Cost and Performance 

Baseline for Fossil Energy 

Plants

Volume 1: Bituminous Coal 

and Natural Gas to Electricity

Revision 2, November 2010

DOE/NETL-2010/1397
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 1: BITUMINOUS COAL AND NATURAL GAS 

TO ELECTRICITY

DOE/2010/1397

Final Report (Original Issue Date, May 2007)

Revision 1, August 2007

Revision 2, November 2010

NETL Contact:

James Black

Combustion Systems Lead

Office of Systems, Analysis and Planning

National Energy Technology Laboratory

www.netl.doe.gov
This page intentionally left blank
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 Pulverized Coal (PC) Combustion, Integrated 

Gasification Combined Cycles (IGCC), and Natural Gas Combined Cycles (NGCC), all with and 

without carbon dioxide (CO2) capture and sequestration assuming that the plants use technology 

available today. 

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. 
Results

This independent analysis of fossil energy plant cost and performance is considered to be the 

most comprehensive set of publicly available data to date. While input was sought from 

technology vendors, the final assessment of performance and cost was determined 

independently, and may not represent the views of the technology vendors. The extent of 

collaboration with technology vendors varied from case to case, with minimal or no input from 

some vendors. Selection of system components and plant configurations from potential options 

and the rapid escalation in labor and material costs made it a challenge to develop state-of-the-art 

configurations and cost estimates. The rigorous expert technical review and systematic use of 

existing vendor quotes and project design/build data to develop the cost estimates in this report 

are believed to provide the most up-to-date performance and costs available in the public 

literature. The main purpose of publishing Revision 2 is to update performance and economic 

results. New data from technology vendors was incorporated into the modeling approach, 

owner’s costs were added to the financial model, and supplemental chapters were added that 

extend beyond the original report scope. The following are highlights of the study:

• Coal-based plants using today’s technology are capable of producing electricity at 

relatively high efficiencies of about 39 percent, higher heating value ([HHV], without 

CO2 capture) on bituminous coal while meeting or exceeding current environmental 

requirements for criteria pollutants.

• Total overnight cost (TOC) for the non-capture plants are as follows: NGCC, $718/kW;

PC, $2,010/kW (average); IGCC, $2,505/kW (average). With CO2 capture, capital costs 

are: NGCC, $1,497/kW; PC, $3,590/kW (average); IGCC, $3,568/kW (average).

• At fuel costs of $1.64/MMBtu of coal and $6.55/MMBtu of natural gas, the COE for the 

non-capture plants is: 59 mills/kWh for NGCC, 59 mills/kWh for PC (average), and 77

mills/kWh (average) for IGCC.

• When today’s technology for CO2 capture and sequestration (CCS) is integrated into 

these new power plants, the resultant COE, including the cost of CO2 TS&M, is: 86

mills/kWh for NGCC; 108 mills/kWh (average) for PC; and 112 mills/kWh (average) for 

IGCC. The cost of transporting CO2 50 miles for storage in a geologic formation with 

over 30 years of monitoring is estimated to add about 3 to 6 mills/kWh. This represents 

less than 5.5 percent of the COE for each CO2 capture case. 

• A sensitivity study on natural gas price shows that at a coal price of $1.64/MMBtu, the 

average COE for IGCC with capture equals that of NGCC with CO2 capture at a gas price 

of $9.80/MMBtu. The average COE for PC with capture equals that of NGCC with 

capture at a gas price of $9.25/MMBtu. In terms of capacity factor (CF), when noncapture NGCC drops to 40 percent, such as in a peaking application, the COE is 

comparable to non-capture IGCC operating at base load (80 percent CF). 

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 for Fossil Energy Plants

VII

Table of Contents

TABLE OF CONTENTS ..........................................................................................................VII

LIST OF EXHIBITS...................................................................................................................XI

PREPARED BY ....................................................................................................................... XIX

ACKNOWLEDGMENTS.........................................................................................................XX

LIST OF ACRONYMS AND ABBREVIATIONS............................................................... XXI

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

PERFORMANCE..............................................................................................................................3

ENERGY EFFICIENCY..................................................................................................................3

WATER USE................................................................................................................................7

COST RESULTS..............................................................................................................................9

TOTAL OVERNIGHT COST............................................................................................................9

COST OF ELECTRICITY..............................................................................................................11

CO2 EMISSION PRICE IMPACT ..................................................................................................16

COST OF CO2AVOIDED............................................................................................................19

ENVIRONMENTAL PERFORMANCE...............................................................................................21

1. INTRODUCTION................................................................................................................27

2. GENERAL EVALUATION BASIS ...................................................................................31

2.1 SITE CHARACTERISTICS ..................................................................................................31

2.2 COAL CHARACTERISTICS ................................................................................................32

2.3 NATURAL GAS CHARACTERISTICS..................................................................................34

2.4 ENVIRONMENTAL TARGETS ............................................................................................34

2.4.1 IGCC..........................................................................................................................37

2.4.2 PC ..............................................................................................................................38

2.4.3 NGCC.........................................................................................................................39

2.4.4 CARBON DIOXIDE ........................................................................................................40

2.5 CAPACITY FACTOR .........................................................................................................41

2.6 RAW WATER WITHDRAWAL AND CONSUMPTION............................................................41

2.7 COST ESTIMATING METHODOLOGY ................................................................................42

2.7.1 CAPITAL COSTS............................................................................................................42

2.7.2 OPERATIONS AND MAINTENANCE COSTS .......................................................................52

2.7.3 CO2 TRANSPORT, STORAGE AND MONITORING ..............................................................53

2.7.4 FINANCE STRUCTURE, DISCOUNTED CASH FLOW ANALYSIS, AND COE..........................56

2.8 IGCC STUDY COST ESTIMATES COMPARED TO INDUSTRY ESTIMATES ..........................63

3. IGCC POWER PLANTS ....................................................................................................67

3.1 IGCC COMMON PROCESS AREAS ...................................................................................67

3.1.1 COAL RECEIVING AND STORAGE ...................................................................................67

3.1.2 AIR SEPARATION UNIT (ASU) CHOICE AND INTEGRATION .............................................68

3.1.3 WATER GAS SHIFT REACTORS.......................................................................................72

3.1.4 MERCURY REMOVAL ....................................................................................................72

3.1.5 ACID GAS REMOVAL (AGR) PROCESS SELECTION .........................................................73

3.1.6 SULFUR RECOVERY/TAIL GAS CLEANUP PROCESS SELECTION .......................................81

3.1.7 SLAG HANDLING ..........................................................................................................84

3.1.8 POWER ISLAND ............................................................................................................84

3.1.9 STEAM GENERATION ISLAND.........................................................................................88
Cost and Performance Baseline for Fossil Energy Plants

VIII

3.1.10 ACCESSORY ELECTRIC PLANT ...................................................................................92

3.1.11 INSTRUMENTATION AND CONTROL ............................................................................92

3.2 GENERAL ELECTRIC ENERGY IGCC CASES ....................................................................93

3.2.1 GASIFIER BACKGROUND...............................................................................................94

3.2.2 PROCESS DESCRIPTION ................................................................................................96

3.2.3 KEY SYSTEM ASSUMPTIONS.........................................................................................103

3.2.4 SPARING PHILOSOPHY................................................................................................105

3.2.5 CASE 1 PERFORMANCE RESULTS ................................................................................105

3.2.6 CASE 1 - MAJOR EQUIPMENT LIST ..............................................................................116

3.2.7 CASE 1 - COST ESTIMATING........................................................................................124

3.2.8 CASE 2 - GEE IGCC WITH CO2 CAPTURE ..................................................................131

3.2.9 CASE 2 PERFORMANCE RESULTS ................................................................................135

3.2.10 CASE 2 - MAJOR EQUIPMENT LIST ..........................................................................146

3.2.11 CASE 2 - COST ESTIMATING....................................................................................155

3.3 CONOCOPHILLIPS E-GASTM IGCC CASES.....................................................................162

3.3.1 GASIFIER BACKGROUND.............................................................................................162

3.3.2 PROCESS DESCRIPTION ..............................................................................................164

3.3.3 KEY SYSTEM ASSUMPTIONS.........................................................................................170

3.3.4 SPARING PHILOSOPHY................................................................................................170

3.3.5 CASE 3 PERFORMANCE RESULTS ................................................................................172

3.3.6 CASE 3 - MAJOR EQUIPMENT LIST ..............................................................................182

3.3.7 CASE 3 - COSTS ESTIMATING RESULTS ........................................................................191

3.3.8 CASE 4 - E-GASTM IGCC POWER PLANT WITH CO2 CAPTURE.....................................198

3.3.9 CASE 4 PERFORMANCE RESULTS ................................................................................202

3.3.10 CASE 4 - MAJOR EQUIPMENT LIST ..........................................................................214

3.3.11 CASE 4 - COST ESTIMATING RESULTS......................................................................222

3.4 SHELL GLOBAL SOLUTIONS IGCC CASES.....................................................................229

3.4.1 GASIFIER BACKGROUND.............................................................................................229

3.4.2 PROCESS DESCRIPTION ..............................................................................................231

3.4.3 KEY SYSTEM ASSUMPTIONS.........................................................................................237

3.4.4 SPARING PHILOSOPHY................................................................................................239

3.4.5 CASE 5 PERFORMANCE RESULTS ................................................................................239

3.4.6 CASE 5 - MAJOR EQUIPMENT LIST ..............................................................................250

3.4.7 CASE 5 - COST ESTIMATING........................................................................................258

3.4.8 CASE 6 - SHELL IGCC POWER PLANT WITH CO2 CAPTURE .........................................265

3.4.9 CASE 6 PERFORMANCE RESULTS ................................................................................271

3.4.10 CASE 6 - MAJOR EQUIPMENT LIST ..........................................................................282

3.4.11 CASE 6 - COST ESTIMATING....................................................................................290

3.5 IGCC CASE SUMMARY.................................................................................................297

4. PULVERIZED COAL RANKINE CYCLE PLANTS ...................................................305

4.1 PC COMMON PROCESS AREAS......................................................................................306

4.1.1 COAL AND SORBENT RECEIVING AND STORAGE ...........................................................306

4.1.2 STEAM GENERATOR AND ANCILLARIES ........................................................................306

4.1.3 NOX CONTROL SYSTEM...............................................................................................309

4.1.4 PARTICULATE CONTROL .............................................................................................310

4.1.5 MERCURY REMOVAL ..................................................................................................310
Cost and Performance Baseline for Fossil Energy Plants

IX

4.1.6 FLUE GAS DESULFURIZATION.....................................................................................310

4.1.7 CARBON DIOXIDE RECOVERY FACILITY.......................................................................313

4.1.8 POWER GENERATION..................................................................................................318

4.1.9 BALANCE OF PLANT ...................................................................................................318

4.1.10 ACCESSORY ELECTRIC PLANT .................................................................................322

4.1.11 INSTRUMENTATION AND CONTROL ..........................................................................322

4.2 SUBCRITICAL PC CASES ...............................................................................................322

4.2.1 PROCESS DESCRIPTION ..............................................................................................323

4.2.2 KEY SYSTEM ASSUMPTIONS.........................................................................................327

4.2.3 SPARING PHILOSOPHY................................................................................................329

4.2.4 CASE 9 PERFORMANCE RESULTS ................................................................................329

4.2.5 CASE 9 – MAJOR EQUIPMENT LIST .............................................................................338

4.2.6 CASE 9 – COST ESTIMATING .......................................................................................346

4.2.7 CASE 10 – PC SUBCRITICAL UNIT WITH CO2 CAPTURE ...............................................353

4.2.8 CASE 10 PERFORMANCE RESULTS ..............................................................................353

4.2.9 CASE 10 – MAJOR EQUIPMENT LIST ...........................................................................364

4.2.10 CASE 10 – COST ESTIMATING .................................................................................373

4.3 SUPERCRITICAL PC CASES ............................................................................................380

4.3.1 PROCESS DESCRIPTION ..............................................................................................380

4.3.2 KEY SYSTEM ASSUMPTIONS.........................................................................................384

4.3.3 SPARING PHILOSOPHY................................................................................................385

4.3.4 CASE 11 PERFORMANCE RESULTS ..............................................................................385

4.3.5 CASE 11 – MAJOR EQUIPMENT LIST ...........................................................................394

4.3.6 CASE 11 – COSTS ESTIMATING RESULTS......................................................................402

4.3.7 CASE 12 – SUPERCRITICAL PC WITH CO2 CAPTURE....................................................409

4.3.8 CASE 12 PERFORMANCE RESULTS ..............................................................................409

4.3.9 CASE 12 – MAJOR EQUIPMENT LIST ...........................................................................420

4.3.10 CASE 12 – COST ESTIMATING BASIS ........................................................................429

4.4 PC CASE SUMMARY......................................................................................................436

5. NATURAL GAS COMBINED CYCLE PLANTS .........................................................443

5.1 NGCC COMMON PROCESS AREAS................................................................................443

5.1.1 NATURAL GAS SUPPLY SYSTEM ...................................................................................443

5.1.2 COMBUSTION TURBINE...............................................................................................443

5.1.3 HEAT RECOVERY STEAM GENERATOR .........................................................................445

5.1.4 NOX CONTROL SYSTEM ..............................................................................................445

5.1.5 CARBON DIOXIDE RECOVERY FACILITY.......................................................................446

5.1.6 STEAM TURBINE.........................................................................................................448

5.1.7 WATER AND STEAM SYSTEMS ......................................................................................449

5.1.8 ACCESSORY ELECTRIC PLANT .....................................................................................451

5.1.9 INSTRUMENTATION AND CONTROL ..............................................................................451

5.2 NGCC CASES ...............................................................................................................452

5.2.1 PROCESS DESCRIPTION ..............................................................................................452

5.2.2 KEY SYSTEM ASSUMPTIONS.........................................................................................455

5.2.3 SPARING PHILOSOPHY................................................................................................456

5.2.4 CASE 13 PERFORMANCE RESULTS ..............................................................................457

5.2.5 CASE 13 – MAJOR EQUIPMENT LIST ...........................................................................464
Cost and Performance Baseline for Fossil Energy Plants

X

5.2.6 CASE 13 – COST ESTIMATING .....................................................................................469

5.2.7 CASE 14 – NGCC WITH CO2 CAPTURE.......................................................................476

5.2.8 CASE 14 PERFORMANCE RESULTS ..............................................................................476

5.2.9 CASE 14 MAJOR EQUIPMENT LIST ..............................................................................486

5.2.10 CASE 14 – COST ESTIMATING .................................................................................492

5.3 NGCC CASE SUMMARY ...............................................................................................499

6. EFFECT OF HIGHER NATURAL GAS PRICES AND DISPATCH-BASED 

CAPACITY FACTORS ............................................................................................................505

6.1 INCREASING NATURAL GAS PRICES..............................................................................505

6.2 PRICE METHODOLOGY..................................................................................................505

6.3 COST OF ELECTRICITY ..................................................................................................506

6.4 DISPATCH-BASED CAPACITY FACTORS ........................................................................513

6.5 DISPATCH MODELING RESULTS WITHIN PJM...............................................................516

6.6 PJM INDEPENDENT SYSTEM OPERATOR .......................................................................522

6.6.1 PJM ROLES AND RESPONSIBILITIES ............................................................................523

6.6.2 GENERATION MIX.......................................................................................................524

6.6.3 PJM MARKETS...........................................................................................................524

6.6.4 PJM ENERGY MARKETS .............................................................................................525

6.6.5 DAY-AHEAD MARKET .................................................................................................525

6.6.6 PRICES AND DEMAND.................................................................................................527

6.7 DESCRIPTION OF THE PJM REGIONAL MODELING ........................................................529

6.8 WPLANET MODEL INPUTS ...........................................................................................530

7. DRY AND PARALLEL COOLING................................................................................533

7.1 STUDY RESULTS ...........................................................................................................535

7.2 SENSITIVITY CASE ........................................................................................................542

7.3 CONCLUSIONS...............................................................................................................543

8. GEE IGCC IN QUENCH-ONLY CONFIGURATION WITH CO2 CAPTURE........545

8.1 CASE 2A – GEE IGCC IN QUENCH ONLY MODE WITH CO2 CAPTURE .........................546

8.1.1 KEY SYSTEM ASSUMPTIONS.........................................................................................550

8.1.2 CASE 2A PERFORMANCE RESULTS ..............................................................................552

8.1.3 CASE 2A – MAJOR EQUIPMENT LIST ...........................................................................561

8.1.4 CASE 2A – COST ESTIMATING.....................................................................................570

9. SENSITIVITY TO MEA SYSTEM PERFORMANCE AND COST BITUMINOUS 

BASELINE CASE 12A..............................................................................................................577

9.1 BASIS FOR SENSITIVITY ANALYSIS ...............................................................................577

9.2 PERFORMANCE..............................................................................................................577

9.3 COST ESTIMATING ........................................................................................................583

10. REVISION CONTROL.................................................................................................591

11. REFERENCES...............................................................................................................595
Cost and Performance Baseline for Fossil Energy Plants

XI

List of Exhibits

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

Exhibit ES-2 Cost and Performance Summary and Environmental Profile for All Cases............ 5

Exhibit ES-3 Net Plant Efficiency (HHV Basis)........................................................................... 6

Exhibit ES-4 Raw Water Withdrawal and Consumption .............................................................. 8

Exhibit ES-5 Plant Capital Costs................................................................................................. 10

Exhibit ES-6 Economic Parameters Used to Calculate COE ...................................................... 12

Exhibit ES-7 COE by Cost Component....................................................................................... 13

Exhibit ES-8 COE Sensitivity to Fuel Costs in Non-Capture Cases........................................... 14

Exhibit ES-9 COE Sensitivity to Fuel Costs in CO2 Capture Cases............................................ 15

Exhibit ES-10 COE Sensitivity to Capacity Factor..................................................................... 16

Exhibit ES-11 Impact of Carbon Emissions Price on Study Technologies................................. 17

Exhibit ES-12 Lowest Cost Power Generation Options Comparing NGCC and Coal................ 18

Exhibit ES-13 First Year CO2 Avoided Costs............................................................................. 20

Exhibit ES-14 Study Environmental Targets............................................................................... 21

Exhibit ES-15 SO2, NOx, and Particulate Emission Rates.......................................................... 23

Exhibit ES-16 Mercury Emission Rates...................................................................................... 24

Exhibit ES-17 CO2 Emissions Normalized By Net Output......................................................... 26

Exhibit 1-1 Case Descriptions ..................................................................................................... 29

Exhibit 2-1 Site Ambient Conditions........................................................................................... 31

Exhibit 2-2 Site Characteristics ................................................................................................... 31

Exhibit 2-3 Design Coal............................................................................................................... 33

Exhibit 2-4 Natural Gas Composition.......................................................................................... 34

Exhibit 2-5 Standards of Performance for Electric Utility Steam Generating Units................... 35

Exhibit 2-6 NSPS Mercury Emission Limits............................................................................... 36

Exhibit 2-7 Probability Distribution of Mercury Concentration in the Illinois No. 6 Coal......... 36

Exhibit 2-8 Environmental Targets for IGCC Cases................................................................... 37

Exhibit 2-9 Environmental Targets for PC Cases........................................................................ 38

Exhibit 2-10 Environmental Targets for NGCC Cases................................................................ 39

Exhibit 2-11 Capital Cost Levels and their Elements.................................................................. 43

Exhibit 2-12 Features of an AACE Class 4 Cost Estimate.......................................................... 44

Exhibit 2-13 AACE Guidelines for Process Contingency........................................................... 48

Exhibit 2-14 TASC/TOC Factors ................................................................................................. 49

Exhibit 2-15 Owner’s Costs Included in TOC............................................................................. 50

Exhibit 2-16 CO2 Pipeline Specification ..................................................................................... 53

Exhibit 2-17 Deep, Saline Aquifer Specification ........................................................................ 54

Exhibit 2-18 Global Economic Assumptions .............................................................................. 57

Exhibit 2-19 Financial Structure for Investor Owned Utility High and Low Risk Projects........ 58

Exhibit 2-20 Illustration of COE Solutions using DCF Analysis................................................ 60

Exhibit 2-21 PC with CCS in Current 2007 Dollars.................................................................... 61

Exhibit 2-22 Capital Charge Factors for COE Equation ............................................................. 62

Exhibit 2-23 COE and LCOE Summary...................................................................................... 63

Exhibit 3-1 Air Extracted from the Combustion Turbine and Supplied to the ASU in NonCarbon Capture Cases........................................................................................................... 70

Exhibit 3-2 Typical ASU Process Schematic .............................................................................. 71
Cost and Performance Baseline for Fossil Energy Plants

XII

Exhibit 3-3 Flow Diagram for a Conventional AGR Unit........................................................... 75

Exhibit 3-4 Common Chemical Reagents Used in AGR Processes............................................ 76

Exhibit 3-5 Physical Solvent AGR Process Simplified Flow Diagram....................................... 77

Exhibit 3-6 Common Physical Solvents Used in AGR Processes............................................... 78

Exhibit 3-7 Common Mixed Solvents Used in AGR Processes.................................................. 79

Exhibit 3-8 Equilibrium Solubility Data on H2S and CO2 in Various Solvents.......................... 79

Exhibit 3-9 Typical Three-Stage Claus Sulfur Plant ................................................................... 82

Exhibit 3-10 Advanced F Class Combustion Turbine Performance Characteristics Using Natural 

Gas ........................................................................................................................................ 85

Exhibit 3-11 Typical Fuel Specification for F-Class Machines................................................... 86

Exhibit 3-12 Allowable Gas Fuel Contaminant Level for F-Class Machines............................. 87

Exhibit 3-13 Case 1 Block Flow Diagram, GEE IGCC without CO2 Capture............................ 98

Exhibit 3-14 Case 1 Stream Table, GEE IGCC without CO2 Capture ........................................ 99

Exhibit 3-15 GEE IGCC Plant Study Configuration Matrix ..................................................... 103

Exhibit 3-16 Balance of Plant Assumptions.............................................................................. 104

Exhibit 3-17 Case 1 Plant Performance Summary .................................................................... 106

Exhibit 3-18 Case 1 Emissions.................................................................................................. 107

Exhibit 3-19 Case 1 Carbon Balance ......................................................................................... 108

Exhibit 3-20 Case 1 Sulfur Balance........................................................................................... 108

Exhibit 3-21 Case 1 Water Balance ........................................................................................... 109

Exhibit 3-22 Case 1 Coal Gasification and Air Separation Units Heat and Mass Balance 

Schematic............................................................................................................................ 111

Exhibit 3-23 Case 1 Syngas Cleanup Heat and Mass Balance Schematic ................................ 112

Exhibit 3-24 Case 1 Combined-Cycle Power Generation Heat and Mass Balance Schematic . 113

Exhibit 3-25 Case 1 Overall Energy Balance (0°C [32°F] Reference)...................................... 115

Exhibit 3-26 Case 1 Total Plant Cost Summary ........................................................................ 125

Exhibit 3-27 Case 1 Total Plant Cost Details............................................................................ 126

Exhibit 3-28 Case 1 Initial and Annual O&M Costs................................................................. 130

Exhibit 3-29 Case 2 Block Flow Diagram, GEE IGCC with CO2 Capture............................... 132

Exhibit 3-30 Case 2 Stream Table, GEE IGCC with CO2 Capture ........................................... 133

Exhibit 3-31 Case 2 Plant Performance Summary .................................................................... 136

Exhibit 3-32 Case 2 Air Emissions............................................................................................ 137

Exhibit 3-33 Case 2 Carbon Balance ......................................................................................... 138

Exhibit 3-34 Case 2 Sulfur Balance........................................................................................... 138

Exhibit 3-35 Case 2 Water Balance ........................................................................................... 139

Exhibit 3-36 Case 2 Coal Gasification and Air Separation Units Heat and Mass Balance 

Schematic............................................................................................................................ 141

Exhibit 3-37 Case 2 Syngas Cleanup Heat and Mass Balance Schematic ................................ 142

Exhibit 3-38 Case 2 Combined-Cycle Power Generation Heat and Mass Balance Schematic . 143

Exhibit 3-39 Case 2 Overall Energy Balance (0°C [32°F] Reference)...................................... 145

Exhibit 3-40 Case 2 Total Plant Cost Summary ........................................................................ 156

Exhibit 3-41 Case 2 Total Plant Cost Details............................................................................ 157

Exhibit 3-42 Case 2 Initial and Annual Operating and Maintenance Costs.............................. 161

Exhibit 3-43 Case 3 Block Flow Diagram, E-GasTM IGCC without CO2 Capture.................... 165

Exhibit 3-44 Case 3 Stream Table, E-GasTM IGCC without CO2 Capture................................ 166

Exhibit 3-45 CoP IGCC Plant Study Configuration Matrix ...................................................... 171
Cost and Performance Baseline for Fossil Energy Plants

XIII

Exhibit 3-46 Case 3 Plant Performance Summary .................................................................... 173

Exhibit 3-47 Case 3 Air Emissions............................................................................................ 174

Exhibit 3-48 Case 3 Carbon Balance ......................................................................................... 175

Exhibit 3-49 Case 3 Sulfur Balance........................................................................................... 175

Exhibit 3-50 Case 3 Water Balance ........................................................................................... 176

Exhibit 3-51 Case 3 Coal Gasification and Air Separation Unit Heat and Mass Balance 

Schematic............................................................................................................................ 177

Exhibit 3-52 Case 3 Syngas Cleanup Heat and Mass Balance Schematic ................................ 178

Exhibit 3-53 Case 3 Combined Cycle Power Generation Heat and Mass Balance Schematic . 179

Exhibit 3-54 Case 3 Overall Energy Balance (0°C [32°F] Reference)...................................... 181

Exhibit 3-55 Case 3 Total Plant Cost Summary ........................................................................ 192

Exhibit 3-56 Case 3 Total Plant Cost Details............................................................................ 193

Exhibit 3-57 Case 3 Initial and Annual Operating and Maintenance Costs.............................. 197

Exhibit 3-58 Case 4 Block Flow Diagram, E-GasTM IGCC with CO2 Capture......................... 199

Exhibit 3-59 Case 4 Stream Table, E-GasTM IGCC with CO2 Capture ..................................... 200

Exhibit 3-60 Case 4 Plant Performance Summary .................................................................... 204

Exhibit 3-61 Case 4 Air Emissions............................................................................................ 205

Exhibit 3-62 Case 4 Carbon Balance ......................................................................................... 206

Exhibit 3-63 Case 4 Sulfur Balance........................................................................................... 206

Exhibit 3-64 Case 4 Water Balance ........................................................................................... 207

Exhibit 3-65 Case 4 Coal Gasification and Air Separation Unit Heat and Mass Balance 

Schematic............................................................................................................................ 209

Exhibit 3-66 Case 4 Syngas Cleanup Heat and Mass Balance Schematic ................................ 210

Exhibit 3-67 Case 4 Combined Cycle Power Generation Heat and Mass Balance Schematic . 211

Exhibit 3-68 Case 4 Overall Energy Balance (0°C [32°F] Reference)...................................... 213

Exhibit 3-69 Case 4 Total Plant Cost Summary ........................................................................ 223

Exhibit 3-70 Case 4 Total Plant Cost Details............................................................................ 224

Exhibit 3-71 Case 4 Initial and Annual Operating and Maintenance Costs.............................. 228

Exhibit 3-72 Case 5 Block Flow Diagram, Shell IGCC without CO2 Capture ......................... 232

Exhibit 3-73 Case 5 Stream Table, Shell IGCC without CO2 Capture...................................... 233

Exhibit 3-74 Shell IGCC Plant Study Configuration Matrix..................................................... 238

Exhibit 3-75 Case 5 Plant Performance Summary .................................................................... 240

Exhibit 3-76 Case 5 Air Emissions............................................................................................ 241

Exhibit 3-77 Case 5 Carbon Balance ......................................................................................... 242

Exhibit 3-78 Case 5 Sulfur Balance........................................................................................... 242

Exhibit 3-79 Case 5 Water Balance ........................................................................................... 243

Exhibit 3-80 Case 5 Coal Gasification and Air Separation Unit Heat and Mass Balance 

Schematic............................................................................................................................ 245

Exhibit 3-81 Case 5 Syngas Cleanup Heat and Mass Balance Schematic ................................ 246

Exhibit 3-82 Case 5 Combined Cycle Power Generation Heat and Mass Balance Schematic . 247

Exhibit 3-83 Case 5 Overall Energy Balance (0°C [32°F] Reference)...................................... 249

Exhibit 3-84 Case 5 Total Plant Cost Summary ........................................................................ 259

Exhibit 3-85 Case 5 Total Plant Cost Details............................................................................ 260

Exhibit 3-86 Case 5 Initial and Annual Operating and Maintenance Costs.............................. 264

Exhibit 3-87 Case 6 Block Flow Diagram, Shell IGCC with CO2 Capture .............................. 268

Exhibit 3-88 Case 6 Stream Table, Shell IGCC with CO2 Capture........................................... 269
Cost and Performance Baseline for Fossil Energy Plants

XIV

Exhibit 3-89 Case 6 Plant Performance Summary .................................................................... 272

Exhibit 3-90 Case 6 Air Emissions............................................................................................ 273

Exhibit 3-91 Case 6 Carbon Balance ......................................................................................... 274

Exhibit 3-92 Case 6 Sulfur Balance........................................................................................... 274

Exhibit 3-93 Case 6 Water Balance ........................................................................................... 275

Exhibit 3-94 Case 6 Coal Gasification and Air Separation Unit Heat and Mass Balance 

Schematic............................................................................................................................ 277

Exhibit 3-95 Case 6 Syngas Cleanup Heat and Mass Balance Schematic ................................ 278

Exhibit 3-96 Case 6 Combined Cycle Power Generation Heat and Mass Balance Schematic . 279

Exhibit 3-97 Case 6 Overall Energy Balance (0°C [32°F] Reference)...................................... 281

Exhibit 3-98 Case 6 Total Plant Cost Summary ........................................................................ 291

Exhibit 3-99 Case 6 Total Plant Cost Details............................................................................ 292

Exhibit 3-100 Case 6 Initial and Annual Operating and Maintenance Costs............................ 296

Exhibit 3-101 Estimated Performance and Cost Results for IGCC Cases................................. 297

Exhibit 3-102 Plant Capital Cost for IGCC Cases..................................................................... 298

Exhibit 3-103 COE for IGCC Cases.......................................................................................... 299

Exhibit 3-104 Capacity Factor Sensitivity of IGCC Cases........................................................ 300

Exhibit 3-105 Coal Price Sensitivity of IGCC Cases ................................................................ 301

Exhibit 3-106 Cost of CO2 Avoided in IGCC Cases................................................................. 301

Exhibit 3-107 Carbon Conversion Efficiency and Slag Carbon Content .................................. 302

Exhibit 3-108 Raw Water Withdrawal and Consumption in IGCC Cases................................ 304

Exhibit 4-1 Fluor Econamine FG PlusSM Typical Flow Diagram ............................................. 314

Exhibit 4-2 CO2 Compressor Interstage Pressures .................................................................... 317

Exhibit 4-3 Case 9 Block Flow Diagram, Subcritical Unit without CO2 Capture..................... 324

Exhibit 4-4 Case 9 Stream Table, Subcritical Unit without CO2 Capture................................. 325

Exhibit 4-5 Subcritical PC Plant Study Configuration Matrix .................................................. 327

Exhibit 4-6 Balance of Plant Assumptions................................................................................ 328

Exhibit 4-7 Case 9 Plant Performance Summary ...................................................................... 330

Exhibit 4-8 Case 9 Air Emissions.............................................................................................. 331

Exhibit 4-9 Case 9 Carbon Balance ........................................................................................... 332

Exhibit 4-10 Case 9 Sulfur Balance........................................................................................... 332

Exhibit 4-11 Case 9 Water Balance ........................................................................................... 333

Exhibit 4-12 Case 9 Heat and Mass Balance, Subcritical PC Boiler without CO2 Capture...... 335

Exhibit 4-13 Case 9 Heat and Mass Balance, Subcritical Steam Cycle .................................... 336

Exhibit 4-14 Case 9 Overall Energy Balance (0°C [32°F] Reference)...................................... 337

Exhibit 4-15 Case 9 Total Plant Cost Summary ........................................................................ 347

Exhibit 4-16 Case 9 Total Plant Cost Details............................................................................ 348

Exhibit 4-17 Case 9 Initial and Annual Operating and Maintenance Costs.............................. 352

Exhibit 4-18 Case 10 Block Flow Diagram, Subcritical Unit with CO2 Capture...................... 354

Exhibit 4-19 Case 10 Stream Table, Subcritical Unit with CO2 Capture ................................... 355

Exhibit 4-20 Case 10 Plant Performance Summary ................................................................... 357

Exhibit 4-21 Case 10 Air Emissions.......................................................................................... 358

Exhibit 4-22 Case 10 Carbon Balance ....................................................................................... 359

Exhibit 4-23 Case 10 Sulfur Balance......................................................................................... 359

Exhibit 4-24 Case 10 Water Balance ......................................................................................... 359

Exhibit 4-25 Case 10 Heat and Mass Balance, Subcritical PC Boiler with CO2 Capture ......... 361
Cost and Performance Baseline for Fossil Energy Plants

XV

Exhibit 4-26 Case 10 Heat and Mass Balance, Subcritical Steam Cycle .................................. 362

Exhibit 4-27 Case 10 Overall Energy Balance (0°C [32°F] Reference).................................... 363

Exhibit 4-28 Case 10 Total Plant Cost Summary ...................................................................... 374

Exhibit 4-29 Case 10 Total Plant Cost Details.......................................................................... 375

Exhibit 4-30 Case 10 Initial and Annual Operating and Maintenance Costs............................ 379

Exhibit 4-31 Case 11 Block Flow Diagram, Supercritical Unit without CO2 Capture.............. 381

Exhibit 4-32 Case 11 Stream Table, Supercritical Unit without CO2 Capture.......................... 382

Exhibit 4-33 Supercritical PC Plant Study Configuration Matrix ............................................. 384

Exhibit 4-34 Case 11 Plant Performance Summary .................................................................. 386

Exhibit 4-35 Case 11 Air Emissions.......................................................................................... 387

Exhibit 4-36 Case 11 Carbon Balance ....................................................................................... 387

Exhibit 4-37 Case 11 Sulfur Balance......................................................................................... 388

Exhibit 4-38 Case 11 Water Balance ......................................................................................... 388

Exhibit 4-39 Case 11 Heat and Mass Balance, Supercritical PC Boiler without CO2 Capture. 391

Exhibit 4-40 Case 11 Heat and Mass Balance, Supercritical Steam Cycle ............................... 392

Exhibit 4-41 Case 11 Overall Energy Balance (0°C [32°F] Reference).................................... 393

Exhibit 4-42 Case 11 Total Plant Cost Summary ...................................................................... 403

Exhibit 4-43 Case 11 Total Plant Cost Details.......................................................................... 404

Exhibit 4-44 Case 11 Initial and Annual Operating and Maintenance Costs............................ 408

Exhibit 4-45 Case 12 Block Flow Diagram, Supercritical Unit with CO2 Capture................... 410

Exhibit 4-46 Case 12 Stream Table, Supercritical Unit with CO2 Capture............................... 411

Exhibit 4-47 Case 12 Plant Performance Summary .................................................................. 413

Exhibit 4-48 Case 12 Air Emissions.......................................................................................... 414

Exhibit 4-49 Case 12 Carbon Balance ....................................................................................... 415

Exhibit 4-50 Case 12 Sulfur Balance......................................................................................... 415

Exhibit 4-51 Case 12 Water Balance ......................................................................................... 415

Exhibit 4-52 Case 12 Heat and Mass Balance, Supercritical PC Boiler with CO2 Capture ...... 417

Exhibit 4-53 Case 12 Heat and Mass Balance, Supercritical Steam Cycle ............................... 418

Exhibit 4-54 Case 12 Overall Energy Balance (0°C [32°F] Reference).................................... 419

Exhibit 4-55 Case 12 Total Plant Cost Summary ...................................................................... 430

Exhibit 4-56 Case 12 Total Plant Cost Details.......................................................................... 431

Exhibit 4-57 Case 12 Initial and Annual Operating and Maintenance Costs............................ 435

Exhibit 4-58 Estimated Performance and Cost Results for Pulverized Coal Cases .................. 436

Exhibit 4-59 Plant Capital Cost for PC Cases ........................................................................... 437

Exhibit 4-60 COE for PC Cases................................................................................................. 438

Exhibit 4-61 Sensitivity of COE to Capacity Factor for PC Cases ........................................... 439

Exhibit 4-62 Sensitivity of COE to Coal Price for PC Cases.................................................... 440

Exhibit 4-63 First Year Cost of CO2 Avoided in PC Cases....................................................... 440

Exhibit 4-64 Raw Water Withdrawal and Consumption in PC Cases....................................... 442

Exhibit 5-1 Combustion Turbine Typical Scope of Supply....................................................... 444

Exhibit 5-2 CO2 Compressor Interstage Pressures .................................................................... 449

Exhibit 5-3 Case 13 Block Flow Diagram, NGCC without CO2 Capture................................. 453

Exhibit 5-4 Case 13 Stream Table, NGCC without CO2 Capture ............................................. 454

Exhibit 5-5 NGCC Plant Study Configuration Matrix .............................................................. 455

Exhibit 5-6 NGCC Balance of Plant Assumptions.................................................................... 456

Exhibit 5-7 Case 13 Plant Performance Summary .................................................................... 457
Cost and Performance Baseline for Fossil Energy Plants

XVI

Exhibit 5-8 Case 13 Air Emissions............................................................................................ 458

Exhibit 5-9 Case 13 Carbon Balance ......................................................................................... 458

Exhibit 5-10 Case 13 Water Balance ......................................................................................... 459

Exhibit 5-11 Case 13 Heat and Mass Balance, NGCC without CO2 Capture ........................... 461

Exhibit 5-12 Case 13 Overall Energy Balance (0°C [32°F] Reference).................................... 463

Exhibit 5-13 Case 13 Total Plant Cost Summary ...................................................................... 470

Exhibit 5-14 Case 13 Total Plant Cost Details.......................................................................... 471

Exhibit 5-15 Case 13 Initial and Annual Operating and Maintenance Cost Summary ............. 475

Exhibit 5-16 Case 14 Block Flow Diagram, NGCC with CO2 Capture .................................... 477

Exhibit 5-17 Case 14 Stream Table, NGCC with CO2 Capture ................................................ 478

Exhibit 5-18 Case 14 Plant Performance Summary .................................................................. 479

Exhibit 5-19 Case 14 Air Emissions.......................................................................................... 480

Exhibit 5-20 Case 14 Carbon Balance ....................................................................................... 480

Exhibit 5-21 Case 14 Water Balance ......................................................................................... 481

Exhibit 5-22 Case 14 Heat and Mass Balance, NGCC with CO2 Capture ................................ 483

Exhibit 5-23 Case 14 Overall Energy Balance (0°C [32°F] Reference).................................... 485

Exhibit 5-24 Case 14 Total Plant Cost Summary ...................................................................... 493

Exhibit 5-25 Case 14 Total Plant Cost Details.......................................................................... 494

Exhibit 5-26 Case 14 Initial and Annual Operating and Maintenance Cost Summary ............. 498

Exhibit 5-27 Estimated Performance and Cost Results for NGCC Cases................................. 499

Exhibit 5-28 Plant Capital Cost for NGCC Cases..................................................................... 500

Exhibit 5-29 COE of NGCC Cases............................................................................................ 501

Exhibit 5-30 Sensitivity of COE to Capacity Factor in NGCC Cases....................................... 502

Exhibit 5-31 Sensitivity of COE to Fuel Price in NGCC Cases................................................ 502

Exhibit 5-32 Raw Water Withdrawal and Consumption in NGCC Cases................................. 504

Exhibit 6-1 COE By Cost Component....................................................................................... 508

Exhibit 6-2 First Year CO2 Avoided Costs................................................................................ 509

Exhibit 6-3 COE Sensitivity to Fuel Costs in Non-Capture Cases............................................ 510

Exhibit 6-4 COE Sensitivity to Fuel Costs in CO2 Capture Cases............................................ 511

Exhibit 6-5 COE Sensitivity to Capacity Factor in Non-Capture Cases ................................... 512

Exhibit 6-6 COE Sensitivity to Capacity Factor in Capture Cases............................................ 513

Exhibit 6-7 Dispatch Based Capacity Factors for Cases without CO2 Capture......................... 514

Exhibit 6-8 Estimated Stacking Order in PJM for Year 2010 Based on First Year Production 

Costs.................................................................................................................................... 517

Exhibit 6-9 Capacity Factors of Replacement Units Dispatched into PJM............................... 518

Exhibit 6-10 Dispatch Based Capacity Factors Assuming No CO2 Capture............................. 518

Exhibit 6-11 Summary of Prospective Facility Parameters for Modeling................................. 519

Exhibit 6-12 Comparison of COE as a Function of Capacity Factor ........................................ 520

Exhibit 6-13 Impact of Dispatched Based Capacity Factors on the Cost of Electricity............ 521

Exhibit 6-14 The PJM Operating Territory ............................................................................... 523

Exhibit 6-15 PJM Installed Capacity by Fuel Type................................................................... 524

Exhibit 6-16 PJM East Day-Ahead LMP for 2006.................................................................... 526

Exhibit 6-17 PJM Load and Day-Ahead LMP for 2006............................................................ 527

Exhibit 6-18 PJM Day-Ahead LMP vs. Demand for 2006........................................................ 528

Exhibit 6-19 PJM Price/Load Distribution for 2006.................................................................. 528

Exhibit 6-20 Data Sources for Electricity Generation in the PJM Region in Year 2006 .......... 530
Cost and Performance Baseline for Fossil Energy Plants

XVII

Exhibit 6-21 Assumptions for Projecting PJM Year 2006 into 2010 ........................................ 531

Exhibit 6-22 Breakdown of Additional Generation in the PJM ISO by Fuel Type................... 531

Exhibit 6-23 Summary of Prospective Facility Parameters....................................................... 532

Exhibit 7-1 Cost Accounts Affected by Change in Cooling System......................................... 534

Exhibit 7-2 Normalized Raw Water Withdrawal for Baseline, Parallel and Dry Cooling Cases

............................................................................................................................................. 536

Exhibit 7-3 Absolute Decrease in Raw Water Withdrawal for Parallel and Dry Cooling Cases

............................................................................................................................................. 537

Exhibit 7-4 Net Output Reduction Relative to the Baseline (Wet Cooling) Case ..................... 538

Exhibit 7-5 Total Overnight Cost for Baseline, Parallel and Dry Cooling Cases...................... 540

Exhibit 7-6 COE for Baseline, Parallel and Dry Cooling Systems............................................ 541

Exhibit 7-7 Design Ambient Conditions for SC PC Sensitivity Case ........................................ 542

Exhibit 8-1 Case 2A Block Flow Diagram, GEE Quench Only IGCC with CO2 Capture........ 547

Exhibit 8-2 Case 2A Stream Table, GEE Quench Only IGCC with CO2 Capture.................... 548

Exhibit 8-3 GEE IGCC Plant Study Configuration Matrix ....................................................... 551

Exhibit 8-4 Case 2A Plant Performance Summary.................................................................... 553

Exhibit 8-5 Case 2A Air Emissions........................................................................................... 554

Exhibit 8-6 Case 2A Carbon Balance ........................................................................................ 555

Exhibit 8-7 Case 2A Sulfur Balance.......................................................................................... 555

Exhibit 8-8 Case 2A Water Balance .......................................................................................... 556

Exhibit 8-9 Case 2A Coal Gasification and Air Separation Unit Heat and Mass Balance 

Schematic............................................................................................................................ 557

Exhibit 8-10 Case 2A Syngas Cleanup Heat and Mass Balance Schematic.............................. 558

Exhibit 8-11 Case 2A Combined Cycle Power Generation Heat and Mass Balance Schematic

............................................................................................................................................. 559

Exhibit 8-12 Case 2A Overall Energy Balance ......................................................................... 561

Exhibit 8-13 Case 2A Total Plant Cost Summary ..................................................................... 571

Exhibit 8-14 Case 2A Total Plant Cost Details ......................................................................... 572

Exhibit 8-15 Case 2A Initial and Annual Operating and Maintenance Costs ........................... 576

Exhibit 9-1 Case 12A Block Flow Diagram, Supercritical Unit with CO2 Capture (MEA 

Sensitivity) .......................................................................................................................... 579

Exhibit 9-2 Case 12A Stream Table, Supercritical Unit with CO2 Capture .............................. 580

Exhibit 9-3 Case 12A Plant Performance Summary.................................................................. 582

Exhibit 9-4 Case 12A Total Plant Cost Summary ..................................................................... 584

Exhibit 9-5 Case 12A Total Plant Cost Details ......................................................................... 585

Exhibit 9-6 Case 12A Initial and Annual Operating and Maintenance Costs ........................... 589

Exhibit 10-1 Record of Revisions.............................................................................................. 591
Cost and Performance Baseline for Fossil Energy Plants

XVIII

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

XIX

PREPARED BY

Research and Development Solutions, LLC (RDS)

:

UPDATED BY

Energy Sector Planning and Analysis (ESPA)

:

John L. Haslbeck

Booz Allen Hamilton

Norma J. Kuehn

Booz Allen Hamilton

Eric G. Lewis

Booz Allen Hamilton

Lora L. Pinkerton

WorleyParsons Group, Inc.

James Simpson

WorleyParsons Group, Inc.

Marc J. Turner

Booz Allen Hamilton

Elsy Varghese

WorleyParsons Group, Inc.

Mark C. Woods

Booz Allen Hamilton

DOE Contract # DE-FE0004001
Cost and Performance Baseline for Fossil Energy Plants

XX

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 41817-401.01.04. 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 OSAP Systems Division

James Black

Daniel Cicero

Jared Ciferno

Kristin Gerdes

Eric Grol

Jeffrey Hoffmann

Julianne Klara

Patrick Le

Michael Matuszewski

Sean Plasynski

Larry Rath

Wally Shelton

Gary Stiegel

William Summers

Thomas Tarka

Maria Vargas

Pamela Capicotto

formerly of Parsons Corporation

Michael Rutkowski

formerly of Parsons Corporation

Ronald Schoff

formerly of Parsons Corporation

Vladimir Vaysman

WorleyParsons Group, Inc.
Cost and Performance Baseline for Fossil Energy Plants

XXI

AACE Association for the Advancement of Cost Engineering

LIST OF ACRONYMS AND ABBREVIATIONS

ADIP Aqueous di-isoproponal

AEO Annual Energy Outlook

AGR Acid gas removal

ANSI American National Standards Institute

Aspen Aspen Plus®

ASU Air separation unit

BACT Best available control technology

BEC Bare erected cost

BFD Block flow diagram

BFW Boiler feedwater

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

m3

/d Cubic meters per day

CAMR Clean Air Mercury Rule

CCF Capital Charge Factor

CCS Carbon capture and sequestration

CDR Carbon Dioxide Recovery

CF Capacity factor

CGE Cold gas efficiency

CL Closed-loop

cm Centimeter

CMU Carnegie Mellon University

CO Carbon monoxide

CO2 Carbon dioxide

COE Cost of electricity

CoP ConocoPhillips

COS Carbonyl sulfide

CRT Cathode ray tube

CS Carbon steel

CT Combustion turbine

CTG Combustion Turbine-Generator

CWP Circulating water pump

CWS Circulating water system

DCS Distributed control system

DI De-ionized

DIPA Diisopropanolamine

DLN Dry low NOx

DOE Department of Energy
Cost and Performance Baseline for Fossil Energy Plants

XXII

EAF Equivalent availability factor

E-GasTM ConocoPhillips gasifier technology

EIA Energy Information Administration

EM Electromagnetic

EMF Emission modification factors

EPA Environmental Protection Agency

EPC Engineer/Procure/Construct

EPRI Electric Power Research Institute

EPCM Engineering/Procurement/Construction Management

EU European Union

ESP Electrostatic precipitator

FD Forced draft

FERC Federal Energy Regulatory Commission

FG Flue gas 

FGD Flue gas desulfurization

FOAK First-of-a-kind

FRP Fiberglass-reinforced plastic

ft Foot, feet

FW Feedwater

ft, w.g. Feet of water gauge

GADS Generating Availability Data System

gal Gallon

gal/MWh Gallon per megawatt hour

GCV Gross calorific value

GDP Gross domestic product

GEE General Electric Energy

GHG Greenhouse gas

gpd Gallons per day

gpm Gallons per minute

gr/100 scf grains per one hundred standard cubic feet

GSU Generator step-up transformers

GT Gas turbine

GWh Gigawatt-hour

h Hour

H2 Hydrogen

H2S Hydrogen sulfide

H2SO4 Sulfuric acid

Hg Mercury

HDPE High-density polyethylene

HHV Higher heating value

hp Horsepower

HP High-pressure

HRSG Heat recovery steam generator
Cost and Performance Baseline for Fossil Energy Plants

XXIII

HSS Heat stable salts

HVAC Heating, ventilating, and air conditioning

ICR Information Collection Request

ID Induced draft

IEA International Energy Agency

IGCC Integrated gasification combined cycle

IGVs Inlet guide vanes

In. H2O Inches water

In. Hga Inches mercury (absolute pressure)

In. W.C. Inches water column

IOU Investor-owned utility

IP Intermediate pressure

IPM Integrated Planning Model

IPP Independent power producer

ISO International Standards Organization

kg/GJ Kilogram per gigajoule

kg/hr Kilogram per hour

kJ Kilojoules

kJ/hr Kilojoules per hour

kJ/kg Kilojoules per kilogram

km Kilometer

KO Knockout

kPa Kilopascal absolute

kV Kilovolt

kW Kilowatt

kWe Kilowatt-electric

kWh Kilowatt-hour

LAER Lowest Achievable Emission Rate

LF Levelization factor

lb Pound

lb/gal Pound per gallon

lb/hr Pounds per hour

lb/ft2 Pounds per square foot

lb/MMBtu Pounds per million British thermal units

lb/MWh Pounds per megawatt-hour

lb/TBtu Pounds per trillion British thermal units

LCOE Levelized cost of electricity

LGTI Louisiana Gasification Technology, Inc.

LHV Lower heating value

LMP Locational Marginal Price

LNB Low NOx burner

LNG Liquified natural gas

LP Low-pressure
Cost and Performance Baseline for Fossil Energy Plants

XXIV

lpm Liters per minute

LSE Load-serving entities

m Meters

m/min Meters per minute

m3/min Cubic meter per minute

MAC Main Air Compressor

MAF Moisture/Ash-Free

MCR Maximum continuous rating

md Millidarcy

MDEA Methyldiethanolamine

MEA Monoethanolamine

MHz Megahertz

Mills/kWh Tenths of a cent per kilowatt hour

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 Million kilojoules (also shown as 106 kJ)

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

MNQC Multi Nozzle Quiet Combustor

mol% Mole percent

MPa Megapascals

MVA Mega volt-amps

MW Megawatt

MWe Megawatts electric

MWh Megawatt-hour

N2 Nitrogen

N/A Not applicable

NaOH Sodium hydroxide

NEMA National Electrical Manufacturers Association

NERC North American Electric Reliability Council

NETL National Energy Technology Laboratory

NGCC Natural gas combined cycle

NH3 Ammonia

Nm3 Normal cubic meter

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

O&GJ Oil & Gas Journal

O2 Oxygen

O&M Operation and maintenance
Cost and Performance Baseline for Fossil Energy Plants

XXV

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

OD Outside diameter

OEM Original equipment manufacturers

OFA Overfire air

OP/VWO Over pressure/valves wide open

PA Primary air

PC Pulverized coal

PECO Philadelphia Electric Company

PJM Pennsylvania-New Jersey-Maryland Interconnection

PM Particulate matter

PO Purchase order

POTW Publicly Owned Treatment Works

PP&L Pennsylvania Power & Light Company

ppm Parts per million 

ppmv Parts per million volume

ppmvd Parts per million volume, dry 

PPS Polyphenylensulfide 

PRB Powder River Basin coal region

PSD Prevention of Significant Deterioration

PSE&G Public Service Electric & Gas Company

psi Pounds per square inch

psia Pounds per square inch absolute

psig Pounds per square inch gage

PTFE Teflon (Polytetrafluoroethylene)

PSFM Power systems financial model

RD&D Research, Development, and Demonstration

RDS Research and Development Solutions, LLC

RH Reheater

RTO Regional transmission organization

SC Supercritical

scf Standard cubic feet

scfh Standard cubic feet per hour

scfm Standard cubic feet per minute

Sch Schedule

scmh Standard cubic meter per hour

SCOT Shell Claus Off-gas Treating

SC PC Supercritical Pulverized Coal

SCR Selective catalytic reduction

SEP Samenwerkende Electriciteits-Productiebedrijven NV

SG Specific gravity

SFC Synthetic Fuels Corporation

SGC Synthesis gas cooler

SGS Sour gas shift
Cost and Performance Baseline for Fossil Energy Plants

XXVI

Shell Shell Global Solutions

SNCR Selective non-catalytic reduction

SNG Synthetic natural gas

SO2 Sulfur dioxide

SOx Oxides of sulfur

SRU Sulfur recovery unit

SS Stainless steel

SS Amine SS Specialty Amine

STG Steam turbine generator

Syngas Synthetic gas

TASC Total as-spent cost

TOC Total overnight cost

TPC Total plant cost

TEWAC Totally Enclosed Water-to-Air-Cooled

TGTU Tail gas treating unit

Tonne Metric ton (1000 kg)

TPC Total plant cost

TPD Tons per day

TPH Tons per hour

TPI Total plant investment

TS&M Transport, storage, and monitoring

U.S. United States

vol% Volume percent

WB Wet bulb

WGS Water-gas shift

wg Water gauge

WTI West Texas Intermediate

wt% Weight percent

yr Year

$/kW Dollars per kilowatt

$/MMBtu Dollars per million British thermal units

$/MMkJ Dollars per million kilojoule

$/MW Dollars per megawatt

$/MWh Dollars per megawatt-hour

°C Degrees Celsius

°F Degrees Fahrenheit

5-10s Fifty hour work weeks
Cost and Performance Baseline for Fossil Energy Plants

1

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

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

(IGCC), pulverized coal (PC), and natural gas combined cycle (NGCC) plants, using a consistent 

technical and economic approach that accurately reflects current market conditions. This is 

Volume 1 of a four volume report. The four volume series consists of the following:

EXECUTIVE SUMMARY

• 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

• Overall energy efficiency

• Fuel prices

• Cost of electricity (COE)

• Availability, reliability, and environmental performance

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

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

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

Clean Coal Programs

Twelve power plant configurations were analyzed as listed in Exhibit ES-1. The list includes six

IGCC cases utilizing General Electric Energy (GEE), ConocoPhillips (CoP), and Shell Global 

Solutions (Shell) gasifiers each with and without carbon dioxide (CO2) capture; four PC cases, 

two subcritical and two supercritical (SC), each with and without CO2 capture; and two NGCC 

plants with and without CO2 capture. Two additional cases were originally included in this study 

and involve production of synthetic natural gas (SNG) and the repowering of an existing NGCC 

facility using SNG. The two SNG cases were subsequently moved to Volume 2 of this report 

resulting in the discontinuity of case numbers (1-6 and 9-14).

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

and cost was determined independently and has not been reviewed by individual vendors. Thus, 

portions of this report may not represent the views of the technology vendors. The extent of 

collaboration with technology vendors varied from case to case, with minimal or no 

collaboration obtained from some vendors.

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 
Cost and Performance Baseline for Fossil Energy Plants

2

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 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. 

Baseline fuel costs for this analysis were determined using data from the Energy Information 

Administration’s (EIA) Annual Energy Outlook (AEO) 2008. The first year of capital 

expenditure (2007) costs used are $1.55/MMkJ ($1.64/MMBtu) for coal (Illinois No. 6) and 

$6.21/MMkJ ($6.55 /MMBtu) for natural gas, both on a HHV basis and in 2007 United States 

(U.S.) dollars.

Exhibit ES-1 Case Descriptions

Case Unit 

Cycle

Steam Cycle, 

psig/°F/°F

Combustion 

Turbine

Gasifier/Boiler 

Technology Oxidant

H2S 

Separation/

Removal

Sulfur 

Removal/

Recovery

CO2

Separation

1 IGCC 1800/1050/1050 2 x Advanced 

F Class

GEE Radiant 

Only

95 mol% 

O2

Selexol Claus Plant

2 IGCC 1800/1000/1000 2 x Advanced 

F Class

GEE Radiant 

Only

95 mol% 

O2

Selexol Claus Plant Selexol 

2nd stage

3 IGCC 1800/1050/1050 2 x Advanced 

F Class CoP E-GasTM 95 mol% 

O2

Refrigerated 

MDEA Claus Plant

4 IGCC 1800/1000/1000 2 x Advanced 

F Class CoP E-GasTM 95 mol% 

O2

Selexol Claus Plant Selexol 

2nd stage

5 IGCC 1800/1050/1050 2 x Advanced 

F Class Shell 95 mol% 

O2

Sulfinol-M Claus Plant

6 IGCC 1800/1000/1000 2 x Advanced 

F Class Shell 95 mol% 

O2

Selexol Claus Plant Selexol 

2nd stage

-- -- -- -- -- -- -- -- --

-- -- -- -- -- -- -- -- --

9 PC 2400/1050/1050 Subcritical PC Air

Wet Flue gas 

desulfurization (FGD)/ 

Gypsum

10 PC 2400/1050/1050 Subcritical PC Air Wet FGD/ 

Gypsum

Amine 

Absorber

11 PC 3500/1100/1100 Supercritical PC Air Wet FGD/ 

Gypsum

12 PC 3500/1100/1100 Supercritical PC Air Wet FGD/ 

Gypsum

Amine 

Absorber

13 NGCC 2400/1050/1050 2 x Advanced 

F Class HRSG Air

14 NGCC 2400/1050/1050 2 x Advanced 

F Class HRSG Air Amine 

Absorber

All plant configurations are evaluated based on installation at a greenfield site. Since these are 

state-of-the-art plants, they will have higher efficiencies than the average power plant population. 

Consequently, these plants would be expected to be near the top of the dispatch list and the study
Cost and Performance Baseline for Fossil Energy Plants

3

capacity factor (CF) is chosen to reflect the maximum availability demonstrated for the specific 

plant type, i.e., 80 percent for IGCC and 85 percent for PC and NGCC configurations. Since 

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

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

(Exhibit ES-10) and in the body of the report.

The nominal net plant output for this study is set at 550 megawatt (MW). The actual net output 

varies between technologies because the combustion turbines (CTs) in the IGCC and NGCC 

cases are manufactured in discrete sizes, but the boilers and steam turbines in the PC cases are 

readily available in a wide range of capacities. The result is that all of the PC cases have a net 

output of 550 MW, but the IGCC cases have net outputs ranging from 497 (Case 6) to 629 MW

(Case 5). The range in IGCC net output is caused by the much higher auxiliary load imposed in 

the CO2 capture cases, primarily due to CO2 compression, and the need for extraction steam in 

the water-gas shift (WGS) reactions, which reduces steam turbine output. Higher auxiliary load 

and extraction steam requirements can be accommodated in the PC cases (larger boiler and steam 

turbine) but not in the IGCC cases where it is impossible to maintain a constant net output from 

the steam cycle given the fixed input (CT). Likewise, the two NGCC cases have a net output of 

555 and 474 MW because of the CT constraint.

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

The results are discussed below in the following order:

• Performance (efficiency and raw water consumption)

• Cost (plant capital costs and COE)

• Environmental profile

PERFORMANCE

The net plant efficiency (HHV basis) for all twelve cases is shown in

Energy Efficiency

Exhibit ES-3. The primary 

conclusions that can be drawn are:

• The NGCC with no CO2 capture has the highest net efficiency of the technologies 

modeled in this study with an efficiency of 50.2 percent. 

• The NGCC case with CO2 capture results in the highest efficiency (42.8 percent) 

among all of the capture technologies.

• The NGCC with CO2 capture results in a relative efficiency penalty of 14.7 percent 

(7.4 absolute percent), compared to the non-capture case. The NGCC penalty is less 

than for the PC cases because natural gas is less carbon intensive than coal, and there 

is less CO2 to capture and to compress for equal net power outputs. 

• The energy efficiency of the IGCC non-capture cases is as follows: the dry-fed Shell 

gasifier (42.1 percent), the slurry-fed, two-stage CoP gasifier (39.7 percent) and the 

slurry-fed, single-stage GEE gasifier (39.0 percent). 
Cost and Performance Baseline for Fossil Energy Plants

4

• When CO2 capture is added to the IGCC cases, the energy efficiency of all three cases 

is more nearly equal than the non-capture cases, ranging from 31.0 percent for CoP to 

32.6 percent for GEE, with Shell intermediate at 31.2 percent.

• The relative efficiency penalty for adding CO2 capture to the IGCC cases is 21.4

percent on average. The relative penalty for subcritical and SC PC is 28.9 and 27.6 

percent, respectively. The relative penalty for NGCC is 14.7 percent.

• SC PC without CO2 capture has an efficiency of 39.3 percent. Subcritical PC has an 

efficiency of 36.8 percent, which is the lowest of all the non-capture cases in the 

study.

• The addition of CO2 capture to the PC cases via the Fluor Econamine FG PlusSM

(Econamine) process has the highest relative efficiency penalties out of all the cases 

studied. This is primarily because the low partial pressure of CO2 in the flue gas (FG) 

from a PC plant requires a chemical absorption process rather than physical 

absorption. For chemical absorption processes, the regeneration requirements are 

more energy intensive. The relative efficiency impact on NGCC is less because of 

the lower carbon intensity of natural gas relative to coal as mentioned above.
Cost and Performance Baseline for Fossil Energy Plants

5

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

1 CF is 80% for IGCC cases and 85% for PC and NGCC cases 2 COE and Levelized COE are defined in Section 2.7.

PERFORMANCE Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 9 Case 10 Case 11 Case 12 Case 13 Case 14

CO2 Capture 0% 90% 0% 90% 0% 90% 0% 90% 0% 90% 0% 90%

Gross Power Output (kWe) 747,800 734,000 738,200 703,700 737,000 673,400 582,600 672,700 580,400 662,800 564,700 511,000

Auxiliary Power Requirement (kWe) 125,750 190,750 113,140 190,090 108,020 176,540 32,580 122,740 30,410 112,830 9,620 37,430

Net Power Output (kWe) 622,050 543,250 625,060 513,610 628,980 496,860 550,020 549,960 549,990 549,970 555,080 473,570

Coal Flowrate (lb/hr) 466,901 487,011 459,958 484,212 436,646 465,264 437,378 614,994 409,528 565,820 N/A N/A

Natural Gas Flowrate (lb/hr) N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 167,333 167,333

HHV Thermal Input (kWth) 1,596,320 1,665,074 1,572,582 1,655,503 1,492,878 1,590,722 1,495,379 2,102,643 1,400,162 1,934,519 1,105,812 1,105,812

Net Plant HHV Efficiency (%) 39.0% 32.6% 39.7% 31.0% 42.1% 31.2% 36.8% 26.2% 39.3% 28.4% 50.2% 42.8%

Net Plant HHV Heat Rate (Btu/kWh) 8,756 10,458 8,585 10,998 8,099 10,924 9,277 13,046 8,687 12,002 6,798 7,968

Raw Water Withdrawal (gpm/MWnet) 7.6 10.7 7.0 11.1 6.6 11.3 10.7 20.4 9.7 18.3 4.3 8.4

Process Water Discharge (gpm/MWnet) 1.6 2.0 1.4 2.1 1.2 2.0 2.2 4.7 2.0 4.3 1.0 2.1

Raw Water Consumption (gpm/MWnet) 6.0 8.7 5.5 9.0 5.3 9.3 8.5 15.7 7.7 14.1 3.3 6.3

CO2 Emissions (lb/MMBtu) 197 20 199 20 197 20 204 20 204 20 118 12

CO2 Emissions (lb/MWhgross) 1,434 152 1,448 158 1,361 161 1,783 217 1,675 203 790 87

CO2 Emissions (lb/MWhnet) 1,723 206 1,710 217 1,595 218 1,888 266 1,768 244 804 94

SO2 Emissions (lb/MMBtu) 0.0012 0.0022 0.0117 0.0022 0.0042 0.0021 0.0858 0.0017 0.0858 0.0016 Negligible Negligible

SO2 Emissions (lb/MWhgross) 0.0090 0.0166 0.0852 0.0173 0.0290 0.0171 0.7515 0.0176 0.7063 0.0162 Negligible Negligible

NOx Emissions (lb/MMBtu) 0.059 0.049 0.060 0.049 0.059 0.049 0.070 0.070 0.070 0.070 0.009 0.008

NOx Emissions (lb/MWhgross) 0.430 0.376 0.434 0.396 0.409 0.396 0.613 0.747 0.576 0.697 0.060 0.061

PM Emissions (lb/MMBtu) 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0130 0.0130 0.0130 0.0130 Negligible Negligible

PM Emissions (lb/MWhgross) 0.052 0.055 0.052 0.057 0.049 0.057 0.114 0.139 0.107 0.129 Negligible Negligible

Hg Emissions (lb/TBtu) 0.571 0.571 0.571 0.571 0.571 0.571 1.143 1.143 1.143 1.143 Negligible Negligible

Hg Emissions (lb/MWhgross) 4.16E-06 4.42E-06 4.15E-06 4.59E-06 3.95E-06 4.61E-06 1.00E-05 1.22E-05 9.41E-06 1.14E-05 Negligible Negligible

COST

Total Plant Cost (2007$/kW) 1,987 2,711 1,913 2,817 2,217 3,181 1,622 2,942 1,647 2,913 584 1,226

Total Overnight Cost (2007$/kW) 2,447 3,334 2,351 3,466 2,716 3,904 1,996 3,610 2,024 3,570 718 1,497

 Bare Erected Cost 1,528 2,032 1,470 2,113 1,695 2,385 1,317 2,255 1,345 2,239 482 926

 Home Office Expenses 144 191 138 199 156 221 124 213 127 211 40 78

 Project Contingency 265 369 256 385 302 444 182 369 176 362 62 162

 Process Contingency 50 119 50 120 63 131 0 105 0 100 0 60

 Owner's Costs 460 623 438 649 500 723 374 667 377 657 133 271

Total Overnight Cost (2007$ x 1,000) 1,521,880 1,811,411 1,469,577 1,780,290 1,708,524 1,939,878 1,098,124 1,985,432 1,113,445 1,963,644 398,290 709,039

Total As Spent Capital (2007$/kW) 2,789 3,801 2,680 3,952 3,097 4,451 2,264 4,115 2,296 4,070 771 1,614

COE (mills/kWh, 2007$)1,2 76.3 105.6 74.0 110.3 81.3 119.4 59.4 109.6 58.9 106.5 58.9 85.9

 CO2 TS&M Costs 0.0 5.2 0.0 5.5 0.0 5.6 0.0 5.8 0.0 5.6 0.0 3.2

 Fuel Costs 14.3 17.1 14.0 18.0 13.3 17.9 15.2 21.3 14.2 19.6 44.5 52.2

 Variable Costs 7.3 9.3 7.2 9.8 7.8 9.9 5.1 9.2 5.0 8.7 1.3 2.6

 Fixed Costs 11.3 14.8 11.1 15.5 12.1 16.7 7.8 13.1 8.0 13.0 3.0 5.7

 Capital Costs 43.4 59.1 41.7 61.5 48.2 69.2 31.2 60.2 31.7 59.6 10.1 22.3

LCOE (mills/kWh, 2007$)1,2 96.7 133.9 93.8 139.9 103.1 151.4 75.3 139.0 74.7 135.2 74.7 108.9

Integrated Gasification Combined Cycle Pulverized Coal Boiler NGCC

GEE R+Q CoP E-Gas FSQ Shell PC Subcritical PC Supercritical Advanced F Class
Cost and Performance Baseline for Fossil Energy Plants

6

Exhibit ES-3 Net Plant Efficiency (HHV Basis)

39.0%

32.6%

39.7%

31.0%

42.1%

31.2%

36.8%

26.2%

39.3%

28.4%

50.2%

42.8%

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

GEE GEE w/CO2 

Capture

CoP CoP w/ CO2 

Capture

Shell Shell w/ CO2 

Capture

Subcritical

PC

Subcritical PC 

w/ CO2 

Capture

Supercritical 

PC

Supercritical 

PC w/ CO2 

Capture

NGCC NGCC w/ 

CO2 Capture

Efficiency, % (HHV Basis)
Cost and Performance Baseline for Fossil Energy Plants

7

Three water values are presented for each technology in

Water Use

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 (slurry, quench, flue gas desulfurization [FGD]

makeup, etc.) and internal recycle is water available within the process (boiler feedwater [BFW] 

blowdown, condensate, etc.). 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. All plants are equipped with 

evaporative cooling towers, and all process blowdown streams are assumed to be treated and 

recycled to the cooling tower. The primary conclusions that can be drawn are:

• In all cases the primary water consumer is cooling tower makeup, which ranges from 

73 to 99 percent of the total raw water consumption.

• Among non-capture cases, NGCC requires the least amount of raw water withdrawal, 

followed by IGCC and PC. If an average raw water consumption for the three IGCC 

cases and two PC cases is used, the relative normalized raw water consumption for 

the technologies is 2.5:1.7:1.0 (PC:IGCC:NGCC). The relative results are as 

expected given the much higher steam turbine output in the PC cases, which results in 

higher condenser duties, higher cooling water flows, and ultimately higher cooling 

water makeup. The IGCC cases and the NGCC case have comparable steam turbine 

outputs, but IGCC requires additional water for coal slurry (GEE and CoP), syngas 

quench (GEE), humidification (CoP and Shell), gasifier steam (Shell), and slag 

handling (all cases), which increases the IGCC water withdrawal over NGCC.

• Among capture cases, raw water withdrawal requirements increase (relative to noncapture cases) more dramatically for the PC and NGCC cases than for IGCC cases 

because of the large cooling water demand of the Econamine process, which results in 

greater cooling water makeup requirements. If average water consumption values are 

used for IGCC and PC cases, the relative normalized raw water consumption for the 

technologies in CO2 capture cases is 2.4:1.4:1.0 (PC:IGCC:NGCC). The NGCC CO2

capture case still has the lowest water consumption.

• CO2 capture increases the average raw water consumption for all three technologies 

evaluated, but the increase is lowest for the IGCC cases. The average normalized raw 

water consumption for the three IGCC cases increases by about 58 percent due 

primarily to the need for additional water in the syngas to accomplish the WGS 

reaction. With the addition of CO2 capture, PC normalized raw water consumption

increases by 83 percent and NGCC by 91 percent. The large cooling water demand 

of the Econamine process drives this substantial increase for PC and NGCC.
Cost and Performance Baseline for Fossil Energy Plants

8

Exhibit ES-4 Raw Water Withdrawal and Consumption

7.6

10.7

7.0

11.1

6.6

11.3

10.7

20.4

9.7

18.3

4.3

8.4

6.0

8.7

5.5

9.0

5.3

9.3

8.5

15.7

7.7

14.1

3.3

6.3

0.0

5.0

10.0

15.0

20.0

25.0

GEE GEE w/CO2 

Capture

CoP CoP w/ CO2 

Capture

Shell Shell w/ CO2 

Capture

Subcritical

PC

Subcritical PC 

w/ CO2 

Capture

Supercritical 

PC

Supercritical 

PC w/ CO2 

Capture

NGCC NGCC w/ 

CO2 Capture

Water, gpm/MWnet

Raw Water Withdrawal

Process Discharge

Raw Water Consumption
Cost and Performance Baseline for Fossil Energy Plants

9

COST RESULTS

The Total Overnight Cost (TOC) for each plant was calculated by adding owner’s costs to the 

Total Plant Cost (TPC). The 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). 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).

Total Overnight Cost

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 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 

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:

• Slurry Prep and Feed – 5 percent on GE IGCC cases - systems are operating at 

approximately 800 psia as compared to 600 psia for the other IGCC cases.

• Gasifiers and Syngas Coolers – 15 percent on all IGCC cases – next-generation 

commercial offering and integration with the power island.

• Two Stage Selexol – 20 percent on all IGCC capture cases – lack of operating 

experience at commercial scale in IGCC service.

• Mercury Removal – 5 percent on all IGCC cases – minimal commercial scale 

experience in IGCC applications.

• CO2 Removal System – 20 percent on all PC/NGCC capture cases - post-combustion 

process unproven at commercial scale for power plant applications.

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

syngas firing and air separation unit (ASU) integration; 10 percent on all IGCC 

capture cases – high hydrogen firing. 

• Instrumentation and Controls – 5 percent on all IGCC accounts and 5 percent on the 

PC and NGCC capture cases – integration issues.

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

Exhibit ES-5. The following conclusions can be drawn:

• Among the non-capture cases, NGCC has the lowest TOC at $718 kW followed by PC 

with an average cost of $2,010/kW and IGCC with an average cost of $2,505/kW.
Cost and Performance Baseline for Fossil Energy Plants

10

Exhibit ES-5 Plant Capital Costs

Note: TOC expressed in 2007 dollars. TASC expressed in mixed-year 2007 to 2011 year dollars for coal plants and 2007 to 2009 mixed-year dollars for NGCC.

2,447

3,334

2,351

3,466

2,716

3,904

1,996

3,610

2,024

3,570

718

1,497

2,789

3,801

2,680

3,952

3,097

4,451

2,264

4,115

2,296

4,070

771

1,614

0

1,000

2,000

3,000

4,000

5,000

6,000

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

GEE GEE w/ CO2 

Capture

CoP CoP w/ CO2 

Capture

Shell Shell w/ CO2 

Capture

Subcritical PC Subcritical PC w/ 

CO2 Capture

Supercritical PC Supercritical PC 

w/ CO2 Capture

NGCC NGCC w/ CO2 

Capture

TOC or TASC, $/kW

TASC

Owner's Cost

Process Contingency

Project Contingency

Home Office Expense

Bare Erected Cost
Cost and Performance Baseline for Fossil Energy Plants

11

The average IGCC cost is 25 percent greater than the average PC cost. The process 

contingency for the IGCC cases ranges from $50-63/kW while there is zero process 

contingency for the PC and NGCC non-capture cases. The differential between 

IGCC and PC is reduced to 22 percent when process contingency is eliminated.

• The three IGCC non-capture cases have a TOC ranging from $2,351/kW (CoP) to 

$2,716/kW (Shell) with GEE intermediate at $2,447/kW.

• Among the capture cases, NGCC has the lowest TOC, despite the fact that the TOC

of the NGCC capture case is more than double the cost of the non-capture case at 

$1,497kW. 

• Among the capture cases, the PC cases have the highest TOC at an average of 

$3,590/kW. The average TOC for IGCC CO2 capture cases is $3,568/kW, which is 

less than one percent lower than the average of the PC cases. The process 

contingency for the IGCC capture cases ranges from $119-131/kW, for the PC cases 

from $100-105/kW and $60/kW for the NGCC case.

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) [

Cost of Electricity

2] was used to determine a “base-year” 

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

percent1

Exhibit ES-6

, 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 , which was derived using the PSFM, can also be

used to calculate COE using a simplified equation as detailed in Section 2.7.4.

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

the length of the capital expenditure period (3 year or 5 year). 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. The IGCC cases (with and without CO2 capture) and the 

PC and NGCC cases with CO2 capture were considered to be high risk. The non-capture PC and 

NGCC cases were considered to be low risk. Coal based cases were assumed to have a 5 year 

capital expenditure period and natural gas cases a 3 year period. The current-dollar, 30-year

levelized cost of electricity (LCOE) was also calculated and is shown in Exhibit 2-23, 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 2.7 of the report.

 

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 for Fossil Energy Plants

12

Exhibit ES-6 Economic Parameters Used to Calculate COE

High Risk

(5 year capital 

expenditure 

period)

Low Risk

(5 year capital 

expenditure 

period)

High Risk

(3 year capital 

expenditure 

period)

Low Risk

(3 year capital 

expenditure 

period)

First Year Capital 

Charge Factor 0.1243 0.1165 0.1111 0.1048

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:

• In non-capture cases, NGCC plants have the lowest COE (58.9 mills/kWh), followed by 

PC (average 59.2 mills/kWh) and IGCC (average 77.2 mills/kWh).

• In capture cases, NGCC plants have the lowest COE (85.9 mills/kWh), followed by PC 

(average 108.2 mills/kWh) and IGCC (average 111.8 mills/kWh).

• The COE for the three IGCC non-capture cases ranges from 74.0 mills/kWh (CoP) to 

81.3 mills/kWh (Shell) with GEE intermediate at 76.3 mills/kWh. The study level of 

accuracy is insufficient to definitively quantify the differences in COE of the three IGCC 

technologies.

• Non-capture SC PC has a COE of 58.9 mills/kWh and subcritical PC is 59.4 mills/kWh, 

an insignificant difference given the level of accuracy of the study estimate.

• IGCC is the most expensive technology with CO2 capture, 3 percent higher than PC and 

30 percent higher than NGCC.

• The capital cost component of COE is between 56 and 59 percent in all IGCC and PC 

cases. It represents only 17 percent of COE in the NGCC non-capture case and 26 

percent in the CO2 capture case. 

• The fuel component of COE ranges from 15-19 percent for the IGCC cases and the PC 

CO2 capture cases. For the PC non-capture cases the fuel component varies from 24-26 

percent. The fuel component is 76 percent of the total in the NGCC non-capture case and 

61 percent in the CO2 capture case.

• CO2 TS&M is estimated to add 3 to 6 mills/kWh to the COE, which is less than 5.5 

percent of the total for all capture cases. 
Cost and Performance Baseline for Fossil Energy Plants

13

Exhibit ES-7 COE by Cost Component

43.4

59.1

41.7

61.5

48.2

69.2

31.2

60.2

31.7

59.6

10.1

22.3

11.3

14.8

11.1

15.5

12.1

16.7

7.8

13.1

8.0

13.0

3.0

5.7

7.3

9.3

7.2

9.8

7.8

9.9

5.1

9.2

5.0

8.7

1.3

2.6

14.3

17.1

14.0

18.0

13.3

17.9

15.2

21.3

14.2

19.6

44.5

52.2

5.3

5.6

5.7

5.9

5.7

3.2

76.28

105.66

74.02

110.39

81.31

119.46

59.40

109.69

58.91

106.63

58.90

85.93

0

20

40

60

80

100

120

140

160

GEE GEE w/CO2 

Capture

CoP CoP w/ CO2 

Capture

Shell Shell w/ 

CO2 

Capture

Subcritical 

PC

Subcritical 

PC w/ CO2 

Capture

Supercritical 

PC

Supercritical 

PC w/ CO2 

Capture

NGCC NGCC w/ 

CO2 

Capture

COE, mills/kWh (2007$)

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs
Cost and Performance Baseline for Fossil Energy Plants

14

Exhibit ES-8 shows the COE sensitivity to fuel costs for the non-capture cases. The solid line is 

the COE of NGCC as a function of natural gas cost. The points on the line represent the natural 

gas cost that would be required to make the COE of NGCC equal to PC or IGCC at a given coal 

cost. The coal prices shown ($1.23, $1.64, and $2.05/MMBtu) represent the baseline cost and a 

range of ±25 percent around the baseline. As an example, at a coal cost of $1.64/MMBtu, the 

COE of PC equals NGCC at a natural gas price of $6.59/MMBtu.

Another observation from Exhibit ES-8 is that the COE of IGCC at a coal price of $1.23/MMBtu 

is greater than PC at a coal price of $2.05/MMBtu, due to the higher capital cost of IGCC and its 

relative insensitivity to fuel price. For example, a decrease in coal cost of 40 percent (from $2.05 

to $1.23/MMBtu) results in an IGCC COE decrease of only nine percent (80.7 to 73.7 

mills/kWh).

Fuel cost sensitivity is presented for the CO2 capture cases in Exhibit ES-9. Even at the lowest 

coal cost shown, the COE of NGCC is less than IGCC and PC at the baseline natural gas price of 

$6.55/MMBtu. For the coal-based technologies at the baseline coal cost of $1.64/MMBtu to be 

equal to NGCC, the cost of natural gas would have to be $9.34/MMBtu (PC) or $9.80/MMBtu 

(IGCC). Alternatively, for the COE of coal-based technologies to be equal to NGCC at the high 

end coal cost of $2.05/MMBtu, natural gas prices would have to be $9.98/MMBtu for PC and 

$10.35/MMBtu for IGCC.

Exhibit ES-8 COE Sensitivity to Fuel Costs in Non-Capture Cases

40

50

60

70

80

90

100

3 4 5 6 7 8 9 10 11 12 13

COE, mills/kWh (2007$)

Natural Gas Price, $/MMBtu

NGCC

PC w/ coal at $1.23/MMBtu

PC w/ coal at $1.64/MMBtu

PC w/ coal at $2.05/MMBtu

IGCC w/ coal at $1.23/MMBtu

IGCC w/ coal at $1.64/MMBtu

IGCC w/ coal at $2.05/MMBtu
Cost and Performance Baseline for Fossil Energy Plants

15

Exhibit ES-9 COE Sensitivity to Fuel Costs in CO2 Capture Cases

The sensitivity of COE to CF is shown for all technologies in Exhibit ES-10. The subcritical and 

SC PC cases with no CO2 capture are nearly identical so that the two curves appear as a single 

curve on the graph. The CF is plotted from 30 to 90 percent. The baseline CF is 80 percent for 

IGCC cases with no spare gasifier and is 85 percent for PC and NGCC cases. The curves plotted 

in Exhibit ES-10 for the IGCC cases assume that the CF could be extended to 90 percent with no 

spare gasifier. Similarly, the PC and NGCC curves assume that the CF could reach 90 percent 

with no additional capital equipment.

Technologies with high capital cost (PC and IGCC with CO2 capture) show a greater increase in 

COE with decreased CF. Conversely, NGCC with no CO2 capture is relatively flat because the 

COE is dominated by fuel charges, which decrease as the CF decreases. Conclusions that can be 

drawn from Exhibit ES-10 include:

• At a CF at or below 85 percent, NGCC has the lowest COE out of the non-capture 

cases. 

• The COE of NGCC with CO2 capture is the lowest of the capture technologies in the 

baseline study, and the advantage increases as CF decreases. The relatively low 

capital cost component of NGCC accounts for the increased cost differential with 

decreased CF.

• In non-capture cases, NGCC at 40 percent CF has approximately the same COE as 

the average of the three IGCC cases at base load (80 percent CF) further illustrating 

the relatively small impact of CF on NGCC COE.

40

50

60

70

80

90

100

110

120

130

140

3 4 5 6 7 8 9 10 11 12 13

COE, mills/kWh (2007$)

Natural Gas Price, $/MMBtu

NGCC

PC w/ coal at $1.23/MMBtu

PC w/ coal at $1.64/MMBtu

PC w/ coal at $2.05/MMBtu

IGCC w/ coal at $1.23/MMBtu

IGCC w/ coal at $1.64/MMBtu

IGCC w/ coal at $2.05/MMBtu
Cost and Performance Baseline for Fossil Energy Plants

16

Exhibit ES-10 COE Sensitivity to Capacity Factor

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

examined in this study will become more expensive. The technologies without carbon capture 

will be impacted to a larger extent than those with carbon capture, and coal-based technologies 

will be impacted more than natural gas-based technologies. The most economically favored 

option for each technology is shown in

CO2 Emission Price Impact

Exhibit ES-11. Hence the IGCC non-capture case is 

based on the CoP gasifier, the IGCC capture case is based on the GEE technology, and the PC 

technology is based on supercritical steam conditions.

The curves represent the study design conditions (capacity factor) and fuel prices used for each 

technology; namely 80 percent capacity factor for IGCC plants and 85 percent for PC and NGCC 

plants, and $1.64/MMBtu for coal and $6.55/MMBtu for natural gas. Natural gas fuel prices are 

more volatile than coal and tend to fluctuate over a fairly large range. The two black lines shown 

in Exhibit ES-11 represent NGCC at a fuel price of $9.50/MMBtu and are shown for reference. 

The dispatch-based capacity factor for NGCC plants, addressed in Section 6.4 of this report, is 

significantly less than 85 percent and would result in a higher COE as shown in Exhibit ES-10.

0

50

100

150

200

250

300

0 10 20 30 40 50 60 70 80 90 100

COE, mills/kWh (2007$)

Capacity Factor, %

Shell w/CO2 capture

Sub PC w/CO2 capture

SC PC w/CO2 capture

CoP w/CO2 capture

GEE w/CO2 capture

Shell no capture

GEE no capture

CoP no capture

Sub PC no capture

NGCC w/CO2 capture

SC PC no capture

NGCC no capture

Coal = $1.64/MMBtu

Natural Gas = $6.55/MMBtu
Cost and Performance Baseline for Fossil Energy Plants

17

Exhibit ES-11 Impact of Carbon Emissions Price on Study Technologies

The intersection of the capture and non-capture curves for a given technology gives the cost of 

CO2 avoided for that technology, except for the IGCC cases which use different gasifier 

technologies for the capture and non-capture cases. For example, the cost of CO2 avoided is 

$69/tonne ($63/ton) for SC PC and $84/tonne ($76/ton) for NGCC. These values can be 

compared to those shown in Exhibit ES-13.

The following conclusions can be drawn from the carbon emissions price graph:

• At the baseline study conditions any cost applied to carbon emissions favors NGCC 

technology. While PC and NGCC with no capture start at essentially equivalent 

COEs, they diverge rapidly as the CO2 emission cost increases. The lower carbon 

intensity of natural gas relative to coal and the greater efficiency of the NGCC 

technology account for this effect.

• Capture for NGCC systems is only justified economically at CO2 emissions prices 

greater than $83/tonne ($75/ton) at the baseline natural gas price of $6.55/MMBtu 

and $95/tonne ($86/ton) at the higher natural gas price of $9.50/MMBtu.

• The SC PC and IGCC non-capture curves are nearly parallel indicating that the CO2

emission price impacts the two technologies nearly equally. The two lines gradually

converge due to the slightly lower efficiency of SC PC relative to the CoP IGCC 

technology (39.3 versus 39.7 percent net efficiency). The SC PC and GEE IGCC 

cases with CO2 capture start at nearly equivalent COE values and slowly diverge. 

The COE of the SC PC case increases slightly faster than the GEE IGCC case 

0

20

40

60

80

100

120

140

160

0 10 20 30 40 50 60 70 80 90 100

COE, mills/kWh (2007$)

First Year CO2 Emission Price, $/tonne

NGCC w/Cap ($9.50/MMBtu)

NGCC ($9.50/MMBtu)

IGCC (GEE) w/Capture

IGCC (CoP)

SCPC w/Capture

SCPC

NGCC w/Capture ($6.55/MMBtu)

NGCC ($6.55/MMBtu)
Cost and Performance Baseline for Fossil Energy Plants

18

because of the lower efficiency (28.4 versus 32.6 percent net efficiency) and slightly 

lower capture efficiency (90.2 versus 90.3 percent).

• Comparing only the coal-based technologies, IGCC or PC with capture become the 

favored technology compared to SC PC with no capture at an emission price of 

$67/tonne ($61/ton).

• At a natural gas price of $9.50/MMBtu, NGCC with capture has nearly the same COE 

as IGCC and SC PC with capture at a CO2 emission price of $30/tonne ($27/ton).

• At a natural gas price of $9.50/MMBtu, SC PC without capture has a lower COE than 

NGCC without capture until the CO2 emissions price exceeds $46/tonne ($42/ton).

The relationship between technologies and CO2 emission pricing can also be considered in a 

“phase diagram” type plot as shown in Exhibit ES-12. The lines in the plot represent cost parity 

between different pairs of technologies. 

Exhibit ES-12 Lowest Cost Power Generation Options Comparing NGCC and Coal

The plot demonstrates the following points:

• Non-capture plants are the low cost option below a first year CO2 price of $60/tonne 

($54/ton).

0

2

4

6

8

10

12

14

16

18

20

0 10 20 30 40 50 60 70 80 90 100 110

Natural Gas Price, $/MMBtu

First Year CO2 Emission Price, $/tonne

COE parity between 

NGCC with CCS

and IGCC with CCS

COE parity between Supercritical PC without CCSand IGCC with CCS

Supercritical PC 

without CCS

has lowest COE

NGCC

with CCS

has lowest COE

IGCC

with CCS

has lowest COE

NGCC

without CCS

has lowest COE
Cost and Performance Baseline for Fossil Energy Plants

19

• At natural gas prices below $6.50/MMBtu (and a capacity factor of 85 percent) 

NGCC is always preferred.

• At natural gas prices above $11/MMBtu coal plants are always preferred.

The first year cost of CO2 avoided was calculated as illustrated in Equation ES-1:

Cost of CO2 Avoided

CO Emissions CO Emissions tons MWh

COE COE MWh

Avoided Cost

reference with removal

with removal reference

{ } /

{ } $ /

2 − 2

− = (ES-1)

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-13 for each of the six technologies 

modeled. The avoided costs for each capture case are calculated using the analogous noncapture plant as the reference and again with SC PC without CO2 capture as the reference. The 

following conclusions can be drawn:

• The total first year cost of CO2 avoided is $52.9/tonne ($48/ton) (average IGCC), 

$68.3/tonne ($62/ton) (average PC), and $83.8/tonne ($76/ton) (NGCC) using 

analogous non-capture plants as the reference and $75/tonne ($68/ton) (average 

IGCC), $71.6/tonne ($65/ton) (average PC), and $35.3/tonne ($32/ton) (NGCC) using 

SC PC without capture as the reference.

• CO2 avoided costs for IGCC plants using analogous non-capture plants as reference 

are substantially less than for PC and NGCC because the IGCC CO2 removal is 

accomplished prior to combustion and at elevated pressure using physical absorption.

• CO2 avoided costs for IGCC plants using analogous non-capture as reference are less 

than NGCC plants because the baseline CO2 emissions for NGCC plants are 44

percent less than for IGCC plants. Consequently, the normalized removal cost for 

NGCC plants is divided by a smaller amount of CO2.

• CO2 avoided costs for the GEE IGCC plant are less than for the CoP and Shell IGCC 

plants. This is consistent with the efficiency changes observed when going from a 

non-capture to capture configuration for the GEE IGCC plant. The GEE plant started 

with the lowest efficiency of the IGCC plants but realized the smallest reduction in 

efficiency between the non-capture and capture configurations.

• CO2 avoided costs for NGCC using SC PC as the reference are 53 percent lower than 

IGCC and 50 percent lower than PC because of the relatively low COE of the NGCC 

capture plant compared to IGCC and PC.
Cost and Performance Baseline for Fossil Energy Plants

20

Exhibit ES-13 First Year CO2 Avoided Costs

43

54

61

68 69

84

66

73

86

75

69

36

0

10

20

30

40

50

60

70

80

90

100

GEE CoP Shell Subcritical PC Supercritical PC NGCC

First Year CO2 Avoided Cost, $/tonne (2007$)

Avoided Cost (Analogous Technology w/o Capture Reference)

Avoided Cost (SC PC w/o Capture Reference)
Cost and Performance Baseline for Fossil Energy Plants

21

ENVIRONMENTAL PERFORMANCE

The environmental targets for each technology are summarized in Exhibit ES-14. Emission rates 

of sulfur dioxide (SO2), nitrogen oxide (NOx), and particulate matter (PM) are shown 

graphically in Exhibit ES-15, and emission rates of mercury (Hg) are shown separately in 

Exhibit ES-16 because of the orders of magnitude difference in emission rate values.

Exhibit ES-14 Study Environmental Targets

Technology

Pollutant IGCC PC NGCC

SO2 0.0128 lb/MMBtu 0.085 lb/MMBtu Negligible

NOx 15 ppmv (dry) @ 

15% O2

0.070 lb/MMBtu 2.5 ppmv (dry) @ 

15% O2

PM (Filterable) 0.0071 lb/MMBtu 0.013 lb/MMBtu Negligible

Hg >90% capture 1.14 lb/TBtu N/A

Environmental targets were established for each of the technologies as follows:

• IGCC cases use the EPRI targets established in their CoalFleet for Tomorrow work as 

documented in the CoalFleet User Design Basis Specification for Coal-Based Integrated 

Gasification Combined Cycle (IGCC) Power Plants, EPRI, Palo Alto, CA, 2009.

• PC and NGCC cases are based on best available control technology (BACT)

The primary conclusions that can be drawn are:

• The NGCC baseline plant generates the lowest emissions, followed by IGCC and then 

PC.

• In NGCC cases, study assumptions result in zero emissions of SO2, PM, and Hg. If the 

pipeline natural gas contained the maximum amount of sulfur allowed by Environmental 

Protection Agency (EPA) definition (0.6 gr/100 scf), SO2 emissions would be 0.000839 

kg/GJ (0.00195 lb/MMBtu).

• Based on vendor data it was assumed that dry low NOx (DLN) burners could achieve 25 

ppmv (dry) at 15 percent O2 and, coupled with a selective catalytic reduction (SCR) unit 

that achieves 90 percent NOx reduction efficiency, would result in the environmental 

target of 2.5 ppmv (dry) at 15 percent O2 for both NGCC cases.

• Based on vendor data it was assumed that Selexol, Sulfinol-M, and refrigerated 

methyldiethanolamine (MDEA) could all meet the sulfur environmental target, hence 

emissions of approximately 0.0128 lb/MMBtu in each of the IGCC non-capture cases. In 

the CO2 capture cases, to achieve 95 percent CO2 capture from the syngas, the sulfur 
Cost and Performance Baseline for Fossil Energy Plants

22

removal is greater than in the non-capture cases resulting in emissions of approximately 

0.0009 kg/GJ (0.0022 lb/MMBtu).

• It was a study assumption that each IGCC technology could meet the filterable particulate 

emission limit with the combination of technologies employed. In the case of Shell and 

CoP, this consists of cyclones, candle filters, and the syngas scrubber. In the case of GEE 

particulate control consists of a water quench and syngas scrubber.

• Based on vendor data it was assumed that a combination of low NOx burners (LNBs) and 

nitrogen (N2) dilution could limit IGCC NOx emissions to the environmental target of 15 

ppmvd at 15 percent O2. The small variations in NOx emissions are due to small 

variations in CT gas volumes.

• Based on vendor data it was assumed that 95 percent Hg removal could be achieved 

using carbon beds thus meeting the environmental target. The Hg emissions are reported 

in Exhibit ES-16 as lb per trillion Btu to make the values the same order of magnitude as 

the other reported values.

• It was a study assumption that the PC FGD unit would remove 98 percent of the inlet 

SO2, resulting in the environmental target of 0.037 kg/GJ (0.085 lb/MMBtu). In the CO2

capture cases, the Econamine system employs a polishing scrubber to reduce emissions to 

10 ppmv entering the CO2 absorber. Nearly all of the remaining SO2 is absorbed by the 

Econamine solvent resulting in negligible emissions of SO2 in those cases.

• In PC cases, it was a study assumption that a fabric filter would remove 99.8 percent of 

the entering particulate and that there is an 80/20 split between fly ash and bottom ash. 

The result is the environmental target of 0.006 kg/GJ (0.013 lb/MMBtu) of filterable 

particulate.

• In PC cases, it was a study assumption that NOx emissions exiting the boiler equipped 

with LNBs and overfire air (OFA) would be 0.22 kg/GJ (0.50 lb/MMBtu) and that an 

SCR unit would further reduce the NOx by 86 percent, resulting in the environmental 

target of 0.030 kg/GJ (0.070 lb/MMBtu).

• In PC cases, it was a study assumption that the environmental target of 90 percent of the 

incoming Hg would be removed by the combination of SCR, fabric filter and wet FGD 

thus eliminating the need for activated carbon injection. The resulting Hg emissions for 

each of the PC cases are 4.92 x 10-7 kg/GJ (1.14 lb/TBtu).

CO2 emissions are not currently regulated. However, since there is increasing momentum for 

establishing carbon limits, it was an objective of this study to examine the relative amounts of 

CO2 capture achievable among the six technologies. CO2 emissions are presented in 

Exhibit ES-17 for each case, normalized by net output. In the body of the report CO2 emissions 

are presented on both a net and gross MWh basis. New Source Performance Standards (NSPS) 

contain emission limits for SO2 and NOx on a lb/(gross) MWh basis. However, since CO2 

emissions are not currently regulated, the potential future emission limit basis is not known and 

CO2 emissions are presented in both ways. The following conclusions can be drawn:
Cost and Performance Baseline for Fossil Energy Plants

23

Exhibit ES-15 SO2, NOx, and Particulate Emission Rates

0.00

0.02

0.04

0.06

0.08

0.10

0.12

GEE GEE w/CO2 

Capture

CoP CoP w/ CO2 

Capture

Shell Shell w/ CO2 

Capture

Subcritical

PC

Subcritical 

PC w/ CO2 

Capture

Supercritical 

PC

Supercritical 

PC w/ CO2 

Capture

NGCC NGCC w/ 

CO2 Capture

Emissions, lb/MMBtu

SO2

NOx

Particulate Matter
Cost and Performance Baseline for Fossil Energy Plants

24

Exhibit ES-16 Mercury Emission Rates

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

GEE GEE w/CO2 

Capture

CoP CoP w/ CO2 

Capture

Shell Shell w/ CO2 

Capture

Subcritical

PC

Subcritical PC 

w/ CO2 

Capture

Supercritical 

PC

Supercritical 

PC w/ CO2 

Capture

NGCC NGCC w/ CO2 

Capture

Hg Emissions, lb/TBtu
Cost and Performance Baseline for Fossil Energy Plants

25

• In cases with no CO2 capture, NGCC emits 56 percent less CO2 than PC and 52 percent 

less CO2 than IGCC per unit of net output. The lower NGCC CO2 emissions reflect the 

lower carbon intensity of natural gas relative to coal and the higher cycle efficiency of 

NGCC relative to IGCC and PC. Based on the fuel compositions used in this study, 

natural gas contains 41 lb carbon/MMBtu of heat input and coal contains 55 lb/MMBtu.

• The CO2 reduction goal in this study was a nominal 90 percent in all cases. The result is 

that the controlled CO2 emissions follow the same trend as the uncontrolled, i.e., the 

NGCC case emits less CO2 than the IGCC cases, which emit less than the PC cases.

• In the IGCC cases the nominal 90 percent CO2 reduction was accomplished by using two 

sour gas shift (SGS) reactors to convert carbon monoxide (CO) to CO2. A two-stage 

Selexol process with a second stage CO2 removal efficiency of 92 percent, a number that 

was supported by vendor quotes, was used in the GEE and Shell cases. The GEE CO2

capture case resulted in 90.3 percent reduction of CO2 in the syngas. The Shell capture 

case resulted in 90.1 percent reduction of CO2 in the syngas. In the CoP case, in order for 

the capture target of 90 percent to be achieved, the Selexol efficiency was increased to 95 

percent. This was done because of the high syngas methane content (1.5 vol% compared 

to 0.10 vol% in the GEE gasifier and 0.06 vol% in the Shell gasifier). The CoP capture 

case resulted in 90.4 percent reduction of CO2 in the syngas.

• Among the three non-capture IGCC cases the Shell process has slightly lower emissions 

primarily because it is the most efficient. The emissions in the CO2 capture cases are 

nearly identical for each case.

• The PC and NGCC cases both assume that all of the carbon in the fuel is converted to 

CO2 in the FG and that 90 percent is subsequently removed in the Econamine process, 

which was also supported by a vendor quote.
Cost and Performance Baseline for Fossil Energy Plants

26

Exhibit ES-17 CO2 Emissions Normalized By Net Output

1,723

206

1,710

217

1,595

218

1,888

266

1,768

244

804

94

0

500

1,000

1,500

2,000

2,500

GEE GEE w/CO2 

Capture

CoP CoP w/ CO2 

Capture

Shell Shell w/ CO2 

Capture

Subcritical

PC

Subcritical PC 

w/ CO2 

Capture

Supercritical 

PC

Supercritical 

PC w/ CO2 

Capture

NGCC NGCC w/ 

CO2 Capture

CO2 Emissions, lb/net-MWh
Cost and Performance Baseline for Fossil Energy Plants

27

1.

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

performance of fossil energy power systems, specifically IGCC, PC, and NGCC plants, in a 

consistent technical and economic manner that accurately reflects current market conditions. 

This is Volume 1 of a four volume report. The four volume series consists of the following:

INTRODUCTION

• 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 largely determine 

which 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

• Overall energy efficiency

• Fuel prices

• Cost of electricity (COE)

• Availability, reliability, and environmental performance

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

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

of recent commercial-scale demonstrations under the DOE’s Clean Coal Programs

Twelve different power plant design configurations were analyzed. The configurations are listed 

in Exhibit 1-1. The list includes six IGCC cases utilizing the GEE, CoP, and Shell gasifiers each 

with and without CO2 capture, and six cases representing conventional technologies: PCsubcritical, PC-SC, and NGCC plants, with and without CO2 capture. 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. Individual vendors 

have not reviewed this report and the extent of collaboration with technology vendors varied 

from case to case, with minimal or no collaboration obtained from some vendors.

Cases 7 and 8 were originally included in this study and involve production of SNG and the 

repowering of an existing NGCC facility using SNG. The two SNG cases were subsequently 

moved to Volume 2 of this report resulting in the discontinuity of case numbers (1-6 and 9-14).

GENERATING UNIT CONFIGURATIONS

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

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

sections for each case.
Cost and Performance Baseline for Fossil Energy Plants

28

The IGCC cases have different gross and net power outputs because of the gas turbine (GT) size 

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

of 232 MW when operated on syngas at International Standards Organization (ISO) conditions. 

Each case uses two CTs for a combined gross output of 464 MW. In the combined cycle a heat 

recovery steam generator (HRSG) extracts heat from the CT exhaust to power a steam turbine. 

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. While the 

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

ranges from 673 to 748 MW, which results in a range of net output from 497 (case 6) to 629 MW

(case 5). The coal feed rate required to achieve the gross power output is also different between 

the six cases, ranging from 198,220 to 220,899 kg/hr (437,000 to 487,000 lb/hr).

Similar to the IGCC cases, the NGCC cases do not have a common net power output. The 

NGCC system is again constrained by the available CT size, which is 181 MW at ISO conditions 

for both cases (based on the same advanced F class turbine used in the IGCC cases). Since the 

CO2 capture case requires both a higher auxiliary power load and a significant amount of 

extraction steam, which significantly reduces the steam turbine output, the net output in the 

NGCC case is also reduced. 

All four PC cases have a net output of 550 MW. The boiler and steam turbine industry’s ability 

to match unit size to a custom specification has been commercially demonstrated enabling a 

common net output comparison of the PC cases in this study. The coal feed rate was increased 

in the CO2 capture cases to increase the gross steam turbine output and account for the higher 

auxiliary load, resulting in a constant net output.

The balance of this report is organized as follows:

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

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

six IGCC cases.

• Chapter 4 describes the PC technologies modeled and presents the results for the four 

PC cases.

• Chapter 5 describes the NGCC technologies modeled and presents the results for the 

two NGCC cases.

• Chapter 6 is a supplemental chapter examining the impact of dry and parallel cooling 

systems.

• Chapter 7 is a supplemental chapter examining the cost and performance of a GEE 

gasifier in a quench-only configuration with CO2 capture.

• Chapter 8 is a supplemental chapter examining the COE sensitivity to 

monoethanolamine (MEA) system performance and cost.

• Chapter 9 includes a record of report revisions.

• Chapter 10 contains the reference list.
Cost and Performance Baseline for Fossil Energy Plants

29

Exhibit 1-1 Case Descriptions

Case Unit 

Cycle

Steam Cycle, 

psig/°F/°F

Combustion 

Turbine

Gasifier/Boiler 

Technology Oxidant H2S Separation/Removal

Sulfur 

Removal/

Recovery

PM Control NOx 

Control

CO2

Separation

CO2 

Capture

CO2

Sequestration

1 IGCC 1800/1050/1050 2 x Advanced F 

Class GEE Radiant Only 95 mol% O2

Single-Stage 

Selexol Claus Plant Quench, scrubber and AGR adsorber N2 dilution

2 IGCC 1800/1000/1000 2 x Advanced F 

Class GEE Radiant Only 95 mol% O2 Two-Stage Selexol Claus Plant Quench, scrubber and AGR adsorber N2 dilution Selexol 2nd

stage 90%1 Off-Site 

3 IGCC 1800/1050/1050 2 x Advanced F 

Class CoP E-GasTM 95 mol% O2

Refrigerated 

MDEA Claus Plant Cyclone, barrier filter and scrubber N2 dilution

4 IGCC 1800/1000/1000 2 x Advanced F 

Class CoP E-GasTM 95 mol% O2 Selexol Claus Plant Cyclone, barrier filter and scrubber N2 dilution Selexol 2nd

stage 90%1 Off-Site 

5 IGCC 1800/1050/1050 2 x Advanced F 

Class Shell 95 mol% O2 Sulfinol-M Claus Plant Cyclone, barrier filter and scrubber N2 dilution

6 IGCC 1800/1000/1000 2 x Advanced F 

Class Shell 95 mol% O2 Selexol Claus Plant Cyclone, barrier filter and scrubber N2 dilution Selexol 2nd

stage 90%1 Off-Site

9 PC 2400/1050/1050 Subcritical PC Air Wet FGD/ 

Gypsum Baghouse LNB w/OFA and SCR

10 PC 2400/1050/1050 Subcritical PC Air Wet FGD/ 

Gypsum Baghouse LNB w/OFA and SCR

Amine 

Absorber 90% Off-Site

11 PC 3500/1100/1100 Supercritical PC Air Wet FGD/ 

Gypsum Baghouse LNB w/OFA and SCR

12 PC 3500/1100/1100 Supercritical PC Air Wet FGD/ 

Gypsum Baghouse LNB w/OFA and SCR

Amine 

Absorber 90% Off-Site

13 NGCC 2400/1050/1050 2 x Advanced F 

Class HRSG Air LNB and 

SCR

14 NGCC 2400/1050/1050 2 x Advanced F 

Class HRSG Air LNB and 

SCR

Amine 

Absorber 90% Off-Site

1 Defined as the percentage of carbon in the syngas that is captured; differences are explained in Chapter 3.
Cost and Performance Baseline for Fossil Energy Plants

30

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

31

2.

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/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 vendor quotes, scaled estimates from previous design/build

projects, or a combination of the two. Ultimately a COE was calculated for each of the cases and 

is reported as the revenue requirement figure-of-merit.

GENERAL EVALUATION BASIS

The balance of this chapter documents the design basis common to all technologies, as well as 

environmental targets and cost assumptions used in the study. Technology specific design 

criteria are covered in subsequent chapters.

2.1 SITE CHARACTERISTICS

All plants in this study are assumed to be located at a generic plant site in Midwestern U.S., with

ambient conditions and site characteristics as presented in Exhibit 2-1 and Exhibit 2-2. The 

ambient conditions are the same as ISO conditions.

Exhibit 2-1 Site Ambient Conditions

Elevation, (ft) 0

Barometric Pressure, MPa (psia) 0.10 (14.696)

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

Design Ambient Temperature, Wet Bulb,°C, (°F) 11 (51.5)

Design Ambient Relative Humidity, % 60

Exhibit 2-2 Site Characteristics

Location Greenfield, Midwestern USA

Topography Level

Size, acres 300 (PC/IGCC), 100 (NGCC)

Transportation Rail

Ash/Slag Disposal Off Site

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

Access Land locked, 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 m (4,055 ft)
Cost and Performance Baseline for Fossil Energy Plants

32

The land area for PC and IGCC 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 the NGCC cases it was assumed the plant proper 

occupies about 10 acres leaving a buffer of 0.15 miles to the plant fence line.

In all cases it was assumed that the steam turbine is enclosed in a turbine building and in the PC 

cases the boiler is also enclosed. The gasifier in the IGCC cases and the CTs in the IGCC and 

NGCC cases are 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

• Local code height requirements

• Noise regulations – Impact on site and surrounding area

2.2 COAL CHARACTERISTICS

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

properties are from NETL’s Coal Quality Guidelines [1

The Power Systems Financial Model (PSFM) was used to derive the capital charge factors (CCF)

and levelization factors (LF) for this study [

]. 

2

The coal cost used in this study is $1.55/GJ ($1.64/MMBtu) (2007 cost of coal in June 2007 

dollars). This cost was determined using the following information from the EIA 2008 AEO:

]. The 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 2007 minemouth cost of Illinois No. 6 in 2006 dollars, $32.66/tonne 

($29.63/ton), was obtained from Supplemental Table 112 of the EIA’s 2008 AEO for 

eastern interior high-sulfur bituminous coal.

• The cost of Illinois No. 6 coal was escalated to 2007 dollars using the gross domestic 

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

$33.67/tonne ($30.55/ton) [3

• Transportation costs for Illinois No. 6 were estimated to be 25 percent of the 

minemouth cost based on the average transportation rate of the respective coals to the 

surrounding regions [

]. 

4]. The final delivered costs for Illinois No. 6 coal used in the 

calculations is $42.09/tonne ($38.18/ton) or $1.55/GJ ($1.64/MMBtu). (Note: The 

Illinois No. 6 coal cost of $1.6366/MMBtu was used in calculations, but only two 

decimal places are shown in the report.)
Cost and Performance Baseline for Fossil Energy Plants

33

Exhibit 2-3 Design Coal

Rank Bituminous 

Seam Illinois No. 6 (Herrin)

Source Old Ben Mine

Proximate Analysis (weight %) (Note A)

As Received Dry

Moisture 11.12 0.00

Ash 9.70 10.91

Volatile Matter 34.99 39.37

Fixed Carbon 44.19 49.72

Total 100.00 100.00

Sulfur 2.51 2.82

HHV, kJ/kg 27,113 30,506

HHV, Btu/lb 11,666 13,126

LHV, kJ/kg 26,151 29,544

LHV, Btu/lb 11,252 12,712

Ultimate Analysis (weight %)

As Received Dry

Moisture 11.12 0.00

Carbon 63.75 71.72

Hydrogen 4.50 5.06

Nitrogen 1.25 1.41

Chlorine 0.29 0.33

Sulfur 2.51 2.82

Ash 9.70 10.91

Oxygen (Note B) 6.88 7.75

Total 100.00 100.00

Notes: A. The proximate analysis assumes sulfur as volatile matter

B. By difference
Cost and Performance Baseline for Fossil Energy Plants

34

2.3 NATURAL GAS CHARACTERISTICS

Natural gas is utilized as the main fuel in Cases 13 and 14 (NGCC with and without CO2

capture), and its composition is presented in Exhibit 2-4 [5

Exhibit 2-4 Natural Gas Composition

].

Component Volume Percentage

Methane CH4 93.1

Ethane C2H6 3.2

Propane C3H8 0.7

n-Butane C4H10 0.4

Carbon Dioxide CO2 1.0

Nitrogen N2 1.6

Total 100.0

LHV HHV

kJ/kg 47,454 52,581

MJ/scm 34.71 38.46

Btu/lb 20,410 22,600

Btu/scf 932 1,032

Note: Fuel composition is normalized and heating values are calculated 

The first year cost of natural gas used in this study is $6.21/MMkJ ($6.55/MMBtu) (2007 cost of 

natural gas in 2007 dollars). The cost was determined using the following information from the 

EIA’s 2008 AEO:

• The 2007 East North Central region delivered cost of natural gas to electric utilities in 

2006 dollars, $231.47/1000 m3 ($6.55/1000 ft3

), was obtained from the AEO 2008 

reference case Table 108 and converted to an energy basis, $6.02/MMkJ 

($6.35/MMBtu).

• The 2007 cost was escalated to 2007 dollars using the GDP chain-type price index 

from AEO 2008, resulting in a delivered 2007 price in 2007 dollars of $6.21/MMkJ 

($6.55/MMBtu) [3]. (Note: The natural gas cost of $6.5478/MMBtu was used in 

calculations, but only two decimal places are shown in the report.)

2.4 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 BACT.

The current federal regulation governing new fossil-fuel fired electric utility steam generating 

units is the NSPS as amended in February 2006 and shown in Exhibit 2-5, which represents the 
Cost and Performance Baseline for Fossil Energy Plants

35

minimum level of control that would be required for a new fossil energy plant [6

Exhibit 2-5 Standards of Performance for Electric Utility Steam Generating Units

]. Stationary 

CT emission limits are further defined in 40 CFR Part 60, Subpart KKKK. 

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

The new NSPS standards apply to units with the capacity to generate greater than 73 MW of 

power by burning fossil fuels, as well as cogeneration units that sell more than 25 MW of power 

and more than one-third of their potential output capacity to any utility power distribution 

system. 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 lb/MWh are based on gross power output.

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 EPA 

Green Book Non-attainment Area Map relatively few areas in the Midwestern U.S. are classified 

as “non-attainment” so the plant site for this study was assumed to be in an attainment area [7

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.

].

As of October 2009, no active legislation establishes acceptable mercury emission levels. The 

levels previously established by the Clean Air Mercury Rule (CAMR) have been vacated 

through the D.C Circuit Court. Until new limits are established, the previously established 

CAMR levels are used in this report. The CAMR established NSPS limits for Hg emissions 

from new PC-fired boilers based on coal type as well as for IGCC units independent of coal type. 

The NSPS limits, based on gross output, are shown in Exhibit 2-6 [8]. The applicable limit in 

this study is 20 x 10-6 lb/MWh for both bituminous coal-fired PC boilers and for IGCC units.
Cost and Performance Baseline for Fossil Energy Plants

36

Exhibit 2-6 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 mercury content of 34 samples of Illinois No. 6 coal has an arithmetic mean value of 

0.09 ppm (dry basis) with standard deviation of 0.06 based on coal samples shipped by Illinois

mines [9]. Hence, as illustrated in Exhibit 2-7, there is a 50 percent probability that the mercury 

content in the Illinois No. 6 coal would not exceed 0.09 ppm (dry basis). The coal mercury 

content for this study was assumed to be 0.15 ppm (dry) for all IGCC and PC cases, which 

corresponds to the mean plus one standard deviation and encompasses about 84 percent of the 

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

the bottom ash or slag.

The current NSPS emission limits are provided below for each technology along with the 

environmental targets for this study and the control technologies employed to meet the targets. 

In some cases, application of the control technology results in emissions that are less than the 

target, but in no case are the emissions greater than the target.

Exhibit 2-7 Probability Distribution of Mercury Concentration in the Illinois No. 6 Coal

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

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

Mercury Concentraion in Coal, ppm db

Probability Illinois #6 Sample Will Be At or Below Value

P:\X_GEMSET\0_GEMSET Fuels Price Database\Rev.0 Fuels\[IllinoisNo6 Mercury.xls] Rev. 00 11/21/05 10:

Arithmetic Mean = 0.09 ppm db

Standard Deviation = 0.06 ppm db
Cost and Performance Baseline for Fossil Energy Plants

37

2.4.1

The IGCC environmental targets were chosen to match the EPRI’s design basis for their 

CoalFleet for Tomorrow Initiative and are shown in 

IGCC

Exhibit 2-8 [10

Exhibit 2-8 Environmental Targets for IGCC Cases

]. EPRI notes that these are 

design targets and are not to be used for permitting values.

Pollutant Environmental 

Target NSPS Limit1 Control Technology

NOx 15 ppmv (dry) 

@ 15% O2

1.0 lb/MWh

(0.091 lb/MMBtu)

Low NOx burners and 

syngas nitrogen dilution

SO2 0.0128 lb/MMBtu 1.4 lb/MWh

(0.127 lb/MMBtu)

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 

(1.8 lb/TBtu) Carbon bed

1 The value in parentheses is calculated based on the highest IGCC heat rate in this study of 10,998 Btu/kWh, CoP 

E-Gas with CO2 capture.

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

achieve 15 ppmvd at 15 percent O2, and that value was used for all IGCC cases [11,12

To achieve an environmental target of 0.0128 lb/MMBtu of SO2 requires approximately 28 ppmv 

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

efficiency of about 99.7 percent to reach the environmental target. Vendor data on each of the 

three AGR processes used in the non-capture cases indicate that this level of sulfur removal is 

possible. In the CO2 capture cases, the two-stage Selexol process was designed for 95 percent 

CO2 removal, which results in a sulfur capture of greater than 99.7 percent, hence the lower 

sulfur emissions in the CO2 capture cases.

].

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

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

and either ceramic or metallic candle filters (CoP and Shell). The environmental target of 0.0071 

lb/MMBtu filterable particulates can be achieved with each combination of particulate control 

devices so that in each IGCC case 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 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 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 
Cost and Performance Baseline for Fossil Energy Plants

38

reached. Eastman has yet to experience any mercury contamination in its product [13

2.4.2

]. Mercury

removals of greater than 99 percent can be 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.

BACT was applied to each of the PC cases and the resulting emissions compared to NSPS limits 

and recent permit averages. Since the BACT results met or exceeded the NSPS requirements 

and the average of recent permits, they were used as the environmental targets as shown in 

PC

Exhibit 2-9. The average of recent permits is comprised of 8 units at 5 locations. The 5 plants 

include Elm Road Generating Station, Longview Power, Prairie State, Thoroughbred, and Cross.

It was assumed that LNBs and staged OFA would limit NOx emissions to 0.5 lb/MMBtu and 

that SCR technology would be 86 percent efficient, resulting in emissions of 0.07 lb/MMBtu for 

all cases.

The wet limestone scrubber was assumed to be 98 percent efficient, which results in SO2

emissions of 0.085 lb/MMBtu. Current technology allows FGD removal efficiencies in excess 

of 99 percent, but based on NSPS requirements and recent permit averages, such high removal 

efficiency is not necessary.

The fabric filter used for particulate control was assumed to be 99.8 percent efficient. The result 

is particulate emissions of 0.013 lb/MMBtu in all cases, which also exceeds NSPS and recent 

permit average requirements.

Exhibit 2-9 Environmental Targets for PC Cases

Pollutant Environmental 

Target NSPS Limit

Average of 

Recent 

Permits

Control 

Technology

NOx 0.07 lb/MMBtu

1.0 lb/MWh

(0.111 

lb/MMBtu)

0.08 

lb/MMBtu

Low NOx 

burners, overfire 

air and SCR

SO2

0.085 

lb/MMBtu

1.4 lb/MWh 

(0.156 

lb/MMBtu)

0.16 

lb/MMBtu

Wet limestone 

scrubber

Particulate 

Matter 

(Filterable)

0.013 

lb/MMBtu 0.015 lb/MMBtu 0.017 lb/MMBtu Fabric filter

Mercury 1.14 lb/TBtu 20 x 10-6 lb/MWh 

(2.2 lb/TBtu) 2.49 lb/TBtu Co-benefit capture
Cost and Performance Baseline for Fossil Energy Plants

39

Mercury control for PC cases was assumed to occur through 90 percent co-benefit capture in the 

fabric filter and the wet FGD scrubber. EPA used a statistical method to calculate the Hg cobenefit capture from units using a “best demonstrated technology” approach, which for 

bituminous coals was considered to be a combination of a fabric filter and an FGD system. The 

statistical analysis resulted in a co-benefit capture estimate of 86.7 percent with an efficiency

range of 83.8 to 98.8 percent [14]. EPA’s documentation for their Integrated Planning Model 

(IPM) provides mercury emission modification factors (EMF) based on 190 combinations of 

boiler types and control technologies. The EMF is simply one minus the removal efficiency. 

For PC boilers (as opposed to cyclones, stokers, fluidized beds, and ‘others’) with a fabric filter, 

SCR and wet FGD, the EMF is 0.1, which corresponds to a removal efficiency of 90 percent

[15]. The average reduction in total Hg emissions developed from EPA’s Information Collection 

Request (ICR) data on U.S. coal-fired boilers using bituminous coal, fabric filters, and wet FGD 

is 98 percent [16

Since co-benefit capture alone exceeds the requirements of NSPS and recent permit averages, no 

activated carbon injection is included in this study.

]. The referenced sources bound the co-benefit Hg capture for bituminous coal 

units employing SCR, a fabric filter and a wet FGD system between 83.8 and 98 percent. Ninety 

percent was chosen as near the mid-point of this range and it also matches the value used by EPA 

in their IPM.

2.4.3

BACT was applied to the NGCC cases and the resulting emissions compared to NSPS limits. 

The NGCC environmental targets were chosen based on reasonably obtainable limits given the 

control technologies employed and are presented in 

NGCC

Exhibit 2-10.

Exhibit 2-10 Environmental Targets for NGCC Cases

Pollutant Environmental 

Target

40 CFR Part 60, 

Subpart KKKK 

Limits

Control 

Technology

NOx 2.5 ppmv @ 15% O2 15 ppmv @ 15% O2

Low NOx burners 

and SCR

SO2 Negligible 0.9 lb/MWh

(0.134 lb/MMBtu)1

Low sulfur content 

fuel

Particulate Matter 

(Filterable) N/A N/A N/A

Mercury N/A N/A N/A

1 Assumes a heat rate of 6,719 Btu/kWh from the NGCC non-capture case.

Published vendor literature indicates that 25 ppmv NOx at 15 percent O2 is achievable using 

natural gas and DLN technology [17,18]. The application of SCR with 90 percent efficiency 

further reduces NOx emissions to 2.5 ppmv, which was selected as the environmental target. 
Cost and Performance Baseline for Fossil Energy Plants

40

For the purpose of this study, natural gas was assumed to contain a negligible amount of sulfur 

compounds, and therefore generate negligible sulfur emissions. The EPA defines pipeline 

natural gas as containing >70 percent methane by volume or having a gross calorific value 

(GCV) of between 35.4 and 40.9 MJ/Nm3 (950 and 1,100 Btu/scf) and having a total sulfur 

content of less than 13.7 mg/Nm3 (0.6 gr/100 scf) [19

The pipeline natural gas was assumed to contain no particulate matter (PM) and no mercury 

resulting in no emissions of either.

]. Assuming a sulfur content equal to the 

EPA limit for pipeline natural gas, resulting SO2 emissions for the two NGCC cases in this study 

would be approximately 21 tonnes/yr (23.2 tons/yr) at 85 percent CF or 0.00084 kg/GJ (0.00195 

lb/MMBtu). Thus, for the purpose of this study, SO2 emissions were considered negligible.

2.4.4

CO2 is not currently regulated nationally. However, the possibility exists that federal carbon 

limits will be imposed in the future and this study examines cases that include a reduction in CO2

emissions. Because the form of emission limits, should they be imposed, is not known, CO2

emissions are reported on both a lb/(gross) MWh and lb/(net) MWh basis in each capture case 

emissions table.

Carbon Dioxide

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. In the GEE 

and Shell cases, this was accomplished by using two SGS reactors, to convert CO to CO2, and a

two-stage Selexol process with a second stage CO2 removal efficiency of 92 percent, a number 

that was supported by vendor quotes. The GEE CO2 capture case resulted in 90.3 percent 

reduction of CO2 in the syngas. The Shell capture case resulted in 90.1 percent reduction of CO2

in the syngas. In the CoP case, in order for the capture target of 90 percent to be achieved, a 

third SGS reactor was added and the Selexol efficiency was increased to 95 percent (the 

maximum removal efficiency supported by vendor quotes). This was done because of the high 

syngas methane content (1.5 vol% compared to 0.10 vol% in the GEE gasifier and 0.06 vol% in 

the Shell gasifier). The CoP capture case resulted in 90.4 percent reduction of CO2 in the syngas.

For PC and NGCC cases that have CO2 capture, it is assumed that all of the fuel carbon is 

converted to CO2 in the FG. CO2 is also generated from limestone in the FGD system, and 90 

percent of the CO2 exiting the FGD absorber is subsequently captured using the Econamine 

technology.

The cost of CO2 capture was calculated as an avoided cost as illustrated in the equation below. 

Analogous non-capture technologies and SC non-capture PC were chosen as separate reference 

cases. The COE in the CO2 capture cases includes TS&M as well as capture and compression.

CO Emissions CO Emissions tons MWh

COE COE MWh

Avoided Cost

reference with removal

with removal reference

{ } /

{ } $ /

2 − 2

− =
Cost and Performance Baseline for Fossil Energy Plants

41

2.5 CAPACITY FACTOR

This study assumes that each new plant would be dispatched any time it is available and would 

be capable of generating maximum capacity when online. Therefore, CF and availability are 

equal. The availability for PC and NGCC cases was determined using the Generating 

Availability Data System (GADS) from the North American Electric Reliability Council 

(NERC) [20

NERC defines an equivalent availability factor (EAF), which is essentially a measure of the plant 

CF assuming there is always a demand for the output. The EAF accounts for planned and 

scheduled derated hours as well as seasonal derated hours. As such, the EAF matches this 

study’s definition of CF.

]. Since there are only two operating IGCC plants in North America, the same 

database was not useful for determining IGCC availability. Rather, input from EPRI and their 

work on the CoalFleet for Tomorrow Initiative was used.

The average EAF for coal-fired plants in the 400-599 MW size range was 84.9 percent in 2004 

and averaged 83.9 percent from 2000-2004. Given that many of the plants in this size range are 

older, the EAF was rounded up to 85 percent and that value was used as the PC plant CF.

The average EAF for NGCC plants in the 400-599 MW size range was 84.7 percent in 2004 and 

averaged 82.7 percent from 2000-2004. Using the same rationale as for PC plants, the EAF was 

rounded up to 85 percent and that value was also used as the NGCC plant CF.

EPRI examined the historical forced and scheduled outage times for IGCCs and concluded that 

the reliability factor (which looks at forced or unscheduled outage time only) for a single train 

IGCC (no spares) would be about 90 percent [21

There are four operating IGCC’s worldwide that use a solid feedstock and are primarily power 

producers (Polk, Wabash, Buggenum, and Puertollano). A 2006 report by Higman et al. 

examined the reliability of these IGCC power generation units and concluded that typical annual 

on-stream times are around 80 percent [

]. To get the availability factor, one has to 

deduct the scheduled outage time. In reality the scheduled outage time differs from gasifier 

technology-to-gasifier technology, but the differences are relatively small and would have 

minimal impact on the CF, so for this study it was assumed to be constant at a 30-day planned 

outage per year (or two 15-day outages). The planned outage would amount to 8.2 percent of the 

year, so the availability factor would be (90 percent - 8.2 percent), or 81.2 percent.

22

The addition of CO2 capture 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.

]. 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 the EPRI study and the Higman paper, a CF of 80 percent was chosen for 

IGCC with no spare gasifier required.

2.6 RAW WATER WITHDRAWAL AND CONSUMPTION

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

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

various sources like BFW blowdown and condensate from syngas or FG (in CO2 capture cases) 

was applied to offset the water demand. The difference between demand and recycle is raw 
Cost and Performance Baseline for Fossil Energy Plants

42

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 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, quench system makeup, and FGD system makeup. The difference 

between withdrawal and process water returned to the source is consumption. Consumption 

represents the net impact of the process on the water source.

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

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

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

the balance sent to the ash ponds for evaporation.

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

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

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

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

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

11°C (20°F). The cooling tower makeup rate was determined using the following:[23

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

]

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

• Blowdown losses were calculated as follows:

o Blowdown Losses = Evaporative Losses / (Cycles of Concentration - 1)

Where cycles of concentration is a measure of water quality, and a mid-range 

value of 4 was chosen for this study.

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

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

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

water consumption, again by difference.

2.7 COST ESTIMATING METHODOLOGY

The estimating methodology for capital costs, operations and maintenance costs, and CO2 TS&M 

costs are described below. The finance structure, basis for the discounted cash flow analysis, and 

first-year COE cost calculations are also described.

2.7.1

As illustrated in 

Capital Costs

Exhibit 2-11, 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 
Cost and Performance Baseline for Fossil Energy Plants

43

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

assumed to last five years coal plants (2007 to 2011) and three years for natural gas plants (2007 

to 2009).

Exhibit 2-11 Capital Cost Levels and their Elements

The BEC

The 

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.

TPC

The 

comprises the BEC plus the cost of services provided by the engineering, procurement 

and construction (EPC) contractor and project and process contingencies. EPC services include: 

detailed design, contractor permitting (i.e., those permits that individual contractors must obtain 

to perform their scopes of work, as opposed to project permitting, which is not included here), 

and project/construction management costs. TPC is an overnight cost expressed in base-year 

(2007) dollars.

TOC

The 

comprises the TPC plus owner’s costs. TOC is an “overnight” cost, expressed in baseyear (2007) dollars and as such does not include escalation during construction or interest during 

construction. TOC is an overnight cost expressed in base-year (2007) dollars.

TASC

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.

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. 
Cost and Performance Baseline for Fossil Energy Plants

44

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 [24

Most techno-economic studies completed by NETL feature cost estimates intended for the 

purpose of a “Feasibility Study” (AACE Class 4). 

].

Exhibit 2-12 describes the characteristics of 

an AACE Class 4 Cost Estimate. Cost estimates in this study have an expected accuracy range 

of -15%/+30%.

Exhibit 2-12 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). 

Non-CO2 Capture Plant Maturity

The case estimates provided include technologies at different commercial maturity levels. The 

estimates for the non-CO2-capture PC and NGCC cases represent well-developed commercial 

technology or “nth plants.” The non-capture IGCC cases are also 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, 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 post-combustion CO2 removal technology for the PC and NGCC capture cases is immature 

technology. This technology remains unproven at commercial scale in power generation 

applications. 
Cost and Performance Baseline for Fossil Energy Plants

45

The pre-combustion CO2 removal technology for the IGCC capture cases has a stronger 

commercial experience base. Pre-combustion CO2 removal from syngas streams has been 

proven in chemical processes with similar conditions to that in IGCC plants, but has not been 

demonstrated in IGCC applications. While no commercial IGCC plant yet uses CO2 removal 

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. However, as a result of current market conditions, EPC contractors appear 

more reluctant to assume that overall level of risk. Rather, the current trend appears to be a 

modified EPC approach where much of the risk remains with the Owner. Where Contractors are 

willing to accept the risk in EPC type lump-sum arrangements, it is reflected in the project cost. 

In today’s market, Contractor premiums for accepting these risks, particularly performance risk, 

can be substantial and increase the overall project costs dramatically. 

The EPCM approach used as the basis for the estimates here is anticipated to be the most cost 

effective approach for the Owner. While the Owner retains the risks, the risks become reduced 

with time, as there is better scope definition at the time of contract award(s).

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. 

Other key estimate considerations include the following:

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

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

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

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

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

PAS presents information for eight separate regions. For this study, Region 5 (IL, IN, 

MI, MN, OH, and WI) was selected.
Cost and Performance Baseline for Fossil Energy Plants

46

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

craft labor available locally.

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

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

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

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

• The estimates are based on a greenfield site. 

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

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

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

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

• Costs are limited to within the “fence line,” terminating at the high voltage side of the 

main power transformers with the exception of costs included for TS&M, which are 

treated as an addition to COE.

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

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

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

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

materials management, site safety, and field inspection.

Price Fluctuations

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

substantially. Some reference quotes pre-dated the 2007 year cost basis while others were 

received post-2007. All vendor quotes used to develop these estimates were adjusted to June 

2007 dollars accounting for the price fluctuations. Adjustments of costs pre-dating 2007 

benefitted from a vendor survey of actual and projected pricing increases from 2004 through 

mid-2007 that WorleyParsons conducted for another project. The results of that survey were 

used to validate/recalibrate the corresponding escalation factors used in the conceptual 

estimating models. The more recent economic down turn has resulted in a reduction of 

commodity prices such that many price indices have similar values in January 2010 compared to 

June 2007. For example, the Chemical Engineering Plant Cost Index was 532.7 in June 2007 

and 532.9 in January 2010, and the Gross Domestic Product Chain-type Price Index was 106.7 

on July 1, 2007 and 110.0 on January 1, 2010. While these overall indices are nearly constant, it 

should be noted that the cost of individual equipment types may still deviate from the June 2007 

reference point.

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 
Cost and Performance Baseline for Fossil Energy Plants

47

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

design philosophy occur. Some key examples are: 

• The CT account in the GEE IGCC cases includes a syngas expander, which is not 

required for the CoP or Shell cases.

• The CTs for the IGCC capture cases include an additional cost for firing a high hydrogen

content fuel.

• The Shell gasifier syngas cooling configuration is different between the CO2-capture and 

non-CO2-capture cases, resulting in a significant differential in thermal duty between the 

syngas coolers for the two cases. 

Exclusions

The capital cost estimate includes all anticipated costs for equipment and materials, installation 

labor, professional services (Engineering and Construction Management), and contingency. The 

following items are excluded from the capital costs:

• All taxes, with the exception of payroll and property taxes (property taxes are included 

with the fixed O&M costs)

• Site specific considerations – including, but not limited to, seismic zone, accessibility, 

local regulatory requirements, excessive rock, piles, laydown space, etc. 

• Labor incentives in excess of 5-10s

• Additional premiums associated with an EPC contracting approach

Contingency

Process and project contingencies are included in estimates to account for unknown costs that are 

omitted or unforeseen due to a lack of complete project definition and engineering. 

Contingencies are added because experience has shown that such costs are likely, and expected, 

to be incurred even though they cannot be explicitly determined at the time the estimate is 

prepared. 

Capital cost contingencies do not cover uncertainties or risks associated with

• scope changes

• changes in labor availability or productivity

• delays in equipment deliveries

• changes in regulatory requirements

• unexpected cost escalation

• performance of the plant after startup (e.g., availability, efficiency)

Process Contingency

Process contingency is intended to compensate for uncertainty in cost estimates caused by 

performance uncertainties associated with the development status of a technology. Process 

contingencies are applied to each plant section based on its current technology status.
Cost and Performance Baseline for Fossil Energy Plants

48

As shown in Exhibit 2-13, AACE International Recommended Practice 16R-90 provides 

guidelines for estimating process contingency based on EPRI philosophy [25

Process contingencies have been applied to the estimates in this study as follows:

].

• Slurry Prep and Feed – 5 percent on GE IGCC cases - systems are operating at 

approximately 800 psia as compared to 600 psia for the other IGCC cases

• Gasifiers and Syngas Coolers – 15 percent on all IGCC cases – next-generation

commercial offering and integration with the power island

• Two Stage Selexol – 20 percent on all IGCC capture cases - unproven technology at 

commercial scale in IGCC service

• Mercury Removal – 5 percent on all IGCC cases – minimal commercial scale 

experience in IGCC applications

• CO2 Removal System – 20 percent on all PC/NGCC capture cases - post-combustion 

process unproven at commercial scale for power plant applications

• CTG – 5 percent on all IGCC non-capture cases – syngas firing and ASU integration; 

10 percent on all IGCC capture cases – high hydrogen firing. 

• Instrumentation and Controls – 5 percent on all IGCC accounts and 5 percent on the 

PC and NGCC capture cases – integration issues

Exhibit 2-13 AACE Guidelines for Process Contingency

Technology Status Process Contingency

(% of Associated Process Capital)

New concept with limited data 40+

Concept with bench-scale data 30-70

Small pilot plant data 20-35

Full-sized modules have been operated 5-20

Process is used commercially 0-10

Process contingency is typically not applied to costs that are set equal to a research goal or 

programmatic target since these values presume to reflect the total cost.

Project Contingency

AACE 16R-90 states that project contingency for a “budget-type” estimate (AACE Class 4 or 5) 

should be 15 to 30 percent of the sum of BEC, EPC fees and process contingency. This was 

used as a general guideline, but some project contingency values outside of this range occur 

based on WorleyParsons’ in-house experience. 
Cost and Performance Baseline for Fossil Energy Plants

49

Owner’s Costs

Exhibit 2-15 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 [25]. 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 2-14.

Exhibit 2-14 TASC/TOC Factors

Finance Structure High Risk IOU Low Risk IOU

Capital Expenditure Period Three Years Five Years Three Years Five Years

TASC/TOC 1.078 1.140 1.075 1.134
Cost and Performance Baseline for Fossil Energy Plants

50

Exhibit 2-15 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 and PC, 100 acres for NGCC)

Financing 

Cost

• 2.7% of TPC

This financing cost (not included by AACE 16R-90) covers the cost of securing financing, including fees and closing costs 

but not including interest during construction (or AFUDC). The “rule of thumb” estimate (2.7% of TPC) is based on a 

2008 private communication with a capital services firm.
Cost and Performance Baseline for Fossil Energy Plants

51

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-per-day work 

week. Owner’s contingency is NOT a part of project contingency.)

This lumped cost does NOT include:

­ EPC Risk Premiums (Costs estimates are based on an Engineering Procurement Construction Management approach 

utilizing multiple subcontracts, in which the owner assumes project risks for performance, schedule and cost)

­ Transmission interconnection: the cost of interconnecting with power transmission infrastructure beyond the plant 

busbar.

­ Taxes on capital costs: all capital costs are assumed to be exempt from state and local taxes.

­ Unusual site improvements: normal costs associated with improvements to the plant site are included in the bare 

erected cost, assuming that the site is level and requires no environmental remediation. Unusual costs associated with 

the following design parameters are excluded: flood plain considerations, existing soil/site conditions, water 

discharges and reuse, rainfall/snowfall criteria, seismic design, buildings/enclosures, fire protection, local code height 

requirements, noise regulations.
Cost and Performance Baseline for Fossil Energy Plants

52

2.7.2

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: 

Operations and Maintenance Costs

• Operating labor

• Maintenance – material and labor

• Administrative and support labor

• Consumables

• Fuel

• Waste disposal

• Co-product or by-product credit (that is, a negative cost for any by-products sold)

There are two components of O&M costs; fixed O&M, which is independent of power 

generation, and variable O&M, which is proportional to power generation. 

Operating Labor

Operating labor cost was determined based on of the number of operators required for each 

specific case. The average base labor rate used to determine annual cost is $34.65/hour. The 

associated labor burden is estimated at 30 percent of the base labor rate. Taxes and insurance are 

included as fixed O&M costs totaling 2 percent of the TPC.

Maintenance Material and Labor

Maintenance cost was evaluated on the basis of relationships of maintenance cost to initial 

capital cost. This represents a weighted analysis in which the individual cost relationships were 

considered for each major plant component or section.

Administrative and Support Labor

Labor administration and overhead charges are assessed at rate of 25 percent of the burdened 

O&M labor.

Consumables

The cost of consumables, including fuel, was determined on the basis of individual rates of 

consumption, the unit cost of each specific consumable commodity, and the plant annual 

operating hours. 

Quantities for major consumables such as fuel and sorbent were taken from technology-specific 

heat and mass balance diagrams developed for each plant application. Other consumables were 

evaluated on the basis of the quantity required using reference data. 

The quantities for initial fills and daily consumables were calculated on a 100 percent operating 

capacity basis. The annual cost for the daily consumables was then adjusted to incorporate the 

annual plant operating basis, or CF. 

Initial fills of the consumables, fuels and chemicals, are different from the initial chemical 

loadings, which are included with the equipment pricing in the capital cost.
Cost and Performance Baseline for Fossil Energy Plants

53

Waste Disposal

Waste quantities and disposal costs were determined/evaluated similarly to the consumables. In 

this study both slag from the IGCC cases and fly ash and bottom ash from the PC cases are 

considered a waste with a disposal cost of $17.89/tonne ($16.23/ton). The carbon used for 

mercury control in the IGCC cases is considered a hazardous waste with disposal cost of 

$926/tonne ($840/ton).

