Cost and Performance 

Baseline for Fossil Energy 

Plants

Volume 3a: Low Rank Coal to 

Electricity: IGCC Cases

May 2011

DOE/NETL-2010/1399
Disclaimer

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

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

nor any of their employees, makes any warranty, express or implied, or assumes any 

legal liability or responsibility for the accuracy, completeness, or usefulness of any 

information, apparatus, product, or process disclosed, or represents that its use would 

not infringe privately owned rights. Reference therein to any specific commercial 

product, process, or service by trade name, trademark, manufacturer, or otherwise 

does not necessarily constitute or imply its endorsement, recommendation, or favoring 

by the United States Government or any agency thereof. The views and opinions of 

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

Government or any agency thereof.
COST AND PERFORMANCE BASELINE 

FOR FOSSIL ENERGY PLANTS

VOLUME 3a: LOW RANK COAL TO ELECTRICITY:

IGCC CASES

DOE/NETL-2010/1399

Final Report

May 2011

NETL Contact:

James B. Black

Office of Program Planning & Analysis, Performance Division

National Energy Technology Laboratory

www.netl.doe.gov
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Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

NETL Viewpoint

Background

The goal of Fossil Energy Research, Development, and Demonstration (RD&D) is to ensure the 

availability of ultra-clean (“zero” emissions), abundant, low-cost, domestic electricity and energy 

(including hydrogen) to fuel economic prosperity and strengthen energy security. A broad 

portfolio of technologies is being developed within the Clean Coal Program to accomplish this 

objective. Ever increasing technological enhancements are in various stages of the research 

“pipeline,” and multiple paths are being pursued to create a portfolio of promising technologies 

for development, demonstration, and eventual deployment. The technological progress of recent 

years has created a remarkable new opportunity for coal. Advances in technology are making it 

possible to generate power from fossil fuels with great improvements in the efficiency of energy 

use while at the same time significantly reducing the impact on the environment, including the 

long-term impact of fossil energy use on the Earth’s climate. The objective of the Clean Coal 

RD&D Program is to build on these advances and bring these building blocks together into a 

new, revolutionary concept for future coal-based power and energy production.

Objective

To establish baseline performance and cost estimates for today’s fossil energy plants, it is 

necessary to look at the current state of technology. Such a baseline can be used to benchmark 

the progress of the Fossil Energy RD&D portfolio. This study provides an accurate, independent 

assessment of the cost and performance for Integrated Gasification Combined Cycle (IGCC)

plants with and without carbon dioxide (CO2) capture and sequestration using both Powder River 

Basin (PRB) and North Dakota lignite (NDL) coals. 

Approach

The power plant configurations analyzed in this study were modeled using the ASPEN Plus® 

(Aspen) modeling program. Performance and process limits were based upon published reports, 

information obtained from vendors and users of the technology, cost and performance data from 

design/build utility projects, and/or best engineering judgment. Capital and operating costs were 

estimated by WorleyParsons based on simulation results and through a combination of existing 

vendor quotes, scaled estimates from previous design/build projects, or a combination of the two. 

Operation and maintenance (O&M) costs and the cost for transporting, storing, and monitoring 

(TS&M) carbon dioxide (CO2) in the cases with carbon capture were also estimated based on 

reference data and scaled estimates. The cost of electricity (COE) was determined for all plants 

assuming investor-owned utility (IOU) financing. The initial results of this analysis were 

subjected to a significant peer review by industry experts, academia and government research 

and regulatory agencies. Based on the feedback from these experts, the report was updated both 

in terms of technical content and revised costs.

Fossil Energy RD&D aims at improving the performance and cost of clean coal power systems 

including the development of new approaches to capture and sequester greenhouse gases 

(GHGs). Improved efficiencies and reduced costs are required to improve the competitiveness of 

these systems in today’s market and regulatory environment as well as in a carbon constrained 

scenario. The results of this analysis provide a starting point from which to measure the progress 

of RD&D achievements.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

III

Table of Contents

TABLE OF CONTENTS ...........................................................................................................III

LIST OF EXHIBITS ....................................................................................................................V

PREPARED BY ..........................................................................................................................XI

LIST OF ACRONYMS AND ABBREVIATIONS...............................................................XIII

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

Energy Efficiency .................................................................................................................................................3

Water Use.............................................................................................................................................................3

Cost Results..........................................................................................................................................................7

Cost of Electricity.................................................................................................................................................8

Cost of CO2 Avoided...........................................................................................................................................12

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

2. GENERAL EVALUATION BASIS ...................................................................................23

2.1 SITE CHARACTERISTICS ..................................................................................................23

2.2 COAL CHARACTERISTICS ................................................................................................25

2.3 ENVIRONMENTAL TARGETS ............................................................................................28

2.4 CAPACITY FACTOR .........................................................................................................31

2.5 RAW WATER WITHDRAWAL AND CONSUMPTION............................................................31

2.6 COST ESTIMATING METHODOLOGY ................................................................................33

2.6.1 Capital Costs .......................................................................................................................................33

2.6.2 Operations and Maintenance Costs.....................................................................................................42

2.6.3 CO2 Transport, Storage and Monitoring .............................................................................................43

2.6.4 Finance Structure, Discounted Cash Flow Analysis, and COE...........................................................47

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

3. IGCC POWER PLANTS ....................................................................................................57

3.1 IGCC COMMON PROCESS AREAS ...................................................................................57

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

3.1.2 Coal Drying .........................................................................................................................................58

3.1.3 Gasifier Modeling................................................................................................................................62

3.1.4 ASU Choice and Integration................................................................................................................62

3.1.5 High Temperature Syngas Cooling......................................................................................................66

3.1.6 Water Gas Shift Reactors.....................................................................................................................67

3.1.7 COS Hydrolysis ...................................................................................................................................67

3.1.8 Mercury Removal.................................................................................................................................68

3.1.9 Acid Gas Removal Process Selection...................................................................................................69

3.1.10 Sulfur Recovery/Tail Gas Cleanup Process Selection .........................................................................77

3.1.11 Slag and Ash Handling ........................................................................................................................80

3.1.12 Power Island........................................................................................................................................81

3.1.13 Steam Generation Island .....................................................................................................................85

3.1.14 Accessory Electric Plant......................................................................................................................88

3.1.15 Instrumentation and Control................................................................................................................89

3.2 SHELL COAL GASIFICATION PROCESS IGCC CASES .......................................................90

3.2.1 Gasifier Background............................................................................................................................90

3.2.2 Key System Assumptions......................................................................................................................93

3.2.3 Sparing Philosophy..............................................................................................................................95

3.2.4 SCGP IGCC Non-Capture Case (S1A and L1A) Process Description................................................95

3.2.5 Case S1A and L1A Performance Results...........................................................................................104

3.2.6 Case S1A and L1A Equipment Lists...................................................................................................118

3.2.7 Case S1A and L1A Cost Estimating...................................................................................................132

3.2.8 SCGP IGCC CO2 Capture Cases (S1B and L1B) Process Description.............................................145
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

IV

3.2.9 Case S1B and L1B Performance Results...........................................................................................152

3.2.10 Case S1B and L1B Equipment List ....................................................................................................166

3.2.11 Case S1B and L1B Cost Estimating...................................................................................................182

3.3 TRIGTM IGCC CASES...................................................................................................195

3.3.1 Gasifier Background..........................................................................................................................195

3.3.2 Key System Assumptions....................................................................................................................198

3.3.3 Sparing Philosophy............................................................................................................................200

3.3.4 TRIGTM IGCC Non-Capture Case (S2A) Process Description..........................................................200

3.3.5 Case S2A Performance Results..........................................................................................................207

3.3.6 Case S2A Equipment Lists.................................................................................................................217

3.3.7 Case S2A Cost Estimating .................................................................................................................229

3.3.8 TRIGTM IGCC CO2 Capture Cases (S2B) Process Description ........................................................236

3.3.9 Case S2B Performance Results..........................................................................................................241

3.3.10 Case S2B Equipment List...................................................................................................................251

3.3.11 Case S2B Cost Estimating .................................................................................................................264

3.4 SIEMENS FUEL GASIFIER IGCC CASES .........................................................................271

3.4.1 Gasifier Background..........................................................................................................................271

3.4.2 Key System Assumptions....................................................................................................................273

3.4.3 Sparing Philosophy............................................................................................................................275

3.4.4 SFG IGCC Non-Capture Case (S3A and L3A) Process Description.................................................275

3.4.5 Case S3A and L3A Performance Results...........................................................................................284

3.4.6 Case S3A and L3A Equipment Lists...................................................................................................298

3.4.7 Case S3A and L3A Cost Estimating...................................................................................................311

3.4.8 SFG IGCC CO2 Capture Cases (S3B and L3B) Process Description ...............................................324

3.4.9 Case S3B and L3B Performance Results...........................................................................................331

3.4.10 Case S3B and L3B Equipment List ....................................................................................................344

3.4.11 Case S3B and L3B Cost Estimating...................................................................................................359

3.5 COP E-GASTM IGCC CASES .........................................................................................372

3.5.1 Gasifier Background..........................................................................................................................372

3.5.2 Key System Assumptions....................................................................................................................374

3.5.3 Sparing Philosophy............................................................................................................................377

3.5.4 CoP E-GasTM IGCC Non-Capture Case (S4A) Process Description ................................................377

3.5.5 Case S4A Performance Results..........................................................................................................384

3.5.6 Case S4A Equipment Lists.................................................................................................................393

3.5.7 Case S4A Cost Estimating .................................................................................................................406

3.5.8 CoP E-GasTM IGCC CO2 Capture Cases (S4B) Process Description...............................................413

3.5.9 Case S4B Performance Results..........................................................................................................418

3.5.10 Case S4B Equipment List...................................................................................................................429

3.5.11 Case S4B Cost Estimating .................................................................................................................442

3.6 IGCC CASE SUMMARY.................................................................................................449

4. REFERENCES...................................................................................................................461
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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List of Exhibits

Exhibit ES-1 Case Descriptions..................................................................................................... 2

Exhibit ES-2 Cost and Performance Summary and Environmental Profile for IGCC Cases........ 4

Exhibit ES-3 Net Plant Efficiency ................................................................................................. 5

Exhibit ES-4 Raw Water Withdrawal and Consumption .............................................................. 6

Exhibit ES-5 Plant Capital Costs................................................................................................... 9

Exhibit ES-6 Economic Parameters Used to Calculate COE ...................................................... 10

Exhibit ES-7 COE by Cost Component....................................................................................... 11

Exhibit ES-8 COE Sensitivity to Fuel Costs................................................................................ 13

Exhibit ES-9 COE Sensitivity to Capacity Factor....................................................................... 14

Exhibit ES-10 CO2 Avoided Costs.............................................................................................. 15

Exhibit ES-11 Study Environmental Targets............................................................................... 16

Exhibit ES-12 SO2, NOx and Particulate Emission Rates........................................................... 17

Exhibit ES-13 Mercury Emission Rates...................................................................................... 18

Exhibit 1-1 IGCC Case Descriptions........................................................................................... 20

Exhibit 2-1 Montana Site Ambient Conditions for PRB Coal Cases .......................................... 23

Exhibit 2-2 North Dakota Site Ambient Conditions for Lignite Coal Cases............................... 23

Exhibit 2-3 Site Characteristics ................................................................................................... 24

Exhibit 2-4 Montana Rosebud PRB, Area D, Western Energy Co. Mine, Subbituminous Design 

Coal Analysis........................................................................................................................ 26

Exhibit 2-5 North Dakota Beulah-Zap Lignite, Freedom, ND Mine, Lignite Design Coal 

Analysis................................................................................................................................. 27

Exhibit 2-6 Standards of Performance for Electric Utility Steam Generating Units Built, 

Reconstructed, or Modified After February 28, 2005........................................................... 28

Exhibit 2-7 NSPS Mercury Emission Limits............................................................................... 29

Exhibit 2-8 IGCC Environmental Targets................................................................................... 30

Exhibit 2-9 Capital Cost Levels and their Elements.................................................................... 33

Exhibit 2-10 Features of an AACE Class 4 Cost Estimate.......................................................... 34

Exhibit 2-11 AACE Guidelines for Process Contingency........................................................... 39

Exhibit 2-12 TASC/TOC Factors ................................................................................................ 39

Exhibit 2-13 Owner’s Costs Included in TOC............................................................................. 40

Exhibit 2-14 CO2 Pipeline Specification ..................................................................................... 44

Exhibit 2-15 Deep, Saline Aquifer Specification ........................................................................ 44

Exhibit 2-16 Global Economic Assumptions .............................................................................. 47

Exhibit 2-17 Financial Structure for Investor Owned Utility High and Low Risk Projects........ 48

Exhibit 2-18 Illustration of COE Solutions using DCF Analysis................................................ 50

Exhibit 2-19 PC with CCS in Current 2007 Dollars.................................................................... 51

Exhibit 2-20 Capital Charge Factors for COE Equation ............................................................. 51

Exhibit 2-21 COE and LCOE Summary...................................................................................... 53

Exhibit 2-22 Baseline SC PC Results for CO2 Cost Calculation................................................. 53

Exhibit 3-1 SCGP Lignite Coal Drying Options......................................................................... 60

Exhibit 3-2 WTA Process Schematic .......................................................................................... 61

Exhibit 3-3 Air Extracted from the Combustion Turbine and Supplied to the ASU in NonCarbon Capture Case ............................................................................................................ 64

Exhibit 3-4 Typical ASU Process Schematic .............................................................................. 65
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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Exhibit 3-5 Flow Diagram for a Conventional AGR Unit........................................................... 70

Exhibit 3-6 Summary of Common AGR Processes..................................................................... 71

Exhibit 3-7 Common Chemical Reagents Used in AGR Processes............................................ 72

Exhibit 3-8 Physical Solvent AGR Process Simplified Flow Diagram....................................... 74

Exhibit 3-9 Common Physical Solvents Used in AGR Processes............................................... 74

Exhibit 3-10 Common Mixed Solvents Used in AGR Processes................................................ 75

Exhibit 3-11 Equilibrium Solubility Data on H2S and CO2 in Various Solvents........................ 76

Exhibit 3-12 Typical Three-Stage Claus Sulfur Plant ................................................................. 79

Exhibit 3-13 Advanced F Class Combustion Turbine Performance Characteristics Using Natural 

Gas ........................................................................................................................................ 82

Exhibit 3-14 Typical Fuel Specification for F-Class Machines................................................... 83

Exhibit 3-15 Allowable Gas Fuel Contaminant Level for F-Class Machines............................. 84

Exhibit 3-16 Case S1A/L1A and S1B/L1B Plant Study Configuration Matrix .......................... 93

Exhibit 3-17 Balance of Plant Assumptions................................................................................ 94

Exhibit 3-18 Case S1A and L1A Process Flow Diagram............................................................ 99

Exhibit 3-19 Case S1A Stream Table ........................................................................................ 100

Exhibit 3-20 Case L1A Stream Table........................................................................................ 102

Exhibit 3-21 Case S1A and L1A Plant Performance Summary ................................................ 105

Exhibit 3-22 Cases S1A and L1A Air Emissions...................................................................... 106

Exhibit 3-23 Case S1A and L1A Carbon Balance..................................................................... 107

Exhibit 3-24 Cases S1A and L1A Sulfur Balance ..................................................................... 107

Exhibit 3-25 Case S1A and L1A Water Balance....................................................................... 108

Exhibit 3-26 Case S1A Heat and Mass Balance........................................................................ 111

Exhibit 3-27 Case L1A Heat and Mass Balance........................................................................ 114

Exhibit 3-28 Cases S1A and L1A Energy Balance ................................................................... 117

Exhibit 3-29 Case S1A Total Plant Cost Summary................................................................... 133

Exhibit 3-30 Case S1A Total Plant Cost Details....................................................................... 134

Exhibit 3-31 Case S1A Owner’s Costs...................................................................................... 137

Exhibit 3-32 Case S1A Initial and Annual O&M Costs............................................................ 138

Exhibit 3-33 Case L1A Total Plant Cost Summary................................................................... 139

Exhibit 3-34 Case L1A Total Plant Cost Details....................................................................... 140

Exhibit 3-35 Case L1A Owner’s Costs...................................................................................... 143

Exhibit 3-36 Case L1A Initial and Annual O&M Costs............................................................ 144

Exhibit 3-37 Case S1B and L1B Process Flow Diagram .......................................................... 147

Exhibit 3-38 Case S1B Stream Table ........................................................................................ 148

Exhibit 3-39 Case L1B Stream Table ........................................................................................ 150

Exhibit 3-40 Case S1B and L1B Plant Performance Summary................................................. 153

Exhibit 3-41 Case S1B and L1B Air Emissions........................................................................ 154

Exhibit 3-42 Cases S1B and L1B Carbon Balance.................................................................... 155

Exhibit 3-43 Cases S1B and L1B Sulfur Balance ..................................................................... 155

Exhibit 3-44 Cases S1B and L1B Water Balance...................................................................... 157

Exhibit 3-45 Case S1B Heat and Mass Balance ........................................................................ 159

Exhibit 3-46 Case L1B Heat and Mass Balance........................................................................ 162

Exhibit 3-47 Cases S1B and L1B Energy Balance.................................................................... 165

Exhibit 3-48 Case S1B Total Plant Cost Summary ................................................................... 183

Exhibit 3-49 Case S1B Total Plant Cost Summary Details....................................................... 184
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

VII

Exhibit 3-50 Case S1B Owner’s Costs...................................................................................... 187

Exhibit 3-51 Case S1B Initial and Annual O&M Costs............................................................ 188

Exhibit 3-52 Case L1B Total Plant Cost Summary................................................................... 189

Exhibit 3-53 Case L1B Total Plant Cost Summary Details....................................................... 190

Exhibit 3-54 Case L1B Owner’s Costs...................................................................................... 193

Exhibit 3-55 Case L1B Initial and Annual O&M Costs............................................................ 194

Exhibit 3-56 Case S2A and S2B Plant Study Configuration Matrix......................................... 198

Exhibit 3-57 Balance of Plant Assumptions.............................................................................. 199

Exhibit 3-58 Case S2A Process Flow Diagram......................................................................... 204

Exhibit 3-59 Case S2A Stream Table ........................................................................................ 205

Exhibit 3-60 Case S2A Plant Performance Summary ............................................................... 208

Exhibit 3-61 Cases S2A Air Emissions..................................................................................... 209

Exhibit 3-62 Case S2A Carbon Balance.................................................................................... 210

Exhibit 3-63 Case S2A Sulfur Balance...................................................................................... 210

Exhibit 3-64 Case S2A Water Balance...................................................................................... 211

Exhibit 3-65 Case S2A Heat and Mass Balance........................................................................ 213

Exhibit 3-66 Case S2A Energy Balance .................................................................................... 217

Exhibit 3-67 Case S2A Total Plant Cost Summary................................................................... 230

Exhibit 3-68 Case S2A Total Plant Cost Details....................................................................... 231

Exhibit 3-69 Case S2A Owner’s Costs...................................................................................... 234

Exhibit 3-70 Case S2A Initial and Annual O&M Costs............................................................ 235

Exhibit 3-71 Case S2B Process Flow Diagram ......................................................................... 238

Exhibit 3-72 Case S2B Stream Table ........................................................................................ 239

Exhibit 3-73 Case S2B Plant Performance Summary................................................................ 242

Exhibit 3-74 Case S2B Air Emissions....................................................................................... 243

Exhibit 3-75 Case S2B Carbon Balance .................................................................................... 244

Exhibit 3-76 Case S2B Sulfur Balance...................................................................................... 244

Exhibit 3-77 Case S2B Water Balance ...................................................................................... 245

Exhibit 3-78 Case S2B Heat and Mass Balance ........................................................................ 247

Exhibit 3-79 Case S2B Energy Balance .................................................................................... 251

Exhibit 3-80 Case S2B Total Plant Cost Summary ................................................................... 265

Exhibit 3-81 Case S2B Total Plant Cost Summary Details....................................................... 266

Exhibit 3-82 Case S2B Owner’s Costs...................................................................................... 269

Exhibit 3-83 Case S2B Initial and Annual O&M Costs............................................................ 270

Exhibit 3-84 Case S3A/L3A and S3B/L3B Plant Study Configuration Matrix ........................ 273

Exhibit 3-85 Balance of Plant Assumptions.............................................................................. 274

Exhibit 3-86 Case S3A and L3A Process Flow Diagram.......................................................... 279

Exhibit 3-87 Case S3A Stream Table ........................................................................................ 280

Exhibit 3-88 Case L3A Stream Table........................................................................................ 282

Exhibit 3-89 Case S3A and L3A Plant Performance Summary ................................................ 285

Exhibit 3-90 Cases S3A and L3A Air Emissions...................................................................... 286

Exhibit 3-91 Case S3A and L3A Carbon Balance..................................................................... 287

Exhibit 3-92 Cases S3A and L3A Sulfur Balance ..................................................................... 287

Exhibit 3-93 Case S3A and L3A Water Balance....................................................................... 288

Exhibit 3-94 Case S3A Heat and Mass Balance........................................................................ 291

Exhibit 3-95 Case L3A Heat and Mass Balance........................................................................ 294
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

VIII

Exhibit 3-96 Cases S3A and L3A Energy Balance ................................................................... 297

Exhibit 3-97 Case S3A Total Plant Cost Summary................................................................... 312

Exhibit 3-98 Case S3A Total Plant Cost Details....................................................................... 313

Exhibit 3-99 Case S3A Owner’s Costs...................................................................................... 316

Exhibit 3-100 Case S3A Initial and Annual O&M Costs.......................................................... 317

Exhibit 3-101 Case L3A Total Plant Cost Summary................................................................. 318

Exhibit 3-102 Case L3A Total Plant Cost Details..................................................................... 319

Exhibit 3-103 Case L3A Owner’s Costs.................................................................................... 322

Exhibit 3-104 Case L3A Initial and Annual O&M Costs.......................................................... 323

Exhibit 3-105 Case S3B and L3B Process Flow Diagram ........................................................ 326

Exhibit 3-106 Case S3B Stream Table ...................................................................................... 327

Exhibit 3-107 Case L3B Stream Table ...................................................................................... 329

Exhibit 3-108 Case S3B and L3B Plant Performance Summary............................................... 332

Exhibit 3-109 Case S3B and L3B Air Emissions...................................................................... 333

Exhibit 3-110 Cases S3B and L3B Carbon Balance.................................................................. 334

Exhibit 3-111 Cases S3B and L3B Sulfur Balance ................................................................... 334

Exhibit 3-112 Cases S3B and L3B Water Balance.................................................................... 335

Exhibit 3-113 Case S3B Heat and Mass Balance ...................................................................... 337

Exhibit 3-114 Case L3B Heat and Mass Balance...................................................................... 340

Exhibit 3-115 Cases S3B and L3B Energy Balance.................................................................. 343

Exhibit 3-116 Case S3B Total Plant Cost Summary ................................................................. 360

Exhibit 3-117 Case S3B Total Plant Cost Summary Details..................................................... 361

Exhibit 3-118 Case S3B Owner’s Costs.................................................................................... 364

Exhibit 3-119 Case S3B Initial and Annual O&M Costs.......................................................... 365

Exhibit 3-120 Case L3B Total Plant Cost Summary................................................................. 366

Exhibit 3-121 Case L3B Total Plant Cost Summary Details..................................................... 367

Exhibit 3-122 Case L3B Owner’s Costs.................................................................................... 370

Exhibit 3-123 Case L3B Initial and Annual O&M Costs.......................................................... 371

Exhibit 3-124 Case S4A and S4B Plant Study Configuration Matrix....................................... 375

Exhibit 3-125 Balance of Plant Assumptions............................................................................ 376

Exhibit 3-126 Case S4A Process Flow Diagram....................................................................... 381

Exhibit 3-127 Case S4A Stream Table ...................................................................................... 382

Exhibit 3-128 Case S4A Plant Performance Summary ............................................................. 385

Exhibit 3-129 Cases S4A Air Emissions................................................................................... 386

Exhibit 3-130 Case S4A Carbon Balance.................................................................................. 387

Exhibit 3-131 Case S4A Sulfur Balance.................................................................................... 387

Exhibit 3-132 Case S4A Water Balance.................................................................................... 388

Exhibit 3-133 Case S4A Heat and Mass Balance...................................................................... 389

Exhibit 3-134 Case S4A Energy Balance .................................................................................. 393

Exhibit 3-135 Case S4A Total Plant Cost Summary................................................................. 407

Exhibit 3-136 Case S4A Total Plant Cost Details..................................................................... 408

Exhibit 3-137 Case S4A Owner’s Costs.................................................................................... 411

Exhibit 3-138 Case S4A Initial and Annual O&M Costs.......................................................... 412

Exhibit 3-139 Case S4B Process Flow Diagram ....................................................................... 415

Exhibit 3-140 Case S4B Stream Table ...................................................................................... 416

Exhibit 3-141 Case S4B Plant Performance Summary.............................................................. 419
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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Exhibit 3-142 Case S4B Air Emissions..................................................................................... 420

Exhibit 3-143 Case S4B Carbon Balance .................................................................................. 421

Exhibit 3-144 Case S4B Sulfur Balance.................................................................................... 421

Exhibit 3-145 Case S4B Water Balance .................................................................................... 422

Exhibit 3-146 Case S4B Heat and Mass Balance ...................................................................... 425

Exhibit 3-147 Case S4B Energy Balance .................................................................................. 429

Exhibit 3-148 Case S4B Total Plant Cost Summary ................................................................. 443

Exhibit 3-149 Case S4B Total Plant Cost Summary Details..................................................... 444

Exhibit 3-150 Case S4B Owner’s Costs.................................................................................... 447

Exhibit 3-151 Case S4B Initial and Annual O&M Costs.......................................................... 448

Exhibit 3-152 Estimated Performance and Cost Results for IGCC Cases................................. 450

Exhibit 3-153 Plant Capital Costs.............................................................................................. 451

Exhibit 3-154 COE by Cost Component ................................................................................... 452

Exhibit 3-155 COE Sensitivity to Fuel Costs............................................................................ 453

Exhibit 3-156 COE Sensitivity to Capacity Factor.................................................................... 455

Exhibit 3-157 Cost of CO2 Avoided in IGCC Cases................................................................. 456

Exhibit 3-158 Normalized Water Usage in IGCC Cases........................................................... 457

Exhibit 3-159 Emissions Profile for IGCC Cases...................................................................... 459

Exhibit 3-160 Mercury Emission for IGCC Cases.................................................................... 460
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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PREPARED BY:

Research and Development Solutions, LLC (RDS)

UPDATED BY:

Energy Sector Planning and Analysis (ESPA)

Vincent H. Chou

Booz Allen Hamilton

John L. Haslbeck

formerly Booz Allen Hamilton

Norma J. Kuehn

Booz Allen Hamilton

Lora L. Pinkerton

WorleyParsons

Elsy Varghese

WorleyParsons

Mark C. Woods

Booz Allen Hamilton

DOE Contract # DE-FE0004001
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

XII

Acknowledgments

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

United States Department of Energy’s (DOE) National Energy Technology Laboratory (NETL) 

under DOE NETL Contract Number DE-AM26-04NT41817; Subtask 41817-401.01.14A. The 

report was updated by Booz Allen Hamilton Inc. under DOE NETL Contract Number DEFE0004001, Energy Sector Planning and Analysis.

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

NETL staff and other past contributors, particularly:

John Wimer, Director of Office of Program Planning & Analysis

James Black

Kristin Gerdes

Eric Grol

Jeffrey Hoffmann

Robert James

Lawrence Rath

Robert Brasington

formerly of Parsons Corporation
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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LIST OF ACRONYMS AND ABBREVIATIONS

AACE Association for the Advancement of Cost Engineering

ADIP Aqueous di-isoproponal

AEO Annual Energy Outlook

AFUDC Allowance for funds used during construction

AGR Acid gas removal

Aspen Aspen Plus®

ASU Air separation unit

BACT Best available control technology

BEC Bare erected cost

BFD Block flow diagram

BFW Boiler feedwater

BFP Boiler feed pump

BLS Bureau of Labor Statistics

Btu British thermal unit

Btu/hr British thermal unit per hour

Btu/kWh British thermal unit per kilowatt hour

Btu/lb British thermal unit per pound

Btu/scf British thermal unit per standard cubic foot

CAMR Clean Air Mercury Rule

CCF Capital Charge Factor

CCPI Clean Coal Power Initiative

CCS Carbon capture and storage

CF Capacity factor

CFB Circulating fluidized bed

CGE Cold gas efficiency

CL Closed-loop

cm Centimeter

CO Carbon monoxide

CO2 Carbon dioxide

COE Cost of electricity

CoP Conoco Phillips

COS Carbonyl sulfide

CRT Cathode ray tube

CS Carbon steel

CT Combustion turbine

CTG Combustion Turbine-Generator

CWP Circulating water pump

CWT Cold water temperature

DCS Distributed control system

DEA Diethanolamine

DI De-ionized

DIPA Diisopropanolamine
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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DOE Department of Energy

EIA Energy Information Administration

EPA Environmental Protection Agency

EPC Engineer/Procure/Construct

EPCM Engineering/Procurement/Construction Management

EPRI Electric Power Research Institute

FBG Fluidized bed gasifier

FGD Flue gas desulfurization

FEED Front-End Engineering Design

FOAK First-of-a-kind

FW Feedwater

ft Foot, feet

GDP Gross domestic product

GEE GE Energy

GHG Greenhouse gas

GJ gigajoules

GJ/hr Gigajoules per hour

GPD Gallons per day

gpm Gallons per minute

GRE Great River Energy

GT Gas turbine

GTC Gasification Technology Conference

hr Hour

Hg Mercury

H2 Hydrogen

HDPE High density polyethylene

HHV Higher heating value

hp Horsepower

HP High pressure

HRSG Heat-recovery steam generator

HVAC Heating, ventilating, and air conditioning

HWT Hot water temperature

Hz Hertz

ICR Information Collection Request

IEA International Energy Agency

IEEE Institute of Electrical and Electronics Engineers

IGCC Integrated gasification combined cycle

IGVs Inlet guide vanes

IOU Investor-owned utility

IP Intermediate pressure

ISO International Standards Organization

KBR Kellogg Brown and Root

kg/hr Kilogram per hour
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

XV

kJ/kg Kilojoules per kilogram

kJ/kWh Kilojoules per kilowatt hour

kJ/Nm3 Kilojoules per normal cubic meter

km kilometer

KO Knockout

kV Kilovolt

kW Kilowatt

kWe Kilowatts electric

kWh Kilowatt-hour

kWt Kilowatt-ton

LAER Lowest Achievable Emission Rate

lb Pound

lb/hr Pounds per hour

lb/MMBtu Pounds per million British thermal units

lb/MWh Pounds per megawatt hour

LCOE Levelized cost of electricity

LHV Lower heating value

LNB Low NOx burner

LP Low pressure

lpm Liters per minute

m Meters

m3

/min Cubic meter per minute

MDEA Methyldiethanolamine

MJ/Nm3 Megajoule per normal cubic meter

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

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

MMkJ/hr Million kilojoules (also shown as 106 kJ) per hour

MNQC Multi Nozzle Quiet Combustor

MPa Megapascals

MVA Mega volt-amps

MWe Megawatts electric

MWh Megawatt-hour

MWth Megawatts thermal

N/A Not applicable

NDL North Dakota lignite

NETL National Energy Technology Laboratory

NGCC Natural gas combined cycle

Nm3

/hr Normal cubic meter per hour

NMP N-methyl-2-pyrrolidone

NOAK Nth-of-a-kind

NOx Oxides of nitrogen

NSPS New Source Performance Standards

NSR New Source Review
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

XVI

N2 Nitrogen

O&M Operation and maintenance

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

OCVnq Category n variable operating cost for the initial year of operation

O2 Oxygen

PC Pulverized coal

ph Phase

PM Particulate matter 

PO Purchase order

POTW Publicly Owned Treatment Works

ppbw Parts Per billion by weight

ppm Parts per million 

ppmv Parts per million volume

ppmvd Parts per million volume, dry 

ppmw Parts per million by weight

PRB Powder River Basin coal region

PSD Prevention of Significant Deterioration

PSDF Power Systems Development Facility

PSFM Power Systems Financial Model

psi Pounds per square inch

psia Pounds per square inch absolute

psig Pounds per square inch gage

RDS Research and Development Solutions, LLC

RH Reheater

SC Supercritical

scf Standard cubic feet

scfh Standard cubic feet per hour

scfm Standard cubic feet per minute

SCGP Shell Coal Gasification Process

SCOT Shell Claus Off-gas Treating

SEP Samenwerkende Electriciteits-Productiebedrijven NV

SFG Siemens Fuel Gasifier

SGC Synthesis gas cooler

SGS Sour gas shift

SO2 Sulfur dioxide

SRU Sulfur recovery unit

SS Stainless steel

STG Steam turbine generator

Syngas Synthesis gas

TASC Total as-spent cost

TEWAC Totally Enclosed Water-to-Air Cooled

TGTU Tail gas treating unit

TOC Total overnight cost

Tonne Metric Ton (1000 kg)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

XVII

TPC Total plant cost

tpd Tons per day

TPH Tons per hour

TRIGTM Transport Reactor Integrated Gasification

TS&M Transport, storage, and monitoring

vol% Volume percent

WB Wet bulb

WGS Water gas shift

wt% Weight percent

$/MMBtu Dollars per million British thermal units

$/MWh dollars per megawatt hour

°C Degrees Celsius

°F Degrees Fahrenheit

5-10s 50-hour work-week
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

XVIII

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Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

1

EXECUTIVE SUMMARY

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

of low rank coal-fired power systems, specifically integrated gasification combined cycle 

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

current or near term market conditions. This document is Volume 3a of the Low Rank Coal 

Baseline Reports, which are part of a four volume series consisting of the following:

• Volume 1: Bituminous Coal and Natural Gas to Electricity

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

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

• Volume 4: Bituminous Coal to Liquid Fuels with Carbon Capture

The cost and performance of the various fossil fuel-based technologies will most likely 

determine which combination of technologies will be utilized to meet the demands of the power 

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

• Capital and operating costs

• Environmental issues and performance

• Overall energy efficiency

• Fuel prices

• Cost of electricity (COE)

• Availability, reliability, and environmental performance

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

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

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

Coal Programs

As listed in Exhibit ES-1, 12 IGCC power plant configurations were analyzed based on the Shell 

Coal Gasification Process (SCGP), Transport Integrated Gasification (TRIGTM) gasifier, Siemens 

Fuel Gasifier (SFG), and Conoco Phillips (CoP) E-GasTM gasifier. The list includes eight cases 

firing Rosebud Powder River Basin (PRB) coal at the high elevation Montana site and four cases 

firing North Dakota lignite (NDL) at the mid elevation North Dakota site, with and without 

carbon dioxide (CO2) capture.

The methodology included performing steady-state simulations of the various technologies using 

the Aspen Plus® (Aspen) modeling program. The resulting mass and energy balance data from 

the Aspen model were used to size major pieces of equipment. These equipment sizes formed 

the basis for cost estimating. Performance and process limits were based upon published reports, 

information obtained from vendors and users of the technology, performance data from 

design/build utility projects, and/or best engineering judgment. Capital and operating costs were 

estimated based on simulation results and through a combination of vendor quotes, scaled 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

2

estimates from previous design projects, or a combination of the two. Baseline fuel costs for this 

analysis were determined using data from the Energy Information Administration’s (EIA) 2008 

Annual Energy Outlook (AEO). The 2007 delivered costs used are $0.84/gigajoule (GJ)

($0.89/million British thermal unit [MMBtu]) for rail delivered Powder River Basin (PRB) coal 

and $0.79/GJ ($0.83/MMBtu) for minemouth North Dakota lignite (NDL), both on a higher 

heating value (HHV) basis and in June 2007 United States (U.S.) dollars.

Exhibit ES-1 Case Descriptions

Case Coal

Type

Coal Drying 

Process

Gasifier/Boiler 

Technology

ASU 

Integration

H2S Separation/

Removal CO2 Separation CO2 Capture

S1A S WTA Shell SCGP Yes Sulfinol-M

S1B S WTA Shell SCGP No Selexol Selexol 2nd stage 90%

L1A L WTA Shell SCGP Yes Sulfinol-M

L1B L WTA Shell SCGP No Selexol Selexol 2nd stage 90%

S2A S Flash Pulverizer TRIGTM Yes Sulfinol-M

S2B S Flash Pulverizer TRIGTM No Selexol Selexol 2nd stage 83%

S3A S WTA Siemens SFG Yes Sulfinol-M

S3B S WTA Siemens SFG No Selexol Selexol 2nd stage 90%

L3A L WTA Siemens SFG Yes Sulfinol-M

L3B L WTA Siemens SFG No Selexol Selexol 2nd stage 90%

S4A S None CoP E-GasTM Yes MDEA

S4B S None CoP E-GasTM No Selexol Selexol 2nd stage 90%

Coal Type S= Subbituminous, L= Lignite

All plant configurations were evaluated based on installation at a greenfield site (Montana, 3400 

ft elevation, for PRB cases and North Dakota, 1900 ft elevation, for lignite cases). To compare 

the plants on an equivalent basis, it was assumed that these plants would be dispatched any time 

they are available. The study capacity factor (CF) was chosen to reflect the maximum 

availability demonstrated for the specific plant type (e.g., 80 percent for IGCC configurations). 

Since variations in fuel costs and other factors can influence dispatch order and CF, sensitivity of 

cost of electricity (COE) to CF was evaluated and presented later in this Executive Summary 

(Exhibit ES-9).

The gross and net output varies among the IGCC cases because of the gas turbine (GT) size 

constraint. The advanced F-class turbine used to model these cases comes in a standard size of 

232 megawatt (MW) when operated on synthesis gas (syngas) at International Standards 

Organization (ISO) conditions. Each case uses two combustion turbines (CTs) for a combined 

potential gross output of 464 MW. Because these cases were operated at elevations higher than 

sea level, the output was reduced from the turbine’s ISO condition potential. In the combined 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

3

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

steam turbine. However, the CO2 capture cases consume more extraction steam than the noncapture cases, thus reducing the steam-turbine output. In addition, the CO2 capture cases have a 

higher auxiliary load requirement than non-capture cases, which serves to further reduce net 

plant output.

Exhibit ES-2 shows the cost, performance, and environmental profile summary for all cases 

discussed below.

Energy Efficiency

The net plant efficiency (HHV basis) for all 12 cases is shown in Exhibit ES-3. The following 

primary conclusions can be drawn:

• The Shell case with no CO2 capture firing PRB coal at the Montana site has the 

highest plant efficiency of the technologies modeled in this study, with an efficiency 

of 42.0 percent. 

• The Shell case with CO2 capture firing PRB coal at the Montana site has the highest 

efficiency among all of the capture technologies modeled in this study, with an 

efficiency of 32.1 percent.

• The CO2 capture results in an efficiency penalty of 6 to 10 absolute percent, relative 

to the analogous non-capture case, while noting that the TRIGTM case only captures 

83 percent of the overall carbon. 

• The PRB coal cases at 3,400 ft of elevation have higher efficiency than the 

corresponding lignite coal cases at 1,900 ft of elevation. The negative efficiency 

impact of coal quality is greater than the negative efficiency impacts caused by the 

elevation differences and associated combustion turbine derate.

Water Use

Three water values are presented for each technology in Exhibit ES-4: raw water withdrawal, 

process discharge, and raw water consumption. Each value is normalized by net output. Raw 

water withdrawal is the difference between demand and internal recycle. Demand is the amount 

of water required to satisfy a particular process (cooling tower makeup, quench makeup, slag 

handling, etc.) and internal recycle is water available within the process. 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 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 consumption is the difference between withdrawal and process 

discharge, and it represents the overall impact of the process on the water source, which in this 

study is considered to be 50 percent from groundwater (wells) and 50 percent from a municipal 

source.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

4

Exhibit ES-2 Cost and Performance Summary and Environmental Profile for IGCC Cases

PERFORMANCE S1A L1A S1B L1B S2A S2B S3A L3A S3B L3B S4A S4B

CO2 Capture No No Yes Yes No Yes No No Yes Yes No Yes

Gross Power Output (kWe) 696,700 752,600 663,400 713,300 652,700 621,300 622,200 678,800 634,700 676,900 738,300 727,200

Auxiliary Power Requirement (kWe) 124,020 135,900 191,790 213,240 107,280 160,450 117,480 135,680 189,410 210,390 133,460 212,130

Net Power Output (kWe) 572,680 616,700 471,610 500,060 545,420 460,850 504,720 543,120 445,290 466,510 604,840 515,070

Coal Flowrate (lb/hr) 542,713 760,093 585,970 814,029 545,197 577,946 531,119 743,918 579,796 801,651 656,228 675,058

HHV Thermal Input (kWth) 1,362,134 1,474,011 1,470,704 1,578,608 1,368,368 1,450,564 1,333,034 1,442,644 1,455,207 1,554,603 1,647,041 1,694,303

Net Plant HHV Efficiency (%) 42.0% 41.8% 32.1% 31.7% 39.9% 31.8% 37.9% 37.6% 30.6% 30.0% 36.7% 30.4%

Net Plant HHV Heat Rate (Btu/kWh) 8,116 8,156 10,641 10,772 8,560 10,740 9,012 9,063 11,151 11,371 9,292 11,224

Raw Water Withdrawal (gpm/MWnet) 3.1 3.0 7.2 7.8 3.7 6.5 4.5 4.0 9.0 8.9 5.4 8.4

Process Water Discharge (gpm/MWnet) 0.8 0.8 1.4 1.6 0.8 1.0 1.1 1.1 1.6 1.7 1.1 1.5

Raw Water Consumption (gpm/MWnet) 2.3 2.2 5.9 6.2 2.9 5.5 3.4 2.9 7.4 7.2 4.3 6.9

CO2 Emissions (lb/MMBtu) 214 219 22 22 211 36 214 219 22 22 213 22

CO2 Emissions (lb/MWhgross) 1,426 1,461 165 170 1,507 287 1,563 1,585 172 175 1,620 174

CO2 Emissions (lb/MWhnet) 1,735 1,783 233 242 1,803 386 1,927 1,981 246 255 1,977 245

SO2 Emissions (lb/MMBtu) 0.0023 0.0023 0.0009 0.0010 0.0019 0.0009 0.0039 0.0021 0.0009 0.0010 0.0016 0.0009

SO2 Emissions (lb/MWhgross) 0.015 0.015 0.007 0.007 0.013 0.007 0.029 0.016 0.007 0.008 0.012 0.007

NOx Emissions (lb/MMBtu) 0.062 0.063 0.050 0.049 0.059 0.049 0.061 0.061 0.051 0.050 0.052 0.044

NOx Emissions (lb/MWhgross) 0.412 0.418 0.381 0.371 0.422 0.390 0.444 0.445 0.397 0.391 0.398 0.348

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

PM Emissions (lb/MWhgross) 0.047 0.047 0.054 0.054 0.051 0.057 0.052 0.051 0.056 0.056 0.054 0.056

Hg Emissions (lb/TBtu) 0.351 0.560 0.351 0.560 0.351 0.351 0.351 0.560 0.351 0.560 0.351 0.351

Hg Emissions (lb/MWhgross) 2.34E-06 3.74E-06 2.66E-06 4.23E-06 2.51E-06 2.80E-06 2.57E-06 4.06E-06 2.75E-06 4.39E-06 2.67E-06 2.79E-06

COST

Total Plant Cost (2007$/kW) 2,506 2,539 3,480 3,584 2,236 3,019 2,610 2,656 3,533 3,626 2,265 3,144

Total Overnight Cost (2007$/kW) 3,056 3,094 4,253 4,378 2,728 3,691 3,185 3,239 4,318 4,430 2,771 3,851

 Bare Erected Cost 1,914 1,941 2,610 2,692 1,692 2,228 2,006 2,044 2,654 2,730 1,737 2,357

 Home Office Expenses 177 179 242 250 157 207 186 189 247 254 162 221

 Project Contingency 343 349 486 502 305 421 359 367 493 508 306 431

 Process Contingency 72 69 142 141 83 164 60 56 139 135 60 135

 Owner's Costs 550 556 773 794 492 672 575 583 785 804 505 706

Total Overnight Cost (2007$x1,000) 1,750,189 1,908,200 2,005,883 2,189,363 1,488,063 1,701,132 1,607,607 1,759,016 1,922,741 2,066,464 1,675,790 1,983,369

Total As Spent Capital (2007$/kW) 3,484 3,527 4,849 4,991 3,110 4,208 3,631 3,692 4,922 5,050 3,159 4,390

COE (mills/kWh, 2007$)1 83.2 83.5 119.7 121.9 74.5 105.2 86.8 87.3 121.7 123.7 78.7 112.3

 CO 2 TS&M Costs 0.0 0.0 6.0 5.7 0.0 5.9 0.0 0.0 6.3 6.2 0.0 5.8

 Fuel Costs 7.2 6.7 9.5 8.9 7.6 9.5 8.0 7.5 9.9 9.4 8.3 10.0

 Variable Costs 8.0 8.2 10.6 11.1 6.8 8.8 8.2 8.4 10.6 11.1 8.3 10.9

 Fixed Costs 13.7 13.6 18.3 18.6 11.8 15.5 14.1 14.0 18.4 18.6 13.0 17.4

 Capital Costs 54.2 54.9 75.4 77.6 48.4 65.4 56.5 57.4 76.6 78.5 49.1 68.3

LCOE (mills/kWh, 2007$)1 105.4 105.8 151.8 154.5 94.5 133.3 110.0 110.7 154.3 156.9 99.8 142.4

Shell IGCC Cases TRIG IGCC Cases Siemens IGCC Cases CoP IGCC Cases

1 COE and Levelized COE are defined in Section 2.6
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

5

Exhibit ES-3 Net Plant Efficiency

42.0%

32.1%

39.9%

31.8%

37.9%

30.6%

36.7%

30.4%

41.8%

31.7%

37.6%

30.0%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

S1A No 

Cap

S1B W/Cap S2A No 

Cap

S2B W/Cap S3A No 

Cap

S3B W/Cap S4A No 

Cap

S4B W/Cap L1A No 

Cap

L1B W/Cap L3A No 

Cap

L3B W/Cap

Shell TRIG Siemens CoP Shell Siemens

Efficiency, % (HHV Basis)

North Dakota Lignite Coal

Elevation: 1,900 ft

Montana Powder River Basin Coal

Elevation: 3,400 ft
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

6

Exhibit ES-4 Raw Water Withdrawal and Consumption

3.1

7.2

3.7

6.5

4.5

9.0

5.4

8.4

3.0

7.8

4.0

8.9

2.3

5.9

2.9

5.5

3.4

7.4

4.3

6.9

2.2

6.2

2.9

7.2

0

2

4

6

8

10

12

14

S1A No 

Cap

S1B W/Cap S2A No 

Cap

S2B W/Cap S3A No 

Cap

S3B W/Cap S4A No 

Cap

S4B W/Cap L1A No Cap L1B W/Cap L3A No Cap L3B W/Cap

Shell TRIG Siemens CoP Shell Siemens

Water, gpm/MWnet

Raw Water Withdrawal

Process Water Discharge

Raw Water Consumption

North Dakota Lignite Coal

Elevation: 1,900 ft

Montana Powder River Basin Coal

Elevation: 3,400 ft
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

7

The largest consumer of raw water in all cases is cooling tower makeup. Since plants located in 

the Western U.S. need to consider limited water supplies, a parallel wet/dry condenser was 

chosen for all plant configurations. In a parallel cooling system half of the turbine exhaust steam 

is condensed in an air-cooled condenser and half in a water-cooled condenser. The cooling water 

is provided by a mechanical draft, evaporative cooling tower. The primary conclusions that can 

be drawn are:

• The raw water usage is lower in the lignite coal cases because of its higher moisture 

content, and a significant amount of the coal moisture is recovered in the drying process 

for dry feed cases and used as internal recycle. Thus, while the water demand is nearly 

equal in the Montana PRB and North Dakota lignite cases, the water usage is 

significantly lower when using lignite coal.

• The use of the parallel wet/dry cooling system reduces water demand by 36-47 percent in 

the non-capture cases and by 24-30 percent in the CO2 capture cases relative to using a 

purely wet cooling system. The water savings is less in the CO2 capture cases because a 

significant amount of extraction steam is used in the shift reaction and therefore not 

condensed in the surface condenser.

• The water demand is significantly greater in the CO2 capture cases because one-half of 

the condenser load represents a smaller percentage of the total water requirement, again 

due primarily to the high shift steam requirement.

Cost Results

The Total Plant Cost (TPC) for each technology was determined through a combination of 

vendor quotes, scaled estimates from previous design/build projects, or a combination of the two. 

TPC includes all equipment (complete with initial chemical and catalyst loadings), materials, 

labor (direct and indirect), engineering and construction management, and contingencies (process 

and project). Owner’s costs, including preproduction costs, inventory capital, initial cost for 

catalyst and chemicals, land, financing costs and other owner’s costs were added to TPC to 

generate total overnight cost (TOC). Property taxes and insurance were included in the fixed 

operating costs as an additional owner’s cost. Escalation and interest on debt during the capital 

expenditure period were estimated and added to the TOC to provide the Total As-Spent Cost 

(TASC).

The cost estimates carry an accuracy of -15/+30%, consistent with a “feasibility study” level of 

design engineering applied to the various cases in this study. The value of the study lies not in 

the absolute accuracy of the individual case results, but in the fact that all cases were evaluated 

under the same set of technical and economic assumptions. This consistency of approach allows 

meaningful relative comparisons among the cases evaluated. 

Project contingencies were added to the Engineering/Procurement/Construction Management 

(EPCM) capital accounts to cover project uncertainty and the cost of any additional equipment 

that would result from a detailed design. The contingencies represent costs that are expected to 

occur. Each bare erected cost (BEC) account was evaluated against the level of estimate detail 

and field experience to determine project contingency. Process contingency was added to cost 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

8

account items that were deemed to be first-of-a-kind (FOAK) or posed significant risk due to 

lack of operating experience. The cost accounts that received a process contingency include:

• Gasifiers and Syngas Coolers: 15–20 percent on all IGCC cases, with next-generation 

commercial offering and integration with the power island.

• Two-Stage Selexol: 20 percent on all IGCC capture cases, with lack of operating 

experience at commercial scale in IGCC service.

• Mercury Removal: 5 percent on all IGCC cases, with minimal commercial scale 

experience in IGCC applications.

• Combustion Turbine Generator (CTG): 5 percent on all IGCC non-capture cases, with

syngas firing and ASU integration; 10 percent on all IGCC capture cases, with high 

hydrogen firing. 

• Instrumentation and Controls: 5 percent on all IGCC accounts, with integration issues.

The normalized components of TOC and overall TASC are shown for each plant configuration in

Exhibit ES-5. The TOC, which is used for COE calculations, is the TPC plus owner’s costs. 

The following conclusions can be drawn:

• The TOC is higher for the North Dakota elevation lignite coal cases as compared to the 

Montana elevation PRB coal cases by approximately 9 percent.

• The TOC increase to add CO2 capture is approximately 38 percent.

• The TASC is approximately 15% greater than the TOC based on the study assumptions.

Cost of Electricity

The cost metric used in this study is the COE, which 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 Power Systems Financial Model (PSFM) [2] was used to determine a “base-year” 

(2007) COE that, when escalated at an assumed nominal annual general inflation rate of 3

percent1, provided the stipulated internal rate of return on equity over the entire economic 

analysis period (capital expenditure period plus thirty years of operation). The first year capital 

charge factor (CCF) shown in Exhibit ES-6, which was derived using the PSFM, can also be 

used to calculate COE using a simplified equation as detailed in Section 2.6.4.

 

1 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.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

9

Exhibit ES-5 Plant Capital Costs

3,056

4,253

2,728

3,691

3,185

4,318

2,771

3,851

3,094

4,378

3,239

4,430

3,484

4,849

3,110

4,208

3,631

4,922

3,159

4,390

3,527

4,991

3,692

5,050

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC

S1A No Cap S1B W/Cap S2A No Cap S2B W/Cap S3A No Cap S3B W/Cap S4A No Cap S4B W/Cap L1A No Cap L1B W/Cap L3A No Cap L3B W/Cap

TOC or TASC ($/kW)

TASC

Owner's Cost

Process Contingency

Project Contingency

Home Office Expense

Bare Erected Cost

North Dakota Lignite Coal

Elevation: 1,900 ft

Montana Powder River Basin Coal

Elevation: 3,400 ft

Note: TOC expressed in 2007 dollars. TASC expressed in mixed-year 2007 to 2011 year dollars.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

10

The project financial structure varies depending on the type of project (high or low risk). All 

cases were assumed to be undertaken at investor owned utilities (IOUs). High risk projects are 

those in which commercial scale operating experience is limited. All IGCC cases (with and 

without CO2 capture) were considered to be high risk. All cases were assumed to have a 5 year 

capital expenditure period. The current-dollar, 30-year levelized cost of electricity (LCOE) was 

also calculated and is shown in Exhibit ES-2, but the primary metric used in the balance of this 

study is COE. A more detailed discussion of the two metrics is provided in Section 2.6.

Exhibit ES-6 Economic Parameters Used to Calculate COE

High Risk

(5 year capital 

expenditure 

period)

Low Risk

(5 year capital 

expenditure 

period)

First Year Capital 

Charge Factor 0.1243 0.1165

Commodity prices fluctuate over time based on overall economic activity and general supply and 

demand curves. While the cost basis for this study is June 2007, many price indices had 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. Hence the June 

2007 dollar cost base used in this study is expected to be representative of January 2010 costs.

The COE results are shown in Exhibit ES-7 with the capital cost, fixed operating cost, variable 

operating cost, and fuel cost shown separately. In the capture cases, the CO2 transport, storage, 

and monitoring (TS&M) costs are also shown as a separate bar segment. The following 

conclusions can be drawn:

• The COEs for the Shell and Siemens systems are higher than TRIGTM and CoP for both 

capture and non-capture cases. Note that TRIGTM and CoP were only studied for PRB 

coal and TRIGTM with capture only achieved 83 percent carbon capture.

• TRIGTM is the only technology evaluated that has not been demonstrated at commercial 

scale. For this reason, TRIGTM COEs are subject to a greater level of uncertainty than the 

other technologies in the group.

• The COE is dominated by capital charges in all cases. The capital cost component of 

COE ranges from 61 to 66 percent for IGCC cases.

• The fuel cost component is relatively minor in all cases, ranging from 7 to 10 percent of 

the COE for IGCC cases.

• The CO2 TS&M component adds approximately 5 percent to the COE. 

• The COE increases by 40 to 46% percent for IGCC plants when CO2 capture is added.

• The COE is generally lower for Montana PRB cases compared to the North Dakota 

lignite cases.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

11

Exhibit ES-7 COE by Cost Component

54.2

75.4

48.4

65.4

56.5

76.6

49.1

68.3

54.9

77.6

57.4

78.5

13.7

18.3

11.8

15.5

14.1

18.4

13.0

17.4

13.6

18.6

14.0

18.6

8.0

10.6

6.8

8.8

8.2

10.6

8.3

10.9

8.2

11.1

8.4

11.1

7.2

9.5

7.6

9.5

8.0

9.9

8.3

10.0

6.7

8.9

7.5

9.4

6.0

5.9

6.3

5.8

5.7 6.2

83.2

119.7

74.5

105.2

86.8

121.7

78.7

112.3

83.5

121.9

87.3

123.7

0

20

40

60

80

100

120

140

S1A No 

Cap

S1B W/Cap S2A No 

Cap

S2B W/Cap S3A No 

Cap

S3B W/Cap S4A No 

Cap

S4B W/Cap L1A No 

Cap

L1B W/Cap L3A No 

Cap

L3B W/Cap

Shell TRIG Siemens CoP Shell Siemens

COE (2007 mills/kWh)

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs

North Dakota Lignite Coal

Elevation: 1,900 ft

Montana Powder River Basin Coal

Elevation: 3,400 ft
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

12

Exhibit ES-8 shows the COE sensitivity to fuel costs. The solid lines are the COE of noncapture cases. The dotted lines are the capture cases. As expected, all cases show a linear 

decrease in COE with the decrease in coal prices. As the price for PRB coal decreases from 

$0.89 to $0/MMBtu, the average COE decreases from 81 to 73 tenths of a cent per kilowatt hour 

(mills/kWh) for the non-capture PRB cases and from 115 to 105 mills/kWh for the PRB capture 

cases. As the price for ND lignite coal decreases from $0.83 to $0/MMBtu, the average COE 

decreases from 85 to 78 tenths of a cent per kilowatt hour (mills/kWh) for the non-capture lignite

cases and from 123 to 113 mills/kWh for the lignite capture cases.

The sensitivity of COE to CF is shown in Exhibit ES-9. CF is equal to availability since it was 

assumed that the plants are able to operate at 100 percent capacity whenever power production is 

needed. The solid lines are the COE of non-capture cases. The dotted lines are the capture 

cases. All cases show a decrease in COE with the increase in CF. As the CF increases from 80 

to 100 percent, the average COE decreases from 81 to 66 mills/kWh for the non-capture PRB 

cases and from 115 to 94 mills/kWh for the CO2 capture PRB cases. The average COE 

decreases from 85 to 70 mills/kWh for the non-capture lignite cases and from 123 to 100

mills/kWh for the lignite capture cases.

Cost of CO2 Avoided

The CO2 emissions per megawatt-hour (MWh) are dependent on the chosen technology and 

configuration, and they are higher for the North Dakota lignite cases compared to the Montana 

PRB cases. The first year cost of CO2 avoided is calculated using the equation:

CO Emissions CO Emissions tons MWh

COE COE MWh

Avoided Cost

reference with removal

with removal reference

{ } /

{ } $ /

2 − 2

− =

The COE with CO2 removal includes the costs of capture and compression, as well as TS&M 

costs. The resulting avoided costs are shown in Exhibit ES-10 for each of the CO2 capture 

technologies modeled. The cost of CO2 avoided compared to the analogous non-capture design 

averages $45/ton, with a range of $40/ton–$53/ton. The cost of CO2 avoided, compared to the 

baseline Supercritical (SC) PC non-capture design, was determined using results shown in

Exhibit 2-22 and averages $70/ton, with a range of $63/ton-$77/ton. The analogous CO2 avoided 

costs are lower for the Montana PRB coal than the North Dakota lignite cases, mainly because of 

the capital cost increase due to the low energy density lignite fuel. The cost of CO2 avoided, 

compared to the baseline SC PC plant, follows the same general trend as the COE for each of the 

cases after accounting for the overall carbon removal efficiency. The comparison of the 

analogous Shell designs is affected by the change from a water quench in the CO2 capture case to 

high temperature syngas heat recovery in the non-capture case. This increases efficiency when 

high water concentrations are not required for the WGS reaction, as is the case for non-capture 

cases, at the expense of including high temperature heat exchangers, thus increasing the cost of 

avoiding CO2 emissions for the semi-analogous Shell cases.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

13

Exhibit ES-8 COE Sensitivity to Fuel Costs 

0

20

40

60

80

100

120

140

160

0.0 0.5 1.0 1.5 2.0 2.5

COE (2007 mills/kWh)

Coal Price ($/MMBtu)

Siemens Lignite

w/Capture

Shell Lignite

w/Capture

Siemens PRB

w/Capture

Shell PRB

w/Capture

CoP PRB w/Capture

TRIG PRB w/Capture

Siemens Lignite

Siemens PRB

Shell Lignite

Shell PRB

CoP PRB

TRIG PRB

Capacity Factor = 85% for all cases

Study Coal Costs:

Lignite = $0.83/MMBtu

PRB = $0.89/MMBtu
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

14

Exhibit ES-9 COE Sensitivity to Capacity Factor

0

50

100

150

200

250

300

350

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

COE (2007 mills/kWh)

Capacity Factor (%)

Siemens Lignite

w/Capture

Shell Lignite

w/Capture

Siemens PRB

w/Capture

Shell PRB

w/Capture

CoP PRB w/Capture

TRIG PRB w/Capture

Siemens Lignite

Siemens PRB

Shell Lignite

Shell PRB

CoP PRB

TRIG PRB

Study Capacity Factor is 

80% for all cases
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

15

Exhibit ES-10 CO2 Avoided Costs

48.6

43.28

41.6 40.2

52.7

42.2

74.6

62.90

77.6

66.2 67.5

70.6

0

10

20

30

40

50

60

70

80

90

100

Shell PRB

w/Capture

TRIG PRB w/Capture Siemens PRB

w/Capture

CoP PRB w/Capture Shell Lignite

w/Capture

Siemens Lignite

w/Capture

PRB Lignite

First Year CO2 Avoided Cost (2007$/ton)

Avoided Cost (Analogous Technology w/o Capture Reference)

Avoided Cost (SC PC w/o Capture Reference)

North Dakota Lignite Coal

Elevation: 1,900 ft

Montana Powder River Basin Coal

Elevation: 3,400 ft
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

16

Environmental Performance

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 ES-11. 

Emission rates of sulfur dioxide (SO2), nitrogen oxides (NOx), and particulate matter (PM) are 

shown graphically in Exhibit ES-12, and emission rates of mercury (Hg) are shown separately in 

Exhibit ES-13 because of the orders of magnitude difference in emission rate values.

Exhibit ES-11 Study Environmental Targets

Pollutant Environmental Target Control Technology

NOx 15 ppmv (dry) @ 15% O2

Low NOx burners and 

syngas nitrogen dilution

SO2 0.0128 lb/MMBtu

Selexol, MDEA or 

Sulfinol (depending on 

gasifier technology)

Particulate 

Matter 

(Filterable)

0.0071 lb/MMBtu

Quench, water scrubber, 

and/or cyclones and 

candle filters (depending 

on gasifier technology)

Mercury > 90% capture Carbon bed

The following observations can be made:

• Emissions of SO2 are uniformly extremely low. The same environmental target was used 

as in the bituminous coal cases of Volume 1 of this study, and because the coal sulfur 

content is significantly lower in the design coals of this study, the resulting SO2

emissions are also significantly lower.

• Particulate emissions are the same for each case because it was a study assumption that 

the combination of cyclones and candle filters would exactly meet the environmental 

target of 0.0071 lb/MMBtu.

• NOx emissions were assumed to be 15 ppmv at 15 percent oxygen in all cases. The 

resulting emissions on a lb/MMBtu basis vary slightly because of the variable coal feed 

rates and flue gas volumes generated among cases.

• Mercury emissions are constant for each coal type and significantly below the NSPS limit 

of 20 x 10-6 lb/MWh for IGCC systems. The emissions shown in Exhibit ES-13 are 

equivalent to 3.7 – 4.4 x 10-6 lb/MWh for the four lignite cases (which have the higher 

Hg concentration of the two coal types), or a minimum of 78 percent less than NSPS.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

17

Exhibit ES-12 SO2, NOx and Particulate Emission Rates

0.002

0.001 0.002 0.001

0.004

0.001 0.002 0.001

0.002

0.001 0.002 0.001

0.062

0.050

0.059

0.049

0.061

0.051

0.052

0.044

0.063

0.049

0.061

0.050

0.007

0.00

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

S1A No 

Cap

S1B W/Cap S2A No 

Cap

S2B W/Cap S3A No 

Cap

S3B W/Cap S4A No 

Cap

S4B W/Cap L1A No 

Cap

L1B W/Cap L3A No 

Cap

L3B W/Cap

Shell TRIG Siemens CoP Shell Siemens

Emissions, lb/MMBtu

SO2

NOx

Particulate

North Dakota Lignite Coal

Elevation: 1,900 ft

Montana Powder River Basin Coal

Elevation: 3,400 ft
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

18

Exhibit ES-13 Mercury Emission Rates

0.351 0.351 0.351 0.351 0.351 0.351 0.351 0.351

0.560 0.560 0.560 0.560

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

S1A No 

Cap

S1B W/Cap S2A No 

Cap

S2B W/Cap S3A No 

Cap

S3B W/Cap S4A No 

Cap

S4B W/Cap L1A No 

Cap

L1B W/Cap L3A No 

Cap

L3B W/Cap

Shell TRIG Siemens CoP Shell Siemens

Mercury Emissions, lb/TBtu

North Dakota Lignite Coal

Elevation: 1,900 ft

Montana Powder River Basin Coal

Elevation: 3,400 ft
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

19

1. INTRODUCTION

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

performance of fossil energy power systems—specifically, the Shell Coal Gasification Process 

(SCGP), TRIGTM, Siemens Fuel Gasifier (SFG), and CoP E-GasTM gasifiers using low rank 

Rosebud PRB and ND Lignite coals—in a consistent technical and economic manner that 

accurately reflects current market conditions for plants starting operation in the near term. This 

document is Volume 3a of the Low Rank Coal Baseline Reports, which are part of a four volume 

series consisting of the following:

• Volume 1: Bituminous Coal and Natural Gas to Electricity

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

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

• Volume 4: Bituminous Coal to Liquid Fuels with Carbon Capture

Twelve IGCC cases are modeled and analyzed. Eight cases use PRB subbituminous coal at the 

high elevation Montana site, and four cases use North Dakota Lignite coal at the mid elevation 

North Dakota site, with and without CO2 capture. The different IGCC configurations considered 

in this study are displayed in Exhibit 1-1.

While input was sought from various technology vendors, the final assessment of performance 

and cost was determined independently, and may not represent the views of the technology 

vendors. More detailed engineering for specific project applications must be considered with the 

appropriate technology vendors to determine the preferred designs, based on project details and 

current state of the art. This study’s main use should be to identify important parameters that 

could be optimized for different project goals or specific operating conditions and to help 

quantify the tradeoffs of different power generation configurations.

Generating Unit Configurations

The gross and net output varies among the IGCC cases because of the GT size constraint. The 

advanced F-class turbine used to model these cases comes in a standard size of 232 MW when 

operated on syngas at ISO conditions. Each case uses two CTs for a combined potential gross 

output of 464 MW. Because these cases are operated at elevations greater than sea level, the 

output is reduced from the turbine’s ISO condition potential. In the combined cycle, a HRSG 

extracts heat from the CT exhaust to power a steam turbine. However, the CO2 capture cases 

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

output. In addition, the capture cases have a higher auxiliary load requirement than non-capture 

cases, which serves to further reduce net plant output. Thus, the overall combined cycle gross 

output ranges from 621 to 753 MW, which results in a range of net output from 445 to 617 MW. 

The coal feed rate required to achieve the gross power output is also different between the cases, 

ranging from 240,912 to 369,244 kilogram per hour (kg/hr) (531,119 to 814,029 pounds per hour 

[lb/hr]). The large range of coal feed rates is due to the different gasifier performance, coal 

types, and the addition of CO2 capture.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

20

Exhibit 1-1 IGCC Case Descriptions

Case Unit 

Cycle

Steam Cycle, 

psig/°F/°F

Coal

Type

Coal Drying 

Process

Combustion 

Turbine

Gasifier/Boiler 

Technology Oxidant ASU Integration

H2S Separation/

Removal

Sulfur Removal/

Recovery

CO2

Separation

CO2 

Capture

S1A IGCC 1800/1050/1050 S WTA 2 x Advanced 

F-class Shell SCGP 95 mol% O2 Yes Sulfinol-M Claus Plant

S1B IGCC 1800/1000/1000 S WTA 2 x Advanced 

F-class Shell SCGP 95 mol% O2 No Selexol Claus Plant Selexol 2nd

stage 90%

L1A IGCC 1800/1050/1050 L WTA 2 x Advanced 

F-class Shell SCGP 95 mol% O2 Yes Sulfinol-M Claus Plant

L1B IGCC 1800/1000/1000 L WTA 2 x Advanced 

F-class Shell SCGP 95 mol% O2 No Selexol Claus Plant Selexol 2nd

stage 90%

S2A IGCC 1800/1050/1050 S Flash 

Pulverizer

2 x Advanced 

F-class TRIGTM 95 mol% O2 Yes Sulfinol-M Claus Plant

S2B IGCC 1800/1000/1000 S Flash 

Pulverizer

2 x Advanced 

F-class TRIGTM 95 mol% O2 No Selexol Claus Plant Selexol 2nd

stage 83%1

S3A IGCC 1800/1050/1050 S WTA 2 x Advanced 

F-class Siemens SFG 95 mol% O2 Yes Sulfinol-M Claus Plant

S3B IGCC 1800/1000/1000 S WTA 2 x Advanced 

F-class Siemens SFG 95 mol% O2 No Selexol Claus Plant Selexol 2nd

stage 90%

L3A IGCC 1800/1050/1050 L WTA 2 x Advanced 

F-class Siemens SFG 95 mol% O2 Yes Sulfinol-M Claus Plant

L3B IGCC 1800/1000/1000 L WTA 2 x Advanced 

F-class Siemens SFG 95 mol% O2 No Selexol Claus Plant Selexol 2nd

stage 90%

S4A IGCC 1800/1050/1050 S None 2 x Advanced 

F-class CoP E-GasTM 95 mol% O2 Yes MDEA Claus Plant

S4B IGCC 1800/1000/1000 S None 2 x Advanced 

F-class CoP E-GasTM 95 mol% O2 No Selexol Claus Plant Selexol 2nd

stage 90%

1 Limited due to syngas methane content
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

21

Report Structure

The balance of this report is organized as follows:

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

• Chapter 3 provides the results of the different IGCC configurations.

• Chapter 4 contains the reference list.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

22

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Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

23

2. GENERAL EVALUATION BASIS

For each of the plant configurations in this study, an Aspen model was developed and used to 

generate material and energy balances, which, in turn, were used to provide a design basis for 

items in the major equipment list. The equipment list and material balances were used as the 

basis for generating the capital and operating cost estimates. Performance and process limits 

were based upon published reports, information obtained from vendors and users of the 

technology, performance data from design projects, and/or best engineering judgment. Capital 

and operating costs were estimated by WorleyParsons based on simulation results and through a 

combination of vendor quotes, scaled estimates from previous design/build projects, or a 

combination of the two. Ultimately, a FY COE was calculated for each of the cases and is 

reported as the revenue requirement figure-of-merit.

The balance of this chapter documents the design basis, environmental targets and cost 

assumptions used in the study.

2.1 SITE CHARACTERISTICS

The plants are located at two different generic plant sites. Plants using PRB coal are assumed to 

be located in Montana. Plants using lignite coal are assumed to be located at a minemouth site in 

North Dakota. The ambient conditions for the two sites are shown in Exhibit 2-1 and 

Exhibit 2-2.

Exhibit 2-1 Montana Site Ambient Conditions for PRB Coal Cases

Elevation, m (ft) 1,036 (3,400)

Barometric Pressure, MPa (psia) 0.09 (13.0)

Design Ambient Temperature, Dry Bulb, °C (°F) 5.6 (42)

Design Ambient Temperature, Wet Bulb, °C (°F) 2.8 (37)

Design Ambient Relative Humidity, % 62

Exhibit 2-2 North Dakota Site Ambient Conditions for Lignite Coal Cases

Elevation, m (ft) 579 (1,900)

Barometric Pressure, MPa (psia) 0.10 (13.8)

Design Ambient Temperature, Dry Bulb, °C (°F) 4.4 (40)

Design Ambient Temperature, Wet Bulb, °C (°F) 2.2 (36)

Design Ambient Relative Humidity, % 68

The site characteristics are assumed to be the same for both plant locations as shown in 

Exhibit 2-3.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

24

Exhibit 2-3 Site Characteristics

Location Greenfield 

Topography Level

Size, acres 300

Transportation Rail

Ash/Slag Disposal Off Site

Water Municipal (50%) / Groundwater (50%)

Access Landlocked, having access by rail and highway

CO2 Storage

Compressed to 15.3 MPa (2,215 psia), transported 80 

kilometers (50 miles) and sequestered in a saline formation 

at a depth of 1,239 meters (4,055 feet)

The land area for all cases assumes 30 acres are required for the plant proper, and the balance 

provides a buffer of approximately 0.25 miles to the fence line. The extra land could also 

provide for a rail loop if required.

In all cases it was assumed that the steam turbine is enclosed in a turbine building, but the 

gasifier is not enclosed.

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

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

• Flood plain considerations

• Existing soil/site conditions

• Water discharges and reuse

• Rainfall/snowfall criteria

• Seismic design

• Buildings/enclosures

• Fire protection

• Local code height requirements

• Noise regulations – Impact on site and surrounding area
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

25

2.2 COAL CHARACTERISTICS

There are two design coals: a subbituminous PRB coal from Montana and lignite coal from 

North Dakota. The coal properties are from National Energy Technology Laboratory’s (NETL)

Coal Quality Guidelines and are shown in Exhibit 2-4 and Exhibit 2-5 [1].

The Power Systems Financial Model (PSFM) was used to derive the first year capital charge 

factor for this study [2]. The PSFM requires that all cost inputs have a consistent cost year basis. 

Because the capital and operating cost estimates are in June 2007 dollars, the fuel costs must also 

be in June 2007 dollars.

The cost of coal used in this study is $0.84/GJ ($0.89/MMBtu) for PRB coal and $0.78/GJ 

($0.83/MMBtu) for NDL coal (2007 cost of coal in June 2007 dollars). All coal costs are based 

on HHV. These costs were determined using the following information from the EIA 2008 

AEO:

• The 2007 minemouth cost of PRB coal in 2006 dollars, $13.02/metric ton (tonne)

($11.81/ton), was obtained from Supplemental Table 112 of the EIA’s 2008 AEO for 

western Montana medium-sulfur subbituminous coal. The 2007 minemouth cost of NDL 

coal in 2006 dollars, $11.67/tonne ($10.59/ton), was obtained from the same source.

• The 2007 cost of PRB coal was escalated to June 2007 dollars using the gross domestic 

product (GDP) chain-type price index from AEO 2008, resulting in a price of 

$13.42/tonne ($12.17/ton) [3]. Similarly, the 2007 cost of NDL coal in June 2007 dollars 

is $12.04/tonne ($10.92/ton) or $0.79/GJ ($0.83/MMBtu). 

• Transportation costs for PRB coal were estimated to be 25 percent of the minemouth cost 

based on the average transportation rate for medium subbituminous coal from the western 

Montana region delivered to the mountain region [4]. The final delivered cost of PRB 

coal used in the calculations is $16.78/tonne ($15.22/ton) or $0.85/GJ ($0.89/MMBtu). 

• Note: The PRB coal cost conversion of $15.22/ton to dollars per million Btu results in 

$0.8884/MMBtu, which was used in calculations, but only two decimal places are shown 

in the report. Similarly, the NDL fuel cost converts to $0.8251/MMBtu, which was used

in calculations, but only two decimal places are shown.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

26

Exhibit 2-4 Montana Rosebud PRB, Area D, Western Energy Co. Mine, 

Subbituminous Design Coal Analysis

Proximate Analysis Dry Basis, % As Received, %

Moisture 0.0 25.77

Ash 11.04 8.19

Volatile Matter 40.87 30.34

Fixed Carbon 48.09 35.70

Total 100.0 100.0

Ultimate Analysis Dry Basis, % As Received, %

Carbon 67.45 50.07

Hydrogen 4.56 3.38

Nitrogen 0.96 0.71

Sulfur 0.98 0.73

Chlorine 0.01 0.01

Ash 11.03 8.19

Moisture 0.00 25.77

Oxygen1 15.01 11.14

Total 100.0 100.0

Heating Value Dry Basis As Received

HHV, kJ/kg 26,787 19,920

HHV, Btu/lb 11,516 8,564

LHV, kJ/kg 25,810 19,195

LHV, Btu/lb 11,096 8,252

Hardgrove Grindability Index 57

Ash Mineral Analysis %

Silica SiO2 38.09

Aluminum Oxide Al2O3 16.73

Iron Oxide Fe2O3 6.46

Titanium Dioxide TiO2 0.72

Calcium Oxide CaO 16.56

Magnesium Oxide MgO 4.25

Sodium Oxide Na2O 0.54

Potassium Oxide K2O 0.38

Sulfur Trioxide SO3 15.08

Phosphorous Pentoxide P2O5 0.35

Barium Oxide Ba2O 0.00

Strontium Oxide SrO 0.00

Unknown --- 0.84

Total 100.0

Trace Components ppmd

Mercury2 Hg 0.081 1By difference 2 Mercury value is the mean plus one standard deviation using EPA’s ICR data
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

27

Exhibit 2-5 North Dakota Beulah-Zap Lignite, Freedom, ND Mine, 

Lignite Design Coal Analysis

Proximate Analysis Dry Basis, % As Received, %

Moisture 0.0 36.08

Ash 15.43 9.86

Volatile Matter 41.49 26.52

Fixed Carbon 43.09 27.54

Total 100.0 100.0

Ultimate Analysis Dry Basis, % As Received, %

Carbon 61.88 39.55

Hydrogen 4.29 2.74

Nitrogen 0.98 0.63

Sulfur 0.98 0.63

Chlorine 0.00 0.00

Ash 15.43 9.86

Moisture 0.00 36.08

Oxygen1 16.44 10.51

Total 100.0 100.0

Heating Value Dry Basis As Received

HHV, kJ/kg 24,254 15,391

HHV, Btu/lb 10,427 6,617

LHV, kJ/kg 23,335 14,804

LHV, Btu/lb 10,032 6,364

Hardgrove Grindability Index Not applicable

Ash Mineral Analysis %

Silica SiO2 35.06

Aluminum Oxide Al2O3 12.29

Iron Oxide Fe2O3 5.12

Titanium Dioxide TiO2 0.58

Calcium Oxide CaO 14.39

Magnesium Oxide MgO 6.61

Sodium Oxide Na2O 5.18

Potassium Oxide K2O 0.64

Sulfur Trioxide SO3 16.27

Barium Oxide Ba2O 0.56

Strontium Oxide SrO 0.27

Manganese Dioxide MnO2 0.02

Unknown --- 3.00

Total 100.0

Trace Components ppmd

Mercury2 Hg 0.116 1 By Difference

2 Mercury value is the mean plus one standard deviation using EPA’s ICR data
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

28

2.3 ENVIRONMENTAL TARGETS

The environmental targets for the study were considered on a technology- and fuel-specific basis. 

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 [5] and shown 

in Exhibit 2-6, which represents the minimum level of control that would be required for a new 

fossil energy plant.

The 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. 

The rule also applies to combined cycle, including IGCC plants, and combined heat and power 

CTs that burn 75 percent or more synthetic-coal gas. 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 pounds per megawatt hour (lb/MWh) are based on gross power output.

Exhibit 2-6 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). Environmental area designation 

varies by county and can be established only for a specific site location. Based on the 

Environmental Protection Agency (EPA) Green Book Non-attainment Area Map relatively few 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

29

areas in the Western U.S. are classified as “non-attainment” so the plant site for this study was 

assumed to be in an attainment area [6].

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.

Mercury

The Clean Air Mercury Rule (CAMR), issued on March 15, 2005, established NSPS limits for 

mercury (Hg) emissions from new power plants. These rules were vacated by court action on 

February 8, 2008 and the final resolution of these rules is unknown at this time. Even though the 

rules are vacated, the CAMR emission limits are included for reference only. The NSPS limits

for IGCC plants, based on gross output, are shown in Exhibit 2-7. The applicable limit in this 

study is 20 x 10-6 lb/MWh.

Exhibit 2-7 NSPS Mercury Emission Limits

Coal Type / Technology Hg Emission Limit

Bituminous 20 x 10-6 lb/MWh

Subbituminous (wet units) 66 x 10-6 lb/MWh

Subbituminous (dry units) 97 x 10-6 lb/MWh

Lignite 175 x 10-6 lb/MWh

Coal refuse 16 x 10-6 lb/MWh

IGCC 20 x 10-6 lb/MWh

The coal Hg concentration used for this study did not come from NETL’s Coal Quality 

Guidelines, but rather was determined from the EPA’s ICR database. The ICR database has 137 

records of Montana Rosebud subbituminous coal with an average Hg concentration of 0.056 

parts per million (ppm) (dry) and a standard deviation of 0.025 ppm. There are 266 records for 

NDL from the Beulah seam with an average Hg concentration of 0.081 ppm (dry) and a standard 

deviation of 0.035 ppm. The mercury values in Exhibit 2-4 and Exhibit 2-5 are the mean plus 

one standard deviation, or 0.081 ppm (dry) for PRB coal and 0.116 ppm (dry) for NDL [7]. It 

was further assumed that all of the coal Hg enters the gas phase and none leaves with the bottom 

ash or slag.

Design Targets

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 2-8 [8]. 

Design targets were established specifically for bituminous coal, but are applied to the

subbituminous and lignite cases as well. Because of the lower coal sulfur content in the low rank 
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30

coals, actual sulfur dioxide (SO2) emissions are substantially lower than the environmental 

target. EPRI notes that these are design targets and are not to be used for permitting values.

Exhibit 2-8 IGCC Environmental Targets

Pollutant Environmental Target NSPS Limit Control Technology

NOx 15 ppmv (dry) @ 15% O2 1.0 lb/MWh Low NOx burners and 

syngas nitrogen dilution

SO2 0.0128 lb/MMBtu 1.4 lb/MWh

Selexol, MDEA or 

Sulfinol (depending on 

gasifier technology)

Particulate 

Matter 

(Filterable)

0.0071 lb/MMBtu 0.015 lb/MMBtu

Quench, water scrubber, 

and/or cyclones and 

candle filters (depending 

on gasifier technology)

Mercury > 90% capture 20 x 10-6 lb/MWh Carbon bed

Based on published vendor literature, it was assumed that LNBs and nitrogen dilution can 

achieve 15 ppmv (dry) at 15 percent O2, and that value was used for all IGCC cases [9,10].

To achieve an environmental target of 0.0128 lb/MMBtu of SO2 requires approximately 12 ppmv 

sulfur in the sweet syngas. The acid gas removal (AGR) process required a sulfur capture 

efficiency of about 99.7 percent to reach the environmental target using PRB with a sulfur 

content of 0.73 percent. Vendor data on the AGR processes used in this study indicate that this 

level of sulfur removal is possible. When similar AGR technologies to the Volume 1 IGCC 

cases of this study are used, SO2 emissions are substantially lower because of the lower coal 

sulfur content. In the CO2 capture cases, the two-stage Selexol process results in a sulfur capture 

of greater than 99.7 percent, hence lower sulfur emissions in the CO2 capture cases.

The ash portion of the coal is largely removed from the gasifier as slag for higher temperature 

slagging gasifiers. The ash that remains entrained in the syngas is captured in the downstream 

equipment, including the syngas scrubber and a cyclone and either ceramic or metallic candle 

filters. The amount of entrained ash is dependent on the ash content in the coal and the specific 

gasifier technology. The environmental target of 0.0071 lb/MMBtu filterable particulates can be 

achieved with the combination of particulate control devices employed by each gasifier 

technology so that it was assumed the environmental target was met exactly.

The environmental target for mercury capture is greater than 90 percent. Based on experience at 

the Eastman Chemical plant, where syngas from a GE Energy (GEE) gasifier is treated, the 

actual mercury removal efficiency used is 95 percent. Sulfur-impregnated activated carbon is 

used by Eastman as the adsorbent in the packed beds operated at 30°C (86°F) and 6.2 MPa (900 

pounds per square inch gage [psig]). Mercury removal between 90 and 95 percent has been 

reported with a bed life of 18 to 24 months. Removal efficiencies may be even higher, but at 95 

percent the measurement precision limit was reached. Eastman has yet to experience any 

mercury contamination in its product [11]. Mercury removals of greater than 99 percent can be 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

31

achieved by the use of dual beds, i.e., two beds in series. However, this study assumes that the 

use of sulfur-impregnated carbon in a single carbon bed achieves 95 percent reduction of 

mercury emissions, which meets the environmental target and NSPS limits in all cases.

Carbon Dioxide

CO2 is not currently regulated nationally. 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. CO2 emissions are reported on both a pound (lb)/(gross) MWh and lb/(net) MWh 

basis in each capture case emissions table.

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

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

maximum removal is limited by the amount of carbon that is fully oxidized to CO2, either 

through the gasification or WGS reaction. Lower temperature gasifiers tend to produce more 

methane, which, unless reformed into CO2, cannot be removed effectively and lowers the 

maximum removal. The H2O:CO molar ratio is adjusted as necessary (with a minimum of 0.25 

outlet steam:dry gas ratio) to achieve 90 percent overall CO2 removal, when possible.

2.4 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, CF and availability are 

equal. Input from EPRI and their work on the CoalFleet for Tomorrow Initiative were used to 

set the IGCC case CF.

There are five operating IGCC plants worldwide that use a solid feedstock and are primarily 

power producers (Polk, Wabash, Buggenum, Puertollano, and Nakoso). Higman et al. examined 

the reliability of these IGCC power generation units and concluded that typical annual on-stream 

times are around 80 percent [12]. The CF 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 Higman et al. and others [13], a CF of 80 percent was chosen for IGCC with no spare 

gasifier required.

The addition of carbon capture and storage (CCS) to each technology was assumed not 

to impact the CF. This assumption was made to enable a comparison based on the impact of 

capital and variable operating costs only. Any reduction in assumed CF would further increase 

the COE for the CO2 capture cases.

2.5 RAW WATER WITHDRAWAL AND CONSUMPTION

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

total water demand for each major subsystem was determined and internal recycle water 

available from various sources like boiler feedwater (BFW) 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 as 
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32

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

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

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

as cooling tower makeup, BFW makeup, slurry preparation makeup, ash handling makeup, 

syngas humidification, and quench system makeup. The difference between withdrawal and 

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

the process on the water source.

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

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

water system (SWS) blowdown streams were assumed to be treated and 90 percent returned to 

the water source with the balance sent to the ash ponds for evaporation.

The largest consumer of raw water in all cases is cooling tower makeup. Since plants located in 

the Western United States (U.S.) need to consider limited water supplies, a parallel wet/dry 

steam condenser was chosen for all plant configurations similar to the system recently installed 

at the Comanche 3 plant. In a parallel cooling system half of the turbine exhaust steam is 

condensed in an air-cooled condenser and half in a water-cooled condenser. The cooling water is 

provided by a mechanical draft, evaporative cooling tower, and all process blowdown streams 

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

temperature of 3°C (37°F) at the Montana site and 2°C (36°F) at the NDL site (Exhibit 2-1 and 

Exhibit 2-2) was used to achieve a cooling water temperature of 9°C (48°F) and 8°C (47°F), 

respectively at the two sites using an approach of 6°C (11°F). The cooling water range was 

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

[14]:

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

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

• Blowdown losses = Evaporative Losses / (Cycles of Concentration - 1)

Where cycles of concentration are a measure of water quality, and a mid-range value of 4 

was chosen for this study.

Typical design conditions for air-cooled condensers include an initial temperature difference

(ITD) of 40-55°F [15]. The ITD is the temperature difference between saturated steam at the 

steam turbine generator (STG) exhaust and the inlet dry bulb cooling air temperature. The ITDs 

at the two locations in this study are 48 and 50°F. The fan power requirement is estimated at 3.5 

times the power required for a wet cooling tower with equivalent heat duty [16].

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

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

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

water consumption, again by difference.
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2.6 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.

2.6.1 Capital Costs

As illustrated in Exhibit 2-9, 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 

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 2-9 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 mixed- year 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: 
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34

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.

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. 

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 [17].

Most techno-economic studies completed by NETL feature cost estimates intended for the 

purpose of a “Feasibility Study” (AACE Class 4). Exhibit 2-10 describes the characteristics of 

an AACE Class 4 Cost Estimate. Cost estimates in this study have an expected accuracy range 

of -15%/+30%.

Exhibit 2-10 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

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). 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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Non-CO2 Capture Plant Maturity

The non-capture IGCC cases are based on commercial offerings, however, there have been very 

limited sales of these units so far. These non-CO2-capture IGCC plant costs are less mature in 

the learning curve than PC or NGCC plants, and the costs listed reflect the “next commercial 

offering” level of cost rather than mature nth-of-a-kind (NOAK) cost. Thus, each of these cases 

reflects the expected cost for the next commercial sale of each of these respective technologies. 

CO2 Removal Maturity 

The pre-combustion CO2 removal technology for the IGCC capture cases has a stronger 

commercial experience base than for PC or NGCC plants. 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 technology in commercial service, there are currently IGCC plants with 

CO2 capture well along in the planning stages. 

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. As a result of current market conditions, EPC contractors appear more

reluctant to assume that overall level of risk. 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 and absorbs higher project 

management costs, the risks become reduced with time, as there is better scope definition at the 

time of contract award(s).

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.

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. 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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Other key estimate considerations include the following:

• Labor costs are based on Midwest, Merit Shop using factors from PAS, Inc [18]. PAS 

presents information for eight separate regions. Volume 1 of this study used a generic 

Midwestern site, typical of Region 5 (IL, IN, MI, MN, OH, and WI). The weighted 

average rate for Region 8 (CO, MT, ND, SD, UT, and WY) is within less than one-half of 

one percent of that for Region 5. The difference is inconsequential so the same rates used 

in Volume 1 were maintained in this study. Costs would need to be re-evaluated for 

projects employing union labor.

• 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 as a percentage 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 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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should be noted that the cost of individual equipment types may still deviate from the June 2007 

reference point.

Cross-comparisons 

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

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

review the consistency of the direction of the costs. 

In performing such a comparison, it is important to reference the technical parameters for each 

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

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

design philosophy occur. Some key examples are: 

• The CTs for the IGCC capture cases include an additional cost for firing a high hydrogen 

content fuel.

• Lower overall carbon removal for TRIGTM CO2 capture case due to high methane 

content.

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
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• unexpected cost escalation

• performance of the plant after startup (e.g., availability, efficiency)

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.

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 2-11, AACE International Recommended Practice 16R-90 provides 

guidelines for estimating process contingency based on EPRI philosophy [19].

Process contingencies have been applied to the estimates in this study as follows:

• 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

• Mercury Removal – 5 percent on all IGCC cases – minimal commercial scale experience 

in IGCC 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 – integration issues
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Exhibit 2-11 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.

Owner’s Costs

Exhibit 2-13 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 [19]. 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 2-12.

Exhibit 2-12 TASC/TOC Factors

Finance Structure IOU High Risk IOU Low Risk

TASC/TOC 1.140 1.134
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Exhibit 2-13 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. Not applicable for natural gas.

• 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)

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.
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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/ten-hour-perday 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.

Initial Cost for 

Catalysts and 

Chemicals

• All initial fills not included in BEC

Taxes & Insurance • 2% of TPC (Fixed O&M Cost )
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2.6.2 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 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. 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

43

Initial fills of the consumables, fuels and chemicals, are different from the initial chemical 

loadings (such as reactor catalyst), which are included with the equipment pricing in the capital 

cost.

Waste Disposal

Waste quantities and disposal costs were determined similarly to the consumables. In this study 

slag from the IGCC cases is considered a non-hazardous waste with a disposal cost of 

$17.89/tonne ($16.23/ton). The carbon used for mercury control 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 sulfur, no credit was taken for potential 

salable value.

It should be noted that by-product credits and/or disposal costs could potentially be an additional 

determining factor in the choice of technology for some companies and in selecting some sites. 

A high local value of the product can establish whether or not added capital should be included 

in the plant costs to produce a particular co-product. Slag is a potential by-product in certain 

markets. However, as stated above, the slag is considered a non-hazardous waste in this study 

with a concomitant disposal cost.

2.6.3 CO2 Transport, Storage and Monitoring

For those cases that feature carbon sequestration, 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 2-14 [20]. A glycol dryer located near the 

mid-point of the compression train is used to meet the moisture specification.

• 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 [21]. 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

[22]. (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 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

44

achieve an appropriate down-hole pressure, with hydrostatic head making up the 

difference between the injection and reservoir pressure.

Exhibit 2-14 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 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) [23]. 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 [23]. The assumed aquifer 

characteristics are tabulated in Exhibit 2-15.

Exhibit 2-15 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 (μm2) 22 (22)

Pipeline Distance km (miles) 80 (50)

Injection Rate per Well tonne (ton) CO2/day 9,360 (10,320)

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 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

45

underground pore volume, analogous existing policies were used for representative cost 

scenarios.

The following sections describe the sources and methodology used for each metric.

TS&M Capital 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 [21, 23, 24]. 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 [24]. 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 [23]. 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 [21]. This 

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 [21]. 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.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

46

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 [25]. 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 [26]. 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) [27,28,29]. 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 

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 [30]. 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.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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2.6.4 Finance Structure, Discounted Cash Flow Analysis, and COE

The global economic assumptions are listed in Exhibit 2-16. 

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 (low-risk or high-risk). For this study the owner/developer was assumed to be an IOU. 

All IGCC cases were considered high risk. 

Exhibit 2-17 describes the low-risk IOU (for reference) and high-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

[31].

Exhibit 2-16 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 Coal Plants: 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%2

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

 

2 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.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

48

Parameter Value

% 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%3

Exhibit 2-17 Financial Structure for Investor Owned Utility High and Low 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) is a nominal-dollar4 (current dollar) 

discounted cash flow (DCF) analysis tool. As explained below, the PSFM was used to calculate 

COE5 in two ways: a COE and a levelized COE (LCOE). To illustrate how the two are related, 

COE solutions are shown in Exhibit 2-18 for a generic pulverized coal (PC) power plant and a 

generic natural gas combined cycle (NGCC) power plant, each with carbon capture and 

sequestration installed.

 

3 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.)

4 Since the analysis takes into account taxes and depreciation, a nominal dollar basis is preferred to properly reflect 

the interplay between depreciation and inflation.

5 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.
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• 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 percent6, provided the stipulated internal rate of return on equity 

over the entire economic analysis period (capital expenditure period plus thirty years of 

operation). The COE solutions are shown as curved lines in the upper portion of 

Exhibit 2-18 for a PC power plant and a NGCC power plant. Since this analysis assumes that 

COE 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. 

• The LEVELIZED 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 of 0 percent, i.e., that it remains constant in nominal terms over the 

operational period of the power plant. This study reports LCOE on a current-dollar basis 

over thirty years. “Current dollar” refers to the fact that levelization is done on a nominal, 

rather than a real, basis7. “Thirty-years” refers to the length of the operational period 

assumed for the economic analysis. To calculate the LCOE, the PSFM was used to calculate 

a base-year COE that, when escalated at a nominal annual rate of 0 percent, provided the 

stipulated return on equity over the entire economic analysis period. For the example PC and 

NGCC power plant cases, the LCOE solutions are shown as horizontal lines in the upper 

portion of Exhibit 2-18.

Exhibit 2-18 also illustrates the relationship between COE and the assumed developmental and 

operational timelines for the power plants. As shown in the lower portion of Exhibit 2-18, the 

capital expenditure period is assumed to start in 2007 for all cases in this report. All capital costs 

included in this analysis, including project development and construction costs, are assumed to 

be incurred during the capital expenditure period. Coal-fueled plants are assumed to have a 

capital expenditure period of five years and natural gas-fueled plants are assumed to have a 

capital expenditure period of three years. Since both types of plants begin expending capital in 

the base year (2007), this means that the analysis assumes that they begin operating in different 

years: 2012 for coal plants (see Volume 3b for cost and performance of combustion based 

plants) and 2010 for natural gas plants in this study (see Volume 3c for cost and performance of 

NGCC plants). Note that, according to the Chemical Engineering Plant Cost Index, June-2007 

dollars are nearly equivalent to January-2010 dollars.

 

6 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.

7 For this current-dollar analysis, the LCOE is uniform in current dollars over the analysis period. In contrast, a 

constant-dollar analysis would yield an LCOE that is uniform in constant dollars over the analysis period.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

50

Exhibit 2-18 Illustration of COE Solutions using DCF Analysis

In addition to the capital expenditure period, the economic analysis considers thirty years of 

operation.

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, except for TASC, which is expressed in mixed-year, current 

dollars over the capital expenditure period. 

Consistent with our nominal-dollar discounted cash flow methodology, the COEs shown on

Exhibit 2-18 are expressed in current dollars. However, they can also be expressed in constant, 

base year dollars (June 2007) as shown in Exhibit 2-19 by adjusting them with the assumed 

nominal annual general inflation rate (3 percent).

Exhibit 2-19 illustrates the same information as in Exhibit 2-18 for a PC plant with CCS only on 

a constant 2007 dollar basis. With an assumed nominal COE escalation rate equal to the rate of 

inflation, the COE line now becomes horizontal and the LCOE decreases at a rate of 3 percent

per year.
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Exhibit 2-19 PC with CCS in Current 2007 Dollars

Estimating COE with Capital Charge Factors

For scenarios that adhere to the global economic assumptions listed in Exhibit 2-16 and utilize 

one of the finance structures listed in Exhibit 2-17, the following simplified equation can be used 

to estimate COE as a function of TOC8, fixed O&M, variable O&M (including fuel), capacity 

factor and net output. The equation requires the application of one of the capital charge factors 

(CCF) listed in Exhibit 2-20. These CCFs are valid only for the global economic assumptions 

listed in Exhibit 2-16, the stated finance structure, and the stated capital expenditure period.

