Cost and Performance Baseline for 

Fossil Energy Plants 

DOE/NETL-2007/1281 

Volume 1: Bituminous Coal and Natural Gas to Electricity 

Final Report

May 2007 
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 

DOE/NETL-2007/1281 

Volume 1: Bituminous Coal and Natural Gas to Electricity 

Final Report

May 2007 

NETL Contact: 

Julianne M. Klara 

Senior Analyst 

Office of Systems, Analyses and Planning 

Prepared by: 

Research and Development Solutions, LLC (RDS) 

Mark C. Woods, Parsons Corporation 

Pamela J. Capicotto, Parsons Corporation 

John L. Haslbeck, Parsons Corporation 

Norma J. Kuehn, Parsons Corporation 

Michael Matuszewski, formerly of Parsons Corporation 

Lora L. Pinkerton, WorleyParsons Group, Inc. 

Michael D. Rutkowski, Parsons Corporation 

Ronald L. Schoff, formerly of Parsons Corporation 

Vladimir Vaysman, WorleyParsons Group, Inc. 

National Energy Technology Laboratory 

www.netl.doe.gov 
This page intentionally left blank 
Cost and Performance Baseline for Fossil Energy Plants 

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 to 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 establishes the baseline cost and 

performance for Pulverized Coal Combustion (PC), Integrated Gasification Combined Cycles 

(IGCC), and Natural Gas Combined Cycles (NGCC), all with and without carbon dioxide 

capture and storage assuming that the plants use technology available today. 

Approach 

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

modeling program. Performance and process limits were based on published reports, 

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

from design/build utility projects. Resulting mass and energy balance data were used to size 

equipment, and through a combination of vendor quotes and scaled estimates of prior projects, 

plant capital costs were determined. Operating and maintenance (O&M) costs, and the cost for 

transporting, storing and monitoring CO2 in the cases with carbon capture, were also estimated 

based on reference data and scaled estimates. Levelized cost of electricity (LCOE) was 

determined for all plants assuming investor owned utility financing. The initial results of this 

analysis were subjected to a significant peer review with 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 

The results of this baseline study are considered to be the most comprehensive set of publicly 

available data to date. Issues with proprietary data and the current rapid escalation in labor and 

material costs made it a challenge to develop state-of-the-art configurations and cost estimates. 

The thorough technical review and systematic use of vendor quotes and project design/build data 

to develop the cost estimates in this report are believed to provide the most up-to-date 

i 
Cost and Performance Baseline for Fossil Energy Plants 

performance and costs available in the public literature. Highlights of the study are the 

following: 

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

relatively high efficiencies of about 39%, HHV (without capture) on bituminous coal and 

at the same time meet or exceed current environmental requirements for criteria 

pollutants. 

• Capital cost (total plant cost) for the non-capture plants are as follows: NGCC, $554/kW; 

PC, $1,562/kW (average); IGCC, $1,841/kW (average). With capture, capital costs are: 

NGCC, $1,172/kW; PC, $2,883/kW (average); IGCC, $2,496/kW (average). 

• At fuel costs of $1.80/MMBtu of coal and $6.75/MMBtu of natural gas (HHV), the 20-

year levelized costs of electricity for the non-capture plants are: 64 mills/kWh (average) 

for PC, 68 mills/kWh for NGCC, and 78 mills/kWh (average) for IGCC. 

• When today’s technology for carbon capture and sequestration is integrated into these 

new power plants, the resultant 20-year levelized COE including the cost of CO2

transport, storage and monitoring is: 97 mills/kWh for NGCC; 106 mills/kWh (average) 

for IGCC; and 117 mills/kWh (average) for PC. The cost of transporting CO2 50 miles 

for storage in a geologic formation with over 30 years of monitoring is estimated to be 

about 4 mills/kWh. This represents only about 10 percent of the total carbon capture and 

sequestration costs. 

• A sensitivity study on natural gas price reveals that for CO2 capture cases the levelized 

COE for NGCC is equal to that of IGCC at $7.73/MMBtu, and is equal to that of PC at 

$8.87/MMBtu. In terms of capacity factor, when the NGCC drops below 60 percent, 

such as in a peaking application, the resulting COE is higher than that of an IGCC 

operating at baseload (80 percent capacity factor). 

Fossil Energy RD&D is aimed at improving the performance and cost of clean coal power 

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

gases. 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. 

ii 
Cost and Performance Baseline for Fossil Energy Plants 

TABLE OF CONTENTS 

Table of Contents ......................................................................................................................... iii

List of Exhibits ............................................................................................................................. vi

Acknowledgements ..................................................................................................................... xii

List of Acronyms and Abbreviations ....................................................................................... xiii

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

Performance .....................................................................................................................................3 

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

Water Use...................................................................................................................................6 

Cost Results .....................................................................................................................................8 

Total Plant Cost..........................................................................................................................8 

Levelized Cost of Electricity (LCOE) .....................................................................................10 

Cost of CO2 Removed/Avoided ...............................................................................................15 

Environmental Performance ..........................................................................................................17 

1 Introduction......................................................................................................................23

2 General Evaluation Basis ................................................................................................27

2.1 Site Characteristics.............................................................................................................27 

2.2 Coal Characteristics ...........................................................................................................28 

2.3 Natural Gas Characteristics................................................................................................30 

2.4 Environmental Targets.......................................................................................................30 

2.4.1 IGCC............................................................................................................................33 

2.4.2 PC ...............................................................................................................................34 

2.4.3 NGCC ..........................................................................................................................35 

2.4.4 Carbon Dioxide............................................................................................................36 

2.5 Capacity Factor ..................................................................................................................37 

2.6 Raw Water Usage ..............................................................................................................38 

2.7 Cost Estimating Methodology ...........................................................................................39 

3 IGCC Power Plants..........................................................................................................51 

3.1 IGCC Common Process Areas...........................................................................................51 

3.1.1 Coal Receiving and Storage.........................................................................................51 

3.1.2 Air Separation Unit (ASU) Choice and Integration.....................................................52 

3.1.3 Water Gas Shift Reactors.............................................................................................56 

3.1.4 Mercury Removal ........................................................................................................56

3.1.5 Acid Gas Removal (AGR) Process Selection..............................................................57 

3.1.6 Sulfur Recovery/Tail Gas Cleanup Process Selection.................................................65 

3.1.7 Slag Handling...............................................................................................................68 

3.1.8 Power Island.................................................................................................................68 

3.1.9 Steam Generation Island..............................................................................................74 

3.1.10 Accessory Electric Plant ..............................................................................................77

3.1.11 Instrumentation and Control ........................................................................................77 

3.2 General Electric Energy IGCC Cases................................................................................79 

3.2.1 Gasifier Background ....................................................................................................80

3.2.2 Process Description......................................................................................................82 

3.2.3 Key System Assumptions ............................................................................................89 

3.2.4 Sparing Philosophy ......................................................................................................91 

3.2.5 Case 1 Performance Results.........................................................................................91 

iii 
Cost and Performance Baseline for Fossil Energy Plants 

3.2.6 Case 1 - Major Equipment List..................................................................................104 

3.2.7 Case 1 - Cost Estimating............................................................................................112 

3.2.8 Case 2 - GEE IGCC with CO2 capture ......................................................................118 

3.2.9 Case 2 Performance Results.......................................................................................122 

3.2.10 Case 2 - Major Equipment List..................................................................................136 

3.2.11 Case 2 - Cost Estimating............................................................................................145 

3.3 ConocoPhillips E-GasTM IGCC Cases.............................................................................151 

3.3.1 Gasifier Background ..................................................................................................151 

3.3.2 Process Description....................................................................................................153 

3.3.3 Key System Assumptions ..........................................................................................159 

3.3.4 Sparing Philosophy ....................................................................................................159

3.3.5 Case 3 Performance Results.......................................................................................161 

3.3.6 Case 3 - Major Equipment List..................................................................................174 

3.3.7 Case 3 - Costs Estimating Results .............................................................................182 

3.3.8 Case 4 - E-GasTM IGCC Power Plant with CO2 Capture..........................................188 

3.3.9 Case 4 Performance Results.......................................................................................193 

3.3.10 Case 4 - Major Equipment List..................................................................................206 

3.3.11 Case 4 - Cost Estimating Results...............................................................................214 

3.4 Shell Global Solutions IGCC Cases ................................................................................220 

3.4.1 Gasifier Background ..................................................................................................220 

3.4.2 Process Description....................................................................................................222 

3.4.3 Key System Assumptions ..........................................................................................229 

3.4.4 Sparing Philosophy ....................................................................................................231

3.4.5 Case 5 Performance Results.......................................................................................231 

3.4.6 Case 5 - Major Equipment List..................................................................................244 

3.4.7 Case 5 - Cost Estimating............................................................................................252 

3.4.8 Case 6 - Shell IGCC Power Plant with CO2 Capture................................................258 

3.4.9 Case 6 Performance Results.......................................................................................263 

3.4.10 Case 6 - Major Equipment List..................................................................................276 

3.4.11 Case 6 - Cost Estimating............................................................................................284 

3.5 IGCC Case Summary.......................................................................................................290

4 Pulverized Coal Rankine Cycle Plants.........................................................................299 

4.1 PC Common Process Areas .............................................................................................300 

4.1.1 Coal and Sorbent Receiving and Storage...................................................................300 

4.1.2 Steam Generator and Ancillaries ...............................................................................300 

4.1.3 NOx Control System..................................................................................................303 

4.1.4 Particulate Control .....................................................................................................304 

4.1.5 Mercury Removal ......................................................................................................304 

4.1.6 Flue Gas Desulfurization ...........................................................................................304 

4.1.7 Carbon Dioxide Recovery Facility ............................................................................307 

4.1.8 Power Generation.......................................................................................................311 

4.1.9 Balance of Plant .........................................................................................................312 

4.1.10 Accessory Electric Plant ............................................................................................316 

4.1.11 Instrumentation and Control ......................................................................................316 

4.2 Subcritical PC Cases........................................................................................................317 

4.2.1 Process Description....................................................................................................317 

iv 
Cost and Performance Baseline for Fossil Energy Plants 

4.2.2 Key System Assumptions ..........................................................................................320 

4.2.3 Sparing Philosophy ....................................................................................................322

4.2.4 Case 9 Performance Results.......................................................................................322 

4.2.5 Case 9 – Major Equipment List .................................................................................330 

4.2.6 Case 9 – Cost Estimating ...........................................................................................338 

4.2.7 Case 10 – PC Subcritical Unit with CO2 Capture.....................................................344 

4.2.8 Case 10 Performance Results.....................................................................................344 

4.2.9 Case 10 – Major Equipment List ...............................................................................354 

4.2.10 Case 10 – Cost Estimating .........................................................................................362 

4.3 Supercritical PC cases......................................................................................................368 

4.3.1 Process Description....................................................................................................368 

4.3.2 Key System Assumptions ..........................................................................................371 

4.3.3 Sparing Philosophy ....................................................................................................372

4.3.4 Case 11 Performance Results.....................................................................................372 

4.3.5 Case 11 – Major Equipment List ...............................................................................380 

4.3.6 Case 11 – Costs Estimating Results...........................................................................388 

4.3.7 Case 12 – Supercritical PC with CO2 Capture..........................................................394 

4.3.8 Case 12 Performance Results.....................................................................................394 

4.3.9 Case 12 – Major Equipment List ...............................................................................404 

4.3.10 Case 12 – Cost Estimating Basis ...............................................................................412 

4.4 PC Case Summary ...........................................................................................................418 

5 Natural Gas Combined Cycle Plants............................................................................425 

5.1 NGCC Common Process Areas.......................................................................................425 

5.1.1 Natural Gas Supply System .......................................................................................425 

5.1.2 Combustion Turbine ..................................................................................................425 

5.1.3 Heat Recovery Steam Generator................................................................................427 

5.1.4 NOx Control System..................................................................................................427 

5.1.5 Carbon Dioxide Recovery Facility ............................................................................428 

5.1.6 Steam Turbine............................................................................................................430 

5.1.7 Water and Steam Systems..........................................................................................431 

5.1.8 Accessory Electric Plant ............................................................................................433 

5.1.9 Instrumentation and Control ......................................................................................433 

5.2 NGCC Cases ....................................................................................................................434 

5.2.1 Process Description....................................................................................................434 

5.2.2 Key System Assumptions ..........................................................................................437 

5.2.3 Sparing Philosophy ....................................................................................................438

5.2.4 Case 13 Performance Results.....................................................................................439 

5.2.5 Case 13 – Major Equipment List ...............................................................................446 

5.2.6 Case 13 – Cost Estimating .........................................................................................451 

5.2.7 Case 14 – NGCC with CO2 Capture.........................................................................457 

5.2.8 Case 14 Performance Results....................................................................................457 

5.2.9 Case 14 Major Equipment List ..................................................................................466 

5.2.10 Case 14 – Cost Estimating .........................................................................................472 

5.3 NGCC Case Summary .....................................................................................................478 

6 References.......................................................................................................................483 

v 
Cost and Performance Baseline for Fossil Energy Plants 

LIST OF EXHIBITS 

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

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

Exhibit ES-3 Net Plant Efficiency (HHV Basis) ............................................................................5 

Exhibit ES-4 Water Demand and Usage.........................................................................................7 

Exhibit ES-5 Total Plant Cost.........................................................................................................9 

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

Exhibit ES-7 LCOE By Cost Component.....................................................................................11 

Exhibit ES-8 LCOE Sensitivity to Fuel Costs in Non-Capture Cases..........................................13 

Exhibit ES-9 LCOE Sensitivity to Fuel Costs in CO2 Capture Cases ..........................................13 

Exhibit ES-10 LCOE Sensitivity to Capacity Factor....................................................................14 

Exhibit ES-11 CO2 Capture Costs ................................................................................................16 

Exhibit ES-12 Study Environmental Targets................................................................................17 

Exhibit ES-13 Criteria Pollutant Emissions..................................................................................18

Exhibit ES-14 CO2 Emissions Normalized By Gross Output ......................................................21 

Exhibit 1-1 Case Descriptions ......................................................................................................25 

Exhibit 2-1 Site Ambient Conditions............................................................................................27 

Exhibit 2-2 Site Characteristics ....................................................................................................27 

Exhibit 2-3 Design Coal................................................................................................................29 

Exhibit 2-4 Natural Gas Composition...........................................................................................30 

Exhibit 2-5 Standards of Performance for Electric Utility Steam Generating Units....................31 

Exhibit 2-6 NSPS Mercury Emission Limits................................................................................32 

Exhibit 2-7 Probability Distribution of Mercury Concentration in the Illinois No. 6 Coal..........33 

Exhibit 2-8 Environmental Targets for IGCC Cases ....................................................................33 

Exhibit 2-9 Environmental Targets for PC Cases.........................................................................35 

Exhibit 2-10 Environmental Targets for NGCC Cases.................................................................36 

Exhibit 2-11 CO2 Pipeline Specification ......................................................................................46 

Exhibit 2-12 Deep, Saline Aquifer Specification .........................................................................47 

Exhibit 2-13 Economic Paramenters for LCOE Calculation........................................................49 

Exhibit 2-14 Parameter Assumptions for Capital Charge Factors................................................50 

Exhibit 2-15 Financial Structure for Investor Owned Utility High and Low Risk Projects.........50 

Exhibit 3-1 Air Extracted from the Combustion Turbine and Supplied to the ASU in NonCarbon Capture Cases ............................................................................................................54 

Exhibit 3-2 Typical ASU Process Schematic ...............................................................................55 

Exhibit 3-3 Flow Diagram for a Conventional AGR Unit............................................................59 

Exhibit 3-4 Common Chemical Reagents Used in AGR Processes .............................................60 

Exhibit 3-5 Physical Solvent AGR Process Simplified Flow Diagram........................................61 

Exhibit 3-6 Common Physical Solvents Used in AGR Processes................................................62 

Exhibit 3-7 Common Mixed Solvents Used in AGR Processes...................................................63 

Exhibit 3-8 Equilibrium Solubility Data on H2S and CO2 in Various Solvents .........................63 

Exhibit 3-9 Typical Three-Stage Claus Sulfur Plant ....................................................................66 

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

Natural Gas.............................................................................................................................69 

Exhibit 3-11 Combustion Turbine Typical Scope of Supply........................................................70 

Exhibit 3-12 Typical Fuel Specification for F-Class Machines....................................................72 

vi 
Cost and Performance Baseline for Fossil Energy Plants 

Exhibit 3-13 Allowable Gas Fuel Contaminant Level for F-Class Machines ..............................73 

Exhibit 3-14 Case 1 Process Flow Diagram, GEE IGCC without CO2 Capture .........................84 

Exhibit 3-15 Case 1 Stream Table, GEE IGCC without CO2 Capture ........................................85 

Exhibit 3-16 GEE IGCC Plant Study Configuration Matrix ........................................................89 

Exhibit 3-17 Balance of Plant Assumptions .................................................................................90 

Exhibit 3-18 Case 1 Plant Performance Summary .......................................................................92 

Exhibit 3-19 Case 1 Air Emissions...............................................................................................93 

Exhibit 3-20 Case 1 Carbon Balance............................................................................................94 

Exhibit 3-21 Case 1 Sulfur Balance..............................................................................................94 

Exhibit 3-22 Case 1 Water Balance..............................................................................................95 

Exhibit 3-23 Case 1 Coal Gasification and Air Separation Units Heat and Mass Balance 

Schematic ...............................................................................................................................97 

Exhibit 3-24 Case 1 Syngas Cleanup Heat and Mass Balance Schematic ...................................98 

Exhibit 3-25 Case 1 Sulfur Recovery and Tail Gas Recycle Heat and Mass Balance 

Schematic ...............................................................................................................................99 

Exhibit 3-26 Case 1 Combined-Cycle Power Generation Heat and Mass Balance 

Schematic .............................................................................................................................100 

Exhibit 3-27 Case 1 Steam and Feedwater Heat and Mass Balance Schematic.........................101 

Exhibit 3-28 Case 1 Overall Energy Balance (0°C [32°F] Reference).......................................103 

Exhibit 3-29 Case 1 Total Plant Cost Summary .........................................................................113 

Exhibit 3-30 Case 1 Total Plant Cost Details .............................................................................114 

Exhibit 3-31 Case 1 Initial and Annual O&M Costs ..................................................................117 

Exhibit 3-32 Case 2 Process Flow Diagram, GEE IGCC with CO2 Capture ............................119 

Exhibit 3-33 Case 2 Stream Table, GEE IGCC with CO2 Capture ...........................................120 

Exhibit 3-34 Case 2 Plant Performance Summary .....................................................................124 

Exhibit 3-35 Case 2 Air Emissions.............................................................................................125 

Exhibit 3-36 Case 2 Carbon Balance..........................................................................................126 

Exhibit 3-37 Case 2 Sulfur Balance............................................................................................126 

Exhibit 3-38 Case 2 Water Balance............................................................................................127 

Exhibit 3-39 Case 2 Coal Gasification and Air Separation Units Heat and Mass Balance 

Schematic .............................................................................................................................129 

Exhibit 3-40 Case 2 Syngas Cleanup Heat and Mass Balance Schematic .................................130 

Exhibit 3-41 Case 2 Sulfur Recovery and Tail Gas Recycle Heat and Mass Balance 

Schematic .............................................................................................................................131 

Exhibit 3-42 Case 2 Combined-Cycle Power Generation Heat and Mass Balance 

Schematic .............................................................................................................................132 

Exhibit 3-43 Case 2 Steam and Feedwater Heat and Mass Balance Schematic.........................133 

Exhibit 3-44 Case 2 Overall Energy Balance (0°C [32°F] Reference).......................................135 

Exhibit 3-45 Case 2 Total Plant Cost Summary .........................................................................146 

Exhibit 3-46 Case 2 Total Plant Cost Details .............................................................................147 

Exhibit 3-47 Case 2 Initial and Annual Operating and Maintenance Costs ...............................150 

Exhibit 3-48 Case 3 Process Flow Diagram, E-GasTM IGCC without CO2 Capture.................154 

Exhibit 3-49 Case 3 Stream Table, E-GasTM IGCC without CO2 Capture................................155 

Exhibit 3-50 CoP IGCC Plant Study Configuration Matrix .......................................................160 

Exhibit 3-51 Case 3 Plant Performance Summary .....................................................................162 

Exhibit 3-52 Case 3 Air Emissions.............................................................................................163 

vii 
Cost and Performance Baseline for Fossil Energy Plants 

Exhibit 3-53 Case 3 Carbon Balance..........................................................................................164 

Exhibit 3-54 Case 3 Sulfur Balance............................................................................................164 

Exhibit 3-55 Case 3 Water Balance............................................................................................165 

Exhibit 3-56 Case 3 Coal Gasification and Air Separation Unit Heat and Mass Balance 

Schematic .............................................................................................................................167 

Exhibit 3-57 Case 3 Syngas Cleanup Heat and Mass Balance Schematic .................................168 

Exhibit 3-58 Case 3 Sulfur Recovery and Tail Gas Recycle Heat and Mass Balance 

Schematic .............................................................................................................................169 

Exhibit 3-59 Case 3 Combined Cycle Power Generation Heat and Mass Balance 

Schematic .............................................................................................................................170 

Exhibit 3-60 Case 3 Steam and Feedwater Heat and Mass Balance Schematic.........................171 

Exhibit 3-61 Case 3 Overall Energy Balance (0°C [32°F] Reference).......................................173 

Exhibit 3-62 Case 3 Total Plant Cost Summary .........................................................................183 

Exhibit 3-63 Total Plant Cost Details .........................................................................................184 

Exhibit 3-64 Case 3 Initial and Annual Operating and Maintenance Costs ...............................187 

Exhibit 3-65 Case 4 Process Flow Diagram, E-GasTM IGCC with CO2 Capture ......................189 

Exhibit 3-66 Case 4 Stream Table, E-GasTM IGCC with CO2 Capture .....................................190 

Exhibit 3-67 Case 4 Plant Performance Summary .....................................................................194 

Exhibit 3-68 Case 4 Air Emissions.............................................................................................195 

Exhibit 3-69 Case 4 Carbon Balance..........................................................................................196 

Exhibit 3-70 Case 4 Sulfur Balance............................................................................................196 

Exhibit 3-71 Case 4 Water Balance............................................................................................197 

Exhibit 3-72 Case 4 Coal Gasification and Air Separation Unit Heat and Mass Balance 

Schematic .............................................................................................................................199 

Exhibit 3-73 Case 4 Syngas Cleanup Heat and Mass Balance Schematic .................................200 

Exhibit 3-74 Case 4 Sulfur Recover and Tail Gas Recycle Heat and Mass Balance 

Schematic .............................................................................................................................201 

Exhibit 3-75 Case 4 Combined Cycle Power Generation Heat and Mass Balance 

Schematic .............................................................................................................................202 

Exhibit 3-76 Case 4 Steam and Feedwater Heat and Mass Balance Schematic.........................203 

Exhibit 3-77 Case 4 Overall Energy Balance (0°C [32°F] Reference).......................................205 

Exhibit 3-78 Case 4 Total Plant Cost Summary .........................................................................215 

Exhibit 3-79 Case 4 Total Plant Cost Details .............................................................................216 

Exhibit 3-80 Case 4 Initial and Annual Operating and Maintenance Costs ...............................219 

Exhibit 3-81 Case 5 Process Flow Diagram, Shell IGCC without CO2 Capture.......................223 

Exhibit 3-82 Case 5 Stream Table, Shell IGCC without CO2 Capture......................................224 

Exhibit 3-83 Shell IGCC Plant Study Configuration Matrix......................................................230 

Exhibit 3-84 Case 5 Plant Performance Summary .....................................................................232 

Exhibit 3-85 Case 5 Air Emissions.............................................................................................233 

Exhibit 3-86 Case 5 Carbon Balance..........................................................................................234 

Exhibit 3-87 Case 5 Sulfur Balance............................................................................................234 

Exhibit 3-88 Case 5 Water Balance............................................................................................235 

Exhibit 3-89 Case 5 Coal Gasification and Air Separation Unit Heat and Mass Balance 

Schematic .............................................................................................................................237 

Exhibit 3-90 Case 5 Syngas Cleanup Heat and Mass Balance Schematic .................................238 

viii 
Cost and Performance Baseline for Fossil Energy Plants 

Exhibit 3-91 Case 5 Sulfur Recovery and Tail Gas Recycle Heat and Mass Balance 

Schematic .............................................................................................................................239 

Exhibit 3-92 Case 5 Combined Cycle Power Generation Heat and Mass Balance 

Schematic .............................................................................................................................240 

Exhibit 3-93 Case 5 Steam and Feedwater Heat and Mass Balance Schematic.........................241 

Exhibit 3-94 Case 5 Overall Energy Balance (0°C [32°F] Reference).......................................243 

Exhibit 3-95 Case 5 Total Plant Cost Summary .........................................................................253 

Exhibit 3-96 Case 5 Total Plant Cost Details .............................................................................254 

Exhibit 3-97 Case 5 Initial and Annual Operating and Maintenance Costs ...............................257 

Exhibit 3-98 Case 6 Process Flow Diagram, Shell IGCC with CO2 Capture............................259 

Exhibit 3-99 Case 6 Stream Table, Shell IGCC with CO2 Capture...........................................260 

Exhibit 3-100 Case 6 Plant Performance Summary ...................................................................264 

Exhibit 3-101 Case 6 Air Emissions...........................................................................................265 

Exhibit 3-102 Case 6 Carbon Balance........................................................................................266 

Exhibit 3-103 Case 6 Sulfur Balance..........................................................................................266 

Exhibit 3-104 Case 6 Water Balance..........................................................................................267 

Exhibit 3-105 Case 6 Coal Gasification and Air Separation Unit Heat and Mass Balance 

Schematic .............................................................................................................................269 

Exhibit 3-106 Case 6 Syngas Cleanup Heat and Mass Balance Schematic ...............................270 

Exhibit 3-107 Case 6 Sulfur Recovery and Tail Gas Recycle Heat and Mass Balance 

Schematic .............................................................................................................................271 

Exhibit 3-108 Case 6 Combined Cycle Power Generation Heat and Mass Balance 

Schematic .............................................................................................................................272 

Exhibit 3-109 Case 6 Steam and Feedwater Heat and Mass Balance Schematic.......................273 

Exhibit 3-110 Case 6 Overall Energy Balance (0°C [32°F] Reference).....................................275 

Exhibit 3-111 Case 6 Total Plant Cost Summary .......................................................................285 

Exhibit 3-112 Case 6 Total Plant Cost Details ...........................................................................286 

Exhibit 3-113 Case 6 Initial and Annual Operating and Maintenance Costs .............................289 

Exhibit 3-114 Estimated Performance and Cost Results for IGCC Cases..................................290 

Exhibit 3-115 TPC for IGCC Cases............................................................................................291 

Exhibit 3-116 LCOE for IGCC Cases ........................................................................................292 

Exhibit 3-117 Capacity Factor Sensitivity of IGCC Cases.........................................................293 

Exhibit 3-118 Coal Price Sensitivity of IGCC Cases .................................................................294 

Exhibit 3-119 Cost of CO2 Captured and Avoided in IGCC Cases...........................................294 

Exhibit 3-120 Carbon Conversion Efficiency and Slag Carbon Content ...................................295 

Exhibit 3-121 Water Usage in IGCC Cases................................................................................297 

Exhibit 4-1 Fluor Econamine FG Plus Typical Flow Diagram ..................................................308 

Exhibit 4-2 CO2 Compressor Interstage Pressures ....................................................................311 

Exhibit 4-3 Case 9 Process Flow Diagram, Subcritical Unit without CO2 Capture..................318 

Exhibit 4-4 Case 9 Stream Table, Subcritical Unit without CO2 Capture.................................319 

Exhibit 4-5 Subcritical PC Plant Study Configuration Matrix ...................................................320 

Exhibit 4-6 Balance of Plant Assumptions .................................................................................321 

Exhibit 4-7 Case 9 Plant Performance Summary .......................................................................323 

Exhibit 4-8 Case 9 Air Emissions...............................................................................................324 

Exhibit 4-9 Case 9 Water Balance..............................................................................................325 

Exhibit 4-10 Case 9 Heat and Mass Balance, Subcritical PC Boiler without CO2 Capture......327 

ix 
Cost and Performance Baseline for Fossil Energy Plants 

Exhibit 4-11 Case 9 Overall Energy Balance (0°C [32°F] Reference).......................................329 

Exhibit 4-12 Case 9 Total Plant Cost Summary .........................................................................339 

Exhibit 4-13 Case 9 Total Plant Cost Details .............................................................................340 

Exhibit 4-14 Case 9 Initial and Annual Operating and Maintenance Costs ...............................343 

Exhibit 4-15 Case 10 Process Flow Diagram, Subcritical Unit with CO2 Capture ...................345 

Exhibit 4-16 Case 10 Stream Table, Subcritical Unit with CO2 Capture ...................................346 

Exhibit 4-17 Case 10 Plant Performance Summary ....................................................................347 

Exhibit 4-18 Case 10 Air Emissions...........................................................................................348 

Exhibit 4-19 Case 10 Water Balance..........................................................................................349 

Exhibit 4-20 Case 10 Heat and Mass Balance, Subcritical PC Boiler with CO2 Capture .........351 

Exhibit 4-21 Case 10 Overall Energy Balance (0°C [32°F] Reference).....................................353 

Exhibit 4-22 Case 10 Total Plant Cost Summary .......................................................................363 

Exhibit 4-23 Case 10 Total Plant Cost Details ...........................................................................364 

Exhibit 4-24 Case 10 Initial and Annual Operating and Maintenance Costs .............................367 

Exhibit 4-25 Case 11 Process Flow Diagram, Supercritical Unit without CO2 Capture...........369 

Exhibit 4-26 Case 11 Stream Table, Supercritical Unit without CO2 Capture..........................370 

Exhibit 4-27 Supercritical PC Plant Study Configuration Matrix ..............................................371 

Exhibit 4-28 Case 11 Plant Performance Summary ...................................................................373 

Exhibit 4-29 Case 11 Air Emissions...........................................................................................374 

Exhibit 4-30 Case 11 Water Balance..........................................................................................375 

Exhibit 4-31 Case 11 Heat and Mass Balance, Supercritical PC Boiler without CO2 Capture.377 

Exhibit 4-32 Case 11 Overall Energy Balance (0°C [32°F] Reference).....................................379 

Exhibit 4-33 Case 11 Total Plant Cost Summary .......................................................................389 

Exhibit 4-34 Case 11 Total Plant Cost Details ...........................................................................390 

Exhibit 4-35 Case 11 Initial and Annual Operating and Maintenance Costs .............................393 

Exhibit 4-36 Case 12 Process Flow Diagram, Supercritical Unit with CO2 Capture................395 

Exhibit 4-37 Case 12 Stream Table, Supercritical Unit with CO2 Capture...............................396 

Exhibit 4-38 Case 12 Plant Performance Summary ...................................................................397 

Exhibit 4-39 Case 12 Air Emissions...........................................................................................398 

Exhibit 4-40 Case 12 Water Balance..........................................................................................399 

Exhibit 4-41 Case 12 Heat and Mass Balance, Supercritical PC Boiler with CO2 Capture......401 

Exhibit 4-42 Case 12 Overall Energy Balance (0°C [32°F] Reference).....................................403 

Exhibit 4-43 Case 12 Total Plant Cost Summary .......................................................................413 

Exhibit 4-44 Case 12 Total Plant Cost Details ...........................................................................414 

Exhibit 4-45 Case 12 Initial and Annual Operating and Maintenance Costs .............................417 

Exhibit 4-46 Estimated Performance and Cost Results for Pulverized Coal Cases ...................418 

Exhibit 4-47 Total Plant Cost for PC Cases................................................................................419 

Exhibit 4-48 LCOE for PC Cases ...............................................................................................420 

Exhibit 4-49 Sensitivity of LCOE to Capacity Factor for PC Cases ..........................................421 

Exhibit 4-50 Sensitivity of LCOE to Coal Price for PC Cases...................................................421 

Exhibit 4-51 Cost of CO2 Captured and Avoided in PC Cases .................................................422 

Exhibit 4-52 Water Usage in PC Cases ......................................................................................424 

Exhibit 5-1 Combustion Turbine Typical Scope of Supply........................................................426 

Exhibit 5-2 CO2 Compressor Interstage Pressures ....................................................................431 

Exhibit 5-3 Case 13 Process Flow Diagram, NGCC without CO2 Capture ..............................435 

Exhibit 5-4 Case 13 Stream Table, NGCC without CO2 Capture .............................................436 

x 
Cost and Performance Baseline for Fossil Energy Plants 

Exhibit 5-5 NGCC Plant Study Configuration Matrix ...............................................................437 

Exhibit 5-6 NGCC Balance of Plant Assumptions.....................................................................438 

Exhibit 5-7 Case 13 Plant Performance Summary .....................................................................439 

Exhibit 5-8 Case 13 Air Emissions.............................................................................................440 

Exhibit 5-9 Case 13 Water Balance............................................................................................441 

Exhibit 5-10 Case 13 Heat and Mass Balance, NGCC without CO2 Capture ...........................443 

Exhibit 5-11 Case 13 Overall Energy Balance (0°C [32°F] Reference).....................................445 

Exhibit 5-12 Case 13 Total Plant Cost Summary .......................................................................452 

Exhibit 5-13 Case 13 Total Plant Cost Details ...........................................................................453 

Exhibit 5-14 Case 13 Initial and Annual Operating and Maintenance Cost Summary ..............456 

Exhibit 5-15 Case 14 Process Flow Diagram, NGCC with CO2 Capture .................................458 

Exhibit 5-16 - Case 14 Stream Table, NGCC with CO2 Capture ...............................................459 

Exhibit 5-17 Case 14 Plant Performance Summary ...................................................................460 

Exhibit 5-18 Case 14 Air Emissions...........................................................................................461 

Exhibit 5-19 Case 14 Water Balance..........................................................................................461 

Exhibit 5-20 Case 14 Heat and Mass Balance, NGCC with CO2 Capture ................................463 

Exhibit 5-21 Case 14 Overall Energy Balance (0°C [32°F] Reference).....................................465 

Exhibit 5-22 Case 14 Total Plant Cost Summary .......................................................................473 

Exhibit 5-23 Case 14 Total Plant Cost Details ...........................................................................474 

Exhibit 5-24 Case 14 Initial and Annual Operating and Maintenance Cost Summary ..............477 

Exhibit 5-25 Estimated Performance and Cost Results for NGCC Cases..................................478 

Exhibit 5-26 TPC of NGCC Cases .............................................................................................479

Exhibit 5-27 LCOE of NGCC Cases ..........................................................................................479 

Exhibit 5-28 Sensitivity of LCOE to Capacity Factor in NGCC Cases .....................................480 

Exhibit 5-29 Sensitivity of LCOE to Fuel Price in NGCC Cases...............................................481 

Exhibit 5-30 Water Usage in NGCC Cases ................................................................................482 

xi 
Cost and Performance Baseline for Fossil Energy Plants 

ACKNOWLEDGEMENTS 

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

States Department of Energy’s National Energy Technology Laboratory. This work was 

completed under DOE NETL Contract Number DE-AC26-04NT41817. This work was 

performed under RDS Subtask 401.01.04, Activity 002. The authors wish to acknowledge the 

excellent contributions and cooperation of NETL staff, particularly: 

Julianne Klara, NETL Technical Monitor

Daniel Cicero 

Jared Ciferno 

Jeffrey Hoffmann 

Patrick Le 

Sean Plasynski

Michael Reed 

Gary Stiegel 

Maria Vargas 

John Wimer 

John Winslow 

xii 
Cost and Performance Baseline for Fossil Energy Plants 

LIST OF ACRONYMS AND ABBREVIATIONS 

AACE Association for the Advancement of Cost Engineering 

AC Alternating current 

AEO Annual Energy Outlook 

AGR Acid gas removal 

ANSI American National Standards Institute 

ASU Air separation unit 

BACT Best available control technology 

BEC Bare erected cost 

BFD Block flow diagram 

Btu British thermal unit 

Btu/h British thermal unit per hour 

Btu/kWh British thermal unit per kilowatt hour 

Btu/lb British thermal unit per pound 

Btu/scf British thermal unit per standard cubic foot 

CAAA Clean Air Act Amendments of 1990 

CAIR Clean Air Interstate Rule 

CAMR Clean Air Mercury Rule 

CCF Capital Charge Factor 

CDR Carbon Dioxide Recovery 

CF Capacity factor 

CFM Cubic feet per minute 

CFR Code of Federal Regulations 

CGE Cold gas efficiency 

cm Centimeter 

CO2 Carbon dioxide 

COE Cost of electricity 

CoP ConocoPhillips 

COR Contracting Officer's Representative 

COS Carbonyl sulfide 

CRT Cathode ray tube 

CS Carbon steel 

CT Combustion turbine 

CTG Combustion Turbine-Generator 

CWT Cold water temperature 

dB Decibel 

DCS Distributed control system 

DI De-ionized 

Dia. Diameter 

DLN Dry low NOx 

DOE Department of Energy 

EAF Equivalent availability factor 

xiii 
Cost and Performance Baseline for Fossil Energy Plants 

E-GasTM ConocoPhillips gasifier technology 

EIA Energy Information Administration 

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 

ft, w.g. Feet of water gauge 

GADS Generating Availability Data System 

gal Gallon 

gal/MWh Gallon per megawatt hour 

GDP Gross domestic product 

GEE GE Energy 

gpm Gallons per minute 

gr/100 scf grains per one hundred standard cubic feet 

GT Gas turbine 

h Hour 

H2 Hydrogen 

H2SO4 Sulfuric acid 

HAP Hazardous air pollutant 

HCl Hydrochloric acid 

Hg Mercury 

HDPE High density polyethylene 

HHV Higher heating value 

hp Horsepower 

HP High pressure 

HRSG Heat recovery steam generator 

HSS Heat stable salts 

HVAC Heating, ventilating, and air conditioning 

HWT Hot water temperature 

Hz Hertz 

ICR Information Collection Request 

ID Induced draft 

IGVs Inlet guide vanes 

In. H2O Inches water 

xiv 
Cost and Performance Baseline for Fossil Energy Plants 

In. Hga Inches mercury (absolute pressure) 

In. W.C. Inches water column 

IEEE Institute of Electrical and Electronics Engineers 

IGCC Integrated gasification combined cycle 

IGV Inlet guide vanes 

IOU Investor-owned utility 

IP Intermediate pressure 

IPM Integrated Planning Model 

IPP Independent power producer 

ISO International Standards Organization 

KBR Kellogg, Brown and Root, a subsidiary of Halliburton 

kg/GJ Kilogram per gigajoule 

kg/h Kilogram per hour 

kJ Kilojoules 

kJ/h Kilojoules per hour 

kJ/kg Kilojoules per kilogram 

KO Knockout 

kPa Kilopascal absolute 

kV Kilovolt 

kW Kilowatt 

kWe Kilowatts electric 

kWh Kilowatt-hour 

kWt Kilowatts thermal 

LAER Lowest Achievable Emission Rate 

lb Pound 

lb/h Pounds per hour 

lb/ft2 Pounds per square foot 

lb/MMBtu Pounds per million British thermal units 

lb/MWh Pounds per megawatt hour 

LCOE Levelized cost of electricity 

LFFn Levelization factor for category n fixed operating cost 

LFVn Levelization factor for category n variable operating cost 

LGTI Louisiana Gasification Technology, Inc. 