Co-Products and By-Products 

By-product quantities were also determined similarly to the consumables. However, due to the 

variable marketability of these by-products, specifically gypsum and sulfur, no credit was taken 

for their potential salable value.

It should be noted that by-product credits and/or disposal costs could potentially be an additional 

determining factor in the choice of technology for some companies and in selecting some sites. 

A high local value of the product can establish whether or not added capital should be included 

in the plant costs to produce a particular co-product. Ash and slag are both potential by-products 

in certain markets, and in the absence of activated carbon injection in the PC cases, the fly ash 

would remain uncontaminated and have potential marketability. However, as stated above, the 

ash and slag are considered wastes in this study with a concomitant disposal cost.

2.7.3

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 Transport, Storage and Monitoring

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 2-16 [26

Exhibit 2-16 CO2 Pipeline Specification

]. A glycol dryer located near the 

mid-point of the compression train is used to meet the moisture 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
Cost and Performance Baseline for Fossil Energy Plants

54

• 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 [27]. 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

[28

• 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) [

]. (Although not explored in this study, the use of boost compressors and a smaller 

pipeline diameter could possibly reduce capital costs for sufficiently long pipelines.) The 

diameter of the injection pipe will be of sufficient size that frictional losses during 

injection are minimal and no booster compression is required at the well-head in order to 

achieve an appropriate down-hole pressure, with hydrostatic head making up the 

difference between the injection and reservoir pressure.

29

29

]. 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 [ ]. The assumed aquifer 

characteristics are tabulated in Exhibit 2-17.

The cost metrics utilized in this study provide a best estimate of TS&M costs for a “favorable” 

sequestration project, and may vary significantly based on variables such as terrain to be crossed 

by the pipeline, reservoir characteristics, and number of land owners from which sub-surface 

rights must be acquired. Raw capital and operating costs are derived from detailed cost metrics 

found in the literature, escalated to June 2007-year dollars using appropriate price indices. These 

costs were then verified against values quoted by industrial sources where possible. Where 

regulatory uncertainty exists or costs are undefined, such as liability costs and the acquisition of 

underground pore volume, analogous existing policies were used for representative cost 

scenarios.

Exhibit 2-17 Deep, Saline Aquifer Specification

Parameter Units Base Case

Pressure MPa (psi) 8.4 (1,220)

Thickness m (ft) 161 (530)

Depth m (ft) 1,236 (4,055)

Permeability Md 22

Pipeline Distance km (miles) 80 (50)

Injection Rate per Well tonne (ton) CO2/day 9,360 (10,320)

The following sections describe the sources and methodology used for each metric.
Cost and Performance Baseline for Fossil Energy Plants

55

TS&M Captial Costs

TS&M capital costs include both a 20 percent process contingency and 30 percent project 

contingency. 

In several areas, such as Pore Volume Acquisition, Monitoring, and Liability, cost outlays occur 

over a longer time period, up to 100 years. In these cases a capital fund is established based on 

the net present value of the cost outlay, and this fund is then levelized similar to the other costs.

Transport Costs

CO2 transport costs are broken down into three categories: pipeline costs, related capital 

expenditures, and O&M costs.

Pipeline costs are derived from data published in the Oil and Gas Journal’s (O&GJ) annual 

Pipeline Economics Report for existing natural gas, oil, and petroleum pipeline project costs 

from 1991 to 2003. These costs are expected to be analogous to the cost of building a CO2

pipeline, as noted in various studies [27, 29, 30

30

]. 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 [ ]. 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 [29]. 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 [27]. 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 [27]. These costs include all of the costs 

associated with determining, developing, and maintaining a CO2 storage location, including site 

evaluation, well drilling, and the capital equipment required for distributing and injecting CO2.

Pore Volume Acquisition costs are the costs associated with acquiring rights to use the subsurface volume where the CO2 will be stored, i.e., the pore space in the geologic formation. 

These costs were based on recent research by Carnegie Mellon University, which examined 

existing sub-surface rights acquisition as it pertains to natural gas storage [31]. 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 
Cost and Performance Baseline for Fossil Energy Plants

56

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 [32]. 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) [33,34,35

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.

]. 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. 

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 [36

2.7.4

]. 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.

The global economic assumptions are listed in 

Finance Structure, Discounted Cash Flow Analysis, and COE

Exhibit 2-18. 

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 as well as PC and NGCC cases with CO2 capture were considered high risk. 

The non-capture PC and NGCC cases were considered low risk. Exhibit 2-19 describes the lowrisk IOU and high-risk IOU finance structures that were assumed for this study. These finance 
Cost and Performance Baseline for Fossil Energy Plants

57

structures were recommended in a 2008 NETL report based on interviews with project 

developers/owners, financial organizations and law firms [37].

Exhibit 2-18 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 Natural Gas Plants: 3 Years

Coal Plants: 5 Years

Operational Period 30 years

Economic Analysis Period (used for IRROE) 33 or 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)

3-Year Period: 10%, 60%, 30%

5-Year Period: 10%, 30%, 25%, 20%, 15%

Working Capital zero for all parameters

% of Total Overnight Capital that is Depreciated

100% (this assumption introduces a very small 

error even if a substantial amount of TOC is 

actually non-depreciable)

ESCALATION OF OPERATING REVENUES AND COSTS

Escalation of COE (revenue), O&M Costs, and 

Fuel Costs (nominal annual rate) 3.0%3

 

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.

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.)
Cost and Performance Baseline for Fossil Energy Plants

58

Exhibit 2-19 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

Exhibit 2-20

in two ways: a COE and a levelized COE (LCOE). To illustrate how the two are related, 

COE solutions are shown in 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.

• 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

Exhibit 2-20

, 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 

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. 

 

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.

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.
Cost and Performance Baseline for Fossil Energy Plants

59

• 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

Exhibit 2-20

. “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 2-20 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 2-20, 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 and 2010 for natural gas plants in this study. Note that, according to 

the Chemical Engineering Plant Cost Index, June-2007 dollars are nearly equivalent to January2010 dollars.

 

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 for Fossil Energy Plants

60

Exhibit 2-20 Illustration of COE Solutions using DCF Analysis

In addition to the capital expenditure period, the economic analysis considers thirty years of 

operation for both coal and natural gas plants.

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 2-20 are expressed in current dollars. However, they can also be expressed in constant, 

base year dollars (June 2007) as shown in Exhibit 2-21 by adjusting them with the assumed 

nominal annual general inflation rate (3 percent).

Exhibit 2-21 illustrates the same information as in Exhibit 2-20 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.
Cost and Performance Baseline for Fossil Energy Plants

61

Exhibit 2-21 PC with CCS in Current 2007 Dollars

For scenarios that adhere to the global economic assumptions listed in 

Estimating COE with Capital Charge Factors

Exhibit 2-18 and utilize 

one of the finance structures listed in Exhibit 2-19, the following simplified equation can be used 

to estimate COE as a function of TOC8

Exhibit 2-22

, 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 . These CCFs are valid only for the global economic assumptions 

listed in Exhibit 2-18, the stated finance structure, and the stated capital expenditure period.

 

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 for Fossil Energy Plants

62

Exhibit 2-22 Capital Charge Factors for COE Equation

Finance

Structure High Risk IOU Low Risk IOU

Capital Expenditure Period Three Years Five Years Three Years Five Years

Capital Charge Factor (CCF) 0.111 0.124 0.105 0.116

All factors in the COE equation are expressed in base-year dollars. The base year is the first year 

of capital expenditure, which for this study is assumed to be 2007. As shown in Exhibit 2-18, 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 2-22 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
Cost and Performance Baseline for Fossil Energy Plants

63

The primary cost metric in this study is the COE, which is the base-year cost presented in baseyear dollars. Exhibit 2-23 presents this cost metric along with the COE escalated to the first 

year of operation (2010 for NGCC cases and 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.

Exhibit 2-23 COE and LCOE Summary

Case

COE LCOE

Base-Year First Operational Year Base-Year First Operational Year

2007$

(all cases)

2010$

(NGCC cases)

2012$

(coal cases)

2007$

(all cases)

2010$

(NGCC cases)

2012$

(coal cases)

1 76.28 N/A 88.43 96.70 N/A 112.10

2 105.66 N/A 122.49 133.94 N/A 155.27

3 74.02 N/A 85.81 93.83 N/A 108.77

4 110.39 N/A 127.97 139.93 N/A 162.22

5 81.31 N/A 94.26 103.07 N/A 119.48

6 119.46 N/A 138.49 151.43 N/A 175.55

9 59.40 N/A 68.86 75.29 N/A 87.29

10 109.69 N/A 127.16 139.05 N/A 161.20

11 58.91 N/A 68.29 74.67 N/A 86.56

12 106.63 N/A 123.61 135.16 N/A 156.69

13 58.90 64.36 N/A 74.65 81.58 N/A

14 85.93 93.89 N/A 108.93 119.03 N/A

2.8 IGCC STUDY COST ESTIMATES COMPARED TO INDUSTRY ESTIMATES

The estimated TOC for IGCC cases in this study ranges from $2,351 to $2,716/kW for non- CO2

capture cases and $3,334/kW to $3,904/kW for capture cases. Plant size ranges from 622 - 629

MW (net) for non-capture cases and 497 - 543 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 
Cost and Performance Baseline for Fossil Energy Plants

64

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 

[38,39,40,41].

9

 

Project Scope

Differences in Cost Estimates

For this report, the scope of work is generally limited to work inside the project “fence line”. For 

outgoing power, the scope stops at the high side terminals of the Generator Step-up Transformers 

(GSUs). 

Some typical examples of items outside the fenceline include:

• New access roads and railroad tracks

• Upgrades to existing roads to accommodate increased traffic

• Makeup water pipe outside the fenceline

• Landfill for on-site waste (slag) disposal

• Natural gas line for backup fuel provisions

• Plant switchyard

• Electrical transmission lines & substation

Estimates in this report are based on a generic mid-western greenfield site having “normal” 

characteristics. Accordingly, the estimates do not address items such as:

• Piles or caissons

• Rock removal

• Excessive dewatering

• Expansive soil considerations

• Excessive seismic considerations

• Extreme temperature considerations

• Hazardous or contaminated soils

• Demolition or relocation of existing structures

• Leasing of offsite land for parking or laydown

• Busing of craft to site

• Costs of offsite storage

This report is based on a reasonably “standard” plant. No unusual or extraordinary process 

equipment is included such as:

• Excessive water treatment equipment

• Air-cooled condenser

• Automated coal reclaim

• Zero Liquid Discharge equipment

• SCR catalyst (IGCC cases only)

 

9 Costs were adjusted to June 2007 using the Chemical Engineering Plant Cost Index
Cost and Performance Baseline for Fossil Energy Plants

65

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.
Cost and Performance Baseline for Fossil Energy Plants

66

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

67

3.

Six 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.

IGCC POWER PLANTS

The six cases are based on the GEE gasifier, the CoP E-GasTM gasifier and the Shell gasifier, 

each with and without CO2 capture. As discussed in Section 1, the net output for the six cases 

varies because of the constraint imposed by the fixed GT output and the high auxiliary loads 

imparted by the CO2 capture process.

The CT is based on an advanced F-class design. The HRSG/steam turbine cycle varies based on 

the CT exhaust conditions. Steam conditions range from 12.4 MPa/559°C/559°C (1800 

psig/1038°F/1038°F) to 12.4 MPa/562°C/562°C (1800 psig/1043°F/1043°F) for all of the nonCO2 capture cases and 12.4 MPa/534°C/534°C (1800 psig/993°F/993°F) to 12.4 

MPa/534°C/534°C (1800 psig/994°F/994°F) for all of the CO2 capture cases. The capture cases 

have a lower main and reheat steam temperature primarily because the turbine firing temperature 

is reduced to allow for a parts life equivalent to NGCC operation with a high-hydrogen content 

fuel, which results in a lower turbine exhaust temperature. 

The evaluation scope included developing heat and mass balances and estimating plant 

performance. Equipment lists were developed for each design to support plant capital and 

operating cost estimates. The evaluation basis details, including site ambient conditions, fuel 

composition and environmental targets, 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 Sections 3.2, 3.3 and 3.4.

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, oxygen supply, gas cleanup, power generation, etc. As detailed 

descriptions of these process areas for each case would be burdensome and repetitious, they are 

presented in this section for general background information. Where there is case-specific 

performance information, the performance features are presented in the relevant case sections.

3.1.1

The function of the Coal Receiving and Storage system is to unload, convey, prepare, and store 

the coal delivered to the plant. The scope of the system is from the trestle bottom dumper and 

coal receiving hoppers up to and including the slide gate valves at the outlet of the coal storage 

silos. Coal receiving and storage is identical for all six IGCC cases; however, coal preparation 

and feed are gasifier-specific.

Coal Receiving and Storage

Operation Description – The coal is delivered to the site by 100-car unit trains comprised of 91 

tonne (100 ton) rail cars. The unloading is done by a trestle bottom dumper, which unloads the 

coal into two receiving hoppers. Coal from each hopper is fed directly into a vibratory feeder. 

The 8 cm x 0 (3" x 0) coal from the feeder is discharged onto a belt conveyor. Two conveyors 

with an intermediate transfer tower are assumed to convey the coal to the coal stacker, which 

transfer the coal to either the long-term storage pile or to the reclaim area. The conveyor passes 

under a magnetic plate separator to remove tramp iron and then to the reclaim pile.
Cost and Performance Baseline for Fossil Energy Plants

68

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

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) [

Air Separation Unit (ASU) Choice and Integration

42]. 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.

The residual nitrogen that is available after gasifier oxygen and nitrogen requirements have been 

met is often 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 consumption and to provide a good 

match with available compressor frame sizes.

Residual Nitrogen Injection

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. 

This is particularly beneficial for locations where the ambient temperature and/or 

elevation are high and the GT would normally operate at reduced output.

• By mixing with the syngas or by being injected directly into the combustor, the diluent 

nitrogen lowers the firing temperature (relative to natural gas) and reduces the formation 

of thermal NOx.

In this study, the ASU nitrogen product was used as the primary diluent with a design target of 

reducing the syngas lower heating value (LHV) to 4.4-4.7 MJ/Nm3 (119-125 Btu/scf). If the 

amount of available nitrogen was not sufficient to meet this target, additional dilution was 

provided through syngas humidification, and if still more dilution was required, the third option 

was steam injection.

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 British thermal unit (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 

Air Integration
Cost and Performance Baseline for Fossil Energy Plants

69

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 - 454°C (750 - 850°F), and must be cooled to the last stage main air compressor 

discharge temperature prior to admission to the ASU. High-level recovery from the extracted air 

occurs by transferring heat to the nitrogen stream to be injected into the GT with a gas-to-gas 

heat exchanger.

The Buggenum, Netherlands unit built for Demkolec was the first elevated-pressure, fully 

integrated ASU to be constructed. It was designed to produce up to 1,796 tonnes/day (1,980 tons 

per day [TPD]) of 95 percent purity oxygen for a Shell coal-based gasification unit that fuels a 

Siemens V94.2 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.

Elevated Pressure ASU Experience in Gasification

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 [43].

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.

ASU Basis

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 output must be maintained at 232 MW.

• The diluted syngas must meet heating value requirements specified by a CT vendor, 

which ranged from 4.4-4.7 MJ/Nm3 (119-125 Btu/scf).

Meeting the above constraints resulted in different levels of air extraction in the three non-carbon 

capture cases as shown in Exhibit 3-1. 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

[44,45].
Cost and Performance Baseline for Fossil Energy Plants

70

Exhibit 3-1 Air Extracted from the Combustion Turbine and Supplied to the ASU in NonCarbon Capture Cases

Case No. 1 3 5

Gasifier GEE CoP Shell

Air Extracted from Gas Turbine, % 4.0 4.0 4.0

Air Provided to ASU, % of ASU Total 16.8 18.9 19.4

Air Separation Plant Process Description[46

The air separation plant is designed to produce 95 mole percent (mol%) 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 3-2.

The air feed to the ASU is supplied from two sources. A portion of the air is extracted from the 

compressor of the GT (non-CO2 capture cases only). The remaining air is supplied from a standalone compressor. Air to the stand-alone compressor is first filtered in a suction filter upstream 

of the compressor. This air filter removes particulate, which may tend to cause compressor 

wheel erosion and foul intercoolers. The filtered air is then compressed in the centrifugal 

compressor, with intercooling 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 

regeneration, the heated bed is cooled to near normal operating temperature by passing a cool 

nitrogen stream through the adsorbent beds. The bed is re-pressurized with air and placed on 

stream so that the current on-stream bed(s) can be regenerated.

The air from the pre-purifier is then split into three streams. About 70 percent of the air is fed 

directly to the cold box. About 25 percent of the air is compressed in an air booster compressor. 

This boosted air is then cooled in an aftercooler against cooling water in the first stage and 

against chilled water in the second stage before it is fed to the cold box. The chiller utilizes lowpressure (LP) process steam at 0.3 MPa (50 psia) to drive the absorption refrigeration cycle. The 

remaining five percent of the air is fed to a turbine-driven, single-stage, centrifugal booster 

compressor. This stream is cooled in a shell and tube aftercooler against cooling water before it 

is fed to the cold box.
Cost and Performance Baseline for Fossil Energy Plants

71

All three air feeds are cooled in the cold box to cryogenic temperatures against returning product 

oxygen and nitrogen streams in plate-and-fin heat exchangers. The large air stream is fed 

directly to the first distillation column to begin the separation process. The second largest air 

stream is liquefied against boiling liquid oxygen before it is fed to the distillation columns. The 

third, smallest air stream is fed to the cryogenic expander to produce refrigeration to sustain the 

cryogenic separation process.

Inside the cold box the air is separated into oxygen and nitrogen products. The oxygen product 

is withdrawn from the distillation columns as a liquid and is pressurized by a cryogenic pump. 

The pressurized liquid oxygen is then vaporized against the high-pressure (HP) air feed before 

being warmed to ambient temperature. The gaseous oxygen exits the cold box and is fed to the 

centrifugal compressor with intercooling between each stage of compression. The compressed 

oxygen is then fed to the gasification unit.

Nitrogen is produced from the cold box at two pressure levels. LP nitrogen is split into two 

streams. The majority of the LP nitrogen is compressed and fed to the GT as diluent nitrogen. A 

small portion of the nitrogen is used as the regeneration gas for the pre-purifiers and recombined 

with the diluent nitrogen. A HP nitrogen stream is also produced from the cold box and is 

further compressed before it is also supplied to the GT.

Exhibit 3-2 Typical ASU Process Schematic

Air

Air Filter

Main Air

Compressor

CWS

CWR

Cond. Steam

1st Stage

DCA

2nd Stage

DCA

Prepurifiers

Booster Air

Compressor

Turbine Air 

Booster

Regen

Heater

Steam

Cond.

Regeneration

Nitrogen

Regen. N2

Blower

Liq. Oxygen

Pump

Turbine

Cryogenic Air

Separation Unit

Single Train

GT Nitrogen

HP Oxygen

Oxygen

Compressor

GT Nitrogen

Compressor

Chiller

Air from Gas Turbine

CWS

CWR
Cost and Performance Baseline for Fossil Energy Plants

72

3.1.3

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 (H2) 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 approximately 2: 1 by the addition 

of steam to the syngas stream thus promoting a high conversion of CO. In the cases without CO2

separation and capture, CO shift convertors are not required.

Water Gas Shift Reactors

Water Gas Shift: CO + H2O ↔ CO2 + H2

The CO shift converter can be located either upstream of the AGR step (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. 

Products from the gasifier are humidified with steam or water and contain a portion of the water 

vapor necessary to meet the water-to-gas criteria at the reactor inlet. If the CO converter is 

located downstream of the AGR, then the gasifier product would first have to be cooled and the 

free water separated and treated. Then additional steam would have to be generated and reinjected into the CO converter feed to meet the required water-to-gas ratio. If the CO converter 

is located upstream of the AGR step, no additional equipment is required. This is because the 

CO converter promotes carbonyl sulfide (COS) hydrolysis without a separate catalyst bed. 

Therefore, for this study the CO converter was located upstream of the AGR unit and is referred 

to as SGS.

Process Description - The SGS consists of two paths of parallel fixed-bed reactors arranged in 

series. Two reactors in series are used in each parallel path to achieve sufficient conversion to 

meet the 90 percent CO2 capture target. In the CoP case, a third shift reactor is added to each 

path to increase the CO conversion because of the relatively high amount of CH4 present in the 

syngas. With the third reactor added, CO2 capture is 90.4 percent in the CoP case.

Cooling is provided between the series of reactors to control the exothermic temperature rise. 

The parallel set of reactors is required due to the high gas mass flow rate. In all three CO2

capture cases the heat exchanger after the first SGS reactor is used to vaporize water that is then 

used to adjust the syngas H2O:CO ratio to 2:1 on a molar basis. The heat exchanger after the 

second SGS reactor is used to raise intermediate pressure (IP) steam, which then passes through 

the reheater (RH) section of the HRSG in the GEE and CoP cases, and is used to preheat the 

syngas prior to the first SGS reactor in the Shell case. Approximately 97 percent conversion of 

the CO is achieved in the GEE and Shell cases, and about 98 percent conversion is achieved in 

the CoP case.

3.1.4

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 FG

volumes in comparable PC cases. A conceptual design for an activated, sulfur-impregnated,

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 [

Mercury Removal

13]. 
Cost and Performance Baseline for Fossil Energy Plants

73

The coal mercury content (0.15 ppm dry) and carbon bed removal efficiency (95 percent) were 

discussed previously in Section 2.4. IGCC-specific design considerations are discussed below.

Carbon Bed Location – The packed carbon bed vessels are located upstream of the sulfur 

recovery unit (SRU) and syngas enters at a temperature near 38°C (100°F). Consideration was 

given to locating the beds further upstream before the COS hydrolysis unit (in non-CO2 capture 

cases) at a temperature near 204°C (400°F). However, while the mercury removal efficiency of 

carbon has been found to be relatively insensitive to pressure variations, temperature adversely 

affects the removal efficiency [47

13

]. Eastman Chemical also operates their beds ahead of their 

SRU at a temperature of 30°C (86°F) [ ]. 

Consideration was also given to locating the beds downstream of the SRU. However, it was felt 

that removing the mercury and other contaminants before the SRU would enhance the 

performance of the SRU and increase the life of the various solvents.

Process Parameters – An empty vessel basis gas residence time of approximately 20 seconds 

was used based on Eastman Chemical’s experience [13]. 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 [47] and was selected for 

this application. 

The bed density of 30 lb/ft3 was based on the Calgon Carbon Corporation HGR-P sulfurimpregnated pelletized activated carbon [48

Carbon Replacement Time – Eastman Chemicals replaces its bed every 18 to 24 months [

]. 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.

13]. 

However, bed replacement is not because of mercury loading, but for other reasons including:

• A buildup in pressure drop

• A buildup of water in the bed

• A buildup of other contaminants

For this study a 24 month carbon replacement cycle was assumed. Under these assumptions, the 

mercury loading in the bed would build up to 0.6 - 1.1 weight percent (wt%). Mercury capacity 

of sulfur-impregnated carbon can be as high as 20 wt% [49

3.1.5

]. The mercury laden carbon is 

considered to be a hazardous waste, and the disposal cost estimate reflects this categorization.

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 is 0.0128 lb SO2/MMBtu, which requires that the total sulfur content 

of the syngas be reduced to less than 30 ppmv. This includes all sulfur species, but in particular 

the total of COS and H2S, thereby resulting in stack gas emissions of less than 4 ppmv SO2.

Acid Gas Removal (AGR) Process Selection

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 

COS Hydrolysis
Cost and Performance Baseline for Fossil Energy Plants

74

catalyst manufacturers including Haldor Topsoe and Porocel offer a catalyst that promotes the 

COS hydrolysis reaction. The non-carbon capture COS hydrolysis reactor designs are based on 

information from Porocel. In cases with CO2 capture, the SGS reactors reduce COS to H2S as 

discussed in Section 3.1.3.

The COS hydrolysis reaction is equimolar with a slightly exothermic heat of reaction. The 

reaction is represented as follows.

COS + H2O ↔ CO2 + H2S

Since the reaction is exothermic, higher conversion is achieved at lower temperatures. However, 

at lower temperatures the reaction kinetics are slower. Based on the feed gas for this evaluation, 

Porocel recommended a temperature of 177 to 204°C (350 to 400°F). Since the exit gas COS 

concentration is critical to the amount of H2S that must be removed with the AGR process, a 

retention time of 50-75 seconds was used to achieve 99.5 percent conversion of the COS. The 

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.

H2S removal generally consists of absorption by a regenerable solvent. The most commonly 

used technique is based on countercurrent contact with the solvent. Acid-gas-rich solution from 

the absorber is stripped of its acid gas in a regenerator, usually by application of heat. The 

regenerated lean solution is then cooled and recirculated to the top of the absorber, completing 

the cycle. 

Sulfur Removal

Exhibit 3-3 is a simplified diagram of the AGR process [50

There are well over 30 AGR processes in common commercial use throughout the oil, chemical, 

and natural gas industries. However, in a 2002 report by SFA Pacific a list of 42 operating and 

planned gasifiers shows that only six AGR processes are represented: Rectisol, Sulfinol, MDEA, 

Selexol, aqueous di-isoproponal (ADIP) amine, and FLEXSORB [

].

52]. These processes can be 

separated into three general types: chemical reagents, physical solvents, and hybrid solvents.
Cost and Performance Baseline for Fossil Energy Plants

75

Exhibit 3-3 Flow Diagram for a Conventional AGR Unit

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.

Chemical Solvents

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 3-4

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 LP and heated in the stripper to 

reverse the reactions and strip the acid gas. The acid-gas-lean solution leaves the bottom of the 

regenerator stripper and is cooled, pumped to the required pressure and recirculated back to the 

absorber. For some amines, a filter and a separate reclaiming section (not shown) are needed to 

remove undesirable reaction byproducts.

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
Cost and Performance Baseline for Fossil Energy Plants

76

Exhibit 3-4 Common Chemical Reagents Used in AGR Processes

Chemical Reagent Acronym Process Licensors Using the Reagent

Monoethanolamine MEA Dow, Exxon, Lurgi, Union Carbide

Diethanolamine DEA Elf, Lurgi

Diglycolamine DGA Texaco, Fluor

Triethanolamine TEA AMOCO

Diisopropanolamine DIPA Shell

Methyldiethanolamine MDEA BASF, Dow, Elf, Snamprogetti, Shell, 

Union Carbide, Coastal Chemical

Hindered amine Exxon

Potassium carbonate “hot pot” Eickmeyer, Exxon, Lurgi,

Union Carbide

Typically, the absorber temperature is 27 to 49°C (80 to 120°F) for amine processes, and the 

regeneration temperature is the boiling point of the solutions, generally 104 to 127°C (220 to 

260°F). The liquid circulation rates can vary widely, depending on the amount of acid gas being 

captured. However, the most suitable processes are those that will dissolve 2 to 10 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 (lb/gal) of liquid is typical, with 0.8 to 0.9 being a typical 

“good” value. CoP non-capture, which utilizes the chemical solvent MDEA, uses 0.88 pounds of 

steam per gallon of liquid. The steam conditions are 0.45 MPa (65 psia) and 151°C (304°F).

The major advantage of these systems is the ability to remove acid gas to low levels at low to 

moderate H2S partial pressures. 

Physical solvents 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 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.

Physical Solvents

The physical solvents are regenerated by multistage flashing to LPs. 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 AGR. 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.
Cost and Performance Baseline for Fossil Energy Plants

77

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 3-5 is a simplified flow diagram for a physical reagent type AGR process [50]. Common 

physical solvent processes, along with their licensors, are listed in Exhibit 3-6. 

Exhibit 3-5 Physical Solvent AGR Process Simplified Flow Diagram

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.

Hybrid Solvents

Sulfinol is a mixture of sulfolane (a physical solvent), diisopropanolamine (DIPA) or MDEA 

(chemical solvent), and water. DIPA is used when total AGR is specified, while MDEA 

provides for selective removal of H2S.

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
Cost and Performance Baseline for Fossil Energy Plants

78

Exhibit 3-6 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

Flexsorb PS is a mixture of a hindered amine and an organic solvent. Physically similar to 

Sulfinol, Flexsorb PS is very stable and resistant to chemical degradation. High treated-gas 

purity, with less than 50 ppmv of CO2 and 4 ppmv of H2S, can be achieved. Both Ucarsol LE701, for selective removal, and LE-702, for total AGR, are formulated to remove mercaptans 

from feed gas.

Mixed chemical and physical solvents combine the features of both systems. The mixed solvent 

allows the solution to absorb an appreciable amount of gas at HP. The amine portion is effective 

as a reagent to remove the acid gas to low levels when high purity is desired.

Mixed solvent processes generally operate at absorber temperatures similar to those of the 

amine-type chemical solvents and do not require refrigeration. They also retain some advantages 

of the lower steam requirements typical of the physical solvents. Common mixed chemical and 

physical solvent processes, along with their licensors, are listed in Exhibit 3-7. 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 3-8 shows reported equilibrium solubility data for H2S and CO2 in various representative 

solvents [50]. The solubility is expressed as scf of gas per gallon liquid per atmosphere gas 

partial pressure.

The figure illustrates the relative solubilities of CO2 and H2S in different solvents and the effects 

of temperature. More importantly, it shows an order of magnitude higher solubility of H2S over 

CO2 at a given temperature, which gives rise to the selective absorption of H2S in physical 

solvents. It also illustrates that the acid gas solubility in physical solvents increases with lower 

solvent temperatures.
Cost and Performance Baseline for Fossil Energy Plants

79

Exhibit 3-7 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 3-8 Equilibrium Solubility Data on H2S and CO2 in Various Solvents
Cost and Performance Baseline for Fossil Energy Plants

80

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.

A two-stage Selexol process is used for all IGCC CO2 capture cases in this study. A brief 

process description follows.

AGR used in CO2 Capture Cases

Untreated syngas enters the first of two absorbers where H2S is preferentially removed using 

loaded solvent from the CO2 absorber. The gas exiting the H2S absorber passes through the 

second absorber where CO2 is removed using first flash regenerated, chilled solvent followed by 

thermally regenerated solvent added near the top of the column. The treated gas exits the 

absorber and is sent either directly to the CT or is partially humidified prior to entering the CT. 

A portion of the gas can also be used for coal drying, when required.

The amount of hydrogen recovered from the syngas stream is dependent on the 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 CO2 loaded solvent exits the CO2 absorber, and a portion is sent to the H2S absorber, a 

portion is sent to a reabsorber and the remainder is sent to a series of flash drums for 

regeneration. The CO2 product stream is obtained from the three flash drums, and after flash 

regeneration the solvent is chilled and returned to the CO2 absorber.

The rich solvent exiting the H2S absorber is combined with the rich solvent from the reabsorber 

and the combined stream is heated using the lean solvent from the stripper. The hot, rich solvent 

enters the H2S concentrator and partially flashes. The remaining liquid contacts nitrogen from 

the ASU and a portion of the CO2 along with lesser amounts of H2S and COS are stripped from 

the rich solvent. The stripped gases from the H2S concentrator are sent to the reabsorber where 

the H2S and COS that were co-stripped in the concentrator are transferred to a stream of loaded 

solvent from the CO2 absorber. The clean gas from the reabsorber is combined with the clean 

gas from the H2S absorber and sent to the CT.

The solvent exiting the H2S concentrator is sent to the stripper where the absorbed gases are 

liberated by hot gases flowing up the column from the steam heated reboiler. Water in the 

overhead vapor from the stripper is condensed and returned as reflux to the stripper or exported 

as necessary to maintain the proper water content of the lean solvent. The acid gas from the 

stripper is sent to the Claus plant for further processing. The lean solvent exiting the stripper is 

first cooled by providing heat to the rich solvent, then further cooled by exchange with the 

product gas and finally chilled in the lean chiller before returning to the top of the CO2 absorber.

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 with the Shell and GEE gasifiers in various applications. Both existing E-Gas 

gasifiers use MDEA, but could in theory use any of the existing AGR technologies [

AGR/Gasifier Pairings

50]. The 

following selections were made for the AGR process in non-CO2 capture cases:
Cost and Performance Baseline for Fossil Energy Plants

81

• GEE gasifier: Selexol was chosen based on the GE gasifier operating at the highest 

pressure (815 psia versus 615 psia for CoP and Shell), which favors the physical solvent 

used in the Selexol process.

• CoP gasifier: Refrigerated MDEA was chosen because the two operating E-Gas gasifiers 

use MDEA and because CoP lists MDEA as the selected AGR process on their website

[51

• Shell gasifier: The Sulfinol process was chosen for this case because it is a Shell owned 

technology. While the Shell gasifier can and has been used with other AGR processes, it 

was concluded the most likely pairing would be with the Sulfinol process.

]. Refrigerated MDEA was chosen over conventional MDEA because the sulfur 

emissions environmental target chosen is just outside of the range of conventional (higher 

temperature) MDEA.

The two-stage Selexol process is used in all three cases that require CO2 capture. According to 

the previously referenced SFA Pacific report, “For future IGCC with CO2 removal for 

sequestration, a two-stage Selexol process presently appears to be the preferred AGR process –

as indicated by ongoing engineering studies at EPRI and various engineering firms with IGCC 

interests.”[52]

3.1.6

Currently, most of the world’s sulfur is produced from the acid gases coming from gas treating. 

The Claus process remains the mainstay for sulfur recovery. Conventional three-stage Claus 

plants, with indirect reheat and feeds with a high H2S content, can approach 98 percent sulfur 

recovery efficiency. However, since environmental regulations have become more stringent, 

sulfur recovery plants are required to recover sulfur with over 99.8 percent efficiency. To meet 

these stricter regulations, the Claus process underwent various modifications and add-ons.

Sulfur Recovery/Tail Gas Cleanup Process Selection

The add-on modification to the Claus plant selected for this study can be considered a separate 

option from the Claus process. In this context, it is often called a tail gas treating unit (TGTU) 

process.

The Claus process converts H2S to elemental sulfur via the following reactions:

The Claus Process

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 3-9

[52]. One-third of the H2S is burned in the furnace with oxygen from the air to give sufficient 

SO2 to react with the remaining H2S. Since these reactions are highly exothermic, a waste heat

boiler that recovers this heat to generate 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, 
Cost and Performance Baseline for Fossil Energy Plants

82

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.

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

Exhibit 3-9 Typical Three-Stage Claus Sulfur Plant

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.

Large diluent streams in the feed to the Claus plant, such as N2 from combustion air, or a high 

CO2 content in the feed gas, lead to higher cost Claus processes and any add-on or tail gas units. 

Oxygen-Blown Claus
Cost and Performance Baseline for Fossil Energy Plants

83

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 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.

In many refinery and other conventional Claus applications, tail gas treating involves the 

removal of the remaining sulfur compounds from gases exiting the SRU. Tail gas from a typical 

Claus process, whether a conventional Claus or one of the extended versions of the process, 

usually contains small but varying quantities of COS, CS2, H2S, SO2, and elemental sulfur 

vapors. In addition, there may be H2, CO, and CO2 in the tail gas. In order to remove the rest of 

the sulfur compounds from the tail gas, all of the sulfur-bearing species must first be converted 

to H2S. Then, the resulting H2S is absorbed into a solvent and the clean gas vented or recycled 

for further processing. The clean gas resulting from the hydrolysis step can undergo further 

cleanup in a dedicated absorption unit or be integrated with an upstream AGR unit. The latter 

option is particularly suitable with physical absorption solvents. The approach of treating the tail 

gas in a dedicated amine absorption unit and recycling the resulting acid gas to the Claus plant is 

the one used by the Shell Claus Off-gas Treating (SCOT) process. With tail gas treatment, Claus 

plants can achieve overall removal efficiencies in excess of 99.9 percent.

Tail Gas Treating

In the case of IGCC applications, the tail gas from the Claus plant can be catalytically 

hydrogenated and then recycled back into the system with the choice of location being 

technology dependent, or it can be treated with a SCOT-type process. In the each of the six 

IGCC cases the Claus plant tail gas is hydrogenated, water is separated, the tail gas is 

compressed and then returned to the AGR process for further treatment.

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 six 

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.

Flare Stack
Cost and Performance Baseline for Fossil Energy Plants

84

3.1.7

The slag handling system conveys, stores, and disposes of slag removed from the gasification 

process. Spent material drains from the gasifier bed into a water bath in the bottom of the 

gasifier vessel. A slag crusher receives slag from the water bath and grinds the material into peasized fragments. A slag/water slurry that is between 5 and 10 percent solids leaves the gasifier 

pressure boundary through either a proprietary pressure letdown device (CoP) or through the use 

of lockhoppers (GEE and Shell) to a series of dewatering bins.

Slag Handling

The general aspects of slag handling are the same for all three technologies. The slag is 

dewatered, the water is clarified and recycled and the dried slag is transferred to a storage area 

for disposal. The specifics of slag handling vary among the gasification technologies regarding 

how the water is separated and the end uses of the water recycle streams.

In this 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 transit the unloading 

station underneath the hopper and remove a quantity of slag for disposal. Approximately ten 

truckloads per day are required to remove the total quantity of slag produced by the plant 

operating at nominal rated power. While the slag is suitable for use as a component of road 

paving mixtures, it was assumed in this study that the slag would be landfilled at a specified cost 

just as the ash from the PC boiler cases is assumed to be landfilled at the same per ton cost.

3.1.8 Power Island

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 

vane (IGV). The turbine includes advanced bucket cooling techniques, compressor aerodynamic 

design and advanced alloys, enabling a higher firing temperature than the previous generation 

machines. The standard production version of this machine is fired with natural gas and is also 

commercially offered for use with IGCC derived syngas, although only earlier versions of the 

turbine are currently operating on syngas. For the purposes of this study, it was assumed that the 

advanced F Class turbine will be commercially available for use on both conventional and high 

hydrogen content syngas representative of the cases with CO2 capture. High H2 fuel combustion 

issues like flame stability, flashback, and NOx formation were assumed to be solved in the time 

frame needed to support deployment. However, because these are FOAK applications, process 

contingencies were included in the cost estimates as described in Section 2.7. Performance 

typical of an advanced F class turbine on natural gas at ISO conditions is presented in 

Combustion Turbine 

Exhibit 3-10. 
Cost and Performance Baseline for Fossil Energy Plants

85

Exhibit 3-10 Advanced F Class Combustion Turbine Performance

Characteristics Using Natural Gas

Advanced F Class

Firing Temperature Class, °C (°F) 1371+ (2500+)

Airflow, kg/s (lb/s) 431 (950)

Pressure Ratio 18.5

NOx Emissions, ppmv 25

Simple Cycle Output, MW 185

Combined cycle performance

Net Output, MW 280

Net Efficiency (LHV), % 57.5

Net Heat Rate (LHV), kJ/kWh 

(Btu/kWh) 6,256 (5,934)

In this service, with syngas from an IGCC plant, the machine requires some modifications to the 

burner and turbine nozzles in order to properly combust the low-Btu gas and expand the 

combustion products in the turbine section of the machine.

The modifications to the machine include some redesign of the original can-annular combustors. 

A second modification involves increasing the nozzle areas of the turbine to accommodate the 

mass and volume flow of low-Btu fuel gas combustion products, which are increased relative to 

those produced when firing natural gas. Other modifications include rearranging the various 

auxiliary skids that support the machine to accommodate the spatial requirements of the plant 

general arrangement. The generator is a standard hydrogen-cooled machine with static exciter.

The CT is typically supplied in several fully shop-fabricated modules, complete with all 

mechanical, electrical, and control systems as required for CT operation. Site CT installation 

involves module inter-connection, and linking CT modules to the plant systems. 

Combustion Turbine Package Scope of Supply

A GT when fired on LCV syngas has the potential to increase power output due to the increase in 

flow rate through the turbine. The higher turbine flow and moisture content of the combustion 

products can contribute to overheating of turbine components, affect rating criteria for the parts 

lives, and require a reduction in syngas firing temperatures (compared to the natural gas firing) to 

maintain design metal temperature [

CT Firing Temperature Control Issue for Low Calorific Value Fuel

53]. Uncontrolled syngas firing temperature could result in 

more than 50 percent life cycle reduction of stage 1 buckets. Control systems for syngas 

applications include provisions to compensate for these effects by maintaining virtually constant 

generation output for the range of the specified ambient conditions. IGVs and firing temperature 

are used to maintain the turbine output at the maximum torque rating, producing a flat rating up 

to the IGV full open position. Beyond the IGV full open position, flat output may be extended to 

higher ambient air temperatures by steam/nitrogen injection.
Cost and Performance Baseline for Fossil Energy Plants

86

In this study the firing temperature (defined as inlet rotor temperature) using natural gas in 

NGCC applications is 1371°C (2500°F) while the firing temperature in the non-capture IGCC 

cases is 1333-1343°C (2432-2449°F) and in the CO2 capture cases is 1317-1322°C (2402-

2412°F). The further reduction in firing temperature in the CO2 capture cases is done to 

maintain parts life as the H2O content of the combustion products increases from 6-9 vol% in the 

non-capture cases to 12-14 vol% in the capture cases. The decrease in temperature also results in 

the lower temperature steam cycle in the CO2 capture cases, ranging from 12.4 

MPa/534°C/534°C (1800 psig/993°F/993°F) to 12.4 MPa/534°C/534°C (1800 

psig/994°F/994°F) for all of the CO2 capture cases versus 12.4 MPa/559°C/559°C (1800 

psig/1038°F/1038°F) to 12.4 MPa/562°C/562°C (1800 psig/1043°F/1043°F) for all of the nonCO2 capture cases.

Typical fuel specifications and contaminant levels for successful CT operation are provided in 

reference [

Combustion Turbine Syngas Fuel Requirements 

54] and presented for F Class machines in Exhibit 3-11 and Exhibit 3-12. The vast 

majority of published CT performance information is specific to natural gas operation. Turbine 

performance using syngas requires vendor input as was obtained for this study.

Exhibit 3-11 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 [55

2. To ensure that the fuel gas supply to the GT 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 [

]

54]. 

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 one percent by volume do not significantly affect 

oxidation/corrosion rates. 
Cost and Performance Baseline for Fossil Energy Plants

87

Inlet air is compressed in a single spool compressor to a pressure ratio of approximately 16:1. 

This pressure ratio was vendor specified and less than the 18.5:1 ratio used in natural gas 

applications. The majority of compressor discharge air remains on-board the machine and passes 

to the burner section to support combustion of the syngas. Compressed air is also used in burner, 

transition, and film cooling services. About 4-7 percent of the compressor air is extracted and 

integrated with the air supply of the ASU in non-carbon capture cases. It may be technically 

possible to integrate the CT and ASU in CO2 capture cases as well; however, in this study 

integration was considered only for non-carbon capture cases.

Normal Operation

Exhibit 3-12 Allowable Gas Fuel Contaminant Level for F-Class Machines

Turbine 

Inlet Limit, 

ppbw

Fuel Limit, ppmw

Turbine Inlet Flow/Fuel Flow

50 12 4

Lead 20 1.0 0.240 .080

Vanadium 10 0.5 0.120 0.040

Calcium 40 2.0 0.480 0.160

Magnesium 40 2.0 0.480 0.160

Sodium + Potassium

Na/K = 28 (1) 20 1.0 0.240 0.080

Na/K = 3 10 0.5 0.120 0.40

Na/K ≤ 1 6 0.3 0.072 0.024

Particulates Total (2) 600 30 7.2 2.4

Above 10 microns 6 0.3 0.072 0.024

Notes:

1. Na/K=28 is nominal sea salt ratio

2. The fuel gas delivery system shall be designed to prevent generation or admittance of 

solid particulate to the GT gas fuel system

Pressurized syngas is combusted in several (14) parallel diffusion combustors and syngas 

dilution is used to limit NOx formation. As described in Section 3.1.2 nitrogen from the ASU is 

used as the primary diluent followed by syngas humidification and finally by steam dilution, if 

necessary, to achieve an LHV of 4.4-4.7 MJ/Nm3 (119-125 Btu/scf). The advantages of using 

nitrogen as the primary diluent include:
Cost and Performance Baseline for Fossil Energy Plants

88

• 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.

There are some disadvantages to using nitrogen as the primary diluent, and these include:

• There is a significant auxiliary power requirement to further compress the large nitrogen 

flow from the ASU pressures of 0.4 and 1.3 MPa (56 and 182 psia) to the CT pressure of 

3.2 MPa (465 psia).

• Low quality heat not otherwise useful for other applications can be used to preheat water 

for the syngas humidification process.

• Nitrogen is not as efficient as water in limiting NOx emissions

It is not clear that one dilution method provides a significant advantage over the other. However, 

in this study nitrogen was chosen as the primary diluent based on suggestions by turbine industry 

experts during peer review of the report.

Hot combustion products are expanded in the three-stage turbine-expander. Given the assumed 

ambient conditions, back-end loss, and HRSG pressure drop, the CT exhaust temperature is 

nominally 588°C (1090°F) for non-CO2 capture cases and 562°C (1044°F) for capture cases. 

Gross turbine power, as measured prior to the generator terminals, is 232 MW. The CT 

generator is a standard hydrogen-cooled machine with static exciter.

3.1.9 Steam Generation Island

The HRSG is a horizontal gas flow, drum-type, multi-pressure design that is matched to the 

characteristics of the GT exhaust gas when firing medium-Btu gas. High-temperature FG exiting 

the CT is conveyed through the HRSG to recover the large quantity of thermal energy that 

remains. Flue gas (FG) travels through the HRSG gas path and exits at 132°C (270°F) for all six 

IGCC cases.

Heat Recovery Steam Generator 

The HP drum produces steam at main steam pressure, while the IP drum produces process steam 

and turbine dilution steam, if required. The HRSG drum pressures are nominally 12.4/3.1 MPa 

(1800/443 psia) for the HP/IP turbine sections, respectively. In addition to generating and 

superheating steam, the HRSG performs reheat duty for the cold/hot reheat steam for the steam 

turbine, provides condensate and feedwater (FW) heating, and also provides deaeration of the 

condensate.

Natural circulation of steam is accomplished in the HRSG by utilizing differences in densities 

due to temperature differences of the steam. The natural circulation HRSG provides the most 

cost-effective and reliable design.

The HRSG drums include moisture separators, internal baffles, and piping for FW/steam. All 

tubes, including economizers, superheaters, and headers and drums, are equipped with drains.

Safety relief valves are furnished in order to comply with appropriate codes and ensure a safe 

work place.
Cost and Performance Baseline for Fossil Energy Plants

89

Superheater, boiler, and economizer sections are supported by shop-assembled structural steel. 

Inlet and outlet duct is provided to route the gases from the GT 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.

The steam turbine consists of an HP section, an IP section, and one double-flow LP section, all 

connected to the generator by a common shaft. The HP and IP sections are contained in a singlespan, opposed-flow casing, with the double-flow LP section in a separate casing. The LP turbine 

has a last stage bucket length of 76 cm (30 in).

Steam Turbine Generator and Auxiliaries

Main steam from the HRSG and gasifier island is combined in a header, and then passes through 

the stop valves and control valves and enters the turbine at either 12.4 MPa/559°C to 562°C 

(1800 psig/1038°F to 1043°F) for the non-carbon capture cases, or 12.4 MPa/534°C (1800 

psig/993°F to 994°F) for the carbon capture cases. The steam initially enters the turbine near the 

middle of the HP span, flows through the turbine, and returns to the HRSG for reheating. The 

reheat steam flows through the reheat stop valves and intercept valves and enters the IP section at 

3.1 MPa/558°C to 561°C (443 psig/1036°F to 1041°F) for the non-carbon capture cases or 3.1

MPa/532°C to 533°C (443 psig/990°F to 992°F) for the carbon capture cases. After passing 

through the IP section, the steam enters a crossover pipe, which transports the steam to the LP 

section. The steam divides into two paths and flows through the LP sections, exhausting 

downward into the condenser.

Turbine bearings are lubricated by a closed-loop (CL), water-cooled, pressurized oil system. The 

oil is contained in a reservoir located below the turbine floor. During startup or unit trip an 

emergency oil pump mounted on the reservoir pumps the oil. When the turbine reaches 

95 percent of synchronous speed, the main pump mounted on the turbine shaft pumps oil. The 

oil flows through water-cooled heat exchangers prior to entering the bearings. The oil then flows 

through the bearings and returns by gravity to the lube oil reservoir.

Turbine shafts are sealed against air in-leakage or steam blowout using a modern positive 

pressure variable clearance shaft sealing design arrangement connected to 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 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 for Fossil Energy Plants

90

algorithms, color cathode ray tube (CRT) operator interfacing, and datalink interfaces to the 

balance-of-plant DCS, and incorporates on-line repair capability.

The condensate system transfers condensate from the condenser hotwell to the deaerator, through 

the gland steam condenser, gasifier, and the low-temperature economizer section in the HRSG. 

The system consists of one main condenser; two 50 percent capacity, motor-driven, vertical 

condensate pumps; one gland steam condenser; and a low-temperature tube bundle in the HRSG. 

Condensate is delivered to a common discharge header through separate pump discharge lines, 

each with a check valve and a gate valve. A common minimum flow recirculation line 

discharging to the condenser is provided to maintain minimum flow requirements for the gland 

steam condenser and the condensate pumps. 

Condensate System

The function of the FW system is to pump the various FW streams from the deaerator storage 

tank in the HRSG to the respective steam drums. Two 50 percent capacity boiler feed pumps are 

provided for each of 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. 

Feedwater System

The FW pumps are supplied with instrumentation to monitor and alarm on low oil pressure, or 

high bearing temperature. FW pump suction pressure and temperature are also monitored. In 

addition, the suction of each boiler feed pump is equipped with a startup strainer.

The function of the main steam system is to convey main steam generated in the synthesis gas 

cooler (SGC) and HRSG from the HRSG superheater outlet to the HP turbine stop valves. The 

function of the reheat system is to convey steam from the HP turbine exhaust to the HRSG RH, 

and to the turbine reheat stop valves.

Main and Reheat Steam Systems

Main steam at approximately 12.4 MPa/559°C to 562°C (1800 psig/1038°F to 1043°F) (nonCO2 capture cases) or 12.4 MPa/534°C (1800 psig/993°F to 994°F) (CO2 capture cases) exits the 

HRSG superheater through a motor-operated stop/check valve and a motor-operated gate valve, 

and is routed to the HP turbine. Cold reheat steam at approximately 3.5 MPa/349°C to 372°C

(501 psia/661°F to 702°F) exits the HP turbine, flows through a motor-operated isolation gate 

valve, to the HRSG reheater. Hot reheat steam at approximately 3.1 MPa/558 to 561°C (443 

psig/1036°F to 1041°F) for the non-carbon capture cases and 3.1 MPa/532°C to 533°C (443 

psig/990°F to 992°F) for the CO2 capture cases exits the HRSG RH through a motor-operated 

gate valve and is routed to the IP turbines.

Steam piping is sloped from the HRSG to the drip pots located near the steam turbine for 

removal of condensate from the steam lines. Condensate collected in the drip pots and in lowpoint drains is discharged to the condenser through the drain system.

Steam flow is measured by means of flow nozzles in the steam piping. The flow nozzles are 

located upstream of any branch connections on the main headers.
Cost and Performance Baseline for Fossil Energy Plants

91

Safety valves are installed to comply with appropriate codes and to ensure the safety of 

personnel and equipment.

The circulating water system (CWS) is a closed-cycle cooling water system that supplies cooling 

water to the condenser to condense the main turbine exhaust steam. The system also supplies 

cooling water to the AGR plant as required, and to the auxiliary cooling system. The auxiliary 

cooling system is a CL process that utilizes a higher quality water to remove heat from 

compressor intercoolers, oil coolers and other ancillary equipment and transfers that heat to the 

main circulating cooling water system in plate and frame heat exchangers. The heat transferred 

to the circulating water in the condenser and other applications is removed by a mechanical draft 

cooling tower.

Circulating Water System

The system consists of two 50 percent capacity vertical CWPs, a mechanical draft evaporative 

cooling tower, and CS cement-lined interconnecting piping. The pumps are single-stage vertical 

pumps. The piping system is equipped with butterfly isolation valves and all required expansion 

joints. The cooling tower is a multi-cell wood frame counterflow mechanical draft cooling 

tower.

The condenser is a single-pass, horizontal type with divided water boxes. There are two separate 

circulating water circuits in each box. One-half of the condenser can be removed from service 

for cleaning or for plugging tubes. This can be done during normal operation at reduced load.

The condenser is equipped with an air extraction system to evacuate the condenser steam space 

for removal of non-condensable gases during steam turbine operation and to rapidly reduce the 

condenser pressure from atmospheric pressure before unit startup and admission of steam to the 

condenser.

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.

Raw Water, Fire Protection, and Cycle Makeup Water Systems

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, each with a full-capacity activated 

carbon filter, primary cation exchanger, primary anion exchanger, mixed bed exchanger, recycle 

pump, and regeneration equipment. The equipment is skid-mounted and includes a control panel 

and associated piping, valves, and instrumentation.
Cost and Performance Baseline for Fossil Energy Plants

92

3.1.10

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.

Accessory Electric Plant

3.1.11

An integrated plant-wide distributed control system (DCS) is provided. The DCS is a redundant 

microprocessor-based, functionally DCS. The control room houses an array of multiple video 

monitor (CRT) and keyboard units. The CRT/keyboard units are the primary interface between 

the generating process and operations personnel. The DCS incorporates plant monitoring and 

control functions for all the major plant equipment. The DCS is designed to be operational and 

accessible 99.5 percent of the time it is required (99.5 percent availability). The plant equipment 

and the DCS are designed for automatic response to load changes from minimum load to 

100 percent. Startup and shutdown routines are manually implemented, with operator selection 

of modular automation routines available. The exception to this, and an important facet of the 

control system for gasification, is the critical controller system, which is a part of the license 

package from the gasifier supplier and is a dedicated and distinct hardware segment of the DCS.

Instrumentation and Control

This critical controller system is used to control the gasification process. The partial oxidation of 

the fuel feed and oxygen feed streams to form a syngas product is a stoichiometric, temperatureand pressure-dependent reaction. The critical controller utilizes a redundant microprocessor 

executing calculations and dynamic controls at 100- to 200-millisecond intervals. The enhanced 

execution speeds as well as evolved predictive controls allow the critical controller to mitigate 

process upsets and maintain the reactor operation within a stable set of operating parameters.
Cost and Performance Baseline for Fossil Energy Plants

93

3.2 GENERAL ELECTRIC ENERGY IGCC CASES

This section contains an evaluation of plant designs for Cases 1 and 2, which are based on the 

GEE gasifier in the “radiant only” configuration. GEE offers three design configurations:[56

• Quench: In this configuration, the hot syngas exiting the gasifier passes through a pool of 

water to quench the temperature to 289°C (550°F) before entering the syngas scrubber. It 

is the simplest and lowest capital cost design, but also the least efficient. This 

configuration is examined in Section 

]

8.

• Radiant Only: In this configuration, the hot syngas exiting the gasifier passes through a 

radiant syngas cooler where it is cooled from about 1316°C (2400°F) to 677°C (1250°F), 

then through a water quench where the syngas is further cooled to about 232°C (450°F) 

prior to entering the syngas scrubber. Relative to the quench configuration, the radiant 

only design offers increased output, higher efficiency, improved reliability/availability, 

and results in the lowest COE. This configuration was chosen by GEE and Bechtel for 

the design of their reference plant.

• Radiant-Convective: In this configuration, the hot syngas exiting the gasifier passes 

through a radiant syngas cooler where it is cooled from about 1316°C (2400°F) to 760°C 

(1400°F), then passes over a pool of water where particulate is removed but the syngas is 

not quenched, then through a convective syngas cooler where the syngas is further cooled 

to about 371°C (700°F) prior to entering additional heat exchangers or the scrubber. This 

configuration has the highest overall efficiency, but at the expense of highest capital cost 

and the lowest availability. This is the configuration used at Tampa Electric’s Polk 

Power Station.

Note that the radiant only configuration includes a water quench and, based on functionality, 

would be more appropriately named radiant-quench. The term radiant only is used to distinguish 

it from the radiant-convective configuration. Since radiant only is the terminology used by GEE, 

it will be used throughout this report.

The balance of Section 3.2 is organized as follows:

• Gasifier Background provides information on the development and status of the GEE 

gasification technology.

• Process and System Description provides an overview of the technology operation as 

applied to Case 1. The systems that are common to all gasifiers were covered in Section 

3.1 and only features that are unique to Case 1 are discussed further in this section.

• Key Assumptions is a summary of study and modeling assumptions relevant to Cases 1 

and 2.

• Sparing Philosophy is provided for both Cases 1 and 2.

• Performance Results provides the main modeling results from Case 1, including the 

performance summary, environmental performance, carbon balance, sulfur balance, water 

balance, mass and energy balance diagrams, and mass and energy balance tables.

• Equipment List provides an itemized list of major equipment for Case 1 with account 

codes that correspond to the cost accounts in the Cost Estimates section.
Cost and Performance Baseline for Fossil Energy Plants

94

• Cost Estimates provides a summary of capital and operating costs for Case 1.

• Process and System Description, Performance Results, Equipment List and Cost 

Estimates are repeated for Case 2.

3.2.1

Development and Current Status[

Gasifier Background

57

The oil price increases and supply disruptions of the 1970s renewed interest in the Texaco 

partial-oxidation process for gasification of coal or other solid opportunity fuels. Three 14 

tonne/day (15 TPD) pilot plants at the Montebello laboratories have been used to test numerous 

coals. Two larger pilot plants were also built. The first gasified 150 tonne/day (165 TPD) of 

coal and was built to test syngas generation by Rührchemie and Rührkohle at Oberhausen, 

Germany, and included a SGC. The second gasified 172 tonne/day (190 TPD) of coal using a 

quench-only gasifier cooler and was built to make hydrogen at an existing TVA ammonia plant 

at Muscle Shoals, Alabama. These two large-scale pilot plants successfully operated for several 

years during the 1980s and tested a number of process variables and numerous coals.

] – Initial development of the GEE gasification 

technology (formerly licensed by Texaco and then ChevronTexaco) was conducted in the 1940s 

at Texaco’s Montebello, California laboratories. From 1946 to 1954 the Montebello pilot plant 

produced syngas (hydrogen and carbon monoxide) by partial oxidation of a variety of feedstocks, 

including natural gas, oil, asphalt, coal tar, and coal. From 1956 to 1958, coal was gasified in a 

91 tonne/day (100 TPD) Texaco coal gasifier at the Olin Mathieson Chemical Plant in 

Morgantown, West Virginia, for the production of ammonia.

The first commercial Texaco coal gasification plant was built for Tennessee Eastman at 

Kingsport, Tennessee, and started up in 1983. To date, 24 gasifiers have been built in 12 plants 

for coal and petroleum coke. Several of the plants require a hydrogen-rich gas and therefore 

directly water quench the raw gas to add the water for shifting the CO to H2, and have no SGCs.

The Cool Water plant was the first commercial-scale Texaco coal gasification project for the 

electric utility industry. This facility gasified 907 tonne/day (1,000 TPD) (dry basis) of 

bituminous coal and generated 120 MW of electricity by IGCC operation. In addition, the plant 

was the first commercial-sized Texaco gasifier used with a SGC. The Cool Water plant operated 

from 1984 to 1989 and was a success in terms of operability, availability, and environmental 

performance. 

The Tampa Electric IGCC Clean Coal Technology Demonstration Project built on the Cool 

Water experience to demonstrate the use of the Texaco coal gasification process in an IGCC 

plant. The plant utilizes approximately 2,268 tonne/day (2,500 TPD) of coal in a single Texaco 

gasifier to generate a net of approximately 250 megawatts electric (MWe). The syngas is cooled 

in a high-temperature radiant heat exchanger, generating HP steam, and further cooled in 

convective heat exchangers (the radiant-convective configuration). The particles in the cooled 

gas are removed in a water-based scrubber. The cleaned gas then enters a hydrolysis reactor 

where COS is converted to H2S. After additional cooling, the syngas is sent to a conventional 

AGR unit, where H2S is absorbed by reaction with an amine solvent. H2S is removed from the 

amine by steam stripping and sent to a sulfuric acid (H2SO4) plant. The cleaned gas is sent to a 

General Electric MS 7001FA CT. 
Cost and Performance Baseline for Fossil Energy Plants

95

The Delaware Clean Energy Project is a coke gasification and CT repowering of an existing 

130 MW coke-fired boiler cogeneration power plant at the Motiva oil refinery in Delaware City, 

Delaware. The Texaco coal gasification process was modified to gasify 1,814 tonne/day 

(2,000 TPD) of this low-quality petroleum coke. The plant is designed to use all the fluid 

petroleum coke generated at Motiva’s Delaware City Plant and produce a nominal 238,136 kg/hr

(525,000 lb/hr) of 8.6 MPa (1250 psig) steam, and 120,656 kg/hr (266,000 lb/hr) of 1.2 MPa 

(175 psig) steam for export to the refinery and the use/sale of 120 MW of electrical power. 

Environmentally, these new facilities help satisfy tighter NOx and SO2 emission limitations at 

the Delaware City Plant.

Gasifier Capacity – The largest GEE gasifier is the unit at Tampa Electric, which consists of the 

radiant-convective configuration. The daily coal-handling capacity of this unit is 2,268 tonnes 

(2,500 tons) of bituminous coal. The dry gas production rate is 0.19 million Nm3

/hr (6.7 million 

scfh) with an energy content of about 1,897 million kJ/hr (HHV) (1,800 million Btu/hr). This 

size matches the F Class CTs that are used at Tampa.

Distinguishing Characteristics – A key advantage of the GEE coal gasification technology is 

the extensive operating experience at full commercial scale. Furthermore, Tampa Electric is an 

IGCC power generation facility, operated by conventional electric utility staff, and is 

environmentally one of the cleanest coal-fired power plants in the world. The GEE gasifier also 

operates at the highest pressure of the three gasifiers in this study, 5.6 MPa (815 psia) compared 

to 4.2 MPa (615 psia) for CoP and Shell.

Entrained-flow gasifiers have fundamental environmental advantages over fluidized-bed and 

moving-bed gasifiers. They produce no hydrocarbon liquids, and the only solid waste is an inert 

slag. The relatively high H2/CO ratio and CO2 content of GEE gasification fuel gas helps 

achieve low NOx and CO emissions in even the higher-temperature advanced CTs.

The key disadvantages of the GEE coal gasification technology are the limited refractory life, the 

relatively high oxygen requirements and high waste heat recovery duty (SGC design). As with 

the other entrained-flow slagging gasifiers, the GEE process has this disadvantage due to its high 

operating temperature. The disadvantage is magnified in the single-stage, slurry feed design. 

The quench design significantly reduces the capital cost of syngas cooling, while innovative heat 

integration maintains good overall thermal efficiency although lower than the SGC design. 

Another disadvantage of the GEE process is the limited ability to economically handle low-rank 

coals relative to moving-bed and fluidized-bed gasifiers or to entrained-flow gasifiers with dry 

feed. For slurry fed entrained gasifiers using low-rank coals, developers of two-stage slurry fed 

gasifiers claim advantages over single-stage slurry fed.

Important Coal Characteristics – The slurry feeding system and the recycle of process 

condensate water as the principal slurrying liquid make low levels of ash and soluble salts 

desirable coal characteristics for use in the GEE coal gasification process. High ash levels 

increase the ratio of water-to-carbon in the feed slurry, thereby increasing the oxygen 

requirements. The slurry feeding also favors the use of high-rank coals, such as bituminous coal, 

since their low inherent moisture content increases the moisture-free solids content of the slurry 

and thereby reduces oxygen requirements. 
Cost and Performance Baseline for Fossil Energy Plants

96

3.2.2

In this section the overall GEE gasification process is described. The system description follows 

the block flow diagram (BFD) in 

Process Description

Exhibit 3-13 and stream numbers reference the same exhibit. 

The tables in Exhibit 3-14 provide stream compositions, temperature, pressure, enthalpy, and 

flow rates for the numbered streams in the BFD.

Coal receiving and handling is common to all cases and was covered in Section 

Coal Grinding and Slurry Preparation

3.1.1. The 

receiving and handling subsystem ends at the coal silo. Coal is then fed onto a conveyor by 

vibratory feeders located below each silo. The conveyor feeds the coal to an inclined conveyor 

that delivers the coal to the rod mill feed hopper. The feed hopper provides a surge capacity of 

about two hours and contains two hopper outlets. Each hopper outlet discharges onto a weigh 

feeder, which in turn feeds a rod mill. Each rod mill is sized to process 55 percent of the coal 

feed requirements of the gasifier. The rod mill grinds the coal and wets it with treated slurry 

water transferred from the slurry water tank by the slurry water pumps. The coal slurry is 

discharged through a trommel screen into the rod mill discharge tank, and then the slurry is 

pumped to the slurry storage tanks. The dry solids concentration of the final slurry is 63 percent. 

The Polk Power Station operates at a slurry concentration of 62-68 percent using bituminous coal 

and CoP presented a paper showing the slurry concentration of Illinois No. 6 coal as 63 percent

[58

The coal grinding system is equipped with a dust suppression system consisting of water sprays 

aided by a wetting agent. The degree of dust suppression required depends on local 

environmental regulations. All of the tanks are equipped with vertical agitators to keep the coal 

slurry solids suspended.

].

The equipment in the coal grinding and slurry preparation system is fabricated of materials 

appropriate for the abrasive environment present in the system. The tanks and agitators are 

rubber lined. The pumps are either rubber-lined or hardened metal to minimize erosion. Piping 

is fabricated of high-density polyethylene (HDPE).

This plant utilizes two gasification trains to process a total of 5,083 tonnes/day (5,603 TPD) of 

Illinois No. 6 coal. Each of the 2 x 50 percent gasifiers operates at maximum capacity. The 

largest operating GEE gasifier is the 2,268 tonne/day (2,500 TPD) unit at Polk Power Station. 

However, that unit operates at about 2.8 MPa (400 psia). The gasifier in this study, which 

operates at 5.6 MPa (815 psia), will be able to process more coal and maintain the same gas 

residence time.

Gasification

The slurry feed pump takes suction from the slurry run tank, and the discharge is sent to the feed 

injector of the GEE gasifier (stream 6). Oxygen from the ASU is vented during preparation for 

startup and is sent to the feed injector during normal operation. The air separation plant supplies 

4,171 tonnes/day (4,597 TPD) of 95 mol% oxygen to the gasifiers (stream 5) and the Claus plant 

(stream 3). Carbon conversion in the gasifier is assumed to be 98 percent including a fines 

recycle stream.
Cost and Performance Baseline for Fossil Energy Plants

97

The gasifier vessel is a refractory-lined, HP combustion chamber. The coal slurry feedstock and 

oxygen are fed through a fuel injector at the top of the gasifier vessel. The coal slurry and the 

oxygen react in the gasifier at 5.6 MPa (815 psia) and 1,316°C (2,400°F) to produce syngas.

The syngas consists primarily of hydrogen and carbon monoxide, with lesser amounts of water 

vapor and carbon dioxide, and small amounts of hydrogen sulfide, COS, methane, argon, and 

nitrogen. The heat in the gasifier liquefies coal ash. Hot syngas and molten solids from the 

reactor flow downward into a radiant heat exchanger where the syngas is cooled.

Syngas is cooled from 1,316°C (2,400°F) to 677°C (1,250°F) in the radiant SGC (stream 9) and 

the molten slag solidifies in the process. The solids collect in the water sump at the bottom of 

the gasifier and are removed periodically using a lock hopper system (stream 8). The waste heat 

from this cooling is used to generate HP steam. BFW in the tubes is saturated, and then steam 

and water are separated in a steam drum. Approximately 412,096 kg/hr (908,500 lb/hr) of 

saturated steam at 13.8 MPa (2,000 psia) is produced. This steam then forms part of the general 

heat recovery system that provides steam to the steam turbine.

Raw Gas Cooling/Particulate Removal

The syngas exiting the radiant cooler is directed downwards by a dip tube into a water sump. 

Most of the entrained solids are separated from the syngas at the bottom of the dip tube as the 

syngas goes upwards through the water. The syngas exits the quench chamber saturated at a 

temperature of 232°C (450°F).

The slag handling system removes solids from the gasification process equipment. These solids 

consist of a small amount of unconverted carbon and essentially all of the ash contained in the 

feed coal. These solids are in the form of glass, which fully encapsulates any metals. Solids 

collected in the water sump below the radiant SGC are removed by gravity and forced circulation 

of water from the lock hopper circulating pump. The fine solids not removed from the bottom of 

the quench water sump remain entrained in the water circulating through the quench chamber. In 

order to limit the amount of solids recycled to the quench chamber, a continuous blowdown 

stream is removed from the bottom of the syngas quench. The blowdown is sent to the vacuum 

flash drum in the black water flash section. The circulating quench water is pumped by 

circulating pumps to the quench gasifier.

Syngas exiting the water quench passes to a syngas scrubber where a water wash is used to 

remove remaining chlorides, NH3, SO2, and PM. The syngas exits the scrubber still saturated at 

206°C (403°F) before it is preheated to 223°C (433°F) (stream 10) prior to entering the COS 

hydrolysis reactor.

Syngas Scrubber/Sour Water Stripper

The sour water stripper removes NH3, SO2, and other impurities from the scrubber and other 

waste streams. The stripper consists of a sour drum that accumulates sour water from the gas 

scrubber and condensate from SGCs. Sour water from the drum flows to the sour stripper, which 

consists of a packed column with a steam-heated reboiler. Sour gas is stripped from the liquid 

and sent to the SRU. Remaining water is sent to wastewater treatment.
Cost and Performance Baseline for Fossil Energy Plants

98

Exhibit 3-13 Case 1 Block Flow Diagram, GEE IGCC without CO2 Capture
Cost and Performance Baseline for Fossil Energy Plants

99

Exhibit 3-14 Case 1 Stream Table, GEE IGCC without CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12

V-L Mole Fraction

Ar 0.0092 0.0233 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0068 0.0099

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0012 0.0009 0.0009 0.0013

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3579 0.2825 0.2825 0.4151

CO2 0.0003 0.0081 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1366 0.1078 0.1079 0.1586

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3416 0.2696 0.2696 0.3961

H2O 0.0099 0.2081 0.0000 0.0003 0.0000 0.0000 0.9994 0.0000 0.1358 0.3181 0.3180 0.0012

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0002 0.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0059 0.0085

N2 0.7732 0.5621 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0080 0.0063 0.0063 0.0092

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0021 0.0020 0.0020 0.0000

O2 0.2074 0.1985 0.9504 0.0054 0.9504 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

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 21,872 1,067 102 19,380 5,298 0 4,829 0 22,212 28,142 28,142 19,153

V-L Flowrate (kg/hr) 631,164 28,941 3,290 543,810 170,485 0 87,000 0 446,032 552,597 552,597 390,595

Solids Flowrate (kg/hr) 0 0 0 0 0 211,783 0 23,236 0 0 0 0

Temperature (°C) 15 20 32 93 32 15 146 1,316 677 223 223 35

Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.48 5.41 5.24

Enthalpy (kJ/kg)A 30.23 36.80 26.67 92.52 26.67 --- 558.58 --- 1,424.13 1,066.74 1,066.63 40.35

Density (kg/m3

) 1.2 1.6 11.0 24.4 11.0 --- 866.9 --- 13.9 26.7 26.3 41.9

V-L Molecular Weight 28.857 27.132 32.181 28.060 32.181 --- 18.015 --- 20.081 19.636 19.636 20.393

V-L Flowrate (lbmol/hr) 48,220 2,352 225 42,726 11,680 0 10,647 0 48,969 62,043 62,043 42,226

V-L Flowrate (lb/hr) 1,391,479 63,803 7,253 1,198,895 375,855 0 191,803 0 983,333 1,218,267 1,218,267 861,115

Solids Flowrate (lb/hr) 0 0 0 0 0 466,901 0 51,227 0 0 0 0

Temperature (°F) 59 68 90 199 90 59 295 2,400 1,250 433 433 95

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 795.0 785.0 760.0

Enthalpy (Btu/lb)A 13.0 15.8 11.5 39.8 11.5 --- 240.1 --- 612.3 458.6 458.6 17.3

Density (lb/ft3) 0.076 0.098 0.687 1.521 0.687 --- 54.120 --- 0.870 1.665 1.643 2.617

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Fossil Energy Plants

100

Exhibit 3-14 Case 1 Stream Table, GEE IGCC without CO2 Capture (Continued)

13 14 15 16 17 18 19 20 21 22 23 24

V-L Mole Fraction

Ar 0.0097 0.0000 0.0000 0.0040 0.0100 0.0100 0.0100 0.0092 0.0092 0.0089 0.0089 0.0000

CH4 0.0013 0.0000 0.0000 0.0000 0.0013 0.0013 0.0013 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.3977 0.0002 0.0000 0.0021 0.4089 0.4089 0.4089 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.1811 0.6124 0.0000 0.6947 0.1562 0.1562 0.1562 0.0003 0.0003 0.0807 0.0807 0.0000

COS 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.3812 0.0000 0.0000 0.0415 0.3920 0.3920 0.3920 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0012 0.0128 0.0000 0.0018 0.0006 0.0006 0.0006 0.0099 0.0099 0.0638 0.0638 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2S 0.0086 0.1817 0.0000 0.0111 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0191 0.1905 0.0000 0.2448 0.0309 0.0309 0.0309 0.7732 0.7732 0.7427 0.7427 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0023 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.2074 0.1039 0.1039 0.0000

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

Total 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 19,992 951 0 839 19,445 19,445 19,445 110,253 4,410 136,882 136,882 35,596

V-L Flowrate (kg/hr) 422,592 36,883 0 31,997 397,047 397,047 397,047 3,181,557 127,262 3,995,152 3,995,152 641,276

Solids Flowrate (kg/hr) 0 0 5,307 0 0 0 0 0 0 0 0 0

Temperature (°C) 35 45 174 38 45 241 196 15 432 589 132 561

Pressure (MPa, abs) 5.21 5.2 0.409 5.512 5.171 5.136 3.172 0.101 1.619 0.105 0.105 12.512

Enthalpy (kJ/kg)A 36.92 -1.2 --- -5.039 54.553 365.190 296.114 30.227 463.785 741.466 235.132 3,502.816

Density (kg/m3

) 43.4 95.0 5,288.2 97.7 40.0 24.1 16.4 1.2 7.9 0.4 0.9 35.1

V-L Molecular Weight 21.138 39 --- 38.145 20.419 20.419 20.419 28.857 28.857 29.187 29.187 18.015

V-L Flowrate (lbmol/hr) 44,075 2,096 0 1,849 42,870 42,870 42,870 243,066 9,723 301,773 301,773 78,476

V-L Flowrate (lb/hr) 931,655 81,313 0 70,540 875,339 875,339 875,339 7,014,133 280,565 8,807,803 8,807,803 1,413,772

Solids Flowrate (lb/hr) 0 0 11,699 0 0 0 0 0 0 0 0 0

Temperature (°F) 94 112 345 100 112 465 386 59 810 1,093 270 1,043

Pressure (psia) 755.0 750.0 59.3 799.5 750.0 745.0 460.0 14.7 234.9 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 15.9 -0.5 --- -2.2 23.5 157.0 127.3 13.0 199.4 318.8 101.1 1,505.9

Density (lb/ft3) 2.712 6 330.129 6.098 2.499 1.508 1.026 0.076 0.495 0.027 0.057 2.191
Cost and Performance Baseline for Fossil Energy Plants

101

Syngas exiting the scrubber (stream 10) passes through a COS hydrolysis reactor where about 

99.5 percent of the COS is converted to CO2 and H2S (Section 

COS Hydrolysis, Mercury Removal and Acid Gas Removal

3.1.5). The gas exiting the COS 

reactor (stream 11) passes through a series of heat exchangers and knockout (KO) drums to 

lower the syngas temperature to 35°C (95°F) and to separate entrained water. The cooled syngas 

(stream 12) then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.4).

Cool, particulate-free syngas (stream 13) enters the Selexol absorber unit at approximately 

5.2 MPa (755 psia) and 34°C (94°F). In this absorber, H2S is preferentially removed from the 

fuel gas stream along with smaller amounts of CO2, COS and other gases such as hydrogen. The 

rich solution leaving the bottom of the absorber is heated against the lean solvent returning from 

the regenerator before entering the H2S concentrator. A portion of the non-sulfur bearing

absorbed gases is driven from the solvent in the H2S concentrator using N2 from the ASU as the 

stripping medium. The temperature of the H2S concentrator overhead stream is reduced prior to 

entering the reabsorber where a second stage of H2S absorption occurs. The rich solvent from 

the reabsorber is combined with the rich solvent from the absorber and sent to the stripper where 

it is regenerated through the indirect application of thermal energy via condensation of LP steam 

in a reboiler. The stripper acid gas stream (stream 14), consisting of 18 percent H2S and 

61 percent CO2 (with the balance mostly N2), is then sent to the Claus unit.

Acid gas from the first-stage stripper of the Selexol unit is routed to the Claus plant. The Claus 

plant partially oxidizes the H2S in the acid gas to elemental sulfur. About 5,307 kg/hr (11,699

lb/hr) of elemental sulfur (stream 15) are recovered from the fuel gas stream. This value 

represents an overall sulfur recovery efficiency of 99.6 percent.

Claus Unit

Acid gas from the Selexol unit is preheated to 232°C (450°F). A portion of the acid gas along 

with all of the sour gas from the stripper and oxygen from the ASU are fed to the Claus furnace. 

In the furnace, H2S is catalytically oxidized to SO2 at a furnace temperature greater than 1,343°C 

(2,450°F), which must be maintained in order to thermally decompose all of the NH3 present in 

the sour gas stream.

Following the thermal stage and condensation of sulfur, two reheater and two sulfur converters 

are used to obtain a per-pass H2S conversion of approximately 99.9 percent. The Claus Plant tail 

gas is hydrogenated and recycled back to the Selexol process (stream 16). In the furnace waste 

heat boiler, 12,432 kg/hr (27,408 lb/hr) of 4.2 MPa (605 psia) steam are generated. This steam is 

used to satisfy all Claus process preheating and reheating requirements as well as to produce 

some steam for the medium-pressure steam header. The sulfur condensers produce 0.34 MPa 

(50 psig) and steam for the LP steam header and 2.9 MPa (415 psig) for IP steam.

Clean syngas exiting the Selexol absorber is re-heated (stream 18) using HP BFW and then 

expanded to 3.2 MPa (460 psia) using an expansion turbine (stream 19). The syngas stream is 

diluted with nitrogen from the ASU (stream 4) and enters the advanced F Class CT burner. The 

CT compressor provides combustion air to the burner and also 17 percent of the air requirements 

in the ASU (stream 21). The exhaust gas exits the CT at 589°C (1,093°F) (stream 22) and enters 

the HRSG where additional heat is recovered until the FG exits the HRSG at 132°C (270°F) 

(stream 23) and is discharged through the plant stack. The steam raised in the HRSG is used to 

Power Block
Cost and Performance Baseline for Fossil Energy Plants

102

power an advanced, commercially available steam turbine using a 12.4 MPa/562°C/562°C (1800 

psig/1043°F/1043°F) steam cycle.

The elevated pressure ASU was described in Section 

Air Separation Unit

3.1.2. In Case 1 the ASU is designed to 

produce a nominal output of 4,171 tonnes/day (4,597 TPD) of 95 mol% O2 for use in the gasifier 

(stream 5) and Claus plant (stream 3). The plant is designed with two production trains. The air 

compressor is powered by an electric motor. Approximately 13,051 tonnes/day (14,387 TPD) of 

nitrogen are also recovered, compressed, and used for dilution in the GT combustor (stream 4). 

About 4 percent of the GT air is used to supply approximately 17 percent of the ASU air 

requirements (stream 21).

Balance of plant items were covered in Sections 

Balance of Plant

3.1.9, 3.1.10, and 3.1.11.
Cost and Performance Baseline for Fossil Energy Plants

103

3.2.3

System assumptions for Cases 1 and 2, GEE IGCC with and without CO2 capture, are presented 

in 

Key System Assumptions

Exhibit 3-15.

Exhibit 3-15 GEE IGCC Plant Study Configuration Matrix

Case 1 2

Gasifier Pressure, MPa (psia) 5.6 (815) 5.6 (815)

O2:Coal Ratio, kg O2/kg dry coal 0.91 0.91

Carbon Conversion, % 98 98

Syngas HHV at Gasifier Outlet, 

kJ/Nm3 (Btu/scf) 8,663 (233) 8,644 (232)

Steam Cycle, MPa/°C/°C 

(psig/°F/°F)

12.4/562/562

(1800/1043/1043)

12.4/534/534

(1800/994/994)

Condenser Pressure, mm Hg 

(in Hg) 51 (2.0) 51 (2.0)

Combustion Turbine 2x Advanced F Class

(232 MW output each)

2x Advanced F Class

(232 MW output each)

Gasifier Technology GEE Radiant Only GEE Radiant Only

Oxidant 95 vol% Oxygen 95 vol% Oxygen

Coal Illinois No. 6 Illinois No. 6

Coal Slurry Solids Content, % 63 63

COS Hydrolysis Yes Occurs in SGS

Sour Gas Shift No Yes

H2S Separation Selexol Selexol 1st Stage

Sulfur Removal, % 99.7 99.9

Sulfur Recovery

Claus Plant with Tail Gas 

Recycle to Selexol/ 

Elemental Sulfur

Claus Plant with Tail Gas 

Recycle to Selexol/ 

Elemental Sulfur

Particulate Control Water Quench, Scrubber, 

and AGR Absorber

Water Quench, Scrubber, 

and AGR Absorber

Mercury Control Carbon Bed Carbon Bed

NOx Control

Multi Nozzle Quiet 

Combustor (MNQC)

(LNB) and N2 Dilution

MNQC (LNB) and N2

Dilution

CO2 Separation N/A Selexol 2nd Stage

Overall CO2 Capture N/A 90.3%

CO2 Sequestration N/A Off-site Saline Formation
Cost and Performance Baseline for Fossil Energy Plants

104

The balance of plant assumptions are common to all cases and are presented in 

Balance of Plant – Cases 1 and 2

Exhibit 3-16.

Exhibit 3-16 Balance of Plant Assumptions

Cooling system Recirculating Wet Cooling Tower

Fuel and Other storage

Coal 30 days

Slag 30 days

Sulfur 30 days

Sorbent 30 days

Plant Distribution Voltage

Motors below 1 hp 110/220 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 Gas Turbine 

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.
Cost and Performance Baseline for Fossil Energy Plants

105

3.2.4

The sparing philosophy for Cases 1 and 2 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.

Sparing Philosophy

The plant design consists of the following major subsystems:

• Two ASUs (2 x 50%)

• Two trains of slurry preparation and slurry pumps (2 x 50%)

• Two trains of gasification, including gasifier, SGC, quench and scrubber (2 x 50%). 

• Two trains of syngas clean-up process (2 x 50%).

• Two trains of Selexol AGR, single-stage in Case 1 and two-stage in Case 2, (2 x 50%) 

and one Claus-based SRU (1 x 100%). 

• Two CT/HRSG tandems (2 x 50%).

• One steam turbine (1 x 100%).

3.2.5

The plant produces a net output of 622 MWe at a net plant efficiency of 39.0 percent (HHV 

basis). GEE has reported a net plant efficiency of 38.5 percent for their reference plant, and they 

also presented a range of efficiencies of 38.5-40 percent depending on fuel type [

Case 1 Performance Results

59,60

Overall performance for the plant is summarized in 

]. 

Typically the higher efficiencies result from fuel blends that include petroleum coke.

Exhibit 3-17, which includes auxiliary power 

requirements. The ASU accounts for approximately 78 percent of the auxiliary load between the 

main air compressor, the nitrogen compressor, the oxygen compressor and ASU auxiliaries. The 

cooling water system, including the CWPs and the cooling tower fan, account for approximately 

5 percent of the auxiliary load, and the BFW pumps account for an additional 3 percent. All 

other individual auxiliary loads are less than 3 percent of the total.
Cost and Performance Baseline for Fossil Energy Plants

106

Exhibit 3-17 Case 1 Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Gas Turbine Power 464,000

Sweet Gas Expander Power 7,500

Steam Turbine Power 276,300

TOTAL POWER, kWe 747,800

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 460

Coal Milling 2,180

Sour Water Recycle Slurry Pump 180

Slag Handling 1,120

Air Separation Unit Auxiliaries 1,000

Air Separation Unit Main Air Compressor 53,820

Oxygen Compressor 10,260

Nitrogen Compressors 33,340

Boiler Feedwater Pumps 3,980

Condensate Pump 230

Quench Water Pump 520

Circulating Water Pump 4,200

Ground Water Pumps 430

Cooling Tower Fans 2,170

Scrubber Pumps 220

Acid Gas Removal 2,590

Gas Turbine Auxiliaries 1,000

Steam Turbine Auxiliaries 100

Claus Plant/TGTU Auxiliaries 250

Claus Plant TG Recycle Compressor 2,090

Miscellaneous Balance of Plant2 3,000

Transformer Losses 2,610

TOTAL AUXILIARIES, kWe 125,750

NET POWER, kWe 622,050

Net Plant Efficiency, % (HHV) 39.0

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,238 (8,756)

CONDENSER COOLING DUTY 106 kJ/hr (106 Btu/hr) 1,540 (1,460)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 211,783 (466,901)

Thermal Input1, kWt 1,596,320

Raw Water Withdrawal, m3/min (gpm) 17.9 (4,735)

Raw Water Consumption, m3/min (gpm) 14.2 (3,755)

1 - HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)

2 - Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Fossil Energy Plants

107

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 

2.4. A summary of the plant air emissions for Case 1 is presented in

Environmental Performance

Exhibit 3-18.

Exhibit 3-18 Case 1 Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) @

80% capacity factor

kg/MWh

(lb/MWh)

SO2 0.001 (0.001) 21 (24) 0.004 (.01)

NOx 0.025 (0.059) 1,023 (1,128) 0.195 (.430)

Particulates 0.003 (0.0071) 123 (136) 0.023 (.052)

Hg 2.46E-7 

(5.71E-7) 0.010 (0.011) 1.89E-6 (4.16E-6)

CO2 84.6 (196.8) 3,407,901 

(3,756,568) 650 (1,434)

CO2

1 782 (1,723) 1 CO2 emissions based on net power instead of gross power

The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the Selexol 

AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel 

gas down to a level of less than 30 ppmv. This results in a concentration in the FG of less than 

4 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, producing 

elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H2S 

and then recycled back to the Selexol process, thereby eliminating the need for a tail gas 

treatment unit.

NOx emissions are limited by nitrogen dilution of the syngas to 15 ppmvd (as NO2 @15 percent 

O2). Ammonia in the syngas is removed with process condensate prior to the low-temperature 

AGR process and ultimately destroyed in the Claus plant burner. This helps lower NOx levels as 

well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of the 

syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

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 plant is shown in Exhibit 3-19. The carbon input to the plant consists 

of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since 

the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned 

carbon in the slag and as CO2 in the stack gas and ASU vent gas.
Cost and Performance Baseline for Fossil Energy Plants

108

Exhibit 3-19 Case 1 Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 135,000 (297,625) Slag 2,700 (5,952)

Air (CO2) 519 (1,143) Stack Gas 132,716 (292,588)

ASU Vent 103 (227)

CO2 Product 0 (0)

Total 135,519 (298,768) Total 135,519 (298,768)

Exhibit 3-20 shows the sulfur balances for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur emitted in the 

stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 3-20 Case 1 Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 5,308 (11,702) Elemental Sulfur 5,307 (11,699)

Stack Gas 2 (3)

CO2 Product 0 (0)

Total 5,308 (11,702) Total 5,308 (11,702)

Exhibit 3-21 shows the overall water balance for the plant. Water demand represents the total 

amount of water required for a particular process. Some water is recovered within the process, 

primarily as syngas condensate, and is re-used as internal recycle. The difference between 

demand and recycle is raw water withdrawal. Raw water withdrawal is defined as the water 

removed from the ground or diverted from a surface-water source for use in the plant and was 

assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water 

withdrawal can be represented by the water metered from a raw water source and used in the 

plant processes for any and all purposes, such as cooling tower makeup, BFW makeup, quench 

system makeup, and slag handling makeup. The difference between water withdrawal and 

process water discharge is defined as water consumption and can be represented by the portion 

of the raw water withdrawn that is evaporated, transpired, incorporated into products or 

otherwise not returned to the water source from which it was withdrawn. Water consumption 

represents the net impact of the plant process on the water source balance.
Cost and Performance Baseline for Fossil Energy Plants

109

Exhibit 3-21 Case 1 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)

Slag Handling 0.50 (133) 0.50 (133) 0.0 (0) 0.0 (0) 0.0 (0)

Slurry Water 1.45 (384) 1.45 (384) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.7 (726) 0.90 (237) 1.9 (489) 0.0 (0) 1.9 (489)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (8) -0.03 (-8)

Condenser Makeup

Gasifier Steam

Shift Steam

GT Steam Dilution

BFW Makeup

0.2 (54)

0.20 (54)

0.0 (0) 0.2 (54)

0.20 (54)

0.0 (0) 0.2 (54)

Cooling Tower

BFW Blowdown

SWS Blowdown

SWS Excess Water

Humidifier Tower 

Blowdown

16.4 (4,321) 0.49 (129)

0.20 (54)

0.29 (75)

15.9 (4,192)

-0.20 (-54)

-0.29 (-75)

3.7 (972) 12.2 (3,220)

Total 21.3 (5,618) 3.34 (883) 17.9 (4,735) 3.7 (979) 14.2 (3,755)

Heat and mass balance diagrams are shown for the following subsystems in 

Heat and Mass Balance Diagrams

Exhibit 3-22 through

Exhibit 3-24:

• Coal gasification and ASU

• Syngas cleanup, sulfur recovery and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is provided in tabular form in Exhibit 3-25. The power out is 

the combined CT, steam turbine and expander power prior to generator losses. The power at the 

generator terminals (shown in Exhibit 3-17) is calculated by multiplying the power out by a 

combined generator efficiency of 98.2 percent.
Cost and Performance Baseline for Fossil Energy Plants

110

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

111

Exhibit 3-22 Case 1 Coal Gasification and Air Separation Units Heat and Mass Balance Schematic

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 1

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 1

GEE GASIFIER

ASU AND GASIFICATION

DWG. NO.

BB-HMB-CS-1-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

1 OF 3

Ambient Air

Four Stage Air

Compressor

Elevated

Pressure

ASU

Four Stage N2

Compressor

Four Stage O2

Compressor

ASU 

Vent

Water

Steam

Gross Plant Power: 748 MWe

Auxiliary Load: 126 MWe

Net Plant Power: 622 MWe

Net Plant Efficiency, HHV: 39.0%

Net Plant Heat Rate: 8,756 BTU/KWe

N2 to GT Combustor

1,391,479 W

59.0 T

14.7 P

13.0 H

375,855 W

90.0 T

125.0 P

11.5 H

375,855 W

241.2 T

940.0 P

40.8 H

To Claus Plant

7,253 W

90.0 T

125.0 P

11.5 H

63,803 W

68.2 T

16.4 P

15.8 H

1,073,296 W

90.0 T

56.4 P

14.2 H

150,595 W

50.0 T

182.0 P

2.9 H

5

1

3

2

Slurry Mix 

Tank

Milled Coal

Slag

466,901 W

59.0 T

14.7 P

191,803 W

295.0 T

840.0 P

240.1 H

51,227 W

2,400.0 T

815.0 P

1,198,895 W

389.0 T

384.0 P

88.2 H

658,704 W

159.7 T

840.0 P

2,933.2 H

100.0 T

189.5 P

18.0 H

6

Air From GT

Compressor

280,565 W

220.0 T

224.9 P

50.9 H

280,565 W

809.8 T

234.9 P

199.4 H

1,198,895 W

199.0 T

384.0 P

39.8 H

21

HP BFW

N2 to AGR

N2 Boost

Compressor

24,996 W

199.0 T

384.0 P

39.8 H

24,996 W

376.3 T

785.0 P

84.2 H

Saturated Steam

To HRSG HP

Superheater

GE Energy 

Gasifier

Radiant

Syngas

Cooler

Black

Water

Flash

Tank

Knockout

Drum

Vent To Claus Unit

Raw Fuel Gas

CWS

CWR

Fines

Process Water

From Sour Water Stripper Syngas 

Scrubber

Slag Quench 

Section

Drag 

Conveyor

4

983,333 W

1,250.0 T

805.0 P

612.3 H

1,218,267 W

402.9 T

800.0 P

445.7 H

Syngas

Quench

1,346,417 W

450.0 T

805.0 P

535.7 H

8

9

Sour Water

7
Cost and Performance Baseline for Fossil Energy Plants

112

Exhibit 3-23 Case 1 Syngas Cleanup Heat and Mass Balance Schematic

Mercury 

Removal

Knock

Out 

Drum

Syngas

Preheater

Sour

Drum

Process Condensate to Syngas Scrubber

Makeup Water

Claus Plant

Tail 

Gas

Furnace

Catalytic

Reactor

Beds

Sulfur

Knock Out

From 

ASU

Syngas

Coolers

Sour

Stripper

1,218,267 W

402.9 T

800.0 P

457.9 H

931,655 W

94.2 T

755.0 P

15.9 H

81,313 W

112.2 T

750.0 P

875,339 W

385.6 T

460.0 P

127.3 H

11,699 W

79,721 W

450.0 T

58.9 P

249.7 H

2,855 W

234.5 T

65.0 P

405.2 H

7,253 W

90.0 T

125.0 P

11.5 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 1

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 1

GEE GASIFIER

GAS CLEANUP SYSTEM

DWG. NO.

BB-HMB-CS-1-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

2 OF 3

Sour Gas

Sour Water

Water

Steam

Gross Plant Power: 748 MWe

Auxiliary Load: 126 MWe

Net Plant Power: 622 MWe

Net Plant Efficiency, HHV: 39.0%

Net Plant Heat Rate: 8,756 BTU/KWe

15

12

16

CO2

Tailgas

71,392 W

120.0 T

56.8 P

32.0 H

861,115 W

95.3 T

760.0 P

17.3 H

9,181 W

118.2 T

56.8 P

44.4 H

3

70,540 W

100.0 T

799.5 P

Raw Syngas

17 875,339 W

112.2 T

750.0 P

23.5 H

Claus Oxygen

Preheater

7,253 W

450.0 T

124.5 P

91.9 H

COS Hydrolysis 1,218,267 W

432.7 T

785.0 P

458.6 H

COS Hydrolysis

Preheater

1,218,267 W

432.9 T

795.0 P

458.6 H

10 11

Clean Gas Acid Gas

13

AGR- Selexol

14

Fuel Gas

Expander

Fuel Gas To GT

19

875,339 W

465.0 T

745.0 P

157.0 H

18

N2 to AGR

24,996 W

376.3 T

785.0 P

84.2 H

Hydrogenation 

and Tail Gas 

Cooling

Tail Gas Recycle 

Compressor
Cost and Performance Baseline for Fossil Energy Plants

113

Exhibit 3-24 Case 1 Combined-Cycle Power Generation Heat and Mass Balance Schematic

HRSG

HP

Turbine

IP

Turbine

Nitrogen Diluent

Intake

Ambient Air

Steam Seal 

Regulator

Ip Extraction Steam

To 250 PSIA Header

LP Process Header

Blowdown

Flash

To WWT

Gland

Steam

Condenser

Condensate to Gasification Island

HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP 

Turbine

Stack

Compressor Expander

Fuel Gas

Deaerator

IP BFW

Generator

Generator

Condensate

Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class 

Gas Turbine

MP Flash Bottoms

LP Flash Tops

1,198,895 W

385.0 T

389.0 P

87.2 H

7,014,133 W

59.0 T

14.7 P

13.0 H

1,581,185 W

101.1 T

1.0 P

69.1 H

8,807,803 W

269.7 T

15.2 P

101.1 H

875,339 W

385.6 T

460.0 P

127.3 H

8,807,803 W

1,092.7 T

15.2 P

318.8 H From Gasifier

Island Preheating

To Claus

LP BFW

1,413,772 W

1,042.7 T

1,814.7 P

1,505.9 H

9,644 W

298.0 T

65.0 P

1,179.0 H

1,440,764 W

278.8 T

2,250.7 P

252.3 H

26,992 W

585.0 T

2,000.7 P

593.3 H

1,542,260 W

512.1 T

65.0 P

1,288.0 H

1,581,185 W

103.2 T

120.0 P

71.4 H

1,581,185 W

235.0 T

105.0 P

203.7 H

1,400 W

661.9 T

65.0 P

1,361.9 H

1,400 W

212.0 T

14.7 P

179.9 H

IP Pump NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 1

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 1

GEE GASIFIER

POWER BLOCK SYSTEM

DWG. NO.

BB-HMB-CS-1-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

Gross Plant Power: 748 MWe

Auxiliary Load: 126 MWe

Net Plant Power: 622 MWe

Net Plant Efficiency, HHV: 39.0%

20 Net Plant Heat Rate: 8,756 BTU/KWe

22

24

19

23

Flue Gas

HOT WELL

CONDENSER Make-up

27,011 W

59.0 T

14.7 P

27.1 H

8,822 W

701.7 T

501.4 P

1,358.0 H

9,515 W

661.9 T

65.0 P

1,361.9 H

35,544 W

897.8 T

280.0 P

1,472.7 H

780 W

1,042.7 T

1,814.7 P

1,505.9 H

1,312 W

540.7 T

65.0 P

1,302.1 H

Air Extraction

280,565 W

809.8 T

234.9 P

199.4 H

21
Cost and Performance Baseline for Fossil Energy Plants

114

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

115

Exhibit 3-25 Case 1 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,747 (5,447) 4.8 (4.6) 5,752 (5,451)

ASU Air 19.1 (18.1) 19 (18)

CT Air 96.2 (91.2) 96 (91)

Water 67.4 (63.9) 67 (64)

Auxiliary Power 453 (429) 453 (429)

TOTAL 5,747 (5,447) 187.4 (177.7) 453 (429) 6,387 (6,054)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 1.1 (1.0) 1 (1)

Slag 89 (84) 36.3 (34.4) 125 (118)

Sulfur 49 (47) 0.6 (0.6) 50 (47)

CO2

Cooling Tower 

Blowdown 27.3 (25.9) 27 (26)

HRSG Flue Gas 939 (890) 939 (890)

Condenser 1,536 (1,456) 1,536 (1,456)

Non-Condenser 

Cooling Tower 

Loads*

422 (400) 422 (400)

Process Losses** 594 (563) 594 (563)

Power 2,692 (2,552) 2,692 (2,552)

TOTAL 138 (131) 3,557 (3,372) 2,692 (2,552) 6,387 (6,054)

* Includes ASU compressor intercoolers, CO2 compressor intercoolers, sour water stripper condenser, syngas 

cooler (low level heat rejection) and extraction air cooler.

** Calculated by difference to close the energy balance.
Cost and Performance Baseline for Fossil Energy Plants

116

3.2.6

Major equipment items for the GEE gasifier with no CO2 capture are shown in the following 

tables. The accounts used in the equipment list correspond to the account numbers used in the 

cost estimates in Section 

Case 1 - Major Equipment List

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.

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 45 tonne (50 ton) 2 1

9 Feeder Vibratory 172 tonne/hr (190 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 354 tonne/hr (390 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 172 tonne (190 ton) 2 0

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0) 2 0

14 As-Fired Coal Sampling 

System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 354 tonne/hr (390 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 354 tonne/hr (390 tph) 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 816 tonne (900 ton) 3 0
Cost and Performance Baseline for Fossil Energy Plants

117

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 82 tonne/h (90 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 236 tonne/h (260 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 1 0

4 Weigh Feeder Belt 118 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 118 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank 

with Agitator Field erected 287,504 liters (75,950 gal) 2 0

7 Slurry Water Pumps Centrifugal 795 lpm (210 gpm) 2 1

8 Trommel Screen Coarse 163 tonne/h (180 tph) 2 0

9 Rod Mill Discharge Tank with 

Agitator Field erected 376,122 liters (99,360 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,028 lpm (800 gpm) 2 2

11 Slurry Storage Tank with 

Agitator Field erected 1,128,440 liters (298,100 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,435 lpm (1,700 gpm) 2 2

13 Slurry Product Pumps Positive 

displacement 3,028 lpm (800 gpm) 2 2
Cost and Performance Baseline for Fossil Energy Plants

118

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 1,082,628 liters (286,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,624 lpm @ 91 m H2O

(1,750 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 493,508 kg/hr (1,088,000 lb/hr) 2 0

4 Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

8,366 lpm @ 27 m H2O

(2,210 gpm @ 90 ft H2O) 2 1

5 High Pressure 

Feedwater Pump No. 1

Barrel type, multi-stage, 

centrifugal

HP water: 6,246 lpm @ 1,859 m 

H2O (1,650 gpm @ 6,100 ft 

H2O)

2 1

6 High Pressure 

Feedwater Pump No. 2

Barrel type, multi-stage, 

centrifugal

IP water: 1,060 lpm @ 223 m 

H2O (280 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 Cylce Cooling 

Heat Exchangers Plate and frame 247 GJ/hr (234 MMBtu/hr) each 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 88,579 lpm @ 21 m H2O(23,400 gpm @ 70 ft H2O) 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

4,618 lpm @ 18 m H2O

(1,220 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single 

suction

3,066 lpm @ 268 m H2O 

(810 gpm @ 880 ft H2O) 3 1

16 Filtered Water Pumps Stainless steel, single 

suction

2,082 lpm @ 49 m H2O

(550 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,003,134 liter (265,000 gal) 2 0

18 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 303 lpm (80 gpm) 2 0

19 Liquid Waste Treatment 

System 10 years, 24-hour storm 1 0
Cost and Performance Baseline for Fossil Energy Plants

119

ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW 

TEMPERATURE HEAT RECOVERY

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized slurry-feed, 

entrained bed

2,812 tonne/day, 5.6 MPa

(3,100 tpd, 815 psia) 2 0

2 Synthesis Gas Cooler

Vertical downflow 

radiant heat exchanger 

with outlet quench 

chamber

245,393 kg/hr (541,000 lb/hr) 2 0

3

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 336,112 kg/hr (741,000 lb/hr) 2 0

4 Raw Gas Coolers Shell and tube with 

condensate drain 215,910 kg/hr (476,000 lb/hr) 8 0

5 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator

215,456 kg/hr, 35°C, 5.3 MPa

(475,000 lb/hr, 95°F, 765 psia) 2 0

6 Flare Stack

Self-supporting, carbon 

steel, stainless steel top, 

pilot ignition

336,112 kg/hr (741,000 lb/hr) 

syngas

2 0

7

ASU Main Air 

Compressor Centrifugal, multi-stage 4,757 m3/min @ 1.3 MPa(168,000 scfm @ 190 psia) 2 0

8 Cold Box Vendor design 2,268 tonne/day (2,500 tpd) of 

95% purity oxygen 2 0

9 Oxygen Compressor Centrifugal, multi-stage

1,161 m3/min (41,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 psia)

2 0

10 Primary Nitrogen 

Compressor Centrifugal, multi-stage

3,766 m3/min (133,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 0

11 Secondary Nitrogen 

Compressor Centrifugal, single-stage

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 0

12 Syngas Dilution Nitrogen 

Boost Compressor Centrifugal, single-stage

0 m3/min (0 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 psia)

2 0

13 AGR Nitrogen Boost 

Compressor Centrifugal, single-stage

85 m3/min (3,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 5.4 MPa (790 psia)

2 0

14 Extraction Air Heat 

Exchanger

Gas-to-gas, vendor 

design

69,853 kg/hr, 432°C, 1.6 MPa

(154,000 lb/hr, 810°F, 235 psia) 2 0
Cost and Performance Baseline for Fossil Energy Plants

120

ACCOUNT 5A SYNGAS CLEANUP

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

ACCOUNT 7 HRSG, DUCTING, AND STACK

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon 

bed

215,003 kg/hr (474,000 lb/hr) 

35°C (95°F) 

5.2 MPa (760 psia)

2 0

2 Sulfur Plant Claus type 140 tonne/day (154 tpd) 1 0

3 COS Hydrolysis Reactor Fixed bed, 

catalytic

303,907 kg/hr (670,000 lb/hr)

221°C (430°F)

5.4 MPa (790 psia)

2 0

4 Acid Gas Removal Plant Selexol

232,239 kg/hr (512,000 lb/hr)

35°C (94°F)

5.2 MPa (755 psia)

2 0

5 Hydrogenation Reactor Fixed bed, 

catalytic

36,161 kg/hr (79,721 lb/hr)

232°C (450°F)

0.4 MPa (58.9 psia)

1 0

6 Tail Gas Recycle 

Compressor Centrifugal 31,997 kg/hr (70,540 lb/hr) each 1 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gas Turbine Advanced F class 230 MW 2 0

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase 2 0

3 Syngas Expansion 

Turbine/Generator Turbo Expander

218,359 kg/h (481,400 lb/h)

5.1 MPa (745 psia) Inlet

3.2 MPa (460 psia) Outlet

2 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS 

liner

76 m (250 ft) high x

8.4 m (27 ft) diameter 1 0

2 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator

Main steam - 352,702 kg/hr, 12.4 

MPa/561°C (777,575 lb/hr, 

1,800 psig/1,043°F)

 Reheat steam - 345,710 kg/hr, 

3.1 MPa/561°C (762,160 lb/hr, 

452 psig/1,043°F)

2 0
Cost and Performance Baseline for Fossil Energy Plants

121

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

291 MW 

12.4 MPa/561°C/561°C 

(1,800 psig/ 1043°F/1043°F)

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitiation

320 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase 1 0

3 Steam Bypass One per HRSG 50% steam flow @ design 

steam conditions 2 0

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,688 GJ/hr (1,600 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 11°C 

(20°F)

1 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water 

Pumps Vertical, wet pit 420,181 lpm @ 30 m(111,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

/ 2,353 GJ/hr (2,230 MMBtu/hr) 

heat duty

1 0
Cost and Performance Baseline for Fossil Energy Plants

122

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 242,266 liters (64,000 gal) 2 0

2 Slag Crusher Roll 13 tonne/hr (14 tph) 2 0

3 Slag Depressurizer Lock Hopper 13 tonne/hr (14 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 147,631 liters (39,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 64,352 liters (17,000 gal) 2

6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 2 0

7 Slag Separation Screen Vibrating 13 tonne/hr (14 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 13 tonne/hr (14 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 208,198 liters (55,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal 

centrifugal

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 68,137 liters (18,000 gal) 2 0

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H2O

(60 gpm @ 1,850 ft H2O) 2 2

13 Slag Storage Bin Vertical, field 

erected 907 tonne (1,000 tons) 2 0

14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 1 0
Cost and Performance Baseline for Fossil Energy Plants

123

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CTG Step-up 

Transformer Oil-filled 24 kV/345 kV, 260 MVA, 

3-ph, 60 Hz 2 0

2 STG Step-up 

Transformer Oil-filled 24 kV/345 kV, 320 MVA, 3-ph, 60 Hz 1 0

3

High Voltage 

Auxiliary 

Transformer

Oil-filled 345 kV/13.8 kV, 54 MVA, 

3-ph, 60 Hz 2 0

4

Medium Voltage 

Auxiliary 

Transformer

Oil-filled 24 kV/4.16 kV, 29 MVA, 

3-ph, 60 Hz 1 1

5 Low Voltage 

Transformer Dry ventilated 4.16 kV/480 V, 4 MVA, 3-ph, 60 Hz 1 1

6

CTG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, 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

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 for Fossil Energy Plants

124

3.2.7

The cost estimating methodology was described previously in Section 2.6. 

Case 1 - Cost Estimating

Exhibit 3-26 shows 

the total plant capital cost summary organized by cost account and Exhibit 3-27 shows a more 

detailed breakdown of the capital costs, along with owner’s costs, TOC, and TASC. 

Exhibit 3-28 shows the initial and annual O&M costs.

The estimated TOC of the GEE gasifier with no CO2 capture is $2,447/kW. Process contingency 

represents 2.0 percent of the TOC and project contingency represents 10.8 percent. The COE is 

76.3 mills/kWh.
Cost and Performance Baseline for Fossil Energy Plants

125

Exhibit 3-26 Case 1 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-08

Project: Bituminous Baseline Study

Case: Case 1 - GEE Radiant 640MW IGCC w/o CO2

Plant Size: 622.1 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 $13,912 $2,585 $10,788 $0 $0 $27,285 $2,477 $0 $5,952 $35,714 $57

 2 COAL & SORBENT PREP & FEED $23,713 $4,326 $14,245 $0 $0 $42,284 $3,844 $1,535 $9,533 $57,195 $92

 3 FEEDWATER & MISC. BOP SYSTEMS $9,622 $7,783 $9,458 $0 $0 $26,863 $2,531 $0 $6,737 $36,131 $58

 4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $111,116 $0 $60,871 $0 $0 $171,987 $15,755 $23,878 $32,445 $244,065 $392

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $160,703 $0 w/equip. $0 $0 $160,703 $15,577 $0 $17,628 $193,908 $312

4.4-4.9 Other Gasification Equipment $7,664 $11,266 $12,070 $0 $0 $31,001 $3,020 $0 $7,624 $41,645 $67

SUBTOTAL 4 $279,483 $11,266 $72,942 $0 $0 $363,691 $34,352 $23,878 $57,697 $479,618 $771

 5A GAS CLEANUP & PIPING $57,957 $3,800 $55,494 $0 $0 $117,251 $11,380 $93 $25,944 $154,668 $249

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 $186

6.2-6.9 Combustion Turbine Other $5,928 $887 $1,801 $0 $0 $8,615 $816 $0 $1,721 $11,152 $18

SUBTOTAL 6 $91,679 $887 $8,070 $0 $0 $100,636 $9,540 $4,601 $12,256 $127,033 $204

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $35,357 $0 $5,027 $0 $0 $40,384 $3,840 $0 $4,422 $48,646 $78

7.2-7.9 SCR System, Ductwork and Stack $3,329 $2,373 $3,108 $0 $0 $8,810 $817 $0 $1,566 $11,193 $18

SUBTOTAL 7 $38,685 $2,373 $8,136 $0 $0 $49,194 $4,657 $0 $5,989 $59,839 $96

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $29,111 $0 $4,994 $0 $0 $34,104 $3,272 $0 $3,738 $41,114 $66

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,373 $1,001 $7,239 $0 $0 $18,613 $1,694 $0 $4,041 $24,348 $39

SUBTOTAL 8 $39,483 $1,001 $12,233 $0 $0 $52,718 $4,967 $0 $7,778 $65,462 $105

 9 COOLING WATER SYSTEM $9,649 $9,237 $7,877 $0 $0 $26,763 $2,486 $0 $5,971 $35,220 $57

10 ASH/SPENT SORBENT HANDLING SYS $14,359 $8,029 $14,555 $0 $0 $36,943 $3,559 $0 $4,363 $44,864 $72

11 ACCESSORY ELECTRIC PLANT $28,222 $10,643 $21,238 $0 $0 $60,103 $5,165 $0 $12,277 $77,546 $125

12 INSTRUMENTATION & CONTROL $10,249 $1,885 $6,603 $0 $0 $18,737 $1,698 $937 $3,561 $24,933 $40

13 IMPROVEMENTS TO SITE $3,349 $1,974 $8,263 $0 $0 $13,586 $1,341 $0 $4,478 $19,405 $31

14 BUILDINGS & STRUCTURES $0 $6,725 $7,701 $0 $0 $14,427 $1,314 $0 $2,573 $18,313 $29

 

TOTAL COST $620,363 $72,516 $257,603 $0 $0 $950,481 $89,310 $31,044 $165,109 $1,235,944 $1,987

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline for Fossil Energy Plants

126

Exhibit 3-27 Case 1 Total Plant Cost Details

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 $3,653 $0 $1,785 $0 $0 $5,439 $487 $0 $1,185 $7,111 $11

1.2 Coal Stackout & Reclaim $4,721 $0 $1,144 $0 $0 $5,865 $514 $0 $1,276 $7,655 $12

1.3 Coal Conveyors & Yd Crush $4,389 $0 $1,132 $0 $0 $5,522 $485 $0 $1,201 $7,207 $12

1.4 Other Coal Handling $1,148 $0 $262 $0 $0 $1,410 $123 $0 $307 $1,840 $3

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 $2,585 $6,464 $0 $0 $9,049 $867 $0 $1,983 $11,900 $19

SUBTOTAL 1. $13,912 $2,585 $10,788 $0 $0 $27,285 $2,477 $0 $5,952 $35,714 $57

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying w/ 2.3 $0 w/ 2.3 $0 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,558 $373 $244 $0 $0 $2,175 $186 $0 $472 $2,833 $5

2.3 Slurry Prep & Feed $21,299 $0 $9,398 $0 $0 $30,697 $2,789 $1,535 $7,004 $42,025 $68

2.4 Misc.Coal Prep & Feed $857 $623 $1,869 $0 $0 $3,349 $308 $0 $731 $4,388 $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 $3,330 $2,734 $0 $0 $6,063 $562 $0 $1,325 $7,950 $13

SUBTOTAL 2. $23,713 $4,326 $14,245 $0 $0 $42,284 $3,844 $1,535 $9,533 $57,195 $92

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,896 $4,974 $2,626 $0 $0 $10,496 $972 $0 $2,294 $13,762 $22

3.2 Water Makeup & Pretreating $620 $65 $347 $0 $0 $1,031 $98 $0 $339 $1,469 $2

3.3 Other Feedwater Subsystems $1,585 $536 $482 $0 $0 $2,602 $234 $0 $567 $3,403 $5

3.4 Service Water Systems $355 $731 $2,536 $0 $0 $3,621 $353 $0 $1,192 $5,167 $8

3.5 Other Boiler Plant Systems $1,904 $738 $1,829 $0 $0 $4,471 $424 $0 $979 $5,874 $9

3.6 FO Supply Sys & Nat Gas $315 $596 $556 $0 $0 $1,467 $141 $0 $322 $1,930 $3

3.7 Waste Treatment Equipment $867 $0 $529 $0 $0 $1,395 $136 $0 $459 $1,991 $3

3.8 Misc. Power Plant Equipment $1,080 $145 $554 $0 $0 $1,779 $172 $0 $585 $2,536 $4

SUBTOTAL 3. $9,622 $7,783 $9,458 $0 $0 $26,863 $2,531 $0 $6,737 $36,131 $58

 4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $111,116 $0 $60,871 $0 $0 $171,987 $15,755 $23,878 $32,445 $244,065 $392

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $160,703 $0 w/equip. $0 $0 $160,703 $15,577 $0 $17,628 $193,908 $312

4.4 Scrubber & Low Temperature Cooling $5,873 $4,781 $4,975 $0 $0 $15,629 $1,501 $0 $3,426 $20,556 $33

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Other Gasification Equipment $1,791 $0 $1,681 $0 $0 $3,472 $417 $0 $948 $4,837 $8

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 $6,486 $5,414 $0 $0 $11,900 $1,103 $0 $3,251 $16,253 $26

SUBTOTAL 4. $279,483 $11,266 $72,942 $0 $0 $363,691 $34,352 $23,878 $57,697 $479,618 $771
Cost and Performance Baseline for Fossil Energy Plants

127

Exhibit 3-27 Case 1 Total Plant Cost Details (Continued)

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 Single Stage Selexol $41,961 $0 $35,605 $0 $0 $77,565 $7,501 $0 $17,013 $102,080 $164

5A.2 Elemental Sulfur Plant $10,055 $2,004 $12,972 $0 $0 $25,031 $2,431 $0 $5,493 $32,955 $53

5A.3 Mercury Removal $1,057 $0 $804 $0 $0 $1,862 $180 $93 $427 $2,561 $4

5A.4 COS Hydrolysis $3,575 $0 $4,668 $0 $0 $8,243 $801 $0 $1,809 $10,853 $17

5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Blowback Gas Systems $1,310 $0 $248 $0 $0 $1,558 $190 $0 $350 $2,098 $3

5A.7 Fuel Gas Piping $0 $688 $482 $0 $0 $1,170 $108 $0 $256 $1,534 $2

5A.9 HGCU Foundations $0 $1,108 $714 $0 $0 $1,822 $167 $0 $597 $2,586 $4

SUBTOTAL 5A. $57,957 $3,800 $55,494 $0 $0 $117,251 $11,380 $93 $25,944 $154,668 $249

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $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 $186

6.2 Syngas Expander $5,928 $0 $819 $0 $0 $6,747 $641 $0 $1,108 $8,496 $14

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $887 $982 $0 $0 $1,868 $175 $0 $613 $2,656 $4

SUBTOTAL 6. $91,679 $887 $8,070 $0 $0 $100,636 $9,540 $4,601 $12,256 $127,033 $204

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $35,357 $0 $5,027 $0 $0 $40,384 $3,840 $0 $4,422 $48,646 $78

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,706 $1,217 $0 $0 $2,923 $256 $0 $636 $3,816 $6

7.4 Stack $3,329 $0 $1,250 $0 $0 $4,579 $439 $0 $502 $5,519 $9

7.9 HRSG,Duct & Stack Foundations $0 $667 $640 $0 $0 $1,307 $122 $0 $429 $1,858 $3

SUBTOTAL 7. $38,685 $2,373 $8,136 $0 $0 $49,194 $4,657 $0 $5,989 $59,839 $96

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $29,111 $0 $4,994 $0 $0 $34,104 $3,272 $0 $3,738 $41,114 $66

8.2 Turbine Plant Auxiliaries $202 $0 $463 $0 $0 $665 $65 $0 $73 $803 $1

8.3 Condenser & Auxiliaries $5,053 $0 $1,484 $0 $0 $6,537 $625 $0 $716 $7,878 $13

8.4 Steam Piping $5,117 $0 $3,600 $0 $0 $8,717 $749 $0 $2,367 $11,833 $19

8.9 TG Foundations $0 $1,001 $1,693 $0 $0 $2,694 $255 $0 $885 $3,835 $6

SUBTOTAL 8. $39,483 $1,001 $12,233 $0 $0 $52,718 $4,967 $0 $7,778 $65,462 $105
Cost and Performance Baseline for Fossil Energy Plants

128

Exhibit 3-27 Case 1 Total Plant Cost Details (Continued)

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

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $6,699 $0 $1,219 $0 $0 $7,918 $754 $0 $1,301 $9,973 $16

9.2 Circulating Water Pumps $1,737 $0 $122 $0 $0 $1,859 $157 $0 $302 $2,318 $4

9.3 Circ.Water System Auxiliaries $147 $0 $21 $0 $0 $168 $16 $0 $28 $211 $0

9.4 Circ.Water Piping $0 $6,124 $1,588 $0 $0 $7,712 $697 $0 $1,682 $10,090 $16

9.5 Make-up Water System $343 $0 $490 $0 $0 $833 $80 $0 $183 $1,096 $2

9.6 Component Cooling Water Sys $723 $865 $615 $0 $0 $2,203 $206 $0 $482 $2,891 $5

9.9 Circ.Water System Foundations $0 $2,248 $3,822 $0 $0 $6,071 $576 $0 $1,994 $8,640 $14

SUBTOTAL 9. $9,649 $9,237 $7,877 $0 $0 $26,763 $2,486 $0 $5,971 $35,220 $57

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $11,822 $6,519 $13,243 $0 $0 $31,584 $3,048 $0 $3,463 $38,095 $61

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0

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 $575 $0 $626 $0 $0 $1,201 $116 $0 $198 $1,515 $2

10.7 Ash Transport & Feed Equipment $771 $0 $186 $0 $0 $957 $89 $0 $157 $1,204 $2

10.8 Misc. Ash Handling Equipment $1,191 $1,460 $436 $0 $0 $3,087 $294 $0 $507 $3,888 $6

10.9 Ash/Spent Sorbent Foundation $0 $51 $64 $0 $0 $115 $11 $0 $38 $163 $0

SUBTOTAL 10. $14,359 $8,029 $14,555 $0 $0 $36,943 $3,559 $0 $4,363 $44,864 $72

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $958 $0 $947 $0 $0 $1,905 $182 $0 $209 $2,296 $4

11.2 Station Service Equipment $3,920 $0 $353 $0 $0 $4,273 $394 $0 $467 $5,134 $8

11.3 Switchgear & Motor Control $7,247 $0 $1,318 $0 $0 $8,565 $794 $0 $1,404 $10,763 $17

11.4 Conduit & Cable Tray $0 $3,366 $11,106 $0 $0 $14,472 $1,400 $0 $3,968 $19,840 $32

11.5 Wire & Cable $0 $6,432 $4,226 $0 $0 $10,658 $774 $0 $2,858 $14,291 $23

11.6 Protective Equipment $0 $686 $2,496 $0 $0 $3,182 $311 $0 $524 $4,017 $6

11.7 Standby Equipment $236 $0 $230 $0 $0 $466 $44 $0 $77 $587 $1

11.8 Main Power Transformers $15,862 $0 $146 $0 $0 $16,008 $1,211 $0 $2,583 $19,801 $32

11.9 Electrical Foundations $0 $158 $416 $0 $0 $574 $55 $0 $189 $818 $1

SUBTOTAL 11. $28,222 $10,643 $21,238 $0 $0 $60,103 $5,165 $0 $12,277 $77,546 $125

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

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 $1,012 $0 $676 $0 $0 $1,687 $160 $84 $290 $2,221 $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 $233 $0 $149 $0 $0 $382 $36 $19 $87 $524 $1

12.7 Computer & Accessories $5,397 $0 $173 $0 $0 $5,570 $511 $278 $636 $6,995 $11

12.8 Instrument Wiring & Tubing $0 $1,885 $3,854 $0 $0 $5,739 $487 $287 $1,628 $8,141 $13

12.9 Other I & C Equipment $3,608 $0 $1,752 $0 $0 $5,359 $504 $268 $920 $7,051 $11

SUBTOTAL 12. $10,249 $1,885 $6,603 $0 $0 $18,737 $1,698 $937 $3,561 $24,933 $40
Cost and Performance Baseline for Fossil Energy Plants

129

Exhibit 3-27 Case 1 Total Plant Cost Details (Continued)

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

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $105 $2,246 $0 $0 $2,351 $233 $0 $775 $3,360 $5

13.2 Site Improvements $0 $1,869 $2,483 $0 $0 $4,352 $429 $0 $1,435 $6,216 $10

13.3 Site Facilities $3,349 $0 $3,534 $0 $0 $6,883 $679 $0 $2,268 $9,830 $16

SUBTOTAL 13. $3,349 $1,974 $8,263 $0 $0 $13,586 $1,341 $0 $4,478 $19,405 $31

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 $2,446 $3,484 $0 $0 $5,930 $546 $0 $971 $7,447 $12

14.3 Administration Building $0 $845 $613 $0 $0 $1,459 $130 $0 $238 $1,827 $3

14.4 Circulation Water Pumphouse $0 $167 $88 $0 $0 $255 $22 $0 $42 $319 $1

14.5 Water Treatment Buildings $0 $518 $506 $0 $0 $1,024 $93 $0 $167 $1,284 $2

14.6 Machine Shop $0 $433 $296 $0 $0 $729 $65 $0 $119 $912 $1

14.7 Warehouse $0 $699 $451 $0 $0 $1,149 $102 $0 $188 $1,439 $2

14.8 Other Buildings & Structures $0 $418 $326 $0 $0 $744 $66 $0 $162 $973 $2

14.9 Waste Treating Building & Str. $0 $935 $1,787 $0 $0 $2,723 $254 $0 $595 $3,572 $6

SUBTOTAL 14. $0 $6,725 $7,701 $0 $0 $14,427 $1,314 $0 $2,573 $18,313 $29

TOTAL COST $620,363 $72,516 $257,603 $0 $0 $950,481 $89,310 $31,044 $165,109 $1,235,944 $1,987

Owner's Costs

Preproduction Costs

6 Months All Labor $12,214 $20

1 Month Maintenance Materials $2,742 $4

1 Month Non-fuel Consumables $269 $0

1 Month Waste Disposal $304 $0

25% of 1 Months Fuel Cost at 100% CF $1,627 $3

2% of TPC $24,719 $40

Total $41,874 $67

Inventory Capital

60 day supply of fuel and consumables at 100% CF $13,328 $21

0.5% of TPC (spare parts) $6,180 $10

Total $19,507 $31

Initial Cost for Catalyst and Chemicals $4,892 $8

Land $900 $1

Other Owner's Costs $185,392 $298

Financing Costs $33,370 $54

Total Overnight Costs (TOC) $1,521,880 $2,447

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $1,734,944 $2,789
Cost and Performance Baseline for Fossil Energy Plants

130

Exhibit 3-28 Case 1 Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 1 - GEE Radiant 640MW IGCC w/o CO2 Heat Rate-net (Btu/kWh): 8,756

MWe-net: 622

 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

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 2.0 2.0

 Operator 9.0 9.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 3.0 3.0

 TOTAL-O.J.'s 15.0 15.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $5,918,913 $9.515

Maintenance Labor Cost $13,622,877 $21.900

Administrative & Support Labor $4,885,447 $7.854

Property Taxes and Insurance $24,718,883 $39.738

TOTAL FIXED OPERATING COSTS $49,146,120 $79.007

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $26,322,759 $0.00604

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water (/1000 gallons) 0 3,409 1.08 $0 $1,076,793 $0.00025

Chemicals

MU & WT Chem. (lbs) 0 20,311 0.17 $0 $1,026,436 $0.00024

Carbon (Mercury Removal) (lb) 54,833 75 1.05 $57,584 $23,034 $0.00001

COS Catalyst (m3) 422 0.29 2,397.36 $1,011,578 $202,316 $0.00005

Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000

Selexol Solution (gal) 285,358 45 13.40 $3,823,295 $175,961 $0.00004

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip. 1.94 131.27 $0 $74,422 $0.00002

Subtotal Chemicals $4,892,457 $1,502,168 $0.00034

Other

Supplemental Fuel (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 75 0.42 $0 $9,148 $0.00000

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 615 16.23 $0 $2,912,403 $0.00067

 Subtotal-Waste Disposal $0 $2,921,551 $0.00067

By-products & Emissions

Sulfur (tons) 0 140 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $4,892,457 $31,823,271 $0.00730

Fuel (ton) 0 5,603 38.18 $0 $62,470,676 $0.01433
Cost and Performance Baseline for Fossil Energy Plants

131

3.2.8

Case 2 is configured to produce electric power with CO2 capture. The plant configuration is the 

same as Case 1, namely two gasifier trains, two advanced F Class turbines, two HRSGs, and one 

steam turbine. The gross power output from the plant is constrained by the capacity of the two 

CTs, and since the CO2 capture process increases the auxiliary load on the plant, the net output is 

significantly reduced relative to Case 1.

Case 2 - GEE IGCC with CO2 Capture

The process description for Case 2 is similar to Case 1 with several notable exceptions to 

accommodate CO2 capture. A BFD and stream tables for Case 2 are shown in Exhibit 3-29 and 

Exhibit 3-30, respectively. Instead of repeating the entire process description, only differences 

from Case 1 are reported here.

The gasification process is the same as Case 1 with the exception that total coal feed to the two 

gasifiers is 5,302 tonnes/day (5,844 TPD) (stream 6) and the ASU provides 4,342 tonnes/day 

(4,786 TPD) of 95 percent oxygen to the gasifier and Claus plant (streams 3 and 5).

Gasification

Raw gas cooling and particulate removal are the same as Case 1 with the exception that 

approximately 443,118 kg/hr (976,891 lb/hr) of saturated steam at 13.8 MPa (2,000 psia) is 

generated in the radiant SGCs.

Raw Gas Cooling/Particulate Removal

No differences from Case 1.

Syngas Scrubber/Sour Water Stripper

The SGS process was described in Section 

SGS

3.1.3. In Case 2 steam (stream 11) is added to the 

syngas exiting the scrubber to adjust the H2O:CO molar ratio to 2:1 prior to the first SGS reactor. 

The hot syngas exiting the first stage of SGS is used to generate the steam that is added in stream 

11. A second stage of SGS results in 97 percent overall conversion of the CO to CO2. The warm 

syngas from the second stage of SGS (stream 12) is cooled to 236°C (456°F) by preheating the 

unshifted syngas prior to the SGS. The SGS catalyst also serves to hydrolyze COS thus 

eliminating the need for a separate COS hydrolysis reactor. Following the second SGS cooler 

the syngas is further cooled to 35°C (95°F) prior to the mercury removal beds.

Mercury removal is the same as in Case 1.

Mercury Removal and AGR

The AGR process in Case 2 is a two stage Selexol process where H2S is removed in the first 

stage and CO2 in the second stage of absorption as previously described in Section 3.1.5. The 

process results in three product streams, the clean syngas, a CO2-rich stream and an acid gas feed 

to the Claus plant. The acid gas (stream 18) contains 35 percent H2S and 52 percent CO2 with 

the balance primarily N2. The CO2-rich stream is discussed further in the CO2 compression 

section.
Cost and Performance Baseline for Fossil Energy Plants

132

Exhibit 3-29 Case 2 Block Flow Diagram, GEE IGCC with CO2 Capture
Cost and Performance Baseline for Fossil Energy Plants

133

Exhibit 3-30 Case 2 Stream Table, GEE IGCC with CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12

V-L Mole Fraction

Ar 0.0092 0.0166 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0054

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0007

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2823 0.0000 0.0060

CO2 0.0003 0.0054 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1089 0.0000 0.3082

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2689 0.0000 0.4366

H2O 0.0099 0.1363 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3190 1.0000 0.2325

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0001

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0047

N2 0.7732 0.7061 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0044

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0013

O2 0.2074 0.1356 0.9504 0.0054 0.9504 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

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 27,361 1,650 96 20,051 5,526 0 5,037 0 23,122 29,284 7,193 36,478

V-L Flowrate (kg/hr) 789,560 45,332 3,080 562,615 177,828 0 90,748 0 465,243 575,983 129,587 705,570

Solids Flowrate (kg/hr) 0 0 0 0 0 220,904 0 24,237 0 0 0 0

Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 240

Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.52 5.52 5.41

Enthalpy (kJ/kg)A 30.23 35.64 26.67 92.50 26.67 --- 537.77 --- 1,424.65 1,065.71 2,918.18 942.21

Density (kg/m3) 1.2 1.5 11.0 24.4 11.0 --- 872.0 --- 14.0 27.2 25.6 24.8

V-L Molecular Weight 28.857 27.476 32.181 28.060 32.181 --- 18.015 --- 20.121 19.669 18.015 19.343

V-L Flowrate (lbmol/hr) 60,321 3,637 211 44,204 12,183 0 11,106 0 50,976 64,561 15,858 80,419

V-L Flowrate (lb/hr) 1,740,683 99,940 6,791 1,240,354 392,044 0 200,064 0 1,025,685 1,269,825 285,691 1,555,516

Solids Flowrate (lb/hr) 0 0 0 0 0 487,011 0 53,433 0 0 0 0

Temperature (°F) 59 65 90 199 90 59 287 2,400 1,250 403 550 463

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0

Enthalpy (Btu/lb)A 13.0 15.3 11.5 39.8 11.5 --- 231.2 --- 612.5 458.2 1,254.6 405.1

Density (lb/ft3) 0.076 0.091 0.687 1.521 0.687 --- 54.440 --- 0.871 1.699 1.597 1.550

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Fossil Energy Plants

134

Exhibit 3-30 Case 2 Stream Table, GEE IGCC with CO2 Capture (Continued)

13 14 15 16 17 18 19 20 21 22 23 24

V-L Mole Fraction

Ar 0.0071 0.0071 0.0115 0.0115 0.0002 0.0018 0.0000 0.0103 0.0092 0.0091 0.0091 0.0000

CH4 0.0009 0.0009 0.0015 0.0015 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0078 0.0077 0.0124 0.0124 0.0002 0.0022 0.0000 0.0064 0.0000 0.0000 0.0000 0.0000

CO2 0.4019 0.4055 0.0502 0.0502 0.9948 0.5214 0.0000 0.6664 0.0003 0.0083 0.0083 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.5692 0.5649 0.9139 0.9139 0.0048 0.1028 0.0000 0.2561 0.0000 0.0000 0.0000 0.0000

H2O 0.0012 0.0013 0.0001 0.0001 0.0000 0.0226 0.0000 0.0017 0.0099 0.1222 0.1222 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2S 0.0061 0.0061 0.0000 0.0000 0.0000 0.3477 0.0000 0.0050 0.0000 0.0000 0.0000 0.0000

N2 0.0058 0.0064 0.0105 0.0105 0.0000 0.0008 0.0000 0.0542 0.7732 0.7541 0.7541 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1064 0.1064 0.0000

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

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 27,978 28,368 17,423 17,423 10,425 497 0 390 110,253 139,657 139,657 34,500

V-L Flowrate (kg/hr) 552,391 564,920 90,179 90,179 456,650 17,684 0 12,529 3,181,557 3,834,352 3,834,352 621,521

Solids Flowrate (kg/hr) 0 0 0 0 0 0 5,524 0 0 0 0 0

Temperature (°C) 35 35 35 196 51 48 178 38 15 562 132 534

Pressure (MPa, abs) 5.14 5.1 5.102 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512

Enthalpy (kJ/kg)A 37.11 36.4 195.532 1,124.237 -162.306 74.865 --- 5.295 30.227 834.762 343.819 3,432.885

Density (kg/m3

) 40.7 40.9 10.1 4.2 641.8 2.2 5,280.5 77.9 1.2 0.4 0.9 36.7

V-L Molecular Weight 19.744 20 5.176 5.176 43.805 35.588 --- 32.153 28.857 27.455 27.455 18.015

V-L Flowrate (lbmol/hr) 61,681 62,540 38,412 38,412 22,983 1,095 0 859 243,066 307,891 307,891 76,059

V-L Flowrate (lb/hr) 1,217,813 1,245,436 198,810 198,810 1,006,740 38,986 0 27,622 7,014,133 8,453,299 8,453,299 1,370,220

Solids Flowrate (lb/hr) 0 0 0 0 0 0 12,178 0 0 0 0 0

Temperature (°F) 95 95 95 384 124 119 352 100 59 1,044 270 994

Pressure (psia) 745.0 740.0 740.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 16.0 15.7 84.1 483.3 -69.8 32.2 --- 2.3 13.0 358.9 147.8 1,475.9

Density (lb/ft3) 2.544 3 0.630 0.260 40.068 0.137 329.649 4.864 0.076 0.026 0.053 2.293
Cost and Performance Baseline for Fossil Energy Plants

135

CO2 from the AGR process is flashed at three pressure levels to separate CO2 and decrease H2

losses to the CO2 product pipeline. The HP CO2 stream is flashed at 2.0 MPa (289.7 psia), 

compressed, and recycled back to the CO2 absorber. The MP CO2 stream is flashed at 1.0 MPa 

(149.7 psia). The LP CO2 stream is flashed at 0.1 MPa (16.7 psia), compressed to 1.0 MPa 

(149.5 psia), and combined with the MP CO2 stream. The combined stream is compressed from 

2.1 MPa (149.5 psia) to 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 dewpoint of 

-40oC (-40°F) with triethylene glycol. The raw CO2 stream from the Selexol process contains 

over 99 percent CO2. The CO2 (stream 17) is transported to the plant fence line and is 

sequestration ready. CO2 TS&M costs were estimated using the methodology described in 

Section 2.7.

CO2 Compression and Dehydration

The Claus plant is the same as Case 1 with the following exceptions:

Claus Unit

• 5,528 kg/hr (12,178 lb/hr) of sulfur (stream 19) are produced

• The waste heat boiler generates 13,555 kg/hr (29,884 lb/hr) of 4.0 MPa (575 psia) steam 

of which 12,679 kg/hr (27,953 lb/hr) is available to the medium pressure steam header.

Clean syngas from the AGR plant is heated to 241°C (465°F) using HP BFW before passing 

through an expansion turbine. The clean syngas (stream 16) is diluted with nitrogen (stream 4) 

and then enters the CT burner. There is no integration between the CT and the ASU in this case. 

The exhaust gas (stream 22) exits the CT at 562°C (1044°F) and enters the HRSG where 

additional heat is recovered. The FG exits the HRSG at 132°C (270°F) (stream 23) and is 

discharged through the plant stack. The steam raised in the HRSG is used to power an advanced 

commercially available steam turbine using a 12.4 MPa/534°C/534°C (1800 psig/994°F/994°F) 

steam cycle.

Power Block

The same elevated pressure ASU is used in Case 2 and produces 4,342 tonnes/day (4,786 TPD) 

of 95 mole% oxygen and 14,591 tonnes/day (16,084 TPD) of nitrogen. There is no integration 

between the ASU and the CT.

Air Separation Unit (ASU)

3.2.9

The Case 2 modeling assumptions were presented previously in Section 

Case 2 Performance Results

3.2.3.

The plant produces a net output of 543 MW at a net plant efficiency of 32.6 percent (HHV 

basis). Overall performance for the entire plant is summarized in Exhibit 3-31, which includes 

auxiliary power requirements. The ASU accounts for nearly 60 percent of the auxiliary load 

between the main air compressor, the nitrogen compressor, the oxygen compressor, and ASU 

auxiliaries. The two-stage Selexol process and CO2 compression account for an additional 26 

percent of the auxiliary power load. The BFW pumps and cooling water system (CWPs and 

cooling tower fan) comprise over 6 percent of the load, leaving 8 percent of the auxiliary load for 

all other systems.
Cost and Performance Baseline for Fossil Energy Plants

136

Exhibit 3-31 Case 2 Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Gas Turbine Power 464,000

Sweet Gas Expander Power 6,500

Steam Turbine Power 263,500

TOTAL POWER, kWe 734,000

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 470

Coal Milling 2,270

Sour Water Recycle Slurry Pump 190

Slag Handling 1,160

Air Separation Unit Auxiliaries 1,000

Air Separation Unit Main Air Compressor 67,330

Oxygen Compressor 10,640

Nitrogen Compressors 35,640

CO2 Compressor 31,160

Boiler Feedwater Pumps 4,180

Condensate Pump 280

Quench Water Pump 540

Circulating Water Pump 4,620

Ground Water Pumps 530

Cooling Tower Fans 2,390

Scrubber Pumps 230

Acid Gas Removal 19,230

Gas Turbine Auxiliaries 1,000

Steam Turbine Auxiliaries 100

Claus Plant/TGTU Auxiliaries 250

Claus Plant TG Recycle Compressor 1,780

Miscellaneous Balance of Plant2 3,000

Transformer Losses 2,760

TOTAL AUXILIARIES, kWe 190,750

NET POWER, kWe 543,250

Net Plant Efficiency, % (HHV) 32.6

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,034 (10,458)

CONDENSER COOLING DUTY 106 kJ/hr (106 Btu/hr) 1,509 (1,430)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 220,904 (487,011)

Thermal Input1, kWt 1,665,074

Raw Water Withdrawal, m3/min (gpm) 22.0 (5,815)

Raw Water Consumption, m3/min (gpm) 17.9 (4,739)

1 - HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)

2 - Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Fossil Energy Plants

137

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 

2.4. A summary of the plant air emissions for Case 2 is presented in 

Environmental Performance

Exhibit 3-32. 

