 15.0% 173 1,329 2

SUBTOTAL 2. $13,221 $769 $3,356 $0 $17,346 $1,520 $0 $2,830 $21,697 $39

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 21,402 0 6,913 0 28,316 8.8% 2,479 0% 0 15.0% 4,619 35,414 64

3.2 Water Makeup & Pretreating 6,289 0 2,024 0 8,313 9.4% 779 0% 0 20.0% 1,818 10,911 20

3.3 Other Feedwater Subsystems 6,552 0 2,769 0 9,321 8.9% 831 0% 0 15.0% 1,523 11,675 21

3.4 Service Water Systems 1,233 0 671 0 1,904 9.3% 177 0% 0 20.0% 416 2,496 5

3.5 Other Boiler Plant Systems 8,244 0 8,139 0 16,383 9.4% 1,537 0% 0 15.0% 2,688 20,608 37

3.6 FO Supply Sys & Nat Gas 272 0 340 0 612 9.3% 57 0% 0 15.0% 100 770 1

3.7 Waste Treatment Equipment 4,656 0 2,654 0 7,311 9.7% 708 0% 0 20.0% 1,604 9,623 17

3.8 Misc. Power Plant Equipment 2,890 0 883 0 3,773 9.6% 362 0% 0 20.0% 827 4,962 9

SUBTOTAL 3. $51,539 $0 $24,394 $0 $75,933 $6,930 $0 $13,596 $96,459 $175

4 PC BOILER & ACCESSORIES

4.1 PC Boiler 183,083 0 102,728 0 285,811 9.7% 27,684 0.0% 0 10.0% 31,349 344,844 627

4.2 SCR (w/4.1) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.3 Open 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.4 Boiler BoP (w/ID Fans) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.5 Primary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.6 Secondary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.7 Major Component Rigging 0 w/4.1 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.8 PC Foundations 0 w/14.1 w/14.1 0 0 0% 0 0% 0 0.0% 0 0 0

SUBTOTAL 4. $183,083 $0 $102,728 $0 $285,811 $27,684 $0 $31,349 $344,844 $627

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

168

Exhibit 3-64 Case 1D (85%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1D - Supercritical PC w/ 85% CO2 Capture x $1, 000

Plant Size: 550.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

5A FLUE GAS CLEANUP

5.1 Absorber Vessels & Accessories 78,763 0 16,956 0 95,719 9.5% 9,059 0% 0 10.0% 10,478 115,256 210

5.2 Other FGD 4,113 0 4,661 0 8,774 9.6% 845 0% 0 10.0% 962 10,582 19

5.3 Bag House & Accessories 19,975 0 12,676 0 32,651 9.6% 3,123 0% 0 10.0% 3,577 39,351 72

5.4 Other Particulate Removal Materials 1,305 0 1,397 0 2,702 9.6% 260 0% 0 10.0% 296 3,259 6

5.5 Gypsum Dewatering System 5,292 0 899 0 6,191 9.4% 585 0% 0 10.0% 678 7,453 14

5.6 Mercury Removal System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.7 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.8 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.9 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

SUBTOTAL 5A. $109,448 $0 $36,589 $0 $146,037 $13,873 $0 $15,991 $175,901 $320

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System 195,757 0 59,277 0 255,033 9.5% 24,205 20% 51,007 20.0% 66,049 396,294 720

5B.2 CO2 Compression & Drying 26,380 0 8,239 0 34,619 9.5% 3,287 0% 0 20.0% 7,581 45,487 83

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $222,137 $0 $67,516 $0 $289,653 $27,491 $51,007 $73,630 $441,781 $803

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.2 Combustion Turbine Accessories 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.3 Compressed Air Piping 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7 HRSG, DUCTING & STACK

7.1 Flue Gas Recycle Heat Exchanger N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

7.2 SCR System 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

7.3 Ductwork 9,393 0 6,035 0 15,428 8.7% 1,347 0% 0 15.0% 2,516 19,292 35

7.4 Stack 8,465 0 4,953 0 13,418 9.6% 1,282 0% 0 10.0% 1,470 16,171 29

7.9 HRSG, Duct & Stack Foundations 0 1,016 1,154 0 2,170 9.3% 202 0% 0 20.0% 475 2,847 5

SUBTOTAL 7. $17,858 $1,016 $12,143 $0 $31,017 $2,832 $0 $4,461 $38,310 $70

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories 54,723 0 7,262 0 61,984 9.6% 5,935 0% 0 10.0% 6,792 74,711 136

8.2 Turbine Plant Auxiliaries 369 0 789 0 1,158 9.7% 112 0% 0 10.0% 127 1,397 3

8.3 Condenser & Auxiliaries 4,913 0 1,830 0 6,743 9.5% 641 0% 0 10.0% 738 8,122 15

8.4 Steam Piping 18,500 0 9,122 0 27,622 8.3% 2,305 0% 0 15.0% 4,489 34,416 63

8.9 TG Foundations 0 1,158 1,829 0 2,986 9.4% 281 0% 0 20.0% 653 3,921 7

SUBTOTAL 8. $78,504 $1,158 $20,831 $0 $100,493 $9,274 $0 $12,800 $122,567 $223

9 COOLING WATER SYSTEM

9.1 Cooling Towers 13,419 0 4,179 0 17,598 9.5% 1,671 0% 0 10.0% 1,927 21,196 39

9.2 Circulating Water Pumps 2,392 0 183 0 2,575 8.6% 220 0% 0 10.0% 280 3,075 6

9.3 Circ. Water System Auxiliaries 629 0 84 0 712 9.4% 67 0% 0 10.0% 78 858 2

9.4 Circ. Water Piping 0 4,984 4,830 0 9,813 9.2% 904 0% 0 15.0% 1,608 12,325 22

9.5 Make-up Water System 586 0 783 0 1,369 9.5% 130 0% 0 15.0% 225 1,723 3

9.6 Component Cooling Water System 498 0 396 0 894 9.4% 84 0% 0 15.0% 147 1,125 2

9.9 Circ. Water System Foundations 0 3,006 4,776 0 7,782 9.4% 732 0% 0 20.0% 1,703 10,217 19

SUBTOTAL 9. $17,524 $7,990 $15,231 $0 $40,744 $3,808 $0 $5,966 $50,518 $92

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*
Carbon Dioxide Capture Sensitivity Analysis

169

Exhibit 3-64 Case 1D (85%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1D - Supercritical PC w/ 85% CO2 Capture x $1, 000

Plant Size: 550.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Ash Coolers N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.2 Cyclone Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.3 HGCU Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.4 High Temperature Ash Piping N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.5 Other Ash Recovery Equipment N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.6 Ash Storage Silos 682 0 2,102 0 2,785 9.7% 271 0% 0 10.0% 306 3,362 6

10.7 Ash Transport & Feed Equipment 4,417 0 4,525 0 8,942 9.5% 846 0% 0 10.0% 979 10,766 20

10.8 Misc. Ash Handling Equipment 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

10.9 Ash/Spent Sorbent Foundation 0 162 191 0 353 9.3% 33 0% 0 20.0% 77 463 1

SUBTOTAL 10. $5,100 $162 $6,818 $0 $12,080 $1,150 $0 $1,362 $14,591 $27

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment 1,677 0 272 0 1,950 9.3% 181 0% 0 7.5% 160 2,290 4

11.2 Station Service Equipment 4,700 0 1,544 0 6,244 9.6% 597 0% 0 7.5% 513 7,354 13

11.3 Switchgear & Motor Control 5,403 0 918 0 6,322 9.3% 585 0% 0 10.0% 691 7,597 14

11.4 Conduit & Cable Tray 0 3,388 11,713 0 15,101 9.6% 1,445 0% 0 15.0% 2,482 19,028 35

11.5 Wire & Cable 0 6,392 12,339 0 18,731 8.4% 1,578 0% 0 15.0% 3,046 23,356 42

11.6 Protective Equipment 260 0 885 0 1,146 9.8% 112 0% 0 10.0% 126 1,383 3

11.7 Standby Equipment 1,328 0 30 0 1,358 9.5% 129 0% 0 10.0% 149 1,635 3

11.8 Main Power Transformers 7,634 0 129 0 7,762 7.6% 590 0% 0 10.0% 835 9,187 17

11.9 Electrical Foundations 0 329 808 0 1,137 9.5% 108 0% 0 20.0% 249 1,494 3

SUBTOTAL 11. $21,002 $10,109 $28,639 $0 $59,750 $5,325 $0 $8,250 $73,326 $133

12 INSTRUMENTATION & CONTROL

12.1 PC Control Equipment w/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0

12.2 Combustion Turbine Control N/A 0 N/A 0 0 0% 0 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 0.0% 0 0 0

12.4 Other Major Component Control 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

12.5 Signal Processing Equipment W/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0

12.6 Control Boards, Panels & Racks 509 0 305 0 813 9.6% 78 0% 0 15.0% 134 1,025 2

12.7 Computer Accessories 5,134 0 897 0 6,032 9.5% 574 0% 0 10.0% 661 7,267 13

12.8 Instrument Wiring & Tubing 2,783 0 5,521 0 8,305 8.5% 707 0% 0 15.0% 1,352 10,364 19

12.9 Other I & C Equipment 1,451 0 3,292 0 4,743 9.7% 462 0% 0 10.0% 521 5,726 10

SUBTOTAL 12. $9,877 $0 $10,016 $0 $19,893 $1,822 $0 $2,667 $24,382 $44

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 55 1,107 0 1,163 9.9% 115 0% 0 20.0% 255 1,533 3

13.2 Site Improvements 0 1,838 2,283 0 4,121 9.8% 405 0% 0 20.0% 905 5,430 10

13.3 Site Facilities 3,294 0 3,248 0 6,542 9.8% 642 0% 0 20.0% 1,437 8,620 16

SUBTOTAL 13. $3,294 $1,893 $6,638 $0 $11,825 $1,161 $0 $2,597 $15,583 $28

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

170

Exhibit 3-64 Case 1D (85%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 1D - Supercritical PC w/ 85% CO2 Capture x $1, 000

Plant Size: 550.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Boiler Building 0 8,828 7,764 0 16,592 9.0% 1,490 0% 0 15.0% 2,712 20,794 38

14.2 Turbine Building 0 12,760 11,892 0 24,652 9.0% 2,220 0% 0 15.0% 4,031 30,902 56

14.3 Administration Building 0 641 677 0 1,318 9.1% 119 0% 0 15.0% 216 1,653 3

14.4 Circulation Water Pumphouse 0 143 114 0 257 8.9% 23 0% 0 15.0% 42 322 1

14.5 Water Treatment Buildings 0 803 732 0 1,536 9.0% 137 0% 0 15.0% 251 1,924 3

14.6 Machine Shop 0 428 288 0 716 8.9% 64 0% 0 15.0% 117 897 2

14.7 Warehouse 0 290 291 0 582 9.0% 53 0% 0 15.0% 95 729 1

14.8 Other Buildings & Structures 0 237 202 0 439 9.0% 39 0% 0 15.0% 72 550 1

14.9 Waste Treating Building & Str. 0 452 1,370 0 1,822 9.4% 172 0% 0 15.0% 299 2,293 4

SUBTOTAL 14. $0 $24,583 $23,331 $0 $47,914 $4,317 $0 $7,835 $60,065 $109

Total Cost $752,015 $52,896 $369,839 $0 $1,174,751 $110,436 $51,007 $189,260 $1,525,453 $2,773

Owner's Costs

Preproduction Costs

6 Months All Labor $10,262 $19

1 Month Maintenance Materials $1,469 $3

1 Month Non-fuel Consumables $1,299 $2

1 Month Waste Disposal $320 $1

25% of 1 Months Fuel Cost at 100% CF $1,942 $4

2% of TPC $30,509 $55

Total $45,800 $83

Inventory Capital

60 day supply of fuel and consumables at 100% CF $18,132 $33

0.5% of TPC (spare parts) $7,627 $14

Total $25,759 $47

Initial Cost for Catalyst and Chemicals $2,280 $4

Land $900 $2

Other Owner's Costs $228,818 $416

Financing Costs $41,187 $75

Total Overnight Costs (TOC) $1,870,197 $3,400.0

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,132,024 $3,876

Labor Bare 

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Project Cont.
Carbon Dioxide Capture Sensitivity Analysis

171

Exhibit 3-65 Case 1D Initial and Annual O&M Expenses

Case: Case 1D - Supercritical PC w/ 85% CO2 Capture

Plant Size (MWe): 550.05 Heat Rate (Btu/kWh): 11,819

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 85 CO2 Captured (TPD): 13446

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 11.3 11.3

Foreman 1.0 1.0

Lab Tech's etc. 2.0 2.0

TOTAL Operating Jobs 16.3 16.3

$ $/kW-net

Annual Operating Labor Cost (calc'd) 6,431,885 11.69

Maintenance Labor Cost (calc'd) 9,986,997 18.16

Administrative & Support Labor (calc'd) 4,104,721 7.46

Property Taxes & Insurance $30,509,054 $55.466

TOTAL FIXED OPERATING COSTS $51,032,657 $92.778

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $14,980,495 0.00366

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 7,611 1.08 $0 $2,550,103 0.00062

Chemicals

 MU & WT Chem. (lb) 0 36,840 0.17 $0 $1,943,058 0.00047

 Limestone (ton) 0 676 21.63 $0 $4,536,881 0.00111

 Carbon (Hg Removal) (lb) 0 0 1.05 $0 $0 0.00000

 MEA Solvent (ton) 939 1.35 2249.89 $2,112,135 $942,347 0.00023

 Caustic Soda, NaOH (ton) 66 6.63 433.68 $28,768 $892,528 0.00022

 Sulfuric acid, H2SO4 (ton) 63 6.33 138.78 $8,785 $272,542 0.00007

 Corrosion Inhibitor 0 0 0.00 $129,850 $6,271 0.00000

 Activated C, MEA (lb) 0 1,590 1.05 $0 $518,099 0.00013

 Ammonia, 28% soln (ton) 0 21 129.80 $0 $826,568 0.00020

Subtotal Chemicals $2,279,537 $9,938,295 0.00243

Other

 Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

 SCR Catalyst Replacement (m3)w/equip. 0.42 5,775.94 $0 $759,439 0.00019

 Emission Penalties 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $759,439 0.00019

Waste Disposal

 Spent Mercury Catalyst (lb) 0 0 0.31 $0 $0 0.00000

 Flyash (ton) 0 519 16.23 $0 $2,612,200 0.00064

 Bottom Ash (ton) 0 130 16.23 $0 $653,050 0.00016

Subtotal Solid Waste Disposal $0 $3,265,250 0.00080

By-products & Emissions

 Gypsum (tons) 0 0 0.00 $0 $0 0.00000

 Sulfur (tons) 0 0 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 0.00000

TOTAL VARIABLE OPERATING COSTS $31,493,582 0.00769

Coal FUEL (tons) 200,622 6,687 38.19 $7,660,781 $79,225,242 0.01934

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

172

Exhibit 3-66 Case 1E (90%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1E - Supercritical PC w/ 90% CO2 Capture x $1, 000

Plant Size: 550.01 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload 4,023 0 1,837 0 5,860 8.9% 523 0% 0 15.0% 957 7,341 13

1.2 Coal Stackout & Reclaim 5,199 0 1,178 0 6,377 8.8% 558 0% 0 15.0% 1,040 7,975 14

1.3 Coal Conveyors & Yd Crus 4,833 0 1,165 0 5,999 8.8% 526 0% 0 15.0% 979 7,504 14

1.4 Other Coal Handling 1,265 0 270 0 1,534 8.7% 134 0% 0 15.0% 250 1,919 3

1.5 Sorbent Receive & Unload 166 0 50 0 216 8.8% 19 0% 0 15.0% 35 270 0

1.6 Sorbent Stackout & Reclaim 2,680 0 491 0 3,171 8.7% 276 0% 0 15.0% 517 3,965 7

1.7 Sorbent Conveyors 956 207 235 0 1,398 8.7% 121 0% 0 15.0% 228 1,747 3

1.8 Other Sorbent Handling 578 135 303 0 1,016 8.8% 90 0% 0 15.0% 166 1,272 2

1.9 Coal & Sorbent Hnd.Foundations 0 4,947 6,240 0 11,187 9.3% 1,046 0% 0 15.0% 1,835 14,068 26

SUBTOTAL 1. $19,700 $5,289 $11,769 $0 $36,758 $3,293 $0 $6,008 $46,059 $84

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying 2,331 0 454 0 2,785 8.7% 243 0% 0 15.0% 454 3,482 6

2.2 Prepared Coal Storage & Feed 5,967 0 1,303 0 7,270 8.7% 636 0% 0 15.0% 1,186 9,091 17

2.3 Slurry Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.4 Misc. Coal Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.5 Sorbent Prep Equipment 4,567 197 949 0 5,713 8.7% 498 0% 0 15.0% 932 7,142 13

2.6 Sorbent Storage & Feed 550 0 211 0 761 8.9% 68 0% 0 15.0% 124 953 2

2.7 Sorbent Injection System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.8 Booster Air Supply System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.9 Coal & Sorbent Feed Foundation 0 583 490 0 1,073 9.2% 99 0% 0 15.0% 176 1,347 2

SUBTOTAL 2. $13,415 $780 $3,406 $0 $17,601 $1,543 $0 $2,872 $22,015 $40

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 21,729 0 7,019 0 28,748 8.8% 2,517 0% 0 15.0% 4,690 35,954 65

3.2 Water Makeup & Pretreating 6,520 0 2,099 0 8,618 9.4% 808 0% 0 20.0% 1,885 11,311 21

3.3 Other Feedwater Subsystems 6,652 0 2,811 0 9,463 8.9% 843 0% 0 15.0% 1,546 11,853 22

3.4 Service Water Systems 1,278 0 695 0 1,973 9.3% 183 0% 0 20.0% 431 2,588 5

3.5 Other Boiler Plant Systems 8,381 0 8,274 0 16,655 9.4% 1,562 0% 0 15.0% 2,733 20,950 38

3.6 FO Supply Sys & Nat Gas 274 0 342 0 616 9.3% 57 0% 0 15.0% 101 774 1

3.7 Waste Treatment Equipment 4,687 0 2,672 0 7,358 9.7% 713 0% 0 20.0% 1,614 9,685 18

3.8 Misc. Power Plant Equipment 2,906 0 888 0 3,794 9.6% 364 0% 0 20.0% 832 4,989 9

SUBTOTAL 3. $52,425 $0 $24,800 $0 $77,225 $7,048 $0 $13,832 $98,105 $178

4 PC BOILER & ACCESSORIES

4.1 PC Boiler 185,896 0 104,307 0 290,203 9.7% 28,109 0.0% 0 10.0% 31,831 350,144 637

4.2 SCR (w/4.1) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.3 Open 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.4 Boiler BoP (w/ID Fans) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.5 Primary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.6 Secondary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.7 Major Component Rigging 0 w/4.1 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.8 PC Foundations 0 w/14.1 w/14.1 0 0 0% 0 0% 0 0.0% 0 0 0

SUBTOTAL 4. $185,896 $0 $104,307 $0 $290,203 $28,109 $0 $31,831 $350,144 $637

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

173

Exhibit 3-66 Case 1E (90%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1E - Supercritical PC w/ 90% CO2 Capture x $1, 000

Plant Size: 550.01 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

5A FLUE GAS CLEANUP

5.1 Absorber Vessels & Accessories 80,030 0 17,229 0 97,259 9.5% 9,205 0% 0 10.0% 10,646 117,111 213

5.2 Other FGD 4,179 0 4,736 0 8,916 9.6% 859 0% 0 10.0% 977 10,752 20

5.3 Bag House & Accessories 20,320 0 12,896 0 33,216 9.6% 3,177 0% 0 10.0% 3,639 40,032 73

5.4 Other Particulate Removal Materials 1,328 0 1,421 0 2,749 9.6% 265 0% 0 10.0% 301 3,315 6

5.5 Gypsum Dewatering System 5,366 0 911 0 6,278 9.4% 593 0% 0 10.0% 687 7,558 14

5.6 Mercury Removal System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.7 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.8 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.9 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

SUBTOTAL 5A. $111,224 $0 $37,193 $0 $148,417 $14,099 $0 $16,252 $178,767 $325

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System 205,392 0 62,194 0 267,586 9.5% 25,396 20% 53,517 20.0% 69,300 415,800 756

5B.2 CO2 Compression & Drying 27,599 0 8,620 0 36,219 9.5% 3,438 0% 0 20.0% 7,932 47,589 87

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $232,992 $0 $70,814 $0 $303,806 $28,834 $53,517 $77,231 $463,389 $843

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.2 Combustion Turbine Accessories 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.3 Compressed Air Piping 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7 HRSG, DUCTING & STACK

7.1 Flue Gas Recycle Heat Exchanger N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

7.2 SCR System 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

7.3 Ductwork 9,472 0 6,086 0 15,557 8.7% 1,359 0% 0 15.0% 2,537 19,454 35

7.4 Stack 8,445 0 4,942 0 13,387 9.6% 1,279 0% 0 10.0% 1,467 16,132 29

7.9 HRSG, Duct & Stack Foundations 0 1,019 1,158 0 2,177 9.3% 203 0% 0 20.0% 476 2,856 5

SUBTOTAL 7. $17,917 $1,019 $12,185 $0 $31,121 $2,841 $0 $4,480 $38,442 $70

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories 55,108 0 7,313 0 62,421 9.6% 5,977 0% 0 10.0% 6,840 75,238 137

8.2 Turbine Plant Auxiliaries 371 0 795 0 1,166 9.7% 113 0% 0 10.0% 128 1,407 3

8.3 Condenser & Auxiliaries 4,825 0 1,797 0 6,622 9.5% 629 0% 0 10.0% 725 7,977 15

8.4 Steam Piping 18,786 0 9,263 0 28,049 8.3% 2,341 0% 0 15.0% 4,559 34,949 64

8.9 TG Foundations 0 1,165 1,841 0 3,007 9.4% 283 0% 0 20.0% 658 3,947 7

SUBTOTAL 8. $79,091 $1,165 $21,009 $0 $101,265 $9,343 $0 $12,909 $123,517 $225

9 COOLING WATER SYSTEM

9.1 Cooling Towers 13,922 0 4,335 0 18,257 9.5% 1,733 0% 0 10.0% 1,999 21,989 40

9.2 Circulating Water Pumps 2,502 0 192 0 2,694 8.6% 230 0% 0 10.0% 292 3,217 6

9.3 Circ. Water System Auxiliaries 650 0 87 0 737 9.4% 70 0% 0 10.0% 81 887 2

9.4 Circ. Water Piping 0 5,157 4,998 0 10,154 9.2% 935 0% 0 15.0% 1,663 12,753 23

9.5 Make-up Water System 604 0 807 0 1,411 9.5% 134 0% 0 15.0% 232 1,776 3

9.6 Component Cooling Water System 515 0 410 0 925 9.4% 87 0% 0 15.0% 152 1,164 2

9.9 Circ. Water System Foundations 0 3,102 4,929 0 8,031 9.4% 756 0% 0 20.0% 1,757 10,544 19

SUBTOTAL 9. $18,194 $8,259 $15,757 $0 $42,210 $3,945 $0 $6,176 $52,331 $95

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*
Carbon Dioxide Capture Sensitivity Analysis

174

Exhibit 3-66 Case 1E (90%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1E - Supercritical PC w/ 90% CO2 Capture x $1, 000

Plant Size: 550.01 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Ash Coolers N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.2 Cyclone Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.3 HGCU Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.4 High Temperature Ash Piping N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.5 Other Ash Recovery Equipment N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.6 Ash Storage Silos 691 0 2,129 0 2,819 9.7% 275 0% 0 10.0% 309 3,403 6

10.7 Ash Transport & Feed Equipment 4,472 0 4,581 0 9,053 9.5% 856 0% 0 10.0% 991 10,900 20

10.8 Misc. Ash Handling Equipment 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

10.9 Ash/Spent Sorbent Foundation 0 164 193 0 357 9.3% 33 0% 0 20.0% 78 469 1

SUBTOTAL 10. $5,163 $164 $6,903 $0 $12,230 $1,164 $0 $1,378 $14,772 $27

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment 1,687 0 274 0 1,961 9.3% 182 0% 0 7.5% 161 2,303 4

11.2 Station Service Equipment 4,824 0 1,585 0 6,410 9.6% 613 0% 0 7.5% 527 7,549 14

11.3 Switchgear & Motor Control 5,547 0 943 0 6,489 9.3% 601 0% 0 10.0% 709 7,799 14

11.4 Conduit & Cable Tray 0 3,477 12,024 0 15,501 9.6% 1,484 0% 0 15.0% 2,548 19,533 36

11.5 Wire & Cable 0 6,562 12,667 0 19,229 8.4% 1,620 0% 0 15.0% 3,127 23,976 44

11.6 Protective Equipment 260 0 885 0 1,146 9.8% 112 0% 0 10.0% 126 1,383 3

11.7 Standby Equipment 1,334 0 30 0 1,364 9.5% 129 0% 0 10.0% 149 1,643 3

11.8 Main Power Transformers 7,634 0 129 0 7,762 7.6% 590 0% 0 10.0% 835 9,187 17

11.9 Electrical Foundations 0 332 813 0 1,145 9.5% 109 0% 0 20.0% 251 1,504 3

SUBTOTAL 11. $21,286 $10,371 $29,350 $0 $61,006 $5,439 $0 $8,432 $74,877 $136

12 INSTRUMENTATION & CONTROL

12.1 PC Control Equipment w/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0

12.2 Combustion Turbine Control N/A 0 N/A 0 0 0% 0 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 0.0% 0 0 0

12.4 Other Major Component Control 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

12.5 Signal Processing Equipment W/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0

12.6 Control Boards, Panels & Racks 513 0 307 0 820 9.6% 79 0% 0 15.0% 135 1,033 2

12.7 Computer Accessories 5,174 0 904 0 6,079 9.5% 579 0% 0 10.0% 666 7,323 13

12.8 Instrument Wiring & Tubing 2,805 0 5,564 0 8,369 8.5% 713 0% 0 15.0% 1,362 10,444 19

12.9 Other I & C Equipment 1,462 0 3,318 0 4,780 9.7% 466 0% 0 10.0% 525 5,770 10

SUBTOTAL 12. $9,954 $0 $10,094 $0 $20,048 $1,836 $0 $2,687 $24,571 $45

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 56 1,112 0 1,168 9.9% 115 0% 0 20.0% 257 1,540 3

13.2 Site Improvements 0 1,847 2,294 0 4,140 9.8% 407 0% 0 20.0% 909 5,456 10

13.3 Site Facilities 3,309 0 3,264 0 6,573 9.8% 645 0% 0 20.0% 1,444 8,662 16

SUBTOTAL 13. $3,309 $1,902 $6,669 $0 $11,881 $1,167 $0 $2,610 $15,658 $28

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

175

Exhibit 3-66 Case 1E (90%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 1E - Supercritical PC w/ 90% CO2 Capture x $1, 000

Plant Size: 550.01 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Boiler Building 0 8,839 7,773 0 16,612 9.0% 1,492 0% 0 15.0% 2,716 20,819 38

14.2 Turbine Building 0 12,784 11,915 0 24,699 9.0% 2,224 0% 0 15.0% 4,038 30,961 56

14.3 Administration Building 0 642 679 0 1,321 9.1% 120 0% 0 15.0% 216 1,657 3

14.4 Circulation Water Pumphouse 0 148 118 0 266 8.9% 24 0% 0 15.0% 43 333 1

14.5 Water Treatment Buildings 0 831 757 0 1,588 9.0% 142 0% 0 15.0% 260 1,990 4

14.6 Machine Shop 0 429 289 0 718 8.9% 64 0% 0 15.0% 117 899 2

14.7 Warehouse 0 291 292 0 583 9.0% 53 0% 0 15.0% 95 731 1

14.8 Other Buildings & Structures 0 238 202 0 440 9.0% 39 0% 0 15.0% 72 552 1

14.9 Waste Treating Building & Str. 0 453 1,375 0 1,828 9.4% 173 0% 0 15.0% 300 2,301 4

SUBTOTAL 14. $0 $24,655 $23,400 $0 $48,055 $4,330 $0 $7,858 $60,242 $110

Total Cost $770,565 $53,605 $377,655 $0 $1,201,825 $112,991 $53,517 $194,556 $1,562,889 $2,842

Owner's Costs

Preproduction Costs

6 Months All Labor $10,406 $19

1 Month Maintenance Materials $1,503 $3

1 Month Non-fuel Consumables $1,356 $2

1 Month Waste Disposal $327 $1

25% of 1 Months Fuel Cost at 100% CF $1,985 $4

2% of TPC $31,258 $57

Total $46,834 $85

Inventory Capital

60 day supply of fuel and consumables at 100% CF $18,592 $34

0.5% of TPC (spare parts) $7,814 $14

Total $26,406 $48

Initial Cost for Catalyst and Chemicals $2,477 $5

Land $900 $2

Other Owner's Costs $234,433 $426

Financing Costs $42,198 $77

Total Overnight Costs (TOC) $1,916,138 $3,483.8

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,184,397 $3,972

Labor Bare 

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Project Cont.
Carbon Dioxide Capture Sensitivity Analysis

176

Exhibit 3-67 Case 1E Initial and Annual O&M Expenses

Case: Case 1E - Supercritical PC w/ 90% CO2 Capture

Plant Size (MWe): 550.01 Heat Rate (Btu/kWh): 12,083

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 85 CO2 Captured (TPD): 14609

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 11.3 11.3

Foreman 1.0 1.0

Lab Tech's etc. 2.0 2.0

TOTAL Operating Jobs 16.3 16.3

$ $/kW-net

Annual Operating Labor Cost (calc'd) 6,431,885 11.69

Maintenance Labor Cost (calc'd) 10,217,164 18.58

Administrative & Support Labor (calc'd) 4,162,262 7.57

Property Taxes & Insurance $31,257,786 $56.831

TOTAL FIXED OPERATING COSTS $52,069,097 $94.669

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $15,325,746 0.00374

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 8,007 1.08 $0 $2,682,853 0.00066

Chemicals

 MU & WT Chem. (lb) 0 38,758 0.17 $0 $2,044,208 0.00050

 Limestone (ton) 0 692 21.63 $0 $4,640,812 0.00113

 Carbon (Hg Removal) (lb) 0 0 1.05 $0 $0 0.00000

 MEA Solvent (ton) 1,020 1.47 2249.89 $2,294,818 $1,023,853 0.00025

 Caustic Soda, NaOH (ton) 72 7.21 433.68 $31,256 $969,725 0.00024

 Sulfuric acid, H2SO4 (ton) 69 6.88 138.78 $9,544 $296,115 0.00007

 Corrosion Inhibitor 0 0 0.00 $141,081 $6,814 0.00000

 Activated C, MEA (lb) 0 1,728 1.05 $0 $562,910 0.00014

 Ammonia, 28% soln (ton) 0 21 129.80 $0 $844,943 0.00021

Subtotal Chemicals $2,476,699 $10,389,380 0.00254

Other

 Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

 SCR Catalyst Replacement (m3)w/equip. 0.42 5,775.94 $0 $759,439 0.00019

 Emission Penalties 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $759,439 0.00019

Waste Disposal

 Spent Mercury Catalyst (lb) 0 0 0.31 $0 $0 0.00000

 Flyash (ton) 0 530 16.23 $0 $2,670,269 0.00065

 Bottom Ash (ton) 0 133 16.23 $0 $667,567 0.00016

Subtotal Solid Waste Disposal $0 $3,337,836 0.00082

By-products & Emissions

 Gypsum (tons) 0 0 0.00 $0 $0 0.00000

 Sulfur (tons) 0 0 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 0.00000

TOTAL VARIABLE OPERATING COSTS $32,495,254 0.00793

Coal FUEL (tons) 205,082 6,836 38.19 $7,831,079 $80,986,412 0.01978

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

177

Exhibit 3-68 Case 1F (95%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1F - Supercritical PC w/ 95% CO2 Capture x $1, 000

Plant Size: 549.96 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload 4,088 0 1,867 0 5,955 8.9% 532 0% 0 15.0% 973 7,459 14

1.2 Coal Stackout & Reclaim 5,283 0 1,197 0 6,480 8.8% 567 0% 0 15.0% 1,057 8,104 15

1.3 Coal Conveyors & Yd Crus 4,911 0 1,184 0 6,096 8.8% 534 0% 0 15.0% 995 7,625 14

1.4 Other Coal Handling 1,285 0 274 0 1,559 8.7% 136 0% 0 15.0% 254 1,950 4

1.5 Sorbent Receive & Unload 169 0 51 0 220 8.8% 19 0% 0 15.0% 36 275 0

1.6 Sorbent Stackout & Reclaim 2,726 0 500 0 3,226 8.7% 281 0% 0 15.0% 526 4,033 7

1.7 Sorbent Conveyors 973 210 239 0 1,422 8.7% 123 0% 0 15.0% 232 1,777 3

1.8 Other Sorbent Handling 588 138 308 0 1,033 8.8% 91 0% 0 15.0% 169 1,294 2

1.9 Coal & Sorbent Hnd.Foundations 0 5,027 6,341 0 11,368 9.3% 1,063 0% 0 15.0% 1,865 14,295 26

SUBTOTAL 1. $20,022 $5,375 $11,961 $0 $37,358 $3,347 $0 $6,106 $46,810 $85

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying 2,371 0 462 0 2,833 8.7% 247 0% 0 15.0% 462 3,542 6

2.2 Prepared Coal Storage & Feed 6,070 0 1,325 0 7,395 8.7% 647 0% 0 15.0% 1,206 9,248 17

2.3 Slurry Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.4 Misc. Coal Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.5 Sorbent Prep Equipment 4,647 200 965 0 5,812 8.7% 506 0% 0 15.0% 948 7,266 13

2.6 Sorbent Storage & Feed 560 0 214 0 774 8.9% 69 0% 0 15.0% 126 969 2

2.7 Sorbent Injection System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.8 Booster Air Supply System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.9 Coal & Sorbent Feed Foundation 0 593 498 0 1,091 9.2% 100 0% 0 15.0% 179 1,370 2

SUBTOTAL 2. $13,647 $793 $3,464 $0 $17,904 $1,569 $0 $2,921 $22,394 $41

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 22,119 0 7,145 0 29,263 8.8% 2,562 0% 0 15.0% 4,774 36,599 67

3.2 Water Makeup & Pretreating 6,704 0 2,158 0 8,862 9.4% 831 0% 0 20.0% 1,939 11,631 21

3.3 Other Feedwater Subsystems 6,771 0 2,862 0 9,633 8.9% 859 0% 0 15.0% 1,574 12,065 22

3.4 Service Water Systems 1,314 0 715 0 2,029 9.3% 188 0% 0 20.0% 444 2,661 5

3.5 Other Boiler Plant Systems 8,544 0 8,436 0 16,980 9.4% 1,593 0% 0 15.0% 2,786 21,359 39

3.6 FO Supply Sys & Nat Gas 275 0 344 0 620 9.3% 58 0% 0 15.0% 102 779 1

3.7 Waste Treatment Equipment 4,723 0 2,692 0 7,415 9.7% 718 0% 0 20.0% 1,627 9,760 18

3.8 Misc. Power Plant Equipment 2,925 0 893 0 3,818 9.6% 367 0% 0 20.0% 837 5,022 9

SUBTOTAL 3. $53,376 $0 $25,245 $0 $78,621 $7,175 $0 $14,081 $99,877 $182

4 PC BOILER & ACCESSORIES

4.1 PC Boiler 189,257 0 106,193 0 295,450 9.7% 28,617 0.0% 0 10.0% 32,407 356,474 648

4.2 SCR (w/4.1) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.3 Open 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.4 Boiler BoP (w/ID Fans) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.5 Primary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.6 Secondary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.7 Major Component Rigging 0 w/4.1 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.8 PC Foundations 0 w/14.1 w/14.1 0 0 0% 0 0% 0 0.0% 0 0 0

SUBTOTAL 4. $189,257 $0 $106,193 $0 $295,450 $28,617 $0 $32,407 $356,474 $648

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

178

Exhibit 3-68 Case 1F (95%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1F - Supercritical PC w/ 95% CO2 Capture x $1, 000

Plant Size: 549.96 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

5A FLUE GAS CLEANUP

5.1 Absorber Vessels & Accessories 81,546 0 17,555 0 99,101 9.5% 9,379 0% 0 10.0% 10,848 119,328 217

5.2 Other FGD 4,259 0 4,826 0 9,084 9.6% 875 0% 0 10.0% 996 10,955 20

5.3 Bag House & Accessories 20,734 0 13,158 0 33,892 9.6% 3,242 0% 0 10.0% 3,713 40,847 74

5.4 Other Particulate Removal Materials 1,354 0 1,449 0 2,804 9.6% 270 0% 0 10.0% 307 3,381 6

5.5 Gypsum Dewatering System 5,455 0 926 0 6,381 9.4% 603 0% 0 10.0% 698 7,683 14

5.6 Mercury Removal System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.7 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.8 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.9 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

SUBTOTAL 5A. $113,347 $0 $37,915 $0 $151,262 $14,369 $0 $16,563 $182,194 $331

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System 215,143 0 65,147 0 280,290 9.5% 26,602 20% 56,058 20.0% 72,590 435,539 792

5B.2 CO2 Compression & Drying 28,843 0 9,008 0 37,852 9.5% 3,593 0% 0 20.0% 8,289 49,734 90

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $243,986 $0 $74,155 $0 $318,141 $30,195 $56,058 $80,879 $485,273 $882

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.2 Combustion Turbine Accessories 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.3 Compressed Air Piping 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7 HRSG, DUCTING & STACK

7.1 Flue Gas Recycle Heat Exchanger N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

7.2 SCR System 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

7.3 Ductwork 9,565 0 6,146 0 15,711 8.7% 1,372 0% 0 15.0% 2,562 19,646 36

7.4 Stack 8,512 0 4,981 0 13,494 9.6% 1,289 0% 0 10.0% 1,478 16,261 30

7.9 HRSG, Duct & Stack Foundations 0 1,023 1,162 0 2,184 9.3% 204 0% 0 20.0% 478 2,866 5

SUBTOTAL 7. $18,078 $1,023 $12,289 $0 $31,389 $2,865 $0 $4,518 $38,773 $71

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories 55,493 0 7,364 0 62,857 9.6% 6,018 0% 0 10.0% 6,887 75,762 138

8.2 Turbine Plant Auxiliaries 374 0 800 0 1,174 9.7% 114 0% 0 10.0% 129 1,417 3

8.3 Condenser & Auxiliaries 4,692 0 1,748 0 6,440 9.5% 612 0% 0 10.0% 705 7,757 14

8.4 Steam Piping 19,128 0 9,432 0 28,560 8.3% 2,384 0% 0 15.0% 4,641 35,585 65

8.9 TG Foundations 0 1,173 1,854 0 3,027 9.4% 285 0% 0 20.0% 662 3,974 7

SUBTOTAL 8. $79,687 $1,173 $21,197 $0 $102,058 $9,413 $0 $13,025 $124,496 $226

9 COOLING WATER SYSTEM

9.1 Cooling Towers 14,317 0 4,458 0 18,776 9.5% 1,782 0% 0 10.0% 2,056 22,614 41

9.2 Circulating Water Pumps 2,590 0 199 0 2,789 8.6% 238 0% 0 10.0% 303 3,330 6

9.3 Circ. Water System Auxiliaries 668 0 89 0 757 9.4% 71 0% 0 10.0% 83 911 2

9.4 Circ. Water Piping 0 5,292 5,129 0 10,422 9.2% 960 0% 0 15.0% 1,707 13,089 24

9.5 Make-up Water System 618 0 826 0 1,445 9.5% 137 0% 0 15.0% 237 1,819 3

9.6 Component Cooling Water System 529 0 421 0 950 9.4% 89 0% 0 15.0% 156 1,194 2

9.9 Circ. Water System Foundations 0 3,178 5,049 0 8,226 9.4% 774 0% 0 20.0% 1,800 10,800 20

SUBTOTAL 9. $18,722 $8,470 $16,171 $0 $43,363 $4,053 $0 $6,342 $53,757 $98

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*
Carbon Dioxide Capture Sensitivity Analysis

179

Exhibit 3-68 Case 1F (95%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1F - Supercritical PC w/ 95% CO2 Capture x $1, 000

Plant Size: 549.96 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Ash Coolers N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.2 Cyclone Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.3 HGCU Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.4 High Temperature Ash Piping N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.5 Other Ash Recovery Equipment N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.6 Ash Storage Silos 701 0 2,160 0 2,860 9.7% 279 0% 0 10.0% 314 3,453 6

10.7 Ash Transport & Feed Equipment 4,537 0 4,648 0 9,185 9.5% 869 0% 0 10.0% 1,005 11,058 20

10.8 Misc. Ash Handling Equipment 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

10.9 Ash/Spent Sorbent Foundation 0 167 196 0 363 9.3% 34 0% 0 20.0% 79 476 1

SUBTOTAL 10. $5,238 $167 $7,003 $0 $12,408 $1,181 $0 $1,399 $14,987 $27

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment 1,696 0 275 0 1,971 9.3% 183 0% 0 7.5% 162 2,315 4

11.2 Station Service Equipment 4,947 0 1,625 0 6,573 9.6% 629 0% 0 7.5% 540 7,741 14

11.3 Switchgear & Motor Control 5,688 0 967 0 6,654 9.3% 616 0% 0 10.0% 727 7,997 15

11.4 Conduit & Cable Tray 0 3,566 12,329 0 15,895 9.6% 1,521 0% 0 15.0% 2,612 20,029 36

11.5 Wire & Cable 0 6,728 12,989 0 19,717 8.4% 1,661 0% 0 15.0% 3,207 24,585 45

11.6 Protective Equipment 260 0 885 0 1,146 9.8% 112 0% 0 10.0% 126 1,383 3

11.7 Standby Equipment 1,340 0 31 0 1,370 9.5% 130 0% 0 10.0% 150 1,650 3

11.8 Main Power Transformers 7,680 0 129 0 7,809 7.6% 593 0% 0 10.0% 840 9,243 17

11.9 Electrical Foundations 0 334 819 0 1,152 9.5% 110 0% 0 20.0% 252 1,514 3

SUBTOTAL 11. $21,610 $10,628 $30,050 $0 $62,288 $5,554 $0 $8,616 $76,459 $139

12 INSTRUMENTATION & CONTROL

12.1 PC Control Equipment w/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0

12.2 Combustion Turbine Control N/A 0 N/A 0 0 0% 0 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 0.0% 0 0 0

12.4 Other Major Component Control 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

12.5 Signal Processing Equipment W/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0

12.6 Control Boards, Panels & Racks 516 0 309 0 826 9.6% 79 0% 0 15.0% 136 1,041 2

12.7 Computer Accessories 5,213 0 911 0 6,124 9.5% 583 0% 0 10.0% 671 7,378 13

12.8 Instrument Wiring & Tubing 2,826 0 5,606 0 8,432 8.5% 718 0% 0 15.0% 1,372 10,522 19

12.9 Other I & C Equipment 1,473 0 3,343 0 4,816 9.7% 469 0% 0 10.0% 528 5,813 11

SUBTOTAL 12. $10,028 $0 $10,169 $0 $20,197 $1,850 $0 $2,707 $24,755 $45

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 56 1,118 0 1,174 9.9% 116 0% 0 20.0% 258 1,547 3

13.2 Site Improvements 0 1,856 2,305 0 4,161 9.8% 409 0% 0 20.0% 914 5,483 10

13.3 Site Facilities 3,326 0 3,280 0 6,605 9.8% 648 0% 0 20.0% 1,451 8,704 16

SUBTOTAL 13. $3,326 $1,912 $6,702 $0 $11,940 $1,173 $0 $2,623 $15,735 $29

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

180

Exhibit 3-68 Case 1F (95%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 1F - Supercritical PC w/ 95% CO2 Capture x $1, 000

Plant Size: 549.96 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Boiler Building 0 8,850 7,783 0 16,632 9.0% 1,494 0% 0 15.0% 2,719 20,845 38

14.2 Turbine Building 0 12,809 11,938 0 24,748 9.0% 2,228 0% 0 15.0% 4,046 31,022 56

14.3 Administration Building 0 644 681 0 1,324 9.1% 120 0% 0 15.0% 217 1,661 3

14.4 Circulation Water Pumphouse 0 152 120 0 272 8.9% 24 0% 0 15.0% 44 341 1

14.5 Water Treatment Buildings 0 852 777 0 1,630 9.0% 146 0% 0 15.0% 266 2,042 4

14.6 Machine Shop 0 431 289 0 720 8.9% 64 0% 0 15.0% 118 901 2

14.7 Warehouse 0 292 293 0 584 9.0% 53 0% 0 15.0% 96 733 1

14.8 Other Buildings & Structures 0 238 203 0 441 9.0% 40 0% 0 15.0% 72 553 1

14.9 Waste Treating Building & Str. 0 454 1,379 0 1,833 9.4% 173 0% 0 15.0% 301 2,307 4

SUBTOTAL 14. $0 $24,722 $23,463 $0 $48,185 $4,342 $0 $7,879 $60,405 $110

Total Cost $790,324 $54,263 $385,976 $0 $1,230,563 $115,703 $56,058 $200,065 $1,602,389 $2,914

Owner's Costs

Preproduction Costs

6 Months All Labor $10,558 $19

1 Month Maintenance Materials $1,538 $3

1 Month Non-fuel Consumables $1,412 $3

1 Month Waste Disposal $336 $1

25% of 1 Months Fuel Cost at 100% CF $2,037 $4

2% of TPC $32,048 $58

Total $47,930 $87

Inventory Capital

60 day supply of fuel and consumables at 100% CF $19,120 $35

0.5% of TPC (spare parts) $8,012 $15

Total $27,132 $49

Initial Cost for Catalyst and Chemicals $2,683 $5

Land $900 $2

Other Owner's Costs $240,358 $437

Financing Costs $43,265 $79

Total Overnight Costs (TOC) $1,964,657 $3,572.4

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,239,708 $4,072

Labor Bare 

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Project Cont.
Carbon Dioxide Capture Sensitivity Analysis

181

Exhibit 3-69 Case 1F Initial and Annual O&M Expenses

Case: Case 1F - Supercritical PC w/ 95% CO2 Capture

Plant Size (MWe): 549.96 Heat Rate (Btu/kWh): 12,400

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 85 CO2 Captured (TPD): 15824

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 11.3 11.3

Foreman 1.0 1.0

Lab Tech's etc. 2.0 2.0

TOTAL Operating Jobs 16.3 16.3

$ $/kW-net

Annual Operating Labor Cost (calc'd) 6,431,885 11.70

Maintenance Labor Cost (calc'd) 10,461,480 19.02

Administrative & Support Labor (calc'd) 4,223,341 7.68

Property Taxes & Insurance $32,047,789 $58.273

TOTAL FIXED OPERATING COSTS $53,164,496 $96.670

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $15,692,221 0.00383

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 8,328 1.08 $0 $2,790,368 0.00068

Chemicals

 MU & WT Chem. (lb) 0 40,311 0.17 $0 $2,126,129 0.00052

 Limestone (ton) 0 710 21.63 $0 $4,765,707 0.00116

 Carbon (Hg Removal) (lb) 0 0 1.05 $0 $0 0.00000

 MEA Solvent (ton) 1,105 1.59 2249.89 $2,485,693 $1,109,014 0.00027

 Caustic Soda, NaOH (ton) 78 7.81 433.68 $33,856 $1,050,384 0.00026

 Sulfuric acid, H2SO4 (ton) 74 7.45 138.78 $10,338 $320,744 0.00008

 Corrosion Inhibitor 0 0 0.00 $152,815 $7,380 0.00000

 Activated C, MEA (lb) 0 1,872 1.05 $0 $609,731 0.00015

 Ammonia, 28% soln (ton) 0 22 129.80 $0 $867,053 0.00021

Subtotal Chemicals $2,682,703 $10,856,142 0.00265

Other

 Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

 SCR Catalyst Replacement (m3)w/equip. 0.42 5,775.94 $0 $759,439 0.00019

 Emission Penalties 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $759,439 0.00019

Waste Disposal

 Spent Mercury Catalyst (lb) 0 0 0.31 $0 $0 0.00000

 Flyash (ton) 0 544 16.23 $0 $2,740,142 0.00067

 Bottom Ash (ton) 0 136 16.23 $0 $685,035 0.00017

Subtotal Solid Waste Disposal $0 $3,425,177 0.00084

By-products & Emissions

 Gypsum (tons) 0 0 0.00 $0 $0 0.00000

 Sulfur (tons) 0 0 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 0.00000

TOTAL VARIABLE OPERATING COSTS $33,523,348 0.00819

Coal FUEL (tons) 210,448 7,015 38.19 $8,035,996 $83,105,597 0.02029

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

182

Exhibit 3-70 Case 1G (99%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1G - Supercritical PC w/ 99% CO2 Capture x $1, 000

Plant Size: 549.97 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload 4,263 0 1,947 0 6,210 8.9% 555 0% 0 15.0% 1,015 7,779 14

1.2 Coal Stackout & Reclaim 5,509 0 1,248 0 6,758 8.8% 592 0% 0 15.0% 1,102 8,451 15

1.3 Coal Conveyors & Yd Crus 5,122 0 1,235 0 6,357 8.8% 557 0% 0 15.0% 1,037 7,952 14

1.4 Other Coal Handling 1,340 0 286 0 1,626 8.7% 142 0% 0 15.0% 265 2,033 4

1.5 Sorbent Receive & Unload 176 0 53 0 229 8.8% 20 0% 0 15.0% 37 287 1

1.6 Sorbent Stackout & Reclaim 2,841 0 521 0 3,362 8.7% 293 0% 0 15.0% 548 4,203 8

1.7 Sorbent Conveyors 1,014 219 249 0 1,482 8.7% 128 0% 0 15.0% 242 1,852 3

1.8 Other Sorbent Handling 612 144 321 0 1,077 8.8% 95 0% 0 15.0% 176 1,348 2

1.9 Coal & Sorbent Hnd.Foundations 0 5,242 6,612 0 11,854 9.3% 1,108 0% 0 15.0% 1,944 14,906 27

SUBTOTAL 1. $20,878 $5,604 $12,472 $0 $38,954 $3,490 $0 $6,367 $48,811 $89

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying 2,479 0 483 0 2,962 8.7% 258 0% 0 15.0% 483 3,704 7

2.2 Prepared Coal Storage & Feed 6,347 0 1,385 0 7,733 8.7% 676 0% 0 15.0% 1,261 9,670 18

2.3 Slurry Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.4 Misc. Coal Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.5 Sorbent Prep Equipment 4,846 209 1,006 0 6,061 8.7% 528 0% 0 15.0% 988 7,578 14

2.6 Sorbent Storage & Feed 584 0 224 0 807 8.9% 72 0% 0 15.0% 132 1,011 2

2.7 Sorbent Injection System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.8 Booster Air Supply System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

2.9 Coal & Sorbent Feed Foundation 0 619 520 0 1,139 9.2% 105 0% 0 15.0% 187 1,430 3

SUBTOTAL 2. $14,256 $828 $3,618 $0 $18,702 $1,639 $0 $3,051 $23,393 $43

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 23,175 0 7,486 0 30,661 8.8% 2,685 0% 0 15.0% 5,002 38,347 70

3.2 Water Makeup & Pretreating 7,202 0 2,318 0 9,520 9.4% 892 0% 0 20.0% 2,083 12,495 23

3.3 Other Feedwater Subsystems 7,095 0 2,998 0 10,093 8.9% 900 0% 0 15.0% 1,649 12,642 23

3.4 Service Water Systems 1,412 0 768 0 2,180 9.3% 202 0% 0 20.0% 476 2,859 5

3.5 Other Boiler Plant Systems 8,989 0 8,875 0 17,863 9.4% 1,676 0% 0 15.0% 2,931 22,470 41

3.6 FO Supply Sys & Nat Gas 280 0 350 0 630 9.3% 59 0% 0 15.0% 103 792 1

3.7 Waste Treatment Equipment 4,817 0 2,746 0 7,563 9.7% 733 0% 0 20.0% 1,659 9,954 18

3.8 Misc. Power Plant Equipment 2,975 0 909 0 3,883 9.6% 373 0% 0 20.0% 851 5,108 9

SUBTOTAL 3. $55,944 $0 $26,450 $0 $82,394 $7,519 $0 $14,754 $104,667 $190

4 PC BOILER & ACCESSORIES

4.1 PC Boiler 198,367 0 111,304 0 309,671 9.7% 29,995 0.0% 0 10.0% 33,967 373,632 679

4.2 SCR (w/4.1) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.3 Open 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.4 Boiler BoP (w/ID Fans) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

4.5 Primary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.6 Secondary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.7 Major Component Rigging 0 w/4.1 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0

4.8 PC Foundations 0 w/14.1 w/14.1 0 0 0% 0 0% 0 0.0% 0 0 0

SUBTOTAL 4. $198,367 $0 $111,304 $0 $309,671 $29,995 $0 $33,967 $373,632 $679

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

183

Exhibit 3-70 Case 1G (99%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1G - Supercritical PC w/ 99% CO2 Capture x $1, 000

Plant Size: 549.97 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

5A FLUE GAS CLEANUP

5.1 Absorber Vessels & Accessories 85,658 0 18,440 0 104,098 9.5% 9,852 0% 0 10.0% 11,395 125,346 228

5.2 Other FGD 4,473 0 5,069 0 9,542 9.6% 919 0% 0 10.0% 1,046 11,508 21

5.3 Bag House & Accessories 21,859 0 13,872 0 35,731 9.6% 3,418 0% 0 10.0% 3,915 43,064 78

5.4 Other Particulate Removal Materials 1,427 0 1,527 0 2,954 9.6% 284 0% 0 10.0% 324 3,562 6

5.5 Gypsum Dewatering System 5,682 0 965 0 6,647 9.4% 628 0% 0 10.0% 728 8,003 15

5.6 Mercury Removal System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.7 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.8 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

5.9 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

SUBTOTAL 5A. $119,099 $0 $39,874 $0 $158,973 $15,102 $0 $17,407 $191,482 $348

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System 229,196 0 69,402 0 298,598 9.5% 28,339 20% 59,720 20.0% 77,331 463,988 844

5B.2 CO2 Compression & Drying 30,626 0 9,565 0 40,192 9.5% 3,816 0% 0 20.0% 8,801 52,809 96

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $259,822 $0 $78,967 $0 $338,790 $32,155 $59,720 $86,133 $516,797 $940

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.2 Combustion Turbine Accessories 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.3 Compressed Air Piping 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7 HRSG, DUCTING & STACK

7.1 Flue Gas Recycle Heat Exchanger N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

7.2 SCR System 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

7.3 Ductwork 9,815 0 6,306 0 16,121 8.7% 1,408 0% 0 15.0% 2,629 20,158 37

7.4 Stack 8,763 0 5,128 0 13,891 9.6% 1,327 0% 0 10.0% 1,522 16,740 30

7.9 HRSG, Duct & Stack Foundations 0 1,032 1,173 0 2,205 9.3% 205 0% 0 20.0% 482 2,892 5

SUBTOTAL 7. $18,578 $1,032 $12,606 $0 $32,216 $2,941 $0 $4,633 $39,790 $72

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories 56,173 0 7,454 0 63,627 9.6% 6,092 0% 0 10.0% 6,972 76,691 139

8.2 Turbine Plant Auxiliaries 378 0 810 0 1,189 9.7% 115 0% 0 10.0% 130 1,434 3

8.3 Condenser & Auxiliaries 4,179 0 1,557 0 5,735 9.5% 545 0% 0 10.0% 628 6,908 13

8.4 Steam Piping 20,055 0 9,889 0 29,944 8.3% 2,499 0% 0 15.0% 4,866 37,309 68

8.9 TG Foundations 0 1,187 1,876 0 3,063 9.4% 288 0% 0 20.0% 670 4,021 7

SUBTOTAL 8. $80,785 $1,187 $21,585 $0 $103,557 $9,540 $0 $13,267 $126,364 $230

9 COOLING WATER SYSTEM

9.1 Cooling Towers 15,389 0 4,792 0 20,181 9.5% 1,916 0% 0 10.0% 2,210 24,306 44

9.2 Circulating Water Pumps 2,830 0 217 0 3,047 8.6% 261 0% 0 10.0% 331 3,638 7

9.3 Circ. Water System Auxiliaries 714 0 95 0 809 9.4% 76 0% 0 10.0% 89 974 2

9.4 Circ. Water Piping 0 5,659 5,485 0 11,144 9.2% 1,027 0% 0 15.0% 1,826 13,996 25

9.5 Make-up Water System 657 0 878 0 1,535 9.5% 145 0% 0 15.0% 252 1,932 4

9.6 Component Cooling Water System 566 0 450 0 1,015 9.4% 95 0% 0 15.0% 167 1,277 2

9.9 Circ. Water System Foundations 0 3,380 5,371 0 8,751 9.4% 824 0% 0 20.0% 1,915 11,490 21

SUBTOTAL 9. $20,155 $9,040 $17,287 $0 $46,482 $4,344 $0 $6,788 $57,614 $105

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*
Carbon Dioxide Capture Sensitivity Analysis

184

Exhibit 3-70 Case 1G (99%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1G - Supercritical PC w/ 99% CO2 Capture x $1, 000

Plant Size: 549.97 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Ash Coolers N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.2 Cyclone Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.3 HGCU Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.4 High Temperature Ash Piping N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.5 Other Ash Recovery Equipment N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0

10.6 Ash Storage Silos 728 0 2,243 0 2,971 9.7% 289 0% 0 10.0% 326 3,586 7

10.7 Ash Transport & Feed Equipment 4,713 0 4,827 0 9,540 9.5% 902 0% 0 10.0% 1,044 11,486 21

10.8 Misc. Ash Handling Equipment 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0

10.9 Ash/Spent Sorbent Foundation 0 173 204 0 377 9.3% 35 0% 0 20.0% 82 494 1

SUBTOTAL 10. $5,441 $173 $7,274 $0 $12,888 $1,227 $0 $1,453 $15,567 $28

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment 1,712 0 278 0 1,990 9.3% 184 0% 0 7.5% 163 2,338 4

11.2 Station Service Equipment 5,153 0 1,693 0 6,847 9.6% 655 0% 0 7.5% 563 8,064 15

11.3 Switchgear & Motor Control 5,925 0 1,007 0 6,932 9.3% 642 0% 0 10.0% 757 8,331 15

11.4 Conduit & Cable Tray 0 3,715 12,844 0 16,558 9.6% 1,585 0% 0 15.0% 2,721 20,865 38

11.5 Wire & Cable 0 7,009 13,531 0 20,540 8.4% 1,731 0% 0 15.0% 3,341 25,611 47

11.6 Protective Equipment 260 0 885 0 1,146 9.8% 112 0% 0 10.0% 126 1,383 3

11.7 Standby Equipment 1,350 0 31 0 1,381 9.5% 131 0% 0 10.0% 151 1,663 3

11.8 Main Power Transformers 7,725 0 130 0 7,856 7.6% 597 0% 0 10.0% 845 9,298 17

11.9 Electrical Foundations 0 338 828 0 1,166 9.5% 111 0% 0 20.0% 255 1,532 3

SUBTOTAL 11. $22,127 $11,062 $31,227 $0 $64,416 $5,746 $0 $8,923 $79,085 $144

12 INSTRUMENTATION & CONTROL

12.1 PC Control Equipment w/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0

12.2 Combustion Turbine Control N/A 0 N/A 0 0 0% 0 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 0.0% 0 0 0

12.4 Other Major Component Control 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0

12.5 Signal Processing Equipment W/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0

12.6 Control Boards, Panels & Racks 523 0 313 0 836 9.6% 80 0% 0 15.0% 137 1,053 2

12.7 Computer Accessories 5,276 0 922 0 6,199 9.5% 590 0% 0 10.0% 679 7,468 14

12.8 Instrument Wiring & Tubing 2,860 0 5,674 0 8,535 8.5% 727 0% 0 15.0% 1,389 10,651 19

12.9 Other I & C Equipment 1,491 0 3,383 0 4,874 9.7% 475 0% 0 10.0% 535 5,884 11

SUBTOTAL 12. $10,150 $0 $10,293 $0 $20,443 $1,872 $0 $2,740 $25,056 $46

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 57 1,129 0 1,185 9.9% 117 0% 0 20.0% 260 1,562 3

13.2 Site Improvements 0 1,874 2,327 0 4,201 9.8% 412 0% 0 20.0% 923 5,536 10

13.3 Site Facilities 3,358 0 3,311 0 6,669 9.8% 655 0% 0 20.0% 1,465 8,788 16

SUBTOTAL 13. $3,358 $1,930 $6,767 $0 $12,054 $1,184 $0 $2,648 $15,886 $29

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

185

Exhibit 3-70 Case 1G (99%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 1G - Supercritical PC w/ 99% CO2 Capture x $1, 000

Plant Size: 549.97 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Boiler Building 0 8,871 7,801 0 16,672 9.0% 1,497 0% 0 15.0% 2,725 20,895 38

14.2 Turbine Building 0 12,858 11,984 0 24,842 9.0% 2,237 0% 0 15.0% 4,062 31,141 57

14.3 Administration Building 0 647 684 0 1,331 9.1% 121 0% 0 15.0% 218 1,669 3

14.4 Circulation Water Pumphouse 0 161 128 0 289 8.9% 26 0% 0 15.0% 47 363 1

14.5 Water Treatment Buildings 0 911 831 0 1,742 9.0% 156 0% 0 15.0% 285 2,183 4

14.6 Machine Shop 0 433 291 0 723 8.9% 64 0% 0 15.0% 118 905 2

14.7 Warehouse 0 293 294 0 587 9.0% 53 0% 0 15.0% 96 736 1

14.8 Other Buildings & Structures 0 239 204 0 443 9.0% 40 0% 0 15.0% 72 556 1

14.9 Waste Treating Building & Str. 0 458 1,389 0 1,846 9.4% 174 0% 0 15.0% 303 2,324 4

SUBTOTAL 14. $0 $24,871 $23,605 $0 $48,476 $4,368 $0 $7,927 $60,770 $110

Total Cost $828,959 $55,727 $403,330 $0 $1,288,016 $121,121 $59,720 $210,057 $1,678,914 $3,053

Owner's Costs

Preproduction Costs

6 Months All Labor $10,864 $20

1 Month Maintenance Materials $1,610 $3

1 Month Non-fuel Consumables $1,536 $3

1 Month Waste Disposal $359 $1

25% of 1 Months Fuel Cost at 100% CF $2,180 $4

2% of TPC $33,578 $61

Total $50,127 $91

Inventory Capital

60 day supply of fuel and consumables at 100% CF $20,509 $37

0.5% of TPC (spare parts) $8,395 $15

Total $28,903 $53

Initial Cost for Catalyst and Chemicals $2,992 $5

Land $900 $2

Other Owner's Costs $251,837 $458

Financing Costs $45,331 $82

Total Overnight Costs (TOC) $2,059,004 $3,743.8

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,347,264 $4,268

Labor Bare 

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Project Cont.
Carbon Dioxide Capture Sensitivity Analysis

186

Exhibit 3-71 Case 1G Initial and Annual O&M Expenses

Case: Case 1G - Supercritical PC w/ 99% CO2 Capture

Plant Size (MWe): 549.97 Heat Rate (Btu/kWh): 13,269

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 85 CO2 Captured (TPD): 17646

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 11.3 11.3

Foreman 1.0 1.0

Lab Tech's etc. 2.0 2.0

TOTAL Operating Jobs 16.3 16.3

$ $/kW-net

Annual Operating Labor Cost (calc'd) 6,431,885 11.69

Maintenance Labor Cost (calc'd) 10,949,911 19.91

Administrative & Support Labor (calc'd) 4,345,449 7.90

Property Taxes & Insurance $33,578,281 $61.055

TOTAL FIXED OPERATING COSTS $55,305,527 $100.561

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $16,424,867 0.00401

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 9,212 1.08 $0 $3,086,655 0.00075

Chemicals

 MU & WT Chem. (lb) 0 44,592 0.17 $0 $2,351,886 0.00057

 Limestone (ton) 0 758 21.63 $0 $5,083,719 0.00124

 Carbon (Hg Removal) (lb) 0 0 1.05 $0 $0 0.00000

 MEA Solvent (ton) 1,232 1.77 2249.89 $2,771,955 $1,236,732 0.00030

 Caustic Soda, NaOH (ton) 87 8.71 433.68 $37,755 $1,171,350 0.00029

 Sulfuric acid, H2SO4 (ton) 83 8.31 138.78 $11,529 $357,683 0.00009

 Corrosion Inhibitor 0 0 0.00 $170,414 $8,230 0.00000

 Activated C, MEA (lb) 0 2,087 1.05 $0 $679,951 0.00017

 Ammonia, 28% soln (ton) 0 23 129.80 $0 $927,839 0.00023

Subtotal Chemicals $2,991,654 $11,817,390 0.00289

Other

 Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

 SCR Catalyst Replacement (m3)w/equip. 0.42 5,775.94 $0 $759,439 0.00019

 Emission Penalties 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $759,439 0.00019

Waste Disposal

 Spent Mercury Catalyst (lb) 0 0 0.31 $0 $0 0.00000

 Flyash (ton) 0 582 16.23 $0 $2,932,245 0.00072

 Bottom Ash (ton) 0 146 16.23 $0 $733,061 0.00018

Subtotal Solid Waste Disposal $0 $3,665,306 0.00090

By-products & Emissions

 Gypsum (tons) 0 0 0.00 $0 $0 0.00000

 Sulfur (tons) 0 0 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 0.00000

TOTAL VARIABLE OPERATING COSTS $35,753,658 0.00873

Coal FUEL (tons) 225,202 7,507 38.19 $8,599,376 $88,931,883 0.02172

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

187

3.2.5 Supercritical PC Cost and Performance Summary

A summary of plant costs and performance for the SC PC cases is shown in Exhibit 3-72.

Exhibit 3-72 Cost and Performance Results for the Supercritical PC Cases

Case 0 1A 1B 1C 1D 1E 1F 1G

CO2 Capture, % 0% 30% 50% 70% 85% 90% 95% 99%

Gross Power Output, MWe 580.4 601.5 618.2 637.8 654.8 661.3 667.9 679.6

Net Power Output, MWe 550.0 550.0 550.0 550.0 550.1 550.0 550.0 550.0

Net Plant Efficiency, % (HHV) 39.3 35.2 32.9 30.6 28.9 28.2 27.5 25.7

Net Plant Heat Rate, Btu/kWh (HHV) 8,687 9,695 10,379 11,151 11,819 12,083 12,400 13,269

Coal Flowrate (lb/hr) 409,550 457,066 489,316 525,764 557,283 569,672 584,578 625,561

Total CO2 Captured, lb/MWhnet NA 588 1,057 1,582 2,037 2,213 2,398 2,674

CO2 Capture & Compression Cost, $x1000 NA $190,138 $266,902 $336,794 $441,781 $463,389 $485,273 $516,797

Total Plant Cost, $x1000 $905,901 $1,138,688 $1,258,942 $1,378,696 $1,525,453 $1,562,889 $1,602,389 $1,678,914

Owner’s Costs, $x1000 $207,800 $258,649 $285,448 $312,458 $344,744 $353,249 $362,267 $380,090

Total Overnight Cost, $x1000 $1,113,701 $1,397,338 $1,544,390 $1,691,155 $1,870,197 $1,916,138 $1,964,657 $2,059,004

Total Overnight Cost, $/kW $2,025 $2,541 $2,808 $3,075 $3,400 $3,484 $3,572 $3,744

Total As-Spent Capital, $x1000 $1,262,937 $1,592,965 $1,760,604 $1,927,917 $2,132,024 $2,184,397 $2,239,708 $2,347,264

Total As-Spent Capital, $/kW $2,296 $2,896 $3,201 $3,505 $3,876 $3,972 $4,072 $4,268

CO2 Capital Cost Penaltya, $/kW NA $516 $783 $1,050 $1,375 $1,459 $1,548 $1,719

Cost of Electricityb, mills/kWh 58.90 76.64 84.38 92.75 101.49 104.29 107.00 112.65

COE CO2 Penaltya, mills/kWh NA 17.7 25.5 33.8 42.6 45.4 48.1 53.8

Percent increase in COEa, % NA 30.1 43.3 57.5 72.3 77.1 81.7 91.3

Cost of CO2 Avoideda, $/tonne NA 102.8 79.1 69.2 67.2 65.9 64.7 68.2

CO2 Emissions, lb/MMBtu 203.2 142.9 101.7 61.7 31.2 20.4 10.2 2.0

CO2 Emissions, lb/MWhnet 1,765 1,385 1,055 687 369 246 126 27

SO2 Emissions, lb/MMBtu 0.086 0.064 0.050 0.036 0.017 0.017 0.016 0.016

SO2 Emissions, lb/MWh 0.75 0.570 0.460 0.340 0.170 0.170 0.170 0.170

NOx Emissions, lb/MMBtu 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070

NOx Emissions, lb/MWh 0.608 0.621 0.646 0.673 0.695 0.703 0.715 0.752

PM Emissions, lb/MMBtu 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013

PM Emissions, lb/MWh 0.113 0.115 0.120 0.125 0.129 0.131 0.133 0.140

Hg Emissions, lb/TBtu 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14

Hg Emissions, lb/TWh 9.93 10.1 10.6 11.0 11.3 11.5 11.7 12.3

Raw Water Withdrawal, gpm 5,394 6,245 6,987 8,386 9,615 10,095 10,512 11,664

Raw Water Consumption, gpm 4,301 4,898 5,433 6,474 7,392 7,753 8,074 8,961

Raw Water Consumption, gal/MWhnet 469 534 593 706 806 846 881 978

a Relative to Case 0 (SC PC without capture from 2010 Bituminous Baseline study)

b Capacity factor is 85% for the SC PC cases
Carbon Dioxide Capture Sensitivity Analysis

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Carbon Dioxide Capture Sensitivity Analysis

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4. Case 2 – GEE IGCC with Variable CO2 Capture

This section evaluates a range of CO2 capture levels for four IGCC plant designs, which are 

based on the GEE gasifier in the “radiant only” configuration. GEE offers three design 

configurations [44]: 

Quench: In this configuration, the hot syngas exiting the gasifier passes through a pool of 

water to quench the temperature to less than 260 °C (500 °F) before entering the syngas 

scrubber. It is the simplest and lowest capital cost design, but also the least efficient.

Radiant-Only: 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), then through a water quench where the syngas is further cooled to about 223 °C (450

°F) prior to entering the syngas scrubber. Relative to the quench configuration, the 

radiant-only 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), passes over a pool of water where particulate is removed but the syngas is 

not quenched, 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-only configuration includes a water quench and, based on functionality, 

would be more appropriately named radiant-quench. The term radiant-only is used to distinguish 

it from the radiant-convective configuration. Since radiant-only is the terminology used by GEE, 

it will be used throughout this report.

The balance of Section 4 is organized as follows:

Gasifier Background provides information on the development and status of the GEE 

gasification technology.

Process Description provides an overview of the technology operation for IGCC Designs

2 through 4, which include WGS reactor(s) and a two-stage SelexolTM unit. 

Performance Results provides the main modeling results from Designs 1–4 including the 

performance summary, environmental performance, carbon balance, sulfur balance, water 

balance, mass and energy balance diagrams, mass and energy balance tables.

Equipment List provides an itemized list of major equipment for Designs 1–4 with 

account codes that correspond to the cost accounts in the Cost Estimates section.
Carbon Dioxide Capture Sensitivity Analysis

190

Cost Estimates details the capital and O&M costs for IGCC Designs 1–4

4.1 Gasifier Background

Development and Current Status [45] – Initial development of the GEE gasification 

technology (formerly licensed by Texaco and then ChevronTexaco) was conducted in the 1940s 

at Texaco‟s Montebello, California laboratories. From 1946 to 1954 the Montebello pilot plant 

produced synthesis gas (hydrogen and carbon monoxide) by partial oxidation of a variety of 

feedstocks, including natural gas, oil, asphalt, coal tar, and coal. From 1956 to 1958, coal was 

gasified in a 91 tonne/day (100 TPD) Texaco coal gasifier at the Olin Mathieson Chemical Plant 

in Morgantown, West Virginia, for the production of ammonia. 

The oil price increases and supply disruptions of the 1970s renewed interest in the Texaco 

partial-oxidation process for gasification of coal or other solid opportunity fuels. Three 14 

tonne/day (15 TPD) pilot plants at the Montebello laboratories have been used to test numerous 

coals. Two larger pilot plants were also built. The first gasified 150 tonne/day (165 TPD) of 

coal and was built to test synthesis gas generation by Rührchemie and Rührkohle at Oberhausen, 

Germany, and included a synthesis gas cooler. The second gasified 172 tonne/day (190 TPD) of 

coal using a quench-only gasifier cooler and was built to make hydrogen at an existing TVA 

ammonia plant at Muscle Shoals, Alabama. These two large-scale pilot plants successfully 

operated for several years during the 1980s and tested a number of process variables and 

numerous coals.

The first commercial Texaco coal gasification plant was built for Tennessee Eastman at 

Kingsport, Tennessee, and started up in 1983. To date, 24 gasifiers have been built in 12 plants 

for coal and petroleum coke. Several of the plants require a hydrogen-rich gas and therefore 

directly water-quench the raw gas to add the water for shifting the CO to H2, and have no 

synthesis gas coolers.

The Cool Water plant was the first commercial-scale Texaco coal gasification project for the 

electric utility industry. This facility gasified 907 tonne/day (1,000 TPD) (dry basis) of 

bituminous coal and generated 120 MW of electricity by IGCC operation. In addition, the plant 

was the first commercial-sized Texaco gasifier used with a synthesis gas cooler. The Cool Water 

plant operated from 1984 to 1989 and was a success in terms of operability, availability, and 

environmental performance. 

The Tampa Electric IGCC Clean Coal Technology Demonstration Project built on the Cool 

Water experience to demonstrate the use of the Texaco coal gasification process in an IGCC 

plant. The plant utilizes approximately 2,268 tonne/day (2,500 TPD) of coal in a single Texaco 

gasifier to generate a net of approximately 250 MWe. The syngas is cooled in a hightemperature radiant heat exchanger, generating high-pressure steam, and further cooled in 

convective heat exchangers (the radiant-convective configuration). The particles in the cooled 

gas are removed in a water-based scrubber. The cleaned gas then enters a hydrolysis reactor 

where COS is converted to H2S. After additional cooling, the syngas is sent to a conventional 

AGR unit, where H2S is absorbed by reaction with an amine solvent. H2S is removed from the 

amine by steam stripping and sent to a sulfuric acid plant. The cleaned gas is sent to a General 

Electric MS 7001FA combustion turbine (CT). 
Carbon Dioxide Capture Sensitivity Analysis

191

The Delaware Clean Energy Project is a coke gasification and CT repowering of an existing 

130 MW coke-fired boiler cogeneration power plant at the Motiva oil refinery in Delaware City, 

Delaware. The Texaco coal gasification process was modified to gasify 1,814 tonne/day 

(2,000 TPD) of this low-quality petroleum coke. The plant is designed to use all the fluid 

petroleum coke generated at Motiva‟s Delaware City Plant and produce a nominal 238,136 kg/h 

(525,000 lb/h) of 8.6 MPa (1,250 psig) steam, and 120,656 kg/h (266,000 lb/h) of 1.2 MPa 

(175 psig) steam for export to the refinery and the use/sale of 120 MW of electrical power. 

Environmentally, these new facilities help satisfy tighter NOx and SO2 emission limitations at the 

Delaware City Plant.

Gasifier Capacity – 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/h (6.7 million 

scfh) with an energy content of about 1,897 million kJ/h (HHV) (1,800 million Btu/h). This size 

matches the F Class CTs that are used at Tampa.

Distinguishing Characteristics – A key advantage of the GEE coal gasification technology is 

the extensive operating experience at full commercial scale. Furthermore, Tampa Electric is an 

IGCC power generation facility, operated by conventional electric utility staff, and is 

environmentally one of the cleanest coal-fired power plants in the world. The GEE gasifier also 

operates at the highest pressure of the three gasifiers in this study, 5.6 MPa (815 psia) compared 

to 4.2 MPa (615 psia) for CoP and Shell.

Entrained-flow gasifiers have fundamental environmental advantages over fluidized-bed and 

moving-bed gasifiers. They produce no hydrocarbon liquids, and the only solid waste is an inert 

slag. The relatively high H2/CO ratio and CO2 content of GEE gasification fuel gas helps 

achieve low nitrogen oxide (NOx) and CO emissions in even the higher-temperature advanced 

CTs.

The key disadvantages of the GEE coal gasification technology are the limited refractory life, the 

relatively high oxygen requirements and high waste heat recovery duty (synthesis gas cooler 

design). As with the other entrained-flow slagging gasifiers, the GEE process has this 

disadvantage due to its high operating temperature. The disadvantage is magnified in the singlestage, slurry feed design. The quench design significantly reduces the capital cost of syngas 

cooling, while innovative heat integration maintains good overall thermal efficiency although 

lower than the synthesis gas cooler design. Another disadvantage of the GEE process is the 

limited ability to economically handle low-rank coals relative to moving-bed and fluidized-bed 

gasifiers or to entrained-flow gasifiers with dry feed. For slurry fed entrained gasifiers using 

low-rank coals, developers of two-stage slurry fed gasifiers claim advantages over single-stage 

slurry fed.

Important Coal Characteristics – The slurry feeding system and the recycle of process 

condensate water as the principal slurrying liquid make low levels of ash and soluble salts 

desirable coal characteristics for use in the GEE coal gasification process. High ash levels 

increase the ratio of water-to-carbon in the feed slurry, thereby increasing the oxygen 

requirements. The slurry feeding also favors the use of high-rank coals, such as bituminous coal, 
Carbon Dioxide Capture Sensitivity Analysis

192

since their low inherent moisture content increases the moisture-free solids content of the slurry 

and thereby reduces oxygen requirements. 

4.2 Process Description

In this section the overall GEE gasification process is described. The system description follows 

the Designs 2 through 4 block flow diagrams. 

4.2.1 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 for all four IGCC plant designs.

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.

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.

4.2.2 Coal Grinding and Slurry Preparation

Coal 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 [46].

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 
Carbon Dioxide Capture Sensitivity Analysis

193

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 high-density polyethylene (HDPE).

4.2.3 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 study, 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) [47]. 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 

gas turbine, the ASU operates at or near the supply pressure from the gas turbine‟s air 

compressor.

4.2.3.1 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 gas turbine. 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 gas turbine by injecting residual nitrogen from the ASU can 

have a number of benefits, depending on the design of the gas turbine: 

Increased diluent increases mass flow through the turbine, thus increasing the power 

output of the gas turbine 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 gas turbine 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 NOx.

In this study, the ASU nitrogen product was used as the primary diluent with a design target of 

reducing the syngas lower heating value (LHV) to 4.5-4.8 MJ/Nm3(120-128 Btu/scf). If the 

amount of available nitrogen was not sufficient to meet this target, additional dilution was 

provided through syngas humidification, and if still more dilution was required, the third option 

was steam injection.
Carbon Dioxide Capture Sensitivity Analysis

194

4.2.3.2 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 gas turbine. Medium Btu syngas streams result in a higher mass 

flow than natural gas to provide the same heat content to the gas turbine. Some gas turbine 

designs may need to extract air to maintain stable compressor or turbine operation in response to 

increased fuel flow rates. Other gas turbines 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 gas turbine. 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 gas turbine nitrogen diluents stream with a gas-togas heat exchanger.

4.2.3.3 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 TPD) of 95 percent purity oxygen for a Shell coal-based gasification unit that fuels a 

Siemens V94.2 gas turbine. In normal operation at the Buggenum plant, the ASU receives all of 

its air supply from, and sends all residual nitrogen to, the gas turbine.

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 gas turbine. All of the nitrogen 

produced in the ASU is used in the gas turbine. 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 [48].

4.2.3.4 ASU Basis

For this study, air integration is used for Design 1 only. For Designs 2 through 4, where higher 

CO2 removal efficiencies are desired, all of the available combustion air is required to maintain 

mass flow through the turbine and hence maintain power output once the syngas is diluted to the 

target heating value.

The amount of air extracted from the gas turbine in Design 1 is determined through a process 

that includes the following constraints:

The CT output must be maintained at 232 MW.

The diluted syngas must meet heating value requirements specified by a CT vendor, 

which ranged from 4.5–4.8 MJ/Nm3(120–128 Btu/scf) (LHV).
Carbon Dioxide Capture Sensitivity Analysis

195

For Design 1, about 4 percent of the pressurized CT air supply was extracted, which accounts for 

approximately 16.8 percent of the total ASU air requirement. It was not a goal of this project to 

optimize the integration of the CT and the ASU, although several recent 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 [49, 50]. 

4.2.3.5 Air Separation Plant Process Description [51]

The ASU is designed to produce 95 mole percent O2 for use in the gasifier. The plant is 

designed with two production trains, one for each gasifier. The air compressor is powered by an 

electric motor. Nitrogen is also recovered, compressed, and used as a diluent in the gas turbine 

combustor. A process schematic of a typical ASU is shown in Exhibit 4-1.

The air feed to the ASU is from one or two sources, depending on the plant design. The bulk of 

the air is supplied from a stand-alone compressor, while a portion is extracted from the 

compressor of the gas turbine in Design 1 only. 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 between each stage.

Air from the stand-alone compressor is combined with the extraction air in Design 1, 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 countercurrent to the normal airflow. The 

nitrogen is heated against extraction steam (1.7 MPa [250 psia]) in a shell and tube heat 

exchanger. 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 low

pressure process steam at 0.3 MPa (50 psia). The remaining 5 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.

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 
Carbon Dioxide Capture Sensitivity Analysis

196

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 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. Low-pressure nitrogen is split 

into two streams. The majority of the low-pressure nitrogen is compressed and fed to the gas 

turbine 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 high-pressure nitrogen stream is also 

produced from the cold box and is further compressed before it is also supplied to the gas 

turbine.

Exhibit 4-1 Typical ASU Process Schematic

Air

Air Filter

Main Air

Compressor

CWS

CWR

Cond. Steam

1st Stage

DCA

2nd Stage

DCA

Prepurifiers

Booster Air

Compressor

Turbine Air 

Booster

Regen

Heater

Steam

Cond.

Regeneration

Nitrogen

Regen. N2

Blower

Liq. Oxygen

Pump

Turbine

Cryogenic Air

Separation Unit

Single Train

GT Nitrogen

HP Oxygen

Oxygen

Compressor

GT Nitrogen

Compressor

Chiller

Air from Gas Turbine

CWS

CWR

1

2

15

12

10

3

5

7

6

8 9
Carbon Dioxide Capture Sensitivity Analysis

197

4.2.4 Gasification

Each IGCC plant design in this study utilizes two gasification trains to process the 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 study, 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. Oxygen from the ASU is vented during preparation for startup and 

is sent to the feed injector during normal operation. The ASU supplies 95 mole percent oxygen 

to the GEE gasifiers and the Claus plant. Carbon conversion in the gasifier is assumed to be 98 

percent, including a fines recycle stream.

The gasifier vessel is a refractory-lined, high-pressure 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 CO2, and small amounts of hydrogen sulfide, carbonyl sulfide, 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.

4.2.5 Raw Gas Cooling/Particulate Removal

Syngas is cooled from 1,316 °C (2,400 °F) to 677 °C (1,250 °F) in the radiant synthesis gas 

cooler 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. The waste heat 

from this cooling is used to generate high-pressure saturated steam. Boiler feedwater in the tubes 

is saturated, and then steam and water are separated in a steam drum. 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 223 °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 synthesis gas cooler 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 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 
Carbon Dioxide Capture Sensitivity Analysis

198

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.

4.2.6 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 and particulate. The syngas exits the scrubber still saturated at 206

°C (403 °F).

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 synthesis gas coolers. 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 sulfur recovery unit. Remaining water is sent to wastewater 

treatment.

4.2.7 Water Gas Shift Reactors

In this study, IGCC Designs 2 through 4 include water gas shift (WGS) reactor(s). The WGS 

reaction converts most of the syngas carbon monoxide (CO) to hydrogen and CO2 by reacting 

the CO with water over a bed of catalyst. A typical offering from a commercial catalyst vendor

is a steam-to-dry gas (S:DG) molar ratio of 0.3 at the outlet of the final shift reactor. The 

function of this excess steam is to drive the shift equilibrium toward the products. The reaction 

consumes one mol of water per mol of CO converted, and releases heat in the process:

H2O + CO  H2 + CO2 Hrxn = -17,697 Btu/lb-mol (1)

The WGS reactor(s) can be located either upstream of the AGR system (sour gas shift) or 

immediately downstream (sweet gas shift). If the WGS is located downstream of the AGR, then 

the metallurgy of the unit is less stringent but additional equipment must be added to the process. 

Products from the gasifier are humidified 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 WGS feed to 

meet the required water-to-gas ratio. If the CO converter is located upstream of the AGR, no 

additional equipment is required since the WGS reactor(s) also promote carbonyl sulfide (COS) 

hydrolysis without a separate catalyst bed. 

COS + H2O  H2S + CO2 Hrxn = -14,526 Btu/lb-mol (2)

This reaction converts sulfur to a form (H2S) that is removed more readily than COS in an AGR 

system, helping to meet emission specifications. The SelexolTM solvent‟s affinity for H2S is 

nearly 4 times greater than it is for COS [52]. Since this physical solvent‟s driving force is 

partial pressure, and sulfur concentrations are relatively low to begin with, conversion to H2S 

(which the SelexolTM solvent can separate more easily) is effective in reducing the size of the 

SelexolTM process, while achieving the low sulfur levels required by local permitting agencies 
Carbon Dioxide Capture Sensitivity Analysis

199

(this analysis assumes 0.0128 lb SO2/MMBtu). Therefore, for this study the WGS was located 

upstream of the AGR and is referred to as sour gas shift (SGS).

Depending on the plant design, the SGS consists of either two paths of parallel fixed-bed reactors 

arranged in series, or a single, parallel fixed-bed reactor. 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. The heat exchanger after the first SGS reactor is used to vaporize 

water. The heat exchanger after the second SGS reactor is used to raise IP steam, which then 

passes through the reheater section of the HRSG in the GEE IGCC plant design. Approximately 

96 percent conversion of the CO is achieved in the GEE design.

The default S:DG ratio (0.3) represents a typical offering by a commercial catalyst vendor. The 

WGS and COS hydrolysis reactions occur at locations within the catalyst matrix, referred to as 

active sites, where water molecules have formed weak chemical bonds with the catalyst material. 

In order for chemical bonding of water molecules to occur on the catalyst surface, diffusion of 

H2O through the bulk syngas must first occur. At the base case S:DG ratio, diffusion rates are 

fast enough such that there are adequate active catalyst sites on which the reactions can occur. 

This helps to maintain reasonable reactor sizes and costs. 

A key portion of this study is devoted to optimizing the WGS step for lower degrees of carbon 

capture. The three methods that will be investigated are: (1) to bypass a portion of syngas 

around the shift reactor(s); (2) to use less shift steam (a S:DG ratio of 0.25 will be used); and (3) 

to use one shift reactor instead of two (D2). These will be used in combination with one another 

in order to arrive at the optimum configuration for each level of CO2 capture.

4.2.8 Mercury Removal

An IGCC power plant has the potential of removing mercury in a more simple and cost-effective 

manner than conventional PC plants. This is because mercury can be removed from the syngas 

at elevated pressure and prior to combustion so that syngas volumes are much smaller than flue 

gas volumes in comparable PC cases. A conceptual design for a carbon bed adsorption system 

was developed for mercury control in the IGCC plants being studied. 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 [53]. The coal mercury content (0.15 ppm 

dry) and carbon bed removal efficiency (95 percent) were discussed previously in Sections 2.2

and 2.4. IGCC-specific design considerations are discussed below.

Carbon Bed Location – The packed carbon bed vessels are located upstream of the sulfur 

recovery unit and syngas enters at a temperature near 35 °C (95 °F). Eastman Chemical also 

operates their beds ahead of their sulfur recovery unit at a temperature of 30 °C (86 °F) [53]. 

Process Parameters – An empty vessel basis gas residence time of approximately 20 seconds 

was used based on Eastman Chemical‟s experience [53]. 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 and was selected for this 

application. 
Carbon Dioxide Capture Sensitivity Analysis

200

The bed density of 30 lb/ft3 was based on the Calgon Carbon Corporation HGR-P sulfurimpregnated pelletized activated carbon. These parameters determined the size of the vessels 

and the amount of carbon required. Each gasifier train has one mercury removal bed and there 

are two gasifier trains in each IGCC case, resulting in two carbon beds per case.

Carbon Replacement Time – Eastman Chemicals replaces its bed every 18 to 24 months [53]. 

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 study, 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%. The mercury-laden carbon is considered 

to be a hazardous waste, and the disposal cost estimate reflects this categorization.

4.2.9 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 acid gas removal (AGR) and sulfur recovery. 

The environmental target for these IGCC plant designs is 0.0128 lb SO2/MMBtu, which requires 

that the total sulfur content of the syngas be reduced to less than 30 ppmv. This includes all 

sulfur species, but in particular the total of COS and hydrogen sulfide (H2S), thereby resulting in 

stack gas emissions of less than 4 ppmv SO2.

4.2.9.1 COS Hydrolysis

The use of COS hydrolysis pretreatment in the feed to the AGR process provides a means to 

reduce the COS concentration. 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 COS hydrolysis reactor design employed in this study, for IGCC 

Designs 1 through 3, is based on information from Porocel. However, the WGS reactor(s) also 

reduce COS to H2S as discussed in Section 4.2.7.

The COS hydrolysis reaction is equimolar with a slightly exothermic heat of reaction. The 

reaction is represented as follows:

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 
Carbon Dioxide Capture Sensitivity Analysis

201

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.

4.2.9.2 Sulfur Removal

H2S removal generally consists of absorption by a regenerable solvent. The most commonly 

used technique is based on countercurrent 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 

regenerated lean solution is then cooled and recirculated to the top of the absorber, completing 

the cycle. Exhibit 4-2 is a simplified diagram of the AGR process [52].

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, 

methyldiethanolamine (MDEA), SelexolTM, aqueous di-isoproponal amine (DIPA), and 

FLEXSORB [52]. These processes can be separated into three general types: chemical reagents, 

physical solvents, and hybrid solvents.

Exhibit 4-2 Flow Diagram for a Conventional AGR Unit

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

Chemical Solvents

Frequently used for AGR, chemical solvents are more suitable than physical or hybrid solvents 

for applications at lower operating pressures. The chemical nature of acid gas absorption makes 

solution loading and circulation less dependent on the acid gas partial pressure. Because the 
Carbon Dioxide Capture Sensitivity Analysis

202

solution is aqueous, co-absorption of hydrocarbons is minimal. In a conventional amine unit, the 

chemical solvent reacts exothermically with the acid gas constituents. They form a weak 

chemical bond that can be broken, releasing the acid gas and regenerating the solvent for reuse.

In recent years MDEA, a tertiary amine, has acquired a much larger share of the gas-treating 

market. Compared with primary and secondary amines, MDEA has superior capabilities for 

selectively removing H2S in the presence of CO2, is resistant to degradation by organic sulfur 

compounds, has a low tendency for corrosion, has a relatively low circulation rate, and consumes 

less energy. Several MDEA-based solvents that are formulated for high H2S selectivity are 

commercially-available.

Chemical reagents are used to remove the acid gases by a reversible chemical reaction of the acid 

gases with an aqueous solution of various alkanolamines or alkaline salts in water. Exhibit 4-3

lists commonly used chemical reagents along with principal licensors that use them in their 

processes. The process consists of an absorber and regenerator, which are connected by a 

circulation of the chemical reagent aqueous solution. The absorber contacts the lean solution 

with the main gas stream (at pressure) to remove the acid gases by absorption/ reaction with the 

chemical solution. The acid-gas-rich solution is reduced to low pressure and heated in the 

stripper to reverse the reactions and strip the acid gas. The acid-gas-lean solution leaves the 

bottom of the regenerator stripper and is cooled, pumped to the required pressure and 

recirculated back to the absorber. For some amines, a filter and a separate reclaiming section 

(not shown) are needed to remove undesirable reaction byproducts.

Exhibit 4-3 Common Chemical Reagents Used in AGR Processes

Chemical Reagent Acronym Process Licensors Using the Reagent

Monoethanolamine MEA Dow, Exxon, Lurgi, Union Carbide

Diethanolamine DEA Elf, Lurgi

Diglycolamine DGA Texaco, Fluor

Triethanolamine TEA AMOCO

Diisopropanolamine DIPA Shell

Methyldiethanolamine MDEA BASF, Dow, Elf, Snamprogetti, Shell, Union 

Carbide, Coastal Chemical

Hindered amine Exxon

Potassium carbonate ―hot pot‖ Eickmeyer, Exxon, Lurgi,

Union Carbide

Typically, the absorber temperature is 27 to 49 °C (80 to 120 °F) for amine processes, and the 

regeneration temperature is the boiling point of the solutions, generally 104 to 127 °C (220 to 

260 °F). The liquid circulation rates can vary widely, depending on the amount of acid gas being 

captured. However, the most suitable processes are those that will dissolve 2 to 10 scf acid gas 

per gallon of solution circulated. Steam consumption can vary widely also: 0.7 to 1.5 pounds 

per gallon of liquid is typical. 
Carbon Dioxide Capture Sensitivity Analysis

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The major advantage of these systems is the ability to remove acid gas to low levels at low to 

moderate H2S partial pressures. 

Physical Solvents

Physical solvents involve absorption of acid gases into certain organic solvents that have a high 

solubility for acid gases. As the name implies, physical solvents involve only the physical 

solution of acid gas – the acid gas loading in the solvent is proportional to the acid gas partial 

pressure (Henry‟s Law). Physical solvent absorbers are usually operated at lower temperatures 

than is the case for chemical solvents. The solution step occurs at high pressure and at or below 

ambient temperature while the regeneration step (dissolution) occurs by pressure letdown and 

indirect stripping with low-pressure 0.45 MPa (65 psia) steam. It is generally accepted that 

physical solvents become increasingly economical, and eventually superior to amine capture, as 

the partial pressure of acid gas in the syngas increases.

The physical solvents are regenerated by multistage flashing to low pressures. Because the 

solubility of acid gases increases as the temperature decreases, absorption is generally carried out 

at lower temperatures, and refrigeration is often required.

Most physical solvents are capable of removing organic sulfur compounds. Exhibiting higher 

solubility of H2S than CO2, they can be designed for selective H2S or total acid gas removal. In 

applications where CO2 capture is desired the CO2 is flashed off at various pressures, which 

reduces the compression work and parasitic power load associated with sequestration.

Physical solvents co-absorb heavy hydrocarbons from the feed stream. Since heavy 

hydrocarbons cannot be recovered by flash regeneration, they are stripped along with the acid 

gas during heated regeneration. These hydrocarbon losses result in a loss of valuable product 

and may lead to CO2 contamination. 

Several physical solvents that use anhydrous organic solvents have been commercialized. They 

include the SelexolTM process, which uses dimethyl ether of polyethylene glycol as a solvent; 

Rectisol®, with methanol as the solvent; Purisol, which uses N-methyl-2-pyrrolidone (NMP) as a 

solvent; and the propylene-carbonate process.