LHV Lower heating value 

LNB Low NOx burner 

LP Low pressure 

lpm Liters per minute 

m Meters 

m/min Meters per minute 

m3

/min Cubic meter per minute 

MAF Moisture and Ash Free 

MCR Maximum continuous rate 

MDEA Methyldiethanolamine 

xv 
Cost and Performance Baseline for Fossil Energy Plants 

MEA Monoethanolamine 

MHz Megahertz 

MJ/Nm3 Megajoule per normal cubic meter 

MMBtu Million British thermal units (also shown as 106

 Btu) 

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

MMkJ Million kilojoules (also shown as 106

 kJ) 

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

MNQC Multi Nozzle Quiet Combustor 

MPa Megapascals 

MVA Mega volt-amps 

MWe Megawatts electric 

MWh Megawatt-hour 

MWt Megawatts thermal 

N/A Not applicable 

NAAQS National Ambient Air Quality Standards 

NEMA National Electrical Manufacturers Association 

NERC North American Electric Reliability Council 

NETL National Energy Technology Laboratory 

NFPA National Fire Protection Association 

NGCC Natural gas combined cycle 

Nm3 Normal cubic meter 

NOx Oxides of nitrogen 

NSPS New Source Performance Standards 

NSR New Source Review 

O&M Operation and maintenance 

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

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

OD Outside diameter 

OFA Overfire air 

OP/VWO Over pressure/valve wide open 

OSHA Occupational Safety and Health Administration 

OTR Ozone transport region 

PA Primary air 

PAC Powdered activated carbon 

PC Pulverized coal 

PF Power Factor 

PM Particulate matter 

PM10 Particulate matter measuring 10 μm or less 

POTW Publicly Owned Treatment Works 

ppm Parts per million 

ppmv Parts per million volume 

ppmvd Parts per million volume, dry 

PPS Polyphenylensulfide 

xvi 
Cost and Performance Baseline for Fossil Energy Plants 

PRB Powder River Basin coal region 

PSA Pressure Swing Adsorption 

PSD Prevention of Significant Deterioration 

psia Pounds per square inch absolute 

psid Pounds per square inch differential 

psig Pounds per square inch gage 

PTFE Teflon (Polytetrafluoroethylene) 

Qty Quantity 

RDS Research and Development Solutions, LLC 

RH Reheater 

scfh Standard cubic feet per hour 

scfm Standard cubic feet per minute 

Sch. Schedule 

scmh Standard cubic meter per hour 

SCOT Shell Claus Off-gas Treating 

SCR Selective catalytic reduction 

SG Specific gravity 

SGC Synthesis gas cooler 

SGS Sour gas shift 

SIP State implementation plan 

SNCR Selective non-catalytic reduction 

SO2 Sulfur dioxide 

SOx Oxides of sulfur 

SRU Sulfur recovery unit 

SS Stainless steel 

SS Amine SS Specialty Amine 

STG Steam turbine generator 

TCR Total capital requirement 

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 

V-L Vapor Liquid portion of stream (excluding solids) 

vol% Volume percent 

WB Wet bulb 

wg Water gauge 

wt% Weight percent 

$/MMBtu Dollars per million British thermal units 

$/MMkJ Dollars per million kilojoule 

xvii 
Cost and Performance Baseline for Fossil Energy Plants 

This page intentionally left blank 

xviii 
Cost and Performance Baseline for Fossil Energy Plants 

EXECUTIVE SUMMARY

The objective of this report is to present performance and cost estimates for 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 for plants starting operation in 2010. This is 

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

• Volume 1: Electricity production using bituminous coal for coal-based technologies 

• Volume 2: Synthetic natural gas production and repowering using a variety of coal types 

• Volume 3: Electricity production from low rank coal (PC and IGCC) 

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’s) 

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 gasifiers 

each with and without CO2 capture; four PC cases, two subcritical and two supercritical, each 

with and without CO2 capture; and two NGCC plants with and without CO2 capture. 

The methodology was to use information provided by the technology vendors (IGCC/NGCC) or 

to use conventional models (PC) to perform steady-state simulations of the technology using the 

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

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

basis for cost estimating. Costs were determined by WorleyParsons through a combination of 

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

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

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

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

Information Administration’s (EIA) Annual Energy Outlook (AEO) 2007. The first year (2010) 

costs used are $1.71/MMkJ ($1.80/MMBtu) for coal (Illinois No. 6) and $6.40/MMkJ 

($6.75/MMBtu) for natural gas, both on a higher heating value (HHV) basis and in 2007 U.S. 

dollars. 

1 
Cost and Performance Baseline for Fossil Energy Plants 

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

7 SNG See Volume 2 

8 SNG See Volume 2 

9 PC 2400/1050/1050 Subcritical PC Air Wet 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 2400/1050/950 2 x Advanced 

F Class HRSG Air 

14 NGCC 2400/1050/950 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 

capacity factor 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 capacity factor, sensitivity of 

levelized COE to capacity factor 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 MW. The actual net output varies 

between technologies because the combustion turbines 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 517 to 640 MW. 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 

reactions, which reduces steam turbine output. Higher auxiliary load and extraction steam 

2 
Cost and Performance Baseline for Fossil Energy Plants 

3 

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 (combustion turbine). Likewise, the two NGCC cases have a net output of 

560 and 482 MW because of the combustion turbine 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 usage) 

• Cost (total plant cost and levelized cost of electricity) 

• Environmental profile 

PERFORMANCE 

ENERGY EFFICIENCY

The net plant efficiency (HHV basis) for all 12 cases is shown in 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 50.8 percent. 

• The NGCC case with CO2 capture results in the highest efficiency (43.7 percent) 

among all of the capture technologies. 

• The NGCC with CO2 capture results in an efficiency penalty of 7.1 absolute percent, 

relative 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 (41.1 percent), the slurry-fed, two-stage CoP gasifier (39.3 percent) and the 

slurry-fed, single-stage GEE gasifier (38.2 percent). 

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

is almost equal, ranging from 31.7 percent for CoP to 32.5 percent for GEE, with 

Shell intermediate at 32.0 percent. 

• Supercritical PC without CO2 capture has an efficiency of 39.1 percent, which is 

nearly equal to the average of the three non-capture IGCC technologies. 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 (Fluor’s Econamine FG Plus process) 

has a much greater impact on efficiency than CO2 capture in the IGCC cases. This is 

primarily because the low partial pressure of CO2 in the flue gas from a PC plant 

requires a chemical absorption process rather than physical absorption. For chemical 

absorption processes, the regeneration requirements are much more energy intensive. 

Thus the energy penalty for both subcritical and supercritical PC is 11.9 absolute 

percent resulting in post-capture efficiencies of 24.9 percent and 27.2 percent, 

respectively. 
Cost and Performance Baselin

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

Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 9 Case 10 Case 11 Cas

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

Gross Power Output (kWe) 770,350 744,960 742,510 693,840 748,020 693,555 583,315 679,923 580,260 663

Auxiliary Power Requirement (kWe) 130,100 189,285 119,140 175,600 112,170 176,420 32,870 130,310 30,110 117

Net Power Output (kWe) 640,250 555,675 623,370 518,240 635,850 517,135 550,445 549,613 550,150 545

Coal Flowrate (lb/hr) 489,634 500,379 463,889 477,855 452,620 473,176 437,699 646,589 411,282 586Natural Gas Flowrate (lb/hr) N/A N/A N/A N/A N/A N/A N/A N/A N/A NHHV Thermal Input (kWth) 1,674,044 1,710,780 1,586,023 1,633,771 1,547,493 1,617,772 1,496,479 2,210,668 1,406,161 2,00

Net Plant HHV Efficiency (%) 38.2% 32.5% 39.3% 31.7% 41.1% 32.0% 36.8% 24.9% 39.1% 27Net Plant HHV Heat Rate (Btu/kW-hr) 8,922 10,505 8,681 10,757 8,304 10,674 9,276 13,724 8,721 12Raw Water Usage, gpm 4,003 4,579 3,757 4,135 3,792 4,563 6,212 14,098 5,441 12Total Plant Cost ($ x 1,000) 1,160,919 1,328,209 1,080,166 1,259,883 1,256,810 1,379,524 852,612 1,591,277 866,391 1,56Total Plant Cost ($/kW) 1,813 2,390 1,733 2,431 1,977 2,668 1,549 2,895 1,575 2,LCOE (mills/kWh)1 78.0 102.9 75.3 105.7 80.5 110.4 64.0 118.8 63.3 11

CO2 Emissions (lb/hr) 1,123,781 114,476 1,078,144 131,328 1,054,221 103,041 1,038,110 152,975 975,370 138

CO2 Emissions (tons/year) @ CF1 3,937,728 401,124 3,777,815 460,175 3,693,990 361,056 3,864,884 569,524 3,631,301 516

CO2 Emissions (lb/MMBtu) 197 19.6 199 23.6 200 18.7 203 20.3 203 2

CO2 Emissions (kg/MWh)2 662 69.7 659 85.9 639 67.4 807 102 762 9

CO2 Emissions (lb/MWh)2 1,459 154 1,452 189 1,409 149 1,780 225 1,681 2

CO2 Emissions (lb/MWh)3 1,755 206 1,730 253 1,658 199 1,886 278 1,773 2SO2 Emissions (lb/hr) 73 56 68 48 66 58 433 Negligible 407 Neg

SO2 Emissions (tons/year) @ CF1 254 196 237 167 230 204 1,613 Negligible 1,514 Neg

SO2 Emissions (lb/MMBtu) 0.0127 0.0096 0.0125 0.0085 0.0124 0.0105 0.0848 Negligible 0.0847 Neg

SO2 Emissions (kg/MWh)2 0.0427 0.0341 0.0413 0.0311 0.0398 0.0380 0.3369 Negligible 0.3179 Neg

SO2 Emissions (lb/MWh)2 0.0942 0.0751 0.0909 0.0686 0.0878 0.0837 0.7426 Negligible 0.7007 NegNOx Emissions (lb/hr) 313 273 321 277 309 269 357 528 336 4NOx Emissions (tons/year) @ CF1 1,096 955 1,126 972 1,082 944 1,331 1,966 1,250 1,

NOx Emissions (lb/MMBtu) 0.055 0.047 0.059 0.050 0.058 0.049 0.070 0.070 0.070 0.NOx Emissions (kg/MWh)2 0.184 0.166 0.196 0.181 0.187 0.176 0.278 0.352 0.263 0.NOx Emissions (lb/MWh)2 0.406 0.366 0.433 0.400 0.413 0.388 0.613 0.777 0.579 0.PM Emissions (lb/hr) 41 41 38 40 37 39 66 98 62 8PM Emissions (tons/year) @ CF1 142 145 135 139 131 137 247 365 232 3

PM Emissions (lb/MMBtu) 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0130 0.0130 0.0130 0.0PM Emissions (kg/MWh)2 0.024 0.025 0.023 0.026 0.023 0.026 0.052 0.065 0.049 0.

PM Emissions (lb/MWh)2 0.053 0.056 0.052 0.057 0.050 0.057 0.114 0.144 0.107 0.Hg Emissions (lb/hr) 0.0033 0.0033 0.0031 0.0032 0.0030 0.0032 0.0058 0.0086 0.0055 0.0Hg Emissions (tons/year) @ CF1 0.011 0.012 0.011 0.011 0.011 0.011 0.022 0.032 0.020 0.Hg Emissions (lb/TBtu) 0.571 0.571 0.571 0.571 0.571 0.571 1.14 1.14 1.14 1Hg Emissions (kg/MWh)2 1.92E-06 2.03E-06 1.89E-06 2.08E-06 1.83E-06 2.06E-06 4.54E-06 5.75E-06 4.29E-06 5.35

Hg Emissions (lb/MWh)2 4.24E-06 4.48E-06 4.16E-06 4.59E-06 4.03E-06 4.55E-06 1.00E-05 1.27E-05 9.45E-06 1.18

1 Capacity factor is 80% for IGCC cases and 85% for PC and NGCC cases2 Value is based on gross output3 Value is based on net output

Pulverized Coal Boiler 

GEE CoP Shell PC Subcritical PC Supercrit

Integrated Gasification Combined Cycle

4 
Cost and Performance Baselin

5 

38.2%

32.5%

39.3%

31.7%

41.1%

32.0%

36.8%

24.9%

39.1%

27.2%

0.0%

10.0%20.0%30.0%40.0%50.0%60.0%

Efficiency, % (HHV Basis)

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

Exhibit ES-3 Net Plant Efficiency (HHV Basis) 
Cost and Performance Baseline for Fossil Energy Plants 

6 

WATER USE

Three water values are presented for each technology in Exhibit ES-4: water demand, internal 

recycle and raw water usage. Demand is the amount of water required to satisfy a particular 

process (slurry, quench, FGD makeup, etc.) and internal recycle is water available within the 

process (boiler feedwater blowdown, condensate, etc.). Raw water usage is the difference 

between demand and recycle, 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 

71 to 99 percent of the total raw water usage. 

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

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

and two PC cases is used, the relative raw water usage for the technologies is 

2.3:1.5:1.0 (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 requirements 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 demand over NGCC. 

• Among capture cases, the raw water requirement increases (relative to non-capture 

cases) much 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 

much greater cooling water makeup requirements. If average water usage values are 

used for IGCC and PC cases, the relative raw water usage for the technologies in CO2

capture cases is 2.8:1.06:1.0 (PC:NGCC:IGCC). Note that the NGCC CO2 capture 

case requires slightly more water than the average of the three IGCC CO2 capture 

cases. 

• CO2 capture increases the average raw water usage of the IGCC cases by the least 

amount of the technologies evaluated: about 15 percent due primarily to the need for 

additional water in the syngas to accomplish the water gas shift reaction. With the 

addition of CO2 capture, PC raw water usage increases by 125 percent and NGCC by 

86 percent. The large cooling water demand of the Econamine process drives this 

substantial increase for PC and NGCC. 
4,958

4,003

5,422

4,579 4,1193,757

5,021

4,135

3,963 3,792

5,581

4,563

6,286 6,212

15,488

14,098

5,514

5,441

13,483

12,15

2

0

2,0004,0006,0008,000

10,00012,00014,00016,000

Water, gpm

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

Water DemandInternal RecycleRaw Water Usage

Cost and Performance Baselin

7 

Exhibit ES-4 Water Demand and Usage 
Cost and Performance Baseline for Fossil Energy Plants 

8 

COST RESULTS 

TOTAL PLANT COST

The total plant cost (TPC) for each technology was determined through a combination of vendor 

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

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

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

project). Owner’s costs are not included. 

The cost estimates carry an accuracy of ±30 percent, consistent with the screening 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 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 – 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. 

The normalized total plant cost (TPC) for each technology is shown in Exhibit ES-5. The 

following conclusions can be drawn: 
1,813

2,390

1,733

2,431

1,977

2,668

1,549

2,895

1,575

2,870

0

500

1,0001,5002,0002,5003,0003,500

Total Plant Cost, $/kW

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

Cost and Performance Baselin

9 

Exhibit ES-5 Total Plant Cost 
Cost and Performance Baseline for Fossil Energy Plants 

10 

• Among the non-capture cases, NGCC has the lowest capital cost at $554/kW 

followed by PC with an average cost of $1,562/kW and IGCC with an average cost of 

$1,841/kW. The average IGCC cost is 18 percent greater than the average PC cost. 

The process contingency for the IGCC cases ranges from $44-51/kW while there is 

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

between IGCC and PC is reduced to 15 percent when process contingency is 

eliminated. 

• The three IGCC non-capture cases have a capital cost ranging from $1,733/kW (CoP) 

to $1,977/kW (Shell) with GEE intermediate at $1,813/kW. 

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

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

case at $1,172/kW. 

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

$2,883/kW. The average capital cost for IGCC CO2 capture cases is $2,496/kW, 

which is 13 percent less than the average of the PC cases. The process contingency 

for the IGCC capture cases ranges from $101-105/kW, for the PC cases from $99-

104/kW and $59/kW for the NGCC case. If process contingency is removed from the 

PC and IGCC cases, the cost of IGCC is 16 percent less than PC. 

LEVELIZED COST OF ELECTRICITY (LCOE)

The 20-year LCOE was calculated for each case using the economic parameters shown in 

Exhibit ES-6. The cases were divided into two categories, representing high risk and low risk 

projects undertaken at investor owned utilities. 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. 

Exhibit ES-6 Economic Parameters Used to Calculate LCOE 

High Risk Low Risk 

Capital Charge Factor 0.175 0.164 

Coal Levelization Factor 1.2022 1.2089 

Natural Gas Levelization Factor 1.1651 1.1705 

Levelization for all other O&M 1.1568 1.1618 

The LCOE 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, PC plants have the lowest LCOE (average 63.7 mills/kWh), 

followed by NGCC (68.4 mills/kWh) and IGCC (average 77.9 mills/kWh). 
78.0

102.9

75.3

105.7

80.5

110.4

64.0

118.8

63.3

114.8

0

20406080

100120140160

LCOE, mills/kWh

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

CO2 TS&M CostsFuel CostsVariable CostsFixed CostsCapital Costs

Cost and Performance Baselin

11 

Exhibit ES-7 LCOE By Cost Component 
Cost and Performance Baseline for Fossil Energy Plants 

• In capture cases, NGCC plants have the lowest LCOE (97.4 mills/kWh), followed by 

IGCC (average 106.3 mills/kWh) and PC (average 116.8 mills/kWh). 

• The LCOE for the three IGCC non-capture cases ranges from 75.3 mills/kWh (CoP) to 

80.5 mills/kWh (Shell) with GEE in between at 78.0 mills/kWh. The study level of 

accuracy is insufficient to distinguish between the LCOE of the three IGCC technologies. 

• Non-capture supercritical PC has an LCOE of 63.3 mills/kWh and subcritical PC is 64.0 

mills/kWh, an insignificant difference given the level of accuracy of the study estimate. 

• PC is the most expensive technology with CO2 capture, 10 percent higher than IGCC and 

nearly 20 percent higher than NGCC. 

• The capital cost component of LCOE is between 53 and 62 percent in all IGCC and PC 

cases. It represents only 18 percent of LCOE in the NGCC non-capture case and 28 

percent in the CO2 capture case. 

• The fuel component of LCOE ranges from 21-25 percent for the IGCC cases and the PC 

CO2 capture cases. For the PC non-capture cases the fuel component varies from 30-32 

percent. The fuel component is 78 percent of the total in the NGCC non-capture case and 

63 percent in the CO2 capture case. 

• CO2 transport, storage and monitoring is estimated to add 4 mills/kWh to the LCOE, 

which is less than 4 perecent of the total LCOE for all capture cases. 

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

is the LCOE 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 LCOE of NGCC equal to PC or IGCC at a 

given coal cost. The coal prices shown ($1.35, $1.80 and $2.25/MMBtu) represent the baseline 

cost and a range of ±25 percent around the baseline. As an example, at a coal cost of 

$1.80/MMBtu, the LCOE of PC equals NGCC at a natural gas price of $6.15/MMBtu. 

Another observation from Exhibit ES-8 is that the LCOE of IGCC at a coal price of 

$1.35/MMBtu is greater than PC at a coal price of $2.25/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 $2.25 to $1.35/MMBtu) results in an IGCC LCOE decrease of only 13 percent 

(82.5 to 73.2 mills/kWh). 

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

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

of $6.75/MMBtu. For the coal-based technologies at the baseline coal cost of $1.80/MMBtu to 

be equal to NGCC, the cost of natural gas would have to be $7.73/MMBtu (IGCC) or 

$8.87/MMBtu (PC). Alternatively, for the LCOE of coal-based technologies to be equal to 

NGCC at the high end coal cost of $2.25/MMBtu, natural gas prices would have to be 

$8.35/MMBtu for IGCC and $9.65/MMBtu for PC. 

12 
Cost and Performance Baseline for Fossil Energy Plants 

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

40

50

60

70

80

90

100

3 4 5 6 7 8 910 11

Natural Gas Price, $/MMBtu

LCOE, mills/kWh

NGCC

PC w/ coal at $1.35/MMBtu

PC w/ coal at $1.80/MMBtu

PC w/ coal at $2.25/MMBtu

IGCC w/ coal at $1.35/MMBtu

IGCC w/ coal at $1.80/MMBtu

IGCC w/ coal at $2.25/MMBtu

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

40.0

50.0

60.0

70.0

80.0

90.0

100.0

110.0

120.0

130.0

140.0

3 4 5 6 7 8 910 11

Natural Gas Price, $/MMBtu

LCOE, mills/kWh

NGCC

PC w/ coal at $1.35/MMBtu

PC w/ coal at $1.80/MMBtu

PC w/ coal at $2.25/MMBtu

IGCC w/ coal at $1.35/MMBtu

IGCC w/ coal at $1.80/MMBtu

IGCC w/ coal at $2.25/MMBtu

13 
Cost and Performance Baseline for Fossil Energy Plants 

The sensitivity of LCOE to capacity factor is shown for all technologies in Exhibit ES-10. The 

subcritical and supercritical PC cases with no CO2 capture are nearly identical so that the two 

curves appear as a single curve on the graph. The capacity factor is plotted from 40 to 90 

percent. The baseline capacity factor 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 capacity factor could be extended to 90 percent with no spare gasifier. Similarly, 

the PC and NGCC curves assume that the capacity factor could reach 90 percent with no 

additional capital equipment. 

Exhibit ES-10 LCOE Sensitivity to Capacity Factor 

0

50

100

150

200

250

0 10 20 30 40 50 60 70 80 90 100

Capacity Factor, %

LCOE, mills/kWh

GEE no capture

CoP no capture

Shell no capture

GEE w/CO2 capture

CoP w/CO2 capture

Shell w/CO2 capture

Sub PC no capture

SC PC no capture

Sub PC w/CO2 capture

SC PC w/CO2 capture

NGCC no capture

NGCC w/CO2 capture

Coal = $1.80/MMBtu

Natural Gas = $6.75/MMBtu

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

LCOE with decreased capacity factor. Conversely, NGCC with no CO2 capture is relatively flat 

because the LCOE is dominated by fuel charges which decrease as the capacity factor decreases. 

Conclusions that can be drawn from Exhibit ES-10 include: 

• At a capacity factor below 72 percent NGCC has the lowest LCOE in the non-capture 

cases. 

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

the baseline study, and the advantage increases as capacity factor decreases. The 

relatively low capital cost component of NGCC accounts for the increased cost 

differential with decreased capacity factor. 

14 
Cost and Performance Baseline for Fossil Energy Plants 

15 

COST OF CO2REMOVED/AVOIDED

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

costs. The resulting removal and avoided costs are shown in Exhibit ES-11 for each of the six 

technologies modeled. The following conclusions can be drawn: 

The cost of CO2 capture was calculated in two ways, the cost of CO2 removed and the cost of 

CO2 avoided, as illustrated in Equations ES-1 and ES-2, respectively. 

• CO2 removal and 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 removal and avoided costs for IGCC plants are less than NGCC plants because 

the baseline CO2 emissions for NGCC plants are 46 percent less than for IGCC 

plants. Consequently, the normalized removal cost for NGCC plants is divided by a 

smaller amount of CO2. 

• CO2 removal and avoided costs for IGCC plants 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. 

• The total cost of CO2 avoided is $39/ton (average IGCC), $68/ton (average PC), and 

$83/ton (NGCC). 

• In non-capture cases NGCC at 40 percent capacity factor has the same LCOE as the 

average of the three IGCC cases at 72 percent capacity factor further illustrating the 

relatively small impact of capacity factor on NGCC LCOE. 

CO removed MWhtons

LCOE LCOE MWh

CostemovalR with removal removalow

{ /}

{ /$}

2

− / = (ES-1) 

Emissions Emissions MWhtons

LCOE LCOE MWh

Avoided Cost

removalow with removal

with removal removalow

{ /}

{ /$}

/

/

− = − (ES-2) 
27

32 32

41

31

42 44

68

45

68 

0

102030405060708090

$/ton, CO2

GEE IGCC CoP IGCC Shell IGCC Subcritical PC Supercritical PC 

Removal CostAvoided Cost

Cost and Performance Baselin

16 

Exhibit ES-11 CO2 Capture Costs 
Cost and Performance Baseline for Fossil Energy Plants 

17 

ENVIRONMENTAL PERFORMANCE 

The environmental targets for each technology are summarized in Exhibit ES-12 and emission 

rates of SO2, NOx, PM and Hg are shown graphically in Exhibit ES-13. Targets were chosen on 

the basis of the environmental regulations that would most likely apply to plants built in 2010. 

Exhibit ES-12 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: Version 4. 

• PC and NGCC cases are based on best available control technology. 

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 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 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 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 removal is greater than in the noncapture cases resulting in emissions of approximately 0.0041 kg/GJ (0.0095 lb/MMBtu). 
Cost and Performance Baselin

18 

0.000000.020000.040000.060000.080000.100000.12000

Emissions, lb/MMBtu (lb/10/TBtu)

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 

SO2NOxPMHg (lb/10/TBtu)

Exhibit ES-13 Criteria Pollutant Emissions 
Cost and Performance Baseline for Fossil Energy Plants 

• 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 and 

nitrogen dilution could limit IGCC NOx emissions to the environmental target of 15 

ppmv (dry) at 15 percent O2. The small variations in NOx emissions are due to small 

variations in combustion turbine 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-13 as lb/10 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 flue gas desulfurization (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 99.9 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 low NOx burners and overfire air 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). 

Carbon dioxide 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 carbon capture achievable among the six technologies. CO2 emissions are 

presented in Exhibit ES-14 for each case, normalized by gross 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 hence the two reported values of CO2. The following conclusions can be 

drawn: 

• In cases with no carbon capture, NGCC emits 55 percent less CO2 than PC and 46 

percent less CO2 than IGCC per unit of gross output. The lower NGCC CO2 emissions 

reflect the lower carbon intensity of natural gas relative to coal. Based on the fuel 

19 
Cost and Performance Baseline for Fossil Energy Plants 

20 

compositions used in this study, natural gas contains 32 pounds of carbon per million Btu 

of heat input and coal contains 55 pounds per million Btu. 

• 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 adding 

sour gas shift (SGS) reactors to convert CO to CO2 and using a two-stage Selexol process 

with a second stage CO2 removal efficiency of up to 95 percent, a number that was 

supported by vendor quotes. In the GEE CO2 capture case, two stages of SGS and a 

Selexol CO2 removal efficiency of 92 percent were required, which resulted in 90.2 

percent reduction of CO2 in the syngas. The CoP capture case required three stages of 

SGS and 95 percent CO2 capture in the Selexol process, which resulted in 88.4 percent 

reduction of CO2 in the syngas. In the CoP case, the capture target of 90 percent could 

not be achieved because of the high syngas methane content (3.5 vol% compared to 0.10 

vol% in the GEE gasifier and 0.04 vol% in the Shell gasifier). The Shell capture case 

required two stages of SGS and 95 percent capture in the Selexol process, which resulted 

in 90.8 percent reduction of CO2 in the syngas. 

• The CO2 emissions in the three non-capture IGCC cases are nearly identical. The slight 

difference reflects the relative efficiency between the three technologies. The emissions 

in the CO2 capture cases are nearly identical for the Shell and GEE cases, but about 19 

percent higher in the CoP case because of the high syngas CH4 content discussed above. 

• The PC and NGCC cases both assume that all of the carbon in the fuel is converted to 

CO2 in the flue gas and that 90 percent is subsequently removed in the Econamine FG 

Plus process, which was also supported by a vendor quote. 
1,459

154

1,452

189

1,409

149

1,780

225

1,681

209

0

200400600800

1,0001,2001,4001,6001,8002,000

CO2 Emissions, lb/MWh

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

Cost and Performance Baselin

21 

Exhibit ES-14 CO2 Emissions Normalized By Gross Output 
Cost and Performance Baseline for Fossil Energy Plants 

This page intentionally left blank 

22 
Cost and Performance Baseline for Fossil Energy Plants 

1 INTRODUCTION

The objective of this report is to present performance and cost data for fossil energy power 

systems, specifically integrated gasification combined cycle (IGCC), pulverized coal (PC), and 

natural gas combined cycle (NGCC) plants, in a consistent technical and economic manner that 

accurately reflects current market conditions for plants starting operation in 2010. This is 

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

• Volume 1: Electricity production only using bituminous coal for coal-based technologies 

• Volume 2: Synthetic natural gas production and repowering using a variety of coal types 

• Volume 3: Electricity production only from low rank coal (PC and IGCC) 

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 Department of Energy’s (DOE) 

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 General Electric Energy (GEE), 

ConocoPhillips (CoP), and Shell gasifiers each with and without CO2 capture, and six cases 

representing conventional technologies: PC-subcritical, PC-supercritical, and NGCC plants both 

with and without CO2 capture. Cases 7 and 8 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). 

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. 

The IGCC cases have different gross and net power outputs because of the gas turbine 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. Each case uses two combustion turbines for a combined 

gross output of 464 MW. In the combined cycle a heat recovery steam generator extracts heat 

 23 
Cost and Performance Baseline for Fossil Energy Plants 

 24 

from the combustion turbine exhaust to power a steam turbine. However, the carbon 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 combustion turbines 

provide 464 MW gross output in all six cases, the overall combined cycle gross output ranges 

from 694 to 770 MW, which results in a range of net output from 517 to 640 MW. The coal feed 

rate required to achieve the gross power output is also different between the six cases, ranging 

from 204,117 to 226,796 kg/h (450,000 to 500,000 lb/h). 

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 combustion turbine size, which is 185 MW 

for both cases (based on the same advanced F class turbine used in the IGCC cases). Since the 

carbon 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 carbon 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 desribes the NGCC technologies modeled and presents the results for the 

two NGCC cases. 

• Chapter 6 contains the reference list. 
Cost and Performance Baselin

 25 

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 

S

1 IGCC 1800/1050/1050 2 x Advanced F Class GEE Radiant Only 95 mol% O2 Selexol Claus Plant Quench, scrubber and AGR adsorber N2 dilution2 IGCC 1800/1000/1000 2 x Advanced F Class GEE Radiant Only 95 mol% O2 Selexol Claus Plant Quench, scrubber and AGR adsorber N2 dilution S

2

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 dilution4 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 S

2

5 IGCC 1800/1050/1050 2 x Advanced F Class Shell 95 mol% O2 Sulfinol-M Claus Plant Cyclone, barrier filter and scrubber N2 dilution6 IGCC 1800/1000/1000 2 x Advanced F Class Shell 95 mol% O2 Selexol Claus Plant Cyclone, barrier filter and scrubber N2 dilution S

2

7 SNG See Volume 2 8 SNG See Volume 2 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 

A

11 PC 3500/1100/1100 Supercritical PC Air Wet FGD/ Gypsum Baghouse LNB w/OFA and SCR12 PC 3500/1100/1100 Supercritical PC Air Wet FGD/ Gypsum Baghouse LNB w/OFA and SCR 

A

13 NGCC 2400/1050/950 2 x Advanced F Class HRSG Air LNB and SCR 14 NGCC 2400/1050/950 2 x Advanced F Class HRSG Air LNB and SCR 

A

Note (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 

This page intentionally left blank 

 26 
Cost and Performance Baseline for Fossil Energy Plants 

2 GENERAL EVALUATION BASIS

For each of the plant configurations in this study an AspenPlus 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. Ultimately a 20-year levelized cost 

of electricity (LCOE) was calculated for each of the cases and is reported as the revenue 

requirement figure-of-merit. 

The balance of this chapter documents the design basis 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 USA, 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, m (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 train and highway 

CO2 Storage 

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

kilometers (50 miles) and sequestered in a saline 

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

The land area for 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. 

 27 
Cost and Performance Baseline for Fossil Energy Plants 

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 combustion turbines 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 

• Fire protection 

• 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 first year cost of coal used in this study is $1.71/MMkJ ($1.80/MMBtu) (2010 cost of coal in 

2007 dollars). The cost was determined using the following information from the Energy 

Information Administration’s (EIA) 2007 Annual Energy Outlook (AEO): 

• The 2010 minemouth cost of coal in 2005 dollars, $35.23/tonne ($31.96/ton), was 

obtained from Supplemental Table 113 of the EIA’s 2007 AEO for eastern interior 

high-sulfur bituminous coal. 

• The delivery costs were assumed to be 25 percent of the minemouth cost for eastern 

interior coal delivered to Illinois and surrounding states. [2] 

• The 2010 delivered cost ($44.04/tonne [$39.95/ton]) was escalated to 2007 dollars 

using the gross domestic product (GDP) chain-type price index from AEO 2007, 

resulting in a delivered 2010 price in 2007 dollars of $45.32/tonne ($41.11/ton) or 

$1.71/MMkJ ($1.80/MMBtu). [3] (Note: The conversion of $41.11/ton to dollars per 

million Btu results in $1.8049/MMBtu which was used in calculations, but only two 

decimal places are shown in the report.) 

 28 
Cost and Performance Baseline for Fossil Energy Plants 

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 

 29 
Cost and Performance Baseline for Fossil Energy Plants 

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. [4] 

Exhibit 2-4 Natural Gas Composition 

Component Volume Percentage 

Methane CH4 93.9 

Ethane C2H6 3.2 

Propane C3H8 0.7 

n-Butane C4H10 0.4 

Carbon Dioxide CO2 1.0 

Nitrogen N2 0.8 

Total 100.0 

LHV HHV 

kJ/kg 47,764 52,970 

MJ/scm 35 39 

Btu/lb 20,552 22,792 

Btu/scf 939 1,040 

Note: Fuel composition is normalized and heating values are calculated 

The first year cost of natural gas used in this study is $6.40/MMkJ ($6.75/MMBtu) (2010 cost of 

natural gas in 2007 dollars). The cost was determined using the following information from the 

EIA’s 2007 AEO: 

• The 2010 national average delivered cost of natural gas to electric utilities in 2005 

dollars, $6.07/MMkJ ($6.40/MMBtu), was obtained from the AEO 2007 reference 

case Table 13. 

• The 2010 cost was escalated to 2007 dollars using the GDP chain-type price index 

from AEO 2007, resulting in a delivered 2010 price in 2007 dollars of $6.40/MMkJ 

($6.75/MMBtu). [3] 

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 best available control technology (BACT). 

The current federal regulation governing new fossil-fuel fired electric utility steam generating 

units is the New Source Performance Standards (NSPS) as amended in February 2006 and shown 

in Exhibit 2-5, which represents the minimum level of control that would be required for a new 

 30 
Cost and Performance Baseline for Fossil Energy Plants 

fossil energy plant. [5] Stationary combustion turbine emission limits are further defined in 40 

CFR Part 60, Subpart KKKK. 

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

Built, Reconstructed, or Modified After February 28, 2005 

New Units Reconstructed Units Modified Units 

Emission 

Limit 

% 

Reduction 

Emission 

Limit 

(lb/MMBtu)

% 

Reduction 

Emission 

Limit 

(lb/MMBtu) 

% 

Reduction 

PM 0.015 

lb/MMBtu 99.9 0.015 99.9 0.015 99.8 

SO2 1.4 lb/MWh 95 0.15 95 0.15 90 

NOx 1.0 lb/MWh N/A 0.11 N/A 0.15 N/A 

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 combustion turbines 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 

Environmental Protection Agency (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. [6] 

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

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

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

this study. 

The Clean Air Mercury Rule (CAMR) established NSPS limits for Hg emissions from new 

pulverized coal-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. [7] The applicable 

limit in this study is 20 x 10-6 lb/MWh for both bituminous coal-fired PC boilers and for IGCC 

units. 

 31 
Cost and Performance Baseline for Fossil Energy Plants 

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. [8] 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. 

 32 
Cost and Performance Baseline for Fossil Energy Plants 

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

2.4.1 IGCC

The IGCC environmental targets were chosen to match the Electric Power Research Institute’s 

(EPRI) design basis for their CoalFleet for Tomorrow Initiative and are shown in Exhibit 2-8. [9] 

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

Exhibit 2-8 Environmental Targets for IGCC Cases 

Pollutant Environmental 

Target NSPS Limit1 Control Technology 

NOx 15 ppmv (dry) @ 15% 

O2

1.0 lb/MWh 

(0.116 lb/MMBtu) 

Low NOx burners and 

syngas nitrogen dilution 

SO2 0.0128 lb/MMBtu 1.4 lb/MWh 

(0.162 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 

(2.3 lb/TBtu) Carbon bed 

1

 The value in parentheses is calculated based on an average heat rate of 8,640 Btu/kWh from the 

three non-CO2 capture gasifier cases. 

 33 
Cost and Performance Baseline for Fossil Energy Plants 

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

dilution can achieve 15 ppmv (dry) at 15 percent O2, and that value was used for all IGCC cases. 

[10, 11] 

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 

reached. Eastman has yet to experience any mercury contamination in its product. [12] 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. 