Exhibit 3-32 Case 2 Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(tons/year) @ 

80% capacity factor

kg/MWh

(lb/MWh)

SO2 0.001 (0.002) 39 (43) 0.008 (.02)

NOx 0.021 (0.049) 878 (967) 0.171 (.376)

Particulates 0.003 (0.0071) 128 (141) 0.025 (.055)

Hg 2.46E-7 (5.71E-7) 0.010 (0.011) 2.01E-6 (4.42E-6)

CO2 8.5 (19.7) 355,438 (391,804) 69 (152)

CO2

1 93 (206) 1 CO2 emissions based on net power instead of gross power

The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the two-stage 

Selexol AGR process. As a result of achieving the 90 percent CO2 removal target, the sulfur 

compounds are removed to an extent that exceeds the environmental target in Section 2.4. The 

clean syngas exiting the AGR process has a sulfur concentration of approximately 5 ppmv. This 

results in a concentration in the FG of less than 1 ppmv. The H2S-rich regeneration gas from the 

AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is 

hydrogenated to convert all sulfur species to H2S and then recycled back to the Selexol process, 

thereby eliminating the need for a tail gas treatment unit.

NOx emissions are limited by nitrogen dilution to 15 ppmvd (as NO2 @15 percent O2). 

Ammonia in the syngas is removed with process condensate prior to the low-temperature AGR 

process. This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of the 

syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Ninety-five percent of mercury is captured from the syngas by an activated carbon bed.

Ninety-two 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 3-33. 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, as CO2 in the stack gas, 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 for Fossil Energy Plants

138

(Carbon in CO2 Product)/[(Carbon in the Coal)-(Carbon in Slag)] or

274,672/(310,444-6,209) *100 or

90.3 percent

Exhibit 3-33 Case 2 Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 140,815 (310,444) Slag 2,816 (6,209)

Air (CO2) 540 (1,191) Stack Gas 13,842 (30,516)

ASU Vent 107 (237)

CO2 Product 124,589 (274,672)

Total 141,355 (311,634) Total 141,355 (311,634)

Exhibit 3-34 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur emitted in the 

stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 3-34 Case 2 Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 5,537 (12,207) Elemental Sulfur 5,524 (12,178)

Stack Gas 3 (6)

CO2 Product 10 (23)

Total 5,537 (12,207) Total 5,537 (12,207)

Exhibit 3-35 shows the overall water balance for the plant. The exhibit is presented in an 

identical manner for Case 1.
Cost and Performance Baseline for Fossil Energy Plants

139

Exhibit 3-35 Case 2 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)

Slag Handling 0.53 (139) 0.53 (139) 0.0 (0) 0.0 (0) 0.0 (0)

Slurry Water 1.51 (400) 1.51 (400) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.9 (757) 0.72 (191) 2.1 (566) 0.0 (0) 2.1 (566)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7) -0.03 (-7)

Condenser Makeup

Gasifier Steam

Shift Steam

GT Steam Dilution

BFW Makeup

2.4 (627)

2.2 (571)

0.21 (56)

0.0 (0) 2.4 (627)

2.2 (571)

0.21 (56)

0.0 (0) 2.4 (627)

Cooling Tower

BFW Blowdown

SWS Blowdown

SWS Excess Water

Humidifier Tower 

Blowdown

18.0 (4,750) 0.49 (129)

0.21 (56)

0.28 (73)

17.5 (4,622)

-0.21 (-56)

-0.28 (-73)

4.0 (1,068) 13.5 (3,553)

Total 25.3 (6,673) 3.25 (858) 22.0 (5,815) 4.1 (1,076) 17.9 (4,739)

Heat and mass balance diagrams are shown for the following subsystems in 

Heat and Mass Balance Diagrams

Exhibit 3-36 through

Exhibit 3-38:

• Coal gasification and ASU

• Syngas cleanup, sulfur recovery, and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is presented in tabular form in Exhibit 3-39. The power out is 

the combined CT, steam turbine and expander power prior to generator losses. The power at the 

generator terminals (shown in Exhibit 3-31) is calculated by multiplying the power out by a 

combined generator efficiency of 98.3 percent.
Cost and Performance Baseline for Fossil Energy Plants

140

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

141

Exhibit 3-36 Case 2 Coal Gasification and Air Separation Units Heat and Mass Balance Schematic

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 2

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 2

GEE GASIFIER

ASU AND GASIFICATION

DWG. NO.

BB-HMB-CS-2-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

1 OF 3

Ambient Air

Four Stage Air

Compressor

Elevated

Pressure

ASU

Four Stage N2

Compressor

Four Stage O2

Compressor

ASU 

Vent

Water

Steam

Gross Plant Power: 734 MWe

Auxiliary Load: 191 MWe

Net Plant Power: 543 MWe

Net Plant Efficiency, HHV: 32.6%

Net Plant Heat Rate: 10,458 BTU/KWe

N2 to GT Combustor

1,740,683 W

59.0 T

14.7 P

13.0 H

392,044 W

90.0 T

125.0 P

11.5 H

392,044 W

241.2 T

940.0 P

40.8 H

To Claus Plant

6,791 W

90.0 T

125.0 P

11.5 H

99,940 W

64.8 T

16.4 P

15.3 H

1,083,577 W

90.0 T

56.4 P

14.2 H

156,777 W

50.0 T

182.0 P

2.9 H

5

1

3

2

Slurry Mix 

Tank

Milled Coal

Slag

487,011 W

59.0 T

14.7 P

200,064 W

287.0 T

840.0 P

231.2 H

53,433 W

2,400.0 T

815.0 P

676,491 W

385.0 T

384.0 P

87.2 H

687,075 W

156.4 T

840.0 P

2,950.2 H

100.0 T

189.5 P

18.0 H

6

676,491 W

199.0 T

384.0 P

39.8 H

HP BFW

N2 to GT Combustor

N2 Boost

Compressor 563,864 W

199.0 T

384.0 P

39.8 H

563,864 W

385.0 T

469.0 P

87.0 H

Saturated Steam

To HRSG HP

Superheater

GE Energy 

Gasifier

Radiant

Syngas

Cooler

Black

Water

Flash

Tank

Knockout

Drum

Vent To Claus Unit

Raw Fuel Gas

CWS

CWR

Fines

Process Water

From Sour Water Stripper Syngas 

Scrubber

Slag Quench 

Section

Drag 

Conveyor

4

1,025,685 W

1,250.0 T

805.0 P

612.5 H

1,269,825 W

403.1 T

800.0 P

458.2 H

Syngas

Quench

1,403,986 W

450.0 T

805.0 P

536.1 H

8

9

10

Sour Water

7
Cost and Performance Baseline for Fossil Energy Plants

142

Exhibit 3-37 Case 2 Syngas Cleanup Heat and Mass Balance Schematic

Mercury 

Removal

Knock

Out 

Drum

Syngas

Preheater

Sour

Drum

Process Condensate to Syngas Scrubber

Makeup Water

Claus Plant

Tail 

Gas

Furnace

Catalytic

Reactor

Beds

Sulfur

Knock Out

From 

ASU

Syngas

Coolers

Sour

Stripper

1,269,825 W

403.1 T

800.0 P

458.2 H

1,245,436 W

94.6 T

740.0 P

15.7 H

38,986 W

119.0 T

23.7 P

198,810 W

384.3 T

460.0 P

483.3 H

12,178 W

36,094 W

450.0 T

12.3 P

457.8 H

2,495 W

239.1 T

65.0 P

441.9 H

6,791 W

90.0 T

125.0 P

11.5 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 2

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 2

GEE GASIFIER

GAS CLEANUP SYSTEM

DWG. NO.

BB-HMB-CS-2-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

2 OF 3

Sour Gas

Sour Water

Water

Steam

Gross Plant Power: 734 MWe

Auxiliary Load: 191 MWe

Net Plant Power: 543 MWe

Net Plant Efficiency, HHV: 32.6%

Net Plant Heat Rate: 10,458 BTU/KWe

19

13

20

CO2

Tailgas

30,072 W

120.0 T

10.6 P

112.1 H

1,217,813 W

94.9 T

745.0 P

16.0 H

8,472 W

114.3 T

10.6 P

40.0 H

3

27,622 W

100.0 T

799.5 P

Raw Syngas

15 198,810 W

94.6 T

740.0 P

84.1 H

Claus Oxygen

Preheater

6,791 W

450.0 T

124.5 P

91.9 H

18

Fuel Gas

Expander

Fuel Gas To GT

16

198,810 W

465.0 T

735.0 P

597.2 H

High

Temperature

Shift #1

Low

Temperature 

Shift #2

Shift Steam

12

11

COS Hydrolysis

Preheater

1,269,825 W

413.1 T

795.0 P

450.3 H

285,691 W

550.0 T

800.0 P

1,254.1 H

1,555,516 W

436.4 T

795.0 P

598.0 H

776.2 T

795.0 P

582.1 H

400.0 T

795.0 P

408.0 H

1,555,516 W

463.4 T

785.0 P

405.1 H

1,555,516 W

455.6 T

780.0 P

401.5 H

Two-Stage

Selexol

Clean Gas

CO2

Acid Gas

Multistage 

Intercooled CO2

Compressor

Interstage Knockout

CO2 Product

17

10

14

1,006,740 W

123.8 T

2,214.7 P

Tail Gas Recycle

Compressor

Hydrogenation 

and Tail Gas 

Cooling
Cost and Performance Baseline for Fossil Energy Plants

143

Exhibit 3-38 Case 2 Combined-Cycle Power Generation Heat and Mass Balance Schematic

HRSG

HP

Turbine

IP

Turbine

Nitrogen Diluent

Intake

Ambient Air

Steam Seal 

Regulator

Ip Extraction Steam

To 250 PSIA Header

LP Process Header

Blowdown

Flash

To WWT

Gland

Steam

Condenser

Condensate to Gasification Island

HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP 

Turbine

Stack

Compressor Expander

Fuel Gas

Deaerator

IP BFW

Generator

Generator

Condensate

Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class 

Gas Turbine

MP Flash Bottoms

LP Flash Tops

7,014,133 W

59.0 T

14.7 P

13.0 H

1,875,803 W

101.1 T

1.0 P

69.1 H

8,453,299 W

269.9 T

15.2 P

147.8 H

198,810 W

384.3 T

460.0 P

483.3 H

8,453,299 W

1,043.8 T

15.2 P

358.9 H From Gasifier

Island Preheating

To Claus

LP BFW

1,370,220 W

993.8 T

1,814.7 P

1,475.9 H

10,303 W

298.0 T

65.0 P

1,179.0 H

1,399,040 W

278.8 T

2,250.7 P

252.3 H

28,836 W

585.0 T

2,000.7 P

593.3 H

1,550,132 W

474.9 T

65.0 P

1,269.6 H

1,875,803 W

102.9 T

120.0 P

71.1 H

1,875,803 W

235.0 T

105.0 P

203.7 H

1,400 W

614.9 T

65.0 P

1,338.7 H

1,400 W

212.0 T

14.7 P

179.9 H

IP Pump NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 2

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 2

GEE GASIFIER

POWER BLOCK SYSTEM

DWG. NO.

BB-HMB-CS-2-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

Gross Plant Power: 734 MWe

Auxiliary Load: 191 MWe

Net Plant Power: 543 MWe

Net Plant Efficiency, HHV: 32.6%

21 Net Plant Heat Rate: 10,458 BTU/KWe

22

24

16

23

Flue Gas

HOT WELL

CONDENSER Make-up

313,510 W

59.0 T

14.7 P

27.1 H

9,026 W

660.5 T

501.4 P

1,334.5 H

9,761 W

614.9 T

65.0 P

1,338.7 H

34,034 W

852.1 T

280.0 P

1,448.8 H

798 W

993.8 T

1,814.7 P

1,475.9 H

1,337 W

505.0 T

65.0 P

1,284.5 H
Cost and Performance Baseline for Fossil Energy Plants

144

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

145

Exhibit 3-39 Case 2 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,994 (5,681) 5.0 (4.7) 5,999 (5,686)

ASU Air 24 (23) 24 (23)

GT Air 96 (91) 96 (91)

Water 83 (78) 83 (78)

Auxiliary Power 687 (651) 687 (651)

TOTAL 5,994 (5,681) 208 (197) 687 (651) 6,889 (6,529)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 2 (2) 2 (2)

Slag 92 (88) 38 (36) 130 (123)

Sulfur 51 (49) 1 (1) 52 (49)

CO2 -74 (-70) -74 (-70)

Cooling Tower 

Blowdown 30 (28) 30 (28)

HRSG Flue Gas 1,318 (1,250) 1,318 (1,250)

Condenser 1,513 (1,434) 1,513 (1,434)

Non-Condenser 

Cooling Tower 

Loads*

632 (599) 632 (599)

Process Losses** 643 (610) 643 (610)

Power 2,642 (2,505) 2,642 (2,505)

TOTAL 144 (136) 4,103 (3,889) 2,642 (2,505) 6,889 (6,529)

* Includes ASU compressor intercoolers, CO2 compressor intercoolers, sour water stripper condenser, and 

syngas cooler (low level heat rejection).

** Calculated by difference to close the energy balance.
Cost and Performance Baseline for Fossil Energy Plants

146

3.2.10

Major equipment items for the GEE gasifier with CO2 capture are shown in the following tables. 

The accounts used in the equipment list correspond to the account numbers used in the cost 

estimates in Section 

Case 2 - Major Equipment List

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.

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 45 tonne (50 ton) 2 1

9 Feeder Vibratory 181 tonne/hr (200 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 363 tonne/hr (400 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 181 tonne (200 ton) 2 0

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0) 2 0

14 As-Fired Coal Sampling 

System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 363 tonne/hr (400 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 363 tonne/hr (400 tph) 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 816 tonne (900 ton) 3 0
Cost and Performance Baseline for Fossil Energy Plants

147

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 82 tonne/h (90 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 245 tonne/h (270 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 490 tonne (540 ton) 1 0

4 Weigh Feeder Belt 118 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 118 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank 

with Agitator Field erected 299,921 liters (79,230 gal) 2 0

7 Slurry Water Pumps Centrifugal 833 lpm (220 gpm) 2 1

8 Trommel Screen Coarse 172 tonne/h (190 tph) 2 0

9 Rod Mill Discharge Tank with 

Agitator Field erected 392,323 liters (103,640 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,407 lpm (900 gpm) 2 2

11 Slurry Storage Tank with 

Agitator Field erected 1,176,894 liters (310,900 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,435 lpm (1,700 gpm) 2 2

13 Slurry Product Pumps Positive 

displacement 3,407 lpm (900 gpm) 2 2
Cost and Performance Baseline for Fossil Energy Plants

148

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 1,093,984 liters (289,000 gal) 2 0

2 Condensate Pumps Vertical canned 7,836 lpm @ 91 m H2O

(2,070 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 546,579 kg/hr (1,205,000 lb/hr) 2 0

4 Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

8,025 lpm @ 27 m H2O

(2,120 gpm @ 90 ft H2O) 2 1

5 High Pressure 

Feedwater Pump No. 1

Barrel type, multi-stage, 

centrifugal

HP water: 6,057 lpm @ 1,859 m 

H2O (1,600 gpm @ 6,100 ft 

H2O)

2 1

6 High Pressure 

Feedwater Pump No. 2

Barrel type, multi-stage, 

centrifugal

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) 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 Cylce Cooling 

Heat Exchangers Plate and frame 362 GJ/hr (343 MMBtu/hr) each 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 129,840 lpm @ 21 m H2O(34,300 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

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

5,716 lpm @ 18 m H2O

(1,510 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) 4 1

16 Filtered Water Pumps Stainless steel, single 

suction

3,369 lpm @ 49 m H2O

(890 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,608,800 liter (425,000 gal) 2 0

18 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 1,476 lpm (390 gpm) 2 0

19 Liquid Waste Treatment 

System 10 years, 24-hour storm 1 0
Cost and Performance Baseline for Fossil Energy Plants

149

ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW 

TEMPERATURE HEAT RECOVERY

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Gasifier Pressurized slurry-feed, 

entrained bed

2,903 tonne/day, 5.6 MPa

(3,200 tpd, 814.96 psia) 2 0

2 Synthesis Gas Cooler

Vertical downflow 

radiant heat exchanger 

with outlet quench 

chamber

255,826 kg/hr (564,000 lb/hr) 2 0

3

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 350,173 kg/hr (772,000 lb/hr) 2 0

4 Raw Gas Coolers Shell and tube with 

condensate drain 388,275 kg/hr (856,000 lb/hr) 8 0

5 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator

304,360 kg/hr, 35°C, 5.2 MPa

(671,000 lb/hr, 95°F, 750 psia) 2 0

6 Flare Stack

Self-supporting, carbon 

steel, stainless steel top, 

pilot ignition

350,173 kg/hr (772,000 lb/hr) 

syngas

2 0

7

ASU Main Air 

Compressor Centrifugal, multi-stage 5,947 m3/min @ 1.3 MPa(210,000 scfm @ 190 psia) 2 0

8 Cold Box Vendor design 2,359 tonne/day (2,600 tpd) of 

95% purity oxygen 2 0

9 Oxygen Compressor Centrifugal, multi-stage

1,189 m3/min (42,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 psia)

2 0

10 Primary Nitrogen 

Compressor Centrifugal, multi-stage

3,794 m3/min (134,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 0

11 Secondary Nitrogen 

Compressor Centrifugal, single-stage

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 0

12 Syngas Dilution Nitrogen 

Boost Compressor Centrifugal, single-stage

1,982 m3/min (70,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 psia)

2 0
Cost and Performance Baseline for Fossil Energy Plants

150

ACCOUNT 5A SOUR GAS SHIFT AND SYNGAS CLEANUP

ACCOUNT 5B CO2 COMPRESSION

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon 

bed

303,907 kg/hr (670,000 lb/hr) 

35°C (95°F)

5.1 MPa (745 psia)

2 0

2 Sulfur Plant Claus type 146 tonne/day (161 tpd) 1 0

3 Water Gas Shift Reactors Fixed bed, 

catalytic

388,275 kg/hr (856,000 lb/hr) 

227°C (440°F)

5.4 MPa (790 psia)

4 0

4 Shift Reactor Heat Recovery 

Exchangers Shell and Tube

Exchanger 1: 157 GJ/hr (149 

MMBtu/hr) 

Exchanger 2: 3 GJ/hr (3 

MMBtu/hr) 

4 0

5 Acid Gas Removal Plant Two-stage 

Selexol

310,711 kg/hr (685,000 lb/hr) 

35°C (95°F)

5.1 MPa (740 psia)

2 0

6 Hydrogenation Reactor Fixed bed, 

catalytic

18,009 kg/hr (39,704 lb/hr)

232°C (450°F)

0.1 MPa (12.3 psia)

1 0

7 Tail Gas Recycle 

Compressor Centrifugal 13,782 kg/hr (30,385 lb/hr) 1 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CO2 

Compressor

Integrally geared, 

multi-stage centrifugal

1,133 m3/min @ 15.3 MPa 

(40,000 scfm @ 2,215 psia) 4 0
Cost and Performance Baseline for Fossil Energy Plants

151

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

ACCOUNT 7 HRSG, DUCTING, AND STACK

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gas Turbine Advanced F class 232 MW 2 0

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase 2 0

3 Syngas Expansion 

Turbine/Generator Turbo Expander

49,578 kg/h (109,300 lb/h)

5.1 MPa (735 psia) Inlet

3.2 MPa (460 psia) Outlet

2 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS 

liner

76 m (250 ft) high x

8.5 m (28 ft) diameter 1 0

2 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator

Main steam - 341,837 kg/hr, 12.4 

MPa/534°C (753,621 lb/hr, 

1,800 psig/994°F)

 Reheat steam - 336,628 kg/hr, 

3.1 MPa/534°C (742,137 lb/hr, 

452 psig/994°F)

2 0
Cost and Performance Baseline for Fossil Energy Plants

152

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

277 MW 

12.4 MPa/534°C/534°C 

(1,800 psig/ 994°F/994°F)

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitiation

310 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase 1 0

3 Steam Bypass One per HRSG 50% steam flow @ design 

steam conditions 2 0

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,667 GJ/hr (1,580 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 11°C 

(20°F)

1 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water 

Pumps Vertical, wet pit 461,820 lpm @ 30 m(122,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

/ 2,585 GJ/hr (2,450 MMBtu/hr) 

heat duty

1 0
Cost and Performance Baseline for Fossil Energy Plants

153

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 253,623 liters (67,000 gal) 2 0

2 Slag Crusher Roll 14 tonne/hr (15 tph) 2 0

3 Slag Depressurizer Lock Hopper 14 tonne/hr (15 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 151,416 liters (40,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 68,137 liters (18,000 gal) 2

6 Slag Conveyor Drag chain 14 tonne/hr (15 tph) 2 0

7 Slag Separation Screen Vibrating 14 tonne/hr (15 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 14 tonne/hr (15 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 215,768 liters (57,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal 

centrifugal

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 68,137 liters (18,000 gal) 2 0

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H2O

(60 gpm @ 1,850 ft H2O) 2 2

13 Slag Storage Bin Vertical, field 

erected 998 tonne (1,100 tons) 2 0

14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 1 0
Cost and Performance Baseline for Fossil Energy Plants

154

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CTG Step-up 

Transformer Oil-filled 24 kV/345 kV, 260 MVA, 3-ph, 60 Hz 2 0

2 STG Step-up 

Transformer Oil-filled 24 kV/345 kV, 310 MVA, 3-ph, 60 Hz 1 0

3

High Voltage 

Auxiliary 

Transformer

Oil-filled 345 kV/13.8 kV, 80 MVA, 

3-ph, 60 Hz 2 0

4

Medium Voltage 

Auxiliary 

Transformer

Oil-filled 24 kV/4.16 kV, 48 MVA, 

3-ph, 60 Hz 1 1

5 Low Voltage 

Transformer Dry ventilated 4.16 kV/480 V, 7 MVA, 3-ph, 60 Hz 1 1

6

CTG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, 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

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 for Fossil Energy Plants

155

3.2.11

The cost estimating methodology was described previously in Section

Case 2 - Cost Estimating

2.7. Exhibit 3-40 shows 

the TPC summary organized by cost account and Exhibit 3-41 shows a more detailed breakdown 

of the capital costs along with owner’s costs, TOC, and TASC. Exhibit 3-42 shows the initial 

and annual O&M costs.

The estimated TOC of the GEE gasifier with CO2 capture is $3,334/kW. Process contingency 

represents 3.6 percent of the TPC and project contingency represents 11.1 percent. The COE, 

including CO2 TS&M costs of 5.3 mills/kWh is 105.7 mills/kWh.
Cost and Performance Baseline for Fossil Energy Plants

156

Exhibit 3-40 Case 2 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14

Project: Bituminous Baseline Study

Case: Case 2 - GEE Radiant 550MW IGCC w/ CO2

Plant Size: 543.3 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 $14,280 $2,654 $11,074 $0 $0 $28,008 $2,542 $0 $6,110 $36,660 $67

 2 COAL & SORBENT PREP & FEED $24,391 $4,448 $14,651 $0 $0 $43,489 $3,954 $1,579 $9,804 $58,826 $108

 3 FEEDWATER & MISC. BOP SYSTEMS $10,158 $7,914 $10,237 $0 $0 $28,309 $2,671 $0 $7,166 $38,146 $70

 4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $113,863 $0 $62,389 $0 $0 $176,251 $16,146 $24,460 $33,252 $250,109 $460

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $193,046 $0 w/equip. $0 $0 $193,046 $18,712 $0 $21,176 $232,934 $429

4.4-4.9 Other Gasification Equipment $7,894 $12,285 $12,270 $0 $0 $32,449 $3,078 $0 $7,755 $43,282 $80

SUBTOTAL 4 $314,803 $12,285 $74,659 $0 $0 $401,747 $37,935 $24,460 $62,183 $526,325 $969

 5A GAS CLEANUP & PIPING $96,775 $3,334 $82,247 $0 $0 $182,357 $17,666 $27,526 $45,625 $273,174 $503

5B CO2 COMPRESSION $18,256 $0 $11,190 $0 $0 $29,446 $2,836 $0 $6,456 $38,739 $71

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,600 $239

6.2-6.9 Combustion Turbine Other $5,550 $887 $1,748 $0 $0 $8,185 $775 $0 $1,650 $10,610 $20

SUBTOTAL 6 $97,576 $887 $8,331 $0 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $258

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,620 $0 $4,780 $0 $0 $38,401 $3,651 $0 $4,205 $46,257 $85

7.2-7.9 SCR System, Ductwork and Stack $3,376 $2,407 $3,153 $0 $0 $8,936 $828 $0 $1,589 $11,353 $21

SUBTOTAL 7 $36,996 $2,407 $7,933 $0 $0 $47,336 $4,480 $0 $5,794 $57,610 $106

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $28,123 $0 $4,808 $0 $0 $32,931 $3,160 $0 $3,609 $39,699 $73

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,211 $967 $7,075 $0 $0 $18,253 $1,662 $0 $3,950 $23,865 $44

SUBTOTAL 8 $38,333 $967 $11,883 $0 $0 $51,183 $4,821 $0 $7,559 $63,564 $117

 9 COOLING WATER SYSTEM $10,319 $9,775 $8,388 $0 $0 $28,483 $2,646 $0 $6,348 $37,477 $69

10 ASH/SPENT SORBENT HANDLING SYS $14,734 $8,239 $14,938 $0 $0 $37,910 $3,652 $0 $4,476 $46,038 $85

11 ACCESSORY ELECTRIC PLANT $32,062 $12,584 $24,591 $0 $0 $69,237 $5,953 $0 $14,261 $89,451 $165

12 INSTRUMENTATION & CONTROL $11,404 $2,098 $7,347 $0 $0 $20,849 $1,889 $1,042 $3,962 $27,743 $51

13 IMPROVEMENTS TO SITE $3,485 $2,054 $8,600 $0 $0 $14,140 $1,396 $0 $4,661 $20,196 $37

14 BUILDINGS & STRUCTURES $0 $6,882 $7,834 $0 $0 $14,716 $1,340 $0 $2,628 $18,684 $34

 

TOTAL COST $723,574 $76,529 $303,902 $0 $0 $1,104,005 $103,905 $64,468 $200,468 $1,472,845 $2,711

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline for Fossil Energy Plants

157

Exhibit 3-41 Case 2 Total Plant Cost Details

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 $3,750 $0 $1,833 $0 $0 $5,583 $500 $0 $1,217 $7,299 $13

1.2 Coal Stackout & Reclaim $4,846 $0 $1,175 $0 $0 $6,021 $528 $0 $1,310 $7,858 $14

1.3 Coal Conveyors & Yd Crush $4,505 $0 $1,162 $0 $0 $5,668 $498 $0 $1,233 $7,398 $14

1.4 Other Coal Handling $1,179 $0 $269 $0 $0 $1,448 $127 $0 $315 $1,889 $3

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 $2,654 $6,635 $0 $0 $9,289 $890 $0 $2,036 $12,215 $22

SUBTOTAL 1. $14,280 $2,654 $11,074 $0 $0 $28,008 $2,542 $0 $6,110 $36,660 $67

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying w/2.3 $0 w/2.3 $0 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,602 $383 $251 $0 $0 $2,236 $191 $0 $485 $2,913 $5

2.3 Slurry Prep & Feed $21,908 $0 $9,667 $0 $0 $31,575 $2,869 $1,579 $7,205 $43,227 $80

2.4 Misc.Coal Prep & Feed $881 $641 $1,922 $0 $0 $3,443 $316 $0 $752 $4,512 $8

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 $3,424 $2,811 $0 $0 $6,234 $577 $0 $1,362 $8,174 $15

SUBTOTAL 2. $24,391 $4,448 $14,651 $0 $0 $43,489 $3,954 $1,579 $9,804 $58,826 $108

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,836 $4,870 $2,571 $0 $0 $10,276 $952 $0 $2,246 $13,474 $25

3.2 Water Makeup & Pretreating $717 $75 $401 $0 $0 $1,193 $114 $0 $392 $1,699 $3

3.3 Other Feedwater Subsystems $1,552 $524 $472 $0 $0 $2,548 $229 $0 $555 $3,332 $6

3.4 Service Water Systems $411 $845 $2,934 $0 $0 $4,190 $409 $0 $1,380 $5,979 $11

3.5 Other Boiler Plant Systems $2,203 $854 $2,116 $0 $0 $5,173 $491 $0 $1,133 $6,796 $13

3.6 FO Supply Sys & Nat Gas $315 $596 $556 $0 $0 $1,467 $141 $0 $322 $1,930 $4

3.7 Waste Treatment Equipment $1,003 $0 $612 $0 $0 $1,615 $157 $0 $532 $2,303 $4

3.8 Misc. Power Plant Equipment $1,121 $150 $576 $0 $0 $1,847 $178 $0 $608 $2,634 $5

SUBTOTAL 3. $10,158 $7,914 $10,237 $0 $0 $28,309 $2,671 $0 $7,166 $38,146 $70

 4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $113,863 $0 $62,389 $0 $0 $176,251 $16,146 $24,460 $33,252 $250,109 $460

4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $193,046 $0 w/equip. $0 $0 $193,046 $18,712 $0 $21,176 $232,934 $429

4.4 Scrubber & Low Temperature Cooling $6,049 $4,924 $5,125 $0 $0 $16,097 $1,546 $0 $3,529 $21,172 $39

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Soot Recovery & SARU $1,845 $876 $1,731 $0 $0 $4,452 $429 $0 $976 $5,857 $11

4.8 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $6,486 $5,414 $0 $0 $11,900 $1,103 $0 $3,251 $16,253 $30

SUBTOTAL 4. $314,803 $12,285 $74,659 $0 $0 $401,747 $37,935 $24,460 $62,183 $526,325 $969
Cost and Performance Baseline for Fossil Energy Plants

158

Exhibit 3-41 Case 2 Total Plant Cost Details (Continued)

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 $74,127 $0 $62,899 $0 $0 $137,025 $13,252 $27,405 $35,536 $213,219 $392

5A.2 Elemental Sulfur Plant $10,329 $2,059 $13,326 $0 $0 $25,713 $2,498 $0 $5,642 $33,853 $62

5A.3 Mercury Removal $1,376 $0 $1,047 $0 $0 $2,423 $234 $121 $556 $3,334 $6

5A.4 Shift Reactors $9,594 $0 $3,862 $0 $0 $13,456 $1,290 $0 $2,949 $17,696 $33

5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Blowback Gas Systems $1,349 $0 $256 $0 $0 $1,605 $196 $0 $360 $2,161 $4

5A.7 Fuel Gas Piping $0 $634 $444 $0 $0 $1,078 $100 $0 $236 $1,413 $3

5A.9 HGCU Foundations $0 $642 $414 $0 $0 $1,056 $97 $0 $346 $1,498 $3

SUBTOTAL 5A. $96,775 $3,334 $82,247 $0 $0 $182,357 $17,666 $27,526 $45,625 $273,174 $503

5B CO2 COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $18,256 $0 $11,190 $0 $0 $29,446 $2,836 $0 $6,456 $38,739 $71

SUBTOTAL 5B. $18,256 $0 $11,190 $0 $0 $29,446 $2,836 $0 $6,456 $38,739 $71

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,600 $239

6.2 Syngas Expander $5,550 $0 $767 $0 $0 $6,316 $600 $0 $1,038 $7,954 $15

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $887 $982 $0 $0 $1,868 $175 $0 $613 $2,656 $5

SUBTOTAL 6. $97,576 $887 $8,331 $0 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $258

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,620 $0 $4,780 $0 $0 $38,401 $3,651 $0 $4,205 $46,257 $85

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,731 $1,235 $0 $0 $2,965 $260 $0 $645 $3,870 $7

7.4 Stack $3,376 $0 $1,268 $0 $0 $4,644 $445 $0 $509 $5,598 $10

7.9 HRSG, Duct & Stack Foundations $0 $676 $650 $0 $0 $1,326 $123 $0 $435 $1,884 $3

SUBTOTAL 7. $36,996 $2,407 $7,933 $0 $0 $47,336 $4,480 $0 $5,794 $57,610 $106

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $28,123 $0 $4,808 $0 $0 $32,931 $3,160 $0 $3,609 $39,699 $73

8.2 Turbine Plant Auxiliaries $195 $0 $447 $0 $0 $642 $63 $0 $70 $775 $1

8.3 Condenser & Auxiliaries $5,009 $0 $1,471 $0 $0 $6,480 $619 $0 $710 $7,809 $14

8.4 Steam Piping $5,006 $0 $3,522 $0 $0 $8,528 $733 $0 $2,315 $11,576 $21

8.9 TG Foundations $0 $967 $1,635 $0 $0 $2,603 $247 $0 $855 $3,704 $7

SUBTOTAL 8. $38,333 $967 $11,883 $0 $0 $51,183 $4,821 $0 $7,559 $63,564 $117
Cost and Performance Baseline for Fossil Energy Plants

159

Exhibit 3-41 Case 2 Total Plant Cost Details (Continued)

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

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $7,155 $0 $1,302 $0 $0 $8,457 $805 $0 $1,389 $10,652 $20

9.2 Circulating Water Pumps $1,856 $0 $134 $0 $0 $1,990 $168 $0 $324 $2,481 $5

9.3 Circ.Water System Auxiliaries $155 $0 $22 $0 $0 $177 $17 $0 $29 $224 $0

9.4 Circ.Water Piping $0 $6,481 $1,680 $0 $0 $8,161 $738 $0 $1,780 $10,679 $20

9.5 Make-up Water System $388 $0 $555 $0 $0 $943 $90 $0 $207 $1,240 $2

9.6 Component Cooling Water Sys $765 $915 $651 $0 $0 $2,331 $218 $0 $510 $3,060 $6

9.9 Circ.Water System Foundations $0 $2,379 $4,044 $0 $0 $6,423 $609 $0 $2,110 $9,142 $17

SUBTOTAL 9. $10,319 $9,775 $8,388 $0 $0 $28,483 $2,646 $0 $6,348 $37,477 $69

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $12,136 $6,692 $13,595 $0 $0 $32,424 $3,129 $0 $3,555 $39,109 $72

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0

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 $589 $0 $641 $0 $0 $1,229 $119 $0 $202 $1,551 $3

10.7 Ash Transport & Feed Equipment $790 $0 $190 $0 $0 $980 $91 $0 $161 $1,232 $2

10.8 Misc. Ash Handling Equipment $1,219 $1,494 $446 $0 $0 $3,160 $301 $0 $519 $3,980 $7

10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $0 $117 $11 $0 $39 $167 $0

SUBTOTAL 10. $14,734 $8,239 $14,938 $0 $0 $37,910 $3,652 $0 $4,476 $46,038 $85

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $947 $0 $937 $0 $0 $1,885 $180 $0 $206 $2,271 $4

11.2 Station Service Equipment $4,697 $0 $423 $0 $0 $5,121 $472 $0 $559 $6,152 $11

11.3 Switchgear & Motor Control $8,684 $0 $1,579 $0 $0 $10,264 $952 $0 $1,682 $12,898 $24

11.4 Conduit & Cable Tray $0 $4,034 $13,308 $0 $0 $17,342 $1,677 $0 $4,755 $23,775 $44

11.5 Wire & Cable $0 $7,708 $5,064 $0 $0 $12,772 $928 $0 $3,425 $17,125 $32

11.6 Protective Equipment $0 $686 $2,496 $0 $0 $3,182 $311 $0 $524 $4,016 $7

11.7 Standby Equipment $234 $0 $228 $0 $0 $462 $44 $0 $76 $581 $1

11.8 Main Power Transformers $17,500 $0 $144 $0 $0 $17,644 $1,334 $0 $2,847 $21,825 $40

11.9 Electrical Foundations $0 $156 $410 $0 $0 $567 $54 $0 $186 $807 $1

SUBTOTAL 11. $32,062 $12,584 $24,591 $0 $0 $69,237 $5,953 $0 $14,261 $89,451 $165

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

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 $1,126 $0 $752 $0 $0 $1,877 $178 $94 $322 $2,471 $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 $259 $0 $166 $0 $0 $425 $40 $21 $97 $583 $1

12.7 Computer & Accessories $6,005 $0 $192 $0 $0 $6,197 $569 $310 $708 $7,784 $14

12.8 Instrument Wiring & Tubing $0 $2,098 $4,288 $0 $0 $6,386 $542 $319 $1,812 $9,059 $17

12.9 Other I & C Equipment $4,014 $0 $1,949 $0 $0 $5,963 $561 $298 $1,023 $7,846 $14

SUBTOTAL 12. $11,404 $2,098 $7,347 $0 $0 $20,849 $1,889 $1,042 $3,962 $27,743 $51
Cost and Performance Baseline for Fossil Energy Plants

160

Exhibit 3-41 Case 2 Total Plant Cost Details (Continued)

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

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $109 $2,337 $0 $0 $2,447 $243 $0 $807 $3,496 $6

13.2 Site Improvements $0 $1,945 $2,585 $0 $0 $4,530 $447 $0 $1,493 $6,470 $12

13.3 Site Facilities $3,485 $0 $3,678 $0 $0 $7,163 $706 $0 $2,361 $10,230 $19

SUBTOTAL 13. $3,485 $2,054 $8,600 $0 $0 $14,140 $1,396 $0 $4,661 $20,196 $37

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 $2,377 $3,387 $0 $0 $5,764 $530 $0 $944 $7,238 $13

14.3 Administration Building $0 $882 $640 $0 $0 $1,522 $136 $0 $249 $1,906 $4

14.4 Circulation Water Pumphouse $0 $166 $88 $0 $0 $253 $22 $0 $41 $317 $1

14.5 Water Treatment Buildings $0 $600 $585 $0 $0 $1,185 $107 $0 $194 $1,486 $3

14.6 Machine Shop $0 $452 $309 $0 $0 $761 $68 $0 $124 $952 $2

14.7 Warehouse $0 $729 $471 $0 $0 $1,200 $106 $0 $196 $1,502 $3

14.8 Other Buildings & Structures $0 $437 $340 $0 $0 $777 $69 $0 $169 $1,015 $2

14.9 Waste Treating Building & Str. $0 $976 $1,865 $0 $0 $2,841 $265 $0 $621 $3,728 $7

SUBTOTAL 14. $0 $6,882 $7,834 $0 $0 $14,716 $1,340 $0 $2,628 $18,684 $34

TOTAL COST $723,574 $76,529 $303,902 $0 $0 $1,104,005 $103,905 $64,468 $200,468 $1,472,845 $2,711

Owner's Costs

Preproduction Costs

6 Months All Labor $13,488 $25

1 Month Maintenance Materials $2,998 $6

1 Month Non-fuel Consumables $384 $1

1 Month Waste Disposal $318 $1

25% of 1 Months Fuel Cost at 100% CF $1,697 $3

2% of TPC $29,457 $54

Total $48,341 $89

Inventory Capital

60 day supply of fuel and consumables at 100% CF $14,068 $26

0.5% of TPC (spare parts) $7,364 $14

Total $21,432 $39

Initial Cost for Catalyst and Chemicals $7,199 $13

Land $900 $2

Other Owner's Costs $220,927 $407

Financing Costs $39,767 $73

Total Overnight Costs (TOC) $1,811,411 $3,334

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,065,009 $3,801
Cost and Performance Baseline for Fossil Energy Plants

161

Exhibit 3-42 Case 2 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 2 - GEE Radiant 550MW IGCC w/ CO2 Heat Rate-net (Btu/kWh): 10,458

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

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 2.0 2.0

 Operator 10.0 10.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 3.0 3.0

 TOTAL-O.J.'s 16.0 16.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $6,313,507 $11.622

Maintenance Labor Cost $15,266,708 $28.103

Administrative & Support Labor $5,395,054 $9.931

Property Taxes and Insurance $29,456,896 $54.223

TOTAL FIXED OPERATING COSTS $56,432,165 $103.879

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $28,779,845 $0.00756

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water (/1000 gallons) 0 4,187 1.08 $0 $1,322,398 $0.00035

Chemicals

MU & WT Chem. (lbs) 0 24,944 0.17 $0 $1,260,554 $0.00033

Carbon (Mercury Removal) (lb) 79,786 109 1.05 $83,789 $33,516 $0.00001

COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000

Water Gas Shift Catalyst (ft3) 6,246 4.28 498.83 $3,115,855 $623,171 $0.00016

Selexol Solution (gal) 298,502 95 13.40 $3,999,401 $371,618 $0.00010

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip 2.01 131.27 $0 $77,209 $0.00002

Subtotal-Chemicals $7,199,046 $2,366,068 $0.00062

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.) 0 109 0.42 $0 $13,311 $0.00000

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 641 16.23 $0 $3,037,841 $0.00080

Subtotal Waste Disposal $0 $3,051,152 $0.00080

By-products & Emissions 0 0 0.00 $0 $0.00000

Sulfur (ton) 0 146 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $7,199,046 $35,519,462 $0.00933

Fuel (ton) 0 5,844 38.18 $0 $65,161,317 $0.01712
Cost and Performance Baseline for Fossil Energy Plants

162

3.3 CONOCOPHILLIPS E-GASTM IGCC CASES

This section contains an evaluation of plant designs for Cases 3 and 4, which are based on the 

CoP E-GasTM gasifier. Cases 3 and 4 are very similar in terms of process, equipment, scope and 

arrangement, except that Case 4 includes SGS reactors, CO2 absorption/regeneration and 

compression/transport systems. There are no provisions for CO2 removal in Case 3.

The balance of this section is organized in an analogous manner to Section 3.2:

• Gasifier Background

• Process System Description for Case 3

• Key Assumptions for Cases 3 and 4

• Sparing Philosophy for Cases 3 and 4

• Performance Results for Case 3

• Equipment List for Case 3

• Cost Estimates for Case 3

• Process and System Description, Performance Results, Equipment List, and Cost 

Estimate for Case 4

3.3.1

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 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.

Gasifier Background

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 

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. 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 
Cost and Performance Baseline for Fossil Energy Plants

163

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 gasifier originally developed by Dow is now known as the CoP EGasTM gasifier. The daily coal-handling capacity of the E-Gas 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 1,678 tonnes 

(1,850 tons) (MAF basis) for high-sulfur bituminous coal. The dry gas production rate is about 

189,724 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.

With increased power and fuel GT demand, the gasifier coal feed increases proportionately. CoP 

has indicated that the gasifier can readily handle the increased demand.

Distinguishing Characteristics - A key 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. The two-stage operation improves the efficiency, 

reduces oxygen requirements, and enables more effective operation on slurry feeds relative to a 

single stage gasifier. The fire-tube SGC used by E-Gas has a lower capital cost than a water-tube 

design, an added advantage for the CoP technology at this time. However, this experience may 

spur other developers to try fire-tube designs.

Entrained-flow gasifiers have fundamental environmental advantages over fluidized-bed and 

moving-bed gasifiers. They produce no hydrocarbon liquids, and the only solid waste is an inert 

slag.

The key 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. However, the two-stage 

operation results in a quenched syngas that is higher in CH4 content than other gasifiers. This 

becomes a disadvantage in CO2 capture cases since the CH4 passes through the SGS reactors 

without change, and is also not separated by the AGR thus limiting the amount of carbon that can 

be captured.

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.

Bituminous coals with lower inherent moisture improve the slurry concentration and reduce 

oxygen requirements. The two-stage operation reduces the negative impact of low-rank coal use 

in slurry feed, entrained-flow gasification. Low to moderate ash fusion-temperature coals are 

preferred for slagging gasifiers. Coals with high ash fusion temperatures may require flux 

addition for optimal gasification operation.
Cost and Performance Baseline for Fossil Energy Plants

164

3.3.2

In this section the overall CoP gasification process is described. The system description follows 

the BFD in 

Process Description

Exhibit 3-43 and stream numbers reference the same exhibit. The tables in 

Exhibit 3-44 provide process data for the numbered streams in the BFD.

Coal receiving and handling is common to all cases and was covered in Section 

Coal Grinding and Slurry Preparation

3.1.1. The 

receiving and handling subsystem ends at the coal silo. Coal grinding and slurry preparation is 

similar to the GEE cases but repeated here for completeness.

Coal from the coal silo is fed onto a conveyor by vibratory feeders located below each silo. The 

conveyor feeds the coal to an inclined conveyor that delivers the coal to the rod mill feed hopper. 

The feed hopper provides a surge capacity of about two hours and contains two hopper outlets. 

Each hopper outlet discharges onto a weigh feeder, which in turn feeds a rod mill. Each rod mill 

is sized to process 55 percent of the coal feed requirements of the gasifier. The rod mill grinds 

the coal and wets it with treated slurry water transferred from the slurry water tank by the slurry 

water pumps. The coal slurry is discharged through a trommel screen into the rod mill discharge 

tank, and then the slurry is pumped to the slurry storage tanks. The dry solids concentration of 

the final slurry is 63 percent. The Polk Power Station operates at a slurry concentration of 62-68 

percent using bituminous coal and CoP presented a paper showing the slurry concentration of 

Illinois No. 6 coal as 63 percent [58].

The coal grinding system is equipped with a dust suppression system consisting of water sprays 

aided by a wetting agent. The degree of dust suppression required depends on local 

environmental regulations. All of the tanks are equipped with vertical agitators to keep the coal 

slurry solids suspended.

The equipment in the coal grinding and slurry preparation system is fabricated of materials 

appropriate for the abrasive environment present in the system. The tanks and agitators are 

rubber lined. The pumps are either rubber-lined or hardened metal to minimize erosion. Piping 

is fabricated of HDPE.

This plant utilizes two gasification trains to process a total of 5,007 tonnes/day (5,519 TPD) of 

Illinois No. 6 coal. Each of the 2 x 50 percent gasifiers operate at maximum capacity. The EGasTM two-stage coal gasification technology features an oxygen-blown, entrained-flow, 

refractory-lined gasifier with continuous slag removal. About 78 percent of the total slurry feed 

is fed to the first (or bottom) stage of the gasifier. The air separation plant supplies 3,711 

tonnes/day (4,090 TPD) of 95 percent oxygen to the gasifiers (stream 5) and the Claus plant 

(stream 3). All oxygen for gasification is fed to this stage of the gasifier at a pressure of 4.2 MPa 

(615 psia). This stage is best described as a horizontal cylinder with two horizontally opposed 

burners. The highly exothermic gasification/oxidation reactions take place rapidly at 

temperatures of 1,316 to 1,427°C (2,400 to 2,600°F). The hot raw gas from the first stage enters 

the second (top) stage, which is a vertical cylinder perpendicular to the first stage. The 

remaining 22 percent of coal slurry is injected into this hot raw gas. The endothermic 

gasification/devolatilization reaction in this stage reduces the final gas temperature to about 

1,038°C (1,900°F). Total slurry to both stages is shown as stream 7 in 

Gasification

Exhibit 3-43.
Cost and Performance Baseline for Fossil Energy Plants

165

Exhibit 3-43 Case 3 Block Flow Diagram, E-GasTM IGCC without CO2 Capture
Cost and Performance Baseline for Fossil Energy Plants

166

Exhibit 3-44 Case 3 Stream Table, E-GasTM IGCC without CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12

V-L Mole Fraction

Ar 0.0092 0.0241 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0078 0.0078 0.0096

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0465 0.0465 0.0575

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3011 0.3011 0.3727

CO2 0.0003 0.0083 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1556 0.1559 0.1929

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0003 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2724 0.2724 0.3372

H2O 0.0099 0.2163 0.0000 0.0003 0.0000 1.0000 0.0000 0.9968 0.0000 0.1889 0.1885 0.0015

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0002 0.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0072 0.0075 0.0092

N2 0.7732 0.5460 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0000 0.0157 0.0157 0.0194

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0032 0.0000 0.0045 0.0045 0.0000

O2 0.2074 0.2054 0.9504 0.0054 0.9504 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

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 18,976 916 111 17,427 4,694 3,766 0 4,758 0 21,817 21,817 17,626

V-L Flowrate (kg/hr) 547,576 24,820 3,567 489,004 151,056 67,848 0 85,707 0 459,732 459,732 384,240

Solids Flowrate (kg/hr) 0 0 0 0 0 0 208,634 0 21,295 0 0 0

Temperature (°C) 15 20 32 93 32 343 15 149 1,038 186 186 35

Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.10 0.10 5.79 4.24 4.07 4.00 3.83

Enthalpy (kJ/kg)A 30.23 36.92 26.67 92.52 26.67 0.00 --- 567.36 --- 673.10 672.88 39.55

Density (kg/m3) 1.2 1.6 11.0 24.4 11.0 20.1 --- 862.4 --- 22.7 22.3 33.0

V-L Molecular Weight 28.857 27.090 32.181 28.060 32.181 18.015 --- 18.012 --- 21.073 21.073 21.799

V-L Flowrate (lbmol/hr) 41,834 2,020 244 38,420 10,348 8,303 0 10,490 0 48,098 48,098 38,859

V-L Flowrate (lb/hr) 1,207,199 54,719 7,864 1,078,070 333,021 149,578 0 188,951 0 1,013,536 1,013,536 847,104

Solids Flowrate (lb/hr) 0 0 0 0 0 0 459,958 0 46,947 0 0 0

Temperature (°F) 59 69 90 199 90 650 59 300 1,900 367 367 95

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 740.0 14.7 840.0 615.0 590.0 580.0 555.0

Enthalpy (Btu/lb)A 13.0 15.9 11.5 39.8 11.5 --- 243.9 --- 289.4 289.3 17.0

Density (lb/ft3) 0.076 0.098 0.687 1.521 0.687 1.257 --- 53.837 --- 1.416 1.391 2.061

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Fossil Energy Plants

167

Exhibit 3-44 Case 3 Stream Table (Continued)

13 14 15 16 17 18 19 20 21 22 23 24 25

V-L Mole Fraction

Ar 0.0095 0.0098 0.0085 0.0085 0.0000 0.0000 0.0041 0.0055 0.0092 0.0092 0.0087 0.0087 0.0000

CH4 0.0555 0.0576 0.0500 0.0500 0.0002 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.3597 0.3734 0.3241 0.3241 0.0010 0.0000 0.0848 0.0061 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.2137 0.1931 0.1676 0.1676 0.7537 0.0000 0.4983 0.7790 0.0003 0.0003 0.0803 0.0803 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0003 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.3299 0.3425 0.2973 0.2973 0.0009 0.0000 0.0209 0.1311 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0015 0.0015 0.1333 0.1333 0.0000 0.0000 0.3350 0.0018 0.0099 0.0099 0.0860 0.0860 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2S 0.0090 0.0000 0.0000 0.0000 0.2443 0.0000 0.0014 0.0043 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0213 0.0221 0.0192 0.0192 0.0000 0.0000 0.0537 0.0723 0.7732 0.7732 0.7250 0.7250 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.2074 0.1000 0.1000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0013 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 18,275 17,601 20,276 20,276 674 0 873 649 110,253 4,410 137,246 137,246 40,181

V-L Flowrate (kg/hr) 408,330 380,350 428,548 428,548 27,980 0 28,108 24,090 3,181,557 127,262 3,971,848 3,971,848 723,874

Solids Flowrate (kg/hr) 0 0 0 0 0 5,215 0 0 0 0 0 0 0

Temperature (°C) 34 45 143 193 45 175 232 38 15 432 588 132 561

Pressure (MPa, abs) 3.79 3.76 3.21 3.2 3.757 0.409 0.406 5.512 0.101 1.619 0.105 0.105 12.512

Enthalpy (kJ/kg)A 36.82 55.08 489.40 569.9 -0.670 --- 731.470 -6.625 30.227 463.785 783.868 272.294 3,500.624

Density (kg/m3) 33.7 31.0 19.7 17.3 73.5 5,285.4 3.1 96.3 1.2 7.9 0.4 0.9 35.2

V-L Molecular Weight 22.344 21.610 21.135 21 41.529 --- 32.209 37.141 28.857 28.857 28.940 28.940 18.015

V-L Flowrate (lbmol/hr) 40,289 38,804 44,702 44,702 1,485 0 1,924 1,430 243,066 9,723 302,576 302,576 88,584

V-L Flowrate (lb/hr) 900,213 838,528 944,788 944,788 61,685 0 61,967 53,110 7,014,133 280,565 8,756,427 8,756,427 1,595,870

Solids Flowrate (lb/hr) 0 0 0 0 0 11,497 0 0 0 0 0 0 0

Temperature (°F) 94 112 290 380 112 347 450 100 59 810 1,091 270 1,041

Pressure (psia) 550.0 545.0 465.0 460.0 545.0 59.3 58.9 799.5 14.7 234.9 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 15.8 23.7 210.4 245.0 -0.3 --- 314.5 -2.8 13.0 199.4 337.0 117.1 1,505.0

Density (lb/ft3) 2.105 1.938 1.230 1 4.586 329.954 0.195 6.012 0.076 0.495 0.026 0.056 2.194
Cost and Performance Baseline for Fossil Energy Plants

168

The syngas produced by the CoP gasifier is higher in methane content than either the GEE or 

Shell gasifier. The two stage design allows for improved cold gas efficiency (CGE) and lower 

oxygen consumption, but the quenched second stage allows some CH4 to remain. The syngas 

CH4 concentration exiting the gasifier in Case 3 is 4.3 vol% (compared to 0.10 vol% in Case 1 

[GEE] and 0.001 vol% in Case 5 [Shell]). The relatively high CH4 concentration impacts CO2

capture efficiency as discussed further in Section 3.3.8.

The raw syngas, less than 1,038°C (1,900°F), from the second stage of the gasifier is cooled to 

316°C (600°F) in the waste heat recovery (SGC) unit, which consists of a fire-tube boiler and 

convective superheating and economizing sections. 554,830 kg/hr (1,223,171 lb/hr) of HP 

saturated steam is raised as a result of the raw gas cooling. Fire-tube boilers cost markedly less 

than comparable duty water-tube boilers. This is because of the large savings in high-grade steel 

associated with containing the hot HP syngas in relatively small tubes.

Raw Gas Cooling/Particulate Removal

The coal ash is converted to molten slag, which flows down through a tap hole. The molten slag 

is quenched in water and removed through a proprietary continuous-pressure letdown/dewatering 

system (stream 9). Char is produced in the second gasifier stage and is captured and recycled to 

the hotter first stage to be gasified.

The cooled gas from the SGC is cleaned of remaining particulate via a cyclone collector 

followed by a ceramic candle filter. Recycled syngas is used as the pulse gas to clean the candle 

filters. The recovered fines are pneumatically returned to the first stage of the gasifier. The 

combination of recycled char and recycled particulate results in high overall carbon conversion 

(99.2 percent used in this study). 

Following particulate removal, additional heat is removed from the syngas to raise saturated IP 

steam at 0.4 MPa (65 psia). In this manner the syngas is cooled to 232°C (450°F) prior to the 

syngas scrubber.

Syngas exiting the second of the two low temperature heat exchangers passes to a syngas 

scrubber where a water wash is used to remove chlorides, SO2, NH3, and particulate. The syngas 

exits the scrubber saturated at 169°C (337°F).

Syngas Scrubber/Sour Water Stripper

The sour water stripper removes NH3, SO2, and other impurities from the scrubber and other 

waste streams. The stripper consists of a sour drum that accumulates sour water from the gas 

scrubber and condensate from SGCs. Sour water from the drum flows to the sour stripper, which 

consists of a packed column with a steam-heated reboiler. Sour gas is stripped from the liquid 

and sent to the SRU. Remaining water is sent to wastewater treatment.

Syngas exiting the scrubber is reheated to 186°C (367°F) by using HP steam from the HRSG 

evaporator prior to entering a COS hydrolysis reactor (stream 10). About 99.5 percent of the 

COS is converted to CO2 and H2O (Section 

COS Hydrolysis, Mercury Removal and Acid Gas Removal

3.1.5). The gas exiting the COS reactor (stream 11) 

passes through a series of heat exchangers and KO drums to lower the syngas temperature to 

35°C (95°F) and to separate entrained water. The cooled syngas (stream 12) then passes through 

a carbon bed to remove 95 percent of the Hg (Section 3.1.4).
Cost and Performance Baseline for Fossil Energy Plants

169

Cool, particulate-free syngas (stream 13) enters the absorber unit at approximately 3.8 MPa 

(550 psia) and 34°C (94°F). In the absorber, H2S is preferentially removed from the fuel gas 

stream by contact with MDEA. The absorber column is operated at 44°C (112°F) by 

refrigerating the lean MDEA solvent. The lower temperature is required to achieve an outlet H2S 

concentration of less than 30 ppmv in the sweet syngas. The stripper acid gas stream (stream 

17), consisting of 24 percent H2S and 75 percent CO2, is sent to the Claus unit. The acid gas is 

combined with the sour water stripper off gas and introduced into the Claus plant burner section.

Acid gas from the MDEA unit is preheated to 232°C (450°F). A portion of the acid gas along 

with all of the sour gas from the stripper and oxygen from the ASU are fed to the Claus furnace. 

In the furnace, H2S is catalytically oxidized to SO2 at a furnace temperature of 1,316°C 

(2,400°F), which must be maintained in order to thermally decompose all of the NH3 present in 

the sour gas stream.

Claus Unit

Following the thermal stage and condensation of sulfur, two reheaters and two sulfur converters 

are used to obtain a per-pass H2S conversion of approximately 99.5 percent. The Claus Plant tail 

gas is hydrogenated and recycled back to the gasifier (stream 20). In the furnace waste heat 

boiler, 13,866 kg/hr (30,568 lb/hr) of 3.0 MPa (430 psia) steam is generated. This steam is used 

to satisfy all Claus process preheating and reheating requirements as well as to provide some 

steam to the medium-pressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) 

steam for the LP steam header and IP steam at 2.9 MPa (415 psig).

A flow rate of 5,215 kg/hr (11,497 lb/hr) of elemental sulfur (stream 18) is recovered from the 

fuel gas stream. This value represents an overall sulfur recovery efficiency of 99.7 percent.

Clean syngas exiting the MDEA absorber (stream 14) is partially humidified (stream 15) because 

there is not sufficient nitrogen from the ASU to provide the level of dilution required to reach the 

target syngas heating value. The moisturized syngas stream is reheated (stream 16), further 

diluted with nitrogen from the ASU (stream 4) and enters the advanced F Class CT burner. The 

CT compressor provides combustion air to the burner and also 19 percent of the total ASU air 

requirement (stream 22). The exhaust gas exits the CT at 588°C (1,091°F) (stream 23) and 

enters the HRSG where additional heat is recovered until the FG exits the HRSG at 132°C 

(270°F) (stream 24) and is discharged through the plant stack. The steam raised in the HRSG is 

used to power an advanced, commercially available steam turbine using a 12.4 

MPa/561°C/561°C (1800 psig/1041°F/1041°F) steam cycle.

Power Block

The elevated pressure ASU was described in Section 

Air Separation Unit

3.1.2. In Case 3, the ASU is designed to 

produce a nominal output of 3,711 tonnes/day (4,091 TPD) of 95 mol% O2 for use in the gasifier 

(stream 5) and Claus plant (stream 3). The plant is designed with two production trains. The air 

compressor is powered by an electric motor. Approximately 11,736 tonnes/day (12,937 TPD) of 

nitrogen are also recovered, compressed, and used as dilution in the GT combustor (stream 4). 

About 4 percent of the GT air is used to supply approximately 19 percent of the ASU air 

requirements (stream 22).
Cost and Performance Baseline for Fossil Energy Plants

170

Balance of plant items were covered in Sections 

Balance of Plant

3.1.9, 3.1.10, and 3.1.11.

3.3.3

System assumptions for Cases 3 and 4, CoP IGCC with and without CO2 capture, are compiled 

in 

Key System Assumptions

Exhibit 3-45.

The balance of plant assumptions are common to all cases and were presented previously in 

Balance of Plant – Cases 3 and 4

Exhibit 3-16.

3.3.4

The sparing philosophy for Cases 3 and 4 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.

Sparing Philosophy

The plant design consists of the following major subsystems:

• Two ASUs (2 x 50%)

• Two trains of slurry preparation and slurry pumps (2 x 50%)

• Two trains of gasification, including gasifier, SGC, cyclone, and candle filter (2 x 50%). 

• Two trains of syngas clean-up process (2 x 50%).

• Two trains of refrigerated MDEA AGR in Case 3 and two-stage Selexol in Case 4 

(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%).
Cost and Performance Baseline for Fossil Energy Plants

171

Exhibit 3-45 CoP IGCC Plant Study Configuration Matrix

Case 3 4

Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O2:Coal Ratio, kg O2/kg dry coal 0.81 0.88

Carbon Conversion, % 99.2 99.2

Syngas HHV at Gasifier Outlet, 

kJ/Nm3 (Btu/scf) 8,319 (223) 7,021 (189)

Steam Cycle, MPa/°C/°C 

(psig/°F/°F)

12.4/561/561

(1800/1041/1041)

12.4/534/534

(1800/994/994)

Condenser Pressure, mm Hg 

(in Hg) 51 (2.0) 51 (2.0)

CT 2x Advanced F Class

(232 MW output each)

2x Advanced F Class

(232 MW output each)

Gasifier Technology CoP E-GasTM CoP E-GasTM

Oxidant 95 vol% Oxygen 95 vol% Oxygen

Coal Illinois No. 6 Illinois No. 6

Coal Slurry Solids Content, % 63 63

COS Hydrolysis Yes Occurs in SGS

SGS No Yes

H2S Separation Refrigerated MDEA Selexol 1st Stage

Sulfur Removal, % 99.7 99.9

Sulfur Recovery

Claus Plant with Tail Gas 

Recycle to Gasifier/ 

Elemental Sulfur

Claus Plant with Tail Gas 

Recycle to Gasifier/ 

Elemental Sulfur

Particulate Control

Cyclone, Candle Filter, 

Scrubber, and AGR 

Absorber

Cyclone, Candle Filter, 

Scrubber, and AGR 

Absorber

Mercury Control Carbon Bed Carbon Bed

NOx Control

MNQC (LNB), N2

Dilution and 

Humidification

MNQC (LNB), N2 Dilution 

and Humidification

CO2 Separation N/A Selexol 2nd Stage

Overall CO2 Capture N/A 90.4%

CO2 Sequestration N/A Off-site Saline Formation
Cost and Performance Baseline for Fossil Energy Plants

172

3.3.5

The plant produces a net output of 625 MWe at a net plant efficiency of 39.7 percent (HHV 

basis). 

Case 3 Performance Results

Overall performance for the entire plant is summarized in Exhibit 3-46, 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, 

accounts for approximately 5 percent of the auxiliary load, and the BFW pumps account for an 

additional 3.9 percent. All other individual auxiliary loads are less than 3.5 percent of the total.
Cost and Performance Baseline for Fossil Energy Plants

173

Exhibit 3-46 Case 3 Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Gas Turbine Power 464,000

Sweet Gas Expander Power 0

Steam Turbine Power 274,200

TOTAL POWER, kWe 738,200

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 460

Coal Milling 2,150

Sour Water Recycle Slurry Pump 180

Slag Handling 1,100

Air Separation Unit Auxiliaries 1,000

Air Separation Unit Main Air Compressor 46,700

Oxygen Compressor 7,920

Nitrogen Compressors 29,910

Boiler Feedwater Pumps 4,410

Condensate Pump 240

Syngas Recycle Compressor 810

Circulating Water Pump 3,880

Ground Water Pumps 400

Cooling Tower Fans 2,010

Scrubber Pumps 320

Acid Gas Removal 3,150

Gas Turbine Auxiliaries 1,000

Steam Turbine Auxiliaries 100

Claus Plant/TGTU Auxiliaries 250

Claus Plant TG Recycle Compressor 1,610

Miscellaneous Balance of Plant2 3,000

Transformer Losses 2,540

TOTAL AUXILIARIES, kWe 113,140

NET POWER, kWe 625,060

Net Plant Efficiency, % (HHV) 39.7

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,057 (8,585)

CONDENSER COOLING DUTY 106 kJ/hr (106 Btu/hr) 1,414 (1,340)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 208,634 (459,958)

Thermal Input1, kWt 1,572,582

Raw Water Withdrawal, m3/min (gpm) 16.5 (4,367)

Raw Water Consumption, m3/min (gpm) 13.1 (3,465)

1 - HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)

2 - Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Fossil Energy Plants

174

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 

2.4. A summary of the plant air emissions for Case 3 is presented in 

Environmental Performance

Exhibit 3-47. 

Exhibit 3-47 Case 3 Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

80% capacity factor

kg/MWh

(lb/MWh)

SO2 0.005 (0.012) 200 (220) 0.039 (.09)

NOx 0.026 (0.060) 1,017 (1,122) 0.197 (.434)

Particulates 0.003 (0.0071) 121 (133) 0.023 (.052)

Hg 2.46E-7 (5.71E-7) 0.010 (0.011) 1.88E-6 (4.15E-6)

CO2 85.7 (199.2) 3,398,362 (3,746,053) 657 (1,448)

CO2

1 776 (1,710)

1 CO2 emissions based on net power instead of gross power

The low level of SO2 in the plant emissions is achieved by capture of the sulfur in the gas by the 

refrigerated Coastal SS Specialty Amine (SS Amine) AGR process. The AGR process removes 

99.7 percent of the sulfur compounds in the fuel gas down to a level of less than 30 ppmv. This 

results in a concentration in the FG of less than 4 ppmv. The H2S-rich regeneration gas from the 

AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is 

hydrogenated to convert all sulfur species to H2S and then recycled back to the gasifier, thereby 

eliminating the need for a tail gas treatment unit.

NOx emissions are limited by the use of nitrogen dilution (primarily) and humidification (to a 

lesser extent) to 15 ppmvd (as NO2 @ 15 percent O2). Ammonia in the syngas is removed with 

process condensate prior to the low-temperature AGR process and destroyed in the Claus plant 

burner. This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone 

and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

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 plant is shown in Exhibit 3-48. The carbon input to the plant consists 

of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since 

the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned 

carbon in the slag and CO2 in the stack gas and ASU vent gas. 
Cost and Performance Baseline for Fossil Energy Plants

175

Exhibit 3-48 Case 3 Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 132,993 (293,199) Slag 1,064 (2,346)

Air (CO2) 507 (1,118) Stack Gas 132,344 (291,769)

ASU Vent 92 (202)

CO2 Product 0 (0)

Total 133,500 (294,317) Total 133,500 (294,317)

Exhibit 3-49 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur emitted in the 

stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 3-49 Case 3 Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 5,229 (11,528) Elemental Sulfur 5,215 (11,497)

Stack Gas 14 (31)

CO2 Product 0 (0)

Total 5,229 (11,528) Total 5,229 (11,528)

Exhibit 3-50 shows the overall water balance for the plant. The water balance was explained in

Case 1 [GEE], but is also presented here for completeness.

Water demand represents the total amount of water required for a particular process. Some water 

is recovered within the process, primarily as syngas condensate, and is re-used as internal 

recycle. The difference between demand and recycle is raw water withdrawal. Raw water 

withdrawal is defined as the water removed from the ground or diverted from a surface-water 

source for use in the plant and was assumed to be provided 50 percent by a POTW and 50 

percent from groundwater. Raw water withdrawal can be represented by the water metered from 

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

tower makeup, BFW makeup, quench system makeup, and slag handling makeup. The 

difference between water withdrawal and process water discharge is defined as water 

consumption and can be represented by the portion of the raw water withdrawn that is 

evaporated, transpired, incorporated into products or otherwise not returned to the water source 

from which it was withdrawn. Water consumption represents the net impact of the plant process 

on the water source balance.
Cost and Performance Baseline for Fossil Energy Plants

176

Exhibit 3-50 Case 3 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)

Slag Handling 0.46 (122) 0.46 (122) 0.0 (0) 0.0 (0) 0.0 (0)

Slurry Water 1.43 (378) 0.99 (263) 0.4 (115) 0.0 (0) 0.4 (115)

Quench/Wash 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier 0.8 (222) 0.8 (222) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.01 (4) -0.01 (-4)

Condenser Makeup

Gasifier Steam

Shift Steam

GT Steam Dilution

BFW Makeup

1.3 (354)

1.1 (299)

0.21 (55)

0.0 (0) 1.3 (354)

1.1 (299)

0.21 (55)

0.0 (0) 1.3 (354)

Cooling Tower

BFW Blowdown

SWS Blowdown

SWS Excess Water

Humidifier Tower 

Blowdown

15.1 (3,991) 0.35 (93)

0.21 (55)

0.15 (38)

14.8 (3,898)

-0.21 (-55)

-0.15 (-38)

3.4 (897) 11.4 (3,000)

Total 19.2 (5,067) 2.65 (700) 16.5 (4,367) 3.4 (901) 13.1 (3,465)

Heat and mass balance diagrams are shown for the following subsystems in 

Heat and Mass Balance Diagrams

Exhibit 3-51 through

Exhibit 3-53:

• Coal gasification and ASU

• Syngas cleanup, sulfur recovery, and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is provided in tabular form in Exhibit 3-54. The power out is 

the combined CT and steam turbine power prior to generator losses. The power at the generator 

terminals (shown in Exhibit 3-46) is calculated by multiplying the power out by a combined 

generator efficiency of 98.3 percent.
Cost and Performance Baseline for Fossil Energy Plants

177

Exhibit 3-51 Case 3 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 3

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 3

COP GASIFIER

ASU AND GASIFICATION

DWG. NO.

BB-HMB-CS-3-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

1 OF 3

Ambient Air

Four Stage Air

Compressor

Elevated

Pressure

ASU

Four Stage N2

Compressor

Four Stage O2

Compressor

ASU 

Vent

Water

Steam

Gross Plant Power: 738 MWe

Auxiliary Load: 113 MWe

Net Plant Power: 625 MWe

Net Plant Efficiency, HHV: 39.7%

Net Plant Heat Rate: 8,585 BTU/KWe

N2 to GT Combustor 1,207,199 W

59.0 T

14.7 P

13.0 H

333,021 W

90.0 T

125.0 P

11.5 H

333,021 W

223.0 T

740.0 P

37.5 H

To Claus Plant

7,864 W

90.0 T

125.0 P

11.5 H

54,719 W

68.5 T

16.4 P

15.9 H

957,085 W

90.0 T

56.4 P

14.2 H

133,998 W

50.0 T

182.0 P

2.9 H

5

1

3

2

Candle Filter

Slurry Mix 

Tank

E-Gas TM

Gasifier

Milled Coal

Water

Slag

Cyclones

Saturated Steam to HRSG

BFW from HRSG

Blowdown to Flash Tank

Fire

Tube

Boiler

Steam

Drum

459,958 W

59.0 T

14.7 P

188,951 W

300.0 T

840.0 P

243.9 H

46,947 W

1,900.0 T

615.0 P

1,241,593 W

600.0 T

605.0 P

422.3 H

1,078,070 W

389.0 T

384.0 P

88.2 H

Fuel Gas

9

648,909 W

161.6 T

840.0 P

3,007.7 H

1,241,593 W

600.0 T

605.0 P

422.3 H

1,241,593 W

1,833.8 T

615.0 P

968.9 H

144,019 W

158.8 T

800.0 P

36.9 H

N2 Diluent

Preheater

1,241,593 W

450.0 T

600.0 P

361.4 H

100.0 T

189.5 P

18.0 H

7

8

Steam

149,578 W

650.0 T

740.0 P

1,316.8 H

Syngas Recycle

Compressor

144,019 W

105.0 T

600.0 P

18.8 H

4

Air From GT

Compressor

280,565 W

220.0 T

224.9 P

50.9 H

280,565 W

809.8 T

234.9 P

199.4 H

IP BFW

Raw Syngas 

to Scrubber

1,061,562 W

450.0 T

600.0 P

361.4 H

1,078,070 W

199.0 T

384.0 P

39.8 H

22

6
Cost and Performance Baseline for Fossil Energy Plants

178

Exhibit 3-52 Case 3 Syngas Cleanup Heat and Mass Balance Schematic

Mercury 

Removal

Knock

Out 

Drum

Raw Syngas

Syngas

Preheater

Fuel Gas to GT

Sour

Drum

To Water Treatment

Makeup Water

Claus Plant

Tail 

Gas

Furnace

Catalytic

Reactor

Beds

Sulfur

Knock Out

From 

ASU

Syngas

Coolers

Sour

Stripper

Syngas

Scrubber

Condensate 

to Deaerator

Condensate

1,061,562 W

450.0 T

600.0 P

361.4 H

1,013,536 W

336.7 T

595.0 P

284.4 H

900,213 W

93.7 T

550.0 P

15.8 H

944,788 W

290.3 T

465.0 P

210.4 H

61,685 W

112.2 T

545.0 P

944,788 W

380.0 T

460.0 P

245.0 H

11,497 W 61,967 W

450.0 T

58.9 P

314.5 H

3,916 W

191.1 T

65.0 P

190.1 H

7,864 W

90.0 T

125.0 P

11.5 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 3

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 3

COP GASIFIER

GAS CLEANUP SYSTEM

DWG. NO.

BB-HMB-CS-3-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

2 OF 3

Sour Gas

Sour Water

Water

Steam

Gross Plant Power: 738 MWe

Auxiliary Load: 113 MWe

Net Plant Power: 625 MWe

Net Plant Efficiency, HHV: 39.7%

Net Plant Heat Rate: 8,585 BTU/KWe

14

18

12

16

20

CO2

Tailgas

53,768 W

120.0 T

56.8 P

33.1 H

847,104 W

95.2 T

555.0 P

17.0 H

8,858 W

118.5 T

56.8 P

44.8 H

3

53,110 W

100.0 T

799.5 P

Humidification 15

838,528 W

112.2 T

545.0 P

23.7 H

Claus Oxygen

Preheater

7,864 W

450.0 T

124.5 P

91.9 H

COS Hydrolysis

1,013,536 W

367.0 T

580.0 P

289.3 H

COS Hydrolysis

Preheater

1,013,536 W

366.7 T

590.0 P

289.4 H

10 11

19

Clean Gas Acid Gas

13

AGR- MDEA

17

Tail Gas

Compressor

Hydrogenation

And Tail Gas

Cooling
Cost and Performance Baseline for Fossil Energy Plants

179

Exhibit 3-53 Case 3 Combined Cycle Power Generation Heat and Mass Balance Schematic

HRSG

HP

Turbine

IP

Turbine

Nitrogen Diluent

Intake

Ambient Air

Steam Seal 

Regulator

Gasifier Steam

Ip Extraction Steam

To 250 PSIA Header

Blowdown

Flash

To WWT

Gland

Steam

Condenser

Condensate to Gasification Island

HP BFW to Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP 

Turbine

Stack

Compressor Expander

Fuel Gas

Deaerator

IP BFW

Generator

Generator

Condensate

Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class 

Gas Turbine

MP Flash Bottoms

LP Flash Tops

1,078,070 W

199.0 T

384.0 P

39.8 H

7,014,133 W

59.0 T

14.7 P

13.0 H

1,603,037 W

101.1 T

1.0 P

69.1 H

8,756,427 W

269.9 T

15.2 P

117.1 H

944,788 W

380.0 T

460.0 P

245.0 H

8,756,427 W

1,091.1 T

15.2 P

337.0 H

LP

Process

Header

From Gasifier

Island Preheating

To Claus

LP BFW

1,595,870 W

1,041.1 T

1,814.7 P

1,505.0 H

9,989 W

298.0 T

65.0 P

1,179.0 H

1,623,826 W

278.8 T

2,250.7 P

252.3 H

27,956 W

585.0 T

2,000.7 P

593.3 H

1,414,204 W

539.6 T

65.0 P

1,301.6 H

1,603,037 W

103.2 T

120.0 P

71.4 H

1,603,037 W

235.0 T

105.0 P

203.7 H

1,400 W

660.4 T

65.0 P

1,361.1 H

1,400 W

212.0 T

14.7 P

179.9 H

IP Pump NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 3

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 3

COP GASIFIER

POWER BLOCK SYSTEM

DWG. NO.

BB-HMB-CS-3-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

Gross Plant Power: 738 MWe

Auxiliary Load: 113 MWe

Net Plant Power: 625 MWe

Net Plant Efficiency, HHV: 39.7%

21 Net Plant Heat Rate: 8,585 BTU/KWe

23

25

16

24

Flue Gas

HOT WELL

CONDENSER Make-up

176,912 W

59.0 T

14.7 P

27.1 H

8,828 W

700.3 T

501.4 P

1,357.3 H

9,522 W

660.4 T

65.0 P

1,361.1 H

25,722 W

896.4 T

280.0 P

1,472.0 H

781 W

1,041.1 T

1,814.7 P

1,505.0 H

1,313 W

539.6 T

65.0 P

1,301.6 H

Air Extraction

280,565 W

809.8 T

234.9 P

199.4 H

22
Cost and Performance Baseline for Fossil Energy Plants

180

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

181

Exhibit 3-54 Case 3 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,661 (5,366) 4.7 (4.5) 5,666 (5,370)

ASU Air 16.6 (15.7) 17 (16)

GT Air 96.2 (91.2) 96 (91)

Water 62.2 (58.9) 62 (59)

Auxiliary Power 407 (386) 407 (386)

TOTAL 5,661 (5,366) 179.6 (170.2) 407 (386) 6,248 (5,922)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0.9 (0.9) 1 (1)

Slag 35 (33) 23.9 (22.7) 59 (56)

Sulfur 48 (46) 0.6 (0.6) 49 (46)

CO2

Cooling Tower 

Blowdown 25.2 (23.9) 25 (24)

HRSG Flue Gas 1,082 (1,025) 1,082 (1,025)

Condenser 1,415 (1,342) 1,415 (1,342)

Non-Condenser 

Cooling Tower Loads* 411 (389) 411 (389)

Process Losses** 549 (521) 549 (521)

Power 2,658 (2,519) 2,658 (2,519)

TOTAL 83 (79) 3,507 (3,324) 2,658 (2,519) 6,248 (5,922)

* Includes ASU compressor intercoolers, CO2 compressor intercoolers, sour water stripper condenser, syngas 

cooler (low level heat rejection) and extraction air cooler. 

** Calculated by difference to close the energy balance.
Cost and Performance Baseline for Fossil Energy Plants

182

3.3.6

Major equipment items for the CoP gasifier with no CO2 capture are shown in the following 

tables. The accounts used in the equipment list correspond to the account numbers used in the 

cost estimates in Section 

Case 3 - Major Equipment List

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.

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 45 tonne (50 ton) 2 1

9 Feeder Vibratory 172 tonne/hr (190 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 345 tonne/hr (380 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 172 tonne (190 ton) 2 0

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0) 2 0

14 As-Fired Coal Sampling 

System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 345 tonne/hr (380 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 345 tonne/hr (380 tph) 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 726 tonne (800 ton) 3 0
Cost and Performance Baseline for Fossil Energy Plants

183

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 73 tonne/h (80 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 227 tonne/h (250 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 1 0

4 Weigh Feeder Belt 118 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 118 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank 

with Agitator Field erected 283,227 liters (74,820 gal) 2 0

7 Slurry Water Pumps Centrifugal 795 lpm (210 gpm) 2 1

8 Trommel Screen Coarse 163 tonne/h (180 tph) 2 0

9 Rod Mill Discharge Tank with 

Agitator Field erected 370,519 liters (97,880 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,028 lpm (800 gpm) 2 2

11 Slurry Storage Tank with 

Agitator Field erected 1,111,406 liters (293,600 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,057 lpm (1,600 gpm) 2 2

13 Slurry Product Pumps Positive 

displacement 3,028 lpm (800 gpm) 2 2
Cost and Performance Baseline for Fossil Energy Plants

184

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 1,082,628 liters (286,000 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 478,994 kg/hr (1,056,000 lb/hr) 2 0

4 Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

8,101 lpm @ 27 m H2O

(2,140 gpm @ 90 ft H2O) 2 1

5 High Pressure 

Feedwater Pump No. 1

Barrel type, multi-stage, 

centrifugal

HP water: 7,041 lpm @ 1,859 m 

H2O (1,860 gpm @ 6,100 ft 

H2O)

2 1

6 High Pressure 

Feedwater Pump No. 2

Barrel type, multi-stage, 

centrifugal

IP water: 492 lpm @ 223 m H2O 

(130 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 Cylce Cooling 

Heat Exchangers Plate and frame 240 GJ/hr (228 MMBtu/hr) each 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 86,307 lpm @ 21 m H2O(22,800 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

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

4,240 lpm @ 18 m H2O

(1,120 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) 3 1

16 Filtered Water Pumps Stainless steel, single 

suction

1,628 lpm @ 49 m H2O

(430 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 787,366 liter (208,000 gal) 2 0

18 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 303 lpm (80 gpm) 2 0

19 Liquid Waste Treatment 

System 10 years, 24-hour storm 1 0
Cost and Performance Baseline for Fossil Energy Plants

185

ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW 

TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier

Pressurized two-stage, 

slurry-feed entrained 

bed

2,722 tonne/day, 4.2 MPa

(3,000 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler Fire-tube boiler 309,804 kg/hr (683,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 309,804 kg/hr (683,000 lb/hr) 

Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with 

pulse-jet cleaning metallic filters 2 0

5

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 264,898 kg/hr (584,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with 

condensate drain 212,735 kg/hr (469,000 lb/hr) 8 0

7 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator

212,281 kg/hr, 35°C, 3.9 MPa

(468,000 lb/hr, 95°F, 560 psia) 2 0

8 Saturation Water 

Economizers Shell and tube 91 GJ/hr (86 MMBtu/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 235,868 kg/hr, 143°C, 3.3 MPa

(520,000 lb/hr, 290°F, 480 psia) 2 0

10 Saturator Water Pump Centrifugal 2,271 lpm @ 12 m H2O

(600 gpm @ 40 ft H2O) 2 2

11 Synthesis Gas Reheater Shell and tube 209,106 kg/hr (461,000 lb/hr) 2 0

12 Flare Stack

Self-supporting, carbon 

steel, stainless steel top, 

pilot ignition

264,898 kg/hr (584,000 lb/hr) 

syngas

2 0

13 ASU Main Air 

Compressor Centrifugal, multi-stage 4,134 m3/min @ 1.3 MPa(146,000 scfm @ 190 psia) 2 0

14 Cold Box Vendor design 1,996 tonne/day (2,200 tpd) of 

95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi-stage

1,019 m3/min (36,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 5.1 MPa (740 psia)

2 0

16 Primary Nitrogen 

Compressor Centrifugal, multi-stage

3,370 m3/min (119,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 0

17 Secondary Nitrogen 

Compressor Centrifugal, single-stage

481 m3/min (17,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 0

18 Transport Nitrogen 

Boost Compressor Centrifugal, single-stage

57 m3/min (2,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 5.4 MPa (790 psia)

2 0

19 Extraction Air Heat 

Exchanger

Gas-to-gas, vendor 

design

69,853 kg/hr, 432°C, 1.6 MPa

(154,000 lb/hr, 810°F, 235 psia) 2 0
Cost and Performance Baseline for Fossil Energy Plants

186

ACCOUNT 5 SYNGAS CLEANUP

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

ACCOUNT 7 HRSG, STACK, AND DUCTING

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon 

bed

211,374 kg/hr (466,000 lb/hr) 

35°C (95°F) 

3.8 MPa (555 psia)

2 0

2 Sulfur Plant Claus type 138 tonne/day (152 tpd) 1 0

3 COS Hydrolysis Reactor Fixed bed, 

catalytic

252,651 kg/hr (557,000 lb/hr)

188°C (370°F)

4.1 MPa (590 psia)

2 0

4 Acid Gas Removal Plant MDEA

224,528 kg/hr (495,000 lb/hr)

34°C (94°F)

3.8 MPa (550 psia)

2 0

5 Hydrogenation Reactor Fixed bed, 

catalytic

28,108 kg/hr (61,967 lb/hr)

232°C (450°F)

0.4 MPa (58.9 psia)

1 0

6 Tail Gas Recycle 

Compressor Centrifugal 24,090 kg/hr (53,110 lb/hr) each 1 0

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Gas Turbine Advanced F class 232 MW 2 0

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase 2 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS 

liner

76 m (250 ft) high x

8.4 m (28 ft) diameter 1 0

2 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator

Main steam - 398,131 kg/hr, 12.4 

MPa/561°C (877,728 lb/hr, 

1,800 psig/1,041°F)

 Reheat steam - 358,685 kg/hr, 

3.1 MPa/561°C (790,766 lb/hr, 

452 psig/1,041°F)

2 0
Cost and Performance Baseline for Fossil Energy Plants

187

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

289 MW 

12.4 MPa/561°C/561°C 

(1,800 psig/ 1041°F/1041°F)

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitiation

320 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase 1 0

3 Steam Bypass One per HRSG 50% steam flow @ design 

steam conditions 2 0

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,561 GJ/hr (1,480 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 11°C 

(20°F)

1 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water 

Pumps Vertical, wet pit 389,897 lpm @ 30 m(103,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

/ 2,173 GJ/hr (2,060 MMBtu/hr) 

heat duty

1 0
Cost and Performance Baseline for Fossil Energy Plants

188

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 223,339 liters (59,000 gal) 2 0

2 Slag Crusher Roll 12 tonne/hr (13 tph) 2 0

3 Slag Depressurizer Proprietary 12 tonne/hr (13 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 136,275 liters (36,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 60,567 liters (16,000 gal) 2

6 Slag Conveyor Drag chain 12 tonne/hr (13 tph) 2 0

7 Slag Separation Screen Vibrating 12 tonne/hr (13 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 12 tonne/hr (13 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 189,271 liters (50,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal 

centrifugal

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 60,567 liters (16,000 gal) 2 0

12 Grey Water Pumps Centrifugal 227 lpm @ 433 m H2O

(60 gpm @ 1,420 ft H2O) 2 2

13 Slag Storage Bin Vertical, field 

erected 816 tonne (900 tons) 2 0

14 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 1 0
Cost and Performance Baseline for Fossil Energy Plants

189

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, 260 MVA, 3-ph, 60 Hz 2 0

2 STG Step-up 

Transformer Oil-filled 24 kV/345 kV, 320 MVA, 3-ph, 60 Hz 1 0

3

High Voltage 

Auxiliary 

Transformer

Oil-filled 345 kV/13.8 kV, 47 MVA, 

3-ph, 60 Hz 2 0

4

Medium Voltage 

Auxiliary 

Transformer

Oil-filled 24 kV/4.16 kV, 29 MVA, 

3-ph, 60 Hz 1 1

5 Low Voltage 

Transformer Dry ventilated 4.16 kV/480 V, 4 MVA, 3-ph, 60 Hz 1 1

6

CTG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, 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 for Fossil Energy Plants

190

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 for Fossil Energy Plants

191

3.3.7

The cost estimating methodology was described previously in Section 2.6. 

Case 3 - Costs Estimating Results

Exhibit 3-55 shows 

the total plant capital cost summary organized by cost account and Exhibit 3-56 shows a more 

detailed breakdown of the capital costs along with owner’s costs, TOC and TASC. Exhibit 3-57

shows the initial and annual O&M costs.

The estimated TOC of the CoP gasifier with no CO2 capture is $2,351/kW. Process contingency 

represents 2.1 percent of the TOC and project contingency is 10.9 percent. The COE is 74.0

mills/kWh.
Cost and Performance Baseline for Fossil Energy Plants

192

Exhibit 3-55 Case 3 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14

Project: Bituminous Baseline Study

Case: Case 3 - ConocoPhillips 625MW IGCC w/o CO2

Plant Size: 625.1 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 $13,783 $2,561 $10,689 $0 $0 $27,033 $2,454 $0 $5,897 $35,384 $57

 2 COAL & SORBENT PREP & FEED $23,433 $4,283 $14,157 $0 $0 $41,873 $3,759 $0 $9,126 $54,759 $88

 3 FEEDWATER & MISC. BOP SYSTEMS $9,806 $8,188 $9,436 $0 $0 $27,429 $2,581 $0 $6,822 $36,832 $59

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $117,991 $0 $65,449 $0 $0 $183,440 $16,853 $25,442 $34,617 $260,352 $417

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $145,765 $0 w/equip. $0 $0 $145,765 $14,129 $0 $15,989 $175,883 $281

4.4-4.9 Other Gasification Equipment $17,104 $9,335 $11,583 $0 $0 $38,023 $3,633 $0 $9,003 $50,658 $81

SUBTOTAL 4 $280,861 $9,335 $77,032 $0 $0 $367,228 $34,614 $25,442 $59,609 $486,893 $779

 5A GAS CLEANUP & PIPING $47,943 $3,806 $47,221 $0 $0 $98,970 $9,573 $85 $21,865 $130,493 $209

5B CO2 COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $85,751 $0 $6,269 $0 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $185

6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4

SUBTOTAL 6 $85,751 $806 $7,162 $0 $0 $93,719 $8,883 $4,601 $11,092 $118,295 $189

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $35,467 $0 $5,043 $0 $0 $40,510 $3,852 $0 $4,436 $48,798 $78

7.2-7.9 SCR System, Ductwork and Stack $3,335 $2,378 $3,114 $0 $0 $8,827 $818 $0 $1,570 $11,215 $18

SUBTOTAL 7 $38,802 $2,378 $8,157 $0 $0 $49,337 $4,670 $0 $6,006 $60,013 $96

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $28,970 $0 $4,963 $0 $0 $33,934 $3,256 $0 $3,719 $40,909 $65

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,556 $996 $7,591 $0 $0 $19,143 $1,738 $0 $4,220 $25,101 $40

SUBTOTAL 8 $39,526 $996 $12,554 $0 $0 $53,076 $4,994 $0 $7,939 $66,009 $106

 9 COOLING WATER SYSTEM $9,144 $8,826 $7,504 $0 $0 $25,474 $2,366 $0 $5,687 $33,527 $54

10 ASH/SPENT SORBENT HANDLING SYS $19,026 $1,439 $9,440 $0 $0 $29,905 $2,869 $0 $3,575 $36,349 $58

 11 ACCESSORY ELECTRIC PLANT $27,425 $10,189 $20,427 $0 $0 $58,041 $4,986 $0 $11,827 $74,854 $120

 12 INSTRUMENTATION & CONTROL $10,234 $1,883 $6,594 $0 $0 $18,710 $1,696 $936 $3,556 $24,897 $40

 13 IMPROVEMENTS TO SITE $3,328 $1,962 $8,212 $0 $0 $13,503 $1,333 $0 $4,451 $19,287 $31

 14 BUILDINGS & STRUCTURES $0 $6,670 $7,642 $0 $0 $14,313 $1,303 $0 $2,553 $18,169 $29

 

TOTAL COST $609,063 $63,322 $246,227 $0 $0 $918,612 $86,080 $31,064 $160,007 $1,195,762 $1,913

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline for Fossil Energy Plants

193

Exhibit 3-56 Case 3 Total Plant Cost Details

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 $3,619 $0 $1,769 $0 $0 $5,388 $483 $0 $1,174 $7,045 $11

1.2 Coal Stackout & Reclaim $4,677 $0 $1,134 $0 $0 $5,811 $509 $0 $1,264 $7,584 $12

1.3 Coal Conveyors & Yd Crush $4,349 $0 $1,122 $0 $0 $5,470 $480 $0 $1,190 $7,141 $11

1.4 Other Coal Handling $1,138 $0 $260 $0 $0 $1,397 $122 $0 $304 $1,823 $3

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 $2,561 $6,404 $0 $0 $8,966 $859 $0 $1,965 $11,790 $19

SUBTOTAL 1. $13,783 $2,561 $10,689 $0 $0 $27,033 $2,454 $0 $5,897 $35,384 $57

 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 $1,542 $369 $242 $0 $0 $2,153 $184 $0 $467 $2,805 $4

2.3 Slurry Prep & Feed $21,042 $0 $9,358 $0 $0 $30,400 $2,714 $0 $6,623 $39,737 $64

2.4 Misc.Coal Prep & Feed $848 $617 $1,851 $0 $0 $3,316 $305 $0 $724 $4,345 $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 $3,297 $2,707 $0 $0 $6,004 $556 $0 $1,312 $7,871 $13

SUBTOTAL 2. $23,433 $4,283 $14,157 $0 $0 $41,873 $3,759 $0 $9,126 $54,759 $88

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $3,157 $5,422 $2,862 $0 $0 $11,440 $1,060 $0 $2,500 $15,000 $24

3.2 Water Makeup & Pretreating $585 $61 $327 $0 $0 $974 $93 $0 $320 $1,387 $2

3.3 Other Feedwater Subsystems $1,727 $584 $525 $0 $0 $2,836 $255 $0 $618 $3,709 $6

3.4 Service Water Systems $335 $690 $2,394 $0 $0 $3,419 $334 $0 $1,126 $4,879 $8

3.5 Other Boiler Plant Systems $1,798 $697 $1,727 $0 $0 $4,221 $400 $0 $924 $5,546 $9

3.6 FO Supply Sys & Nat Gas $313 $591 $551 $0 $0 $1,456 $140 $0 $319 $1,915 $3

3.7 Waste Treatment Equipment $818 $0 $499 $0 $0 $1,318 $128 $0 $434 $1,880 $3

3.8 Misc. Power Plant Equipment $1,072 $143 $550 $0 $0 $1,765 $170 $0 $581 $2,517 $4

SUBTOTAL 3. $9,806 $8,188 $9,436 $0 $0 $27,429 $2,581 $0 $6,822 $36,832 $59

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $117,991 $0 $65,449 $0 $0 $183,440 $16,853 $25,442 $34,617 $260,352 $417

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $145,765 $0 w/equip. $0 $0 $145,765 $14,129 $0 $15,989 $175,883 $281

4.4 LT Heat Recovery & FG Saturation $17,104 $0 $6,502 $0 $0 $23,606 $2,304 $0 $5,182 $31,092 $50

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 $1,503 $612 $0 $0 $2,114 $203 $0 $463 $2,780 $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 $7,833 $4,469 $0 $0 $12,302 $1,126 $0 $3,357 $16,785 $27

SUBTOTAL 4. $280,861 $9,335 $77,032 $0 $0 $367,228 $34,614 $25,442 $59,609 $486,893 $779
Cost and Performance Baseline for Fossil Energy Plants

194

Exhibit 3-56 Case 3 Total Plant Cost Details (Continued)

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 $33,341 $0 $28,290 $0 $0 $61,631 $5,960 $0 $13,518 $81,110 $130

5A.2 Elemental Sulfur Plant $9,938 $1,981 $12,822 $0 $0 $24,741 $2,403 $0 $5,429 $32,573 $52

5A.3 Mercury Removal $970 $0 $738 $0 $0 $1,708 $165 $85 $392 $2,350 $4

5A.4 COS Hydrolysis $3,196 $0 $4,173 $0 $0 $7,369 $717 $0 $1,617 $9,703 $16

5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Blowback Gas Systems $499 $280 $157 $0 $0 $936 $89 $0 $205 $1,230 $2

5A.7 Fuel Gas Piping $0 $768 $538 $0 $0 $1,306 $121 $0 $285 $1,712 $3

5A.9 HGCU Foundations $0 $778 $501 $0 $0 $1,279 $118 $0 $419 $1,816 $3

SUBTOTAL 5A. $47,943 $3,806 $47,221 $0 $0 $98,970 $9,573 $85 $21,865 $130,493 $209

5B CO2 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 $85,751 $0 $6,269 $0 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $185

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. $85,751 $806 $7,162 $0 $0 $93,719 $8,883 $4,601 $11,092 $118,295 $189

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $35,467 $0 $5,043 $0 $0 $40,510 $3,852 $0 $4,436 $48,798 $78

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,710 $1,220 $0 $0 $2,929 $257 $0 $637 $3,823 $6

7.4 Stack $3,335 $0 $1,253 $0 $0 $4,588 $440 $0 $503 $5,530 $9

7.9 HRSG, Duct & Stack Foundations $0 $668 $642 $0 $0 $1,310 $122 $0 $430 $1,861 $3

SUBTOTAL 7. $38,802 $2,378 $8,157 $0 $0 $49,337 $4,670 $0 $6,006 $60,013 $96

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $28,970 $0 $4,963 $0 $0 $33,934 $3,256 $0 $3,719 $40,909 $65

8.2 Turbine Plant Auxiliaries $201 $0 $460 $0 $0 $661 $65 $0 $73 $798 $1

8.3 Condenser & Auxiliaries $4,785 $0 $1,529 $0 $0 $6,314 $604 $0 $692 $7,609 $12

8.4 Steam Piping $5,570 $0 $3,918 $0 $0 $9,489 $815 $0 $2,576 $12,880 $21

8.9 TG Foundations $0 $996 $1,683 $0 $0 $2,679 $254 $0 $880 $3,813 $6

SUBTOTAL 8. $39,526 $996 $12,554 $0 $0 $53,076 $4,994 $0 $7,939 $66,009 $106
Cost and Performance Baseline for Fossil Energy Plants

195

Exhibit 3-56 Case 3 Total Plant Cost Details (Continued)

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

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $6,338 $0 $1,153 $0 $0 $7,491 $713 $0 $1,231 $9,434 $15

9.2 Circulating Water Pumps $1,648 $0 $113 $0 $0 $1,761 $149 $0 $287 $2,197 $4

9.3 Circ.Water System Auxiliaries $140 $0 $20 $0 $0 $160 $15 $0 $26 $202 $0

9.4 Circ.Water Piping $0 $5,855 $1,518 $0 $0 $7,373 $666 $0 $1,608 $9,647 $15

9.5 Make-up Water System $327 $0 $467 $0 $0 $794 $76 $0 $174 $1,044 $2

9.6 Component Cooling Water Sys $691 $827 $588 $0 $0 $2,106 $197 $0 $461 $2,764 $4

9.9 Circ.Water System Foundations $0 $2,144 $3,645 $0 $0 $5,789 $549 $0 $1,901 $8,239 $13

SUBTOTAL 9. $9,144 $8,826 $7,504 $0 $0 $25,474 $2,366 $0 $5,687 $33,527 $54

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $16,609 $0 $8,191 $0 $0 $24,799 $2,383 $0 $2,718 $29,900 $48

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 $548 $0 $596 $0 $0 $1,144 $111 $0 $188 $1,443 $2

10.7 Ash Transport & Feed Equipment $735 $0 $177 $0 $0 $912 $85 $0 $150 $1,147 $2

10.8 Misc. Ash Handling Equipment $1,135 $1,391 $415 $0 $0 $2,941 $280 $0 $483 $3,704 $6

10.9 Ash/Spent Sorbent Foundation $0 $48 $61 $0 $0 $109 $10 $0 $36 $155 $0

SUBTOTAL 10. $19,026 $1,439 $9,440 $0 $0 $29,905 $2,869 $0 $3,575 $36,349 $58

 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 $3,741 $0 $337 $0 $0 $4,078 $376 $0 $445 $4,900 $8

11.3 Switchgear & Motor Control $6,917 $0 $1,258 $0 $0 $8,174 $758 $0 $1,340 $10,272 $16

11.4 Conduit & Cable Tray $0 $3,213 $10,599 $0 $0 $13,812 $1,336 $0 $3,787 $18,935 $30

11.5 Wire & Cable $0 $6,139 $4,034 $0 $0 $10,172 $739 $0 $2,728 $13,639 $22

11.6 Protective Equipment $0 $680 $2,474 $0 $0 $3,153 $308 $0 $519 $3,980 $6

11.7 Standby Equipment $234 $0 $229 $0 $0 $463 $44 $0 $76 $583 $1

11.8 Main Power Transformers $15,583 $0 $145 $0 $0 $15,727 $1,190 $0 $2,538 $19,454 $31

11.9 Electrical Foundations $0 $157 $412 $0 $0 $569 $54 $0 $187 $810 $1

SUBTOTAL 11. $27,425 $10,189 $20,427 $0 $0 $58,041 $4,986 $0 $11,827 $74,854 $120

 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 $1,010 $0 $675 $0 $0 $1,685 $159 $84 $289 $2,218 $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 $232 $0 $149 $0 $0 $381 $36 $19 $87 $523 $1

12.7 Computer & Accessories $5,389 $0 $173 $0 $0 $5,562 $510 $278 $635 $6,985 $11

12.8 Instrument Wiring & Tubing $0 $1,883 $3,849 $0 $0 $5,731 $486 $287 $1,626 $8,130 $13

12.9 Other I & C Equipment $3,602 $0 $1,749 $0 $0 $5,352 $504 $268 $918 $7,041 $11

SUBTOTAL 12. $10,234 $1,883 $6,594 $0 $0 $18,710 $1,696 $936 $3,556 $24,897 $40
Cost and Performance Baseline for Fossil Energy Plants

196

Exhibit 3-56 Case 3 Total Plant Cost Details (Continued)

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

 13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $104 $2,232 $0 $0 $2,336 $232 $0 $771 $3,339 $5

13.2 Site Improvements $0 $1,857 $2,468 $0 $0 $4,326 $427 $0 $1,426 $6,178 $10

13.3 Site Facilities $3,328 $0 $3,512 $0 $0 $6,841 $674 $0 $2,255 $9,770 $16

SUBTOTAL 13. $3,328 $1,962 $8,212 $0 $0 $13,503 $1,333 $0 $4,451 $19,287 $31

 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 $2,435 $3,468 $0 $0 $5,903 $543 $0 $967 $7,413 $12

14.3 Administration Building $0 $842 $611 $0 $0 $1,452 $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 $489 $477 $0 $0 $967 $87 $0 $158 $1,212 $2

14.6 Machine Shop $0 $431 $295 $0 $0 $726 $64 $0 $119 $909 $1

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 $2,711 $253 $0 $593 $3,557 $6

SUBTOTAL 14. $0 $6,670 $7,642 $0 $0 $14,313 $1,303 $0 $2,553 $18,169 $29

TOTAL COST $609,063 $63,322 $246,227 $0 $0 $918,612 $86,080 $31,064 $160,007 $1,195,762 $1,913

Owner's Costs

Preproduction Costs

6 Months All Labor $12,309 $20

1 Month Maintenance Materials $2,766 $4

1 Month Non-fuel Consumables $239 $0

1 Month Waste Disposal $279 $0

25% of 1 Months Fuel Cost at 100% CF $1,603 $3

2% of TPC $23,915 $38

Total $41,111 $66

Inventory Capital

60 day supply of fuel and consumables at 100% CF $13,092 $21

0.5% of TPC (spare parts) $5,979 $10

Total $19,071 $31

Initial Cost for Catalyst and Chemicals $1,084 $2

Land $900 $1

Other Owner's Costs $179,364 $287

Financing Costs $32,286 $52

Total Overnight Costs (TOC) $1,469,577 $2,351

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $1,675,318 $2,680
Cost and Performance Baseline for Fossil Energy Plants

197

Exhibit 3-57 Case 3 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 3 - ConocoPhillips 625MW IGCC w/o CO2 Heat Rate-net(Btu/kWh): 8,585

MWe-net: 625

 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

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 2.0 2.0

 Operator 9.0 9.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 3.0 3.0

 TOTAL-O.J.'s 15.0 15.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $5,918,913 $9.469

Maintenance Labor Cost $13,775,415 $22.039

Administrative & Support Labor $4,923,582 $7.877

Property Taxes and Insurance $23,935,631 $38.293

TOTAL FIXED OPERATING COSTS $48,553,541 $77.678

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $26,551,568 $0.00606

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water (/1000 gallons) 0 3,144.24 1.08 $0 $993,106 $0.00023

Chemicals

MU & WT Chem. (lbs) 0 18,732 0.17 $0 $946,662 $0.00022

Carbon (Mercury Removal) (lb) 68,511 94 1.05 $71,948 $28,779 $0.00001

COS Catalyst (m3) 327 0.22 2,397.36 $784,204 $156,841 $0.00004

Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000

MDEA Solution (gal) 26,146 37 8.70 $227,412 $93,463 $0.00002

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip. 1.91 131.27 $0 $73,243 $0.00002

Subtotal Chemicals $1,083,564 $1,298,988 $0.00030

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 94 0.42 $0 $11,430 $0.00000

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 563 16.23 $0 $2,669,064 $0.00061

 Subtotal-Waste Disposal $0 $2,680,493 $0.00061

By-products & Emissions

Sulfur (ton) 0 138 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $1,083,564 $31,524,155 $0.00720

Fuel (ton) 0 5,519 38.18 $0 $61,541,712 $0.01405
Cost and Performance Baseline for Fossil Energy Plants

198

3.3.8

This case is configured to produce electric power with CO2 capture. The plant configuration is 

the same as Case 3, namely two gasifier trains, two advanced F class turbines, two HRSGs, and 

one steam turbine. The gross power output from the plant is constrained by the capacity of the 

two CTs, and since the CO2 capture and compression process increases the auxiliary load on the 

plant, the net output is significantly reduced relative to Case 3.

Case 4 - E-GasTM IGCC Power Plant with CO2 Capture

The process description for Case 4 is similar to Case 3 with several notable exceptions to 

accommodate CO2 capture. A BFD and stream tables for Case 4 are shown in Exhibit 3-58 and

Exhibit 3-59, respectively. Instead of repeating the entire process description, only differences 

from Case 3 are reported here.

No differences from Case 3.

Coal Preparation and Feed Systems

The gasification process is the same as Case 3 with the exception that total coal feed to the two 

gasifiers is 5,271 tonnes/day (5,811 TPD) (stream 8) and the ASU provides 4,234 tonnes/day 

(4,668 TPD) of 95 mol% oxygen to the gasifier and Claus plant (streams 5 and 3).

Gasification

Raw gas cooling and particulate removal are the same as Case 3 with the exception that 

approximately 418,710 kg/hr (923,082 lb/hr) of saturated steam at 13.8 MPa (2,000 psia) is 

generated in the SGC.

Raw Gas Cooling/Particulate Removal

No differences from Case 3.

Syngas Scrubber/Sour Water Stripper

The SGS process was described in Section 

Sour Gas Shift (SGS)

3.1.3. In Case 4 steam (stream 11) is added to the 

syngas exiting the scrubber to adjust the H2O:CO molar ratio to approximately 2.25:1 prior to the 

first WGS reactor. The hot syngas exiting the first stage of SGS is used to preheat a portion of 

the water used to humidify the clean syngas leaving the AGR. The final stage of SGS brings the

overall conversion of the CO to CO2 to 98.5 percent. The syngas exiting the final stage of SGS 

still contains 1.2 vol% CH4, which is subsequently oxidized to CO2 in the CT and results in a 

carbon capture of 90.4 percent. The warm syngas exiting the second stage of the SGS at 204°C 

(400°F) (stream 12) is cooled to 201°C (393°F) by preheating the syngas entering the first SGS 

reactor. The SGS catalyst also serves to hydrolyze COS thus eliminating the need for a separate 

COS hydrolysis reactor. The syngas is further dehydrated and cooled to 35°C (95°F) in syngas 

coolers prior to the mercury removal beds.

Mercury removal is the same as in Case 3.

Mercury Removal and Acid Gas Removal
Cost and Performance Baseline for Fossil Energy Plants

199

Exhibit 3-58 Case 4 Block Flow Diagram, E-GasTM IGCC with CO2 Capture
Cost and Performance Baseline for Fossil Energy Plants

200

Exhibit 3-59 Case 4 Stream Table, E-GasTM IGCC with CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12 13

V-L Mole Fraction

Ar 0.0092 0.0209 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0054 0.0071

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0125 0.0164

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0028 0.0037

CO2 0.0003 0.0071 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3103 0.4090

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.4128 0.5441

H2O 0.0099 0.1780 0.0000 0.0003 0.0000 1.0000 1.0000 0.0000 0.9963 0.0000 1.0000 0.2376 0.0015

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0048 0.0063

N2 0.7732 0.6187 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0090 0.0119

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0037 0.0000 0.0000 0.0046 0.0000

O2 0.2074 0.1754 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

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 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 26,685 1,231 145 19,704 5,338 1,287 4,969 0 5,009 0 9,357 37,866 26,948

V-L Flowrate (kg/hr) 770,042 33,603 4,654 552,893 171,782 23,193 89,523 0 90,226 0 168,566 748,369 547,649

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 219,635 0 22,418 0 0 0

Temperature (°C) 15 19 32 93 32 154 343 15 171 1,038 288 204 35

Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.79 5.10 0.10 5.79 4.24 5.52 4.07 3.79

Enthalpy (kJ/kg)A 30.23 36.49 26.67 92.50 26.67 599.34 3,063.97 --- 673.50 --- 2,918.18 873.73 40.91

Density (kg/m3) 1.2 1.5 11.0 24.4 11.0 857.7 20.1 --- 836.0 --- 25.6 20.6 30.9

V-L Molecular Weight 28.857 27.295 32.181 28.060 32.181 18.015 18.015 --- 18.012 --- 18.015 19.764 20.322

V-L Flowrate (lbmol/hr) 58,830 2,714 319 43,440 11,768 2,838 10,955 0 11,044 0 20,628 83,479 59,411

V-L Flowrate (lb/hr) 1,697,652 74,082 10,260 1,218,920 378,715 51,133 197,365 0 198,914 0 371,625 1,649,872 1,207,359

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 484,212 0 49,422 0 0 0

Temperature (°F) 59 67 90 199 90 310 650 59 340 1,900 550 400 95

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 840.0 740.0 14.7 840.0 615.0 800.0 590.0 550.0

Enthalpy (Btu/lb)A 13.0 15.7 11.5 39.8 11.5 257.7 1,317.3 --- 289.6 --- 1,254.6 375.6 17.6

Density (lb/ft3) 0.076 0.095 0.687 1.521 0.687 53.543 1.257 --- 52.192 --- 1.597 1.285 1.928

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Fossil Energy Plants

201

Exhibit 3-59 Case 4 Stream Table, E-GasTM IGCC with CO2 Capture (Continued)

14 15 16 17 18 19 20 21 22 23 24 25

V-L Mole Fraction

Ar 0.0071 0.0119 0.0114 0.0114 0.0002 0.0011 0.0000 0.0068 0.0092 0.0090 0.0090 0.0000

CH4 0.0159 0.0262 0.0251 0.0251 0.0008 0.0045 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0038 0.0063 0.0060 0.0060 0.0001 0.0007 0.0000 0.0076 0.0000 0.0000 0.0000 0.0000

CO2 0.4172 0.0352 0.0338 0.0338 0.9945 0.7021 0.0000 0.6907 0.0003 0.0082 0.0082 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.5341 0.8964 0.8588 0.8588 0.0044 0.0591 0.0000 0.2007 0.0000 0.0000 0.0000 0.0000

H2O 0.0015 0.0001 0.0421 0.0421 0.0000 0.0162 0.0000 0.0017 0.0099 0.1246 0.1246 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2S 0.0062 0.0000 0.0000 0.0000 0.0000 0.2153 0.0000 0.0026 0.0000 0.0000 0.0000 0.0000

N2 0.0142 0.0239 0.0229 0.0229 0.0001 0.0010 0.0000 0.0901 0.7732 0.7529 0.7529 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1052 0.1052 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 27,761 16,435 17,155 17,155 10,499 800 0 812 110,253 139,694 139,694 34,515

V-L Flowrate (kg/hr) 575,208 83,813 96,780 96,780 459,855 31,069 0 27,560 3,181,557 3,831,230 3,831,230 621,792

Solids Flowrate (kg/hr) 0 0 0 0 0 0 5,494 0 0 0 0 0

Temperature (°C) 34 34 108 193 51 48 176 38 15 562 132 534

Pressure (MPa, abs) 3.8 3.757 3.206 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512

Enthalpy (kJ/kg)A 39.0 196.106 903.063 1,360.503 -162.349 62.132 --- 1.774 30.227 839.766 348.188 3,432.696

Density (kg/m3

) 31.3 7.4 5.6 4.6 641.8 2.4 5,283.7 83.6 1.2 0.4 0.9 36.7

V-L Molecular Weight 21 5.100 5.642 5.642 43.800 38.814 --- 33.925 28.857 27.426 27.426 18.015

V-L Flowrate (lbmol/hr) 61,202 36,233 37,820 37,820 23,146 1,765 0 1,791 243,066 307,972 307,972 76,092

V-L Flowrate (lb/hr) 1,268,117 184,776 213,363 213,363 1,013,807 68,496 0 60,759 7,014,133 8,446,417 8,446,417 1,370,817

Solids Flowrate (lb/hr) 0 0 0 0 0 0 12,112 0 0 0 0 0

Temperature (°F) 94 94 227 380 124 119 349 100 59 1,044 270 994

Pressure (psia) 545.0 545.0 465.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 16.8 84.3 388.2 584.9 -69.8 26.7 --- 0.8 13.0 361.0 149.7 1,475.8

Density (lb/ft3) 2 0.461 0.352 0.285 40.067 0.149 329.851 5.220 0.076 0.026 0.053 2.293
Cost and Performance Baseline for Fossil Energy Plants

202

The AGR process in Case 4 is a two stage Selexol process where H2S is removed in the first 

stage and CO2 in the second stage of absorption as previously described in Section 3.1.5. The 

process results in three product streams, the clean syngas, a CO2-rich stream, and an acid gas 

feed to the Claus plant. The acid gas (stream 19) contains 21.5 percent H2S and 70 percent CO2

with the balance primarily H2. The CO2-rich stream is discussed further in the CO2 compression 

section.

CO2 from the AGR process is flashed at three pressure levels to separate CO2 and decrease H2

losses to the CO2 product pipeline. The HP CO2 stream is flashed at 2.0 MPa (289.7 psia), 

compressed, and recycled back to the CO2 absorber. The MP CO2 stream is flashed at 1.0 MPa 

(149.7 psia). The LP CO2 stream is flashed at 0.1 MPa (16.7 psia), compressed to 1.0 MPa 

(149.5 psia), and combined with the MP CO2 stream. The combined stream is compressed from 

1.0 MPa (149.5 psia) to a SC condition at 15.3 MPa (2215 psia) using a multiple-stage, 

intercooled compressor. During compression, the CO2 stream is dehydrated to a dewpoint of 

-40oC (-40°F) with triethylene glycol. The raw CO2 stream from the Selexol process contains 

over 99 percent CO2. The CO2 (stream 18) is transported to the plant fence line and is 

sequestration ready. CO2 TS&M costs were estimated using the methodology described in

Section 

CO2 Compression and Dehydration

2.7.

The Claus plant is the same as Case 3 with the following exceptions:

Claus Unit

• 5,494 kg/hr (12,112 lb/hr) of sulfur (stream 20) are produced

• The waste heat boiler generates 12,679 kg/hr (27,953 lb/hr) of 3.0 MPa (430 psia) steam, 

which provides all of the Claus plant process needs and provides some additional steam 

to the medium pressure steam header.

Clean syngas from the AGR plant is partially humidified to 4 percent because the nitrogen 

available from the ASU is insufficient to provide adequate dilution. The moisturized syngas is 

reheated (stream 17) to 193°C (380°F) using HP BFW, diluted with nitrogen (stream 4), and then 

enters the CT burner. There is no integration between the CT and the ASU in this case. The 

exhaust gas (stream 23) exits the CT at 562°C (1044°F) and enters the HRSG where additional 

heat is recovered. The FG exits the HRSG at 132°C (270°F) (stream 24) and is discharged 

through the plant stack. The steam raised in the HRSG is used to power an advanced 

commercially available steam turbine using a 12.4 MPa/534°C/534°C (1800 psig/994°F/994°F) 

steam cycle.

Power Block

The elevated pressure ASU is the same as in other cases and produces 4,234 tonnes/day (4,668

TPD) of 95 mol% oxygen and 14,230 tonnes/day (15,686 TPD) of nitrogen. There is no 

integration between the ASU and the CT.

Air Separation Unit (ASU)

3.3.9

The Case 4 modeling assumptions were presented previously in Section 

Case 4 Performance Results

3.3.3.
Cost and Performance Baseline for Fossil Energy Plants

203

The plant produces a net output of 514 MWe at a net plant efficiency of 31.0 percent (HHV 

basis). Overall performance for the entire plant is summarized in Exhibit 3-60, which includes 

auxiliary power requirements. The ASU accounts for nearly 58 percent of the auxiliary load 

between the main air compressor, the nitrogen compressor, the oxygen compressor, and ASU 

auxiliaries. The two-stage Selexol process and CO2 compression account for an additional 27 

percent of the auxiliary power load. The BFW pumps and cooling water system (CWPs and 

cooling tower fan) comprise nearly 6 percent of the load, leaving 9 percent of the auxiliary load 

for all other systems.
Cost and Performance Baseline for Fossil Energy Plants

204

Exhibit 3-60 Case 4 Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Gas Turbine Power 464,000

Sweet Gas Expander Power 0

Steam Turbine Power 239,700

TOTAL POWER, kWe 703,700

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 470

Coal Milling 2,260

Sour Water Recycle Slurry Pump 200

Slag Handling 1,160

Air Separation Unit Auxiliaries 1,000

Air Separation Unit Main Air Compressor 65,670

Oxygen Compressor 9,010

Nitrogen Compressors 35,340

CO2 Compressor 31,380

Boiler Feedwater Pumps 4,160

Condensate Pump 310

Syngas Recycle Compressor 520

Circulating Water Pump 4,670

Ground Water Pumps 520

Cooling Tower Fans 2,410

Scrubber Pumps 400

Acid Gas Removal 19,900

Gas Turbine Auxiliaries 1,000

Steam Turbine Auxiliaries 100

Claus Plant/TGTU Auxiliaries 250

Claus Plant TG Recycle Compressor 3,700

Miscellaneous Balance of Plant2 3,000

Transformer Losses 2,660

TOTAL AUXILIARIES, kWe 190,090

NET POWER, kWe 513,610

Net Plant Efficiency, % (HHV) 31.0

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,604 (10,998)

CONDENSER COOLING DUTY 106 kJ/hr (106 Btu/hr) 1,403 (1,330)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 219,635 (484,212)

Thermal Input1, kWt 1,655,503

Raw Water Withdrawal, m3/min (gpm) 21.6 (5,717)

Raw Water Consumption, m3/min (gpm) 17.5 (4,631)

1 - HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)

2 - Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Fossil Energy Plants

205

The environmental targets for emissions of Hg, NOx, SO2, CO2, and PM were presented in 

Section 

Environmental Performance

2.4. A summary of the plant air emissions for Case 4 is presented in Exhibit 3-61. 

Exhibit 3-61 Case 4 Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(tons/year) 

80% CF

kg/MWh

(lb/MWh)

SO2 0.001 (0.002) 39 (43) 0.008 (.02)

NOx 0.021 (0.049) 885 (976) 0.180 (.396)

Particulates 0.003 (0.0071) 127 (141) 0.026 (.057)

Hg 2.46E-7 

(5.71E-7) 0.010 (0.011) 2.08E-6 (4.59E-6)

CO2 8.5 (19.7) 354,267 (390,512) 72 (158)

CO2

1 98 (217)

1 CO2 emissions based on net power instead of gross power

The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the two-stage 

Selexol AGR process. The CO2 capture target results in the sulfur compounds being removed to 

a greater extent than required in the environmental targets of Section 2.4. The clean syngas 

exiting the AGR process has a sulfur concentration of approximately 5 ppmv. This results in a 

concentration in the FG of less than 1 ppmv. The H2S-rich regeneration gas from the AGR 

system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is 

hydrogenated to convert all sulfur species to H2S, and then recycled back to the Selexol, thereby 

eliminating the need for a tail gas treatment unit.

NOx emissions are limited by the use of humidification and nitrogen dilution to 15 ppmvd (NO2

@ 15 percent O2). Ammonia in the syngas is removed with process condensate prior to the lowtemperature AGR process and ultimately destroyed in the Claus plant burner. This helps lower 

NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone 

and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Ninety five percent of mercury is captured from the syngas by an activated carbon bed.

Ninety five percent of the CO2 from the syngas is captured in the AGR system and compressed 

for sequestration. The overall carbon removal is 90.4 percent.

The carbon balance for the plant 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 in the 

carbon balance below since the Aspen model accounts for air components throughout. Carbon 

leaves the plant as unburned carbon in the slag, CO2 in the stack gas, ASU vent gas and the 

captured CO2 product. The carbon capture efficiency is defined as the amount of carbon in the 
Cost and Performance Baseline for Fossil Energy Plants

206

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

276,728/(308,659-2,469) *100 or

90.4 percent

In revision 1 of this report, the reported CO2 capture efficiency was 88.4 percent. The high 

methane content of the syngas, relative to the GEE and Shell cases, prevented reaching the 

nominal 90 percent CO2 capture. In order to achieve 90 percent capture, the two-stage Selexol 

CO2 removal efficiency was increased from 92 to 95 percent. 

Exhibit 3-62 Case 4 Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 140,006 (308,659) Slag 1,120 (2,469)

Air (CO2) 537 (1,185) Stack Gas 13,796 (30,416)

ASU Vent 105 (231)

CO2 Product 125,522 (276,728)

Total 140,543 (309,844) Total 140,543 (309,844)

Exhibit 3-63 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the 

stack gas, and sulfur in the CO2 product. Sulfur in the slag is considered to be negligible.

Exhibit 3-63 Case 4 Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 5,505 (12,136) Elemental Sulfur 5,494 (12,112)

Stack Gas 3 (6)

CO2 Product 8 (18)

Total 5,505 (12,136) Total 5,505 (12,136)

Exhibit 3-64 shows the overall water balance for the plant. The exhibit is presented in an 

identical manner for Cases 1 through 3.
Cost and Performance Baseline for Fossil Energy Plants

207

Exhibit 3-64 Case 4 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)

Slag Handling 0.49 (128) 0.49 (128) 0.0 (0) 0.0 (0) 0.0 (0)

Slurry Water 1.51 (398) 1.51 (398) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier 0.2 (61) 0.2 (61) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7) -0.03 (-7)

Condenser Makeup

Gasifier Steam

Shift Steam

GT Steam 

Dilution

BFW Makeup

4.5 (1,193)

1.5 (395)

2.8 (743)

0.21 (55)

0.0 (0) 4.5 (1,193)

1.5 (395)

2.8 (743)

0.21 (55)

0.0 (0) 4.5 (1,193)

Cooling Tower

BFW Blowdown

SWS Blowdown

SWS Excess 

Water

Humidifier Tower 

Blowdown

18.2 (4,798) 1.0 (274)

0.21 (55)

0.26 (68)

0.6 (152)

17.1 (4,524)

-0.21 (-55)

-0.26 (-68)

-0.6 (-152)

4.1 (1,079) 13.0 (3,445)

Total 24.9 (6,578) 3.3 (861) 21.6 (5,717) 4.1 (1,086) 17.5 (4,631)

Heat and mass balance diagrams are shown for the following subsystems in 

Heat and Mass Balance Diagrams

Exhibit 3-65 through

Exhibit 3-67:

• Coal gasification and ASU

• Syngas cleanup including sulfur recovery and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is provided in tabular form in Exhibit 3-68. The power out is 

the combined CT and steam turbine power prior to generator losses. The power at the generator 

terminals (shown in Exhibit 3-60) is calculated by multiplying the power out by a combined 

generator efficiency of 98.4 percent.
Cost and Performance Baseline for Fossil Energy Plants

208

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

209

Exhibit 3-65 Case 4 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 4

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 4

COP GASIFIER

ASU AND GASIFICATION

DWG. NO.

BB-HMB-CS-4-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

1 OF 3

Ambient Air

Four Stage Air

Compressor

Elevated

Pressure

ASU

Four Stage N2

Compressor

Four Stage O2

Compressor

ASU 

Vent

Water

Steam

Gross Plant Power: 704 MWe

Auxiliary Load: 190 MWe

Net Plant Power: 514 MWe

Net Plant Efficiency, HHV: 31.0%

Net Plant Heat Rate: 10,998 BTU/KWe

N2 to GT Combustor

1,697,652 W

59.0 T

14.7 P

13.0 H

378,715 W

90.0 T

125.0 P

11.5 H

378,715 W

223.0 T

740.0 P

37.5 H

To Claus Plant

10,260 W

90.0 T

125.0 P

11.5 H

74,082 W

66.9 T

16.4 P

15.7 H

1,080,178 W

90.0 T

56.4 P

14.2 H

152,901 W

50.0 T

182.0 P

2.9 H

5

1

3

2

457,753 W

385.0 T

469.0 P

87.0 H

Candle Filter

Slurry Mix 

Tank

E-Gas TM

Gasifier

Milled Coal

Water

Slag

Raw Syngas 

to Scrubber

Cyclones

Syngas Recycle

Saturated Steam to HRSG

BFW from HRSG

Blowdown to Flash Tank

Fire

Tube

Boiler

Steam

Drum

484,212 W

59.0 T

14.7 P

198,914 W

340.0 T

840.0 P

289.6 H

49,422 W

1,355,003 W

600.0 T

605.0 P

485.6 H

761,167 W

385.0 T

384.0 P

87.2 H

Fuel Gas

10

683,126 W

178.6 T

840.0 P

3,040.6 H

1,355,003 W

600.0 T

605.0 P

485.6 H

1,355,003 W

1,801.8 T

615.0 P

1,029.4 H

Boost Compressor

N2 to GT Combustor

79,928 W

160.9 T

800.0 P

42.6 H

N2 Diluent

Preheater

1,355,003 W

450.0 T

600.0 P

422.6 H

100.0 T

189.5 P

18.0 H

8

9

Steam

Sour Water

7

6 197,365 W

650.0 T

740.0 P

1,316.8 H

51,133 W

310.0 T

840.0 P

257.7 H

Syngas Recycle

Compressor

79,928 W

105.0 T

585.0 P

21.6 H

4
Cost and Performance Baseline for Fossil Energy Plants

210

Exhibit 3-66 Case 4 Syngas Cleanup Heat and Mass Balance Schematic

Mercury 

Removal

Knock

Out 

Drum

Multistage 

Intercooled CO2

Compressor

Raw Syngas

Syngas

Preheater

Fuel Gas to GT

Sour

Drum

To Water Treatment

Makeup Water

Interstage Knockout

Claus Plant

Tail 

Gas

Furnace

Catalytic

Reactor

Beds

Sulfur

High

Temperature

Shift #1

Low 

Temperature 

Shift #2

Knock Out

From 

ASU

CO2 Product

Shift Steam

Fuel Gas

Humidification

Syngas

Coolers

Sour

Stripper

Two-Stage

Selexol

Clean Gas

CO2

Acid Gas

Syngas

Scrubber

Condensate 

to Deaerator

Condensate

371,625 W

550.0 T

800.0 P

1,254.1 H

362.9 T

590.0 P

340.0 H

1,355,003 W

450.0 T

600.0 P

422.6 H

1,278,247 W

352.9 T

595.0 P

343.8 H

1,268,117 W

93.8 T

545.0 P

16.8 H

213,363 W

227.0 T

465.0 P

388.2 H

68,496 W

119.0 T

23.7 P

26.7 H

1,013,807 W

123.7 T

2,214.7 P

1,547,580 W

392.6 T

585.0 P

372.4 H

213,363 W

380.0 T

460.0 P

584.9 H

12,112 W

72,809 W

280.0 T

17.3 P

312.6 H

6,165 W

195.4 T

65.0 P

206.5 H

10,260 W

90.0 T

125.0 P

11.5 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 4

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 4

COP GASIFIER

GAS CLEANUP SYSTEM

DWG. NO.

BB-HMB-CS-4-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

2 OF 3

Sour Gas

Sour Water

Water

Steam

Gross Plant Power: 704 MWe

Auxiliary Load: 190 MWe

Net Plant Power: 514 MWe

Net Plant Efficiency, HHV: 31.0%

Net Plant Heat Rate: 10,998 BTU/KWe

1,649,872 W

398.4 T

590.0 P

546.0 H

400.0 T

590.0 P

397.7 H

15

20

19

18

14

13

12

17

21

CO2

Tailgas

65,864 W

120.0 T

10.6 P

106.8 H

1,207,359 W

94.6 T

550.0 P

17.6 H

12,050 W

111.6 T

10.6 P

37.1 H

1,014,845 W

60.0 T

135.0 P 3

Syngas Recycle

11

60,759 W

100.0 T

799.5 P

0.8 H

1,649,872 W

400.0 T

590.0 P

375.6 H

698.4 T

590.0 P

532.7 H

102,292 W

392.6 T

585.0 P

372.4 H

Humidification 16

184,776 W

93.8 T

545.0 P

84.3 H

Claus Oxygen

Preheater

10,260 W

450.0 T

124.5 P

91.9 H

Tail Gas

Compressor

Hydrogenation

And Tail Gas

Cooling
Cost and Performance Baseline for Fossil Energy Plants

211

Exhibit 3-67 Case 4 Combined Cycle Power Generation Heat and Mass Balance Schematic

HRSG

HP

Turbine

IP

Turbine

Nitrogen Diluent

Intake

Ambient Air

Steam Seal 

Regulator

Gasifier and WGS

Steam

Ip Extraction Steam

To 250 PSIA Header

Blowdown

Flash

To WWT

Gland

Steam

Condenser

Condensate to Gasification Island

HP BFW to Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP 

Turbine

Stack

Compressor Expander

Fuel Gas

Deaerator

IP BFW

Generator

Generator

Condensate

Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class 

Gas Turbine

MP Flash Bottoms

LP Flash Tops

1,218,920 W

7,014,133 W

59.0 T

14.7 P

13.0 H

2,068,816 W

101.1 T

1.0 P

69.1 H

8,446,417 W

270.0 T

15.2 P

149.7 H

213,363 W

380.0 T

460.0 P

584.9 H

8,446,417 W

1,043.7 T

15.2 P

361.0 H

LP

Process

Header

From Gasifier

Island Preheating

To Claus

LP BFW

1,370,817 W

993.7 T

1,814.7 P

1,475.8 H

9,744 W

298.0 T

65.0 P

1,179.0 H

1,398,140 W

278.8 T

2,250.7 P

252.3 H

27,273 W

585.0 T

2,000.7 P

593.3 H

1,460,271 W

464.8 T

65.0 P

1,264.6 H

2,068,816 W

102.7 T

120.0 P

70.9 H

2,068,816 W

235.0 T

105.0 P

203.7 H

1,400 W

614.7 T

65.0 P

1,338.6 H

1,400 W

212.0 T

14.7 P

179.9 H

IP Pump NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 4

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 4

COP GASIFIER

POWER BLOCK SYSTEM

DWG. NO.

BB-HMB-CS-4-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

Gross Plant Power: 704 MWe

Auxiliary Load: 190 MWe

Net Plant Power: 514 MWe

Net Plant Efficiency, HHV: 31.0%

22 Net Plant Heat Rate: 10,998 BTU/KWe

23

25

17

24

Flue Gas

HOT WELL

CONDENSER Make-up

596,383 W

59.0 T

14.7 P

27.1 H

9,026 W

660.4 T

501.4 P

1,334.5 H

9,762 W

614.7 T

65.0 P

1,338.6 H

25,041 W

851.8 T

280.0 P

1,448.7 H

798 W

993.7 T

1,814.7 P

1,475.8 H

1,337 W

504.8 T

65.0 P

1,284.4 H
Cost and Performance Baseline for Fossil Energy Plants

212

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

213

Exhibit 3-68 Case 4 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,960 (5,649) 5.0 (4.7) 5,965 (5,654)

ASU Air 23.3 (22.1) 23 (22)

GT Air 96.2 (91.2) 96 (91)

Water 81.4 (77.1) 81 (77)

Auxiliary Power 684 (649) 684 (649)

TOTAL 5,960 (5,649) 205.8 (195.1) 684 (649) 6,850 (6,492)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 1.2 (1.2) 1 (1)

Slag 37 (35) 25.2 (23.9) 62 (59)

Sulfur 51 (48) 0.6 (0.6) 52 (49)

CO2 -74.7 (-70.8) -75 (-71)

Cooling Tower Blowdown 30.3 (28.8) 30 (29)

HRSG Flue Gas 1,334 (1,264) 1,334 (1,264)

Condenser 1,408 (1,334) 1,408 (1,334)

Non-Condenser Cooling 

Tower Loads* 755 (716) 755 (716)

Process Losses** 749 (710) 749 (710)

Power 2,533 (2,401) 2,533 (2,401)

TOTAL 88 (83) 4,229 (4,008) 2,533 (2,401) 6,850 (6,492)

* Includes ASU compressor intercoolers, CO2 compressor intercoolers, sour water stripper condenser, syngas 

cooler (low level heat rejection) and extraction air cooler.

** Calculated by difference to close the energy balance 
Cost and Performance Baseline for Fossil Energy Plants

214

3.3.10

Major equipment items for the CoP 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 

Case 4 - Major Equipment List

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.

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 45 tonne (50 ton) 2 1

9 Feeder Vibratory 181 tonne/hr (200 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 363 tonne/hr (400 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 181 tonne (200 ton) 2 0

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0) 2 0

14 As-Fired Coal Sampling 

System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 363 tonne/hr (400 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 363 tonne/hr (400 tph) 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 363 tonne (400 ton) 6 0
Cost and Performance Baseline for Fossil Energy Plants

215

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 82 tonne/h (90 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 245 tonne/h (270 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 481 tonne (530 ton) 1 0

4 Weigh Feeder Belt 118 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 118 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank 

with Agitator Field erected 298,179 liters (78,770 gal) 2 0

7 Slurry Water Pumps Centrifugal 833 lpm (220 gpm) 2 1

8 Trommel Screen Coarse 172 tonne/h (190 tph) 2 0

9 Rod Mill Discharge Tank with 

Agitator Field erected 390,052 liters (103,040 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,407 lpm (900 gpm) 2 2

11 Slurry Storage Tank with 

Agitator Field erected 1,170,080 liters (309,100 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,435 lpm (1,700 gpm) 2 2

13 Slurry Product Pumps Positive 

displacement 3,407 lpm (900 gpm) 2 2
Cost and Performance Baseline for Fossil Energy Plants

216

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 1,101,555 liters (291,000 gal) 2 0

2 Condensate Pumps Vertical canned 8,669 lpm @ 91 m H2O

(2,290 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 606,907 kg/hr (1,338,000 lb/hr) 2 0

4 Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

8,555 lpm @ 27 m H2O

(2,260 gpm @ 90 ft H2O) 2 1

5 High Pressure 

Feedwater Pump No. 1

Barrel type, multi-stage, 

centrifugal

HP water: 6,057 lpm @ 1,859 m 

H2O (1,600 gpm @ 6,100 ft 

H2O)

2 1

6 High Pressure 

Feedwater Pump No. 2

Barrel type, multi-stage, 

centrifugal

IP water: 1,287 lpm @ 223 m 

H2O (340 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 Cylce Cooling 

Heat Exchangers Plate and frame 430 GJ/hr (407 MMBtu/hr) each 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 154,066 lpm @ 21 m H2O(40,700 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

5,602 lpm @ 18 m H2O

(1,480 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) 4 1

16 Filtered Water Pumps Stainless steel, single 

suction

3,066 lpm @ 49 m H2O

(810 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,472,525 liter (389,000 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 for Fossil Energy Plants

217

ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW 

TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier

Pressurized two-stage, 

slurry-feed entrained 

bed

2,903 tonne/day, 4.2 MPa

(3,200 tpd, 614.96 psia) 2 0

2 Synthesis Gas Cooler Fire-tube boiler 337,926 kg/hr (745,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 337,926 kg/hr (745,000 lb/hr) 

Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with 

pulse-jet cleaning metallic filters 2 0

5

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 337,926 kg/hr (745,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with 

condensate drain 386,007 kg/hr (851,000 lb/hr) 8 0

7 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator

303,000 kg/hr, 35°C, 3.8 MPa

(668,000 lb/hr, 95°F, 555 psia) 2 0

8 Saturation Water 

Economizers Shell and tube 36 GJ/hr (34 MMBtu/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 53,070 kg/hr, 108°C, 3.8 MPa

(117,000 lb/hr, 227°F, 545 psia) 2 0

10 Saturator Water Pump Centrifugal 757 lpm @ 12 m H2O

(200 gpm @ 40 ft H2O) 2 2

11 Synthesis Gas Reheater Shell and tube 53,070 kg/hr (117,000 lb/hr) 2 0

12 Flare Stack

Self-supporting, carbon 

steel, stainless steel top, 

pilot ignition

337,926 kg/hr (745,000 lb/hr) 

syngas

2 0

13 ASU Main Air 

Compressor Centrifugal, multi-stage 5,805 m3/min @ 1.3 MPa(205,000 scfm @ 190 psia) 2 0

14 Cold Box Vendor design 2,359 tonne/day (2,600 tpd) of 

95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi-stage

1,161 m3/min (41,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 5.1 MPa (740 psia)

2 0

16 Primary Nitrogen 

Compressor Centrifugal, multi-stage

3,794 m3/min (134,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 0

17 Secondary Nitrogen 

Compressor Centrifugal, single-stage

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 0

18 Gasifier Purge Nitrogen 

Boost Compressor Centrifugal, single-stage

1,614 m3/min (57,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 psia)

2 0
Cost and Performance Baseline for Fossil Energy Plants

218

ACCOUNT 5A SOUR GAS SHIFT AND SYNGAS CLEANUP

ACCOUNT 5B CO2 COMPRESSION

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon 

bed

301,185 kg/hr (664,000 lb/hr) 

35°C (95°F)

3.8 MPa (550 psia)

2 0

2 Sulfur Plant Claus type 145 tonne/day (160 tpd) 1 0

3 Water Gas Shift Reactors Fixed bed, 

catalytic

411,408 kg/hr (907,000 lb/hr) 

204°C (400°F)

4.1 MPa (590 psia)

4 0

4 Shift Reactor Heat Recovery 

Exchangers Shell and Tube

Exchanger 1: 94 GJ/hr (89 

MMBtu/hr) 

Exchanger 2: 3 GJ/hr (3 

MMBtu/hr) 

4 0

5 Acid Gas Removal Plant Two-stage 

Selexol

316,154 kg/hr (697,000 lb/hr) 

34°C (94°F)

3.8 MPa (545 psia)

2 0

6 Hydrogenation Reactor Fixed bed, 

catalytic

36,328 kg/hr (80,090 lb/hr)

232°C (450°F)

0.1 MPa (12.3 psia)

1 0

7 Tail Gas Recycle 

Compressor Centrifugal 30,316 kg/hr (66,835 lb/hr) 1 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CO2 

Compressor

Integrally geared, 

multi-stage centrifugal

1,141 m3/min @ 15.3 MPa 

(40,300 scfm @ 2,215 psia) 4 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gas Turbine Advanced F class 232 MW 2 0

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase 2 0
Cost and Performance Baseline for Fossil Energy Plants

219

ACCOUNT 7 HRSG, DUCTING, AND STACK

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS 

liner

76 m (250 ft) high x

8.5 m (28 ft) diameter 1 0

2 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator

Main steam - 341,986 kg/hr, 12.4 

MPa/534°C (753,949 lb/hr, 

1,800 psig/994°F)

 Reheat steam - 298,222 kg/hr, 

3.1 MPa/534°C (657,466 lb/hr, 

452 psig/994°F)

2 0

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

252 MW 

12.4 MPa/534°C/534°C 

(1800 psig/ 994°F/994°F)

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitiation

280 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase 1 0

3 Steam Bypass One per HRSG 50% steam flow @ design 

steam conditions 2 0

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,551 GJ/hr (1,470 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 11°C 

(20°F)

1 0
Cost and Performance Baseline for Fossil Energy Plants

220

ACCOUNT 9 COOLING WATER SYSTEM

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Circulating Water 

Pumps Vertical, wet pit 469,391 lpm @ 30 m(124,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

/ 2606 GJ/hr (2470 MMBtu/hr) 

heat duty

1 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 234,696 liters (62,000 gal) 2 0

2 Slag Crusher Roll 13 tonne/hr (14 tph) 2 0

3 Slag Depressurizer Proprietary 13 tonne/hr (14 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 140,060 liters (37,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 64,352 liters (17,000 gal) 2

6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 2 0

7 Slag Separation Screen Vibrating 13 tonne/hr (14 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 13 tonne/hr (14 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 200,627 liters (53,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal 

centrifugal

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 64,352 liters (17,000 gal) 2 0

12 Grey Water Pumps Centrifugal 227 lpm @ 433 m H2O

(60 gpm @ 1,420 ft H2O) 2 2

13 Slag Storage Bin Vertical, field 

erected 907 tonne (1,000 tons) 2 0

14 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 1 0
Cost and Performance Baseline for Fossil Energy Plants

221

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CTG Step-up 

Transformer Oil-filled 24 kV/345 kV, 260 MVA, 3-ph, 60 Hz 2 0

2 STG Step-up 

Transformer Oil-filled 24 kV/345 kV, 280 MVA, 3-ph, 60 Hz 1 0

3

High Voltage 

Auxiliary 

Transformer

Oil-filled 345 kV/13.8 kV, 79 MVA, 

3-ph, 60 Hz 2 0

4

Medium Voltage 

Auxiliary 

Transformer

Oil-filled 24 kV/4.16 kV, 51 MVA, 

3-ph, 60 Hz 1 1

5 Low Voltage 

Transformer Dry ventilated 4.16 kV/480 V, 8 MVA, 3-ph, 60 Hz 1 1

6

CTG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, 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

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 for Fossil Energy Plants

222

3.3.11

The cost estimating methodology was described previously in Section 2.6. 