Exhibit 4-4 is a simplified flow diagram for a physical reagent type acid gas removal process 

[52]. Common physical solvent processes, along with their licensors, are listed in Exhibit 4-5. 
Carbon Dioxide Capture Sensitivity Analysis

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Exhibit 4-4 Physical Solvent AGR Process Simplified Flow Diagram

Treated 

Gas

Cooler

Lean 

Solvent

L/R 

Exchanger

Rich Solvent

Feed 

Gas

Absorber

Lean Solvent

Pump

Reboiler

Stripper

Acid 

Gas

Condenser

Flash 

Gas

Treated 

Gas

Cooler

Lean 

Solvent

L/R 

Exchanger

Rich Solvent

Feed 

Gas

Absorber

Lean Solvent

Pump

Reboiler

Stripper

Acid 

Gas

Condenser

Flash 

Gas

Exhibit 4-5 Common Physical Solvents Used in AGR Processes

Solvent Solvent/Process

Trade Name

Process 

Licensors

Dimethyl ether of polyethylene 

glycol SelexolTM UOP

Methanol Rectisol® Linde AG and 

Lurgi

Methanol and toluene Rectisol II Linde AG

N—methyl pyrrolidone Purisol Lurgi

Polyethylene glycol and dialkyl 

ethers Sepasolv MPE BASF

Propylene carbonate Fluor Solvent Fluor

Tetrahydrothiophenedioxide Sulfolane Shell

Tributyl phosphate Estasolvan Uhde and IFP

Hybrid Solvents

Hybrid solvents combine the high treated-gas purity offered by chemical solvents with the flash 

regeneration and lower energy requirements of physical solvents. Some examples of hybrid 

solvents are Sulfinol, Flexsorb PS, and Ucarsol LE.
Carbon Dioxide Capture Sensitivity Analysis

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Sulfinol is a mixture of sulfolane (a physical solvent), DIPA or MDEA (chemical solvent), and 

water. DIPA is used when total acid gas removal is specified, while MDEA provides for 

selective removal of H2S.

Flexsorb PS is a mixture of a hindered amine and an organic solvent. Physically similar to

Sulfinol, Flexsorb PS is very stable and resistant to chemical degradation. High treated-gas 

purity, with less than 50 ppmv of CO2 and 4 ppmv of H2S, can be achieved. Both Ucarsol LE701, for selective removal, and LE-702, for total acid gas removal, are formulated to remove 

mercaptans from feed gas.

Mixed chemical and physical solvents combine the features of both systems. The mixed solvent 

allows the solution to absorb an appreciable amount of gas at high pressure. The amine portion 

is effective as a reagent to remove the acid gas to low levels when high purity is desired.

Mixed solvent processes generally operate at absorber temperatures similar to those of the 

amine-type chemical solvents and do not require refrigeration. They also retain some advantages 

of the lower steam requirements typical of the physical solvents. Common mixed chemical and 

physical solvent processes, along with their licensors, are listed in Exhibit 4-6. The key 

advantage of mixed solvent processes is their apparent ability to remove H2S and, in some cases, 

COS to meet very stringent purified gas specifications.

Exhibit 4-6 Common Mixed Solvents Used in AGR Processes

Solvent/Chemical Reagent Solvent/Process

Trade Name

Process 

Licensors

Methanol/MDEA or 

diethylamine Amisol Lurgi

Sulfolane/MDEA or DIPA Sulfinol Shell

Methanol and toluene Selefining Snamprogetti

(Unspecified) /MDEA FLEXSORB PS Exxon

Exhibit 4-7 shows reported equilibrium solubility data for H2S and CO2 in various representative 

solvents [52]. The solubility is expressed as standard cubic feet of gas per gallon liquid per 

atmosphere gas partial pressure.

The figure illustrates the relative solubilities of CO2 and H2S in different solvents and the effects 

of temperature. More importantly, it shows an order of magnitude higher solubility of H2S over 

CO2 at a given temperature, which gives rise to the selective absorption of H2S in physical 

solvents. It also illustrates that the acid gas solubility in physical solvents increases with lower 

solvent temperatures.
Carbon Dioxide Capture Sensitivity Analysis

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Exhibit 4-7 Equilibrium Solubility Data on H2S and CO2 in Various Solvents

The ability of a process to selectively absorb H2S may be further enhanced by the relative 

absorption rates of H2S and CO2. Thus, some processes, besides using equilibrium solubility 

differences, will use absorption rate differences between the two acid gases to achieve 

selectivity. This is particularly true of the amine processes where the CO2 and H2S absorption 

rates are very different.

4.2.9.3 SelexolTM System

There are numerous commercial AGR processes that could meet the sulfur environmental target 

of this study. The most frequently used AGR systems (SelexolTM, Sulfinol, MDEA, and 

Rectisol®) have all been used with the GEE gasifier in various applications. For Design 1, a 
Carbon Dioxide Capture Sensitivity Analysis

207

single-stage SelexolTM system was chosen based on the GEE gasifier operating at a high pressure 

(815 psia), which favors the physical solvent used in the SelexolTM process.

For Designs 2 through 4, a two-stage SelexolTM process was employed for selective H2S removal 

and bulk CO2 capture. The two-stage SelexolTM system was chosen based on the GEE gasifier 

operating at a high pressure (815 psia), which favors the physical solvent used in the SelexolTM 

process. A brief process description follows.

Untreated 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 SelexolTM 

process design conditions. In this study, hydrogen recovery is 99.4 percent. The minimal 

hydrogen slip to the CO2 sequestration stream maximizes the overall plant efficiency. The 

SelexolTM plant cost estimates are based on a plant designed to recover this high percentage of 

hydrogen. For model simplification, a nominal recovery of 100 percent was used with the 

assumption that the additional 0.6 percent hydrogen sent to the CT would have a negligible 

impact on overall system performance.

The CO2 loaded solvent exits the CO2 absorber and 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, and 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. 

A Selexol process flow diagram is shown in Exhibit 4-8.
Carbon Dioxide Capture Sensitivity Analysis

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Exhibit 4-8 Generic Two-Stage SelexolTM Process Flow Diagram

Steam

Stage 1 H2S Absorber

H2S Concentrator

Rich Flash Drum

CO2 Rich

H2S/CO2 Acid Gas Stripper

MP Flash

LP Flash

Stage 2 CO2 Absorber

HP Flash

Treated Gas H2S/CO2 Rich

Lean Selexol

CO2 Rich

Semi-Lean Selexol

Feed Gas

Loaded Solvent Chiller Feed/ Product Exchanger

Rich Solvent Pump

CO2 Recycle Cooler CO2 Recycle Compressor Semi-Lean Solvent Pump Semi-Lean Solvent Chiller

Loaded Solvent Pump

LP Lean Solvent Pump

Lean Solvent Chiller

Lean/Rich Exchanger

Lean Solvent Cooler

HP Lean Solvent Pump

Acid Gas To Claus Plant/ ZnO Bed

Stripping Gas Compressor

Combined CO2 Product Rich Flash Gas Compressor

4.2.10 CO2 Compression and Dehydration

CO2 from the two-stage SelexolTM unit in IGCC Designs 2 through 4 is flashed at three pressure 

levels to separate CO2 and decrease H2 losses to the CO2 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), 

and is compressed to 1.0 MPa (149.5 psia) and combined with the MP CO2 stream. The 

combined stream is compressed from 2.1 MPa (300 psia) to a supercritical condition at 15.3 MPa 

(2,215 psia) using a multiple-stage, intercooled compressor. During compression, the CO2

stream is dehydrated to a dewpoint of -40 oC (-40 °F) with triethylene glycol. The raw CO2

stream from the SelexolTM process contains over 99 percent CO2 with the balance primarily 

hydrogen. The CO2 is transported to the plant fence line and is sequestration ready. CO2 TS&M 

costs were estimated using the methodology described in Section 2.7.

4.2.11 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.
Carbon Dioxide Capture Sensitivity Analysis

209

The add-on modification to the Claus plant selected for this study can be considered a separate 

option from the Claus process. In this context, it is often called a tail gas treating unit (TGTU) 

process.

4.2.11.1 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 4-9

[52]. 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 high-pressure steam usually follows the furnace. Sulfur 

is condensed in a condenser that follows the high-pressure steam recovery section. Low-pressure 

steam is raised in the condenser. The tail gas from the first condenser then goes to several 

catalytic conversion stages, usually 2 to 3, 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.

4.2.11.2 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 from 1,093 to 1427 °C (2,000 to 2,600 °F), and as 

the temperature decreases, conversion increases dramatically.
Carbon Dioxide Capture Sensitivity Analysis

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Exhibit 4-9 Typical Three-Stage Claus Sulfur Plant

Claus plant sulfur recovery efficiency depends on many factors, including:

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.

4.2.11.3 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 
Carbon Dioxide Capture Sensitivity Analysis

211

feed streams, to provide operating flexibility at lower costs than would be the case for 

conventional Claus units. At least four of the recently built 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 1,593 to 1,649 °C (2,900 to 3,000 °F) as the enrichment moves beyond 

40 to 70 vol percent O2 in the oxidant feed stream. Although oxygen enrichment has many 

benefits, its 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 plant designs.

4.2.11.4 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 sulfur recovery unit. 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. For the GEE gasifier, the 

Claus plant tail gas is hydrogenated, water is separated, and the tail gas is compressed and 

returned to the SelexolTM process for further treatment. GEE experience at the Polk Power 

Station is not relevant to this study since the acid gas is converted to sulfuric acid rather than 

sulfur and the tail gas, containing 150-250 ppm SO2, is discharged through a dedicated stack

[46]. 

4.2.11.5 Flare Stack

A self-supporting, refractory-lined, carbon steel flare stack is typically provided to combust and 

dispose of unreacted gas during startup, shutdown, and upset conditions. However, in each 

IGCC plant design a flare stack was provided for syngas dumping during startup, shutdown, etc. 

This flare stack eliminates the need for a separate Claus plant flare.

4.2.12 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 
Carbon Dioxide Capture Sensitivity Analysis

212

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 GEE 

gasifier pressure boundary through the use of lockhoppers to a series of dewatering bins.

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 study, 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 transmit 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 

operating at nominal rated power. While the slag is suitable for use as a component of road 

paving mixtures, it was assumed in this study that the slag would be landfilled at a specified cost 

just as the ash from the PC boiler cases is assumed to be landfilled at the same per ton cost.

4.2.13 Power Island

4.2.13.1 Combustion Turbine 

The gas turbine generator selected for this application is representative of the advanced F Class 

turbines. This machine is an axial flow, single spool, and constant speed unit, with variable inlet 

guide vanes. 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 study, it was assumed that the 

advanced F Class turbine will be commercially available to support a 2015 startup date 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 firstof-a-kind applications, process contingencies were included in the cost estimates as described in 

Section 2.7. Performance typical of an advanced F class turbine on natural gas at ISO conditions 

is presented in Exhibit 4-10. 
Carbon Dioxide Capture Sensitivity Analysis

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Exhibit 4-10 Advanced F Class Combustion Turbine Performance

Characteristics Using Natural Gas

Advanced F Class

Firing Temperature Class, °C ( F) 1371+ (2500+)

Airflow, kg/s (lb/s) 431 (950)

Pressure Ratio 18.5

NOx Emissions, ppmv 25

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 some 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 

general arrangement. The generator is a standard hydrogen-cooled machine with static exciter.

4.2.13.2 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. The CT 

package scope of supply for combined cycle applications, while project specific, does not vary 

much from project-to-project. The typical scope of supply is presented in Exhibit 4-11.

Exhibit 4-11 Combustion Turbine Typical Scope of Supply

System System Scope

1.0 Engine Assembly Coupling to Generator, Dry Chemical Exhaust Bearing Fire Protection System, 

Insulation Blankets, Platforms, Stairs and Ladders

1.1 Engine Assembly 

with Bedplate

Variable Inlet Guide, Vane System Compressor, Bleed System, Purge Air System, 

Bearing Seal Sir System, Combustors, Dual Fuel Nozzles Turbine Rotor Air Cooler

1.2 Walk-in acoustical 

enclosure HVAC, Lighting, and Low Pressure CO2 Fire Protection System
Carbon Dioxide Capture Sensitivity Analysis

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System System Scope

2.0 Mechanical 

Package

HVAC and Lighting, Air Compressor for Pneumatic System, Low Pressure CO2

Fire Protection System

2.1

2.2

Lubricating Oil 

System and 

Control Oil 

System

Lube Oil Reservoir, Accumulators, 2x100% AC Driven Oil Pumps DC Emergency 

Oil Pump with Starter, 2x100% Oil Coolers, Duplex Oil Filter, Oil Temperature and 

Pressure Control Valves, Oil Vapor Exhaust Fans and Demister Oil Heaters Oil 

Interconnect Piping (SS and CS) Oil System Instrumentation Oil for Flushing and 

First Filling

3.0 Electrical Package

HVAC and Lighting, AC and DC Motor Control Centers, Generator Voltage 

Regulating Cabinet, Generator Protective Relay Cabinet, DC Distribution Panel, 

Battery Charger, Digital Control System with Local Control Panel (all control and 

monitoring functions as well as data logger and sequence of events recorder), 

Control System Valves and Instrumentation Communication link for interface with 

plant DCS Supervisory System, Bentley Nevada Vibration Monitoring System, Low 

Pressure CO2 Fire Protection System, Cable Tray and Conduit Provisions for 

Performance Testing including Test Ports, Thermowells, Instrumentation and DCS 

interface cards

4.0 Inlet And Exhaust 

Systems

Inlet Duct Trash Screens, Inlet Duct and Silencers, Self Cleaning Filters, Hoist 

System For Filter Maintenance, Evaporative Cooler System, Exhaust Duct 

Expansion Joint, Exhaust Silencers Inlet and Exhaust Flow, Pressure and 

Temperature Ports and Instrumentation

5.0 Fuel Systems

5.1 Fuel Syngas 

System

Gas Valves Including Vent, Throttle and Trip Valves Gas Filter/Separator Gas 

Supply Instruments and Instrument Panel

5.2 Backup Fuel 

System Specific to backup fuel type

6.0 Starting System Enclosure, Starting Motor or Static Start System, Turning Gear and Clutch 

Assembly, Starting Clutch Torque Converter

7.0 Generator

Static or Rotating Exciter (Excitation transformer to be included for a static 

system), Line Termination Enclosure with CTs, VTs, Surge Arrestors, and Surge 

Capacitors, Neutral Cubicle with CT, Neutral Tie Bus, Grounding Transformer, and 

Secondary Resistor, Generator Gas Dryer, Seal Oil System (including Defoaming 

Tank, Reservoir, Seal Oil Pump, Emergency Seal Oil Pump, Vapor Extractor, and 

Oil Mist Eliminator), Generator Auxiliaries Control Enclosure, Generator Breaker, 

Iso-Phase bus connecting generator and breaker, Grounding System Connectors

7.1 Generator Cooling 

TEWAC System (including circulation system, interconnecting piping and controls), 

or Hydrogen Cooling System (including H2 to Glycol and Glycol to Air heat 

exchangers, liquid level detector circulation system, interconnecting piping and 

controls)

8.0 Miscellaneous

Interconnecting Pipe, Wire, Tubing and Cable, Instrument Air System Including Air 

Dryer, On Line and Off Line Water Wash System, LP CO2 Storage Tank, Drain 

System, Drain Tanks, Coupling, Coupling Cover and Associated Hardware
Carbon Dioxide Capture Sensitivity Analysis

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4.2.13.3 CT Firing Temperature Control Issue for Low Calorific Value Fuel

A gas turbine when fired on low calorific value 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. [54] 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. Inlet guide vanes (IGV) 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 study, the firing temperature (defined as inlet rotor temperature) with CO2 capture is 

1,318–1,327 °C (2,405–2,420° F). A reduction in firing temperature with CO2 capture is done to 

maintain parts life as the water content of the combustion products increases to 14–16 vol%. 

The decrease in temperature also results in the lower temperature steam cycle with CO2 capture 

538 °C/538 °C [1,000 °F/1,000 °F].

4.2.13.4 Combustion Turbine Syngas Fuel Requirements 

Typical fuel specifications and contaminant levels for successful CT operation are presented for 

F Class machines in Exhibit 4-12 and Exhibit 4-13 [55]. 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 study.
Carbon Dioxide Capture Sensitivity Analysis

216

Exhibit 4-12 Typical Fuel Specification for 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) (1) Varies with gas 

pressure (2)

Flammability Limit Ratio, Rich-to-Lean, 

Volume Basis (3) 2:2.1

Sulfur (4)

Notes:

1. The maximum fuel temperature is defined in reference [56]

2. To ensure that the fuel gas supply to the gas turbine 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 [55]. 

3. Maximum flammability ratio limit is not defined. Fuel with flammability ratio significantly 

larger than those of natural gas may require start-up fuel

4. The quantity of sulfur in syngas is not limited by specification. Experience has shown that 

fuel sulfur levels up to 1 percent by volume do not significantly affect oxidation/corrosion 

rates. 

4.2.13.5 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 18.5:1 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 percent of the compressor air is extracted and 

integrated with the air supply of the ASU in Design 1. It may be technically possible to integrate 

the CT and ASU in CO2 capture cases (Designs 2–4) as well; however, in this study integration 

was considered only for Design 1.
Carbon Dioxide Capture Sensitivity Analysis

217

Exhibit 4-13 Allowable Gas Fuel Contaminant Level for 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 = 28 (1) 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 Total (2) 600 30 7.2 2.4

Above 10 microns 6 0.3 0.072 0.024

Notes:

1. Na/K=28 is nominal sea salt ratio

2. The fuel gas delivery system shall be designed to prevent generation or admittance of solid 

particulate to the gas turbine gas fuel system

Pressurized syngas is combusted in several (14) parallel diffusion combustors and syngas 

dilution is used to limit NOx formation. As described in Section 4.2.3.1 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 4.5–4.8 MJ/Nm3(120–128 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.

Limiting the water content reduces the need to de-rate firing temperature for the highhydrogen (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).

The low quality heat used in the syngas humidification process does not provide 

significant benefit to the process in other applications.

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 study nitrogen was chosen as the primary diluent based on suggestions by turbine industry 

experts during peer review of the report.
Carbon Dioxide Capture Sensitivity Analysis

218

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 566 °C (1,050 °F) with CO2 capture. 

Gross turbine power, as measured prior to the generator terminals, is 232 MW. The CT 

generator is a standard hydrogen-cooled machine with static exciter.

4.2.14 Steam Generation Island

4.2.14.1 Heat Recovery Steam Generator 

The heat recovery steam generator (HRSG) is a horizontal gas flow, drum-type, multi-pressure 

design that is matched to the characteristics of the gas turbine exhaust gas when firing mediumBtu 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 four IGCC plant designs.

The high pressure (HP) drum produces steam at main steam pressure, while the intermediate 

pressure (IP) drum produces process steam and turbine dilution steam, if required. The HRSG 

drum pressures are nominally 12.4/2.9 MPa (1,800/420 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 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 feedwater/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 gas turbine 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.

4.2.14.2 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).
Carbon Dioxide Capture Sensitivity Analysis

219

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 12.4 MPa/538 °C (1,800 psig/1,000

°F) with CO2 capture. The steam initially enters the turbine near the middle of the high-pressure 

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 2.6 to 2.9 

MPa/538 °C (375 to 420 psig/1,000 °F) with CO2 capture. 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, 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 a low-pressure 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 closed-loop oil seal system. The oil seal system consists of 

storage tank, pumps, filters, and pressure controls, all skid-mounted.

The steam turbine generator is controlled by a triple-redundant, microprocessor-based electrohydraulic control system. The system provides digital control of the unit in accordance with 

programmed control algorithms, color CRT operator interfacing, and datalink interfaces to the 

balance-of-plant DCS, and incorporates on-line repair capability.

4.2.14.3 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. 

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 
Carbon Dioxide Capture Sensitivity Analysis

220

discharging to the condenser is provided to maintain minimum flow requirements for the gland 

steam condenser and the condensate pumps. 

4.2.14.4 Feedwater System

The function of the feedwater system is to pump the various feedwater 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 three 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 feedwater pumps are supplied with instrumentation to monitor and alarm on low oil 

pressure, or high bearing temperature. Feedwater pump suction pressure and temperature are 

also monitored. In addition, the suction of each boiler feed pump is equipped with a startup 

strainer.

4.2.14.5 Main and Reheat Steam Systems

The function of the main steam system is to convey main steam generated in the synthesis gas 

cooler 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 reheater, and 

to the turbine reheat stop valves.

With CO2 capture, main steam at approximately 12.4 MPa/538 °C (1,800 psig/1,000 °F) 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 3.1 to 3.4 MPa/341 °C (450 

to 500 psia/645 °F) exits the HP turbine, flows through a motor-operated isolation gate valve, to 

the HRSG reheater. Hot reheat steam at approximately 2.9 MPa/538 °C (420 psia/1,000 °F) 

exits the HRSG reheater through a motor-operated 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.

4.2.14.6 Circulating Water System

The circulating water system 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 cooling 

system is a closed-loop process that utilizes a higher quality water to remove heat from 
Carbon Dioxide Capture Sensitivity Analysis

221

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 circulating water pumps, a mechanical 

draft evaporative cooling tower, and carbon steel 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.

4.2.14.7 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 water gas shift reactor(s) for appropriate plant 

designs, 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.

4.2.15 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.
Carbon Dioxide Capture Sensitivity Analysis

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4.2.16 Instrumentation and Control

An integrated plant-wide distributed control system (DCS) is provided. The DCS is a redundant 

microprocessor-based, functionally distributed control system. 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 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.

4.3 GEE IGCC CO2 Capture Sensitivity

The evaluation scope included developing heat and mass balances and estimating GEE IGCC 

power plant performance while gasifying bituminous Illinois No. 6 coal. Equipment lists were 

developed for each design to support plant capital and operating costs estimates. 

The IGCC plants are assumed to be built on a “green-field” site and utilize recirculating wet 

evaporative cooling systems for cycle heat rejection. Major systems for each plant (described in 

Section 4.2) include:

1. GEE radiant-only gasifier

2. ASU

3. Water gas shift

4. Acid gas removal

5. CO2 Recovery

6. Balance of Plant

Support facilities include coal handling (receiving, crushing, slurry preparation, and storing),

solid waste disposal, circulating water system with evaporative mechanical draft cooling towers, 

wastewater treatment, and other ancillary systems equipment necessary for an efficient, highly 

available, and completely operable facility. 
Carbon Dioxide Capture Sensitivity Analysis

223

The plant designs are based on using components suitable for a 30-year life, with provision for 

periodic maintenance and replacement of critical parts. All equipment is based on compliance 

with the latest applicable codes and standards. ASME, ANSI, IEEE, NFPA, CAA, state 

regulations, and OSHA codes are all adhered to in the design approach.

IGCC Plant Designs

The Case 2 IGCC plant designs used to analyze the full range of potential CO2 capture levels are 

shown in Exhibit 4-14. While each of these plant designs includes the process and ancillary 

equipment described in Section 4.2, the designs are unique in terms of the WGS and AGR 

sections. In particular, the WGS section, as described below, is different for each plant design. 

D1 has no WGS reactor. The minimum (0 percent) and maximum (25 percent) CO2

capture levels for this particular configuration are modeled. Due to the high level of 

integration between the H2S and CO2 absorbers, it is not feasible to model no CO2

capture with a two-stage SelexolTM system. Consequently, D1A (0 percent capture) 

employs a one-stage SelexolTM unit for H2S control, while D1B (25 percent capture) 

utilizes a two-stage SelexolTM unit to maximize CO2 capture from the unshifted 

syngas. D1 includes a COS hydrolysis unit to treat the entire syngas stream.

D2 has one-stage WGS with CO2 capture ranging from 25 percent (upper limit from 

D1) to the maximum achievable limit for this particular configuration (75 percent) by 

varying the WGS bypass ratio and the two-stage SelexolTM CO2 removal efficiency. 

The SelexolTM removal efficiency is changed by varying the solvent circulation rate, 

which changes the size and cost of the SelexolTM system. The combined syngas 

stream (shifted and unshifted gas) is routed through a COS hydrolysis unit.

D3 has two-stage WGS with CO2 capture ranging from 25 percent (upper limit from 

D1) to the maximum achievable limit for this particular configuration (85 percent) by 

varying the WGS bypass ratio and the two-stage SelexolTM CO2 removal efficiency. 

The SelexolTM removal efficiency is changed by varying the solvent circulation rate, 

which changes the size and cost of the SelexolTM system. The WGS bypass stream 

passes through a COS hydrolysis unit.

D4 has two-stage WGS and no bypass with CO2 capture ranging from 90 to 97

percent. To achieve greater than 90 percent CO2 removal, the two-stage SelexolTM 

CO2 removal efficiency is increased by raising the solvent circulation rate, which 

increases the size and cost of the SelexolTM system. D4 does not include a COS 

hydrolysis unit since sufficient COS to H2S conversion occurs across the two WGS 

reactors. 
Carbon Dioxide Capture Sensitivity Analysis

224

Exhibit 4-14 Case 2 GEE IGCC Plant Configuration Summary

Case CO2

Capture

CO2

Separation

Intended 

Storage Gasifier Steam psig/°F/°F Oxidant WGS Sulfur Control

D1A 0% N/A N/A

GEE

Radiant 

Only

1800/1050/1050 95 mol% 

O2

N/A

SelexolTM

D1B 25%

SelexolTM 

2

nd Stage

Saline 

Formation

N/A

D2A 25%

One-Stage 

with 

bypass

D2B 45%

D2C 60%

D2D 75%

D3A 25%

Two-Stage 

with 

bypass

D3B 45%

D3C 60%

D3D 75%

D3E 85%

D4A 90% Two-Stage 

without 

bypass

D4B 95%

D4C 97%

4.3.1 IGCC Design 1 – Without Water Gas Shift

Design 1 (D1) represents an IGCC plant without WGS reactors. As a result, the entire syngas 

stream is passed through a COS hydrolysis unit to ensure that the low sulfur levels required by 

local permitting agencies (this analysis assumes 0.0128 lb SO2/MMBtu) are achieved. 

The Case 2 D1 analysis involves the development of cost and performance estimates for no CO2

capture (D1A) and the maximum level of CO2 removal (25 percent) that can be achieved without 

WGS (D1B). Due to the high level of integration between the H2S and CO2 absorbers in the 

two-stage SelexolTM system (see Exhibit 4-8), it is assumed in this analysis that it is not possible 

to operate the two stages independently, and therefore is not feasible to model 0 percent CO2

capture with this system. Since the first stage is designed to operate synergistically with the 

second, some level of CO2 removal is unavoidable. Consequently, D1A (0 percent capture) 

employs a one-stage SelexolTM unit for H2S control, while D1B (25 percent capture) utilizes a 

two-stage SelexolTM unit to maximize CO2 capture from the unshifted syngas. 

The process block flow diagram for Case 2 D1A is shown in Exhibit 4-15. This process results 

in no CO2 removal since a one-stage SelexolTM unit is employed exclusively for H2S removal. 

Case 2 D1A also includes air integration between the ASU and CT (stream 21) where about 4

percent of the pressurized CT air supply is extracted, accounting for approximately 16.8 percent

of the total ASU air requirement. The corresponding stream tables for Case 2 D1A are contained 

in Exhibit 4-16.
Carbon Dioxide Capture Sensitivity Analysis

225

The process block flow diagram for Case 2 D1B is shown in Exhibit 4-17. To maximize CO2

removal, this process employs a two-stage SelexolTM unit for selective H2S removal and bulk 

CO2 capture. Note that D1B does not include air integration between the ASU and CT, which, 

along with a different heat integration scheme, explains the decreased coal feed rate observed for 

D1B. The corresponding stream tables for Case 2 D1B are contained in Exhibit 4-18. 

Overall performance for Case 2-D1 is summarized in Exhibit 4-19 which includes auxiliary 

power requirements.

Material and energy balance information, environmental performance and a major equipment list

are summarized in Sections 4.3.1.1 and 4.3.1.2. 
Carbon Dioxide Capture Sensitivity Analysis

226

Exhibit 4-15 Case 2 D1A Process Block Flow Diagram, IGCC without WGS (0% CO2 Removal)

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 ONE- STAGE SELEXOL UNIT CLAUS PLANT

SYNGAS H/P REHEAT

HRSG 2X ADVANCED F CLASS GAS TURBINE

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 24 464 MWe

7.5 MWe

276 MWe 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
Carbon Dioxide Capture Sensitivity Analysis

227

Exhibit 4-16 Case 2 D1A Stream Table, IGCC without CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12

V-L Mole Fraction

A r 0.0092 0.0237 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0068 0.0099

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

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

CO2 0.0003 0.0082 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1366 0.1078 0.1079 0.1586

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

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

H2O 0.0099 0.2114 0.0000 0.0003 0.0000 0.0000 0.9994 0.0000 0.1358 0.3181 0.3180 0.0012

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

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

N2 0.7732 0.5553 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0080 0.0063 0.0063 0.0092

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

O2 0.2074 0.2015 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

S O2 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

V-L Flowrate (kgmol/hr) 21,870 1,050 102 19,395 5,297 0 4,829 0 22,210 28,140 28,140 19,152

V-L Flowrate (kg/hr) 631,092 28,469 3,288 544,226 170,471 0 86,993 0 445,994 552,546 552,546 390,561

Solids Flowrate (kg/hr) 0 0 0 0 0 211,765 0 23,234 0 0 0 0

Temperature (°C) 15 20 32 93 32 15 146 1,316 677 223 223 35

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

Enthalpy (kJ/kg)A 30.23 36.86 26.67 92.52 26.67 --- 558.58 --- 1,424.13 1,066.72 1,066.62 40.35

Density (kg/m3) 1.2 1.6 11.0 24.4 11.0 --- 866.9 --- 13.9 26.7 26.3 41.9

V-L Molecular Weight 28.857 27.117 32.181 28.060 32.181 --- 18.015 --- 20.081 19.636 19.636 20.393

V-L Flowrate (lbmol/hr) 48,214 2,315 225 42,759 11,679 0 10,646 0 48,965 62,037 62,037 42,222

V-L Flowrate (lb/hr) 1,391,319 62,763 7,248 1,199,813 375,823 0 191,787 0 983,248 1,218,155 1,218,155 861,041

Solids Flowrate (lb/hr) 0 0 0 0 0 466,861 0 51,223 0 0 0 0

Temperature (°F) 59 68 90 199 90 59 295 2,400 1,250 433 433 95

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

Enthalpy (Btu/lb)A 13.0 15.8 11.5 39.8 11.5 --- 240.1 --- 612.3 458.6 458.6 17.3

Density (lb/ft3) 0.076 0.098 0.687 1.521 0.687 --- 54.120 --- 0.870 1.665 1.643 2.617

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

228

Exhibit 4-16 Case 2 D1A Stream Table, IGCC without CO2 Capture (continued)

13 14 15 16 17 18 19 20 21 22 23 24

V-L Mole Fraction

A r 0.0097 0.0000 0.0000 0.0040 0.0100 0.0100 0.0100 0.0092 0.0092 0.0089 0.0089 0.0000

CH4 0.0013 0.0000 0.0000 0.0000 0.0013 0.0013 0.0013 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.3977 0.0002 0.0000 0.0021 0.4089 0.4089 0.4089 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.1811 0.6125 0.0000 0.6947 0.1562 0.1562 0.1562 0.0003 0.0003 0.0807 0.0807 0.0000

COS 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.3812 0.0000 0.0000 0.0414 0.3920 0.3920 0.3920 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0012 0.0128 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 0.0000 0.0000

H2S 0.0086 0.1816 0.0000 0.0111 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0191 0.1905 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 0.0000 0.0000

O2 0.0000 0.0023 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.2074 0.1039 0.1039 0.0000

S O2 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 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 19,990 950 0 839 19,444 19,444 19,444 110,253 4,410 136,896 136,896 35,591

V-L Flowrate (kg/hr) 422,555 36,875 0 31,993 397,017 397,017 397,017 3,181,557 127,262 3,995,539 3,995,539 641,191

Solids Flowrate (kg/hr) 0 0 5,302 0 0 0 0 0 0 0 0 0

Temperature (°C) 35 45 174 38 45 241 196 15 432 589 132 561

Pressure (MPa, abs) 5.21 5.2 0.409 5.512 5.171 5.136 3.172 0.101 1.619 0.105 0.105 12.512

Enthalpy (kJ/kg)A 36.92 -1.2 --- -5.043 54.552 365.188 296.112 30.227 463.785 741.334 235.099 3,502.568

Density (kg/m3) 43.4 95.0 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 21.138 39 --- 38.147 20.419 20.419 20.419 28.857 28.857 29.187 29.187 18.015

V-L Flowrate (lbmol/hr) 44,071 2,095 0 1,849 42,866 42,866 42,866 243,066 9,723 301,803 301,803 78,466

V-L Flowrate (lb/hr) 931,574 81,295 0 70,533 875,273 875,273 875,273 7,014,133 280,565 8,808,656 8,808,656 1,413,583

Solids Flowrate (lb/hr) 0 0 11,688 0 0 0 0 0 0 0 0 0

Temperature (°F) 94 112 345 100 112 465 386 59 810 1,092 270 1,042

Pressure (psia) 755.0 750.0 59.3 799.5 750.0 745.0 460.0 14.7 234.9 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 15.9 -0.5 --- -2.2 23.5 157.0 127.3 13.0 199.4 318.7 101.1 1,505.8

Density (lb/ft3) 2.712 6 330.129 6.098 2.499 1.508 1.026 0.076 0.495 0.027 0.057 2.192

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

229

Exhibit 4-17 Case 2 D1B Process Block Flow Diagram, IGCC without WGS (25% CO2 Removal)

GAS TURBINE COMBUSTOR

TURBINE COOLING AIR

QUENCH AND SYNGAS SCRUBBER

GAS COOLING BFW HEATING & KNOCKOUT COS HYDROLYSIS

ELEVATED PRESSURE ASU

GEE GASIFIER SECTION (RADIANT COOLER)

SOUR WATER STRIPPER

MERCURY REMOVAL TWO- STAGE SELEXOL UNIT

CLAUS PLANT

HRSG

AMBIENT AIR

SYNGAS EXPANDER HYDROGENATION REACTOR AND GAS COOLER

CO2 COMPRESSION

1 5

9

10

11 12 13

16

18 19

20

17

6 8

2 3 4

21

22 23

AIR TO ASU

AS-RECEIVED COAL SLAG 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 ADVANCED F CLASS GAS TURBINE

SYNGAS H/P REHEAT

14

15

CLAUS PLANT OXIDANT STEAM TURBINE 24 281 MWe

5.8 MWe

464 MWe 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
Carbon Dioxide Capture Sensitivity Analysis

230

Exhibit 4-18 Case 2 D1B Stream Table, IGCC with 25% CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12

V-L Mole Fraction

A r 0.0092 0.0140 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0068 0.0100

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0009 0.0013

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2820 0.2820 0.4151

CO2 0.0003 0.0044 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.1090 0.1604

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

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2686 0.2686 0.3954

H2O 0.0099 0.1107 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3197 0.3195 0.0012

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

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0059 0.0086

N2 0.7732 0.7598 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0055 0.0081

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0016 0.0000

O2 0.2074 0.1112 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

S O2 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

V-L Flowrate (kgmol/hr) 26,011 1,933 94 18,697 5,251 0 4,786 0 21,971 27,854 27,854 18,924

V-L Flowrate (kg/hr) 750,612 53,323 3,014 524,635 168,970 0 86,227 0 442,069 547,801 547,801 386,853

Solids Flowrate (kg/hr) 0 0 0 0 0 209,901 0 23,030 0 0 0 0

Temperature (°C) 15 17 32 93 32 15 142 1,316 677 212 212 35

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 5.14

Enthalpy (kJ/kg)A 30.23 35.12 26.67 92.50 26.67 --- 537.77 --- 1,424.65 1,049.10 1,049.00 40.01

Density (kg/m3) 1.2 1.4 11.0 24.4 11.0 --- 872.0 --- 14.0 27.4 27.0 41.3

V-L Molecular Weight 28.857 27.587 32.181 28.060 32.181 --- 18.015 --- 20.121 19.667 19.667 20.443

V-L Flowrate (lbmol/hr) 57,346 4,261 206 41,220 11,576 0 10,552 0 48,437 61,407 61,407 41,720

V-L Flowrate (lb/hr) 1,654,817 117,556 6,645 1,156,623 372,515 0 190,099 0 974,594 1,207,695 1,207,695 852,865

Solids Flowrate (lb/hr) 0 0 0 0 0 462,752 0 50,772 0 0 0 0

Temperature (°F) 59 63 90 199 90 59 287 2,400 1,250 413 413 95

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 795.0 785.0 745.0

Enthalpy (Btu/lb)A 13.0 15.1 11.5 39.8 11.5 --- 231.2 --- 612.5 451.0 451.0 17.2

Density (lb/ft3) 0.076 0.089 0.687 1.521 0.687 --- 54.440 --- 0.871 1.710 1.688 2.575

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

231

Exhibit 4-18 Case 2 D1B Stream Table, IGCC with 25% CO2 Capture (continued)

13 14 15 16 17 18 19 20 21 22 23 24

V-L Mole Fraction

A r 0.0101 0.0118 0.0118 0.0118 0.0006 0.0037 0.0000 0.0228 0.0092 0.0091 0.0091 0.0000

CH4 0.0013 0.0015 0.0015 0.0015 0.0002 0.0009 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.4114 0.4813 0.4813 0.4813 0.0257 0.1675 0.0000 0.0031 0.0000 0.0000 0.0000 0.0000

CO2 0.1611 0.0260 0.0260 0.0260 0.9648 0.0000 0.0000 0.2380 0.0003 0.0599 0.0599 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 0.0000

H2 0.3973 0.4685 0.4685 0.4685 0.0085 0.1031 0.0000 0.6146 0.0000 0.0000 0.0000 0.0000

H2O 0.0012 0.0001 0.0001 0.0001 0.0000 0.0310 0.0000 0.0013 0.0099 0.0632 0.0632 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

H2S 0.0085 0.0000 0.0000 0.0000 0.0001 0.6923 0.0000 0.0036 0.0000 0.0000 0.0000 0.0000

N2 0.0091 0.0108 0.0108 0.0108 0.0001 0.0016 0.0000 0.1165 0.7732 0.7566 0.7566 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

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1112 0.1112 0.0000

S O2 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

V-L Flowrate (kgmol/hr) 19,096 16,093 16,093 16,093 2,754 235 0 173 110,253 137,400 137,400 35,014

V-L Flowrate (kg/hr) 389,636 263,433 263,433 263,433 119,071 6,868 0 2,783 3,181,557 3,969,626 3,969,626 630,792

Solids Flowrate (kg/hr) 0 0 0 0 0 0 5,253 0 0 0 0 0

Temperature (°C) 35 35 241 197 64 48 182 38 15 582 132 554

Pressure (MPa, abs) 5.1 4.999 4.964 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512

Enthalpy (kJ/kg)A 40.2 54.462 434.577 354.231 -107.672 100.083 --- 59.876 30.227 733.067 235.743 3,484.156

Density (kg/m3) 40.9 31.5 18.7 13.1 480.9 1.8 5,270.3 34.5 1.2 0.4 0.9 35.5

V-L Molecular Weight 20 16.370 16.370 16.370 43.231 29.259 --- 16.124 28.857 28.891 28.891 18.015

V-L Flowrate (lbmol/hr) 42,100 35,478 35,478 35,478 6,072 517 0 381 243,066 302,915 302,915 77,193

V-L Flowrate (lb/hr) 859,001 580,771 580,771 580,771 262,506 15,141 0 6,136 7,014,133 8,751,528 8,751,528 1,390,658

Solids Flowrate (lb/hr) 0 0 0 0 0 0 11,581 0 0 0 0 0

Temperature (°F) 95 95 465 387 147 119 360 100 59 1,080 270 1,030

Pressure (psia) 740.0 725.0 720.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 17.3 23.4 186.8 152.3 -46.3 43.0 --- 25.7 13.0 315.2 101.4 1,497.9

Density (lb/ft3) 3 1.969 1.166 0.819 30.024 0.112 329.017 2.152 0.076 0.027 0.056 2.218

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

232

Exhibit 4-19 Case 2 D1 Performance Modeling Results 

POWER SUMMARY (Gross Power at Generator 

Terminals, kWe)

D1A 

(0%)

D1B 

(25%)

Gas Turbine Power 464,000 464,000

Sweet Gas Expander Power 7,500 5,800

Steam Turbine Power 276,300 280,600

Total 747,800 750,400

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 459 457

Coal Milling 2,178 2,159

Sour Water Recycle Slurry Pump 183 181

Slag Handling 1,115 1,106

Air Separation Unit Auxiliaries 1,000 1,000

Air Separation Unit Main Air Compressor 53,817 64,010

Oxygen Compressor 10,255 10,164

Nitrogen Compressors 33,370 31,386

CO2 Compressor 0 8,410

Boiler Feedwater Pumps 3,975 3,968

Condensate Pump 235 249

Quench Water Pump 519 513

Circulating Water Pump 4,204 4,165

Ground Water Pumps 428 425

Cooling Tower Fans 2,172 2,152

Scrubber Pumps 216 212

Acid Gas Removal 2,588 4,807

Gas Turbine Auxiliaries 1,000 1,000

Steam Turbine Auxiliaries 100 100

Claus Plant/TGTU Auxiliaries 250 250

Claus Plant TG Recycle Compressor 2,085 828

Miscellaneous Balance of Plant 1

3,000 3,000

Transformer Losses 2,606 2,666

TOTAL AUXILIARIES, kWe 125,755 143,208

NET POWER, kWe 622,045 607,192

Net Plant Efficiency, % (HHV) 39.0% 38.4%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,238 (8,756) 9,380 (8,891)

Condenser Duty, GJ/hr (106Btu/hr) 1,540 (1,460) 1,625 (1,540)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 211,765 (466,861) 209,901 (462,752)

Thermal Input, kWth

2

1,596,183 1,582,134

Raw Water Withdrawal, m

3

/min (gpm) 17.9 (4,734) 17.8 (4,692)

Raw Water Consumption, m

3

/min (gpm) 14.2 (3,755) 14.1 (3,722)

Notes: 1. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage 

loads

2. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)
Carbon Dioxide Capture Sensitivity Analysis

233

4.3.1.1 Environmental Performance for Case 2 D1A and D1B

The environmental targets for emissions of Hg, NOx, SO2, and particulate matter were presented 

in Section 2.4. A summary of the plant air emissions for Case 2 D1A and D1B is presented in 

Exhibit 4-20.

For Case 2 D1A and D1B, SO2 emissions are controlled by sulfur capture across the one-stage 

and two-stage SelexolTM AGR processes, respectively. The one-stage SelexolTM unit removes 

over 99 percent of the sulfur compounds in the fuel gas down to a level of less than 15 ppmv, 

resulting in a concentration in the flue gas of less than 3 ppmv. For D1B, the clean syngas 

exiting the two-stage SelexolTM unit has a sulfur concentration of less than 10 ppmv, resulting in 

a concentration in the flue gas of less than 2 ppmv. The H2S-rich regeneration gas produced in 

both D1A and D1B 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 SelexolTM unit, 

thereby eliminating the need for a tail gas treatment unit. 

For both D1A and D1B, 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 incinerated in the Claus plant burner. 

This also assists in lowering NOx levels. 

Particulate discharge to the atmosphere for D1A and D1B 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.

Ninety-five percent of the mercury is captured from the syngas by an activated carbon bed. 

For D1A, CO2 emissions represent the uncontrolled discharge from the process. The carbon 

balance for D1A is shown in Exhibit 4-21. The carbon input to the plant consists of carbon in 

the air and coal. Carbon in the air is not neglected here since the Aspen Plus® model accounts 

for air components throughout. Carbon leaves the plant as unburned carbon in the slag, as 

dissolved CO2 in the wastewater blowdown stream, and as CO2 in the stack gas and ASU vent 

gas. Carbon in the wastewater blowdown stream is calculated by difference to close the material 

balance.

Twenty-five percent of the CO2 from the syngas in D1B is captured in the two-stage SelexolTM 

unit and compressed for sequestration. The carbon balance for D1B is also shown in

Exhibit 4-21. The carbon input to the plant consists of carbon in the air and 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, as dissolved CO2 in the wastewater blowdown 

stream, and as CO2 in the stack gas, ASU vent gas, and the captured CO2 product. Carbon in the 

wastewater blowdown stream is calculated by difference to close the material balance. The 

carbon capture efficiency is defined as the pounds of carbon in the CO2 product stream relative 

to the amount of carbon in the coal, less carbon contained in the slag, represented by the 

following fraction:

(Carbon in CO2 Product)/[(Carbon in the Coal)-(Carbon in Slag)] or

72,256/(294,980-5,900)*100 = 25.0% 
Carbon Dioxide Capture Sensitivity Analysis

234

Exhibit 4-22 shows the sulfur balance for Case 2 D1A and D1B. Sulfur input comes solely from 

the sulfur in the coal. Sulfur output includes the pounds of sulfur recovered in the Claus plant, 

dissolved SO2 in the wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in 

the slag is considered to be negligible, and the sulfur content of the blowdown stream is 

calculated by difference to close the material balance. The total sulfur capture is represented by 

the following fraction:

(Sulfur byproduct/Sulfur in the coal) or

(11,688/11,701)*100 = 99.8% (D1A)

(11,581/11,598)*100 = 99.8% (D1B) 

The overall water balances for Case 2 D1A and D1B are shown in Exhibit 4-23 and Exhibit 4-24, 

respectively. Raw water is obtained from groundwater (50 percent) and from municipal sources 

(50 percent). Water demand represents the total amount of water required for a particular 

process. Some water is recovered within the process and that water is reused as internal recycle. 

Raw water withdrawal is the difference between water demand and internal recycle. Process 

water discharged from the power plant is also accounted for in this study. Raw water 

consumption represents raw water withdrawal less process water discharge.

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 4-25 through 

Exhibit 4-30.

Gasifier and ASU

Syngas Cleanup

Power Block

An overall plant energy balance is provided in tabular form for Case 2 D1A and D1B in 

Exhibit 4-31 and Exhibit 4-32, respectively. The power out is the combined combustion turbine, 

steam turbine and expander power after generator losses. In addition, energy balance Sankey 

diagrams are provided for D1A and D1B in Exhibit 4-33 and Exhibit 4-34, respectively.

Exhibit 4-20 Case 2 D1 Estimated Air Emission Rates

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

85% capacity factor

kg/MWh

(lb/MWh)

D1A D1B D1A D1B D1A D1B

SO2

0.002 

(0.005)

0.001 

(0.002)

84 (93) 37 (40) 0.016 (0.04) 0.007 (0.02)

NOX

0.025

(0.059)

0.024

(0.055)

1,023 (1,128) 947 (1,044) 0.195 (0.430) 0.180 (0.397)

PM

0.003

(0.0071)

0.003

(0.0071)

123 (135) 122 (134) 0.023 (0.052) 0.023 (0.051)

Hg 0.246x10-6

(0.571x10-6)

0.246x10-6

(0.571x10-6)

0.010 (0.011) 0.010 (0.011) 1.89x10-6

(4.16x10-6)

1.87x10-6

(4.11x10-6)

CO2 84.6 (196.8) 63.5 (147.8)

3,407,608 

(3,756,245)

2,536,560

(2,796,079)

650 (1,434) 482 (1,063)

CO2 net 782 (1,723) 596 (1,314)
Carbon Dioxide Capture Sensitivity Analysis

235

Exhibit 4-21 Case 2 D1 Carbon Balance

Carbon In, kg/hr (lb/hr)

D1A D1B

Coal 134,989 (297,599) 133,801 (294,980)

Air (CO2) 518 (1,143) 535 (1,179)

Total 135,507 (298,742) 134,336 (296,159)

Carbon Out, kg/hr (lb/hr)

Slag 2,700 (5,952) 2,676 (5,900)

Stack Gas 132,704 (292,563) 98,783 (217,779)

ASU Vent 103 (227) 102 (225)

CO2 Product 0 (0) 32,775 (72,256)

Convergence Tolerance 0 (0) 0 (-1)

Total 135,507 (298,742) 134,336 (296,159)

Exhibit 4-22 Case 2 D1 Sulfur Balance

Sulfur In, kg/hr (lb/hr)

D1A D1B

Coal 5,308 (11,701) 5,261 (11,598)

Total 5,308 (11,701) 5,261 (11,598)

Sulfur Out, kg/hr (lb/hr)

Elemental Sulfur 5,302 (11,688) 5,253 (11,581)

Stack Gas 6 (13) 3 (6)

CO2 Product 0 (0) 5 (12)

Convergence Tolerance 0 (0) 0 (-1)

Total 5,308 (11,701) 5,261 (11,598)
Carbon Dioxide Capture Sensitivity Analysis

236

Exhibit 4-23 Case 2 D1A (0%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Slag Handling 0.50 (133) 0.50 (133) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.7 (726) 0.90 (237) 1.9 (489) 0.0 (0) 1.9 (489)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (8) -0.03 (-8)

Condenser Makeup 0.2 (54) 0.0 (0) 0.2 (54) 0.0 (0) 0.2 (54)

 Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

 Shift Steam 0.0 (0) 0.0 (0) 0.0 (0)

 CT Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

 BFW Makeup 0.20 (54) 0.0 (0) 0.20 (54)

Cooling Tower 16.4 (4,321) 0.49 (129) 15.9 (4,191) 3.7 (972) 12.2 (3,220)

 BFW Blowdown 0.0 (0) 0.20 (54) -0.20 (-54)

 SWS Blowdown 0.0 (0) 0.29 (75) -0.29 (-75)

 SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

 Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 21.3 (5,617) 3.34 (883) 17.9 (4,734) 3.7 (979) 14.2 (3,755)

Total, gal/MWhnet 542 85 457 94 362
Carbon Dioxide Capture Sensitivity Analysis

237

Exhibit 4-24 Case 2 D1B (25%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Slag Handling 0.50 (132) 0.50 (132) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.7 (719) 0.88 (232) 1.8 (487) 0.0 (0) 1.8 (487)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7) -0.03 (-7)

Condenser Makeup 0.2 (55) 0.0 (0) 0.2 (55) 0.0 (0) 0.2 (55)

 Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

 Shift Steam 0.0 (0) 0.0 (0) 0.0 (0)

 CT Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

 BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 16.2 (4,280) 0.49 (129) 15.7 (4,150) 3.6 (963) 12.1 (3,188)

 BFW Blowdown 0.0 (0) 0.21 (55) -0.21 (-55)

 SWS Blowdown 0.0 (0) 0.28 (74) -0.28 (-74)

 SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

 Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 21.1 (5,566) 3.31 (874) 17.8 (4,692) 3.7 (970) 14.1 (3,722)

Total, gal/MWhnet 550 86 464 96 368
Carbon Dioxide Capture Sensitivity Analysis

238

This page intentionally left blank
Carbon Dioxide Capture Sensitivity Analysis

239

Exhibit 4-25 Case 2 D1A (0%) Heat and Mass Balance, GEE Gasifier and ASU

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D1A HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D1A (0%) GEE GASIFIER ASU AND GASIFICATION DWG. NO. CCSA-HMB-CS-2-D1A-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 1 OF 3

Ambient Air Four Stage Air Compressor

Elevated Pressure ASU Four Stage N2 Compressor

Four Stage O2 Compressor

ASU Vent

Water

Steam

Gross Plant Power: 748 MWe Auxiliary Load: 126 MWe Net Plant Power: 622 MWe Net Plant Efficiency, HHV: 39.0% Net Plant Heat Rate: 8,756 BTU/KWe

N2 to GT Combustor 1,391,319 W 59.0 T 14.7 P 13.0 H

375,823 W 90.0 T 125.0 P 11.5 H

375,823 W 241.2 T 940.0 P 40.8 H

To Claus Plant 7,248 W 90.0 T 125.0 P 11.5 H

62,763 W 68.3 T 16.4 P 15.8 H

1,074,227 W 90.0 T 56.4 P 14.2 H

150,581 W 50.0 T 182.0 P 2.9 H 5

1

3

2

Slurry Mix Tank

Milled Coal

Slag

466,861 W 59.0 T 14.7 P

191,787 W 295.0 T 840.0 P 240.1 H

51,223 W 2,400.0 T 815.0 P

1,199,813 W 389.0 T 384.0 P 88.2 H

658,648 W 159.7 T 840.0 P 2,933.2 H

1,390,077 W 100.0 T 189.5 P 18.0 H

6

Air From GT Compressor

280,565 W 220.0 T 224.9 P 50.9 H

280,565 W 809.8 T 234.9 P 199.4 H 1,199,813 W 199.0 T 384.0 P 39.8 H 21

HP BFW

N2 to AGR N2 Boost Compressor 24,994 W 199.0 T 384.0 P 39.8 H 24,994 W 376.3 T 785.0 P 84.2 H

Saturated Steam To HRSG HP Superheater

GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank

Knockout Drum

Vent To Claus Unit

Raw Fuel Gas

CWS

CWR

Fines

Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench Section Drag Conveyor

4

983,248 W 1,250.0 T 805.0 P 612.3 H 1,218,155 W 402.9 T 800.0 P 445.7 H

Syngas Quench

1,346,301 W 450.0 T 805.0 P 535.7 H

8

9

Sour Water

7
Carbon Dioxide Capture Sensitivity Analysis

240

Exhibit 4-26 Case 2 D1A (0%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum

Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water

Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out

From ASU Syngas Coolers

Sour Stripper

1,218,155 W 402.9 T 800.0 P 457.9 H

931,574 W 94.2 T 755.0 P 15.9 H 81,295 W 112.2 T 750.0 P

875,273 W 385.6 T 460.0 P 127.3 H

11,688 W 79,709 W 450.0 T 58.9 P 249.6 H 2,855 W 234.5 T 65.0 P 405.2 H 7,248 W 90.0 T 125.0 P 11.5 H NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D1A HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D1A (0%) GEE GASIFIER GAS CLEANUP SYSTEM DWG. NO. CCSA-HMB-CS-2-D1A-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 2 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 748 MWe Auxiliary Load: 126 MWe Net Plant Power: 622 MWe Net Plant Efficiency, HHV: 39.0% Net Plant Heat Rate: 8,756 BTU/KWe

15

12 16

CO2

Tailgas

Tail Gas Cleanup Unit Tail Gas Compressor 71,385 W 120.0 T 56.8 P 32.0 H

861,041 W 95.3 T 760.0 P 17.3 H

9,176 W 118.2 T 56.8 P 44.4 H

3 70,533 W 100.0 T 799.5 P Raw Syngas

17 875,273 W 112.2 T 750.0 P 23.5 H

Claus Oxygen Preheater

7,248 W 450.0 T 124.5 P 91.9 H

COS Hydrolysis 1,218,155 W 432.7 T 785.0 P 458.6 H

COS Hydrolysis Preheater

1,218,155 W 432.9 T 795.0 P 458.6 H

10 11 Clean Gas Acid Gas

13

AGR- Selexol

14

Fuel Gas Expander Fuel Gas To GT 19 875,273 W 465.0 T 745.0 P 157.0 H

18

N2 to AGR

24,994 W 376.3 T 785.0 P 84.2 H
Carbon Dioxide Capture Sensitivity Analysis

241

Exhibit 4-27 Case 2 D1A (0%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine

Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator

Ip Extraction Steam To 250 PSIA Header

LP Process Header

Blowdown Flash To WWT

Gland Steam Condenser Condensate to Gasification Island

HP BFW to Radiant Syngas Cooler HP Saturated Steam to HRSG Superheater

LP Turbine

Stack

Compressor Expander

Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class Gas Turbine

MP Flash Bottoms LP Flash Tops 1,199,813 W 385.0 T 389.0 P 87.2 H

7,014,133 W 59.0 T 14.7 P 13.0 H 1,581,157 W 101.1 T 1.0 P 69.1 H

8,808,656 W 269.7 T 15.2 P 101.1 H

875,273 W 385.6 T 460.0 P 127.3 H

8,808,656 W 1,092.5 T 15.2 P 318.7 H From Gasifier Island Preheating

To Claus

LP BFW 1,413,583 W 1,042.5 T 1,814.7 P 1,505.8 H

9,644 W 298.0 T 65.0 P 1,179.0 H 1,440,575 W 278.8 T 2,250.7 P 252.3 H 26,992 W 585.0 T 2,000.7 P 593.3 H

1,542,232 W 511.9 T 65.0 P 1,288.0 H

1,581,157 W 103.2 T 120.0 P 71.4 H

1,581,157 W 235.0 T 105.0 P 203.7 H

1,400 W 661.7 T 65.0 P 1,361.8 H 1,400 W 212.0 T 14.7 P 179.9 H

IP Pump NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D1A HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D1A (0%) GEE GASIFIER POWER BLOCK SYSTEM DWG. NO. CCSA-HMB-CS-2-D1A-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 3 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 748 MWe Auxiliary Load: 126 MWe Net Plant Power: 622 MWe Net Plant Efficiency, HHV: 39.0% 20 Net Plant Heat Rate: 8,756 BTU/KWe

22

24 19

23

Flue Gas

HOT WELL CONDENSER Make-up 27,010 W 59.0 T 14.7 P 27.1 H

8,823 W 701.5 T 501.4 P 1,357.9 H 8,315 W 661.7 T 65.0 P 1,361.8 H 35,555 W 897.7 T 280.0 P 1,472.6 H 781 W 1,042.5 T 1,814.7 P 1,505.8 H 1,312 W 540.5 T 65.0 P 1,302.1 H

Air Extraction 280,565 W 809.8 T 234.9 P 199.4 H

21
Carbon Dioxide Capture Sensitivity Analysis

242

Exhibit 4-28 Case 2 D1B (25%) Heat and Mass Balance, GEE Gasifier and ASU

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D1B HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D1B (25%) GEE GASIFIER ASU AND GASIFICATION DWG. NO. CCSA-HMB-CS-2-D1B-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 1 OF 3

Ambient Air Four Stage Air Compressor

Elevated Pressure ASU Four Stage N2 Compressor

Four Stage O2 Compressor

ASU Vent

Water

Steam

Gross Plant Power: 750 MWe Auxiliary Load: 143 MWe Net Plant Power: 607 MWe Net Plant Efficiency, HHV: 38.4% Net Plant Heat Rate: 8,891 BTU/KWe

1,654,817 W 59.0 T 14.7 P 13.0 H

372,515 W 90.0 T 125.0 P 11.5 H

372,515 W 241.2 T 940.0 P 40.8 H

To Claus Plant 6,645 W 90.0 T 125.0 P 11.5 H

117,556 W 63.4 T 16.4 P 15.1 H

1,007,579 W 90.0 T 56.4 P 14.2 H

149,043 W 50.0 T 182.0 P 2.9 H 5

1

3

2

Slurry Mix Tank

Milled Coal

Slag

462,752 W 59.0 T 14.7 P

190,099 W 287.0 T 840.0 P 231.2 H

50,772 W 2,400.0 T 815.0 P

652,851 W 156.4 T 840.0 P 2,950.2 H

100.0 T 189.5 P 18.0 H

6

HP BFW

Saturated Steam To HRSG HP Superheater

GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank

Knockout Drum

Vent To Claus Unit

Raw Fuel Gas

CWS

CWR

Fines

Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench Section Drag Conveyor

974,594 W 1,250.0 T 805.0 P 612.5 H 1,207,695 W 403.3 T 800.0 P 446.7 H

Syngas Quench

1,334,052 W 450.0 T 805.0 P 536.1 H

8

9

Sour Water

7

N2 to GT Combustor 1,156,623 W 385.0 T 384.0 P 87.2 H 1,156,623 W 199.0 T 384.0 P 39.8 H N2 to GT Combustor N2 Boost Compressor 0 W 199.0 T 384.0 P 39.8 H 0 W 385.0 T 469.0 P 87.0 H 4

1,156,623 W 199.0 T 384.0 P 39.8 H
Carbon Dioxide Capture Sensitivity Analysis

243

Exhibit 4-29 Case 2 D1B (25%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum

Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water

Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out

From ASU Syngas Coolers

Sour Stripper

1,207,695 W 403.3 T 800.0 P 446.7 H

859,001 W 94.7 T 740.0 P 17.3 H 15,141 W 119.0 T 23.7 P

580,771 W 386.9 T 460.0 P 152.3 H

11,581 W 12,718 W 450.0 T 12.3 P 850.9 H 2,512 W 240.3 T 65.0 P 445.4 H 6,645 W 90.0 T 125.0 P 11.5 H NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D1B HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D1B (25%) GEE GASIFIER GAS CLEANUP SYSTEM DWG. NO. CCSA-HMB-CS-2-D1B-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 2 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 750 MWe Auxiliary Load: 143 MWe Net Plant Power: 607 MWe Net Plant Efficiency, HHV: 38.4% Net Plant Heat Rate: 8,891 BTU/KWe

19

12

CO2

Tailgas

Tail Gas Cleanup Unit 7,222 W 120.0 T 10.6 P 202.7 H

852,865 W 94.8 T 745.0 P 17.2 H

6,582 W 116.7 T 10.6 P 42.7 H

3 6,136 W 100.0 T Raw Syngas 799.5 P

14 580,771 W 94.7 T 725.0 P 23.4 H

Claus Oxygen Preheater

6,645 W 450.0 T 124.5 P 91.9 H

COS Hydrolysis 1,207,695 W 413.2 T 785.0 P 451.0 H

COS Hydrolysis Preheater

1,207,695 W 413.3 T 795.0 P 451.0 H

10 11

13 18

Fuel Gas Expander Fuel Gas To GT 16 580,771 W 465.0 T 720.0 P 186.8 H

15

Multistage Intercooled CO2 Compressor Interstage Knockout

CO2 Product 17 262,506 W 146.8 T 2,214.7 P

Two-Stage Selexol

Clean Gas

CO2

Acid Gas

Tail Gas Compressor

20
Carbon Dioxide Capture Sensitivity Analysis

244

Exhibit 4-30 Case 2 D1B (25%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine

Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator

Ip Extraction Steam To 250 PSIA Header

LP Process Header

Blowdown Flash To WWT

Gland Steam Condenser Condensate to Gasification Island

HP BFW to Radiant Syngas Cooler HP Saturated Steam to HRSG Superheater

LP Turbine

Stack

Compressor Expander

Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class Gas Turbine

MP Flash Bottoms LP Flash Tops

7,014,133 W 59.0 T 14.7 P 13.0 H 1,678,735 W 101.1 T 1.0 P 69.1 H

8,751,528 W 269.9 T 15.2 P 101.4 H

580,771 W 386.9 T 460.0 P 152.3 H

8,751,528 W 1,079.5 T 15.2 P 315.2 H From Gasifier Island Preheating

To Claus

LP BFW 1,390,658 W 1,029.5 T 1,814.7 P 1,497.9 H

10,077 W 298.0 T 65.0 P 1,179.0 H 1,418,866 W 278.8 T 2,250.7 P 252.3 H 28,203 W 585.0 T 2,000.7 P 593.3 H

1,639,262 W 493.0 T 65.0 P 1,278.6 H

1,678,735 W 103.1 T 120.0 P 71.3 H

1,678,735 W 235.0 T 105.0 P 203.7 H

1,400 W 649.4 T 65.0 P 1,355.7 H 1,400 W 212.0 T 14.7 P 179.9 H

IP Pump NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D1B HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D1B (25%) GEE GASIFIER POWER BLOCK SYSTEM DWG. NO. CCSA-HMB-CS-2-D1B-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 3 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 750 MWe Auxiliary Load: 143 MWe Net Plant Power: 607 MWe Net Plant Efficiency, HHV: 38.4% Net Plant Heat Rate: 8,891 BTU/KWe 21

22

24 16

23

Flue Gas

HOT WELL CONDENSER Make-up 27,495 W 59.0 T 14.7 P 27.1 H

8,875 W 690.6 T 501.4 P 1,351.7 H 9,579 W 649.4 T 65.0 P 1,355.7 H 25,433 W 885.6 T 280.0 P 1,466.3 H 785 W 1,029.5 T 1,814.7 P 1,497.9 H 1,318 W 531.1 T 65.0 P 1,297.4 H
Carbon Dioxide Capture Sensitivity Analysis

245

Exhibit 4-31 Case 2 D1A (0%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,746 

(5,446) 4.8 (4.6) 0 (0) 5,751 (5,451)

ASU Air 0 (0) 19.1 (18.1) 0 (0) 19 (18)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 67.4 (63.9) 0 (0) 67 (64)

Totals 5,746 

(5,446) 187.4 (177.7) 0 (0) 5,934 (5,624)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.0 (1.0) 0 (0) 1 (1)

Slag 89 (84) 36.3 (34.4) 0 (0) 125 (118)

Sulfur 49 (47) 0.6 (0.6) 0 (0) 50 (47)

Gasifier Heat Loss 0 (0) 41.2 (39.0) 0 (0) 41 (39)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 939 (890) 0 (0) 939 (890)

Cooling Tower* 0 (0) 1,986 (1,882) 0 (0) 1,986 

(1,882)

Process Losses** 0 (0) 489 (464) 0 (0) 489 (464)

Net Power 0 (0) 0.0 (0.0) 2,239 

(2,123)

2,239 

(2,123)

Totals 138 (130) 3,557 (3,371) 2,239 

(2,123)

5,934 

(5,624)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Includes Condenser, Cooling Tower Blowdown, and the following Non-Condenser 

 Cooling Tower Loads: ASU compressor intercoolers, CO2 compressor intercoolers,

 sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

 air cooler.

** Calculated by difference to close the energy balance.
Carbon Dioxide Capture Sensitivity Analysis

246

Exhibit 4-32 Case 2 D1B (25%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,696 

(5,398) 4.8 (4.5) 0 (0) 5,700 (5,403)

ASU Air 0 (0) 22.7 (21.5) 0 (0) 23 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 66.8 (63.3) 0 (0) 67 (63)

Totals 5,696 

(5,398) 190.4 (180.5) 0 (0) 5,886 (5,579)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.9 (1.8) 0 (0) 2 (2)

Slag 88 (83) 36.0 (34.1) 0 (0) 124 (117)

Sulfur 49 (46) 0.6 (0.6) 0 (0) 49 (47)

CO2 0 (0) -12.8 (-12.2) 0 (0) -13 (-12)

Gasifier Heat Loss 0 (0) 42.4 (40.2) 0 (0) 42 (40)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 936 (887) 0 (0) 936 (887)

Cooling Tower* 0 (0) 2,072 (1,964) 0 (0) 2,072 

(1,964)

Process Losses** 0 (0) 424 (402) 0 (0) 424 (402)

Net Power 0 (0) 0.0 (0.0) 2,186 

(2,072)

2,186 

(2,072)

Totals 136 (129) 3,564 (3,378) 2,186 

(2,072)

5,886 

(5,579)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Includes Condenser, Cooling Tower Blowdown, and the following Non-Condenser 

 Cooling Tower Loads: ASU compressor intercoolers, CO2 compressor intercoolers,

 sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

 air cooler.

** Calculated by difference to close the energy balance.
Carbon Dioxide Capture Sensitivity Analysis

247

Exhibit 4-33 Case 2 D1A Energy Balance Sankey Diagram

Exhibit 4-34 Case 2 D1B Energy Balance Sankey Diagram
Carbon Dioxide Capture Sensitivity Analysis

248

4.3.1.2 Major Equipment List for Case 2 D1

Major equipment items for Case 2 D1A and D1B are shown in the following tables. The accounts used in the equipment list 

correspond to the account numbers used in the cost estimates. 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. 

ACCOUNT 1 COAL HANDLING

Equipment 

No. Description Type

Design Conditions Opr Qty.

D1A D1B (Spares)

1

Bottom Trestle Dumper and Receiving 

Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0)

3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

4 Transfer Tower No. 1 Enclosed N/A N/A 1 (0)

5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

6 As-Received Coal Sampling System Two-stage N/A N/A 1 (0)

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

8 Reclaim Hopper N/A 45 tonne (50 ton) 45 tonne (50 ton) 2 (1)

9 Feeder Vibratory 172 tonne/hr (190 tph) 172 tonne/hr (190 tph) 2 (1)

10 Conveyor No. 3 Belt w/ tripper 354 tonne/hr (390 tph) 345 tonne/hr (380 tph) 1 (0)

11 Crusher Tower N/A N/A N/A 1 (0)

12 Coal Surge Bin w/ Vent Filter Dual outlet 172 tonne (190 ton) 172 tonne (190 ton) 2 (0)

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0) 2 (0)

14 As-Fired Coal Sampling System Swing hammer N/A N/A 1 (1)

15 Conveyor No. 4 Belt w/tripper 354 tonne/hr (390 tph) 345 tonne/hr (380 tph) 1 (0)

16 Transfer Tower No. 2 Enclosed N/A N/A 1 (0)

17 Conveyor No. 5 Belt w/ tripper 354 tonne/hr (390 tph) 345 tonne/hr (380 tph) 1 (0)

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 816 tonne (900 ton) 726 tonne (800 ton) 3 (0)
Carbon Dioxide Capture Sensitivity Analysis

249

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type

Design Condition Opr Qty.

D1A D1B (Spares)

1 Feeder Vibratory 82 tonne/h (90 tph) 73 tonne/h (80 tph) 3 (0)

2 Conveyor No. 6 Belt w/tripper 236 tonne/h (260 tph) 227 tonne/h (250 tph) 1 (0)

3 Rod Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 463 tonne (510 ton) 1 (0)

4 Weigh Feeder Belt 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)

5 Rod Mill Rotary 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)

6

Slurry Water Storage 

Tank with Agitator Field erected 287,504 liters (75,950 gal) 284,968 liters (75,280 gal) 2 (0)

7 Slurry Water Pumps Centrifugal 795 lpm (210 gpm) 795 lpm (210 gpm) 2 (1)

8 Trommel Screen Coarse 163 tonne/h (180 tph) 163 tonne/h (180 tph) 2 (0)

9

Rod Mill Discharge Tank 

with Agitator Field erected 376,084 liters (99,350 gal) 372,790 liters (98,480 gal) 2 (0)

10 Rod Mill Product Pumps Centrifugal 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 2 (2)

11 Slurry Storage Tank with 

Agitator Field erected 1,128,440 liters (298,100 gal)

1,118,220 liters 

(295,400 gal) 2 (0)

12 Slurry Recycle Pumps Centrifugal 6,435 lpm (1,700 gpm) 6,057 lpm (1,600 gpm) 2 (2)

13 Slurry Product Pumps Positive 

displacement 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 2 (2)

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment 

No. Description Type

Design Condition Opr Qty.

D1A D1B (Spares)

1

Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 1,082,628 liters (286,000 gal) 1,086,413 liters (287,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 6,624 lpm @ 91 m H2O

(1,750 gpm @ 300 ft H2O)

7,041 lpm @ 91 m H2O

(1,860 gpm @ 300 ft H2O) 2 (1)

3

Deaerator (integral w/ 

HRSG) Horizontal spray type 493,508 kg/hr (1,088,000 lb/hr)

483,983 kg/hr 

(1,067,000 lb/hr) 2 (0)

4

Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

8,366 lpm @ 27 m H2O

(2,210 gpm @ 90 ft H2O)

8,101 lpm @ 27 m H2O

(2,140 gpm @ 90 ft H2O) 2 (1)
Carbon Dioxide Capture Sensitivity Analysis

250

Equipment 

No. Description Type

Design Condition Opr Qty.

D1A D1B (Spares)

5

High Pressure Feedwater 

Pump No. 1

Barrel type, multistage, centrifugal

HP water: 6,246 lpm @ 1,859 

m H2O (1,650 gpm @ 6,100 ft 

H2O)

HP water: 6,132 lpm @ 1,859 

m H2O (1,620 gpm @ 6,100 

ft H2O)

2 (1)

6

High Pressure Feedwater 

Pump No. 2

Barrel type, multistage, centrifugalIP water: 1,060 lpm @ 223 m 

H2O (280 gpm @ 730 ft H2O)

IP water: 1,476 lpm @ 223 m 

H2O (390 gpm @ 730 ft H2O) 2 (1)

7 Auxiliary Boiler Shop fabricated, water 

tube

18,144 kg/hr, 2.8 MPa, 343°C

(40,000 lb/hr, 400 psig, 650°F)

18,144 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)

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) 28 m3/min (1,000 scfm) 2 (1)

10 Closed Cylce Cooling 

Heat Exchangers Plate and frame 247 GJ/hr (233.7595997 MMBtu/hr) each

247 GJ/hr (234.1323798 

MMBtu/hr) each 2 (0)

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 88,579 lpm @ 21 m H2O(23,400 gpm @ 70 ft H2O)

88,579 lpm @ 21 m H2O

(23,400 gpm @ 70 ft H2O) 2 (1)

12 Engine-Driven Fire Pump Vertical turbine, diesel 

engine

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O) 1 (1)

13 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O) 1 (1)

14 Raw Water Pumps Stainless steel, single 

suction

4,618 lpm @ 18 m H2O

(1,220 gpm @ 60 ft H2O)

4,580 lpm @ 18 m H2O

(1,210 gpm @ 60 ft H2O) 2 (1)

15 Ground Water Pumps Stainless steel, single 

suction

3,066 lpm @ 268 m H2O 

(810 gpm @ 880 ft H2O)

3,028 lpm @ 268 m H2O 

(800 gpm @ 880 ft H2O) 3 (1)

16 Filtered Water Pumps Stainless steel, single 

suction

2,082 lpm @ 49 m H2O

(550 gpm @ 160 ft H2O)

2,082 lpm @ 49 m H2O

(550 gpm @ 160 ft H2O) 2 (1)

17 Filtered Water Tank Vertical, cylindrical 1,003,134 liter (265,000 gal) 995,563 liter (263,000 gal) 2 (0)

18 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 303 lpm (80 gpm) 303 lpm (80 gpm) 2 (0)

19 Liquid Waste Treatment 

System 10 years, 24-hour storm 10 years, 24-hour storm 1 (0)
Carbon Dioxide Capture Sensitivity Analysis

251

ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment 

No. Description Type

Design Condition Opr Qty.

D1A D1B (Spares)

1 Gasifier Pressurized slurryfeed, entrained bed

2,812 tonne/day, 5.6 MPa

(3,100 tpd, 815 psia)

2,812 tonne/day, 5.6 MPa

(3,100 tpd, 814.96 psia) 2 (0)

2 Synthesis Gas Cooler

Vertical downflow 

radiant heat 

exchanger with outlet 

quench chamber

245,393 kg/hr (541,000 lb/hr) 243,126 kg/hr (536,000 lb/hr) 2 (0)

3

Synthesis Gas 

Cyclone High efficiency 335,658 kg/hr (740,000 lb/hr) Design efficiency 90%

332,937 kg/hr (734,000 lb/hr) 

Design efficiency 90% 2 (0)

4 Candle Filter Pressurized filter with 

pulse-jet cleaning metallic filters metallic filters 2 (0)

5

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 335,658 kg/hr (740,000 lb/hr) 332,937 kg/hr (734,000 lb/hr) 2 (0)

6 Raw Gas Coolers Shell and tube with 

condensate drain 215,910 kg/hr (476,000 lb/hr) 287,578 kg/hr (634,000 lb/hr) 8 (0)

7

Raw Gas Knockout 

Drum

Vertical with mist 

eliminator

215,456 kg/hr, 35°C, 5.3 MPa

(475,000 lb/hr, 95°F, 765 psia)

213,188 kg/hr, 35°C, 5.2 MPa

(470,000 lb/hr, 95°F, 750 psia) 2 (0)

8 Flare Stack

Self-supporting, 

carbon steel, stainless 

steel top, pilot ignition

335,658 kg/hr (740,000 lb/hr) 

syngas

332,937 kg/hr (734,000 lb/hr) 

syngas

2 (0)

9

ASU Main Air 

Compressor

Centrifugal, multistage4,757 m3/min @ 1.3 MPa

(168,000 scfm @ 190 psia)

5,635 m3/min @ 1.3 MPa

(199,000 scfm @ 190 psia) 2 (0)

10 Cold Box Vendor design 2,268 tonne/day (2,500 tpd) of 

95% purity oxygen

2,268 tonne/day (2,500 tpd) 

of 95% purity oxygen 2 (0)

11 Oxygen Compressor Centrifugal, multistage

1,161 m3/min (41,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 psia)

1,133 m3/min (40,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 

psia)

2 (0)

12 Primary Nitrogen 

Compressor

Centrifugal, multistage

3,766 m3/min (133,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

3,540 m3/min (125,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 

psia)

2 (0)
Carbon Dioxide Capture Sensitivity Analysis

252

Equipment 

No. Description Type

Design Condition Opr Qty.

D1A D1B (Spares)

13 Secondary Nitrogen 

Compressor

Centrifugal, singlestage

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 

psia)

2 (0)

14

Syngas Dilution 

Nitrogen Boost 

Compressor

Centrifugal, singlestage

0 m3/min (0 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 psia)

0 m3/min (0 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 

psia)

2 (0)

15 AGR Nitrogen Boost 

Compressor

Centrifugal, singlestage

85 m3/min (3,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 5.4 MPa (790 psia)

N/A 2 (0)

16 Extraction Air Heat 

Exchanger

Gas-to-gas, vendor 

design

69,853 kg/hr, 432°C, 1.6 MPa

(154,000 lb/hr, 810°F, 235 psia) N/A 2 (0)

ACCOUNT 5A SYNGAS CLEANUP

Equipment 

No. Description Type

Design Condition Opr Qty.

D1A D1B (Spares)

1 Mercury Adsorber Sulfated carbon bed

215,003 kg/hr (474,000 lb/hr) 

35°C (95°F) 

5.2 MPa (760 psia)

212,735 kg/hr (469,000 lb/hr) 

35°C (95°F) 

5.1 MPa (745 psia)

2 (0)

2 Sulfur Plant Claus type 140 tonne/day (154 tpd) 139 tonne/day (153 tpd) 1 (0)

3

COS Hydrolysis 

Reactor Fixed bed, catalytic

303,907 kg/hr (670,000 lb/hr)

221°C (430°F)

5.4 MPa (790 psia)

301,185 kg/hr (664,000 lb/hr)

204°C (400°F)

5.5 MPa (800 psia)

2 (0)

4

Acid Gas Removal 

Plant Selexol

232,239 kg/hr (512,000 lb/hr)

35°C (94°F)

5.2 MPa (755 psia)

214,096 kg/hr (472,000 lb/hr) 

35°C (95°F) 

5.1 MPa (740 psia)

2 (0)

5

Hydrogenation 

Reactor Fixed bed, catalytic

36,155 kg/hr (79,709 lb/hr)

232°C (450°F)

0.4 MPa (58.9 psia)

6,346 kg/hr (13,990 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

1 (0)

6

Tail Gas Recycle 

Compressor Centrifugal 31993 kg/hr (70533.3901 lb/hr) 3,062 kg/hr (6,750 lb/hr) 1 (0)
Carbon Dioxide Capture Sensitivity Analysis

253

ACCOUNT 5B CO2 COMPRESSION

Equipment 

No. Description Type

Design Condition Opr Qty.

D1A D1B (Spares)

1 CO2 Compressor Integrally geared, multistage centrifugal N/A

300 m3/min @ 15.3 MPa 

(10,600 scfm @ 2,215 

psia)

4 (0)

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment 

No. Description Type

Design Condition Opr Qty.

D1A D1B (Spares)

1 Gas Turbine Advanced F class 230 MW 230 MW 2 (0)

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase

260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase 2 (0)

3

Syngas Expansion 

Turbine/Generator Turbo Expander

218,359 kg/h (481,400 lb/h)

5.1 MPa (745 psia) Inlet

3.2 MPa (460 psia) Outlet

144,877 kg/h (319,400 lb/h)

5.0 MPa (720 psia) Inlet

3.2 MPa (460 psia) Outlet

2 (0)

ACCOUNT 7 HRSG, DUCTING, AND STACK

Equipment 

No. Description Type

Design Condition Opr Qty.

D1A D1B (Spares)

1 Stack CS plate, type 

409SS liner

76 m (250 ft) high x

8.4 m (27 ft) diameter

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 - 352,655 kg/hr, 

12.4 MPa/561°C (777,471 

lb/hr, 1,800 psig/1,042°F)

 Reheat steam - 345,662 

kg/hr, 3.1 MPa/561°C (762,055 

lb/hr, 452 psig/1,042°F)

Main steam - 346,935 kg/hr, 

12.4 MPa/554°C (764,862 

lb/hr, 1,800 psig/1,030°F)

 Reheat steam - 346,574 

kg/hr, 3.1 MPa/554°C (764,065 

lb/hr, 452 psig/1,030°F)

2 (0)
Carbon Dioxide Capture Sensitivity Analysis

254

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type

Design Condition Opr Qty.

D1A D1B (Spares)

1 Steam Turbine

Commercially 

available advanced 

steam turbine

291 MW 12.4 

MPa/561°C/561°C (1,800 psig/ 

1042°F/1042°F)

295 MW 12.4 

MPa/554°C/554°C (1,800 psig/ 

1030°F/1030°F)

1 (0)

2

Steam Turbine 

Generator

Hydrogen cooled, 

static excitation

320 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

330 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design 

steam conditions

50% steam flow @ design 

steam conditions 2 (0)

4

Surface 

Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,688 GJ/hr (1,600 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), Water temperature rise 

11°C (20°F)

1,783 GJ/hr (1,690 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), Water temperature rise 

11°C (20°F)

1 (0)

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type

Design Condition Opr Qty.

D1A D1B (Spares)

1

Circulating 

Water Pumps Vertical, wet pit 420,181 lpm @ 30 m(111,000 gpm @ 100 ft)

416,395 lpm @ 30 m

(110,000 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 / 2,353 GJ/hr (2,230 

MMBtu/hr) heat duty

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) 

HWT / 2,332 GJ/hr (2,210 

MMBtu/hr) heat duty

1 (0)

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type

Design Condition Opr Qty.

D1A D1B (Spares)

1 Slag Quench Tank Water bath 242,266 liters (64,000 gal) 242,266 liters (64,000 gal) 2 (0)

2 Slag Crusher Roll 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 2 (0)

3 Slag Depressurizer Lock Hopper 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 2 (0)

4 Slag Receiving Tank Horizontal, weir 147,631 liters (39,000 gal) 143,846 liters (38,000 gal) 2 (0)
Carbon Dioxide Capture Sensitivity Analysis

255

Equipment 

No. Description Type

Design Condition Opr Qty.

D1A D1B (Spares)

5

Black Water Overflow 

Tank Shop fabricated 64,352 liters (17,000 gal) 64,352 liters (17,000 gal) 2 (0)

6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 2 (0)

7

Slag Separation 

Screen Vibrating 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 2 (0)

8

Coarse Slag 

Conveyor Belt/bucket 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 2 (0)

9

Fine Ash Settling 

Tank Vertical, gravity 208,198 liters (55,000 gal) 208,198 liters (55,000 gal) 2 (0)

10 Fine Ash Recycle 

Pumps Horizontal centrifugal 38 lpm @ 14 m H2O(10 gpm @ 46 ft H2O)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O) 2 (2)

11 Grey Water Storage 

Tank Field erected 68,137 liters (18,000 gal) 64,352 liters (17,000 gal) 2 (0)

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H2O

(60 gpm @ 1,850 ft H2O)

227 lpm @ 564 m H2O

(60 gpm @ 1,850 ft H2O) 2 (2)

13 Slag Storage Bin Vertical, field erected 907 tonne (1,000 tons) 907 tonne (1,000 tons) 2 (0)

14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 1 (0)

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type

Design Condition Opr Qty.

D1A D1B (Spares)

1

CTG Step-up 

Transformer Oil-filled 24 kV/345 kV, 260 MVA, 3-ph, 60 Hz

24 kV/345 kV, 260 MVA, 

3-ph, 60 Hz 2 (0)

2

STG Step-up 

Transformer Oil-filled 24 kV/345 kV, 320 MVA, 3-ph, 60 Hz

24 kV/345 kV, 330 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

345 kV/13.8 kV, 63 MVA, 

3-ph, 60 Hz 2 (0)

4

Medium Voltage 

Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 29 MVA, 3-ph, 60 Hz

24 kV/4.16 kV, 30 MVA, 

3-ph, 60 Hz 1 (1)

5

Low Voltage 

Transformer Dry ventilated 4.16 kV/480 V, 4 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 4 MVA, 

3-ph, 60 Hz 1 (1)

6

CTG Isolated Phase 

Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 2 (0)
Carbon Dioxide Capture Sensitivity Analysis

256

Equipment 

No. Description Type

Design Condition Opr Qty.

D1A D1B (Spares)

7

STG Isolated Phase 

Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 1 (0)

8

Medium Voltage 

Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz 1 (1)

9

Low Voltage 

Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz 1 (1)

10 Emergency Diesel 

Generator

Sized for emergency 

shutdown 750 kW, 480 V, 3-ph, 60 Hz 750 kW, 480 V, 3-ph, 60 Hz 1 (0)

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment 

No. Description Type

Design Condition Opr Qty.

D1A D1B (Spares)

1

DCS - Main 

Control

Monitor/keyboard; 

Operator printer 

(laser color); 

Engineering printer 

(laser B&W)

Operator stations/printers and 

engineering stations/printers

Operator stations/printers and 

engineering stations/printers 1 (0)

2

DCS -

Processor

Microprocessor with 

redundant 

input/output

N/A N/A 1 (0)

3

DCS - Data 

Highway Fiber optic Fully redundant, 25% spare Fully redundant, 25% spare 1 (0)
Carbon Dioxide Capture Sensitivity Analysis

257

4.3.2 IGCC Design 2 – Single Water Gas Shift Reactor

A process block flow diagram for Case 2 Design 2 (D2) is shown in Exhibit 4-35. D2 represents 

an IGCC plant with a single WGS reactor and bypass stream (stream 13). This IGCC design 

uses a S:DG molar ratio of 0.25 at the outlet of the WGS reactor. The WGS bypass ratio and the 

two-stage SelexolTM CO2 removal efficiency are adjusted to control the total CO2 capture level. 

The SelexolTM removal efficiency is altered by varying the solvent circulation rate, which 

changes the size and cost of the SelexolTM system.

The WGS bypass ratio impacts the degree of CO to CO2 and COS to H2S conversion across the 

WGS reactor. Consequently, a downstream COS hydolysis unit is included in this design to 

ensure that sulfur emissions are below the limit of 0.0128 lb SO2/MMBtu. 

Four levels of total CO2 removal were modeled for Case 2 D2: 25 percent (D2A), 45 percent

(D2B), 60 percent (D2C), and 75 percent (D2D). The corresponding stream tables are contained 

in Exhibit 4-36, Exhibit 4-37, Exhibit 4-38, and Exhibit 4-39, respectively. 

Overall performance for Case 2 D2 is summarized in Exhibit 4-40 which includes auxiliary 

power requirements.

Material and energy balance information, environmental performance and a major equipment list

are summarized in Sections 4.3.2.1 and 4.3.2.2.
Carbon Dioxide Capture Sensitivity Analysis

258

Exhibit 4-35 Case 2 D2 Process Block Flow Diagram, IGCC with Single WGS Reactor and Bypass

GAS TURBINE COMBUSTOR

TURBINE COOLING AIR

QUENCH AND SYNGAS SCRUBBER

GAS COOLING BFW HEATING & KNOCKOUT SHIFT REACTOR

ELEVATED PRESSURE ASU

GEE GASIFIER SECTION (RADIANT COOLER)

SOUR WATER STRIPPER

MERCURY REMOVAL TWO- STAGE SELEXOL UNIT

CLAUS PLANT

HRSG

AMBIENT AIR

SYNGAS EXPANDER HYDROGENATION REACTOR AND GAS COOLER

CO2 COMPRESSION

1 5

9

12 16 17

19

21 22

23

20

6 8

2 3 4

24

25 26

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 ADVANCED F CLASS GAS TURBINE

SYNGAS H/P REHEAT

18

CLAUS PLANT OXIDANT STEAM TURBINE 27 464 MWe Note: Block Flow Diagram is not intended to represent a complete material balance. Only major process streams and equipment are shown.