2.4.2 PC

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 

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 overfire air (OFA) would limit NOx emissions to 0.5 

lb/MMBtu and that selective catalytic reduction (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 flue gas desulfurization (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. 

 34 
Cost and Performance Baseline for Fossil Energy Plants 

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 

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. [13] 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. 

[14] 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. [15] 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. 

Since co-benefit capture alone exceeds the requirements of NSPS and recent permit averages, no 

activated carbon injection is included in this study. 

2.4.3 NGCC

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 Exhibit 2-10. 

 35 
Cost and Performance Baseline for Fossil Energy Plants 

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 

(0.135 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 6,690 Btu/kWh. 

Published vendor literature indicates that 25 ppmv NOx at 15 percent O2 is achievable using 

natural gas and dry low NOx (DLN) technology. [16, 17] The application of SCR with 90 

percent efficiency further reduces NOx emissions to 2.5 ppmv, which was selected as the 

environmental target. 

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 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). [18] 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 21 

tonnes/yr (23.2 tons/yr) at 85 percent capacity factor or 0.00084 kg/GJ (0.00195 lb/MMBtu). 

Thus for the purpose of this study, SO2 emissions were considered negligible. 

The pipeline natural gas was assumed to contain no particulate matter and no mercury resulting 

in no emissions of either. 

2.4.4 CARBON DIOXIDE

Carbon dioxide (CO2) is not currently regulated. However, the possibility exists that carbon 

limits will be imposed in the future and this study examines cases that include a reduction in CO2

emissions. Because 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. 

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

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

minimum number of water gas shift reactors was used with a maximum Selexol CO2 removal 

efficiency of 95 percent (based on a vendor quote) to achieve an overall CO2 removal efficiency 

of 90 percent. Once the number of shift reactors was determined, the Selexol removal efficiency 

was decreased from 95 percent if possible while still meeting the 90 percent overall target. In the 

 36 
Cost and Performance Baseline for Fossil Energy Plants 

case of the E-GasTM gasifier, CO2 capture is limited to 88.4 percent because of the relatively high 

methane content in the syngas that is not converted to CO2 in the shift reactors. 

For PC and NGCC cases that have CO2 capture, it is assumed that all of the fuel carbon is 

converted to CO2 in the flue gas. 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 

FG Plus technology. 

The cost of CO2 capture was calculated in two ways, the cost of CO2 removed and the cost of 

CO2 avoided, as illustrated in Equations 1 and 2, respectively. The cost of electricity in the CO2

capture cases includes transport, storage and monitoring (TS&M) as well as capture and 

compression. 

(1) CO removed MWhtons

LCOE LCOE MWh

CostemovalR with removal removalow

{ /}

{ /$}

2

− / =

(2) Emissions Emissions MWhtons

LCOE LCOE MWh

Avoided Cost

removalow with removal

with removal removalow

{ /}

{ /$}

/

/

−

− =

2.5 CAPACITY FACTOR 

This study assumes that each new plant would be dispatched any time it is available and would 

be capable of generating maximum capacity when online. Therefore capacity factor and 

availability are equal. The availability for PC and NGCC cases was determined using the 

Generating Availability Data System (GADS) from the North American Electric Reliability 

Council (NERC). [19] 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. 

NERC defines an equivalent availability factor (EAF), which is essentially a measure of the plant 

capacity factor assuming there is always a demand for the output. The EAF accounts for planned 

and scheduled derated hours as well as seasonal derated hours. As such, the EAF matches this 

study’s definition of capacity factor. 

The average EAF for coal-fired plants in the 400-599 MW size range was 84.9 percent in 2004 

and averaged 83.9 percent from 2000-2004. 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 capacity 

factor. 

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 capacity factor. 

EPRI examined the historical forced and scheduled outage times for IGCCs and concluded that 

the reliability factor (which looks at forced or unscheduled outage time only) for a single train 

IGCC (no spares) would be about 90 percent. [20] To get the availability factor, one has to 

 37 
Cost and Performance Baseline for Fossil Energy Plants 

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 capacity factor, so for this study it was assumed to be constant at a 30-day 

planned outage per year (or two 15-day outages). The planned outage would amount to 

8.2 percent of the year, so the availability factor would be (90 percent - 8.2 percent), or 

81.2 percent. 

There are four operating IGCC’s worldwide that use a solid feedstock and are primarily power 

producers (Polk, Wabash, Buggenum and Puertollano). A 2006 report by Higman et al. 

examined the reliability of these IGCC power generation units and concluded that typical annual 

on-stream times are around 80 percent. [21] The capacity factor would be somewhat less than 

the on-stream time since most plants operate at less than full load for some portion of the 

operating year. Given the results of the EPRI study and the Higman paper, a capacity factor of 

80 percent was chosen for IGCC with no spare gasifier required. 

The addition of CO2 capture to each technology was assumed not to impact the capacity factor. 

This assumption was made to enable a comparison based on the impact of capital and variable 

operating costs only. Any reduction in assumed capacity factor would further increase the 

LCOE for the CO2 capture cases. 

2.6 RAW WATER USAGE 

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

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

various sources like boiler feedwater blowdown and condensate from syngas or flue gas (in CO2

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

recycle is raw water usage. 

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

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

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

tower makeup, boiler feedwater makeup, slurry preparation makeup, ash handling makeup, 

syngas humidification, quench system makeup, and FGD system makeup. Usage represents the 

overall impact of the process on the water source. 

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 [22]: 

• 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. 

 38 
Cost and Performance Baseline for Fossil Energy Plants 

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, and by difference, 

the amount of raw water required. 

2.7 COST ESTIMATING METHODOLOGY 

The Total Plant Cost (TPC) and Operation and Maintenance (O&M) costs for each of the cases 

in the study were estimated by WorleyParsons Group Inc. (WorleyParsons). The estimates carry 

an accuracy of ±30 percent, consistent with the screening study level of information available for 

the various study power technologies. 

WorleyParsons used an in-house database and conceptual estimating models for the capital cost 

and O&M cost estimates. Costs were further calibrated using a combination of adjusted vendorfurnished and actual cost data from recent design and design/build projects. 

The capital costs for each cost account were reviewed by comparing individual accounts across 

all of the other cases and technologies to ensure an accurate representation of the relative cost 

differences between the cases and accounts. 

All capital and O&M costs are presented as “overnight costs” expressed in December 2006 

dollars. In this study the first year of plant construction is assumed to be 2007, and the resulting 

LCOE is expressed in year 2007 dollars. The capital and operating costs in December 2006 

dollars were treated as a January 2007 year cost throughout the report without escalation. In this 

report December 2006 dollars and January 2007 dollars are considered to be equal. 

Capital costs are presented at the TPC level. TPC includes: 

• Equipment (complete with initial chemical and catalyst loadings), 

• Materials, 

• Labor (direct and indirect), 

• Engineering and construction management, and 

• Contingencies (process and project). 

Owner’s costs are excluded. 

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 cost. Thus, each of these cases reflects 

the expected cost for the next commercial sale of each of these respective technologies. 

 39 
Cost and Performance Baseline for Fossil Energy Plants 

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. 

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 Engineering/Procurement/Construction Management (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. Site-specific 

considerations such as unusual soil conditions, special seismic zone requirements, or unique 

local conditions such as accessibility, local regulatory requirements, etc. are not considered in the 

estimates. 

The estimate 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. The single exception to the fence line limit is in the CO2 capture cases 

where costs are included for TS&M of the CO2. 

Labor costs are based on Merit Shop (non-union), in a competitive bidding environment. 

Capital Costs 

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 

 40 
Cost and Performance Baseline for Fossil Energy Plants 

estimating models. This provides a basis for subsequent comparisons and easy modification 

when comparing between specific case-by-case variations. 

Key equipment costs for each of the cases were calibrated to reflect recent quotations and/or 

purchase orders for other ongoing in-house power or process projects. These include, but are not 

limited to the following equipment: 

• Pulverized Coal Boilers 

• Combustion Turbine Generators 

• Steam Turbine Generators 

• Circulating Water Pumps and Drivers 

• Cooling Towers 

• Condensers 

• Air Separation Units (partial) 

• Main Transformers 

• Econamine FG Plus CO2 Capture Process (quote provided specifically for this project) 

Other key estimate considerations include the following: 

• Labor costs are based on Midwest, Merit Shop. Costs would need to be re-evaluated for 

projects at different locations or for projects employing union labor. 

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

craft labor available locally. 

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

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

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

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

Current indications are that regional craft shortages are likely over the next several years. 

The types and amounts of incentives will vary based on project location and timing 

relative to other work. The cost impact resulting from an inadequate local work force can 

be significant. 

• 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 of CO2 in all 

capture cases. 

 41 
Cost and Performance Baseline for Fossil Energy Plants 

• Engineering and Construction Management were estimated as a percent of bare erected 

cost; 10 percent for IGCC and PC technologies, and 9 percent for NGCC technologies. 

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. 

• All capital costs are presented as “Overnight Costs” in December 2006 dollars. As 

previously mentioned, December 2006 and January 2007 dollars are considered 

equivalent in this report. Escalation to period-of-performance is specifically excluded. 

Price Escalation 

A significant change in power plant cost occurred in recent years due to the significant increases 

in the pricing of equipment and bulk materials. This estimate includes these increases. All 

vendor quotes used to develop these estimates were received within the last two years. The price 

escalation of vendor quotes incorporated a vendor survey of actual and projected pricing 

increases from 2004 through the third quarter of 2006 that WorleyParsons conducted for a recent 

project. The results of that survey were used to validate/recalibrate the corresponding escalation 

factors used in the conceptual estimating models. 

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. As noted above, the capital costs were 

reviewed and compared across all of the cases, accounts, and technologies to ensure that a 

consistent representation of the relative cost differences is reflected in the estimates. 

In performing such a comparison, it is important to reference the technical parameters for each 

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

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

design philosophy occur. Some key examples are: 

• The combustion turbine account in the GEE IGCC cases includes a syngas expander 

which is not required for the CoP or Shell cases. 

• The combustion turbines 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: 

• Escalation to period-of-performance 

 42 
Cost and Performance Baseline for Fossil Energy Plants 

• Owner’s costs – including, but not limited to land acquisition and right-of-way, permits 

and licensing, royalty allowances, economic development, project development costs, 

allowance for funds-used-during construction, legal fees, Owner’s engineering, preproduction costs, furnishings, Owner’s contingency, etc. 

• All taxes, with the exception of payroll taxes 

• 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 a 5-day/10-hour work week 

• Additional premiums associated with an EPC contracting approach 

Contingency 

Both the project contingency and process contingency costs represent costs that are expected to 

be spent in the development and execution of the project that are not yet fully reflected in the 

design. It is industry practice to include project contingency in the TPC to cover project 

uncertainty and the cost of any additional equipment that would result during detailed design. 

Likewise, the estimates include process contingency to cover the cost of any additional 

equipment that would be required as a result of continued technology development. 

Project Contingency

Project contingencies were added to each of the capital accounts to cover project uncertainty and 

the cost of any additional equipment that could result from detailed design. The project 

contingencies represent costs that are expected to occur. Each bare erected cost account was 

evaluated against the level of estimate detail, field experience, and the basis for the equipment 

pricing to define project contingency. 

The capital cost estimates associated with the plant designs in this study were derived from 

various sources which include prior conceptual designs and actual design and construction of 

both process and power plants. 

The Association for the Advancement of Cost Engineering (AACE) International recognizes five 

classes of estimates. On the surface, the level of project definition of the cases evaluated in this 

study would appear to fall under an AACE International Class 5 Estimate, associated with less 

than 2 percent project definition, and based on preliminary design methodology. However, the 

study cases are actually more in line with the AACE International Class 4 Estimate, which is 

associated with equipment factoring, parametric modeling, historical relationship factors, and 

broad unit cost data. 

Based on the AACE International contingency guidelines as presented in NETL’s "Quality 

Guidelines for Energy System Studies" it would appear that the overall project contingencies for 

the subject cases should be in the range of 30 to 40 percent. [4] However, such contingencies are 

believed to be too high when the basis for the cost numbers is considered. The costs have been 

extrapolated from an extensive data base of project costs (estimated, quoted, and actual), based 

on both conceptual and detailed designs for the various technologies. This information has been 

used to calibrate the costs in the current studies, thus improving the quality of the overall 

estimates. As such, the overall project contingencies should be more in the range of 15 to 20 

percent based on the specific technology; with the PC and NGCC cases being at the lower end of 

 43 
Cost and Performance Baseline for Fossil Energy Plants 

the range, and the IGCC cases at the higher end, and the capture cases being higher than the noncapture cases. 

Process Contingency

Process contingency is intended to compensate for uncertainties arising as a result of the state of 

technology development. Process contingencies have been applied to the estimates 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 

• Combustion Turbine Generator – 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 

AACE International provides standards for process contingency relative to technology status; 

from commercial technology at 0 to 5 percent to new technology with little or no test data at 40 

percent. The process contingencies as applied in this study are consistent with the AACE 

International standards. 

All contingencies included in the TPC, both project and process, represent costs that are expected 

to be spent in the development and execution of the project. 

Operations and Maintenance (O&M) 

The production costs or operating costs and related maintenance expenses (O&M) pertain to 

those charges associated with operating and maintaining the power plants over their expected 

life. These costs include: 

• Operating labor 

• Maintenance – material and labor 

• Administrative and support labor 

• Consumables 

• Fuel 

• Waste disposal 

• Co-product or by-product credit (that is, a negative cost for any by-products sold) 

 44 
Cost and Performance Baseline for Fossil Energy Plants 

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 $33/hr. The 

associated labor burden is estimated at 30 percent of the base labor rate. 

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. The exception to this is the maintenance 

cost for the combustion turbines, which is calculated as a function of operating hours. 

It should be noted that a detailed analysis considering each of the individual gasifier components 

and gasifier refractory life is beyond the scope of this study. However, to address this at a high 

level, the maintenance factors applied to the gasifiers vary between the individual gasifier 

technology suppliers. The gasifier maintenance factors used for this study are as follows: 

• GE – 10 percent on all gasifier components 

• CoP and Shell – 7.5 percent on the gasifier and related components, and 4.5 percent on 

the syngas cooling. 

Administrative and Support Labor

Labor administration and overhead charges are assessed at rate of 25 percent of the burdened 

operation and maintenance 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 capacity factor. 

Initial fills of the consumables, fuels and chemicals, are different from the initial chemical 

loadings, which are included with the equipment pricing in the capital cost. 

Waste Disposal 

Waste quantities and disposal costs were determined/evaluated similarly to the consumables. In 

this study both slag from the IGCC cases and fly ash and bottom ash from the PC cases are 

considered a waste with a disposal cost of $17.03/tonne ($15.45/ton). The carbon used for 

mercury control in the IGCC cases is considered a hazardous waste with disposal cost of 

$882/tonne ($800/ton). 

 45 
Cost and Performance Baseline for Fossil Energy Plants 

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. Nor were any of the technologies penalized for their potential 

disposal cost. That is, for this evaluation, it is assumed that the by-product or co-product value 

simply offset disposal costs, for a net zero in operating costs. 

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. 

CO2 Transport, Storage and Monitoring 

For those cases that feature CO2 capture, the capital and operating costs for CO2 transport, 

storage and monitoring (TS&M) were independently estimated by the National Energy 

Technology Laboratory (NETL). Those costs were converted to a levelized cost of electricity 

(LCOE) and combined with the plant capital and operating costs to produce an overall LCOE. 

The TS&M costs were levelized over a twenty-year period using the methodology described in 

the next subsection of this report. 

CO2 TS&M costs were estimated 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 2-11. [23] 

Exhibit 2-11 CO2 Pipeline Specification 

Parameter Units Parameter Value 

Inlet Pressure MPa (psia) 15.3 (2,215) 

Outlet Pressure MPa (psia) 10.4 (1,515) 

Inlet Temperature °C (°F) 26 (79) 

N2 Concentration ppmv < 300 

O2 Concentration ppmv < 40 

Ar Concentration ppmv < 10 

• The CO2 is transported 80 kilometers (50 miles) via pipeline to a geologic sequestration 

field for injection into a saline formation. 

• The CO2 is transported and injected as a supercritical fluid in order to avoid two-phase 

flow and achieve maximum efficiency. [24] The pipeline is assumed to have an outlet 

 46 
Cost and Performance Baseline for Fossil Energy Plants 

pressure (above the supercritical pressure) of 10.4 MPa (1,515 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 4.8 MPa (700 psi) over an 

80 kilometer (50 mile) pipeline length. [25] (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. 

• The saline formation is at a depth of 1,239 meters (4,055 ft) and has a permeability of 22 

millidarcy (a measure of permeability defined as roughly 10-12 Darcy) and formation 

pressure of 8.4 MPa (1,220 psig). [23] This is considered an average storage site and 

requires roughly one injection well for each 9,360 tonnes (10,320 short tons) of CO2

injected per day. [23] The assumed aquifer characteristics are tabulated in Exhibit 2-12. 

Exhibit 2-12 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) 

For CO2 transport and storage, capital and O&M costs were assessed using metrics from a 2001 

Battelle report. [24] These costs were scaled from the 1999-year dollars described in the report 

to Dec-2006-year dollars using U.S. Bureau of Labor Statistics (BLS) Producer Price Indices for 

the oil and gas industry and the Chemical Engineering Plant Cost Index. Project and process 

contingencies of thirty and twenty percent, respectively, were applied to the Battelle costs to 

cover additional costs that are expected to arise from: i) developing a more detailed project 

definition, and ii) using technologies that have not been well-demonstrated to date in a similar 

commercial application. 

For CO2 monitoring, costs were assessed using metrics for a saline formation “enhanced 

monitoring package” as reported in a 2004 International Energy Agency (IEA) report. [26] The 

IEA report presented costs for two types of saline formations: those with low and high residual 

gas saturations. The reported monitoring costs were higher for saline formations with low 

residual gas saturation, and those costs were used as the basis for this report. The IEA report 

calculated the present value of life-cycle monitoring costs using a ten percent discount rate. The 

present value cost included the initial capital cost for monitoring as well as O&M costs for 

 47 
Cost and Performance Baseline for Fossil Energy Plants 

monitoring over a period of eighty years (a thirty-year injection period followed by fifty years of 

post-injection monitoring). 

For this study, the present value reported in the IEA report was adjusted from Nov-2004-year 

dollars to Dec-2006-year dollars using U.S. BLS Producer Price Indices for the oil and gas 

industry. Project and process contingencies of thirty and thirty-five percent, respectively, were 

applied to the IEA value to cover additional costs that are expected to arise as described above. 

The resulting metric used for this report is a present value of $0.176 per metric ton of CO2 stored 

over a thirty-year injection period. 

In accordance with the IEA’s present-value, life-cycle methodology, this report levelized 

monitoring costs over a twenty-year period by simply applying a capital charge factor to the 

present value of life-cycle monitoring costs (10 percent discount rate). This approach is 

representative of a scenario in which the power plant owner establishes a “CO2 Monitoring 

Fund” prior to plant startup that is equal to the present value of life-cycle monitoring costs. 

Establishing such a fund at the outset could allay concerns about the availability of funds to pay 

for monitoring during the post-injection period, when the plant is no longer operating. While it 

is recognized that other, more nuanced, approaches could be taken to levelizing eighty years of 

monitoring costs over a twenty-year period, the approach applied in this report was chosen 

because it is simple to describe and should result in a conservative (i.e., higher) estimate of the 

funds required. 

Levelized Cost of Electricity 

The revenue requirement method of performing an economic analysis of a prospective power 

plant has been widely used in the electric utility industry. This method permits the incorporation 

of the various dissimilar components for a potential new plant into a single value that can be 

compared to various alternatives. The revenue requirement figure-of-merit in this report is cost 

of electricity (COE) levelized over a 20 year period and expressed in mills/kWh (numerically 

equivalent to $/MWh). The 20-year LCOE was calculated using a simplified model derived 

from the NETL Power Systems Financial Model. [27] 

The equation used to calculate LCOE is as follows: 

(CCFP)(TPC) + [(LFF1)(OCF1) + (LFF2)(OCF2) + ...] + (CF)[(LFV1)(OCV1) + (LFV2)(OCV2) + ...] 

LCOEP = 

(CF)(MWh) 

where 

LCOEP = levelized cost of electricity over P years, $/MWh 

P = levelization period (e.g., 10, 20 or 30 years) 

CCF = capital charge factor for a levelization period of P years 

TPC = total plant cost, $ 

LFFn = levelization factor for category n fixed operating cost 

OCFn = category n fixed operating cost for the initial year of operation (but expressed in 

“first-year-of-construction” year dollars) 

CF = plant capacity factor 

 48 
Cost and Performance Baseline for Fossil Energy Plants 

LFVn = levelization factor for category n variable operating cost 

OCVn = category n variable operating cost at 100 percent capacity factor for the initial year 

of operation (but expressed in “first-year-of-construction” year dollars) 

MWh = annual net megawatt-hours of power generated at 100 percent capacity factor 

All costs are expressed in “first-year-of-construction” year dollars, and the resulting LCOE is 

also expressed in “first-year-of-construction” year dollars. In this study the first year of plant 

construction is assumed to be 2007, and the resulting LCOE is expressed in year 2007 dollars. 

The capital cost in December 2006 dollars was treated as a 2007 year cost. 

In CO2 capture cases, the LCOE for TS&M costs was added to the LCOE calculated using the 

above equation to generate a total cost including CO2 capture, sequestration and subsequent 

monitoring. 

Although their useful life is usually well in excess of thirty years, a twenty-year levelization 

period is typically used for large energy conversion plants and is the levelization period used in 

this study. 

The technologies modeled in this study were divided into one of two categories for calculating 

LCOE: investor owned utility (IOU) high risk and IOU low risk. All IGCC cases as well as PC 

and NGCC cases with CO2 capture are considered high risk. The non-capture PC and NGCC 

cases are considered low risk. The resulting capital charge factor and levelization factors are 

shown in Exhibit 2-13. 

Exhibit 2-13 Economic Paramenters for LCOE Calculation 

High Risk Low Risk Nominal 

Escalation, %1

Capital Charge Factor 0.175 0.164 N/A 

Coal Levelization Factor 1.2022 1.2089 2.35 

Natural Gas Levelization Factor 1.1651 1.1705 1.96 

General O&M Levelization Factor 1.1568 1.1618 1.87 

1

 Nominal escalation is the real escalation plus the general annual average inflation rate of 1.87 

percent. 

The economic assumptions used to derive the capital charge factors are shown in Exhibit 2-14. 

The difference between the high risk and low risk categories is manifested in the debt-to-equity 

ratio and the weighted cost of capital. The values used to generate the capital charge factors and 

levelization factors in this study are shown in Exhibit 2-15. 

 49 
Cost and Performance Baseline for Fossil Energy Plants 

Exhibit 2-14 Parameter Assumptions for Capital Charge Factors 

Parameter Value 

Income Tax Rate 38% (Effective 34% Federal, 6% State) 

Repayment Term of Debt 15 years 

Grace Period on Debt Repayment 0 years 

Debt Reserve Fund None 

Depreciation 20 years, 150% declining balance 

Working Capital zero for all parameters 

Plant Economic Life 30 years 

Investment Tax Credit 0% 

Tax Holiday 0 years 

Start-Up Costs (% of EPC)1 2% 

All other additional capital costs ($) 0 

EPC escalation 0% 

Duration of Construction 3 years 

1

 EPC costs equal total plant costs less contingencies 

Exhibit 2-15 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 9% 4.5% 2.79% 

Equity 50 12% 6% 6% 

Total 11% 8.79% 

High Risk 

Debt 45 11% 4.95% 3.07% 

Equity 55 12% 6.6% 6.6% 

Total 11.55% 9.67% 

 50 
Cost and Performance Comparison of Fossil Energy Power Plants 

51 

3 IGCC POWER PLANTS

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 in 2010. 

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 gas turbine output and the high auxiliary 

loads imparted by the CO2 capture process. 

The combustion turbine is based on an advanced F-class design. The HRSG/steam turbine cycle 

is 12.4 MPa/566°C/566°C (1800 psig/1050°F/1050°F) for all of the non-CO2 capture cases and 

12.4 MPa/538°C/538°C (1800 psig/1000°F/1000°F) for all of the CO2 capture cases. The 

capture cases have a lower main and reheat steam temperature primarily because the turbine 

firing temperature is reduced to allow for a parts life equivalent to NGCC operation with a highhydrogen content fuel, which results in a lower turbine exhaust temperature. 

The evaluation scope included developing heat and mass balances and estimating plant 

performance. Equipment lists were developed for each design to support plant capital and 

operating cost estimates. The evaluation basis details, including site ambient conditions, fuel 

composition and environmental targets, were provided in Section 2. Section 3.1 covers general 

information that is common to all IGCC cases, and case specific information is subsequently 

presented in 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 COAL RECEIVING AND STORAGE

The function of the Coal Receiving and Storage system is to unload, convey, prepare, and store 

the coal delivered to the plant. The scope of the system is from the trestle bottom dumper and 

coal receiving hoppers up to and including the slide gate valves at the outlet of the coal storage 

silos. Coal receiving and storage is identical for all six IGCC cases; however, coal preparation 

and feed are gasifier-specific. 

Operation Description – The coal is delivered to the site by 100-car unit trains comprised of 91 

tonne (100 ton) rail cars. The unloading is done by a trestle bottom dumper, which unloads the 

coal into two receiving hoppers. Coal from each hopper is fed directly into a vibratory feeder. 

The 8 cm x 0 (3" x 0) coal from the feeder is discharged onto a belt conveyor. Two conveyors 

with an intermediate transfer tower are assumed to convey the coal to the coal stacker, which 

transfer the coal to either the long-term storage pile or to the reclaim area. The conveyor passes 

under a magnetic plate separator to remove tramp iron and then to the reclaim pile. 

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 
Cost and Performance Comparison of Fossil Energy Power Plants 

52 

bin located in the crusher tower. The coal is reduced in size to 3 cm x 0 (11⁄4" x 0) by the 

crusher. A conveyor then transfers the coal to a transfer tower. In the transfer tower the coal is 

routed to the tripper, which loads the coal into one of three silos. Two sampling systems are 

supplied: the as-received sampling system and the as-fired sampling system. Data from the 

analyses are used to support the reliable and efficient operation of the plant. 

3.1.2 AIR SEPARATION UNIT (ASU) CHOICE AND INTEGRATION

In order to economically and efficiently support IGCC projects, air separation equipment has 

been modified and improved in response to production requirements and the consistent need to 

increase single train output. “Elevated pressure” air separation designs have been implemented 

that result in distillation column operating pressures that are about twice as high as traditional 

plants. In this 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). [28] For 

IGCC designs the elevated pressure ASU process minimizes power consumption and decreases 

the size of some of the equipment items. When the air supply to the ASU is integrated with the 

gas turbine, the ASU operates at or near the supply pressure from the gas turbine’s air 

compressor. 

Residual Nitrogen Injection 

The residual nitrogen that is available after gasifier oxygen and nitrogen requirements have been 

met is often compressed and sent to the gas turbine. Since all product streams are being 

compressed, the ASU air feed pressure is optimized to reduce the total power consumption and 

to provide a good match with available compressor frame sizes. 

Increasing the diluent flow to the gas turbine by injecting residual nitrogen from the ASU can 

have a number of benefits, depending on the design of the gas turbine: 

• Increased diluent increases mass flow through the turbine, thus increasing the power 

output of the gas turbine while maintaining optimum firing temperatures for syngas 

operation. This is particularly beneficial for locations where the ambient temperature 

and/or elevation are high and the gas turbine would normally operate at reduced output. 

• By mixing with the syngas or by being injected directly into the combustor, the diluent 

nitrogen lowers the firing temperature (relative to natural gas) and reduces the formation 

of NOx. 

In this study, the ASU nitrogen product was used as the primary diluent with a design target of 

reducing the syngas lower heating value (LHV) to 4.5-4.8 MJ/Nm3

 (120-128 Btu/scf). If the 

amount of available nitrogen was not sufficient to meet this target, additional dilution was 

provided through syngas humidification, and if still more dilution was required, the third option 

was steam injection. 

Air Integration 

Integration between the ASU and the combustion turbine can be practiced by extracting some, or 

all, of the ASU’s air requirement from the gas turbine. Medium Btu syngas streams result in a 

higher mass flow than natural gas to provide the same heat content to the gas turbine. Some gas 

turbine designs may need to extract air to maintain stable compressor or turbine operation in 

response to increased fuel flow rates. Other gas turbines may balance air extraction against 
Cost and Performance Comparison of Fossil Energy Power Plants 

53 

injection of all of the available nitrogen from the ASU. The amount of air extracted can also be 

varied as the ambient temperature changes at a given site to optimize year-round performance. 

An important aspect of air-integrated designs is the need to efficiently recover the heat of 

compression contained in the air extracted from the gas turbine. Extraction air temperature is 

normally in the range 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 gas turbine 

with a gas-to-gas heat exchanger. 

Elevated Pressure ASU Experience in Gasification 

The Buggenum, Netherlands unit built for Demkolec was the first elevated-pressure, fully 

integrated ASU to be constructed. It was designed to produce up to 1,796 tonnes/day 

(1,980 TPD) of 95 percent purity oxygen for a Shell coal-based gasification unit that fuels a 

Siemens V94.2 gas turbine. In normal operation at the Buggenum plant the ASU receives all of 

its air supply from and sends all residual nitrogen to the gas turbine. 

The Polk County, Florida ASU for the Tampa Electric IGCC is also an elevated-pressure, 

95 percent purity oxygen design that provides 1,832 tonnes/day (2,020 TPD) of oxygen to a GEE 

coal-based gasification unit, which fuels a General Electric 7FA gas turbine. All of the nitrogen 

produced in the ASU is used in the gas turbine. The original design did not allow for air 

extraction from the combustion turbine. After a combustion turbine 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. [29] 

ASU Basis 

For this study, air integration is used for the non-carbon capture cases only. In the carbon 

capture cases, once the syngas is diluted to the target heating value, all of the available 

combustion air is required to maintain mass flow through the turbine and hence maintain power 

output. 

The amount of air extracted from the gas turbine in the non-capture cases is determined through 

a process that includes the following constraints: 

• The combustion turbine output must be maintained at 232 MW. 

• The diluted syngas must meet heating value requirements specified by a combustion 

turbine vendor, which ranged from 4.5-4.8 MJ/Nm3

 (120-128 Btu/scf) (LHV). 

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 combustion turbine 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. [30, 31] 
Cost and Performance Comparison of Fossil Energy Power Plants 

54 

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, % 4.1 4.9 6.7 

Air Provided to ASU, % of ASU Total 15.7 22.3 31.0 

Air Separation Plant Process Description [32] 

The air separation plant is designed to produce 95 mole percent O2 for use in the gasifier. The 

plant is designed with two production trains, one for each gasifier. The air compressor is 

powered by an electric motor. Nitrogen is also recovered, compressed, and used as dilution in 

the gas turbine 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 gas turbine (non-CO2 capture cases only). The remaining air is supplied from 

a stand-alone compressor. Air to the stand-alone compressor is first filtered in a suction filter 

upstream of the compressor. This air filter removes particulate, which may tend to cause 

compressor wheel erosion and foul intercoolers. The filtered air is then compressed in the 

centrifugal compressor, with intercooling between each stage. 

Air from the stand-alone compressor is combined with the extraction air, and the combined 

stream is cooled and fed to an adsorbent-based pre-purifier system. The adsorbent removes 

water, carbon dioxide, and C4+ saturated hydrocarbons in the air. After passing through the 

adsorption beds, the air is filtered with a dust filter to remove any adsorbent fines that may be 

present. Downstream of the dust filter a small stream of air is withdrawn to supply the 

instrument air requirements of the ASU. 

Regeneration of the adsorbent in the pre-purifiers is accomplished by passing a hot nitrogen 

stream through the off-stream bed(s) in a direction countercurrent to the normal airflow. The 

nitrogen is heated against extraction steam (1.7 MPa [250 psia]) in a shell and tube heat 

exchanger. The regeneration nitrogen drives off the adsorbed contaminants. Following 

regeneration, the heated bed is cooled to near normal operating temperature by passing a cool 

nitrogen stream through the adsorbent beds. The bed is re-pressurized with air and placed on 

stream so that the current on-stream bed(s) can be regenerated. 

The air from the pre-purifier is then split into three streams. About 70 percent of the air is fed 

directly to the cold box. About 25 percent of the air is compressed in an air booster compressor. 

This boosted air is then cooled in an aftercooler against cooling water in the first stage and 

against chilled water in the second stage before it is fed to the cold box. The chiller utilizes low 

pressure process steam at 0.3 MPa (50 psia). The remaining 5 percent of the air is fed to a 

turbine-driven, single-stage, centrifugal booster compressor. This stream is cooled in a shell and 

tube aftercooler against cooling water before it is fed to the cold box. 

All three air feeds are cooled in the cold box to cryogenic temperatures against returning product 

oxygen and nitrogen streams in plate-and-fin heat exchangers. The large air stream is fed 
Cost and Performance Comparison of Fossil Energy Power Plants 

55 

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 air feed before being 

warmed to ambient temperature. The gaseous oxygen exits the cold box and is fed to the 

centrifugal compressor with intercooling between each stage of compression. The compressed 

oxygen is then fed to the gasification unit. 

Nitrogen is produced from the cold box at two pressure levels. Low-pressure nitrogen is split 

into two streams. The majority of the low-pressure nitrogen is compressed and fed to the gas 

turbine as diluent nitrogen. A small portion of the nitrogen is used as the regeneration gas for the 

pre-purifiers and recombined with the diluent nitrogen. A high-pressure nitrogen stream is also 

produced from the cold box and is further compressed before it is also supplied to the gas 

turbine.

Exhibit 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

1

2

15

12

10

3

5

7

6

8 9
Cost and Performance Comparison of Fossil Energy Power Plants 

56 

3.1.3 WATER GAS SHIFT REACTORS

Selection of Technology - In the cases with CO2 separation and capture, the gasifier product 

must be converted to hydrogen-rich syngas. The first step is to convert most of the syngas 

carbon monoxide (CO) to hydrogen and CO2 by reacting the CO with water over a bed of 

catalyst. The H2O:CO molar ratio in the shift reaction, shown below, is adjusted to 

approximately 2: 1 by the addition of steam to the syngas stream thus promoting a high 

conversion of CO. In the cases without CO2 separation and capture, CO shift convertors are not 

required. 

Water Gas Shift: CO + H2O ↔ CO2 + H2

The CO shift converter can be located either upstream of the acid gas removal step (sour gas 

shift) or immediately downstream (sweet gas shift). If the CO converter is located downstream 

of the acid gas removal, 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 acid gas removal, then the gasifier 

product would first have to be cooled and the free water separated and treated. Then additional 

steam would have to be generated and re-injected into the CO converter feed to meet the required 

water-to-gas ratio. If the CO converter is located upstream of the acid gas removal 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 acid gas removal unit and is referred to as sour gas shift (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 Shell and GEE gasifier cases. In the CoP case, a 

third shift reactor is added to each path to increase the CO conversion. Even with the third 

reactor added, CO2 capture is only 88.4 percent in the CoP case because of the relatively high 

amount of CH4 present in the syngas. 

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 IP steam which then passes through the reheater 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 96 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 MERCURY REMOVAL

An IGCC power plant has the potential of removing mercury in a more simple and cost-effective 

manner than conventional PC plants. This is because mercury can be removed from the syngas 

at elevated pressure and prior to combustion so that syngas volumes are much smaller than flue 

gas volumes in comparable PC cases. A conceptual design for a carbon bed adsorption system 

was developed for mercury control in the IGCC plants being studied. Data on the performance 

of carbon bed systems were obtained from the Eastman Chemical Company, which uses carbon 
Cost and Performance Comparison of Fossil Energy Power Plants 

57 

beds at its syngas facility in Kingsport, Tennessee.[12] The coal mercury content (0.15 ppm dry) 

and carbon bed removal efficiency (95 percent) were discussed previously in Section 2.4. IGCCspecific design considerations are discussed below. 

Carbon Bed Location – The packed carbon bed vessels are located upstream of the sulfur 

recovery unit and syngas enters at a temperature near 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. [33] Eastman Chemical also operates their beds ahead of their sulfur 

recovery unit at a temperature of 30°C (86°F). [12] 

Consideration was also given to locating the beds downstream of the sulfur recovery unit (SRU). 

However, it was felt that removing the mercury and other contaminants before the sulfur 

recovery unit 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. [12] 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 [33] 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. [34] These parameters determined the size of the 

vessels and the amount of carbon required. Each gasifier train has one mercury removal bed and 

there are two gasifier trains in each IGCC case, resulting in two carbon beds per case. 

Carbon Replacement Time – Eastman Chemicals replaces its bed every 18 to 24 months. [12] 

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%. [35] The mercury laden carbon is 

considered to be a hazardous waste, and the disposal cost estimate reflects this categorization. 

3.1.5 ACID GAS REMOVAL (AGR) PROCESS SELECTION

Gasification of coal to generate power produces a syngas that must be treated prior to further 

utilization. A portion of the treatment consists of acid gas removal (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. 
Cost and Performance Comparison of Fossil Energy Power Plants 

58 

COS Hydrolysis 

The use of COS hydrolysis pretreatment in the feed to the acid gas removal process provides a 

means to reduce the COS concentration. This method was first commercially proven at the 

Buggenum plant, and was also used at both the Tampa Electric and Wabash River IGCC 

projects. Several catalyst manufacturers including Haldor Topsoe and Porocel offer a catalyst 

that promotes the COS hydrolysis reaction. The non-carbon capture COS hydrolysis reactor 

designs are based on information from Porocel. In cases with carbon 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. 