Case 4 - Cost Estimating Results

Exhibit 3-69 shows 

the total plant capital cost summary organized by cost account and Exhibit 3-70 shows a more 

detailed breakdown of the capital costs as well as TOC, TASC, and breakdown of owner’s costs. 

Exhibit 3-71 shows the initial and annual O&M costs. 

The estimated TOC of the CoP gasifier with CO2 capture is $3,466/kW. Process contingency 

represents 3.5 percent of the TOC and project contingency represents 11.1 percent. The COE, 

including CO2 TS&M costs of 5.6 mills/kWh, is 110.4 mills/kWh.
Cost and Performance Baseline for Fossil Energy Plants

223

Exhibit 3-69 Case 4 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14

Project: Bituminous Baseline Study

Case: Case 4 - ConocoPhillips 500MW IGCC w/ CO2

Plant Size: 513.6 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 $14,229 $2,644 $11,035 $0 $0 $27,908 $2,533 $0 $6,088 $36,529 $71

 2 COAL & SORBENT PREP & FEED $24,241 $4,431 $14,646 $0 $0 $43,318 $3,889 $0 $9,441 $56,648 $110

 3 FEEDWATER & MISC. BOP SYSTEMS $10,074 $7,882 $10,144 $0 $0 $28,101 $2,651 $0 $7,106 $37,858 $74

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $114,050 $0 $63,266 $0 $0 $177,316 $16,295 $24,521 $33,478 $251,609 $490

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $186,025 $0 w/equip. $0 $0 $186,025 $18,031 $0 $20,406 $224,461 $437

4.4-4.9 Other Gasification Equipment $24,056 $10,168 $14,678 $0 $0 $48,902 $4,688 $0 $11,449 $65,038 $127

SUBTOTAL 4 $324,131 $10,168 $77,944 $0 $0 $412,242 $39,014 $24,521 $65,332 $541,109 $1,054

 5A GAS CLEANUP & PIPING $89,500 $3,812 $77,878 $0 $0 $171,190 $16,546 $26,077 $42,894 $256,707 $500

5B CO2 COMPRESSION $18,339 $0 $11,242 $0 $0 $29,581 $2,849 $0 $6,486 $38,916 $76

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,609 $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 $257

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,631 $0 $4,782 $0 $0 $38,414 $3,652 $0 $4,207 $46,272 $90

7.2-7.9 SCR System, Ductwork and Stack $3,377 $2,407 $3,153 $0 $0 $8,938 $829 $0 $1,589 $11,355 $22

SUBTOTAL 7 $37,008 $2,407 $7,935 $0 $0 $47,351 $4,481 $0 $5,796 $57,628 $112

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $26,321 $0 $4,278 $0 $0 $30,600 $2,935 $0 $3,353 $36,888 $72

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $9,952 $903 $6,987 $0 $0 $17,843 $1,623 $0 $3,868 $23,333 $45

SUBTOTAL 8 $36,274 $903 $11,266 $0 $0 $48,442 $4,558 $0 $7,221 $60,222 $117

 9 COOLING WATER SYSTEM $10,387 $9,859 $8,527 $0 $0 $28,773 $2,673 $0 $6,406 $37,852 $74

10 ASH/SPENT SORBENT HANDLING SYS $19,651 $1,481 $9,750 $0 $0 $30,882 $2,963 $0 $3,691 $37,536 $73

11 ACCESSORY ELECTRIC PLANT $31,778 $12,519 $24,431 $0 $0 $68,728 $5,909 $0 $14,164 $88,801 $173

12 INSTRUMENTATION & CONTROL $11,157 $2,052 $7,188 $0 $0 $20,397 $1,849 $1,020 $3,877 $27,142 $53

13 IMPROVEMENTS TO SITE $3,416 $2,014 $8,429 $0 $0 $13,859 $1,368 $0 $4,568 $19,796 $39

14 BUILDINGS & STRUCTURES $0 $6,693 $7,589 $0 $0 $14,282 $1,300 $0 $2,555 $18,136 $35

 

TOTAL COST $722,212 $67,672 $295,478 $0 $0 $1,085,363 $102,090 $61,479 $197,964 $1,446,895 $2,817

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline for Fossil Energy Plants

224

Exhibit 3-70 Case 4 Total Plant Cost Details

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 $3,737 $0 $1,826 $0 $0 $5,563 $498 $0 $1,212 $7,273 $14

1.2 Coal Stackout & Reclaim $4,829 $0 $1,171 $0 $0 $5,999 $526 $0 $1,305 $7,830 $15

1.3 Coal Conveyors & Yd Crush $4,489 $0 $1,158 $0 $0 $5,648 $496 $0 $1,229 $7,372 $14

1.4 Other Coal Handling $1,175 $0 $268 $0 $0 $1,443 $126 $0 $314 $1,883 $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 $2,644 $6,612 $0 $0 $9,256 $887 $0 $2,029 $12,172 $24

SUBTOTAL 1. $14,229 $2,644 $11,035 $0 $0 $27,908 $2,533 $0 $6,088 $36,529 $71

 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 $1,596 $382 $250 $0 $0 $2,228 $190 $0 $484 $2,902 $6

2.3 Slurry Prep & Feed $21,768 $0 $9,681 $0 $0 $31,449 $2,808 $0 $6,851 $41,108 $80

2.4 Misc.Coal Prep & Feed $877 $639 $1,914 $0 $0 $3,430 $315 $0 $749 $4,495 $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 $3,411 $2,800 $0 $0 $6,211 $575 $0 $1,357 $8,143 $16

SUBTOTAL 2. $24,241 $4,431 $14,646 $0 $0 $43,318 $3,889 $0 $9,441 $56,648 $110

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,834 $4,868 $2,570 $0 $0 $10,272 $952 $0 $2,245 $13,468 $26

3.2 Water Makeup & Pretreating $709 $74 $396 $0 $0 $1,179 $112 $0 $387 $1,679 $3

3.3 Other Feedwater Subsystems $1,551 $524 $472 $0 $0 $2,546 $229 $0 $555 $3,330 $6

3.4 Service Water Systems $406 $835 $2,899 $0 $0 $4,140 $404 $0 $1,363 $5,907 $12

3.5 Other Boiler Plant Systems $2,177 $843 $2,090 $0 $0 $5,111 $485 $0 $1,119 $6,714 $13

3.6 FO Supply Sys & Nat Gas $313 $591 $551 $0 $0 $1,456 $140 $0 $319 $1,915 $4

3.7 Waste Treatment Equipment $991 $0 $604 $0 $0 $1,595 $155 $0 $525 $2,276 $4

3.8 Misc. Power Plant Equipment $1,094 $146 $562 $0 $0 $1,802 $174 $0 $593 $2,569 $5

SUBTOTAL 3. $10,074 $7,882 $10,144 $0 $0 $28,101 $2,651 $0 $7,106 $37,858 $74

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $114,050 $0 $63,266 $0 $0 $177,316 $16,295 $24,521 $33,478 $251,609 $490

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $186,025 $0 w/equip. $0 $0 $186,025 $18,031 $0 $20,406 $224,461 $437

4.4 LT Heat Recovery & FG Saturation $24,056 $0 $9,145 $0 $0 $33,201 $3,240 $0 $7,288 $43,730 $85

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 $1,643 $669 $0 $0 $2,312 $222 $0 $507 $3,041 $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 $8,525 $4,864 $0 $0 $13,389 $1,226 $0 $3,654 $18,268 $36

SUBTOTAL 4. $324,131 $10,168 $77,944 $0 $0 $412,242 $39,014 $24,521 $65,332 $541,109 $1,054
Cost and Performance Baseline for Fossil Energy Plants

225

Exhibit 3-70 Case 4 Total Plant Cost Details (Continued)

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 $70,224 $0 $59,586 $0 $0 $129,810 $12,554 $25,962 $33,665 $201,991 $393

5A.2 Elemental Sulfur Plant $10,291 $2,051 $13,278 $0 $0 $25,620 $2,489 $0 $5,622 $33,730 $66

5A.3 Mercury Removal $1,302 $0 $991 $0 $0 $2,294 $222 $115 $526 $3,156 $6

5A.4 Shift Reactors $7,138 $0 $2,873 $0 $0 $10,011 $960 $0 $2,194 $13,164 $26

5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Blowback Gas Systems $545 $306 $172 $0 $0 $1,023 $98 $0 $224 $1,345 $3

5A.7 Fuel Gas Piping $0 $723 $506 $0 $0 $1,229 $114 $0 $269 $1,612 $3

5A.9 HGCU Foundations $0 $732 $472 $0 $0 $1,204 $111 $0 $394 $1,709 $3

SUBTOTAL 5A. $89,500 $3,812 $77,878 $0 $0 $171,190 $16,546 $26,077 $42,894 $256,707 $500

5B CO2 COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $18,339 $0 $11,242 $0 $0 $29,581 $2,849 $0 $6,486 $38,916 $76

SUBTOTAL 5B. $18,339 $0 $11,242 $0 $0 $29,581 $2,849 $0 $6,486 $38,916 $76

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,609 $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 $257

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,631 $0 $4,782 $0 $0 $38,414 $3,652 $0 $4,207 $46,272 $90

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,731 $1,235 $0 $0 $2,966 $260 $0 $645 $3,871 $8

7.4 Stack $3,377 $0 $1,269 $0 $0 $4,645 $445 $0 $509 $5,599 $11

7.9 HRSG,Duct & Stack Foundations $0 $677 $650 $0 $0 $1,326 $123 $0 $435 $1,885 $4

SUBTOTAL 7. $37,008 $2,407 $7,935 $0 $0 $47,351 $4,481 $0 $5,796 $57,628 $112

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $26,321 $0 $4,278 $0 $0 $30,600 $2,935 $0 $3,353 $36,888 $72

8.2 Turbine Plant Auxiliaries $182 $0 $417 $0 $0 $599 $59 $0 $66 $724 $1

8.3 Condenser & Auxiliaries $4,762 $0 $1,521 $0 $0 $6,284 $601 $0 $688 $7,573 $15

8.4 Steam Piping $5,008 $0 $3,523 $0 $0 $8,531 $733 $0 $2,316 $11,580 $23

8.9 TG Foundations $0 $903 $1,526 $0 $0 $2,429 $230 $0 $798 $3,457 $7

SUBTOTAL 8. $36,274 $903 $11,266 $0 $0 $48,442 $4,558 $0 $7,221 $60,222 $117
Cost and Performance Baseline for Fossil Energy Plants

226

Exhibit 3-70 Case 4 Total Plant Cost Details (Continued)

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

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $7,196 $0 $1,401 $0 $0 $8,597 $819 $0 $1,412 $10,828 $21

9.2 Circulating Water Pumps $1,877 $0 $136 $0 $0 $2,013 $170 $0 $327 $2,510 $5

9.3 Circ.Water System Auxiliaries $157 $0 $22 $0 $0 $179 $17 $0 $29 $226 $0

9.4 Circ.Water Piping $0 $6,545 $1,697 $0 $0 $8,241 $745 $0 $1,797 $10,783 $21

9.5 Make-up Water System $384 $0 $549 $0 $0 $933 $90 $0 $205 $1,227 $2

9.6 Component Cooling Water Sys $773 $924 $657 $0 $0 $2,354 $221 $0 $515 $3,090 $6

9.9 Circ.Water System Foundations $0 $2,391 $4,064 $0 $0 $6,455 $612 $0 $2,120 $9,187 $18

SUBTOTAL 9. $10,387 $9,859 $8,527 $0 $0 $28,773 $2,673 $0 $6,406 $37,852 $74

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $17,164 $0 $8,464 $0 $0 $25,628 $2,462 $0 $2,809 $30,900 $60

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 $613 $0 $0 $1,177 $114 $0 $194 $1,485 $3

10.7 Ash Transport & Feed Equipment $756 $0 $182 $0 $0 $938 $88 $0 $154 $1,180 $2

10.8 Misc. Ash Handling Equipment $1,168 $1,431 $427 $0 $0 $3,026 $288 $0 $497 $3,811 $7

10.9 Ash/Spent Sorbent Foundation $0 $50 $63 $0 $0 $112 $11 $0 $37 $160 $0

SUBTOTAL 10. $19,651 $1,481 $9,750 $0 $0 $30,882 $2,963 $0 $3,691 $37,536 $73

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $924 $0 $914 $0 $0 $1,839 $176 $0 $201 $2,216 $4

11.2 Station Service Equipment $4,676 $0 $421 $0 $0 $5,097 $470 $0 $557 $6,124 $12

11.3 Switchgear & Motor Control $8,644 $0 $1,572 $0 $0 $10,216 $948 $0 $1,675 $12,838 $25

11.4 Conduit & Cable Tray $0 $4,015 $13,247 $0 $0 $17,262 $1,670 $0 $4,733 $23,665 $46

11.5 Wire & Cable $0 $7,672 $5,041 $0 $0 $12,713 $924 $0 $3,409 $17,046 $33

11.6 Protective Equipment $0 $680 $2,474 $0 $0 $3,153 $308 $0 $519 $3,980 $8

11.7 Standby Equipment $229 $0 $223 $0 $0 $452 $43 $0 $74 $570 $1

11.8 Main Power Transformers $17,305 $0 $140 $0 $0 $17,445 $1,319 $0 $2,815 $21,579 $42

11.9 Electrical Foundations $0 $152 $398 $0 $0 $550 $53 $0 $181 $784 $2

SUBTOTAL 11. $31,778 $12,519 $24,431 $0 $0 $68,728 $5,909 $0 $14,164 $88,801 $173

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 $1,101 $0 $735 $0 $0 $1,837 $174 $92 $315 $2,418 $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 $253 $0 $162 $0 $0 $415 $39 $21 $95 $571 $1

12.7 Computer & Accessories $5,875 $0 $188 $0 $0 $6,063 $557 $303 $692 $7,615 $15

12.8 Instrument Wiring & Tubing $0 $2,052 $4,196 $0 $0 $6,248 $530 $312 $1,773 $8,863 $17

12.9 Other I & C Equipment $3,927 $0 $1,907 $0 $0 $5,834 $549 $292 $1,001 $7,676 $15

SUBTOTAL 12. $11,157 $2,052 $7,188 $0 $0 $20,397 $1,849 $1,020 $3,877 $27,142 $53
Cost and Performance Baseline for Fossil Energy Plants

227

Exhibit 3-70 Case 4 Total Plant Cost Details (Continued)

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

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $107 $2,291 $0 $0 $2,398 $238 $0 $791 $3,427 $7

13.2 Site Improvements $0 $1,906 $2,533 $0 $0 $4,440 $438 $0 $1,463 $6,341 $12

13.3 Site Facilities $3,416 $0 $3,605 $0 $0 $7,021 $692 $0 $2,314 $10,027 $20

SUBTOTAL 13. $3,416 $2,014 $8,429 $0 $0 $13,859 $1,368 $0 $4,568 $19,796 $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 $2,246 $3,200 $0 $0 $5,445 $501 $0 $892 $6,838 $13

14.3 Administration Building $0 $870 $631 $0 $0 $1,501 $134 $0 $245 $1,880 $4

14.4 Circulation Water Pumphouse $0 $163 $86 $0 $0 $250 $22 $0 $41 $312 $1

14.5 Water Treatment Buildings $0 $592 $578 $0 $0 $1,171 $106 $0 $191 $1,468 $3

14.6 Machine Shop $0 $445 $305 $0 $0 $750 $67 $0 $122 $939 $2

14.7 Warehouse $0 $719 $464 $0 $0 $1,183 $105 $0 $193 $1,481 $3

14.8 Other Buildings & Structures $0 $431 $335 $0 $0 $766 $68 $0 $167 $1,001 $2

14.9 Waste Treating Building & Str. $0 $963 $1,840 $0 $0 $2,802 $261 $0 $613 $3,676 $7

SUBTOTAL 14. $0 $6,693 $7,589 $0 $0 $14,282 $1,300 $0 $2,555 $18,136 $35

TOTAL COST $722,212 $67,672 $295,478 $0 $0 $1,085,363 $102,090 $61,479 $197,964 $1,446,895 $2,817

Owner's Costs

Preproduction Costs

6 Months All Labor $13,491 $26

1 Month Maintenance Materials $2,999 $6

1 Month Non-fuel Consumables $385 $1

1 Month Waste Disposal $295 $1

25% of 1 Months Fuel Cost at 100% CF $1,687 $3

2% of TPC $28,938 $56

Total $47,793 $93

Inventory Capital

60 day supply of fuel and consumables at 100% CF $13,995 $27

0.5% of TPC (spare parts) $7,234 $14

Total $21,230 $41

Initial Cost for Catalyst and Chemicals $7,371 $14

Land $900 $2

Other Owner's Costs $217,034 $423

Financing Costs $39,066 $76

Total Overnight Costs (TOC) $1,780,290 $3,466

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,029,531 $3,952
Cost and Performance Baseline for Fossil Energy Plants

228

Exhibit 3-71 Case 4 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 4 - ConocoPhillips 500MW IGCC w/ CO2 Heat Rate-net (Btu/kWh): 10,998

MWe-net: 514

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

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 2.0 2.0

 Operator 10.0 10.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 3.0 3.0

 TOTAL-O.J.'s 16.0 16.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $6,313,507 $12.292

Maintenance Labor Cost $15,271,560 $29.734

Administrative & Support Labor $5,396,267 $10.507

Property Taxes and Insurance $28,937,909 $56.342

TOTAL FIXED OPERATING COSTS $55,919,243 $108.875

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $28,787,121 $0.00800

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

 Water(/1000 gallons) 0 4,116 1.08 $0 $1,300,111 $0.00036

Chemicals

MU & WT Chem. (lbs) 0 24,523 0.17 $0 $1,239,310 $0.00034

Carbon (Mercury Removal) (lb) 104,394 143 1.05 $109,631 $43,852 $0.00001

COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000

Water Gas Shift Catalyst (ft3) 6,484 4.44 498.83 $3,234,413 $646,883 $0.00018

Selexol Solution (gal) 300,533 98 13.40 $4,026,613 $384,543 $0.00011

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip. 2.00 131.27 $0 $76,827 $0.00002

Subtotal Chemicals $7,370,657 $2,391,415 $0.00066

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.) 0 143 0.42 $0 $17,416 $0.00000

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 593 16.23 $0 $2,809,802 $0.00078

Subtotal Waste Disposal $0 $2,827,218 $0.00079

By-products & Emissions

Sulfur (ton) 0 145 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $7,370,657 $35,305,866 $0.00981

Fuel (ton) 0 5,811 38.18 $0 $64,786,772 $0.01800
Cost and Performance Baseline for Fossil Energy Plants

229

3.4 SHELL GLOBAL SOLUTIONS IGCC CASES

This section contains an evaluation of plant designs for Cases 5 and 6, which are based on the 

Shell gasifier. Cases 5 and 6 are very similar in terms of process, equipment, scope and 

arrangement, except that Case 6 employs a syngas quench and includes SGS reactors, CO2

absorption/regeneration, and compression/transport systems. There are no provisions for CO2

removal in Case 5.

The balance of this section is organized in an analogous manner to Sections 3.2 and 3.3:

• Gasifier Background

• Process System Description for Case 5

• Key Assumptions for Cases 5 and 6

• Sparing Philosophy for Cases 5 and 6

• Performance Results for Case 5

• Equipment List for Case 5

• Cost Estimates For Case 5

• Process and System Description, Performance Results, Equipment List, and Cost 

Estimate for Case 6

3.4.1

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.

Gasifier Background

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 hours 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 hours from 1978 to 1983, and successfully gasified over 27,216 tonnes (30,000 tons) of 

coal.

From 1974 until mid-1981, Heinrich Koppers GmbH (now Krupp Koppers) cooperated with 

Shell in the development work for the coal gasification technology at the 150 tonnes/day 

(165 TPD) pilot plant in Hamburg. Krupp Koppers is the licensor of the commercially proven 

Koppers-Totzek coal gasification technology, an entrained-flow slagging gasification system 

operated at atmospheric pressure.

In June 1981, the partnership between Shell and Krupp Koppers was terminated. Since that time, 

this gasification technology has been developed solely by Shell as the Shell Coal Gasification 

Process. Krupp Koppers continued its own development of a similar pressurized, dry feed, 

entrained-flow gasification technology called PRENFLO. Krupp Koppers has built and 

successfully operated a small 45 tonnes/day (50 TPD) PRENFLO pilot plant at Fuerstenhausen, 
Cost and Performance Baseline for Fossil Energy Plants

230

Germany. In 2000 Shell and Krupp Uhde agreed to join forces again in gasification and jointly 

offer the Shell coal gasification process.

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 227 tonnes/day (250 TPD) and to gasify high-moisture, high-ash lignite at the rate of 

363 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 1,814 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 design is 

the use of extraction air from the CT air compressor to feed the oxygen plant.

Gasifier Capacity – As of 2009, Shell reported ten gasifiers in operation producing 100,000-

150,000 Nm3

/hr and three of the same size in construction. Another three ranging from 150,000-

250,000 Nm3/hr are also in construction [61

Distinguishing Characteristics – The key advantage of the Shell coal gasification technology is 

its lack of feed coal limitations. One of the major achievements of the Shell development 

program has been the successful gasification of a wide variety of coals ranging from anthracite to 

brown coal. The dry pulverized feed system developed by Shell uses all coal types with 

essentially no operating and design modifications (provided the drying pulverizers are 

appropriately sized). The dry fed Shell gasifier also has the advantage of lower oxygen 

requirement than comparable slurry fed entrained flow gasifiers.

]. The large gasifier operating in The Netherlands 

has a bituminous coal-handling capacity of 1,633 tonnes/day (1,800 TPD) and produces dry gas 

at a rate of 158,575 Nm3

/hr (5.6 million scf/hr) with an energy content of about 1,792 MMkJ/hr

(1,700 MMBtu/hr) (HHV). This gasifier was sized to match the fuel gas requirements for the 

Siemens/Kraftwerk Union V-94.2 CT and could easily be scaled up to match advanced F Class 

turbine requirements.

Entrained-flow slagging gasifiers have fundamental environmental advantages over fluidizedbed and moving-bed gasifiers. 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 fixedsalts blowdown problems associated with slurry feeding.
Cost and Performance Baseline for Fossil Energy Plants

231

A disadvantage of the Shell coal gasification technology is the high waste heat recovery (SGC) 

duty. As with the other slagging gasifiers, the Shell process has this disadvantage due to its high 

operating temperature. 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. Demonstration of the reliability and safety of the dry 

coal feeding system was essential for the successful development of the Shell technology. The 

high operating temperature required by all entrained-flow slagging processes can result in 

relatively high capital and maintenance costs. However, the Shell gasifier employs a cooled 

refractory, which requires fewer change outs than an uncooled refractory. Life of a water wall is 

determined by metallurgy and temperature and can provide a significant O&M cost benefit over 

refractory lined gasifiers.

Important Coal Characteristics – Characteristics desirable for coal considered for use in the 

Shell gasifier include moderate ash fusion temperature and relatively low ash content. The Shell 

gasifier is extremely flexible; it can handle a wide variety of different coals, 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, heat removal, slag management, and maintenance. 

However, dry feeding reduces the negative effects of high ash content relative to slurry feed 

gasifiers.

3.4.2

In this section the overall Shell gasification process for Case 5 is described. The system 

description follows the BFD in 

Process Description

Exhibit 3-72 and stream numbers reference the same Exhibit. 

The tables in Exhibit 3-73 provide process data for the numbered streams in the BFD.

Coal receiving and handling is common to all cases and was covered in Section 

Coal Preparation and Feed Systems

3.1.1. The 

receiving and handling subsystem ends at the coal silo. The Shell process uses a dry feed 

system, which is sensitive to the coal moisture content. Coal moisture consists of two parts, 

surface moisture and inherent moisture. For coal to flow smoothly through the lock hoppers, the 

surface moisture must be removed. The Illinois No. 6 coal used in this study contains 

11.12 percent total moisture on an as-received basis (stream 9). It was assumed that the coal 

must be dried to 5 percent moisture to allow for smooth flow through the dry feed system 

(stream 10).

The coal is simultaneously crushed and dried in the coal mill then delivered to a surge hopper 

with an approximate 2-hour capacity. The drying medium is provided by combining the off-gas 

from the Claus plant TGTU and a slipstream of clean syngas (stream 8) and passing them

through an incinerator. The incinerator FG, with an oxygen content of 6 vol%, is then used to 

dry the coal in the mill.

The coal is drawn from the surge hoppers and fed through a pressurization lock hopper system to 

a dense phase pneumatic conveyor, which uses nitrogen from the ASU to convey the coal to the 

gasifiers.
Cost and Performance Baseline for Fossil Energy Plants

232

Exhibit 3-72 Case 5 Block Flow Diagram, Shell IGCC without CO2 Capture
Cost and Performance Baseline for Fossil Energy Plants

233

Exhibit 3-73 Case 5 Stream Table, Shell IGCC without CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

Ar 0.0092 0.0262 0.0318 0.0023 0.0318 0.0000 0.0023 0.0100 0.0000 0.0000 0.0000 0.0095 0.0095 0.0096

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0006 0.0006 0.0006

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.5980 0.0000 0.0000 0.0000 0.5797 0.5797 0.5833

CO2 0.0003 0.0092 0.0000 0.0000 0.0000 0.0000 0.0000 0.0158 0.0000 0.0000 0.0000 0.0143 0.0143 0.0151

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0007 0.0007 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3142 0.0000 0.8090 0.0000 0.3006 0.3006 0.3024

H2O 0.0099 0.2378 0.0000 0.0003 0.0000 1.0000 0.0004 0.0013 0.0000 0.0935 0.0000 0.0252 0.0252 0.0194

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0030 0.0000 0.0009 0.0009 0.0001

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0081 0.0081 0.0089

N2 0.7732 0.5018 0.0178 0.9919 0.0178 0.0000 0.9919 0.0601 0.0000 0.0163 0.0000 0.0567 0.0567 0.0570

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0036 0.0036 0.0036

O2 0.2074 0.2251 0.9504 0.0054 0.9504 0.0000 0.0054 0.0000 0.0000 0.0782 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 18,364 812 88 16,375 4,591 1,061 882 252 0 0 0 25,096 17,567 17,460

V-L Flowrate (kg/hr) 529,935 21,917 2,828 459,480 147,752 19,111 24,747 5,088 0 0 0 509,993 356,995 354,790

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 198,059 185,222 19,837 0 0 0

Temperature (°C) 15 21 32 93 32 343 32 45 15 16 1,427 1,079 191 177

Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.10 5.41 3.65 0.10 5.79 4.24 4.24 4.03 3.90

Enthalpy (kJ/kg)A 30.23 37.32 26.67 92.52 26.67 3,063.97 21.22 60.75 --- 0.00 0.00 0.00 325.96 297.28

Density (kg/m3

) 1.2 1.6 11.0 24.4 11.0 20.1 60.5 27.8 --- 16.5 --- 7.6 21.0 20.9

V-L Molecular Weight 28.857 26.992 32.181 28.060 32.181 18.015 28.060 20.195 --- --- --- 20.322 20.322 20.320

V-L Flowrate (lbmol/hr) 40,486 1,790 194 36,101 10,122 2,339 1,944 555 0 0 0 55,328 38,729 38,493

V-L Flowrate (lb/hr) 1,168,307 48,319 6,236 1,012,980 325,738 42,132 54,557 11,218 0 0 0 1,124,342 787,039 782,178

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 436,646 408,345 43,732 0 0 0

Temperature (°F) 59 70 90 199 90 650 90 112 59 60 2,600 1,974 375 351

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 740.0 785.0 530.0 14.7 840.0 615.0 615.0 585.0 565.0

Enthalpy (Btu/lb)A 13.0 16.0 11.5 39.8 11.5 1,317.3 9.1 26.1 --- 140.1 127.8

Density (lb/ft3) 0.076 0.101 0.687 1.521 0.687 1.257 3.774 1.734 --- 1.029 --- 0.475 1.310 1.303

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Fossil Energy Plants

234

Exhibit 3-73 Case 5 Stream Table, Shell IGCC without CO2 Capture (Continued)

15 16 17 18 19 20 21 22 23 24 25 26 27

V-L Mole Fraction

Ar 0.0098 0.0098 0.0100 0.0079 0.0079 0.0004 0.0000 0.0058 0.0092 0.0092 0.0086 0.0086 0.0000

CH4 0.0006 0.0006 0.0006 0.0005 0.0005 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.5962 0.5845 0.5980 0.4741 0.4741 0.0167 0.0000 0.1034 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0155 0.0257 0.0158 0.0125 0.0125 0.4460 0.0000 0.2613 0.0003 0.0003 0.0752 0.0752 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.3091 0.3072 0.3142 0.2491 0.2491 0.0096 0.0000 0.0429 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0014 0.0015 0.0013 0.2083 0.2083 0.0063 0.0000 0.4259 0.0099 0.0099 0.0906 0.0906 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2S 0.0091 0.0089 0.0000 0.0000 0.0000 0.3872 0.0000 0.0016 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0583 0.0618 0.0601 0.0476 0.0476 0.1338 0.0000 0.1585 0.7732 0.7732 0.7210 0.7210 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.2074 0.1046 0.1046 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 17,081 17,426 16,771 21,155 21,155 402 0 510 110,253 4,410 137,428 137,428 39,521

V-L Flowrate (kg/hr) 347,994 358,740 338,688 417,666 417,666 14,964 0 13,723 3,181,557 127,262 3,962,154 3,962,154 711,987

Solids Flowrate (kg/hr) 0 0 0 0 0 0 4,959 0 0 0 0 0 0

Temperature (°C) 35 34 45 161 193 45 178 232 15 432 587 132 559

Pressure (MPa, abs) 3.72 3.69 3.65 3.21 3.2 3.654 0.409 0.406 0.101 1.619 0.105 0.105 12.512

Enthalpy (kJ/kg)A 0.00 44.26 60.75 0.00 762.9 13.883 --- 1,007.135 30.227 463.785 791.043 280.131 3,496.259

Density (kg/m3) 29.5 29.6 27.8 17.7 16.2 60.9 5,278.6 2.6 1.2 7.9 0.4 0.9 35.2

V-L Molecular Weight 20.373 20.587 20.195 19.743 20 37.190 --- 26.923 28.857 28.857 28.831 28.831 18.015

V-L Flowrate (lbmol/hr) 37,657 38,417 36,974 46,639 46,639 887 0 1,124 243,066 9,723 302,978 302,978 87,130

V-L Flowrate (lb/hr) 767,195 790,887 746,680 920,797 920,797 32,989 0 30,253 7,014,133 280,565 8,735,053 8,735,053 1,569,662

Solids Flowrate (lb/hr) 0 0 0 0 0 0 10,933 0 0 0 0 0 0

Temperature (°F) 94 94 112 321 380 112 353 450 59 810 1,088 270 1,038

Pressure (psia) 540.0 535.0 530.0 465.0 460.0 530.0 59.3 58.9 14.7 234.9 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 19.0 26.1 328.0 6.0 --- 433.0 13.0 199.4 340.1 120.4 1,503.1

Density (lb/ft3

) 1.844 1.850 1.734 1.103 1 3.805 329.535 0.163 0.076 0.495 0.026 0.056 2.200
Cost and Performance Baseline for Fossil Energy Plants

235

There are two Shell dry feed, pressurized, upflow, entrained, slagging gasifiers, operating at 4.2 

MPa (615 psia) and processing a total of 4,753 tonnes/day (5,240 TPD) of as-received coal. The 

air separation plant supplies 3,614 tonnes/day (3,984 TPD) of 95 percent oxygen to the gasifiers 

(stream 5) and the Claus plant (stream 3). Coal reacts with oxygen and steam at a temperature of 

1427°C (2600°F) in the gasifier to produce principally hydrogen and carbon monoxide with little 

carbon dioxide formed. 

Gasifier

The gasifier includes a refractory-lined water wall that is also protected by molten slag that 

solidifies on the cooled walls. 

High-temperature heat recovery in each gasifier train is accomplished in three steps, including 

the gasifier jacket, which cools and solidifies slag touching the gasifier walls and maintains the 

syngas temperature at 1,427°C (2,600°F). The product gas from the gasifier is cooled to

approximately 1,093°C (2,000°F) by adding cooled recycled fuel gas to lower the temperature 

below the ash melting point. Gas (stream 12) then goes through a duct cooler and syngas cooler, 

which lower the gas temperature from approximately 1,093°C (2,000°F) to 316°C (600°F), and 

produce HP steam for use in the steam cycle. 

Raw Gas Cooling/Particulate Removal

After passing through the duct cooler and syngas cooler, the syngas passes through a cyclone and 

a raw gas candle filter where a majority of the fine particles are removed and returned to the 

gasifier with the coal fuel. The filter consists of an array of ceramic candle elements in a 

pressure vessel. Fines produced by the gasification system are recirculated to extinction. The 

ash that is not carried out with the gas forms slag and runs down the interior walls, exiting the 

gasifier in liquid form. The slag is solidified in a quench tank for disposal (stream 11). 

Lockhoppers are used to reduce the pressure of the solids from 4.2 to 0.1 MPa (615 to 15 psia). 

The syngas scrubber removes additional PM further downstream.

After passing through the cyclone and ceramic candle filter array, the syngas is further cooled to 

191°C (375°F) (stream 13) by raising IP steam.

About 30 percent of the cooled syngas is recycled back to the gasifier exit as quench gas. A 

single-stage compressor is utilized to boost the pressure of the cooled fuel gas stream from 4.0 

MPa (575 psia) to 4.0 MPa (585 psia) to provide quench gas to cool the gas stream from the 

gasifier.

Quench Gas Compressor

The raw syngas exiting the final raw gas cooler at 191°C (375°F) (stream 13) then enters the 

scrubber for removal of chlorides, SO2, NH3 and remaining particulate. The quench scrubber 

washes the syngas in a counter-current flow in two packed beds. The syngas leaves the scrubber 

saturated at a temperature of 94°C (201oF). The quench scrubber removes essentially all traces 

of entrained particles, principally unconverted carbon, slag, and metals. The bottoms from the 

scrubber are sent to the slag removal and handling system for processing.

Syngas Scrubber/Sour Water Stripper

The sour water stripper removes NH3, SO2, and other impurities from the waste stream of the 

scrubber. The sour gas stripper consists of a sour drum that accumulates sour water from the gas 
Cost and Performance Baseline for Fossil Energy Plants

236

scrubber and condensate from SGCs. Sour water from the drum flows to the sour stripper, which 

consists of a packed column with a steam-heated reboiler. Sour gas is stripped from the liquid 

and sent to the SRU. Remaining water is sent to wastewater treatment.

H2S and COS are at significant concentrations, requiring removal for the power plant to achieve 

the low design level of SO2 emissions. H2S is removed in an AGR process; however, because 

COS is not readily removable, it is first catalytically converted to H2S in a COS hydrolysis unit.

COS Hydrolysis, Mercury Removal and AGR

Following the water scrubber, the gas is reheated to 177°C (350°F) and fed to the COS 

hydrolysis reactor. The COS in the sour gas is hydrolyzed with steam over a catalyst bed to H2S, 

which is more easily removed by the AGR solvent. Before the raw fuel gas can be treated in the 

AGR process (stream 14), it must be cooled to about 35°C (95°F). During this cooling through a 

series of heat exchangers, part of the water vapor condenses. This water, which contains some 

NH3, is sent to the sour water stripper. The cooled syngas (stream 15) then passes through a 

carbon bed to remove 95 percent of the Hg (Section 3.1.4).

The Sulfinol process, developed by Shell in the early 1960s, is a combination process that uses a 

mixture of amines and a physical solvent. The solvent consists of an aqueous amine and 

sulfolane. Sulfinol-D uses diisopropanolamine (DIPA), while Sulfinol-M uses MDEA. The 

mixed solvents allow for better solvent loadings at high acid gas partial pressures and higher 

solubility of COS and organic sulfur compounds than straight aqueous amines. Sulfinol-M was 

selected for this application. 

The sour syngas is fed directly into an HP contactor. The HP contactor is an absorption column 

in which the H2S, COS, CO2, and small amounts of H2 and CO are removed from the gas by the 

Sulfinol solvent. The overhead gas stream from the HP contactor is then washed with water in 

the sweet gas scrubber before leaving the unit as the feed gas to the sulfur polishing unit.

The rich solvent from the bottom of the HP contactor flows through a hydraulic turbine and is 

flashed in the rich solvent flash vessel. The flashed gas is then scrubbed in the LP contactor with 

lean solvent to remove H2S and COS. The overhead from the LP contactor is flashed in the LP 

KO drum. This gas can be used as a utility fuel gas, consisting primarily of H2 and CO, at

0.8 MPa (118 psia) and 38°C (101°F). The solvent from the bottom of the LP contactor is 

returned to the rich solvent flash vessel.

Hot, lean solvent in the lean/rich solvent exchanger then heats the flashed rich solvent before 

entering the stripper. The stripper strips the H2S, COS, and CO2 from the solvent at LP with heat 

supplied through the stripper reboiler. The acid gas stream to sulfur recovery/tail gas cleanup is 

recovered as the flash gas from the stripper accumulator. The lean solvent from the bottom of 

the stripper is cooled in the lean/rich solvent exchanger and the lean solvent cooler. Most of the 

lean solvent is pumped to the HP contactor. A small amount goes to the LP contactor.

The Sulfinol process removes essentially all of the CO2 along with the H2S and COS. The acid 

gas fed to the SRU contains 39 vol% H2S and 45 vol% CO2. The CO2 passes through the SRU, 

the TGTU and ultimately is vented through the coal dryer. Since the amount of CO2 in the 

syngas is small initially, this does not have a significant effect on the mass flow reaching the GT. 

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 for Fossil Energy Plants

237

The SRU is a Claus bypass type SRU utilizing oxygen (stream 3) instead of air. The Claus plant 

produces molten sulfur (stream 21) by reacting approximately one third of the H2S in the feed to 

SO2, then reacting the H2S and SO2 to sulfur and water. The use of Claus technology results in 

an overall sulfur recovery exceeding 99 percent. 

Claus Unit

Utilizing oxygen instead of air in the Claus plant reduces the overall cost of the sulfur recovery 

plant. The sulfur plant produces approximately 119 tonnes/day (131 TPD) of elemental sulfur. 

Feed for this case consists of acid gas from both the acid gas cleanup unit (stream 20) and a vent 

stream from the sour water stripper in the gasifier section. A slipstream of clean syngas (stream 

8) is passed through an incinerator and combusted with air. The hot, nearly inert incinerator off 

gas is used to dry coal before being vented to the atmosphere.

In the furnace waste heat boiler, 11,991 kg/hr (26,435 lb/hr) of 3.0 MPa (430 psia) steam are 

generated. This steam is used to satisfy all Claus process preheating and reheating requirements 

as well as to provide some steam to the medium-pressure steam header. The sulfur condensers 

produce 0.34 MPa (50 psig) steam for the LP steam header.

Clean syngas exiting the Sulfinol absorber (stream 17) is humidified because there is not 

sufficient nitrogen from the ASU to provide the level of dilution required. The moisturized 

syngas (stream 18) is reheated (stream 19), further diluted with nitrogen from the ASU (stream 

4) and steam, and enters the advanced F Class CT burner. The CT compressor provides 

combustion air to the burner and also 19 percent of the air requirements in the ASU (stream 24). 

The exhaust gas exits the CT at 587°C (1,088°F) (stream 25) and enters the HRSG where 

additional heat is recovered until the FG exits the HRSG at 132°C (270°F) (stream 26) and is 

discharged through the plant stack. The steam raised in the HRSG is used to power an advanced, 

commercially available steam turbine using a 12.4 MPa/559°C/559°C (1800 

psig/1038°F/1038°F) steam cycle.

Power Block

The ASU is designed to produce a nominal output of 3,614 tonnes/day (3,984 TPD) of 95 mol%

O2 for use in the gasifier (stream 5) and SRU (stream 3). The plant is designed with two 

production trains. The air compressor is powered by an electric motor. Approximately 11,028

tonnes/day (12,156 TPD) of nitrogen are also recovered, compressed, and used as dilution in the 

GT combustor. About 4 percent of the GT air is used to supply approximately 19 percent of the 

ASU air requirements.

Air Separation Unit (ASU)

Balance of plant items were covered in Sections 

Balance of Plant

3.1.9, 3.1.10 and 3.1.11.

3.4.3

System assumptions for Cases 5 and 6, Shell IGCC with and without CO2 capture, are compiled 

in 

Key System Assumptions

Exhibit 3-74.
Cost and Performance Baseline for Fossil Energy Plants

238

The balance of plant assumptions are common to all cases and were presented previously in 

Balance of Plant – Cases 5 and 6

Exhibit 3-16.

Exhibit 3-74 Shell IGCC Plant Study Configuration Matrix

Case 5 6

Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O2:Coal Ratio, kg O2/kg dry coal 0.84 0.84

Carbon Conversion, % 99.5 99.5

Syngas HHV at Gasifier Outlet, 

kJ/Nm3 (Btu/scf) 10,841 (291) 10,849 (291)

Steam Cycle, MPa/°C/°C 

(psig/°F/°F)

12.4/559/559

(1800/1038/1038)

12.4/534/534

(1800/993/993)

Condenser Pressure, mm Hg

(in Hg) 51 (2.0) 51 (2.0)

CT 2x Advanced F Class 

(232 MW output each)

2x Advanced F Class

(232 MW output each)

Gasifier Technology Shell Shell

Oxidant 95 vol% Oxygen 95 vol% Oxygen

Coal Illinois No. 6 Illinois No. 6

Coal Feed Moisture Content, % 5 5

COS Hydrolysis Yes Occurs in SGS

SGS No Yes

H2S Separation Sulfinol-M Selexol 1st Stage

Sulfur Removal, % 99.7 99.9

Sulfur Recovery

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Particulate Control

Cyclone, Candle Filter, 

Scrubber, and AGR 

Absorber

Cyclone, Candle Filter, 

Scrubber, and AGR 

Absorber

Mercury Control Carbon Bed Carbon Bed

NOx Control

MNQC (LNB), N2

Dilution, Humidification 

and steam dilution

MNQC (LNB), N2 Dilution 

and Humidification

CO2 Separation N/A Selexol 2nd Stage

Overall CO2 Capture N/A 90.1%

CO2 Sequestration N/A Off-site Saline Formation
Cost and Performance Baseline for Fossil Energy Plants

239

3.4.4

The sparing philosophy for Cases 5 and 6 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.

Sparing Philosophy

The plant design consists of the following major subsystems:

• Two ASUs (2 x 50%)

• Two trains of coal drying and dry feed systems (2 x 50%)

• Two trains of gasification, including gasifier, SGC, cyclone, and barrier filter (2 x 50%). 

• Two trains of syngas clean-up process (2 x 50%).

• Two trains of Sulfinol-M acid gas removal in Case 5 and two-stage Selexol in Case 6 

(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%).

3.4.5

The plant produces a net output of 629 MWe at a net plant efficiency of 42.1 percent (HHV 

basis). Shell has reported expected efficiencies using bituminous coal of around 44-45 percent 

(HHV basis), although this value excluded the net power impact of coal drying [

Case 5 Performance Results

62

Overall performance for the entire plant is summarized in 

]. Accounting 

for coal drying would reduce the efficiency by only about 0.5-1 percentage points so the 

efficiency results for the Shell case are still lower in this study than reported by the vendor.

Exhibit 3-75, which includes auxiliary 

power requirements. The ASU accounts for approximately 79 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, 

accounts for approximately 5 percent of the auxiliary load, and the BFW pumps account for an 

additional 4 percent. All other individual auxiliary loads are 3 percent or less of the total.
Cost and Performance Baseline for Fossil Energy Plants

240

Exhibit 3-75 Case 5 Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Gas Turbine Power 464,000

Sweet Gas Expander Power 0

Steam Turbine Power 273,000

TOTAL POWER, kWe 737,000

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 440

Coal Milling 2,040

Slag Handling 520

Air Separation Unit Auxiliaries 1,000

Air Separation Unit Main Air Compressor 45,190

Oxygen Compressor 8,890

Nitrogen Compressors 29,850

Boiler Feedwater Pumps 4,500

Condensate Pump 230

Syngas Recycle Compressor 680

Circulating Water Pump 3,400

Ground Water Pumps 370

Cooling Tower Fans 1,760

Scrubber Pumps 770

Acid Gas Removal 620

Gas Turbine Auxiliaries 1,000

Steam Turbine Auxiliaries 100

Claus Plant/TGTU Auxiliaries 250

Claus Plant TG Recycle Compressor 890

Miscellaneous Balance of Plant2 3,000

Transformer Losses 2,520

TOTAL AUXILIARIES, kWe 108,020

NET POWER, kWe 628,980

Net Plant Efficiency, % (HHV) 42.1

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,545 (8,099)

CONDENSER COOLING DUTY 106 kJ/hr (106 Btu/hr) 1,393 (1,320)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 198,059 (436,646)

Thermal Input1, kWt 1,492,878

Raw Water Withdrawal, m3/min (gpm) 15.7 (4,142)

Raw Water Consumption, m3/min (gpm) 12.7 (3,356)

1 - HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)

2 - Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Fossil Energy Plants

241

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 

2.4. A summary of the plant air emissions for Case 5 is presented in 

Environmental Performance

Exhibit 3-76. 

Exhibit 3-76 Case 5 Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

80% capacity factor

kg/MWh

(lb/MWh)

SO2 0.002 (0.004) 68 (75) 0.013 (.03)

NOx 0.025 (0.059) 957 (1,055) 0.185 (.409)

Particulates 0.003 (0.0071) 115 (127) 0.022 (.049)

Hg 2.46E-7 (5.71E-7) 0.009 (0.010) 1.79E-6 (3.95E-6)

CO2 84.7 (196.9) 3,188,643 (3,514,877) 617 (1,361)

CO2

1 723 (1,595)

1 CO2 emissions based on net power instead of gross power

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 6 ppmv. This results in a concentration in the HRSG FG of less 

than 2 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, 

producing elemental sulfur. The Claus plant tail gas is compressed and recycled back to the 

AGR to capture most of the remaining sulfur. The SO2 emissions in Exhibit 3-76 include both 

the stack emissions and the coal dryer emissions.

NOx emissions are limited by the use of nitrogen dilution, humidification and steam dilution to 

15 ppmvd (as NO2 @ 15 percent O2). Ammonia in the syngas is removed with process 

condensate prior to the low-temperature AGR process and destroyed in the Claus plant burner. 

This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone 

and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

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 plant is shown in Exhibit 3-77. 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, as dissolved CO2 in the wastewater blowdown stream, and as CO2 in the stack 

gas, ASU vent gas and coal dryer vent gas. Carbon in the wastewater blowdown stream is 

calculated by difference to close the material balance.
Cost and Performance Baseline for Fossil Energy Plants

242

Exhibit 3-77 Case 5 Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 126,252 (278,339) Slag 631 (1,392)

Air (CO2) 508 (1,120) Stack Gas 124,177 (273,764)

ASU Vent 89 (197)

CO2 Product 0 (0)

Dryer Stack 

Gas 1,863 (4,106)

Total 126,760 (279,459) Total 126,760 (279,459)

Exhibit 3-78 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur in the coal drying 

gas, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 3-78 Case 5 Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 4,964 (10,944) Elemental Sulfur 4,959 (10,933)

Stack Gas 5 (11)

CO2 Product 0 (0)

Total 4,964 (10,944) Total 4,964 (10,944)

Exhibit 3-79 shows the overall water balance for the plant. Explanation on the water balance has 

been given for Case 1 [GEE] and Case 3 [CoP] but is also presented here for completeness.

Water demand represents the total amount of water required for a particular process. Some water 

is recovered within the process, primarily as syngas condensate, and is re-used as internal 

recycle. The difference between demand and recycle is raw water withdrawal. Raw water 

withdrawal is defined as the water removed from the ground or diverted from a surface-water 

source for use in the plant and was assumed to be provided 50 percent by a POTW and 50 

percent from groundwater. Raw water withdrawal can be represented by the water metered from 

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

tower makeup, BFW makeup, quench system makeup, and slag handling makeup. The 

difference between water withdrawal and process water discharge is defined as water 

consumption and can be represented by the portion of the raw water withdrawn that is 

evaporated, transpired, incorporated into products or otherwise not returned to the water source 

from which it was withdrawn. Water consumption represents the net impact of the plant process 

on the water source balance.
Cost and Performance Baseline for Fossil Energy Plants

243

Exhibit 3-79 Case 5 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)

Slag Handling 0.43 (114) 0.2 (45) 0.3 (69) 0.0 (0) 0.3 (69)

Quench/Wash 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier 1.4 (365) 0.0 (0) 1.4 (365) 0.0 (0) 1.4 (365)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

Condenser Makeup

Gasifier Steam

Shift Steam

GT Steam Dilution

BFW Makeup

1.1 (282)

0.3 (84)

0.5 (135)

0.2 (62)

0.0 (0) 1.1 (282)

0.3 (84)

0.5 (135)

0.2 (62)

0.0 (0) 1.1 (282)

Cooling Tower

BFW Blowdown

SWS Blowdown

SWS Excess Water

Humidifier Tower 

Blowdown

13.2 (3,494) 0.25 (67)

0.23 (62)

0.02 (4)

0.0 (0)

13.0 (3,427)

-0.23 (-62)

-0.02 (-4)

3.0 (786) 10.0 (2,641)

Total 16.1 (4,254) 0.4 (112) 15.7 (4,142) 3.0 (786) 12.7 (3,356)

Heat and mass balance diagrams are shown for the following subsystems in 

Heat and Mass Balance Diagrams

Exhibit 3-80 through

Exhibit 3-82:

• Coal gasification and ASU

• Syngas cleanup, sulfur recovery, and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is provided in tabular form in Exhibit 3-54. The power out is 

the combined CT and steam turbine power prior to generator losses. The power at the generator 

terminals (shown in Exhibit 3-75) is calculated by multiplying the power out by a combined 

generator efficiency of 98.3 percent.
Cost and Performance Baseline for Fossil Energy Plants

244

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

245

Exhibit 3-80 Case 5 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic

NOTES:

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 5

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 5

SHELL GASIFIER

ASU, GASIFICATION, AND GAS COOLING

DWG. NO.

BB-HMB-CS-5-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

1 OF 3

Ambient Air

Intercooled

Air Compressor

Elevated

Pressure

ASU

Intercooled

Nitrogen Compressor

Intercooled

Oxygen Compressor

Milled Coal

Sour Gas

Sour Water

ASU 

VENT

Water

Steam

Slag

Removal

Slag

GROSS PLANT POWER: 737 MWE

AUXILIARY LOAD: 108 MWE

NET PLANT POWER: 629 MWE

NET PLANT EFFICIENCY, HHV: 42.1%

NET PLANT HEAT RATE: 8,099 BTU/KWE

Dry Coal

Coal

Feeding

Steam

Air from GT Compressor

Candle 

Filter

Cyclone

Blowdown 

to Flash Tank

BFW 

from HRSG

Saturated Steam

to HRSG

N2 to GT Combustor

Boost Compressor

Recycle

Compressor

Raw Syngas

to Scrubber

Steam

Drum

220.0 T

224.9 P

50.9 H

393.5 T

625.0 P

146.7 H

To Claus Plant

9 10

1

3

4

7

6

11

13

2

1,168,307 W

59.0 T

14.7 P

48,319 W

69.5 T

16.4 P

937,042 W

90.0 T

56.4 P

14.2 H

130,495 W

50.0 T

182.0 P

2.9 H

6,236 W

90.0 T

125.0 P

11.5 H

325,738 W

90.0 T

125.0 P

11.5 H

325,738 W

241.2 T

940.0 P

40.8 H

54,557 W

376.3 T

785.0 P

436,646 W

59.0 T

14.7 P

408,345 W

60.0 T

840.0 P

1,526.1 H

43,732 W

2,600.0 T

615.0 P

1,124,342 W

1,974.4 T

615.0 P

750.2 H

787,039 W

375.0 T

585.0 P

140.1 H

280,565 W

809.8 T

234.9 P

199.4 H

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LB/HR

H ENTHALPY, BTU/LB

MWE POWER, MEGAWATTS ELECTRICAL

1,012,980 W

389.0 T

384.0 P

88.2 H

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

5

42,132 W

650.0 T

740.0 P

1,317.3 H

Coal

Drying

Incinerator

Incinerator Air Syngas Slip Stream

Flue Gas/

Combustion

Products

Incinerator Exhaust

11,218 W

112.2 T

530.0 P

26.1 H

53,179 W

59.0 T

14.7 P

92,698 W

290.0 T

14.4 P

12

8

Raw Gas

Cooler

199.0 T

384.0 P

39.8 H

1,124,342 W

600.0 T

595.0 P

221.1 H

337,303 W

375.0 T

585.0 P

140.1 H

Syngas 

Cooler

Duct Cooler

Steam 

Generation

Shell 

Gasifier
Cost and Performance Baseline for Fossil Energy Plants

246

Exhibit 3-81 Case 5 Syngas Cleanup Heat and Mass Balance Schematic

NOTES:

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 5

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 5

SHELL GASIFIER

GAS CLEANUP SYSTEM

PLANT PERFORMANCE SUMMARY

LEGEND

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Mercury 

Removal

Knock

Out

Drum

Raw Syngas

Sour 

Drum

To Water Treatment

Makeup Water

Claus Plant

Tail 

Gas

Furnace

Catalytic

Reactor

Beds

Sulfur

COS

Hydrolysis

Sour Water

Reboiler

Acid Gas

Tailgas

Carbon Dioxide

Sour Gas

Sulfur

Hydrogen

DWG. NO.

BB-HMB-CS-5-PG-2 PAGES

2 OF 3

Sour

Stripper

Clean Gas Acid Gas

Syngas

Scrubber

GROSS PLANT POWER: 737 MWE

AUXILIARY LOAD: 108 MWE

NET PLANT POWER: 629 MWE

NET PLANT EFFICIENCY, HHV: 42.1%

NET PLANT HEAT RATE: 8,099 BTU/KWE

Water

13

AGR- Sulfinol

15

16

20

21

22

787,039 W

375.0 T

585.0 P

140.1 H

23,692 W

100.0 T

799.5 P

4.8 H

782,178 W

200.9 T

580.0 P

74.7 H

351.2 T

565.0 P

127.8 H

790,887 W

93.9 T

535.0 P

19.0 H

Syngas

Coolers

HP BFW

746,680 W

112.2 T

530.0 P

26.1 H

10,933 W

353.2 T

59.3 P

From

ASU 11,669 W

90.0 T

125.0 P

11.5 H

1,962 W

141.5 T

65.0 P

75.9 H

30,253 W

450.0 T

58.9 P

32,989 W

112.2 T

530.0 P

Knock Out

Tailgas to AGR

HP BFW

350.0 T

575.0 P

128.0 H

767,195 W

94.4 T

540.0 P

19.5 H

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LB/HR

H ENTHALPY, BTU/LB

MWE POWER, MEGAWATTS ELECTRICAL

6,561 W

118.9 T

56.8 P

45.2 H

Treated Syngas

14

Slip Stream 

to Coal Dryer

17

Humidification 18 19 Humidified Fuel Gas

8

Tailgas Recycle

Compressor

Hydrogenation

And Tail Gas 

Cooling

24,042 W

120.0 T

56.8 P
Cost and Performance Baseline for Fossil Energy Plants

247

Exhibit 3-82 Case 5 Combined Cycle Power Generation Heat and Mass Balance Schematic

NOTES:

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 5

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 5

SHELL GASIFIER

POWER BLOCK SYSTEM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LB/HR

H ENTHALPY, BTU/LB

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Synthesis Gas

HRSG

HP

Turbine

IP

Turbine

Nitrogen Dilution

Intake

Ambient Air

Steam Seal 

Regulator

IP Extraction Steam

to 250 PSIA Header

Blowdown

Flash

To WWT

Make-up

Gland

Steam

Condenser

Condensate to Gasification Island

HP BFW to Raw Gas Coolers

HP Saturated Steam to HRSG Superheater

LP 

Turbine

Stack

Compressor Expander

Humidified Fuel Gas

Air to ASU

Deaerator

IP BFW

Generator

Generator

Condensate

Pump

HP Pump

Steam Turbine

LP Pump

Water

Steam

DWG. NO.

BB-HMB-CS-5-PG-3 PAGES

3 OF 3

Advanced F-Class 

Gas Turbine

GROSS PLANT POWER: 737 MWE

AUXILIARY LOAD: 108 MWE

NET PLANT POWER: 629 MWE

NET PLANT EFFICIENCY, HHV: 42.1%

NET PLANT HEAT RATE: 8,099 BTU/KWE

Flue Gas/

Combustion

Products

To Gasifier

MP Flash Bottoms

LP Flash Tops

LP 

Process

Header

From Gasifier

Island Preheating

To Claus

LP BFW

IP Pump

23

24

4

19

25 26

27

7,014,133 W

59.0 T

14.7 P

280,565 W

809.8 T

234.9 P

920,797 W

380.0 T

460.0 P

328.0 H

1,012,980 W

385.0 T

389.0 P

8,735,053 W

1,088.0 T

15.2 P

340.1 H

1,569,662 W

1,038.0 T

1,814.7 P

1,503.1 H

103.2 T

120.0 P

71.5 H

34,923 W

585.0 T

2,000.7 P

592.9 H

12,478 W

298.0 T

65.0 P

1,178.6 H

1,395,354 W

537.3 T

65.0 P

1,300.5 H

8,735,053 W

269.6 T

15.2 P

120.4 H

1,548,142 W

235.0 T

105.0 P

203.3 H

140,851 W

59.0 T

14.7 P

27.1 H

1,604,593 W

278.8 T

2,250.7 P

251.9 H

1,548,142 W

101.1 T

1.0 P

69.1 H

1,400 W

657.5 T

65.0 P

1,359.7 H

1,400 W

212.0 T

14.7 P

179.9 H

26,045 W

893.6 T

280.0 P

1,470.5 H

HOT WELL

CONDENSER

Steam Dilution

67,709 W

475.0 T

460.0 P

80,190 W

298.0 T

65.0 P

1,178.6 H

40,813 W

537.3 T

65.0 P

1,300.5 H
Cost and Performance Baseline for Fossil Energy Plants

248

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

249

Exhibit 3-83 Case 5 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,374 (5,094) 4.5 (4.3) 5,379 (5,098)

ASU Air 16.0 (15.2) 16 (15)

GT Air 96.2 (91.2) 96 (91)

Water 59.0 (55.9) 59 (56)

Auxiliary Power 389 (369) 389 (369)

TOTAL 5,374 (5,094) 175.6 (166.5) 389 (369) 5,939 (5,629)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0.8 (0.8) 1 (1)

Slag 21 (20) 33.5 (31.7) 54 (51)

Sulfur 46 (44) 0.6 (0.5) 47 (44)

CO2

Cooling Tower 

Blowdown 22.1 (20.9) 22 (21)

HRSG Flue Gas 1,110 (1,052) 1,110 (1,052)

Condenser 1,397 (1,324) 1,397 (1,324)

Non-Condenser 

Cooling Tower Loads* 215 (204) 215 (204)

Process Losses** 439 (417) 439 (417)

Power 2,653 (2,515) 2,653 (2,515)

TOTAL 67 (63) 3,219 (3,051) 2,653 (2,515) 5,939 (5,629)

* Includes ASU compressor intercoolers, CO2 compressor intercoolers, sour water stripper 

condenser, syngas cooler (low level heat rejection) and extraction air cooler.

** Calculated by difference to close the energy balance.
Cost and Performance Baseline for Fossil Energy Plants

250

3.4.6

Major equipment items for the Shell gasifier with no CO2 capture are shown in the following 

tables. The accounts used in the equipment list correspond to the account numbers used in the 

cost estimates in Section 

Case 5 - Major Equipment List

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.

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 45 tonne (50 ton) 2 1

9 Feeder Vibratory 163 tonne/hr (180 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 327 tonne/hr (360 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 163 tonne (180 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 327 tonne/hr (360 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 327 tonne/hr (360 tph) 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 726 tonne (800 ton) 3 0
Cost and Performance Baseline for Fossil Energy Plants

251

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 73 tonne/hr (80 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 218 tonne/hr (240 tph) 1 0

3 Roller Mill Feed Hopper Dual Outlet 435 tonne (480 ton) 1 0

4 Weigh Feeder Belt 109 tonne/hr (120 tph) 2 0

5 Coal Dryer and Pulverizer Rotary 109 tonne/hr (120 tph) 2 0

6 Coal Dryer Feed Hopper Vertical Hopper 218 tonne (240 ton) 2 0
Cost and Performance Baseline for Fossil Energy Plants

252

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 1,165,907 liters (308,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,473 lpm @ 91 m H2O

(1,710 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 436,356 kg/hr (962,000 lb/hr) 2 0

4 Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

7,419 lpm @ 27 m H2O

(1,960 gpm @ 90 ft H2O) 2 1

5 High Pressure 

Feedwater Pump No. 1

Barrel type, multi-stage, 

centrifugal

HP water: 6,927 lpm @ 1,859 m 

H2O (1,830 gpm @ 6,100 ft 

H2O)

2 1

6 High Pressure 

Feedwater Pump No. 2

Barrel type, multi-stage, 

centrifugal

IP water: 2,461 lpm @ 223 m 

H2O (650 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 Cylce Cooling 

Heat Exchangers Plate and frame 133 GJ/hr (126 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) 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

4,391 lpm @ 18 m H2O

(1,160 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single 

suction

2,915 lpm @ 268 m H2O 

(770 gpm @ 880 ft H2O) 3 1

16 Filtered Water Pumps Stainless steel, single 

suction

1,779 lpm @ 49 m H2O

(470 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 851,718 liter (225,000 gal) 2 0

18 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 341 lpm (90 gpm) 2 0

19 Liquid Waste Treatment 

System 10 years, 24-hour storm 1 0
Cost and Performance Baseline for Fossil Energy Plants

253

ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW 

TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized dry-feed, 

entrained bed

2,631 tonne/day, 4.2 MPa

(2,900 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler Convective spiralwound tube boiler 280,320 kg/hr (618,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 280,320 kg/hr (618,000 lb/hr) 

Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with 

pulse-jet cleaning metallic filters 2 0

5

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 196,405 kg/hr (433,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with 

condensate drain 192,777 kg/hr (425,000 lb/hr) 8 0

7 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator

191,870 kg/hr, 35°C, 3.8 MPa

(423,000 lb/hr, 94°F, 545 psia) 2 0

8 Saturation Water 

Economizers Shell and tube 131 GJ/hr (124 MMBtu/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 229,518 kg/hr, 161°C, 3.3 MPa

(506,000 lb/hr, 321°F, 480 psia) 2 0

10 Saturator Water Pump Centrifugal 3,407 lpm @ 12 m H2O

(900 gpm @ 40 ft H2O) 2 2

11 Synthesis Gas Reheater Shell and tube 186,426 kg/hr (411,000 lb/hr) 2 0

12 Flare Stack

Self-supporting, carbon 

steel, stainless steel top, 

pilot ignition

196,405 kg/hr (433,000 lb/hr) 

syngas

2 0

13 ASU Main Air 

Compressor Centrifugal, multi-stage 3,993 m3/min @ 1.3 MPa(141,000 scfm @ 190 psia) 2 0

14 Cold Box Vendor design 1,996 tonne/day (2,200 tpd) of 

95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi-stage

991 m3/min (35,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 psia)

2 0

16 Primary Nitrogen 

Compressor Centrifugal, multi-stage

3,285 m3/min (116,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 0

17 Secondary Nitrogen 

Compressor Centrifugal, single-stage

453 m3/min (16,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 0

18 Transport Nitrogen 

Boost Compressor Centrifugal, single-stage

198 m3/min (7,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 5.4 MPa (790 psia)

2 0

19 Extraction Air Heat 

Exchanger

Gas-to-gas, vendor 

design

69,853 kg/hr, 432°C, 1.6 MPa

(154,000 lb/hr, 810°F, 235 psia) 2 0
Cost and Performance Baseline for Fossil Energy Plants

254

ACCOUNT 5 SYNGAS CLEANUP

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

ACCOUNT 7 HRSG, DUCTING AND STACK

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon 

bed

191,416 kg/hr (422,000 lb/hr) 

35°C (94°F) 

3.7 MPa (540 psia)

2 0

2 Sulfur Plant Claus type 131 tonne/day (144 tpd) 1 0

3 COS Hydrolysis Reactor Fixed bed, 

catalytic

195,045 kg/hr (430,000 lb/hr)

177°C (350°F)

4.0 MPa (580 psia)

2 0

4 Acid Gas Removal Plant Sulfinol

197,313 kg/hr (435,000 lb/hr)

34°C (94°F)

3.7 MPa (535 psia)

2 0

5 Hydrogenation Reactor Fixed bed, 

catalytic

13,723 kg/hr (30,253 lb/hr)

232°C (450°F)

0.4 MPa (58.9 psia)

1 0

6 Tail Gas Recycle 

Compressor Centrifugal 10,747 kg/hr (23,692 lb/hr) each 1 0

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Gas Turbine Advanced F class 232 MW 2 0

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase 2 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS 

liner

76 m (250 ft) high x

8.4 m (28 ft) diameter 1 0

2 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator

Main steam - 393,555 kg/hr, 12.4 

MPa/559°C (867,640 lb/hr, 

1,800 psig/1,038°F)

 Reheat steam - 362,720 kg/hr, 

3.1 MPa/559°C (799,662 lb/hr, 

452 psig/1,038°F)

2 0
Cost and Performance Baseline for Fossil Energy Plants

255

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

289 MW 

12.4 MPa/559°C/559°C 

(1,800 psig/ 1038°F/1038°F)

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitiation

320 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase 1 0

3 Steam Bypass One per HRSG 50% steam flow @ design 

steam conditions 2 0

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,540 GJ/hr (1,460 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 11°C 

(20°F)

1 0

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, multicell

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

/ 1,899 GJ/hr (1,800 MMBtu/hr) 

heat duty

1 0
Cost and Performance Baseline for Fossil Energy Plants

256

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 208,198 liters (55,000 gal) 2 0

2 Slag Crusher Roll 11 tonne/hr (12 tph) 2 0

3 Slag Depressurizer Lock Hopper 11 tonne/hr (12 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 124,919 liters (33,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 56,781 liters (15,000 gal) 2

6 Slag Conveyor Drag chain 11 tonne/hr (12 tph) 2 0

7 Slag Separation Screen Vibrating 11 tonne/hr (12 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 11 tonne/hr (12 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 177,914 liters (47,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal 

centrifugal

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 56,781 liters (15,000 gal) 2 0

12 Grey Water Pumps Centrifugal 189 lpm @ 433 m H2O

(50 gpm @ 1,420 ft H2O) 2 2

13 Slag Storage Bin Vertical, field 

erected 816 tonne (900 tons) 2 0

14 Unloading Equipment Telescoping chute 91 tonne/hr (100 tph) 1 0
Cost and Performance Baseline for Fossil Energy Plants

257

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CTG Step-up 

Transformer Oil-filled 24 kV/345 kV, 260 MVA, 

3-ph, 60 Hz 2 0

2 STG Step-up 

Transformer Oil-filled 24 kV/345 kV, 320 MVA, 3-ph, 60 Hz 1 0

3

High Voltage 

Auxiliary 

Transformer

Oil-filled 345 kV/13.8 kV, 47 MVA, 

3-ph, 60 Hz 2 0

4

Medium Voltage 

Auxiliary 

Transformer

Oil-filled 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 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

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 for Fossil Energy Plants

258

3.4.7 Case 5 - Cost Estimating

The cost estimating methodology was described previously in Section 2.6. 

Costs Results

Exhibit 3-84 shows 

the total plant capital cost summary organized by cost account and Exhibit 3-85 shows a more 

detailed breakdown of the capital costs along with owner’s costs, TOC and TASC. Exhibit 3-86

shows the initial and annual O&M costs.

The estimated TOC of the Shell gasifier with no CO2 capture is $2,716/kW. Process 

contingency represents 2.3 percent of the TOC and project contingency represents 11.1 percent. 

The COE is 81.3 mills/kWh.
Cost and Performance Baseline for Fossil Energy Plants

259

Exhibit 3-84 Case 5 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14

Project: Bituminous Baseline Study

Case: Case 5 - Shell 600MW IGCC w/o CO2

Plant Size: 629.0 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 $13,346 $2,480 $10,349 $0 $0 $26,175 $2,376 $0 $5,710 $34,261 $54

2 COAL & SORBENT PREP & FEED $105,424 $8,399 $17,537 $0 $0 $131,359 $11,391 $0 $28,550 $171,300 $272

3 FEEDWATER & MISC. BOP SYSTEMS $9,632 $8,082 $9,224 $0 $0 $26,938 $2,534 $0 $6,691 $36,163 $57

4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $171,446 $0 $73,699 $0 $0 $245,145 $21,883 $34,079 $46,149 $347,255 $552

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $148,365 $0 w/equip. $0 $0 $148,365 $14,381 $0 $16,275 $179,021 $285

4.4-4.9 Other Gasification Equipment $15,541 $9,100 $10,950 $0 $0 $35,592 $3,394 $0 $8,498 $47,483 $75

SUBTOTAL 4 $335,353 $9,100 $84,649 $0 $0 $429,102 $39,657 $34,079 $70,922 $573,760 $912

 5A GAS CLEANUP & PIPING $50,101 $3,724 $47,806 $0 $0 $101,630 $9,827 $86 $22,447 $133,990 $213

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 $184

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 $188

7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $35,374 $0 $5,030 $0 $0 $40,404 $3,842 $0 $4,425 $48,670 $77

7.2-7.9 Ductwork and Stack $3,337 $2,379 $3,116 $0 $0 $8,833 $819 $0 $1,571 $11,222 $18

SUBTOTAL 7 $38,712 $2,379 $8,146 $0 $0 $49,237 $4,661 $0 $5,995 $59,893 $95

8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $28,830 $0 $4,946 $0 $0 $33,776 $3,241 $0 $3,702 $40,718 $65

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,446 $993 $7,524 $0 $0 $18,963 $1,722 $0 $4,181 $24,865 $40

SUBTOTAL 8 $39,276 $993 $12,470 $0 $0 $52,739 $4,963 $0 $7,883 $65,584 $104

9 COOLING WATER SYSTEM $8,350 $8,140 $6,922 $0 $0 $23,411 $2,174 $0 $5,234 $30,819 $49

10 ASH/SPENT SORBENT HANDLING SYS $17,858 $1,384 $8,862 $0 $0 $28,104 $2,696 $0 $3,366 $34,166 $54

11 ACCESSORY ELECTRIC PLANT $26,986 $10,003 $20,101 $0 $0 $57,090 $4,905 $0 $11,625 $73,620 $117

12 INSTRUMENTATION & CONTROL $10,318 $1,898 $6,648 $0 $0 $18,864 $1,710 $943 $3,585 $25,102 $40

13 IMPROVEMENTS TO SITE $3,326 $1,960 $8,206 $0 $0 $13,492 $1,332 $0 $4,447 $19,272 $31

14 BUILDINGS & STRUCTURES $0 $6,644 $7,614 $0 $0 $14,258 $1,298 $0 $2,544 $18,100 $29

 

TOTAL COST $744,432 $65,991 $255,695 $0 $0 $1,066,118 $98,407 $39,709 $190,092 $1,394,325 $2,217

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline for Fossil Energy Plants

260

Exhibit 3-85 Case 5 Total Plant Cost Details

Client: USDOE/NETL Report Date: 2010-Jan-14

Project: Bituminous Baseline Study

Case: Case 5 - Shell 600MW IGCC w/o CO2

Plant Size: 629.0 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 $3,505 $0 $1,713 $0 $0 $5,217 $467 $0 $1,137 $6,822 $11

1.2 Coal Stackout & Reclaim $4,529 $0 $1,098 $0 $0 $5,627 $493 $0 $1,224 $7,344 $12

1.3 Coal Conveyors & Yd Crush $4,211 $0 $1,086 $0 $0 $5,297 $465 $0 $1,152 $6,914 $11

1.4 Other Coal Handling $1,102 $0 $251 $0 $0 $1,353 $118 $0 $294 $1,766 $3

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 $2,480 $6,201 $0 $0 $8,681 $832 $0 $1,903 $11,416 $18

SUBTOTAL 1. $13,346 $2,480 $10,349 $0 $0 $26,175 $2,376 $0 $5,710 $34,261 $54

2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $40,051 $2,406 $5,836 $0 $0 $48,294 $4,167 $0 $10,492 $62,953 $100

2.2 Prepared Coal Storage & Feed $1,897 $454 $297 $0 $0 $2,648 $226 $0 $575 $3,450 $5

2.3 Dry Coal Injection System $62,432 $725 $5,798 $0 $0 $68,955 $5,939 $0 $14,979 $89,872 $143

2.4 Misc.Coal Prep & Feed $1,043 $759 $2,276 $0 $0 $4,078 $375 $0 $891 $5,344 $8

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 $4,055 $3,329 $0 $0 $7,384 $684 $0 $1,614 $9,681 $15

SUBTOTAL 2. $105,424 $8,399 $17,537 $0 $0 $131,359 $11,391 $0 $28,550 $171,300 $272

3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $3,130 $5,375 $2,837 $0 $0 $11,343 $1,051 $0 $2,479 $14,872 $24

3.2 Water Makeup & Pretreating $564 $59 $315 $0 $0 $938 $89 $0 $308 $1,335 $2

3.3 Other Feedwater Subsystems $1,713 $579 $521 $0 $0 $2,812 $253 $0 $613 $3,678 $6

3.4 Service Water Systems $323 $664 $2,306 $0 $0 $3,293 $321 $0 $1,084 $4,699 $7

3.5 Other Boiler Plant Systems $1,732 $671 $1,663 $0 $0 $4,065 $386 $0 $890 $5,341 $8

3.6 FO Supply Sys & Nat Gas $313 $591 $551 $0 $0 $1,454 $140 $0 $319 $1,913 $3

3.7 Waste Treatment Equipment $788 $0 $481 $0 $0 $1,269 $124 $0 $418 $1,810 $3

3.8 Misc. Power Plant Equipment $1,071 $143 $550 $0 $0 $1,764 $170 $0 $580 $2,514 $4

SUBTOTAL 3. $9,632 $8,082 $9,224 $0 $0 $26,938 $2,534 $0 $6,691 $36,163 $57

4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $171,446 $0 $73,699 $0 $0 $245,145 $21,883 $34,079 $46,149 $347,255 $552

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $148,365 $0 w/equip. $0 $0 $148,365 $14,381 $0 $16,275 $179,021 $285

4.4 LT Heat Recovery & FG Saturation $15,541 $0 $5,908 $0 $0 $21,449 $2,093 $0 $4,709 $28,251 $45

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 $8,179 $4,667 $0 $0 $12,847 $1,176 $0 $3,506 $17,528 $28

SUBTOTAL 4. $335,353 $9,100 $84,649 $0 $0 $429,102 $39,657 $34,079 $70,922 $573,760 $912

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline for Fossil Energy Plants

261

Exhibit 3-85 Case 5 Total Plant Cost Details (Continued)

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 $35,020 $0 $29,715 $0 $0 $64,735 $6,261 $0 $14,199 $85,194 $135

5A.2 Elemental Sulfur Plant $9,609 $1,915 $12,397 $0 $0 $23,921 $2,324 $0 $5,249 $31,494 $50

5A.3 Mercury Removal $976 $0 $743 $0 $0 $1,720 $166 $86 $394 $2,366 $4

5A.4 COS Hydrolysis $2,882 $0 $3,764 $0 $0 $6,646 $646 $0 $1,459 $8,751 $14

5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Blowback Gas Systems $1,613 $271 $153 $0 $0 $2,037 $193 $0 $446 $2,677 $4

5A.7 Fuel Gas Piping $0 $764 $535 $0 $0 $1,298 $120 $0 $284 $1,703 $3

5A.9 HGCU Foundations $0 $773 $499 $0 $0 $1,272 $117 $0 $417 $1,805 $3

SUBTOTAL 5A. $50,101 $3,724 $47,806 $0 $0 $101,630 $9,827 $86 $22,447 $133,990 $213

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 $184

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 $188

7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $35,374 $0 $5,030 $0 $0 $40,404 $3,842 $0 $4,425 $48,670 $77

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,711 $1,220 $0 $0 $2,931 $257 $0 $638 $3,826 $6

7.4 Stack $3,337 $0 $1,254 $0 $0 $4,591 $440 $0 $503 $5,534 $9

7.9 HRSG,Duct & Stack Foundations $0 $669 $642 $0 $0 $1,311 $122 $0 $430 $1,863 $3

SUBTOTAL 7. $38,712 $2,379 $8,146 $0 $0 $49,237 $4,661 $0 $5,995 $59,893 $95

8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $28,830 $0 $4,946 $0 $0 $33,776 $3,241 $0 $3,702 $40,718 $65

8.2 Turbine Plant Auxiliaries $200 $0 $459 $0 $0 $659 $64 $0 $72 $796 $1

8.3 Condenser & Auxiliaries $4,740 $0 $1,514 $0 $0 $6,254 $598 $0 $685 $7,537 $12

8.4 Steam Piping $5,506 $0 $3,873 $0 $0 $9,379 $806 $0 $2,546 $12,731 $20

8.9 TG Foundations $0 $993 $1,678 $0 $0 $2,671 $253 $0 $877 $3,801 $6

SUBTOTAL 8. $39,276 $993 $12,470 $0 $0 $52,739 $4,963 $0 $7,883 $65,584 $104

9 COOLING WATER SYSTEM

9.1 Cooling Towers $5,766 $0 $1,049 $0 $0 $6,815 $649 $0 $1,120 $8,584 $14

9.2 Circulating Water Pumps $1,500 $0 $99 $0 $0 $1,599 $135 $0 $260 $1,993 $3

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 $14

9.5 Make-up Water System $317 $0 $453 $0 $0 $769 $74 $0 $169 $1,012 $2

9.6 Component Cooling Water Sys $637 $762 $542 $0 $0 $1,942 $182 $0 $425 $2,549 $4

9.9 Circ.Water System Foundations $0 $1,977 $3,361 $0 $0 $5,339 $506 $0 $1,753 $7,598 $12

SUBTOTAL 9. $8,350 $8,140 $6,922 $0 $0 $23,411 $2,174 $0 $5,234 $30,819 $49
Cost and Performance Baseline for Fossil Energy Plants

262

Exhibit 3-85 Case 5 Total Plant Cost Details (Continued)

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 $15,534 $0 $7,661 $0 $0 $23,194 $2,229 $0 $2,542 $27,965 $44

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 $527 $0 $573 $0 $0 $1,100 $107 $0 $181 $1,387 $2

10.7 Ash Transport & Feed Equipment $706 $0 $170 $0 $0 $877 $82 $0 $144 $1,102 $2

10.8 Misc. Ash Handling Equipment $1,091 $1,337 $399 $0 $0 $2,827 $269 $0 $464 $3,561 $6

10.9 Ash/Spent Sorbent Foundation $0 $47 $59 $0 $0 $105 $10 $0 $34 $149 $0

SUBTOTAL 10. $17,858 $1,384 $8,862 $0 $0 $28,104 $2,696 $0 $3,366 $34,166 $54

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $950 $0 $939 $0 $0 $1,889 $180 $0 $207 $2,276 $4

11.2 Station Service Equipment $3,667 $0 $330 $0 $0 $3,998 $369 $0 $437 $4,803 $8

11.3 Switchgear & Motor Control $6,780 $0 $1,233 $0 $0 $8,013 $743 $0 $1,313 $10,069 $16

11.4 Conduit & Cable Tray $0 $3,149 $10,390 $0 $0 $13,539 $1,309 $0 $3,712 $18,561 $30

11.5 Wire & Cable $0 $6,017 $3,954 $0 $0 $9,971 $724 $0 $2,674 $13,369 $21

11.6 Protective Equipment $0 $679 $2,471 $0 $0 $3,150 $308 $0 $519 $3,976 $6

11.7 Standby Equipment $234 $0 $228 $0 $0 $462 $44 $0 $76 $583 $1

11.8 Main Power Transformers $15,356 $0 $144 $0 $0 $15,500 $1,173 $0 $2,501 $19,174 $30

11.9 Electrical Foundations $0 $157 $411 $0 $0 $568 $54 $0 $187 $810 $1

SUBTOTAL 11. $26,986 $10,003 $20,101 $0 $0 $57,090 $4,905 $0 $11,625 $73,620 $117

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 $1,019 $0 $680 $0 $0 $1,699 $161 $85 $292 $2,236 $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 $234 $0 $150 $0 $0 $384 $36 $19 $88 $528 $1

12.7 Computer & Accessories $5,433 $0 $174 $0 $0 $5,607 $515 $280 $640 $7,043 $11

12.8 Instrument Wiring & Tubing $0 $1,898 $3,880 $0 $0 $5,778 $490 $289 $1,639 $8,197 $13

12.9 Other I & C Equipment $3,632 $0 $1,764 $0 $0 $5,396 $508 $270 $926 $7,099 $11

SUBTOTAL 12. $10,318 $1,898 $6,648 $0 $0 $18,864 $1,710 $943 $3,585 $25,102 $40
Cost and Performance Baseline for Fossil Energy Plants

263

Exhibit 3-85 Case 5 Total Plant Cost Details (Continued)

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

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $104 $2,230 $0 $0 $2,335 $232 $0 $770 $3,336 $5

13.2 Site Improvements $0 $1,856 $2,466 $0 $0 $4,322 $426 $0 $1,425 $6,173 $10

13.3 Site Facilities $3,326 $0 $3,509 $0 $0 $6,835 $674 $0 $2,253 $9,762 $16

SUBTOTAL 13. $3,326 $1,960 $8,206 $0 $0 $13,492 $1,332 $0 $4,447 $19,272 $31

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 $2,428 $3,459 $0 $0 $5,887 $542 $0 $964 $7,394 $12

14.3 Administration Building $0 $841 $610 $0 $0 $1,452 $129 $0 $237 $1,818 $3

14.4 Circulation Water Pumphouse $0 $166 $88 $0 $0 $254 $22 $0 $41 $317 $1

14.5 Water Treatment Buildings $0 $471 $460 $0 $0 $931 $84 $0 $152 $1,168 $2

14.6 Machine Shop $0 $431 $295 $0 $0 $725 $64 $0 $118 $908 $1

14.7 Warehouse $0 $695 $449 $0 $0 $1,144 $101 $0 $187 $1,432 $2

14.8 Other Buildings & Structures $0 $416 $324 $0 $0 $741 $66 $0 $161 $968 $2

14.9 Waste Treating Building & Str. $0 $931 $1,779 $0 $0 $2,710 $253 $0 $592 $3,555 $6

SUBTOTAL 14. $0 $6,644 $7,614 $0 $0 $14,258 $1,298 $0 $2,544 $18,100 $29

TOTAL COST $744,432 $65,991 $255,695 $0 $0 $1,066,118 $98,407 $39,709 $190,092 $1,394,325 $2,217

Owner's Costs

Preproduction Costs

6 Months All Labor $12,811 $20

1 Month Maintenance Materials $2,891 $5

1 Month Non-fuel Consumables $407 $1

1 Month Waste Disposal $260 $0

25% of 1 Months Fuel Cost at 100% CF $1,521 $2

2% of TPC $27,887 $44

Total $45,778 $73

Inventory Capital

60 day supply of fuel and consumables at 100% CF $12,790 $20

0.5% of TPC (spare parts) $6,972 $11

Total $19,762 $31

Initial Cost for Catalyst and Chemicals $963 $2

Land $900 $1

Other Owner's Costs $209,149 $333

Financing Costs $37,647 $60

Total Overnight Costs (TOC) $1,708,524 $2,716

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $1,947,717 $3,097
Cost and Performance Baseline for Fossil Energy Plants

264

Exhibit 3-86 Case 5 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 5 - Shell 600MW IGCC w/o CO2 Heat Rate-net (Btu/kWh): 8,099

MWe-net: 629

 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

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 2.0 2.0

 Operator 9.0 9.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 3.0 3.0

 TOTAL-O.J.'s 15.0 15.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $5,918,913 $9.410

Maintenance Labor Cost $14,578,930 $23.179

Administrative & Support Labor $5,124,461 $8.147

Property Taxes and Insurance $27,886,508 $44.336

TOTAL FIXED OPERATING COSTS $53,508,812 $85.072

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $27,756,840 $0.00630

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water (/1000 gallons) 0 2,982 1.08 $0 $941,938 $0.00021

Chemicals

MU & WT Chem. (lbs) 0 17,767 0.17 $0 $897,887 $0.00020

Carbon (Mercury Removal) (lb) 69,345 95 1.05 $72,824 $29,130 $0.00001

COS Catalyst (m3) 262 0.18 2,397.36 $627,613 $125,523 $0.00003

Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000

Sulfinol Solution (gal) 26,146 629 10.05 $262,733 $1,846,503 $0.00042

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip. 1.82 131.27 $0 $69,945 $0.00002

Subtotal Chemicals $963,170 $2,968,988 $0.00067

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 95 0.42 $0 $11,569 $0.00000

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 525 16.23 $0 $2,486,313 $0.00056

 Subtotal-Waste Disposal $0 $2,497,882 $0.00057

By-products & Emissions

Sulfur (ton) 0 131 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $963,170 $34,165,649 $0.00775

Fuel (ton) 0 5,240 38.18 $0 $58,422,569 $0.01325
Cost and Performance Baseline for Fossil Energy Plants

265

3.4.8

This case is configured to produce electric power with CO2 capture. The plant configuration is 

the same as Case 5, namely two Shell gasifier trains, two advanced F class turbines, two HRSGs 

and one steam turbine. The gross power output is constrained by the capacity of the two CTs, 

and since the CO2 capture and compression process increases the auxiliary load on the plant, the 

net output is significantly reduced relative to Case 5 (497 MW versus 629 MW).

Case 6 - Shell IGCC Power Plant with CO2 Capture

The process description for Case 6 is similar to Case 5 with several notable exceptions to 

accommodate CO2 capture. A BFD and stream tables for Case 6 are shown in Exhibit 3-87 and 

Exhibit 3-88, respectively. Instead of repeating the entire process description, only differences 

from Case 5 are reported here.

No differences from Case 5.

Coal Preparation and Feed Systems

The gasification process is the same as Case 5 with the following exceptions:

Gasification

• Total coal feed (as-received) to the two gasifiers is 5,065 tonnes/day (5,583 TPD) 

(stream 9)

• The ASU provides 3,852 tonnes/day (4,246 TPD) of 95 mol% oxygen to the gasifier and

Claus plant (streams 5 and 3)

After the raw syngas is cooled to approximately 1,093°C (2,000°F) by the syngas quench 

recycle, syngas is further cooled to 899°C (1,650°F) by raising HP steam at 13.8 MPa (2,000 

psia). A water quench follows to cool the raw syngas from 899°C (1,650°F) to 399°C (750°F) 

while providing a portion of the water required for WGS. The syngas is then cooled to 316°C 

(600°F) by raising steam, which is used in the SGS unit. After particulate filtration, the syngas is 

cooled to 232°C (450°F) by raising IP steam at 0.4 MPa (65 psia) before proceeding to the 

scrubber.

Raw Gas Cooling/Particulate Removal

Syngas exits the scrubber at 191°C (376°F).

Syngas Scrubber/Sour Water Stripper

The SGS process was described in Section 

Sour Gas Shift (SGS)

3.1.3. In Case 6 the syngas after the scrubber is 

reheated to 197°C (386°F) and then steam (stream 14) is added to adjust the H2O:CO molar ratio 

to approximately 1.8:1 prior to the first SGS reactor. The hot syngas exiting the first stage of 

SGS is used to preheat water used to humidify clean syngas prior to entering the CT. One more 

stage of SGS (for a total of two) results in 97.8 percent overall conversion of the CO to CO2. 

The warm syngas from the second stage of SGS is cooled to 248°C (478°F) by preheating the 

syngas prior to the first stage of SGS. The SGS catalyst also serves to hydrolyze COS thus 

eliminating the need for a separate COS hydrolysis reactor. Following the second stage of SGS, 

the syngas is further cooled to 35°C (95°F) prior to the mercury removal beds.
Cost and Performance Baseline for Fossil Energy Plants

266

Mercury removal is the same as in Case 5.

Mercury Removal and AGR

The AGR process in Case 6 is a two stage Selexol process where H2S is removed in the first 

stage and CO2 in the second stage of absorption. The process results in three product streams, 

the clean syngas (stream 18), a CO2-rich stream and an acid gas feed to the Claus plant (stream 

22). The acid gas contains 34 percent H2S and 51 percent CO2 with the balance primarily H2. 

The CO2-rich stream is discussed further in the CO2 compression section. 

CO2 from the AGR process is flashed at three pressure levels to separate CO2 and decrease H2

losses to the CO2 product pipeline. The HP CO2 stream is flashed at 2.0 MPa (289.7 psia), 

compressed, and recycled back to the CO2 absorber. The MP CO2 stream is flashed at 1.0 MPa 

(149.7 psia). The LP CO2 stream is flashed at 0.1 MPa (16.7 psia), compressed to 1.0 MPa 

(149.5 psia), and combined with the MP CO2 stream. The combined stream is compressed from 

1.0 MPa (149.5 psia) to a SC condition at 15.3 MPa (2215 psia) using a multiple-stage, 

intercooled compressor. During compression, the CO2 stream is dehydrated to a dewpoint of 

-40oC (-40°F) with triethylene glycol. The raw CO2 stream from the Selexol process contains 

over 99 percent CO2. The CO2 (stream 21) is transported to the plant fence line and is 

sequestration ready. CO2 TS&M costs were estimated using the methodology described in 

Section 2.7.

CO2 Compression and Dehydration

The Claus plant is the same as Case 5 with the following exceptions:

Claus Unit

• 5,277 kg/hr (11,634 lb/hr) of sulfur (stream 23) are produced

• The waste heat boiler generates 13,697 kg/hr (30,197 lb/hr) of 3.0 MPa (430 psia) steam, 

which provides all of the Claus plant process needs and provides some additional steam 

to the medium pressure steam header.

Clean syngas from the AGR plant is combined with a small amount of clean gas from the CO2

compression process (stream 18) and partially humidified because the nitrogen available from 

the ASU is insufficient to provide adequate dilution. The moisturized syngas is reheated to 

193°C (380°F) using HP BFW, diluted with nitrogen (stream 4), and then enters the CT burner. 

The exhaust gas (stream 27) exits the CT at 562°C (1,043°F) and enters the HRSG where 

additional heat is recovered. The FG exits the HRSG at 132°C (270°F) (stream 28) and is 

discharged through the plant stack. The steam raised in the HRSG is used to power an advanced 

commercially available steam turbine using a 12.4 MPa/534°C/534°C (1800 psig/993°F/993°F) 

steam cycle. There is no integration between the CT and the ASU in this case.

Power Block

The same elevated pressure ASU is used as in Case 5 and produces 3,852 tonnes/day (4,246 

TPD) of 95 mol% oxygen and 12,290 tonnes/day (13,547 TPD) of nitrogen. There is no 

integration between the ASU and the CT.

Air Separation Unit (ASU)
Cost and Performance Baseline for Fossil Energy Plants

267

Balance of plant items were covered in Sections 

Balance of Plant

3.1.9, 3.1.10 and 3.1.11.
Cost and Performance Baseline for Fossil Energy Plants

268

Exhibit 3-87 Case 6 Block Flow Diagram, Shell IGCC with CO2 Capture
Cost and Performance Baseline for Fossil Energy Plants

269

Exhibit 3-88 Case 6 Stream Table, Shell IGCC with CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

V-L Mole Fraction

Ar 0.0092 0.0230 0.0318 0.0023 0.0318 0.0000 0.0023 0.0096 0.0000 0.0000 0.0000 0.0085 0.0061 0.0000 0.0047

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0005 0.0004 0.0000 0.0003

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0130 0.0000 0.0000 0.0000 0.5187 0.3712 0.0000 0.2873

CO2 0.0003 0.0079 0.0000 0.0000 0.0000 0.0000 0.0000 0.0455 0.0000 0.0000 0.0000 0.0126 0.0090 0.0000 0.0070

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0004 0.0000 0.0003

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.8727 0.0000 0.8090 0.0000 0.2691 0.1926 0.0000 0.1491

H2O 0.0099 0.1984 0.0000 0.0003 0.0000 1.0000 0.0004 0.0001 0.0000 0.0935 0.0000 0.1278 0.3758 1.0000 0.5172

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0030 0.0000 0.0008 0.0006 0.0000 0.0001

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0052 0.0000 0.0040

N2 0.7732 0.5759 0.0178 0.9919 0.0178 0.0000 0.9919 0.0585 0.0000 0.0163 0.0000 0.0507 0.0363 0.0000 0.0281

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0033 0.0024 0.0000 0.0019

O2 0.2074 0.1948 0.9504 0.0054 0.9504 0.0000 0.0054 0.0000 0.0000 0.0782 0.0000 0.0000 0.0000 0.0000 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 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 24,277 1,004 102 17,310 4,886 1,130 940 308 0 5,809 0 26,493 29,249 11,003 37,783

V-L Flowrate (kg/hr) 700,548 27,328 3,289 485,713 157,225 20,363 26,368 1,900 0 37,081 0 531,672 569,894 198,213 723,426

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 211,040 160,281 21,137 0 0 0 0

Temperature (°C) 15 20 32 93 32 343 32 35 15 16 1,427 1,082 232 288 217

Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.10 5.62 3.59 0.10 5.79 4.24 4.24 4.03 5.52 3.96

Enthalpy (kJ/kg)A 30.23 36.90 26.67 92.51 26.67 3,063.97 20.78 163.14 --- 3,549.69 --- 2,043.24 1,217.35 2,918.18 1,541.02

Density (kg/m3) 1.2 1.5 11.0 24.4 11.0 20.1 62.8 8.5 --- 16.5 --- 7.5 19.1 25.6 19.5

V-L Molecular Weight 28.857 27.206 32.181 28.060 32.181 18.015 28.060 6.159 --- 6.383 --- 20.069 19.484 18.015 19.147

V-L Flowrate (lbmol/hr) 53,521 2,215 225 38,162 10,771 2,492 2,072 680 0 12,807 0 58,407 64,482 24,256 83,298

V-L Flowrate (lb/hr) 1,544,445 60,249 7,250 1,070,813 346,622 44,894 58,132 4,188 0 81,749 0 1,172,137 1,256,401 436,986 1,594,881

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 465,264 353,359 46,599 0 0 0 0

Temperature (°F) 59 68 90 199 90 650 90 94 59 60 2,600 1,980 450 550 422

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 740.0 815.0 520.0 14.7 840.0 615.0 615.0 585.0 800.0 575.0

Enthalpy (Btu/lb)A 13.0 15.9 11.5 39.8 11.5 1,317.3 8.9 70.1 --- 1,526.1 --- 878.4 523.4 1,254.6 662.5

Density (lb/ft3) 0.076 0.097 0.687 1.521 0.687 1.257 3.918 0.531 --- 1.029 --- 0.468 1.190 1.597 1.218

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Fossil Energy Plants

270

Exhibit 3-88 Case 6 Stream Table (Continued)

16 17 18 19 20 21 22 23 24 25 26 27 28 29

V-L Mole Fraction

Ar 0.0062 0.0062 0.0096 0.0086 0.0086 0.0002 0.0017 0.0000 0.0065 0.0102 0.0092 0.0088 0.0088 0.0000

CH4 0.0004 0.0004 0.0006 0.0005 0.0005 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0084 0.0084 0.0130 0.0116 0.0116 0.0002 0.0025 0.0000 0.1143 0.0060 0.0000 0.0000 0.0000 0.0000

CO2 0.3776 0.3810 0.0455 0.0407 0.0407 0.9944 0.5141 0.0000 0.2866 0.6257 0.0003 0.0080 0.0080 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.5633 0.5593 0.8727 0.7819 0.7819 0.0050 0.1068 0.0000 0.0659 0.2694 0.0000 0.0000 0.0000 0.0000

H2O 0.0016 0.0016 0.0001 0.1041 0.1041 0.0000 0.0300 0.0000 0.4715 0.0017 0.0099 0.1374 0.1374 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2S 0.0057 0.0057 0.0000 0.0000 0.0000 0.0000 0.3398 0.0000 0.0014 0.0057 0.0000 0.0000 0.0000 0.0000

N2 0.0368 0.0374 0.0585 0.0524 0.0524 0.0002 0.0047 0.0000 0.0516 0.0813 0.7732 0.7397 0.7397 0.0000

NH3 0.0000 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 0.2074 0.1060 0.1060 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0018 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 28,837 29,237 18,312 20,438 20,438 10,099 488 0 630 400 110,253 139,892 139,892 28,855

V-L Flowrate (kg/hr) 562,223 574,690 112,786 151,092 151,092 442,270 17,202 0 16,585 12,466 3,181,557 3,818,362 3,818,362 519,836

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,277 0 0 0 0 0 0

Temperature (°C) 35 35 35 137 193 51 48 178 232 38 15 562 132 534

Pressure (MPa, abs) 3.62 3.6 3.585 3.206 3.172 15.270 0.163 0.119 0.085 5.51 0.101 0.105 0.105 12.512

Enthalpy (kJ/kg)A 45.33 44.5 163.144 1,181.236 1,416.715 -161.704 85.006 --- 1,114.498 8.30 30.227 866.140 371.288 3,431.999

Density (kg/m3) 28.1 28.1 8.5 6.9 6.0 639.8 2.2 5,279.4 0.5 74.4 1.2 0.4 0.8 36.8

V-L Molecular Weight 19.496 20 6.159 7.393 7.393 43.792 35.245 --- 26.336 31.160 28.857 27.295 27.295 18.015

V-L Flowrate (lbmol/hr) 63,576 64,458 40,371 45,059 45,059 22,265 1,076 0 1,388 882 243,066 308,408 308,408 63,615

V-L Flowrate (lb/hr) 1,239,491 1,266,974 248,650 333,100 333,100 975,038 37,925 0 36,563 27,484 7,014,133 8,418,047 8,418,047 1,146,042

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 11,634 0 0 0 0 0 0

Temperature (°F) 95 94 94 278 380 124 119 352 450 100 59 1,043 270 993

Pressure (psia) 525.0 520.0 520.0 465.0 460.0 2,214.7 23.7 17.3 12.3 799.5 14.7 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 19.5 19.1 70.1 507.8 609.1 -69.5 36.5 --- 479.1 3.6 13.0 372.4 159.6 1,475.5

Density (lb/ft3) 1.753 2 0.531 0.431 0.374 39.942 0.135 329.584 0.033 4.646 0.076 0.026 0.053 2.295
Cost and Performance Baseline for Fossil Energy Plants

271

3.4.9

The Case 6 modeling assumptions were presented previously in Section 

Case 6 Performance Results

3.4.3.

The plant produces a net output of 497 MWe at a net plant efficiency of 31.2 percent (HHV 

basis). Overall performance for the plant is summarized in Exhibit 3-89, which includes 

auxiliary power requirements. The ASU accounts for approximately 58 percent of the auxiliary 

load between the main air compressor, the nitrogen compressor, the oxygen compressor and 

ASU auxiliaries. The two-stage Selexol process and CO2 compression account for an additional 

28 percent of the auxiliary power load. The BFW and CWS (CWPs and cooling tower fan) 

comprise approximately 4 percent of the load, leaving 10 percent of the auxiliary load for all 

other systems.
Cost and Performance Baseline for Fossil Energy Plants

272

Exhibit 3-89 Case 6 Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Gas Turbine Power 464,000

Sweet Gas Expander Power 0

Steam Turbine Power 209,400

TOTAL POWER, kWe 673,400

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 460

Coal Milling 2,170

Slag Handling 550

Air Separation Unit Auxiliaries 1,000

Air Separation Unit Main Air Compressor 59,740

Oxygen Compressor 9,460

Nitrogen Compressors 32,910

CO2 Compressor 30,210

Boiler Feedwater Pumps 3,500

Condensate Pump 280

Quench Water Pump 610

Syngas Recycle Compressor 790

Circulating Water Pump 4,370

Ground Water Pumps 510

Cooling Tower Fans 2,260

Scrubber Pumps 360

Acid Gas Removal 18,650

Gas Turbine Auxiliaries 1,000

Steam Turbine Auxiliaries 100

Claus Plant/TGTU Auxiliaries 250

Claus Plant TG Recycle Compressor 1,830

Miscellaneous Balance of Plant2 3,000

Transformer Losses 2,530

TOTAL AUXILIARIES, kWe 176,540

NET POWER, kWe 496,860

Net Plant Efficiency, % (HHV) 31.2

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,526 (10,924)

CONDENSER COOLING DUTY 106 kJ/hr (106 Btu/hr) 1,340 (1,270)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 211,040 (465,264)

Thermal Input1, kWt 1,590,722

Raw Water Withdrawal, m3/min (gpm) 21.3 (5,633)

Raw Water Consumption, m3/min (gpm) 17.5 (4,616)

1 - HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 

2 - Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Fossil Energy Plants

273

The environmental targets for emissions of Hg, NOx, SO2, CO2, and PM were presented in 

Section 2.4. A summary of the plant air emissions for Case 6 is presented in 

Environmental Performance

Exhibit 3-90. 

Exhibit 3-90 Case 6 Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

80% CF

kg/MWh

(lb/MWh)

SO2 0.001 (0.002) 37 (40) 0.008 (.02)

NOx 0.021 (0.049) 847 (934) 0.180 (.396)

Particulates 0.003 (0.0071) 123 (135) 0.026 (.057)

Hg 2.46E-7 (5.71E-7) 0.010 (0.011) 2.09E-6 (4.61E-6)

CO2 8.6 (20.0) 344,507 (379,754) 73 (161)

CO2

1

99 (218)

1 CO2 emissions based on net power instead of gross power

The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the two-stage 

Selexol AGR process. The CO2 capture target results in the sulfur compounds being removed to 

a greater extent than required in the environmental targets of Section 2.4. The clean syngas 

exiting the AGR process has a sulfur concentration of approximately 4 ppmv. This results in a 

concentration in the HRSG FG of less than 1 ppmv. The H2S-rich regeneration gas from the 

AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is 

compressed and recycled back to the AGR where most of the remaining sulfur is removed.

NOx emissions are limited by the use of nitrogen dilution and humidification to 15 ppmvd (as 

NO2 @ 15 percent O2). Ammonia in the syngas is removed with process condensate prior to the 

low-temperature AGR process and subsequently destroyed in the Claus plant burner. This helps 

lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone 

and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Ninety five percent of mercury is captured from the syngas by an activated carbon bed.

Ninety five percent of the CO2 from the syngas is captured in the AGR system and compressed 

for sequestration. Because not all CO is converted to CO2 in the shift reactors, the overall CO2

removal is 90.1 percent.

The carbon balance for the plant 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 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 slag, CO2 in the 

stack gas, coal dryer vent gas, 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 for Fossil Energy Plants

274

(Carbon in Product for Sequestration)/[(Carbon in the Coal)-(Carbon in Slag)] or

265,992/(296,581-1,483) * 100 or

90.1 percent

Exhibit 3-91 Case 6 Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 134,527 (296,581) Slag 673 (1,483)

Air (CO2) 532 (1,173) Stack Gas 13,416 (29,578)

ASU Vent 95 (210)

CO2 Product 120,652 (265,992)

Coal Dryer 

Stack Gas 223 (491)

Total 135,059 (297,754) Total 135,059 (297,754)

Exhibit 3-92 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the 

stack gas and sulfur from the tail gas unit that is vented through the coal dryer. Sulfur in the slag 

is considered negligible.

Exhibit 3-92 Case 6 Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 5,290 (11,661) Elemental 

Sulfur 5,277 (11,634)

Stack Gas 3 (6)

CO2 Product 10 (22)

Total 5,290 (11,661) Total 5,290 (11,661)

Exhibit 3-93 shows the overall water balance for the plant. The exhibit is presented in an 

identical manner as for previous cases.
Cost and Performance Baseline for Fossil Energy Plants

275

Exhibit 3-93 Case 6 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)

Slag Handling 0.46 (121) 0.46 (121) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 3.2 (836) 2.2 (587) 0.9 (250) 0.0 (0) 0.9 (250)

Humidifier 0.7 (177) 0.7 (177) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7) -0.03 (-7)

Condenser Makeup

Gasifier Steam

Shift Steam

GT Steam 

Dilution

BFW Makeup

3.8 (1,012)

0.3 (90)

3.3 (874)

0.18 (48)

0.0 (0) 3.8 (1,012)

0.3 (90)

3.3 (874)

0.18 (48)

0.0 (0) 3.8 (1,012)

Cooling Tower

BFW Blowdown

SWS Blowdown

SWS Excess 

Water

Humidifier Tower 

Blowdown

17.0 (4,490) 0.45 (119)

0.18 (48)

0.27 (71)

16.5 (4,371)

-0.18 (-48)

-0.27 (-71)

3.8 (1,010) 12.7 (3,361)

Total 25.1 (6,637) 3.8 (1,004) 21.3 (5,633) 3.8 (1,017) 17.5 (4,616)

Heat and mass balance diagrams are shown for the following subsystems in 

Heat and Mass Balance Diagrams

Exhibit 3-94 through

Exhibit 3-96:

• Coal gasification and ASU

• Syngas cleanup including sulfur recovery and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is provided in tabular form in Exhibit 3-97. The power out is 

the combined CT and steam turbine power prior to generator losses. The power at the generator 

terminals (shown in Exhibit 3-89) is calculated by multiplying the power out by a combined 

generator efficiency of 98.4 percent.
Cost and Performance Baseline for Fossil Energy Plants

276

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

277

Exhibit 3-94 Case 6 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic

NOTES:

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 6

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 6

SHELL GASIFIER

ASU, GASIFICATION, AND GAS COOLING

DWG. NO.

BB-HMB-CS-6-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

1 OF 3

Ambient Air

Intercooled

Air Compressor

Elevated

Pressure

ASU

Intercooled

Nitrogen Compressor

Intercooled

Oxygen Compressor

Milled Coal

Sour Gas

Sour Water

ASU 

VENT

Water

Steam

Slag

Removal

Slag

GROSS PLANT POWER: 673 MWE

AUXILIARY LOAD: 177 MWE

NET PLANT POWER: 497 MWE

NET PLANT EFFICIENCY, HHV: 31.2%

NET PLANT HEAT RATE: 10,924 BTU/KWE

Dry Coal

Coal

Feeding

Steam

Candle 

Cyclone Filter

N2 to GT Combustor

Boost Compressor

Recycle

Compressor

Raw Syngas

to Scrubber

519.9 T

625.0 P

551.7 H

To Claus Plant

9 10

1

3

7

6

11

13

2

1,544,445 W

59.0 T

14.7 P

13.0 H

60,249 W

67.9 T

16.4 P

15.9 H

989,843 W

90.0 T

56.4 P

14.2 H 139,103 W

50.0 T

182.0 P

2.9 H

7,250 W

90.0 T

125.0 P

11.5 H

346,622 W

90.0 T

125.0 P

11.5 H

346,622 W

241.2 T

940.0 P

58,132 W 40.8 H

386.6 T

815.0 P

86.8 H

465,264 W

59.0 T

14.7 P

435,108 W

60.0 T

840.0 P

1,526.1 H

46,599 W

2,600.0 T

615.0 P

1,172,137 W

1,979.6 T

615.0 P

878.4 H

1,256,401 W

450.0 T

585.0 P

523.4 H

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LB/HR

H ENTHALPY, BTU/LB

MWE POWER, MEGAWATTS ELECTRICAL

687,451 W

385.0 T

384.0 P

87.2 H

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

5

44,894 W

650.0 T

740.0 P

1,317.3 H

Coal

Drying

Incinerator

Incinerator Air Syngas Slip Stream

Flue Gas/

Combustion

Products

Incinerator Exhaust

4,188 W

94.4 T

520.0 P

70.1 H

63,439 W

59.0 T

14.7 P

13.4 H

97,783 W

290.0 T

14.4 P

8

199.0 T

384.0 P

39.8 H

333,980 W

450.0 T

585.0 P

523.4 H

Syngas

Quench

Cooler

Quench Water

418,244 W

420.0 T

1,200.0 P

387.9 H

Shift Steam

For WGF Reactors

Saturated Steam

To HRSG

HP

BFW

IP

BFW

N2 Compressor

N2 to GT Combustor

Saturated Steam

To HRSG

HP

BFW

12

1,650.0 T

605.0 P

739.8 H

600.0 T

595.0 P

585.2 H

1,590,381 W

750.0 T

605.0 P

647.4 H

100.0 T

189.5 P

18.0 H

383,362 W

385.0 T

469.0 P

87.0 H

Syngas 

Cooler

Duct Cooler

Steam 

Generation

Shell 

Gasifier

4
Cost and Performance Baseline for Fossil Energy Plants

278

Exhibit 3-95 Case 6 Syngas Cleanup Heat and Mass Balance Schematic

NOTES:

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 6

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 6

SHELL GASIFIER

GAS CLEANUP SYSTEM

PLANT PERFORMANCE SUMMARY

LEGEND

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Mercury 

Removal

Knock

Out

Drum

Raw Syngas

Sour 

Drum

To Water Treatment

Makeup Water

Claus Plant

Tail 

Gas

Furnace

Catalytic

Reactor

Beds

Sulfur

Sour Water

Reboiler

Acid Gas

Tailgas

Carbon Dioxide

Sour Gas

Sulfur

Hydrogen

DWG. NO.

BB-HMB-CS-6-PG-2 PAGES

2 OF 3

Sour

Stripper

Syngas

Scrubber

GROSS PLANT POWER: 673 MWE

AUXILIARY LOAD: 177 MWE

NET PLANT POWER: 497 MWE

NET PLANT EFFICIENCY, HHV: 31.2%

NET PLANT HEAT RATE: 10,924 BTU/KWE

Water

13

16

17

22

23

24

1,256,401 W

450.0 T

585.0 P

523.4 H

27,484 W

100.0 T

799.5 P

3.6 H

436,986 W

550.0 T

800.0 P

1,254.1 H

1,594,881 W

484.5 T

565.0 P

423.7 H

1,266,974 W

94.4 T

520.0 P

19.1 H

Syngas

Coolers

248,650 W

94.4 T

520.0 P

70.1 H

11,634 W

352.5 T

17.3 P

From

ASU

3,022 W

227.6 T

65.0 P

370.2 H

36,563 W

450.0 T

12.3 P

479.1 H

37,925 W

119.0 T

23.7 P

36.5 H

Knock Out

Tailgas to AGR

1,594,881 W

422.2 T

575.0 P

662.5 H

1,239,491 W

94.8 T

525.0 P

19.5 H

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LB/HR

H ENTHALPY, BTU/LB

MWE POWER, MEGAWATTS ELECTRICAL

9,080 W

114.5 T

10.6 P

40.3 H

Treated Syngas

Slip Stream 

to Coal Dryer

18

Humidification 19 20 Humidified Fuel Gas

8

Shift Steam

High

Temperature

Shift #1

Low

Temperature

Shift #2

Fuel Gas

Humidification

1,157,895 W

375.6 T

580.0 P

435.0 H

385.6 T

575.0 P

439.1 H

477.9 T

560.0 P

420.7 H

WGS and Steam

Cycle Steam

14

15

Two-Stage

Selexol

Clean Gas

CO2

Acid Gas

Interstage Knockout

CO2 Product

21

Multistage 

Intercooled CO2

Compressor

7,250 W

450.0 T

124.5 P

91.9 H

975,038 W

124.0 T

2,214.7 P

25

Tailgas Recycle

Compressor

Hydrogenation

And Tail Gas 

Cooling
Cost and Performance Baseline for Fossil Energy Plants

279

Exhibit 3-96 Case 6 Combined Cycle Power Generation Heat and Mass Balance Schematic

NOTES:

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 6

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 6

SHELL GASIFIER

POWER BLOCK SYSTEM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LB/HR

H ENTHALPY, BTU/LB

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Synthesis Gas

HRSG

HP

Turbine

IP

Turbine

Nitrogen Dilution

Intake

Ambient Air

Steam Seal 

Regulator

IP Extraction Steam

to 250 PSIA Header

LP 

Process Header

Blowdown

Flash

To WWT

Make-up

Gland

Steam

Condenser

Condensate to Gasification Island

HP& IP BFW to Raw Gas Coolers

HP & IP Saturated Steam to HRSG Superheater

LP 

Turbine

Stack

Compressor Expander

Humidified Fuel Gas

Deaerator

IP BFW

Generator

Generator

Condensate

Pump

HP Pump

Steam Turbine

LP Pump

Water

Steam

DWG. NO.

BB-HMB-CS-6-PG-3 PAGES

3 OF 3

Advanced F-Class 

Gas Turbine

GROSS PLANT POWER: 673 MWE

AUXILIARY LOAD: 177 MWE

NET PLANT POWER: 497 MWE

NET PLANT EFFICIENCY, HHV: 31.2%

NET PLANT HEAT RATE: 10,924 BTU/KWE

Flue Gas/

Combustion

Products

To Gasifier

MP Flash Bottoms

LP Flash Tops

From Gasifier

Island Preheating

To Claus

LP BFW

IP Pump

26

4

20

27 28

29

7,014,133 W

59.0 T

14.7 P

13.0 H

333,100 W

380.0 T

460.0 P

609.1 H

1,070,813 W

199.0 T

384.0 P

39.8 H

8,418,047 W

1,043.2 T

15.2 P

372.4 H

1,146,042 W

993.2 T

1,814.7 P

1,475.5 H

1,911,334 W

102.8 T

120.0 P

71.1 H

23,308 W

585.0 T

2,000.7 P

592.9 H

8,328 W

298.0 T

65.0 P

1,178.6 H

1,393,094 W

439.8 T

65.0 P

1,252.2 H

8,418,047 W

270.0 T

15.2 P

159.6 H

1,911,334 W

235.0 T

105.0 P

203.3 H

506,076 W

59.0 T

14.7 P

27.1 H

1,169,363 W

278.8 T

2,250.7 P

251.9 H

1,911,334 W

101.1 T

1.0 P

69.1 H

1,400 W

614.2 T

65.0 P

1,338.3 H

1,400 W

212.0 T

14.7 P

179.9 H

26,345 W

851.0 T

280.0 P

1,448.2 H

HOT WELL

CONDENSER

217,834 W

298.0 T

65.0 P

1,178.6 H
Cost and Performance Baseline for Fossil Energy Plants

280

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

281

Exhibit 3-97 Case 6 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,727 (5,428) 4.8 (4.5) 5,731 (5,432)

ASU Air 21.2 (20.1) 21 (20)

GT Air 96.2 (91.2) 96 (91)

Water 80.2 (76.0) 80 (76)

Auxiliary Power 636 (602) 636 (602)

TOTAL 5,727 (5,428) 202.3 (191.7) 636 (602) 6,564 (6,222)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 1.0 (1.0) 1 (1)

Slag 22 (21) 35.7 (33.8) 58 (55)

Sulfur 49 (46) 0.6 (0.6) 50 (47)

CO2 -71.5 (-67.8) -72 (-68)

Cooling Tower 

Blowdown 28.4 (26.9) 28 (27)

HRSG Flue Gas 1,418 (1,344) 1,418 (1,344)

Condenser 1,335 (1,265) 1,335 (1,265)

Non-Condenser 

Cooling Tower 

Loads*

687 (651) 687 (651)

Process Losses** 635 (602) 635 (602)

Power 2,424 (2,298) 2,424 (2,298)

TOTAL 71 (67) 4,069 (3,857) 2,424 (2,298) 6,564 (6,222)

* Includes ASU compressor intercoolers, CO2 compressor intercoolers, sour water stripper condenser, syngas 

cooler (low level heat rejection) and extraction air cooler. 

** Calculated by difference to close the energy balance.
Cost and Performance Baseline for Fossil Energy Plants

282

3.4.10

Major equipment items for the Shell gasifier with CO2 capture are shown in the following tables. 

The accounts used in the equipment list correspond to the account numbers used in the cost 

estimates in Section 

Case 6 - Major Equipment List

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.

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 45 tonne (50 ton) 2 1

9 Feeder Vibratory 172 tonne/hr (190 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 345 tonne/hr (380 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 172 tonne (190 ton) 2 0

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0) 2 0

14 As-Fired Coal Sampling 

System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 345 tonne/hr (380 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 345 tonne/hr (380 tph) 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 816 tonne (900 ton) 3 0
Cost and Performance Baseline for Fossil Energy Plants

283

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 82 tonne/hr (90 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 236 tonne/hr (260 tph) 1 0

3 Roller Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 1 0

4 Weigh Feeder Belt 118 tonne/hr (130 tph) 2 0

5 Coal Dryer and Pulverizer Rotary 118 tonne/hr (130 tph) 2 0

6 Coal Dryer Feed Hopper Vertical Hopper 236 tonne (260 ton) 2 0
Cost and Performance Baseline for Fossil Energy Plants

284

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 987,992 liters (261,000 gal) 2 0

2 Condensate Pumps Vertical canned 7,987 lpm @ 91 m H2O

(2,110 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 551,115 kg/hr (1,215,000 lb/hr) 2 0

4 Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

7,987 lpm @ 27 m H2O

(2,110 gpm @ 90 ft H2O) 2 1

5 High Pressure 

Feedwater Pump No. 1

Barrel type, multi-stage, 

centrifugal

HP water: 5,072 lpm @ 1,859 m 

H2O (1,340 gpm @ 6,100 ft 

H2O)

2 1

6 High Pressure 

Feedwater Pump No. 2

Barrel type, multi-stage, 

centrifugal

IP water: 1,211 lpm @ 223 m 

H2O (320 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 Cylce Cooling 

Heat Exchangers Plate and frame 393 GJ/hr (372 MMBtu/hr) each 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 140,817 lpm @ 21 m H2O(37,200 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) 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

5,943 lpm @ 18 m H2O

(1,570 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single 

suction

2,953 lpm @ 268 m H2O 

(780 gpm @ 880 ft H2O) 4 1

16 Filtered Water Pumps Stainless steel, single 

suction

4,656 lpm @ 49 m H2O

(1,230 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 2,225,822 liter (588,000 gal) 2 0

18 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 2,082 lpm (550 gpm) 2 0

19 Liquid Waste Treatment 

System 10 years, 24-hour storm 1 0
Cost and Performance Baseline for Fossil Energy Plants

285

ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW 

TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized dry-feed, 

entrained bed

2,812 tonne/day, 4.2 MPa

(3,100 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler Convective spiralwound tube boiler 396,893 kg/hr (875,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 313,432 kg/hr (691,000 lb/hr) 

Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with 

pulse-jet cleaning metallic filters 2 0

5

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 313,432 kg/hr (691,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with 

condensate drain 397,801 kg/hr (877,000 lb/hr) 8 0

7 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator

309,804 kg/hr, 35°C, 3.7 MPa

(683,000 lb/hr, 95°F, 530 psia) 2 0

8 Saturation Water 

Economizers Shell and tube 78 GJ/hr (74 MMBtu/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 83,007 kg/hr, 137°C, 3.6 MPa

(183,000 lb/hr, 278°F, 520 psia) 2 0

10 Saturator Water Pump Centrifugal 1,893 lpm @ 12 m H2O

(500 gpm @ 40 ft H2O) 2 2

11 Synthesis Gas Reheater Shell and tube 83,007 kg/hr (183,000 lb/hr) 2 0

12 Flare Stack

Self-supporting, carbon 

steel, stainless steel top, 

pilot ignition

313,432 kg/hr (691,000 lb/hr) 

syngas

2 0

13 ASU Main Air 

Compressor Centrifugal, multi-stage 5,267 m3/min @ 1.3 MPa(186,000 scfm @ 190 psia) 2 0

14 Cold Box Vendor design 2,087 tonne/day (2,300 tpd) of 

95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi-stage

1,048 m3/min (37,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 psia)

2 0

16 Primary Nitrogen 

Compressor Centrifugal, multi-stage

3,483 m3/min (123,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 0

17 Secondary Nitrogen 

Compressor Centrifugal, single-stage

481 m3/min (17,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 0

18 Gasifier Purge Nitrogen 

Boost Compressor Centrifugal, single-stage

1,359 m3/min (48,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 psia)

2 0
Cost and Performance Baseline for Fossil Energy Plants

286

ACCOUNT 5 SYNGAS CLEANUP

ACCOUNT 5B CO2 COMPRESSION

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon 

bed

309,350 kg/hr (682,000 lb/hr) 

35°C (95°F) 

3.6 MPa (525 psia)

2 0

2 Sulfur Plant Claus type 139 tonne/day (154 tpd) 1 0

3 Water Gas Shift Reactors Fixed bed, 

catalytic

397,801 kg/hr (877,000 lb/hr) 

216°C (420°F) 

4.0 MPa (580 psia)

4 0

4 Shift Reactor Heat Recovery 

Exchangers Shell and Tube

Exchanger 1: 121 GJ/hr (114 

MMBtu/hr) 

Exchanger 2: 3 GJ/hr (3 

MMBtu/hr) 

4 0

5 Acid Gas Removal Plant Two-stage 

Selexol

316,154 kg/hr (697,000 lb/hr) 

35°C (94°F) 

3.6 MPa (520 psia)

2 0

6 Hydrogenation Reactor Fixed bed, 

catalytic

18,243 kg/hr (40,220 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

1 0

7 Tail Gas Recycle 

Compressor Centrifugal 13,713 kg/hr (30,232 lb/hr) 1 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CO2 

Compressor

Integrally geared, 

multi-stage centrifugal

1,096 m3/min @ 15.3 MPa 

(38,700 scfm @ 2,215 psia) 4 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gas Turbine Advanced F class 232 MW 2 0

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase 2 0
Cost and Performance Baseline for Fossil Energy Plants

287

ACCOUNT 7 HRSG, DUCTING, AND STACK

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS 

liner

76 m (250 ft) high x

8.5 m (28 ft) diameter 1 0

2 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator

Main steam - 285,910 kg/hr, 12.4 

MPa/534°C (630,323 lb/hr, 

1,800 psig/993°F)

 Reheat steam - 244,783 kg/hr, 

3.1 MPa/534°C (539,654 lb/hr, 

452 psig/993°F)

2 0

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

220 MW 

12.4 MPa/534°C/534°C 

(1800 psig/ 993°F/993°F)

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitiation

240 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase 1 0

3 Steam Bypass One per HRSG 50% steam flow @ design 

steam conditions 2 0

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,467 GJ/hr (1,390 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 11°C 

(20°F)

1 0
Cost and Performance Baseline for Fossil Energy Plants

288

ACCOUNT 9 COOLING WATER SYSTEM

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Circulating Water 

Pumps Vertical, wet pit 439,108 lpm @ 30 m(116,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

/ 2437 GJ/hr (2310 MMBtu/hr) 

heat duty

1 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 223,339 liters (59,000 gal) 2 0

2 Slag Crusher Roll 12 tonne/hr (13 tph) 2 0

3 Slag Depressurizer Lock Hopper 12 tonne/hr (13 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 132,489 liters (35,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 60,567 liters (16,000 gal) 2

6 Slag Conveyor Drag chain 12 tonne/hr (13 tph) 2 0

7 Slag Separation Screen Vibrating 12 tonne/hr (13 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 12 tonne/hr (13 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 189,271 liters (50,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal 

centrifugal

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 60,567 liters (16,000 gal) 2 0

12 Grey Water Pumps Centrifugal 227 lpm @ 433 m H2O

(60 gpm @ 1,420 ft H2O) 2 2

13 Slag Storage Bin Vertical, field 

erected 816 tonne (900 tons) 2 0

14 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 1 0
Cost and Performance Baseline for Fossil Energy Plants

289

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CTG Step-up 

Transformer Oil-filled 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 1 0

3

High Voltage 

Auxiliary 

Transformer

Oil-filled 345 kV/13.8 kV, 74 MVA, 

3-ph, 60 Hz 2 0

4

Medium Voltage 

Auxiliary 

Transformer

Oil-filled 24 kV/4.16 kV, 46 MVA, 

3-ph, 60 Hz 1 1

5 Low Voltage 

Transformer Dry ventilated 4.16 kV/480 V, 7 MVA, 3-ph, 60 Hz 1 1

6

CTG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, 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

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 for Fossil Energy Plants

290

3.4.11

The cost estimating methodology was described previously in Section 

Case 6 - Cost Estimating

2.6. Exhibit 3-98 shows 

the total plant capital cost summary organized by cost account and Exhibit 3-99 shows a more 

detailed breakdown of the capital costs along with owner’s costs, TOC and TASC. 

Exhibit 3-100 shows the initial and annual O&M costs.

The estimated TOC of the Shell gasifier with CO2 capture is $3,904/kW. Process contingency 

represents 3.4 percent of the TOC and project contingency represents 11.4 percent. The COE, 

including CO2 TS&M costs of 5.7 mills/kWh, is 119.5 mills/kWh.
Cost and Performance Baseline for Fossil Energy Plants

291

Exhibit 3-98 Case 6 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14

Project: Bituminous Baseline Study

Case: Case 6 - Shell 500MW IGCC w/ CO2

Plant Size: 496.9 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 $13,881 $2,580 $10,765 $0 $0 $27,226 $2,471 $0 $5,939 $35,636 $72

 2 COAL & SORBENT PREP & FEED $109,935 $8,758 $18,287 $0 $0 $136,980 $11,879 $0 $29,772 $178,630 $360

 3 FEEDWATER & MISC. BOP SYSTEMS $9,471 $7,207 $9,699 $0 $0 $26,377 $2,492 $0 $6,717 $35,585 $72

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $144,815 $0 $61,614 $0 $0 $206,430 $18,447 $28,271 $38,955 $292,103 $588

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 $173,504 $0 w/equip. $0 $0 $173,504 $16,818 $0 $19,032 $209,354 $421

4.4-4.9 Other Gasification Equipment $25,591 $9,849 $15,118 $0 $0 $50,557 $4,851 $0 $11,805 $67,213 $135

SUBTOTAL 4 $343,911 $9,849 $76,732 $0 $0 $430,492 $40,115 $28,271 $69,793 $568,670 $1,145

 5A Gas Cleanup & Piping $91,097 $3,993 $77,814 $0 $0 $172,904 $16,706 $26,070 $43,284 $258,964 $521

 5B CO2 REMOVAL & COMPRESSION $17,811 $0 $10,524 $0 $0 $28,335 $2,728 $0 $6,213 $37,276 $75

 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 $261

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 $266

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,709 $0 $4,793 $0 $0 $38,502 $3,661 $0 $4,216 $46,379 $93

7.2-7.9 Ductwork and Stack $3,380 $2,410 $3,156 $0 $0 $8,946 $829 $0 $1,591 $11,367 $23

SUBTOTAL 7 $37,089 $2,410 $7,949 $0 $0 $47,448 $4,490 $0 $5,807 $57,745 $116

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $23,934 $0 $4,000 $0 $0 $27,935 $2,680 $0 $3,061 $33,676 $68

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $9,162 $818 $6,331 $0 $0 $16,312 $1,486 $0 $3,487 $21,285 $43

SUBTOTAL 8 $33,096 $818 $10,332 $0 $0 $44,246 $4,166 $0 $6,549 $54,961 $111

 9 COOLING WATER SYSTEM $9,932 $9,472 $8,108 $0 $0 $27,512 $2,555 $0 $6,134 $36,202 $73

10 ASH/SPENT SORBENT HANDLING SYS $18,585 $1,433 $9,223 $0 $0 $29,241 $2,805 $0 $3,501 $35,547 $72

11 ACCESSORY ELECTRIC PLANT $30,536 $12,099 $23,664 $0 $0 $66,300 $5,703 $0 $13,663 $85,666 $172

12 INSTRUMENTATION & CONTROL $11,002 $2,024 $7,089 $0 $0 $20,115 $1,823 $1,006 $3,823 $26,766 $54

13 IMPROVEMENTS TO SITE $3,346 $1,972 $8,255 $0 $0 $13,572 $1,340 $0 $4,474 $19,386 $39

14 BUILDINGS & STRUCTURES $0 $6,461 $7,281 $0 $0 $13,741 $1,250 $0 $2,463 $17,455 $35

 

TOTAL COST $821,717 $69,882 $293,196 $0 $0 $1,184,795 $110,031 $65,208 $220,470 $1,580,505 $3,181

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline for Fossil Energy Plants

292

Exhibit 3-99 Case 6 Total Plant Cost Details

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 $3,645 $0 $1,781 $0 $0 $5,427 $486 $0 $1,183 $7,095 $14

1.2 Coal Stackout & Reclaim $4,711 $0 $1,142 $0 $0 $5,853 $513 $0 $1,273 $7,639 $15

1.3 Coal Conveyors & Yd Crush $4,380 $0 $1,130 $0 $0 $5,510 $484 $0 $1,199 $7,192 $14

1.4 Other Coal Handling $1,146 $0 $261 $0 $0 $1,407 $123 $0 $306 $1,836 $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 $2,580 $6,450 $0 $0 $9,030 $865 $0 $1,979 $11,874 $24

SUBTOTAL 1. $13,881 $2,580 $10,765 $0 $0 $27,226 $2,471 $0 $5,939 $35,636 $72

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $41,765 $2,509 $6,086 $0 $0 $50,360 $4,346 $0 $10,941 $65,647 $132

2.2 Prepared Coal Storage & Feed $1,978 $473 $310 $0 $0 $2,762 $236 $0 $600 $3,598 $7

2.3 Dry Coal Injection System $65,103 $756 $6,046 $0 $0 $71,905 $6,193 $0 $15,620 $93,718 $189

2.4 Misc.Coal Prep & Feed $1,088 $792 $2,373 $0 $0 $4,253 $391 $0 $929 $5,573 $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 $4,228 $3,471 $0 $0 $7,700 $713 $0 $1,683 $10,095 $20

SUBTOTAL 2. $109,935 $8,758 $18,287 $0 $0 $136,980 $11,879 $0 $29,772 $178,630 $360

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,492 $4,279 $2,259 $0 $0 $9,029 $836 $0 $1,973 $11,839 $24

3.2 Water Makeup & Pretreating $701 $73 $392 $0 $0 $1,167 $111 $0 $383 $1,661 $3

3.3 Other Feedwater Subsystems $1,363 $461 $415 $0 $0 $2,238 $201 $0 $488 $2,928 $6

3.4 Service Water Systems $401 $827 $2,869 $0 $0 $4,097 $400 $0 $1,349 $5,845 $12

3.5 Other Boiler Plant Systems $2,154 $835 $2,069 $0 $0 $5,057 $480 $0 $1,107 $6,644 $13

3.6 FO Supply Sys & Nat Gas $313 $591 $551 $0 $0 $1,454 $140 $0 $319 $1,913 $4

3.7 Waste Treatment Equipment $981 $0 $598 $0 $0 $1,579 $154 $0 $520 $2,252 $5

3.8 Misc. Power Plant Equipment $1,066 $143 $547 $0 $0 $1,756 $170 $0 $578 $2,503 $5

SUBTOTAL 3. $9,471 $7,207 $9,699 $0 $0 $26,377 $2,492 $0 $6,717 $35,585 $72

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $144,815 $0 $61,614 $0 $0 $206,430 $18,447 $28,271 $38,955 $292,103 $588

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $173,504 $0 w/equip. $0 $0 $173,504 $16,818 $0 $19,032 $209,354 $421

4.4 LT Heat Recovery & FG Saturation $25,591 $0 $9,728 $0 $0 $35,319 $3,447 $0 $7,753 $46,519 $94

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 $1,406 $572 $0 $0 $1,978 $190 $0 $433 $2,601 $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 $8,443 $4,818 $0 $0 $13,261 $1,214 $0 $3,619 $18,094 $36

SUBTOTAL 4. $343,911 $9,849 $76,732 $0 $0 $430,492 $40,115 $28,271 $69,793 $568,670 $1,145
Cost and Performance Baseline for Fossil Energy Plants

293

Exhibit 3-99 Case 6 Total Plant Cost Details (Continued)

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 $70,179 $0 $59,549 $0 $0 $129,728 $12,546 $25,946 $33,644 $201,864 $406

5A.2 Elemental Sulfur Plant $10,017 $1,996 $12,924 $0 $0 $24,937 $2,422 $0 $5,472 $32,831 $66

5A.3 Mercury Removal $1,410 $0 $1,073 $0 $0 $2,483 $240 $124 $569 $3,417 $7

5A.4 Shift Reactors $7,366 $0 $2,965 $0 $0 $10,330 $990 $0 $2,264 $13,585 $27

5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

5A.5 Blowback Gas Systems $2,125 $358 $201 $0 $0 $2,684 $255 $0 $588 $3,526 $7

5A.6 Fuel Gas Piping $0 $814 $570 $0 $0 $1,384 $128 $0 $303 $1,815 $4

5A.9 HGCU Foundations $0 $824 $532 $0 $0 $1,356 $125 $0 $444 $1,925 $4

SUBTOTAL 5A. $91,097 $3,993 $77,814 $0 $0 $172,904 $16,706 $26,070 $43,284 $258,964 $521

5B CO2 COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $17,811 $0 $10,524 $0 $0 $28,335 $2,728 $0 $6,213 $37,276 $75

SUBTOTAL 5B. $17,811 $0 $10,524 $0 $0 $28,335 $2,728 $0 $6,213 $37,276 $75

 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 $261

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 $266

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,709 $0 $4,793 $0 $0 $38,502 $3,661 $0 $4,216 $46,379 $93

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,733 $1,236 $0 $0 $2,969 $260 $0 $646 $3,875 $8

7.4 Stack $3,380 $0 $1,270 $0 $0 $4,650 $445 $0 $510 $5,605 $11

7.9 HRSG,Duct & Stack Foundations $0 $677 $650 $0 $0 $1,328 $124 $0 $435 $1,887 $4

SUBTOTAL 7. $37,089 $2,410 $7,949 $0 $0 $47,448 $4,490 $0 $5,807 $57,745 $116

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $23,934 $0 $4,000 $0 $0 $27,935 $2,680 $0 $3,061 $33,676 $68

8.2 Turbine Plant Auxiliaries $165 $0 $378 $0 $0 $543 $53 $0 $60 $656 $1

8.3 Condenser & Auxiliaries $4,579 $0 $1,463 $0 $0 $6,042 $578 $0 $662 $7,282 $15

8.4 Steam Piping $4,418 $0 $3,108 $0 $0 $7,526 $647 $0 $2,043 $10,215 $21

8.9 TG Foundations $0 $818 $1,383 $0 $0 $2,201 $209 $0 $723 $3,132 $6

SUBTOTAL 8. $33,096 $818 $10,332 $0 $0 $44,246 $4,166 $0 $6,549 $54,961 $111

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $6,867 $0 $1,249 $0 $0 $8,116 $773 $0 $1,333 $10,222 $21

9.2 Circulating Water Pumps $1,791 $0 $127 $0 $0 $1,919 $162 $0 $312 $2,393 $5

9.3 Circ.Water System Auxiliaries $151 $0 $21 $0 $0 $172 $16 $0 $28 $217 $0

9.4 Circ.Water Piping $0 $6,288 $1,630 $0 $0 $7,918 $716 $0 $1,727 $10,360 $21

9.5 Make-up Water System $381 $0 $544 $0 $0 $925 $89 $0 $203 $1,217 $2

9.6 Component Cooling Water Sys $742 $888 $632 $0 $0 $2,262 $212 $0 $495 $2,968 $6

9.9 Circ.Water System Foundations $0 $2,296 $3,904 $0 $0 $6,200 $588 $0 $2,037 $8,825 $18

SUBTOTAL 9. $9,932 $9,472 $8,108 $0 $0 $27,512 $2,555 $0 $6,134 $36,202 $73
Cost and Performance Baseline for Fossil Energy Plants

294

Exhibit 3-99 Case 6 Total Plant Cost Details (Continued)

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 $16,178 $0 $7,978 $0 $0 $24,156 $2,321 $0 $2,648 $29,125 $59

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 $546 $0 $594 $0 $0 $1,139 $111 $0 $187 $1,437 $3

10.7 Ash Transport & Feed Equipment $732 $0 $177 $0 $0 $908 $85 $0 $149 $1,142 $2

10.8 Misc. Ash Handling Equipment $1,130 $1,385 $414 $0 $0 $2,929 $279 $0 $481 $3,689 $7

10.9 Ash/Spent Sorbent Foundation $0 $48 $61 $0 $0 $109 $10 $0 $36 $155 $0

SUBTOTAL 10. $18,585 $1,433 $9,223 $0 $0 $29,241 $2,805 $0 $3,501 $35,547 $72

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $901 $0 $891 $0 $0 $1,792 $171 $0 $196 $2,159 $4

11.2 Station Service Equipment $4,510 $0 $406 $0 $0 $4,916 $453 $0 $537 $5,906 $12

11.3 Switchgear & Motor Control $8,338 $0 $1,516 $0 $0 $9,854 $914 $0 $1,615 $12,383 $25

11.4 Conduit & Cable Tray $0 $3,873 $12,777 $0 $0 $16,650 $1,610 $0 $4,565 $22,826 $46

11.5 Wire & Cable $0 $7,400 $4,862 $0 $0 $12,262 $891 $0 $3,288 $16,442 $33

11.6 Protective Equipment $0 $679 $2,471 $0 $0 $3,150 $308 $0 $519 $3,976 $8

11.7 Standby Equipment $224 $0 $219 $0 $0 $443 $42 $0 $73 $558 $1

11.8 Main Power Transformers $16,564 $0 $136 $0 $0 $16,699 $1,263 $0 $2,694 $20,656 $42

11.9 Electrical Foundations $0 $147 $386 $0 $0 $534 $51 $0 $175 $760 $2

SUBTOTAL 11. $30,536 $12,099 $23,664 $0 $0 $66,300 $5,703 $0 $13,663 $85,666 $172

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 $1,086 $0 $725 $0 $0 $1,811 $171 $91 $311 $2,384 $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 $250 $0 $160 $0 $0 $410 $39 $20 $94 $563 $1

12.7 Computer & Accessories $5,794 $0 $185 $0 $0 $5,979 $549 $299 $683 $7,510 $15

12.8 Instrument Wiring & Tubing $0 $2,024 $4,137 $0 $0 $6,161 $523 $308 $1,748 $8,740 $18

12.9 Other I & C Equipment $3,873 $0 $1,881 $0 $0 $5,753 $541 $288 $987 $7,570 $15

SUBTOTAL 12. $11,002 $2,024 $7,089 $0 $0 $20,115 $1,823 $1,006 $3,823 $26,766 $54
Cost and Performance Baseline for Fossil Energy Plants

295

Exhibit 3-99 Case 6 Total Plant Cost Details (Continued)

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

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $105 $2,244 $0 $0 $2,349 $233 $0 $775 $3,356 $7

13.2 Site Improvements $0 $1,867 $2,481 $0 $0 $4,348 $429 $0 $1,433 $6,210 $12

13.3 Site Facilities $3,346 $0 $3,530 $0 $0 $6,876 $678 $0 $2,266 $9,820 $20

SUBTOTAL 13. $3,346 $1,972 $8,255 $0 $0 $13,572 $1,340 $0 $4,474 $19,386 $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 $2,071 $2,950 $0 $0 $5,021 $462 $0 $822 $6,306 $13

14.3 Administration Building $0 $857 $622 $0 $0 $1,479 $132 $0 $242 $1,853 $4

14.4 Circulation Water Pumphouse $0 $161 $85 $0 $0 $246 $22 $0 $40 $308 $1

14.5 Water Treatment Buildings $0 $586 $572 $0 $0 $1,158 $105 $0 $189 $1,452 $3

14.6 Machine Shop $0 $439 $300 $0 $0 $739 $66 $0 $121 $926 $2

14.7 Warehouse $0 $709 $457 $0 $0 $1,166 $103 $0 $190 $1,460 $3

14.8 Other Buildings & Structures $0 $424 $330 $0 $0 $755 $67 $0 $164 $987 $2

14.9 Waste Treating Building & Str. $0 $949 $1,813 $0 $0 $2,762 $257 $0 $604 $3,623 $7

SUBTOTAL 14. $0 $6,461 $7,281 $0 $0 $13,741 $1,250 $0 $2,463 $17,455 $35

TOTAL COST $821,717 $69,882 $293,196 $0 $0 $1,184,795 $110,031 $65,208 $220,470 $1,580,505 $3,181

Owner's Costs

Preproduction Costs

6 Months All Labor $13,300 $27

1 Month Maintenance Materials $2,951 $6

1 Month Non-fuel Consumables $378 $1

1 Month Waste Disposal $278 $1

25% of 1 Months Fuel Cost at 100% CF $1,621 $3

2% of TPC $31,610 $64

Total $50,138 $101

Inventory Capital

60 day supply of fuel and consumables at 100% CF $13,459 $27

0.5% of TPC (spare parts) $7,903 $16

Total $21,361 $43

Initial Cost for Catalyst and Chemicals $7,224 $15

Land $900 $2

Other Owner's Costs $237,076 $477

Financing Costs $42,674 $86

Total Overnight Costs (TOC) $1,939,878 $3,904

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,211,461 $4,451
Cost and Performance Baseline for Fossil Energy Plants

296

Exhibit 3-100 Case 6 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 6 - Shell 500MW IGCC w/ CO2 Heat Rate-net (Btu/kWh): 10,924

MWe-net: 497

 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

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 2.0 2.0

 Operator 10.0 10.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 3.0 3.0

 TOTAL-O.J.'s 16.0 16.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $6,313,507 $12.707

Maintenance Labor Cost $14,966,466 $30.122

Administrative & Support Labor $5,319,993 $10.707

Property Taxes and Insurance $31,610,092 $63.620

TOTAL FIXED OPERATING COSTS $58,210,058 $117.156

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $28,329,484 $0.00814

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water (/1000 gallons) 0 4,056 1.08 $0 $1,281,009 $0.00037

Chemicals

MU & WT Chem. (lbs) 0 24,163 0.17 $0 $1,221,101 $0.00035

Carbon (Mercury Removal) (lb) 117,815 161 1.05 $123,726 $49,490 $0.00001

COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000

Water Gas Shift Catalyst (ft3) 6,470 4.43 498.83 $3,227,388 $645,478 $0.00019

Selexol Solution (gal) 289,068 92 13.40 $3,873,002 $360,241 $0.00010

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip. 1.93 131.27 $0 $74,040 $0.00002

Subtotal Chemicals $7,224,116 $2,350,349 $0.00068

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.) 0 161 0.42 $0 $19,655 $0.00001

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 559 16.23 $0 $2,649,268 $0.00076

 Subtotal-Waste Disposal $0 $2,668,923 $0.00077

By-products & Emissions

Sulfur (ton) 0 140 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $7,224,116 $34,629,764 $0.00995

Fuel (ton) 0 5,583 38.18 $0 $62,251,620 $0.01788
Cost and Performance Baseline for Fossil Energy Plants

297

3.5 IGCC CASE SUMMARY

The performance results of the six IGCC plant configurations modeled in this study are 

summarized in Exhibit 3-101.