23 TAIL GAS RECYCLE FROM CLAUS PLANT

SLURRY MIXER SLURRY 7 WATER

COS HYDROLYSIS 15 11

10

13

14
Carbon Dioxide Capture Sensitivity Analysis

259

Exhibit 4-36 Case 2 D2A Stream Table, 25% CO2 Removal with Single WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

A r 0.0092 0.0140 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0050 0.0068 0.0068

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 0.2820 0.0000 0.0283 0.2820 0.2803

CO2 0.0003 0.0044 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.0000 0.2588 0.1088 0.1098

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 0.0001 0.0001

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2686 0.0000 0.3761 0.2686 0.2694

H2O 0.0099 0.1105 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3197 1.0000 0.3214 0.3197 0.3197

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 0.0002 0.0002

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0043 0.0057 0.0057

N2 0.7732 0.7600 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0041 0.0055 0.0055

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0012 0.0016 0.0016

O2 0.2074 0.1111 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

S O2 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 (kgmol/hr) 26,017 1,936 94 18,699 5,252 0 4,788 0 21,976 27,860 50 190 27,721 27,911

V-L Flowrate (kg/hr) 750,784 53,401 3,014 524,689 169,010 0 86,248 0 442,173 547,930 907 3,647 545,190 548,837

Solids Flowrate (kg/hr) 0 0 0 0 0 209,950 0 23,035 0 0 0 0 0 0

Temperature (°C) 15 17 32 93 32 15 142 1,316 677 206 288 408 212 212

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 5.48 5.48 5.48

Enthalpy (kJ/kg)A 30.23 35.12 26.67 92.50 26.67 --- 537.77 --- 1,424.65 1,067.56 2,918.18 1,478.37 1,049.10 1,049.29

Density (kg/m3) 1.2 1.4 11.0 24.4 11.0 --- 872.0 --- 14.0 27.2 25.6 18.6 27.4 27.4

V-L Molecular Weight 28.857 27.588 32.181 28.060 32.181 --- 18.015 --- 20.121 19.667 18.015 19.228 19.667 19.664

V-L Flowrate (lbmol/hr) 57,359 4,267 206 41,224 11,578 0 10,555 0 48,448 61,422 111 418 61,115 61,533

V-L Flowrate (lb/hr) 1,655,196 117,730 6,644 1,156,741 372,603 0 190,143 0 974,824 1,207,979 2,000 8,040 1,201,939 1,209,979

Solids Flowrate (lb/hr) 0 0 0 0 0 462,861 0 50,784 0 0 0 0 0 0

Temperature (°F) 59 63 90 199 90 59 287 2,400 1,250 403 550 767 413 413

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 795.0 795.0 795.0

Enthalpy (Btu/lb)A 13.0 15.1 11.5 39.8 11.5 --- 231.2 --- 612.5 459.0 1,254.6 635.6 451.0 451.1

Density (lb/ft3) 0.076 0.089 0.687 1.521 0.687 --- 54.440 --- 0.871 1.699 1.597 1.162 1.710 1.710

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

260

Exhibit 4-36 Case 2 D2A Stream Table, 25% CO2 Removal with Single WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27

V-L Mole Fraction

A r 0.0068 0.0100 0.0101 0.0118 0.0118 0.0006 0.0037 0.0000 0.0228 0.0092 0.0091 0.0091 0.0000

CH4 0.0009 0.0013 0.0013 0.0015 0.0015 0.0002 0.0009 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.2803 0.4126 0.4089 0.4791 0.4791 0.0253 0.1669 0.0000 0.0031 0.0000 0.0000 0.0000 0.0000

CO2 0.1100 0.1619 0.1626 0.0263 0.0263 0.9653 0.0000 0.0000 0.2373 0.0003 0.0597 0.0597 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 0.0000 0.0000

H2 0.2694 0.3964 0.3984 0.4705 0.4705 0.0085 0.1036 0.0000 0.6154 0.0000 0.0000 0.0000 0.0000

H2O 0.3196 0.0012 0.0012 0.0001 0.0001 0.0000 0.0311 0.0000 0.0013 0.0099 0.0635 0.0635 1.0000

HCl 0.0002 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 0.0059 0.0086 0.0085 0.0000 0.0000 0.0001 0.6924 0.0000 0.0034 0.0000 0.0000 0.0000 0.0000

N2 0.0055 0.0081 0.0091 0.0108 0.0108 0.0001 0.0016 0.0000 0.1166 0.7732 0.7566 0.7566 0.0000

NH3 0.0016 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 0.2074 0.1112 0.1112 0.0000

S O2 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 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 27,911 18,962 19,135 16,101 16,101 2,784 235 0 172 110,253 137,409 137,409 35,016

V-L Flowrate (kg/hr) 548,837 387,556 390,331 262,829 262,829 120,373 6,864 0 2,775 3,181,557 3,969,076 3,969,076 630,824

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,254 0 0 0 0 0

Temperature (°C) 212 35 35 35 197 64 48 182 38 15 582 132 554

Pressure (MPa, abs) 5.41 5.14 5.10 5.00 3.17 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512

Enthalpy (kJ/kg)A 1,049.19 40.00 40.14 54.66 355.29 -108.502 100.241 --- 60.056 30.227 733.496 236.187 3,483.972

Density (kg/m3) 27.0 41.2 40.9 31.5 13.1 483.1 1.8 5,270.3 34.4 1.2 0.4 0.9 35.5

V-L Molecular Weight 19.664 20.438 20 16.323 16.323 43.239 29.245 --- 16.092 28.857 28.885 28.885 18.015

V-L Flowrate (lbmol/hr) 61,533 41,805 42,185 35,498 35,498 6,137 517 0 380 243,066 302,934 302,934 77,197

V-L Flowrate (lb/hr) 1,209,979 854,415 860,533 579,439 579,439 265,378 15,133 0 6,118 7,014,133 8,750,314 8,750,314 1,390,729

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 11,583 0 0 0 0 0

Temperature (°F) 413 95 95 95 387 146 119 360 100 59 1,079 270 1,029

Pressure (psia) 785.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 451.1 17.2 17.3 23.5 152.7 -46.6 43.1 --- 25.8 13.0 315.3 101.5 1,497.8

Density (lb/ft3) 1.688 2.575 3 1.964 0.817 30.161 0.112 329.017 2.147 0.076 0.027 0.056 2.218

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

261

Exhibit 4-37 Case 2 D2B Stream Table, 45% CO2 Capture with Single WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

A r 0.0092 0.0143 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0061 0.0068 0.0065

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0008 0.0009 0.0009

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2821 0.0000 0.0615 0.2821 0.1879

CO2 0.0003 0.0045 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.0000 0.2884 0.1088 0.1855

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 0.0001 0.0001

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2687 0.0000 0.4314 0.2687 0.3381

H2O 0.0099 0.1135 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3196 1.0000 0.2000 0.3196 0.2685

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0002 0.0002 0.0002

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0052 0.0057 0.0055

N2 0.7732 0.7537 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0049 0.0055 0.0053

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0014 0.0016 0.0015

O2 0.2074 0.1140 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

S O2 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 (kgmol/hr) 26,429 1,914 96 19,047 5,334 0 4,863 0 22,320 28,292 1,328 12,644 16,975 29,620

V-L Flowrate (kg/hr) 762,647 52,772 3,082 534,452 171,659 0 87,600 0 449,104 556,426 23,916 246,487 333,856 580,342

Solids Flowrate (kg/hr) 0 0 0 0 0 213,242 0 23,396 0 0 0 0 0 0

Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 415 212 208

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 5.48 5.48 5.48

Enthalpy (kJ/kg)A 30.23 35.18 26.67 92.50 26.67 --- 537.77 --- 1,424.65 1,067.22 2,918.18 1,192.31 1,048.78 939.48

Density (kg/m3) 1.2 1.4 11.0 24.4 11.0 --- 872.0 --- 14.0 27.2 25.6 18.5 27.4 27.3

V-L Molecular Weight 28.857 27.575 32.181 28.060 32.181 --- 18.015 --- 20.121 19.667 18.015 19.494 19.667 19.593

V-L Flowrate (lbmol/hr) 58,265 4,219 211 41,991 11,760 0 10,720 0 49,208 62,373 2,927 27,876 37,424 65,300

V-L Flowrate (lb/hr) 1,681,348 116,343 6,795 1,178,265 378,444 0 193,124 0 990,106 1,226,710 52,727 543,410 736,026 1,279,436

Solids Flowrate (lb/hr) 0 0 0 0 0 470,117 0 51,580 0 0 0 0 0 0

Temperature (°F) 59 64 90 199 90 59 287 2,400 1,250 403 550 780 413 407

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 795.0 795.0 795.0

Enthalpy (Btu/lb)A 13.0 15.1 11.5 39.8 11.5 --- 231.2 --- 612.5 458.8 1,254.6 512.6 450.9 403.9

Density (lb/ft3) 0.076 0.090 0.687 1.521 0.687 --- 54.440 --- 0.871 1.699 1.597 1.156 1.710 1.706

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

262

Exhibit 4-37 Case 2 D2B Stream Table, 45% CO2 Capture with Single WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27

V-L Mole Fraction

A r 0.0065 0.0089 0.0090 0.0117 0.0117 0.0003 0.0037 0.0000 0.0254 0.0092 0.0091 0.0091 0.0000

CH4 0.0009 0.0012 0.0012 0.0015 0.0015 0.0001 0.0009 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.1879 0.2572 0.2553 0.3319 0.3319 0.0100 0.1184 0.0000 0.0022 0.0000 0.0000 0.0000 0.0000

CO2 0.1856 0.2540 0.2535 0.0363 0.0363 0.9832 0.0000 0.0000 0.1881 0.0003 0.0445 0.0445 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 0.0000 0.0000

H2 0.3381 0.4627 0.4641 0.6079 0.6079 0.0062 0.1370 0.0000 0.6492 0.0000 0.0000 0.0000 0.0000

H2O 0.2684 0.0012 0.0012 0.0001 0.0001 0.0000 0.0357 0.0000 0.0013 0.0099 0.0811 0.0811 1.0000

HCl 0.0002 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 0.0056 0.0076 0.0076 0.0000 0.0000 0.0000 0.7027 0.0000 0.0037 0.0000 0.0000 0.0000 0.0000

N2 0.0053 0.0072 0.0081 0.0106 0.0106 0.0001 0.0016 0.0000 0.1301 0.7732 0.7555 0.7555 0.0000

NH3 0.0015 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 0.2074 0.1097 0.1097 0.0000

S O2 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 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 29,620 21,644 21,801 16,538 16,538 5,010 235 0 157 110,253 138,067 138,067 34,907

V-L Flowrate (kg/hr) 580,342 436,590 438,860 213,515 213,515 218,355 6,684 0 2,270 3,181,557 3,929,525 3,929,525 628,866

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,337 0 0 0 0 0

Temperature (°C) 208 35 35 35 197 55 48 182 38 15 576 132 548

Pressure (MPa, abs) 5.41 5.14 5.10 5.00 3.17 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512

Enthalpy (kJ/kg)A 939.40 39.11 39.27 72.72 451.83 -145.215 110.774 --- 69.903 30.227 762.853 267.463 3,469.021

Density (kg/m3) 27.0 41.0 40.7 24.8 10.3 587.9 1.7 5,270.3 30.7 1.2 0.4 0.9 35.9

V-L Molecular Weight 19.593 20.172 20 12.911 12.911 43.582 28.392 --- 14.458 28.857 28.461 28.461 18.015

V-L Flowrate (lbmol/hr) 65,300 47,716 48,062 36,460 36,460 11,046 519 0 346 243,066 304,385 304,385 76,958

V-L Flowrate (lb/hr) 1,279,436 962,516 967,522 470,720 470,720 481,390 14,737 0 5,005 7,014,133 8,663,119 8,663,119 1,386,412

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 11,765 0 0 0 0 0

Temperature (°F) 407 95 95 95 387 130 119 360 100 59 1,069 270 1,019

Pressure (psia) 785.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 403.9 16.8 16.9 31.3 194.3 -62.4 47.6 --- 30.1 13.0 328.0 115.0 1,491.4

Density (lb/ft3) 1.684 2.562 3 1.547 0.646 36.702 0.109 329.013 1.916 0.076 0.026 0.055 2.239

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

263

Exhibit 4-38 Case 2 D2C Stream Table, 60% CO2 Capture with Single WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

A r 0.0092 0.0142 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0061 0.0068 0.0063

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0008 0.0009 0.0008

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2819 0.0000 0.0616 0.2819 0.1201

CO2 0.0003 0.0045 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.0000 0.2884 0.1088 0.2408

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 0.0001 0.0001

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2685 0.0000 0.4314 0.2685 0.3882

H2O 0.0099 0.1129 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3199 1.0000 0.1999 0.3199 0.2317

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0002 0.0002 0.0002

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0052 0.0057 0.0054

N2 0.7732 0.7550 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0049 0.0055 0.0051

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0014 0.0016 0.0015

O2 0.2074 0.1134 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

S O2 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 (kgmol/hr) 26,770 1,949 98 19,282 5,402 0 4,925 0 22,606 28,667 2,382 22,807 8,242 31,049

V-L Flowrate (kg/hr) 772,488 53,746 3,141 541,055 173,856 0 88,721 0 454,852 563,787 42,908 444,606 162,089 606,695

Solids Flowrate (kg/hr) 0 0 0 0 0 215,970 0 23,696 0 0 0 0 0 0

Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 416 212 206

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 5.48 5.48 5.48

Enthalpy (kJ/kg)A 30.23 35.17 26.67 92.50 26.67 --- 537.77 --- 1,424.65 1,068.08 2,918.18 1,192.12 1,049.60 860.25

Density (kg/m3) 1.2 1.4 11.0 24.4 11.0 --- 872.0 --- 14.0 27.2 25.6 18.5 27.4 27.3

V-L Molecular Weight 28.857 27.578 32.181 28.060 32.181 --- 18.015 --- 20.121 19.667 18.015 19.494 19.667 19.540

V-L Flowrate (lbmol/hr) 59,017 4,297 215 42,510 11,910 0 10,858 0 49,837 63,201 5,251 50,281 18,170 68,452

V-L Flowrate (lb/hr) 1,703,045 118,490 6,924 1,192,823 383,287 0 195,596 0 1,002,776 1,242,938 94,595 980,189 357,345 1,337,533

Solids Flowrate (lb/hr) 0 0 0 0 0 476,133 0 52,240 0 0 0 0 0 0

Temperature (°F) 59 64 90 199 90 59 287 2,400 1,250 403 550 780 413 403

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 795.0 795.0 795.0

Enthalpy (Btu/lb)A 13.0 15.1 11.5 39.8 11.5 --- 231.2 --- 612.5 459.2 1,254.6 512.5 451.2 369.8

Density (lb/ft3) 0.076 0.090 0.687 1.521 0.687 --- 54.440 --- 0.871 1.699 1.597 1.156 1.710 1.703

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

264

Exhibit 4-38 Case 2 D2C Stream Table, 60% CO2 Capture with Single WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27

V-L Mole Fraction

A r 0.0063 0.0081 0.0083 0.0116 0.0116 0.0002 0.0037 0.0000 0.0280 0.0092 0.0091 0.0091 0.0000

CH4 0.0008 0.0011 0.0011 0.0015 0.0015 0.0001 0.0009 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.1201 0.1564 0.1555 0.2171 0.2171 0.0049 0.0791 0.0000 0.0015 0.0000 0.0000 0.0000 0.0000

CO2 0.2408 0.3137 0.3127 0.0462 0.0462 0.9891 0.0000 0.0000 0.1408 0.0003 0.0326 0.0326 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 0.0000 0.0000

H2 0.3882 0.5057 0.5068 0.7131 0.7131 0.0055 0.1642 0.0000 0.6815 0.0000 0.0000 0.0000 0.0000

H2O 0.2317 0.0012 0.0012 0.0001 0.0001 0.0000 0.0395 0.0000 0.0013 0.0099 0.0954 0.0954 1.0000

HCl 0.0002 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 0.0054 0.0070 0.0070 0.0000 0.0000 0.0000 0.7110 0.0000 0.0039 0.0000 0.0000 0.0000 0.0000

N2 0.0051 0.0066 0.0075 0.0105 0.0105 0.0000 0.0016 0.0000 0.1431 0.7732 0.7543 0.7543 0.0000

NH3 0.0015 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 0.2074 0.1086 0.1086 0.0000

S O2 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 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 31,049 23,833 23,978 16,933 16,933 6,790 236 0 145 110,253 138,593 138,593 34,560

V-L Flowrate (kg/hr) 606,695 476,637 478,503 174,962 174,962 296,664 6,538 0 1,866 3,181,557 3,897,575 3,897,575 622,616

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,405 0 0 0 0 0

Temperature (°C) 206 35 35 35 198 53 48 182 38 15 571 132 544

Pressure (MPa, abs) 5.41 5.14 5.10 5.00 3.17 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512

Enthalpy (kJ/kg)A 860.19 38.39 38.56 93.69 567.40 -154.608 119.799 --- 81.238 30.227 787.418 293.271 3,457.191

Density (kg/m3) 26.9 40.9 40.5 19.8 8.3 617.1 1.7 5,270.2 27.2 1.2 0.4 0.9 36.1

V-L Molecular Weight 19.540 19.999 20 10.332 10.332 43.694 27.699 --- 12.893 28.857 28.122 28.122 18.015

V-L Flowrate (lbmol/hr) 68,452 52,543 52,862 37,332 37,332 14,968 520 0 319 243,066 305,545 305,545 76,193

V-L Flowrate (lb/hr) 1,337,533 1,050,805 1,054,918 385,725 385,725 654,032 14,413 0 4,113 7,014,133 8,592,683 8,592,683 1,372,633

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 11,916 0 0 0 0 0

Temperature (°F) 403 95 95 95 388 127 119 360 100 59 1,061 270 1,011

Pressure (psia) 785.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 369.8 16.5 16.6 40.3 243.9 -66.5 51.5 --- 34.9 13.0 338.5 126.1 1,486.3

Density (lb/ft3) 1.681 2.554 3 1.236 0.517 38.525 0.106 329.010 1.698 0.076 0.026 0.055 2.257

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

265

Exhibit 4-39 Case 2 D2D Stream Table, 75% CO2 Capture with Single WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

A r 0.0092 0.0152 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0061 0.0000 0.0061

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0008 0.0000 0.0008

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2819 0.0000 0.0616 0.0000 0.0616

CO2 0.0003 0.0049 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.0000 0.2885 0.0000 0.2885

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 0.2685 0.0000 0.4315 0.0000 0.4315

H2O 0.0099 0.1226 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3201 1.0000 0.1998 0.0000 0.1998

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0002 0.0000 0.0002

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0052 0.0000 0.0052

N2 0.7732 0.7347 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0049 0.0000 0.0049

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0014 0.0000 0.0014

O2 0.2074 0.1226 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

S O2 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 0.0000 1.0000

V-L Flowrate (kgmol/hr) 27,043 1,813 94 19,635 5,462 0 4,979 0 22,854 28,991 3,368 32,358 0 32,358

V-L Flowrate (kg/hr) 780,370 49,911 3,040 550,960 175,763 0 89,694 0 459,840 570,131 60,671 630,802 0 630,802

Solids Flowrate (kg/hr) 0 0 0 0 0 218,339 0 23,956 0 0 0 0 0 0

Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 415 --- 204

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 5.48 --- 5.48

Enthalpy (kJ/kg)A 30.23 35.36 26.67 92.50 26.67 --- 537.77 --- 1,424.65 1,068.64 2,918.18 1,191.97 --- 791.08

Density (kg/m3) 1.2 1.4 11.0 24.4 11.0 --- 872.0 --- 14.0 27.2 25.6 18.5 --- 27.2

V-L Molecular Weight 28.857 27.535 32.181 28.060 32.181 --- 18.015 --- 20.121 19.666 18.015 19.494 --- 19.494

V-L Flowrate (lbmol/hr) 59,619 3,996 208 43,288 12,041 0 10,977 0 50,384 63,913 7,425 71,338 0 71,338

V-L Flowrate (lb/hr) 1,720,422 110,034 6,701 1,214,660 387,491 0 197,741 0 1,013,775 1,256,924 133,757 1,390,681 0 1,390,681

Solids Flowrate (lb/hr) 0 0 0 0 0 481,355 0 52,813 0 0 0 0 0 0

Temperature (°F) 59 64 90 199 90 59 287 2,400 1,250 403 550 780 --- 400

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 795.0 --- 795.0

Enthalpy (Btu/lb)A 13.0 15.2 11.5 39.8 11.5 --- 231.2 --- 612.5 459.4 1,254.6 512.5 --- 340.1

Density (lb/ft3) 0.076 0.090 0.687 1.521 0.687 --- 54.440 --- 0.871 1.699 1.597 1.156 --- 1.700

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

266

Exhibit 4-39 Case 2 D2D Stream Table, 75% CO2 Capture with Single WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27

V-L Mole Fraction

A r 0.0061 0.0076 0.0077 0.0115 0.0115 0.0002 0.0028 0.0000 0.0178 0.0092 0.0091 0.0091 0.0000

CH4 0.0008 0.0010 0.0010 0.0015 0.0015 0.0001 0.0007 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0616 0.0770 0.0764 0.1143 0.1143 0.0021 0.0315 0.0000 0.0044 0.0000 0.0000 0.0000 0.0000

CO2 0.2885 0.3608 0.3612 0.0493 0.0493 0.9925 0.2533 0.0000 0.4110 0.0003 0.0207 0.0207 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 0.0000 0.0000

H2 0.4315 0.5396 0.5390 0.8128 0.8128 0.0051 0.1414 0.0000 0.4667 0.0000 0.0000 0.0000 0.0000

H2O 0.1998 0.0012 0.0012 0.0001 0.0001 0.0000 0.0323 0.0000 0.0015 0.0099 0.1087 0.1087 1.0000

HCl 0.0002 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 0.0053 0.0066 0.0065 0.0000 0.0000 0.0000 0.5369 0.0000 0.0047 0.0000 0.0000 0.0000 0.0000

N2 0.0049 0.0062 0.0069 0.0105 0.0105 0.0000 0.0012 0.0000 0.0940 0.7732 0.7541 0.7541 0.0000

NH3 0.0014 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 0.2074 0.1075 0.1075 0.0000

S O2 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 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 32,358 25,873 26,095 17,195 17,195 8,562 317 0 222 110,253 139,112 139,112 34,199

V-L Flowrate (kg/hr) 630,802 513,914 518,948 133,950 133,950 374,680 9,945 0 5,033 3,181,557 3,866,468 3,866,468 616,113

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,464 0 0 0 0 0

Temperature (°C) 204 35 35 35 198 52 48 181 38 15 567 132 539

Pressure (MPa, abs) 5.41 5.14 5.10 5.00 3.17 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512

Enthalpy (kJ/kg)A 791.04 37.74 37.69 127.51 753.85 -159.330 97.137 --- 32.253 30.227 810.659 318.046 3,445.333

Density (kg/m3) 26.9 40.8 40.6 14.9 6.2 632.2 1.9 5,272.4 50.3 1.2 0.4 0.9 36.4

V-L Molecular Weight 19.494 19.863 20 7.790 7.790 43.760 31.351 --- 22.680 28.857 27.794 27.794 18.015

V-L Flowrate (lbmol/hr) 71,338 57,041 57,530 37,909 37,909 18,877 699 0 489 243,066 306,690 306,690 75,397

V-L Flowrate (lb/hr) 1,390,681 1,132,987 1,144,084 295,309 295,309 826,028 21,926 0 11,097 7,014,133 8,524,103 8,524,103 1,358,296

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 12,047 0 0 0 0 0

Temperature (°F) 400 95 95 95 388 125 119 359 100 59 1,052 270 1,002

Pressure (psia) 785.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 340.1 16.2 16.2 54.8 324.1 -68.5 41.8 --- 13.9 13.0 348.5 136.7 1,481.2

Density (lb/ft3) 1.679 2.548 3 0.930 0.390 39.466 0.120 329.147 3.139 0.076 0.026 0.054 2.274

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

267

Exhibit 4-40 Case 2 D2 Performance Modeling Results 

POWER SUMMARY (Gross Power at 

Generator Terminals, kWe)

D2A 

(25%)

D2B 

(45%)

D2C 

(60%)

D2D 

(75%)

Gas Turbine Power 464,000 464,000 464,000 464,000

Sweet Gas Expander Power 5,800 6,000 6,100 6,200

Steam Turbine Power 280,600 276,900 275,100 271,800

Total 750,400 746,900 745,200 742,000

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 457 461 463 466

Coal Milling 2,159 2,193 2,221 2,246

Sour Water Recycle Slurry Pump 181 183 185 186

Slag Handling 1,106 1,123 1,138 1,150

Air Separation Unit Auxiliaries 1,000 1,000 1,000 1,000

Air Separation Unit Main Air Compressor 64,024 65,036 65,875 66,547

Oxygen Compressor 10,167 10,326 10,404 10,518

Nitrogen Compressors 31,389 32,027 33,061 34,281

CO2 Compressor 8,497 15,047 20,335 25,605

Boiler Feedwater Pumps 3,970 4,001 4,035 4,062

Condensate Pump 250 256 260 262

Quench Water Pump 513 518 523 527

Circulating Water Pump 4,165 4,312 4,420 4,513

Ground Water Pumps 425 456 480 501

Cooling Tower Fans 2,153 2,231 2,287 2,331

Scrubber Pumps 212 216 218 220

Acid Gas Removal 4,861 8,912 12,149 15,519

Gas Turbine Auxiliaries 1,000 1,000 1,000 1,000

Steam Turbine Auxiliaries 100 100 100 100

Claus Plant/TGTU Auxiliaries 250 250 250 250

Claus Plant TG Recycle Compressor 828 756 699 1,052

Miscellaneous Balance of Plant 1

3,000 3,000 3,000 3,000

Transformer Losses 2,667 2,693 2,719 2,741

TOTAL AUXILIARIES, kWe 143,374 156,097 166,822 178,077

NET POWER, kWe 607,026 590,803 578,378 563,923

Net Plant Efficiency, % (HHV) 38.4% 36.8% 35.5% 34.3%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,385 (8,895) 9,796 (9,285) 10,132 (9,604) 10,506 (9,958)

Condenser Duty, GJ/hr (106Btu/hr) 1,625 (1,540) 1,614 (1,530) 1,593 (1,510) 1,561 (1,480)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 209,950 (462,861) 213,242 (470,117) 215,970 (476,133) 218,339 (481,355)

Thermal Input, kWth 

2

1,582,508 1,607,315 1,627,884 1,645,739

Raw Water Withdrawal, m3/min (gpm) 17.8 (4,697) 19.1 (5,038) 20.1 (5,300) 20.9 (5,530)

Raw Water Consumption, m3/min (gpm) 14.1 (3,727) 15.3 (4,033) 16.2 (4,270) 17.0 (4,481)

Notes: 1. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

2. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 
Carbon Dioxide Capture Sensitivity Analysis

268

4.3.2.1 Environmental Performance for Case 2 D2

The environmental targets for emissions of Hg, NOx, SO2, and particulate matter were presented 

in Section 2.4. A summary of the plant air emissions for Case 2 D2A, D2B, D2C, and D2D is 

presented in Exhibit 4-41.

For Case 2 D2, SO2 emissions are controlled by sulfur capture across the two-stage SelexolTM 

unit. The clean syngas exiting the AGR unit has a sulfur concentration of about 10 ppmv, 

resulting in a concentration in the flue gas of less than 2 ppmv. The H2S-rich regeneration gas 

produced in Case 2 D2 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 SelexolTM 

unit, 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 incinerated in the Claus plant burner. This also assists in lowering 

NOx levels. 

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.

Ninety-five percent of the mercury is captured from the syngas by an activated carbon bed. 

For Case 2 D2, varying levels of the CO2 [25 percent (D2A), 45 percent (D2B), 60 percent

(D2C), and 75 percent (D2D)] in the syngas are captured in the two-stage SelexolTM unit and 

compressed for sequestration. The carbon balance for Case 2 D2 is shown in Exhibit 4-42. The 

carbon input to the plant consists of carbon in the air and 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, as dissolved CO2 in the wastewater blowdown stream, and as CO2

in the stack gas, ASU vent gas, and the captured CO2 product. Carbon in the wastewater 

blowdown stream is calculated by difference to close the material balance. The carbon capture 

efficiency is defined as the pounds of carbon in the CO2 product stream relative to the amount of 

carbon in the coal, less carbon contained in the slag, represented by the following fraction:

(Carbon in CO2 Product)/[(Carbon in the Coal)-(Carbon in Slag)] or

73,037/(295,050-5,901)*100=25.3% (D2A)

131,784/(299,675-5,993)*100=44.9% (D2B)

178,734/(303,510-6,070)*100=60.1% (D2C)

225,516/(306,839-6,137)*100=75.0% (D2D)

Exhibit 4-43 shows the sulfur balance for Case 2 D2. Sulfur input comes solely from the sulfur 

in the coal. Sulfur output includes the pounds of sulfur recovered in the Claus plant, dissolved 

SO2 in the wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is 

considered to be negligible, and the sulfur content of the blowdown stream is calculated by 

difference to close the material balance. The total sulfur capture is represented by the following 

fraction:
Carbon Dioxide Capture Sensitivity Analysis

269

(Sulfur byproduct/Sulfur in the coal) or

(11,583/11,601)*100 = 99.8% (D2A)

(11,765/11,783)*100 = 99.8% (D2B)

(11,916/11,934)*100 = 99.8% (D2C)

(12,047/12,065)*100 = 99.8% (D2D)

The overall water balances for Case 2 D2A, D2B, D2C, and D2D are shown in Exhibit 4-44, 

Exhibit 4-45, Exhibit 4-46, and Exhibit 4-47, respectively. Raw water is obtained from 

groundwater (50 percent) and from municipal sources (50 percent). Water demand represents 

the total amount of water required for a particular process. Some water is recovered within the 

process and that water is reused as internal recycle. Raw water withdrawal is the difference 

between water demand and internal recycle. Process water discharged from the power plant is 

also accounted for in this study. Raw water consumption represents raw water withdrawal less 

process water discharge.

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 4-48 through 

Exhibit 4-59.

Gasifier and ASU

Syngas Cleanup

Power Block

An overall plant energy balance for Case D2A, D2B, D2C, and D2D is provided in tabular form 

in Exhibit 4-60, Exhibit 4-61, Exhibit 4-62, and Exhibit 4-63, respectively. The power out is the 

combined combustion turbine, steam turbine and expander power after generator losses. In 

addition, energy balance Sankey diagrams are provided for D2A, D2B, D2C, and D2D in Exhibit 

4-64, Exhibit 4-65, Exhibit 4-66, and Exhibit 4-67, respectively.
Carbon Dioxide Capture Sensitivity Analysis

270

Exhibit 4-41 Case 2 D2 Estimated Air Emission Rates

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

85% capacity factor

kg/MWh

(lb/MWh)

D2A D2B D2C D2D D2A D2B D2C D2D D2A D2B D2C D2D

SO2

0.001 

(0.002)

0.001 

(0.002)

0.001 

(0.002)

0.001 

(0.002) 37 (40) 37 (41) 38 (42) 38 (42) 0.007 (0.02)

0.007 

(0.02)

0.007 

(0.02)

0.007 

(0.02)

NOX

0.024 

(0.055)

0.023 

(0.053)

0.022 

(0.051)

0.022 

(0.050) 947 (1,044) 926 (1,021) 909 (1,002) 894 (985) 0.180 (0.397)

0.177 

(0.390)

0.174 

(0.384)

0.172 

(0.379)

PM 0.003 

(0.0071)

0.003 

(0.0071)

0.003 

(0.0071)

0.003 

(0.0071) 122 (134) 124 (136) 125 (138) 127 (140) 0.023 (0.051)

0.024 

(0.052)

0.024 

(0.053)

0.024 

(0.054)

Hg 0.246x10-6

(0.571x10-6)

0.246x10-6

(0.571x10-6)

0.246x10-6

(0.571x10-6)

0.246x10-6

(0.571x10-6)

0.010 

(0.011)

0.010 

(0.011)

0.010 

(0.011)

0.010 

(0.011)

1.87x10-6

(4.11x10-6)

1.90x10-6

(4.20x10-6)

1.93x10-6

(4.26x10-6)

1.96x10-6

(4.32x10-6)

CO2

63.3

(147.3)

46.8 (108.8) 33.9 (78.9) 21.4 (49.7) 2,528,260 

(2,786,929)

1,896,795 

(2,090,859)

1,393,730

(1,536,324)

886,830

(977,563)

481 (1,060) 362 (799) 267 (588) 171 (376)

CO2

net 594 (1,310) 458 (1,010) 344 (758) 224 (495)
Carbon Dioxide Capture Sensitivity Analysis

271

Exhibit 4-42 Case 2 D2 Carbon Balance

Carbon In, kg/hr (lb/hr)

D2A D2B D2C D2D

Coal 133,832

(295,050)

135,930

(299,675)

137,670

(303,510)

139,180

(306,839)

Air (CO2)

535 

(1,179)

536 

(1,183)

538 

(1,185)

539 

(1,188)

Total 134,367

(296,229)

136,466

(300,858)

138,208

(304,695)

139,719

(308,027)

Carbon Out, kg/hr (lb/hr)

Slag 2,677 

(5,901)

2,719 

(5,993)

2,753

(6,070)

2,784 

(6,137)

Stack Gas 98,459

(217,066)

73,868

(162,851)

54,277

(119,660)

34,536

(76,140)

ASU Vent 102 (225) 104 (229) 105 (232) 106 (234)

CO2 Product 33,129

(73,037)

59,776

(131,784)

81,072

(178,734)

102,292

(225,516)

Convergence 

Tolerance 0 (0) -1 (1) 1 (-1) 1 (0)

Total 134,367 

(296,229)

136,466 

(300,858)

138,208 

(304,695)

139,719 

(308,027)

Exhibit 4-43 Case 2 D2 Sulfur Balance

Sulfur In, kg/hr (lb/hr)

D2A D2B D2C D2D

Coal 5,262

(11,601)

5,345

(11,783)

5,413

(11,934)

5,472

(12,065)

Total 5,262

(11,601)

5,345

(11,783)

5,413

(11,934)

5,472

(12,065)

Sulfur Out, kg/hr (lb/hr)

Elemental Sulfur 5,254

(11,583)

5,337 

(11,765)

5,405

(11,916)

5,464

(12,047)

Stack Gas 3 (6) 3 (6) 3 (6) 3 (6)

CO2 Product 5 (12) 5 (12) 5 (12) 5 (12)

Convergence 

Tolerance* 0 (0) 0 (0) 0 (0) 0 (0)

Total 5,262 

(11,601)

5,345 

(11,783)

5,413 

(11,934)

5,472 

(12,065)
Carbon Dioxide Capture Sensitivity Analysis

272

Exhibit 4-44 Case 2 D2A (25%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Slag Handling 0.50 (132) 0.50 (132) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.7 (719) 0.88 (233) 1.8 (486) 0.0 (0) 1.8 (486)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7) -0.03 (-7)

Condenser Makeup 0.2 (59) 0.0 (0) 0.2 (59) 0.0 (0) 0.2 (59)

 Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

 Shift Steam 0.0 (4) 0.0 (0) 0.0 (4)

 CT Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

 BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 16.2 (4,282) 0.49 (130) 15.7 (4,153) 3.6 (963) 12.1 (3,190)

 BFW Blowdown 0.0 (0) 0.21 (55) -0.21 (-55)

 SWS Blowdown 0.0 (0) 0.28 (75) -0.28 (-75)

 SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

 Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 21.1 (5,572) 3.31 (875) 17.8 (4,697) 3.7 (970) 14.1 (3,727)

Total, gal/MWhnet 551 86 464 96 368
Carbon Dioxide Capture Sensitivity Analysis

273

Exhibit 4-45 Case 2 D2B (45%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Slag Handling 0.51 (134) 0.51 (134) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.8 (730) 0.63 (167) 2.1 (564) 0.0 (0) 2.1 (564)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7) -0.03 (-7)

Condenser Makeup 0.6 (161) 0.0 (0) 0.6 (161) 0.0 (0) 0.6 (161)

 Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

 Shift Steam 0.4 (105) 0.0 (0) 0.4 (105)

 CT Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

 BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 16.8 (4,437) 0.47 (124) 16.3 (4,313) 3.8 (998) 12.5 (3,315)

 BFW Blowdown 0.0 (0) 0.21 (55) -0.21 (-55)

 SWS Blowdown 0.0 (0) 0.26 (69) -0.26 (-69)

 SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

 Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 22.1 (5,848) 3.07 (811) 19.1 (5,038) 3.8 (1,005) 15.3 (4,033)

Total, gal/MWhnet 594 82 512 102 410
Carbon Dioxide Capture Sensitivity Analysis

274

Exhibit 4-46 Case 2 D2C (60%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Slag Handling 0.51 (136) 0.51 (136) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.8 (740) 0.43 (113) 2.4 (626) 0.0 (0) 2.4 (626)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.02 (6) -0.02 (-6)

Condenser Makeup 0.9 (244) 0.0 (0) 0.9 (244) 0.0 (0) 0.9 (244)

 Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

 Shift Steam 0.7 (189) 0.0 (0) 0.7 (189)

 CT Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

 BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 17.2 (4,548) 0.45 (119) 16.8 (4,429) 3.9 (1,023) 12.9 (3,406)

 BFW Blowdown 0.0 (0) 0.21 (55) -0.21 (-55)

 SWS Blowdown 0.0 (0) 0.24 (64) -0.24 (-64)

 SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

 Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 22.9 (6,059) 2.87 (759) 20.1 (5,300) 3.9 (1,029) 16.2 (4,270)

Total, gal/MWhnet 629 79 550 107 443
Carbon Dioxide Capture Sensitivity Analysis

275

Exhibit 4-47 Case 2 D2D (75%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Slag Handling 0.52 (137) 0.52 (137) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.8 (748) 0.24 (62) 2.6 (686) 0.0 (0) 2.6 (686)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.02 (6) -0.02 (-6)

Condenser Makeup 1.2 (322) 0.0 (0) 1.2 (322) 0.0 (0) 1.2 (322)

 Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

 Shift Steam 1.0 (268) 0.0 (0) 1.0 (268)

 CT Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

 BFW Makeup 0.21 (54) 0.0 (0) 0.21 (54)

Cooling Tower 17.6 (4,636) 0.43 (114) 17.1 (4,522) 3.9 (1,043) 13.2 (3,480)

 BFW Blowdown 0.0 (0) 0.21 (54) -0.21 (-54)

 SWS Blowdown 0.0 (0) 0.23 (59) -0.23 (-59)

 SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

 Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 23.6 (6,239) 2.68 (709) 20.9 (5,530) 4.0 (1,049) 17.0 (4,481)

Total, gal/MWhnet 664 75 588 112 477
Carbon Dioxide Capture Sensitivity Analysis

276

This page intentionally left blank
Carbon Dioxide Capture Sensitivity Analysis

277

Exhibit 4-48 Case 2 D2A (25%) Heat and Mass Balance, GEE Gasifier and ASU

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D2A HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D2A (25%) GEE GASIFIER ASU AND GASIFICATION DWG. NO. CCSA-HMB-CS-2-D2A-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 1 OF 3

Ambient Air Four Stage Air Compressor

Elevated Pressure ASU Four Stage N2 Compressor

Four Stage O2 Compressor

ASU Vent

Water

Steam

Gross Plant Power: 750 MWe Auxiliary Load: 143 MWe Net Plant Power: 607 MWe Net Plant Efficiency, HHV: 38.4% Net Plant Heat Rate: 8,895 BTU/KWe

N2 to GT Combustor 1,655,196 W 59.0 T 14.7 P 13.0 H

372,603 W 90.0 T 125.0 P 11.5 H

372,603 W 241.2 T 940.0 P 40.8 H

To Claus Plant 6,644 W 90.0 T 125.0 P 11.5 H

117,730 W 63.4 T 16.4 P 15.1 H

1,007,664 W 90.0 T 56.4 P 14.2 H

149,078 W 50.0 T 182.0 P 2.9 H 5

1

3

2

Slurry Mix Tank

Milled Coal

Slag

462,861 W 59.0 T 14.7 P

190,143 W 287.0 T 840.0 P 231.2 H

50,784 W 2,400.0 T 815.0 P

1,156,741 W 385.0 T 384.0 P 87.2 H

653,005 W 156.4 T 840.0 P 2,950.2 H

100.0 T 189.5 P 18.0 H

6

1,156,741 W 199.0 T 384.0 P 39.8 H

HP BFW

N2 to GT Combustor N2 Boost Compressor 0 W 199.0 T 384.0 P 39.8 H 0 W 385.0 T 469.0 P 87.0 H

Saturated Steam To HRSG HP Superheater

GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank

Knockout Drum

Vent To Claus Unit

Raw Fuel Gas

CWS

CWR

Fines

Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench Section Drag Conveyor

974,824 W 1,250.0 T 805.0 P 612.5 H 1,207,979 W 403.3 T 800.0 P 459.0 H

Syngas Quench

1,334,367 W 450.0 T 805.0 P 536.1 H

8

9

10 Sour Water

7

4

1,156,741 W 199.0 T 384.0 P 39.8 H
Carbon Dioxide Capture Sensitivity Analysis

278

Exhibit 4-49 Case 2 D2A (25%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum

Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water

Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out

From Syngas ASU Coolers

Sour Stripper 1,207,979 W 403.3 T 800.0 P 459.0 H

860,533 W 94.7 T 740.0 P 17.3 H 15,133 W 119.0 T 23.7 P

579,439 W 386.9 T 460.0 P 152.7 H

11,583 W 12,707 W 450.0 T 12.3 P 852.1 H

2,514 W 240.3 T 65.0 P 445.8 H

6,644 W 90.0 T 125.0 P 11.5 H NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D2A HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D2A (25%) GEE GASIFIER GAS CLEANUP SYSTEM DWG. NO. CCSA-HMB-CS-2-D2A-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 2 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 750 MWe Auxiliary Load: 143 MWe Net Plant Power: 607 MWe Net Plant Efficiency, HHV: 38.4% Net Plant Heat Rate: 8,895 BTU/KWe

22

16 23

CO2

Tailgas

Tail Gas Cleanup Unit

Tail Gas Compressor

7,203 W 120.0 T 10.6 P 203.0 H

854,415 W 94.8 T 745.0 P 17.2 H

6,589 W 116.7 T 10.6 P 42.7 H

3 6,118 W 100.0 T 799.5 P

Raw Syngas

18 579,439 W 94.7 T 725.0 P 23.5 H

Claus Oxygen Preheater

6,644 W 450.0 T 124.5 P 91.9 H

21

Fuel Gas Expander Fuel Gas To GT 19 579,439 W 465.0 T 720.0 P 187.4 H High Temperature Shift Shift Steam

11

COS Hydrolysis Preheater

1,207,979 W 413.3 T 795.0 P 451.0 H

2,000 W 550.0 T 800.0 P 1,254.1 H

8,040 W 445.0 T 795.0 P 650.9 H 8,040 W 766.8 T 795.0 P 635.6 H

400.0 T 795.0 P 463.4 H 1,209,979 W 413.1 T 785.0 P 451.1 H Two-Stage Selexol

Clean Gas

CO2

Acid Gas

Multistage Intercooled CO2 Compressor Interstage Knockout

CO2 Product 20 10

17

265,378 W 146.4 T 2,214.7 P

COS Hydrolysis

13 15 1,201,939 W 413.3 T 795.0 P 451.0 H

1,209,979 W 413.2 T 795.0 P 451.1 H

1,209,979 W 402.7 T 780.0 P 446.7 H

12 14
Carbon Dioxide Capture Sensitivity Analysis

279

Exhibit 4-50 Case 2 D2A (25%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine

Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator

Ip Extraction Steam To 250 PSIA Header

LP Process Header

Blowdown Flash To WWT

Gland Steam Condenser Condensate to Gasification Island

HP BFW to Radiant Syngas Cooler HP Saturated Steam to HRSG Superheater

LP Turbine

Stack

Compressor Expander

Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class Gas Turbine

MP Flash Bottoms LP Flash Tops

7,014,133 W 59.0 T 14.7 P 13.0 H 1,680,546 W 101.1 T 1.0 P 69.1 H

8,750,314 W 269.9 T 15.2 P 101.5 H

579,439 W 386.9 T 460.0 P 152.7 H

8,750,314 W 1,079.4 T 15.2 P 315.3 H From Gasifier Island Preheating

To Claus

LP BFW 1,390,729 W 1,029.4 T 1,814.7 P 1,497.8 H

10,077 W 298.0 T 65.0 P 1,179.0 H 1,418,938 W 278.8 T 2,250.7 P 252.3 H 28,205 W 585.0 T 2,000.7 P 593.3 H

1,639,069 W 492.9 T 65.0 P 1,278.5 H

1,680,546 W 103.1 T 120.0 P 71.3 H

1,680,546 W 235.0 T 105.0 P 203.7 H

1,400 W 649.2 T 65.0 P 1,355.6 H 1,400 W 212.0 T 14.7 P 179.9 H

IP Pump NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D2A HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D2A (25%) GEE GASIFIER POWER BLOCK SYSTEM DWG. NO. CCSA-HMB-CS-2-D2A-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 3 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 750 MWe Auxiliary Load: 143 MWe Net Plant Power: 607 MWe Net Plant Efficiency, HHV: 38.4% Net Plant Heat Rate: 8,895 BTU/KWe 24

25

27 19

26

Flue Gas

HOT WELL CONDENSER Make-up 29,498 W 59.0 T 14.7 P 27.1 H

8,876 W 690.4 T 501.4 P 1,351.7 H 9,579 W 649.2 T 65.0 P 1,355.6 H 25,447 W 885.4 T 280.0 P 1,466.2 H 785 W 1,029.4 T 1,814.7 P 1,497.8 H 1,319 W 531.0 T 65.0 P 1,297.3 H
Carbon Dioxide Capture Sensitivity Analysis

280

Exhibit 4-51 Case 2 D2B (45%) Heat and Mass Balance, GEE Gasifier and ASU

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D2B HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D2B (45%) GEE GASIFIER ASU AND GASIFICATION DWG. NO. CCSA-HMB-CS-2-D2B-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 1 OF 3

Ambient Air Four Stage Air Compressor

Elevated Pressure ASU Four Stage N2 Compressor

Four Stage O2 Compressor

ASU Vent

Water

Steam

Gross Plant Power: 747 MWe Auxiliary Load: 156 MWe Net Plant Power: 591 MWe Net Plant Efficiency, HHV: 36.8% Net Plant Heat Rate: 9,283 BTU/KWe

N2 to GT Combustor 1,681,348 W 59.0 T 14.7 P 13.0 H

378,444 W 90.0 T 125.0 P 11.5 H

378,444 W 241.2 T 940.0 P 40.8 H

To Claus Plant 6,795 W 90.0 T 125.0 P 11.5 H

116,343 W 63.6 T 16.4 P 15.1 H

1,026,832 W 90.0 T 56.4 P 14.2 H

151,433 W 50.0 T 182.0 P 2.9 H 5

1

3

2

Slurry Mix Tank

Milled Coal

Slag

470,117 W 59.0 T 14.7 P

193,124 W 287.0 T 840.0 P 231.2 H

51,580 W 2,400.0 T 815.0 P

1,164,779 W 385.0 T 384.0 P 87.2 H

663,241 W 156.4 T 840.0 P 2,950.2 H

100.0 T 189.5 P 18.0 H

6

1,164,779 W 199.0 T 384.0 P 39.8 H

HP BFW

N2 to GT Combustor N2 Boost Compressor 13,485 W 199.0 T 384.0 P 39.8 H 13,485 W 385.0 T 469.0 P 87.0 H

Saturated Steam To HRSG HP Superheater

GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank

Knockout Drum

Vent To Claus Unit

Raw Fuel Gas

CWS

CWR

Fines

Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench Section Drag Conveyor

990,106 W 1,250.0 T 805.0 P 612.5 H 1,226,710 W 403.2 T 800.0 P 458.8 H

Syngas Quench

1,355,284 W 450.0 T 805.0 P 536.1 H

8

9

10 Sour Water

7

4

1,178,265 W 199.0 T 384.0 P 39.8 H
Carbon Dioxide Capture Sensitivity Analysis

281

Exhibit 4-52 Case 2 D2B (45%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum

Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water

Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out

From Syngas ASU Coolers

Sour Stripper 1,226,710 W 403.2 T 800.0 P 458.8 H

967,522 W 94.7 T 740.0 P 16.9 H 14,737 W 119.0 T 23.7 P

470,720 W 387.3 T 460.0 P 194.3 H

11,765 W 12,188 W 450.0 T 12.3 P 910.5 H

2,422 W 237.9 T 65.0 P 430.1 H

6,795 W 90.0 T 125.0 P 11.5 H NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D2B HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D2B (45%) GEE GASIFIER GAS CLEANUP SYSTEM DWG. NO. CCSA-HMB-CS-2-D2B-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 2 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 747 MWe Auxiliary Load: 156 MWe Net Plant Power: 591 MWe Net Plant Efficiency, HHV: 36.8% Net Plant Heat Rate: 9,283 BTU/KWe

22

16 23

CO2

Tailgas

Tail Gas Cleanup Unit

Tail Gas Compressor

5,992 W 120.0 T 10.6 P 221.7 H

962,516 W 94.8 T 745.0 P 16.8 H

7,183 W 117.3 T 10.6 P 43.3 H

3 5,005 W 100.0 T 799.5 P

Raw Syngas

18 470,720 W 94.7 T 725.0 P 31.3 H

Claus Oxygen Preheater

6,795 W 450.0 T 124.5 P 91.9 H

21

Fuel Gas Expander Fuel Gas To GT 19 470,720 W 465.0 T 720.0 P 238.0 H High Temperature Shift Shift Steam

11

COS Hydrolysis Preheater

1,226,710 W 413.2 T 795.0 P 450.9 H

52,727 W 550.0 T 800.0 P 1,254.1 H

543,410 W 425.4 T 795.0 P 528.9 H 543,410 W 779.9 T 795.0 P 512.6 H

400.0 T 795.0 P 340.3 H 1,279,436 W 407.0 T 785.0 P 403.9 H Two-Stage Selexol

Clean Gas

CO2

Acid Gas

Multistage Intercooled CO2 Compressor Interstage Knockout

CO2 Product 20 10

17

481,390 W 130.2 T 2,214.7 P

COS Hydrolysis

13 15 736,026 W 413.2 T 795.0 P 450.9 H

1,279,436 W 407.2 T 795.0 P 403.9 H

1,279,436 W 397.3 T 780.0 P 399.7 H

12 14
Carbon Dioxide Capture Sensitivity Analysis

282

Exhibit 4-53 Case 2 D2B (45%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine

Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator

Ip Extraction Steam To 250 PSIA Header

LP Process Header

Blowdown Flash To WWT

Gland Steam Condenser Condensate to Gasification Island

HP BFW to Radiant Syngas Cooler HP Saturated Steam to HRSG Superheater

LP Turbine

Stack

Compressor Expander

Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class Gas Turbine

MP Flash Bottoms LP Flash Tops

7,014,133 W 59.0 T 14.7 P 13.0 H 1,726,692 W 101.1 T 1.0 P 69.1 H

8,663,119 W 270.1 T 15.2 P 115.0 H

470,720 W 387.3 T 460.0 P 194.3 H

8,663,119 W 1,068.9 T 15.2 P 328.0 H From Gasifier Island Preheating

To Claus

LP BFW 1,386,412 W 1,018.9 T 1,814.7 P 1,491.4 H

10,133 W 298.0 T 65.0 P 1,179.0 H 1,414,787 W 278.8 T 2,250.7 P 252.3 H 28,360 W 585.0 T 2,000.7 P 593.3 H

1,634,321 W 484.9 T 65.0 P 1,274.6 H

1,726,692 W 103.0 T 120.0 P 71.2 H

1,726,692 W 235.0 T 105.0 P 203.7 H

1,400 W 639.2 T 65.0 P 1,350.6 H 1,400 W 212.0 T 14.7 P 179.9 H

IP Pump NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D2B HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D2B (45%) GEE GASIFIER POWER BLOCK SYSTEM DWG. NO. CCSA-HMB-CS-2-D2B-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 3 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 747 MWe Auxiliary Load: 156 MWe Net Plant Power: 591 MWe Net Plant Efficiency, HHV: 36.8% Net Plant Heat Rate: 9,283 BTU/KWe 24

25

27 19

26

Flue Gas

HOT WELL CONDENSER Make-up 80,339 W 59.0 T 14.7 P 27.1 H

8,919 W 681.6 T 501.4 P 1,346.7 H 9,632 W 639.2 T 65.0 P 1,350.6 H 25,775 W 875.6 T 280.0 P 1,461.1 H 789 W 1,018.9 T 1,814.7 P 1,491.4 H 1,324 W 523.3 T 65.0 P 1,293.6 H
Carbon Dioxide Capture Sensitivity Analysis

283

Exhibit 4-54 Case 2 D2C (60%) Heat and Mass Balance, GEE Gasifier and ASU

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D2C HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D2C (60%) GEE GASIFIER ASU AND GASIFICATION DWG. NO. CCSA-HMB-CS-2-D2C-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 1 OF 3

Ambient Air Four Stage Air Compressor

Elevated Pressure ASU Four Stage N2 Compressor

Four Stage O2 Compressor

ASU Vent

Water

Steam

Gross Plant Power: 745 MWe Auxiliary Load: 167 MWe Net Plant Power: 578 MWe Net Plant Efficiency, HHV: 35.5% Net Plant Heat Rate: 9,604 BTU/KWe

N2 to GT Combustor 1,703,045 W 59.0 T 14.7 P 13.0 H

383,287 W 90.0 T 125.0 P 11.5 H

383,287 W 241.2 T 940.0 P 40.8 H

To Claus Plant 6,924 W 90.0 T 125.0 P 11.5 H

118,490 W 63.6 T 16.4 P 15.1 H

1,039,436 W 90.0 T 56.4 P 14.2 H

153,387 W 50.0 T 182.0 P 2.9 H 5

1

3

2

Slurry Mix Tank

Milled Coal

Slag

476,133 W 59.0 T 14.7 P

195,596 W 287.0 T 840.0 P 231.2 H

52,240 W 2,400.0 T 815.0 P

995,367 W 385.0 T 384.0 P 87.2 H

671,729 W 156.4 T 840.0 P 2,950.2 H

100.0 T 189.5 P 18.0 H

6

995,367 W 199.0 T 384.0 P 39.8 H

HP BFW

N2 to GT Combustor N2 Boost Compressor 197,457 W 199.0 T 384.0 P 39.8 H 197,457 W 385.0 T 469.0 P 87.0 H

Saturated Steam To HRSG HP Superheater

GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank

Knockout Drum

Vent To Claus Unit

Raw Fuel Gas

CWS

CWR

Fines

Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench Section Drag Conveyor

1,002,776 W 1,250.0 T 805.0 P 612.5 H 1,242,938 W 403.3 T 800.0 P 459.2 H

Syngas Quench

1,372,628 W 450.0 T 805.0 P 536.1 H

8

9

10 Sour Water

7

4

1,192,823 W 199.0 T 384.0 P 39.8 H
Carbon Dioxide Capture Sensitivity Analysis

284

Exhibit 4-55 Case 2 D2C (60%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum

Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water

Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out

From Syngas ASU Coolers

Sour Stripper 1,242,938 W 403.3 T 800.0 P 459.2 H

1,054,918 W 94.7 T 740.0 P 16.6 H 14,413 W 119.0 T 23.7 P

385,725 W 387.6 T 460.0 P 243.9 H

11,916 W 11,783 W 450.0 T 12.3 P 960.8 H

2,362 W 235.6 T 65.0 P 414.6 H

6,924 W 90.0 T 125.0 P 11.5 H NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D2C HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D2C (60%) GEE GASIFIER GAS CLEANUP SYSTEM DWG. NO. CCSA-HMB-CS-2-D2C-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 2 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 745 MWe Auxiliary Load: 167 MWe Net Plant Power: 578 MWe Net Plant Efficiency, HHV: 35.5% Net Plant Heat Rate: 9,604 BTU/KWe

22

16 23

CO2

Tailgas

Tail Gas Cleanup Unit

Tail Gas Compressor

5,023 W 120.0 T 10.6 P 243.1 H

1,050,805 W 94.9 T 745.0 P 16.5 H

7,670 W 117.6 T 10.6 P 43.7 H

3 4,113 W 100.0 T 799.5 P

Raw Syngas

18 385,725 W 94.7 T 725.0 P 40.3 H

Claus Oxygen Preheater

6,924 W 450.0 T 124.5 P 91.9 H

21

Fuel Gas Expander Fuel Gas To GT 19 385,725 W 465.0 T 720.0 P 298.7 H High Temperature Shift Shift Steam

11

COS Hydrolysis Preheater

1,242,938 W 413.3 T 795.0 P 451.2 H

94,595 W 550.0 T 800.0 P 1,254.1 H

980,189 W 425.4 T 795.0 P 528.8 H 980,189 W 779.9 T 795.0 P 512.5 H

400.0 T 795.0 P 340.2 H 1,337,533 W 403.1 T 785.0 P 369.8 H Two-Stage Selexol

Clean Gas

CO2

Acid Gas

Multistage Intercooled CO2 Compressor Interstage Knockout

CO2 Product 20 10

17

654,032 W 126.6 T 2,214.7 P

COS Hydrolysis

13 15 357,345 W 413.3 T 795.0 P 451.2 H

1,337,533 W 403.2 T 795.0 P 369.8 H

1,337,533 W 393.8 T 780.0 P 365.8 H

12 14
Carbon Dioxide Capture Sensitivity Analysis

285

Exhibit 4-56 Case 2 D2C (60%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine

Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator

Ip Extraction Steam To 250 PSIA Header

LP Process Header

Blowdown Flash To WWT

Gland Steam Condenser Condensate to Gasification Island

HP BFW to Radiant Syngas Cooler HP Saturated Steam to HRSG Superheater

LP Turbine

Stack

Compressor Expander

Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class Gas Turbine

MP Flash Bottoms LP Flash Tops

7,014,133 W 59.0 T 14.7 P 13.0 H 1,752,266 W 101.1 T 1.0 P 69.1 H

8,592,683 W 270.0 T 15.2 P 126.1 H

385,725 W 387.6 T 460.0 P 243.9 H

8,592,683 W 1,060.7 T 15.2 P 338.5 H From Gasifier Island Preheating

To Claus

LP BFW 1,372,633 W 1,010.7 T 1,814.7 P 1,486.3 H

10,170 W 298.0 T 65.0 P 1,179.0 H 1,401,100 W 278.8 T 2,250.7 P 252.3 H 28,465 W 585.0 T 2,000.7 P 593.3 H

1,618,169 W 484.1 T 65.0 P 1,274.2 H

1,752,266 W 103.0 T 120.0 P 71.2 H

1,752,266 W 235.0 T 105.0 P 203.7 H

1,400 W 631.2 T 65.0 P 1,346.7 H 1,400 W 212.0 T 14.7 P 179.9 H

IP Pump NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D2C HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D2C (60%) GEE GASIFIER POWER BLOCK SYSTEM DWG. NO. CCSA-HMB-CS-2-D2C-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 3 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 745 MWe Auxiliary Load: 167 MWe Net Plant Power: 578 MWe Net Plant Efficiency, HHV: 35.5% Net Plant Heat Rate: 9,604 BTU/KWe 24

25

27 19

26

Flue Gas

HOT WELL CONDENSER Make-up 122,023 W 59.0 T 14.7 P 27.1 H

8,953 W 674.7 T 501.4 P 1,342.7 H 9,674 W 631.2 T 65.0 P 1,346.7 H 26,025 W 867.9 T 280.0 P 1,457.1 H 792 W 1,010.7 T 1,814.7 P 1,486.3 H 1,328 W 517.3 T 65.0 P 1,290.6 H
Carbon Dioxide Capture Sensitivity Analysis

286

Exhibit 4-57 Case 2 D2D (75%) Heat and Mass Balance, GEE Gasifier and ASU

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D2D HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D2D (75%) GEE GASIFIER ASU AND GASIFICATION DWG. NO. CCSA-HMB-CS-2-D2D-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 1 OF 3

Ambient Air Four Stage Air Compressor

Elevated Pressure ASU Four Stage N2 Compressor

Four Stage O2 Compressor

ASU Vent

Water

Steam

Gross Plant Power: 742 MWe Auxiliary Load: 178 MWe Net Plant Power: 564 MWe Net Plant Efficiency, HHV: 34.3% Net Plant Heat Rate: 9,958 BTU/KWe

N2 to GT Combustor 1,720,422 W 59.0 T 14.7 P 13.0 H

387,491 W 90.0 T 125.0 P 11.5 H

387,491 W 241.2 T 940.0 P 40.8 H

To Claus Plant 6,701 W 90.0 T 125.0 P 11.5 H

110,034 W 64.1 T 16.4 P 15.2 H

1,059,707 W 90.0 T 56.4 P 14.2 H

154,952 W 50.0 T 182.0 P 2.9 H 5

1

3

2

Slurry Mix Tank

Milled Coal

Slag

481,355 W 59.0 T 14.7 P

197,741 W 287.0 T 840.0 P 231.2 H

52,813 W 2,400.0 T 815.0 P

837,375 W 385.0 T 384.0 P 87.2 H

679,096 W 156.4 T 840.0 P 2,950.2 H

100.0 T 189.5 P 18.0 H

6

837,375 W 199.0 T 384.0 P 39.8 H

HP BFW

N2 to GT Combustor N2 Boost Compressor 377,285 W 199.0 T 384.0 P 39.8 H 377,285 W 385.0 T 469.0 P 87.0 H

Saturated Steam To HRSG HP Superheater

GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank

Knockout Drum

Vent To Claus Unit

Raw Fuel Gas

CWS

CWR

Fines

Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench Section Drag Conveyor

1,013,775 W 1,250.0 T 805.0 P 612.5 H 1,256,924 W 403.4 T 800.0 P 459.4 H

Syngas Quench

1,387,683 W 450.0 T 805.0 P 536.1 H

8

9

10 Sour Water

7

4

1,214,660 W 199.0 T 384.0 P 39.8 H
Carbon Dioxide Capture Sensitivity Analysis

287

Exhibit 4-58 Case 2 D2D (75%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum

Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water

Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out

From Syngas ASU Coolers

Sour Stripper 1,256,924 W 403.4 T 800.0 P 459.4 H

1,144,084 W 94.8 T 740.0 P 16.2 H 21,926 W 119.0 T 23.7 P

295,309 W 387.7 T 460.0 P 324.1 H

12,047 W 18,888 W 450.0 T 12.3 P 720.3 H

2,307 W 233.1 T 65.0 P 398.0 H

6,701 W 90.0 T 125.0 P 11.5 H NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D2D HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D2D (75%) GEE GASIFIER GAS CLEANUP SYSTEM DWG. NO. CCSA-HMB-CS-2-D2D-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 2 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 742 MWe Auxiliary Load: 178 MWe Net Plant Power: 564 MWe Net Plant Efficiency, HHV: 34.3% Net Plant Heat Rate: 9,958 BTU/KWe

22

16 23

CO2

Tailgas

Tail Gas Cleanup Unit

Tail Gas Compressor

12,492 W 120.0 T 10.6 P 151.9 H

1,132,987 W 94.9 T 745.0 P 16.2 H

7,791 W 116.4 T 10.6 P 42.4 H

3 11,097 W 100.0 T 799.5 P

Raw Syngas

18 295,309 W 94.8 T 725.0 P 54.8 H

Claus Oxygen Preheater

6,701 W 450.0 T 124.5 P 91.9 H

21

Fuel Gas Expander Fuel Gas To GT 19 295,309 W 465.0 T 720.0 P 396.7 H High Temperature Shift Shift Steam

11

COS Hydrolysis Preheater

1,256,924 W 413.4 T 795.0 P 451.5 H

133,757 W 550.0 T 800.0 P 1,254.1 H

1,390,681 W 425.4 T 795.0 P 528.7 H 1,390,681 W 779.9 T 795.0 P 512.5 H

400.0 T 795.0 P 340.1 H 1,390,681 W 399.8 T 785.0 P 340.1 H Two-Stage Selexol

Clean Gas

CO2

Acid Gas

Multistage Intercooled CO2 Compressor Interstage Knockout

CO2 Product 20 10

17

826,028 W 124.8 T 2,214.7 P

COS Hydrolysis

13 15 0 W

--- T --- P 0.0 H

1,390,681 W 400.0 T 795.0 P 340.1 H

1,390,681 W 390.9 T 780.0 P 336.1 H

12 14
Carbon Dioxide Capture Sensitivity Analysis

288

Exhibit 4-59 Case 2 D2D (75%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine

Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator

Ip Extraction Steam To 250 PSIA Header

LP Process Header

Blowdown Flash To WWT

Gland Steam Condenser Condensate to Gasification Island

HP BFW to Radiant Syngas Cooler HP Saturated Steam to HRSG Superheater

LP Turbine

Stack

Compressor Expander

Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class Gas Turbine

MP Flash Bottoms LP Flash Tops

7,014,133 W 59.0 T 14.7 P 13.0 H 1,760,818 W 101.1 T 1.0 P 69.1 H

8,524,103 W 270.0 T 15.2 P 136.7 H

295,309 W 387.7 T 460.0 P 324.1 H

8,524,103 W 1,052.4 T 15.2 P 348.5 H From Gasifier Island Preheating

To Claus

LP BFW 1,358,296 W 1,002.4 T 1,814.7 P 1,481.2 H

10,201 W 298.0 T 65.0 P 1,179.0 H 1,386,847 W 278.8 T 2,250.7 P 252.3 H 28,550 W 585.0 T 2,000.7 P 593.3 H

1,587,698 W 484.0 T 65.0 P 1,274.2 H

1,760,818 W 103.0 T 120.0 P 71.2 H

1,760,818 W 235.0 T 105.0 P 203.7 H

1,400 W 623.3 T 65.0 P 1,342.8 H 1,400 W 212.0 T 14.7 P 179.9 H

IP Pump NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D2D HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D2D (75%) GEE GASIFIER POWER BLOCK SYSTEM DWG. NO. CCSA-HMB-CS-2-D2D-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 3 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 742 MWe Auxiliary Load: 178 MWe Net Plant Power: 564 MWe Net Plant Efficiency, HHV: 34.3% Net Plant Heat Rate: 9,958 BTU/KWe 24

25

27 19

26

Flue Gas

HOT WELL CONDENSER Make-up 161,004 W 59.0 T 14.7 P 27.1 H

8,989 W 667.7 T 501.4 P 1,338.7 H 9,716 W 623.3 T 65.0 P 1,342.8 H 30,139 W 860.2 T 280.0 P 1,453.1 H 795 W 1,002.4 T 1,814.7 P 1,481.2 H 1,333 W 511.3 T 65.0 P 1,287.7 H
Carbon Dioxide Capture Sensitivity Analysis

289

Exhibit 4-60 Case 2 D2A (25%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,697 

(5,400) 4.8 (4.5) 0 (0) 5,702 (5,404)

ASU Air 0 (0) 22.7 (21.5) 0 (0) 23 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 66.9 (63.4) 0 (0) 67 (63)

Totals 5,697 

(5,400) 190.5 (180.5) 0 (0) 5,888 (5,580)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.9 (1.8) 0 (0) 2 (2)

Slag 88 (83) 36.0 (34.1) 0 (0) 124 (117)

Sulfur 49 (46) 0.6 (0.6) 0 (0) 49 (47)

CO2 0 (0) -13.1 (-12.4) 0 (0) -13 (-12)

Gasifier Heat Loss 0 (0) 42.4 (40.2) 0 (0) 42 (40)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 937 (889) 0 (0) 937 (889)

Cooling Tower* 0 (0) 2,073 (1,965) 0 (0) 2,073 

(1,965)

Process Losses** 0 (0) 424 (402) 0 (0) 424 (402)

Net Power 0 (0) 0.0 (0.0) 2,185 

(2,071)

2,185 

(2,071)

Totals 136 (129) 3,566 (3,380) 2,185 

(2,071)

5,888 

(5,580)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Includes Condenser, Cooling Tower Blowdown, and the following Non-Condenser 

 Cooling Tower Loads: ASU compressor intercoolers, CO2 compressor intercoolers,

 sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

 air cooler.

** Calculated by difference to close the energy balance.
Carbon Dioxide Capture Sensitivity Analysis

290

Exhibit 4-61 Case 2 D2B (45%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,786 

(5,484) 4.8 (4.6) 0 (0) 5,791 (5,489)

ASU Air 0 (0) 23.1 (21.8) 0 (0) 23 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 71.7 (68.0) 0 (0) 72 (68)

Totals 5,786 

(5,484) 195.8 (185.5) 0 (0) 5,982 (5,670)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.9 (1.8) 0 (0) 2 (2)

Slag 89 (84) 36.5 (34.6) 0 (0) 126 (119)

Sulfur 49 (47) 0.6 (0.6) 0 (0) 50 (47)

CO2 0 (0) -31.7 (-30.1) 0 (0) -32 (-30)

Gasifier Heat Loss 0 (0) 43.1 (40.8) 0 (0) 43 (41)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,051 (996) 0 (0) 1,051 (996)

Cooling Tower* 0 (0) 2,113 (2,003) 0 (0) 2,113 

(2,003)

Process Losses** 0 (0) 439 (416) 0 (0) 439 (416)

Net Power 0 (0) 0.0 (0.0) 2,127 

(2,016)

2,127 

(2,016)

Totals 139 (131) 3,717 (3,523) 2,127 

(2,016)

5,982 

(5,670)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Includes Condenser, Cooling Tower Blowdown, and the following Non-Condenser 

 Cooling Tower Loads: ASU compressor intercoolers, CO2 compressor intercoolers,

 sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

 air cooler.

** Calculated by difference to close the energy balance.
Carbon Dioxide Capture Sensitivity Analysis

291

Exhibit 4-62 Case 2 D2C (60%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,860 

(5,555) 4.9 (4.6) 0 (0) 5,865 (5,559)

ASU Air 0 (0) 23.4 (22.1) 0 (0) 23 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 75.4 (71.5) 0 (0) 75 (71)

Totals 5,860 

(5,555) 199.9 (189.4) 0 (0) 6,060 (5,744)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.9 (1.8) 0 (0) 2 (2)

Slag 90 (86) 37.0 (35.1) 0 (0) 127 (121)

Sulfur 50 (47) 0.6 (0.6) 0 (0) 51 (48)

CO2 0 (0) -45.9 (-43.5) 0 (0) -46 (-43)

Gasifier Heat Loss 0 (0) 43.6 (41.4) 0 (0) 44 (41)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,143 (1,083) 0 (0) 1,143 

(1,083)

Cooling Tower* 0 (0) 2,139 (2,028) 0 (0) 2,139 

(2,028)

Process Losses** 0 (0) 455 (431) 0 (0) 455 (431)

Net Power 0 (0) 0.0 (0.0) 2,082 

(1,974)

2,082 

(1,974)

Totals 140 (133) 3,838 (3,637) 2,082 

(1,974)

6,060 

(5,744)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Includes Condenser, Cooling Tower Blowdown, and the following Non-Condenser 

 Cooling Tower Loads: ASU compressor intercoolers, CO2 compressor intercoolers,

 sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

 air cooler.

** Calculated by difference to close the energy balance.
Carbon Dioxide Capture Sensitivity Analysis

292

Exhibit 4-63 Case 2 D2D (75%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,925 

(5,615) 5.0 (4.7) 0 (0) 5,930 (5,620)

ASU Air 0 (0) 23.6 (22.4) 0 (0) 24 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 78.7 (74.6) 0 (0) 79 (75)

Totals 5,925 

(5,615) 203.4 (192.8) 0 (0) 6,128 (5,808)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.8 (1.7) 0 (0) 2 (2)

Slag 91 (86) 37.4 (35.4) 0 (0) 129 (122)

Sulfur 51 (48) 0.6 (0.6) 0 (0) 51 (49)

CO2 0 (0) -59.7 (-56.6) 0 (0) -60 (-57)

Gasifier Heat Loss 0 (0) 44.1 (41.8) 0 (0) 44 (42)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,230 (1,166) 0 (0) 1,230 

(1,166)

Cooling Tower* 0 (0) 2,152 (2,040) 0 (0) 2,152 

(2,040)

Process Losses** 0 (0) 486 (461) 0 (0) 486 (461)

Net Power 0 (0) 0.0 (0.0) 2,030 

(1,924)

2,030 

(1,924)

Totals 142 (134) 3,956 (3,750) 2,030 

(1,924)

6,128 

(5,808)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Includes Condenser, Cooling Tower Blowdown, and the following Non-Condenser 

 Cooling Tower Loads: ASU compressor intercoolers, CO2 compressor intercoolers,

 sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

 air cooler.

** Calculated by difference to close the energy balance.
Carbon Dioxide Capture Sensitivity Analysis

293

Exhibit 4-64 Case 2 D2A Energy Balance Sankey Diagram

Exhibit 4-65 Case 2 D2B Energy Balance Sankey Diagram
Carbon Dioxide Capture Sensitivity Analysis

294

Exhibit 4-66 Case 2 D2C Energy Balance Sankey Diagram

Exhibit 4-67 Case 2 D2D Energy Balance Sankey Diagram
Carbon Dioxide Capture Sensitivity Analysis

295

4.3.2.2 Major Equipment List for Case 2 D2

Major equipment items for Case 2 D2 (single WGS with bypass) are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates. 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. 

ACCOUNT 1 COAL HANDLING

Equipment 

No. Description Type

Design Conditions Opr Qty.

D2A D2B D2C D2D (Spares)

1

Bottom Trestle Dumper and 

Receiving Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0)

3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

4 Transfer Tower No. 1 Enclosed N/A N/A N/A N/A 1 (0)

5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

6

As-Received Coal Sampling 

System Two-stage N/A N/A N/A N/A 1 (0)

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

8 Reclaim Hopper N/A 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 2 (1)

9 Feeder Vibratory 172 tonne/hr (190 tph) 172 tonne/hr (190 tph) 181 tonne/hr (200 tph) 181 tonne/hr (200 tph) 2 (1)

10 Conveyor No. 3 Belt w/ tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 1 (0)

11 Crusher Tower N/A N/A N/A N/A N/A 1 (0)

12 Coal Surge Bin w/ Vent 

Filter Dual outlet 172 tonne (190 ton) 172 tonne (190 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

2 (0)

14 As-Fired Coal Sampling 

System Swing hammer N/A N/A N/A N/A 1 (1)

15 Conveyor No. 4 Belt w/tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 1 (0)

16 Transfer Tower No. 2 Enclosed N/A N/A N/A N/A 1 (0)

17 Conveyor No. 5 Belt w/ tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 1 (0)

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 726 tonne (800 ton) 816 tonne (900 ton) 816 tonne (900 ton) 816 tonne (900 ton) 3 (0)

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type

Design Condition Opr Qty.

D2A D2B D2C D2D (Spares)

1 Feeder Vibratory 73 tonne/h (80 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 3 (0)

2 Conveyor No. 6 Belt w/tripper 227 tonne/h (250 tph) 236 tonne/h (260 tph) 236 tonne/h (260 tph) 236 tonne/h (260 tph) 1 (0)

3 Rod Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 472 tonne (520 ton) 472 tonne (520 ton) 481 tonne (530 ton) 1 (0)

4 Weigh Feeder Belt 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)

5 Rod Mill Rotary 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)

6

Slurry Water Storage 

Tank with Agitator Field erected 285,044 liters (75,300 gal) 289,511 liters (76,480 gal)

293,220 liters 

(77,460 gal)

296,438 liters 

(78,310 gal)

2 (0)

7 Slurry Water Pumps Centrifugal 795 lpm (210 gpm) 795 lpm (210 gpm) 833 lpm (220 gpm) 833 lpm (220 gpm) 2 (1)

8 Trommel Screen Coarse 163 tonne/h (180 tph) 163 tonne/h (180 tph) 163 tonne/h (180 tph) 172 tonne/h (190 tph) 2 (0)
Carbon Dioxide Capture Sensitivity Analysis

296

Equipment 

No. Description Type

Design Condition Opr Qty.

D2A D2B D2C D2D (Spares)

9

Rod Mill Discharge Tank 

with Agitator Field erected 372,866 liters (98,500 gal) 378,696 liters (100,040 gal)

383,541 liters 

(101,320 gal)

387,781 liters 

(102,440 gal)

2 (0)

10 Rod Mill Product Pumps Centrifugal 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,407 lpm (900 gpm) 2 (2)

11 Slurry Storage Tank with 

Agitator Field erected 1,118,598 liters (295,500 gal)

1,136,011 liters 

(300,100 gal)

1,150,774 liters 

(304,000 gal)

1,163,266 liters 

(307,300 gal)

2 (0)

12 Slurry Recycle Pumps Centrifugal 6,057 lpm (1,600 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 2 (2)

13 Slurry Product Pumps Positive 

displacement 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,407 lpm (900 gpm) 2 (2)

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment No. Description Type

Design Condition Opr Qty.

D2A D2B D2C D2D (Spares)

1

Demineralized Water Storage 

Tank

Vertical, cylindrical, 

outdoor 1,086,413 liters (287,000 gal) 1,090,199 liters (288,000 gal)

1,078,842 liters 

(285,000 gal)

1,067,486 liters 

(282,000 gal)

2 (0)

2 Condensate Pumps Vertical canned 7,041 lpm @ 91 m H2O

(1,860 gpm @ 300 ft H2O)

7,230 lpm @ 91 m H2O

(1,910 gpm @ 300 ft H2O)

7,344 lpm @ 91 m H2O

(1,940 gpm @ 300 ft H2O)

7,382 lpm @ 91 m H2O

(1,950 gpm @ 300 ft H2O)

2 (1)

3 Deaerator (integral w/ HRSG) Horizontal spray type 484,437 kg/hr 

(1,068,000 lb/hr)

495,323 kg/hr 

(1,092,000 lb/hr)

501,220 kg/hr 

(1,105,000 lb/hr)

505,755 kg/hr 

(1,115,000 lb/hr)

2 (0)

4

Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

8,101 lpm @ 27 m H2O

(2,140 gpm @ 90 ft H2O)

8,139 lpm @ 27 m H2O

(2,150 gpm @ 90 ft H2O)

7,912 lpm @ 27 m H2O

(2,090 gpm @ 90 ft H2O)

7,684 lpm @ 27 m H2O

(2,030 gpm @ 90 ft H2O)

2 (1)

5

High Pressure Feedwater Pump 

No. 1

Barrel type, multistage, centrifugal

HP water: 6,132 lpm @ 1,859 

m H2O (1,620 gpm @ 6,100 

ft H2O)

HP water: 6,132 lpm @ 

1,859 m H2O (1,620 gpm @ 

6,100 ft H2O)

HP water: 6,057 lpm @ 

1,859 m H2O (1,600 gpm @ 

6,100 ft H2O)

HP water: 5,981 lpm @ 

1,859 m H2O (1,580 gpm @ 

6,100 ft H2O)

2 (1)

6

High Pressure Feedwater Pump 

No. 2

Barrel type, multistage, centrifugalIP water: 1,476 lpm @ 223 m 

H2O (390 gpm @ 730 ft H2O)

IP water: 1,514 lpm @ 223 

m H2O (400 gpm @ 730 ft 

H2O)

IP water: 1,628 lpm @ 223 

m H2O (430 gpm @ 730 ft 

H2O)

IP water: 1,703 lpm @ 223 

m H2O (450 gpm @ 730 ft 

H2O)

2 (1)

7 Auxiliary Boiler Shop fabricated, water 

tube

18,144 kg/hr, 2.8 MPa, 343°C

(40,000 lb/hr, 400 psig, 

650°F)

18,144 kg/hr, 2.8 MPa, 

343°C

(40,000 lb/hr, 400 psig, 

650°F)

18,144 kg/hr, 2.8 MPa, 

343°C

(40,000 lb/hr, 400 psig, 

650°F)

18,144 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)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

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) 28 m3/min (1,000 scfm) 28 m3/min (1,000 scfm) 28 m3/min (1,000 scfm) 2 (1)

10 Closed Cylce Cooling Heat 

Exchangers Plate and frame 248 GJ/hr (234.6264965 MMBtu/hr) each

275 GJ/hr (260.9758943 

MMBtu/hr) each

299 GJ/hr (283.58088495 

MMBtu/hr) each

324 GJ/hr (306.6532524 

MMBtu/hr) each

2 (0)

11 Closed Cycle Cooling Water 

Pumps Horizontal centrifugal 88,957 lpm @ 21 m H2O(23,500 gpm @ 70 ft H2O)

98,799 lpm @ 21 m H2O

(26,100 gpm @ 70 ft H2O)

107,506 lpm @ 21 m H2O

(28,400 gpm @ 70 ft H2O)

116,212 lpm @ 21 m H2O

(30,700 gpm @ 70 ft H2O)

2 (1)

12 Engine-Driven Fire Pump Vertical turbine, diesel 

engine

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

1 (1)

13 Fire Service Booster Pump Two-stage horizontal 

centrifugal

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

1 (1)

14 Raw Water Pumps Stainless steel, single 

suction

4,580 lpm @ 18 m H2O

(1,210 gpm @ 60 ft H2O)

4,921 lpm @ 18 m H2O

(1,300 gpm @ 60 ft H2O)

5,186 lpm @ 18 m H2O

(1,370 gpm @ 60 ft H2O)

5,413 lpm @ 18 m H2O

(1,430 gpm @ 60 ft H2O)

2 (1)

15 Ground Water Pumps Stainless steel, single 

suction

3,028 lpm @ 268 m H2O 

(800 gpm @ 880 ft H2O)

3,293 lpm @ 268 m H2O 

(870 gpm @ 880 ft H2O)

2,574 lpm @ 268 m H2O 

(680 gpm @ 880 ft H2O)

2,725 lpm @ 268 m H2O 

(720 gpm @ 880 ft H2O)

3 (1)

16 Filtered Water Pumps Stainless steel, single 

suction

2,082 lpm @ 49 m H2O

(550 gpm @ 160 ft H2O)

2,309 lpm @ 49 m H2O

(610 gpm @ 160 ft H2O)

2,498 lpm @ 49 m H2O

(660 gpm @ 160 ft H2O)

2,688 lpm @ 49 m H2O

(710 gpm @ 160 ft H2O)

2 (1)

17 Filtered Water Tank Vertical, cylindrical 999,349 liter (264,000 gal) 1,112,911 liter (294,000 gal) 1,207,546 liter (319,000 gal) 1,290,825 liter (341,000 gal) 2 (0)

18 Makeup Water Demineralizer Anion, cation, and 

mixed bed 303 lpm (80 gpm) 530 lpm (140 gpm) 681 lpm (180 gpm) 871 lpm (230 gpm) 2 (0)
Carbon Dioxide Capture Sensitivity Analysis

297

Equipment No. Description Type

Design Condition Opr Qty.

D2A D2B D2C D2D (Spares)

19 Liquid Waste Treatment System 10 years, 24-hour storm 10 years, 24-hour storm 10 years, 24-hour storm 10 years, 24-hour storm 1 (0)

ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment No. Description Type

Design Condition Opr Qty.

D2A D2B D2C D2D (Spares)

1 Gasifier Pressurized slurryfeed, entrained bed

2,812 tonne/day, 5.6 MPa

(3,100 tpd, 814.96 psia)

2,812 tonne/day, 5.6 MPa

(3,100 tpd, 814.96 psia)

2,812 tonne/day, 5.6 MPa

(3,100 tpd, 814.96 psia)

2,903 tonne/day, 5.6 MPa

(3,200 tpd, 814.96 psia)

2 (0)

2 Synthesis Gas Cooler

Vertical downflow 

radiant heat 

exchanger with outlet 

quench chamber

243,126 kg/hr (536,000 lb/hr) 247,208 kg/hr (545,000 

lb/hr)

250,383 kg/hr (552,000 

lb/hr)

253,105 kg/hr (558,000 

lb/hr)

2 (0)

3 Synthesis Gas Cyclone High efficiency 332,937 kg/hr (734,000 lb/hr) 

Design efficiency 90%

337,926 kg/hr (745,000 

lb/hr) Design efficiency 90%

342,462 kg/hr (755,000 

lb/hr) Design efficiency 90%

346,091 kg/hr (763,000 

lb/hr) Design efficiency 90%

2 (0)

4 Candle Filter Pressurized filter with 

pulse-jet cleaning metallic filters metallic filters metallic filters metallic filters 2 (0)

5

Syngas Scrubber Including Sour 

Water Stripper Vertical upflow 332,937 kg/hr (734,000 lb/hr) 337,926 kg/hr (745,000 lb/hr)

342,462 kg/hr 

(755,000 lb/hr)

346,091 kg/hr 

(763,000 lb/hr)

2 (0)

6 Raw Gas Coolers Shell and tube with 

condensate drain 288,031 kg/hr (635,000 lb/hr) 319,329 kg/hr (704,000 lb/hr)

333,844 kg/hr 

(736,000 lb/hr)

346,998 kg/hr 

(765,000 lb/hr)

8 (0)

7 Raw Gas Knockout Drum Vertical with mist 

eliminator

213,642 kg/hr, 35°C, 5.1 MPa

(471,000 lb/hr, 95°F, 745 

psia)

240,404 kg/hr, 35°C, 5.2 

MPa

(530,000 lb/hr, 95°F, 750 

psia)

262,630 kg/hr, 35°C, 5.1 

MPa

(579,000 lb/hr, 95°F, 745 

psia)

283,042 kg/hr, 35°C, 5.1 

MPa

(624,000 lb/hr, 95°F, 745 

psia)

2 (0)

8 Flare Stack

Self-supporting, 

carbon steel, stainless 

steel top, pilot ignition

332,937 kg/hr (734,000 lb/hr) 

syngas

337,926 kg/hr (745,000 

lb/hr) syngas

342,462 kg/hr (755,000 

lb/hr) syngas

346,091 kg/hr (763,000 

lb/hr) syngas

2 (0)

9 ASU Main Air Compressor Centrifugal, multistage

5,663 m3/min @ 1.3 MPa

(200,000 scfm @ 190 psia)

5,748 m3/min @ 1.3 MPa

(203,000 scfm @ 190 psia)

5,805 m3/min @ 1.3 MPa

(205,000 scfm @ 190 psia)

5,862 m3/min @ 1.3 MPa

(207,000 scfm @ 190 psia)

2 (0)

10 Cold Box Vendor design 2,268 tonne/day (2,500 tpd) 

of 95% purity oxygen

2,268 tonne/day (2,500 tpd) 

of 95% purity oxygen

2,359 tonne/day (2,600 tpd) 

of 95% purity oxygen

2,359 tonne/day (2,600 tpd) 

of 95% purity oxygen

2 (0)

11 Oxygen Compressor Centrifugal, multistage

1,133 m3/min (40,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 

psia)

1,161 m3/min (41,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 

psia)

1,161 m3/min (41,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 

psia)

1,189 m3/min (42,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 

psia)

2 (0)

12 Primary Nitrogen Compressor Centrifugal, multistage

3,540 m3/min (125,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 

psia)

3,596 m3/min 

(127,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 

psia)

3,653 m3/min 

(129,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 

psia)

3,710 m3/min 

(131,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 

psia)

2 (0)

13 Secondary Nitrogen 

Compressor

Centrifugal, singlestage

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 

psia)

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 

psia)

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 

psia)

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 

psia)

2 (0)

14 Syngas Dilution Nitrogen Boost 

Compressor

Centrifugal, singlestage

0 m3/min (0 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 

psia)

57 m3/min (2,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 

psia)

680 m3/min (24,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 

psia)

1,331 m3/min (47,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 

psia)

2 (0)
Carbon Dioxide Capture Sensitivity Analysis

298

ACCOUNT 5A SYNGAS CLEANUP

Equipment 

No. Description Type

Design Condition Opr Qty.

D2A D2B D2C D2D (Spares)

1

Mercury 

Adsorber

Sulfated carbon 

bed

213,188 kg/hr 

(470,000 lb/hr) 

35°C (95°F) 

5.1 MPa (745 psia)

239,950 kg/hr 

(529,000 lb/hr) 

35°C (95°F) 

5.1 MPa (745 psia)

262,176 kg/hr (578,000 lb/hr) 

35°C (95°F) 

5.1 MPa (745 psia)

282,588 kg/hr 

(623,000 lb/hr) 

35°C (95°F) 

5.1 MPa (745 psia)

2 (0)

2 Sulfur Plant Claus type 139 tonne/day (153 tpd) 141 tonne/day (155 tpd) 143 tonne/day (157 tpd) 144 tonne/day (159 tpd) 1 (0)

3

Water Gas Shift 

Reactor

Fixed bed, 

catalytic

1,814 kg/hr (4,000 lb/hr) 

232°C (450°F) 

5.4 MPa (790 psia)

135,624 kg/hr (299,000 

lb/hr) 

221°C (430°F) 

5.4 MPa (790 psia)

244,486 kg/hr (539,000 lb/hr) 

221°C (430°F) 

5.4 MPa (790 psia)

346,998 kg/hr (765,000 

lb/hr) 

221°C (430°F) 

5.4 MPa (790 psia)

2 (0)

4

Shift Reactor 

Heat Recovery 

Exchangers

Shell and Tube

Exchanger 1: 02 GJ/hr 

(02 MMBtu/hr) 

Exchanger 2: 6 GJ/hr 

(6 MMBtu/hr) 

Exchanger 1: 109 GJ/hr 

(103 MMBtu/hr) 

Exchanger 2: 6 GJ/hr 

(6 MMBtu/hr) 

Exchanger 1: 196 GJ/hr 

(186 MMBtu/hr) 

Exchanger 2: 6 GJ/hr 

(6 MMBtu/hr) 

Exchanger 1: 278 GJ/hr 

(264 MMBtu/hr) 

Exchanger 2: 6 GJ/hr 

(6 MMBtu/hr) 

2 (0)

5

COS Hydrolysis 

Reactor

Fixed bed, 

catalytic

301,639 kg/hr 

(665,000 lb/hr)

210°C (410°F)

5.4 MPa (790 psia)

319,329 kg/hr 

(704,000 lb/hr)

210°C (410°F)

5.4 MPa (790 psia)

333,844 kg/hr (736,000 lb/hr)

204°C (400°F)

5.4 MPa (790 psia)

346,998 kg/hr 

(765,000 lb/hr)

204°C (400°F)

5.4 MPa (790 psia)

2 (0)

6

Acid Gas 

Removal Plant

Two-stage 

Selexol

214,549 kg/hr 

(473,000 lb/hr) 

35°C (95°F) 

5.1 MPa (740 psia)

241,311 kg/hr 

(532,000 lb/hr) 

35°C (95°F) 

5.1 MPa (740 psia)

263,084 kg/hr (580,000 lb/hr) 

35°C (95°F) 

5.1 MPa (740 psia)

285,310 kg/hr 

(629,000 lb/hr) 

35°C (95°F) 

5.1 MPa (740 psia)

2 (0)

7

Hydrogenation 

Reactor

Fixed bed, 

catalytic

6,340 kg/hr (13,978 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

6,081 kg/hr (13,407 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

5,879 kg/hr (12,961 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

9,424 kg/hr (20,776 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

1 (0)

8

Tail Gas Recycle 

Compressor Centrifugal 3,053 kg/hr (6,730 lb/hr) 2,497 kg/hr (5,506 lb/hr) 2,052 kg/hr (4,524 lb/hr) 5,537 kg/hr (12,206 lb/hr) 1 (0)

ACCOUNT 5B CO2 COMPRESSION

Equipment 

No. Description Type

Design Condition Opr Qty.

D2A D2B D2C D2D (Spares)

1 CO2 Compressor Integrally geared, multistage centrifugal

303 m

3

/min @ 15.3 MPa 

(10,700 scfm @ 2,215 

psia)

544 m

3

/min @ 15.3 MPa 

(19,200 scfm @ 2,215 

psia)

736 m3/min @ 15.3 MPa 

(26,000 scfm @ 2,215 

psia)

929 m3/min @ 15.3 MPa 

(32,800 scfm @ 2,215 

psia)

4 (0)

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment 

No. Description Type

Design Condition Opr Qty.

D2A D2B D2C D2D (Spares)

1 Gas Turbine Advanced F class 230 MW 230 MW 230 MW 230 MW 2 (0)

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase

260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase

260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase

260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase

2 (0)

3

Syngas Expansion 

Turbine/Generator Turbo Expander

144,560 kg/h (318,700 lb/h)

5.0 MPa (720 psia) Inlet

3.2 MPa (460 psia) Outlet

117,435 kg/h (258,900 lb/h)

5.0 MPa (730 psia) Inlet

3.2 MPa (460 psia) Outlet

96,207 kg/h (212,100 lb/h)

5.0 MPa (720 psia) Inlet

3.2 MPa (460 psia) Outlet

73,663 kg/h (162,400 lb/h)

5.0 MPa (730 psia) Inlet

3.2 MPa (460 psia) Outlet

2 (0)
Carbon Dioxide Capture Sensitivity Analysis

299

ACCOUNT 7 HRSG, DUCTING, AND STACK

Equipment 

No. Description Type

Design Condition Opr Qty.

D2A D2B D2C D2D (Spares)

1 Stack CS plate, type 

409SS liner

76 m (250 ft) high x

8.4 m (28 ft) diameter

76 m (250 ft) high x

8.4 m (28 ft) diameter

76 m (250 ft) high x

8.4 m (28 ft) diameter

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 - 346,953 kg/hr, 

12.4 MPa/554°C (764,901 

lb/hr, 1,800 psig/1,029°F)

 Reheat steam - 346,475 

kg/hr, 3.1 MPa/554°C (763,846 

lb/hr, 452 psig/1,029°F)

Main steam - 345,876 kg/hr, 

12.4 MPa/548°C (762,527 

lb/hr, 1,800 psig/1,019°F)

 Reheat steam - 342,768 

kg/hr, 3.1 MPa/548°C (755,673 

lb/hr, 452 psig/1,019°F)

Main steam - 342,439 kg/hr, 

12.4 MPa/544°C (754,948 

lb/hr, 1,800 psig/1,011°F)

 Reheat steam - 346,896 

kg/hr, 3.1 MPa/544°C (764,776 

lb/hr, 452 psig/1,011°F)

Main steam - 338,862 kg/hr, 

12.4 MPa/539°C (747,063 

lb/hr, 1,800 psig/1,002°F)

 Reheat steam - 350,486 

kg/hr, 3.1 MPa/539°C (772,688 

lb/hr, 452 psig/1,002°F)

2 (0)

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type

Design Condition Opr Qty.

D2A D2B D2C D2D (Spares)

1 Steam Turbine

Commercially 

available advanced 

steam turbine

295 MW 12.4 

MPa/554°C/554°C (1,800 psig/ 

1029°F/1029°F)

292 MW 12.4 

MPa/548°C/548°C (1,800 psig/ 

1019°F/1019°F)

290 MW 12.4 

MPa/544°C/544°C (1,800 psig/ 

1011°F/1011°F)

286 MW 12.4 

MPa/539°C/539°C (1,800 psig/ 

1002°F/1002°F)

1 (0)

2

Steam Turbine 

Generator

Hydrogen cooled, 

static excitation

330 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

320 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

320 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

320 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design 

steam conditions

50% steam flow @ design 

steam conditions

50% steam flow @ design 

steam conditions

50% steam flow @ design 

steam conditions

2 (0)

4

Surface 

Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,783 GJ/hr (1,690 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), Water temperature rise 

11°C (20°F)

1,772 GJ/hr (1,680 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), Water temperature rise 

11°C (20°F)

1,751 GJ/hr (1,660 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), Water temperature rise 

11°C (20°F)

1,720 GJ/hr (1,630 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), Water temperature rise 

11°C (20°F)

1 (0)

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type

Design Condition Opr Qty.

D2A D2B D2C D2D (Spares)

1

Circulating 

Water Pumps Vertical, wet pit 416,395 lpm @ 30 m(110,000 gpm @ 100 ft)

431,537 lpm @ 30 m

(114,000 gpm @ 100 ft)

442,893 lpm @ 30 m

(117,000 gpm @ 100 ft)

450,464 lpm @ 30 m

(119,000 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 / 2,332 GJ/hr (2,210 

MMBtu/hr) heat duty

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) 

HWT / 2,416 GJ/hr (2,290 

MMBtu/hr) heat duty

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) 

HWT / 2,469 GJ/hr (2,340 

MMBtu/hr) heat duty

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) 

HWT / 2,522 GJ/hr (2,390 

MMBtu/hr) heat duty

1 (0)

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type

Design Condition Opr Qty.

D2A D2B D2C D2D (Spares)

1 Slag Quench Tank Water bath 242,266 liters (64,000 gal) 246,052 liters (65,000 gal) 249,837 liters (66,000 gal) 249,837 liters (66,000 gal) 2 (0)

2 Slag Crusher Roll 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 2 (0)

3 Slag Depressurizer Lock Hopper 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 2 (0)

4 Slag Receiving Tank Horizontal, weir 143,846 liters (38,000 gal) 147,631 liters (39,000 gal) 151,416 liters (40,000 gal) 151,416 liters (40,000 gal) 2 (0)

5

Black Water Overflow 

Tank Shop fabricated 64,352 liters (17,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)
Carbon Dioxide Capture Sensitivity Analysis

300

Equipment 

No. Description Type

Design Condition Opr Qty.

D2A D2B D2C D2D (Spares)

6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 2 (0)

7

Slag Separation 

Screen Vibrating 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 2 (0)

8

Coarse Slag 

Conveyor Belt/bucket 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 2 (0)

9

Fine Ash Settling 

Tank Vertical, gravity 208,198 liters (55,000 gal) 208,198 liters (55,000 gal) 211,983 liters (56,000 gal) 215,768 liters (57,000 gal) 2 (0)

10 Fine Ash Recycle 

Pumps Horizontal centrifugal 38 lpm @ 14 m H2O(10 gpm @ 46 ft H2O)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

2 (2)

11 Grey Water Storage 

Tank Field erected 64,352 liters (17,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H2O

(60 gpm @ 1,850 ft H2O)

227 lpm @ 564 m H2O

(60 gpm @ 1,850 ft H2O)

227 lpm @ 564 m H2O

(60 gpm @ 1,850 ft H2O)

227 lpm @ 564 m H2O

(60 gpm @ 1,850 ft H2O)

2 (2)

13 Slag Storage Bin Vertical, field erected 907 tonne (1,000 tons) 907 tonne (1,000 tons) 907 tonne (1,000 tons) 907 tonne (1,000 tons) 2 (0)

14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 1 (0)

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type

Design Condition Opr Qty.

D2A D2B D2C D2D (Spares)

1

CTG Step-up 

Transformer Oil-filled 24 kV/345 kV, 260 MVA, 3-ph, 60 Hz

24 kV/345 kV, 260 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 260 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 260 MVA, 

3-ph, 60 Hz

2 (0)

2

STG Step-up 

Transformer Oil-filled 24 kV/345 kV, 330 MVA, 3-ph, 60 Hz

24 kV/345 kV, 320 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 320 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 320 MVA, 

3-ph, 60 Hz

1 (0)

3

High Voltage Auxiliary 

Transformer Oil-filled 345 kV/13.8 kV, 63 MVA, 3-ph, 60 Hz

345 kV/13.8 kV, 68 MVA, 

3-ph, 60 Hz

345 kV/13.8 kV, 72 MVA, 

3-ph, 60 Hz

345 kV/13.8 kV, 76 MVA, 

3-ph, 60 Hz

2 (0)

4

Medium Voltage 

Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 30 MVA, 3-ph, 60 Hz

24 kV/4.16 kV, 34 MVA, 

3-ph, 60 Hz

24 kV/4.16 kV, 38 MVA, 

3-ph, 60 Hz

24 kV/4.16 kV, 43 MVA, 

3-ph, 60 Hz

1 (1)

5

Low Voltage 

Transformer Dry ventilated 4.16 kV/480 V, 4 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 5 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 6 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 6 MVA, 

3-ph, 60 Hz

1 (1)

6

CTG Isolated Phase 

Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 2 (0)

7

STG Isolated Phase 

Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 1 (0)

8

Medium Voltage 

Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz 1 (1)

9

Low Voltage 

Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz 1 (1)

10 Emergency Diesel 

Generator

Sized for emergency 

shutdown 750 kW, 480 V, 3-ph, 60 Hz 750 kW, 480 V, 3-ph, 60 Hz 750 kW, 480 V, 3-ph, 60 Hz 750 kW, 480 V, 3-ph, 60 Hz 1 (0)
Carbon Dioxide Capture Sensitivity Analysis

301

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment 

No. Description Type

Design Condition Opr Qty.

D2A D2B D2C D2D (Spares)

1

DCS - Main 

Control

Monitor/keyboard; 

Operator printer 

(laser color); 

Engineering printer 

(laser B&W)

Operator stations/printers and 

engineering stations/printers

Operator stations/printers and 

engineering stations/printers

Operator stations/printers and 

engineering stations/printers

Operator stations/printers and 

engineering stations/printers

1 (0)

2

DCS -

Processor

Microprocessor with 

redundant 

input/output

N/A N/A N/A N/A 1 (0)

3

DCS - Data 

Highway Fiber optic Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare 1 (0)
Carbon Dioxide Capture Sensitivity Analysis

302

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Carbon Dioxide Capture Sensitivity Analysis

303

4.3.3 IGCC Design 3 – Two Water Gas Shift Reactors with Bypass

A process block flow diagram for Case 2 Design 3 (D3) is shown in Exhibit 4-68. D3 represents 

an IGCC plant with two WGS reactors and a bypass stream (stream 13). This IGCC design uses 

a S:DG molar ratio of 0.25 at the outlet of the second WGS reactor. The WGS bypass ratio and 

the two-stage SelexolTM CO2 removal efficiency are adjusted to control the total CO2 capture 

level. The SelexolTM removal efficiency is altered by varying the solvent circulation rate, which 

changes the size and cost of the SelexolTM system.

The WGS bypass impacts the degree of CO to CO2 and COS to H2S conversion across the WGS 

reactor. Consequently, the WGS bypass stream is routed through a COS hydolysis unit to ensure 

that sulfur emissions are below the limit of 0.0128 lb SO2/MMBtu. 

Five levels of total CO2 removal were modeled for Case 2 D3: 25 percent (D3A), 45 percent

(D3B), 60 percent (D3C), 75 percent (D3D), and 85 percent (D3E). The corresponding stream 

tables are contained in Exhibit 4-69, Exhibit 4-70, Exhibit 4-71, Exhibit 4-72, and Exhibit 4-73, 

respectively. 

Overall performance for Case 2 D3 is summarized in Exhibit 4-74 which includes auxiliary 

power requirements.

Material and energy balance information, environmental performance and a major equipment list

are summarized in Sections 4.3.3.1 and 4.3.3.2.
Carbon Dioxide Capture Sensitivity Analysis

304

Exhibit 4-68 Case 2 D3 Process Block Flow Diagram, IGCC with Two WGS Reactors and Bypass

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 TWO- STAGE SELEXOL UNIT

CLAUS PLANT

HRSG

AMBIENT AIR

SYNGAS EXPANDER HYDROGENATION REACTOR AND GAS COOLER

CO2 COMPRESSION

1 5

9

12 16 17

19

21 22

23

20

6 8

2 3 4

24

25 26

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 ADVANCED F CLASS GAS TURBINE

SYNGAS H/P REHEAT

18

CLAUS PLANT OXIDANT STEAM TURBINE 27 464 MWe Note: Block Flow Diagram is not intended to represent a complete material balance. Only major process streams and equipment are shown.