Sulfur Removal 

Hydrogen sulfide removal generally consists of absorption by a regenerable solvent. The most 

commonly used technique is based on countercurrent contact with the solvent. Acid-gas-rich 

solution from the absorber is stripped of its acid gas in a regenerator, usually by application of 

heat. The regenerated lean solution is then cooled and recirculated to the top of the absorber, 

completing the cycle. Exhibit 3-3 is a simplified diagram of the AGR process. [36] 

There are well over 30 AGR processes in common commercial use throughout the oil, chemical, 

and natural gas industries. However, in a 2002 report by SFA Pacific a list of 42 operating and 

planned gasifiers shows that only six AGR processes are represented: Rectisol, Sulfinol, 

methyldiethanolamine (MDEA), Selexol, aqueous di-isoproponal (ADIP) amine and 

FLEXSORB. [38] These processes can be separated into three general types: chemical reagents, 

physical solvents, and hybrid solvents. 
Cost and Performance Comparison of Fossil Energy Power Plants 

59 

Exhibit 3-3 Flow Diagram for a Conventional AGR Unit 

Treated 

Gas

Cooler

Lean 

Solvent

L/R 

Exchanger

Rich Solvent

Absorber

Lean Solvent

Pump

Reboiler

Stripper

Acid 

Gas

Condenser

Feed 

Gas

Treated 

Gas

Cooler

Lean 

Solvent

L/R 

Exchanger

Rich Solvent

Absorber

Lean Solvent

Pump

Reboiler

Stripper

Acid 

Gas

Condenser

Feed 

Gas

Chemical Solvents 

Frequently used for acid gas removal, 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. 

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 low pressure and heated in the 

stripper to reverse the reactions and strip the acid gas. The acid-gas-lean solution leaves the 

bottom of the regenerator stripper and is cooled, pumped to the required pressure and 

recirculated back to the absorber. For some amines, a filter and a separate reclaiming section 

(not shown) are needed to remove undesirable reaction byproducts. 
Cost and Performance Comparison of Fossil Energy Power Plants 

60 

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 scf acid gas 

per gallon of solution circulated. Steam consumption can vary widely also: 0.7 to 1.5 pounds 

per gallon of liquid is typical, with 0.8 to 0.9 being a typical “good” value. Case 3, 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 

Physical solvents involve absorption of acid gases into certain organic solvents that have a high 

solubility for acid gases. As the name implies, physical solvents involve only the physical 

solution of acid gas – the acid gas loading in the solvent is proportional to the acid gas partial 

pressure (Henry’s Law). Physical solvent absorbers are usually operated at lower temperatures 

than is the case for chemical solvents. The solution step occurs at high pressure and at or below 

ambient temperature while the regeneration step (dissolution) occurs by pressure letdown and 

indirect stripping with low-pressure 0.45 MPa (65 psia) steam. It is generally accepted that 

physical solvents become increasingly economical, and eventually superior to amine capture, as 

the partial pressure of acid gas in the syngas increases. 

The physical solvents are regenerated by multistage flashing to low pressures. Because the 

solubility of acid gases increases as the temperature decreases, absorption is generally carried out 

at lower temperatures, and refrigeration is often required. 

Most physical solvents are capable of removing organic sulfur compounds. Exhibiting higher 

solubility of H2S than CO2, they can be designed for selective H2S or total acid gas removal. In 
Cost and Performance Comparison of Fossil Energy Power Plants 

61 

applications where CO2 capture is desired the CO2 is flashed off at various pressures, which 

reduces the compression work and parasitic power load associated with sequestration. 

Physical solvents co-absorb heavy hydrocarbons from the feed stream. Since heavy 

hydrocarbons cannot be recovered by flash regeneration, they are stripped along with the acid 

gas during heated regeneration. These hydrocarbon losses result in a loss of valuable product 

and may lead to CO2 contamination. 

Several physical solvents that use anhydrous organic solvents have been commercialized. They 

include the Selexol process, which uses dimethyl ether of polyethylene glycol as a solvent; 

Rectisol, with methanol as the solvent; Purisol, which uses N-methyl-2-pyrrolidone (NMP) as a 

solvent; and the propylene-carbonate process. 

Exhibit 3-5 is a simplified flow diagram for a physical reagent type acid gas removal process. 

[36] Common physical solvent processes, along with their licensors, are listed in Exhibit 3-6. 

Exhibit 3-5 Physical Solvent AGR Process Simplified Flow Diagram 

Treated 

Gas

Cooler

Lean 

Solvent

L/R 

Exchanger

Rich Solvent

Feed 

Gas

Absorber

Lean Solvent

Pump

Reboiler

Stripper

Acid 

Gas

Condenser

Flash 

Gas

Treated 

Gas

Cooler

Lean 

Solvent

L/R 

Exchanger

Rich Solvent

Feed 

Gas

Absorber

Lean Solvent

Pump

Reboiler

Stripper

Acid 

Gas

Condenser

Flash 

Gas

Hybrid Solvents 

Hybrid solvents combine the high treated-gas purity offered by chemical solvents with the flash 

regeneration and lower energy requirements of physical solvents. Some examples of hybrid 

solvents are Sulfinol, Flexsorb PS, and Ucarsol LE. 

Sulfinol is a mixture of sulfolane (a physical solvent), diisopropanolamine (DIPA) or MDEA 

(chemical solvent), and water. DIPA is used when total acid gas removal is specified, while 

MDEA provides for selective removal of H2S. 
Cost and Performance Comparison of Fossil Energy Power Plants 

62 

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 acid gas removal, are formulated to remove 

mercaptans from feed gas. 

Mixed chemical and physical solvents combine the features of both systems. The mixed solvent 

allows the solution to absorb an appreciable amount of gas at high pressure. The amine portion 

is effective as a reagent to remove the acid gas to low levels when high purity is desired. 

Mixed solvent processes generally operate at absorber temperatures similar to those of the 

amine-type chemical solvents and do not require refrigeration. They also retain some advantages 

of the lower steam requirements typical of the physical solvents. Common mixed chemical and 

physical solvent processes, along with their licensors, are listed in Exhibit 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 [36]. The solubility is expressed as standard cubic feet of gas per gallon liquid per 

atmosphere gas partial pressure. 

The figure illustrates the relative solubilities of CO2 and H2S in different solvents and the effects 

of temperature. More importantly, it shows an order of magnitude higher solubility of H2S over 

CO2 at a given temperature, which gives rise to the selective absorption of H2S in physical 

solvents. It also illustrates that the acid gas solubility in physical solvents increases with lower 

solvent temperatures. 
Cost and Performance Comparison of Fossil Energy Power Plants 

63 

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 Comparison of Fossil Energy Power Plants 

64 

The ability of a process to selectively absorb H2S may be further enhanced by the relative 

absorption rates of H2S and CO2. Thus, some processes, besides using equilibrium solubility 

differences, will use absorption rate differences between the two acid gases to achieve 

selectivity. This is particularly true of the amine processes where the CO2 and H2S absorption 

rates are very different. 

CO2 Capture 

A two-stage Selexol process is used for all IGCC capture cases in this study. A brief process 

description follows. 

Untreated syngas enters the first of two absorbers where H2S is preferentially removed using 

loaded solvent from the CO2 absorber. The gas exiting the H2S absorber passes through the 

second absorber where CO2 is removed using first flash regenerated, chilled solvent followed by 

thermally regenerated solvent added near the top of the column. The treated gas exits the 

absorber and is sent either directly to the combustion turbine or is partially humidified prior to 

entering the combustion turbine. A portion of the gas can also be used for coal drying, when 

required. 

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 combustion turbine. 

The solvent exiting the H2S concentrator is sent to the stripper where the absorbed gases are 

liberated by hot gases flowing up the column from the steam heated reboiler. Water in the 

overhead vapor from the stripper is condensed and returned as reflux to the stripper or exported 

as necessary to maintain the proper water content of the lean solvent. The acid gas from the 

stripper is sent to the Claus plant for further processing. The lean solvent exiting the stripper is 

first cooled by providing heat to the rich solvent, then further cooled by exchange with the 

product gas and finally chilled in the lean chiller before returning to the top of the CO2 absorber. 

AGR/Gasifier Pairings 

There are numerous commercial AGR processes that could meet the sulfur environmental target 

of this study. The most frequently used AGR systems (Selexol, Sulfinol, MDEA, and Rectisol) 

have all been used with the Shell and GE gasifiers in various applications. Both existing E-Gas 

gasifiers use MDEA, but could in theory use any of the existing AGR technologies. [36] The 

following selections were made for the AGR process in non-CO2 capture cases: 
Cost and Performance Comparison of Fossil Energy Power Plants 

65 

• 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. 

[37] 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. 

• Shell gasifier: The Sulfinol process was chosen for this case because it is a Shell owned 

technology. While the Shell gasifier can and has been used with other AGR processes, it 

was concluded the most likely pairing would be with the Sulfinol process. 

The two-stage Selexol process is used in all three cases that require carbon 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.” [38] 

3.1.6 SULFUR RECOVERY/TAIL GAS CLEANUP PROCESS SELECTION

Currently, most of the world’s sulfur is produced from the acid gases coming from gas treating. 

The Claus process remains the mainstay for sulfur recovery. Conventional three-stage Claus 

plants, with indirect reheat and feeds with a high H2S content, can approach 98 percent sulfur 

recovery efficiency. However, since environmental regulations have become more stringent, 

sulfur recovery plants are required to recover sulfur with over 99.8 percent efficiency. To meet 

these stricter regulations, the Claus process underwent various modifications and add-ons. 

The add-on modification to the Claus plant selected for this 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 

The Claus process converts H2S to elemental sulfur via the following reactions: 

H2S + 3/2 O2 ↔ H2O + SO2

2H2S + SO2 ↔ 2H2O + 3S 

The second reaction, the Claus reaction, is equilibrium limited. The overall reaction is: 

3H2S + 3/2 O2 ↔ 3H2O + 3S 

The sulfur in the vapor phase exists as S2, S6, and S8 molecular species, with the S2 predominant 

at higher temperatures, and S8 predominant at lower temperatures. 

A simplified process flow diagram of a typical three-stage Claus plant is shown in Exhibit 3-9. 

[38] One-third of the H2S is burned in the furnace with oxygen from the air to give sufficient 

SO2 to react with the remaining H2S. Since these reactions are highly exothermic, a waste heat 

boiler that recovers this heat to generate high-pressure steam usually follows the furnace. Sulfur 

is condensed in a condenser that follows the high-pressure steam recovery section. Low-pressure 
Cost and Performance Comparison of Fossil Energy Power Plants 

66 

steam is raised in the condenser. The tail gas from the first condenser then goes to several 

catalytic conversion stages, usually 2 to 3, where the remaining sulfur is recovered via the Claus 

reaction. Each catalytic stage consists of gas preheat, a catalytic reactor, and a sulfur condenser. 

The liquid sulfur goes to the sulfur pit, while the tail gas proceeds to the incinerator or for further 

processing in a TGTU. 

Claus Plant Sulfur Recovery Efficiency 

The Claus reaction is equilibrium limited, and sulfur conversion is sensitive to the reaction 

temperature. The highest sulfur conversion in the thermal zone is limited to about 75 percent. 

Typical furnace temperatures are in the range from 1093 to 1427°C (2000 to 2600°F), and as the 

temperature decreases, conversion increases dramatically. 

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. 
Cost and Performance Comparison of Fossil Energy Power Plants 

67 

Oxygen-Blown Claus 

Large diluent streams in the feed to the Claus plant, such as N2 from combustion air, or a high 

CO2 content in the feed gas, lead to higher cost Claus processes and any add-on or tail gas units. 

One way to reduce diluent flows through the Claus plant and to obtain stable temperatures in the 

furnace for dilute H2S streams is the oxygen-blown Claus process. 

The oxygen-blown Claus process was originally developed to increase capacity at existing 

conventional Claus plants and to increase flame temperatures of low H2S content gases. The 

process has also been used to provide the capacity and operating flexibility for sulfur plants 

where the feed gas is variable in flow and composition such as often found in refineries. The 

application of the process has now been extended to grass roots installations, even for rich H2S 

feed streams, to provide operating flexibility at lower costs than would be the case for 

conventional Claus units. At least four of the 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 percent O2 in the oxidant feed stream. Although oxygen enrichment has many benefits, 

its primary benefit for lean H2S feeds is a stable furnace temperature. Sulfur recovery is not 

significantly enhanced by oxygen enrichment. Because the IGCC process already requires an 

ASU, the oxygen-blown Claus plant was chosen for all cases. 

Tail Gas Treating 

In many refinery and other conventional Claus applications, tail gas treating involves the 

removal of the remaining sulfur compounds from gases exiting the sulfur recovery unit. Tail gas 

from a typical Claus process, whether a conventional Claus or one of the extended versions of 

the process, usually contains small but varying quantities of COS, CS2, H2S, SO2, and elemental 

sulfur vapors. In addition, there may be H2, CO, and CO2 in the tail gas. In order to remove the 

rest of the sulfur compounds from the tail gas, all of the sulfur-bearing species must first be 

converted to H2S. Then, the resulting H2S is absorbed into a solvent and the clean gas vented or 

recycled for further processing. The clean gas resulting from the hydrolysis step can undergo 

further cleanup in a dedicated absorption unit or be integrated with an upstream AGR unit. The 

latter option is particularly suitable with physical absorption solvents. The approach of treating 

the tail gas in a dedicated amine absorption unit and recycling the resulting acid gas to the Claus 

plant is the one used by the Shell Claus Off-gas Treating (SCOT) process. With tail gas 

treatment, Claus plants can achieve overall removal efficiencies in excess of 99.9 percent. 

In the case of IGCC applications, the tail gas from the Claus plant can be catalytically 

hydrogenated and then recycled back into the system with the choice of location being 

technology dependent, or it can be treated with a SCOT-type process. In the two GEE gasifier 

cases the Claus plant tail gas is hydrogenated, water is separated, the tail gas is compressed and 

returned to the Selexol process for further treatment. GEE experience at the Polk Power Station 

is not relevant to this study since the acid gas is converted to sulfuric acid rather than sulfur and 

the tail gas, containing 150-250 ppm SO2, is discharged through a dedicated stack. [39] In the 

two CoP cases the tail gas is treated in the same manner as in the GEE cases except that the 

recycle endpoint is the gasifier rather than the AGR process. This method is the same as 
Cost and Performance Comparison of Fossil Energy Power Plants 

68 

practiced at the CoP Wabash River plant. [40] The two recycle points were chosen based on 

conversations with the gasifier technology vendors. 

In the two Shell cases the Claus tail gas is catalytically hydrogenated and then treated in an 

amine-based tail gas cleanup process. The bulk of the H2S in the tail gas is captured and 

recycled back to the Claus plant inlet gas stream. The sweet gas from the TGTU is combined 

with a slipstream of clean syngas and the combined stream is combusted in an incinerator. The 

hot, inert gases from the incinerator are used to dry the feed coal and then vented to atmosphere. 

Since the Shell Puertollano plant uses a combination of natural gas combustion and IP steam to 

dry their coal, their tail gas treatment procedure is different than employed in this study. The 

Claus plant tail gas is hydrogenated and recycled, but the recycle endpoint is not specified. [41] 

Flare Stack 

A self-supporting, refractory-lined, carbon steel flare stack is typically provided to combust and 

dispose of unreacted gas during startup, shutdown, and upset conditions. However, in 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. 

3.1.7 SLAG HANDLING

The slag handling system conveys, stores, and disposes of slag removed from the gasification 

process. Spent material drains from the gasifier bed into a water bath in the bottom of the 

gasifier vessel. A slag crusher receives slag from the water bath and grinds the material into peasized fragments. A slag/water slurry that is between 5 and 10 percent solids leaves the gasifier 

pressure boundary through either a proprietary pressure letdown device (CoP) or through the use 

of lockhoppers (GEE and Shell) to a series of dewatering bins. 

The general aspects of slag handling are the same for all three technologies. The slag is 

dewatered, the water is clarified and recycled and the dried slag is transferred to a storage area 

for disposal. The specifics of slag handling vary among the gasification technologies regarding 

how the water is separated and the end uses of the water recycle streams. 

In this 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

Combustion Turbine 

The gas turbine generator selected for this application is representative of the advanced F Class 

turbines. This machine is an axial flow, single spool, and constant speed unit, with variable inlet 

guide vanes. The turbine includes advanced bucket cooling techniques, compressor aerodynamic 

design and advanced alloys, enabling a higher firing temperature than the previous generation 

machines. The standard production version of this machine is fired with natural gas and is also 
Cost and Performance Comparison of Fossil Energy Power Plants 

69 

commercially offered for use with IGCC derived syngas, although only earlier versions of the 

turbine are currently operating on syngas. For the purposes of this study, it was assumed that the 

advanced F Class turbine will be commercially available to support a 2010 startup date on both 

conventional and high hydrogen content syngas representative of the cases with CO2 capture. 

High H2 fuel combustion issues like flame stability, flashback and NOx formation were assumed 

to be solved in the time frame needed to support deployment. However, because these are firstof-a-kind applications, process contingencies were included in the cost estimates as described in 

Section 2.7. Performance typical of an advanced F class turbine on natural gas at ISO conditions 

is presented in Exhibit 3-10. 

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. 

Combustion Turbine Package Scope of Supply 

The combustion turbine (CT) is typically supplied in several fully shop-fabricated modules, 

complete with all mechanical, electrical and control systems as required for CT operation. Site 

CT installation involves module inter-connection, and linking CT modules to the plant systems. 

The CT package scope of supply for combined cycle application, while project specific, does not 

vary much from project-to-project. The typical scope of supply is presented in Exhibit 3-11. 
Cost and Performance Comparison of Fossil Energy Power Plants 

70 

Exhibit 3-11 Combustion Turbine Typical Scope of Supply 

System System Scope 

1.0 ENGINE 

ASSEMBLY 

Coupling to Generator, Dry Chemical Exhaust Bearing Fire Protection 

System, Insulation Blankets, Platforms, Stairs and Ladders

1.1 

Engine 

Assembly with 

Bedplate 

Variable Inlet Guide, Vane System Compressor, Bleed System, Purge Air 

System, Bearing Seal Sir System, Combustors, Dual Fuel Nozzles Turbine 

Rotor Air Cooler 

1.2 

Walk-in 

acoustical 

enclosure 

HVAC, Lighting, and Low Pressure CO2 Fire Protection System 

2.0 MECHANICAL 

PACKAGE 

HVAC and Lighting, Air Compressor for Pneumatic System, Low Pressure 

CO2 Fire Protection System

2.1 

2.2 

Lubricating Oil 

System and 

Control Oil 

System 

Lube Oil Reservoir, Accumulators, 2x100% AC Driven Oil Pumps DC 

Emergency Oil Pump with Starter, 2x100% Oil Coolers, Duplex Oil Filter, 

Oil Temperature and Pressure Control Valves, Oil Vapor Exhaust Fans and 

Demister Oil Heaters Oil Interconnect Piping (SS and CS) Oil System 

Instrumentation Oil for Flushing and First Filling 

3.0 ELECTRICAL 

PACKAGE 

HVAC and Lighting, AC and DC Motor Control Centers, Generator 

Voltage Regulating Cabinet, Generator Protective Relay Cabinet, DC 

Distribution Panel, Battery Charger, Digital Control System with Local 

Control Panel (all control and monitoring functions as well as data logger 

and sequence of events recorder), Control System Valves and 

Instrumentation Communication link for interface with plant DCS 

Supervisory System, Bentley Nevada Vibration Monitoring System, Low 

Pressure CO2 Fire Protection System, Cable Tray and Conduit Provisions 

for Performance Testing including Test Ports, Thermowells, 

Instrumentation and DCS interface cards

4.0 

INLET AND 

EXHAUST 

SYSTEMS 

Inlet Duct Trash Screens, Inlet Duct and Silencers, Self Cleaning Filters, 

Hoist System For Filter Maintenance, Evaporative Cooler System, Exhaust 

Duct Expansion Joint, Exhaust Silencers Inlet and Exhaust Flow, Pressure 

and Temperature Ports and Instrumentation

5.0 FUEL 

SYSTEMS 

5.1 Fuel Syngas 

System 

Gas Valves Including Vent, Throttle and Trip Valves Gas Filter/Separator 

Gas Supply Instruments and Instrument Panel 

5.2 Backup Fuel 

System Specific to backup fuel type 
Cost and Performance Comparison of Fossil Energy Power Plants 

71 

System System Scope 

6.0 STARTING 

SYSTEM 

Enclosure, Starting Motor or Static Start System, Turning Gear and Clutch 

Assembly, Starting Clutch Torque Converter

7.0 GENERATOR 

Static or Rotating Exciter (Excitation transformer to be included for a static 

system), Line Termination Enclosure with CTs, VTs, Surge Arrestors, and 

Surge Capacitors, Neutral Cubicle with CT, Neutral Tie Bus, Grounding 

Transformer, and Secondary Resistor, Generator Gas Dryer, Seal Oil 

System (including Defoaming Tank, Reservoir, Seal Oil Pump, Emergency 

Seal Oil Pump, Vapor Extractor, and Oil Mist Eliminator), Generator 

Auxiliaries Control Enclosure, Generator Breaker, Iso-Phase bus connecting 

generator and breaker, Grounding System Connectors

7.1 Generator 

Cooling 

TEWAC System (including circulation system, interconnecting piping and 

controls), or Hydrogen Cooling System (including H2 to Glycol and Glycol 

to Air heat exchangers, liquid level detector circulation system, 

interconnecting piping and controls) 

8.0 Miscellaneous 

Interconnecting Pipe, Wire, Tubing and Cable, Instrument Air System 

Including Air Dryer, On Line and Off Line Water Wash System, LP CO2

Storage Tank, Drain System, Drain Tanks, Coupling, Coupling Cover and 

Associated Hardware

CT Firing Temperature Control Issue for Low Calorific Value Fuel 

A gas turbine when fired on low calorific value syngas has the potential to increase power output 

due to the increase in flow rate through the turbine. The higher turbine flow and moisture 

content of the combustion products can contribute to overheating of turbine components, affect 

rating criteria for the parts lives, and require a reduction in syngas firing temperatures (compared 

to the natural gas firing) to maintain design metal temperature. [42] Uncontrolled syngas firing 

temperature could result in more than 50 percent life cycle reduction of stage 1 buckets. Control 

systems for syngas applications include provisions to compensate for these effects by 

maintaining virtually constant generation output for the range of the specified ambient 

conditions. Inlet guide vanes (IGV) and firing temperature are used to maintain the turbine 

output at the maximum torque rating, producing a flat rating up to the IGV full open position. 

Beyond the IGV full open position, flat output may be extended to higher ambient air 

temperatures by steam/nitrogen injection. 

In this study the firing temperature (defined as inlet rotor temperature) using natural gas in 

NGCC applications is 1399°C (2550°F) while the firing temperature in the non-capture IGCC 

cases is 1343-1354°C (2450-2470°F) and in the CO2 capture cases is 1318-1327°C (2405-

2420°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 8-10 volume 

percent (vol%) in the non-capture cases to 14-16 vol% in the capture cases. The decrease in 

temperature also results in the lower temperature steam cycle in the CO2 capture cases 

(538°C/538°C [1000°F/1000°F] versus 566°C/566°C [1050°F/1050°F] for non-capture cases). 
Cost and Performance Comparison of Fossil Energy Power Plants 

72 

Combustion Turbine Syngas Fuel Requirements. 

Typical fuel specifications and contaminant levels for successful combustion turbine operation 

are provided in reference [43] and presented for F Class machines in Exhibit 3-12 and 

Exhibit 3-13. 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 3-12 Typical Fuel Specification for F-Class Machines 

Max Min 

LHV, kJ/m3 (Btu/scf) None 3.0 (100) 

Gas Fuel Pressure, MPa (psia) 3.1 (450) 

Gas Fuel Temperature, °C (°F) (1) Varies with gas 

pressure (2) 

Flammability Limit Ratio, Rich-to-Lean, 

Volume Basis (3) 2:2.1 

Sulfur (4) 

Notes: 

1. The maximum fuel temperature is defined in reference [44] 

2. To ensure that the fuel gas supply to the gas turbine is 100 percent free of liquids 

the minimum fuel gas temperature must meet the required superheat over the 

respective dew point. This requirement is independent of the hydrocarbon and 

moisture concentration. Superheat calculation shall be performed as described in 

GEI-4140G [43]. 

3. Maximum flammability ratio limit is not defined. Fuel with flammability ratio 

significantly larger than those of natural gas may require start-up fuel 

4. The quantity of sulfur in syngas is not limited by specification. Experience has 

shown that fuel sulfur levels up to 1 percent by volume do not significantly affect 

oxidation/corrosion rates. 

Normal Operation 

Inlet air is compressed in a single spool compressor to a pressure ratio of approximately 16:1. 

This pressure ratio was vendor specified and less than the 18.5:1 ratio used in natural gas 

applications. The majority of compressor discharge air remains on-board the machine and passes 

to the burner section to support combustion of the syngas. Compressed air is also used in burner, 

transition, and film cooling services. About 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. 
Cost and Performance Comparison of Fossil Energy Power Plants 

73 

Exhibit 3-13 Allowable Gas Fuel Contaminant Level for F-Class Machines 

Fuel Limit, ppmw 

Turbine Inlet Flow/Fuel Flow 

Turbine 

Inlet Limit, 

ppbw 50 12 4 

Lead 20 1.0 0.240 .080 

Vanadium 10 0.5 0.120 0.040 

Calcium 40 2.0 0.480 0.160 

Magnesium 40 2.0 0.480 0.160 

Sodium + Potassium 

Na/K = 28 (1) 20 1.0 0.240 0.080 

Na/K = 3 10 0.5 0.120 0.40 

Na/K ≤ 1 6 0.3 0.072 0.024 

Particulates Total (2) 600 30 7.2 2.4 

Above 10 microns 6 0.3 0.072 0.024 

Notes: 

1. Na/K=28 is nominal sea salt ratio 

2. The fuel gas delivery system shall be designed to prevent generation or admittance of 

solid particulate to the gas turbine gas fuel system 

Pressurized syngas is combusted in several (14) parallel diffusion combustors and syngas 

dilution is used to limit NOx formation. As described in Section 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 4.5-4.8 MJ/Nm3 (120-128 Btu/scf). The advantages of using 

nitrogen as the primary diluent include: 

• Nitrogen from the ASU is already partially compressed and using it for dilution 

eliminates wasting the compression energy. 

• Limiting the water content reduces the need to de-rate firing temperature, 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). 

• The low quality heat used in the syngas humidification process does not provide 

significant benefit to the process in other applications. 

• Nitrogen is not as efficient as water in limiting NOx emissions 
Cost and Performance Comparison of Fossil Energy Power Plants 

74 

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 599°C (1110°F) for non-CO2 capture cases and 566°C (1050°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

Heat Recovery Steam Generator 

The heat recovery steam generator (HRSG) is a horizontal gas flow, drum-type, multi-pressure 

design that is matched to the characteristics of the gas turbine exhaust gas when firing mediumBtu gas. High-temperature flue gas exiting the CT is conveyed through the HRSG to recover the 

large quantity of thermal energy that remains. Flue gas travels through the HRSG gas path and 

exits at 132°C (270°F) for all six IGCC cases. 

The high pressure (HP) drum produces steam at main steam pressure, while the intermediate 

pressure (IP) drum produces process steam and turbine dilution steam, if required. The HRSG 

drum pressures are nominally 12.4/2.9 MPa (1800/420 psia) for the HP/IP turbine sections, 

respectively. In addition to generating and superheating steam, the HRSG performs reheat duty 

for the cold/hot reheat steam for the steam turbine, provides condensate and feedwater heating, 

and also provides deaeration of the condensate. 

Natural circulation of steam is accomplished in the HRSG by utilizing differences in densities 

due to temperature differences of the steam. The natural circulation HRSG provides the most 

cost-effective and reliable design. 

The HRSG drums include moisture separators, internal baffles, and piping for feedwater/steam. 

All tubes, including economizers, superheaters, and headers and drums, are equipped with 

drains. 

Safety relief valves are furnished in order to comply with appropriate codes and ensure a safe 

work place. 

Superheater, boiler, and economizer sections are supported by shop-assembled structural steel. 

Inlet and outlet duct is provided to route the gases from the gas turbine outlet to the HRSG inlet 

and the HRSG outlet to the stack. A diverter valve is included in the inlet duct to bypass the gas 

when appropriate. Suitable expansion joints are also included. 

Steam Turbine Generator and Auxiliaries 

The steam turbine consists of an HP section, an IP section, and one double-flow low pressure 

(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. The LP turbine has a last stage bucket length of 76 cm (30 in). 

Main steam from the HRSG and gasifier island is combined in a header, and then passes through 

the stop valves and control valves and enters the turbine at either 12.4 MPa/566°C (1800 
Cost and Performance Comparison of Fossil Energy Power Plants 

75 

psig/1050°F) for the non-carbon capture cases, or 12.4 MPa/538°C (1800 psig/1000°F) for the 

carbon capture cases. The steam initially enters the turbine near the middle of the high-pressure 

span, flows through the turbine, and returns to the HRSG for reheating. The reheat steam flows 

through the reheat stop valves and intercept valves and enters the IP section at 2.6 to 2.9 

MPa/566°C (375 to 420 psig/1050°F) for the non-carbon capture cases or 2.6 to 2.9 MPa/538°C 

(375 to 420 psig/1000°F) for the carbon capture cases. After passing through the IP section, the 

steam enters a crossover pipe, which transports the steam to the LP section. The steam divides 

into two paths and flows through the LP sections, exhausting downward into the condenser. 

Turbine bearings are lubricated by a closed-loop, water-cooled, pressurized oil system. The oil 

is contained in a reservoir located below the turbine floor. During startup or unit trip an 

emergency oil pump mounted on the reservoir pumps the oil. When the turbine reaches 

95 percent of synchronous speed, the main pump mounted on the turbine shaft pumps oil. The 

oil flows through water-cooled heat exchangers prior to entering the bearings. The oil then flows 

through the bearings and returns by gravity to the lube oil reservoir. 

Turbine shafts are sealed against air in-leakage or steam blowout using a modern positive 

pressure variable clearance shaft sealing design arrangement connected to a low-pressure steam 

seal system. During startup, seal steam is provided from the main steam line. As the unit 

increases load, HP turbine gland leakage provides the seal steam. Pressure-regulating valves 

control the gland header pressure and dump any excess steam to the condenser. A steam packing 

exhauster maintains a vacuum at the outer gland seals to prevent leakage of steam into the 

turbine room. Any steam collected is condensed in the packing exhauster and returned to the 

condensate system. 

The generator is a hydrogen-cooled synchronous type, generating power at 24 kV. A static, 

transformer type exciter is provided. The generator is cooled with a hydrogen gas recirculation 

system using fans mounted on the generator rotor shaft. The heat absorbed by the gas is 

removed as it passes over finned tube gas coolers mounted in the stator frame. Gas is prevented 

from escaping at the rotor shafts by a closed-loop oil seal system. The oil seal system consists of 

storage tank, pumps, filters, and pressure controls, all skid-mounted. 

The steam turbine generator is controlled by a triple-redundant, microprocessor-based electrohydraulic control system. The system provides digital control of the unit in accordance with 

programmed control algorithms, color CRT operator interfacing, and datalink interfaces to the 

balance-of-plant DCS, and incorporates on-line repair capability. 

Condensate System 

The condensate system transfers condensate from the condenser hotwell to the deaerator, through 

the gland steam condenser, gasifier, and the low-temperature economizer section in the HRSG. 

The system consists of one main condenser; two 50 percent capacity, motor-driven, vertical 

condensate pumps; one gland steam condenser; and a low-temperature tube bundle in the HRSG. 

Condensate is delivered to a common discharge header through separate pump discharge lines, 

each with a check valve and a gate valve. A common minimum flow recirculation line 

discharging to the condenser is provided to maintain minimum flow requirements for the gland 

steam condenser and the condensate pumps. 
Cost and Performance Comparison of Fossil Energy Power Plants 

76 

Feedwater System 

The function of the feedwater system is to pump the various feedwater streams from the 

deaerator storage tank in the HRSG to the respective steam drums. Two 50 percent capacity 

boiler feed pumps are provided for each of three pressure levels, HP, IP, and LP. Each pump is 

provided with inlet and outlet isolation valves, and outlet check valve. Minimum flow 

recirculation to prevent overheating and cavitation of the pumps during startup and low loads is 

provided by an automatic recirculation valve and associated piping that discharges back to the 

deaerator storage tank. Pneumatic flow control valves control the recirculation flow. 

The feedwater pumps are supplied with instrumentation to monitor and alarm on low oil 

pressure, or high bearing temperature. Feedwater pump suction pressure and temperature are 

also monitored. In addition, the suction of each boiler feed pump is equipped with a startup 

strainer. 

Main and Reheat Steam Systems 

The function of the main steam system is to convey main steam generated in the synthesis gas 

cooler (SGC) and HRSG from the HRSG superheater outlet to the HP turbine stop valves. The 

function of the reheat system is to convey steam from the HP turbine exhaust to the HRSG 

reheater, and to the turbine reheat stop valves. 

Main steam at approximately 12.4 MPa/566°C (1800 psig/1050°F) (non-carbon capture cases) or 

12.4 MPa/538°C (1800 psig/1000°F) (carbon 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 3.1 to 3.4 MPa/341°C (450 to 500 psia/645°F) exits 

the HP turbine, flows through a motor-operated isolation gate valve, to the HRSG reheater. Hot 

reheat steam at approximately 2.9 to 3.2 MPa/566°C (420 to 467 psia/1050°F) for non-carbon 

capture cases and 2.9 MPa/538°C (420 psia/1000°F) for carbon capture cases exits the HRSG 

reheater through a motor-operated gate valve and is routed to the IP turbines. 

Steam piping is sloped from the HRSG to the drip pots located near the steam turbine for 

removal of condensate from the steam lines. Condensate collected in the drip pots and in lowpoint drains is discharged to the condenser through the drain system. 

Steam flow is measured by means of flow nozzles in the steam piping. The flow nozzles are 

located upstream of any branch connections on the main headers. 

Safety valves are installed to comply with appropriate codes and to ensure the safety of 

personnel and equipment. 

Circulating Water System 

The circulating water system is a closed-cycle cooling water system that supplies cooling water 

to the condenser to condense the main turbine exhaust steam. The system also supplies cooling 

water to the AGR plant as required, and to the auxiliary cooling system. The auxiliary cooling 

system is a closed-loop process that utilizes a higher quality water to remove heat from 

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. 
Cost and Performance Comparison of Fossil Energy Power Plants 

77 

The system consists of two 50 percent capacity vertical circulating water pumps, a mechanical 

draft evaporative cooling tower, and carbon steel cement-lined interconnecting piping. The 

pumps are single-stage vertical pumps. The piping system is equipped with butterfly isolation 

valves and all required expansion joints. The cooling tower is a multi-cell wood frame 

counterflow mechanical draft cooling tower. 

The condenser is a single-pass, horizontal type with divided water boxes. There are two separate 

circulating water circuits in each box. One-half of the condenser can be removed from service 

for cleaning or for plugging tubes. This can be done during normal operation at reduced load. 

The condenser is equipped with an air extraction system to evacuate the condenser steam space 

for removal of non-condensable gases during steam turbine operation and to rapidly reduce the 

condenser pressure from atmospheric pressure before unit startup and admission of steam to the 

condenser. 

Raw Water, Fire Protection, and Cycle Makeup Water Systems 

The raw water system supplies cooling tower makeup, cycle makeup, service water and potable 

water requirements. The water source is 50 percent from a POTW and 50 percent from 

groundwater. Booster pumps within the plant boundary provide the necessary pressure. 

The fire protection system provides water under pressure to the fire hydrants, hose stations, and 

fixed water suppression system within the buildings and structures. The system consists of 

pumps, underground and aboveground supply piping, distribution piping, hydrants, hose stations, 

spray systems, and deluge spray systems. One motor-operated booster pump is supplied on the 

intake structure of the cooling tower with a diesel engine backup pump installed on the water 

inlet line. 

The cycle makeup water system provides high quality demineralized water for makeup to the 

HRSG cycle, for steam injection ahead of the water gas shift reactors in CO2 capture cases, and 

for injection steam to the auxiliary boiler for control of NOx emissions, if required. 

The cycle makeup system consists of two 100 percent trains, each with a full-capacity activated 

carbon filter, primary cation exchanger, primary anion exchanger, mixed bed exchanger, recycle 

pump, and regeneration equipment. The equipment is skid-mounted and includes a control panel 

and associated piping, valves, and instrumentation. 

3.1.10 ACCESSORY ELECTRIC PLANT

The accessory electric plant consists of switchgear and control equipment, generator equipment, 

station service equipment, conduit and cable trays, and wire and cable. It also includes the main 

power transformer, all required foundations, and standby equipment. 

3.1.11 INSTRUMENTATION AND CONTROL

An integrated plant-wide distributed control system (DCS) is provided. The DCS is a redundant 

microprocessor-based, functionally distributed control system. The control room houses an array 

of multiple video monitor (CRT) and keyboard units. The CRT/keyboard units are the primary 

interface between the generating process and operations personnel. The DCS incorporates plant 

monitoring and control functions for all the major plant equipment. The DCS is designed to be 

operational and accessible 99.5 percent of the time it is required (99.5 percent availability). The 
Cost and Performance Comparison of Fossil Energy Power Plants 

78 

plant equipment and the DCS are designed for automatic response to load changes from 

minimum load to 100 percent. Startup and shutdown routines are manually implemented, with 

operator selection of modular automation routines available. The exception to this, and an 

important facet of the control system for gasification, is the critical controller system, which is a 

part of the license package from the gasifier supplier and is a dedicated and distinct hardware 

segment of the DCS. 

This critical controller system is used to control the gasification process. The partial oxidation of 

the fuel feed and oxygen feed streams to form a syngas product is a stoichiometric, temperatureand pressure-dependent reaction. The critical controller utilizes a redundant microprocessor 

executing calculations and dynamic controls at 100- to 200-millisecond intervals. The enhanced 

execution speeds as well as evolved predictive controls allow the critical controller to mitigate 

process upsets and maintain the reactor operation within a stable set of operating parameters. 
Cost and Performance Comparison of Fossil Energy Power Plants 

79 

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 [45]: 

• Quench: In this configuration, the hot syngas exiting the gasifier passes through a pool of 

water to quench the temperature to less than 260°C (500°F) before entering the syngas 

scrubber. It is the simplest and lowest capital cost design, but also the least efficient. 