Exhibit 2-20 Capital Charge Factors for COE Equation

Finance Structure High Risk IOU Low Risk IOU

Capital Charge Factor (CCF) 0.1243 0.1165

 

8 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). 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

52

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 2-16, 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.

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 2-20 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

The primary cost metric in this study is the COE, which is the base-year cost presented in baseyear dollars. Ex X presents this cost metric along with the COE escalated to the first year of 

operation (2012 for coal cases) using the average annual inflation rate of 3 percent. Similarly, 

the LCOE is presented in both base-year dollars and first year of operation dollars. Using a 

similar methodology, the reader may generate either metric in the desired cost year basis.

The cost of avoiding CO2 was calculated in two ways: the cost of CO2 avoided compared to the 

analogous non-capture design and the cost of CO2 avoided compared to a baseline SC PC boiler 

plant firing the same coal at the same design conditions, using the equation below:
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

53

CO Emissions CO Emissions tons MWh

COE COE MWh

Avoided Cost

reference with removal

with removal reference

{ } /

{ } $ /

2 − 2

− =

Exhibit 2-21 COE and LCOE Summary

Case

COE LCOE

Base-Year First Operational 

Year Base-Year First Operational Year

2007$ 2012$ 2007$ 2012$

S1A 83.2 96.4 105.4 122.2

S1B 119.7 138.8 151.8 175.9

L1A 83.5 96.8 105.8 122.7

L1B 121.9 141.3 154.5 179.1

S2A 74.5 86.4 94.5 109.5

S2B 105.2 122.0 133.4 154.6

S3A 86.8 100.6 110.0 127.5

S3B 121.7 141.1 154.3 178.9

L3A 87.3 101.2 110.7 128.3

L3B 123.7 143.5 156.9 181.9

S4A 78.7 91.3 99.8 115.7

S4B 112.3 130.2 142.4 165.1

The baseline SC PC boiler plant is a 550MW plant with the results presented in Exhibit 2-22, 

below, and in the combustion portion of this report volume. The COE in the CO2 capture cases 

includes TS&M, as well as capture and compression.

Exhibit 2-22 Baseline SC PC Results for CO2 Cost Calculation

PRB (S12A) Lignite (L12A)

Net Output (MW) 550 550

COE (mills/kWh) 57.80 62.19

Emissions (lb/net-MWh) 1,892 1,996
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2.7 IGCC STUDY COST ESTIMATES COMPARED TO INDUSTRY ESTIMATES

The estimated TOC for IGCC cases in this study ranges from $2,728 to $3,239/kW for non- CO2

capture cases and $3,691/kW to $4,430/kW for capture cases. Plant size ranges from 504 - 617

MW (net) for non-capture cases and 445 - 515 MW (net) for capture cases. 

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 

$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 

[32,33,34,35].9

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 greenfield site having “normal” characteristics. 

Accordingly, the estimates do not address items such as:

• Piles or caissons

• Rock removal

• Excessive dewatering

 

9 Costs were adjusted to June 2007 using the Chemical Engineering Plant Cost Index
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55

• 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

• Automated coal reclaim

• Zero Liquid Discharge equipment

• SCR catalyst

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.
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3. IGCC POWER PLANTS

Twelve IGCC power plant configurations were evaluated and the results are presented in this 

section. Each design is based on a market-ready technology that is assumed to be commercially 

available to support startup in the near term.

The six cases are based on the Shell Coal Gasification Process, TRIGTM gasifier, Siemens Fuel 

Gasifier and CoP E-GasTM gasifier, each with and without CO2 capture. As discussed in Section 

1, the net output for the twelve cases varies because of the constraint imposed by the fixed GT

output and the high auxiliary loads imparted by the CO2 capture process. The TRIGTM gasifier 

development has focused more on air-blown gasification for power generation, for characterizing 

the gasifier performance on a range of coals, so only PRB coal was considered as a starting point 

for comparison to other potential configurations. The CoP E-GasTM gasifier feed has an upper 

limit for coal slurry concentration, which becomes a concern for lower rank coals, so to err on 

the side of more proven feedstocks, only PRB coal was considered for CoP cases.

The CT is based on an advanced F-class design. The HRSG/steam turbine cycle is nominally 

12.4 MPa/566°C/566°C (1800 psig/1050°F/1050°F) for all of the non-CO2 capture cases and 

nominally 12.4 MPa/538°C/538°C (1800 psig/1000°F/1000°F) for all of the CO2 capture cases. 

The capture cases have a lower main and reheat steam temperature primarily because the turbine 

firing temperature is reduced to allow for a parts life equivalent to NGCC operation with a highhydrogen content fuel, which results in a lower turbine exhaust temperature. 

The evaluation scope included developing heat and mass balances and estimating plant 

performance. Equipment lists were developed for each design to support plant capital and 

operating cost estimates. The evaluation basis details, including site ambient conditions, fuel 

composition and environmental targets, were provided in Section 2. Section 3.1 covers general 

information that is common to all IGCC cases, and case specific information is subsequently 

presented in the gasifier background sections.

3.1 IGCC COMMON PROCESS AREAS

The IGCC cases have process areas, which are common to each plant configuration such as coal 

receiving and storage, coal drying, oxygen supply, gas cleanup, power generation, etc. As 

detailed descriptions of these process areas for each case would be burdensome and repetitious, 

they are presented in this section for general background information. Where there is casespecific performance information, the performance features are presented in the relevant case 

sections.

3.1.1 Coal Receiving and Storage

The function of the Coal Receiving and Storage system is to unload, convey, prepare, and store 

the coal delivered to the plant. The scope of the system is from the trestle bottom dumper and 

coal receiving hoppers up to and including the slide gate valves at the outlet of the coal storage 

silos.
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Operation Description – The coal is delivered to the site by 100-car unit trains comprised of 91 

tonne (100 ton) rail cars for PRB cases. The lignite cases are located at a minemouth location. 

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 centimeters (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.

3.1.2 Coal Drying

Reduction in coal moisture content can improve the efficiency of dry-feed gasifiers, with a 

corresponding increase in auxiliaries and drying equipment costs. Coal moisture consists of two 

components, surface moisture and inherent moisture. Low rank coals have higher inherent 

moisture content and total moisture content than bituminous and other high rank coals. 

Depending on the size of the coal fed to the gasifier, it may be necessary to reduce most, if not 

all, of the surface moisture for coal transport properties to be acceptable. It should be noted that 

fluidization tests would need to be performed for the specific coals, in conjunction with the 

gasifier vendors, to ensure that the coal drying scheme results in the required coal transportation 

properties.

Dry feed gasifiers utilize coal drying schemes as described below. This reduces the amount of 

diluent fed to the gasifier, balanced out by the auxiliaries required to vaporize the coal moisture, 

generally providing a net increase to efficiency while introducing additional cost and complexity 

to the feed system. The slurry feed system is described in the individual technology section for 

the CoP E-GasTM IGCC cases.

In a Gasification Technology Conference (GTC) paper [36], Shell indicated for its entrained 

flow gasifier feeding coal in the size range of 50 – 100 microns that it would dry lignite coal 

from 53 to 12 percent and subbituminous coal from 30 to 6 percent. The presentation indicated 

the coal would be dried using the fine grain WTA (fluidized bed drying technology with built-in 

waste heat recovery) process, which dries coal at a particle size of about 1 millimeter (mm)

(1,000 microns). Consequently, the coal must be run through a pulverizer after drying before 

being fed to the gasifier.

In personal correspondence with Shell, they indicated the moisture content of the coal after 

drying should be 3-14 percent depending on coal type [37]. EPRI and IEA recently performed 

studies that included the Shell gasifier using lignite coal that used a design moisture content of 5 

percent entering the gasifier [38,39]. 
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59

Publications by Southern Company Services indicate for their transport gasifier that coal with a 

top size of 700 microns [40] would be dried to a moisture level of 18 weight percent (wt%) [41].

Consequently, for the dry-feed entrained flow gasifiers in this study it is assumed that the 

subbituminous coal is dried to 6 percent moisture and the lignite to 12 percent moisture. For the 

transport gasifiers in this study, the coal will be dried to 18 percent moisture. In more detailed 

designs, coal fluidization tests would be performed to fine tune the coal feeding process.

The coal drying process selected for a specific IGCC system is a function of the drying 

requirement. The options considered for coal drying include:

• Option 1: Use conventional IGCC coal drying methods, which consist of deriving heat 

from the combustion of natural gas and/or syngas and using the flue gas, either directly or 

indirectly (by heating a nitrogen stream), for use in drying the coal. Some examples 

include the following:

o At the Buggenum facility bituminous coal is ground in a conventional roller mill 

and simultaneously dried using a heated inert recycle gas stream that carries the 

evaporated water from the system as it sweeps the PC through an internal, rotating 

classifier. The inert gas generator is fueled by the in-line combustion of treated 

syngas. Excess gas is vented on pressure control [42].

o At the Puertollano facility, coal is ground in mills using nitrogen for drying from 

10 percent to less than 2 percent moisture. The drying circuit is heated to about 

250°C (482°F) by intermediate pressure (IP)-steam and additional burning of 

natural gas. The report notes that a dual drying circuit using only natural gas and 

the produced syngas could be studied [43].

• Option 2: Use a conventional drying method with the warm gas exiting the HRSG used 

as the heat source. The HRSG exit gas is typically around 270°F and contains 10-11 

percent oxygen. The high oxygen concentration is a concern with low rank coals and self 

ignition levels in the drying circuit, for the specific coals, should be studied and 

addressed in a more detailed design.

• Option 3: Dry the coal using a scheme similar to the Great River Energy (GRE) Clean 

Coal Power Initiative (CCPI) project approach. In the case of gasification where the 

drying requirements are greater than in PC plants, higher grade heat than is available 

from the cooling water exiting the condenser will be required. However, there are many 

sources of low-level waste heat in an IGCC plant and integration of this heat into the 

drying circuit is possible. Because of the tendency for low rank coals to spontaneously 

combust after the moisture is removed, it may be necessary to fluidize the coal bed with 

something other than air. Depending on the source of the fluidization gas, the process 

could become cost prohibitive.

• Option 4: Use the WTA process (German acronym for “fluidized bed dryer with 

integrated waste heat recovery”) [44] proposed by RWE Power AG, which consists of a 

fluid bed dryer utilizing a heat pump-type cycle with recovered coal moisture used for 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

60

fluidizing the coal bed and used as the working fluid [45]. This is the option presented 

by Shell at the 2005 GTC Conference, as mentioned above.

• Option 5: Use a process similar to the Integrated Drying and Gasification Combined 

Cycle (IDGCC) being developed in Australia.

• Option 6: Use a drying configuration practiced by Southern Company Services[46]

where coal is dried in a closed-loop (CL) including a roll mill pulverizer, flash dryer, gas 

cooler to condense water vapor, and heater to heat the gas for drying. The oxygen 

concentration of the CL gas is monitored and nitrogen is fed as necessary to maintain an 

oxygen concentration below 11.3 percent for safety reasons. The source of heat is waste 

heat or IP steam. The water removed from the coal is collected in the cooler, treated, and 

used in the process.

Conventional coal drying methods would be suitable for this study, but there is an efficiency 

penalty involved with burning either syngas or natural gas as a heat source and there are 

additional CO2 emissions generated by the process. Using steam as the heat source also impacts 

overall efficiency.

The GRE process has potential because of the many sources of low-grade heat in the IGCC 

process. However, the fluidization gas source would have to be identified assuming ambient air 

cannot be used because of the combustion tendencies of dried, low rank coals. One possibility 

would be using the HRSG exhaust gas, which contains 10-11 percent oxygen.

The RWE process has the advantage of using steam and coal moisture as the fluidizing medium 

thus eliminating the spontaneous combustion concerns. However, the vapor compressor imposes 

a significant auxiliary load. In Shell’s GTC presentation the relative power and steam use are 

compared for three different technologies [47]. The results shown in Exhibit 3-1 assume 350 ton 

per hour (TPH) of as-received lignite coal with 53 percent moisture dried to 12 percent.

Exhibit 3-1 SCGP Lignite Coal Drying Options

Coal Feed, “dried” basis Power Use, kW Steam Use, lb/hr

Water 

Product, lb/hr

Conventional drying 

(rotary kiln) 3,180 449,000 0

Fluid bed simple 4,670 411,000 0

Fluid bed with WTA 

process 15,890 64,000 261,700

The IDGCC process is being commercialized by HRL Ltd. HRL has been trying to develop a 

project in Australia since 2002, originally at a scale of 400 MW and more recently at a scale of 

600 MW [48]. The process utilizes hot syngas from an air blown fluidized bed gasifier (FBG) to 

dry brown coal prior to entering the gasifier. Sulfur is captured in the fluid bed and particulates 

are removed in a downstream candle filter. The warm, humidified syngas is then burned in a GT

[49].
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The technology is being developed for an air-blown FBG and has features that make it less 

attractive in the case of an entrained-flow, oxygen-blown gasifier like the Shell process. The 

coal is crushed to 10 mm top size and pressurized to 2.5 MPa (363 pounds per square inch [psi]) 

through a lock hopper system. The FBG can accept 10 mm coal, and at that size and high 

moisture content the coal will still flow through the lock hoppers. However, in the case of the 

Shell gasifier, the coal top size is significantly smaller (Shell does not specify the size, but states 

that conventional coal pulverizers are used, which likely results in an average coal size of 50-100 

μm) and the coal must be dried prior to pressurizing to avoid lock hopper flow problems.

Where applicable, the WTA coal drying system was chosen for the traditional dry feed gasifiers 

largely because of its ability to recover the water from the coal in liquid state for use in the 

process and the fact that syngas is not used to provide heat for drying. In conventional dryers, 

the water is mixed with the heating gas and discharged to atmosphere as vapor. Recovery of the 

coal moisture in a liquid state results in a sizable electric auxiliary load.

The ‘closed’ WTA process has been demonstrated at pilot scale. Plans for a commercial 

demonstration of an ‘open’ version of the process have been delayed. In spite of the uncertainty 

of the commercial demonstration, the potential benefit of the technology was viewed to be 

significant enough to use the ‘closed version’ of the process in this study. A process schematic is 

shown in Exhibit 3-2, reprinted from Kakaras, Emm. et al. [50].

Exhibit 3-2 WTA Process Schematic
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62

An effort was made to apply the WTA process to the TRIGTM IGCC cases. The PRB coal as 

received contains 26 percent moisture, and must only be dried to 18 percent moisture for the 

transport gasifier cases. Because of the low moisture delta (8 percent), there is a reduced amount 

of moisture available to provide the working fluid for the heat pump cycle requiring excessively 

high steam compressor discharge pressures (and subsequently temperatures) to produce the heat 

necessary to both vaporize the water and sensibly heat the coal. Consequently, the WTA process 

was not used for the TRIGTM cases, but rather the Southern Company Services system described 

in Option 6 above was paired with the associated transport gasifier technology.

For the TRIGTM IGCC systems, fluidized-bed roller mills simultaneously dry and crush the coal 

to 700 μm by a combination of flash drying and in bed heating, utilizing waste heat where 

possible.

3.1.3 Gasifier Modeling

Gasifier performance was modeled at the boundaries of the gasifier operation as an equilibrium 

reactor. Many literature references support this modeling strategy [44,51,52]. Gasifier vendors’ 

input were used to determine the inputs to the gasifier, as well as the typical or desired 

configuration of the gasifier, high temperature heat recovery, and syngas cleaning processes. 

The boundaries of the gasifier model and the syngas compositions were generally provided or 

refined with estimates from the vendors and the temperature approaches to equilibrium were 

adjusted to match the syngas exiting these boundary conditions. 

3.1.4 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) [53]. 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 

GT, the ASU operates at or near the supply pressure from the GT’s air compressor.

Residual Nitrogen Injection

The residual nitrogen that is available after gasifier oxygen and nitrogen requirements have been 

met is compressed and sent to the GT. Since all product streams are being compressed, the ASU 

air feed pressure is optimized to reduce the total power.

Increasing the diluent flow to the GT by injecting residual nitrogen from the ASU can have a 

number of benefits, depending on the design of the GT: 

• Increased diluent increases mass flow through the turbine, thus increasing the power output 

of the GT while maintaining optimum firing temperatures for syngas operation.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

63

• By mixing with the syngas or by being injected directly into the combustor, the diluent 

nitrogen lowers the firing temperature (relative to natural gas) and reduces the formation of 

thermal NOx.

In this study, the ASU nitrogen product was used as the primary diluent with a design target of 

reducing the syngas lower heating value (LHV) to 4.2 to 4.8 megajoule per normal cubic meter 

(MJ/Nm3) (115-132 British thermal unit per standard cubic foot [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.

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 GT. Medium Btu syngas streams result in a higher mass flow 

than natural gas to provide the same heat content to the GT. Some GT designs may need to 

extract air to maintain stable compressor or turbine operation in response to increased fuel flow 

rates. Other GTs 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 GT. Extraction air temperature is normally 

in the range 399 to 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 heat recovery from 

the extracted air occurs by transferring heat to the nitrogen stream to be injected into the GT with 

a gas-to-gas heat exchanger.

Elevated Pressure ASU Experience in Gasification

The Buggenum, Netherlands unit built for Demkolec, now owned by NUON, was the first 

elevated-pressure, fully integrated ASU to be constructed. It was designed to produce up to 

1,796 tonnes/day (1,980 tons per day [tpd]) of 95 percent purity oxygen for a Shell coal-based 

gasification unit that fuels a Siemens V94.2 GT. In normal operation at the Buggenum plant the 

ASU receives all of its air supply from and sends all residual nitrogen to the GT.

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 GT. All of the nitrogen 

produced in the ASU is used in the GT. 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 [54].

ASU Basis

For this study, air integration is used for the non-carbon capture cases only. In the CO2 capture 

cases, once the syngas is diluted to the target heating value, all of the available combustion air is 

required to maintain mass flow through the turbine and hence maintain power output.
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The amount of air extracted from the GT in the non-capture cases is determined through a 

process that includes the following constraints:

• The CT must be fully loaded; i.e., sufficient gas mass flow is supplied to maximize the 

turbine power output at the given elevation.

• The diluted syngas must meet heating value requirements specified by a CT vendor, which 

ranged from 4.2-4.8 MJ/Nm3 (115-132 Btu/scf) (LHV).

The air extraction for the non-CO2 capture case is shown in Exhibit 3-3. 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 [55,56].

Exhibit 3-3 Air Extracted from the Combustion Turbine and Supplied to the ASU in NonCarbon Capture Case

Case No. S1A L1A S2A S3A L3A S4A

Air Extracted from GT, % 2.5 6.0 0.7 2.8 3.2 6.0

Air Provided to ASU, % of ASU Total 11.0 26.0 3.9 13.3 13.6 18.7

Air Separation Plant Process Description [57]

The air separation plant 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 dilution in 

the GT combustor. A process schematic of a typical ASU is shown in Exhibit 3-4.

The air feed to the ASU can be supplied from two sources. A portion of the air can be extracted 

from the compressor of the GT (non-CO2 capture cases only). The remaining air is supplied 

from a stand-alone compressor. Air to the stand-alone compressor is first filtered in a suction 

filter upstream of the compressor. This air filter removes particulate, which may tend to cause 

compressor wheel erosion and foul intercoolers. The filtered air is then compressed in the 

centrifugal compressor, with intercooling between each stage.

Air from the stand-alone compressor is combined with the extraction air, and the combined 

stream is cooled and fed to an adsorbent-based pre-purifier system. The adsorbent removes 

water, CO2, and C4+ saturated hydrocarbons in the air. After passing through the adsorption 

beds, the air is filtered with a dust filter to remove any adsorbent fines that may be present. 

Downstream of the dust filter a small stream of air is withdrawn to supply the instrument air 

requirements of the ASU.

Regeneration of the adsorbent in the pre-purifiers is accomplished by passing a hot nitrogen 

stream through the off-stream bed(s) in a direction 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 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

65

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.

Exhibit 3-4 Typical ASU Process Schematic

Cryogenic Air 

Separation Unit

Single Train

Oxygen 

Compressor

HP Oxygen

Nitrogen 

Compressor

HP Nitrogen

Regen

Heater

Cond.

Steam

Regeneration

Nitrogen

Prepurifiers

Two Stage

DCA

Booster Air

Compressor

Air

Main Air

Compressor Air Filter

CWR

CWS

Chiller CWS

CWR

Steam

Cond

Regen. N2

Blower

Liq. Oxygen

Pump Turbine Turbine Air

Booster

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 (LP) process steam at 0.45 MPa (65 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 

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.
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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 HP air feed before being warmed to 

ambient temperature. The gaseous oxygen exits the cold box and is fed to the centrifugal 

compressor with intercooling between each stage of compression. The compressed oxygen is 

then fed to the gasification unit.

Nitrogen is produced from the cold box at two pressure levels. Both streams are compressed for 

use as CT diluent nitrogen. Some of the nitrogen stream is compressed further for use as 

transport gas in lockhoppers in dry feed systems.

3.1.5 High Temperature Syngas Cooling

The main configurations considered in this study for high temperature syngas cooling were 

determined from commercial or near commercial offerings by the different gasifier vendors and 

include: syngas coolers, syngas recycle quench, and water quench. High temperature syngas 

coolers are the most aggressive heat recovery approach, where high quality sensible heat is 

recovered from syngas. This increases plant efficiency at the cost of expensive heat exchangers 

requiring special materials of construction to resist corrosion and the high syngas temperatures.

The high temperature syngas cooling equipment varied by technology vendor with one utilizing 

waterwall heat exchangers and two others utilizing less expensive firetube heat exchangers. The 

fourth technology vendor chose not to include any high temperature heat exchanger.

Systems using high temperature syngas coolers can also utilize other syngas cooling methods to 

minimize the disadvantages of using these heat exchangers. The syngas recycle quench method 

returns a portion of cooled syngas to reduce the temperature of the raw syngas entering the 

syngas coolers. This approach reduces the temperatures entering the syngas coolers, potentially 

reducing costs by allowing for cheaper materials of construction. A similar amount of heat is 

recovered, which is a result of a proportional increase in the size of the syngas stream, which 

offsets the lower inlet temperatures to the syngas coolers. Extra equipment required for this 

configuration includes compressors, piping, and headers required to recycle the syngas.

Another option considered for lowering the inlet temperature to the syngas coolers is a water 

quench. This is a more reliable and less costly option as it relies on spraying water into the 

syngas to reduce its temperature entering the heat exchangers. A disadvantage is that the latent 

heat of vaporization of the quench water can only be recovered at low temperatures, which 

means in many cases that it goes to waste, reducing the efficiency of the plant. A water quench 

reduces the temperature entering the heat exchangers, similar to the syngas recycle quench, and 

can also be designed to help reduce corrosion and fouling in the heat exchangers by removing 

some of the particulates and acid gases exiting the gasifier. For CO2 capture cases, the water 

added to the syngas is an additional benefit as it is required for the WGS reaction, which would 

otherwise be extracted from the steam cycle if it was not directly raised by the syngas. The 

individual chosen syngas cooling schemes are enumerated in the specific technology process 

descriptions.
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3.1.6 Water Gas Shift Reactors

Selection of Technology - In the cases with CO2 separation and capture, the gasifier product 

must be converted to hydrogen-rich syngas. The first step is to convert most of the syngas CO to 

hydrogen and CO2 by reacting the CO with water over a bed of catalyst. The H2O:CO molar 

ratio in the shift reaction, shown below, is adjusted to prevent deposition on the catalyst by the 

addition of steam to the syngas stream to push the equilibrium towards a high conversion of CO. 

The H2O:CO molar ratio is adjusted as necessary (with a minimum of 0.25 outlet steam:dry gas 

ratio) to achieve 90 percent overall CO2 removal, if possible. In the cases without CO2

separation and capture, CO shift convertors are not required.

Water Gas Shift: CO + H2O ↔ CO2 + H2

The CO shift converter can be located either upstream of the AGR step (sour gas shift [SGS]) or 

immediately downstream (sweet gas shift). If the CO converter is located downstream of the 

AGR, then the metallurgy of the unit is less stringent, but additional equipment must be added to 

the process, such as carbonyl sulfide (COS) hydrolysis unit. Products from the gasifier are 

quenched with water and contain a portion of the water vapor necessary to meet the water-to-gas 

criteria at the reactor outlet. If the CO converter is located downstream of the AGR, then the 

gasifier product would first have to be cooled, reducing the water content of the syngas. Then 

additional steam would have to be generated and re-injected into the shift reactor feed and the 

stream would have to be reheated to the catalyst operating temperature to encourage the WGS

reaction. If the shift reactor is located upstream of the AGR step, these steps are avoided, but the 

choice of shift catalyst must consider its sulfur tolerance. Therefore, for this study the CO 

converter was located upstream of the AGR unit and is referred to as SGS, which also 

hydrolyzes the COS to H2S for removal in the AGR.

Process Description - The SGS consists of two parallel paths of fixed-bed reactors. Each 

parallel path consists of two or three reactor stages in series to achieve a sufficient conversion to 

meet the CO2 capture target, if possible.

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 exchangers

after the first SGS reactor are used to superheat shift steam. The heat exchanger after the second 

SGS reactor is a gas-gas exchanger used to preheat the syngas prior to the first SGS reactor.

3.1.7 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 non-carbon capture COS hydrolysis reactor designs are based on 

information from Porocel. In cases with CO2 capture, the SGS reactors reduce COS to H2S as 

discussed in Section 3.1.6.
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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. Since the exit gas COS concentration is 

critical to the amount of H2S that must be removed with the AGR process, a retention time of 50-

75 seconds was used to achieve 99.5 percent conversion of the COS. The Porocel activated 

alumina-based catalyst, designated as Hydrocel 640 catalyst, promotes the COS hydrolysis 

reaction without promoting reaction of H2S and CO to form COS and H2.

Although the reaction is exothermic, the heat of reaction is dissipated among the large amount of 

non-reacting components. Therefore, the reaction is essentially isothermal. The product gas, 

now containing less than 4 ppmv of COS, is cooled prior to entering the mercury removal 

process and the AGR.

3.1.8 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 [11]. The coal mercury content (0.081 ppm 

dry for PRB and 0.116 ppm dry for lignite) and carbon bed removal efficiency (95 percent) were 

discussed previously in Section 2.3. IGCC-specific design considerations are discussed below.

Carbon Bed Location – The packed carbon bed vessels are located upstream of the AGR 

process and syngas enters at a temperature near 38°C (100°F). Consideration was given to 

locating the beds further upstream before the COS hydrolysis unit (in non-CO2 capture cases) at 

a temperature near 204°C (400°F). However, while the mercury removal efficiency of carbon 

has been found to be relatively insensitive to pressure variations, temperature adversely affects 

the removal efficiency [58]. Eastman Chemical also operates their beds ahead of their sulfur 

recovery unit (SRU) at a temperature of 30°C (86°F) [11]. 

Consideration was also given to locating the beds downstream of the AGR. However, it was felt 

that removing the mercury and other contaminants before the AGR unit would enhance the 

performance of both the AGR and SRU and increase the life of the various solvents.

Process Parameters – A superficial gas residence time of approximately 20 seconds was used 

based on Eastman Chemical’s experience [11]. 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 [58] and was selected for 

this application. 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

69

The bed density of 30 pounds per cubic foot (lb/ft3) was based on the Calgon Carbon 

Corporation HGR-P sulfur-impregnated pelletized activated carbon [59]. 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 [11]. 

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 0.64 wt%. Mercury capacity of sulfurimpregnated carbon can be as high as 20 wt% [60]. The mercury laden carbon is considered to 

be a hazardous waste, and the disposal cost estimate reflects this categorization.

3.1.9 Acid Gas Removal Process Selection

Gasification of coal to generate power produces a syngas that must be treated prior to further 

utilization. A portion of the treatment consists of AGR and sulfur recovery. The environmental 

target for these IGCC cases, 0.0128 lb sulfur dioxide per million British thermal units, is based 

on the EPRI CoalFleet values for bituminous coal [8] and 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 H2S, thereby resulting in stack gas emissions of less than 4 ppmv SO2. Because 

the low rank western coals have substantially less sulfur than eastern bituminous coal, the 

resulting sulfur emissions are significantly below the environmental target.

Sulfur Removal

Hydrogen sulfide 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 3-5 is a simplified diagram of the AGR process [61].

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), Selexol, aqueous di-isoproponal (ADIP) amine and 

FLEXSORB [66]. These processes can be separated into three general types: chemical reagents, 

physical solvents, and hybrid solvents. A summary of these common AGR processes is shown 

in Exhibit 3-6. The optimum technology choice for a particular IGCC plant depends on many 

factors such as gasifier operating pressure, availability of low/medium pressure steam, AGR 

requirements, and capital cost.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

70

Exhibit 3-5 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

One process with potential in low-sulfur coal applications is CrystaSulf®, which is a nonaqueous 

process that effectively treats gas with too much H2S to use a scavenger system but too little to 

use an amine/Claus approach. The niche market for CrystaSulf® is reported as 0.2-30 long tons 

per day (LTPD) [62]. According to the CrystaSulf® literature, the total treating costs for H2S 

removal become greater than for amine systems above 30 LTPD [63]. CrystaSulf® was the 

proposed AGR technology for the cancelled Orlando Gasification CCPI Project. The estimated 

sulfur production rate for that project was 9.1 LTPD, which is well within the optimum range of 

the technology [64].

The sulfur production rates for the Low Rank IGCC cases are on the order of 50 LTPD. Since 

these values are significantly greater than the upper range established by CrystaTech, 

CrystaSulf® was not further considered for this study. The different classes of AGR processes 

are described generally below.

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 

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.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

71

Exhibit 3-6 Summary of Common AGR Processes

Solvent 

Type Process H2S Selectivity

Solvent

Circulation Heat Input Capital 

Cost

Pressure 

Sensitive

High 

Removal

Physical Rectisol, 

Selexol Good

High, 

decreases with 

increased 

pressure

Low High Yes

Yes, at high 

acid gas 

partial 

pressures

Mixed Sulfinol, 

FLEXSORB

Good but more 

complicated to 

achieve

Intermediate Intermediate Intermediate

Yes, but to a 

lesser extent 

than physical 

solvents only

Yes, at 

optimum 

operating 

conditions

Chemical Amines (MEA, 

DEA, MDEA)

Varies 

depending on 

amine selected, 

highest for 

MDEA

Low High Low No

Yes, but 

with 

refrigeration
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

72

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. Commercially available are several MDEA-based solvents that are formulated for 

high H2S selectivity.

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 3-7

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 lower 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 are 

needed to remove undesirable reaction byproducts.

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 standard 

cubic feet (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, with 0.8 to 0.9 being a typical “good” 

value.

The major advantage of these systems is the ability to remove acid gas to low levels at low to 

moderate H2S partial pressures.

Exhibit 3-7 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
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

73

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 (HP) and at or 

below ambient temperature while the regeneration step (dissolution) occurs by pressure letdown 

and indirect stripping with LP 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 Selexol 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 3-8 is a simplified flow diagram for a physical reagent type AGR process [61]. Common 

physical solvent processes, along with their licensors, are listed in Exhibit 3-9. 

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.

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.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

74

Exhibit 3-8 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 3-9 Common Physical Solvents Used in AGR Processes

Solvent Solvent/Process

Trade Name

Process 

Licensors

Dimethyl ether of polyethylene glycol Selexol 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

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 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

75

physical solvent processes, along with their licensors, are listed in Exhibit 3-10. 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 3-10 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 3-11 shows reported equilibrium solubility data for H2S and CO2 in various 

representative solvents [61]. The solubility is expressed as scf of gas per gallon liquid per 

atmosphere gas partial pressure.

The figure illustrates the relative solubility 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.

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.

CO2 Capture

A two-stage Selexol process is used for CO2 capture cases in this study as a common basis for 

comparison of these technologies and configurations. This decision was guided the design of 

current commercial chemical plants, mainly producing ammonia, that use the Selexol process to 

remove CO2 in the 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.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

76

Exhibit 3-11 Equilibrium Solubility Data on H2S and CO2 in Various Solvents

The amount of hydrogen remaining in the syngas stream is dependent on the Selexol 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 Selexol plant cost 

estimates are based on a plant designed to recover this high percentage of hydrogen. The 

balance of the hydrogen is co-sequestered with the CO2, destroyed in the Claus plant burner, or 

recycled upstream of the AGR.

The CO2 loaded solvent exits the CO2 absorber and a portion is sent to the H2S absorber and the 

remainder is sent to a series of flash drums for regeneration. Flash gas from the first flash drum 

is fed to a compressor and recycled to the CO2 absorber. The CO2 product stream is obtained 

from the remaining flash drums, and after flash regeneration the solvent is chilled and returned to 

the CO2 absorber.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

77

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.

AGR/Gasifier Pairings

There are numerous commercial AGR processes that could meet the sulfur environmental target 

of this study. The most frequently used AGR systems (Selexol, Sulfinol, MDEA, and Rectisol) 

have all been used in various precombustion applications. To maintain comparability between 

designs of other volumes of this study and to mimic commercial offerings as much as is 

practical, the Sulfinol-M process was chosen for all cases except the CoP design, in order to be 

consistent with the non-capture cases in the NETL Bituminous Baseline Study [65]. Previous 

vendor performance estimates for Sulfinol systems showed high removals for H2S (99.77

percent) and CO2 (97.5 percent). With the higher CO2 and lower H2S concentrations in the raw

gas for the lower rank coals, it is necessary for the AGR to slip a significant amount of CO2. The 

high slip is necessary to reduce the volume and increase the H2S concentration of the acid gas 

stream to the Claus plant for adequate performance and minimum capital cost. The literature 

indicates that Sulfinol systems with very high CO2 slips have been designed, but efforts to obtain 

an updated Sulfinol performance estimate from Shell have been unsuccessful to date.

The two-stage Selexol process is used in all cases that require CO2 capture. Selexol was also 

used for CO2 capture cases in the NETL Bituminous Baseline Study [65]. According to the 

previously referenced SFA Pacific report, “For future IGCC with CO2 removal for sequestration, 

a two-stage Selexol process presently appears to be the preferred AGR process – as indicated by 

ongoing engineering studies at EPRI and various engineering firms with IGCC interests.” [66].

3.1.10 Sulfur Recovery/Tail Gas Cleanup Process Selection

The Claus process is the main process used for gas treating and 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, a tail gas treating unit (TGTU) must be added to the conventional Claus process 

to recover sulfur with over 99.8 percent efficiency.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

78

The Claus Process

The Claus process converts H2S to elemental sulfur via the following reactions:

H2S + 3/2 O2 ↔ H2O + SO2

2H2S + SO2 ↔ 2H2O + 3S

The second reaction, the Claus reaction, is equilibrium limited. The overall reaction is:

3H2S + 3/2 O2 ↔ 3H2O + 3S

The sulfur in the vapor phase exists as S2, S6, and S8 molecular species, with the S2 predominant 

at higher temperatures, and S8 predominant at lower temperatures.

A simplified process flow diagram of a typical three-stage Claus plant is shown in Exhibit 3-12

[66]. One-third of the H2S is burned in the furnace with oxygen from the air to give sufficient 

SO2 to react with the remaining H2S. Since these reactions are highly exothermic, a waste heat 

boiler that recovers this heat to generate HP steam usually follows the furnace. Sulfur is 

condensed in a condenser that follows the HP steam recovery section. LP steam is raised in the 

condenser. The tail gas from the first condenser then goes to several catalytic conversion stages, 

usually 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.

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 1093 to 1427°C (2000 to 2600°F), and as the 

temperature decreases, conversion increases dramatically.

Claus plant sulfur recovery efficiency depends on many factors:

• H2S concentration of the feed gas

• Number of catalytic stages

• Gas reheat method

In order to keep Claus plant recovery efficiencies approaching 94 to 96 percent for feed gases 

that contain about 20 to 50 percent H2S, a split-flow design is often used. In this version of the 

Claus plant, part of the feed gas is bypassed around the furnace to the first catalytic stage, while 

the rest of the gas is oxidized in the furnace to mostly SO2. This results in a more stable 

temperature in the furnace.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

79

Exhibit 3-12 Typical Three-Stage Claus Sulfur Plant

Oxygen-Blown Claus

Large diluent streams in the feed to the Claus plant, such as nitrogen (N2) from combustion air, 

or a high CO2 content in the feed gas, lead to higher cost of the Claus process and any add-on or 

tail gas units. One way to reduce diluent flows through the Claus plant and to obtain stable 

temperatures in the furnace for dilute H2S streams is the oxygen-blown Claus process.

The oxygen-blown Claus process was originally developed to increase capacity at existing 

conventional Claus plants and to increase flame temperatures of low H2S content gases. The 

process has also been used to provide the capacity and operating flexibility for sulfur plants 

where the feed gas is variable in flow and composition such as often found in refineries. The 

application of the process has now been extended to grass roots installations, even for rich H2S 

feed streams, to provide operating flexibility at lower costs than would be the case for 

conventional Claus units. At least four of the 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 1593 to 1649°C (2900 to 3000°F) as the enrichment moves beyond 40 to 

70 volume percent (vol%) 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 cases.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

80

Tail Gas Treating

In many refinery and other conventional Claus applications, tail gas treating involves the 

removal of the remaining sulfur compounds from gases exiting the SRU. Tail gas from a typical 

Claus process, whether a conventional Claus or one of the extended versions of the process, 

usually contains small, but varying quantities of COS, CS4, 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. All cases in this study use 

a catalytic hydrogenation step with tail gas recycle to just upstream of the AGR. The Shell 

Puertollano plant treats the tail gas in a similar manner, but the recycle endpoint is not specified

[43].

Flare Stack

A self-supporting, refractory-lined, carbon steel (CS) flare stack is typically provided to combust 

and dispose of unreacted gas during startup, shutdown, and upset conditions. However, in all 

IGCC cases a flare stack was provided for syngas dumping during startup, shutdown, etc. This 

flare stack eliminates the need for a separate Claus plant flare.

3.1.11 Slag and Ash Handling

The slag handling system for slagging gasifiers, operating above the ash fusion temperature, is 

discussed in this section, specifically the Shell SCGP, Siemens SFG, and CoP gasification 

technologies. The non-slagging TRIGTM gasifier operates below the ash fusion temperature and 

most of the entrained ash is captured by a disengager and cyclone and recycled back to the 

gasifier to increase overall carbon conversion. Any remaining ash is removed by a high 

temperature high pressure barrier filter and continuously cooled and removed for possible reuse 

or disposal. Once the ash is separated and processed, the material handling is similar to that 

described for slagging gasifiers below.

The slag handling system conveys, stores, and disposes of slag removed from the gasification 

process. Spent material drains from the gasifier bed into a water bath in the bottom of the 

gasifier vessel. A slag crusher receives slag from the water bath and grinds the material into peasized fragments. A slag/water slurry that is between 5 and 10 percent solids leaves the gasifier 

pressure boundary, generally through the use of lockhoppers, to a series of dewatering bins.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

81

The general aspects of slag handling are the same for all slagging gasifier technologies. The slag 

is dewatered, the water is clarified and recycled and the dried slag is transferred to a storage area 

for disposal. The specifics of slag handling vary among different 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 enter 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.

3.1.12 Power Island

Combustion Turbine 

The GT 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 (IGVs). 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 near term

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 FOAK applications, process contingencies were included in the cost 

estimates as described in Section 2.6. Performance typical of an advanced F class turbine on 

natural gas at ISO conditions is presented in Exhibit 3-13. 

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.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

82

Exhibit 3-13 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)

Combustion Turbine Package scope of Supply

The CT is typically supplied in several fully shop fabricated modules, complete with mechanical, 

electrical and control systems as required for CT operation. Site CT installation involves module 

interconnection, and linking CT modules to the plant systems.

CT Firing Temperature Control Issue for Low Calorific Value Fuel

A CT when fired on low calorific value (LCV) syngas has the potential to increase power output 

due to the increase in flow rate through the turbine. The higher turbine flow and moisture 

content of the combustion products can contribute to overheating of turbine components, affect 

rating criteria for the parts lives, and require a reduction in syngas firing temperatures (compared 

to the natural gas firing) to maintain design metal temperature [67]. 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. 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 nitrogen injection.

Combustion Turbine Syngas Fuel Requirements 

Typical fuel specifications and contaminant levels for successful CT operation are provided in 

reference [68] and presented for F Class machines in Exhibit 3-14 and Exhibit 3-15. 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 these cases.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

83

Exhibit 3-14 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 [69].

2. To ensure that the fuel gas supply to the CT is 100 percent free of liquids the 

minimum fuel gas temperature must meet the required superheat over the respective 

dew point. This requirement is independent of the hydrocarbon and moisture 

concentration. Superheat calculation shall be performed as described in 

GEI-4140G [68]. 

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.

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 6 percent of the compressor air is extracted and 

integrated with the air supply of the ASU in non-carbon capture cases. It may be technically 

possible to integrate the CT and ASU in CO2 capture cases as well; however, in this study 

integration was not recommended by the CT vendor and is considered only for non-carbon 

capture cases.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

84

Exhibit 3-15 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 = 281 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 Total2 600 30 7.2 2.4

Above 10 microns 6 0.3 0.072 0.024

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 CT gas fuel system

A high level analysis on the alkalinity of the coals, particularly the high sodium lignite coal, 

indicated that if all the sodium and potassium in the coal was partitioned to the gas phase and 

passed through the gas cleanup, the fuel would not meet the specified limits for the CT. For 

plants firing high alkali coals, quench cooling is preferable to syngas coolers to avoid any

potential fouling problems. Sodium, in the form of sodium hydroxide, is converted mainly into 

sodium chloride or sodium carbonate when leaving the reactor, and can cause fouling on heat 

exchangers until the syngas is cooled below the respective melting points of 800o

C and 850oC. 

The highly soluble species, such as the alkali salts, are removed in any water scrubbing or 

knockout (KO) drums and should not cause any limitations on the CT.

Pressurized syngas is combusted in several (14) parallel diffusion combustors and syngas 

dilution is used to limit NOx formation. As described in Section 3.1.4 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 4.2-4.8 MJ/Nm3 (115-132 Btu/scf). In the cases discussed in 

this report, nitrogen dilution alone was sufficient for all cases except S2B, which required 

humidification. 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, particularly in 

the high-hydrogen (CO2 capture) cases.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

85

Disadvantages to using nitrogen as the primary diluent include:

• Significant auxiliary power is still required to further compress the large nitrogen flow 

from the ASU pressure to the GT pressure.

• The low quality heat, which is saved from avoiding 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 Volume 1 of this series of reports.

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 593°C (1,100°F) for non-CO2 capture cases and 566°C (1,050°F) for capture cases. 

Gross turbine power, as measured prior to the generator terminals, is 232 MW at ISO conditions. 

Turbine output is reduced at the elevated sites for this study because the compressor capacity on 

a mass flow basis is reduced because of the reduced ambient air density. The CT generator is a 

standard hydrogen-cooled machine with static exciter.

3.1.13 Steam Generation Island

Heat Recovery Steam Generator 

The HRSG is a horizontal flow, drum-type, multi-pressure design that is matched to the 

characteristics of the CT exhaust when firing medium-Btu syngas. 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) in all 

IGCC cases.

The HP drum produces steam at main steam pressure, while the IP drum produces process steam 

and turbine dilution steam, if required. The HRSG drum pressures are nominally 12.4/2.9 MPa 

(1800/420 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 FW heating, and also provides deaeration of the condensate.

Natural circulation of steam is accomplished in the HRSG by utilizing differences in densities 

due to temperature differences of the steam. The natural circulation HRSG provides the most 

cost-effective and reliable design.

The HRSG drums include moisture separators, internal baffles, and piping for FW/steam. All 

tubes, including economizers, superheaters, and headers and drums, are equipped with drains.

Safety relief valves are furnished in order to comply with appropriate codes and ensure a safe 

work place.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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Superheater, boiler, and economizer sections are supported by shop-assembled structural steel. 

Inlet and outlet duct is provided to route the gases from the CT outlet to the HRSG inlet and the 

HRSG outlet to the stack. A diverter valve is included in the inlet duct to bypass the gas when 

appropriate. Suitable expansion joints are also included.

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.

Main steam from the HRSG and gasifier island is combined in a header, and then passes through 

the stop valves and control valves and nominally enters the turbine at either 12.4 MPa/566°C 

(1800 psig/1050°F) for the non-carbon capture cases, or 12.4 MPa/538°C (1800 psig/1000°F) for 

the carbon capture cases. The steam initially enters the turbine near the middle of the HP span, 

flows through the turbine, and returns to the HRSG for reheating. The reheat steam flows 

through the reheat stop valves and intercept valves and enters the IP section at 3.2 MPa/566°C 

(467 psia/1050°F) for the non-carbon capture cases or 3.2 MPa/538°C (467 psia/1000°F) for the 

carbon capture cases. After passing through the IP section, the steam enters a crossover pipe, 

which transports the steam to the LP section. The steam divides into two paths and flows 

through the LP sections, exhausting downward into the condenser.

Turbine bearings are lubricated by a CL, water-cooled, pressurized oil system. The oil is 

contained in a reservoir located below the turbine floor. During startup or unit trip an emergency 

oil pump mounted on the reservoir pumps the oil. When the turbine reaches 95 percent of 

synchronous speed, the main pump mounted on the turbine shaft pumps oil. The oil flows 

through water-cooled heat exchangers prior to entering the bearings. The oil then flows through 

the bearings and returns by gravity to the lube oil reservoir.

Turbine shafts are sealed against air in-leakage or steam blowout using a modern positive 

pressure variable clearance shaft sealing design arrangement connected to a LP steam seal 

system. During startup, seal steam is provided from the main steam line. As the unit increases 

load, HP turbine gland leakage provides the seal steam. Pressure-regulating valves control the 

gland header pressure and dump any excess steam to the condenser. A steam packing exhauster 

maintains a vacuum at the outer gland seals to prevent leakage of steam into the turbine room. 

Any steam collected is condensed in the packing exhauster and returned to the condensate 

system.

The generator is a hydrogen-cooled synchronous type, generating power at 24 kilovolt (kV). A 

static, transformer type exciter is provided. The generator is cooled with a hydrogen gas 

recirculation system using fans mounted on the generator rotor shaft. The heat absorbed by the 

gas is removed as it passes over finned tube gas coolers mounted in the stator frame. Gas is 

prevented from escaping at the rotor shafts by a CL oil seal system. The oil seal system consists 

of storage tank, pumps, filters, and pressure controls, all skid-mounted.

The STG is controlled by a triple-redundant, microprocessor-based electro-hydraulic control 

system. The system provides digital control of the unit in accordance with programmed control 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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algorithms, operator display interfacing, and datalink interfaces to the balance-of-plant 

distributed control system (DCS), and incorporates on-line repair capability.

Condensate System

The function of the condensate system is to pump condensate from both the air-cooled and 

water-cooled condensers to the deaerator, through the gland steam condenser and the lowtemperature economizer section in the HRSG. 

Feedwater System

The function of the FW system is to pump the various FW streams from the deaerator storage

tank in the HRSG to the respective steam drums. Two 50 percent capacity boiler feed pumps 

(BFPs) 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 FW pumps are supplied with instrumentation to monitor and alarm on low oil pressure, or 

high bearing temperature. FW pump suction pressure and temperature are also monitored. In 

addition, the suction of each BFP is equipped with a startup strainer.

Cooling Systems

Exhaust steam from the steam turbine is split 50/50 to a surface condenser cooled with cooling 

water and to an air-cooled condenser using ambient air and forced convection. A decision to use 

a parallel wet/dry cooling system to reduce the plant water requirement was based primarily on 

the recently completed Xcel Energy Comanche 3 PC plant, which uses such a system. Parallel 

cooling has less of a performance impact on combined cycle systems than on PC systems; and 

with the relatively low ambient temperature, the performance impact from the parallel cooling, 

as compared to wet cooling, is minor.

The major impact of parallel cooling is a significant reduction in water requirement when 

compared to a wet cooling system. This impact is included in the water balance presented later 

in this report.

With this cooling system and the specific ambient temperature, a condenser pressure of 0.005 

MPa (0.698 psia) (condensing temperature of 32°C [90°F]) is used in the model as compared to 

0.007 MPa (0.983 psia) (condensing temperature of 38°C [101°F]) used in Volume 1 of this 

series.

The circulating water system is a closed-cycle cooling water system that supplies cooling water 

to the surface condenser to condense one-half of 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 CL process that utilizes a higher quality water to remove heat 

from compressor intercoolers, oil coolers and other ancillary equipment and transfers that heat to 

the main circulating cooling water system in plate and frame heat exchangers. The heat 

transferred to the circulating water in the surface condenser and other applications is removed by 

a mechanical draft cooling tower.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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The system consists of two 50 percent capacity vertical circulating water pumps (CWP), a 

mechanical draft evaporative cooling tower, and CS cement-lined interconnecting piping. The 

pumps are single-stage vertical pumps. The piping system is equipped with butterfly isolation 

valves and all required expansion joints. The cooling tower is a multi-cell wood frame 

counterflow mechanical draft cooling tower.

The water-cooled surface 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 air-cooled condenser utilizes ambient air and forced convection 

across tube bundles to condense the balance of the turbine exhaust steam.

Both condensers are 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.

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 WGS reactors in CO2 capture cases, and for 

injection steam to the auxiliary boiler for control of NOx emissions, if required.

The cycle makeup system consists of two 100 percent trains, for redundancy, each with a fullcapacity activated carbon filter, primary cation exchanger, primary anion exchanger, mixed bed 

exchanger, recycle pump, and regeneration equipment. The equipment is skid-mounted and 

includes a control panel and associated piping, valves, and instrumentation.

3.1.14 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.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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3.1.15 Instrumentation and Control

An integrated plant-wide distributed control system (DCS) is provided. The DCS is a redundant

microprocessor-based, functionally DCS. The control room houses an array of multiple video 

monitor and keyboard units. The DCS incorporates plant monitoring and control functions for 

all the major plant equipment. 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 high speed redundant 

microprocessor to execute calculations and dynamic controls. 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.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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3.2 SHELL COAL GASIFICATION PROCESS IGCC CASES

This section contains an evaluation of plant designs for Cases S1A, S1B, L1A, and L1B, which 

are based on the SCGP. The non-capture (A) and CO2 capture (B) cases are very similar in 

terms of process, equipment, scope and arrangement, except that CO2 capture cases include SGS

reactors, CO2 absorption/regeneration and compression/transport systems. 

Section 3.2.4 covers the results for the S1A and L1A non-capture case using PRB and lignite

coal and Section 3.2.8 covers the S1B and L1B CO2-capture cases. The sections are organized 

analogously as follows:

• Process and System Description provides an overview of the specific technology’s

operation.

• Block flow diagram (BFD) and stream table display results for major processes and 

streams

• Performance Results provides the main modeling results, including the performance 

summary, environmental performance, carbon balance, sulfur balance, water balance, 

mass and energy balance diagrams, and mass and energy balance tables.

• Equipment List provides an itemized list of major equipment with account codes that 

correspond to the cost accounts in the Cost Estimates section.

• Cost Estimates provides a summary of capital and operating costs.

Process and System Description, Performance Results, Equipment List and Cost Estimates are 

repeated for the CO2 capture cases in Section 3.2.8. If the information is identical to that 

presented for the non-capture cases, a reference is made to the earlier section rather than 

repeating the information.

3.2.1 Gasifier Background

Development and Current Status – Development of the Shell gasification process for partial 

oxidation of oil and gas began in the early 1950s. More than 75 commercial Shell partialoxidation plants have been built worldwide to convert a variety of hydrocarbon liquids and gases 

to carbon monoxide and hydrogen.

Shell Internationale Petroleum Maatschappij B.V. began work on coal gasification in 1972. The 

coal gasifier is significantly different than the oil and gas gasifiers developed earlier. A 

pressurized, entrained-flow, slagging coal gasifier was built at Shell’s Amsterdam laboratories. 

This 5 tonnes/day (6 tpd) process development unit has operated for approximately 12,000 hrs 

since 1976. A larger 150 tonnes/day (165 tpd) pilot plant was built at Shell’s Hamburg refinery 

in Hamburg, Germany. This larger unit operated for approximately 6,000 hrs from 1978 to 

1983, and successfully gasified over 27,200 tonnes (30,000 tons) of coal.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

91

Based on the experience it gained with the Hamburg unit, Shell built a demonstration unit at its 

oil refinery and chemical complex in Deer Park, Texas, near Houston. This new unit, commonly 

called SCGP-1 (for Shell Coal Gasification Plant-1), was designed to gasify bituminous coal at 

the rate of 230 tonnes/day (250 tpd) and to gasify high-moisture, high-ash lignite at the rate of 

360 tonnes/day (400 tpd). The relatively small difference in size between the Hamburg and Deer 

Park units reflects design changes and improvements.

The Deer Park demonstration plant operated successfully after startup in July 1987. Before the 

end of the program in 1991, after 15,000 hours of operation, 18 different feedstocks were 

gasified at the plant, including domestic coals ranging from lignite to high-sulfur bituminous, 

three widely traded foreign coals, and petroleum coke. The Deer Park unit produced superheated 

HP steam in the waste heat recovery boiler. The plant also had facilities for extensive 

environmental monitoring and for sidestream testing of several AGR processes, including 

Sulfinol-D, Sulfinol-M, highly loaded MDEA, and various wastewater treatment schemes.

In spring 1989, Shell announced that its technology had been selected for the large commercialscale Demkolec B.V. IGCC plant at Buggenum, near Roermond, in The Netherlands. This plant 

generates 250 MW of IGCC electricity with a single Shell gasifier consuming 1,800 tonnes/day 

(2,000 tpd) (dry basis) of coal. The plant was originally owned and operated by Samenwerkende 

Electriciteits-Productiebedrijven NV (SEP), a consortium of Dutch 

utilities, and began operation in 1994. In 2000 the plant was 

purchased by Nuon. Shell was extensively involved in the design, 

startup, and initial operation of this plant. A key feature of this IGCC

design is the use of extraction air from the CT air compressor to feed 

the oxygen plant.

Gasifier Capacity – The large gasifier operating at the Buggenum 

plant in the Netherlands has a bituminous coal-handling capacity of 

1,630 tonnes/day (1,800 tpd) and produces dry gas at a rate of 158,580

normal cubic meter per hour (Nm3

/hr) (5.6 million standard cubic feet 

per hour [scf/hr]) with an energy content of about 1,790 million 

kilojoules per hour (MMkJ/hr) (1,700 million British thermal units per 

hour [MMBtu/hr]) (HHV). This gasifier was sized to match the fuel 

gas requirements for the Siemens/Kraftwerk Union V-94.2 CT and 

could easily be scaled up to match advanced F Class turbine 

requirements, requiring one gasifier for each CT.

Distinguishing Characteristics – The SCGP uses a dry feed, entrained flow, slagging, single 

stage, up-flow gasifier to produce syngas at HPs and temperatures. The gasifier uses a 

membrane wall design to control the reactor vessel wall temperature, increasing operational 

flexibility. The dry feeding system helps achieve high carbon conversion and higher cold gas 

efficiencies compared to slurry fed systems. Multiple burner design allows a wider range of 

gasifier scalability. The syngas outlet is separated from the slag outlet allowing the application 

of higher ash coals proven with up to 30 percent ash content in the burner feed. The Shell 

process also uses a gas quench at the gasifier outlet to further mitigate problems associated with 

any remaining sticky fly ash/slag particulates.
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Entrained-flow slagging gasifiers have fundamental environmental advantages over fluidizedbed and moving-bed gasifiers without a slagging area. They produce no hydrocarbon liquids, 

and the only solid waste is an inert slag. The dry feed entrained-flow gasifiers also have minor 

environmental advantages over the slurry feed entrained-flow gasifiers. They produce a higher 

H2S/CO2 ratio acid gas, which improves sulfur recovery and lessens some of the gray water 

processing and the fixed-salts blowdown problems associated with slurry feeding.

The ability to feed dry solids minimizes the oxygen requirement and makes the Shell gasifier 

somewhat more efficient than entrained flow gasifiers employing slurry feed systems. The 

penalty paid for this increase in efficiency is a coal feed system that is more costly and 

operationally more complex. The SCGP produces a high temperature syngas, with very little 

methane, and uses high temperature synthesis gas coolers (SGC) to recover a large amount of 

this heat. The high gasification temperatures improve operational reliability by reducing the 

amount of tars exiting the gasifier. The high operating temperature produced by all entrainedflow slagging processes can result in relatively high capital and maintenance costs, but can be 

partially avoided by adding different syngas cooling schemes such as a water quench, as in the 

CO2 capture cases, where the reduction in heat recovery is mitigated by the shift steam 

requirement downstream. Shell's gasifier also employs a cooled membrane wall to help control 

gasifier temperature, which requires fewer changeouts than an uncooled refractory. Buggenum 

operating experience has confirmed that one yearly maintenance turnaround is sufficient to 

achieve high reliability plant operation.

Important Coal Characteristics – One main consideration for coal-fired in the Shell gasifier is

the ash characteristics. The ash content has to be minimum 8 wt% on burner feed and can be 

adjusted using slag and ash recycle or fresh ash (as needed). The syngas outlet is separated from 

slag outlet allowing application of higher ash coals - up to 30 percent ash content in burner feed 

is proven. A wide variety of different coals have been tested on the Shell gasifier, including 

lignite. High-ash fusion-temperature coals may require flux addition for optimal gasifier 

operation. The ash content, fusion temperature, and composition affect the required gasifier 

operating temperature level, oxygen requirements, slag and ash management. Solids handling 

requirements (coal, slag and ash) impact maintenance needs. 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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3.2.2 Key System Assumptions

System assumptions for Cases S1A and L1A and S1B and L1B, SCGP IGCC using PRB and

lignite coal with and without CO2 capture, are compiled in Exhibit 3-16.

Exhibit 3-16 Case S1A/L1A and S1B/L1B Plant Study Configuration Matrix

Case S1A / L1A S1B / L1B

Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O2:Coal Ratio, kg O2/kg dry coal 0.780 / 0.736 0.773 / 0.736

Carbon Conversion, % 99.5 99.5

Syngas HHV at Gasifier Outlet, 

kJ/Nm3 (Btu/scf) 10,389 (279) / 9,384 (252) 10,476 (281) / 9,397 (252)

Nominal Steam Cycle, MPa/°C/°C 

(psig/°F/°F)

12.4/566/566 

(1800/1050/1050)

12.4/538/538 

(1800/1000/1000)

Condenser Pressure, mm Hg

(in Hg) 36 (1.4) 36 (1.4)

Combustion Turbine

2x Advanced F Class 

(Nominal 232 MW output 

each, reduced by elevation 

considerations)

2x Advanced F Class 

(Nominal 232 MW output 

each, reduced by elevation 

considerations)

Gasifier Technology Shell (SCGP) Shell (SCGP)

Oxidant 95 vol% Oxygen 95 vol% Oxygen

Coal Subbituminous / Lignite Subbituminous / Lignite

Coal Feed Moisture Content, % 6 / 12 6 / 12

COS Hydrolysis Yes Yes (Part of WGS)

Water Gas Shift No Yes

H2S Separation Sulfinol-M Selexol (1st Stage)

Sulfur Removal, % 99.9 99.7

CO2 Separation None Selexol (2nd Stage)

CO2 Removal, % N/A 90

Sulfur Recovery

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Particulate Control

Cyclone, Candle Filter, 

Scrubber, and AGR 

Absorber

Cyclone, Candle Filter, 

Scrubber, and AGR 

Absorber

Mercury Control Carbon Bed Carbon Bed

NOx Control MNQC (LNB) and N2

Dilution 

MNQC (LNB) and N2

Dilution
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Balance of Plant – All Cases

The balance of plant assumptions are common to all cases and are presented in Exhibit 3-17.

Exhibit 3-17 Balance of Plant Assumptions

Cooling water system Recirculating Wet Cooling Tower

Fuel and Other storage

Coal 30 days

Slag 30 days

Sulfur 30 days

Sorbent 30 days

Plant Distribution Voltage

Motors below 1 hp 110/220 volt

Motors between 1 hp and 

250 hp 480 volt

Motors between 250 hp and 

5,000 hp 4,160 volt

Motors above 5,000 hp 13,800 volt

Steam and CT Generators 24,000 volt

Grid Interconnection Voltage 345 kV

Water and Waste Water

Makeup Water

The water supply is 50 percent from a local POTW

and 50 percent from groundwater, and is assumed to 

be in sufficient quantities to meet plant makeup 

requirements.

Makeup for potable, process, and de-ionized (DI) 

water is drawn from municipal sources.

Process Wastewater

Water associated with gasification activity and storm 

water that contacts equipment surfaces is collected 

and treated for discharge through a permitted 

discharge.

Sanitary Waste Disposal

Design includes a packaged domestic sewage 

treatment plant with effluent discharged to the 

industrial wastewater treatment system. Sludge is 

hauled off site. Packaged plant was sized for 5.68 

cubic meters per day (1,500 gallons per day)

Water Discharge

Most of the process wastewater is recycled to the

cooling tower basin. Blowdown is treated for 

chloride and metals, and discharged.
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3.2.3 Sparing Philosophy

The sparing philosophy is provided below. Single trains are utilized throughout with exceptions 

where equipment capacity requires an additional train. There is no redundancy other than 

normal sparing of rotating equipment.

The plant design consists of the following major subsystems:

• Two ASUs (2 x 50%).

• Two trains of coal drying and dry feed systems (2 x 50%).

• Two trains of gasification, including gasifier, SGC, cyclone, and barrier filter (2 x 50%). 

• Two trains of syngas clean-up process (2 x 50%).

• Two trains of Sulfinol-M acid gas removal in non-capture cases and two trains of twostage Selexol in CO2 capture cases (2 x 50%).

• One train of Claus-based sulfur recovery (1 x 100%).

• Two CT/HRSG tandems (2 x 50%).

• One steam turbine (1 x 100%).

3.2.4 SCGP IGCC Non-Capture Case (S1A and L1A) Process Description

In this section the overall SCGP for Case S1A and L1A is described. The process does not 

change with fuel type so a single description is provided. The system description follows the 

BFD in Exhibit 3-18 and stream numbers reference the same exhibit. The tables in Exhibit 3-19

and Exhibit 3-20 provide process data for the numbered streams in the BFD.

Coal Preparation and Feed Systems

Coal receiving and handling is common to all cases and was covered in Section 3.1.1. The 

receiving and handling subsystem ends at the coal silo. The Shell process uses a dry feed system 

which is sensitive to the coal moisture content. Coal moisture consists of two parts, surface 

moisture and inherent moisture. For coal to flow smoothly through the lock hoppers, the surface 

moisture must be removed. The PRB coal used in this study contains 25.77 percent total 

moisture on an as-received basis and the NDL contains 36.08 percent moisture. It was assumed 

that the PRB coal must be dried to 6 percent moisture and the lignite to 12 percent to allow for 

smooth flow through the dry feed system; however, fluidization tests would need to be 

completed on actual coal samples for actual design and operation.

The raw coal is crushed in the coal mill then delivered to a surge hopper with an approximate 2-

hour capacity, which in turn delivers the coal to the coal pre-heater. The WTA coal drying 

process includes a water-heated, horizontal, rotary-kiln coal pre-heater, a fluidized bed coal dryer 

and a water-cooled, horizontal, rotary-kiln coal cooler. The moisture driven from the coal in the 

fluid bed dryer passes through a baghouse for particulate removal and then is split into two 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

96

streams. The smaller of the two streams is compressed and used as the fluidizing medium in the 

coal dryer. The bulk of the removed moisture is compressed and the high temperature vapor 

passes through internal coils in the dryer to provide the heat to drive off the coal moisture and 

then exits the dryer as liquid water. The warm water is used in the coal pre-heater before being 

used as cooling tower makeup water. The vapor compressor consumes the vast majority of the 

WTA process auxiliary load.

The coal is drawn from the surge hoppers and fed through a pressurization lock hopper system to 

a dense phase pneumatic conveyor, which uses nitrogen from the ASU to convey the coal to the 

gasifiers.

Gasifier

There are two Shell dry feed, pressurized, up flow, entrained, slagging gasifiers, operating at 

4.24 MPa (615 psia) and processing a total of 5,908 tonne/day (6,513 tpd) of as-received coal in 

the PRB case and 8,274 tonne/day (9,121 tpd) in the lignite case. Coal reacts with oxygen in a 

reducing environment to produce principally hydrogen and carbon monoxide with little CO2 

formed. 

Raw Gas Cooling/Particulate Removal

High-temperature heat recovery in each gasifier train is accomplished in three steps, including 

the gasifier membrane wall, which maintains a protective ash layer over the membrane wall and 

thus permits the reaction temperature of roughly 1400°C (2,550°F). The product gas from the 

gasifier is cooled using a syngas recycle quench to lower the temperature below the ash melting 

point. Syngas then goes through a raw gas cooler, which lowers the gas temperature to a 

minimum of 230°C (450°F), and contributes to the production of HP steam for use in the steam 

cycle.

The solids are removed as slag and as ash. Liquid slag is solidified in a water bath and removed 

via a lock hopper system. Ash carried over with the syngas is removed in a ceramic candle filter.

The ash is removed similarly via a lock hopper system. Cyclones can be implemented in specific 

designs depending on plant size and coal operating characteristics. The syngas scrubber removes 

any possibility of remaining PM passing the candle filter further downstream, by protecting 

against leakage from the filter seals or any undetected candle breakage that would allow large 

particulates into the scrubber.

Syngas Scrubber/Sour Water Stripper

The raw synthesis gas exiting the ceramic particulate filter enters the scrubber for removal of 

chlorides and any remaining particulates. The quench scrubber washes the syngas in a countercurrent flow in two packed beds. The quench scrubber removes essentially all traces of entrained 

particles, principally unconverted carbon, slag, and metals. The bottoms from the scrubber are 

sent to the slag removal and handling system for processing.

The sour water stripper removes ammonia, sulfur, and other impurities from the waste stream of 

the scrubber. The sour gas stripper consists of a sour drum that accumulates sour water from the 

gas scrubber and condensate from SGCs. Sour water from the drum flows to the sour stripper, 

which consists of a packed column with a steam-heated reboiler. Sour gas is stripped from the 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

97

liquid and sent to the SRU. Part of the stripper water is sent to wastewater treatment, avoiding 

accumulation of salts, to be reused in the scrubber section.

COS Hydrolysis, Mercury Removal and AGR

H2S and COS are at significant concentrations, requiring removal for the power plant to achieve 

the low design level of SO2 emissions. H2S is removed in an AGR process; however, because 

COS is not readily removed, it is first catalytically converted to H2S in a COS hydrolysis unit.

Following the water scrubber, the gas is fed to the COS hydrolysis reactor at above 177°C 

(350°F). The COS in the sour gas is hydrolyzed with steam over a catalyst bed to H2S, which is 

more easily removed by the AGR solvent. Before the raw fuel gas can be treated in the AGR 

process, it must be cooled to about 35°C (95°F). During this cooling through a series of heat 

exchangers, part of the water vapor condenses. This water, which contains some NH3, is sent to 

the sour water stripper. The cooled syngas then passes through a carbon bed to remove 95 

percent of the Hg (Section 3.1.8).

The Sulfinol process, developed by Shell in the early 1960s, is a combination process that uses a 

mixture of amines and a physical solvent. The solvent consists of an aqueous amine and 

sulfolane. Sulfinol-D uses DIPA, while Sulfinol-M uses MDEA. The mixed solvents allow for 

better solvent loadings at high acid gas partial pressures and higher solubility of COS and 

organic sulfur compounds than straight aqueous amines. Sulfinol-M was selected for the Shell

non-CO2 capture applications. 

The sour syngas is fed directly into an HP contactor. The HP contactor is an absorption column 

in which the H2S, COS, CO2, and small amounts of H2 and CO are removed from the gas by the 

Sulfinol solvent. The overhead gas stream from the HP contactor is then washed with water in 

the sweet gas scrubber before leaving the unit as the feed gas to the sulfur polishing unit.

The rich solvent from the bottom of the HP contactor flows through a hydraulic turbine and is 

flashed in the rich solvent flash vessel. The flashed gas is then scrubbed in the LP contactor with 

lean solvent to remove H2S and COS. The overhead from the LP contactor is flashed in the LP 

KO drum. This gas can be used as a utility fuel gas, consisting primarily of H2 and CO, at 

0.8 MPa (118 psia) and 38°C (101°F). The solvent from the bottom of the LP contactor is 

returned to the rich solvent flash vessel.

Hot, lean solvent in the lean/rich solvent exchanger then heats the flashed rich solvent before 

entering the stripper. The stripper strips the H2S, COS, and CO2 from the solvent at LP with heat 

supplied through the stripper reboiler. The acid gas stream to sulfur recovery/tail gas cleanup is 

recovered as the flash gas from the stripper accumulator. The lean solvent from the bottom of 

the stripper is cooled in the lean/rich solvent exchanger and the lean solvent cooler. Most of the 

lean solvent is pumped to the HP contactor. A small amount goes to the LP contactor.

The Sulfinol process removes about 15 percent of the CO2 along with the H2S and COS. The 

acid gas is fed to the SRU. The residual CO2 passes through the SRU, the hydrogenation reactor 

and is recycled to the AGR. However, the costs of the sulfur recovery/tail gas cleanup are higher 

than for a sulfur removal process producing an acid gas stream with a higher sulfur 

concentration.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

98

Claus Unit

The SRU is a Claus bypass type SRU utilizing oxygen instead of air. The Claus plant produces 

molten sulfur by converting approximately one third of the H2S in the feed to SO2, then reacting 

the H2S and SO2 to sulfur and water. The combination of Claus technology and tail gas recycle 

results in an overall sulfur recovery exceeding 99 percent, producing 43 tonne/day (47 tpd) of 

sulfur in the PRB case and 52 tonne/day (57 tpd) in the lignite case. 

Utilizing oxygen instead of air in the Claus plant reduces the overall cost of the sulfur recovery 

plant. Feed for each case consists of acid gas from both the acid gas cleanup unit and a vent 

stream from the sour water stripper in the gasifier section.

In the furnace waste heat boiler steam is generated. This steam is used to satisfy all Claus 

process preheating and reheating requirements, as well as to provide some steam to the mediumpressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) steam for the LP

steam header.

Power Block

Clean syngas exiting the Sulfinol absorber is reheated, diluted with nitrogen from the ASU, and 

enters the advanced F Class CT burner. The CT compressor provides combustion air to the 

burner and a portion of the air requirement for the ASU. The exhaust gas exits the CT around

593°C (1,100°F) and enters the HRSG where additional heat is recovered until the flue gas exits 

the HRSG at 132°C (270°F) and is discharged through the plant stack. The steam raised in the 

HRSG is used to power an advanced, commercially available steam turbine using a nominal 12.4 

MPa/566°C/566°C (1800 psig/1050°F/1050°F) steam cycle.

Air Separation Unit

The ASU is designed to produce approximately 3,653 tonne/day (4,026 tpd) in the PRB case and 

4,150 tonne/day (4,574 tpd) in the lignite case of 95 mole percent (mol%) O2 for use in the 

gasifier and SRU. The plant is designed with two production trains. The air compressor is 

powered by an electric motor. Nitrogen is also recovered, compressed, and used as diluent in the 

CT combustor or as a coal transport fluid. Air extraction is taken from the CT compressor to 

reduce the size of the main air compressor.

Balance of Plant

Balance of plant items were covered in Sections 3.1.12, 3.1.13, 3.1.14, and 3.1.15.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

99

Exhibit 3-18 Case S1A and L1A Process Flow Diagram
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

100

Exhibit 3-19 Case S1A Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

V-L Mole Fraction

Ar 0.0093 0.0093 0.0291 0.0318 0.0023 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0000 0.0104 0.0104 0.0104

CH4 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 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.5994 0.5994 0.5994

CO2 0.0003 0.0003 0.0102 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0335 0.0335 0.0335

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 0.0005 0.0005 0.0005

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 0.2593 0.2593 0.2593

H2O 0.0064 0.0064 0.1937 0.0000 0.0002 0.0002 0.0000 0.0000 0.0000 1.0000 0.0000 0.0000 0.0309 0.0309 0.0309

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0030 0.0030 0.0030

N2 0.7759 0.7759 0.5163 0.0178 0.9920 0.9920 0.0178 0.0000 0.0000 0.0000 0.0000 0.0000 0.0607 0.0607 0.0607

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0022 0.0022 0.0022

O2 0.2081 0.2081 0.2507 0.9504 0.0054 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 20,415 2,522 736 46 16,606 866 4,684 0 0 2,874 0 0 16,119 7,423 16,119

V-L Flowrate (kg/hr) 589,886 72,887 20,300 1,466 465,982 24,300 150,725 0 0 51,774 0 0 348,649 160,563 348,649

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 246,170 0 194,396 20,772 0 0 0

Temperature (°C) 6 411 21 32 196 195 32 --- 6 33 71 1,454 1,454 245 232

Pressure (MPa, abs) 0.09 1.43 0.11 0.86 2.65 5.62 0.86 --- 0.09 0.55 0.09 4.24 4.24 4.24 3.96

Enthalpy (kJ/kg)A 15.26 434.33 40.10 26.67 202.63 199.69 26.67 --- --- 140.14 --- --- 2,292.13 400.31 382.35

Density (kg/m3) 1.1 7.2 1.6 11.0 18.9 39.8 11.0 --- --- 985.3 --- --- 6.3 21.0 20.1

V-L Molecular Weight 28.895 28.895 27.587 32.181 28.061 28.061 32.181 --- --- 18.015 --- --- 21.630 21.630 21.630

V-L Flowrate (lbmol/hr) 45,007 5,561 1,622 100 36,610 1,909 10,326 0 0 6,336 0 0 35,537 16,366 35,536

V-L Flowrate (lb/hr) 1,300,475 160,689 44,754 3,232 1,027,315 53,571 332,292 0 0 114,143 0 0 768,639 353,981 768,639

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 542,713 0 428,570 45,794 0 0 0

Temperature (°F) 42 771 70 90 385 383 90 --- 42 92 160 2,650 2,650 473 450

Pressure (psia) 13.0 207.6 16.4 125.0 385.0 815.0 125.0 --- 13.0 80.1 12.7 614.7 614.7 615.0 574.7

Enthalpy (Btu/lb)A 6.6 186.7 17.2 11.5 87.1 85.9 11.5 --- --- 60.2 --- --- 985.4 172.1 164.4

Density (lb/ft3) 0.070 0.452 0.097 0.687 1.183 2.485 0.687 --- --- 61.510 --- --- 0.396 1.311 1.257

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

101

Exhibit 3-19 Case S1A Stream Table (Continued)

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31

V-L Mole Fraction

Ar 0.0098 0.0108 0.0091 0.0107 0.0008 0.0000 0.0063 0.0109 0.0109 0.0093 0.0091 0.0091 0.0000 0.0000 0.0000 0.0000

CH4 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 0.0000 0.0000

CO 0.5639 0.6178 0.0027 0.6103 0.0299 0.0000 0.0649 0.6182 0.6182 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0319 0.0350 0.4801 0.0406 0.4222 0.0000 0.2729 0.0354 0.0354 0.0003 0.0832 0.0832 0.0000 0.0000 0.0000 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 0.0000 0.0000 0.0000

H2 0.2440 0.2673 0.1276 0.2656 0.0142 0.0000 0.0298 0.2690 0.2690 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0879 0.0030 0.0323 0.0030 0.0224 0.0000 0.3822 0.0028 0.0028 0.0064 0.0396 0.0396 1.0000 1.0000 1.0000 1.0000

H2S 0.0033 0.0036 0.0041 0.0036 0.2650 0.0000 0.0014 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0571 0.0625 0.3441 0.0661 0.2455 0.0000 0.2410 0.0637 0.0637 0.7759 0.7583 0.7583 0.0000 0.0000 0.0000 0.0000

NH3 0.0021 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 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2081 0.1098 0.1098 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 17,135 15,640 200 15,834 213 0 285 15,621 15,621 100,352 123,127 123,127 34,784 18,472 18,472 37,460

V-L Flowrate (kg/hr) 366,944 340,056 6,431 346,380 7,634 0 7,966 338,746 338,746 2,899,687 3,631,528 3,631,528 626,641 332,787 332,787 674,848

Solids Flowrate (kg/hr) 0 0 0 0 0 1,788 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 177 35 49 37 40 176 138 42 196 6 589 132 561 32 32 33

Pressure (MPa, abs) 3.79 3.69 0.32 3.62 0.4 0.370 0.370 3.597 3.563 0.090 0.093 0.090 12.512 0.005 0.005 0.827

Enthalpy (kJ/kg)A 426.53 45.20 93.62 44.60 54.4 --- 780.053 55.279 271.387 15.260 694.591 195.610 3,502.487 2,306.994 2,306.994 140.562

Density (kg/m3) 21.6 31.3 3.9 30.8 5.8 5,284.2 3.0 29.7 19.6 1.1 0.4 0.8 35.1 0.04 0.04 995.0

V-L Molecular Weight 21.415 21.742 32.185 21.876 36 --- 27.918 21.686 21.686 28.895 29.494 29.494 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 37,775 34,481 440 34,908 470 0 629 34,438 34,438 221,239 271,449 271,449 76,685 40,725 40,725 82,585

V-L Flowrate (lb/hr) 808,973 749,695 14,177 763,637 16,829 0 17,561 746,808 746,808 6,392,716 8,006,150 8,006,150 1,381,506 733,670 733,670 1,487,785

Solids Flowrate (lb/hr) 0 0 0 0 0 3,943 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 351 95 120 98 104 348 280 108 385 42 1,092 270 1,042 90 90 92

Pressure (psia) 549.7 534.7 46.5 524.7 60.0 53.6 53.6 521.7 516.7 13.0 13.5 13.0 1,814.7 0.7 0.7 120.0

Enthalpy (Btu/lb)A 183.4 19.4 40.3 19.2 23.4 --- 335.4 23.8 116.7 6.6 298.6 84.1 1,505.8 991.8 991.8 60.4

Density (lb/ft3) 1.345 1.952 0.242 1.920 0.362 329.882 0.190 1.853 1.221 0.070 0.024 0.049 2.192 0.002 0.002 62.115
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

102

Exhibit 3-20 Case L1A Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

V-L Mole Fraction

Ar 0.0093 0.0093 0.0293 0.0318 0.0023 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0000 0.0100 0.0100 0.0100

CH4 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 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.5272 0.5272 0.5272

CO2 0.0003 0.0003 0.0103 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0643 0.0643 0.0643

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 0.0004 0.0004 0.0004

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 0.2477 0.2477 0.2477

H2O 0.0062 0.0062 0.1878 0.0000 0.0002 0.0002 0.0000 0.0000 0.0000 1.0000 0.0000 0.0000 0.0801 0.0801 0.0801

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0032 0.0032 0.0032

N2 0.7761 0.7761 0.5200 0.0178 0.9920 0.9920 0.0178 0.0000 0.0000 0.0000 0.0000 0.0000 0.0658 0.0658 0.0658

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0014 0.0014 0.0014

O2 0.2082 0.2082 0.2525 0.9504 0.0054 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 20,814 5,237 830 38 18,733 1,116 5,335 0 0 5,237 0 0 19,089 6,742 19,089

V-L Flowrate (kg/hr) 601,490 151,347 22,953 1,225 525,667 31,304 171,673 0 0 94,342 0 0 418,721 147,880 418,721

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 344,772 0 250,430 34,686 0 0 0

Temperature (°C) 4 408 21 32 196 195 32 --- 4 32 71 1,371 1,371 245 232

Pressure (MPa, abs) 0.10 1.52 0.11 0.86 2.65 5.62 0.86 --- 0.10 0.34 0.09 4.24 4.24 4.24 3.96

Enthalpy (kJ/kg)A 13.75 431.19 40.37 26.67 202.62 199.68 26.67 --- --- 135.07 --- --- 2,286.86 499.79 482.15

Density (kg/m3) 1.2 7.7 1.5 11.0 18.9 39.8 11.0 --- --- 986.5 --- --- 6.8 21.4 20.5

V-L Molecular Weight 28.898 28.898 27.657 32.181 28.061 28.061 32.181 --- --- 18.015 --- --- 21.935 21.935 21.935

V-L Flowrate (lbmol/hr) 45,888 11,546 1,830 84 41,299 2,459 11,761 0 0 11,545 0 0 42,084 14,863 42,084

V-L Flowrate (lb/hr) 1,326,060 333,663 50,603 2,700 1,158,897 69,013 378,475 0 0 207,989 0 0 923,122 326,020 923,122

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 760,093 0 552,104 76,470 0 0 0

Temperature (°F) 40 767 70 90 385 383 90 --- 40 90 160 2,500 2,500 472 450

Pressure (psia) 13.8 220.4 16.4 125.0 385.0 815.0 125.0 --- 13.8 50.0 13.5 614.7 614.7 615.0 574.7

Enthalpy (Btu/lb)A 5.9 185.4 17.4 11.5 87.1 85.8 11.5 --- --- 58.1 --- --- 983.2 214.9 207.3

Density (lb/ft3

) 0.074 0.482 0.097 0.687 1.183 2.485 0.687 --- --- 61.584 --- --- 0.422 1.335 1.280

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

103

Exhibit 3-20 Case L1A Stream Table (Continued)

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31

V-L Mole Fraction

Ar 0.0097 0.0109 0.0045 0.0108 0.0005 0.0000 0.0038 0.0110 0.0110 0.0093 0.0090 0.0090 0.0000 0.0000 0.0000 0.0000

CH4 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 0.0000 0.0000

CO 0.5068 0.5728 0.0060 0.5620 0.0181 0.0000 0.0774 0.5734 0.5734 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0621 0.0702 0.6341 0.0813 0.5955 0.0000 0.4628 0.0706 0.0706 0.0003 0.0868 0.0868 0.0000 0.0000 0.0000 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 0.0000 0.0000 0.0000

H2 0.2381 0.2691 0.0982 0.2659 0.0093 0.0000 0.0161 0.2713 0.2713 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.1153 0.0016 0.0323 0.0016 0.0079 0.0000 0.2502 0.0015 0.0015 0.0062 0.0415 0.0415 1.0000 1.0000 1.0000 1.0000

H2S 0.0034 0.0038 0.0041 0.0038 0.1869 0.0000 0.0013 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0633 0.0715 0.2208 0.0745 0.1817 0.0000 0.1864 0.0722 0.0722 0.7761 0.7565 0.7565 0.0000 0.0000 0.0000 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 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 0.2082 0.1062 0.1062 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0018 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 19,855 17,568 352 17,910 367 0 417 17,543 17,543 106,961 130,591 130,591 39,860 19,306 19,306 39,167

V-L Flowrate (kg/hr) 432,511 391,337 12,445 403,595 14,075 0 13,601 389,520 389,520 3,090,914 3,854,769 3,854,769 718,096 347,804 347,804 705,610

Solids Flowrate (kg/hr) 0 0 0 0 0 2,157 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 177 35 49 35 40 176 138 42 196 4 589 132 561 32 32 33

Pressure (MPa, abs) 3.79 3.69 0.32 3.62 0.4 0.370 0.370 3.597 3.563 0.095 0.099 0.095 12.512 0.005 0.005 0.827

Enthalpy (kJ/kg)A 477.51 40.71 86.59 39.57 42.3 --- 490.944 51.058 265.393 13.748 697.962 198.353 3,502.136 2,321.555 2,321.555 140.358

Density (kg/m3) 22.0 32.1 4.3 32.0 6.2 5,283.3 3.6 30.5 20.0 1.2 0.4 0.8 35.1 0.04 0.04 995.0

V-L Molecular Weight 21.784 22.276 35.359 22.535 38 --- 32.625 22.204 22.204 28.898 29.518 29.518 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 43,772 38,731 776 39,484 809 0 919 38,675 38,675 235,808 287,903 287,903 87,877 42,563 42,563 86,349

V-L Flowrate (lb/hr) 953,523 862,751 27,437 889,774 31,030 0 29,986 858,744 858,744 6,814,298 8,498,311 8,498,311 1,583,131 766,778 766,778 1,555,604

Solids Flowrate (lb/hr) 0 0 0 0 0 4,756 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 350 95 120 94 104 349 280 108 385 40 1,092 270 1,042 90 90 92

Pressure (psia) 549.7 534.7 46.5 524.7 60.0 53.6 53.6 521.7 516.7 13.8 14.3 13.8 1,814.7 0.7 0.7 120.0

Enthalpy (Btu/lb)A 205.3 17.5 37.2 17.0 18.2 --- 211.1 22.0 114.1 5.9 300.1 85.3 1,505.6 998.1 998.1 60.3

Density (lb/ft3) 1.374 2.006 0.266 1.996 0.386 329.828 0.222 1.902 1.251 0.074 0.025 0.052 2.192 0.002 0.002 62.116
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

104

3.2.5 Case S1A and L1A Performance Results

The non-capture SCGP IGCC plant using PRB coal at the Montana site (elevation 3,400 ft)

produces a net output of 573 megawatt electric (MWe) at a net plant efficiency of 42.0 percent 

(HHV basis). The same plant configuration using lignite coal at the North Dakota site (elevation

1,900 ft) produces a net output of 617 MWe at a net plant efficiency of 41.8 percent (HHV 

basis). 

Overall performance for the plant is summarized in Exhibit 3-21, which includes auxiliary power 

requirements. The ASU accounts for approximately 74 percent of the total auxiliary load, 

distributed between the main air compressor, the oxygen compressor, the nitrogen compressor, 

and ASU auxiliaries. Coal handling and drying account for approximately 10 percent of the 

auxiliary load. The cooling water system, including the CWPs and cooling tower fan, and the 

air-cooled condenser account for about 5 percent of the auxiliary load. All other individual 

auxiliary loads are less than 3 percent of the total.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

105

Exhibit 3-21 Case S1A and L1A Plant Performance Summary

POWER SUMMARY (Gross Power at Generator 

Terminals, kWe) S1A L1A

Gas Turbine Power 423,900 449,400

Steam Turbine Power 272,800 303,200

TOTAL POWER, kWe 696,700 752,600

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 500 600

Coal Milling 2,530 3,550

Slag Handling 540 900

WTA Coal Dryer Compressor 8,680 12,120

WTA Coal Dryer Auxiliaries 570 800

Air Separation Unit Auxiliaries 1,000 1,000

Air Separation Unit Main Air Compressor 52,530 52,190

Oxygen Compressor 8,250 9,400

Nitrogen Compressors 30,220 34,460

Boiler Feedwater Pumps 3,890 4,450

Condensate Pump 220 230

Syngas Recycle Compressor 840 760

Circulating Water Pump 1,970 2,230

Ground Water Pumps 160 170

Cooling Tower Fans 1,280 1,370

Air Cooled Condenser Fans 3,230 3,210

Scrubber Pumps 10 90

Acid Gas Removal 260 450

Gas Turbine Auxiliaries 1,000 1,000

Steam Turbine Auxiliaries 100 100

Claus Plant/TGTU Auxiliaries 250 250

Claus Plant TG Recycle Compressor 540 920

Miscellaneous Balance of Plant1 3,000 3,000

Transformer Losses 2,450 2,650

TOTAL AUXILIARIES, kWe 124,020 135,900

NET POWER, kWe 572,680 616,700

Net Plant Efficiency, % (HHV) 42.0% 41.8%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,563 (8,116) 8,605 (8,156)

CONDENSER COOLING DUTY GJ/hr (106 Btu/hr) 1,445 (1,370) 1,519 (1,440)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 246,170 

(542,713)

344,772 

(760,093)

Thermal Input, kWt 1,362,134 1,474,011

Raw Water Withdrawal, m3/min (gpm) 6.8 (1,792) 7.1 (1,879)

Raw Water Consumption, m3/min (gpm) 5.1 (1,336) 5.2 (1,362) 1 Includes plant control systems, lighting, HVAC and miscellaneous low voltage loads
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

106

Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in 

Section 2.3. A summary of the plant air emissions for the non-capture cases is presented in 

Exhibit 3-22.

Exhibit 3-22 Cases S1A and L1A Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

80% capacity factor

kg/MWh

(lb/MWh)

S1A L1A S1A L1A S1A L1A

SO2

0.001 

(0.002)

0.001 

(0.002) 33 (37) 37 (40) 0.007 (0.015)

0.007 

(0.015)

NOX

0.027 

(0.062)

0.027 

(0.063) 912 (1,005) 1,001 (1,103)

0.187 

(0.412)

0.190 

(0.418)

Particulates 0.003 

(0.0071)

0.003 

(0.0071) 105 (116) 114 (125) 0.021 (0.047)

0.022 

(0.047)

Hg 1.51E-7 

(3.51E-7)

2.41E-7 

(5.60E-7)

0.005 

(0.006)

0.009 

(0.010)

1.06E-6 

(2.34E-6)

1.70E-6 

(3.74E-6)

CO2 gross

91.9 

(213.8)

94.0 

(218.6)

3,158,977 

(3,482,176)

3,494,523 

(3,852,052)

647 

(1,426)

663 

(1,461)

CO2 net 787 

(1,735)

809 

(1,783)

The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the Sulfinol-M 

AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel 

gas down to a level of less than 5 ppmv in both cases. This results in a concentration in the flue 

gas of less than 1 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus 

plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated and recycled 

upstream of the AGR to capture most of the remaining sulfur. Because the environmental target 

was set based on higher sulfur bituminous coal, the resulting SO2 emissions with lower sulfur 

western coals are substantially less than the environmental target.

NOx emissions are limited to 15 parts per million volume, dry (ppmvd) (as NO2 @ 15 percent 

O2) by the use of low NOx burners and nitrogen dilution of the fuel gas. Ammonia in the syngas 

is removed with process condensate prior to the low-temperature AGR process and destroyed in 

the Claus plant burner. This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone 

and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Ninety five percent of the mercury is captured from the syngas by an activated carbon bed.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

107

CO2 emissions represent the uncontrolled discharge from the process.

The carbon balance for the two cases is shown in Exhibit 3-23. The carbon input to the plant 

consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected 

here since the Aspen model accounts for air components throughout. Carbon leaves the plant as 

unburned carbon in the slag and as CO2 in the stack gas and ASU vent gas.

Exhibit 3-23 Case S1A and L1A Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

S1A L1A S1A L1A

Coal 123,253 

(271,726)

136,370 

(300,645) Slag 616 (1,359) 682 (1,503)

Air (CO2) 476 (1,049) 503 (1,110) Stack Gas 123,022 

(271,217)

136,089 

(300,025)

ASU Vent 90 (199) 103 (226)

Total 123,729 

(272,775)

136,874 

(301,755) Total 123,729 (272,775)

136,874 

(301,755)

Exhibit 3-24 shows the sulfur balance for the non-capture case. Sulfur input comes solely from 

the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur 

emitted in the stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 3-24 Cases S1A and L1A Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

S1A L1A S1A L1A

Coal 1,791 (3,948) 2,160 (4,761) Elemental Sulfur 1,788 (3,943) 2,157 (4,756)

Stack Gas 2 (5) 3 (6)

Total 1,791 (3,948) 2,160 (4,761) Total 1,791 (3,948) 2,160 (4,761)

Exhibit 3-25 shows the overall water balance for the plant. 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, primarily as coal moisture from the drying process and syngas condensate, and that 

water is re-used as internal recycle. Raw water withdrawal is the difference between water 

demand and internal recycle. Some water is discharged from the process to a permitted outfall. 

The difference between the withdrawal and discharge is the consumption.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

108

Exhibit 3-25 Case S1A and L1A Water Balance

Water Use

Water Demand

m3/min (gpm)

Internal Recycle m3/min 

(gpm)

Raw Water Withdrawal

m3/min (gpm)

Process Water 

Discharge m3/min 

(gpm)

Raw Water 

Consumption m3/min 

(gpm)

S1A L1A S1A L1A S1A L1A S1A L1A S1A L1A

Slag Handling 0.45 (119) 0.75 (199) 0.4 (112) 0.7 (179) 0.03 (7) 0.08 (20) 0 (0) 0 (0) 0.03 (7) 0.08 (20)

SWS Blowdown 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0.00 (1.1) 0.01 

(1.8) 0.00 (-1.1) -0.01 (-1.8)

Condenser Makeup 0.15 (41) 0.17 (44) 0 (0) 0 (0) 0.15 (41) 0.17 (44) 0 (0) 0 (0) 0.15 (41) 0.17 (44)

 BFW Makeup 0.15 (41) 0.17 (44) 0.15 (41) 0.17 (44)

Cooling Tower 7.66 

(2,024)

8.68 

(2,293) 1.1 (280) 1.8 (478) 6.60 (1,744) 6.87 (1,815) 1.72 (455) 1.95 (516)

4.88 

(1,289)

4.92 

(1,300)

 Water from Coal Drying 0.9 (228) 1.6 (416) -0.86 (-228) -1.57 (-416)

 BFW Blowdown 0.2 (41) 0.2 (44) -0.15 (-41) -0.17 (-44)

 SWS Blowdown 0.0 (11) 0.1 (18) -0.04 (-11) -0.07 (-18)

Total 8.3 (2,184) 9.6 (2,536) 1.5 (392) 2.5 (657) 6.8 (1,792) 7.1 (1,879) 1.73 (456) 1.96 

(518)

5.06 

(1,336)

5.16 

(1,362)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

109

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-26 and 

Exhibit 3-27:

• Coal gasification and ASU

• Syngas cleanup

• Combined cycle power generation

An overall plant energy balance is provided in tabular form in Exhibit 3-28 for the two cases. 

The power out is the combined CT and steam turbine power after generator losses.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

110

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Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

111

Exhibit 3-26 Case S1A Heat and Mass Balance 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

112

Exhibit 3-26 Case S1A Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

113

Exhibit 3-26 Case S1A Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

114

Exhibit 3-27 Case L1A Heat and Mass Balance
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

115

Exhibit 3-27 Case L1A Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

116

Exhibit 3-27 Case L1A Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

117

Exhibit 3-28 Cases S1A and L1A Energy Balance

HHV Sensible + Latent Power Total

S1A L1A S1A L1A S1A L1A S1A L1A

Heat In GJ/hr (MMBtu/hr)

Coal 4,904 

(4,648)

5,306 

(5,030) 2.5 (2.4) 3.1 (2.9) 0 (0) 0 (0) 4,906 (4,650)

5,310 

(5,032)

ASU Air 0 (0) 0 (0) 9.0 (8.5) 8.3 (7.8) 0 (0) 0 (0) 9 (9) 8 (8)

GT Air 0 (0) 0 (0) 44.2 (41.9) 42.5 (40.3) 0 (0) 0 (0) 44 (42) 42 (40)

Raw Water Makeup 0 (0) 0 (0) 9.4 (8.9) 7.9 (7.5) 0 (0) 0 (0) 9 (9) 8 (8)

Auxiliary Power 0 (0) 0 (0) 0 (0) 0 (0) 446 (423) 489 (464) 446 (423) 489 (464)

Totals 4,904 

(4,648)

5,306

(5,030) 65.2 (61.8) 61.7 (58.5) 446 (423) 489 (464) 5,415 (5,133)

5,857 

(5,552)

Heat Out GJ/hr (MMBtu/hr)

ASU Intercoolers 0 (0) 0 (0) 190 (181) 198 (188) 0 (0) 0 (0) 190 (181) 198 (188)

ASU Vent 0 (0) 0 (0) 0.8 (0.8) 0.9 (0.9) 0 (0) 0 (0) 1 (1) 1 (1)

Slag 20 (19) 22 (21) 36.0 (34.1) 55.5 (52.6) 0 (0) 0 (0) 56 (53) 78 (74)

Sulfur 17 (16) 20 (19) 0.2 (0.2) 0.2 (0.2) 0 (0) 0 (0) 17 (16) 20 (19)

Cooling Tower 

Blowdown 0 (0) 0 (0) 9.6 (9.1) 10.6 (10.0) 0 (0) 0 (0) 10 (9) 11 (10)

HRSG Flue Gas 0 (0) 0 (0) 710 (673) 765 (725) 0 (0) 0 (0) 710 (673) 765 (725)

Condenser 0 (0) 0 (0) 1,445

(1,369)

1,520 

(1,441) 0 (0) 0 (0) 1,445 (1,369)

1,520 

(1,441)

Auxiliary Cooling Load 0 (0) 0 (0) 25 (24) 86 (81) 0 (0) 0 (0) 25 (24) 86 (81)

Process Losses 0 (0) 0 (0) 453 (429) 470 (445) 0 (0) 0 (0) 453 (429) 470 (445)

Power 0 (0) 0 (0) 0 (0) 0 (0) 2,508 

(2,377)

2,709 

(2,568)

2,508 

(2,377)

2,709 

(2,568)

Totals 37 (35) 42 (40) 2,870 

(2,721)

3,106 

(2,944)

2,508 

(2,377)

2,709 

(2,568)

5,415 

(5,133)

5,857 

(5,552)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

118

3.2.6 Case S1A and L1A Equipment Lists

Major equipment items for the SCGP with no CO2 capture are shown in the following tables. 