23 TAIL GAS RECYCLE FROM CLAUS PLANT

SLURRY MIXER SLURRY 7 WATER

COS HYDROLYSIS

15 11 10 13

14
Carbon Dioxide Capture Sensitivity Analysis

305

Exhibit 4-69 Case 2 D3A Stream Table, 25% CO2 Removal with Two WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

A r 0.0092 0.0141 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0068 0.0068 0.0068

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0009 0.0009 0.0009

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2820 0.0000 0.0372 0.2820 0.2820

CO2 0.0003 0.0044 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.0000 0.3537 0.1088 0.1090

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 0.0001 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2686 0.0000 0.5133 0.2686 0.2686

H2O 0.0099 0.1117 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3197 1.0000 0.0749 0.3197 0.3195

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0002 0.0002 0.0002

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0058 0.0057 0.0059

N2 0.7732 0.7576 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0055 0.0055 0.0055

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0016 0.0016 0.0016

O2 0.2074 0.1122 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

S O2 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 (kgmol/hr) 26,013 1,915 94 18,716 5,251 0 4,787 0 21,972 27,856 0 70 27,786 27,786

V-L Flowrate (kg/hr) 750,670 52,828 3,016 525,175 168,981 0 86,233 0 442,098 547,834 0 1,370 546,465 546,465

Solids Flowrate (kg/hr) 0 0 0 0 0 209,915 0 23,031 0 0 0 0 0 0

Temperature (°C) 15 17 32 93 32 15 142 1,316 677 206 288 266 212 212

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 5.48 5.41

Enthalpy (kJ/kg)A 30.23 35.15 26.67 92.50 26.67 --- 537.77 --- 1,424.65 1,067.55 2,918.18 621.54 1,049.09 1,048.99

Density (kg/m3) 1.2 1.4 11.0 24.4 11.0 --- 872.0 --- 14.0 27.2 25.6 23.6 27.4 27.0

V-L Molecular Weight 28.857 27.583 32.181 28.060 32.181 --- 18.015 --- 20.121 19.667 18.015 19.667 19.667 19.667

V-L Flowrate (lbmol/hr) 57,350 4,222 207 41,262 11,576 0 10,553 0 48,440 61,411 0 154 61,257 61,257

V-L Flowrate (lb/hr) 1,654,945 116,465 6,650 1,157,812 372,540 0 190,111 0 974,659 1,207,768 0 3,020 1,204,748 1,204,748

Solids Flowrate (lb/hr) 0 0 0 0 0 462,783 0 50,775 0 0 0 0 0 0

Temperature (°F) 59 63 90 199 90 59 287 2,400 1,250 403 550 510 413 413

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0 795.0 785.0

Enthalpy (Btu/lb)A 13.0 15.1 11.5 39.8 11.5 --- 231.2 --- 612.5 459.0 1,254.6 267.2 451.0 451.0

Density (lb/ft3) 0.076 0.089 0.687 1.521 0.687 --- 54.440 --- 0.871 1.699 1.597 1.471 1.710 1.688

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

306

Exhibit 4-69 Case 2 D3A Stream Table, 25% CO2 Removal with Two WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27

V-L Mole Fraction

A r 0.0068 0.0100 0.0101 0.0118 0.0118 0.0006 0.0037 0.0000 0.0228 0.0092 0.0091 0.0091 0.0000

CH4 0.0009 0.0013 0.0013 0.0015 0.0015 0.0002 0.0009 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.2814 0.4138 0.4101 0.4806 0.4806 0.0254 0.1672 0.0000 0.0031 0.0000 0.0000 0.0000 0.0000

CO2 0.1096 0.1611 0.1618 0.0254 0.0254 0.9652 0.0000 0.0000 0.2378 0.0003 0.0597 0.0597 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 0.0000 0.0000

H2 0.2692 0.3959 0.3979 0.4699 0.4699 0.0085 0.1033 0.0000 0.6144 0.0000 0.0000 0.0000 0.0000

H2O 0.3189 0.0012 0.0012 0.0001 0.0001 0.0000 0.0310 0.0000 0.0013 0.0099 0.0633 0.0633 1.0000

HCl 0.0002 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 0.0059 0.0086 0.0085 0.0000 0.0000 0.0001 0.6924 0.0000 0.0039 0.0000 0.0000 0.0000 0.0000

N2 0.0055 0.0081 0.0091 0.0108 0.0108 0.0001 0.0016 0.0000 0.1166 0.7732 0.7567 0.7567 0.0000

NH3 0.0016 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 0.2074 0.1112 0.1112 0.0000

S O2 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 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 27,856 18,942 19,115 16,083 16,083 2,782 235 0 172 110,253 137,409 137,409 35,011

V-L Flowrate (kg/hr) 547,834 387,186 389,967 262,538 262,538 120,297 6,868 0 2,781 3,181,557 3,969,271 3,969,271 630,726

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,253 0 0 0 0 0

Temperature (°C) 206 35 35 35 197 64 48 182 38 15 582 132 554

Pressure (MPa, abs) 5.38 5.14 5.1 4.999 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512

Enthalpy (kJ/kg)A 1,037.76 40.00 40.1 54.667 355.129 -108.419 100.144 --- 59.854 30.227 733.224 235.966 3,483.940

Density (kg/m3) 27.2 41.3 40.9 31.5 13.1 482.9 1.8 5,270.3 34.5 1.2 0.4 0.9 35.5

V-L Molecular Weight 19.667 20.440 20 16.324 16.324 43.239 29.253 --- 16.127 28.857 28.887 28.887 18.015

V-L Flowrate (lbmol/hr) 61,411 41,760 42,141 35,457 35,457 6,134 518 0 380 243,066 302,935 302,935 77,185

V-L Flowrate (lb/hr) 1,207,768 853,600 859,731 578,797 578,797 265,209 15,141 0 6,131 7,014,133 8,750,744 8,750,744 1,390,513

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 11,581 0 0 0 0 0

Temperature (°F) 403 95 95 95 387 146 119 360 100 59 1,079 270 1,029

Pressure (psia) 780.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 446.2 17.2 17.3 23.5 152.7 -46.6 43.1 --- 25.7 13.0 315.2 101.4 1,497.8

Density (lb/ft3) 1.699 2.575 3 1.964 0.817 30.148 0.112 329.017 2.152 0.076 0.027 0.056 2.218

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

307

Exhibit 4-70 Case 2 D3B Stream Table, 45% CO2 Capture with Two WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

A r 0.0092 0.0147 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0057 0.0068 0.0068

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0008 0.0009 0.0009

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2821 0.0000 0.0082 0.2821 0.2821

CO2 0.0003 0.0047 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.0000 0.3199 0.1088 0.1090

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 0.0001 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2687 0.0000 0.4539 0.2687 0.2687

H2O 0.0099 0.1176 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3195 1.0000 0.2004 0.3195 0.3194

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 0.0002 0.0002

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0049 0.0057 0.0059

N2 0.7732 0.7452 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0046 0.0055 0.0055

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 0.0016 0.0016

O2 0.2074 0.1178 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

S O2 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 (kgmol/hr) 26,413 1,847 96 19,102 5,331 0 4,860 0 22,307 28,275 1,660 10,312 19,623 19,623

V-L Flowrate (kg/hr) 762,207 50,886 3,081 535,999 171,560 0 87,549 0 448,843 556,088 29,897 200,060 385,925 385,925

Solids Flowrate (kg/hr) 0 0 0 0 0 213,118 0 23,383 0 0 0 0 0 0

Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 246 212 212

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 5.48 5.41

Enthalpy (kJ/kg)A 30.23 35.26 26.67 92.50 26.67 --- 537.77 --- 1,424.65 1,067.17 2,918.18 878.31 1,048.73 1,048.62

Density (kg/m3) 1.2 1.4 11.0 24.4 11.0 --- 872.0 --- 14.0 27.2 25.6 24.5 27.4 27.0

V-L Molecular Weight 28.857 27.557 32.181 28.060 32.181 --- 18.015 --- 20.121 19.667 18.015 19.401 19.667 19.667

V-L Flowrate (lbmol/hr) 58,231 4,071 211 42,113 11,753 0 10,714 0 49,179 62,335 3,659 22,733 43,261 43,261

V-L Flowrate (lb/hr) 1,680,379 112,185 6,793 1,181,676 378,224 0 193,012 0 989,530 1,225,965 65,912 441,057 850,820 850,820

Solids Flowrate (lb/hr) 0 0 0 0 0 469,844 0 51,550 0 0 0 0 0 0

Temperature (°F) 59 64 90 199 90 59 287 2,400 1,250 403 550 474 413 413

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0 795.0 785.0

Enthalpy (Btu/lb)A 13.0 15.2 11.5 39.8 11.5 --- 231.2 --- 612.5 458.8 1,254.6 377.6 450.9 450.8

Density (lb/ft3) 0.076 0.090 0.687 1.521 0.687 --- 54.440 --- 0.871 1.699 1.597 1.529 1.710 1.688

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

308

Exhibit 4-70 Case 2 D3B Stream Table, 45% CO2 Capture with Two WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27

V-L Mole Fraction

A r 0.0064 0.0089 0.0090 0.0117 0.0117 0.0003 0.0037 0.0000 0.0254 0.0092 0.0091 0.0091 0.0000

CH4 0.0008 0.0012 0.0012 0.0015 0.0015 0.0001 0.0009 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.1877 0.2605 0.2586 0.3364 0.3364 0.0101 0.1196 0.0000 0.0022 0.0000 0.0000 0.0000 0.0000

CO2 0.1817 0.2520 0.2516 0.0330 0.0330 0.9831 0.0000 0.0000 0.1897 0.0003 0.0445 0.0445 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.3325 0.4613 0.4627 0.6066 0.6066 0.0062 0.1363 0.0000 0.6477 0.0000 0.0000 0.0000 0.0000

H2O 0.2784 0.0012 0.0012 0.0001 0.0001 0.0000 0.0356 0.0000 0.0013 0.0099 0.0807 0.0807 1.0000

HCl 0.0002 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 0.0056 0.0076 0.0076 0.0000 0.0000 0.0000 0.7022 0.0000 0.0039 0.0000 0.0000 0.0000 0.0000

N2 0.0052 0.0072 0.0081 0.0107 0.0107 0.0001 0.0016 0.0000 0.1298 0.7732 0.7559 0.7559 0.0000

NH3 0.0015 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 0.2074 0.1098 0.1098 0.0000

S O2 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 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 29,934 21,574 21,731 16,471 16,471 5,008 235 0 157 110,253 138,060 138,060 34,991

V-L Flowrate (kg/hr) 585,985 435,306 437,592 212,348 212,348 218,254 6,686 0 2,286 3,181,557 3,929,905 3,929,905 630,373

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,332 0 0 0 0 0

Temperature (°C) 218 35 35 35 197 55 48 182 38 15 576 132 548

Pressure (MPa, abs) 5.38 5.14 5.1 4.999 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512

Enthalpy (kJ/kg)A 980.84 39.13 39.3 72.894 451.811 -145.133 110.524 --- 69.469 30.227 761.977 266.773 3,469.035

Density (kg/m3) 26.2 41.0 40.7 24.7 10.3 587.7 1.7 5,270.3 30.8 1.2 0.4 0.9 35.9

V-L Molecular Weight 19.576 20.177 20 12.892 12.892 43.582 28.415 --- 14.524 28.857 28.465 28.465 18.015

V-L Flowrate (lbmol/hr) 65,994 47,562 47,909 36,313 36,313 11,041 519 0 347 243,066 304,370 304,370 77,142

V-L Flowrate (lb/hr) 1,291,877 959,686 964,724 468,146 468,146 481,167 14,739 0 5,039 7,014,133 8,663,957 8,663,957 1,389,734

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 11,754 0 0 0 0 0

Temperature (°F) 425 95 95 95 387 130 119 360 100 59 1,069 270 1,019

Pressure (psia) 780.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 421.7 16.8 16.9 31.3 194.2 -62.4 47.5 --- 29.9 13.0 327.6 114.7 1,491.4

Density (lb/ft3) 1.637 2.562 3 1.545 0.645 36.688 0.109 329.014 1.925 0.076 0.026 0.055 2.239

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

309

Exhibit 4-71 Case 2 D3C Stream Table, 60% CO2 Capture with Two WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

A r 0.0092 0.0145 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0057 0.0068 0.0068

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0008 0.0009 0.0009

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2820 0.0000 0.0082 0.2820 0.2820

CO2 0.0003 0.0046 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.0000 0.3201 0.1088 0.1089

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 0.0001 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2686 0.0000 0.4542 0.2686 0.2686

H2O 0.0099 0.1159 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3199 1.0000 0.2000 0.3199 0.3197

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 0.0002 0.0002

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0049 0.0057 0.0059

N2 0.7732 0.7489 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0046 0.0055 0.0055

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 0.0016 0.0016

O2 0.2074 0.1162 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

S O2 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 (kgmol/hr) 26,755 1,898 98 19,321 5,399 0 4,922 0 22,593 28,651 3,003 18,760 12,893 12,893

V-L Flowrate (kg/hr) 772,061 52,330 3,140 542,142 173,759 0 88,671 0 454,598 563,459 54,092 363,995 253,557 253,557

Solids Flowrate (kg/hr) 0 0 0 0 0 215,850 0 23,682 0 0 0 0 0 0

Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 245 212 212

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 5.48 5.41

Enthalpy (kJ/kg)A 30.23 35.23 26.67 92.50 26.67 --- 537.77 --- 1,424.65 1,068.03 2,918.18 877.14 1,049.56 1,049.45

Density (kg/m3) 1.2 1.4 11.0 24.4 11.0 --- 872.0 --- 14.0 27.2 25.6 24.5 27.4 27.0

V-L Molecular Weight 28.857 27.565 32.181 28.060 32.181 --- 18.015 --- 20.121 19.667 18.015 19.402 19.667 19.667

V-L Flowrate (lbmol/hr) 58,984 4,185 215 42,596 11,904 0 10,851 0 49,809 63,164 6,620 41,360 28,424 28,424

V-L Flowrate (lb/hr) 1,702,103 115,369 6,922 1,195,219 383,073 0 195,486 0 1,002,216 1,242,215 119,253 802,471 558,997 558,997

Solids Flowrate (lb/hr) 0 0 0 0 0 475,867 0 52,211 0 0 0 0 0 0

Temperature (°F) 59 64 90 199 90 59 287 2,400 1,250 403 550 474 413 413

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0 795.0 785.0

Enthalpy (Btu/lb)A 13.0 15.1 11.5 39.8 11.5 --- 231.2 --- 612.5 459.2 1,254.6 377.1 451.2 451.2

Density (lb/ft3) 0.076 0.090 0.687 1.521 0.687 --- 54.440 --- 0.871 1.699 1.597 1.529 1.710 1.688

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

310

Exhibit 4-71 Case 2 D3C Stream Table, 60% CO2 Capture with Two WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27

V-L Mole Fraction

A r 0.0061 0.0082 0.0083 0.0116 0.0116 0.0002 0.0037 0.0000 0.0279 0.0092 0.0091 0.0091 0.0000

CH4 0.0008 0.0011 0.0011 0.0015 0.0015 0.0001 0.0009 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.1197 0.1595 0.1585 0.2214 0.2214 0.0050 0.0804 0.0000 0.0015 0.0000 0.0000 0.0000 0.0000

CO2 0.2341 0.3119 0.3109 0.0436 0.0436 0.9890 0.0000 0.0000 0.1431 0.0003 0.0327 0.0327 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0003 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.3786 0.5044 0.5055 0.7114 0.7114 0.0055 0.1634 0.0000 0.6794 0.0000 0.0000 0.0000 0.0000

H2O 0.2488 0.0012 0.0012 0.0001 0.0001 0.0000 0.0394 0.0000 0.0013 0.0099 0.0949 0.0949 1.0000

HCl 0.0002 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 0.0053 0.0070 0.0070 0.0000 0.0000 0.0000 0.7102 0.0000 0.0043 0.0000 0.0000 0.0000 0.0000

N2 0.0050 0.0067 0.0075 0.0106 0.0106 0.0000 0.0016 0.0000 0.1426 0.7732 0.7547 0.7547 0.0000

NH3 0.0014 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 0.2074 0.1086 0.1086 0.0000

S O2 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 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 31,653 23,756 23,901 16,877 16,877 6,770 236 0 145 110,253 138,580 138,580 34,720

V-L Flowrate (kg/hr) 617,551 475,219 477,104 174,441 174,441 295,786 6,538 0 1,884 3,181,557 3,898,141 3,898,141 625,490

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,399 0 0 0 0 0

Temperature (°C) 227 35 35 35 197 53 48 182 38 15 572 132 544

Pressure (MPa, abs) 5.38 5.14 5.1 4.999 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512

Enthalpy (kJ/kg)A 938.62 38.42 38.6 93.689 566.535 -154.509 119.522 --- 80.508 30.227 786.493 292.348 3,457.373

Density (kg/m3) 25.6 40.9 40.6 19.8 8.3 616.8 1.7 5,270.3 27.4 1.2 0.4 0.9 36.1

V-L Molecular Weight 19.510 20.004 20 10.336 10.336 43.693 27.725 --- 12.984 28.857 28.129 28.129 18.015

V-L Flowrate (lbmol/hr) 69,783 52,373 52,693 37,207 37,207 14,924 520 0 320 243,066 305,516 305,516 76,544

V-L Flowrate (lb/hr) 1,361,467 1,047,679 1,051,833 384,577 384,577 652,097 14,414 0 4,154 7,014,133 8,593,931 8,593,931 1,378,969

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 11,902 0 0 0 0 0

Temperature (°F) 441 95 95 95 387 127 119 360 100 59 1,061 270 1,011

Pressure (psia) 780.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 403.5 16.5 16.6 40.3 243.6 -66.4 51.4 --- 34.6 13.0 338.1 125.7 1,486.4

Density (lb/ft3) 1.596 2.554 3 1.236 0.517 38.506 0.106 329.011 1.711 0.076 0.026 0.055 2.256

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

311

Exhibit 4-72 Case 2 D3D Stream Table, 75% CO2 Capture with Two WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

A r 0.0092 0.0147 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0057 0.0068 0.0068

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0008 0.0009 0.0009

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2818 0.0000 0.0082 0.2818 0.2818

CO2 0.0003 0.0047 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1087 0.0000 0.3200 0.1087 0.1089

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 0.0001 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2684 0.0000 0.4540 0.2684 0.2684

H2O 0.0099 0.1173 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3201 1.0000 0.2004 0.3201 0.3200

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 0.0002 0.0002

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0049 0.0057 0.0059

N2 0.7732 0.7458 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0046 0.0055 0.0055

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 0.0016 0.0016

O2 0.2074 0.1175 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

S O2 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 (kgmol/hr) 27,079 1,898 97 19,579 5,467 0 4,983 0 22,874 29,018 4,371 27,295 6,094 6,094

V-L Flowrate (kg/hr) 781,417 52,303 3,125 549,373 175,918 0 89,773 0 460,245 570,666 78,736 529,562 119,840 119,840

Solids Flowrate (kg/hr) 0 0 0 0 0 218,531 0 23,977 0 0 0 0 0 0

Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 246 212 212

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 5.48 5.41

Enthalpy (kJ/kg)A 30.23 35.26 26.67 92.50 26.67 --- 537.77 --- 1,424.65 1,068.75 2,918.18 878.16 1,050.26 1,050.15

Density (kg/m3) 1.2 1.4 11.0 24.4 11.0 --- 872.0 --- 14.0 27.2 25.6 24.5 27.4 27.0

V-L Molecular Weight 28.857 27.559 32.181 28.060 32.181 --- 18.015 --- 20.121 19.666 18.015 19.402 19.666 19.666

V-L Flowrate (lbmol/hr) 59,699 4,184 214 43,164 12,052 0 10,986 0 50,428 63,974 9,635 60,175 13,434 13,434

V-L Flowrate (lb/hr) 1,722,729 115,309 6,889 1,211,160 387,832 0 197,915 0 1,014,666 1,258,103 173,583 1,167,485 264,202 264,202

Solids Flowrate (lb/hr) 0 0 0 0 0 481,779 0 52,859 0 0 0 0 0 0

Temperature (°F) 59 64 90 199 90 59 287 2,400 1,250 403 550 474 413 413

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0 795.0 785.0

Enthalpy (Btu/lb)A 13.0 15.2 11.5 39.8 11.5 --- 231.2 --- 612.5 459.5 1,254.6 377.5 451.5 451.5

Density (lb/ft3) 0.076 0.090 0.687 1.521 0.687 --- 54.440 --- 0.871 1.699 1.597 1.529 1.710 1.688

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

312

Exhibit 4-72 Case 2 D3D Stream Table, 75% CO2 Capture with Two WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27

V-L Mole Fraction

A r 0.0059 0.0076 0.0077 0.0115 0.0115 0.0002 0.0034 0.0000 0.0251 0.0092 0.0091 0.0091 0.0000

CH4 0.0008 0.0010 0.0010 0.0015 0.0015 0.0001 0.0008 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0581 0.0748 0.0744 0.1109 0.1109 0.0020 0.0374 0.0000 0.0022 0.0000 0.0000 0.0000 0.0000

CO2 0.2814 0.3621 0.3612 0.0525 0.0525 0.9925 0.0915 0.0000 0.2188 0.0003 0.0207 0.0207 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.4201 0.5405 0.5410 0.8132 0.8132 0.0051 0.1732 0.0000 0.6180 0.0000 0.0000 0.0000 0.0000

H2O 0.2222 0.0012 0.0012 0.0001 0.0001 0.0000 0.0393 0.0000 0.0013 0.0099 0.1091 0.1091 1.0000

HCl 0.0002 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 0.0051 0.0065 0.0065 0.0000 0.0000 0.0000 0.6525 0.0000 0.0043 0.0000 0.0000 0.0000 0.0000

N2 0.0048 0.0062 0.0069 0.0104 0.0104 0.0000 0.0015 0.0000 0.1302 0.7732 0.7536 0.7536 0.0000

NH3 0.0014 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 0.2074 0.1074 0.1074 0.0000

S O2 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 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 33,389 25,949 26,110 17,262 17,262 8,567 260 0 161 110,253 139,118 139,118 34,438

V-L Flowrate (kg/hr) 649,402 515,316 517,847 135,159 135,159 374,880 7,436 0 2,531 3,181,557 3,866,090 3,866,090 620,418

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,464 0 0 0 0 0

Temperature (°C) 235 35 35 35 198 52 48 182 38 15 567 132 539

Pressure (MPa, abs) 5.38 5.14 5.1 4.999 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512

Enthalpy (kJ/kg)A 900.98 37.72 37.8 126.739 751.045 -159.378 116.518 --- 62.078 30.227 811.540 318.762 3,445.343

Density (kg/m3) 25.0 40.8 40.5 15.0 6.3 632.3 1.8 5,270.9 33.6 1.2 0.4 0.9 36.4

V-L Molecular Weight 19.450 19.859 20 7.830 7.830 43.760 28.585 --- 15.759 28.857 27.790 27.790 18.015

V-L Flowrate (lbmol/hr) 73,609 57,208 57,562 38,056 38,056 18,886 573 0 354 243,066 306,702 306,702 75,924

V-L Flowrate (lb/hr) 1,431,687 1,136,078 1,141,658 297,976 297,976 826,469 16,393 0 5,580 7,014,133 8,523,270 8,523,270 1,367,787

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 12,047 0 0 0 0 0

Temperature (°F) 455 95 95 95 388 125 119 360 100 59 1,052 270 1,002

Pressure (psia) 780.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 387.3 16.2 16.3 54.5 322.9 -68.5 50.1 --- 26.7 13.0 348.9 137.0 1,481.2

Density (lb/ft3) 1.561 2.548 3 0.935 0.391 39.476 0.110 329.053 2.098 0.076 0.026 0.054 2.274

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

313

Exhibit 4-73 Case 2 D3E Stream Table, 85% CO2 Capture with Two WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

A r 0.0092 0.0147 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0057 0.0068 0.0068

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0008 0.0009 0.0009

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2821 0.0000 0.0082 0.2821 0.2821

CO2 0.0003 0.0047 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.0000 0.3202 0.1088 0.1090

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 0.0001 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2687 0.0000 0.4544 0.2687 0.2687

H2O 0.0099 0.1180 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3196 1.0000 0.1997 0.3196 0.3195

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 0.0002 0.0002

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0049 0.0057 0.0059

N2 0.7732 0.7444 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0046 0.0055 0.0055

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 0.0016 0.0016

O2 0.2074 0.1182 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

S O2 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 (kgmol/hr) 27,303 1,903 97 19,752 5,513 0 5,025 0 23,066 29,240 5,292 33,070 1,462 1,462

V-L Flowrate (kg/hr) 787,883 52,428 3,125 554,227 177,399 0 90,529 0 464,121 575,073 95,335 641,654 28,754 28,754

Solids Flowrate (kg/hr) 0 0 0 0 0 220,372 0 24,179 0 0 0 0 0 0

Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 246 212 212

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 5.48 5.41

Enthalpy (kJ/kg)A 30.23 35.27 26.67 92.50 26.67 --- 537.77 --- 1,424.65 1,067.37 2,918.18 876.50 1,048.92 1,048.81

Density (kg/m3) 1.2 1.4 11.0 24.4 11.0 --- 872.0 --- 14.0 27.2 25.6 24.5 27.4 27.0

V-L Molecular Weight 28.857 27.556 32.181 28.060 32.181 --- 18.015 --- 20.121 19.667 18.015 19.403 19.667 19.667

V-L Flowrate (lbmol/hr) 60,193 4,195 214 43,545 12,153 0 11,079 0 50,853 64,464 11,667 72,907 3,223 3,223

V-L Flowrate (lb/hr) 1,736,984 115,584 6,889 1,221,862 391,098 0 199,581 0 1,023,211 1,267,818 210,177 1,414,604 63,391 63,391

Solids Flowrate (lb/hr) 0 0 0 0 0 485,836 0 53,304 0 0 0 0 0 0

Temperature (°F) 59 64 90 199 90 59 287 2,400 1,250 403 550 474 413 413

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0 795.0 785.0

Enthalpy (Btu/lb)A 13.0 15.2 11.5 39.8 11.5 --- 231.2 --- 612.5 458.9 1,254.6 376.8 451.0 450.9

Density (lb/ft3) 0.076 0.090 0.687 1.521 0.687 --- 54.440 --- 0.871 1.699 1.597 1.529 1.710 1.688

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

314

 Case 2 D3E Stream Table, 85% CO2 Capture with Two WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27

V-L Mole Fraction

A r 0.0057 0.0072 0.0073 0.0114 0.0114 0.0002 0.0033 0.0000 0.0236 0.0092 0.0091 0.0091 0.0000

CH4 0.0008 0.0010 0.0009 0.0015 0.0015 0.0001 0.0008 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0198 0.0249 0.0248 0.0385 0.0385 0.0006 0.0124 0.0000 0.0026 0.0000 0.0000 0.0000 0.0000

CO2 0.3113 0.3917 0.3909 0.0584 0.0584 0.9942 0.1451 0.0000 0.2643 0.0003 0.0126 0.0126 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.4465 0.5618 0.5619 0.8798 0.8798 0.0049 0.1787 0.0000 0.5803 0.0000 0.0000 0.0000 0.0000

H2O 0.2048 0.0012 0.0012 0.0001 0.0001 0.0000 0.0392 0.0000 0.0014 0.0099 0.1188 0.1188 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

H2S 0.0050 0.0062 0.0062 0.0000 0.0000 0.0000 0.6187 0.0000 0.0046 0.0000 0.0000 0.0000 0.0000

N2 0.0047 0.0059 0.0066 0.0104 0.0104 0.0000 0.0014 0.0000 0.1233 0.7732 0.7529 0.7529 0.0000

NH3 0.0013 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 0.2074 0.1066 0.1066 0.0000

S O2 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 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 34,532 27,442 27,613 17,527 17,527 9,788 277 0 171 110,253 139,484 139,484 34,252

V-L Flowrate (kg/hr) 670,407 542,625 545,608 108,540 108,540 428,616 8,057 0 2,982 3,181,557 3,844,326 3,844,326 617,053

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,509 0 0 0 0 0

Temperature (°C) 240 35 35 35 198 51 48 182 38 15 564 132 536

Pressure (MPa, abs) 5.38 5.14 5.1 4.999 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512

Enthalpy (kJ/kg)A 875.18 37.27 37.4 162.361 952.098 -161.516 114.764 --- 53.244 30.227 828.855 336.978 3,437.205

Density (kg/m3) 24.7 40.8 40.5 11.8 5.0 639.2 1.8 5,271.4 37.5 1.2 0.4 0.9 36.6

V-L Molecular Weight 19.414 19.773 20 6.193 6.193 43.791 29.095 --- 17.451 28.857 27.561 27.561 18.015

V-L Flowrate (lbmol/hr) 76,130 60,500 60,877 38,640 38,640 21,578 610 0 377 243,066 307,509 307,509 75,512

V-L Flowrate (lb/hr) 1,477,995 1,196,284 1,202,859 239,291 239,291 944,936 17,762 0 6,575 7,014,133 8,475,287 8,475,287 1,360,368

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 12,146 0 0 0 0 0

Temperature (°F) 463 95 95 95 388 124 119 360 100 59 1,047 270 997

Pressure (psia) 780.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 376.3 16.0 16.1 69.8 409.3 -69.4 49.3 --- 22.9 13.0 356.3 144.9 1,477.7

Density (lb/ft3) 1.540 2.545 3 0.739 0.310 39.907 0.112 329.081 2.342 0.076 0.026 0.054 2.287

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

315

Exhibit 4-74 Case 2 D3 Performance Modeling Results 

POWER SUMMARY (Gross Power at 

Generator Terminals, kWe)

D3A 

(25%)

D3B 

(45%)

D3C 

(60%)

D3D 

(75%)

D3E 

(85%)

Gas Turbine Power 464,000 464,000 464,000 464,000 464,000

Sweet Gas Expander Power 5,800 5,900 6,100 6,200 6,300

Steam Turbine Power 280,600 276,300 274,100 271,400 269,500

Total 750,400 746,200 744,200 741,600 739,800

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 457 460 463 466 468

Coal Milling 2,159 2,192 2,220 2,247 2,266

Sour Water Recycle Slurry Pump 181 183 185 187 188

Slag Handling 1,106 1,122 1,137 1,151 1,161

Air Separation Unit Auxiliaries 1,000 1,000 1,000 1,000 1,000

Air Separation Unit Main Air 

Compressor 64,015 64,998 65,839 66,636 67,188

Oxygen Compressor 10,165 10,320 10,398 10,528 10,616

Nitrogen Compressors 31,421 32,122 33,120 34,181 34,905

CO2 Compressor 8,492 15,038 20,275 25,616 29,261

Boiler Feedwater Pumps 3,968 4,009 4,053 4,096 4,125

Condensate Pump 249 259 264 269 273

Quench Water Pump 513 519 524 529 533

Circulating Water Pump 4,165 4,320 4,428 4,536 4,606

Ground Water Pumps 425 456 480 504 520

Cooling Tower Fans 2,153 2,233 2,290 2,344 2,381

Scrubber Pumps 212 216 218 220 223

Acid Gas Removal 4,858 8,907 12,112 15,425 17,676

Gas Turbine Auxiliaries 1,000 1,000 1,000 1,000 1,000

Steam Turbine Auxiliaries 100 100 100 100 100

Claus Plant/TGTU Auxiliaries 250 250 250 250 250

Claus Plant TG Recycle Compressor 828 758 701 772 819

Miscellaneous Balance of Plant 13,000 3,000 3,000 3,000 3,000

Transformer Losses 2,665 2,691 2,717 2,741 2,757

TOTAL AUXILIARIES, kWe 143,382 156,153 166,774 177,798 185,316

NET POWER, kWe 607,018 590,047 577,426 563,802 554,484

Net Plant Efficiency, % (HHV) 38.4% 36.7% 35.5% 34.2% 33.4%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,384 (8,894) 9,801 (9,289) 10,143 (9,614) 10,518 (9,969) 10,784 (10,222)

Condenser Duty, GJ/hr (106Btu/hr) 1,625 (1,540) 1,614 (1,530) 1,593 (1,510) 1,572 (1,490) 1,551 (1,470)

CONSUMABLES

As-Received Coal Feed, kg/hr 

(lb/hr)

209,915

(462,783)

213,118

(469,844)

215,850

(475,867)

218,531

(481,779)

220,372

(485,836)

Thermal Input, kWth 

2

1,582,239 1,606,380 1,626,975 1,647,185 1,661,057

Raw Water Withdrawal, m3/min (gpm) 17.8 (4,695) 19.1 (5,040) 20.1 (5,307) 21.1 (5,569) 21.8 (5,748)

Raw Water Consumption, m3/min (gpm) 14.1 (3,725) 15.3 (4,034) 16.2 (4,276) 17.1 (4,514) 17.7 (4,677)

Notes: 1. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

2. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 
Carbon Dioxide Capture Sensitivity Analysis

316

4.3.3.1 Environmental Performance for Case 2 D3

The environmental targets for emissions of Hg, NOx, SO2, and particulate matter were presented 

in Section 2.4. A summary of the plant air emissions for Case 2 D3A, D3B, D3C, D3D, and 

D3E is presented in Exhibit 4-75.

For Case 2 D3, SO2 emissions are controlled by sulfur capture across the two-stage SelexolTM 

unit. The clean syngas exiting the AGR unit has a sulfur concentration of about 10 ppmv, 

resulting in a concentration in the flue gas of less than 2 ppmv. The H2S-rich regeneration gas 

produced in Case 2 D3 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 SelexolTM 

unit, 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 incinerated in the Claus plant burner. This also assists in lowering 

NOx levels. 

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.

Ninety-five percent of the mercury is captured from the syngas by an activated carbon bed. 

For Case 2 D3, varying levels of the CO2 [25 percent (D3A), 45 percent (D3B), 60 percent

(D3C), 75 percent (D3D), and 85 percent (D3E)] in the syngas are captured in the two-stage 

SelexolTM unit and compressed for sequestration. The carbon balance for Case 2 D3 is shown in 

Exhibit 4-76. The carbon input to the plant consists of carbon in the air and 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, as dissolved CO2 in the wastewater blowdown 

stream, and as CO2 in the stack gas, ASU vent gas, and the captured CO2 product. Carbon in the 

wastewater blowdown stream is calculated by difference to close the material balance. The 

carbon capture efficiency is defined as the pounds of carbon in the CO2 product stream relative 

to the amount of carbon in the coal, less carbon contained in the slag, represented by the 

following fraction:

(Carbon in CO2 Product)/[(Carbon in the Coal)-(Carbon in Slag)] or

72,992/(295,000-5,900)*100=25.2% (D3A)

131,728/(299,501-5,990)*100=44.9% (D3B)

178,210/(303,340-6,067)*100=59.9% (D3C)

225,630/(307,108-6,142)*100=75.0% (D3D)

257,847/(309,695-6,194)*100=85.0% (D3E)

Exhibit 4-77 shows the sulfur balance for Case 2 D3. Sulfur input comes solely from the sulfur 

in the coal. Sulfur output includes the pounds of sulfur recovered in the Claus plant, dissolved 

SO2 in the wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is 

considered to be negligible, and the sulfur content of the blowdown stream is calculated by 
Carbon Dioxide Capture Sensitivity Analysis

317

difference to close the material balance. The total sulfur capture is represented by the following 

fraction:

(Sulfur byproduct/Sulfur in the coal) or

(11,581/11,599)*100 = 99.8% (D3A)

(11,754/11,776)*100 = 99.8% (D3B)

(11,902/11,927)*100 = 99.8% (D3C)

(12,047/12,075)*100 = 99.8% (D3D)

(12,146/12,177)*100 = 99.8% (D3E) 

The overall water balances for Case 2 D3A, D3B, D3C, D3D, and D3E are shown in 

Exhibit 4-78, Exhibit 4-79, Exhibit 4-80, Exhibit 4-81, and Exhibit 4-82, respectively. Raw 

water is obtained from groundwater (50 percent) and from municipal sources (50 percent). 

Water demand represents the total amount of water required for a particular process. Some water 

is recovered within the process and that water is reused as internal recycle. Raw water 

withdrawal is the difference between water demand and internal recycle. Process water 

discharged from the power plant is also accounted for in this study. Raw water consumption 

represents raw water withdrawal less process water discharge.

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 4-83 through 

Exhibit 4-97.

Gasifier and ASU

Syngas Cleanup

Power Block

An overall plant energy balance for Case D3A, D3B, D3C, D3D, and D3E is provided in tabular 

form in Exhibit 4-98, Exhibit 4-99, Exhibit 4-100, Exhibit 4-101, and Exhibit 4-102, 

respectively. The power out is the combined combustion turbine, steam turbine and expander 

power after generator losses. In addition, energy balance Sankey diagrams are provided for 

D3A, D3B, D3C, D3D, and D3E in Exhibit 4-103, Exhibit 4-104, Exhibit 4-105, Exhibit 4-106, 

and Exhibit 4-107, respectively.
Carbon Dioxide Capture Sensitivity Analysis

318

Exhibit 4-75 Case 2 D3 Estimated Air Emission Rates

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

85% capacity factor

kg/MWh

(lb/MWh)

D3A D3B D3C D3A D3B D3C D3A D3B D3C

SO2 0.001 (0.002) 0.001 (0.002) 0.001 (0.002) 37 (40) 37 (41) 38 (42) 0.007 (0.020) 0.007 (0.020) 0.007 (0.020)

NOX 0.024 (0.055) 0.023 (0.053) 0.022 (0.052) 947 (1,044) 927 (1,022) 910 (1,003) 0.180 (0.397) 0.177 (0.391) 0.174 (0.385)

PM 0.003 (0.0071) 0.003 (0.0071) 0.003 (0.0071) 122 (134) 124 (136) 125 (138) 0.023 (0.051) 0.024 (0.052) 0.024 (0.053)

Hg 0.246x10-6

(0.571x10-6)

0.246x10-6

(0.571x10-6)

0.246x10-6

(0.571x10-6)

0.010 (0.011) 0.010 (0.011) 0.010 (0.011) 1.87x10-6

(4.11x10-6)

1.90x10-6

(4.20x10-6)

1.93x10-6

(4.26x10-6)

CO2 63.3 (147.3) 46.8 (108.8) 34.1 (79.2) 2,528,207

(2,786,871)

1,895,466

(2,089,393)

1,397,892 

(1,540,913)

481 (1,060) 362 (799) 268 (591)

CO2 net 594 (1,310) 458 (1,011) 345 (762)

Exhibit 4-75 Case 2 D3 Estimated Air Emission Rates (continued)

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

85% capacity factor

kg/MWh

(lb/MWh)

D3D D3E D3D D3E D3D D3E

SO2

0.001

(0.002)

0.001

(0.002)

38 (42) 39 (42) 0.007 (0.020) 0.007 (0.020)

NOX

0.021

(0.050)

0.021

(0.049)

893 (985) 882 (972) 0.172 (0.379) 0.170 (0.375)

PM 0.003

(0.0071)

0.003

(0.0071)

127 (140) 128 (141) 0.024 (0.054) 0.025 (0.054)

Hg 0.246x10-6

(0.571x10-6)

0.246x10-6

(0.571x10-6)

0.010 (0.011) 0.010 (0.011) 1.96x10-6

(4.33x10-6)

1.99x10-6

(4.38x10-6)

CO2 21.4 (49.7) 13.0 (30.1) 888,578

(979,489)

542,862

(598,402)

171 (377) 105 (231)

CO2 net 225 (496) 140 (308)
Carbon Dioxide Capture Sensitivity Analysis

319

Exhibit 4-76 Case 2 D3 Carbon Balance

Carbon In, kg/hr (lb/hr)

D3A D3B D3C D3D D3E

Coal 133,810

(295,000)

135,851

(299,501)

137,593

(303,340)

139,302

(307,108)

140,475

(309,695)

Air (CO2)

535 

(1,179)

536 

(1,182)

538 

(1,185) 539 (1,188) 540 (1,190)

Total 134,345

(296,179)

136,387

(300,683)

138,131

(304,525)

139,841

(308,296)

141,015

(310,885)

Carbon Out, kg/hr (lb/hr)

Slag 2,676

(5,900)

2,717

(5,990)

2,752 

(6,067)

2,786

(6,142)

2,810 

(6,194)

Stack Gas 98,457

(217,061)

73,816

(162,737)

54,439 

(120,017)

34,604

(76,290)

21,141

(46,608)

ASU Vent 102 (225) 104 (229) 105 (231) 106 (234) 107 (236)

CO2 Product 33,109

(72,992)

59,751

(131,728)

80,835

(178,210)

102,344

(225,630)

116,957

(257,847)

Convergence 

Tolerance 1 (1) -1 (-1) 0 (0) 1 (0) 0 (0)

Total 134,345 

(296,179)

136,387 

(300,683)

138,131 

(304,525)

139,841 

(308,296)

141,015 

(310,885)

Exhibit 4-77 Case 2 D3 Sulfur Balance

Sulfur In, kg/hr (lb/hr)

D3A D3B D3C D3D D3E

Coal 5,261

(11,599)

5,342

(11,776)

5,410

(11,927)

5,477

(12,075)

5,523

(12,177)

Total 5,261

(11,599)

5,342

(11,776)

5,410

(11,927)

5,477

(12,075)

5,523

(12,177)

Sulfur Out, kg/hr (lb/hr)

Elemental Sulfur 5,253

(11,581)

5,332

(11,754)

5,399

(11,902)

5,464

(12,047)

5,509

(12,146)

Stack Gas 3 (6) 3 (6) 3 (6) 3 (6) 3 (6)

CO2 Product 6 (12) 7 (16) 9 (19) 10 (22) 11 (25)

Convergence 

Tolerance -1 (0) 0 (0) -1 (0) 0 (0) 0 (0)

Total 5,261 

(11,599)

5,342

(11,776)

5,410

(11,927)

5,477

(12,075)

5,523

(12,177)
Carbon Dioxide Capture Sensitivity Analysis

320

Exhibit 4-78 Case 2 D3A (25%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Slag Handling 0.50 (132) 0.50 (132) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.7 (719) 0.87 (231) 1.8 (488) 0.0 (0) 1.8 (488)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7) -0.03 (-7)

Condenser Makeup 0.2 (55) 0.0 (0) 0.2 (55) 0.0 (0) 0.2 (55)

 Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

 Shift Steam 0.0 (0) 0.0 (0) 0.0 (0)

 CT Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

 BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 16.2 (4,282) 0.49 (129) 15.7 (4,152) 3.6 (963) 12.1 (3,190)

 BFW Blowdown 0.0 (0) 0.21 (55) -0.21 (-55)

 SWS Blowdown 0.0 (0) 0.28 (74) -0.28 (-74)

 SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

 Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 21.1 (5,568) 3.30 (872) 17.8 (4,695) 3.7 (970) 14.1 (3,725)

Total, gal/MWhnet 550 86 464 96 368
Carbon Dioxide Capture Sensitivity Analysis

321

Exhibit 4-79 Case 2 D3B (45%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Slag Handling 0.51 (134) 0.51 (134) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.8 (730) 0.72 (191) 2.0 (538) 0.0 (0) 2.0 (538)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7) -0.03 (-7)

Condenser Makeup 0.7 (187) 0.0 (0) 0.7 (187) 0.0 (0) 0.7 (187)

 Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

 Shift Steam 0.5 (132) 0.0 (0) 0.5 (132)

 CT Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

 BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 16.8 (4,441) 0.48 (127) 16.3 (4,314) 3.8 (999) 12.6 (3,316)

 BFW Blowdown 0.0 (0) 0.21 (55) -0.21 (-55)

 SWS Blowdown 0.0 (0) 0.27 (71) -0.27 (-71)

 SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

 Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 22.3 (5,878) 3.17 (838) 19.1 (5,040) 3.8 (1,006) 15.3 (4,034)

Total, gal/MWhnet 598 85 513 102 410
Carbon Dioxide Capture Sensitivity Analysis

322

Exhibit 4-80 Case 2 D3C (60%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Slag Handling 0.51 (136) 0.51 (136) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.8 (739) 0.60 (157) 2.2 (582) 0.0 (0) 2.2 (582)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7) -0.03 (-7)

Condenser Makeup 1.1 (294) 0.0 (0) 1.1 (294) 0.0 (0) 1.1 (294)

 Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

 Shift Steam 0.9 (239) 0.0 (0) 0.9 (239)

 CT Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

 BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 17.2 (4,555) 0.47 (124) 16.8 (4,431) 3.9 (1,024) 12.9 (3,407)

 BFW Blowdown 0.0 (0) 0.21 (55) -0.21 (-55)

 SWS Blowdown 0.0 (0) 0.26 (68) -0.26 (-68)

 SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

 Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 23.1 (6,115) 3.06 (808) 20.1 (5,307) 3.9 (1,031) 16.2 (4,276)

Total, gal/MWhnet 635 84 551 107 444
Carbon Dioxide Capture Sensitivity Analysis

323

Exhibit 4-81 Case 2 D3D (75%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Slag Handling 0.52 (137) 0.52 (137) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.8 (748) 0.47 (123) 2.4 (625) 0.0 (0) 2.4 (625)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.02 (7) -0.02 (-7)

Condenser Makeup 1.5 (402) 0.0 (0) 1.5 (402) 0.0 (0) 1.5 (402)

 Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

 Shift Steam 1.3 (347) 0.0 (0) 1.3 (347)

 CT Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

 BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 17.7 (4,663) 0.46 (121) 17.2 (4,542) 4.0 (1,049) 13.2 (3,494)

 BFW Blowdown 0.0 (0) 0.21 (55) -0.21 (-55)

 SWS Blowdown 0.0 (0) 0.25 (66) -0.25 (-66)

 SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

 Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 24.0 (6,347) 2.94 (777) 21.1 (5,569) 4.0 (1,055) 17.1 (4,514)

Total, gal/MWhnet 675 83 593 112 480
Carbon Dioxide Capture Sensitivity Analysis

324

Exhibit 4-82 Case 2 D3E (85%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Slag Handling 0.52 (138) 0.52 (138) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.9 (755) 0.38 (99) 2.5 (655) 0.0 (0) 2.5 (655)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.02 (6) -0.02 (-6)

Condenser Makeup 1.8 (475) 0.0 (0) 1.8 (475) 0.0 (0) 1.8 (475)

 Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

 Shift Steam 1.6 (420) 0.0 (0) 1.6 (420)

 CT Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

 BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 17.9 (4,736) 0.45 (119) 17.5 (4,618) 4.0 (1,065) 13.4 (3,553)

 BFW Blowdown 0.0 (0) 0.21 (55) -0.21 (-55)

 SWS Blowdown 0.0 (0) 0.24 (64) -0.24 (-64)

 SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

 Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 24.6 (6,504) 2.86 (756) 21.8 (5,748) 4.1 (1,072) 17.7 (4,677)

Total, gal/MWhnet 704 82 622 116 506
Carbon Dioxide Capture Sensitivity Analysis

325

Exhibit 4-83 Case 2 D3A (25%) Heat and Mass Balance, GEE Gasifier and ASU

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D3A HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D3A (25%) GEE GASIFIER ASU AND GASIFICATION DWG. NO. CCSA-HMB-CS-2-D3A-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 1 OF 3

Ambient Air Four Stage Air Compressor

Elevated Pressure ASU Four Stage N2 Compressor

Four Stage O2 Compressor

ASU Vent

Water

Steam

Gross Plant Power: 750 MWe Auxiliary Load: 143 MWe Net Plant Power: 607 MWe Net Plant Efficiency, HHV: 38.4% Net Plant Heat Rate: 8,894 BTU/KWe

N2 to GT Combustor 1,654,945 W 59.0 T 14.7 P 13.0 H

372,540 W 90.0 T 125.0 P 11.5 H

372,540 W 241.2 T 940.0 P 40.8 H

To Claus Plant 6,650 W 90.0 T 125.0 P 11.5 H

116,465 W 63.5 T 16.4 P 15.1 H

1,008,757 W 90.0 T 56.4 P 14.2 H

149,055 W 50.0 T 182.0 P 2.9 H 5

1

3

2

Slurry Mix Tank

Milled Coal

Slag

462,783 W 59.0 T 14.7 P

190,111 W 287.0 T 840.0 P 231.2 H

50,775 W 2,400.0 T 815.0 P

1,157,812 W 385.0 T 384.0 P 87.2 H

652,894 W 156.4 T 840.0 P 2,950.2 H

100.0 T 189.5 P 18.0 H

6

1,157,812 W 199.0 T 384.0 P 39.8 H

HP BFW

N2 to GT Combustor N2 Boost Compressor 0 W 199.0 T 384.0 P 39.8 H 0 W 385.0 T 469.0 P 87.0 H

Saturated Steam To HRSG HP Superheater

GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank

Knockout Drum

Vent To Claus Unit

Raw Fuel Gas

CWS

CWR

Fines

Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench Section Drag Conveyor

974,659 W 1,250.0 T 805.0 P 612.5 H 1,207,768 W 403.3 T 800.0 P 459.0 H

Syngas Quench

1,334,140 W 450.0 T 805.0 P 536.1 H

8

9

10 Sour Water

7

4

1,157,812 W 199.0 T 384.0 P 39.8 H
Carbon Dioxide Capture Sensitivity Analysis

326

Exhibit 4-84 Case 2 D3A (25%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum

Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water

Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out

From Syngas ASU Coolers

Sour Stripper 1,207,768 W 403.3 T 800.0 P 459.0 H

859,731 W 94.7 T 740.0 P 17.3 H 15,141 W 119.0 T 23.7 P

578,797 W 386.9 T 460.0 P 152.7 H

11,581 W 12,720 W 450.0 T 12.3 P 850.9 H

2,511 W 240.2 T 65.0 P 445.2 H

6,650 W 90.0 T 125.0 P 11.5 H NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D3A HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D3A (25%) GEE GASIFIER GAS CLEANUP SYSTEM DWG. NO. CCSA-HMB-CS-2-D3A-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 2 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 750 MWe Auxiliary Load: 143 MWe Net Plant Power: 607 MWe Net Plant Efficiency, HHV: 38.4% Net Plant Heat Rate: 8,894 BTU/KWe

22

16 23

CO2

Tailgas

Tail Gas Cleanup Unit

Tail Gas Compressor

7,215 W 120.0 T 10.6 P 202.7 H

853,600 W 94.8 T 745.0 P 17.2 H

6,589 W 116.7 T 10.6 P 42.7 H

3 6,131 W 100.0 T 799.5 P

Raw Syngas

18 578,797 W 94.7 T 725.0 P 23.5 H

Claus Oxygen Preheater

6,650 W 450.0 T 124.5 P 91.9 H

21

Fuel Gas Expander Fuel Gas To GT 19 578,797 W 465.0 T 720.0 P 187.3 H High Temperature Shift #1 Low Temperature Shift #2 Shift Steam 12 11

COS Hydrolysis Preheater

1,207,768 W 413.3 T 795.0 P 451.0 H

0 W 550.0 T 800.0 P 1,254.1 H

3,020 W 413.3 T 795.0 P 451.1 H 768.8 T 795.0 P 435.3 H 400.0 T 795.0 P 271.8 H 3,020 W 510.4 T 785.0 P 267.2 H

1,207,768 W 403.0 T 780.0 P 446.2 H

Two-Stage Selexol

Clean Gas

CO2

Acid Gas

Multistage Intercooled CO2 Compressor Interstage Knockout

CO2 Product 20 10

17

265,209 W 146.4 T 2,214.7 P

COS Hydrolysis 13 14

15

1,204,748 W 413.3 T 795.0 P 451.0 H 1,204,748 W 413.2 T 785.0 P 451.0 H 1,207,768 W 413.4 T 785.0 P 450.5 H
Carbon Dioxide Capture Sensitivity Analysis

327

Exhibit 4-85 Case 2 D3A (25%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine

Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator

Ip Extraction Steam To 250 PSIA Header

LP Process Header

Blowdown Flash To WWT

Gland Steam Condenser Condensate to Gasification Island

HP BFW to Radiant Syngas Cooler HP Saturated Steam to HRSG Superheater

LP Turbine

Stack

Compressor Expander

Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class Gas Turbine

MP Flash Bottoms LP Flash Tops

7,014,133 W 59.0 T 14.7 P 13.0 H 1,678,708 W 101.1 T 1.0 P 69.1 H

8,750,744 W 269.9 T 15.2 P 101.4 H

578,797 W 386.9 T 460.0 P 152.7 H

8,750,744 W 1,079.4 T 15.2 P 315.2 H From Gasifier Island Preheating

To Claus

LP BFW 1,390,513 W 1,029.4 T 1,814.7 P 1,497.8 H

10,077 W 298.0 T 65.0 P 1,179.0 H 1,418,721 W 278.8 T 2,250.7 P 252.3 H 28,204 W 585.0 T 2,000.7 P 593.3 H

1,639,233 W 492.9 T 65.0 P 1,278.5 H

1,678,708 W 103.1 T 120.0 P 71.3 H

1,678,708 W 235.0 T 105.0 P 203.7 H

1,400 W 649.2 T 65.0 P 1,355.6 H 1,400 W 212.0 T 14.7 P 179.9 H

IP Pump NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D3A HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D3A (25%) GEE GASIFIER POWER BLOCK SYSTEM DWG. NO. CCSA-HMB-CS-2-D3A-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 3 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 750 MWe Auxiliary Load: 143 MWe Net Plant Power: 607 MWe Net Plant Efficiency, HHV: 38.4% Net Plant Heat Rate: 8,894 BTU/KWe 24

25

27 19

26

Flue Gas

HOT WELL CONDENSER Make-up 27,496 W 59.0 T 14.7 P 27.1 H

8,876 W 690.4 T 501.4 P 1,351.7 H 9,580 W 649.2 T 65.0 P 1,355.6 H 25,424 W 885.4 T 280.0 P 1,466.2 H 785 W 1,029.4 T 1,814.7 P 1,497.8 H 1,319 W 531.0 T 65.0 P 1,297.3 H
Carbon Dioxide Capture Sensitivity Analysis

328

Exhibit 4-86 Case 2 D3B (45%) Heat and Mass Balance, GEE Gasifier and ASU

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D3B HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D3B (45%) GEE GASIFIER ASU AND GASIFICATION DWG. NO. CCSA-HMB-CS-2-D3B-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 1 OF 3

Ambient Air Four Stage Air Compressor

Elevated Pressure ASU Four Stage N2 Compressor

Four Stage O2 Compressor

ASU Vent

Water

Steam

Gross Plant Power: 746 MWe Auxiliary Load: 156 MWe Net Plant Power: 590 MWe Net Plant Efficiency, HHV: 36.7% Net Plant Heat Rate: 9,289 BTU/KWe

N2 to GT Combustor 1,680,379 W 59.0 T 14.7 P 13.0 H

378,224 W 90.0 T 125.0 P 11.5 H

378,224 W 241.2 T 940.0 P 40.8 H

To Claus Plant 6,793 W 90.0 T 125.0 P 11.5 H

112,185 W 63.8 T 16.4 P 15.2 H

1,030,331 W 90.0 T 56.4 P 14.2 H

151,346 W 50.0 T 182.0 P 2.9 H 5

1

3

2

Slurry Mix Tank

Milled Coal

Slag

469,844 W 59.0 T 14.7 P

193,012 W 287.0 T 840.0 P 231.2 H

51,550 W 2,400.0 T 815.0 P

1,170,481 W 385.0 T 384.0 P 87.2 H

662,856 W 156.4 T 840.0 P 2,950.2 H

100.0 T 189.5 P 18.0 H

6

1,170,481 W 199.0 T 384.0 P 39.8 H

HP BFW

N2 to GT Combustor N2 Boost Compressor 11,195 W 199.0 T 384.0 P 39.8 H 11,195 W 385.0 T 469.0 P 87.0 H

Saturated Steam To HRSG HP Superheater

GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank

Knockout Drum

Vent To Claus Unit

Raw Fuel Gas

CWS

CWR

Fines

Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench Section Drag Conveyor

989,530 W 1,250.0 T 805.0 P 612.5 H 1,225,965 W 403.2 T 800.0 P 458.8 H

Syngas Quench

1,354,496 W 450.0 T 805.0 P 536.1 H

8

9

10 Sour Water

7

4

1,181,676 W 199.0 T 384.0 P 39.8 H
Carbon Dioxide Capture Sensitivity Analysis

329

Exhibit 4-87 Case 2 D3B (45%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum

Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water

Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out

From Syngas ASU Coolers

Sour Stripper 1,225,965 W 403.2 T 800.0 P 458.8 H

964,724 W 94.7 T 740.0 P 16.9 H 14,739 W 119.0 T 23.7 P

468,146 W 387.1 T 460.0 P 194.2 H

11,754 W 12,234 W 450.0 T 12.3 P 909.1 H

2,455 W 239.0 T 65.0 P 437.8 H

6,793 W 90.0 T 125.0 P 11.5 H NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D3B HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D3B (45%) GEE GASIFIER GAS CLEANUP SYSTEM DWG. NO. CCSA-HMB-CS-2-D3B-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 2 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 746 MWe Auxiliary Load: 156 MWe Net Plant Power: 590 MWe Net Plant Efficiency, HHV: 36.7% Net Plant Heat Rate: 9,289 BTU/KWe

22

16 23

CO2

Tailgas

Tail Gas Cleanup Unit

Tail Gas Compressor

6,028 W 120.0 T 10.6 P 220.8 H

959,686 W 94.8 T 745.0 P 16.8 H

7,195 W 117.3 T 10.6 P 43.3 H

3 5,039 W 100.0 T 799.5 P

Raw Syngas

18 468,146 W 94.7 T 725.0 P 31.3 H

Claus Oxygen Preheater

6,793 W 450.0 T 124.5 P 91.9 H

21

Fuel Gas Expander Fuel Gas To GT 19 468,146 W 465.0 T 720.0 P 238.1 H High Temperature Shift #1 Low Temperature Shift #2 Shift Steam 12 11

COS Hydrolysis Preheater

1,225,965 W 413.2 T 795.0 P 450.9 H

65,912 W 550.0 T 800.0 P 1,254.1 H

441,057 W 432.1 T 795.0 P 571.0 H 779.0 T 795.0 P 554.9 H 400.0 T 795.0 P 380.9 H 441,057 W 474.0 T 785.0 P 377.6 H

1,291,877 W 425.0 T 780.0 P 421.7 H

Two-Stage Selexol

Clean Gas

CO2

Acid Gas

Multistage Intercooled CO2 Compressor Interstage Knockout

CO2 Product 20 10

17

481,167 W 130.3 T 2,214.7 P

COS Hydrolysis 13 14

15

850,820 W 413.2 T 795.0 P 450.9 H 850,820 W 413.1 T 785.0 P 450.8 H 1,291,877 W 434.6 T 785.0 P 425.8 H
Carbon Dioxide Capture Sensitivity Analysis

330

Exhibit 4-88 Case 2 D3B (45%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine

Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator

Ip Extraction Steam To 250 PSIA Header

LP Process Header

Blowdown Flash To WWT

Gland Steam Condenser Condensate to Gasification Island

HP BFW to Radiant Syngas Cooler HP Saturated Steam to HRSG Superheater

LP Turbine

Stack

Compressor Expander

Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class Gas Turbine

MP Flash Bottoms LP Flash Tops

7,014,133 W 59.0 T 14.7 P 13.0 H 1,740,783 W 101.1 T 1.0 P 69.1 H

8,663,957 W 270.2 T 15.2 P 114.7 H

468,146 W 387.1 T 460.0 P 194.2 H

8,663,957 W 1,068.9 T 15.2 P 327.6 H From Gasifier Island Preheating

To Claus

LP BFW 1,389,734 W 1,018.9 T 1,814.7 P 1,491.4 H

10,138 W 298.0 T 65.0 P 1,179.0 H 1,418,112 W 278.8 T 2,250.7 P 252.3 H 28,376 W 585.0 T 2,000.7 P 593.3 H

1,635,132 W 483.4 T 65.0 P 1,273.8 H

1,740,783 W 103.0 T 120.0 P 71.2 H

1,740,783 W 235.0 T 105.0 P 203.7 H

1,400 W 639.2 T 65.0 P 1,350.6 H 1,400 W 212.0 T 14.7 P 179.9 H

IP Pump NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D3B HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D3B (45%) GEE GASIFIER POWER BLOCK SYSTEM DWG. NO. CCSA-HMB-CS-2-D3B-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 3 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 746 MWe Auxiliary Load: 156 MWe Net Plant Power: 590 MWe Net Plant Efficiency, HHV: 36.7% Net Plant Heat Rate: 9,289 BTU/KWe 24

25

27 19

26

Flue Gas

HOT WELL CONDENSER Make-up 93,619 W 59.0 T 14.7 P 27.1 H

8,919 W 681.6 T 501.4 P 1,346.7 H 9,632 W 639.2 T 65.0 P 1,350.6 H 25,757 W 875.6 T 280.0 P 1,461.1 H 789 W 1,018.9 T 1,814.7 P 1,491.4 H 1,324 W 523.3 T 65.0 P 1,293.6 H
Carbon Dioxide Capture Sensitivity Analysis

331

Exhibit 4-89 Case 2 D3C (60%) Heat and Mass Balance, GEE Gasifier and ASU

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D3C HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D3C (60%) GEE GASIFIER ASU AND GASIFICATION DWG. NO. CCSA-HMB-CS-2-D3C-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 1 OF 3

Ambient Air Four Stage Air Compressor

Elevated Pressure ASU Four Stage N2 Compressor

Four Stage O2 Compressor

ASU Vent

Water

Steam

Gross Plant Power: 744 MWe Auxiliary Load: 167 MWe Net Plant Power: 577 MWe Net Plant Efficiency, HHV: 35.5% Net Plant Heat Rate: 9,614 BTU/KWe

N2 to GT Combustor 1,702,103 W 59.0 T 14.7 P 13.0 H

383,073 W 90.0 T 125.0 P 11.5 H

383,073 W 241.2 T 940.0 P 40.8 H

To Claus Plant 6,922 W 90.0 T 125.0 P 11.5 H

115,369 W 63.7 T 16.4 P 15.1 H

1,041,917 W 90.0 T 56.4 P 14.2 H

153,302 W 50.0 T 182.0 P 2.9 H 5

1

3

2

Slurry Mix Tank

Milled Coal

Slag

475,867 W 59.0 T 14.7 P

195,486 W 287.0 T 840.0 P 231.2 H

52,211 W 2,400.0 T 815.0 P

1,001,462 W 385.0 T 384.0 P 87.2 H

671,354 W 156.4 T 840.0 P 2,950.2 H

100.0 T 189.5 P 18.0 H

6

1,001,462 W 199.0 T 384.0 P 39.8 H

HP BFW

N2 to GT Combustor N2 Boost Compressor 193,757 W 199.0 T 384.0 P 39.8 H 193,757 W 385.0 T 469.0 P 87.0 H

Saturated Steam To HRSG HP Superheater

GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank

Knockout Drum

Vent To Claus Unit

Raw Fuel Gas

CWS

CWR

Fines

Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench Section Drag Conveyor

1,002,216 W 1,250.0 T 805.0 P 612.5 H 1,242,215 W 403.3 T 800.0 P 459.2 H

Syngas Quench

1,371,861 W 450.0 T 805.0 P 536.1 H

8

9

10 Sour Water

7

4

1,195,219 W 199.0 T 384.0 P 39.8 H
Carbon Dioxide Capture Sensitivity Analysis

332

Exhibit 4-90 Case 2 D3C (60%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum

Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water

Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out

From Syngas ASU Coolers

Sour Stripper 1,242,215 W 403.3 T 800.0 P 459.2 H

1,051,833 W 94.7 T 740.0 P 16.6 H 14,414 W 119.0 T 23.7 P

384,577 W 387.5 T 460.0 P 243.6 H

11,902 W 11,854 W 450.0 T 12.3 P 959.2 H

2,420 W 237.6 T 65.0 P 429.1 H

6,922 W 90.0 T 125.0 P 11.5 H NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D3C HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D3C (60%) GEE GASIFIER GAS CLEANUP SYSTEM DWG. NO. CCSA-HMB-CS-2-D3C-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 2 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 744 MWe Auxiliary Load: 167 MWe Net Plant Power: 577 MWe Net Plant Efficiency, HHV: 35.5% Net Plant Heat Rate: 9,614 BTU/KWe

22

16 23

CO2

Tailgas

Tail Gas Cleanup Unit

Tail Gas Compressor

5,067 W 120.0 T 10.6 P 241.8 H

1,047,679 W 94.9 T 745.0 P 16.5 H

7,700 W 117.6 T 10.6 P 43.7 H

3 4,154 W 100.0 T 799.5 P

Raw Syngas

18 384,577 W 94.7 T 725.0 P 40.3 H

Claus Oxygen Preheater

6,922 W 450.0 T 124.5 P 91.9 H

21

Fuel Gas Expander Fuel Gas To GT 19 384,577 W 465.0 T 720.0 P 298.3 H High Temperature Shift #1 Low Temperature Shift #2 Shift Steam 12 11

COS Hydrolysis Preheater

1,242,215 W 413.3 T 795.0 P 451.2 H

119,253 W 550.0 T 800.0 P 1,254.1 H

802,471 W 432.1 T 795.0 P 570.6 H 778.6 T 795.0 P 554.3 H 400.0 T 795.0 P 380.4 H 802,471 W 473.9 T 785.0 P 377.1 H

1,361,467 W 440.6 T 780.0 P 403.5 H

Two-Stage Selexol

Clean Gas

CO2

Acid Gas

Multistage Intercooled CO2 Compressor Interstage Knockout

CO2 Product 20 10

17

652,097 W 126.6 T 2,214.7 P

COS Hydrolysis 13 14

15

558,997 W 413.3 T 795.0 P 451.2 H 558,997 W 413.2 T 785.0 P 451.2 H 1,361,467 W 449.7 T 785.0 P 407.5 H
Carbon Dioxide Capture Sensitivity Analysis

333

Exhibit 4-91 Case 2 D3C (60%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine

Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator

Ip Extraction Steam To 250 PSIA Header

LP Process Header

Blowdown Flash To WWT

Gland Steam Condenser Condensate to Gasification Island

HP BFW to Radiant Syngas Cooler HP Saturated Steam to HRSG Superheater

LP Turbine

Stack

Compressor Expander

Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class Gas Turbine

MP Flash Bottoms LP Flash Tops

7,014,133 W 59.0 T 14.7 P 13.0 H 1,779,215 W 101.1 T 1.0 P 69.1 H

8,593,931 W 269.9 T 15.2 P 125.7 H

384,577 W 387.5 T 460.0 P 243.6 H

8,593,931 W 1,060.8 T 15.2 P 338.1 H From Gasifier Island Preheating

To Claus

LP BFW 1,378,969 W 1,010.8 T 1,814.7 P 1,486.4 H

10,184 W 298.0 T 65.0 P 1,179.0 H 1,407,477 W 278.8 T 2,250.7 P 252.3 H 28,503 W 585.0 T 2,000.7 P 593.3 H

1,620,282 W 481.5 T 65.0 P 1,272.9 H

1,779,215 W 103.0 T 120.0 P 71.2 H

1,779,215 W 235.0 T 105.0 P 203.7 H

1,400 W 631.4 T 65.0 P 1,346.8 H 1,400 W 212.0 T 14.7 P 179.9 H

IP Pump NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D3C HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D3C (60%) GEE GASIFIER POWER BLOCK SYSTEM DWG. NO. CCSA-HMB-CS-2-D3C-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 3 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 744 MWe Auxiliary Load: 167 MWe Net Plant Power: 577 MWe Net Plant Efficiency, HHV: 35.5% Net Plant Heat Rate: 9,614 BTU/KWe 24

25

27 19

26

Flue Gas

HOT WELL CONDENSER Make-up 146,860 W 59.0 T 14.7 P 27.1 H

8,953 W 674.8 T 501.4 P 1,342.8 H 9,673 W 631.4 T 65.0 P 1,346.8 H 26,009 W 868.0 T 280.0 P 1,457.1 H 792 W 1,010.8 T 1,814.7 P 1,486.4 H 1,328 W 517.4 T 65.0 P 1,290.7 H
Carbon Dioxide Capture Sensitivity Analysis

334

Exhibit 4-92 Case 2 D3D (75%) Heat and Mass Balance, GEE Gasifier and ASU

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D3D HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D3D (75%) GEE GASIFIER ASU AND GASIFICATION DWG. NO. CCSA-HMB-CS-2-D3D-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 1 OF 3

Ambient Air Four Stage Air Compressor

Elevated Pressure ASU Four Stage N2 Compressor

Four Stage O2 Compressor

ASU Vent

Water

Steam

Gross Plant Power: 742 MWe Auxiliary Load: 178 MWe Net Plant Power: 564 MWe Net Plant Efficiency, HHV: 34.2% Net Plant Heat Rate: 9,969 BTU/KWe

N2 to GT Combustor 1,722,729 W 59.0 T 14.7 P 13.0 H

387,832 W 90.0 T 125.0 P 11.5 H

387,832 W 241.2 T 940.0 P 40.8 H

To Claus Plant 6,889 W 90.0 T 125.0 P 11.5 H

115,309 W 63.8 T 16.4 P 15.2 H

1,056,000 W 90.0 T 56.4 P 14.2 H

155,160 W 50.0 T 182.0 P 2.9 H 5

1

3

2

Slurry Mix Tank

Milled Coal

Slag

481,779 W 59.0 T 14.7 P

197,915 W 287.0 T 840.0 P 231.2 H

52,859 W 2,400.0 T 815.0 P

831,750 W 385.0 T 384.0 P 87.2 H

679,693 W 156.4 T 840.0 P 2,950.2 H

100.0 T 189.5 P 18.0 H

6

831,750 W 199.0 T 384.0 P 39.8 H

HP BFW

N2 to GT Combustor N2 Boost Compressor 379,410 W 199.0 T 384.0 P 39.8 H 379,410 W 385.0 T 469.0 P 87.0 H

Saturated Steam To HRSG HP Superheater

GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank

Knockout Drum

Vent To Claus Unit

Raw Fuel Gas

CWS

CWR

Fines

Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench Section Drag Conveyor

1,014,666 W 1,250.0 T 805.0 P 612.5 H 1,258,103 W 403.4 T 800.0 P 459.5 H

Syngas Quench

1,388,902 W 450.0 T 805.0 P 536.1 H

8

9

10 Sour Water

7

4

1,211,160 W 199.0 T 384.0 P 39.8 H
Carbon Dioxide Capture Sensitivity Analysis

335

Exhibit 4-93 Case 2 D3D (75%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum

Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water

Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out

From Syngas ASU Coolers

Sour Stripper 1,258,103 W 403.4 T 800.0 P 459.5 H

1,141,658 W 94.7 T 740.0 P 16.3 H 16,393 W 119.0 T 23.7 P

297,976 W 387.8 T 460.0 P 322.9 H

12,047 W 13,625 W 450.0 T 12.3 P 904.3 H

2,390 W 236.2 T 65.0 P 419.4 H

6,889 W 90.0 T 125.0 P 11.5 H NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D3D HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D3D (75%) GEE GASIFIER GAS CLEANUP SYSTEM DWG. NO. CCSA-HMB-CS-2-D3D-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 2 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 742 MWe Auxiliary Load: 178 MWe Net Plant Power: 564 MWe Net Plant Efficiency, HHV: 34.2% Net Plant Heat Rate: 9,969 BTU/KWe

22

16 23

CO2

Tailgas

Tail Gas Cleanup Unit

Tail Gas Compressor

6,590 W 120.0 T 10.6 P 206.5 H

1,136,078 W 94.9 T 745.0 P 16.2 H

8,045 W 117.5 T 10.6 P 43.5 H

3 5,580 W 100.0 T 799.5 P

Raw Syngas

18 297,976 W 94.7 T 725.0 P 54.5 H

Claus Oxygen Preheater

6,889 W 450.0 T 124.5 P 91.9 H

21

Fuel Gas Expander Fuel Gas To GT 19 297,976 W 465.0 T 720.0 P 395.1 H High Temperature Shift #1 Low Temperature Shift #2 Shift Steam 12 11

COS Hydrolysis Preheater

1,258,103 W 413.4 T 795.0 P 451.5 H

173,583 W 550.0 T 800.0 P 1,254.1 H

1,167,485 W 432.1 T 795.0 P 570.9 H 779.0 T 795.0 P 554.8 H 400.0 T 795.0 P 380.8 H 1,167,485 W 474.0 T 785.0 P 377.5 H

1,431,687 W 454.7 T 780.0 P 387.3 H

Two-Stage Selexol

Clean Gas

CO2

Acid Gas

Multistage Intercooled CO2 Compressor Interstage Knockout

CO2 Product 20 10

17

826,469 W 124.8 T 2,214.7 P

COS Hydrolysis 13 14

15

264,202 W 413.4 T 795.0 P 451.5 H 264,202 W 413.3 T 785.0 P 451.5 H 1,431,687 W 463.3 T 785.0 P 391.2 H
Carbon Dioxide Capture Sensitivity Analysis

336

Exhibit 4-94 Case 2 D3D (75%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine

Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator

Ip Extraction Steam To 250 PSIA Header

LP Process Header

Blowdown Flash To WWT

Gland Steam Condenser Condensate to Gasification Island

HP BFW to Radiant Syngas Cooler HP Saturated Steam to HRSG Superheater

LP Turbine

Stack

Compressor Expander

Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class Gas Turbine

MP Flash Bottoms LP Flash Tops

7,014,133 W 59.0 T 14.7 P 13.0 H 1,813,468 W 101.1 T 1.0 P 69.1 H

8,523,270 W 269.9 T 15.2 P 137.0 H

297,976 W 387.8 T 460.0 P 322.9 H

8,523,270 W 1,052.4 T 15.2 P 348.9 H From Gasifier Island Preheating

To Claus

LP BFW 1,367,787 W 1,002.4 T 1,814.7 P 1,481.2 H

10,229 W 298.0 T 65.0 P 1,179.0 H 1,396,415 W 278.8 T 2,250.7 P 252.3 H 28,629 W 585.0 T 2,000.7 P 593.3 H

1,600,263 W 479.7 T 65.0 P 1,272.0 H

1,813,468 W 102.9 T 120.0 P 71.1 H

1,813,468 W 235.0 T 105.0 P 203.7 H

1,400 W 623.3 T 65.0 P 1,342.8 H 1,400 W 212.0 T 14.7 P 179.9 H

IP Pump NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D3D HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D3D (75%) GEE GASIFIER POWER BLOCK SYSTEM DWG. NO. CCSA-HMB-CS-2-D3D-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 3 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 742 MWe Auxiliary Load: 178 MWe Net Plant Power: 564 MWe Net Plant Efficiency, HHV: 34.2% Net Plant Heat Rate: 9,969 BTU/KWe 24

25

27 19

26

Flue Gas

HOT WELL CONDENSER Make-up 201,089 W 59.0 T 14.7 P 27.1 H

8,988 W 667.7 T 501.4 P 1,338.7 H 9,716 W 623.3 T 65.0 P 1,342.8 H 27,806 W 860.2 T 280.0 P 1,453.1 H 795 W 1,002.4 T 1,814.7 P 1,481.2 H 1,333 W 511.3 T 65.0 P 1,287.6 H
Carbon Dioxide Capture Sensitivity Analysis

337

Exhibit 4-95 Case 2 D3E (85%) Heat and Mass Balance, GEE Gasifier and ASU

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D3E HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D3E (85%) GEE GASIFIER ASU AND GASIFICATION DWG. NO. CCSA-HMB-CS-2-D3E-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 1 OF 3

Ambient Air Four Stage Air Compressor

Elevated Pressure ASU Four Stage N2 Compressor

Four Stage O2 Compressor

ASU Vent

Water

Steam

Gross Plant Power: 740 MWe Auxiliary Load: 185 MWe Net Plant Power: 554 MWe Net Plant Efficiency, HHV: 33.4% Net Plant Heat Rate: 10,222 BTU/KWe

N2 to GT Combustor 1,736,984 W 59.0 T 14.7 P 13.0 H

391,098 W 90.0 T 125.0 P 11.5 H

391,098 W 241.2 T 940.0 P 40.8 H

To Claus Plant 6,889 W 90.0 T 125.0 P 11.5 H

115,584 W 63.8 T 16.4 P 15.2 H

1,065,418 W 90.0 T 56.4 P 14.2 H

156,444 W 50.0 T 182.0 P 2.9 H 5

1

3

2

Slurry Mix Tank

Milled Coal

Slag

485,836 W 59.0 T 14.7 P

199,581 W 287.0 T 840.0 P 231.2 H

53,304 W 2,400.0 T 815.0 P

716,301 W 385.0 T 384.0 P 87.2 H

685,417 W 156.4 T 840.0 P 2,950.2 H

100.0 T 189.5 P 18.0 H

6

716,301 W 199.0 T 384.0 P 39.8 H

HP BFW

N2 to GT Combustor N2 Boost Compressor 505,561 W 199.0 T 384.0 P 39.8 H 505,561 W 385.0 T 469.0 P 87.0 H

Saturated Steam To HRSG HP Superheater

GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank

Knockout Drum

Vent To Claus Unit

Raw Fuel Gas

CWS

CWR

Fines

Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench Section Drag Conveyor

1,023,211 W 1,250.0 T 805.0 P 612.5 H 1,267,818 W 403.3 T 800.0 P 458.9 H

Syngas Quench

1,400,599 W 450.0 T 805.0 P 536.1 H

8

9

10 Sour Water

7

4

1,221,862 W 199.0 T 384.0 P 39.8 H
Carbon Dioxide Capture Sensitivity Analysis

338

Exhibit 4-96 Case 2 D3E (85%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum

Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water

Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out

From Syngas ASU Coolers

Sour Stripper 1,267,818 W 403.3 T 800.0 P 458.9 H

1,202,859 W 94.8 T 740.0 P 16.1 H 17,762 W 119.0 T 23.7 P

239,291 W 387.9 T 460.0 P 409.3 H

12,146 W 14,876 W 450.0 T 12.3 P 870.8 H

2,371 W 235.0 T 65.0 P 411.8 H

6,889 W 90.0 T 125.0 P 11.5 H NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D3E HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D3E (85%) GEE GASIFIER GAS CLEANUP SYSTEM DWG. NO. CCSA-HMB-CS-2-D3E-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 2 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 740 MWe Auxiliary Load: 185 MWe Net Plant Power: 554 MWe Net Plant Efficiency, HHV: 33.4% Net Plant Heat Rate: 10,222 BTU/KWe

22

16 23

CO2

Tailgas

Tail Gas Cleanup Unit

Tail Gas Compressor

7,650 W 120.0 T 10.6 P 189.7 H

1,196,284 W 94.9 T 745.0 P 16.0 H

8,301 W 117.4 T 10.6 P 43.5 H

3 6,575 W 100.0 T 799.5 P

Raw Syngas

18 239,291 W 94.8 T 725.0 P 69.8 H

Claus Oxygen Preheater

6,889 W 450.0 T 124.5 P 91.9 H

21

Fuel Gas Expander Fuel Gas To GT 19 239,291 W 465.0 T 720.0 P 500.6 H High Temperature Shift #1 Low Temperature Shift #2 Shift Steam 12 11

COS Hydrolysis Preheater

1,267,818 W 413.3 T 795.0 P 451.0 H

210,177 W 550.0 T 800.0 P 1,254.1 H

1,414,604 W 432.0 T 795.0 P 570.4 H 778.9 T 795.0 P 554.2 H 400.0 T 795.0 P 380.2 H 1,414,604 W 473.9 T 785.0 P 376.8 H

1,477,995 W 463.2 T 780.0 P 376.3 H

Two-Stage Selexol

Clean Gas

CO2

Acid Gas

Multistage Intercooled CO2 Compressor Interstage Knockout

CO2 Product 20 10

17

944,936 W 124.0 T 2,214.7 P

COS Hydrolysis 13 14

15

63,391 W 413.3 T 795.0 P 451.0 H 63,391 W 413.1 T 785.0 P 450.9 H 1,477,995 W 471.5 T 785.0 P 380.0 H
Carbon Dioxide Capture Sensitivity Analysis

339

Exhibit 4-97 Case 2 D3E (85%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine

Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator

Ip Extraction Steam To 250 PSIA Header

LP Process Header

Blowdown Flash To WWT

Gland Steam Condenser Condensate to Gasification Island

HP BFW to Radiant Syngas Cooler HP Saturated Steam to HRSG Superheater

LP Turbine

Stack

Compressor Expander

Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class Gas Turbine

MP Flash Bottoms LP Flash Tops

7,014,133 W 59.0 T 14.7 P 13.0 H 1,835,108 W 101.1 T 1.0 P 69.1 H

8,475,287 W 269.9 T 15.2 P 144.9 H

239,291 W 387.9 T 460.0 P 409.3 H

8,475,287 W 1,046.8 T 15.2 P 356.3 H From Gasifier Island Preheating

To Claus

LP BFW 1,360,368 W 996.8 T 1,814.7 P 1,477.7 H

10,261 W 298.0 T 65.0 P 1,179.0 H 1,389,073 W 278.8 T 2,250.7 P 252.3 H 28,719 W 585.0 T 2,000.7 P 593.3 H

1,585,352 W 478.6 T 65.0 P 1,271.5 H

1,835,108 W 102.9 T 120.0 P 71.1 H

1,835,108 W 235.0 T 105.0 P 203.7 H

1,400 W 617.8 T 65.0 P 1,340.1 H 1,400 W 212.0 T 14.7 P 179.9 H

IP Pump NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D3E HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D3E (85%) GEE GASIFIER POWER BLOCK SYSTEM DWG. NO. CCSA-HMB-CS-2-D3E-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 3 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 740 MWe Auxiliary Load: 185 MWe Net Plant Power: 554 MWe Net Plant Efficiency, HHV: 33.4% Net Plant Heat Rate: 10,222 BTU/KWe 24

25

27 19

26

Flue Gas

HOT WELL CONDENSER Make-up 237,610 W 59.0 T 14.7 P 27.1 H

9,013 W 663.0 T 501.4 P 1,336.0 H 9,746 W 617.8 T 65.0 P 1,340.1 H 28,912 W 855.0 T 280.0 P 1,450.3 H 797 W 996.8 T 1,814.7 P 1,477.7 H 1,336 W 507.2 T 65.0 P 1,285.6 H
Carbon Dioxide Capture Sensitivity Analysis

340

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Carbon Dioxide Capture Sensitivity Analysis

341

Exhibit 4-98 Case 2 D3A (25%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,696 

(5,399) 4.8 (4.5) 0 (0) 5,701 (5,403)

ASU Air 0 (0) 22.7 (21.5) 0 (0) 23 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 66.8 (63.3) 0 (0) 67 (63)

Totals 5,696 

(5,399) 190.5 (180.5) 0 (0) 5,887 (5,579)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.9 (1.8) 0 (0) 2 (2)

Slag 88 (83) 36.0 (34.1) 0 (0) 124 (117)

Sulfur 49 (46) 0.6 (0.6) 0 (0) 49 (47)

CO2 0 (0) -13.0 (-12.4) 0 (0) -13 (-12)

Gasifier Heat Loss 0 (0) 42.4 (40.2) 0 (0) 42 (40)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 937 (888) 0 (0) 937 (888)

Cooling Tower* 0 (0) 2,073 (1,965) 0 (0) 2,073 

(1,965)

Process Losses** 0 (0) 424 (402) 0 (0) 424 (402)

Net Power 0 (0) 0.0 (0.0) 2,185 

(2,071)

2,185 

(2,071)

Totals 136 (129) 3,565 (3,379) 2,185 

(2,071)

5,887 

(5,579)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Includes Condenser, Cooling Tower Blowdown, and the following Non-Condenser 

 Cooling Tower Loads: ASU compressor intercoolers, CO2 compressor intercoolers,

 sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

 air cooler.

** Calculated by difference to close the energy balance.
Carbon Dioxide Capture Sensitivity Analysis

342

Exhibit 4-99 Case 2 D3B (45%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,783 

(5,481) 4.8 (4.6) 0 (0) 5,788 (5,486)

ASU Air 0 (0) 23.0 (21.8) 0 (0) 23 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 71.7 (68.0) 0 (0) 72 (68)

Totals 5,783 

(5,481) 195.8 (185.6) 0 (0) 5,979 (5,667)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.8 (1.7) 0 (0) 2 (2)

Slag 89 (84) 36.5 (34.6) 0 (0) 126 (119)

Sulfur 49 (47) 0.6 (0.6) 0 (0) 50 (47)

CO2 0 (0) -31.7 (-30.0) 0 (0) -32 (-30)

Gasifier Heat Loss 0 (0) 43.1 (40.8) 0 (0) 43 (41)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,048 (994) 0 (0) 1,048 (994)

Cooling Tower* 0 (0) 2,115 (2,005) 0 (0) 2,115 

(2,005)

Process Losses** 0 (0) 439 (416) 0 (0) 439 (416)

Net Power 0 (0) 0.0 (0.0) 2,124 

(2,013)

2,124 

(2,013)

Totals 138 (131) 3,716 (3,522) 2,124 

(2,013)

5,979 

(5,667)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Includes Condenser, Cooling Tower Blowdown, and the following Non-Condenser 

 Cooling Tower Loads: ASU compressor intercoolers, CO2 compressor intercoolers,

 sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

 air cooler.

** Calculated by difference to close the energy balance.
Carbon Dioxide Capture Sensitivity Analysis

343

Exhibit 4-100 Case 2 D3C (60%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,857 

(5,551) 4.9 (4.6) 0 (0) 5,862 (5,556)

ASU Air 0 (0) 23.3 (22.1) 0 (0) 23 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 75.5 (71.6) 0 (0) 76 (72)

Totals 5,857 

(5,551) 199.9 (189.5) 0 (0) 6,057 (5,741)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.8 (1.7) 0 (0) 2 (2)

Slag 90 (86) 37.0 (35.0) 0 (0) 127 (121)

Sulfur 50 (47) 0.6 (0.6) 0 (0) 51 (48)

CO2 0 (0) -45.7 (-43.3) 0 (0) -46 (-43)

Gasifier Heat Loss 0 (0) 43.6 (41.3) 0 (0) 44 (41)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,140 (1,080) 0 (0) 1,140 

(1,080)

Cooling Tower* 0 (0) 2,143 (2,031) 0 (0) 2,143 

(2,031)

Process Losses** 0 (0) 455 (431) 0 (0) 455 (431)

Net Power 0 (0) 0.0 (0.0) 2,079 

(1,970)

2,079 

(1,970)

Totals 140 (133) 3,838 (3,638) 2,079 

(1,970)

6,057 

(5,741)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Includes Condenser, Cooling Tower Blowdown, and the following Non-Condenser 

 Cooling Tower Loads: ASU compressor intercoolers, CO2 compressor intercoolers,

 sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

 air cooler.

** Calculated by difference to close the energy balance.
Carbon Dioxide Capture Sensitivity Analysis

344

Exhibit 4-101 Case 2 D3D (75%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,930 

(5,620) 5.0 (4.7) 0 (0) 5,935 (5,625)

ASU Air 0 (0) 23.6 (22.4) 0 (0) 24 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 79.3 (75.1) 0 (0) 79 (75)

Totals 5,930 

(5,620) 204.0 (193.4) 0 (0) 6,134 (5,814)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.8 (1.7) 0 (0) 2 (2)

Slag 91 (87) 37.4 (35.5) 0 (0) 129 (122)

Sulfur 51 (48) 0.6 (0.6) 0 (0) 51 (49)

CO2 0 (0) -59.7 (-56.6) 0 (0) -60 (-57)

Gasifier Heat Loss 0 (0) 44.1 (41.8) 0 (0) 44 (42)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,232 (1,168) 0 (0) 1,232 

(1,168)

Cooling Tower* 0 (0) 2,167 (2,054) 0 (0) 2,167 

(2,054)

Process Losses** 0 (0) 476 (451) 0 (0) 476 (451)

Net Power 0 (0) 0.0 (0.0) 2,030 

(1,924)

2,030 

(1,924)

Totals 142 (135) 3,962 (3,755) 2,030 

(1,924)

6,134 

(5,814)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Includes Condenser, Cooling Tower Blowdown, and the following Non-Condenser 

 Cooling Tower Loads: ASU compressor intercoolers, CO2 compressor intercoolers,

 sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

 air cooler.

** Calculated by difference to close the energy balance.
Carbon Dioxide Capture Sensitivity Analysis

345

Exhibit 4-102 Case 2 D3E (85%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,980 

(5,668) 5.0 (4.7) 0 (0) 5,985 (5,673)

ASU Air 0 (0) 23.8 (22.6) 0 (0) 24 (23)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 81.8 (77.6) 0 (0) 82 (78)

Totals 5,980 

(5,668) 206.8 (196.0) 0 (0) 6,187 (5,864)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.8 (1.8) 0 (0) 2 (2)

Slag 92 (87) 37.7 (35.8) 0 (0) 130 (123)

Sulfur 51 (48) 0.6 (0.6) 0 (0) 52 (49)

CO2 0 (0) -69.2 (-65.6) 0 (0) -69 (-66)

Gasifier Heat Loss 0 (0) 44.5 (42.2) 0 (0) 45 (42)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,295 (1,228) 0 (0) 1,295 

(1,228)

Cooling Tower* 0 (0) 2,183 (2,069) 0 (0) 2,183 

(2,069)

Process Losses** 0 (0) 490 (465) 0 (0) 490 (465)

Net Power 0 (0) 0.0 (0.0) 1,996 

(1,892)

1,996 

(1,892)

Totals 143 (136) 4,047 (3,836) 1,996 

(1,892)

6,187 

(5,864)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Includes Condenser, Cooling Tower Blowdown, and the following Non-Condenser 

 Cooling Tower Loads: ASU compressor intercoolers, CO2 compressor intercoolers,

 sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

 air cooler.

** Calculated by difference to close the energy balance.
Carbon Dioxide Capture Sensitivity Analysis

346

Exhibit 4-103 Case 2 D3A Energy Balance Sankey Diagram

Exhibit 4-104 Case 2 D3B Energy Balance Sankey Diagram
Carbon Dioxide Capture Sensitivity Analysis

347

Exhibit 4-105 Case 2 D3C Energy Balance Sankey Diagram

Exhibit 4-106 Case 2 D3D Energy Balance Sankey Diagram
Carbon Dioxide Capture Sensitivity Analysis

348

Exhibit 4-107 Case 2 D3E Energy Balance Sankey Diagram
Carbon Dioxide Capture Sensitivity Analysis

349

4.3.3.2 Major Equipment List for Case 2 D3

Major equipment items for Case 2 D3 (two WGS with bypass) are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates. 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. 

ACCOUNT 1 COAL HANDLING

Equipment 

No. Description Type

Design Conditions Opr Qty.

D3A D3B D3C D3D D3E (Spares)

1

Bottom Trestle Dumper and 

Receiving Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0)

3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

4 Transfer Tower No. 1 Enclosed N/A N/A N/A N/A N/A 1 (0)

5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

6

As-Received Coal Sampling 

System Two-stage N/A N/A N/A N/A N/A 1 (0)

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

8 Reclaim Hopper N/A 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 2 (1)

9 Feeder Vibratory 172 tonne/hr (190 tph) 172 tonne/hr (190 tph) 181 tonne/hr (200 tph) 181 tonne/hr (200 tph) 181 tonne/hr (200 tph) 2 (1)

10 Conveyor No. 3 Belt w/ tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0)

11 Crusher Tower N/A N/A N/A N/A N/A N/A 1 (0)

12 Coal Surge Bin w/ Vent 

Filter Dual outlet 172 tonne (190 ton) 172 tonne (190 ton) 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

2 (0)

14 As-Fired Coal Sampling 

System Swing hammer N/A N/A N/A N/A N/A 1 (1)

15 Conveyor No. 4 Belt w/tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0)

16 Transfer Tower No. 2 Enclosed N/A N/A N/A N/A N/A 1 (0)

17 Conveyor No. 5 Belt w/ tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0)

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 726 tonne (800 ton) 816 tonne (900 ton) 816 tonne (900 ton) 816 tonne (900 ton) 816 tonne (900 ton) 3 (0)

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type

Design Condition Opr Qty.

D3A D3B D3C D3D D3E (Spares)

1 Feeder Vibratory 73 tonne/h (80 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 3 (0)

2 Conveyor No. 6 Belt w/tripper 227 tonne/h (250 tph) 236 tonne/h (260 tph) 236 tonne/h (260 tph) 236 tonne/h (260 tph) 245 tonne/h (270 tph) 1 (0)

3 Rod Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 472 tonne (520 ton) 472 tonne (520 ton) 481 tonne (530 ton) 481 tonne (530 ton) 1 (0)

4 Weigh Feeder Belt 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)

5 Rod Mill Rotary 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)

6

Slurry Water Storage 

Tank with Agitator Field erected 284,968 liters (75,280 gal) 289,321 liters (76,430 gal)

293,031 liters 

(77,410 gal)

296,665 liters 

(78,370 gal)

299,163 liters 

(79,030 gal)

2 (0)
Carbon Dioxide Capture Sensitivity Analysis

350

Equipment 

No. Description Type

Design Condition Opr Qty.

D3A D3B D3C D3D D3E (Spares)

7 Slurry Water Pumps Centrifugal 795 lpm (210 gpm) 795 lpm (210 gpm) 833 lpm (220 gpm) 833 lpm (220 gpm) 833 lpm (220 gpm) 2 (1)

8 Trommel Screen Coarse 163 tonne/h (180 tph) 163 tonne/h (180 tph) 163 tonne/h (180 tph) 172 tonne/h (190 tph) 172 tonne/h (190 tph) 2 (0)

9

Rod Mill Discharge Tank 

with Agitator Field erected 372,790 liters (98,480 gal) 378,506 liters (99,990 gal)

383,352 liters 

(101,270 gal)

388,121 liters 

(102,530 gal)

391,377 liters 

(103,390 gal)

2 (0)

10 Rod Mill Product Pumps Centrifugal 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 2 (2)

11 Slurry Storage Tank with 

Agitator Field erected 1,118,598 liters (295,500 gal)

1,135,633 liters 

(300,000 gal)

1,150,017 liters 

(303,800 gal)

1,164,402 liters 

(307,600 gal)

1,174,244 liters 

(310,200 gal)

2 (0)

12 Slurry Recycle Pumps Centrifugal 6,057 lpm (1,600 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 2 (2)

13 Slurry Product Pumps Positive 

displacement 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 2 (2)

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment 

No. Description Type

Design Condition Opr Qty.