• Radiant Only: In this configuration, the hot syngas exiting the gasifier passes through a 

radiant syngas cooler where it is cooled from about 1316°C (2400°F) to 816°C (1500°F), 

then through a water quench where the syngas is further cooled to about 204°C (400°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 cost of electricity. 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 Estimates provides a summary of capital and operating costs for Case 1. 
Cost and Performance Comparison of Fossil Energy Power Plants 

80 

• Process and System Description, Performance Results, Equipment List and Cost 

Estimates are repeated for Case 2. 

3.2.1 GASIFIER BACKGROUND

Development and Current Status [46] – Initial development of the GEE gasification 

technology (formerly licensed by Texaco and then ChevronTexaco) was conducted in the 1940s 

at Texaco’s Montebello, California laboratories. From 1946 to 1954 the Montebello pilot plant 

produced synthesis gas (hydrogen and carbon monoxide) by partial oxidation of a variety of 

feedstocks, including natural gas, oil, asphalt, coal tar, and coal. From 1956 to 1958, coal was 

gasified in a 91 tonne/day (100 TPD) Texaco coal gasifier at the Olin Mathieson Chemical Plant 

in Morgantown, West Virginia, for the production of ammonia. 

The oil price increases and supply disruptions of the 1970s renewed interest in the Texaco 

partial-oxidation process for gasification of coal or other solid opportunity fuels. Three 14 

tonne/day (15 TPD) pilot plants at the Montebello laboratories have been used to test numerous 

coals. Two larger pilot plants were also built. The first gasified 150 tonne/day (165 TPD) of 

coal and was built to test synthesis gas generation by Rührchemie and Rührkohle at Oberhausen, 

Germany, and included a synthesis gas cooler. The second gasified 172 tonne/day (190 TPD) of 

coal using a quench-only gasifier cooler and was built to make hydrogen at an existing TVA 

ammonia plant at Muscle Shoals, Alabama. These two large-scale pilot plants successfully 

operated for several years during the 1980s and tested a number of process variables and 

numerous coals. 

The first commercial Texaco coal gasification plant was built for Tennessee Eastman at 

Kingsport, Tennessee, and started up in 1983. To date, 24 gasifiers have been built in 12 plants 

for coal and petroleum coke. Several of the plants require a hydrogen-rich gas and therefore 

directly water quench the raw gas to add the water for shifting the CO to H2, and have no 

synthesis gas coolers. 

The Cool Water plant was the first commercial-scale Texaco coal gasification project for the 

electric utility industry. This facility gasified 907 tonne/day (1,000 TPD) (dry basis) of 

bituminous coal and generated 120 MW of electricity by IGCC operation. In addition, the plant 

was the first commercial-sized Texaco gasifier used with a synthesis gas cooler. The Cool Water 

plant operated from 1984 to 1989 and was a success in terms of operability, availability, and 

environmental performance. 

The Tampa Electric IGCC Clean Coal Technology Demonstration Project built on the Cool 

Water experience to demonstrate the use of the Texaco coal gasification process in an IGCC 

plant. The plant utilizes approximately 2,268 tonne/day (2,500 TPD) of coal in a single Texaco 

gasifier to generate a net of approximately 250 MWe. The syngas is cooled in a hightemperature radiant heat exchanger, generating high-pressure steam, and further cooled in 

convective heat exchangers (the radiant-convective configuration). The particles in the cooled 

gas are removed in a water-based scrubber. The cleaned gas then enters a hydrolysis reactor 

where COS is converted to H2S. After additional cooling, the syngas is sent to a conventional 

AGR unit, where H2S is absorbed by reaction with an amine solvent. H2S is removed from the 

amine by steam stripping and sent to a sulfuric acid plant. The cleaned gas is sent to a General 

Electric MS 7001FA combustion turbine. 
Cost and Performance Comparison of Fossil Energy Power Plants 

81 

The Delaware Clean Energy Project is a coke gasification and combustion turbine repowering of 

an existing 130 MW coke-fired boiler cogeneration power plant at the Motiva oil refinery in 

Delaware City, Delaware. The Texaco coal gasification process was modified to gasify 1,814 

tonne/day (2,000 TPD) of this low-quality petroleum coke. The plant is designed to use all the 

fluid petroleum coke generated at Motiva’s Delaware City Plant and produce a nominal 238,136 

kg/h (525,000 lb/h) of 8.6 MPa (1250 psig) steam, and 120,656 kg/h (266,000 lb/h) of 1.2 MPa 

(175 psig) steam for export to the refinery and the use/sale of 120 MW of electrical power. 

Environmentally, these new facilities help satisfy tighter NOx and SO2 emission limitations at the 

Delaware City Plant. 

Gasifier Capacity – The largest GEE gasifier is the unit at Tampa Electric, which consists of the 

radiant-convective configuration. The daily coal-handling capacity of this unit is 2,268 tonnes 

(2,500 tons) of bituminous coal. The dry gas production rate is 0.19 million Nm3/h (6.7 million 

scfh) with an energy content of about 1,897 million kJ/h (HHV) (1,800 million Btu/h). This size 

matches the F Class combustion turbines that are used at Tampa. 

Distinguishing Characteristics – A key advantage of the GEE coal gasification technology is 

the extensive operating experience at full commercial scale. Furthermore, Tampa Electric is an 

IGCC power generation facility, operated by conventional electric utility staff, and is 

environmentally one of the cleanest coal-fired power plants in the world. The GEE gasifier also 

operates at the highest pressure of the three gasifiers in this study, 5.6 MPa (815 psia) compared 

to 4.2 MPa (615 psia) for CoP and Shell. 

Entrained-flow gasifiers have fundamental environmental advantages over fluidized-bed and 

moving-bed gasifiers. They produce no hydrocarbon liquids, and the only solid waste is an inert 

slag. The relatively high H2/CO ratio and CO2 content of GEE gasification fuel gas helps 

achieve low nitrogen oxide (NOx) and CO emissions in even the higher-temperature advanced 

combustion turbines. 

The key disadvantages of the GEE coal gasification technology are the limited refractory life, the 

relatively high oxygen requirements and high waste heat recovery duty (synthesis gas cooler 

design). As with the other entrained-flow slagging gasifiers, the GEE process has this 

disadvantage due to its high operating temperature. The disadvantage is magnified in the singlestage, slurry feed design. The quench design significantly reduces the capital cost of syngas 

cooling, while innovative heat integration maintains good overall thermal efficiency although 

lower than the synthesis gas cooler design. Another disadvantage of the GEE process is the 

limited ability to economically handle low-rank coals relative to moving-bed and fluidized-bed 

gasifiers or to entrained-flow gasifiers with dry feed. For slurry fed entrained gasifiers using 

low-rank coals, developers of two-stage slurry fed gasifiers claim advantages over single-stage 

slurry fed. 

Important Coal Characteristics – The slurry feeding system and the recycle of process 

condensate water as the principal slurrying liquid make low levels of ash and soluble salts 

desirable coal characteristics for use in the GEE coal gasification process. High ash levels 

increase the ratio of water-to-carbon in the feed slurry, thereby increasing the oxygen 

requirements. The slurry feeding also favors the use of high-rank coals, such as bituminous coal, 

since their low inherent moisture content increases the moisture-free solids content of the slurry 

and thereby reduces oxygen requirements. 
Cost and Performance Comparison of Fossil Energy Power Plants 

82 

3.2.2 PROCESS DESCRIPTION

In this section the overall GEE gasification process is described. The system description follows 

the block flow diagram (BFD) in Exhibit 3-14 and stream numbers reference the same Exhibit. 

The tables in Exhibit 3-15 provide stream compositions, temperature, pressure, enthalpy and 

flow rates for the numbered streams in the BFD. 

Coal Grinding and Slurry Preparation 

Coal receiving and handling is common to all cases and was covered in Section 3.1.1. The 

receiving and handling subsystem ends at the coal silo. Coal is then fed onto a conveyor by 

vibratory feeders located below each silo. The conveyor feeds the coal to an inclined conveyor 

that delivers the coal to the rod mill feed hopper. The feed hopper provides a surge capacity of 

about two hours and contains two hopper outlets. Each hopper outlet discharges onto a weigh 

feeder, which in turn feeds a rod mill. Each rod mill is sized to process 55 percent of the coal 

feed requirements of the gasifier. The rod mill grinds the coal and wets it with treated slurry 

water transferred from the slurry water tank by the slurry water pumps. The coal slurry is 

discharged through a trommel screen into the rod mill discharge tank, and then the slurry is 

pumped to the slurry storage tanks. The dry solids concentration of the final slurry is 63 percent. 

The Polk Power Station operates at a slurry concentration of 62-68 percent using bituminous coal 

and CoP presented a paper showing the slurry concentration of Illinois No. 6 coal as 63 percent. 

[39, 47] 

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). 

Gasification 

This plant utilizes two gasification trains to process a total of 5,331 tonnes/day (5,876 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. 

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 

4,560 tonnes/day (5,025 TPD) of 95 mole percent oxygen to the gasifiers (stream 5) and the 

Claus plant (stream 3). Carbon conversion in the gasifier is assumed to be 98 percent including a 

fines recycle stream. 

The gasifier vessel is a refractory-lined, high-pressure combustion chamber. The coal slurry 

feedstock and oxygen are fed through a fuel injector at the top of the gasifier vessel. The coal 
Cost and Performance Comparison of Fossil Energy Power Plants 

83 

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, carbonyl sulfide, methane, 

argon, and nitrogen. The heat in the gasifier liquefies coal ash. Hot syngas and molten solids 

from the reactor flow downward into a radiant heat exchanger where the syngas is cooled. 

Raw Gas Cooling/Particulate Removal 

Syngas is cooled from 1,316°C (2,400°F) to 593°C (1,100°F) in the radiant synthesis gas cooler 

(SGC) (stream 8) 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 7). The waste heat from this cooling is used to generate high-pressure steam. Boiler 

feedwater in the tubes is saturated, and then steam and water are separated in a steam drum. 

Approximately 528,118 kg/h (1,164,300 lb/h) of saturated steam at 13.8 MPa (2,000 psia) is 

produced. This steam then forms part of the general heat recovery system that provides steam to 

the steam turbine. 

The syngas exiting the radiant cooler is directed downwards by a dip tube into a water sump. 

Most of the entrained solids are separated from the syngas at the bottom of the dip tube as the 

syngas goes upwards through the water. The syngas exits the quench chamber saturated at a 

temperature of 210°C (410°F). 

The slag handling system removes solids from the gasification process equipment. These solids 

consist of a small amount of unconverted carbon and essentially all of the ash contained in the 

feed coal. These solids are in the form of glass, which fully encapsulates any metals. Solids 

collected in the water sump below the radiant synthesis gas cooler are removed by gravity and 

forced circulation of water from the lock hopper circulating pump. The fine solids not removed 

from the bottom of the quench water sump remain entrained in the water circulating through the 

quench chamber. In order to limit the amount of solids recycled to the quench chamber, a 

continuous blowdown stream is removed from the bottom of the syngas quench. The blowdown 

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 Scrubber/Sour Water Stripper 

Syngas exiting the water quench passes to a syngas scrubber where a water wash is used to 

remove remaining chlorides and particulate. The syngas exits the scrubber still saturated at 

199°C (390°F) (stream 9). 

The sour water stripper removes NH3, SO2, and other impurities from the scrubber and other 

waste streams. The stripper consists of a sour drum that accumulates sour water from the gas 

scrubber and condensate from synthesis gas coolers. Sour water from the drum flows to the sour 

stripper, which consists of a packed column with a steam-heated reboiler. Sour gas is stripped 

from the liquid and sent to the sulfur recovery unit. Remaining water is sent to wastewater 

treatment. 
Cost and Performance Comparison of F

84 

Exhibit 3-14 Case 1 Process Flow Diagram, GEE IGCC without CO2 Capture 
Cost and Performance Comparison of F

85 

Exhibit 3-15 Case 1 Stream Table, GEE IGCC without CO2 Capture 

12345 6A 7 8 9 10 

V-L Mole Fraction 

Ar 0.0094 0.0065 0.0360 0.0023 0.0320 0.0000 0.0000 0.0079 0.0067 0.006CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0010 0.0008 0.000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3442 0.2922 0.292CO2 0.0003 0.0015 0.0000 0.0000 0.0000 0.0000 0.0000 0.1511 0.1276 0.127COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0002 0.000H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3349 0.2849 0.284H2O 0.0104 0.0496 0.0000 0.0000 0.0000 1.0000 0.0000 0.1429 0.2726 0.272

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0061 0.006N2 0.7722 0.8978 0.0140 0.9924 0.0180 0.0000 0.0000 0.0089 0.0076 0.007

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0017 0.0014 0.001O2 0.2077 0.0445 0.9500 0.0053 0.9500 0.0000 0.0000 0.0000 0.0000 0.000SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.000V-L Flowrate (lbmol/hr) 53,342 13,347 277 36,897 12,736 14,199 0 51,296 60,278 60,27

V-L Flowrate (lb/hr) 1,539,150 371,000 8,942 1,035,410 409,853 255,589 0 1,046,880 1,206,760 1,206,7Solids Flowrate (lb/hr) 0 0 0 0 0 435,187 53,746 0 0 0 Temperature (°F) 233 58 90 385 206 141 410 1100 390 390 Pressure (psia) 190.1 16.4 125.0 460.0 980.0 1050.0 797.7 799.7 792.7 782.Enthalpy (BTU/lb)B 55.6 16.6 12.5 87.8 37.7 --- 1,710 535.5 400.3 400.

Density (lb/ft3) 0.738 0.085 0.683 1.424 4.416 --- --- 0.975 1.740 1.71

Molecular Weight 28.85 27.80 32.23 28.06 32.18 --- --- 20.41 20.02 20.0

A - Solids flowrate includes dry coal; V-L flowrate includes slurry water and water from coalB - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of F

86 

Exhibit 3-15 Case 1 Stream Table (continued) 

13 14 15 16 17 18 19 20 21 

V-L Mole Fraction 

Ar 0.0000 0.0000 0.0188 0.0097 0.0097 0.0059 0.0097 0.0094 0.0094 CH4 0.0000 0.0000 0.0764 0.0012 0.0012 0.0169 0.0012 0.0000 0.0000 

CO 0.0000 0.0000 0.0003 0.4195 0.4195 0.0814 0.4195 0.0000 0.0000 CO2 0.3803 0.0000 0.6066 0.1414 0.1414 0.5518 0.1414 0.0003 0.0003 COS 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2 0.0000 0.0000 0.0126 0.4164 0.4164 0.0532 0.4164 0.0000 0.0000 H2O 0.0200 0.0000 0.0020 0.0009 0.0009 0.0000 0.0009 0.0104 0.0104 

H2S 0.3576 0.0000 0.0103 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 N2 0.2106 0.0000 0.2728 0.0110 0.0110 0.2908 0.0110 0.7722 0.7722 

NH3 0.0313 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 0.2077 0.2077 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 

Total 1.0000 0 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (lbmol/hr) 863 0 860 40,704 40,704 3,978 40,704 242,899 9,914 

V-L Flowrate (lb/hr) 30,839 0 31,584 795,458 795,458 140,512 795,458 7,008,680 286,060 Solids Flowrate (lb/hr) 0 12,235 0 0 0 0 0 0 0 Temperature (°F) 120 358 100 112 460 151 380 59 811 Pressure (psia) 30.0 24.9 368.0 719.0 714.0 460.0 460.0 14.7 234.9 Enthalpy (BTU/lb)B 31.1 -99.5 16.1 30.3 162.2 27.1 131.2 13.5 200.0 

Density (lb/ft3) 0.172 329.192 2.252 2.289 1.414 2.481 0.998 0.076 0.497 

Molecular Weight 35.73 256.53 36.74 19.54 19.54 35.33 19.54 28.85 28.85 

B - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of Fossil Energy Power Plants 

87 

COS Hydryolysis, Mercury Removal and Acid Gas Removal 

Syngas exiting the scrubber (stream 9) passes through a COS hydrolysis reactor where about 

99.5 percent of the COS is converted to CO2 and H2S (Section 3.1.5). The gas exiting the COS 

reactor (stream 10) passes through a series of heat exchangers and knockout drums to lower the 

syngas temperature to 39°C (103°F) and to separate entrained water. The cooled syngas (stream 

11) then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.4). 

Cool, particulate-free synthesis gas (stream 12) enters the Selexol absorber unit at approximately 

5.1 MPa (733 psia) and 39°C (103°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 lowpressure steam in a reboiler. The stripper acid gas stream (stream 13), consisting of 36 percent 

H2S and 38 percent CO2 (with the balance mostly N2), is then sent to the Claus unit. The 

secondary sweet fuel gas stream from the reabsorber is compressed to 3.2 MPa (460 psia) 

(stream 18) and combined with the primary sweet syngas after the expansion turbine (stream 19). 

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 5,550 kg/h 

(12,235 lb/h) of elemental sulfur (stream 14) are recovered from the fuel gas stream. This value 

represents an overall sulfur recovery efficiency of 99.6 percent. 

Acid gas from the Selexol unit is preheated to 232°C (450°F). A portion of the acid gas along 

with all of the sour gas from the stripper and oxygen from the ASU are fed to the Claus furnace. 

In the furnace, H2S is catalytically oxidized to SO2 at a furnace temperature greater than 1,343°C 

(2,450°F), which must be maintained in order to thermally decompose all of the NH3 present in 

the sour gas stream. 

Following the thermal stage and condensation of sulfur, two reheaters and two sulfur converters 

are used to obtain a per-pass H2S conversion of approximately 99.7 percent. The Claus Plant tail 

gas is hydrogenated and recycled back to the Selexol process (stream 15). In the furnace waste 

heat boiler, 8,772 kg/h (19,340 lb/h) of 3.6 MPa (525 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) steam for the low-pressure steam header. 

Power Block 

Clean syngas exiting the Selexol absorber is re-heated (stream 17) using HP boiler feedwater and 

then expanded to 3.2 MPa (460 psia) using an expansion turbine (stream 19). A second clean 

gas stream from the Selexol reabsorber is compressed and combined with stream 19. The 

combined syngas stream is further diluted with nitrogen from the ASU (stream 4) and enters the 
Cost and Performance Comparison of Fossil Energy Power Plants 

88 

advanced F Class CT burner. The CT compressor provides combustion air to the burner and also 

16 percent of the air requirements in the ASU (stream 21). The exhaust gas exits the CT at 

602°C (1,115°F) (stream 22) and enters the HRSG where additional heat is recovered until the 

flue gas exits the HRSG at 132°C (270°F) (stream 23) and is discharged through the plant stack. 

The steam raised in the HRSG is used to power an advanced, commercially available steam 

turbine using a 12.4 MPa/566°C/566°C (1800 psig/1050°F/1050°F) steam cycle. 

Air Separation Unit (ASU) 

The elevated pressure ASU was described in Section 3.1.2. In Case 1 the air separation unit 

(ASU) is designed to produce a nominal output of 4,560 tonnes/day (5,025 TPD) of 95 mole 

percent 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 

11,270 tonnes/day (12,425 TPD) of nitrogen are also recovered, compressed, and used as 

dilution in the gas turbine combustor (stream 4). About 4.1 percent of the gas turbine air is used 

to supply approximately 16 percent of the ASU air requirements (stream 21). 

Balance of Plant 

Balance of plant items were covered in Sections 3.1.9, 3.1.10 and 3.1.11. 
Cost and Performance Comparison of Fossil Energy Power Plants 

89 

3.2.3 KEY SYSTEM ASSUMPTIONS

System assumptions for Cases 1 and 2, GEE IGCC with and without CO2 capture, are presented 

in Exhibit 3-16. 

Exhibit 3-16 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 0.95 0.95 

Carbon Conversion, % 98 98 

Syngas HHV at SGC Outlet, 

kJ/Nm3

 (Btu/scf) 8,210 (226) 8,210 (226) 

Steam Cycle, MPa/°C/°C 

(psig/°F/°F) 

12.4/566/566 

(1800/1050/1050) 

12.4/538/538 

(1800/1000/1000) 

Condenser Pressure, mm Hg 

(in Hg) 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 Conent, % 63 63 

COS Hydrolysis Yes Occurs in SGS 

Sour Gas Shift No Yes 

H2S Separation Selexol Selexol 1st Stage 

Sulfur Removal, % 99.6 99.6 

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 MNQC (LNB) and N2

Dilution 

MNQC (LNB) and N2

Dilution 

CO2 Separation N/A Selexol 2nd Stage 

CO2 Capture N/A 90.2% from Syngas 

CO2 Sequestration N/A Off-site Saline Formation 
Cost and Performance Comparison of Fossil Energy Power Plants 

90 

Balance of Plant – Cases 1 and 2 

The balance of plant assumptions are common to all cases and are presented in Exhibit 3-17. 

Exhibit 3-17 Balance of Plant Assumptions 

Cooling 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 Publicly 

Owned Treatment Works 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 Comparison of Fossil Energy Power Plants 

91 

3.2.4 SPARING PHILOSOPHY

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. 

The plant design consists of the following major subsystems: 

• Two air separation units (2 x 50%) 

• Two trains of slurry preparation and slurry pumps (2 x 50%) 

• Two trains of gasification, including gasifier, synthesis gas cooler, quench and scrubber 

(2 x 50%). 

• Two trains of syngas clean-up process (2 x 50%). 

• Two trains of Selexol acid gas removal, single-stage in Case 1 and two-stage in Case 2, 

(2 x 50%) and one Claus-based sulfur recovery unit (1 x 100%). 

• Two combustion turbine/HRSG tandems (2 x 50%). 

• One steam turbine (1 x 100%). 

3.2.5 CASE 1 PERFORMANCE RESULTS

The plant produces a net output of 640 MWe at a net plant efficiency of 38.2 percent (HHV 

basis). GEE has reported a net plant effiency 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. [48, 49] 

Typically the higher efficiencies result from fuel blends that include petroleum coke. 

Overall performance for the plant is summarized in Exhibit 3-18 which includes auxiliary power 

requirements. The ASU accounts for over 79 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 circulating water pumps and the cooling tower fan, accounts for over 

4 percent of the auxiliary load, and the BFW pumps account for an additional 3.5 percent. All 

other individual auxiliary loads are less than 3 percent of the total. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 92 

Exhibit 3-18 Case 1 Plant Performance Summary 

POWER SUMMARY (Gross Power at Generator Terminals, kWe) 

Gas Turbine Power 464,300 

Sweet Gas Expander Power 7,130 

Steam Turbine Power 298,920 

TOTAL POWER, kWe 770,350 

AUXILIARY LOAD SUMMARY, kWe 

Coal Handling 450 

Coal Milling 2,280 

Coal Slurry Pumps 740 

Slag Handling and Dewatering 1,170 

Air Separation Unit Auxiliaries 1,000 

Air Separation Unit Main Air Compressor 60,070 

Oxygen Compressor 11,270 

Nitrogen Compressor 30,560 

Claus Plant Tail Gas Recycle Compressor 1,230 

Boiler Feedwater Pumps 4,590 

Condensate Pump 250 

Flash Bottoms Pump 200 

Circulating Water Pumps 3,710 

Cooling Tower Fans 1,910 

Scrubber Pumps 300 

Selexol Unit Auxiliaries 3,420 

Gas Turbine Auxiliaries 1,000 

Steam Turbine Auxiliaries 100 

Claus Plant/TGTU Auxiliaries 200 

Miscellaneous Balance of Plant (Note 1) 3,000 

Transformer Loss 2,650 

TOTAL AUXILIARIES, kWe 130,100 

NET POWER, kWe 640,250 

Net Plant Efficiency, % (HHV) 38.2 

Net Plant Heat Rate (Btu/kWh) 8,922 

CONDENSER COOLING DUTY 106 kJ/h (106 Btu/h) 1,705 (1,617) 

CONSUMABLES 

As-Received Coal Feed, kg/h (lb/h) 222,095 (489,634) 

Thermal Input, kWt 1,674,044 

Raw Water Usage, m3/min (gpm) 15.2 (4,003) 

Note 1: Includes plant control systems, lighting, HVAC and miscellaneous low voltage loads 
Cost and Performance Comparison of Fossil Energy Power Plants 

 93 

Environmental Performance 

The environmental targets for emissions of Hg, NOx, SO2 and particulate matter were presented 

in Section 2.4. A summary of the plant air emissions for Case 1 is presented in Exhibit 3-19. 

Exhibit 3-19 Case 1 Air Emissions 

kg/GJ 

(lb/106 Btu) 

Tonne/year 

(ton/year) @ 

80% capacity factor 

kg/MWh 

(lb/MWh) 

SO2 0.005 (0.0127) 231 (254) 0.043 (0.094) 

NOX 0.024 (0.055) 994 (1,096) 0.184 (0.406) 

Particulates 0.003 (0.0071) 129 (142) 0.024 (0.053) 

Hg 0.25x10-6

(.57x10-6) 0.010 (0.011) 1.9x10-6(4.2x10-6) 

CO2 85 (197) 3,572,000 

(3,938,000) 662 (1,459) 

CO2

1 796 (1,755) 

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 flue gas of less 

than 4 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, 

producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species 

to H2S and then recycled back to the Selexol process, thereby eliminating the need for a tail gas 

treatment unit. 

NOX emissions are limited by nitrogen dilution of the syngas to 15 ppmvd (as NO2 @15 percent 

O2). Ammonia in the syngas is removed with process condensate prior to the low-temperature 

AGR process and ultimately destroyed in the Claus plant burner. This helps lower NOX levels as 

well. 

Particulate discharge to the atmosphere is limited to extremely low values by the use of the 

syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only. 

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 3-20. 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 AspenPlus model accounts for air components throughout. Carbon leaves the plant as 

unburned carbon in the slag, as dissolved CO2 in the wastewater blowdown stream, and as CO2

in the stack gas and ASU vent gas. Carbon in the wastewater blowdown stream is calculated by 

difference to close the material balance. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 94 

Exhibit 3-20 Case 1 Carbon Balance 

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) 

Coal 141,585 (312,142) Slag 2,843 (6,267) 

Air (CO2) 529 (1,165) Stack Gas 139,020 (306,486) 

ASU Vent 111 (245) 

Wastewater 141 (310) 

Total 142,114 (313,307) Total 142,114 (313,307) 

Exhibit 3-21 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, dissolved SO2 in the 

wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is 

considered to be negligible, and the sulfur content of the blowdown stream is calculated by 

difference to close the material balance. The total sulfur capture is represented by the following 

fraction: 

(Sulfur byproduct/Sulfur in the coal) or 

(12,235/12,290) or 

99.6 percent 

Exhibit 3-21 Case 1 Sulfur Balance 

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) 

Coal 5,575 (12,290) Elemental Sulfur 5,550 (12,235) 

Stack Gas 16 (36) 

Wastewater 8 (19) 

Total 5,575 (12,290) Total 5,575 (12,290) 

Exhibit 3-22 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 

makeup is the difference between water demand and internal recycle. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 95 

Exhibit 3-22 Case 1 Water Balance 

Water Use Water Demand, 

m3/min (gpm) 

Internal Recycle, 

m3/min (gpm) 

Raw Water Makeup, 

m3/min (gpm) 

Slurry 1.5 (402) 1.5 (402) 0 

Slag Handling 0.5 (140) 0 0.5 (140) 

Quench/Scrubber 2.1 (561) 1.6 (427) 0.8 (210) 

BFW Makeup 0.2 (49) 0 0.2 (49) 

Cooling Tower 

Makeup 14.4 (3,805) 0.5 (125) 13.9 (3,680) 

Total 18.7 (4,957) 3.6 (954) 15.2 (4,003) 

Heat and Mass Balance Diagrams 

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-23 through 

Exhibit 3-27: 

• Coal gasification and air separation unit 

• Syngas cleanup 

• Sulfur recovery and tail gas recycle 

• Combined cycle power generation 

• Steam and feedwater 

An overall plant energy balance is provided in tabular form in Exhibit 3-28. The power out is 

the combined combustion turbine, steam turbine and expander power prior to generator losses. 

The power at the generator terminals (shown in Exhibit 3-18) is calculated by multiplying the 

power out by a combined generator efficiency of 98.2 percent. 

The heat and material balances shown in these figures are shown in U.S. standard units. The 

following factors can be used for conversion to SI units. The same conversions apply to all cases 

but are shown only once for Case 1. 

P, absolute pressure, psia, multiply by 6.895 x10-3 = MPa (megapascals) 

°F, temperature, (°F minus 32) divided by 1.8 = °C (Centigrade) 

H, enthalpy, Btu/lb, multiply H by 2.3260 = kJ/kg (kilojoules/kilogram) 

W, total plant flow, lb/h, multiply W by 0.4536 = kg/h (kilogram/hour) 

Heat rate, Btu/kWh, multiply Btu/kWh by 1.0551 = kJ/kWh (kilojoules/kilowatt-hour) 
Cost and Performance Comparison of Fossil Energy Power Plants 

 96 

This page intentionally left blank 
97 

Exhibit 3-23 Case 1 Coal Gasification and Air Separation Units Heat and Mass Bala
98 

Exhibit 3-24 Case 1 Syngas Cleanup Heat and Mass Balance Schematic 
99 

Exhibit 3-25 Case 1 Sulfur Recovery and Tail Gas Recycle Heat and Mass Balance 
100 

Exhibit 3-26 Case 1 Combined-Cycle Power Generation Heat and Mass Balance 
101 

Exhibit 3-27 Case 1 Steam and Feedwater Heat and Mass Balance Schema
102 

This page intentionally left blank 
Cost and Performance Comparison of Fossil Energy Power Plants 

103 

Exhibit 3-28 Case 1 Overall Energy Balance (0°C [32°F] Reference) 

HHV Sensible + Latent Power Total 

Heat In (MMBtu/hr) 

Coal 5,712.1 4.8 5,716.8 

ASU Air 20.8 20.8 

CT Air 94.6 94.6 

Water 2.9 2.9 

Auxiliary Power 444.0 444.0 

Totals 5,712.1 123.1 444.0 6,279.2 

Heat Out (MMBtu/hr) 

ASU Intercoolers 228.0 228.0 

ASU Vent 6.1 6.1 

Slag 88.3 3.6 91.9 

Sulfur 48.7 (1.2) 47.5 

Tail Gas Compressor 

Intercoolers 4.4 4.4 

HRSG Flue Gas 896.8 896.8 

Condenser 1,617.0 1,617.0 

Process Losses (1) 710.8 710.8 

Power 2,676.7 2,676.7 

Totals 137.0 3,465.5 2,676.7 6,279.2 

(1) Process Losses are calculated by difference and reflect various gasification, turbine, 

HRSG and other heat and work losses. Aspen flowsheet balance is within 0.5 percent. 
Cost and Performance Comparison of Fossil Energy Power Plants 

104 

3.2.6 CASE 1 - MAJOR EQUIPMENT LIST

Major equipment items for the GEE gasifier with no CO2 capture are shown in the following 

tables. The accounts used in the equipment list correspond to the account numbers used in the 

cost estimates in Section 3.2.7. In general, the design conditions include a 10 percent 

contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans. 

ACCOUNT 1 COAL HANDLING 

Equipment 

No. Description Type Operating Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0

3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0

5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling 

System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0

8 Reclaim Hopper N/A 2 1

9 Feeder Vibratory 2 1

10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0

12 Coal Surge Bin w/ Vent 

Filter

Dual outlet 2 0

13 Crusher Impactor 

reduction 2 0

14 As-Fired Coal Sampling 

System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0

17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 3 0

N/A

363 tonne/h (400 tph)

816 tonne (900 ton)

45 tonne (50 ton)

181 tonne/h (200 tph)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

363 tonne/h (400 tph)

181 tonne (200 ton)

N/A

N/A

363 tonne/h (400 tph)

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph)

N/A

1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)

1,134 tonne/h (1,250 tph)
Cost and Performance Comparison of Fossil Energy Power Plants 

105 

ACCOUNT 2 COAL PREPARATION AND FEED 

Equipment 

No. Description Type Operating Qty. Spares

1 Feeder Gravimetric 3 0

2 Conveyor No. 6 Belt w/tripper 1 0

3 Rod Mill Feed Hopper Dual Outlet 1 0

4 Weigh Feeder Belt 2 0

5 Rod Mill Rotary 2 0

6 Slurry Water Storage Tank 

with Agitator Field erected 2 0

7 Slurry Water Pumps Centrifugal 2 2

10 Trommel Screen Coarse 2 0

11 Rod Mill Discharge Tank with 

Agitator Field erected 2 0

12 Rod Mill Product Pumps Centrifugal 2 2

13 Slurry Storage Tank with 

Agitator Field erected 2 0

14 Slurry Recycle Pumps Centrifugal 2 2

15 Slurry Product Pumps Positive 

displacement 2 2

172 tonne/h (190 tph)

2,650 lpm (700 gpm)

5,337 lpm (1,410 gpm)

946,361 liters (250,000 gal)

118 tonne/h (130 tph)

320,248 liters (84,600 gal)

2,650 lpm (700 gpm)

833 lpm (220 gpm)

118 tonne/h (130 tph)

302,835 liters (80,000 gal)

Design Condition

82 tonne/h (90 tph)

245 tonne/h (270 tph)

490 tonne (540 ton)
Cost and Performance Comparison of Fossil Energy Power Plants 

106 

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT 

Equipment 

No. Description Type OperatingQty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 2 0

2 Condensate Pumps Vertical canned 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 2 0

4 Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage 2 1

6 High Pressure 

Feedwater Pump No. 2

Barrel type, multistage, centrifugal 2 1

7 Auxiliary Boiler Shop fabricated, water 

tube 1 0

8 Service Air 

Compressors Flooded Screw 2 1

9 Instrument Air Dryers Duplex, regenerative 2 1

10 Closed Cycle Cooling 

Heat Exchangers Plate and frame 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 2 1

12 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine 1 1

13 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal 1 1

14 Raw Water Pumps Stainless steel, single 

suction 2 1

15 Filtered Water Pumps Stainless steel, single 

suction 2 1

16 Filtered Water Tank Vertical, cylindrical 2 0

17 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 2 0

18 Liquid Waste Treatment 

System 1 0

1,931 lpm @ 283 m H2O

(510 gpm @ 930 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C

(40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

Design Condition

745,732 liters (197,000 gal)

7,079 lpm @ 110 m H2O

(1,870 gpm @ 360 ft H2O)

514,828 kg/h (1,135,000 lb/h)

IP water: 1,893 lpm @ 223 m 

H2O (500 gpm @ 730 ft H2O)

HP water: 6,890 lpm @ 1,890 m 

H2O (1,820 gpm @ 6,200 ft 

H2O)

2,498 lpm @ 49 m H2O

(660 gpm @ 160 ft H2O)

28 m3/min (1,000 scfm)

58 MMkJ/h (55 MMBtu/h) each

20,820 lpm @ 21 m H2O

(5,500 gpm @ 70 ft H2O)

3,785 lpm @ 88 m H2O

(1,000 gpm @ 290 ft H2O)

2,650 lpm @ 64 m H2O

(700 gpm @ 210 ft H2O)

8,593 lpm @ 18 m H2O

(2,270 gpm @ 60 ft H2O)

1,211,341 liter (320,000 gal)

189 lpm (50 gpm)

10 years, 24-hour storm

5 2 1 High Pressure 

Feedwater Pump No. 1

Barrel type, multistage, centrifugal
Cost and Performance Comparison of Fossil Energy Power Plants 

107 

ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW 

TEMPERATURE HEAT RECOVERY 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Gasifier Pressurized slurry-feed, 

entrained bed 2 0

2 Synthesis Gas Cooler

Vertical downflow 

radiant heat exchanger 

with outlet quench 

chamber

2 0

3

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 2 0

4 Raw Gas Coolers Shell and tube with 

condensate drain 6 0

5 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator 2 0

6 Flare Stack

Self-supporting, carbon 

steel, stainless steel 

top, pilot ignition

2 0

7 ASU Main Air 

Compressor

Centrifugal, multistage

2 0

8 Cold Box Vendor design 2 0

9 Oxygen Compressor Centrifugal, multistage

2 0

10 Nitrogen Compressor Centrifugal, multistage

2 0

11 Nitrogen Boost 

Compressor

Centrifugal, multistage

2 0

12 Extraction Air Heat 

Exchanger

Gas-to-gas, vendor 

design 2 0

566 m3/min @ 2.3 MPa

(20,000 scfm @ 340 psia)

71,214 kg/h, 433°C, 1.6 MPa

(157,000 lb/h, 811°F, 235 psia)

330,216 kg/h (728,000 lb/h) 

syngas

5,267 m3/min @ 1.3 MPa

(186,000 scfm @ 190 psia)

2,540 tonne/day (2,800 tpd) of 

95% purity oxygen

1,246 m3/min @ 7.1 MPa

(44,000 scfm @ 1,030 psia)

3,058 m3/min @ 3.4 MPa

(108,000 scfm @ 490 psia)

Design Condition

2,903 tonne/day, 5.6 MPa

(3,200 tpd, 815 psia)

274,424 kg/h (605,000 lb/h)

330,216 kg/h (728,000 lb/h)

301,186 kg/h (664,000 lb/h)

218,178 kg/h, 39°C, 5.2 MPa

(481,000 lb/h, 103°F, 753 psia)
Cost and Performance Comparison of Fossil Energy Power Plants 

108 

ACCOUNT 5A SYNGAS CLEANUP 

Equipment 

No. Description Type Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon 

bed 2 0

2 Sulfur Plant Claus type 1 0

3 COS Hydrolysis Reactor Fixed bed, 

catalytic 2 0

4 Acid Gas Removal Plant Selexol 2 0

5 Hydrogenation Reactor Fixed bed, 

catalytic 1 0

6 Tail Gas Recycle 

Compressor Centrifugal 1 1

183 m3/min @ 3.0 MPa

(6,480 scfm @ 430 psia)

225,436 kg/h (497,000 lb/h)

42°C (107°F) 5.1 MPa (733 psia)

19,504 kg/h (43,000 lb/h)

232°C (450°F) 0.2 MPa (25 psia)

Design Condition

225,436 kg/h (497,000 lb/h) 42°C 

(107°F) 5.1 MPa (743 psia)

147 tonne/day (162 tpd)

301,186 kg/h (664,000 lb/h) 

199°C (390°F) 5.5 MPa (793 psia)

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty. Spares

1 Gas Turbine Advanced F class 2 0

2 Gas Turbine Generator TEWAC 2 0

3 Sweet Syngas Expansion 

Turbine/Generator Turbo expander 2 0

Design Condition

232 MW 

260 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

198,447 kg/h (437,500 lb/h) 

Delta P: 2.1 MPa (310 psi) 

Power output: 3,980 kW

ACCOUNT 7 HRSG, DUCTING, AND STACK 

Equipment 

No. Description Type Operating Qty. Spares

1 Stack CS plate, type 409SS 

liner 1 0

Design Condition

76 m (250 ft) high x

8.3 m (27 ft) diameter

Main steam - 388,803 kg/h, 12.4 

MPa/566°C (857,162 lb/h, 1,800 

psig/1,050°F) 2 2 0 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator

 Reheat steam - 382,124 kg/h, 

2.9 MPa/566°C (842,437 lb/h, 

420 psig/1,050°F)
Cost and Performance Comparison of Fossil Energy Power Plants 

109 

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitiation 1 0

3 Steam Bypass One per HRSG 2 0

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1 0

315 MW 

12.4 MPa/566°C/566°C 

(1800 psig/ 

1050°F/1050°F)

1,876 MMkJ/h (1,780 

MMBtu/h) heat duty, Inlet 

water temperature 16°C 

(60°F), Water temperature 

rise 11°C (20°F)

350 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase

50% steam flow @ design 

steam conditions

Design Condition

ACCOUNT 9 COOLING WATER SYSTEM 

Equipment 

No. Description Type OperatingQty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell1 0

Design Condition

370,973 lpm @ 30 m

(98,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

2,066 MMkJ/h (1,960 MMBtu/h) 

heat load
Cost and Performance Comparison of Fossil Energy Power Plants 

110 

ACCOUNT 10 SLAG RECOVERY AND HANDLING 

Equipment 

No. Description Type Operating Qty. Spares

1 Slag Quench Tank Water bath 2 0

2 Slag Crusher Roll 2 0

3 Slag Depressurizer Lock Hopper 2 0

4 Slag Receiving Tank Horizontal, weir 2 0

5 Black Water Overflow Tank Shop fabricated 2 0

6 Slag Conveyor Drag chain 2 0

7 Slag Separation Screen Vibrating 2 0

8 Coarse Slag Conveyor Belt/bucket 2 0

9 Fine Ash Settling Tank Vertical, gravity 2 0

10 Fine Ash Recycle Pumps Horizontal 

centrifugal 2 2

11 Grey Water Storage Tank Field erected 2 0

12 Grey Water Pumps Centrifugal 2 2

13 Slag Storage Bin Vertical, field 

erected 2 0

14 Unloading Equipment Telescoping chute 1 0

249,839 liters (66,000 gal)

76 lpm @ 14 m H2O

(20 gpm @ 46 ft H2O)

998 tonne (1,100 tons)

109 tonne/h (120 tph)

79,494 liters (21,000 gal)

303 lpm @ 564 m H2O

(80 gpm @ 1,850 ft H2O)

166,559 liters (44,000 gal)

14 tonne/h (15 tph)

14 tonne/h (15 tph)

14 tonne/h (15 tph)

79,494 liters (21,000 gal)

Design Condition

257,410 liters (68,000 gal)

14 tonne/h (15 tph)

14 tonne/h (15 tph)
Cost and Performance Comparison of Fossil Energy Power Plants 

111 

ACCOUNT 11 ACCESSORY ELECTRIC PLANT 

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, 260 MVA, 

3-ph, 60 Hz

2 STG Transformer Oil-filled 24 kV/345 kV, 200 MVA, 

3-ph, 60 Hz 1 0

24 kV/4.16 kV, 142 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 21 MVA, 

3-ph, 60 Hz

750 kW, 480 V, 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

ACCOUNT 12 INSTRUMENTATION AND CONTROLS 

Equipment 

No. Description Type OperatingQty. 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

2 DCS - Processor

Microprocessor with 

redundant 

input/output

N/A 1 0

Fully redundant, 25% spare
Cost and Performance Comparison of Fossil Energy Power Plants 

112 

3.2.7 CASE 1 - COST ESTIMATING

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-29 shows 

the total plant capital cost summary organized by cost account and Exhibit 3-30 shows a more 

detailed breakdown of the capital costs. Exhibit 3-31 shows the initial and annual O&M costs. 