The accounts used in the equipment list correspond to the account numbers used in the cost 

estimates in Section 3.2.7. In general, the design conditions include a 10 percent contingency for 

flows and heat duties and a 21 percent contingency for heads on pumps and fans.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

119

ACCOUNT 1 COAL HANDLING

Equipment 

No. Description Type S1A Design Conditions L1A Design Condition Operating Qty 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 54 tonne (60 ton) 73 tonne (80 ton) 2 1

9 Feeder Vibratory 200 tonne/hr (220 tph) 281 tonne/hr (310 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 408 tonne/hr (450 tph) 572 tonne/hr (630 tph) 1 0

11 Crusher Tower N/A N/A N/A 1 0

12 Coal Surge Bin w/ Vent 

Filter Dual outlet 200 tonne (220 ton) 281 tonne (310 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 408 tonne/hr (450 tph) 572 tonne/hr (630 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 408 tonne/hr (450 tph) 572 tonne/hr (630 tph) 1 0

18 Coal Silo w/ Vent Filter 

and Slide Gates Field erected 907 tonne (1,000 ton) 1,270 tonne (1,400 ton) 3 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

120

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1 Feeder Vibratory 91 tonne/hr (100 tph) 127 tonne/hr (140 tph) 3 0

2 Conveyor No. 

6 Belt w/tripper 272 tonne/hr (300 tph) 381 tonne/hr (420 tph) 1 0

3 Roller Mill 

Feed Hopper Dual Outlet 544 tonne (600 ton) 762 tonne (840 ton) 1 0

4 Weigh Feeder Belt 136 tonne/hr (150 tph) 191 tonne/hr (210 tph) 2 0

5 Pulverizer Rotary 136 tonne/hr (150 tph) 191 tonne/hr (210 tph) 2 0

6 Coal Dryer 

Feed Hopper Vertical Hopper 272 tonne (300 ton) 381 tonne (420 ton) 2 0

7 Coal 

Preheater

Water Heated 

Horizontal Rotary Kiln

Coal feed: 272 tonne/hr 

(300 tph)

Heat duty: 30.1 GJ/hr 

(28.6 MMBtu/hr)

Coal feed: 381 tonne/hr 

(420 tph)

Heat duty: 47 GJ/hr 

(44 MMBtu/hr)

1 0

8 Coal Dryer Fluidized Bed with 

Internal Coils

Coal feed: 136 tonne/hr 

(150 tph)

Heat duty: 75.8 GJ/hr 

(71.8 MMBtu/hr)

Bed diameter: 11.9 m (39 ft)

Coal feed: 191 tonne/hr 

(210 tph)

Heat duty: 136 GJ/hr 

(129 MMBtu/hr)

Bed diameter: 14.0 m (46 ft)

2 0

9 Steam 

Compressor

Reciprocating, MultiStage

567 m3

/min (20,040 scfm)

Suction - 0.09 MPa (13 psia)

Discharge - 0.72 MPa 

(105 psia)

1034 m3/min (36,510 scfm)

Suction - 0.10 MPa 

(13.8 psia)

Discharge - 0.52 MPa 

(75 psia)

2 0

10 Dryer Exhaust 

Filter Hot Baghouse

Steam - 28,486 kg/hr 

(62,800 lb/hr)

Temperature - 107°C 

(225°F)

Steam - 51,891 kg/hr 

(114,400 lb/hr)

Temperature - 107°C 

(225°F)

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

121

Equipment 

No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

11 Dry Coal 

Cooler

Water Cooled 

Horizontal Rotary Kiln

214 tonne/hr (236 tph)

Heat duty - 12 GJ/hr 

(12 MMBtu/hr)

275 tonne/hr (304 tph)

Heat duty - 17 GJ/hr 

(16 MMBtu/hr)

1 0

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment 

No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1

Demineralized 

Water Storage 

Tank

Vertical, cylindrical, 

outdoor

594,310 liters 

(157,000 gal)

639,735 liters 

(169,000 gal) 2 0

2 Condensate Pumps Vertical canned

6,208 lpm @ 91 m H2O

(1,640 gpm @ 300 ft 

H2O)

6,511 lpm @ 91 m H2O

(1,720 gpm @ 300 ft 

H2O)

2 1

3 Deaerator (integral 

w/ HRSG) Horizontal spray type 412,769 kg/hr (910,000 lb/hr)

441,345 kg/hr 

(973,000 lb/hr) 2 0

4

Intermediate 

Pressure 

Feedwater Pump

Horizontal 

centrifugal, single 

stage

1,022 lpm @ 27 m H2O

(270 gpm @ 90 ft H2O)

568 lpm @ 27 m H2O

(150 gpm @ 90 ft H2O) 2 1

5

High Pressure 

Feedwater Pump 

No. 1

Barrel type, multistage, centrifugal

HP water: 6,095 lpm @ 

1,890 m H2O (1,610 gpm 

@ 6,200 ft H2O)

HP water: 7,003 lpm @ 

1,890 m H2O (1,850 gpm 

@ 6,200 ft H2O)

2 1

6

High Pressure 

Feedwater Pump 

No. 2

Barrel type, multistage, centrifugal

IP water: 1,514 lpm @ 

223 m H2O (400 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)

1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

122

Equipment 

No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

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 Cycle

Cooling Heat 

Exchangers

Plate and frame 133 GJ/hr 

(126 MMBtu/hr) each

171 GJ/hr 

(162 MMBtu/hr) each 2 0

11

Closed Cycle 

Cooling Water 

Pumps

Horizontal 

centrifugal

47,696 lpm @ 21 m H2O

(12,600 gpm @ 70 ft 

H2O)

61,324 lpm @ 21 m H2O

(16,200 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

1,893 lpm @ 18 m H2O

(500 gpm @ 60 ft H2O)

2,006 lpm @ 18 m H2O

(530 gpm @ 60 ft H2O) 2 1

15 Ground Water 

Pumps

Stainless steel, single 

suction

3,823 lpm @ 268 m H2O 

(1,010 gpm @ 880 ft 

H2O)

4,013 lpm @ 268 m H2O 

(1,060 gpm @ 880 ft 

H2O)

2 1

16 Filtered Water 

Pumps

Stainless steel, single 

suction

416 lpm @ 49 m H2O

(110 gpm @ 160 ft H2O)

606 lpm @ 49 m H2O

(160 gpm @ 160 ft H2O) 2 1

17 Filtered Water 

Tank Vertical, cylindrical 196,841 liter (52,000 gal) 283,906 liter (75,000 gal) 2 0

18 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 151 lpm (40 gpm) 189 lpm (50 gpm) 2 0

19 Liquid Waste 

Treatment System 10 years, 24-hour storm 10 years, 24-hour storm 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

123

ACCOUNT 4 GASIFIER, ASU, AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment 

No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1 Gasifier Pressurized dryfeed, entrained bed

3,266 tonne/day, 4.2 MPa

(3,600 tpd, 615 psia)

4,536 tonne/day, 4.2 MPa

(5,000 tpd, 615 psia) 2 0

2 Synthesis Gas 

Cooler

Convective spiralwound tube boiler

279,866 kg/hr 

(617,000 lb/hr)

Heat duty: 510 GJ/hr 

(484 MMBtu/hr)

311,618 kg/hr 

(687,000 lb/hr)

Heat duty: 577 GJ/hr 

(547 MMBtu/hr)

2 0

3 Synthesis Gas 

Cyclone High efficiency

279,866 kg/hr 

(617,000 lb/hr) 

Design efficiency 90%

311,618 kg/hr 

(687,000 lb/hr) 

Design efficiency 90%

2 0

4 Candle Filter

Pressurized filter 

with pulse-jet 

cleaning

ceramic filters ceramic filters 2 0

5

Syngas Scrubber 

Including Sour 

Water Stripper

Vertical up flow 191,870 kg/hr 

(423,000 lb/hr)

230,425 kg/hr 

(508,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with 

condensate drain

187,334 kg/hr 

(413,000 lb/hr)

215,910 kg/hr 

(476,000 lb/hr) 8 0

7 Raw Gas 

Knockout Drum

Vertical with mist 

eliminator

186,880 kg/hr, 35°C, 

3.6 MPa

(412,000 lb/hr, 95°F, 

525 psia)

215,456 kg/hr, 35°C, 

3.6 MPa

(475,000 lb/hr, 95°F, 

525 psia)

2 0

8 Synthesis Gas 

Reheater Shell and tube 186,426 kg/hr (411,000 lb/hr)

214,096 kg/hr 

(472,000 lb/hr) 2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

124

Equipment 

No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

9 Flare Stack

Self-supporting, 

carbon steel, 

stainless steel top, 

pilot ignition

191,870 kg/hr 

(423,000 lb/hr) syngas

230,425 kg/hr 

(508,000 lb/hr) syngas 2 0

10 ASU Main Air 

Compressor

Centrifugal, multistage

4,446 m3

/min @ 1.3 MPa

(157,000 scfm 

@ 190 psia)

4,531 m3/min @ 1.3 MPa

(160,000 scfm 

@ 190 psia)

2 0

11 Cold Box Vendor design

1,996 tonne/day 

(2,200 tpd) of 

95% purity oxygen

2,268 tonne/day 

(2,500 tpd) of 

95% purity oxygen

2 0

12 Oxygen 

Compressor

Centrifugal, multistage

1,019 m3/min 

(36,000 scfm)

Suction - 0.9 MPa 

(130 psia)

Discharge - 5.1 MPa 

(740 psia)

1,161 m3/min 

(41,000 scfm)

Suction - 0.9 MPa 

(130 psia)

Discharge - 5.1 MPa 

(740 psia)

2 0

13 Primary Nitrogen 

Compressor

Centrifugal, multistage

3,341 m3/min 

(118,000 scfm)

Suction - 0.4 MPa 

(60 psia)

Discharge - 2.7 MPa 

(390 psia)

3,794 m3/min 

(134,000 scfm)

Suction - 0.4 MPa 

(60 psia)

Discharge - 2.7 MPa 

(390 psia)

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

125

Equipment 

No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

14

Secondary 

Nitrogen 

Compressor

Centrifugal, singlestage

453 m3/min (16,000 scfm)

Suction - 2.7 MPa 

(390 psia)

Discharge - 5.7 MPa 

(820 psia)

538 m3/min (19,000 scfm)

Suction - 2.7 MPa 

(390 psia)

Discharge - 5.7 MPa 

(820 psia)

2 0

15

Transport 

Nitrogen Boost 

Compressor

Centrifugal, singlestage

187 m3

/min (6,600 scfm)

Suction - 2.7 MPa 

(389 psia)

Discharge - 5.6 MPa 

(815 psia)

244 m3/min (8,600 scfm)

Suction - 2.7 MPa 

(389 psia)

Discharge - 5.6 MPa 

(815 psia)

2 0

16 Extraction Air 

Heat Exchanger

Gas-to-gas, vendor 

design

39,916 kg/hr, 411°C, 

1.4 MPa

(88,000 lb/hr, 771°F, 

208 psia)

83,461 kg/hr, 408°C, 

1.5 MPa

(184,000 lb/hr, 767°F, 

220 psia)

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

126

ACCOUNT 5 SYNGAS CLEANUP

Equipment 

No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1 Mercury Adsorber Sulfated carbon 

bed

186,880 kg/hr 

(412,000 lb/hr) 

35°C (95°F) 

3.7 MPa (535 psia)

215,456 kg/hr 

(475,000 lb/hr) 

35°C (95°F) 

3.7 MPa (535 psia)

2 0

2 Sulfur Plant Claus type 47 tonne/day (52 tpd) 57 tonne/day (63 tpd) 1 0

3 COS Hydrolysis 

Reactor

Fixed bed, 

catalytic

201,849 kg/hr 

(445,000 lb/hr)

177°C (350°F)

3.9 MPa (560 psia)

237,682 kg/hr 

(524,000 lb/hr)

177°C (350°F)

3.9 MPa (560 psia)

2 0

4 Acid Gas Removal 

Plant Sulfinol

190,509 kg/hr 

(420,000 lb/hr)

37°C (98°F)

3.6 MPa (525 psia)

221,807 kg/hr 

(489,000 lb/hr)

35°C (94°F)

3.6 MPa (525 psia)

2 0

5 Hydrogenation 

Reactor

Fixed bed, 

catalytic

7,966 kg/hr 

(17,561 lb/hr)

232°C (450°F)

0.3 MPa (48.6 psia)

13,601 kg/hr 

(29,986 lb/hr)

232°C (450°F)

0.3 MPa (48.6 psia)

1 0

6 Tail Gas Recycle 

Compressor Centrifugal 6,344 kg/hr (13986 lb/hr)

12,257 kg/hr 

(27023 lb/hr) 1 0

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment 

No. Description Type S1A Design Condition L1A Design Condition Operating Qty Spares

1 Gas Turbine Advanced F 

class 210 MW 225 MW 2 0

2 Gas Turbine 

Generator TEWAC 230 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase

250 MVA @ 0.9 p.f., 

24 kV, 60 Hz, 3-phase 2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

127

ACCOUNT 7 HRSG, DUCTING AND STACK

Equipment 

No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1 Stack CS plate, type 

409SS liner

76 m (250 ft) high x

8.6 m (20 ft) diameter

76 m (250 ft) high x

8.6 m (20 ft) diameter 2 0

2

Heat Recovery 

Steam 

Generator

Drum, multipressure with 

economizer 

section and 

integral deaerator

Main steam - 344,652 

kg/hr, 12.4 MPa/561°C 

(759,828 lb/hr, 1,800 

psig/1,042°F)

Reheat steam - 337,721 

kg/hr, 3.1 MPa/561°C 

(744,547 lb/hr, 452 

psig/1,042°F)

Main steam - 394,953 

kg/hr, 12.4 MPa/561°C 

(870,722 lb/hr, 1,800 

psig/1,042°F)

Reheat steam - 387,959 

kg/hr, 3.1 MPa/561°C 

(855,304 lb/hr, 452 

psig/1,042°F)

2 0

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1 Steam Turbine Commercially 

available

287 MW

12.4 MPa/561°C/561°C 

(1,800 psig/ 

1,042°F/1,042°F)

319 MW

12.4 MPa/561°C/561°C 

(1,800 psig/ 

1,042°F/1,042°F)

1 0

2 Steam Turbine 

Generator

Hydrogen cooled, 

static excitation

320 MVA @ 0.9 p.f., 

24 kV, 60 Hz, 3-phase

350 MVA @ 0.9 p.f., 

24 kV, 60 Hz, 3-phase 1 0

3 Surface 

Condenser

Single pass, 

divided waterbox 

including vacuum 

pumps

791 GJ/hr (750 MMBtu/hr), 

Condensing temperature 

32°C (90°F), Inlet water 

temperature 9°C (48°F), 

Water temperature rise 

11°C (20°F)

833 GJ/hr (790 MMBtu/hr), 

Condensing temperature 

32°C (90°F), Inlet water 

temperature 8°C (47°F), 

Water temperature rise 

11°C (20°F)

1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

128

Equipment 

No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

4 Air-cooled 

Condenser ---

791 GJ/hr (750 MMBtu/hr), 

Condensing temperature 

32°C (90°F), Ambient 

temperature 6°C (42°F)

833 GJ/hr (790 MMBtu/hr), 

Condensing temperature 

32°C (90°F), Ambient 

temperature 4°C (40°F)

1 0

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1 Circulating 

Water Pumps Vertical, wet pit 196,841 lpm @ 30 m(52,000 gpm @ 100 ft)

223,339 lpm @ 30 m

(59,000 gpm @ 100 ft) 2 1

2 Cooling 

Tower

Evaporative, 

mechanical 

draft, multi-cell

3°C (37°F) wet bulb / 9°C 

(48°F) CWT / 20°C (68°F) 

HWT / 1,097 GJ/hr (1,040 

MMBtu/hr) heat duty

2°C (36°F) wet bulb / 8°C 

(47°F) CWT / 19°C (67°F) 

HWT / 1,245 GJ/hr (1,180 

MMBtu/hr) heat duty

1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

129

ACCOUNT 10 SLAG/ASH RECOVERY AND HANDLING

Equipment 

No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1 Slag Quench Tank Water bath 219,554 liters (58,000 gal) 363,400 liters (96,000 gal) 2 0

2 Slag Crusher Roll 12 tonne/hr (13 tph) 19 tonne/hr (21 tph) 2 0

3 Slag Depressurizer Proprietary 12 tonne/hr (13 tph) 19 tonne/hr (21 tph) 2 0

4 Slag Receiving 

Tank

Horizontal, 

weir 132,489 liters (35,000 gal) 219,554 liters (58,000 gal) 2 0

5 Black Water 

Overflow Tank

Shop

fabricated 60,567 liters (16,000 gal) 98,421 liters (26,000 gal) 2

6 Slag Conveyor Drag chain 12 tonne/hr (13 tph) 19 tonne/hr (21 tph) 2 0

7 Slag Separation 

Screen Vibrating 12 tonne/hr (13 tph) 19 tonne/hr (21 tph) 2 0

8 Coarse Slag 

Conveyor Belt/bucket 12 tonne/hr (13 tph) 19 tonne/hr (21 tph) 2 0

9 Fine Ash Settling 

Tank

Vertical, 

gravity 185,485 liters (49,000 gal) 310,404 liters (82,000 gal) 2 0

10 Fine Ash Recycle 

Pumps

Horizontal 

centrifugal

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

76 lpm @ 14 m H2O

(20 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage 

Tank Field erected 60,567 liters (16,000 gal) 98,421 liters (26,000 gal) 2 0

12 Grey Water Pumps Centrifugal 227 lpm @ 433 m H2O

(60 gpm @ 1,420 ft H2O)

341 lpm @ 433 m H2O

(90 gpm @ 1,420 ft H2O) 2 2

13 Slag Storage Bin Vertical, field 

erected 816 tonne (900 tons) 1,361 tonne (1,500 tons) 2 0

14 Unloading 

Equipment

Telescoping 

chute 100 tonne/hr (110 tph) 163 tonne/hr (180 tph) 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

130

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type S1A Design Conditions

L1A Design 

Condition

Operating 

Qty Spares

1 CTG Step-up 

Transformer Oil-filled 24 kV/345 kV, 230 MVA, 3-ph, 60 Hz

24 kV/345 kV, 

250 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, 

350 MVA, 3-ph, 60 Hz 1 0

3

High Voltage 

Auxiliary 

Transformer

Oil-filled 345 kV/13.8 kV, 

55 MVA, 3-ph, 60 Hz

345 kV/13.8 kV, 

60 MVA, 3-ph, 60 Hz 2 0

4

Medium Voltage 

Auxiliary 

Transformer

Oil-filled 24 kV/4.16 kV, 

24 MVA, 3-ph, 60 Hz

24 kV/4.16 kV, 

28 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, selfcooled 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 2 0

7

STG Isolated Phase 

Bus Duct and Tap 

Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 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
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

131

ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment 

No. Description Type S1A Design Conditions

L1A Design 

Condition

Operating 

Qty Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator printer (laser 

color); Engineering printer (laser B&W)

Operator stations/printers and 

engineering stations/printers 1 0

2 DCS -

Processor

Microprocessor with redundant 

input/output N/A 1 0

3 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

132

3.2.7 Case S1A and L1A Cost Estimating

Costs Results

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-29 shows 

the TPC summary organized by cost account for the PRB coal case (S1A) and Exhibit 3-33

shows the same information for the lignite coal case (L1A). A more detailed breakdown of the 

capital costs is shown in Exhibit 3-30 for S1A and Exhibit 3-34 for L1A. Exhibit 3-31 and 

Exhibit 3-35 show the addition of owner’s costs to determine the TOC, used to calculate COE. 

Exhibit 3-32 shows the initial and annual O&M costs for Case S1A and Exhibit 3-36 shows the 

same information for Case L1A.

The estimated TOC of the SCGP with no CO2 capture using PRB coal is $3,056/kW and using 

lignite coal is $3,094/kW. Process contingency represents about 2 percent, project contingency 

represents 11 percent, and owner’s costs represent 18 percent of TOC for the two cases. The 

COE is 83.2 mills/kWh in the PRB case and 83.5 mills/kWh in the lignite case.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

133

Exhibit 3-29 Case S1A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S1A - Shell IGCC w/o CO2

Plant Size: 572.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING $15,272 $2,838 $11,843 $0 $0 $29,953 $2,719 $0 $6,534 $39,206 $68

 2 COAL & SORBENT PREP & FEED $114,839 $9,569 $19,594 $0 $0 $144,001 $12,493 $0 $31,299 $187,793 $328

 3 FEEDWATER & MISC. BOP SYSTEMS $7,631 $6,907 $6,754 $0 $0 $21,292 $1,996 $0 $5,177 $28,466 $50

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $177,839 $0 $76,848 $0 $0 $254,687 $22,725 $35,634 $47,895 $360,940 $630

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $149,195 $0 w/equip. $0 $0 $149,195 $14,461 $0 $16,366 $180,022 $314

4.4-4.9 Other Gasification Equipment $15,912 $9,909 $11,552 $0 $0 $37,373 $3,560 $0 $8,957 $49,890 $87

SUBTOTAL 4 $342,946 $9,909 $88,401 $0 $0 $441,256 $40,746 $35,634 $73,217 $590,853 $1,032

 5A GAS CLEANUP & PIPING $44,251 $2,654 $40,865 $0 $0 $87,771 $8,483 $81 $19,398 $115,732 $202

5B CO2 REMOVAL & COMPRESSION $0 $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 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $202

6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4

SUBTOTAL 6 $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $207

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,735 $0 $4,655 $0 $0 $37,390 $3,555 $0 $4,094 $45,039 $79

7.2-7.9 SCR System, Ductwork and Stack $3,449 $2,459 $3,253 $0 $0 $9,162 $850 $0 $1,630 $11,642 $20

SUBTOTAL 7 $36,185 $2,459 $7,908 $0 $0 $46,552 $4,405 $0 $5,725 $56,681 $99

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $28,830 $0 $4,943 $0 $0 $33,773 $3,241 $0 $3,701 $40,715 $71

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $35,457 $992 $12,090 $0 $0 $48,540 $4,701 $0 $10,904 $64,145 $112

SUBTOTAL 8 $64,287 $992 $17,034 $0 $0 $82,313 $7,941 $0 $14,605 $104,860 $183

 9 COOLING WATER SYSTEM $5,692 $5,857 $4,875 $0 $0 $16,424 $1,525 $0 $3,692 $21,640 $38

10 ASH/SPENT SORBENT HANDLING SYS $18,383 $1,419 $9,122 $0 $0 $28,924 $2,775 $0 $3,463 $35,163 $61

11 ACCESSORY ELECTRIC PLANT $27,278 $10,483 $20,837 $0 $0 $58,598 $5,040 $0 $12,002 $75,640 $132

12 INSTRUMENTATION & CONTROL $10,120 $1,862 $6,520 $0 $0 $18,501 $1,677 $925 $3,516 $24,619 $43

13 IMPROVEMENTS TO SITE $3,238 $1,909 $7,990 $0 $0 $13,137 $1,297 $0 $4,330 $18,764 $33

14 BUILDINGS & STRUCTURES $0 $6,373 $7,345 $0 $0 $13,718 $1,249 $0 $2,453 $17,420 $30

 

TOTAL COST $775,873 $64,038 $256,248 $0 $0 $1,096,159 $101,228 $41,241 $196,504 $1,435,132 $2,506

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

134

Exhibit 3-30 Case S1A Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S1A - Shell IGCC w/o CO2

Plant Size: 572.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $4,010 $0 $1,960 $0 $0 $5,970 $535 $0 $1,301 $7,806 $14

1.2 Coal Stackout & Reclaim $5,182 $0 $1,256 $0 $0 $6,439 $564 $0 $1,401 $8,404 $15

1.3 Coal Conveyors & Yd Crush $4,818 $0 $1,243 $0 $0 $6,061 $532 $0 $1,319 $7,912 $14

1.4 Other Coal Handling $1,261 $0 $288 $0 $0 $1,548 $135 $0 $337 $2,020 $4

1.5 Sorbent Receive & Unload $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

1.7 Sorbent Conveyors $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

1.9 Coal & Sorbent Hnd.Foundations $0 $2,838 $7,096 $0 $0 $9,934 $952 $0 $2,177 $13,064 $23

SUBTOTAL 1. $15,272 $2,838 $11,843 $0 $0 $29,953 $2,719 $0 $6,534 $39,206 $68

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $46,233 $2,777 $6,737 $0 $0 $55,747 $4,810 $0 $12,111 $72,669 $127

2.2 Prepared Coal Storage & Feed $1,988 $476 $312 $0 $0 $2,775 $237 $0 $602 $3,615 $6

2.3 Dry Coal Injection System $65,414 $759 $6,075 $0 $0 $72,248 $6,223 $0 $15,694 $94,165 $164

2.4 Misc.Coal Prep & Feed $1,204 $876 $2,627 $0 $0 $4,708 $433 $0 $1,028 $6,169 $11

2.5 Sorbent Prep Equipment $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

2.7 Sorbent Injection System $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

2.9 Coal & Sorbent Feed Foundation $0 $4,681 $3,843 $0 $0 $8,523 $789 $0 $1,863 $11,175 $20

SUBTOTAL 2. $114,839 $9,569 $19,594 $0 $0 $144,001 $12,493 $0 $31,299 $187,793 $328

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,854 $4,900 $2,587 $0 $0 $10,341 $958 $0 $2,260 $13,559 $24

3.2 Water Makeup & Pretreating $311 $32 $174 $0 $0 $517 $49 $0 $170 $736 $1

3.3 Other Feedwater Subsystems $1,561 $528 $475 $0 $0 $2,564 $230 $0 $559 $3,353 $6

3.4 Service Water Systems $178 $366 $1,272 $0 $0 $1,816 $177 $0 $598 $2,591 $5

3.5 Other Boiler Plant Systems $955 $370 $917 $0 $0 $2,242 $213 $0 $491 $2,945 $5

3.6 FO Supply Sys & Nat Gas $303 $571 $533 $0 $0 $1,407 $136 $0 $308 $1,851 $3

3.7 Waste Treatment Equipment $435 $0 $265 $0 $0 $700 $68 $0 $230 $998 $2

3.8 Misc. Power Plant Equipment $1,036 $139 $532 $0 $0 $1,706 $165 $0 $561 $2,432 $4

SUBTOTAL 3. $7,631 $6,907 $6,754 $0 $0 $21,292 $1,996 $0 $5,177 $28,466 $50

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $177,839 $0 $76,848 $0 $0 $254,687 $22,725 $35,634 $47,895 $360,940 $630

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $149,195 $0 w/equip. $0 $0 $149,195 $14,461 $0 $16,366 $180,022 $314

4.4 LT Heat Recovery & FG Saturation $15,912 $0 $6,049 $0 $0 $21,961 $2,143 $0 $4,821 $28,925 $51

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $921 $375 $0 $0 $1,296 $124 $0 $284 $1,704 $3

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $8,988 $5,129 $0 $0 $14,117 $1,292 $0 $3,852 $19,261 $34

SUBTOTAL 4. $342,946 $9,909 $88,401 $0 $0 $441,256 $40,746 $35,634 $73,217 $590,853 $1,032

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

135

Exhibit 3-30 Case S1A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S1A - Shell IGCC w/o CO2

Plant Size: 572.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 5A GAS CLEANUP & PIPING

5A.1 Sulfinol System $34,171 $0 $28,995 $0 $0 $63,165 $6,109 $0 $13,855 $83,129 $145

5A.2 Elemental Sulfur Plant $4,852 $967 $6,260 $0 $0 $12,078 $1,173 $0 $2,650 $15,902 $28

5A.3 Mercury Removal $920 $0 $700 $0 $0 $1,620 $156 $81 $371 $2,229 $4

5A.4 COS Hydrolysis $2,912 $0 $3,802 $0 $0 $6,714 $653 $0 $1,473 $8,840 $15

5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Blowback Gas Systems $1,397 $235 $132 $0 $0 $1,765 $167 $0 $386 $2,318 $4

5A.7 Fuel Gas Piping $0 $722 $505 $0 $0 $1,227 $114 $0 $268 $1,609 $3

5A.9 HGCU Foundations $0 $731 $471 $0 $0 $1,202 $110 $0 $394 $1,706 $3

SUBTOTAL 5A. $44,251 $2,654 $40,865 $0 $0 $87,771 $8,483 $81 $19,398 $115,732 $202

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5B. $0 $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 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $202

6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4

SUBTOTAL 6. $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $207

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,735 $0 $4,655 $0 $0 $37,390 $3,555 $0 $4,094 $45,039 $79

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,768 $1,294 $0 $0 $3,062 $269 $0 $666 $3,997 $7

7.4 Stack $3,449 $0 $1,296 $0 $0 $4,745 $455 $0 $520 $5,720 $10

7.9 HRSG,Duct & Stack Foundations $0 $691 $664 $0 $0 $1,355 $126 $0 $444 $1,925 $3

SUBTOTAL 7. $36,185 $2,459 $7,908 $0 $0 $46,552 $4,405 $0 $5,725 $56,681 $99

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $28,830 $0 $4,943 $0 $0 $33,773 $3,241 $0 $3,701 $40,715 $71

8.2 Turbine Plant Auxiliaries $200 $0 $459 $0 $0 $659 $64 $0 $72 $795 $1

8.3a Condenser & Auxiliaries $2,973 $0 $950 $0 $0 $3,923 $375 $0 $430 $4,728 $8

8.3b Air Cooled Condenser $27,249 $0 $5,463 $0 $0 $32,711 $3,271 $0 $7,197 $43,179 $75

8.4 Steam Piping $5,035 $0 $3,542 $0 $0 $8,577 $737 $0 $2,329 $11,643 $20

8.9 TG Foundations $0 $992 $1,677 $0 $0 $2,669 $253 $0 $877 $3,799 $7

SUBTOTAL 8. $64,287 $992 $17,034 $0 $0 $82,313 $7,941 $0 $14,605 $104,860 $183

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $3,928 $0 $714 $0 $0 $4,642 $442 $0 $763 $5,847 $10

9.2 Circulating Water Pumps $1,021 $0 $57 $0 $0 $1,079 $91 $0 $175 $1,345 $2

9.3 Circ.Water System Auxiliaries $93 $0 $13 $0 $0 $106 $10 $0 $17 $134 $0

9.4 Circ.Water Piping $0 $3,885 $1,007 $0 $0 $4,893 $442 $0 $1,067 $6,402 $11

9.5 Make-up Water System $191 $0 $274 $0 $0 $465 $45 $0 $102 $612 $1

9.6 Component Cooling Water Sys $459 $549 $390 $0 $0 $1,398 $131 $0 $306 $1,834 $3

9.9 Circ.Water System Foundations $0 $1,423 $2,419 $0 $0 $3,841 $364 $0 $1,262 $5,467 $10

SUBTOTAL 9. $5,692 $5,857 $4,875 $0 $0 $16,424 $1,525 $0 $3,692 $21,640 $38

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

136

Exhibit 3-30 Case S1A Total Plant Cost Details (Continued) Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S1A - Shell IGCC w/o CO2

Plant Size: 572.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $15,999 $0 $7,890 $0 $0 $23,888 $2,295 $0 $2,618 $28,802 $50

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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

10.4 High Temperature Ash Piping $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

10.6 Ash Storage Silos $540 $0 $588 $0 $0 $1,128 $109 $0 $186 $1,423 $2

10.7 Ash Transport & Feed Equipment $725 $0 $175 $0 $0 $900 $84 $0 $148 $1,131 $2

10.8 Misc. Ash Handling Equipment $1,119 $1,372 $410 $0 $0 $2,901 $276 $0 $476 $3,653 $6

10.9 Ash/Spent Sorbent Foundation $0 $48 $60 $0 $0 $108 $10 $0 $35 $153 $0

SUBTOTAL 10. $18,383 $1,419 $9,122 $0 $0 $28,924 $2,775 $0 $3,463 $35,163 $61

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $919 $0 $909 $0 $0 $1,828 $175 $0 $200 $2,203 $4

11.2 Station Service Equipment $3,872 $0 $349 $0 $0 $4,221 $389 $0 $461 $5,071 $9

11.3 Switchgear & Motor Control $7,159 $0 $1,302 $0 $0 $8,460 $785 $0 $1,387 $10,632 $19

11.4 Conduit & Cable Tray $0 $3,325 $10,970 $0 $0 $14,296 $1,383 $0 $3,920 $19,598 $34

11.5 Wire & Cable $0 $6,354 $4,175 $0 $0 $10,528 $765 $0 $2,823 $14,117 $25

11.6 Protective Equipment $0 $653 $2,375 $0 $0 $3,028 $296 $0 $499 $3,822 $7

11.7 Standby Equipment $228 $0 $222 $0 $0 $450 $43 $0 $74 $567 $1

11.8 Main Power Transformers $15,101 $0 $139 $0 $0 $15,239 $1,153 $0 $2,459 $18,851 $33

11.9 Electrical Foundations $0 $151 $396 $0 $0 $546 $52 $0 $180 $778 $1

SUBTOTAL 11. $27,278 $10,483 $20,837 $0 $0 $58,598 $5,040 $0 $12,002 $75,640 $132

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $999 $0 $667 $0 $0 $1,666 $158 $83 $286 $2,193 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $230 $0 $147 $0 $0 $377 $36 $19 $86 $518 $1

12.7 Computer & Accessories $5,329 $0 $171 $0 $0 $5,500 $505 $275 $628 $6,907 $12

12.8 Instrument Wiring & Tubing $0 $1,862 $3,806 $0 $0 $5,667 $481 $283 $1,608 $8,039 $14

12.9 Other I & C Equipment $3,562 $0 $1,730 $0 $0 $5,292 $498 $265 $908 $6,963 $12

SUBTOTAL 12. $10,120 $1,862 $6,520 $0 $0 $18,501 $1,677 $925 $3,516 $24,619 $43

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $102 $2,171 $0 $0 $2,273 $226 $0 $750 $3,248 $6

13.2 Site Improvements $0 $1,807 $2,401 $0 $0 $4,208 $415 $0 $1,387 $6,011 $10

13.3 Site Facilities $3,238 $0 $3,417 $0 $0 $6,655 $656 $0 $2,193 $9,505 $17

SUBTOTAL 13. $3,238 $1,909 $7,990 $0 $0 $13,137 $1,297 $0 $4,330 $18,764 $33

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1

14.2 Steam Turbine Building $0 $2,427 $3,458 $0 $0 $5,885 $541 $0 $964 $7,390 $13

14.3 Administration Building $0 $828 $601 $0 $0 $1,429 $127 $0 $233 $1,790 $3

14.4 Circulation Water Pumphouse $0 $163 $86 $0 $0 $249 $22 $0 $41 $311 $1

14.5 Water Treatment Buildings $0 $260 $254 $0 $0 $513 $46 $0 $84 $644 $1

14.6 Machine Shop $0 $424 $290 $0 $0 $714 $63 $0 $117 $894 $2

14.7 Warehouse $0 $684 $442 $0 $0 $1,126 $100 $0 $184 $1,410 $2

14.8 Other Buildings & Structures $0 $409 $318 $0 $0 $727 $65 $0 $158 $950 $2

14.9 Waste Treating Building & Str. $0 $914 $1,746 $0 $0 $2,660 $248 $0 $582 $3,489 $6

SUBTOTAL 14. $0 $6,373 $7,345 $0 $0 $13,718 $1,249 $0 $2,453 $17,420 $30

TOTAL COST $775,873 $64,038 $256,248 $0 $0 $1,096,159 $101,228 $41,241 $196,504 $1,435,132 $2,506

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

137

Exhibit 3-31 Case S1A Owner’s Costs

Owner's Costs $x1000 $/kW

Preproduction Costs

6 Months Fixed O&M $13,195 $23

1 Month Variable O&M $3,363 $6

25% of 1 Months Fuel Cost at 100% CF $754 $1

2% of TPC $28,703 $50

Total $46,014 $80

Inventory Capital

60 day supply of consumables at 100% CF $6,151 $11

0.5% of TPC (spare parts) $7,176 $13

Total $13,326 $23

 Initial Cost for Catalyst and Chemicals $799 $1

Land $900 $2

Other Owner's Costs $215,270 $376

Financing Costs $38,749 $68

Total Owner's Costs $315,058 $550

Total Overnight Cost (TOC) $1,750,189 $3,056

TASC Multiplier 1.140

Total As-Spent Cost (TASC) $1,995,216 $3,484
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

138

Exhibit 3-32 Case S1A Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case S1A - Shell IGCC w/o CO2 Heat Rate-net (Btu/kWh): 8115

MWe-net: 573

Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 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-O.J.'s 15.0 15.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $5,918,913 $10.335

Maintenance Labor Cost $15,192,490 $26.529

Administrative & Support Labor $5,277,851 $9.216

Property Taxes and Insurance $28,702,632 $50.120

TOTAL FIXED OPERATING COSTS $55,091,886 $96.200

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $28,677,180 $0.00715

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

Water (/1000 gallons) 0 1,290 1.08 $0 $407,294 $0.00010

Chemicals

MU & WT Chem.(lbs) 0 7,683 0.17 $0 $388,246 $0.00010

Carbon (Mercury Removal) (lb) 64,000 88 1.05 $67,211 $26,884 $0.00001

COS Catalyst (m3) 257 0.18 2,397.36 $616,357 $123,271 $0.00003

Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000

Sulfinol Solution (gal) 11,507 8 10.05 $115,630 $22,945 $0.00001

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip. 0.72 131.27 $0 $27,465 $0.00001

Subtotal Chemicals $799,198 $588,813 $0.00015

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 88 0.42 $0 $10,677 $0.00000

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 550 16.23 $0 $2,603,499 $0.00065

Subtotal Waste Disposal $0 $2,614,176 $0.00065

By-products & Emissions 

 Sulfur (tons) 0 47 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $799,198 $32,287,462 $0.00805

Fuel (ton) 0 6,513 15.22 $0 $28,937,267 $0.00721
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

139

Exhibit 3-33 Case L1A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-20

Project: Low Rank Western Coal Baseline Study

Case: Case L1A - Shell IGCC w/o CO2

Plant Size: 616.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING $18,819 $3,497 $14,594 $0 $0 $36,910 $3,350 $0 $8,052 $48,312 $78

 2 COAL & SORBENT PREP & FEED $140,634 $11,900 $24,207 $0 $0 $176,741 $15,335 $0 $38,415 $230,491 $374

 3 FEEDWATER & MISC. BOP SYSTEMS $8,213 $7,525 $7,209 $0 $0 $22,947 $2,150 $0 $5,559 $30,656 $50

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (S $183,394 $0 $79,368 $0 $0 $262,762 $23,441 $36,845 $49,395 $372,443 $604

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $161,830 $0 w/equip. $0 $0 $161,830 $15,686 $0 $17,752 $195,268 $317

4.4-4.9 Other Gasification Equipment $17,853 $11,411 $13,127 $0 $0 $42,390 $4,036 $0 $10,174 $56,600 $92

SUBTOTAL 4 $363,076 $11,411 $92,495 $0 $0 $466,982 $43,163 $36,845 $77,321 $624,311 $1,012

 5A GAS CLEANUP & PIPING $49,333 $2,938 $45,661 $0 $0 $97,932 $9,465 $88 $21,641 $129,126 $209

5B CO2 REMOVAL & COMPRESSION $0 $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 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $188

6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4

SUBTOTAL 6 $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $192

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $34,161 $0 $4,857 $0 $0 $39,019 $3,710 $0 $4,273 $47,001 $76

7.2-7.9 SCR System, Ductwork and Stack $3,447 $2,457 $3,250 $0 $0 $9,154 $849 $0 $1,629 $11,632 $19

SUBTOTAL 7 $37,608 $2,457 $8,108 $0 $0 $48,173 $4,559 $0 $5,902 $58,633 $95

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $31,044 $0 $5,379 $0 $0 $36,423 $3,495 $0 $3,992 $43,910 $71

8.2-8.9 Turbine Plant Auxiliaries and Steam Pip $37,097 $1,072 $12,854 $0 $0 $51,022 $4,935 $0 $11,495 $67,452 $109

SUBTOTAL 8 $68,140 $1,072 $18,233 $0 $0 $87,445 $8,430 $0 $15,487 $111,362 $181

 9 COOLING WATER SYSTEM $6,199 $6,318 $5,258 $0 $0 $17,774 $1,650 $0 $3,991 $23,415 $38

10 ASH/SPENT SORBENT HANDLING S $25,382 $1,887 $12,592 $0 $0 $39,861 $3,824 $0 $4,759 $48,444 $79

11 ACCESSORY ELECTRIC PLANT $28,874 $10,987 $21,847 $0 $0 $61,708 $5,304 $0 $12,626 $79,638 $129

12 INSTRUMENTATION & CONTROL $10,381 $1,910 $6,688 $0 $0 $18,979 $1,720 $949 $3,607 $25,255 $41

13 IMPROVEMENTS TO SITE $3,359 $1,980 $8,288 $0 $0 $13,627 $1,345 $0 $4,492 $19,464 $32

14 BUILDINGS & STRUCTURES $0 $6,624 $7,665 $0 $0 $14,289 $1,302 $0 $2,551 $18,142 $29

 

TOTAL COST $845,770 $71,311 $280,008 $0 $0 $1,197,089 $110,482 $42,483 $215,494 $1,565,547 $2,539

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

140

Exhibit 3-34 Case L1A Total Plant Cost Details

Client: USDOE/NETL Report Date: 2010-Jan-20

Project: Low Rank Western Coal Baseline Study

Case: Case L1A - Shell IGCC w/o CO2

Plant Size: 616.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $4,942 $0 $2,415 $0 $0 $7,357 $659 $0 $1,603 $9,619 $16

1.2 Coal Stackout & Reclaim $6,386 $0 $1,548 $0 $0 $7,934 $695 $0 $1,726 $10,356 $17

1.3 Coal Conveyors & Yd Crush $5,937 $0 $1,532 $0 $0 $7,469 $656 $0 $1,625 $9,750 $16

1.4 Other Coal Handling $1,553 $0 $354 $0 $0 $1,908 $167 $0 $415 $2,490 $4

1.5 Sorbent Receive & Unload $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

1.7 Sorbent Conveyors $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

1.9 Coal & Sorbent Hnd.Foundations $0 $3,497 $8,744 $0 $0 $12,242 $1,173 $0 $2,683 $16,098 $26

SUBTOTAL 1. $18,819 $3,497 $14,594 $0 $0 $36,910 $3,350 $0 $8,052 $48,312 $78

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $57,744 $3,469 $8,414 $0 $0 $69,627 $6,008 $0 $15,127 $90,762 $147

2.2 Prepared Coal Storage & Feed $2,400 $574 $376 $0 $0 $3,351 $287 $0 $727 $4,365 $7

2.3 Dry Coal Injection System $78,986 $917 $7,335 $0 $0 $87,238 $7,514 $0 $18,950 $113,702 $184

2.4 Misc.Coal Prep & Feed $1,504 $1,094 $3,282 $0 $0 $5,880 $540 $0 $1,284 $7,705 $12

2.5 Sorbent Prep Equipment $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

2.7 Sorbent Injection System $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

2.9 Coal & Sorbent Feed Foundation $0 $5,846 $4,800 $0 $0 $10,646 $986 $0 $2,326 $13,958 $23

SUBTOTAL 2. $140,634 $11,900 $24,207 $0 $0 $176,741 $15,335 $0 $38,415 $230,491 $374

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $3,147 $5,404 $2,853 $0 $0 $11,404 $1,057 $0 $2,492 $14,953 $24

3.2 Water Makeup & Pretreating $322 $34 $180 $0 $0 $535 $51 $0 $176 $762 $1

3.3 Other Feedwater Subsystems $1,722 $582 $524 $0 $0 $2,827 $254 $0 $616 $3,698 $6

3.4 Service Water Systems $184 $379 $1,316 $0 $0 $1,879 $183 $0 $619 $2,681 $4

3.5 Other Boiler Plant Systems $988 $383 $949 $0 $0 $2,319 $220 $0 $508 $3,047 $5

3.6 FO Supply Sys & Nat Gas $317 $598 $558 $0 $0 $1,472 $142 $0 $323 $1,937 $3

3.7 Waste Treatment Equipment $450 $0 $274 $0 $0 $724 $71 $0 $238 $1,033 $2

3.8 Misc. Power Plant Equipment $1,084 $145 $557 $0 $0 $1,786 $172 $0 $587 $2,545 $4

SUBTOTAL 3. $8,213 $7,525 $7,209 $0 $0 $22,947 $2,150 $0 $5,559 $30,656 $50

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (S $183,394 $0 $79,368 $0 $0 $262,762 $23,441 $36,845 $49,395 $372,443 $604

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $161,830 $0 w/equip. $0 $0 $161,830 $15,686 $0 $17,752 $195,268 $317

4.4 LT Heat Recovery & FG Saturation $17,853 $0 $6,787 $0 $0 $24,639 $2,405 $0 $5,409 $32,453 $53

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,042 $424 $0 $0 $1,467 $141 $0 $321 $1,929 $3

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $10,368 $5,916 $0 $0 $16,284 $1,491 $0 $4,444 $22,219 $36

SUBTOTAL 4. $363,076 $11,411 $92,495 $0 $0 $466,982 $43,163 $36,845 $77,321 $624,311 $1,012

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

141

Exhibit 3-34 Case L1A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2010-Jan-20

Project: Low Rank Western Coal Baseline Study

Case: Case L1A - Shell IGCC w/o CO2

Plant Size: 616.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 5A GAS CLEANUP & PIPING

5A.1 Sulfinol System $38,030 $0 $32,269 $0 $0 $70,300 $6,799 $0 $15,420 $92,518 $150

5A.2 Elemental Sulfur Plant $5,501 $1,096 $7,097 $0 $0 $13,695 $1,330 $0 $3,005 $18,030 $29

5A.3 Mercury Removal $996 $0 $758 $0 $0 $1,754 $169 $88 $402 $2,413 $4

5A.4 COS Hydrolysis $3,312 $0 $4,326 $0 $0 $7,638 $743 $0 $1,676 $10,057 $16

5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Blowback Gas Systems $1,494 $251 $141 $0 $0 $1,886 $179 $0 $413 $2,478 $4

5A.7 Fuel Gas Piping $0 $790 $553 $0 $0 $1,344 $125 $0 $294 $1,762 $3

5A.9 HGCU Foundations $0 $800 $516 $0 $0 $1,316 $121 $0 $431 $1,868 $3

SUBTOTAL 5A. $49,333 $2,938 $45,661 $0 $0 $97,932 $9,465 $88 $21,641 $129,126 $209

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $85,752 $0 $6,269 $0 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $188

6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4

SUBTOTAL 6. $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $192

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $34,161 $0 $4,857 $0 $0 $39,019 $3,710 $0 $4,273 $47,001 $76

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,767 $1,292 $0 $0 $3,059 $269 $0 $666 $3,993 $6

7.4 Stack $3,447 $0 $1,295 $0 $0 $4,741 $454 $0 $520 $5,715 $9

7.9 HRSG,Duct & Stack Foundations $0 $691 $663 $0 $0 $1,354 $126 $0 $444 $1,924 $3

SUBTOTAL 7. $37,608 $2,457 $8,108 $0 $0 $48,173 $4,559 $0 $5,902 $58,633 $95

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $31,044 $0 $5,379 $0 $0 $36,423 $3,495 $0 $3,992 $43,910 $71

8.2 Turbine Plant Auxiliaries $216 $0 $495 $0 $0 $711 $70 $0 $78 $859 $1

8.3a Condenser & Auxiliaries $3,083 $0 $985 $0 $0 $4,068 $389 $0 $446 $4,903 $8

8.3b Air Cooled Condenser $28,258 $0 $5,665 $0 $0 $33,923 $3,392 $0 $7,463 $44,779 $73

8.4 Steam Piping $5,539 $0 $3,896 $0 $0 $9,436 $811 $0 $2,562 $12,808 $21

8.9 TG Foundations $0 $1,072 $1,812 $0 $0 $2,883 $273 $0 $947 $4,104 $7

SUBTOTAL 8. $68,140 $1,072 $18,233 $0 $0 $87,445 $8,430 $0 $15,487 $111,362 $181

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $4,291 $0 $780 $0 $0 $5,071 $483 $0 $833 $6,387 $10

9.2 Circulating Water Pumps $1,116 $0 $65 $0 $0 $1,181 $99 $0 $192 $1,472 $2

9.3 Circ.Water System Auxiliaries $100 $0 $14 $0 $0 $115 $11 $0 $19 $145 $0

9.4 Circ.Water Piping $0 $4,191 $1,087 $0 $0 $5,278 $477 $0 $1,151 $6,906 $11

9.5 Make-up Water System $197 $0 $282 $0 $0 $479 $46 $0 $105 $630 $1

9.6 Component Cooling Water Sys $495 $592 $421 $0 $0 $1,508 $141 $0 $330 $1,979 $3

9.9 Circ.Water System Foundations $0 $1,535 $2,609 $0 $0 $4,144 $393 $0 $1,361 $5,898 $10

SUBTOTAL 9. $6,199 $6,318 $5,258 $0 $0 $17,774 $1,650 $0 $3,991 $23,415 $38

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

142

Exhibit 3-34 Case L1A Total Plant Cost Details (Continued) Client: USDOE/NETL Report Date: 2010-Jan-20

Project: Low Rank Western Coal Baseline Study

Case: Case L1A - Shell IGCC w/o CO2

Plant Size: 616.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $22,213 $0 $10,954 $0 $0 $33,167 $3,187 $0 $3,635 $39,989 $65

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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

10.4 High Temperature Ash Piping $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

10.6 Ash Storage Silos $718 $0 $782 $0 $0 $1,500 $145 $0 $247 $1,892 $3

10.7 Ash Transport & Feed Equipment $963 $0 $232 $0 $0 $1,196 $112 $0 $196 $1,503 $2

10.8 Misc. Ash Handling Equipment $1,488 $1,823 $545 $0 $0 $3,855 $367 $0 $633 $4,856 $8

10.9 Ash/Spent Sorbent Foundation $0 $64 $80 $0 $0 $143 $13 $0 $47 $204 $0

SUBTOTAL 10. $25,382 $1,887 $12,592 $0 $0 $39,861 $3,824 $0 $4,759 $48,444 $79

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $961 $0 $951 $0 $0 $1,912 $183 $0 $209 $2,304 $4

11.2 Station Service Equipment $4,056 $0 $366 $0 $0 $4,422 $408 $0 $483 $5,312 $9

11.3 Switchgear & Motor Control $7,499 $0 $1,364 $0 $0 $8,863 $822 $0 $1,453 $11,137 $18

11.4 Conduit & Cable Tray $0 $3,483 $11,492 $0 $0 $14,975 $1,448 $0 $4,106 $20,529 $33

11.5 Wire & Cable $0 $6,656 $4,373 $0 $0 $11,029 $801 $0 $2,958 $14,788 $24

11.6 Protective Equipment $0 $689 $2,507 $0 $0 $3,196 $312 $0 $526 $4,035 $7

11.7 Standby Equipment $236 $0 $231 $0 $0 $467 $45 $0 $77 $588 $1

11.8 Main Power Transformers $16,121 $0 $147 $0 $0 $16,268 $1,231 $0 $2,625 $20,123 $33

11.9 Electrical Foundations $0 $159 $418 $0 $0 $577 $55 $0 $190 $822 $1

SUBTOTAL 11. $28,874 $10,987 $21,847 $0 $0 $61,708 $5,304 $0 $12,626 $79,638 $129

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,025 $0 $684 $0 $0 $1,709 $162 $85 $293 $2,250 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $236 $0 $151 $0 $0 $387 $37 $19 $88 $531 $1

12.7 Computer & Accessories $5,466 $0 $175 $0 $0 $5,641 $518 $282 $644 $7,085 $11

12.8 Instrument Wiring & Tubing $0 $1,910 $3,904 $0 $0 $5,814 $493 $291 $1,649 $8,247 $13

12.9 Other I & C Equipment $3,654 $0 $1,774 $0 $0 $5,428 $511 $271 $932 $7,142 $12

SUBTOTAL 12. $10,381 $1,910 $6,688 $0 $0 $18,979 $1,720 $949 $3,607 $25,255 $41

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $105 $2,253 $0 $0 $2,358 $234 $0 $778 $3,370 $5

13.2 Site Improvements $0 $1,875 $2,491 $0 $0 $4,366 $431 $0 $1,439 $6,235 $10

13.3 Site Facilities $3,359 $0 $3,545 $0 $0 $6,904 $681 $0 $2,275 $9,860 $16

SUBTOTAL 13. $3,359 $1,980 $8,288 $0 $0 $13,627 $1,345 $0 $4,492 $19,464 $32

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1

14.2 Steam Turbine Building $0 $2,586 $3,684 $0 $0 $6,270 $577 $0 $1,027 $7,874 $13

14.3 Administration Building $0 $847 $615 $0 $0 $1,462 $130 $0 $239 $1,831 $3

14.4 Circulation Water Pumphouse $0 $167 $88 $0 $0 $255 $22 $0 $42 $319 $1

14.5 Water Treatment Buildings $0 $269 $262 $0 $0 $531 $48 $0 $87 $666 $1

14.6 Machine Shop $0 $434 $297 $0 $0 $730 $65 $0 $119 $914 $1

14.7 Warehouse $0 $700 $452 $0 $0 $1,152 $102 $0 $188 $1,442 $2

14.8 Other Buildings & Structures $0 $419 $326 $0 $0 $746 $67 $0 $162 $975 $2

14.9 Waste Treating Building & Str. $0 $937 $1,791 $0 $0 $2,729 $254 $0 $597 $3,580 $6

SUBTOTAL 14. $0 $6,624 $7,665 $0 $0 $14,289 $1,302 $0 $2,551 $18,142 $29

TOTAL COST $845,770 $71,311 $280,008 $0 $0 $1,197,089 $110,482 $42,483 $215,494 $1,565,547 $2,539

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

143

Exhibit 3-35 Case L1A Owner’s Costs

Owner's Costs $x1000 $/kW

Preproduction Costs

6 Months Fixed O&M $13,821 $22

1 Month Variable O&M $3,711 $6

25% of 1 Months Fuel Cost at 100% CF $757 $1

2% of TPC $31,311 $51

Total $49,601 $80

Inventory Capital

60 day supply of consumables at 100% CF $6,199 $10

0.5% of TPC (spare parts) $7,828 $13

Total $14,027 $23

 Initial Cost for Catalyst and Chemicals $1,024 $2

Land $900 $1

Other Owner's Costs $234,832 $381

Financing Costs $42,270 $69

Total Owner's Costs $342,653 $556

Total Overnight Cost (TOC) $1,908,200 $3,094

TASC Multiplier 1.140

Total As-Spent Cost (TASC) $2,175,349 $3,527
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

144

Exhibit 3-36 Case L1A Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case L1A - Shell IGCC w/o CO2 Heat Rate-net (Btu/kWh): 8156

MWe-net: 617

Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 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-O.J.'s 15.0 15.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $5,918,913 $9.598

Maintenance Labor Cost $16,194,989 $26.261

Administrative & Support Labor $5,528,476 $8.965

Property Taxes and Insurance $31,310,940 $50.772

TOTAL FIXED OPERATING COSTS $58,953,318 $95.595

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $30,180,929 $0.00698

Consumables Consumption Unit Initial

 Initial Fill /Day Cost Cost

Water (/1000 gallons) 0 1,353 1.08 $0 $427,306 $0.00010

Chemicals

MU & WT Chem.(lbs) 0 8,060 0.17 $0 $407,323 $0.00009

Carbon (Mercury Removal) (lb) 71,689 98 1.05 $75,286 $30,114 $0.00001

COS Catalyst (m3) 298 0.20 2,397.36 $714,200 $142,840 $0.00003

Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000

Sulfinol Solution (gal) 23,349 16 10.05 $234,627 $46,573 $0.00001

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip. 0.85 131.27 $0 $32,615 $0.00001

Subtotal Chemicals $1,024,112 $659,465 $0.00015

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 98 0.42 $0 $11,960 $0.00000

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 918 16.23 $0 $4,347,545 $0.00101

Subtotal Waste Disposal $0 $4,359,504 $0.00101

By-products & Emissions 

Sulfur (tons) 0 57 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $1,024,112 $35,627,205 $0.00824

Fuel (ton) 0 9,121 10.92 $0 $29,082,622 $0.00673
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

145

3.2.8 SCGP IGCC CO2 Capture Cases (S1B and L1B) Process Description

Cases S1B and L1B are configured to produce electric power with CO2 capture. The plant 

configurations are similar to Cases S1A and L1A with the major differences being the addition 

of WGS, the use of a two-stage Selexol AGR plant instead of Sulfinol and subsequent 

compression of the captured CO2 stream. The gross power output is constrained by the capacity 

of the two CTs, and since the CO2 capture and compression process increases the auxiliary load 

on the plant, the net output is significantly reduced relative to Cases S1A and L1A.

The process description for Cases S1B and L1B is similar to Cases S1A and L1A with several 

notable exceptions to accommodate CO2 capture. A BFD for the CO2 capture case is shown in 

Exhibit 3-37 and stream tables are shown in Exhibit 3-38. Instead of repeating the entire process 

description, only differences from the non-capture cases are reported here.

Coal Preparation and Feed Systems

No differences from non-capture cases.

Gasification

The gasification process is the same as the non-capture cases except the coal feed (as-received) 

to the gasifiers is 6,379 tonne/day (7,032 tpd)for the PRB case and 8,861 tonne/day (9,768 tpd)

for the lignite case.

Raw Gas Cooling/Particulate Removal

Specifically for the Shell technology for switching to carbon capture, the high temperature 

section of the raw gas cooler is replaced by a direct contact water quench, which cools the gas to 

363°C (685°F), simultaneously increasing the water content of the syngas for the downstream 

WGS reaction.

Sour Water Stripper

No differences from non-capture cases.

SGS

The SGS process was described in Section 3.1.6. The water concentration in the syngas is 

controlled by varying the exit temperature of the water scrubber upstream of the shift reactors 

and is augmented by injection of shift steam. The hot syngas exiting the first stage of SGS is 

used to superheat steam. One more stage of SGS (for a total of two) results in approximately 97

percent overall conversion of CO to CO2. The warm syngas from the second stage of SGS is 

cooled to preheat the syngas prior to the first stage of SGS. The SGS catalyst also serves to 

hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. Following the 

second stage of SGS, the syngas is further cooled to 35°C (95°F) prior to the mercury removal 

beds.

Mercury Removal and AGR

Mercury removal is the same as in the non-capture cases.

The AGR process in the CO2 capture cases is a two stage Selexol process where H2S is removed 

in the first stage and CO2 in the second stage of absorption. The process results in three product 

streams, the clean syngas, a CO2-rich stream and an acid gas feed to the Claus plant. The acid 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

146

gas contains about 17 percent H2S and 66 percent CO2 with the balance primarily H2. The CO2-

rich stream is discussed further in the CO2 compression section. 

CO2 Compression and Dehydration

CO2 from the AGR process is generated at two pressure levels. The LP stream is compressed 

from 0.12 MPa (17 psia) to 1.0 MPa (150 psia) and then combined with the HP stream. The 

combined stream is further compressed to a SC condition at 15.3 MPa (2215 psia) using a 

multiple-stage, intercooled compressor. During compression, the CO2 stream is dehydrated to a 

dew point of -40oC (-40°F) using a thermal swing adsorptive dryer. The raw CO2 stream from 

the Selexol process contains over 99 percent CO2. The dehydrated CO2 is transported to the 

plant fence line and is sequestration ready.

Claus Unit

The Claus plant is the same as the non-capture cases except 46 tonne/day (51 tpd) of sulfur are 

produced in the PRB case and 55 tonne/day (61 tpd) in the lignite case.

Power Block

Clean syngas from the AGR plant is reheated to 196°C (385°F) using HP BFW, diluted with 

nitrogen, and then enters the CT burner. The exhaust gas exits the CT at a nominal 566°C 

(1,050°F) and enters the HRSG where additional heat is recovered. The flue gas exits the HRSG 

at 132°C (270°F) and is discharged through the plant stack. The steam raised in the HRSG is 

used to power an advanced commercially available steam turbine using a nominal 12.4 

MPa/538°C/538°C (1800 psig/1000°F/1000°F) steam cycle. There is no air integration between 

the CT and the ASU in either capture case.

ASU

The same elevated pressure ASU is used as in non-capture cases except the output is

3,933 tonne/day (4,335 tpd) of 95 mol% oxygen to the gasifier and Claus plant for the PRB case 

and 4,447 tonne/day (4,902 tpd) for the lignite case

Balance of Plant

Balance of plant items were covered in Sections 3.1.12, 3.1.13, 3.1.14, and 3.1.15.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

147

Exhibit 3-37 Case S1B and L1B Process Flow Diagram
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

148

Exhibit 3-38 Case S1B Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

V-L Mole Fraction

Ar 0.0093 0.0160 0.0318 0.0023 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0000 0.0104 0.0060 0.0000 0.0060 0.0000 0.0051

CH4 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 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.6016 0.3470 0.0000 0.3470 0.0000 0.2969

CO2 0.0003 0.0051 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0318 0.0183 0.0000 0.0183 0.0000 0.0157

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0003 0.0000 0.0003 0.0000 0.0003

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2616 0.1508 0.0000 0.1508 0.0000 0.1291

H2O 0.0064 0.0975 0.0000 0.0002 0.0002 0.0000 0.0000 0.0000 1.0000 0.0000 0.0000 0.0279 0.4386 0.9981 0.4386 1.0000 0.5196

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0030 0.0017 0.0000 0.0017 0.0000 0.0015

N2 0.7759 0.7523 0.0178 0.9920 0.9920 0.0178 0.0000 0.0000 0.0000 0.0000 0.0000 0.0604 0.0348 0.0000 0.0348 0.0000 0.0298

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0029 0.0024 0.0019 0.0024 0.0000 0.0021

O2 0.2081 0.1291 0.9504 0.0054 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 24,697 1,577 78 17,093 935 5,014 0 0 3,103 0 0 17,390 6,685 12,763 30,153 4,420 35,237

V-L Flowrate (kg/hr) 713,612 43,868 2,517 479,643 26,236 161,348 0 0 55,901 0 0 375,047 134,128 229,913 604,961 79,634 696,534

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 265,792 0 209,891 22,427 0 0 0 0 0 0

Temperature (°C) 6 18 32 196 197 32 --- 6 33 71 1,427 1,427 246 170 232 288 232

Pressure (MPa, abs) 0.09 0.11 0.86 2.65 5.62 0.86 --- 0.09 0.55 0.09 4.24 4.24 4.24 0.79 3.93 4.14 3.79

Enthalpy (kJ/kg)A 15.26 36.45 26.67 202.64 201.76 26.67 --- --- 139.92 --- --- 2,242.88 1,346.50 668.41 1,325.51 2,956.19 1,527.21

Density (kg/m3) 1.1 1.4 11.0 18.9 39.6 11.0 --- --- 985.3 --- --- 6.4 20.3 838.4 19.3 18.2 18.6

V-L Molecular Weight 28.895 27.826 32.181 28.061 28.061 32.181 --- --- 18.015 --- --- 21.567 20.063 18.013 20.063 18.015 19.767

V-L Flowrate (lbmol/hr) 54,447 3,476 172 37,684 2,061 11,054 0 0 6,841 0 0 38,338 14,739 28,139 66,477 9,745 77,683

V-L Flowrate (lb/hr) 1,573,246 96,713 5,550 1,057,431 57,841 355,711 0 0 123,241 0 0 826,838 295,701 506,872 1,333,710 175,564 1,535,594

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 585,970 0 462,730 49,444 0 0 0 0 0 0

Temperature (°F) 42 64 90 385 387 90 --- 42 92 160 2,600 2,600 474 338 450 550 449

Pressure (psia) 13.0 16.4 125.0 384.0 815.0 125.0 --- 13.0 80.0 13.0 614.7 614.7 615.0 115.0 569.7 600.0 549.7

Enthalpy (Btu/lb)A 6.6 15.7 11.5 87.1 86.7 11.5 --- --- 60.2 --- --- 964.3 578.9 287.4 569.9 1,270.9 656.6

Density (lb/ft3) 0.070 0.089 0.687 1.180 2.475 0.687 --- --- 61.513 --- --- 0.401 1.265 52.337 1.205 1.135 1.160

A - Reference conditions are 32.02 F & 0.089 PSIA
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Exhibit 3-38 Case S1B Stream Table (Continued)

18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34

V-L Mole Fraction

Ar 0.0066 0.0094 0.0067 0.0022 0.0000 0.0071 0.0002 0.0002 0.0106 0.0106 0.0093 0.0091 0.0091 0.0000 0.0000 0.0000 0.0000

CH4 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 0.0000 0.0000 0.0000

CO 0.0097 0.0035 0.0096 0.0035 0.0000 0.0403 0.0002 0.0002 0.0153 0.0153 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.3970 0.6359 0.4011 0.6588 0.0000 0.4434 0.9919 0.9948 0.0490 0.0490 0.0003 0.0089 0.0089 0.0000 0.0000 0.0000 0.0000

COS 0.0000 0.0000 0.0000 0.0001 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.5440 0.1223 0.5391 0.1254 0.0000 0.0549 0.0046 0.0046 0.8617 0.8617 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0017 0.1381 0.0017 0.0382 0.0000 0.3856 0.0029 0.0000 0.0001 0.0001 0.0064 0.1208 0.1208 1.0000 1.0000 1.0000 1.0000

H2S 0.0022 0.0065 0.0023 0.1657 0.0000 0.0048 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0387 0.0843 0.0395 0.0060 0.0000 0.0638 0.0002 0.0002 0.0632 0.0632 0.7759 0.7549 0.7549 0.0000 0.0000 0.0000 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2081 0.1062 0.1062 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 0.0000 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) 27,106 390 27,442 376 0 515 10,004 9,975 17,062 17,062 100,352 127,026 127,026 25,110 17,107 17,107 39,134

V-L Flowrate (kg/hr) 550,130 13,168 562,339 13,525 0 15,427 437,535 437,012 111,279 111,279 2,899,687 3,490,609 3,490,609 452,359 308,189 308,189 705,016

Solids Flowrate (kg/hr) 0 0 0 0 1,928 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 35 49 34 48 176 232 16 72 31 196 6 561 132 533 32 32 33

Pressure (MPa, abs) 3.43 0.07 3.36 0.16 0.1 0.085 1.032 15.270 3.238 3.203 0.090 0.093 0.090 12.512 0.005 0.005 0.827

Enthalpy (kJ/kg)A 43.64 234.02 42.61 94.11 --- 861.747 5.232 -95.273 135.215 893.518 15.260 830.526 341.308 3,430.159 2,284.211 2,284.211 140.266

Density (kg/m3) 27.8 0.9 27.5 2.2 5,284.6 0.6 20.1 461.3 8.3 5.3 1.1 0.4 0.7 36.8 0.04 0.04 995.0

V-L Molecular Weight 20.296 33.776 20.492 35.946 --- 29.941 43.735 43.809 6.522 6.522 28.895 27.479 27.479 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 59,758 859 60,500 830 0 1,136 22,056 21,992 37,615 37,615 221,239 280,045 280,045 55,358 37,715 37,715 86,276

V-L Flowrate (lb/hr) 1,212,830 29,030 1,239,745 29,817 0 34,010 964,599 963,447 245,329 245,329 6,392,716 7,695,476 7,695,476 997,281 679,441 679,441 1,554,294

Solids Flowrate (lb/hr) 0 0 0 0 4,251 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 95 120 94 119 348 450 60 162 87 385 42 1,042 270 992 90 90 92

Pressure (psia) 497.6 10.6 487.6 23.7 17.3 12.3 149.7 2,214.7 469.6 464.6 13.0 13.5 13.0 1,814.7 0.7 0.7 120.0

Enthalpy (Btu/lb)A 18.8 100.6 18.3 40.5 --- 370.5 2.2 -41.0 58.1 384.1 6.6 357.1 146.7 1,474.7 982.0 982.0 60.3

Density (lb/ft3) 1.733 0.058 1.718 0.138 330 0.038 1.254 28.796 0.515 0.330 0.070 0.023 0.046 2.297 0.002 0.002 62.116
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Exhibit 3-39 Case L1B Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

V-L Mole Fraction

Ar 0.0093 0.0093 0.0318 0.0023 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0000 0.0100 0.0058 0.0000 0.0058 0.0000 0.0055

CH4 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 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.5271 0.3057 0.0000 0.3057 0.0000 0.2869

CO2 0.0003 0.0025 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0643 0.0373 0.0000 0.0373 0.0000 0.0350

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0004 0.0002 0.0000 0.0002 0.0000 0.0002

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2477 0.1436 0.0000 0.1436 0.0000 0.1348

H2O 0.0062 0.0466 0.0000 0.0002 0.0002 0.0000 0.0000 0.0000 1.0000 0.0000 0.0000 0.0802 0.4666 1.0000 0.4666 1.0000 0.4993

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0032 0.0018 0.0000 0.0018 0.0000 0.0017

N2 0.7761 0.8746 0.0178 0.9922 0.9922 0.0178 0.0000 0.0000 0.0000 0.0000 0.0000 0.0658 0.0382 0.0000 0.0382 0.0000 0.0358

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0014 0.0008 0.0000 0.0008 0.0000 0.0007

O2 0.2082 0.0670 0.9504 0.0053 0.0053 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 27,921 3,603 44 17,365 1,195 5,714 0 0 5,608 0 0 20,444 6,518 14,814 35,257 1,619 37,556

V-L Flowrate (kg/hr) 806,854 100,755 1,429 487,271 33,525 183,875 0 0 101,037 0 0 448,453 132,242 266,870 715,323 29,158 756,739

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 369,238 0 268,201 37,148 0 0 0 0 0 0

Temperature (°C) 4 16 32 196 197 32 --- 4 32 71 1,371 1,371 245 171 232 288 233

Pressure (MPa, abs) 0.10 0.11 0.86 2.65 5.62 0.86 --- 0.10 0.34 0.09 4.24 4.24 4.24 0.79 3.93 4.14 3.79

Enthalpy (kJ/kg)A 13.75 34.65 26.67 202.62 201.73 26.67 --- --- 134.94 --- --- 2,286.87 1,394.66 674.27 1,374.03 2,956.19 1,457.26

Density (kg/m3) 1.2 1.4 11.0 18.9 39.6 11.0 --- --- 986.5 --- --- 6.8 20.6 838.7 19.6 18.2 18.9

V-L Molecular Weight 28.898 27.966 32.181 28.060 28.060 32.181 --- --- 18.015 --- --- 21.936 20.289 18.015 20.289 18.015 20.150

V-L Flowrate (lbmol/hr) 61,555 7,943 98 38,284 2,634 12,597 0 0 12,364 0 0 45,071 14,370 32,658 77,729 3,568 82,797

V-L Flowrate (lb/hr) 1,778,809 222,127 3,150 1,074,248 73,910 405,375 0 0 222,748 0 0 988,670 291,544 588,347 1,577,017 64,283 1,668,325

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 814,029 0 591,281 81,896 0 0 0 0 0 0

Temperature (°F) 40 61 90 385 387 90 --- 40 90 160 2,500 2,500 474 339 450 550 451

Pressure (psia) 13.8 16.4 125.0 384.0 815.0 125.0 --- 13.8 50.0 13.5 614.7 614.7 615.0 115.0 569.7 600.0 549.7

Enthalpy (Btu/lb)A 5.9 14.9 11.5 87.1 86.7 11.5 --- --- 58.0 --- --- 983.2 599.6 289.9 590.7 1,270.9 626.5

Density (lb/ft3) 0.074 0.085 0.687 1.179 2.475 0.687 --- --- 61.586 --- --- 0.422 1.287 52.359 1.225 1.135 1.177

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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Exhibit 3-39 Case L1B Stream Table (Continued)

18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34

V-L Mole Fraction

Ar 0.0070 0.0060 0.0070 0.0022 0.0000 0.0049 0.0002 0.0002 0.0112 0.0112 0.0093 0.0092 0.0092 0.0000 0.0000 0.0000 0.0000

CH4 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 0.0000 0.0000 0.0000

CO 0.0101 0.0060 0.0100 0.0036 0.0000 0.0790 0.0002 0.0002 0.0161 0.0161 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.4026 0.6471 0.4068 0.6513 0.0000 0.4546 0.9920 0.9949 0.0502 0.0502 0.0003 0.0093 0.0093 0.0000 0.0000 0.0000 0.0000

COS 0.0000 0.0000 0.0000 0.0001 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.5302 0.1626 0.5261 0.1193 0.0000 0.0588 0.0044 0.0044 0.8484 0.8484 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0017 0.1381 0.0017 0.0382 0.0000 0.3698 0.0029 0.0000 0.0001 0.0001 0.0062 0.1201 0.1201 1.0000 1.0000 1.0000 1.0000

H2S 0.0024 0.0068 0.0025 0.1784 0.0000 0.0054 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0459 0.0334 0.0458 0.0068 0.0000 0.0273 0.0002 0.0002 0.0740 0.0740 0.7761 0.7541 0.7541 0.0000 0.0000 0.0000 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2082 0.1073 0.1073 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 0.0000 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) 29,315 419 29,676 417 0 512 10,972 10,940 18,287 18,287 106,961 134,709 134,709 26,245 18,526 18,526 39,107

V-L Flowrate (kg/hr) 608,290 13,763 621,022 15,053 0 15,448 479,908 479,329 126,060 126,060 3,090,914 3,704,245 3,704,245 472,820 333,743 333,743 704,530

Solids Flowrate (kg/hr) 0 0 0 0 2,307 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 35 49 35 48 177 232 16 72 31 216 4 560 132 532 32 32 33

Pressure (MPa, abs) 3.43 0.07 3.36 0.16 0.1 0.085 0.931 15.270 3.238 3.234 0.095 0.099 0.095 12.512 0.005 0.005 0.827

Enthalpy (kJ/kg)A 42.51 240.64 41.58 93.85 --- 832.551 6.361 -95.603 127.658 930.527 13.748 827.700 339.845 3,427.809 2,290.992 2,290.992 140.266

Density (kg/m3) 28.4 0.9 28.1 2.2 5,282.6 0.6 18.0 462.1 8.7 5.4 1.2 0.4 0.8 36.9 0.04 0.04 995.0

V-L Molecular Weight 20.750 32.869 20.927 36.063 --- 30.157 43.740 43.816 6.893 6.893 28.898 27.498 27.498 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 64,628 923 65,425 920 0 1,129 24,189 24,118 40,316 40,316 235,808 296,983 296,983 57,861 40,842 40,842 86,217

V-L Flowrate (lb/hr) 1,341,049 30,342 1,369,120 33,187 0 34,057 1,058,017 1,056,739 277,916 277,916 6,814,298 8,166,462 8,166,462 1,042,389 735,778 735,778 1,553,224

Solids Flowrate (lb/hr) 0 0 0 0 5,086 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 95 120 94 119 350 450 60 161 87 420 40 1,040 270 990 90 90 92

Pressure (psia) 497.6 10.6 487.6 23.7 17.3 12.3 135.0 2,214.7 469.6 469.0 13.8 14.3 13.8 1,814.7 0.7 0.7 120.0

Enthalpy (Btu/lb)A 18.3 103.5 17.9 40.3 --- 357.9 2.7 -41.1 54.9 400.1 5.9 355.8 146.1 1,473.7 984.9 984.9 60.3

Density (lb/ft3) 1.774 0.056 1.756 0.138 330 0.038 1.123 28.851 0.545 0.339 0.074 0.024 0.048 2.301 0.002 0.002 62.116
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3.2.9 Case S1B and L1B Performance Results

The Case S1B and L1B modeling assumptions were presented previously in Exhibit 3-16.

The SCGP IGCC plant with CO2 capture and using PRB coal at the Montana site (elevation 

3,400 ft) produces a net output of 472 MWe at a net plant efficiency of 32.1 percent (HHV 

basis). The same plant configuration using lignite coal at the NDL site (elevation 1,900 ft) 

produces a net output of 500 MWe at a net plant efficiency of 31.7 percent (HHV basis). 

Overall performance for the plants is summarized in Exhibit 3-40, which includes auxiliary 

power requirements. The ASU accounts for approximately 55 percent of the total auxiliary load 

in both cases, distributed between the main air compressor, the oxygen compressor, the nitrogen 

compressor, and ASU auxiliaries. The coal drying process accounts for approximately 6 percent. 

CO2 compression accounts for about 17 percent and the AGR process accounts for about 

9.6 percent of the auxiliary load in both cases. All other individual auxiliary loads are less than 

3 percent of the total.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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Exhibit 3-40 Case S1B and L1B Plant Performance Summary

POWER SUMMARY (Gross Power at Generator 

Terminals, kWe) S1B L1B

Gas Turbine Power 430,900 456,600

Steam Turbine Power 232,500 256,700

TOTAL POWER, kWe 663,400 713,300

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 510 620

Coal Milling 2,730 3,800

Slag Handling 580 970

WTA Coal Dryer Compressor 9,370 12,980

WTA Coal Dryer Auxiliaries 620 850

Air Separation Unit Auxiliaries 1,000 1,000

Air Separation Unit Main Air Compressor 63,550 70,010

Oxygen Compressor 8,830 10,070

Nitrogen Compressors 33,340 34,630

CO2 Compressor 31,560 35,250

Boiler Feedwater Pumps 3,260 3,300

Condensate Pump 230 230

Quench Water Pump 760 880

Syngas Recycle Compressor 820 800

Circulating Water Pump 2,730 3,410

Ground Water Pumps 310 350

Cooling Tower Fans 1,780 2,090

Air Cooled Condenser Fans 2,960 3,040

Scrubber Pumps 20 30

Acid Gas Removal 18,400 20,180

Gas Turbine Auxiliaries 1,000 1,000

Steam Turbine Auxiliaries 100 100

Claus Plant/TGTU Auxiliaries 250 250

Claus Plant TG Recycle Compressor 1,530 1,640

Miscellaneous Balance of Plant1 3,000 3,000

Transformer Losses 2,550 2,760

TOTAL AUXILIARIES, kWe 191,790 213,240

NET POWER, kWe 471,610 500,060

Net Plant Efficiency, % (HHV) 32.1% 31.7%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,227 (10,641) 11,365 (10,772)

CONDENSER COOLING DUTY GJ/hr (106 Btu/hr) 1,319 (1,250) 1,435 (1,360)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 265,792 (585,970) 369,238 (814,029)

Thermal Input, kWt 1,470,704 1,578,608

Raw Water Withdrawal, m3/min (gpm) 12.9 (3,404) 14.8 (3,917)

Raw Water Consumption, m3/min (gpm) 10.5 (2,767) 11.8 (3,124)

1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

154

Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, CO2, and PM were presented in 

Section 2.3. A summary of the plant air emissions for the CO2 capture cases is presented in 

Exhibit 3-41.

Exhibit 3-41 Case S1B and L1B Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

80% capacity factor

kg/MWh

(lb/MWh)

S1B L1B S1B L1B S1B L1B

SO2

0.000 

(0.001)

0.000 

(0.001) 14 (15) 17 (18) 0.003 (0.007)

0.003 

(0.007)

NOX

0.022 

(0.050)

0.021 

(0.049) 802 (885) 841 (927) 0.173 (0.381)

0.168 

(0.371)

Particulates 0.003 

(0.0071)

0.003 

(0.0071) 113 (125) 122 (134) 0.024 (0.054)

0.024 

(0.054)

Hg 1.51E-7 

(3.51E-7)

2.41E-7 

(5.60E-7)

0.006 

(0.006)

0.010 

(0.011)

1.20E-6 

(2.66E-6)

1.92E-6 

(4.23E-6)

CO2 gross 9.4 (21.9) 9.7 (22.5) 348,874 

(384,567)

384,547 

(423,890) 75 (165) 77 (170)

CO2 net 106 (233) 110 (242)

The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the two-stage 

Selexol AGR process. Just as in the non-capture cases, the SO2 emission are significantly less

than the environmental targets of Section 2.3. The clean syngas exiting the AGR process has a 

sulfur concentration of approximately 2 ppmv. This results in a concentration in the flue gas of 

less than 0.3 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, 

producing elemental sulfur. The tail gas is hydrogenated and recycled upstream of the AGR.

NOx emissions are limited to 15 ppmvd (as NO2 @ 15 percent O2) by the use of low NOx 

burners and nitrogen dilution of the fuel gas. Ammonia in the syngas is removed with process 

condensate prior to the low-temperature AGR process and subsequently destroyed in the Claus 

plant burner. This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone 

and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Ninety five percent of mercury is captured from the syngas by an activated carbon bed.

Slightly greater than 92 percent of the CO2 from the syngas is captured in the AGR system and 

compressed for sequestration.

The carbon balance for the plant is shown in Exhibit 3-42. The carbon input to the plant consists 

of carbon in the air in addition to carbon in the coal. Carbon in the air is not used in the carbon 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

155

capture equation below, but it is not neglected in the balance since the Aspen model accounts for 

air components throughout. Carbon leaves the plant as unburned carbon in the slag, CO2 in the 

stack gas and ASU vent gas, and the captured CO2 product. The carbon capture efficiency is 

defined as the amount 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 Product for Sequestration)/[(Carbon in the Coal)-(Carbon in Slag)] or

90 percent (both cases S1B and L1B)

Exhibit 3-42 Cases S1B and L1B Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

S1B L1B S1B L1B

Coal 133,077 

(293,384)

146,047 

(321,979) Slag 665 (1,467) 730 (1,610)

Air (CO2) 492 (1,086) 531 (1,171) Stack Gas 13,586 

(29,953)

14,976 

(33,016)

ASU Vent 97 (214) 110 (242)

CO2 Product 119,220 

(262,836)

130,763 

(288,282)

Total 133,569 

(294,470)

146,578 

(323,150) Total 133,569 (294,470)

146,578 

(323,150)

Exhibit 3-43 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the 

stack gas, and sulfur that is sequestered with the CO2 product. Sulfur in the slag is considered 

negligible.

Exhibit 3-43 Cases S1B and L1B Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

S1B L1B S1B L1B

Coal 1,934 (4,263) 2,313 (5,099) Elemental 

Sulfur 1,928 (4,251) 2,307 (5,086)

Stack Gas 1 (2) 1 (3)

CO2 Product 4 (9) 5 (11)

Convergence 

Tolerance1 0 (0) 0 (0)

Total 1,934 (4,263) 2,313 (5,099) Total 1,934 (4,263) 2,313 (5,099)

Exhibit 3-44 shows the overall water balance for the plant. 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, primarily from the coal drying process and as syngas condensate, and that water is reused as internal recycle. Raw water withdrawal is the difference between water demand and 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

156

internal recycle. Some water is discharged from the process to a permitted outfall. The 

difference between the withdrawal and discharge is the consumption.

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-45 and 

Exhibit 3-46:

• Coal gasification and ASU

• Syngas cleanup

• Combined cycle power generation

An overall plant energy balance is provided in tabular form in Exhibit 3-47 for the two cases. 

The power out is the combined CT and steam turbine power after generator losses.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

157

Exhibit 3-44 Cases S1B and L1B Water Balance

Water Use

Water Demand

m3/min (gpm)

Internal Recycle m3/min 

(gpm)

Raw Water Withdrawal

m3/min (gpm)

Process Water 

Discharge m3/min (gpm)

Raw Water Consumption 

m3/min (gpm)

S1B L1B S1B L1B S1B L1B S1B L1B S1B L1B

Slag Handling 0.49 (128) 0.81 (213) 0.49 (128) 0.81 (213) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0)

Quench/Wash 3.84 (1014) 4.45 (1177) 1.74 (460) 1.45 (383) 2.10 (554) 3.01 (794) 0 (0) 0 (0) 2.10 (554) 3.01 (794)

SWS Blowdown 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0.02 (6) 0.02 (6) -0.02 (-6) -0.02 (-6)

Condenser Makeup 1.48 (391) 0.62 (163) 0 (0) 0 (0) 1.48 (391) 0.62 (163) 0 (0) 0 (0) 1.48 (391) 0.62 (163)

 Shift Steam 1.33 (351) 0.49 (129) 1.33 (351) 0.49 (129)

 BFW Makeup 0.15 (40) 0.13 (35) 0.15 (40) 0.13 (35)

Cooling Tower 10.62 

(2,804)

13.25 

(3,500) 1.31 (345) 2.04 (540) 9.31 (2,459)

11.20 

(2,960) 2.39 (631) 2.98 (787) 6.92 (1,828)

8.22 

(2,173)

 Water from Coal Drying 0.93 (246) 1.69 (445) -0.93

(-246)

-1.69 (-

445)

 BFW Blowdown 0.15 (40) 0.13 (35) -0.15 (-40) -0.13 (-35)

 SWS Blowdown 0.22 (59) 0.23 (60) -0.22 (-59) -0.23 (-60)

Total 16.4 

(4,338)

19.1 

(5,052) 3.5 (934) 4.30 (1135) 12.9 (3,404)

14.83 

(3,917) 2.4 (637) 3.00 (793) 10.5 (2,767)

11.83 

(3,124)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

158

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Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

159

Exhibit 3-45 Case S1B Heat and Mass Balance 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

160

Exhibit 3-45 Case S1B Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

161

Exhibit 3-45 Case S1B Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

162

Exhibit 3-46 Case L1B Heat and Mass Balance
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

163

Exhibit 3-46 Case L1B Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

164

Exhibit 3-46 Case L1B Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

165

Exhibit 3-47 Cases S1B and L1B Energy Balance

HHV Sensible + Latent Power Total

S1B L1B S1B L1B S1B L1B S1B L1B

Heat In GJ/hr (MMBtu/hr)

Coal 5,295

(5,018)

5,683 

(5,386) 2.7 (2.6) 3.3 (3.1) 0 (0) 0 (0) 5,297 (5,021) 5,686 (5,390)

ASU Air 0 (0) 0 (0) 10.9 (10.3) 11.1 (10.5) 0 (0) 0 (0) 11 (10) 11 (11)

GT Air 0 (0) 0 (0) 44.2 (41.9) 42.5 (40.3) 0 (0) 0 (0) 44 (42) 42 (40)

Raw Water Makeup 0 (0) 0 (0) 17.9 (17.0) 16.5 (15.6) 0 (0) 0 (0) 18 (17) 16 (16)

Auxiliary Power 0 (0) 0 (0) 0 (0) 0 (0) 690 (654) 768 (728) 690 (654) 768 (728)

Totals 5,295

(5,018)

5,683 

(5,386) 75.8 (71.8) 73.4 (69.5) 690 (654) 768 (728) 6,061 (5,744) 6,524 (6,184)

Heat Out GJ/hr (MMBtu/hr)

ASU Intercoolers 0 (0) 0 (0) 217 (206) 231 (219) 0 (0) 0 (0) 217 (206) 231 (219)

ASU Vent 0 (0) 0 (0) 1.6 (1.5) 3.5 (3.3) 0 (0) 0 (0) 2 (1) 3 (3)

Slag 22 (21) 24 (23) 37.9 (35.9) 59.5 (56.4) 0 (0) 0 (0) 60 (57) 83 (79)

Sulfur 18 (17) 21 (20) 0.2 (0.2) 0.3 (0.2) 0 (0) 0 (0) 18 (17) 22 (21)

CO2 0 (0) 0 (0) -41.6 (-39.5) -45.8 (-43.4) 0 (0) 0 (0) -42 (-39) -46 (-43)

CO2 Comp Intercoolers 0 (0) 0 (0) 153.3 (145.3) 170.5 (161.6) 0 (0) 0 (0) 153 (145) 170 (162)

Cooling Tower 

Blowdown 0 (0) 0 (0) 13.3 (12.6) 16.1 (15.3) 0 (0) 0 (0) 13 (13) 16 (15)

HRSG Flue Gas 0 (0) 0 (0) 1,191 (1,129) 1,259 (1,193) 0 (0) 0 (0) 1,191 (1,129) 1,259 (1,193)

Condenser 0 (0) 0 (0) 1,316 (1,248) 1,436 (1,361) 0 (0) 0 (0) 1,316 (1,248) 1,436 (1,361)

Auxiliary Cooling Load 0 (0) 0 (0) 162 (154) 399 (378) 0 (0) 0 (0) 162 (154) 399 (378)

Process Losses 0 (0) 0 (0) 581 (551) 382 (362) 0 (0) 0 (0) 581 (551) 382 (362)

Power 0 (0) 0 (0) 0 (0) 0 (0) 2,388

(2,264)

2,568 

(2,434) 2,388 (2,264) 2,568 (2,434)

Totals 40 (38) 45 (43) 3,633 (3,443) 3,911 (3,707) 2,388 

(2,264)

2,568 

(2,434) 6,061 (5,744) 6,524 (6,184)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

166

3.2.10 Case S1B and L1B Equipment List

Major equipment items for the SCGP with CO2 capture are shown in the following tables. The 

accounts used in the equipment list correspond to the account numbers used in the cost estimates 

in Section 3.2.11. In general, the design conditions include a 10 percent contingency for flows 

and heat duties and a 21 percent contingency for heads on pumps and fans.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

167

ACCOUNT 1 COAL HANDLING

Equipment 

No. Description Type S1B Design Conditions L1B Design Condition Operating Qty 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 54 tonne (60 ton) 73 tonne (80 ton) 2 1

9 Feeder Vibratory 218 tonne/hr (240 tph) 308 tonne/hr (340 tph) 2 1

10 Conveyor No. 3 Belt w/ 

tripper 435 tonne/hr (480 tph) 608 tonne/hr (670 tph) 1 0

11 Crusher Tower N/A N/A N/A 1 0

12 Coal Surge Bin w/ 

Vent Filter Dual outlet 218 tonne (240 ton) 308 tonne (340 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 435 tonne/hr (480 tph) 608 tonne/hr (670 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A N/A 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

168

Equipment 

No. Description Type S1B Design Conditions L1B Design Condition Operating Qty Spares

17 Conveyor No. 5 Belt w/ 

tripper 435 tonne/hr (480 tph) 608 tonne/hr (670 tph) 1 0

18 Coal Silo w/ Vent 

Filter and Slide Gates Field erected 998 tonne (1,100 ton) 1,361 tonne (1,500 ton) 3 0

ACCOUNT 2 COAL PREPARATION AND FEED 

Equipment 

No. Description Type S1B Design Condition L1B Design Condition Operating Qty Spares

1 Feeder Vibratory 100 tonne/hr (110 tph) 136 tonne/hr (150 tph) 3 0

2 Conveyor No. 

6 Belt w/tripper 290 tonne/hr (320 tph) 408 tonne/hr (450 tph) 1 0

3 Roller Mill 

Feed Hopper Dual Outlet 581 tonne (640 ton) 816 tonne (900 ton) 1 0

4 Weigh Feeder Belt 145 tonne/hr (160 tph) 200 tonne/hr (220 tph) 2 0

5 Pulverizer Rotary 145 tonne/hr (160 tph) 200 tonne/hr (220 tph) 2 0

6 Coal Dryer 

Feed Hopper Vertical Hopper 290 tonne (320 ton) 408 tonne (450 ton) 2 0

7 Coal 

Preheater

Water Heated 

Horizontal Rotary Kiln

Coal feed: 290 tonne/hr 

(320 tph)

Heat duty: 32.5 GJ/hr 

(30.8 MMBtu/hr)

Coal feed: 408 tonne/hr 

(450 tph)

Heat duty: 50 GJ/hr 

(48 MMBtu/hr)

1 0

8 Coal Dryer Fluidized Bed with 

Internal Coils

Coal feed: 145 tonne/hr 

(160 tph)

Heat duty: 81.8 GJ/hr 

(77.6 MMBtu/hr)

Bed diameter: 12.5 m 

(41 ft)

Coal feed: 200 tonne/hr 

(220 tph)

Heat duty: 146 GJ/hr 

(138 MMBtu/hr)

Bed diameter: 14.6 m 

(48 ft)

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

169

Equipment 

No. Description Type S1B Design Condition L1B Design Condition Operating Qty Spares

9 Steam 

Compressor

Reciprocating, MultiStage

612 m3/min (21,630 scfm)

Suction - 0.09 MPa (13 

psia)

Discharge - 0.72 MPa 

(105.0 psia)

1107 m3/min (39,100 scfm)

Suction - 0.10 MPa (13.8

psia)

Discharge - 0.52 MPa (75 

psia)

2 0

10 Dryer Exhaust 

Filter Hot Baghouse

Steam - 30,754 kg/hr 

(67,800 lb/hr)

Temperature - 107°C 

(225°F)

Steam - 55,565 kg/hr 

(122,500 lb/hr)

Temperature - 107°C 

(225°F)

2 0

11 Dry Coal 

Cooler

Water Cooled 

Horizontal Rotary Kiln

231 tonne/hr (255 tph)

Heat duty - 13 GJ/hr 

(13 MMBtu/hr)

295 tonne/hr (325 tph)

Heat duty - 18 GJ/hr 

(18 MMBtu/hr)

1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

170

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment 

No. Description Type S1B Design Condition L1B Design Condition Operating Qty Spares

1

Demineralized 

Water Storage 

Tank

Vertical, 

cylindrical, 

outdoor

582,953 liters (154,000 gal) 507,245 liters (134,000 gal) 2 0

2 Condensate Pumps Vertical 

canned

6,511 lpm @ 91 m H2O

(1,720 gpm @ 300 ft H2O)

6,511 lpm @ 91 m H2O

(1,720 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral 

w/ HRSG)

Horizontal 

spray type

467,200 kg/hr 

(1,030,000 lb/hr)

479,447 kg/hr 

(1,057,000 lb/hr) 2 0

4

Intermediate 

Pressure Feedwater 

Pump

Horizontal 

centrifugal, 

single stage

1,590 lpm @ 27 m H2O

(420 gpm @ 90 ft H2O)

1,476 lpm @ 27 m H2O

(390 gpm @ 90 ft H2O) 2 1

5

High Pressure 

Feedwater Pump 

No. 1

Barrel type, 

multi-stage, 

centrifugal

HP water: 4,429 lpm @ 

1,890 m H2O (1,170 gpm @ 

6,200 ft H2O)

HP water: 4,618 lpm @ 

1,890 m H2O (1,220 gpm @ 

6,200 ft H2O)

2 1

6

High Pressure 

Feedwater Pump 

No. 2

Barrel type, 

multi-stage, 

centrifugal

IP water: 2,423 lpm @ 223 

m H2O (640 gpm @ 730 ft 

H2O)

IP water: 1,249 lpm @ 223 

m H2O (330 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 Cycle 

Cooling Heat 

Exchangers

Plate and 

frame

308 GJ/hr (292 MMBtu/hr) 

each

455 GJ/hr (431 MMBtu/hr) 

each 2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

171

Equipment 

No. Description Type S1B Design Condition L1B Design Condition Operating Qty Spares

11

Closed Cycle 

Cooling Water 

Pumps

Horizontal 

centrifugal

110,155 lpm @ 21 m H2O

(29,100 gpm @ 70 ft H2O)

163,151 lpm @ 21 m H2O

(43,100 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

3,596 lpm @ 18 m H2O

(950 gpm @ 60 ft H2O)

4,126 lpm @ 18 m H2O

(1,090 gpm @ 60 ft H2O) 2 1

15 Ground Water 

Pumps

Stainless steel, 

single suction

2,385 lpm @ 268 m H2O 

(630 gpm @ 880 ft H2O)

2,763 lpm @ 268 m H2O 

(730 gpm @ 880 ft H2O) 2 1

16 Filtered Water 

Pumps

Stainless steel, 

single suction

3,255 lpm @ 49 m H2O

(860 gpm @ 160 ft H2O)

3,331 lpm @ 49 m H2O

(880 gpm @ 160 ft H2O) 2 1

17 Filtered Water 

Tank

Vertical, 

cylindrical

1,570,946 liter (415,000 

gal)

1,593,658 liter (421,000 

gal) 2 0

18 Makeup Water 

Demineralizer

Anion, cation, 

and mixed bed 908 lpm (240 gpm) 416 lpm (110 gpm) 2 0

19 Liquid Waste 

Treatment System 10 years, 24-hour storm 10 years, 24-hour storm 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

172

ACCOUNT 4 GASIFIER, ASU, AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY 

Equipment 

No. Description Type S1B Design Condition L1B Design Condition Operating Qty Spares

1 Gasifier Pressurized dryfeed, entrained bed

3,538 tonne/day, 4.2 MPa

(3,900 tpd, 615 psia)

4,899 tonne/day, 4.2 MPa

(5,400 tpd, 615 psia) 2 0

2 Quench Vertical with water 

mist spray nozzles

Raw Gas - 28,096 m3/hr 

@ 4.2 MPa

(992,210 cuft/hr 

@ 610 psia)

Water - 114,957 kg/hr 

(253,436 lb/hr)

Raw Gas - 31,598 m3/hr 

@ 4.2 MPa

(1,115,882 cuft/hr 

@ 610 psia)

Water - 133,435 kg/hr 

(294,174 lb/hr)

2 0

3 Synthesis Gas 

Cooler

Convective spiralwound tube boiler

406,419 kg/hr 

(896,000 lb/hr)

Heat duty: 165 GJ/hr 

(157 MMBtu/hr)

466,293 kg/hr 

(1,028,000 lb/hr)

Heat duty: 191 GJ/hr 

(181 MMBtu/hr)

2 0

4 Synthesis Gas 

Cyclone High efficiency

406,419 kg/hr 

(896,000 lb/hr) 

Design efficiency 90%

466,293 kg/hr 

(1,028,000 lb/hr) 

Design efficiency 90%

2 0

6

Syngas Scrubber 

Including Sour 

Water Stripper

Vertical up flow 332,937 kg/hr 

(734,000 lb/hr)

393,265 kg/hr 

(867,000 lb/hr) 2 0

7 Raw Gas Coolers Shell and tube with 

condensate drain

346,998 kg/hr 

(765,000 lb/hr)

416,398 kg/hr 

(918,000 lb/hr) 8 0

8 Raw Gas 

Knockout Drum

Vertical with mist 

eliminator

303,000 kg/hr, 35°C, 

3.5 MPa

(668,000 lb/hr, 95°F, 

503 psia)

334,751 kg/hr, 35°C, 

3.5 MPa

(738,000 lb/hr, 95°F, 

503 psia)

2 0

10 Synthesis Gas 

Reheater Shell and tube 61,235 kg/hr (135,000 lb/hr)

69,400 kg/hr 

(153,000 lb/hr) 2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

173

Equipment 

No. Description Type S1B Design Condition L1B Design Condition Operating Qty Spares

11 Flare Stack

Self-supporting, 

carbon steel, 

stainless steel top, 

pilot ignition

332,937 kg/hr 

(734,000 lb/hr) syngas

393,265 kg/hr 

(867,000 lb/hr) syngas 2 0

12 ASU Main Air 

Compressor

Centrifugal, multistage

5,352 m3

/min @ 1.3 MPa

(189,000 scfm 

@ 190 psia)

6,060 m3/min @ 1.3 MPa

(214,000 scfm 

@ 190 psia)

2 0

13 Cold Box Vendor design 2,177 tonne/day (2,400

tpd) of 95% purity oxygen

2,449 tonne/day (2,700 

tpd) of 95% purity oxygen 2 0

14 Oxygen 

Compressor

Centrifugal, multistage

1,076 m3/min 

(38,000 scfm)

Suction - 0.9 MPa 

(130 psia)

Discharge - 5.1 MPa 

(740 psia)

1,246 m3/min 

(44,000 scfm)

Suction - 0.9 MPa 

(130 psia)

Discharge - 5.1 MPa 

(740 psia)

2 0

15 Primary Nitrogen 

Compressor

Centrifugal, multistage

3,426 m3/min 

(121,000 scfm)

Suction - 0.4 MPa 

(60 psia)

Discharge - 2.7 MPa 

(390 psia)

3,455 m3/min 

(122,000 scfm)

Suction - 0.4 MPa 

(60 psia)

Discharge - 2.7 MPa 

(390 psia)

2 0

16

Secondary 

Nitrogen 

Compressor

Centrifugal, singlestage

510 m3/min (18,000 scfm)

Suction - 2.6 MPa 

(380 psia)

Discharge - 5.7 MPa 

(820 psia)

566 m3/min (20,000 scfm)

Suction - 2.6 MPa 

(380 psia)

Discharge - 5.7 MPa 

(820 psia)

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

174

Equipment 

No. Description Type S1B Design Condition L1B Design Condition Operating Qty Spares

17

Transport 

Nitrogen Boost 

Compressor

Centrifugal, singlestage

204 m3/min (7,200 scfm)

Suction - 2.6 MPa (384 

psia)

Discharge - 5.6 MPa (815 

psia)

261 m3/min (9,200 scfm)

Suction - 2.6 MPa (384 

psia)

Discharge - 5.6 MPa (815 

psia)

2 0

18

Syngas Dilution 

Nitrogen Boost 

Compressor

Centrifugal, singlestage

1,478 m3/min (52,200 

scfm)

Suction - 2.6 MPa (384 

psia)

Discharge - 3.2 MPa (469 

psia)

1,781 m3/min (62,900 

scfm)

Suction - 2.6 MPa (384 

psia)

Discharge - 3.2 MPa (469 

psia)

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

175

ACCOUNT 5 SYNGAS CLEANUP

Equipment 

No. Description Type S1B Design Condition L1B Design Condition Operating Qty Spares

1 Mercury 

Adsorber

Sulfated 

carbon bed

302,546 kg/hr (667,000 lb/hr) 

35°C (95°F) 

3.4 MPa (498 psia)

334,751 kg/hr (738,000 lb/hr) 

35°C (95°F) 

3.4 MPa (498 psia)

2 0

2 Sulfur Plant Claus type 51 tonne/day (56 tpd) 61 tonne/day (67 tpd) 1 0

3 WGS Reactors Fixed bed, 

catalytic

383,286 kg/hr (845,000 lb/hr) 

232°C (450°F) 

3.8 MPa (550 psia)

416,398 kg/hr (918,000 lb/hr) 

232°C (450°F) 

3.8 MPa (550 psia)

4 0

4

Shift Reactor 

Heat Recovery 

Exchangers

Shell and Tube Exchanger 1: 197 GJ/hr 

(187 MMBtu/hr) 

Exchanger 1: 204 GJ/hr 

(193 MMBtu/hr) 4 0

5 AGR Plant Two-stage 

Selexol

309,350 kg/hr (682,000 lb/hr) 

34°C (94°F) 

3.4 MPa (488 psia)

341,555 kg/hr (753,000 lb/hr) 

35°C (94°F) 

3.4 MPa (488 psia)

2 0

6 Hydrogenation 

Reactor

Fixed bed, 

catalytic

16,970 kg/hr (37,411 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

16,993 kg/hr (37,463 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

1 0

7 Tail Gas Recycle 

Compressor Centrifugal 13,441 kg/hr (29,633 lb/hr) 14,019 kg/hr (30,906 lb/hr) 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

176

ACCOUNT 5B CO2 COMPRESSION

Equipment 

No. Description Type S1B Design Condition L1B Design Condition Operating Qty Spares

1 CO2

Compressor

Integrally geared, 

multi-stage centrifugal

1,082 m3/min @ 

15.3 MPa (38,200 scfm 

@ 2,215 psia)

1,186 m3/min @ 

15.3 MPa (41,900 scfm 

@ 2,215 psia)

4 0

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment 

No. Description Type S1B Design Condition L1B Design Condition Operating Qty Spares

1 Gas Turbine Advanced F 

class 215 MW 230 MW 2 0

2 Gas Turbine 

Generator TEWAC 240 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

ACCOUNT 7 HRSG, DUCTING AND STACK

Equipment 

No. Description Type S1B Design Condition L1B Design Condition Operating Qty Spares

1 Stack CS plate, type 

409SS liner

76 m (250 ft) high x

8.7 m (20 ft) diameter

76 m (250 ft) high x

8.7 m (20 ft) diameter 2 0

2

Heat Recovery 

Steam 

Generator

Drum, multipressure with 

economizer 

section and 

integral deaerator

Main steam - 248,798 

kg/hr, 12.4 MPa/533°C 

(548,505 lb/hr, 1,800 

psig/992°F)

Reheat steam - 312,480 

kg/hr, 3.1 MPa/533°C 

(688,900 lb/hr, 452 

psig/992°F)

Main steam - 260,051 

kg/hr, 12.4 MPa/532°C 

(573,314 lb/hr, 1,800 

psig/990°F)

Reheat steam - 358,821 

kg/hr, 3.1 MPa/532°C 

(791,066 lb/hr, 452 

psig/990°F)

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

177

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type S1B Design Condition L1B Design Condition Operating Qty Spares

1 Steam Turbine Commercially 

available

245 MW

12.4 MPa/533°C/533°C 

(1,800 psig/ 992°F/992°F)

270 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

270 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 Surface 

Condenser

Single pass, 

divided waterbox 

including vacuum 

pumps

728 GJ/hr (690 MMBtu/hr), 

Condensing temperature 

32°C (90°F), Inlet water 

temperature 9°C (48°F), 

Water temperature rise 

11°C (20°F)

791 GJ/hr (750 MMBtu/hr), 

Condensing temperature 

32°C (90°F), Inlet water 

temperature 8°C (47°F), 

Water temperature rise 

11°C (20°F)

1 0

4 Air-cooled 

Condenser ---

728 GJ/hr (690 MMBtu/hr), 

Condensing temperature 

32°C (90°F), Ambient 

temperature 6°C (42°F)

791 GJ/hr (750 MMBtu/hr), 

Condensing temperature 

32°C (90°F), Ambient 

temperature 4°C (40°F)

1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

178

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type S1B Design Condition L1B Design Condition Operating Qty Spares

1 Circulating 

Water Pumps Vertical, wet pit 272,550 lpm @ 30 m

(72,000 gpm @ 100 ft)

340,687 lpm @ 30 m

(90,000 gpm @ 100 ft) 2 1

2 Cooling 

Tower

Evaporative, 

mechanical 

draft, multi-cell

3°C (37°F) wet bulb / 9°C 

(48°F) CWT / 20°C (68°F) 

HWT / 1530 GJ/hr (1450 

MMBtu/hr) heat duty

2°C (36°F) wet bulb / 8°C 

(47°F) CWT / 19°C (67°F) 

HWT / 1899 GJ/hr (1800 

MMBtu/hr) heat duty

1 0

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type S1B Design Condition L1B Design Condition Operating Qty Spares

1 Slag Quench Tank Water bath 234,696 liters (62,000 gal) 389,897 liters (103,000 

gal) 2 0

2 Slag Crusher Roll 13 tonne/hr (14 tph) 21 tonne/hr (23 tph) 2 0

3 Slag Depressurizer Proprietary 13 tonne/hr (14 tph) 21 tonne/hr (23 tph) 2 0

4 Slag Receiving 

Tank

Horizontal, 

weir 140,060 liters (37,000 gal) 234,696 liters (62,000 gal) 2 0

5 Black Water 

Overflow Tank

Shop 

fabricated 64,352 liters (17,000 gal) 105,992 liters (28,000 gal) 2

6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 21 tonne/hr (23 tph) 2 0

7 Slag Separation 

Screen Vibrating 13 tonne/hr (14 tph) 21 tonne/hr (23 tph) 2 0

8 Coarse Slag 

Conveyor Belt/bucket 13 tonne/hr (14 tph) 21 tonne/hr (23 tph) 2 0

9 Fine Ash Settling 

Tank

Vertical, 

gravity 200,627 liters (53,000 gal) 333,116 liters (88,000 gal) 2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

179

Equipment 

No. Description Type S1B Design Condition L1B Design Condition Operating Qty Spares

10 Fine Ash Recycle 

Pumps

Horizontal 

centrifugal

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

76 lpm @ 14 m H2O

(20 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage 

Tank Field erected 64,352 liters (17,000 gal) 105,992 liters (28,000 gal) 2 0

12 Grey Water Pumps Centrifugal 227 lpm @ 433 m H2O

(60 gpm @ 1,420 ft H2O)

379 lpm @ 433 m H2O

(100 gpm @ 1,420 ft H2O) 2 2

13 Slag Storage Bin Vertical, field 

erected 907 tonne (1,000 tons) 1,451 tonne (1,600 tons) 2 0

14 Unloading 

Equipment

Telescoping 

chute 100 tonne/hr (110 tph) 172 tonne/hr (190 tph) 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

180

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type S1B Design Condition L1B Design Condition

Operating 

Qty Spares

1 CTG Step-up 

Transformer Oil-filled 24 kV/345 kV, 240 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, 270 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, 

81 MVA, 3-ph, 60 Hz

345 kV/13.8 kV, 

91 MVA, 3-ph, 60 Hz 2 0

4

Medium Voltage 

Auxiliary 

Transformer

Oil-filled 24 kV/4.16 kV, 

47 MVA, 3-ph, 60 Hz

24 kV/4.16 kV, 

53 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 1 1

6

CTG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 2 0

7

STG Isolated Phase 

Bus Duct and Tap 

Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 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
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

181

ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment 

No. Description Type S1B Design Condition

L1B Design 

Condition

Operating 

Qty Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator printer (laser 

color); Engineering printer (laser B&W)

Operator stations/printers and 

engineering stations/printers 1 0

2 DCS -

Processor

Microprocessor with redundant 

input/output N/A 1 0

3 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

182

3.2.11 Case S1B and L1B Cost Estimating

Costs Results

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-48 shows 

the TPC summary organized by cost account for the PRB coal case (S1B) and Exhibit 3-52

shows the same information for the lignite coal case (L1B). A more detailed breakdown of the 

capital costs is shown in Exhibit 3-49 for S1B and Exhibit 3-53 for L1B. Exhibit 3-50 and 

Exhibit 3-54 show the calculation and addition of owner’s costs to determine the TOC, used to 

calculate COE. Exhibit 3-51 shows the initial and annual O&M costs for Case S1B and 

Exhibit 3-55 shows the same information for Case L1B.