Exhibit 3-101 Estimated Performance and Cost Results for IGCC Cases

1 CF is 80% for all IGCC cases 2 COE and LCOE are defined in Section 2.7.

PERFORMANCE Case 1 Case 2 Case 3 Case 4 Case 5 Case 6

CO2 Capture 0% 90% 0% 90% 0% 90%

Gross Power Output (kWe) 747,800 734,000 738,200 703,700 737,000 673,400

Auxiliary Power Requirement (kWe) 125,750 190,750 113,140 190,090 108,020 176,540

Net Power Output (kWe) 622,050 543,250 625,060 513,610 628,980 496,860

Coal Flowrate (lb/hr) 466,901 487,011 459,958 484,212 436,646 465,264

Natural Gas Flowrate (lb/hr) N/A N/A N/A N/A N/A N/A

HHV Thermal Input (kWth) 1,596,320 1,665,074 1,572,582 1,655,503 1,492,878 1,590,722

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

Net Plant HHV Heat Rate (Btu/kWh) 8,756 10,458 8,585 10,998 8,099 10,924

Raw Water Withdrawal (gpm/MWnet) 7.6 10.7 7.0 11.1 6.6 11.3

Process Water Discharge (gpm/MWnet) 1.6 2.0 1.4 2.1 1.2 2.0

Raw Water Consumption (gpm/MWnet) 6.0 8.7 5.5 9.0 5.3 9.3

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

CO2 Emissions (lb/MWhgross) 1,434 152 1,448 158 1,361 161

CO2 Emissions (lb/MWhnet) 1,723 206 1,710 217 1,595 218

SO2 Emissions (lb/MMBtu) 0.0012 0.0022 0.0117 0.0022 0.0042 0.0021

SO2 Emissions (lb/MWhgross) 0.0090 0.0166 0.0852 0.0173 0.0290 0.0171

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

NOx Emissions (lb/MWhgross) 0.430 0.376 0.434 0.396 0.409 0.396

PM Emissions (lb/MMBtu) 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071

PM Emissions (lb/MWhgross) 0.052 0.055 0.052 0.057 0.049 0.057

Hg Emissions (lb/TBtu) 0.571 0.571 0.571 0.571 0.571 0.571

Hg Emissions (lb/MWhgross) 4.16E-06 4.42E-06 4.15E-06 4.59E-06 3.95E-06 4.61E-06

COST

Total Plant Cost (2007$/kW) 1,987 2,711 1,913 2,817 2,217 3,181

Total Overnight Cost (2007$/kW) 2,447 3,334 2,351 3,466 2,716 3,904

 Bare Erected Cost 1,528 2,032 1,470 2,113 1,695 2,385

 Home Office Expenses 144 191 138 199 156 221

 Project Contingency 265 369 256 385 302 444

 Process Contingency 50 119 50 120 63 131

 Owner's Costs 460 623 438 649 500 723

Total Overnight Cost (2007$ x 1,000) 1,521,880 1,811,411 1,469,577 1,780,290 1,708,524 1,939,878

Total As Spent Capital (2007$/kW) 2,789 3,801 2,680 3,952 3,097 4,451

COE (mills/kWh, 2007$)1,2 76.3 105.6 74.0 110.3 81.3 119.4

 CO2 TS&M Costs 0.0 5.2 0.0 5.5 0.0 5.6

 Fuel Costs 14.3 17.1 14.0 18.0 13.3 17.9

 Variable Costs 7.3 9.3 7.2 9.8 7.8 9.9

 Fixed Costs 11.3 14.8 11.1 15.5 12.1 16.7

 Capital Costs 43.4 59.1 41.7 61.5 48.2 69.2

LCOE (mills/kWh, 2007$)1,2 96.7 133.9 93.8 139.9 103.1 151.4

Integrated Gasification Combined Cycle

GEE R+Q CoP E-Gas FSQ Shell
Cost and Performance Baseline for Fossil Energy Plants

298

The components of TOC and the overall TASC of the six IGCC cases are shown in 

Exhibit 3-102. The following TOC observations are made with the caveat that the differences 

between cases are less than the estimate accuracy (-15%/+30%). However, all cases are 

evaluated using a common set of technical and economic assumptions allowing meaningful 

comparisons among the cases:

• CoP has the lowest TOC cost among the non-capture cases. The E-Gas technology has 

several features that lend it to being lower cost, such as:

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

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

the gas temperature (slurry quench) and drops the syngas temperature into a 

range where a radiant cooler is not needed.

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

it, which reduces the height of the main gasifier structure. The E-Gas 

proprietary slag removal system, used instead of lock hoppers below the 

gasifier, also contributes to the lower structure height.

The TOC of the GEE gasifier is about 4 percent greater than CoP and Shell is about 16

percent higher.

Exhibit 3-102 Plant Capital Cost for IGCC Cases

• The GEE gasifier is the low cost technology in the CO2 capture cases, with CoP about 4

percent higher and Shell about 17 percent higher. The greatest uncertainty in all of the 

capital cost estimates is for the Shell capture case, which is based on a water quench 

process that has been proposed by Shell in a patent application [63]. However, to date 

there have been no commercial applications of this configuration.

2,447

3,334

2,351

3,466

2,716

3,904

2,789

3,801

2,680

3,952

3,097

4,451

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

GEE GEE w/ CO2 Capture CoP CoP w/ CO2 Capture Shell Shell w/ CO2 Capture

TOC or TASC, $/kW (2007$)

TASC

Owner's Cost

Process Contingency

Project Contingency

Home Office Expense

Bare Erected Cost
Cost and Performance Baseline for Fossil Energy Plants

299

• The ASU cost represents on average 12 percent of the TOC (range from 10.5-12.9

percent). The ASU cost includes oxygen and nitrogen compression, and in the noncapture cases, also includes the cost of the CT extraction air heat exchanger. With 

nitrogen dilution used to the maximum extent possible, nitrogen compression costs are 

significant.

• The TOC premium for adding CO2 capture averages 42 percent ($3,568/kW versus 

$2,504/kW).

The COE is shown for the IGCC cases in Exhibit 3-103. 

Exhibit 3-103 COE for IGCC Cases

The following observations can be made:

• The COE is dominated by capital costs, at least 56 percent of the total in all cases.

• In the non-capture cases the CoP gasifier has the lowest COE, but the differential with 

Shell is reduced (compared to the TOC) primarily because of the higher efficiency of the 

Shell gasifier. The Shell COE is 10 percent higher than CoP (compared to 16 percent 

higher TOC). The GEE gasifier COE is about 3 percent higher than CoP.

• In the capture cases the variation in COE is small, however the order of the GEE and CoP 

gasifiers is reversed. The range is from 105.7 mills/kWh for GEE to 119.5 mills/kWh for 

Shell with CoP intermediate at 110.4 mills/kWh. The COE CO2 capture premium for the 

IGCC cases averages 45 percent (range of 39 to 49 percent).

43.4

59.1

41.7

61.5

48.2

69.2

11.3

14.8

11.1

15.5

12.1

16.7

7.3

9.3

7.2

9.8

7.8

9.9

14.3

17.1

14.0

18.0

13.3

17.9 5.3

5.6

5.7

0

20

40

60

80

100

120

140

160

GEE GEE w/CO2 Capture CoP CoP w/ CO2 Capture Shell Shell w/ CO2 Capture

COE, mills/kWh (2007$)

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs
Cost and Performance Baseline for Fossil Energy Plants

300

• The CO2 TS&M COE component comprises less than 5.5 percent of the total COE in all 

capture cases.

The effect of CF and coal price on COE is shown in Exhibit 3-104 and Exhibit 3-105, 

respectively.

The assumption implicit in Exhibit 3-104 is that each gasifier technology can achieve a CF of up 

to 90 percent with no additional capital equipment. The cost differential between technologies 

decreases as CF increases. At low CF the capital cost differential is more magnified and the 

spread between technologies increases slightly.

Exhibit 3-104 Capacity Factor Sensitivity of IGCC Cases

COE is relatively insensitive to fuel costs for the IGCC cases as shown in Exhibit 3-105. A 

tripling of coal price from 1 to $3/MMBtu results in an average COE increase of only about 19-

25 percent for all cases.

As presented in Section 2.4 the cost of CO2 capture was calculated as an avoided cost. The 

results for the IGCC CO2 capture cases are shown in Exhibit 3-106. The first year cost of CO2

avoided using each analogous IGCC non-capture technology as the reference averages 

$52.9/tonne ($48/ton) with a range of $43-$61.7/tonne ($39-$56/ton). The cost of CO2 avoided 

is higher when using SC PC without CO2 capture as the technology reference. Avoided costs

average $75/tonne ($68/ton) with a range of $66.1-$86/tonne ($60-$78/ton). The avoided cost is 

elevated because SC PC without capture has a significantly lower COE than any IGCC 

technology.

0

50

100

150

200

250

300

0 10 20 30 40 50 60 70 80 90 100

COE, mills/kWh (2007$)

Capacity Factor, %

Shell w/CO2 Capture

CoP w/CO2 Capture

GEE w/CO2 Capture

Shell No Capture

GEE No Capture

CoP No Capture

Coal = $1.64/MMBtu
Cost and Performance Baseline for Fossil Energy Plants

301

Exhibit 3-105 Coal Price Sensitivity of IGCC Cases

Exhibit 3-106 Cost of CO2 Avoided in IGCC Cases

0

20

40

60

80

100

120

140

160

0 0.5 1 1.5 2 2.5 3 3.5 4

COE, mills/kWh (2007$)

Coal Price, $/MMBtu

Shell w/CO2 Capture

CoP w/CO2 Capture

GEE w/CO2 Capture

Shell No Capture

GEE No Capture

CoP No Capture

Capacity factor = 80% 

43

54

61

66

73

86

0

10

20

30

40

50

60

70

80

90

100

GEE CoP Shell

First Year CO2 Avoided Cost, $/tonne (2007$)

Avoided Cost (Analogous Technology w/o Capture Reference)

Avoided Cost (SC PC w/o Capture Reference)
Cost and Performance Baseline for Fossil Energy Plants

302

The following observations can be made regarding plant performance:

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

efficiency (42.1 percent), followed by the two-stage CoP slurry fed gasifier (39.7 percent) 

and the single-stage GEE gasifier (39.0 percent). The absolute values of the GEE and 

CoP gasifiers are close to the reported values per the vendors [59, 60]. The Shell 

efficiency is slightly lower than reported by the vendor in other recent presentations [62].

• In the CO2 capture cases the efficiency of the three gasifiers ranges from 31.0 to 32.6

percent.

• The dry fed Shell gasifier experiences the largest energy penalty (25.9 relative percent) 

primarily because addition of the steam required for the WGS reaction is provided as 

quench water to reduce the syngas temperature from 899°C (1,650°F) to 399°C (750°F). 

Quench to 399°C (750°F) reduces the amount of heat recovered in the syngas cooler 

relative to the non-capture case where syngas recycle reduces the temperature to only 

1,093°C (2,000°F) prior to the cooler. The CO2 capture scheme used in this study for the 

Shell process is similar to one described in a recent Shell patent application [63

• The CoP process experiences the second largest energy penalty (21.9 relative percent) 

primarily because, like the Shell case, a significant amount of water must be added to the 

syngas for the SGS reactions.

].

• The energy penalty for the GEE gasifier with CO2 capture is 16.3 relative percent. The 

smaller energy penalty results from the large amount of water already in the syngas from 

the quench step prior to SGS. While the quench limits the efficiency in the non-capture 

case, it is the primary reason that the net efficiency is slightly greater than CoP and Shell 

in the CO2 capture case.

• The assumed carbon conversion efficiency in this study for the three gasifiers results in 

differing amount of carbon in the slag. Exhibit 3-107 shows carbon conversion and slag 

carbon content. CO2 capture efficiency is reported based on the amount of carbon 

entering the system with the coal less the carbon exiting the gasifier with the slag.

Exhibit 3-107 Carbon Conversion Efficiency and Slag Carbon Content

Gasifier Vendor Carbon Conversion, % Slag Carbon Content, wt%

GEE 98.0 11.62

CoP 99.2 5.00

Shell 99.5 3.18

• Particulate emissions and Hg emissions are essentially the same for all six IGCC cases. 

The environmental target for particulate emissions is 0.0071 lb/MMBtu, and it was 

assumed that the combination of particulate control used by each technology could meet 

this limit. Similarly, the carbon beds used for mercury control were uniformly assumed 

to achieve 95 percent removal. The small variation in Hg emissions is due to a similar 

small variation in coal feed rate among the six cases. In all cases the Hg emissions are 

substantially below the NSPS requirement of 20 x 10-6 lb/MWh. Had 90 percent been 
Cost and Performance Baseline for Fossil Energy Plants

303

chosen for the Hg removal efficiency, all six cases would still have had emissions less 

than half of the NSPS limit.

• Based on vendor data, it was assumed that the advanced F class turbine would achieve 15 

ppmv NOx emissions at 15 percent O2 for both “standard” syngas in the non-capture 

cases and for high hydrogen syngas in the CO2 capture cases. The NOx emissions are 

slightly lower in the three capture cases (compared to non-capture) because of the lower 

syngas volume generated in high hydrogen syngas cases.

• The environmental target for SO2 emissions is 0.0128 lb/MMBtu. Vendor quotes 

confirmed that each of the AGR processes, Selexol, refrigerated MDEA and Sulfinol-M, 

could meet the limit. CoP E-Gas has the highest SO2 emissions (0.005 kg/GJ (0.012

lb/MMBtu)) of the six IGCC cases because refrigerated MDEA has the lowest H2S 

removal efficiency of the AGR technologies. The two-stage Selexol process used for 

each of the CO2 capture cases resulted in lower SO2 emissions because the unit was 

designed to meet the CO2 removal requirement.

Water withdrawal, process discharge, and water consumption, all normalized by net output, are 

presented in Exhibit 3-108. The following observations can be made:

• Raw water usage for all cases is dominated by cooling tower makeup requirements, 

which accounts for 79-87 percent of raw water usage in non-capture cases and 73-75

percent in CO2 capture cases.

• Normalized water withdrawal for the GEE non-capture case is 9 percent higher than the 

CoP non-capture case and 15 percent higher than the Shell non-capture case primarily 

because of the large quench water requirement. However, because much of the quench 

water is subsequently recovered as condensate as the syngas is cooled, the raw water 

consumption of the GEE process is only 9 percent higher than CoP and 13 percent higher 

than Shell.

• The Shell non-capture case has the lowest normalized water withdrawal, but is 

approximately equal to CoP in normalized raw water consumption because very little 

water is available to recover for internal recycle in the Shell system. The GEE 

normalized raw water consumption is slightly higher than CoP and Shell primarily 

because the larger steam turbine output leads to higher cooling tower makeup 

requirements.

• The normalized water withdrawal for the three CO2 capture cases varies by only 6

percent from the highest to the lowest. The variation between cases is small because each 

technology requires approximately the same amount of water in the syngas prior to the 

shift reactors. The difference in technologies is where and how the water is introduced. 

Much of the water is introduced in the quench sections of the GEE and Shell cases while 

steam is added in the CoP case.

• The normalized raw water consumption in the CO2 capture cases also shows little 

variation with GEE the lowest, CoP only 3.4 percent higher and Shell about 7 percent 

higher.
Cost and Performance Baseline for Fossil Energy Plants

304

Exhibit 3-108 Raw Water Withdrawal and Consumption in IGCC Cases

0

2

4

6

8

10

12

GEE GEE w/CO2 

Capture

CoP CoP w/ CO2 

Capture

Shell Shell w/ CO2 

Capture

7.6

10.7

7.0

11.1

6.6

11.3

6.0

8.7

5.5

9.0

5.3

9.3

Water, gpm/MWnet

Raw Water Withdrawal

Process Discharge

Raw Water Consumption
Cost and Performance Baseline for Fossil Energy Plants

305

4.

Four PC fired (PC) Rankine cycle 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 in time for the plant startup date. All designs employ a one-on-one 

configuration comprised of a state-of-the art PC steam generator firing Illinois No. 6 coal and a 

steam turbine. 

PULVERIZED COAL RANKINE CYCLE PLANTS 

The PC cases are evaluated with and without CO2 capture on a common 550 MWe net basis. 

The designs that include CO2 capture have a larger gross unit size to compensate for the higher 

auxiliary loads. The constant net output sizing basis is selected because it provides for a 

meaningful side-by-side comparison of the results. The boiler and steam turbine industry ability 

to match unit size to a custom specification has been commercially demonstrated enabling 

common net output comparison of the PC cases in this study. As discussed in Section 0, this was 

not possible in the IGCC cases because of the fixed output from the CT. However, the net output 

from the PC cases falls in the range of outputs from the IGCC cases, which average 518 MW for 

CO2 capture cases and 625 MW for non-capture cases.

Steam conditions for the Rankine cycle cases were selected based on a survey of boiler and 

steam turbine original equipment manufacturers (OEM), who were asked for the most advanced 

steam conditions that they would guarantee for a commercial project in the US with subcritical 

and SC PC units rated at nominal 550 MWe net capacities and firing Illinois No. 6 coal [64

 For subcritical cases (9 and 10) – 16.5 MPa/566°C/566°C (2,400 psig/1,050°F/1,050°F)

]. 

Based on the OEM responses, the following single-reheat steam conditions were selected for the 

study:

 For SC cases (11 and 12) – 24.1 MPa/593°C/593°C (3,500 psig/1,100°F/1,100°F)

While the current DOE program for the ultra SC cycle materials development targets 

732°C/760°C (1,350oF/1,400oF) at 34.5 MPa (5,000 psi) cycle conditions to be available by 

2015, and a similar Thermie program in the European Union (EU) has targeted 700°C/720°C 

(1,292oF/1,328oF) at about 29.0 MPa (4,200 psi) [65], steam temperature selection for boilers 

depends upon fuel corrosiveness. Most of the contacted OEMs were of the opinion that the 

steam conditions in this range would be limited to low sulfur coal applications (such as PRB). 

Their primary concern is that elevated temperature operation while firing high sulfur coal (such 

as Illinois No. 6) would result in an exponential increase of the material wastage rates of the 

highest temperature portions of the superheater and RH due to coal ash corrosion, requiring 

pressure parts replacement outages approximately every 10 or 15 years. This cost would offset 

the value of fuel savings and emissions reduction due to the higher efficiency. The 

availability/reliability of the more exotic materials required to support the elevated temperature 

environment for high sulfur/chlorine applications, while extensively demonstrated in the 

laboratory [66], has not been commercially demonstrated. In addition, the three most recently 

built SC units in North America have steam cycles similar to this study’s design basis, namely 

Genesee Phase 3 in Canada, which started operations in 2004 (25.0 MPa/570°C/568°C [3,625 

psia/1,058°F/1,054°F]), Council Bluffs 4 in the United States, which started operation in 2007

(25.4 MPa/566°C/593°C [3,690 psia/1,050°F/1,100°F]), and Oak Creek 1 and 2, which are 

currently under construction (24.1 MPa/566°C [3,500 psig/1,050°F]).
Cost and Performance Baseline for Fossil Energy Plants

306

The evaluation basis details, including site ambient conditions, fuel composition and the 

emissions control basis, are provided in Section 2 of this report.

4.1 PC COMMON PROCESS AREAS

The PC cases have process areas that are common to each plant configuration, such as coal 

receiving and storage, emissions control technologies, power generation, etc. As detailed 

descriptions of these process areas in each case section would be burdensome and repetitious, 

they are presented in this section for general background information. The performance features 

of these sections are then presented in the case-specific sections.

4.1.1

The function of the coal portion of the Coal and Sorbent Receiving and Storage system for PC 

plants is identical to the IGCC facilities. It is to provide the equipment required for unloading, 

conveying, preparing, and storing the fuel delivered to the plant. The scope of the system is from 

the trestle bottom dumper and coal receiving hoppers up to the coal storage silos. The system is 

designed to support short-term operation at the 5 percent over pressure/valves wide open 

(OP/VWO) condition (16 hours) and long-term operation of 90 days or more at the maximum 

continuous rating (MCR).

Coal and Sorbent Receiving and Storage

The scope of the sorbent receiving and storage system includes truck roadways, turnarounds, 

unloading hoppers, conveyors and the day storage bin.

Operation Description - The coal is delivered to the site by 100-car unit trains comprised of 91 

tonne (100 ton) rail cars. The unloading is done by a trestle bottom dumper, which unloads the 

coal into two receiving hoppers. Coal from each hopper is fed directly into a vibratory feeder. 

The 8 cm x 0 (3" x 0) coal from the feeder is discharged onto a belt conveyor. Two conveyors 

with an intermediate transfer tower are assumed to convey the coal to the coal stacker, which 

transfer the coal to either the long-term storage pile or to the reclaim area. The conveyor passes 

under a magnetic plate separator to remove tramp iron and then to the reclaim pile.

Coal from the reclaim pile is fed by two vibratory feeders, located under the pile, onto a belt 

conveyor, which transfers the coal to the coal surge bin located in the crusher tower. The coal is 

reduced in size to 2.5 cm x 0 (1" x 0) by the coal crushers. The coal is then transferred by 

conveyor to the transfer tower. In the transfer tower the coal is routed to the tripper that loads 

the coal into one of the six boiler silos.

Limestone is delivered to the site using 23 tonne (25 ton) trucks. The trucks empty into a below 

grade hopper where a feeder transfers the limestone to a conveyor for delivery to the storage pile. 

Limestone from the storage pile is transferred to a reclaim hopper and conveyed to a day bin.

4.1.2

The steam generator for the subcritical PC plants is a drum-type, wall-fired, balanced draft, 

natural circulation, totally enclosed dry bottom furnace, with superheater, reheater, economizer 

and air-heater.

Steam Generator and Ancillaries

The steam generator for the SC plants is a once-through, spiral-wound, Benson-boiler, wall-fired, 

balanced draft type unit with a water-cooled dry bottom furnace. It includes superheater, 

reheater, economizer, and air heater.
Cost and Performance Baseline for Fossil Energy Plants

307

It is assumed for the purposes of this study that the power plant is designed to be operated as a 

base-loaded unit but with some consideration for daily or weekly cycling.

The combustion systems for both subcritical and SC steam conditions are equipped with LNBs 

and OFA. It is assumed for the purposes of this study that the power plant is designed for 

operation as a base-load unit.

The steam generator includes the following for both subcritical and SC PCs: 

Scope

 Drum-type evaporator 

(subcritical only)

 Economizer  OFA system

 Once-through type steam 

generator (SC only)

 Spray type desuperheater  Forced draft (FD) fans

 Startup circuit, including 

integral separators (SC

only)

 Soot blower system  Primary air (PA) fans

 Water-cooled furnace, 

dry bottom

 Air preheaters 

(Ljungstrom type)

 Induced draft (ID) fans

 Two-stage superheater  Coal feeders and 

pulverizers

 Reheater (RH)  Low NOx Coal burners 

and light oil igniters/ 

warm-up system

The steam generator operates as follows:

For the subcritical steam system FW enters the economizer, recovers heat from the combustion 

gases exiting the steam generator, and then passes to the boiler drum, from where it is distributed 

to the water wall circuits enclosing the furnace. After passing through the lower and upper 

furnace circuits and steam drum in sequence, the steam passes through the convection enclosure 

circuits to the primary superheater and then to the secondary superheater.

Feedwater and Steam

The steam then exits the steam generator en route to the HP turbine. Steam from the HP turbine 

returns to the steam generator as cold reheat and returns to the IP turbine as hot reheat. 

For the SC steam system FW enters the bottom header of the economizer and passes upward 

through the economizer tube bank, through stringer tubes, which support the primary 

superheater, and discharges to the economizer outlet headers. From the outlet headers, water 

flows to the furnace hopper inlet headers via external downcomers. Water then flows upward 

through the furnace hopper and furnace wall tubes. From the furnace, water flows to the steam 

water separator. During low load operation (operation below the Benson point), the water from 

the separator is returned to the economizer inlet with the boiler recirculating pump. Operation at 

loads above the Benson point is once through.
Cost and Performance Baseline for Fossil Energy Plants

308

Steam flows from the separator through the furnace roof to the convection pass enclosure walls, 

primary superheater, through the first stage of water attemperation, to the furnace platens. From 

the platens, the steam flows through the second stage of attemperation and then to the 

intermediate superheater. The steam then flows to the final superheater and on to the outlet pipe 

terminal. Two stages of spray attemperation are used to provide tight temperature control in all 

high temperature sections during rapid load changes.

Steam returning from the turbine passes through the primary reheater surface, then through 

crossover piping containing inter-stage attemperation. The crossover piping feeds the steam to 

the final reheater banks and then out to the turbine. Inter-stage attemperation is used to provide 

outlet temperature control during load changes.

Combustion air from the FD fans is heated in Ljungstrom type air preheaters, recovering heat 

energy from the exhaust gases exiting the boiler. This air is distributed to the burner windbox as 

secondary air. Air for conveying PC to the burners is supplied by the PA fans. This air is heated 

in the Ljungstrom type air preheaters to permit drying of the PC, and a portion of the air from the 

PA fans bypasses the air preheaters to be used for regulating the outlet coal/air temperature 

leaving the mills. 

Air and Combustion Products

The PC and air mixture flows to the coal nozzles at various elevations of the furnace. The hot 

combustion products rise to the top of the boiler and pass through the superheater and reheater 

sections. The gases then pass through the economizer and air preheater. The gases exit the 

steam generator at this point and flow to the SCR reactor, fabric filter, ID fan, FGD system, and 

stack.

The crushed Illinois No. 6 bituminous coal is fed through feeders to each of the mills 

(pulverizers), where its size is reduced to approximately 72 percent passing 200 mesh and less 

than 0.5 percent remaining on 50 mesh [

Fuel Feed

67]. The PC exits each mill via the coal piping and is 

distributed to the coal nozzles in the furnace walls using air supplied by the PA fans.

The furnace bottom comprises several hoppers, with a clinker grinder under each hopper. The 

hoppers are of welded steel construction, lined with refractory. The hopper design incorporates a 

water-filled seal trough around the upper periphery for cooling and sealing. Water and ash 

discharged from the hopper pass through the clinker grinder to an ash sluice system for 

conveyance to hydrobins, where the ash is dewatered before it is transferred to trucks for offsite 

disposal. The description of the balance of the bottom ash handling system is presented in 

Section

Ash Removal

4.1.9. The steam generator incorporates fly ash hoppers under the economizer outlet and 

air heater outlet.

A boiler of this capacity employs approximately 24 to 36 coal nozzles arranged at multiple 

elevations. Each burner is designed as a low-NOx configuration, with staging of the coal 

combustion to minimize NOx formation. In addition, OFA nozzles are provided to further stage 

combustion and thereby minimize NOx formation.

Burners
Cost and Performance Baseline for Fossil Energy Plants

309

Oil-fired pilot torches are provided for each coal burner for ignition, warm-up and flame 

stabilization at startup and low loads.

Each steam generator is furnished with two vertical-shaft Ljungstrom regenerative type air 

preheaters. These units are driven by electric motors through gear reducers.

Air Preheaters

The soot-blowing system utilizes an array of 50 to 150 retractable nozzles and lances that clean 

the furnace walls and convection surfaces with jets of HP steam. The blowers are sequenced to 

provide an effective cleaning cycle depending on the coal quality and design of the furnace and 

convection surfaces. Electric motors drive the soot blowers through their cycles.

Soot Blowers

4.1.3

The plant is designed to achieve the environmental target of 0.07 lb NOx/MMBtu. Two 

measures are taken to reduce the NOx. The first is a combination of LNBs and the introduction 

of staged OFA in the boiler. The LNBs and OFA reduce the emissions to about 0.5 lb/MMBtu. 

NOx Control System

The second measure taken to reduce the NOx emissions is the installation of an SCR system 

prior to the air heater. SCR uses ammonia and a catalyst to reduce NOx to N2 and H2O. The 

SCR system consists of three subsystems: reactor vessel, ammonia storage and injection, and 

gas flow control. The SCR system is designed for 86 percent reduction with 2 ppmv ammonia 

slip at the end of the catalyst life. This, along with the LNBs, achieves the emission limit of 

0.07 lb/MMBtu.

The SCR capital costs are included with the boiler costs, as is the cost for the initial load of 

catalyst.

Selective non-catalytic reduction (SNCR) was considered for this application. However, with 

the installation of the LNBs and OFA system, the boiler exhaust gas contains relatively small 

amounts of NOx, which makes removal of the quantity of NOx with SNCR to reach the 

emissions limit of 0.07 lb/MMBtu difficult. SNCR works better in applications that contain 

medium to high quantities of NOx and require removal efficiencies in the range of 40 to 

60 percent. SCR, because of the catalyst used in the reaction, can achieve higher efficiencies 

with lower concentrations of NOx.

The reactor vessel is designed to allow proper retention time for the ammonia to contact the NOx 

in the boiler exhaust gas. Ammonia is injected into the gas immediately prior to entering the 

reactor vessel. The catalyst contained in the reactor vessel enhances the reaction between the 

ammonia and the NOx in the gas. Catalysts consist of various active materials such as titanium 

dioxide, vanadium pentoxide, and tungsten trioxide. The operating range for vanadium/titaniumbased catalysts is 260°C (500°F) to 455°C (850°F). The boiler is equipped with economizer 

bypass to provide FG to the reactors at the desired temperature during periods of low flow rate, 

such as low load operation. Also included with the reactor vessel is soot-blowing equipment 

used for cleaning the catalyst.

SCR Operation Description

The ammonia storage and injection system consists of the unloading facilities, bulk storage tank, 

vaporizers, dilution air skid, and injection grid.
Cost and Performance Baseline for Fossil Energy Plants

310

The FG flow control consists of ductwork, dampers, and flow straightening devices required to 

route the boiler exhaust to the SCR reactor and then to the air heater. The economizer bypass 

and associated dampers for low load temperature control are also included.

4.1.4

The fabric filter (or baghouse) consists of two separate single-stage, in-line, multi-compartment 

units. Each unit is of high (0.9-1.5 m/min [3-5 ft/min]) air-to-cloth ratio design with a pulse-jet 

on-line cleaning system. The ash is collected on the outside of the bags, which are supported by 

steel cages. The dust cake is removed by a pulse of compressed air. The bag material is 

polyphenylensulfide (PPS) with intrinsic Teflon Polytetrafluoroethylene (PTFE) coating [

Particulate Control

68

4.1.5

]. 

The bags are rated for a continuous temperature of 180°C (356°F) and a peak temperature of 

210°C (410°F). Each compartment contains a number of gas passages with filter bags, and 

heated ash hoppers supported by a rigid steel casing. The fabric filter is provided with necessary 

control devices, inlet gas distribution devices, insulators, inlet and outlet nozzles, expansion 

joints, and other items as required.

Mercury removal is based on a coal Hg content of 0.15 ppmd. The basis for the coal Hg 

concentration was discussed in Section

Mercury Removal

2.4. The combination of pollution control technologies 

used in the PC plants, SCR, fabric filters and FGD, result in significant co-benefit capture of 

mercury. The SCR promotes the oxidation of elemental mercury, which in turn enhances the 

mercury removal capability of the fabric filter and FGD unit. The mercury co-benefit capture is 

assumed to be 90 percent for this combination of control technologies as described in Section 

2.4. Co-benefit capture alone is sufficient to meet current NSPS mercury limits so no activated 

carbon injection is included in the PC cases.

4.1.6

The FGD system is a wet limestone forced oxidation positive pressure absorber non-reheat unit, 

with wet-stack, and gypsum production. The function of the FGD system is to scrub the boiler 

exhaust gases to remove the SO2 prior to release to the environment, or entering into the Carbon 

Dioxide Removal (CDR) facility. Sulfur removal efficiency is 98 percent in the FGD unit for all 

cases. For Cases 10 and 12 with CO2 capture, the SO2 content of the scrubbed gases must be 

further reduced to approximately 10 ppmv to minimize formation of amine heat stable salts 

(HSS) during the CO2 absorption process. The CDR unit includes a polishing scrubber to reduce 

the FG SO2 concentration from about 44 ppmv at the FGD exit to the required 10 ppmv prior to 

the CDR absorber. The scope of the FGD system is from the outlet of the ID fans to the stack 

inlet (Cases 9 and 11) or to the CDR process inlet (Cases 10 and 12). The system description is 

divided into three sections:

Flue Gas Desulfurization

• Limestone Handling and Reagent Preparation

• FGD Scrubber

• Byproduct Dewatering
Cost and Performance Baseline for Fossil Energy Plants

311

The function of the limestone reagent preparation system is to grind and slurry the limestone 

delivered to the plant. The scope of the system is from the day bin up to the limestone feed 

system. The system is designed to support continuous base load operation. 

Reagent Preparation System

Operation Description - Each day bin supplies a 100 percent capacity ball mill via a weigh 

feeder. The wet ball mill accepts the limestone and grinds the limestone to 90 to 95 percent 

passing 325 mesh (44 microns). Water is added at the inlet to the ball mill to create limestone 

slurry. The reduced limestone slurry is then discharged into a mill slurry tank. Mill recycle 

pumps, two per tank, pump the limestone water slurry to an assembly of hydrocyclones and 

distribution boxes. The slurry is classified into several streams, based on suspended solids 

content and size distribution.

The hydrocyclone underflow with oversized limestone is directed back to the mill for further 

grinding. The hydrocyclone overflow with correctly sized limestone is routed to a reagent 

storage tank. Reagent distribution pumps direct slurry from the tank to the absorber module.

The FG exiting the air preheater section of the boiler passes through one of two parallel fabric 

filter units, then through the ID fans and into the one 100 percent capacity absorber module. The 

absorber module is designed to operate with counter-current flow of gas and reagent. Upon 

entering the bottom of the absorber vessel, the gas stream is subjected to an initial quenching 

spray of reagent. The gas flows upward through the spray zone, which provides enhanced 

contact between gas and reagent. Multiple spray elevations with header piping and nozzles 

maintain a consistent reagent concentration in the spray zone. Continuing upward, the reagentladen gas passes through several levels of moisture separators. These consist of chevron-shaped 

vanes that direct the gas flow through several abrupt changes in direction, separating the 

entrained droplets of liquid by inertial effects. The scrubbed FG exits at the top of the absorber 

vessel and is routed to the plant stack or CDR process.

FGD Scrubber

The scrubbing slurry falls to the lower portion of the absorber vessel, which contains a large 

inventory of liquid. Oxidation air is added to promote the oxidation of calcium sulfite contained 

in the slurry to calcium sulfate (gypsum). Multiple agitators operate continuously to prevent 

settling of solids and enhance mixture of the oxidation air and the slurry. Recirculation pumps 

recirculate the slurry from the lower portion of the absorber vessel to the spray level. Spare 

recirculation pumps are provided to ensure availability of the absorber.

The absorber chemical equilibrium is maintained by continuous makeup of fresh reagent, and 

blowdown of byproduct solids via the bleed pumps. A spare bleed pump is provided to ensure 

availability of the absorber. The byproduct solids are routed to the byproduct dewatering system. 

The circulating slurry is monitored for pH and density.

This FGD system is designed for wet stack operation. Scrubber bypass or reheat, which may be 

utilized at some older facilities to ensure the exhaust gas temperature is above the saturation 

temperature, is not employed in this reference plant design because new scrubbers have 

improved mist eliminator efficiency, and detailed flow modeling of the flue interior enables the 

placement of gutters and drains to intercept moisture that may be present and convey it to a 

drain. Consequently, raising the exhaust gas temperature above the FGD discharge temperature 

of 57°C (135°F) (non-CO2 capture cases) or 32°C (89°F) (CO2 capture cases) is not necessary.
Cost and Performance Baseline for Fossil Energy Plants

312

The function of the byproduct dewatering system is to dewater the bleed slurry from the FGD 

absorber modules. The dewatering process selected for this plant is gypsum dewatering 

producing wallboard grade gypsum. The scope of the system is from the bleed pump discharge 

connections to the gypsum storage pile. 

Byproduct Dewatering

Operation Description - The recirculating reagent in the FGD absorber vessel accumulates 

dissolved and suspended solids on a continuous basis as byproducts from the SO2 absorption 

process. Maintenance of the quality of the recirculating slurry requires that a portion be 

withdrawn and replaced by fresh reagent. This is accomplished on a continuous basis by the 

bleed pumps pulling off byproduct solids and the reagent distribution pumps supplying fresh 

reagent to the absorber. 

Gypsum (calcium sulfate) is produced by the injection of oxygen into the calcium sulfite 

produced in the absorber tower sump. The bleed from the absorber contains approximately 

20 wt% gypsum. The absorber slurry is pumped by an absorber bleed pump to a primary 

dewatering hydrocyclone cluster. The primary hydrocyclone performs two process functions. 

The first function is to dewater the slurry from 20 wt% to 50 wt% solids. The second function of 

the primary hydrocyclone is to perform a CaCO3 and CaSO4•2H2O separation. This process 

ensures a limestone stoichiometry in the absorber vessel of 1.10 and an overall limestone 

stoichiometry of 1.05. This system reduces the overall operating cost of the FGD system. The 

underflow from the hydrocyclone flows into the filter feed tank, from which it is pumped to a 

horizontal belt vacuum filter. Two 100 percent filter systems are provided for redundant 

capacity.

The hydrocyclone is a simple and reliable device (no moving parts) designed to increase the 

slurry concentration in one step to approximately 50 wt%. This high slurry concentration is 

necessary to optimize operation of the vacuum belt filter.

Hydrocyclones

The hydrocyclone feed enters tangentially and experiences centrifugal motion so that the heavy 

particles move toward the wall and flow out the bottom. Some of the lighter particles collect at 

the center of the cyclone and flow out the top. The underflow is thus concentrated from 20 wt% 

at the feed to 50 wt%.

Multiple hydrocyclones are used to process the bleed stream from the absorber. The 

hydrocyclones are configured in a cluster with a common feed header. The system has two 

hydrocyclone clusters, each with five 15 cm (6 inch) diameter units. Four cyclones are used to 

continuously process the bleed stream at design conditions, and one cyclone is spare.

Cyclone overflow and underflow are collected in separate launders. The overflow from the 

hydrocyclones still contains about 5 wt% solids, consisting of gypsum, fly ash, and limestone 

residues and is sent back to the absorber. The underflow of the hydrocyclones flows into the 

filter feed tank from where it is pumped to the horizontal belt vacuum filters.

The secondary dewatering system consists of horizontal vacuum belt filters. The preconcentrated gypsum slurry (50 wt%) is pumped to an overflow pan through which the slurry 

flows onto the vacuum belt. As the vacuum is pulled, a layer of cake is formed. The cake is 

Horizontal Vacuum Belt Filters
Cost and Performance Baseline for Fossil Energy Plants

313

dewatered to approximately 90 wt% solids as the belt travels to the discharge. At the discharge 

end of the filter, the filter cloth is turned over a roller where the solids are dislodged from the 

filter cloth. This cake falls through a chute onto the pile prior to the final byproduct uses. The 

required vacuum is provided by a vacuum pump. The filtrate is collected in a filtrate tank that 

provides surge volume for use of the filtrate in grinding the limestone. Filtrate that is not used 

for limestone slurry preparation is returned to the absorber.

4.1.7

A Carbon Dioxide Recovery (CDR) facility is used in Cases 10 and 12 to remove 90 percent of 

the CO2 in the flue gas exiting the FGD unit, purify it, and compress it to a SC condition. The 

flue gas exiting the FGD unit contains about 1 percent more CO2 than the raw flue gas because 

of the CO2 liberated from the limestone in the FGD absorber vessel. The CDR is comprised of 

the flue gas supply, SO2 polishing, CO2 absorption, solvent stripping and reclaiming, and CO2

compression and drying.

Carbon Dioxide Recovery Facility

The CO2 absorption/stripping/solvent reclaim process for Cases 10 and 12 is based on the Fluor

Econamine FG PlusSM technology [69, 70]. A typical flowsheet is shown in Exhibit 4-1. The 

Econamine FG Plus process uses a formulation of MEA and a proprietary corrosion inhibitor to 

recover CO2 from the flue gas. This process is designed to recover high-purity CO2 from LP

streams that contain oxygen, such as flue gas from coal-fired power plants, GT exhaust gas, and 

other waste gases. The Econamine process used in this study differs from previous studies, 

including the 2003 IEA study, [71

• The complexity of the control and operation of the plant is significantly decreased

] in the following ways:

• Solvent consumption is decreased

• Hard to dispose waste from the plant is greatly reduced

The above are achieved at the expense of a slightly higher steam requirement in the stripper 

(3,556 kJ/kg) [1,530 Btu/lb] versus 3,242 kJ/kg [1,395 Btu/lb] used in the IEA study) [72].
Cost and Performance Baseline for Fossil Energy Plants

314

Exhibit 4-1 Fluor Econamine FG PlusSM Typical Flow Diagram
Cost and Performance Baseline for Fossil Energy Plants

315

To minimize the accumulation of HSS, the incoming flue gas must have an SO2 concentration of 

10 ppmv or less. The gas exiting the FGD system passes through an SO2 polishing step to 

achieve this objective. The polishing step consists of a non-plugging, low-differential-pressure, 

spray-baffle-type scrubber using a 20 wt% solution of sodium hydroxide (NaOH). A removal 

efficiency of about 75 percent is necessary to reduce SO2 emissions from the FGD outlet to 10 

ppmv as required by the Econamine process. The polishing scrubber proposed for this 

application has been demonstrated in numerous industrial applications throughout the world and 

can achieve removal efficiencies of over 95 percent if necessary.

SO2 Polishing and FG Cooling and Supply 

The polishing scrubber also serves as the flue gas cooling system. Cooling water from the PC 

plant is used to reduce the flue gas temperature to below the adiabatic saturation temperature 

resulting in a reduction of the flue gas moisture content. Flue gas is cooled beyond the CO2

absorption process requirements to 32°C (90°F) to account for the subsequent temperature 

increase of about 17°C (30°F) in the flue gas blower. Downstream from the Polishing Scrubber 

flue gas pressure is boosted in the FG Blowers by approximately 0.014 MPa (2 psi) to overcome 

pressure drop in the CO2 absorber tower.

Cooling water is provided from the PC plant CWS and returned to the PC plant cooling tower. 

The CDR facility requires a significant amount of cooling water for flue gas cooling, water wash 

cooling, absorber intercooling, reflux condenser duty, reclaimer cooling, the lean solvent cooler, 

and CO2 compression interstage cooling. The cooling water requirements for the CDR facility in 

the two PC capture cases range from 1,173,350-1,286,900 lpm (310,000-340,000 gpm), which 

greatly exceeds the PC plant cooling water requirement of 643,450-757,000 lpm (170,000-

200,000 gpm).

Circulating Water System

The cooled flue gas enters the bottom of the CO2 Absorber and flows up through the tower 

countercurrent to a stream of lean MEA-based solvent. Approximately 90 percent of the CO2 in 

the feed gas is absorbed into the lean solvent, and the rest leaves the top of the absorber section 

and flows into the water wash section of the tower. The lean solvent enters the top of the 

absorber section, absorbs the CO2 from the FG and leaves the bottom of the absorber with the 

absorbed CO2. The FG Plus process also includes solvent intercooling. The semi-rich solvent is 

extracted from the column, cooled using cooling water, and returned to the absorber section just 

below the extraction point. The CO2 carrying capacity of the solvent is increased at lower 

temperature, which reduces the solvent circulation rate.

CO2 Absorption Section

The purpose of the Water Wash section is to minimize solvent losses due to mechanical 

entrainment and evaporation. The flue gas from the top of the CO2 Absorption section is 

contacted with a re-circulating stream of water for the removal of most of the lean solvent. The 

scrubbed gases, along with unrecovered solvent, exit the top of the wash section for discharge to 

the atmosphere via the vent stack. The water stream from the bottom of the wash section is 

collected on a chimney tray. A portion of the water collected on the chimney tray spills over to 

Water Wash Section
Cost and Performance Baseline for Fossil Energy Plants

316

the absorber section as water makeup for the amine with the remainder pumped via the Wash 

Water Pump, cooled by the Water Wash Cooler, and recirculated to the top of the CO2 Absorber. 

The wash water level is maintained by wash water makeup. 

The rich solvent from the bottom of the CO2 Absorber is preheated by the lean solvent from the 

Solvent Stripper in the Lean/Rich Cross Exchanger. The heated rich solvent is routed to the 

Solvent Stripper for removal of the absorbed CO2. The stripped solvent from the bottom of the 

Solvent Stripper is pumped via the Lean Solvent Pump to the Lean Solvent Cooler. A slipstream 

of the lean solvent is then sent through the Amine Filter Package to prevent buildup of 

contaminants in the solution. The filtered lean solvent is mixed with the remaining lean solvent 

from the Lean Solvent Cooler and sent to the CO2 Absorber, completing the circulating solvent 

circuit.

Rich/Lean Amine Heat Exchange System

The purpose of the Solvent Stripper is to separate the CO2 from the rich solvent feed exiting the 

bottom of the CO2 Absorber. The rich solvent is collected on a chimney tray below the bottom 

packed section of the Stripper and routed to the Reboiler where the rich solvent is heated by 

steam, stripping the CO2 from the solution. Steam is provided from the crossover pipe between 

the IP and LP sections of the steam turbine and is 0.5 MPa (74 psia) and 152°C (306°F) for the 

two PC cases. The hot wet vapor from the top of the stripper containing CO2, steam, and solvent 

vapor, is partially condensed in the Reflux Condenser by cross exchanging the hot wet vapor 

with cooling water. The partially condensed stream then flows to the Reflux Drum where the 

vapor and liquid are separated. The uncondensed CO2-rich gas is then delivered to the CO2

product compressor. The condensed liquid from the Reflux Drum is pumped via the Reflux 

Pump where a portion of condensed overhead liquid is combined with the lean solvent entering 

the CO2 Absorber. The rest of the pumped liquid is routed back to the Solvent Stripper as reflux, 

which aids in limiting the amount of solvent vapors entering the stripper overhead system.

Solvent Stripper

The low temperature reclaimer technology is a recent development for the FG Plus technology. 

A small slipstream of the lean solvent is fed to the Solvent Reclaimer for the removal of highboiling nonvolatile impurities including HSS, volatile acids and iron products from the 

circulating solvent solution. Reclaiming occurs in two steps, the first is an ion-exchange process. 

There is a small amount of degradation products that cannot be removed via ion-exchange, and a 

second atmospheric pressure reclaiming process is used to remove the degradation products. The 

solvent reclaimer system reduces corrosion, foaming and fouling in the solvent system. The 

reclaimed solvent is returned to the Solvent Stripper and the spent solvent is pumped via the 

Solvent Reclaimer Drain Pump to the Solvent Reclaimer Drain Tank for disposal. The quantity 

of spent solvent is greatly reduced from the previously used thermal reclaimer systems.

Solvent Reclaimer 

Steam condensate from the Solvent Stripper Reclaimer accumulates in the Solvent Reclaimer 

Condensate Drum and is level controlled to the Solvent Reboiler Condensate Drum. Steam 

condensate from the Solvent Stripper Reboilers is also collected in the Solvent Reboiler 

Steam Condensate
Cost and Performance Baseline for Fossil Energy Plants

317

Condensate Drum and returned to the steam cycle between BFW heaters 4 and 5 via the Solvent 

Reboiler Condensate Pumps.

A proprietary corrosion inhibitor is intermittently injected into the CO2 Absorber rich solvent 

bottoms outlet line. This additive is to help control the rate of corrosion throughout the CO2

recovery plant system.

Corrosion Inhibitor System

In the compression section, the CO2 is compressed to 15.3 MPa (2,215 psia) by a six-stage 

centrifugal compressor. The discharge pressures of the stages were balanced to give reasonable 

power distribution and discharge temperatures across the various stages as shown in 

Gas Compression and Drying System

Exhibit 4-2.

Exhibit 4-2 CO2 Compressor Interstage Pressures

Stage Outlet Pressure, 

MPa (psia)

1 0.36 (52)

2 0.78 (113)

3 1.71 (248)

4 3.76 (545)

5 8.27 (1,200)

6 15.3 (2,215)

Power consumption for this large compressor was estimated assuming a polytropic efficiency of 

86 percent and a mechanical efficiency of 98 percent for all stages. During compression to 15.3 

MPa (2,215 psia) in the multiple-stage, intercooled compressor, the CO2 stream is dehydrated to 

a dewpoint of -40oC (-40°F) with triethylene glycol. The virtually moisture-free SC CO2 stream 

is delivered to the plant battery limit as sequestration ready. CO2 TS&M costs were estimated 

and included in LCOE and COE using the methodology described in Section 2.7.

Several alternatives to rejecting the heat of CO2 compression to cooling water were investigated 

in a separate study [73]. The first alternative consisted of using a portion of the heat to pre-heat 

BFW while the remaining heat was still rejected to cooling water. This configuration resulted in 

an increase in efficiency of 0.3 percentage points (absolute). The second alternative modified the 

CO2 compression intercooling configuration to enable integration into a LiBr-H2O absorption 

refrigeration system, where water is the refrigerant. In the CO2 compression section, the single 

intercooler between each compression stage was replaced with one kettle reboiler and two 

counter current shell and tube heat exchangers. The kettle reboiler acts as the generator that 

rejects heat from CO2 compression to the LiBr-H2O solution to enable the separation of the 

refrigerant from the brine solution. The second heat exchanger rejects heat to the cooling water. 

The evaporator heat exchanger acts as the refrigerator and cools the CO2 compression stream by 

vaporizing the refrigerant. Only five stages of CO2 compression were necessary for Approach 2. 

The compression ratios were increased from the reference cases to create a compressor outlet 
Cost and Performance Baseline for Fossil Energy Plants

318

temperature of at least 200°F to maintain a temperature gradient of 10°F in the kettle reboiler. 

This configuration resulted in an efficiency increase of 0.1 percentage points (absolute).

It was concluded that the small increase in efficiency did not justify the added cost and 

complexity of the two configurations and hence they were not incorporated into the base design.

4.1.8

The steam turbine is designed for long-term operation (90 days or more) at MCR with throttle 

control valves 95 percent open. It is also capable of a short-term 5 percent OP/VWO condition 

(16 hours).

Power Generation

For the subcritical cases, the steam turbine is a tandem compound type, consisting of HP-IP-two 

LP (double flow) sections enclosed in three casings, designed for condensing single reheat 

operation, and equipped with non-automatic extractions and four-flow exhaust. The turbine 

drives a hydrogen-cooled generator. The turbine has DC motor-operated lube oil pumps, and 

main lube oil pumps, which are driven off the turbine shaft [74

The steam-turbine generator systems for the SC plants are similar in design to the subcritical 

systems. The differences include steam cycle conditions and eight extractions points versus 

seven for the subcritical design.

]. The exhaust pressure is 50.8 

cm (2 in) Hg in the single pressure condenser. There are seven extraction points. The condenser 

is two-shell, transverse, single pressure with divided waterbox for each shell.

Turbine bearings are lubricated by a closed-loop, water-cooled pressurized oil system. Turbine 

shafts are sealed against air in-leakage or steam blowout using a labyrinth gland arrangement 

connected to a LP steam seal system. The generator stator is cooled with a CL water system 

consisting of circulating pumps, shell and tube or plate and frame type heat exchangers, filters, 

and deionizers, all skid-mounted. The generator rotor is cooled with a hydrogen gas 

recirculation system using fans mounted on the generator rotor shaft. 

Operation Description - The turbine stop valves, control valves, reheat stop valves, and 

intercept valves are controlled by an electro-hydraulic control system. Main steam from the 

boiler passes through the stop valves and control valves and enters the turbine at 16.5 

MPa/566°C (2,400 psig/1,050oF) for the subcritical cases and 24.1MPa /593°C 

(3,500psig/1,100°F) for the SC cases. The steam initially enters the turbine near the middle of 

the HP span, flows through the turbine, and returns to the boiler for reheating. The reheat steam 

flows through the reheat stop valves and intercept valves and enters the IP section at 566°C 

(1,050oF) in the subcritical cases and 593°C (1,100°F) in the SC cases. After passing through the 

IP section, the steam enters a crossover pipe, which transports the steam to the two LP sections. 

The steam divides into four paths and flows through the LP sections exhausting downward into 

the condenser. 

The turbine is designed to operate at constant inlet steam pressure over the entire load range.

4.1.9

The balance of plant components consist of the condensate, FW, main and reheat steam, 

extraction steam, ash handling, ducting and stack, waste treatment and miscellaneous systems as 

described below.

Balance of Plant
Cost and Performance Baseline for Fossil Energy Plants

319

The function of the condensate system is to pump condensate from the condenser hotwell to the 

deaerator, through the gland steam condenser and the LP FW heaters. Each system consists of 

one main condenser; two variable speed electric motor-driven vertical condensate pumps each 

sized for 50 percent capacity; one gland steam condenser; four LP heaters; and one deaerator 

with storage tank.

Condensate

Condensate is delivered to a common discharge header through two separate pump discharge 

lines, each with a check valve and a gate valve. A common minimum flow recirculation line 

discharging to the condenser is provided downstream of the gland steam condenser to maintain 

minimum flow requirements for the gland steam condenser and the condensate pumps.

LP FW heaters 1 through 4 are 50 percent capacity, parallel flow, and are located in the 

condenser neck. All remaining FW heaters are 100 percent capacity shell and U-tube heat 

exchangers. Each LP FW heater is provided with inlet/outlet isolation valves and a full capacity 

bypass. LP FW heater drains cascade down to the next lowest extraction pressure heater and 

finally discharge into the condenser. Pneumatic level control valves control normal drain levels 

in the heaters. High heater level dump lines discharging to the condenser are provided for each 

heater for turbine water induction protection. Pneumatic level control valves control dump line 

flow.

The function of the FW system is to pump the FW from the deaerator storage tank through the 

HP FW heaters to the economizer. One turbine-driven BFW pump sized at 100 percent capacity 

is provided to pump FW through the HP FW heaters. One 25 percent motor-driven BFW pump 

is provided for startup. The pumps are provided with inlet and outlet isolation valves, and 

individual minimum flow recirculation lines discharging back to the deaerator storage tank. The 

recirculation flow is controlled by automatic recirculation valves, which are a combination check 

valve in the main line and in the bypass, bypass control valve, and flow sensing element. The 

suction of the boiler feed pump is equipped with startup strainers, which are utilized during 

initial startup and following major outages or system maintenance.

Feedwater

Each HP FW heater is provided with inlet/outlet isolation valves and a full capacity bypass. FW

heater drains cascade down to the next lowest extraction pressure heater and finally discharge 

into the deaerator. Pneumatic level control valves control normal drain level in the heaters. 

High heater level dump lines discharging to the condenser are provided for each heater for 

turbine water induction protection. Dump line flow is controlled by pneumatic level control 

valves.

The deaerator is a horizontal, spray tray type with internal direct contact stainless steel (SS) vent 

condenser and storage tank. The boiler feed pump turbine is driven by main steam up to 

60 percent plant load. Above 60 percent load, extraction from the IP turbine exhaust (1.05 

MPa/395°C [153 psig/743°F]) provides steam to the boiler feed pump steam turbine.

The function of the main steam system is to convey main steam from the boiler superheater 

outlet to the HP turbine stop valves. The function of the reheat system is to convey steam from 

the HP turbine exhaust to the boiler reheater and from the boiler reheater outlet to the IP turbine 

stop valves.

Main and Reheat Steam
Cost and Performance Baseline for Fossil Energy Plants

320

Main steam exits the boiler superheater through a motor-operated stop/check valve and a motoroperated gate valve and is routed in a single line feeding the HP turbine. A branch line off the IP 

turbine exhaust feeds the boiler feed water pump turbine during unit operation starting at 

approximately 60 percent load.

Cold reheat steam exits the HP turbine, flows through a motor-operated isolation gate valve and 

a flow control valve, and enters the boiler reheater. Hot reheat steam exits the boiler reheater 

through a motor-operated gate valve and is routed to the IP turbine. A branch connection from 

the cold reheat piping supplies steam to FW heater 7. 

The function of the extraction steam system is to convey steam from turbine extraction points 

through the following routes:

Extraction Steam

 From HP turbine exhaust (cold reheat) to heater 7

 From IP turbine extraction to heater 6 and the deaerator (heater 5)

 From LP turbine extraction to heaters 1, 2, 3, and 4

The turbine is protected from overspeed on turbine trip, from flash steam reverse flow from the 

heaters through the extraction piping to the turbine. This protection is provided by positive 

closing, balanced disc non-return valves located in all extraction lines except the lines to the LP 

FW heaters in the condenser neck. The extraction non-return valves are located only in 

horizontal runs of piping and as close to the turbine as possible.

The turbine trip signal automatically trips the non-return valves through relay dumps. The 

remote manual control for each heater level control system is used to release the non-return 

valves to normal check valve service when required to restart the system.

It is assumed that the plant is serviced by a public water facility and has access to groundwater 

for use as makeup cooling water with minimal pretreatment. All filtration and treatment of the 

circulating water are conducted on site. A mechanical draft, wood frame, counter-flow cooling 

tower is provided for the circulating water heat sink. Two 50 percent CWPs are provided. The 

CWS provides cooling water to the condenser, the auxiliary cooling water system, and the CDR 

facility in capture cases.

Circulating Water System

The auxiliary cooling water system is a CL system. Plate and frame heat exchangers with 

circulating water as the cooling medium are provided. This system provides cooling water to the 

lube oil coolers, turbine generator, boiler feed pumps, etc. All pumps, vacuum breakers, air 

release valves, instruments, controls, etc. are included for a complete operable system.

The CDR system in Cases 10 and 12 requires a substantial amount of cooling water that is 

provided by the PC plant CWS. The additional cooling load imposed by the CDR is reflected in 

the significantly larger CWPs and cooling tower in those cases.

The function of the ash handling system is to provide the equipment required for conveying, 

preparing, storing, and disposing of the fly ash and bottom ash produced on a daily basis by the 

boiler. The scope of the system is from the baghouse hoppers, air heater and economizer hopper 

Ash Handling System
Cost and Performance Baseline for Fossil Energy Plants

321

collectors, and bottom ash hoppers to the hydrobins (for bottom ash) and truck filling stations 

(for fly ash). The system is designed to support short-term operation at the 5 percent OP/VWO 

condition (16 hours) and long-term operation at the 100 percent guarantee point (90 days or 

more). 

The fly ash collected in the baghouse and the air heaters is conveyed to the fly ash storage silo. 

A pneumatic transport system using LP air from a blower provides the transport mechanism for 

the fly ash. Fly ash is discharged through a wet unloader, which conditions the fly ash and 

conveys it through a telescopic unloading chute into a truck for disposal.

The bottom ash from the boiler is fed into a clinker grinder. The clinker grinder is provided to 

break up any clinkers that may form. From the clinker grinders the bottom ash is sluiced to 

hydrobins for dewatering and offsite removal by truck.

Ash from the economizer hoppers and pyrites (rejected from the coal pulverizers) is conveyed 

using water to the economizer/pyrites transfer tank. This material is then sluiced on a periodic 

basis to the hydrobins.

One stack is provided with a single fiberglass-reinforced plastic (FRP) liner. The stack is 

constructed of reinforced concrete. The stack is 152 m (500 ft) high for adequate particulate 

dispersion.

Ducting and Stack

An onsite water treatment facility treats all runoff, cleaning wastes, blowdown, and backwash to 

within the U.S. EPA standards for suspended solids, oil and grease, pH, and miscellaneous 

metals. Waste treatment equipment is housed in a separate building. The waste treatment 

system consists of a water collection basin, three raw waste pumps, an acid neutralization 

system, an oxidation system, flocculation, clarification/thickening, and sludge dewatering. The 

water collection basin is a synthetic-membrane-lined earthen basin, which collects rainfall 

runoff, maintenance cleaning wastes, and backwash flows.

Waste Treatment/Miscellaneous Systems

The raw waste is pumped to the treatment system at a controlled rate by the raw waste pumps. 

The neutralization system neutralizes the acidic wastewater with hydrated lime in a two-stage 

system, consisting of a lime storage silo/lime slurry makeup system, dry lime feeder, lime slurry 

tank, slurry tank mixer, and lime slurry feed pumps.

The oxidation system consists of an air compressor, which injects air through a sparger pipe into 

the second-stage neutralization tank. The flocculation tank is fiberglass with a variable speed 

agitator. A polymer dilution and feed system is also provided for flocculation. The clarifier is a 

plate-type, with the sludge pumped to the dewatering system. The sludge is dewatered in filter 

presses and disposed offsite. Trucking and disposal costs are included in the cost estimate. The 

filtrate from the sludge dewatering is returned to the raw waste sump.

Miscellaneous systems consisting of fuel oil, service air, instrument air, and service water are 

provided. A storage tank provides a supply of No. 2 fuel oil used for startup and for a small 

auxiliary boiler. Fuel oil is delivered by truck. All truck roadways and unloading stations inside 

the fence area are provided.
Cost and Performance Baseline for Fossil Energy Plants

322

Foundations are provided for the support structures, pumps, tanks, and other plant components. 

The following buildings are included in the design basis:

Buildings and Structures

 Steam turbine building  Fuel oil pump house  Guard house

 Boiler building  Coal crusher building  Runoff water pump house

 Administration and 

service building

 Continuous emissions 

monitoring building

 Industrial waste treatment 

building

 Makeup water and 

pretreatment building

 Pump house and electrical 

equipment building

 FGD system buildings

4.1.10

The accessory electric plant consists of switchgear and control equipment, generator equipment, 

station service equipment, conduit and cable trays, and wire and cable. It also includes the main 

power transformer, required foundations, and standby equipment.

Accessory Electric Plant

4.1.11

An integrated plant-wide control and monitoring DCS is provided. The DCS is a redundant 

microprocessor-based, functionally distributed system. The control room houses an array of 

multiple video monitor and keyboard units. The monitor/keyboard units are the primary 

interface between the generating process and operations personnel. The DCS incorporates plant 

monitoring and control functions for all the major plant equipment. The DCS is designed to 

provide 99.5 percent availability. The plant equipment and the DCS are designed for automatic 

response to load changes from minimum load to 100 percent. Startup and shutdown routines are 

implemented as supervised manual, with operator selection of modular automation routines 

available.

Instrumentation and Control

4.2 SUBCRITICAL PC CASES

This section contains an evaluation of plant designs for Cases 9 and 10, which are based on a 

subcritical PC plant with a nominal net output of 550 MWe. Both plants use a single reheat 16.5 

MPa/566°C/566°C (2400 psig/1050°F/1050°F) cycle. The only difference between the two 

plants is that Case 10 includes CO2 capture while Case 9 does not.

The balance of Section 4.2 is organized as follows:

• Process and System Description provides an overview of the technology operation as 

applied to Case 9. The systems that are common to all PC cases were covered in Section 

4.1 and only features that are unique to Case 9 are discussed further in this section.

• Key Assumptions is a summary of study and modeling assumptions relevant to Cases 9 

and 10.

• Sparing Philosophy is provided for both Cases 9 and 10.
Cost and Performance Baseline for Fossil Energy Plants

323

• Performance Results provides the main modeling results from Case 9, including the 

performance summary, environmental performance, carbon/sulfur balances, water 

balance, mass and energy balance diagrams and energy balance table.

• Equipment List provides an itemized list of major equipment for Case 9 with account 

codes that correspond to the cost accounts in the Cost Estimates section.

• Cost Estimates provides a summary of capital and operating costs for Case 9.

• Process and System Description, Performance Results, Equipment List and Cost 

Estimates are discussed for Case 10.

4.2.1

In this section the subcritical PC process without CO2 capture is described. The system 

description follows the BFD in 

Process Description

Exhibit 4-3 and stream numbers reference the same Exhibit. The 

tables in Exhibit 4-4 provide process data for the numbered streams in the BFD.

Coal (stream 8) and PA (stream 4) are introduced into the boiler through the wall-fired burners. 

Additional combustion air, including the OFA, is provided by the FD fans (stream 1). The boiler 

operates at a slight negative pressure so air leakage is into the boiler, and the infiltration air is 

accounted for in stream 7. Streams 3 and 6 show Ljungstrom air preheater leakages from the FD

and PA fan outlet streams to the boiler exhaust.

FG exits the boiler through the SCR reactor (stream 10) and is cooled to 169°C (337°F) in the 

combustion air preheater before passing through a fabric filter for particulate removal (stream 

12). An ID fan increases the FG temperature to 181°C (357°F) and provides the motive force for 

the FG (stream 13) to pass through the FGD unit. FGD inputs and outputs include makeup water 

(stream 15), oxidation air (stream 16), limestone slurry (stream 14) and product gypsum (stream 

17). The clean, saturated FG exiting the FGD unit (stream 18) passes to the plant stack and is 

discharged to atmosphere.
Cost and Performance Baseline for Fossil Energy Plants

324

Exhibit 4-3 Case 9 Block Flow Diagram, Subcritical Unit without CO2 Capture
Cost and Performance Baseline for Fossil Energy Plants

325

Exhibit 4-4 Case 9 Stream Table, Subcritical Unit without CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12

V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087

CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1447 0.0000 0.1447

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0868 0.0000 0.0868

N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7325 0.0000 0.7325

O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0250 0.0000 0.0250

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000

V-L Flowrate (kgmol/hr) 51,817 51,817 1,535 15,918 15,918 2,191 1,195 0 0 72,904 0 72,904

V-L Flowrate (kg/hr) 1,495,285 1,495,285 44,287 459,336 459,336 63,217 34,480 0 0 2,168,255 0 2,168,255

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 198,391 3,848 15,390 15,390 0

Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169

Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10

Enthalpy (kJ/kg)A 30.23 34.36 34.36 30.23 40.78 40.78 30.23 --- --- 327.06 --- 308.70

Density (kg/m3

) 1.2 1.2 1.2 1.2 1.3 1.3 1.2 --- --- 0.8 --- 0.8

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857 --- --- 29.741 --- 29.741

V-L Flowrate (lbmol/hr) 114,237 114,237 3,383 35,092 35,092 4,830 2,634 0 0 160,726 0 160,726

V-L Flowrate (lb/hr) 3,296,540 3,296,540 97,637 1,012,663 1,012,663 139,369 76,015 0 0 4,780,183 0 4,780,183

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 437,378 8,482 33,929 33,929 0

Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337

Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.7 14.4 14.7 14.2

Enthalpy (Btu/lb)A 13.0 14.8 14.8 13.0 17.5 17.5 13.0 --- --- 140.6 --- 132.7

Density (lb/ft3

) 0.076 0.078 0.078 0.076 0.081 0.081 0.076 --- --- 0.050 --- 0.049

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Fossil Energy Plants

326

Exhibit 4-4 Case 9 Stream Table, Subcritical Unit without CO2 Capture (Continued)

13 14 15 16 17 18 19 20 21 22 23

V-L Mole Fraction

Ar 0.0087 0.0000 0.0000 0.0128 0.0000 0.0082 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.1447 0.0000 0.0000 0.0005 0.0004 0.1350 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0868 1.0000 1.0000 0.0062 0.9995 0.1517 1.0000 1.0000 1.0000 1.0000 1.0000

N2 0.7325 0.0000 0.0000 0.7506 0.0000 0.6808 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0250 0.0000 0.0000 0.2300 0.0000 0.0243 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0021 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 72,904 2,530 10,275 775 188 79,300 93,366 85,851 85,851 76,805 77,739

V-L Flowrate (kg/hr) 2,168,255 45,571 185,106 22,509 3,383 2,287,903 1,682,017 1,546,628 1,546,628 1,383,663 1,400,483

Solids Flowrate (kg/hr) 0 19,690 0 0 30,645 0 0 0 0 0 0

Temperature (°C) 181 15 15 167 57 57 566 363 566 38 39

Pressure (MPa, abs) 0.11 0.10 0.10 0.31 0.10 0.10 16.65 4.28 3.90 0.01 1.69

Enthalpy (kJ/kg)A 320.79 --- -46.80 177.65 --- 297.69 3,472.33 3,120.82 3,594.06 2,016.19 165.31

Density (kg/m3

) 0.8 --- 1,003.1 2.5 --- 1.1 47.7 15.7 10.3 0.1 993.3

V-L Molecular Weight 29.741 --- 18.015 29.029 --- 28.851 18.015 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 160,726 5,577 22,652 1,709 414 174,826 205,837 189,269 189,269 169,326 171,384

V-L Flowrate (lb/hr) 4,780,183 100,467 408,090 49,625 7,459 5,043,963 3,708,212 3,409,730 3,409,730 3,050,454 3,087,536

Solids Flowrate (lb/hr) 0 43,410 0 0 67,561 0 0 0 0 0 0

Temperature (°F) 357 59 59 333 135 135 1,050 686 1,050 101 103

Pressure (psia) 15.3 15.0 14.7 45.0 14.8 14.8 2,415.0 620.5 565.5 1.0 245.0

Enthalpy (Btu/lb)A 137.9 --- -20.1 76.4 --- 128.0 1,492.8 1,341.7 1,545.2 866.8 71.1

Density (lb/ft3) 0.052 --- 62.622 0.154 --- 0.067 2.977 0.983 0.643 0.004 62.010
Cost and Performance Baseline for Fossil Energy Plants

327

4.2.2

System assumptions for Cases 9 and 10, subcritical PC with and without CO2 capture, are 

compiled in

Key System Assumptions

Exhibit 4-5.

Exhibit 4-5 Subcritical PC Plant Study Configuration Matrix

Case 9 

w/o CO2 Capture 

Case 10 

w/CO2 Capture

Steam Cycle, MPa/°C/°C (psig/°F/°F) 16.5/566/566 

(2400/1050/1050)

16.5/566/566 

(2400/1050/1050)

Coal Illinois No. 6 Illinois No. 6

Condenser pressure, mm Hg (in Hg) 50.8 (2) 50.8 (2)

Boiler Efficiency, % 88 88

Cooling water to condenser, °C (oF) 16 (60) 16 (60)

Cooling water from condenser, °C (oF) 27 (80) 27 (80)

Stack temperature, °C (°F) 57 (135) 32 (89)

SO2 Control Wet Limestone 

Forced Oxidation

Wet Limestone 

Forced Oxidation

FGD Efficiency, % (A) 98 98 (B, C)

NOx Control LNB w/OFA and 

SCR

LNB w/OFA and 

SCR

SCR Efficiency, % (A) 86 86

Ammonia Slip (end of catalyst life), 

ppmv

2 2

Particulate Control Fabric Filter Fabric Filter

Fabric Filter efficiency, % (A) 99.8 99.8

Ash Distribution, Fly/Bottom 80% / 20% 80% / 20%

Mercury Control Co-benefit Capture Co-benefit Capture

Mercury removal efficiency, % (A) 90 90

CO2 Control N/A Econamine

Overall CO2 Capture (A) N/A 90.2%

CO2 Sequestration N/A Off-site Saline 

Formation

A. Removal efficiencies are based on the FG content

B. An SO2 polishing step is included to meet more stringent SOx content limits in the FG (< 10 

ppmv) to reduce formation of amine HSS during the CO2 absorption process

C. SO2 exiting the post-FGD polishing step is absorbed in the CO2 capture process making stack 

emissions negligible

The balance of plant assumptions are common to all cases and are presented in 

Balance of Plant – Cases 9 and 10

Exhibit 4-6.
Cost and Performance Baseline for Fossil Energy Plants

328

Exhibit 4-6 Balance of Plant Assumptions

Cooling system Recirculating Wet Cooling Tower

Fuel and Other storage

Coal 30 days

Ash 30 days

Gypsum 30 days

Limestone 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 GT 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 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 is 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 will be treated for 

chloride and metals, and discharged.
Cost and Performance Baseline for Fossil Energy Plants

329

4.2.3

Single trains are used throughout the design 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:

Sparing Philosophy

• One dry-bottom, wall-fired PC subcritical boiler (1 x 100%)

• Two SCR reactors (2 x 50%)

• Two single-stage, in-line, multi-compartment fabric filters (2 x 50%)

• One wet limestone forced oxidation positive pressure absorber (1 x 100%)

• One steam turbine (1 x 100%)

• For Case 10 only, two parallel Econamine CO2 absorption systems, with each system 

consisting of two absorbers, strippers and ancillary equipment (2 x 50%)

4.2.4

The plant produces a net output of 550 MWe at a net plant efficiency of 36.8 percent (HHV 

basis). Overall performance for the plant is summarized in 

Case 9 Performance Results

Exhibit 4-7, which includes auxiliary 

power requirements.
Cost and Performance Baseline for Fossil Energy Plants

330

Exhibit 4-7 Case 9 Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Steam Turbine Power 582,600

TOTAL (STEAM TURBINE) POWER, kWe 582,600

AUXILIARY LOAD SUMMARY, kWe

Coal Handling and Conveying 450

Pulverizers 2,970

Sorbent Handling & Reagent Preparation 950

Ash Handling 570

Primary Air Fans 1,400

Forced Draft Fans 1,780

Induced Draft Fans 7,540

SCR 50

Baghouse 70

Wet FGD 3,180

Miscellaneous Balance of Plant2,3 2,000

Steam Turbine Auxiliaries 400

Condensate Pumps 890

Circulating Water Pump 5,250

Ground Water Pumps 530

Cooling Tower Fans 2,720

Transformer Losses 1,830

TOTAL AUXILIARIES, kWe 32,580

NET POWER, kWe 550,020

Net Plant Efficiency (HHV) 36.8%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,788 (9,277)

CONDENSER COOLING DUTY 106 kJ/hr (106 Btu/hr) 2,566 (2,432)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 198,391 (437,378)

Limestone Sorbent Feed, kg/hr (lb/hr) 19,691 (43,410)

Thermal Input, kWt1 1,495,379

Raw Water Withdrawal, m3/min (gpm) 22.3 (5,896)

Raw Water Consumption, m3/min (gpm) 17.7 (4,680)

1. HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)

2. Boiler feed pumps are turbine driven

3. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Fossil Energy Plants

331

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 

2.4. A summary of the plant air emissions for Case 9 is presented in 

Environmental Performance

Exhibit 4-8.

Exhibit 4-8 Case 9 Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

85% CF

kg/MWh

(lb/MWh)

SO2 0.037 (0.086) 1,479 (1,630) 0.341 (.75)

NOx 0.030 (0.070) 1,206 (1,330) 0.278 (.613)

Particulates 0.006 (0.0130) 224 (247) 0.052 (.114)

Hg 4.91E-7 

(1.14E-6)

0.020 (0.022) 4.54E-6 (1.00E-5)

CO2 87.5 (203.5) 3,507,605 

(3,866,472) 809 (1,783)

CO2

1 856 (1,888)

1 CO2 emissions based on net power instead of gross power

SO2 emissions are controlled using a wet limestone forced oxidation scrubber that achieves a 

removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site. 

The wallboard grade material can potentially be marketed and sold, but since it is highly 

dependent on local market conditions, no byproduct credit was taken. The saturated FG exiting 

the scrubber is vented through the plant stack.

NOx emissions are controlled to about 0.5 lb/106 Btu through the use of LNBs and OFA. An 

SCR unit then further reduces the NOx concentration by 86 percent to 0.07 lb/106 Btu.

Particulate emissions are controlled using a pulse jet fabric filter, which operates at an efficiency 

of 99.8 percent.

Co-benefit capture results in a 90 percent reduction of mercury emissions.

CO2 emissions represent the uncontrolled discharge from the process.

The carbon balance for the plant is shown in Exhibit 4-9. The carbon input to the plant consists 

of carbon in the coal, carbon in the air, and carbon in the limestone reagent used in the FGD. 

Carbon in the air is not neglected here since the Aspen model accounts for air components 

throughout. Carbon leaves the plant mostly as CO2 through the stack but also leaves as gypsum.
Cost and Performance Baseline for Fossil Energy Plants

332

Exhibit 4-9 Case 9 Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 126,464 (278,805) Stack Gas 128,563 (283,434)

Air (CO2) 275 (607) FGD Product 174 (383)

FGD Reagent 1,998 (4,405)

Total 128,737 (283,817) Total 128,737 (283,817)

Exhibit 4-10 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered from the FGD as gypsum and sulfur emitted 

in the stack gas.

Exhibit 4-10 Case 9 Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 4,973 (10,963) Stack Gas 99 (219)

FGD Product 4,873 (10,743)

Total 4,973 (10,963) Total 4,973 (10,963)

Exhibit 4-11 shows the water balance for Case 9. Water demand represents the total amount of 

water required for a particular process. Some water is recovered within the process and is reused as internal recycle. The difference between demand and recycle is raw water withdrawal. 

Raw water withdrawal is defined as the water removed from the ground or diverted from a 

surface-water source for use in the plant and was assumed to be provided 50 percent by a POTW 

and 50 percent from groundwater. Raw water withdrawal can be represented by the water 

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

as FDG makeup, BFW makeup, and cooling tower makeup. The difference between water 

withdrawal and process water discharge is defined as water consumption and can be represented 

by the portion of the raw water withdrawn that is evaporated, transpired, incorporated into 

products or otherwise not returned to the water source from which it was withdrawn. Water 

consumption represents the net impact of the plant process on the water source.
Cost and Performance Baseline for Fossil Energy Plants

333

Exhibit 4-11 Case 9 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)

FGD Makeup 3.9 (1,017) 0.0 (0) 3.9 (1,017) 0.0 (0) 3.9 (1,017)

BFW Makeup 0.3 (74) 0.0 (0) 0.3 (74) 0.0 (0) 0.3 (74)

Cooling Tower 20.5 (5,404) 2.3 (600) 18.2 (4,804) 4.6 (1,215) 13.6 (3,589)

Total 24.6 (6,495) 2.3 (600) 22.3 (5,896) 4.6 (1,215) 17.7 (4,680)

A heat and mass balance diagram is shown for the Case 9 PC boiler, the FGD unit, and steam 

cycle as shown in 

Heat and Mass Balance Diagrams

Exhibit 4-12 and Exhibit 4-13.

An overall plant energy balance is provided in tabular form in Exhibit 4-14. The power out is 

the steam turbine power prior to generator losses. The power at the generator terminals (shown 

in Exhibit 4-7) is calculated by multiplying the power out by a generator efficiency of 98.6 

percent.
Cost and Performance Baseline for Fossil Energy Plants

334

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

335

Exhibit 4-12 Case 9 Heat and Mass Balance, Subcritical PC Boiler without CO2 Capture

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Ash

Slurry

Synthesis Gas

Sour Gas

Sour Water

Water

Steam

PAGES

1 OF 2

BITUMINOUS BASELINE STUDY

CASE 9

SUBCRITICAL PULVERIZED COAL

BOILER AND GAS CLEANUP SYSTEMS

DWG. NO.

BB-HMB-CS-9-PG-1

Pulverized

Coal

Boiler

AMMONIA SCR

INFILTRATION

AIR

AIR

AIR

COAL

ASH

From Feedwater

Heaters

Single Reheat

To IP Turbine

Throttle Steam

To HP Turbine

FGD

ASH

FORCED

DRAFT FANS

PRIMARY

AIR FANS

STACK

437,378 W

77.8 T

16.1 P

17.5 H

66.4 T

15.3 P

14.8 H

3,708,212 W

1,050.0 T

2,415.0 P

1,492.8 H

3,409,730 W

1,050.0 T

565.5 P

1,545.2 H

Single Reheat

Extraction from

HP Turbine

1,012,663 W

59.0 T

14.7 P

13.0 H

3,296,540 W

59.0 T

14.7 P

13.0 H

76,015 W

59.0 T

14.7 P

13.0 H

4,814,113 W

337.0 T

14.4 P

140.6 H

8,482 W

33,929 W

3,409,730 W

686.0 T

620.5 P

1,341.7 H

3,708,212 W

484.4 T

3,100.5 P

469.5 H

5

5,043,963 W

135.0 T

14.8 P

128.0 H

1 2

4

7

9

4,780,183 W ID FANS

337.0 T

14.2 P

132.7 H

Gross Plant Power: 583 MWe

Auxiliary Load: 33 MWe

Net Plant Power: 550 MWe

Net Plant Efficiency, HHV: 36.8%

Net Plant Heat Rate: 9,277 BTU/KWe

Lime/Ash

Flue Gas

OXIDATION 

AIR

MAKE-UP 

WATER

LIMESTONE 

SLURRY

GYPSUM

15

14

11

357.4 T

15.3 P

137.9 H

143,877 W

59.0 T

15.0 P

49,625 W

332.9 T

45.0 P

408,090 W

59.0 T

14.7 P

75,020 W

135.0 T

14.8 P

Baghouse

3

6

8

10

12 13

16

17

19 18

20

21

DOE/NETL

SC PC PLANT

CASE 9
Cost and Performance Baseline for Fossil Energy Plants

336

Exhibit 4-13 Case 9 Heat and Mass Balance, Subcritical Steam Cycle

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Sour Gas

Sour Water

Water

Steam

PAGES

2 OF 2

DWG. NO.

BB-HMB-CS-9-PG-2

BITUMINOUS BASELINE STUDY

CASE 9

SUBCRITICAL PULVERIZED COAL

POWER BLOCK SYSTEMS

LP TURBINE GENERATOR HP

TURBINE

IP

TURBINE

CONDENSER

HOT WELL

P-1028 To Boiler P-1048

BOILER FEED

PUMP TURBINE 

DRIVES

STEAM SEAL

REGULATOR

Throttle

Steam

Single Reheat

Extraction

From Boiler

GLAND SEAL

CONDENSER

CONDENSATE

PUMPS

3,708,212 W

1,050.0 T

2,415.0 P

1,492.8 H

226,208 W

915.9 T

323.0 P

1,480.7 H

254,026 W

682.6 T

589.7 P

1,341.7 H

3,409,730 W

686.0 T

620.5 P

1,341.7 H

620.5 P

620.5 P

620.5 P

350.5 P

167.7 P

167.7 P

154,414 W

734.9 T

164.3 P

1,393.4 H

154,414 W

126.1 T

2.0 P

1,097.1 H

2,388,619 W

101.1 T

1.0 P

1,017.1 H

2,793 W

212.0 T

14.7 P

179.9 H

64.2 P

41.6 P

11.8 P

101.4 T

250.0 P

70.0 H

2,793 W

712.8 T

167.7 P

1,381.9 H

3,087,536 W

101.1 T

1.0 P

69.1 H

3,087,536 W

102.5 T

245.0 P

71.1 H

3,087,536 W

152.8 T

240.0 P

121.2 H

501,326 W

112.5 T

1.4 P

80.4 H

370,446 W

162.8 T

5.1 P

130.6 H

3,087,536 W

284.7 T

220.0 P

253.9 H

480,234 W

364.6 T

323.0 P

337.0 H

3,087,536 W

257.7 T

230.0 P

226.5 H

254,026 W

436.2 T

366.7 P

414.3 H

3,708,212 W

426.2 T

3,105.5 P

406.0 H

DEAERATOR

BOILER

FEED PUMPS

3,708,212 W

484.4 T

3,100.5 P

469.5 H

3,409,730 W

1,050.0 T

565.5 P

1,545.2 H

80,030 W

267.7 T

40.3 P

236.3 H

267,224 W

200.5 T

11.7 P

168.3 H

3,087,536 W

190.5 T

235.0 P

158.8 H

177,524 W

728.1 T

130.0 P

1,391.5 H

80,030 W

524.8 T

57.3 P

1,294.9 H

187,193 W

439.2 T

37.1 P

1,255.2 H

103,223 W

228.6 T

10.5 P

1,159.5 H

130,880 W

157.8 T

4.5 P

1,120.2 H

2,415.0 P

3,037,555 W

734.9 T

164.3 P

1,393.4 H

2,883,141 W

734.9 T

164.3 P

1,393.4 H

5.0 P

Steam Turbine

Makeup

354.6 T

3,110.5 P

330.9 H

3,708,212 W

347.3 T

130.0 P

318.5 H

3,301 W

712.8 T

167.7 P

1,381.9 H

Gross Plant Power: 583 MWe

Auxiliary Load: 33 MWe

Net Plant Power: 550 MWe

Net Plant Efficiency, HHV: 36.8%

Net Plant Heat Rate: 9,277 BTU/KWe

FWH 4 FWH 3 FWH 2 FWH 1 FWH 7 FWH 6

6,805 W

712.8 T

167.7 P

1,381.9 H

19

23

DOE/NETL

SC PC PLANT

CASE 9

2,415.0 P

21

1,850.0 P

Single Reheat

Extraction to

Boiler

20

3,442,057 W

1,048.6 T

565.5 P

1,544.4 H

37,082 W

59.0 T

14.7 P

27.1 H
Cost and Performance Baseline for Fossil Energy Plants

337

Exhibit 4-14 Case 9 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,383 (5,102) 4.5 (4.3) 5,388 (5,107)

Air 60.1 (57.0) 60.1 (57.0)

Raw Water Withdrawal 84.0 (79.6) 84.0 (79.6)

Limestone 0.22 (0.21) 0.22 (0.21)

Auxiliary Power 117 (111) 117 (111)

Totals 5,383 (5,102) 148.8 (141.1) 117 (111) 5,649 (5,355)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.5 (0.4) 0.5 (0.4)

Fly Ash + FGD Ash 1.9 (1.8) 1.9 (1.8)

Flue Gas 681 (646) 681 (646)

Condenser 2,566 (2,432) 2,566 (2,432)

Cooling Tower Blowdown 34.2 (32.4) 34.2 (32.4)

Process Losses* 269 (255) 269 (255)

Power 2,097 (1,988) 2,097 (1,988)

Totals 0 (0) 3,552 (3,367) 2,097 (1,988) 5,649 (5,355)

* Process losses are estimated to match the heat input to the plant. Process losses include 

losses from: turbines, gas cooling, etc.
Cost and Performance Baseline for Fossil Energy Plants

338

4.2.5

Major equipment items for the subcritical PC plant 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 

Case 9 – Major Equipment List

4.2.6. In general, the design conditions include a 10 percent 

contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 COAL AND SORBENT 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 45 tonne (50 ton) 2 1

9 Feeder Vibratory 163 tonne/hr (180 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 327 tonne/hr (360 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 163 tonne (180 ton) 2 0

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3 in x 0 - 1-1/4 in x 0) 2 0

14 As-Fired Coal Sampling 

System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 327 tonne/hr (360 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 327 tonne/hr (360 tph) 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 726 tonne (800 ton) 3 0

19 Limestone Truck Unloading 

Hopper

N/A 36 tonne (40 ton) 1 0

20 Limestone Feeder Belt 82 tonne/hr (90 tph) 1 0

21 Limestone Conveyor No. L1 Belt 82 tonne/hr (90 tph) 1 0

22 Limestone Reclaim Hopper N/A 18 tonne (20 ton) 1 0

23 Limestone Reclaim Feeder Belt 64 tonne/hr (70 tph) 1 0

24 Limestone Conveyor No. L2 Belt 64 tonne/hr (70 tph) 1 0

25 Limestone Day Bin w/ actuator 263 tonne (290 ton) 2 0
Cost and Performance Baseline for Fossil Energy Plants

339

ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Coal Feeder Gravimetric 36 tonne/hr (40 tph) 6 0

2 Coal Pulverizer Ball type or 

equivalent 36 tonne/hr (40 tph) 6 0

3 Limestone Weigh Feeder Gravimetric 22 tonne/hr (24 tph) 1 1

4 Limestone Ball Mill Rotary 22 tonne/hr (24 tph) 1 1

5 Limestone Mill Slurry Tank 

with Agitator N/A 83,279 liters (22,000 gal) 1 1

6 Limestone Mill Recycle 

Pumps

Horizontal 

centrifugal

1,401 lpm @ 12m H2O (370 gpm 

@ 40 ft H2O) 1 1

7 Hydroclone Classifier

4 active 

cyclones in a 5 

cyclone bank

341 lpm (90 gpm) per cyclone 1 1

8 Distribution Box 2-way N/A 1 1

9 Limestone Slurry Storage 

Tank with Agitator Field erected 469,391 liters (124,000 gal) 1 1

10 Limestone Slurry Feed 

Pumps

Horizontal 

centrifugal

984 lpm @ 9m H2O (260 gpm @ 

30 ft H2O) 1 1
Cost and Performance Baseline for Fossil Energy Plants

340

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 1,112,911 liters (294,000 gal) 2 0

2 Condensate Pumps Vertical canned 25,741 lpm @ 213 m H2O (6,800 

gpm @ 700 ft H2O) 1 1

3 Deaerator and Storage 

Tank Horizontal spray type 1,850,203 kg/hr (4,079,000 lb/hr), 5 min. tank 1 0

4 Boiler Feed 

Pump/Turbine

Barrel type, multi-stage, 

centrifugal

31,040 lpm @ 2,530 m H2O 

(8,200 gpm @ 8,300 ft H2O) 1 1

5

Startup Boiler Feed 

Pump, Electric Motor 

Driven

Barrel type, multi-stage, 

centrifugal

9,085 lpm @ 2,530 m H2O (2,400 

gpm @ 8,300 ft H2O) 1 0

6 LP Feedwater Heater 

1A/1B Horizontal U-tube 771,107 kg/hr (1,700,000 lb/hr) 2 0

7

LP Feedwater Heater 

2A/2B Horizontal U-tube 771,107 kg/hr (1,700,000 lb/hr) 2 0

8 LP Feedwater Heater 

3A/3B Horizontal U-tube 771,107 kg/hr (1,700,000 lb/hr) 2 0

9 LP Feedwater Heater 

4A/4B Horizontal U-tube 771,107 kg/hr (1,700,000 lb/hr) 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 1,850,657 kg/hr (4,080,000 lb/hr) 1 0

11 HP Feedwater Heater 7 Horizontal U-tube 1,850,657 kg/hr (4,080,000 lb/hr) 1 0

12 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

13 Fuel Oil System No. 2 fuel oil for light 

off 1,135,624 liter (300,000 gal) 1 0

14 Service Air 

Compressors Flooded Screw 28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

15 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

16 Closed Cycle Cooling 

Heat Exchangers Shell and tube 53 GJ/hr (50 MMBtu/hr) each 2 0

17 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 20,820 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 2 1

18 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 88 m H2O (1,000 

gpm @ 290 ft H2O) 1 1

19 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 64 m H2O (700 gpm 

@ 210 ft H2O) 1 1

20 Raw Water Pumps Stainless steel, single 

suction

6,549 lpm @ 18 m H2O (1,730 

gpm @ 60 ft H2O) 2 1

21 Ground Water Pumps Stainless steel, single 

suction

2,612 lpm @ 268 m H2O (690 

gpm @ 880 ft H2O) 5 1

22 Filtered Water Pumps Stainless steel, single 

suction

2,006 lpm @ 49 m H2O (530 gpm 

@ 160 ft H2O) 2 1

23 Filtered Water Tank Vertical, cylindrical 1,919,204 liter (507,000 gal) 1 0

24 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly, 

electrodeionization unit

606 lpm (160 gpm) 1 1

25 Liquid Waste Treatment 

System -- 10 years, 24-hour storm 1 0
Cost and Performance Baseline for Fossil Energy Plants

341

ACCOUNT 4 BOILER AND ACCESSORIES

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Boiler

Subcritical, drum 

wall-fired, low NOx 

burners, overfire air

1,850,657 kg/hr steam @ 17.9 

MPa/574°C/574°C (4,080,000 

lb/hr steam @ 2,600 

psig/1,065°F/1,065°F)

1 0

2 Primary Air Fan Centrifugal

252,651 kg/hr, 3,446 m3/min @ 

123 cm WG (557,000 lb/hr, 

121,700 acfm @ 48 in. WG)

2 0

3 Forced Draft Fan Centrifugal

822,363 kg/hr, 11,222 m3/min @ 

47 cm WG (1,813,000 lb/hr, 

396,300 acfm @ 19 in. WG)

2 0

4 Induced Draft Fan Centrifugal

1,192,494 kg/hr, 25,114 m3/min 

@ 91 cm WG (2,629,000 lb/hr, 

886,900 acfm @ 36 in. WG)

2 0

5 SCR Reactor Vessel Space for spare 

layer 2,385,896 kg/hr (5,260,000 lb/hr) 2 0

6 SCR Catalyst -- -- 3 0

7 Dilution Air Blower Centrifugal 142 m3/min @ 108 cm WG 

(5,000 acfm @ 42 in. WG) 2 1

8 Ammonia Storage Horizontal tank 155,202 liter (41,000 gal) 5 0

9 Ammonia Feed 

Pump Centrifugal 30 lpm @ 91 m H2O (8 gpm @ 

300 ft H2O) 2 1
Cost and Performance Baseline for Fossil Energy Plants

342

ACCOUNT 5 FLUE GAS CLEANUP

ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES 

N/A

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Fabric Filter

Single stage, highratio with pulse-jet 

online cleaning 

system

1,192,494 kg/hr (2,629,000 lb/hr) 

99.8% efficiency 2 0

2 Absorber Module Counter-current 

open spray

47,912 m3/min (1,692,000 acfm) 1 0

3 Recirculation Pumps Horizontal 

centrifugal

166,558 lpm @ 64 m H2O 

(44,000 gpm @ 210 ft H2O) 5 1

4 Bleed Pumps Horizontal 

centrifugal

4,240 lpm (1,120 gpm) at 20 wt% 

solids 2 1

5 Oxidation Air Blowers Centrifugal 84 m3/min @ 0.3 MPa (2,960 

acfm @ 37 psia) 2 1

6 Agitators Side entering 50 hp 5 1

7 Dewatering Cyclones Radial assembly, 

5 units each 1,060 lpm (280 gpm) per cyclone 2 0

8 Vacuum Filter Belt Horizontal belt 34 tonne/hr (37 tph) of 50 wt % 

slurry 2 1

9 Filtrate Water Return 

Pumps

Horizontal 

centrifugal

644 lpm @ 12 m H2O (170 gpm 

@ 40 ft H2O) 1 1

10 Filtrate Water Return 

Storage Tank Vertical, lined 416,395 lpm (110,000 gal) 1 0

11 Process Makeup Water 

Pumps

Horizontal 

centrifugal

3,407 lpm @ 21 m H2O (900 gpm 

@ 70 ft H2O) 1 1
Cost and Performance Baseline for Fossil Energy Plants

343

ACCOUNT 7 HRSG, DUCTING & STACK

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack Reinforced concrete 

with FRP liner

152 m (500 ft) high x

5.8 m (19 ft) diameter 1 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

613 MW

16.5 MPa/566°C/566°C 

(2400.3 psig/ 

1050°F/1050°F)

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitation

680 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase 1 0

3 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

2,828 GJ/hr (2,680 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 

11°C (20°F)

1 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water 

Pumps Vertical, wet pit 526,200 lpm @ 30 m(139,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

/ 2944 GJ/hr (2790 MMBtu/hr) 

heat duty

1 0
Cost and Performance Baseline for Fossil Energy Plants

344

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Economizer Hopper (part of 

boiler scope of supply) -- -- 4 0

2 Bottom Ash Hopper (part of 

boiler scope of supply) -- -- 2 0

3 Clinker Grinder -- 4.5 tonne/hr (5 tph) 1 1

4

Pyrites Hopper (part of 

pulverizer scope of supply 

included with boiler)

-- -- 6 0

5 Hydroejectors -- -- 12

6 Economizer /Pyrites Transfer 

Tank -- -- 1 0

7 Ash Sluice Pumps Vertical, wet pit 151 lpm @ 17 m H2O (40 gpm 

@ 56 ft H2O) 1 1

8 Ash Seal Water Pumps Vertical, wet pit 7,571 lpm @ 9 m H2O (2000 

gpm @ 28 ft H2O) 1 1

9 Hydrobins -- 151 lpm (40 gpm) 1 1

10 Baghouse Hopper (part of 

baghouse scope of supply) -- -- 24 0

11 Air Heater Hopper (part of 

boiler scope of supply) -- -- 10 0

12 Air Blower -- 16 m3/min @ 0.2 MPa (550 

scfm @ 24 psi) 1 1

13 Fly Ash Silo Reinforced 

concrete 998 tonne (1,100 ton) 2 0

14 Slide Gate Valves -- -- 2 0

15 Unloader -- -- 1 0

16 Telescoping Unloading Chute -- 91 tonne/hr (100 tph) 1 0
Cost and Performance Baseline for Fossil Energy Plants

345

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 STG Transformer Oil-filled 24 kV/345 kV, 650 MVA, 3-

ph, 60 Hz 1 0

2 Auxiliary 

Transformer Oil-filled 24 kV/4.16 kV, 34 MVA, 3-ph, 60 Hz 1 1

3 Low Voltage 

Transformer Dry ventilated 4.16 kV/480 V, 5 MVA, 3-ph, 60 Hz

1 1

4

STG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0

5 Medium Voltage 

Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

6 Low Voltage 

Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

7 Emergency Diesel 

Generator

Sized for emergency 

shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0

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 for Fossil Energy Plants

346

4.2.6

The cost estimating methodology was described previously in Section 2.6. 

Case 9 – Cost Estimating

Exhibit 4-15 shows 

the total plant capital cost summary organized by cost account and Exhibit 4-16 shows a more 

detailed breakdown of the capital costs along with owner’s costs, TOC and TASC. Exhibit 4-17

shows the initial and annual O&M costs.

The estimated TOC of the subcritical PC boiler with no CO2 capture is $1,996/kW. No process 

contingency is included in this case because all elements of the technology are commercially 

proven. The project contingency is 9.1 percent of the TOC. The COE is 59.4 mills/kWh.
Cost and Performance Baseline for Fossil Energy Plants

347

Exhibit 4-15 Case 9 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14

Project: Bituminous Baseline Study

Case: Case 9 - 1x550 MWnet SubCritical PC

Plant Size: 550 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 $17,068 $4,598 $10,229 $0 $0 $31,895 $2,862 $0 $5,214 $39,970 $73

 2 COAL & SORBENT PREP & FEED $11,494 $665 $2,916 $0 $0 $15,075 $1,321 $0 $2,459 $18,855 $34

 3 FEEDWATER & MISC. BOP SYSTEMS $39,707 $0 $19,059 $0 $0 $58,766 $5,391 $0 $10,518 $74,674 $136

 4 PC BOILER

4.1 PC Boiler & Accessories $134,824 $0 $86,704 $0 $0 $221,527 $21,582 $0 $24,311 $267,420 $486

4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4 $134,824 $0 $86,704 $0 $0 $221,527 $21,582 $0 $24,311 $267,420 $486

 5 FLUE GAS CLEANUP $83,799 $0 $28,488 $0 $0 $112,287 $10,747 $0 $12,303 $135,338 $246

 5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

7.2-7.9 HRSG Accessories, Ductwork and Stack $18,242 $1,049 $12,388 $0 $0 $31,679 $2,908 $0 $4,516 $39,104 $71

SUBTOTAL 7 $18,242 $1,049 $12,388 $0 $0 $31,679 $2,908 $0 $4,516 $39,104 $71

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $49,912 $0 $6,242 $0 $0 $56,154 $5,380 $0 $6,153 $67,688 $123

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $23,604 $1,092 $12,657 $0 $0 $37,354 $3,294 $0 $5,668 $46,316 $84

SUBTOTAL 8 $73,516 $1,092 $18,900 $0 $0 $93,508 $8,674 $0 $11,822 $114,004 $207

 9 COOLING WATER SYSTEM $13,230 $6,710 $12,250 $0 $0 $32,189 $3,030 $0 $4,784 $40,003 $73

10 ASH/SPENT SORBENT HANDLING SYS $4,573 $145 $6,114 $0 $0 $10,833 $1,042 $0 $1,222 $13,096 $24

11 ACCESSORY ELECTRIC PLANT $17,808 $6,355 $18,529 $0 $0 $42,692 $3,765 $0 $5,747 $52,203 $95

12 INSTRUMENTATION & CONTROL $8,665 $0 $8,786 $0 $0 $17,451 $1,582 $0 $2,338 $21,371 $39

13 IMPROVEMENTS TO SITE $2,974 $1,710 $5,995 $0 $0 $10,679 $1,054 $0 $2,347 $14,079 $26

14 BUILDINGS & STRUCTURES $0 $23,479 $22,248 $0 $0 $45,727 $4,125 $0 $12,463 $62,315 $113

 

TOTAL COST $425,899 $45,804 $252,606 $0 $0 $724,309 $68,082 $0 $100,043 $892,433 $1,622

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline for Fossil Energy Plants

348

Exhibit 4-16 Case 9 Total Plant Cost Details

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 $3,508 $0 $1,602 $0 $0 $5,110 $457 $0 $835 $6,402 $12

1.2 Coal Stackout & Reclaim $4,533 $0 $1,027 $0 $0 $5,561 $487 $0 $907 $6,954 $13

1.3 Coal Conveyors $4,215 $0 $1,016 $0 $0 $5,231 $458 $0 $853 $6,543 $12

1.4 Other Coal Handling $1,103 $0 $235 $0 $0 $1,338 $117 $0 $218 $1,673 $3

1.5 Sorbent Receive & Unload $140 $0 $42 $0 $0 $183 $16 $0 $30 $229 $0

1.6 Sorbent Stackout & Reclaim $2,269 $0 $416 $0 $0 $2,685 $234 $0 $438 $3,357 $6

1.7 Sorbent Conveyors $810 $175 $199 $0 $0 $1,183 $102 $0 $193 $1,479 $3

1.8 Other Sorbent Handling $489 $115 $257 $0 $0 $860 $76 $0 $140 $1,077 $2

1.9 Coal & Sorbent Hnd.Foundations $0 $4,308 $5,435 $0 $0 $9,743 $915 $0 $1,599 $12,257 $22

SUBTOTAL 1. $17,068 $4,598 $10,229 $0 $0 $31,895 $2,862 $0 $5,214 $39,970 $73

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $2,014 $0 $393 $0 $0 $2,407 $210 $0 $393 $3,009 $5

2.2 Coal Conveyor to Storage $5,158 $0 $1,126 $0 $0 $6,284 $549 $0 $1,025 $7,858 $14

2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.5 Sorbent Prep Equipment $3,857 $166 $801 $0 $0 $4,824 $420 $0 $787 $6,031 $11

2.6 Sorbent Storage & Feed $465 $0 $178 $0 $0 $643 $57 $0 $105 $805 $1

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 $499 $419 $0 $0 $917 $85 $0 $150 $1,153 $2

SUBTOTAL 2. $11,494 $665 $2,916 $0 $0 $15,075 $1,321 $0 $2,459 $18,855 $34

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $16,257 $0 $5,611 $0 $0 $21,868 $1,915 $0 $3,567 $27,351 $50

3.2 Water Makeup & Pretreating $4,751 $0 $1,529 $0 $0 $6,280 $594 $0 $1,375 $8,248 $15

3.3 Other Feedwater Subsystems $5,318 $0 $2,248 $0 $0 $7,566 $678 $0 $1,237 $9,480 $17

3.4 Service Water Systems $931 $0 $507 $0 $0 $1,438 $135 $0 $315 $1,888 $3

3.5 Other Boiler Plant Systems $6,259 $0 $6,179 $0 $0 $12,438 $1,181 $0 $2,043 $15,662 $28

3.6 FO Supply Sys & Nat Gas $256 $0 $320 $0 $0 $575 $54 $0 $94 $724 $1

3.7 Waste Treatment Equipment $3,221 $0 $1,836 $0 $0 $5,057 $492 $0 $1,110 $6,659 $12

3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,715 $0 $829 $0 $0 $3,544 $341 $0 $777 $4,662 $8

SUBTOTAL 3. $39,707 $0 $19,059 $0 $0 $58,766 $5,391 $0 $10,518 $74,674 $136

 4 PC BOILER & ACCESSORIES

4.1 PC Boiler & Accessories $134,824 $0 $86,704 $0 $0 $221,527 $21,582 $0 $24,311 $267,420 $486

4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4. $134,824 $0 $86,704 $0 $0 $221,527 $21,582 $0 $24,311 $267,420 $486
Cost and Performance Baseline for Fossil Energy Plants

349

Exhibit 4-16 Case 9 Total Plant Cost Details (Continued)

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

 5 FLUE GAS CLEANUP

5.1 Absorber Vessels & Accessories $58,362 $0 $12,564 $0 $0 $70,926 $6,762 $0 $7,769 $85,456 $155

5.2 Other FGD $3,046 $0 $3,451 $0 $0 $6,497 $631 $0 $713 $7,840 $14

5.3 Bag House & Accessories $16,493 $0 $10,467 $0 $0 $26,959 $2,598 $0 $2,956 $32,513 $59

5.4 Other Particulate Removal Materials $1,116 $0 $1,194 $0 $0 $2,310 $224 $0 $253 $2,788 $5

5.5 Gypsum Dewatering System $4,783 $0 $812 $0 $0 $5,595 $533 $0 $613 $6,741 $12

5.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5. $83,799 $0 $28,488 $0 $0 $112,287 $10,747 $0 $12,303 $135,338 $246

 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 N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $9,097 $0 $5,845 $0 $0 $14,942 $1,303 $0 $2,437 $18,682 $34

7.4 Stack $9,145 $0 $5,351 $0 $0 $14,496 $1,396 $0 $1,589 $17,481 $32

7.9 Duct & Stack Foundations $0 $1,049 $1,192 $0 $0 $2,241 $210 $0 $490 $2,941 $5

SUBTOTAL 7. $18,242 $1,049 $12,388 $0 $0 $31,679 $2,908 $0 $4,516 $39,104 $71

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $49,912 $0 $6,242 $0 $0 $56,154 $5,380 $0 $6,153 $67,688 $123

8.2 Turbine Plant Auxiliaries $348 $0 $746 $0 $0 $1,094 $107 $0 $120 $1,321 $2

8.3 Condenser & Auxiliaries $7,251 $0 $2,295 $0 $0 $9,545 $913 $0 $1,046 $11,504 $21

8.4 Steam Piping $16,005 $0 $7,891 $0 $0 $23,896 $2,008 $0 $3,886 $29,790 $54

8.9 TG Foundations $0 $1,092 $1,726 $0 $0 $2,818 $267 $0 $617 $3,701 $7

SUBTOTAL 8. $73,516 $1,092 $18,900 $0 $0 $93,508 $8,674 $0 $11,822 $114,004 $207
Cost and Performance Baseline for Fossil Energy Plants

350

Exhibit 4-16 Case 9 Total Plant Cost Details (Continued)

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

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $9,783 $0 $3,046 $0 $0 $12,829 $1,227 $0 $1,406 $15,461 $28

9.2 Circulating Water Pumps $2,033 $0 $128 $0 $0 $2,161 $182 $0 $234 $2,578 $5

9.3 Circ.Water System Auxiliaries $531 $0 $71 $0 $0 $602 $57 $0 $66 $725 $1

9.4 Circ.Water Piping $0 $4,210 $4,080 $0 $0 $8,290 $776 $0 $1,360 $10,427 $19

9.5 Make-up Water System $462 $0 $618 $0 $0 $1,080 $103 $0 $177 $1,361 $2

9.6 Component Cooling Water Sys $421 $0 $335 $0 $0 $755 $72 $0 $124 $951 $2

9.9 Circ.Water System Foundations & Structures $0 $2,500 $3,972 $0 $0 $6,471 $612 $0 $1,417 $8,500 $15

SUBTOTAL 9. $13,230 $6,710 $12,250 $0 $0 $32,189 $3,030 $0 $4,784 $40,003 $73

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $612 $0 $1,885 $0 $0 $2,497 $245 $0 $274 $3,017 $5

10.7 Ash Transport & Feed Equipment $3,961 $0 $4,058 $0 $0 $8,019 $767 $0 $879 $9,664 $18

10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.9 Ash/Spent Sorbent Foundation $0 $145 $171 $0 $0 $317 $30 $0 $69 $416 $1

SUBTOTAL 10. $4,573 $145 $6,114 $0 $0 $10,833 $1,042 $0 $1,222 $13,096 $24

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $1,602 $0 $260 $0 $0 $1,862 $173 $0 $153 $2,187 $4

11.2 Station Service Equipment $2,904 $0 $954 $0 $0 $3,858 $361 $0 $316 $4,535 $8

11.3 Switchgear & Motor Control $3,339 $0 $567 $0 $0 $3,906 $362 $0 $427 $4,695 $9

11.4 Conduit & Cable Tray $0 $2,093 $7,238 $0 $0 $9,331 $903 $0 $1,535 $11,769 $21

11.5 Wire & Cable $0 $3,950 $7,625 $0 $0 $11,575 $975 $0 $1,882 $14,432 $26

11.6 Protective Equipment $270 $0 $918 $0 $0 $1,188 $116 $0 $130 $1,434 $3

11.7 Standby Equipment $1,279 $0 $29 $0 $0 $1,308 $120 $0 $143 $1,571 $3

11.8 Main Power Transformers $8,414 $0 $172 $0 $0 $8,587 $652 $0 $924 $10,162 $18

11.9 Electrical Foundations $0 $312 $765 $0 $0 $1,077 $103 $0 $236 $1,416 $3

SUBTOTAL 11. $17,808 $6,355 $18,529 $0 $0 $42,692 $3,765 $0 $5,747 $52,203 $95

12 INSTRUMENTATION & CONTROL

12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $446 $0 $267 $0 $0 $713 $67 $0 $117 $898 $2

12.7 Distributed Control System Equipment $4,504 $0 $787 $0 $0 $5,291 $491 $0 $578 $6,360 $12

12.8 Instrument Wiring & Tubing $2,442 $0 $4,844 $0 $0 $7,285 $621 $0 $1,186 $9,092 $17

12.9 Other I & C Equipment $1,273 $0 $2,888 $0 $0 $4,161 $403 $0 $456 $5,021 $9

SUBTOTAL 12. $8,665 $0 $8,786 $0 $0 $17,451 $1,582 $0 $2,338 $21,371 $39
Cost and Performance Baseline for Fossil Energy Plants

351

Exhibit 4-16 Case 9 Total Plant Cost Details (Continued)

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

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $50 $1,000 $0 $0 $1,050 $104 $0 $231 $1,385 $3

13.2 Site Improvements $0 $1,660 $2,061 $0 $0 $3,721 $367 $0 $818 $4,906 $9

13.3 Site Facilities $2,974 $0 $2,933 $0 $0 $5,908 $582 $0 $1,298 $7,788 $14

SUBTOTAL 13. $2,974 $1,710 $5,995 $0 $0 $10,679 $1,054 $0 $2,347 $14,079 $26

14 BUILDINGS & STRUCTURES

14.1 Boiler Building $0 $8,519 $7,491 $0 $0 $16,010 $1,439 $0 $4,362 $21,811 $40

14.2 Turbine Building $0 $12,310 $11,473 $0 $0 $23,784 $2,144 $0 $6,482 $32,409 $59

14.3 Administration Building $0 $587 $621 $0 $0 $1,208 $110 $0 $329 $1,647 $3

14.4 Circulation Water Pumphouse $0 $168 $134 $0 $0 $302 $27 $0 $82 $411 $1

14.5 Water Treatment Buildings $0 $603 $549 $0 $0 $1,152 $104 $0 $314 $1,570 $3

14.6 Machine Shop $0 $393 $264 $0 $0 $657 $58 $0 $179 $893 $2

14.7 Warehouse $0 $266 $267 $0 $0 $533 $48 $0 $145 $727 $1

14.8 Other Buildings & Structures $0 $217 $185 $0 $0 $403 $36 $0 $110 $548 $1

14.9 Waste Treating Building & Str. $0 $416 $1,263 $0 $0 $1,680 $159 $0 $460 $2,299 $4

SUBTOTAL 14. $0 $23,479 $22,248 $0 $0 $45,727 $4,125 $0 $12,463 $62,315 $113

TOTAL COST $425,899 $45,804 $252,606 $0 $0 $724,309 $68,082 $0 $100,043 $892,433 $1,622

Owner's Costs

Preproduction Costs

6 Months All Labor $7,104 $13

1 Month Maintenance Materials $859 $2

1 Month Non-fuel Consumables $956 $2

1 Month Waste Disposal $251 $0

25% of 1 Months Fuel Cost at 100% CF $1,524 $3

2% of TPC $17,849 $32

Total $28,543 $52

Inventory Capital

60 day supply of fuel and consumables at 100% CF $13,824 $25

0.5% of TPC (spare parts) $4,462 $8

Total $18,287 $33

Initial Cost for Catalyst and Chemicals $0 $0

Land $900 $2

Other Owner's Costs $133,865 $243

Financing Costs $24,096 $44

Total Overnight Costs (TOC) $1,098,124 $1,996

TASC Multiplier (IOU, low-risk, 35 year) 1.134

Total As-Spent Cost (TASC) $1,245,272 $2,264
Cost and Performance Baseline for Fossil Energy Plants

352

Exhibit 4-17 Case 9 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 9 - 1x550 MWnet SubCritical PC Heat Rate-net (Btu/kWh): 9,276

MWe-net: 550

Capacity Factor (%): 85

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

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 2.0 2.0

 Operator 9.0 9.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 2.0 2.0

 TOTAL-O.J.'s 14.0 14.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $5,524,319 $10.043

Maintenance Labor Cost $5,842,145 $10.621

Administrative & Support Labor $2,841,616 $5.166

Property Taxes and Insurance $17,848,664 $32.449

TOTAL FIXED OPERATING COSTS $32,056,744 $58.280

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $8,763,218 $0.00214

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water (/1000 gallons) 0 4,245.12 1.08 $0 $1,424,619 $0.00035

Chemicals

MU & WT Chem.(lbs) 0 20,549 0.17 $0 $1,103,371 $0.00027

Limestone (ton) 0 521 21.63 $0 $3,496,290 $0.00085

Carbon (Mercury Removal) (lb) 0 0 1.05 $0 $0 $0.00000

MEA Solvent (ton) 0 0 2,249.89 $0 $0 $0.00000

NaOH (tons) 0 0 433.68 $0 $0 $0.00000

H2SO4 (tons) 0 0 138.78 $0 $0 $0.00000

Corrosion Inhibitor 0 0 0.00 $0 $0 $0.00000

Activated Carbon (lb) 0 0 1.05 $0 $0 $0.00000

Ammonia (19% NH3) ton 0 78 129.80 $0 $3,136,289 $0.00077

Subtotal Chemicals $0 $7,735,950 $0.00189

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000

SCR Catalyst (m3) w/equip. 0.33 5,775.94 $0 $592,641 $0.00014

Emission Penalties 0 0 0.00 $0 $0 $0.00000

Subtotal Other $0 $592,641 $0.00014

Waste Disposal

Fly Ash (ton) 0 407 16.23 $0 $2,049,540 $0.00050

Bottom Ash (ton) 0 102 16.23 $0 $512,385 $0.00013

 Subtotal-Waste Disposal $0 $2,561,926 $0.00063

By-products & Emissions 

Gypsum (tons) 0 811 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $0 $21,078,354 $0.00515

Fuel (ton) 0 5,248 38.18 $0 $62,175,757 $0.01518
Cost and Performance Baseline for Fossil Energy Plants

353

4.2.7

The plant configuration for Case 10, subcritical PC, is the same as Case 9 with the exception that 

the Econamine technology was added for CO2 capture. The nominal net output was maintained 

at 550 MW by increasing the boiler size and turbine/generator size to account for the greater 

auxiliary load imposed by the CDR facility. Unlike the IGCC cases where gross output was 

fixed by the available size of the CTs, the PC cases utilize boilers and steam turbines that can be 

procured at nearly any desired output making it possible to maintain a constant net output.

Case 10 – PC Subcritical Unit with CO2 Capture

The process description for Case 10 is essentially the same as Case 9 with one notable exception, 

the addition of CO2 capture. A BFD and stream tables for Case 10 are shown in Exhibit 4-18

and Exhibit 4-19, respectively. Since the CDR facility process description was provided in 

Section 4.1.7, it is not repeated here.

4.2.8

The Case 10 modeling assumptions were presented previously in Section 

Case 10 Performance Results

4.2.2.

The plant produces a net output of 550 MW at a net plant efficiency of 26.2 percent (HHV 

basis). Overall plant performance is summarized in Exhibit 4-20, which includes auxiliary 

power requirements. The CDR facility, including CO2 compression, accounts for over half of 

the auxiliary plant load. The CWS (CWPs and cooling tower fan) accounts for over 14 percent 

of the auxiliary load, largely due to the high cooling water demand of the CDR facility.
Cost and Performance Baseline for Fossil Energy Plants

354

Exhibit 4-18 Case 10 Block Flow Diagram, Subcritical Unit with CO2 Capture
Cost and Performance Baseline for Fossil Energy Plants

355

Exhibit 4-19 Case 10 Stream Table, Subcritical Unit with CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 0.0000

CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 1.0000

N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 0.0000

O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 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 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 72,691 72,691 2,163 22,330 22,330 3,063 1,680 0 0 102,289 0 102,289 102,289 3,643

V-L Flowrate (kg/hr) 2,097,642 2,097,642 62,415 644,374 644,374 88,396 48,482 0 0 3,042,405 0 3,042,405 3,042,405 65,636

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 278,956 5,410 21,640 21,640 0 0 28,403

Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169 182 15

Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 0.10

Enthalpy (kJ/kg)A 30.23 34.36 34.36 30.23 40.78 40.78 30.23 --- --- 327.39 --- 308.96 322.83 ---

Density (kg/m3

) 1.2 1.2 1.2 1.2 1.3 1.3 1.2 --- --- 0.8 --- 0.8 0.8 ---

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857 --- --- 29.743 --- 29.743 29.743 ---

V-L Flowrate (lbmol/hr) 160,256 160,256 4,768 49,229 49,229 6,753 3,704 0 0 225,509 0 225,509 225,509 8,032

V-L Flowrate (lb/hr) 4,624,510 4,624,510 137,601 1,420,601 1,420,601 194,880 106,884 0 0 6,707,354 0 6,707,354 6,707,354 144,703

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 614,994 11,927 47,708 47,708 0 0 62,618

Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337 360 59

Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.4 15.0

Enthalpy (Btu/lb)A 13.0 14.8 14.8 13.0 17.5 17.5 13.0 --- --- 140.8 --- 132.8 138.8 ---

Density (lb/ft3) 0.076 0.078 0.078 0.076 0.081 0.081 0.076 --- --- 0.050 --- 0.049 0.052 ---

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Fossil Energy Plants

356

Exhibit 4-19 Case 10 Stream Table, Subcritical Unit with CO2 Capture (Continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 28

V-L Mole Fraction

Ar 0.0000 0.0128 0.0000 0.0081 0.0108 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0000 0.0005 0.0004 0.1350 0.0179 0.9961 0.9985 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 1.0000 0.0062 0.9996 0.1537 0.0383 0.0039 0.0015 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

N2 0.0000 0.7506 0.0000 0.6793 0.9013 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.2300 0.0000 0.0238 0.0316 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 14,732 1,049 269 111,453 83,996 13,598 13,566 48,632 48,632 131,223 121,115 121,115 60,504 61,816

V-L Flowrate (kg/hr) 265,393 30,461 4,845 3,213,261 2,366,318 597,086 596,497 876,112 876,112 2,364,021 2,181,912 2,181,912 1,089,994 1,113,634

Solids Flowrate (kg/hr) 0 0 43,806 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 15 181 58 58 32 21 35 296 151 566 363 566 38 39

Pressure (MPa, abs) 0.10 0.31 0.10 0.10 0.10 0.16 15.27 0.51 0.90 16.65 4.28 3.90 0.01 1.69

Enthalpy (kJ/kg)A -46.80 191.62 --- 301.43 93.86 19.49 -211.71 3,054.75 636.27 3,472.33 3,120.82 3,594.06 2,028.64 165.87

Density (kg/m3

) 1,003.1 2.4 --- 1.1 1.1 2.9 795.9 2.0 916.0 47.7 15.7 10.3 0.1 993.3

V-L Molecular Weight 18.015 29.029 --- 28.831 28.172 43.908 43.971 18.015 18.015 18.015 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 32,478 2,313 593 245,711 185,179 29,979 29,907 107,214 107,214 289,297 267,012 267,012 133,388 136,281

V-L Flowrate (lb/hr) 585,092 67,154 10,682 7,084,027 5,216,839 1,316,349 1,315,051 1,931,497 1,931,497 5,211,774 4,810,293 4,810,293 2,403,024 2,455,142

Solids Flowrate (lb/hr) 0 0 96,577 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 59 357 136 136 89 69 95 565 304 1,050 686 1,050 101 103

Pressure (psia) 14.7 45.0 14.9 14.9 14.7 23.5 2,214.5 73.5 130.0 2,415.0 620.5 565.5 1.0 245.0

Enthalpy (Btu/lb)A -20.1 82.4 --- 129.6 40.4 8.4 -91.0 1,313.3 273.5 1,492.8 1,341.7 1,545.2 872.2 71.3

Density (lb/ft3) 62.622 0.149 --- 0.067 0.070 0.184 49.684 0.122 57.183 2.977 0.983 0.643 0.004 62.007
Cost and Performance Baseline for Fossil Energy Plants

357

Exhibit 4-20 Case 10 Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Steam Turbine Power 672,700

TOTAL (STEAM TURBINE) POWER, kWe 672,700

AUXILIARY LOAD SUMMARY, kWe

Coal Handling and Conveying 540

Pulverizers 4,180

Sorbent Handling & Reagent Preparation 1,370

Ash Handling 800

Primary Air Fans 1,960

Forced Draft Fans 2,500

Induced Draft Fans 12,080

SCR 70

Baghouse 100

Wet FGD 4,470

Econamine FG Plus Auxiliaries 22,400

CO2 Compression 48,790

Miscellaneous Balance of Plant2,3 2,000

Steam Turbine Auxiliaries 400

Condensate Pumps 700

Circulating Water Pumps 11,190

Ground Water Pumps 1,020

Cooling Tower Fans 5,820

Transformer Losses 2,350

TOTAL AUXILIARIES, kWe 122,740

NET POWER, kWe 549,960

Net Plant Efficiency (HHV) 26.2%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 13,764 (13,046)

CONDENSER COOLING DUTY 106 kJ/hr (106 Btu/hr) 2,034 (1,928)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 278,956 (614,994)

Limestone Sorbent Feed, kg/hr (lb/hr) 28,404 (62,618)

Thermal Input, kWt1 2,102,643

Raw Water Withdrawal, m3/min (gpm) 42.5 (11,224)

Raw Water Consumption, m3/min (gpm) 32.6 (8,620)

1. HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)

2. Boiler feed pumps are turbine driven

3. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads.
Cost and Performance Baseline for Fossil Energy Plants

358

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 

2.4. A summary of the plant air emissions for Case 10 is presented in 

Environmental Performance

Exhibit 4-21.

Exhibit 4-21 Case 10 Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

85% CF

kg/MWh

(lb/MWh)

SO2 0.001 (0.002) 40 (44) 0.008 (.02)

NOx 0.030 (0.070) 1,696 (1,870) 0.339 (.747)

Particulates 0.006 (0.0130) 315 (347) 0.063 (.139)

Hg 4.91E-7 (1.14E-6) 0.028 (0.031) 5.53E-6 (1.22E-5)

CO2 8.8 (20.4) 493,198 (543,658) 98 (217)

CO2

1 120 (266)

1 CO2 emissions based on net power instead of gross power

SO2 emissions are controlled using a wet limestone forced oxidation scrubber that achieves a 

removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site. 

The wallboard grade material can potentially be marketed and sold, but since it is highly 

dependent on local market conditions, no byproduct credit was taken. The SO2 emissions are 

further reduced to 10 ppmv using a NaOH based polishing scrubber in the CDR facility. The 

remaining low concentration of SO2 is essentially completely removed in the CDR absorber 

vessel resulting in very low SO2 emissions.

NOx emissions are controlled to about 0.5 lb/106 Btu through the use of LNBs and OFA. An 

SCR unit then further reduces the NOx concentration by 86 percent to 0.07 lb/106 Btu.

Particulate emissions are controlled using a pulse jet fabric filter, which operates at an efficiency 

of 99.8 percent.

Co-benefit capture results in a 90 percent reduction of mercury emissions.

Ninety percent of the CO2 in the FG is removed in CDR facility.

The carbon balance for the plant is shown in Exhibit 4-22. The carbon input to the plant consists 

of carbon in the coal in addition to carbon in the air and limestone for the FGD. Carbon in the 

air is not neglected here since the Aspen model accounts for air components throughout. Carbon 

leaves the plant as CO2 in the stack gas, carbon in the FGD product, and the captured CO2

product. The CO2 capture efficiency is defined by the following fraction: 

1-[(Stack Gas Carbon-Air Carbon)/(Total Carbon In-Air Carbon)] or

[1-(39,853-850)/(399,230-850) *100] or

90.2 percent
Cost and Performance Baseline for Fossil Energy Plants

359

Exhibit 4-22 Case 10 Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 177,820 (392,026) Stack Gas 18,077 (39,853)

Air (CO2) 386 (850) FGD Product 317 (699)

FGD Reagent 2,882 (6,354) CO2 Product 162,694 (358,679)

Total 181,088 (399,230) Total 181,088 (399,230)

Exhibit 4-23 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered from the FGD as gypsum, sulfur emitted in

the stack gas, and sulfur removed in the polishing scrubber.

Exhibit 4-23 Case 10 Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 6,992 (15,414) FGD Product 6,852 (15,106)

Stack Gas 3 (6)

Econamine Polishing 

Scrubber/HSS 137 (302)

Total 6,992 (15,414) Total 6,992 (15,414)

Exhibit 4-24 shows the overall water balance for the plant. The exhibit is presented in an 

identical manner as was for Case 9.

Exhibit 4-24 Case 10 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)

Econamine 0.2 (39) 0.0 (0) 0.2 (39) 0.0 (0) 0.2 (39)

FGD Makeup 5.5 (1,460) 0.0 (0) 5.5 (1,460) 0.0 (0) 5.5 (1,460)

BFW Makeup 0.4 (104) 0.0 (0) 0.4 (104) 0.0 (0) 0.4 (104)

Cooling Tower 43.8 (11,580) 7.4 (1,959) 36.4 (9,621) 9.9 (2,604) 26.6 (7,017)

Total 49.9 (13,182) 7.4 (1,959) 42.5 (11,224) 9.9 (2,604) 32.6 (8,620)
Cost and Performance Baseline for Fossil Energy Plants

360

A heat and mass balance diagram is shown for the Case 10 PC boiler, the FGD unit, CDR system 

and steam cycle in 

Heat and Mass Balance Diagrams

Exhibit 4-25 and Exhibit 4-26. An overall plant energy balance is provided in 

tabular form in Exhibit 4-27. 

The power out is the steam turbine power prior to generator losses. The power at the generator 

terminals (shown in Exhibit 4-20) is calculated by multiplying the power out by a generator 

efficiency of 98.4 percent. The Econamine process heat out stream represents heat rejected to 

cooling water and ultimately to ambient via the cooling tower. The same is true of the condenser 

heat out stream. The CO2 compressor intercooler load is included in the Econamine process heat 

out stream.
Cost and Performance Baseline for Fossil Energy Plants

361

Exhibit 4-25 Case 10 Heat and Mass Balance, Subcritical PC Boiler with CO2 Capture
Cost and Performance Baseline for Fossil Energy Plants

362

Exhibit 4-26 Case 10 Heat and Mass Balance, Subcritical Steam Cycle

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Sour Gas

Sour Water

Water

Steam

PAGES

2 OF 2

DWG. NO.