D3A D3B D3C D3D D3E (Spares)

1

Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor

1,086,413 liters 

(287,000 gal)

1,097,769 liters 

(290,000 gal)

1,090,199 liters 

(288,000 gal)

1,078,842 liters 

(285,000 gal)

1,075,057 liters 

(284,000 gal)

2 (0)

2 Condensate Pumps Vertical canned 7,041 lpm @ 91 m H2O

(1,860 gpm @ 300 ft H2O)

7,306 lpm @ 91 m H2O

(1,930 gpm @ 300 ft H2O)

7,457 lpm @ 91 m H2O

(1,970 gpm @ 300 ft H2O)

7,609 lpm @ 91 m H2O

(2,010 gpm @ 300 ft H2O)

7,684 lpm @ 91 m H2O

(2,030 gpm @ 300 ft H2O)

2 (1)

3

Deaerator (integral w/ 

HRSG) Horizontal spray type 483,983 kg/hr (1,067,000 lb/hr)

499,859 kg/hr 

(1,102,000 lb/hr)

509,384 kg/hr 

(1,123,000 lb/hr)

518,456 kg/hr 

(1,143,000 lb/hr)

524,353 kg/hr 

(1,156,000 lb/hr)

2 (0)

4

Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

8,101 lpm @ 27 m H2O

(2,140 gpm @ 90 ft H2O)

8,176 lpm @ 27 m H2O

(2,160 gpm @ 90 ft H2O)

8,025 lpm @ 27 m H2O

(2,120 gpm @ 90 ft H2O)

7,874 lpm @ 27 m H2O

(2,080 gpm @ 90 ft H2O)

7,760 lpm @ 27 m H2O

(2,050 gpm @ 90 ft H2O)

2 (1)

5

High Pressure Feedwater 

Pump No. 1

Barrel type, multistage, centrifugal

HP water: 6,132 lpm @ 

1,859 m H2O 

(1,620 gpm @ 6,100 ft H2O)

HP water: 6,132 lpm @ 

1,859 m H2O 

(1,620 gpm @ 6,100 ft H2O)

HP water: 6,095 lpm @ 

1,859 m H2O (1,610 gpm 

@ 6,100 ft H2O)

HP water: 6,057 lpm @ 

1,859 m H2O (1,600 gpm @ 

6,100 ft H2O)

HP water: 6,019 lpm @ 

1,859 m H2O (1,590 gpm @ 

6,100 ft H2O)

2 (1)

6

High Pressure Feedwater 

Pump No. 2

Barrel type, multistage, centrifugal

IP water: 1,476 lpm @ 223 

m H2O 

(390 gpm @ 730 ft H2O)

IP water: 1,514 lpm @ 223 

m H2O 

(400 gpm @ 730 ft H2O)

IP water: 1,590 lpm @ 

223 m H2O (420 gpm @ 

730 ft H2O)

IP water: 1,666 lpm @ 223 

m H2O (440 gpm @ 730 ft 

H2O)

IP water: 1,741 lpm @ 223 

m H2O (460 gpm @ 730 ft 

H2O)

2 (1)

7 Auxiliary Boiler Shop fabricated, water 

tube

18,144 kg/hr, 2.8 MPa, 

343°C

(40,000 lb/hr, 400 psig, 

650°F)

18,144 kg/hr, 2.8 MPa, 

343°C

(40,000 lb/hr, 400 psig, 

650°F)

18,144 kg/hr, 2.8 MPa, 

343°C

(40,000 lb/hr, 400 psig, 

650°F)

18,144 kg/hr, 2.8 MPa, 

343°C

(40,000 lb/hr, 400 psig, 

650°F)

18,144 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)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

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) 28 m3/min (1,000 scfm) 28 m3/min (1,000 scfm) 28 m3/min (1,000 scfm) 28 m3/min (1,000 scfm) 2 (1)

10 Closed Cylce Cooling Heat 

Exchangers Plate and frame 247 GJ/hr (234.44802645 MMBtu/hr) each

277 GJ/hr (262.36186405 

MMBtu/hr) each

301 GJ/hr (285.73317245 

MMBtu/hr) each

327 GJ/hr (309.64151075 

MMBtu/hr) each

345 GJ/hr (326.5623988 

MMBtu/hr) each

2 (0)

11 Closed Cycle Cooling Water 

Pumps Horizontal centrifugal 88,579 lpm @ 21 m H2O(23,400 gpm @ 70 ft H2O)

99,178 lpm @ 21 m H2O

(26,200 gpm @ 70 ft H2O)

108,263 lpm @ 21 m H2O

(28,600 gpm @ 70 ft H2O)

117,348 lpm @ 21 m H2O

(31,000 gpm @ 70 ft H2O)

123,783 lpm @ 21 m H2O

(32,700 gpm @ 70 ft H2O)

2 (1)

12 Engine-Driven Fire Pump Vertical turbine, diesel 

engine

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

1 (1)

13 Fire Service Booster Pump Two-stage horizontal 

centrifugal

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

1 (1)

14 Raw Water Pumps Stainless steel, single 

suction

4,580 lpm @ 18 m H2O

(1,210 gpm @ 60 ft H2O)

4,921 lpm @ 18 m H2O

(1,300 gpm @ 60 ft H2O)

5,186 lpm @ 18 m H2O

(1,370 gpm @ 60 ft H2O)

5,451 lpm @ 18 m H2O

(1,440 gpm @ 60 ft H2O)

5,640 lpm @ 18 m H2O

(1,490 gpm @ 60 ft H2O)

2 (1)

15 Ground Water Pumps Stainless steel, single 

suction

3,028 lpm @ 268 m H2O 

(800 gpm @ 880 ft H2O)

3,293 lpm @ 268 m H2O 

(870 gpm @ 880 ft H2O)

2,612 lpm @ 268 m H2O 

(690 gpm @ 880 ft H2O)

2,725 lpm @ 268 m H2O 

(720 gpm @ 880 ft H2O)

2,839 lpm @ 268 m H2O 

(750 gpm @ 880 ft H2O)

3 (1)
Carbon Dioxide Capture Sensitivity Analysis

351

Equipment 

No. Description Type

Design Condition Opr Qty.

D3A D3B D3C D3D D3E (Spares)

16 Filtered Water Pumps Stainless steel, single 

suction

2,082 lpm @ 49 m H2O

(550 gpm @ 160 ft H2O)

2,385 lpm @ 49 m H2O

(630 gpm @ 160 ft H2O)

2,612 lpm @ 49 m H2O

(690 gpm @ 160 ft H2O)

2,877 lpm @ 49 m H2O

(760 gpm @ 160 ft H2O)

3,028 lpm @ 49 m H2O

(800 gpm @ 160 ft H2O)

2 (1)

17 Filtered Water Tank Vertical, cylindrical 995,563 liter (263,000 gal) 1,139,409 liter (301,000 gal) 1,256,757 liter 

(332,000 gal) 1,374,104 liter (363,000 gal) 1,453,598 liter (384,000 gal) 2 (0)

18 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 303 lpm (80 gpm) 568 lpm (150 gpm) 795 lpm (210 gpm) 1,022 lpm (270 gpm) 1,173 lpm (310 gpm) 2 (0)

19 Liquid Waste Treatment 

System 10 years, 24-hour storm 10 years, 24-hour storm 10 years, 24-hour storm 10 years, 24-hour storm 10 years, 24-hour storm 1 (0)

ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment 

No. Description Type

Design Condition Opr Qty.

D3A D3B D3C D3D D3E (Spares)

1 Gasifier Pressurized slurryfeed, entrained bed

2,812 tonne/day, 5.6 MPa

(3,100 tpd, 814.96 psia)

2,812 tonne/day, 5.6 MPa

(3,100 tpd, 814.96 psia)

2,812 tonne/day, 5.6 MPa

(3,100 tpd, 814.96 psia)

2,903 tonne/day, 5.6 MPa

(3,200 tpd, 814.96 psia)

2,903 tonne/day, 5.6 MPa

(3,200 tpd, 814.96 psia)

2 (0)

2 Synthesis Gas Cooler

Vertical downflow 

radiant heat 

exchanger with outlet 

quench chamber

243,126 kg/hr 

(536,000 lb/hr)

246,754 kg/hr 

(544,000 lb/hr)

249,929 kg/hr 

(551,000 lb/hr)

253,105 kg/hr 

(558,000 lb/hr)

255,373 kg/hr 

(563,000 lb/hr)

2 (0)

3 Synthesis Gas Cyclone High efficiency 332,937 kg/hr (734,000 

lb/hr) Design efficiency 90%

337,926 kg/hr (745,000 

lb/hr) Design efficiency 90%

342,462 kg/hr (755,000 

lb/hr) Design efficiency 90%

346,545 kg/hr (764,000 

lb/hr) Design efficiency 90%

349,266 kg/hr (770,000 

lb/hr) Design efficiency 90%

2 (0)

4 Candle Filter Pressurized filter with 

pulse-jet cleaning metallic filters metallic filters metallic filters metallic filters metallic filters 2 (0)

5

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 332,937 kg/hr 

(734,000 lb/hr)

337,926 kg/hr 

(745,000 lb/hr)

342,462 kg/hr 

(755,000 lb/hr)

346,545 kg/hr 

(764,000 lb/hr)

349,266 kg/hr 

(770,000 lb/hr)

2 (0)

6 Raw Gas Coolers Shell and tube with 

condensate drain

287,578 kg/hr 

(634,000 lb/hr)

322,504 kg/hr 

(711,000 lb/hr)

339,741 kg/hr 

(749,000 lb/hr)

356,977 kg/hr 

(787,000 lb/hr)

368,771 kg/hr 

(813,000 lb/hr)

8 (0)

7 Raw Gas Knockout Drum Vertical with mist 

eliminator

213,642 kg/hr, 35°C, 5.2 

MPa

(471,000 lb/hr, 95°F, 750 

psia)

239,950 kg/hr, 35°C, 5.2 

MPa

(529,000 lb/hr, 95°F, 750 

psia)

261,723 kg/hr, 35°C, 5.2 

MPa

(577,000 lb/hr, 95°F, 750 

psia)

283,949 kg/hr, 35°C, 5.2 

MPa

(626,000 lb/hr, 95°F, 750 

psia)

298,917 kg/hr, 35°C, 5.2 

MPa

(659,000 lb/hr, 95°F, 750 

psia)

2 (0)

8 Flare Stack

Self-supporting, 

carbon steel, stainless 

steel top, pilot ignition

332,937 kg/hr (734,000 

lb/hr) syngas

337,926 kg/hr (745,000 

lb/hr) syngas

342,462 kg/hr (755,000 

lb/hr) syngas

346,545 kg/hr (764,000 

lb/hr) syngas

349,266 kg/hr (770,000 

lb/hr) syngas

2 (0)

9

ASU Main Air 

Compressor

Centrifugal, multistage5,635 m

3

/min @ 1.3 MPa

(199,000 scfm @ 190 psia)

5,748 m3/min @ 1.3 MPa

(203,000 scfm @ 190 psia)

5,805 m3/min @ 1.3 MPa

(205,000 scfm @ 190 psia)

5,890 m3/min @ 1.3 MPa

(208,000 scfm @ 190 psia)

5,918 m3/min @ 1.3 MPa

(209,000 scfm @ 190 psia)

2 (0)

10 Cold Box Vendor design 2,268 tonne/day (2,500 tpd) 

of 95% purity oxygen

2,268 tonne/day (2,500 tpd) 

of 95% purity oxygen

2,359 tonne/day (2,600 tpd) 

of 95% purity oxygen

2,359 tonne/day (2,600 tpd) 

of 95% purity oxygen

2,359 tonne/day (2,600 tpd) 

of 95% purity oxygen

2 (0)

11 Oxygen Compressor Centrifugal, multistage

1,133 m3/min (40,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 

psia)

1,161 m3/min (41,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 

psia)

1,161 m3/min (41,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 

psia)

1,189 m3/min (42,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 

psia)

1,189 m3/min (42,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 

psia)

2 (0)

12 Primary Nitrogen 

Compressor

Centrifugal, multistage

3,540 m3/min 

(125,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 

psia)

3,625 m3/min 

(128,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 

psia)

3,653 m3/min 

(129,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 

psia)

3,710 m3/min 

(131,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 

psia)

3,738 m

3

/min 

(132,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 

psia)

2 (0)
Carbon Dioxide Capture Sensitivity Analysis

352

Equipment 

No. Description Type

Design Condition Opr Qty.

D3A D3B D3C D3D D3E (Spares)

13 Secondary Nitrogen 

Compressor

Centrifugal, singlestage

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 

psia)

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 

psia)

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 

psia)

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 

psia)

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 

psia)

2 (0)

14 Syngas Dilution Nitrogen 

Boost Compressor

Centrifugal, singlestage

0 m3/min (0 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 

psia)

28 m3/min (1,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 

psia)

680 m3/min (24,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 

psia)

1,331 m3/min (47,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 

psia)

1,784 m3/min (63,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 

psia)

2 (0)

ACCOUNT 5A SYNGAS CLEANUP

Equipment 

No. Description Type

Design Condition Opr Qty.

D3A D3B D3C D3D D3E (Spares)

1 Mercury Adsorber Sulfated 

carbon bed

212,735 kg/hr (469,000 lb/hr) 

35°C (95°F) 

5.1 MPa (745 psia)

239,497 kg/hr (528,000 lb/hr) 

35°C (95°F) 

5.1 MPa (745 psia)

261,269 kg/hr (576,000 lb/hr) 

35°C (95°F) 

5.1 MPa (745 psia)

283,495 kg/hr (625,000 lb/hr) 

35°C (95°F) 

5.1 MPa (745 psia)

298,464 kg/hr (658,000 lb/hr) 

35°C (95°F) 

5.1 MPa (745 psia)

2 (0)

2 Sulfur Plant Claus type 139 tonne/day (153 tpd) 141 tonne/day (155 tpd) 143 tonne/day (157 tpd) 144 tonne/day (159 tpd) 145 tonne/day (160 tpd) 1 (0)

3

Water Gas Shift 

Reactors

Fixed bed, 

catalytic

907 kg/hr (2,000 lb/hr) 

210°C (410°F) 

5.4 MPa (790 psia)

110,223 kg/hr (243,000 lb/hr) 

221°C (430°F) 

5.4 MPa (790 psia)

200,034 kg/hr (441,000 lb/hr) 

221°C (430°F) 

5.4 MPa (790 psia)

291,206 kg/hr (642,000 lb/hr) 

221°C (430°F) 

5.4 MPa (790 psia)

352,895 kg/hr (778,000 lb/hr) 

221°C (430°F) 

5.4 MPa (790 psia)

4 (0)

4

Shift Reactor Heat 

Recovery Exchangers

Shell and 

Tube

Exchanger 1: 00 GJ/hr 

(00 MMBtu/hr) 

Exchanger 2: 3 GJ/hr 

(3 MMBtu/hr) 

Exchanger 1: 45 GJ/hr 

(42 MMBtu/hr) 

Exchanger 2: 3 GJ/hr 

(3 MMBtu/hr) 

Exchanger 1: 81 GJ/hr 

(77 MMBtu/hr) 

Exchanger 2: 3 GJ/hr 

(3 MMBtu/hr) 

Exchanger 1: 118 GJ/hr 

(112 MMBtu/hr) 

Exchanger 2: 3 GJ/hr 

(3 MMBtu/hr) 

Exchanger 1: 143 GJ/hr 

(135 MMBtu/hr) 

Exchanger 2: 3 GJ/hr 

(3 MMBtu/hr) 

4 (0)

5

COS Hydrolysis 

Reactor

Fixed bed, 

catalytic

300,732 kg/hr (663,000 lb/hr)

210°C (410°F)

5.4 MPa (790 psia)

212,281 kg/hr (468,000 lb/hr)

210°C (410°F)

5.4 MPa (790 psia)

139,253 kg/hr (307,000 lb/hr)

210°C (410°F)

5.4 MPa (790 psia)

65,771 kg/hr (145,000 lb/hr)

210°C (410°F)

5.4 MPa (790 psia)

15,876 kg/hr (35,000 lb/hr)

210°C (410°F)

5.4 MPa (790 psia)

2 (0)

6

Acid Gas Removal 

Plant

Two-stage 

Selexol

214,549 kg/hr (473,000 lb/hr) 

35°C (95°F) 

5.1 MPa (740 psia)

240,858 kg/hr (531,000 lb/hr) 

35°C (95°F) 

5.1 MPa (740 psia)

262,630 kg/hr (579,000 lb/hr) 

35°C (95°F) 

5.1 MPa (740 psia)

284,856 kg/hr (628,000 lb/hr) 

35°C (95°F) 

5.1 MPa (740 psia)

300,278 kg/hr (662,000 lb/hr) 

35°C (95°F) 

5.1 MPa (740 psia)

2 (0)

7

Hydrogenation 

Reactor

Fixed bed, 

catalytic

6,347 kg/hr (13,992 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

6,104 kg/hr (13,457 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

5,915 kg/hr (13,039 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

6,798 kg/hr (14,988 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

7,423 kg/hr (16,364 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

1 (0)

8

Tail Gas Recycle 

Compressor Centrifugal 3,059 kg/hr (6,744 lb/hr) 2,514 kg/hr (5,543 lb/hr) 2,073 kg/hr (4,570 lb/hr) 2,784 kg/hr (6,138 lb/hr) 3,281 kg/hr (7,233 lb/hr) 1 (0)

ACCOUNT 5B CO2 COMPRESSION

Equipment 

No. Description Type

Design Condition Opr Qty.

D (Spares) 3A D3B D3C D3D D3E

1 CO2 Compressor Integrally geared, multistage centrifugal

303 m

3

/min @ 15.3 MPa 

(10,700 scfm @ 2,215 psia)

544 m3/min @ 15.3 MPa 

(19,200 scfm @ 2,215 psia)

736 m3/min @ 15.3 MPa 

(26,000 scfm @ 2,215 psia)

929 m

3

/min @ 15.3 MPa 

(32,800 scfm @ 2,215 psia)

1,062 m3/min @ 15.3 MPa 

(37,500 scfm @ 2,215 psia)

4 (0)
Carbon Dioxide Capture Sensitivity Analysis

353

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment 

No. Description Type

Design Condition Opr Qty.

D3A D3B D3C D3D D3E (Spares)

1 Gas Turbine Advanced F class 230 MW 230 MW 230 MW 230 MW 230 MW 2 (0)

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase

260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase

260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase

260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase

260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase

2 (0)

3

Syngas Expansion 

Turbine/Generator Turbo Expander

144,378 kg/h (318,300 lb/h)

5.0 MPa (720 psia) Inlet

3.2 MPa (460 psia) Outlet

116,800 kg/h (257,500 lb/h)

5.0 MPa (720 psia) Inlet

3.2 MPa (460 psia) Outlet

95,935 kg/h (211,500 lb/h)

5.0 MPa (720 psia) Inlet

3.2 MPa (460 psia) Outlet

74,344 kg/h (163,900 lb/h)

5.0 MPa (720 psia) Inlet

3.2 MPa (460 psia) Outlet

59,693 kg/h (131,600 lb/h)

5.0 MPa (720 psia) Inlet

3.2 MPa (460 psia) Outlet

2 (0)

ACCOUNT 7 HRSG, DUCTING, AND STACK

Equipment 

No. Description Type

Design Condition Opr Qty.

D3A D3B D3C D3D D3E (Spares)

1 Stack CS plate, type 

409SS liner

76 m (250 ft) high x

8.4 m (28 ft) diameter

76 m (250 ft) high x

8.4 m (28 ft) diameter

76 m (250 ft) high x

8.4 m (28 ft) diameter

76 m (250 ft) high x

8.4 m (28 ft) diameter

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 - 346,899 kg/hr, 

12.4 MPa/554°C (764,782 

lb/hr, 1,800 psig/1,029°F)

 Reheat steam - 346,477 

kg/hr, 3.1 MPa/554°C (763,852 

lb/hr, 452 psig/1,029°F)

Main steam - 346,705 kg/hr, 

12.4 MPa/548°C (764,354 

lb/hr, 1,800 psig/1,019°F)

 Reheat steam - 340,285 

kg/hr, 3.1 MPa/548°C (750,200 

lb/hr, 452 psig/1,019°F)

Main steam - 344,019 kg/hr, 

12.4 MPa/544°C (758,433 

lb/hr, 1,800 psig/1,011°F)

 Reheat steam - 342,563 

kg/hr, 3.1 MPa/544°C (755,223 

lb/hr, 452 psig/1,011°F)

Main steam - 341,230 kg/hr, 

12.4 MPa/539°C (752,283 

lb/hr, 1,800 psig/1,002°F)

 Reheat steam - 344,795 

kg/hr, 3.1 MPa/539°C (760,143 

lb/hr, 452 psig/1,002°F)

Main steam - 339,379 kg/hr, 

12.4 MPa/536°C (748,203 

lb/hr, 1,800 psig/997°F)

 Reheat steam - 346,307 

kg/hr, 3.1 MPa/536°C (763,477 

lb/hr, 452 psig/997°F)

2 (0)

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type

Design Condition Opr Qty.

D3A D3B D3C D3D D3E (Spares)

1 Steam Turbine

Commercially 

available advanced 

steam turbine

295 MW 12.4 

MPa/554°C/554°C (1,800 psig/ 

1029°F/1029°F)

291 MW 12.4 

MPa/548°C/548°C (1,800 psig/ 

1019°F/1019°F)

289 MW 12.4 

MPa/544°C/544°C (1,800 psig/ 

1011°F/1011°F)

286 MW 12.4 

MPa/539°C/539°C (1,800 psig/ 

1002°F/1002°F)

284 MW 12.4 

MPa/536°C/536°C (1,800 psig/ 

997°F/997°F)

1 (0)

2

Steam Turbine 

Generator

Hydrogen cooled, 

static excitation

330 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

320 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

320 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

320 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

320 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design 

steam conditions

50% steam flow @ design 

steam conditions

50% steam flow @ design 

steam conditions

50% steam flow @ design 

steam conditions

50% steam flow @ design 

steam conditions

2 (0)

4

Surface 

Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,783 GJ/hr (1,690 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), Water temperature rise 

11°C (20°F)

1,772 GJ/hr (1,680 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), Water temperature rise 

11°C (20°F)

1,751 GJ/hr (1,660 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), Water temperature rise 

11°C (20°F)

1,730 GJ/hr (1,640 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), Water temperature rise 

11°C (20°F)

1,709 GJ/hr (1,620 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), Water temperature rise 

11°C (20°F)

1 (0)
Carbon Dioxide Capture Sensitivity Analysis

354

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type

Design Condition Opr Qty.

D3A D3B D3C D3D D3E (Spares)

1

Circulating 

Water Pumps Vertical, wet pit 416,395 lpm @ 30 m(110,000 gpm @ 100 ft)

431,537 lpm @ 30 m

(114,000 gpm @ 100 ft)

442,893 lpm @ 30 m

(117,000 gpm @ 100 ft)

454,249 lpm @ 30 m

(120,000 gpm @ 100 ft)

461,820 lpm @ 30 m

(122,000 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 / 2,332 GJ/hr (2,210 

MMBtu/hr) heat duty

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) 

HWT / 2,416 GJ/hr (2,290 

MMBtu/hr) heat duty

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) 

HWT / 2,479 GJ/hr (2,350 

MMBtu/hr) heat duty

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) 

HWT / 2,532 GJ/hr (2,400 

MMBtu/hr) heat duty

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) 

HWT / 2,574 GJ/hr (2,440 

MMBtu/hr) heat duty

1 (0)

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type

Design Condition Opr Qty.

D (Spares) 3A D3B D3C D3D D3E

1 Slag Quench Tank Water bath 242,266 liters (64,000 gal) 246,052 liters (65,000 gal) 249,837 liters (66,000 gal) 249,837 liters (66,000 gal) 253,623 liters (67,000 gal) 2 (0)

2 Slag Crusher Roll 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

3 Slag Depressurizer Lock Hopper 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

4 Slag Receiving Tank Horizontal, weir 143,846 liters (38,000 gal) 147,631 liters (39,000 gal) 151,416 liters (40,000 gal) 151,416 liters (40,000 gal) 151,416 liters (40,000 gal) 2 (0)

5

Black Water Overflow 

Tank Shop fabricated 64,352 liters (17,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)

6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

7

Slag Separation 

Screen Vibrating 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

8

Coarse Slag 

Conveyor Belt/bucket 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

9

Fine Ash Settling 

Tank Vertical, gravity 208,198 liters (55,000 gal) 208,198 liters (55,000 gal) 211,983 liters (56,000 gal) 215,768 liters (57,000 gal) 215,768 liters (57,000 gal) 2 (0)

10 Fine Ash Recycle 

Pumps Horizontal centrifugal 38 lpm @ 14 m H2O(10 gpm @ 46 ft H2O)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

2 (2)

11 Grey Water Storage 

Tank Field erected 64,352 liters (17,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H2O

(60 gpm @ 1,850 ft H2O)

227 lpm @ 564 m H2O

(60 gpm @ 1,850 ft H2O)

227 lpm @ 564 m H2O

(60 gpm @ 1,850 ft H2O)

227 lpm @ 564 m H2O

(60 gpm @ 1,850 ft H2O)

227 lpm @ 564 m H2O

(60 gpm @ 1,850 ft H2O)

2 (2)

13 Slag Storage Bin Vertical, field erected 907 tonne (1,000 tons) 907 tonne (1,000 tons) 907 tonne (1,000 tons) 907 tonne (1,000 tons) 998 tonne (1,100 tons) 2 (0)

14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 1 (0)
Carbon Dioxide Capture Sensitivity Analysis

355

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type

Design Condition Opr Qty.

D3A D3B D3C D3D D3E (Spares)

1

CTG Step-up 

Transformer Oil-filled 24 kV/345 kV, 260 MVA, 3-ph, 60 Hz

24 kV/345 kV, 260 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 260 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 260 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 260 MVA, 

3-ph, 60 Hz

2 (0)

2

STG Step-up 

Transformer Oil-filled 24 kV/345 kV, 330 MVA, 3-ph, 60 Hz

24 kV/345 kV, 320 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 320 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 320 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 320 MVA, 

3-ph, 60 Hz

1 (0)

3

High Voltage Auxiliary 

Transformer Oil-filled 345 kV/13.8 kV, 63 MVA, 3-ph, 60 Hz

345 kV/13.8 kV, 68 MVA, 

3-ph, 60 Hz

345 kV/13.8 kV, 72 MVA, 

3-ph, 60 Hz

345 kV/13.8 kV, 76 MVA, 

3-ph, 60 Hz

345 kV/13.8 kV, 79 MVA, 

3-ph, 60 Hz

2 (0)

4

Medium Voltage 

Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 30 MVA, 3-ph, 60 Hz

24 kV/4.16 kV, 34 MVA, 

3-ph, 60 Hz

24 kV/4.16 kV, 38 MVA, 

3-ph, 60 Hz

24 kV/4.16 kV, 42 MVA, 

3-ph, 60 Hz

24 kV/4.16 kV, 45 MVA, 

3-ph, 60 Hz

1 (1)

5

Low Voltage 

Transformer Dry ventilated 4.16 kV/480 V, 4 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 5 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 6 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 6 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 7 MVA, 

3-ph, 60 Hz

1 (1)

6

CTG Isolated Phase 

Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 2 (0)

7

STG Isolated Phase 

Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 1 (0)

8

Medium Voltage 

Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz 1 (1)

9

Low Voltage 

Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz 1 (1)

10 Emergency Diesel 

Generator

Sized for emergency 

shutdown 750 kW, 480 V, 3-ph, 60 Hz 750 kW, 480 V, 3-ph, 60 Hz 750 kW, 480 V, 3-ph, 60 Hz 750 kW, 480 V, 3-ph, 60 Hz 750 kW, 480 V, 3-ph, 60 Hz 1 (0)

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment 

No. Description Type

Design Condition Opr Qty.

D3A D3B D3C D3D D3E (Spares)

1

DCS - Main 

Control

Monitor/keyboard; 

Operator printer 

(laser color); 

Engineering printer 

(laser B&W)

Operator stations/printers and 

engineering stations/printers

Operator stations/printers and 

engineering stations/printers

Operator stations/printers and 

engineering stations/printers

Operator stations/printers and 

engineering stations/printers

Operator stations/printers and 

engineering stations/printers

1 (0)

2

DCS -

Processor

Microprocessor with 

redundant 

input/output

N/A N/A N/A N/A N/A 1 (0)

3

DCS - Data 

Highway Fiber optic Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare 1 (0)
Carbon Dioxide Capture Sensitivity Analysis

356

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Carbon Dioxide Capture Sensitivity Analysis

357

4.3.4 IGCC Design 4 – Two Water Gas Shift Reactors Without Bypass

A process block flow diagram for Case 2 Design 4 (D4) is shown in Exhibit 4-108. D4 

represents an IGCC plant with two WGS reactors and no bypass stream, which maximizes total 

CO2 capture. This IGCC design uses a S:DG molar ratio of 0.3 at the outlet of the second WGS 

reactor. To achieve greater than 90 percent CO2 removal, the two-stage SelexolTM CO2 removal 

efficiency is increased by raising the solvent circulation rate, which increases the size and cost of 

the SelexolTM system. According to UOP, two-stage SelexolTM systems have been designed for 

up to 97 percent CO2 recovery and this level of control was deemed the maximum for this study 

[57]. D4 does not include a COS hydrolysis unit since the entire syngas stream passes through 

two WGS reactors. 

Three levels of total CO2 removal were modeled for Case 2 D4: 90 percent (D4A), 95 percent

(D4B), and 97 percent (D4C). The corresponding stream tables are contained in Exhibit 4-109, 

Exhibit 4-110, and Exhibit 4-111, respectively. 

Overall performance for Case 2 D4 is summarized in Exhibit 4-112 which includes auxiliary 

power requirements. Note that the coal feed rate remains essentially constant at CO2 capture 

levels of 90 percent and higher, but a small decrease (~0.2 percent) is observed. This anomaly 

can be explained by a significant increase in the quantity of nitrogen sent to the CT for dilution 

and temperature control. The excess nitrogen increases the total mass flow to the CT, which 

leads to a CT power output greater than 464 MW. As a result, the Aspen model reduces the coal 

feed rate slightly to maintain a CT gross power output of 464 MW (based on two turbines) since 

an advanced F Class turbine is designed for a gross output of 232 MW. However, as expected, 

the net power output and net plant efficiency decrease as the CO2 capture level increases.

Material and energy balance information, environmental performance and a major equipment list

are summarized in Sections 4.3.4.1 and 4.3.4.2.
Carbon Dioxide Capture Sensitivity Analysis

358

Exhibit 4-108 Case 2 D4 Process Block Flow Diagram, IGCC with Two WGS Reactors

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 TWO- 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

16

18 19

20

17

6 8

2 3 4

21

22 23

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 ADVANCED F CLASS GAS TURBINE

SYNGAS H/P REHEAT

15

CLAUS PLANT OXIDANT STEAM TURBINE 24 464 MWe 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
Carbon Dioxide Capture Sensitivity Analysis

359

Exhibit 4-109 Case 2 D4A Stream Table, 90% CO2 Removal

1 2 3 4 5 6 7 8 9 10 11 12

V-L Mole Fraction

A r 0.0092 0.0165 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0054

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

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

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

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

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

H2O 0.0099 0.1356 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3190 1.0000 0.2325

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

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

N2 0.7732 0.7074 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0044

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

O2 0.2074 0.1350 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

S O2 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

V-L Flowrate (kgmol/hr) 27,374 1,659 98 20,052 5,526 0 5,038 0 23,123 29,287 7,192 36,479

V-L Flowrate (kg/hr) 789,924 45,576 3,158 562,651 177,833 0 90,750 0 465,257 576,023 129,569 705,592

Solids Flowrate (kg/hr) 0 0 0 0 0 220,911 0 24,238 0 0 0 0

Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 240

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

Enthalpy (kJ/kg)A 30.23 35.63 26.67 92.50 26.67 --- 537.77 --- 1,424.65 1,065.78 2,918.18 942.21

Density (kg/m3) 1.2 1.5 11.0 24.4 11.0 --- 872.0 --- 14.0 27.2 25.6 24.8

V-L Molecular Weight 28.857 27.479 32.181 28.060 32.181 --- 18.015 --- 20.121 19.669 18.015 19.343

V-L Flowrate (lbmol/hr) 60,349 3,657 216 44,207 12,183 0 11,106 0 50,977 64,566 15,856 80,422

V-L Flowrate (lb/hr) 1,741,483 100,477 6,963 1,240,434 392,056 0 200,070 0 1,025,716 1,269,913 285,651 1,555,564

Solids Flowrate (lb/hr) 0 0 0 0 0 487,026 0 53,435 0 0 0 0

Temperature (°F) 59 65 90 199 90 59 287 2,400 1,250 403 550 463

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

Enthalpy (Btu/lb)A 13.0 15.3 11.5 39.8 11.5 --- 231.2 --- 612.5 458.2 1,254.6 405.1

Density (lb/ft3) 0.076 0.091 0.687 1.521 0.687 --- 54.440 --- 0.871 1.699 1.597 1.550

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

360

Exhibit 4-109 Case 2 D4A Stream Table, 90% CO2 Removal (continued)

13 14 15 16 17 18 19 20 21 22 23 24

V-L Mole Fraction

A r 0.0071 0.0071 0.0115 0.0115 0.0002 0.0018 0.0000 0.0106 0.0092 0.0091 0.0091 0.0000

CH4 0.0009 0.0009 0.0015 0.0015 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0078 0.0077 0.0124 0.0124 0.0002 0.0022 0.0000 0.0060 0.0000 0.0000 0.0000 0.0000

CO2 0.4019 0.4056 0.0502 0.0502 0.9948 0.5215 0.0000 0.6744 0.0003 0.0083 0.0083 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.5692 0.5648 0.9139 0.9139 0.0048 0.1028 0.0000 0.2474 0.0000 0.0000 0.0000 0.0000

H2O 0.0012 0.0013 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 0.0000

H2S 0.0061 0.0061 0.0000 0.0000 0.0000 0.3477 0.0000 0.0050 0.0000 0.0000 0.0000 0.0000

N2 0.0058 0.0065 0.0105 0.0105 0.0000 0.0008 0.0000 0.0549 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 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1064 0.1064 0.0000

S O2 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

V-L Flowrate (kgmol/hr) 27,979 28,364 17,419 17,419 10,425 497 0 385 110,253 139,656 139,656 34,499

V-L Flowrate (kg/hr) 552,408 564,934 90,173 90,173 456,670 17,684 0 12,527 3,181,557 3,834,382 3,834,382 621,516

Solids Flowrate (kg/hr) 0 0 0 0 0 0 5,524 0 0 0 0 0

Temperature (°C) 35 35 35 198 51 48 180 38 15 562 132 534

Pressure (MPa, abs) 5.14 5.1 4.999 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512

Enthalpy (kJ/kg)A 37.11 36.4 195.466 1,134.797 -162.309 74.861 --- 4.442 30.227 834.702 343.768 3,432.882

Density (kg/m3) 40.7 40.9 9.9 4.1 641.8 2.2 5,275.4 79.1 1.2 0.4 0.9 36.7

V-L Molecular Weight 19.744 20 5.177 5.177 43.805 35.589 --- 32.508 28.857 27.456 27.456 18.015

V-L Flowrate (lbmol/hr) 61,683 62,532 38,403 38,403 22,984 1,095 0 850 243,066 307,890 307,890 76,058

V-L Flowrate (lb/hr) 1,217,850 1,245,467 198,798 198,798 1,006,784 38,986 0 27,617 7,014,133 8,453,366 8,453,366 1,370,208

Solids Flowrate (lb/hr) 0 0 0 0 0 0 12,178 0 0 0 0 0

Temperature (°F) 95 95 95 388 124 119 356 100 59 1,044 270 994

Pressure (psia) 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 16.0 15.6 84.0 487.9 -69.8 32.2 --- 1.9 13.0 358.9 147.8 1,475.9

Density (lb/ft3) 2.544 3 0.618 0.259 40.069 0.137 329.335 4.938 0.076 0.026 0.053 2.293

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

361

Exhibit 4-110 Case 2 D4B Stream Table, 95% CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12

V-L Mole Fraction

A r 0.0092 0.0264 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0054

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

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2818 0.0000 0.0060

CO2 0.0003 0.0092 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1087 0.0000 0.3082

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

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2684 0.0000 0.4366

H2O 0.0099 0.2316 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3203 1.0000 0.2325

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

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

N2 0.7732 0.5064 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0044

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

O2 0.2074 0.2264 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

S O2 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

V-L Flowrate (kgmol/hr) 27,345 969 102 20,718 5,516 0 5,029 0 23,082 29,288 7,127 36,415

V-L Flowrate (kg/hr) 789,090 26,226 3,280 581,359 177,521 0 90,591 0 464,438 575,969 128,386 704,355

Solids Flowrate (kg/hr) 0 0 0 0 0 220,522 0 24,195 0 0 0 0

Temperature (°C) 15 21 32 93 32 15 142 1,316 677 206 288 240

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

Enthalpy (kJ/kg)A 30.23 37.59 26.67 92.51 26.67 --- 537.77 --- 1,424.65 1,069.11 2,918.18 942.19

Density (kg/m3) 1.2 1.6 11.0 24.4 11.0 --- 872.0 --- 14.0 27.2 25.6 24.8

V-L Molecular Weight 28.857 27.062 32.181 28.060 32.181 --- 18.015 --- 20.121 19.666 18.015 19.343

V-L Flowrate (lbmol/hr) 60,285 2,137 225 45,676 12,161 0 11,086 0 50,888 64,569 15,711 80,281

V-L Flowrate (lb/hr) 1,739,646 57,819 7,231 1,281,677 391,366 0 199,718 0 1,023,911 1,269,794 283,043 1,552,837

Solids Flowrate (lb/hr) 0 0 0 0 0 486,169 0 53,341 0 0 0 0

Temperature (°F) 59 70 90 199 90 59 287 2,400 1,250 403 550 463

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

Enthalpy (Btu/lb)A 13.0 16.2 11.5 39.8 11.5 --- 231.2 --- 612.5 459.6 1,254.6 405.1

Density (lb/ft3) 0.076 0.100 0.687 1.521 0.687 --- 54.440 --- 0.871 1.698 1.597 1.550

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

362

Exhibit 4-110 Case 2 D4B Stream Table, 95% CO2 Capture (continued)

13 14 15 16 17 18 19 20 21 22 23 24

V-L Mole Fraction

A r 0.0071 0.0070 0.0119 0.0119 0.0002 0.0008 0.0000 0.0043 0.0092 0.0091 0.0091 0.0000

CH4 0.0009 0.0009 0.0015 0.0015 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0078 0.0077 0.0131 0.0131 0.0002 0.0010 0.0000 0.0065 0.0000 0.0000 0.0000 0.0000

CO2 0.4019 0.4180 0.0194 0.0194 0.9950 0.7832 0.0000 0.8771 0.0003 0.0043 0.0043 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.5692 0.5527 0.9432 0.9432 0.0045 0.0462 0.0000 0.0851 0.0000 0.0000 0.0000 0.0000

H2O 0.0012 0.0013 0.0001 0.0001 0.0000 0.0105 0.0000 0.0019 0.0099 0.1218 0.1218 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

H2S 0.0061 0.0060 0.0000 0.0000 0.0000 0.1576 0.0000 0.0035 0.0000 0.0000 0.0000 0.0000

N2 0.0058 0.0063 0.0108 0.0108 0.0000 0.0003 0.0000 0.0216 0.7732 0.7583 0.7583 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

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1065 0.1065 0.0000

S O2 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

V-L Flowrate (kgmol/hr) 27,930 28,911 16,835 16,835 10,949 1,104 0 982 110,253 139,757 139,757 34,339

V-L Flowrate (kg/hr) 551,437 590,590 66,062 66,062 479,736 44,371 0 39,153 3,181,557 3,828,979 3,828,979 618,619

Solids Flowrate (kg/hr) 0 0 0 0 0 0 5,514 0 0 0 0 0

Temperature (°C) 35 34 34 197 51 48 178 38 15 561 132 533

Pressure (MPa, abs) 5.14 5.1 4.999 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512

Enthalpy (kJ/kg)A 37.11 33.6 256.725 1,476.079 -162.700 53.966 --- -15.243 30.227 832.909 343.672 3,429.212

Density (kg/m3) 40.7 42.1 7.5 3.1 643.2 2.5 5,279.2 110.1 1.2 0.4 0.9 36.8

V-L Molecular Weight 19.744 20 3.924 3.924 43.815 40.204 --- 39.887 28.857 27.397 27.397 18.015

V-L Flowrate (lbmol/hr) 61,574 63,738 37,115 37,115 24,139 2,433 0 2,164 243,066 308,111 308,111 75,704

V-L Flowrate (lb/hr) 1,215,711 1,302,028 145,641 145,641 1,057,638 97,821 0 86,317 7,014,133 8,441,453 8,441,453 1,363,822

Solids Flowrate (lb/hr) 0 0 0 0 0 0 12,156 0 0 0 0 0

Temperature (°F) 95 94 94 387 124 119 353 100 59 1,041 270 991

Pressure (psia) 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 16.0 14.5 110.4 634.6 -69.9 23.2 --- -6.6 13.0 358.1 147.8 1,474.3

Density (lb/ft3) 2.544 3 0.468 0.197 40.153 0.154 329.568 6.873 0.076 0.026 0.053 2.299

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

363

Exhibit 4-111 Case 2 D4C Stream Table, 97% CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12

V-L Mole Fraction

A r 0.0092 0.0274 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0054

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

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2818 0.0000 0.0060

CO2 0.0003 0.0096 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1087 0.0000 0.3082

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

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2684 0.0000 0.4366

H2O 0.0099 0.2415 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3201 1.0000 0.2325

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

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

N2 0.7732 0.4856 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0044

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

O2 0.2074 0.2358 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

S O2 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

V-L Flowrate (kgmol/hr) 27,337 929 104 20,752 5,513 0 5,025 0 23,067 29,264 7,127 36,391

V-L Flowrate (kg/hr) 788,869 25,102 3,344 582,313 177,406 0 90,532 0 464,140 575,510 128,391 703,901

Solids Flowrate (kg/hr) 0 0 0 0 0 220,380 0 24,179 0 0 0 0

Temperature (°C) 15 21 32 93 32 15 142 1,316 677 206 288 240

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

Enthalpy (kJ/kg)A 30.23 37.80 26.67 92.51 26.67 --- 537.77 --- 1,424.65 1,068.81 2,918.18 942.20

Density (kg/m3) 1.2 1.6 11.0 24.4 11.0 --- 872.0 --- 14.0 27.2 25.6 24.8

V-L Molecular Weight 28.857 27.019 32.181 28.060 32.181 --- 18.015 --- 20.121 19.666 18.015 19.343

V-L Flowrate (lbmol/hr) 60,268 2,048 229 45,751 12,154 0 11,079 0 50,855 64,517 15,712 80,229

V-L Flowrate (lb/hr) 1,739,159 55,341 7,372 1,283,780 391,114 0 199,590 0 1,023,253 1,268,783 283,054 1,551,837

Solids Flowrate (lb/hr) 0 0 0 0 0 485,856 0 53,307 0 0 0 0

Temperature (°F) 59 70 90 199 90 59 287 2,400 1,250 403 550 463

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

Enthalpy (Btu/lb)A 13.0 16.2 11.5 39.8 11.5 --- 231.2 --- 612.5 459.5 1,254.6 405.1

Density (lb/ft3) 0.076 0.101 0.687 1.521 0.687 --- 54.440 --- 0.871 1.699 1.597 1.550

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

364

Exhibit 4-111 Case 2 D4C Stream Table, 97% CO2 Capture (continued)

13 14 15 16 17 18 19 20 21 22 23 24

V-L Mole Fraction

A r 0.0071 0.0069 0.0120 0.0120 0.0002 0.0007 0.0000 0.0035 0.0092 0.0091 0.0091 0.0000

CH4 0.0009 0.0009 0.0015 0.0015 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0078 0.0077 0.0133 0.0133 0.0002 0.0008 0.0000 0.0062 0.0000 0.0000 0.0000 0.0000

CO2 0.4019 0.4231 0.0059 0.0059 0.9951 0.8233 0.0000 0.9044 0.0003 0.0027 0.0027 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.5692 0.5478 0.9561 0.9561 0.0044 0.0376 0.0000 0.0638 0.0000 0.0000 0.0000 0.0000

H2O 0.0012 0.0013 0.0001 0.0001 0.0000 0.0087 0.0000 0.0019 0.0099 0.1217 0.1217 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

H2S 0.0061 0.0060 0.0000 0.0000 0.0000 0.1285 0.0000 0.0030 0.0000 0.0000 0.0000 0.0000

N2 0.0058 0.0063 0.0110 0.0110 0.0000 0.0003 0.0000 0.0173 0.7732 0.7600 0.7600 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

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1065 0.1065 0.0000

S O2 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

V-L Flowrate (kgmol/hr) 27,912 29,141 16,593 16,593 11,168 1,356 0 1,229 110,253 139,792 139,792 34,282

V-L Flowrate (kg/hr) 551,082 601,304 56,035 56,035 489,389 55,454 0 50,222 3,181,557 3,826,524 3,826,524 617,598

Solids Flowrate (kg/hr) 0 0 0 0 0 0 5,510 0 0 0 0 0

Temperature (°C) 35 34 34 197 51 48 178 38 15 560 132 532

Pressure (MPa, abs) 5.14 5.1 4.999 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512

Enthalpy (kJ/kg)A 37.11 32.5 297.541 1,704.475 -162.852 51.196 --- -18.172 30.227 832.246 343.704 3,427.800

Density (kg/m3) 40.7 42.7 6.5 2.7 643.7 2.5 5,280.0 115.5 1.2 0.4 0.9 36.9

V-L Molecular Weight 19.744 21 3.377 3.377 43.819 40.909 --- 40.864 28.857 27.373 27.373 18.015

V-L Flowrate (lbmol/hr) 61,535 64,244 36,581 36,581 24,622 2,988 0 2,710 243,066 308,188 308,188 75,579

V-L Flowrate (lb/hr) 1,214,928 1,325,649 123,536 123,536 1,078,918 122,254 0 110,721 7,014,133 8,436,041 8,436,041 1,361,570

Solids Flowrate (lb/hr) 0 0 0 0 0 0 12,148 0 0 0 0 0

Temperature (°F) 95 93 93 386 124 119 352 100 59 1,040 270 990

Pressure (psia) 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 16.0 14.0 127.9 732.8 -70.0 22.0 --- -7.8 13.0 357.8 147.8 1,473.7

Density (lb/ft3) 2.544 3 0.403 0.169 40.186 0.157 329.622 7.208 0.076 0.026 0.053 2.301

A - Reference conditions are 32.02 F & 0.089 PSIA
Carbon Dioxide Capture Sensitivity Analysis

365

Exhibit 4-112 Case 2 D4 Performance Modeling Results 

POWER SUMMARY (Gross Power at 

Generator Terminals, kWe)

D4A 

(90%)

D4B 

(95%)

D4C 

(97%)

Gas Turbine Power 464,000 464,000 464,000

Sweet Gas Expander Power 6,300 6,000 6,000

Steam Turbine Power 263,700 256,600 253,600

Total 734,000 726,600 723,600

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 469 468 468

Coal Milling 2,272 2,268 2,267

Sour Water Recycle Slurry Pump 190 190 189

Slag Handling 1,164 1,161 1,161

Air Separation Unit Auxiliaries 1,000 1,000 1,000

Air Separation Unit Main Air Compressor 67,362 67,291 67,272

Oxygen Compressor 10,642 10,624 10,617

Nitrogen Compressors 35,645 36,975 37,084

CO2 Compressor 31,161 32,723 33,376

Boiler Feedwater Pumps 4,178 4,167 4,163

Condensate Pump 279 266 261

Quench Water Pump 538 537 536

Circulating Water Pump 4,621 4,551 4,521

Ground Water Pumps 527 519 517

Cooling Tower Fans 2,390 2,352 2,337

Scrubber Pumps 226 221 221

Acid Gas Removal 19,230 21,273 22,125

Gas Turbine Auxiliaries 1,000 1,000 1,000

Steam Turbine Auxiliaries 100 100 100

Claus Plant/TGTU Auxiliaries 250 250 250

Claus Plant TG Recycle Compressor 1,760 4,400 5,493

Miscellaneous Balance of Plant 1

3,000 3,000 3,000

Transformer Losses 2,752 2,754 2,751

TOTAL AUXILIARIES, kWe 190,756 198,090 200,709

NET POWER, kWe 543,244 528,510 522,891

Net Plant Efficiency, % (HHV) 32.6% 31.8% 31.5%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,035 (10,459) 11,322 (10,731) 11,437 (10,840)

Condenser Duty, GJ/hr (106Btu/hr) 1,519 (1,440) 1,435 (1,360) 1,403 (1,330)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 220,911 (487,026) 220,522 (486,169) 220,380 (485,856)

Thermal Input, kWth 

2

1,665,125 1,662,195 1,661,125

Raw Water Withdrawal, m3/min (gpm) 22.0 (5,817) 21.7 (5,739) 21.6 (5,707)

Raw Water Consumption, m3/min (gpm) 17.9 (4,741) 17.7 (4,679) 17.6 (4,654)

Notes: 1. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

2. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 
Carbon Dioxide Capture Sensitivity Analysis

366

4.3.4.1 Environmental Performance for Case 2 D4

The environmental targets for emissions of Hg, NOx, SO2, and particulate matter were presented 

in Section 2.4. A summary of the plant air emissions for Case 2 D4A, D4B, and D4C is 

presented in Exhibit 4-113.

For Case 2 D4, SO2 emissions are controlled by sulfur capture across the two-stage SelexolTM 

unit. The clean syngas exiting the AGR unit has a sulfur concentration of about 10 ppmv, 

resulting in a concentration in the flue gas of less than 2 ppmv. The H2S-rich regeneration gas 

produced in Case 2 D4 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 SelexolTM 

unit, 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 incinerated in the Claus plant burner. This also assists in lowering 

NOx levels. 

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.

Ninety-five percent of the mercury is captured from the syngas by an activated carbon bed. 

For Case 2 D4, varying levels of the CO2 [90 percent (D4A), 95 percent (D4B), and 97 percent

(D4C)] in the syngas are captured in the two-stage SelexolTM unit and compressed for 

sequestration. The carbon balance for Case 2 D4 is shown in Exhibit 4-114. The carbon input to 

the plant consists of carbon in the air and 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, as dissolved CO2 in the wastewater blowdown stream, and as CO2 in the stack 

gas, ASU vent gas, and the captured CO2 product. Carbon in the wastewater blowdown stream 

is calculated by difference to close the material balance. The carbon capture efficiency is 

defined as the pounds of carbon in the CO2 product stream relative to the amount of carbon in the 

coal, less carbon contained in the slag, represented by the following fraction:

(Carbon in CO2 Product)/[(Carbon in the Coal)-(Carbon in Slag)] or

274,684/(310,453-6,209)*100=90.3% (D4A)

288,563/(309,907-6,198)*100=95.0% (D4B)

294,371/(309,708-6,194)*100=97.0% (D4C)

Exhibit 4-115 shows the sulfur balance for Case 2 D2. Sulfur input comes solely from the sulfur 

in the coal. Sulfur output includes the pounds of sulfur recovered in the Claus plant, dissolved 

SO2 in the wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is 

considered to be negligible, and the sulfur content of the blowdown stream is calculated by 

difference to close the material balance. The total sulfur capture is represented by the following 

fraction:
Carbon Dioxide Capture Sensitivity Analysis

367

(Sulfur byproduct/Sulfur in the coal) or

(12,178/12,207)*100 = 99.8% (D4A)

(12,156/12,185)*100 = 99.8% (D4B)

(12,148/12,178)*100 = 99.8% (D4C) 

The overall water balances for Case 2 D4A, D4B, and D4C are shown in Exhibit 4-116, 

Exhibit 4-117, and Exhibit 4-118, respectively. Raw water is obtained from groundwater (50 

percent) and from municipal sources (50 percent). Water demand represents the total amount of 

water required for a particular process. Some water is recovered within the process and that 

water is reused as internal recycle. Raw water withdrawal is the difference between water 

demand and internal recycle. Process water discharged from the power plant is also accounted

for in this study. Raw water consumption represents raw water withdrawal less process water 

discharge.

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 4-119

through Exhibit 4-127.

Gasifier and ASU

Syngas Cleanup

Power Block

An overall plant energy balance for Case D4A, D4B, and D4C is provided in tabular form in 

Exhibit 4-128, Exhibit 4-129, and Exhibit 4-130, respectively. The power out is the combined 

combustion turbine, steam turbine and expander power after generator losses. In addition, 

energy balance Sankey diagrams are provided for D4A, D4B, and D4C in Exhibit 4-131, Exhibit 

4-132, and Exhibit 4-133, respectively.
Carbon Dioxide Capture Sensitivity Analysis

368

Exhibit 4-113 Case 2 D4 Estimated Air Emission Rates

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

85% capacity factor

kg/MWhnet

(lb/MWhnet)

D4A D4B D4C D4A D4B D4C D4A D4B D4C

SO2 0.001 (0.002) 0.001 (0.002) 0.001 (0.002) 39 (43) 39 (43) 39 (43) 0.008 (0.020) 0.008 (0.020) 0.008 (0.020)

NOX 0.021 (0.049) 0.021 (0.049) 0.021 (0.049) 878 (967) 878 (968) 878 (968) 0.171 (0.376) 0.172 (0.380) 0.173 (0.382)

PM 0.003 (0.0071) 0.003 (0.0071) 0.003 (0.0071) 128 (141) 128 (141) 128 (141) 0.025 (0.055) 0.025 (0.055) 0.025 (0.056)

Hg 0.246x10-6

(0.571x10-6)

0.246x10-6

(0.571x10-6)

0.246x10-6

(0.571x10-6)

0.010 (0.011) 0.010 (0.011) 0.010 (0.011) 2.01x10-6

(4.42x10-6)

2.02x10-6

(4.46x10-6)

2.03x10-6

(4.48x10-6)

CO2 8.5 (19.7) 4.5 (10.4) 2.8 (6.5) 355,405

(391,767)

187,497

(206,680)

117,588

(129,619)

69 (152) 37 (81) 23 (51)

CO2 net 93 (206) 51 (112) 32 (71)
Carbon Dioxide Capture Sensitivity Analysis

369

Exhibit 4-114 Case 2 D4 Carbon Balance

Carbon In, kg/hr (lb/hr)

D4A D4B D4C

Coal 140,819

(310,453)

140,571

(309,907)

140,481 

(309,708)

Air (CO2) 540 (1,191) 540 (1,190) 540 (1,190)

Total 141,359

(311,644)

141,111

(311,097)

141,021

(310,898)

Carbon Out, kg/hr (lb/hr)

Slag 2,816 (6,209)

2,811

(6,198)

2,810 

(6,194)

Stack Gas 13,841

(30,514)

7,302

(16,098)

4,579

(10,096)

ASU Vent 107 (237) 107 (237) 107 (237)

CO2 Product 124,595

(274,684)

130,890

(288,563)

133,525

(294,371)

Convergence 

Tolerance 0 (0) 1 (1) 0 (0)

Total 141,359 

(311,644)

141,111 

(311,097)

141,021 

(310,898)

Exhibit 4-115 Case 2 D4 Sulfur Balance

Sulfur In, kg/hr (lb/hr)

D4A D4B D4C

Coal 5,537

(12,207)

5,527

(12,185)

5,524

(12,178)

Total 5,537

(12,207)

5,527

(12,185)

5,524

(12,178)

Sulfur Out, kg/hr (lb/hr)

Elemental Sulfur 5,524

(12,178)

5,514

(12,156)

5,510

(12,148)

Stack Gas 3 (6) 3 (6) 3 (6)

CO2 Product 10 (23) 11 (23) 11 (24)

Convergence 

Tolerance 0 (0) -1 (0) 0 (0)

Total 5,537

(12,207)

5,527

(12,185)

5,524

(12,178)
Carbon Dioxide Capture Sensitivity Analysis

370

Exhibit 4-116 Case 2 D4A (90%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Slag Handling 0.53 (139) 0.53 (139) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.9 (757) 0.72 (191) 2.1 (566) 0.0 (0) 2.1 (566)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7) -0.03 (-7)

Condenser Makeup 2.4 (627) 0.0 (0) 2.4 (627) 0.0 (0) 2.4 (627)

 Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

 Shift Steam 2.2 (571) 0.0 (0) 2.2 (571)

 CT Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

 BFW Makeup 0.21 (56) 0.0 (0) 0.21 (56)

Cooling Tower 18.0 (4,753) 0.49 (129) 17.5 (4,625) 4.0 (1,069) 13.5 (3,556)

 BFW Blowdown 0.0 (0) 0.21 (56) -0.21 (-56)

 SWS Blowdown 0.0 (0) 0.28 (73) -0.28 (-73)

 SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

 Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 25.3 (6,676) 3.25 (858) 22.0 (5,817) 4.1 (1,076) 17.9 (4,741)

Total, gal/MWhnet 737 95 643 119 524
Carbon Dioxide Capture Sensitivity Analysis

371

Exhibit 4-117 Case 2 D4B (95%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Slag Handling 0.52 (139) 0.52 (139) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.9 (755) 0.71 (189) 2.1 (567) 0.0 (0) 2.1 (567)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7) -0.03 (-7)

Condenser Makeup 2.4 (622) 0.0 (0) 2.4 (622) 0.0 (0) 2.4 (622)

 Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

 Shift Steam 2.1 (566) 0.0 (0) 2.1 (566)

 CT Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

 BFW Makeup 0.21 (56) 0.0 (0) 0.21 (56)

Cooling Tower 17.7 (4,679) 0.49 (128) 17.2 (4,551) 4.0 (1,052) 13.2 (3,498)

 BFW Blowdown 0.0 (0) 0.21 (56) -0.21 (-56)

 SWS Blowdown 0.0 (0) 0.28 (73) -0.28 (-73)

 SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

 Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 25.0 (6,594) 3.24 (855) 21.7 (5,739) 4.0 (1,060) 17.7 (4,679)

Total, gal/MWhnet 749 97 652 120 531
Carbon Dioxide Capture Sensitivity Analysis

372

Exhibit 4-118 Case 2 D4C (97%) Water Balance

Water Use Water Demand, 

m

3

/min (gpm)

Internal Recycle, 

m

3

/min (gpm)

Raw Water Withdrawal, 

m

3

/min (gpm)

Process Water Discharge, 

m

3

/min (gpm)

Raw Water Consumption, 

m

3

/min (gpm)

Slag Handling 0.52 (138) 0.52 (138) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.9 (755) 0.72 (189) 2.1 (566) 0.0 (0) 2.1 (566)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7) -0.03 (-7)

Condenser Makeup 2.4 (622) 0.0 (0) 2.4 (622) 0.0 (0) 2.4 (622)

 Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

 Shift Steam 2.1 (566) 0.0 (0) 2.1 (566)

 CT Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

 BFW Makeup 0.21 (56) 0.0 (0) 0.21 (56)

Cooling Tower 17.6 (4,648) 0.49 (128) 17.1 (4,519) 4.0 (1,045) 13.2 (3,474)

 BFW Blowdown 0.0 (0) 0.21 (56) -0.21 (-56)

 SWS Blowdown 0.0 (0) 0.28 (73) -0.28 (-73)

 SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

 Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 24.8 (6,562) 3.24 (855) 21.6 (5,707) 4.0 (1,052) 17.6 (4,654)

Total, gal/MWhnet 753 98 655 121 534
Carbon Dioxide Capture Sensitivity Analysis

373

Exhibit 4-119 Case 2 D4A (90%) Heat and Mass Balance, GEE Gasifier and ASU

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D4A HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D4A (90%) GEE GASIFIER ASU AND GASIFICATION DWG. NO. CCSA-HMB-CS-2-D4A-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 1 OF 3

Ambient Air Four Stage Air Compressor

Elevated Pressure ASU Four Stage N2 Compressor

Four Stage O2 Compressor

ASU Vent

Water

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/KWe

N2 to GT Combustor 1,741,483 W 59.0 T 14.7 P 13.0 H

392,056 W 90.0 T 125.0 P 11.5 H

392,056 W 241.2 T 940.0 P 40.8 H

To Claus Plant 6,963 W 90.0 T 125.0 P 11.5 H

100,477 W 64.8 T 16.4 P 15.3 H

1,083,585 W 90.0 T 56.4 P 14.2 H

156,849 W 50.0 T 182.0 P 2.9 H 5

1

3

2

Slurry Mix Tank

Milled Coal

Slag

487,026 W 59.0 T 14.7 P

200,070 W 287.0 T 840.0 P 231.2 H

53,435 W 2,400.0 T 815.0 P

676,733 W 385.0 T 384.0 P 87.2 H

687,096 W 156.4 T 840.0 P 2,950.2 H

100.0 T 189.5 P 18.0 H

6

676,733 W 199.0 T 384.0 P 39.8 H

HP BFW

N2 to GT Combustor N2 Boost Compressor 563,700 W 199.0 T 384.0 P 39.8 H 563,700 W 385.0 T 469.0 P 87.0 H

Saturated Steam To HRSG HP Superheater

GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank

Knockout Drum

Vent To Claus Unit

Raw Fuel Gas

CWS

CWR

Fines

Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench Section Drag Conveyor

1,025,716 W 1,250.0 T 805.0 P 612.5 H 1,269,913 W 403.1 T 800.0 P 458.2 H

Syngas Quench

1,404,029 W 450.0 T 805.0 P 536.1 H

8

9

10 Sour Water

7

4

1,240,434 W 199.0 T 384.0 P 39.8 H
Carbon Dioxide Capture Sensitivity Analysis

374

Exhibit 4-120 Case 2 D4A (90%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum

Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water

Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out

From ASU Syngas Coolers

Sour Stripper 1,269,913 W 403.1 T 800.0 P 458.2 H

1,245,467 W 94.6 T 740.0 P 15.6 H 38,986 W 119.0 T 23.7 P

198,798 W 387.6 T 460.0 P 487.9 H

12,178 W 36,265 W 450.0 T 12.3 P 463.8 H

2,495 W 239.1 T 65.0 P 442.0 H

6,963 W 90.0 T 125.0 P 11.5 H NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D4A HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D4A (90%) GEE GASIFIER GAS CLEANUP SYSTEM DWG. NO. CCSA-HMB-CS-2-D4A-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 2 OF 3

Sour Gas Sour Water

Water

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/KWe

19

13 20

CO2

Tailgas

Tail Gas Cleanup Unit

Tail Gas Compressor

30,039 W 120.0 T 10.6 P 111.0 H

1,217,850 W 94.9 T 745.0 P 16.0 H

8,649 W 114.4 T 10.6 P 40.2 H

3 27,617 W 100.0 T 799.5 P

Raw Syngas

15 198,798 W 94.6 T 725.0 P 84.0 H

Claus Oxygen Preheater

6,963 W 450.0 T 124.5 P 91.9 H

18

Fuel Gas Expander Fuel Gas To GT 16 198,798 W 465.0 T 720.0 P 597.0 H

High Temperature Shift #1 Low Temperature Shift #2 Shift Steam

12 11

COS Hydrolysis Preheater

1,269,913 W 413.1 T 795.0 P 450.3 H

285,651 W 550.0 T 800.0 P 1,254.1 H

1,555,564 W 436.4 T 795.0 P 598.0 H 776.2 T 795.0 P 582.1 H 400.0 T 795.0 P 408.0 H 1,555,564 W 463.4 T 785.0 P 405.1 H

1,555,564 W 455.6 T 780.0 P 401.5 H

Two-Stage Selexol

Clean Gas

CO2

Acid Gas

Multistage Intercooled CO2 Compressor Interstage Knockout

CO2 Product 17 10

14

1,006,784 W 123.8 T 2,214.7 P
Carbon Dioxide Capture Sensitivity Analysis

375

Exhibit 4-121 Case 2 D4A (90%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine

Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator

Ip Extraction Steam To 250 PSIA Header

LP Process Header

Blowdown Flash To WWT

Gland Steam Condenser Condensate to Gasification Island

HP BFW to Radiant Syngas Cooler HP Saturated Steam to HRSG Superheater

LP Turbine

Stack

Compressor Expander

Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class Gas Turbine

MP Flash Bottoms LP Flash Tops

7,014,133 W 59.0 T 14.7 P 13.0 H 1,877,010 W 101.1 T 1.0 P 69.1 H

8,453,366 W 269.9 T 15.2 P 147.8 H

198,798 W 387.6 T 460.0 P 487.9 H

8,453,366 W 1,043.8 T 15.2 P 358.9 H From Gasifier Island Preheating

To Claus

LP BFW 1,370,208 W 993.8 T 1,814.7 P 1,475.9 H

10,303 W 298.0 T 65.0 P 1,179.0 H 1,399,027 W 278.8 T 2,250.7 P 252.3 H 28,835 W 585.0 T 2,000.7 P 593.3 H

1,551,382 W 474.9 T 65.0 P 1,269.6 H

1,877,010 W 102.9 T 120.0 P 71.1 H

1,877,010 W 235.0 T 105.0 P 203.7 H

1,400 W 614.9 T 65.0 P 1,338.7 H 1,400 W 212.0 T 14.7 P 179.9 H

IP Pump NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D4A HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D4A (90%) GEE GASIFIER POWER BLOCK SYSTEM DWG. NO. CCSA-HMB-CS-2-D4A-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 3 OF 3

Sour Gas Sour Water

Water

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/KWe 21

22

24 16

23

Flue Gas

HOT WELL CONDENSER Make-up 313,467 W 59.0 T 14.7 P 27.1 H

9,026 W 660.5 T 501.4 P 1,334.5 H 9,761 W 614.9 T 65.0 P 1,338.7 H 32,521 W 852.1 T 280.0 P 1,448.8 H 798 W 993.8 T 1,814.7 P 1,475.9 H 1,337 W 505.0 T 65.0 P 1,284.5 H
Carbon Dioxide Capture Sensitivity Analysis

376

Exhibit 4-122 Case 2 D4B (95%) Heat and Mass Balance, GEE Gasifier and ASU

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D4B HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D4B (95%) GEE GASIFIER ASU AND GASIFICATION DWG. NO. CCSA-HMB-CS-2-D4B-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 1 OF 3

Ambient Air Four Stage Air Compressor

Elevated Pressure ASU Four Stage N2 Compressor

Four Stage O2 Compressor

ASU Vent

Water

Steam

Gross Plant Power: 727 MWe Auxiliary Load: 198 MWe Net Plant Power: 529 MWe Net Plant Efficiency, HHV: 31.8% Net Plant Heat Rate: 10,731 BTU/KWe

N2 to GT Combustor 1,739,646 W 59.0 T 14.7 P 13.0 H

391,366 W 90.0 T 125.0 P 11.5 H

391,366 W 241.2 T 940.0 P 40.8 H

To Claus Plant 7,231 W 90.0 T 125.0 P 11.5 H

57,819 W 69.5 T 16.4 P 16.2 H

1,124,993 W 90.0 T 56.4 P 14.2 H

156,684 W 50.0 T 182.0 P 2.9 H 5

1

3

2

Slurry Mix Tank

Milled Coal

Slag

486,169 W 59.0 T 14.7 P

199,718 W 287.0 T 840.0 P 231.2 H

53,341 W 2,400.0 T 815.0 P

685,905 W 385.0 T 384.0 P 87.2 H

685,887 W 156.4 T 840.0 P 2,950.2 H

100.0 T 189.5 P 18.0 H

6

685,905 W 199.0 T 384.0 P 39.8 H

HP BFW

N2 to GT Combustor N2 Boost Compressor 595,772 W 199.0 T 384.0 P 39.8 H 595,772 W 385.0 T 469.0 P 87.0 H

Saturated Steam To HRSG HP Superheater

GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank

Knockout Drum

Vent To Claus Unit

Raw Fuel Gas

CWS

CWR

Fines

Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench Section Drag Conveyor

1,023,911 W 1,250.0 T 805.0 P 612.5 H 1,269,794 W 403.4 T 800.0 P 459.6 H

Syngas Quench

1,401,558 W 450.0 T 805.0 P 536.1 H

8

9

10 Sour Water

7

4

1,281,677 W 199.0 T 384.0 P 39.8 H
Carbon Dioxide Capture Sensitivity Analysis

377

Exhibit 4-123 Case 2 D4B (95%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum

Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water

Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out

From ASU Syngas Coolers

Sour Stripper 1,269,794 W 403.4 T 800.0 P 459.6 H

1,302,028 W 93.7 T 740.0 P 14.5 H 97,821 W 119.0 T 23.7 P

145,641 W 386.5 T 460.0 P 634.6 H

12,156 W 95,382 W 450.0 T 12.3 P 220.8 H

2,486 W 239.1 T 65.0 P 441.7 H

7,231 W 90.0 T 125.0 P 11.5 H NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D4B HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D4B (95%) GEE GASIFIER GAS CLEANUP SYSTEM DWG. NO. CCSA-HMB-CS-2-D4B-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 2 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 727 MWe Auxiliary Load: 198 MWe Net Plant Power: 529 MWe Net Plant Efficiency, HHV: 31.8% Net Plant Heat Rate: 10,731 BTU/KWe

19

13 20

CO2

Tailgas

Tail Gas Cleanup Unit

Tail Gas Compressor

92,487 W 120.0 T 10.6 P 92.6 H

1,215,711 W 94.9 T 745.0 P 16.0 H

9,060 W 106.5 T 10.6 P 31.6 H

3 86,317 W 100.0 T 799.5 P

Raw Syngas

15 145,641 W 93.7 T 725.0 P 110.4 H

Claus Oxygen Preheater

7,231 W 450.0 T 124.5 P 91.9 H

18

Fuel Gas Expander Fuel Gas To GT 16 145,641 W 465.0 T 720.0 P 778.4 H

High Temperature Shift #1 Low Temperature Shift #2 Shift Steam

12 11

COS Hydrolysis Preheater

1,269,794 W 413.4 T 795.0 P 451.7 H

283,043 W 550.0 T 800.0 P 1,254.1 H

1,552,837 W 436.5 T 795.0 P 598.0 H 776.2 T 795.0 P 582.1 H 400.0 T 795.0 P 408.0 H 1,552,837 W 463.4 T 785.0 P 405.1 H

1,552,837 W 455.5 T 780.0 P 401.5 H

Two-Stage Selexol

Clean Gas

CO2

Acid Gas

Multistage Intercooled CO2 Compressor Interstage Knockout

CO2 Product 17 10

14

1,057,638 W 123.6 T 2,214.7 P
Carbon Dioxide Capture Sensitivity Analysis

378

Exhibit 4-124 Case 2 D4B (95%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine

Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator

Ip Extraction Steam To 250 PSIA Header

LP Process Header

Blowdown Flash To WWT

Gland Steam Condenser Condensate to Gasification Island

HP BFW to Radiant Syngas Cooler HP Saturated Steam to HRSG Superheater

LP Turbine

Stack

Compressor Expander

Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class Gas Turbine

MP Flash Bottoms LP Flash Tops

7,014,133 W 59.0 T 14.7 P 13.0 H 1,790,237 W 101.1 T 1.0 P 69.1 H

8,441,453 W 269.9 T 15.2 P 147.8 H

145,641 W 386.5 T 460.0 P 634.6 H

8,441,453 W 1,041.2 T 15.2 P 358.1 H From Gasifier Island Preheating

To Claus

LP BFW 1,363,822 W 991.2 T 1,814.7 P 1,474.3 H

10,276 W 298.0 T 65.0 P 1,179.0 H 1,392,587 W 278.8 T 2,250.7 P 252.3 H 28,759 W 585.0 T 2,000.7 P 593.3 H

1,467,229 W 482.6 T 65.0 P 1,273.4 H

1,790,237 W 102.9 T 120.0 P 71.2 H

1,790,237 W 235.0 T 105.0 P 203.7 H

1,400 W 612.4 T 65.0 P 1,337.4 H 1,400 W 212.0 T 14.7 P 179.9 H

IP Pump NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D4B HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D4B (95%) GEE GASIFIER POWER BLOCK SYSTEM DWG. NO. CCSA-HMB-CS-2-D4B-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 3 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 727 MWe Auxiliary Load: 198 MWe Net Plant Power: 529 MWe Net Plant Efficiency, HHV: 31.8% Net Plant Heat Rate: 10,731 BTU/KWe 21

22

24 16

23

Flue Gas

HOT WELL CONDENSER Make-up 310,833 W 59.0 T 14.7 P 27.1 H

9,037 W 658.4 T 501.4 P 1,333.3 H 9,775 W 612.4 T 65.0 P 1,337.4 H 36,583 W 849.7 T 280.0 P 1,447.6 H 799 W 991.2 T 1,814.7 P 1,474.3 H 1,338 W 503.2 T 65.0 P 1,283.6 H
Carbon Dioxide Capture Sensitivity Analysis

379

Exhibit 4-125 Case 2 D4C (97%) Heat and Mass Balance, GEE Gasifier and ASU

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D4C HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D4C (97%) GEE GASIFIER ASU AND GASIFICATION DWG. NO. CCSA-HMB-CS-2-D4C-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 1 OF 3

Ambient Air Four Stage Air Compressor

Elevated Pressure ASU Four Stage N2 Compressor

Four Stage O2 Compressor

ASU Vent

Water

Steam

Gross Plant Power: 724 MWe Auxiliary Load: 201 MWe Net Plant Power: 523 MWe Net Plant Efficiency, HHV: 31.5% Net Plant Heat Rate: 10,840 BTU/KWe

N2 to GT Combustor 1,739,159 W 59.0 T 14.7 P 13.0 H

391,114 W 90.0 T 125.0 P 11.5 H

391,114 W 241.2 T 940.0 P 40.8 H

To Claus Plant 7,372 W 90.0 T 125.0 P 11.5 H

55,341 W 70.0 T 16.4 P 16.2 H

1,127,140 W 90.0 T 56.4 P 14.2 H

156,640 W 50.0 T 182.0 P 2.9 H 5

1

3

2

Slurry Mix Tank

Milled Coal

Slag

485,856 W 59.0 T 14.7 P

199,590 W 287.0 T 840.0 P 231.2 H

53,307 W 2,400.0 T 815.0 P

674,610 W 385.0 T 384.0 P 87.2 H

685,445 W 156.4 T 840.0 P 2,950.2 H

100.0 T 189.5 P 18.0 H

6

674,610 W 199.0 T 384.0 P 39.8 H

HP BFW

N2 to GT Combustor N2 Boost Compressor 609,170 W 199.0 T 384.0 P 39.8 H 609,170 W 385.0 T 469.0 P 87.0 H

Saturated Steam To HRSG HP Superheater

GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank

Knockout Drum

Vent To Claus Unit

Raw Fuel Gas

CWS

CWR

Fines

Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench Section Drag Conveyor

1,023,253 W 1,250.0 T 805.0 P 612.5 H 1,268,783 W 403.4 T 800.0 P 459.5 H

Syngas Quench

1,400,657 W 450.0 T 805.0 P 536.1 H

8

9

10 Sour Water

7

4

1,283,780 W 199.0 T 384.0 P 39.8 H
Carbon Dioxide Capture Sensitivity Analysis

380

Exhibit 4-126 Case 2 D4C (97%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum

Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water

Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out

From ASU Syngas Coolers

Sour Stripper 1,268,783 W 403.4 T 800.0 P 459.5 H

1,325,649 W 93.3 T 740.0 P 14.0 H 122,254 W 119.0 T 23.7 P

123,536 W 386.0 T 460.0 P 732.8 H

12,148 W 119,963 W 450.0 T 12.3 P 192.7 H

2,485 W 239.1 T 65.0 P 441.9 H

7,372 W 90.0 T 125.0 P 11.5 H NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D4C HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D4C (97%) GEE GASIFIER GAS CLEANUP SYSTEM DWG. NO. CCSA-HMB-CS-2-D4C-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 2 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 724 MWe Auxiliary Load: 201 MWe Net Plant Power: 523 MWe Net Plant Efficiency, HHV: 31.5% Net Plant Heat Rate: 10,840 BTU/KWe

19

13 20

CO2

Tailgas

Tail Gas Cleanup Unit

Tail Gas Compressor

118,438

W 120.0 T 10.6 P 90.7 H

1,214,928 W 94.9 T 745.0 P 16.0 H

9,242 W 103.4 T 10.6 P 28.3 H

3 110,721 W 100.0 T 799.5 P

Raw Syngas

15 123,536 W 93.3 T 725.0 P 127.9 H

Claus Oxygen Preheater

7,372 W 450.0 T 124.5 P 91.9 H

18

Fuel Gas Expander Fuel Gas To GT 16 123,536 W 465.0 T 720.0 P 899.8 H

High Temperature Shift #1 Low Temperature Shift #2 Shift Steam

12 11

COS Hydrolysis Preheater

1,268,783 W 413.4 T 795.0 P 451.6 H

283,054 W 550.0 T 800.0 P 1,254.1 H

1,551,837 W 436.5 T 795.0 P 598.0 H 776.2 T 795.0 P 582.1 H 400.0 T 795.0 P 408.0 H 1,551,837 W 463.4 T 785.0 P 405.1 H

1,551,837 W 455.5 T 780.0 P 401.5 H

Two-Stage Selexol

Clean Gas

CO2

Acid Gas

Multistage Intercooled CO2 Compressor Interstage Knockout

CO2 Product 17 10

14

1,078,918 W 123.6 T 2,214.7 P
Carbon Dioxide Capture Sensitivity Analysis

381

Exhibit 4-127 Case 2 D4C (97%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine

Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator

Ip Extraction Steam To 250 PSIA Header

LP Process Header

Blowdown Flash To WWT

Gland Steam Condenser Condensate to Gasification Island

HP BFW to Radiant Syngas Cooler HP Saturated Steam to HRSG Superheater

LP Turbine

Stack

Compressor Expander

Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class Gas Turbine

MP Flash Bottoms LP Flash Tops

7,014,133 W 59.0 T 14.7 P 13.0 H 1,754,867 W 101.1 T 1.0 P 69.1 H

8,436,041 W 270.0 T 15.2 P 147.8 H

123,536 W 386.0 T 460.0 P 732.8 H

8,436,041 W 1,040.3 T 15.2 P 357.8 H From Gasifier Island Preheating

To Claus

LP BFW 1,361,570 W 990.3 T 1,814.7 P 1,473.7 H

10,250 W 298.0 T 65.0 P 1,179.0 H 1,390,284 W 278.8 T 2,250.7 P 252.3 H 28,689 W 585.0 T 2,000.7 P 593.3 H

1,431,875 W 486.0 T 65.0 P 1,275.2 H

1,754,867 W 103.0 T 120.0 P 71.2 H

1,754,867 W 235.0 T 105.0 P 203.7 H

1,400 W 611.5 T 65.0 P 1,337.0 H 1,400 W 212.0 T 14.7 P 179.9 H

IP Pump NOTES: 1. ENTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0.08865 PSIA

DOE/NETL GEE IGCC PLANT CASE 2 D4C HEAT AND MATERIAL FLOW DIAGRAM CO2 CAPTURE SENSITIVITY STUDY CASE 2 D4C (97%) GEE GASIFIER POWER BLOCK SYSTEM DWG. NO. CCSA-HMB-CS-2-D4C-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA F TEMPERATURE, °F W FLOWRATE, LBM/HR H ENTHALPY, BTU/LBM MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen Nitrogen Coal/Char/ Slurry/Slag

Synthesis Gas

PAGES 3 OF 3

Sour Gas Sour Water

Water

Steam

Gross Plant Power: 724 MWe Auxiliary Load: 201 MWe Net Plant Power: 523 MWe Net Plant Efficiency, HHV: 31.5% Net Plant Heat Rate: 10,840 BTU/KWe 21

22

24 16

23

Flue Gas

HOT WELL CONDENSER Make-up 310,812 W 59.0 T 14.7 P 27.1 H

9,041 W 657.6 T 501.4 P 1,332.8 H 9,780 W 611.5 T 65.0 P 1,337.0 H 38,262 W 848.8 T 280.0 P 1,447.1 H 800 W 990.3 T 1,814.7 P 1,473.7 H 1,339 W 502.5 T 65.0 P 1,283.3 H
Carbon Dioxide Capture Sensitivity Analysis

382

This page intentionally left blank
Carbon Dioxide Capture Sensitivity Analysis

383

Exhibit 4-128 Case 2 D4A (90%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,994 

(5,682) 5.0 (4.7) 0 (0) 5,999 (5,686)

ASU Air 0 (0) 23.9 (22.6) 0 (0) 24 (23)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 82.8 (78.5) 0 (0) 83 (78)

Totals 5,994 

(5,682) 207.9 (197.0) 0 (0) 6,202 (5,879)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.6 (1.5) 0 (0) 2 (2)

Slag 92 (88) 37.8 (35.9) 0 (0) 130 (123)

Sulfur 51 (49) 0.6 (0.6) 0 (0) 52 (49)

CO2 0 (0) -74.1 (-70.3) 0 (0) -74 (-70)

Gasifier Heat Loss 0 (0) 44.6 (42.3) 0 (0) 45 (42)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,318 (1,249) 0 (0) 1,318 

(1,249)

Cooling Tower* 0 (0) 2,177 (2,063) 0 (0) 2,177 

(2,063)

Process Losses** 0 (0) 534 (506) 0 (0) 534 (506)

Net Power 0 (0) 0.0 (0.0) 1,956 

(1,854)

1,956 

(1,854)

Totals 144 (136) 4,103 (3,889) 1,956 

(1,854)

6,202 

(5,879)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Includes Condenser, Cooling Tower Blowdown, and the following Non-Condenser 

 Cooling Tower Loads: ASU compressor intercoolers, CO2 compressor intercoolers,

 sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

 air cooler.

** Calculated by difference to close the energy balance.
Carbon Dioxide Capture Sensitivity Analysis

384

Exhibit 4-129 Case 2 D4B (95%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,984 

(5,672) 5.0 (4.7) 0 (0) 5,989 (5,676)

ASU Air 0 (0) 23.9 (22.6) 0 (0) 24 (23)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 81.7 (77.4) 0 (0) 82 (77)

Totals 5,984 

(5,672) 206.7 (195.9) 0 (0) 6,191 (5,868)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.0 (0.9) 0 (0) 1 (1)

Slag 92 (87) 37.8 (35.8) 0 (0) 130 (123)

Sulfur 51 (48) 0.6 (0.6) 0 (0) 52 (49)

CO2 0 (0) -78.1 (-74.0) 0 (0) -78 (-74)

Gasifier Heat Loss 0 (0) 44.5 (42.2) 0 (0) 45 (42)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,316 (1,247) 0 (0) 1,316 

(1,247)

Cooling Tower* 0 (0) 2,121 (2,010) 0 (0) 2,121 

(2,010)

Process Losses** 0 (0) 639 (605) 0 (0) 639 (605)

Net Power 0 (0) 0.0 (0.0) 1,903 

(1,803)

1,903 

(1,803)

Totals 143 (136) 4,145 (3,928) 1,903 

(1,803)

6,191 

(5,868)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Includes Condenser, Cooling Tower Blowdown, and the following Non-Condenser 

 Cooling Tower Loads: ASU compressor intercoolers, CO2 compressor intercoolers,

 sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

 air cooler.

** Calculated by difference to close the energy balance.
Carbon Dioxide Capture Sensitivity Analysis

385

Exhibit 4-130 Case 2 D4C (97%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,980 

(5,668) 5.0 (4.7) 0 (0) 5,985 (5,673)

ASU Air 0 (0) 23.8 (22.6) 0 (0) 24 (23)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 81.2 (77.0) 0 (0) 81 (77)

Totals 5,980 

(5,668) 206.2 (195.5) 0 (0) 6,186 (5,863)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 0.9 (0.9) 0 (0) 1 (1)

Slag 92 (87) 37.8 (35.8) 0 (0) 130 (123)

Sulfur 51 (48) 0.6 (0.6) 0 (0) 52 (49)

CO2 0 (0) -79.7 (-75.5) 0 (0) -80 (-76)

Gasifier Heat Loss 0 (0) 44.5 (42.2) 0 (0) 45 (42)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,315 (1,247) 0 (0) 1,315 

(1,247)

Cooling Tower* 0 (0) 2,097 (1,988) 0 (0) 2,097 

(1,988)

Process Losses** 0 (0) 681 (645) 0 (0) 681 (645)

Net Power 0 (0) 0.0 (0.0) 1,882 

(1,784)

1,882 

(1,784)

Totals 143 (136) 4,161 (3,944) 1,882 

(1,784)

6,186 

(5,863)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia)

* Includes Condenser, Cooling Tower Blowdown, and the following Non-Condenser 

 Cooling Tower Loads: ASU compressor intercoolers, CO2 compressor intercoolers,

 sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

 air cooler.

** Calculated by difference to close the energy balance.
Carbon Dioxide Capture Sensitivity Analysis

386

Exhibit 4-131 Case 2 D4A Energy Balance Sankey Diagram

Exhibit 4-132 Case 2 D4B Energy Balance Sankey Diagram
Carbon Dioxide Capture Sensitivity Analysis

387

Exhibit 4-133 Case 2 D4C Energy Balance Sankey Diagram
Carbon Dioxide Capture Sensitivity Analysis

388

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Carbon Dioxide Capture Sensitivity Analysis

389

4.3.4.2 Major Equipment List for Case 2 D4

Major equipment items for Case 2 D4 (two WGS reactors without bypass) are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates. 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. 

ACCOUNT 1 COAL HANDLING

Equipment 

No. Description Type

Design Conditions Opr Qty.

D4A D4B D4C (Spares)

1

Bottom Trestle Dumper and 

Receiving Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0)

3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

4 Transfer Tower No. 1 Enclosed N/A N/A N/A 1 (0)

5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

6

As-Received Coal Sampling 

System Two-stage N/A N/A N/A 1 (0)

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

8 Reclaim Hopper N/A 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 2 (1)

9 Feeder Vibratory 181 tonne/hr (200 tph) 181 tonne/hr (200 tph) 181 tonne/hr (200 tph) 2 (1)

10 Conveyor No. 3 Belt w/ tripper 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0)

11 Crusher Tower N/A N/A N/A N/A 1 (0)

12 Coal Surge Bin w/ Vent 

Filter Dual outlet 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0) 2 (0)

14 As-Fired Coal Sampling 

System Swing hammer N/A N/A N/A 1 (1)

15 Conveyor No. 4 Belt w/tripper 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0)

16 Transfer Tower No. 2 Enclosed N/A N/A N/A 1 (0)

17 Conveyor No. 5 Belt w/ tripper 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0)

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 816 tonne (900 ton) 816 tonne (900 ton) 816 tonne (900 ton) 3 (0)

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type

Design Condition Opr Qty.

D4A D4B D4C (Spares)

1 Feeder Vibratory 82 tonne/h (90 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 3 (0)

2 Conveyor No. 6 Belt w/tripper 245 tonne/h (270 tph) 245 tonne/h (270 tph) 245 tonne/h (270 tph) 1 (0)

3 Rod Mill Feed Hopper Dual Outlet 490 tonne (540 ton) 481 tonne (530 ton) 481 tonne (530 ton) 1 (0)

4 Weigh Feeder Belt 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)

5 Rod Mill Rotary 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)

6

Slurry Water Storage 

Tank with Agitator Field erected 299,921 liters (79,230 gal) 299,391 liters (79,090 gal)

299,201 liters 

(79,040 gal) 2 (0)

7 Slurry Water Pumps Centrifugal 833 lpm (220 gpm) 833 lpm (220 gpm) 833 lpm (220 gpm) 2 (1)

8 Trommel Screen Coarse 172 tonne/h (190 tph) 172 tonne/h (190 tph) 172 tonne/h (190 tph) 2 (0)
Carbon Dioxide Capture Sensitivity Analysis

390

Equipment 

No. Description Type

Design Condition Opr Qty.

D4A D4B D4C (Spares)

9

Rod Mill Discharge Tank 

with Agitator Field erected 392,323 liters (103,640 gal)

391,642 liters 

(103,460 gal)

391,377 liters 

(103,390 gal) 2 (0)

10 Rod Mill Product Pumps Centrifugal 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 2 (2)

11 Slurry Storage Tank with 

Agitator Field erected 1,176,894 liters (310,900 gal)

1,175,001 liters 

(310,400 gal)

1,174,244 liters 

(310,200 gal) 2 (0)

12 Slurry Recycle Pumps Centrifugal 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 2 (2)

13 Slurry Product Pumps Positive 

displacement 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 2 (2)

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment No. Description Type

Design Condition Opr Qty.

D4A D4B D4C (Spares)

1

Demineralized Water Storage 

Tank

Vertical, cylindrical, 

outdoor 1,093,984 liters (289,000 gal) 1,093,984 liters (289,000 gal) 1,093,984 liters (289,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 7,874 lpm @ 91 m H2O

(2,080 gpm @ 300 ft H2O)

7,495 lpm @ 91 m H2O

(1,980 gpm @ 300 ft H2O)

7,344 lpm @ 91 m H2O

(1,940 gpm @ 300 ft H2O)

2 (1)

3 Deaerator (integral w/ HRSG) Horizontal spray type 546,579 kg/hr (1,205,000 lb/hr) 549,754 kg/hr (1,212,000 lb/hr) 551,568 kg/hr (1,216,000 lb/hr) 2 (0)

4

Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

8,025 lpm @ 27 m H2O

(2,120 gpm @ 90 ft H2O)

8,063 lpm @ 27 m H2O

(2,130 gpm @ 90 ft H2O)

8,063 lpm @ 27 m H2O

(2,130 gpm @ 90 ft H2O)

2 (1)

5

High Pressure Feedwater Pump 

No. 1

Barrel type, multistage, centrifugalHP water: 6,057 lpm @ 1,859 m H2O 

(1,600 gpm @ 6,100 ft H2O)

HP water: 6,019 lpm @ 1,859 m H2O 

(1,590 gpm @ 6,100 ft H2O)

HP water: 6,019 lpm @ 1,859 m 

H2O (1,590 gpm @ 6,100 ft H2O)

2 (1)

6

High Pressure Feedwater Pump 

No. 2

Barrel type, multistage, centrifugalIP water: 1,703 lpm @ 223 m H2O 

(450 gpm @ 730 ft H2O)

IP water: 1,741 lpm @ 223 m H2O 

(460 gpm @ 730 ft H2O)

IP water: 1,703 lpm @ 223 m H2O 

(450 gpm @ 730 ft H2O)

2 (1)

7 Auxiliary Boiler Shop fabricated, water 

tube

18,144 kg/hr, 2.8 MPa, 343°C

(40,000 lb/hr, 400 psig, 650°F)

18,144 kg/hr, 2.8 MPa, 343°C

(40,000 lb/hr, 400 psig, 650°F)

18,144 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)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

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) 28 m3/min (1,000 scfm) 28 m3/min (1,000 scfm) 2 (1)

10 Closed Cylce Cooling Heat 

Exchangers Plate and frame 362 GJ/hr (343.5076381 MMBtu/hr) each

375 GJ/hr (355.39736925 MMBtu/hr) 

each

380 GJ/hr (360.46720325 

MMBtu/hr) each

2 (0)

11 Closed Cycle Cooling Water 

Pumps Horizontal centrifugal 130,218 lpm @ 21 m H2O(34,400 gpm @ 70 ft H2O)

134,382 lpm @ 21 m H2O

(35,500 gpm @ 70 ft H2O)

136,275 lpm @ 21 m H2O

(36,000 gpm @ 70 ft H2O)

2 (1)

12 Engine-Driven Fire Pump Vertical turbine, diesel 

engine

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

1 (1)

13 Fire Service Booster Pump Two-stage horizontal 

centrifugal

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

1 (1)

14 Raw Water Pumps Stainless steel, single 

suction

5,716 lpm @ 18 m H2O

(1,510 gpm @ 60 ft H2O)

5,640 lpm @ 18 m H2O

(1,490 gpm @ 60 ft H2O)

5,602 lpm @ 18 m H2O

(1,480 gpm @ 60 ft H2O)

2 (1)

15 Ground Water Pumps Stainless steel, single 

suction

2,839 lpm @ 268 m H2O 

(750 gpm @ 880 ft H2O)

2,801 lpm @ 268 m H2O 

(740 gpm @ 880 ft H2O)

2,801 lpm @ 268 m H2O 

(740 gpm @ 880 ft H2O)

3 (1)

16 Filtered Water Pumps Stainless steel, single 

suction

3,369 lpm @ 49 m H2O

(890 gpm @ 160 ft H2O)

3,331 lpm @ 49 m H2O

(880 gpm @ 160 ft H2O)

3,331 lpm @ 49 m H2O

(880 gpm @ 160 ft H2O)

2 (1)

17 Filtered Water Tank Vertical, cylindrical 1,608,800 liter (425,000 gal) 1,605,015 liter (424,000 gal) 1,601,229 liter (423,000 gal) 2 (0)

18 Makeup Water Demineralizer Anion, cation, and 

mixed bed 1,476 lpm (390 gpm) 1,476 lpm (390 gpm) 1,476 lpm (390 gpm) 2 (0)

19 Liquid Waste Treatment System 10 years, 24-hour storm 10 years, 24-hour storm 10 years, 24-hour storm 1 (0)
Carbon Dioxide Capture Sensitivity Analysis

391

ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment No. Description Type

Design Condition Opr Qty.

D4A D4B D4C (Spares)

1 Gasifier Pressurized slurryfeed, entrained bed

2,903 tonne/day, 5.6 MPa

(3,200 tpd, 814.96 psia)

2,903 tonne/day, 5.6 MPa

(3,200 tpd, 814.96 psia)

2,903 tonne/day, 5.6 MPa

(3,200 tpd, 814.96 psia)

2 (0)

2 Synthesis Gas Cooler

Vertical downflow 

radiant heat 

exchanger with outlet 

quench chamber

255,826 kg/hr (564,000 lb/hr) 255,373 kg/hr (563,000 lb/hr) 255,373 kg/hr (563,000 lb/hr) 2 (0)

3 Synthesis Gas Cyclone High efficiency 350,173 kg/hr (772,000 lb/hr) Design 

efficiency 90%

349,720 kg/hr (771,000 lb/hr) Design 

efficiency 90%

349,720 kg/hr (771,000 lb/hr) 

Design efficiency 90%

2 (0)

4 Candle Filter Pressurized filter with 

pulse-jet cleaning metallic filters metallic filters metallic filters 2 (0)

5

Syngas Scrubber Including Sour 

Water Stripper Vertical upflow 350,173 kg/hr (772,000 lb/hr) 349,720 kg/hr (771,000 lb/hr) 349,720 kg/hr (771,000 lb/hr) 2 (0)

6 Raw Gas Coolers Shell and tube with 

condensate drain 388,275 kg/hr (856,000 lb/hr) 387,368 kg/hr (854,000 lb/hr) 387,368 kg/hr (854,000 lb/hr) 8 (0)

7 Raw Gas Knockout Drum Vertical with mist 

eliminator

304,360 kg/hr, 35°C, 5.2 MPa

(671,000 lb/hr, 95°F, 750 psia)

303,907 kg/hr, 35°C, 5.2 MPa

(670,000 lb/hr, 95°F, 750 psia)

303,453 kg/hr, 35°C, 5.2 MPa

(669,000 lb/hr, 95°F, 750 psia)

2 (0)

8 Flare Stack

Self-supporting, 

carbon steel, stainless 

steel top, pilot ignition

350,173 kg/hr (772,000 lb/hr) syngas 349,720 kg/hr (771,000 lb/hr) syngas 349,720 kg/hr (771,000 lb/hr) 

syngas

2 (0)

9 ASU Main Air Compressor Centrifugal, multistage

5,947 m3/min @ 1.3 MPa

(210,000 scfm @ 190 psia)

5,947 m3/min @ 1.3 MPa

(210,000 scfm @ 190 psia)

5,947 m3/min @ 1.3 MPa

(210,000 scfm @ 190 psia)

2 (0)

10 Cold Box Vendor design 2,359 tonne/day (2,600 tpd) of 95% 

purity oxygen

2,359 tonne/day (2,600 tpd) of 95% 

purity oxygen

2,359 tonne/day (2,600 tpd) of 

95% purity oxygen

2 (0)

11 Oxygen Compressor Centrifugal, multistage

1,189 m3/min (42,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 psia)

1,189 m3/min (42,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 psia)

1,189 m3/min (42,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 psia)

2 (0)

12 Primary Nitrogen Compressor Centrifugal, multistage

3,794 m3/min (134,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

3,936 m3/min (139,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

3,964 m3/min (140,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 (0)

13 Secondary Nitrogen 

Compressor

Centrifugal, singlestage

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 (0)

14 Syngas Dilution Nitrogen Boost 

Compressor

Centrifugal, singlestage

1,982 m3/min (70,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 psia)

2,095 m3/min (74,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 psia)

2,152 m3/min (76,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 psia)

2 (0)

ACCOUNT 5A SYNGAS CLEANUP

Equipment 

No. Description Type

Design Condition Opr Qty.

D4A D4B D4C (Spares)

1

Mercury 

Adsorber

Sulfated carbon 

bed

303,907 kg/hr (670,000 lb/hr) 

35°C (95°F) 

5.1 MPa (745 psia)

303,453 kg/hr (669,000 lb/hr) 

35°C (95°F) 

5.1 MPa (745 psia)

303,000 kg/hr (668,000 lb/hr) 

35°C (95°F) 

5.1 MPa (745 psia)

2 (0)

2 Sulfur Plant Claus type 146 tonne/day (161 tpd) 146 tonne/day (160 tpd) 146 tonne/day (160 tpd) 1 (0)

3

Water Gas Shift 

Reactors

Fixed bed, 

catalytic

388,275 kg/hr (856,000 lb/hr) 

227°C (440°F) 

5.4 MPa (790 psia)

387,368 kg/hr (854,000 lb/hr) 

227°C (440°F) 

5.4 MPa (790 psia)

387,368 kg/hr (854,000 lb/hr) 

227°C (440°F) 

5.4 MPa (790 psia)

4 (0)
Carbon Dioxide Capture Sensitivity Analysis

392

Equipment 

No. Description Type

Design Condition Opr Qty.

D4A D4B D4C (Spares)

4

Shift Reactor 

Heat Recovery 

Exchangers

Shell and Tube

Exchanger 1: 157 GJ/hr (149 

MMBtu/hr) 

Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 

Exchanger 1: 157 GJ/hr (149 MMBtu/hr) 

Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 

Exchanger 1: 157 GJ/hr (149 

MMBtu/hr) 

Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 

4 (0)

5

Acid Gas 

Removal Plant

Two-stage 

Selexol

310,711 kg/hr (685,000 lb/hr) 

35°C (95°F) 

5.1 MPa (740 psia)

324,772 kg/hr (716,000 lb/hr) 

34°C (94°F) 

5.1 MPa (740 psia)

330,669 kg/hr (729,000 lb/hr) 

34°C (93°F) 

5.1 MPa (740 psia)

2 (0)

6

Hydrogenation 

Reactor

Fixed bed, 

catalytic

18,095 kg/hr (39,892 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

47,591 kg/hr (104,920 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

59,856 kg/hr (131,960 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

1 (0)

7

Tail Gas Recycle 

Compressor Centrifugal 13,779 kg/hr (30,378 lb/hr) 43,068 kg/hr (94,949 lb/hr) 55,244 kg/hr (121,793 lb/hr) 1 (0)

ACCOUNT 5B CO2 COMPRESSION

Equipment 

No. Description Type

Design Condition Opr Qty.