The estimated TOC of SCGP with CO2 capture using PRB coal is $4,253/kW and using lignite 

coal is $4,378/kW. Process contingency represents about 3 percent, project contingency 

12 percent, and owner’s costs 18 percent of TOC for both cases. The COE is 119.7 mills/kWh in 

the PRB case and 121.9 mills/kWh in the lignite case.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

183

Exhibit 3-48 Case S1B Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S1B - Shell IGCC w/ CO2

Plant Size: 471.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING $16,015 $2,976 $12,420 $0 $0 $31,412 $2,851 $0 $6,853 $41,115 $87

 2 COAL & SORBENT PREP & FEED $120,801 $10,066 $20,611 $0 $0 $151,477 $13,141 $0 $32,924 $197,542 $419

 3 FEEDWATER & MISC. BOP SYSTEMS $7,824 $6,231 $7,649 $0 $0 $21,705 $2,046 $0 $5,466 $29,217 $62

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $154,035 $0 $65,678 $0 $0 $219,713 $19,628 $30,204 $41,437 $310,981 $659

4.2 Syngas Cooling w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $182,062 $0 w/equip. $0 $0 $182,062 $17,647 $0 $19,971 $219,680 $466

4.4-4.9 Other Gasification Equipment $24,921 $10,768 $15,384 $0 $0 $51,072 $4,892 $0 $11,994 $67,958 $144

SUBTOTAL 4 $361,019 $10,768 $81,062 $0 $0 $452,848 $42,168 $30,204 $73,401 $598,620 $1,269

 5A GAS CLEANUP & PIPING $85,262 $3,037 $70,594 $0 $0 $158,893 $15,346 $25,676 $40,132 $240,047 $509

5B CO2 COMPRESSION $18,189 $0 $10,541 $0 $0 $28,730 $2,766 $0 $6,299 $37,795 $80

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,610 $9,348 $9,861 $11,782 $129,600 $275

6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5

SUBTOTAL 6 $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $280

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $31,403 $0 $4,465 $0 $0 $35,869 $3,410 $0 $3,928 $43,207 $92

7.2-7.9 SCR System, Ductwork and Stack $3,524 $2,513 $3,324 $0 $0 $9,361 $868 $0 $1,666 $11,895 $25

SUBTOTAL 7 $34,928 $2,513 $7,789 $0 $0 $45,230 $4,279 $0 $5,594 $55,102 $117

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $25,807 $0 $4,350 $0 $0 $30,157 $2,893 $0 $3,305 $36,355 $77

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $32,695 $883 $10,769 $0 $0 $44,347 $4,309 $0 $9,892 $58,547 $124

SUBTOTAL 8 $58,502 $883 $15,119 $0 $0 $74,504 $7,202 $0 $13,197 $94,903 $201

 9 COOLING WATER SYSTEM $7,191 $7,127 $6,051 $0 $0 $20,369 $1,892 $0 $4,564 $26,824 $57

10 ASH/SPENT SORBENT HANDLING SYS $19,291 $1,481 $9,573 $0 $0 $30,345 $2,911 $0 $3,632 $36,888 $78

11 ACCESSORY ELECTRIC PLANT $31,184 $12,483 $24,269 $0 $0 $67,936 $5,844 $0 $14,034 $87,815 $186

12 INSTRUMENTATION & CONTROL $10,989 $2,022 $7,081 $0 $0 $20,092 $1,821 $1,005 $3,818 $26,736 $57

13 IMPROVEMENTS TO SITE $3,322 $1,958 $8,196 $0 $0 $13,476 $1,331 $0 $4,442 $19,249 $41

14 BUILDINGS & STRUCTURES $0 $6,408 $7,287 $0 $0 $13,694 $1,246 $0 $2,455 $17,396 $37

 

TOTAL COST $866,544 $68,758 $295,716 $0 $0 $1,231,019 $114,350 $66,745 $229,150 $1,641,264 $3,480

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

184

Exhibit 3-49 Case S1B Total Plant Cost Summary Details

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S1B - Shell IGCC w/ CO2

Plant Size: 471.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $4,206 $0 $2,055 $0 $0 $6,261 $561 $0 $1,364 $8,186 $17

1.2 Coal Stackout & Reclaim $5,435 $0 $1,318 $0 $0 $6,752 $592 $0 $1,469 $8,813 $19

1.3 Coal Conveyors & Yd Crush $5,053 $0 $1,304 $0 $0 $6,357 $558 $0 $1,383 $8,298 $18

1.4 Other Coal Handling $1,322 $0 $302 $0 $0 $1,624 $142 $0 $353 $2,119 $4

1.5 Sorbent Receive & Unload $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

1.7 Sorbent Conveyors $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

1.9 Coal & Sorbent Hnd.Foundations $0 $2,976 $7,442 $0 $0 $10,418 $999 $0 $2,283 $13,700 $29

SUBTOTAL 1. $16,015 $2,976 $12,420 $0 $0 $31,412 $2,851 $0 $6,853 $41,115 $87

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $48,633 $2,922 $7,086 $0 $0 $58,641 $5,060 $0 $12,740 $76,442 $162

2.2 Prepared Coal Storage & Feed $2,091 $500 $328 $0 $0 $2,919 $250 $0 $634 $3,802 $8

2.3 Dry Coal Injection System $68,810 $799 $6,390 $0 $0 $75,999 $6,546 $0 $16,509 $99,054 $210

2.4 Misc.Coal Prep & Feed $1,267 $922 $2,764 $0 $0 $4,952 $455 $0 $1,081 $6,489 $14

2.5 Sorbent Prep Equipment $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

2.7 Sorbent Injection System $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

2.9 Coal & Sorbent Feed Foundation $0 $4,924 $4,042 $0 $0 $8,966 $830 $0 $1,959 $11,756 $25

SUBTOTAL 2. $120,801 $10,066 $20,611 $0 $0 $151,477 $13,141 $0 $32,924 $197,542 $419

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,263 $3,887 $2,052 $0 $0 $8,203 $760 $0 $1,792 $10,755 $23

3.2 Water Makeup & Pretreating $491 $51 $274 $0 $0 $816 $78 $0 $268 $1,162 $2

3.3 Other Feedwater Subsystems $1,238 $418 $377 $0 $0 $2,034 $183 $0 $443 $2,660 $6

3.4 Service Water Systems $281 $578 $2,006 $0 $0 $2,865 $279 $0 $943 $4,088 $9

3.5 Other Boiler Plant Systems $1,506 $584 $1,447 $0 $0 $3,537 $335 $0 $774 $4,647 $10

3.6 FO Supply Sys & Nat Gas $303 $571 $533 $0 $0 $1,407 $136 $0 $308 $1,851 $4

3.7 Waste Treatment Equipment $686 $0 $418 $0 $0 $1,104 $108 $0 $363 $1,575 $3

3.8 Misc. Power Plant Equipment $1,057 $141 $542 $0 $0 $1,740 $168 $0 $573 $2,481 $5

SUBTOTAL 3. $7,824 $6,231 $7,649 $0 $0 $21,705 $2,046 $0 $5,466 $29,217 $62

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $154,035 $0 $65,678 $0 $0 $219,713 $19,628 $30,204 $41,437 $310,981 $659

4.2 Syngas Cooling w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $182,062 $0 w/equip. $0 $0 $182,062 $17,647 $0 $19,971 $219,680 $466

4.4 LT Heat Recovery & FG Saturation $24,921 $0 $9,474 $0 $0 $34,395 $3,357 $0 $7,550 $45,302 $96

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,428 $581 $0 $0 $2,009 $193 $0 $440 $2,642 $6

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $9,340 $5,329 $0 $0 $14,669 $1,343 $0 $4,003 $20,014 $42

SUBTOTAL 4. $361,019 $10,768 $81,062 $0 $0 $452,848 $42,168 $30,204 $73,401 $598,620 $1,269

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

185

Exhibit 3-49 Case S1B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S1B - Shell IGCC w/ CO2

Plant Size: 471.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $69,120 $0 $58,650 $0 $0 $127,770 $12,357 $25,554 $33,136 $198,817 $422

5A.2 Elemental Sulfur Plant $5,103 $1,017 $6,584 $0 $0 $12,704 $1,234 $0 $2,788 $16,725 $35

5A.3 Mercury Removal $1,388 $0 $1,056 $0 $0 $2,444 $236 $122 $560 $3,362 $7

5A.4 Shift Reactors $7,422 $0 $2,988 $0 $0 $10,410 $998 $0 $2,282 $13,690 $29

5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

5A.5 Blowback Gas Systems $2,228 $375 $211 $0 $0 $2,815 $267 $0 $616 $3,698 $8

5A.6 Fuel Gas Piping $0 $817 $572 $0 $0 $1,390 $129 $0 $304 $1,822 $4

5A.9 HGCU Foundations $0 $828 $534 $0 $0 $1,361 $125 $0 $446 $1,932 $4

SUBTOTAL 5A. $85,262 $3,037 $70,594 $0 $0 $158,893 $15,346 $25,676 $40,132 $240,047 $509

5B CO2 COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $18,189 $0 $10,541 $0 $0 $28,730 $2,766 $0 $6,299 $37,795 $80

SUBTOTAL 5B. $18,189 $0 $10,541 $0 $0 $28,730 $2,766 $0 $6,299 $37,795 $80

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,610 $9,348 $9,861 $11,782 $129,600 $275

6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5

SUBTOTAL 6. $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $280

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $31,403 $0 $4,465 $0 $0 $35,869 $3,410 $0 $3,928 $43,207 $92

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,807 $1,322 $0 $0 $3,128 $275 $0 $681 $4,084 $9

7.4 Stack $3,524 $0 $1,324 $0 $0 $4,849 $465 $0 $531 $5,844 $12

7.9 HRSG,Duct & Stack Foundations $0 $706 $678 $0 $0 $1,384 $129 $0 $454 $1,967 $4

SUBTOTAL 7. $34,928 $2,513 $7,789 $0 $0 $45,230 $4,279 $0 $5,594 $55,102 $117

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $25,807 $0 $4,350 $0 $0 $30,157 $2,893 $0 $3,305 $36,355 $77

8.2 Turbine Plant Auxiliaries $178 $0 $408 $0 $0 $586 $57 $0 $64 $708 $2

8.3a Condenser & Auxiliaries $2,805 $0 $896 $0 $0 $3,701 $354 $0 $405 $4,460 $9

8.3b Air Cooled Condenser $25,704 $0 $5,153 $0 $0 $30,857 $3,086 $0 $6,788 $40,731 $86

8.4 Steam Piping $4,008 $0 $2,820 $0 $0 $6,828 $587 $0 $1,854 $9,268 $20

8.9 TG Foundations $0 $883 $1,492 $0 $0 $2,375 $225 $0 $780 $3,381 $7

SUBTOTAL 8. $58,502 $883 $15,119 $0 $0 $74,504 $7,202 $0 $13,197 $94,903 $201

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $4,957 $0 $902 $0 $0 $5,858 $558 $0 $962 $7,378 $16

9.2 Circulating Water Pumps $1,283 $0 $79 $0 $0 $1,362 $115 $0 $222 $1,698 $4

9.3 Circ.Water System Auxiliaries $113 $0 $16 $0 $0 $129 $12 $0 $21 $163 $0

9.4 Circ.Water Piping $0 $4,723 $1,224 $0 $0 $5,948 $538 $0 $1,297 $7,782 $17

9.5 Make-up Water System $281 $0 $402 $0 $0 $684 $66 $0 $150 $899 $2

9.6 Component Cooling Water Sys $558 $667 $474 $0 $0 $1,699 $159 $0 $372 $2,230 $5

9.9 Circ.Water System Foundations $0 $1,737 $2,952 $0 $0 $4,689 $445 $0 $1,540 $6,674 $14

SUBTOTAL 9. $7,191 $7,127 $6,051 $0 $0 $20,369 $1,892 $0 $4,564 $26,824 $57

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

186

Exhibit 3-49 Case S1B Total Plant Cost Summary Details (Continued) Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S1B - Shell IGCC w/ CO2

Plant Size: 471.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $16,803 $0 $8,287 $0 $0 $25,090 $2,411 $0 $2,750 $30,251 $64

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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

10.4 High Temperature Ash Piping $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

10.6 Ash Storage Silos $564 $0 $614 $0 $0 $1,177 $114 $0 $194 $1,485 $3

10.7 Ash Transport & Feed Equipment $756 $0 $182 $0 $0 $939 $88 $0 $154 $1,180 $3

10.8 Misc. Ash Handling Equipment $1,168 $1,431 $428 $0 $0 $3,027 $288 $0 $497 $3,812 $8

10.9 Ash/Spent Sorbent Foundation $0 $50 $63 $0 $0 $112 $11 $0 $37 $160 $0

SUBTOTAL 10. $19,291 $1,481 $9,573 $0 $0 $30,345 $2,911 $0 $3,632 $36,888 $78

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $893 $0 $883 $0 $0 $1,776 $170 $0 $195 $2,140 $5

11.2 Station Service Equipment $4,675 $0 $421 $0 $0 $5,096 $470 $0 $557 $6,122 $13

11.3 Switchgear & Motor Control $8,642 $0 $1,572 $0 $0 $10,214 $947 $0 $1,674 $12,835 $27

11.4 Conduit & Cable Tray $0 $4,015 $13,244 $0 $0 $17,258 $1,669 $0 $4,732 $23,659 $50

11.5 Wire & Cable $0 $7,670 $5,040 $0 $0 $12,710 $923 $0 $3,408 $17,042 $36

11.6 Protective Equipment $0 $653 $2,375 $0 $0 $3,028 $296 $0 $499 $3,822 $8

11.7 Standby Equipment $223 $0 $217 $0 $0 $440 $42 $0 $72 $554 $1

11.8 Main Power Transformers $16,752 $0 $134 $0 $0 $16,886 $1,277 $0 $2,724 $20,887 $44

11.9 Electrical Foundations $0 $146 $382 $0 $0 $528 $51 $0 $174 $752 $2

SUBTOTAL 11. $31,184 $12,483 $24,269 $0 $0 $67,936 $5,844 $0 $14,034 $87,815 $186

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,085 $0 $724 $0 $0 $1,809 $171 $90 $311 $2,382 $5

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $249 $0 $160 $0 $0 $409 $39 $20 $94 $562 $1

12.7 Computer & Accessories $5,787 $0 $185 $0 $0 $5,972 $548 $299 $682 $7,501 $16

12.8 Instrument Wiring & Tubing $0 $2,022 $4,133 $0 $0 $6,154 $522 $308 $1,746 $8,730 $19

12.9 Other I & C Equipment $3,868 $0 $1,878 $0 $0 $5,747 $541 $287 $986 $7,561 $16

SUBTOTAL 12. $10,989 $2,022 $7,081 $0 $0 $20,092 $1,821 $1,005 $3,818 $26,736 $57

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $104 $2,228 $0 $0 $2,332 $232 $0 $769 $3,332 $7

13.2 Site Improvements $0 $1,854 $2,463 $0 $0 $4,317 $426 $0 $1,423 $6,166 $13

13.3 Site Facilities $3,322 $0 $3,505 $0 $0 $6,827 $673 $0 $2,250 $9,750 $21

SUBTOTAL 13. $3,322 $1,958 $8,196 $0 $0 $13,476 $1,331 $0 $4,442 $19,249 $41

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1

14.2 Steam Turbine Building $0 $2,205 $3,142 $0 $0 $5,347 $492 $0 $876 $6,714 $14

14.3 Administration Building $0 $856 $621 $0 $0 $1,477 $132 $0 $241 $1,850 $4

14.4 Circulation Water Pumphouse $0 $160 $85 $0 $0 $245 $21 $0 $40 $306 $1

14.5 Water Treatment Buildings $0 $410 $400 $0 $0 $810 $73 $0 $132 $1,016 $2

14.6 Machine Shop $0 $438 $300 $0 $0 $738 $66 $0 $121 $924 $2

14.7 Warehouse $0 $707 $457 $0 $0 $1,164 $103 $0 $190 $1,457 $3

14.8 Other Buildings & Structures $0 $422 $329 $0 $0 $751 $67 $0 $164 $982 $2

14.9 Waste Treating Building & Str. $0 $944 $1,804 $0 $0 $2,748 $256 $0 $601 $3,605 $8

SUBTOTAL 14. $0 $6,408 $7,287 $0 $0 $13,694 $1,246 $0 $2,455 $17,396 $37

TOTAL COST $866,544 $68,758 $295,716 $0 $0 $1,231,019 $114,350 $66,745 $229,150 $1,641,264 $3,480

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

187

Exhibit 3-50 Case S1B Owner’s Costs

Owner's Costs $x1000 $/kW

Preproduction Costs

6 Months Fixed O&M $13,825 $29

1 Month Variable O&M $3,642 $8

25% of 1 Months Fuel Cost at 100% CF $814 $2

2% of TPC $32,825 $70

Total $51,106 $108

Inventory Capital

60 day supply of consumables at 100% CF $6,943 $15

0.5% of TPC (spare parts) $8,206 $17

Total $15,150 $32

 Initial Cost for Catalyst and Chemicals $6,959 $15

Land $900 $2

Other Owner's Costs $246,190 $522

Financing Costs $44,314 $94

Total Owner's Costs $364,619 $773

Total Overnight Cost (TOC) $2,005,883 $4,253

TASC Multiplier 1.140

Total As-Spent Cost (TASC) $2,286,707 $4,849
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

188

Exhibit 3-51 Case S1B Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case S1B - Shell IGCC w/ CO2 Heat Rate-net (Btu/kWh): 10641

MWe-net: 472

Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 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-O.J.'s 16.0 16.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $6,313,507 $13.387

Maintenance Labor Cost $15,805,936 $33.515

Administrative & Support Labor $5,529,861 $11.725

Property Taxes and Insurance $32,825,287 $69.603

TOTAL FIXED OPERATING COSTS $60,474,591 $128.230

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $29,588,685 $0.00895

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

Water (/1000 gallons) 0 2,451 1.08 $0 $774,109 $0.00023

Chemicals

MU & WT Chem.(lbs) 0 14,602 0.17 $0 $737,906 $0.00022

Carbon (Mercury Removal) (lb) 116,627 160 1.05 $122,478 $48,991 $0.00001

COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000

Water Gas Shift Catalyst (ft3) 6,034 4.13 498.83 $3,009,845 $601,969 $0.00018

Selexol Solution (gal) 285,640 91 13.40 $3,827,073 $355,483 $0.00011

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip. 0.77 131.27 $0 $29,430 $0.00001

Subtotal Chemicals $6,959,397 $1,773,780 $0.00054

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 160 0.42 $0 $19,457 $0.00001

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 593 16.23 $0 $2,811,013 $0.00085

Subtotal Waste Disposal $0 $2,830,470 $0.00086

By-products & Emissions 

Sulfur (tons) 0 51 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $6,959,397 $34,967,044 $0.01058

Fuel (ton) 0 7,032 15.22 $0 $31,243,745 $0.00945
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

189

Exhibit 3-52 Case L1B Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-20

Project: Low Rank Western Coal Baseline Study

Case: Case L1B - Shell IGCC w/ CO2

Plant Size: 500.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING $19,636 $3,649 $15,228 $0 $0 $38,513 $3,496 $0 $8,402 $50,410 $101

 2 COAL & SORBENT PREP & FEED $147,143 $12,451 $25,327 $0 $0 $184,922 $16,045 $0 $40,193 $241,160 $482

 3 FEEDWATER & MISC. BOP SYSTEMS $8,297 $6,517 $8,203 $0 $0 $23,016 $2,171 $0 $5,817 $31,004 $62

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $162,263 $0 $69,450 $0 $0 $231,713 $20,694 $32,004 $43,666 $328,076 $656

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $198,128 $0 w/equip. $0 $0 $198,128 $19,204 $0 $21,733 $239,066 $478

4.4-4.9 Other Gasification Equipment $26,410 $12,329 $16,813 $0 $0 $55,552 $5,316 $0 $13,093 $73,961 $148

SUBTOTAL 4 $386,801 $12,329 $86,263 $0 $0 $485,393 $45,214 $32,004 $78,493 $641,103 $1,282

 5A GAS CLEANUP & PIPING $91,544 $3,296 $75,944 $0 $0 $170,784 $16,495 $27,522 $43,117 $257,918 $516

5B CO2 COMPRESSION $20,109 $0 $11,415 $0 $0 $31,524 $3,034 $0 $6,912 $41,470 $83

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,599 $259

6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5

SUBTOTAL 6 $92,026 $806 $7,475 $0 $0 $100,307 $9,507 $9,861 $12,339 $132,014 $264

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,673 $0 $4,646 $0 $0 $37,319 $3,548 $0 $4,087 $44,954 $90

7.2-7.9 SCR System, Ductwork and Stack $3,522 $2,511 $3,322 $0 $0 $9,355 $867 $0 $1,665 $11,887 $24

SUBTOTAL 7 $36,195 $2,511 $7,967 $0 $0 $46,673 $4,416 $0 $5,751 $56,840 $114

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $27,623 $0 $4,708 $0 $0 $32,332 $3,102 $0 $3,543 $38,977 $78

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $34,547 $949 $11,364 $0 $0 $46,860 $4,555 $0 $10,446 $61,862 $124

SUBTOTAL 8 $62,171 $949 $16,072 $0 $0 $79,192 $7,657 $0 $13,989 $100,839 $202

 9 COOLING WATER SYSTEM $8,339 $8,139 $6,908 $0 $0 $23,386 $2,172 $0 $5,228 $30,786 $62

10 ASH/SPENT SORBENT HANDLING SYS $26,501 $1,960 $13,147 $0 $0 $41,608 $3,992 $0 $4,965 $50,565 $101

11 ACCESSORY ELECTRIC PLANT $33,167 $13,157 $25,566 $0 $0 $71,890 $6,181 $0 $14,839 $92,909 $186

12 INSTRUMENTATION & CONTROL $11,243 $2,068 $7,244 $0 $0 $20,556 $1,863 $1,028 $3,907 $27,353 $55

13 IMPROVEMENTS TO SITE $3,438 $2,027 $8,484 $0 $0 $13,949 $1,377 $0 $4,598 $19,924 $40

14 BUILDINGS & STRUCTURES $0 $6,664 $7,603 $0 $0 $14,267 $1,299 $0 $2,553 $18,120 $36

 

TOTAL COST $946,611 $76,524 $322,846 $0 $0 $1,345,980 $124,918 $70,414 $251,103 $1,792,415 $3,584

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

190

Exhibit 3-53 Case L1B Total Plant Cost Summary Details

Client: USDOE/NETL Report Date: 2010-Jan-20

Project: Low Rank Western Coal Baseline Study

Case: Case L1B - Shell IGCC w/ CO2

Plant Size: 500.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $5,157 $0 $2,520 $0 $0 $7,676 $688 $0 $1,673 $10,037 $20

1.2 Coal Stackout & Reclaim $6,663 $0 $1,615 $0 $0 $8,279 $726 $0 $1,801 $10,805 $22

1.3 Coal Conveyors & Yd Crush $6,195 $0 $1,598 $0 $0 $7,794 $684 $0 $1,696 $10,173 $20

1.4 Other Coal Handling $1,621 $0 $370 $0 $0 $1,991 $174 $0 $433 $2,598 $5

1.5 Sorbent Receive & Unload $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

1.7 Sorbent Conveyors $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

1.9 Coal & Sorbent Hnd.Foundations $0 $3,649 $9,124 $0 $0 $12,773 $1,224 $0 $2,799 $16,797 $34

SUBTOTAL 1. $19,636 $3,649 $15,228 $0 $0 $38,513 $3,496 $0 $8,402 $50,410 $101

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $60,417 $3,629 $8,803 $0 $0 $72,849 $6,286 $0 $15,827 $94,963 $190

2.2 Prepared Coal Storage & Feed $2,511 $601 $394 $0 $0 $3,506 $300 $0 $761 $4,567 $9

2.3 Dry Coal Injection System $82,642 $959 $7,675 $0 $0 $91,276 $7,861 $0 $19,828 $118,965 $238

2.4 Misc.Coal Prep & Feed $1,574 $1,145 $3,433 $0 $0 $6,152 $565 $0 $1,344 $8,061 $16

2.5 Sorbent Prep Equipment $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

2.7 Sorbent Injection System $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

2.9 Coal & Sorbent Feed Foundation $0 $6,117 $5,022 $0 $0 $11,138 $1,032 $0 $2,434 $14,604 $29

SUBTOTAL 2. $147,143 $12,451 $25,327 $0 $0 $184,922 $16,045 $0 $40,193 $241,160 $482

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,329 $4,000 $2,112 $0 $0 $8,441 $782 $0 $1,845 $11,068 $22

3.2 Water Makeup & Pretreating $542 $57 $303 $0 $0 $901 $86 $0 $296 $1,284 $3

3.3 Other Feedwater Subsystems $1,274 $431 $388 $0 $0 $2,093 $188 $0 $456 $2,737 $5

3.4 Service Water Systems $310 $639 $2,216 $0 $0 $3,165 $309 $0 $1,042 $4,516 $9

3.5 Other Boiler Plant Systems $1,664 $645 $1,598 $0 $0 $3,907 $371 $0 $856 $5,134 $10

3.6 FO Supply Sys & Nat Gas $317 $598 $558 $0 $0 $1,472 $142 $0 $323 $1,937 $4

3.7 Waste Treatment Equipment $758 $0 $462 $0 $0 $1,220 $119 $0 $402 $1,740 $3

3.8 Misc. Power Plant Equipment $1,103 $148 $566 $0 $0 $1,817 $175 $0 $598 $2,589 $5

SUBTOTAL 3. $8,297 $6,517 $8,203 $0 $0 $23,016 $2,171 $0 $5,817 $31,004 $62

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $162,263 $0 $69,450 $0 $0 $231,713 $20,694 $32,004 $43,666 $328,076 $656

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $198,128 $0 w/equip. $0 $0 $198,128 $19,204 $0 $21,733 $239,066 $478

4.4 LT Heat Recovery & FG Saturation $26,410 $0 $10,040 $0 $0 $36,450 $3,557 $0 $8,001 $48,008 $96

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,599 $651 $0 $0 $2,250 $216 $0 $493 $2,959 $6

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $10,730 $6,122 $0 $0 $16,852 $1,543 $0 $4,599 $22,993 $46

SUBTOTAL 4. $386,801 $12,329 $86,263 $0 $0 $485,393 $45,214 $32,004 $78,493 $641,103 $1,282

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

191

Exhibit 3-53 Case L1B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2010-Jan-20

Project: Low Rank Western Coal Baseline Study

Case: Case L1B - Shell IGCC w/ CO2

Plant Size: 500.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $74,094 $0 $62,870 $0 $0 $136,964 $13,246 $27,393 $35,521 $213,123 $426

5A.2 Elemental Sulfur Plant $5,754 $1,147 $7,423 $0 $0 $14,324 $1,391 $0 $3,143 $18,858 $38

5A.3 Mercury Removal $1,465 $0 $1,115 $0 $0 $2,580 $249 $129 $592 $3,549 $7

5A.4 Shift Reactors $7,788 $0 $3,135 $0 $0 $10,923 $1,047 $0 $2,394 $14,364 $29

5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

5A.5 Blowback Gas Systems $2,444 $411 $232 $0 $0 $3,086 $293 $0 $676 $4,055 $8

5A.6 Fuel Gas Piping $0 $864 $605 $0 $0 $1,469 $136 $0 $321 $1,926 $4

5A.9 HGCU Foundations $0 $875 $564 $0 $0 $1,439 $132 $0 $471 $2,042 $4

SUBTOTAL 5A. $91,544 $3,296 $75,944 $0 $0 $170,784 $16,495 $27,522 $43,117 $257,918 $516

5B CO2 COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $20,109 $0 $11,415 $0 $0 $31,524 $3,034 $0 $6,912 $41,470 $83

SUBTOTAL 5B. $20,109 $0 $11,415 $0 $0 $31,524 $3,034 $0 $6,912 $41,470 $83

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,599 $259

6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5

SUBTOTAL 6. $92,026 $806 $7,475 $0 $0 $100,307 $9,507 $9,861 $12,339 $132,014 $264

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,673 $0 $4,646 $0 $0 $37,319 $3,548 $0 $4,087 $44,954 $90

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,805 $1,321 $0 $0 $3,126 $275 $0 $680 $4,081 $8

7.4 Stack $3,522 $0 $1,323 $0 $0 $4,845 $464 $0 $531 $5,840 $12

7.9 HRSG,Duct & Stack Foundations $0 $706 $678 $0 $0 $1,383 $129 $0 $454 $1,966 $4

SUBTOTAL 7. $36,195 $2,511 $7,967 $0 $0 $46,673 $4,416 $0 $5,751 $56,840 $114

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $27,623 $0 $4,708 $0 $0 $32,332 $3,102 $0 $3,543 $38,977 $78

8.2 Turbine Plant Auxiliaries $191 $0 $439 $0 $0 $630 $62 $0 $69 $761 $2

8.3a Condenser & Auxiliaries $2,973 $0 $950 $0 $0 $3,923 $375 $0 $430 $4,728 $9

8.3b Air Cooled Condenser $27,249 $0 $5,463 $0 $0 $32,711 $3,271 $0 $7,197 $43,179 $86

8.4 Steam Piping $4,134 $0 $2,908 $0 $0 $7,043 $605 $0 $1,912 $9,559 $19

8.9 TG Foundations $0 $949 $1,604 $0 $0 $2,553 $242 $0 $839 $3,634 $7

SUBTOTAL 8. $62,171 $949 $16,072 $0 $0 $79,192 $7,657 $0 $13,989 $100,839 $202

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $5,766 $0 $1,049 $0 $0 $6,815 $649 $0 $1,120 $8,584 $17

9.2 Circulating Water Pumps $1,500 $0 $99 $0 $0 $1,599 $135 $0 $260 $1,993 $4

9.3 Circ.Water System Auxiliaries $129 $0 $18 $0 $0 $148 $14 $0 $24 $186 $0

9.4 Circ.Water Piping $0 $5,400 $1,400 $0 $0 $6,800 $615 $0 $1,483 $8,897 $18

9.5 Make-up Water System $306 $0 $438 $0 $0 $744 $71 $0 $163 $978 $2

9.6 Component Cooling Water Sys $637 $762 $542 $0 $0 $1,942 $182 $0 $425 $2,549 $5

9.9 Circ.Water System Foundations $0 $1,977 $3,361 $0 $0 $5,339 $506 $0 $1,753 $7,598 $15

SUBTOTAL 9. $8,339 $8,139 $6,908 $0 $0 $23,386 $2,172 $0 $5,228 $30,786 $62

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

192

Exhibit 3-53 Case L1B Total Plant Cost Summary Details (Continued) Client: USDOE/NETL Report Date: 2010-Jan-20

Project: Low Rank Western Coal Baseline Study

Case: Case L1B - Shell IGCC w/ CO2

Plant Size: 500.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $23,209 $0 $11,445 $0 $0 $34,654 $3,330 $0 $3,798 $41,782 $84

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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

10.4 High Temperature Ash Piping $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

10.6 Ash Storage Silos $746 $0 $812 $0 $0 $1,558 $151 $0 $256 $1,965 $4

10.7 Ash Transport & Feed Equipment $1,001 $0 $241 $0 $0 $1,242 $116 $0 $204 $1,562 $3

10.8 Misc. Ash Handling Equipment $1,545 $1,894 $566 $0 $0 $4,005 $381 $0 $658 $5,044 $10

10.9 Ash/Spent Sorbent Foundation $0 $66 $83 $0 $0 $149 $14 $0 $49 $212 $0

SUBTOTAL 10. $26,501 $1,960 $13,147 $0 $0 $41,608 $3,992 $0 $4,965 $50,565 $101

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $932 $0 $922 $0 $0 $1,853 $177 $0 $203 $2,233 $4

11.2 Station Service Equipment $4,926 $0 $444 $0 $0 $5,370 $495 $0 $587 $6,452 $13

11.3 Switchgear & Motor Control $9,108 $0 $1,656 $0 $0 $10,764 $998 $0 $1,764 $13,527 $27

11.4 Conduit & Cable Tray $0 $4,231 $13,957 $0 $0 $18,188 $1,759 $0 $4,987 $24,934 $50

11.5 Wire & Cable $0 $8,084 $5,311 $0 $0 $13,395 $973 $0 $3,592 $17,960 $36

11.6 Protective Equipment $0 $689 $2,507 $0 $0 $3,196 $312 $0 $526 $4,035 $8

11.7 Standby Equipment $230 $0 $225 $0 $0 $455 $43 $0 $75 $574 $1

11.8 Main Power Transformers $17,971 $0 $141 $0 $0 $18,112 $1,370 $0 $2,922 $22,404 $45

11.9 Electrical Foundations $0 $153 $402 $0 $0 $555 $53 $0 $183 $791 $2

SUBTOTAL 11. $33,167 $13,157 $25,566 $0 $0 $71,890 $6,181 $0 $14,839 $92,909 $186

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,110 $0 $741 $0 $0 $1,851 $175 $93 $318 $2,437 $5

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $255 $0 $164 $0 $0 $419 $40 $21 $96 $575 $1

12.7 Computer & Accessories $5,921 $0 $190 $0 $0 $6,110 $561 $306 $698 $7,674 $15

12.8 Instrument Wiring & Tubing $0 $2,068 $4,228 $0 $0 $6,296 $534 $315 $1,786 $8,932 $18

12.9 Other I & C Equipment $3,958 $0 $1,922 $0 $0 $5,879 $553 $294 $1,009 $7,736 $15

SUBTOTAL 12. $11,243 $2,068 $7,244 $0 $0 $20,556 $1,863 $1,028 $3,907 $27,353 $55

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $108 $2,306 $0 $0 $2,414 $240 $0 $796 $3,449 $7

13.2 Site Improvements $0 $1,919 $2,550 $0 $0 $4,469 $441 $0 $1,473 $6,382 $13

13.3 Site Facilities $3,438 $0 $3,628 $0 $0 $7,067 $697 $0 $2,329 $10,092 $20

SUBTOTAL 13. $3,438 $2,027 $8,484 $0 $0 $13,949 $1,377 $0 $4,598 $19,924 $40

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1

14.2 Steam Turbine Building $0 $2,340 $3,334 $0 $0 $5,674 $522 $0 $929 $7,125 $14

14.3 Administration Building $0 $874 $634 $0 $0 $1,508 $134 $0 $246 $1,888 $4

14.4 Circulation Water Pumphouse $0 $164 $87 $0 $0 $251 $22 $0 $41 $314 $1

14.5 Water Treatment Buildings $0 $453 $442 $0 $0 $895 $81 $0 $146 $1,122 $2

14.6 Machine Shop $0 $447 $306 $0 $0 $753 $67 $0 $123 $943 $2

14.7 Warehouse $0 $722 $466 $0 $0 $1,188 $105 $0 $194 $1,488 $3

14.8 Other Buildings & Structures $0 $433 $337 $0 $0 $769 $69 $0 $168 $1,006 $2

14.9 Waste Treating Building & Str. $0 $967 $1,848 $0 $0 $2,815 $262 $0 $615 $3,693 $7

SUBTOTAL 14. $0 $6,664 $7,603 $0 $0 $14,267 $1,299 $0 $2,553 $18,120 $36

TOTAL COST $946,611 $76,524 $322,846 $0 $0 $1,345,980 $124,918 $70,414 $251,103 $1,792,415 $3,584

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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Exhibit 3-54 Case L1B Owner’s Costs

Owner's Costs $x1000 $/kW

Preproduction Costs

6 Months Fixed O&M $14,586 $29

1 Month Variable O&M $4,058 $8

25% of 1 Months Fuel Cost at 100% CF $811 $2

2% of TPC $35,848 $72

Total $55,303 $111

Inventory Capital

60 day supply of consumables at 100% CF $6,987 $14

0.5% of TPC (spare parts) $8,962 $18

Total $15,949 $32

 Initial Cost for Catalyst and Chemicals $7,538 $15

Land $900 $2

Other Owner's Costs $268,862 $538

Financing Costs $48,395 $97

Total Owner's Costs $396,948 $794

Total Overnight Cost (TOC) $2,189,363 $4,378

TASC Multiplier 1.140

Total As-Spent Cost (TASC) $2,495,874 $4,991
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Exhibit 3-55 Case L1B Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case L1B - Shell IGCC w/ CO2 Heat Rate-net (Btu/kWh): 10,772

MWe-net: 500

Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 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-O.J.'s 16.0 16.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $6,313,507 $12.625

Maintenance Labor Cost $17,024,604 $34.045

Administrative & Support Labor $5,834,528 $11.668

Property Taxes and Insurance $35,848,299 $71.688

TOTAL FIXED OPERATING COSTS $65,020,938 $130.026

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $31,416,690 $0.00896

Consumables Consumption Unit Initial

 Initial Fill /Day Cost Cost

Water (/1000 gallons) 0 2,820 1.08 $0 $890,771 $0.00025

Chemicals

MU & WT Chem.(lbs) 0 16,802 0.17 $0 $849,113 $0.00024

Carbon (Mercury Removal) (lb) 126,002 173 1.05 $132,324 $52,930 $0.00002

COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000

Water Gas Shift Catalyst (ft3) 6,431 4.40 498.83 $3,207,993 $641,599 $0.00018

Selexol Solution (gal) 313,293 100 13.40 $4,197,575 $389,897 $0.00011

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip. 0.90 131.27 $0 $34,681 $0.00001

Subtotal Chemicals $7,537,892 $1,968,219 $0.00056

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 173 0.42 $0 $21,021 $0.00001

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 983 16.23 $0 $4,656,048 $0.00133

Subtotal Waste Disposal $0 $4,677,069 $0.00133

By-products & Emissions 

Sulfur (tons) 0 61 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $7,537,892 $38,952,749 $0.01112

Fuel (ton) 0 9,768 10.92 $0 $31,146,334 $0.00889
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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3.3 TRIGTM IGCC CASES

This section contains an evaluation of plant designs for Cases S2A and S2B, which are based on 

the TRIGTM transport gasifier, developed by Kellogg Brown and Root (KBR) and Southern 

Company. Cases S2A and S2B are very similar in terms of process, equipment, scope and 

arrangement, except that Case S2B includes SGS reactors, CO2 absorption/regeneration and 

compression/transport systems. 

Section 3.3.4 covers the results for the S2A non-capture case using PRB coal and Section 3.3.8

covers the S2B CO2-capture case using PRB coal. The sections are organized analogously as 

follows:

• Process and System Description provides an overview of the specific technology’s

operation.

• BFD and stream table display results for major processes and streams

• Performance Results provides the main modeling results, including the performance 

summary, environmental performance, carbon balance, sulfur balance, water balance, 

mass and energy balance diagrams, and mass and energy balance tables.

• Equipment List provides an itemized list of major equipment with account codes that 

correspond to the cost accounts in the Cost Estimates section.

• Cost Estimates provides a summary of capital and operating costs.

Process and System Description, Performance Results, Equipment List and Cost Estimates are 

repeated for Case S2B in Section 3.3.8. If the information is identical to that presented for the 

non-capture cases, a reference is made to the earlier section rather than repeating the information.

3.3.1 Gasifier Background

Development and Current Status – The Transport Gasifier for IGCC applications is based on 

technology developed by KBR for fluid catalytic cracking for refineries. First deployed 

commercially in the late 1930’s in the petroleum refining industry, the transport gasifier has 

undergone major development, particularly coal applications for IGCC power generation at the 

Power Systems Development Facility (PSDF), near Willsonville, Alabama. The large scale pilot 

facility was established in 1995 to reduce the capital cost and increase the efficiency of advanced 

coal-based power generation, while meeting strict environmental standards and providing data 

for commercial scale up. 

With the collaboration of the U.S. Department of Energy (DOE), EPRI, Southern Company, 

KBR, Siemens-Westinghouse, and Peabody Holding company, the TRIGTM gasifier at the PSDF 

has been operated for over 15,000 hours, testing multiple fuels, including PRB and lignite coals, 

in both air blown and oxygen blown operation. Gasification was carried out under conditions of 

871°C (1,600°F) to 982°C (1,800°F), pressures of up to 1.72 MPag (250 psig) and at coal feed 

rates from 1,130 kg/hr (2,500 lb/hr) to 2,270 kg/hr (5,000 lb/hr). 
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Based on the experience from the PSDF, Southern Company was prepared to construct an airblown, 275 MW Orlando Gasification Project firing PRB coal with co-funding from the DOE 

CCPI-2 Program. All major contracts with the plant owners and partners were signed by January 

2006 and the FEED and updated costs were completed in March 2007, with an estimated startup 

in 2010. The project was converted to a natural gas feed during the construction phase because 

of uncertainty surrounding possible greenhouse gas (GHG) regulation for the state of Florida.

Current projects utilizing this technology include the Mississippi air-blown IGCC owned by the 

Mississippi Power Company, proposed to generate 582 MW firing Mississippi lignite coal, with 

$133 million (M) of federal tax credits under the Energy Policy Act of 2005. Co-funding from 

the cancelled DOE CCPI-2 project in Orlando was transferred to this project. The FEED and 

updated cost estimate was prepared by Southern Company and KBR with planned commercial 

operation in June 2013. 

Gasifier Capacity – Commercial scale units are in the design 

and construction phases, and the largest current TRIGTM 

installation is at the PSDF run by Southern Company, 

processing up to 50 tonne/day (55 tpd) of coal. The FEED 

work, which was completed for the cancelled Orlando 

Gasification Project, indicated gasification of 2,990 tonne/day 

(3,300 tpd) of PRB coal that would have been used to fire a 

GE 7FA CT. This scale up is consistent with the size of the 

two gasifiers used for each of the TRIGTM cases in this study.

Distinguishing Characteristics – The TRIGTM gasifier is a 

dry feed, fast CFB, non-slagging, single stage gasifier 

producing syngas at moderate temperatures. The entire 

gasifier is constructed from refractory lined piping and 

vessels. Advantages of the TRIGTM coal gasification 

technology is it’s a small footprint with a high thermal 

throughput, the ability to process a variety of high ash, high 

melting point coals, and its relatively high overall carbon 

conversion. The transport gasifier operates at higher 

circulation rates, velocities, and riser densities than a conventional circulating bed, resulting in 

higher throughput, mixing, heat and mass transfer. The dry feed non-slagging gasifier allows the 

firing of high moisture and ash fuels such as sub-bituminous and lignite coals.

The high circulation rates of the transport gasifier results in a lower per pass carbon conversion 

compared to other gasifier technologies, but the unreacted carbon, along with the ash, is 

separated and recirculated to increase the overall carbon conversion. Larger coal particle sizes 

(up to 0.75” top size) are acceptable because of the high recirculation rate, which reduces the 

necessary coal preparation compared to other dry feed gasifier technologies. Ash removal is 

controlled to maintain a constant gasifier bed inventory, which aids in transport, and is removed 

at the gasifier pressure, flowing through an ash cooler, then though a proprietary continuous 

pressure let-down system. The ash is then moisturized with stripped water from the SWS to 

minimize dust emissions while it is being landfilled. Because of the non-slagging design and 

dust removal, no black or gray water systems are required for transporting or disposing of these 
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wastes. Due to the thorough mixing in the gasifier, the opportunity exists for in-situ sulfur 

capture by injecting limestone during the gasification process, although that was not considered 

in this study. 

The high efficiency of the TRIGTM gasifier, associated with the lower gasification temperature, 

helps reduce the operating cost of the gasifier, but creates more methane when compared to other 

gasifiers. Higher methane content increases the heating value of the fuel and is associated with 

high cold gas efficiencies, but can become a problem if high CO2 removal is required. Because 

of this, the TRIGTM CO2 capture case achieves less than 90 percent overall carbon capture.

Important Coal Characteristics – The TRIGTM gasifier is able to fire lower rank coals with 

high moisture and ash content and high ash fusion temperatures because of its non-slagging ash 

removal system. Dry feeding also reduces the negative effects of high ash content relative to 

slurry feed gasifiers, which are limited by solids content in the slurry. 
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3.3.2 Key System Assumptions

System assumptions for Cases S2A and S2B TRIGTM IGCC using PRB coal, with and without 

CO2 capture, are compiled in Exhibit 3-56.

Exhibit 3-56 Case S2A and S2B Plant Study Configuration Matrix

Case S2A S2B

Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O2:Coal Ratio, kg O2/kg dry coal 0.654 0.661

Carbon Conversion, % 98.0 98.0

Syngas HHV at Gasifier Outlet, 

kJ/Nm3 (Btu/scf) 9,490 (255) 9,460 (254)

Nominal Steam Cycle, MPa/°C/°C 

(psig/°F/°F)

12.4/566/566 

(1,800/1,050/1,050)

12.4/538/538 

(1,800/1,000/1,000)

Condenser Pressure, mm Hg

(in Hg) 36 (1.4) 36 (1.4)

Combustion Turbine

2x Advanced F Class 

(Nominal 232 MW output 

each, reduced by elevation 

considerations)

2x Advanced F Class 

(Nominal 232 MW output 

each, reduced by elevation 

considerations)

Gasifier Technology TRIGTM TRIGTM

Oxidant 95 vol% Oxygen 95 vol% Oxygen

Coal Subbituminous Subbituminous

Coal Feed Moisture Content, % 18 18

COS Hydrolysis Yes Yes (Part of WGS)

Water Gas Shift No Yes

H2S Separation Sulfinol-M Selexol (1st Stage)

Sulfur Removal, % 99.9 99.8

CO2 Separation None Selexol (2nd Stage)

CO2 Removal, % N/A 83

Sulfur Recovery

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Particulate Control Cyclone, Candle Filter, 

and AGR Absorber

Cyclone, Candle Filter, and 

AGR Absorber

Mercury Control Carbon Bed Carbon Bed

NOx Control MNQC (LNB) and N2

Dilution 

MNQC (LNB) and N2

Dilution
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Balance of Plant – All Cases

The balance of plant assumptions are common to all cases and are presented in Exhibit 3-57.

Exhibit 3-57 Balance of Plant Assumptions

Cooling water system Recirculating Wet Cooling Tower

Fuel and Other storage

Coal 30 days

Slag 30 days

Sulfur 30 days

Sorbent 30 days

Plant Distribution Voltage

Motors below 1 hp 110/220 volt

Motors between 1 hp and 

250 hp 480 volt

Motors between 250 hp and 

5,000 hp 4,160 volt

Motors above 5,000 hp 13,800 volt

Steam and CT Generators 24,000 volt

Grid Interconnection Voltage 345 kV

Water and Waste Water

Makeup Water

The water supply is 50 percent from a local POTW

and 50 percent from groundwater, and is assumed to 

be in sufficient quantities to meet plant makeup 

requirements.

Makeup for potable, process, and DI water is drawn 

from municipal sources

Process Wastewater

Water associated with gasification activity and storm 

water that contacts equipment surfaces is collected 

and treated for discharge through a permitted 

discharge.

Sanitary Waste Disposal

Design includes a packaged domestic sewage 

treatment plant with effluent discharged to the 

industrial wastewater treatment system. Sludge is 

hauled off site. Packaged plant was sized for 5.68 

cubic meters per day (1,500 GPD)

Water Discharge

Most of the process wastewater is recycled to the 

cooling tower basin. Blowdown is treated for 

chloride and metals, and discharged.
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3.3.3 Sparing Philosophy

The sparing philosophy for Cases S2A and S2B is provided below. Single trains are utilized 

throughout with exceptions where equipment capacity requires an additional train. There is no 

redundancy other than normal sparing of rotating equipment.

The plant design consists of the following major subsystems:

• Two ASUs (2 x 50%).

• Two trains of coal drying and dry feed systems (2 x 50%).

• Two trains of gasification, including gasifier, SGC, cyclone, and barrier filter (2 x 50%). 

• Two trains of syngas clean-up process (2 x 50%).

• Two trains of Sulfinol-M acid gas removal in non-capture cases and two trains of twostage Selexol in CO2 capture cases (2 x 50%).

• One train of Claus-based sulfur recovery (1 x 100%). 

• Two CT/HRSG tandems (2 x 50%).

• One steam turbine (1 x 100%).

3.3.4 TRIGTM IGCC Non-Capture Case (S2A) Process Description

In this section the overall TRIGTM gasification process for Case S2A is described. The system 

description follows the BFD in Exhibit 3-58, and the tables in Exhibit 3-59 provide process data 

for the numbered streams.

Coal Preparation and Feed Systems

Coal receiving and handling is common to all cases and generally described in Section 3.1.1. 

The TRIGTM gasifier drying process described for the Orlando Gasification Project [70] utilizes 

flash dryers with the pulverizers. A closed loop of gas, containing less than 11.3 percent oxygen

[71] to meet fire code standards, is heated, preferably with medium pressure steam, to provide 

the heat to dry the coal. While the Orlando Project paper [46] does not indicate coal moisture 

levels, the study paper [71] indicates the PRB coal is dried from 28 to 18 percent. After the coal 

and drying gas are separated, the gas is cooled below its dew point to remove moisture before 

being reheated. The condensed water is treated and used in the process.

The main motivation to dry the coal is to enable transport into the gasifier. The TRIGTM gasifier 

accommodates a larger coal particle (700 micron top side) than the dry-feed, entrained-flow 

gasifier (approximately 70 micron), enabling the transport of coal with 18 percent moisture.

For these reasons, and to be consistent with plans for the Orlando project, it was decided to dry 

the PRB coal to 18 percent and not use the WTA process, but rather use a system like that 
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201

described for the Orlando project to realize some of the coal handling and gasification benefits of 

the transport gasifier.

Gasifier

There are two parallel TRIGTM dry feed, pressurized, up flow, transport gasifiers, operating at 

4.2 MPa (615 psia) and processing a total of 5,935 tonne/day (6,542 tpd) of as-received PRB 

Coal that reacts with oxygen and steam in a reducing environment at a temperature of 982°C 

(1,800°F) to produce principally hydrogen and carbon monoxide along with comparatively high 

concentrations of methane (~5 vol%) due to the low gasification temperatures. 

Raw Gas Cooling/Particulate Removal

High-temperature heat recovery in each gasifier train is performed by raw gas coolers in three 

sections, a superheater, an evaporator, and an economizer, which lower the raw gas temperature 

from 982°C (1,800°F) to 343°C (650°F). Particulates are removed using high temperature, HP

rigid, barrier-type filter elements and pulsed with recycled syngas to clean the filters of the 

trapped ash. The collected particulates are cooled and depressurized using a continuous fine ash 

removal system and conveyed to the ash silo for disposal. The syngas is further cooled to 260°C 

(500°F) before entering further gas treatment, with much of the heat recovered by indirect 

cooling by BFW.

Sour Water Stripper

Water condensed during the cooling of the raw gas, along with all other sour water from the 

plant are sent to the sour water stripper, which removes NH3, SO2, and other impurities from the 

waste stream. The sour gas stripper consists of a sour drum that accumulates sour water that 

flows to the sour stripper, which consists of a packed column with a steam-heated reboiler. Sour 

gas is stripped from the liquid and sent to the SRU. Remaining water is sent to wastewater 

treatment.

COS Hydrolysis, Mercury Removal and Acid Gas Removal

H2S and COS are at significant concentrations, requiring removal for the power plant to achieve 

the low design level of SO2 emissions. H2S is removed in an AGR process; however, because 

COS is not readily removed, it is first catalytically converted to H2S in a COS hydrolysis unit.

The cooled raw gas is fed to the COS hydrolysis reactor where the COS in the sour gas is 

hydrolyzed with steam, over a catalyst bed, into H2S, which is more easily removed by the AGR 

solvent. Before the raw fuel gas can be treated in the AGR process, it must be cooled to about 

35°C (95°F). During this cooling through a series of heat exchangers, part of the water vapor 

condenses. This water, which contains some NH3, is sent to the sour water stripper. The cooled 

syngas then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.8).

The Sulfinol process, developed by Shell in the early 1960s, is a combination process that uses a 

mixture of amines and a physical solvent. The solvent consists of an aqueous amine and 

sulfolane. Sulfinol-D uses DIPA, while Sulfinol-M uses MDEA. The mixed solvents allow for 

better solvent loadings at high acid gas partial pressures and higher solubility of COS and 

organic sulfur compounds than straight aqueous amines. Sulfinol-M was selected for the nonCO2 capture applications. 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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The sour syngas is fed directly into a HP contactor. The HP contactor is an absorption column in 

which the H2S, COS, CO2, and small amounts of H2 and CO are removed from the gas by the 

Sulfinol solvent. The overhead gas stream from the HP contactor is then washed with water in 

the sweet gas scrubber before leaving the unit as the feed gas to the sulfur polishing unit.

The rich solvent from the bottom of the HP contactor flows through a hydraulic turbine and is 

flashed in the rich solvent flash vessel. The flashed gas is then scrubbed in the LP contactor with 

lean solvent to remove H2S and COS. The overhead from the LP contactor is flashed in the LP 

KO drum. This gas can be used as a utility fuel gas, consisting primarily of H2 and CO, at 

0.8 MPa (118 psia) and 38°C (101°F). The solvent from the bottom of the LP contactor is 

returned to the rich solvent flash vessel.

Hot, lean solvent in the lean/rich solvent exchanger then heats the flashed rich solvent before 

entering the stripper. The stripper strips the H2S, COS, and CO2 from the rich solvent at LP with 

heat supplied through the stripper reboiler. The acid gas stream to sulfur recovery/tail gas 

cleanup is recovered as the flash gas from the stripper accumulator. The lean solvent from the 

bottom of the stripper is cooled in the lean/rich solvent exchanger and the lean solvent cooler. 

Most of the lean solvent is pumped to the HP contactor. A small amount goes to the LP 

contactor.

The Sulfinol process removes about 15 percent of the CO2 along with the H2S and COS. The 

acid gas is fed to the SRU. The residual CO2 passes through the SRU, the hydrogenation reactor 

and is recycled upstream of the AGR system.

Claus Unit

The SRU is a Claus bypass type SRU utilizing oxygen instead of air. The Claus plant produces 

molten sulfur by converting approximately one third of the H2S in the feed to SO2, then reacting 

the H2S and SO2 to sulfur and water. The combinations of Claus technology and tail gas recycle 

results in an overall sulfur recovery exceeding 99 percent, producing 43 tonne/day (48 tpd) of 

sulfur. 

Utilizing oxygen instead of air in the Claus plant reduces the overall cost of the sulfur recovery 

plant. Feed for each case consists of acid gas from both the acid gas cleanup unit and a vent 

stream from the sour water stripper in the gasifier section.

In the furnace waste heat boiler steam is generated. This steam is used to satisfy all Claus 

process preheating and reheating requirements, as well as to provide some steam to the mediumpressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) steam for the LP

steam header.

Power Block

Clean syngas exiting the Sulfinol absorber reheated and diluted with nitrogen from the ASU, and 

enters the advanced F Class CT burner. The CT compressor provides combustion air to the 

burner and a portion of the air requirements for the ASU. The exhaust gas exits the CT at 586°C 

(1,087°F) and enters the HRSG where additional heat is recovered until the flue gas exits the 

HRSG at 132°C (270°F) and is discharged through the plant stack. The steam generated in the 
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203

HRSG is used to power a steam turbine using a nominal 12.4 MPa/566°C/566°C (1800 

psig/1050°F/1050°F) steam cycle.

Air Separation Unit

The ASU is designed to produce approximately 3,098 tonne/day (3,415 tpd) of 95 mol% O2 for 

use in the gasifier and SRU. The plant is designed with two production trains. The air 

compressor is powered by an electric motor. Nitrogen is also recovered, compressed, and used 

as dilution in the CT combustor or as a coal transport fluid. Air extraction is taken from the CT

compressor to reduce the size of the main air compressor.

Balance of Plant

Balance of plant items were covered in Sections 3.1.12, 3.1.13, 3.1.14, and 3.1.15.
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Exhibit 3-58 Case S2A Process Flow Diagram
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205

Exhibit 3-59 Case S2A Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13

V-L Mole Fraction

Ar 0.0093 0.0093 0.0291 0.0360 0.0023 0.0360 0.0000 0.0000 0.0000 0.0000 0.0000 0.0079 0.0093

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0532 0.0628

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3426 0.4051

CO2 0.0003 0.0003 0.0102 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1618 0.1915

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 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 0.2712 0.3206

H2O 0.0064 0.0064 0.1937 0.0000 0.0002 0.0000 1.0000 0.0000 1.0000 0.0000 0.0000 0.1518 0.0016

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0029 0.0037

N2 0.7759 0.7759 0.5163 0.0140 0.9920 0.0140 0.0000 0.0000 0.0000 0.0000 0.0000 0.0046 0.0055

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0039 0.0000

O2 0.2081 0.2081 0.2507 0.9500 0.0054 0.9500 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 18,706 750 624 55 13,225 3,951 3,355 0 1,349 0 0 18,112 15,320

V-L Flowrate (kg/hr) 540,510 21,680 17,220 1,769 371,104 127,326 60,443 0 24,303 0 0 388,909 338,660

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 247,297 0 223,864 22,724 0 0

Temperature (°C) 6 411 21 32 196 32 343 6 16 71 982 260 35

Pressure (MPa, abs) 0.09 1.43 0.11 0.86 2.65 0.86 5.10 0.09 0.10 0.10 4.24 4.02 3.81

Enthalpy (kJ/kg)A 15.26 434.33 40.10 26.59 202.64 26.59 3,062.93 --- 67.41 --- --- 705.74 38.93

Density (kg/m3

) 1.1 7.2 1.6 11.0 18.9 11.0 20.1 --- 1,002.0 --- --- 19.4 33.3

V-L Molecular Weight 28.895 28.895 27.587 32.229 28.061 32.229 18.015 --- 18.015 --- --- 21.472 22.106

V-L Flowrate (lbmol/hr) 41,240 1,654 1,376 121 29,156 8,710 7,397 0 2,974 0 0 39,931 33,774

V-L Flowrate (lb/hr) 1,191,622 47,797 37,963 3,900 818,144 280,705 133,255 0 53,579 0 0 857,398 746,618

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 545,197 0 493,536 50,098 0 0

Temperature (°F) 42 771 70 90 385 90 650 42 61 160 1,800 500 95

Pressure (psia) 13.0 207.6 16.4 125.0 384.0 125.0 740.0 13.0 14.5 14.6 615.0 582.5 552.5

Enthalpy (Btu/lb)A 6.6 186.7 17.2 11.4 87.1 11.4 1,316.8 --- 29.0 --- --- 303.4 16.7

Density (lb/ft3

) 0.070 0.452 0.097 0.688 1.180 0.688 1.257 --- 62.556 --- --- 1.212 2.082

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

206

Exhibit 3-59 Case S2A Stream Table (Continued)

15 16 17 18 19 20 21 22 23 24 25 26 27

V-L Mole Fraction

Ar 0.0003 0.0000 0.0031 0.0032 0.0094 0.0094 0.0093 0.0090 0.0090 0.0000 0.0000 0.0000 0.0000

CH4 0.0024 0.0000 0.0012 0.0000 0.0627 0.0627 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0074 0.0000 0.0578 0.0061 0.4047 0.4047 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.8648 0.0000 0.6575 0.7300 0.1914 0.1914 0.0003 0.0824 0.0824 0.0000 0.0000 0.0000 0.0000

COS 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.0065 0.0000 0.0122 0.0680 0.3230 0.3230 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0046 0.0000 0.2151 0.1381 0.0015 0.0015 0.0064 0.0613 0.0613 1.0000 1.0000 1.0000 1.0000

H2S 0.1033 0.0000 0.0007 0.0018 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0107 0.0000 0.0513 0.0527 0.0073 0.0073 0.7759 0.7385 0.7385 0.0000 0.0000 0.0000 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2081 0.1089 0.1089 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0009 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 0.0000 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) 553 0 675 657 15,335 15,335 100,835 123,065 123,065 34,631 15,671 15,671 35,201

V-L Flowrate (kg/hr) 23,339 0 24,382 24,042 337,748 337,748 2,913,623 3,600,794 3,600,794 623,885 282,309 282,309 634,155

Solids Flowrate (kg/hr) 0 1,797 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 48 174 232 49 31 196 6 588 132 560 32 32 33

Pressure (MPa, abs) 0.16 0.1 0.085 0.073 3.238 3.203 0.090 0.093 0.090 12.512 0.005 0.005 0.827

Enthalpy (kJ/kg)A 45.44 --- 512.471 217.046 34.170 283.546 15.260 734.275 230.852 3,498.933 2,301.992 2,301.992 140.856

Density (kg/m3) 2.6 --- 0.7 1.0 28.6 17.9 1.1 0.4 0.8 35.2 0.04 0.04 995.0

V-L Molecular Weight 42.235 --- 36.126 36.591 22.025 22.025 28.895 29.259 29.259 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 1,218 0 1,488 1,449 33,807 33,807 222,302 271,312 271,312 76,348 34,548 34,548 77,605

V-L Flowrate (lb/hr) 51,453 0 53,754 53,003 744,606 744,606 6,423,439 7,938,393 7,938,393 1,375,430 622,384 622,384 1,398,073

Solids Flowrate (lb/hr) 0 3,962 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 119 344 450 120 87 385 42 1,090 270 1,040 90 90 92

Pressure (psia) 23.7 17.3 12.3 10.6 469.6 464.6 13.0 13.5 13.0 1,814.7 0.7 0.7 120.0

Enthalpy (Btu/lb)A 19.5 --- 220.3 93.3 14.7 121.9 6.6 315.7 99.2 1,504.3 989.7 989.7 60.6

Density (lb/ft3) 0.162 --- 0.046 0.063 1.787 1.120 0.070 0.024 0.050 2.197 0.002 0.002 62.114
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

207

3.3.5 Case S2A Performance Results

The non-capture TRIGTM IGCC plant using PRB coal at the Montana site (elevation 3,400 ft) 

produces a net output of 545 MWe at a net plant efficiency of 39.9 percent (HHV basis). 

Overall performance for the plant is summarized in Exhibit 3-60, which includes auxiliary power 

requirements. The ASU accounts for approximately 76 percent of the total auxiliary load, 

distributed between the main air compressor, the oxygen compressor, the nitrogen compressor, 

and ASU auxiliaries. The cooling water system, including the CWPs and cooling tower fan, and 

the air-cooled condenser account for about 5 percent of the auxiliary load, the coal drying 

process accounts for 3 percent of the auxiliary load, and the BFW pumps account for an 

additional 4 percent. All other individual auxiliary loads are less than 3 percent of the total.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

208

Exhibit 3-60 Case S2A Plant Performance Summary

POWER SUMMARY (Gross Power at Generator 

Terminals, kWe) S2A

Gas Turbine Power 419,100

Steam Turbine Power 233,600

TOTAL POWER, kWe 652,700

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 500

Coal Crushing 690

Ash Handling 590

Coal Dryer Circulation Blower 2,420

Air Separation Unit Auxiliaries 1,000

Air Separation Unit Main Air Compressor 48,130

Oxygen Compressor 6,160

Nitrogen Compressors 26,380

Boiler Feedwater Pumps 3,840

Condensate Pump 210

Syngas Recycle Compressors 1,440

Circulating Water Pump 1,920

Ground Water Pumps 190

Cooling Tower Fans 1,250

Air Cooled Condenser Fans 2,730

Acid Gas Removal 740

Gas Turbine Auxiliaries 1,000

Steam Turbine Auxiliaries 100

Claus Plant/TGTU Auxiliaries 250

Claus Plant TG Recycle Compressor 2,470

Miscellaneous Balance of Plant1 3,000

Transformer Losses 2,270

TOTAL AUXILIARIES, kWe 107,280

NET POWER, kWe 545,420

Net Plant Efficiency, % (HHV) 39.9%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,032 (8,560)

CONDENSER COOLING DUTY GJ/hr (106 Btu/hr) 1,224 (1,160)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 247,297 

(545,197)

Thermal Input, kWt 1,368,368

Raw Water Withdrawal, m3/min (gpm) 7.7 (2,045)

Raw Water Consumption, m3/min (gpm) 6.0 (1,598)

1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

209

Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in 

Section 2.3. A summary of the plant air emissions for Case S2A is presented in Exhibit 3-61.

Exhibit 3-61 Cases S2A Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

80% capacity factor

kg/MWh

(lb/MWh)

SO2 0.001 (0.002) 28 (31) 0.006 (0.013)

NOX 0.025 (0.059) 875 (965) 0.191 (0.422)

Particulates 0.003 (0.0071) 105 (116) 0.023 (0.051)

Hg 1.51E-7 (3.51E-7) 0.005 (0.006) 1.14E-6 (2.51E-6)

CO2 gross 90.5 (210.6) 3,125,929 (3,445,747) 683 (1,507)

CO2 net 818 (1,803)

The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the Sulfinol-M 

AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel 

gas down to a level of less than 5 ppmv in both cases. This results in a concentration in the flue 

gas of less than 1 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus 

plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated and recycled to the 

AGR to capture most of the remaining sulfur. Because the environmental target was set based 

on higher sulfur bituminous coal, the resulting SO2 emissions with lower sulfur western coals are 

substantially less than the environmental target.

NOx emissions are limited to 15 ppmvd (as NO2 @ 15 percent O2) by the use of low NOx 

burners and nitrogen dilution of the fuel gas. Ammonia in the syngas is removed with process 

condensate prior to the low-temperature AGR process and destroyed in the Claus plant burner. 

This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone 

and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Ninety five percent of the mercury is captured from the syngas by an activated carbon bed.

CO2 emissions represent the uncontrolled discharge from the process.

The carbon balance for this case is shown in Exhibit 3-62. The carbon input to the plant consists 

of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since 

the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned 

carbon in the ash and as CO2 in the stack gas and ASU vent gas.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

210

Exhibit 3-62 Case S2A Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 123,817 (272,970) Slag/Ash 2,476 (5,459)

Air (CO2) 471 (1,038) Stack Gas 121,735 (268,379)

ASU Vent 77 (169)

Total 124,288 (274,008) Total 124,288 (274,008)

Exhibit 3-63 shows the sulfur balance for the non capture case. Sulfur input comes solely from 

the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur 

emitted in the stack gas. Sulfur in the ash is considered to be negligible.

Exhibit 3-63 Case S2A Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 1,799 (3,966) Elemental Sulfur 1,797 (3,962)

Stack Gas 2 (4)

Total 1,799 (3,966) Total 1,799 (3,966)

Exhibit 3-64 shows the overall water balance for the plant. 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, primarily as coal moisture from the drying process and syngas condensate, and that 

water is re-used as internal recycle. Raw water withdrawal is the difference between water 

demand and internal recycle. Some water is discharged from the process to a permitted outfall. 

The difference between the withdrawal and discharge is the consumption.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

211

Exhibit 3-64 Case S2A Water Balance

Water Use

Water 

Demand

m3/min (gpm)

Internal 

Recycle 

m3/min (gpm)

Raw Water 

Withdrawal 

m3/min (gpm)

Process 

Water 

Discharge 

m3/min (gpm)

Raw Water 

Consumption 

m3/min (gpm)

S2A S2A S2A S2A S2A

Slag Handling 0.49 (130) 0.49 (130) 0 (0) 0 (0) 0 (0)

SWS Blowdown 0 (0) 0 (0) 0 (0) 0.01 (2) -0.01 (-2)

Condenser Makeup 1.16 (307) 0 (0) 1.16 (307) 0 (0) 1.16 (307)

Gasifier Steam 1.01 (267) 1.01 (267)

BFW Makeup 0.15 (40) 0.15 (40)

Cooling Tower Makeup 7.49 (1,978) 0.91 (240) 6.58 (1,738) 1.68 (445) 4.89 (1,293)

Coal Drying 0.41 (107) -0.41 (-107)

BFW Blowdown 0.15 (40) -0.15 (-40)

SWS Blowdown 0.08 (20) -0.08 (-20)

SWS Excess Water 0.28 (73) -0.28 (-73)

Total 9.1 (2,415) 1.4 (370) 7.7 (2,045) 1.7 (447) 6.1 (1,598)

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-65:

• Coal gasification and ASU

• Syngas cleanup

• Power block

An overall plant energy balance is provided in tabular form in Exhibit 3-66 based on 0°C (32°F) 

reference conditions. The power out is the combined CT and steam turbine power after 

generator losses.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

213

Exhibit 3-65 Case S2A Heat and Mass Balance 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

214

Exhibit 3-65 Case S2A Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

215

Exhibit 3-65 Case S2A Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

216

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Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

217

Exhibit 3-66 Case S2A Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 4,926 (4,669) 2.5 (2.4) 0 (0) 4,929 (4,671)

ASU Air 0 (0) 8.2 (7.8) 0 (0) 8 (8)

GT Air 0 (0) 44.5 (42.1) 0 (0) 44 (42)

Raw Water Makeup 0 (0) 10.8 (10.2) 0 (0) 11 (10)

Auxiliary Power 0 (0) 0 (0) 386 (366) 386 (366)

Totals 4,926 (4,669) 66.0 (62.6) 386 (366) 5,378 (5,098)

Heat Out GJ/hr (MMBtu/hr)

ASU Intercoolers 0 (0) 170 (161) 0 (0) 170 (161)

ASU Vent 0 (0) 0.7 (0.7) 0 (0) 1 (1)

Slag 81 (77) 23.6 (22.4) 0 (0) 105 (99)

Sulfur 17 (16) 0.2 (0.2) 0 (0) 17 (16)

Cooling Tower Blowdown 0 (0) 9.4 (8.9) 0 (0) 9 (9)

HRSG Flue Gas 0 (0) 831 (788) 0 (0) 831 (788)

Condenser 0 (0) 1,219 (1,155) 0 (0) 1,219 (1,155)

Auxiliary Cooling Load 0 (0) 67 (64) 0 (0) 67 (64)

Electrical Generator Loss 0 (0) 0 (0) 36 (34) 36 (34)

Process Losses 0 (0) 574 (544) 0 (0) 574 (544)

Power 0 (0) 0 (0) 2,350 (2,227) 2,350 (2,227)

Totals 98 (93) 2,895 (2,744) 2,386 (2,261) 5,378 (5,098)

3.3.6 Case S2A Equipment Lists

Major equipment items for the TRIGTM gasifier with no CO2 capture using PRB coal are shown 

in the following tables. The accounts used in the equipment list correspond to the account 

numbers used in the cost estimates in Section 3.3.7. In general, the design conditions include a 

10 percent contingency for flows and heat duties and a 21 percent contingency for heads on 

pumps and fans.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

218

ACCOUNT 1 COAL HANDLING

Equipment 

No. Description Type S2A Design Condition Operating Qty Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0

4 Transfer Tower No. 1 Enclosed N/A 1 0

5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling 

System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0

8 Reclaim Hopper N/A 54 tonne (60 ton) 2 1

9 Feeder Vibratory 200 tonne/hr (220 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 408 tonne/hr (450 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 200 tonne (220 ton) 2 0

13 Crusher Impactor reduction 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 1 1

15 Conveyor No. 4 Belt w/tripper 408 tonne/hr (450 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 408 tonne/hr (450 tph) 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 907 tonne (1,000 ton) 3 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

219

ACCOUNT 2 COAL PREPARATION AND FEED 

Equipment 

No. Description Type S2A Design Condition Operating Qty Spares

1 Feeder Vibratory 45 tonne/hr (50 tph) 6 0

2 Coal Mill Hydraulic Unit

Hot gas (350F) enters the bottom 

of the mill for drying and 

conveying

272 tonne (300 ton) 2 0

3 Cyclonic Baghouse Gas Recycled to Dryer, Coal to 

Feeder

Coal - 91 tonne (100 ton)

Recycle Gas -226,687 kg/hr 

(499,760 lb/hr)

6 0

4 Discharge Feeder Rotary 45 tonne/hr (50 tph) 6 0

5 Coal Feed Storage Bin Vertical Hopper 45 tonne/hr (50 tph) 6 0

6 Coal Feed Lock Vessel Vertical Hopper 45 tonne/hr (50 tph) 6 0

7 Coal Feed Conveyor Vertical Hopper 91 tonne (100 ton) 6 0

8 Drying Recycle Cooler Water cooled shell and tube 226,687 kg/hr (499,760 lb/hr) 6 0

9 Moisture Separator Drum Cyclonic 226,687 kg/hr (499,760 lb/hr) 6 0

10 Baghouse Exhaust 

Blower Centrifugal

Recycle Gas- 226,687 kg/hr 

(499,760 lb/hr)

2,420 kWe

6 0

11 Drying Heater Steam heated shell and tube

Recycle Gas- 226,687 kg/hr 

(499,760 lb/hr)

110 MMBtu/hr

6 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

220

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment 

No. Description Type S2A Design Condition Operating Qty Spares

1 Demineralized Water Storage 

Tank Vertical, cylindrical, outdoor 586,739 liters (155,000 gal) 2 0

2 Condensate Pumps Vertical canned 5,867 lpm @ 91 m H2O

(1,550 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 435,449 kg/hr 

(960,000 lb/hr) 2 0

4 Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, single 

stage

1,363 lpm @ 27 m H2O

(360 gpm @ 90 ft H2O) 2 1

5 High Pressure Feedwater Pump 

No. 1

Barrel type, multi-stage, 

centrifugal

HP water: 6,057 lpm @ 

1,890 m H2O (1,600 gpm @ 

6,200 ft H2O)

2 1

6 High Pressure Feedwater Pump 

No. 2

Barrel type, multi-stage, 

centrifugal

IP water: 1,022 lpm @ 223 

m H2O (270 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)

1 0

8 Service Air Compressors Flooded Screw 28 m3

/min @ 0.7 MPa

(1,000 scfm @ 100 psig) 2 1
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

221

Equipment 

No. Description Type S2A Design Condition Operating Qty Spares

9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

10 Closed Cycle Cooling Heat 

Exchangers Plate and frame 145 GJ/hr (137 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water 

Pumps Horizontal centrifugal 51,860 lpm @ 21 m H2O(13,700 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) 1 1

13 Fire Service Booster Pump Two-stage horizontal 

centrifugal

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, single suction 2,158 lpm @ 18 m H2O

(570 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single suction 2,158 lpm @ 268 m H2O 

(570 gpm @ 880 ft H2O) 2 1

16 Filtered Water Pumps Stainless steel, single suction 984 lpm @ 49 m H2O

(260 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 476,962 liter (126,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and mixed bed 151 lpm (40 gpm) 2 0

19 Liquid Waste Treatment 

System 10 years, 24-hour storm 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

222

ACCOUNT 4 GASIFIER, ASU, AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY 

Equipment 

No. Description Type S2A Design Condition Operating Qty Spares

1 Gasifier TRIGTM dry feed, circulating fastfluidized bed

3,266 tonne/day, 4.2 MPa

(3,600 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler

Vertical down flow heat 

exchanger with evaporator, 

superheater, and economizer 

stages

281,681 kg/hr (621,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 281,681 kg/hr (621,000 lb/hr) 

Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with pulse-jet 

cleaning metallic filters 2 0

5

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical up flow 285,310 kg/hr (629,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with condensate 

drain 186,426 kg/hr (411,000 lb/hr) 8 0

7 Raw Gas Knockout 

Drum Vertical with mist eliminator 186,426 kg/hr, 35°C, 3.8 MPa(411,000 lb/hr, 95°F, 553 psia) 2 0

11 Synthesis Gas Reheater Shell and tube 185,973 kg/hr (410,000 lb/hr) 2 0

12 Flare Stack Self-supporting, carbon steel, 

stainless steel top, pilot ignition

285,310 kg/hr (629,000 lb/hr) 

syngas

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

223

Equipment 

No. Description Type S2A Design Condition Operating Qty Spares

13 ASU Main Air 

Compressor Centrifugal, multi-stage 4,049 m3

/min @ 1.3 MPa

(143,000 scfm @ 190 psia) 2 0

14 Cold Box Vendor design 1,724 tonne/day (1,900 tpd) of 

95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi-stage

850 m3/min (30,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 4.3 MPa (620 psia)

2 0

16 Primary Nitrogen 

Compressor Centrifugal, multi-stage

2,832 m3

/min (100,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 0

17 Secondary Nitrogen 

Compressor Centrifugal, single-stage

396 m3

/min (14,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 0

18 Extraction Air Heat 

Exchanger Gas-to-gas, vendor design 11,793 kg/hr, 411°C, 1.4 MPa(26,000 lb/hr, 771°F, 208 psia) 2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

224

ACCOUNT 5 SYNGAS CLEANUP

Equipment 

No. Description Type S2A Design Condition Operating Qty Spares

1 Mercury Adsorber Sulfated carbon bed

186,426 kg/hr (411,000 lb/hr) 

35°C (95°F) 

3.8 MPa (553 psia)

2 0

2 Sulfur Plant Claus type 47 tonne/day (52 tpd) 1 0

3 COS Hydrolysis Reactor Fixed bed, catalytic

214,096 kg/hr (472,000 lb/hr)

260°C (500°F)

4.0 MPa (580 psia)

2 0

4 Acid Gas Removal Plant Sulfinol

198,673 kg/hr (438,000 lb/hr)

246°C (476°F)

3.7 MPa (543 psia)

2 0

5 Hydrogenation Reactor Fixed bed, catalytic

24,382 kg/hr (53,754 lb/hr)

232°C (450°F)

0.1 MPa (12.3 psia)

1 0

6 Tail Gas Recycle 

Compressor Centrifugal 22,446 kg/hr (49,485 lb/hr) 1 0

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment 

No. Description Type S2A Design Condition Operating Qty Spares

1 Gas Turbine Advanced F class 210 MW 2 0

2 Gas Turbine Generator TEWAC 230 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

225

ACCOUNT 7 HRSG, DUCTING AND STACK

Equipment 

No. Description Type S2A Design Condition Operating Qty Spares

1 Stack CS plate, type 409SS 

liner

76 m (250 ft) high x

8.4 m (20 ft) diameter 2 0

2 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator

Main steam - 343,137 kg/hr, 12.4 MPa/560°C 

(756,486 lb/hr, 1,800 psig/1,040°F)

Reheat steam - 302,892 kg/hr, 3.1 MPa/560°C 

(667,763 lb/hr, 452 psig/1,040°F)

2 0

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type S2A Design Condition Operating Qty Spares

1 Steam Turbine Commercially 

available

246 MW

12.4 MPa/560°C/560°C (1,800 psig/ 

1,040°F/1,040°F)

1 0

2 Steam Turbine 

Generator

Hydrogen cooled, 

static excitation 270 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0

3 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

675 GJ/hr (640 MMBtu/hr), Condensing 

temperature 32°C (90°F), Inlet water 

temperature 9°C (48°F), Water temperature 

rise 11°C (20°F)

1 0

4 Air-cooled 

Condenser ---

675 GJ/hr (640 MMBtu/hr), Condensing 

temperature 32°C (90°F), Ambient 

temperature 6°C (42°F)

1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

226

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type S2A Design Condition Operating Qty Spares

1 Circulating 

Water Pumps Vertical, wet pit 193,056 lpm @ 30 m

(51,000 gpm @ 100 ft) 2 1

2 Cooling 

Tower

Evaporative, 

mechanical draft, 

multi-cell

3°C (37°F) WB / 9°C (48°F) CWT / 20°C (68°F) 

HWT / 1,076 GJ/hr (1,020 MMBtu/hr) heat duty 1 0

ACCOUNT 10 ASH RECOVERY AND HANDLING

Equipment 

No. Description Type S2A Design Condition Operating Qty Spares

1

Coarse Ash 

Depressurization and 

Cooling

Proprietary Fine Ash - 3 tonne/hr (3 tph) 2 0

2 Makeup Solids Storage 

Bin

Vertical, shop 

fabricated 30 tonnes (33 tons) 2 0

3 Makeup Solids Storage 

Bin Vent Filter

Pulsed Fabric 

Filter 180 Nm3

/hr (106 scfm) 2 0

4 Coarse Ash Conveyor Dense Phase 3 tonne/hr (3 tph) 2 0

5

Fine Ash 

Depressurization and 

Cooling

Proprietary Coarse Ash - 10 tonne/hr (11 tph) 2 0

6 Ash Storage Silo Reinforced 

concrete 2,999 tonne (3,306 tons) 1 0

7 Ash Silo Vent Filter Pulsed Fabric 

Filter 2,883 Nm3

/hr (1,696 scfm) 1 0

8 Storage Silo Discharge 

Feeder Rotary 300 tonne/hr (331 tph) 2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

227

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type S2A Design Condition Operating Qty Spares

1 CTG Step-up Transformer Oil-filled 24 kV/345 kV, 230 MVA,

3-ph, 60 Hz 2 0

2 STG Step-up Transformer Oil-filled 24 kV/345 kV, 270 MVA,

3-ph, 60 Hz 1 0

3 High Voltage Auxiliary 

Transformer Oil-filled 345 kV/13.8 kV, 46 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Auxiliary 

Transformer Oil-filled 24 kV/4.16 kV, 24 MVA,3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 4 MVA, 

3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct and 

Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct and 

Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency 

shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

228

ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment 

No. Description Type S2A Design Condition Operating Qty Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator printer (laser 

color); Engineering printer (laser B&W)

Operator stations/printers and 

engineering stations/printers 1 0

2 DCS - Processor Microprocessor with redundant 

input/output N/A 1 0

3 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

229

3.3.7 Case S2A Cost Estimating

Costs Results

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-67 shows 

the TPC summary organized by cost account for the Case S2A. A more detailed breakdown of 

the capital costs is shown in Exhibit 3-68. Exhibit 3-69 shows the calculation and addition of 

owner’s costs to determine the TOC, used to calculate COE. Exhibit 3-70 shows the initial and 

annual O&M costs for Case S2A.