BB-HMB-CS-10-PG-2

BITUMINOUS BASELINE STUDY

CASE 10

SUBCRITICAL PULVERIZED COAL

POWER BLOCK SYSTEMS

LP TURBINE GENERATOR HP

TURBINE

IP

TURBINE

CONDENSER

HOT WELL

P-1028 To Boiler P-1048

BOILER FEED

PUMP TURBINE 

DRIVES

STEAM SEAL

REGULATOR

Throttle

Steam

Single Reheat

Extraction

From Boiler

GLAND SEAL

CONDENSER

CONDENSATE

PUMPS

5,211,774 W

1,050.0 T

2,415.0 P

1,492.8 H

493,596 W

916.3 T

323.0 P

1,480.9 H

357,025 W

682.6 T

589.7 P

1,341.7 H

4,810,293 W

686.0 T

620.5 P

1,341.7 H

620.5 P

620.5 P

620.5 P

350.5 P

75.0 P

75.0 P

284,197 W

564.7 T

73.5 P

1,313.3 H

284,197 W

126.1 T

2.0 P

1,088.1 H

1,715,276 W

101.1 T

1.0 P

1,020.0 H

2,793 W

212.0 T

14.7 P

179.9 H

64.2 P

41.6 P

11.8 P

101.4 T

250.0 P

70.0 H

2,793 W

634.8 T

75.0 P

1,347.9 H

2,455,142 W

101.1 T

1.0 P

69.1 H

2,455,142 W

102.8 T

245.0 P

71.3 H

2,455,142 W

152.8 T

240.0 P

121.2 H

397,457 W

112.8 T

1.4 P

80.6 H

293,413 W

162.8 T

5.1 P

130.6 H

2,455,142 W

284.7 T

220.0 P

253.9 H

850,621 W

319.4 T

323.0 P

289.8 H

2,455,142 W

257.7 T

230.0 P

226.5 H

357,025 W

436.2 T

366.7 P

414.3 H

5,211,774 W

426.2 T

3,105.5 P

406.0 H

DEAERATOR

BOILER

FEED PUMPS

5,211,774 W

484.4 T

3,100.5 P

469.5 H

4,810,293 W

1,050.0 T

565.5 P

1,545.2 H

63,337 W

267.7 T

40.3 P

236.3 H

211,580 W

200.5 T

11.7 P

168.3 H

2,455,142 W

190.5 T

235.0 P

158.8 H

26,631 W

577.8 T

70.0 P

1,320.0 H

63,337 W

535.0 T

57.3 P

1,300.0 H

148,243 W

448.7 T

37.1 P

1,259.8 H

81,833 W

236.1 T

10.5 P

1,163.0 H

104,045 W

157.8 T

4.5 P

1,116.3 H

2,415.0 P

4,325,282 W

564.7 T

73.5 P

1,313.3 H

2,109,588 W

564.7 T

73.5 P

1,313.3 H

5.0 P

Steam Turbine

Makeup

309.4 T

3,110.5 P

284.6 H

5,211,774 W

302.9 T

70.0 P

272.3 H

3,301 W

634.8 T

75.0 P

1,347.9 H

Gross Plant Power: 673 MWe

Auxiliary Load: 123 MWe

Net Plant Power: 550 MWe

Net Plant Efficiency, HHV: 26.2%

Net Plant Heat Rate: 13,046 BTU/KWe

FWH 4 FWH 3 FWH 2 FWH 1 FWH 7 FWH 6

3,145 W

634.8 T

75.0 P

1,347.9 H

24

28

DOE/NETL

SC PC PLANT

CASE 10

2,415.0 P

26

1,850.0 P

Single Reheat

Extraction to

Boiler

25

4,842,620 W

1,049.0 T

565.5 P

1,544.6 H

52,118 W

48.0 T

11.4 P

16.1 H

Econamine

Steam

Econamine

Condensate

1,931,497 W

304.0 T

130.0 P

273.5 H

1,931,497 W

564.7 T

73.5 P

1,313.3 H
Cost and Performance Baseline for Fossil Energy Plants

363

Exhibit 4-27 Case 10 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 7,570 (7,175) 6.3 (6.0) 7,576 (7,181)

Air 84.3 (79.9) 84.3 (79.9)

Raw Water Makeup 159.9 (151.5) 159.9 (151.5)

Limestone 0.32 (0.30) 0.32 (0.30)

Auxiliary Power 442 (419) 442 (419)

Totals 7,570 (7,175) 250.9 (237.8) 442 (419) 8,262 (7,831)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.7 (0.6) 0.7 (0.6)

Fly Ash + FGD Ash 2.6 (2.5) 2.6 (2.5)

Flue Gas 222 (211) 222 (211)

Condenser 2,034 (1,928) 2,034 (1,928)

CO2 -126 (-120) -126 (-120)

Cooling Tower 

Blowdown 73.2 (69.4) 73.2 (69.4)

Econamine Losses 3,585 (3,398) 3,585 (3,398)

Process Losses* 49.6 (47.0) 49.6 (47.0)

Power 2,422 (2,295) 2,422 (2,295)

Totals 0 (0) 5,841 (5,536) 2,422 (2,295) 8,262 (7,831)

* Process losses are estimated to match the heat input to the plant. Process losses include 

losses from: turbines, gas cooling, etc.
Cost and Performance Baseline for Fossil Energy Plants

364

4.2.9

Major equipment items for the subcritical PC plant 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 

Case 10 – Major Equipment List

4.2.10. In general, the design conditions include a 10 percent 

contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 FUEL AND SORBENT HANDLING

Equipment 

No. Description Type Design Condition 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 227 tonne/hr (250 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 463 tonne/hr (510 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 227 tonne (250 ton) 2 0

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3 in x 0 - 1-1/4 in x 0) 2 0

14 As-Fired Coal Sampling 

System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 463 tonne/hr (510 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 463 tonne/hr (510 tph) 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 998 tonne (1,100 ton) 3 0

19 Limestone Truck Unloading 

Hopper

N/A 36 tonne (40 ton) 1 0

20 Limestone Feeder Belt 118 tonne/hr (130 tph) 1 0

21 Limestone Conveyor No. L1 Belt 118 tonne/hr (130 tph) 1 0

22 Limestone Reclaim Hopper N/A 27 tonne (30 ton) 1 0

23 Limestone Reclaim Feeder Belt 91 tonne/hr (100 tph) 1 0

24 Limestone Conveyor No. L2 Belt 91 tonne/hr (100 tph) 1 0

25 Limestone Day Bin w/ actuator 372 tonne (410 ton) 2 0
Cost and Performance Baseline for Fossil Energy Plants

365

ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Coal Feeder Gravimetric 54 tonne/hr (60 tph) 6 0

2 Coal Pulverizer Ball type or 

equivalent 54 tonne/hr (60 tph) 6 0

3 Limestone Weigh Feeder Gravimetric 31 tonne/hr (34 tph) 1 1

4 Limestone Ball Mill Rotary 31 tonne/hr (34 tph) 1 1

5 Limestone Mill Slurry Tank 

with Agitator N/A 121,133 liters (32,000 gal) 1 1

6 Limestone Mill Recycle 

Pumps

Horizontal 

centrifugal

2,006 lpm @ 12m H2O (530 gpm 

@ 40 ft H2O) 1 1

7 Hydroclone Classifier

4 active 

cyclones in a 5 

cyclone bank

492 lpm (130 gpm) per cyclone 1 1

8 Distribution Box 2-way N/A 1 1

9 Limestone Slurry Storage 

Tank with Agitator Field erected 673,803 liters (178,000 gal) 1 1

10 Limestone Slurry Feed 

Pumps

Horizontal 

centrifugal

1,401 lpm @ 9m H2O (370 gpm 

@ 30 ft H2O) 1 1
Cost and Performance Baseline for Fossil Energy Plants

366

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 1,563,375 liters (413,000 gal) 2 0

2 Condensate Pumps Vertical canned 20,441 lpm @ 213 m H2O (5,400 

gpm @ 700 ft H2O) 1 1

3 Deaerator and Storage 

Tank Horizontal spray type 2,600,445 kg/hr (5,733,000 lb/hr), 5 min. tank 1 0

4 Boiler Feed 

Pump/Turbine

Barrel type, multi-stage, 

centrifugal

43,532 lpm @ 2,591 m H2O 

(11,500 gpm @ 8,500 ft H2O) 1 1

5

Startup Boiler Feed 

Pump, Electric Motor 

Driven

Barrel type, multi-stage, 

centrifugal

12,870 lpm @ 2,591 m H2O 

(3,400 gpm @ 8,500 ft H2O) 1 0

6 LP Feedwater Heater 

1A/1B Horizontal U-tube 612,350 kg/hr (1,350,000 lb/hr) 2 0

7

LP Feedwater Heater 

2A/2B Horizontal U-tube 612,350 kg/hr (1,350,000 lb/hr) 2 0

8 LP Feedwater Heater 

3A/3B Horizontal U-tube 612,350 kg/hr (1,350,000 lb/hr) 2 0

9 LP Feedwater Heater 

4A/4B Horizontal U-tube 612,350 kg/hr (1,350,000 lb/hr) 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 2,599,084 kg/hr (5,730,000 lb/hr) 1 0

11 HP Feedwater Heater 7 Horizontal U-tube 2,599,084 kg/hr (5,730,000 lb/hr) 1 0

12 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

13 Fuel Oil System No. 2 fuel oil for light 

off 1,135,624 liter (300,000 gal) 1 0

14 Service Air 

Compressors Flooded Screw 28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

15 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

16 Closed Cycle Cooling 

Heat Exchangers Shell and tube 53 GJ/hr (50 MMBtu/hr) each 2 0

17 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 20,820 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 2 1

18 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 88 m H2O (1,000 

gpm @ 290 ft H2O) 1 1

19 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 64 m H2O (700 gpm 

@ 210 ft H2O) 1 1

20 Raw Water Pumps Stainless steel, single 

suction

12,265 lpm @ 18 m H2O (3,240 

gpm @ 60 ft H2O) 2 1

21 Ground Water Pumps Stainless steel, single 

suction

4,921 lpm @ 268 m H2O (1,300 

gpm @ 880 ft H2O) 5 1

22 Filtered Water Pumps Stainless steel, single 

suction

2,953 lpm @ 49 m H2O (780 gpm 

@ 160 ft H2O) 2 1

23 Filtered Water Tank Vertical, cylindrical 2,839,059 liter (750,000 gal) 1 0

24 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly, 

electrodeionization unit

1,022 lpm (270 gpm) 1 1

25 Liquid Waste Treatment 

System -- 10 years, 24-hour storm 1 0
Cost and Performance Baseline for Fossil Energy Plants

367

ACCOUNT 4 BOILER AND ACCESSORIES

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Boiler

Subcritical, drum 

wall-fired, low NOx 

burners, overfire air

2,599,084 kg/hr steam @ 17.9 

MPa/574°C/574°C (5,730,000 

lb/hr steam @ 2,600 

psig/1,065°F/1,065°F)

1 0

2 Primary Air Fan Centrifugal

354,256 kg/hr, 4,837 m3/min @ 

123 cm WG (781,000 lb/hr, 

170,800 acfm @ 48 in. WG)

2 0

3 Forced Draft Fan Centrifugal

1,153,485 kg/hr, 15,744 m3/min 

@ 47 cm WG (2,543,000 lb/hr, 

556,000 acfm @ 19 in. WG)

2 0

4 Induced Draft Fan Centrifugal

1,673,302 kg/hr, 35,314 m3/min 

@ 104 cm WG (3,689,000 lb/hr, 

1,247,100 acfm @ 41 in. WG)

2 0

5 SCR Reactor Vessel Space for spare 

layer 3,347,512 kg/hr (7,380,000 lb/hr) 2 0

6 SCR Catalyst -- -- 3 0

7 Dilution Air Blower Centrifugal 198 m3/min @ 108 cm WG 

(7,000 acfm @ 42 in. WG) 2 1

8 Ammonia Storage Horizontal tank 219,554 liter (58,000 gal) 5 0

9 Ammonia Feed 

Pump Centrifugal 42 lpm @ 91 m H2O (11 gpm @ 

300 ft H2O) 2 1
Cost and Performance Baseline for Fossil Energy Plants

368

ACCOUNT 5 FLUE GAS CLEANUP

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Fabric Filter

Single stage, highratio with pulse-jet 

online cleaning 

system

1,673,302 kg/hr (3,689,000 lb/hr) 

99.8% efficiency 2 0

2 Absorber Module Counter-current 

open spray

66,913 m3/min (2,363,000 acfm) 1 0

3 Recirculation Pumps Horizontal 

centrifugal

230,910 lpm @ 64 m H2O 

(61,000 gpm @ 210 ft H2O) 5 1

4 Bleed Pumps Horizontal 

centrifugal

6,095 lpm (1,610 gpm) at 20 wt% 

solids 2 1

5 Oxidation Air Blowers Centrifugal 117 m3/min @ 0.3 MPa (4,130 

acfm @ 37 psia) 2 1

6 Agitators Side entering 50 hp 5 1

7 Dewatering Cyclones Radial assembly, 

5 units each 1,514 lpm (400 gpm) per cyclone 2 0

8 Vacuum Filter Belt Horizontal belt 48 tonne/hr (53 tph) of 50 wt % 

slurry 2 1

9 Filtrate Water Return 

Pumps

Horizontal 

centrifugal

908 lpm @ 12 m H2O (240 gpm 

@ 40 ft H2O) 1 1

10 Filtrate Water Return 

Storage Tank Vertical, lined 605,666 lpm (160,000 gal) 1 0

11 Process Makeup Water 

Pumps

Horizontal 

centrifugal

4,883 lpm @ 21 m H2O (1,290 

gpm @ 70 ft H2O) 1 1
Cost and Performance Baseline for Fossil Energy Plants

369

ACCOUNT 5B CARBON DIOXIDE RECOVERY 

ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES 

N/A

ACCOUNT 7 HRSG, DUCTING & STACK

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Econamine FG 

Plus

Amine-based CO2 

capture technology

1,767,196 kg/h (3,896,000 lb/h) 

20.6 wt % CO2 concentration 2 0

2

Econamine 

Condensate 

Pump

Centrifugal 18,435 lpm @ 52 m H2O (4,870 

gpm @ 170 ft H2O) 1 1

3 CO2 

Compressor

Integrally geared, 

multi-stage centrifugal

327,872 kg/h @ 15.3 MPa 

(722,834 lb/h @ 2,215 psia) 2 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack Reinforced concrete 

with FRP liner

152 m (500 ft) high x

5.8 m (19 ft) diameter 1 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

708 MW

16.5 MPa/566°C/566°C 

(2400.3 psig/ 

1050°F/1050°F)

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitation

790 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase 1 0

3 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

2,237 GJ/hr (2,120 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 

11°C (20°F)

1 0
Cost and Performance Baseline for Fossil Energy Plants

370

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Circulating Water 

Pumps Vertical, wet pit 1,128,100 lpm @ 30 m

(298,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

/ 6299 GJ/hr (5970 MMBtu/hr) 

heat duty

1 0
Cost and Performance Baseline for Fossil Energy Plants

371

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Economizer Hopper (part of 

boiler scope of supply) -- -- 4 0

2 Bottom Ash Hopper (part of 

boiler scope of supply) -- -- 2 0

3 Clinker Grinder -- 6.4 tonne/hr (7 tph) 1 1

4

Pyrites Hopper (part of 

pulverizer scope of supply 

included with boiler)

-- -- 6 0

5 Hydroejectors -- -- 12

6 Economizer /Pyrites Transfer 

Tank -- -- 1 0

7 Ash Sluice Pumps Vertical, wet pit 227 lpm @ 17 m H2O (60 gpm 

@ 56 ft H2O) 1 1

8 Ash Seal Water Pumps Vertical, wet pit 7,571 lpm @ 9 m H2O (2000 

gpm @ 28 ft H2O) 1 1

9 Hydrobins -- 227 lpm (60 gpm) 1 1

10 Baghouse Hopper (part of 

baghouse scope of supply) -- -- 24 0

11 Air Heater Hopper (part of 

boiler scope of supply) -- -- 10 0

12 Air Blower -- 22 m3/min @ 0.2 MPa (770 

scfm @ 24 psi) 1 1

13 Fly Ash Silo Reinforced 

concrete 1,451 tonne (1,600 ton) 2 0

14 Slide Gate Valves -- -- 2 0

15 Unloader -- -- 1 0

16 Telescoping Unloading Chute -- 136 tonne/hr (150 tph) 1 0
Cost and Performance Baseline for Fossil Energy Plants

372

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 STG Transformer Oil-filled 24 kV/345 kV, 650 MVA, 3-

ph, 60 Hz 1 0

2 Auxiliary 

Transformer Oil-filled 24 kV/4.16 kV, 134 MVA, 3-ph, 60 Hz 1 1

3 Low Voltage 

Transformer Dry ventilated 4.16 kV/480 V, 20 MVA, 3-ph, 60 Hz 1 1

4

STG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0

5 Medium Voltage 

Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

6 Low Voltage 

Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

7 Emergency Diesel 

Generator

Sized for emergency 

shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0

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 for Fossil Energy Plants

373

4.2.10

The cost estimating methodology was described previously in Section 

Case 10 – Cost Estimating

2.7. Exhibit 4-28 shows 

the total plant capital cost summary organized by cost account and Exhibit 4-29 shows a more 

detailed breakdown of the capital costs along with owner’s costs, TOC, and TASC. Exhibit 4-30

shows the initial and annual O&M costs.

The estimated TOC of the subcritical PC boiler with CO2 capture is $3,610/kW. Process 

contingency represents 2.9 percent of the TOC and project contingency represents 10.2 percent. 

The COE, including CO2 TS&M costs of 5.9 mills/kWh, is 109.7 mills/kWh.
Cost and Performance Baseline for Fossil Energy Plants

374

Exhibit 4-28 Case 10 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14

Project: Bituminous Baseline Study

Case: Case 10 - 1x550 MWnet SubCritical PC w/ CO2 Capture

Plant Size: 550.0 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 $21,191 $5,688 $12,662 $0 $0 $39,542 $3,548 $0 $6,463 $49,553 $90

 2 COAL & SORBENT PREP & FEED $14,465 $844 $3,675 $0 $0 $18,984 $1,664 $0 $3,097 $23,744 $43

 3 FEEDWATER & MISC. BOP SYSTEMS $52,748 $0 $25,315 $0 $0 $78,063 $7,174 $0 $14,102 $99,339 $181

 4 PC BOILER

4.1 PC Boiler & Accessories $171,007 $0 $109,973 $0 $0 $280,980 $27,374 $0 $30,835 $339,189 $617

4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4 $171,007 $0 $109,973 $0 $0 $280,980 $27,374 $0 $30,835 $339,189 $617

 5 FLUE GAS CLEANUP $107,581 $0 $36,768 $0 $0 $144,350 $13,816 $0 $15,817 $173,983 $316

 5B CO2 REMOVAL & COMPRESSION $247,434 $0 $75,421 $0 $0 $322,855 $30,869 $56,959 $82,137 $492,819 $896

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

7.2-7.9 HRSG Accessories, Ductwork and Stack $19,509 $1,069 $13,214 $0 $0 $33,792 $3,095 $0 $4,848 $41,735 $76

SUBTOTAL 7 $19,509 $1,069 $13,214 $0 $0 $33,792 $3,095 $0 $4,848 $41,735 $76

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $55,209 $0 $6,905 $0 $0 $62,114 $5,951 $0 $6,806 $74,871 $136

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $26,840 $1,213 $15,303 $0 $0 $43,356 $3,796 $0 $6,701 $53,853 $98

SUBTOTAL 8 $82,049 $1,213 $22,207 $0 $0 $105,470 $9,747 $0 $13,507 $128,724 $234

 9 COOLING WATER SYSTEM $22,313 $10,599 $19,714 $0 $0 $52,626 $4,953 $0 $7,745 $65,324 $119

10 ASH/SPENT SORBENT HANDLING SYS $5,525 $176 $7,387 $0 $0 $13,088 $1,258 $0 $1,477 $15,823 $29

11 ACCESSORY ELECTRIC PLANT $25,948 $11,057 $31,311 $0 $0 $68,316 $6,043 $0 $9,343 $83,703 $152

12 INSTRUMENTATION & CONTROL $9,942 $0 $10,082 $0 $0 $20,024 $1,816 $1,001 $2,805 $25,646 $47

13 IMPROVEMENTS TO SITE $3,344 $1,922 $6,739 $0 $0 $12,006 $1,184 $0 $2,638 $15,828 $29

14 BUILDINGS & STRUCTURES $0 $25,775 $24,432 $0 $0 $50,207 $4,529 $0 $8,210 $62,947 $114

 

TOTAL COST $783,055 $58,343 $398,903 $0 $0 $1,240,301 $117,071 $57,960 $203,025 $1,618,357 $2,942

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline for Fossil Energy Plants

375

Exhibit 4-29 Case 10 Total Plant Cost Details

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 $4,333 $0 $1,979 $0 $0 $6,313 $564 $0 $1,031 $7,908 $14

1.2 Coal Stackout & Reclaim $5,600 $0 $1,269 $0 $0 $6,869 $601 $0 $1,120 $8,590 $16

1.3 Coal Conveyors $5,207 $0 $1,255 $0 $0 $6,462 $566 $0 $1,054 $8,083 $15

1.4 Other Coal Handling $1,362 $0 $290 $0 $0 $1,653 $144 $0 $270 $2,067 $4

1.5 Sorbent Receive & Unload $178 $0 $54 $0 $0 $231 $20 $0 $38 $289 $1

1.6 Sorbent Stackout & Reclaim $2,869 $0 $526 $0 $0 $3,395 $296 $0 $554 $4,244 $8

1.7 Sorbent Conveyors $1,024 $221 $251 $0 $0 $1,496 $129 $0 $244 $1,869 $3

1.8 Other Sorbent Handling $618 $145 $324 $0 $0 $1,088 $96 $0 $178 $1,361 $2

1.9 Coal & Sorbent Hnd.Foundations $0 $5,322 $6,714 $0 $0 $12,036 $1,130 $0 $1,975 $15,141 $28

SUBTOTAL 1. $21,191 $5,688 $12,662 $0 $0 $39,542 $3,548 $0 $6,463 $49,553 $90

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $2,523 $0 $492 $0 $0 $3,014 $263 $0 $492 $3,768 $7

2.2 Coal Conveyor to Storage $6,459 $0 $1,410 $0 $0 $7,869 $688 $0 $1,283 $9,840 $18

2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.5 Sorbent Prep Equipment $4,894 $211 $1,016 $0 $0 $6,121 $533 $0 $998 $7,652 $14

2.6 Sorbent Storage & Feed $590 $0 $226 $0 $0 $815 $72 $0 $133 $1,021 $2

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 $633 $531 $0 $0 $1,164 $108 $0 $191 $1,463 $3

SUBTOTAL 2. $14,465 $844 $3,675 $0 $0 $18,984 $1,664 $0 $3,097 $23,744 $43

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $20,624 $0 $7,119 $0 $0 $27,743 $2,430 $0 $4,526 $34,699 $63

3.2 Water Makeup & Pretreating $7,503 $0 $2,415 $0 $0 $9,919 $938 $0 $2,171 $13,028 $24

3.3 Other Feedwater Subsystems $6,747 $0 $2,851 $0 $0 $9,599 $860 $0 $1,569 $12,027 $22

3.4 Service Water Systems $1,471 $0 $800 $0 $0 $2,271 $214 $0 $497 $2,982 $5

3.5 Other Boiler Plant Systems $8,081 $0 $7,979 $0 $0 $16,060 $1,526 $0 $2,638 $20,224 $37

3.6 FO Supply Sys & Nat Gas $278 $0 $348 $0 $0 $626 $59 $0 $103 $788 $1

3.7 Waste Treatment Equipment $5,087 $0 $2,900 $0 $0 $7,987 $777 $0 $1,753 $10,517 $19

3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,955 $0 $903 $0 $0 $3,858 $371 $0 $846 $5,075 $9

SUBTOTAL 3. $52,748 $0 $25,315 $0 $0 $78,063 $7,174 $0 $14,102 $99,339 $181

 4 PC BOILER

4.1 PC Boiler & Accessories $171,007 $0 $109,973 $0 $0 $280,980 $27,374 $0 $30,835 $339,189 $617

4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4. $171,007 $0 $109,973 $0 $0 $280,980 $27,374 $0 $30,835 $339,189 $617
Cost and Performance Baseline for Fossil Energy Plants

376

Exhibit 4-29 Case 10 Total Plant Cost Details (Continued)

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

 5 FLUE GAS CLEANUP

5.1 Absorber Vessels & Accessories $74,713 $0 $16,084 $0 $0 $90,797 $8,656 $0 $9,945 $109,399 $199

5.2 Other FGD $3,899 $0 $4,418 $0 $0 $8,317 $807 $0 $912 $10,037 $18

5.3 Bag House & Accessories $21,582 $0 $13,697 $0 $0 $35,279 $3,400 $0 $3,868 $42,546 $77

5.4 Other Particulate Removal Materials $1,461 $0 $1,563 $0 $0 $3,023 $293 $0 $332 $3,648 $7

5.5 Gypsum Dewatering System $5,926 $0 $1,007 $0 $0 $6,933 $660 $0 $759 $8,352 $15

5.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5. $107,581 $0 $36,768 $0 $0 $144,350 $13,816 $0 $15,817 $173,983 $316

 5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $218,463 $0 $66,332 $0 $0 $284,795 $27,229 $56,959 $73,796 $442,779 $805

5B.2 CO2 Compression & Drying $28,971 $0 $9,089 $0 $0 $38,060 $3,640 $0 $8,340 $50,040 $91

SUBTOTAL 5B. $247,434 $0 $75,421 $0 $0 $322,855 $30,869 $56,959 $82,137 $492,819 $896

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $10,193 $0 $6,549 $0 $0 $16,743 $1,460 $0 $2,730 $20,933 $38

7.4 Stack $9,316 $0 $5,451 $0 $0 $14,766 $1,422 $0 $1,619 $17,807 $32

7.9 Duct & Stack Foundations $0 $1,069 $1,214 $0 $0 $2,283 $214 $0 $499 $2,996 $5

SUBTOTAL 7. $19,509 $1,069 $13,214 $0 $0 $33,792 $3,095 $0 $4,848 $41,735 $76

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $55,209 $0 $6,905 $0 $0 $62,114 $5,951 $0 $6,806 $74,871 $136

8.2 Turbine Plant Auxiliaries $387 $0 $828 $0 $0 $1,215 $119 $0 $133 $1,467 $3

8.3 Condenser & Auxiliaries $6,154 $0 $2,549 $0 $0 $8,702 $835 $0 $954 $10,490 $19

8.4 Steam Piping $20,300 $0 $10,009 $0 $0 $30,310 $2,547 $0 $4,928 $37,784 $69

8.9 TG Foundations $0 $1,213 $1,917 $0 $0 $3,130 $296 $0 $685 $4,111 $7

SUBTOTAL 8. $82,049 $1,213 $22,207 $0 $0 $105,470 $9,747 $0 $13,507 $128,724 $234

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $16,661 $0 $5,188 $0 $0 $21,850 $2,090 $0 $2,394 $26,333 $48

9.2 Circulating Water Pumps $3,467 $0 $260 $0 $0 $3,727 $315 $0 $404 $4,446 $8

9.3 Circ.Water System Auxiliaries $839 $0 $112 $0 $0 $951 $90 $0 $104 $1,146 $2

9.4 Circ.Water Piping $0 $6,653 $6,448 $0 $0 $13,101 $1,226 $0 $2,149 $16,476 $30

9.5 Make-up Water System $680 $0 $909 $0 $0 $1,589 $152 $0 $261 $2,002 $4

9.6 Component Cooling Water Sys $665 $0 $529 $0 $0 $1,194 $113 $0 $196 $1,503 $3

9.9 Circ.Water System Foundations & Structures $0 $3,946 $6,269 $0 $0 $10,214 $966 $0 $2,236 $13,417 $24

SUBTOTAL 9. $22,313 $10,599 $19,714 $0 $0 $52,626 $4,953 $0 $7,745 $65,324 $119
Cost and Performance Baseline for Fossil Energy Plants

377

Exhibit 4-29 Case 10 Total Plant Cost Details (Continued)

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 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $739 $0 $2,278 $0 $0 $3,017 $296 $0 $331 $3,645 $7

10.7 Ash Transport & Feed Equipment $4,786 $0 $4,902 $0 $0 $9,688 $926 $0 $1,061 $11,676 $21

10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.9 Ash/Spent Sorbent Foundation $0 $176 $207 $0 $0 $383 $36 $0 $84 $502 $1

SUBTOTAL 10. $5,525 $176 $7,387 $0 $0 $13,088 $1,258 $0 $1,477 $15,823 $29

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $1,742 $0 $283 $0 $0 $2,025 $188 $0 $166 $2,379 $4

11.2 Station Service Equipment $5,148 $0 $1,691 $0 $0 $6,839 $639 $0 $561 $8,039 $15

11.3 Switchgear & Motor Control $5,918 $0 $1,006 $0 $0 $6,924 $642 $0 $757 $8,322 $15

11.4 Conduit & Cable Tray $0 $3,710 $12,830 $0 $0 $16,540 $1,601 $0 $2,721 $20,862 $38

11.5 Wire & Cable $0 $7,001 $13,516 $0 $0 $20,517 $1,729 $0 $3,337 $25,582 $47

11.6 Protective Equipment $270 $0 $918 $0 $0 $1,188 $116 $0 $130 $1,434 $3

11.7 Standby Equipment $1,370 $0 $31 $0 $0 $1,401 $128 $0 $153 $1,682 $3

11.8 Main Power Transformers $11,500 $0 $191 $0 $0 $11,691 $886 $0 $1,258 $13,835 $25

11.9 Electrical Foundations $0 $345 $846 $0 $0 $1,191 $114 $0 $261 $1,566 $3

SUBTOTAL 11. $25,948 $11,057 $31,311 $0 $0 $68,316 $6,043 $0 $9,343 $83,703 $152

12 INSTRUMENTATION & CONTROL

12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $512 $0 $307 $0 $0 $819 $77 $41 $141 $1,077 $2

12.7 Distributed Control System Equipment $5,168 $0 $903 $0 $0 $6,071 $563 $304 $694 $7,632 $14

12.8 Instrument Wiring & Tubing $2,802 $0 $5,558 $0 $0 $8,359 $712 $418 $1,423 $10,913 $20

12.9 Other I & C Equipment $1,460 $0 $3,314 $0 $0 $4,774 $463 $239 $548 $6,024 $11

SUBTOTAL 12. $9,942 $0 $10,082 $0 $0 $20,024 $1,816 $1,001 $2,805 $25,646 $47
Cost and Performance Baseline for Fossil Energy Plants

378

Exhibit 4-29 Case 10 Total Plant Cost Details (Continued)

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

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $56 $1,124 $0 $0 $1,180 $117 $0 $260 $1,557 $3

13.2 Site Improvements $0 $1,866 $2,318 $0 $0 $4,184 $413 $0 $919 $5,516 $10

13.3 Site Facilities $3,344 $0 $3,298 $0 $0 $6,642 $655 $0 $1,459 $8,756 $16

SUBTOTAL 13. $3,344 $1,922 $6,739 $0 $0 $12,006 $1,184 $0 $2,638 $15,828 $29

14 BUILDINGS & STRUCTURES

14.1 Boiler Building $0 $9,158 $8,054 $0 $0 $17,212 $1,547 $0 $2,814 $21,573 $39

14.2 Turbine Building $0 $13,420 $12,507 $0 $0 $25,927 $2,337 $0 $4,240 $32,503 $59

14.3 Administration Building $0 $646 $684 $0 $0 $1,330 $121 $0 $218 $1,668 $3

14.4 Circulation Water Pumphouse $0 $176 $140 $0 $0 $317 $28 $0 $52 $397 $1

14.5 Water Treatment Buildings $0 $952 $868 $0 $0 $1,819 $164 $0 $297 $2,281 $4

14.6 Machine Shop $0 $432 $290 $0 $0 $723 $64 $0 $118 $905 $2

14.7 Warehouse $0 $293 $294 $0 $0 $587 $53 $0 $96 $736 $1

14.8 Other Buildings & Structures $0 $239 $204 $0 $0 $443 $40 $0 $72 $555 $1

14.9 Waste Treating Building & Str. $0 $458 $1,391 $0 $0 $1,849 $176 $0 $304 $2,329 $4

SUBTOTAL 14. $0 $25,775 $24,432 $0 $0 $50,207 $4,529 $0 $8,210 $62,947 $114

TOTAL COST $783,055 $58,343 $398,903 $0 $0 $1,240,301 $117,071 $57,960 $203,025 $1,618,357 $2,942

Owner's Costs

Preproduction Costs

6 Months All Labor $10,547 $19

1 Month Maintenance Materials $1,534 $3

1 Month Non-fuel Consumables $1,789 $3

1 Month Waste Disposal $353 $1

25% of 1 Months Fuel Cost at 100% CF $2,143 $4

2% of TPC $32,367 $59

Total $48,733 $89

Inventory Capital

60 day supply of fuel and consumables at 100% CF $20,189 $37

0.5% of TPC (spare parts) $8,092 $15

Total $28,281 $51

Initial Cost for Catalyst and Chemicals $2,712 $5

Land $900 $2

Other Owner's Costs $242,754 $441

Financing Costs $43,696 $79

Total Overnight Costs (TOC) $1,985,432 $3,610

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,263,393 $4,115
Cost and Performance Baseline for Fossil Energy Plants

379

Exhibit 4-30 Case 10 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 10 - 1x550 MWnet SubCritical PC w/ CO2 Capture Heat Rate-net (Btu/kWh): 13,044

MWe-net: 550

Capacity Factor (%): 85

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

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 2.0 2.0

 Operator 11.3 11.3

 Foreman 1.0 1.0

 Lab Tech's, etc. 2.0 2.0

 TOTAL-O.J.'s 16.3 16.3

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $6,444,907 $11.718

Maintenance Labor Cost $10,429,543 $18.962

Administrative & Support Labor $4,218,612 $7.670

Property Taxes and Insurance $32,367,148 $58.848

TOTAL FIXED OPERATING COSTS $53,460,210 $97.199

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $15,644,314 $0.00382

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water(/1000 gallons) 0 8,081 1.08 $0 $2,711,996 $0.00066

Chemicals

MU & WT Chem.(lbs) 0 39,119 0.17 $0 $2,100,447 $0.00051

Limestone (ton) 0 751 21.63 $0 $5,043,346 $0.00123

Carbon (Mercury Removal) (lb) 0 0 1.05 $0 $0 $0.00000

MEA Solvent (ton) 1,117 1.58 2,249.89 $2,513,263 $1,105,563 $0.00027

NaOH (tons) 79 7.89 433.68 $34,221 $1,061,704 $0.00026

H2SO4 (tons) 75 7.53 138.78 $10,450 $324,217 $0.00008

Corrosion Inhibitor 0 0 0.00 $154,511 $7,358 $0.00000

Activated Carbon (lb) 0 1,892 1.05 $0 $616,433 $0.00015

Ammonia (19% NH3) ton 0 110 129.80 $0 $4,446,378 $0.00109

Subtotal Chemicals $2,712,445 $14,705,446 $0.00359

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000

SCR Catalyst (m3) w/equip. 0.46 5,775.94 $0 $831,516 $0.00020

Emission Penalties 0 0 0.00 $0 $0 $0.00000

Subtotal Other $0 $831,516 $0.00020

Waste Disposal

Fly Ash (ton) 0 572 16.23 $0 $2,881,846 $0.00070

Bottom Ash (ton) 0 143 16.23 $0 $720,462 $0.00018

 Subtotal-Waste Disposal $0 $3,602,308 $0.00088

By-products & Emissions 

Gypsum (tons) 0 1,159 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $2,712,445 $37,495,580 $0.00916

Fuel(ton) 0 7,380 38.18 $0 $87,425,787 $0.02135
Cost and Performance Baseline for Fossil Energy Plants

380

4.3 SUPERCRITICAL PC CASES

This section contains an evaluation of plant designs for Cases 11 and 12, which are based on a 

SC PC plant with a nominal net output of 550 MWe. Both plants use a single reheat 24.1 

MPa/593°C/593°C (3,500 psig/1,100°F/1,100°F) cycle. The only difference between the two 

plants is that Case 12 includes CO2 capture while Case 11 does not.

The balance of Section 4.3 is organized in an analogous manner to the subcritical PC section:

• Process and System Description for Case 11

• Key Assumptions for Cases 11 and 12

• Sparing Philosophy for Cases 11 and 12

• Performance Results for Case 11

• Equipment List for Case 11

• Cost Estimates for Case 11

• Process and System Description, Performance Results, Equipment List and Cost 

Estimates for Case 12

4.3.1

In this section the SC PC process without CO2 capture is described. The system description is 

nearly identical to the subcritical PC case without CO2 capture but is repeated here for 

completeness. The description follows the BFD in 

Process Description

Exhibit 4-31 and stream numbers reference 

the same Exhibit. The tables in Exhibit 4-32 provide process data for the numbered streams in 

the BFD.

Coal (stream 8) and PA (stream 4) are introduced into the boiler through the wall-fired burners. 

Additional combustion air, including the OFA, is provided by the FD fans (stream 1). The boiler 

operates at a slight negative pressure so air leakage is into the boiler, and the infiltration air is 

accounted for in stream 5. Streams 3 and 6 show Ljungstrom air preheater leakages from the FD

and PA fan outlet streams to the boiler exhaust.

FG exits the boiler through the SCR reactor (stream 10) and is cooled to 169°C (337°F) in the 

combustion air preheater before passing through a fabric filter for particulate removal (stream 

12). An ID fan increases the FG temperature to 181°C (357°F) and provides the motive force for 

the FG (stream 13) to pass through the FGD unit. FGD inputs and outputs include makeup water 

(stream 15), oxidation air (stream 16), limestone slurry (stream 14), and product gypsum (stream 

17). The clean, saturated FG exiting the FGD unit (stream 18) passes to the plant stack and is 

discharged to the atmosphere.
Cost and Performance Baseline for Fossil Energy Plants

381

Exhibit 4-31 Case 11 Block Flow Diagram, Supercritical Unit without CO2 Capture
Cost and Performance Baseline for Fossil Energy Plants

382

Exhibit 4-32 Case 11 Stream Table, Supercritical Unit without CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12

V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087

CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870

N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324

O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000

V-L Flowrate (kgmol/hr) 48,414 48,414 1,434 14,872 14,872 2,047 1,119 0 0 68,126 0 68,126

V-L Flowrate (kg/hr) 1,397,067 1,397,067 41,378 429,164 429,164 59,064 32,284 0 0 2,026,262 0 2,026,262

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 185,759 3,603 14,410 14,410 0

Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169

Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10

Enthalpy (kJ/kg)A 30.23 34.36 34.36 30.23 40.78 40.78 30.23 --- --- 327.37 --- 308.94

Density (kg/m3

) 1.2 1.2 1.2 1.2 1.3 1.3 1.2 --- --- 0.8 --- 0.8

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857 --- --- 29.743 --- 29.743

V-L Flowrate (lbmol/hr) 106,734 106,734 3,161 32,787 32,787 4,512 2,466 0 0 150,191 0 150,191

V-L Flowrate (lb/hr) 3,080,006 3,080,006 91,224 946,145 946,145 130,215 71,175 0 0 4,467,142 0 4,467,142

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 409,528 7,942 31,769 31,769 0

Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337

Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.7 14.4 14.7 14.2

Enthalpy (Btu/lb)A 13.0 14.8 14.8 13.0 17.5 17.5 13.0 --- --- 140.7 --- 132.8

Density (lb/ft3

) 0.076 0.078 0.078 0.076 0.081 0.081 0.076 --- --- 0.050 --- 0.049

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Fossil Energy Plants

383

Exhibit 4-32 Case 11 Stream Table, Supercritical Unit without CO2 Capture (Continued)

13 14 15 16 17 18 19 20 21 22 23

V-L Mole Fraction

Ar 0.0087 0.0000 0.0000 0.0128 0.0000 0.0082 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.1450 0.0000 0.0000 0.0005 0.0004 0.1353 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0870 1.0000 1.0000 0.0062 0.9995 0.1517 1.0000 1.0000 1.0000 1.0000 1.0000

N2 0.7324 0.0000 0.0000 0.7506 0.0000 0.6808 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0247 0.0000 0.0000 0.2300 0.0000 0.0240 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0021 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 68,126 2,369 9,597 726 176 74,091 92,389 76,591 76,591 69,891 69,891

V-L Flowrate (kg/hr) 2,026,262 42,682 172,898 21,076 3,168 2,137,881 1,664,421 1,379,803 1,379,803 1,259,099 1,259,099

Solids Flowrate (kg/hr) 0 18,437 0 0 28,694 0 0 0 0 0 0

Temperature (°C) 181 15 15 167 57 57 593 354 593 38 39

Pressure (MPa, abs) 0.11 0.10 0.10 0.31 0.10 0.10 24.23 4.90 4.52 0.01 1.69

Enthalpy (kJ/kg)A 321.02 --- -46.80 177.65 --- 297.66 3,476.62 3,082.88 3,652.22 1,985.85 165.59

Density (kg/m3

) 0.8 --- 1,003.1 2.5 --- 1.1 69.2 18.7 11.6 0.1 993.3

V-L Molecular Weight 29.743 --- 18.015 29.029 --- 28.855 18.015 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 150,191 5,223 21,158 1,601 387 163,343 203,684 168,854 168,854 154,082 154,082

V-L Flowrate (lb/hr) 4,467,142 94,099 381,174 46,465 6,985 4,713,221 3,669,421 3,041,946 3,041,946 2,775,839 2,775,839

Solids Flowrate (lb/hr) 0 40,646 0 0 63,259 0 0 0 0 0 0

Temperature (°F) 357 59 59 333 135 135 1,100 669 1,100 101 103

Pressure (psia) 15.3 15.0 14.7 45.0 14.8 14.8 3,514.7 710.8 655.8 1.0 245.0

Enthalpy (Btu/lb)A 138.0 --- -20.1 76.4 --- 128.0 1,494.7 1,325.4 1,570.2 853.8 71.2

Density (lb/ft3) 0.052 --- 62.622 0.154 --- 0.067 4.319 1.165 0.722 0.004 62.009
Cost and Performance Baseline for Fossil Energy Plants

384

4.3.2

System assumptions for Cases 11 and 12, SC PC with and without CO2 capture, are compiled in

Key System Assumptions

Exhibit 4-33.

Exhibit 4-33 Supercritical PC Plant Study Configuration Matrix

Case 11

w/o CO2 Capture 

Case 12

w/CO2 Capture

Steam Cycle, MPa/°C/°C (psig/°F/°F) 24.1/593/593 

(3500/1100/1100)

24.1/593/593 

(3500/1100/1100)

Coal Illinois No. 6 Illinois No. 6

Condenser pressure, mm Hg (in Hg) 50.8 (2) 50.8 (2)

Boiler Efficiency, % 88 88

Cooling water to condenser, °C (oF) 16 (60) 16 (60)

Cooling water from condenser, °C (oF) 27 (80) 27 (80)

Stack temperature, °C (°F) 57 (135) 32 (89)

SO2 Control Wet Limestone 

Forced Oxidation

Wet Limestone 

Forced Oxidation

FGD Efficiency, % (A) 98 98 (B, C)

NOx Control LNB w/OFA and 

SCR

LNB w/OFA and 

SCR

SCR Efficiency, % (A) 86 86

Ammonia Slip (end of catalyst life), 

ppmv

2 2

Particulate Control Fabric Filter Fabric Filter

Fabric Filter efficiency, % (A) 99.8 99.8

Ash Distribution, Fly/Bottom 80% / 20% 80% / 20%

Mercury Control Co-benefit Capture Co-benefit Capture

Mercury removal efficiency, % (A) 90 90

CO2 Control N/A Econamine

Overall CO2 Capture (A) N/A 90.2%

CO2 Sequestration N/A Off-site Saline 

Formation

A. Removal efficiencies are based on the FG content

B. An SO2 polishing step is included to meet more stringent SOx content limits in the FG (< 10 

ppmv) to reduce formation of amine HSS during the CO2 absorption process

C. SO2 exiting the post-FGD polishing step is absorbed in the CO2 capture process making stack 

emissions negligible

The balance of plant assumptions are common to all cases and were presented previously in 

Balance of Plant – Cases 11 and 12

Exhibit 4-6.
Cost and Performance Baseline for Fossil Energy Plants

385

4.3.3

Single trains are used throughout the design 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:

Sparing Philosophy

• One dry-bottom, wall-fired PC SC boiler (1 x 100%)

• Two SCR reactors (2 x 50%)

• Two single-stage, in-line, multi-compartment fabric filters (2 x 50%)

• One wet limestone forced oxidation positive pressure absorber (1 x 100%)

• One steam turbine (1 x 100%)

• For Case 12 only, two parallel Econamine CO2 absorption systems, with each system 

consisting of two absorbers, strippers, and ancillary equipment (2 x 50%)

4.3.4

The plant produces a net output of 550 MWe at a net plant efficiency of 39.3 percent (HHV 

basis).

Case 11 Performance Results

Overall performance for the plant is summarized in Exhibit 4-34, which includes auxiliary power 

requirements. 
Cost and Performance Baseline for Fossil Energy Plants

386

Exhibit 4-34 Case 11 Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Steam Turbine Power 580,400

TOTAL (STEAM TURBINE) POWER, kWe 580,400

AUXILIARY LOAD SUMMARY, kWe 

Coal Handling and Conveying 440

Pulverizers 2,780

Sorbent Handling & Reagent Preparation 890

Ash Handling 530

Primary Air Fans 1,300

Forced Draft Fans 1,660

Induced Draft Fans 7,050

SCR 50

Baghouse 70

Wet FGD 2,970

Miscellaneous Balance of Plant2,3 2,000

Steam Turbine Auxiliaries 400

Condensate Pumps 800

Circulating Water Pumps 4,730

Ground Water Pumps 480

Cooling Tower Fans 2,440

Transformer Losses 1,820

TOTAL AUXILIARIES, kWe 30,410

NET POWER, kWe 549,990

Net Plant Efficiency (HHV) 39.3%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,165 (8,687)

CONDENSER COOLING DUTY, 106 kJ/hr (106 Btu/hr) 2,298 (2,178)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 185,759 (409,528)

Limestone Sorbent Feed, kg/hr (lb/hr) 18,437 (40,646)

Thermal Input, kWt1 1,400,162

Raw Water Withdrawal, m3/min (gpm) 20.1 (5,321)

Raw Water Consumption, m3/min (gpm) 16.0 (4,227)

1. HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)

2. Boiler feed pumps are turbine driven

3. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Fossil Energy Plants

387

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 

2.4. A summary of the plant air emissions for Case 11 is presented in 

Environmental Performance

Exhibit 4-35.

Exhibit 4-35 Case 11 Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

85% CF

kg/MWh

(lb/MWh)

SO2 0.037 (0.086) 1,385 (1,526) 0.320 (.71)

NOx 0.030 (0.070) 1,130 (1,245) 0.261 (.576)

Particulates 0.006 (0.0130) 210 (231) 0.049 (.107)

Hg 4.91E-7 (1.14E-6) 0.018 (0.020) 4.27E-6 (9.41E-6)

CO2 87.5 (203.5) 3,284,245 

(3,620,261) 760 (1,675)

CO2

1 802 (1,768)

1 CO2 emissions based on net power instead of gross power

SO2 emissions are controlled using a wet limestone forced oxidation scrubber that achieves a 

removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site. 

The wallboard grade material can potentially be marketed and sold, but since it is highly 

dependent on local market conditions, no byproduct credit was taken. The saturated FG exiting 

the scrubber is vented through the plant stack.

NOx emissions are controlled to about 0.5 lb/106 Btu through the use of LNBs and OFA. An 

SCR unit then further reduces the NOx concentration by 86 percent to 0.07 lb/106 Btu.

Particulate emissions are controlled using a pulse jet fabric filter, which operates at an efficiency 

of 99.8 percent.

Co-benefit capture results in a 90 percent reduction of mercury emissions.

CO2 emissions represent the uncontrolled discharge from the process.

The carbon balance for the plant is shown in Exhibit 4-36. The carbon input to the plant consists 

of carbon in the coal, carbon in the air, and carbon in the limestone reagent used in the FGD. 

Carbon in the air is not neglected here since the Aspen model accounts for air components 

throughout. Carbon leaves the plant mostly as CO2 through the stack but also leaves as gypsum.

Exhibit 4-36 Case 11 Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 118,411 (261,052) Stack Gas 120,377 (265,385)

Air (CO2) 257 (567) FGD Product 163 (358)

FGD Reagent 1,871 (4,124)

Total 120,539 (265,744) Total 120,539 (265,744)
Cost and Performance Baseline for Fossil Energy Plants

388

Exhibit 4-37 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes sulfur emitted in the stack gas and the sulfur recovered from the 

FGD as gypsum.

Exhibit 4-37 Case 11 Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 4,656 (10,264) Stack Gas 93 (205)

FGD Product 4,563 (10,059)

Total 4,656 (10,264) Total 4,656 (10,264)

Exhibit 4-38 shows the overall water balance for the plant. Water demand represents the total 

amount of water required for a particular process. Some water is recovered within the process 

and is re-used as internal recycle. The difference between demand and recycle is raw water 

withdrawal. Raw water withdrawal is defined as the water removed from the ground or diverted 

from a surface-water source for use in the plant and was assumed to be provided 50 percent by a 

POTW and 50 percent from groundwater. Raw water withdrawal can be represented by the 

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

such as FDG makeup, BFW makeup, and cooling tower makeup. The difference between water 

withdrawal and process water discharge is defined as water consumption and can be represented 

by the portion of the raw water withdrawn that is evaporated, transpired, incorporated into 

products or otherwise not returned to the water source from which it was withdrawn. Water 

consumption represents the net impact of the plant process on the water source balance.

Exhibit 4-38 Case 11 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)

FGD Makeup 3.6 (951) 0.0 (0) 3.6 (951) 0.0 (0) 3.6 (951)

BFW Makeup 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

Cooling Tower 18.4 (4,863) 1.9 (492) 16.5 (4,370) 4.1 (1,094) 12.4 (3,277)

Total 22.0 (5,813) 1.9 (492) 20.1 (5,321) 4.1 (1,094) 16.0 (4,227)
Cost and Performance Baseline for Fossil Energy Plants

389

A heat and mass balance diagram is shown for the Case 11 PC boiler, the FGD unit and steam 

cycle in 

Heat and Mass Balance Diagrams

Exhibit 4-39 and Exhibit 4-40. An overall plant energy balance is provided in tabular 

form in Exhibit 4-41. The power out is the steam turbine power prior to generator losses. The 

power at the generator terminals (shown in Exhibit 4-34) is calculated by multiplying the power 

out by a generator efficiency of 98.4 percent.
Cost and Performance Baseline for Fossil Energy Plants

390

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

391

Exhibit 4-39 Case 11 Heat and Mass Balance, Supercritical PC Boiler without CO2 Capture

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Ash

Slurry

Synthesis Gas

Sour Gas

Sour Water

Water

Steam

PAGES

1 OF 2

BITUMINOUS BASELINE STUDY

CASE 11

SUPERCRITICAL PULVERIZED COAL

BOILER AND GAS CLEANUP SYSTEMS

DWG. NO.

BB-HMB-CS-11-PG-1

Pulverized

Coal

Boiler

AMMONIA SCR

INFILTRATION

AIR

AIR

AIR

COAL

ASH

From Feedwater

Heaters

Single Reheat

To IP Turbine

Throttle Steam

To HP Turbine

FGD

ASH

FORCED

DRAFT FANS

PRIMARY

AIR FANS

STACK

409,528 W

77.8 T

16.1 P

17.5 H

66.4 T

15.3 P

14.8 H

3,669,421 W

1,100.0 T

3,514.7 P

1,494.7 H

3,041,946 W

1,100.0 T

655.8 P

1,570.2 H

Single Reheat

Extraction from

HP Turbine

946,145 W

59.0 T

14.7 P

13.0 H

3,080,006 W

59.0 T

14.7 P

13.0 H

71,175 W

59.0 T

14.7 P

13.0 H

4,498,911 W

337.0 T

14.4 P

140.7 H

7,942 W

31,769 W

3,041,946 W

669.2 T

710.8 P

1,325.4 H

3,669,421 W

556.6 T

4,185.0 P

552.5 H

5

4,713,221 W

135.0 T

14.8 P

128.0 H

1 2

4

7

9

4,467,142 W ID FANS

337.0 T

14.2 P

132.8 H

Gross Plant Power: 580 MWe

Auxiliary Load: 30 MWe

Net Plant Power: 550 MWe

Net Plant Efficiency, HHV: 39.3%

Net Plant Heat Rate: 8,687 BTU/KWe

Lime/Ash

Flue Gas

OXIDATION 

AIR

MAKE-UP 

WATER

LIMESTONE 

SLURRY

GYPSUM

15

14

11

357.4 T

15.3 P

138.0 H

134,744 W

59.0 T

15.0 P

46,465 W

332.9 T

45.0 P

381,174 W

59.0 T

14.7 P

70,244 W

135.0 T

14.8 P

Baghouse

3

6

8

10

12 13

16

17

19 18

20

21

DOE/NETL

SC PC PLANT

CASE 11
Cost and Performance Baseline for Fossil Energy Plants

392

Exhibit 4-40 Case 11 Heat and Mass Balance, Supercritical Steam Cycle

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Sour Gas

Sour Water

Water

Steam

PAGES

2 OF 2

DWG. NO.

BB-HMB-CS-11-PG-2

BITUMINOUS BASELINE STUDY

CASE 11

SUPERCRITICAL PULVERIZED COAL

POWER BLOCK SYSTEMS

LP TURBINE GENERATOR HP

TURBINE

IP

TURBINE

CONDENSER

HOT WELL

P-1028 P-1048

To Boiler

BOILER FEED

PUMP TURBINE 

DRIVES

STEAM SEAL

REGULATOR

Throttle

Steam

Single Reheat

Extraction

From Boiler

GLAND SEAL

CONDENSER

CONDENSATE

PUMPS

3,669,421 W

1,100.0 T

3,514.7 P

1,494.7 H

2,900.0 P

169,635 W

888.4 T

300.8 P

1,467.0 H

327,489 W

663.9 T

689.5 P

1,323.6 H

Single Reheat

Extraction to

Boiler 3,041,946 W

669.2 T

710.8 P

1,325.4 H

710.8 P

1,115.5 P

269,128 W

772.0 T

1,085.0 P

1,367.5 H

710.8 P

710.8 P

310.1 P

137.7 P

137.7 P

223,857 W

687.5 T

134.9 P

1,370.8 H

223,857 W

126.1 T

2.0 P

1,093.5 H 2,775,839 W

101.1 T

1.0 P

853.8 H

2,793 W

212.0 T

14.7 P

179.9 H

72.7 P19.2 P

8.4 P

101.4 T

250.0 P

70.0 H

2,793 W

713.5 T

137.7 P

1,383.8 H

2,775,839 W

101.1 T

1.0 P

69.1 H

2,775,839 W

102.6 T

245.0 P

71.2 H

2,775,839 W

141.4 T

240.0 P

109.8 H

480,444 W

112.6 T

1.4 P

80.5 H

388,060 W

151.4 T

3.9 P

119.2 H

2,775,839 W

296.9 T

225.0 P

266.5 H

766,252 W

369.5 T

172.2 P

341.9 H

2,775,839 W

218.0 T

230.0 P

186.4 H

596,617 W

429.6 T

342.2 P

407.0 H

269,128 W

511.5 T

753.7 P

501.2 H

3,669,421 W

419.6 T

4,195.0 P

400.2 H

3,669,421 W

501.5 T

4,190.0 P

488.9 H

DEAERATOR

BOILER

FEED PUMPS

3,669,421 W

556.6 T

4,185.0 P

552.5 H

3,041,946 W

1,100.0 T

655.8 P

1,570.2 H

200,638 W

228.0 T

20.0 P

196.0 H

299,542 W

188.4 T

9.0 P

156.2 H

2,775,839 W

178.4 T

235.0 P

146.7 H

127,330 W

696.6 T

133.6 P

1,375.5 H

200,638 W

545.6 T

69.0 P

1,304.2 H

98,904 W

293.8 T

18.2 P

1,188.3 H

88,519 W

211.3 T

8.1 P

1,152.2 H

92,383 W

146.4 T

3.4 P

1,077.8 H

2,900.0 P

2,762,263 W

687.5 T

134.9 P

2,538,406 W

687.5 T

134.9 P

1,370.8 H

3.5 P

2,900.0 P

359.5 T

4,200.0 P

337.6 H

3,669,421 W

349.4 T

133.6 P

320.7 H

3,301 W

713.5 T

137.7 P

1,383.8 H

Gross Plant Power: 580 MWe

Auxiliary Load: 30 MWe

Net Plant Power: 550 MWe

Net Plant Efficiency, HHV: 39.3%

Net Plant Heat Rate: 8,687 BTU/KWe

FWH 4 FWH 3 FWH 2 FWH 1 FWH 8 FWH 7 FWH 6

7,482 W

713.5 T

137.7 P

1,383.8 H

19

20

21

22

23

DOE/NETL

SC PC PLANT

CASE 11
Cost and Performance Baseline for Fossil Energy Plants

393

Exhibit 4-41 Case 11 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,041 (4,778) 4.2 (4.0) 5,045 (4,782)

Air 56.2 (53.2) 56.2 (53.2)

Raw Water Makeup 76.8 (72.8) 76.8 (72.8)

Limestone 0.21 (0.20) 0.21 (0.20)

Auxiliary Power 110 (104) 110 (104)

Totals 5,041 (4,778) 137.4 (130.3) 110 (104) 5,288 (5,012)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.4 (0.4) 0.4 (0.4)

Fly Ash + FGD Ash 1.7 (1.7) 1.7 (1.7)

Flue Gas 636 (603) 636 (603)

Condenser 2,298 (2,178) 2,298 (2,178)

Cooling Tower 

Blowdown 30.8 (29.2) 30.8 (29.2)

Process Losses* 231 (219) 231 (219)

Power 2,089 (1,980) 2,089 (1,980)

Totals 0 (0) 3,198 (3,031) 2,089 (1,980) 5,288 (5,012)

* Process losses are estimated to match the heat input to the plant. Process losses include 

losses from: turbines, gas cooling, etc.
Cost and Performance Baseline for Fossil Energy Plants

394

4.3.5

Major equipment items for the SC PC plant 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 

Case 11 – Major Equipment List 

4.3.6. In general, the design conditions include a 10 percent 

contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 FUEL AND SORBENT HANDLING

Equipment 

No. Description Type Design Condition 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 36 tonne (40 ton) 2 1

9 Feeder Vibratory 154 tonne/hr (170 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 308 tonne/hr (340 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 154 tonne (170 ton) 2 0

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3 in x 0 - 1-1/4 in x 0) 2 0

14 As-Fired Coal Sampling 

System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 308 tonne/hr (340 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 308 tonne/hr (340 tph) 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 726 tonne (800 ton) 3 0

19 Limestone Truck Unloading 

Hopper

N/A 36 tonne (40 ton) 1 0

20 Limestone Feeder Belt 82 tonne/hr (90 tph) 1 0

21 Limestone Conveyor No. L1 Belt 82 tonne/hr (90 tph) 1 0

22 Limestone Reclaim Hopper N/A 18 tonne (20 ton) 1 0

23 Limestone Reclaim Feeder Belt 64 tonne/hr (70 tph) 1 0

24 Limestone Conveyor No. L2 Belt 64 tonne/hr (70 tph) 1 0

25 Limestone Day Bin w/ actuator 245 tonne (270 ton) 2 0
Cost and Performance Baseline for Fossil Energy Plants

395

ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Coal Feeder Gravimetric 36 tonne/hr (40 tph) 6 0

2 Coal Pulverizer Ball type or 

equivalent 36 tonne/hr (40 tph) 6 0

3 Limestone Weigh Feeder Gravimetric 20 tonne/hr (22 tph) 1 1

4 Limestone Ball Mill Rotary 20 tonne/hr (22 tph) 1 1

5 Limestone Mill Slurry Tank 

with Agitator N/A 75,708 liters (20,000 gal) 1 1

6 Limestone Mill Recycle 

Pumps

Horizontal 

centrifugal

1,287 lpm @ 12m H2O (340 gpm 

@ 40 ft H2O) 1 1

7 Hydroclone Classifier

4 active 

cyclones in a 5 

cyclone bank

341 lpm (90 gpm) per cyclone 1 1

8 Distribution Box 2-way N/A 1 1

9 Limestone Slurry Storage 

Tank with Agitator Field erected 439,108 liters (116,000 gal) 1 1

10 Limestone Slurry Feed 

Pumps

Horizontal 

centrifugal

908 lpm @ 9m H2O (240 gpm @ 

30 ft H2O) 1 1
Cost and Performance Baseline for Fossil Energy Plants

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 1,101,555 liters (291,000 gal) 2 0

2 Condensate Pumps Vertical canned 23,091 lpm @ 213 m H2O (6,100 

gpm @ 700 ft H2O) 1 1

3 Deaerator and Storage 

Tank Horizontal spray type 1,830,699 kg/hr (4,036,000 lb/hr), 

5 min. tank 1 0

4 Boiler Feed 

Pump/Turbine

Barrel type, multi-stage, 

centrifugal

30,662 lpm @ 3,444 m H2O 

(8,100 gpm @ 11,300 ft H2O) 1 1

5

Startup Boiler Feed 

Pump, Electric Motor 

Driven

Barrel type, multi-stage, 

centrifugal

9,085 lpm @ 3,444 m H2O (2,400 

gpm @ 11,300 ft H2O) 1 0

6 LP Feedwater Heater 

1A/1B Horizontal U-tube 693,996 kg/hr (1,530,000 lb/hr) 2 0

7

LP Feedwater Heater 

2A/2B Horizontal U-tube 693,996 kg/hr (1,530,000 lb/hr) 2 0

8 LP Feedwater Heater 

3A/3B Horizontal U-tube 693,996 kg/hr (1,530,000 lb/hr) 2 0

9 LP Feedwater Heater 

4A/4B Horizontal U-tube 693,996 kg/hr (1,530,000 lb/hr) 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 1,832,513 kg/hr (4,040,000 lb/hr) 1 0

11 HP Feedwater Heater 7 Horizontal U-tube 1,832,513 kg/hr (4,040,000 lb/hr) 1 0

12 HP Feedwater heater 8 Horizontal U-tube 1,832,513 kg/hr (4,040,000 lb/hr) 1 0

13 Auxiliary Boiler Shop fabricated, water 

tube

18,144 kg/hr, 2.8 MPa, 343°C 

(40,000 lb/hr, 400 psig, 650°F) 1 0

14 Fuel Oil System No. 2 fuel oil for light 

off 1,135,624 liter (300,000 gal) 1 0

15 Service Air 

Compressors Flooded Screw 28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

16 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

17 Closed Cycle Cooling 

Heat Exchangers Shell and tube 53 GJ/hr (50 MMBtu/hr) each 2 0

18 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 20,820 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 2 1

19 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 88 m H2O (1,000 

gpm @ 290 ft H2O) 1 1

20 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 64 m H2O (700 gpm 

@ 210 ft H2O) 1 1

21 Raw Water Pumps Stainless steel, single 

suction

5,943 lpm @ 18 m H2O (1,570 

gpm @ 60 ft H2O) 2 1

22 Ground Water Pumps Stainless steel, single 

suction

2,385 lpm @ 268 m H2O (630 

gpm @ 880 ft H2O) 5 1

23 Filtered Water Pumps Stainless steel, single 

suction

1,893 lpm @ 49 m H2O (500 gpm 

@ 160 ft H2O) 2 1

24 Filtered Water Tank Vertical, cylindrical 1,816,998 liter (480,000 gal) 1 0

25 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly, 

electrodeionization unit

606 lpm (160 gpm) 1 1

26 Liquid Waste Treatment 

System -- 10 years, 24-hour storm 1 0
Cost and Performance Baseline for Fossil Energy Plants

397

ACCOUNT 4 BOILER AND ACCESSORIES

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Boiler

Supercritical, drum, 

wall-fired, low NOx 

burners, overfire air

1,832,513 kg/hr steam @ 25.5 

MPa/602°C/602°C (4,040,000 

lb/hr steam @ 3,700 

psig/1,115°F/1,115°F)

1 0

2 Primary Air Fan Centrifugal

235,868 kg/hr, 3,220 m3/min @ 

123 cm WG (520,000 lb/hr, 

113,700 acfm @ 48 in. WG)

2 0

3 Forced Draft Fan Centrifugal

768,385 kg/hr, 10,486 m3/min @ 

47 cm WG (1,694,000 lb/hr, 

370,300 acfm @ 19 in. WG)

2 0

4 Induced Draft Fan Centrifugal

1,114,476 kg/hr, 23,469 m3/min 

@ 91 cm WG (2,457,000 lb/hr, 

828,800 acfm @ 36 in. WG)

2 0

5 SCR Reactor Vessel Space for spare 

layer 2,227,139 kg/hr (4,910,000 lb/hr) 2 0

6 SCR Catalyst -- -- 3 0

7 Dilution Air Blower Centrifugal 133 m3/min @ 108 cm WG 

(4,700 acfm @ 42 in. WG) 2 1

8 Ammonia Storage Horizontal tank 147,631 liter (39,000 gal) 5 0

9 Ammonia Feed 

Pump Centrifugal 28 lpm @ 91 m H2O (7 gpm @ 

300 ft H2O) 2 1
Cost and Performance Baseline for Fossil Energy Plants

398

ACCOUNT 5 FLUE GAS CLEANUP

ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES 

N/A

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Fabric Filter

Single stage, highratio with pulse-jet 

online cleaning 

system

1,114,476 kg/hr (2,457,000 lb/hr) 

99.8% efficiency 2 0

2 Absorber Module Counter-current 

open spray

44,769 m3/min (1,581,000 acfm) 1 0

3 Recirculation Pumps Horizontal 

centrifugal

155,202 lpm @ 64 m H2O 

(41,000 gpm @ 210 ft H2O) 5 1

4 Bleed Pumps Horizontal 

centrifugal

3,975 lpm (1,050 gpm) at 20 wt% 

solids 2 1

5 Oxidation Air Blowers Centrifugal 78 m3/min @ 0.3 MPa (2,770 

acfm @ 37 psia) 2 1

6 Agitators Side entering 50 hp 5 1

7 Dewatering Cyclones Radial assembly, 

5 units each 984 lpm (260 gpm) per cyclone 2 0

8 Vacuum Filter Belt Horizontal belt 32 tonne/hr (35 tph) of 50 wt % 

slurry 2 1

9 Filtrate Water Return 

Pumps

Horizontal 

centrifugal

606 lpm @ 12 m H2O (160 gpm 

@ 40 ft H2O) 1 1

10 Filtrate Water Return 

Storage Tank Vertical, lined 378,541 lpm (100,000 gal) 1 0

11 Process Makeup Water 

Pumps

Horizontal 

centrifugal

3,180 lpm @ 21 m H2O (840 gpm 

@ 70 ft H2O) 1 1
Cost and Performance Baseline for Fossil Energy Plants

399

ACCOUNT 7 HRSG, DUCTING & STACK

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack Reinforced concrete 

with FRP liner

152 m (500 ft) high x

5.6 m (19 ft) diameter 1 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

611 MW

24.1 MPa/593°C/593°C 

(3500 psig/ 

1100°F/1100°F)

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitation

680 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase 1 0

3 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

2,532 GJ/hr (2,400 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 

11°C (20°F)

1 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water 

Pumps Vertical, wet pit 473,200 lpm @ 30 m(125,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

/ 2648 GJ/hr (2510 MMBtu/hr) 

heat duty

1 0
Cost and Performance Baseline for Fossil Energy Plants

400

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Economizer Hopper (part of 

boiler scope of supply) -- -- 4 0

2 Bottom Ash Hopper (part of 

boiler scope of supply) -- -- 2 0

3 Clinker Grinder -- 3.6 tonne/hr (4 tph) 1 1

4

Pyrites Hopper (part of 

pulverizer scope of supply 

included with boiler)

-- -- 6 0

5 Hydroejectors -- -- 12

6 Economizer /Pyrites Transfer 

Tank -- -- 1 0

7 Ash Sluice Pumps Vertical, wet pit 151 lpm @ 17 m H2O (40 gpm 

@ 56 ft H2O) 1 1

8 Ash Seal Water Pumps Vertical, wet pit 7,571 lpm @ 9 m H2O (2000 

gpm @ 28 ft H2O) 1 1

9 Hydrobins -- 151 lpm (40 gpm) 1 1

10 Baghouse Hopper (part of 

baghouse scope of supply) -- -- 24 0

11 Air Heater Hopper (part of 

boiler scope of supply) -- -- 10 0

12 Air Blower -- 14 m3/min @ 0.2 MPa (510 

scfm @ 24 psi) 1 1

13 Fly Ash Silo Reinforced 

concrete 907 tonne (1,000 ton) 2 0

14 Slide Gate Valves -- -- 2 0

15 Unloader -- -- 1 0

16 Telescoping Unloading Chute -- 91 tonne/hr (100 tph) 1 0
Cost and Performance Baseline for Fossil Energy Plants

401

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 STG Transformer Oil-filled 24 kV/345 kV, 650 MVA, 3-

ph, 60 Hz 1 0

2 Auxiliary 

Transformer Oil-filled 24 kV/4.16 kV, 32 MVA, 3-ph, 60 Hz 1 1

3 Low Voltage 

Transformer Dry ventilated 4.16 kV/480 V, 5 MVA, 3-ph, 60 Hz

1 1

4

STG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0

5 Medium Voltage 

Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

6 Low Voltage 

Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

7 Emergency Diesel 

Generator

Sized for emergency 

shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0

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 for Fossil Energy Plants

402

4.3.6

The cost estimating methodology was described previously in Section 

Case 11 – Costs Estimating Results

2.7. Exhibit 4-42 shows 

the total plant capital cost summary organized by cost account and Exhibit 4-43 shows a more 

detailed breakdown of the capital costs as well as owner’s costs, TOC, and TASC. Exhibit 4-44

shows the initial and annual O&M costs.

The estimated TOC of the SC PC boiler with no CO2 capture is $2,024/kW. No process 

contingency was included in this case because all elements of the technology are commercially 

proven. The project contingency is 8.7 percent of the TOC. The COE is 58.9 mills/kWh.
Cost and Performance Baseline for Fossil Energy Plants

403

Exhibit 4-42 Case 11 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14

Project: Bituminous Baseline Study

Case: Case 11 - 1x550 MWnet SuperCritical PC

Plant Size: 550.0 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 $16,381 $4,414 $9,819 $0 $0 $30,614 $2,747 $0 $5,004 $38,365 $70

 2 COAL & SORBENT PREP & FEED $11,008 $637 $2,793 $0 $0 $14,438 $1,265 $0 $2,356 $18,059 $33

 3 FEEDWATER & MISC. BOP SYSTEMS $42,453 $0 $19,927 $0 $0 $62,380 $5,705 $0 $11,064 $79,149 $144

 4 PC BOILER

4.1 PC Boiler & Accessories $157,253 $0 $88,235 $0 $0 $245,488 $23,891 $0 $26,938 $296,317 $539

4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4 $157,253 $0 $88,235 $0 $0 $245,488 $23,891 $0 $26,938 $296,317 $539

 5 FLUE GAS CLEANUP $79,643 $0 $27,049 $0 $0 $106,692 $10,211 $0 $11,690 $128,593 $234

 5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

7.2-7.9 HRSG Accessories, Ductwork and Stack $17,397 $1,000 $11,814 $0 $0 $30,211 $2,773 $0 $4,307 $37,291 $68

SUBTOTAL 7 $17,397 $1,000 $11,814 $0 $0 $30,211 $2,773 $0 $4,307 $37,291 $68

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $51,625 $0 $6,866 $0 $0 $58,491 $5,606 $0 $6,410 $70,507 $128

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $22,954 $1,089 $12,590 $0 $0 $36,633 $3,228 $0 $5,580 $45,441 $83

SUBTOTAL 8 $74,579 $1,089 $19,456 $0 $0 $95,124 $8,833 $0 $11,990 $115,948 $211

 9 COOLING WATER SYSTEM $12,303 $6,296 $11,466 $0 $0 $30,066 $2,830 $0 $4,475 $37,370 $68

10 ASH/SPENT SORBENT HANDLING SYS $4,409 $140 $5,895 $0 $0 $10,444 $1,004 $0 $1,178 $12,627 $23

11 ACCESSORY ELECTRIC PLANT $17,541 $6,187 $18,041 $0 $0 $41,769 $3,682 $0 $5,617 $51,068 $93

12 INSTRUMENTATION & CONTROL $8,739 $0 $8,862 $0 $0 $17,601 $1,596 $0 $2,358 $21,555 $39

13 IMPROVEMENTS TO SITE $2,969 $1,707 $5,984 $0 $0 $10,660 $1,052 $0 $2,342 $14,054 $26

14 BUILDINGS & STRUCTURES $0 $22,720 $21,552 $0 $0 $44,272 $3,994 $0 $7,240 $55,506 $101

 

TOTAL COST $444,675 $44,192 $250,892 $0 $0 $739,759 $69,584 $0 $96,558 $905,901 $1,647

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline for Fossil Energy Plants

404

Exhibit 4-43 Case 11 Total Plant Cost Details

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 $3,368 $0 $1,538 $0 $0 $4,906 $438 $0 $802 $6,146 $11

1.2 Coal Stackout & Reclaim $4,352 $0 $986 $0 $0 $5,338 $467 $0 $871 $6,676 $12

1.3 Coal Conveyors $4,046 $0 $976 $0 $0 $5,022 $440 $0 $819 $6,282 $11

1.4 Other Coal Handling $1,059 $0 $226 $0 $0 $1,284 $112 $0 $209 $1,606 $3

1.5 Sorbent Receive & Unload $135 $0 $41 $0 $0 $175 $15 $0 $29 $219 $0

1.6 Sorbent Stackout & Reclaim $2,176 $0 $399 $0 $0 $2,574 $224 $0 $420 $3,218 $6

1.7 Sorbent Conveyors $776 $168 $190 $0 $0 $1,135 $98 $0 $185 $1,418 $3

1.8 Other Sorbent Handling $469 $110 $246 $0 $0 $825 $73 $0 $135 $1,032 $2

1.9 Coal & Sorbent Hnd.Foundations $0 $4,136 $5,218 $0 $0 $9,354 $879 $0 $1,535 $11,767 $21

SUBTOTAL 1. $16,381 $4,414 $9,819 $0 $0 $30,614 $2,747 $0 $5,004 $38,365 $70

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $1,929 $0 $376 $0 $0 $2,305 $201 $0 $376 $2,881 $5

2.2 Coal Conveyor to Storage $4,939 $0 $1,078 $0 $0 $6,017 $526 $0 $981 $7,524 $14

2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.5 Sorbent Prep Equipment $3,695 $159 $768 $0 $0 $4,622 $402 $0 $754 $5,778 $11

2.6 Sorbent Storage & Feed $445 $0 $171 $0 $0 $616 $55 $0 $101 $771 $1

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 $478 $401 $0 $0 $879 $81 $0 $144 $1,105 $2

SUBTOTAL 2. $11,008 $637 $2,793 $0 $0 $14,438 $1,265 $0 $2,356 $18,059 $33

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 FeedwaterSystem $18,623 $0 $6,016 $0 $0 $24,638 $2,153 $0 $4,019 $30,810 $56

3.2 Water Makeup & Pretreating $4,460 $0 $1,436 $0 $0 $5,895 $557 $0 $1,291 $7,743 $14

3.3 Other Feedwater Subsystems $5,701 $0 $2,409 $0 $0 $8,111 $727 $0 $1,326 $10,163 $18

3.4 Service Water Systems $874 $0 $476 $0 $0 $1,350 $127 $0 $295 $1,772 $3

3.5 Other Boiler Plant Systems $6,807 $0 $6,721 $0 $0 $13,528 $1,285 $0 $2,222 $17,035 $31

3.6 FO Supply Sys & Nat Gas $255 $0 $319 $0 $0 $574 $54 $0 $94 $723 $1

3.7 Waste Treatment Equipment $3,024 $0 $1,724 $0 $0 $4,747 $462 $0 $1,042 $6,251 $11

3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,709 $0 $828 $0 $0 $3,536 $340 $0 $775 $4,652 $8

SUBTOTAL 3. $42,453 $0 $19,927 $0 $0 $62,380 $5,705 $0 $11,064 $79,149 $144

 4 PC BOILER

4.1 PC Boiler & Accessories $157,253 $0 $88,235 $0 $0 $245,488 $23,891 $0 $26,938 $296,317 $539

4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4. $157,253 $0 $88,235 $0 $0 $245,488 $23,891 $0 $26,938 $296,317 $539
Cost and Performance Baseline for Fossil Energy Plants

405

Exhibit 4-43 Case 11 Total Plant Cost Details (Continued)

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

 5 FLUE GAS CLEANUP

5.1 Absorber Vessels & Accessories $55,471 $0 $11,942 $0 $0 $67,413 $6,427 $0 $7,384 $81,224 $148

5.2 Other FGD $2,895 $0 $3,280 $0 $0 $6,175 $599 $0 $677 $7,452 $14

5.3 Bag House & Accessories $15,622 $0 $9,914 $0 $0 $25,536 $2,461 $0 $2,800 $30,797 $56

5.4 Other Particulate Removal Materials $1,057 $0 $1,131 $0 $0 $2,189 $212 $0 $240 $2,641 $5

5.5 Gypsum Dewatering System $4,598 $0 $781 $0 $0 $5,379 $512 $0 $589 $6,480 $12

5.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5. $79,643 $0 $27,049 $0 $0 $106,692 $10,211 $0 $11,690 $128,593 $234

 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 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $8,675 $0 $5,574 $0 $0 $14,249 $1,242 $0 $2,324 $17,816 $32

7.4 Stack $8,721 $0 $5,103 $0 $0 $13,824 $1,331 $0 $1,516 $16,671 $30

7.9 Duct & Stack Foundations $0 $1,000 $1,137 $0 $0 $2,137 $200 $0 $467 $2,804 $5

SUBTOTAL 7. $17,397 $1,000 $11,814 $0 $0 $30,211 $2,773 $0 $4,307 $37,291 $68

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $51,625 $0 $6,866 $0 $0 $58,491 $5,606 $0 $6,410 $70,507 $128

8.2 Turbine Plant Auxiliaries $347 $0 $744 $0 $0 $1,091 $107 $0 $120 $1,317 $2

8.3 Condenser & Auxiliaries $6,712 $0 $2,288 $0 $0 $9,000 $861 $0 $986 $10,848 $20

8.4 Steam Piping $15,895 $0 $7,837 $0 $0 $23,732 $1,994 $0 $3,859 $29,585 $54

8.9 TG Foundations $0 $1,089 $1,721 $0 $0 $2,810 $266 $0 $615 $3,691 $7

SUBTOTAL 8. $74,579 $1,089 $19,456 $0 $0 $95,124 $8,833 $0 $11,990 $115,948 $211

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $9,084 $0 $2,829 $0 $0 $11,913 $1,139 $0 $1,305 $14,358 $26

9.2 Circulating Water Pumps $1,887 $0 $116 $0 $0 $2,003 $169 $0 $217 $2,389 $4

9.3 Circ.Water System Auxiliaries $498 $0 $66 $0 $0 $565 $54 $0 $62 $680 $1

9.4 Circ.Water Piping $0 $3,950 $3,828 $0 $0 $7,779 $728 $0 $1,276 $9,783 $18

9.5 Make-up Water System $438 $0 $585 $0 $0 $1,024 $98 $0 $168 $1,290 $2

9.6 Component Cooling Water Sys $395 $0 $314 $0 $0 $709 $67 $0 $116 $892 $2

9.9 Circ.Water System Foundations& Structures $0 $2,346 $3,727 $0 $0 $6,073 $575 $0 $1,330 $7,977 $15

SUBTOTAL 9. $12,303 $6,296 $11,466 $0 $0 $30,066 $2,830 $0 $4,475 $37,370 $68
Cost and Performance Baseline for Fossil Energy Plants

406

Exhibit 4-43 Case 11 Total Plant Cost Details (Continued)

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 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $590 $0 $1,818 $0 $0 $2,408 $236 $0 $264 $2,909 $5

10.7 Ash Transport & Feed Equipment $3,819 $0 $3,912 $0 $0 $7,731 $739 $0 $847 $9,317 $17

10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.9 Ash/Spent Sorbent Foundation $0 $140 $165 $0 $0 $305 $29 $0 $67 $401 $1

SUBTOTAL 10. $4,409 $140 $5,895 $0 $0 $10,444 $1,004 $0 $1,178 $12,627 $23

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $1,598 $0 $260 $0 $0 $1,858 $172 $0 $152 $2,182 $4

11.2 Station Service Equipment $2,824 $0 $928 $0 $0 $3,752 $351 $0 $308 $4,410 $8

11.3 Switchgear & Motor Control $3,247 $0 $552 $0 $0 $3,798 $352 $0 $415 $4,565 $8

11.4 Conduit & Cable Tray $0 $2,035 $7,038 $0 $0 $9,073 $878 $0 $1,493 $11,445 $21

11.5 Wire & Cable $0 $3,841 $7,414 $0 $0 $11,255 $948 $0 $1,830 $14,034 $26

11.6 Protective Equipment $260 $0 $885 $0 $0 $1,146 $112 $0 $126 $1,383 $3

11.7 Standby Equipment $1,277 $0 $29 $0 $0 $1,306 $120 $0 $143 $1,568 $3

11.8 Main Power Transformers $8,335 $0 $172 $0 $0 $8,507 $646 $0 $915 $10,068 $18

11.9 Electrical Foundations $0 $311 $763 $0 $0 $1,074 $103 $0 $235 $1,412 $3

SUBTOTAL 11. $17,541 $6,187 $18,041 $0 $0 $41,769 $3,682 $0 $5,617 $51,068 $93

12 INSTRUMENTATION & CONTROL

12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $450 $0 $270 $0 $0 $720 $68 $0 $118 $906 $2

12.7 Distributed Control System Equipment $4,543 $0 $794 $0 $0 $5,337 $495 $0 $583 $6,415 $12

12.8 Instrument Wiring & Tubing $2,463 $0 $4,885 $0 $0 $7,348 $626 $0 $1,196 $9,170 $17

12.9 Other I & C Equipment $1,284 $0 $2,913 $0 $0 $4,197 $407 $0 $460 $5,064 $9

SUBTOTAL 12. $8,739 $0 $8,862 $0 $0 $17,601 $1,596 $0 $2,358 $21,555 $39
Cost and Performance Baseline for Fossil Energy Plants

407

Exhibit 4-43 Case 11 Total Plant Cost Details (Continued)

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

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $50 $998 $0 $0 $1,048 $104 $0 $230 $1,382 $3

13.2 Site Improvements $0 $1,657 $2,058 $0 $0 $3,715 $366 $0 $816 $4,897 $9

13.3 Site Facilities $2,969 $0 $2,928 $0 $0 $5,897 $581 $0 $1,296 $7,774 $14

SUBTOTAL 13. $2,969 $1,707 $5,984 $0 $0 $10,660 $1,052 $0 $2,342 $14,054 $26

14 BUILDINGS & STRUCTURES

14.1 Boiler Building $0 $8,281 $7,282 $0 $0 $15,564 $1,399 $0 $2,544 $19,507 $35

14.2 Turbine Building $0 $11,828 $11,024 $0 $0 $22,851 $2,060 $0 $3,737 $28,648 $52

14.3 Administration Building $0 $586 $620 $0 $0 $1,206 $109 $0 $197 $1,513 $3

14.4 Circulation Water Pumphouse $0 $168 $134 $0 $0 $301 $27 $0 $49 $378 $1

14.5 Water Treatment Buildings $0 $566 $516 $0 $0 $1,081 $97 $0 $177 $1,356 $2

14.6 Machine Shop $0 $392 $264 $0 $0 $656 $58 $0 $107 $821 $1

14.7 Warehouse $0 $266 $267 $0 $0 $532 $48 $0 $87 $668 $1

14.8 Other Buildings & Structures $0 $217 $185 $0 $0 $402 $36 $0 $66 $504 $1

14.9 Waste Treating Building & Str. $0 $416 $1,262 $0 $0 $1,678 $159 $0 $276 $2,112 $4

SUBTOTAL 14. $0 $22,720 $21,552 $0 $0 $44,272 $3,994 $0 $7,240 $55,506 $101

TOTAL COST $444,675 $44,192 $250,892 $0 $0 $739,759 $69,584 $0 $96,558 $905,901 $1,647

Owner's Costs

Preproduction Costs

6 Months All Labor $7,258 $13

1 Month Maintenance Materials $895 $2

1 Month Non-fuel Consumables $892 $2

1 Month Waste Disposal $235 $0

25% of 1 Months Fuel Cost at 100% CF $1,427 $3

2% of TPC $18,118 $33

Total $28,826 $52

Inventory Capital

60 day supply of fuel and consumables at 100% CF $12,944 $24

0.5% of TPC (spare parts) $4,530 $8

Total $17,474 $32

Initial Cost for Catalyst and Chemicals $0 $0

Land $900 $2

Other Owner's Costs $135,885 $247

Financing Costs $24,459 $44

Total Overnight Costs (TOC) $1,113,445 $2,024

TASC Multiplier (IOU, low-risk, 35 year) 1.134

Total As-Spent Cost (TASC) $1,262,647 $2,296
Cost and Performance Baseline for Fossil Energy Plants

408

Exhibit 4-44 Case 11 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 11 - 1x550 MWnet SuperCritical PC Heat Rate-net (Btu/kWh): 8,686

MWe-net: 550

 Capacity Factor (%): 85

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

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 2.0 2.0

 Operator 9.0 9.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 2.0 2.0

 TOTAL-O.J.'s 14.0 14.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $5,524,319 $10.044

Maintenance Labor Cost $6,088,905 $11.070

Administrative & Support Labor $2,903,306 $5.279

Property Taxes and Insurance $18,118,017 $32.941

TOTAL FIXED OPERATING COSTS $32,634,546 $59.333

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $9,133,357 $0.00223

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water (/1000 gallons) 0 3,884 1.08 $0 $1,303,324 $0.00032

Chemicals

MU & WT Chem.(lbs) 0 18,799 0.17 $0 $1,009,427 $0.00025

Limestone (ton) 0 488 21.63 $0 $3,273,667 $0.00080

Carbon (Mercury Removal) (lb) 0 0 1.05 $0 $0 $0.00000

MEA Solvent (ton) 0 0 2,249.89 $0 $0 $0.00000

NaOH (tons) 0 0 433.68 $0 $0 $0.00000

H2SO4 (tons) 0 0 138.78 $0 $0 $0.00000

Corrosion Inhibitor 0 0 0.00 $0 $0 $0.00000

Activated Carbon (lb) 0 0 1.05 $0 $0 $0.00000

Ammonia (19% NH3) ton 0 74 129.80 $0 $2,960,869 $0.00072

Subtotal Chemicals $0 $7,243,963 $0.00177

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000

SCR Catalyst (m3) w/equip. 0.31 5,775.94 $0 $553,798 $0.00014

Emission Penalties 0 0 0.00 $0 $0 $0.00000

Subtotal Other $0 $553,798 $0.00014

Waste Disposal

Fly Ash (ton) 0 381 16.23 $0 $1,919,038 $0.00047

Bottom Ash (ton) 0 95 16.23 $0 $479,759 $0.00012

 Subtotal-Waste Disposal $0 $2,398,797 $0.00059

By-products & Emissions 

 Gypsum (tons) 0 759 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $0 $20,633,239 $0.00504

Fuel (ton) 0 4,914 38.18 $0 $58,217,892 $0.01422
Cost and Performance Baseline for Fossil Energy Plants

409

4.3.7

The plant configuration for Case 12, SC PC, is the same as Case 11 with the exception that the 

Econamine CDR technology was added for CO2 capture. The nominal net output is maintained 

at 550 MW by increasing the boiler size and turbine/generator size to account for the greater 

auxiliary load imposed by the CDR facility. Unlike the IGCC cases where gross output was 

fixed by the available size of the CTs, the PC cases utilize boilers and steam turbines that can be 

procured at nearly any desired output making it possible to maintain a constant net output.

Case 12 – Supercritical PC with CO2 Capture

The process description for Case 12 is essentially the same as Case 11 with one notable 

exception, the addition of CO2 capture. A BFD and stream tables for Case 12 are shown in 

Exhibit 4-45 and Exhibit 4-46, respectively. Since the CDR facility process description was 

provided in Section 4.1.7, it is not repeated here.

4.3.8

The Case 12 modeling assumptions were presented previously in Section 

Case 12 Performance Results

4.3.2.

The plant produces a net output of 550 MW at a net plant efficiency of 28.4 percent (HHV 

basis). Overall plant performance is summarized in Exhibit 4-47, which includes auxiliary 

power requirements. The CDR facility, including CO2 compression, accounts for approximately

58 percent of the auxiliary plant load. The CWS (CWPs and cooling tower fan) accounts for 

over 13 percent of the auxiliary load, largely due to the high cooling water demand of the CDR 

facility
Cost and Performance Baseline for Fossil Energy Plants

410

Exhibit 4-45 Case 12 Block Flow Diagram, Supercritical Unit with CO2 Capture
Cost and Performance Baseline for Fossil Energy Plants

411

Exhibit 4-46 Case 12 Stream Table, Supercritical Unit with CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 0.0000

CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 1.0000

N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 0.0000

O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 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 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 66,876 66,876 1,990 20,544 20,544 2,818 1,546 0 0 94,107 0 94,107 94,107 3,385

V-L Flowrate (kg/hr) 1,929,852 1,929,852 57,422 592,830 592,830 81,325 44,605 0 0 2,799,052 0 2,799,052 2,799,052 60,975

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 256,652 4,977 19,910 19,910 0 0 25,966

Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169 182 15

Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 0.10

Enthalpy (kJ/kg)A 30.23 34.36 34.36 30.23 40.78 40.78 30.23 --- --- 327.40 --- 308.96 322.83 ---

Density (kg/m3

) 1.2 1.2 1.2 1.2 1.3 1.3 1.2 --- --- 0.8 --- 0.8 0.8 ---

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857 --- --- 29.743 --- 29.743 29.743 ---

V-L Flowrate (lbmol/hr) 147,437 147,437 4,387 45,291 45,291 6,213 3,408 0 0 207,471 0 207,471 207,471 7,462

V-L Flowrate (lb/hr) 4,254,595 4,254,595 126,595 1,306,967 1,306,967 179,291 98,338 0 0 6,170,854 0 6,170,854 6,170,854 134,426

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 565,820 10,973 43,893 43,893 0 0 57,245

Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337 360 59

Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.4 15.0

Enthalpy (Btu/lb)A 13.0 14.8 14.8 13.0 17.5 17.5 13.0 --- --- 140.8 --- 132.8 138.8 ---

Density (lb/ft3) 0.076 0.078 0.078 0.076 0.081 0.081 0.076 --- --- 0.050 --- 0.049 0.052 ---

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Fossil Energy Plants

412

Exhibit 4-46 Case 12 Stream Table, Supercritical Unit with CO2 Capture (Continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 28

V-L Mole Fraction

Ar 0.0000 0.0128 0.0000 0.0081 0.0108 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0000 0.0005 0.0004 0.1350 0.0179 0.9961 0.9985 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 1.0000 0.0062 0.9996 0.1537 0.0383 0.0039 0.0015 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

N2 0.0000 0.7506 0.0000 0.6793 0.9013 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.2300 0.0000 0.0238 0.0316 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 13,485 975 250 102,548 77,286 12,511 12,481 44,922 44,922 126,511 103,236 103,236 49,304 49,304

V-L Flowrate (kg/hr) 242,941 28,289 4,498 2,956,531 2,177,293 549,344 548,802 809,288 809,288 2,279,133 1,859,826 1,859,826 888,227 888,227

Solids Flowrate (kg/hr) 0 0 40,138 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 15 181 58 58 32 21 35 291 151 593 354 593 38 40

Pressure (MPa, abs) 0.10 0.31 0.10 0.10 0.10 0.16 15.27 0.51 0.92 24.23 4.90 4.52 0.01 1.69

Enthalpy (kJ/kg)A -46.80 191.58 --- 301.43 93.86 19.49 -211.71 3,045.10 636.31 3,476.62 3,081.81 3,652.22 2,115.77 166.72

Density (kg/m3

) 1,003.1 2.4 --- 1.1 1.1 2.9 795.9 2.0 916.0 69.2 18.7 11.6 0.1 993.2

V-L Molecular Weight 18.015 29.029 --- 28.831 28.172 43.908 43.971 18.015 18.015 18.015 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 29,730 2,148 550 226,080 170,387 27,582 27,516 99,037 99,037 278,909 227,597 227,597 108,697 108,697

V-L Flowrate (lb/hr) 535,592 62,368 9,916 6,518,034 4,800,109 1,211,096 1,209,902 1,784,175 1,784,175 5,024,628 4,100,215 4,100,215 1,958,206 1,958,206

Solids Flowrate (lb/hr) 0 0 88,488 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 59 357 136 136 89 69 95 556 304 1,100 668 1,100 101 103

Pressure (psia) 14.7 45.0 14.9 14.9 14.7 23.5 2,214.5 73.5 133.6 3,514.7 710.8 655.8 1.0 245.0

Enthalpy (Btu/lb)A -20.1 82.4 --- 129.6 40.4 8.4 -91.0 1,309.2 273.6 1,494.7 1,324.9 1,570.2 909.6 71.7

Density (lb/ft3) 62.622 0.149 --- 0.067 0.070 0.184 49.684 0.123 57.184 4.319 1.166 0.722 0.004 62.002
Cost and Performance Baseline for Fossil Energy Plants

413

Exhibit 4-47 Case 12 Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Steam Turbine Power 662,800

TOTAL (STEAM TURBINE) POWER, kWe 662,800

AUXILIARY LOAD SUMMARY, kWe

Coal Handling and Conveying 510

Pulverizers 3,850

Sorbent Handling & Reagent Preparation 1,250

Ash Handling 740

Primary Air Fans 1,800

Forced Draft Fans 2,300

Induced Draft Fans 11,120

SCR 70

Baghouse 100

Wet FGD 4,110

Econamine FG Plus Auxiliaries 20,600

CO2 Compression 44,890

Miscellaneous Balance of Plant2,3 2,000

Steam Turbine Auxiliaries 400

Condensate Pumps 560

Circulating Water Pumps 10,100

Ground Water Pumps 910

Cooling Tower Fans 5,230

Transformer Losses 2,290

TOTAL AUXILIARIES, kWe 112,830

NET POWER, kWe 549,970

Net Plant Efficiency (HHV) 28.4%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 12,663 (12,002)

CONDENSER COOLING DUTY, 106 kJ/hr (106 Btu/hr) 1,737 (1,646)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 256,652 (565,820)

Limestone Sorbent Feed, kg/hr (lb/hr) 25,966 (57,245)

Thermal Input, kWt1 1,934,519

Raw Water Withdrawal, m3/min (gpm) 38.1 (10,071)

Raw Water Consumption, m3/min (gpm) 29.3 (7,733)

1. HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)

2. Boiler feed pumps are turbine driven

3. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Fossil Energy Plants

414

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 

Environmental Performance

2.4. A summary of the plant air emissions for Case 12 is presented in Exhibit 4-48.

Exhibit 4-48 Case 12 Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

85% CF

kg/MWh

(lb/MWh)

SO2 0.001 (0.002) 36 (40) 0.007 (.02)

NOx 0.030 (0.070) 1,561 (1,720) 0.316 (.697)

Particulates 0.006 (0.0130) 290 (319) 0.059 (.129)

Hg 4.91E-7 (1.14E-6) 0.025 (0.028) 5.16E-6 (1.14E-5)

CO2 8.8 (20.4) 453,763 (500,188) 92 (203)

CO2

1 111 (244)

1 CO2 emissions based on net power instead of gross power

SO2 emissions are controlled using a wet limestone forced oxidation scrubber that achieves a 

removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site. 

The wallboard grade material can potentially be marketed and sold, but since it is highly 

dependent on local market conditions, no byproduct credit was taken. The SO2 emissions are 

further reduced to 10 ppmv using a NaOH based polishing scrubber in the CDR facility. The 

remaining low concentration of SO2 is essentially completely removed in the CDR absorber 

vessel resulting in very low SO2 emissions.

NOx emissions are controlled to about 0.5 lb/106 Btu through the use of LNBs and OFA. An 

SCR unit then further reduces the NOx concentration by 86 percent to 0.07 lb/106 Btu.

Particulate emissions are controlled using a pulse jet fabric filter, which operates at an efficiency 

of 99.8 percent.

Co-benefit capture results in a 90 percent reduction of mercury emissions.

Ninety percent of the CO2 in the FG is removed in CDR facility.

The carbon balance for the plant is shown in Exhibit 4-49. The carbon input to the plant consists 

of carbon in the coal in addition to carbon in the air and limestone for the FGD. Carbon in the 

air is not neglected here since the Aspen model accounts for air components throughout. Carbon 

leaves the plant as CO2 in the stack gas, carbon in the FGD product, and the captured CO2

product. The carbon capture efficiency is defined by the following fraction: 

1-[(Stack Gas Carbon-Air Carbon)/(Total Carbon In-Air Carbon)] or

[1-(36,667-783)/(367,272-783) * 100] or

90.2 percent
Cost and Performance Baseline for Fossil Energy Plants

415

Exhibit 4-49 Case 12 Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 163,602 (360,680) Stack Gas 16,632 (36,667)

Air (CO2) 355 (783) FGD Product 274 (605)

FGD Reagent 2,635 (5,809) CO2 Product 149,685 (329,999)

Total 166,592 (367,272) Total 166,592 (367,272)

Exhibit 4-50 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered from the FGD as gypsum, sulfur emitted in

the stack gas, and sulfur removed in the polishing scrubber.

Exhibit 4-50 Case 12 Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 6,433 (14,182) FGD Product 6,304 (13,898)

Stack Gas 2 (5)

Econamine Polishing 

Scrubber/HSS 126 (278)

Total 6,433 (14,182) Total 6,433 (14,182)

Exhibit 4-51 shows the overall water balance for the plant. The exhibit is presented in an 

identical manner as for Case 11.

Exhibit 4-51 Case 12 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)

Econamine 0.1 (36) 0.0 (0) 0.1 (36) 0.00 (0) 0.1 (36)

FGD Makeup 5.1 (1,340) 0.0 (0) 5.1 (1,340) 0.00 (0) 5.1 (1,340)

BFW Makeup 0.0 (0) 0.0 (0) 0.0 (0) 0.00 (0) 0.0 (0)

Cooling Tower 39.4 (10,399) 6.5 (1,703) 32.9 (8,696) 8.9 (2,339) 24.1 (6,357)

Total 44.6 (11,774) 6.5 (1,703) 38.1 (10,071) 8.9 (2,339) 29.3 (7,733)
Cost and Performance Baseline for Fossil Energy Plants

416

A heat and mass balance diagram is shown for the Case 12 PC boiler, the FGD unit, CDR 

system, and steam cycle in 

Heat and Mass Balance Diagrams

Exhibit 4-52 and Exhibit 4-53. An overall plant energy balance is 

provided in tabular form in Exhibit 4-54. The power out is the steam turbine power prior to 

generator losses. The power at the generator terminals (shown in Exhibit 4-47) is calculated by 

multiplying the power out by a generator efficiency of 98.5 percent. The Econamine process 

heat out stream represents heat rejected to cooling water and ultimately to ambient via the 

cooling tower. The same is true of the condenser heat out stream. The CO2 compressor 

intercooler load is included in the Econamine process heat out stream.
Cost and Performance Baseline for Fossil Energy Plants

417

Exhibit 4-52 Case 12 Heat and Mass Balance, Supercritical PC Boiler with CO2 Capture

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Ash

Slurry

Synthesis Gas

Sour Gas

Sour Water

Water

Steam

PAGES

1 OF 2

BITUMINOUS BASELINE STUDY

CASE 12

SUPERCRITICAL PULVERIZED COAL

BOILER AND GAS CLEANUP SYSTEMS

DWG. NO.

BB-HMB-CS-12-PG-1

Pulverized

Coal

Boiler

AMMONIA SCR

INFILTRATION

AIR

AIR

AIR

COAL

ASH

From Feedwater

Heaters

Single Reheat

To IP Turbine

Throttle Steam

To HP Turbine

FGD

ASH

FORCED

DRAFT FANS

PRIMARY

AIR FANS

STACK

565,820 W

77.8 T

16.1 P

17.5 H

66.4 T

15.3 P

14.8 H

5,024,628 W

1,100.0 T

3,514.7 P

1,494.7 H

4,100,215 W

1,100.0 T

655.8 P

1,570.6 H

Single Reheat

Extraction from

HP Turbine

1,306,967 W

59.0 T

14.7 P

13.0 H

4,254,595 W

59.0 T

14.7 P

13.0 H

98,338 W

59.0 T

14.7 P

13.0 H

6,214,747 W

337.0 T

14.4 P

140.8 H

10,973 W

43,893 W

4,100,215 W

668.4 T

710.8 P

1,324.9 H

5,024,628 W

545.5 T

4,185.0 P

539.3 H

5

6,518,034 W

135.8 T

14.9 P

129.6 H

1 2

4

7

8

9

6,170,854 W ID FANS

337.0 T

14.2 P

132.8 H

Gross Plant Power: 663 MWe

Auxiliary Load: 113 MWe

Net Plant Power: 550 MWe

Net Plant Efficiency, HHV: 28.4%

Net Plant Heat Rate: 12,002 BTU/KWe

Lime/Ash

Flue Gas

OXIDATION 

AIR

MAKE-UP 

WATER

LIMESTONE 

SLURRY

GYPSUM

15

14

11

360.4 T

15.4 P

138.8 H

191,671 W

59.0 T

15.0 P

62,368 W

357.4 T

45.0 P

82.4 H

535,592 W

59.0 T

14.7 P

98,404 W

135.8 T

14.9 P

STRIPPER

ABSORBER

FLUE GAS Acid Gas

ECONAMINE FG+

ECONAMINE

CONDENSATE

18

252,068 W

306.3 T

73.5 P

1,181.0 H

1,784,175 W

556.3 T

73.5 P

1,309.6 H

1,784,175 W

304.0 T

133.6 P

273.6 H

ECONAMINE

STEAM

1,209,902 W

95.0 T

2,214.5 P

1,211,096 W

69.0 T

23.5 P

8.4 H

4,800,109 W

88.8 T

14.7 P

40.4 H CO2 

COMPRESSION

(INTERSTAGE 

COOLING)

CO2

PRODUCT

Baghouse

21

22

20

3

6

10 12 13

16

17

19

23

24

25

26

DOE/NETL

SC PC PLANT

CASE 12
Cost and Performance Baseline for Fossil Energy Plants

418

Exhibit 4-53 Case 12 Heat and Mass Balance, Supercritical Steam Cycle

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Sour Gas

Sour Water

Water

Steam

PAGES

2 OF 2

DWG. NO.

BB-HMB-CS-12-PG-2

BITUMINOUS BASELINE STUDY

CASE 12

SUPERCRITICAL PULVERIZED COAL

POWER BLOCK SYSTEMS

LP TURBINE GENERATOR HP

TURBINE

IP

TURBINE

CONDENSER

HOT WELL

P-1028 P-1048

To Boiler

BOILER FEED

PUMP TURBINE 

DRIVES

STEAM SEAL

REGULATOR

Throttle

Steam

Single Reheat

Extraction

From Boiler

GLAND SEAL

CONDENSER

CONDENSATE

PUMPS

5,024,628 W

1,100.0 T

3,514.7 P

1,494.7 H

2,900.0 P

285,001 W

803.0 T

211.9 P

1,426.1 H

612,527 W

665.2 T

700.8 P

1,323.6 H

Single Reheat

Extraction to

Boiler

4,100,215 W

668.4 T

710.8 P

1,324.9 H

710.8 P

1,115.5 P

281,028 W

763.9 T

990.5 P

1,367.5 H

710.8 P

710.8 P

221.9 P

75.0 P

75.0 P

375,024 W

556.3 T

73.5 P

1,309.2 H

126.1 T

2.0 P

1,085.4 H

1,337,035 W

101.1 T

1.0 P

1,009.5 H

2,793 W

212.0 T

14.7 P

179.9 H

29.0 P

11.4 P

4.5 P

101.4 T

250.0 P

70.0 H

2,793 W

674.7 T

75.0 P

1,367.7 H

1,958,206 W

101.1 T

1.0 P

69.1 H

1,958,206 W

103.1 T

245.0 P

71.7 H

1,958,206 W

123.8 T

240.0 P

92.2 H

240,053 W

113.1 T

1.4 P

81.0 H

202,990 W

133.8 T

2.5 P

101.6 H

1,958,206 W

235.0 T

225.0 P

203.5 H

1,178,556 W

321.8 T

91.9 P

291.8 H

1,958,206 W

190.2 T

230.0 P

158.5 H

893,554 W

398.7 T

243.6 P

373.2 H

281,028 W

513.3 T

765.9 P

503.4 H

5,024,628 W

388.7 T

4,195.0 P

367.8 H

5,024,628 W

503.3 T

4,190.0 P

491.0 H

DEAERATOR

BOILER

FEED PUMPS

5,024,628 W

545.5 T

4,185.0 P

539.3 H

24

4,100,215 W

1,100.0 T

655.8 P

1,570.6 H

83,560 W

200.2 T

11.6 P

168.0 H

155,189 W

161.0 T

4.9 P

128.7 H

1,958,206 W

151.0 T

235.0 P

119.3 H

103,690 W

595.3 T

70.0 P

1,328.7 H

83,560 W

370.1 T

25.0 P

1,223.5 H

71,629 W

216.1 T

10.4 P

1,153.6 H

47,801 W

156.0 T

4.3 P

1,123.0 H

37,063 W

128.8 T

2.2 P

1,054.1 H

2,900.0 P

3,731,302 W

556.3 T

73.5 P

1,309.2 H

1,572,104 W

556.3 T

73.5 P

1,309.2 H

2.3 P

2,900.0 P

311.8 T

4,200.0 P

289.0 H

5,024,628 W

302.9 T

70.0 P

272.3 H

3,301 W

674.7 T

75.0 P

1,367.7 H

Gross Plant Power: 663 MWe

Auxiliary Load: 113 MWe

Net Plant Power: 550 MWe

Net Plant Efficiency, HHV: 28.4%

Net Plant Heat Rate: 12,002 BTU/KWe

FWH 4 FWH 3 FWH 2 FWH 1 FWH 8 FWH 7 FWH 6

4,985 W

674.7 T

75.0 P

1,367.7 H

1,784,175 W

304.0 T

133.6 P

273.6 H

ECONAMINE

CONDENSATE

23

1,784,175 W

556.3 T

73.5 P

1,309.6 H

ECONAMINE

STEAM

22

25

26

28

DOE/NETL

SC PC PLANT

CASE 12
Cost and Performance Baseline for Fossil Energy Plants

419

Exhibit 4-54 Case 12 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 6,964 (6,601) 5.8 (5.5) 6,970 (6,606)

Air 77.6 (73.6) 77.6 (73.6)

Raw Water Makeup 144.9 (137.3) 144.9 (137.3)

Limestone 0.29 (0.28) 0.29 (0.28)

Auxiliary Power 406 (385) 406 (385)

Totals 6,964 (6,601) 228.6 (216.7) 406 (385) 7,599 (7,203)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.6 (0.6) 0.6 (0.6)

Fly Ash + FGD Ash 2.4 (2.3) 2.4 (2.3)

Flue Gas 204 (194) 204 (194)

Condenser 1,737 (1,646) 1,737 (1,646)

CO2 -116 (-110) -116 (-110)

Cooling Tower 

Blowdown 65.8 (62.3) 65.8 (62.3)

Econamine Losses 3,298 (3,126) 3,298 (3,126)

Process Losses* 21.3 (20.2) 21.3 (20.2)

Power 2,386 (2,262) 2,386 (2,262)

Totals 0 (0) 5,213 (4,941) 2,386 (2,262) 7,599 (7,203)

* Process losses are estimated to match the heat input to the plant. Process losses include losses from: 

turbines, HRSGs, combustion reactions, gas cooling, etc.
Cost and Performance Baseline for Fossil Energy Plants

420

4.3.9

Major equipment items for the SC PC plant 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 

Case 12 – Major Equipment List

4.3.10. In general, the design conditions include a 10 percent contingency 

for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 FUEL AND SORBENT HANDLING

Equipment 

No. Description Type Design Condition 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 209 tonne/hr (230 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 426 tonne/hr (470 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 209 tonne (230 ton) 2 0

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3 in x 0 - 1-1/4 in x 0) 2 0

14 As-Fired Coal Sampling 

System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 426 tonne/hr (470 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 426 tonne/hr (470 tph) 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 907 tonne (1,000 ton) 3 0

19 Limestone Truck Unloading 

Hopper

N/A 36 tonne (40 ton) 1 0

20 Limestone Feeder Belt 109 tonne/hr (120 tph) 1 0

21 Limestone Conveyor No. L1 Belt 109 tonne/hr (120 tph) 1 0

22 Limestone Reclaim Hopper N/A 18 tonne (20 ton) 1 0

23 Limestone Reclaim Feeder Belt 82 tonne/hr (90 tph) 1 0

24 Limestone Conveyor No. L2 Belt 82 tonne/hr (90 tph) 1 0

25 Limestone Day Bin w/ actuator 345 tonne (380 ton) 2 0
Cost and Performance Baseline for Fossil Energy Plants

421

ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Coal Feeder Gravimetric 45 tonne/hr (50 tph) 6 0

2 Coal Pulverizer Ball type or 

equivalent 45 tonne/hr (50 tph) 6 0

3 Limestone Weigh Feeder Gravimetric 28 tonne/hr (31 tph) 1 1

4 Limestone Ball Mill Rotary 28 tonne/hr (31 tph) 1 1

5 Limestone Mill Slurry Tank 

with Agitator N/A 109,777 liters (29,000 gal) 1 1

6 Limestone Mill Recycle 

Pumps

Horizontal 

centrifugal

1,855 lpm @ 12m H2O (490 gpm 

@ 40 ft H2O) 1 1

7 Hydroclone Classifier

4 active 

cyclones in a 5 

cyclone bank

454 lpm (120 gpm) per cyclone 1 1

8 Distribution Box 2-way N/A 1 1

9 Limestone Slurry Storage 

Tank with Agitator Field erected 617,022 liters (163,000 gal) 1 1

10 Limestone Slurry Feed 

Pumps

Horizontal 

centrifugal

1,287 lpm @ 9m H2O (340 gpm 

@ 30 ft H2O) 1 1
Cost and Performance Baseline for Fossil Energy Plants

422

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 1,506,594 liters (398,000 gal) 2 0

2 Condensate Pumps Vertical canned 16,277 lpm @ 213 m H2O (4,300 

gpm @ 700 ft H2O) 1 1

3 Deaerator and Storage 

Tank Horizontal spray type 2,507,005 kg/hr (5,527,000 lb/hr), 5 min. tank 1 0

4 Boiler Feed 

Pump/Turbine

Barrel type, multi-stage, 

centrifugal

42,018 lpm @ 3,505 m H2O 

(11,100 gpm @ 11,500 ft H2O) 1 1

5

Startup Boiler Feed 

Pump, Electric Motor 

Driven

Barrel type, multi-stage, 

centrifugal

12,492 lpm @ 3,505 m H2O 

(3,300 gpm @ 11,500 ft H2O) 1 0

6 LP Feedwater Heater 

1A/1B Horizontal U-tube 489,880 kg/hr (1,080,000 lb/hr) 2 0

7

LP Feedwater Heater 

2A/2B Horizontal U-tube 489,880 kg/hr (1,080,000 lb/hr) 2 0

8 LP Feedwater Heater 

3A/3B Horizontal U-tube 489,880 kg/hr (1,080,000 lb/hr) 2 0

9 LP Feedwater Heater 

4A/4B Horizontal U-tube 489,880 kg/hr (1,080,000 lb/hr) 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 2,508,366 kg/hr (5,530,000 lb/hr) 1 0

11 HP Feedwater Heater 7 Horizontal U-tube 2,508,366 kg/hr (5,530,000 lb/hr) 1 0

12 HP Feedwater heater 8 Horizontal U-tube 2,508,366 kg/hr (5,530,000 lb/hr) 1 0

13 Auxiliary Boiler Shop fabricated, water 

tube

18,144 kg/hr, 2.8 MPa, 343°C 

(40,000 lb/hr, 400 psig, 650°F) 1 0

14 Fuel Oil System No. 2 fuel oil for light 

off 1,135,624 liter (300,000 gal) 1 0

15 Service Air 

Compressors Flooded Screw 28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

16 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

17 Closed Cycle Cooling 

Heat Exchangers Shell and tube 53 GJ/hr (50 MMBtu/hr) each 2 0

18 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 20,820 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 2 1

19 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 88 m H2O (1,000 

gpm @ 290 ft H2O) 1 1

20 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 64 m H2O (700 gpm 

@ 210 ft H2O) 1 1

21 Raw Water Pumps Stainless steel, single 

suction

11,016 lpm @ 18 m H2O (2,910 

gpm @ 60 ft H2O) 2 1

22 Ground Water Pumps Stainless steel, single 

suction

4,429 lpm @ 268 m H2O (1,170 

gpm @ 880 ft H2O) 5 1

23 Filtered Water Pumps Stainless steel, single 

suction

2,725 lpm @ 49 m H2O (720 gpm 

@ 160 ft H2O) 2 1

24 Filtered Water Tank Vertical, cylindrical 2,619,505 liter (692,000 gal) 1 0

25 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly, 

electrodeionization unit

984 lpm (260 gpm) 1 1

26 Liquid Waste Treatment 

System -- 10 years, 24-hour storm 1 0
Cost and Performance Baseline for Fossil Energy Plants

423

ACCOUNT 4 BOILER AND ACCESSORIES

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Boiler

Supercritical, drum, 

wall-fired, low NOx 

burners, overfire air

2,508,366 kg/hr steam @ 25.5 

MPa/602°C/602°C (5,530,000 

lb/hr steam @ 3,700 

psig/1,115°F/1,115°F)

1 0

2 Primary Air Fan Centrifugal

326,133 kg/hr, 4,449 m3/min @ 

123 cm WG (719,000 lb/hr, 

157,100 acfm @ 48 in. WG)

2 0

3 Forced Draft Fan Centrifugal

1,061,406 kg/hr, 14,484 m3/min 

@ 47 cm WG (2,340,000 lb/hr, 

511,500 acfm @ 19 in. WG)

2 0

4 Induced Draft Fan Centrifugal

1,539,493 kg/hr, 32,491 m3/min 

@ 104 cm WG (3,394,000 lb/hr, 

1,147,400 acfm @ 41 in. WG)

2 0

5 SCR Reactor Vessel Space for spare 

layer 3,079,892 kg/hr (6,790,000 lb/hr) 2 0

6 SCR Catalyst -- -- 3 0

7 Dilution Air Blower Centrifugal 184 m3/min @ 108 cm WG 

(6,500 acfm @ 42 in. WG) 2 1

8 Ammonia Storage Horizontal tank 200,627 liter (53,000 gal) 5 0

9 Ammonia Feed 

Pump Centrifugal 39 lpm @ 91 m H2O (10 gpm @ 

300 ft H2O) 2 1
Cost and Performance Baseline for Fossil Energy Plants

424

ACCOUNT 5 FLUE GAS CLEANUP

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Fabric Filter

Single stage, highratio with pulse-jet 

online cleaning 

system

1,539,493 kg/hr (3,394,000 lb/hr) 

99.8% efficiency 2 0

2 Absorber Module Counter-current 

open spray

61,561 m3/min (2,174,000 acfm) 1 0

3 Recirculation Pumps Horizontal 

centrifugal

215,768 lpm @ 64 m H2O 

(57,000 gpm @ 210 ft H2O) 5 1

4 Bleed Pumps Horizontal 

centrifugal

5,565 lpm (1,470 gpm) at 20 wt% 

solids 2 1

5 Oxidation Air Blowers Centrifugal 109 m3/min @ 0.3 MPa (3,840 

acfm @ 37 psia) 2 1

6 Agitators Side entering 50 hp 5 1

7 Dewatering Cyclones Radial assembly, 

5 units each 1,401 lpm (370 gpm) per cyclone 2 0

8 Vacuum Filter Belt Horizontal belt 44 tonne/hr (49 tph) of 50 wt % 

slurry 2 1

9 Filtrate Water Return 

Pumps

Horizontal 

centrifugal

833 lpm @ 12 m H2O (220 gpm 

@ 40 ft H2O) 1 1

10 Filtrate Water Return 

Storage Tank Vertical, lined 567,812 lpm (150,000 gal) 1 0

11 Process Makeup Water 

Pumps

Horizontal 

centrifugal

4,467 lpm @ 21 m H2O (1,180 

gpm @ 70 ft H2O) 1 1
Cost and Performance Baseline for Fossil Energy Plants

425

ACCOUNT 5C CARBON DIOXIDE RECOVERY

ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES 

N/A

ACCOUNT 7 HRSG, DUCTING & STACK

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Econamine FG 

Plus

Amine-based CO2 

capture technology

1,626,129 kg/h (3,585,000 lb/h) 

20.6 wt % CO2 concentration 2 0

2

Econamine 

Condensate 

Pump

Centrifugal 16,959 lpm @ 52 m H2O (4,480 

gpm @ 170 ft H2O) 1 1

3 CO2 

Compressor

Integrally geared, 

multi-stage centrifugal

301,656 kg/h @ 15.3 MPa 

(665,037 lb/h @ 2,215 psia) 2 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack Reinforced concrete 

with FRP liner

152 m (500 ft) high x

5.6 m (18 ft) diameter 1 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

698 MW

24.1 MPa/593°C/593°C 

(3500 psig/ 

1100°F/1100°F)

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitation

780 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase 1 0

3 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,910 GJ/hr (1,810 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 

11°C (20°F)

1 0
Cost and Performance Baseline for Fossil Energy Plants

426

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Circulating Water 

Pumps Vertical, wet pit 1,014,500 lpm @ 30 m

(268,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

/ 5655 GJ/hr (5360 MMBtu/hr) 

heat duty

1 0
Cost and Performance Baseline for Fossil Energy Plants

427

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Economizer Hopper (part of 

boiler scope of supply) -- -- 4 0

2 Bottom Ash Hopper (part of 

boiler scope of supply) -- -- 2 0

3 Clinker Grinder -- 5.4 tonne/hr (6 tph) 1 1

4

Pyrites Hopper (part of 

pulverizer scope of supply 

included with boiler)

-- -- 6 0

5 Hydroejectors -- -- 12

6 Economizer /Pyrites Transfer 

Tank -- -- 1 0

7 Ash Sluice Pumps Vertical, wet pit 227 lpm @ 17 m H2O (60 gpm 

@ 56 ft H2O) 1 1

8 Ash Seal Water Pumps Vertical, wet pit 7,571 lpm @ 9 m H2O (2000 

gpm @ 28 ft H2O) 1 1

9 Hydrobins -- 227 lpm (60 gpm) 1 1

10 Baghouse Hopper (part of 

baghouse scope of supply) -- -- 24 0

11 Air Heater Hopper (part of 

boiler scope of supply) -- -- 10 0

12 Air Blower -- 20 m3/min @ 0.2 MPa (710 

scfm @ 24 psi) 1 1

13 Fly Ash Silo Reinforced 

concrete 1,270 tonne (1,400 ton) 2 0

14 Slide Gate Valves -- -- 2 0

15 Unloader -- -- 1 0

16 Telescoping Unloading Chute -- 127 tonne/hr (140 tph) 1 0
Cost and Performance Baseline for Fossil Energy Plants

428

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 STG Transformer Oil-filled 24 kV/345 kV, 650 MVA, 3-

ph, 60 Hz 1 0

2 Auxiliary 

Transformer Oil-filled 24 kV/4.16 kV, 123 MVA, 3-ph, 60 Hz 1 1

3 Low Voltage 

Transformer Dry ventilated 4.16 kV/480 V, 18 MVA, 3-ph, 60 Hz 1 1

4

STG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0

5 Medium Voltage 

Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

6 Low Voltage 

Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

7 Emergency Diesel 

Generator

Sized for emergency 

shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0

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 for Fossil Energy Plants

429

4.3.10

The cost estimating methodology was described previously in Section 

Case 12 – Cost Estimating Basis

2.7. Exhibit 4-55 shows 

the total plant capital cost summary organized by cost account and Exhibit 4-56 shows a more 

detailed breakdown of the capital costs as well as owner’s costs, TOC, and TASC. Exhibit 4-57

shows the initial and annual O&M costs.

The estimated TOC of the SC PC boiler with CO2 capture is $3,570/kW. Process contingency 

represents 2.8 percent of the TOC and project contingency represents 10.2 percent. The COE, 

including CO2 TS&M costs of 5.7 mills/kWh, is 106.6 mills/kWh.
Cost and Performance Baseline for Fossil Energy Plants

430

Exhibit 4-55 Case 12 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14

Project: Bituminous Baseline Study

Case: Case 12 - 1x550 MWnet Super-Critical PC w/ CO2 Capture

Plant Size: 550.0 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 $20,098 $5,400 $12,019 $0 $0 $37,517 $3,366 $0 $6,132 $47,015 $85

 2 COAL & SORBENT PREP & FEED $13,673 $796 $3,473 $0 $0 $17,942 $1,572 $0 $2,927 $22,442 $41

 3 FEEDWATER & MISC. BOP SYSTEMS $54,851 $0 $25,849 $0 $0 $80,700 $7,397 $0 $14,455 $102,552 $186

 4 PC BOILER

4.1 PC Boiler & Accessories $195,902 $0 $109,921 $0 $0 $305,822 $29,763 $0 $33,559 $369,144 $671

4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4 $195,902 $0 $109,921 $0 $0 $305,822 $29,763 $0 $33,559 $369,144 $671

 5 FLUE GAS CLEANUP $101,027 $0 $34,490 $0 $0 $135,517 $12,971 $0 $14,849 $163,336 $297

5B CO2 REMOVAL & COMPRESSION $235,366 $0 $71,742 $0 $0 $307,108 $29,363 $54,181 $78,130 $468,782 $852

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

7.2-7.9 HRSG Accessories, Ductwork and Stack $17,541 $961 $11,881 $0 $0 $30,383 $2,783 $0 $4,359 $37,526 $68

SUBTOTAL 7 $17,541 $961 $11,881 $0 $0 $30,383 $2,783 $0 $4,359 $37,526 $68

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $56,794 $0 $7,537 $0 $0 $64,331 $6,165 $0 $7,050 $77,546 $141

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $27,360 $1,200 $15,331 $0 $0 $43,892 $3,826 $0 $6,848 $54,565 $99

SUBTOTAL 8 $84,154 $1,200 $22,868 $0 $0 $108,222 $9,991 $0 $13,898 $132,111 $240

 9 COOLING WATER SYSTEM $20,722 $9,941 $18,443 $0 $0 $49,106 $4,622 $0 $7,236 $60,965 $111

10 ASH/SPENT SORBENT HANDLING SYS $5,276 $168 $7,053 $0 $0 $12,497 $1,202 $0 $1,410 $15,108 $27

11 ACCESSORY ELECTRIC PLANT $25,213 $10,656 $30,191 $0 $0 $66,060 $5,843 $0 $9,029 $80,931 $147

12 INSTRUMENTATION & CONTROL $10,017 $0 $10,157 $0 $0 $20,174 $1,829 $1,009 $2,826 $25,838 $47

13 IMPROVEMENTS TO SITE $3,321 $1,909 $6,692 $0 $0 $11,921 $1,176 $0 $2,620 $15,717 $29

14 BUILDINGS & STRUCTURES $0 $24,782 $23,519 $0 $0 $48,301 $4,357 $0 $7,899 $60,557 $110

 

TOTAL COST $787,159 $55,813 $388,298 $0 $0 $1,231,270 $116,235 $55,190 $199,329 $1,602,023 $2,913

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline for Fossil Energy Plants

431

Exhibit 4-56 Case 12 Total Plant Cost Details

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 $4,115 $0 $1,880 $0 $0 $5,995 $536 $0 $980 $7,510 $14

1.2 Coal Stackout & Reclaim $5,318 $0 $1,205 $0 $0 $6,523 $571 $0 $1,064 $8,158 $15

1.3 Coal Conveyors $4,944 $0 $1,192 $0 $0 $6,137 $538 $0 $1,001 $7,676 $14

1.4 Other Coal Handling $1,294 $0 $276 $0 $0 $1,569 $137 $0 $256 $1,963 $4

1.5 Sorbent Receive & Unload $168 $0 $51 $0 $0 $218 $19 $0 $36 $273 $0

1.6 Sorbent Stackout & Reclaim $2,709 $0 $496 $0 $0 $3,205 $279 $0 $523 $4,007 $7

1.7 Sorbent Conveyors $967 $209 $237 $0 $0 $1,413 $122 $0 $230 $1,765 $3

1.8 Other Sorbent Handling $584 $137 $306 $0 $0 $1,027 $91 $0 $168 $1,285 $2

1.9 Coal & Sorbent Hnd.Foundations $0 $5,054 $6,376 $0 $0 $11,430 $1,074 $0 $1,876 $14,379 $26

SUBTOTAL 1. $20,098 $5,400 $12,019 $0 $0 $37,517 $3,366 $0 $6,132 $47,015 $85

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $2,388 $0 $465 $0 $0 $2,853 $249 $0 $465 $3,567 $6

2.2 Coal Conveyor to Storage $6,113 $0 $1,334 $0 $0 $7,447 $651 $0 $1,215 $9,313 $17

2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.5 Sorbent Prep Equipment $4,617 $199 $959 $0 $0 $5,774 $503 $0 $942 $7,219 $13

2.6 Sorbent Storage & Feed $556 $0 $213 $0 $0 $769 $68 $0 $126 $963 $2

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 $597 $501 $0 $0 $1,098 $102 $0 $180 $1,380 $3

SUBTOTAL 2. $13,673 $796 $3,473 $0 $0 $17,942 $1,572 $0 $2,927 $22,442 $41

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $22,860 $0 $7,384 $0 $0 $30,244 $2,643 $0 $4,933 $37,820 $69

3.2 Water Makeup & Pretreating $6,997 $0 $2,252 $0 $0 $9,249 $875 $0 $2,025 $12,149 $22

3.3 Other Feedwater Subsystems $6,998 $0 $2,958 $0 $0 $9,956 $892 $0 $1,627 $12,475 $23

3.4 Service Water Systems $1,372 $0 $746 $0 $0 $2,118 $199 $0 $463 $2,780 $5

3.5 Other Boiler Plant Systems $8,675 $0 $8,565 $0 $0 $17,240 $1,638 $0 $2,832 $21,709 $39

3.6 FO Supply Sys & Nat Gas $276 $0 $345 $0 $0 $621 $59 $0 $102 $781 $1

3.7 Waste Treatment Equipment $4,744 $0 $2,704 $0 $0 $7,448 $725 $0 $1,635 $9,808 $18

3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,930 $0 $895 $0 $0 $3,825 $368 $0 $838 $5,031 $9

SUBTOTAL 3. $54,851 $0 $25,849 $0 $0 $80,700 $7,397 $0 $14,455 $102,552 $186

 4 PC BOILER

4.1 PC Boiler & Accessories $195,902 $0 $109,921 $0 $0 $305,822 $29,763 $0 $33,559 $369,144 $671

4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4. $195,902 $0 $109,921 $0 $0 $305,822 $29,763 $0 $33,559 $369,144 $671
Cost and Performance Baseline for Fossil Energy Plants

432

Exhibit 4-56 Case 12 Total Plant Cost Details (Continued)

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

 5 FLUE GAS CLEANUP

5.1 Absorber Vessels & Accessories $70,185 $0 $15,109 $0 $0 $85,294 $8,132 $0 $9,343 $102,768 $187

5.2 Other FGD $3,663 $0 $4,150 $0 $0 $7,813 $758 $0 $857 $9,428 $17

5.3 Bag House & Accessories $20,190 $0 $12,813 $0 $0 $33,003 $3,180 $0 $3,618 $39,801 $72

5.4 Other Particulate Removal Materials $1,366 $0 $1,462 $0 $0 $2,828 $274 $0 $310 $3,413 $6

5.5 Gypsum Dewatering System $5,623 $0 $955 $0 $0 $6,579 $626 $0 $720 $7,925 $14

5.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5. $101,027 $0 $34,490 $0 $0 $135,517 $12,971 $0 $14,849 $163,336 $297

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $207,807 $0 $63,097 $0 $0 $270,904 $25,901 $54,181 $70,197 $421,183 $766

5B.2 CO2 Compression & Drying $27,558 $0 $8,646 $0 $0 $36,204 $3,462 $0 $7,933 $47,599 $87

SUBTOTAL 5. $235,366 $0 $71,742 $0 $0 $307,108 $29,363 $54,181 $78,130 $468,782 $852

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $9,165 $0 $5,889 $0 $0 $15,054 $1,313 $0 $2,455 $18,822 $34

7.4 Stack $8,376 $0 $4,901 $0 $0 $13,277 $1,278 $0 $1,456 $16,011 $29

7.9 Duct & Stack Foundations $0 $961 $1,092 $0 $0 $2,052 $192 $0 $449 $2,693 $5

SUBTOTAL 7. $17,541 $961 $11,881 $0 $0 $30,383 $2,783 $0 $4,359 $37,526 $68

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $56,794 $0 $7,537 $0 $0 $64,331 $6,165 $0 $7,050 $77,546 $141

8.2 Turbine Plant Auxiliaries $382 $0 $819 $0 $0 $1,202 $118 $0 $132 $1,451 $3

8.3 Condenser & Auxiliaries $5,509 $0 $2,030 $0 $0 $7,540 $722 $0 $826 $9,088 $17

8.4 Steam Piping $21,469 $0 $10,585 $0 $0 $32,054 $2,693 $0 $5,212 $39,959 $73

8.9 TG Foundations $0 $1,200 $1,896 $0 $0 $3,096 $293 $0 $678 $4,067 $7

SUBTOTAL 8. $84,154 $1,200 $22,868 $0 $0 $108,222 $9,991 $0 $13,898 $132,111 $240

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $15,451 $0 $4,811 $0 $0 $20,262 $1,938 $0 $2,220 $24,419 $44

9.2 Circulating Water Pumps $3,219 $0 $248 $0 $0 $3,467 $293 $0 $376 $4,136 $8

9.3 Circ.Water System Auxiliaries $787 $0 $105 $0 $0 $892 $85 $0 $98 $1,075 $2

9.4 Circ.Water Piping $0 $6,243 $6,050 $0 $0 $12,293 $1,151 $0 $2,017 $15,460 $28

9.5 Make-up Water System $641 $0 $857 $0 $0 $1,498 $144 $0 $246 $1,888 $3

9.6 Component Cooling Water Sys $624 $0 $496 $0 $0 $1,120 $106 $0 $184 $1,410 $3

9.9 Circ.Water System Foundations & Structures $0 $3,698 $5,876 $0 $0 $9,575 $906 $0 $2,096 $12,577 $23

SUBTOTAL 9. $20,722 $9,941 $18,443 $0 $0 $49,106 $4,622 $0 $7,236 $60,965 $111
Cost and Performance Baseline for Fossil Energy Plants

433

Exhibit 4-56 Case 12 Total Plant Cost Details (Continued)

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 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $706 $0 $2,175 $0 $0 $2,881 $283 $0 $316 $3,480 $6

10.7 Ash Transport & Feed Equipment $4,570 $0 $4,681 $0 $0 $9,250 $885 $0 $1,014 $11,149 $20

10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.9 Ash/Spent Sorbent Foundation $0 $168 $198 $0 $0 $365 $34 $0 $80 $479 $1

SUBTOTAL 10. $5,276 $168 $7,053 $0 $0 $12,497 $1,202 $0 $1,410 $15,108 $27

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $1,727 $0 $280 $0 $0 $2,008 $186 $0 $165 $2,358 $4

11.2 Station Service Equipment $4,957 $0 $1,629 $0 $0 $6,585 $616 $0 $540 $7,741 $14

11.3 Switchgear & Motor Control $5,699 $0 $969 $0 $0 $6,667 $618 $0 $729 $8,014 $15

11.4 Conduit & Cable Tray $0 $3,573 $12,354 $0 $0 $15,926 $1,542 $0 $2,620 $20,089 $37

11.5 Wire & Cable $0 $6,742 $13,014 $0 $0 $19,756 $1,664 $0 $3,213 $24,633 $45

11.6 Protective Equipment $261 $0 $888 $0 $0 $1,149 $112 $0 $126 $1,388 $3

11.7 Standby Equipment $1,360 $0 $31 $0 $0 $1,391 $128 $0 $152 $1,670 $3

11.8 Main Power Transformers $11,209 $0 $189 $0 $0 $11,398 $864 $0 $1,226 $13,488 $25

11.9 Electrical Foundations $0 $342 $837 $0 $0 $1,179 $113 $0 $258 $1,550 $3

SUBTOTAL 11. $25,213 $10,656 $30,191 $0 $0 $66,060 $5,843 $0 $9,029 $80,931 $147

12 INSTRUMENTATION & CONTROL

12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $516 $0 $309 $0 $0 $825 $78 $41 $142 $1,085 $2

12.7 Distributed Control System Equipment $5,207 $0 $910 $0 $0 $6,117 $567 $306 $699 $7,689 $14

12.8 Instrument Wiring & Tubing $2,823 $0 $5,599 $0 $0 $8,422 $718 $421 $1,434 $10,995 $20

12.9 Other I & C Equipment $1,471 $0 $3,339 $0 $0 $4,810 $466 $241 $552 $6,069 $11

SUBTOTAL 12. $10,017 $0 $10,157 $0 $0 $20,174 $1,829 $1,009 $2,826 $25,838 $47
Cost and Performance Baseline for Fossil Energy Plants

434

Exhibit 4-56 Case 12 Total Plant Cost Details (Continued)

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

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $56 $1,116 $0 $0 $1,172 $116 $0 $258 $1,546 $3

13.2 Site Improvements $0 $1,853 $2,301 $0 $0 $4,154 $410 $0 $913 $5,477 $10

13.3 Site Facilities $3,321 $0 $3,275 $0 $0 $6,595 $650 $0 $1,449 $8,694 $16

SUBTOTAL 13. $3,321 $1,909 $6,692 $0 $0 $11,921 $1,176 $0 $2,620 $15,717 $29

14 BUILDINGS & STRUCTURES

14.1 Boiler Building $0 $8,851 $7,784 $0 $0 $16,635 $1,495 $0 $2,719 $20,849 $38

14.2 Turbine Building $0 $12,808 $11,937 $0 $0 $24,746 $2,230 $0 $4,046 $31,023 $56

14.3 Administration Building $0 $643 $680 $0 $0 $1,324 $120 $0 $217 $1,660 $3

14.4 Circulation Water Pumphouse $0 $176 $139 $0 $0 $315 $28 $0 $51 $395 $1

14.5 Water Treatment Buildings $0 $887 $809 $0 $0 $1,697 $153 $0 $277 $2,127 $4

14.6 Machine Shop $0 $430 $289 $0 $0 $719 $64 $0 $117 $901 $2

14.7 Warehouse $0 $292 $292 $0 $0 $584 $53 $0 $96 $732 $1

14.8 Other Buildings & Structures $0 $238 $203 $0 $0 $441 $40 $0 $72 $553 $1

14.9 Waste Treating Building & Str. $0 $456 $1,384 $0 $0 $1,840 $175 $0 $302 $2,317 $4

SUBTOTAL 14. $0 $24,782 $23,519 $0 $0 $48,301 $4,357 $0 $7,899 $60,557 $110

TOTAL COST $787,159 $55,813 $388,298 $0 $0 $1,231,270 $116,235 $55,190 $199,329 $1,602,023 $2,913

Owner's Costs

Preproduction Costs

6 Months All Labor $10,579 $19

1 Month Maintenance Materials $1,541 $3

1 Month Non-fuel Consumables $1,637 $3

1 Month Waste Disposal $325 $1

25% of 1 Months Fuel Cost at 100% CF $1,971 $4

2% of TPC $32,040 $58

Total $48,094 $87

Inventory Capital

60 day supply of fuel and consumables at 100% CF $18,563 $34

0.5% of TPC (spare parts) $8,010 $15

Total $26,573 $48

Initial Cost for Catalyst and Chemicals $2,496 $5

Land $900 $2

Other Owner's Costs $240,304 $437

Financing Costs $43,255 $79

Total Overnight Costs (TOC) $1,963,644 $3,570

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,238,554 $4,070
Cost and Performance Baseline for Fossil Energy Plants

435

Exhibit 4-57 Case 12 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 12 - 1x550 MWnet Super-Critical PC w/ CO2 Capture Heat Rate-net (Btu/kWh): 12,002

MWe-net: 550

Capacity Factor (%): 85

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

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 2.0 2.0

 Operator 11.3 11.3

 Foreman 1.0 1.0

 Lab Tech's, etc. 2.0 2.0

 TOTAL-O.J.'s 16.3 16.3

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $6,444,907 $11.719

Maintenance Labor Cost $10,481,104 $19.058

Administrative & Support Labor $4,231,503 $7.694

Property Taxes and Insurance $32,040,467 $58.260

TOTAL FIXED OPERATING COSTS $53,197,981 $96.731

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $15,721,656 $0.00384

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water(/1000 gallons) 0 7,324 1.08 $0 $2,457,806 $0.00060

Chemicals

MU & WT Chem.(lbs) 0 35,452 0.17 $0 $1,903,577 $0.00046

Limestone (ton) 0 687 21.63 $0 $4,610,586 $0.00113

Carbon (Mercury Removal) lb 0 0 1.05 $0 $0 $0.00000

MEA Solvent (ton) 1,028 1.46 2,249.89 $2,312,307 $1,017,164 $0.00025

NaOH (tons) 73 7.26 433.68 $31,484 $976,789 $0.00024

H2SO4 (tons) 69 6.93 138.78 $9,615 $298,293 $0.00007

Corrosion Inhibitor 0 0 0.00 $142,156 $6,769 $0.00000

Activated Carbon (lb) 0 1,741 1.05 $0 $567,144 $0.00014

Ammonia (19% NH3) ton 0 102 129.80 $0 $4,090,854 $0.00100

Subtotal Chemicals $2,495,562 $13,471,176 $0.00329

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000

SCR Catalyst (m3) w/equip. 0.43 5,775.94 $0 $765,005 $0.00019

Emission Penalties 0 0 0.00 $0 $0 $0.00000

Subtotal Other $0 $765,005 $0.00019

Waste Disposal

Fly Ash (ton) 0 527 16.23 $0 $2,651,418 $0.00065

Bottom Ash (ton) 0 132 16.23 $0 $662,855 $0.00016

Subtotal-Waste Disposal $0 $3,314,273 $0.00081

By-products & Emissions 

Gypsum (tons) 0 1,062 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $2,495,562 $35,729,917 $0.00873

Fuel (ton) 0 6,790 38.18 $0 $80,434,598 $0.01964
Cost and Performance Baseline for Fossil Energy Plants

436

4.4 PC CASE SUMMARY

The performance results of the four PC plant configurations are summarized in Exhibit 4-58.

Exhibit 4-58 Estimated Performance and Cost Results for Pulverized Coal Cases

1 Capacity factor is 85% for all PC cases 2 COE and LCOE are defined in Section 2.7.

PERFORMANCE Case 9 Case 10 Case 11 Case 12

CO2 Capture 0% 90% 0% 90%

Gross Power Output (kWe) 582,600 672,700 580,400 662,800

Auxiliary Power Requirement (kWe) 32,580 122,740 30,410 112,830

Net Power Output (kWe) 550,020 549,960 549,990 549,970

Coal Flowrate (lb/hr) 437,378 614,994 409,528 565,820

Natural Gas Flowrate (lb/hr) N/A N/A N/A N/A

HHV Thermal Input (kWth) 1,495,379 2,102,643 1,400,162 1,934,519

Net Plant HHV Efficiency (%) 36.8% 26.2% 39.3% 28.4%

Net Plant HHV Heat Rate (Btu/kWh) 9,277 13,046 8,687 12,002

Raw Water Withdrawal (gpm/MWnet) 10.7 20.4 9.7 18.3

Process Water Discharge (gpm/MWnet) 2.2 4.7 2.0 4.3

Raw Water Consumption (gpm/MWnet) 8.5 15.7 7.7 14.1

CO2 Emissions (lb/MMBtu) 204 20 204 20

CO2 Emissions (lb/MWhgross) 1,783 217 1,675 203

CO2 Emissions (lb/MWhnet) 1,888 266 1,768 244

SO2 Emissions (lb/MMBtu) 0.0858 0.0017 0.0858 0.0016

SO2 Emissions (lb/MWhgross) 0.7515 0.0176 0.7063 0.0162

NOx Emissions (lb/MMBtu) 0.070 0.070 0.070 0.070

NOx Emissions (lb/MWhgross) 0.613 0.747 0.576 0.697

PM Emissions (lb/MMBtu) 0.0130 0.0130 0.0130 0.0130

PM Emissions (lb/MWhgross) 0.114 0.139 0.107 0.129

Hg Emissions (lb/TBtu) 1.143 1.143 1.143 1.143

Hg Emissions (lb/MWhgross) 1.00E-05 1.22E-05 9.41E-06 1.14E-05

COST

Total Plant Cost (2007$/kW) 1,622 2,942 1,647 2,913

Total Overnight Cost (2007$/kW) 1,996 3,610 2,024 3,570

 Bare Erected Cost 1,317 2,255 1,345 2,239

 Home Office Expenses 124 213 127 211

 Project Contingency 182 369 176 362

 Process Contingency 0 105 0 100

 Owner's Costs 374 667 377 657

Total Overnight Cost (2007$ x 1,000) 1,098,124 1,985,432 1,113,445 1,963,644

Total As Spent Capital (2007$/kW) 2,264 4,115 2,296 4,070

COE (mills/kWh, 2007$)1,2 59.4 109.6 58.9 106.5

 CO2 TS&M Costs 0.0 5.8 0.0 5.6

 Fuel Costs 15.2 21.3 14.2 19.6

 Variable Costs 5.1 9.2 5.0 8.7

 Fixed Costs 7.8 13.1 8.0 13.0

 Capital Costs 31.2 60.2 31.7 59.6

LCOE (mills/kWh, 2007$)1,2 75.3 139.0 74.7 135.2

Pulverized Coal Boiler

PC Subcritical PC Supercritical
Cost and Performance Baseline for Fossil Energy Plants

437

The components of TOC and overall TASC are shown for each PC case in Exhibit 4-59.

The following observations about TOC can be made:

• The TOC of the non-capture SC PC case is only incrementally greater than non-capture 

subcritical PC (less than 2 percent). The TOC of subcritical PC with CO2 capture is 

approximately 1 percent greater than SC PC with CO2 capture.

• The TOC penalty for adding CO2 capture in the subcritical case is 81 percent and is 76

percent in the SC case. The Econamine cost includes a process contingency of 

approximately $100/kW in both the subcritical and SC cases. Eliminating the process 

contingency results in a CO2 capture cost penalty of 76 and 71 percent for the subcritical 

and SC PC cases, respectively. In addition to the high cost of the Econamine process, 

there is a significant increase in the cost of the cooling towers and CWPs in the CO2

capture cases because of the larger cooling water demand discussed previously. In 

addition, the gross output of the two PC plants increases by 90 MW (subcritical) and 82

MW (SC) to maintain the net output at 550 MW. The increased gross output results in 

higher coal flow rate and consequent higher costs for all cost accounts in the estimate.

Exhibit 4-59 Plant Capital Cost for PC Cases

1,996

3,610

2,024

3,570

2,264

4,115

2,296

4,070

0

1,000

2,000

3,000

4,000

5,000

6,000

TOC TASC TOC TASC TOC TASC TOC TASC

Subcritical PC Subcritical PC w/ CO2 

Capture

Supercritical PC Supercritical PC w/ CO2 

Capture

TOC or TASC, $/kW (2007$)

TASC

Owner's Cost

Process Contingency

Project Contingency

Home Office Expense

Bare Erected Cost
Cost and Performance Baseline for Fossil Energy Plants

438

The COE is shown for the four PC cases in Exhibit 4-60. The following observations can be 

made:

• Capital costs represent the largest fraction of COE in all cases, but particularly so in the 

CO2 capture cases. Fuel cost is the second largest component of COE, and capital 

charges and fuel costs combined represent 74 to 78 percent of the total in all cases.

• In the non-capture case the slight increase in capital cost in the SC case is more than 

offset by the efficiency gain so that the COE for SC PC is 1 percent less than subcritical 

despite having a nearly 2 percent higher TOC.