D (Spares) 4A D4B D4C

1 CO2 Compressor Integrally geared, multistage centrifugal

1,133 m3/min @ 15.3 MPa 

(40,000 scfm @ 2,215 psia)

1,189 m3/min @ 15.3 MPa 

(42,000 scfm @ 2,215 psia)

1,212 m3/min @ 15.3 MPa 

(42,800 scfm @ 2,215 psia)

4 (0)

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment 

No. Description Type

Design Condition Opr Qty.

D4A D4B D4C (Spares)

1 Gas Turbine Advanced F class 230 MW 230 MW 230 MW 2 (0)

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase

260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase

260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase 2 (0)

3

Syngas Expansion 

Turbine/Generator Turbo Expander

49,578 kg/h (109,300 lb/h)

5.0 MPa (720 psia) Inlet

3.2 MPa (460 psia) Outlet

36,333 kg/h (80,100 lb/h)

5.0 MPa (720 psia) Inlet

3.2 MPa (460 psia) Outlet

30,799 kg/h (67,900 lb/h)

5.0 MPa (720 psia) Inlet

3.2 MPa (460 psia) Outlet

2 (0)

ACCOUNT 7 HRSG, DUCTING, AND STACK

Equipment 

No. Description Type

Design Condition Opr Qty.

D4A D4B D4C (Spares)

1 Stack CS plate, type 

409SS liner

76 m (250 ft) high x

8.5 m (28 ft) diameter

76 m (250 ft) high x

8.5 m (28 ft) diameter

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 - 341,834 kg/hr, 

12.4 MPa/534°C (753,614 

lb/hr, 1,800 psig/994°F)

 Reheat steam - 336,639 

kg/hr, 3.1 MPa/534°C (742,162 

lb/hr, 452 psig/994°F)

Main steam - 340,240 kg/hr, 

12.4 MPa/533°C (750,102 

lb/hr, 1,800 psig/991°F)

 Reheat steam - 335,536 

kg/hr, 3.1 MPa/533°C (739,731 

lb/hr, 452 psig/991°F)

Main steam - 339,679 kg/hr, 

12.4 MPa/532°C (748,864 

lb/hr, 1,800 psig/990°F)

 Reheat steam - 334,930 

kg/hr, 3.1 MPa/532°C (738,395 

lb/hr, 452 psig/990°F)

2 (0)
Carbon Dioxide Capture Sensitivity Analysis

393

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type

Design Condition Opr Qty.

D4A D4B D4C (Spares)

1 Steam Turbine

Commercially 

available advanced 

steam turbine

278 MW 12.4 

MPa/534°C/534°C (1,800 psig/ 

994°F/994°F)

270 MW 12.4 

MPa/533°C/533°C (1,800 psig/ 

991°F/991°F)

267 MW 12.4 

MPa/532°C/532°C (1,800 psig/ 

990°F/990°F)

1 (0)

2

Steam Turbine 

Generator

Hydrogen cooled, 

static excitation

310 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

300 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

300 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design 

steam conditions

50% steam flow @ design 

steam conditions

50% steam flow @ design 

steam conditions 2 (0)

4

Surface 

Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,667 GJ/hr (1,580 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), Water temperature rise 

11°C (20°F)

1,583 GJ/hr (1,500 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), Water temperature rise 

11°C (20°F)

1,540 GJ/hr (1,460 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), Water temperature rise 

11°C (20°F)

1 (0)

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type

Design Condition Opr Qty.

D4A D4B D4C (Spares)

1

Circulating 

Water Pumps Vertical, wet pit 461,820 lpm @ 30 m(122,000 gpm @ 100 ft)

458,035 lpm @ 30 m

(121,000 gpm @ 100 ft)

454,249 lpm @ 30 m

(120,000 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 / 2,585 GJ/hr (2,450 

MMBtu/hr) heat duty

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) 

HWT / 2,543 GJ/hr (2,410 

MMBtu/hr) heat duty

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) 

HWT / 2,532 GJ/hr (2,400 

MMBtu/hr) heat duty

1 (0)

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type

Design Condition Opr Qty.

D (Spares) 4A D4B D4C

1 Slag Quench Tank Water bath 253,623 liters (67,000 gal) 253,623 liters (67,000 gal) 253,623 liters (67,000 gal) 2 (0)

2 Slag Crusher Roll 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

3 Slag Depressurizer Lock Hopper 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

4 Slag Receiving Tank Horizontal, weir 151,416 liters (40,000 gal) 151,416 liters (40,000 gal) 151,416 liters (40,000 gal) 2 (0)

5

Black Water Overflow 

Tank Shop fabricated 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)

6 Slag Conveyor Drag chain 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

7

Slag Separation 

Screen Vibrating 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

8

Coarse Slag 

Conveyor Belt/bucket 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

9

Fine Ash Settling 

Tank Vertical, gravity 215,768 liters (57,000 gal) 215,768 liters (57,000 gal) 215,768 liters (57,000 gal) 2 (0)

10 Fine Ash Recycle 

Pumps Horizontal centrifugal 38 lpm @ 14 m H2O(10 gpm @ 46 ft H2O)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

2 (2)

11 Grey Water Storage 

Tank Field erected 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H2O

(60 gpm @ 1,850 ft H2O)

227 lpm @ 564 m H2O

(60 gpm @ 1,850 ft H2O)

227 lpm @ 564 m H2O

(60 gpm @ 1,850 ft H2O)

2 (2)
Carbon Dioxide Capture Sensitivity Analysis

394

Equipment 

No. Description Type

Design Condition Opr Qty.

D (Spares) 4A D4B D4C

13 Slag Storage Bin Vertical, field erected 998 tonne (1,100 tons) 998 tonne (1,100 tons) 998 tonne (1,100 tons) 2 (0)

14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 1 (0)

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type

Design Condition Opr Qty.

D4A D4B D4C (Spares)

1

CTG Step-up 

Transformer Oil-filled 24 kV/345 kV, 260 MVA, 3-ph, 60 Hz

24 kV/345 kV, 260 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 260 MVA, 

3-ph, 60 Hz

2 (0)

2

STG Step-up 

Transformer Oil-filled 24 kV/345 kV, 310 MVA, 3-ph, 60 Hz

24 kV/345 kV, 300 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 300 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

345 kV/13.8 kV, 82 MVA, 

3-ph, 60 Hz

345 kV/13.8 kV, 82 MVA, 

3-ph, 60 Hz

2 (0)

4

Medium Voltage 

Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 48 MVA, 3-ph, 60 Hz

24 kV/4.16 kV, 53 MVA, 

3-ph, 60 Hz

24 kV/4.16 kV, 55 MVA, 

3-ph, 60 Hz

1 (1)

5

Low Voltage 

Transformer Dry ventilated 4.16 kV/480 V, 7 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 8 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 8 MVA, 

3-ph, 60 Hz

1 (1)

6

CTG Isolated Phase 

Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 2 (0)

7

STG Isolated Phase 

Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 1 (0)

8

Medium Voltage 

Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz 1 (1)

9

Low Voltage 

Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz 1 (1)

10 Emergency Diesel 

Generator

Sized for emergency 

shutdown 750 kW, 480 V, 3-ph, 60 Hz 750 kW, 480 V, 3-ph, 60 Hz 750 kW, 480 V, 3-ph, 60 Hz 1 (0)

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment 

No. Description Type

Design Condition Opr Qty.

D4A D4B D4C (Spares)

1

DCS - Main 

Control

Monitor/keyboard; 

Operator printer 

(laser color); 

Engineering printer 

(laser B&W)

Operator stations/printers and 

engineering stations/printers

Operator stations/printers and 

engineering stations/printers

Operator stations/printers and 

engineering stations/printers 1 (0)

2

DCS -

Processor

Microprocessor with 

redundant 

input/output

N/A N/A N/A 1 (0)

3

DCS - Data 

Highway Fiber optic Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare 1 (0)
Carbon Dioxide Capture Sensitivity Analysis

395

4.3.5 Economic Analysis for the GEE IGCC Cases

The capital and operating costs for Case 2 Designs 1-4 are presented in Section 4.3.6. A cost and 

performance summary table (Exhibit 4-162) for the GEE IGCC cases is shown in Section 4.3.7. 

4.3.6 Capital and Operating Cost Results

The capital and operating costs for Case 2 Designs 1-4 are shown in Exhibit 4-134 through 

Exhibit 4-161. The capital costs for each case include the total plant cost (TPC), the owner‟s 

costs, the total overnight cost (TOC), and the total as-spent capital (TASC) cost. The capital and 

operating cost estimating methodology is explained in Section 2.7.
Carbon Dioxide Capture Sensitivity Analysis

396

Exhibit 4-134 Case 2 D1A (0%) Capital Costs 

Department: NETL Office of Systems Analysis and Planning Cost Base: 1-Jun-07

Project: CO2 Capture Sensitivity Analysis Prepared: 14-Jun-10

Case: Case 2 D1A - GEE IGCC w/o WGS (0% CO2 Capture) x $1, 000

Plant Size: 622.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload $3,653 $0 $1,785 0 5,439 9.0% $487 0% 0 20.0% $1,185 7,111 11

1.2 Coal Stackout & Reclaim $4,721 $0 $1,144 0 5,865 8.8% $514 0% 0 20.0% $1,276 7,655 12

1.3 Coal Conveyors & Yd Crus $4,389 $0 $1,132 0 5,522 8.8% $485 0% 0 20.0% $1,201 7,207 12

1.4 Other Coal Handling $1,148 $0 $262 0 1,410 8.8% $123 0% 0 20.0% $307 1,840 3

1.5 Sorbent Receive & Unload $0 $0 $0 0 0 0.0% $0 0% 0 0.0% $0 0 0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 0 0 0.0% $0 0% 0 0.0% $0 0 0

1.7 Sorbent Conveyors $0 $0 $0 0 0 0.0% $0 0% 0 0.0% $0 0 0

1.8 Other Sorbent Handling $0 $0 $0 0 0 0.0% $0 0% 0 0.0% $0 0 0

1.9 Coal & Sorbent Hnd.Foundations $0 $2,585 $6,464 0 9,049 9.6% $867 0% 0 20.0% $1,983 11,900 19

SUBTOTAL 1. $13,912 $2,585 $10,788 $0 $27,285 $2,477 $0 $5,952 $35,714 $57

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying w/ 2.3 $0 w/ 2.3 0 0 0.0% $0 0% 0 0.0% $0 0 0

2.2 Prepared Coal Storage & Feed $1,558 $373 $244 0 2,175 8.6% $186 0% 0 20.0% $472 2,833 5

2.3 Slurry Prep & Feed $21,299 $0 $9,398 0 30,697 9.1% $2,789 5% $1,535 20.0% $7,004 42,025 68

2.4 Misc. Coal Prep & Feed $857 $623 $1,869 0 3,349 9.2% $308 0% 0 20.0% $731 4,388 7

2.5 Sorbent Prep Equipment $0 $0 $0 0 0 0.0% $0 0% 0 0.0% $0 0 0

2.6 Sorbent Storage & Feed $0 $0 $0 0 0 0.0% $0 0% 0 0.0% $0 0 0

2.7 Sorbent Injection System $0 $0 $0 0 0 0.0% $0 0% 0 0.0% $0 0 0

2.8 Booster Air Supply System $0 $0 $0 0 0 0.0% $0 0% 0 0.0% $0 0 0

2.9 Coal & Sorbent Feed Foundation $0 $3,330 $2,734 0 6,063 9.3% $562 0% 0 20.0% $1,325 7,950 13

SUBTOTAL 2. $23,713 $4,326 $14,245 $0 $42,284 $3,844 $1,535 $9,533 $57,195 $92

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,896 $4,974 $2,626 0 10,496 9.3% $972 0% 0 20.0% 2,294 13,762 22

3.2 Water Makeup & Pretreating $620 $65 $347 0 1,031 9.5% $98 0% 0 30.0% 339 1,469 2

3.3 Other Feedwater Subsystems $1,585 $536 $482 0 2,602 9.0% $234 0% 0 20.0% 567 3,403 5

3.4 Service Water Systems $355 $731 $2,536 0 3,621 9.8% $353 0% 0 30.0% 1,192 5,167 8

3.5 Other Boiler Plant Systems $1,904 $738 $1,829 0 4,471 9.5% $424 0% 0 20.0% 979 5,874 9

3.6 FO Supply Sys & Nat Gas $315 $596 $556 0 1,467 9.6% $141 0% 0 20.0% 322 1,930 3

3.7 Waste Treatment Equipment $867 $0 $529 0 1,395 9.7% $136 0% 0 30.0% 459 1,991 3

3.8 Misc. Power Plant Equipment $1,080 $145 $554 0 1,779 9.7% $172 0% 0 30.0% 585 2,536 4

SUBTOTAL 3. $9,622 $7,783 $9,458 $0 $26,863 $2,531 $0 $6,737 $36,131 $58

4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $111,116 $0 $60,871 0 171,987 9.2% $15,755 13.9% $23,878 15.3% $32,445 244,065 392

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/4.1 0 0 0.0% $0 0% 0 0.0% $0 0 0

4.3 ASU/Oxidant Compression $160,703 $0 w/equip. 0 160,703 9.7% $15,577 0% 0 10.0% $17,628 193,908 312

4.4 Scrubber & Low Temperature Cooling $5,873 $4,781 $4,975 0 15,629 9.6% $1,501 0% 0 20.0% $3,426 20,556 33

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 0 0 0.0% $0 0% 0 0.0% $0 0 0

4.6 Other Gasification Equipment $1,791 $0 $1,681 0 3,472 12.0% $417 0% 0 24.4% $948 4,837 8

4.7 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 0 0 0.0% $0 0% 0 0.0% $0 0 0

4.8 Gasification Foundations $0 $6,486 $5,414 0 11,900 9.3% $1,103 0% 0 25.0% $3,251 16,253 26

SUBTOTAL 4. $279,483 $11,266 $72,942 $0 $363,691 $34,352 $23,878 $57,697 $479,618 $771

Labor Bare Project Cont. TOTAL PLANT COST

Erected 

Eng'g CM H.O. & Process Cont.

Acct No. Item/Description

Equipment 

Cost

Material 

Cost
Carbon Dioxide Capture Sensitivity Analysis

397

Exhibit 4-134 Case 2 D1A (0%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: 1-Jun-07

Project: CO2 Capture Sensitivity Analysis Prepared: 14-Jun-10

Case: Case 2 D1A - GEE IGCC w/o WGS (0% CO2 Capture) x $1, 000

Plant Size: 622.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

5A GAS CLEANUP & PIPING

5A.1 Single Stage Selexol $41,961 $0 $35,605 0 77,565 9.7% $7,501 0% 0 20.0% 17,013 102,080 164

5A.2 Elemental Sulfur Plant $10,055 $2,004 $12,972 0 25,031 9.7% $2,431 0% 0 20.0% 5,493 32,955 53

5A.3 Mercury Removal $1,057 $0 $804 0 1,862 9.7% $180 5% 93 20.0% 427 2,561 4

5A.4 COS Hydrolysis $3,575 $0 $4,668 0 8,243 9.7% $801 0% 0 20.0% 1,809 10,853 17

5A.5 Particulate Removal $0 $0 $0 0 0 0.0% $0 0% 0 20.0% 0 0 0

5A.6 Blowback Gas Systems $1,310 $0 $248 0 1,558 12.2% $190 0% 0 20.0% 350 2,098 3

5A.7 Fuel Gas Piping $0 $688 $482 0 1,170 9.3% $108 0% 0 20.0% 256 1,534 2

5A.9 HGCU Foundations $0 $1,108 $714 0 1,822 9.2% $167 0% 0 30.0% 597 2,586 4

5.9 Open 0 0 0 0 0 0.0% 0 0% 0 20.0% 0 0 0

SUBTOTAL 5A. $57,957 $3,800 $55,494 $0 $117,251 $11,380 $93 $25,944 $154,668 $249

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0

5B.2 CO2 Compression & Drying 0 0 0 0 0 10% 0 0% 0 20.0% 0 0 0

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $85,752 $0 $6,269 0 92,021 9.5% $8,724 5% 4,601 10.0% 10,535 115,881 186

6.2 Syngas Expander $5,928 $0 $819 0 6,747 9.5% $641 0% 0 15.0% 1,108 8,496 14

6.3 Compressed Air Piping $0 $0 $0 0 0 0.0% $0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations $0 $887 $982 0 1,868 9.4% $175 0% 0 30.0% 613 2,656 4

SUBTOTAL 6. $91,679 $887 $8,070 $0 $100,636 $9,540 $4,601 $12,256 $127,033 $204

7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $35,357 $0 $5,027 0 40,384 9.5% $3,840 0% 0 10.0% 4,422 48,646 78

7.2 Open $0 $0 $0 0 0 0.0% $0 0% 0 0.0% 0 0 0

7.3 Ductwork $0 $1,706 $1,217 0 2,923 8.8% $256 0% 0 20.0% 636 3,816 6

7.4 Stack $3,329 $0 $1,250 0 4,579 9.6% $439 0% 0 10.0% 502 5,519 9

7.5 HRSG,Duct & Stack Foundations $0 $667 $640 0 1,307 9.3% $122 0% 0 30.0% 429 1,858 3

SUBTOTAL 7. $38,685 $2,373 $8,136 $0 $49,194 $4,657 $0 $5,989 $59,839 $96

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories $29,111 $0 $4,994 0 34,104 9.6% $3,272 0% 0 10.0% 3,738 41,114 66

8.2 Turbine Plant Auxiliaries $202 $0 $463 0 665 9.8% $65 0% 0 10.0% 73 803 1

8.3 Condenser & Auxiliaries $5,053 $0 $1,484 0 6,537 9.6% $625 0% 0 10.0% 716 7,878 13

8.4 Steam Piping $5,117 $0 $3,600 0 8,717 8.6% $749 0% 0 25.0% 2,367 11,833 19

8.5 TG Foundations $0 $1,001 $1,693 0 2,694 9.5% $255 0% 0 30.0% 885 3,835 6

SUBTOTAL 8. $39,483 $1,001 $12,233 $0 $52,718 $4,967 $0 $7,778 $65,462 $105

9 COOLING WATER SYSTEM

9.1 Cooling Towers $6,699 $0 $1,219 0 7,918 9.5% $754 0% 0 15.0% 1,301 9,973 16

9.2 Circulating Water Pumps $1,737 $0 $122 0 1,859 8.4% $157 0% 0 15.0% 302 2,318 4

9.3 Circ. Water System Auxiliaries $147 $0 $21 0 168 9.5% $16 0% 0 15.0% 28 211 0

9.4 Circ. Water Piping $0 $6,124 $1,588 0 7,712 9.0% $697 0% 0 20.0% 1,682 10,090 16

9.5 Make-up Water System $343 $0 $490 0 833 9.6% $80 0% 0 20.0% 183 1,096 2

9.6 Component Cooling Water System $723 $865 $615 0 2,203 9.4% $206 0% 0 20.0% 482 2,891 5

9.9 Circ. Water System Foundations $0 $2,248 $3,822 0 6,071 9.5% $576 0% 0 30.0% 1,994 8,640 14

SUBTOTAL 9. $9,649 $9,237 $7,877 $0 $26,763 $2,486 $0 $5,971 $35,220 $57

*

Labor Bare Project Cont. TOTAL PLANT COST

Erected 

Eng'g CM H.O. & Process Cont.

Acct No. Item/Description

Equipment 

Cost

Material 

Cost
Carbon Dioxide Capture Sensitivity Analysis

398

Exhibit 4-134 Case 2 D1A (0%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: 1-Jun-07

Project: CO2 Capture Sensitivity Analysis Prepared: 14-Jun-10

Case: Case 2 D1A - GEE IGCC w/o WGS (0% CO2 Capture) x $1, 000

Plant Size: 622.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $11,822 $6,519 $13,243 0 31,584 9.7% $3,048 0% 0 10.0% 3,463 38,095 61

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 0 0 0.0% $0 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 0.0% 0 0 0

10.4 High Temperature Ash Piping $0 $0 $0 0 0 0.0% $0 0% 0 0.0% 0 0 0

10.5 Other Ash Recovery Equipment $0 $0 $0 0 0 0.0% $0 0% 0 0.0% 0 0 0

10.6 Ash Storage Silos $575 $0 $626 0 1,201 9.7% $116 0% 0 15.0% 198 1,515 2

10.7 Ash Transport & Feed Equipment $771 $0 $186 0 957 9.3% $89 0% 0 15.0% 157 1,204 2

10.8 Misc. Ash Handling Equipment $1,191 $1,460 $436 0 3,087 9.5% $294 0% 0 15.0% 507 3,888 6

10.9 Ash/Spent Sorbent Foundation $0 $51 $64 0 115 9.4% $11 0% 0 30.0% 38 163 0

SUBTOTAL 10. $14,359 $8,029 $14,555 $0 $36,943 $3,559 $0 $4,363 $44,864 $72

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $958 $0 $947 0 1,905 9.5% $182 0% 0 10.0% 209 2,296 4

11.2 Station Service Equipment $3,920 $0 $353 0 4,273 9.2% $394 0% 0 10.0% 467 5,134 8

11.3 Switchgear & Motor Control $7,247 $0 $1,318 0 8,565 9.3% $794 0% 0 15.0% 1,404 10,763 17

11.4 Conduit & Cable Tray $0 $3,366 $11,106 0 14,472 9.7% $1,400 0% 0 25.0% 3,968 19,840 32

11.5 Wire & Cable $0 $6,432 $4,226 0 10,658 7.3% $774 0% 0 25.0% 2,858 14,291 23

11.6 Protective Equipment $0 $686 $2,496 0 3,182 9.8% $311 0% 0 15.0% 524 4,017 6

11.7 Standby Equipment $236 $0 $230 0 466 9.5% $44 0% 0 15.0% 77 587 1

11.8 Main Power Transformers $15,862 $0 $146 0 16,008 7.6% $1,211 0% 0 15.0% 2,583 19,801 32

11.9 Electrical Foundations $0 $158 $416 0 574 9.6% $55 0% 0 30.0% 189 818 1

SUBTOTAL 11. $28,222 $10,643 $21,238 $0 $60,103 $5,165 $0 $12,277 $77,546 $125

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 0 0 0.0% $0 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 0.0% 0 0 0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 0 0 0.0% $0 0% 0 0.0% 0 0 0

12.4 Other Major Component Control $1,012 $0 $676 0 1,687 9.5% $160 5% 84 15.0% 290 2,221 4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 0 0 0.0% $0 0% 0 0.0% 0 0 0

12.6 Control Boards, Panels & Racks $233 $0 $149 0 382 9.5% $36 5% 19 20.0% 87 524 1

12.7 Computer Accessories $5,397 $0 $173 0 5,570 9.2% $511 5% 278 10.0% 636 6,995 11

12.8 Instrument Wiring & Tubing $0 $1,885 $3,854 0 5,739 8.5% $487 5% 287 25.0% 1,628 8,141 13

12.9 Other I & C Equipment $3,608 $0 $1,752 0 5,359 9.4% $504 5% 268 15.0% 920 7,051 11

SUBTOTAL 12. $10,249 $1,885 $6,603 $0 $18,737 $1,698 $937 $3,561 $24,933 $40

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $105 $2,246 0 2,351 9.9% $233 0% 0 30.0% 775 3,360 5

13.2 Site Improvements $0 $1,869 $2,483 0 4,352 9.9% $429 0% 0 30.0% 1,435 6,216 10

13.3 Site Facilities $3,349 $0 $3,534 0 6,883 9.9% $679 0% 0 30.0% 2,268 9,830 16

SUBTOTAL 13. $3,349 $1,974 $8,263 $0 $13,586 $1,341 $0 $4,478 $19,405 $31

Labor Bare Project Cont. TOTAL PLANT COST

Erected 

Eng'g CM H.O. & Process Cont.

Acct No. Item/Description

Equipment 

Cost

Material 

Cost
Carbon Dioxide Capture Sensitivity Analysis

399

Exhibit 4-134 Case 2 D1A (0%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: 1-Jun-07

Project: CO2 Capture Sensitivity Analysis Prepared: 27-May-11

Case: Case 2 D1A - GEE IGCC w/o WGS (0% CO2 Capture) x $1, 000

Plant Size: 622.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $265 $150 0 414 8.8% $36 0% 0 20.0% 90 541 1

14.2 Steam Turbine Building $0 $2,446 $3,484 0 5,930 9.2% $546 0% 0 15.0% 971 7,447 12

14.3 Administration Building $0 $845 $613 0 1,459 8.9% $130 0% 0 15.0% 238 1,827 3

14.4 Circulation Water Pumphouse $0 $167 $88 0 255 8.8% $22 0% 0 15.0% 42 319 1

14.5 Water Treatment Buildings $0 $518 $506 0 1,024 9.0% $93 0% 0 15.0% 167 1,284 2

14.6 Machine Shop $0 $433 $296 0 729 8.9% $65 0% 0 15.0% 119 912 1

14.7 Warehouse $0 $699 $451 0 1,149 8.9% $102 0% 0 15.0% 188 1,439 2

14.8 Other Buildings & Structures $0 $418 $326 0 744 8.9% $66 0% 0 20.0% 162 973 2

14.9 Waste Treating Building & Str. $0 $935 $1,787 0 2,723 9.3% $254 0% 0 20.0% 595 3,572 6

SUBTOTAL 14. $0 $6,725 $7,701 $0 $14,427 $1,314 $0 $2,573 $18,313 $29

Total Cost $620,363 $72,516 $257,603 $0 $950,481 $89,310 $31,044 $165,109 $1,235,944 $1,987

Owner's Costs

Preproduction Costs

6 Months All Labor $12,214 $20

1 Month Maintenance Materials $2,742 $4

1 Month Non-fuel Consumables $269 $0

1 Month Waste Disposal $304 $0

25% of 1 Months Fuel Cost at 100% CF $1,627 $3

2% of TPC $24,719 $40

Total $41,874 $67

Inventory Capital

60 day supply of fuel and consumables at 100% CF $13,552 $22

0.5% of TPC (spare parts) $6,180 $10

Total $19,732 $32

Initial Cost for Catalyst and Chemicals $4,892 $8

Land $900 $1

Other Owner's Costs $185,392 $298

Financing Costs $33,370 $54

Total Overnight Costs (TOC) $1,522,105 $2,446.9

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $1,735,200 $2,790

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont. TOTAL PLANT COST

Erected 

Eng'g CM H.O. & Process Cont.
Carbon Dioxide Capture Sensitivity Analysis

400

Exhibit 4-135 Case 2 D1A Initial and Annual O&M Expenses

Case: Case 2 D1A - GEE IGCC w/o WGS (0% CO2 Capture)

Plant Size (MWe): 622.05 Heat Rate (Btu/kWh): 8,756

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.80

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun-07 TPI Year: 2015

Capacity Factor (%): 80 CO2 Captured (TPD): 0

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 9.0 9.0

Foreman 1.0 1.0

Lab Tech's etc. 3.0 3.0

TOTAL Operating Jobs 15.0 15.0

$ $/kW-net

Annual Operating Labor Cost (calc'd) $5,918,913 $9.515

Maintenance Labor Cost (calc'd) $13,622,877 $21.900

Administrative & Support Labor (calc'd) $4,885,447 $7.854

Property Taxes and Insurance $24,718,883 $39.738

TOTAL FIXED OPERATING COSTS $49,146,120 $79.007

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $26,322,759 0.00604

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 3,409 1.08 $0 $1,076,793 0.00025

Chemicals

MU & WT Chem. (lbs) 0 20,311 0.17 $0 $1,026,436 0.00024

Carbon (Mercury Removal) (lb) 54,833 75 1.05 $57,584 $23,034 0.00001

COS Catalyst (m3) 422 0.29 2,397.36 $1,011,578 $202,316 0.00005

Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 0.00000

Selexol Solution (gal) 285,358 45 13.40 $3,823,295 $175,961 0.00004

SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000

Claus Catalyst (ft3) w/equip. 1.94 131.27 $0 $74,422 0.00002

Subtotal Chemicals $4,892,457 $1,502,168 0.00034

Other

 Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

Gases, N2 etc. (/100scf) 0 0.00 0.00 $0 $0 0.00000

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $0 0.00000

Waste Disposal

 Spent Mercury Sorbent (lb) 0 75 0.42 $0 $9,148 0.00000

 Flyash (ton) 0 0 0.00 $0 $0 0.00000

 Slag (ton) 0 615 16.23 $0 $2,912,403 0.00067

Subtotal Solid Waste Disposal $0 $2,921,551 0.00067

By-products & Emissions

 Sulfur (tons) 0 140 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 0.00000

TOTAL VARIABLE OPERATING COSTS $31,823,271 0.00730

Coal FUEL (tons) 0 5,603 38.19 $0 $62,471,741 0.01433

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

401

Exhibit 4-136 Case 2 D1B (25%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D1B - GEE IGCC w/o WGS (25% CO2 Capture) x $1, 000

Plant Size: 607.19 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload $3,633 $0 $1,775 $0 $5,408 9.0% $484 0% $0 20.0% $1,179 $7,072 $12

1.2 Coal Stackout & Reclaim $4,695 $0 $1,138 $0 $5,833 8.8% $511 0% $0 20.0% $1,269 $7,613 $13

1.3 Coal Conveyors & Yd Crus $4,365 $0 $1,126 $0 $5,491 8.8% $482 0% $0 20.0% $1,195 $7,168 $12

1.4 Other Coal Handling $1,142 $0 $261 $0 $1,403 8.8% $123 0% $0 20.0% $305 $1,830 $3

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $2,571 $6,428 $0 $8,999 9.6% $863 0% $0 20.0% $1,972 $11,834 $19

SUBTOTAL 1. $13,835 $2,571 $10,729 $0 $27,134 $2,463 $0 $5,919 $35,516 $58

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,549 $371 $243 $0 $2,162 8.6% 185 0% 0 20.0% $469 $2,816 $5

2.3 Slurry Prep & Feed $21,171 $0 $9,346 $0 $30,517 9.1% 2,773 5% 1,526 20.0% $6,963 $41,778 $69

2.4 Misc. Coal Prep & Feed $852 $620 $1,858 $0 $3,329 9.2% 306 0% 0 20.0% $727 $4,362 $7

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $3,310 $2,717 $0 $6,027 9.3% 558 0% 0 20.0% $1,317 $7,903 $13

SUBTOTAL 2. $23,571 $4,300 $14,165 $0 $42,035 $3,822 $1,526 $9,477 $56,860 $94

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 2,865 4,919 2,597 0 10,381 9.3% 962 0% 0 20.0% $2,269 $13,611 $22

3.2 Water Makeup & Pretreating 616 64 344 0 1,024 9.5% 98 0% 0 30.0% $337 $1,459 $2

3.3 Other Feedwater Subsystems 1,567 530 477 0 2,574 9.0% 231 0% 0 20.0% $561 $3,366 $6

3.4 Service Water Systems 352 726 2,519 0 3,597 9.8% 351 0% 0 30.0% $1,184 $5,132 $8

3.5 Other Boiler Plant Systems 1,891 733 1,816 0 4,441 9.5% 421 0% 0 20.0% $972 $5,834 $10

3.6 FO Supply Sys & Nat Gas $311 $588 $549 $0 1,448 9.6% 139 0% 0 20.0% $318 $1,905 $3

3.7 Waste Treatment Equipment 861 0 525 0 1,386 9.7% 135 0% 0 30.0% $456 $1,977 $3

3.8 Misc. Power Plant Equipment $1,107 $148 $569 $0 1,824 9.7% 176 0% 0 30.0% $600 $2,600 $4

SUBTOTAL 3. $9,571 $7,709 $9,395 $0 $26,675 $2,513 $0 $6,697 $35,885 $59

4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $109,860 $0 $60,195 $0 $170,055 9.2% $15,578 13.9% $23,600 15.3% $32,083 $241,316 $397

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.3 ASU/Oxidant Compression $186,270 $0 w/equip. $0 $186,270 9.7% $18,055 0% $0 10.0% $20,433 $224,758 $370

4.4 Scrubber & Low Temperature Cooling 5,837 $4,751 $4,944 $0 $15,532 9.6% $1,491 0% $0 20.0% $3,405 $20,428 $34

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.6 Soot Recovery & SARU $1,780 $845 $1,671 $0 $4,296 9.6% $414 0% $0 20.0% $942 $5,652 $9

4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.8 Gasification Foundations $0 $6,258 $5,224 $0 $11,481 9.3% $1,064 0% $0 25.0% $3,136 $15,682 $26

SUBTOTAL 4. $303,747 $11,853 $72,034 $0 $387,634 $36,603 $23,600 $59,998 $507,835 $836

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

402

Exhibit 4-136 Case 2 D1B (25%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D1B - GEE IGCC w/o WGS (25% CO2 Capture) x $1, 000

Plant Size: 607.19 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $53,610 $0 $45,490 $0 $99,100 9.7% $9,584 20% $19,820 20.0% $25,701 $154,205 $254

5A.2 Elemental Sulfur Plant $9,987 $1,990 $12,884 $0 $24,861 9.7% $2,415 0% $0 20.0% $5,455 $32,732 $54

5A.3 Mercury Removal $1,063 $0 $809 $0 $1,872 9.7% $181 5% $94 20.0% $429 $2,576 $4

5A.4 COS Hydrolysis $3,549 $0 $4,635 $0 $8,184 9.7% $796 0% $0 20.0% $1,796 $10,776 $18

5A.5 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0

5A.6 Blowback Gas Systems $1,302 $0 $247 $0 $1,549 12.2% $189 0% $0 20.0% $348 $2,085 $3

5A.7 Fuel Gas Piping $0 $599 $419 $0 $1,018 9.3% $94 0% $0 20.0% $222 $1,335 $2

5A.9 HGCU Foundations $0 $617 $398 $0 $1,015 9.2% $93 0% $0 30.0% $332 $1,440 $2

5.9 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

SUBTOTAL 5A. $69,511 $3,206 $64,882 $0 $137,599 $13,352 $19,914 $34,284 $205,149 $338

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0

5B.2 CO2 Compression & Drying $5,766 $0 $3,534 $0 $9,300 9.6% $896 0% $0 20.0% $2,039 $12,235 $20

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $5,766 $0 $3,534 $0 $9,300 $896 $0 $2,039 $12,235 $20

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 213

6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 13

6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 4

SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $231

7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $34,760 $0 $4,942 $0 $39,702 9.5% $3,775 0% $0 10.0% $4,348 $47,825 $79

7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

7.3 Ductwork $0 $1,711 $1,221 $0 $2,932 8.8% $257 0% $0 20.0% $638 $3,827 $6

7.4 Stack $3,338 $0 $1,254 $0 $4,592 9.6% $440 0% $0 10.0% $503 $5,535 $9

7.9 HRSG, Duct & Stack Foundations $0 $669 $642 $0 $1,311 9.3% $122 0% $0 30.0% $430 $1,863 $3

SUBTOTAL 7. $38,098 $2,380 $8,060 $0 $48,537 $4,594 $0 $5,919 $59,050 $97

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories $29,446 $0 $5,034 $0 $34,480 9.6% $3,308 0% $0 10.0% $3,779 $41,567 $68

8.2 Turbine Plant Auxiliaries $204 $0 $468 $0 $672 9.8% $66 0% $0 10.0% $74 $811 $1

8.3 Condenser & Auxiliaries $5,250 $0 $1,541 $0 $6,792 9.6% $649 0% $0 10.0% $744 $8,185 $13

8.4 Steam Piping $5,058 $0 $3,558 $0 $8,616 8.6% $740 0% $0 25.0% $2,339 $11,696 $19

8.9 TG Foundations $0 $1,012 $1,711 $0 $2,723 9.5% $258 0% $0 30.0% $894 $3,876 $6

SUBTOTAL 8. $39,958 $1,012 $12,313 $0 $53,283 $5,022 $0 $7,830 $66,135 $109

9 COOLING WATER SYSTEM

9.1 Cooling Towers $6,657 $0 $1,211 $0 $7,868 9.5% $749 0% $0 15.0% $1,293 $9,910 $16

9.2 Circulating Water Pumps $1,722 $0 $124 $0 $1,847 8.4% $156 0% $0 15.0% $300 $2,303 $4

9.3 Circ. Water System Auxiliaries $146 $0 $21 $0 $167 9.5% $16 0% $0 15.0% $27 $210 $0

9.4 Circ. Water Piping $0 $6,091 $1,579 $0 $7,670 9.0% $693 0% $0 20.0% $1,673 $10,036 $17

9.5 Make-up Water System $341 $0 $488 $0 $829 9.6% $80 0% $0 20.0% $182 $1,090 $2

9.6 Component Cooling Water System $719 $860 $612 $0 $2,191 9.4% $205 0% $0 20.0% $479 $2,875 $5

9.9 Circ. Water System Foundations $0 $2,236 $3,801 $0 $6,036 9.5% $572 0% $0 30.0% $1,983 $8,591 $14

SUBTOTAL 9. $9,586 $9,186 $7,836 $0 $26,608 $2,471 $0 $5,937 $35,015 $58

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*
Carbon Dioxide Capture Sensitivity Analysis

403

Exhibit 4-136 Case 2 D1B (25%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D1B - GEE IGCC w/o WGS (25% CO2 Capture) x $1, 000

Plant Size: 607.19 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $11,758 $6,483 $13,171 $0 $31,412 9.7% $3,032 0% $0 10.0% $3,444 $37,888 $62

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.6 Ash Storage Silos $572 $0 $622 $0 $1,194 9.7% $116 0% $0 15.0% $197 $1,507 $2

10.7 Ash Transport & Feed Equipment $767 $0 $185 $0 $952 9.3% $89 0% $0 15.0% $156 $1,197 $2

10.8 Misc. Ash Handling Equipment $1,185 $1,452 $434 $0 $3,071 9.5% $292 0% $0 15.0% $504 $3,867 $6

10.9 Ash/Spent Sorbent Foundation $0 $51 $64 $0 $114 9.4% $11 0% $0 30.0% $37 $162 $0

SUBTOTAL 10. $14,282 $7,986 $14,476 $0 $36,744 $3,539 $0 $4,339 $44,622 $73

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $961 $0 $951 $0 $1,912 9.5% $183 0% $0 10.0% $209 $2,303 $4

11.2 Station Service Equipment $4,150 $0 $374 $0 $4,524 9.2% $417 0% $0 10.0% $494 $5,435 $9

11.3 Switchgear & Motor Control $7,672 $0 $1,395 $0 $9,067 9.3% $841 0% $0 15.0% $1,486 $11,394 $19

11.4 Conduit & Cable Tray $0 $3,564 $11,756 $0 $15,320 9.7% $1,482 0% $0 25.0% $4,200 $21,002 $35

11.5 Wire & Cable $0 $6,809 $4,474 $0 $11,283 7.3% $820 0% $0 25.0% $3,026 $15,128 $25

11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7

11.7 Standby Equipment $236 $0 $231 $0 $467 9.5% $45 0% $0 15.0% $77 $588 $1

11.8 Main Power Transformers $17,787 $0 $146 $0 $17,934 7.6% $1,356 0% $0 15.0% $2,894 $22,184 $37

11.9 Electrical Foundations $0 $159 $417 $0 $577 9.6% $55 0% $0 30.0% $190 $821 $1

SUBTOTAL 11. $30,806 $11,218 $22,240 $0 $64,264 $5,509 $0 $13,099 $82,872 $136

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.4 Other Major Component Control $1,045 $0 $698 $0 $1,743 9.5% $165 5% $87 15.0% $299 $2,294 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.6 Control Boards,Panels & Racks $240 $0 $154 $0 $394 9.5% $37 5% $20 20.0% $90 $541 $1

12.7 Computer & Accessories $5,574 $0 $178 $0 $5,752 9.2% $528 5% $288 10.0% $657 $7,224 $12

12.8 Instrument Wiring & Tubing $0 $1,947 $3,980 $0 $5,928 8.5% $503 5% $296 25.0% $1,682 $8,408 $14

12.9 Other I & C Equipment $3,726 $0 $1,809 $0 $5,535 9.4% $521 5% $277 15.0% $950 $7,282 $12

SUBTOTAL 12. $10,584 $1,947 $6,820 $0 $19,351 $1,754 $968 $3,678 $25,750 $42

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 108 2,297 0 2,405 9.9% 239 0% 0 30.0% 793 3,436 6

13.2 Site Improvements 0 1,912 2,540 0 4,452 9.9% 439 0% 0 30.0% 1,467 6,358 10

13.3 Site Facilities 3,426 0 3,615 0 7,040 9.9% 694 0% 0 30.0% 2,320 10,054 17

SUBTOTAL 13. $3,426 $2,019 $8,452 $0 $13,897 $1,372 $0 $4,581 $19,849 $33

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

404

Exhibit 4-136 Case 2 D1B (25%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D1B - GEE IGCC w/o WGS (25% CO2 Capture) x $1, 000

Plant Size: 607.19 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $263 $149 $0 $412 8.8% $36 0% $0 20.0% $90 $539 $1

14.2 Steam Turbine Building $0 $2,361 $3,363 $0 $5,724 9.2% $527 0% $0 15.0% $938 $7,188 $12

14.3 Administration Building $0 $875 $634 $0 $1,509 8.9% $134 0% $0 15.0% $246 $1,890 $3

14.4 Circulation Water Pumphouse $0 $156 $82 $0 $238 8.8% $21 0% $0 15.0% $39 $298 $0

14.5 Water Treatment Buildings $0 $520 $508 $0 $1,028 9.0% $93 0% $0 15.0% $168 $1,289 $2

14.6 Machine Shop $0 $448 $306 $0 $754 8.9% $67 0% $0 15.0% $123 $944 $2

14.7 Warehouse $0 $723 $467 $0 $1,189 8.9% $105 0% $0 15.0% $194 $1,489 $2

14.8 Other Buildings & Structures $0 $433 $337 $0 $770 8.9% $69 0% $0 20.0% $168 $1,006 $2

14.9 Waste Treating Building & Str. $0 $961 $1,837 $0 $2,799 9.3% $261 0% $0 20.0% $612 $3,672 $6

SUBTOTAL 14. $0 $6,739 $7,684 $0 $14,423 $1,313 $0 $2,578 $18,314 $30

Total Cost $670,315 $73,013 $270,950 $0 $1,014,278 $95,346 $55,868 $179,806 $1,345,298 $2,216

Owner's Costs

Preproduction Costs

6 Months All Labor $12,712 $21

1 Month Maintenance Materials $2,754 $5

1 Month Non-fuel Consumables $273 $0

1 Month Waste Disposal $302 $0

25% of 1 Months Fuel Cost at 100% CF $1,612 $3

2% of TPC $26,906 $44

Total $44,559 $73

Inventory Capital

60 day supply of fuel and consumables at 100% CF $13,445 $22

0.5% of TPC (spare parts) $6,726 $11

Total $20,171 $33

Initial Cost for Catalyst and Chemicals $4,931 $8

Land $900 $1

Other Owner's Costs $201,795 $332

Financing Costs $36,323 $60

Total Overnight Costs (TOC) $1,653,977 $2,724.0

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $1,885,534 $3,105

Labor Bare 

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Project Cont.
Carbon Dioxide Capture Sensitivity Analysis

405

Exhibit 4-137 Case 2 D1B Initial and Annual O&M Expenses

Case: Case 2 D1B - GEE IGCC w/o WGS (25% CO2 Capture)

Plant Size (MWe): 607.19 Heat Rate (Btu/kWh): 8,891

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 80 CO2 Captured (TPD): 3,094

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 10.0 10.0

Foreman 1.0 1.0

Lab Tech's etc. 3.0 3.0

TOTAL Operating Jobs 16.0 16.0

$ $/kW-net

Annual Operating Labor Cost (calc'd) $6,313,507 $10.398

Maintenance Labor Cost (calc'd) $14,025,931 $23.100

Administrative & Support Labor (calc'd) $5,084,860 $8.374

Property Taxes & Insurance $26,905,955 $44.312

TOTAL FIXED OPERATING COSTS $52,330,253 $86.184

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $26,440,810 0.00621

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 3,378 1.08 $0 $1,067,015 0.00025

Chemicals

MU & WT Chem. (lbs) 0 20,127 0.17 $0 $1,017,114 0.00024

Carbon (Mercury Removal) (lb) 55,194 95 1.05 $57,963 $29,132 0.00001

COS Catalyst (m3) 418 0.29 2,397.36 $1,001,137 $200,227 0.00005

Water Gas Shift Catalyst (ft3) 0 0.00 498.83 $0 $0 0.00000

Selexol Solution (gal) 289,013 59 13.40 $3,872,261 $230,395 0.00005

SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000

Claus Catalyst (ft3) 0 1.92 131.27 $0 $73,424 0.00002

Subtotal Chemicals $4,931,362 $1,550,292 0.00036

Other

Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $0 0.00000

Waste Disposal

Spent Mercury Sorbent (lb) 0 95 0.42 $0 $11,651 0.00000

Flyash (ton) 0 0 0.00 $0 $0 0.00000

Slag (ton) 0 609 16.23 $0 $2,886,534 0.00068

Subtotal Solid Waste Disposal $0 $2,898,185 $0

By-products & Emissions

Sulfur (tons) 0 139 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $31,956,302 0.00751

Coal FUEL (tons) 0 5,553 38.19 $0 $61,916,574 0.01455

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

406

Exhibit 4-138 Case 2 D2A (25%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2A - GEE IGCC w/ one WGS bypass (25% CO2 Capture) x $1, 000

Plant Size: 607.03 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload $3,634 $0 $1,776 $0 $5,409 9.0% $485 0% $0 20.0% $1,179 $7,073 $12

1.2 Coal Stackout & Reclaim $4,695 $0 $1,138 $0 $5,834 8.8% $511 0% $0 20.0% $1,269 $7,614 $13

1.3 Coal Conveyors & Yd Crus $4,365 $0 $1,126 $0 $5,492 8.8% $482 0% $0 20.0% $1,195 $7,169 $12

1.4 Other Coal Handling $1,142 $0 $261 $0 $1,403 8.8% $123 0% $0 20.0% $305 $1,831 $3

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $2,571 $6,429 $0 $9,001 9.6% $863 0% $0 20.0% $1,973 $11,836 $19

SUBTOTAL 1. $13,837 $2,571 $10,730 $0 $27,138 $2,463 $0 $5,920 $35,522 $59

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,549 $371 $243 $0 $2,162 8.6% 185 0% 0 20.0% $469 $2,817 $5

2.3 Slurry Prep & Feed $21,174 $0 $9,348 $0 $30,522 9.1% 2,773 5% 1,526 20.0% $6,964 $41,785 $69

2.4 Misc. Coal Prep & Feed $852 $620 $1,858 $0 $3,330 9.2% 306 0% 0 20.0% $727 $4,363 $7

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $3,310 $2,718 $0 $6,028 9.3% 558 0% 0 20.0% $1,317 $7,904 $13

SUBTOTAL 2. $23,574 $4,301 $14,167 $0 $42,042 $3,822 $1,526 $9,478 $56,868 $94

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 2,865 4,920 2,597 0 10,381 9.3% 962 0% 0 20.0% $2,269 $13,612 $22

3.2 Water Makeup & Pretreating 616 64 345 0 1,025 9.5% 98 0% 0 30.0% $337 $1,460 $2

3.3 Other Feedwater Subsystems 1,567 530 477 0 2,574 9.0% 231 0% 0 20.0% $561 $3,366 $6

3.4 Service Water Systems 353 726 2,521 0 3,600 9.8% 351 0% 0 30.0% $1,185 $5,136 $8

3.5 Other Boiler Plant Systems 1,893 733 1,818 0 4,444 9.5% 422 0% 0 20.0% $973 $5,839 $10

3.6 FO Supply Sys & Nat Gas $311 $588 $549 $0 1,448 9.6% 140 0% 0 20.0% $318 $1,905 $3

3.7 Waste Treatment Equipment 862 0 526 0 1,387 9.7% 135 0% 0 30.0% $457 $1,979 $3

3.8 Misc. Power Plant Equipment $1,107 $148 $569 $0 1,824 9.7% 176 0% 0 30.0% $600 $2,600 $4

SUBTOTAL 3. $9,574 $7,710 $9,399 $0 $26,684 $2,514 $0 $6,699 $35,897 $59

4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $109,878 $0 $60,205 $0 $170,083 9.2% $15,581 13.9% $23,604 15.3% $32,088 $241,356 $398

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.3 ASU/Oxidant Compression $186,300 $0 w/equip. $0 $186,300 9.7% $18,058 0% $0 10.0% $20,436 $224,794 $370

4.4 Scrubber & Low Temperature Cooling 5,838 $4,751 $4,945 $0 $15,534 9.6% $1,492 0% $0 20.0% $3,405 $20,431 $34

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.6 Soot Recovery & SARU $1,780 $845 $1,671 $0 $4,296 9.6% $414 0% $0 20.0% $942 $5,652 $9

4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.8 Gasification Foundations $0 $6,259 $5,225 $0 $11,483 9.3% $1,064 0% $0 25.0% $3,137 $15,684 $26

SUBTOTAL 4. $303,796 $11,855 $72,046 $0 $387,697 $36,609 $23,604 $60,008 $507,918 $837

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

407

Exhibit 4-138 Case 2 D2A (25%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2A - GEE IGCC w/ one WGS bypass (25% CO2 Capture) x $1, 000

Plant Size: 607.03 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $53,677 $0 $45,546 $0 $99,223 9.7% $9,596 20% $19,845 20.0% $25,733 $154,396 $254

5A.2 Elemental Sulfur Plant $9,988 $1,991 $12,886 $0 $24,864 9.7% $2,415 0% $0 20.0% $5,456 $32,735 $54

5A.3 Mercury Removal $1,064 $0 $810 $0 $1,874 9.7% $181 5% $94 20.0% $430 $2,579 $4

5A.4 Shift Reactors $156 $0 $63 $0 $219 9.6% $21 0% $0 20.0% $48 $288 $0

5A.5 COS Hydrolysis $3,554 $0 $4,642 $0 $8,196 9.7% $797 0% $0 20.0% $1,799 $10,791 $18

5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0

5A.7 Blowback Gas Systems $1,302 $0 $247 $0 $1,549 12.2% $189 0% $0 20.0% $348 $2,085 $3

5A.8 Fuel Gas Piping $0 $599 $419 $0 $1,018 9.3% $94 0% $0 20.0% $223 $1,335 $2

5A.9 HGCU Foundations $0 $617 $398 $0 $1,015 9.2% $93 0% $0 30.0% $332 $1,440 $2

5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

SUBTOTAL 5A. $69,741 $3,206 $65,010 $0 $137,958 $13,387 $19,938 $34,367 $205,650 $339

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0

5B.2 CO2 Compression & Drying $5,818 $0 $3,566 $0 $9,384 9.6% $904 0% $0 20.0% $2,058 $12,346 $20

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $5,818 $0 $3,566 $0 $9,384 $904 $0 $2,058 $12,346 $20

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 213

6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 13

6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 4

SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $231

7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $34,760 $0 $4,942 $0 $39,702 9.5% $3,775 0% $0 10.0% $4,348 $47,825 $79

7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

7.3 Ductwork $0 $1,711 $1,221 $0 $2,932 8.8% $257 0% $0 20.0% $638 $3,827 $6

7.4 Stack $3,338 $0 $1,254 $0 $4,592 9.6% $440 0% $0 10.0% $503 $5,535 $9

7.9 HRSG, Duct & Stack Foundations $0 $669 $642 $0 $1,311 9.3% $122 0% $0 30.0% $430 $1,863 $3

SUBTOTAL 7. $38,098 $2,380 $8,060 $0 $48,538 $4,594 $0 $5,919 $59,050 $97

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories $29,446 $0 $5,034 $0 $34,480 9.6% $3,308 0% $0 10.0% $3,779 $41,567 $68

8.2 Turbine Plant Auxiliaries $204 $0 $468 $0 $672 9.8% $66 0% $0 10.0% $74 $811 $1

8.3 Condenser & Auxiliaries $5,250 $0 $1,541 $0 $6,792 9.6% $649 0% $0 10.0% $744 $8,185 $13

8.4 Steam Piping $5,058 $0 $3,558 $0 $8,617 8.6% $740 0% $0 25.0% $2,339 $11,696 $19

8.9 TG Foundations $0 $1,012 $1,711 $0 $2,723 9.5% $258 0% $0 30.0% $894 $3,876 $6

SUBTOTAL 8. $39,958 $1,012 $12,313 $0 $53,283 $5,022 $0 $7,830 $66,135 $109

9 COOLING WATER SYSTEM

9.1 Cooling Towers $6,657 $0 $1,211 $0 $7,868 9.5% $749 0% $0 15.0% $1,293 $9,910 $16

9.2 Circulating Water Pumps $1,722 $0 $124 $0 $1,847 8.4% $156 0% $0 15.0% $300 $2,303 $4

9.3 Circ. Water System Auxiliaries $146 $0 $21 $0 $167 9.5% $16 0% $0 15.0% $27 $210 $0

9.4 Circ. Water Piping $0 $6,091 $1,579 $0 $7,670 9.0% $693 0% $0 20.0% $1,673 $10,036 $17

9.5 Make-up Water System $341 $0 $488 $0 $829 9.6% $80 0% $0 20.0% $182 $1,091 $2

9.6 Component Cooling Water System $719 $860 $612 $0 $2,191 9.4% $205 0% $0 20.0% $479 $2,875 $5

9.9 Circ. Water System Foundations $0 $2,236 $3,801 $0 $6,036 9.5% $572 0% $0 30.0% $1,983 $8,591 $14

SUBTOTAL 9. $9,586 $9,186 $7,836 $0 $26,608 $2,471 $0 $5,937 $35,016 $58

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*
Carbon Dioxide Capture Sensitivity Analysis

408

Exhibit 4-138 Case 2 D2A (25%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2A - GEE IGCC w/ one WGS bypass (25% CO2 Capture) x $1, 000

Plant Size: 607.03 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $11,759 $6,484 $13,173 $0 $31,417 9.7% $3,032 0% $0 10.0% $3,445 $37,894 $62

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.6 Ash Storage Silos $572 $0 $623 $0 $1,195 9.7% $116 0% $0 15.0% $197 $1,507 $2

10.7 Ash Transport & Feed Equipment $767 $0 $185 $0 $952 9.3% $89 0% $0 15.0% $156 $1,198 $2

10.8 Misc. Ash Handling Equipment $1,185 $1,452 $434 $0 $3,071 9.5% $292 0% $0 15.0% $505 $3,868 $6

10.9 Ash/Spent Sorbent Foundation $0 $51 $64 $0 $114 9.4% $11 0% $0 30.0% $37 $162 $0

SUBTOTAL 10. $14,284 $7,987 $14,478 $0 $36,749 $3,540 $0 $4,340 $44,629 $74

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $961 $0 $951 $0 $1,912 9.5% $183 0% $0 10.0% $209 $2,303 $4

11.2 Station Service Equipment $4,152 $0 $374 $0 $4,526 9.2% $417 0% $0 10.0% $494 $5,437 $9

11.3 Switchgear & Motor Control $7,675 $0 $1,396 $0 $9,071 9.3% $841 0% $0 15.0% $1,487 $11,400 $19

11.4 Conduit & Cable Tray $0 $3,565 $11,762 $0 $15,328 9.7% $1,483 0% $0 25.0% $4,203 $21,013 $35

11.5 Wire & Cable $0 $6,812 $4,476 $0 $11,289 7.3% $820 0% $0 25.0% $3,027 $15,136 $25

11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7

11.7 Standby Equipment $236 $0 $231 $0 $467 9.5% $45 0% $0 15.0% $77 $588 $1

11.8 Main Power Transformers $17,787 $0 $146 $0 $17,934 7.6% $1,356 0% $0 15.0% $2,894 $22,184 $37

11.9 Electrical Foundations $0 $159 $417 $0 $577 9.6% $55 0% $0 30.0% $190 $821 $1

SUBTOTAL 11. $30,812 $11,223 $22,249 $0 $64,284 $5,510 $0 $13,104 $82,899 $137

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.4 Other Major Component Control $1,045 $0 $698 $0 $1,743 9.5% $165 5% $87 15.0% $299 $2,294 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.6 Control Boards,Panels & Racks $240 $0 $154 $0 $394 9.5% $37 5% $20 20.0% $90 $541 $1

12.7 Computer & Accessories $5,575 $0 $178 $0 $5,754 9.2% $528 5% $288 10.0% $657 $7,227 $12

12.8 Instrument Wiring & Tubing $0 $1,948 $3,982 $0 $5,929 8.5% $503 5% $296 25.0% $1,682 $8,411 $14

12.9 Other I & C Equipment $3,727 $0 $1,810 $0 $5,537 9.4% $521 5% $277 15.0% $950 $7,285 $12

SUBTOTAL 12. $10,588 $1,948 $6,822 $0 $19,357 $1,754 $968 $3,679 $25,758 $42

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 108 2,297 0 2,405 9.9% 239 0% 0 30.0% 793 3,437 6

13.2 Site Improvements 0 1,912 2,541 0 4,452 9.9% 439 0% 0 30.0% 1,467 6,359 10

13.3 Site Facilities 3,426 0 3,615 0 7,041 9.9% 694 0% 0 30.0% 2,320 10,055 17

SUBTOTAL 13. $3,426 $2,019 $8,453 $0 $13,898 $1,372 $0 $4,581 $19,851 $33

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

409

Exhibit 4-138 Case 2 D2A (25%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D2A - GEE IGCC w/ one WGS bypass (25% CO2 Capture) x $1, 000

Plant Size: 607.03 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $263 $149 $0 $412 8.8% $36 0% $0 20.0% $90 $539 $1

14.2 Steam Turbine Building $0 $2,361 $3,363 $0 $5,724 9.2% $527 0% $0 15.0% $938 $7,188 $12

14.3 Administration Building $0 $875 $634 $0 $1,509 8.9% $134 0% $0 15.0% $247 $1,890 $3

14.4 Circulation Water Pumphouse $0 $156 $82 $0 $238 8.8% $21 0% $0 15.0% $39 $298 $0

14.5 Water Treatment Buildings $0 $521 $508 $0 $1,029 9.0% $93 0% $0 15.0% $168 $1,290 $2

14.6 Machine Shop $0 $448 $306 $0 $754 8.9% $67 0% $0 15.0% $123 $944 $2

14.7 Warehouse $0 $723 $467 $0 $1,189 8.9% $105 0% $0 15.0% $194 $1,489 $2

14.8 Other Buildings & Structures $0 $433 $337 $0 $770 8.9% $69 0% $0 20.0% $168 $1,006 $2

14.9 Waste Treating Building & Str. $0 $962 $1,838 $0 $2,799 9.3% $261 0% $0 20.0% $612 $3,672 $6

SUBTOTAL 14. $0 $6,740 $7,685 $0 $14,425 $1,313 $0 $2,578 $18,316 $30

Total Cost $670,668 $73,026 $271,145 $0 $1,014,840 $95,399 $55,897 $179,930 $1,346,066 $2,217

Owner's Costs

Preproduction Costs

6 Months All Labor $12,717 $21

1 Month Maintenance Materials $2,756 $5

1 Month Non-fuel Consumables $273 $0

1 Month Waste Disposal $302 $0

25% of 1 Months Fuel Cost at 100% CF $1,613 $3

2% of TPC $26,921 $44

Total $44,582 $73

Inventory Capital

60 day supply of fuel and consumables at 100% CF $13,449 $22

0.5% of TPC (spare parts) $6,730 $11

Total $20,179 $33

Initial Cost for Catalyst and Chemicals $4,945 $8

Land $900 $1

Other Owner's Costs $201,910 $333

Financing Costs $36,344 $60

Total Overnight Costs (TOC) $1,654,925 $2,726.3

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $1,886,615 $3,108

Labor Bare 

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Project Cont.
Carbon Dioxide Capture Sensitivity Analysis

410

Exhibit 4-139 Case 2 D2A Initial and Annual O&M Expenses

Case: Case 2 D2A - GEE IGCC w/ one WGS bypass (25% CO2 Capture)

Plant Size (MWe): 607.03 Heat Rate (Btu/kWh): 8,895

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 80 CO2 Captured (TPD): 3,129

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 10.0 10.0

Foreman 1.0 1.0

Lab Tech's etc. 3.0 3.0

TOTAL Operating Jobs 16.0 16.0

$ $/kW-net

Annual Operating Labor Cost (calc'd) $6,313,507 $10.401

Maintenance Labor Cost (calc'd) $14,033,692 $23.119

Administrative & Support Labor (calc'd) $5,086,800 $8.380

Property Taxes & Insurance $26,921,314 $44.350

TOTAL FIXED OPERATING COSTS $52,355,313 $86.249

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $26,455,440 0.00622

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 3,382 1.08 $0 $1,068,152 0.00025

Chemicals

MU & WT Chem. (lbs) 0 20,148 0.17 $0 $1,018,198 0.00024

Carbon (Mercury Removal) (lb) 55,299 95 1.05 $58,073 $29,132 0.00001

COS Catalyst (m3) 419 0.29 2,397.36 $1,003,295 $200,659 0.00005

Water Gas Shift Catalyst (ft3) 23 0.02 498.83 $11,473 $2,295 0.00000

Selexol Solution (gal) 289,013 59 13.40 $3,872,261 $230,395 0.00005

SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000

Claus Catalyst (ft3) 0 1.92 131.27 $0 $73,436 0.00002

Subtotal Chemicals $4,945,103 $1,554,114 0.00037

Other

Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $0 0.00000

Waste Disposal

Spent Mercury Sorbent (lb) 0 95 0.42 $0 $11,651 0.00000

Flyash (ton) 0 0 0.00 $0 $0 0.00000

Slag (ton) 0 609 16.23 $0 $2,887,216 0.00068

Subtotal Solid Waste Disposal $0 $2,898,867 $0

By-products & Emissions

Sulfur (tons) 0 139 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $31,976,573 0.00752

Coal FUEL (tons) 0 5,554 38.19 $0 $61,931,158 0.01456

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

411

Exhibit 4-140 Case 2 D2B (45%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2B - GEE IGCC w/ one WGS bypass (45% CO2 Capture) x $1, 000

Plant Size: 590.80 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload $3,669 $0 $1,793 $0 $5,462 9.0% $489 0% $0 20.0% $1,190 $7,141 $12

1.2 Coal Stackout & Reclaim $4,741 $0 $1,149 $0 $5,890 8.8% $516 0% $0 20.0% $1,281 $7,688 $13

1.3 Coal Conveyors & Yd Crus $4,408 $0 $1,137 $0 $5,545 8.8% $487 0% $0 20.0% $1,206 $7,238 $12

1.4 Other Coal Handling $1,153 $0 $263 $0 $1,416 8.8% $124 0% $0 20.0% $308 $1,848 $3

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $2,596 $6,492 $0 $9,088 9.6% $871 0% $0 20.0% $1,992 $11,951 $20

SUBTOTAL 1. $13,971 $2,596 $10,834 $0 $27,401 $2,487 $0 $5,978 $35,866 $61

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,565 $374 $245 $0 $2,185 8.6% 187 0% 0 20.0% $474 $2,846 $5

2.3 Slurry Prep & Feed $21,396 $0 $9,444 $0 $30,840 9.1% 2,802 5% 1,542 20.0% $7,037 $42,221 $71

2.4 Misc. Coal Prep & Feed $860 $626 $1,877 $0 $3,364 9.2% 309 0% 0 20.0% $735 $4,408 $7

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $3,345 $2,746 $0 $6,091 9.3% 564 0% 0 20.0% $1,331 $7,986 $14

SUBTOTAL 2. $23,821 $4,345 $14,313 $0 $42,479 $3,862 $1,542 $9,577 $57,460 $97

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 2,859 4,909 2,592 0 10,360 9.3% 960 0% 0 20.0% $2,264 $13,583 $23

3.2 Water Makeup & Pretreating 648 68 362 0 1,078 9.5% 103 0% 0 30.0% $354 $1,534 $3

3.3 Other Feedwater Subsystems 1,564 529 476 0 2,568 9.0% 231 0% 0 20.0% $560 $3,359 $6

3.4 Service Water Systems 371 763 2,649 0 3,783 9.8% 369 0% 0 30.0% $1,246 $5,398 $9

3.5 Other Boiler Plant Systems 1,989 771 1,910 0 4,671 9.5% 443 0% 0 20.0% $1,023 $6,137 $10

3.6 FO Supply Sys & Nat Gas $313 $591 $551 $0 1,454 9.6% 140 0% 0 20.0% $319 $1,913 $3

3.7 Waste Treatment Equipment 906 0 552 0 1,458 9.7% 142 0% 0 30.0% $480 $2,080 $4

3.8 Misc. Power Plant Equipment $1,112 $149 $571 $0 1,831 9.7% 177 0% 0 30.0% $602 $2,610 $4

SUBTOTAL 3. $9,761 $7,779 $9,663 $0 $27,203 $2,564 $0 $6,847 $36,614 $62

4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $111,081 $0 $60,864 $0 $171,945 9.2% $15,752 13.9% $23,862 15.3% $32,439 $243,998 $413

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.3 ASU/Oxidant Compression $188,356 $0 w/equip. $0 $188,356 9.7% $18,257 0% $0 10.0% $20,661 $227,274 $385

4.4 Scrubber & Low Temperature Cooling 5,901 $4,803 $4,999 $0 $15,704 9.6% $1,508 0% $0 20.0% $3,442 $20,655 $35

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.6 Soot Recovery & SARU $1,800 $855 $1,689 $0 $4,343 9.6% $419 0% $0 20.0% $952 $5,714 $10

4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.8 Gasification Foundations $0 $6,327 $5,282 $0 $11,609 9.3% $1,076 0% $0 25.0% $3,171 $15,856 $27

SUBTOTAL 4. $307,138 $11,985 $72,835 $0 $391,958 $37,011 $23,862 $60,667 $513,498 $869

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

412

Exhibit 4-140 Case 2 D2B (45%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2B - GEE IGCC w/ one WGS bypass (45% CO2 Capture) x $1, 000

Plant Size: 590.80 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $60,122 $0 $51,015 $0 $111,138 9.7% $10,748 20% $22,228 20.0% $28,823 $172,936 $293

5A.2 Elemental Sulfur Plant $10,093 $2,011 $13,021 $0 $25,125 9.7% $2,441 0% $0 20.0% $5,513 $33,079 $56

5A.3 Mercury Removal $1,161 $0 $884 $0 $2,045 9.7% $197 5% $102 20.0% $469 $2,814 $5

5A.4 Shift Reactors $2,918 $0 $1,175 $0 $4,092 9.6% $392 0% $0 20.0% $897 $5,382 $9

5A.5 COS Hydrolysis $3,705 $0 $4,839 $0 $8,544 9.7% $831 0% $0 20.0% $1,875 $11,250 $19

5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0

5A.7 Blowback Gas Systems $1,316 $0 $249 $0 $1,566 12.2% $191 0% $0 20.0% $351 $2,108 $4

5A.8 Fuel Gas Piping $0 $611 $428 $0 $1,039 9.3% $96 0% $0 20.0% $227 $1,362 $2

5A.9 HGCU Foundations $0 $625 $403 $0 $1,027 9.2% $94 0% $0 30.0% $337 $1,458 $2

5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

SUBTOTAL 5A. $79,316 $3,247 $72,013 $0 $154,576 $14,991 $22,330 $38,492 $230,389 $390

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0

5B.2 CO2 Compression & Drying $9,620 $0 $5,897 $0 $15,517 9.6% $1,495 0% $0 20.0% $3,402 $20,414 $35

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $9,620 $0 $5,897 $0 $15,517 $1,495 $0 $3,402 $20,414 $35

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 219

6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 13

6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 4

SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $237

7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $34,421 $0 $4,894 $0 $39,315 9.5% $3,738 0% $0 10.0% $4,305 $47,359 $80

7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

7.3 Ductwork $0 $1,717 $1,225 $0 $2,942 8.8% $258 0% $0 20.0% $640 $3,840 $7

7.4 Stack $3,350 $0 $1,258 $0 $4,609 9.6% $442 0% $0 10.0% $505 $5,555 $9

7.9 HRSG, Duct & Stack Foundations $0 $671 $645 $0 $1,316 9.3% $122 0% $0 30.0% $431 $1,870 $3

SUBTOTAL 7. $37,771 $2,388 $8,022 $0 $48,182 $4,560 $0 $5,882 $58,624 $99

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories $29,158 $0 $4,985 $0 $34,143 9.6% $3,276 0% $0 10.0% $3,742 $41,161 $70

8.2 Turbine Plant Auxiliaries $202 $0 $463 $0 $665 9.8% $65 0% $0 10.0% $73 $804 $1

8.3 Condenser & Auxiliaries $5,226 $0 $1,534 $0 $6,761 9.6% $646 0% $0 10.0% $741 $8,148 $14

8.4 Steam Piping $5,048 $0 $3,551 $0 $8,598 8.6% $739 0% $0 25.0% $2,334 $11,671 $20

8.9 TG Foundations $0 $1,002 $1,695 $0 $2,697 9.5% $256 0% $0 30.0% $886 $3,838 $6

SUBTOTAL 8. $39,634 $1,002 $12,228 $0 $52,864 $4,982 $0 $7,776 $65,622 $111

9 COOLING WATER SYSTEM

9.1 Cooling Towers $6,825 $0 $1,242 $0 $8,067 9.5% $768 0% $0 15.0% $1,325 $10,160 $17

9.2 Circulating Water Pumps $1,767 $0 $128 $0 $1,895 8.4% $160 0% $0 15.0% $308 $2,363 $4

9.3 Circ. Water System Auxiliaries $149 $0 $21 $0 $170 9.5% $16 0% $0 15.0% $28 $215 $0

9.4 Circ. Water Piping $0 $6,223 $1,613 $0 $7,836 9.0% $708 0% $0 20.0% $1,709 $10,253 $17

9.5 Make-up Water System $356 $0 $509 $0 $865 9.6% $83 0% $0 20.0% $190 $1,138 $2

9.6 Component Cooling Water System $735 $879 $625 $0 $2,238 9.4% $210 0% $0 20.0% $490 $2,938 $5

9.9 Circ. Water System Foundations $0 $2,284 $3,883 $0 $6,167 9.5% $585 0% $0 30.0% $2,026 $8,777 $15

SUBTOTAL 9. $9,832 $9,385 $8,021 $0 $27,238 $2,530 $0 $6,075 $35,843 $61

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*
Carbon Dioxide Capture Sensitivity Analysis

413

Exhibit 4-140 Case 2 D2B (45%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2B - GEE IGCC w/ one WGS bypass (45% CO2 Capture) x $1, 000

Plant Size: 590.80 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $11,873 $6,547 $13,301 $0 $31,721 9.7% $3,062 0% $0 10.0% $3,478 $38,261 $65

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.6 Ash Storage Silos $577 $0 $628 $0 $1,205 9.7% $117 0% $0 15.0% $198 $1,520 $3

10.7 Ash Transport & Feed Equipment $774 $0 $187 $0 $961 9.3% $90 0% $0 15.0% $158 $1,208 $2

10.8 Misc. Ash Handling Equipment $1,195 $1,465 $438 $0 $3,098 9.5% $295 0% $0 15.0% $509 $3,902 $7

10.9 Ash/Spent Sorbent Foundation $0 $51 $64 $0 $115 9.4% $11 0% $0 30.0% $38 $164 $0

SUBTOTAL 10. $14,420 $8,063 $14,617 $0 $37,100 $3,574 $0 $4,381 $45,055 $76

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $958 $0 $948 $0 $1,906 9.5% $182 0% $0 10.0% $209 $2,296 $4

11.2 Station Service Equipment $4,307 $0 $388 $0 $4,695 9.2% $433 0% $0 10.0% $513 $5,641 $10

11.3 Switchgear & Motor Control $7,963 $0 $1,448 $0 $9,411 9.3% $873 0% $0 15.0% $1,543 $11,826 $20

11.4 Conduit & Cable Tray $0 $3,699 $12,203 $0 $15,902 9.7% $1,538 0% $0 25.0% $4,360 $21,800 $37

11.5 Wire & Cable $0 $7,068 $4,644 $0 $11,711 7.3% $851 0% $0 25.0% $3,141 $15,703 $27

11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7

11.7 Standby Equipment $236 $0 $230 $0 $466 9.5% $44 0% $0 15.0% $77 $587 $1

11.8 Main Power Transformers $17,725 $0 $146 $0 $17,870 7.6% $1,352 0% $0 15.0% $2,883 $22,105 $37

11.9 Electrical Foundations $0 $159 $416 $0 $574 9.6% $55 0% $0 30.0% $189 $818 $1

SUBTOTAL 11. $31,188 $11,611 $22,918 $0 $65,718 $5,638 $0 $13,437 $84,793 $144

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.4 Other Major Component Control $1,069 $0 $713 $0 $1,782 9.5% $169 5% $89 15.0% $306 $2,346 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.6 Control Boards,Panels & Racks $246 $0 $157 $0 $403 9.5% $38 5% $20 20.0% $92 $554 $1

12.7 Computer & Accessories $5,700 $0 $182 $0 $5,882 9.2% $540 5% $294 10.0% $672 $7,388 $13

12.8 Instrument Wiring & Tubing $0 $1,991 $4,071 $0 $6,062 8.5% $514 5% $303 25.0% $1,720 $8,599 $15

12.9 Other I & C Equipment $3,810 $0 $1,850 $0 $5,660 9.4% $533 5% $283 15.0% $971 $7,447 $13

SUBTOTAL 12. $10,824 $1,991 $6,974 $0 $19,790 $1,793 $989 $3,761 $26,334 $45

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 108 2,311 0 2,420 9.9% 240 0% 0 30.0% 798 3,458 6

13.2 Site Improvements 0 1,923 2,556 0 4,479 9.9% 442 0% 0 30.0% 1,476 6,398 11

13.3 Site Facilities 3,447 0 3,637 0 7,084 9.9% 698 0% 0 30.0% 2,335 10,117 17

SUBTOTAL 13. $3,447 $2,032 $8,504 $0 $13,983 $1,380 $0 $4,609 $19,972 $34

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

414

Exhibit 4-140 Case 2 D2B (45%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D2B - GEE IGCC w/ one WGS bypass (45% CO2 Capture) x $1, 000

Plant Size: 590.80 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $264 $149 $0 $413 8.8% $36 0% $0 20.0% $90 $539 $1

14.2 Steam Turbine Building $0 $2,367 $3,371 $0 $5,738 9.2% $528 0% $0 15.0% $940 $7,206 $12

14.3 Administration Building $0 $877 $636 $0 $1,514 8.9% $135 0% $0 15.0% $247 $1,896 $3

14.4 Circulation Water Pumphouse $0 $159 $84 $0 $243 8.8% $21 0% $0 15.0% $40 $304 $1

14.5 Water Treatment Buildings $0 $545 $532 $0 $1,077 9.0% $97 0% $0 15.0% $176 $1,351 $2

14.6 Machine Shop $0 $449 $307 $0 $756 8.9% $67 0% $0 15.0% $124 $947 $2

14.7 Warehouse $0 $725 $468 $0 $1,193 8.9% $106 0% $0 15.0% $195 $1,493 $3

14.8 Other Buildings & Structures $0 $434 $338 $0 $772 8.9% $69 0% $0 20.0% $168 $1,010 $2

14.9 Waste Treating Building & Str. $0 $966 $1,847 $0 $2,813 9.3% $262 0% $0 20.0% $615 $3,690 $6

SUBTOTAL 14. $0 $6,786 $7,733 $0 $14,520 $1,322 $0 $2,595 $18,436 $31

Total Cost $688,318 $74,099 $282,905 $0 $1,045,321 $98,313 $58,584 $186,909 $1,389,128 $2,351

Owner's Costs

Preproduction Costs

6 Months All Labor $12,980 $22

1 Month Maintenance Materials $2,839 $5

1 Month Non-fuel Consumables $311 $1

1 Month Waste Disposal $307 $1

25% of 1 Months Fuel Cost at 100% CF $1,638 $3

2% of TPC $27,783 $47

Total $45,857 $78

Inventory Capital

60 day supply of fuel and consumables at 100% CF $13,726 $23

0.5% of TPC (spare parts) $6,946 $12

Total $20,672 $35

Initial Cost for Catalyst and Chemicals $5,808 $10

Land $900 $2

Other Owner's Costs $208,369 $353

Financing Costs $37,506 $63

Total Overnight Costs (TOC) $1,708,241 $2,891

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $1,947,394 $3,296

Labor Bare 

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Project Cont.
Carbon Dioxide Capture Sensitivity Analysis

415

Exhibit 4-141 Case 2 D2B Initial and Annual O&M Expenses

Case: Case 2 D2B - GEE IGCC w/ one WGS bypass (45% CO2 Capture)

Plant Size (MWe): 590.80 Heat Rate (Btu/kWh): 9,283

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 80 CO2 Captured (TPD): 5,736

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 10.0 10.0

Foreman 1.0 1.0

Lab Tech's etc. 3.0 3.0

TOTAL Operating Jobs 16.0 16.0

$ $/kW-net

Annual Operating Labor Cost (calc'd) $6,313,507 $10.686

Maintenance Labor Cost (calc'd) $14,455,208 $24.467

Administrative & Support Labor (calc'd) $5,192,179 $8.788

Property Taxes & Insurance $27,782,556 $47.025

TOTAL FIXED OPERATING COSTS $53,743,450 $90.967

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $27,250,055 0.00658

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 3,627 1.08 $0 $1,145,699 0.00028

Chemicals

MU & WT Chem. (lbs) 0 21,611 0.17 $0 $1,092,119 0.00026

Carbon (Mercury Removal) (lb) 62,618 107 1.05 $65,760 $32,812 0.00001

COS Catalyst (m3) 444 0.30 2,397.36 $1,064,667 $212,933 0.00005

Water Gas Shift Catalyst (ft3) 1,535 1.05 498.83 $765,706 $153,141 0.00004

Selexol Solution (gal) 291,937 70 13.40 $3,911,435 $273,860 0.00007

SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000

Claus Catalyst (ft3) 0 1.95 131.27 $0 $74,590 0.00002

Subtotal Chemicals $5,807,568 $1,839,455 0.00044

Other

Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $0 0.00000

Waste Disposal

Spent Mercury Sorbent (lb) 0 107 0.42 $0 $13,122 0.00000

Flyash (ton) 0 0 0.00 $0 $0 0.00000

Slag (ton) 0 619 16.23 $0 $2,932,471 0.00071

Subtotal Solid Waste Disposal $0 $2,945,593 $0

By-products & Emissions

Sulfur (tons) 0 141 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $33,180,803 0.00801

Coal FUEL (tons) 0 5,641 38.19 $0 $62,902,016 0.01519

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

416

Exhibit 4-142 Case 2 D2C (60%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2C - GEE IGCC w/ one WGS bypass (60% CO2 Capture) x $1, 000

Plant Size: 578.38 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload $3,698 $0 $1,807 $0 $5,505 9.0% $493 0% $0 20.0% $1,200 $7,198 $12

1.2 Coal Stackout & Reclaim $4,778 $0 $1,158 $0 $5,937 8.8% $520 0% $0 20.0% $1,291 $7,749 $13

1.3 Coal Conveyors & Yd Crus $4,443 $0 $1,146 $0 $5,589 8.8% $491 0% $0 20.0% $1,216 $7,295 $13

1.4 Other Coal Handling $1,162 $0 $265 $0 $1,428 8.8% $125 0% $0 20.0% $310 $1,863 $3

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $2,617 $6,543 $0 $9,160 9.6% $878 0% $0 20.0% $2,008 $12,045 $21

SUBTOTAL 1. $14,081 $2,617 $10,920 $0 $27,618 $2,507 $0 $6,025 $36,150 $63

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,578 $378 $247 $0 $2,203 8.6% 188 0% 0 20.0% $478 $2,870 $5

2.3 Slurry Prep & Feed $21,579 $0 $9,524 $0 $31,103 9.1% 2,826 5% 1,555 20.0% $7,097 $42,580 $74

2.4 Misc. Coal Prep & Feed $868 $631 $1,893 $0 $3,392 9.2% 312 0% 0 20.0% $741 $4,445 $8

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $3,373 $2,769 $0 $6,142 9.3% 569 0% 0 20.0% $1,342 $8,053 $14

SUBTOTAL 2. $24,025 $4,382 $14,433 $0 $42,840 $3,895 $1,555 $9,658 $57,948 $100

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 2,839 4,875 2,573 0 10,287 9.3% 953 0% 0 20.0% $2,248 $13,488 $23

3.2 Water Makeup & Pretreating 672 70 375 0 1,117 9.5% 106 0% 0 30.0% $367 $1,590 $3

3.3 Other Feedwater Subsystems 1,553 525 472 0 2,550 9.0% 229 0% 0 20.0% $556 $3,336 $6

3.4 Service Water Systems 384 791 2,746 0 3,922 9.8% 383 0% 0 30.0% $1,291 $5,596 $10

3.5 Other Boiler Plant Systems 2,062 799 1,980 0 4,842 9.5% 459 0% 0 20.0% $1,060 $6,361 $11

3.6 FO Supply Sys & Nat Gas $314 $592 $553 $0 1,459 9.6% 140 0% 0 20.0% $320 $1,919 $3

3.7 Waste Treatment Equipment 939 0 573 0 1,511 9.7% 147 0% 0 30.0% $498 $2,156 $4

3.8 Misc. Power Plant Equipment $1,115 $149 $573 $0 1,837 9.7% 177 0% 0 30.0% $604 $2,619 $5

SUBTOTAL 3. $9,878 $7,802 $9,846 $0 $27,526 $2,596 $0 $6,944 $37,066 $64

4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $112,074 $0 $61,408 $0 $173,483 9.2% $15,892 13.9% $24,076 15.3% $32,729 $246,180 $426

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.3 ASU/Oxidant Compression $190,054 $0 w/equip. $0 $190,054 9.7% $18,422 0% $0 10.0% $20,848 $229,323 $396

4.4 Scrubber & Low Temperature Cooling 5,954 $4,846 $5,044 $0 $15,845 9.6% $1,521 0% $0 20.0% $3,473 $20,839 $36

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.6 Soot Recovery & SARU $1,816 $862 $1,704 $0 $4,382 9.6% $422 0% $0 20.0% $961 $5,765 $10

4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.8 Gasification Foundations $0 $6,384 $5,329 $0 $11,713 9.3% $1,085 0% $0 25.0% $3,200 $15,998 $28

SUBTOTAL 4. $309,898 $12,092 $73,486 $0 $395,476 $37,343 $24,076 $61,211 $518,106 $896

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

417

Exhibit 4-142 Case 2 D2C (60%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2C - GEE IGCC w/ one WGS bypass (60% CO2 Capture) x $1, 000

Plant Size: 578.38 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $64,485 $0 $54,717 $0 $119,201 9.7% $11,528 20% $23,840 20.0% $30,914 $185,484 $321

5A.2 Elemental Sulfur Plant $10,179 $2,029 $13,133 $0 $25,341 9.7% $2,462 0% $0 20.0% $5,561 $33,363 $58

5A.3 Mercury Removal $1,238 $0 $942 $0 $2,180 9.7% $210 5% $109 20.0% $500 $2,999 $5

5A.4 Shift Reactors $4,409 $0 $1,775 $0 $6,184 9.6% $593 0% $0 20.0% $1,355 $8,132 $14

5A.5 COS Hydrolysis $3,830 $0 $5,001 $0 $8,831 9.7% $859 0% $0 20.0% $1,938 $11,627 $20

5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0

5A.7 Blowback Gas Systems $1,328 $0 $252 $0 $1,580 12.2% $193 0% $0 20.0% $355 $2,127 $4

5A.8 Fuel Gas Piping $0 $621 $435 $0 $1,056 9.3% $98 0% $0 20.0% $231 $1,385 $2

5A.9 HGCU Foundations $0 $631 $407 $0 $1,038 9.2% $95 0% $0 30.0% $340 $1,473 $3

5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

SUBTOTAL 5A. $85,469 $3,281 $76,661 $0 $165,411 $16,038 $23,949 $41,193 $246,590 $426

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0

5B.2 CO2 Compression & Drying $12,539 $0 $7,686 $0 $20,226 9.6% $1,948 0% $0 20.0% $4,435 $26,609 $46

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $12,539 $0 $7,686 $0 $20,226 $1,948 $0 $4,435 $26,609 $46

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 224

6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 14

6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5

SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $242

7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $34,159 $0 $4,857 $0 $39,016 9.5% $3,710 0% $0 10.0% $4,273 $46,999 $81

7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

7.3 Ductwork $0 $1,722 $1,228 $0 $2,950 8.8% $259 0% $0 20.0% $642 $3,850 $7

7.4 Stack $3,359 $0 $1,262 $0 $4,620 9.6% $443 0% $0 10.0% $506 $5,569 $10

7.9 HRSG, Duct & Stack Foundations $0 $673 $646 $0 $1,319 9.3% $123 0% $0 30.0% $433 $1,875 $3

SUBTOTAL 7. $37,518 $2,394 $7,993 $0 $47,906 $4,534 $0 $5,853 $58,293 $101

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories $29,018 $0 $4,961 $0 $33,978 9.6% $3,260 0% $0 10.0% $3,724 $40,963 $71

8.2 Turbine Plant Auxiliaries $201 $0 $461 $0 $662 9.8% $65 0% $0 10.0% $73 $800 $1

8.3 Condenser & Auxiliaries $5,178 $0 $1,520 $0 $6,699 9.6% $640 0% $0 10.0% $734 $8,073 $14

8.4 Steam Piping $5,012 $0 $3,526 $0 $8,537 8.6% $733 0% $0 25.0% $2,318 $11,589 $20

8.9 TG Foundations $0 $998 $1,686 $0 $2,684 9.5% $254 0% $0 30.0% $882 $3,820 $7

SUBTOTAL 8. $39,409 $998 $12,154 $0 $52,561 $4,953 $0 $7,730 $65,244 $113

9 COOLING WATER SYSTEM

9.1 Cooling Towers $6,929 $0 $1,260 $0 $8,189 9.5% $780 0% $0 15.0% $1,345 $10,315 $18

9.2 Circulating Water Pumps $1,800 $0 $130 $0 $1,931 8.4% $163 0% $0 15.0% $314 $2,408 $4

9.3 Circ. Water System Auxiliaries $151 $0 $22 $0 $173 9.5% $16 0% $0 15.0% $28 $218 $0

9.4 Circ. Water Piping $0 $6,320 $1,639 $0 $7,959 9.0% $719 0% $0 20.0% $1,736 $10,414 $18

9.5 Make-up Water System $367 $0 $525 $0 $892 9.6% $86 0% $0 20.0% $195 $1,173 $2

9.6 Component Cooling Water System $746 $892 $635 $0 $2,273 9.4% $213 0% $0 20.0% $497 $2,984 $5

9.9 Circ. Water System Foundations $0 $2,320 $3,944 $0 $6,264 9.5% $594 0% $0 30.0% $2,057 $8,915 $15

SUBTOTAL 9. $9,994 $9,533 $8,154 $0 $27,681 $2,571 $0 $6,174 $36,426 $63

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*
Carbon Dioxide Capture Sensitivity Analysis

418

Exhibit 4-142 Case 2 D2C (60%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2C - GEE IGCC w/ one WGS bypass (60% CO2 Capture) x $1, 000

Plant Size: 578.38 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $11,967 $6,599 $13,406 $0 $31,972 9.7% $3,086 0% $0 10.0% $3,506 $38,564 $67

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.6 Ash Storage Silos $581 $0 $632 $0 $1,214 9.7% $118 0% $0 15.0% $200 $1,531 $3

10.7 Ash Transport & Feed Equipment $780 $0 $188 $0 $968 9.3% $90 0% $0 15.0% $159 $1,217 $2

10.8 Misc. Ash Handling Equipment $1,204 $1,475 $441 $0 $3,120 9.5% $297 0% $0 15.0% $513 $3,930 $7

10.9 Ash/Spent Sorbent Foundation $0 $51 $65 $0 $116 9.4% $11 0% $0 30.0% $38 $165 $0

SUBTOTAL 10. $14,532 $8,126 $14,732 $0 $37,390 $3,602 $0 $4,415 $45,406 $79

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $957 $0 $946 $0 $1,903 9.5% $182 0% $0 10.0% $208 $2,293 $4

11.2 Station Service Equipment $4,433 $0 $399 $0 $4,832 9.2% $445 0% $0 10.0% $528 $5,805 $10

11.3 Switchgear & Motor Control $8,195 $0 $1,490 $0 $9,685 9.3% $898 0% $0 15.0% $1,588 $12,171 $21

11.4 Conduit & Cable Tray $0 $3,807 $12,559 $0 $16,365 9.7% $1,583 0% $0 25.0% $4,487 $22,435 $39

11.5 Wire & Cable $0 $7,274 $4,779 $0 $12,053 7.3% $876 0% $0 25.0% $3,232 $16,160 $28

11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7

11.7 Standby Equipment $235 $0 $230 $0 $465 9.5% $44 0% $0 15.0% $76 $586 $1

11.8 Main Power Transformers $17,694 $0 $146 $0 $17,840 7.6% $1,349 0% $0 15.0% $2,878 $22,067 $38

11.9 Electrical Foundations $0 $158 $415 $0 $573 9.6% $55 0% $0 30.0% $188 $817 $1

SUBTOTAL 11. $31,514 $11,925 $23,460 $0 $66,899 $5,743 $0 $13,710 $86,352 $149

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.4 Other Major Component Control $1,087 $0 $726 $0 $1,813 9.5% $172 5% $91 15.0% $311 $2,387 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.6 Control Boards,Panels & Racks $250 $0 $160 $0 $410 9.5% $39 5% $21 20.0% $94 $563 $1

12.7 Computer & Accessories $5,799 $0 $186 $0 $5,985 9.2% $549 5% $299 10.0% $683 $7,517 $13

12.8 Instrument Wiring & Tubing $0 $2,026 $4,142 $0 $6,167 8.5% $523 5% $308 25.0% $1,750 $8,749 $15

12.9 Other I & C Equipment $3,877 $0 $1,882 $0 $5,759 9.4% $542 5% $288 15.0% $988 $7,577 $13

SUBTOTAL 12. $11,013 $2,026 $7,096 $0 $20,135 $1,825 $1,007 $3,827 $26,793 $46

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 109 2,321 0 2,430 9.9% 241 0% 0 30.0% 801 3,472 6

13.2 Site Improvements 0 1,932 2,567 0 4,498 9.9% 444 0% 0 30.0% 1,483 6,425 11

13.3 Site Facilities 3,461 0 3,652 0 7,114 9.9% 701 0% 0 30.0% 2,344 10,159 18

SUBTOTAL 13. $3,461 $2,040 $8,540 $0 $14,042 $1,386 $0 $4,628 $20,056 $35

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

419

Exhibit 4-142 Case 2 D2C (60%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D2C - GEE IGCC w/ one WGS bypass (60% CO2 Capture) x $1, 000

Plant Size: 578.38 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $264 $149 $0 $414 8.8% $36 0% $0 20.0% $90 $540 $1

14.2 Steam Turbine Building $0 $2,371 $3,377 $0 $5,748 9.2% $529 0% $0 15.0% $941 $7,218 $12

14.3 Administration Building $0 $879 $638 $0 $1,517 8.9% $135 0% $0 15.0% $248 $1,900 $3

14.4 Circulation Water Pumphouse $0 $161 $86 $0 $247 8.8% $22 0% $0 15.0% $40 $309 $1

14.5 Water Treatment Buildings $0 $564 $550 $0 $1,114 9.0% $101 0% $0 15.0% $182 $1,397 $2

14.6 Machine Shop $0 $450 $308 $0 $758 8.9% $67 0% $0 15.0% $124 $949 $2

14.7 Warehouse $0 $726 $469 $0 $1,195 8.9% $106 0% $0 15.0% $195 $1,496 $3

14.8 Other Buildings & Structures $0 $435 $339 $0 $774 8.9% $69 0% $0 20.0% $169 $1,012 $2

14.9 Waste Treating Building & Str. $0 $970 $1,853 $0 $2,823 9.3% $263 0% $0 20.0% $617 $3,703 $6

SUBTOTAL 14. $0 $6,820 $7,769 $0 $14,589 $1,328 $0 $2,607 $18,524 $32

Total Cost $700,906 $74,923 $291,263 $0 $1,067,091 $100,392 $60,448 $191,841 $1,419,771 $2,455

Owner's Costs

Preproduction Costs

6 Months All Labor $13,169 $23

1 Month Maintenance Materials $2,898 $5

1 Month Non-fuel Consumables $341 $1

1 Month Waste Disposal $311 $1

25% of 1 Months Fuel Cost at 100% CF $1,659 $3

2% of TPC $28,395 $49

Total $46,772 $81

Inventory Capital

60 day supply of fuel and consumables at 100% CF $13,954 $24

0.5% of TPC (spare parts) $7,099 $12

Total $21,053 $36

Initial Cost for Catalyst and Chemicals $6,510 $11

Land $900 $2

Other Owner's Costs $212,966 $368

Financing Costs $38,334 $66

Total Overnight Costs (TOC) $1,746,306 $3,019

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $1,990,789 $3,442

Labor Bare 

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Project Cont.
Carbon Dioxide Capture Sensitivity Analysis

420

Exhibit 4-143 Case 2 D2C Initial and Annual O&M Expenses

Case: Case 2 D2C - GEE IGCC w/ one WGS bypass (60% CO2 Capture)

Plant Size (MWe): 578.38 Heat Rate (Btu/kWh): 9,604

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 80 CO2 Captured (TPD): 7,820

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 10.0 10.0

Foreman 1.0 1.0

Lab Tech's etc. 3.0 3.0

TOTAL Operating Jobs 16.0 16.0

$ $/kW-net

Annual Operating Labor Cost (calc'd) $6,313,507 $10.916

Maintenance Labor Cost (calc'd) $14,756,256 $25.513

Administrative & Support Labor (calc'd) $5,267,441 $9.107

Property Taxes & Insurance $28,395,426 $49.095

TOTAL FIXED OPERATING COSTS $54,732,630 $94.631

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $27,817,573 0.00686

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 3,816 1.08 $0 $1,205,281 0.00030

Chemicals

MU & WT Chem. (lbs) 0 22,735 0.17 $0 $1,148,914 0.00028

Carbon (Mercury Removal) (lb) 68,570 117 1.05 $72,010 $35,878 0.00001

COS Catalyst (m3) 466 0.32 2,397.36 $1,115,971 $223,194 0.00006

Water Gas Shift Catalyst (ft3) 2,769 1.90 498.83 $1,381,263 $276,253 0.00007

Selexol Solution (gal) 294,129 78 13.40 $3,940,815 $306,332 0.00008

SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000

Claus Catalyst (ft3) 0 1.97 131.27 $0 $75,548 0.00002

Subtotal Chemicals $6,510,059 $2,066,119 0.00051

Other

Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $0 0.00000

Waste Disposal

Spent Mercury Sorbent (lb) 0 117 0.42 $0 $14,349 0.00000

Flyash (ton) 0 0 0.00 $0 $0 0.00000

Slag (ton) 0 627 16.23 $0 $2,969,994 0.00073

Subtotal Solid Waste Disposal $0 $2,984,343 $0

By-products & Emissions

Sulfur (tons) 0 143 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $34,073,315 0.00841

Coal FUEL (tons) 0 5,714 38.19 $0 $63,706,962 0.01572

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

421

Exhibit 4-144 Case 2 D2D (75%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2D - GEE IGCC w/ one WGS bypass (75% CO2 Capture) x $1, 000