The estimated TOC of the TRIGTM IGCC plant with no CO2 capture using PRB coal is 

$2,728/kW. Process contingency represents 3 percent, project contingency 11 percent, and 

owner’s costs 18 percent of the TOC. The COE is 74.5 mills/kWh.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

230

Exhibit 3-67 Case S2A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-15

Project: Low Rank Western Coal Baseline Study

Case: Case S2A - TRIG IGCC w/o CO2

Plant Size: 545.4 MW,net Estimate Type: Conceptual Cost Base (June) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING $15,315 $2,846 $11,877 $0 $0 $30,038 $2,727 $0 $6,553 $39,317 $72

 2 COAL & SORBENT PREP & FEED $74,930 $6,218 $12,637 $0 $0 $93,784 $8,134 $0 $20,384 $122,302 $224

 3 FEEDWATER & MISC. BOP SYSTEMS $7,748 $6,933 $6,960 $0 $0 $21,641 $2,030 $0 $5,280 $28,950 $53

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (TRIG) $121,159 $0 $51,615 $0 $0 $172,774 $15,430 $39,698 $34,951 $262,852 $482

4.2 Syngas Cooling w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $128,334 $0 w/equip. $0 $0 $128,334 $12,439 $0 $14,077 $154,850 $284

4.4-4.9 Flare Stack System $6,797 $10,047 $8,147 $0 $0 $24,990 $2,351 $0 $6,240 $33,581 $62

SUBTOTAL 4 $256,290 $10,047 $59,761 $0 $0 $326,097 $30,220 $39,698 $55,268 $451,284 $827

 5A GAS CLEANUP & PIPING $45,807 $2,736 $42,230 $0 $0 $90,773 $8,773 $77 $20,060 $119,683 $219

 5B CO2 REMOVAL & COMPRESSION $0 $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 $0 $92,022 $8,724 $4,601 $10,535 $115,882 $212

6.2-6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4

SUBTOTAL 6 $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $217

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,744 $0 $4,656 $0 $0 $37,399 $3,556 $0 $4,096 $45,051 $83

7.2-7.9 Ductwork, Stack and Foundations $3,358 $2,394 $3,135 $0 $0 $8,886 $824 $0 $1,580 $11,290 $21

SUBTOTAL 7 $36,101 $2,394 $7,791 $0 $0 $46,286 $4,380 $0 $5,676 $56,341 $103

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $25,881 $0 $4,366 $0 $0 $30,247 $2,902 $0 $3,315 $36,464 $67

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $32,245 $886 $11,177 $0 $0 $44,307 $4,281 $0 $9,994 $58,583 $107

SUBTOTAL 8 $58,125 $886 $15,543 $0 $0 $74,554 $7,183 $0 $13,309 $95,046 $174

 9 COOLING WATER SYSTEM $5,635 $5,789 $4,842 $0 $0 $16,266 $1,510 $0 $3,657 $21,434 $39

10 ASH/SPENT SORBENT HANDLING SYS $19,451 $1,492 $9,652 $0 $0 $30,596 $2,935 $0 $3,662 $37,192 $68

11 ACCESSORY ELECTRIC PLANT $25,693 $9,805 $19,553 $0 $0 $55,052 $4,734 $0 $11,261 $71,046 $130

12 INSTRUMENTATION & CONTROL $9,819 $1,806 $6,326 $0 $0 $17,951 $1,627 $898 $3,412 $23,887 $44

13 IMPROVEMENTS TO SITE $3,139 $1,850 $7,746 $0 $0 $12,736 $1,257 $0 $4,198 $18,191 $33

14 BUILDINGS & STRUCTURES $0 $6,105 $6,984 $0 $0 $13,089 $1,192 $0 $2,346 $16,626 $30

 

TOTAL COST $643,805 $59,713 $219,065 $0 $0 $922,584 $85,586 $45,274 $166,155 $1,219,598 $2,236

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

231

Exhibit 3-68 Case S2A Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-15

Project: Low Rank Western Coal Baseline Study

Case: Case S2A - TRIG IGCC w/o CO2

Plant Size: 545.4 MW,net Estimate Type: Conceptual Cost Base (June) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $4,022 $0 $1,965 $0 $0 $5,987 $536 $0 $1,305 $7,828 $14

1.2 Coal Stackout & Reclaim $5,197 $0 $1,260 $0 $0 $6,457 $566 $0 $1,405 $8,428 $15

1.3 Coal Conveyors & Yd Crush $4,832 $0 $1,247 $0 $0 $6,079 $534 $0 $1,322 $7,935 $15

1.4 Other Coal Handling $1,264 $0 $288 $0 $0 $1,553 $136 $0 $338 $2,026 $4

1.5 Sorbent Receive & Unload $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

1.7 Sorbent Conveyors $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

1.9 Coal & Sorbent Hnd.Foundations $0 $2,846 $7,116 $0 $0 $9,962 $955 $0 $2,183 $13,101 $24

SUBTOTAL 1. $15,315 $2,846 $11,877 $0 $0 $30,038 $2,727 $0 $6,553 $39,317 $72

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $30,142 $1,811 $4,392 $0 $0 $36,345 $3,136 $0 $7,896 $47,377 $87

2.2 Prepared Coal Storage & Feed $1,428 $342 $224 $0 $0 $1,993 $170 $0 $433 $2,596 $5

2.3 Dry Coal Injection System $42,648 $495 $3,961 $0 $0 $47,103 $4,057 $0 $10,232 $61,392 $113

2.4 Misc.Coal Prep & Feed $713 $519 $1,555 $0 $0 $2,786 $256 $0 $608 $3,650 $7

2.5 Sorbent Prep Equipment $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

2.7 Sorbent Injection System $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

2.9 Coal & Sorbent Feed Foundation $0 $3,052 $2,505 $0 $0 $5,557 $515 $0 $1,214 $7,286 $13

SUBTOTAL 2. $74,930 $6,218 $12,637 $0 $0 $93,784 $8,134 $0 $20,384 $122,302 $224

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,842 $4,880 $2,576 $0 $0 $10,297 $954 $0 $2,250 $13,502 $25

3.2 Water Makeup & Pretreating $342 $36 $191 $0 $0 $568 $54 $0 $187 $809 $1

3.3 Other Feedwater Subsystems $1,555 $525 $473 $0 $0 $2,553 $229 $0 $556 $3,339 $6

3.4 Service Water Systems $195 $403 $1,397 $0 $0 $1,995 $195 $0 $657 $2,847 $5

3.5 Other Boiler Plant Systems $1,049 $407 $1,007 $0 $0 $2,463 $234 $0 $539 $3,236 $6

3.6 FO Supply Sys & Nat Gas $291 $550 $513 $0 $0 $1,354 $130 $0 $297 $1,781 $3

3.7 Waste Treatment Equipment $478 $0 $291 $0 $0 $769 $75 $0 $253 $1,097 $2

3.8 Misc. Power Plant Equipment $997 $133 $512 $0 $0 $1,642 $159 $0 $540 $2,340 $4

SUBTOTAL 3. $7,748 $6,933 $6,960 $0 $0 $21,641 $2,030 $0 $5,280 $28,950 $53

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (TRIG) $121,159 $0 $51,615 $0 $0 $172,774 $15,430 $39,698 $34,951 $262,852 $482

4.2 Syngas Cooling w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $128,334 $0 w/equip. $0 $0 $128,334 $12,439 $0 $14,077 $154,850 $284

4.4 LT Heat Recovery & FG Saturation $6,797 $0 $2,584 $0 $0 $9,380 $915 $0 $2,059 $12,355 $23

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,038 $422 $0 $0 $1,460 $140 $0 $320 $1,920 $4

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $9,009 $5,140 $0 $0 $14,149 $1,295 $0 $3,861 $19,305 $35

SUBTOTAL 4. $256,290 $10,047 $59,761 $0 $0 $326,097 $30,220 $39,698 $55,268 $451,284 $827

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

232

Exhibit 3-68 Case S2A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-15

Project: Low Rank Western Coal Baseline Study

Case: Case S2A - TRIG IGCC w/o CO2

Plant Size: 545.4 MW,net Estimate Type: Conceptual Cost Base (June) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 5A GAS CLEANUP & PIPING

5A.1 Sulfinol System $35,180 $0 $29,851 $0 $0 $65,031 $6,289 $0 $14,264 $85,584 $157

5A.2 Elemental Sulfur Plant $4,867 $970 $6,280 $0 $0 $12,117 $1,177 $0 $2,659 $15,953 $29

5A.3 Mercury Removal $879 $0 $669 $0 $0 $1,548 $150 $77 $355 $2,130 $4

5A.4 COS Hydrolysis $3,272 $0 $4,272 $0 $0 $7,544 $734 $0 $1,656 $9,933 $18

5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

5A.5 Blowback Gas Systems $1,609 $271 $152 $0 $0 $2,032 $193 $0 $445 $2,669 $5

5A.6 Fuel Gas Piping $0 $743 $520 $0 $0 $1,263 $117 $0 $276 $1,657 $3

5A.9 HGCU Foundations $0 $752 $485 $0 $0 $1,237 $114 $0 $405 $1,757 $3

SUBTOTAL 5A. $45,807 $2,736 $42,230 $0 $0 $90,773 $8,773 $77 $20,060 $119,683 $219

 5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5B. $0 $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 $0 $92,022 $8,724 $4,601 $10,535 $115,882 $212

6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4

SUBTOTAL 6. $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $217

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,744 $0 $4,656 $0 $0 $37,399 $3,556 $0 $4,096 $45,051 $83

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,721 $1,228 $0 $0 $2,949 $259 $0 $642 $3,849 $7

7.4 Stack $3,358 $0 $1,261 $0 $0 $4,619 $443 $0 $506 $5,567 $10

7.9 HRSG,Duct & Stack Foundations $0 $673 $646 $0 $0 $1,319 $123 $0 $432 $1,874 $3

SUBTOTAL 7. $36,101 $2,394 $7,791 $0 $0 $46,286 $4,380 $0 $5,676 $56,341 $103

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $25,881 $0 $4,366 $0 $0 $30,247 $2,902 $0 $3,315 $36,464 $67

8.2 Turbine Plant Auxiliaries $179 $0 $409 $0 $0 $588 $58 $0 $65 $710 $1

8.3a Condenser & Auxiliaries $2,661 $0 $850 $0 $0 $3,511 $336 $0 $385 $4,231 $8

8.3b Air Cooled Condenser $24,385 $0 $4,889 $0 $0 $29,274 $2,927 $0 $6,440 $38,642 $71

8.4 Steam Piping $5,020 $0 $3,531 $0 $0 $8,551 $735 $0 $2,321 $11,607 $21

8.9 TG Foundations $0 $886 $1,498 $0 $0 $2,383 $226 $0 $783 $3,392 $6

SUBTOTAL 8. $58,125 $886 $15,543 $0 $0 $74,554 $7,183 $0 $13,309 $95,046 $174

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $3,875 $0 $705 $0 $0 $4,580 $436 $0 $752 $5,768 $11

9.2 Circulating Water Pumps $1,008 $0 $56 $0 $0 $1,064 $90 $0 $173 $1,326 $2

9.3 Circ.Water System Auxiliaries $92 $0 $13 $0 $0 $105 $10 $0 $17 $132 $0

9.4 Circ.Water Piping $0 $3,840 $996 $0 $0 $4,836 $437 $0 $1,055 $6,328 $12

9.5 Make-up Water System $207 $0 $296 $0 $0 $504 $48 $0 $110 $662 $1

9.6 Component Cooling Water Sys $453 $542 $386 $0 $0 $1,381 $129 $0 $302 $1,813 $3

9.9 Circ.Water System Foundations $0 $1,406 $2,391 $0 $0 $3,797 $360 $0 $1,247 $5,404 $10

SUBTOTAL 9. $5,635 $5,789 $4,842 $0 $0 $16,266 $1,510 $0 $3,657 $21,434 $39

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

233

Exhibit 3-68 Case S2A Total Plant Cost Details (Continued) Client: USDOE/NETL Report Date: 2009-Oct-15

Project: Low Rank Western Coal Baseline Study

Case: Case S2A - TRIG IGCC w/o CO2

Plant Size: 545.4 MW,net Estimate Type: Conceptual Cost Base (June) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $16,945 $0 $8,357 $0 $0 $25,302 $2,431 $0 $2,773 $30,506 $56

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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

10.4 High Temperature Ash Piping $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

10.6 Ash Storage Silos $568 $0 $618 $0 $0 $1,186 $115 $0 $195 $1,496 $3

10.7 Ash Transport & Feed Equipment $762 $0 $184 $0 $0 $946 $88 $0 $155 $1,189 $2

10.8 Misc. Ash Handling Equipment $1,176 $1,442 $431 $0 $0 $3,049 $290 $0 $501 $3,840 $7

10.9 Ash/Spent Sorbent Foundation $0 $50 $63 $0 $0 $113 $11 $0 $37 $161 $0

SUBTOTAL 10. $19,451 $1,492 $9,652 $0 $0 $30,596 $2,935 $0 $3,662 $37,192 $68

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $885 $0 $875 $0 $0 $1,759 $168 $0 $193 $2,120 $4

11.2 Station Service Equipment $3,616 $0 $326 $0 $0 $3,941 $363 $0 $430 $4,735 $9

11.3 Switchgear & Motor Control $6,684 $0 $1,216 $0 $0 $7,900 $733 $0 $1,295 $9,927 $18

11.4 Conduit & Cable Tray $0 $3,105 $10,243 $0 $0 $13,348 $1,291 $0 $3,660 $18,299 $34

11.5 Wire & Cable $0 $5,933 $3,898 $0 $0 $9,831 $714 $0 $2,636 $13,181 $24

11.6 Protective Equipment $0 $624 $2,269 $0 $0 $2,893 $283 $0 $476 $3,652 $7

11.7 Standby Equipment $221 $0 $216 $0 $0 $436 $42 $0 $72 $550 $1

11.8 Main Power Transformers $14,288 $0 $133 $0 $0 $14,420 $1,091 $0 $2,327 $17,838 $33

11.9 Electrical Foundations $0 $144 $378 $0 $0 $522 $50 $0 $172 $744 $1

SUBTOTAL 11. $25,693 $9,805 $19,553 $0 $0 $55,052 $4,734 $0 $11,261 $71,046 $130

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $969 $0 $647 $0 $0 $1,616 $153 $81 $278 $2,128 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $223 $0 $143 $0 $0 $366 $35 $18 $84 $502 $1

12.7 Computer & Accessories $5,170 $0 $166 $0 $0 $5,336 $490 $267 $609 $6,702 $12

12.8 Instrument Wiring & Tubing $0 $1,806 $3,692 $0 $0 $5,499 $466 $275 $1,560 $7,800 $14

12.9 Other I & C Equipment $3,456 $0 $1,678 $0 $0 $5,134 $483 $257 $881 $6,755 $12

SUBTOTAL 12. $9,819 $1,806 $6,326 $0 $0 $17,951 $1,627 $898 $3,412 $23,887 $44

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $99 $2,105 $0 $0 $2,204 $219 $0 $727 $3,149 $6

13.2 Site Improvements $0 $1,752 $2,328 $0 $0 $4,080 $403 $0 $1,345 $5,827 $11

13.3 Site Facilities $3,139 $0 $3,313 $0 $0 $6,452 $636 $0 $2,126 $9,215 $17

SUBTOTAL 13. $3,139 $1,850 $7,746 $0 $0 $12,736 $1,257 $0 $4,198 $18,191 $33

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1

14.2 Steam Turbine Building $0 $2,211 $3,150 $0 $0 $5,362 $493 $0 $878 $6,733 $12

14.3 Administration Building $0 $808 $586 $0 $0 $1,395 $124 $0 $228 $1,746 $3

14.4 Circulation Water Pumphouse $0 $159 $84 $0 $0 $244 $21 $0 $40 $305 $1

14.5 Water Treatment Buildings $0 $286 $279 $0 $0 $564 $51 $0 $92 $707 $1

14.6 Machine Shop $0 $414 $283 $0 $0 $697 $62 $0 $114 $872 $2

14.7 Warehouse $0 $668 $431 $0 $0 $1,099 $97 $0 $179 $1,376 $3

14.8 Other Buildings & Structures $0 $400 $312 $0 $0 $712 $64 $0 $155 $930 $2

14.9 Waste Treating Building & Str. $0 $894 $1,709 $0 $0 $2,603 $243 $0 $569 $3,415 $6

SUBTOTAL 14. $0 $6,105 $6,984 $0 $0 $13,089 $1,192 $0 $2,346 $16,626 $30

TOTAL COST $643,805 $59,713 $219,065 $0 $0 $922,584 $85,586 $45,274 $166,155 $1,219,598 $2,236

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

234

Exhibit 3-69 Case S2A Owner’s Costs

Owner's Costs $x1000 $/kW

Preproduction Costs

6 Months Fixed O&M $10,339 $19

1 Month Variable O&M $2,696 $5

25% of 1 Months Fuel Cost at 100% CF $757 $1

2% of TPC $24,392 $45

Total $38,184 $70

Inventory Capital

60 day supply of consumables at 100% CF $6,218 $11

0.5% of TPC (spare parts) $6,098 $11

Total $12,316 $23

 Initial Cost for Catalyst and Chemicals $1,197 $2

Land $900 $2

Other Owner's Costs $182,940 $335

Financing Costs $32,929 $60

Total Owner's Costs $268,466 $492

Total Overnight Cost (TOC) $1,488,063 $2,728

TASC Multiplier 1.140

Total As-Spent Cost (TASC) $1,696,392 $3,110
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

235

Exhibit 3-70 Case S2A Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (June) 2007

Case S2A - TRIG IGCC w/o CO2 Heat Rate-net(Btu/kWh): 8560

MWe-net: 545

 Capacity Factor: (%): 80

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 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-O.J.'s 15.0 15.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $5,918,913 $10.852

Maintenance Labor Cost $10,623,062 $19.477

Administrative & Support Labor $4,135,494 $7.582

Property Taxes and Insurance $24,391,958 $44.721

TOTAL FIXED OPERATING COSTS $45,069,427 $82.633

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $21,823,035 $0.00571

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

Water (/1000 gallons) 0 1,472 1.08 $0 $465,056 $0.00012

Chemicals

MU & WT Chem. (lb) 0 8,772 0.17 $0 $443,307 $0.00012

Carbon (Mercury Removal) (lb) 89,744 123 1.05 $94,246 $37,698 $0.00001

COS Catalyst (m3) 272 0.19 2,397.36 $651,525 $130,305 $0.00003

Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000

Sulfinol Solution (gal) 44,892 31 10.05 $451,105 $89,526 $0.00002

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip. 0.72 131.27 $0 $27,586 $0.00001

Subtotal Chemicals $1,196,876 $728,423 $0.00019

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 123 0.42 $0 $14,972 $0.00000

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 601 16.23 $0 $2,848,202 $0.00075

Subtotal Waste Disposal $0 $2,863,174 $0.00075

By-products & Emissions 

Sulfur (tons) 0 48 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $1,196,876 $25,879,688 $0.00677

Fuel (ton) 0 6,542 15.22 $0 $29,069,719 $0.00761
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

236

3.3.8 TRIGTM IGCC CO2 Capture Cases (S2B) Process Description

Case S2B is configured to produce electric power with CO2 capture. The plant configurations 

are similar to Cases S2A with the major differences being the addition of WGS, the use of a twostage Selexol AGR plant instead of Sulfinol and subsequent compression of the captured CO2

stream. The gross power output is constrained by the capacity of the two CTs, and since the CO2

capture and compression process increases the auxiliary load on the plant, the net output is 

significantly reduced relative to Case S2A.

The process description for Case S2B is similar to Case S2A with several notable exceptions to 

accommodate CO2 capture. A BFD for the CO2 capture case is shown in Exhibit 3-71 and 

stream tables are shown in Exhibit 3-72. Instead of repeating the entire process description, only 

differences from Cases S2A are reported here.

Coal Preparation and Feed Systems

No differences from Case S2A.

Gasification

The gasification process is the same as Case S2A except the coal feed (as-received) to the two 

gasifiers is 6,292 tonne/day (6,935 tpd).

Raw Gas Cooling/Particulate Removal

No differences from Case S2A.

Sour Water Stripper

No differences from Case S2A.

Sour Gas Shift

The SGS process was described in Section 3.1.6. In Case S2B steam is added to the cooled raw 

gas to drive the equilibrium. The hot syngas between shift stages is used to superheat the added 

steam. Three total stages of SGS results in 98.7 percent overall conversion of the CO to CO2. 

The warm syngas from the last stage of SGS is cooled to maintain the inlet syngas temperature to 

the first stage of SGS. The SGS catalyst also serves to hydrolyze COS thus eliminating the need 

for a separate COS hydrolysis reactor. Following the last stage of SGS, the syngas is further 

cooled to 35°C (95°F) prior to the mercury removal beds.

Mercury Removal and AGR

Mercury removal is the same as in Case S2A.

The AGR process in Case S2B is a two-stage Selexol process where H2S is removed in the first 

stage and CO2 in the second stage of absorption. The process results in three product streams, 

the clean syngas, a CO2-rich stream and an acid gas feed to the Claus plant. The acid gas 

contains about 18 percent H2S and 65 percent CO2 with the balance primarily H2. The CO2-rich 

stream is discussed further in the CO2 compression section.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

237

CO2 Compression and Dehydration

CO2 from the AGR process is generated at two pressure levels. The LP stream is compressed 

from 0.12 MPa (17 psia) to 1.0 MPa (150 psia) and then combined with the HP stream. The 

combined stream is further compressed to a SC condition at 15.3 MPa (2,215 psia) using a 

multiple-stage, intercooled compressor. During compression, the CO2 stream is dehydrated to a 

dew point of -40oC (-40°F) using a thermal swing adsorptive dryer. The raw CO2 stream from 

the Selexol process contains over 99 percent CO2. The dehydrated CO2 is transported to the 

plant fence line and is sequestration ready. CO2 TS&M costs were estimated using the 

methodology described in Section 2.6.

Claus Unit

The Claus plant is the same as Cases S2A except 46 tonne/day (50 tpd) of sulfur are produced.

Power Block

Clean syngas from the AGR plant is saturated and then reheated to 196°C (385°F) using HP 

BFW. The conditioned syngas is humidified and then diluted with nitrogen before it enters the 

CT burner. The exhaust gas exits the CT at 562°C (1,044°F) and enters the HRSG where 

additional heat is recovered. The flue gas exits the HRSG at 132°C (270°F) and is discharged 

through the plant stack. The steam produced in the HRSG is used to power a steam turbine with 

a nominal 12.4MPa/538°C/538°C (1,800 psig/1,000°F/1,000°F) steam cycle. There is no air

integration between the CT and the ASU in the capture case.

ASU

The same elevated pressure ASU is used as in Cases S2A except the output is 3,324 tonne/day 

(3,664 tpd) of 95 mol% oxygen.

Balance of Plant

Balance of plant items were covered in Sections 3.1.12, 3.1.13, 3.1.14, and 3.1.15.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

238

Exhibit 3-71 Case S2B Process Flow Diagram
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

239

Exhibit 3-72 Case S2B Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

Ar 0.0093 0.0237 0.0318 0.0023 0.0360 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0052 0.0067 0.0067

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0336 0.0436 0.0429

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2242 0.0038 0.0039

CO2 0.0003 0.0081 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1049 0.4228 0.4261

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1761 0.5150 0.5109

H2O 0.0064 0.1540 0.0000 0.0002 0.0000 1.0000 0.0000 1.0000 0.0000 0.0000 1.0000 0.4484 0.0016 0.0016

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0019 0.0026 0.0026

N2 0.7759 0.6137 0.0178 0.9920 0.0140 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0030 0.0039 0.0052

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0025 0.0000 0.0000

O2 0.2081 0.2005 0.9504 0.0054 0.9500 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 20,872 843 66 14,034 4,231 3,557 0 1,455 0 0 10,253 29,511 22,771 23,132

V-L Flowrate (kg/hr) 603,087 23,325 2,117 393,817 136,368 64,074 0 26,217 0 0 184,714 598,379 476,930 488,394

Solids Flowrate (kg/hr) 0 0 0 0 0 0 262,152 0 237,311 24,089 0 0 0 0

Temperature (°C) 6 20 32 196 32 343 6 16 71 982 288 230 35 35

Pressure (MPa, abs) 0.09 0.11 0.86 2.62 0.86 5.10 0.09 0.10 0.10 4.24 4.14 4.02 3.73 3.66

Enthalpy (kJ/kg)A 15.26 38.58 26.67 202.66 26.59 3,062.93 --- 65.08 --- --- 2,955.16 1,341.87 39.70 39.05

Density (kg/m3) 1.1 1.5 11.0 18.7 11.0 20.1 --- 1,002.6 --- --- 18.2 20.2 31.4 31.1

V-L Molecular Weight 28.895 27.685 32.181 28.061 32.229 18.015 --- 18.015 --- --- 18.015 20.276 20.945 21.113

V-L Flowrate (lbmol/hr) 46,014 1,857 145 30,941 9,328 7,841 0 3,208 0 0 22,604 65,062 50,202 50,998

V-L Flowrate (lb/hr) 1,329,580 51,423 4,668 868,218 300,640 141,259 0 57,798 0 0 407,225 1,319,200 1,051,450 1,076,726

Solids Flowrate (lb/hr) 0 0 0 0 0 0 577,946 0 523,182 53,107 0 0 0 0

Temperature (°F) 42 68 90 385 90 650 42 60 160 1,800 550 446 95 94

Pressure (psia) 13.0 16.4 125.0 380.0 125.0 740.0 13.0 14.5 14.6 615.0 600.0 582.5 540.4 530.4

Enthalpy (Btu/lb)A 6.6 16.6 11.5 87.1 11.4 1,316.8 --- 28.0 --- --- 1,270.5 576.9 17.1 16.8

Density (lb/ft3) 0.070 0.093 0.687 1.167 0.688 1.257 --- 62.589 --- --- 1.135 1.260 1.958 1.939

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

240

Exhibit 3-72 Case S2B Stream Table (Continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 28 29

V-L Mole Fraction

Ar 0.0020 0.0000 0.0063 0.0074 0.0111 0.0085 0.0093 0.0088 0.0088 0.0000 0.0000 0.0000 0.0000 0.0001 0.0001

CH4 0.0239 0.0000 0.0055 0.0000 0.0698 0.0538 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0022 0.0022

CO 0.0013 0.0000 0.1128 0.0076 0.0064 0.0049 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0001

CO2 0.6511 0.0000 0.3578 0.5528 0.0542 0.0418 0.0003 0.0145 0.0145 0.0000 0.0000 0.0000 0.0000 0.9908 0.9935

COS 0.0001 0.0000 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

H2 0.1105 0.0000 0.0590 0.2189 0.8497 0.6545 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0041 0.0041

H2O 0.0350 0.0000 0.3947 0.1381 0.0001 0.2298 0.0064 0.1454 0.1454 1.0000 1.0000 1.0000 1.0000 0.0027 0.0000

H2S 0.1753 0.0000 0.0008 0.0018 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0007 0.0000 0.0625 0.0735 0.0087 0.0067 0.7759 0.7272 0.7272 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2081 0.1041 0.1041 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0004 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 0.0000 1.0000 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) 341 0 492 418 13,822 17,944 100,835 126,897 126,897 32,509 12,936 12,936 40,195 8,969 8,945

V-L Flowrate (kg/hr) 12,277 0 13,917 12,493 84,121 158,381 2,913,623 3,465,821 3,465,821 585,655 233,055 233,055 724,125 391,997 391,563

Solids Flowrate (kg/hr) 0 1,903 0 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 48 177 232 49 31 196 6 562 132 534 32 32 33 16 72

Pressure (MPa, abs) 0.16 0.12 0.1 0.073 3.309 3.216 0.090 0.093 0.090 12.512 0.005 0.005 0.827 1.032 15.270

Enthalpy (kJ/kg)A 90.08 --- 919.2 263.386 145.239 1,851.859 15.260 881.971 384.653 3,432.690 2,295.131 2,295.131 140.154 5.022 -94.557

Density (kg/m3) 2.2 --- 0.6 0.8 7.9 7.3 1.1 0.4 0.8 36.7 0.04 0.04 995.0 20.1 459.1

V-L Molecular Weight 36.008 --- 28 29.884 6.086 8.826 28.895 27.312 27.312 18.015 18.015 18.015 18.015 43.706 43.775

V-L Flowrate (lbmol/hr) 752 0 1,084 922 30,473 39,560 222,302 279,760 279,760 71,670 28,520 28,520 88,615 19,773 19,720

V-L Flowrate (lb/hr) 27,066 0 30,682 27,543 185,455 349,170 6,423,439 7,640,828 7,640,828 1,291,148 513,797 513,797 1,596,423 864,205 863,250

Solids Flowrate (lb/hr) 0 4,196 0 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 119 350 450 120 87 385 42 1,044 270 994 90 90 92 60 162

Pressure (psia) 23.7 17.3 12.3 10.6 480.0 466.4 13.0 13.5 13.0 1,814.7 0.7 0.7 120.0 149.7 2,214.7

Enthalpy (Btu/lb)A 38.7 --- 395.2 113.2 62.4 796.2 6.6 379.2 165.4 1,475.8 986.7 986.7 60.3 2.2 -40.7

Density (lb/ft3) 0.138 --- 0.036 0.051 0.492 0.454 0.070 0.023 0.047 2.293 0.002 0.002 62.117 1.253 28.658
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

241

3.3.9 Case S2B Performance Results

The Case S2B modeling assumptions were presented previously in Exhibit 3-56.

The TRIGTM IGCC plant with CO2 capture and using PRB coal at the Montana site (elevation 

3,400 ft) produces a net output of 461 MWe at a net plant efficiency of 31.8 percent (HHV 

basis).

Overall performance for the plant is summarized in Exhibit 3-73, which includes auxiliary power 

requirements. The ASU accounts for approximately 57 percent of the total auxiliary load, 

distributed between the main air compressor, the oxygen compressor, the nitrogen compressor, 

and ASU auxiliaries. CO2 compression accounts for about 18 percent and the AGR process 

about 10 percent of the auxiliary load. All other individual auxiliary loads are less than 3 percent 

of the total.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

242

Exhibit 3-73 Case S2B Plant Performance Summary

POWER SUMMARY (Gross Power at Generator 

Terminals, kWe) S2B

Gas Turbine Power 426,400

Steam Turbine Power 194,900

TOTAL POWER, kWe 621,300

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 510

Coal Crushing 730

Ash Handling 630

Coal Dryer Circulation Blower 2,560

Air Separation Unit Auxiliaries 1,000

Air Separation Unit Main Air Compressor 53,710

Oxygen Compressor 6,600

Nitrogen Compressors 30,060

CO2 Compressor 28,290

Boiler Feedwater Pumps 3,960

Condensate Pump 240

Syngas Recycle Compressors 1,550

Circulating Water Pump 2,020

Ground Water Pumps 280

Cooling Tower Fans 1,320

Air Cooled Condenser Fans 2,230

Acid Gas Removal 16,480

Gas Turbine Auxiliaries 1,000

Steam Turbine Auxiliaries 100

Claus Plant/TGTU Auxiliaries 250

Claus Plant TG Recycle Compressor 1,600

Miscellaneous Balance of Plant1 3,000

Transformer Losses 2,330

TOTAL AUXILIARIES, kWe 160,450

NET POWER, kWe 460,850

Net Plant Efficiency, % (HHV) 31.8%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,331 (10,740)

CONDENSER COOLING DUTY GJ/hr (106 Btu/hr) 992 (940)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 262,152 (577,946)

Thermal Input, kWt 1,450,564

Raw Water Withdrawal, m3/min (gpm) 11.3 (2,989)

Raw Water Consumption, m3/min (gpm) 9.5 (2,517)

1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

243

Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, CO2, and PM were presented in 

Section 2.3. A summary of the plant air emissions for Case S2B is presented in Exhibit 3-74.

Exhibit 3-74 Case S2B Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

80% capacity factor

kg/MWh

(lb/MWh)

SO2 0.000 (0.001) 13 (15) 0.003 (0.007)

NOX 0.021 (0.049) 770 (849) 0.177 (0.390)

Particulates 0.003 (0.0071) 112 (123) 0.026 (0.057)

Hg 1.51E-7 (3.51E-7) 0.006 (0.006) 1.27E-6 (2.80E-6)

CO2 gross 15.5 (36.0) 566,135 (624,057) 130 (287)

CO2 net 175 (386)

The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the two-stage 

Selexol AGR process. Just as in the non-capture cases, the SO2 emission are significantly less 

than the environmental targets of Section 2.3. The clean syngas exiting the AGR process has a 

sulfur concentration of approximately 2 ppmv. This results in a concentration in the flue gas of 

less than 0.3 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, 

producing elemental sulfur. The tail gas is hydrogenated and recycled to the gasifier.

NOx emissions are limited to 15 ppmvd (as NO2 @ 15 percent O2) by the use of humidification 

and nitrogen dilution of the fuel gas and low NOx burners. Ammonia in the syngas is removed 

with process condensate prior to the low-temperature AGR process and subsequently destroyed 

in the Claus plant burner. This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone 

and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Ninety five percent of mercury is captured from the syngas by an activated carbon bed.

More than 92 percent of the CO2 from the syngas is captured in the AGR system and compressed 

for sequestration. In the TRIGTM case, because of the considerable methane content, which is 

not removed by the AGR, and because not all the CO is converted to CO2 in the shift reactors, 

the overall CO2 removal is less than the target 90 percent. The high methane concentrations are 

a result of the lower gasification temperatures, which result in a higher cold gas efficiency

(CGE), which is particularly important for power generation applications. It is technologically 

possible to remove the last marginal amounts of carbon to achieve 90% overall capture, though 

these approaches are either unjustifiably detrimental to the performance of the plant, or outside 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

244

the parameters of this study. These possibilities include steam reforming of the methane, 

increasing the solvent circulation rate in the Selexol AGR to increase its CO2 removal, although 

with diminishing returns, or co-sequestering CO2 and sulfur, using different AGR solvents that 

can achieve higher CO2 removals.

The carbon balance for the plant is shown in Exhibit 3-75. The carbon input to the plant consists 

of carbon in the air in addition to carbon in the coal. Carbon in the air is not used in the carbon 

capture equation below, but it is not neglected in the balance since the Aspen model accounts for 

air components throughout. Carbon leaves the plant as unburned carbon in the ash, CO2 in the 

stack gas and ASU vent gas, and the captured CO2 product. The carbon capture efficiency is 

defined as the amount 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 Product for Sequestration)/[(Carbon in the Coal)-(Carbon in Slag)] or

83.2 percent

Exhibit 3-75 Case S2B Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 131,255 (289,367) Slag/Ash 2,625 (5,787)

Air (CO2) 479 (1,057) Stack Gas 22,047 (48,606)

ASU Vent 82 (181)

CO2 Product 106,980 (235,850)

Total 131,734 (290,424) Total 131,734 (290,424)

Exhibit 3-76 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the 

stack gas and sulfur that is co-sequestered with the CO2 product. Sulfur in the ash is considered 

negligible. 

Exhibit 3-76 Case S2B Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 1,907 (4,204) Elemental Sulfur 1,903 (4,196)

Stack Gas 1 (2)

CO2 Product 3 (6)

Total 1,907 (4,204) Total 1,907 (4,204)

Exhibit 3-77 shows the overall water balance for the plant. 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, primarily from the coal drying process and as syngas condensate, and that water is re-
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

245

used as internal recycle. Raw water withdrawal is the difference between water demand and 

internal recycle. Some water is discharged from the process to a permitted outfall. The 

difference between the withdrawal and discharge is the consumption.

Exhibit 3-77 Case S2B Water Balance

Water Use

Water 

Demand

m3/min (gpm)

Internal 

Recycle 

m3/min (gpm)

Raw Water 

Withdrawal 

m3/min (gpm)

Process 

Water 

Discharge 

m3/min (gpm)

Raw Water 

Consumption 

m3/min (gpm)

S2B S2B S2B S2B S2B

Slag Handling 0.52 (138) 0.5 (138) 0 (0) 0 (0) 0 (0)

Humidifier 1.28 (337) 1.3 (337) 0 (0) 0 (0) 0 (0)

SWS Blowdown 0 (0) 0 (0) 0 (0) 0.02 (5) -0.02 (-5)

Condenser Makeup 4.31 (1,138) 0 (0) 4.31 (1,138) 0 (0) 4.31 (1,138)

Gasifier Steam 1.07 (283) 1.07 (283)

Shift Steam 3.08 (814) 3.08 (814)

BFW Makeup 0.15 (41) 0.15 (41)

Cooling Tower Makeup 7.86 (2,077) 0.85 (225) 7.01 (1,852) 1.77 (467) 5.24 (1,384)

Coal Drying 0.44 (116) -0.44 (-116)

BFW Blowdown 0.15 (41) -0.15 (-41)

SWS Blowdown 0.19 (49) -0.19 (-49)

SWS Excess Water 0.07 (20) -0.07 (-20)

Total 14.0 (3,690) 2.7 (700) 11.3 (2,989) 1.8 (472) 9.5 (2,517)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

246

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-78:

• Coal gasification and ASU

• Syngas cleanup

• Power block

An overall plant energy balance is provided in tabular form in Exhibit 3-79 based on 0°C (32°F) 

reference conditions. The power out is the combined CT and steam turbine power after 

generator losses.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

247

Exhibit 3-78 Case S2B Heat and Mass Balance 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

248

Exhibit 3-78 Case S2B Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

249

Exhibit 3-78 Case S2B Heat and Mass Balance (Continued) 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

250

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Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

251

Exhibit 3-79 Case S2B Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,222 (4,950) 2.7 (2.5) 0 (0) 5,225 (4,952)

ASU Air 0 (0) 9.2 (8.7) 0 (0) 9 (9)

GT Air 0 (0) 44.5 (42.1) 0 (0) 44 (42)

Raw Water Makeup 0 (0) 15.7 (14.9) 0 (0) 16 (15)

Auxiliary Power 0 (0) 0 (0) 578 (547) 578 (547)

Totals 5,222 (4,950) 72.1 (68.3) 578 (547) 5,872 (5,565)

Heat Out GJ/hr (MMBtu/hr)

ASU Intercoolers 0 (0) 185 (176) 0 (0) 185 (176)

ASU Vent 0 (0) 0.9 (0.9) 0 (0) 1 (1)

Slag 86 (82) 25.0 (23.7) 0 (0) 111 (105)

Sulfur 18 (17) 0.2 (0.2) 0 (0) 18 (17)

CO2 0 (0) -37.0 (-35.1) 0 (0) -37 (-35)

CO2 Comp Intercoolers 0 (0) 137.0 (129.9) 0 (0) 137 (130)

Cooling Tower Blowdown 0 (0) 9.9 (9.3) 0 (0) 10 (9)

HRSG Flue Gas 0 (0) 1,333 (1,264) 0 (0) 1,333 (1,264)

Condenser 0 (0) 989 (937) 0 (0) 989 (937)

Auxiliary Cooling 0 (0) 32 (30) 0 (0) 32 (30)

Electrical Generator Loss 0 (0) 0 (0) 34 (32) 34 (32)

Process Losses 0 (0) 822 (779) 0 (0) 822 (779)

Power 0 (0) 0 (0) 2,237 (2,120) 2,237 (2,120)

Totals 104 (98) 3,497 (3,315) 2,271 (2,152) 5,872 (5,565)

3.3.10 Case S2B Equipment List

Major equipment items for the TRIGTM gasifier with CO2 capture are shown in the following 

tables. The accounts used in the equipment list correspond to the account numbers used in the 

cost estimates in Section 3.3.11. In general, the design conditions include a 10 percent 

contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

252

ACCOUNT 1 COAL HANDLING

Equipment 

No. Description Type S2B Design Condition Operating Qty Spares

1 Bottom Trestle Dumper 

and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0

4 Transfer Tower No. 1 Enclosed N/A 1 0

5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As-Received Coal 

Sampling System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0

8 Reclaim Hopper N/A 54 tonne (60 ton) 2 1

9 Feeder Vibratory 218 tonne/hr (240 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 435 tonne/hr (480 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent 

Filter Dual outlet 218 tonne (240 ton) 2 0

13 Crusher Impactor reduction 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 1 1

15 Conveyor No. 4 Belt w/tripper 435 tonne/hr (480 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 435 tonne/hr (480 tph) 1 0

18 Coal Silo w/ Vent Filter 

and Slide Gates Field erected 998 tonne (1,100 ton) 3 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

253

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type S2B Design Condition Operating Qty Spares

1 Feeder Vibratory 45 tonne/hr (50 tph) 6 0

2 Coal Mill Hydraulic 

Unit

Hot gas 177°C (350°F) enters 

the bottom of the mill for 

drying and conveying

290 tonne (320 ton) 2 0

3 Cyclonic Baghouse Gas Recycled to Dryer, Coal 

to Feeder

Coal - 100 tonne (110 ton)

Recycle Gas -240,304 kg/hr 

(529,780 lb/hr)

6 0

4 Discharge Feeder Rotary 45 tonne/hr (50 tph) 6 0

5 Coal Feed Storage Bin Vertical Hopper 45 tonne/hr (50 tph) 6 0

6 Coal Feed Lock 

Vessel Vertical Hopper 45 tonne/hr (50 tph) 6 0

7 Coal Feed Conveyor Vertical Hopper 100 tonne (110 ton) 6 0

8 Drying Recycle 

Cooler Water cooled shell and tube 240,304 kg/hr (529,780 lb/hr) 6 0

9 Moisture Separator 

Drum Cyclonic 240,304 kg/hr (529,780 lb/hr) 6 0

10 Baghouse Exhaust 

Blower Centrifugal

Recycle Gas- 240,304 kg/hr 

(529,780 lb/hr)

2,560 kWe

6 0

11 Drying Heater Steam heated shell and tube

Recycle Gas- 240,304 kg/hr 

(529,780 lb/hr)

120 MMBtu/hr

6 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

254

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment 

No. Description Type S2B Design Condition Operating Qty Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, 

outdoor 594,310 liters (157,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,700 lpm @ 91 m H2O

(1,770 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray 

type 498,044 kg/hr (1,098,000 lb/hr) 2 0

4 Intermediate Pressure Feedwater 

Pump

Horizontal 

centrifugal, single 

stage

1,060 lpm @ 27 m H2O

(280 gpm @ 90 ft H2O) 2 1

5 High Pressure Feedwater Pump No. 

1

Barrel type, multistage, centrifugal

HP water: 5,716 lpm @ 1,890 m 

H2O (1,510 gpm @ 6,200 ft 

H2O)

2 1

6 High Pressure Feedwater Pump No. 

2

Barrel type, multistage, centrifugalIP water: 1,817 lpm @ 223 m 

H2O (480 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) 1 0

8 Service Air Compressors Flooded Screw 28 m3

/min @ 0.7 MPa

(1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, 

regenerative 28 m3

/min (1,000 scfm) 2 1

10 Closed Cycle Cooling Heat 

Exchangers Plate and frame 210 GJ/hr (199 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water 

Pumps

Horizontal 

centrifugal

74,951 lpm @ 21 m H2O

(19,800 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) 1 1
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

255

Equipment 

No. Description Type S2B Design Condition Operating Qty Spares

13 Fire Service Booster Pump

Two-stage 

horizontal 

centrifugal

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, 

single suction

3,142 lpm @ 18 m H2O

(830 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, 

single suction

3,142 lpm @ 268 m H2O (830 

gpm @ 880 ft H2O) 2 1

16 Filtered Water Pumps Stainless steel, 

single suction

3,445 lpm @ 49 m H2O

(910 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,650,440 liter (436,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and 

mixed bed 1,855 lpm (490 gpm) 2 0

19 Liquid Waste Treatment System 10 years, 24-hour storm 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

256

ACCOUNT 4 GASIFIER, ASU, AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment 

No. Description Type S2B Design Condition Operating Qty Spares

1 Gasifier TRIGTM dry feed, circulating fastfluidized bed

3,447 tonne/day, 4.2 MPa

(3,800 tpd, 615 psia) 2 0

2 Synthesis Gas 

Cooler

Vertical down flow heat exchanger 

with evaporator, superheater, and 

economizer stages

299,825 kg/hr (661,000 lb/hr) 2 0

3 Synthesis Gas 

Cyclone High efficiency 299,825 kg/hr (661,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with pulse-jet 

cleaning metallic filters 2 0

5

Syngas Scrubber 

Including Sour 

Water Stripper

Vertical up flow 227,703 kg/hr (502,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with condensate drain 262,630 kg/hr (579,000 lb/hr) 8 0

7 Raw Gas Knockout 

Drum Vertical with mist eliminator 262,176 kg/hr, 35°C, 3.7 MPa(578,000 lb/hr, 95°F, 540 psia) 2 0

8 Saturation Water 

Economizers Shell and tube 262,630 kg/hr (579,000 lb/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 87,090 kg/hr, 239°C, 3.3 MPa

(192,000 lb/hr, 462°F, 480 psia) 2 0

10 Saturator Water 

Pump Centrifugal 1,893 lpm @ 12 m H2O(500 gpm @ 40 ft H2O) 2 2
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

257

Equipment 

No. Description Type S2B Design Condition Operating Qty Spares

11 Synthesis Gas 

Reheater Shell and tube 46,266 kg/hr (102,000 lb/hr) 2 0

12 Flare Stack Self-supporting, carbon steel, stainless 

steel top, pilot ignition

227,703 kg/hr (502,000 lb/hr) 

syngas

2 0

13 ASU Main Air 

Compressor Centrifugal, multi-stage 4,531 m3

/min @ 1.3 MPa

(160,000 scfm @ 190 psia) 2 0

14 Cold Box Vendor design 1,814 tonne/day (2,000 tpd) of 

95% purity oxygen 2 0

15 Oxygen 

Compressor Centrifugal, multi-stage

934 m3/min (33,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 4.3 MPa (620 psia)

2 0

16 Primary Nitrogen 

Compressor Centrifugal, multi-stage

2,010 m3/min (71,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.6 MPa (380 psia)

2 0

17 Secondary Nitrogen 

Compressor Centrifugal, single-stage

368 m3

/min (13,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 5.7 MPa (820 psia)

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

258

ACCOUNT 5 SYNGAS CLEANUP

Equipment 

No. Description Type S2B Design Condition Operating Qty Spares

1 Mercury Adsorber Sulfated carbon 

bed

262,176 kg/hr (578,000 lb/hr) 

35°C (95°F) 

3.7 MPa (540 psia)

2 0

2 Sulfur Plant Claus type 50 tonne/day (55 tpd) 1 0

3 Water Gas Shift Reactors Fixed bed, 

catalytic

329,308 kg/hr (726,000 lb/hr) 

232°C (450°F) 

4.0 MPa (580 psia)

4 0

4 Shift Reactor Heat Recovery 

Exchangers Shell and Tube

Exchanger 1: 131 GJ/hr (124 

MMBtu/hr) 

Exchanger 2: 19 GJ/hr (18 MMBtu/hr) 

4 0

5 Acid Gas Removal Plant Two-stage Selexol

268,527 kg/hr (592,000 lb/hr) 

35°C (94°F) 

3.7 MPa (530 psia)

2 0

6 Hydrogenation Reactor Fixed bed, 

catalytic

15,309 kg/hr (33,750 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

1 0

7 Tail Gas Recycle Compressor Centrifugal 12,626 kg/hr (27,835 lb/hr) 1 0

ACCOUNT 5B CO2 COMPRESSION

Equipment 

No. Description Type S2B Design Condition Operating Qty Spares

1 CO2

Compressor

Integrally geared, multi-stage 

centrifugal

971 m3/min @ 15.3 MPa (34,300 scfm 

@ 2,215 psia) 4 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

259

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment 

No. Description Type S2B Design Condition Operating Qty Spares

1 Gas Turbine Advanced F 

class 215 MW 2 0

2 Gas Turbine Generator TEWAC 240 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0

ACCOUNT 7 HRSG, DUCTING AND STACK

Equipment 

No. Description Type S2B Design Condition Operating Qty Spares

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x

8.6 m (20 ft) diameter 2 0

2 Heat Recovery 

Steam Generator

Drum, multi-pressure with 

economizer section and 

integral deaerator

Main steam - 322,110 kg/hr, 12.4 MPa/534°C 

(710,131 lb/hr, 1,800 psig/994°F)

Reheat steam - 279,722 kg/hr, 3.1 MPa/534°C 

(616,681 lb/hr, 452 psig/994°F)

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

260

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type S2B Design Condition Operating Qty Spares

1 Steam Turbine Commercially 

available

205 MW

12.4 MPa/534°C/534°C (1,800 psig/ 994°F/994°F) 1 0

2 Steam Turbine 

Generator

Hydrogen cooled, 

static excitation 230 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0

3 Surface 

Condenser

Single pass, divided 

waterbox including 

vacuum pumps

549 GJ/hr (520 MMBtu/hr), 

Condensing temperature 32°C (90°F), 

Inlet water temperature 9°C (48°F), 

Water temperature rise 11°C (20°F)

1 0

4 Air-cooled 

Condenser ---

549 GJ/hr (520 MMBtu/hr), 

Condensing temperature 32°C (90°F), 

Ambient temperature 6°C (42°F)

1 0

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type S2B Design Condition Operating Qty Spares

1 Circulating Water 

Pumps Vertical, wet pit 200,627 lpm @ 30 m

(53,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative, mechanical draft, 

multi-cell

3°C (37°F) WB / 9°C (48°F) CWT / 

20°C (68°F) HWT / 1,129 GJ/hr 

(1,070 MMBtu/hr) heat duty

1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

261

ACCOUNT 10 ASH RECOVERY AND HANDLING

Equipment 

No. Description Type S2B Design Condition Operating Qty Spares

1 Coarse Ash Depressurization 

and Cooling Proprietary Fine Ash - 3 tonne/hr (3 tph) 2 0

2 Makeup Solids Storage Bin Vertical, shop 

fabricated 32 tonnes (35 tons) 2 0

3 Makeup Solids Storage Bin 

Vent Filter Pulsed Fabric Filter 190 Nm3

/hr (112 scfm) 2 0

4 Coarse Ash Conveyor Dense Phase 3 tonne/hr (3 tph) 2 0

5 Fine Ash Depressurization 

and Cooling Proprietary Coarse Ash - 11 tonne/hr (12 tph) 2 0

6 Ash Storage Silo Reinforced concrete 3,180 tonne (3,505 tons) 1 0

7 Ash Silo Vent Filter Pulsed Fabric Filter 3,055 Nm3/hr (1,797 scfm) 1 0

8 Storage Silo Discharge Feeder Rotary 318 tonne/hr (351 tph) 2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

262

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type S2B Design Condition Operating Qty Spares

1 CTG Step-up Transformer Oil-filled 24 kV/345 kV, 240 MVA, 

3-ph, 60 Hz 2 0

2 STG Step-up Transformer Oil-filled 24 kV/345 kV, 230 MVA,

3-ph, 60 Hz 1 0

3 High Voltage Auxiliary 

Transformer Oil-filled 345 kV/13.8 kV, 67 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Auxiliary 

Transformer Oil-filled 24 kV/4.16 kV, 41 MVA,3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 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 2 0

7 STG Isolated Phase Bus Duct 

and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency 

shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

263

ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment 

No. Description Type S2B Design Condition Operating Qty Spares

1 DCS - Main Control

Monitor/keyboard; Operator 

printer (laser color);

Engineering printer (laser 

B&W)

Operator stations/printers and 

engineering stations/printers 1 0

2 DCS - Processor Microprocessor with redundant 

input/output N/A 1 0

3 DCS - Data Highway Fiber optic Fully redundant, 25% spare 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

264

3.3.11 Case S2B Cost Estimating

Costs Results

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-80 shows 

the TPC summary organized by cost account with a more detailed breakdown of the capital costs 

shown in Exhibit 3-81. Exhibit 3-82 shows the calculation and addition of owner’s costs to 

determine the TOC, used to calculate COE. Exhibit 3-83 shows the initial and annual O&M 

costs for Case S2B.

The estimated TOC of the TRIGTM IGCC plant with CO2 capture using PRB coal is $3,691/kW. 

Process contingency represents 4 percent, project contingency 11 percent, and owner’s costs 18 

percent of the TOC. The COE is 105.2 mills/kWh.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

265

Exhibit 3-80 Case S2B Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-15

Project: Low Rank Western Coal Baseline Study

Case: Case S2B - TRIG IGCC w/ CO2

Plant Size: 460.9 MW,net Estimate Type: Conceptual Cost Base (June) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING $15,879 $2,951 $12,314 $0 $0 $31,144 $2,827 $0 $6,794 $40,765 $88

 2 COAL & SORBENT PREP & FEED $77,809 $6,484 $13,276 $0 $0 $97,568 $8,464 $0 $21,207 $127,239 $276

 3 FEEDWATER & MISC. BOP SYSTEMS $8,217 $6,965 $7,732 $0 $0 $22,915 $2,154 $0 $5,676 $30,746 $67

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $125,998 $0 $53,847 $0 $0 $179,845 $16,058 $41,465 $36,371 $273,739 $594

4.2 Syngas Cooling (w/4.1) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $128,018 $0 w/equip. $0 $0 $128,018 $12,409 $0 $14,043 $154,470 $335

4.4-4.9 Other Gasification Equipment $9,189 $10,292 $9,200 $0 $0 $28,681 $2,709 $0 $7,073 $38,463 $83

SUBTOTAL 4 $263,206 $10,292 $63,047 $0 $0 $336,544 $31,175 $41,465 $57,487 $466,672 $1,013

 5A GAS CLEANUP & PIPING $76,834 $2,672 $64,176 $0 $0 $143,682 $13,879 $23,255 $36,288 $217,105 $471

 5B CO2 REMOVAL & COMPRESSION $16,750 $0 $9,707 $0 $0 $26,457 $2,547 $0 $5,801 $34,805 $76

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,610 $9,348 $9,861 $11,782 $129,600 $281

6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5

SUBTOTAL 6 $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $286

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $31,608 $0 $4,494 $0 $0 $36,103 $3,433 $0 $3,954 $43,489 $94

7.2-7.9 Ductwork and Stack $3,430 $2,445 $3,203 $0 $0 $9,078 $842 $0 $1,614 $11,534 $25

SUBTOTAL 7 $35,038 $2,445 $7,697 $0 $0 $45,181 $4,274 $0 $5,568 $55,023 $119

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $22,780 $0 $3,777 $0 $0 $26,557 $2,548 $0 $2,911 $32,016 $69

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $28,346 $776 $10,012 $0 $0 $39,134 $3,773 $0 $8,865 $51,772 $112

SUBTOTAL 8 $51,126 $776 $13,789 $0 $0 $65,691 $6,321 $0 $11,776 $83,788 $182

 9 COOLING WATER SYSTEM $5,860 $5,932 $5,047 $0 $0 $16,839 $1,564 $0 $3,784 $22,187 $48

10 ASH/SPENT SORBENT HANDLING SYS $20,179 $1,541 $10,013 $0 $0 $31,732 $3,044 $0 $3,796 $38,573 $84

11 ACCESSORY ELECTRIC PLANT $28,954 $11,504 $22,461 $0 $0 $62,920 $5,413 $0 $12,976 $81,309 $176

12 INSTRUMENTATION & CONTROL $10,732 $1,974 $6,915 $0 $0 $19,621 $1,778 $981 $3,729 $26,110 $57

13 IMPROVEMENTS TO SITE $3,220 $1,898 $7,945 $0 $0 $13,063 $1,290 $0 $4,306 $18,659 $40

14 BUILDINGS & STRUCTURES $0 $6,068 $6,854 $0 $0 $12,922 $1,176 $0 $2,324 $16,423 $36

 

TOTAL COST $705,833 $62,309 $258,448 $0 $0 $1,026,590 $95,414 $75,563 $193,851 $1,391,417 $3,019

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

266

Exhibit 3-81 Case S2B Total Plant Cost Summary Details

Client: USDOE/NETL Report Date: 2009-Oct-15

Project: Low Rank Western Coal Baseline Study

Case: Case S2B - TRIG IGCC w/ CO2

Plant Size: 460.9 MW,net Estimate Type: Conceptual Cost Base (June) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $4,170 $0 $2,038 $0 $0 $6,208 $556 $0 $1,353 $8,117 $18

1.2 Coal Stackout & Reclaim $5,389 $0 $1,306 $0 $0 $6,695 $587 $0 $1,456 $8,738 $19

1.3 Coal Conveyors & Yd Crush $5,010 $0 $1,293 $0 $0 $6,302 $553 $0 $1,371 $8,227 $18

1.4 Other Coal Handling $1,311 $0 $299 $0 $0 $1,610 $141 $0 $350 $2,101 $5

1.5 Sorbent Receive & Unload $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

1.7 Sorbent Conveyors $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

1.9 Coal & Sorbent Hnd.Foundations $0 $2,951 $7,378 $0 $0 $10,329 $990 $0 $2,264 $13,583 $29

SUBTOTAL 1. $15,879 $2,951 $12,314 $0 $0 $31,144 $2,827 $0 $6,794 $40,765 $88

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $31,325 $1,882 $4,564 $0 $0 $37,771 $3,259 $0 $8,206 $49,237 $107

2.2 Prepared Coal Storage & Feed $1,347 $322 $211 $0 $0 $1,880 $161 $0 $408 $2,449 $5

2.3 Dry Coal Injection System $44,321 $514 $4,116 $0 $0 $48,952 $4,216 $0 $10,634 $63,802 $138

2.4 Misc.Coal Prep & Feed $816 $594 $1,780 $0 $0 $3,190 $293 $0 $697 $4,180 $9

2.5 Sorbent Prep Equipment $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

2.7 Sorbent Injection System $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

2.9 Coal & Sorbent Feed Foundation $0 $3,171 $2,604 $0 $0 $5,775 $535 $0 $1,262 $7,572 $16

SUBTOTAL 2. $77,809 $6,484 $13,276 $0 $0 $97,568 $8,464 $0 $21,207 $127,239 $276

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,720 $4,671 $2,466 $0 $0 $9,856 $913 $0 $2,154 $12,923 $28

3.2 Water Makeup & Pretreating $447 $47 $250 $0 $0 $744 $71 $0 $244 $1,059 $2

3.3 Other Feedwater Subsystems $1,488 $503 $453 $0 $0 $2,443 $220 $0 $533 $3,196 $7

3.4 Service Water Systems $256 $527 $1,829 $0 $0 $2,612 $255 $0 $860 $3,727 $8

3.5 Other Boiler Plant Systems $1,374 $532 $1,319 $0 $0 $3,225 $306 $0 $706 $4,237 $9

3.6 FO Supply Sys & Nat Gas $291 $550 $513 $0 $0 $1,354 $130 $0 $297 $1,781 $4

3.7 Waste Treatment Equipment $625 $0 $381 $0 $0 $1,007 $98 $0 $331 $1,436 $3

3.8 Misc. Power Plant Equipment $1,016 $136 $522 $0 $0 $1,674 $162 $0 $551 $2,387 $5

SUBTOTAL 3. $8,217 $6,965 $7,732 $0 $0 $22,915 $2,154 $0 $5,676 $30,746 $67

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (TRIG) $125,998 $0 $53,847 $0 $0 $179,845 $16,058 $41,465 $36,371 $273,739 $594

4.2 Syngas Cooling w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $128,018 $0 w/equip. $0 $0 $128,018 $12,409 $0 $14,043 $154,470 $335

4.4 LT Heat Recovery & FG Saturation $9,189 $0 $3,493 $0 $0 $12,683 $1,238 $0 $2,784 $16,705 $36

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,017 $414 $0 $0 $1,431 $137 $0 $314 $1,881 $4

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $9,275 $5,292 $0 $0 $14,568 $1,334 $0 $3,975 $19,877 $43

SUBTOTAL 4. $263,206 $10,292 $63,047 $0 $0 $336,544 $31,175 $41,465 $57,487 $466,672 $1,013

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

267

Exhibit 3-81 Case S2B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-15

Project: Low Rank Western Coal Baseline Study

Case: Case S2B - TRIG IGCC w/ CO2

Plant Size: 460.9 MW,net Estimate Type: Conceptual Cost Base (June) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $62,625 $0 $53,138 $0 $0 $115,763 $11,196 $23,153 $30,022 $180,134 $391

5A.2 Elemental Sulfur Plant $5,058 $1,008 $6,526 $0 $0 $12,592 $1,223 $0 $2,763 $16,578 $36

5A.3 Mercury Removal $1,167 $0 $888 $0 $0 $2,054 $198 $103 $471 $2,827 $6

5A.4 Shift Reactors $6,301 $0 $2,536 $0 $0 $8,837 $847 $0 $1,937 $11,621 $25

5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

5A.5 Blowback Gas Systems $1,684 $283 $160 $0 $0 $2,127 $202 $0 $466 $2,795 $6

5A.6 Fuel Gas Piping $0 $686 $480 $0 $0 $1,166 $108 $0 $255 $1,529 $3

5A.9 HGCU Foundations $0 $695 $448 $0 $0 $1,142 $105 $0 $374 $1,622 $4

SUBTOTAL 5A. $76,834 $2,672 $64,176 $0 $0 $143,682 $13,879 $23,255 $36,288 $217,105 $471

 5B CO2 COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $16,750 $0 $9,707 $0 $0 $26,457 $2,547 $0 $5,801 $34,805 $76

SUBTOTAL 5B. $16,750 $0 $9,707 $0 $0 $26,457 $2,547 $0 $5,801 $34,805 $76

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,610 $9,348 $9,861 $11,782 $129,600 $281

6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5

SUBTOTAL 6. $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $286

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $31,608 $0 $4,494 $0 $0 $36,103 $3,433 $0 $3,954 $43,489 $94

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,758 $1,254 $0 $0 $3,012 $264 $0 $655 $3,932 $9

7.4 Stack $3,430 $0 $1,288 $0 $0 $4,718 $452 $0 $517 $5,687 $12

7.9 HRSG,Duct & Stack Foundations $0 $687 $660 $0 $0 $1,347 $125 $0 $442 $1,914 $4

SUBTOTAL 7. $35,038 $2,445 $7,697 $0 $0 $45,181 $4,274 $0 $5,568 $55,023 $119

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $22,780 $0 $3,777 $0 $0 $26,557 $2,548 $0 $2,911 $32,016 $69

8.2 Turbine Plant Auxiliaries $157 $0 $359 $0 $0 $515 $50 $0 $57 $622 $1

8.3a Condenser & Auxiliaries $2,301 $0 $735 $0 $0 $3,036 $290 $0 $333 $3,659 $8

8.3b Air Cooled Condenser $21,086 $0 $4,227 $0 $0 $25,314 $2,531 $0 $5,569 $33,414 $73

8.4 Steam Piping $4,802 $0 $3,378 $0 $0 $8,181 $703 $0 $2,221 $11,104 $24

8.9 TG Foundations $0 $776 $1,312 $0 $0 $2,088 $198 $0 $686 $2,972 $6

SUBTOTAL 8. $51,126 $776 $13,789 $0 $0 $65,691 $6,321 $0 $11,776 $83,788 $182

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $4,007 $0 $729 $0 $0 $4,736 $451 $0 $778 $5,964 $13

9.2 Circulating Water Pumps $1,035 $0 $58 $0 $0 $1,093 $92 $0 $178 $1,363 $3

9.3 Circ.Water System Auxiliaries $94 $0 $13 $0 $0 $108 $10 $0 $18 $136 $0

9.4 Circ.Water Piping $0 $3,930 $1,019 $0 $0 $4,949 $447 $0 $1,079 $6,475 $14

9.5 Make-up Water System $260 $0 $372 $0 $0 $632 $61 $0 $139 $832 $2

9.6 Component Cooling Water Sys $464 $555 $395 $0 $0 $1,414 $132 $0 $309 $1,855 $4

9.9 Circ.Water System Foundations $0 $1,447 $2,460 $0 $0 $3,907 $370 $0 $1,283 $5,561 $12

SUBTOTAL 9. $5,860 $5,932 $5,047 $0 $0 $16,839 $1,564 $0 $3,784 $22,187 $48

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

268

Exhibit 3-81 Case S2B Total Plant Cost Summary Details (Continued) Client: USDOE/NETL Report Date: 2009-Oct-15

Project: Low Rank Western Coal Baseline Study

Case: Case S2B - TRIG IGCC w/ CO2

Plant Size: 460.9 MW,net Estimate Type: Conceptual Cost Base (June) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $17,590 $0 $8,674 $0 $0 $26,264 $2,524 $0 $2,879 $31,667 $69

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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

10.4 High Temperature Ash Piping $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

10.6 Ash Storage Silos $587 $0 $638 $0 $0 $1,225 $119 $0 $202 $1,545 $3

10.7 Ash Transport & Feed Equipment $787 $0 $190 $0 $0 $977 $91 $0 $160 $1,228 $3

10.8 Misc. Ash Handling Equipment $1,215 $1,489 $445 $0 $0 $3,149 $300 $0 $517 $3,966 $9

10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $0 $117 $11 $0 $38 $166 $0

SUBTOTAL 10. $20,179 $1,541 $10,013 $0 $0 $31,732 $3,044 $0 $3,796 $38,573 $84

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $859 $0 $850 $0 $0 $1,709 $163 $0 $187 $2,060 $4

11.2 Station Service Equipment $4,297 $0 $387 $0 $0 $4,684 $432 $0 $512 $5,628 $12

11.3 Switchgear & Motor Control $7,944 $0 $1,445 $0 $0 $9,388 $871 $0 $1,539 $11,798 $26

11.4 Conduit & Cable Tray $0 $3,690 $12,174 $0 $0 $15,864 $1,534 $0 $4,350 $21,748 $47

11.5 Wire & Cable $0 $7,051 $4,633 $0 $0 $11,683 $849 $0 $3,133 $15,665 $34

11.6 Protective Equipment $0 $624 $2,269 $0 $0 $2,893 $283 $0 $476 $3,652 $8

11.7 Standby Equipment $216 $0 $211 $0 $0 $426 $41 $0 $70 $537 $1

11.8 Main Power Transformers $15,639 $0 $128 $0 $0 $15,767 $1,192 $0 $2,544 $19,503 $42

11.9 Electrical Foundations $0 $139 $365 $0 $0 $504 $48 $0 $166 $718 $2

SUBTOTAL 11. $28,954 $11,504 $22,461 $0 $0 $62,920 $5,413 $0 $12,976 $81,309 $176

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,059 $0 $707 $0 $0 $1,767 $167 $88 $303 $2,326 $5

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $243 $0 $156 $0 $0 $400 $38 $20 $91 $549 $1

12.7 Computer & Accessories $5,652 $0 $181 $0 $0 $5,832 $535 $292 $666 $7,325 $16

12.8 Instrument Wiring & Tubing $0 $1,974 $4,036 $0 $0 $6,010 $510 $301 $1,705 $8,526 $19

12.9 Other I & C Equipment $3,778 $0 $1,834 $0 $0 $5,612 $528 $281 $963 $7,384 $16

SUBTOTAL 12. $10,732 $1,974 $6,915 $0 $0 $19,621 $1,778 $981 $3,729 $26,110 $57

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $101 $2,159 $0 $0 $2,260 $224 $0 $745 $3,230 $7

13.2 Site Improvements $0 $1,797 $2,388 $0 $0 $4,185 $413 $0 $1,379 $5,977 $13

13.3 Site Facilities $3,220 $0 $3,398 $0 $0 $6,618 $652 $0 $2,181 $9,451 $21

SUBTOTAL 13. $3,220 $1,898 $7,945 $0 $0 $13,063 $1,290 $0 $4,306 $18,659 $40

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1

14.2 Steam Turbine Building $0 $1,984 $2,826 $0 $0 $4,810 $443 $0 $788 $6,040 $13

14.3 Administration Building $0 $835 $606 $0 $0 $1,441 $128 $0 $235 $1,804 $4

14.4 Circulation Water Pumphouse $0 $157 $83 $0 $0 $240 $21 $0 $39 $300 $1

14.5 Water Treatment Buildings $0 $374 $365 $0 $0 $739 $67 $0 $121 $926 $2

14.6 Machine Shop $0 $427 $292 $0 $0 $720 $64 $0 $118 $901 $2

14.7 Warehouse $0 $690 $445 $0 $0 $1,135 $101 $0 $185 $1,421 $3

14.8 Other Buildings & Structures $0 $413 $322 $0 $0 $735 $66 $0 $160 $961 $2

14.9 Waste Treating Building & Str. $0 $924 $1,765 $0 $0 $2,689 $251 $0 $588 $3,528 $8

SUBTOTAL 14. $0 $6,068 $6,854 $0 $0 $12,922 $1,176 $0 $2,324 $16,423 $36

TOTAL COST $705,833 $62,309 $258,448 $0 $0 $1,026,590 $95,414 $75,563 $193,851 $1,391,417 $3,019

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

269

Exhibit 3-82 Case S2B Owner’s Costs

Owner's Costs $x1000 $/kW

Preproduction Costs

6 Months Fixed O&M $11,155 $24

1 Month Variable O&M $2,962 $6

25% of 1 Months Fuel Cost at 100% CF $802 $2

2% of TPC $27,828 $60

Total $42,748 $93

Inventory Capital

60 day supply of consumables at 100% CF $6,787 $15

0.5% of TPC (spare parts) $6,957 $15

Total $13,745 $30

 Initial Cost for Catalyst and Chemicals $6,042 $13

Land $900 $2

Other Owner's Costs $208,713 $453

Financing Costs $37,568 $82

Total Owner's Costs $309,715 $672

Total Overnight Cost (TOC) $1,701,132 $3,691

TASC Multiplier 1.140

Total As-Spent Cost (TASC) $1,939,291 $4,208
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

270

Exhibit 3-83 Case S2B Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (June): 2007

Case S2B - TRIG IGCC w/ CO2 Heat Rate-net (Btu/kWh): 10740

MWe-net: 461

Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 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-O.J.'s 16.0 16.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $6,313,507 $13.700

Maintenance Labor Cost $11,535,125 $25.030

Administrative & Support Labor $4,462,158 $9.682

Property Taxes and Insurance $27,828,342 $60.385

TOTAL FIXED OPERATING COSTS $50,139,132 $108.797

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $23,182,469 $0.00718

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

Water (/1000 gallons) 0 2,152 1.08 $0 $679,733 $0.00021

Chemicals

MU & WT Chem. (lb) 0 12,821 0.17 $0 $647,944 $0.00020

Carbon (Mercury Removal) (lb) 89,518 123 1.05 $94,009 $37,604 $0.00001

COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000

Water Gas Shift Catalyst (ft3) 5,053 3.46 498.83 $2,520,820 $504,164 $0.00016

Selexol Solution (gal) 255,792 81 13.40 $3,427,162 $318,336 $0.00010

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip. 0.76 131.27 $0 $29,076 $0.00001

 Subtotal Chemicals $6,041,991 $1,537,124 $0.00048

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 123 0.42 $0 $14,934 $0.00000

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 637 16.23 $0 $3,019,289 $0.00093

 Subtotal Waste Disposal $0 $3,034,224 $0.00094

By-products & Emissions 

 Sulfur (tons) 0 50 0.00 $0 $0 $0.00000

 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $6,041,991 $28,433,550 $0.00880

Fuel (ton) 0 6,935 15.22 $0 $30,815,893 $0.00954
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

271

3.4 SIEMENS FUEL GASIFIER IGCC CASES

This section contains an evaluation of plant designs for Cases S3A, S3B, L3A, and L3B, which 

are based on the SFG. The non-capture (A) and CO2 capture (B) cases are very similar in terms 

of process, equipment, scope and arrangement, except that CO2 capture cases includes SGS

reactors, CO2 absorption/regeneration and compression/transport systems. 

Section 3.4.4 covers the results for the S3A and L3A non-capture case using PRB and Lignite 

coal and Section 3.4.8 covers the S3B and L3B CO2-capture cases. The sections are organized 

analogously as follows:

• Process and System Description provides an overview of the specific technology’s

operation.

• BFD and stream table display results for major processes and streams.

• Performance Results provides the main modeling results, including the performance 

summary, environmental performance, carbon balance, sulfur balance, water balance, 

mass and energy balance diagrams, and mass and energy balance tables.

• Equipment List provides an itemized list of major equipment with account codes that 

correspond to the cost accounts in the Cost Estimates section.

• Cost Estimates provides a summary of capital and operating costs.

Process and System Description, Performance Results, Equipment List and Cost Estimates are 

repeated for the CO2 capture cases in Section 3.4.8. If the information is identical to that 

presented for the non-capture cases, a reference is made to the earlier section rather than 

repeating the information.

3.4.1 Gasifier Background

Development and Current Status – The SFG process for IGCC applications is based on the 

Noell process, also known under the name GSP, developed by Deutsches Brennstoffinstitut 

Freiberg in 1975 for the gasification of German domestic brown coal and other solid fuels. The 

Noell Group acquired the technology in 1991 and did further development to gasify waste 

materials and liquid residues. The gasifier was marketed under the Future Energy GmbH 

company and was sold to Siemens in 2006. The first gasifier of this type was a 200 megawatt 

thermal (MWth) thermal unit built at Schwarze Pumpe, Germany in 1984, firing high sodium 

lignite. It was converted to process natural gas and waste liquids in 1990. Other installations 

include a 5 MWth test plant in Freiberg, Germany where alternative feed testing is ongoing and a 

175 MWth autothermal oil conversion plant in the Czech Republic, commissioned in 2008. 

Current gasifier projects include the Shanxi Lanhua Coal 1,000 MWth coal to ammonia plant, 

which is in its engineering phase, and the Shenhua Ningxia Coal Based Polypropylene Project 

with capacity of 2,500 MWth of coal to polypropylene production, due to enter commercial 

operation in mid 2011. Siemens SFG-500 Gasifiers are also planned for the Secure Energy, Coal 

to SNG project in IL slated to be commissioned in 2013.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

272

In this study, three parallel Siemens dry feed, pressurized, down flow, entrained, slagging 

gasifiers are used to power two advanced F-class turbines. The Siemens gasifiers have a 

‘cooling screen’ (heat exchanger tubes) on the inside surface of the gasifier, which eliminates the 

need for refractory inside the gasifier. This cooling screen also raises a small amount of LP

steam that is used inside the gasification island to heat the O2 before entering the gasifier. A full 

quench in the bottom of the gasifier helps remove the slag and also cools the syngas for further 

downstream cleanup and heat recovery.

Gasifier Capacity – At the outset of this study, the largest 

commercial offering from Siemens was a nominal 500 MW 

thermal input gasifier. The largest current commercial offering 

is a nominal 1,200 MW thermal input gasifier. Based on 

vendor input and assuming a 500 MW thermal gasifier, less 

than 3 gasifiers are required to run the plant at full capacity 

except the lignite CCS case, which requires 3.2 gasifiers due to 

the low quality coal and high auxiliary requirements. For 

consistency and comparability, all the cases were costed as 

three gasifiers, while accounting for the differences in gas flow.

Distinguishing Characteristics – The Siemens gasifier is a dry 

feed, entrained flow, slagging, single stage, down-flow gasifier 

producing syngas at high pressures and temperatures. The 

gasifier uses a cooling screen design to control the reactor 

vessel wall temperature. The gasifier temperature is controlled 

above the slag fluid temperature to assure the creation of a protective slag layer on the inside of 

the cooling screen while LP steam is generated in the cooling screen. This approach helps 

minimize the risk of slag attack that occurs with refractory lining and helps improves the lifetime 

and maintenance, as well as start-up and shutdown times. The more complex dry feeding system 

helps achieve high conversion rates, lower oxygen consumption and higher efficiencies 

compared to slurry fed systems.

The gasifier unit also contains a built in quench section below the reaction section where both the 

hot raw syngas and liquid slag are discharged and the raw gas is cooled and saturated by 

injection of water. Molten slag is cooled and granulated in a water bath at the bottom of the 

quench vessel. This mode of operation helps improve the reliability of the gasifier by 

simplifying the raw gas quench and slag removal steps, at the expense of adding moisture to the 

syngas. The high temperature in the gasifier ensures that no tars or other hydrocarbon liquids are 

formed, and the quench section helps reduce the syngas exit temperature. This built in quench 

can be a competitive alternative to high temperature syngas cooling, especially for CO2 capture 

and chemical synthesis applications where H2 and CO2 is preferable to CO production, as it uses 

the sensible heat of the syngas to directly raise steam for the WGS reaction, avoiding extracting 

steam from the steam cycle and the cost of the necessary heat exchangers. 

Important Coal Characteristics – The Siemens gasifier is generally able to fire most types of 

coal, petcoke, or mixed feeds. The gasifier temperature can be controlled to use a wide range of 

feeds, which Siemens can characterize at their test facility, in order to develop specific operating 

parameters for each fuel and ash type.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

273

3.4.2 Key System Assumptions

System assumptions for Cases S3A and L3A and S3B and L3B, SFG IGCC using PRB and 

lignite coal with and without CO2 capture, are compiled in Exhibit 3-84.

Exhibit 3-84 Case S3A/L3A and S3B/L3B Plant Study Configuration Matrix

Case S3A / L3A S3B / L3B

Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O2:Coal Ratio, kg O2/kg dry coal 0.758 / 0.720 0.767 / 0.719

Carbon Conversion, % 99.5 99.5

Syngas HHV at Gasifier Outlet, 

kJ/Nm3 (Btu/scf) 4,824 (130) / 4,437 (119) 4,834 (130) / 4,651 (125)

Nominal Steam Cycle, MPa/°C/°C 

(psig/°F/°F)

12.4/566/566 

(1800/1050/1050)

12.4/538/538 

(1800/1000/1000)

Condenser Pressure, mm Hg

(in Hg) 36 (1.4) 36 (1.4)

Combustion Turbine

2x Advanced F Class 

(Nominal 232 MW output 

each, reduced by elevation 

considerations)

2x Advanced F Class 

(Nominal 232 MW output 

each, reduced by elevation 

considerations)

Gasifier Technology Siemens (SFG) Siemens (SFG)

Oxidant 95 vol% Oxygen 95 vol% Oxygen

Coal Subbituminous / Lignite Subbituminous / Lignite

Coal Feed Moisture Content, % 6 / 12 6 / 12

COS Hydrolysis Yes Yes (Part of WGS)

Water Gas Shift No Yes

H2S Separation Sulfinol-M Selexol (1st Stage)

Sulfur Removal, % 99.8 99.7

CO2 Separation None Selexol (2nd Stage)

CO2 Removal, % N/A 90

Sulfur Recovery

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Particulate Control Cyclone, Scrubber, and 

AGR Absorber

Cyclone, Scrubber, and 

AGR Absorber

Mercury Control Carbon Bed Carbon Bed

NOx Control MNQC (LNB) and N2

Dilution 

MNQC (LNB) and N2

Dilution
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

274

Balance of Plant – All Cases

The balance of plant assumptions are common to all cases and are presented in Exhibit 3-85.

Exhibit 3-85 Balance of Plant Assumptions

Cooling water system Recirculating Wet Cooling Tower

Fuel and Other storage

Coal 30 days

Slag 30 days

Sulfur 30 days

Sorbent 30 days

Plant Distribution Voltage

Motors below 1 hp 110/220 volt

Motors between 1 hp and 

250 hp 480 volt

Motors between 250 hp and 

5,000 hp 4,160 volt

Motors above 5,000 hp 13,800 volt

Steam and CT Generators 24,000 volt

Grid Interconnection Voltage 345 kV

Water and Waste Water

Makeup Water

The water supply is 50 percent from a local POTW 

and 50 percent from groundwater, and is assumed to 

be in sufficient quantities to meet plant makeup 

requirements.

Makeup for potable, process, and DI water is drawn 

from municipal sources

Process Wastewater

Water associated with gasification activity and storm 

water that contacts equipment surfaces is collected 

and treated for discharge through a permitted 

discharge.

Sanitary Waste Disposal

Design includes a packaged domestic sewage 

treatment plant with effluent discharged to the 

industrial wastewater treatment system. Sludge is 

hauled off site. Packaged plant was sized for 5.68 

m3/d (1,500 GPD)

Water Discharge

Most of the process wastewater is recycled to the 

cooling tower basin. Blowdown is treated for 

chloride and metals, and discharged.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

275

3.4.3 Sparing Philosophy

The sparing philosophy is provided below. Single trains are utilized throughout with exceptions 

where equipment capacity requires an additional train. There is no redundancy other than 

normal sparing of rotating equipment.

The plant design consists of the following major subsystems:

• Two ASUs (2 x 50%).

• Two trains of coal drying and dry feed systems (2 x 50%).

• Three trains of gasification, including gasifier, SGC, cyclone, and barrier filter (3 x 33%). 

• Two trains of syngas clean-up process (2 x 50%).

• Two trains of Sulfinol-M acid gas removal in non-capture cases and two trains of twostage Selexol in CO2 capture cases (2 x 50%).

• One train of Claus-based sulfur recovery (1 x 100%).

• Two CT/HRSG tandems (2 x 50%).

• One steam turbine (1 x 100%).

3.4.4 SFG IGCC Non-Capture Case (S3A and L3A) Process Description

In this section the overall SFG process for Case S3A and L3A is described. The process does 

not change with fuel type so a single description is provided. The system description follows the 

BFD in Exhibit 3-86 and stream numbers reference the same exhibit. The tables in Exhibit 3-87

and Exhibit 3-88 provide process data for the numbered streams in the BFD.

Coal Preparation and Feed Systems

Coal receiving and handling is common to all cases and was covered in Section 3.1.1. The 

receiving and handling subsystem ends at the coal silo. The SFG uses a dry feed system, which 

is sensitive to the coal moisture content. Coal moisture consists of two parts, surface moisture 

and inherent moisture. For coal to flow smoothly through the lock hoppers, the surface moisture 

must be removed. The PRB coal used in this study contains 25.77 percent total moisture on an 

as-received basis and the NDL contains 36.08 percent moisture. It was assumed that the PRB 

coal must be dried to 6 percent moisture and the lignite to 12 percent to allow for smooth flow 

through the dry feed system.

The raw coal is crushed in the coal mill then delivered to a surge hopper with an approximate 2-

hour capacity, which in turn delivers the coal to the coal pre-heater. The WTA coal drying 

process includes a water-heated, horizontal, rotary-kiln coal pre-heater, a fluidized bed coal dryer 

and a water-cooled, horizontal, rotary-kiln coal cooler. The moisture driven from the coal in the 

fluid bed dryer passes through a baghouse for particulate removal and then is split into two 

streams. The smaller of the two streams is compressed and used as the fluidizing medium in the 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

276

coal dryer. The bulk of the removed moisture is compressed and the high temperature vapor 

passes through internal coils in the dryer to provide the heat to drive off the coal moisture and 

then exits the dryer as liquid water. The warm water is used in the coal pre-heater before being 

used as cooling tower makeup water. The vapor compressor consumes the vast majority of the 

WTA process auxiliary load.

The coal is drawn from the surge hoppers and fed through a pressurization lock hopper system to 

a dense phase pneumatic conveyor, which uses nitrogen from the ASU to convey the coal to the 

gasifiers.

Gasifier

There are three Siemens dry feed, pressurized, down-flow, entrained, slagging gasifiers, 

operating at 4.24 MPa (615 psia) and processing a total of 5,782 tonne/day (6,373 tpd) of asreceived coal in the PRB case and 8,098 tonne/day (8,927 tpd) in the lignite case. Coal reacts 

with oxygen in a reducing environment to produce principally hydrogen and carbon monoxide 

with little CO2 formed. The hot raw syngas and the liquid slag flow down into the quench 

chamber of the gasifier and the raw gas is cooled and saturated by injecting water. The slag is 

cooled and granulated in a water bath at the bottom of the quench vessel.

Syngas Scrubber/Particulate Removal

A raw gas venturi scrubber system thoroughly mixes the raw syngas with water to ensure wetting 

of fine ash and soot particles. Cyclones are used to separate the water and particulates from the 

raw gas. Syngas scrubbers are employed and use gas condensate from the downstream gas 

cooling processes. The fine particulates are removed in a partial condenser, which continues 

cooling the gas, downstream of the scrubber unit. The particulates act as condensation cores and 

are caught by the condensed droplets in the partial condenser and are recycled to the gasifier 

quench chamber.

Sour Water Stripper

The sour water stripper removes ammonia, sulfur, and other impurities from the waste stream of 

the scrubber. The sour gas stripper consists of a sour drum that accumulates sour water from 

various plant sources. Sour water from the drum flows to the sour stripper, which consists of a 

packed column with a steam-heated reboiler. Sour gas is stripped from the liquid and sent to the 

SRU. Remaining water is sent to wastewater treatment.

COS Hydrolysis, Mercury Removal and AGR

H2S and COS are at significant concentrations, requiring removal for the power plant to achieve 

the low design level of SO2 emissions. H2S is removed in an AGR process; however, because 

COS is not readily removed, it is first catalytically converted to H2S in a COS hydrolysis unit.

The cooled raw gas is fed to the COS hydrolysis reactor where the COS in the sour gas is 

hydrolyzed with steam, over a catalyst bed, into H2S, which is more easily removed by the AGR 

solvent. Before the raw fuel gas can be treated in the AGR process, it must be cooled to about 

35°C (95°F). During this cooling through a series of heat exchangers, part of the water vapor 

condenses. This water, which contains some NH3, is sent to the sour water stripper. The cooled 

syngas then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.8).
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

277

The Sulfinol process, developed by Shell in the early 1960s, is a combination process that uses a 

mixture of amines and a physical solvent. The solvent consists of an aqueous amine and 

sulfolane. Sulfinol-D uses DIPA, while Sulfinol-M uses MDEA. The mixed solvents allow for 

better solvent loadings at high acid gas partial pressures and higher solubility of COS and 

organic sulfur compounds than straight aqueous amines. Sulfinol-M was selected for the 

Siemens non-CO2 capture applications. 

The sour syngas is fed directly into an HP contactor. The HP contactor is an absorption column 

in which the H2S, COS, CO2, and small amounts of H2 and CO are removed from the gas by the 

Sulfinol solvent. The overhead gas stream from the HP contactor is then washed with water in 

the sweet gas scrubber before leaving the unit as the feed gas to the sulfur polishing unit.

The rich solvent from the bottom of the HP contactor flows through a hydraulic turbine and is 

flashed in the rich solvent flash vessel. The flashed gas is then scrubbed in the LP contactor with 

lean solvent to remove H2S and COS. The overhead from the LP contactor is flashed in the LP 

KO drum. This gas can be used as a utility fuel gas, consisting primarily of H2 and CO, at 

0.8 MPa (118 psia) and 38°C (101°F). The solvent from the bottom of the LP contactor is 

returned to the rich solvent flash vessel.

Hot, lean solvent in the lean/rich solvent exchanger then heats the flashed rich solvent before 

entering the stripper. The stripper strips the H2S, COS, and CO2 from the solvent at low pressure 

with heat supplied through the stripper reboiler. The acid gas stream to sulfur recovery/tail gas 

cleanup is recovered as the flash gas from the stripper accumulator. The lean solvent from the 

bottom of the stripper is cooled in the lean/rich solvent exchanger and the lean solvent cooler. 

Most of the lean solvent is pumped to the HP contactor. A small amount goes to the LP 

contactor.

The Sulfinol process removes about 15 percent of the CO2 along with the H2S and COS. The 

acid gas is fed to the SRU. The residual CO2 passes through the SRU, the hydrogenation reactor 

and is recycled to the gasifier. However, the costs of the sulfur recovery/tail gas cleanup are 

higher than for a sulfur removal process producing an acid gas stream with a higher sulfur 

concentration.

Claus Unit

The SRU is a Claus bypass type SRU utilizing oxygen instead of air. The Claus plant produces 

molten sulfur by converting approximately one third of the H2S in the feed to SO2, then reacting 

the H2S and SO2 to sulfur and water. The combination of Claus technology and tail gas recycle 

results in an overall sulfur recovery exceeding 99 percent, producing 42 tonne/day (46 tpd) of 

sulfur in the PRB case and 51 tonne/day (56 tpd) in the lignite case. 

Utilizing oxygen instead of air in the Claus plant reduces the overall cost of the sulfur recovery 

plant. Feed for each case consists of acid gas from both the acid gas cleanup unit and a vent 

stream from the sour water stripper in the gasifier section.

In the furnace waste heat boiler steam is generated. This steam is used to satisfy all Claus 

process preheating and reheating requirements, as well as to provide some steam to the medium-
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

278

pressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) steam for the LP

steam header. 

Power Block

Clean syngas exiting the Sulfinol absorber is reheated, diluted with nitrogen from the ASU, and 

enters the advanced F Class CT burner. The CT compressor provides combustion air to the 

burner and also a portion of the air requirement for the ASU. The exhaust gas exits the CT 

around 566°C (1,050°F) and enters the HRSG where additional heat is recovered until the flue 

gas exits the HRSG at 132°C (270°F) and is discharged through the plant stack. The steam 

raised in the HRSG is used to power an advanced, commercially available steam turbine using a 

nominal 12.4 MPa/566°C/566°C (1800 psig/1050°F/1050°F) steam cycle.

Air Separation Unit

The ASU is designed to produce approximately 3,468 tonne/day (3,823 tpd) in the PRB case and 

3,979 tonne/day (4,386 tpd) in the lignite case of 95 mole percent O2 for use in the gasifier and 

SRU. The plant is designed with two production trains. The air compressor is powered by an 

electric motor. Nitrogen is also recovered, compressed, and used as dilution in the CT

combustor or as a coal transport fluid. Air extraction is taken from the CT compressor to reduce 

the size of the main air compressor.

Balance of Plant

Balance of plant items were covered in Sections 3.1.12, 3.1.13, 3.1.14, and 3.1.15.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

279

Exhibit 3-86 Case S3A and L3A Process Flow Diagram
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

280

Exhibit 3-87 Case S3A Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

V-L Mole Fraction

Ar 0.0093 0.0093 0.0291 0.0318 0.0023 0.0023 0.0360 0.0000 0.0000 0.0000 0.0000 0.0000 0.0046 0.0000 0.0046

CH4 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 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2649 0.0000 0.2649

CO2 0.0003 0.0003 0.0102 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0230 0.0000 0.0231

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 0.0001 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 0.1332 0.0000 0.1332

H2O 0.0064 0.0064 0.1937 0.0000 0.0002 0.0002 0.0000 1.0000 0.0000 1.0000 0.0000 0.0000 0.5443 0.9998 0.5442

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0014 0.0000 0.0016

N2 0.7759 0.7759 0.5163 0.0178 0.9920 0.9920 0.0140 0.0000 0.0000 0.0000 0.0000 0.0000 0.0278 0.0000 0.0278

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0007 0.0002 0.0007

O2 0.2081 0.2081 0.2507 0.9504 0.0054 0.0054 0.9500 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 18,872 2,907 699 35 14,895 1,695 4,449 1,162 0 2,813 0 0 34,856 17,564 34,856

V-L Flowrate (kg/hr) 545,309 83,991 19,275 1,134 417,964 47,561 143,382 20,927 0 50,668 0 0 680,934 316,426 680,934

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 240,911 0 190,243 20,328 0 0 0

Temperature (°C) 6 411 21 32 196 125 32 343 6 33 71 260 214 175 214

Pressure (MPa, abs) 0.09 1.43 0.11 0.86 2.65 5.62 0.86 5.10 0.09 0.55 0.09 4.17 4.10 8.27 4.03

Enthalpy (kJ/kg)A 15.26 434.33 40.10 26.67 202.63 123.73 26.59 3,062.93 --- 140.13 --- --- 1,567.59 699.71 1,567.49

Density (kg/m3) 1.1 7.2 1.6 11.0 18.9 47.0 11.0 20.1 --- 985.3 --- --- 20.9 833.2 20.5

V-L Molecular Weight 28.895 28.895 27.587 32.181 28.061 28.061 32.229 18.015 --- 18.015 --- --- 19.536 18.015 19.536

V-L Flowrate (lbmol/hr) 41,606 6,408 1,540 78 32,838 3,737 9,808 2,561 0 6,201 0 0 76,844 38,722 76,844

V-L Flowrate (lb/hr) 1,202,201 185,168 42,494 2,500 921,453 104,854 316,103 46,136 0 111,704 0 0 1,501,202 697,601 1,501,202

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 531,119 0 419,414 44,815 0 0 0

Temperature (°F) 42 771 70 90 385 257 90 650 42 92 160 500 418 347 417

Pressure (psia) 13.0 207.6 16.4 125.0 385.0 815.0 125.0 740.0 13.0 80.1 12.7 604.7 594.7 1,200.0 584.7

Enthalpy (Btu/lb)A 6.6 186.7 17.2 11.5 87.1 53.2 11.4 1,316.8 --- 60.2 --- --- 673.9 300.8 673.9

Density (lb/ft3) 0.070 0.452 0.097 0.687 1.183 2.937 0.688 1.257 --- 61.510 --- --- 1.304 52.017 1.282

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

281

Exhibit 3-87 Case S3A Stream Table (Continued)

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

V-L Mole Fraction

Ar 0.0101 0.0057 0.0101 0.0006 0.0000 0.0041 0.0102 0.0102 0.0093 0.0091 0.0091 0.0000 0.0000 0.0000 0.0000

CH4 0.0001 0.0000 0.0001 0.0000 0.0000 0.0000 0.0001 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.5812 0.0026 0.5715 0.0213 0.0000 0.0457 0.5814 0.5814 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0506 0.5462 0.0592 0.5013 0.0000 0.3467 0.0512 0.0512 0.0003 0.0814 0.0814 0.0000 0.0000 0.0000 0.0000

COS 0.0000 0.0002 0.0000 0.0000 0.0000 0.0003 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.2922 0.0996 0.2890 0.0118 0.0000 0.0274 0.2940 0.2940 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0015 0.0324 0.0016 0.0089 0.0000 0.3519 0.0014 0.0014 0.0064 0.0431 0.0431 1.0000 1.0000 1.0000 1.0000

H2S 0.0034 0.0916 0.0049 0.2762 0.0000 0.0654 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0609 0.2217 0.0637 0.1799 0.0000 0.1585 0.0616 0.0616 0.7759 0.7540 0.7540 0.0000 0.0000 0.0000 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2081 0.1125 0.1125 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 0.0000 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) 15,882 278 16,153 286 0 389 15,793 15,793 102,359 123,228 123,228 21,819 18,972 18,972 39,649

V-L Flowrate (kg/hr) 339,066 9,598 348,526 10,670 0 11,596 336,292 336,292 2,957,681 3,627,946 3,627,946 393,078 341,794 341,794 714,297

Solids Flowrate (kg/hr) 0 0 0 0 1,748 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 35 49 35 51 181 138 51 196 6 587 134 559 32 32 33

Pressure (MPa, abs) 3.93 0.32 3.86 0.4 0.370 0.370 3.597 3.563 0.090 0.093 0.090 12.512 0.005 0.005 0.827

Enthalpy (kJ/kg)A 42.64 88.47 41.65 55.0 --- 689.453 66.652 275.179 15.260 698.571 202.573 3,496.917 2,248.547 2,248.547 140.297

Density (kg/m3) 32.7 4.2 32.6 5.8 --- 3.3 28.3 19.2 1.1 0.4 0.8 35.2 0.04 0.04 995.0

V-L Molecular Weight 21.349 34.468 21.577 37 --- 29.783 21.293 21.293 28.895 29.441 29.441 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 35,014 614 35,610 630 0 858 34,818 34,818 225,664 271,670 271,670 48,103 41,827 41,827 87,412

V-L Flowrate (lb/hr) 747,513 21,161 768,368 23,524 0 25,566 741,397 741,397 6,520,570 7,998,253 7,998,253 866,588 753,527 753,527 1,574,754

Solids Flowrate (lb/hr) 0 0 0 0 3,855 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 95 120 94 124 358 280 124 385 42 1,088 272 1,038 90 90 92

Pressure (psia) 569.7 46.5 559.7 60.0 53.6 53.6 521.7 516.7 13.0 13.5 13.0 1,814.7 0.7 0.7 120.0

Enthalpy (Btu/lb)A 18.3 38.0 17.9 23.7 --- 296.4 28.7 118.3 6.6 300.3 87.1 1,503.4 966.7 966.7 60.3

Density (lb/ft3) 2.042 0.260 2.032 0.363 --- 0.203 1.767 1.199 0.070 0.024 0.049 2.200 0.002 0.002 62.116
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

282

Exhibit 3-88 Case L3A Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

V-L Mole Fraction

Ar 0.0093 0.0093 0.0293 0.0318 0.0023 0.0023 0.0360 0.0000 0.0000 0.0000 0.0000 0.0000 0.0046 0.0000 0.0046

CH4 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 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2484 0.0000 0.2484

CO2 0.0003 0.0003 0.0103 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0268 0.0000 0.0269

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 0.0001 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 0.1176 0.0000 0.1176

H2O 0.0062 0.0062 0.1878 0.0000 0.0002 0.0002 0.0000 0.0000 0.0000 1.0000 0.0000 0.0000 0.5677 1.0000 0.5675

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0015 0.0000 0.0016

N2 0.7761 0.7761 0.5200 0.0178 0.9920 0.9920 0.0140 0.0000 0.0000 0.0000 0.0000 0.0000 0.0328 0.0000 0.0328

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0005

O2 0.2082 0.2082 0.2525 0.9504 0.0054 0.0054 0.9500 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 21,582 3,397 796 44 16,673 2,358 5,100 0 0 5,125 0 0 40,317 20,979 40,317

V-L Flowrate (kg/hr) 623,675 98,158 22,008 1,406 467,870 66,177 164,371 0 0 92,335 0 0 797,136 377,958 797,136

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 337,436 0 245,101 33,948 0 0 0

Temperature (°C) 4 408 21 32 196 125 32 --- 4 32 71 260 217 175 216

Pressure (MPa, abs) 0.10 1.52 0.11 0.86 2.65 5.62 0.86 --- 0.10 0.34 0.09 4.17 4.10 8.27 4.03

Enthalpy (kJ/kg)A 13.75 431.19 40.37 26.67 202.62 123.72 26.59 --- --- 135.07 --- --- 1,604.74 700.03 1,604.63

Density (kg/m3

) 1.2 7.7 1.5 11.0 18.9 47.0 11.0 --- --- 986.5 --- --- 21.1 833.3 20.8

V-L Molecular Weight 28.898 28.898 27.657 32.181 28.061 28.061 32.229 --- --- 18.015 --- --- 19.771 18.016 19.771

V-L Flowrate (lbmol/hr) 47,581 7,489 1,754 96 36,759 5,199 11,244 0 0 11,299 0 0 88,885 46,252 88,885

V-L Flowrate (lb/hr) 1,374,968 216,401 48,519 3,100 1,031,478 145,896 362,377 0 0 203,563 0 0 1,757,383 833,254 1,757,383

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 743,918 0 540,355 74,843 0 0 0

Temperature (°F) 40 767 70 90 385 257 90 --- 40 90 160 500 422 347 421

Pressure (psia) 13.8 220.4 16.4 125.0 385.0 815.0 125.0 --- 13.8 50.0 13.5 604.7 594.7 1,200.0 584.7

Enthalpy (Btu/lb)A 5.9 185.4 17.4 11.5 87.1 53.2 11.4 --- --- 58.1 --- --- 689.9 301.0 689.9

Density (lb/ft3) 0.074 0.482 0.097 0.687 1.183 2.937 0.688 --- --- 61.584 --- --- 1.320 52.024 1.298

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

283

Exhibit 3-88 Case L3A Stream Table (Continued)

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

V-L Mole Fraction

Ar 0.0106 0.0062 0.0105 0.0005 0.0000 0.0041 0.0107 0.0107 0.0093 0.0091 0.0091 0.0000 0.0000 0.0000 0.0000

CH4 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 0.0000

CO 0.5744 0.0014 0.5645 0.0193 0.0000 0.0365 0.5753 0.5753 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0621 0.6432 0.0725 0.5621 0.0000 0.3896 0.0628 0.0628 0.0003 0.0852 0.0852 0.0000 0.0000 0.0000 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 0.0000 0.0000 0.0000

H2 0.2718 0.0587 0.2681 0.0100 0.0000 0.0179 0.2732 0.2732 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0015 0.0324 0.0016 0.0080 0.0000 0.3813 0.0014 0.0014 0.0062 0.0415 0.0415 1.0000 1.0000 1.0000 1.0000

H2S 0.0037 0.0095 0.0038 0.1960 0.0000 0.0012 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0758 0.2486 0.0790 0.2041 0.0000 0.1644 0.0765 0.0765 0.7761 0.7544 0.7544 0.0000 0.0000 0.0000 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2082 0.1098 0.1098 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0048 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 0.0000 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) 17,434 317 17,741 343 0 479 17,326 17,326 106,961 130,213 130,213 23,023 21,431 21,431 43,503

V-L Flowrate (kg/hr) 384,801 11,581 396,212 12,995 0 14,462 381,626 381,626 3,090,914 3,842,252 3,842,252 414,769 386,093 386,093 783,714

Solids Flowrate (kg/hr) 0 0 0 0 2,111 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 35 49 35 51 174 138 51 196 4 588 132 560 32 32 33

Pressure (MPa, abs) 3.89 0.32 3.82 0.4 0.370 0.370 3.597 3.563 0.095 0.099 0.095 12.512 0.005 0.005 0.827

Enthalpy (kJ/kg)A 40.72 83.74 39.48 53.4 --- 724.869 63.973 266.790 13.748 697.002 197.901 3,500.312 2,248.933 2,248.933 139.912

Density (kg/m3) 33.6 4.4 33.5 5.9 --- 3.3 29.3 19.9 1.2 0.4 0.8 35.2 0.04 0.04 995.0

V-L Molecular Weight 22.072 36.583 22.333 38 --- 30.205 22.027 22.027 28.898 29.508 29.508 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 38,435 698 39,113 757 0 1,056 38,197 38,197 235,808 287,070 287,070 50,757 47,248 47,248 95,907

V-L Flowrate (lb/hr) 848,340 25,533 873,497 28,650 0 31,884 841,341 841,341 6,814,298 8,470,716 8,470,716 914,408 851,189 851,189 1,727,793

Solids Flowrate (lb/hr) 0 0 0 0 4,654 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 95 120 94 124 345 280 124 385 40 1,091 269 1,041 90 90 92

Pressure (psia) 564.7 46.5 554.7 60.0 53.6 53.6 521.7 516.7 13.8 14.3 13.8 1,814.7 0.7 0.7 120.0

Enthalpy (Btu/lb)A 17.5 36.0 17.0 23.0 --- 311.6 27.5 114.7 5.9 299.7 85.1 1,504.9 966.9 966.9 60.2

Density (lb/ft3) 2.097 0.276 2.090 0.368 --- 0.206 1.831 1.240 0.074 0.025 0.052 2.195 0.002 0.002 62.118
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

284

3.4.5 Case S3A and L3A Performance Results

The non-capture SFG IGCC plant using PRB coal at the Montana site (elevation 3,400 ft) 

produces a net output of 505 MWe at a net plant efficiency of 37.9 percent (HHV basis). The 

same plant configuration using lignite coal at the NDL site (elevation 1,900 ft) produces a net 

output of 543 MWe at a net plant efficiency of 37.6 percent (HHV basis). 