The estimated TPC of the GEE gasifier with no CO2 capture is $1,813/kW. Process contingency 

represents 2.5 percent of the TPC and project contingency represents 13.3 percent. The 20-year 

LCOE is 78.0 mills/kWh 
Cost and Performance Comparison of F

113 

Exhibit 3-29 Case 1 Total Plant Cost Summary

Client: USDOE/NETL Report Da

Project: Bituminous Baseline Study

Case: Case 01 - GEE Radiant Only IGCC w/o CO2

Plant Size: 640.3 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Projec

 1 COAL & SORBENT HANDLING $13,505 $2,518 $10,582 $0 $0 $26,606 $2,410 $0 $5

 2 COAL & SORBENT PREP & FEED $23,112 $4,213 $13,999 $0 $0 $41,324 $3,748 $1,500 $9

 3 FEEDWATER & MISC. BOP SYSTEMS $9,975 $8,740 $9,353 $0 $0 $28,067 $2,620 $0 $6

 4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $101,906 $0 $56,569 $0 $0 $158,475 $14,508 $21,881 $29

4.2 Syngas Cooler(w/ Gasifier - 4.1 ) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 

4.3 ASU/Oxidant Compression $152,787 $0 w/equip. $0 $0 $152,787 $14,542 $0 $16

4.4-4.9 Other Gasification Equipment $12,116 $11,603 $12,827 $0 $0 $36,546 $3,471 $0 $8

SUBTOTAL 4 $266,809 $11,603 $69,396 $0 $0 $347,808 $32,521 $21,881 $54

 5A Gas Cleanup & Piping $46,447 $4,978 $47,184 $0 $0 $98,610 $9,456 $89 $21

 5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $82,000 $0 $5,071 $0 $0 $87,072 $8,192 $4,354 $9

6.2-6.9 Combustion Turbine Other $5,440 $752 $1,598 $0 $0 $7,791 $733 $0 $1

SUBTOTAL 6 $87,441 $752 $6,670 $0 $0 $94,862 $8,925 $4,354 $11

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $34,012 $0 $4,840 $0 $0 $38,851 $3,667 $0 $4

7.2-7.9 Ductwork and Stack $3,127 $2,201 $2,922 $0 $0 $8,249 $762 $0 $1

SUBTOTAL 7 $37,138 $2,201 $7,761 $0 $0 $47,101 $4,429 $0 $5

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $29,570 $0 $5,065 $0 $0 $34,635 $3,319 $0 $3

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,895 $1,003 $7,554 $0 $0 $19,452 $1,756 $0 $4

SUBTOTAL 8 $40,465 $1,003 $12,619 $0 $0 $54,087 $5,075 $0 $8

 9 COOLING WATER SYSTEM $7,199 $7,656 $6,445 $0 $0 $21,301 $1,957 $0 $4

10 ASH/SPENT SORBENT HANDLING SYS $14,077 $7,868 $14,278 $0 $0 $36,223 $3,463 $0 $4

11 ACCESSORY ELECTRIC PLANT $23,161 $10,196 $20,591 $0 $0 $53,947 $4,678 $0 $11

12 INSTRUMENTATION & CONTROL $9,437 $1,767 $6,335 $0 $0 $17,538 $1,616 $877 $3

13 IMPROVEMENTS TO SITE $3,211 $1,892 $7,981 $0 $0 $13,084 $1,285 $0 $4

14 BUILDINGS & STRUCTURES $0 $6,373 $7,450 $0 $0 $13,823 $1,257 $0 $2

TOTAL COST $581,977 $71,760 $240,644 $0 $0 $894,382 $83,439 $28,701 $154

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

114 

Exhibit 3-30 Case 1 Total Plant Cost Details 

Client: USDOE/NETL Repor

Project: Bituminous Baseline Study

Case: Case 01 - GEE Radiant Only IGCC w/o CO2

Plant Size: 640.3 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenc

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $3,547 $0 $1,751 $0 $0 $5,298 $474 $0 1.2 Coal Stackout & Reclaim $4,583 $0 $1,123 $0 $0 $5,706 $500 $0 1.3 Coal Conveyors $4,261 $0 $1,111 $0 $0 $5,372 $472 $0 1.4 Other Coal Handling $1,115 $0 $257 $0 $0 $1,372 $120 $0 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,518 $6,341 $0 $0 $8,859 $844 $0 

SUBTOTAL 1. $13,505 $2,518 $10,582 $0 $0 $26,606 $2,410 $0 

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying incl w/2.3 incl. w/ 2.3 incl. w/ 2.3 incl. w/ 2.3 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,515 $361 $240 $0 $0 $2,116 $181 $0 2.3 Slurry Prep & Feed $20,764 $0 $9,236 $0 $0 $30,000 $2,719 $1,500 2.4 Misc.Coal Prep & Feed $833 $603 $1,837 $0 $0 $3,273 $300 $0 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,249 $2,686 $0 $0 $5,936 $548 $0 

SUBTOTAL 2. $23,112 $4,213 $13,999 $0 $0 $41,324 $3,748 $1,500 

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 FeedwaterSystem $3,484 $6,058 $3,201 $0 $0 $12,743 $1,176 $0 3.2 Water Makeup & Pretreating $532 $55 $297 $0 $0 $884 $83 $0 3.3 Other Feedwater Subsystems $1,924 $652 $587 $0 $0 $3,164 $283 $0 3.4 Service Water Systems $306 $625 $2,172 $0 $0 $3,104 $300 $0 3.5 Other Boiler Plant Systems $1,646 $632 $1,567 $0 $0 $3,845 $360 $0 3.6 FO Supply Sys & Nat Gas $306 $577 $539 $0 $0 $1,421 $136 $0 3.7 Waste Treatment Equipment $739 $0 $453 $0 $0 $1,192 $116 $0 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $1,038 $139 $537 $0 $0 $1,715 $165 $0 

SUBTOTAL 3. $9,975 $8,740 $9,353 $0 $0 $28,067 $2,620 $0 

 4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $101,906 $0 $56,569 $0 $0 $158,475 $14,508 $21,881 $4.2 Syngas Cooler(w/ Gasifier - 4.1 ) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $152,787 $0 w/equip. $0 $0 $152,787 $14,542 $0 $4.4 Scrubber & Low Temperature Cooling $9,253 $7,518 $7,846 $0 $0 $24,617 $2,346 $0 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 4.6 Other Gasification Equipment $2,863 $1,359 $2,689 $0 $0 $6,911 $661 $0 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $2,726 $2,292 $0 $0 $5,018 $463 $0 

SUBTOTAL 4. $266,809 $11,603 $69,396 $0 $0 $347,808 $32,521 $21,881 $

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

115 

Exhibit 3-30 Case 1 Total Plant Costs (Continued) 

Client: USDOE/NETL Report Dat

Project: Bituminous Baseline Study

Case: Case 01 - GEE Radiant Only IGCC w/o CO2

Plant Size: 640.3 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project 

 5A GAS CLEANUP & PIPING

5A.1 Single Stage Selexol $33,056 $0 $28,354 $0 $0 $61,411 $5,895 $0 $13,45A.2 Elemental Sulfur Plant $9,860 $1,957 $12,731 $0 $0 $24,548 $2,367 $0 $5,35A.3 Mercury Removal $1,016 $0 $774 $0 $0 $1,790 $172 $89 $45A.4 COS Hydrolysis $2,515 $0 $3,286 $0 $0 $5,801 $560 $0 $1,25A.5 Open $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 5A.7 Fuel Gas Piping $0 $1,942 $1,338 $0 $0 $3,280 $299 $0 $75A.9 HGCU Foundations $0 $1,079 $701 $0 $0 $1,780 $163 $0 $5

SUBTOTAL 5A. $46,447 $4,978 $47,184 $0 $0 $98,610 $9,456 $89 $21,8

 5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $82,000 $0 $5,071 $0 $0 $87,072 $8,192 $4,354 $9,96.2 Syngas Expander $5,440 $0 $760 $0 $0 $6,200 $585 $0 $1,06.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $752 $838 $0 $0 $1,591 $148 $0 $5

SUBTOTAL 6. $87,441 $752 $6,670 $0 $0 $94,862 $8,925 $4,354 $11,5

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $34,012 $0 $4,840 $0 $0 $38,851 $3,667 $0 $4,27.2 Open $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,579 $1,144 $0 $0 $2,723 $239 $0 $57.4 Stack $3,127 $0 $1,175 $0 $0 $4,302 $409 $0 $47.9 HRSG,Duct & Stack Foundations $0 $622 $602 $0 $0 $1,225 $114 $0 $4

SUBTOTAL 7. $37,138 $2,201 $7,761 $0 $0 $47,101 $4,429 $0 $5,7

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $29,570 $0 $5,065 $0 $0 $34,635 $3,319 $0 $3,78.2 Turbine Plant Auxiliaries $204 $0 $467 $0 $0 $670 $65 $0 $8.3 Condenser & Auxiliaries $5,181 $0 $1,496 $0 $0 $6,678 $634 $0 $78.4 Steam Piping $5,510 $0 $3,883 $0 $0 $9,393 $801 $0 $2,58.9 TG Foundations $0 $1,003 $1,707 $0 $0 $2,711 $256 $0 $8

SUBTOTAL 8. $40,465 $1,003 $12,619 $0 $0 $54,087 $5,075 $0 $8,0

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $4,704 $0 $1,034 $0 $0 $5,738 $543 $0 $99.2 Circulating Water Pumps $1,481 $0 $95 $0 $0 $1,575 $135 $0 $29.3 Circ.Water System Auxiliaries $122 $0 $17 $0 $0 $139 $13 $0 $9.4 Circ.Water Piping $0 $5,160 $1,316 $0 $0 $6,476 $573 $0 $1,49.5 Make-up Water System $299 $0 $424 $0 $0 $723 $69 $0 $19.6 Component Cooling Water Sys $594 $711 $502 $0 $0 $1,808 $167 $0 $39.9 Circ.Water System Foundations& Structures $0 $1,785 $3,057 $0 $0 $4,842 $457 $0 $1,5

SUBTOTAL 9. $7,199 $7,656 $6,445 $0 $0 $21,301 $1,957 $0 $4,7

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $11,592 $6,392 $12,995 $0 $0 $30,979 $2,968 $0 $3,310.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $562 $0 $612 $0 $0 $1,174 $113 $0 $110.7 Ash Transport & Feed Equipment $759 $0 $182 $0 $0 $941 $87 $0 $110.8 Misc. Ash Handling Equipment $1,164 $1,427 $426 $0 $0 $3,017 $285 $0 $410.9 Ash/Spent Sorbent Foundation $0 $49 $62 $0 $0 $112 $10 $0 $

SUBTOTAL 10. $14,077 $7,868 $14,278 $0 $0 $36,223 $3,463 $0 $4,2

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

116 

Exhibit 3-30 Case 1 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Repor

Project: Bituminous Baseline Study

Case: Case 01 - GEE Radiant Only IGCC w/o CO2

Plant Size: 640.3 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenci

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $921 $0 $918 $0 $0 $1,839 $175 $0 11.2 Station Service Equipment $3,646 $0 $342 $0 $0 $3,988 $379 $0 11.3 Switchgear & Motor Control $6,967 $0 $1,277 $0 $0 $8,245 $764 $0 11.4 Conduit & Cable Tray $0 $3,315 $10,762 $0 $0 $14,077 $1,346 $0 11.5 Wire & Cable $0 $6,088 $4,095 $0 $0 $10,184 $744 $0 11.6 Protective Equipment $0 $640 $2,427 $0 $0 $3,067 $300 $0 11.7 Standby Equipment $218 $0 $222 $0 $0 $441 $43 $0 11.8 Main Power Transformers $11,408 $0 $142 $0 $0 $11,550 $875 $0 11.9 Electrical Foundations $0 $153 $404 $0 $0 $557 $53 $0 

SUBTOTAL 11. $23,161 $10,196 $20,591 $0 $0 $53,947 $4,678 $0 $

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 12.4 Other Major Component Control $932 $0 $648 $0 $0 $1,580 $152 $79 12.5 Signal Processing Equipment W/12.7 $0 W/12.7 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $214 $0 $143 $0 $0 $357 $34 $18 12.7 Computer & Accessories $4,969 $0 $166 $0 $0 $5,135 $487 $257 12.8 Instrument Wiring & Tubing $0 $1,767 $3,697 $0 $0 $5,464 $463 $273 12.9 Other I & C Equipment $3,322 $0 $1,681 $0 $0 $5,002 $480 $250 

SUBTOTAL 12. $9,437 $1,767 $6,335 $0 $0 $17,538 $1,616 $877 

13 Improvements to Site

13.1 Site Preparation $0 $101 $2,169 $0 $0 $2,270 $224 $0 13.2 Site Improvements $0 $1,792 $2,399 $0 $0 $4,190 $412 $0 13.3 Site Facilities $3,211 $0 $3,413 $0 $0 $6,624 $650 $0 

SUBTOTAL 13. $3,211 $1,892 $7,981 $0 $0 $13,084 $1,285 $0 

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $221 $127 $0 $0 $348 $31 $0 14.2 Steam Turbine Building $0 $2,410 $3,479 $0 $0 $5,888 $540 $0 14.3 Administration Building $0 $802 $590 $0 $0 $1,392 $124 $0 14.4 Circulation Water Pumphouse $0 $158 $85 $0 $0 $243 $21 $0 14.5 Water Treatment Buildings $0 $423 $418 $0 $0 $842 $76 $0 14.6 Machine Shop $0 $411 $285 $0 $0 $695 $62 $0 14.7 Warehouse $0 $663 $434 $0 $0 $1,097 $97 $0 14.8 Other Buildings & Structures $0 $397 $313 $0 $0 $710 $63 $0 14.9 Waste Treating Building & Str. $0 $888 $1,719 $0 $0 $2,607 $242 $0 

SUBTOTAL 14. $0 $6,373 $7,450 $0 $0 $13,823 $1,257 $0 

TOTAL COST $581,977 $71,760 $240,644 $0 $0 $894,382 $83,439 $28,701 $1

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of Fossil Energy Power Plants 

117 

Exhibit 3-31 Case 1 Initial and Annual O&M Costs 

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006

Case 01 - GEE Radiant Only IGCC w/o CO2 Heat Rate-net(Btu/kWh): 8,922

 MWe-net: 640

 Capacity Factor: (%): 80

 OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 33.00 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 Skilled Operator 2.0 2.0

 Operator 9.0 9.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 3.0 3.0

 TOTAL-O.J.'s 15.0 15.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $5,637,060 $8.804

Maintenance Labor Cost $12,434,373 $19.421

Administrative & Support Labor $4,517,858 $7.056

TOTAL FIXED OPERATING COSTS $22,589,291 $35.282

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $23,111,454 $0.00515

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

 Water(/1000 gallons) 0 5,874 1.03 $0 $1,766,592 $0.00039

 Chemicals

 MU & WT Chem.(lb) 122,480 17,497 0.16 $20,185 $841,987 $0.00019

 Carbon (Mercury Removal) (lb) 59,493 81 1.00 $59,493 $23,652 $0.00001

 COS Catalyst (m3) 410 0.28 2,308.40 $946,446 $189,160 $0.00004

 Water Gas Shift Catalyst(ft3) 0 0 475.00 $0 $0 $0.00000

 Selexol Solution (gal) 378 54 12.90 $4,877 $203,424 $0.00005

 MDEA Solution (gal) 0 0 0.96 $0 $0 $0.00000

 Sulfinol Solution (gal) 0 0 9.68 $0 $0 $0.00000

 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

 Claus Catalyst(ft3) w/equip. 2.21 125.00 $0 $80,745 $0.00002

Subtotal Chemicals $1,031,000 $1,338,968 $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 81 0.40 $0 $9,499 $0.00000

 Flyash (ton) 0 0 0.00 $0 $0 $0.00000

 Bottom Ash(ton) 0 645 15.45 $0 $2,909,636 $0.00065

 Subtotal-Waste Disposal $0 $2,919,135 $0.00065

 By-products & Emissions 

 Sulfur(tons) 0 147 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $1,031,000 $29,136,149 $0.00649

 Fuel(ton) 176,276 5,876 42.11 $7,422,978 $72,250,323 $0.01610
Cost and Performance Comparison of Fossil Energy Power Plants 

118 

3.2.8 CASE 2 - GEE IGCC WITH CO2 CAPTURE

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 

combustion turbines, 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 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 3-32 and 

Exhibit 3-33, respectively. Instead of repeating the entire process description, only differences 

from Case 1 are reported here. 

Gasification 

The gasification process is the same as Case 1 with the exception that total coal feed to the two 

gasifiers is 5,448 tonnes/day (6,005 TPD) (stream 6) and the ASU provides 4,635 tonnes/day 

(5,110 TPD) of 95 percent oxygen to the gasifier and Claus plant (streams 3 and 5). 

Raw Gas Cooling/Particulate Removal 

Raw gas cooling and particulate removal are the same as Case 1 with the exception that 

approximately 548,122 kg/h (1,208,400 lb/h) of saturated steam at 13.8 MPa (2,000 psia) is 

generated in the radiant SGCs. 

Syngas Scrubber/Sour Water Stripper 

No differences from Case 1. 

Sour Gas Shift (SGS) 

The SGS process was described in Section 3.1.3. In Case 2 steam (stream 10) 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 

10. A second stage of SGS results in 96 percent overall conversion of the CO to CO2. The warm 

syngas from the second stage of SGS (stream 11) is cooled to 232°C (450°F) by producing IP 

steam that is sent to the reheater 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 39°C (103°F) prior to the mercury removal beds. 

Mercury Removal and Acid Gas Removal 

Mercury removal is the same as in Case 1. 

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 17) contains 41 percent H2S and 45 percent CO2 with 

the balance primarily N2. The CO2-rich stream is discussed further in the CO2 compression 

section. 
Cost and Performance Comparison of F

119 

Exhibit 3-32 Case 2 Process Flow Diagram, GEE IGCC with CO2 Capture 

GAS

TURBINE

COMBUSTOR

TURBINE COOLING AIR

QUENCH AND

SYNGAS

SCRUBBER

GAS COOLING

BFW HEATING

& KNOCKOUT

SHIFT

REACTORS

ELEVATED

PRESSURE

ASU

GEE GASIFIER

SECTION

(RADIANT

COOLER)

SOUR

WATER

STRIPPER

MERCURY

REMOVAL

DUAL

STAGE

SELEXOL

UNIT

C

P

HRSG

AMBIENT AIR

SYNGAS

EXPANDER

HYDRO

REACTO

CO

CO2

COMPRESSI

1

589

10

11 12 13

15

17

6 7

2 3

4

20

21 

AIR TO ASU

COAL SLURRY

SLAG

SHIFT

STEAM

WATER RECYCLE

TO PROCESS

DEMAND

NOTE: WATER FROM TAIL

GAS COOLER MODELED, 

BUT NOT SHOWN

NITROGEN DILUENT

SYNGAS

CLEAN

GAS

CO2

STREAMS

NOTE: TAIL GAS BOOST

COMPRESSOR MODELED, 

BUT NOT SHOWN

FLUE GAS

CO2 PURIFICATION

OFF-GAS

VENT GAS

CLAUS

PLANT

OXIDANT

2X ADVANCED

F CLASS

GAS TURBINE

SYNGAS

H/P 

REHEAT

14

CLAUS

PLANT

OXIDANT

STEAM

TURBINE

6.3 MWe

464.0 MWe
Cost and Performance Comparison of F

120 

Exhibit 3-33 Case 2 Stream Table, GEE IGCC with CO2 Capture 

12345 6A 7 8 9 

V-L Mole Fraction 

Ar 0.0094 0.0089 0.0360 0.0024 0.0320 0.0000 0.0000 0.0079 0.0062 CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0010 0.0008 

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3442 0.2666 CO2 0.0003 0.0023 0.0000 0.0000 0.0000 0.0000 0.0000 0.1511 0.1166 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3349 0.2594 H2O 0.0108 0.0836 0.0000 0.0000 0.0000 1.0000 0.0000 0.1429 0.3365 

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0056 N2 0.7719 0.8367 0.0140 0.9922 0.0180 0.0000 0.0000 0.0089 0.0069 

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0017 0.0013 O2 0.2076 0.0685 0.9500 0.0054 0.9500 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 

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 V-L Flowrate (lbmol/hr) 64,331 8,321 214 42,780 13,015 14,511 0 52,422 67,674 

V-L Flowrate (lb/hr) 1,855,930 229,617 6,904 1,200,560 418,847 261,198 0 1,069,860 1,343,90Solids Flowrate (lb/hr) 0 0 0 0 0 444,737 54,925 0 0 Temperature (°F) 232 60 90 385 206 141 410 1,100 410 Pressure (psia) 190.6 16.4 145.0 460.0 980.0 1,050.0 797.7 799.7 797.7 Enthalpy (BTU/lb)B 55.6 18.0 12.5 87.8 37.7 --- 1,710 535.5 474.7 

Density (lb/ft3) 0.741 0.087 0.792 1.424 4.416 --- --- 0.975 1.697 

Molecular Weight 28.849 27.594 32.229 28.063 32.181 --- --- 20.409 19.858 

A - Solids flowrate includes dry coal; V-L flowrate includes slurry water and water from coalB - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of F

121 

Exhibit 3-33 Case 2 Stream Table (continued) 

12 13 14 15 16 17 18 19 20 

V-L Mole Fraction 

Ar 0.0067 0.0067 0.0111 0.0111 0.0000 0.0000 0.0000 0.0182 0.0094 CH4 0.0008 0.0008 0.0022 0.0022 0.0000 0.0000 0.0000 0.0577 0.0000 

CO 0.0117 0.0117 0.0190 0.0190 0.0000 0.0000 0.0000 0.0003 0.0000 CO2 0.4057 0.4057 0.0448 0.0448 1.0000 0.4488 0.0000 0.6784 0.0003 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0000 0.0000 H2 0.5609 0.5609 0.9095 0.9095 0.0000 0.0000 0.0000 0.0170 0.0000 H2O 0.0009 0.0009 0.0000 0.0000 0.0000 0.0394 0.0000 0.0005 0.0108 

H2S 0.0054 0.0054 0.0000 0.0000 0.0000 0.4102 0.0000 0.0228 0.0000 N2 0.0075 0.0075 0.0134 0.0134 0.0000 0.0807 0.0000 0.2051 0.7719 

NH3 0.0003 0.0003 0.0000 0.0000 0.0000 0.0203 0.0000 0.0000 0.0000 O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2076 SO2 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 V-L Flowrate (lbmol/hr) 62,118 62,118 38,323 38,323 23,493 855 0 576 243,972 

V-L Flowrate (lb/hr) 1,243,070 1,243,070 198,981 198,981 1,033,930 31,703 0 21,951 7,038,47Solids Flowrate (lb/hr) 0 0 0 0 0 0 12,514 0 0 Temperature (°F) 103 103 100 386 155 120 373 95 59 Pressure (psia) 736.7 726.7 696.2 460.0 2,214.7 30.5 25.4 776.1 14.7 Enthalpy (BTU/lb)B 28.0 28.0 91.4 480.6 -46.5 39.7 -96.5 14.0 13.8 

Density (lb/ft3) 2.443 2.410 0.602 0.263 30.975 0.184 --- 4.966 0.076 

Molecular Weight 20.012 20.012 5.192 5.192 44.010 37.082 --- 38.086 28.849 

B - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of Fossil Energy Power Plants 

122 

CO2 Compression and Dehydration 

CO2 from the AGR process is generated at three pressure levels. The LP stream is compressed 

from 0.15 MPa (22 psia) to 1.1 MPa (160 psia) and then combined with the MP stream. The HP 

stream is combined between compressor stages at 2.1 MPa (300 psia). The combined stream is 

compressed from 2.1 MPa (300 psia) to a supercritical 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 93 percent CO2 with the balance primarily nitrogen and hydrogen. For modeling 

purposes it was assumed that the impurities were separated from the CO2 and combined with the 

clean syngas stream from the Selexol process. The pure CO2 (stream 16) 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. 

Claus Unit 

The Claus plant is the same as Case 1 with the following exceptions: 

• 5,676 kg/h (12,514 lb/h) of sulfur (stream 18) are produced 

• The waste heat boiler generates 13,555 (29,884 lb/h) of 4.0 MPa (575 psia) steam of 

which 9,603 kg/h (21,172 lb/h) is available to the medium pressure steam header. 

Power Block 

Clean syngas from the AGR plant is combined with a small amount of clean gas from the CO2

compression process (stream 14) and heated to 465°F using HP boiler feedwater before passing 

through an expansion turbine. The clean syngas (stream 15) is diltuted 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 21) exits the CT at 567°C (1052°F) and enters the HRSG where 

additional heat is recovered. The flue gas exits the HRSG at 132°C (270°F) (stream 22) 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/538°C/538°C (1800 

psig/1000°F/1000°F) steam cycle. 

Air Separation Unit 

The same elevated pressure ASU is used in Case 2 and produces 4,635 tonnes/day (5,110 TPD) 

of 95 mole percent oxygen and 13,070 tonnes/day (14,410 TPD) of nitrogen. There is no 

integration between the ASU and the combustion turbine. 

3.2.9 CASE 2 PERFORMANCE RESULTS

The Case 2 modeling assumptions were presented previously in Section 3.2.3. 

The plant produces a net output of 556 MW at a net plant efficiency of 32.5 percent (HHV 

basis). Overall performance for the entire plant is summarized in Exhibit 3-34 which includes 

auxiliary power requirements. The ASU accounts for nearly 64 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 24 

percent of the auxiliary power load. The BFW pumps and cooling water system (circulating 
Cost and Performance Comparison of Fossil Energy Power Plants 

123 

water pumps and cooling tower fan) comprise over 5 percent of the load, leaving 7 percent of the 

auxiliary load for all other systems. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 124 

Exhibit 3-34 Case 2 Plant Performance Summary 

POWER SUMMARY (Gross Power at Generator Terminals, kWe) 

Gas Turbine Power 464,010 

Sweet Gas Expander Power 6,260 

Steam Turbine Power 274,690 

TOTAL POWER, kWe 744,960 

AUXILIARY LOAD SUMMARY, kWe 

Coal Handling 460 

Coal Milling 2,330 

Coal Slurry Pumps 760 

Slag Handling and Dewatering 1,200 

Air Separation Unit Auxiliaries 1,000 

Air Separation Unit Main Air Compressor 72,480 

Oxygen Compressor 11,520 

Nitrogen Compressor 35,870 

Claus Plant Tail Gas Recycle Compressor 990 

CO2 Compressor 27,400 

Boiler Feedwater Pumps 4,580 

Condensate Pump 265 

Flash Bottoms Pump 200 

Circulating Water Pumps 3,580 

Cooling Tower Fans 1,850 

Scrubber Pumps 420 

Selexol Unit Auxiliaries 17,320 

Gas Turbine Auxiliaries 1,000 

Steam Turbine Auxiliaries 100 

Claus Plant/TGTU Auxiliaries 200 

Miscellaneous Balance of Plant (Note 1) 3,000 

Transformer Loss 2,760 

TOTAL AUXILIARIES, kWe 189,285 

NET POWER, kWe 555,675 

Net Plant Efficiency, % (HHV) 32.5 

Net Plant Heat Rate (Btu/kWh) 10,505 

CONDENSER COOLING DUTY 106 kJ/h (106 Btu/h) 1,509 (1,431) 

CONSUMABLES 

As-Received Coal Feed, kg/h (lb/h) 226,968 (500,379) 

Thermal Input, kWt 1,710,780 

Raw Water Usage, m3/min (gpm) 8.7 (4,578) 

Note 1: Includes plant control systems, lighting, HVAC and miscellaneous low voltage loads 
Cost and Performance Comparison of Fossil Energy Power Plants 

 125 

Environmental Performance 

The environmental targets for emissions of Hg, NOx, SO2, and particulate matter were presented 

in Section 2.4. A summary of the plant air emissions for Case 2 is presented in Exhibit 3-35. 

Exhibit 3-35 Case 2 Air Emissions 

kg/GJ 

(lb/106 Btu) 

Tonne/year 

(tons/year) @ 

80% capacity factor 

kg/MWh 

(lb/MWh) 

SO2 0.004 (0.010) 178 (196) 0.034 (0.075) 

NOX 0.020 (0.047) 867 (955) 0.166 (0.366) 

Particulates 0.003 (0.0071) 132 (145) 0.025 (0.056) 

Hg 0.25x10-6

(0.57x10-6) 

0.011 (0.012) 2.0x10-6

(4.5x10-6) 

CO2 8.4 (19.6) 364,000 (401,000) 70 (154) 

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 23 ppmv. 

This results in a concentration in the flue gas of less than 3 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 3-36. 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 AspenPlus model accounts for air components throughout. Carbon leaves the plant as 

unburned carbon in the slag, as dissolved CO2 in the wastewater blowdown stream, and as CO2

in the stack gas, ASU vent gas, and the captured CO2 product. Carbon in the wastewater 

blowdown stream is calculated by difference to close the material balance. The carbon capture 

efficiency is defined as the 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 Comparison of Fossil Energy Power Plants 

 126 

(Carbon in CO2 Product)/[(Carbon in the Coal)-(Carbon in Slag)] or 

281,981/(318,992-6,404) *100 or 

90.2 percent 

Exhibit 3-36 Case 2 Carbon Balance 

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) 

Coal 144,692 (318,992) Slag 2,905 (6,404) 

Air (CO2) 495 (1,091) Stack Gas 14,162 (31,221) 

CO2 Product 127,904 (281,981) 

ASU Vent 103 (228) 

Wastewater 113 (249) 

Total 145,187 (320,083) Total 145,187 (320,083) 

Exhibit 3-37 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, dissolved SO2 in the 

wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is 

considered to be negligible, and the sulfur content of the blowdown stream is calculated by 

difference to close the material balance. The total sulfur capture is represented by the following 

fraction: 

(Sulfur byproduct/Sulfur in the coal) or 

(12,514/12,560) or 

99.6 percent 

Exhibit 3-37 Case 2 Sulfur Balance 

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) 

Coal 5,697 (12,560) Elemental Sulfur 5,676 (12,514) 

Stack Gas 13 (28) 

Wastewater 8 (18) 

Total 5,697 (12,560) Total 5,697 (12,560) 

Exhibit 3-38 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 

makeup is the difference between water demand and internal recycle. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 127 

Exhibit 3-38 Case 2 Water Balance 

Water Use Water Demand, 

m3/min (gpm) 

Internal Recycle, 

m3/min (gpm) 

Raw Water Makeup, 

m3/min (gpm) 

Slurry 1.6 (411) 1.6 (411) 0 

Slag Handling 0.5 (143) 0 0.5 (143) 

Quench/Scrubber 2.5 (665) 1.2 (315) 1.3 (350) 

Shift Steam 1.8 (479) 0 1.8 (479) 

BFW Makeup 0.2 (45) 0 0.2 (45) 

Cooling Tower 

Makeup 13.9 (3,679) 0.4 (118) 13.5 (3,561) 

Total 20.5 (5,422) 3.2 (844) 17.3 (4,578) 

Heat and Mass Balance Diagrams 

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-39 through 

Exhibit 3-43: 

• Coal gasification and air separation unit 

• Syngas cleanup 

• Sulfur recovery and tail gas recycle 

• Combined cycle power generation 

• Steam and feedwater 

An overall plant energy balance is presented in tabular form in Exhibit 3-44. The power out is 

the combined combustion turbine, steam turbine and expander power prior to generator losses. 

The power at the generator terminals (shown in Exhibit 3-34) is calculated by multiplying the 

power out by a combined generator efficiency of 98.3 percent. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 128 

This page intentionally left blank 
129 

Exhibit 3-39 Case 2 Coal Gasification and Air Separation Units Heat and Mass Bala
130 

Exhibit 3-40 Case 2 Syngas Cleanup Heat and Mass Balance Schematic 
131 

Exhibit 3-41 Case 2 Sulfur Recovery and Tail Gas Recycle Heat and Mass Balance 
132 

Exhibit 3-42 Case 2 Combined-Cycle Power Generation Heat and Mass Balance 
133 

Exhibit 3-43 Case 2 Steam and Feedwater Heat and Mass Balance Schema
134 

This page intentionally left blank 
Cost and Performance Comparison of Fossil Energy Power Plants 

 135 

Exhibit 3-44 Case 2 Overall Energy Balance (0°C [32°F] Reference) 

HHV Sensible + Latent Power Total 

Heat In (MMBtu/hr) 

Coal 5,837.4 4.9 5,842.3 

ASU Air 25.6 25.6 

CT Air 96.9 96.9 

Water 13.3 13.3 

Auxiliary Power 646.0 646.0 

Totals 5,837.4 140.7 646.0 6,624.1 

Heat Out (MMBtu/hr) 

ASU Intercoolers 269.0 269.0 

ASU Vent 4.1 4.1 

Slag 90.2 3.7 93.9 

Sulfur 49.8 (1.2) 48.6 

Tail Gas Compressor 

Intercoolers 3.5 3.5 

CO2 Compressor 

Intercoolers 138.0 138.0 

CO2 Product (48.1) (48.1) 

HRSG Flue Gas 1,250.1 1,250.1 

Condenser 1,431.0 1,431.0 

Process Losses 847.4 847.4 

Power 2,586.5 2,586.5 

Totals 140.0 3,897.5 2,586.5 6,624.1 

(1) Process Losses are calculated by difference and reflect various gasification, turbine, 

HRSG and other heat and work losses. Aspen flowsheet balance is within 0.5 percent. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 136 

3.2.10 CASE 2 - MAJOR EQUIPMENT LIST

Major equipment items for the GEE gasifier with CO2 capture are shown in the following tables. 