Plant Size: 563.92 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload $3,723 $0 $1,819 $0 $5,542 9.0% $496 0% $0 20.0% $1,208 $7,246 $13

1.2 Coal Stackout & Reclaim $4,811 $0 $1,166 $0 $5,977 8.8% $524 0% $0 20.0% $1,300 $7,801 $14

1.3 Coal Conveyors & Yd Crus $4,473 $0 $1,154 $0 $5,627 8.8% $494 0% $0 20.0% $1,224 $7,345 $13

1.4 Other Coal Handling $1,170 $0 $267 $0 $1,437 8.8% $126 0% $0 20.0% $313 $1,876 $3

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $2,634 $6,587 $0 $9,222 9.6% $884 0% $0 20.0% $2,021 $12,127 $22

SUBTOTAL 1. $14,177 $2,634 $10,994 $0 $27,805 $2,524 $0 $6,066 $36,395 $65

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,589 $380 $249 $0 $2,219 8.6% 190 0% 0 20.0% $482 $2,890 $5

2.3 Slurry Prep & Feed $21,737 $0 $9,592 $0 $31,330 9.1% 2,846 5% 1,566 20.0% $7,149 $42,891 $76

2.4 Misc. Coal Prep & Feed $874 $636 $1,907 $0 $3,417 9.2% 314 0% 0 20.0% $746 $4,477 $8

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $3,397 $2,789 $0 $6,186 9.3% 573 0% 0 20.0% $1,352 $8,111 $14

SUBTOTAL 2. $24,200 $4,414 $14,538 $0 $43,152 $3,923 $1,566 $9,728 $58,370 $104

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 2,818 4,839 2,555 0 10,212 9.3% 946 0% 0 20.0% $2,232 $13,389 $24

3.2 Water Makeup & Pretreating 692 72 387 0 1,151 9.5% 110 0% 0 30.0% $378 $1,639 $3

3.3 Other Feedwater Subsystems 1,542 521 469 0 2,532 9.0% 228 0% 0 20.0% $552 $3,311 $6

3.4 Service Water Systems 396 816 2,831 0 4,042 9.8% 394 0% 0 30.0% $1,331 $5,768 $10

3.5 Other Boiler Plant Systems 2,125 824 2,041 0 4,990 9.5% 473 0% 0 20.0% $1,093 $6,556 $12

3.6 FO Supply Sys & Nat Gas $315 $594 $554 $0 1,463 9.6% 141 0% 0 20.0% $321 $1,924 $3

3.7 Waste Treatment Equipment 968 0 590 0 1,558 9.7% 152 0% 0 30.0% $513 $2,222 $4

3.8 Misc. Power Plant Equipment $1,118 $150 $574 $0 1,842 9.7% 178 0% 0 30.0% $606 $2,626 $5

SUBTOTAL 3. $9,974 $7,815 $10,000 $0 $27,789 $2,621 $0 $7,025 $37,436 $66

4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $112,933 $0 $61,879 $0 $174,812 9.2% $16,014 13.9% $24,260 15.3% $32,980 $248,067 $440

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.3 ASU/Oxidant Compression $191,409 $0 w/equip. $0 $191,409 9.7% $18,553 0% $0 10.0% $20,996 $230,959 $410

4.4 Scrubber & Low Temperature Cooling 6,000 $4,883 $5,083 $0 $15,966 9.6% $1,533 0% $0 20.0% $3,500 $20,999 $37

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.6 Soot Recovery & SARU $1,830 $869 $1,717 $0 $4,416 9.6% $426 0% $0 20.0% $968 $5,810 $10

4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.8 Gasification Foundations $0 $6,433 $5,370 $0 $11,803 9.3% $1,094 0% $0 25.0% $3,224 $16,120 $29

SUBTOTAL 4. $312,172 $12,185 $74,049 $0 $398,406 $37,620 $24,260 $61,669 $521,955 $926

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

422

Exhibit 4-144 Case 2 D2D (75%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2D - GEE IGCC w/ one WGS bypass (75% CO2 Capture) x $1, 000

Plant Size: 563.92 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $69,188 $0 $58,708 $0 $127,896 9.7% $12,369 20% $25,579 20.0% $33,169 $199,013 $353

5A.2 Elemental Sulfur Plant $10,254 $2,044 $13,230 $0 $25,527 9.7% $2,480 0% $0 20.0% $5,601 $33,608 $60

5A.3 Mercury Removal $1,307 $0 $994 $0 $2,301 9.7% $222 5% $115 20.0% $528 $3,166 $6

5A.4 Shift Reactors $5,634 $0 $2,268 $0 $7,902 9.6% $758 0% $0 20.0% $1,732 $10,391 $18

5A.5 COS Hydrolysis $3,942 $0 $5,148 $0 $9,090 9.7% $884 0% $0 20.0% $1,995 $11,968 $21

5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0

5A.7 Blowback Gas Systems $1,338 $0 $254 $0 $1,592 12.2% $194 0% $0 20.0% $357 $2,143 $4

5A.8 Fuel Gas Piping $0 $628 $440 $0 $1,068 9.3% $99 0% $0 20.0% $233 $1,400 $2

5A.9 HGCU Foundations $0 $636 $410 $0 $1,047 9.2% $96 0% $0 30.0% $343 $1,486 $3

5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

SUBTOTAL 5A. $91,663 $3,308 $81,451 $0 $176,422 $17,102 $25,694 $43,958 $263,176 $467

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0

5B.2 CO2 Compression & Drying $15,358 $0 $9,414 $0 $24,773 9.6% $2,386 0% $0 20.0% $5,432 $32,591 $58

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $15,358 $0 $9,414 $0 $24,773 $2,386 $0 $5,432 $32,591 $58

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 230

6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 14

6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5

SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $249

7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,897 $0 $4,820 $0 $38,717 9.5% $3,681 0% $0 10.0% $4,240 $46,638 $83

7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

7.3 Ductwork $0 $1,726 $1,231 $0 $2,957 8.8% $259 0% $0 20.0% $643 $3,860 $7

7.4 Stack $3,367 $0 $1,265 $0 $4,632 9.6% $444 0% $0 10.0% $508 $5,584 $10

7.9 HRSG, Duct & Stack Foundations $0 $675 $648 $0 $1,323 9.3% $123 0% $0 30.0% $434 $1,879 $3

SUBTOTAL 7. $37,264 $2,401 $7,964 $0 $47,629 $4,507 $0 $5,824 $57,961 $103

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories $28,760 $0 $4,917 $0 $33,676 9.6% $3,231 0% $0 10.0% $3,691 $40,598 $72

8.2 Turbine Plant Auxiliaries $199 $0 $457 $0 $656 9.8% $64 0% $0 10.0% $72 $793 $1

8.3 Condenser & Auxiliaries $5,106 $0 $1,499 $0 $6,605 9.6% $631 0% $0 10.0% $724 $7,960 $14

8.4 Steam Piping $4,975 $0 $3,499 $0 $8,474 8.6% $728 0% $0 25.0% $2,300 $11,502 $20

8.9 TG Foundations $0 $989 $1,672 $0 $2,661 9.5% $252 0% $0 30.0% $874 $3,787 $7

SUBTOTAL 8. $39,040 $989 $12,044 $0 $52,073 $4,907 $0 $7,661 $64,641 $115

9 COOLING WATER SYSTEM

9.1 Cooling Towers $7,032 $0 $1,279 $0 $8,312 9.5% $791 0% $0 15.0% $1,365 $10,469 $19

9.2 Circulating Water Pumps $1,823 $0 $132 $0 $1,954 8.4% $165 0% $0 15.0% $318 $2,437 $4

9.3 Circ. Water System Auxiliaries $153 $0 $22 $0 $175 9.5% $17 0% $0 15.0% $29 $220 $0

9.4 Circ. Water Piping $0 $6,385 $1,655 $0 $8,040 9.0% $727 0% $0 20.0% $1,753 $10,520 $19

9.5 Make-up Water System $376 $0 $538 $0 $915 9.6% $88 0% $0 20.0% $200 $1,203 $2

9.6 Component Cooling Water System $754 $902 $641 $0 $2,297 9.4% $215 0% $0 20.0% $502 $3,014 $5

9.9 Circ. Water System Foundations $0 $2,344 $3,984 $0 $6,328 9.5% $600 0% $0 30.0% $2,078 $9,006 $16

SUBTOTAL 9. $10,138 $9,630 $8,252 $0 $28,020 $2,603 $0 $6,247 $36,870 $65

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*
Carbon Dioxide Capture Sensitivity Analysis

423

Exhibit 4-144 Case 2 D2D (75%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2D - GEE IGCC w/ one WGS bypass (75% CO2 Capture) x $1, 000

Plant Size: 563.92 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $12,049 $6,644 $13,497 $0 $32,189 9.7% $3,107 0% $0 10.0% $3,530 $38,826 $69

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.6 Ash Storage Silos $585 $0 $636 $0 $1,221 9.7% $118 0% $0 15.0% $201 $1,541 $3

10.7 Ash Transport & Feed Equipment $784 $0 $189 $0 $974 9.3% $91 0% $0 15.0% $160 $1,224 $2

10.8 Misc. Ash Handling Equipment $1,211 $1,484 $443 $0 $3,139 9.5% $299 0% $0 15.0% $516 $3,954 $7

10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $117 9.4% $11 0% $0 30.0% $38 $166 $0

SUBTOTAL 10. $14,629 $8,180 $14,831 $0 $37,640 $3,626 $0 $4,444 $45,710 $81

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $954 $0 $944 $0 $1,898 9.5% $181 0% $0 10.0% $208 $2,287 $4

11.2 Station Service Equipment $4,560 $0 $411 $0 $4,971 9.2% $458 0% $0 10.0% $543 $5,972 $11

11.3 Switchgear & Motor Control $8,430 $0 $1,533 $0 $9,963 9.3% $924 0% $0 15.0% $1,633 $12,520 $22

11.4 Conduit & Cable Tray $0 $3,916 $12,918 $0 $16,834 9.7% $1,628 0% $0 25.0% $4,616 $23,078 $41

11.5 Wire & Cable $0 $7,482 $4,916 $0 $12,398 7.3% $901 0% $0 25.0% $3,325 $16,623 $29

11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7

11.7 Standby Equipment $235 $0 $229 $0 $464 9.5% $44 0% $0 15.0% $76 $585 $1

11.8 Main Power Transformers $17,638 $0 $145 $0 $17,783 7.6% $1,345 0% $0 15.0% $2,869 $21,997 $39

11.9 Electrical Foundations $0 $158 $414 $0 $571 9.6% $55 0% $0 30.0% $188 $814 $1

SUBTOTAL 11. $31,816 $12,241 $24,006 $0 $68,063 $5,847 $0 $13,981 $87,892 $156

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.4 Other Major Component Control $1,106 $0 $738 $0 $1,844 9.5% $175 5% $92 15.0% $317 $2,428 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.6 Control Boards,Panels & Racks $254 $0 $163 $0 $417 9.5% $39 5% $21 20.0% $95 $573 $1

12.7 Computer & Accessories $5,899 $0 $189 $0 $6,087 9.2% $559 5% $304 10.0% $695 $7,646 $14

12.8 Instrument Wiring & Tubing $0 $2,061 $4,212 $0 $6,273 8.5% $532 5% $314 25.0% $1,780 $8,898 $16

12.9 Other I & C Equipment $3,943 $0 $1,915 $0 $5,858 9.4% $551 5% $293 15.0% $1,005 $7,707 $14

SUBTOTAL 12. $11,201 $2,061 $7,217 $0 $20,479 $1,856 $1,024 $3,892 $27,251 $48

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 109 2,330 0 2,439 9.9% 242 0% 0 30.0% 804 3,486 6

13.2 Site Improvements 0 1,939 2,577 0 4,516 9.9% 445 0% 0 30.0% 1,488 6,450 11

13.3 Site Facilities 3,475 0 3,667 0 7,142 9.9% 704 0% 0 30.0% 2,354 10,199 18

SUBTOTAL 13. $3,475 $2,048 $8,574 $0 $14,097 $1,391 $0 $4,647 $20,135 $36

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

424

Exhibit 4-144 Case 2 D2D (75%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D2D - GEE IGCC w/ one WGS bypass (75% CO2 Capture) x $1, 000

Plant Size: 563.92 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $264 $150 $0 $414 8.8% $36 0% $0 20.0% $90 $540 $1

14.2 Steam Turbine Building $0 $2,374 $3,382 $0 $5,757 9.2% $530 0% $0 15.0% $943 $7,229 $13

14.3 Administration Building $0 $881 $639 $0 $1,520 8.9% $135 0% $0 15.0% $248 $1,903 $3

14.4 Circulation Water Pumphouse $0 $163 $86 $0 $249 8.8% $22 0% $0 15.0% $41 $312 $1

14.5 Water Treatment Buildings $0 $580 $566 $0 $1,146 9.0% $104 0% $0 15.0% $187 $1,437 $3

14.6 Machine Shop $0 $451 $309 $0 $759 8.9% $67 0% $0 15.0% $124 $951 $2

14.7 Warehouse $0 $728 $470 $0 $1,198 8.9% $106 0% $0 15.0% $196 $1,499 $3

14.8 Other Buildings & Structures $0 $436 $339 $0 $775 8.9% $69 0% $0 20.0% $169 $1,014 $2

14.9 Waste Treating Building & Str. $0 $973 $1,859 $0 $2,831 9.3% $264 0% $0 20.0% $619 $3,714 $7

SUBTOTAL 14. $0 $6,850 $7,800 $0 $14,650 $1,334 $0 $2,617 $18,600 $33

Total Cost $712,683 $75,643 $299,466 $0 $1,087,792 $102,370 $62,406 $196,623 $1,449,191 $2,570

Owner's Costs

Preproduction Costs

6 Months All Labor $13,348 $24

1 Month Maintenance Materials $2,954 $5

1 Month Non-fuel Consumables $368 $1

1 Month Waste Disposal $314 $1

25% of 1 Months Fuel Cost at 100% CF $1,677 $3

2% of TPC $28,984 $51

Total $47,645 $84

Inventory Capital

60 day supply of fuel and consumables at 100% CF $14,154 $25

0.5% of TPC (spare parts) $7,246 $13

Total $21,400 $38

Initial Cost for Catalyst and Chemicals $7,172 $13

Land $900 $2

Other Owner's Costs $217,379 $385

Financing Costs $39,128 $69

Total Overnight Costs (TOC) $1,782,815 $3,161

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,032,409 $3,604

Labor Bare 

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Project Cont.
Carbon Dioxide Capture Sensitivity Analysis

425

Exhibit 4-145 Case 2 D2D Initial and Annual O&M Expenses

Case: Case 2 D2D - GEE IGCC w/ one WGS bypass (75% CO2 Capture)

Plant Size (MWe): 563.92 Heat Rate (Btu/kWh): 9,958

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 80 CO2 Captured (TPD): 9,988

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 10.0 10.0

Foreman 1.0 1.0

Lab Tech's etc. 3.0 3.0

TOTAL Operating Jobs 16.0 16.0

$ $/kW-net

Annual Operating Labor Cost (calc'd) $6,313,507 $11.196

Maintenance Labor Cost (calc'd) $15,042,519 $26.675

Administrative & Support Labor (calc'd) $5,339,006 $9.468

Property Taxes & Insurance $28,983,817 $51.397

TOTAL FIXED OPERATING COSTS $55,678,849 $98.735

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $28,357,217 0.00718

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 3,982 1.08 $0 $1,257,585 0.00032

Chemicals

MU & WT Chem. (lbs) 0 23,721 0.17 $0 $1,198,773 0.00030

Carbon (Mercury Removal) (lb) 74,096 127 1.05 $77,813 $38,945 0.00001

COS Catalyst (m3) 485 0.33 2,397.36 $1,163,199 $232,640 0.00006

Water Gas Shift Catalyst (ft3) 3,930 2.69 498.83 $1,960,406 $392,081 0.00010

Selexol Solution (gal) 296,322 87 13.40 $3,970,195 $339,078 0.00009

SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000

Claus Catalyst (ft3) 0 1.99 131.27 $0 $76,378 0.00002

Subtotal Chemicals $7,171,613 $2,277,894 0.00058

Other

Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $0 0.00000

Waste Disposal

Spent Mercury Sorbent (lb) 0 127 0.42 $0 $15,575 0.00000

Flyash (ton) 0 0 0.00 $0 $0 0.00000

Slag (ton) 0 634 16.23 $0 $3,002,571 0.00076

Subtotal Solid Waste Disposal $0 $3,018,146 $0

By-products & Emissions

Sulfur (tons) 0 145 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $34,910,843 0.00883

Coal FUEL (tons) 0 5,776 38.19 $0 $64,405,670 0.01630

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

426

Exhibit 4-146 Case 2 D3A (25%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3A - GEE IGCC w/ two WGS bypass (25% CO2 Capture) x $1, 000

Plant Size: 607.02 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload $3,633 $0 $1,775 $0 $5,409 9.0% $484 0% $0 20.0% $1,179 $7,072 $12

1.2 Coal Stackout & Reclaim $4,695 $0 $1,138 $0 $5,833 8.8% $511 0% $0 20.0% $1,269 $7,613 $13

1.3 Coal Conveyors & Yd Crus $4,365 $0 $1,126 $0 $5,491 8.8% $482 0% $0 20.0% $1,195 $7,168 $12

1.4 Other Coal Handling $1,142 $0 $261 $0 $1,403 8.8% $123 0% $0 20.0% $305 $1,830 $3

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $2,571 $6,429 $0 $9,000 9.6% $863 0% $0 20.0% $1,972 $11,835 $19

SUBTOTAL 1. $13,835 $2,571 $10,729 $0 $27,135 $2,463 $0 $5,920 $35,518 $59

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,549 $371 $243 $0 $2,162 8.6% 185 0% 0 20.0% $469 $2,816 $5

2.3 Slurry Prep & Feed $21,172 $0 $9,347 $0 $30,518 9.1% 2,773 5% 1,526 20.0% $6,963 $41,780 $69

2.4 Misc. Coal Prep & Feed $852 $620 $1,858 $0 $3,329 9.2% 306 0% 0 20.0% $727 $4,362 $7

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $3,310 $2,718 $0 $6,028 9.3% 558 0% 0 20.0% $1,317 $7,903 $13

SUBTOTAL 2. $23,572 $4,300 $14,165 $0 $42,037 $3,822 $1,526 $9,477 $56,862 $94

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 2,864 4,919 2,597 0 10,380 9.3% 962 0% 0 20.0% $2,268 $13,610 $22

3.2 Water Makeup & Pretreating 616 64 344 0 1,025 9.5% 98 0% 0 30.0% $337 $1,459 $2

3.3 Other Feedwater Subsystems 1,567 530 477 0 2,573 9.0% 231 0% 0 20.0% $561 $3,366 $6

3.4 Service Water Systems 353 726 2,520 0 3,599 9.8% 351 0% 0 30.0% $1,185 $5,135 $8

3.5 Other Boiler Plant Systems 1,892 733 1,817 0 4,443 9.5% 421 0% 0 20.0% $973 $5,837 $10

3.6 FO Supply Sys & Nat Gas $311 $588 $549 $0 1,448 9.6% 140 0% 0 20.0% $318 $1,905 $3

3.7 Waste Treatment Equipment 861 0 525 0 1,387 9.7% 135 0% 0 30.0% $457 $1,978 $3

3.8 Misc. Power Plant Equipment $1,107 $148 $569 $0 1,824 9.7% 176 0% 0 30.0% $600 $2,600 $4

SUBTOTAL 3. $9,573 $7,709 $9,397 $0 $26,679 $2,514 $0 $6,698 $35,891 $59

4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $109,865 $0 $60,198 $0 $170,063 9.2% $15,579 13.9% $23,601 15.3% $32,084 $241,328 $398

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.3 ASU/Oxidant Compression $186,280 $0 w/equip. $0 $186,280 9.7% $18,056 0% $0 10.0% $20,434 $224,770 $370

4.4 Scrubber & Low Temperature Cooling 5,837 $4,751 $4,945 $0 $15,532 9.6% $1,491 0% $0 20.0% $3,405 $20,429 $34

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.6 Soot Recovery & SARU $1,780 $845 $1,671 $0 $4,296 9.6% $414 0% $0 20.0% $942 $5,652 $9

4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.8 Gasification Foundations $0 $6,258 $5,224 $0 $11,482 9.3% $1,064 0% $0 25.0% $3,136 $15,682 $26

SUBTOTAL 4. $303,762 $11,854 $72,037 $0 $387,653 $36,605 $23,601 $60,001 $507,860 $837

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

427

Exhibit 4-146 Case 2 D3A (25%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3A - GEE IGCC w/ two WGS bypass (25% CO2 Capture) x $1, 000

Plant Size: 607.02 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $53,837 $0 $45,682 $0 $99,519 9.7% $9,625 20% $19,904 20.0% $25,809 $154,856 $255

5A.2 Elemental Sulfur Plant $9,987 $1,990 $12,884 $0 $24,861 9.7% $2,415 0% $0 20.0% $5,455 $32,732 $54

5A.3 Mercury Removal $1,064 $0 $809 $0 $1,873 9.7% $181 5% $94 20.0% $430 $2,577 $4

5A.4 Shift Reactors $145 $0 $58 $0 $203 9.6% $19 0% $0 20.0% $44 $267 $0

5A.5 COS Hydrolysis $3,543 $0 $4,627 $0 $8,170 9.7% $794 0% $0 20.0% $1,793 $10,758 $18

5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0

5A.7 Blowback Gas Systems $1,302 $0 $247 $0 $1,549 12.2% $189 0% $0 20.0% $348 $2,085 $3

5A.8 Fuel Gas Piping $0 $598 $419 $0 $1,018 9.3% $94 0% $0 20.0% $222 $1,334 $2

5A.9 HGCU Foundations $0 $617 $398 $0 $1,015 9.2% $93 0% $0 30.0% $332 $1,440 $2

5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

SUBTOTAL 5A. $69,877 $3,206 $65,125 $0 $138,207 $13,411 $19,997 $34,434 $206,049 $339

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0

5B.2 CO2 Compression & Drying $5,815 $0 $3,564 $0 $9,379 9.6% $903 0% $0 20.0% $2,057 $12,339 $20

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $5,815 $0 $3,564 $0 $9,379 $903 $0 $2,057 $12,339 $20

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 214

6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 13

6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 4

SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $231

7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $34,760 $0 $4,942 $0 $39,702 9.5% $3,775 0% $0 10.0% $4,348 $47,825 $79

7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

7.3 Ductwork $0 $1,711 $1,221 $0 $2,932 8.8% $257 0% $0 20.0% $638 $3,827 $6

7.4 Stack $3,338 $0 $1,254 $0 $4,592 9.6% $440 0% $0 10.0% $503 $5,535 $9

7.9 HRSG, Duct & Stack Foundations $0 $669 $642 $0 $1,311 9.3% $122 0% $0 30.0% $430 $1,863 $3

SUBTOTAL 7. $38,098 $2,380 $8,060 $0 $48,538 $4,594 $0 $5,919 $59,050 $97

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories $29,446 $0 $5,034 $0 $34,480 9.6% $3,308 0% $0 10.0% $3,779 $41,567 $68

8.2 Turbine Plant Auxiliaries $204 $0 $468 $0 $672 9.8% $66 0% $0 10.0% $74 $811 $1

8.3 Condenser & Auxiliaries $5,250 $0 $1,541 $0 $6,792 9.6% $649 0% $0 10.0% $744 $8,185 $13

8.4 Steam Piping $5,058 $0 $3,558 $0 $8,616 8.6% $740 0% $0 25.0% $2,339 $11,695 $19

8.9 TG Foundations $0 $1,012 $1,711 $0 $2,723 9.5% $258 0% $0 30.0% $894 $3,876 $6

SUBTOTAL 8. $39,958 $1,012 $12,312 $0 $53,282 $5,022 $0 $7,830 $66,134 $109

9 COOLING WATER SYSTEM

9.1 Cooling Towers $6,657 $0 $1,211 $0 $7,868 9.5% $749 0% $0 15.0% $1,293 $9,910 $16

9.2 Circulating Water Pumps $1,722 $0 $124 $0 $1,847 8.4% $156 0% $0 15.0% $300 $2,303 $4

9.3 Circ. Water System Auxiliaries $146 $0 $21 $0 $167 9.5% $16 0% $0 15.0% $27 $210 $0

9.4 Circ. Water Piping $0 $6,091 $1,579 $0 $7,670 9.0% $693 0% $0 20.0% $1,673 $10,036 $17

9.5 Make-up Water System $341 $0 $488 $0 $829 9.6% $80 0% $0 20.0% $182 $1,090 $2

9.6 Component Cooling Water System $719 $860 $612 $0 $2,191 9.4% $205 0% $0 20.0% $479 $2,875 $5

9.9 Circ. Water System Foundations $0 $2,236 $3,801 $0 $6,036 9.5% $572 0% $0 30.0% $1,983 $8,591 $14

SUBTOTAL 9. $9,586 $9,186 $7,836 $0 $26,608 $2,471 $0 $5,937 $35,016 $58

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*
Carbon Dioxide Capture Sensitivity Analysis

428

Exhibit 4-146 Case 2 D3A (25%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3A - GEE IGCC w/ two WGS bypass (25% CO2 Capture) x $1, 000

Plant Size: 607.02 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $11,758 $6,484 $13,171 $0 $31,413 9.7% $3,032 0% $0 10.0% $3,445 $37,890 $62

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.6 Ash Storage Silos $572 $0 $622 $0 $1,195 9.7% $116 0% $0 15.0% $197 $1,507 $2

10.7 Ash Transport & Feed Equipment $767 $0 $185 $0 $952 9.3% $89 0% $0 15.0% $156 $1,197 $2

10.8 Misc. Ash Handling Equipment $1,185 $1,452 $434 $0 $3,071 9.5% $292 0% $0 15.0% $504 $3,867 $6

10.9 Ash/Spent Sorbent Foundation $0 $51 $64 $0 $114 9.4% $11 0% $0 30.0% $37 $162 $0

SUBTOTAL 10. $14,282 $7,986 $14,476 $0 $36,745 $3,540 $0 $4,339 $44,624 $74

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $961 $0 $951 $0 $1,912 9.5% $183 0% $0 10.0% $209 $2,303 $4

11.2 Station Service Equipment $4,152 $0 $374 $0 $4,526 9.2% $417 0% $0 10.0% $494 $5,437 $9

11.3 Switchgear & Motor Control $7,676 $0 $1,396 $0 $9,071 9.3% $841 0% $0 15.0% $1,487 $11,400 $19

11.4 Conduit & Cable Tray $0 $3,566 $11,763 $0 $15,328 9.7% $1,483 0% $0 25.0% $4,203 $21,013 $35

11.5 Wire & Cable $0 $6,813 $4,476 $0 $11,289 7.3% $820 0% $0 25.0% $3,027 $15,136 $25

11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7

11.7 Standby Equipment $236 $0 $231 $0 $467 9.5% $45 0% $0 15.0% $77 $588 $1

11.8 Main Power Transformers $17,787 $0 $146 $0 $17,934 7.6% $1,356 0% $0 15.0% $2,894 $22,184 $37

11.9 Electrical Foundations $0 $159 $417 $0 $577 9.6% $55 0% $0 30.0% $190 $821 $1

SUBTOTAL 11. $30,812 $11,223 $22,250 $0 $64,285 $5,511 $0 $13,104 $82,900 $137

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.4 Other Major Component Control $1,045 $0 $698 $0 $1,743 9.5% $165 5% $87 15.0% $299 $2,295 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.6 Control Boards,Panels & Racks $240 $0 $154 $0 $394 9.5% $37 5% $20 20.0% $90 $541 $1

12.7 Computer & Accessories $5,575 $0 $178 $0 $5,754 9.2% $528 5% $288 10.0% $657 $7,227 $12

12.8 Instrument Wiring & Tubing $0 $1,948 $3,982 $0 $5,929 8.5% $503 5% $296 25.0% $1,682 $8,411 $14

12.9 Other I & C Equipment $3,727 $0 $1,810 $0 $5,537 9.4% $521 5% $277 15.0% $950 $7,285 $12

SUBTOTAL 12. $10,588 $1,948 $6,822 $0 $19,357 $1,754 $968 $3,679 $25,758 $42

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 108 2,297 0 2,405 9.9% 239 0% 0 30.0% 793 3,437 6

13.2 Site Improvements 0 1,912 2,541 0 4,453 9.9% 439 0% 0 30.0% 1,468 6,359 10

13.3 Site Facilities 3,426 0 3,615 0 7,041 9.9% 694 0% 0 30.0% 2,321 10,056 17

SUBTOTAL 13. $3,426 $2,019 $8,453 $0 $13,899 $1,372 $0 $4,581 $19,852 $33

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

429

Exhibit 4-146 Case 2 D3A (25%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D3A - GEE IGCC w/ two WGS bypass (25% CO2 Capture) x $1, 000

Plant Size: 607.02 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $263 $149 $0 $412 8.8% $36 0% $0 20.0% $90 $539 $1

14.2 Steam Turbine Building $0 $2,361 $3,363 $0 $5,724 9.2% $527 0% $0 15.0% $938 $7,189 $12

14.3 Administration Building $0 $875 $634 $0 $1,509 8.9% $134 0% $0 15.0% $247 $1,890 $3

14.4 Circulation Water Pumphouse $0 $156 $82 $0 $238 8.8% $21 0% $0 15.0% $39 $298 $0

14.5 Water Treatment Buildings $0 $521 $508 $0 $1,028 9.0% $93 0% $0 15.0% $168 $1,290 $2

14.6 Machine Shop $0 $448 $306 $0 $754 8.9% $67 0% $0 15.0% $123 $944 $2

14.7 Warehouse $0 $723 $467 $0 $1,189 8.9% $105 0% $0 15.0% $194 $1,489 $2

14.8 Other Buildings & Structures $0 $433 $337 $0 $770 8.9% $69 0% $0 20.0% $168 $1,007 $2

14.9 Waste Treating Building & Str. $0 $962 $1,838 $0 $2,799 9.3% $261 0% $0 20.0% $612 $3,672 $6

SUBTOTAL 14. $0 $6,740 $7,685 $0 $14,425 $1,313 $0 $2,578 $18,316 $30

Total Cost $670,759 $73,022 $271,243 $0 $1,015,024 $95,417 $55,953 $179,985 $1,346,380 $2,218

Owner's Costs

Preproduction Costs

6 Months All Labor $12,719 $21

1 Month Maintenance Materials $2,756 $5

1 Month Non-fuel Consumables $273 $0

1 Month Waste Disposal $302 $0

25% of 1 Months Fuel Cost at 100% CF $1,613 $3

2% of TPC $26,928 $44

Total $44,590 $73

Inventory Capital

60 day supply of fuel and consumables at 100% CF $13,446 $22

0.5% of TPC (spare parts) $6,732 $11

Total $20,178 $33

Initial Cost for Catalyst and Chemicals $4,937 $8

Land $900 $1

Other Owner's Costs $201,957 $333

Financing Costs $36,352 $60

Total Overnight Costs (TOC) $1,655,294 $2,727

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $1,887,035 $3,109

Labor Bare 

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Project Cont.
Carbon Dioxide Capture Sensitivity Analysis

430

Exhibit 4-147 Case 2 D3A Initial and Annual O&M Expenses

Case: Case 2 D3A - GEE IGCC w/ two WGS bypass (25% CO2 Capture)

Plant Size (MWe): 607.02 Heat Rate (Btu/kWh): 8,894

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 80 CO2 Captured (TPD): 3,127

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 10.0 10.0

Foreman 1.0 1.0

Lab Tech's etc. 3.0 3.0

TOTAL Operating Jobs 16.0 16.0

$ $/kW-net

Annual Operating Labor Cost (calc'd) $6,313,507 $10.401

Maintenance Labor Cost (calc'd) $14,036,245 $23.123

Administrative & Support Labor (calc'd) $5,087,438 $8.381

Property Taxes & Insurance $26,927,596 $44.360

TOTAL FIXED OPERATING COSTS $52,364,786 $86.266

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $26,460,253 0.00622

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 3,380 1.08 $0 $1,067,697 0.00025

Chemicals

MU & WT Chem. (lbs) 0 20,139 0.17 $0 $1,017,765 0.00024

Carbon (Mercury Removal) (lb) 55,244 95 1.05 $58,016 $29,132 0.00001

COS Catalyst (m3) 417 0.29 2,397.36 $998,740 $199,748 0.00005

Water Gas Shift Catalyst (ft3) 16 0.01 498.83 $7,981 $1,596 0.00000

Selexol Solution (gal) 289,013 59 13.40 $3,872,261 $230,395 0.00005

SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000

Claus Catalyst (ft3) 0 1.92 131.27 $0 $73,424 0.00002

Subtotal Chemicals $4,936,998 $1,552,059 0.00036

Other

Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $0 0.00000

Waste Disposal

Spent Mercury Sorbent (lb) 0 95 0.42 $0 $11,651 0.00000

Flyash (ton) 0 0 0.00 $0 $0 0.00000

Slag (ton) 0 609 16.23 $0 $2,886,704 0.00068

Subtotal Solid Waste Disposal $0 $2,898,355 $0

By-products & Emissions

Sulfur (tons) 0 139 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $31,978,364 0.00752

Coal FUEL (tons) 0 5,553 38.19 $0 $61,920,722 0.01456

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

431

Exhibit 4-148 Case 2 D3B (45%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3B - GEE IGCC w/ two WGS bypass (45% CO2 Capture) x $1, 000

Plant Size: 590.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload $3,667 $0 $1,792 $0 $5,460 9.0% $489 0% $0 20.0% $1,190 $7,139 $12

1.2 Coal Stackout & Reclaim $4,739 $0 $1,149 $0 $5,888 8.8% $516 0% $0 20.0% $1,281 $7,685 $13

1.3 Coal Conveyors & Yd Crus $4,406 $0 $1,137 $0 $5,543 8.8% $487 0% $0 20.0% $1,206 $7,236 $12

1.4 Other Coal Handling $1,153 $0 $263 $0 $1,416 8.8% $124 0% $0 20.0% $308 $1,848 $3

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $2,595 $6,489 $0 $9,084 9.6% $871 0% $0 20.0% $1,991 $11,946 $20

SUBTOTAL 1. $13,966 $2,595 $10,830 $0 $27,391 $2,486 $0 $5,975 $35,853 $61

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,564 $374 $245 $0 $2,184 8.6% 187 0% 0 20.0% $474 $2,845 $5

2.3 Slurry Prep & Feed $21,388 $0 $9,440 $0 $30,828 9.1% 2,801 5% 1,541 20.0% $7,034 $42,204 $72

2.4 Misc. Coal Prep & Feed $860 $626 $1,877 $0 $3,363 9.2% 309 0% 0 20.0% $734 $4,406 $7

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $3,343 $2,745 $0 $6,088 9.3% 564 0% 0 20.0% $1,330 $7,983 $14

SUBTOTAL 2. $23,812 $4,344 $14,307 $0 $42,463 $3,861 $1,541 $9,573 $57,438 $97

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 2,864 4,918 2,596 0 10,377 9.3% 961 0% 0 20.0% $2,268 $13,606 $23

3.2 Water Makeup & Pretreating 648 68 362 0 1,078 9.5% 103 0% 0 30.0% $354 $1,535 $3

3.3 Other Feedwater Subsystems 1,567 529 476 0 2,573 9.0% 231 0% 0 20.0% $561 $3,365 $6

3.4 Service Water Systems 371 764 2,650 0 3,785 9.8% 369 0% 0 30.0% $1,246 $5,400 $9

3.5 Other Boiler Plant Systems 1,990 771 1,911 0 4,672 9.5% 443 0% 0 20.0% $1,023 $6,138 $10

3.6 FO Supply Sys & Nat Gas $313 $590 $551 $0 1,454 9.6% 140 0% 0 20.0% $319 $1,913 $3

3.7 Waste Treatment Equipment 906 0 553 0 1,458 9.7% 142 0% 0 30.0% $480 $2,080 $4

3.8 Misc. Power Plant Equipment $1,111 $149 $571 $0 1,831 9.7% 177 0% 0 30.0% $602 $2,610 $4

SUBTOTAL 3. $9,769 $7,789 $9,670 $0 $27,227 $2,566 $0 $6,853 $36,647 $62

4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $111,036 $0 $60,840 $0 $171,875 9.2% $15,745 13.9% $23,853 15.3% $32,426 $243,899 $413

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.3 ASU/Oxidant Compression $188,280 $0 w/equip. $0 $188,280 9.7% $18,250 0% $0 10.0% $20,653 $227,183 $385

4.4 Scrubber & Low Temperature Cooling 5,899 $4,801 $4,997 $0 $15,698 9.6% $1,507 0% $0 20.0% $3,441 $20,646 $35

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.6 Soot Recovery & SARU $1,799 $854 $1,688 $0 $4,342 9.6% $418 0% $0 20.0% $952 $5,712 $10

4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.8 Gasification Foundations $0 $6,325 $5,280 $0 $11,604 9.3% $1,075 0% $0 25.0% $3,170 $15,849 $27

SUBTOTAL 4. $307,014 $11,980 $72,805 $0 $391,799 $36,996 $23,853 $60,642 $513,290 $870

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

432

Exhibit 4-148 Case 2 D3B (45%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3B - GEE IGCC w/ two WGS bypass (45% CO2 Capture) x $1, 000

Plant Size: 590.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $60,416 $0 $51,265 $0 $111,681 9.7% $10,801 20% $22,336 20.0% $28,964 $173,782 $295

5A.2 Elemental Sulfur Plant $10,086 $2,010 $13,013 $0 $25,110 9.7% $2,439 0% $0 20.0% $5,510 $33,058 $56

5A.3 Mercury Removal $1,159 $0 $882 $0 $2,041 9.7% $197 5% $102 20.0% $468 $2,808 $5

5A.4 Shift Reactors $4,761 $0 $1,917 $0 $6,677 9.6% $640 0% $0 20.0% $1,464 $8,781 $15

5A.5 COS Hydrolysis $2,778 $0 $3,627 $0 $6,405 9.7% $623 0% $0 20.0% $1,405 $8,433 $14

5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0

5A.7 Blowback Gas Systems $1,316 $0 $249 $0 $1,565 12.2% $191 0% $0 20.0% $351 $2,107 $4

5A.8 Fuel Gas Piping $0 $609 $427 $0 $1,036 9.3% $96 0% $0 20.0% $226 $1,358 $2

5A.9 HGCU Foundations $0 $624 $402 $0 $1,027 9.2% $94 0% $0 30.0% $336 $1,457 $2

5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

SUBTOTAL 5A. $80,516 $3,243 $71,782 $0 $155,541 $15,081 $22,438 $38,724 $231,785 $393

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0

5B.2 CO2 Compression & Drying $9,615 $0 $5,894 $0 $15,509 9.6% $1,494 0% $0 20.0% $3,401 $20,403 $35

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $9,615 $0 $5,894 $0 $15,509 $1,494 $0 $3,401 $20,403 $35

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 220

6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 13

6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5

SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $238

7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $34,421 $0 $4,894 $0 $39,315 9.5% $3,738 0% $0 10.0% $4,305 $47,359 $80

7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

7.3 Ductwork $0 $1,717 $1,225 $0 $2,943 8.8% $258 0% $0 20.0% $640 $3,841 $7

7.4 Stack $3,350 $0 $1,259 $0 $4,609 9.6% $442 0% $0 10.0% $505 $5,555 $9

7.9 HRSG, Duct & Stack Foundations $0 $671 $645 $0 $1,316 9.3% $123 0% $0 30.0% $432 $1,870 $3

SUBTOTAL 7. $37,771 $2,389 $8,023 $0 $48,182 $4,560 $0 $5,882 $58,625 $99

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories $29,111 $0 $4,977 $0 $34,088 9.6% $3,271 0% $0 10.0% $3,736 $41,095 $70

8.2 Turbine Plant Auxiliaries $202 $0 $463 $0 $664 9.8% $65 0% $0 10.0% $73 $802 $1

8.3 Condenser & Auxiliaries $5,226 $0 $1,534 $0 $6,761 9.6% $646 0% $0 10.0% $741 $8,148 $14

8.4 Steam Piping $5,056 $0 $3,557 $0 $8,613 8.6% $740 0% $0 25.0% $2,338 $11,691 $20

8.9 TG Foundations $0 $1,001 $1,692 $0 $2,693 9.5% $255 0% $0 30.0% $884 $3,832 $6

SUBTOTAL 8. $39,595 $1,001 $12,222 $0 $52,819 $4,977 $0 $7,772 $65,568 $111

9 COOLING WATER SYSTEM

9.1 Cooling Towers $6,825 $0 $1,242 $0 $8,067 9.5% $768 0% $0 15.0% $1,325 $10,160 $17

9.2 Circulating Water Pumps $1,767 $0 $128 $0 $1,895 8.4% $160 0% $0 15.0% $308 $2,363 $4

9.3 Circ. Water System Auxiliaries $149 $0 $21 $0 $170 9.5% $16 0% $0 15.0% $28 $215 $0

9.4 Circ. Water Piping $0 $6,223 $1,613 $0 $7,836 9.0% $708 0% $0 20.0% $1,709 $10,253 $17

9.5 Make-up Water System $356 $0 $509 $0 $865 9.6% $83 0% $0 20.0% $190 $1,138 $2

9.6 Component Cooling Water System $735 $879 $625 $0 $2,238 9.4% $210 0% $0 20.0% $490 $2,938 $5

9.9 Circ. Water System Foundations $0 $2,284 $3,883 $0 $6,167 9.5% $585 0% $0 30.0% $2,026 $8,777 $15

SUBTOTAL 9. $9,832 $9,385 $8,021 $0 $27,238 $2,530 $0 $6,075 $35,843 $61

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*
Carbon Dioxide Capture Sensitivity Analysis

433

Exhibit 4-148 Case 2 D3B (45%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3B - GEE IGCC w/ two WGS bypass (45% CO2 Capture) x $1, 000

Plant Size: 590.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $11,869 $6,545 $13,296 $0 $31,710 9.7% $3,061 0% $0 10.0% $3,477 $38,247 $65

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.6 Ash Storage Silos $577 $0 $628 $0 $1,205 9.7% $117 0% $0 15.0% $198 $1,520 $3

10.7 Ash Transport & Feed Equipment $774 $0 $187 $0 $961 9.3% $90 0% $0 15.0% $158 $1,208 $2

10.8 Misc. Ash Handling Equipment $1,195 $1,464 $437 $0 $3,097 9.5% $295 0% $0 15.0% $509 $3,900 $7

10.9 Ash/Spent Sorbent Foundation $0 $51 $64 $0 $115 9.4% $11 0% $0 30.0% $38 $164 $0

SUBTOTAL 10. $14,415 $8,060 $14,612 $0 $37,087 $3,573 $0 $4,379 $45,039 $76

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $958 $0 $947 $0 $1,905 9.5% $182 0% $0 10.0% $209 $2,295 $4

11.2 Station Service Equipment $4,308 $0 $388 $0 $4,696 9.2% $433 0% $0 10.0% $513 $5,642 $10

11.3 Switchgear & Motor Control $7,964 $0 $1,448 $0 $9,412 9.3% $873 0% $0 15.0% $1,543 $11,828 $20

11.4 Conduit & Cable Tray $0 $3,700 $12,205 $0 $15,904 9.7% $1,538 0% $0 25.0% $4,361 $21,803 $37

11.5 Wire & Cable $0 $7,069 $4,644 $0 $11,713 7.3% $851 0% $0 25.0% $3,141 $15,705 $27

11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7

11.7 Standby Equipment $236 $0 $230 $0 $466 9.5% $44 0% $0 15.0% $76 $586 $1

11.8 Main Power Transformers $17,714 $0 $146 $0 $17,860 7.6% $1,351 0% $0 15.0% $2,882 $22,093 $37

11.9 Electrical Foundations $0 $158 $416 $0 $574 9.6% $55 0% $0 30.0% $189 $818 $1

SUBTOTAL 11. $31,180 $11,613 $22,920 $0 $65,712 $5,638 $0 $13,437 $84,787 $144

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.4 Other Major Component Control $1,069 $0 $714 $0 $1,782 9.5% $169 5% $89 15.0% $306 $2,346 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.6 Control Boards,Panels & Racks $246 $0 $157 $0 $403 9.5% $38 5% $20 20.0% $92 $554 $1

12.7 Computer & Accessories $5,700 $0 $183 $0 $5,883 9.2% $540 5% $294 10.0% $672 $7,389 $13

12.8 Instrument Wiring & Tubing $0 $1,991 $4,071 $0 $6,062 8.5% $514 5% $303 25.0% $1,720 $8,600 $15

12.9 Other I & C Equipment $3,811 $0 $1,850 $0 $5,661 9.4% $533 5% $283 15.0% $971 $7,448 $13

SUBTOTAL 12. $10,825 $1,991 $6,975 $0 $19,791 $1,794 $990 $3,761 $26,336 $45

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 108 2,312 0 2,420 9.9% 240 0% 0 30.0% 798 3,458 6

13.2 Site Improvements 0 1,924 2,556 0 4,480 9.9% 442 0% 0 30.0% 1,477 6,399 11

13.3 Site Facilities 3,447 0 3,638 0 7,085 9.9% 698 0% 0 30.0% 2,335 10,118 17

SUBTOTAL 13. $3,447 $2,032 $8,506 $0 $13,985 $1,380 $0 $4,610 $19,975 $34

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Project Cont.

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST
Carbon Dioxide Capture Sensitivity Analysis

434

Exhibit 4-148 Case 2 D3B (45%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D3B - GEE IGCC w/ two WGS bypass (45% CO2 Capture) x $1, 000

Plant Size: 590.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $264 $149 $0 $413 8.8% $36 0% $0 20.0% $90 $539 $1

14.2 Steam Turbine Building $0 $2,367 $3,372 $0 $5,738 9.2% $528 0% $0 15.0% $940 $7,206 $12

14.3 Administration Building $0 $877 $636 $0 $1,514 8.9% $135 0% $0 15.0% $247 $1,896 $3

14.4 Circulation Water Pumphouse $0 $159 $84 $0 $243 8.8% $21 0% $0 15.0% $40 $304 $1

14.5 Water Treatment Buildings $0 $546 $532 $0 $1,078 9.0% $97 0% $0 15.0% $176 $1,351 $2

14.6 Machine Shop $0 $449 $307 $0 $756 8.9% $67 0% $0 15.0% $124 $947 $2

14.7 Warehouse $0 $725 $468 $0 $1,193 8.9% $106 0% $0 15.0% $195 $1,493 $3

14.8 Other Buildings & Structures $0 $434 $338 $0 $772 8.9% $69 0% $0 20.0% $168 $1,010 $2

14.9 Waste Treating Building & Str. $0 $966 $1,847 $0 $2,813 9.3% $262 0% $0 20.0% $615 $3,690 $6

SUBTOTAL 14. $0 $6,787 $7,734 $0 $14,521 $1,322 $0 $2,595 $18,437 $31

Total Cost $689,332 $74,096 $282,632 $0 $1,046,059 $98,381 $58,683 $187,111 $1,390,235 $2,356

Owner's Costs

Preproduction Costs

6 Months All Labor $12,987 $22

1 Month Maintenance Materials $2,841 $5

1 Month Non-fuel Consumables $311 $1

1 Month Waste Disposal $307 $1

25% of 1 Months Fuel Cost at 100% CF $1,637 $3

2% of TPC $27,805 $47

Total $45,887 $78

Inventory Capital

60 day supply of fuel and consumables at 100% CF $13,720 $23

0.5% of TPC (spare parts) $6,951 $12

Total $20,671 $35

Initial Cost for Catalyst and Chemicals $5,828 $10

Land $900 $2

Other Owner's Costs $208,535 $353

Financing Costs $37,536 $64

Total Overnight Costs (TOC) $1,709,592 $2,897

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $1,948,935 $3,303

Labor Bare 

Erected 

Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Project Cont.
Carbon Dioxide Capture Sensitivity Analysis

435

Exhibit 4-149 Case 2 D3B Initial and Annual O&M Expenses

Case: Case 2 D3B - GEE IGCC w/ two WGS bypass (45% CO2 Capture)

Plant Size (MWe): 590.05 Heat Rate (Btu/kWh): 9,289

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 80 CO2 Captured (TPD): 5,732

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 10.0 10.0

Foreman 1.0 1.0

Lab Tech's etc. 3.0 3.0

TOTAL Operating Jobs 16.0 16.0

$ $/kW-net

Annual Operating Labor Cost (calc'd) $6,313,507 $10.700

Maintenance Labor Cost (calc'd) $14,465,416 $24.516

Administrative & Support Labor (calc'd) $5,194,731 $8.804

Property Taxes & Insurance $27,804,693 $47.123

TOTAL FIXED OPERATING COSTS $53,778,347 $91.142

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $27,269,300 0.00659

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 3,629 1.08 $0 $1,146,154 0.00028

Chemicals

MU & WT Chem. (lbs) 0 21,619 0.17 $0 $1,092,552 0.00026

Carbon (Mercury Removal) (lb) 62,427 107 1.05 $65,559 $32,812 0.00001

COS Catalyst (m3) 294 0.20 2,397.36 $705,303 $141,061 0.00003

Water Gas Shift Catalyst (ft3) 2,296 1.57 498.83 $1,145,316 $229,063 0.00006

Selexol Solution (gal) 291,937 70 13.40 $3,911,435 $273,860 0.00007

SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000

Claus Catalyst (ft3) 0 1.94 131.27 $0 $74,521 0.00002

Subtotal Chemicals $5,827,613 $1,843,868 0.00045

Other

Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $0 0.00000

Waste Disposal

Spent Mercury Sorbent (lb) 0 107 0.42 $0 $13,122 0.00000

Flyash (ton) 0 0 0.00 $0 $0 0.00000

Slag (ton) 0 619 16.23 $0 $2,930,765 0.00071

Subtotal Solid Waste Disposal $0 $2,943,888 $0

By-products & Emissions

Sulfur (tons) 0 141 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $33,203,210 0.00803

Coal FUEL (tons) 0 5,638 38.19 $0 $62,865,489 0.01520

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

436

Exhibit 4-150 Case 2 D3C (60%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3C - GEE IGCC w/ two WGS bypass (60% CO2 Capture) x $1, 000

Plant Size: 577.43 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload $3,697 $0 $1,806 $0 $5,503 9.0% $493 0% $0 20.0% $1,199 $7,195 $12

1.2 Coal Stackout & Reclaim $4,777 $0 $1,158 $0 $5,935 8.8% $520 0% $0 20.0% $1,291 $7,746 $13

1.3 Coal Conveyors & Yd Crus $4,441 $0 $1,146 $0 $5,587 8.8% $490 0% $0 20.0% $1,215 $7,293 $13

1.4 Other Coal Handling $1,162 $0 $265 $0 $1,427 8.8% $125 0% $0 20.0% $310 $1,862 $3

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $2,616 $6,541 $0 $9,157 9.6% $878 0% $0 20.0% $2,007 $12,041 $21

SUBTOTAL 1. $14,076 $2,616 $10,916 $0 $27,608 $2,506 $0 $6,023 $36,137 $63

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,577 $377 $247 $0 $2,202 8.6% 188 0% 0 20.0% $478 $2,869 $5

2.3 Slurry Prep & Feed $21,571 $0 $9,520 $0 $31,091 9.1% 2,825 5% 1,555 20.0% $7,094 $42,564 $74

2.4 Misc. Coal Prep & Feed $867 $631 $1,893 $0 $3,391 9.2% 312 0% 0 20.0% $741 $4,443 $8

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $3,372 $2,768 $0 $6,140 9.3% 569 0% 0 20.0% $1,342 $8,050 $14

SUBTOTAL 2. $24,016 $4,380 $14,428 $0 $42,824 $3,893 $1,555 $9,654 $57,926 $100

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 2,848 4,891 2,582 0 10,321 9.3% 956 0% 0 20.0% $2,255 $13,533 $23

3.2 Water Makeup & Pretreating 672 70 376 0 1,118 9.5% 106 0% 0 30.0% $367 $1,592 $3

3.3 Other Feedwater Subsystems 1,558 527 474 0 2,559 9.0% 230 0% 0 20.0% $558 $3,346 $6

3.4 Service Water Systems 385 792 2,749 0 3,926 9.8% 383 0% 0 30.0% $1,293 $5,601 $10

3.5 Other Boiler Plant Systems 2,064 800 1,982 0 4,846 9.5% 460 0% 0 20.0% $1,061 $6,367 $11

3.6 FO Supply Sys & Nat Gas $314 $592 $552 $0 1,458 9.6% 140 0% 0 20.0% $320 $1,919 $3

3.7 Waste Treatment Equipment 940 0 573 0 1,513 9.7% 147 0% 0 30.0% $498 $2,158 $4

3.8 Misc. Power Plant Equipment $1,115 $149 $573 $0 1,837 9.7% 177 0% 0 30.0% $604 $2,618 $5

SUBTOTAL 3. $9,896 $7,821 $9,861 $0 $27,578 $2,601 $0 $6,956 $37,135 $64

4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $112,030 $0 $61,384 $0 $173,415 9.2% $15,886 13.9% $24,066 15.3% $32,716 $246,084 $426

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.3 ASU/Oxidant Compression $189,980 $0 w/equip. $0 $189,980 9.7% $18,415 0% $0 10.0% $20,839 $229,234 $397

4.4 Scrubber & Low Temperature Cooling 5,952 $4,844 $5,042 $0 $15,838 9.6% $1,521 0% $0 20.0% $3,472 $20,831 $36

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.6 Soot Recovery & SARU $1,815 $862 $1,704 $0 $4,381 9.6% $422 0% $0 20.0% $961 $5,763 $10

4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.8 Gasification Foundations $0 $6,381 $5,327 $0 $11,708 9.3% $1,085 0% $0 25.0% $3,198 $15,991 $28

SUBTOTAL 4. $309,777 $12,088 $73,457 $0 $395,322 $37,329 $24,066 $61,187 $517,904 $897

Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Acct No. Item/Description Erected 

Equipment 

Cost

Material 

Cost

Labor
Carbon Dioxide Capture Sensitivity Analysis

437

Exhibit 4-150 Case 2 D3C (60%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3C - GEE IGCC w/ two WGS bypass (60% CO2 Capture) x $1, 000

Plant Size: 577.43 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $64,608 $0 $54,821 $0 $119,429 9.7% $11,550 20% $23,886 20.0% $30,973 $185,838 $322

5A.2 Elemental Sulfur Plant $10,171 $2,027 $13,123 $0 $25,321 9.7% $2,460 0% $0 20.0% $5,556 $33,337 $58

5A.3 Mercury Removal $1,235 $0 $940 $0 $2,175 9.7% $210 5% $109 20.0% $499 $2,992 $5

5A.4 Shift Reactors $7,237 $0 $2,913 $0 $10,150 9.6% $973 0% $0 20.0% $2,225 $13,348 $23

5A.5 COS Hydrolysis $2,070 $0 $2,703 $0 $4,773 9.7% $464 0% $0 20.0% $1,047 $6,284 $11

5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0

5A.7 Blowback Gas Systems $1,328 $0 $252 $0 $1,579 12.2% $193 0% $0 20.0% $354 $2,126 $4

5A.8 Fuel Gas Piping $0 $620 $434 $0 $1,054 9.3% $98 0% $0 20.0% $230 $1,382 $2

5A.9 HGCU Foundations $0 $630 $406 $0 $1,037 9.2% $95 0% $0 30.0% $340 $1,472 $3

5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

SUBTOTAL 5A. $86,648 $3,277 $75,592 $0 $165,518 $16,043 $23,995 $41,224 $246,779 $427

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0

5B.2 CO2 Compression & Drying $12,507 $0 $7,666 $0 $20,173 9.6% $1,943 0% $0 20.0% $4,423 $26,540 $46

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $12,507 $0 $7,666 $0 $20,173 $1,943 $0 $4,423 $26,540 $46

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 224

6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 14

6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5

SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $243

7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $34,172 $0 $4,859 $0 $39,031 9.5% $3,711 0% $0 10.0% $4,274 $47,017 $81

7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

7.3 Ductwork $0 $1,721 $1,228 $0 $2,949 8.8% $259 0% $0 20.0% $642 $3,850 $7

7.4 Stack $3,358 $0 $1,262 $0 $4,620 9.6% $443 0% $0 10.0% $506 $5,568 $10

7.9 HRSG, Duct & Stack Foundations $0 $673 $646 $0 $1,319 9.3% $123 0% $0 30.0% $433 $1,874 $3

SUBTOTAL 7. $37,530 $2,394 $7,995 $0 $47,919 $4,535 $0 $5,855 $58,309 $101

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories $28,939 $0 $4,947 $0 $33,887 9.6% $3,251 0% $0 10.0% $3,714 $40,852 $71

8.2 Turbine Plant Auxiliaries $201 $0 $460 $0 $661 9.8% $65 0% $0 10.0% $73 $798 $1

8.3 Condenser & Auxiliaries $5,178 $0 $1,520 $0 $6,699 9.6% $640 0% $0 10.0% $734 $8,073 $14

8.4 Steam Piping $5,029 $0 $3,537 $0 $8,566 8.6% $736 0% $0 25.0% $2,325 $11,627 $20

8.9 TG Foundations $0 $995 $1,682 $0 $2,677 9.5% $254 0% $0 30.0% $879 $3,810 $7

SUBTOTAL 8. $39,347 $995 $12,147 $0 $52,489 $4,946 $0 $7,725 $65,160 $113

9 COOLING WATER SYSTEM

9.1 Cooling Towers $6,950 $0 $1,264 $0 $8,214 9.5% $782 0% $0 15.0% $1,349 $10,346 $18

9.2 Circulating Water Pumps $1,800 $0 $130 $0 $1,931 8.4% $163 0% $0 15.0% $314 $2,408 $4

9.3 Circ. Water System Auxiliaries $151 $0 $22 $0 $173 9.5% $16 0% $0 15.0% $28 $218 $0

9.4 Circ. Water Piping $0 $6,320 $1,639 $0 $7,959 9.0% $719 0% $0 20.0% $1,736 $10,414 $18

9.5 Make-up Water System $367 $0 $525 $0 $892 9.6% $86 0% $0 20.0% $196 $1,174 $2

9.6 Component Cooling Water System $746 $892 $635 $0 $2,273 9.4% $213 0% $0 20.0% $497 $2,984 $5

9.9 Circ. Water System Foundations $0 $2,320 $3,944 $0 $6,264 9.5% $594 0% $0 30.0% $2,057 $8,915 $15

SUBTOTAL 9. $10,015 $9,533 $8,159 $0 $27,706 $2,573 $0 $6,178 $36,458 $63

*

Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Acct No. Item/Description Erected 

Equipment 

Cost

Material 

Cost

Labor
Carbon Dioxide Capture Sensitivity Analysis

438

Exhibit 4-150 Case 2 D3C (60%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3C - GEE IGCC w/ two WGS bypass (60% CO2 Capture) x $1, 000

Plant Size: 577.43 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $11,963 $6,597 $13,401 $0 $31,961 9.7% $3,085 0% $0 10.0% $3,505 $38,551 $67

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.6 Ash Storage Silos $581 $0 $632 $0 $1,213 9.7% $118 0% $0 15.0% $200 $1,531 $3

10.7 Ash Transport & Feed Equipment $779 $0 $188 $0 $967 9.3% $90 0% $0 15.0% $159 $1,216 $2

10.8 Misc. Ash Handling Equipment $1,204 $1,475 $441 $0 $3,119 9.5% $297 0% $0 15.0% $512 $3,928 $7

10.9 Ash/Spent Sorbent Foundation $0 $51 $65 $0 $116 9.4% $11 0% $0 30.0% $38 $165 $0

SUBTOTAL 10. $14,527 $8,123 $14,727 $0 $37,377 $3,600 $0 $4,413 $45,391 $79

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $956 $0 $945 $0 $1,901 9.5% $182 0% $0 10.0% $208 $2,291 $4

11.2 Station Service Equipment $4,432 $0 $399 $0 $4,832 9.2% $445 0% $0 10.0% $528 $5,805 $10

11.3 Switchgear & Motor Control $8,194 $0 $1,490 $0 $9,684 9.3% $898 0% $0 15.0% $1,587 $12,170 $21

11.4 Conduit & Cable Tray $0 $3,806 $12,557 $0 $16,363 9.7% $1,583 0% $0 25.0% $4,487 $22,433 $39

11.5 Wire & Cable $0 $7,273 $4,779 $0 $12,051 7.3% $875 0% $0 25.0% $3,232 $16,158 $28

11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7

11.7 Standby Equipment $235 $0 $230 $0 $465 9.5% $44 0% $0 15.0% $76 $586 $1

11.8 Main Power Transformers $17,677 $0 $145 $0 $17,822 7.6% $1,348 0% $0 15.0% $2,876 $22,046 $38

11.9 Electrical Foundations $0 $158 $415 $0 $573 9.6% $55 0% $0 30.0% $188 $816 $1

SUBTOTAL 11. $31,494 $11,923 $23,456 $0 $66,874 $5,741 $0 $13,706 $86,321 $149

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.4 Other Major Component Control $1,087 $0 $726 $0 $1,813 9.5% $172 5% $91 15.0% $311 $2,386 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.6 Control Boards,Panels & Racks $250 $0 $160 $0 $410 9.5% $39 5% $21 20.0% $94 $563 $1

12.7 Computer & Accessories $5,799 $0 $186 $0 $5,985 9.2% $549 5% $299 10.0% $683 $7,516 $13

12.8 Instrument Wiring & Tubing $0 $2,026 $4,141 $0 $6,167 8.5% $523 5% $308 25.0% $1,750 $8,748 $15

12.9 Other I & C Equipment $3,876 $0 $1,882 $0 $5,759 9.4% $542 5% $288 15.0% $988 $7,577 $13

SUBTOTAL 12. $11,012 $2,026 $7,095 $0 $20,133 $1,825 $1,007 $3,826 $26,791 $46

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 109 2,321 0 2,430 9.9% 241 0% 0 30.0% 801 3,472 6

13.2 Site Improvements 0 1,931 2,567 0 4,498 9.9% 444 0% 0 30.0% 1,483 6,424 11

13.3 Site Facilities 3,461 0 3,652 0 7,113 9.9% 701 0% 0 30.0% 2,344 10,159 18

SUBTOTAL 13. $3,461 $2,040 $8,540 $0 $14,041 $1,386 $0 $4,628 $20,055 $35

Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Acct No. Item/Description Erected 

Equipment 

Cost

Material 

Cost

Labor
Carbon Dioxide Capture Sensitivity Analysis

439

Exhibit 4-150 Case 2 D3C (60%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D3C - GEE IGCC w/ two WGS bypass (60% CO2 Capture) x $1, 000

Plant Size: 577.43 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $264 $149 $0 $414 8.8% $36 0% $0 20.0% $90 $540 $1

14.2 Steam Turbine Building $0 $2,371 $3,377 $0 $5,748 9.2% $529 0% $0 15.0% $941 $7,218 $13

14.3 Administration Building $0 $879 $638 $0 $1,517 8.9% $135 0% $0 15.0% $248 $1,900 $3

14.4 Circulation Water Pumphouse $0 $161 $86 $0 $247 8.8% $22 0% $0 15.0% $40 $309 $1

14.5 Water Treatment Buildings $0 $564 $551 $0 $1,115 9.0% $101 0% $0 15.0% $182 $1,398 $2

14.6 Machine Shop $0 $450 $308 $0 $758 8.9% $67 0% $0 15.0% $124 $949 $2

14.7 Warehouse $0 $726 $469 $0 $1,195 8.9% $106 0% $0 15.0% $195 $1,496 $3

14.8 Other Buildings & Structures $0 $435 $339 $0 $774 8.9% $69 0% $0 20.0% $169 $1,012 $2

14.9 Waste Treating Building & Str. $0 $970 $1,853 $0 $2,823 9.3% $263 0% $0 20.0% $617 $3,704 $6

SUBTOTAL 14. $0 $6,821 $7,770 $0 $14,590 $1,328 $0 $2,607 $18,525 $32

Total Cost $701,883 $74,924 $290,140 $0 $1,066,947 $100,373 $60,483 $191,838 $1,419,640 $2,459

Owner's Costs

Preproduction Costs

6 Months All Labor $13,167 $23

1 Month Maintenance Materials $2,897 $5

1 Month Non-fuel Consumables $342 $1

1 Month Waste Disposal $311 $1

25% of 1 Months Fuel Cost at 100% CF $1,658 $3

2% of TPC $28,393 $49

Total $46,768 $81

Inventory Capital

60 day supply of fuel and consumables at 100% CF $13,949 $24

0.5% of TPC (spare parts) $7,098 $12

Total $21,047 $36

Initial Cost for Catalyst and Chemicals $6,559 $11

Land $900 $2

Other Owner's Costs $212,946 $369

Financing Costs $38,330 $66

Total Overnight Costs (TOC) $1,746,192 $3,024

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $1,990,658 $3,447

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Erected 
Carbon Dioxide Capture Sensitivity Analysis

440

Exhibit 4-151 Case 2 D3C Initial and Annual O&M Expenses

Case: Case 2 D3C - GEE IGCC w/ two WGS bypass (60% CO2 Capture)

Plant Size (MWe): 577.43 Heat Rate (Btu/kWh): 9,614

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 80 CO2 Captured (TPD): 7,796

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 10.0 10.0

Foreman 1.0 1.0

Lab Tech's etc. 3.0 3.0

TOTAL Operating Jobs 16.0 16.0

$ $/kW-net

Annual Operating Labor Cost (calc'd) $6,313,507 $10.934

Maintenance Labor Cost (calc'd) $14,754,262 $25.552

Administrative & Support Labor (calc'd) $5,266,942 $9.121

Property Taxes & Insurance $28,392,808 $49.171

TOTAL FIXED OPERATING COSTS $54,727,519 $94.778

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $27,813,813 0.00687

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 3,821 1.08 $0 $1,206,873 0.00030

Chemicals

MU & WT Chem. (lbs) 0 22,765 0.17 $0 $1,150,432 0.00028

Carbon (Mercury Removal) (lb) 68,360 117 1.05 $71,790 $35,878 0.00001

COS Catalyst (m3) 193 0.13 2,397.36 $463,410 $92,682 0.00002

Water Gas Shift Catalyst (ft3) 4,176 2.86 498.83 $2,083,118 $416,624 0.00010

Selexol Solution (gal) 294,129 78 13.40 $3,940,815 $306,332 0.00008

SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000

Claus Catalyst (ft3) 0 1.97 131.27 $0 $75,459 0.00002

Subtotal Chemicals $6,559,132 $2,077,406 0.00051

Other

Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $0 0.00000

Waste Disposal

Spent Mercury Sorbent (lb) 0 117 0.42 $0 $14,349 0.00000

Flyash (ton) 0 0 0.00 $0 $0 0.00000

Slag (ton) 0 627 16.23 $0 $2,968,345 0.00073

Subtotal Solid Waste Disposal $0 $2,982,694 $0

By-products & Emissions

Sulfur (tons) 0 143 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $34,080,786 0.00842

Coal FUEL (tons) 0 5,710 38.19 $0 $63,671,371 0.01573

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

441

Exhibit 4-152 Case 2 D3D (75%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3D - GEE IGCC w/ two WGS bypass (75% CO2 Capture) x $1, 000

Plant Size: 563.80 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload $3,725 $0 $1,820 $0 $5,545 9.0% $497 0% $0 20.0% $1,208 $7,250 $13

1.2 Coal Stackout & Reclaim $4,813 $0 $1,167 $0 $5,980 8.8% $524 0% $0 20.0% $1,301 $7,805 $14

1.3 Coal Conveyors & Yd Crus $4,475 $0 $1,155 $0 $5,630 8.8% $494 0% $0 20.0% $1,225 $7,349 $13

1.4 Other Coal Handling $1,171 $0 $267 $0 $1,438 8.8% $126 0% $0 20.0% $313 $1,877 $3

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $2,636 $6,591 $0 $9,227 9.6% $884 0% $0 20.0% $2,022 $12,134 $22

SUBTOTAL 1. $14,184 $2,636 $11,000 $0 $27,820 $2,525 $0 $6,069 $36,415 $65

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,590 $381 $249 $0 $2,220 8.6% 190 0% 0 20.0% $482 $2,892 $5

2.3 Slurry Prep & Feed $21,750 $0 $9,598 $0 $31,348 9.1% 2,848 5% 1,567 20.0% $7,153 $42,916 $76

2.4 Misc. Coal Prep & Feed $874 $636 $1,908 $0 $3,419 9.2% 314 0% 0 20.0% $747 $4,480 $8

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $3,399 $2,791 $0 $6,190 9.3% 573 0% 0 20.0% $1,353 $8,116 $14

SUBTOTAL 2. $24,215 $4,416 $14,546 $0 $43,177 $3,925 $1,567 $9,734 $58,404 $104

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 2,832 4,863 2,567 0 10,262 9.3% 951 0% 0 20.0% $2,243 $13,456 $24

3.2 Water Makeup & Pretreating 696 73 389 0 1,157 9.5% 110 0% 0 30.0% $380 $1,647 $3

3.3 Other Feedwater Subsystems 1,549 524 471 0 2,544 9.0% 229 0% 0 20.0% $555 $3,327 $6

3.4 Service Water Systems 398 820 2,845 0 4,062 9.8% 396 0% 0 30.0% $1,338 $5,796 $10

3.5 Other Boiler Plant Systems 2,136 828 2,051 0 5,015 9.5% 476 0% 0 20.0% $1,098 $6,589 $12

3.6 FO Supply Sys & Nat Gas $315 $594 $554 $0 1,463 9.6% 141 0% 0 20.0% $321 $1,925 $3

3.7 Waste Treatment Equipment 972 0 593 0 1,565 9.7% 152 0% 0 30.0% $515 $2,233 $4

3.8 Misc. Power Plant Equipment $1,118 $150 $574 $0 1,842 9.7% 178 0% 0 30.0% $606 $2,626 $5

SUBTOTAL 3. $10,016 $7,851 $10,045 $0 $27,912 $2,633 $0 $7,055 $37,600 $67

4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $113,003 $0 $61,917 $0 $174,920 9.2% $16,024 13.9% $24,275 15.3% $33,000 $248,220 $440

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.3 ASU/Oxidant Compression $191,589 $0 w/equip. $0 $191,589 9.7% $18,571 0% $0 10.0% $21,016 $231,175 $410

4.4 Scrubber & Low Temperature Cooling 6,004 $4,886 $5,086 $0 $15,976 9.6% $1,534 0% $0 20.0% $3,502 $21,012 $37

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.6 Soot Recovery & SARU $1,831 $869 $1,718 $0 $4,419 9.6% $426 0% $0 20.0% $969 $5,813 $10

4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.8 Gasification Foundations $0 $6,437 $5,373 $0 $11,810 9.3% $1,094 0% $0 25.0% $3,226 $16,130 $29

SUBTOTAL 4. $312,426 $12,192 $74,095 $0 $398,713 $37,649 $24,275 $61,713 $522,350 $926

Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Acct No. Item/Description Erected 

Equipment 

Cost

Material 

Cost

Labor
Carbon Dioxide Capture Sensitivity Analysis

442

Exhibit 4-152 Case 2 D3D (75%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3D - GEE IGCC w/ two WGS bypass (75% CO2 Capture) x $1, 000

Plant Size: 563.80 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $68,896 $0 $58,460 $0 $127,356 9.7% $12,317 20% $25,471 20.0% $33,029 $198,173 $351

5A.2 Elemental Sulfur Plant $10,254 $2,044 $13,230 $0 $25,527 9.7% $2,480 0% $0 20.0% $5,601 $33,608 $60

5A.3 Mercury Removal $1,309 $0 $996 $0 $2,305 9.7% $223 5% $115 20.0% $529 $3,172 $6

5A.4 Shift Reactors $9,410 $0 $3,788 $0 $13,198 9.6% $1,265 0% $0 20.0% $2,893 $17,356 $31

5A.5 COS Hydrolysis $1,225 $0 $1,600 $0 $2,825 9.7% $275 0% $0 20.0% $620 $3,720 $7

5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0

5A.7 Blowback Gas Systems $1,339 $0 $254 $0 $1,593 12.2% $194 0% $0 20.0% $357 $2,145 $4

5A.8 Fuel Gas Piping $0 $630 $441 $0 $1,071 9.3% $99 0% $0 20.0% $234 $1,404 $2

5A.9 HGCU Foundations $0 $636 $410 $0 $1,047 9.2% $96 0% $0 30.0% $343 $1,486 $3

5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

SUBTOTAL 5A. $92,433 $3,310 $79,179 $0 $174,922 $16,949 $25,586 $43,606 $261,063 $463

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0

5B.2 CO2 Compression & Drying $15,364 $0 $9,418 $0 $24,782 9.6% $2,387 0% $0 20.0% $5,434 $32,603 $58

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $15,364 $0 $9,418 $0 $24,782 $2,387 $0 $5,434 $32,603 $58

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 230

6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 14

6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5

SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $249

7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,910 $0 $4,822 $0 $38,732 9.5% $3,683 0% $0 10.0% $4,241 $46,656 $83

7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

7.3 Ductwork $0 $1,726 $1,231 $0 $2,957 8.8% $259 0% $0 20.0% $643 $3,860 $7

7.4 Stack $3,367 $0 $1,265 $0 $4,632 9.6% $444 0% $0 10.0% $508 $5,583 $10

7.9 HRSG, Duct & Stack Foundations $0 $675 $648 $0 $1,322 9.3% $123 0% $0 30.0% $434 $1,879 $3

SUBTOTAL 7. $37,277 $2,401 $7,966 $0 $47,643 $4,509 $0 $5,826 $57,978 $103

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories $28,728 $0 $4,911 $0 $33,640 9.6% $3,228 0% $0 10.0% $3,687 $40,554 $72

8.2 Turbine Plant Auxiliaries $199 $0 $457 $0 $656 9.8% $64 0% $0 10.0% $72 $792 $1

8.3 Condenser & Auxiliaries $5,130 $0 $1,506 $0 $6,636 9.6% $634 0% $0 10.0% $727 $7,998 $14

8.4 Steam Piping $5,000 $0 $3,517 $0 $8,517 8.6% $732 0% $0 25.0% $2,312 $11,560 $21

8.9 TG Foundations $0 $988 $1,670 $0 $2,658 9.5% $252 0% $0 30.0% $873 $3,783 $7

SUBTOTAL 8. $39,057 $988 $12,061 $0 $52,106 $4,910 $0 $7,671 $64,687 $115

9 COOLING WATER SYSTEM

9.1 Cooling Towers $7,053 $0 $1,283 $0 $8,336 9.5% $794 0% $0 15.0% $1,369 $10,499 $19

9.2 Circulating Water Pumps $1,834 $0 $132 $0 $1,966 8.4% $166 0% $0 15.0% $320 $2,452 $4

9.3 Circ. Water System Auxiliaries $154 $0 $22 $0 $176 9.5% $17 0% $0 15.0% $29 $221 $0

9.4 Circ. Water Piping $0 $6,417 $1,664 $0 $8,081 9.0% $730 0% $0 20.0% $1,762 $10,573 $19

9.5 Make-up Water System $378 $0 $540 $0 $919 9.6% $88 0% $0 20.0% $201 $1,208 $2

9.6 Component Cooling Water System $758 $906 $645 $0 $2,308 9.4% $216 0% $0 20.0% $505 $3,029 $5

9.9 Circ. Water System Foundations $0 $2,356 $4,004 $0 $6,360 9.5% $603 0% $0 30.0% $2,089 $9,052 $16

SUBTOTAL 9. $10,176 $9,679 $8,291 $0 $28,145 $2,614 $0 $6,275 $37,035 $66

*

Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Acct No. Item/Description Erected 

Equipment 

Cost

Material 

Cost

Labor
Carbon Dioxide Capture Sensitivity Analysis

443

Exhibit 4-152 Case 2 D3D (75%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3D - GEE IGCC w/ two WGS bypass (75% CO2 Capture) x $1, 000

Plant Size: 563.80 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $12,055 $6,647 $13,504 $0 $32,207 9.7% $3,108 0% $0 10.0% $3,532 $38,847 $69

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.6 Ash Storage Silos $585 $0 $637 $0 $1,222 9.7% $119 0% $0 15.0% $201 $1,541 $3

10.7 Ash Transport & Feed Equipment $785 $0 $189 $0 $974 9.3% $91 0% $0 15.0% $160 $1,225 $2

10.8 Misc. Ash Handling Equipment $1,212 $1,485 $444 $0 $3,141 9.5% $299 0% $0 15.0% $516 $3,956 $7

10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $117 9.4% $11 0% $0 30.0% $38 $166 $0

SUBTOTAL 10. $14,637 $8,184 $14,839 $0 $37,660 $3,628 $0 $4,447 $45,734 $81

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $954 $0 $943 $0 $1,897 9.5% $181 0% $0 10.0% $208 $2,286 $4

11.2 Station Service Equipment $4,557 $0 $411 $0 $4,967 9.2% $458 0% $0 10.0% $543 $5,968 $11

11.3 Switchgear & Motor Control $8,424 $0 $1,532 $0 $9,956 9.3% $923 0% $0 15.0% $1,632 $12,511 $22

11.4 Conduit & Cable Tray $0 $3,913 $12,910 $0 $16,823 9.7% $1,627 0% $0 25.0% $4,612 $23,062 $41

11.5 Wire & Cable $0 $7,477 $4,913 $0 $12,390 7.3% $900 0% $0 25.0% $3,322 $16,612 $29

11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7

11.7 Standby Equipment $235 $0 $229 $0 $464 9.5% $44 0% $0 15.0% $76 $585 $1

11.8 Main Power Transformers $17,631 $0 $145 $0 $17,776 7.6% $1,344 0% $0 15.0% $2,868 $21,989 $39

11.9 Electrical Foundations $0 $158 $414 $0 $571 9.6% $55 0% $0 30.0% $188 $814 $1

SUBTOTAL 11. $31,800 $12,234 $23,992 $0 $68,026 $5,844 $0 $13,973 $87,842 $156

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.4 Other Major Component Control $1,105 $0 $738 $0 $1,843 9.5% $175 5% $92 15.0% $317 $2,427 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.6 Control Boards,Panels & Racks $254 $0 $163 $0 $417 9.5% $39 5% $21 20.0% $95 $573 $1

12.7 Computer & Accessories $5,896 $0 $189 $0 $6,085 9.2% $559 5% $304 10.0% $695 $7,642 $14

12.8 Instrument Wiring & Tubing $0 $2,060 $4,211 $0 $6,271 8.5% $532 5% $314 25.0% $1,779 $8,895 $16

12.9 Other I & C Equipment $3,941 $0 $1,914 $0 $5,855 9.4% $551 5% $293 15.0% $1,005 $7,704 $14

SUBTOTAL 12. $11,197 $2,060 $7,214 $0 $20,471 $1,855 $1,024 $3,891 $27,240 $48

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 109 2,330 0 2,439 9.9% 242 0% 0 30.0% 804 3,485 6

13.2 Site Improvements 0 1,939 2,576 0 4,515 9.9% 445 0% 0 30.0% 1,488 6,449 11

13.3 Site Facilities 3,474 0 3,666 0 7,140 9.9% 704 0% 0 30.0% 2,353 10,197 18

SUBTOTAL 13. $3,474 $2,048 $8,572 $0 $14,095 $1,391 $0 $4,646 $20,132 $36

Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Acct No. Item/Description Erected 

Equipment 

Cost

Material 

Cost

Labor
Carbon Dioxide Capture Sensitivity Analysis

444

Exhibit 4-152 Case 2 D3D (75%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D3D - GEE IGCC w/ two WGS bypass (75% CO2 Capture) x $1, 000

Plant Size: 563.80 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $264 $150 $0 $414 8.8% $36 0% $0 20.0% $90 $540 $1

14.2 Steam Turbine Building $0 $2,374 $3,382 $0 $5,756 9.2% $530 0% $0 15.0% $943 $7,229 $13

14.3 Administration Building $0 $881 $639 $0 $1,520 8.9% $135 0% $0 15.0% $248 $1,903 $3

14.4 Circulation Water Pumphouse $0 $164 $87 $0 $251 8.8% $22 0% $0 15.0% $41 $314 $1

14.5 Water Treatment Buildings $0 $583 $568 $0 $1,151 9.0% $104 0% $0 15.0% $188 $1,443 $3

14.6 Machine Shop $0 $451 $308 $0 $759 8.9% $67 0% $0 15.0% $124 $951 $2

14.7 Warehouse $0 $728 $470 $0 $1,198 8.9% $106 0% $0 15.0% $196 $1,499 $3

14.8 Other Buildings & Structures $0 $436 $339 $0 $775 8.9% $69 0% $0 20.0% $169 $1,014 $2

14.9 Waste Treating Building & Str. $0 $973 $1,860 $0 $2,833 9.3% $264 0% $0 20.0% $619 $3,716 $7

SUBTOTAL 14. $0 $6,853 $7,804 $0 $14,657 $1,334 $0 $2,618 $18,609 $33

Total Cost $713,833 $75,738 $297,352 $0 $1,086,924 $102,277 $62,313 $196,390 $1,447,904 $2,568

Owner's Costs

Preproduction Costs

6 Months All Labor $13,340 $24

1 Month Maintenance Materials $2,952 $5

1 Month Non-fuel Consumables $373 $1

1 Month Waste Disposal $315 $1

25% of 1 Months Fuel Cost at 100% CF $1,679 $3

2% of TPC $28,958 $51

Total $47,616 $84

Inventory Capital

60 day supply of fuel and consumables at 100% CF $14,175 $25

0.5% of TPC (spare parts) $7,240 $13

Total $21,415 $38

Initial Cost for Catalyst and Chemicals $7,298 $13

Land $900 $2

Other Owner's Costs $217,186 $385

Financing Costs $39,093 $69

Total Overnight Costs (TOC) $1,781,411 $3,160

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,030,809 $3,602

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Erected 
Carbon Dioxide Capture Sensitivity Analysis

445

Exhibit 4-153 Case 2 D3D Initial and Annual O&M Expenses

Case: Case 2 D3D - GEE IGCC w/ two WGS bypass (75% CO2 Capture)

Plant Size (MWe): 563.80 Heat Rate (Btu/kWh): 9,969

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 80 CO2 Captured (TPD): 9,928

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 10.0 10.0

Foreman 1.0 1.0

Lab Tech's etc. 3.0 3.0

TOTAL Operating Jobs 16.0 16.0

$ $/kW-net

Annual Operating Labor Cost (calc'd) $6,313,507 $11.198

Maintenance Labor Cost (calc'd) $15,030,504 $26.659

Administrative & Support Labor (calc'd) $5,336,003 $9.464

Property Taxes & Insurance $28,958,076 $51.362

TOTAL FIXED OPERATING COSTS $55,638,089 $98.684

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $28,334,568 0.00717

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 4,010 1.08 $0 $1,266,455 0.00032

Chemicals

MU & WT Chem. (lbs) 0 23,889 0.17 $0 $1,207,227 0.00031

Carbon (Mercury Removal) (lb) 74,302 127 1.05 $78,030 $38,945 0.00001

COS Catalyst (m3) 91 0.06 2,397.36 $219,119 $43,824 0.00001

Water Gas Shift Catalyst (ft3) 6,076 4.16 498.83 $3,030,897 $606,179 0.00015

Selexol Solution (gal) 296,322 87 13.40 $3,970,195 $339,078 0.00009

SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000

Claus Catalyst (ft3) 0 1.99 131.27 $0 $76,378 0.00002

Subtotal Chemicals $7,298,241 $2,311,631 0.00059

Other

Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $0 0.00000

Waste Disposal

Spent Mercury Sorbent (lb) 0 127 0.42 $0 $15,575 0.00000

Flyash (ton) 0 0 0.00 $0 $0 0.00000

Slag (ton) 0 634 16.23 $0 $3,005,186 0.00076

Subtotal Solid Waste Disposal $0 $3,020,761 $0

By-products & Emissions

Sulfur (tons) 0 145 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $34,933,414 0.00884

Coal FUEL (tons) 0 5,781 38.19 $0 $64,462,401 0.01631

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

446

Exhibit 4-154 Case 2 D3E (85%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3E - GEE IGCC w/ two WGS bypass (85% CO2 Capture) x $1, 000

Plant Size: 554.48 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload $3,744 $0 $1,830 $0 $5,574 9.0% $499 0% $0 20.0% $1,215 $7,288 $13

1.2 Coal Stackout & Reclaim $4,839 $0 $1,173 $0 $6,012 8.8% $527 0% $0 20.0% $1,308 $7,846 $14

1.3 Coal Conveyors & Yd Crus $4,499 $0 $1,161 $0 $5,659 8.8% $497 0% $0 20.0% $1,231 $7,387 $13

1.4 Other Coal Handling $1,177 $0 $269 $0 $1,446 8.8% $126 0% $0 20.0% $314 $1,886 $3

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $2,650 $6,625 $0 $9,275 9.6% $889 0% $0 20.0% $2,033 $12,197 $22

SUBTOTAL 1. $14,258 $2,650 $11,057 $0 $27,965 $2,538 $0 $6,101 $36,605 $66

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,599 $383 $251 $0 $2,233 8.6% 191 0% 0 20.0% $485 $2,908 $5

2.3 Slurry Prep & Feed $21,873 $0 $9,651 $0 $31,524 9.1% 2,864 5% 1,576 20.0% $7,193 $43,157 $78

2.4 Misc. Coal Prep & Feed $879 $640 $1,919 $0 $3,438 9.2% 316 0% 0 20.0% $751 $4,505 $8

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $3,418 $2,806 $0 $6,224 9.3% 576 0% 0 20.0% $1,360 $8,161 $15

SUBTOTAL 2. $24,351 $4,441 $14,627 $0 $43,419 $3,947 $1,576 $9,788 $58,731 $106

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 2,821 4,845 2,558 0 10,224 9.3% 947 0% 0 20.0% $2,234 $13,405 $24

3.2 Water Makeup & Pretreating 711 74 398 0 1,183 9.5% 113 0% 0 30.0% $389 $1,685 $3

3.3 Other Feedwater Subsystems 1,544 522 469 0 2,535 9.0% 228 0% 0 20.0% $552 $3,315 $6

3.4 Service Water Systems 407 838 2,909 0 4,155 9.8% 405 0% 0 30.0% $1,368 $5,928 $11

3.5 Other Boiler Plant Systems 2,185 847 2,098 0 5,129 9.5% 487 0% 0 20.0% $1,123 $6,739 $12

3.6 FO Supply Sys & Nat Gas $315 $595 $555 $0 1,466 9.6% 141 0% 0 20.0% $321 $1,929 $3

3.7 Waste Treatment Equipment 994 0 607 0 1,601 9.7% 156 0% 0 30.0% $527 $2,284 $4

3.8 Misc. Power Plant Equipment $1,121 $150 $575 $0 1,846 9.7% 178 0% 0 30.0% $607 $2,632 $5

SUBTOTAL 3. $10,098 $7,871 $10,169 $0 $28,139 $2,655 $0 $7,122 $37,916 $68

4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $113,668 $0 $62,282 $0 $175,950 9.2% $16,118 13.9% $24,418 15.3% $33,195 $249,681 $450

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.3 ASU/Oxidant Compression $192,697 $0 w/equip. $0 $192,697 9.7% $18,678 0% $0 10.0% $21,138 $232,513 $419

4.4 Scrubber & Low Temperature Cooling 6,039 $4,915 $5,116 $0 $16,070 9.6% $1,543 0% $0 20.0% $3,523 $21,136 $38

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.6 Soot Recovery & SARU $1,842 $874 $1,728 $0 $4,445 9.6% $428 0% $0 20.0% $975 $5,847 $11

4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.8 Gasification Foundations $0 $6,475 $5,405 $0 $11,879 9.3% $1,101 0% $0 25.0% $3,245 $16,225 $29

SUBTOTAL 4. $314,246 $12,264 $74,531 $0 $401,041 $37,869 $24,418 $62,075 $525,402 $948

Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Acct No. Item/Description Erected 

Equipment 

Cost

Material 

Cost

Labor
Carbon Dioxide Capture Sensitivity Analysis

447

Exhibit 4-154 Case 2 D3E (85%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3E - GEE IGCC w/ two WGS bypass (85% CO2 Capture) x $1, 000

Plant Size: 554.48 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $71,710 $0 $60,848 $0 $132,558 9.7% $12,820 20% $26,512 20.0% $34,378 $206,267 $372

5A.2 Elemental Sulfur Plant $10,310 $2,055 $13,302 $0 $25,668 9.7% $2,493 0% $0 20.0% $5,632 $33,793 $61

5A.3 Mercury Removal $1,358 $0 $1,034 $0 $2,392 9.7% $231 5% $120 20.0% $549 $3,291 $6

5A.4 Shift Reactors $10,763 $0 $4,333 $0 $15,096 9.6% $1,447 0% $0 20.0% $3,309 $19,851 $36

5A.5 COS Hydrolysis $451 $0 $589 $0 $1,040 9.7% $101 0% $0 20.0% $228 $1,369 $2

5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0

5A.7 Blowback Gas Systems $1,347 $0 $255 $0 $1,602 12.2% $195 0% $0 20.0% $360 $2,157 $4

5A.8 Fuel Gas Piping $0 $637 $446 $0 $1,082 9.3% $100 0% $0 20.0% $237 $1,419 $3

5A.9 HGCU Foundations $0 $641 $413 $0 $1,053 9.2% $97 0% $0 30.0% $345 $1,495 $3

5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

SUBTOTAL 5A. $95,940 $3,332 $81,219 $0 $180,491 $17,485 $26,631 $45,036 $269,644 $486

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0

5B.2 CO2 Compression & Drying $17,272 $0 $10,588 $0 $27,860 9.6% $2,684 0% $0 20.0% $6,109 $36,652 $66

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $17,272 $0 $10,588 $0 $27,860 $2,684 $0 $6,109 $36,652 $66

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 234

6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 14

6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5

SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $253

7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,726 $0 $4,795 $0 $38,521 9.5% $3,663 0% $0 10.0% $4,218 $46,402 $84

7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

7.3 Ductwork $0 $1,729 $1,234 $0 $2,963 8.8% $260 0% $0 20.0% $645 $3,867 $7

7.4 Stack $3,373 $0 $1,267 $0 $4,641 9.6% $445 0% $0 10.0% $509 $5,594 $10

7.9 HRSG, Duct & Stack Foundations $0 $676 $649 $0 $1,325 9.3% $123 0% $0 30.0% $434 $1,883 $3

SUBTOTAL 7. $37,099 $2,405 $7,945 $0 $47,449 $4,490 $0 $5,806 $57,746 $104

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories $28,579 $0 $4,886 $0 $33,465 9.6% $3,211 0% $0 10.0% $3,668 $40,344 $73

8.2 Turbine Plant Auxiliaries $198 $0 $454 $0 $652 9.8% $64 0% $0 10.0% $72 $788 $1

8.3 Condenser & Auxiliaries $5,082 $0 $1,492 $0 $6,574 9.6% $628 0% $0 10.0% $720 $7,923 $14

8.4 Steam Piping $4,980 $0 $3,503 $0 $8,484 8.6% $729 0% $0 25.0% $2,303 $11,516 $21

8.9 TG Foundations $0 $983 $1,661 $0 $2,644 9.5% $251 0% $0 30.0% $868 $3,763 $7

SUBTOTAL 8. $38,840 $983 $11,997 $0 $51,820 $4,883 $0 $7,631 $64,334 $116

9 COOLING WATER SYSTEM

9.1 Cooling Towers $7,135 $0 $1,298 $0 $8,433 9.5% $803 0% $0 15.0% $1,385 $10,621 $19

9.2 Circulating Water Pumps $1,856 $0 $134 $0 $1,990 8.4% $168 0% $0 15.0% $324 $2,481 $4

9.3 Circ. Water System Auxiliaries $155 $0 $22 $0 $177 9.5% $17 0% $0 15.0% $29 $224 $0

9.4 Circ. Water Piping $0 $6,481 $1,680 $0 $8,161 9.0% $738 0% $0 20.0% $1,780 $10,679 $19

9.5 Make-up Water System $385 $0 $551 $0 $936 9.6% $90 0% $0 20.0% $205 $1,231 $2

9.6 Component Cooling Water System $765 $915 $651 $0 $2,331 9.4% $218 0% $0 20.0% $510 $3,060 $6

9.9 Circ. Water System Foundations $0 $2,379 $4,044 $0 $6,423 9.5% $609 0% $0 30.0% $2,110 $9,142 $16

SUBTOTAL 9. $10,296 $9,775 $8,381 $0 $28,452 $2,643 $0 $6,343 $37,438 $68

*

Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Acct No. Item/Description Erected 

Equipment 

Cost

Material 

Cost

Labor
Carbon Dioxide Capture Sensitivity Analysis

448

Exhibit 4-154 Case 2 D3E (85%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3E - GEE IGCC w/ two WGS bypass (85% CO2 Capture) x $1, 000

Plant Size: 554.48 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $12,118 $6,682 $13,574 $0 $32,374 9.7% $3,125 0% $0 10.0% $3,550 $39,049 $70

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.6 Ash Storage Silos $588 $0 $640 $0 $1,227 9.7% $119 0% $0 15.0% $202 $1,549 $3

10.7 Ash Transport & Feed Equipment $788 $0 $190 $0 $979 9.3% $91 0% $0 15.0% $160 $1,230 $2

10.8 Misc. Ash Handling Equipment $1,218 $1,492 $446 $0 $3,156 9.5% $300 0% $0 15.0% $518 $3,974 $7

10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $117 9.4% $11 0% $0 30.0% $38 $167 $0

SUBTOTAL 10. $14,712 $8,226 $14,915 $0 $37,853 $3,646 $0 $4,469 $45,969 $83

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $952 $0 $942 $0 $1,894 9.5% $181 0% $0 10.0% $207 $2,282 $4

11.2 Station Service Equipment $4,639 $0 $418 $0 $5,057 9.2% $466 0% $0 10.0% $552 $6,076 $11

11.3 Switchgear & Motor Control $8,576 $0 $1,560 $0 $10,136 9.3% $940 0% $0 15.0% $1,661 $12,737 $23

11.4 Conduit & Cable Tray $0 $3,984 $13,143 $0 $17,127 9.7% $1,657 0% $0 25.0% $4,696 $23,479 $42

11.5 Wire & Cable $0 $7,612 $5,001 $0 $12,613 7.3% $916 0% $0 25.0% $3,382 $16,912 $31

11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7

11.7 Standby Equipment $234 $0 $229 $0 $463 9.5% $44 0% $0 15.0% $76 $584 $1

11.8 Main Power Transformers $17,599 $0 $145 $0 $17,744 7.6% $1,342 0% $0 15.0% $2,863 $21,948 $40

11.9 Electrical Foundations $0 $157 $413 $0 $570 9.6% $55 0% $0 30.0% $187 $812 $1

SUBTOTAL 11. $32,000 $12,439 $24,346 $0 $68,786 $5,911 $0 $14,150 $88,847 $160

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.4 Other Major Component Control $1,117 $0 $746 $0 $1,863 9.5% $176 5% $93 15.0% $320 $2,453 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.6 Control Boards,Panels & Racks $257 $0 $165 $0 $421 9.5% $40 5% $21 20.0% $96 $579 $1

12.7 Computer & Accessories $5,960 $0 $191 $0 $6,151 9.2% $565 5% $308 10.0% $702 $7,725 $14

12.8 Instrument Wiring & Tubing $0 $2,082 $4,256 $0 $6,338 8.5% $538 5% $317 25.0% $1,798 $8,991 $16

12.9 Other I & C Equipment $3,984 $0 $1,935 $0 $5,919 9.4% $557 5% $296 15.0% $1,016 $7,787 $14

SUBTOTAL 12. $11,318 $2,082 $7,292 $0 $20,692 $1,875 $1,035 $3,933 $27,535 $50

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 109 2,335 0 2,445 9.9% 243 0% 0 30.0% 806 3,494 6