• In the CO2 capture case, the cost differential between subcritical and SC PC is negligible 

(about 1 percent), but the SC PC has a 3 percent lower COE because of the higher 

efficiency.

Exhibit 4-60 COE for PC Cases

31.2

60.2

31.7

59.6

7.8

13.1

8.0

13.0

5.1

9.2

5.0

8.7

15.2

21.3

14.2

19.6

5.9

5.7

0

20

40

60

80

100

120

140

Subcritical PC Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2 Capture

COE, mills/kWh (2007$)

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs
Cost and Performance Baseline for Fossil Energy Plants

439

The sensitivity of COE to capacity factor is shown in Exhibit 4-61. Implicit in the curves is the 

assumption that a capacity factor of greater than 85 percent can be achieved without the 

expenditure of additional capital. The subcritical and SC cases with no CO2 capture are nearly 

identical making it difficult to distinguish between the two lines. The COE increases more 

rapidly at low CF because the relatively high capital component is spread over fewer kilowatthours of generation.

The sensitivity of COE to coal price is shown in Exhibit 4-62. As in the IGCC cases, the COE in 

the PC cases is relatively insensitive to coal price.

As presented in Section 2.4 the first year cost of CO2 avoided was calculated, and the results for 

the PC CO2 capture cases are shown in Exhibit 4-63.

The cost of CO2 avoided using the analogous non-capture technology as the reference is nearly 

identical for the subcritical and SC PC cases. Using SC PC as the non-capture reference case 

increases the avoided cost of subcritical PC with CO2 capture because subcritical PC has the

higher COE of the two capture technologies.

Exhibit 4-61 Sensitivity of COE to Capacity Factor for PC Cases

0

50

100

150

200

250

300

0 10 20 30 40 50 60 70 80 90 100

COE, mills/kWh (2007$)

Capacity Factor, %

Subcritical w/CO2 Capture

Supercritical w/CO2 Capture

Subcritical No Capture

Supercritical No Capture

Coal price = $1.64/MMBtu 
Cost and Performance Baseline for Fossil Energy Plants

440

Exhibit 4-62 Sensitivity of COE to Coal Price for PC Cases

Exhibit 4-63 First Year Cost of CO2 Avoided in PC Cases

0

20

40

60

80

100

120

140

0 0.5 1 1.5 2 2.5 3 3.5 4

COE, mills/kWh (2007$)

Fuel Price, $/MMBtu

Subcritical w/CO2 Capture

Supercritical w/CO2 Capture

Subcritical No Capture

Supercritical No Capture

Capacity Factor = 85%

68 69

75

69

0

10

20

30

40

50

60

70

80

90

100

Subcritical PC Supercritical PC

CO2 Avoided Cost, $/tonne (2007$)

Avoided Cost (Analogous Technology w/o Capture Reference)

Avoided Cost (SC PC w/o Capture Reference)
Cost and Performance Baseline for Fossil Energy Plants

441

The following observations can be made regarding plant performance with reference to 

Exhibit 4-58:

• The efficiency of the non-capture, SC PC plant is 2.5 absolute percentage points higher 

than the equivalent subcritical PC plant (39.3 percent compared to 36.8 percent). The 

efficiencies are comparable to those reported in other studies once steam cycle conditions 

are considered. For example, in an EPA study [75

Similar results from an EPRI study using Illinois No. 6 coal were reported as 

follows:[

] comparing PC and IGCC plant 

configurations the subcritical PC plant using bituminous coal had an efficiency of 35.9 

percent with a steam cycle of 16.5 MPa/538°C/538°C (2,400 psig/1,000°F/1,000°F). The 

higher steam cycle temperature in this study 566°C/566°C (1,050°F/1,050°F) is one 

factor that results in a higher net efficiency. The same study reported a SC plant 

efficiency of 38.3 percent with a steam cycle of 24.1 MPa/566°C/566°C (3,500 

psig/1,050°F/1,050°F). Again, the more aggressive steam conditions in this study, 

593°C/593°C (1,100°F/1,100°F) are one factor resulting in a higher net efficiency.

76

o Subcritical PC efficiency of 35.7 percent with a steam cycle of 16.5 

MPa/538°C/538°C (2,400 psig/1,000°F/1,000°F).

]

o SC PC efficiency of 38.3 percent with a steam cycle of 24.8 MPa/593°C/593°C 

(3,600 psig/1,100°F/1,100°F).

• The addition of CO2 capture to the two PC cases results in a relative efficiency penalty of 

28.9 percent in the subcritical PC case and 27.6 percent in the SC PC case. The 

efficiency is negatively impacted by the large auxiliary loads of the Econamine process 

and CO2 compression, as well as the large increase in cooling water requirement, which 

increases the CWP and cooling tower fan auxiliary loads. The auxiliary load increases by 

90 MW in the subcritical PC case and by 82 MW in the SC PC case.

• NOx, PM, and Hg emissions are the same for all four PC cases on a heat input basis 

because of the environmental target assumptions of fixed removal efficiencies for each 

case (86 percent SCR efficiency, 99.8 percent baghouse efficiency and 90 percent cobenefit capture). The emissions on a mass basis or normalized by gross output are higher 

for subcritical cases than SC cases and are higher for CO2 capture cases than non-capture 

cases because of the higher efficiencies of SC PC and non-capture PC cases.

• SO2 emissions are likewise constant on a heat input basis for the non-capture cases, but 

the Econamine process polishing scrubber and absorber vessel result in negligible SO2

emissions in CO2 capture cases. The SO2 emissions for subcritical PC are higher than SC

on a mass basis and when normalized by gross output because of the lower efficiency.

• Uncontrolled CO2 emissions on a mass basis are greater for subcritical PC compared to 

SC because of the lower efficiency. The capture cases result in a 90 percent reduction of 

CO2 for both subcritical and SC PC.

• Raw water consumption for all cases is dominated by cooling tower makeup 

requirements, which accounts for about 77 percent of raw water in non-capture cases and 

81 percent of raw water in CO2 capture cases. The amount of raw water consumption in 
Cost and Performance Baseline for Fossil Energy Plants

442

the CO2 capture cases is greatly increased by the cooling water requirements of the 

Econamine process. Cooling water is required to:

o Reduce the FG temperature from 57°C (135°F) (FGD exit temperature) to 32°C 

(89°F) (Econamine absorber operating temperature), which also requires 

condensing water from the FG that comes saturated from the FGD unit.

o Remove the heat input by the stripping steam to cool the solvent

o Remove the heat input from the auxiliary electric loads

o Remove heat in the CO2 compressor intercoolers

The normalized water withdrawal, process discharge and raw water consumption are shown 

in Exhibit 4-64 for each of the PC cases. In the CO2 capture cases, additional water is 

recovered from the FG as it is cooled to the absorber temperature of 32°C (89°F). The 

condensate is treated and also used as cooling tower makeup.

Exhibit 4-64 Raw Water Withdrawal and Consumption in PC Cases

10.7

20.4

9.7

18.3

8.5

15.7

7.7

14.1

0

5

10

15

20

25

Subcritical

PC

Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2 

Capture

Water, gpm/MWnet

Raw Water Withdrawal

Process Discharge

Raw Water Consumption
Cost and Performance Baseline for Fossil Energy Plants

443

5.

Two NGCC power plant configurations were evaluated and are presented in this section. Each 

design is based on a market-ready technology that is assumed to be commercially available in 

time to support start up. Each design consists of two advanced F class CTGs, two HRSG’s and 

one STG in a multi-shaft 2x2x1 configuration. 

NATURAL GAS COMBINED CYCLE PLANTS

The NGCC cases are evaluated with and without CO2 capture on a common thermal input basis. 

The NGCC designs that include CDR have a smaller plant net output resulting from the 

additional CDR facility auxiliary loads. Like in the IGCC cases, the sizes of the NGCC designs 

were determined by the output of the commercially available CT. Hence, evaluation of the 

NGCC designs on a common net output basis was not possible. 

The Rankine cycle portion of both designs uses a single reheat 16.5 MPa/566°C/566°C 

(2400 psig/1050°F/1050°F) steam cycle. A more aggressive steam cycle was considered but not 

chosen because there are very few HRSGs in operation that would support such conditions [64].

5.1 NGCC COMMON PROCESS AREAS

The two NGCC cases are nearly identical in configuration with the exception that Case 14 

includes CO2 capture while Case 13 does not. The process areas that are common to the two 

plant configurations are presented in this section.

5.1.1

It was assumed that a natural gas main with adequate capacity is in close proximity (within 16 

km [10 miles]) to the site fence line and that a suitable right of way is available to install a 

branch line to the site. For the purposes of this study it was also assumed that the gas will be 

delivered to the plant custody transfer point at 3.0 MPa (435 psig) and 38°C (100oF), which 

matches the advanced F Class fuel system requirements. Hence, neither a pressure reducing 

station with gas preheating (to prevent moisture and hydrocarbon condensation), nor a fuel 

booster compressor are required. 

Natural Gas Supply System

A new gas metering station is assumed to be added on the site, adjacent to the new CT. The 

meter may be of the rate-of-flow type, with input to the plant computer for summing and 

recording, or may be of the positive displacement type. In either case, a complete time-line 

record of gas consumption rates and cumulative consumption is provided.

5.1.2

The combined cycle plant is based on two CTG’s. The CTG is representative of the advanced F 

Class turbines with an ISO base rating of 184,400 kW when firing natural gas [

Combustion Turbine

77

Each CTG is provided with inlet air filtration systems; inlet silencers; lube and control oil 

systems including cooling; electric motor starting systems; acoustical enclosures including 

heating and ventilation; control systems including supervisory, fire protection, and fuel systems. 

No back up fuel was envisioned for this project.

]. This 

machine is an axial flow, single spool, constant speed unit, with variable IGVs, and dry LNB 

combustion system.
Cost and Performance Baseline for Fossil Energy Plants

444

The CTG is typically supplied in several fully shop-fabricated modules, complete with all 

mechanical, electrical, and control systems required for CTG operation. Site CTG installation 

involves module interconnection and linking CTG modules to the plant systems. The CTG 

package scope of supply for combined cycle application, while project specific, does not vary 

much from project-to-project. A typical scope of supply is presented in Exhibit 5-1.

Exhibit 5-1 Combustion Turbine Typical Scope of Supply

System System Scope

ENGINE 

ASSEMBLY

Coupling to Generator, Dry Chemical Exhaust Bearing Fire Protection System, 

Insulation Blankets, Platforms, Stairs and Ladders

Engine Assembly 

with Bedplate

Variable IGV System, Compressor, Bleed System, Purge Air System, Bearing Seal 

Air System, Combustors, Dual Fuel Nozzles, Turbine Rotor Cooler

Walk-in acoustical 

enclosure HVAC, Lighting, and LP CO2 Fire Protection System

MECHANICAL 

PACKAGE

HVAC, Lighting, Air Compressor for Pneumatic System, LP CO2 Fire Protection 

System

Lubricating Oil 

System and 

Control Oil System

Lube Oil Reservoir, Accumulators, 2x100% AC Driven Oil Pumps, DC Emergency 

Oil Pump with Starter, 2x100% Oil Coolers, Duplex Oil Filter, Oil Temperature and 

Pressure Control Valves, Oil Vapor Exhaust Fans and Demister, Oil Heaters, Oil 

Interconnect Piping (SS and CS), Oil System Instrumentation, Oil for Flushing and 

First Filling

ELECTRICAL 

PACKAGE

HVAC, Lighting, AC and DC Motor Control Centers, Generator Voltage Regulating 

Cabinet, Generator Protective Relay Cabinet, DC Distribution Panel, Battery 

Charger, Digital Control System with Local Control Panel (all control and 

monitoring functions as well as data logger and sequence of events recorder), 

Control System Valves and Instrumentation Communication link for interface with 

plant DCS Supervisory System, Bentley Nevada Vibration Monitoring System, LP

CO2 Fire Protection System, Cable Tray and Conduit Provisions for Performance 

Testing including Test Ports, Thermowells, Instrumentation and DCS interface 

cards

INLET AND 

EXHAUST 

SYSTEMS

Inlet Duct Trash Screens, Inlet Duct and Silencers, Self Cleaning Filters, Hoist 

System For Filter Maintenance, Evaporative Cooler System, Exhaust Duct 

Expansion Joint, Exhaust Silencers Inlet and Exhaust Flow, Pressure and 

Temperature Ports and Instrumentation

FUEL SYSTEMS

N. Gas System Gas Valves Including Vent, Throttle and Trip Valves, Gas Filter/Separator, Gas 

Supply Instruments and Instrument Panel

STARTING 

SYSTEM

Enclosure, Starting Motor or Static Start System, Turning Gear and Clutch 

Assembly, Starting Clutch, Torque Converter

GENERATOR

Static or Rotating Exciter (Excitation transformer to be included for a static

system), Line Termination Enclosure with CTs, VTs, Surge Arrestors, and Surge 

Capacitors, Neutral Cubicle with CT, Neutral Tie Bus, Grounding Transformer, and 

Secondary Resistor, Generator Gas Dryer, Seal Oil System (including Defoaming 

Tank, Reservoir, Seal Oil Pump, Emergency Seal Oil Pump, Vapor Extractor, and 

Oil Mist Eliminator), Generator Auxiliaries Control Enclosure, Generator Breaker, 

Iso-Phase bus connecting generator and breaker, Grounding System Connectors

Generator Cooling 

Totally Enclosed Water-to-Air-Cooled (TEWAC) System (including circulation 

system, interconnecting piping and controls), or Hydrogen Cooling System 

(including H2 to Glycol and Glycol to Air heat exchangers, liquid level detector 

circulation system, interconnecting piping and controls)

MISCELLANEOUS

Interconnecting Pipe, Wire, Tubing and Cable Instrument Air System Including Air 

Dryer On Line and Off Line Water Wash System LP CO2 Storage Tank Drain 

System Drain Tanks Coupling, Coupling Cover and Associated Hardware
Cost and Performance Baseline for Fossil Energy Plants

445

The generators would typically be provided with the CT package. The generators are assumed to 

be 24 kV, 3-phase, 60 hertz, constructed to meet American National Standards Institute (ANSI) 

and National Electrical Manufacturers Association (NEMA) standards for turbine-driven 

synchronous generators. The generator is TEWAC, complete with excitation system, cooling, 

and protective relaying.

5.1.3

The HRSG is configured with HP, IP, and LP steam drums, and superheater, reheater, and 

economizer sections. The HP drum is supplied with FW by the HP boiler feed pump to generate 

HP steam, which passes to the superheater section for heating to 566°C (1050°F). The IP drum 

is supplied with FW by the IP boiler feed pump. The IP steam from the drum is superheated to 

566°C (1050°F) and mixed with hot reheat steam from the reheat section at 566°C (1050oF). 

The combined flows are admitted into the IP section of the steam turbine. The LP drum provides 

steam LP turbine.

Heat Recovery Steam Generator

The economizer sections heat condensate and FW (in separate tube bundles). The HRSG tubes 

are typically comprised of bare surface and/or finned tubing or pipe material. The hightemperature portions are type P91 or P22 ferritic alloy material; the low-temperature portions 

(< 399°C [750°F]) are CS. Each HRSG exhausts directly to the stack, which is fabricated from 

CS plate materials and lined with Type 409 SS. The stack for the NGCC cases is assumed to be 

46 m (150 ft) high, and the cost is included in the HRSG account.

5.1.4

This reference plant is designed to achieve 2.5 ppmvd NOx emissions (expressed as NO2 and 

referenced to 15 percent O2). Two measures are taken to reduce the NOx. The first is a DLN

burner in the CTG. The DLN burners are a low NOx design and reduce the emissions to about 

25 ppmvd (referenced to 15 percent O2) [

NOx Control System

78

The second measure taken to reduce the NOx emissions was the installation of a SCR system. 

SCR uses ammonia and a catalyst to reduce NOx to N2 and H2O. The SCR system consists of 

reactor, and ammonia supply and storage system. The SCR system is designed for 90 percent 

reduction while firing natural gas. This along with the dry LNB achieves the emission limit of 

2.5 ppmvd (referenced to 15 percent O2).

].

Operation Description - The SCR reactor is located in the FG path inside the HRSG between 

the HP and IP sections. The SCR reactor is equipped with one catalyst layer consisting of 

catalyst modules stacked in line on a supporting structural frame. The SCR reactor has space for 

installation of an additional layer. Ammonia is injected into the gas immediately prior to 

entering the SCR reactor. The ammonia injection grid is arranged into several sections, and 

consists of multiple pipes with nozzles. Ammonia flow rate into each injection grid section is 

controlled taking into account imbalances in the FG flow distribution across the HRSG. The 

catalyst contained in the reactor enhances the reaction between the ammonia and the NOx in the 

gas. The catalyst consists of various active materials such as titanium dioxide, vanadium 

pentoxide, and tungsten trioxide. The optimum inlet FG temperature range for the catalyst is 

260°C (500°F) to 343°C (650°F). 

The ammonia storage and injection system consists of the unloading facilities, bulk storage tank, 

vaporizers, and dilution air skid.
Cost and Performance Baseline for Fossil Energy Plants

446

5.1.5

A CDR facility is used in Case 14 to remove 90 percent of the CO2 in the FG exiting the HRSG, 

purify it, and compress it to a SC condition. It is assumed that all of the carbon in the natural gas 

is converted to CO2. The CDR is comprised of FG supply, CO2 absorption, solvent stripping and 

reclaiming, and CO2 compression and drying.

Carbon Dioxide Recovery Facility

The CO2 absorption/stripping/solvent reclaim process for Case 14 is based on the Fluor 

Econamine FG PlusSM technology as previously described in Section 4.1.7 with the exception 

that no SO2 polishing step is required in the NGCC case. If the pipeline natural gas used in this 

study contained the maximum amount of sulfur allowed per EPA specifications (0.6 gr S/100 

scf), the FG would contain 0.4 ppmv of SO2, which is well below the limit where a polishing 

scrubber would be required (10 ppmv). A description of the basic process steps is repeated here 

for completeness with minor modifications to reflect application in an NGCC system as opposed 

to PC.

The function of the FG cooling and supply system is to transport FG from the HRSG to the CO2

absorption tower, and condition FG pressure, temperature and moisture content so it meets the 

requirements of the Econamine process. Temperature and hence moisture content of the FG

exiting the HRSG is reduced in the Direct Contact FG Cooler, where FG is cooled using cooling 

water. 

FG Cooling and Supply 

The water condensed from the FG is collected in the bottom of the Direct Contact FG Cooler 

section and re-circulated to the top of the Direct Contact FG Cooler section via the FG

Circulation Water Cooler, which rejects heat to the plant CWS. Level in the Direct Contact FG

Cooler is controlled by directing the excess water to the cooling water return line. In the Direct 

Contact FG Cooler, FG is cooled beyond the CO2 absorption process requirements to 33°C 

(91°F) to account for the subsequent FG temperature increase of 14°C (25°F) in the FG blower. 

Downstream from the Direct Contact FG Cooler FG pressure is boosted in the FG blowers by 

approximately 0.01 MPa (2 psi) to overcome pressure drop in the CO2 absorber tower.

Cooling water is provided from the NGCC plant CWS and returned to the NGCC plant cooling 

tower. The CDR facility requires a significant amount of cooling water for FG cooling, water 

wash cooling, absorber intercooling, reflux condenser duty, reclaimer cooling, the lean solvent 

cooler, and CO2 compression interstage cooling. The cooling water requirements for the CDR 

facility in the NGCC capture case is about 594,308 lpm (157,000 gpm), which greatly exceeds 

the NGCC plant cooling water requirement of about 200,626 lpm (53,000 gpm).

Circulating Water System

The cooled FG enters the bottom of the CO2 Absorber and flows up through the tower 

countercurrent to a stream of lean MEA-based solvent called Econamine. Approximately 90 

percent of the CO2 in the feed gas is absorbed into the lean solvent, and the rest leaves the top of 

the absorber section and flows into the water wash section of the tower. The lean solvent enters 

the top of the absorber, absorbs the CO2 from the flue gas and leaves the bottom of the absorber 

with the absorbed CO2.

CO2 Absorption 
Cost and Performance Baseline for Fossil Energy Plants

447

The purpose of the Water Wash section is to minimize solvent losses due to mechanical 

entrainment and evaporation. The FG from the top of the CO2 Absorption section is contacted 

with a re-circulating stream of water for the removal of most of the lean solvent. The scrubbed 

gases, along with unrecovered solvent, exit the top of the wash section for discharge to the 

atmosphere via the vent stack. The water stream from the bottom of the wash section is collected 

on a chimney tray. A portion of the water collected on the chimney tray spills over to the 

absorber section as water makeup for the amine with the remainder pumped via the Wash Water 

Pump and cooled by the Wash Water Cooler, and recirculated to the top of the CO2 Absorber. 

The wash water level is maintained by water makeup from the Wash Water Makeup Pump. 

Water Wash Section

The rich solvent from the bottom of the CO2 Absorber is preheated by the lean solvent from the 

Solvent Stripper in the Rich Lean Solvent Exchanger. The heated rich solvent is routed to the 

Solvent Stripper for removal of the absorbed CO2. The stripped solvent from the bottom of the 

Solvent Stripper is pumped via the Hot Lean Solvent Pumps through the Rich Lean Exchanger to 

the Solvent Surge Tank. Prior to entering the Solvent Surge Tank, a slipstream of the lean 

solvent is pumped via the Solvent Filter Feed Pump through the Solvent Filter Package to 

prevent buildup of contaminants in the solution. From the Solvent Surge Tank the lean solvent is 

pumped via the Warm Lean Solvent Pumps to the Lean Solvent Cooler for further cooling, after 

which the cooled lean solvent is returned to the CO2 Absorber, completing the circulating solvent 

circuit.

Rich/Lean Amine Heat Exchange System

The purpose of the Solvent Stripper is to separate the CO2 from the rich solvent feed exiting the

bottom of the CO2 Absorber. The rich solvent is collected on a chimney tray below the bottom 

packed section of the Solvent Stripper and routed to the Solvent Stripper Reboilers where the 

rich solvent is heated by steam, stripping the CO2 from the solution. Steam is provided from the 

crossover pipe between the IP and LP sections of the steam turbine at about 0.51 MPa (73.5 psia) 

and 152°C (306°F). The hot wet vapor from the top of the stripper containing CO2, steam, and 

solvent vapor, is partially condensed in the Solvent Stripper Condenser by cross exchanging the 

hot wet vapor with cooling water. The partially condensed stream then flows to the Solvent 

Stripper Reflux Drum where the vapor and liquid are separated. The uncondensed CO2-rich gas 

is then delivered to the CO2 product compressor. The condensed liquid from the Solvent 

Stripper Reflux Drum is pumped via the Solvent Stripper Reflux Pumps where a portion of 

condensed overhead liquid is used as make-up water for the Water Wash section of the CO2

Absorber. The rest of the pumped liquid is routed back to the Solvent Stripper as reflux, which 

aids in limiting the amount of solvent vapors entering the stripper overhead system.

Solvent Stripper

A small slipstream of the lean solvent from the Solvent Stripper bottoms is fed to the Solvent 

Stripper Reclaimer for the removal of high-boiling nonvolatile impurities (HSS), volatile acids,

and iron products from the circulating solvent solution. The solvent bound in the HSS is 

recovered by reaction with caustic and heating with steam. The solvent reclaimer system 

reduces corrosion, foaming and fouling in the solvent system. The reclaimed solvent is returned 

Solvent Stripper Reclaimer 
Cost and Performance Baseline for Fossil Energy Plants

448

to the Solvent Stripper and the spent solvent is pumped via the Solvent Reclaimer Drain Pump to 

the Solvent Reclaimer Drain Tank.

Steam condensate from the Solvent Stripper Reclaimer accumulates in the Solvent Reclaimer 

Condensate Drum and level controlled to the Solvent Reboiler Condensate Drum. Steam 

condensate from the Solvent Stripper Reboilers is also collected in the Solvent Reboiler 

Condensate Drum and returned to the steam cycle just downstream of the deaerator via the 

Solvent Reboiler Condensate Pumps.

Steam Condensate

A proprietary corrosion inhibitor is continuously injected into the CO2 Absorber rich solvent 

bottoms outlet line, the Solvent Stripper bottoms outlet line and the Solvent Stripper top tray. 

This constant injection is to help control the rate of corrosion throughout the CO2 recovery plant 

system.

Corrosion Inhibitor System

In the compression section, the CO2 is compressed to 15.3 MPa (2,215 psia) by a six-stage 

centrifugal compressor. The discharge pressures of the stages were balanced to give reasonable 

power distribution and discharge temperatures across the various stages as shown in 

Gas Compression and Drying System

Exhibit 5-2.

Power consumption for this large compressor was estimated assuming a polytropic efficiency of 

86 percent and a mechanical efficiency of 98 percent for all stages. During compression to 15.3 

MPa (2,215 psia) in the multiple-stage, intercooled compressor, the CO2 stream is dehydrated to 

a dewpoint of -40oC (-40°F) with triethylene glycol. The virtually moisture-free SC CO2 stream 

is delivered to the plant battery limit as sequestration ready. CO2 TS&M costs were estimated 

and included in LCOE and COE using the methodology described in Section 2.7.

5.1.6

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 single 

span, opposed-flow casing, with the double-flow LP section in a separate casing. 

Steam Turbine

Main steam from the boiler passes through the stop valves and control valves and enters the 

turbine at 16.5 MPa/566°C (2400 psig/1050°F). 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 

2.5 MPa/566°C (360 psia/1050°F). After passing through the IP section, the steam enters a 

cross-over pipe, which transports the steam to the LP section. A branch line equipped with 

combined stop/intercept valves conveys LP steam from the HRSG LP drum to a tie-in at the 

cross-over line. The steam divides into two paths and flows through the LP sections exhausting 

downward into the condenser.
Cost and Performance Baseline for Fossil Energy Plants

449

Exhibit 5-2 CO2 Compressor Interstage Pressures

Stage Outlet Pressure, 

MPa (psia)

1 0.36 (52)

2 0.78 (113)

3 1.71 (248)

4 3.76 (545)

5 8.27 (1,200)

6 15.3 (2,215)

Turbine bearings are lubricated by a CL, water-cooled pressurized oil system. 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. The generator 

is a hydrogen-cooled synchronous type, generating power at 24 kV. A static, transformer type 

exciter is provided. The generator is cooled with a hydrogen gas recirculation system using fans 

mounted on the generator rotor shaft. The STG is controlled by a triple-redundant 

microprocessor-based electro-hydraulic control system. The system provides digital control of 

the unit in accordance with programmed control algorithms, color monitor/operator interfacing, 

and datalink interfaces to the balance-of-plant DCS, and incorporates on-line repair capability.

5.1.7 Water and Steam Systems

The function of the condensate system is to pump condensate from the condenser hotwell to the 

deaerator, through the gland steam condenser; and the low-temperature economizer section in the 

HRSG.

Condensate

The system consists of one main condenser; two 50 percent capacity, motor-driven vertical 

multistage condensate pumps (total of two pumps for the plant); one gland steam condenser; 

condenser air removal vacuum pumps, condensate polisher, and a low-temperature tube bundle 

in the HRSG.

Condensate is delivered to a common discharge header through two separate pump discharge 

lines, each with a check valve and a gate valve. A common minimum flow recirculation line 

discharging to the condenser is provided to maintain minimum flow requirements for the gland 

steam condenser and the condensate pumps.

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. One 100 percent capacity motor-driven feed 

pump is provided per each HRSG (total of two pumps for the plant). The FW pumps are 

equipped with an interstage takeoff to provide IP and LP FW. Each pump is provided with inlet 

and outlet isolation valves, outlet check valves, and individual minimum flow recirculation lines 

Feedwater
Cost and Performance Baseline for Fossil Energy Plants

450

discharging back to the deaerator storage tank. The recirculation flow is controlled by pneumatic 

flow control valves. In addition, the suctions of the boiler feed pumps are equipped with startup 

strainers, which are utilized during initial startup and following major outages or system 

maintenance.

The steam system is comprised of main, reheat, intermediate, and LP steam systems. The 

function of the main steam system is to convey main steam from the HRSG superheater outlet to 

the HP turbine stop valves. The function of the reheat system is to convey steam from the HP 

turbine exhaust to the HRSG reheater and from the HRSG reheater outlet to the turbine reheat 

stop valves.

Steam System

Main steam exits the HRSG superheater through a motor-operated stop/check valve and a motoroperated gate valve, and is routed to the HP turbine.

Cold reheat steam exits the HP turbine, and flows through a motor-operated isolation gate valve 

to the HRSG reheater. Hot reheat steam exits at the HRSG reheater through a motor-operated 

gate valve and is routed to the IP turbines. 

The function of the CWS is to supply cooling water to condense the main turbine exhaust steam, 

for the auxiliary cooling system and for the CDR facility in Case 14. The system consists of two 

50 percent capacity vertical CWPs (total of two pumps for the plant), a mechanical draft 

evaporative cooling tower, and interconnecting piping. The condenser is a single pass, 

horizontal type with divided water boxes. There are two separate circulating water circuits in 

each box. One-half of the condenser can be removed from service for cleaning or plugging 

tubes. This can be done during normal operation at reduced load. 

Circulating Water System

The auxiliary cooling system is a CL system. Plate and frame heat exchangers with circulating 

water as the cooling medium are provided. The system provides cooling water to the following 

systems:

1. CTG lube oil coolers

2. CTG air coolers

3. STG lube oil coolers

4. STG hydrogen coolers

5. Boiler feed water pumps 

6. Air compressors

7. Generator seal oil coolers (as applicable)

8. Sample room chillers

9. Blowdown coolers

10. Condensate extraction pump-motor coolers

The CDR system in Case 14 requires a substantial amount of cooling water that is provided by 

the NGCC plant CWS. The additional cooling load imposed by the CDR is reflected in the 

significantly larger CWPs and cooling tower in that case.
Cost and Performance Baseline for Fossil Energy Plants

451

Structures assumed for NGCC cases can be summarized as follows:

Buildings and Structures

1. Generation Building housing the STG

2. CWP House

3. Administration / Office / Control Room / Maintenance Building 

4. Water Treatment Building

5. Fire Water Pump House

5.1.8

The accessory electric plant consists of all switchgear and control equipment, generator 

equipment, station service equipment, conduit and cable trays, wire, and cable. It also includes 

the main transformer, required foundations, and standby equipment.

Accessory Electric Plant

5.1.9

An integrated plant-wide DCS is provided. The DCS is a redundant microprocessor-based, 

functionally distributed system. The control room houses an array of video monitors and 

keyboard units. The monitor/keyboard units are the primary interface between the generating 

process and operations personnel. The DCS incorporates plant monitoring and control functions 

for all the major plant equipment. The DCS is designed to provide 99.5 percent availability.

Instrumentation and Control

The plant equipment and the DCS are designed for automatic response to load changes from 

minimum load to 100 percent. Startup and shutdown routines are implemented as supervised 

manual procedures with operator selection of modular automation routines available.
Cost and Performance Baseline for Fossil Energy Plants

452

5.2 NGCC CASES

This section contains an evaluation of plant designs for Cases 13 and 14. These two cases are 

similar in design and are based on an NGCC plant with a constant thermal input. Both plants use 

a single reheat 16.5 MPa/566°C/566°C (2400 psig/1050°F/1050°F) cycle. The only difference 

between the two plants is that Case 14 includes CO2 capture while Case 13 does not.

The balance of Section 5.2 is organized as follows:

• Process and System Description provides an overview of the technology operation as 

applied to Case 13. The systems that are common to all NGCC cases were covered in 

Section 5.1 and only features that are unique to Case 13 are discussed further in this 

section.

• Key Assumptions is a summary of study and modeling assumptions relevant to Cases 13 

and 14.

• Sparing Philosophy is provided for both Cases 13 and 14.

• Performance Results provides the main modeling results from Case 13, including the 

performance summary, environmental performance, carbon balance, water balance, mass 

and energy balance diagrams, and energy balance table.

• Equipment List provides an itemized list of major equipment for Case 13 with account 

codes that correspond to the cost accounts in the Cost Estimates section.

• Cost Estimates provides a summary of capital and operating costs for Case 13.

• Process and System Description, Performance Results, Equipment List and Cost 

Estimates are reported for Case 14.

5.2.1

In this section the NGCC process without CO2 capture is described. The system description 

follows the BFD in 

Process Description

Exhibit 5-3 and stream numbers reference the same exhibit. The tables in 

Exhibit 5-4 provide process data for the numbered streams in the BFD. The BFD shows only 

one of the two CT/HRSG combinations, but the flow rates in the stream table are the total for 

two systems.

Ambient air (stream 1) and natural gas (stream 2) are combined in the dry LNB, which is 

operated to control the rotor inlet temperature at 1371°C (2500°F). The FG exits the turbine at 

629°C (1163°F) (stream 3) and passes into the HRSG. The HRSG generates both the main 

steam and reheat steam for the steam turbine. FG exits the HRSG at 106°C (222°F) and passes 

to the plant stack
Cost and Performance Baseline for Fossil Energy Plants

453

Exhibit 5-3 Case 13 Block Flow Diagram, NGCC without CO2 Capture
Cost and Performance Baseline for Fossil Energy Plants

454

Exhibit 5-4 Case 13 Stream Table, NGCC without CO2 Capture

1 2 3 4 5 6

V-L Mole Fraction

Ar 0.0092 0.0000 0.0089 0.0089 0.0000 0.0000

CH4 0.0000 0.9310 0.0000 0.0000 0.0000 0.0000

C2H6 0.0000 0.0320 0.0000 0.0000 0.0000 0.0000

C3H8 0.0000 0.0070 0.0000 0.0000 0.0000 0.0000

C4H10 0.0000 0.0040 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0003 0.0100 0.0404 0.0404 0.0000 0.0000

H2O 0.0099 0.0000 0.0867 0.0867 1.0000 1.0000

N2 0.7732 0.0160 0.7432 0.7432 0.0000 0.0000

O2 0.2074 0.0000 0.1209 0.1209 0.0000 0.0000

SO2 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

V-L Flowrate (kgmol/hr) 109,323 4,380 113,831 113,831 21,589 28,545

V-L Flowrate (kg/hr) 3,154,735 75,901 3,230,636 3,230,636 388,927 514,240

Solids Flowrate (kg/hr) 0 0 0 0 0 0

Temperature (°C) 15 38 629 106 566 38

Pressure (MPa, abs) 0.10 3.10 0.11 0.10 16.65 0.01

Enthalpy (kJ/kg)A 30.23 46.30 835.81 248.81 3,472.36 160.61

Density (kg/m3) 1.2 22.2 0.4 0.9 47.7 992.9

V-L Molecular Weight 28.857 17.328 28.381 28.381 18.015 18.015

V-L Flowrate (lbmol/hr) 241,016 9,657 250,954 250,954 47,595 62,930

V-L Flowrate (lb/hr) 6,955,000 167,333 7,122,333 7,122,333 857,437 1,133,706

Solids Flowrate (lb/hr) 0 0 0 0 0 0

Temperature (°F) 59 100 1,163 222 1,050 101

Pressure (psia) 14.7 450.0 15.2 14.7 2,414.7 1.0

Enthalpy (Btu/lb)A 13.0 19.9 359.3 107.0 1,492.8 69.1

Density (lb/ft3

) 0.076 1.384 0.025 0.057 2.977 61.982

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Fossil Energy Plants

455

5.2.2

System assumptions for Cases 13 and 14, NGCC with and without CO2 capture, are compiled in

Key System Assumptions

Exhibit 5-5.

Exhibit 5-5 NGCC Plant Study Configuration Matrix

Case 13

w/o CO2 Capture 

Case 14

w/CO2 Capture

Steam Cycle, MPa/°C/°C (psig/°F/°F) 16.5/566/566

(2400/1050/1050)

16.5/566/566

(2400/1050/1050)

Fuel Natural Gas Natural Gas

Fuel Pressure at Plant Battery Limit MPa 

(psia) 3.1 (450) 3.1 (450)

Condenser Pressure, mm Hg (in Hg) 50.8 (2) 50.8 (2)

Cooling Water to Condenser, °C (oF) 16 (60) 16 (60)

Cooling Water from Condenser, °C (oF) 27 (80) 27 (80)

Stack Temperature, °C (°F) 106 (222) 29 (85)

SO2 Control Low Sulfur Fuel Low Sulfur Fuel

NOx Control LNB and SCR LNB and SCR

SCR Efficiency, % (A) 90 90

Ammonia Slip (End of Catalyst Life), 

ppmv

10 10

Particulate Control N/A N/A

Mercury Control N/A N/A

CO2 Control N/A Econamine

Overall CO2 Capture (A) N/A 90.7%

CO2 Sequestration N/A Off-site Saline 

Formation

A. Removal efficiencies are based on the FG content

The balance of plant assumptions are common to both NGCC cases and are presented in 

Balance of Plant – Cases 13 and 14

Exhibit 5-6.
Cost and Performance Baseline for Fossil Energy Plants

456

Exhibit 5-6 NGCC Balance of Plant Assumptions

Cooling System Recirculating Wet Cooling Tower

Fuel and Other Storage

Natural Gas Pipeline supply at 3.1 MPa (450 psia) and 38°C 

(100°F)

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 GT 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 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 is 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.

5.2.3

Dual trains are used to accommodate the size of commercial GTs. There is no redundancy other 

than normal sparing of rotating equipment. The plant design consists of the following major 

subsystems:

Sparing Philosophy

• Two advanced F class CTGs (2 x 50%)

• Two 3-pressure reheat HRSGs with self supporting stacks and SCR systems (2 x 50%)

• One 3-pressure reheat, triple-admission STG (1 x 100%)

• Two trains of Econamine CO2 capture (2 x 50%) (Case 14 only)
Cost and Performance Baseline for Fossil Energy Plants

457

5.2.4

The plant produces a net output of 555 MW at a net plant efficiency of 50.2 percent (HHV 

basis).

Case 13 Performance Results

Overall plant performance is summarized in Exhibit 5-7, which includes auxiliary power 

requirements.

Exhibit 5-7 Case 13 Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Gas Turbine Power 362,200

Steam Turbine Power 202,500

TOTAL POWER, kWe 564,700

AUXILIARY LOAD SUMMARY, kWe

Condensate Pumps 170

Boiler Feedwater Pumps 2,720

Circulating Water Pump 2,300

Ground Water Pumps 210

Cooling Tower Fans 1,190

SCR 10

Gas Turbine Auxiliaries 700

Steam Turbine Auxiliaries 100

Miscellaneous Balance of Plant1 500

Transformer Losses 1,720

TOTAL AUXILIARIES, kWe 9,620

NET POWER, kWe 555,080

Net Plant Efficiency (HHV) 50.2%

Net Plant Efficiency (LHV) 55.7%

Net Plant Heat Rate (HHV), kJ/kWh (Btu/kWh) 7,172 (6,798)

Net Plant Heat Rate (LHV), kJ/kWh (Btu/kWh) 6,466 (6,129)

CONDENSER COOLING DUTY, 106 kJ/hr (106 Btu/hr) 1,139 (1,080)

CONSUMABLES

Natural Gas Feed Flow, kg/hr (lb/hr) 75,901 (167,333)

Thermal Input (HHV), kWth 1,105,812

Thermal Input (LHV) , kWth 997,032

Raw Water Withdrawal, m3/min (gpm) 8.9 (2,362)

Raw Water Consumption, m3/min (gpm) 6.9 (1,831)

1. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Fossil Energy Plants

458

The environmental targets for emissions of NOx, SO2, and PM were presented in Section 2.4. A 

summary of the plant air emissions for Case 13 is presented in 

Environmental Performance

Exhibit 5-8.

Exhibit 5-8 Case 13 Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

85% CF

kg/MWh

(lb/MWh)

SO2 Negligible Negligible Negligible

NOx 0.004 (0.009) 115 (127) 0.027 (0.060)

Particulates Negligible Negligible Negligible

Hg Negligible Negligible Negligible

CO2 51 (118) 1,507,427 

(1,661,654) 359 (790)

CO2

1 365 (804)

1 CO2 emissions based on net power instead of gross power

The operation of the modern, state-of-the-art GT fueled by natural gas, coupled to a HRSG, 

results in very low levels of NOx emissions and negligible levels of SO2, particulate and Hg 

emissions. As noted in Section 2.4, if the fuel contains the maximum amount of sulfur 

compounds allowed in pipeline natural gas, the NGCC SO2 emissions would be 21 tonnes/yr (23 

tons/yr) at 85 percent CF, or 0.00195 lb/MMBtu.

The low level of NOx production (2.5 ppmvd at 15 percent O2) is achieved by utilizing a dry 

LNB coupled with an SCR system.

CO2 emissions are reduced relative to those produced by burning coal given the same power 

output because of the higher heat content of natural gas, the lower carbon intensity of gas relative 

to coal, and the higher overall efficiency of the NGCC plant relative to a coal-fired plant.

The carbon balance for the plant is shown in Exhibit 5-9. The carbon input to the plant consists 

of carbon in the natural gas and carbon as CO2 in the CT air. Carbon leaves the plant as CO2

through the stack.

Exhibit 5-9 Case 13 Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Natural Gas 54,822 (120,863) Stack Gas 55,251 (121,808)

Air (CO2) 429 (946)

Total 55,251 (121,808) Total 55,251 (121,808)
Cost and Performance Baseline for Fossil Energy Plants

459

A sulfur balance is not included for Case 13 because the sulfur concentration of the natural gas 

feed is negligible. Consequently, sulfur emissions are also negligible, as shown in Exhibit 5-8, 

despite the use of no sulfur control technology.

Exhibit 5-10 shows the water balance for Case 13. Water demand represents the total amount of 

water required for a particular process. Some water is recovered within the process and is reused as internal recycle. The difference between demand and recycle is raw water withdrawal. 

Raw water withdrawal is defined as the water removed from the ground or diverted from a 

surface-water source for use in the plant and was assumed to be provided 50 percent by a POTW 

and 50 percent from groundwater. Raw water withdrawal can be represented by the water 

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

as condenser and cooling tower makeup. The difference between water withdrawal and process 

water discharge is defined as water consumption and can be represented by the portion of the raw 

water withdrawn that is evaporated, transpired, incorporated into products or otherwise not 

returned to the water source from which it was withdrawn. Water consumption represents the 

net impact of the plant process on the water source balance.

Exhibit 5-10 Case 13 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)

Condenser Makeup

BFW Makeup

0.1 (23)

0.1 (23)

0.0 (0) 0.1 (23)

0.1 (23)

0.0 (0) 0.1 (23)

Cooling Tower

BFW 

Blowdown

8.9 (2,362)

0.0 (0)

0.1 (23)

0.1 (23)

8.9 (2,339)

-0.1 (-23)

2.0 (531) 6.8 (1,808)

Total 9.0 (2,385) 0.1 (23) 8.9 (2,362) 2.0 (531) 6.9 (1,831)

A heat and mass balance diagram is shown for the NGCC in 

Heat and Mass Balance Diagrams

Exhibit 5-11. An overall plant 

energy balance is provided in tabular form in Exhibit 5-12. The power out is the combined CT

and steam turbine power prior to generator losses. The power at the generator terminals (shown 

in Exhibit 5-7) is calculated by multiplying the power out by a combined generator efficiency of 

98.4 percent.
Cost and Performance Baseline for Fossil Energy Plants

460

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

461

Exhibit 5-11 Case 13 Heat and Mass Balance, NGCC without CO2 Capture

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Nitrogen

Natural Gas

Carbon Dioxide

Water

Steam

PAGES

1 OF 1

NATURAL GAS COMBINED CYCLE PLANT

CASE 13

2 X ADVANCED F-CLASS GT

2400/1050/1050

DWG. NO.

BB-HMB-CS-13-PG-1

Flue Gas

AMBIENT

AIR

1 6,955,000 W

59.0 T

14.7 P

12.9 H

Gross Plant Power: 565 MWe

Auxiliary Load: 10 MWe

Net Plant Power: 555 MWe

Net Plant Efficiency, HHV: 50.2%

ADVANCED Net Plant Heat Rate: 6,798 BTU/KWe

F CLASS

GAS TURBINES

COMBUSTOR

NATURAL

GAS 167,333 W

100.0 T

450.0 P

19.9 H

2

7,122,333 W

222.4 T

14.7 P

106.9 H

7,122,333 W

1,163.5 T

15.2 P

359.3 H

GENERATOR

CONDENSATE

PUMPS

8,801 

W

1,302 

W

101.3 T

130.0 P

69.5 H

1,133,706 W

101.1 T

1.0 P

69.1 H

1,400 W

581.0 T

75.0 P

1,321.3 H

1,017,200 W

641.4 T

75.0 P

1,351.1 H

1,110,400 W

632.6 T

75.0 P

1,346.8 H

1,110,400 W

101.1 T

1.0 P

1,032.6 H

HOT WELL

CONDENSER

STACK

4

STEAM TURBINE

MAKEUP

11,337 W

59.0 T

14.7 P

27.1 H

AIR INLET

FILTER

3

HP PUMP

1,133,706 W

253.0 T

100.0 P

221.9 H

BLOWDOWN

94,141 W

300.1 T

95.0 P

269.4 H

173,467 W

300.7 T

400.0 P

270.7 H

866,098 W

305.3 T

2,540.0 P

279.3 H 11,337 

W

GLAND SEAL

CONDENSER

1,400 W

212.0 T

14.7 P

179.9 H

LP TURBINE

9,569 W

1,133,706 W

103.9 T

120.0 P

72.1 H

Three Pressure 

Heat Recovery 

Steam Generator 

(HRSG)

829,777 W

1,055.0 T

360.0 P

1,553.4 H

A

A

171,732 W

1,055.0 T

360.0 P

1,553.4 H

HOT REHEAT

COLD

REHEAT

829,777 W

587.9 T

390.0 P

1,300.6 H

STEAM SEAL

REGULATOR

93,200 W

537.0 T

80.0 P

1,299.1 H

16,993 W

970.1 T

1,850.0 P

1,459.8 H

HP

TURBINE

IP

TURBINE

852,917 

W

2,654 W

1,050.0 T

2,414.7 P

1,492.8 H

1,018,502 

W

MAIN STEAM

857,437 W

1,050.0 T

2,414.7 P

1,492.8 H

5

10,969 W

866 

W

IP

STEAM

IP PUMP

LP PUMP

6

DOE/NETL

SC PC PLANT

CASE 13
Cost and Performance Baseline for Fossil Energy Plants

462

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

463

Exhibit 5-12 Case 13 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Natural Gas 3,981 (3,773) 2.7 (2.5) 3,984 (3,776)

GT Air 95.4 (90.4) 95 (90)

Raw Water Withdrawal 33.6 (31.9) 34 (32)

Auxiliary Power 35 (33) 35 (33)

Totals 3,981 (3,773) 131.6 (124.8) 35 (33) 4,147 (3,931)

Heat Out GJ/hr (MMBtu/hr)

Cooling Tower 

Blowdown 14.9 (14.2) 15 (14)

Stack Gas 804 (762) 804 (762)

Condenser 1,141 (1,082) 1,141 (1,082)

Process Losses* 154 (146) 154 (146)

Power 2,033 (1,927) 2,033 (1,927)

Totals 0 (0) 2,114 (2,004) 2,033 (1,927) 4,147 (3,931)

* Process Losses are calculated by difference and reflect various turbine, and other heat and 

work losses.
Cost and Performance Baseline for Fossil Energy Plants

464

5.2.5

Major equipment items for the NGCC plant 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 

Case 13 – Major Equipment List

5.2.6. In general, the design conditions include a 10 percent 

contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 COAL AND SORBENT HANDLING

N/A

ACCOUNT 2 FUEL AND SORBENT PREPARATION AND FEED

Equipment 

No. Description Type Operating Qty. Spares

1 Gas Pipeline

Underground, 

coated carbon 

steel, wrapped 

cathodic 

protection

16 km 

(10 mile) 0

2 Gas Metering Station -- 1 0

Design Condition

63 m3/min @ 3.1 MPa

(2,216 acfm @ 450 psia)

41 cm (16 in) standard wall pipe

63 m3/min (2,216 acfm)
Cost and Performance Baseline for Fossil Energy Plants

465

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT

Equipment 

No. Description Type Operating 

Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 2 0

2 Condensate Pumps Vertical canned 2 1

4 Auxiliary Boiler Shop fabricated, water 

tube 1 0

5

Service Air 

Compressors Flooded Screw 2 1

6 Instrument Air Dryers Duplex, regenerative 2 1

7 Closed Cycle Cooling 

Heat Exchangers Plate and frame 2 0

8 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 2 1

9 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine 1 1

10 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal 1 1

11 Raw Water Pumps Stainless steel, single 

suction 2 1

12 Filtered Water Pumps Stainless steel, single 

suction 2 1

13 Filtered Water Tank Vertical, cylindrical 1 0

14 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly 

and electro-deionization 

unit

1 0

15 Liquid Waste Treatment 

System 1 0

Design Condition

678,767 liters (179,310 gal)

4,732 lpm @ 110 m H2O

(1,250 gpm @ 360 ft H2O)

13 MMkJ/hr (13 MMBtu/hr)

3 Boiler Feedwater Pump

Horizontal, split case, 

multi-stage, centrifugal, 

with interstage bleed for 

IP and LP feedwater

5,300 lpm @ 21 m H2O

(1,400 gpm @ 70 ft H2O)

2

HP water: 3,634 lpm @ 2,103 m H2O 

(960 gpm @ 6,900 ft H2O)

IP water: 719 lpm @ 283 m H2O 

(190 gpm @ 930 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C

(40,000 lb/h, 400 psig, 650°F)

13 m3/min @ 0.7 MPa

(450 scfm @ 100 psig)

LP water: 379 lpm @ 24.4 m H2O 

(100 gpm @ 80 ft H2O)

1

143,847 liter (38,000 gal)

341 lpm (90 gpm)

10 years, 24-hour storm

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

4,921 lpm @ 18 m H2O

(1,300 gpm @ 60 ft H2O)

151 lpm @ 49 m H2O

(40 gpm @ 160 ft H2O)

13 m3/min (450 scfm)
Cost and Performance Baseline for Fossil Energy Plants

466

ACCOUNT 4 GASIFIER, BOILER AND ACCESSORIES 

N/A

ACCOUNT 5 FLUE GAS CLEANUP

N/A

ACCOUNT 6 COMBUSTION TURBINE GENERATORS AND AUXILIARIES

ACCOUNT 7 WASTE HEAT BOILER, DUCTING, AND STACK 

Equipment 

No. Description Type Operating Qty. Spares

1 Gas Turbine Advanced F class w/ 

dry low-NOx burner 2 0

2 Gas Turbine 

Generator TEWAC 2 0

Design Condition

184 MW 

200 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase

Equipment 

No. Description Type Operating 

Qty. Spares

1 Stack CS plate, type 409SS 

liner 2 0

3 SCR Reactor Space for spare layer 2 0

4 SCR Catalyst -- 1 layer 0

5

Dilution Air 

Blowers Centrifugal 2 1

6 Ammonia Feed 

Pump Centrifugal 2 1

7 Ammonia 

Storage Tank Horizontal tank 1 0

2 2 0 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator Reheat steam - 249,852 kg/h, 2.4 

MPa/566°C (550,830 lb/h, 345 

psig/1,050°F)

Design Condition

46 m (150 ft) high x

7.5 m (25 ft) diameter

Main steam - 213,910 kg/h, 16.5 

MPa/566°C (471,590 lb/h, 2,400 

psig/1,050°F)

1,778,084 kg/h (3,920,000 lb/h)

Space available for an additional 

catalyst layer

11 m3/min @ 107 cm WG

(390 scfm @ 42 in WG)

3.8 lpm @ 91 m H2O

(1 gpm @ 300 ft H2O)

68,138 liter (18,000 gal)
Cost and Performance Baseline for Fossil Energy Plants

467

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

N/A

Equipment 

No. Description Type Operating Qty. Spares

1 Steam Turbine

Tandem compound, 

HP, IP, and twoflow LP turbines

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitation 1 0

3 Steam Bypass One per HRSG 2 0

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1 0

Design Condition

213 MW 

16.5 MPa/566°C/566°C 

(2,400 psig/ 

1050°F/1050°F)

1,254 MMkJ/hr, (1,190 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 

11°C (20°F)

240 MVA @ 0.9 p.f., 

24 kV, 60 Hz, 3-phase

50% steam flow @ design 

steam conditions

Equipment 

No. Description Type Operating Qty. Spares

1 Circulating Water 

Pumps Vertical, wet pit 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell

1 0

Design Condition

230,912 lpm @ 30.5 m

(61,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

1,283 MMkJ/hr (1,217 

MMBtu/hr) heat load
Cost and Performance Baseline for Fossil Energy Plants

468

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment 

No. Description Type Operating Qty. Spares

1 CTG Transformer Oil-filled 2 0

3 Auxiliary 

Transformer Oil-filled 1 1

4 Low Voltage 

Transformer Dry ventilated 1 1

5

CTG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, self-cooled 2 0

6

STG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, self-cooled 1 0

7 Medium Voltage 

Switchgear Metal clad 1 1

8 Low Voltage 

Switchgear Metal enclosed 1 1

9 Emergency Diesel 

Generator

Sized for emergency 

shutdown 1 0

Design Condition

24 kV/345 kV, 200 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 230 MVA, 

3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz

4.16 kV/480 V, 1 MVA, 

3-ph, 60 Hz

750 kW, 480 V, 3-ph, 60 Hz

24 kV/4.16 kV, 09 MVA, 

3-ph, 60 Hz

2 STG Transformer Oil-filled 1 0

Equipment 

No. Description Type Operating Qty. Spares

1 DCS - Main 

Control

Monitor/keyboard; 

Operator printer (laser 

color); Engineering 

printer (laser B&W)

1 0

3 DCS - Data 

Highway Fiber optic 1 0

Design Condition

Operator stations/printers and 

engineering stations/printers

0

Fully redundant, 25% spare

2 DCS - Processor 1 Microprocessor with 

redundant input/output N/A
Cost and Performance Baseline for Fossil Energy Plants

469

5.2.6

The cost estimating methodology was described previously in Section 

Case 13 – Cost Estimating

2.7. Exhibit 5-13 shows 

the total plant capital cost summary organized by cost account and Exhibit 5-14 shows a more 

detailed breakdown of the capital costs. Exhibit 5-15 shows the initial and annual O&M costs.

The estimated TOC of the NGCC with no CO2 capture is $718/kW. No process contingency was 

included in this case because all elements of the technology are commercially proven. The 

project contingency is 8.6 percent of TOC. The COE is 58.9 mills/kWh.
Cost and Performance Baseline for Fossil Energy Plants

470

Exhibit 5-13 Case 13 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14

Project: Bituminous Baseline Study

Case: Case 13 - 1x555 MWnet 2x1 7FB NGCC

Plant Size: 555.1 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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 2 COAL & SORBENT PREP & FEED $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 3 FEEDWATER & MISC. BOP SYSTEMS $22,444 $4,461 $6,516 $0 $0 $33,421 $2,819 $0 $5,782 $42,022 $76

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4-4.9 Other gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 5A GAS CLEANUP & PIPING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $75,294 $0 $4,804 $0 $0 $80,098 $6,800 $0 $8,690 $95,589 $172

6.2-6.9 Combustion Turbine Other $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $3

SUBTOTAL 6 $75,294 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,490 $176

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $80

7.2-7.9 SCR System, Ductwork and Stack $1,243 $950 $1,118 $0 $0 $3,311 $282 $0 $583 $4,176 $8

SUBTOTAL 7 $34,200 $950 $5,397 $0 $0 $40,548 $3,453 $0 $4,624 $48,624 $88

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $23,774 $0 $3,855 $0 $0 $27,630 $2,374 $0 $3,000 $33,005 $59

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $8,304 $798 $5,509 $0 $0 $14,611 $1,190 $0 $2,164 $17,965 $32

SUBTOTAL 8 $32,078 $798 $9,365 $0 $0 $42,241 $3,565 $0 $5,164 $50,970 $92

 9 COOLING WATER SYSTEM $5,524 $4,298 $3,854 $0 $0 $13,677 $1,137 $0 $2,106 $16,920 $30

10 ASH/SPENT SORBENT HANDLING SYS $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT $16,639 $3,671 $8,860 $0 $0 $29,170 $2,237 $0 $3,330 $34,737 $63

12 INSTRUMENTATION & CONTROL $5,778 $593 $4,801 $0 $0 $11,173 $930 $0 $1,387 $13,490 $24

13 IMPROVEMENTS TO SITE $1,722 $935 $4,582 $0 $0 $7,238 $640 $0 $1,576 $9,455 $17

14 BUILDINGS & STRUCTURES $0 $4,155 $4,417 $0 $0 $8,571 $697 $0 $1,390 $10,658 $19

 

TOTAL COST $193,680 $20,581 $53,339 $0 $0 $267,599 $22,400 $0 $34,366 $324,365 $584

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline for Fossil Energy Plants

471

Exhibit 5-14 Case 13 Total Plant Cost Details

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.2 Coal Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.3 Coal Conveyors & Yd Crush $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.4 Other Coal Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 1. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.3 Slurry Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 2. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,426 $2,499 $2,055 $0 $0 $6,980 $576 $0 $1,133 $8,690 $16

3.2 Water Makeup & Pretreating $1,466 $153 $766 $0 $0 $2,384 $203 $0 $517 $3,105 $6

3.3 Other Feedwater Subsystems $1,106 $374 $314 $0 $0 $1,794 $144 $0 $291 $2,229 $4

3.4 Service Water Systems $173 $357 $1,157 $0 $0 $1,687 $147 $0 $367 $2,201 $4

3.5 Other Boiler Plant Systems $1,162 $450 $1,043 $0 $0 $2,655 $225 $0 $432 $3,313 $6

3.6 Natural Gas, incl. pipeline $14,667 $505 $440 $0 $0 $15,612 $1,323 $0 $2,540 $19,476 $35

3.7 Waste Treatment Equipment $529 $0 $302 $0 $0 $831 $72 $0 $181 $1,084 $2

3.8 Misc. Equip.(cranes,AirComp.,Comm.) $915 $122 $439 $0 $0 $1,477 $128 $0 $321 $1,925 $3

SUBTOTAL 3. $22,444 $4,461 $6,516 $0 $0 $33,421 $2,819 $0 $5,782 $42,022 $76

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4 LT Heat Recovery & FG Saturation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.5 Misc. Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Cost and Performance Baseline for Fossil Energy Plants

472

Exhibit 5-14 Case 13 Total Plant Cost Details (Continued)

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.2 Elemental Sulfur Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.3 Mercury Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.4 COS Hydrolysis $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.5 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Fuel Gas Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.9 HGCU Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

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 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $75,294 $0 $4,804 $0 $0 $80,098 $6,800 $0 $8,690 $95,589 $172

6.2 Combustion Turbine Accessories $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 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $3

SUBTOTAL 6. $75,294 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,490 $176

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $80

7.2 SCR System $1,243 $522 $733 $0 $0 $2,498 $215 $0 $407 $3,120 $6

7.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.9 HRSG,Duct & Stack Foundations $0 $428 $385 $0 $0 $813 $68 $0 $176 $1,057 $2

SUBTOTAL 7. $34,200 $950 $5,397 $0 $0 $40,548 $3,453 $0 $4,624 $48,624 $88

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $23,774 $0 $3,855 $0 $0 $27,630 $2,374 $0 $3,000 $33,005 $59

8.2 Turbine Plant Auxiliaries $161 $0 $369 $0 $0 $530 $46 $0 $58 $634 $1

8.3 Condenser & Auxiliaries $4,108 $0 $1,226 $0 $0 $5,334 $457 $0 $579 $6,370 $11

8.4 Steam Piping $4,035 $0 $2,653 $0 $0 $6,688 $513 $0 $1,080 $8,281 $15

8.9 TG Foundations $0 $798 $1,261 $0 $0 $2,059 $175 $0 $447 $2,680 $5

SUBTOTAL 8. $32,078 $798 $9,365 $0 $0 $42,241 $3,565 $0 $5,164 $50,970 $92

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $3,880 $0 $496 $0 $0 $4,377 $373 $0 $475 $5,224 $9

9.2 Circulating Water Pumps $1,142 $0 $63 $0 $0 $1,205 $91 $0 $130 $1,425 $3

9.3 Circ.Water System Auxiliaries $93 $0 $12 $0 $0 $105 $9 $0 $11 $126 $0

9.4 Circ.Water Piping $0 $2,713 $657 $0 $0 $3,370 $272 $0 $546 $4,189 $8

9.5 Make-up Water System $229 $0 $305 $0 $0 $534 $46 $0 $87 $667 $1

9.6 Component Cooling Water Sys $180 $215 $143 $0 $0 $539 $45 $0 $88 $672 $1

9.9 Circ.Water System Foundations $0 $1,370 $2,177 $0 $0 $3,547 $301 $0 $770 $4,618 $8

SUBTOTAL 9. $5,524 $4,298 $3,854 $0 $0 $13,677 $1,137 $0 $2,106 $16,920 $30
Cost and Performance Baseline for Fossil Energy Plants

473

Exhibit 5-14 Case 13 Total Plant Cost Details (Continued)

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.7 Ash Transport & Feed Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.9 Ash/Spent Sorbent Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 10. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $4,068 $0 $2,444 $0 $0 $6,513 $552 $0 $530 $7,594 $14

11.2 Station Service Equipment $1,208 $0 $102 $0 $0 $1,310 $108 $0 $106 $1,525 $3

11.3 Switchgear & Motor Control $1,489 $0 $253 $0 $0 $1,742 $145 $0 $189 $2,076 $4

11.4 Conduit & Cable Tray $0 $712 $2,194 $0 $0 $2,905 $251 $0 $474 $3,630 $7

11.5 Wire & Cable $0 $2,266 $1,391 $0 $0 $3,657 $236 $0 $584 $4,477 $8

11.6 Protective Equipment $0 $563 $1,916 $0 $0 $2,480 $217 $0 $270 $2,966 $5

11.7 Standby Equipment $103 $0 $94 $0 $0 $197 $17 $0 $21 $235 $0

11.8 Main Power Transformers $9,770 $0 $146 $0 $0 $9,916 $673 $0 $1,059 $11,648 $21

11.9 Electrical Foundations $0 $130 $319 $0 $0 $449 $38 $0 $98 $585 $1

SUBTOTAL 11. $16,639 $3,671 $8,860 $0 $0 $29,170 $2,237 $0 $3,330 $34,737 $63

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 $735 $0 $458 $0 $0 $1,193 $101 $0 $194 $1,488 $3

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 $220 $0 $132 $0 $0 $351 $30 $0 $57 $438 $1

12.7 Computer & Accessories $3,514 $0 $105 $0 $0 $3,619 $298 $0 $392 $4,308 $8

12.8 Instrument Wiring & Tubing $0 $593 $1,134 $0 $0 $1,727 $130 $0 $279 $2,136 $4

12.9 Other I & C Equipment $1,310 $0 $2,972 $0 $0 $4,282 $372 $0 $465 $5,120 $9

SUBTOTAL 12. $5,778 $593 $4,801 $0 $0 $11,173 $930 $0 $1,387 $13,490 $24
Cost and Performance Baseline for Fossil Energy Plants

474

Exhibit 5-14 Case 13 Total Plant Cost Details (Continued)

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

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $92 $1,837 $0 $0 $1,929 $172 $0 $420 $2,520 $5

13.2 Site Improvements $0 $843 $1,047 $0 $0 $1,890 $167 $0 $411 $2,469 $4

13.3 Site Facilities $1,722 $0 $1,698 $0 $0 $3,419 $302 $0 $744 $4,465 $8

SUBTOTAL 13. $1,722 $935 $4,582 $0 $0 $7,238 $640 $0 $1,576 $9,455 $17

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $236 $125 $0 $0 $361 $28 $0 $58 $447 $1

14.2 Steam Turbine Building $0 $1,972 $2,626 $0 $0 $4,598 $378 $0 $746 $5,722 $10

14.3 Administration Building $0 $455 $308 $0 $0 $763 $61 $0 $124 $947 $2

14.4 Circulation Water Pumphouse $0 $152 $75 $0 $0 $227 $18 $0 $37 $281 $1

14.5 Water Treatment Buildings $0 $316 $288 $0 $0 $605 $49 $0 $98 $752 $1

14.6 Machine Shop $0 $394 $252 $0 $0 $647 $51 $0 $105 $803 $1

14.7 Warehouse $0 $255 $154 $0 $0 $408 $32 $0 $66 $507 $1

14.8 Other Buildings & Structures $0 $76 $56 $0 $0 $132 $11 $0 $21 $164 $0

14.9 Waste Treating Building & Str. $0 $298 $533 $0 $0 $831 $69 $0 $135 $1,036 $2

SUBTOTAL 14. $0 $4,155 $4,417 $0 $0 $8,571 $697 $0 $1,390 $10,658 $19

TOTAL COST $193,680 $20,581 $53,339 $0 $0 $267,599 $22,400 $0 $34,366 $324,365 $584

Owner's Costs

Preproduction Costs

6 Months All Labor $2,880 $5

1 Month Maintenance Materials $388 $1

1 Month Non-fuel Consumables $146 $0

1 Month Waste Disposal $0 $0

25% of 1 Months Fuel Cost at 100% CF $4,509 $8

2% of TPC $6,487 $12

Total $14,410 $26

Inventory Capital

60 day supply of consumables at 100% CF $180 $0

0.5% of TPC (spare parts) $1,622 $3

Total $1,802 $3

Initial Cost for Catalyst and Chemicals $0 $0

Land $300 $1

Other Owner's Costs $48,655 $88

Financing Costs $8,758 $16

Total Overnight Costs (TOC) $398,290 $718

TASC Multiplier (IOU, low-risk, 33 year) 1.075

Total As-Spent Cost (TASC) $428,162 $771
Cost and Performance Baseline for Fossil Energy Plants

475

Exhibit 5-15 Case 13 Initial and Annual Operating and Maintenance Cost Summary

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 13 - 1x555 MWnet 2x1 7FB NGCC Heat Rate-net (Btu/kWh): 6,798

MWe-net: 555

 Capacity Factor (%): 85

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

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 1.0 1.0

 Operator 2.0 2.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 1.0 1.0

 TOTAL-O.J.'s 5.0 5.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $1,972,971 $3.554

Maintenance Labor Cost $2,635,374 $4.748

Administrative & Support Labor $1,152,086 $2.076

Property Taxes and Insurance $6,487,309 $11.687

TOTAL FIXED OPERATING COSTS $12,247,740 $22.065

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $3,953,061 $0.00096

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water (/1000 gallons) 0.00 1700.64 1.08 $0 $570,718 $0.00014

Chemicals

MU & WT Chem. (lbs) 0.00 10131.92 0.17 $0 $544,027 $0.00013

MEA Solvent (ton) 0.00 0.00 2249.89 $0 $0 $0.00000

Activated Carbon (lb) 0.00 0.00 1.05 $0 $0 $0.00000

Corrosion Inhibitor 0.00 0.00 0.00 $0 $0 $0.00000

SCR Catalyst (m3) w/equip. 0.07 5775.94 $0 $129,612 $0.00003

Ammonia (19% NH3) ton 0.00 6.06 129.80 $0 $244,142 $0.00006

Subtotal Chemicals $0 $917,781 $0.00022

Other

Supplemental Fuel (MBtu) 0.00 0.00 0.00 $0 $0 $0.00000

Gases, N2 etc.(/100scf) 0.00 0.00 0.00 $0 $0 $0.00000

L.P. Steam (/1000 pounds) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal Other $0 $0 $0.00000

Waste Disposal

Flyash (ton) 0.00 0.00 0.00 $0 $0 $0.00000

Bottom Ash (ton) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal Waste Disposal $0 $0 $0.00000

By-products

Sulfur (tons) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $0 $5,441,560 $0.00132

Fuel (MMBtu) 0 90,562 6.55 $0 $183,973,460 $0.04451
Cost and Performance Baseline for Fossil Energy Plants

476

5.2.7

The plant configuration for Case 14 is the same as Case 13 with the exception that the 

Econamine CDR technology was added for CO2 capture. The nominal net output decreases to 

474 MW because, like the IGCC cases, the CT fixes the output and the CDR facility significantly 

increases the auxiliary power load and reduces the steam turbine output.

Case 14 – NGCC with CO2 Capture

The process description for Case 14 is essentially the same as Case 13 with one notable 

exception, the addition of CO2 capture. A BFD and stream tables for Case 14 are shown in 

Exhibit 5-16 and Exhibit 5-17, respectively. Since the CDR facility process description was 

provided in Section 5.1.5, it is not repeated here.

5.2.8

The Case 14 modeling assumptions were presented previously in Section 

Case 14 Performance Results

5.2.2.

The plant produces a net output of 474 MW at a net plant efficiency of 42.8 percent (HHV 

basis). Overall plant performance is summarized in Exhibit 5-18, which includes auxiliary 

power requirements. The CDR facility, including CO2 compression, accounts for over 66

percent of the auxiliary plant load. The CWS (CWPs and cooling tower fan) accounts for nearly 

18 percent of the auxiliary load, largely due to the high cooling water demand of the CDR 

facility.
Cost and Performance Baseline for Fossil Energy Plants

477

Exhibit 5-16 Case 14 Block Flow Diagram, NGCC with CO2 Capture
Cost and Performance Baseline for Fossil Energy Plants

478

Exhibit 5-17 Case 14 Stream Table, NGCC with CO2 Capture

1 2 3 4 5 6 7 8 9 10 11

V-L Mole Fraction

Ar 0.0092 0.0000 0.0089 0.0089 0.0098 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CH4 0.0000 0.9310 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

C2H6 0.0000 0.0320 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

C3H8 0.0000 0.0070 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

C4H10 0.0000 0.0040 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

CO2 0.0003 0.0100 0.0404 0.0404 0.0045 0.9893 1.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0099 0.0000 0.0867 0.0867 0.0339 0.0107 0.0000 1.0000 1.0000 1.0000 1.0000

N2 0.7732 0.0160 0.7432 0.7432 0.8187 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.2074 0.0000 0.1209 0.1209 0.1332 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

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 109,323 4,380 113,831 113,831 103,333 4,185 4,140 17,887 17,887 21,589 13,482

V-L Flowrate (kg/hr) 3,154,735 75,901 3,230,636 3,230,636 2,933,892 183,013 182,203 322,243 322,243 388,927 242,889

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 15 38 629 143 30 21 51 152 151 566 38

Pressure (MPa, abs) 0.10 3.10 0.11 0.10 0.10 0.16 15.27 0.51 0.49 16.65 0.01

Enthalpy (kJ/kg)A 30.23 46.30 835.81 288.61 83.96 26.65 -164.90 2,746.79 635.72 3,472.36 160.61

Density (kg/m3) 1.2 22.2 0.4 0.8 1.1 2.9 653.5 2.7 915.8 47.7 992.9

V-L Molecular Weight 28.857 17.328 28.381 28.381 28.393 43.731 44.010 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 241,016 9,657 250,954 250,954 227,809 9,226 9,127 39,435 39,435 47,595 29,724

V-L Flowrate (lb/hr) 6,955,000 167,333 7,122,333 7,122,333 6,468,125 403,474 401,689 710,425 710,425 857,437 535,480

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 59 100 1,163 290 85 69 124 306 304 1,050 101

Pressure (psia) 14.7 450.0 15.2 14.7 14.7 23.5 2,214.7 73.5 71.0 2,414.7 1.0

Enthalpy (Btu/lb)A 13.0 19.9 359.3 124.1 36.1 11.5 -70.9 1,180.9 273.3 1,492.8 69.1

Density (lb/ft3) 0.076 1.384 0.025 0.052 0.071 0.183 40.800 0.169 57.172 2.977 61.982

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Fossil Energy Plants

479

Exhibit 5-18 Case 14 Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Gas Turbine Power 362,200

Steam Turbine Power 148,800

TOTAL POWER, kWe 511,000

AUXILIARY LOAD SUMMARY, kWe

Condensate Pumps 80

Boiler Feedwater Pumps 2,710

Amine System Auxiliaries 9,600

CO2 Compression 15,200

Circulating Water Pump 4,360

Ground Water Pumps 360

Cooling Tower Fans 2,250

SCR 10

Gas Turbine Auxiliaries 700

Steam Turbine Auxiliaries 100

Miscellaneous Balance of Plant1 500

Transformer Losses 1,560

TOTAL AUXILIARIES, kWe 37,430

NET POWER, kWe 473,570

Net Plant Efficiency (HHV) 42.8%

Net Plant Efficiency (LHV) 47.5%

Net Plant Heat Rate (HHV), kJ/kWh (Btu/kWh) 8,406 (7,968)

Net Plant Heat Rate (LHV), kJ/kWh (Btu/kWh) 7,579 (7,184)

CONDENSER COOLING DUTY, 106 kJ/hr (106 Btu/hr) 528 (500)

CONSUMABLES

Natural Gas Feed Flow, kg/hr (lb/hr) 75,901 (167,333)

Thermal Input (HHV), kWth 1,105,812

Thermal Input (LHV) , kWth 997,032

Raw Water Withdrawal, m3/min (gpm) 15.1 (3,980)

Raw Water Consumption, m3/min (gpm) 11.3 (2,985)

1. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Fossil Energy Plants

480

The environmental targets for emissions of NOx, SO2, and PM were presented in Section 2.4. A 

summary of the plant air emissions for Case 14 is presented in 

Environmental Performance

Exhibit 5-19.

Exhibit 5-19 Case 14 Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

85% CF

kg/MWh

(lb/MWh)

SO2 Negligible Negligible Negligible

NOx 0.004 (0.008) 105 (115) 0.027 (0.061)

Particulates Negligible Negligible Negligible

Hg Negligible Negligible Negligible

CO2 5.1 (11.8) 150,743 (166,165) 40 (87)

CO2

1 43 (94) 1 CO2 emissions based on net power instead of gross power

The operation of the modern, state-of-the-art GT fueled by natural gas, coupled to a HRSG, 

results in very low levels of NOx emissions and negligible levels of SO2, particulate, and Hg 

emissions. As noted in Section 2.4, if the fuel contains the maximum amount of sulfur 

compounds allowed in pipeline natural gas, the NGCC SO2 emissions would be 21 tonnes/yr (23 

tons/yr) at 85 percent CF, or 0.00195 lb/MMBtu.

The low level of NOx production (2.5 ppmvd at 15 percent O2) is achieved by utilizing a dry 

LNB coupled with an SCR system.

Ninety percent of the CO2 in the FG is removed in CDR facility.

The carbon balance for the plant is shown in Exhibit 5-20. The carbon input to the plant consists 

of carbon in the natural gas in addition to carbon in the CT air. Carbon leaves the plant as CO2

in the stack gas and the captured CO2 product. The CO2 capture efficiency is defined by the 

following fraction: 

(CO2 Product Carbon)/(Natural Gas Carbon)*100 or

(109,628)/(120,863) * 100 or

90.7 percent

Exhibit 5-20 Case 14 Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Natural Gas 54,822 (120,863) Stack Gas 5,525 (12,181)

Air (CO2) 429 (946) CO2 Product 49,726 (109,628)

Total 55,251 (121,808) Total 55,251 (121,808)
Cost and Performance Baseline for Fossil Energy Plants

481

A sulfur balance is not included for Case 14 because the sulfur concentration of natural gas is 

negligible. Consequently, sulfur emissions are also negligible, as shown in Exhibit 5-19, despite 

the use of no sulfur control technology.

Exhibit 5-21 shows the overall water balance for the plant. The exhibit is presented in an 

identical manner as was for Case 13.

Exhibit 5-21 Case 14 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)

Econamine 0.04 (12) 0.0 (0) 0.04 (12) 0.0 (0) 0.04 (12)

Condenser Makeup

BFW Makeup

0.1 (23)

0.1 (23)

0.0 (0) 0.1 (23)

0.1 (23)

0.0 (0) 0.1 (23)

Cooling Tower

BFW Blowdown

Flue Gas 

Condensate

17.0 (4,477) 2.0 (520)

0.1 (23)

1.9 (497)

15.0 (3,958)

-0.1 (-23)

-1.9 (-497)

3.8 (1,007) 11.2 (2,951)

CO2 Product 

Condensate

0.03 (8) -0.03 (-8)

Total 17.1 (4,512) 2.0 (528) 15.1 (3,992) 3.8 (1,007) 11.3 (2,985)

A heat and mass balance diagram is shown for the NGCC in 

Heat and Mass Balance Diagrams

Exhibit 5-22. An overall plant 

energy balance is provided in tabular form in Exhibit 5-23.

The power out is the combined CT and steam turbine power prior to generator losses. The power 

at the generator terminals (shown in Exhibit 5-18) is calculated by multiplying the power out by 

a combined generator efficiency of 98.3 percent. The Econamine process heat out stream 

represents heat rejected to cooling water and ultimately to ambient via the cooling tower. The 

same is true of the condenser heat out stream. The CO2 compressor intercooler load is included 

in the Econamine process heat out stream.
Cost and Performance Baseline for Fossil Energy Plants

482

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

483

Exhibit 5-22 Case 14 Heat and Mass Balance, NGCC with CO2 Capture

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Nitrogen

Natural Gas

Carbon Dioxide

Water

Steam

PAGES

1 OF 1

NATURAL GAS COMBINED CYCLE PLANT

CASE 14

2 X ADVANCED F-CLASS GT

2400/1050/1050

DWG. NO.

BB-HMB-CS-14-PG-1

Flue Gas

401,689 W

123.8 T

2,214.7 P

CO2

PRODUCT

AMBIENT

AIR

1 6,955,000 W

59.0 T

14.7 P

12.9 H

CO2 COMPRESSION 

(INTERSTAGE COOLING) 

& DRYING

403,474 W

69.0 T

23.5 P

11.5 H

KNOCKOUT 

WATER

248,601 W

85.1 T

14.7 P

8.6 H

Gross Plant Power: 511 MWe

Auxiliary Load: 37 MWe

Net Plant Power: 474 MWe

Net Plant Efficiency, HHV: 42.8%

ADVANCED Net Plant Heat Rate: 7,968 BTU/KWe

F CLASS

GAS TURBINES

COMBUSTOR

NATURAL

GAS 167,333 W

100.0 T

450.0 P

19.9 H

2

6,468,125 W

85.1 T

14.7 P

36.0 H

7,122,333 W

289.7 T

14.7 P

124.0 H

7,122,333 W

1,163.5 T

15.2 P

359.3 H

GENERATOR

CONDENSATE

PUMPS

8,801 

W

1,302 

W

101.3 T

130.0 P

69.5 H

535,480 W

101.1 T

1.0 P

69.1 H

5

1,400 W

581.0 T

75.0 P

1,321.3 H

1,017,200 W

641.4 T

75.0 P

1,351.1 H

512,174 W

622.2 T

75.0 P

1,341.7 H

512,174 W

101.1 T

1.0 P

1,029.8 H

HOT WELL

CONDENSER

STACK

4

REBOILER CONDENSATE

CONDENSATE

PUMPS

STEAM TURBINE

MAKEUP

11,337 W

59.0 T

14.7 P

27.1 H

AIR INLET

FILTER

3

HP PUMP

535,480 W

253.0 T

100.0 P

221.9 H

BLOWDOWN

94,141 W

300.1 T

95.0 P

269.4 H

173,467 W

300.7 T

400.0 P

270.7 H

866,098 W

305.3 T

2,540.0 P

279.3 H 11,337 

W

STRIPPER

ABSORBER FLUE GAS ACID GAS

ECONAMINE FG+

BLOWER

598,226 W

641.4 T

75.0 P

1,351.1 H

WATER

1,785 W

100.0 T

14.7 P

GLAND SEAL

CONDENSER

1,400 W

212.0 T

14.7 P

179.9 H

LP TURBINE

STEAM TO REBOILER

710,425 W

306.2 T

73.5 P

1,180.9 H

9,569 W

535,480 W

106.8 T

120.0 P

75.0 H

Three Pressure 

Heat Recovery 

Steam Generator 

(HRSG)

829,777 W

1,055.0 T

360.0 P

1,553.4 H

A

A

171,732 W

1,055.0 T

360.0 P

1,553.4 H

HOT REHEAT

COLD

REHEAT

829,777 W

587.9 T

390.0 P

1,300.6 H

STEAM SEAL

REGULATOR

93,200 W

537.0 T

80.0 P

1,299.1 H

16,993 W

970.1 T

1,850.0 P

1,459.8 H

HP

TURBINE

IP

TURBINE

852,917 

W

2,654 W

1,050.0 T

2,414.7 P

1,492.8 H

1,018,502 

W

MAIN STEAM

857,437 W

1,050.0 T

2,414.7 P

1,492.8 H

6

7

8

9

10

10,969 W

866 

W

IP

STEAM

598,226 W

303.9 T

73.5 P

273.3 H

IP PUMP

LP PUMP

710,425 W

303.9 T

71.0 P

273.3 H

DOE/NETL

SC PC PLANT

CASE 14

11
Cost and Performance Baseline for Fossil Energy Plants

484

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

485

Exhibit 5-23 Case 14 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Natural Gas 3,981 (3,773) 2.7 (2.5) 3,984 (3,776)

GT Air 95.4 (90.4) 95 (90)

Raw Water Withdrawal 56.7 (53.7) 57 (54)

Auxiliary Power 0.0 (0.0) 135 (128) 135 (128)

Totals 3,981 (3,773) 154.7 (146.6) 135 (128) 4,270 (4,048)

Heat Out GJ/hr (MMBtu/hr)

CO2 -30.0 (-28.5) -30 (-28)

Cooling Tower Blowdown 28.3 (26.8) 28 (27)

Econamine Losses 1,010 (957) 1,010 (957)

CO2 Compression 

Intercooling 84.9 (80.5) 85 (81)

Stack Gas 246 (233) 246 (233)

Condenser 532 (504) 532 (504)

Process Losses* 560 (530) 560 (530)

Power 1,840 (1,744) 1,840 (1,744)

Totals 0 (0) 2,431 (2,304) 1,840 (1,744) 4,270 (4,048)

* Process Losses are calculated by difference and reflect various boiler, turbine, and other 

heat and work losses. Aspen flowsheet balance is within 0.5 percent.
Cost and Performance Baseline for Fossil Energy Plants

486

5.2.9

Major equipment items for the NGCC plant 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 

Case 14 Major Equipment List

5.2.10. In general, the design conditions include a 10 percent contingency 

for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 COAL AND SORBENT HANDLING

N/A

ACCOUNT 2 FUEL AND SORBENT PREPARATION AND FEED

Equipment 

No. Description Type Operating Qty. Spares

1 Gas Pipeline

Underground, 

coated carbon 

steel, wrapped 

cathodic 

protection

16 km 

(10 mile) 0

2 Gas Metering Station -- 1 0

Design Condition

63 m3/min @ 3.1 MPa

(2,216 acfm @ 450 psia)

41 cm (16 in) standard wall pipe

63 m3/min (2,216 acfm)
Cost and Performance Baseline for Fossil Energy Plants

487

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT

Equipment 

No. Description Type Operating 

Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 2 0

2 Condensate Pumps Vertical canned 2 1

4 Auxiliary Boiler Shop fabricated, water 

tube 1 0

5

Service Air 

Compressors Flooded Screw 2 1

6 Instrument Air Dryers Duplex, regenerative 2 1

7 Closed Cycle Cooling 

Heat Exchangers Plate and frame 2 0

8 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 2 1

9 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine 1 1

10 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal 1 1

11 Raw Water Pumps Stainless steel, single 

suction 2 1

12 Filtered Water Pumps Stainless steel, single 

suction 2 1

13 Filtered Water Tank Vertical, cylindrical 1 0

14 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly 

and electro-deionization 

unit

1 0

15 Liquid Waste Treatment 

System 1 0

1

143,847 liter (38,000 gal)

341 lpm (90 gpm)

10 years, 24-hour storm

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

8,328 lpm @ 18 m H2O

(2,200 gpm @ 60 ft H2O)

151 lpm @ 49 m H2O

(40 gpm @ 160 ft H2O)

13 m3/min (450 scfm)

2

HP water: 3,634 lpm @ 2,103 m H2O 

(960 gpm @ 6,900 ft H2O)

IP water: 719 lpm @ 283 m H2O 

(190 gpm @ 930 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C

(40,000 lb/h, 400 psig, 650°F)

13 m3/min @ 0.7 MPa

(450 scfm @ 100 psig)

LP water: 379 lpm @ 24.4 m H2O 

(100 gpm @ 80 ft H2O)

3 Boiler Feedwater Pump

Horizontal, split case, 

multi-stage, centrifugal, 

with interstage bleed for 

IP and LP feedwater

Design Condition

677,594 liters (179,000 gal)

2,233 lpm @ 110 m H2O

(590 gpm @ 360 ft H2O)

13 MMkJ/hr (13 MMBtu/hr)

5,300 lpm @ 21 m H2O

(1,400 gpm @ 70 ft H2O)
Cost and Performance Baseline for Fossil Energy Plants

488

ACCOUNT 4 GASIFIER, BOILER AND ACCESSORIES 

N/A

ACCOUNT 5B CARBON DIOXIDE RECOVERY

ACCOUNT 6 COMBUSTION TURBINE GENERATORS AND AUXILIARIES

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Econamine FG 

Plus

Amine-based CO2 

capture technology

1,776,723 kg/hr (3,917,000 

lb/hr) 6.3 wt % CO2 

concentration

2 0

2 CO2 

Compressor Integrally geared, multi 100,244 kg/hr @ 15.3 MPa (221,000 lb/hr @ 2,215 psia) 2 0

Equipment 

No. Description Type Operating Qty. Spares

1 Gas Turbine Advanced F class w/ 

dry low-NOx burner 2 0

2 Gas Turbine 

Generator TEWAC 2 0

Design Condition

180 MW 

200 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase
Cost and Performance Baseline for Fossil Energy Plants

489

ACCOUNT 7 WASTE HEAT BOILER, DUCTING, AND STACK 

Equipment 

No. Description Type Operating Qty. Spares

1 Stack CS plate, type 409SS 

liner 2 0

3 SCR Reactor Space for spare layer 2 0

4 SCR Catalyst -- 1 layer 0

5

Dilution Air 

Blowers Centrifugal 2 1

6 Ammonia Feed 

Pump Centrifugal 2 1

7 Ammonia 

Storage Tank Horizontal tank 1 0

2 2 0 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator Reheat steam - 249,852 kg/h, 2.4 

MPa/566°C (550,830 lb/h, 345 

psig/1,050°F)

Design Condition

46 m (150 ft) high x

6.4 m (21 ft) diameter

Main steam - 213,910 kg/h, 16.5 

MPa/566°C (471,590 lb/h, 2,400 

psig/1,050°F)

1,614,791 kg/h (3,560,000 lb/h)

Space available for an additional 

catalyst layer

11 m3/min @ 107 cm WG

(390 scfm @ 42 in WG)

3.8 lpm @ 91 m H2O

(1 gpm @ 300 ft H2O)

68,138 liter (18,000 gal)
Cost and Performance Baseline for Fossil Energy Plants

490

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

N/A

Equipment 

No. Description Type Operating Qty. Spares

1 Steam Turbine

Tandem compound, 

HP, IP, and twoflow LP turbines

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitation 1 0

3 Steam Bypass One per HRSG 2 0

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1 0

Design Condition

157 MW 

16.5 MPa/566°C/566°C 

(2,400 psig/ 

1050°F/1050°F)

580 MMkJ/hr, (550 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 

11°C (20°F)

170 MVA @ 0.9 p.f., 

24 kV, 60 Hz, 3-phase

50% steam flow @ design 

steam conditions

Equipment 

No. Description Type Operating Qty. Spares

1 Circulating Water 

Pumps Vertical, wet pit 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell

1 0

Design Condition

435,326 lpm @ 30.5 m

(115,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

613 MMkJ/hr (582 MMBtu/hr) 

heat load
Cost and Performance Baseline for Fossil Energy Plants

491

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment 

No. Description Type Operating Qty. Spares

1 CTG Transformer Oil-filled 2 0

2 STG Transformer Oil-filled 1 0

3

High Voltage 

Auxiliary 

Transformer

Oil-filled 2 0

4 Medium Voltage 

Transformer Oil-filled 1 1

5 Low Voltage 

Transformer Dry ventilated 1 1

6

CTG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, self-cooled 2 0

7

STG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, self-cooled 1 0

8 Medium Voltage 

Switchgear Metal clad 1 1

9 Low Voltage 

Switchgear Metal enclosed 1 1

10 Emergency Diesel 

Generator

Sized for emergency 

shutdown 1 0

Design Condition

24 kV/345 kV, 200 MVA, 

3-ph, 60 Hz

345 kV/13.8 kV, 8 MVA, 3-ph, 

60 Hz

24 kV/345 kV, 150 MVA, 

3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz

4.16 kV/480 V, 3 MVA, 

3-ph, 60 Hz

750 kW, 480 V, 3-ph, 60 Hz

24 kV/4.16 kV, 23 MVA, 

3-ph, 60 Hz

Equipment 

No. Description Type Operating Qty. Spares

1 DCS - Main 

Control

Monitor/keyboard; 

Operator printer (laser 

color); Engineering 

printer (laser B&W)

1 0

3 DCS - Data 

Highway Fiber optic 1 0

1 0

Fully redundant, 25% spare

Design Condition

Operator stations/printers and 

engineering stations/printers

2 DCS - Processor Microprocessor with 

redundant input/output N/A
Cost and Performance Baseline for Fossil Energy Plants

492

5.2.10

The cost estimating methodology was described previously in Section 

Case 14 – Cost Estimating

2.7. Exhibit 5-24 shows 

the total plant capital cost summary organized by cost account and Exhibit 5-25 shows a more 

detailed breakdown of the capital costs. Exhibit 5-26 shows the initial and annual O&M costs.

The estimated TOC of the NGCC with CO2 capture is $1,497/kW. Process contingency 

represents 4.0 percent of the TOC and project contingency represents 10.8 percent. The COE, 

including CO2 TS&M costs of 3.2 mills/kWh, is 85.9 mills/kWh.
Cost and Performance Baseline for Fossil Energy Plants

493

Exhibit 5-24 Case 14 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14

Project: Bituminous Baseline Study

Case: Case 14 - 1x475 MWnet 2x1 7FB NGCC w/ CO2 Capture

Plant Size: 473.6 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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 2 COAL & SORBENT PREP & FEED $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 3 FEEDWATER & MISC. BOP SYSTEMS $23,934 $4,864 $7,962 $0 $0 $36,760 $3,106 $0 $6,447 $46,312 $98

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4-4.9 Other gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A GAS CLEANUP & PIPING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B CO2 REMOVAL & COMPRESSION $121,638 $0 $37,053 $0 $0 $158,691 $13,593 $27,994 $40,056 $240,334 $507

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $75,294 $0 $4,804 $0 $0 $80,098 $6,800 $0 $8,690 $95,589 $202

6.2-6.9 Combustion Turbine Other $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $4

SUBTOTAL 6 $75,294 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,490 $206

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $94

7.2-7.9 SCR System, Ductwork and Stack $1,243 $950 $1,118 $0 $0 $3,311 $282 $0 $583 $4,176 $9

SUBTOTAL 7 $34,201 $950 $5,397 $0 $0 $40,548 $3,453 $0 $4,624 $48,624 $103

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $19,229 $0 $3,465 $0 $0 $22,694 $1,951 $0 $2,465 $27,110 $57

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $6,570 $637 $4,691 $0 $0 $11,898 $958 $0 $1,824 $14,680 $31

SUBTOTAL 8 $25,799 $637 $8,156 $0 $0 $34,592 $2,909 $0 $4,289 $41,791 $88

 9 COOLING WATER SYSTEM $8,569 $6,296 $5,689 $0 $0 $20,554 $1,708 $0 $3,140 $25,403 $54

10 ASH/SPENT SORBENT HANDLING SYS $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT $20,769 $5,564 $12,124 $0 $0 $38,458 $2,957 $0 $4,473 $45,888 $97

12 INSTRUMENTATION & CONTROL $6,272 $644 $5,211 $0 $0 $12,127 $1,010 $606 $1,575 $15,318 $32

13 IMPROVEMENTS TO SITE $1,724 $936 $4,588 $0 $0 $7,248 $641 $0 $1,578 $9,467 $20

14 BUILDINGS & STRUCTURES $0 $3,982 $4,121 $0 $0 $8,103 $658 $0 $1,314 $10,075 $21

 

TOTAL COST $318,200 $24,594 $95,849 $0 $0 $438,642 $36,957 $28,600 $76,502 $580,701 $1,226

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline for Fossil Energy Plants

494

Exhibit 5-25 Case 14 Total Plant Cost Details

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.2 Coal Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.3 Coal Conveyors & Yd Crush $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.4 Other Coal Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 1. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.3 Slurry Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 2. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,426 $2,499 $2,055 $0 $0 $6,980 $576 $0 $1,133 $8,690 $18

3.2 Water Makeup & Pretreating $2,123 $222 $1,109 $0 $0 $3,453 $294 $0 $750 $4,497 $9

3.3 Other Feedwater Subsystems $1,106 $374 $314 $0 $0 $1,794 $144 $0 $291 $2,229 $5

3.4 Service Water Systems $251 $517 $1,676 $0 $0 $2,444 $213 $0 $531 $3,188 $7

3.5 Other Boiler Plant Systems $1,683 $652 $1,511 $0 $0 $3,846 $326 $0 $626 $4,798 $10

3.6 Natural Gas, incl. pipeline $14,652 $476 $415 $0 $0 $15,543 $1,317 $0 $2,529 $19,389 $41

3.7 Waste Treatment Equipment $766 $0 $437 $0 $0 $1,203 $105 $0 $262 $1,569 $3

3.8 Misc. Equip.(cranes,AirComp.,Comm.) $927 $124 $445 $0 $0 $1,496 $129 $0 $325 $1,951 $4

SUBTOTAL 3. $23,934 $4,864 $7,962 $0 $0 $36,760 $3,106 $0 $6,447 $46,312 $98

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4 LT Heat Recovery & FG Saturation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.5 Misc. Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Cost and Performance Baseline for Fossil Energy Plants

495

Exhibit 5-25 Case 14 Total Plant Cost Details (Continued)

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.2 Elemental Sulfur Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.3 Mercury Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.4 COS Hydrolysis $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.5 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Fuel Gas Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.9 HGCU Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $107,387 $0 $32,583 $0 $0 $139,970 $11,989 $27,994 $35,991 $215,943 $456

5B.2 CO2 Compression & Drying $14,251 $0 $4,471 $0 $0 $18,721 $1,604 $0 $4,065 $24,390 $52

SUBTOTAL 5. $121,638 $0 $37,053 $0 $0 $158,691 $13,593 $27,994 $40,056 $240,334 $507

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $75,294 $0 $4,804 $0 $0 $80,098 $6,800 $0 $8,690 $95,589 $202

6.2 Combustion Turbine Accessories $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 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $4

SUBTOTAL 6. $75,294 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,490 $206

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $94

7.2 SCR System $1,243 $522 $733 $0 $0 $2,498 $215 $0 $407 $3,120 $7

7.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.9 HRSG,Duct & Stack Foundations $0 $428 $385 $0 $0 $813 $68 $0 $176 $1,057 $2

SUBTOTAL 7. $34,201 $950 $5,397 $0 $0 $40,548 $3,453 $0 $4,624 $48,624 $103

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $19,229 $0 $3,465 $0 $0 $22,694 $1,951 $0 $2,465 $27,110 $57

8.2 Turbine Plant Auxiliaries $141 $0 $317 $0 $0 $458 $40 $0 $50 $548 $1

8.3 Condenser & Auxiliaries $2,393 $0 $714 $0 $0 $3,107 $266 $0 $337 $3,711 $8

8.4 Steam Piping $4,035 $0 $2,653 $0 $0 $6,688 $513 $0 $1,080 $8,281 $17

8.9 TG Foundations $0 $637 $1,007 $0 $0 $1,644 $139 $0 $357 $2,140 $5

SUBTOTAL 8. $25,799 $637 $8,156 $0 $0 $34,592 $2,909 $0 $4,289 $41,791 $88

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $6,077 $0 $777 $0 $0 $6,854 $584 $0 $744 $8,182 $17

9.2 Circulating Water Pumps $1,780 $0 $106 $0 $0 $1,887 $142 $0 $203 $2,232 $5

9.3 Circ.Water System Auxiliaries $136 $0 $18 $0 $0 $154 $13 $0 $17 $184 $0

9.4 Circ.Water Piping $0 $3,968 $962 $0 $0 $4,930 $399 $0 $799 $6,128 $13

9.5 Make-up Water System $313 $0 $418 $0 $0 $730 $63 $0 $119 $912 $2

9.6 Component Cooling Water Sys $264 $315 $210 $0 $0 $788 $66 $0 $128 $983 $2

9.9 Circ.Water System Foundations $0 $2,013 $3,198 $0 $0 $5,211 $442 $0 $1,130 $6,783 $14

SUBTOTAL 9. $8,569 $6,296 $5,689 $0 $0 $20,554 $1,708 $0 $3,140 $25,403 $54
Cost and Performance Baseline for Fossil Energy Plants

496

Exhibit 5-25 Case 14 Total Plant Cost Details (Continued)

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.7 Ash Transport & Feed Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.9 Ash/Spent Sorbent Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 10. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $5,372 $0 $3,228 $0 $0 $8,600 $728 $0 $700 $10,028 $21

11.2 Station Service Equipment $1,980 $0 $167 $0 $0 $2,147 $177 $0 $174 $2,498 $5

11.3 Switchgear & Motor Control $2,440 $0 $415 $0 $0 $2,855 $237 $0 $309 $3,402 $7

11.4 Conduit & Cable Tray $0 $1,166 $3,595 $0 $0 $4,761 $412 $0 $776 $5,949 $13

11.5 Wire & Cable $0 $3,713 $2,280 $0 $0 $5,993 $386 $0 $957 $7,337 $15

11.6 Protective Equipment $0 $563 $1,916 $0 $0 $2,480 $217 $0 $270 $2,966 $6

11.7 Standby Equipment $98 $0 $90 $0 $0 $188 $16 $0 $20 $224 $0

11.8 Main Power Transformers $10,878 $0 $136 $0 $0 $11,014 $747 $0 $1,176 $12,937 $27

11.9 Electrical Foundations $0 $121 $298 $0 $0 $419 $36 $0 $91 $546 $1

SUBTOTAL 11. $20,769 $5,564 $12,124 $0 $0 $38,458 $2,957 $0 $4,473 $45,888 $97

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 $797 $0 $498 $0 $0 $1,295 $110 $65 $220 $1,690 $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 $238 $0 $143 $0 $0 $381 $32 $19 $65 $497 $1

12.7 Computer & Accessories $3,814 $0 $114 $0 $0 $3,928 $323 $196 $445 $4,892 $10

12.8 Instrument Wiring & Tubing $0 $644 $1,230 $0 $0 $1,874 $141 $94 $316 $2,426 $5

12.9 Other I & C Equipment $1,422 $0 $3,226 $0 $0 $4,648 $404 $232 $528 $5,813 $12

SUBTOTAL 12. $6,272 $644 $5,211 $0 $0 $12,127 $1,010 $606 $1,575 $15,318 $32
Cost and Performance Baseline for Fossil Energy Plants

497

Exhibit 5-25 Case 14 Total Plant Cost Details (Continued)

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

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $92 $1,839 $0 $0 $1,931 $172 $0 $421 $2,524 $5

13.2 Site Improvements $0 $844 $1,049 $0 $0 $1,893 $167 $0 $412 $2,472 $5

13.3 Site Facilities $1,724 $0 $1,700 $0 $0 $3,424 $302 $0 $745 $4,471 $9

SUBTOTAL 13. $1,724 $936 $4,588 $0 $0 $7,248 $641 $0 $1,578 $9,467 $20

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $236 $125 $0 $0 $361 $28 $0 $58 $447 $1

14.2 Steam Turbine Building $0 $1,639 $2,183 $0 $0 $3,822 $314 $0 $620 $4,756 $10

14.3 Administration Building $0 $462 $313 $0 $0 $775 $62 $0 $125 $962 $2

14.4 Circulation Water Pumphouse $0 $147 $73 $0 $0 $220 $17 $0 $36 $272 $1

14.5 Water Treatment Buildings $0 $458 $418 $0 $0 $876 $71 $0 $142 $1,089 $2

14.6 Machine Shop $0 $401 $256 $0 $0 $657 $52 $0 $106 $815 $2

14.7 Warehouse $0 $259 $156 $0 $0 $415 $33 $0 $67 $515 $1

14.8 Other Buildings & Structures $0 $77 $56 $0 $0 $134 $11 $0 $22 $166 $0

14.9 Waste Treating Building & Str. $0 $303 $541 $0 $0 $845 $70 $0 $137 $1,052 $2

SUBTOTAL 14. $0 $3,982 $4,121 $0 $0 $8,103 $658 $0 $1,314 $10,075 $21

TOTAL COST $318,200 $24,594 $95,849 $0 $0 $438,642 $36,957 $28,600 $76,502 $580,701 $1,226

Owner's Costs

Preproduction Costs

6 Months All Labor $4,163 $9

1 Month Maintenance Materials $612 $1

1 Month Non-fuel Consumables $273 $1

1 Month Waste Disposal $0 $0

25% of 1 Months Fuel Cost at 100% CF $4,509 $10

2% of TPC $11,614 $25

Total $21,170 $45

Inventory Capital

60 day supply of consumables at 100% CF $357 $1

0.5% of TPC (spare parts) $2,904 $6

Total $3,260 $7

Initial Cost for Catalyst and Chemicals $823 $2

Land $300 $1

Other Owner's Costs $87,105 $184

Financing Costs $15,679 $33

Total Overnight Costs (TOC) $709,039 $1,497

TASC Multiplier (IOU, high-risk, 33 year) 1.078

Total As-Spent Cost (TASC) $764,344 $1,614
Cost and Performance Baseline for Fossil Energy Plants

498

Exhibit 5-26 Case 14 Initial and Annual Operating and Maintenance Cost Summary

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 14 - 1x475 MWnet 2x1 7FB NGCC w/ CO2 Capture Heat Rate-net (Btu/kWh): 7,968

MWe-net: 474

 Capacity Factor (%): 85

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

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 1.0 1.0

 Operator 3.3 3.3

 Foreman 1.0 1.0

 Lab Tech's, etc. 1.0 1.0

 TOTAL-O.J.'s 6.3 6.3

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $2,497,781 $5.274

Maintenance Labor Cost $4,162,295 $8.789

Administrative & Support Labor $1,665,019 $3.516

Property Taxes and Insurance $11,614,024 $24.524

TOTAL FIXED OPERATING COSTS $19,939,120 $42.104

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $6,243,443 $0.00177

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water (/1000 gallons) 0.00 2,865.60 1.08 $0 $961,666 $0.00027

Chemicals

MU & WT Chem.(lbs) 0.00 17,072.41 0.17 $0 $916,693 $0.00026

MEA Solvent (ton) 344.71 0.48 2,249.89 $775,561 $337,908 $0.00010

Activated Carbon (lb) 0.00 578.27 1.05 $0 $188,408 $0.00005

Corrosion Inhibitor 0.00 0.00 0.00 $47,225 $2,249 $0.00000

SCR Catalyst (m3) w/equip. 0.07 5,775.94 $0 $129,612 $0.00004

Ammonia (19% NH3) (ton) 0.00 6.06 129.80 $0 $244,142 $0.00007

Subtotal Chemicals $822,786 $1,819,011 $0.00052

Other

Supplemental Fuel (MBtu) 0.00 0.00 0.00 $0 $0 $0.00000

Gases,N2 etc. (/100scf) 0.00 0.00 0.00 $0 $0 $0.00000

L.P. Steam (/1000 pounds) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal Other $0 $0 $0.00000

Waste Disposal

Flyash (ton) 0.00 0.00 0.00 $0 $0 $0.00000

Bottom Ash (ton) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal Waste Disposal $0 $0 $0.00000

By-products

Sulfur (tons) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $822,786 $9,024,121 $0.00256

Fuel (MMBtu) 0 90,562 6.55 $0 $183,972,091 $0.05217
Cost and Performance Baseline for Fossil Energy Plants

499

5.3 NGCC CASE SUMMARY

The performance results of the two NGCC plant configurations modeled in this study are 

summarized in Exhibit 5-27.

Exhibit 5-27 Estimated Performance and Cost Results for NGCC Cases

1 Capacity factor is 85% for all NGCC cases 2 COE and LCOE are defined in Section 2.7.

PERFORMANCE Case 13 Case 14

CO2 Capture 0% 90%

Gross Power Output (kWe) 564,700 511,000

Auxiliary Power Requirement (kWe) 9,620 37,430

Net Power Output (kWe) 555,080 473,570

Coal Flowrate (lb/hr) N/A N/A

Natural Gas Flowrate (lb/hr) 167,333 167,333

HHV Thermal Input (kWth) 1,105,812 1,105,812

Net Plant HHV Efficiency (%) 50.2% 42.8%

Net Plant HHV Heat Rate (Btu/kWh) 6,798 7,968

Raw Water Withdrawal (gpm/MWnet) 4.3 8.4

Process Water Discharge (gpm/MWnet) 1.0 2.1

Raw Water Consumption (gpm/MWnet) 3.3 6.3

CO2 Emissions (lb/MMBtu) 118 12

CO2 Emissions (lb/MWhgross) 790 87

CO2 Emissions (lb/MWhnet) 804 94

SO2 Emissions (lb/MMBtu) Negligible Negligible

SO2 Emissions (lb/MWhgross) Negligible Negligible

NOx Emissions (lb/MMBtu) 0.009 0.008

NOx Emissions (lb/MWhgross) 0.060 0.061

PM Emissions (lb/MMBtu) Negligible Negligible

PM Emissions (lb/MWhgross) Negligible Negligible

Hg Emissions (lb/TBtu) Negligible Negligible

Hg Emissions (lb/MWhgross) Negligible Negligible

COST

Total Plant Cost (2007$/kW) 584 1,226

Total Overnight Cost (2007$/kW) 718 1,497

 Bare Erected Cost 482 926

 Home Office Expenses 40 78

 Project Contingency 62 162

 Process Contingency 0 60

 Owner's Costs 133 271

Total Overnight Cost (2007$ x 1,000) 398,290 709,039

Total As Spent Capital (2007$/kW) 771 1,614

COE (mills/kWh, 2007$)1,2 58.9 85.9

 CO2 TS&M Costs 0.0 3.2

 Fuel Costs 44.5 52.2

 Variable Costs 1.3 2.6

 Fixed Costs 3.0 5.7

 Capital Costs 10.1 22.3

LCOE (mills/kWh, 2007$)1,2 74.7 108.9

NGCC

 Advanced F Class
Cost and Performance Baseline for Fossil Energy Plants

500

The components of TOC and overall TASC are shown for the two NGCC cases in Exhibit 5-28. 

The TOC of the non-capture case, $718/kW, is the lowest of all technologies studied by at least 

50 percent. Addition of CO2 capture more than doubles the TOC cost, but NGCC with capture is 

still the least capital intensive of all the capture technologies by at least 55 percent. The process 

contingency included for the Econamine process totals $59/kW, which represents approximately 

4 percent of the TOC.

The COE for NGCC cases is heavily dependent on the price of natural gas as shown in 

Exhibit 5-29. The fuel component of COE represents 76 percent of the total in the non-capture 

case and 61 percent of the total in the CO2 capture case. Because COE has a small capital 

component, it is less sensitive to CF than the more capital intensive PC and IGCC cases. The 

decrease in net kilowatt-hours (kWh) produced is nearly offset by a corresponding decrease in 

fuel cost. The CO2 TS&M component of COE is only 4 percent of the total in the CO2 capture 

case.

Exhibit 5-28 Plant Capital Cost for NGCC Cases

718

1,497

771

1,614

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

TOC TASC TOC TASC

NGCC NGCC w/ CO2 Capture

TOC or TASC, $/kW (2007$)

TASC

Owner's Cost

Process Contingency

Project Contingency

Home Office Expense

Bare Erected Cost
Cost and Performance Baseline for Fossil Energy Plants

501

Exhibit 5-29 COE of NGCC Cases

The sensitivity of NGCC to CF is shown in Exhibit 5-30. Unlike the PC and IGCC case, NGCC 

is relatively insensitive to CF but highly sensitive to fuel cost as shown in Exhibit 5-31. A 33 

percent increase in natural gas price (from $6 to $8/MMBtu) results in a COE increase of 25

percent in the non-capture case and 20 percent in the CO2 capture case. Because of the higher 

capital cost in the CO2 capture case, the impact of fuel price changes is slightly diminished.

As presented in Section 2.4 the first year cost of CO2 avoided cost was calculated. In the NGCC 

capture case the cost of CO2 avoided using NGCC without CO2 capture as the reference is 

$69.5/tonne ($63/ton). The high cost relative to PC and IGCC technologies is mainly due to the 

much smaller amount of CO2 generated by NGCC and therefore captured in the Econamine 

process. The cost of CO2 avoided is $35.3/tonne ($32/ton) when using SC PC without capture as 

the reference. This is due to the smaller difference in COE and larger difference in CO2

emissions between the SC PC non-capture and NGCC capture cases.

10.1

3.0 22.3

5.7

1.3

2.6

44.5

52.2

3.2

0

20

40

60

80

100

120

140

160

NGCC NGCC w/ CO2 Capture

COE, mills/kWh (2007$)

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs
Cost and Performance Baseline for Fossil Energy Plants

502

Exhibit 5-30 Sensitivity of COE to Capacity Factor in NGCC Cases

Exhibit 5-31 Sensitivity of COE to Fuel Price in NGCC Cases

0

20

40

60

80

100

120

140

160

0 10 20 30 40 50 60 70 80 90 100

COE, mills/kWh (2007$)

Capacity Factor, %

NGCC w/CO2 Capture

NGCC No Capture

Natural gas price = $6.55/MMBtu

0

20

40

60

80

100

120

140

0 2 4 6 8 10 12 14

COE, mills/kWh (2007$)

Natural Gas Price, $/MMBtu

NGCC No Capture

NGCC w/CO2 Capture

Capacity factor = 85%
Cost and Performance Baseline for Fossil Energy Plants

503

The following observations can be made regarding plant performance with reference to 

Exhibit 5-27:

• The efficiency of the NGCC case with no CO2 capture is 50.2 percent (HHV basis). 

Gas Turbine World provides estimated performance for an advanced F class turbine 

operated on natural gas in a combined cycle mode, and the reported efficiency is 57.5 

percent (LHV basis) [79

• The efficiency penalty to add CO2 capture in the NGCC case is 14.7 relative percent. 

The efficiency reduction is caused primarily by the auxiliary loads of the Econamine 

system and CO2 compression as well as the significantly increased cooling water 

requirement, which increases the auxiliary load of the CWPs and the cooling tower 

fan. CO2 capture results in a 28 MW increase in auxiliary load compared to the noncapture case.

]. Adjusting the result from this study to an LHV basis 

results in an efficiency of 55.7 percent.

• The energy penalty for NGCC is less than PC (14.7 relative percent for NGCC 

compared to 28.9 and 27.6 relative percent for subcritical and SC PC respectively)

and IGCC (21.4 relative percent) mainly because natural gas has a lower carbon 

intensity than coal and NGCC has a higher efficiency than PC or IGCC. In the PC 

cases, about 589,670 kg/hr (1.3 million lb/hr) of CO2 must be captured and 

compressed while in the NGCC case only about 181,437 kg/hr (400,000 lb/hr) is 

captured and compressed.

• A study assumption is that the natural gas contains no PM or Hg, resulting in 

negligible emissions of both.

• This study also assumes that the natural gas contains no sulfur compounds, resulting 

in negligible emissions of SO2. As noted previously in the report, if the natural gas 

contained the maximum allowable amount of sulfur per EPA’s pipeline natural gas 

specification, the resulting SO2 emissions would be 21 tonnes/yr (23 tons/yr), or 

0.00195 lb/MMBtu.

• NOx emissions are nearly identical for the two NGCC cases on a heat input and mass 

basis. This is a result of the fixed output from the GT (25 ppmv at 15 percent O2) and 

the fixed efficiency of the SCR (90 percent).

The normalized water withdrawal, process discharge and raw water consumption are shown in 

Exhibit 5-32 for the NGCC cases. The following observations can be made:

• Normalized water withdrawal increases 95 percent and normalized raw water 

consumption 91 percent in the CO2 capture case. The high cooling water demand of 

the Econamine process results in a large increase in cooling tower makeup 

requirements.

• Cooling tower makeup comprises approximately 99 percent of the raw water 

consumption in both NGCC cases. The only internal recycle stream in the noncapture case is the BFW blowdown, which is recycled to the cooling tower. In the 

CO2 capture case condensate is recovered from the FG as it is cooled to the absorber 

temperature of 32°C (89°F) and is also recycled to the cooling tower.
Cost and Performance Baseline for Fossil Energy Plants

504

Exhibit 5-32 Raw Water Withdrawal and Consumption in NGCC Cases

4.3

8.4

3.3

6.3

0

1

2

3

4

5

6

7

8

9

NGCC NGCC w/ CO2 Capture

Water, gpm/MWnet

Raw Water Withdrawal

Process Discharge

Raw Water Consumption
Cost and Performance Baseline for Fossil Energy Plants

505

6.

This supplementary chapter presents sensitivities of the economic performance to higher natural 

gas prices and dispatch-based CFs. Sections 

EFFECT OF HIGHER NATURAL GAS PRICES AND DISPATCH-BASED 

CAPACITY FACTORS

6.1 through 6.3 discuss the sensitivity to higher 

natural gas prices (at a constant CF)

10 while Sections 6.4 through 6.8 examine dispatch-based 

CFs.

6.1 INCREASING NATURAL GAS PRICES

An investigation was conducted because of the potential for natural gas prices to increase over 

the long-term. Regulations limiting the emissions of CO2 may cause natural gas to become an 

increasingly attractive fuel source for power generation. Natural gas is preferred in many cases 

because of its lower carbon intensity relative to coal: burning natural gas emits less CO2 than an 

equivalent amount of coal. When compared to the average IGCC and PC non-capture cases in 

this study, NGCC emits 52 percent and 56 percent less CO2 on a lb/net-MWh basis, respectively. 

As demand increases the natural gas supply has the potential to become constrained. Gas 

resources within the U.S. are mature and much of the low-cost gas has already been produced. 

Drilling and exploration will need to be done to find alternative sources of natural gas. 

Producers will have to drill higher cost wells with lower deliverability requiring high-cost 

technology to meet increased demand. Additional pipelines will have to be built as this gas will 

come from increasingly remote areas. The recently accessible Marcellus shale formation still 

must overcome environmental obstacles to be viable. The cost to produce the same volume of 

gas will increase causing the consumer to pay more for natural gas.

As domestic production costs increase, an alternative source for natural gas is imported liquefied

natural gas (LNG). LNG is increasingly becoming a worldwide commodity as the supply and 

availability increase. As of 2009, there are only seven import terminals in the U.S. If imported 

LNG is to become a viable fuel source for the U.S., more terminal facilities will have to be built 

to keep up with the increasing demand. There is significant lag time between planning, permit 

acquisition, and construction of these large-scale facilities. This lag time, along with competition 

for LNG resources between other nations as the U.S. enters the market, will further limit the 

supply to the U.S.

6.2 PRICE METHODOLOGY

The baseline natural gas price used in this report is $6.55/MMBtu (June 2007 dollars). Two 

other natural gas prices are evaluated in this chapter to judge the sensitivity of the results to 

higher gas prices. The first is the EIA’s AEO 2008 “High Price” projection for 2010. The “High 

Price” is $7.54/MMBtu in 2007 dollars11

 

10 It is acknowledged that changes in fuel pricing will likely have an impact on capacity factor. However for

the purposes of this example, capacity factor is assumed to remain constant at a relatively high value of 85 percent in 

the face of changing fuel prices.

.

11 The AEO 2008 “High Price” is reported as $7.31/MMBtu in 2006 dollars. This value was escalated to 

$7.54/MMBtu in 2007 dollars by using the GDP chain-type price index from AEO 2008.
Cost and Performance Baseline for Fossil Energy Plants

506

The second natural gas cost is derived from applying the historical correlation between natural 

gas and West Texas Intermediate (WTI) crude oil [80

NG Price ($/MMBtu) = -0.4744 + 0.1543 x (Oil Price WTI ($/bbl))

]. 

The AEO “High Price” projection cost for imported crude oil in 2010 is $71.33/bbl in 2007 

dollars12

6.3 COST OF ELECTRICITY

. Using the “High Price” in the correlation equation results in a natural gas price of 

$10.53/MMBtu. Using the Oil Correlation again, a $51.94/bbl price would be needed to have a 

$7.54/MMBtu price for natural gas.

The COE results are shown in Exhibit 6-1 with the capital costs, fixed operating cost, variable 

operating cost, and fuel cost shown separately. In capture cases the CO2 TS&M costs are also 

shown as a separate bar segment. Fuel cost is the dominant component of COE in all NGCC 

cases and therefore fuel price increases have a significant impact. The following conclusions can 

be drawn:

• In non-capture cases, the NGCC “High Price” case still has a lower COE (65.6

mills/kWh) than any of the IGCC cases (average 77.2 mills/kWh), but the NGCC Oil

Correlation Price cost (86.0 mills/kWh) represents the highest COE of all the non-capture 

cases.

• In capture cases, the NGCC baseline cost (85.9 mills/kWh) is the lowest capture case cost 

in the initial study, and the NGCC “High Price” cost (93.8 mills/kWh) is still the lowest 

COE.

• When the natural gas price increases to $10.53/MMBtu in the Oil Correlation case, 

NGCC becomes the most expensive technology with CO2 capture. This differs from the 

baseline results where NGCC with capture was the lowest cost.

• For the three NGCC cases without CO2 capture, the fuel component of COE ranges from 

76 percent to 83 percent. For capture cases, the fuel component of COE ranges from 61 

percent to 71 percent.

• For the NGCC non-capture cases, an increase in the natural gas price of 15.1 percent for 

“High Price” and 60.8 percent for the Oil Correlation price cause an increase of 11

percent and 46 percent in the COE, respectively. The COE in the NGCC CO2 capture 

cases increases by 9 percent and 37 percent, respectively.

First year CO2 avoided costs are shown in Exhibit 6-7 and are calculated using both analogous 

technologies and non-capture SC PC as references. The IGCC and PC cases were averaged to 

emphasize the NGCC cases at different natural gas prices. The following conclusions can be 

drawn:

• For NGCC cases, the first year CO2 avoided costs increase with the price of natural gas. 

This is consistent with the COE trend as NGCC cases are predominately affected by fuel 

price.

 

12 The AEO “High Price” is reported as $69.19/bbl in 2006 dollars. This value was escalated to $71.33 in 

2007 dollars by using the GDP chain-type price index from AEO 2008.
Cost and Performance Baseline for Fossil Energy Plants

507

• At the baseline natural gas price of $6.55/MMBtu, the NGCC cases have a higher first 

year CO2 avoided cost per ton than PC or IGCC when compared to the analogous noncapture technology. However, NGCC has the lowest first year avoided cost relative to a 

non-capture SC PC plant except at the highest natural gas price case.
Cost and Performance Baseline for Fossil Energy Plants

508

Exhibit 6-1 COE By Cost Component

44.4

63.3

31.2

60.2

31.7

59.6

10.1

22.3

10.1

22.3

10.1

22.3

11.5

15.7

7.8

13.1

8.0

13.0

3.0

5.7

3.0

5.7

3.0

5.7

7.4

9.7

5.1

9.2

5.0

8.7

1.3

2.6

1.3

2.6

1.3

2.6

13.9

17.7

15.2

21.3

14.2

19.6

44.5

52.2

51.3

60.1

71.6

83.9

5.5

5.9

5.7

3.2

3.2

3.2

77.2

111.8

59.4

109.7

58.9

106.6

58.9

85.9

65.6

93.8

86.0

117.7

0

20

40

60

80

100

120

140

IGCC Average IGCC Average 

w/ CO2 

Capture

Subcritical PC Subcritical PC 

w/ CO2 

Capture

Supercritical 

PC

Supercritical 

PC w/ CO2 

Capture

NGCC NGCC w/ CO2 

Capture

NGCC High 

Price

NGCC High 

Price w/ CO2 

Capture

NGCC Oil 

Correlation

NGCC Oil 

Correlation w/ 

CO2 Capture

COE, mills/kWh (2007$)

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs
Cost and Performance Baseline for Fossil Energy Plants

509

Exhibit 6-2 First Year CO2 Avoided Costs

52

69

84

88

98

75

72

36

46

77

0

20

40

60

80

100

120

IGCC Average PC Average NGCC Baseline NGCC "High Price" NGCC Petroleum 

Correlation

First Year CO2 Avoided Cost, $/tonne (2007$)

FY Avoided Cost (Analogous Technology w/o Capture Reference)

FY Avoided Cost (SC PC w/o Capture Reference)
Cost and Performance Baseline for Fossil Energy Plants

510

Exhibit 6-3 shows the COE sensitivity to fuel costs for the non-capture cases. The solid line is 

the COE of NGCC as a function of natural gas cost. The points on the line represent the natural 

gas costs that would be required to make the COE of NGCC equal to PC or IGCC at a given coal 

cost. The coal prices shown ($1.23, $1.64 and $2.05/MMBtu) represent the baseline cost and a 

range of ±25 percent around the baseline. The vertical lines represent the natural gas prices 

highlighted in this section.

At the AEO “High Price” of $7.54/MMBtu NGCC has a lower COE than all IGCC cases at any 

of the coal prices. At this natural gas price for non-capture cases PC is the most cost effective 

method for producing electricity. For IGCC cases to compete with NGCC cases at the highest 

studied coal price, the cost of natural gas would have to be $9.75/MMBtu.

Fuel cost sensitivity is presented for the CO2 capture cases in Exhibit 6-4. Even at the lowest 

coal cost shown ($1.23/MMBtu), the COE of NGCC at the “High Price” is lower than both the 

IGCC cases and PC cases. At a natural gas price 52 percent higher than the baseline price of 

$6.55/MMBtu, the NGCC case is statistically equal to the PC cases at a coal cost of 25 percent 

more than the baseline price ($2.05/MMBtu).

Exhibit 6-3 COE Sensitivity to Fuel Costs in Non-Capture Cases

40

50

60

70

80

90

100

3 4 5 6 7 8 9 10 11 12 13

COE, mills/kWh (2007$)

Natural Gas Price, $/MMBtu

NGCC

PC w/ coal at $1.23/MMBtu

PC w/ coal at $1.64/MMBtu

PC w/ coal at $2.05/MMBtu

IGCC w/ coal at $1.23/MMBtu

IGCC w/ coal at $1.64/MMBtu

IGCC w/ coal at $2.05/MMBtu

Baseline Study Price-

$6.55/MMBtu

AEO "High Price"-

$7.54/MMBtu

Petroleum Correlation 

Price- $10.53/MMBtu
Cost and Performance Baseline for Fossil Energy Plants

511

Exhibit 6-4 COE Sensitivity to Fuel Costs in CO2 Capture Cases

The sensitivity of COE to CF is shown for all non capture technologies in Exhibit 6-5 and for all 

capture technologies in Exhibit 6-6. The baseline PC and IGCC cases for non-capture and 

capture were averaged to highlight the comparison with the NGCC cases. The average PC plant 

with capture and the average IGCC plant with capture are nearly identical so that the two curves 

appear as a single curve on the graph. The CF is plotted from 30 to 90 percent. The baseline CF

is 80 percent for IGCC cases with no spare gasifier and is 85 percent for PC and NGCC cases. 

The curves plotted in Exhibit 6-5 and Exhibit 6-6 for IGCC cases assume that the CF could be 

extended to 90 percent with no spare gasifier. Similarly, the PC and NGCC curves assume that 

the CF could reach 90 percent with no additional capital equipment.

40

50

60

70

80

90

100

110

120

130

140

3 4 5 6 7 8 9 10 11 12 13

COE, mills/kWh (2007$)

Natural Gas Price, $/MMBtu

NGCC

PC w/ coal at $1.23/MMBtu

PC w/ coal at $1.64/MMBtu

PC w/ coal at $2.05/MMBtu

IGCC w/ coal at $1.23/MMBtu

IGCC w/ coal at $1.64/MMBtu

IGCC w/ coal at $2.05/MMBtu

Baseline Study Price-

$6.55/MMBtu

AEO "High Price"-

$7.54/MMBtu

Petroleum 

Correlation Price-

$10.53/MMBtu
Cost and Performance Baseline for Fossil Energy Plants

512

Exhibit 6-5 COE Sensitivity to Capacity Factor in Non-Capture Cases

40

60

80

100

120

140

160

180

200

20 30 40 50 60 70 80 90 100

COE, mills/kWh (2007$)

Capacity Factor, %

Avg. IGCC no capture

Avg. PC no capture

NGCC no capture Petroleum Correlation

NGCC no capture "High Price"

NGCC no capture

Coal = $1.64/MMBtu

Natural Gas = $6.55/MMBtu
Cost and Performance Baseline for Fossil Energy Plants

513

Exhibit 6-6 COE Sensitivity to Capacity Factor in Capture Cases

The NGCC curves are flatter than the coal curves because for NGCC the fuel cost, rather than 

the capital cost, is the dominant component of COE, even at baseline natural gas prices. 

Conclusions that can be drawn from Exhibit 6-5 and Exhibit 6-6 include:

• At high CFs, coal based technologies with and without CO2 capture can be competitive 

with NGCC depending on the price of natural gas. As the CF falls among the noncapture technologies, IGCC becomes less competitive first, followed by PC. IGCC and 

PC with CO2 capture become less competitive together as the CF decreases.

• At low CFs, the coal based IGCC and PC technologies are affected to a greater extent 

than NGCC. At a CF less than 45 percent, NGCC is the most economic option at each 

natural gas price examined.

6.4 DISPATCH-BASED CAPACITY FACTORS

The baseline assumption in this report was that all technologies would always be dispatched 

when available, making CF and availability factor equivalent. In reality the marginal production 

cost would determine dispatch order and hence CF. The balance of this chapter examines the 

determination and impact of a dispatch-based CF.

Estimates are provided for the plant dispatch expected in cases without CO2 capture, if these 

units were to compete for electric sales with the other 1,706 generators that would provide the 

generation to supply the demand of the PJM Interconnection (PJM) control region in 2010. The 

40

60

80

100

120

140

160

180

200

220

240

260

280

300

20 30 40 50 60 70 80 90 100

COE, mills/kWh (2007$)

Capacity Factor, %

Avg. IGCC w/CO2 capture

Avg. PC w/CO2 capture

NGCC w/ CO2 capture Petroleum 

Correlation

NGCC w/ CO2 capture "High Price"

NGCC w/CO2 capture

Coal = $1.64/MMBtu

Natural Gas = $6.55/MMBtu
Cost and Performance Baseline for Fossil Energy Plants

514

basis for projecting the expected CF of each of the units without CO2 capture is provided, along 

with the financial implications of that dispatch.

The estimated year 2010 CFs earned in the PJM operating region for the units examined are 

listed in Exhibit 6-7. The bases for these estimates are discussed later in this chapter.

Exhibit 6-7 Dispatch Based Capacity Factors for Cases without CO2 Capture

Case Year 2010

Capacity Factor

Case 1 - GE IGCC 51.5%

Case 3 - CoP IGCC 54.1%

Case 5 - Shell IGCC 62.0%

Case 9 – Subcritical PC 73.4%

Case 11 - SC PC 85.0%

Case 13 – NGCC 16.5%

The annual CF of an electric generating unit is the ratio of its actual generation (that is, the unit’s 

annual kWh) to the kWh it would generate if, hypothetically, it could operate at full capacity for 

every hour of the year without interruption. The CF is a measure of how much the unit is used, 

and is an important measure for assessing the potential for profitable financial return from the 

investment in the purchase of the generating equipment.

About Capacity Factor

No generating unit can run all of the time; thus, the CF of a unit is always less than 1.00. 

Reasons for the unit not running all of the time include:

• The unit is removed from service for planned maintenance.

• The unit is forced to temporarily decrease output due to a partial equipment failure that 

limits output, which requires unplanned maintenance that can be accomplished with the 

unit running at partial load.

• The unit is forced to be completely removed from service due to equipment failures and 

subsequent required unplanned maintenance. 

• The unit runs only at part load because of grid variations in the demand for power. The 

ability of the unit to follow the demand makes this unit the most economical to turndown 

compared to the other units running at the same time.

• The unit costs more to operate than competing units, therefore it is displaced by units that 

are either more efficient or use less costly fuel. Since the unit’s production costs are 

higher than competing units that could meet the system power demand at a given period 
Cost and Performance Baseline for Fossil Energy Plants

515

of time, the unit is dropped for periods of time from the dispatch order since it is not 

needed. Units that have lower production costs then meet the demand, and the unit 

remains idle until once again the system demand rises high enough so that the unit rejoins 

the dispatch order as the most cost effective unit available for service at that given level 

of demand.

A unit cannot have a CF greater than its equivalent availability (defined as the fraction of time 

that the unit is available accounting only for planned maintenance and forced outages). The 

equivalent availability thus forms the upper bound on the CF. Of course, the unit may have a 

lower CF when there are periods of time where competing units with lower production costs can 

win the competitive bidding to meet demand, forcing the less economical unit to be idle.

For the most part, a generating unit can only provide a financial return to its investors when it is 

running. While a unit can earn revenue even if it is not providing output, selling ancillary 

services, such as providing reserve power and other standby services, overwhelmingly, the 

investment in the unit is made with anticipation of revenue from unit operations; the more hours 

the unit runs —that is, the higher its CF— the greater potential return from its operations.

Financial Implications of Capacity Factor

An electric generating unit’s CF has a dramatic impact on the annual fixed operating costs. 

These costs must be paid whether or not the unit is operating and earning revenue. These fixed 

costs include property tax, paying off the capital investment to the investment bankers, salaries 

for the operations staff who need to be there whether the plant is running or not, and others. The 

greater the CF (the number of hours that a unit operates, and thus earns revenue), the greater the 

period over which these fixed operating costs can be amortized, and the lower the percentage 

impact on the total annual costs of production for the unit.

PJM Interconnection is a regional transmission organization (RTO) that coordinates the 

movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky,

Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West 

Virginia, and the District of Columbia. As an Independent System Operator, in 2006, PJM

dispatched the generation of 1,706 sources for meeting demand. It is an excellent choice for 

modeling the dispatch prospects of the units modeled in this study, since:

Unit Dispatch in the PJM Control Region

• PJM is the largest control region in the world, eclipsing Japan, and of France, the next 

larger regions. 

• PJM dispatches a diverse mix of generation.

• PJM is a model for competitive electric power dispatch operations; more than 70 nations 

have sent delegates to PJM to learn about its market model and its operation of the 

electric grid.
Cost and Performance Baseline for Fossil Energy Plants

516

This analysis of unit dispatch within PJM for the cases in this study was performed with 

consideration for the following:

Method Used to Estimate Unit Dispatch in PJM in Year 2010

• Hour-by-hour forecast of expected electric demand within the control region in 2010.

• Forecast of fuel costs for the units competing for electric sales within the region in 2010.

• Assessment of the seasonal availability of the competing fleet of generating units.

• Estimates for each of the generating units competing for electric sales within the control 

region:

− Variable operating costs for each.

− Fuel and other production costs for each.

• Forecast the hour-by-hour unit dispatch that would result in the most competitive mix of 

units for each hour of operation throughout the target study year 2010.

To update the examined cases, dispatched based CFs were determined for the six cases without 

CO2 capture through modeling the dispatch of the units in the PJM ISO. The remainder of this 

chapter provides:

Dispatch-Based Capacity Factor – What is Discussed

• The modeling results of the six non-capture cases within this region.

• A description of the PJM ISO.

• A review of the modeling method and assumptions that were used to develop these 

estimates.

• A listing of the case economics at the anticipated CF levels estimated in this chapter.

6.5 DISPATCH MODELING RESULTS WITHIN PJM

Year 2010 unit dispatch modeling in the PJM control region was performed under two scenarios:

• Natural gas price fixed at the EIA-predicted value for 2010 of $6.55/MMBtu.

• Varying the natural gas price over the range of $0 to $20/MMBtu. 

The generating unit dispatch stack, including a list of generating units ordered by production 

costs, for the fixed natural gas price case is shown in Exhibit 6-8 and illustrates the increase in 

production cost with increased cumulative production from the system. Additionally, this plot 

shows the fuel type of the plants within the stack. As expected, the fuel price dominates the 

stacking order with the technologies using the lower cost (or no cost) fuels being dispatched first, 

then coal, then natural gas; those with the most expensive fuel, No. 2 oil, are dispatched last.
Cost and Performance Baseline for Fossil Energy Plants

517

Exhibit 6-8 Estimated Stacking Order in PJM for Year 2010 Based on First Year 

Production Costs

The stack curve in Exhibit 6-8 would change with variations in the natural gas price. For 

example, as the price of natural gas decreases, the production cost of the natural gas-fired units 

would decrease. This could eventually lead to a drop below the bituminous coal-fired unit’s 

production costs. In this case, the natural gas units would shift to the left of the bituminous coalfired units and be dispatched first.

Based on the uncertainty of natural gas prices in 2010, the initial dispatch modeling was 

performed as a scan of the natural gas price ranging from $0 to $20/MMBtu. At low natural gas 

prices, $2.50/MMBtu, the natural gas units in the PJM fleet are dispatched prior to the coal-fired

units. The most efficient coal unit, SC PC, achieves the lowest production cost and therefore is 

the first to be dispatched with increasing natural gas prices. This results in the SC PC unit 

having the highest CF, as shown in Exhibit 6-9. Exhibit 6-9 further shows that the dispatch of 

the units is not significantly impacted by natural gas prices in the range of $6-$10/MMBtu. 

When the price of natural gas is above $12.50/MMBtu, the production cost of the NGCC unit is 

above that of the oil-fired units in the fleet, so the CF continues to drop.

0

50

100

150

200

250

300

0 20000 40000 60000 80000 100000 120000 140000 160000

Production Cost ($/MWh)

Cumulative Production (MW)

Natural Gas

Wind

Landfill Gas

Hydro

Coal

No 2 Oil

Black Liquor

MSW

Other Gas

Wood Solids

No. 6 Oil

Nuclear

NaturalGas Price = $6.55/MMBtu

Coal Price = $1.64/MMBtu
Cost and Performance Baseline for Fossil Energy Plants

518

Exhibit 6-9 Capacity Factors of Replacement Units Dispatched into PJM

The fuel costs used in this study (coal at $1.64/MMBtu and natural gas at $6.55/MMBtu) lead to 

the CFs listed in Exhibit 6-10.

Exhibit 6-10 Dispatch Based Capacity Factors Assuming No CO2 Capture

Case CF

Case 1 - GE IGCC 51.5%

Case 3 - CoP IGCC 54.1%

Case 5 - Shell IGCC 62.0%

Case 9 – Subcritical PC 73.4%

Case 11 - SC PC 85.0%

Case 13 - NGCC 16.5%

Exhibit 6-11 illustrates the desired unit dispatch factor, which ignores availability and is 

therefore the percentage of time that a unit would be dispatched if it is 100 percent available, as a 

function of the production cost of the entire PJM fleet. For the coal-based cases, there is a high 

sensitivity of the dispatch factor on the production cost; that is if the production cost changes a 

0

20

40

60

80

100

$0 $5 $10 $15 $20

Capacity Factor (%)

NG Price ($/MMBtu)

PC Supercritical

PC Subcritical

IGCC - Shell

IGCC - CoP

IGCC - GE

NGCC - F Class
Cost and Performance Baseline for Fossil Energy Plants

519

small amount the dispatch factor changes significantly. Additionally, the high efficiency of the 

SC PC leads to this unit being very competitive compared to the existing PJM portfolio.

Exhibit 6-11 Summary of Prospective Facility Parameters for Modeling

The dispatch based CFs were used to revise the economic analyses for the cases without CO2

capture. The impact of dispatch based CFs on the LCOE are summarized in Exhibit 6-12 and 

Exhibit 6-13. These exhibits compare the “must run” LCOEs (“initial”) determined with the CFs 

initially assumed in this report to the LCOEs determined with the dispatch-based CF

(“calculated”) for 2010 operations in PJM. In the comparison, it is important to note that 

variable costs (fuel and variable O&M) are the same while the fixed costs (capital charges and 

fixed O&M) vary.
Cost and Performance Baseline for Fossil Energy Plants

520

Exhibit 6-12 Comparison of COE as a Function of Capacity Factor

Breakdown of COE ($/MWh) COE

CF $/MWh Capital 

Costs

Fixed 

O&M

Variable 

O&M Fuel

Case 1 

GE IGCC

Initial 80.0% $43.39 $11.28 $7.30 $14.36 $76.32

Calculated 51.5% $67.40 $17.52 $7.30 $14.36 $106.57

Case 3 

CoP IGCC

Initial 80.0% $41.68 $11.08 $7.20 $14.08 $74.05

Calculated 54.1% $61.64 $16.39 $7.20 $14.08 $99.31

Case 5

Shell IGCC

Initial 80.0% $48.16 $12.16 $7.75 $13.28 $81.35

Calculated 62.0% $62.14 $15.69 $7.75 $13.28 $98.86

Case 9 

Subcritical PC

Initial 85.0% $33.31 $7.83 $5.15 $15.21 $61.50

Calculated 73.4% $38.57 $9.07 $5.15 $15.21 $68.00

Case 11 

SC PC

Initial 85.0% $33.78 $7.97 $5.04 $14.25 $61.03

Calculated 85.0% $33.78 $7.97 $5.04 $14.25 $61.03

Case 13 

NGCC

Initial 85.0% $10.11 $2.96 $1.32 $44.53 $58.92

Calculated 16.5% $52.08 $15.27 $1.32 $44.53 $113.20
Cost and Performance Baseline for Fossil Energy Plants

521

Exhibit 6-13 Impact of Dispatched Based Capacity Factors on the Cost of Electricity

$0

$25

$50

$75

$100

$125

$150

Cost of Electricity ($/MWh)

Capital Costs

Fixed O&M

Variable O&M

Fuel

coal natural gas

GEE IGCC ConocoPhilips 

IGCC

Shell IGCC Subcritical PC Supercritical

PC

NGCC

CF = 

80%

CF = 

52%

CF = 

80%

CF = 

85%

CF = 

85%

CF = 

73% CF = 

85%

CF = 

62%

CF = 

80%

CF = 

54%

CF = 

17%

CF = 

85%

Left Collumn - Assumed Capacity Factor

Right Collumn - Dispatch Calculation Based Capacity Factor
Cost and Performance Baseline for Fossil Energy Plants

522

6.6 PJM INDEPENDENT SYSTEM OPERATOR

PJM was formed in 1927 in order to share the resources of three utilities, Philadelphia Electric 

Company (PECO), Pennsylvania Power & Light Company (PP&L), and Public Service Electric 

& Gas Company (PSE&G), thus allowing them to increase operational efficiencies. This became 

the world’s first power pool. PJM became the first fully functioning Independent System 

Operator in 1998, responsible for both the safety and reliability of the transmission system and 

overseeing the administration of a competitive wholesale electric power market.