Overall performance for the plant is summarized in Exhibit 3-89, which includes auxiliary power 

requirements. The ASU accounts for approximately 74 percent of the total auxiliary load, 

distributed between the main air compressor, the oxygen compressor, the nitrogen compressor, 

and ASU auxiliaries. The coal handling and drying account for approximately 10 percent of the

auxiliary load. The cooling water system, including the CWPs and cooling tower fan, and the 

air-cooled condenser account for about 6 percent of the auxiliary load. All other individual 

auxiliary loads are less than 3 percent of the total.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

285

Exhibit 3-89 Case S3A and L3A Plant Performance Summary

POWER SUMMARY (Gross Power at Generator 

Terminals, kWe) S3A L3A

Gas Turbine Power 415,100 446,500

Steam Turbine Power 207,100 232,300

TOTAL POWER, kWe 622,200 678,800

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 490 590

Coal Milling 2,480 3,470

Slag Handling 530 880

WTA Coal Dryer Compressor 8,490 11,860

WTA Coal Dryer Auxiliaries 560 780

Air Separation Unit Auxiliaries 1,000 1,000

Air Separation Unit Main Air Compressor 48,560 54,120

Oxygen Compressor 7,850 9,000

Nitrogen Compressors 29,220 33,820

Boiler Feedwater Pumps 2,490 2,710

Condensate Pump 230 260

Circulating Water Pump 2,320 2,480

Ground Water Pumps 200 200

Cooling Tower Fans 1,510 1,520

Air Cooled Condenser Fans 3,240 3,450

Quench / Scrubber Pumps 640 1,490

Acid Gas Removal 380 420

Gas Turbine Auxiliaries 1,000 1,000

Steam Turbine Auxiliaries 100 100

Claus Plant/TGTU Auxiliaries 250 250

Claus Plant TG Recycle Compressor 730 850

Miscellaneous Balance of Plant1 3,000 3,000

Transformer Losses 2,210 2,430

TOTAL AUXILIARIES, kWe 117,480 135,680

NET POWER, kWe 504,720 543,120

Net Plant Efficiency, % (HHV) 37.9% 37.6%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,508 (9,012) 9,562 (9,063)

CONDENSER COOLING DUTY GJ/hr (106 Btu/hr) 1,445 (1,370) 1,635 (1,550)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 240,911 (531,119) 337,436 (743,918)

Thermal Input, kWt 1,333,034 1,442,644

Raw Water Withdrawal, m3/min (gpm) 8.6 (2,259) 8.3 (2,190)

Raw Water Consumption, m3/min (gpm) 6.5 (1,711) 6.1 (1,601)

1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

286

Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in 

Section 2.3. A summary of the plant air emissions for the non-capture cases is presented in

Exhibit 3-90.

Exhibit 3-90 Cases S3A and L3A Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

80% capacity factor

kg/MWh

(lb/MWh)

S3A L3A S3A L3A S3A L3A

SO2

0.002 

(0.004)

0.001 

(0.002) 57 (63) 34 (37) 0.013 (0.029)

0.007 

(0.016)

NOX

0.026 

(0.061)

0.026 

(0.061) 878 (968) 960 (1,058) 0.201 (0.444)

0.202 

(0.445)

Particulates 0.003 

(0.0071)

0.003 

(0.0071) 103 (113) 111 (122) 0.024 (0.052)

0.023 

(0.051)

Hg 1.51E-7 

(3.51E-7)

2.41E-7 

(5.60E-7)

0.005 

(0.006)

0.009 

(0.010)

1.16E-6 

(2.57E-6)

1.84E-6 

(4.06E-6)

CO2 gross

91.9 

(213.8)

94.0 

(218.6)

3,091,870 

(3,408,203)

3,420,559 

(3,770,521)

709 

(1,563)

719 

(1,585)

CO2 net 874 

(1,927)

899 

(1,981)

The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the Sulfinol-M 

AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel 

gas down to a level of less than 5 ppmv in both cases. This results in a concentration in the flue 

gas of less than 1 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus 

plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated and recycled 

upstream of the AGR to capture most of the remaining sulfur. Because the environmental target 

was set based on higher sulfur bituminous coal, the resulting SO2 emissions with lower sulfur 

western coals are substantially less than the environmental target.

NOx emissions are limited to 15 ppmvd (as NO2 @ 15 percent O2) by the use of low NOx 

burners and nitrogen dilution of the fuel gas. Ammonia in the syngas is removed with process 

condensate prior to the low-temperature AGR process and destroyed in the Claus plant burner. 

This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a venturi

scrubber and cyclone in addition to 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.

CO2 emissions represent the uncontrolled discharge from the process.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

287

The carbon balance for the two cases is shown in Exhibit 3-91. The carbon input to the plant 

consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected 

here since the Aspen model accounts for air components throughout. Carbon leaves the plant as 

unburned carbon in the slag and as CO2 in the stack gas and ASU vent gas. Carbon that is not 

accounted for is shown as convergence tolerance.

Exhibit 3-91 Case S3A and L3A Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

S3A L3A S3A L3A

Coal 120,620 

(265,921)

133,468 

(294,247) Slag 603 (1,330) 667 (1,471)

Air (CO2) 477 (1,053) 506 (1,116) Stack Gas 120,408 

(265,455)

133,209 

(293,675)

ASU Vent 86 (189) 98 (217)

Total 121,097 

(266,974)

133,975 

(295,363) Total 121,097 (266,974)

133,975 

(295,363)

Exhibit 3-92 shows the sulfur balance for the non-capture case. Sulfur input comes solely from 

the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur 

emitted in the stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 3-92 Cases S3A and L3A Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

S3A L3A S3A L3A

Coal 1,753 (3,864) 2,114 (4,660) Elemental Sulfur 1,748 (3,855) 2,112 (4,655)

Stack Gas 4 (9) 2 (5)

Total 1,753 (3,864) 2,114 (4,660) Total 1,753 (3,864) 2,114 (4,660)

Exhibit 3-93 shows the overall water balance for the plant. 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, primarily as coal moisture from the drying process and syngas condensate, and that 

water is re-used as internal recycle. Raw water withdrawal is the difference between water 

demand and internal recycle. Some water is discharged from the process to a permitted outfall. 

The difference between the withdrawal and discharge is the consumption.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

288

Exhibit 3-93 Case S3A and L3A Water Balance

Water Use

Water Demand

m3/min (gpm)

Internal Recycle m3/min 

(gpm)

Raw Water Withdrawal

m3/min (gpm)

Process Water 

Discharge m3/min (gpm)

Raw Water Consumption 

m3/min (gpm)

S3A L3A S3A L3A S3A L3A S3A L3A S3A L3A

Slag Handling 0.44 (116) 0.74 (194) 0.44 (116) 0.74 (194) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0)

Quench / Scrubber 5.28 (1395) 6.31 (1667) 4.72 (1248) 5.49 (1451) 0.56 (147) 0.82 (216) 0 (0) 0 (0) 0.56 (147) 0.82 (216)

SWS Blowdown 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0.05 (14) 0.06 (16) -0.05 (-14) -0.06 (-16)

Condenser Makeup 0.51 (135) 0.19 (51) 0 (0) 0 (0) 0.51 (135) 0.19 (51) 0 (0) 0 (0) 0.51 (135) 0.19 (51)

 Gasifier Steam 0.35 (92) 0.35 (92)

 BFW Makeup 0.16 (43) 0.19 (51) 0.16 (43) 0.19 (51)

Cooling Tower 9.01 

(2,380)

9.64 

(2,546) 1.53 (403) 2.36 (622) 7.49 (1,977)

7.28 

(1,923) 2.03 (535) 2.17 (573) 5.46 (1442) 5.11 (1,351)

 Water from Coal Drying 0.85 (223) 1.54 (407) -0.85 

(-223)

-1.54 

(-407)

 BFW Blowdown 0.16 (43) 0.19 (51) -0.16 (-43) -0.19 (-51)

 SWS Blowdown 0.52 (136) 0.62 (165) -0.52 

(-136)

-0.62 

(-165)

Total 15.2 

(4,027)

16.9 

(4,458) 6.7 (1,767) 8.6 (2,267) 8.6 (2,259) 8.3 (2,190) 2.1 (549) 2.2 (589) 6.5 (1,711) 6.1 (1,601)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

289

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-94 and 

Exhibit 3-95:

• Coal gasification and ASU

• Syngas cleanup

• Combined cycle power generation

An overall plant energy balance is provided in tabular form in Exhibit 3-96 for the two cases. 

The power out is the combined CT and steam turbine power after generator losses.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

290

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Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

291

Exhibit 3-94 Case S3A Heat and Mass Balance
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

292

Exhibit 3-94 Case S3A Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

293

Exhibit 3-94 Case S3A Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

294

Exhibit 3-95 Case L3A Heat and Mass Balance
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

295

Exhibit 3-95 Case L3A Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

296

Exhibit 3-95 Case L3A Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

297

Exhibit 3-96 Cases S3A and L3A Energy Balance

HHV Sensible + Latent Power Total

S3A L3A S3A L3A S3A L3A S3A L3A

Heat In GJ/hr (MMBtu/hr)

Coal 4,799 

(4,549)

5,194 

(4,923) 2.5 (2.3) 3.0 (2.8) 0 (0) 0 (0) 4,801 (4,551)

5,197 

(4,925)

ASU Air 0 (0) 0 (0) 8.3 (7.9) 8.6 (8.1) 0 (0) 0 (0) 8 (8) 9 (8)

GT Air 0 (0) 0 (0) 45.1 (42.8) 42.5 (40.3) 0 (0) 0 (0) 45 (43) 42 (40)

Raw Water Makeup 0 (0) 0 (0) 11.9 (11.3) 9.2 (8.7) 0 (0) 0 (0) 12 (11) 9 (9)

Auxiliary Power 0 (0) 0 (0) 0 (0) 0 (0) 423 (401) 488 (463) 423 (401) 488 (463)

Totals 4,799 

(4,549)

5,194 

(4,923) 67.8 (64.3) 63.3 (60.0) 423 (401) 488 (463) 5,290 (5,014)

5,745 

(5,445)

Heat Out GJ/hr (MMBtu/hr)

ASU Intercoolers 0 (0) 0 (0) 178 (169) 199 (189) 0 (0) 0 (0) 178 (169) 199 (189)

ASU Vent 0 (0) 0 (0) 0.8 (0.7) 0.9 (0.8) 0 (0) 0 (0) 1 (1) 1 (1)

Slag 20 (19) 22 (21) 4.4 (4.2) 7.4 (7.0) 0 (0) 0 (0) 24 (23) 29 (28)

Sulfur 16 (15) 20 (19) 0.2 (0.2) 0.2 (0.2) 0 (0) 0 (0) 16 (16) 20 (19)

Cooling Tower 

Blowdown 0 (0) 0 (0) 11.3 (10.7) 11.7 (11.1) 0 (0) 0 (0) 11 (11) 12 (11)

HRSG Flue Gas 0 (0) 0 (0) 735 (697) 760 (721) 0 (0) 0 (0) 735 (697) 760 (721)

Condenser 0 (0) 0 (0) 1,442 

(1,367)

1,631 

(1,546) 0 (0) 0 (0) 1,443 (1,368)

1,631 

(1,546)

Auxiliary Cooling Load 0 (0) 0 (0) 197 (187) 158 (150) 0 (0) 0 (0) 197 (187) 158 (150)

Electrical Generator 

Loss 0 (0) 0 (0) 0 (0) 0 (0) 34 (32) 37 (35) 34 (32) 37 (35)

Process Losses 0 (0) 0 (0) 411 (390) 454 (430) 411 (390) 454 (430)

Power 0 (0) 0 (0) 0 (0) 0 (0) 2,240 

(2,123)

2,444 

(2,316)

2,240 

(2,123)

2,444 

(2,316)

Totals 36 (34) 41 (39) 2,980 

(2,824)

3,223 

(3,055)

2,274 

(2,155)

2,481 

(2,351)

5,290 

(5,014)

5,745 

(5,445)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

298

3.4.6 Case S3A and L3A Equipment Lists

Major equipment items for the SFG with no CO2 capture are shown in the following tables. The 

accounts used in the equipment list correspond to the account numbers used in the cost estimates 

in Section 3.4.7. In general, the design conditions include a 10 percent contingency for flows 

and heat duties and a 21 percent contingency for heads on pumps and fans.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

299

ACCOUNT 1 COAL HANDLING

Equipment 

No. Description Type S3A Design Conditions L3A Design Condition Operating Qty 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 54 tonne (60 ton) 73 tonne (80 ton) 2 1

9 Feeder Vibratory 200 tonne/hr (220 tph) 281 tonne/hr (310 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 399 tonne/hr (440 tph) 553 tonne/hr (610 tph) 1 0

11 Crusher Tower N/A N/A N/A 1 0

12 Coal Surge Bin w/ Vent 

Filter Dual outlet 200 tonne (220 ton) 281 tonne (310 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 399 tonne/hr (440 tph) 553 tonne/hr (610 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 399 tonne/hr (440 tph) 553 tonne/hr (610 tph) 1 0

18 Coal Silo w/ Vent Filter 

and Slide Gates Field erected 907 tonne (1,000 ton) 1,270 tonne (1,400 ton) 3 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

300

ACCOUNT 2 COAL PREPARATION AND FEED 

Equipment 

No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1 Feeder Vibratory 91 tonne/hr (100 tph) 127 tonne/hr (140 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 263 tonne/hr (290 tph) 372 tonne/hr (410 tph) 1 0

3 Roller Mill 

Feed Hopper Dual Outlet 526 tonne (580 ton) 744 tonne (820 ton) 1 0

4 Weigh Feeder Belt 136 tonne/hr (150 tph) 181 tonne/hr (200 tph) 2 0

5 Pulverizer Rotary 136 tonne/hr (150 tph) 181 tonne/hr (200 tph) 2 0

6 Coal Dryer 

Feed Hopper Vertical Hopper 263 tonne (290 ton) 372 tonne (410 ton) 2 0

7 Coal Preheater

Water Heated 

Horizontal Rotary 

Kiln

Coal feed: 263 tonne/hr (290 

tph)

Heat duty: 29.5 GJ/hr (28.0 

MMBtu/hr)

Coal feed: 372 tonne/hr (410 

tph)

Heat duty: 45.8 GJ/hr (43.4 

MMBtu/hr)

1 0

8 Coal Dryer Fluidized Bed with 

Internal Coils

Coal feed: 136 tonne/hr (150 

tph)

Heat duty: 74.2 GJ/hr (70.3 

MMBtu/hr)

Bed diameter: 11.9 m (39 ft)

Coal feed: 181 tonne/hr (200 

tph)

Heat duty: 133.0 GJ/hr 

(126.1 MMBtu/hr)

Bed diameter: 14.0 m (46 ft)

2 0

9 Steam 

Compressor

Reciprocating, MultiStage

555 m3/min (19,610 scfm)

Suction - 0.09 MPa (13 psia)

Discharge - 0.72 MPa (105 

psia)

1012 m3/min (35,730 scfm)

Suction - 0.10 MPa (13.8

psia)

Discharge - 0.52 MPa (75 

psia)

2 0

10 Dryer Exhaust 

Filter Hot Baghouse

Steam - 27,851 kg/hr 

(61,400 lb/hr)

Temperature - 107°C 

(225°F)

Steam - 50,802 kg/hr 

(112,000 lb/hr)

Temperature - 107°C 

(225°F)

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

301

Equipment 

No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

11 Dry Coal 

Cooler

Water Cooled 

Horizontal Rotary 

Kiln

209 tonne/hr (231 tph)

Heat duty - 12 GJ/hr 

(11 MMBtu/hr)

270 tonne/hr (297 tph)

Heat duty - 17 GJ/hr 

(16 MMBtu/hr)

1 0

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment 

No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1

Demineralized 

Water Storage 

Tank

Vertical, cylindrical, 

outdoor

635,949 liters 

(168,000 gal)

749,512 liters 

(198,000 gal) 2 0

2 Condensate Pumps Vertical canned

6,587 lpm @ 91 m H2O

(1,740 gpm @ 300 ft 

H2O)

7,230 lpm @ 91 m H2O

(1,910 gpm @ 300 ft 

H2O)

2 1

3 Deaerator (integral 

w/ HRSG) Horizontal spray type 469,015 kg/hr (1,034,000 lb/hr)

511,652 kg/hr 

(1,128,000 lb/hr) 2 0

4

Intermediate 

Pressure 

Feedwater Pump

Horizontal 

centrifugal, single

stage

4,240 lpm @ 27 m H2O

(1,120 gpm @ 90 ft H2O)

4,732 lpm @ 27 m H2O

(1,250 gpm @ 90 ft H2O) 2 1

5

High Pressure 

Feedwater Pump 

No. 1

Barrel type, multistage, centrifugal

HP water: 3,823 lpm @ 

1,890 m H2O (1,010 gpm 

@ 6,200 ft H2O)

HP water: 4,050 lpm @ 

1,890 m H2O (1,070 gpm 

@ 6,200 ft H2O)

2 1

6

High Pressure 

Feedwater Pump 

No. 2

Barrel type, multistage, centrifugal

IP water: 1,098 lpm @ 

223 m H2O (290 gpm @ 

730 ft H2O)

IP water: 2,006 lpm @ 

223 m H2O (530 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
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

302

Equipment 

No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

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 Cycle

Cooling Heat 

Exchangers

Plate and frame 221 GJ/hr 

(209 MMBtu/hr) each

211 GJ/hr 

(200 MMBtu/hr) each 2 0

11

Closed Cycle 

Cooling Water 

Pumps

Horizontal 

centrifugal

79,115 lpm @ 21 m H2O

(20,900 gpm @ 70 ft 

H2O)

75,708 lpm @ 21 m H2O

(20,000 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)

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

2,385 lpm @ 18 m H2O

(630 gpm @ 60 ft H2O)

2,347 lpm @ 18 m H2O

(620 gpm @ 60 ft H2O) 2 1

15 Ground Water 

Pumps

Stainless steel, single 

suction

2,385 lpm @ 268 m H2O 

(630 gpm @ 880 ft H2O)

2,347 lpm @ 268 m H2O 

(620 gpm @ 880 ft H2O) 2 1

16 Filtered Water 

Pumps

Stainless steel, single 

suction

3,520 lpm @ 49 m H2O

(930 gpm @ 160 ft H2O)

4,088 lpm @ 49 m H2O

(1,080 gpm @ 160 ft 

H2O)

2 1

17 Filtered Water 

Tank Vertical, cylindrical 1,684,508 liter (445,000 gal)

1,957,058 liter (517,000 

gal) 2 0

18 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 189 lpm (50 gpm) 189 lpm (50 gpm) 2 0

19 Liquid Waste 

Treatment System 10 years, 24-hour storm 10 years, 24-hour storm 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

303

ACCOUNT 4 GASIFIER, ASU,AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY 

Equipment 

No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1 Gasifier Pressurized dryfeed, entrained bed

2,087 tonne/day, 4.2 MPa

(2,300 tpd, 605 psia)

2,994 tonne/day, 4.2 MPa

(3,300 tpd, 605 psia) 3 0

2 Synthesis Gas 

Cyclone High efficiency

247,661 kg/hr 

(546,000 lb/hr) 

Design efficiency 90%

288,938 kg/hr 

(637,000 lb/hr) 

Design efficiency 90%

3 0

3

Syngas Scrubber 

Including Sour 

Water Stripper

Vertical up flow 247,661 kg/hr 

(546,000 lb/hr)

288,938 kg/hr 

(637,000 lb/hr) 3 0

4 Raw Gas Coolers Shell and tube with 

condensate drain

224,982 kg/hr 

(496,000 lb/hr)

244,033 kg/hr 

(538,000 lb/hr) 8 0

5 Raw Gas 

Knockout Drum

Vertical with mist 

eliminator

185,973 kg/hr, 51°C, 

3.6 MPa

(410,000 lb/hr, 124°F, 

522 psia)

211,828 kg/hr, 35°C, 

3.8 MPa

(467,000 lb/hr, 95°F, 

555 psia)

2 0

6 Synthesis Gas 

Reheater Shell and tube 185,066 kg/hr (408,000 lb/hr)

210,013 kg/hr 

(463,000 lb/hr) 2 0

7 Flare Stack

Self-supporting, 

carbon steel, 

stainless steel top, 

pilot ignition

371,946 kg/hr 

(820,000 lb/hr) syngas

433,634 kg/hr 

(956,000 lb/hr) syngas 2 0

8 ASU Main Air 

Compressor

Centrifugal, multistage

4,106 m3

/min @ 1.3 MPa

(145,000 scfm 

@ 190 psia)

4,701 m3/min @ 1.3 MPa

(166,000 scfm 

@ 190 psia)

2 0

9 Cold Box Vendor design

1,905 tonne/day 

(2,100 tpd) of 

95% purity oxygen

2,177 tonne/day 

(2,400 tpd) of 

95% purity oxygen

2 2
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

304

Equipment 

No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

10 Oxygen 

Compressor

Centrifugal, multistage

963 m3

/min (34,000 scfm)

Suction - 0.9 MPa 

(130 psia)

Discharge - 5.1 MPa 

(740 psia)

1,104 m3

/min 

(39,000 scfm)

Suction - 0.9 MPa 

(130 psia)

Discharge - 5.1 MPa 

(740 psia)

2 0

11 Primary Nitrogen 

Compressor

Centrifugal, multistage

3,171 m3/min 

(112,000 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)

2 0

12

Secondary 

Nitrogen 

Compressor

Centrifugal, singlestage

453 m3

/min (16,000 scfm)

Suction - 2.7 MPa 

(390 psia)

Discharge - 5.7 MPa 

(820 psia)

510 m3/min (18,000 scfm)

Suction - 2.7 MPa 

(390 psia)

Discharge - 5.7 MPa 

(820 psia)

2 0

13 Extraction Air 

Heat Exchanger

Gas-to-gas, vendor 

design

46,266 kg/hr, 411°C, 

1.4 MPa

(102,000 lb/hr, 771°F, 

208 psia)

53,978 kg/hr, 408°C, 

1.5 MPa

(119,000 lb/hr, 767°F, 

220 psia)

2 0

14

Transport 

Nitrogen Boost 

Compressor

Centrifugal, multistage

368 m3

/min (13,000 scfm)

Suction - 2.7 MPa 

(389 psia)

Discharge - 5.6 MPa 

(815 psia)

513 m3/min (18,100 scfm)

Suction - 2.7 MPa 

(389 psia)

Discharge - 5.6 MPa 

(815 psia)

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

305

ACCOUNT 5 SYNGAS CLEANUP

Equipment 

No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1 Mercury Adsorber Sulfated carbon 

bed

186,426 kg/hr 

(411,000 lb/hr) 

35°C (95°F) 

3.9 MPa (570 psia)

211,828 kg/hr 

(467,000 lb/hr) 

35°C (95°F) 

3.9 MPa (565 psia)

2 0

2 Sulfur Plant Claus type 46 tonne/day (51 tpd) 56 tonne/day (61 tpd) 1 0

3 COS Hydrolysis 

Reactor

Fixed bed, 

catalytic

374,667 kg/hr 

(826,000 lb/hr)

216°C (420°F)

4.1 MPa (590 psia)

438,624 kg/hr 

(967,000 lb/hr)

216°C (420°F)

4.1 MPa (590 psia)

2 0

4 Acid Gas Removal 

Plant Sulfinol

191,870 kg/hr 

(423,000 lb/hr)

35°C (94°F)

3.9 MPa (560 psia)

217,724 kg/hr 

(480,000 lb/hr)

35°C (94°F)

3.8 MPa (555 psia)

2 0

5 Hydrogenation 

Reactor

Fixed bed, 

catalytic

11,596 kg/hr 

(25,566 lb/hr)

232°C (450°F)

0.3 MPa (48.6 psia)

14,462 kg/hr 

(31,884 lb/hr)

232°C (450°F)

0.3 MPa (48.6 psia)

1 0

6 Tail Gas Recycle 

Compressor Centrifugal 9,551 kg/hr(21,056 lb/hr)

11,411 kg/hr 

(25,157 lb/hr) 1 0

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment 

No. Description Type S3A Design Condition L3A Design Condition Operating Qty Spares

1 Gas Turbine Advanced F 

class 210 MW 225 MW 2 0

2 Gas Turbine 

Generator TEWAC 230 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase

250 MVA @ 0.9 p.f., 

24 kV, 60 Hz, 3-phase 2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

306

ACCOUNT 7 HRSG, DUCTING AND STACK

Equipment 

No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1 Stack CS plate, type 

409SS liner

76 m (250 ft) high x

8.6 m (20 ft) diameter

76 m (250 ft) high x

8.6 m (20 ft) diameter 2 0

2

Heat Recovery 

Steam 

Generator

Drum, multipressure with 

economizer 

section and 

integral deaerator

Main steam - 216,193 

kg/hr, 12.4 MPa/559°C 

(476,623 lb/hr, 1,800 

psig/1,038°F)

Reheat steam - 199,389 

kg/hr, 3.1 MPa/559°C 

(439,577 lb/hr, 452 

psig/1,038°F)

Main steam - 228,123 

kg/hr, 12.4 MPa/560°C 

(502,924 lb/hr, 1,800 

psig/1,041°F)

Reheat steam - 221,125 

kg/hr, 3.1 MPa/560°C 

(487,498 lb/hr, 452 

psig/1,041°F)

2 0

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1 Steam Turbine Commercially 

available

218 MW

12.4 MPa/559°C/559°C 

(1,800 psig/ 

1,038°F/1,038°F)

244 MW

12.4 MPa/560°C/560°C 

(1,800 psig/ 

1,041°F/1,041°F)

1 0

2 Steam Turbine 

Generator

Hydrogen cooled, 

static excitation

240 MVA @ 0.9 p.f., 

24 kV, 60 Hz, 3-phase

270 MVA @ 0.9 p.f., 

24 kV, 60 Hz, 3-phase 1 0

3 Surface 

Condenser

Single pass, 

divided waterbox 

including vacuum 

pumps

791 GJ/hr (750 MMBtu/hr), 

Condensing temperature 

32°C (90°F), Inlet water 

temperature 9°C (48°F), 

Water temperature rise 

11°C (20°F)

897 GJ/hr (850 MMBtu/hr), 

Condensing temperature 

32°C (90°F), Inlet water 

temperature 8°C (47°F), 

Water temperature rise 

11°C (20°F)

1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

307

Equipment 

No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

4 Air-cooled 

Condenser ---

791 GJ/hr (750 MMBtu/hr), 

Condensing temperature 

32°C (90°F), Ambient 

temperature 6°C (42°F)

897 GJ/hr (850 MMBtu/hr), 

Condensing temperature 

32°C (90°F), Ambient 

temperature 4°C (40°F)

1 0

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1 Circulating 

Water Pumps Vertical, wet pit 230,910 lpm @ 30 m(61,000 gpm @ 100 ft)

249,837 lpm @ 30 m

(66,000 gpm @ 100 ft) 2 1

2 Cooling 

Tower

Evaporative, 

mechanical 

draft, multi-cell

3°C (37°F) WB / 9°C (48°F) 

CWT / 20°C (68°F) HWT / 

1,298 GJ/hr (1,230 

MMBtu/hr) heat duty

2°C (36°F) WB / 8°C (47°F) 

CWT / 19°C (67°F) HWT / 

1,382 GJ/hr (1,310 

MMBtu/hr) heat duty

1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

308

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1 Slag Quench Tank Water bath 143,846 liters (38,000 gal) 238,481 liters (63,000 gal) 3 0

2 Slag Crusher Roll 7 tonne/hr (8 tph) 13 tonne/hr (14 tph) 3 0

3 Slag Depressurizer Proprietary 7 tonne/hr (8 tph) 13 tonne/hr (14 tph) 3 0

4 Slag Receiving 

Tank

Horizontal, 

weir 87,064 liters (23,000 gal) 143,846 liters (38,000 gal) 3 0

5 Black Water 

Overflow Tank

Shop 

fabricated 37,854 liters (10,000 gal) 64,352 liters (17,000 gal) 3

6 Slag Conveyor Drag chain 7 tonne/hr (8 tph) 13 tonne/hr (14 tph) 3 0

7 Slag Separation 

Screen Vibrating 7 tonne/hr (8 tph) 13 tonne/hr (14 tph) 3 0

8 Coarse Slag 

Conveyor Belt/bucket 7 tonne/hr (8 tph) 13 tonne/hr (14 tph) 3 0

9 Fine Ash Settling 

Tank

Vertical, 

gravity 121,133 liters (32,000 gal) 204,412 liters (54,000 gal) 3 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) 3 2

11 Grey Water Storage 

Tank Field erected 37,854 liters (10,000 gal) 64,352 liters (17,000 gal) 3 0

12 Grey Water Pumps Centrifugal 151 lpm @ 424 m H2O

(40 gpm @ 1,390 ft H2O)

227 lpm @ 424 m H2O

(60 gpm @ 1,390 ft H2O) 3 3

13 Slag Storage Bin Vertical, field 

erected 544 tonne (600 tons) 907 tonne (1,000 tons) 3 0

14 Unloading 

Equipment

Telescoping 

chute 91 tonne/hr (100 tph) 154 tonne/hr (170 tph) 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

309

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type S3A Design Conditions

L3A Design 

Condition

Operating 

Qty Spares

1 CTG Step-up 

Transformer Oil-filled 24 kV/345 kV, 230 MVA, 3-ph, 60 Hz

24 kV/345 kV, 

250 MVA, 3-ph, 60 Hz 2 0

2 STG Step-up 

Transformer Oil-filled 24 kV/345 kV, 240 MVA, 3-ph, 60 Hz

24 kV/345 kV, 

270 MVA, 3-ph, 60 Hz 1 0

3

High Voltage 

Auxiliary 

Transformer

Oil-filled 345 kV/13.8 kV, 

52 MVA, 3-ph, 60 Hz

345 kV/13.8 kV, 

60 MVA, 3-ph, 60 Hz 2 0

4

Medium Voltage 

Auxiliary 

Transformer

Oil-filled 24 kV/4.16 kV, 

24 MVA, 3-ph, 60 Hz

24 kV/4.16 kV, 

27 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, selfcooled 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 2 0

7

STG Isolated Phase 

Bus Duct and Tap 

Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 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
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

310

ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment 

No. Description Type S3A Design Conditions

L3A Design 

Condition

Operating 

Qty Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator printer (laser 

color); Engineering printer (laser B&W)

Operator stations/printers and 

engineering stations/printers 1 0

2 DCS -

Processor

Microprocessor with redundant 

input/output N/A 1 0

3 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

311

3.4.7 Case S3A and L3A Cost Estimating

Costs Results

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-97 shows 

the total capital cost summary organized by cost account for the PRB coal case (S3A) and 

Exhibit 3-101 shows the same information for the NDL coal case (L3A). A more detailed 

breakdown of the capital costs is shown in Exhibit 3-98 for S3A and Exhibit 3-102 for L3A.

Exhibit 3-99 and Exhibit 3-103 show the calculation and addition of owner’s costs to determine 

the TOC, used to calculate COE. Exhibit 3-100 shows the initial and annual O&M costs for 

Case S3A and Exhibit 3-104 shows the same information for Case L3A.

The estimated TOC of the SFG with no CO2 capture using PRB coal is $3,185/kW and using 

lignite coal is $3,239/kW. Process contingency represents 2 percent, project contingency 

represents 11 percent, and owner’s costs represent 18 percent of TOC in both cases. The COE is 

86.8 mills/kWh in the PRB case and 87.3 mills/kWh in the lignite case.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

312

Exhibit 3-97 Case S3A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S3A - Siemens 504 MW IGCC w/o CO2

Plant Size: 504.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING $15,069 $2,800 $11,686 $0 $0 $29,555 $2,683 $0 $6,447 $38,685 $77

 2 COAL & SORBENT PREP & FEED $113,213 $9,434 $19,316 $0 $0 $141,963 $12,316 $0 $30,856 $185,135 $367

 3 FEEDWATER & MISC. BOP SYSTEMS $6,625 $5,455 $6,288 $0 $0 $18,368 $1,730 $0 $4,587 $24,684 $49

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $112,359 $0 $52,484 $0 $0 $164,843 $14,646 $24,727 $30,632 $234,848 $465

4.2 Syngas Cooling (w/4.1) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $147,856 $0 w/equip. $0 $0 $147,856 $14,332 $0 $16,219 $178,406 $353

4.4-4.9 Other Gasification Equipment $27,422 $12,190 $17,132 $0 $0 $56,744 $5,433 $0 $13,350 $75,527 $150

SUBTOTAL 4 $287,637 $12,190 $69,616 $0 $0 $369,443 $34,410 $24,727 $60,201 $488,782 $968

 5A Gas Cleanup & Piping $44,796 $2,573 $43,329 $0 $0 $90,698 $8,770 $79 $20,056 $119,603 $237

 5B CO2 REMOVAL & COMPRESSION $0 $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 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $230

6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5

SUBTOTAL 6 $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $234

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,576 $0 $4,632 $0 $0 $37,208 $3,538 $0 $4,075 $44,820 $89

7.2-7.9 Ductwork and Stack $3,459 $2,466 $3,262 $0 $0 $9,187 $852 $0 $1,635 $11,674 $23

SUBTOTAL 7 $36,035 $2,466 $7,894 $0 $0 $46,394 $4,390 $0 $5,709 $56,494 $112

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $23,782 $0 $3,965 $0 $0 $27,747 $2,662 $0 $3,041 $33,450 $66

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $34,018 $811 $10,715 $0 $0 $45,544 $4,438 $0 $10,082 $60,065 $119

SUBTOTAL 8 $57,800 $811 $14,680 $0 $0 $73,292 $7,100 $0 $13,123 $93,515 $185

 9 COOLING WATER SYSTEM $6,387 $6,453 $5,413 $0 $0 $18,252 $1,695 $0 $4,097 $24,044 $48

10 ASH/SPENT SORBENT HANDLING SYS $20,248 $1,402 $10,041 $0 $0 $31,692 $3,041 $0 $3,763 $38,496 $76

11 ACCESSORY ELECTRIC PLANT $25,991 $10,114 $20,028 $0 $0 $56,133 $4,830 $0 $11,520 $72,483 $144

12 INSTRUMENTATION & CONTROL $9,586 $1,763 $6,176 $0 $0 $17,526 $1,588 $876 $3,331 $23,321 $46

13 IMPROVEMENTS TO SITE $3,069 $1,809 $7,572 $0 $0 $12,450 $1,229 $0 $4,104 $17,782 $35

14 BUILDINGS & STRUCTURES $0 $5,974 $6,769 $0 $0 $12,743 $1,160 $0 $2,286 $16,188 $32

 

TOTAL COST $712,207 $64,051 $235,970 $0 $0 $1,012,228 $93,824 $30,283 $181,172 $1,317,507 $2,610

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

313

Exhibit 3-98 Case S3A Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S3A - Siemens 504 MW IGCC w/o CO2

Plant Size: 504.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $3,957 $0 $1,934 $0 $0 $5,891 $528 $0 $1,284 $7,702 $15

1.2 Coal Stackout & Reclaim $5,114 $0 $1,240 $0 $0 $6,353 $557 $0 $1,382 $8,292 $16

1.3 Coal Conveyors & Yd Crush $4,754 $0 $1,227 $0 $0 $5,981 $525 $0 $1,301 $7,807 $15

1.4 Other Coal Handling $1,244 $0 $284 $0 $0 $1,528 $134 $0 $332 $1,994 $4

1.5 Sorbent Receive & Unload $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

1.7 Sorbent Conveyors $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

1.9 Coal & Sorbent Hnd.Foundations $0 $2,800 $7,002 $0 $0 $9,802 $939 $0 $2,148 $12,890 $26

SUBTOTAL 1. $15,069 $2,800 $11,686 $0 $0 $29,555 $2,683 $0 $6,447 $38,685 $77

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $45,578 $2,738 $6,641 $0 $0 $54,958 $4,742 $0 $11,940 $71,640 $142

2.2 Prepared Coal Storage & Feed $1,959 $469 $307 $0 $0 $2,736 $234 $0 $594 $3,564 $7

2.3 Dry Coal Injection System $64,488 $748 $5,989 $0 $0 $71,226 $6,135 $0 $15,472 $92,833 $184

2.4 Misc.Coal Prep & Feed $1,187 $864 $2,590 $0 $0 $4,641 $427 $0 $1,014 $6,081 $12

2.5 Sorbent Prep Equipment $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

2.7 Sorbent Injection System $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

2.9 Coal & Sorbent Feed Foundation $0 $4,614 $3,788 $0 $0 $8,403 $778 $0 $1,836 $11,017 $22

SUBTOTAL 2. $113,213 $9,434 $19,316 $0 $0 $141,963 $12,316 $0 $30,856 $185,135 $367

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,038 $3,501 $1,848 $0 $0 $7,387 $684 $0 $1,614 $9,686 $19

3.2 Water Makeup & Pretreating $367 $38 $205 $0 $0 $610 $58 $0 $200 $869 $2

3.3 Other Feedwater Subsystems $1,115 $377 $339 $0 $0 $1,831 $165 $0 $399 $2,395 $5

3.4 Service Water Systems $210 $432 $1,500 $0 $0 $2,142 $209 $0 $705 $3,056 $6

3.5 Other Boiler Plant Systems $1,126 $436 $1,082 $0 $0 $2,644 $251 $0 $579 $3,474 $7

3.6 FO Supply Sys & Nat Gas $286 $541 $504 $0 $0 $1,332 $128 $0 $292 $1,752 $3

3.7 Waste Treatment Equipment $513 $0 $313 $0 $0 $825 $80 $0 $272 $1,177 $2

3.8 Misc. Power Plant Equipment $969 $130 $497 $0 $0 $1,596 $154 $0 $525 $2,275 $5

SUBTOTAL 3. $6,625 $5,455 $6,288 $0 $0 $18,368 $1,730 $0 $4,587 $24,684 $49

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (Siemens $112,359 $0 $52,484 $0 $0 $164,843 $14,646 $24,727 $30,632 $234,848 $465

4.2 Syngas Cooling w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $147,856 $0 w/equip. $0 $0 $147,856 $14,332 $0 $16,219 $178,406 $353

4.4 LT Heat Recovery & FG Saturation $27,422 $0 $10,425 $0 $0 $37,847 $3,694 $0 $8,308 $49,849 $99

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,519 $618 $0 $0 $2,137 $205 $0 $468 $2,810 $6

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $10,671 $6,089 $0 $0 $16,761 $1,534 $0 $4,574 $22,869 $45

SUBTOTAL 4. $287,637 $12,190 $69,616 $0 $0 $369,443 $34,410 $24,727 $60,201 $488,782 $968

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

314

Exhibit 3-98 Case S3A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S3A - Siemens 504 MW IGCC w/o CO2

Plant Size: 504.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 5A GAS CLEANUP & PIPING

5A.1 Sulfinol System $34,319 $0 $29,120 $0 $0 $63,439 $6,135 $0 $13,915 $83,489 $165

5A.2 Elemental Sulfur Plant $4,779 $952 $6,166 $0 $0 $11,897 $1,156 $0 $2,611 $15,663 $31

5A.3 Mercury Removal $896 $0 $682 $0 $0 $1,577 $152 $79 $362 $2,170 $4

5A.4 COS Hydrolysis $4,802 $0 $6,271 $0 $0 $11,074 $1,077 $0 $2,430 $14,581 $29

5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.7 Fuel Gas Piping $0 $805 $564 $0 $0 $1,369 $127 $0 $299 $1,796 $4

5A.9 HGCU Foundations $0 $816 $526 $0 $0 $1,341 $123 $0 $439 $1,904 $4

SUBTOTAL 5A. $44,796 $2,573 $43,329 $0 $0 $90,698 $8,770 $79 $20,056 $119,603 $237

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5B. $0 $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 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $230

6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5

SUBTOTAL 6. $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $234

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,576 $0 $4,632 $0 $0 $37,208 $3,538 $0 $4,075 $44,820 $89

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,773 $1,297 $0 $0 $3,070 $270 $0 $668 $4,008 $8

7.4 Stack $3,459 $0 $1,299 $0 $0 $4,758 $456 $0 $521 $5,736 $11

7.9 HRSG,Duct & Stack Foundations $0 $693 $666 $0 $0 $1,359 $126 $0 $445 $1,930 $4

SUBTOTAL 7. $36,035 $2,466 $7,894 $0 $0 $46,394 $4,390 $0 $5,709 $56,494 $112

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $23,782 $0 $3,965 $0 $0 $27,747 $2,662 $0 $3,041 $33,450 $66

8.2 Turbine Plant Auxiliaries $164 $0 $375 $0 $0 $539 $53 $0 $59 $650 $1

8.3a Condenser & Auxiliaries $2,973 $0 $950 $0 $0 $3,923 $375 $0 $430 $4,728 $9

8.3b Air Cooled Condenser $27,249 $0 $5,463 $0 $0 $32,711 $3,271 $0 $7,197 $43,179 $86

8.4 Steam Piping $3,633 $0 $2,556 $0 $0 $6,188 $532 $0 $1,680 $8,400 $17

8.9 TG Foundations $0 $811 $1,372 $0 $0 $2,183 $207 $0 $717 $3,107 $6

SUBTOTAL 8. $57,800 $811 $14,680 $0 $0 $73,292 $7,100 $0 $13,123 $93,515 $185

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $4,417 $0 $803 $0 $0 $5,221 $497 $0 $858 $6,575 $13

9.2 Circulating Water Pumps $1,142 $0 $67 $0 $0 $1,209 $102 $0 $197 $1,508 $3

9.3 Circ.Water System Auxiliaries $102 $0 $15 $0 $0 $117 $11 $0 $19 $147 $0

9.4 Circ.Water Piping $0 $4,276 $1,109 $0 $0 $5,384 $487 $0 $1,174 $7,045 $14

9.5 Make-up Water System $220 $0 $315 $0 $0 $535 $51 $0 $117 $703 $1

9.6 Component Cooling Water Sys $505 $604 $430 $0 $0 $1,538 $144 $0 $336 $2,019 $4

9.9 Circ.Water System Foundations $0 $1,573 $2,675 $0 $0 $4,248 $403 $0 $1,395 $6,046 $12

SUBTOTAL 9. $6,387 $6,453 $5,413 $0 $0 $18,252 $1,695 $0 $4,097 $24,044 $48

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

315

Exhibit 3-98 Case S3A Total Plant Cost Details (Continued) Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S3A - Siemens 504 MW IGCC w/o CO2

Plant Size: 504.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $17,892 $0 $8,824 $0 $0 $26,716 $2,567 $0 $2,928 $32,211 $64

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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

10.4 High Temperature Ash Piping $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

10.6 Ash Storage Silos $534 $0 $581 $0 $0 $1,115 $108 $0 $183 $1,406 $3

10.7 Ash Transport & Feed Equipment $716 $0 $173 $0 $0 $889 $83 $0 $146 $1,118 $2

10.8 Misc. Ash Handling Equipment $1,106 $1,355 $405 $0 $0 $2,866 $273 $0 $471 $3,610 $7

10.9 Ash/Spent Sorbent Foundation $0 $47 $59 $0 $0 $107 $10 $0 $35 $151 $0

SUBTOTAL 10. $20,248 $1,402 $10,041 $0 $0 $31,692 $3,041 $0 $3,763 $38,496 $76

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $860 $0 $851 $0 $0 $1,711 $163 $0 $187 $2,062 $4

11.2 Station Service Equipment $3,746 $0 $338 $0 $0 $4,083 $376 $0 $446 $4,906 $10

11.3 Switchgear & Motor Control $6,925 $0 $1,259 $0 $0 $8,184 $759 $0 $1,341 $10,285 $20

11.4 Conduit & Cable Tray $0 $3,217 $10,612 $0 $0 $13,829 $1,338 $0 $3,792 $18,958 $38

11.5 Wire & Cable $0 $6,146 $4,038 $0 $0 $10,185 $740 $0 $2,731 $13,656 $27

11.6 Protective Equipment $0 $611 $2,225 $0 $0 $2,837 $277 $0 $467 $3,581 $7

11.7 Standby Equipment $216 $0 $211 $0 $0 $427 $41 $0 $70 $537 $1

11.8 Main Power Transformers $14,245 $0 $128 $0 $0 $14,373 $1,087 $0 $2,319 $17,779 $35

11.9 Electrical Foundations $0 $139 $365 $0 $0 $505 $48 $0 $166 $719 $1

SUBTOTAL 11. $25,991 $10,114 $20,028 $0 $0 $56,133 $4,830 $0 $11,520 $72,483 $144

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $946 $0 $632 $0 $0 $1,578 $149 $79 $271 $2,077 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $217 $0 $139 $0 $0 $357 $34 $18 $82 $490 $1

12.7 Computer & Accessories $5,048 $0 $162 $0 $0 $5,210 $478 $260 $595 $6,543 $13

12.8 Instrument Wiring & Tubing $0 $1,763 $3,605 $0 $0 $5,368 $455 $268 $1,523 $7,615 $15

12.9 Other I & C Equipment $3,374 $0 $1,639 $0 $0 $5,013 $472 $251 $860 $6,595 $13

SUBTOTAL 12. $9,586 $1,763 $6,176 $0 $0 $17,526 $1,588 $876 $3,331 $23,321 $46

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $96 $2,058 $0 $0 $2,154 $214 $0 $710 $3,079 $6

13.2 Site Improvements $0 $1,713 $2,276 $0 $0 $3,988 $394 $0 $1,315 $5,696 $11

13.3 Site Facilities $3,069 $0 $3,238 $0 $0 $6,307 $622 $0 $2,079 $9,008 $18

SUBTOTAL 13. $3,069 $1,809 $7,572 $0 $0 $12,450 $1,229 $0 $4,104 $17,782 $35

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1

14.2 Steam Turbine Building $0 $2,057 $2,931 $0 $0 $4,988 $459 $0 $817 $6,264 $12

14.3 Administration Building $0 $819 $594 $0 $0 $1,413 $126 $0 $231 $1,769 $4

14.4 Circulation Water Pumphouse $0 $157 $83 $0 $0 $240 $21 $0 $39 $300 $1

14.5 Water Treatment Buildings $0 $307 $299 $0 $0 $606 $55 $0 $99 $759 $2

14.6 Machine Shop $0 $419 $287 $0 $0 $706 $63 $0 $115 $884 $2

14.7 Warehouse $0 $677 $437 $0 $0 $1,113 $99 $0 $182 $1,394 $3

14.8 Other Buildings & Structures $0 $394 $307 $0 $0 $700 $63 $0 $153 $916 $2

14.9 Waste Treating Building & Str. $0 $880 $1,682 $0 $0 $2,562 $239 $0 $560 $3,362 $7

SUBTOTAL 14. $0 $5,974 $6,769 $0 $0 $12,743 $1,160 $0 $2,286 $16,188 $32

TOTAL COST $712,207 $64,051 $235,970 $0 $0 $1,012,228 $93,824 $30,283 $181,172 $1,317,507 $2,610

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

316

Exhibit 3-99 Case S3A Owner’s Costs

Owner's Costs $x1000 $/kW

Preproduction Costs

6 Months Fixed O&M $11,711 $23

1 Month Variable O&M $3,023 $6

25% of 1 Months Fuel Cost at 100% CF $737 $1

2% of TPC $26,350 $52

Total $41,821 $83

Inventory Capital

60 day supply of consumables at 100% CF $6,095 $12

0.5% of TPC (spare parts) $6,588 $13

Total $12,682 $25

 Initial Cost for Catalyst and Chemicals $1,498 $3

Land $900 $2

Other Owner's Costs $197,626 $392

Financing Costs $35,573 $70

Total Owner's Costs $290,100 $575

Total Overnight Cost (TOC) $1,607,607 $3,185

TASC Multiplier 1.140

Total As-Spent Cost (TASC) $1,832,672 $3,631
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

317

Exhibit 3-100 Case S3A Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case S3A - Siemens 504 MW IGCC w/o CO2 Heat Rate-net (Btu/kWh): 9,011

MWe-net: 505

 Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate (base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 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-O.J.'s 15.0 15.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $5,918,913 $11.727

Maintenance Labor Cost $12,818,175 $25.397

Administrative & Support Labor $4,684,272 $9.281

Property Taxes and Insurance $26,350,141 $52.208

TOTAL FIXED OPERATING COSTS $49,771,501 $98.614

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $25,115,707 $0.00710

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

Water (/1000 gallons) 0 1,627 1.08 $0 $513,950 $0.00015

Chemicals

MU & WT Chem.(lbs) 0 9,694 0.17 $0 $489,914 $0.00014

Carbon (Mercury Removal) (lb) 61,010 84 1.05 $64,071 $25,628 $0.00001

COS Catalyst (m3) 523 0.36 2,397.36 $1,253,811 $250,762 $0.00007

Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000

Sulfinol Solution (gal) 17,905 12 10.05 $179,922 $35,705 $0.00001

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip. 0.70 131.27 $0 $26,903 $0.00001

 Subtotal Chemicals $1,497,803 $828,913 $0.00023

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 84 0.42 $0 $10,178 $0.00000

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 538 16.23 $0 $2,547,879 $0.00072

Subtotal Waste Disposal $0 $2,558,058 $0.00072

By-products & Emissions 

Sulfur (tons) 0 46 0.00 $0 $0 $0.00000

 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $1,497,803 $29,016,628 $0.00820

Fuel (ton) 0 6,373 15.22 $0 $28,319,073 $0.00801
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

318

Exhibit 3-101 Case L3A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case L3A - Siemens 543 MW IGCC w/o CO2

Plant Size: 543.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING $18,570 $3,451 $14,401 $0 $0 $36,421 $3,306 $0 $7,945 $47,672 $88

 2 COAL & SORBENT PREP & FEED $138,652 $11,733 $23,866 $0 $0 $174,250 $15,119 $0 $37,874 $227,242 $418

 3 FEEDWATER & MISC. BOP SYSTEMS $6,771 $5,627 $6,359 $0 $0 $18,757 $1,766 $0 $4,673 $25,196 $46

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (Siemen $112,359 $0 $52,484 $0 $0 $164,843 $14,646 $24,727 $30,632 $234,848 $432

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $163,595 $0 w/equip. $0 $0 $163,595 $15,857 $0 $17,945 $197,397 $363

4.4-4.9 Other Gasification Equipment $30,620 $14,004 $19,354 $0 $0 $63,977 $6,123 $0 $15,075 $85,175 $157

SUBTOTAL 4 $306,574 $14,004 $71,838 $0 $0 $392,415 $36,626 $24,727 $63,653 $517,421 $953

 5A GAS CLEANUP & PIPING $49,303 $2,824 $47,777 $0 $0 $99,904 $9,661 $85 $22,087 $131,737 $243

5B CO2 REMOVAL & COMPRESSION $0 $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 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $213

6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4

SUBTOTAL 6 $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $218

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $34,059 $0 $4,843 $0 $0 $38,902 $3,699 $0 $4,260 $46,861 $86

7.2-7.9 SCR System, Ductwork and Stack $3,437 $2,450 $3,241 $0 $0 $9,128 $847 $0 $1,624 $11,599 $21

SUBTOTAL 7 $37,496 $2,450 $8,084 $0 $0 $48,031 $4,545 $0 $5,885 $58,461 $108

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $25,733 $0 $4,347 $0 $0 $30,080 $2,886 $0 $3,297 $36,263 $67

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $36,939 $882 $11,553 $0 $0 $49,374 $4,815 $0 $10,913 $65,102 $120

SUBTOTAL 8 $62,673 $882 $15,899 $0 $0 $79,454 $7,701 $0 $14,210 $101,365 $187

 9 COOLING WATER SYSTEM $6,676 $6,750 $5,627 $0 $0 $19,053 $1,769 $0 $4,272 $25,094 $46

10 ASH/SPENT SORBENT HANDLING SYS $27,975 $1,864 $13,870 $0 $0 $43,710 $4,194 $0 $5,176 $53,079 $98

11 ACCESSORY ELECTRIC PLANT $27,937 $10,833 $21,400 $0 $0 $60,169 $5,175 $0 $12,351 $77,695 $143

12 INSTRUMENTATION & CONTROL $9,866 $1,815 $6,357 $0 $0 $18,037 $1,635 $902 $3,428 $24,001 $44

13 IMPROVEMENTS TO SITE $3,198 $1,885 $7,892 $0 $0 $12,975 $1,281 $0 $4,277 $18,533 $34

14 BUILDINGS & STRUCTURES $0 $6,155 $7,032 $0 $0 $13,187 $1,201 $0 $2,364 $16,752 $31

 

TOTAL COST $781,441 $71,079 $257,562 $0 $0 $1,110,083 $102,860 $30,314 $199,286 $1,442,543 $2,656

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

319

Exhibit 3-102 Case L3A Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case L3A - Siemens 543 MW IGCC w/o CO2

Plant Size: 543.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $4,877 $0 $2,383 $0 $0 $7,260 $650 $0 $1,582 $9,492 $17

1.2 Coal Stackout & Reclaim $6,302 $0 $1,528 $0 $0 $7,829 $686 $0 $1,703 $10,218 $19

1.3 Coal Conveyors & Yd Crush $5,859 $0 $1,512 $0 $0 $7,370 $647 $0 $1,603 $9,621 $18

1.4 Other Coal Handling $1,533 $0 $350 $0 $0 $1,883 $165 $0 $409 $2,457 $5

1.5 Sorbent Receive & Unload $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

1.7 Sorbent Conveyors $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

1.9 Coal & Sorbent Hnd.Foundations $0 $3,451 $8,629 $0 $0 $12,079 $1,158 $0 $2,647 $15,885 $29

SUBTOTAL 1. $18,570 $3,451 $14,401 $0 $0 $36,421 $3,306 $0 $7,945 $47,672 $88

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $56,930 $3,420 $8,295 $0 $0 $68,645 $5,924 $0 $14,914 $89,482 $165

2.2 Prepared Coal Storage & Feed $2,366 $566 $371 $0 $0 $3,303 $282 $0 $717 $4,303 $8

2.3 Dry Coal Injection System $77,873 $904 $7,232 $0 $0 $86,009 $7,408 $0 $18,683 $112,100 $206

2.4 Misc.Coal Prep & Feed $1,483 $1,079 $3,235 $0 $0 $5,797 $533 $0 $1,266 $7,596 $14

2.5 Sorbent Prep Equipment $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

2.7 Sorbent Injection System $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

2.9 Coal & Sorbent Feed Foundation $0 $5,764 $4,732 $0 $0 $10,496 $972 $0 $2,294 $13,761 $25

SUBTOTAL 2. $138,652 $11,733 $23,866 $0 $0 $174,250 $15,119 $0 $37,874 $227,242 $418

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,125 $3,648 $1,926 $0 $0 $7,699 $713 $0 $1,682 $10,095 $19

3.2 Water Makeup & Pretreating $359 $37 $200 $0 $0 $597 $57 $0 $196 $849 $2

3.3 Other Feedwater Subsystems $1,162 $393 $353 $0 $0 $1,909 $172 $0 $416 $2,496 $5

3.4 Service Water Systems $205 $423 $1,467 $0 $0 $2,095 $204 $0 $690 $2,989 $6

3.5 Other Boiler Plant Systems $1,101 $427 $1,058 $0 $0 $2,586 $245 $0 $566 $3,397 $6

3.6 FO Supply Sys & Nat Gas $298 $563 $525 $0 $0 $1,385 $133 $0 $304 $1,823 $3

3.7 Waste Treatment Equipment $501 $0 $306 $0 $0 $807 $79 $0 $266 $1,151 $2

3.8 Misc. Power Plant Equipment $1,020 $137 $524 $0 $0 $1,680 $162 $0 $553 $2,395 $4

SUBTOTAL 3. $6,771 $5,627 $6,359 $0 $0 $18,757 $1,766 $0 $4,673 $25,196 $46

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (Siemen $112,359 $0 $52,484 $0 $0 $164,843 $14,646 $24,727 $30,632 $234,848 $432

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $163,595 $0 w/equip. $0 $0 $163,595 $15,857 $0 $17,945 $197,397 $363

4.4 LT Heat Recovery & FG Saturation $30,620 $0 $11,640 $0 $0 $42,260 $4,124 $0 $9,277 $55,661 $102

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,693 $689 $0 $0 $2,382 $228 $0 $522 $3,133 $6

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $12,310 $7,024 $0 $0 $19,335 $1,770 $0 $5,276 $26,381 $49

SUBTOTAL 4. $306,574 $14,004 $71,838 $0 $0 $392,415 $36,626 $24,727 $63,653 $517,421 $953

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

320

Exhibit 3-102 Case L3A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case L3A - Siemens 543 MW IGCC w/o CO2

Plant Size: 543.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 5A GAS CLEANUP & PIPING

5A.1 Sulfinol System $37,542 $0 $31,855 $0 $0 $69,397 $6,711 $0 $15,222 $91,330 $168

5A.2 Elemental Sulfur Plant $5,422 $1,081 $6,995 $0 $0 $13,498 $1,311 $0 $2,962 $17,771 $33

5A.3 Mercury Removal $961 $0 $731 $0 $0 $1,692 $163 $85 $388 $2,328 $4

5A.4 COS Hydrolysis $5,378 $0 $7,023 $0 $0 $12,401 $1,206 $0 $2,721 $16,329 $30

5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.7 Fuel Gas Piping $0 $866 $607 $0 $0 $1,473 $137 $0 $322 $1,931 $4

5A.9 HGCU Foundations $0 $877 $566 $0 $0 $1,443 $133 $0 $473 $2,048 $4

SUBTOTAL 5A. $49,303 $2,824 $47,777 $0 $0 $99,904 $9,661 $85 $22,087 $131,737 $243

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5B. $0 $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 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $213

6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4

SUBTOTAL 6. $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $218

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $34,059 $0 $4,843 $0 $0 $38,902 $3,699 $0 $4,260 $46,861 $86

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,762 $1,289 $0 $0 $3,051 $268 $0 $664 $3,982 $7

7.4 Stack $3,437 $0 $1,291 $0 $0 $4,728 $453 $0 $518 $5,699 $10

7.9 HRSG,Duct & Stack Foundations $0 $689 $661 $0 $0 $1,350 $126 $0 $443 $1,918 $4

SUBTOTAL 7. $37,496 $2,450 $8,084 $0 $0 $48,031 $4,545 $0 $5,885 $58,461 $108

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $25,733 $0 $4,347 $0 $0 $30,080 $2,886 $0 $3,297 $36,263 $67

8.2 Turbine Plant Auxiliaries $178 $0 $408 $0 $0 $586 $57 $0 $64 $707 $1

8.3a Condenser & Auxiliaries $3,246 $0 $1,037 $0 $0 $4,282 $410 $0 $469 $5,161 $10

8.3b Air Cooled Condenser $29,744 $0 $5,963 $0 $0 $35,707 $3,571 $0 $7,855 $47,133 $87

8.4 Steam Piping $3,772 $0 $2,653 $0 $0 $6,425 $552 $0 $1,744 $8,722 $16

8.9 TG Foundations $0 $882 $1,491 $0 $0 $2,374 $225 $0 $780 $3,378 $6

SUBTOTAL 8. $62,673 $882 $15,899 $0 $0 $79,454 $7,701 $0 $14,210 $101,365 $187

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $4,616 $0 $840 $0 $0 $5,456 $520 $0 $896 $6,872 $13

9.2 Circulating Water Pumps $1,207 $0 $73 $0 $0 $1,280 $108 $0 $208 $1,595 $3

9.3 Circ.Water System Auxiliaries $107 $0 $15 $0 $0 $123 $12 $0 $20 $155 $0

9.4 Circ.Water Piping $0 $4,483 $1,162 $0 $0 $5,645 $510 $0 $1,231 $7,386 $14

9.5 Make-up Water System $216 $0 $309 $0 $0 $525 $50 $0 $115 $690 $1

9.6 Component Cooling Water Sys $529 $633 $450 $0 $0 $1,613 $151 $0 $353 $2,116 $4

9.9 Circ.Water System Foundations $0 $1,634 $2,778 $0 $0 $4,412 $418 $0 $1,449 $6,279 $12

SUBTOTAL 9. $6,676 $6,750 $5,627 $0 $0 $19,053 $1,769 $0 $4,272 $25,094 $46

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

321

Exhibit 3-102 Case L3A Total Plant Cost Details (Continued) Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case L3A - Siemens 543 MW IGCC w/o CO2

Plant Size: 543.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $24,843 $0 $12,251 $0 $0 $37,095 $3,564 $0 $4,066 $44,725 $82

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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

10.4 High Temperature Ash Piping $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

10.6 Ash Storage Silos $710 $0 $772 $0 $0 $1,482 $144 $0 $244 $1,870 $3

10.7 Ash Transport & Feed Equipment $952 $0 $230 $0 $0 $1,182 $110 $0 $194 $1,486 $3

10.8 Misc. Ash Handling Equipment $1,470 $1,802 $538 $0 $0 $3,810 $363 $0 $626 $4,798 $9

10.9 Ash/Spent Sorbent Foundation $0 $63 $79 $0 $0 $142 $13 $0 $46 $201 $0

SUBTOTAL 10. $27,975 $1,864 $13,870 $0 $0 $43,710 $4,194 $0 $5,176 $53,079 $98

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $905 $0 $895 $0 $0 $1,800 $172 $0 $197 $2,169 $4

11.2 Station Service Equipment $4,018 $0 $362 $0 $0 $4,380 $404 $0 $478 $5,262 $10

11.3 Switchgear & Motor Control $7,428 $0 $1,351 $0 $0 $8,779 $814 $0 $1,439 $11,032 $20

11.4 Conduit & Cable Tray $0 $3,451 $11,383 $0 $0 $14,834 $1,435 $0 $4,067 $20,336 $37

11.5 Wire & Cable $0 $6,593 $4,332 $0 $0 $10,925 $794 $0 $2,930 $14,648 $27

11.6 Protective Equipment $0 $641 $2,332 $0 $0 $2,973 $290 $0 $490 $3,753 $7

11.7 Standby Equipment $225 $0 $220 $0 $0 $445 $42 $0 $73 $560 $1

11.8 Main Power Transformers $15,361 $0 $136 $0 $0 $15,497 $1,172 $0 $2,500 $19,170 $35

11.9 Electrical Foundations $0 $148 $388 $0 $0 $537 $51 $0 $176 $764 $1

SUBTOTAL 11. $27,937 $10,833 $21,400 $0 $0 $60,169 $5,175 $0 $12,351 $77,695 $143

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $974 $0 $650 $0 $0 $1,624 $154 $81 $279 $2,138 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $224 $0 $144 $0 $0 $367 $35 $18 $84 $505 $1

12.7 Computer & Accessories $5,195 $0 $166 $0 $0 $5,361 $492 $268 $612 $6,734 $12

12.8 Instrument Wiring & Tubing $0 $1,815 $3,710 $0 $0 $5,525 $469 $276 $1,567 $7,837 $14

12.9 Other I & C Equipment $3,473 $0 $1,686 $0 $0 $5,159 $485 $258 $885 $6,788 $12

SUBTOTAL 12. $9,866 $1,815 $6,357 $0 $0 $18,037 $1,635 $902 $3,428 $24,001 $44

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $100 $2,145 $0 $0 $2,245 $223 $0 $740 $3,209 $6

13.2 Site Improvements $0 $1,785 $2,372 $0 $0 $4,157 $410 $0 $1,370 $5,937 $11

13.3 Site Facilities $3,198 $0 $3,375 $0 $0 $6,573 $648 $0 $2,166 $9,388 $17

SUBTOTAL 13. $3,198 $1,885 $7,892 $0 $0 $12,975 $1,281 $0 $4,277 $18,533 $34

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1

14.2 Steam Turbine Building $0 $2,204 $3,140 $0 $0 $5,344 $492 $0 $875 $6,711 $12

14.3 Administration Building $0 $819 $594 $0 $0 $1,413 $126 $0 $231 $1,769 $3

14.4 Circulation Water Pumphouse $0 $161 $85 $0 $0 $247 $22 $0 $40 $309 $1

14.5 Water Treatment Buildings $0 $300 $292 $0 $0 $592 $54 $0 $97 $743 $1

14.6 Machine Shop $0 $419 $287 $0 $0 $706 $63 $0 $115 $884 $2

14.7 Warehouse $0 $677 $437 $0 $0 $1,113 $99 $0 $182 $1,394 $3

14.8 Other Buildings & Structures $0 $405 $316 $0 $0 $721 $64 $0 $157 $942 $2

14.9 Waste Treating Building & Str. $0 $906 $1,731 $0 $0 $2,637 $246 $0 $577 $3,460 $6

SUBTOTAL 14. $0 $6,155 $7,032 $0 $0 $13,187 $1,201 $0 $2,364 $16,752 $31

TOTAL COST $781,441 $71,079 $257,562 $0 $0 $1,110,083 $102,860 $30,314 $199,286 $1,442,543 $2,656

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

322

Exhibit 3-103 Case L3A Owner’s Costs

Owner's Costs $x1000 $/kW

Preproduction Costs

6 Months Fixed O&M $12,238 $23

1 Month Variable O&M $3,335 $6

25% of 1 Months Fuel Cost at 100% CF $741 $1

2% of TPC $28,851 $53

Total $45,164 $83

Inventory Capital

60 day supply of consumables at 100% CF $6,129 $11

0.5% of TPC (spare parts) $7,213 $13

Total $13,342 $25

 Initial Cost for Catalyst and Chemicals $1,737 $3

Land $900 $2

Other Owner's Costs $216,381 $398

Financing Costs $38,949 $72

Total Owner's Costs $316,473 $583

Total Overnight Cost (TOC) $1,759,016 $3,239

TASC Multiplier 1.140

Total As-Spent Cost (TASC) $2,005,278 $3,692
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

323

Exhibit 3-104 Case L3A Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case L3A - Siemens 543 MW IGCC w/o CO2 Heat Rate-net (Btu/kWh): 9,063

MWe-net: 543

 Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 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-O.J.'s 15.0 15.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $5,918,913 $10.898

Maintenance Labor Cost $13,661,375 $25.154

Administrative & Support Labor $4,895,072 $9.013

Property Taxes and Insurance $28,850,854 $53.121

TOTAL FIXED OPERATING COSTS $53,326,213 $98.185

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $26,380,507 $0.00693

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

Water (/1000 gallons) 0 1,577 1.08 $0 $498,031 $0.00013

Chemicals

MU & WT Chem.(lbs) 0 9,394 0.17 $0 $474,740 $0.00012

Carbon (Mercury Removal) (lb) 67,428 92 1.05 $70,811 $28,325 $0.00001

COS Catalyst (m3) 605 0.41 2,397.36 $1,450,277 $290,055 $0.00008

Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000

Sulfinol Solution (gal) 21,466 15 10.05 $215,705 $42,794 $0.00001

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip. 0.83 131.27 $0 $31,975 $0.00001

Subtotal Chemicals $1,736,794 $867,889 $0.00023

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 92 0.42 $0 $11,249 $0.00000

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 898 16.23 $0 $4,255,027 $0.00112

Subtotal Waste Disposal $0 $4,266,277 $0.00112

By-products & Emissions 

Sulfur (tons) 0 56 0.00 $0 $0 $0.00000

Subtotal-By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $1,736,794 $32,012,704 $0.00841

Fuel (ton) 0 8,927 10.92 $0 $28,463,735 $0.00748
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

324

3.4.8 SFG IGCC CO2 Capture Cases (S3B and L3B) Process Description

Cases S3B and L3B are configured to produce electric power with CO2 capture. The plant 

configurations are similar to Cases S3A and L3A with the major differences being the addition 

of WGS, the use of a two-stage Selexol AGR plant instead of Sulfinol and subsequent 

compression of the captured CO2 stream. The gross power output is constrained by the capacity 

of the two CTs, and since the CO2 capture and compression process increases the auxiliary load 

on the plant, the net output is significantly reduced relative to Cases S3A and L3A.

The process description for Cases S3B and L3B is similar to Cases S3A and L3A with several 

notable exceptions to accommodate CO2 capture. A BFD for the CO2 capture cases is shown in 

Exhibit 3-105 and stream tables are shown in Exhibit 3-106 and Exhibit 3-107. Instead of 

repeating the entire process description, only differences from the non-capture cases are reported 

here.

Coal Preparation and Feed Systems

No differences from non-capture cases.

Gasification

The gasification process is the same as the non-capture cases except the coal feed (as-received) 

to the gasifiers is 6,312 tonne/day (6,958 tpd) for the PRB case and 8,727 tonne/day (9,620 tpd)

for the lignite case.

Raw Gas Cooling/Particulate Removal

No differences from non-capture cases.

Sour Water Stripper

No differences from non-capture cases.

Sour Gas Shift

The SGS process was described in Section 3.1.6. The water concentration in the syngas is 

controlled by varying the exit temperature of the water scrubber upstream of the shift reactors. 

The hot syngas exiting the first stage of SGS is used to superheat steam. One more stage of SGS 

(for a total of two) results in approximately 97 percent overall conversion of CO to CO2. The 

warm syngas from the second stage of SGS is cooled to preheat the syngas prior to the first stage 

of SGS. The SGS catalyst also serves to hydrolyze COS, thus eliminating the need for a separate 

COS hydrolysis reactor. Following the second stage of SGS, the syngas is further cooled to 

35°C (95°F) prior to the mercury removal beds..

Mercury Removal and AGR

Mercury removal is the same as in the non-capture cases.

The AGR process in the CO2 capture cases is a two stage Selexol process where H2S is removed 

in the first stage and CO2 in the second stage of absorption. The process results in three product 

streams, the clean syngas, a CO2-rich stream and an acid gas feed to the Claus plant. The acid 

gas contains about 17 percent H2S and 65 percent CO2 with the balance primarily H2. The CO2-

rich stream is discussed further in the CO2 compression section. 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

325

CO2 Compression and Dehydration

CO2 from the AGR process is generated at two pressure levels. The LP stream is compressed 

from 0.12 MPa (17 psia) to 1.0 MPa (150 psia) and then combined with the HP stream. The 

combined stream is further compressed to a SC condition at 15.3 MPa (2215 psia) using a 

multiple-stage, intercooled compressor. During compression, the CO2 stream is dehydrated to a 

dew point of -40oC (-40°F) using a thermal swing adsorptive dryer. The raw CO2 stream from 

the Selexol process contains over 99 percent CO2. The dehydrated CO2 is transported to the 

plant fence line and is sequestration ready. CO2 TS&M costs were estimated using the 

methodology described in Section 2.6.

Claus Unit

The Claus plant is the same as the non-capture cases except 46 tonne/day (51 tpd) of sulfur are 

produced in the PRB case and 55 tonne/day (60 tpd) in the lignite case.

Power Block

Clean syngas from the AGR plant is reheated to 196°C (385°F) using HP BFW, diluted with 

nitrogen, and then enters the CT burner. The exhaust gas exits the CT at a nominal 566°C 

(1,050°F) and enters the HRSG where additional heat is recovered. The flue gas exits the HRSG 

at 132°C (270°F) and is discharged through the plant stack. The steam raised in the HRSG is 

used to power an advanced commercially available steam turbine using a nominal 12.4 

MPa/538°C/538°C (1,800 psig/1,000°F/1,000°F) steam cycle. There is no air integration 

between the CT and the ASU in either capture case.

ASU

The same elevated pressure ASU is used as in non-capture cases except the output is 

3,837 tonne/day (4,229 tpd) of 95 mol% oxygen to the gasifier and Claus plant for the PRB case 

and 4,286 tonne/day (4,725 tpd) for the lignite case

Balance of Plant

Balance of plant items were covered in Sections 3.1.12, 3.1.13, 3.1.14, and 3.1.15.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

326

Exhibit 3-105 Case S3B and L3B Process Flow Diagram
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

327

Exhibit 3-106 Case S3B Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

V-L Mole Fraction

Ar 0.0093 0.0254 0.0318 0.0023 0.0023 0.0360 0.0000 0.0000 0.0000 0.0000 0.0000 0.0051 0.0000 0.0051 0.0064

CH4 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 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2832 0.0000 0.2832 0.0101

CO2 0.0003 0.0088 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0257 0.0000 0.0257 0.3809

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0001 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 0.1456 0.0000 0.1456 0.5325

H2O 0.0064 0.1664 0.0000 0.0002 0.0002 0.0000 1.0000 0.0000 1.0000 0.0000 0.0000 0.4854 1.0000 0.4854 0.0016

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0015 0.0000 0.0015 0.0021

N2 0.7759 0.5832 0.0178 0.9920 0.9920 0.0140 0.0000 0.0000 0.0000 0.0000 0.0000 0.0524 0.0000 0.0524 0.0663

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0000 0.0008 0.0000

O2 0.2081 0.2162 0.9504 0.0054 0.0054 0.9500 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 24,095 900 47 16,376 1,850 4,914 1,268 0 3,070 0 0 35,328 0 35,328 27,923

V-L Flowrate (kg/hr) 696,213 24,890 1,497 459,533 51,920 158,373 22,845 0 55,312 0 0 701,295 0 701,295 567,855

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 262,991 0 207,679 22,191 0 0 0 0

Temperature (°C) 6 20 32 196 197 32 343 6 33 71 260 208 288 232 35

Pressure (MPa, abs) 0.09 0.11 0.86 2.65 5.62 0.86 5.10 0.09 0.55 0.09 4.17 4.07 4.14 4.00 3.60

Enthalpy (kJ/kg)A 15.26 39.05 26.67 202.64 201.76 26.59 3,062.93 --- 139.92 --- --- 1,401.25 2,955.16 1,444.76 43.22

Density (kg/m3) 1.1 1.5 11.0 18.9 39.6 11.0 20.1 --- 985.3 --- --- 21.1 18.2 19.6 29.2

V-L Molecular Weight 28.895 27.654 32.181 28.061 28.061 32.229 18.015 --- 18.015 --- --- 19.851 18.015 19.851 20.336

V-L Flowrate (lbmol/hr) 53,119 1,984 103 36,104 4,079 10,833 2,796 0 6,769 0 0 77,885 0 77,885 61,561

V-L Flowrate (lb/hr) 1,534,887 54,874 3,300 1,013,098 114,463 349,152 50,364 0 121,942 0 0 1,546,091 0 1,546,091 1,251,906

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 579,796 0 457,854 48,923 0 0 0 0

Temperature (°F) 42 68 90 385 387 90 650 42 92 160 500 407 550 450 95

Pressure (psia) 13.0 16.4 125.0 384.0 815.0 125.0 740.0 13.0 80.0 12.7 604.7 589.7 600.0 579.7 522.6

Enthalpy (Btu/lb)A 6.6 16.8 11.5 87.1 86.7 11.4 1,316.8 --- 60.2 --- --- 602.4 1,270.5 621.1 18.6

Density (lb/ft3

) 0.070 0.094 0.687 1.180 2.475 0.688 1.257 --- 61.513 --- --- 1.318 1.135 1.223 1.823

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

328

Exhibit 3-106 Case S3B Stream Table (Continued)

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31

V-L Mole Fraction

Ar 0.0067 0.0064 0.0022 0.0000 0.0056 0.0002 0.0002 0.0100 0.0100 0.0093 0.0090 0.0090 0.0000 0.0000 0.0000 0.0000

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0060 0.0101 0.0038 0.0000 0.0760 0.0003 0.0003 0.0156 0.0156 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.6603 0.3853 0.6540 0.0000 0.4865 0.9916 0.9945 0.0460 0.0460 0.0003 0.0089 0.0089 0.0000 0.0000 0.0000 0.0000

COS 0.0000 0.0000 0.0001 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.1409 0.5283 0.1270 0.0000 0.0574 0.0047 0.0047 0.8248 0.8248 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.1381 0.0016 0.0394 0.0000 0.3338 0.0030 0.0000 0.0001 0.0001 0.0064 0.1204 0.1204 1.0000 1.0000 1.0000 1.0000

H2S 0.0052 0.0022 0.1632 0.0000 0.0011 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0429 0.0661 0.0104 0.0000 0.0362 0.0003 0.0003 0.1034 0.1034 0.7759 0.7553 0.7553 0.0000 0.0000 0.0000 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 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 0.2081 0.1064 0.1064 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0031 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 0.0000 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) 374 28,247 375 0 443 9,895 9,865 17,977 17,747 100,352 127,019 127,019 17,949 17,444 17,444 36,575

V-L Flowrate (kg/hr) 12,597 579,530 13,417 0 13,813 432,659 432,123 133,455 131,748 2,899,687 3,490,969 3,490,969 323,355 314,255 314,255 658,912

Solids Flowrate (kg/hr) 0 0 0 1,908 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 49 35 48 175 232 16 72 31 216 6 561 132 533 32 32 33

Pressure (MPa, abs) 0.07 3.53 0.16 0.1 0.085 0.931 15.270 3.238 3.203 0.090 0.093 0.090 12.512 0.005 0.005 0.827

Enthalpy (kJ/kg)A 235.23 42.11 95.90 --- 755.306 6.442 -94.805 118.187 862.962 15.260 829.552 340.436 3,430.204 2,255.058 2,255.058 140.571

Density (kg/m3) 0.9 29.0 2.2 --- 0.6 18.0 460.0 9.4 5.8 1.1 0.4 0.7 36.8 0.04 0.04 995.0

V-L Molecular Weight 33.644 20.517 35.800 --- 31.159 43.725 43.803 7.424 7.424 28.895 27.484 27.484 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 825 62,273 826 0 977 21,815 21,749 39,632 39,126 221,239 280,028 280,028 39,571 38,457 38,457 80,634

V-L Flowrate (lb/hr) 27,771 1,277,645 29,579 0 30,452 953,849 952,667 294,217 290,454 6,392,716 7,696,268 7,696,268 712,876 692,813 692,813 1,452,653

Solids Flowrate (lb/hr) 0 0 0 4,206 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 120 94 119 347 450 60 162 87 420 42 1,042 270 992 90 90 92

Pressure (psia) 10.6 512.6 23.7 17.3 12.3 135.0 2,214.7 469.6 464.6 13.0 13.5 13.0 1,814.7 0.7 0.7 120.0

Enthalpy (Btu/lb)A 101.1 18.1 41.2 --- 324.7 2.8 -40.8 50.8 371.0 6.6 356.6 146.4 1,474.7 969.5 969.5 60.4

Density (lb/ft3) 0.058 1.808 0.137 --- 0.039 1.123 28.720 0.587 0.361 0.070 0.023 0.046 2.297 0.002 0.002 62.115
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

329

Exhibit 3-107 Case L3B Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

V-L Mole Fraction

Ar 0.0093 0.0170 0.0318 0.0023 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0000 0.0054 0.0000 0.0054 0.0068

CH4 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 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2889 0.0000 0.2889 0.0103

CO2 0.0003 0.0055 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0304 0.0000 0.0304 0.3960

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0002 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 0.1415 0.0000 0.1415 0.5371

H2O 0.0062 0.1013 0.0000 0.0002 0.0002 0.0000 1.0000 0.0000 1.0000 0.0000 0.0000 0.4950 1.0000 0.4950 0.0016

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0017 0.0000 0.0017 0.0024

N2 0.7761 0.7372 0.0178 0.9920 0.9920 0.0178 0.0000 0.0000 0.0000 0.0000 0.0000 0.0360 0.0000 0.0360 0.0457

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0010 0.0000 0.0010 0.0000

O2 0.2082 0.1389 0.9504 0.0054 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 26,909 1,591 56 17,415 2,353 5,493 0 0 5,523 0 0 37,348 0 37,348 29,362

V-L Flowrate (kg/hr) 777,605 44,312 1,814 488,676 66,031 176,772 0 0 99,501 0 0 744,717 0 744,717 600,885

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 363,623 0 264,122 36,583 0 0 0 0

Temperature (°C) 4 18 32 196 197 32 343 4 32 71 260 209 288 226 35

Pressure (MPa, abs) 0.10 0.11 0.86 2.65 5.62 0.86 5.10 0.10 0.34 0.09 4.17 4.10 4.14 4.03 3.60

Enthalpy (kJ/kg)A 13.75 36.85 26.67 202.62 201.75 26.67 3,062.93 --- 134.94 --- --- 1,418.72 2,955.16 1,448.03 42.49

Density (kg/m3) 1.2 1.4 11.0 18.9 39.6 11.0 20.1 --- 986.5 --- --- 21.4 18.2 20.2 29.4

V-L Molecular Weight 28.898 27.846 32.181 28.061 28.061 32.181 18.015 --- 18.015 --- --- 19.940 18.015 19.940 20.465

V-L Flowrate (lbmol/hr) 59,324 3,508 124 38,393 5,188 12,110 0 0 12,176 0 0 82,338 0 82,338 64,732

V-L Flowrate (lb/hr) 1,714,325 97,692 4,000 1,077,346 145,573 389,715 0 0 219,362 0 0 1,641,820 0 1,641,820 1,324,726

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 801,651 0 582,290 80,651 0 0 0 0

Temperature (°F) 40 64 90 385 387 90 650 40 90 160 500 409 550 438 95

Pressure (psia) 13.8 16.4 125.0 384.0 815.0 125.0 740.0 13.8 50.0 13.5 604.7 594.7 600.0 584.7 522.6

Enthalpy (Btu/lb)A 5.9 15.8 11.5 87.1 86.7 11.5 1,316.8 --- 58.0 --- --- 609.9 1,270.5 622.5 18.3

Density (lb/ft3

) 0.074 0.089 0.687 1.180 2.475 0.687 1.257 --- 61.586 --- --- 1.335 1.135 1.261 1.837

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

330

Exhibit 3-107 Case L3B Stream Table (Continued)

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31

V-L Mole Fraction

Ar 0.0073 0.0068 0.0022 0.0000 0.0056 0.0002 0.0002 0.0108 0.0108 0.0093 0.0091 0.0091 0.0000 0.0000 0.0000 0.0000

CH4 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 0.0000 0.0000

CO 0.0043 0.0103 0.0037 0.0000 0.0683 0.0003 0.0003 0.0162 0.0162 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.6625 0.4004 0.6492 0.0000 0.4464 0.9920 0.9948 0.0489 0.0489 0.0003 0.0091 0.0091 0.0000 0.0000 0.0000 0.0000

COS 0.0000 0.0000 0.0001 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.1371 0.5326 0.1223 0.0000 0.0549 0.0045 0.0045 0.8506 0.8506 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.1381 0.0016 0.0371 0.0000 0.3856 0.0029 0.0000 0.0001 0.0001 0.0062 0.1201 0.1201 1.0000 1.0000 1.0000 1.0000

H2S 0.0077 0.0025 0.1784 0.0000 0.0010 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0429 0.0458 0.0069 0.0000 0.0332 0.0002 0.0002 0.0733 0.0733 0.7761 0.7544 0.7544 0.0000 0.0000 0.0000 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 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 0.2082 0.1073 0.1073 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0047 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 0.0000 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) 404 29,711 413 0 523 10,810 10,779 18,237 18,237 106,961 134,708 134,708 18,759 18,905 18,905 38,261

V-L Flowrate (kg/hr) 13,661 613,551 14,837 0 15,765 472,792 472,236 124,209 124,209 3,090,914 3,703,790 3,703,790 337,956 340,584 340,584 689,276

Solids Flowrate (kg/hr) 0 0 0 2,272 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 49 35 48 175 232 16 72 31 216 4 560 133 532 32 32 33

Pressure (MPa, abs) 0.07 3.53 0.16 0.1 0.085 0.931 15.270 3.238 3.234 0.095 0.099 0.095 12.512 0.005 0.005 0.827

Enthalpy (kJ/kg)A 234.19 41.51 92.67 --- 857.472 6.283 -95.297 129.249 941.449 13.748 827.741 340.637 3,427.815 2,254.480 2,254.480 140.362

Density (kg/m3) 0.9 29.2 2.2 --- 0.6 18.0 461.3 8.6 5.4 1.2 0.4 0.8 36.9 0.04 0.04 995.0

V-L Molecular Weight 33.799 20.651 35.961 --- 30.119 43.737 43.811 6.811 6.811 28.898 27.495 27.495 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 891 65,502 910 0 1,154 23,832 23,764 40,206 40,206 235,808 296,981 296,981 41,357 41,679 41,679 84,350

V-L Flowrate (lb/hr) 30,116 1,352,649 32,709 0 34,756 1,042,328 1,041,102 273,833 273,833 6,814,298 8,165,460 8,165,460 745,066 750,859 750,859 1,519,593

Solids Flowrate (lb/hr) 0 0 0 5,008 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 120 94 119 347 450 60 162 87 420 40 1,040 271 990 90 90 92

Pressure (psia) 10.6 512.6 23.7 17.3 12.3 135.0 2,214.7 469.6 469.0 13.8 14.3 13.8 1,814.7 0.7 0.7 120.0

Enthalpy (Btu/lb)A 100.7 17.8 39.8 --- 368.6 2.7 -41.0 55.6 404.8 5.9 355.9 146.4 1,473.7 969.3 969.3 60.3

Density (lb/ft3) 0.058 1.822 0.138 --- 0.038 1.123 28.800 0.538 0.335 0.074 0.024 0.048 2.301 0.002 0.002 62.116
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

331

3.4.9 Case S3B and L3B Performance Results

The Case S3B and L3B modeling assumptions were presented previously in Exhibit 3-84.

The SFG IGCC plant with CO2 capture and using PRB coal at the Montana site (elevation 3,400 

ft) produces a net output of 445 MWe at a net plant efficiency of 30.6 percent (HHV basis). The 

same plant configuration using lignite coal at the North Dakota site (elevation 1,900 ft) produces 

a net output of 467 MWe at a net plant efficiency of 30.0 percent (HHV basis). 

Overall performance for the plants is summarized in Exhibit 3-108, which includes auxiliary 

power requirements The ASU accounts for approximately 56 percent of the total auxiliary load 

in both cases, distributed between the main air compressor, the oxygen compressor, the nitrogen 

compressor, and ASU auxiliaries. The coal drying process accounts for approximately 7 percent 

of the auxiliary load. CO2 compression accounts for about 17 percent and the AGR process 

accounts for about 10 percent of the auxiliary load. All other individual auxiliary loads are less 

than 3 percent of the total.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

332

Exhibit 3-108 Case S3B and L3B Plant Performance Summary

POWER SUMMARY (Gross Power at Generator 

Terminals, kWe) S3B L3B

Gas Turbine Power 430,900 456,600

Steam Turbine Power 203,800 220,300

TOTAL POWER, kWe 634,700 676,900

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 510 620

Coal Milling 2,700 3,740

Slag Handling 580 950

WTA Coal Dryer Compressor 9,270 12,780

WTA Coal Dryer Auxiliaries 600 840

Air Separation Unit Auxiliaries 1,000 1,000

Air Separation Unit Main Air Compressor 62,000 67,470

Oxygen Compressor 8,670 9,680

Nitrogen Compressors 34,640 37,800

CO2 Compressor 31,220 34,730

Boiler Feedwater Pumps 2,330 2,440

Condensate Pump 220 230

Quench Water Pump 10 10

Circulating Water Pump 3,090 3,380

Ground Water Pumps 360 380

Cooling Tower Fans 2,020 2,070

Air Cooled Condenser Fans 2,990 3,050

Scrubber Pumps 750 740

Acid Gas Removal 18,190 19,910

Gas Turbine Auxiliaries 1,000 1,000

Steam Turbine Auxiliaries 100 100

Claus Plant/TGTU Auxiliaries 250 250

Claus Plant TG Recycle Compressor 1,460 1,580

Miscellaneous Balance of Plant1 3,000 3,000

Transformer Losses 2,450 2,640

TOTAL AUXILIARIES, kWe 189,410 210,390

NET POWER, kWe 445,290 466,510

Net Plant Efficiency, % (HHV) 30.6% 30.0%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,765 (11,151) 11,997 (11,371)

CONDENSER COOLING DUTY GJ/hr (106 Btu/hr) 1,329 (1,260) 1,445 (1,370)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 262,991 (579,796) 363,623 (801,651)

Thermal Input, kWt 1,455,207 1,554,603

Raw Water Withdrawal, m3/min (gpm) 15.2 (4,025) 15.8 (4,165)

Raw Water Consumption, m3/min (gpm) 12.5 (3,304) 12.8 (3,379)

1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

333

Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, CO2, and PM were presented in 

Section 2.3. A summary of the plant air emissions for the CO2 capture cases is presented in

Exhibit 3-109.

Exhibit 3-109 Case S3B and L3B Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

80% capacity factor

kg/MWh

(lb/MWh)

S3B L3B S3B L3B S3B L3B

SO2

0.000 

(0.001)

0.000 

(0.001) 14 (15) 16 (18) 0.003 (0.007)

0.003 

(0.008)

NOX

0.022 

(0.051)

0.021 

(0.050) 802 (884) 841 (927) 0.180 (0.397)

0.177 

(0.391)

Particulates 0.003 

(0.0071)

0.003 

(0.0071) 112 (124) 120 (132) 0.025 (0.056)

0.025 

(0.056)

Hg 1.51E-7 

(3.51E-7)

2.41E-7 

(5.60E-7)

0.006 

(0.006)

0.009 

(0.010)

1.25E-6 

(2.75E-6)

1.99E-6 

(4.39E-6)

CO2 gross 9.5 (22.0) 9.6 (22.4) 347,578 

(383,140)

377,494 

(416,116) 78 (172) 80 (175)

CO2 net 111 (246) 115 (255)

The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the two-stage 

Selexol AGR process. Just as in the non-capture cases, the SO2 emission are significantly less 

than the environmental targets of Section 2.3. The clean syngas exiting the AGR process has a 

sulfur concentration of approximately 2 ppmv. This results in a concentration in the flue gas of 

less than 0.3 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, 

producing elemental sulfur. The tail gas is hydrogenated and recycled upstream of the AGR.

NOx emissions are limited to 15 ppmvd (as NO2 @ 15 percent O2) by the use of low NOx 

burners and nitrogen dilution of the fuel gas. Ammonia in the syngas is removed with process 

condensate prior to the low-temperature AGR process and subsequently destroyed in the Claus 

plant burner. This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone 

and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Ninety five percent of mercury is captured from the syngas by an activated carbon bed.

Slightly greater than 92 percent of the CO2 from the syngas is captured in the AGR system and 

compressed for sequestration.

The carbon balance for the plant is shown in Exhibit 3-110. The carbon input to the plant 

consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not used in the 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

334

carbon capture equation below, but it is not neglected in the balance since the Aspen model 

accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, 

CO2 in the stack gas and ASU vent gas, and the captured CO2 product. The carbon capture 

efficiency is defined as the amount 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 Product for Sequestration)/[(Carbon in the Coal)-(Carbon in Slag)] or

90 percent (both cases S3B and L3B)

Exhibit 3-110 Cases S3B and L3B Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

S3B L3B S3B L3B

Coal 131,675 

(290,293)

143,826 

(317,083) Slag 658 (1,451) 719 (1,585)

Air (CO2) 490 (1,081) 527 (1,163) Stack Gas 13,536 

(29,842)

14,701 

(32,410)

ASU Vent 95 (209) 106 (234)

CO2 Product 117,876 

(259,871)

128,827 

(284,016)

Total 132,165 

(291,374)

144,354 

(318,245) Total 132,165 (291,374)

144,354 

(318,245)

Exhibit 3-111 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur 

in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the 

stack gas and sulfur that is co-sequestered with the CO2 product. Sulfur in the slag is considered 

negligible. 

Exhibit 3-111 Cases S3B and L3B Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

S3B L3B S3B L3B

Coal 1,913 (4,218) 2,278 (5,022) Elemental 

Sulfur 1,908 (4,206) 2,272 (5,008)

Stack Gas 1 (2) 1 (3)

CO2 Product 4 (9) 5 (11)

Total 1,913 (4,218) 2,278 (5,022) Total 1,913 (4,218) 2,278 (5,022)

Exhibit 3-112 shows the overall water balance for the plant. 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, primarily from the coal drying process and as syngas condensate, and that water is reused as internal recycle. Raw water withdrawal is the difference between water demand and 

internal recycle. Some water is discharged from the process to a permitted outfall. The 

difference between the withdrawal and discharge is the consumption.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

335

Exhibit 3-112 Cases S3B and L3B Water Balance

Water Use

Water Demand

m3/min (gpm)

Internal Recycle m3/min 

(gpm)

Raw Water Withdrawal

m3/min (gpm)

Process Water 

Discharge m3/min (gpm)

Raw Water Consumption 

m3/min (gpm)

S3B L3B S3B L3B S3B L3B S3B L3B S3B L3B

Slag Handling 0.48 (127) 0.79 (210) 0.5 (127) 0.8 (210) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0)

Quench/Wash 5.56 (1469) 5.98 (1580) 1.6 (426) 1.5 (386) 3.95 (1043) 4.52 (1194) 0 (0) 0 (0) 3.95 (1043) 4.52 (1194)

SWS Blowdown 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0.02 (6) 0.02 (6) -0.02 (-6) -0.02 (-6)

Condenser Makeup 0.51 (134) 0.14 (36) 0 (0) 0 (0) 0.51 (134) 0.14 (36) 0 (0) 0 (0) 0.51 (134) 0.14 (36)

 Shift Steam 0.38 (101) 0.38 (101)

 BFW Makeup 0.13 (33) 0.14 (36) 0.13 (33) 0.14 (36)

Cooling Tower 12.04 

(3,180)

13.13 

(3,469) 1.3 (333) 2.0 (534) 10.78 (2,848)

11.11 

(2,935) 2.71 (715) 2.95 (780) 8.07 (2,132)

8.16 

(2,155)

 Water from Coal Drying 0.9 (244) 1.7 (439) -0.92 

(-244)

-1.66 

(-439)

 BFW Blowdown 0.1 (33) 0.1 (36) -0.13 (-33) -0.14 (-36)

 SWS Blowdown 0.2 (55) 0.2 (60) -0.21 (-55) -0.23 (-60)

Total 18.6 

(4,911)

20.0 

(5,294) 3.4 (886) 4.3 (1,130) 15.2 (4,025)

15.8 

(4,165) 2.7 (721) 3.0 (786) 12.5 (3,304)

12.8 

(3,379)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

336

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-113 and 

Exhibit 3-114:

• Coal gasification and ASU

• Syngas cleanup

• Combined cycle power generation

An overall plant energy balance is provided in tabular form in Exhibit 3-115 for the two cases. 