The accounts used in the equipment list correspond to the account numbers used in the cost 

estimates in Section 3.2.11. 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 Operating 

Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0

3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0

5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling 

System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0

8 Reclaim Hopper N/A 2 1

9 Feeder Vibratory 2 1

10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor 

reduction 2 0

14 As-Fired Coal Sampling 

System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0

17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 3 0

N/A

372 tonne/h (410 tph)

816 tonne (900 ton)

45 tonne (50 ton)

191 tonne/h (210 tph)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

372 tonne/h (410 tph)

191 tonne (210 ton)

N/A

N/A

372 tonne/h (410 tph)

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph)

N/A

1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)

1,134 tonne/h (1,250 tph)
Cost and Performance Comparison of Fossil Energy Power Plants 

 137 

ACCOUNT 2 COAL PREPARATION AND FEED 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Coal Feeder Gravimetric 3 0

2 Conveyor No. 6 Belt w/tripper 1 0

3 Rod Mill Feed Hopper Dual Outlet 1 0

4 Weigh Feeder Belt 2 0

5 Rod Mill Rotary 2 0

6 Slurry Water Storage Tank 

with Agitator Field erected 2 0

7 Slurry Water Pumps Centrifugal 2 2

10 Trommel Screen Coarse 2 0

11 Rod Mill Discharge Tank with 

Agitator Field erected 2 0

12 Rod Mill Product Pumps Centrifugal 2 2

13 Slurry Storage Tank with 

Agitator Field erected 2 0

14 Slurry Recycle Pumps Centrifugal 2 2

15 Slurry Product Pumps Positive 

displacement 2 2

172 tonne/h (190 tph)

2,726 lpm (720 gpm)

5,451 lpm (1,440 gpm)

984,215 liters (260,000 gal)

127 tonne/h (140 tph)

327,441 liters (86,500 gal)

2,726 lpm (720 gpm)

871 lpm (230 gpm)

127 tonne/h (140 tph)

306,621 liters (81,000 gal)

Design Condition

82 tonne/h (90 tph)

254 tonne/h (280 tph)

499 tonne (550 ton)
Cost and Performance Comparison of Fossil Energy Power Plants 

 138 

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT 

Equipment 

No. Description Type Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 3 0

2 Condensate Pumps Vertical canned 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 2 0

4 Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage 2 1

6 High Pressure 

Feedwater Pump No. 2

Barrel type, multistage, centrifugal 2 1

7 Auxiliary Boiler Shop fabricated, water 

tube 1 0

8 Service Air 

Compressors Flooded Screw 2 1

9 Instrument Air Dryers Duplex, regenerative 2 1

10 Closed Cylce Cooling 

Heat Exchangers Plate and frame 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 2 1

12 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine 1 1

13 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal 1 1

14 Raw Water Pumps Stainless steel, single 

suction 2 1

15 Filtered Water Pumps Stainless steel, single 

suction 2 1

16 Filtered Water Tank Vertical, cylindrical 2 0

17 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 2 0

18 Liquid Waste Treatment 

System 1 0

1,363 lpm @ 707 m H2O

(360 gpm @ 2320 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C

(40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

Design Condition

1,037,211 liters (274,000 gal)

7,457 lpm @ 91 m H2O

(1,970 gpm @ 300 ft H2O)

544,311 kg/h (1,200,000 lb/h)

IP water: 1,817 lpm @ 223 m H2O 

(480 gpm @ 730 ft H2O)

HP water: 6,662 lpm @ 1,890 m 

H2O (1,760 gpm @ 6,200 ft H2O)

3,710 lpm @ 49 m H2O

(980 gpm @ 160 ft H2O)

28 m3/min (1,000 scfm)

58 MMkJ/h (55 MMBtu/h) each

20,820 lpm @ 21 m H2O

(5,500 gpm @ 70 ft H2O)

3,785 lpm @ 88 m H2O

(1,000 gpm @ 290 ft H2O)

2,650 lpm @ 64 m H2O

(700 gpm @ 210 ft H2O)

9,615 lpm @ 18 m H2O

(2,540 gpm @ 60 ft H2O)

1,786,728 liter (472,000 gal)

1,173 lpm (310 gpm)

10 years, 24-hour storm

5 2 1 High Pressure 

Feedwater Pump No. 1

Barrel type, multistage, centrifugal
Cost and Performance Comparison of Fossil Energy Power Plants 

 139 

ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW 

TEMPERATURE HEAT RECOVERY 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Gasifier Pressurized slurry-feed, 

entrained bed 2 0

2 Synthesis Gas Cooler

Vertical downflow 

radiant heat exchanger 

with outlet quench 

chamber

2 0

3

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 2 0

4 Raw Gas Coolers Shell and tube with 

condensate drain 6 0

5 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator 2 0

6 Flare Stack

Self-supporting, carbon 

steel, stainless steel 

top, pilot ignition

2 0

7 ASU Main Air 

Compressor

Centrifugal, multistage

2 0

8 Cold Box Vendor design 2 0

9 Oxygen Compressor Centrifugal, multistage

2 0

10 Nitrogen Compressor Centrifugal, multistage

2 0

11 Nitrogen Boost 

Compressor

Centrifugal, multistage

2 0

595 m3/min @ 2.3 MPa

(21,000 scfm @ 340 psia)

335,205 kg/h (739,000 lb/h) 

syngas

6,343 m3/min @ 1.3 MPa

(224,000 scfm @ 190 psia)

2,540 tonne/day (2,800 tpd)

of 95% purity oxygen

1,274 m3/min @ 7.1 MPa

(45,000 scfm @ 1,030 psia)

3,625 m3/min @ 3.4 MPa

(128,000 scfm @ 490 psia)

Design Condition

2,994 tonne/day, 5.6 MPa 

(3,300 tpd, 815 psia)

280,774 kg/h (619,000 lb/h)

335,205 kg/h (739,000 lb/h)

395,079 kg/h (871,000 lb/h)

297,103 kg/h, 38°C, 5.2 MPa

(655,000 lb/h, 100°F, 747 psia)
Cost and Performance Comparison of Fossil Energy Power Plants 

 140 

ACCOUNT 5A SOUR GAS SHIFT AND SYNGAS CLEANUP 

Equipment 

No. Description Type OperatingQty. Spares

1 Mercury Adsorber Sulfated carbon 

bed 2 0

2 Sulfur Plant Claus type 1 0

3 Water Gas Shift Reactors Fixed bed, 

catalytic 4 0

4 Shift Reactor Heat Recovery 

Exhchangers Shell and Tube 4 0

5 Acid Gas Removal Plant Two-stage 

Selexol 2 0

6 Hydrogenation Reactor Fixed bed, 

catalytic 1 0

7 Tail Gas Recycle 

Compressor Centrifugal 1 0

Exchanger 1: 148 MMkJ/h (140 

MMBtu/h)

Exchanger 2: 32 MMkJ/h (30 

MMBtu/h)

11,431 kg/h @ 6.4 MPa

(25,200 lb/h @ 930 psi)

395,079 kg/h (871,000 lb/h)

232°C (450°F) 5.5 MPa (798 psia)

310,258 kg/h (684,000 lb/h) 39°C 

(103°F) 5.0 MPa (727 psia)

15,513 kg/h (34,200 lb/h)

232°C (450°F) 0.2 MPa (25 psia)

Design Condition

310,258 kg/h (684,000 lb/h) 39°C 

(103°F) 5.1 MPa (737 psia)

150 tonne/day (165 tpd)

ACCOUNT 5B CO2 COMPRESSION 

Equipment 

No. Description Type Operating Qty. Spares

1 CO2 Compressor Integrally geared, multistage centrifugal 4 1

Design Condition

1,157 m3/min @ 15.3 MPa

(40,859 scfm @ 2,215 psia)
Cost and Performance Comparison of Fossil Energy Power Plants 

 141 

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Gas Turbine Advanced F class 2 0

2 Gas Turbine Generator TEWAC 2 0

3 Syngas Expansion 

Turbine/Generator Turbo expander 2 0

Design Condition

232 MW 

260 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

49,641 kg/h (109,440 lb/h)

4.8 MPa (691 psia) Inlet

3.2 MPa (460 psia) Outlet

ACCOUNT 7 HRSG, DUCTING, AND STACK 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Stack CS plate, type 409SS 

liner 1 0

Design Condition

76 m (250 ft) high x

8.5 m (28 ft) diameter

Main steam - 376,049 kg/h, 12.4 

MPa/538°C (829,045 lb/h, 1,800 

psig/1,000°F)

2 2 0 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator

 Reheat steam - 381,590 kg/h, 

2.9 MPa/538°C (841,261 lb/h, 

420 psig/1,000°F)
Cost and Performance Comparison of Fossil Energy Power Plants 

 142 

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitiation 1 0

3 Steam Bypass One per HRSG 2 0

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1 0

330 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase

50% steam flow @ design 

steam conditions

Design Condition

298 MW 

12.4 MPa/538°C/538°C 

(1800 psig/ 

1000°F/1000°F)

1,676 MMkJ/h (1,590 

MMBtu/h) heat duty, Inlet 

water temperature 16°C 

(60°F), Water temperature 

rise 11°C (20°F)

ACCOUNT 9 COOLING WATER SYSTEM 

Equipment 

No. Description Type Operating Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell1 0

Design Condition

359,617 lpm @ 30 m

(95,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) 

HWT 2,003 MMkJ/h (1,900 

MMBtu/h) heat duty
Cost and Performance Comparison of Fossil Energy Power Plants 

 143 

ACCOUNT 10 SLAG RECOVERY AND HANDLING 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Slag Quench Tank Water bath 2 0

2 Slag Crusher Roll 2 0

3 Slag Depressurizer Lock Hopper 2 0

4 Slag Receiving Tank Horizontal, weir 2 0

5 Black Water Overflow Tank Shop fabricated 2 0

6 Slag Conveyor Drag chain 2 0

7 Slag Separation Screen Vibrating 2 0

8 Coarse Slag Conveyor Belt/bucket 2 0

9 Fine Ash Settling Tank Vertical, gravity 2 0

10 Fine Ash Recycle Pumps Horizontal 

centrifugal 2 2

11 Grey Water Storage Tank Field erected 2 0

12 Grey Water Pumps Centrifugal 2 2

13 Slag Storage Bin Vertical, field 

erected 2 0

14 Unloading Equipment Telescoping chute 1 0

253,625 liters (67,000 gal)

76 lpm @ 14 m H2O

(20 gpm @ 46 ft H2O)

998 tonne (1,100 tons)

118 tonne/h (130 tph)

83,280 liters (22,000 gal)

303 lpm @ 564 m H2O

(80 gpm @ 1,850 ft H2O)

170,345 liters (45,000 gal)

14 tonne/h (15 tph)

14 tonne/h (15 tph)

14 tonne/h (15 tph)

79,494 liters (21,000 gal)

Design Condition

261,195 liters (69,000 gal)

14 tonne/h (15 tph)

14 tonne/h (15 tph)
Cost and Performance Comparison of Fossil Energy Power Plants 

 144 

ACCOUNT 11 ACCESSORY ELECTRIC PLANT 

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, 260 MVA, 

3-ph, 60 Hz

2 STG Transformer Oil-filled 24 kV/345 kV, 110 MVA, 

3-ph, 60 Hz 1 0

24 kV/4.16 kV, 207 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 31 MVA, 

3-ph, 60 Hz

750 kW, 480 V, 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

ACCOUNT 12 INSTRUMENTATION AND CONTROL 

Equipment 

No. Description Type OperatingQty. 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 Comparison of Fossil Energy Power Plants 

 145 

3.2.11 CASE 2 - COST ESTIMATING

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-45 shows 

the total plant cost summary organized by cost account and Exhibit 3-46 shows a more detailed 

breakdown of the capital costs. Exhibit 3-47 shows the initial and annual O&M costs. 

The estimated TPC of the GEE gasifier with CO2 capture is $2,390/kW. Process contingency 

represents 4.2 percent of the TPC and project contingency represents 13.6 percent. The 20-year 

LCOE, including CO2 TS&M costs of 3.9 mills/kWh, is 102.9 mills/kWh. 
Cost and Performance Comparison of F

 146 

Exhibit 3-45 Case 2 Total Plant Cost Summary 

Client: USDOE/NETL Report D

Project: Bituminous Baseline Study

Case: Case 02 - GEE Radiant Only IGCC w/ CO2

Plant Size: 555.7 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Proje

 1 COAL & SORBENT HANDLING $13,688 $2,552 $10,726 $0 $0 $26,966 $2,443 $0 $5

 2 COAL & SORBENT PREP & FEED $23,455 $4,274 $14,205 $0 $0 $41,934 $3,803 $1,522 $9 3 FEEDWATER & MISC. BOP SYSTEMS $10,144 $8,686 $9,657 $0 $0 $28,487 $2,661 $0 $7

 4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $103,362 $0 $57,380 $0 $0 $160,742 $14,715 $22,192 $304.2 Syngas Cooler(w/ Gasifier - 4.1 ) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 

4.3 ASU/Oxidant Compression $157,723 $0 w/equip. $0 $0 $157,723 $15,012 $0 $17

4.4-4.9 Other Gasification Equipment $12,297 $11,735 $12,985 $0 $0 $37,018 $3,516 $0 $8

SUBTOTAL 4 $273,383 $11,735 $70,365 $0 $0 $355,484 $33,243 $22,192 $56

 5A Gas Cleanup & Piping $79,047 $4,945 $70,370 $0 $0 $154,363 $14,797 $22,231 $38

 5B CO2 REMOVAL & COMPRESSION $17,712 $0 $10,865 $0 $0 $28,577 $2,732 $0 $6

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $88,000 $0 $5,325 $0 $0 $93,325 $8,779 $9,332 $11

6.2-6.9 Combustion Turbine Other $5,270 $752 $1,575 $0 $0 $7,598 $715 $0 $1

SUBTOTAL 6 $93,270 $752 $6,900 $0 $0 $100,922 $9,494 $9,332 $12

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,193 $0 $4,581 $0 $0 $36,774 $3,471 $0 $4

7.2-7.9 Ductwork and Stack $3,222 $2,268 $3,011 $0 $0 $8,501 $785 $0 $1

SUBTOTAL 7 $35,415 $2,268 $7,592 $0 $0 $45,275 $4,256 $0 $5

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $28,444 $0 $4,847 $0 $0 $33,291 $3,190 $0 $3

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,439 $943 $7,306 $0 $0 $18,688 $1,684 $0 $4

SUBTOTAL 8 $38,883 $943 $12,153 $0 $0 $51,979 $4,875 $0 $7

 9 COOLING WATER SYSTEM $7,074 $7,437 $6,229 $0 $0 $20,740 $1,905 $0 $4

10 ASH/SPENT SORBENT HANDLING SYS $14,265 $7,973 $14,470 $0 $0 $36,708 $3,509 $0 $4

11 ACCESSORY ELECTRIC PLANT $23,997 $11,838 $23,440 $0 $0 $59,275 $5,162 $0 $1212 INSTRUMENTATION & CONTROL $10,469 $1,960 $7,028 $0 $0 $19,457 $1,793 $973 $3

13 IMPROVEMENTS TO SITE $3,318 $1,956 $8,248 $0 $0 $13,522 $1,328 $0 $4

14 BUILDINGS & STRUCTURES $0 $6,410 $7,441 $0 $0 $13,851 $1,259 $0 $2

TOTAL COST $644,121 $73,729 $279,690 $0 $0 $997,540 $93,261 $56,251 $181

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 147 

Exhibit 3-46 Case 2 Total Plant Cost Details 

Client: USDOE/NETL Repor

Project: Bituminous Baseline Study

Case: Case 02 - GEE Radiant Only IGCC w/ CO2

Plant Size: 555.7 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenci

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $3,595 $0 $1,775 $0 $0 $5,370 $481 $0 1.2 Coal Stackout & Reclaim $4,645 $0 $1,138 $0 $0 $5,783 $507 $0 1.3 Coal Conveyors $4,319 $0 $1,126 $0 $0 $5,445 $478 $0 1.4 Other Coal Handling $1,130 $0 $260 $0 $0 $1,390 $122 $0 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,552 $6,427 $0 $0 $8,979 $856 $0 

SUBTOTAL 1. $13,688 $2,552 $10,726 $0 $0 $26,966 $2,443 $0 

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying incl w/2.3 incl. w/ 2.3 incl. w/ 2.3 incl. w/ 2.3 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,537 $366 $244 $0 $0 $2,146 $184 $0 2.3 Slurry Prep & Feed $21,073 $0 $9,373 $0 $0 $30,446 $2,760 $1,522 2.4 Misc.Coal Prep & Feed $845 $612 $1,863 $0 $0 $3,320 $304 $0 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,296 $2,725 $0 $0 $6,021 $555 $0 

SUBTOTAL 2. $23,455 $4,274 $14,205 $0 $0 $41,934 $3,803 $1,522 

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 FeedwaterSystem $3,396 $5,905 $3,119 $0 $0 $12,420 $1,146 $0 3.2 Water Makeup & Pretreating $577 $60 $322 $0 $0 $960 $91 $0 3.3 Other Feedwater Subsystems $1,875 $636 $573 $0 $0 $3,084 $276 $0 3.4 Service Water Systems $333 $679 $2,358 $0 $0 $3,370 $326 $0 3.5 Other Boiler Plant Systems $1,787 $686 $1,701 $0 $0 $4,173 $391 $0 3.6 FO Supply Sys & Nat Gas $306 $577 $539 $0 $0 $1,421 $136 $0 3.7 Waste Treatment Equipment $802 $0 $492 $0 $0 $1,294 $125 $0 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $1,068 $144 $553 $0 $0 $1,765 $170 $0 

SUBTOTAL 3. $10,144 $8,686 $9,657 $0 $0 $28,487 $2,661 $0 

 4 GASIFIER & ACCESSORIES

4.1 Syngas Cooler Gasifier System $103,362 $0 $57,380 $0 $0 $160,742 $14,715 $22,192 $4.2 Syngas Cooler(w/ Gasifier - 4.1 ) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $157,723 $0 w/equip. $0 $0 $157,723 $15,012 $0 $4.4 Scrubber & Low Temperature Cooling $9,391 $7,629 $7,963 $0 $0 $24,983 $2,381 $0 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 4.6 Other Gasification Equipment $2,907 $1,380 $2,730 $0 $0 $7,017 $671 $0 4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $2,726 $2,292 $0 $0 $5,018 $463 $0 

SUBTOTAL 4. $273,383 $11,735 $70,365 $0 $0 $355,484 $33,243 $22,192 $

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

148 

Exhibit 3-46 Case 2 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Report Date: 0

Project: Bituminous Baseline Study

Case: Case 02 - GEE Radiant Only IGCC w/ CO2

Plant Size: 555.7 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 ($x1

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOT

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project 

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $59,515 $0 $51,050 $0 $0 $110,564 $10,614 $22,113 $28,658 5A.2 Elemental Sulfur Plant $10,010 $1,987 $12,925 $0 $0 $24,922 $2,403 $0 $5,465 5A.3 Mercury Removal $1,340 $0 $1,020 $0 $0 $2,360 $226 $118 $541 5A.4 Shift Reactors $8,183 $0 $3,380 $0 $0 $11,563 $1,101 $0 $2,533 5A.5 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.7 Fuel Gas Piping $0 $1,862 $1,283 $0 $0 $3,146 $287 $0 $686 5A.9 HGCU Foundations $0 $1,096 $712 $0 $0 $1,808 $166 $0 $592 

SUBTOTAL 5A. $79,047 $4,945 $70,370 $0 $0 $154,363 $14,797 $22,231 $38,475 

 5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $17,712 $0 $10,865 $0 $0 $28,577 $2,732 $0 $6,262 

SUBTOTAL 5B. $17,712 $0 $10,865 $0 $0 $28,577 $2,732 $0 $6,262 

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $88,000 $0 $5,325 $0 $0 $93,325 $8,779 $9,332 $11,144 6.2 Syngas Expander $5,270 $0 $737 $0 $0 $6,007 $567 $0 $986 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $752 $838 $0 $0 $1,591 $148 $0 $522 

SUBTOTAL 6. $93,270 $752 $6,900 $0 $0 $100,922 $9,494 $9,332 $12,651 

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,193 $0 $4,581 $0 $0 $36,774 $3,471 $0 $4,025 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,627 $1,179 $0 $0 $2,806 $246 $0 $610 7.4 Stack $3,222 $0 $1,211 $0 $0 $4,433 $422 $0 $485 7.9 HRSG,Duct & Stack Foundations $0 $641 $620 $0 $0 $1,262 $117 $0 $414 

SUBTOTAL 7. $35,415 $2,268 $7,592 $0 $0 $45,275 $4,256 $0 $5,534 

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $28,444 $0 $4,847 $0 $0 $33,291 $3,190 $0 $3,648 8.2 Turbine Plant Auxiliaries $195 $0 $449 $0 $0 $645 $63 $0 $71 8.3 Condenser & Auxiliaries $4,788 $0 $1,407 $0 $0 $6,195 $588 $0 $678 8.4 Steam Piping $5,455 $0 $3,844 $0 $0 $9,299 $793 $0 $2,523 8.9 TG Foundations $0 $943 $1,605 $0 $0 $2,548 $240 $0 $837 

SUBTOTAL 8. $38,883 $943 $12,153 $0 $0 $51,979 $4,875 $0 $7,757 

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $4,602 $0 $1,012 $0 $0 $5,614 $531 $0 $922 9.2 Circulating Water Pumps $1,448 $0 $92 $0 $0 $1,540 $132 $0 $251 9.3 Circ.Water System Auxiliaries $119 $0 $17 $0 $0 $136 $13 $0 $22 9.4 Circ.Water Piping $0 $5,063 $1,292 $0 $0 $6,354 $563 $0 $1,383 9.5 Make-up Water System $320 $0 $454 $0 $0 $774 $73 $0 $170 9.6 Component Cooling Water Sys $584 $698 $493 $0 $0 $1,775 $164 $0 $388 9.9 Circ.Water System Foundations& Structures $0 $1,676 $2,870 $0 $0 $4,546 $429 $0 $1,492 

SUBTOTAL 9. $7,074 $7,437 $6,229 $0 $0 $20,740 $1,905 $0 $4,628 

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $11,749 $6,479 $13,172 $0 $0 $31,400 $3,008 $0 $3,441 10.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $569 $0 $619 $0 $0 $1,188 $114 $0 $195 10.7 Ash Transport & Feed Equipment $768 $0 $184 $0 $0 $953 $88 $0 $156 10.8 Misc. Ash Handling Equipment $1,178 $1,444 $432 $0 $0 $3,054 $289 $0 $501 10.9 Ash/Spent Sorbent Foundation $0 $50 $63 $0 $0 $113 $11 $0 $37 

SUBTOTAL 10. $14,265 $7,973 $14,470 $0 $0 $36,708 $3,509 $0 $4,331 

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

149 

Exhibit 3-46 Case 2 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Repor

Project: Bituminous Baseline Study

Case: Case 02 - GEE Radiant Only IGCC w/ CO2

Plant Size: 555.7 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenci

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $903 $0 $900 $0 $0 $1,803 $171 $0 11.2 Station Service Equipment $4,284 $0 $402 $0 $0 $4,686 $445 $0 11.3 Switchgear & Motor Control $8,187 $0 $1,501 $0 $0 $9,687 $897 $0 11.4 Conduit & Cable Tray $0 $3,895 $12,645 $0 $0 $16,540 $1,581 $0 11.5 Wire & Cable $0 $7,154 $4,812 $0 $0 $11,966 $875 $0 11.6 Protective Equipment $0 $640 $2,427 $0 $0 $3,067 $300 $0 11.7 Standby Equipment $215 $0 $219 $0 $0 $434 $42 $0 11.8 Main Power Transformers $10,409 $0 $139 $0 $0 $10,548 $799 $0 11.9 Electrical Foundations $0 $149 $395 $0 $0 $544 $52 $0 

SUBTOTAL 11. $23,997 $11,838 $23,440 $0 $0 $59,275 $5,162 $0 $

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,034 $0 $719 $0 $0 $1,752 $169 $88 12.5 Signal Processing Equipment W/12.7 $0 W/12.7 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $238 $0 $159 $0 $0 $396 $38 $20 12.7 Computer & Accessories $5,513 $0 $184 $0 $0 $5,697 $540 $285 12.8 Instrument Wiring & Tubing $0 $1,960 $4,102 $0 $0 $6,062 $514 $303 12.9 Other I & C Equipment $3,685 $0 $1,864 $0 $0 $5,550 $533 $277 

SUBTOTAL 12. $10,469 $1,960 $7,028 $0 $0 $19,457 $1,793 $973 

13 Improvements to Site

13.1 Site Preparation $0 $104 $2,242 $0 $0 $2,346 $231 $0 13.2 Site Improvements $0 $1,851 $2,479 $0 $0 $4,330 $425 $0 13.3 Site Facilities $3,318 $0 $3,527 $0 $0 $6,845 $672 $0 

SUBTOTAL 13. $3,318 $1,956 $8,248 $0 $0 $13,522 $1,328 $0 

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $221 $127 $0 $0 $348 $31 $0 14.2 Steam Turbine Building $0 $2,290 $3,307 $0 $0 $5,597 $514 $0 14.3 Administration Building $0 $833 $612 $0 $0 $1,446 $129 $0 14.4 Circulation Water Pumphouse $0 $156 $84 $0 $0 $240 $21 $0 14.5 Water Treatment Buildings $0 $460 $454 $0 $0 $914 $82 $0 14.6 Machine Shop $0 $426 $296 $0 $0 $722 $64 $0 14.7 Warehouse $0 $688 $450 $0 $0 $1,139 $101 $0 14.8 Other Buildings & Structures $0 $412 $325 $0 $0 $738 $66 $0 14.9 Waste Treating Building & Str. $0 $922 $1,785 $0 $0 $2,707 $252 $0 

SUBTOTAL 14. $0 $6,410 $7,441 $0 $0 $13,851 $1,259 $0 

TOTAL COST $644,121 $73,729 $279,690 $0 $0 $997,540 $93,261 $56,251 $1

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of Fossil Energy Power Plants 

150 

Exhibit 3-47 Case 2 Initial and Annual Operating and Maintenance Costs 

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006

Case 02 - GEE Radiant Only IGCC w/ CO2 Heat Rate-net(Btu/kWh): 10,505

 MWe-net: 556

 Capacity Factor: (%): 80

 OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 33.00 $/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 $6,012,864 $10.820

Maintenance Labor Cost $13,432,424 $24.172

Administrative & Support Labor $4,861,322 $8.748

TOTAL FIXED OPERATING COSTS $24,306,610 $43.741

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $24,602,924 $0.00632

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

 Water(/1000 gallons) 0 6,594 1.03 $0 $1,983,139 $0.00051

 Chemicals

 MU & WT Chem.(lb) 137,493 19,642 0.16 $22,659 $945,198 $0.00024

 Carbon (Mercury Removal) (lb) 84,811 116 1.00 $84,811 $33,872 $0.00001

 COS Catalyst (m3) 0 0 2,308.40 $0 $0 $0.00000

 Water Gas Shift Catalyst(ft3) 6,288 4.30 475.00 $2,986,800 $596,410 $0.00015

 Selexol Solution (gal) 504 72 12.90 $6,502 $271,232 $0.00007

 MDEA Solution (gal) 0 0 0.96 $0 $0 $0.00000

 Sulfinol Solution (gal) 0 0 9.68 $0 $0 $0.00000

 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

 Claus Catalyst(ft3) w/equip 2.25 125.00 $0 $82,125 $0.00002

Subtotal Chemicals $3,100,772 $1,928,837 $0.00050

 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) 0 116 0.40 $0 $13,603 $0.00000

 Flyash (ton) 0 0 0.00 $0 $0 $0.00000

 Bottom Ash(ton) 0 659 15.45 $0 $2,973,464 $0.00076

 Subtotal-Waste Disposal $0 $2,987,067 $0.00077

 By-products & Emissions 0 0 0.00 $0 $0.00000

 Sulfur(tons) 0 150 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $3,100,772 $31,501,967 $0.00809

 Fuel(ton) 180,143 6,005 42.11 $7,585,825 $73,835,368 $0.01896
Cost and Performance Comparison of Fossil Energy Power Plants 

151 

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 

ConocoPhillips (CoP) E-GasTM gasifier. Cases 3 and 4 are very similar in terms of process, 

equipment, scope and arrangement, except that Case 4 includes sour gas shift 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 GASIFIER BACKGROUND

Dow Chemical (the former principal stockholder of Destec Energy, which was bought by Global 

Energy, Inc., the gasifier business that was purchased by ConocoPhillips) is a major producer of 

chemicals. They began coal gasification development work in 1976 with bench-scale (2 kg/h 

[4 lb/h]) reactor testing. Important fundamental data were obtained for conversion and yields 

with various coals and operating conditions. This work led to the construction of a pilot plant at 

Dow’s large chemical complex in Plaquemine, Louisiana. The pilot plant was designed for a 

capacity of 11 tonnes/day (12 TPD) (dry lignite basis) and was principally operated with air as 

the oxidant. The plant also operated with oxygen at an increased capacity of 33 tonnes/day 

(36 TPD) (dry lignite basis). This pilot plant operated from 1978 through 1983. 

Following successful operation of the pilot plant, Dow built a larger 499 tonnes/day (550 TPD) 

(dry lignite basis) gasifier at Plaquemine. In 1984, Dow Chemical and the U.S. Synthetic Fuels 

Corporation (SFC) announced a price guarantee contract which allowed the building of the first 

commercial-scale Dow coal gasification unit. The Louisiana Gasification Technology, Inc. 

(LGTI) plant, sometimes called the Dow Syngas Project, was also located in the Dow 

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, 
Cost and Performance Comparison of Fossil Energy Power Plants 

152 

Indiana to produce 265 MW of net power from local high-sulfur bituminous coal. The design of 

the project gasifier was based on the Destec LGTI gasifier. Experience gained in that project 

provided significant input to the design of the Wabash River coal gasification facility and 

eliminated much of the risk associated with scale-up and process variables. 

Gasifier Capacity – The 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/h 

(5 million scf/h) with an energy content of about 1,370 MMkJ/h (1,300 MMBtu/h) (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/h (6.7 million scf/h) with an energy content of about 1,950 MMkJ/h (1,850 MMBtu/h) 

(HHV). This size matches the combustion turbine, which is a GE 7FA. 

With increased power and fuel gas turbine 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 Comparison of Fossil Energy Power Plants 

153 

3.3.2 PROCESS DESCRIPTION

In this section the overall CoP gasification process is described. The system description follows 

the BFD in Exhibit 3-48 and stream numbers reference the same Exhibit. The tables in 

Exhibit 3-49 provide process data for the numbered streams in the BFD. 

Coal Grinding and Slurry Preparation 

Coal receiving and handling is common to all cases and was covered in Section 3.1.1. The 

receiving and handling subsystem ends at the coal silo. Coal grinding and slurry preparation is 

similar to the GEE cases but repeated here for completeness. 

Coal from the coal silo is fed onto a conveyor by vibratory feeders located below each silo. The 

conveyor feeds the coal to an inclined conveyor that delivers the coal to the rod mill feed hopper. 

The feed hopper provides a surge capacity of about two hours and contains two hopper outlets. 

Each hopper outlet discharges onto a weigh feeder, which in turn feeds a rod mill. Each rod mill 

is sized to process 55 percent of the coal feed requirements of the gasifier. The rod mill grinds 

the coal and wets it with treated slurry water transferred from the slurry water tank by the slurry 

water pumps. The coal slurry is discharged through a trommel screen into the rod mill discharge 

tank, and then the slurry is pumped to the slurry storage tanks. The dry solids concentration of 

the final slurry is 63 percent. The Polk Power Station operates at a slurry concentration of 62-68 

percent using bituminous coal and CoP presented a paper showing the slurry concentration of 

Illinois No. 6 coal as 63 percent. [39, 47] 

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). 

Gasification 

This plant utilizes two gasification trains to process a total of 5,050 tonnes/day (5,567 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. 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 1,010°C (1,850°F). Total slurry to both stages is shown as stream 6 in Exhibit 3-48. 
Cost and Performance Comparison of F

154 

Exhibit 3-48 Case 3 Process Flow Diagram, E-GasTM IGCC without CO2 Capture 
Cost and Performance Comparison of F

155 

Exhibit 3-49 Case 3 Stream Table, E-GasTM IGCC without CO2 Capture 

12345 6A 7 8 9 

V-L Mole Fraction 

Ar 0.0092 0.0262 0.0360 0.0024 0.0320 0.0000 0.0000 0.0080 0.0080 CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0400 0.0400 

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3851 0.3851 CO2 0.0003 0.0090 0.0000 0.0000 0.0000 0.0000 0.0000 0.1468 0.1473 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2738 0.2738 H2O 0.0099 0.2756 0.0000 0.0004 0.0000 1.0000 0.0000 0.1251 0.1246 

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0079 0.0084 N2 0.7732 0.4638 0.0140 0.9919 0.0180 0.0000 0.0000 0.0102 0.0102 

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0026 0.0026 O2 0.2074 0.2254 0.9500 0.0054 0.9500 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 

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 V-L Flowrate (lbmol/hr) 41,839 1,917 242 40,619 10,830 13,452 0 55,289 55,289 

V-L Flowrate (lb/hr) 1,207,360 51,005 7,811 1,139,740 348,539 242,145 0 1,196,610 1,196,61Solids Flowrate (lb/hr) 0 0 0 0 0 412,305 47,201 0 0 Temperature (°F) 235 70 90 385 191 140 1,850 400 401 Pressure (psia) 190.0 16.4 125.0 460.0 740.0 850.0 850.0 554.7 544.7 Enthalpy (BTU/lb)B 55.7 26.8 12.5 88.0 34.4 --- 1,120 241.5 241.4 

Density (lb/ft3) 0.735 0.104 0.683 1.424 3.412 --- --- 1.302 1.277 

Molecular Weight 28.857 26.613 32.229 28.060 32.181 --- --- 21.643 21.643 

A - Solids flowrate includes dry coal; V-L flowrate includes slurry water and water from coalB - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of F

156 

Exhibit 3-49 Case 3 Stream Table Continued 

12 13 14 15 16 17 18 19 20 

V-L Mole Fraction 

Ar 0.0095 0.0088 0.0088 0.0000 0.0000 0.0059 0.0092 0.0094 0.0094 CH4 0.0471 0.0434 0.0434 0.0001 0.0000 0.0000 0.0383 0.0000 0.0000 

CO 0.4544 0.4189 0.4189 0.0014 0.0000 0.0910 0.0003 0.0000 0.0000 CO2 0.1513 0.1395 0.1395 0.7034 0.0000 0.4812 0.8551 0.0003 0.0003 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0004 0.0000 0.0000 0.0000 H2 0.3235 0.2982 0.2982 0.0010 0.0000 0.0186 0.0097 0.0000 0.0000 H2O 0.0019 0.0798 0.0798 0.0000 0.0000 0.3490 0.0023 0.0108 0.0108 

H2S 0.0000 0.0000 0.0000 0.2941 0.0000 0.0068 0.0140 0.0000 0.0000 N2 0.0120 0.0111 0.0111 0.0000 0.0000 0.0454 0.0710 0.7719 0.7719 

NH3 0.0002 0.0002 0.0002 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 0.2076 0.2076 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0017 0.0000 0.0000 0.0000 

Total 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (lbmol/hr) 37,428 40,600 40,600 1,205 0 1,596 1,021 243,395 12,038 

V-L Flowrate (lb/hr) 806,593 863,729 863,729 49,439 0 50,953 42,010 7,021,820 347,293 Solids Flowrate (lb/hr) 0 0 0 0 11,591 0 0 0 0 Temperature (°F) 99 266 385 187 368 320 251 59 811 Pressure (psia) 494.2 484.2 479.2 30.0 24.9 24.9 804.1 14.7 234.9 Enthalpy (BTU/lb)B 24.2 153.9 197.6 33.3 -97.5 288.6 49.1 13.8 200.3 

Density (lb/ft3) 1.776 1.324 1.125 0.177 --- 0.095 4.340 0.076 0.497 

Molecular Weight 21.550 21.274 21.274 41.022 --- 31.929 41.154 28.849 28.849 

B - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of Fossil Energy Power Plants 

157 

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 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 3.9 vol% (compared to 0.10 vol% in Case 1 [GEE] 

and 0.04 vol% in Case 5 [Shell]). The relatively high CH4 concentration impacts CO2 capture 

efficiency as discussed further in Section 3.3.8. 

Raw Gas Cooling/Particulate Removal 

The 1,010°C (1,850°F) raw coal gas from the second stage of the gasifier is cooled to 371°C 

(700°F) in the waste heat recovery (synthesis gas cooler) unit, which consists of a fire-tube boiler 

and convective superheating and economizing sections. 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 high-pressure synthesis gas in relatively small tubes. 

The coal ash is converted to molten slag, which flows down through a tap hole. The molten slag 

is quenched in water and removed through a proprietary continuous-pressure letdown/dewatering 

system (stream 7). Char is produced in the second gasifier stage and is 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 provide syngas reheat prior to the COS reactor and to generate steam for the LP steam header. In this manner the 

syngas is cooled to 166°C (330°F) prior to the syngas scrubber. 

Syngas Scrubber/Sour Water Stripper 

Syngas exiting the second of the two low temperature heat exchangers passes to a syngas 

scrubber where a water wash is used to remove chlorides and particulate. The syngas exits the 

scrubber saturated at 152°C (305°F). 

The sour water stripper removes NH3, SO2, and other impurities from the scrubber and other 

waste streams. The stripper consists of a sour drum that accumulates sour water from the gas 

scrubber and condensate from synthesis gas coolers. Sour water from the drum flows to the sour 

stripper, which consists of a packed column with a steam-heated reboiler. Sour gas is stripped 

from the liquid and sent to the sulfur recovery unit. Remaining water is sent to wastewater 

treatment. 