The scope of the PJM East and PJM West operations includes:

• 51 million people served

• 144,644 MW of peak load

• 164,905 MW of generation capacity 

• 729,000 GWh (gigawatt-hour) of energy per year

• 1,706 generation sources of diverse types

• 56,250 miles of transmission lines

• 450+ members

• $71 billion in energy and energy service trades since 1997

PJM is a limited liability company that operates on a profit neutral basis. PJM’s Operating 

Agreement and Tariff provide that it can recoup its operating expenses from its member 

companies. Debt service is included in the operating expenses that PJM bills to members on a 

monthly basis. It is a non-stock corporation owned by its members and governed by the Federal

Energy Regulatory Commission (FERC) in cooperation with the state regulatory boards in which 

it operates. Other income comes from studies and interconnection fees, membership dues, and 

interest. 

Today, PJM has evolved to become more of a process than a specific region, though its physical 

region is expanding rapidly, as well. The recent issues in wholesale trading and stalled 

unregulated retail initiatives have demonstrated the need to provide a uniform set of operating 

principles that allows the forces of supply and demand to work freely in a transparent manner 

while encouraging participation by new, non-utility participants. PJM has shown it has the 

technology (notably a suite of Internet scheduling and trading tools) and organizational structure 

to accomplish this while maintaining system reliability. PJM’s operating territory as of February 

2008 is shown in Exhibit 6-14 [81].
Cost and Performance Baseline for Fossil Energy Plants

523

Exhibit 6-14 The PJM Operating Territory

6.6.1

PJM is its region’s RTO with responsibility to act in several roles, including:

PJM Roles and Responsibilities

• Control area operator

• Transmission provider

• Market administrator

• Regional transmission planner

• NERC security coordinator

PJM is responsible for the region’s electric integrity, unit dispatch and reliability, and 

administering the pricing mechanisms for delivery of all power. With the implementation of the 

PJM Open Access Transmission Tariff in 1997, PJM began operating the nation’s first regional 

bid-based energy market, and now operates six competitive markets selling energy, capacity and 

ancillary services. PJM enables participants to buy and sell energy, schedule bilateral electric 

sale transactions, and reserve transmission service. PJM provides the accounting and billing 

services for these transactions.

Each day, PJM forecasts how much electricity will be needed and receives offers to supply 

electricity from producers and other suppliers of electricity. PJM decides what offers to accept 
Cost and Performance Baseline for Fossil Energy Plants

524

by selecting which plants will make electricity over the next period. PJM bases its decisions on 

the overall least cost for the whole region, considering the pattern of demand and availability of 

supply. PJM directs the operation of the generation plants by agreements with their owners. The 

electricity actually flows through transmission lines (high tower, high voltage lines) to local 

utilities’ distribution station and from there is sent on local electric lines to homes, factories and 

businesses. PJM also anticipates electricity needs years ahead and makes plans to ensure that 

enough electricity will be there as the region grows [82

6.6.2

].

Generation capacity in PJM is currently 187,172 MW based on the stacking order compiled in 

January 2008 for the year 2006. The mix of fuels in PJM as indicated in the stacking order is 

shown in Exhibit 6-15.

Generation Mix

Exhibit 6-15 PJM Installed Capacity by Fuel Type

6.6.3

PJM is dedicated to making all facets of electric generation service that are practicable available 

on a competitive market basis, thus providing accurate pricing signals and access to these 

products for all participants in a deregulated electricity environment. PJM’s spot and ancillary 

markets offer market flexibility in that they support bilateral transactions by providing liquidity 

and risk management instruments, allowing self-scheduling of supply, and providing spot market 

access. Based on the short but significant history of this effort, it would appear that PJM has 

PJM Markets

Coal , 38.8

Natural Gas, 27.4

Nuclear, 16.5

Distilate/Residual 

Fuel Oil and Oil 

Based Fuels, 7.7

Hydro, 3.3

Biomass and 

Municipal Waste, 

1.1

Wind, 1.6 Other, 3.7
Cost and Performance Baseline for Fossil Energy Plants

525

succeeded in creating rational markets with the ability to adapt as market power or reliability 

issues arise. PJM currently operates six markets:

• Day-ahead energy market

• Real-time energy market

• Daily capacity market

• Monthly/multi-monthly (interval) capacity market

• Regulation market

• Monthly FTR auction market

6.6.4

Generation owners in PJM can sell the output from their units in three ways: bid into the PJM 

day-ahead market, self-schedule their output to serve their own load, or sell their output directly 

(bilaterally) to another party.

PJM Energy Markets

PJM was a net exporter of energy on a monthly basis for every month in 2006, and exported an 

average of 1.5 million MWh. Imports into the region and exports out of the region respond to 

market prices. As detailed in the PJM Interconnection State of the Market Report – 2006, this 

activity supports the view that the PJM energy market is liquid, and exists in the context of a 

much broader energy marketplace.

All anticipated generation and load in PJM must be scheduled through PJM at least the day 

before. Generators are contacted the day before and advised as to which (if any) of their bids 

were accepted, the hours they must run, and the amounts that they will be required to provide 

each hour. If a generator fails to supply the generation when required, it must replace that energy 

by purchasing it – either bilaterally or from the real-time energy market. 

PJM runs two energy markets: the day-ahead market and the real-time market. All transactions 

made in the day-ahead market are financially binding, with adjustments for actual generation and 

usage made using the real-time market. 

6.6.5

This study assumes that the units modeled in this study would be selling their output to the PJM 

day-ahead market. The day-ahead energy market is a financial market and is used to provide a 

hedge against price fluctuations (primarily congestion charges) in the real-time market. Based 

on load schedules submitted by all load-serving entities (LSEs) at least the day before the 

Operating Day, PJM calculates the expected energy needed at various locations (major busses) 

throughout the system, and accepts both sell and buy bids for the total amount needed each hour 

plus reserves. Then PJM stacks the sell bids in low-to-high price (or economic) order and 

assigns a price for electricity for each hour at each location for the following day in dollars per 

megawatt ($/MW). The price for one megawatt of power during each hour the next operating 

day in the day-ahead market will be the lowest price bid satisfying the anticipated load 

requirement for that hour, plus any congestion charges expected to occur at that location. This 

hourly price is known as the Locational Marginal Price, or LMP. All successful bidders for that 

hour receive the price accepted, regardless of the price they bid.

Day-Ahead Market

PJM defines LMP as the “cost of supplying the next MW of load at a specific location, 

considering generation marginal cost, cost of transmission congestion, and losses.” LMP values 
Cost and Performance Baseline for Fossil Energy Plants

526

are the result of security-constrained economic dispatch operations, a method system operators 

have used to manage congestion for years. A least-cost security constrained dispatch algorithm 

determines the least expensive way to serve load while respecting transmission limits.

During periods of low demand, the LMP is generally the same at all locations. That is, none of 

the transmission capability is constrained. During periods of high demand, equipment problems, 

or system irregularities, the LMP can vary significantly from one location to another. This is 

especially so during peak system days. 

Day-Ahead Energy Market Timeline

• Up to 12 noon – PJM receives bids and offers for energy for next Operating Day.

• 12 noon to 4 pm – Day-ahead market is closed for evaluation by PJM.

• 4 pm – PJM posts day-ahead and hourly schedules.

• 4 pm to 6 pm – Re-bidding period. Re-bidding period is for generation not selected for 

day-ahead market and lets them re-bid for regulation, operating, and spinning reserves. 

PJM desires to give preference to uncommitted capacity first.

• PJM continually re-evaluates and sends out individual generation schedule updates as 

required throughout the Operating Day.

The maximum and minimum day ahead electricity prices for the PJM ISO region for the year 

2006 are shown in Exhibit 6-16. 

Exhibit 6-16 PJM East Day-Ahead LMP for 2006

$0

$50

$100

$150

$200

$250

$300

$350

$400

Jan-06 Feb-06 Mar-06 Apr-06 May-06 Jun-06 Jul-06 Aug-06 Sep-06 Oct-06 Nov-06 Dec-06

Day Ahead LMP ($/MWh)

DA LMP Minimum

DA LMP Maximum
Cost and Performance Baseline for Fossil Energy Plants

527

6.6.6

There is a strong correlation between price and demand in the PJM markets. Exhibit 6-17

illustrates day-ahead high and low prices, and daily high and low loads for the year 2006. 

Prices and Demand

Exhibit 6-17 PJM Load and Day-Ahead LMP for 2006

Exhibit 6-18 and Exhibit 6-19 show the correlation between price and demand over a one-year 

period. They also show a rational association between the two, supporting the viewpoint that 

PJM has been effective at creating competitive energy markets. 

$0

$100

$200

$300

$400

$500

$600

0 

25 

50 

75 

100 

125 

150 

Jan-06 Feb-06 Mar-06 Apr-06 May-06 Jun-06 Jul-06 Aug-06 Sep-06 Oct-06 Nov-06 Dec-06

DA - LMP ($/MWh)

Demand (GW)

PJM Demand - Minimum

PJM Demand - Maximum

DA LMP Minimum

DA LMP Maximum
Cost and Performance Baseline for Fossil Energy Plants

528

Exhibit 6-18 PJM Day-Ahead LMP vs. Demand for 2006

Exhibit 6-19 PJM Price/Load Distribution for 2006
Cost and Performance Baseline for Fossil Energy Plants

529

6.7 DESCRIPTION OF THE PJM REGIONAL MODELING

The analysis tools used to predict economic dispatch are a series of databases and calculations 

designed to model future dispatching of power generation facilities taking into account:

• Fuel Cost

• Additional new generation

• Changes in demand

• Changes in legislation

These procedures emulate the competitive dispatch of units. Outputs from the modeling include:

• CFs for competing units

• Individual and fleet wide emissions 

The analysis method is based on modeling the current conditions in a power generation network 

and then projecting the operation of the system into the future. Modeling of a current generation 

system requires:

• The demand of the generation system on an hourly basis

• The selling price of electricity within the generation system on an hourly basis

• Identifying power generation units in the system with their operating parameters 

including:

− Nameplate capacity

− Fuel type

− Heat rate

− Emission intensities 

− Variable operating and maintenance costs

− Delivered fuel costs

To project the existing system into the future, the existing conditions are modified by projections 

of future:

• Fuel Prices

• Demand

• Change in generation unit portfolio

• Changes in legislation

This data above is acquired through a variety of publicly available databases and internal 

modeling methods.

The dispatch of prospective units is determined through:

• Determining the dispatch order of the existing plants in a system based on the production 

costs of the individual units. These electricity production costs are determined from the 

fuel costs, plant efficiency, the variable operating and maintenance costs, and penalties 

that are related to the generation of electricity such as for CO2 emissions. In the case of 

modeling the PJM region, 1,706 units are characterized. The list of plants and their 
Cost and Performance Baseline for Fossil Energy Plants

530

information, ordered by production cost, is referred to as the “stack”. The units are then 

inserted into this mix of generating units, and ordered based upon their specific 

production costs.

• Identifying the marginal production cost of the last-dispatched unit for a given hour 

through comparing the hourly demand for the generation system to the cumulative 

generation in the stack. The last facility dispatched to meet the demand sets the 

production cost for that hour. 

• Determining if a prospective unit is dispatched in an hour by comparing the plant 

production cost to the production cost of the last plant dispatched. If the prospective 

unit’s production cost is less, then the unit is dispatched.

• Sum the hourly results for the prospective power plants to determine the CF for each unit

during the year.

o For the non-capture technologies, the CFs of the facilities, listed earlier in 

Exhibit 6-7, were determined through dispatch modeling of these units into the 

PJM ISO.

6.8 WPLANET MODEL INPUTS

The inputs for the model were obtained from standard databases containing generation 

information for the year 2006. Exhibit 6-20 provides a summary of the sources used to obtain 

the required information for 2006.

Exhibit 6-20 Data Sources for Electricity Generation in the PJM Region in Year 2006

Generation System Parameter for 2006 Data Source Comments

Hourly System-Wide Demand PJM website database

Electricity Selling Price (DA-LMP1) PJM website database Not required for current 

calculations

Contributing Power Generation Unit 

Names PJM website database

Generation Unit Parameters 2006 UDI Database2

Fuel Type 2006 UDI Database

Nameplate Capacity 2006 UDI Database

Heat rate 2006 eGrid Database

Emission Intensities 2006 eGrid Database Not required for current 

calculations

Variable O&M Costs Power plant operations 

models

Delivered Fuel Costs 2006 FERC Form 423 1 DA-LMP is Day Ahead Locational Marginal Price 2 UDI World Electric Power Plants Database 2006, available from www.platts.com
Cost and Performance Baseline for Fossil Energy Plants

531

This data is cast into the future for projections of the fuel prices, generation demand, and 

additions to the generation facility portfolio. The assumptions for the projections and the data 

sources used are summarized in Exhibit 6-21.

Exhibit 6-21 Assumptions for Projecting PJM Year 2006 into 2010

Fuel Prices

Natural Gas EAO 2007 - $6.55/MMBtu 

Bituminous Coal EAO 2007 -$1.64/MMBtu

Subbituminous Coal Scaled Bituminous Coal Price

Diesel Fuel Oil 2006 delivered fuel costs scaled 

to 2010 by futures market prices.

Other Fuels Fixed at previous study prices.

Demand Forecast 1.44 % increase per year based on 2006 EIA-411 projected 

demand growth for RFC Reliability Region. 

Changes in Generation 

Facility Portfolio

Data from future power generation studies on PJM website. 

Summarized in Exhibit 6-22

The additional facilities that are planned or under construction and expected to be in service in 

2010 amount to an additional 10,000 MW of generating capability. The breakdown of these 

technologies by fuel type is shown in Exhibit 6-22.

Exhibit 6-22 Breakdown of Additional Generation in the PJM ISO by Fuel Type

Coal, 51.4

Coal IGCC, 10.5

Natural Gas, 10.5

Wind, 24.6

Other (Biomass, 

Solar, Refuse, 

Wood), 3
Cost and Performance Baseline for Fossil Energy Plants

532

The characteristics of the non-carbon capture units are listed in Exhibit 6-23. These costs are 

based on the AEO 2008 projections of the 2007 natural gas and coal prices, $6.55/MMBtu and 

$1.64/MMBtu respectively. The SC PC facility has the lowest production costs (fuel and 

variable O&M costs) from the high efficiency and the low fuel cost. In spite of the greater 

efficiency and lower O&M cost of the natural gas-fired combined cycle system, the natural gasfired unit has the greatest operating cost by a factor of two because of the greater fuel cost. 

Exhibit 6-23 Summary of Prospective Facility Parameters

Bituminous 

Baseline Facility 

Types

Fuel 

Type

Fuel Cost 

($/MMBtu)

O&M 

(mills/kWh)

Production 

Costs 

(mills/kWh)

Heat Rate 

(Btu/kWh)

Nameplate 

Capacity

Case 1 

IGCC GEE

Bit 

Coal $1.64 $7.30 $21.66 8,756 622

Case 3

IGCC CoP

Bit 

Coal $1.64 $7.20 $21.28 8,585 625

Case 5

IGCC Shell

Bit 

Coal $1.64 $7.75 $21.03 8,099 629

Case 9

PC Sub

Bit 

Coal $1.64 $5.15 $20.36 9,276 550

Case 11

PC Super

Bit 

Coal $1.64 $5.04 $19.28 8,686 550

Case 13

NGCC F-Class NG $6.55 $1.32 $45.84 6,798 555
Cost and Performance Baseline for Fossil Energy Plants

533

7.

This supplementary chapter examines the impact of dry and parallel cooling systems on the cost 

and performance of six plant configurations:

DRY AND PARALLEL COOLING

• IGCC (CoP) without CO2 capture

• IGCC (CoP) with CO2 capture

• SC PC without CO2 capture

• SC PC with CO2 capture

• NGCC without CO2 capture

• NGCC with CO2 capture

Parallel and dry cooling systems don’t have universal definitions. In this study the systems are 

defined as follows:

Parallel Cooling: Steam exiting the LP turbine is divided equally between a conventional 

condenser using cooling water as the cooling medium and an air-cooled condenser using ambient 

air as the cooling medium. Additional cooling loads use cooling water, which rejects heat to an 

evaporative cooling tower.

Dry Cooling:

The cooling system definition results in significant load on an evaporative cooling tower in PC 

and NGCC cases with CO2 capture even in the dry cooling scenarios because of the large 

Econamine cooling water requirement. Since the cooling water temperature achieved in an aircooled cooler would be significantly higher than in an evaporative cooling tower, the Econamine 

performance would also be affected. The quote basis for the Econamine process is for 16°C 

(60°F) cooling water and no data were available to estimate performance characteristics at higher 

temperatures. Hence the decision to maintain an evaporative cooling tower for non-condenser 

loads even in the dry cooling cases.

Steam exiting the LP condenser is condensed entirely in an air-cooled condenser. 

Additional miscellaneous cooling loads use cooling water that rejects heat to an evaporative 

cooling tower.

The study ambient design conditions are the same as ISO conditions and were presented 

previously in Exhibit 2-1. The ambient conditions and additional study assumptions result in the 

following design basis:

• Coal feed rate was maintained constant relative to the baseline case for both the parallel

and dry cooling scenarios, which resulted in constant gross output but different net output 

for each case (different auxiliary loads for an air-cooled condenser).

• The condenser approach temperature in the baseline study was 12°C (21°F). The 

approach temperature for the air-cooled condenser was assumed to be 23°C (42°F)[83], 

which maintained a constant condenser temperature and pressure of 38°C (101°F) and 

0.0068 MPa (0.9823 psia) for all cases. 
Cost and Performance Baseline for Fossil Energy Plants

534

• The power requirement for the air-cooled condenser fans is 3.5 times greater than for 

evaporative cooling tower fans when the air-cooled condenser and cooling tower have 

equivalent heat duty [84

• The baseline study accounted for cooling loads that were modeled such as the steam 

turbine condenser; the CO2 capture process; compressor intercoolers; low temperature 

syngas cooling and sour water stripper condenser (IGCC cases); and an allowance for 

miscellaneous loads. The miscellaneous loads assigned to each technology were 100 

MMBtu/hr for PC and 25 MMBtu/hr for IGCC and NGCC. These loads were maintained 

at the same values for the parallel and dry cooling cases and were assigned to the 

evaporative cooling tower.

].

The cost accounts affected by the change in cooling system are shown in Exhibit 7-1 along with 

the process parameter used for cost scaling and the scaling exponent.

Exhibit 7-1 Cost Accounts Affected by Change in Cooling System

Cost Account Scaling Parameter Scaling 

Exponent

Account 3.2: Water Makeup and Pretreating Raw water makeup 0.71

Account 3.4: Service Water Systems Raw water makeup 0.71

Account 3.7: Waste Treatment Equipment Raw water makeup 0.71

Account 8.3a: Condenser and Auxiliaries Condenser duty 0.67

Account 8.3b: Air-Cooled Condenser Air-cooled condenser duty 0.70

Account 9.1: Cooling Towers Cooling tower duty 0.70

Account 9.2: CWPs Circulating water flow rate 0.86

Account 9.3: CWS Auxiliaries Circulating water flow rate 0.65

Account 9.4: Circulating Water Piping Circulating water flow rate 0.65

Account 9.5: Makeup Water System Raw water makeup 0.60

Account 9.6: Component Cooling Water 

System Circulating water flow rate 0.65

Account 9.9: CWS Foundations and 

Structures Circulating water flow rate 0.60

Account 14.4: Circulation Water 

Pumphouse Circulating water flow rate 0.60

Account 14.5: Water Treatment Buildings Raw water makeup 0.66

Account 14.9: Waste Treatment Building 

and Structures Raw water makeup 0.07
Cost and Performance Baseline for Fossil Energy Plants

535

7.1 STUDY RESULTS

Dry and parallel cooling systems result in decreased water consumption at the expense of 

increased cost and reduced efficiency. There is a net increase in capital cost because of the 

addition of the air-cooled condenser, which is greater than the reductions realized from the 

reduced cooling water flow rate and cooling tower duty. The O&M costs change minimally 

because an increase in fixed O&M costs (maintenance labor and materials) is approximately 

offset by a decrease in variable O&M costs (raw water and water treatment chemicals).

The normalized raw water withdrawal for the baseline, parallel, and dry cases is shown in 

Exhibit 7-2. In each case the raw water withdrawal (in gpm) is normalized by the net unit output 

(in MWs). In Exhibit 7-3 the absolute net reduction in raw water withdrawal (in gpm) for the 

parallel and dry cooling systems is shown. The raw water source continues to be 50 percent 

from groundwater and 50 percent from a municipal water supply. The following conclusions can 

be drawn:

• The greatest impact on raw water withdrawal is for PC and NGCC non-capture cases 

using dry cooling. The steam turbine condenser duty represents over 95 percent of the 

cooling duty in those cases, and the use of an air-cooled condenser leaves very little 

remaining load for the cooling tower. Water demand for FGD in the PC case and for 

BFW makeup in the PC and NGCC cases is relatively small, resulting in low normalized 

water withdrawal. The impact is not quite as dramatic in the IGCC non-capture case 

because there are additional cooling loads besides the steam turbine condenser, namely 

low temperature syngas cooling, the ASU Main Air Compressor (MAC) intercoolers, the 

AGR process, and the SWS condenser.

• The smallest impact of dry and parallel cooling on water withdrawal is for PC and NGCC 

CO2 capture cases. The Econamine process requires significantly more cooling water 

than the two-stage Selexol process used in IGCC cases, and the capture process cooling 

load is assigned to an evaporative cooling tower. Therefore, the cases using the 

Econamine process continue to have significant evaporative and blowdown losses from 

the cooling tower, which diminishes the water savings of the parallel and dry systems.

• NGCC has the lowest normalized raw water withdrawal for CO2 capture cases using 

conventional wet cooling. The same is true using a parallel cooling system. However, 

when using a dry cooling system, the IGCC capture plant has the lowest normalized raw 

water withdrawal primarily due to the higher steam turbine output of the IGCC plant (240 

MW) compared to the NGCC plant (149 MW) and the associated cooling duty.

In all cases the use of parallel and dry cooling has a significant impact on water withdrawal. The 

absolute water savings ranges from 537 gpm for NGCC with CO2 capture using parallel cooling 

to 4,649 gpm for SC PC without capture using dry cooling.

The reduction in water withdrawal comes with a performance and cost penalty. The net plant 

output decreases slightly because the increase in auxiliary load due to the air-cooled condenser 

fan is greater than the decrease due to a reduction in the cooling tower fan and CWP loads.
Cost and Performance Baseline for Fossil Energy Plants

536

Exhibit 7-2 Normalized Raw Water Withdrawal for Baseline, Parallel and Dry Cooling Cases

7.0

4.7

2.4

11.1

8.4

5.6

9.8

5.6

1.4

18.3

15.1

11.9

4.3

2.2

0.1

8.4

7.3

6.1

0

2

4

6

8

10

12

14

16

18

20

Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry

IGCC No Capture IGCC w/Capture SCPC No Capture SCPC w/Capture NGCC No Capture NGCC w/Capture

Normalized Raw Water Withdrawal, gpm/net-MW
Cost and Performance Baseline for Fossil Energy Plants

537

Exhibit 7-3 Absolute Decrease in Raw Water Withdrawal for Parallel and Dry Cooling Cases

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry

IGCC No Capture IGCC w/Capture SCPC No Capture SCPC w/Capture NGCC No Capture NGCC w/Capture

1,432

2,863

1,424

2,848

2,324

4,649

1,753

3,510

1,154

2,309

537

1,075

Water Withdrawal Reduction, gpm
Cost and Performance Baseline for Fossil Energy Plants

538

The impact on net plant output relative to the baseline (wet cooling) cases is shown in 

Exhibit 7-4. The plant de-rate is greatest for the dry cooling cases because the air-cooled 

condenser load increases faster than the cooling tower fan/CWP load decreases. The de-rate 

ranges from 100 kW for NGCC with CO2 capture using parallel cooling to 1,059 kW for SC PC 

without CO2 capture using dry cooling. The impact on net plant efficiency is relatively small 

with the largest decrease less than 0.3 percentage points when going from wet to dry cooling for 

the SC PC without CO2 capture case.

Exhibit 7-4 Net Output Reduction Relative to the Baseline (Wet Cooling) Case

Technology/Cooling 

System

Net Output 

Reduction, kW

(No CO2

Capture)

Net Plant 

Efficiency, 

%

Net Output 

Reduction, kW

(With CO2

Capture)

Net Plant 

Efficiency, 

%

IGCC/Wet N/A 39.75 N/A 31.02

 IGCC/Parallel -290 39.73 -280 31.01

 IGCC/Dry -690 39.70 -670 30.98

SC PC/Wet N/A 39.28 N/A 28.67

 SC PC/Parallel -500 39.25 -300 28.40

 SC PC/Dry -1,059 39.21 -630 28.40

NGCC/Wet N/A 50.20 N/A 42.83

 NGCC/Parallel -270 50.17 -100 42.82

 NGCC/Dry -497 50.15 -200 42.81

The cost impact is more significant than the performance impact. The capital cost of the aircooled condenser is only partially offset by the reduction in cost of the cooling tower, CWS, and 

other water systems impacted by the reduction in water usage. Because there are always 

miscellaneous cooling loads assigned to the evaporative cooling tower, the cooling tower and 

CWSs are never eliminated, even in the dry cooling cases. The TOC for each case is shown in 

Exhibit 7-5.

The increase in TOC ranges from $46/kW for NGCC with CO2 capture using parallel cooling to 

$109/kW for SC PC with CO2 capture using dry cooling. The TOC delta between parallel and 

dry cooling cases is smallest for SC PC with no capture. The increase in cost of the air-cooled 

condenser is more nearly offset by reductions in other water related accounts because of the very 

large decrease in water withdrawal, which decreases from 3,080 gpm in the parallel cooling case 

to 770 gpm in the dry cooling case.
Cost and Performance Baseline for Fossil Energy Plants

539

The O&M costs stay approximately constant for all cases as discussed at the beginning of 

Section 7.1. The TOC and O&M costs were used to calculate a COE for each of the cases. The 

impact on the COE is shown in Exhibit 7-6. The range of COE increase is from 0.83 mills/kWh 

(NGCC with capture using parallel cooling) to 2.16 mills/kWh (IGCC with CO2 capture using 

dry cooling). The COE actually shows a slight decrease when going from parallel to dry cooling 

for the SC PC no capture case for several reasons:

• The TOC increase is small because of the large reduction in water requirements as 

discussed above.

• The decrease in variable operating cost is more significant because of the large decrease 

in water withdrawal.
Cost and Performance Baseline for Fossil Energy Plants

540

Exhibit 7-5 Total Overnight Cost for Baseline, Parallel and Dry Cooling Cases

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry

IGCC No Capture IGCC w/Capture SCPC No Capture SCPC w/Capture NGCC No Capture NGCC w/Capture

2,351 2,351 2,351

3,466 3,466 3,466

2,024 2,024 2,024

3,570 3,570 3,570

718 718 718

1,497 1,497 1,497

57 77

72 103

82 92

65 109

56 73

46 66

TOC, $/kW (2007$)

TOC Baseline, $/kW

TOC Increase, $/kW
Cost and Performance Baseline for Fossil Energy Plants

541

Exhibit 7-6 COE for Baseline, Parallel and Dry Cooling Systems

0

20

40

60

80

100

120

140

Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry

IGCC No Capture IGCC w/Capture SCPC No Capture SCPC w/Capture NGCC No Capture NGCC w/Capture

74.0 74.0 74.0

110.4 110.4 110.4

58.9 58.9 58.9

106.6 106.6 106.6

58.9 58.9 58.9

85.9 85.9 85.9

1.25 1.60

1.56 2.16

1.41 1.38

1.08 1.82

0.94 1.14

0.83 1.14

COE, mills/kWh (2007$)

Baseline COE (Wet Cooling)

Incremental COE (Hybrid/Parallel Cooling)
Cost and Performance Baseline for Fossil Energy Plants

542

7.2 SENSITIVITY CASE

The assumptions made in this study resulted in a constant fuel feed rate and constant condenser 

operating condition for all cases. The constant condenser temperature and pressure are the result 

of assuming ISO ambient conditions. In reality fossil energy plants are designed for summer and 

winter temperature extremes. The SC PC case without CO2 capture was used to examine the 

effect on a dry and wet cooling system of designing for a high ambient summer temperature.

The ambient design conditions used for the sensitivity study are shown in Exhibit 7-7 and are 

representative of summertime at Chicago’s O’Hare Airport [85

83

]. For the dry cooling case a 50°F 

approach to the dry bulb temperature was assumed [ ], which results in a condenser 

temperature of 138°F. For the wet cooling case the following assumptions result in a condenser 

temperature of 118°F:

• Circulating water is cooled to within 5°F of the WB temperature

• The cooling water temperature range is 20°F

• The condenser temperature approach is 20°F

Exhibit 7-7 Design Ambient Conditions for SC PC Sensitivity Case

Elevation, m (ft) 0

Barometric Pressure, MPa (psia) 0.10 (14.696)

Design Ambient Temperature, Dry Bulb, °C (°F) 31 (88)

Design Ambient Temperature, WB, °C (°F) 23 (73)

Design Ambient Relative Humidity, % 47

In both cases the net output was maintained at approximately 550 MW, which required an 

increase in coal feed rate relative to the baseline SC PC cases. The results, presented below, 

show that the cost and performance penalties of a dry cooling system are greater than when using 

ISO design conditions.

The normalized water usage for the wet system at high ambient temperature design conditions is 

10.3 gpm/MW(net) and for the dry system is 1.4 gpm/MW(net), or a reduction of 86 percent.

The performance penalty is 1.45 percentage points (38.23 to 36.78 percent). The dry cooling 

case requires an increase in coal feed rate of 3.9 percent to maintain the same net power output 

as the wet cooling case.

The cost penalty is also greater than in the ISO ambient condition case. The TOC increases by 

$145/kW in the dry cooling case compared to $92/kW for dry cooling at ISO conditions. The 

high ambient temperature case results in cost increases for all cost accounts (rather than just 

water based accounts) because of the increase in coal feed rate. The COE increases by 3.05

mills/kWh in the dry cooling case at high ambient temperature compared to only 1.38 mills/kWh 

at ISO conditions. The increase in COE represents a 5.1 percent increase over the wet cooling 
Cost and Performance Baseline for Fossil Energy Plants

543

case at high ambient temperature. The COE includes the increased fuel cost to maintain a 

nominal 550 MW net output.

7.3 CONCLUSIONS

Parallel and dry cooling have a significant impact on water consumption for all fossil energy 

technologies examined. The amount of water saved relative to a conventional wet cooling 

system ranges from 240 - 2,077 million gallons per year. The cost and performance penalty for 

dry and parallel cooling systems at ISO conditions is less than at a higher summer ambient 

design temperature that would represent a typical power plant design point. The performance 

penalty (net plant efficiency) at ISO conditions ranges from 0.006 to 0.270 percentage points and 

is 1.45 percentage points at the high temperature ambient condition. The cost penalty is 

primarily capital cost and ranges from 0.83 to 2.16 mills/kWh at ISO conditions and is 3.05

mills/kWh at high ambient temperature using SC PC with no capture and a dry cooling system.
Cost and Performance Baseline for Fossil Energy Plants

544

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

545

8.

GEE offers three design configurations for their gasification system [

GEE IGCC IN QUENCH-ONLY CONFIGURATION WITH CO2 CAPTURE

86

• Quench: In this configuration, the hot syngas exiting the gasifier passes through a pool of 

water to quench the temperature to approximately 288°C (550°F) before entering the 

syngas scrubber. It is the simplest and lowest capital cost design, but also the least 

efficient.

]:

• Radiant Only: In this configuration, the hot syngas exiting the gasifier passes through a 

radiant syngas cooler where it is cooled from about 1,316°C (2,400°F) to 677°C 

(1,250°F), then through a water quench where the syngas is further cooled to about 

232°C (450°F) prior to entering the syngas scrubber. Relative to the quench 

configuration, the radiant only design offers increased net power output, higher 

efficiency, improved reliability/availability relative to the radiant-convective 

configuration described below, and results in the lowest COE. This configuration was 

chosen by GEE and Bechtel for the design of their reference plant.

• Radiant-Convective: In this configuration, the hot syngas exiting the gasifier passes 

through a radiant syngas cooler where it is cooled from about 1,316°C (2,400°F) to 

677°C (1,250°F), then passes over a pool of water where particulate is removed but the 

syngas is not quenched, then through a convective syngas cooler where the syngas is 

further cooled to about 371°C (700°F) prior to entering additional heat exchangers or the 

scrubber. This configuration has the highest overall efficiency, but at the expense of 

highest capital cost and the lowest availability. This is the configuration used at Tampa 

Electric’s Polk Power Station.

Chapter 0 of this report examined the radiant only version of the GEE gasifier in both noncapture and capture configurations (Cases 1 and 2). This supplementary chapter examines the 

performance of the GEE gasifier operated in the quench only mode with carbon capture (Case 

2A).

The balance of this chapter is organized analogously to Section 3.2 of the original report (GEE

IGCC Cases), and more specifically Section 3.2.8, which covers the GEE IGCC with CO2

capture. However, only deviations from the original chapter are presented here to avoid needless 

repetition:

• Process and System Description provides an overview of the technology operation as 

applied to the GE IGCC operated in quench only mode. The systems that are common to 

all gasifiers were covered in Section 3.1 and features unchanged from the radiant only 

operation were covered in Section 3.2.8. Only features that are unique to quench only 

operation are discussed further in this section.

• Key Assumptions is a summary of study and modeling assumptions relevant to the GEE 

IGCC cases.

• Sparing Philosophy is unchanged from the radiant only cases and not repeated here.

• Performance Results provides the main modeling results from quench only configuration, 

including the performance summary, environmental performance, carbon balance, sulfur 
Cost and Performance Baseline for Fossil Energy Plants

546

balance, water balance, mass and energy balance diagrams, and mass and energy balance 

tables.

• Equipment List provides an itemized list of major equipment for Case 2A.

8.1 CASE 2A – GEE IGCC IN QUENCH ONLY MODE WITH CO2 CAPTURE

Case 2A is configured to produce electric power with CO2 capture. The plant configuration is 

the same as the GEE IGCC Case 2 with the exception that the gasifier is operated in quench only 

mode. The gross power output from the plant is constrained by the capacity of the two CTs, and 

since the CO2 capture process increases the auxiliary load on the plant, the net output is 

significantly reduced relative to Case 1.

The process description for Case 2A is similar to Case 2 with exception of the gasifier operating 

mode. A BFD and stream tables for Case 2A are shown in Exhibit 8-1 and Exhibit 8-2, 

respectively. Instead of repeating the entire process description, only differences from Case 2 

are reported here.

The gasification process is the same as Case 2 with the exception that the syngas exiting the 

gasifier passes through a water quench where the temperature is reduced from 1,316°C (2,400°F) 

to 288°C (550°F). The total coal feed to the two gasifiers is 5,301 tonnes/day (5,844 TPD) 

(stream 6) and the ASU provides 4,343 tonnes/day (4,787 TPD) of 95 percent oxygen to the 

gasifier and Claus plant (streams 3 and 5).

Gasification

Particulate is largely removed in the quench tank and no additional heat recovery occurs prior to 

the syngas scrubber.

Raw Gas Cooling/Particulate Removal

The outlet temperature from the syngas scrubber is 227°C (440°F) (stream 10).

Syngas Scrubber/Sour Water Stripper

The SGS process is the same as described for Case 2 with a 97 percent overall conversion of the 

CO to CO2. The warm syngas from the second stage of SGS (stream 12) is cooled to 244°C 

(471°F) by heating the syngas entering the first shift reactor. The syngas is then cooled to 193°C 

(380°F) by producing IP steam that is sent to the RH in the HRSG. The SGS catalyst also serves 

to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. Following 

the second SGS cooler the syngas is further cooled to 35°C (95°F) prior to the mercury removal 

beds.

Sour Gas Shift (SGS)
Cost and Performance Baseline for Fossil Energy Plants

547

Exhibit 8-1 Case 2A Block Flow Diagram, GEE Quench Only IGCC with CO2 Capture
Cost and Performance Baseline for Fossil Energy Plants

548

Exhibit 8-2 Case 2A Stream Table, GEE Quench Only IGCC with CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12

V-L Mole Fraction

Ar 0.0092 0.0165 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0053 0.0000 0.0053

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0007 0.0000 0.0007

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2197 0.0000 0.0061

CO2 0.0003 0.0054 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.0848 0.0000 0.2985

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2093 0.0000 0.4229

H2O 0.0099 0.1355 0.0000 0.0003 0.0000 0.0000 0.9997 0.0000 0.1369 0.4700 1.0000 0.2562

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0001 0.0000 0.0001

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0045 0.0000 0.0046

N2 0.7732 0.7077 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0043 0.0000 0.0043

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0003 0.0000 0.0019 0.0013 0.0000 0.0013

O2 0.2074 0.1349 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

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

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 27,367 1,660 97 20,045 5,526 0 5,037 0 23,121 37,625 0 37,625

V-L Flowrate (kg/hr) 789,731 45,607 3,132 562,472 177,815 0 90,741 0 465,209 726,195 0 726,195

Solids Flowrate (kg/hr) 0 0 0 0 0 220,888 0 24,235 0 0 0 0

Temperature (°C) 15 18 32 93 32 15 146 1,316 1,316 227 288 250

Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.62 5.58 5.52 5.45

Enthalpy (kJ/kg)A 30.23 35.62 26.67 92.50 26.67 --- 0.00 --- 2,631.86 1,479.52 2,918.18 1,017.26

Density (kg/m3) 1.2 1.5 11.0 24.4 11.0 --- 867.1 --- 8.5 25.9 25.6 24.5

V-L Molecular Weight 28.857 27.479 32.181 28.060 32.181 --- 18.015 --- 20.121 19.301 18.015 19.301

V-L Flowrate (lbmol/hr) 60,334 3,659 215 44,193 12,182 0 11,105 0 50,972 82,948 0 82,948

V-L Flowrate (lb/hr) 1,741,060 100,545 6,906 1,240,039 392,015 0 200,050 0 1,025,611 1,600,986 0 1,600,986

Solids Flowrate (lb/hr) 0 0 0 0 0 486,976 0 53,430 0 0 0 0

Temperature (°F) 59 65 90 199 90 59 295 2,400 2,400 440 550 481

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 815.0 810.0 800.0 790.0

Enthalpy (Btu/lb)A 13.0 15.3 11.5 39.8 11.5 --- --- 1,131.5 636.1 1,254.6 437.3

Density (lb/ft3) 0.076 0.091 0.687 1.521 0.687 --- 54.131 --- 0.530 1.619 1.597 1.529

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Fossil Energy Plants

549

Exhibit 8-2 Case 2A Stream Table, GEE Quench Only IGCC with CO2 Capture (Continued)

13 14 15 16 17 18 19 20 21 22 23 24

V-L Mole Fraction

Ar 0.0071 0.0071 0.0115 0.0115 0.0002 0.0018 0.0000 0.0103 0.0092 0.0091 0.0091 0.0000

CH4 0.0009 0.0009 0.0015 0.0015 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0082 0.0081 0.0130 0.0130 0.0002 0.0023 0.0000 0.0061 0.0000 0.0000 0.0000 0.0000

CO2 0.4017 0.4053 0.0501 0.0501 0.9948 0.5218 0.0000 0.6606 0.0003 0.0083 0.0083 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.5690 0.5647 0.9133 0.9133 0.0048 0.1029 0.0000 0.2596 0.0000 0.0000 0.0000 0.0000

H2O 0.0012 0.0012 0.0001 0.0001 0.0000 0.0225 0.0000 0.0017 0.0099 0.1222 0.1222 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2S 0.0061 0.0061 0.0000 0.0000 0.0000 0.3472 0.0000 0.0043 0.0000 0.0000 0.0000 0.0000

N2 0.0058 0.0065 0.0105 0.0105 0.0000 0.0008 0.0000 0.0574 0.7732 0.7541 0.7541 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1064 0.1064 0.0000

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

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 27,963 28,357 17,424 17,424 10,414 496 0 394 110,253 139,653 139,653 20,010

V-L Flowrate (kg/hr) 552,101 564,705 90,455 90,455 456,190 17,654 0 12,604 3,181,557 3,834,485 3,834,485 360,491

Solids Flowrate (kg/hr) 0 0 0 0 0 0 5,523 0 0 0 0 0

Temperature (°C) 35 35 35 195 51 48 178 38 15 562 132 534

Pressure (MPa, abs) 5.17 5.1 5.137 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512

Enthalpy (kJ/kg)A 36.94 36.2 194.924 1,117.278 -162.292 74.702 --- 5.842 30.227 834.643 343.500 3,432.968

Density (kg/m3) 41.0 41.2 10.2 4.2 641.8 2.2 5,280.6 77.3 1.2 0.4 0.9 36.7

V-L Molecular Weight 19.744 20 5.191 5.191 43.804 35.590 --- 31.966 28.857 27.457 27.457 18.015

V-L Flowrate (lbmol/hr) 61,647 62,516 38,414 38,414 22,960 1,094 0 869 243,066 307,881 307,881 44,115

V-L Flowrate (lb/hr) 1,217,174 1,244,961 199,419 199,419 1,005,728 38,921 0 27,786 7,014,133 8,453,593 8,453,593 794,747

Solids Flowrate (lb/hr) 0 0 0 0 0 0 12,177 0 0 0 0 0

Temperature (°F) 95 95 95 383 124 119 352 100 59 1,044 270 994

Pressure (psia) 750.0 745.0 745.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Enthalpy (Btu/lb)A 15.9 15.6 83.8 480.3 -69.8 32.1 --- 2.5 13.0 358.8 147.7 1,475.9

Density (lb/ft3) 2.562 3 0.636 0.261 40.065 0.137 329.655 4.823 0.076 0.026 0.053 2.293
Cost and Performance Baseline for Fossil Energy Plants

550

Mercury removal and the AGR process are the same as in Case 2.

Mercury Removal and Acid Gas Removal

The AGR process in Case 2A is a two stage Selexol process where H2S is removed in the first 

stage and CO2 in the second stage of absorption as previously described in Section 3.1.5. The 

process results in three product streams, the clean syngas, a CO2-rich stream and an acid gas feed 

to the Claus plant. The acid gas (stream 18) contains 35 percent H2S and 52 percent CO2 with 

the balance primarily H2.

The CO2 compression and dehydration scheme is the same as for Case 2.

CO2 Compression and Dehydration

The Claus plant is the same as Case 2 with the following exceptions:

Claus Unit

• 5,523 kg/hr (12,177 lb/hr) of sulfur (stream 19) are produced

• The waste heat boiler generates 12,957 kg/hr (28,564 lb/hr) of 3.0 MPa (430 psia) steam.

Clean syngas from the AGR plant is heated to 241°C (465°F) using first hot water from the 

syngas scrubber followed by HP BFW before passing through an expansion turbine. The clean 

syngas (stream 16) is diluted with nitrogen (stream 4) and then enters the CT burner. There is no 

integration between the CT and the ASU in this case. The exhaust gas (stream 22) exits the CT 

at 562°C (1,044°F) and enters the HRSG where additional heat is recovered. The FG exits the 

HRSG at 132°C (270°F) (stream 23) and is discharged through the plant stack. The steam raised 

in the HRSG is used to power an advanced commercially available steam turbine using a 

nominal 12.4 MPa/538°C/538°C (1800 psig/1000°F/1000°F) steam cycle.

Power Block

The same elevated pressure ASU is used in Case 2A and produces 4,343 tonnes/day (4,787 TPD) 

of 95 mol% oxygen and 14,595 tonnes/day (16,087 TPD) of nitrogen. There is no integration 

between the ASU and the CT.

Air Separation Unit

8.1.1

System assumptions for Case 2A are shown in 

Key System Assumptions

Exhibit 8-3.
Cost and Performance Baseline for Fossil Energy Plants

551

Exhibit 8-3 GEE IGCC Plant Study Configuration Matrix

Case 2A

Gasifier Pressure, MPa (psia) 5.6 (815)

O2:Coal Ratio, kg O2/kg dry coal 0.91

Carbon Conversion, % 98

Syngas HHV at Gasifier Outlet, kJ/Nm3 (Btu/scf) 8,655 (232)

Steam Cycle, MPa/°C/°C (psig/°F/°F) 12.4/534/534 (1800/994/994)

Condenser Pressure, mm Hg 

(in Hg) 51 (2.0)

CT 2x Advanced F Class

(232 MW output each)

Gasifier Technology GEE Quench Only

Oxidant 95 vol% Oxygen

Coal Illinois No. 6

Coal Slurry Solids Content, % 63

COS Hydrolysis Occurs in SGS

SGS Yes

H2S Separation Selexol 1st Stage

Sulfur Removal, % 99.8

Sulfur Recovery Claus Plant with Tail Gas Recycle to

Selexol/ Elemental Sulfur

Particulate Control Water Quench, Scrubber, and 

AGR Absorber

Mercury Control Carbon Bed

NOx Control MNQC (LNB) and N2 Dilution

CO2 Separation Selexol 2nd Stage

CO2 Capture 90.2%

CO2 Sequestration Off-site Saline Formation
Cost and Performance Baseline for Fossil Energy Plants

552

8.1.2

The plant produces a net output of 494 MW at a net plant efficiency of 29.7 percent (HHV 

basis). Overall performance for the entire plant is summarized in 

Case 2A Performance Results

Exhibit 8-4, which includes 

auxiliary power requirements. The ASU accounts for 60 percent of the auxiliary load between 

the main air compressor, the nitrogen compressor, the oxygen compressor, and ASU auxiliaries. 

The two-stage Selexol process and CO2 compression account for an additional 26 percent of the 

auxiliary power load. The BFW pumps and cooling water system (CWPs and cooling tower fan) 

comprise about 5 percent of the load, leaving 9 percent of the auxiliary load for all other systems.
Cost and Performance Baseline for Fossil Energy Plants

553

Exhibit 8-4 Case 2A Plant Performance Summary

POWER SUMMARY 

(Gross Power at Generator Terminals, kWe) Case 2 Case 2A

Gas Turbine Power 464,000 464,000

Sweet Gas Expander Power 6,500 6,600

Steam Turbine Power 263,500 213,600

TOTAL POWER, kWe 734,000 684,200

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 470 470

Coal Milling 2,270 2,270

Sour Water Recycle Slurry Pump 190 200

Slag Handling 1,160 1,160

Air Separation Unit Auxiliaries 1,000 1,000

Air Separation Unit Main Air Compressor 67,330 67,350

Oxygen Compressor 10,640 10,640

Nitrogen Compressors 35,640 35,630

CO2 Compressor 31,160 31,130

Boiler Feedwater Pumps 4,180 2,620

Condensate Pump 280 230

Quench Water Pump 540 1,270

Circulating Water Pump 4,620 4,810

Ground Water Pumps 530 550

Cooling Tower Fans 2,390 2,490

Scrubber Pumps 230 480

Acid Gas Removal 19,230 19,210

Gas Turbine Auxiliaries 1,000 1,000

Steam Turbine Auxiliaries 100 100

Claus Plant/TGTU Auxiliaries 250 250

Claus Plant TG Recycle Compressor 1,780 1,800

Miscellaneous Balance of Plant2 3,000 3,000

Transformer Losses 2,760 2,600

TOTAL AUXILIARIES, kWe 190,750 190,260

NET POWER, kWe 543,250 493,940

Net Plant Efficiency, % (HHV) 32.6 29.7

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,034 (10,458) 12,135 (11,502)

CONDENSER COOLING DUTY 106 kJ/hr (106 Btu/hr) 1,509 (1,430) 1,467 (1,390)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 220,904 (487,011) 220,888 (486,976)

Thermal Input, kWt1 1,665,074 1,664,954

Raw Water Withdrawal, m3/min (gpm) 22.0 (5,815) 23.2 (6,117)

Raw Water Consumption, m3/min (gpm) 17.9 (4,739) 18.9 (4,993)

1 - HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)

2 - Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Fossil Energy Plants

554

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in 

Section

Environmental Performance

2.4. A summary of the plant air emissions for Case 2A is presented in Exhibit 8-5.

Exhibit 8-5 Case 2A Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(tons/year) @ 

80% CF

kg/MWh

(lb/MWh)

SO2 0.001 (0.002) 39 (43) 0.008 (.018)

NOx 0.021 (0.049) 878 (968) 0.183 (.404)

Particulates 0.003 (0.0071) 128 (141) 0.027 (.059)

Hg 2.46E-7 (5.71E-7) 0.010 (0.011) 2.15E-6 (4.74E-6)

CO2 8.5 (19.8) 358,390 (395,058) 75 (165)

CO2

1 104 (228)

1 CO2 emissions based on net power instead of gross power

The low level of SO2 emissions is achieved by capture of the sulfur in the gas by the two-stage 

Selexol AGR process. As a result of achieving the 90 percent CO2 removal target, the sulfur 

compounds are removed to an extent that exceeds the environmental target in Section 2.4. The 

clean syngas exiting the AGR process has a sulfur concentration of approximately 5 ppmv. This 

results in a concentration in the FG of less than less than 1 ppmv. The H2S-rich regeneration gas 

from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail 

gas is hydrogenated to convert all sulfur species to H2S and then recycled back to the Selexol 

process, thereby eliminating the need for a tail gas treatment unit.

NOx emissions are limited by nitrogen dilution to 15 ppmvd (as NO2 @15 percent O2). 

Ammonia in the syngas is removed with process condensate prior to the low-temperature AGR 

process. This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of the 

syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Ninety five percent of mercury is captured from the syngas by an activated carbon bed.

Ninety 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 8-6. 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, ASU vent gas, and the captured CO2 product. The 

CO2 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 for Fossil Energy Plants

555

(Carbon in CO2 Product)/[(Carbon in the Coal)-(Carbon in Slag)] or

274,397/(310,421-6,208) * 100 or

90.2 percent

Exhibit 8-6 Case 2A Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 140,805 (310,421) Slag 2,816 (6,208)

Air (CO2) 540 (1,191) Stack Gas 13,957 (30,770)

ASU Vent 107 (237)

CO2 Product 124,464 (274,397)

Total 141,345 (311,612) Total 141,345 (311,612)

Exhibit 8-7 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur co-sequestered 

with the CO2 product, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be 

negligible.

Exhibit 8-7 Case 2A Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 5,536 (12,206) Elemental Sulfur 5,523 (12,177)

Stack Gas 3 (6)

CO2 Product 10 (23)

Total 5,536 (12,206) Total 5,536 (12,206)

Exhibit 8-8 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 syngas condensate, and that water is re-used as internal recycle. Raw water 

withdrawal is the difference between water demand and internal recycle. Some process water is 

returned to the source via cooling tower and sour water stripper blowdown. The difference 

between raw water withdrawal and process water discharge is raw water consumption, or the net 

impact on the water source.
Cost and Performance Baseline for Fossil Energy Plants

556

Exhibit 8-8 Case 2A 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)

Slag Handling 0.53 (139) 0.53 (139) 0.0 (0) 0.0 (0) 0.0 (0)

Slurry Water 1.5 (400) 1.5 (400) 0.0 (0) 0.0 (0) 0.0 (0)

Quench Water 6.7 (1,759) 1.9 (493) 4.8 (1,267) 0.0 (0) 4.8 (1,267)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.04 (10) -0.04 (-10)

Condenser 

Makeup

Gasifier Steam

Shift Steam

BFW Makeup

0.15 (40)

0.15 (40)

0.0 (0) 0.15 (40)

0.15 (40)

0.0 (0) 0.15 (40)

Cooling Tower 

Makeup

BFW 

Blowdown

SWS Blowdown

SWS Excess

18.8 (4,954) 0.54 (143)

0.15 (40)

0.39 (103)

18.2 (4,811)

-0.15 (-40)

-0.39 (-103)

4.2 (1,114) 14.0 (3,697)

Total 27.6 (7,292) 4.4 (1,174) 23.2 (6,117) 4.3 (1,124) 18.9 (4,993)

A plant heat and material balance is presented in 

Energy Balance

Exhibit 8-9 through Exhibit 8-11 with an

overall plant energy balance presented in tabular form in Exhibit 8-12. 
Cost and Performance Baseline for Fossil Energy Plants

557

Exhibit 8-9 Case 2A Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 2A

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 2A

GEE GASIFIER (QUENCH ONLY)

ASU AND GASIFICATION

DWG. NO.

BB-HMB-CS-2A-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

1 OF 3

Ambient Air

Four Stage Air

Compressor

Elevated

Pressure

ASU

Four Stage N2

Compressor

Four Stage O2

Compressor

ASU 

Vent

Water

Steam

Gross Plant Power: 684 MWe

Auxiliary Load: 190 MWe

Net Plant Power: 494 MWe

Net Plant Efficiency, HHV: 29.7%

Net Plant Heat Rate: 11,502 BTU/KWe

N2 to GT Combustor 1,741,060 W

59.0 T

14.7 P

13.0 H

392,015 W

90.0 T

125.0 P

11.5 H

392,015 W

241.2 T

940.0 P

40.8 H

To Claus Plant

6,906 W

90.0 T

125.0 P

11.5 H

100,545 W

64.7 T

16.4 P

15.3 H

1,083,228 W

90.0 T

56.4 P

14.2 H

156,811 W

50.0 T

182.0 P

2.9 H

5

1

3

2

Slurry Mix 

Tank

Milled Coal

Slag

486,976 W

59.0 T

14.7 P

200,050 W

295.0 T

840.0 P

240.4 H

53,430 W

2,400.0 T

815.0 P

677,288 W

385.0 T

384.0 P

87.2 H

687,025 W

159.8 T

840.0 P

2,952.8 H

100.0 T

189.5 P

18.0 H

6

677,288 W

199.0 T

384.0 P

39.8 H

N2 to GT Combustor

N2 Boost

Compressor 562,752 W

199.0 T

384.0 P

39.8 H

562,752 W

385.0 T

469.0 P

87.0 H

Black

Water

Flash

Tank

Knockout

Drum

Vent To Claus Unit

Raw Fuel Gas

CWS

CWR

Fines

Process Water

From Sour Water Stripper Syngas 

Scrubber

Slag Quench 

Section

Drag 

Conveyor

4

1,025,611 W

2,400.0 T

815.0 P

1,131.5 H

1,600,986 W

440.0 T

810.0 P

636.1 H

Syngas

Quench

1,905,234 W

550.0 T

815.0 P

761.0 H

8

9

10

Sour Water

7

HP BFW

Saturated Steam 

To HRSG HP 

Superheater

Radiant

Syngas

Cooler
Cost and Performance Baseline for Fossil Energy Plants

558

Exhibit 8-10 Case 2A Syngas Cleanup Heat and Mass Balance Schematic

Mercury 

Removal

Knock

Out 

Drum

Syngas

Preheater

Sour

Drum

Process Condensate to Syngas Scrubber

Makeup Water

Claus Plant

Tail 

Gas

Furnace

Catalytic

Reactor

Beds

Sulfur

Knock Out

From 

ASU

Syngas

Coolers

Sour

Stripper

1,600,986 W

440.0 T

810.0 P

636.1 H

1,244,961 W

94.6 T

745.0 P

15.6 H

38,921 W

119.0 T

23.7 P

199,419 W

383.2 T

460.0 P

480.3 H

12,177 W

36,693 W

450.0 T

12.3 P

467.0 H

3,043 W

246.5 T

65.0 P

500.1 H

6,906 W

90.0 T

125.0 P

11.5 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 2A

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 2A

GEE GASIFIER (QUENCH ONLY)

GAS CLEANUP SYSTEM

DWG. NO.

BB-HMB-CS-2A-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

2 OF 3

Sour Gas

Sour Water

Water

Steam

Gross Plant Power: 684 MWe

Auxiliary Load: 190 MWe

Net Plant Power: 494 MWe

Net Plant Efficiency, HHV: 29.7%

Net Plant Heat Rate: 11,502 BTU/KWe

19

13

20

CO2

Tailgas

30,265 W

120.0 T

10.6 P

112.7 H

1,217,174 W

94.9 T

750.0 P

15.9 H

8,907 W

114.5 T

10.6 P

40.3 H

3

27,786 W

100.0 T

799.5 P

Raw Syngas

15 199,419 W

94.6 T

745.0 P

83.8 H

Claus Oxygen

Preheater

6,906 W

450.0 T

124.5 P

91.9 H

18

Fuel Gas

Expander

Fuel Gas To GT

16

199,419 W

465.0 T

740.0 P

595.4 H

High

Temperature

Shift #1

Low

Temperature 

Shift #2

Shift Steam

12

11

COS Hydrolysis

Preheater

1,600,986 W

450.0 T

805.0 P

621.4 H

0 W

1,600,986 W

449.7 T

800.0 P

621.4 H

781.7 T

800.0 P

606.0 H

425.0 T

800.0 P

440.0 H

1,600,986 W

481.4 T

790.0 P

437.3 H

1,600,986 W

471.1 T

785.0 P

432.6 H

Two-Stage

Selexol

Clean Gas

CO2

Acid Gas

Multistage 

Intercooled CO2

Compressor

Interstage Knockout

CO2 Product

17

10

14

1,005,728 W

123.8 T

2,214.7 P

Tail Gas Recycle

Compressor

Hydrogenation 

and Tail Gas 

Cooling
Cost and Performance Baseline for Fossil Energy Plants

559

Exhibit 8-11 Case 2A Combined Cycle Power Generation Heat and Mass Balance Schematic

HRSG

HP

Turbine

IP

Turbine

Nitrogen Diluent

Intake

Ambient Air

Steam Seal 

Regulator

Ip Extraction Steam

To 250 PSIA Header

LP Process Header

Blowdown

Flash

To WWT

Gland

Steam

Condenser

Condensate to Gasification Island

HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP 

Turbine

Stack

Compressor Expander

Fuel Gas

Deaerator

IP BFW

Generator

Generator

Condensate

Pump

HP Pump

Steam Turbine

LP Pump

Advanced F-Class 

Gas Turbine

MP Flash Bottoms

LP Flash Tops

7,014,133 W

59.0 T

14.7 P

13.0 H

1,523,839 W

101.1 T

1.0 P

69.1 H

8,453,593 W

269.6 T

15.2 P

147.7 H

199,419 W

383.2 T

460.0 P

480.3 H

8,453,593 W

1,043.8 T

15.2 P

358.8 H From Gasifier

Island Preheating

To Claus

LP BFW

794,747 W

993.8 T

1,814.7 P

1,475.9 H

6,774 W

298.0 T

65.0 P

1,179.0 H

813,698 W

278.8 T

2,250.7 P

252.3 H

18,959 W

585.0 T

2,000.7 P

593.3 H

1,491,866 W

441.1 T

65.0 P

1,252.8 H

1,523,839 W

103.2 T

120.0 P

71.4 H

1,523,839 W

235.0 T

105.0 P

203.7 H

1,400 W

614.9 T

65.0 P

1,338.7 H

1,400 W

212.0 T

14.7 P

179.9 H

IP Pump NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE 2A

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE 2A

GEE GASIFIER (QUENCH ONLY)

POWER BLOCK SYSTEM

DWG. NO.

BB-HMB-CS-2A-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

Gross Plant Power: 684 MWe

Auxiliary Load: 190 MWe

Net Plant Power: 494 MWe

Net Plant Efficiency, HHV: 29.7%

21 Net Plant Heat Rate: 11,502 BTU/KWe

22

24

16

23

Flue Gas

HOT WELL

CONDENSER Make-up

19,812 W

59.0 T

14.7 P

27.1 H

9,025 W

660.6 T

501.4 P

1,334.6 H

9,761 W

614.9 T

65.0 P

1,338.7 H

33,608 W

851.8 T

280.0 P

1,448.6 H

798 W

993.8 T

1,814.7 P

1,475.9 H

1,337 W

504.7 T

65.0 P

1,284.4 H
Cost and Performance Baseline for Fossil Energy Plants

560

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

561

Exhibit 8-12 Case 2A Overall Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,994 (5,681) 5.0 (4.7) 5,999 (5,686)

ASU Air 23.9 (22.6) 24 (23)

GT Air 96.2 (91.2) 96 (91)

Water 87.1 (82.5) 87 (83)

Auxiliary Power 685 (649) 685 (649)

TOTAL 5,994 (5,681) 212.1 (201.1) 685 (649) 6,891 (6,531)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 1.6 (1.5) 2 (2)

Slag 92 (88) 37.8 (35.9) 130 (123)

Sulfur 51 (49) 0.6 (0.6) 52 (49)

CO2 -74.0 (-70.2) -74 (-70)

Cooling Tower 

Blowdown 31.3 (29.7) 31 (30)

HRSG Flue Gas 1,317 (1,248) 1,317 (1,248)

Condenser 1,452 (1,377) 1,452 (1,377)

Non-Condenser 

Cooling Tower Loads1 794 (753) 794 (753)

Process Losses2 723 (686) 723 (686)

Power 2,463 (2,335) 2,463 (2,335)

TOTAL 144 (136) 4,284 (4,061) 2,463 (2,335) 6,891 (6,531)

1 Includes ASU compressor intercoolers, CO2 compressor intercoolers, sour water stripper condenser, and syngas 

cooler (low level heat rejection)

2 Calculated by difference to close the energy balance

8.1.3

Major equipment items for the GEE quench only gasifier with CO2 capture are shown in the 

following tables. In general, the design conditions include a 10 percent contingency for flows 

and heat duties and a 21 percent contingency for heads on pumps and fans.

Case 2A – Major Equipment List
Cost and Performance Baseline for Fossil Energy Plants

562

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 45 tonne (50 ton) 2 1

9 Feeder Vibratory 181 tonne/hr (200 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 363 tonne/hr (400 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 181 tonne (200 ton) 2 0

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0) 2 0

14 As-Fired Coal Sampling 

System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 363 tonne/hr (400 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 363 tonne/hr (400 tph) 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 816 tonne (900 ton) 3 0
Cost and Performance Baseline for Fossil Energy Plants

563

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 82 tonne/h (90 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 245 tonne/h (270 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 490 tonne (540 ton) 1 0

4 Weigh Feeder Belt 118 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 118 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank 

with Agitator Field erected 299,883 liters (79,220 gal) 2 0

7 Slurry Water Pumps Centrifugal 833 lpm (220 gpm) 2 1

8 Trommel Screen Coarse 172 tonne/h (190 tph) 2 0

9 Rod Mill Discharge Tank with 

Agitator Field erected 392,285 liters (103,630 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,407 lpm (900 gpm) 2 2

11 Slurry Storage Tank with 

Agitator Field erected 1,176,894 liters (310,900 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,435 lpm (1,700 gpm) 2 2

13 Slurry Product Pumps Positive 

displacement 3,407 lpm (900 gpm) 2 2
Cost and Performance Baseline for Fossil Energy Plants

564

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 810,078 liters (214,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,397 lpm @ 91 m H2O

(1,690 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 464,932 kg/hr (1,025,000 lb/hr) 2 0

4 Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

6,587 lpm @ 27 m H2O

(1,740 gpm @ 90 ft H2O) 2 1

5 High Pressure 

Feedwater Pump No. 1

Barrel type, multi-stage, 

centrifugal

HP water: 3,520 lpm @ 1,859 m 

H2O (930 gpm @ 6,100 ft 

H2O)

2 1

6 High Pressure 

Feedwater Pump No. 2

Barrel type, multi-stage, 

centrifugal

IP water: 1,590 lpm @ 223 m 

H2O (420 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 Cylce Cooling 

Heat Exchangers Plate and frame 451 GJ/hr (428 MMBtu/hr) each 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 162,016 lpm @ 21 m H2O(42,800 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

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

5,867 lpm @ 18 m H2O

(1,550 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single 

suction

2,915 lpm @ 268 m H2O 

(770 gpm @ 880 ft H2O) 4 1

16 Filtered Water Pumps Stainless steel, single 

suction

3,899 lpm @ 49 m H2O

(1,030 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,862,423 liter (492,000 gal) 2 0

18 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 227 lpm (60 gpm) 2 0

19 Liquid Waste Treatment 

System 10 years, 24-hour storm 1 0
Cost and Performance Baseline for Fossil Energy Plants

565

ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW 

TEMPERATURE HEAT RECOVERY

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized slurry-feed, 

entrained bed

2,903 tonne/day, 5.6 MPa

(3,200 tpd, 814.96 psia) 2 0

2 Synthesis Gas Quench Pressurized quench 

tank 255,826 kg/hr (564,000 lb/hr) 2 0

3

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 475,365 kg/hr (1,048,000 lb/hr) 2 0

4 Raw Gas Coolers Shell and tube with 

condensate drain 399,615 kg/hr (881,000 lb/hr) 8 0

5 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator

304,360 kg/hr, 35°C, 5.2 MPa

(671,000 lb/hr, 95°F, 755 psia) 2 0

6 Synthesis Gas Reheater Shell and tube 49,895 kg/hr (110,000 lb/hr) 2 0

7 Flare Stack

Self-supporting, carbon 

steel, stainless steel top, 

pilot ignition

475,365 kg/hr (1,048,000 lb/hr) 

syngas

2 0

8 ASU Main Air 

Compressor Centrifugal, multi-stage 5,947 m3/min @ 1.3 MPa(210,000 scfm @ 190 psia) 2 0

9 Cold Box Vendor design 2,359 tonne/day (2,600 tpd) of 

95% purity oxygen 2 0

10 Oxygen Compressor Centrifugal, multi-stage

1,189 m3/min (42,000 scfm)

Suction - 0.9 MPa (130 psia)

Discharge - 6.5 MPa (940 psia)

2 0

11 Primary Nitrogen 

Compressor Centrifugal, multi-stage

3,794 m3/min (134,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 0

12 Secondary Nitrogen 

Compressor Centrifugal, single-stage

538 m3/min (19,000 scfm)

Suction - 1.2 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 0

13 Syngas Dilution Nitrogen 

Boost Compressor Centrifugal, single-stage

1,982 m3/min (70,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 psia)

2 0
Cost and Performance Baseline for Fossil Energy Plants

566

ACCOUNT 5 SYNGAS CLEANUP

ACCOUNT 5B CO2 COMPRESSION

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon 

bed

303,453 kg/hr (669,000 lb/hr) 

35°C (95°F) 

5.2 MPa (750 psia)

2 0

2 Sulfur Plant Claus type 146 tonne/day (161 tpd) 1 0

3 Water Gas Shift Reactors Fixed bed, 

catalytic

399,615 kg/hr (881,000 lb/hr) 

232°C (450°F) 

5.5 MPa (800 psia)

4 0

4 Shift Reactor Heat Recovery 

Exchangers Shell and Tube

Exchanger 1: 154 GJ/hr (146 

MMBtu/hr) 

Exchanger 2: 4 GJ/hr (4 

MMBtu/hr) 

4 0

5 Acid Gas Removal Plant Two-stage 

Selexol

310,711 kg/hr (685,000 lb/hr) 

35°C (95°F) 

5.1 MPa (745 psia)

2 0

6 Hydrogenation Reactor Fixed bed, 

catalytic

18,308 kg/hr (40,363 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

1 0

7 Tail Gas Recycle 

Compressor Centrifugal 13,878 kg/hr (30,597 lb/hr) 1 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CO2 

Compressor

Integrally geared, 

multi-stage centrifugal

1,130 m3/min @ 15.3 MPa 

(39,900 scfm @ 2,215 psia) 4 1

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gas Turbine Advanced F class 230 MW 2 0

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase 2 0

3 Syngas Expansion 

Turbine/Generator Turbo Expander

49,759 kg/h (109,700 lb/h)

5.1 MPa (740 psia) Inlet

3.2 MPa (460 psia) Outlet

2 0
Cost and Performance Baseline for Fossil Energy Plants

567

ACCOUNT 7 HRSG, DUCTING AND STACK

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS 

liner

76 m (250 ft) high x

8.5 m (28 ft) diameter 1 0

2 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator

Main steam - 198,270 kg/hr, 12.4 

MPa/534°C (437,111 lb/hr, 

1,800 psig/994°F)

 Reheat steam - 265,278 kg/hr, 

3.1 MPa/534°C (584,838 lb/hr, 

452 psig/994°F)

2 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

225 MW 

12.4 MPa/534°C/534°C 

(1800 psig/ 994°F/994°F)

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitiation

250 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase 1 0

3 Steam Bypass One per HRSG 50% steam flow @ design 

steam conditions 2 0

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,593 GJ/hr (1,510 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 11°C 

(20°F)

1 0

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water 

Pumps Vertical, wet pit 484,533 lpm @ 30 m(128,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

/ 2690 GJ/hr (2550 MMBtu/hr) 

heat duty

1 0
Cost and Performance Baseline for Fossil Energy Plants

568

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type Design Condition Operating 

Qty. Spares

1 Slag Quench Tank Water bath 253,623 liters (67,000 gal) 2 0

2 Slag Crusher Roll 14 tonne/hr (15 tph) 2 0

3 Slag Depressurizer Lock Hopper 14 tonne/hr (15 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 151,416 liters (40,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 68,137 liters (18,000 gal) 2

6 Slag Conveyor Drag chain 14 tonne/hr (15 tph) 2 0

7 Slag Separation Screen Vibrating 14 tonne/hr (15 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 14 tonne/hr (15 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 215,768 liters (57,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal 

centrifugal

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 68,137 liters (18,000 gal) 2 0

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H2O

(60 gpm @ 1,850 ft H2O) 2 2

13 Slag Storage Bin Vertical, field 

erected 998 tonne (1,100 tons) 2 0

14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 1 0
Cost and Performance Baseline for Fossil Energy Plants

569

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CTG Step-up 

Transformer Oil-filled 24 kV/345 kV, 260 MVA, 

3-ph, 60 Hz 2 0

2 STG Step-up 

Transformer Oil-filled 24 kV/345 kV, 250 MVA, 3-ph, 60 Hz 1 0

3

High Voltage 

Auxiliary 

Transformer

Oil-filled 345 kV/13.8 kV, 80 MVA, 

3-ph, 60 Hz 2 0

4

Medium Voltage 

Auxiliary 

Transformer

Oil-filled 24 kV/4.16 kV, 48 MVA, 

3-ph, 60 Hz 1 1

5 Low Voltage 

Transformer Dry ventilated 4.16 kV/480 V, 7 MVA, 3-ph, 60 Hz 1 1

6

CTG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, 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

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 for Fossil Energy Plants

570

8.1.4

The cost estimating methodology was described previously in Section 

Case 2A – Cost Estimating

2.7. Exhibit 8-13 shows 

the TPC summary organized by cost account and Exhibit 8-14 shows a more detailed breakdown 

of the capital costs. Exhibit 8-15 shows the initial and annual O&M costs.

The estimated TOC of the GEE gasifier with CO2 capture in quench-only configuration is 

$3,375/kW. Process contingency represents 3.4 percent of the TOC and project contingency 

represents 11.0 percent. The COE, including CO2 TS&M costs of 5.8 mills/kWh, is 108.5

mills/kWh. For comparison, the TOC and COE for Case 2, GEE in radiant-only configuration 

with CO2 capture are $3,334/kW and 105.7 mills/kWh.
Cost and Performance Baseline for Fossil Energy Plants

571

Exhibit 8-13 Case 2A Total Plant Cost Summary

Case: Case 2A - GEE Quench 495 MWnet IGCC w/ CO2

Plant Size: 493.9 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 $14,279 $2,654 $11,074 $0 $0 $28,007 $2,542 $0 $6,110 $36,659 $74

 2 COAL & SORBENT PREP & FEED $21,755 $4,448 $17,256 $0 $0 $43,459 $3,959 $1,577 $9,799 $58,794 $119

 3 FEEDWATER & MISC. BOP SYSTEMS $8,849 $6,224 $9,449 $0 $0 $24,521 $2,324 $0 $6,359 $33,204 $67

 4 GASIFIER & ACCESSORIES

4.1 Quench Gasifier System $66,598 $0 $57,069 $0 $0 $123,667 $11,556 $16,201 $23,572 $174,996 $354

4.2 Syngas Scrubber Sys. w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $193,046 $0 w/equip. $0 $0 $193,046 $18,712 $0 $21,176 $232,934 $472

4.4-4.9 Other Gasification Equipment $7,097 $2,671 $2,230 $0 $0 $11,999 $1,125 $0 $2,892 $16,016 $32

SUBTOTAL 4 $266,741 $2,671 $59,299 $0 $0 $328,712 $31,392 $16,201 $47,640 $423,945 $858

 5A GAS CLEANUP & PIPING $97,698 $3,331 $82,513 $0 $0 $183,542 $17,795 $27,526 $45,888 $274,751 $556

5B CO2 COMPRESSION $18,242 $0 $11,182 $0 $0 $29,424 $2,834 $0 $6,452 $38,709 $78

 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 $262

6.2-6.9 Combustion Turbine Other $5,547 $887 $1,748 $0 $0 $8,182 $775 $0 $1,650 $10,607 $21

SUBTOTAL 6 $97,573 $887 $8,331 $0 $0 $106,791 $10,123 $9,861 $13,432 $140,206 $284

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,631 $0 $4,782 $0 $0 $38,413 $3,652 $0 $4,206 $46,271 $94

7.2-7.9 SCR System, Ductwork and Stack $3,375 $2,406 $3,152 $0 $0 $8,933 $828 $0 $1,588 $11,350 $23

SUBTOTAL 7 $37,006 $2,406 $7,934 $0 $0 $47,346 $4,480 $0 $5,795 $57,621 $117

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $24,314 $0 $4,162 $0 $0 $28,476 $2,732 $0 $3,121 $34,329 $69

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $8,443 $830 $5,626 $0 $0 $14,898 $1,367 $0 $3,064 $19,330 $39

SUBTOTAL 8 $32,756 $830 $9,788 $0 $0 $43,374 $4,099 $0 $6,185 $53,659 $109

 9 COOLING WATER SYSTEM $10,625 $10,049 $8,616 $0 $0 $29,290 $2,720 $0 $6,524 $38,535 $78

10 ASH/SPENT SORBENT HANDLING SYS $14,733 $8,238 $14,937 $0 $0 $37,909 $3,652 $0 $4,476 $46,037 $93

11 ACCESSORY ELECTRIC PLANT $31,380 $12,503 $24,392 $0 $0 $68,275 $5,874 $0 $14,086 $88,234 $179

12 INSTRUMENTATION & CONTROL $10,977 $2,019 $7,072 $0 $0 $20,068 $1,819 $1,003 $3,814 $26,704 $54

13 IMPROVEMENTS TO SITE $3,371 $1,987 $8,317 $0 $0 $13,675 $1,350 $0 $4,508 $19,533 $40

14 BUILDINGS & STRUCTURES $0 $6,539 $7,369 $0 $0 $13,909 $1,265 $0 $2,492 $17,666 $36

 

TOTAL COST $665,985 $64,787 $287,529 $0 $0 $1,018,301 $96,229 $56,168 $183,558 $1,354,257 $2,742
Cost and Performance Baseline for Fossil Energy Plants

572

Exhibit 8-14 Case 2A Total Plant Cost Details

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 $3,750 $0 $1,832 $0 $0 $5,582 $500 $0 $1,216 $7,299 $15

1.2 Coal Stackout & Reclaim $4,846 $0 $1,175 $0 $0 $6,020 $528 $0 $1,310 $7,858 $16

1.3 Coal Conveyors & Yd Crush $4,505 $0 $1,162 $0 $0 $5,668 $498 $0 $1,233 $7,398 $15

1.4 Other Coal Handling $1,179 $0 $269 $0 $0 $1,448 $127 $0 $315 $1,889 $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 $2,654 $6,635 $0 $0 $9,289 $890 $0 $2,036 $12,215 $25

SUBTOTAL 1. $14,279 $2,654 $11,074 $0 $0 $28,007 $2,542 $0 $6,110 $36,659 $74

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying w/2.3 $0 w/2.3 $0 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,602 $383 $251 $0 $0 $2,236 $191 $0 $485 $2,913 $6

2.3 Slurry Prep & Feed $19,273 $0 $12,273 $0 $0 $31,546 $2,874 $1,577 $7,199 $43,196 $87

2.4 Misc.Coal Prep & Feed $881 $641 $1,922 $0 $0 $3,443 $316 $0 $752 $4,512 $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 $3,423 $2,811 $0 $0 $6,234 $577 $0 $1,362 $8,174 $17

SUBTOTAL 2. $21,755 $4,448 $17,256 $0 $0 $43,459 $3,959 $1,577 $9,799 $58,794 $119

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $1,916 $3,291 $1,737 $0 $0 $6,944 $643 $0 $1,517 $9,105 $18

3.2 Water Makeup & Pretreating $744 $78 $416 $0 $0 $1,237 $118 $0 $406 $1,761 $4

3.3 Other Feedwater Subsystems $1,048 $354 $319 $0 $0 $1,722 $155 $0 $375 $2,252 $5

3.4 Service Water Systems $426 $876 $3,042 $0 $0 $4,343 $424 $0 $1,430 $6,197 $13

3.5 Other Boiler Plant Systems $2,284 $885 $2,193 $0 $0 $5,362 $509 $0 $1,174 $7,045 $14

3.6 FO Supply Sys & Nat Gas $315 $596 $556 $0 $0 $1,467 $141 $0 $322 $1,930 $4

3.7 Waste Treatment Equipment $1,040 $0 $634 $0 $0 $1,674 $163 $0 $551 $2,388 $5

3.8 Misc. Power Plant Equipment $1,076 $144 $552 $0 $0 $1,772 $171 $0 $583 $2,527 $5

SUBTOTAL 3. $8,849 $6,224 $9,449 $0 $0 $24,521 $2,324 $0 $6,359 $33,204 $67

 4 GASIFIER & ACCESSORIES

4.1 Quench Gasifier System $66,598 $0 $57,069 $0 $0 $123,667 $11,556 $16,201 $23,572 $174,996 $354

4.2 Syngas Scrubber Sys. w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $193,046 $0 w/equip. $0 $0 $193,046 $18,712 $0 $21,176 $232,934 $472

4.4 Low Temperature Cooling $7,097 $0 $0 $0 $0 $7,097 $671 $0 $1,554 $9,321 $19

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $2,671 $2,230 $0 $0 $4,902 $454 $0 $1,339 $6,695 $14

SUBTOTAL 4. $266,741 $2,671 $59,299 $0 $0 $328,712 $31,392 $16,201 $47,640 $423,945 $858
Cost and Performance Baseline for Fossil Energy Plants

573

Exhibit 8-14 Case 2A Total Plant Cost Details (Continued)

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 $74,127 $0 $62,899 $0 $0 $137,026 $13,252 $27,405 $35,537 $213,219 $432

5A.2 Elemental Sulfur Plant $10,328 $2,058 $13,325 $0 $0 $25,712 $2,498 $0 $5,642 $33,851 $69

5A.3 Mercury Removal $1,372 $0 $1,044 $0 $0 $2,417 $233 $121 $554 $3,325 $7

5A.4 Shift Reactors $10,045 $0 $4,044 $0 $0 $14,089 $1,351 $0 $3,088 $18,527 $38

5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Blowback Gas Systems $1,826 $0 $346 $0 $0 $2,172 $265 $0 $487 $2,924 $6

5A.7 Fuel Gas Piping $0 $632 $443 $0 $0 $1,075 $100 $0 $235 $1,410 $3

5A.9 HGCU Foundations $0 $640 $413 $0 $0 $1,053 $97 $0 $345 $1,495 $3

SUBTOTAL 5A. $97,698 $3,331 $82,513 $0 $0 $183,542 $17,795 $27,526 $45,888 $274,751 $556

5B CO2 COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $18,242 $0 $11,182 $0 $0 $29,424 $2,834 $0 $6,452 $38,709 $78

SUBTOTAL 5B. $18,242 $0 $11,182 $0 $0 $29,424 $2,834 $0 $6,452 $38,709 $78

 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 $262

6.2 Syngas Expander $5,547 $0 $766 $0 $0 $6,313 $600 $0 $1,037 $7,951 $16

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $887 $982 $0 $0 $1,868 $175 $0 $613 $2,656 $5

SUBTOTAL 6. $97,573 $887 $8,331 $0 $0 $106,791 $10,123 $9,861 $13,432 $140,206 $284

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,631 $0 $4,782 $0 $0 $38,413 $3,652 $0 $4,206 $46,271 $94

7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $1,730 $1,234 $0 $0 $2,964 $260 $0 $645 $3,869 $8

7.4 Stack $3,375 $0 $1,268 $0 $0 $4,643 $445 $0 $509 $5,597 $11

7.9 HRSG, Duct & Stack Foundations $0 $676 $649 $0 $0 $1,326 $123 $0 $435 $1,884 $4

SUBTOTAL 7. $37,006 $2,406 $7,934 $0 $0 $47,346 $4,480 $0 $5,795 $57,621 $117

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $24,314 $0 $4,162 $0 $0 $28,476 $2,732 $0 $3,121 $34,329 $69

8.2 Turbine Plant Auxiliaries $171 $0 $393 $0 $0 $564 $55 $0 $62 $681 $1

8.3 Condenser & Auxiliaries $4,853 $0 $1,425 $0 $0 $6,277 $600 $0 $688 $7,565 $15

8.4 Steam Piping $3,419 $0 $2,405 $0 $0 $5,825 $500 $0 $1,581 $7,906 $16

8.9 TG Foundations $0 $830 $1,403 $0 $0 $2,233 $212 $0 $733 $3,178 $6

SUBTOTAL 8. $32,756 $830 $9,788 $0 $0 $43,374 $4,099 $0 $6,185 $53,659 $109
Cost and Performance Baseline for Fossil Energy Plants

574

Exhibit 8-14 Case 2A Total Plant Cost Details (Continued)

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

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $7,359 $0 $1,339 $0 $0 $8,697 $828 $0 $1,429 $10,954 $22

9.2 Circulating Water Pumps $1,919 $0 $141 $0 $0 $2,060 $174 $0 $335 $2,569 $5

9.3 Circ.Water System Auxiliaries $160 $0 $23 $0 $0 $183 $17 $0 $30 $230 $0

9.4 Circ.Water Piping $0 $6,671 $1,729 $0 $0 $8,400 $759 $0 $1,832 $10,991 $22

9.5 Make-up Water System $400 $0 $572 $0 $0 $972 $93 $0 $213 $1,278 $3

9.6 Component Cooling Water Sys $787 $942 $670 $0 $0 $2,399 $225 $0 $525 $3,149 $6

9.9 Circ.Water System Foundations $0 $2,437 $4,143 $0 $0 $6,579 $624 $0 $2,161 $9,364 $19

SUBTOTAL 9. $10,625 $10,049 $8,616 $0 $0 $29,290 $2,720 $0 $6,524 $38,535 $78

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $12,136 $6,692 $13,595 $0 $0 $32,423 $3,129 $0 $3,555 $39,107 $79

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 Slag Handling System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $589 $0 $641 $0 $0 $1,229 $119 $0 $202 $1,551 $3

10.7 Ash Transport & Feed Equipment $790 $0 $190 $0 $0 $980 $91 $0 $161 $1,232 $2

10.8 Misc. Ash Handling Equipment $1,219 $1,494 $446 $0 $0 $3,160 $301 $0 $519 $3,980 $8

10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $0 $117 $11 $0 $39 $167 $0

SUBTOTAL 10. $14,733 $8,238 $14,937 $0 $0 $37,909 $3,652 $0 $4,476 $46,037 $93

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $909 $0 $899 $0 $0 $1,809 $173 $0 $198 $2,179 $4

11.2 Station Service Equipment $4,668 $0 $421 $0 $0 $5,089 $469 $0 $556 $6,114 $12

11.3 Switchgear & Motor Control $8,630 $0 $1,570 $0 $0 $10,199 $946 $0 $1,672 $12,817 $26

11.4 Conduit & Cable Tray $0 $4,009 $13,225 $0 $0 $17,234 $1,667 $0 $4,725 $23,626 $48

11.5 Wire & Cable $0 $7,660 $5,033 $0 $0 $12,693 $922 $0 $3,404 $17,018 $34

11.6 Protective Equipment $0 $686 $2,496 $0 $0 $3,182 $311 $0 $524 $4,017 $8

11.7 Standby Equipment $226 $0 $221 $0 $0 $446 $43 $0 $73 $562 $1

11.8 Main Power Transformers $16,946 $0 $137 $0 $0 $17,084 $1,292 $0 $2,756 $21,132 $43

11.9 Electrical Foundations $0 $149 $391 $0 $0 $540 $52 $0 $177 $769 $2

SUBTOTAL 11. $31,380 $12,503 $24,392 $0 $0 $68,275 $5,874 $0 $14,086 $88,234 $179

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 $1,084 $0 $724 $0 $0 $1,807 $171 $90 $310 $2,379 $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 $561 $1

12.7 Computer & Accessories $5,780 $0 $185 $0 $0 $5,965 $548 $298 $681 $7,492 $15

12.8 Instrument Wiring & Tubing $0 $2,019 $4,128 $0 $0 $6,147 $521 $307 $1,744 $8,720 $18

12.9 Other I & C Equipment $3,864 $0 $1,876 $0 $0 $5,740 $540 $287 $985 $7,552 $15

SUBTOTAL 12. $10,977 $2,019 $7,072 $0 $0 $20,068 $1,819 $1,003 $3,814 $26,704 $54
Cost and Performance Baseline for Fossil Energy Plants

575

Exhibit 8-14 Case 2A Total Plant Cost Details (Continued)

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

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $106 $2,261 $0 $0 $2,366 $235 $0 $780 $3,382 $7

13.2 Site Improvements $0 $1,881 $2,500 $0 $0 $4,381 $432 $0 $1,444 $6,257 $13

13.3 Site Facilities $3,371 $0 $3,557 $0 $0 $6,928 $683 $0 $2,283 $9,894 $20

SUBTOTAL 13. $3,371 $1,987 $8,317 $0 $0 $13,675 $1,350 $0 $4,508 $19,533 $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 $2,096 $2,986 $0 $0 $5,081 $468 $0 $832 $6,381 $13

14.3 Administration Building $0 $862 $625 $0 $0 $1,487 $132 $0 $243 $1,863 $4

14.4 Circulation Water Pumphouse $0 $162 $86 $0 $0 $247 $22 $0 $40 $310 $1

14.5 Water Treatment Buildings $0 $622 $606 $0 $0 $1,228 $111 $0 $201 $1,540 $3

14.6 Machine Shop $0 $441 $302 $0 $0 $743 $66 $0 $121 $930 $2

14.7 Warehouse $0 $712 $460 $0 $0 $1,172 $104 $0 $191 $1,467 $3

14.8 Other Buildings & Structures $0 $427 $332 $0 $0 $759 $68 $0 $165 $992 $2

14.9 Waste Treating Building & Str. $0 $954 $1,823 $0 $0 $2,776 $259 $0 $607 $3,642 $7

SUBTOTAL 14. $0 $6,539 $7,369 $0 $0 $13,909 $1,265 $0 $2,492 $17,666 $36

TOTAL COST $665,985 $64,787 $287,529 $0 $0 $1,018,301 $96,229 $56,168 $183,558 $1,354,257 $2,742

Owner's Costs

Preproduction Costs

6 Months All Labor $12,023 $24

1 Month Maintenance Materials $2,632 $5

1 Month Non-fuel Consumables $400 $1

1 Month Waste Disposal $318 $1

25% of 1 Months Fuel Cost at 100% CF $1,697 $3

2% of TPC $27,085 $55

Total $44,154 $89

Inventory Capital

60 day supply of fuel and consumables at 100% CF $14,085 $29

0.5% of TPC (spare parts) $6,771 $14

Total $20,856 $42

Initial Cost for Catalyst and Chemicals $7,292 $15

Land $900 $2

Other Owner's Costs $203,139 $411

Financing Costs $36,565 $74

Total Overnight Costs (TOC) $1,667,163 $3,375

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $1,900,566 $3,848
Cost and Performance Baseline for Fossil Energy Plants

576

Exhibit 8-15 Case 2A Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 2A - GEE Quench 495 MWnet IGCC w/ CO2 Heat Rate-net (Btu/kWh): 11,502

MWe-net: 494

 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 $12.782

Maintenance Labor Cost $12,922,767 $26.163

Administrative & Support Labor $4,809,068 $9.736

Property Taxes and Insurance $27,085,142 $54.835

TOTAL FIXED OPERATING COSTS $51,130,484 $103.516

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $25,263,935 $0.00730

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water (/1000 gallons) 0 4,404 1.08 $0 $1,391,076 $0.00040

Chemicals

MU & WT Chem. (lbs) 0 26,239 0.17 $0 $1,326,020 $0.00038

Carbon (Mercury Removal) (lb) 79,195 108 1.05 $83,168 $33,267 $0.00001

COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000

Water Gas Shift Catalyst (ft3) 6,443 4.41 498.83 $3,213,847 $642,769 $0.00019

Selexol Solution (gal) 298,200 95 13.40 $3,995,355 $371,115 $0.00011

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip 2.01 131.27 $0 $77,204 $0.00002

Subtotal-Chemicals $7,292,370 $2,450,376 $0.00071

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.) 0 108 0.42 $0 $13,212 $0.00000

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 641 16.23 $0 $3,037,649 $0.00088

Subtotal Waste Disposal $0 $3,050,861 $0.00088

By-products & Emissions

Sulfur (ton) 0 146 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $7,292,370 $32,156,247 $0.00929

Fuel (ton) 0 5,844 38.18 $0 $65,156,652 $0.01882
Cost and Performance Baseline for Fossil Energy Plants

577

9.

Studies of PC plants with post combustion capture of CO2 for the 2009 NETL Bituminous and 

Low Rank Baselines Studies are based on a performance and cost estimate for an Econamine 

CO2 capture system provided by Fluor in 2005 [

SENSITIVITY TO MEA SYSTEM PERFORMANCE AND COST BITUMINOUS 

BASELINE CASE 12A

87]. A recent Fluor publication [88

The Fluor publication [

] indicates 

that Fluor has improved the Econamine system. According to Fluor, the improved system is able 

to achieve a reboiler steam requirement of 1,270 Btu/lbCO2 as compared to the 1,530 Btu/lbCO2

used in the baseline studies. Fluor also indicated concurrent reductions in auxiliary electrical 

power requirements and capital costs. 

88] indicates the improvements in performance and cost are enabled by 

an improved solvent formulation with an MEA concentration greater than 30 percent and 

improved corrosion inhibitors. Fluor states that the improved solvent results in increased 

reaction rates enabling less absorber packing and lower capital cost. Also, the higher solvent 

carrying capacity results in lower solvent circulation rates, lower steam requirements, and lower 

capital cost of solvent circulation equipment.

Cost and performance data on the improved system were unavailable directly from Fluor. Using

a commercial AGR software package, the CO2 removal process was simulated using higher 

MEA concentrations, but the confidence in the generated results and any associated equipment 

sizing or costing changes were not adequate for use in this analysis. Therefore, a sensitivity 

analysis was performed using published data from Fluor and best engineering judgment to 

estimate the impact of an improved MEA CO2 capture system on the performance and cost of a 

SC boiler firing bituminous coal with back-end CO2 capture.

9.1 BASIS FOR SENSITIVITY ANALYSIS

The sensitivity analysis was performed on Case 12 of the Bituminous Baseline Study. This case 

used a SC PC plant burning bituminous (Illinois #6) coal at ISO conditions. The sensitivity case 

was labeled Case 12A.

It was assumed, based on qualitative statements by Fluor, that the improved performance and 

reduced cost were achieved by increasing the MEA concentration from 30 wt% to 36 wt%. It 

was further assumed that Econamine reboiler steam requirements, power requirements and 

capital cost were inversely proportional to the increase in MEA concentration. The reboiler 

steam requirement and electrical auxiliary requirements were reduced by the ratio of 30/36 = 

0.83. The Econamine plant capital cost was scaled using two factors - the first based on the 

amount of CO2 captured to the 0.6 power and the second based on the ratio of the increased 

solvent concentration to the 0.7 power.

The Aspen model for Case 12 was modified for the reduced reboiler steam requirement and 

calculations were adjusted for the reduced auxiliary power requirement. Performance and cost 

estimates for Case 12A as compared to Case 12 are included in the following sections.

9.2 PERFORMANCE

The BFD, Stream Tables and Performance Summary for Case 12A are shown in Exhibit 9-1, 

Exhibit 9-2, and Exhibit 9-3. The Performance Summary from Case 12 is also included in 
Cost and Performance Baseline for Fossil Energy Plants

578

Exhibit 9-3 for comparison. The net plant efficiency for Case 12A is 29.8 percent compared to 

28.4 percent for Case 12.

The auxiliary power for Case 12A is 104 MW compared to 113 MW for Case 12. Gross output 

was reduced for Case 12A by 9 MW to maintain a 550 MW net output for both cases. The 

reduction in auxiliary power results primarily from reductions in the Econamine and CO2

compressor auxiliaries with minor reductions in most other auxiliary loads resulting from a 

slightly smaller gross plant size.
Cost and Performance Baseline for Fossil Energy Plants

579

Exhibit 9-1 Case 12A Block Flow Diagram, Supercritical Unit with CO2 Capture (MEA Sensitivity)
Cost and Performance Baseline for Fossil Energy Plants

580

Exhibit 9-2 Case 12A Stream Table, Supercritical Unit with CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 0.0000

CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 1.0000

N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 0.0000

O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 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 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 63,824 63,824 1,899 19,606 19,606 2,690 1,475 0 0 89,812 0 89,812 89,812 3,349

V-L Flowrate (kg/hr) 1,841,767 1,841,767 54,801 565,772 565,772 77,613 42,569 0 0 2,671,294 0 2,671,294 2,671,294 60,334

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 244,938 4,750 19,001 19,001 0 0 24,719

Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169 182 15

Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 0.10

Enthalpy (kJ/kg)A 30.23 34.36 34.36 30.23 40.78 40.78 30.23 --- --- 327.40 --- 308.96 322.83 ---

Density (kg/m3

) 1.2 1.2 1.2 1.2 1.3 1.3 1.2 --- --- 0.8 --- 0.8 0.8 ---

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857 --- --- 29.743 --- 29.743 29.743 ---

V-L Flowrate (lbmol/hr) 140,708 140,708 4,187 43,224 43,224 5,930 3,252 0 0 198,001 0 198,001 198,001 7,383

V-L Flowrate (lb/hr) 4,060,401 4,060,401 120,816 1,247,313 1,247,313 171,108 93,850 0 0 5,889,196 0 5,889,196 5,889,196 133,014

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 539,995 10,472 41,890 41,890 0 0 54,497

Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337 360 59

Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.4 15.0

Enthalpy (Btu/lb)A 13.0 14.8 14.8 13.0 17.5 17.5 13.0 --- --- 140.8 --- 132.8 138.8 ---

Density (lb/ft3) 0.076 0.078 0.078 0.076 0.081 0.081 0.076 --- --- 0.050 --- 0.049 0.052 ---

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Fossil Energy Plants

581

Exhibit 9-2 Case 12A Stream Table, Supercritical Unit with CO2 Capture (Continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 28

V-L Mole Fraction

Ar 0.0000 0.0128 0.0000 0.0081 0.0108 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0000 0.0005 0.0004 0.1351 0.0179 0.9961 0.9985 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 1.0000 0.0062 0.9996 0.1537 0.0383 0.0039 0.0015 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

N2 0.0000 0.7506 0.0000 0.6793 0.9013 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.2300 0.0000 0.0238 0.0316 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 12,734 913 236 97,848 73,741 11,940 11,911 35,621 35,621 120,750 98,499 98,499 53,856 53,856

V-L Flowrate (kg/hr) 229,411 26,510 4,260 2,821,044 2,077,415 524,270 523,755 641,731 641,731 2,175,344 1,774,495 1,774,495 970,240 970,240

Solids Flowrate (kg/hr) 0 0 38,244 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 15 181 58 58 32 21 35 291 151 593 354 593 38 39

Pressure (MPa, abs) 0.10 0.31 0.10 0.10 0.10 0.16 15.27 0.51 0.92 24.23 4.90 4.52 0.01 1.69

Enthalpy (kJ/kg)A -46.80 191.58 --- 301.42 93.86 19.49 -211.71 3,045.10 636.31 3,476.62 3,081.96 3,652.22 2,111.17 166.38

Density (kg/m3

) 1,003.1 2.4 --- 1.1 1.1 2.9 795.9 2.0 916.0 69.2 18.7 11.6 0.1 993.2

V-L Molecular Weight 18.015 29.029 --- 28.831 28.172 43.908 43.971 18.015 18.015 18.015 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 28,074 2,013 521 215,717 162,571 26,323 26,260 78,532 78,532 266,208 217,154 217,154 118,733 118,733

V-L Flowrate (lb/hr) 505,766 58,445 9,392 6,219,337 4,579,917 1,155,818 1,154,682 1,414,774 1,414,774 4,795,812 3,912,091 3,912,091 2,139,012 2,139,012

Solids Flowrate (lb/hr) 0 0 84,314 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 59 357 136 136 89 69 95 556 304 1,100 669 1,100 101 103

Pressure (psia) 14.7 45.0 14.9 14.9 14.7 23.5 2,214.5 73.5 133.6 3,514.7 710.8 655.8 1.0 245.0

Enthalpy (Btu/lb)A -20.1 82.4 --- 129.6 40.4 8.4 -91.0 1,309.2 273.6 1,494.7 1,325.0 1,570.2 907.6 71.5

Density (lb/ft3) 62.622 0.149 --- 0.067 0.070 0.184 49.685 0.123 57.184 4.319 1.165 0.722 0.004 62.004
Cost and Performance Baseline for Fossil Energy Plants

582

Exhibit 9-3 Case 12A Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Bituminous Baseline Case 12 12A

Steam Turbine Power 662,800 654,200

TOTAL (STEAM TURBINE) POWER, kWe 662,800 654,200

AUXILIARY LOAD SUMMARY, kWe

Coal Handling and Conveying 510 500

Pulverizers 3,850 3,670

Sorbent Handling & Reagent Preparation 1,250 1,190

Ash Handling 740 700

Primary Air Fans 1,800 1,720

Forced Draft Fans 2,300 2,190

Induced Draft Fans 11,120 10,610

SCR 70 60

Baghouse 100 90

Wet FGD 4,110 3,920

Econamine FG Plus Auxiliaries 20,600 16,400

CO2 Compression 44,890 42,840

Miscellaneous Balance of Plant2,3 2,000 2,000

Steam Turbine Auxiliaries 400 400

Condensate Pumps 560 610

Circulating Water Pumps 10,100 9,390

Ground Water Pumps 920 850

Cooling Tower Fans 5,230 4,860

Transformer Losses 2,290 2,240

TOTAL AUXILIARIES, kWe 112,840 104,240

NET POWER, kWe 549,960 549,960

Net Plant Efficiency (HHV) 28.4% 29.8%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 12,663 (12,002) 12,085 (11,455)

CONDENSER COOLING DUTY, 106 kJ/hr (106 Btu/hr) 1,737 (1,646) 1,893 (1,794)

CONSUMABLES

As-Received Coal Feed, kg/hr (lb/hr) 256,652 

(565,820)

244,938 

(539,995)

Limestone Sorbent Feed, kg/hr (lb/hr) 25,966 (57,245) 24,720 (54,497)

Thermal Input, kWt1 1,934,519 1,846,224

Raw Water Withdrawal, m3/min (gpm) 38.1 (10,071) 35.4 (9,350)

Raw Water Consumption, m3/min (gpm) 29.3 (7,733) 27.2 (7,177)

1. HHV of As-Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)

2. Boiler feed pumps are turbine driven

3. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Fossil Energy Plants

583

9.3 COST ESTIMATING

The cost estimating methodology was described in Section 2.7 of this report. Exhibit 9-4 shows 

the TPC summary organized by cost account and Exhibit 9-5 shows a more detailed breakdown 

of the capital costs including the TOC and TASC. Exhibit 9-6 shows the initial and annual 

O&M costs.

The TPC was estimated using a factored cost method with Case 12 as the reference. Account 

5B.1 was scaled based on CO2 captured to the 0.6 power and additionally reduced by 12 percent

as discussed previously to account for capital cost reductions resulting from the reduced solvent 

circulation rate.

The estimated TOC for Case 12A is $3,364/kW. This represents a reduction from Case 12 of 6

percent. Process contingency represents 2.6 percent of the TOC and project contingency 

represents 10.0 percent. The COE, including CO2 TS&M costs of 5.3 mills/kWh, is 100.8

mills/kWh. This COE is 5.5 percent less than the Baseline Case 12 COE of 106.6 mills/kWh.
Cost and Performance Baseline for Fossil Energy Plants

584

Exhibit 9-4 Case 12A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14

Project: Bituminous Baseline Study

Case: Case 12A - 1x550 MWnet Super-Critical PC w/ CO2 Capture (MEA Sensitivity)

Plant Size: 550.0 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 $19,514 $5,244 $11,671 $0 $0 $36,429 $3,268 $0 $5,955 $45,652 $83

 2 COAL & SORBENT PREP & FEED $13,252 $772 $3,366 $0 $0 $17,391 $1,524 $0 $2,837 $21,753 $40

 3 FEEDWATER & MISC. BOP SYSTEMS $52,950 $0 $24,940 $0 $0 $77,890 $7,138 $0 $13,939 $98,967 $180

 4 PC BOILER

4.1 PC Boiler & Accessories $189,629 $0 $106,401 $0 $0 $296,030 $28,810 $0 $32,484 $357,324 $650

4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4 $189,629 $0 $106,401 $0 $0 $296,030 $28,810 $0 $32,484 $357,324 $650

 5 FLUE GAS CLEANUP $97,431 $0 $33,251 $0 $0 $130,682 $12,508 $0 $14,319 $157,509 $286

 5B CO2 REMOVAL & COMPRESSION $204,675 $0 $62,416 $0 $0 $267,091 $25,537 $46,378 $67,801 $406,807 $740

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

7.2-7.9 HRSG Accessories, Ductwork and Stack $17,413 $958 $11,797 $0 $0 $30,168 $2,764 $0 $4,326 $37,258 $68

SUBTOTAL 7 $17,413 $958 $11,797 $0 $0 $30,168 $2,764 $0 $4,326 $37,258 $68

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $56,268 $0 $7,467 $0 $0 $63,735 $6,108 $0 $6,984 $76,827 $140

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $26,997 $1,189 $15,089 $0 $0 $43,276 $3,779 $0 $6,723 $53,778 $98

SUBTOTAL 8 $83,265 $1,189 $22,556 $0 $0 $107,010 $9,887 $0 $13,707 $130,605 $237

 9 COOLING WATER SYSTEM $19,662 $9,537 $17,647 $0 $0 $46,846 $4,410 $0 $6,916 $58,171 $106

10 ASH/SPENT SORBENT HANDLING SYS $5,135 $163 $6,865 $0 $0 $12,163 $1,169 $0 $1,372 $14,705 $27

11 ACCESSORY ELECTRIC PLANT $24,767 $10,309 $29,247 $0 $0 $64,322 $5,686 $0 $8,780 $78,788 $143

12 INSTRUMENTATION & CONTROL $9,915 $0 $10,054 $0 $0 $19,969 $1,811 $998 $2,798 $25,575 $47

13 IMPROVEMENTS TO SITE $3,281 $1,886 $6,612 $0 $0 $11,779 $1,162 $0 $2,588 $15,529 $28

14 BUILDINGS & STRUCTURES $0 $24,540 $23,290 $0 $0 $47,830 $4,315 $0 $7,822 $59,967 $109

 

TOTAL COST $740,888 $54,598 $370,114 $0 $0 $1,165,600 $109,989 $47,376 $185,644 $1,508,610 $2,743

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline for Fossil Energy Plants

585

Exhibit 9-5 Case 12A Total Plant Cost Details

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 $3,998 $0 $1,826 $0 $0 $5,823 $520 $0 $952 $7,295 $13

1.2 Coal Stackout & Reclaim $5,166 $0 $1,171 $0 $0 $6,337 $554 $0 $1,034 $7,925 $14

1.3 Coal Conveyors $4,803 $0 $1,158 $0 $0 $5,961 $522 $0 $973 $7,456 $14

1.4 Other Coal Handling $1,257 $0 $268 $0 $0 $1,525 $133 $0 $249 $1,907 $3

1.5 Sorbent Receive & Unload $163 $0 $49 $0 $0 $212 $19 $0 $35 $265 $0

1.6 Sorbent Stackout & Reclaim $2,625 $0 $481 $0 $0 $3,106 $270 $0 $506 $3,883 $7

1.7 Sorbent Conveyors $937 $203 $230 $0 $0 $1,369 $118 $0 $223 $1,710 $3

1.8 Other Sorbent Handling $566 $133 $297 $0 $0 $995 $88 $0 $162 $1,245 $2

1.9 Coal & Sorbent Hnd.Foundations $0 $4,909 $6,192 $0 $0 $11,101 $1,043 $0 $1,822 $13,966 $25

SUBTOTAL 1. $19,514 $5,244 $11,671 $0 $0 $36,429 $3,268 $0 $5,955 $45,652 $83

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $2,315 $0 $451 $0 $0 $2,766 $241 $0 $451 $3,458 $6

2.2 Coal Conveyor to Storage $5,927 $0 $1,294 $0 $0 $7,221 $631 $0 $1,178 $9,030 $16

2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.5 Sorbent Prep Equipment $4,471 $193 $929 $0 $0 $5,593 $487 $0 $912 $6,991 $13

2.6 Sorbent Storage & Feed $539 $0 $206 $0 $0 $745 $66 $0 $122 $933 $2

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 $579 $486 $0 $0 $1,066 $99 $0 $175 $1,339 $2

SUBTOTAL 2. $13,252 $772 $3,366 $0 $0 $17,391 $1,524 $0 $2,837 $21,753 $40

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 FeedwaterSystem $22,174 $0 $7,163 $0 $0 $29,337 $2,564 $0 $4,785 $36,686 $67

3.2 Water Makeup & Pretreating $6,639 $0 $2,137 $0 $0 $8,776 $830 $0 $1,921 $11,526 $21

3.3 Other Feedwater Subsystems $6,789 $0 $2,869 $0 $0 $9,658 $865 $0 $1,578 $12,101 $22

3.4 Service Water Systems $1,301 $0 $708 $0 $0 $2,009 $189 $0 $440 $2,638 $5

3.5 Other Boiler Plant Systems $8,379 $0 $8,272 $0 $0 $16,651 $1,582 $0 $2,735 $20,968 $38

3.6 FO Supply Sys & Nat Gas $273 $0 $341 $0 $0 $613 $58 $0 $101 $772 $1

3.7 Waste Treatment Equipment $4,501 $0 $2,566 $0 $0 $7,066 $688 $0 $1,551 $9,305 $17

3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,894 $0 $884 $0 $0 $3,779 $363 $0 $828 $4,970 $9

SUBTOTAL 3. $52,950 $0 $24,940 $0 $0 $77,890 $7,138 $0 $13,939 $98,967 $180

 4 PC BOILER

4.1 PC Boiler & Accessories $189,629 $0 $106,401 $0 $0 $296,030 $28,810 $0 $32,484 $357,324 $650

4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4. $189,629 $0 $106,401 $0 $0 $296,030 $28,810 $0 $32,484 $357,324 $650
Cost and Performance Baseline for Fossil Energy Plants

586

Exhibit 9-5 Case 12A Total Plant Cost Details (Continued)

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

 5 FLUE GAS CLEANUP

5.1 Absorber Vessels & Accessories $67,660 $0 $14,566 $0 $0 $82,226 $7,839 $0 $9,006 $99,071 $180

5.2 Other FGD $3,531 $0 $4,001 $0 $0 $7,532 $731 $0 $826 $9,089 $17

5.3 Bag House & Accessories $19,454 $0 $12,346 $0 $0 $31,801 $3,065 $0 $3,487 $38,352 $70

5.4 Other Particulate Removal Materials $1,317 $0 $1,409 $0 $0 $2,725 $264 $0 $299 $3,289 $6

5.5 Gypsum Dewatering System $5,469 $0 $929 $0 $0 $6,398 $609 $0 $701 $7,708 $14

5.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5. $97,431 $0 $33,251 $0 $0 $130,682 $12,508 $0 $14,319 $157,509 $286

 5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $177,879 $0 $54,009 $0 $0 $231,888 $22,171 $46,378 $60,087 $360,524 $656

5B.2 CO2 Compression & Drying $26,796 $0 $8,406 $0 $0 $35,202 $3,367 $0 $7,714 $46,283 $84

SUBTOTAL 5B. $204,675 $0 $62,416 $0 $0 $267,091 $25,537 $46,378 $67,801 $406,807 $740

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $9,063 $0 $5,823 $0 $0 $14,886 $1,298 $0 $2,428 $18,611 $34

7.4 Stack $8,350 $0 $4,886 $0 $0 $13,236 $1,274 $0 $1,451 $15,962 $29

7.9 Duct & Stack Foundations $0 $958 $1,088 $0 $0 $2,046 $192 $0 $448 $2,685 $5

SUBTOTAL 7. $17,413 $958 $11,797 $0 $0 $30,168 $2,764 $0 $4,326 $37,258 $68

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $56,268 $0 $7,467 $0 $0 $63,735 $6,108 $0 $6,984 $76,827 $140

8.2 Turbine Plant Auxiliaries $379 $0 $812 $0 $0 $1,191 $116 $0 $131 $1,438 $3

8.3 Condenser & Auxiliaries $5,837 $0 $2,151 $0 $0 $7,988 $765 $0 $875 $9,629 $18

8.4 Steam Piping $20,781 $0 $10,247 $0 $0 $31,028 $2,607 $0 $5,045 $38,680 $70

8.9 TG Foundations $0 $1,189 $1,879 $0 $0 $3,069 $290 $0 $672 $4,031 $7

SUBTOTAL 8. $83,265 $1,189 $22,556 $0 $0 $107,010 $9,887 $0 $13,707 $130,605 $237
Cost and Performance Baseline for Fossil Energy Plants

587

Exhibit 9-5 Case 12A Total Plant Cost Details (Continued)

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

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $14,675 $0 $4,570 $0 $0 $19,245 $1,840 $0 $2,109 $23,194 $42

9.2 Circulating Water Pumps $3,023 $0 $233 $0 $0 $3,255 $275 $0 $353 $3,884 $7

9.3 Circ.Water System Auxiliaries $754 $0 $100 $0 $0 $854 $81 $0 $94 $1,029 $2

9.4 Circ.Water Piping $0 $5,974 $5,789 $0 $0 $11,763 $1,101 $0 $1,930 $14,794 $27

9.5 Make-up Water System $613 $0 $819 $0 $0 $1,433 $137 $0 $235 $1,805 $3

9.6 Component Cooling Water Sys $597 $0 $475 $0 $0 $1,072 $102 $0 $176 $1,350 $2

9.9 Circ.Water System Foundations& Structures $0 $3,563 $5,661 $0 $0 $9,224 $873 $0 $2,019 $12,116 $22

SUBTOTAL 9. $19,662 $9,537 $17,647 $0 $0 $46,846 $4,410 $0 $6,916 $58,171 $106

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $687 $0 $2,117 $0 $0 $2,804 $275 $0 $308 $3,387 $6

10.7 Ash Transport & Feed Equipment $4,448 $0 $4,556 $0 $0 $9,004 $861 $0 $986 $10,851 $20

10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.9 Ash/Spent Sorbent Foundation $0 $163 $192 $0 $0 $356 $33 $0 $78 $467 $1

SUBTOTAL 10. $5,135 $163 $6,865 $0 $0 $12,163 $1,169 $0 $1,372 $14,705 $27

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $1,714 $0 $278 $0 $0 $1,993 $185 $0 $163 $2,341 $4

11.2 Station Service Equipment $4,791 $0 $1,574 $0 $0 $6,366 $595 $0 $522 $7,483 $14

11.3 Switchgear & Motor Control $5,508 $0 $936 $0 $0 $6,445 $597 $0 $704 $7,746 $14

11.4 Conduit & Cable Tray $0 $3,454 $11,941 $0 $0 $15,395 $1,490 $0 $2,533 $19,418 $35

11.5 Wire & Cable $0 $6,517 $12,580 $0 $0 $19,097 $1,609 $0 $3,106 $23,811 $43

11.6 Protective Equipment $261 $0 $888 $0 $0 $1,149 $112 $0 $126 $1,388 $3

11.7 Standby Equipment $1,352 $0 $31 $0 $0 $1,383 $127 $0 $151 $1,660 $3

11.8 Main Power Transformers $11,140 $0 $187 $0 $0 $11,327 $859 $0 $1,219 $13,405 $24

11.9 Electrical Foundations $0 $339 $830 $0 $0 $1,168 $112 $0 $256 $1,536 $3

SUBTOTAL 11. $24,767 $10,309 $29,247 $0 $0 $64,322 $5,686 $0 $8,780 $78,788 $143

12 INSTRUMENTATION & CONTROL

12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0

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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $511 $0 $306 $0 $0 $816 $77 $41 $140 $1,074 $2

12.7 Distributed Control System Equipment $5,154 $0 $901 $0 $0 $6,055 $561 $303 $692 $7,611 $14

12.8 Instrument Wiring & Tubing $2,794 $0 $5,542 $0 $0 $8,336 $710 $417 $1,420 $10,883 $20

12.9 Other I & C Equipment $1,456 $0 $3,305 $0 $0 $4,761 $462 $238 $546 $6,007 $11

SUBTOTAL 12. $9,915 $0 $10,054 $0 $0 $19,969 $1,811 $998 $2,798 $25,575 $47
Cost and Performance Baseline for Fossil Energy Plants

588

Exhibit 9-5 Case 12A Total Plant Cost Details (Continued)

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

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $55 $1,103 $0 $0 $1,158 $115 $0 $255 $1,528 $3

13.2 Site Improvements $0 $1,831 $2,274 $0 $0 $4,105 $405 $0 $902 $5,411 $10

13.3 Site Facilities $3,281 $0 $3,235 $0 $0 $6,516 $642 $0 $1,432 $8,590 $16

SUBTOTAL 13. $3,281 $1,886 $6,612 $0 $0 $11,779 $1,162 $0 $2,588 $15,529 $28

14 BUILDINGS & STRUCTURES

14.1 Boiler Building $0 $8,791 $7,731 $0 $0 $16,522 $1,485 $0 $2,701 $20,708 $38

14.2 Turbine Building $0 $12,699 $11,836 $0 $0 $24,535 $2,211 $0 $4,012 $30,758 $56

14.3 Administration Building $0 $637 $673 $0 $0 $1,310 $119 $0 $214 $1,644 $3

14.4 Circulation Water Pumphouse $0 $168 $134 $0 $0 $302 $27 $0 $49 $378 $1

14.5 Water Treatment Buildings $0 $842 $768 $0 $0 $1,610 $145 $0 $263 $2,018 $4

14.6 Machine Shop $0 $426 $286 $0 $0 $712 $63 $0 $116 $892 $2

14.7 Warehouse $0 $289 $290 $0 $0 $578 $52 $0 $95 $725 $1

14.8 Other Buildings & Structures $0 $236 $201 $0 $0 $437 $39 $0 $71 $547 $1

14.9 Waste Treating Building & Str. $0 $452 $1,372 $0 $0 $1,825 $173 $0 $300 $2,298 $4

SUBTOTAL 14. $0 $24,540 $23,290 $0 $0 $47,830 $4,315 $0 $7,822 $59,967 $109

TOTAL COST $740,888 $54,598 $370,114 $0 $0 $1,165,600 $109,989 $47,376 $185,644 $1,508,610 $2,743

BEC, Categories 1-12 $1,105,992

Owner's Costs

Preproduction Costs

6 Months All Labor $10,153 $18

1 Month Maintenance Materials $1,457 $3

1 Month Non-fuel Consumables $1,478 $3

1 Month Waste Disposal $309 $1

25% of 1 Months Fuel Cost at 100% CF $1,882 $3

2% of TPC $30,172 $55

Total $45,451 $83

Inventory Capital

60 day supply of fuel and consumables at 100% CF $18,151 $33

0.5% of TPC (spare parts) $7,543 $14

Total $25,694 $47

Initial Cost for Catalyst and Chemicals $2,383 $4

Land $900 $2

Other Owner's Costs $226,291 $411

Financing Costs $40,732 $74

Total Overnight Costs (TOC) $1,850,062 $3,364

TASC Multiplier (IOU, low risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,109,071 $3,835
Cost and Performance Baseline for Fossil Energy Plants

589

Exhibit 9-6 Case 12A Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 12A - 1x550 MWnet Super-Critical PC w/ CO2 Capture (MEA Sensitivity) Heat Rate-net (Btu/kWh): 11,455

MWe-net: 550

Capacity Factor (%): 85

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

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 2.0 2.0

 Operator 11.3 11.3

 Foreman 1.0 1.0

 Lab Tech's, etc. 2.0 2.0

 TOTAL-O.J.'s 16.3 16.3

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $6,444,907 $11.719

Maintenance Labor Cost $9,800,561 $17.820

Administrative & Support Labor $4,061,367 $7.385

Property Taxes and Insurance $30,172,197 $54.863

TOTAL FIXED OPERATING COSTS $50,479,031 $91.787

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $14,863,811 $0.00363

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

 Water(/1000 gallons) 0 6,801 1.08 $0 $2,282,387 $0.00056

 Chemicals

 MU & WT Chem.(lb) 0 32,922 0.17 $0 $1,767,714 $0.00043

 Limestone (ton) 0 654 21.63 $0 $4,389,274 $0.00107

 Carbon (Mercury Removal) (lb) 0 0 1.05 $0 $0 $0.00000

 MEA Solvent (ton) 981 1.39 2,249.89 $2,208,132 $971,338 $0.00024

 NaOH (tons) 69 6.93 433.68 $30,065 $932,782 $0.00023

 H2SO4 (tons) 66 6.62 138.78 $9,181 $284,854 $0.00007

 Corrosion Inhibitor 0 0 0.00 $135,751 $0 $0.00000

 Activated Carbon(lb) 0 1,662 1.05 $0 $541,593 $0.00013

 Ammonia (28% NH3) ton 0 97 129.80 $0 $3,904,140 $0.00095

Subtotal Chemicals $2,383,130 $12,791,695 $0.00312

 Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000

SCR Catalyst (m3) w/equip. 0.41 5,775.94 $0 $730,089 $0.00018

Emission Penalties 0 0 0.00 $0 $0 $0.00000

Subtotal Other $0 $730,089 $0.00018

 Waste Disposal

Fly Ash (ton) 0 502 16.23 $0 $2,524,978 $0.00062

Bottom Ash (ton) 0 125 16.23 $0 $628,224 $0.00015

 Subtotal-Waste Disposal $0 $3,153,202 $0.00077

 By-products & Emissions 

Gypsum (tons) 0 1,013 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $2,383,130 $33,821,185 $0.00826

 Fuel(ton) 0 6,480 38.18 $0 $76,766,172 $0.01875
Cost and Performance Baseline for Fossil Energy Plants

590

This page intentionally left blank
Cost and Performance Baseline for Fossil Energy Plants

591

10.

The initial issue of this report was published on May 15, 2007. Subsequent to the issue date, 

updates have been made to various report sections. These additions were made for clarification 

and aesthetic purposes and to correct an error made in determining the Econamine cooling water 

requirement in the PC and NGCC CO2 capture cases. The water balances and water 

consumption comparison exhibits were updated accordingly. In addition, the PC and NGCC 

energy balance tables contained errors, which have been corrected in this version of the report. 

None of the changes affect the conclusions in version 1 of the report.

REVISION CONTROL

This second revision to this report includes more extensive changes. In the two years since the 

first version was released, improved modeling algorithms were developed, additional vendor 

information became available and numerous minor errors were identified.

Several studies were initiated that build on the baseline results generated here. The studies 

include:

• Impact of parallel and dry cooling systems

• Performance of a GE IGCC with CO2 capture operated in a quench only mode 

• COE sensitivity to Econamine cost and reboiler steam requirements

• Natural gas price sensitivity analysis

• Impact of dispatch-based CFs

All of these studies are reported as supplemental chapters to the original report. Because they 

were not part of the original study, they are not addressed in the Executive Summary or 

elsewhere throughout the report.

Exhibit 10-1 contains information added, changed or deleted in successive revisions.

Exhibit 10-1 Record of Revisions

Revision 

Number

Revision 

Date Description of Change Comments

1 8/23/07

Added disclaimer to 

Executive Summary and 

Introduction

Disclaimer involves clarification on extent 

of participation of technology vendors.

Removed reference to 

Cases 7 and 8 in Exhibits 

ES-1 and 1-1.

SNG cases moved to Volume 2 of this report 

as explained in the Executive Summary and 

Section 1.

Added Section 2.8

Explains differences in IGCC TPC estimates 

in this study versus costs reported by other 

sources.
Cost and Performance Baseline for Fossil Energy Plants

592

Revision 

Number

Revision 

Date Description of Change Comments

Added Exhibit ES-14

Mercury emissions are now shown in a 

separate exhibit from SO2, NOx and PM 

because of the different y-axis scale.

Corrected PC and NGCC 

CO2 capture case water 

balances

The Econamine process cooling water 

requirement for the PC and NGCC CO2

capture cases was overstated and has been 

revised.

Replaced Exhibits ES-4, 

3-121, 4-52 and 5-30

The old water usage figures were in gpm 

(absolute) and in the new figures the water 

numbers are normalized by net plant output.

Updated Selexol process 

description

Text was added to Section 3.1.5 to describe 

how H2 slip was handled in the models.

Revised PC and NGCC 

CO2 capture case energy 

balances (Exhibits 4-21, 

4-42 and 5-21)

The earlier version of the energy balances 

improperly accounted for the Econamine 

process heat losses. The heat removed from 

the Econamine process is rejected to the 

cooling tower.

Corrected Exhibit 5-12

and Exhibit 5-23.

Sensible heat for combustion air in the two 

NGCC cases was for only one of the two 

combustion turbines – corrected to account 

for both turbines

2 10/27/10

Updated circulating water 

flow rate values in Section 

4.1.7.

Revision 1 changes to Econamine cooling 

water flow rate were not made in the text in 

Section 4.1.7 (Circulating Water System).

Added Supplmental 

Chapter 6 “Effect of 

Higher Natural Gas Prices 

and Dispatch-Based 

Capacity Factors”
Cost and Performance Baseline for Fossil Energy Plants

593

Revision 

Number

Revision 

Date Description of Change Comments

Added Supplemental 

Chapter 7 “Dry and 

Parallel Cooling”

Added Supplemental 

Chapter 8 “GEE IGCC in 

Quench-Only 

Configuration with CO2

Capture” 

Added Supplemental 

Chapter 9 “Sensitivity to 

MEA System 

Performance and Cost 

Bituminous Baseline Case 

12A”

Updated Aspen models

Major Aspen model updates included:

• Converting FORTRAN code based 

steam cycles to Aspen blocks

• Using the Peng-Robinson property 

method in the Aspen gasifier section

• Modifying the AGR used in the IGCC 

cases to more closely represent 

commercially available technology

• Increasing the capture efficiency of the 

CoP plant with capture to achieve 90

percent

• Correcting a steam condition error in the 

supercritical PC cases with capture

Updated case performance 

results

Major updates included:

• Revising the water balances to include 

withdrawal and consumption

• CAD-based HMB diagrams were 

replaced with Visio versions
Cost and Performance Baseline for Fossil Energy Plants

594

Revision 

Number

Revision 

Date Description of Change Comments

Completed updating case 

economic results

Major updates included:

• Adding owner’s costs to the total plant 

costs to generate total overnight cost

• Updating fuel costs

• Revising the TS&M methodology to 

include the July, 2007 Handy-Whitman 

Index, pore space acquisition costs, and 

liability costs

• Re-costing of cases based on the updated 

performance results

• Switching to COE as the primary cost 

metric (as opposed to levelized COE)

Updated report tables, 

figures and text to reflect 

the revision 2 changes
Cost and Performance Baseline for Fossil Energy Plants

595

11.

1 Coal Specifications for Quality Guidelines, Revision 0, May 31, 2005

REFERENCES

2 NETL Power Systems Financial Model Version 5.0, December 2008

User Guide available at: 

http://www.netl.doe.gov/business/solicitations/ssc2008/references/PSFM%20User%20G

uide.pdf

3 Gross Domestic Product: Chain-type Price Index, Seasonally Adjusted, 

http://research.stlouisfed.org/fred2/series/GDPCTPI

4 Personal Communication between John Wimer (NETL) and Diane Kearney (EIA), AEO 

2007 Reference Case NEMS model forecasted average costs of delivering (transport cost 

only) to electric utilities in 2010, as shown in the AEO 2007 data provided by the EIA to 

NETL on March 30, 2007. (Source: aeo2007.d112106a) 

5 Quality Guidelines for Energy System Studies, prepared by DOE NETL Office of 

Systems and Policy Support, June 4, 2003

6 40 CFR Part 60 – Standards of Performance for Electric Utility Steam Generating Units 

for Which Construction Commenced after September 18, 1978, Final Rule Amendments, 

February 27, 2006

7 US EPA Green Book Nonattainment Area Map, 

http://www.epa.gov/oar/oaqps/greenbk/mapnpoll.html

8 40 CFR 60, EPA-HQ-OAR-2002-0056; FRL-8180-4; “Revision of December 2000 Clean 

Air Act Section 112 (n) Finding Regarding Electric Utility Steam Generating Units and 

Standards of Performance for New and Existing Electric Utility Steam Generating Units: 

Reconsideration,” May 31, 2006

9 2004 Keystone Coal Industry Manual, A Mining Media Publication

10 CoalFleet User Design Basis Specification for Coal-Based Integrated Gasification 

Combined Cycle (IGCC) Power Plants, EPRI, Palo Alto, CA: 2009. 1017501.

11 Thomas, Greg, “Delivering the IGCC Solution”, GE Energy January 31, 2006

12 Morehead, Harry and Hannemann, Frank, “Siemens Technology Improvements Enhance 

IGCC Plant Economics,” Gasification Technologies 2005, San Francisco, CA, October 

2005

13 Telephone communication with David Denton, Eastman Chemical Co.

14 Memorandum from Robert Wayland (Group Leader, Energy Strategies Group, Office of 

Quality Planning and Standards, EPA) to William H. Maxwell (Energy Strategies Group, 

Office of Air Quality Planning and Standards, EPA), “Revised New Source Performance 

Standards (NSPS) Statistical Analysis for Mercury Emissions,” May 31, 2006

15 Standalone Documentation for EPA Base Case 2004 (V.2.1.9) Using the Integrated 

Planning Model, U.S. Environmental Protection Agency, EPA 430-R-05-011, September 

2005
Cost and Performance Baseline for Fossil Energy Plants

596

16 Srivastava, R.K., Staudt, James E., and Jozewicz, Wojciech, “Preliminary Estimates of 

Performance and Cost of Mercury Emission Control Technology Applications on Electric 

Utility Boilers: An Update,” Combined Power Plant Air Pollutant Control Mega 

Symposium, Washington DC, August 30-September 2, 2004

17 Gleitz, Robert, “Advanced GT Technology,” GE Power Systems, July 2003

18 Eldrid, Roberta, Kaufman, Lynda and Marks, Paul, “The 7FB: The Next Evolution of the 

F Gas Turbine,” GER-4194, April 2001

19 “Resolution of “Natural Gas” and “Pipeline Natural Gas” Definition Issues, EPA’s Clean 

Air Market Programs, http://www.epa.gov/airmarkt/monitoring/gasdef/

20 North American Electric Reliability Council website, http://www.nerc.com/~gads/

21 “Evaluation of Alternative IGCC Plant Designs for High Availability and Near Zero 

Emissions: RAM Analysis and Impact of SCR,” EPRI, Palo Alto, CA, 2005, 1010461

22 Higman, Christopher, DellaVilla, Sal, and Steele, Bob, “The Reliability of Integrated 

Gasification Combined Cycle (IGCC) Power Generation Units,” Achema 2006, May 

2006

23 Cooling Tower Fundamentals, ed. John C. Hensley, 2nd Edition, The Marley Cooling 

Tower Company, Mission, Kansas, 1985

24 “Cost Estimate Classification System – As Applied in Engineering, Procurement, and 

Construction for the Process Industries; TCM Framework 7.3 – Cost Estimating and 

Budgeting,” AACE International Recommended Practice No. 18R-97, 2005

25 “Conducting Technical and Economic Evaluations – As Applied for the Process and 

Utility Industries; TCM Framework: 3.2 – Asset Planning, 3.3 Investment Decision 

Making, AACE International Recommended Practice 16R-90, 2003

26 Economic Evaluation of CO2 Storage and Sink Enhancement Options, Tennessee Valley 

Authority, NETL and EPRI, December 2002

27 Smith, Lawrence A., Gupta, Neeraj, Sass, Bruce M. and Bubenik, Thomas A., 

“Engineering and Economic Assessment of Carbon Dioxide Sequestration in Saline 

Formations,” Battelle Memorial Institute, 2001

28 Ciferno, Jared P. and McIlvried, Howard, “CO2 Flow Modeling and Pipe Diameter 

Determination,” February, 2003

29 Economic Evaluation of CO2 Storage and Sink Enhancement Options, Tennessee Valley 

Authority, NETL and EPRI, December 2002

30 Parker, N., “Using Natural Gas Transmission Pipeline Costs to Estimate Hydrogen 

Pipeline Costs,” Institute of Transportation Studies, University of California, Davis, CA, 

2004.

31 Gresham, R. L., Apt, J., et. al, “Implications of Compensating Property-Owners for 

Geologic Sequestration of CO2,” Department of Engineering and Public Policy, Carnegie 

Mellon University, Pittsburgh, PA, 1999.
Cost and Performance Baseline for Fossil Energy Plants

597

32 Klass, A.B., Wilson, E.J., “Climate Change and Carbon Sequestration: Assessing a 

Liability Regime for Long-Term Storage of Carbon Dioxide,” 58 Emory Law Journal 

103, 2008

33 Senate Bill No. 2095, 61st Legislative Assembly of North Dakota, January 6th, 2009

34 House Bill No. 661, Louisiana House of Representatives Regular Session, 2009

35 Enrolled Act No. 20 (Original House Bill No. 58), 60th Legislature of the State of 

Wyoming, General Session, 2009

36 Overview of Monitoring Requirements for Geologic Storage Projects. IEA Greenhouse 

Gas R&D Programme, Report Number PH4/29, November 2004

37 “Recommended Project Finance Structures for the Economic Analysis of Fossil-Based 

Energy Projects,” DOE/NETL-401/090808, September 2008

38 “Cash Creek Incentives $150 Million,” Evansville Courier & Press, 2008, 

http://www.courierpress.com/news/2008/mar/28/cash-creek-incentives-150-million/

39 “No Customer for Controversial Energy Project,” BusinessNorth.com, 

http://www.businessnorth.com/exclusives.asp?RID=2934

40 “Summit Seeks Grant for Clean Coal Power Plant Near Penwell,” mywesttexas.com, 

September 26, 2009, http://www.mywesttexas.com/news/top_stories/article_85e0ec6cc3ce-52b5-a6cc-ede89e9fc7d5.html

41 “Proposed Coal-fired IGCC Power Plant Would Cost $5,500/kW,” Power-Gen 

Worldwide, March 19, 2010, 

http://www.powergenworldwide.com/index/display/articledisplay/4210875418/articles/p

owergenworldwide/coal-generation/new-projects/2010/03/mississippi-power.html

42 Universal Industrial Gases, Inc., http://www.uigi.com/cryodist.html

43 Jenkins, Steve, “Real-World Experience with IGCC – Lessons Learned in Design, 

Permitting, Operations and Maintenance,” URS Corporation, August 17, 2005

44 Geosits, Robert F. and Schmoe, Lee A., “IGCC – The Challenges of Integration, 

Proceedings of GT2005 ASME Turbo Expo 2005: Power for Land, Sea, and Air,” Reno, 

NV, June 2005

45 Jaeger, Harry, “Plant Design Net Rated 644 MW and 38% HHV on Low Rank Coal,” 

Gas Turbine World, March-April 2006

46 Personal communication, Ray Drnevich, Praxair, Inc., ray_drnevich@praxair.com, 

November 2002

47 http://www.calgoncarbon.com/bulletins/Mercury_Removal_Gas_Streams.htmn

48 http://www.calgoncarbon.com/bulletins/HGR-P.htm

49 http://www.calgoncarbon.com/bulletins/TYPE_HGR.htm

50 “Process Screening Study of Alternative Gas Treating and Sulfur Removal Systems for 

IGCC Power Plant Applications,” EPRI AP-5505, December 1987
Cost and Performance Baseline for Fossil Energy Plants

598

51 http://www.coptechnologysolutions.com/egas/process_overview/index.htm

52 “Process Screening Analysis of Alternative Gas Treating and Sulfur Removal for 

Gasification,” Revised Final Report, December 2002, SFA Pacific for NETL

53 Brdar, R. Daniel, and Jones, Robert M. “GE IGCC Technology and Experience with 

Advanced Gas Turbines,” GER-4207, GE Power Systems, Schenectady, NY, 10/2000.

54 GEI-41040G, “Process Specification for Fuel Gases for Combustion in Heavy-Duty 

Turbines,” January 2002

55 GEK-4189, “Design Considerations for Heated Gas Fuel”

56 Rigdon, Robert and Schmoe, Lee, “The IGCC Reference Plant,” Gasification 

Technologies Conference 2005, San Francisco, CA, October 2005

57 Coal Gasification Guidebook: Status, Applications, and Technologies, TR-102034, EPRI, 

December 1993

58 Breton, David and Keeler, Clifton, “Comparative IGCC Performance and Costs for 

Domestic Coals,” Gasification Technologies Council, San Francisco, CA, October 2005

59 Thomas, Greg, “Delivering the IGCC Solution,” GE Energy, January 31, 2006

60 Rigdon, Robert and Miles, Kevin, “The Cleaner Coal Option,” Power Engineering 

International, July 2006

61 van Holthoon, Evert, “Shell Coal Gasification – Leading Technology Across Multiple 

Applications,” Gasification Technologies Conference, October 6, 2009

62 van der Ploeg, H.J., Chhoa, T. And Zuideveld, P.L., “The Shell Coal Gasification Process 

for the US Industry,” Gasification Technology Conference, Washington DC, October 

2004

63 Van den Berg et al., “Method and System for Producing Synthesis Gas, Gasification 

Reactor, and Gasification System,” United States Patent Application Publication, Pub. 

No. US 2006/0260191 A1, November 2006

64 Steam Conditions for PC Plant Designs Market Based Advanced Coal Power Systems 

Comparison Study, WorleyParsons, June 2005

65 Laffont, Patrick, Bartelemy, Jacques, Scarlin, Brendon and Kervenec, Christian, “A 

Clean and Efficient Supercritical Circulating Fluidized Bed Power Plant,” Alstom Power

66 Phillips, Simon, Yamomoto, Kenji, Shinotsuka, Noburu, and Fukuda, Yuji, “Application 

of High Temperature Countermeasures in High Sulfur Coal-fired boilers,” Electric Power 

2003, March 4-6, 2003, www.hitachi.us/power

67 Richard F. Storm, Optimizing Combustion in Boilers with Low NOx Burners, Storm 

Engineering & Associates, Power Magazine, October 1993

68 Peter Wieslanger, Fabric Filters for Power Applications, ALSTOM Power Environmental 

Systems AB, 2000, www.power.alstom.com
Cost and Performance Baseline for Fossil Energy Plants

599

69 Improvement in Power Generation with Post-Combustion Capture of CO2, IEA 

Greenhouse Gas R&D Programme, Report PH4/33, November 2004

70 Reddy, Satish, Johnson, Dennis, and Gilmartin, John, “Fluor’s Econamine FG PlusSM

Technology for CO2 Capture at Coal-Fired Power Plants,” Power Plant Air Pollutant 

Control “Mega” Symposium, Baltimore, MD, August 2008

71 Roberts, C. A., et al., “Potential for Improvement in Power Generation with PostCombustion Capture of CO2,” IEA Greenhouse Gas R&D Programme, 2003

72 Updated Coal Power Systems Study, Pulverized Coal Boiler, Fluor Subcontract Report 

for Carbon Dioxide Capture Unit, Fluor, December 2005

73 “Screening Analysis: Integrated Compressor Intercooling,” DOE/NETL-401/011508, 

January 2008

74 W.G. Gorman, J.K. Reinker, Steam Turbines for Utility Applications, GER-3646C, GE 

Power Generation, 1994

75 “Environmental Footprints and Costs of Coal-Based Integrated Gasification Combined 

Cycle and Pulverized Coal Technologies,” Final Report, EPA-430/R-06/006, July 2006

76 Booras, George and Holt, Neville, “Pulverized Coal and IGCC Plant Cost and 

Performance Estimates,” Gasification Technologies 2004, Washington DC, October 2004

77 GER-3567H, GE Gas Turbine Performance Characteristics, Frank J. Brooks, GE Power 

Systems, 10/00, 

http://www.gepower.com/prod_serv/products/tech_docs/en/downloads/ger3567h.pdf

78 GER-3568G, Dry Low NOx Combustions Systems for GE Heavy-Duty Gas Turbines, 

L.B. Davis, S.H. Black, GE Power Systems, 10/00, 

http://www.gepower.com/prod_serv/products/tech_docs/en/downloads/ger3568g.pdf

79 Gas Turbine World: 2009 GTW Handbook, Volume 27, Pequot Publishing Inc., 2009

80 Brown, Stephen P.A., “Natural Gas Pricing: Do Oil Prices Still Matter?” Federal Reserve 

Bank of Dallas, Southwest Economy, July/August 2005

81 PJM Website, Map of PJM Territory Served, http://pjm.com/about-pjm/how-weoperate/~/media/about-pjm/pjm-zones.ashx

82 PJM 101 The Basics: Locational Marginal Pricing, 

http://www.pjm.com/~/media/training/core-curriculum/ip-pjm-101/pjm101part1.ashx, 

October 23, 2009

83 Personal Correspondence with Frank Ortega, GEA Power Cooling, Inc., 

“Historically...power stations using dry cooling have used ACC design approaches 

...between 40 and 55°F,” September 4, 2008

84 “Technical Development Document for the Final Regulations Addressing Cooling Water 

Intake Structures for New Facilities,” United States Environmental Protection Agency, 

EPA-821-R-01-036, November 2001

85 ASHRAE Handbook of Fundamentals, 1997
Cost and Performance Baseline for Fossil Energy Plants

600

86 Rigdon, Robert and Schmoe, Lee, “The IGCC Reference Plant,” Gasification 

Technologies Conference 2005, San Francisco, CA, October 2005

87 Updated Coal Power Systems Study, Pulverized Coal Boiler, Fluor Subcontract Report 

for Carbon Dioxide Capture Unit, Fluor, December 2005

88 Reddy, Satish, “Econamine FG PlusSM Technology for Post-combustion CO2 Capture,” 

11th Meeting of the International Post-Combustion CO2 Capture Network, May 20 – 21, 

2008, Vienna, Austria