The power out is the combined CT and steam turbine power after generator losses.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

337

Exhibit 3-113 Case S3B Heat and Mass Balance
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

338

Exhibit 3-113 Case S3B Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

339

Exhibit 3-113 Case S3B Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

340

Exhibit 3-114 Case L3B Heat and Mass Balance
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

341

Exhibit 3-114 Case L3B Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

342

Exhibit 3-114 Case L3B Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

343

Exhibit 3-115 Cases S3B and L3B Energy Balance

HHV Sensible + Latent Power Total

S3B L3B S3B L3B S3B L3B S3B L3B

Heat In GJ/hr (MMBtu/hr)

Coal 5,239 

(4,965)

5,597 

(5,305) 2.7 (2.6) 3.2 (3.1) 0 (0) 0 (0) 5,241 (4,968) 5,600 (5,308)

ASU Air 0 (0) 0 (0) 10.6 (10.1) 10.7 (10.1) 0 (0) 0 (0) 11 (10) 11 (10)

GT Air 0 (0) 0 (0) 44.2 (41.9) 42.5 (40.3) 0 (0) 0 (0) 44 (42) 42 (40)

Raw Water Makeup 0 (0) 0 (0) 21.2 (20.1) 17.5 (16.6) 0 (0) 0 (0) 21 (20) 18 (17)

Auxiliary Power 0 (0) 0 (0) 0 (0) 0 (0) 682 (646) 757 (718) 682 (646) 757 (718)

Totals 5,239 

(4,965)

5,597 

(5,305) 78.8 (74.6) 74.0 (70.1) 682 (646) 757 (718) 5,999 (5,686) 6,428 (6,093)

Heat Out GJ/hr (MMBtu/hr)

ASU Intercoolers 0 (0) 0 (0) 215 (204) 232 (220) 0 (0) 0 (0) 215 (204) 232 (220)

ASU Vent 0 (0) 0 (0) 1.0 (0.9) 1.6 (1.5) 0 (0) 0 (0) 1 (1) 2 (2)

Slag 22 (20) 24 (22) 4.8 (4.6) 7.9 (7.5) 0 (0) 0 (0) 26 (25) 32 (30)

Sulfur 18 (17) 21 (20) 0.2 (0.2) 0.3 (0.2) 0 (0) 0 (0) 18 (17) 21 (20)

CO2 0 (0) 0 (0) -41.0 (-38.8) -45.0 (-42.7) 0 (0) 0 (0) -41 (-39) -45 (-43)

CO2 Comp Intercoolers 0 (0) 0 (0) 151.4 (143.5) 167.8 (159.0) 0 (0) 0 (0) 151 (144) 168 (159)

Cooling Tower 

Blowdown 0 (0) 0 (0) 15.1 (14.3) 16.0 (15.2) 0 (0) 0 (0) 15 (14) 16 (15)

HRSG Flue Gas 0 (0) 0 (0) 1,188 (1,126) 1,262 (1,196) 0 (0) 0 (0) 1,188 (1,126) 1,262 (1,196)

Condenser 0 (0) 0 (0) 1,330 (1,260) 1,443 (1,368) 0 (0) 0 (0) 1,330 (1,260) 1,443 (1,368)

Auxiliary Cooling 

Loads 0 (0) 0 (0) 348 (329) 385 (365) 0 (0) 0 (0) 348 (329) 385 (365)

Generator Loss 0 (0) 0 (0) 0 (0) 0 (0) 35 (33) 37 (35) 35 (33) 37 (35)

Process Losses 0 (0) 0 (0) 428 (406) 439 (416) 0 (0) 0 (0) 428 (406) 439 (416)

Power 0 (0) 0 (0) 0 (0) 0 (0) 2,285 (2,166)

2,437 

(2,310) 2,285 (2,166) 2,437 (2,310)

Totals 39 (37) 45 (42) 3,640 (3,450) 3,909 (3,705) 2,320 

(2,199)

2,474 

(2,345) 5,999 (5,686) 6,428 (6,093)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

344

3.4.10 Case S3B and L3B Equipment List

Major equipment items for the SFG with CO2 capture are shown in the following tables. The 

accounts used in the equipment list correspond to the account numbers used in the cost estimates 

in Section 3.4.11. In general, the design conditions include a 10 percent contingency for flows 

and heat duties and a 21 percent contingency for heads on pumps and fans.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

345

ACCOUNT 1 COAL HANDLING

Equipment 

No. Description Type S3B Design Conditions L3B Design Condition Operating Qty 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 54 tonne (60 ton) 73 tonne (80 ton) 2 1

9 Feeder Vibratory 218 tonne/hr (240 tph) 299 tonne/hr (330 tph) 2 1

10 Conveyor No. 3 Belt w/ 

tripper 435 tonne/hr (480 tph) 599 tonne/hr (660 tph) 1 0

11 Crusher Tower N/A N/A N/A 1 0

12 Coal Surge Bin w/ 

Vent Filter Dual outlet 218 tonne (240 ton) 299 tonne (330 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 435 tonne/hr (480 tph) 599 tonne/hr (660 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A N/A 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

346

Equipment 

No. Description Type S3B Design Conditions L3B Design Condition Operating Qty Spares

17 Conveyor No. 5 Belt w/ 

tripper 435 tonne/hr (480 tph) 599 tonne/hr (660 tph) 1 0

18 Coal Silo w/ Vent 

Filter and Slide Gates Field erected 998 tonne (1,100 ton) 1,361 tonne (1,500 ton) 3 0

ACCOUNT 2 COAL PREPARATION AND FEED 

Equipment 

No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 Feeder Vibratory 100 tonne/hr (110 tph) 136 tonne/hr (150 tph) 3 0

2 Conveyor No. 

6 Belt w/tripper 290 tonne/hr (320 tph) 399 tonne/hr (440 tph) 1 0

3 Roller Mill 

Feed Hopper Dual Outlet 581 tonne (640 ton) 798 tonne (880 ton) 1 0

4 Weigh Feeder Belt 145 tonne/hr (160 tph) 200 tonne/hr (220 tph) 2 0

5 Pulverizer Rotary 145 tonne/hr (160 tph) 200 tonne/hr (220 tph) 2 0

6 Coal Dryer 

Feed Hopper Vertical Hopper 290 tonne (320 ton) 399 tonne (440 ton) 2 0

7 Coal 

Preheater

Water Heated 

Horizontal Rotary Kiln

Coal feed: 290 tonne/hr 

(320 tph)

Heat duty: 32.2 GJ/hr 

(30.5 MMBtu/hr)

Coal feed: 399 tonne/hr 

(440 tph)

Heat duty: 49.4 GJ/hr 

(46.8 MMBtu/hr)

1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

347

Equipment 

No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

8 Coal Dryer Fluidized Bed with 

Internal Coils

Coal feed: 145 tonne/hr 

(160 tph)

Heat duty: 81.0 GJ/hr 

(76.7 MMBtu/hr)

Bed diameter: 12.5 m 

(41 ft)

Coal feed: 200 tonne/hr 

(220 tph)

Heat duty: 143.3 GJ/hr

(135.8 MMBtu/hr)

Bed diameter: 14.6 m 

(48 ft)

2 0

9 Steam 

Compressor

Reciprocating, MultiStage

606 m3/min (21,400 scfm)

Suction - 0.09 MPa (13 

psia)

Discharge - 0.72 MPa (105 

psia)

1,090 m3/min (38,500 scfm)

Suction - 0.10 MPa (13.8 

psia)

Discharge - 0.52 MPa (75 

psia)

2 0

10 Dryer Exhaust 

Filter Hot Baghouse

Steam - 30,436 kg/hr 

(67,100 lb/hr)

Temperature - 107°C 

(225°F)

Steam - 54,703 kg/hr 

(120,600 lb/hr)

Temperature - 107°C 

(225°F)

2 0

11 Dry Coal 

Cooler

Water Cooled 

Horizontal Rotary Kiln

228 tonne/hr (252 tph)

Heat duty - 13 GJ/hr 

(13 MMBtu/hr)

291 tonne/hr (320 tph)

Heat duty - 18 GJ/hr 

(17 MMBtu/hr)

1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

348

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment 

No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1

Demineralized 

Water Storage 

Tank

Vertical, 

cylindrical, 

outdoor

488,318 liters (129,000 gal) 526,172 liters (139,000 gal) 2 0

2 Condensate Pumps Vertical 

canned

6,095 lpm @ 91 m H2O

(1,610 gpm @ 300 ft H2O)

6,359 lpm @ 91 m H2O

(1,680 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral 

w/ HRSG)

Horizontal 

spray type

441,345 kg/hr 

(973,000 lb/hr)

466,747 kg/hr 

(1,029,000 lb/hr) 2 0

4

Intermediate 

Pressure Feedwater 

Pump

Horizontal 

centrifugal, 

single stage

2,801 lpm @ 27 m H2O

(740 gpm @ 90 ft H2O)

3,066 lpm @ 27 m H2O

(810 gpm @ 90 ft H2O) 2 1

5

High Pressure 

Feedwater Pump 

No. 1

Barrel type, 

multi-stage, 

centrifugal

HP water: 3,142 lpm @ 

1,890 m H2O (830 gpm @ 

6,200 ft H2O)

HP water: 3,293 lpm @ 

1,890 m H2O (870 gpm @ 

6,200 ft H2O)

2 1

6

High Pressure 

Feedwater Pump 

No. 2

Barrel type, 

multi-stage, 

centrifugal

IP water: 1,136 lpm @ 223 

m H2O (300 gpm @ 730 ft 

H2O)

IP water: 1,249 lpm @ 223 

m H2O (330 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 Cycle 

Cooling Heat 

Exchangers

Plate and 

frame

407 GJ/hr (386 MMBtu/hr) 

each

446 GJ/hr (422 MMBtu/hr) 

each 2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

349

Equipment 

No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

11

Closed Cycle 

Cooling Water 

Pumps

Horizontal 

centrifugal

146,117 lpm @ 21 m H2O

(38,600 gpm @ 70 ft H2O)

159,744 lpm @ 21 m H2O

(42,200 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

4,240 lpm @ 18 m H2O

(1,120 gpm @ 60 ft H2O)

4,391 lpm @ 18 m H2O

(1,160 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)

2,915 lpm @ 268 m H2O 

(770 gpm @ 880 ft H2O) 2 1

16 Filtered Water 

Pumps

Stainless steel, 

single suction

3,710 lpm @ 49 m H2O

(980 gpm @ 160 ft H2O)

3,899 lpm @ 49 m H2O

(1,030 gpm @ 160 ft H2O) 2 1

17 Filtered Water 

Tank

Vertical, 

cylindrical

1,775,358 liter (469,000 

gal)

1,866,208 liter (493,000 

gal) 2 0

18 Makeup Water 

Demineralizer

Anion, cation, 

and mixed bed 151 lpm (40 gpm) 151 lpm (40 gpm) 2 0

19 Liquid Waste 

Treatment System 10 years, 24-hour storm 10 years, 24-hour storm 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

350

ACCOUNT 4 GASIFIER, ASU, AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY 

Equipment 

No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 Gasifier Pressurized dryfeed, entrained bed

2,359 tonne/day, 4.2 MPa

(2,600 tpd, 605 psia)

3,175 tonne/day, 4.2 MPa

(3,500 tpd, 605 psia) 3 0

2 Synthesis Gas

Cyclone High efficiency

285,310 kg/hr 

(629,000 lb/hr) 

Design efficiency 90%

303,453 kg/hr 

(669,000 lb/hr) 

Design efficiency 90%

3 0

3

Syngas Scrubber 

Including Sour 

Water Stripper

Vertical up flow 274,877 kg/hr 

(606,000 lb/hr)

292,567 kg/hr 

(645,000 lb/hr) 3 0

4 Raw Gas Coolers Shell and tube with 

condensate drain

385,554 kg/hr 

(850,000 lb/hr)

409,594 kg/hr 

(903,000 lb/hr) 8 0

5 Raw Gas 

Knockout Drum

Vertical with mist 

eliminator

312,525 kg/hr, 35°C, 

3.6 MPa

(689,000 lb/hr, 95°F, 

528 psia)

330,669 kg/hr, 35°C, 

3.6 MPa

(729,000 lb/hr, 95°F, 

528 psia)

2 0

6 Synthesis Gas 

Reheater Shell and tube 73,482 kg/hr (162,000 lb/hr)

68,492 kg/hr 

(151,000 lb/hr) 2 0

7 Flare Stack

Self-supporting, 

carbon steel, 

stainless steel top, 

pilot ignition

412,315 kg/hr 

(909,000 lb/hr) syngas

438,624 kg/hr 

(967,000 lb/hr) syngas 2 0

8 ASU Main Air 

Compressor

Centrifugal, multistage

5,239 m3

/min @ 1.3 MPa

(185,000 scfm 

@ 190 psia)

5,833 m3/min @ 1.3 MPa

(206,000 scfm 

@ 190 psia)

2 0

9 Cold Box Vendor design

2,087 tonne/day 

(2,300 tpd) of 

95% purity oxygen

2,359 tonne/day 

(2,600 tpd) of

95% purity oxygen

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

351

Equipment 

No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

10 Oxygen 

Compressor

Centrifugal, multistage

1,076 m3/min (38,000 

scfm)

Suction - 0.9 MPa (130 

psia)

Discharge - 5.1 MPa (740 

psia)

1,189 m3/min (42,000 

scfm)

Suction - 0.9 MPa (130 

psia)

Discharge - 5.1 MPa (740 

psia)

2 0

11 Primary Nitrogen 

Compressor

Centrifugal, multistage

3,483 m3/min (123,000 

scfm)

Suction - 0.4 MPa (60 

psia)

Discharge - 2.7 MPa (390 

psia)

3,738 m3/min (132,000

scfm)

Suction - 0.4 MPa (60 

psia)

Discharge - 2.7 MPa (390 

psia)

2 0

12

Secondary 

Nitrogen 

Compressor

Centrifugal, singlestage

481 m3

/min (17,000 scfm)

Suction - 2.6 MPa (380 

psia)

Discharge - 5.7 MPa (820 

psia)

538 m3/min (19,000 scfm)

Suction - 2.6 MPa (380 

psia)

Discharge - 5.7 MPa (820 

psia)

2 0

13

Transport 

Nitrogen Boost 

Compressor

Centrifugal, singlestage

402 m3/min (14,200 scfm)

Suction - 2.6 MPa (384 

psia)

Discharge - 5.6 MPa (815 

psia)

510 m3/min (18,000 scfm)

Suction - 2.6 MPa (384 

psia)

Discharge - 5.6 MPa (815 

psia)

2 0

14

Syngas Dilution 

Nitrogen Boost 

Compressor

Centrifugal, singlestage

1,535 m3/min (54,200 

scfm)

Suction - 2.6 MPa (384 

psia)

Discharge - 3.2 MPa (469 

psia)

1,668 m3/min (58,900 

scfm)

Suction - 2.6 MPa (384 

psia)

Discharge - 3.2 MPa (469 

psia)

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

352

ACCOUNT 5 SYNGAS CLEANUP

Equipment 

No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 Mercury 

Adsorber

Sulfated 

carbon bed

312,525 kg/hr (689,000 lb/hr) 

35°C (95°F) 

3.6 MPa (523 psia)

330,669 kg/hr (729,000 lb/hr) 

35°C (95°F) 

3.6 MPa (523 psia)

2 0

2 Sulfur Plant Claus type 50 tonne/day (56 tpd) 60 tonne/day (66 tpd) 1 0

3 Water Gas Shift 

Reactors

Fixed bed, 

catalytic

385,554 kg/hr (850,000 lb/hr) 

232°C (450°F) 

4.0 MPa (580 psia)

409,594 kg/hr (903,000 lb/hr) 

227°C (440°F) 

4.0 MPa (580 psia)

4 0

4

Shift Reactor 

Heat Recovery 

Exchangers

Shell and tube Exchanger 1: 189 GJ/hr 

(179 MMBtu/hr) 

Exchanger 1: 199 GJ/hr 

(188 MMBtu/hr) 4 0

5 Acid Gas 

Removal Plant

Two-stage 

Selexol

318,875 kg/hr (703,000 lb/hr) 

35°C (94°F) 

3.5 MPa (513 psia)

337,473 kg/hr (744,000 lb/hr) 

35°C (94°F) 

3.5 MPa (513 psia)

2 0

6 Hydrogenation 

Reactor

Fixed bed, 

catalytic

15,194 kg/hr (33,497 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

17,341 kg/hr (38,231 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

1 0

7 Tail Gas Recycle 

Compressor Centrifugal 12,854 kg/hr (28,339 lb/hr) 13,945 kg/hr (30,743 lb/hr) 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

353

ACCOUNT 5B CO2 COMPRESSION

Equipment 

No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 CO2

Compressor

Integrally geared, 

multi-stage centrifugal

1,070 m3/min @ 15.3 

MPa (37,800 scfm @ 

2,215 psia)

1,169 m3/min @ 15.3 

MPa (41,300 scfm @ 

2,215 psia)

4 0

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment 

No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 Gas Turbine Advanced F 

class 215 MW 230 MW 2 0

2 Gas Turbine 

Generator TEWAC 240 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

ACCOUNT 7 HRSG, DUCTING AND STACK

Equipment 

No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 Stack CS plate, type 

409SS liner

76 m (250 ft) high x

8.7 m (20 ft) diameter

76 m (250 ft) high x

8.7 m (20 ft) diameter 2 0

2

Heat Recovery 

Steam 

Generator

Drum, multipressure with 

economizer 

section and 

integral deaerator

Main steam - 177,845 

kg/hr, 12.4 MPa/533°C 

(392,082 lb/hr, 1,800 

psig/992°F)

Reheat steam - 251,394 

kg/hr, 3.1 MPa/533°C 

(554,230 lb/hr, 452 

psig/992°F)

Main steam - 185,876 

kg/hr, 12.4 MPa/532°C 

(409,786 lb/hr, 1,800 

psig/990°F)

Reheat steam - 273,486 

kg/hr, 3.1 MPa/532°C 

(602,934 lb/hr, 452 

psig/990°F)

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

354

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 Steam Turbine Commercially 

available

214 MW

12.4 MPa/533°C/533°C 

(1,800 psig/ 992°F/992°F)

232 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

240 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase

260 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase 1 0

3 Surface 

Condenser

Single pass, 

divided waterbox 

including vacuum 

pumps

728 GJ/hr (690 MMBtu/hr), 

Condensing temperature 

32°C (90°F), Inlet water 

temperature 9°C (48°F), 

Water temperature rise 

11°C (20°F)

791 GJ/hr (750 MMBtu/hr), 

Condensing temperature 

32°C (90°F), Inlet water 

temperature 8°C (47°F), 

Water temperature rise 

11°C (20°F)

1 0

4 Air-cooled 

Condenser ---

728 GJ/hr (690 MMBtu/hr), 

Condensing temperature 

32°C (90°F), Ambient 

temperature 6°C (42°F)

791 GJ/hr (750 MMBtu/hr), 

Condensing temperature 

32°C (90°F), Ambient 

temperature 4°C (40°F)

1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

355

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 Circulating 

Water Pumps Vertical, wet pit 310,404 lpm @ 30 m

(82,000 gpm @ 100 ft)

336,902 lpm @ 30 m

(89,000 gpm @ 100 ft) 2 1

2 Cooling 

Tower

Evaporative, 

mechanical 

draft, multi-cell

3°C (37°F) WB / 9°C (48°F) 

CWT / 20°C (68°F) HWT / 

1730 GJ/hr 

(1640 MMBtu/hr) heat duty

2°C (36°F) WB / 8°C (47°F) 

CWT / 19°C (67°F) HWT / 

1889 GJ/hr 

(1790 MMBtu/hr) heat duty

1 0

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 Slag Quench Tank Water bath 155,202 liters (41,000 gal) 257,408 liters (68,000 gal) 3 0

2 Slag Crusher Roll 8 tonne/hr (9 tph) 14 tonne/hr (15 tph) 3 0

3 Slag Depressurizer Proprietary 8 tonne/hr (9 tph) 14 tonne/hr (15 tph) 3 0

4 Slag Receiving 

Tank

Horizontal, 

weir 94,635 liters (25,000 gal) 155,202 liters (41,000 gal) 3 0

5 Black Water 

Overflow Tank

Shop 

fabricated 41,640 liters (11,000 gal) 68,137 liters (18,000 gal) 3

6 Slag Conveyor Drag chain 8 tonne/hr (9 tph) 14 tonne/hr (15 tph) 3 0

7 Slag Separation 

Screen Vibrating 8 tonne/hr (9 tph) 14 tonne/hr (15 tph) 3 0

8 Coarse Slag 

Conveyor Belt/bucket 8 tonne/hr (9 tph) 14 tonne/hr (15 tph) 3 0

9 Fine Ash Settling 

Tank

Vertical, 

gravity 132,489 liters (35,000 gal) 219,554 liters (58,000 gal) 3 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

356

Equipment 

No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

10 Fine Ash Recycle 

Pumps

Horizontal 

centrifugal

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

76 lpm @ 14 m H2O

(20 gpm @ 46 ft H2O) 3 3

11 Grey Water Storage 

Tank Field erected 41,640 liters (11,000 gal) 68,137 liters (18,000 gal) 3 0

12 Grey Water Pumps Centrifugal 151 lpm @ 424 m H2O

(40 gpm @ 1,390 ft H2O)

265 lpm @ 424 m H2O

(70 gpm @ 1,390 ft H2O) 3 3

13 Slag Storage Bin Vertical, field 

erected 544 tonne (600 tons) 998 tonne (1,100 tons) 3 0

14 Unloading 

Equipment

Telescoping 

chute 100 tonne/hr (110 tph) 172 tonne/hr (190 tph) 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

357

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type S3B Design Condition L3B Design Condition

Operating 

Qty Spares

1 CTG Step-up 

Transformer Oil-filled 24 kV/345 kV, 240 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, 240 MVA, 3-ph, 60 Hz

24 kV/345 kV, 

260 MVA, 3-ph, 60 Hz 1 0

3

High Voltage 

Auxiliary 

Transformer

Oil-filled 345 kV/13.8 kV, 

81 MVA, 3-ph, 60 Hz

345 kV/13.8 kV, 

90 MVA, 3-ph, 60 Hz 2 0

4

Medium Voltage 

Auxiliary 

Transformer

Oil-filled 24 kV/4.16 kV, 

46 MVA, 3-ph, 60 Hz

24 kV/4.16 kV, 

50 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 1 1

6

CTG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz 2 0

7

STG Isolated Phase 

Bus Duct and Tap 

Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 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
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

358

ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment 

No. Description Type S3B Design Condition

L3B Design 

Condition

Operating 

Qty Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator printer (laser 

color); Engineering printer (laser B&W)

Operator stations/printers and 

engineering stations/printers 1 0

2 DCS -

Processor

Microprocessor with redundant 

input/output N/A 1 0

3 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

359

3.4.11 Case S3B and L3B Cost Estimating

Costs Results

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-116 shows 

the TPC summary organized by cost account for the PRB coal case (S3B) and Exhibit 3-120

shows the same information for the NDL coal case (L3B). A more detailed breakdown of the 

capital costs is shown in Exhibit 3-117 for S3B and Exhibit 3-121 for L3B. Exhibit 3-118 and 

Exhibit 3-122 show the calculation and addition of owner’s costs to determine the TOC, used to 

calculate COE. Exhibit 3-119 shows the initial and annual O&M costs for Case S3B and 

Exhibit 3-123 shows the same information for Case L3B.

The estimated TOC of the SFG with CO2 capture using PRB coal is $4,318/kW and using lignite 

coal is $4,430/kW. Process contingency represents 3 percent, project contingency represents 

12 percent, and owner’s costs represent 18 percent of TOC in both cases. The COE is 

121.7 mills/kWh in the PRB case and 123.7 mills/kWh in the lignite case.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

360

Exhibit 3-116 Case S3B Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S3B - Siemens 445 MW IGCC w/ CO2

Plant Size: 445.3 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING $15,911 $2,957 $12,339 $0 $0 $31,206 $2,833 $0 $6,808 $40,846 $92

 2 COAL & SORBENT PREP & FEED $119,959 $9,996 $20,467 $0 $0 $150,422 $13,050 $0 $32,694 $196,166 $441

 3 FEEDWATER & MISC. BOP SYSTEMS $7,393 $5,413 $7,602 $0 $0 $20,407 $1,931 $0 $5,245 $27,583 $62

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (Siemen $112,359 $0 $52,484 $0 $0 $164,843 $14,646 $24,727 $30,632 $234,848 $527

4.2 Syngas Cooling w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $184,152 $0 w/equip. $0 $0 $184,152 $17,850 $0 $20,200 $222,202 $499

4.4-4.9 Other Gasification Equipment $27,994 $12,820 $17,683 $0 $0 $58,497 $5,599 $0 $13,775 $77,871 $175

SUBTOTAL 4 $324,505 $12,820 $70,168 $0 $0 $407,493 $38,095 $24,727 $64,608 $534,921 $1,201

 5A GAS CLEANUP & PIPING $84,233 $2,870 $71,635 $0 $0 $158,738 $15,335 $26,220 $40,227 $240,519 $540

5B CO2 COMPRESSION $18,605 $0 $10,561 $0 $0 $29,166 $2,807 $0 $6,395 $38,368 $86

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,610 $9,348 $9,861 $11,782 $129,600 $291

6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5

SUBTOTAL 6 $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $296

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $31,401 $0 $4,465 $0 $0 $35,866 $3,410 $0 $3,928 $43,204 $97

7.2-7.9 SCR System, Ductwork and Stack $3,524 $2,513 $3,324 $0 $0 $9,361 $868 $0 $1,666 $11,895 $27

SUBTOTAL 7 $34,925 $2,513 $7,789 $0 $0 $45,227 $4,278 $0 $5,593 $55,098 $124

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $23,475 $0 $3,915 $0 $0 $27,390 $2,628 $0 $3,002 $33,019 $74

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $31,839 $802 $10,004 $0 $0 $42,645 $4,160 $0 $9,426 $56,231 $126

SUBTOTAL 8 $55,314 $802 $13,919 $0 $0 $70,035 $6,788 $0 $12,428 $89,251 $200

 9 COOLING WATER SYSTEM $7,844 $7,697 $6,551 $0 $0 $22,092 $2,052 $0 $4,943 $29,087 $65

10 ASH/SPENT SORBENT HANDLING SYS $21,399 $1,472 $10,612 $0 $0 $33,483 $3,213 $0 $3,974 $40,669 $91

11 ACCESSORY ELECTRIC PLANT $30,719 $12,337 $23,901 $0 $0 $66,958 $5,760 $0 $13,849 $86,566 $194

12 INSTRUMENTATION & CONTROL $10,750 $1,978 $6,926 $0 $0 $19,653 $1,781 $983 $3,735 $26,152 $59

13 IMPROVEMENTS TO SITE $3,253 $1,917 $8,026 $0 $0 $13,196 $1,303 $0 $4,350 $18,849 $42

14 BUILDINGS & STRUCTURES $0 $6,276 $7,071 $0 $0 $13,347 $1,214 $0 $2,395 $16,957 $38

 

TOTAL COST $826,836 $69,854 $285,041 $0 $0 $1,181,731 $109,945 $61,790 $219,583 $1,573,049 $3,533

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

361

Exhibit 3-117 Case S3B Total Plant Cost Summary Details

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S3B - Siemens 445 MW IGCC w/ CO2

Plant Size: 445.3 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $4,178 $0 $2,042 $0 $0 $6,220 $557 $0 $1,355 $8,133 $18

1.2 Coal Stackout & Reclaim $5,399 $0 $1,309 $0 $0 $6,708 $588 $0 $1,459 $8,755 $20

1.3 Coal Conveyors & Yd Crush $5,020 $0 $1,295 $0 $0 $6,315 $554 $0 $1,374 $8,243 $19

1.4 Other Coal Handling $1,313 $0 $300 $0 $0 $1,613 $141 $0 $351 $2,105 $5

1.5 Sorbent Receive & Unload $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

1.7 Sorbent Conveyors $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

1.9 Coal & Sorbent Hnd.Foundations $0 $2,957 $7,393 $0 $0 $10,350 $992 $0 $2,268 $13,610 $31

SUBTOTAL 1. $15,911 $2,957 $12,339 $0 $0 $31,206 $2,833 $0 $6,808 $40,846 $92

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $48,294 $2,901 $7,037 $0 $0 $58,232 $5,025 $0 $12,651 $75,909 $170

2.2 Prepared Coal Storage & Feed $2,076 $497 $326 $0 $0 $2,899 $248 $0 $629 $3,776 $8

2.3 Dry Coal Injection System $68,331 $793 $6,346 $0 $0 $75,470 $6,500 $0 $16,394 $98,364 $221

2.4 Misc.Coal Prep & Feed $1,258 $915 $2,745 $0 $0 $4,918 $452 $0 $1,074 $6,444 $14

2.5 Sorbent Prep Equipment $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

2.7 Sorbent Injection System $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

2.9 Coal & Sorbent Feed Foundation $0 $4,889 $4,014 $0 $0 $8,903 $825 $0 $1,946 $11,674 $26

SUBTOTAL 2. $119,959 $9,996 $20,467 $0 $0 $150,422 $13,050 $0 $32,694 $196,166 $441

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $1,771 $3,041 $1,605 $0 $0 $6,417 $594 $0 $1,402 $8,413 $19

3.2 Water Makeup & Pretreating $553 $58 $309 $0 $0 $919 $88 $0 $302 $1,309 $3

3.3 Other Feedwater Subsystems $969 $327 $295 $0 $0 $1,591 $143 $0 $347 $2,080 $5

3.4 Service Water Systems $316 $651 $2,260 $0 $0 $3,227 $315 $0 $1,062 $4,604 $10

3.5 Other Boiler Plant Systems $1,697 $657 $1,629 $0 $0 $3,984 $378 $0 $872 $5,234 $12

3.6 FO Supply Sys & Nat Gas $286 $541 $504 $0 $0 $1,332 $128 $0 $292 $1,752 $4

3.7 Waste Treatment Equipment $772 $0 $471 $0 $0 $1,243 $121 $0 $409 $1,774 $4

3.8 Misc. Power Plant Equipment $1,029 $138 $529 $0 $0 $1,696 $164 $0 $558 $2,417 $5

SUBTOTAL 3. $7,393 $5,413 $7,602 $0 $0 $20,407 $1,931 $0 $5,245 $27,583 $62

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (Siemen $112,359 $0 $52,484 $0 $0 $164,843 $14,646 $24,727 $30,632 $234,848 $527

4.2 Syngas Cooling w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $184,152 $0 w/equip. $0 $0 $184,152 $17,850 $0 $20,200 $222,202 $499

4.4 LT Heat Recovery & FG Saturation $27,994 $0 $10,642 $0 $0 $38,636 $3,771 $0 $8,481 $50,887 $114

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,670 $680 $0 $0 $2,350 $225 $0 $515 $3,090 $7

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $11,150 $6,362 $0 $0 $17,512 $1,603 $0 $4,779 $23,894 $54

SUBTOTAL 4. $324,505 $12,820 $70,168 $0 $0 $407,493 $38,095 $24,727 $64,608 $534,921 $1,201

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

362

Exhibit 3-117 Case S3B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S3B - Siemens 445 MW IGCC w/ CO2

Plant Size: 445.3 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $70,593 $0 $59,900 $0 $0 $130,492 $12,620 $26,098 $33,842 $203,053 $456

5A.2 Elemental Sulfur Plant $5,067 $1,010 $6,537 $0 $0 $12,614 $1,225 $0 $2,768 $16,607 $37

5A.3 Mercury Removal $1,384 $0 $1,054 $0 $0 $2,438 $235 $122 $559 $3,354 $8

5A.4 Shift Reactors $7,189 $0 $2,894 $0 $0 $10,082 $967 $0 $2,210 $13,259 $30

5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.7 Fuel Gas Piping $0 $924 $647 $0 $0 $1,572 $146 $0 $344 $2,061 $5

5A.9 HGCU Foundations $0 $936 $604 $0 $0 $1,540 $141 $0 $504 $2,185 $5

SUBTOTAL 5A. $84,233 $2,870 $71,635 $0 $0 $158,738 $15,335 $26,220 $40,227 $240,519 $540

5B CO2 COMPRESSION

5B.1 CO2 Removal System w/5A.1 $0 w/5A.1 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $18,605 $0 $10,561 $0 $0 $29,166 $2,807 $0 $6,395 $38,368 $86

SUBTOTAL 5B. $18,605 $0 $10,561 $0 $0 $29,166 $2,807 $0 $6,395 $38,368 $86

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,610 $9,348 $9,861 $11,782 $129,600 $291

6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5

SUBTOTAL 6. $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $296

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $31,401 $0 $4,465 $0 $0 $35,866 $3,410 $0 $3,928 $43,204 $97

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,807 $1,322 $0 $0 $3,128 $275 $0 $681 $4,083 $9

7.4 Stack $3,524 $0 $1,324 $0 $0 $4,848 $464 $0 $531 $5,844 $13

7.9 HRSG,Duct & Stack Foundations $0 $706 $678 $0 $0 $1,384 $129 $0 $454 $1,967 $4

SUBTOTAL 7. $34,925 $2,513 $7,789 $0 $0 $45,227 $4,278 $0 $5,593 $55,098 $124

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $23,475 $0 $3,915 $0 $0 $27,390 $2,628 $0 $3,002 $33,019 $74

8.2 Turbine Plant Auxiliaries $162 $0 $371 $0 $0 $532 $52 $0 $58 $643 $1

8.3a Condenser & Auxiliaries $2,805 $0 $896 $0 $0 $3,701 $354 $0 $405 $4,460 $10

8.3b Air Cooled Condenser $25,704 $0 $5,153 $0 $0 $30,857 $3,086 $0 $6,788 $40,731 $91

8.4 Steam Piping $3,169 $0 $2,229 $0 $0 $5,398 $464 $0 $1,465 $7,327 $16

8.9 TG Foundations $0 $802 $1,356 $0 $0 $2,157 $205 $0 $709 $3,071 $7

SUBTOTAL 8. $55,314 $802 $13,919 $0 $0 $70,035 $6,788 $0 $12,428 $89,251 $200

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $5,403 $0 $983 $0 $0 $6,386 $608 $0 $1,049 $8,043 $18

9.2 Circulating Water Pumps $1,405 $0 $90 $0 $0 $1,495 $126 $0 $243 $1,864 $4

9.3 Circ.Water System Auxiliaries $122 $0 $17 $0 $0 $140 $13 $0 $23 $176 $0

9.4 Circ.Water Piping $0 $5,107 $1,324 $0 $0 $6,430 $581 $0 $1,402 $8,414 $19

9.5 Make-up Water System $311 $0 $445 $0 $0 $756 $73 $0 $166 $994 $2

9.6 Component Cooling Water Sys $603 $721 $513 $0 $0 $1,837 $172 $0 $402 $2,411 $5

9.9 Circ.Water System Foundations $0 $1,870 $3,179 $0 $0 $5,049 $479 $0 $1,658 $7,185 $16

SUBTOTAL 9. $7,844 $7,697 $6,551 $0 $0 $22,092 $2,052 $0 $4,943 $29,087 $65

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

363

Exhibit 3-117 Case S3B Total Plant Cost Summary Details (Continued) Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S3B - Siemens 445 MW IGCC w/ CO2

Plant Size: 445.3 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $18,925 $0 $9,333 $0 $0 $28,258 $2,715 $0 $3,097 $34,071 $77

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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

10.4 High Temperature Ash Piping $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

10.6 Ash Storage Silos $561 $0 $610 $0 $0 $1,170 $114 $0 $193 $1,477 $3

10.7 Ash Transport & Feed Equipment $752 $0 $181 $0 $0 $933 $87 $0 $153 $1,173 $3

10.8 Misc. Ash Handling Equipment $1,161 $1,423 $425 $0 $0 $3,009 $286 $0 $494 $3,790 $9

10.9 Ash/Spent Sorbent Foundation $0 $50 $62 $0 $0 $112 $11 $0 $37 $159 $0

SUBTOTAL 10. $21,399 $1,472 $10,612 $0 $0 $33,483 $3,213 $0 $3,974 $40,669 $91

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $870 $0 $861 $0 $0 $1,731 $165 $0 $190 $2,086 $5

11.2 Station Service Equipment $4,634 $0 $418 $0 $0 $5,052 $466 $0 $552 $6,069 $14

11.3 Switchgear & Motor Control $8,568 $0 $1,558 $0 $0 $10,126 $939 $0 $1,660 $12,725 $29

11.4 Conduit & Cable Tray $0 $3,980 $13,130 $0 $0 $17,110 $1,655 $0 $4,691 $23,456 $53

11.5 Wire & Cable $0 $7,604 $4,996 $0 $0 $12,601 $915 $0 $3,379 $16,895 $38

11.6 Protective Equipment $0 $611 $2,225 $0 $0 $2,837 $277 $0 $467 $3,581 $8

11.7 Standby Equipment $218 $0 $213 $0 $0 $431 $41 $0 $71 $543 $1

11.8 Main Power Transformers $16,429 $0 $130 $0 $0 $16,559 $1,252 $0 $2,672 $20,483 $46

11.9 Electrical Foundations $0 $141 $371 $0 $0 $512 $49 $0 $168 $729 $2

SUBTOTAL 11. $30,719 $12,337 $23,901 $0 $0 $66,958 $5,760 $0 $13,849 $86,566 $194

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,061 $0 $709 $0 $0 $1,770 $168 $88 $304 $2,330 $5

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $244 $0 $156 $0 $0 $400 $38 $20 $92 $550 $1

12.7 Computer & Accessories $5,661 $0 $181 $0 $0 $5,842 $536 $292 $667 $7,337 $16

12.8 Instrument Wiring & Tubing $0 $1,978 $4,043 $0 $0 $6,020 $511 $301 $1,708 $8,540 $19

12.9 Other I & C Equipment $3,784 $0 $1,837 $0 $0 $5,621 $529 $281 $965 $7,396 $17

SUBTOTAL 12. $10,750 $1,978 $6,926 $0 $0 $19,653 $1,781 $983 $3,735 $26,152 $59

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $102 $2,181 $0 $0 $2,283 $227 $0 $753 $3,263 $7

13.2 Site Improvements $0 $1,815 $2,412 $0 $0 $4,227 $417 $0 $1,393 $6,038 $14

13.3 Site Facilities $3,253 $0 $3,432 $0 $0 $6,685 $659 $0 $2,203 $9,548 $21

SUBTOTAL 13. $3,253 $1,917 $8,026 $0 $0 $13,196 $1,303 $0 $4,350 $18,849 $42

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1

14.2 Steam Turbine Building $0 $2,038 $2,903 $0 $0 $4,940 $455 $0 $809 $6,204 $14

14.3 Administration Building $0 $859 $623 $0 $0 $1,482 $132 $0 $242 $1,856 $4

14.4 Circulation Water Pumphouse $0 $158 $84 $0 $0 $241 $21 $0 $39 $302 $1

14.5 Water Treatment Buildings $0 $462 $451 $0 $0 $912 $82 $0 $149 $1,144 $3

14.6 Machine Shop $0 $440 $301 $0 $0 $740 $66 $0 $121 $927 $2

14.7 Warehouse $0 $710 $458 $0 $0 $1,168 $103 $0 $191 $1,462 $3

14.8 Other Buildings & Structures $0 $416 $324 $0 $0 $740 $66 $0 $161 $968 $2

14.9 Waste Treating Building & Str. $0 $930 $1,778 $0 $0 $2,708 $253 $0 $592 $3,553 $8

SUBTOTAL 14. $0 $6,276 $7,071 $0 $0 $13,347 $1,214 $0 $2,395 $16,957 $38

TOTAL COST $826,836 $69,854 $285,041 $0 $0 $1,181,731 $109,945 $61,790 $219,583 $1,573,049 $3,533

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

364

Exhibit 3-118 Case S3B Owner’s Costs

Owner's Costs $x1000 $/kW

Preproduction Costs

6 Months Fixed O&M $12,933 $29

1 Month Variable O&M $3,445 $8

25% of 1 Months Fuel Cost at 100% CF $805 $2

2% of TPC $31,461 $71

Total $48,644 $109

Inventory Capital

60 day supply of consumables at 100% CF $6,932 $16

0.5% of TPC (spare parts) $7,865 $18

Total $14,797 $33

 Initial Cost for Catalyst and Chemicals $6,922 $16

Land $900 $2

Other Owner's Costs $235,957 $530

Financing Costs $42,472 $95

Total Owner's Costs $349,692 $785

Total Overnight Cost (TOC) $1,922,741 $4,318

TASC Multiplier 1.140

Total As-Spent Cost (TASC) $2,191,925 $4,922
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

365

Exhibit 3-119 Case S3B Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun) 2007

Case S3B - Siemens 445 MW IGCC w/ CO2 Heat Rate-net(Btu/kWh): 11,151

MWe-net: 445

 Capacity Factor: (%): 80

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 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-O.J.'s 16.0 16.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $6,313,507 $14.178

Maintenance Labor Cost $14,379,765 $32.293

Administrative & Support Labor $5,173,318 $11.618

Property Taxes and Insurance $31,460,972 $70.653

TOTAL FIXED OPERATING COSTS $57,327,563 $128.742

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $27,449,429 $0.00880

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

Water (/1000 gallons) 0 2,898 1.08 $0 $915,331 $0.00029

Chemicals

MU & WT Chem.(lbs) 0 17,265 0.17 $0 $872,524 $0.00028

Carbon (Mercury Removal) (lb) 114,477 157 1.05 $120,220 $48,088 $0.00002

COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000

Water Gas Shift Catalyst (ft3) 6,049 4.14 498.83 $3,017,654 $603,531 $0.00019

Selexol Solution (gal) 282,412 90 13.40 $3,783,824 $351,466 $0.00011

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip. 0.76 131.27 $0 $29,144 $0.00001

Subtotal Chemicals $6,921,697 $1,904,753 $0.00061

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 157 0.42 $0 $19,098 $0.00001

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 587 16.23 $0 $2,781,394 $0.00089

Subtotal Waste Disposal $0 $2,800,492 $0.00090

By-products & Emissions 

Sulfur (tons) 0 50 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $6,921,697 $33,070,006 $0.01060

Fuel (ton) 0 6,958 15.22 $0 $30,914,533 $0.00991
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

366

Exhibit 3-120 Case L3B Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case L3B - Siemens 467 MW IGCC w/ CO2

Plant Size: 466.5 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING $19,450 $3,614 $15,084 $0 $0 $38,148 $3,463 $0 $8,322 $49,933 $107

 2 COAL & SORBENT PREP & FEED $145,819 $12,270 $24,711 $0 $0 $182,800 $15,856 $0 $39,731 $238,387 $511

 3 FEEDWATER & MISC. BOP SYSTEMS $7,616 $5,584 $7,820 $0 $0 $21,020 $1,989 $0 $5,401 $28,409 $61

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $112,359 $0 $52,484 $0 $0 $164,843 $14,646 $24,727 $30,632 $234,848 $503

4.2 Syngas Cooling (w/4.1) w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $198,687 $0 w/equip. $0 $0 $198,687 $19,259 $0 $21,795 $239,740 $514

4.4-4.9 Other Gasification Equipment $29,196 $14,523 $19,100 $0 $0 $62,820 $6,005 $0 $14,860 $83,686 $179

SUBTOTAL 4 $340,242 $14,523 $71,585 $0 $0 $426,350 $39,910 $24,727 $67,287 $558,274 $1,197

 5A Gas Cleanup & Piping $87,936 $3,020 $75,000 $0 $0 $165,956 $16,033 $27,288 $42,026 $251,303 $539

 5B CO2 REMOVAL & COMPRESSION $19,885 $0 $11,288 $0 $0 $31,173 $3,000 $0 $6,835 $41,008 $88

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,599 $278

6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5

SUBTOTAL 6 $92,026 $806 $7,475 $0 $0 $100,307 $9,507 $9,861 $12,339 $132,014 $283

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,635 $0 $4,640 $0 $0 $37,275 $3,544 $0 $4,082 $44,901 $96

7.2-7.9 Ductwork and Stack $3,526 $2,514 $3,326 $0 $0 $9,366 $869 $0 $1,667 $11,901 $26

SUBTOTAL 7 $36,161 $2,514 $7,966 $0 $0 $46,641 $4,413 $0 $5,749 $56,802 $122

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $24,841 $0 $4,166 $0 $0 $29,007 $2,783 $0 $3,179 $34,969 $75

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $33,661 $849 $10,539 $0 $0 $45,049 $4,396 $0 $9,950 $59,395 $127

SUBTOTAL 8 $58,502 $849 $14,705 $0 $0 $74,056 $7,179 $0 $13,129 $94,364 $202

 9 COOLING WATER SYSTEM $8,311 $8,092 $6,895 $0 $0 $23,298 $2,164 $0 $5,209 $30,671 $66

10 ASH/SPENT SORBENT HANDLING SYS $29,325 $1,943 $14,539 $0 $0 $45,807 $4,395 $0 $5,422 $55,625 $119

11 ACCESSORY ELECTRIC PLANT $32,486 $12,985 $25,133 $0 $0 $70,604 $6,071 $0 $14,599 $91,274 $196

12 INSTRUMENTATION & CONTROL $10,955 $2,015 $7,059 $0 $0 $20,029 $1,815 $1,001 $3,807 $26,653 $57

13 IMPROVEMENTS TO SITE $3,354 $1,977 $8,275 $0 $0 $13,606 $1,343 $0 $4,485 $19,434 $42

14 BUILDINGS & STRUCTURES $0 $6,418 $7,268 $0 $0 $13,685 $1,245 $0 $2,455 $17,385 $37

 

TOTAL COST $892,068 $76,612 $304,802 $0 $0 $1,273,481 $118,383 $62,877 $236,794 $1,691,536 $3,626

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

367

Exhibit 3-121 Case L3B Total Plant Cost Summary Details

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case L3B - Siemens 467 MW IGCC w/ CO2

Plant Size: 466.5 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $5,108 $0 $2,496 $0 $0 $7,604 $681 $0 $1,657 $9,942 $21

1.2 Coal Stackout & Reclaim $6,600 $0 $1,600 $0 $0 $8,201 $719 $0 $1,784 $10,703 $23

1.3 Coal Conveyors & Yd Crush $6,137 $0 $1,583 $0 $0 $7,720 $678 $0 $1,680 $10,077 $22

1.4 Other Coal Handling $1,606 $0 $366 $0 $0 $1,972 $173 $0 $429 $2,573 $6

1.5 Sorbent Receive & Unload $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

1.7 Sorbent Conveyors $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

1.9 Coal & Sorbent Hnd.Foundations $0 $3,614 $9,038 $0 $0 $12,652 $1,213 $0 $2,773 $16,638 $36

SUBTOTAL 1. $19,450 $3,614 $15,084 $0 $0 $38,148 $3,463 $0 $8,322 $49,933 $107

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $59,809 $3,593 $8,715 $0 $0 $72,116 $6,223 $0 $15,668 $94,007 $202

2.2 Prepared Coal Storage & Feed $2,833 $678 $444 $0 $0 $3,955 $338 $0 $859 $5,152 $11

2.3 Dry Coal Injection System $81,811 $949 $7,598 $0 $0 $90,358 $7,782 $0 $19,628 $117,768 $252

2.4 Misc.Coal Prep & Feed $1,367 $995 $2,983 $0 $0 $5,344 $491 $0 $1,167 $7,003 $15

2.5 Sorbent Prep Equipment $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

2.7 Sorbent Injection System $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

2.9 Coal & Sorbent Feed Foundation $0 $6,055 $4,971 $0 $0 $11,026 $1,021 $0 $2,409 $14,457 $31

SUBTOTAL 2. $145,819 $12,270 $24,711 $0 $0 $182,800 $15,856 $0 $39,731 $238,387 $511

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 FeedwaterSystem $1,829 $3,141 $1,658 $0 $0 $6,627 $614 $0 $1,448 $8,689 $19

3.2 Water Makeup & Pretreating $566 $59 $316 $0 $0 $942 $90 $0 $309 $1,341 $3

3.3 Other Feedwater Subsystems $1,001 $338 $304 $0 $0 $1,643 $148 $0 $358 $2,149 $5

3.4 Service Water Systems $324 $667 $2,315 $0 $0 $3,306 $323 $0 $1,089 $4,717 $10

3.5 Other Boiler Plant Systems $1,738 $674 $1,669 $0 $0 $4,081 $387 $0 $894 $5,362 $11

3.6 FO Supply Sys & Nat Gas $298 $563 $525 $0 $0 $1,385 $133 $0 $304 $1,823 $4

3.7 Waste Treatment Equipment $791 $0 $483 $0 $0 $1,274 $124 $0 $419 $1,817 $4

3.8 Misc. Power Plant Equipment $1,069 $143 $549 $0 $0 $1,761 $170 $0 $579 $2,511 $5

SUBTOTAL 3. $7,616 $5,584 $7,820 $0 $0 $21,020 $1,989 $0 $5,401 $28,409 $61

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (Siemens $112,359 $0 $52,484 $0 $0 $164,843 $14,646 $24,727 $30,632 $234,848 $503

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $198,687 $0 w/equip. $0 $0 $198,687 $19,259 $0 $21,795 $239,740 $514

4.4 LT Heat Recovery & FG Saturation $29,196 $0 $11,099 $0 $0 $40,295 $3,933 $0 $8,846 $53,073 $114

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,744 $710 $0 $0 $2,454 $235 $0 $538 $3,227 $7

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $12,779 $7,292 $0 $0 $20,071 $1,837 $0 $5,477 $27,385 $59

SUBTOTAL 4. $340,242 $14,523 $71,585 $0 $0 $426,350 $39,910 $24,727 $67,287 $558,274 $1,197

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

368

Exhibit 3-121 Case L3B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case L3B - Siemens 467 MW IGCC w/ CO2

Plant Size: 466.5 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $73,469 $0 $62,340 $0 $0 $135,809 $13,134 $27,162 $35,221 $211,325 $453

5A.2 Elemental Sulfur Plant $5,695 $1,135 $7,347 $0 $0 $14,177 $1,377 $0 $3,111 $18,665 $40

5A.3 Mercury Removal $1,435 $0 $1,092 $0 $0 $2,527 $244 $126 $579 $3,476 $7

5A.4 Shift Reactors $7,337 $0 $2,953 $0 $0 $10,291 $987 $0 $2,255 $13,533 $29

5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.7 Fuel Gas Piping $0 $937 $656 $0 $0 $1,593 $148 $0 $348 $2,089 $4

5A.9 HGCU Foundations $0 $949 $612 $0 $0 $1,560 $143 $0 $511 $2,215 $5

SUBTOTAL 5A. $87,936 $3,020 $75,000 $0 $0 $165,956 $16,033 $27,288 $42,026 $251,303 $539

5B CO2 COMPRESSION

5B.1 CO2 Removal System (w/5A.1) w/5A.1 $0 w/5A.1 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $19,885 $0 $11,288 $0 $0 $31,173 $3,000 $0 $6,835 $41,008 $88

SUBTOTAL 5B. $19,885 $0 $11,288 $0 $0 $31,173 $3,000 $0 $6,835 $41,008 $88

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,599 $278

6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5

SUBTOTAL 6. $92,026 $806 $7,475 $0 $0 $100,307 $9,507 $9,861 $12,339 $132,014 $283

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,635 $0 $4,640 $0 $0 $37,275 $3,544 $0 $4,082 $44,901 $96

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,808 $1,322 $0 $0 $3,130 $275 $0 $681 $4,086 $9

7.4 Stack $3,526 $0 $1,325 $0 $0 $4,851 $465 $0 $532 $5,847 $13

7.9 HRSG,Duct & Stack Foundations $0 $706 $679 $0 $0 $1,385 $129 $0 $454 $1,968 $4

SUBTOTAL 7. $36,161 $2,514 $7,966 $0 $0 $46,641 $4,413 $0 $5,749 $56,802 $122

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $24,841 $0 $4,166 $0 $0 $29,007 $2,783 $0 $3,179 $34,969 $75

8.2 Turbine Plant Auxiliaries $171 $0 $392 $0 $0 $563 $55 $0 $62 $680 $1

8.3a Condenser & Auxiliaries $2,973 $0 $950 $0 $0 $3,923 $375 $0 $430 $4,728 $10

8.3b Air Cooled Condenser $27,249 $0 $5,463 $0 $0 $32,711 $3,271 $0 $7,197 $43,179 $93

8.4 Steam Piping $3,268 $0 $2,299 $0 $0 $5,567 $478 $0 $1,511 $7,557 $16

8.9 TG Foundations $0 $849 $1,435 $0 $0 $2,284 $216 $0 $750 $3,250 $7

SUBTOTAL 8. $58,502 $849 $14,705 $0 $0 $74,056 $7,179 $0 $13,129 $94,364 $202

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $5,744 $0 $1,045 $0 $0 $6,789 $646 $0 $1,115 $8,551 $18

9.2 Circulating Water Pumps $1,488 $0 $98 $0 $0 $1,586 $134 $0 $258 $1,977 $4

9.3 Circ.Water System Auxiliaries $129 $0 $18 $0 $0 $147 $14 $0 $24 $185 $0

9.4 Circ.Water Piping $0 $5,364 $1,391 $0 $0 $6,754 $610 $0 $1,473 $8,838 $19

9.5 Make-up Water System $318 $0 $454 $0 $0 $772 $74 $0 $169 $1,015 $2

9.6 Component Cooling Water Sys $633 $757 $539 $0 $0 $1,929 $181 $0 $422 $2,532 $5

9.9 Circ.Water System Foundations $0 $1,971 $3,350 $0 $0 $5,321 $504 $0 $1,748 $7,573 $16

SUBTOTAL 9. $8,311 $8,092 $6,895 $0 $0 $23,298 $2,164 $0 $5,209 $30,671 $66

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

369

Exhibit 3-121 Case L3B Total Plant Cost Summary Details (Continued) Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case L3B - Siemens 467 MW IGCC w/ CO2

Plant Size: 466.5 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $26,061 $0 $12,852 $0 $0 $38,912 $3,739 $0 $4,265 $46,916 $101

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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

10.4 High Temperature Ash Piping $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

10.6 Ash Storage Silos $740 $0 $805 $0 $0 $1,545 $150 $0 $254 $1,949 $4

10.7 Ash Transport & Feed Equipment $992 $0 $239 $0 $0 $1,232 $115 $0 $202 $1,548 $3

10.8 Misc. Ash Handling Equipment $1,532 $1,878 $561 $0 $0 $3,971 $378 $0 $652 $5,001 $11

10.9 Ash/Spent Sorbent Foundation $0 $65 $82 $0 $0 $148 $14 $0 $48 $210 $0

SUBTOTAL 10. $29,325 $1,943 $14,539 $0 $0 $45,807 $4,395 $0 $5,422 $55,625 $119

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $904 $0 $894 $0 $0 $1,797 $172 $0 $197 $2,166 $5

11.2 Station Service Equipment $4,879 $0 $440 $0 $0 $5,319 $490 $0 $581 $6,390 $14

11.3 Switchgear & Motor Control $9,020 $0 $1,640 $0 $0 $10,661 $989 $0 $1,747 $13,397 $29

11.4 Conduit & Cable Tray $0 $4,190 $13,823 $0 $0 $18,014 $1,742 $0 $4,939 $24,695 $53

11.5 Wire & Cable $0 $8,006 $5,260 $0 $0 $13,267 $964 $0 $3,558 $17,788 $38

11.6 Protective Equipment $0 $641 $2,332 $0 $0 $2,973 $290 $0 $490 $3,753 $8

11.7 Standby Equipment $225 $0 $219 $0 $0 $444 $42 $0 $73 $559 $1

11.8 Main Power Transformers $17,458 $0 $136 $0 $0 $17,594 $1,330 $0 $2,839 $21,763 $47

11.9 Electrical Foundations $0 $148 $388 $0 $0 $535 $51 $0 $176 $763 $2

SUBTOTAL 11. $32,486 $12,985 $25,133 $0 $0 $70,604 $6,071 $0 $14,599 $91,274 $196

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,081 $0 $722 $0 $0 $1,804 $171 $90 $310 $2,374 $5

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $249 $0 $159 $0 $0 $408 $39 $20 $93 $560 $1

12.7 Computer & Accessories $5,769 $0 $185 $0 $0 $5,954 $546 $298 $680 $7,478 $16

12.8 Instrument Wiring & Tubing $0 $2,015 $4,120 $0 $0 $6,135 $520 $307 $1,741 $8,703 $19

12.9 Other I & C Equipment $3,856 $0 $1,873 $0 $0 $5,729 $539 $286 $983 $7,538 $16

SUBTOTAL 12. $10,955 $2,015 $7,059 $0 $0 $20,029 $1,815 $1,001 $3,807 $26,653 $57

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $105 $2,249 $0 $0 $2,354 $234 $0 $776 $3,364 $7

13.2 Site Improvements $0 $1,872 $2,487 $0 $0 $4,359 $430 $0 $1,437 $6,225 $13

13.3 Site Facilities $3,354 $0 $3,539 $0 $0 $6,893 $680 $0 $2,272 $9,844 $21

SUBTOTAL 13. $3,354 $1,977 $8,275 $0 $0 $13,606 $1,343 $0 $4,485 $19,434 $42

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1

14.2 Steam Turbine Building $0 $2,135 $3,042 $0 $0 $5,177 $476 $0 $848 $6,501 $14

14.3 Administration Building $0 $859 $623 $0 $0 $1,482 $132 $0 $242 $1,856 $4

14.4 Circulation Water Pumphouse $0 $161 $85 $0 $0 $247 $22 $0 $40 $308 $1

14.5 Water Treatment Buildings $0 $473 $462 $0 $0 $935 $84 $0 $153 $1,172 $3

14.6 Machine Shop $0 $440 $301 $0 $0 $740 $66 $0 $121 $927 $2

14.7 Warehouse $0 $710 $458 $0 $0 $1,168 $103 $0 $191 $1,462 $3

14.8 Other Buildings & Structures $0 $425 $331 $0 $0 $756 $68 $0 $165 $988 $2

14.9 Waste Treating Building & Str. $0 $950 $1,816 $0 $0 $2,766 $258 $0 $605 $3,629 $8

SUBTOTAL 14. $0 $6,418 $7,268 $0 $0 $13,685 $1,245 $0 $2,455 $17,385 $37

TOTAL COST $892,068 $76,612 $304,802 $0 $0 $1,273,481 $118,383 $62,877 $236,794 $1,691,536 $3,626

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

370

Exhibit 3-122 Case L3B Owner’s Costs

Owner's Costs $x1000 $/kW

Preproduction Costs

6 Months Fixed O&M $13,411 $29

1 Month Variable O&M $3,766 $8

25% of 1 Months Fuel Cost at 100% CF $799 $2

2% of TPC $33,831 $73

Total $51,807 $111

Inventory Capital

60 day supply of consumables at 100% CF $6,910 $15

0.5% of TPC (spare parts) $8,458 $18

Total $15,368 $33

 Initial Cost for Catalyst and Chemicals $7,452 $16

Land $900 $2

Other Owner's Costs $253,730 $544

Financing Costs $45,671 $98

Total Owner's Costs $374,928 $804

Total Overnight Cost (TOC) $2,066,464 $4,430

TASC Multiplier 1.140

Total As-Spent Cost (TASC) $2,355,769 $5,050
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

371

Exhibit 3-123 Case L3B Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case L3B - Siemens 467 MW IGCC w/ CO2 Heat Rate-net (Btu/kWh): 11,371

MWe-net: 467

Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 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-O.J.'s 16.0 16.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $6,313,507 $13.533

Maintenance Labor Cost $15,143,762 $32.462

Administrative & Support Labor $5,364,317 $11.499

Property Taxes and Insurance $33,830,718 $72.519

TOTAL FIXED OPERATING COSTS $60,652,304 $130.013

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $28,595,428 $0.00875

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

Water (/1000 gallons) 0 2,999 1.08 $0 $947,169 $0.00029

Chemicals

MU & WT Chem. (lb) 0 17,866 0.17 $0 $902,873 $0.00028

Carbon (Mercury Removal) (lb) 120,179 165 1.05 $126,208 $50,483 $0.00002

COS Catalyst (lb) 0 0 2,397.36 $0 $0 $0.00000

Water Gas Shift Catalyst (ft3) 6,395 4.38 498.83 $3,190,190 $638,038 $0.00020

Selexol Solution (gal) 308,653 98 13.40 $4,135,407 $384,552 $0.00012

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip. 0.89 131.27 $0 $34,196 $0.00001

Subtotal Chemicals $7,451,805 $2,010,143 $0.00061

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 165 0.42 $0 $20,050 $0.00001

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 968 16.23 $0 $4,585,247 $0.00140

Subtotal Waste Disposal $0 $4,605,296 $0.00141

By-products & Emissions 

Sulfur (tons) 0 60 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $7,451,805 $36,158,036 $0.01106

Fuel (ton) 0 9,620 10.92 $0 $30,672,715 $0.00938
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

372

3.5 COP E-GASTM IGCC CASES

This section contains an evaluation of plant designs for Cases S4A and S4B, which are based on 

the E-GasTM gasifier, developed by CoP. The non-capture (A) and CO2 capture (B) cases are 

very similar in terms of process, equipment, scope and arrangement, except that CO2 capture 

cases includes SGS reactors, CO2 absorption/regeneration and compression/transport systems. 

Section 3.5.4 covers the results for the S4A non-capture case using PRB coal and Section 3.5.8

covers the S4B CO2-capture case using PRB coal. The sections are organized analogously as 

follows:

• Process and System Description provides an overview of the specific technology’s

operation.

• BFD and stream table display results for major processes and streams

• Performance Results provides the main modeling results, including the performance 

summary, environmental performance, carbon balance, sulfur balance, water balance, 

mass and energy balance diagrams, and mass and energy balance tables.

• Equipment List provides an itemized list of major equipment with account codes that 

correspond to the cost accounts in the Cost Estimates section.

• Cost Estimates provides a summary of capital and operating costs.

Process and System Description, Performance Results, Equipment List and Cost Estimates are 

repeated for Case S4B in Section 3.5.8. If the information is identical to that presented for the 

non-capture cases, a reference is made to the earlier section rather than repeating the information.

3.5.1 Gasifier Background

Development and Current Status – The CoP E-GasTM technology was first developed by Dow 

Chemical (the former principal stockholder of Destec Energy, which was bought by Global 

Energy, Inc., the gasifier business that was later purchased by CoP) who is a major producer of 

chemicals. They began coal gasification development work in 1976 with bench-scale (2 kg/hr

[4 lb/hr]) reactor testing. Important fundamental data were obtained for conversion and yields 

with various coals and operating conditions. This work led to the construction of a pilot plant at 

Dow’s large chemical complex in Plaquemine, Louisiana. The pilot plant was designed for a 

capacity of 11 tonnes/day (12 tpd) (dry lignite basis) and was principally operated with air as the 

oxidant. The plant also operated with oxygen at an increased capacity of 33 tonnes/day (36 tpd) 

(dry lignite basis). This pilot plant operated from 1978 through 1983.

Following successful operation of the pilot plant, Dow built a larger 499 tonnes/day (550 tpd) 

(dry lignite basis) gasifier at Plaquemine. In 1984, Dow Chemical and the U.S. Synthetic Fuels 

Corporation (SFC) announced a price guarantee contract, which allowed the building of the first 

commercial-scale Dow coal gasification unit. The Louisiana Gasification Technology, Inc. 

(LGTI) plant, sometimes called the Dow Syngas Project, was also located in the Dow 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

373

Plaquemine chemical complex. The plant gasified about 1,451 tonnes/day (1,600 tpd) (dry basis) 

of subbituminous coal to generate 184 MW (gross) of combined-cycle electricity utilizing a 

Westinghouse D-Class CT.. To ensure continuous power output to the petrochemical complex, a 

minimum of 20 percent of natural gas was co-fired with the syngas. LGTI was operated from 

1987 through 1995.

In September 1991, DOE selected the Wabash River coal 

gasification repowering project, which used the Destec Energy 

process, for funding under the Clean Coal Technology 

Demonstration Program. The project was a joint venture of 

Destec and Public Service of Indiana (PSI Energy, Inc.). Its 

purpose was to repower a unit at PSI’s Wabash River station in 

West Terre Haute, Indiana to produce 265 MW of net power 

from local high-sulfur bituminous coal. The design of the 

project gasifier was based on the Destec LGTI gasifier. 

Experience gained in that project provided significant input to 

the design of the Wabash River coal gasification facility and 

eliminated much of the risk associated with scale-up and process 

variables. 

Gasifier Capacity –The daily coal-handling capacity of the EGasTM gasifier operating at Plaquemine was in the range of 1,270 

tonnes (1,400 tons) (moisture/ash-free [MAF] basis) for 

bituminous coal to 1,497 tonnes (1,650 tons) for lignite. The dry 

gas production rate was 141,600 Nm3

/hr (5 million scf/hr) with 

an energy content of about 1,370 MMkJ/hr (1,300 MMBtu/hr) 

(HHV). The daily coal-handling capacity of the gasifier at 

Wabash River is about 1,680 tonnes (1,850 tons) (MAF basis) 

for high-sulfur bituminous coal. The dry gas production rate is 

about 189,720 Nm3/hr (6.7 million scf/hr) with an energy 

content of about 1,950 MMkJ/hr (1,850 MMBtu/hr) (HHV). 

This size matches the CT, which is a GE 7FA.

Gasifier sizing for this study was limited, per CoP recommendation, to 130 percent of the 

Wabash gasifier, as the maximum scale-up for a demonstrated commercial design resulting in a 

maximum gasifier throughput of around 4,000 tpd of as-received coal, depending on the 

feedstock, resulting in 2 gasifier trains for both cases.

Distinguishing Characteristics - The CoP E-GasTM gasifier is a slurry feed, entrained flow, 

slagging, two-stage gasifier producing syngas at high pressures and high temperatures, which is 

quenched using a coal slurry, offering additional operational flexibility and the ability to tune the 

gasifier for different applications. Slurry feed of the coal eliminates the need to dry the coal and 

simplifies the feed system for the coal. The gasifier portion of the reactor is refractory lined, 

requiring periodic maintenance. The fire-tube SGC used by E-GasTM has a lower capital cost 

than a water-tube design. 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

374

Relative disadvantages of the CoP coal gasification technology are the relatively short refractory 

life and the high waste heat recovery (SGC) duty, as with the other entrained-flow slagging 

gasifiers. These disadvantages result from high operating temperature although the syngas exits 

the gasifier at lower temperatures compared to dry feed gasifiers due to the slurry quench. The 

upper stage slurry quench helps to increase the calorific value of the resulting syngas and the 

gasifier CGE, which results in a quenched syngas that is higher in methane (CH4) content than 

other dry feed gasifiers. Special gasifier tuning by the vendor can adjust the composition of the 

syngas to achieve the desired end application, be it power or chemicals production, optimized 

towards high efficiency or low methane for carbon removal. Although high efficiency is 

generally desired, the associated high methane content will require a tradeoff in order to capture 

90 percent of the overall carbon since the AGR process does not capture the carbon from the 

methane in the syngas.

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 E-GasTM coal gasification process. High ash levels 

increase the ratio of water to carbon in the coal in the feed slurry, thereby increasing the oxygen 

requirements. Soluble salts affect the processing cost and amount of water blowdown required 

to avoid problems associated with excessive buildup of salts in the slurry water recycle loop.

An advantage of the CoP coal gasification technology is the current operating experience with 

subbituminous coal at full commercial scale at the Plaquemine plant and bituminous coal at the 

Wabash plant. Bituminous coals with lower inherent moisture improve the slurry concentration 

and reduce oxygen requirements. The two-stage operation reduces the negative impact of lowrank coal use in slurry feed, entrained-flow gasification. Low to moderate ash fusiontemperature coals are preferred for slagging gasifiers. Coals with high ash fusion temperatures 

may require flux addition for optimal gasification operation.

3.5.2 Key System Assumptions

System assumptions for Cases S4A and S4B CoP E-GasTM IGCC using PRB coal, with and 

without CO2 capture, are compiled in Exhibit 3-124.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

375

Exhibit 3-124 Case S4A and S4B Plant Study Configuration Matrix

Case S4A S4B

Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O2:Coal Ratio, kg O2/kg dry coal 0.907 0.917

Carbon Conversion, % 99.1 99.1

Syngas HHV at Gasifier Outlet, 

kJ/Nm3 (Btu/scf) 6,027 (162) 5,878 (158)

Nominal Steam Cycle, MPa/°C/°C 

(psig/°F/°F)

12.4/566/566 

(1,800/1,050/1,050)

12.4/538/538 

(1,800/1,000/1,000)

Condenser Pressure, mm Hg

(in Hg) 36 (1.4) 36 (1.4)

Combustion Turbine

2x Advanced F Class 

(Nominal 232 MW output 

each, reduced by elevation 

considerations)

2x Advanced F Class 

(Nominal 232 MW output 

each, reduced by elevation 

considerations)

Gasifier Technology CoP E-GasTM CoP E-GasTM

Oxidant 95 vol% Oxygen 95 vol% Oxygen

Coal Subbituminous Subbituminous

Coal Slurry Solids Content, % 50 49

COS Hydrolysis Yes Yes (Part of WGS)

Water Gas Shift No Yes

H2S Separation MDEA Selexol (1st Stage)

Sulfur Removal, % 99.9 99.8

CO2 Separation None Selexol (2nd Stage)

CO2 Removal, % N/A 90

Sulfur Recovery

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Particulate Control Cyclone, Candle Filter,

and AGR Absorber

Cyclone, Candle Filter, and 

AGR Absorber

Mercury Control Carbon Bed Carbon Bed

NOx Control MNQC (LNB) and N2

Dilution 

MNQC (LNB) and N2

Dilution
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

376

Balance of Plant – All Cases

The balance of plant assumptions are common to all cases and are presented in Exhibit 3-125.

Exhibit 3-125 Balance of Plant Assumptions

Cooling water system Recirculating Wet Cooling Tower

Fuel and Other storage

Coal 30 days

Slag 30 days

Sulfur 30 days

Sorbent 30 days

Plant Distribution Voltage

Motors below 1 hp 110/220 volt

Motors between 1 hp and 

250 hp 480 volt

Motors between 250 hp and 

5,000 hp 4,160 volt

Motors above 5,000 hp 13,800 volt

Steam and CT Generators 24,000 volt

Grid Interconnection Voltage 345 kV

Water and Waste Water

Makeup Water

The water supply is 50 percent from a local POTW

and 50 percent from groundwater, and is assumed to 

be in sufficient quantities to meet plant makeup 

requirements.

Makeup for potable, process, and DI water is drawn 

from municipal sources

Process Wastewater

Water associated with gasification activity and storm 

water that contacts equipment surfaces is collected 

and treated for discharge through a permitted 

discharge.

Sanitary Waste Disposal

Design includes a packaged domestic sewage 

treatment plant with effluent discharged to the 

industrial wastewater treatment system. Sludge is 

hauled off site. Packaged plant was sized for 5.68 

cubic meters per day (1,500 GPD)

Water Discharge

Most of the process wastewater is recycled to the 

cooling tower basin. Blowdown is treated for 

chloride and metals, and discharged.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

377

3.5.3 Sparing Philosophy

The sparing philosophy for Cases S4A and S4B is provided below. Single trains are utilized 

throughout with exceptions where equipment capacity requires an additional train. There is no 

redundancy other than normal sparing of rotating equipment.

The plant design consists of the following major subsystems:

• Two ASUs (2 x 50%).

• Two trains of coal drying and dry feed systems (2 x 50%).

• Two trains of gasification, including gasifier, SGC, cyclone, and barrier filter (2 x 50%). 

• Two trains of syngas clean-up process (2 x 50%).

• Two trains of MDEA acid gas removal in non-capture cases and two trains of two-stage 

Selexol in CO2 capture cases (2 x 50%).

• One train of Claus-based sulfur recovery (1 x 100%). 

• Two CT/HRSG tandems (2 x 50%).

• One steam turbine (1 x 100%).

3.5.4 CoP E-GasTM IGCC Non-Capture Case (S4A) Process Description

In this section the overall CoP E-GasTM gasification process for Case S4A is described. The 

system description follows the BFD in Exhibit 3-126. The tables in Exhibit 3-127 provide 

process data for the numbered streams in the BFD for the PRB case (S4A).

Coal Preparation and Feed Systems

Coal receiving and handling is common to all cases and generally described in Section 3.1.1. 

For the CoP E-GasTM slurry fed gasifier, coal from the coal silo is fed onto a conveyor by 

vibratory feeders located below each silo. The conveyor feeds the coal to an inclined conveyor 

that delivers the coal to the rod mill feed hopper. The feed hopper provides a surge capacity of 

about two hours and contains two hopper outlets. Each hopper outlet discharges onto a weigh 

feeder, which in turn feeds a rod mill. Each rod mill is sized to process 55 percent of the coal 

feed requirements of the gasifier. The rod mill grinds the coal and wets it with treated slurry 

water transferred from the slurry water tank by the slurry water pumps. The coal slurry is 

discharged through a trammel screen into the rod mill discharge tank, and then the slurry is 

pumped to the slurry storage tanks. The coal is prepared into a slurry with approximately 

50 percent solids and is injected in both the oxidizing and reducing portions of the E-GasTM

gasifier, referred to as the full slurry quench, tuned by CoP to achieve high CGE.

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 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

378

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).

Gasifier

The CoP E-GasTM gasifier is a two-stage, entrained-flow, slurry-fed gasifier. The coal is fed to 

the gasifier as in the full slurry quench configuration, maximizing CGE. The slurry feed and 

quench configuration removes the need for coal drying and also causes lower syngas exit 

temperatures compared to dry feed gasifiers. Oxygen injection is scaled from the coal feed 

resulting in a gasifier exit temperature of around 1,900o

F. Roughly 20 percent of the cleaned 

syngas is recycled to the gasifier to moderate the temperature and aid in transport. The predicted 

raw gas composition and gasifier performance is based on published data and was refined with 

specific vendor quotes by adjusting the gasification reaction’s equilibrium approach 

temperatures.

The two parallel CoP E-GasTM gasifiers operate at 4.2 MPa (615 psia) and process a total of

7,144 tonne/day (7,875 tpd) of as-received PRB. The oxygen is used to gasify a portion of the 

slurry in the horizontal cylinder portion with two horizontally opposed burners. The highly 

exothermic gasification/oxidation reactions take place rapidly at high temperatures of 1,316 to

1,427°C (2,400 to 2,600°F). The hot raw gas from the first stage enters the second (top) stage, 

which is a vertical cylinder perpendicular to the first stage. The remaining coal slurry is injected 

into this hot raw gas. The endothermic gasification/devolatilization reaction in this stage reduces 

the final gas temperature to about 1,038°C (1,900°F). 

Raw Gas Cooling/Particulate Removal

High-temperature heat recovery in each gasifier train is performed by raw gas coolers in three 

sections, a superheater, an evaporator, and an economizer, which lower the raw gas temperature 

from 1,038°C (1,900°F) to 337°C (638°F). After passing through the raw gas coolers, the syngas 

passes through a cyclone and a raw gas candle filter where a majority of the fine particles are 

removed and returned to the gasifier using recycled syngas. The filter consists of an array of 

ceramic candle elements in a pressure vessel. Fines produced by the gasification system are 

recirculated to extinction. The ash that is not carried out with the gas forms slag and exits the 

gasifier in liquid form. The slag is solidified in a quench tank for disposal. 

Sour Water Stripper

Water condensed during the cooling of the raw gas, along with all other sour water from the 

plant are sent to the sour water stripper, which removes NH3, SO2, and other impurities from the 

waste stream. The sour gas stripper consists of a sour drum that accumulates sour water that 

flows to the sour stripper, which consists of a packed column with a steam-heated reboiler. Sour 

gas is stripped from the liquid and sent to the SRU. Remaining water is sent to wastewater 

treatment.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

379

COS Hydrolysis, Mercury Removal and AGR

H2S and COS are at significant concentrations, requiring removal for the power plant to achieve 

the low design level of SO2 emissions. H2S is removed in an AGR process; however, because 

COS is not readily removed, it is first catalytically converted to H2S in a COS hydrolysis unit.

The cooled raw gas is fed to the COS hydrolysis reactor where the COS in the sour gas is 

hydrolyzed with steam, over a catalyst bed, into H2S, which is more easily removed by the AGR 

solvent. Before the raw fuel gas can be treated in the AGR process, it must be cooled to about 

35°C (95°F). During this cooling through a series of heat exchangers, part of the water vapor 

condenses. This water, which contains some NH3, is sent to the sour water stripper. The cooled 

syngas then passes through a carbon bed to remove 95 percent of the Hg.

Cool, particulate-free synthesis gas enters the MDEA absorber unit at approximately 3.7 MPa 

(535 psia) and 35°C (95°F). This AGR system was chosen to mimic the current Wabash CoP EGasTM IGCC installation, as a proven commercial offering. In the absorber, H2S is preferentially 

removed from the fuel gas stream by contact with MDEA. The stripper acid gas stream, 

consisting of 7 percent H2S and 91 percent CO2, is sent to the Claus unit. The acid gas is 

combined with the sour water stripper off gas and introduced into the Claus plant burner section.

Claus Unit

The SRU is a Claus bypass type SRU utilizing oxygen instead of air. The Claus plant produces 

molten sulfur by converting approximately one third of the H2S in the feed to SO2, then reacting 

the H2S and SO2 to sulfur and water. The combination of Claus technology and tail gas recycle 

results in an overall sulfur recovery exceeding 99 percent, producing 52 tonne/day (57 tpd) of 

sulfur.

Utilizing oxygen instead of air in the Claus plant reduces the overall cost of the sulfur recovery 

plant. Feed for each case consists of acid gas from both the acid gas cleanup unit and a vent 

stream from the sour water stripper in the gasifier section.

In the furnace waste heat boiler steam is generated. This steam is used to satisfy all Claus 

process preheating and reheating requirements, as well as to provide some steam to the mediumpressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) steam for the LP

steam header.

Power Block

Clean syngas exiting the MDEA absorber is reheated, diluted with nitrogen from the ASU, and 

enters the advanced F Class CT burner. The CT compressor provides combustion air to the 

burner and a portion of the air requirements for the ASU. The exhaust gas exits the CT at 586°C 

(1,087°F) and enters the HRSG where additional heat is recovered until the flue gas exits the 

HRSG at 132°C (270°F) and is discharged through the plant stack. The steam generated in the 

HRSG is used to power a steam turbine using a nominal 12.4 MPa/566°C/566°C (1800 

psig/1050°F/1050°F) steam cycle.

Air Separation Unit

The ASU is designed to produce approximately 5,212 tonne/day (5,746 tpd) of 95 mole percent 

O2 for use in the gasifier and SRU. The plant is designed with two production trains. The air 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

380

compressor is powered by an electric motor. Nitrogen is also recovered, compressed, and used 

as dilution in the CT combustor or as a coal transport fluid. Air extraction is taken from the CT

compressor to reduce the size of the main air compressor.

Balance of Plant

Balance of plant items were covered in Sections 3.1.12, 3.1.13, 3.1.14, and 3.1.15.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

381

Exhibit 3-126 Case S4A Process Flow Diagram
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

382

Exhibit 3-127 Case S4A Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

Ar 0.0093 0.0094 0.0052 0.0319 0.0021 0.0360 0.0000 0.0000 0.0000 0.0114 0.0000 0.0082 0.0080 0.0080

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0161 0.0000 0.0116 0.0113 0.0113

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3235 0.0000 0.2329 0.2264 0.2264

CO2 0.0003 0.0003 0.0010 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2450 0.0000 0.1765 0.1717 0.1717

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0001 0.0001 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2625 0.3080 0.0000 0.2217 0.2156 0.2156

H2O 0.0064 0.0104 0.0211 0.0000 0.0002 0.0000 0.0000 0.9973 0.6778 0.0833 0.0000 0.3381 0.3563 0.3562

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0031 0.0000 0.0022 0.0022 0.0022

N2 0.7759 0.7722 0.9429 0.0178 0.9927 0.0140 0.0000 0.0000 0.0040 0.0048 0.0000 0.0035 0.0034 0.0034

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0027 0.0012 0.0048 0.0000 0.0053 0.0051 0.0051

O2 0.2081 0.2077 0.0297 0.9503 0.0049 0.9500 0.0000 0.0000 0.0544 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 26,378 6,059 10,801 97 14,950 6,641 0 8,671 19,040 1,582 0 31,402 30,031 30,031

V-L Flowrate (kg/hr) 762,198 174,817 302,410 3,137 419,453 214,047 0 156,182 278,273 36,401 0 678,578 645,989 645,989

Solids Flowrate (kg/hr) 0 0 0 0 0 0 297,660 0 175,569 0 25,712 0 0 0

Temperature (°C) 6 411 15 32 93 32 6 171 149 174 1,038 1,023 232 232

Pressure (MPa, abs) 0.09 1.43 0.11 0.86 2.65 0.86 0.09 5.10 5.10 5.52 4.24 4.24 4.07 4.00

Enthalpy (kJ/kg)A 15.26 441.49 33.48 26.67 92.33 26.59 --- 674.86 --- 394.70 --- 2,466.99 1,081.69 1,081.63

Density (kg/m3

) 1.1 7.2 1.3 11.0 24.4 11.0 --- 836.6 --- 34.2 --- 8.4 21.3 21.0

V-L Molecular Weight 28.895 28.854 27.999 32.181 28.056 32.229 --- 18.013 --- 23.005 --- 21.610 21.511 21.511

V-L Flowrate (lbmol/hr) 58,154 13,357 23,812 215 32,960 14,642 0 19,116 41,975 3,488 0 69,229 66,208 66,208

V-L Flowrate (lb/hr) 1,680,359 385,406 666,700 6,915 924,735 471,894 0 344,323 613,487 80,251 0 1,496,009 1,424,161 1,424,161

Solids Flowrate (lb/hr) 0 0 0 0 0 0 656,228 0 387,064 0 56,686 0 0 0

Temperature (°F) 42 771 58 90 199 90 42 340 300 345 1,900 1,873 450 450

Pressure (psia) 13.0 207.6 16.4 125.0 384.0 125.0 13.0 740.0 740.0 800.0 614.7 614.7 589.7 579.7

Enthalpy (Btu/lb)A 6.6 189.8 14.4 11.5 39.7 11.4 --- 290.1 --- 169.7 --- 1,060.6 465.0 465.0

Density (lb/ft3) 0.070 0.451 0.083 0.687 1.522 0.688 --- 52.227 --- 2.133 --- 0.527 1.331 1.309

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

383

Exhibit 3-127 Case S4A Stream Table (Continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 28 29

V-L Mole Fraction

Ar 0.0124 0.0120 0.0037 0.0002 0.0000 0.0031 0.0126 0.0126 0.0093 0.0094 0.0094 0.0000 0.0000 0.0000 0.0000

CH4 0.0176 0.0167 0.0000 0.0005 0.0000 0.0002 0.0175 0.0175 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.3541 0.3357 0.0057 0.0045 0.0000 0.0494 0.3529 0.3529 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.2686 0.2993 0.8515 0.9102 0.0000 0.6630 0.2676 0.2676 0.0003 0.1008 0.1008 0.0000 0.0000 0.0000 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 0.0000 0.0000 0.0000

H2 0.3371 0.3229 0.0670 0.0047 0.0000 0.0118 0.3394 0.3394 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0014 0.0015 0.0019 0.0029 0.0000 0.2142 0.0014 0.0014 0.0064 0.0642 0.0642 1.0000 1.0000 1.0000 1.0000

H2S 0.0035 0.0034 0.0013 0.0682 0.0000 0.0005 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0053 0.0086 0.0689 0.0088 0.0000 0.0573 0.0086 0.0086 0.7759 0.7238 0.7238 0.0000 0.0000 0.0000 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2081 0.1018 0.1018 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 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 0.0000 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) 19,206 20,274 1,068 1,000 0 1,285 19,274 19,274 100,835 122,337 122,337 40,099 22,058 22,058 44,671

V-L Flowrate (kg/hr) 451,111 493,753 42,642 42,828 0 46,542 450,925 450,925 2,913,623 3,609,183 3,609,183 722,401 397,375 397,375 804,761

Solids Flowrate (kg/hr) 0 0 0 0 2,163 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 35 33 38 51 174 232 51 196 6 594 131 566 32 32 33

Pressure (MPa, abs) 3.82 3.76 5.51 0.4 0.370 0.335 3.597 3.563 0.090 0.093 0.090 12.512 0.005 0.005 0.827

Enthalpy (kJ/kg)A 34.80 30.60 -13.86 43.7 --- 508.895 58.933 268.577 15.260 745.200 233.099 3,513.669 2,304.786 2,304.786 139.823

Density (kg/m3) 35.8 36.8 109.0 6.7 --- 2.9 31.6 21.2 1.1 0.4 0.8 34.9 0.04 0.04 995.0

V-L Molecular Weight 23.489 24.355 39.927 43 --- 36.231 23.396 23.396 28.895 29.502 29.502 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 42,341 44,696 2,354 2,204 0 2,832 42,491 42,491 222,302 269,707 269,707 88,404 48,629 48,629 98,483

V-L Flowrate (lb/hr) 994,530 1,088,539 94,008 94,420 0 102,608 994,119 994,119 6,423,439 7,956,887 7,956,887 1,592,622 876,061 876,061 1,774,195

Solids Flowrate (lb/hr) 0 0 0 0 4,769 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 95 92 100 124 345 450 124 385 42 1,100 268 1,050 90 90 92

Pressure (psia) 554.7 544.7 799.5 60.0 53.6 48.6 521.7 516.7 13.0 13.5 13.0 1,814.7 0.7 0.7 120.0

Enthalpy (Btu/lb)A 15.0 13.2 -6.0 18.8 --- 218.8 25.3 115.5 6.6 320.4 100.2 1,510.6 990.9 990.9 60.1

Density (lb/ft3) 2.234 2.298 6.807 0 --- 0.181 1.975 1.324 0.070 0.024 0.051 2.176 0.002 0.002 62.119
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

384

3.5.5 Case S4A Performance Results

The non-capture CoP E-GasTM IGCC plant using PRB coal at the Montana site (elevation 3,400 

ft) produces a net output of 605 MWe at a net plant efficiency of 36.7 percent (HHV basis). 

Overall performance for the plant is summarized in Exhibit 3-128, which includes auxiliary 

power requirements. The ASU accounts for approximately 78 percent of the total auxiliary load, 

distributed between the main air compressor, the oxygen compressor, the nitrogen compressor, 

and ASU auxiliaries. The cooling water system, including the CWPs and cooling tower fan, and 

the air-cooled condenser account for about 7 percent of the auxiliary load, and the BFW pumps 

account for an additional 3 percent. All other individual auxiliary loads are less than 3 percent of 

the total.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

385

Exhibit 3-128 Case S4A Plant Performance Summary

POWER SUMMARY (Gross Power at Generator 

Terminals, kWe) S4A

Gas Turbine Power 416,400

Steam Turbine Power 321,900

TOTAL POWER, kWe 738,300

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 550

Coal Milling 3,060

Sour Water Recycle Slurry Pump 290

Slag Handling 1,330

Air Separation Unit Auxiliaries 1,000

Air Separation Unit Main Air Compressor 67,880

Oxygen Compressor 11,160

Nitrogen Compressors 23,850

Boiler Feedwater Pumps 4,370

Condensate Pump 260

Syngas Recycle Compressor 610

Circulating Water Pump 2,870

Ground Water Pumps 270

Cooling Tower Fans 1,870

Air Cooled Condenser Fans 3,880

Scrubber Pumps 10

Acid Gas Removal 1,320

Gas Turbine Auxiliaries 1,000

Steam Turbine Auxiliaries 100

Claus Plant/TGTU Auxiliaries 250

Claus Plant TG Recycle Compressor 2,520

Miscellaneous Balance of Plant1 3,000

Transformer Losses 2,010

TOTAL AUXILIARIES, kWe 133,460

NET POWER, kWe 604,840

Net Plant Efficiency, % (HHV) 36.7%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,803 (9,292)

CONDENSER COOLING DUTY GJ/hr (106 Btu/hr) 1,720 (1,630)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 297,660 (656,228)

Thermal Input, kWt 1,647,041

Raw Water Withdrawal, m3/min (gpm) 11.4 (3,023)

Raw Water Consumption, m3/min (gpm) 8.86 (2,341) 1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

386

Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in 

Section 2.3. A summary of the plant air emissions for Case S4A is presented in Exhibit 3-129.

Exhibit 3-129 Cases S4A Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

80% capacity factor

kg/MWh

(lb/MWh)

SO2 0.001 (0.002) 29 (32) 0.006 (0.012)

NOX 0.022 (0.052) 934 (1,030) 0.180 (0.398)

Particulates 0.003 (0.0071) 127 (140) 0.025 (0.054)

Hg 1.51E-7 (3.51E-7) 0.006 (0.007) 1.21E-6 (2.67E-6)

CO2 gross 91.5 (212.8) 3,802,037 (4,191,028) 735 (1,620)

CO2 net 897 (1,977)

The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the MDEA 

AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel 

gas down to a level of less than 5 ppmv. This results in a concentration in the flue gas of less 

than 1 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, 

producing elemental sulfur. The Claus plant tail gas is hydrogenated and recycled to the AGR to 

capture most of the remaining sulfur. Because the environmental target was set based on higher 

sulfur bituminous coal, the resulting SO2 emissions with lower sulfur western coals are 

substantially less than the environmental target.

NOx emissions are limited to 15 ppmvd (as NO2 @ 15 percent O2) by the use of low NOx 

burners and nitrogen dilution of the fuel gas. Ammonia in the syngas is removed with process 

condensate prior to the low-temperature AGR process and destroyed in the Claus plant burner. 

This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone 

and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Ninety five percent of the mercury is captured from the syngas by an activated carbon bed.

CO2 emissions represent the uncontrolled discharge from the process.

The carbon balance for the two cases is shown in Exhibit 3-130. The carbon input to the plant 

consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected 

here since the Aspen model accounts for air components throughout. Carbon leaves the plant as 

unburned carbon in the ash and as CO2 in the stack gas and ASU vent gas.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

387

Exhibit 3-130 Case S4A Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 149,033 (328,561) Slag 1,341 (2,957)

Air (CO2) 501 (1,105) Stack Gas 148,065 (326,427)

ASU Vent 128 (282)

Total 149,534 (329,666) Total 149,534 (329,666)

Exhibit 3-131 shows the sulfur balance for the non capture case. Sulfur input comes solely from 

the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur 

emitted in the stack gas. Sulfur in the ash is considered to be negligible.

Exhibit 3-131 Case S4A Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 2,165 (4,774) Elemental Sulfur 2,163 (4,769)

Stack Gas 2 (5)

Total 2,165 (4,774) Total 2,165 (4,774)

Exhibit 3-132 shows the overall water balance for the plant. 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, primarily as coal moisture from the drying process and syngas condensate, and that 

water is re-used as internal recycle. Raw water withdrawal is the difference between water 

demand and internal recycle. Some water is discharged from the process to a permitted outfall. 