13.2 Site Improvements 0 1,943 2,583 0 4,526 9.9% 446 0% 0 30.0% 1,492 6,464 12

13.3 Site Facilities 3,483 0 3,675 0 7,157 9.9% 705 0% 0 30.0% 2,359 10,222 18

SUBTOTAL 13. $3,483 $2,053 $8,593 $0 $14,128 $1,395 $0 $4,657 $20,179 $36

Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Acct No. Item/Description Erected 

Equipment 

Cost

Material 

Cost

Labor
Carbon Dioxide Capture Sensitivity Analysis

449

Exhibit 4-154 Case 2 D3E (85%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D3E - GEE IGCC w/ two WGS bypass (85% CO2 Capture) x $1, 000

Plant Size: 554.48 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $265 $150 $0 $414 8.8% $36 0% $0 20.0% $90 $541 $1

14.2 Steam Turbine Building $0 $2,376 $3,385 $0 $5,762 9.2% $530 0% $0 15.0% $944 $7,236 $13

14.3 Administration Building $0 $882 $640 $0 $1,521 8.9% $135 0% $0 15.0% $249 $1,905 $3

14.4 Circulation Water Pumphouse $0 $166 $88 $0 $253 8.8% $22 0% $0 15.0% $41 $317 $1

14.5 Water Treatment Buildings $0 $595 $580 $0 $1,175 9.0% $106 0% $0 15.0% $192 $1,474 $3

14.6 Machine Shop $0 $451 $309 $0 $760 8.9% $67 0% $0 15.0% $124 $952 $2

14.7 Warehouse $0 $729 $470 $0 $1,199 8.9% $106 0% $0 15.0% $196 $1,501 $3

14.8 Other Buildings & Structures $0 $436 $340 $0 $776 8.9% $69 0% $0 20.0% $169 $1,015 $2

14.9 Waste Treating Building & Str. $0 $975 $1,864 $0 $2,839 9.3% $265 0% $0 20.0% $621 $3,724 $7

SUBTOTAL 14. $0 $6,875 $7,826 $0 $14,701 $1,338 $0 $2,626 $18,665 $34

Total Cost $721,489 $76,282 $301,818 $0 $1,099,590 $103,483 $63,521 $199,278 $1,465,871 $2,644

Owner's Costs

Preproduction Costs

6 Months All Labor $13,449 $24

1 Month Maintenance Materials $2,986 $5

1 Month Non-fuel Consumables $393 $1

1 Month Waste Disposal $317 $1

25% of 1 Months Fuel Cost at 100% CF $1,693 $3

2% of TPC $29,317 $53

Total $48,156 $87

Inventory Capital

60 day supply of fuel and consumables at 100% CF $14,330 $26

0.5% of TPC (spare parts) $7,329 $13

Total $21,659 $39

Initial Cost for Catalyst and Chemicals $7,797 $14

Land $900 $2

Other Owner's Costs $219,881 $397

Financing Costs $39,579 $71

Total Overnight Costs (TOC) $1,803,843 $3,253

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,056,381 $3,709

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Erected 
Carbon Dioxide Capture Sensitivity Analysis

450

Exhibit 4-155 Case 2 D3E Initial and Annual O&M Expenses

Case: Case 2 D3E - GEE IGCC w/ two WGS bypass (85% CO2 Capture)

Plant Size (MWe): 554.48 Heat Rate (Btu/kWh): 10,222

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 80 CO2 Captured (TPD): 11,376

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 10.0 10.0

Foreman 1.0 1.0

Lab Tech's etc. 3.0 3.0

TOTAL Operating Jobs 16.0 16.0

$ $/kW-net

Annual Operating Labor Cost (calc'd) $6,313,507 $11.386

Maintenance Labor Cost (calc'd) $15,205,658 $27.423

Administrative & Support Labor (calc'd) $5,379,791 $9.702

Property Taxes & Insurance $29,317,421 $52.873

TOTAL FIXED OPERATING COSTS $56,216,377 $101.385

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $28,664,758 0.00738

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 4,139 1.08 $0 $1,307,161 0.00034

Chemicals

MU & WT Chem. (lbs) 0 24,656 0.17 $0 $1,246,030 0.00032

Carbon (Mercury Removal) (lb) 78,342 134 1.05 $82,272 $41,091 0.00001

COS Catalyst (m3) 22 0.02 2,397.36 $52,502 $10,500 0.00000

Water Gas Shift Catalyst (ft3) 7,362 5.04 498.83 $3,672,394 $734,479 0.00019

Selexol Solution (gal) 297,784 92 13.40 $3,989,782 $360,713 0.00009

SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000

Claus Catalyst (ft3) 0 2.01 131.27 $0 $77,006 0.00002

Subtotal Chemicals $7,796,950 $2,469,819 0.00064

Other

Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $0 0.00000

Waste Disposal

Spent Mercury Sorbent (lb) 0 134 0.42 $0 $16,434 0.00000

Flyash (ton) 0 0 0.00 $0 $0 0.00000

Slag (ton) 0 640 16.23 $0 $3,030,485 0.00078

Subtotal Solid Waste Disposal $0 $3,046,919 $0

By-products & Emissions

Sulfur (tons) 0 146 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $35,488,657 0.00913

Coal FUEL (tons) 0 5,830 38.19 $0 $65,005,231 0.01673

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

451

Exhibit 4-156 Case 2 D4A (90%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4A - GEE IGCC w/ two WGS (90% CO2 Capture) x $1, 000

Plant Size: 543.24 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload $3,750 $0 $1,833 $0 $5,583 9.0% $500 0% $0 20.0% $1,217 $7,299 $13

1.2 Coal Stackout & Reclaim $4,846 $0 $1,175 $0 $6,021 8.8% $528 0% $0 20.0% $1,310 $7,858 $14

1.3 Coal Conveyors & Yd Crus $4,505 $0 $1,162 $0 $5,668 8.8% $498 0% $0 20.0% $1,233 $7,398 $14

1.4 Other Coal Handling $1,179 $0 $269 $0 $1,448 8.8% $127 0% $0 20.0% $315 $1,889 $3

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $2,654 $6,635 $0 $9,289 9.6% $890 0% $0 20.0% $2,036 $12,215 $22

SUBTOTAL 1. $14,280 $2,654 $11,074 $0 $28,008 $2,542 $0 $6,110 $36,660 $67

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,602 $383 $251 $0 $2,236 8.6% 191 0% 0 20.0% $485 $2,913 $5

2.3 Slurry Prep & Feed $21,908 $0 $9,667 $0 $31,575 9.1% 2,869 5% 1,579 20.0% $7,205 $43,227 $80

2.4 Misc. Coal Prep & Feed $881 $641 $1,922 $0 $3,443 9.2% 316 0% 0 20.0% $752 $4,512 $8

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $3,424 $2,811 $0 $6,234 9.3% 577 0% 0 20.0% $1,362 $8,174 $15

SUBTOTAL 2. $24,391 $4,448 $14,651 $0 $43,489 $3,954 $1,579 $9,804 $58,826 $108

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 2,836 4,870 2,571 0 10,276 9.3% 952 0% 0 20.0% $2,246 $13,474 $25

3.2 Water Makeup & Pretreating 717 75 401 0 1,193 9.5% 114 0% 0 30.0% $392 $1,699 $3

3.3 Other Feedwater Subsystems 1,552 524 472 0 2,548 9.0% 229 0% 0 20.0% $555 $3,332 $6

3.4 Service Water Systems 411 845 2,934 0 4,190 9.8% 409 0% 0 30.0% $1,380 $5,979 $11

3.5 Other Boiler Plant Systems 2,203 854 2,116 0 5,173 9.5% 491 0% 0 20.0% $1,133 $6,796 $13

3.6 FO Supply Sys & Nat Gas $315 $596 $556 $0 1,467 9.6% 141 0% 0 20.0% $322 $1,930 $4

3.7 Waste Treatment Equipment 1,003 0 612 0 1,615 9.7% 157 0% 0 30.0% $532 $2,303 $4

3.8 Misc. Power Plant Equipment $1,121 $150 $576 $0 1,847 9.7% 178 0% 0 30.0% $608 $2,634 $5

SUBTOTAL 3. $10,158 $7,914 $10,237 $0 $28,309 $2,671 $0 $7,166 $38,146 $70

4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $113,863 $0 $62,389 $0 $176,251 9.2% $16,146 13.9% $24,460 15.3% $33,252 $250,109 $460

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.3 ASU/Oxidant Compression $193,046 $0 w/equip. $0 $193,046 9.7% $18,712 0% $0 10.0% $21,176 $232,934 $429

4.4 Scrubber & Low Temperature Cooling 6,049 $4,924 $5,125 $0 $16,097 9.6% $1,546 0% $0 20.0% $3,529 $21,172 $39

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.6 Soot Recovery & SARU $1,845 $876 $1,731 $0 $4,452 9.6% $429 0% $0 20.0% $976 $5,857 $11

4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.8 Gasification Foundations $0 $6,486 $5,414 $0 $11,900 9.3% $1,103 0% $0 25.0% $3,251 $16,253 $30

SUBTOTAL 4. $314,803 $12,285 $74,659 $0 $401,747 $37,935 $24,460 $62,183 $526,325 $969

Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Acct No. Item/Description Erected 

Equipment 

Cost

Material 

Cost

Labor
Carbon Dioxide Capture Sensitivity Analysis

452

Exhibit 4-156 Case 2 D4A (90%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4A - GEE IGCC w/ two WGS (90% CO2 Capture) x $1, 000

Plant Size: 543.24 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $74,127 $0 $62,899 $0 $137,025 9.7% $13,252 20% $27,405 20.0% $35,536 $213,219 $392

5A.2 Elemental Sulfur Plant $10,329 $2,059 $13,326 $0 $25,713 9.7% $2,498 0% $0 20.0% $5,642 $33,853 $62

5A.3 Mercury Removal $1,376 $0 $1,047 $0 $2,423 9.7% $234 5% $121 20.0% $556 $3,334 $6

5A.4 Shift Reactors $9,594 $0 $3,862 $0 $13,456 9.7% $1,308 0% $0 20.0% $2,953 $17,718 $33

5A.5 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0

5A.6 Blowback Gas Systems $1,349 $0 $256 $0 $1,605 12.2% $196 0% $0 20.0% $360 $2,161 $4

5A.7 Fuel Gas Piping $0 $634 $444 $0 $1,078 9.3% $100 0% $0 20.0% $236 $1,413 $3

5A.9 HGCU Foundations $0 $642 $414 $0 $1,056 9.2% $97 0% $0 30.0% $346 $1,498 $3

5.9 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

SUBTOTAL 5A. $96,775 $3,334 $82,247 $0 $182,357 $17,685 $27,526 $45,629 $273,196 $503

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0

5B.2 CO2 Compression & Drying $18,256 $0 $11,190 $0 $29,446 9.6% $2,836 0% $0 20.0% $6,456 $38,739 $71

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $18,256 $0 $11,190 $0 $29,446 $2,836 $0 $6,456 $38,739 $71

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 239

6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 15

6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5

SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $258

7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,620 $0 $4,780 $0 $38,401 9.5% $3,651 0% $0 10.0% $4,205 $46,257 $85

7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

7.3 Ductwork $0 $1,731 $1,235 $0 $2,965 8.8% $260 0% $0 20.0% $645 $3,870 $7

7.4 Stack $3,376 $0 $1,268 $0 $4,644 9.6% $445 0% $0 10.0% $509 $5,598 $10

7.9 HRSG, Duct & Stack Foundations $0 $676 $650 $0 $1,326 9.3% $123 0% $0 30.0% $435 $1,884 $3

SUBTOTAL 7. $36,996 $2,407 $7,933 $0 $47,336 $4,480 $0 $5,794 $57,610 $106

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories $28,123 $0 $4,808 $0 $32,931 9.6% $3,160 0% $0 10.0% $3,609 $39,699 $73

8.2 Turbine Plant Auxiliaries $195 $0 $447 $0 $642 9.8% $63 0% $0 10.0% $70 $775 $1

8.3 Condenser & Auxiliaries $5,009 $0 $1,471 $0 $6,480 9.6% $619 0% $0 10.0% $710 $7,809 $14

8.4 Steam Piping $5,006 $0 $3,522 $0 $8,528 8.6% $733 0% $0 25.0% $2,315 $11,576 $21

8.9 TG Foundations $0 $967 $1,635 $0 $2,603 9.5% $247 0% $0 30.0% $855 $3,704 $7

SUBTOTAL 8. $38,333 $967 $11,883 $0 $51,183 $4,821 $0 $7,559 $63,564 $117

9 COOLING WATER SYSTEM

9.1 Cooling Towers $7,155 $0 $1,302 $0 $8,457 9.5% $805 0% $0 15.0% $1,389 $10,652 $20

9.2 Circulating Water Pumps $1,856 $0 $134 $0 $1,990 8.4% $168 0% $0 15.0% $324 $2,481 $5

9.3 Circ. Water System Auxiliaries $155 $0 $22 $0 $177 9.5% $17 0% $0 15.0% $29 $224 $0

9.4 Circ. Water Piping $0 $6,481 $1,680 $0 $8,161 9.0% $738 0% $0 20.0% $1,780 $10,679 $20

9.5 Make-up Water System $388 $0 $555 $0 $943 9.6% $90 0% $0 20.0% $207 $1,240 $2

9.6 Component Cooling Water System $765 $915 $651 $0 $2,331 9.4% $218 0% $0 20.0% $510 $3,060 $6

9.9 Circ. Water System Foundations $0 $2,379 $4,044 $0 $6,423 9.5% $609 0% $0 30.0% $2,110 $9,142 $17

SUBTOTAL 9. $10,319 $9,775 $8,388 $0 $28,483 $2,646 $0 $6,348 $37,477 $69

*

Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Acct No. Item/Description Erected 

Equipment 

Cost

Material 

Cost

Labor
Carbon Dioxide Capture Sensitivity Analysis

453

Exhibit 4-156 Case 2 D4A (90%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4A - GEE IGCC w/ two WGS (90% CO2 Capture) x $1, 000

Plant Size: 543.24 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $12,136 $6,692 $13,595 $0 $32,424 9.7% $3,129 0% $0 10.0% $3,555 $39,109 $72

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.6 Ash Storage Silos $589 $0 $641 $0 $1,229 9.7% $119 0% $0 15.0% $202 $1,551 $3

10.7 Ash Transport & Feed Equipment $790 $0 $190 $0 $980 9.3% $91 0% $0 15.0% $161 $1,232 $2

10.8 Misc. Ash Handling Equipment $1,219 $1,494 $446 $0 $3,160 9.5% $301 0% $0 15.0% $519 $3,980 $7

10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $117 9.4% $11 0% $0 30.0% $39 $167 $0

SUBTOTAL 10. $14,734 $8,239 $14,938 $0 $37,910 $3,652 $0 $4,476 $46,038 $85

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $947 $0 $937 $0 $1,885 9.5% $180 0% $0 10.0% $206 $2,271 $4

11.2 Station Service Equipment $4,697 $0 $423 $0 $5,121 9.2% $472 0% $0 10.0% $559 $6,152 $11

11.3 Switchgear & Motor Control $8,684 $0 $1,579 $0 $10,264 9.3% $952 0% $0 15.0% $1,682 $12,898 $24

11.4 Conduit & Cable Tray $0 $4,034 $13,308 $0 $17,342 9.7% $1,677 0% $0 25.0% $4,755 $23,775 $44

11.5 Wire & Cable $0 $7,708 $5,064 $0 $12,772 7.3% $928 0% $0 25.0% $3,425 $17,125 $32

11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7

11.7 Standby Equipment $234 $0 $228 $0 $462 9.5% $44 0% $0 15.0% $76 $581 $1

11.8 Main Power Transformers $17,500 $0 $144 $0 $17,644 7.6% $1,334 0% $0 15.0% $2,847 $21,825 $40

11.9 Electrical Foundations $0 $156 $410 $0 $567 9.6% $54 0% $0 30.0% $186 $807 $1

SUBTOTAL 11. $32,062 $12,584 $24,591 $0 $69,237 $5,953 $0 $14,261 $89,451 $165

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.4 Other Major Component Control $1,126 $0 $752 $0 $1,877 9.5% $178 5% $94 15.0% $322 $2,471 $5

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.6 Control Boards,Panels & Racks $259 $0 $166 $0 $425 9.5% $40 5% $21 20.0% $97 $583 $1

12.7 Computer & Accessories $6,005 $0 $192 $0 $6,197 9.2% $569 5% $310 10.0% $708 $7,784 $14

12.8 Instrument Wiring & Tubing $0 $2,098 $4,288 $0 $6,386 8.5% $542 5% $319 25.0% $1,812 $9,059 $17

12.9 Other I & C Equipment $4,014 $0 $1,949 $0 $5,963 9.4% $561 5% $298 15.0% $1,023 $7,846 $14

SUBTOTAL 12. $11,404 $2,098 $7,347 $0 $20,849 $1,889 $1,042 $3,962 $27,743 $51

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 109 2,337 0 2,447 9.9% 243 0% 0 30.0% 807 3,496 6

13.2 Site Improvements 0 1,945 2,585 0 4,530 9.9% 447 0% 0 30.0% 1,493 6,469 12

13.3 Site Facilities 3,485 0 3,678 0 7,163 9.9% 706 0% 0 30.0% 2,361 10,230 19

SUBTOTAL 13. $3,485 $2,054 $8,600 $0 $14,140 $1,396 $0 $4,661 $20,196 $37

Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Acct No. Item/Description Erected 

Equipment 

Cost

Material 

Cost

Labor
Carbon Dioxide Capture Sensitivity Analysis

454

Exhibit 4-156 Case 2 D4A (90%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D4A - GEE IGCC w/ two WGS (90% CO2 Capture) x $1, 000

Plant Size: 543.24 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $265 $150 $0 $414 8.8% $36 0% $0 20.0% $90 $541 $1

14.2 Steam Turbine Building $0 $2,377 $3,387 $0 $5,764 9.2% $530 0% $0 15.0% $944 $7,238 $13

14.3 Administration Building $0 $882 $640 $0 $1,522 8.9% $136 0% $0 15.0% $249 $1,906 $4

14.4 Circulation Water Pumphouse $0 $166 $88 $0 $253 8.8% $22 0% $0 15.0% $41 $317 $1

14.5 Water Treatment Buildings $0 $600 $585 $0 $1,185 9.0% $107 0% $0 15.0% $194 $1,486 $3

14.6 Machine Shop $0 $452 $309 $0 $761 8.9% $68 0% $0 15.0% $124 $952 $2

14.7 Warehouse $0 $729 $471 $0 $1,200 8.9% $106 0% $0 15.0% $196 $1,502 $3

14.8 Other Buildings & Structures $0 $437 $340 $0 $777 8.9% $69 0% $0 20.0% $169 $1,015 $2

14.9 Waste Treating Building & Str. $0 $976 $1,865 $0 $2,841 9.3% $265 0% $0 20.0% $621 $3,728 $7

SUBTOTAL 14. $0 $6,882 $7,834 $0 $14,716 $1,340 $0 $2,628 $18,684 $34

Total Cost $723,574 $76,529 $303,902 $0 $1,104,005 $103,923 $64,468 $200,471 $1,472,866 $2,711

Owner's Costs

Preproduction Costs

6 Months All Labor $13,488 $25

1 Month Maintenance Materials $2,998 $6

1 Month Non-fuel Consumables $385 $1

1 Month Waste Disposal $318 $1

25% of 1 Months Fuel Cost at 100% CF $1,697 $3

2% of TPC $29,457 $54

Total $48,343 $89

Inventory Capital

60 day supply of fuel and consumables at 100% CF $14,346 $26

0.5% of TPC (spare parts) $7,364 $14

Total $21,711 $40

Initial Cost for Catalyst and Chemicals $7,200 $13

Land $900 $2

Other Owner's Costs $220,930 $407

Financing Costs $39,767 $73

Total Overnight Costs (TOC) $1,811,717 $3,335

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,065,358 $3,802

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Erected 
Carbon Dioxide Capture Sensitivity Analysis

455

Exhibit 4-157 Case 2 D4A Initial and Annual O&M Expenses

Case: Case 2 D4A - GEE IGCC w/ two WGS (90% CO2 Capture)

Plant Size (MWe): 543.24 Heat Rate (Btu/kWh): 10,459

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 80 CO2 Captured (TPD): 12,377

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 10.0 10.0

Foreman 1.0 1.0

Lab Tech's etc. 3.0 3.0

TOTAL Operating Jobs 16.0 16.0

$ $/kW-net

Annual Operating Labor Cost (calc'd) $6,313,507 $11.622

Maintenance Labor Cost (calc'd) $15,266,708 $28.103

Administrative & Support Labor (calc'd) $5,395,054 $9.931

Property Taxes & Insurance $29,457,328 $54.225

TOTAL FIXED OPERATING COSTS $56,432,596 $103.881

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $28,779,845 0.00756

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 4,188 1.08 $0 $1,322,853 0.00035

Chemicals

MU & WT Chem. (lbs) 0 24,952 0.17 $0 $1,260,988 0.00033

Carbon (Mercury Removal) (lb) 79,788 137 1.05 $83,791 $42,011 0.00001

COS Catalyst (m3) 0 0.00 2,397.36 $0 $0 0.00000

Water Gas Shift Catalyst (ft3) 6,247 4.28 498.83 $3,116,197 $623,239 0.00016

Selexol Solution (gal) 298,515 95 13.40 $3,999,575 $371,667 0.00010

SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000

Claus Catalyst (ft3) 0 2.01 131.27 $0 $77,209 0.00002

Subtotal Chemicals $7,199,564 $2,375,114 0.00062

Other

Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $0 0.00000

Waste Disposal

Spent Mercury Sorbent (lb) 0 137 0.42 $0 $16,802 0.00000

Flyash (ton) 0 0 0.00 $0 $0 0.00000

Slag (ton) 0 641 16.23 $0 $3,037,933 0.00080

Subtotal Solid Waste Disposal $0 $3,054,735 $0

By-products & Emissions

Sulfur (tons) 0 146 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $35,532,546 0.00933

Coal FUEL (tons) 0 5,844 38.19 $0 $65,164,454 0.01712

INITIAL & ANNUAL O&M EXPENSES

Consumption

Annual Costs
Carbon Dioxide Capture Sensitivity Analysis

456

Exhibit 4-158 Case 2 D4B (95%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4B - GEE IGCC w/ two WGS (95% CO2 Capture) x $1, 000

Plant Size: 528.51 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload $3,746 $0 $1,831 $0 $5,577 9.0% $500 0% $0 20.0% $1,215 $7,291 $14

1.2 Coal Stackout & Reclaim $4,841 $0 $1,174 $0 $6,014 8.8% $527 0% $0 20.0% $1,308 $7,849 $15

1.3 Coal Conveyors & Yd Crus $4,500 $0 $1,161 $0 $5,662 8.8% $497 0% $0 20.0% $1,232 $7,390 $14

1.4 Other Coal Handling $1,177 $0 $269 $0 $1,446 8.8% $127 0% $0 20.0% $315 $1,887 $4

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $2,651 $6,628 $0 $9,279 9.6% $889 0% $0 20.0% $2,034 $12,202 $23

SUBTOTAL 1. $14,264 $2,651 $11,062 $0 $27,977 $2,540 $0 $6,103 $36,620 $69

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,600 $383 $251 $0 $2,234 8.6% 191 0% 0 20.0% $485 $2,909 $6

2.3 Slurry Prep & Feed $21,883 $0 $9,656 $0 $31,538 9.1% 2,865 5% 1,577 20.0% $7,196 $43,177 $82

2.4 Misc. Coal Prep & Feed $880 $640 $1,919 $0 $3,439 9.2% 316 0% 0 20.0% $751 $4,507 $9

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $3,420 $2,807 $0 $6,227 9.3% 577 0% 0 20.0% $1,361 $8,165 $15

SUBTOTAL 2. $24,362 $4,443 $14,634 $0 $43,438 $3,949 $1,577 $9,793 $58,757 $111

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 2,826 4,854 2,562 0 10,242 9.3% 949 0% 0 20.0% $2,238 $13,429 $25

3.2 Water Makeup & Pretreating 711 74 397 0 1,182 9.5% 113 0% 0 30.0% $388 $1,683 $3

3.3 Other Feedwater Subsystems 1,546 523 470 0 2,539 9.0% 228 0% 0 20.0% $553 $3,321 $6

3.4 Service Water Systems 407 837 2,906 0 4,150 9.8% 405 0% 0 30.0% $1,366 $5,921 $11

3.5 Other Boiler Plant Systems 2,182 846 2,096 0 5,123 9.5% 486 0% 0 20.0% $1,122 $6,731 $13

3.6 FO Supply Sys & Nat Gas $315 $596 $555 $0 1,466 9.6% 141 0% 0 20.0% $321 $1,929 $4

3.7 Waste Treatment Equipment 993 0 606 0 1,599 9.7% 156 0% 0 30.0% $526 $2,281 $4

3.8 Misc. Power Plant Equipment $1,121 $150 $576 $0 1,847 9.7% 178 0% 0 30.0% $607 $2,632 $5

SUBTOTAL 3. $10,102 $7,879 $10,168 $0 $28,149 $2,656 $0 $7,124 $37,929 $72

4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $113,723 $0 $62,312 $0 $176,034 9.2% $16,126 13.9% $24,430 15.3% $33,211 $249,801 $473

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.3 ASU/Oxidant Compression $192,904 $0 w/equip. $0 $192,904 9.7% $18,698 0% $0 10.0% $21,160 $232,762 $440

4.4 Scrubber & Low Temperature Cooling 6,042 $4,918 $5,118 $0 $16,078 9.6% $1,544 0% $0 20.0% $3,524 $21,146 $40

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.6 Soot Recovery & SARU $1,842 $875 $1,729 $0 $4,447 9.6% $429 0% $0 20.0% $975 $5,850 $11

4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.8 Gasification Foundations $0 $6,478 $5,407 $0 $11,885 9.3% $1,101 0% $0 25.0% $3,247 $16,233 $31

SUBTOTAL 4. $314,511 $12,270 $74,567 $0 $401,347 $37,898 $24,430 $62,117 $525,792 $995

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Erected 
Carbon Dioxide Capture Sensitivity Analysis

457

Exhibit 4-158 Case 2 D4B (95%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4B - GEE IGCC w/ two WGS (95% CO2 Capture) x $1, 000

Plant Size: 528.51 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $77,897 $0 $66,097 $0 $143,994 9.7% $13,926 20% $28,799 20.0% $37,344 $224,062 $424

5A.2 Elemental Sulfur Plant $10,316 $2,056 $13,310 $0 $25,682 9.7% $2,495 0% $0 20.0% $5,635 $33,812 $64

5A.3 Mercury Removal $1,374 $0 $1,046 $0 $2,420 9.7% $234 5% $121 20.0% $555 $3,330 $6

5A.4 Shift Reactors $9,582 $0 $3,857 $0 $13,440 9.7% $1,307 0% $0 20.0% $2,949 $17,696 $33

5A.5 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0

5A.6 Blowback Gas Systems $1,348 $0 $255 $0 $1,603 12.2% $196 0% $0 20.0% $360 $2,158 $4

5A.7 Fuel Gas Piping $0 $619 $433 $0 $1,052 9.3% $97 0% $0 20.0% $230 $1,379 $3

5A.9 HGCU Foundations $0 $641 $413 $0 $1,054 9.2% $97 0% $0 30.0% $345 $1,496 $3

5.9 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

SUBTOTAL 5A. $100,517 $3,315 $85,412 $0 $189,245 $18,351 $28,920 $47,418 $283,933 $537

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0

5B.2 CO2 Compression & Drying $19,059 $0 $11,682 $0 $30,741 9.6% $2,961 0% $0 20.0% $6,740 $40,443 $77

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $19,059 $0 $11,682 $0 $30,741 $2,961 $0 $6,740 $40,443 $77

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 245

6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 15

6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5

SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $265

7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,515 $0 $4,765 $0 $38,280 9.5% $3,640 0% $0 10.0% $4,192 $46,112 $87

7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

7.3 Ductwork $0 $1,731 $1,235 $0 $2,967 8.8% $260 0% $0 20.0% $645 $3,872 $7

7.4 Stack $3,378 $0 $1,269 $0 $4,647 9.6% $445 0% $0 10.0% $509 $5,601 $11

7.9 HRSG, Duct & Stack Foundations $0 $677 $650 $0 $1,327 9.3% $124 0% $0 30.0% $435 $1,885 $4

SUBTOTAL 7. $36,892 $2,408 $7,920 $0 $47,220 $4,469 $0 $5,782 $57,470 $109

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories $27,561 $0 $4,712 $0 $32,272 9.6% $3,097 0% $0 10.0% $3,537 $38,906 $74

8.2 Turbine Plant Auxiliaries $191 $0 $438 $0 $629 9.8% $62 0% $0 10.0% $69 $760 $1

8.3 Condenser & Auxiliaries $4,813 $0 $1,413 $0 $6,226 9.6% $595 0% $0 10.0% $682 $7,503 $14

8.4 Steam Piping $4,990 $0 $3,510 $0 $8,500 8.6% $730 0% $0 25.0% $2,307 $11,537 $22

8.9 TG Foundations $0 $948 $1,603 $0 $2,551 9.5% $242 0% $0 30.0% $838 $3,631 $7

SUBTOTAL 8. $37,554 $948 $11,676 $0 $50,178 $4,725 $0 $7,433 $62,337 $118

9 COOLING WATER SYSTEM

9.1 Cooling Towers $7,073 $0 $1,287 $0 $8,360 9.5% $796 0% $0 15.0% $1,373 $10,530 $20

9.2 Circulating Water Pumps $1,845 $0 $133 $0 $1,978 8.4% $167 0% $0 15.0% $322 $2,467 $5

9.3 Circ. Water System Auxiliaries $155 $0 $22 $0 $177 9.5% $17 0% $0 15.0% $29 $222 $0

9.4 Circ. Water Piping $0 $6,449 $1,672 $0 $8,121 9.0% $734 0% $0 20.0% $1,771 $10,626 $20

9.5 Make-up Water System $385 $0 $550 $0 $935 9.6% $90 0% $0 20.0% $205 $1,230 $2

9.6 Component Cooling Water System $761 $911 $648 $0 $2,320 9.4% $217 0% $0 20.0% $507 $3,045 $6

9.9 Circ. Water System Foundations $0 $2,367 $4,024 $0 $6,392 9.5% $606 0% $0 30.0% $2,099 $9,097 $17

SUBTOTAL 9. $10,219 $9,727 $8,337 $0 $28,283 $2,627 $0 $6,307 $37,216 $70

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Erected 

*
Carbon Dioxide Capture Sensitivity Analysis

458

Exhibit 4-158 Case 2 D4B (95%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4B - GEE IGCC w/ two WGS (95% CO2 Capture) x $1, 000

Plant Size: 528.51 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $12,123 $6,685 $13,580 $0 $32,388 9.7% $3,126 0% $0 10.0% $3,551 $39,066 $74

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.6 Ash Storage Silos $588 $0 $640 $0 $1,228 9.7% $119 0% $0 15.0% $202 $1,549 $3

10.7 Ash Transport & Feed Equipment $789 $0 $190 $0 $979 9.3% $91 0% $0 15.0% $161 $1,231 $2

10.8 Misc. Ash Handling Equipment $1,218 $1,493 $446 $0 $3,157 9.5% $300 0% $0 15.0% $519 $3,976 $8

10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $117 9.4% $11 0% $0 30.0% $38 $167 $0

SUBTOTAL 10. $14,718 $8,230 $14,922 $0 $37,869 $3,648 $0 $4,471 $45,989 $87

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $942 $0 $931 $0 $1,873 9.5% $179 0% $0 10.0% $205 $2,257 $4

11.2 Station Service Equipment $4,775 $0 $430 $0 $5,205 9.2% $480 0% $0 10.0% $568 $6,253 $12

11.3 Switchgear & Motor Control $8,827 $0 $1,605 $0 $10,432 9.3% $968 0% $0 15.0% $1,710 $13,110 $25

11.4 Conduit & Cable Tray $0 $4,100 $13,527 $0 $17,628 9.7% $1,705 0% $0 25.0% $4,833 $24,166 $46

11.5 Wire & Cable $0 $7,835 $5,148 $0 $12,982 7.3% $943 0% $0 25.0% $3,481 $17,407 $33

11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $8

11.7 Standby Equipment $232 $0 $227 $0 $459 9.5% $44 0% $0 15.0% $75 $578 $1

11.8 Main Power Transformers $17,378 $0 $143 $0 $17,521 7.6% $1,325 0% $0 15.0% $2,827 $21,674 $41

11.9 Electrical Foundations $0 $155 $407 $0 $563 9.6% $54 0% $0 30.0% $185 $801 $2

SUBTOTAL 11. $32,154 $12,776 $24,915 $0 $69,845 $6,008 $0 $14,409 $90,263 $171

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.4 Other Major Component Control $1,137 $0 $759 $0 $1,896 9.5% $179 5% $95 15.0% $326 $2,496 $5

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.6 Control Boards,Panels & Racks $261 $0 $168 $0 $429 9.5% $41 5% $21 20.0% $98 $589 $1

12.7 Computer & Accessories $6,064 $0 $194 $0 $6,258 9.2% $574 5% $313 10.0% $715 $7,860 $15

12.8 Instrument Wiring & Tubing $0 $2,118 $4,331 $0 $6,449 8.5% $547 5% $322 25.0% $1,830 $9,148 $17

12.9 Other I & C Equipment $4,054 $0 $1,968 $0 $6,022 9.4% $567 5% $301 15.0% $1,033 $7,923 $15

SUBTOTAL 12. $11,516 $2,118 $7,420 $0 $21,054 $1,908 $1,053 $4,001 $28,016 $53

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 110 2,340 0 2,450 9.9% 243 0% 0 30.0% 808 3,501 7

13.2 Site Improvements 0 1,947 2,588 0 4,536 9.9% 447 0% 0 30.0% 1,495 6,478 12

13.3 Site Facilities 3,490 0 3,683 0 7,173 9.9% 707 0% 0 30.0% 2,364 10,243 19

SUBTOTAL 13. $3,490 $2,057 $8,611 $0 $14,158 $1,398 $0 $4,667 $20,222 $38

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Erected 
Carbon Dioxide Capture Sensitivity Analysis

459

Exhibit 4-158 Case 2 D4B (95%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D4B - GEE IGCC w/ two WGS (95% CO2 Capture) x $1, 000

Plant Size: 528.51 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $265 $150 $0 $414 8.8% $36 0% $0 20.0% $90 $541 $1

14.2 Steam Turbine Building $0 $2,378 $3,388 $0 $5,767 9.2% $531 0% $0 15.0% $945 $7,242 $14

14.3 Administration Building $0 $883 $640 $0 $1,523 8.9% $136 0% $0 15.0% $249 $1,907 $4

14.4 Circulation Water Pumphouse $0 $165 $87 $0 $252 8.8% $22 0% $0 15.0% $41 $315 $1

14.5 Water Treatment Buildings $0 $594 $580 $0 $1,174 9.0% $106 0% $0 15.0% $192 $1,472 $3

14.6 Machine Shop $0 $452 $309 $0 $761 8.9% $68 0% $0 15.0% $124 $953 $2

14.7 Warehouse $0 $729 $471 $0 $1,200 8.9% $106 0% $0 15.0% $196 $1,503 $3

14.8 Other Buildings & Structures $0 $437 $340 $0 $777 8.9% $69 0% $0 20.0% $169 $1,016 $2

14.9 Waste Treating Building & Str. $0 $975 $1,864 $0 $2,839 9.3% $265 0% $0 20.0% $621 $3,724 $7

SUBTOTAL 14. $0 $6,878 $7,829 $0 $14,708 $1,339 $0 $2,627 $18,673 $35

Total Cost $726,934 $76,588 $307,485 $0 $1,111,007 $104,599 $65,840 $202,425 $1,483,871 $2,808

Owner's Costs

Preproduction Costs

6 Months All Labor $13,548 $26

1 Month Maintenance Materials $3,017 $6

1 Month Non-fuel Consumables $386 $1

1 Month Waste Disposal $318 $1

25% of 1 Months Fuel Cost at 100% CF $1,694 $3

2% of TPC $29,677 $56

Total $48,640 $92

Inventory Capital

60 day supply of fuel and consumables at 100% CF $14,323 $27

0.5% of TPC (spare parts) $7,419 $14

Total $21,742 $41

Initial Cost for Catalyst and Chemicals $7,396 $14

Land $900 $2

Other Owner's Costs $222,581 $421

Financing Costs $40,065 $76

Total Overnight Costs (TOC) $1,825,194 $3,453

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,080,721 $3,937

Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Acct No. Item/Description Erected 

Equipment 

Cost

Material 

Cost

Labor
Carbon Dioxide Capture Sensitivity Analysis

460

Exhibit 4-159 Case 2 D4B Initial and Annual O&M Expenses

Case: Case 2 D4B - GEE IGCC w/ two WGS (95% CO2 Capture)

Plant Size (MWe): 528.51 Heat Rate (Btu/kWh): 10,731

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 80 CO2 Captured (TPD): 13,692

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 10.0 10.0

Foreman 1.0 1.0

Lab Tech's etc. 3.0 3.0

TOTAL Operating Jobs 16.0 16.0

$ $/kW-net

Annual Operating Labor Cost (calc'd) $6,313,507 $11.946

Maintenance Labor Cost (calc'd) $15,363,537 $29.070

Administrative & Support Labor (calc'd) $5,419,261 $10.254

Property Taxes & Insurance $29,677,411 $56.153

TOTAL FIXED OPERATING COSTS $56,773,716 $107.422

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $28,962,382 0.00782

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 4,132 1.08 $0 $1,305,114 0.00035

Chemicals

MU & WT Chem. (lbs) 0 24,618 0.17 $0 $1,244,079 0.00034

Carbon (Mercury Removal) (lb) 79,648 136 1.05 $83,644 $41,704 0.00001

COS Catalyst (m3) 0 0.00 2,397.36 $0 $0 0.00000

Water Gas Shift Catalyst (ft3) 6,236 4.27 498.83 $3,110,710 $622,142 0.00017

Selexol Solution (gal) 313,601 105 13.40 $4,201,701 $410,790 0.00011

SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000

Claus Catalyst (ft3) 0 2.01 131.27 $0 $77,069 0.00002

Subtotal Chemicals $7,396,055 $2,395,785 0.00065

Other

Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $0 0.00000

Waste Disposal

Spent Mercury Sorbent (lb) 0 136 0.42 $0 $16,679 0.00000

Flyash (ton) 0 0 0.00 $0 $0 0.00000

Slag (ton) 0 640 16.23 $0 $3,032,589 0.00082

Subtotal Solid Waste Disposal $0 $3,049,268 $0

By-products & Emissions

Sulfur (tons) 0 146 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $35,712,549 0.00964

Coal FUEL (tons) 0 5,834 38.19 $0 $65,049,786 0.01756

INITIAL & ANNUAL O&M EXPENSES

Annual Costs

Consumption
Carbon Dioxide Capture Sensitivity Analysis

461

Exhibit 4-160 Case 2 D4C (97%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4C - GEE IGCC w/ two WGS (97% CO2 Capture) x $1, 000

Plant Size: 522.89 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

1 COAL HANDLING SYSTEM

1.1 Coal Receive & Unload $3,744 $0 $1,830 $0 $5,574 9.0% $499 0% $0 20.0% $1,215 $7,288 $14

1.2 Coal Stackout & Reclaim $4,839 $0 $1,173 $0 $6,012 8.8% $527 0% $0 20.0% $1,308 $7,846 $15

1.3 Coal Conveyors & Yd Crus $4,499 $0 $1,161 $0 $5,659 8.8% $497 0% $0 20.0% $1,231 $7,387 $14

1.4 Other Coal Handling $1,177 $0 $269 $0 $1,446 8.8% $126 0% $0 20.0% $314 $1,886 $4

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $2,650 $6,626 $0 $9,275 9.6% $889 0% $0 20.0% $2,033 $12,197 $23

SUBTOTAL 1. $14,259 $2,650 $11,058 $0 $27,966 $2,539 $0 $6,101 $36,606 $70

2 COAL PREP & FEED SYSTEMS

2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,599 $383 $251 $0 $2,233 8.6% 191 0% 0 20.0% $485 $2,908 $6

2.3 Slurry Prep & Feed $21,873 $0 $9,652 $0 $31,525 9.1% 2,864 5% 1,576 20.0% $7,193 $43,158 $83

2.4 Misc. Coal Prep & Feed $879 $640 $1,919 $0 $3,438 9.2% 316 0% 0 20.0% $751 $4,505 $9

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $3,418 $2,806 $0 $6,224 9.3% 576 0% 0 20.0% $1,360 $8,161 $16

SUBTOTAL 2. $24,352 $4,441 $14,627 $0 $43,420 $3,948 $1,576 $9,789 $58,732 $112

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System 2,823 4,848 2,559 0 10,230 9.3% 948 0% 0 20.0% $2,236 $13,413 $26

3.2 Water Makeup & Pretreating 708 74 396 0 1,177 9.5% 112 0% 0 30.0% $387 $1,676 $3

3.3 Other Feedwater Subsystems 1,545 522 470 0 2,536 9.0% 228 0% 0 20.0% $553 $3,317 $6

3.4 Service Water Systems 405 834 2,895 0 4,134 9.8% 403 0% 0 30.0% $1,361 $5,898 $11

3.5 Other Boiler Plant Systems 2,173 842 2,087 0 5,103 9.5% 484 0% 0 20.0% $1,117 $6,705 $13

3.6 FO Supply Sys & Nat Gas $315 $595 $555 $0 1,466 9.6% 141 0% 0 20.0% $321 $1,929 $4

3.7 Waste Treatment Equipment 989 0 604 0 1,593 9.7% 155 0% 0 30.0% $524 $2,272 $4

3.8 Misc. Power Plant Equipment $1,121 $150 $575 $0 1,846 9.7% 178 0% 0 30.0% $607 $2,632 $5

SUBTOTAL 3. $10,079 $7,865 $10,141 $0 $28,085 $2,650 $0 $7,107 $37,842 $72

4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $113,671 $0 $62,284 $0 $175,955 9.2% $16,119 13.9% $24,419 15.3% $33,196 $249,688 $478

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.3 ASU/Oxidant Compression $192,866 $0 w/equip. $0 $192,866 9.7% $18,694 0% $0 10.0% $21,156 $232,717 $445

4.4 Scrubber & Low Temperature Cooling 6,039 $4,915 $5,116 $0 $16,070 9.6% $1,543 0% $0 20.0% $3,523 $21,136 $40

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.6 Soot Recovery & SARU $1,842 $875 $1,728 $0 $4,445 9.6% $428 0% $0 20.0% $975 $5,848 $11

4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

4.8 Gasification Foundations $0 $6,475 $5,405 $0 $11,880 9.3% $1,101 0% $0 25.0% $3,245 $16,226 $31

SUBTOTAL 4. $314,418 $12,265 $74,533 $0 $401,216 $37,886 $24,419 $62,094 $525,614 $1,005

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Erected 
Carbon Dioxide Capture Sensitivity Analysis

462

Exhibit 4-160 Case 2 D4C (97%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4C - GEE IGCC w/ two WGS (97% CO2 Capture) x $1, 000

Plant Size: 522.89 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $79,390 $0 $67,365 $0 $146,755 9.7% $14,193 20% $29,351 20.0% $38,060 $228,358 $437

5A.2 Elemental Sulfur Plant $10,312 $2,055 $13,304 $0 $25,670 9.7% $2,494 0% $0 20.0% $5,633 $33,797 $65

5A.3 Mercury Removal $1,374 $0 $1,045 $0 $2,419 9.7% $234 5% $121 20.0% $555 $3,328 $6

5A.4 Shift Reactors $9,578 $0 $3,856 $0 $13,434 9.7% $1,306 0% $0 20.0% $2,948 $17,688 $34

5A.5 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0

5A.6 Blowback Gas Systems $1,347 $0 $255 $0 $1,602 12.2% $195 0% $0 20.0% $360 $2,157 $4

5A.7 Fuel Gas Piping $0 $612 $429 $0 $1,041 9.3% $96 0% $0 20.0% $227 $1,365 $3

5A.9 HGCU Foundations $0 $641 $413 $0 $1,054 9.2% $97 0% $0 30.0% $345 $1,496 $3

5.9 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

SUBTOTAL 5A. $102,001 $3,308 $86,666 $0 $191,975 $18,615 $29,472 $48,127 $288,189 $551

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0

5B.2 CO2 Compression & Drying $19,393 $0 $11,887 $0 $31,280 9.6% $3,013 0% $0 20.0% $6,859 $41,152 $79

5B.3 CO2 Pipeline 0 0 0

5B.4 CO2 Storage 0 0 0

5B.5 CO2 Monitoring 0 0 0

SUBTOTAL 5B. $19,393 $0 $11,887 $0 $31,280 $3,013 $0 $6,859 $41,152 $79

6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 248

6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 15

6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0

6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5

SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $268

7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,462 $0 $4,758 $0 $38,220 9.5% $3,634 0% $0 10.0% $4,185 $46,039 $88

7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

7.3 Ductwork $0 $1,732 $1,236 $0 $2,967 8.8% $260 0% $0 20.0% $646 $3,873 $7

7.4 Stack $3,379 $0 $1,269 $0 $4,648 9.6% $445 0% $0 10.0% $509 $5,602 $11

7.9 HRSG, Duct & Stack Foundations $0 $677 $650 $0 $1,327 9.3% $124 0% $0 30.0% $435 $1,886 $4

SUBTOTAL 7. $36,840 $2,409 $7,913 $0 $47,162 $4,463 $0 $5,775 $57,400 $110

8 STEAM TURBINE GENERATOR

8.1 Steam TG & Accessories $27,322 $0 $4,671 $0 $31,993 9.6% $3,070 0% $0 10.0% $3,506 $38,569 $74

8.2 Turbine Plant Auxiliaries $190 $0 $435 $0 $624 9.8% $61 0% $0 10.0% $69 $754 $1

8.3 Condenser & Auxiliaries $4,738 $0 $1,391 $0 $6,129 9.6% $586 0% $0 10.0% $672 $7,387 $14

8.4 Steam Piping $4,984 $0 $3,506 $0 $8,489 8.6% $729 0% $0 25.0% $2,305 $11,523 $22

8.9 TG Foundations $0 $940 $1,589 $0 $2,529 9.5% $240 0% $0 30.0% $831 $3,600 $7

SUBTOTAL 8. $37,233 $940 $11,591 $0 $49,765 $4,686 $0 $7,382 $61,832 $118

9 COOLING WATER SYSTEM

9.1 Cooling Towers $7,053 $0 $1,283 $0 $8,336 9.5% $794 0% $0 15.0% $1,369 $10,499 $20

9.2 Circulating Water Pumps $1,834 $0 $132 $0 $1,966 8.4% $166 0% $0 15.0% $320 $2,452 $5

9.3 Circ. Water System Auxiliaries $154 $0 $22 $0 $176 9.5% $17 0% $0 15.0% $29 $221 $0

9.4 Circ. Water Piping $0 $6,417 $1,664 $0 $8,081 9.0% $730 0% $0 20.0% $1,762 $10,573 $20

9.5 Make-up Water System $384 $0 $548 $0 $932 9.6% $89 0% $0 20.0% $204 $1,226 $2

9.6 Component Cooling Water System $758 $906 $645 $0 $2,308 9.4% $216 0% $0 20.0% $505 $3,029 $6

9.9 Circ. Water System Foundations $0 $2,356 $4,004 $0 $6,360 9.5% $603 0% $0 30.0% $2,089 $9,052 $17

SUBTOTAL 9. $10,181 $9,679 $8,299 $0 $28,159 $2,616 $0 $6,278 $37,053 $71

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Erected 

*
Carbon Dioxide Capture Sensitivity Analysis

463

Exhibit 4-160 Case 2 D4C (97%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4C - GEE IGCC w/ two WGS (97% CO2 Capture) x $1, 000

Plant Size: 522.89 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $12,118 $6,682 $13,575 $0 $32,376 9.7% $3,125 0% $0 10.0% $3,550 $39,050 $75

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

10.6 Ash Storage Silos $588 $0 $640 $0 $1,228 9.7% $119 0% $0 15.0% $202 $1,549 $3

10.7 Ash Transport & Feed Equipment $788 $0 $190 $0 $979 9.3% $91 0% $0 15.0% $160 $1,230 $2

10.8 Misc. Ash Handling Equipment $1,218 $1,492 $446 $0 $3,156 9.5% $300 0% $0 15.0% $518 $3,974 $8

10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $117 9.4% $11 0% $0 30.0% $38 $167 $0

SUBTOTAL 10. $14,712 $8,227 $14,916 $0 $37,855 $3,646 $0 $4,469 $45,971 $88

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $939 $0 $929 $0 $1,868 9.5% $178 0% $0 10.0% $205 $2,251 $4

11.2 Station Service Equipment $4,802 $0 $433 $0 $5,235 9.2% $483 0% $0 10.0% $572 $6,289 $12

11.3 Switchgear & Motor Control $8,877 $0 $1,614 $0 $10,492 9.3% $973 0% $0 15.0% $1,720 $13,185 $25

11.4 Conduit & Cable Tray $0 $4,124 $13,604 $0 $17,728 9.7% $1,715 0% $0 25.0% $4,861 $24,303 $46

11.5 Wire & Cable $0 $7,879 $5,177 $0 $13,056 7.3% $948 0% $0 25.0% $3,501 $17,506 $33

11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $8

11.7 Standby Equipment $232 $0 $226 $0 $458 9.5% $44 0% $0 15.0% $75 $577 $1

11.8 Main Power Transformers $17,327 $0 $143 $0 $17,470 7.6% $1,321 0% $0 15.0% $2,819 $21,609 $41

11.9 Electrical Foundations $0 $155 $406 $0 $561 9.6% $54 0% $0 30.0% $184 $799 $2

SUBTOTAL 11. $32,177 $12,844 $25,029 $0 $70,050 $6,027 $0 $14,460 $90,536 $173

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 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 0.0% $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.4 Other Major Component Control $1,141 $0 $762 $0 $1,902 9.5% $180 5% $95 15.0% $327 $2,504 $5

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0

12.6 Control Boards,Panels & Racks $262 $0 $168 $0 $430 9.5% $41 5% $22 20.0% $98 $591 $1

12.7 Computer & Accessories $6,085 $0 $195 $0 $6,280 9.2% $576 5% $314 10.0% $717 $7,887 $15

12.8 Instrument Wiring & Tubing $0 $2,126 $4,346 $0 $6,471 8.5% $549 5% $324 25.0% $1,836 $9,180 $18

12.9 Other I & C Equipment $4,067 $0 $1,975 $0 $6,043 9.4% $569 5% $302 15.0% $1,037 $7,950 $15

SUBTOTAL 12. $11,555 $2,126 $7,445 $0 $21,126 $1,915 $1,056 $4,015 $28,112 $54

13 IMPROVEMENTS TO SITE

13.1 Site Preparation 0 110 2,341 0 2,451 9.9% 243 0% 0 30.0% 808 3,503 7

13.2 Site Improvements 0 1,948 2,589 0 4,538 9.9% 448 0% 0 30.0% 1,496 6,481 12

13.3 Site Facilities 3,492 0 3,684 0 7,176 9.9% 707 0% 0 30.0% 2,365 10,248 20

SUBTOTAL 13. $3,492 $2,058 $8,615 $0 $14,165 $1,398 $0 $4,669 $20,232 $39

Acct No. Item/Description

Equipment 

Cost

Material 

Cost

Labor Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Erected 
Carbon Dioxide Capture Sensitivity Analysis

464

Exhibit 4-160 Case 2 D4C (97%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007

Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D4C - GEE IGCC w/ two WGS (97% CO2 Capture) x $1, 000

Plant Size: 522.89 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $265 $150 $0 $414 8.8% $36 0% $0 20.0% $90 $541 $1

14.2 Steam Turbine Building $0 $2,379 $3,389 $0 $5,768 9.2% $531 0% $0 15.0% $945 $7,243 $14

14.3 Administration Building $0 $883 $641 $0 $1,523 8.9% $136 0% $0 15.0% $249 $1,908 $4

14.4 Circulation Water Pumphouse $0 $164 $87 $0 $251 8.8% $22 0% $0 15.0% $41 $314 $1

14.5 Water Treatment Buildings $0 $592 $578 $0 $1,170 9.0% $106 0% $0 15.0% $191 $1,467 $3

14.6 Machine Shop $0 $452 $309 $0 $761 8.9% $68 0% $0 15.0% $124 $953 $2

14.7 Warehouse $0 $730 $471 $0 $1,201 8.9% $106 0% $0 15.0% $196 $1,503 $3

14.8 Other Buildings & Structures $0 $437 $340 $0 $777 8.9% $69 0% $0 20.0% $169 $1,016 $2

14.9 Waste Treating Building & Str. $0 $975 $1,863 $0 $2,838 9.3% $265 0% $0 20.0% $620 $3,723 $7

SUBTOTAL 14. $0 $6,876 $7,827 $0 $14,703 $1,338 $0 $2,626 $18,668 $36

Total Cost $728,268 $76,573 $308,878 $0 $1,113,719 $104,861 $66,384 $203,184 $1,488,149 $2,846

Owner's Costs

Preproduction Costs

6 Months All Labor $13,572 $26

1 Month Maintenance Materials $3,024 $6

1 Month Non-fuel Consumables $384 $1

1 Month Waste Disposal $317 $1

25% of 1 Months Fuel Cost at 100% CF $1,693 $3

2% of TPC $29,763 $57

Total $48,754 $93

Inventory Capital

60 day supply of fuel and consumables at 100% CF $14,312 $27

0.5% of TPC (spare parts) $7,441 $14

Total $21,753 $42

Initial Cost for Catalyst and Chemicals $7,479 $14

Land $900 $2

Other Owner's Costs $223,222 $427

Financing Costs $40,180 $77

Total Overnight Costs (TOC) $1,830,436 $3,501

TASC Multiplier (IOU, high risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,086,697 $3,991

Bare Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST

Acct No. Item/Description Erected 

Equipment 

Cost

Material 

Cost

Labor
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465

Exhibit 4-161 Case 2 D4C Initial and Annual O&M Expenses

Case: Case 2 D4C - GEE IGCC w/ two WGS (97% CO2 Capture)

Plant Size (MWe): 522.89 Heat Rate (Btu/kWh): 10,840

Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64

Design/Construction 5 years Book Life (yrs): 30

TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015

Capacity Factor (%): 80 CO2 Captured (TPD): 14,240

OPERATING & MAINTENANCE LABOR

Operating Labor

Operating Labor Rate (base): $34.65 $/hour

Operating Labor Burden: 30.00 % of base

Labor Overhead Charge: 25.00 % of labor

Operating Labor Requirements per Shift: units/mod. Total Plant

Skilled Operator 2.0 2.0

Operator 10.0 10.0

Foreman 1.0 1.0

Lab Tech's etc. 3.0 3.0

TOTAL Operating Jobs 16.0 16.0

$ $/kW-net

Annual Operating Labor Cost (calc'd) $6,313,507 $12.074

Maintenance Labor Cost (calc'd) $15,401,050 $29.454

Administrative & Support Labor (calc'd) $5,428,639 $10.382

Property Taxes & Insurance $29,762,975 $56.920

TOTAL FIXED OPERATING COSTS $56,906,172 $108.830

VARIABLE OPERATING COSTS

$ $/kWh-net

Maintenance Material Costs (calc'd) $29,033,099 0.00792

Consumables Unit Initial

Initial /Day Cost Cost $ $/kWh-net

Water (/1000 gallons) 0 4,109 1.08 $0 $1,297,837 0.00035

Chemicals

MU & WT Chem. (lbs) 0 24,480 0.17 $0 $1,237,142 0.00034

Carbon (Mercury Removal) (lb) 79,597 136 1.05 $83,590 $41,704 0.00001

COS Catalyst (m3) 0 0.00 2,397.36 $0 $0 0.00000

Water Gas Shift Catalyst (ft3) 6,232 4.27 498.83 $3,108,715 $621,743 0.00017

Selexol Solution (gal) 319,914 106 13.40 $4,286,284 $414,702 0.00011

SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000

Claus Catalyst (ft3) 0 2.01 131.27 $0 $77,019 0.00002

Subtotal Chemicals $7,478,589 $2,392,310 0.00065

Other

Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000

Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000

Subtotal Other $0 $0 0.00000

Waste Disposal

Spent Mercury Sorbent (lb) 0 136 0.42 $0 $16,679 0.00000

Flyash (ton) 0 0 0.00 $0 $0 0.00000

Slag (ton) 0 640 16.23 $0 $3,030,656 0.00083

Subtotal Solid Waste Disposal $0 $3,047,335 $0

By-products & Emissions

Sulfur (tons) 0 146 0.00 $0 $0 0.00000

Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $35,770,582 0.00976

Coal FUEL (tons) 0 5,830 38.19 $0 $65,007,907 0.01774

INITIAL & ANNUAL O&M EXPENSES

Annual Costs

Consumption
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4.3.7 GEE IGCC Cost and Performance Summary

A summary of plant costs and performance for the GEE IGCC cases is shown in Exhibit 4-162.

Exhibit 4-162 Cost and Performance Results for the GEE IGCC Cases 

Case 2-D1A 2-D1B 2-D2A 2-D2B 2-D2C 2-D2D 2-D3A 2-D3B 2-D3C 2-D3D 2-D3E 2-D4A 2-D4B 2-D4C

CO2 Capture, % 0% 25% 25% 45% 60% 75% 25% 45% 60% 75% 85% 90% 95% 97%

Gross Power Output, MWe 747.8 750.4 750.4 746.9 745.2 742.0 750.4 746.2 744.2 741.6 739.8 734.0 726.6 723.6

Net Power Output, MWe 622.0 607.2 607.0 590.8 578.4 563.9 607.0 590.0 577.4 563.8 554.5 543.2 528.5 522.9

Net Plant Efficiency, % (HHV) 39.0 38.4 38.4 36.8 35.5 34.3 38.4 36.7 35.5 34.2 33.4 32.6 31.8 31.5

Net Plant Heat Rate, Btu/kWh (HHV) 8,756 8,891 8,895 9,283 9,604 9,958 8,894 9,289 9,614 9,969 10,222 10,459 10,731 10,840

Coal Flowrate (lb/hr) 466,861 462,752 462,861 470,117 476,133 481,355 462,783 469,844 475,867 481,779 485,836 487,026 486,169 485,856

Total CO2 Captured, lb/MWhnet NA 425 430 809 1,127 1,476 429 810 1,125 1,467 1,710 1,899 2,159 2,269

CO2 Capture & Compression Cost, $x1000 0 $166,439 $166,741 $193,350 $212,092 $231,604 $167,196 $194,185 $212,378 $230,775 $242,919 $251,958 $264,505 $228,358

Total Plant Cost, $x1000 $1,235,944 $1,345,298 $1,346,066 $1,389,128 $1,419,771 $1,449,191 $1,346,380 $1,390,235 $1,419,640 $1,447,904 $1,465,871 $1,472,866 $1,483,871 $1,488,149

Owner’s Costs, $x1000 $286,161 $308,679 $308,860 $319,113 $326,535 $333,624 $308,914 $319,358 $326,551 $333,508 $337,972 $338,851 $341,323 $342,287

Total Overnight Cost, $x1000 $1,522,105 $1,653,977 $1,654,925 $1,708,241 $1,746,306 $1,782,815 $1,655,294 $1,709,592 $1,746,192 $1,781,411 $1,803,843 $1,811,717 $1,825,194 $1,830,436

Total Overnight Cost, $/kW $2,447 $2,724 $2,726 $2,891 $3,019 $3,161 $2,727 $2,897 $3,024 $3,160 $3,253 $3,335 $3,453 $3,501

Total As-Spent Capital, $x1000 $1,735,200 $1,885,534 $1,886,615 $1,947,394 $1,990,789 $2,032,409 $1,887,035 $1,948,935 $1,990,658 $2,030,809 $2,056,381 $2,065,358 $2,080,721 $2,086,697

Total As-Spent Capital, $/kW $2,790 $3,105 $3,108 $3,296 $3,442 $3,604 $3,109 $3,303 $3,447 $3,602 $3,709 $3,802 $3,937 $3,991

CO2 Capital Cost Penaltya, $/kW $0 $277 $279 $444 $572 $715 $280 $450 $577 $713 $806 $888 $1,007 $1,054

Cost of Electricityb, mills/kWh 76.3 85.3 85.4 90.8 95.2 100.0 85.4 91.0 95.3 100.0 103.1 105.7 109.3 110.8

COE CO2 Penaltya, mills/kWh NA 9.0 9.1 14.5 18.9 23.7 9.1 14.7 19.0 23.7 26.8 29.4 33.0 34.4

Percent increase in COEa, % NA 11.8% 11.9% 19.0% 24.7% 31.0% 12.0% 19.2% 24.9% 31.0% 35.1% 38.5% 43.3% 45.1%

Cost of CO2 Avoideda, $/tonne NA 48.7 48.6 44.9 43.1 42.5 48.7 45.4 43.6 42.5 41.7 42.7 45.2 46.0

CO2 Emissions, lb/MMBtu 196.8 147.8 147.3 108.8 78.9 49.7 147.3 108.8 79.2 49.7 30.1 19.7 10.4 6.5

CO2 Emissions, lb/MWhnet 1,723 1,314 1,310 1,010 758 495 1,310 1,011 762 496 308 206 112 71

SO2 Emissions, lb/MMBtu 0.005 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002

SO2 Emissions, lb/MWh 0.040 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020

NOx Emissions, lb/MMBtu 0.059 0.055 0.055 0.053 0.051 0.050 0.055 0.053 0.052 0.050 0.049 0.049 0.049 0.049

NOx Emissions, lb/MWh 0.430 0.397 0.397 0.390 0.384 0.379 0.397 0.391 0.385 0.379 0.375 0.376 0.380 0.382

PM Emissions, lb/MMBtu 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071

PM Emissions, lb/MWh 0.052 0.051 0.051 0.052 0.053 0.054 0.051 0.052 0.053 0.054 0.054 0.055 0.055 0.056

Hg Emissions, lb/TBtu 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571

Hg Emissions, lb/TWh 4.16 4.11 4.11 4.20 4.26 4.32 4.11 4.20 4.26 4.33 4.38 4.42 4.46 4.48

Raw Water Withdrawal, gpm 4,734 4,692 4,697 5,038 5,300 5,530 4,695 5,040 5,307 5,569 5,748 5,817 5,739 5,707

Raw Water Consumption, gpm 3,755 3,722 3,727 4,033 4,270 4,481 3,725 4,034 4,276 4,514 4,677 4,741 4,679 4,654

Raw Water Consumption, gal/MWhnet 362 368 368 410 443 477 368 410 444 480 506 524 531 534

a Relative to Case 2 D1A (IGCC 0% CO2 capture)

b Capacity factor is 80% for the GEE IGCC cases
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5. Results

The objective of this study was to identify the optimal CO2 capture level at new SC PC and 

IGCC power plants by employing state-of-the-art control technologies in multiple process 

configurations. The SC PC cases (Case 1) utilize Fluor‟s Econamine FG PlusSM process for 

post-combustion CO2 capture, while the IGCC cases (Case 2) employ a slurry-fed, entrainedflow GEE gasifier and leverage UOP‟s two-stage SelexolTM process for pre-combustion CO2

capture. 

The major results from the CO2 capture sensitivity analysis are discussed below in the following 

order:

Performance (efficiency)

Economics (total overnight cost, cost of electricity, and CO2 avoided cost)

Performance and Cost summary

5.2 Performance

5.2.1 Energy Efficiency

The net plant HHV efficiencies for the SC PC and GEE IGCC cases are presented in Exhibit 5-1

and Exhibit 5-2, respectively. As the CO2 capture requirement is increased for either plant type, 

PC or IGCC, there is an increase in the auxiliary power required to support the capture 

equipment (either Econamine or SelexolTM) and the CO2 compressor trains. Further, more steam 

is consumed by the capture equipment, and by the WGS reactor(s) in the IGCC case, making less 

available for supply to the steam turbine. Both effects (higher auxiliary load and reduced steam 

supply to the turbine) detract from the net power produced by the plant per unit of coal energy 

input, as evidenced by the predicted net plant HHV efficiency trends versus CO2 capture level.
Carbon Dioxide Capture Sensitivity Analysis

470

Exhibit 5-1 Net Plant HHV Efficiency for the Supercritical PC Cases

39.3

35.2

32.9

30.6 28.9 28.2

27.5

25.7

0

1 0

2 0

3 0

4 0

5 0

Case 0 0% Case 1A 30% Case 1B 50% Case 1C 70% Case 1D 85% Case 1E 90% Case 1F 95% Case 1G 99% Net Plant HHV Efficiency, %

Net Plant HHV Efficiency (%)

Capture with Bypass Full Capture 
Carbon Dioxide Capture Sensitivity Analysis

471

Exhibit 5-2 Net Plant HHV Efficiency for the GEE IGCC Cases

39.0

38.4 38.4

36.8

35.5

34.3

38.4

36.7

35.5 34.2 33.4

32.6

31.8 31.5

0

1 0

2 0

3 0

4 0

5 0

D1A 0% D1B 25% D2A 25% D2B 45% D2C 60% D2D 75% D3A 25% D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% D4B 95% D4C 97% Net Plant HHV Efficiency, %

Net Plant HHV Efficiency (%)

No WGS One WGS w/ Bypass Two WGS w/ Bypass Two WGS w/o Bypass

5.3 Economics

5.3.1 Total Overnight Cost

All capital costs are presented as “overnight costs” expressed in June 2007 dollars. The capital 

costs are presented at the TOC level, which includes: (1) equipment (complete with initial 

chemical and catalyst loadings); (2) materials; (3) labor (direct and indirect); (4) engineering and 

construction management; (5) contingencies (process and project); and (6) owner‟s costs. The 

owner‟s costs, which are summarized in Exhibit 2-18, include preproduction costs, inventory 

capital, land costs, financing costs, initial cost for catalysts/chemicals, taxes and insurances, and 

other owner‟s costs.

The TOC for the SC PC and GEE IGCC cases are presented in Exhibit 5-3 and Exhibit 5-4, 

respectively. These exhibits categorized the TOC into five categories: (1) bare erected cost; (2) 

engineering, home office, CM, and fee; (3) project contingency; (4) process contingency; and (5) 

owner‟s costs. 
Carbon Dioxide Capture Sensitivity Analysis

472

The SC PC Case 1 TOC estimates apply to facilities designed with a fixed 550 MW net capacity. 

As the design is equipped for increased CO2 capture, moving from Case 1A through Case 1G, 

the TOC also increases as a result of the need for larger power plant components for power 

generation to offset the auxiliary power and steam requirements of the CO2 capture and 

compression systems. Hence, the increase in installed TOC per net kW delivered. 

Exhibit 5-3 TOC for the Supercritical PC Cases

0

500

1000

1500

2000

2500

3000

3500

4000

4500

Case 0 0% Case 1A 30% Case 1B 50% Case 1C 70% Case 1D 85% Case 1E 90% Case 1F 95% Case 1G 99%

2,025

2,541

2,808

3,075

3,400 3,484 3,572

3,744 TOC, $/kW

Owner's Costs

Process Contingency

Project Contingency

Engr., Home Office, CM, and Fee

Bare Erected Cost

Capture with Bypass Capture without Bypass

The Case 2 GEE IGCC TOC estimates apply to facilities designed with a fixed gross combustion 

turbine capacity of 464 MW. As the plant is equipped for increased CO2 capture, moving from 

Case 2 D1A through Case 2 D4C, the TOC also increases as a result of the need for larger plant 

components for power generation to offset the auxiliary power and steam requirements of the 

WGS reactor(s) and the CO2 capture and compression systems. Hence, the increase in installed 

TOC per net kW delivered. 
Carbon Dioxide Capture Sensitivity Analysis

473

Exhibit 5-4 TOC for the GEE IGCC Cases

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

D1A 0% D1B 25% D2A 25% D2B 45% D2C 60% D2D 75% D3A 25% D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% D4B 95% D4C 97%

2,447

2,724 2,726

2,891

3,019

3,161

2,727

2,897 3,024

3,160

3,253 3,335

3,453 3,501 TOC, $/kW

Owner's Costs

Process Contingency

Project Contingency

Engr., Home Office, CM, and Fee

Bare Erected Cost

No WGS One WGS w/ Bypass Two WGS w/ Bypass Two WGS w/o Bypass

5.3.2 Cost of Electricity

The revenue requirement figure-of-merit in this report is COE expressed in mills/kWh 

(numerically equivalent to $/MWh). The capital expenditure and operating periods for SC PC 

and IGCC power plants are 5 and 30 years, respectively. The costs associated with CO2 TS&M

are included for all capture cases. All costs are expressed in June 2007 dollars, and the resulting 

COE is also expressed in June 2007 year dollars.

The COE for the SC PC and GEE IGCC cases are presented in Exhibit 5-5 and Exhibit 5-6, 

respectively. These exhibits categorized the COE into five categories: (1) capital costs; (2) fixed 

costs; (3) variable costs; (4) fuel costs; and (5) CO2 TS&M costs.

The COE estimates are based on capacity factors of 85 and 80 percent for the SC PC and GEE 

IGCC cases, respectively.
Carbon Dioxide Capture Sensitivity Analysis

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Exhibit 5-5 COE for the Supercritical PC Cases

0

20

40

60

80

100

120

140

Case 0 0% Case 1A 30% Case 1B 50% Case 1C 70% Case 1D 85% Case 1E 90% Case 1F 95% Case 1G 99%

58.9

76.6

84.4

92.8

101.5 104.3 107.0

112.7 COE, mills/kWh

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs

Capture with Bypass Capture without Bypass
Carbon Dioxide Capture Sensitivity Analysis

475

Exhibit 5-6 COE for the GEE IGCC Cases

0

20

40

60

80

100

120

140

D1A 0% D1B 25% D2A 25% D2B 45% D2C 60% D2D 75% D3A 25% D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% D4B 95% D4C 97%

76.3

85.3 85.4

90.8

95.2

100.0

85.4

91.0

95.3 100.0

103.1

105.7 109.3 110.8 COE, mills/kWh

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs

No WGS One WGS w/ Bypass Two WGS w/ Bypass Two WGS w/o Bypass

The CO2 TS&M costs were developed using reference data and scaled estimates, as discussed in 

Section 2.7. In general, the CO2 TS&M costs account for about two to three percent of the total 

COE. A breakdown of the CO2 TS&M costs for the SC PC and GEE IGCC cases are shown in 

Exhibit 5-7 and Exhibit 5-8, respectively.

Exhibit 5-7 CO2 TS&M COE for the Supercritical PC Cases

Study Case 

(CO2 Capture Level)

mills/kWh

CO2

Transport

CO2

Storage

CO2

Monitoring

TS&M

COE

Total 

COE

Case 1A (30%) 1.84 0.77 0.30 2.92 76.64

Case 1B (50%) 2.06 1.04 0.55 3.64 84.38

Case 1C (70%) 2.55 1.38 0.82 4.75 92.75

Case 1D (85%) 2.55 1.64 1.05 5.24 101.49

Case 1E (90%) 2.83 1.74 1.14 5.71 104.29

Case 1F (95%) 2.83 1.84 1.24 5.91 107.00

Case 1G (99%) 2.83 1.99 1.38 6.20 112.65
Carbon Dioxide Capture Sensitivity Analysis

476

Exhibit 5-8 CO2 TS&M COE for the GEE IGCC Cases

Study Case 

(CO2 Capture Level)

mills/kWh

CO2

Transport

CO2

Storage

CO2

Monitoring

TS&M

COE

Total 

COE

Case 2 D1A (0%) 0.00 0.00 0.00 0.00 76.31

Case 2 D1B (25%) 1.77 0.67 0.23 2.67 85.35

Case 2 D2A (25%) 1.78 0.67 0.23 2.68 85.41

Case 2 D2B (45%) 2.03 0.90 0.43 3.36 90.83

Case 2 D2C (60%) 2.31 1.08 0.59 3.98 95.16

Case 2 D2D (75%) 2.64 1.28 0.76 4.68 99.98

Case 2 D3A (25%) 1.78 0.67 0.23 2.68 85.43

Case 2 D3B (45%) 2.04 0.90 0.43 3.36 90.99

Case 2 D3C (60%) 2.32 1.09 0.59 3.99 95.31

Case 2 D3D (75%) 2.64 1.28 0.76 4.68 99.96

Case 2 D3E (85%) 2.68 1.48 0.89 5.05 103.08

Case 2 D4A (90%) 2.74 1.57 0.96 5.27 105.70

Case 2 D4B (95%) 2.82 1.67 1.04 5.53 109.32

Case 2 D4C (97%) 2.85 1.72 1.07 5.63 110.75

5.3.3 CO2 Avoided Costs

The CO2 avoided cost was calculated as illustrated in Equation 1. 

(1)

CO Emissions CO Emissions tonnes MWh

COE COE MWh

Avoided Cost

reference with removal

with removal reference

{ } /

{ } $ /

2 2

The CO2 avoided costs for the SC PC and GEE IGCC cases are presented in Exhibit 5-9 and 

Exhibit 5-10, respectively. The IGCC cases are presented both relative to the equivalent IGCC 

without carbon capture and SC PC without capture plants. For the SC PC plant, the CO2 avoided

costs decrease as the CO2 capture level increases until reaching minimum values at 95 percent 

capture (Case 1F).
Carbon Dioxide Capture Sensitivity Analysis

477

Exhibit 5-9 CO2 Avoided Costs for the Supercritical PC Cases

$0

$20

$40

$60

$80

$100

$120

$140

Case 1A 30% Case 1B 50% Case 1C 70% Case 1D 85% Case 1E 90% Case 1F 95% Case 1G 99%

103

79

69 67 66 65 68 C O2 Avoided Cost, $/tonne

Capture with Bypass Capture without Bypass

The CO2 avoided costs for the GEE IGCC cases decrease as the CO2 capture level increases, 

until reaching minimum values at 85 to 90 percent capture (Cases D3E and D4A). As a result, 

this analysis concludes that 85 to 90 percent is the optimal CO2 capture level for a GEE IGCC 

power plant.
Carbon Dioxide Capture Sensitivity Analysis

478

Exhibit 5-10 CO2 Avoided Costs for the GEE IGCC Cases

$0

$20

$40

$60

$80

$100

$120

$140

D1B 25% D2A 25% D2B 45% D2C 60% D2D 75% D3A 25% D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% D4B 95% D4C 97%

129 128

93

79

71

128

94

80

71

67 66 67 67

49 49

45 43 42

49

45 44 42 42 43 45 46 C O2 Avoided Cost, $/tonne

Relative to SCPC w/o CCS

Relative to IGCC w/o CCS

No WGS One WGS w/ Bypass Two WGS w/ Bypass Two WGS w/o Bypass

5.4 Cost and Performance Summary

The following conclusions can be drawn from this analysis.

5.4.1 Supercritical PC Cases

 The „slip-stream‟ approach is more cost-effective for <90 percent CO2 capture than 

removing reduced CO2 fractions from the entire flue gas stream. The cost of CO2 capture 

with the Econamine process is dependent on the volume of gas being treated and a 

reduction in flue gas flow rate will: (1) decrease the quantity of energy consumed by flue 

gas blowers; (2) reduce the size of the CO2 absorption columns; (3) trim the cooling 

water requirement of the direct contact cooling system; and (4) decrease the amount of 

fan power required to increase flue gas temperature and plume buoyancy. 

 With partial bypass around the Econamine system, CO2 capture is limited to 85 percent. 

To achieve 90 percent or greater CO2 capture, the entire flue gas stream must be treated.

 On a $/tonne CO2 avoided basis, 95 percent (Case 1F) is the optimal CO2 capture level.
Carbon Dioxide Capture Sensitivity Analysis

479

5.4.2 GEE IGCC Cases

 For the GEE gasifier, CO2 capture is limited to 25 percent without WGS.

 Due to the high level of integration between the H2S and CO2 absorbers in the two-stage 

SelexolTM system (see Exhibit 4-8), it is assumed in this analysis that it is not possible to 

operate the two stages independently, and therefore is not feasible to model 0 percent

CO2 capture with this system. Since the first stage is designed to operate synergistically 

with the second, some level of CO2 removal is unavoidable. 

 With a S:DG ratio of 0.25, CO2 capture is limited to: (1) 75 percent with one-stage WGS; 

and (2) 85 percent with two-stage WGS and five percent WGS bypass.

 For 90 percent or greater CO2 capture, two WGS reactors without bypass and a S:DG 

ratio of 0.3 are required.

 The performance and cost for intermediate levels of CO2 capture (25 to 75 percent) are 

similar with one- and two-stage WGS. The two-stage WGS system requires more shift 

steam for the two reactors, but the one-stage WGS system requires a larger COS 

hydrolysis unit to treat the entire syngas stream, which adds capital cost.

 On a $/tonne CO2 avoided basis, 85 to 90 percent is the optimal CO2 capture level.

5.4.3 SCPC and IGCC Comparisons

The following conclusions can be drawn from this analysis.

At all levels of carbon capture considered in this analysis, an IGCC plant will operate 

more efficiently than a SC PC plant. This higher efficiency results in lower fuel costs 

and reduced coal handling costs for the same level of power output.

At lower levels of CO2 capture, the COE of a SC PC plant is less than an IGCC plant. 

However this COE advantage begins to disappear as capture level increases. For CCS 

greater than approximately 90 percent, IGCC and SC PC have costs of electricity that are 

nearly equal. This same trend applies to plant capital costs (expressed in $/kW).

CO2 avoided costs, using analogous non-capture plants as reference, are substantially 

lower for IGCC than for SC PC, for all levels of capture. This is reflective of the 

relatively lower cost impact associated with adding CO2 controls to an IGCC plant 

compared to SC PC. However, the avoided CO2 costs for IGCC capture plants, using the 

SC PC non-capture reference plant, are higher due to the higher COE of non-capture 

IGCC plants. 

CO2 avoided costs for SC PC plants are high for low levels of CCS, and then start to 

diminish as the capture increases. Gradually, a minimum is reached around 95% CCS, 

before costs start to rise again slightly. This suggests that if a SC PC plant will lay out 
Carbon Dioxide Capture Sensitivity Analysis

480

the additional capital required to install CO2 controls, that equipment could be used most 

cost-effectively by capturing as much carbon dioxide as possible (up to about 95%).

CO2 avoided costs for IGCC (relative to an IGCC non-capture plant) are less volatile than 

SC PC over a wide range of capture. Although they generally decrease as the level of 

CCS increases (similar to SC PC), the spread between the high and low values is small 

relative to SC PC. Since an IGCC system is a more complex process, it better lends itself 

to optimization than a SC PC plant. To accommodate the specified level of CO2 capture, 

there were numerous variables that were manipulated simultaneously (including the 

number of water gas shift reactors, the amount of shift steam required, solvent circulation 

rate, and the syngas bypass rate) to minimize the cost and performance impact. The SC 

PC plant, although in most cases less expensive than IGCC, is a simpler process and 

therefore exhibits less potential for optimization. 

A summary of SC PC and GEE IGCC plant costs and performance are shown in Exhibit 5-11

and Exhibit 5-12, respectively.
Carbon Dioxide Capture Sensitivity Analysis

481

Exhibit 5-11 Cost and Performance Results for the Supercritical PC Cases

Case 0 1A 1B 1C 1D 1E 1F 1G

CO2 Capture, % 0% 30% 50% 70% 85% 90% 95% 99%

Gross Power Output, MWe 580.4 601.5 618.2 637.8 654.8 661.3 667.9 679.6

Net Power Output, MWe 550.0 550.0 550.0 550.0 550.1 550.0 550.0 550.0

Net Plant Efficiency, % (HHV) 39.3 35.2 32.9 30.6 28.9 28.2 27.5 25.7

Net Plant Heat Rate, Btu/kWh (HHV) 8,687 9,695 10,379 11,151 11,819 12,083 12,400 13,269

Coal Flowrate (lb/hr) 409,550 457,066 489,316 525,764 557,283 569,672 584,578 625,561

Total CO2 Captured, lb/MWhnet NA 588 1,057 1,582 2,037 2,213 2,398 2,674

CO2 Capture & Compression Cost, $x1000 NA $190,138 $266,902 $336,794 $441,781 $463,389 $485,273 $516,797

Total Plant Cost, $x1000 $905,901 $1,138,688 $1,258,942 $1,378,696 $1,525,453 $1,562,889 $1,602,389 $1,678,914

Owner’s Costs, $x1000 $207,800 $258,649 $285,448 $312,458 $344,744 $353,249 $362,267 $380,090

Total Overnight Cost, $x1000 $1,113,701 $1,397,338 $1,544,390 $1,691,155 $1,870,197 $1,916,138 $1,964,657 $2,059,004

Total Overnight Cost, $/kW $2,025 $2,541 $2,808 $3,075 $3,400 $3,484 $3,572 $3,744

Total As-Spent Capital, $x1000 $1,262,937 $1,592,965 $1,760,604 $1,927,917 $2,132,024 $2,184,397 $2,239,708 $2,347,264

Total As-Spent Capital, $/kW $2,296 $2,896 $3,201 $3,505 $3,876 $3,972 $4,072 $4,268

CO2 Capital Cost Penaltya, $/kW NA $516 $783 $1,050 $1,375 $1,459 $1,548 $1,719

Cost of Electricityb, mills/kWh 58.90 76.64 84.38 92.75 101.49 104.29 107.00 112.65

COE CO2 Penaltya, mills/kWh NA 17.7 25.5 33.8 42.6 45.4 48.1 53.8

Percent increase in COEa, % NA 30.1 43.3 57.5 72.3 77.1 81.7 91.3

Cost of CO2 Avoideda, $/tonne NA 102.8 79.1 69.2 67.2 65.9 64.7 68.2

CO2 Emissions, lb/MMBtu 203.2 142.9 101.7 61.7 31.2 20.4 10.2 2.0

CO2 Emissions, lb/MWhnet 1,765 1,385 1,055 687 369 246 126 27

SO2 Emissions, lb/MMBtu 0.086 0.064 0.050 0.036 0.017 0.017 0.016 0.016

SO2 Emissions, lb/MWh 0.75 0.570 0.460 0.340 0.170 0.170 0.170 0.170

NOx Emissions, lb/MMBtu 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070

NOx Emissions, lb/MWh 0.608 0.621 0.646 0.673 0.695 0.703 0.715 0.752

PM Emissions, lb/MMBtu 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013

PM Emissions, lb/MWh 0.113 0.115 0.120 0.125 0.129 0.131 0.133 0.140

Hg Emissions, lb/TBtu 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14

Hg Emissions, lb/TWh 9.93 10.1 10.6 11.0 11.3 11.5 11.7 12.3

Raw Water Withdrawal, gpm 5,394 6,245 6,987 8,386 9,615 10,095 10,512 11,664

Raw Water Consumption, gpm 4,301 4,898 5,433 6,474 7,392 7,753 8,074 8,961

Raw Water Consumption, gal/MWhnet 469 534 593 706 806 846 881 978

a Relative to Case 0 (SC PC without capture from 2010 Bituminous Baseline study)

b Capacity factor is 85% for the SC PC cases
Carbon Dioxide Capture Sensitivity Analysis

482

Exhibit 5-12 Cost and Performance Results for the GEE IGCC Cases

Case 2-D1A 2-D1B 2-D2A 2-D2B 2-D2C 2-D2D 2-D3A 2-D3B 2-D3C 2-D3D 2-D3E 2-D4A 2-D4B 2-D4C

CO2 Capture, % 0% 25% 25% 45% 60% 75% 25% 45% 60% 75% 85% 90% 95% 97%

Gross Power Output, MWe 747.8 750.4 750.4 746.9 745.2 742.0 750.4 746.2 744.2 741.6 739.8 734.0 726.6 723.6

Net Power Output, MWe 622.0 607.2 607.0 590.8 578.4 563.9 607.0 590.0 577.4 563.8 554.5 543.2 528.5 522.9

Net Plant Efficiency, % (HHV) 39.0 38.4 38.4 36.8 35.5 34.3 38.4 36.7 35.5 34.2 33.4 32.6 31.8 31.5

Net Plant Heat Rate, Btu/kWh (HHV) 8,756 8,891 8,895 9,283 9,604 9,958 8,894 9,289 9,614 9,969 10,222 10,459 10,731 10,840

Coal Flowrate (lb/hr) 466,861 462,752 462,861 470,117 476,133 481,355 462,783 469,844 475,867 481,779 485,836 487,026 486,169 485,856

Total CO2 Captured, lb/MWhnet 0 425 430 809 1,127 1,476 429 810 1,125 1,467 1,710 1,899 2,159 2,269

CO2 Capture & Compression Cost, $x1000 0 $166,439 $166,741 $193,350 $212,092 $231,604 $167,196 $194,185 $212,378 $230,775 $242,919 $251,958 $264,505 $228,358

Total Plant Cost, $x1000 $1,235,944 $1,345,298 $1,346,066 $1,389,128 $1,419,771 $1,449,191 $1,346,380 $1,390,235 $1,419,640 $1,447,904 $1,465,871 $1,472,866 $1,483,871 $1,488,149

Owner’s Costs, $x1000 $286,161 $308,679 $308,860 $319,113 $326,535 $333,624 $308,914 $319,358 $326,551 $333,508 $337,972 $338,851 $341,323 $342,287

Total Overnight Cost, $x1000 $1,522,105 $1,653,977 $1,654,925 $1,708,241 $1,746,306 $1,782,815 $1,655,294 $1,709,592 $1,746,192 $1,781,411 $1,803,843 $1,811,717 $1,825,194 $1,830,436

Total Overnight Cost, $/kW $2,447 $2,724 $2,726 $2,891 $3,019 $3,161 $2,727 $2,897 $3,024 $3,160 $3,253 $3,335 $3,453 $3,501

Total As-Spent Capital, $x1000 $1,735,200 $1,885,534 $1,886,615 $1,947,394 $1,990,789 $2,032,409 $1,887,035 $1,948,935 $1,990,658 $2,030,809 $2,056,381 $2,065,358 $2,080,721 $2,086,697

Total As-Spent Capital, $/kW $2,790 $3,105 $3,108 $3,296 $3,442 $3,604 $3,109 $3,303 $3,447 $3,602 $3,709 $3,802 $3,937 $3,991

CO2 Capital Cost Penaltya, $/kW $0 $277 $279 $444 $572 $715 $280 $450 $577 $713 $806 $888 $1,007 $1,054

Cost of Electricityb, mills/kWh 76.3 85.3 85.4 90.8 95.2 100.0 85.4 91.0 95.3 100.0 103.1 105.7 109.3 110.8

COE CO2 Penaltya, mills/kWh 0.0 9.0 9.1 14.5 18.9 23.7 9.1 14.7 19.0 23.7 26.8 29.4 33.0 34.4

Percent increase in COEa, % NA 11.8% 11.9% 19.0% 24.7% 31.0% 12.0% 19.2% 24.9% 31.0% 35.1% 38.5% 43.3% 45.1%

Cost of CO2 Avoideda, $/tonne NA 48.7 48.6 44.9 43.1 42.5 48.7 45.4 43.6 42.5 41.7 42.7 45.2 46.0

CO2 Emissions, lb/MMBtu 196.8 147.8 147.3 108.8 78.9 49.7 147.3 108.8 79.2 49.7 30.1 19.7 10.4 6.5

CO2 Emissions, lb/MWhnet 1,723 1,314 1,310 1,010 758 495 1,310 1,011 762 496 308 206 112 71

SO2 Emissions, lb/MMBtu 0.005 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002

SO2 Emissions, lb/MWh 0.040 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020

NOx Emissions, lb/MMBtu 0.059 0.055 0.055 0.053 0.051 0.050 0.055 0.053 0.052 0.050 0.049 0.049 0.049 0.049

NOx Emissions, lb/MWh 0.430 0.397 0.397 0.390 0.384 0.379 0.397 0.391 0.385 0.379 0.375 0.376 0.380 0.382

PM Emissions, lb/MMBtu 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071

PM Emissions, lb/MWh 0.052 0.051 0.051 0.052 0.053 0.054 0.051 0.052 0.053 0.054 0.054 0.055 0.055 0.056

Hg Emissions, lb/TBtu 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571

Hg Emissions, lb/TWh 4.16 4.11 4.11 4.20 4.26 4.32 4.11 4.20 4.26 4.33 4.38 4.42 4.46 4.48

Raw Water Withdrawal, gpm 4,734 4,697 4,700 5,039 5,301 5,531 4,701 5,048 5,308 5,571 5,749 5,818 5,740 5,708

Raw Water Consumption, gpm 3,755 3,726 3,729 4,034 4,271 4,482 3,729 4,040 4,277 4,515 4,678 4,742 4,680 4,655

Raw Water Consumption, gal/MWhnet 362 368 369 410 443 477 369 411 444 480 506 524 531 534

a Relative to Case 0 (GEE IGCC without capture from 2010 Bituminous Baseline study)

b Capacity factor is 80% for the GEE IGCC cases
Carbon Dioxide Capture Sensitivity Analysis

483

Appendix A
Carbon Dioxide Capture Sensitivity Analysis

484

As part of this study, various cost curves and algorithms were generated as a function of the CO2

capture level. The algorithms can be used to estimate and predict the cost of CO2 capture over a 

full range of removal efficiencies. The following figures present the results of this effort for both 

the SC PC and GEE IGCC cases. 

Supercritical PC Cost Algorithms 

Appendix A- 1 Supercritical PC CO2 Capture & Compression Cost, $000

y = 0.5548x3- 84.558x2 + 8184.8x + 1105.6

R2 = 0.9977

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

500,000

550,000

0 20 40 60 80 100

CO2 Capture & Compression, $000

CO2 Removal, %

Appendix A- 2 Supercritical PC CO2 Capture & Compression Cost, $/kW

y = 0.001x3- 0.1539x2 + 14.887x + 2.0058

R2 = 0.9977

0

100

200

300

400

500

600

700

800

900

1000

0 20 40 60 80 100

CO2 Capture & Compression, $/kW

CO2 Removal, %
Carbon Dioxide Capture Sensitivity Analysis

485

Appendix A- 3 Supercritical PC Total Overnight Cost, $000

y = 17.407x2 + 7296.4x + 1E+06

R2 = 0.9942

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

0 20 40 60 80 100

TOC, $000

C O2 Removal, %

Appendix A- 4 Supercritical PC Total Overnight Cost, $/kW

y = 0.0317x2 + 13.261x + 2052.5

R2 = 0.9941

0

500

1000

1500

2000

2500

3000

3500

4000

4500

0 20 40 60 80 100

TOC, $/kW

C O2 Removal, %
Carbon Dioxide Capture Sensitivity Analysis

486

Appendix A- 5 Supercritical PC Incremental Capital Cost, $000

y = 0.9452x3- 122.94x2 + 12335x - 145.64

R2 = 0.9987

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

1,000,000

0 20 40 60 80 100

Incremental Capital Cost, $000

C O2 Removal, %

Appendix A- 6 Supercritical PC Incremental Capital Cost, $/kW

y = 0.0017x3- 0.2244x2 + 22.457x - 0.2821

R2 = 0.9987

0

200

400

600

800

1000

1200

1400

1600

1800

2000

0 20 40 60 80 100

Incremental Capital Cost, $/kW

C O2 Removal, %
Carbon Dioxide Capture Sensitivity Analysis

487

Appendix A- 7 Supercritical PC COE, mills/kWh

y = 0.0004x2 + 0.4627x + 59.954

R2 = 0.9916

0

20

40

60

80

100

120

140

160

180

200

0 20 40 60 80 100

COE, mills/kWh

C O2 Removal, %

Appendix A- 8 Supercritical PC Incremental COE, mills/kWh

y = 7E-05x3- 0.0093x2 + 0.8136x - 0.0139

R2 = 0.9988

0

10

20

30

40

50

60

70

80

0 20 40 60 80 100

Incremental COE, mills/kWh

C O2 Removal, %
Carbon Dioxide Capture Sensitivity Analysis

488

Appendix A- 9 Supercritical PC Percent Increase in COE

y = 0.0001x3- 0.0159x2 + 1.3813x - 0.0236

R2 = 0.9988

0

20

40

60

80

100

0 20 40 60 80 100

% Increase in COE

C O2 Removal, %

Appendix A- 10 Supercritical PC CO2 Capture Avoided Costs

y = -9E-05x3 + 0.0288x2- 3.0308x + 170.09

R2 = 0.9942

0

20

40

60

80

100

120

0 20 40 60 80 100 CO2 Avoided Cost, $/tonne

C O2 Removal, %
Carbon Dioxide Capture Sensitivity Analysis

489

GEE IGCC Cost Algorithms 

Appendix A- 11 GEE IGCC CO2 Capture & Compression Cost, $000

y = 0.6512x3- 128.25x2 + 8882.4x + 6245.6

R2 = 0.968

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

0 20 40 60 80 100

CO2 Capture & Compression, $000

C O2 Removal, %

Appendix A- 12 GEE IGCC CO2 Capture & Compression Cost, $/kW

y = 0.0011x3- 0.2113x2 + 14.69x + 9.2348

R2 = 0.9761

0

100

200

300

400

500

600

0 20 40 60 80 100

CO2 Capture & Compression, $/kW

C O2 Removal, %
Carbon Dioxide Capture Sensitivity Analysis

490

Appendix A- 13 GEE IGCC Total Overnight Cost, $000

y = -17.934x2 + 4680.4x + 2E+06

R2 = 0.9908

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

0 20 40 60 80 100

TOC, $000

C O2 Removal, %

Appendix A- 14 GEE IGCC Total Overnight Cost, $/kW

y = 0.0215x2 + 7.7x + 2492.3

R2 = 0.9883

0

500

1000

1500

2000

2500

3000

3500

4000

4500

0 20 40 60 80 100

TOC, $/kW

C O2 Removal, %
Carbon Dioxide Capture Sensitivity Analysis

491

Appendix A- 15 GEE IGCC Incremental Capital Cost, $000

y = 0.3375x3- 67.922x2 + 6587.6x + 2094.5

R2 = 0.9987

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

0 20 40 60 80 100

Incremental Capital Cost, $000

C O2 Removal, %

Appendix A- 16 GEE IGCC Incremental Capital Cost, $/kW

y = 0.0013x3- 0.1731x2 + 15.129x - 5.4845

R2 = 0.9979

0

100

200

300

400

500

600

700

800

900

1000

1100

1200

0 20 40 60 80 100

Incremental Capital Cost, $/kW

C O2 Removal, %
Carbon Dioxide Capture Sensitivity Analysis

492

Appendix A- 17 GEE IGCC COE, mills/kWh

y = 0.0007x2 + 0.2567x + 77.683

R2 = 0.9909

0

20

40

60

80

100

120

140

160

180

200

0 20 40 60 80 100

COE, mills/kWh

C O2 Removal, %

Appendix A- 18 GEE IGCC Incremental COE, mills/kWh

y = 4E-05x3- 0.0051x2 + 0.4762x - 0.1251

R2 = 0.9986

0

10

20

30

40

50

60

0 20 40 60 80 100

Incremental COE, mills/kWh

C O2 Removal, %
Carbon Dioxide Capture Sensitivity Analysis

493

Appendix A- 19 GEE IGCC Percent Increase in COE

y = 5E-05x3- 0.0066x2 + 0.6241x - 0.1639

R2 = 0.9986

0

10

20

30

40

50

0 20 40 60 80 100

% Increase in COE

C O2 Removal, %

Appendix A- 20 GEE IGCC CO2 Capture Avoided Costs

y = 0.0152x2- 2.6925x + 185.93

R2 = 0.9976

y = 6E-05x3- 0.0082x2 + 0.1857x + 48.148

R2 = 0.9607

0

20

40

60

80

100

120

140

0 20 40 60 80 100 CO2 Avoided Cost, $/tonne

C O2 Removal, %

Relative to SCPC w/o CCS

Relative to IGCC w/o CCS
Carbon Dioxide Capture Sensitivity Analysis

494

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