The difference between the withdrawal and discharge is the consumption.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

388

Exhibit 3-132 Case S4A Water Balance

Water Use

Water 

Demand

m3/min (gpm)

Internal 

Recycle 

m3/min (gpm)

Raw Water 

Withdrawal 

m3/min 

(gpm),

Process 

Water 

Discharge 

m3/min 

(gpm),

Raw Water 

Consumption 

m3/min 

(gpm),

S4A S4A S4A S4A S4A

Slag Handling 0.56 (147) 0.56 (147) 0 (0) 0 (0) 0 (0)

Slurry Water 2.61 (689) 2.30 (609) 0.30 (80) 0.00 (0) 0.30 (80)

SWS Blowdown 0 (0) 0 (0) 0 (0) 0.08 (21) -0.08 (-21)

Condenser Makeup 0.17 (44) 0 (0) 0.17 (44) 0 (0) 0.17 (44)

BFW Makeup 0.17 (44) 0.17 (44)

Cooling Tower Makeup 11.14 (2,943) 0.17 (44) 10.97 (2,899) 2.51 (662) 8.47 (2,237)

BFW Blowdown 0.17 (44) -0.17 (-44)

Total 14.5 (3,823) 3.03 (800) 11.4 (3,023) 2.58 (683) 8.86 (2,341)

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-133:

• Coal gasification and ASU

• Syngas cleanup

• Power block

An overall plant energy balance is provided in tabular form in Exhibit 3-134 based on 0°C 

(32°F) reference conditions. The power out is the combined CT and steam turbine power after 

generator losses.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

389

Exhibit 3-133 Case S4A Heat and Mass Balance 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

390

Exhibit 3-133 Case S4A Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

391

Exhibit 3-133 Case S4A Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

392

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Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

393

Exhibit 3-134 Case S4A Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,929 (5,620) 3.0 (2.9) 0 (0) 5,932 (5,623)

ASU Air 0 (0) 11.6 (11.0) 0 (0) 12 (11)

GT Air 0 (0) 44.5 (42.1) 0 (0) 44 (42)

Raw Water Makeup 0 (0) 15.9 (15.1) 0 (0) 16 (15)

Auxiliary Power 0 (0) 0 (0) 480 (455) 480 (455)

Totals 5,929 (5,620) 75.1 (71.1) 480 (455) 6,485 (6,146)

Heat Out GJ/hr (MMBtu/hr)

ASU Intercoolers 0 (0) 273 (259) 0 (0) 273 (259)

ASU Vent 0 (0) 10.1 (9.6) 0 (0) 10 (10)

Slag 44 (42) 28.6 (27.1) 0 (0) 73 (69)

Sulfur 20 (19) 0.2 (0.2) 0 (0) 20 (19)

Cooling Tower Blowdown 0 (0) 14.0 (13.2) 0 (0) 14 (13)

HRSG Flue Gas 0 (0) 841 (797) 0 (0) 841 (797)

Condenser 0 (0) 1,724 (1,634) 0 (0) 1,724 (1,634)

Auxiliary Cooling Load 0 (0) 108 (102) 0 (0) 108 (102)

Generator Loss 0 (0) 0 (0) 40 (38) 40 (38)

Process Losses 0 (0) 724 (686) 0 (0) 724 (686)

Power 0 (0) 0 (0) 2,658 (2,519) 2,658 (2,519)

Totals 64 (61) 3,722 (3,528) 2,698 (2,558) 6,485 (6,146)

3.5.6 Case S4A Equipment Lists

Major equipment items for the COPTM gasifier with no CO2 capture using PRB coal 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 3.5.7. In general, the design conditions include a 10 percent 

contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

394

ACCOUNT 1 COAL HANDLING

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0

4 Transfer Tower No. 1 Enclosed N/A 1 0

5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling 

System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0

8 Reclaim Hopper N/A 64 tonne (70 ton) 2 1

9 Feeder Vibratory 245 tonne/hr (270 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 490 tonne/hr (540 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 245 tonne (270 ton) 2 0

13 Crusher Impactor reduction 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 1 1

15 Conveyor No. 4 Belt w/tripper 490 tonne/hr (540 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 490 tonne/hr (540 tph) 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 1,089 tonne (1,200 ton) 3 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

395

ACCOUNT 2 COAL PREPARATION AND FEED 

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Feeder Vibratory 109 tonne/hr (120 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 327 tonne/hr (360 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 653 tonne (720 ton) 1 0

4 Weigh Feeder Belt 163 tonne/hr (180 tph) 2 0

5 Rod Mill Rotary 163 tonne/hr (180 tph) 2 0

6 Slurry Water Storage 

Tank with Agitator Field erected 515,729 liters (136,240 gal) 2 0

7 Slurry Water Pumps Centrifugal 2,877 lpm (760 gpm) 1 0

8 Rod Mill Discharge Tank 

with Agitator Field erected 254 tonne/hr (280 tph) 2 0

9 Slurry Recycle Pumps Centrifugal 469,773 liters (124,100 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,785 lpm (1000 gpm) 2 0

11 Slurry Storage Tank with 

Agitator Field erected 2,818,640 liters (744,600 gal) 1 0

12 Slurry Recycle Pumps Centrifugal 7,949 lpm (2,100 gpm) 2 2

13 Slurry Product Pumps Positive displacement 3,785 lpm (1,000 gpm) 2 2
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

396

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Demineralized Water Storage 

Tank Vertical, cylindrical, outdoor 647,305 liters (171,000 gal) 2 0

2 Condensate Pumps Vertical canned 7,419 lpm @ 91 m H2O

(1,960 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 549,754 kg/hr 

(1,212,000 lb/hr) 2 0

4 Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, single 

stage

2,309 lpm @ 27 m H2O

(610 gpm @ 90 ft H2O) 2 1

5 High Pressure Feedwater Pump 

No. 1

Barrel type, multi-stage, 

centrifugal

HP water: 7,003 lpm @ 

1,890 m H2O (1,850 gpm @ 

6,200 ft H2O)

2 1

6 High Pressure Feedwater Pump 

No. 2

Barrel type, multi-stage, 

centrifugal

IP water: 114 lpm @ 223 m 

H2O (30 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)

1 0

8 Service Air Compressors Flooded Screw 28 m3

/min @ 0.7 MPa

(1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

10 Closed Cycle Cooling Heat 

Exchangers Plate and frame 224 GJ/hr (212 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water 

Pumps Horizontal centrifugal 80,251 lpm @ 21 m H2O(21,200 gpm @ 70 ft H2O) 2 1

12 Engine-Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H2O 1 1
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

397

Equipment 

No. Description Type Design Condition Operating Qty Spares

(1,000 gpm @ 350 ft H2O)

13 Fire Service Booster Pump Two-stage horizontal 

centrifugal

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, single suction 2,801 lpm @ 18 m H2O

(740 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single suction 2,801 lpm @ 268 m H2O

(740 gpm @ 880 ft H2O) 2 1

16 Filtered Water Pumps Stainless steel, single suction 1,173 lpm @ 49 m H2O

(310 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 556,456 liter (147,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and mixed bed 189 lpm (50 gpm) 2 0

19 Liquid Waste Treatment 

System 10 years, 24-hour storm 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

398

ACCOUNT 4 GASIFIER, ASU, AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY 

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Gasifier Pressurized two-stage, slurry-feed 

entrained bed

3,901 tonne/day, 4.2 MPa

(4,300 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler Fire-tube boiler 373,307 kg/hr (823,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 373,307 kg/hr (823,000 lb/hr) 

Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with pulse-jet 

cleaning metallic filters 2 0

5

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical up flow 373,307 kg/hr (823,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with condensate 

drain 355,163 kg/hr (783,000 lb/hr) 8 0

7 Raw Gas Knockout 

Drum Vertical with mist eliminator 248,569 kg/hr, 38°C, 3.9 MPa(548,000 lb/hr, 100°F, 565 psia) 2 0

8 Synthesis Gas Reheater Shell and tube 248,115 kg/hr (547,000 lb/hr) 2 0

9 Flare Stack Self-supporting, carbon steel, 

stainless steel top, pilot ignition

373,307 kg/hr (823,000 lb/hr) 

syngas

2 0

10 ASU Main Air 

Compressor Centrifugal, multi-stage 5,720 m3

/min @ 1.3 MPa

(202,000 scfm @ 190 psia) 2 0

11 Cold Box Vendor design 2,812 tonne/day (3,100 tpd)

of 95% purity oxygen 2 0

12 Oxygen Compressor Centrifugal, multi-stage

1,444 m3

/min (51,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 5.1 MPa (740 psia)

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

399

Equipment 

No. Description Type Design Condition Operating Qty Spares

13 Primary Nitrogen 

Compressor Centrifugal, multi-stage

2,605 m3/min (92,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 0

14 Secondary Nitrogen 

Compressor Centrifugal, single-stage

651 m3

/min (23,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 0

15 Extraction Air Heat 

Exchanger Gas-to-gas, vendor design 96,162 kg/hr, 411°C, 1.4 MPa(212,000 lb/hr, 771°F, 208 psia) 2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

400

ACCOUNT 5 SYNGAS CLEANUP

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Mercury Adsorber Sulfated carbon bed

248,115 kg/hr (547,000 lb/hr) 

35°C (95°F) 

3.8 MPa (555 psia)

2 0

2 Sulfur Plant Claus type 57 tonne/day (63 tpd) 1 0

3 COS Hydrolysis Reactor Fixed bed, catalytic

355,163 kg/hr (783,000 lb/hr)

232°C (450°F)

4.1 MPa (590 psia)

2 0

4 Acid Gas Removal Plant Sulfinol

271,702 kg/hr (599,000 lb/hr)

33°C (92°F)

3.8 MPa (545 psia)

2 0

5 Hydrogenation Reactor Fixed bed, catalytic

46,542 kg/hr (102,608 lb/hr)

232°C (450°F)

0.3 MPa (48.6 psia)

1 0

6 Tail Gas Recycle 

Compressor Centrifugal 42,658 kg/hr (94,044 lb/hr) 1 0

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Gas Turbine Advanced F class 210 MW 2 0

2 Gas Turbine Generator TEWAC 230 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

401

ACCOUNT 7 HRSG, DUCTING AND STACK

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Stack CS plate, type 409SS

liner

76 m (250 ft) high x

8.4 m (19 ft) diameter 2 0

2 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator

Main steam - 397,321 kg/hr, 12.4 MPa/566°C 

(875,942 lb/hr, 1,800 psig/1,050°F)

Reheat steam - 390,352 kg/hr, 3.1 MPa/566°C 

(860,579 lb/hr, 452 psig/1,050°F)

2 0

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Steam Turbine Commercially 

available

339 MW

12.4 MPa/566°C/566°C (1,800 psig/ 

1,050°F/1,050°F)

1 0

2 Steam Turbine 

Generator

Hydrogen cooled, 

static excitation 380 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0

3 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

50% steam flow @ design steam conditions 1 0

4 Air-cooled 

Condenser ---

950 GJ/hr (900 MMBtu/hr), 

Inlet water temperature 09°C (48°F), 

Water temperature rise 11°C (20°F)

1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

402

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Circulating 

Water Pumps Vertical, wet pit 287,691 lpm @ 30 m(76,000 gpm @ 100 ft) 2 1

2 Cooling 

Tower

Evaporative, 

mechanical draft, 

multi-cell

3°C (37°F) WB / 9°C (48°F) CWT /

20°C (68°F) HWT /

1,604 GJ/hr (1,520 MMBtu/hr) heat duty

1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

403

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Slag Quench Tank Water bath 268,764 liters (71,000 gal) 2 0

2 Slag Crusher Roll 15 tonne/hr (16 tph) 2 0

3 Slag Depressurizer Proprietary 15 tonne/hr (16 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 162,773 liters (43,000 gal) 2 0

5 Black Water Overflow 

Tank Shop fabricated 71,923 liters (19,000 gal) 2 0

6 Slag Conveyor Drag chain 15 tonne/hr (16 tph) 2 0

7 Slag Separation Screen Vibrating 15 tonne/hr (16 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 15 tonne/hr (16 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 230,910 liters (61,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal 

centrifugal

76 lpm @ 14 m H2O

(20 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 71,923 liters (19,000 gal) 2 0

12 Grey Water Pumps Centrifugal 265 lpm @ 433 m H2O

(70 gpm @ 1,420 ft H2O) 2 2

13 Slag Storage Bin Vertical, field 

erected 998 tonne (1,100 tons) 2 0

14 Unloading Equipment Telescoping chute 118 tonne/hr (130 tph) 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

404

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 CTG Step-up Transformer Oil-filled 24 kV/345 kV, 230 MVA, 

3-ph, 60 Hz 2 0

2 STG Step-up Transformer Oil-filled 24 kV/345 kV, 380 MVA, 

3-ph, 60 Hz 1 0

3 High Voltage Auxiliary 

Transformer Oil-filled 345 kV/13.8 kV, 57 MVA,3-ph, 60 Hz 2 0

4 Medium Voltage Auxiliary 

Transformer Oil-filled 24 kV/4.16 kV, 32 MVA,3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 5 MVA,

3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct and 

Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct and 

Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency 

shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

405

ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator printer (laser 

color); Engineering printer (laser B&W)

Operator stations/printers and 

engineering stations/printers 1 0

2 DCS - Processor Microprocessor with redundant 

input/output N/A 1 0

3 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

406

3.5.7 Case S4A Cost Estimating

Costs Results

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-135 shows 

the TPC summary organized by cost account for the Case S4A. A more detailed breakdown of 

the capital costs is shown in Exhibit 3-136. Exhibit 3-137 shows the calculation and addition of 

owner’s costs to determine the TOC, used to calculate COE. Exhibit 3-138 shows the initial and 

annual O&M costs for Case S4A.

The estimated TOC of the CoP E-GasTM IGCC plant with no CO2 capture using PRB coal is 

$2,771/kW. Process contingency represents 2 percent, project contingency represents 

11 percent, and owner’s costs represent 18 percent of TOC. The COE is 78.7 mills/kWh.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

407

Exhibit 3-135 Case S4A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S4A - ConocoPhillips IGCC w/o CO2

Plant Size: 604.8 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING $17,180 $3,193 $13,323 $0 $0 $33,696 $3,059 $0 $7,351 $44,106 $73

 2 COAL & SORBENT PREP & FEED $29,627 $5,415 $17,900 $0 $0 $52,942 $4,753 $0 $11,539 $69,233 $114

 3 FEEDWATER & MISC. BOP SYSTEMS $9,132 $8,032 $8,390 $0 $0 $25,554 $2,398 $0 $6,265 $34,218 $57

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $141,056 $0 $76,694 $0 $0 $217,750 $19,592 $30,569 $40,951 $308,862 $511

4.2 Syngas Cooling w/4.1 w/4.1 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $170,773 $0 w/equip. $0 $0 $170,773 $16,553 $0 $18,733 $206,059 $341

4.4-4.9 Other Gasification Equipment $21,702 $12,064 $14,900 $0 $0 $48,667 $4,645 $0 $11,574 $64,886 $107

SUBTOTAL 4 $333,532 $12,064 $91,594 $0 $0 $437,191 $40,790 $30,569 $71,257 $579,807 $959

 5A GAS CLEANUP & PIPING $53,335 $2,999 $49,299 $0 $0 $105,634 $10,211 $91 $23,330 $139,266 $230

5B CO2 REMOVAL & COMPRESSION $0 $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 $0 $92,022 $8,724 $4,601 $10,535 $115,882 $192

6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4

SUBTOTAL 6 $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $196

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,203 $0 $4,721 $0 $0 $37,924 $3,606 $0 $4,153 $45,683 $76

7.2-7.9 Open, Ductwork and Stack $3,336 $2,378 $3,115 $0 $0 $8,829 $819 $0 $1,570 $11,217 $19

SUBTOTAL 7 $36,539 $2,378 $7,836 $0 $0 $46,753 $4,424 $0 $5,723 $56,900 $94

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $32,394 $0 $5,646 $0 $0 $38,040 $3,650 $0 $4,169 $45,859 $76

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $40,553 $1,120 $13,767 $0 $0 $55,441 $5,370 $0 $12,451 $73,262 $121

SUBTOTAL 8 $72,947 $1,120 $19,413 $0 $0 $93,480 $9,020 $0 $16,620 $119,121 $197

 9 COOLING WATER SYSTEM $7,368 $7,303 $6,231 $0 $0 $20,903 $1,942 $0 $4,678 $27,522 $46

10 ASH/SPENT SORBENT HANDLING SYS $21,024 $1,598 $10,432 $0 $0 $33,053 $3,171 $0 $3,953 $40,177 $66

11 ACCESSORY ELECTRIC PLANT $28,690 $10,887 $21,639 $0 $0 $61,216 $5,261 $0 $12,523 $78,999 $131

12 INSTRUMENTATION & CONTROL $10,114 $1,861 $6,517 $0 $0 $18,492 $1,676 $925 $3,514 $24,607 $41

13 IMPROVEMENTS TO SITE $3,329 $1,962 $8,214 $0 $0 $13,505 $1,333 $0 $4,452 $19,290 $32

14 BUILDINGS & STRUCTURES $0 $6,804 $7,884 $0 $0 $14,688 $1,338 $0 $2,615 $18,641 $31

 

TOTAL COST $708,571 $66,423 $275,834 $0 $0 $1,050,827 $98,259 $36,187 $184,912 $1,370,185 $2,265

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

408

Exhibit 3-136 Case S4A Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S4A - ConocoPhillips IGCC w/o CO2

Plant Size: 604.8 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $4,512 $0 $2,205 $0 $0 $6,716 $602 $0 $1,464 $8,782 $15

1.2 Coal Stackout & Reclaim $5,830 $0 $1,413 $0 $0 $7,243 $635 $0 $1,576 $9,454 $16

1.3 Coal Conveyors & Yd Crush $5,420 $0 $1,398 $0 $0 $6,819 $599 $0 $1,484 $8,901 $15

1.4 Other Coal Handling $1,418 $0 $324 $0 $0 $1,742 $152 $0 $379 $2,273 $4

1.5 Sorbent Receive & Unload $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

1.7 Sorbent Conveyors $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

1.9 Coal & Sorbent Hnd. Foundations $0 $3,193 $7,983 $0 $0 $11,176 $1,071 $0 $2,449 $14,696 $24

SUBTOTAL 1. $17,180 $3,193 $13,323 $0 $0 $33,696 $3,059 $0 $7,351 $44,106 $73

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying (incl. w/2.3) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,950 $467 $306 $0 $0 $2,723 $233 $0 $591 $3,546 $6

2.3 Slurry Prep & Feed $26,604 $0 $11,832 $0 $0 $38,436 $3,432 $0 $8,374 $50,241 $83

2.4 Misc.Coal Prep & Feed $1,072 $780 $2,340 $0 $0 $4,193 $385 $0 $916 $5,493 $9

2.5 Sorbent Prep Equipment $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

2.7 Sorbent Injection System $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

2.9 Coal & Sorbent Feed Foundation $0 $4,168 $3,422 $0 $0 $7,590 $703 $0 $1,659 $9,952 $16

SUBTOTAL 2. $29,627 $5,415 $17,900 $0 $0 $52,942 $4,753 $0 $11,539 $69,233 $114

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $3,252 $5,584 $2,948 $0 $0 $11,784 $1,092 $0 $2,575 $15,451 $26

3.2 Water Makeup & Pretreating $450 $47 $251 $0 $0 $748 $71 $0 $246 $1,065 $2

3.3 Other Feedwater Subsystems $1,779 $601 $541 $0 $0 $2,921 $263 $0 $637 $3,821 $6

3.4 Service Water Systems $257 $530 $1,839 $0 $0 $2,626 $256 $0 $865 $3,747 $6

3.5 Other Boiler Plant Systems $1,381 $535 $1,326 $0 $0 $3,242 $307 $0 $710 $4,259 $7

3.6 FO Supply Sys & Nat Gas $313 $591 $552 $0 $0 $1,456 $140 $0 $319 $1,916 $3

3.7 Waste Treatment Equipment $629 $0 $383 $0 $0 $1,012 $99 $0 $333 $1,444 $2

3.8 Misc. Power Plant Equipment $1,072 $143 $550 $0 $0 $1,766 $171 $0 $581 $2,517 $4

SUBTOTAL 3. $9,132 $8,032 $8,390 $0 $0 $25,554 $2,398 $0 $6,265 $34,218 $57

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $141,056 $0 $76,694 $0 $0 $217,750 $19,592 $30,569 $40,951 $308,862 $511

4.2 Syngas Cooling w/4.1 w/4.1 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $170,773 $0 w/equip. $0 $0 $170,773 $16,553 $0 $18,733 $206,059 $341

4.4 LT Heat Recovery & FG Saturation $21,702 $0 $8,250 $0 $0 $29,952 $2,923 $0 $6,575 $39,451 $65

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,428 $581 $0 $0 $2,009 $193 $0 $440 $2,642 $4

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $10,636 $6,069 $0 $0 $16,705 $1,529 $0 $4,559 $22,793 $38

SUBTOTAL 4. $333,532 $12,064 $91,594 $0 $0 $437,191 $40,790 $30,569 $71,257 $579,807 $959

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

409

Exhibit 3-136 Case S4A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S4A - ConocoPhillips IGCC w/o CO2

Plant Size: 604.8 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 5A GAS CLEANUP & PIPING

5A.1 MDEA-LT AGR $40,356 $0 $34,243 $0 $0 $74,599 $7,215 $0 $16,363 $98,176 $162

5A.2 Elemental Sulfur Plant $5,512 $1,098 $7,111 $0 $0 $13,721 $1,333 $0 $3,011 $18,064 $30

5A.3 Mercury Removal $1,039 $0 $790 $0 $0 $1,829 $177 $91 $419 $2,516 $4

5A.4 COS Hydrolysis $4,527 $0 $5,912 $0 $0 $10,440 $1,015 $0 $2,291 $13,746 $23

5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Blowback Gas Systems $1,902 $320 $180 $0 $0 $2,402 $228 $0 $526 $3,156 $5

5A.7 Fuel Gas Piping $0 $785 $550 $0 $0 $1,335 $124 $0 $292 $1,751 $3

5A.9 HGCU Foundations $0 $795 $513 $0 $0 $1,308 $120 $0 $428 $1,857 $3

SUBTOTAL 5A. $53,335 $2,999 $49,299 $0 $0 $105,634 $10,211 $91 $23,330 $139,266 $230

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5B. $0 $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 $0 $92,022 $8,724 $4,601 $10,535 $115,882 $192

6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4

SUBTOTAL 6. $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $196

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,203 $0 $4,721 $0 $0 $37,924 $3,606 $0 $4,153 $45,683 $76

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,710 $1,220 $0 $0 $2,930 $257 $0 $637 $3,824 $6

7.4 Stack $3,336 $0 $1,253 $0 $0 $4,589 $440 $0 $503 $5,532 $9

7.9 HRSG,Duct & Stack Foundations $0 $668 $642 $0 $0 $1,310 $122 $0 $430 $1,862 $3

SUBTOTAL 7. $36,539 $2,378 $7,836 $0 $0 $46,753 $4,424 $0 $5,723 $56,900 $94

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $32,394 $0 $5,646 $0 $0 $38,040 $3,650 $0 $4,169 $45,859 $76

8.2 Turbine Plant Auxiliaries $218 $0 $499 $0 $0 $716 $70 $0 $79 $865 $1

8.3a Condenser & Auxiliaries $3,404 $0 $1,088 $0 $0 $4,492 $430 $0 $492 $5,414 $9

8.3b Air Cooled Condenser $31,198 $0 $6,255 $0 $0 $37,453 $3,745 $0 $8,240 $49,438 $82

8.4 Steam Piping $5,733 $0 $4,033 $0 $0 $9,766 $839 $0 $2,651 $13,256 $22

8.9 TG Foundations $0 $1,120 $1,893 $0 $0 $3,013 $286 $0 $990 $4,289 $7

SUBTOTAL 8. $72,947 $1,120 $19,413 $0 $0 $93,480 $9,020 $0 $16,620 $119,121 $197

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $5,099 $0 $993 $0 $0 $6,092 $580 $0 $1,001 $7,673 $13

9.2 Circulating Water Pumps $1,320 $0 $82 $0 $0 $1,402 $118 $0 $228 $1,749 $3

9.3 Circ.Water System Auxiliaries $116 $0 $17 $0 $0 $133 $13 $0 $22 $167 $0

9.4 Circ.Water Piping $0 $4,840 $1,255 $0 $0 $6,095 $551 $0 $1,329 $7,975 $13

9.5 Make-up Water System $261 $0 $374 $0 $0 $635 $61 $0 $139 $835 $1

9.6 Component Cooling Water Sys $571 $683 $486 $0 $0 $1,741 $163 $0 $381 $2,285 $4

9.9 Circ.Water System Foundations $0 $1,779 $3,025 $0 $0 $4,804 $455 $0 $1,578 $6,838 $11

SUBTOTAL 9. $7,368 $7,303 $6,231 $0 $0 $20,903 $1,942 $0 $4,678 $27,522 $46

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

410

Exhibit 3-136 Case S4A Total Plant Cost Details (Continued) Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S4A - ConocoPhillips IGCC w/o CO2

Plant Size: 604.8 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $18,340 $0 $9,044 $0 $0 $27,384 $2,631 $0 $3,001 $33,016 $55

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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

10.4 High Temperature Ash Piping $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

10.6 Ash Storage Silos $608 $0 $662 $0 $0 $1,270 $123 $0 $209 $1,602 $3

10.7 Ash Transport & Feed Equipment $816 $0 $197 $0 $0 $1,013 $94 $0 $166 $1,273 $2

10.8 Misc. Ash Handling Equipment $1,260 $1,544 $461 $0 $0 $3,265 $311 $0 $536 $4,112 $7

10.9 Ash/Spent Sorbent Foundation $0 $54 $68 $0 $0 $121 $11 $0 $40 $173 $0

SUBTOTAL 10. $21,024 $1,598 $10,432 $0 $0 $33,053 $3,171 $0 $3,953 $40,177 $66

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $951 $0 $940 $0 $0 $1,891 $181 $0 $207 $2,279 $4

11.2 Station Service Equipment $4,020 $0 $362 $0 $0 $4,383 $404 $0 $479 $5,265 $9

11.3 Switchgear & Motor Control $7,433 $0 $1,352 $0 $0 $8,784 $815 $0 $1,440 $11,039 $18

11.4 Conduit & Cable Tray $0 $3,453 $11,390 $0 $0 $14,843 $1,436 $0 $4,070 $20,348 $34

11.5 Wire & Cable $0 $6,597 $4,335 $0 $0 $10,931 $794 $0 $2,931 $14,657 $24

11.6 Protective Equipment $0 $680 $2,474 $0 $0 $3,154 $308 $0 $519 $3,981 $7

11.7 Standby Equipment $234 $0 $229 $0 $0 $463 $44 $0 $76 $583 $1

11.8 Main Power Transformers $16,052 $0 $145 $0 $0 $16,197 $1,225 $0 $2,613 $20,035 $33

11.9 Electrical Foundations $0 $157 $412 $0 $0 $569 $54 $0 $187 $811 $1

SUBTOTAL 11. $28,690 $10,887 $21,639 $0 $0 $61,216 $5,261 $0 $12,523 $78,999 $131

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $998 $0 $667 $0 $0 $1,665 $158 $83 $286 $2,192 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $229 $0 $147 $0 $0 $377 $36 $19 $86 $517 $1

12.7 Computer & Accessories $5,326 $0 $171 $0 $0 $5,497 $505 $275 $628 $6,904 $11

12.8 Instrument Wiring & Tubing $0 $1,861 $3,804 $0 $0 $5,664 $480 $283 $1,607 $8,035 $13

12.9 Other I & C Equipment $3,560 $0 $1,729 $0 $0 $5,289 $498 $264 $908 $6,959 $12

SUBTOTAL 12. $10,114 $1,861 $6,517 $0 $0 $18,492 $1,676 $925 $3,514 $24,607 $41

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $104 $2,232 $0 $0 $2,337 $232 $0 $771 $3,340 $6

13.2 Site Improvements $0 $1,858 $2,469 $0 $0 $4,326 $427 $0 $1,426 $6,179 $10

13.3 Site Facilities $3,329 $0 $3,513 $0 $0 $6,842 $675 $0 $2,255 $9,771 $16

SUBTOTAL 13. $3,329 $1,962 $8,214 $0 $0 $13,505 $1,333 $0 $4,452 $19,290 $32

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1

14.2 Steam Turbine Building $0 $2,682 $3,820 $0 $0 $6,502 $598 $0 $1,065 $8,165 $13

14.3 Administration Building $0 $842 $611 $0 $0 $1,453 $129 $0 $237 $1,819 $3

14.4 Circulation Water Pumphouse $0 $166 $88 $0 $0 $254 $22 $0 $41 $317 $1

14.5 Water Treatment Buildings $0 $376 $367 $0 $0 $742 $67 $0 $121 $931 $2

14.6 Machine Shop $0 $431 $295 $0 $0 $726 $64 $0 $119 $909 $2

14.7 Warehouse $0 $696 $449 $0 $0 $1,145 $101 $0 $187 $1,433 $2

14.8 Other Buildings & Structures $0 $417 $324 $0 $0 $741 $66 $0 $161 $969 $2

14.9 Waste Treating Building & Str. $0 $931 $1,780 $0 $0 $2,712 $253 $0 $593 $3,557 $6

SUBTOTAL 14. $0 $6,804 $7,884 $0 $0 $14,688 $1,338 $0 $2,615 $18,641 $31

TOTAL COST $708,571 $66,423 $275,834 $0 $0 $1,050,827 $98,259 $36,187 $184,912 $1,370,185 $2,265

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

411

Exhibit 3-137 Case S4A Owner’s Costs

Owner's Costs $x1000 $/kW

Preproduction Costs

6 Months Fixed O&M $13,902 $23

1 Month Variable O&M $3,684 $6

25% of 1 Months Fuel Cost at 100% CF $911 $2

2% of TPC $27,404 $45

Total $45,902 $76

Inventory Capital

60 day supply of consumables at 100% CF $7,551 $12

0.5% of TPC (spare parts) $6,851 $11

Total $14,402 $24

 Initial Cost for Catalyst and Chemicals $1,878 $3

Land $900 $1

Other Owner's Costs $205,528 $340

Financing Costs $36,995 $61

Total Owner's Costs $305,605 $505

Total Overnight Cost (TOC) $1,675,790 $2,771

TASC Multiplier 1.140

Total As-Spent Cost (TASC) $1,910,400 $3,159
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

412

Exhibit 3-138 Case S4A Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun) 2007

Case S4A - ConocoPhillips IGCC w/o CO2 Heat Rate-net(Btu/kWh): 9,292

MWe-net: 605

 Capacity Factor: (%): 80

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 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-O.J.'s 15.0 15.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $5,918,913 $9.786

Maintenance Labor Cost $16,324,769 $26.990

Administrative & Support Labor $5,560,920 $9.194

Property Taxes and Insurance $27,403,700 $45.307

TOTAL FIXED OPERATING COSTS $55,208,302 $91.278

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $30,375,594 $0.00717

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

Water (/1000 gallons) 0 2,167.92 1.08 $0 $684,736 $0.00016

Chemicals

MU & WT Chem. (lb) 0 12,916 0.17 $0 $652,713 $0.00015

Carbon (Mercury Removal) (lb) 74,181 102 1.05 $77,902 $31,161 $0.00001

COS Catalyst (m3) 451 0.31 2,397.36 $1,080,271 $216,054 $0.00005

Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000

MDEA Solution (gal) 82,792 56 8.70 $720,105 $142,912 $0.00003

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip. 0.85 131.27 $0 $32,699 $0.00001

Subtotal Chemicals $1,878,278 $1,075,539 $0.00025

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 102 0.42 $0 $12,376 $0.00000

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 680 16.23 $0 $3,222,772 $0.00076

Subtotal Waste Disposal $0 $3,235,147 $0.00076

By-products & Emissions 

Sulfur (tons) 0 57 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $1,878,278 $35,371,017 $0.00834

Fuel (ton) 0 7,875 15.22 $0 $34,989,859 $0.00825
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

413

3.5.8 CoP E-GasTM IGCC CO2 Capture Cases (S4B) Process Description

Case S4B is configured to produce electric power with CO2 capture. The plant configuration is

similar to Cases S4A with the major differences being the addition of WGS, the use of a twostage Selexol AGR plant instead of MDEA and subsequent compression of the captured CO2

stream. The gross power output is constrained by the capacity of the two CTs, and since the CO2

capture and compression process increases the auxiliary load on the plant, the net output is 

significantly reduced relative to Case S4A.

The process description for Case S4B is similar to Case S4A with several notable exceptions to 

accommodate CO2 capture. A BFD for the CO2 capture case is shown in Exhibit 3-139 and 

stream tables are shown in Exhibit 3-140. Instead of repeating the entire process description, 

only differences from Cases S4A are reported here.

Coal Preparation and Feed Systems

Same as for Case S4A except for the coal is slurried to 49 percent solids for injection into the 

two stages of the gasifier.

Gasification

The gasification process is similar to Case S4A except the coal feed (as-received) to the two 

gasifiers is 7,349 tonne/day (8,101 tpd). For cases with a design target of 90 percent overall 

carbon capture, the gasifier can be tuned to minimize methane concentrations, which end up in 

the flue gas as the gas cleanup process does not capture the carbon in the form of methane. 

Varying slurry concentration and different combinations of two stage slurry injection were 

considered based on vendor supplied gasifier performance, guaranteeing a maximum methane 

concentration, with the tradeoff of lower CGE. This reduction in CGE is mainly due to the 

increased slurry water diluent, but for carbon capture requiring WGS reaction, this slurry water 

replaces injected shift steam that would otherwise be extracted from the steam turbine.

Raw Gas Cooling/Particulate Removal

No differences from Case S4A.

Sour Water Stripper

No differences from Case S4A.

Sour Gas Shift

The SGS process was described in Section 3.1.6. The water concentration in the syngas is 

adjusted upstream of the shift reactors by the injection of shift steam, extracted from the steam 

cycle. The hot syngas exiting the first stage of SGS is used to superheat steam. One more stage 

of SGS (for a total of two) results in approximately 97 percent overall conversion of CO to CO2. 

The warm syngas from the second stage of SGS is cooled to preheat the syngas prior to the first 

stage of SGS. The SGS catalyst also serves to hydrolyze COS thus eliminating the need for a 

separate COS hydrolysis reactor. Following the second stage of SGS, the syngas is further 

cooled to 35°C (95°F) prior to the mercury removal beds.

Mercury Removal and AGR

Mercury removal is the same as in Case S4A.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

414

The AGR process in Case S4B is a two stage Selexol process where H2S is removed in the first 

stage and CO2 in the second stage of absorption. The process results in three product streams, 

the clean syngas, a CO2-rich stream, and an acid gas feed to the Claus plant. The acid gas 

contains about 17 percent H2S and 68 percent CO2 with the balance primarily H2. The CO2-rich 

stream is discussed further in the CO2 compression section. 

CO2 Compression and Dehydration

CO2 from the AGR process is generated at two pressure levels. The LP stream is compressed 

from 0.12 MPa (17 psia) to 1.0 MPa (150 psia) and then combined with the HP stream. The 

combined stream is further compressed to a SC condition at 15.3 MPa (2215 psia) using a 

multiple-stage, intercooled compressor. During compression, the CO2 stream is dehydrated to a 

dew point of -40oC (-40°F) using a thermal swing adsorptive dryer. The raw CO2 stream from 

the Selexol process contains over 99 percent CO2. The dehydrated CO2 is transported to the 

plant fence line and is sequestration ready. CO2 TS&M costs were estimated using the 

methodology described in Section 2.6.

Claus Unit

The Claus plant is the same as Cases S4A except 53 tonne/day (59 tpd) of sulfur are produced.

Power Block

Clean syngas from the AGR plant is reheated to 196°C (385°F). The conditioned syngas is 

diluted with nitrogen, and then enters the CT burner. The exhaust gas exits the CT at 561°C 

(1,042°F) and enters the HRSG where additional heat is recovered. The flue gas exits the HRSG 

at 132°C (270°F) and is discharged through the plant stack. The steam raised in the HRSG is 

used to power an advanced commercially available steam turbine using a nominal 

12.4MPa/538°C/538°C (1,800 psig/1,000°F/1,000°F) steam cycle. There is no air integration 

between the CT and the ASU in the capture case.

ASU

The same elevated pressure ASU is used as in Cases S4A except the output is 5,323 tonne/day 

(5,867 tpd) of 95 mole percent oxygen and 11,750 tonne/day (12,952 tpd) of nitrogen.

Balance of Plant

Balance of plant items were covered in Sections 3.1.12, 3.1.13, 3.1.14 and 3.1.15.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

415

Exhibit 3-139 Case S4B Process Flow Diagram
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

416

Exhibit 3-140 Case S4B Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

V-L Mole Fraction

Ar 0.0093 0.0058 0.0318 0.0022 0.0360 0.0000 0.0000 0.0000 0.0077 0.0000 0.0079 0.0077 0.0000 0.0067 0.0090

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0068 0.0000 0.0069 0.0068 0.0000 0.0059 0.0079

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2356 0.0000 0.2419 0.2356 0.0000 0.0027 0.0036

CO2 0.0003 0.0012 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1536 0.0000 0.1577 0.1536 0.0000 0.3376 0.4498

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0001 0.0001 0.0000 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2625 0.2137 0.0000 0.2194 0.2137 0.0000 0.3901 0.5197

H2O 0.0064 0.0230 0.0000 0.0002 0.0000 0.0000 0.9993 0.6787 0.3744 0.0000 0.3577 0.3744 1.0000 0.2498 0.0016

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0022 0.0021 0.0000 0.0019 0.0025

N2 0.7759 0.9350 0.0178 0.9925 0.0140 0.0000 0.0000 0.0040 0.0050 0.0000 0.0051 0.0050 0.0000 0.0044 0.0058

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0007 0.0003 0.0011 0.0000 0.0011 0.0011 0.0000 0.0010 0.0000

O2 0.2081 0.0350 0.9504 0.0051 0.9500 0.0000 0.0000 0.0544 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 33,471 9,121 49 17,449 6,832 0 8,919 19,585 2,404 0 33,454 31,944 4,593 36,538 27,421

V-L Flowrate (kg/hr) 967,149 255,486 1,588 489,579 220,189 0 160,664 286,258 50,937 0 711,541 676,731 82,753 759,484 595,271

Solids Flowrate (kg/hr) 0 0 0 0 0 306,201 0 180,607 0 26,450 0 0 0 0 0

Temperature (°C) 6 15 32 93 32 6 149 149 241 1,038 1,017 194 288 204 35

Pressure (MPa, abs) 0.09 0.11 0.86 2.65 0.86 0.09 5.10 5.10 5.52 4.24 4.24 4.00 4.14 3.79 3.62

Enthalpy (kJ/kg)A 15.26 33.66 26.67 92.32 26.59 --- 571.24 --- 1,140.59 --- 2,517.45 1,069.76 2,956.19 859.79 38.17

Density (kg/m3) 1.1 1.3 11.0 24.4 11.0 --- 863.7 --- 28.2 --- 8.3 22.6 18.2 20.2 31.6

V-L Molecular Weight 28.895 28.011 32.181 28.058 32.229 --- 18.015 --- 21.185 --- 21.270 21.185 18.015 20.786 21.709

V-L Flowrate (lbmol/hr) 73,791 20,108 109 38,468 15,062 0 19,662 43,177 5,301 0 73,752 70,425 10,127 80,552 60,452

V-L Flowrate (lb/hr) 2,132,199 563,251 3,500 1,079,336 485,435 0 354,203 631,091 112,296 0 1,568,680 1,491,937 182,439 1,674,377 1,312,349

Solids Flowrate (lb/hr) 0 0 0 0 0 675,058 0 398,171 0 58,313 0 0 0 0 0

Temperature (°F) 42 59 90 199 90 42 300 300 465 1,900 1,863 382 550 400 95

Pressure (psia) 13.0 16.4 125.0 384.0 125.0 13.0 740.0 740.0 800.0 614.7 614.7 579.7 600.0 549.7 524.7

Enthalpy (Btu/lb)A 6.6 14.5 11.5 39.7 11.4 --- 245.6 --- 490.4 --- 1,082.3 459.9 1,270.9 369.6 16.4

Density (lb/ft3) 0.070 0.084 0.687 1.522 0.688 --- 53.921 --- 1.761 --- 0.521 1.409 1.135 1.261 1.972

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

417

Exhibit 3-140 Case S4B Stream Table (Continued)

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31

V-L Mole Fraction

Ar 0.0084 0.0090 0.0027 0.0000 0.0062 0.0002 0.0002 0.0154 0.0154 0.0093 0.0096 0.0096 0.0000 0.0000 0.0000 0.0000

CH4 0.0000 0.0079 0.0042 0.0000 0.0014 0.0004 0.0004 0.0132 0.0132 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0071 0.0036 0.0012 0.0000 0.0784 0.0001 0.0001 0.0063 0.0063 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.7741 0.4498 0.6789 0.0000 0.4933 0.9929 0.9955 0.0603 0.0603 0.0003 0.0102 0.0102 0.0000 0.0000 0.0000 0.0000

COS 0.0000 0.0000 0.0001 0.0000 0.0003 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.1630 0.5197 0.1090 0.0000 0.0466 0.0039 0.0039 0.8937 0.8937 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0018 0.0016 0.0345 0.0000 0.3407 0.0025 0.0000 0.0001 0.0001 0.0064 0.1204 0.1204 1.0000 1.0000 1.0000 1.0000

H2S 0.0043 0.0025 0.1685 0.0000 0.0010 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0412 0.0058 0.0009 0.0000 0.0303 0.0000 0.0000 0.0110 0.0110 0.7759 0.7535 0.7535 0.0000 0.0000 0.0000 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 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 0.2081 0.1062 0.1062 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0019 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 0.0000 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) 367 27,421 419 0 500 11,456 11,427 15,913 15,913 100,835 127,035 127,035 32,906 22,438 22,438 49,951

V-L Flowrate (kg/hr) 13,301 595,271 15,361 0 15,704 501,429 500,903 91,783 91,783 2,913,623 3,494,984 3,494,984 592,804 404,228 404,228 899,885

Solids Flowrate (kg/hr) 0 0 0 2,223 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 38 35 48 176 138 16 72 31 196 6 561 130 533 32 32 33

Pressure (MPa, abs) 5.51 3.5 0.163 0.119 0.119 0.931 15.270 3.238 3.203 0.090 0.093 0.090 12.512 0.005 0.005 0.827

Enthalpy (kJ/kg)A -5.12 38.2 87.882 --- 644.216 5.951 -96.995 153.366 1,017.404 15.260 829.125 338.189 3,430.351 2,273.814 2,273.814 139.321

Density (kg/m3

) 93.2 31.0 2.3 --- 1.1 18.0 465.8 7.3 4.7 1.1 0.4 0.7 36.8 0.04 0.04 995.1

V-L Molecular Weight 36.268 22 36.699 --- 31.428 43.769 43.834 5.768 5.768 28.895 27.512 27.512 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 809 60,452 923 0 1,102 25,257 25,193 35,081 35,081 222,302 280,065 280,065 72,544 49,467 49,467 110,124

V-L Flowrate (lb/hr) 29,323 1,312,349 33,865 0 34,621 1,105,461 1,104,303 202,347 202,347 6,423,439 7,705,122 7,705,122 1,306,908 891,170 891,170 1,983,906

Solids Flowrate (lb/hr) 0 0 0 4,901 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 100 95 119 349 280 60 161 87 385 42 1,042 267 992 90 90 92

Pressure (psia) 799.5 514.7 23.7 17.3 17.3 135.0 2,214.7 469.6 464.6 13.0 13.5 13.0 1,814.7 0.7 0.7 120.0

Enthalpy (Btu/lb)A -2.2 16.4 37.8 --- 277.0 2.6 -41.7 65.9 437.4 6.6 356.5 145.4 1,474.8 977.6 977.6 59.9

Density (lb/ft3) 5.816 1.935 0.141 --- 0.069 1.124 29.077 0.456 0.292 0.070 0.023 0.046 2.297 0.002 0.002 62.121
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

418

3.5.9 Case S4B Performance Results

The Case S4B modeling assumptions were presented previously in Exhibit 3-124.

The CoP E-GasTM IGCC plant with CO2 capture and using PRB coal at the Montana site 

(elevation 3,400 ft) produces a net output of 515 MWe at a net plant efficiency of 30.4 percent 

(HHV basis).

Overall performance for the plant is summarized in Exhibit 3-141, which includes auxiliary 

power requirements. The ASU accounts for approximately 63 percent of the total auxiliary load, 

distributed between the main air compressor, the oxygen compressor, the nitrogen compressor, 

and ASU auxiliaries. CO2 compression accounts for about 18 percent, and the AGR process 

about 10 percent of the auxiliary load. All other individual auxiliary loads are less than 3 percent 

of the total.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

419

Exhibit 3-141 Case S4B Plant Performance Summary

POWER SUMMARY (Gross Power at Generator 

Terminals, kWe) S4B

Gas Turbine Power 429,000

Steam Turbine Power 298,200

TOTAL POWER, kWe 727,200

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 560

Coal Milling 3,150

Sour Water Recycle Slurry Pump 300

Slag Handling 1,370

Air Separation Unit Auxiliaries 1,000

Air Separation Unit Main Air Compressor 86,130

Oxygen Compressor 11,480

Nitrogen Compressors 28,300

CO2 Compressor 36,110

Boiler Feedwater Pumps 3,910

Condensate Pump 290

Syngas Recycle Compressor 1,040

Circulating Water Pump 3,400

Ground Water Pumps 360

Cooling Tower Fans 2,210

Air Cooled Condenser Fans 3,850

Scrubber Pumps 10

Acid Gas Removal 20,580

Gas Turbine Auxiliaries 1,000

Steam Turbine Auxiliaries 100

Claus Plant/TGTU Auxiliaries 250

Claus Plant TG Recycle Compressor 1,660

Miscellaneous Balance of Plant1 3,000

Transformer Losses 2,070

TOTAL AUXILIARIES, kWe 212,130

NET POWER, kWe 515,070

Net Plant Efficiency, % (HHV) 30.4%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,842 (11,224)

CONDENSER COOLING DUTY GJ/hr (106 Btu/hr) 1,720 (1,630)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 306,201 (675,058)

Thermal Input, kWt 1,694,303

Raw Water Withdrawal, m3/min (gpm) 15.1 (3,987)

Raw Water Consumption, m3/min (gpm) 12.1 (3,199)

1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

420

Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, CO2, and PM were presented in 

Section 2.3. A summary of the plant air emissions for Case S4B is presented in Exhibit 3-142.

Exhibit 3-142 Case S4B Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

80% capacity factor

kg/MWh

(lb/MWh)

SO2 0.000 (0.001) 16 (17) 0.003 (0.007)

NOX 0.019 (0.044) 804 (886) 0.158 (0.348)

Particulates 0.003 (0.0071) 130 (144) 0.026 (0.056)

Hg 1.51E-7 (3.51E-7) 0.006 (0.007) 1.27E-6 (2.79E-6)

CO2 gross 9.4 (21.9) 401,650 (442,743) 79 (174)

CO2 net 111 (245)

The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the two-stage 

Selexol AGR process. Just as in the non-capture cases, the SO2 emission are significantly less 

than the environmental targets of Section 2.3. The clean syngas exiting the AGR process has a 

sulfur concentration of approximately 2 ppmv. This results in a concentration in the flue gas of 

less than 0.3 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, 

producing elemental sulfur. The tail gas is hydrogenated and recycled to the gasifier.

NOx emissions are limited to 15 ppmvd (as NO2 @ 15 percent O2) by the use of low NOx 

burners and nitrogen dilution of the fuel gas. Ammonia in the syngas is removed with process 

condensate prior to the low-temperature AGR process and subsequently destroyed in the Claus 

plant burner. This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone 

and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Ninety five percent of mercury is captured from the syngas by an activated carbon bed.

Slightly greater than 92 percent of the CO2 from the syngas is captured in the AGR system and 

compressed for sequestration.

The carbon balance for the plant is shown in Exhibit 3-143. The carbon input to the plant 

consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not used in the 

carbon capture equation below, but it is not neglected in the balance since the Aspen model 

accounts for air components throughout. Carbon leaves the plant as unburned carbon in the ash, 

CO2 in the stack gas and ASU vent gas, and the captured CO2 product. The carbon capture 

efficiency is defined as the amount 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: 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

421

(Carbon in Product for Sequestration)/[(Carbon in the Coal)-(Carbon in Slag)] or

90.0 percent

Exhibit 3-143 Case S4B Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 153,309 (337,988) Slag 1,380 (3,042)

Air (CO2) 529 (1,166) Stack Gas 15,642 (34,484)

ASU Vent 132 (291)

CO2 Product 136,684 (301,337)

Total 153,838 (339,154) Total 153,838 (339,154)

Exhibit 3-144 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur 

in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the 

stack gas, and sulfur that is co-sequestered with the CO2 product. Sulfur in the ash is considered 

negligible. 

Exhibit 3-144 Case S4B Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 2,227 (4,911) Elemental Sulfur 2,223 (4,901)

Stack Gas 1 (2)

CO2 Product 3 (8)

Total 2,227 (4,911) Total 2,227 (4,911)

1 By difference

Exhibit 3-145 shows the overall water balance for the plant. 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, primarily from the coal drying process and as syngas condensate, and that water is reused as internal recycle. Raw water makeup is the difference between water demand and internal 

recycle.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

422

Exhibit 3-145 Case S4B Water Balance

Water Use

Water 

Demand

m3/min (gpm)

Internal 

Recycle 

m3/min (gpm)

Raw Water 

Withdrawal 

m3/min 

(gpm),

Process 

Water 

Discharge 

m3/min 

(gpm),

Raw Water 

Consumption 

m3/min 

(gpm),

S4B S4B S4B S4B S4B

Slag Handling 0.57 (151) 0.57 (151) 0 (0) 0 (0) 0 (0)

Slurry Water 2.68 (708) 2.1 (557) 0.57 (151) 0 (0) 0.57 (151)

SWS Blowdown 0 (0) 0 (0) 0 (0) 0.01 (2) -0.01 (-2)

Condenser Makeup 1.53 (403) 0 (0) 1.53 (403) 0 (0) 1.53 (403)

Shift Steam 1.38 (365) 1.38 (365)

BFW Makeup 0.14 (38) 0.14 (38)

Cooling Tower Makeup 13.22 

(3,492) 0.2 (60) 12.99 (3,432) 2.97 (785) 10.02 (2,647)

BFW Blowdown 0.14 (38) -0.14 (-38)

SWS Blowdown 0.08 (22) -0.08 (-22)

Total 18.0 (4,755) 2.91 (768) 15.1 (3,987) 2.98 (788) 12.11 

(3,199)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

423

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-146:

• Coal gasification and ASU

• Syngas cleanup

• Power block

An overall plant energy balance is provided in tabular form in Exhibit 3-147 based on 0°C 

(32°F) reference conditions. The power out is the combined CT and steam turbine power after 

generator losses.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

424

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Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

425

Exhibit 3-146 Case S4B Heat and Mass Balance 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

426

Exhibit 3-146 Case S4B Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

427

Exhibit 3-146 Case S4B Heat and Mass Balance (Continued)
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

428

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Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

429

Exhibit 3-147 Case S4B Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 6,099 (5,781) 3.1 (3.0) 0 (0) 6,103 (5,784)

ASU Air 0 (0) 14.8 (14.0) 0 (0) 15 (14)

GT Air 0 (0) 44.5 (42.1) 0 (0) 44 (42)

Raw Water Makeup 0 (0) 21.0 (19.9) 0 (0) 21 (20)

Auxiliary Power 0 (0) 0 (0) 764 (724) 764 (724)

Totals 6,099 (5,781) 83.3 (79.0) 764 (724) 6,947 (6,584)

Heat Out GJ/hr (MMBtu/hr)

ASU Intercoolers 0 (0) 342 (324) 0 (0) 342 (324)

ASU Vent 0 (0) 8.6 (8.2) 0 (0) 9 (8)

Slag 45 (43) 29.5 (27.9) 0 (0) 75 (71)

Sulfur 21 (20) 0.3 (0.2) 0 (0) 21 (20)

CO2 0 (0) -48.6 (-46.0) 0 (0) -49 (-46)

CO2 Comp Intercoolers 0 (0) 176.2 (167.0) 0 (0) 176 (167)

Cooling Tower Blowdown 0 (0) 16.6 (15.7) 0 (0) 17 (16)

HRSG Flue Gas 0 (0) 1,182 (1,120) 0 (0) 1,182 (1,120)

Condenser 0 (0) 1,720 (1,631) 0 (0) 1,720 (1,631)

Auxiliary Cooling 0 (0) 132 (125) 0 (0) 132 (125)

Generator Loss 0 (0) 0 (0) 40 (38) 40 (38)

Process Losses 0 (0) 663 (629) 0 (0) 663 (629)

Power 0 (0) 0 (0) 2,618 (2,481) 2,618 (2,481)

Totals 66 (62) 4,223 (4,003) 2,658 (2,519) 6,947 (6,584)

3.5.10 Case S4B Equipment List

Major equipment items for the CoP E-GasTM gasifier with CO2 capture are shown in the 

following tables. The accounts used in the equipment list correspond to the account numbers 

used in the cost estimates in Section 3.5.11. In general, the design conditions include a 

10 percent contingency for flows and heat duties and a 21 percent contingency for heads on 

pumps and fans.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

430

ACCOUNT 1 COAL HANDLING

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Bottom Trestle Dumper and Receiving 

Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0

4 Transfer Tower No. 1 Enclosed N/A 1 0

5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0

8 Reclaim Hopper N/A 64 tonne (70 ton) 2 1

9 Feeder Vibratory 254 tonne/hr (280 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 508 tonne/hr (560 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 254 tonne (280 ton) 2 0

13 Crusher Impactor 

reduction

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 1 1

15 Conveyor No. 4 Belt w/tripper 508 tonne/hr (560 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 508 tonne/hr (560 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 1,089 tonne (1,200 ton) 3 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

431

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Feeder Vibratory 109 tonne/hr (120 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 336 tonne/hr (370 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 671 tonne (740 ton) 1 0

4 Weigh Feeder Belt 172 tonne/hr (190 tph) 2 0

5 Rod Mill Rotary 172 tonne/hr (190 tph) 2 0

6 Slurry Water Storage 

Tank with Agitator Field erected 530,530 liters (140,150 gal) 2 0

7 Slurry Water Pumps Centrifugal 2,953 lpm (780 gpm) 1 0

8 Trommel Screen Coarse 263 tonne/hr (290 tph) 2 0

9 Rod Mill Discharge 

Tank with Agitator Field erected 483,250 liters (127,660 gal) 2 0

10 Rod Mill Product 

Pumps Centrifugal 4,164 lpm (1100 gpm) 2 0

11 Slurry Storage Tank 

with Agitator Field erected 2,899,649 liters (766,000 gal) 1 0

12 Slurry Recycle Pumps Centrifugal 7,949 lpm (2,100 gpm) 2 2

13 Slurry Product Pumps Positive displacement 4,164 lpm (1,100 gpm) 2 2
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

432

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, 

outdoor 560,241 liters (148,000 gal) 2 0

2 Condensate Pumps Vertical canned 8,290 lpm @ 91 m H2O

(2,190 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray 

type 573,341 kg/hr (1,264,000 lb/hr) 2 0

4 Intermediate Pressure Feedwater 

Pump

Horizontal 

centrifugal, single 

stage

2,158 lpm @ 27 m H2O

(570 gpm @ 90 ft H2O) 2 1

5 High Pressure Feedwater Pump No. 

1

Barrel type, multistage, centrifugal

HP water: 5,754 lpm @ 1,890 m 

H2O (1,520 gpm @ 6,200 ft 

H2O)

2 1

6 High Pressure Feedwater Pump No. 

2

Barrel type, multistage, centrifugalIP water: 189 lpm @ 223 m 

H2O (50 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) 1 0

8 Service Air Compressors Flooded Screw 28 m3

/min @ 0.7 MPa

(1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, 

regenerative 28 m3

/min (1,000 scfm) 2 1

10 Closed Cycle Cooling Heat 

Exchangers Plate and frame 372 GJ/hr (353 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water 

Pumps

Horizontal 

centrifugal

133,625 lpm @ 21 m H2O

(35,300 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) 1 1
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

433

Equipment 

No. Description Type Design Condition Operating Qty Spares

13 Fire Service Booster Pump

Two-stage 

horizontal 

centrifugal

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, 

single suction

3,785 lpm @ 18 m H2O

(1,000 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, 

single suction

2,536 lpm @ 268 m H2O

(670 gpm @ 880 ft H2O) 2 1

16 Filtered Water Pumps Stainless steel, 

single suction

1,931 lpm @ 49 m H2O

(510 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 927,426 liter (245,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and 

mixed bed 908 lpm (240 gpm) 2 0

19 Liquid Waste Treatment System 10 years, 24-hour storm 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

434

ACCOUNT 4 GASIFIER, ASU, AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Gasifier Pressurized two-stage, slurry-feed 

entrained bed

4,082 tonne/day, 4.2 MPa

(4,500 tpd, 615 psia) 2 0

2 Synthesis Gas 

Cooler Fire-tube boiler 391,450 kg/hr (863,000 lb/hr) 2 0

3 Synthesis Gas 

Cyclone High efficiency 391,450 kg/hr (863,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with pulse-jet 

cleaning metallic filters 2 0

5

Syngas Scrubber 

Including Sour 

Water Stripper

Vertical up flow 391,450 kg/hr (863,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with condensate drain 417,759 kg/hr (921,000 lb/hr) 8 0

7 Raw Gas Knockout 

Drum Vertical with mist eliminator 327,494 kg/hr, 35°C, 3.9 MPa(722,000 lb/hr, 95°F, 560 psia) 2 0

8 Synthesis Gas 

Reheater Shell and tube 50,349 kg/hr (111,000 lb/hr) 2 0

9 Flare Stack Self-supporting, carbon steel, stainless 

steel top, pilot ignition

391,450 kg/hr (863,000 lb/hr) 

syngas

2 0

10 ASU Main Air 

Compressor Centrifugal, multi-stage 7,277 m3

/min @ 1.3 MPa

(257,000 scfm @ 190 psia) 2 0

11 Cold Box Vendor design 2,903 tonne/day (3,200 tpd)

of 95% purity oxygen 2 0

12 Oxygen 

Compressor Centrifugal, multi-stage

1,501 m3

/min (53,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 5.1 MPa (740 psia)

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

435

Equipment 

No. Description Type Design Condition Operating Qty Spares

13 Primary Nitrogen 

Compressor Centrifugal, multi-stage

3,115 m3/min (110,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 0

14 Secondary Nitrogen 

Compressor Centrifugal, single-stage

680 m3/min (24,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 0

15

Syngas Dilution 

Nitrogen Boost 

Compressor

Centrifugal, single-stage

1,750 m3/min (61,800 scfm)

Suction - 2.6 MPa (384 psia)

Discharge - 3.2 MPa (469 psia)

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

436

ACCOUNT 5 SYNGAS CLEANUP

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Mercury Adsorber Sulfated carbon 

bed

327,494 kg/hr (722,000 lb/hr) 

35°C (95°F) 

3.6 MPa (525 psia)

2 0

2 Sulfur Plant Claus type 59 tonne/day (65 tpd) 1 0

3 Water Gas Shift Reactors Fixed bed, 

catalytic

417,759 kg/hr (921,000 lb/hr) 

232°C (450°F) 

4.0 MPa (580 psia)

4 0

4 Shift Reactor Heat Recovery 

Exchangers Shell and Tube Exchanger 1: 133 GJ/hr (126 MMBtu/hr) 4 0

5 Acid Gas Removal Plant Two-stage 

Selexol

327,494 kg/hr (722,000 lb/hr) 

35°C (95°F) 

3.5 MPa (515 psia)

2 0

6 Hydrogenation Reactor Fixed bed, 

catalytic

17,274 kg/hr (38,083 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

1 0

7 Tail Gas Recycle Compressor Centrifugal 14,644 kg/hr (32,284 lb/hr) 1 0

ACCOUNT 5B CO2 COMPRESSION

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 CO2

Compressor

Integrally geared, multi-stage 

centrifugal

1,240 m3

/min @ 15.3 MPa (43,800 

scfm @ 2,215 psia) 4 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

437

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Gas Turbine Advanced F 

class 215 MW 2 0

2 Gas Turbine Generator TEWAC 240 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0

ACCOUNT 7 HRSG, DUCTING AND STACK

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x

8.7 m (19 ft) diameter 2 0

2 Heat Recovery 

Steam Generator

Drum, multi-pressure with 

economizer section and 

integral deaerator

Main steam - 326,042 kg/hr, 12.4 MPa/533°C

(718,800 lb/hr, 1,800 psig/992°F)

Reheat steam - 384,422 kg/hr, 3.1 MPa/533°C

(847,506 lb/hr, 452 psig/992°F)

2 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

438

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Steam Turbine Commercially 

available

314 MW

12.4 MPa/533°C/533°C (1,800 psig/ 992°F/992°F) 1 0

2 Steam Turbine 

Generator

Hydrogen cooled, 

static excitation

350 MVA @ 0.9 p.f.,

24 kV, 60 Hz, 3-phase 1 0

3 Surface 

Condenser

Single pass, divided 

waterbox including 

vacuum pumps

950 GJ/hr (900 MMBtu/hr), 

Condensing temperature 32°C (90°F), 

Inlet water temperature 9°C (48°F), 

Water temperature rise 11°C (20°F)

1 0

4 Air-cooled 

Condenser ---

950 GJ/hr (900 MMBtu/hr), 

Condensing temperature 32°C (90°F), 

Ambient temperature 6°C (42°F)

1 0

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Circulating Water 

Pumps Vertical, wet pit 340,687 lpm @ 30 m(90,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative, mechanical draft, 

multi-cell

3°C (37°F) WB / 9°C (48°F) CWT / 

20°C (68°F) HWT / 1,899 GJ/hr 

(1,800 MMBtu/hr) heat duty

1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

439

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 Slag Quench Tank Water bath 276,335 liters (73,000 gal) 2 0

2 Slag Crusher Roll 15 tonne/hr (16 tph) 2 0

3 Slag Depressurizer Proprietary 15 tonne/hr (16 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 166,558 liters (44,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 75,708 liters (20,000 gal) 2 0

6 Slag Conveyor Drag chain 15 tonne/hr (16 tph) 2 0

7 Slag Separation Screen Vibrating 15 tonne/hr (16 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 15 tonne/hr (16 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 238,481 liters (63,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 76 lpm @ 14 m H2O

(20 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 75,708 liters (20,000 gal) 2 0

12 Grey Water Pumps Centrifugal 265 lpm @ 433 m H2O

(70 gpm @ 1,420 ft H2O) 2 2

13 Slag Storage Bin Vertical, field erected 1,089 tonne (1,200 tons) 2 0

14 Unloading Equipment Telescoping chute 118 tonne/hr (130 tph) 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

440

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 CTG Step-up Transformer Oil-filled 24 kV/345 kV, 240 MVA,

3-ph, 60 Hz 2 0

2 STG Step-up Transformer Oil-filled 24 kV/345 kV, 340 MVA,

3-ph, 60 Hz 1 0

3 High Voltage Auxiliary 

Transformer Oil-filled 345 kV/13.8 kV, 70 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Auxiliary 

Transformer Oil-filled 24 kV/4.16 kV, 94 MVA,3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 14 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 2 0

7 STG Isolated Phase Bus Duct 

and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency 

shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

441

ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment 

No. Description Type Design Condition Operating Qty Spares

1 DCS - Main Control

Monitor/keyboard; Operator 

printer (laser color); 

Engineering printer (laser 

B&W)

Operator stations/printers and 

engineering stations/printers 1 0

2 DCS - Processor Microprocessor with redundant 

input/output N/A 1 0

3 DCS - Data Highway Fiber optic Fully redundant, 25% spare 1 0
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

442

3.5.11 Case S4B Cost Estimating

Costs Results

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-148 shows 

the TPC summary organized by cost account with a more detailed breakdown of the capital costs 

shown in Exhibit 3-149. Exhibit 3-150 shows the calculation and addition of owner’s costs to 

determine the TOC, used to calculate COE. Exhibit 3-151 shows the initial and annual O&M 

costs for Case S4B.

The estimated TOC of the CoP E-GasTM IGCC plant with CO2 capture using PRB coal is 

$3,851/kW. Process contingency represents 4 percent, project contingency represents 

11 percent, and owner’s costs represent 18 percent of TOC. The COE is 112.3 mills/kWh.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

443

Exhibit 3-148 Case S4B Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S4B - ConocoPhillips IGCC w/ CO2

Plant Size: 515.11 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING $17,484 $3,249 $13,559 $0 $0 $34,292 $3,113 $0 $7,481 $44,886 $87

 2 COAL & SORBENT PREP & FEED $30,185 $5,517 $18,237 $0 $0 $53,939 $4,842 $0 $11,756 $70,538 $137

 3 FEEDWATER & MISC. BOP SYSTEMS $8,916 $7,230 $8,653 $0 $0 $24,800 $2,336 $0 $6,215 $33,351 $65

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $145,903 $0 $79,531 $0 $0 $225,434 $20,280 $31,720 $42,380 $319,815 $621

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $207,324 $0 w/equip. $0 $0 $207,324 $20,096 $0 $22,742 $250,162 $486

4.4-4.9 Other Gasification Equipment $24,306 $12,187 $15,965 $0 $0 $52,457 $5,014 $0 $12,419 $69,889 $136

SUBTOTAL 4 $377,533 $12,187 $95,496 $0 $0 $485,215 $45,390 $31,720 $77,541 $639,866 $1,242

 5A GAS CLEANUP & PIPING $90,779 $3,037 $75,014 $0 $0 $168,830 $16,307 $27,123 $42,594 $254,854 $495

5B CO2 COMPRESSION $20,780 $0 $12,237 $0 $0 $33,018 $3,179 $0 $7,239 $43,436 $84

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,610 $9,348 $9,861 $11,782 $129,600 $252

6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5

SUBTOTAL 6 $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $256

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $31,545 $0 $4,485 $0 $0 $36,031 $3,426 $0 $3,946 $43,402 $84

7.2-7.9 Open, Ductwork and Stack $3,418 $2,436 $3,191 $0 $0 $9,045 $839 $0 $1,608 $11,492 $22

SUBTOTAL 7 $34,963 $2,436 $7,677 $0 $0 $45,076 $4,264 $0 $5,554 $54,895 $107

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $30,702 $0 $5,308 $0 $0 $36,010 $3,455 $0 $3,947 $43,412 $84

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $39,331 $1,059 $12,929 $0 $0 $53,319 $5,181 $0 $11,889 $70,389 $137

SUBTOTAL 8 $70,034 $1,059 $18,237 $0 $0 $89,329 $8,637 $0 $15,835 $113,801 $221

 9 COOLING WATER SYSTEM $8,342 $8,140 $6,985 $0 $0 $23,467 $2,180 $0 $5,242 $30,889 $60

10 ASH/SPENT SORBENT HANDLING SYS $21,401 $1,623 $10,619 $0 $0 $33,643 $3,228 $0 $4,023 $40,893 $79

11 ACCESSORY ELECTRIC PLANT $33,841 $13,137 $25,530 $0 $0 $72,507 $6,227 $0 $14,935 $93,669 $182

12 INSTRUMENTATION & CONTROL $11,248 $2,069 $7,247 $0 $0 $20,564 $1,864 $1,028 $3,908 $27,364 $53

13 IMPROVEMENTS TO SITE $3,470 $2,045 $8,562 $0 $0 $14,077 $1,390 $0 $4,640 $20,107 $39

14 BUILDINGS & STRUCTURES $0 $6,957 $7,977 $0 $0 $14,934 $1,360 $0 $2,664 $18,958 $37

 

TOTAL COST $821,003 $69,492 $323,505 $0 $0 $1,214,001 $113,822 $69,732 $221,967 $1,619,522 $3,144

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

444

Exhibit 3-149 Case S4B Total Plant Cost Summary Details

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S4B - ConocoPhillips IGCC w/ CO2

Plant Size: 515.11 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $4,591 $0 $2,244 $0 $0 $6,835 $612 $0 $1,490 $8,937 $17

1.2 Coal Stackout & Reclaim $5,933 $0 $1,438 $0 $0 $7,372 $646 $0 $1,604 $9,621 $19

1.3 Coal Conveyors & Yd Crush $5,516 $0 $1,423 $0 $0 $6,940 $609 $0 $1,510 $9,058 $18

1.4 Other Coal Handling $1,443 $0 $329 $0 $0 $1,773 $155 $0 $386 $2,313 $4

1.5 Sorbent Receive & Unload $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

1.7 Sorbent Conveyors $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

1.9 Coal & Sorbent Hnd.Foundations $0 $3,249 $8,124 $0 $0 $11,373 $1,090 $0 $2,493 $14,956 $29

SUBTOTAL 1. $17,484 $3,249 $13,559 $0 $0 $34,292 $3,113 $0 $7,481 $44,886 $87

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying (incl. w/2.3) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,987 $475 $312 $0 $0 $2,774 $237 $0 $602 $3,613 $7

2.3 Slurry Prep & Feed $27,106 $0 $12,055 $0 $0 $39,161 $3,496 $0 $8,531 $51,188 $99

2.4 Misc.Coal Prep & Feed $1,093 $795 $2,384 $0 $0 $4,272 $393 $0 $933 $5,597 $11

2.5 Sorbent Prep Equipment $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

2.7 Sorbent Injection System $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

2.9 Coal & Sorbent Feed Foundation $0 $4,247 $3,487 $0 $0 $7,733 $716 $0 $1,690 $10,140 $20

SUBTOTAL 2. $30,185 $5,517 $18,237 $0 $0 $53,939 $4,842 $0 $11,756 $70,538 $137

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,699 $4,635 $2,447 $0 $0 $9,780 $906 $0 $2,137 $12,823 $25

3.2 Water Makeup & Pretreating $548 $57 $306 $0 $0 $912 $87 $0 $300 $1,299 $3

3.3 Other Feedwater Subsystems $1,477 $499 $449 $0 $0 $2,425 $218 $0 $529 $3,171 $6

3.4 Service Water Systems $314 $646 $2,242 $0 $0 $3,202 $312 $0 $1,054 $4,569 $9

3.5 Other Boiler Plant Systems $1,684 $652 $1,617 $0 $0 $3,953 $375 $0 $866 $5,194 $10

3.6 FO Supply Sys & Nat Gas $313 $591 $552 $0 $0 $1,456 $140 $0 $319 $1,916 $4

3.7 Waste Treatment Equipment $766 $0 $468 $0 $0 $1,234 $120 $0 $406 $1,760 $3

3.8 Misc. Power Plant Equipment $1,115 $149 $573 $0 $0 $1,837 $177 $0 $604 $2,619 $5

SUBTOTAL 3. $8,916 $7,230 $8,653 $0 $0 $24,800 $2,336 $0 $6,215 $33,351 $65

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $145,903 $0 $79,531 $0 $0 $225,434 $20,280 $31,720 $42,380 $319,815 $621

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $207,324 $0 w/equip. $0 $0 $207,324 $20,096 $0 $22,742 $250,162 $486

4.4 LT Heat Recovery & FG Saturation $24,306 $0 $9,240 $0 $0 $33,546 $3,274 $0 $7,364 $44,183 $86

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Other Gasification Equipment $0 $1,399 $569 $0 $0 $1,968 $189 $0 $431 $2,588 $5

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $10,788 $6,155 $0 $0 $16,943 $1,551 $0 $4,623 $23,117 $45

SUBTOTAL 4. $377,533 $12,187 $95,496 $0 $0 $485,215 $45,390 $31,720 $77,541 $639,866 $1,242

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

445

Exhibit 3-149 Case S4B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S4B - ConocoPhillips IGCC w/ CO2

Plant Size: 515.11 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $73,047 $0 $61,982 $0 $0 $135,029 $13,059 $27,006 $35,019 $210,112 $408

5A.2 Elemental Sulfur Plant $5,613 $1,119 $7,241 $0 $0 $13,973 $1,357 $0 $3,066 $18,396 $36

5A.3 Mercury Removal $1,328 $0 $1,011 $0 $0 $2,339 $226 $117 $536 $3,218 $6

5A.4 Shift Reactors $8,762 $0 $3,527 $0 $0 $12,288 $1,178 $0 $2,693 $16,160 $31

5A.5 Particulate Removal w/4.1 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Blowback Gas Systems $2,030 $342 $192 $0 $0 $2,564 $243 $0 $561 $3,368 $7

5A.7 Fuel Gas Piping $0 $784 $549 $0 $0 $1,332 $124 $0 $291 $1,747 $3

5A.9 HGCU Foundations $0 $794 $512 $0 $0 $1,305 $120 $0 $428 $1,853 $4

SUBTOTAL 5A. $90,779 $3,037 $75,014 $0 $0 $168,830 $16,307 $27,123 $42,594 $254,854 $495

5B CO2 COMPRESSION

5B.1 CO2 Removal System w/ 5A.1 $0 w/ 5A.1 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $20,780 $0 $12,237 $0 $0 $33,018 $3,179 $0 $7,239 $43,436 $84

SUBTOTAL 5B. $20,780 $0 $12,237 $0 $0 $33,018 $3,179 $0 $7,239 $43,436 $84

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,610 $9,348 $9,861 $11,782 $129,600 $252

6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5

SUBTOTAL 6. $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $256

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $31,545 $0 $4,485 $0 $0 $36,031 $3,426 $0 $3,946 $43,402 $84

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,752 $1,250 $0 $0 $3,002 $263 $0 $653 $3,918 $8

7.4 Stack $3,418 $0 $1,284 $0 $0 $4,701 $450 $0 $515 $5,667 $11

7.9 HRSG,Duct & Stack Foundations $0 $685 $658 $0 $0 $1,342 $125 $0 $440 $1,907 $4

SUBTOTAL 7. $34,963 $2,436 $7,677 $0 $0 $45,076 $4,264 $0 $5,554 $54,895 $107

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $30,702 $0 $5,308 $0 $0 $36,010 $3,455 $0 $3,947 $43,412 $84

8.2 Turbine Plant Auxiliaries $213 $0 $489 $0 $0 $703 $69 $0 $77 $849 $2

8.3a Condenser & Auxiliaries $3,378 $0 $1,079 $0 $0 $4,457 $426 $0 $488 $5,372 $10

8.3b Air Cooled Condenser $30,958 $0 $6,207 $0 $0 $37,164 $3,716 $0 $8,176 $49,057 $95

8.4 Steam Piping $4,782 $0 $3,364 $0 $0 $8,146 $700 $0 $2,211 $11,057 $21

8.9 TG Foundations $0 $1,059 $1,790 $0 $0 $2,849 $270 $0 $936 $4,054 $8

SUBTOTAL 8. $70,034 $1,059 $18,237 $0 $0 $89,329 $8,637 $0 $15,835 $113,801 $221

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $5,767 $0 $1,122 $0 $0 $6,889 $656 $0 $1,132 $8,677 $17

9.2 Circulating Water Pumps $1,500 $0 $99 $0 $0 $1,599 $135 $0 $260 $1,993 $4

9.3 Circ.Water System Auxiliaries $129 $0 $18 $0 $0 $148 $14 $0 $24 $186 $0

9.4 Circ.Water Piping $0 $5,400 $1,400 $0 $0 $6,800 $615 $0 $1,483 $8,897 $17

9.5 Make-up Water System $309 $0 $442 $0 $0 $751 $72 $0 $165 $988 $2

9.6 Component Cooling Water Sys $637 $762 $542 $0 $0 $1,942 $182 $0 $425 $2,549 $5

9.9 Circ.Water System Foundations $0 $1,977 $3,361 $0 $0 $5,339 $506 $0 $1,753 $7,598 $15

SUBTOTAL 9. $8,342 $8,140 $6,985 $0 $0 $23,467 $2,180 $0 $5,242 $30,889 $60

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

446

Exhibit 3-149 Case S4B Total Plant Cost Summary Details (Continued) Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S4B - ConocoPhillips IGCC w/ CO2

Plant Size: 515.11 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $18,675 $0 $9,209 $0 $0 $27,884 $2,679 $0 $3,056 $33,620 $65

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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

10.4 High Temperature Ash Piping $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

10.6 Ash Storage Silos $618 $0 $672 $0 $0 $1,290 $125 $0 $212 $1,628 $3

10.7 Ash Transport & Feed Equipment $829 $0 $200 $0 $0 $1,029 $96 $0 $169 $1,293 $3

10.8 Misc. Ash Handling Equipment $1,280 $1,568 $469 $0 $0 $3,317 $316 $0 $545 $4,177 $8

10.9 Ash/Spent Sorbent Foundation $0 $55 $69 $0 $0 $123 $12 $0 $40 $175 $0

SUBTOTAL 10. $21,401 $1,623 $10,619 $0 $0 $33,643 $3,228 $0 $4,023 $40,893 $79

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $942 $0 $932 $0 $0 $1,874 $179 $0 $205 $2,259 $4

11.2 Station Service Equipment $4,921 $0 $443 $0 $0 $5,365 $495 $0 $586 $6,445 $13

11.3 Switchgear & Motor Control $9,098 $0 $1,655 $0 $0 $10,752 $997 $0 $1,762 $13,512 $26

11.4 Conduit & Cable Tray $0 $4,226 $13,942 $0 $0 $18,168 $1,757 $0 $4,981 $24,907 $48

11.5 Wire & Cable $0 $8,075 $5,306 $0 $0 $13,381 $972 $0 $3,588 $17,941 $35

11.6 Protective Equipment $0 $680 $2,474 $0 $0 $3,154 $308 $0 $519 $3,981 $8

11.7 Standby Equipment $232 $0 $227 $0 $0 $459 $44 $0 $75 $579 $1

11.8 Main Power Transformers $18,647 $0 $143 $0 $0 $18,790 $1,421 $0 $3,032 $23,243 $45

11.9 Electrical Foundations $0 $155 $408 $0 $0 $563 $54 $0 $185 $802 $2

SUBTOTAL 11. $33,841 $13,137 $25,530 $0 $0 $72,507 $6,227 $0 $14,935 $93,669 $182

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,110 $0 $741 $0 $0 $1,852 $175 $93 $318 $2,438 $5

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $255 $0 $164 $0 $0 $419 $40 $21 $96 $575 $1

12.7 Computer & Accessories $5,923 $0 $190 $0 $0 $6,113 $561 $306 $698 $7,677 $15

12.8 Instrument Wiring & Tubing $0 $2,069 $4,230 $0 $0 $6,299 $534 $315 $1,787 $8,935 $17

12.9 Other I & C Equipment $3,959 $0 $1,923 $0 $0 $5,882 $553 $294 $1,009 $7,739 $15

SUBTOTAL 12. $11,248 $2,069 $7,247 $0 $0 $20,564 $1,864 $1,028 $3,908 $27,364 $53

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $109 $2,327 $0 $0 $2,436 $242 $0 $803 $3,481 $7

13.2 Site Improvements $0 $1,936 $2,573 $0 $0 $4,510 $445 $0 $1,486 $6,441 $13

13.3 Site Facilities $3,470 $0 $3,662 $0 $0 $7,132 $703 $0 $2,350 $10,185 $20

SUBTOTAL 13. $3,470 $2,045 $8,562 $0 $0 $14,077 $1,390 $0 $4,640 $20,107 $39

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1

14.2 Steam Turbine Building $0 $2,560 $3,647 $0 $0 $6,208 $571 $0 $1,017 $7,796 $15

14.3 Administration Building $0 $923 $670 $0 $0 $1,593 $142 $0 $260 $1,995 $4

14.4 Circulation Water Pumphouse $0 $165 $87 $0 $0 $252 $22 $0 $41 $316 $1

14.5 Water Treatment Buildings $0 $458 $447 $0 $0 $905 $82 $0 $148 $1,135 $2

14.6 Machine Shop $0 $450 $308 $0 $0 $758 $67 $0 $124 $949 $2

14.7 Warehouse $0 $727 $469 $0 $0 $1,196 $106 $0 $195 $1,497 $3

14.8 Other Buildings & Structures $0 $435 $339 $0 $0 $774 $69 $0 $169 $1,012 $2

14.9 Waste Treating Building & Str. $0 $973 $1,860 $0 $0 $2,833 $264 $0 $619 $3,716 $7

SUBTOTAL 14. $0 $6,957 $7,977 $0 $0 $14,934 $1,360 $0 $2,664 $18,958 $37

TOTAL COST $821,003 $69,492 $323,505 $0 $0 $1,214,001 $113,822 $69,732 $221,967 $1,619,522 $3,144

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

447

Exhibit 3-150 Case S4B Owner’s Costs

Owner's Costs $x1000 $/kW

Preproduction Costs

6 Months Fixed O&M $15,260 $30

1 Month Variable O&M $4,088 $8

25% of 1 Months Fuel Cost at 100% CF $937 $2

2% of TPC $32,390 $63

Total $52,676 $102

Inventory Capital

60 day supply of consumables at 100% CF $7,986 $16

0.5% of TPC (spare parts) $8,098 $16

Total $16,084 $31

 Initial Cost for Catalyst and Chemicals $7,532 $15

Land $900 $2

Other Owner's Costs $242,928 $472

Financing Costs $43,727 $85

Total Owner's Costs $363,846 $706

Total Overnight Cost (TOC) $1,983,369 $3,851

TASC Multiplier 1.140

Total As-Spent Cost (TASC) $2,261,041 $4,390
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

448

Exhibit 3-151 Case S4B Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case S4B - ConocoPhillips IGCC w/ CO2 Heat Rate-net (Btu/kWh): 11,223

MWe-net: 515

Capacity Factor (%): 80

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 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-O.J.'s 16.0 16.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $6,313,507 $12.257

Maintenance Labor Cost $18,102,733 $35.143

Administrative & Support Labor $6,104,060 $11.850

Property Taxes and Insurance $32,390,449 $62.881

TOTAL FIXED OPERATING COSTS $62,910,750 $122.131

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $33,033,881 $0.00915

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

Water (/1000 gallons) 0 2,867 1.08 $0 $905,553 $0.00025

Chemicals

MU & WT Chem. (lb) 0 17,081 0.17 $0 $863,203 $0.00024

Carbon (Mercury Removal) (lb) 116,627 160 1.05 $122,478 $48,991 $0.00001

COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000

Water Gas Shift Catalyst (ft3) 6,257 4.29 498.83 $3,120,990 $624,198 $0.00017

Selexol Solution (gal) 320,048 102 13.40 $4,288,080 $397,550 $0.00011

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip. 0.87 131.27 $0 $33,524 $0.00001

Subtotal Chemicals $7,531,548 $1,967,466 $0.00055

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 160 0.42 $0 $19,457 $0.00001

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 700 16.23 $0 $3,315,235 $0.00092

Subtotal Waste Disposal $0 $3,334,692 $0.00092

By-products & Emissions 

 Sulfur (tons) 0 59 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $7,531,548 $39,241,592 $0.01087

Fuel (ton) 0 8,101 15.22 $0 $35,993,745 $0.00997
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

449

3.6 IGCC CASE SUMMARY

A summary of the results of the twelve IGCC plant configurations modeled in this study is 

presented in Exhibit 3-152.

The normalized components of TOC and overall TASC are shown for each plant configuration in

Exhibit 3-153. The TOC, which is used for COE calculations, is the TPC plus owner’s costs. 

The following conclusions can be drawn:

• The TOC is higher for the North Dakota elevation lignite coal cases as compared to the 

Montana elevation PRB coal cases by approximately 9 percent.

• The TOC increase to add CO2 capture is approximately 38 percent.

The COE results are shown in Exhibit 3-154 with the capital cost, fixed operating cost, variable 

operating cost, and fuel cost shown separately. In the capture cases, the CO2 TS&M costs are 

also shown as a separate bar segment. The following conclusions can be drawn:

• The COEs for the Shell and Siemens systems are higher than TRIGTM and CoP for both 

capture and non-capture cases. Note that TRIGTM and CoP were only studied for PRB 

coal and TRIGTM with capture only achieved 83 percent carbon capture.

• TRIGTM is the only technology evaluated that has not been demonstrated at commercial 

scale. For this reason, TRIGTM COEs are subject to a greater level of uncertainty than the 

other technologies in the group.

• The COE is dominated by capital charges in all cases. The capital cost component of 

COE ranges from 61 to 66 percent for IGCC cases.

• The fuel cost component is relatively minor in all cases, ranging from 7 to 10 percent of 

the COE for IGCC cases.

• The CO2 TS&M component adds approximately 5 percent to the COE. 

• The COE increases by 40 to 46% percent for IGCC plants when CO2 capture is added.

• The COE is generally lower for Montana PRB cases compared to the North Dakota 

lignite cases.

Exhibit 3-155 shows the COE sensitivity to fuel costs. The solid lines are the COE of noncapture cases. The dotted lines are the capture cases. As expected, all cases show a linear 

decrease in COE with the decrease in coal prices. As the price for PRB coal decreases from 

$0.89 to $0/MMBtu, the average COE decreases from 81 to 73 mills/kWh for the non-capture 

PRB cases and from 115 to 105 mills/kWh for the PRB capture cases. As the price for ND 

lignite coal decreases from $0.83 to $0/MMBtu, the average COE decreases from 85 to 

78 mills/kWh for the non-capture lignite cases and from 123 to 113 mills/kWh for the lignite

capture cases.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

450

Exhibit 3-152 Estimated Performance and Cost Results for IGCC Cases

PERFORMANCE S1A L1A S1B L1B S2A S2B S3A L3A S3B L3B S4A S4B

CO2 Capture No No Yes Yes No Yes No No Yes Yes No Yes

Gross Power Output (kWe) 696,700 752,600 663,400 713,300 652,700 621,300 622,200 678,800 634,700 676,900 738,300 727,200

Auxiliary Power Requirement (kWe) 124,020 135,900 191,790 213,240 107,280 160,450 117,480 135,680 189,410 210,390 133,460 212,130

Net Power Output (kWe) 572,680 616,700 471,610 500,060 545,420 460,850 504,720 543,120 445,290 466,510 604,840 515,070

Coal Flowrate (lb/hr) 542,713 760,093 585,970 814,029 545,197 577,946 531,119 743,918 579,796 801,651 656,228 675,058

HHV Thermal Input (kWth) 1,362,134 1,474,011 1,470,704 1,578,608 1,368,368 1,450,564 1,333,034 1,442,644 1,455,207 1,554,603 1,647,041 1,694,303

Net Plant HHV Efficiency (%) 42.0% 41.8% 32.1% 31.7% 39.9% 31.8% 37.9% 37.6% 30.6% 30.0% 36.7% 30.4%

Net Plant HHV Heat Rate (Btu/kWh) 8,116 8,156 10,641 10,772 8,560 10,740 9,012 9,063 11,151 11,371 9,292 11,224

Raw Water Withdrawal (gpm/MWnet) 3.1 3.0 7.2 7.8 3.7 6.5 4.5 4.0 9.0 8.9 5.4 8.4

Process Water Discharge (gpm/MWnet) 0.8 0.8 1.4 1.6 0.8 1.0 1.1 1.1 1.6 1.7 1.1 1.5

Raw Water Consumption (gpm/MWnet) 2.3 2.2 5.9 6.2 2.9 5.5 3.4 2.9 7.4 7.2 4.3 6.9

CO2 Emissions (lb/MMBtu) 214 219 22 22 211 36 214 219 22 22 213 22

CO2 Emissions (lb/MWhgross) 1,426 1,461 165 170 1,507 287 1,563 1,585 172 175 1,620 174

CO2 Emissions (lb/MWhnet) 1,735 1,783 233 242 1,803 386 1,927 1,981 246 255 1,977 245

SO2 Emissions (lb/MMBtu) 0.0023 0.0023 0.0009 0.0010 0.0019 0.0009 0.0039 0.0021 0.0009 0.0010 0.0016 0.0009

SO2 Emissions (lb/MWhgross) 0.015 0.015 0.007 0.007 0.013 0.007 0.029 0.016 0.007 0.008 0.012 0.007

NOx Emissions (lb/MMBtu) 0.062 0.063 0.050 0.049 0.059 0.049 0.061 0.061 0.051 0.050 0.052 0.044

NOx Emissions (lb/MWhgross) 0.412 0.418 0.381 0.371 0.422 0.390 0.444 0.445 0.397 0.391 0.398 0.348

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

PM Emissions (lb/MWhgross) 0.047 0.047 0.054 0.054 0.051 0.057 0.052 0.051 0.056 0.056 0.054 0.056

Hg Emissions (lb/TBtu) 0.351 0.560 0.351 0.560 0.351 0.351 0.351 0.560 0.351 0.560 0.351 0.351

Hg Emissions (lb/MWhgross) 2.34E-06 3.74E-06 2.66E-06 4.23E-06 2.51E-06 2.80E-06 2.57E-06 4.06E-06 2.75E-06 4.39E-06 2.67E-06 2.79E-06

COST

Total Plant Cost (2007$/kW) 2,506 2,539 3,480 3,584 2,236 3,019 2,610 2,656 3,533 3,626 2,265 3,144

Total Overnight Cost (2007$/kW) 3,056 3,094 4,253 4,378 2,728 3,691 3,185 3,239 4,318 4,430 2,771 3,851

 Bare Erected Cost 1,914 1,941 2,610 2,692 1,692 2,228 2,006 2,044 2,654 2,730 1,737 2,357

 Home Office Expenses 177 179 242 250 157 207 186 189 247 254 162 221

 Project Contingency 343 349 486 502 305 421 359 367 493 508 306 431

 Process Contingency 72 69 142 141 83 164 60 56 139 135 60 135

 Owner's Costs 550 556 773 794 492 672 575 583 785 804 505 706

Total Overnight Cost (2007$x1,000) 1,750,189 1,908,200 2,005,883 2,189,363 1,488,063 1,701,132 1,607,607 1,759,016 1,922,741 2,066,464 1,675,790 1,983,369

Total As Spent Capital (2007$/kW) 3,484 3,527 4,849 4,991 3,110 4,208 3,631 3,692 4,922 5,050 3,159 4,390

COE (mills/kWh, 2007$)1 83.2 83.5 119.7 121.9 74.5 105.2 86.8 87.3 121.7 123.7 78.7 112.3

 CO 2 TS&M Costs 0.0 0.0 6.0 5.7 0.0 5.9 0.0 0.0 6.3 6.2 0.0 5.8

 Fuel Costs 7.2 6.7 9.5 8.9 7.6 9.5 8.0 7.5 9.9 9.4 8.3 10.0

 Variable Costs 8.0 8.2 10.6 11.1 6.8 8.8 8.2 8.4 10.6 11.1 8.3 10.9

 Fixed Costs 13.7 13.6 18.3 18.6 11.8 15.5 14.1 14.0 18.4 18.6 13.0 17.4

 Capital Costs 54.2 54.9 75.4 77.6 48.4 65.4 56.5 57.4 76.6 78.5 49.1 68.3

LCOE (mills/kWh, 2007$)1 105.4 105.8 151.8 154.5 94.5 133.3 110.0 110.7 154.3 156.9 99.8 142.4

Shell IGCC Cases TRIG IGCC Cases Siemens IGCC Cases CoP IGCC Cases

1 CF is 80% for IGCC
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

451

Exhibit 3-153 Plant Capital Costs

3,056

4,253

2,728

3,691

3,185

4,318

2,771

3,851

3,094

4,378

3,239

4,430

3,484

4,849

3,110

4,208

3,631

4,922

3,159

4,390

3,527

4,991

3,692

5,050

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC

S1A No Cap S1B W/Cap S2A No Cap S2B W/Cap S3A No Cap S3B W/Cap S4A No Cap S4B W/Cap L1A No Cap L1B W/Cap L3A No Cap L3B W/Cap

TOC or TASC ($/kW)

TASC

Owner's Cost

Process Contingency

Project Contingency

Home Office Expense

Bare Erected Cost

North Dakota Lignite Coal

Elevation: 1,900 ft

Montana Powder River Basin Coal

Elevation: 3,400 ft
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

452

Exhibit 3-154 COE by Cost Component

54.2

75.4

48.4

65.4

56.5

76.6

49.1

68.3

54.9

77.6

57.4

78.5

13.7

18.3

11.8

15.5

14.1

18.4

13.0

17.4

13.6

18.6

14.0

18.6

8.0

10.6

6.8

8.8

8.2

10.6

8.3

10.9

8.2

11.1

8.4

11.1

7.2

9.5

7.6

9.5

8.0

9.9

8.3

10.0

6.7

8.9

7.5

9.4

6.0

5.9

6.3

5.8

5.7 6.2

83.2

119.7

74.5

105.2

86.8

121.7

78.7

112.3

83.5

121.9

87.3

123.7

0

20

40

60

80

100

120

140

S1A No 

Cap

S1B W/Cap S2A No 

Cap

S2B W/Cap S3A No 

Cap

S3B W/Cap S4A No 

Cap

S4B W/Cap L1A No 

Cap

L1B W/Cap L3A No 

Cap

L3B W/Cap

Shell TRIG Siemens CoP Shell Siemens

COE (2007 mills/kWh)

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs

North Dakota Lignite Coal

Elevation: 1,900 ft

Montana Powder River Basin Coal

Elevation: 3,400 ft
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

453

Exhibit 3-155 COE Sensitivity to Fuel Costs 

0

20

40

60

80

100

120

140

160

0.0 0.5 1.0 1.5 2.0 2.5

COE (2007 mills/kWh)

Coal Price ($/MMBtu)

Siemens Lignite

w/Capture

Shell Lignite

w/Capture

Siemens PRB

w/Capture

Shell PRB

w/Capture

CoP PRB w/Capture

TRIG PRB w/Capture

Siemens Lignite

Siemens PRB

Shell Lignite

Shell PRB

CoP PRB

TRIG PRB

Capacity Factor = 85% for all cases

Study Coal Costs:

Lignite = $0.83/MMBtu

PRB = $0.89/MMBtu
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

454

The sensitivity of COE to CF is shown in Exhibit 3-156. CF is equal to availability since it was 

assumed that the plants are able to operate at 100 percent capacity whenever power production is 

needed. The solid lines are the COE of non-capture cases. The dotted lines are the capture 

cases. All cases show a decrease in COE with the increase in CF. As the CF increases from 

80 to 100 percent, the average COE decreases from 81 to 66 mills/kWh for the non-capture PRB 

cases and from 115 to 94 mills/kWh for the CO2 capture PRB cases. The average COE 

decreases from 85 to 70 mills/kWh for the non-capture lignite cases and from 123 to 

100 mills/kWh for the lignite capture cases.

As presented in Section 2.6 the cost of CO2 avoided was compared in two ways, relative to the 

analogous plant design and compared to a baseline SC PC plant utilizing the same coal. The 

results for the IGCC carbon capture cases are shown in Exhibit 3-157. The cost of CO2 avoided 

compared to the analogous non-capture design averages $45/ton, with a range of $40/ton–

$53/ton. The cost of CO2 avoided, compared to the baseline SC PC non-capture (A) design, was 

determined using results available in Exhibit 2-22 and averages $70/ton, with a range of $63/ton-

$77/ton. The analogous CO2 avoided costs are lower for the Montana PRB than the North 

Dakota lignite cases, mainly because of the capital cost increase in the lignite fuel cases, as well 

as the additional cost for fuel. The cost of CO2 avoided, compared to the baseline SC PC plant, 

follows the same general trend as the COE for each of the cases, after accounting for the TRIGTM 

case only achieving 83 percent overall carbon removal. The comparison of the analogous Shell 

designs is affected by the change from a water quench in the CO2 capture case to high 

temperature syngas heat recovery. This increases efficiency when high water concentrations are 

not required for the WGS reaction, as is the case for non-capture cases and also avoids the 

expense of high temperature heat exchangers, thus increasing the cost of avoiding carbon for the 

semi-analogous Shell cases.

Water demand, internal recycles, and raw water consumption, all normalized by net output, are 

presented in Exhibit 3-158. The following observations can be made:

• The raw water usage is lower in the lignite coal cases because of its higher moisture 

content, and a significant amount of the coal moisture is recovered in the drying process 

for dry feed cases and used as internal recycle. Thus, while the water demand is nearly 

equal in the Montana PRB and North Dakota lignite cases, the water usage is 

significantly lower when using lignite coal.

• The use of the parallel wet/dry cooling system reduces water demand by 36-47 percent in 

the non-capture cases and by 24-30 percent in the CO2 capture cases relative to using a 

purely wet cooling system. The water savings is less in the CO2 capture cases because a 

significant amount of extraction steam is used in the shift reaction and therefore not 

condensed in the surface condenser.

• The water demand is significantly greater in the CO2 capture cases because one-half of 

the condenser load represents a smaller percentage of the total water requirements again 

due primarily to the high shift steam requirement.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

455

Exhibit 3-156 COE Sensitivity to Capacity Factor

0

50

100

150

200

250

300

350

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

COE (2007 mills/kWh)

Capacity Factor (%)

Siemens Lignite

w/Capture

Shell Lignite

w/Capture

Siemens PRB

w/Capture

Shell PRB

w/Capture

CoP PRB w/Capture

TRIG PRB w/Capture

Siemens Lignite

Siemens PRB

Shell Lignite

Shell PRB

CoP PRB

TRIG PRB

Study Capacity Factor is 

80% for all cases
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

456

Exhibit 3-157 Cost of CO2 Avoided in IGCC Cases

48.6

43.28

41.6 40.2

52.7

42.2

74.6

62.90

77.6

66.2 67.5

70.6

0

10

20

30

40

50

60

70

80

90

100

Shell PRB

w/Capture

TRIG PRB w/Capture Siemens PRB

w/Capture

CoP PRB w/Capture Shell Lignite

w/Capture

Siemens Lignite

w/Capture

PRB Lignite

First Year CO2 Avoided Cost (2007$/ton)

Avoided Cost (Analogous Technology w/o Capture Reference)

Avoided Cost (SC PC w/o Capture Reference)

North Dakota Lignite Coal

Elevation: 1,900 ft

Montana Powder River Basin Coal

Elevation: 3,400 ft
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

457

Exhibit 3-158 Normalized Water Usage in IGCC Cases

3.1

7.2

3.7

6.5

4.5

9.0

5.4

8.4

3.0

7.8

4.0

8.9

2.3

5.9

2.9

5.5

3.4

7.4

4.3

6.9

2.2

6.2

2.9

7.2

0

2

4

6

8

10

12

14

S1A No 

Cap

S1B W/Cap S2A No 

Cap

S2B W/Cap S3A No 

Cap

S3B W/Cap S4A No 

Cap

S4B W/Cap L1A No Cap L1B W/Cap L3A No Cap L3B W/Cap

Shell TRIG Siemens CoP Shell Siemens

Water, gpm/MWnet

Raw Water Withdrawal

Process Water Discharge

Raw Water Consumption

North Dakota Lignite Coal

Elevation: 1,900 ft

Montana Powder River Basin Coal

Elevation: 3,400 ft
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

458

The environmental targets were described in Section 2.3. The emissions of SO2, NOx, and PM

are shown in Exhibit 3-159 and mercury emissions are shown in Exhibit 3-160. The following 

observations can be made:

• Emissions of SO2 are uniformly extremely low. The same environmental target was used 

as in the bituminous coal cases of Volume 1 of this study, and because the coal sulfur 

content is significantly lower in the design coals of this study, the resulting SO2

emissions are also significantly lower.

• Particulate emissions are the same for each case because it was a study assumption that 

the combination of cyclones and candle filters would exactly meet the environmental 

target of 0.0071 lb/MMBtu.

• NOx emissions were assumed to be 15 ppmv at 15 percent oxygen in all cases. The 

resulting emissions on a lb/MMBtu basis vary slightly because of the variable coal feed 

rates and flue gas volumes generated among cases.

• Mercury emissions are constant for each coal type and significantly below the NSPS limit 

of 20 x 10-6 lb/MWh for IGCC systems. The emissions shown in Exhibit 3-160 are 

equivalent to 3.7 – 4.4 x 10-6 lb/MWh for the four lignite cases (which have the higher 

Hg concentration of the two coal types), or a minimum of 78 percent less than NSPS.
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

459

Exhibit 3-159 Emissions Profile for IGCC Cases

0.002

0.001 0.002 0.001

0.004

0.001 0.002 0.001

0.002

0.001 0.002 0.001

0.062

0.050

0.059

0.049

0.061

0.051

0.052

0.044

0.063

0.049

0.061

0.050

0.007

0.00

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

S1A No 

Cap

S1B W/Cap S2A No 

Cap

S2B W/Cap S3A No 

Cap

S3B W/Cap S4A No 

Cap

S4B W/Cap L1A No 

Cap

L1B W/Cap L3A No 

Cap

L3B W/Cap

Shell TRIG Siemens CoP Shell Siemens

Emissions, lb/MMBtu

SO2

NOx

Particulate

North Dakota Lignite Coal

Elevation: 1,900 ft

Montana Powder River Basin Coal

Elevation: 3,400 ft
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

460

Exhibit 3-160 Mercury Emission for IGCC Cases

0.351 0.351 0.351 0.351 0.351 0.351 0.351 0.351

0.560 0.560 0.560 0.560

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

S1A No 

Cap

S1B W/Cap S2A No 

Cap

S2B W/Cap S3A No 

Cap

S3B W/Cap S4A No 

Cap

S4B W/Cap L1A No 

Cap

L1B W/Cap L3A No 

Cap

L3B W/Cap

Shell TRIG Siemens CoP Shell Siemens

Mercury Emissions, lb/TBtu

North Dakota Lignite Coal

Elevation: 1,900 ft

Montana Powder River Basin Coal

Elevation: 3,400 ft
Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

461

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Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

462

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Cost and Performance Baseline – Low Rank, Volume 3a (IGCC Cases)

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