COS Hydryolysis, Mercury Removal and Acid Gas Removal 

Syngas exiting the scrubber is reheated to 400°F and enters a COS hydrolysis reactor (stream 8). 

About 99.5 percent of the COS is converted to CO2 and H2O (Section 3.1.5). The gas exiting the 

COS reactor (stream 9) passes through a series of heat exchangers and knockout drums to lower 

the syngas temperature to 39°C (103°F) and to separate entrained water. The cooled syngas 

(stream 10) then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.4). 
Cost and Performance Comparison of Fossil Energy Power Plants 

158 

Cool, particulate-free synthesis gas (stream 11) enters the absorber unit at approximately 

3.4 MPa (495 psia) and 39°C (103°F). In the absorber, H2S is preferentially removed from the 

fuel gas stream by contact with MDEA. The absorber column is operated at 27°C (80°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 

15), consisting of 29 percent H2S and 70 percent CO2, is sent to the Claus unit. The acid gas is 

combined with the sour water stripper off gas and introduced into the Claus plant burner section. 

Claus Unit 

Acid gas from the MDEA unit is preheated to 232°C (450°F). A portion of the acid gas along 

with all of the sour gas from the stripper and oxygen from the ASU are fed to the Claus furnace. 

In the furnace, H2S is catalytically oxidized to SO2 at a furnace temperature of 1,316°C 

(2,400°F), which must be maintained in order to thermally decompose all of the NH3 present in 

the sour gas stream. 

Following the thermal stage and condensation of sulfur, two reheaters and two sulfur converters 

are used to obtain a per-pass H2S conversion of approximately 99.5 percent. The Claus Plant tail 

gas is hydrogenated and recycled back to the gasifier (stream 18). In the furnace waste heat 

boiler, 14,710 kg/h (32,430 lb/h) of 4.0 MPa (575 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 low-pressure steam header. 

A flow rate of 5,258 kg/h (11,591 lb/h) of elemental sulfur (stream 16) is recovered from the fuel 

gas stream. This value represents an overall sulfur recovery efficiency of 99.5 percent. 

Power Block 

Clean syngas exiting the MDEA absorber (stream 12) is partially humidified (stream 13) 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 14), further 

diluted with nitrogen from the ASU (stream 4) and enters the advanced F Class combustion 

turbine (CT) burner. The CT compressor provides combustion air to the burner and also 22 

percent of the total ASU air requirement (stream 20). The exhaust gas exits the CT at 599°C 

(1,111°F) (stream 21) and enters the HRSG where additional heat is recovered until the flue gas 

exits the HRSG at 132°C (270°F) (stream 22) 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/566°C/566°C (1800 psig/1050°F/1050°F) steam cycle. 

Air Separation Unit (ASU) 

The elevated pressure ASU was described in Section 3.1.2. In Case 3 the ASU is designed to 

produce a nominal output of 3,880 tonnes/day (4,275 TPD) of 95 mole percent 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 12,410 tonnes/day 

(13,680 TPD) of nitrogen are also recovered, compressed, and used as dilution in the gas turbine 

combustor (stream 4). About 4.9 percent of the gas turbine air is used to supply approximately 

22 percent of the ASU air requirements (stream 20). 
Cost and Performance Comparison of Fossil Energy Power Plants 

159 

Balance of Plant 

Balance of plant items were covered in Sections 3.1.9, 3.1.10 and 3.1.11. 

3.3.3 KEY SYSTEM ASSUMPTIONS

System assumptions for Cases 3 and 4, CoP IGCC with and without CO2 capture, are compiled 

in Exhibit 3-50. 

Balance of Plant – Cases 3 and 4 

The balance of plant assumptions are common to all cases and were presented previously in 

Exhibit 3-17. 

3.3.4 SPARING PHILOSOPHY

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. 

The plant design consists of the following major subsystems: 

• Two air separation units (2 x 50%) 

• Two trains of slurry preparation and slurry pumps (2 x 50%) 

• Two trains of gasification, including gasifier, synthesis gas cooler, cyclone, and barrier 

filter (2 x 50%). 

• Two trains of syngas clean-up process (2 x 50%). 

• Two trains of refrigerated MDEA acid gas gas removal in Case 3 and two-stage Selexol 

in Case 4 (2 x 50%), 

• One train of Claus-based sulfur recovery (1 x 100%). 

• Two combustion turbine/HRSG tandems (2 x 50%). 

• One steam turbine (1 x 100%). 
Cost and Performance Comparison of Fossil Energy Power Plants 

160 

Exhibit 3-50 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 0.85 0.85 

Carbon Conversion, % 99.2 99.2 

Syngas HHV at MDEA Outlet, 

kJ/Nm3

 (Btu/scf) 11,131 (299) 12,918 (347) 

Steam Cycle, MPa/°C/°C 

(psig/°F/°F) 

12.4/566/566 

(1800/1050/1050) 

12.4/538/538 

(1800/1000/1000) 

Condenser Pressure, mm Hg 

(in Hg) 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 CoP E-GasTM CoP E-GasTM 

Oxidant 95 vol% Oxygen 95 vol% Oxygen 

Coal Illinois No. 6 Illinois No. 6 

Coal Slurry Solids Conent, % 63 63 

COS Hydrolysis Yes Occurs in SGS 

Sour Gas Shift No Yes 

H2S Separation Refrigerated MDEA Selexol 1st Stage 

Sulfur Removal, % 99.5 99.7 

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 

CO2 Capture N/A 88.4% from Syngas 

CO2 Sequestration N/A Off-site Saline Formation 
Cost and Performance Comparison of Fossil Energy Power Plants 

161 

3.3.5 CASE 3 PERFORMANCE RESULTS

The plant produces a net output of 623 MWe at a net plant efficiency of 39.3 percent (HHV 

basis). CoP recently reported the same efficiency for their gasifier using Illinois No. 6 coal and 

an amine based AGR. [47] 

Overall performance for the entire plant is summarized in Exhibit 3-51 which includes auxiliary 

power requirements. The ASU accounts for over 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 circulating water pumps and 

cooling tower fan, accounts for over 4 percent of the auxiliary load, and the BFW pumps account 

for an additional 3.6 percent. All other individual auxiliary loads are less than 3 percent of the 

total. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 162 

Exhibit 3-51 Case 3 Plant Performance Summary 

POWER SUMMARY (Gross Power at Generator Terminals, kWe) 

Gas Turbine Power 464,030 

Steam Turbine Power 278,480 

TOTAL POWER, kWe 742,510 

AUXILIARY LOAD SUMMARY, kWe 

Coal Handling 440 

Coal Milling 2,160 

Coal Slurry Pumps 570 

Slag Handling and Dewatering 1,110 

Air Separation Unit Auxiliaries 1,000 

Air Separation Unit Main Air Compressor 47,130 

Oxygen Compressor 8,240 

Nitrogen Compressor 34,680 

Syngas Recycle Blower 2,130 

Tail Gas Recycle Blower 1,760 

Boiler Feedwater Pumps 4,280 

Condensate Pump 220 

Flash Bottoms Pump 200 

Circulating Water Pumps 3,350 

Cooling Tower Fans 1,730 

Scrubber Pumps 70 

SS Amine Unit Auxiliaries 3,230 

Gas Turbine Auxiliaries 1,000 

Steam Turbine Auxiliaries 100 

Claus Plant/TGTU Auxiliaries 200 

Miscellaneous Balance of Plant (Note 1) 3,000 

Transformer Loss 2,540 

TOTAL AUXILIARIES, kWe 119,140 

NET POWER, kWe 623,370 

Net Plant Efficiency, % (HHV) 39.3 

Net Plant Heat Rate (Btu/kWh) 8,681 

CONDENSER COOLING DUTY 106 kJ/h (106 Btu/h) 1,468 (1,393) 

CONSUMABLES 

As-Received Coal Feed, kg/h (lb/h) 210,417 (463,889) 

Thermal Input, kWt 1,586,023 

Raw Water Usage, m3/min (gpm) 14.2 (3,757) 

Note 1: Includes plant control systems, lighting, HVAC and miscellaneous low voltage loads 
Cost and Performance Comparison of Fossil Energy Power Plants 

 163 

Environmental Performance 

The environmental targets for emissions of Hg, NOx, SO2 and particulate matter were presented 

in Section 2.4. A summary of the plant air emissions for Case 3 is presented in Exhibit 3-52. 

Exhibit 3-52 Case 3 Air Emissions 

kg/GJ 

(lb/106 Btu) 

Tonne/year 

(ton/year) 

80% capacity factor 

kg/MWh 

(lb/MWh) 

SO2 0.0054 (0.0125) 215 (237) 0.041 (0.091) 

NOX 0.026 (0.059) 1,021 (1,126) 0.196 (0.433) 

Particulates 0.003 (0.0071) 122 (135) 0.023 (0.052) 

Hg 0.25x10-6

(0.57x10-6) 0.010 (0.011) 1.9x10-6 (4.2x10-6) 

CO2 85.7 (199) 3,427,000 (3,778,000) 659 (1,452) 

CO2

1 785 (1,730) 

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 Amine AGR process. The AGR process removes over 99 percent of the 

sulfur compounds in the fuel gas down to a level of less than 30 ppmv. This results in a 

concentration in the flue gas of less than 4 ppmv. The H2S-rich regeneration gas from the AGR 

system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is 

hydrogenated to convert all sulfur species to H2S and then recycled back to the 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 3-53. 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 CO2 in the stack 

gas and ASU vent gas. Carbon in the wastewater blowdown stream is calculated by difference to 

close the material balance. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 164 

Exhibit 3-53 Case 3 Carbon Balance 

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) 

Coal 134,141 (295,729) Slag 1,006 (2,218) 

Air (CO2) 465 (1,026) Stack Gas 133,374 (294,039) 

ASU Vent 94 (207) 

Wastewater 132 (291) 

Total 134,606 (296,755) Total 134,606 (296,755) 

Exhibit 3-54 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, dissolved SO2 in the 

wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is 

considered to be negligible, and the sulfur content of the blowdown stream is calculated by 

difference to close the material balance. The total sulfur capture is represented by the following 

fraction: 

(Sulfur byproduct/Sulfur in the coal) or 

(11,591/11,644) or 

99.5 percent 

Exhibit 3-54 Case 3 Sulfur Balance 

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) 

Coal 5,281 (11,644) Elemental Sulfur 5,257 (11,591) 

Stack Gas 15 (34) 

Wastewater 9 (19) 

Total 5,281 (11,644) Total 5,281 (11,644) 

Exhibit 3-55 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 

makeup is the difference between water demand and internal recycle. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 165 

Exhibit 3-55 Case 3 Water Balance 

Water Use Water Demand, 

m3/min (gpm) 

Internal Recycle, 

m3/min (gpm) 

Raw Water Makeup, 

m3/min (gpm) 

Slurry 1.4 (381) 1.1 (292) 0.3 (89) 

Slag Handling 0.5 (123) 0 0.5 (123) 

Syngas Humidifier 0.5 (133) 0 0.5 (133) 

BFW Makeup 0.2 (40) 0 0.2 (40) 

Cooling Tower 

Makeup 13.0 (3,442) 0.3 (70) 12.7 (3,372) 

Total 15.6 (4,119) 1.4 (362) 14.2 (3,757) 

Heat and Mass Balance Diagrams 

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-56 through 

Exhibit 3-60: 

• Coal gasification and air separation unit 

• Syngas cleanup 

• Sulfur recovery and tail gas recycle 

• Combined cycle power generation 

• Steam and feedwater 

An overall plant energy balance is provided in tabular form in Exhibit 3-61. The power out is 

the combined combustion turbine and steam turbine power prior to generator losses. The power 

at the generator terminals (shown in Exhibit 3-51) is calculated by multiplying the power out by 

a combined generator efficiency of 98.3 percent. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 166 

This page intentionally left blank 
167 

Exhibit 3-56 Case 3 Coal Gasification and Air Separation Unit Heat and Mass Balan
168 

Exhibit 3-57 Case 3 Syngas Cleanup Heat and Mass Balance Schematic 
169 

Exhibit 3-58 Case 3 Sulfur Recovery and Tail Gas Recycle Heat and Mass Balance 
170 

Exhibit 3-59 Case 3 Combined Cycle Power Generation Heat and Mass Balance 
171 

Exhibit 3-60 Case 3 Steam and Feedwater Heat and Mass Balance Schema
172 

This page intentionally left blank 
Cost and Performance Comparison of Fossil Energy Power Plants 

 173 

Exhibit 3-61 Case 3 Overall Energy Balance (0°C [32°F] Reference) 

HHV Sensible + Latent Power Total 

Heat In (MMBtu/hr) 

Coal 5,411.7 4.5 5,416.2 

ASU Air 15.9 15.9 

CT Air 96.7 96.7 

Water 4.3 4.3 

Auxiliary Power 406.5 406.5 

Totals 5,411.7 121.3 406.5 5,939.6 

Heat Out (MMBtu/hr) 

ASU Intercoolers 203.0 203.0 

ASU Vent 1.4 1.4 

Slag 31.3 21.6 52.9 

Sulfur 46.2 (1.1) 45.0 

Tail Gas Compressor 

Intercoolers 6.3 6.3 

HRSG Flue Gas 928.0 928.0 

Condenser 1,393.0 1,393.0 

Process Losses 732.1 732.1 

Power 2,577.9 2,577.9 

Totals 77.5 3,284.2 2,577.9 5,939.6 

(1) Process Losses are calculated by difference and reflect various gasification, turbine, 

HRSG and other heat and work losses. Aspen flowsheet balance is within 0.5 percent. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 174 

3.3.6 CASE 3 - MAJOR EQUIPMENT LIST

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 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 Operating 

Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0

3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0

5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling 

System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0

8 Reclaim Hopper N/A 2 1

9 Feeder Vibratory 2 1

10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor 

reduction 2 0

14 As-Fired Coal Sampling 

System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0

17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 3 0

N/A

345 tonne/h (380 tph)

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph)

N/A

1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)

1,134 tonne/h (1,250 tph)

45 tonne (50 ton)

172 tonne/h (190 tph)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

345 tonne/h (380 tph)

172 tonne (190 ton)

N/A

N/A

345 tonne/h (380 tph)

816 tonne (900 ton)
Cost and Performance Comparison of Fossil Energy Power Plants 

 175 

ACCOUNT 2 COAL PREPARATION AND FEED 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Feeder Vibratory 3 0

2 Conveyor No. 6 Belt w/tripper 1 0

3 Rod Mill Feed Hopper Dual Outlet 1 0

4 Weigh Feeder Belt 2 0

5 Rod Mill Rotary 2 0

6 Slurry Water Storage Tank 

with Agitator Field erected 2 0

7 Slurry Water Pumps Centrifugal 2 2

10 Trommel Screen Coarse 2 0

11 Rod Mill Discharge Tank with 

Agitator Field erected 2 0

12 Rod Mill Product Pumps Centrifugal 2 2

13 Slurry Storage Tank with 

Agitator Field erected 2 0

14 Slurry Recycle Pumps Centrifugal 2 2

15 Slurry Product Pumps Positive 

displacement 2 2

Design Condition

82 tonne/h (90 tph)

236 tonne/h (260 tph)

463 tonne (510 ton)

118 tonne/h (130 tph)

303,592 liters (80,200 gal)

2,536 lpm (670 gpm)

795 lpm (210 gpm)

118 tonne/h (130 tph)

283,908 liters (75,000 gal)

163 tonne/h (180 tph)

2,536 lpm (670 gpm)

5,072 lpm (1,340 gpm)

908,506 liters (240,000 gal)
Cost and Performance Comparison of Fossil Energy Power Plants 

 176 

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT 

Equipment 

No. Description Type OperatingQty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 2 0

2 Condensate Pumps Vertical canned 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 2 0

4 Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage 2 1

6 High Pressure 

Feedwater Pump No. 2

Barrel type, multistage, centrifugal 2 1

7 Auxiliary Boiler Shop fabricated, water 

tube 1 0

8 Service Air 

Compressors Flooded Screw 2 1

9 Instrument Air Dryers Duplex, regenerative 2 1

10 Closed Cylce Cooling 

Heat Exchangers Plate and frame 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 2 1

12 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine 1 1

13 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal 1 1

14 Raw Water Pumps Stainless steel, single 

suction 2 1

15 Filtered Water Pumps Stainless steel, single 

suction 2 1

16 Filtered Water Tank Vertical, cylindrical 2 0

17 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 2 0

18 Liquid Waste Treatment 

System 1 0

5 2 1 High Pressure 

Feedwater Pump No. 1

Barrel type, multistage, centrifugal

715,448 liter (189,000 gal)

151 lpm (40 gpm)

10 years, 24-hour storm

1,476 lpm @ 49 m H2O

(390 gpm @ 160 ft H2O)

28 m3/min (1,000 scfm)

58 MMkJ/h (55 MMBtu/h) each

20,820 lpm @ 21 m H2O

(5,500 gpm @ 70 ft H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

7,912 lpm @ 18 m H2O

(2,090 gpm @ 60 ft H2O)

1,325 lpm @ 283 m H2O

(350 gpm @ 930 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C

(40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

Design Condition

1,101,563 liters (291,000 gal)

6,132 lpm @ 91 m H2O

(1,620 gpm @ 300 ft H2O)

463,118 kg/h (1,021,000 lb/h)

IP water: 909 lpm @ 390 m H2O 

(240 gpm @ 1,280 ft H2O)

HP water: 6,511 lpm @ 1,890 m 

H2O (1,720 gpm @ 6,200 ft 

H2O)
Cost and Performance Comparison of Fossil Energy Power Plants 

 177 

ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW 

TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION 

Equipment 

No. Description Type Operating Qty. Spares

1 Gasifier

Pressurized two-stage, 

slurry-feed entrained 

bed

2 0

2 Synthesis Gas Cooler Fire-tube boiler 2 0

3 Synthesis Gas Cyclone High efficiency 2 0

4 Candle Filter Pressurized filter with 

pulse-jet cleaning 2 0

5

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 2 0

6 Raw Gas Coolers Shell and tube with 

condensate drain 6 0

7 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator 2 0

8 Saturation Water 

Economizers Shell and tube 2 0

9 Fuel Gas Saturator Vertical tray tower 2 0

10 Saturator Water Pump Centrifugal 2 2

11 Synthesis Gas Reheater Shell and tube 2 0

12 Flare Stack

Self-supporting, carbon 

steel, stainless steel 

top, pilot ignition

2 0

13 ASU Main Air 

Compressor

Centrifugal, multistage

2 0

14 Cold Box Vendor design 2 0

15 Oxygen Compressor Centrifugal, multistage

2 0

16 Nitrogen Compressor Centrifugal, multistage2 0

17 Nitrogen Boost 

Compressor

Centrifugal, multistage

2 0

18 Extraction Air Heat 

Exchanger

Gas-to-gas, vendor 

design 2 0

metallic filters

298,464 kg/h (658,000 lb/h)

275,784 kg/h (608,000 lb/h)

266,259 kg/h, 39°C, 3.6 MPa

(587,000 lb/h, 103°F, 515 psia)

Design Condition

2,812 tonne/day, 4.2 MPa

(3,100 tpd, 615 psia)

304,361 kg/h (671,000 lb/h)

291,660 kg/h (643,000 lb/h) 

Design efficiency 90%

275,784 kg/h (608,000 lb/h)

201,395 kg/h, 130°C, 3.3 MPa

(444,000 lb/h, 266°F, 484 psia)

4,543 lpm @ 201 m H2O

(1,200 gpm @ 660 ft H2O)

215,457 kg/h (475,000 lb/h)

481 m3/min @ 2.3 MPa

(17,000 scfm @ 340 psia)

86,636 kg/h, 433°C, 1.6 MPa

(191,000 lb/h, 811°F, 235 psia)

298,464 kg/h (658,000 lb/h) 

syngas

4,134 m3/min @ 1.3 MPa

(146,000 scfm @ 190 psia)

2,177 tonne/day (2,400 tpd)

of 95% purity oxygen

1,076 m3/min @ 5.1 MPa

(38,000 scfm @ 740 psia)

3,540 m3/min @ 3.4 MPa

(125,000 scfm @ 490 psia)
Cost and Performance Comparison of Fossil Energy Power Plants 

 178 

ACCOUNT 5 SYNGAS CLEANUP 

Equipment 

No. Description Type OperatingQty. Spares

1 Mercury Adsorber Sulfated carbon 

bed 2 0

2 Sulfur Plant Claus type 1 0

3 COS Hydrolysis Reactor Fixed bed, 

catalytic 2 0

4 Acid Gas Removal Plant MDEA 2 0

5 Hydrogenation Reactor Fixed bed, 

catalytic 1 0

6 Tail Gas Recycle 

Compressor Centrifugal 1 0

Design Condition

234,054 kg/h (516,000 lb/h)

39°C (103°F) 3.4 MPa (495 psia)

139 tonne/day (153 tpd)

298,464 kg/h (658,000 lb/h) 204°C 

(400°F) 3.8 MPa (555 psia)

21,772 kg/h @ 6.6 MPa

(48,000 lb/h @ 950 psia)

213,642 kg/h (471,000 lb/h)

39°C (103°F) 3.3 MPa (485 psia)

25,401 kg/h (56,000 lb/h)

232°C (450°F) 0.2 MPa (25 psia)

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty. Spares

1 Gas Turbine Advanced F class 2 0

2 Gas Turbine Generator TEWAC 2 0

Design Condition

232 MW 

260 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

ACCOUNT 7 HRSG, STACK AND DUCTING 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Stack CS plate, type 409SS 

liner 1 0

2 2 0 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator

 Reheat steam - 361,875 kg/h, 

2.9 MPa/566°C (797,796 lb/h, 

420 psig/1,050°F)

Design Condition

76 m (250 ft) high x

8.3 m (27 ft) diameter

Main steam - 368,554 kg/h, 12.4 

MPa/566°C (812,522 lb/h, 1,800 

psig/1,050°F)
Cost and Performance Comparison of Fossil Energy Power Plants 

 179 

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitiation 1 0

3 Steam Bypass One per HRSG 2 0

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1 0

293 MW 

12.4 MPa/566°C/566°C 

(1800 psig/ 

1050°F/1050°F)

1,613 MMkJ/h (1,530 

MMBtu/h), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 

11°C (20°F)

330 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase

50% steam flow @ design 

steam conditions

Design Condition

ACCOUNT 9 COOLING WATER SYSTEM 

Equipment 

No. Description Type Operating Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell1 0

Design Condition

336,904 lpm @ 30 m

(89,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT, 

1,876 MMkJ/h (1,780 MMBtu/h) 

heat duty
Cost and Performance Comparison of Fossil Energy Power Plants 

 180 

ACCOUNT 10 SLAG RECOVERY AND HANDLING 

Equipment 

No. Description Type Operating Qty. Spares

1 Slag Quench Tank Water bath 2 0

2 Slag Crusher Roll 2 0

3 Slag Depressurizer Proprietary 2 0

4 Slag Receiving Tank Horizontal, weir 2 0

5 Black Water Overflow Tank Shop fabricated 2

6 Slag Conveyor Drag chain 2 0

7 Slag Separation Screen Vibrating 2 0

8 Coarse Slag Conveyor Belt/bucket 2 0

9 Fine Ash Settling Tank Vertical, gravity 2 0

10 Fine Ash Recycle Pumps Horizontal 

centrifugal 2 2

11 Grey Water Storage Tank Field erected 2 0

12 Grey Water Pumps Centrifugal 2 2

13 Grey Water Recycle Heat 

Exchanger Shell and tube 2 0

14 Slag Storage Bin Vertical, field 

erected 2 0

15 Unloading Equipment Telescoping chute 1 0

Design Condition

223,341 liters (59,000 gal)

12 tonne/h (13 tph)

12 tonne/h (13 tph)

147,632 liters (39,000 gal)

12 tonne/h (13 tph)

12 tonne/h (13 tph)

12 tonne/h (13 tph)

68,138 liters (18,000 gal)

219,556 liters (58,000 gal)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

816 tonne (900 tons)

100 tonne/h (110 tph)

71,923 liters (19,000 gal)

265 lpm @ 433 m H2O

(70 gpm @ 1,420 ft H2O)

15,876 kg/h (35,000 lb/h)
Cost and Performance Comparison of Fossil Energy Power Plants 

 181 

ACCOUNT 11 ACCESSORY ELECTRIC PLANT 

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 750 kW, 480 V, 3-ph, 60 Hz 1 0

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

1 0

24 kV/4.16 kV, 130 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 19 MVA, 

3-ph, 60 Hz

Design Condition

24 kV/345 kV, 260 MVA, 

3-ph, 60 Hz

2 STG Transformer Oil-filled 24 kV/345 kV, 190 MVA, 

3-ph, 60 Hz

ACCOUNT 12 INSTRUMENTATION AND CONTROLS 

Equipment 

No. Description Type OperatingQty. 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

2 DCS - Processor

Microprocessor with 

redundant 

input/output

N/A 1 0

Fully redundant, 25% spare
Cost and Performance Comparison of Fossil Energy Power Plants 

 182 

3.3.7 CASE 3 - COSTS ESTIMATING RESULTS

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-62 shows 

the total plant capital cost summary organized by cost account and Exhibit 3-63 shows a more 

detailed breakdown of the capital costs. Exhibit 3-64 shows the initial and annual O&M costs. 

The estimated TPC of the CoP gasifier with no CO2 capture is $1,733/kW. Process contingency 

represents 2.5 percent of the TPC and project contingency is 13.3 percent. The 20-year LCOE is 

75.3 mills/kWh. 
Cost and Performance Comparison of F

 183 

Exhibit 3-62 Case 3 Total Plant Cost Summary 

Client: USDOE/NETL Report Da

Project: Bituminous Baseline Study

Case: Case 03 - ConocoPhillips IGCC w/o CO2

Plant Size: 623.4 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Projec

 1 COAL & SORBENT HANDLING $13,060 $2,435 $10,233 $0 $0 $25,728 $2,088 $0 $5,

 2 COAL & SORBENT PREP & FEED $22,211 $4,065 $13,559 $0 $0 $39,835 $3,200 $0 $8,

 3 FEEDWATER & MISC. BOP SYSTEMS $9,148 $7,886 $8,644 $0 $0 $25,678 $2,149 $0 $6,

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $90,425 $0 $55,527 $0 $0 $145,952 $11,971 $21,893 $26,

4.2 Syngas Cooling (w/4.1) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 

4.3 ASU/Oxidant Compression $137,711 $0 w/equip. $0 $0 $137,711 $11,743 $0 $14,

4.4-4.9 Other Gasification Equipment $18,487 $8,580 $11,695 $0 $0 $38,763 $3,285 $0 $9,

SUBTOTAL 4 $246,624 $8,580 $67,222 $0 $0 $322,427 $26,999 $21,893 $50,

 5A Gas Cleanup & Piping $50,895 $4,805 $38,080 $0 $0 $93,780 $8,032 $104 $20,

 5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $82,000 $0 $5,071 $0 $0 $87,071 $7,338 $4,354 $9,

6.2-6.9 Combustion Turbine Other $0 $684 $762 $0 $0 $1,446 $121 $0 $

SUBTOTAL 6 $82,000 $684 $5,833 $0 $0 $88,517 $7,459 $4,354 $10,

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,926 $0 $4,828 $0 $0 $38,754 $3,277 $0 $4,

7.2-7.9 Ductwork and Stack $3,123 $2,198 $2,918 $0 $0 $8,239 $682 $0 $1,

SUBTOTAL 7 $37,049 $2,198 $7,745 $0 $0 $46,992 $3,959 $0 $5,

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $28,109 $0 $4,930 $0 $0 $33,039 $2,837 $0 $3,

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,092 $953 $7,185 $0 $0 $18,229 $1,473 $0 $3,

SUBTOTAL 8 $38,201 $953 $12,115 $0 $0 $51,268 $4,310 $0 $7,

 9 COOLING WATER SYSTEM $6,760 $7,303 $6,124 $0 $0 $20,187 $1,661 $0 $4,

10 ASH/SPENT SORBENT HANDLING SYS $18,173 $1,373 $9,021 $0 $0 $28,568 $2,437 $0 $3,

11 ACCESSORY ELECTRIC PLANT $22,608 $9,796 $19,825 $0 $0 $52,229 $4,054 $0 $10,12 INSTRUMENTATION & CONTROL $9,358 $1,752 $6,282 $0 $0 $17,391 $1,436 $870 $3,

13 IMPROVEMENTS TO SITE $3,155 $1,860 $7,843 $0 $0 $12,858 $1,132 $0 $4,

14 BUILDINGS & STRUCTURES $0 $6,209 $7,240 $0 $0 $13,449 $1,095 $0 $2,

TOTAL COST $559,240 $59,898 $219,767 $0 $0 $838,905 $70,010 $27,220 $144,

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 184 

Exhibit 3-63 Total Plant Cost Details 

Client: USDOE/NETL Repor

Project: Bituminous Baseline Study

Case: Case 03 - ConocoPhillips IGCC w/o CO2

Plant Size: 623.4 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenc

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $3,430 $0 $1,693 $0 $0 $5,123 $411 $0 1.2 Coal Stackout & Reclaim $4,432 $0 $1,086 $0 $0 $5,517 $433 $0 1.3 Coal Conveyors $4,120 $0 $1,074 $0 $0 $5,195 $409 $0 1.4 Other Coal Handling $1,078 $0 $249 $0 $0 $1,327 $104 $0 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,435 $6,132 $0 $0 $8,566 $731 $0 

SUBTOTAL 1. $13,060 $2,435 $10,233 $0 $0 $25,728 $2,088 $0 

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying incl w/2.3 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,462 $348 $232 $0 $0 $2,042 $157 $0 2.3 Slurry Prep & Feed $19,945 $0 $8,962 $0 $0 $28,908 $2,310 $0 2.4 Misc.Coal Prep & Feed $804 $582 $1,772 $0 $0 $3,158 $259 $0 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,135 $2,592 $0 $0 $5,727 $473 $0 

SUBTOTAL 2. $22,211 $4,065 $13,559 $0 $0 $39,835 $3,200 $0 

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 FeedwaterSystem $3,088 $5,369 $2,836 $0 $0 $11,293 $934 $0 3.2 Water Makeup & Pretreating $502 $52 $280 $0 $0 $834 $71 $0 3.3 Other Feedwater Subsystems $1,705 $578 $521 $0 $0 $2,804 $225 $0 

3.4 Service Water Systems $289 $590 $2,049 $0 $0 $2,928 $254 $0 3.5 Other Boiler Plant Systems $1,553 $596 $1,478 $0 $0 $3,626 $305 $0 3.6 FO Supply Sys & Nat Gas $299 $565 $527 $0 $0 $1,391 $119 $0 3.7 Waste Treatment Equipment $697 $0 $427 $0 $0 $1,124 $98 $0 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $1,015 $136 $526 $0 $0 $1,678 $145 $0 

SUBTOTAL 3. $9,148 $7,886 $8,644 $0 $0 $25,678 $2,149 $0 

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $90,425 $0 $55,527 $0 $0 $145,952 $11,971 $21,893 $

4.2 Syngas Cooling ( w/ 4.1) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $137,711 $0 w/equip. $0 $0 $137,711 $11,743 $0 $4.4 LT Heat Recovery & FG Saturation $18,487 $0 $6,956 $0 $0 $25,443 $2,191 $0 4.5 Misc. Gasification Equipment w/4.1 & 4.2 w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 4.6 Other Gasification Equipment $0 $1,142 $465 $0 $0 $1,607 $137 $0 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $7,439 $4,275 $0 $0 $11,713 $957 $0 

SUBTOTAL 4. $246,624 $8,580 $67,222 $0 $0 $322,427 $26,999 $21,893 $

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 185 

Exhibit 3-63 Total Plant Cost Details (continued) 

Client: USDOE/NETL Report Da

Project: Bituminous Baseline Study

Case: Case 03 - ConocoPhillips IGCC w/o CO2

Plant Size: 623.4 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project 

 5A GAS CLEANUP & PIPING

5A.1 MDEA-LT AGR $34,245 $0 $16,003 $0 $0 $50,248 $4,291 $0 $10,95A.2 Elemental Sulfur Plant $11,411 $2,265 $14,734 $0 $0 $28,410 $2,454 $0 $6,5A.3 Mercury Removal $1,177 $0 $897 $0 $0 $2,074 $178 $104 $45A.4 COS Hydrolysis $3,651 $0 $4,771 $0 $0 $8,422 $728 $0 $1,85A.5 Open $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $410 $230 $130 $0 $0 $770 $65 $0 $5A.7 Fuel Gas Piping $0 $1,161 $800 $0 $0 $1,961 $160 $0 $45A.9 HGCU Foundations $0 $1,149 $746 $0 $0 $1,895 $155 $0 $6

SUBTOTAL 5A. $50,895 $4,805 $38,080 $0 $0 $93,780 $8,032 $104 $20,5

 5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $82,000 $0 $5,071 $0 $0 $87,071 $7,338 $4,354 $9,86.2 Open $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $684 $762 $0 $0 $1,446 $121 $0 $4

SUBTOTAL 6. $82,000 $684 $5,833 $0 $0 $88,517 $7,459 $4,354 $10,3

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $33,926 $0 $4,828 $0 $0 $38,754 $3,277 $0 $4,27.2 Open $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,577 $1,143 $0 $0 $2,719 $214 $0 $57.4 Stack $3,123 $0 $1,174 $0 $0 $4,296 $366 $0 $47.9 HRSG,Duct & Stack Foundations $0 $622 $601 $0 $0 $1,223 $102 $0 $3

SUBTOTAL 7. $37,049 $2,198 $7,745 $0 $0 $46,992 $3,959 $0 $5,6

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $28,109 $0 $4,930 $0 $0 $33,039 $2,837 $0 $3,58.2 Turbine Plant Auxiliaries $198 $0 $455 $0 $0 $654 $57 $0 $8.3 Condenser & Auxiliaries $4,660 $0 $1,421 $0 $0 $6,082 $517 $0 $68.4 Steam Piping $5,233 $0 $3,687 $0 $0 $8,920 $682 $0 $2,48.9 TG Foundations $0 $953 $1,621 $0 $0 $2,574 $217 $0 $8

SUBTOTAL 8. $38,201 $953 $12,115 $0 $0 $51,268 $4,310 $0 $7,5

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $4,397 $0 $967 $0 $0 $5,364 $455 $0 $89.2 Circulating Water Pumps $1,383 $0 $86 $0 $0 $1,469 $113 $0 $29.3 Circ.Water System Auxiliaries $116 $0 $17 $0 $0 $132 $11 $0 $9.4 Circ.Water Piping $0 $4,910 $1,253 $0 $0 $6,163 $489 $0 $1,39.5 Make-up Water System $284 $0 $403 $0 $0 $688 $58 $0 $9.6 Component Cooling Water Sys $579 $693 $490 $0 $0 $1,762 $146 $0 $39.9 Circ.Water System Foundations& Structures $0 $1,699 $2,909 $0 $0 $4,608 $389 $0 $1,4

SUBTOTAL 9. $6,760 $7,303 $6,124 $0 $0 $20,187 $1,661 $0 $4,4

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $15,861 $0 $7,828 $0 $0 $23,688 $2,024 $0 $2,510.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $523 $0 $569 $0 $0 $1,092 $94 $0 $10.7 Ash Transport & Feed Equipment $706 $0 $169 $0 $0 $876 $72 $0 $10.8 Misc. Ash Handling Equipment $1,083 $1,327 $397 $0 $0 $2,807 $238 $0 $410.9 Ash/Spent Sorbent Foundation $0 $46 $58 $0 $0 $104 $9 $0 $

SUBTOTAL 10. $18,173 $1,373 $9,021 $0 $0 $28,568 $2,437 $0 $3,3

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 186 

Exhibit 3-63 Total Plant Cost Details (continued) 

Client: USDOE/NETL Repo

Project: Bituminous Baseline Study

Case: Case 03 - ConocoPhillips IGCC w/o CO2

Plant Size: 623.4 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenc

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $901 $0 $899 $0 $0 $1,800 $153 $0 11.2 Station Service Equipment $3,498 $0 $328 $0 $0 $3,827 $326 $0 11.3 Switchgear & Motor Control $6,686 $0 $1,226 $0 $0 $7,911 $657 $0 11.4 Conduit & Cable Tray $0 $3,181 $10,327 $0 $0 $13,508 $1,157 $0 11.5 Wire & Cable $0 $5,842 $3,930 $0 $0 $9,772 $640 $0 11.6 Protective Equipment $0 $624 $2,365 $0 $0 $2,989 $262 $0 11.7 Standby Equipment $215 $0 $218 $0 $0 $433 $37 $0 11.8 Main Power Transformers $11,308 $0 $138 $0 $0 $11,446 $776 $0 11.9 Electrical Foundations $0 $149 $394 $0 $0 $543 $46 $0 

SUBTOTAL 11. $22,608 $9,796 $19,825 $0 $0 $52,229 $4,054 $0 $

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 12.4 Other Major Component Control $924 $0 $643 $0 $0 $1,566 $135 $78 12.5 Signal Processing Equipment W/12.7 $0 W/12.7 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $212 $0 $142 $0 $0 $354 $31 $18 12.7 Computer & Accessories $4,928 $0 $164 $0 $0 $5,092 $432 $255 12.8 Instrument Wiring & Tubing $0 $1,752 $3,666 $0 $0 $5,418 $412 $271 12.9 Other I & C Equipment $3,294 $0 $1,666 $0 $0 $4,960 $426 $248 

SUBTOTAL 12. $9,358 $1,752 $6,282 $0 $0 $17,391 $1,436 $870 

13 Improvements to Site

13.1 Site Preparation $0 $99 $2,132 $0 $0 $2,231 $197 $0 13.2 Site Improvements $0 $1,761 $2,357 $0 $0 $4,118 $362 $0 13.3 Site Facilities $3,155 $0 $3,354 $0 $0 $6,509 $572 $0 

SUBTOTAL 13. $3,155 $1,860 $7,843 $0 $0 $12,858 $1,132 $0 

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $221 $127 $0 $0 $348 $27 $0 14.2 Steam Turbine Building $0 $2,309 $3,334 $0 $0 $5,643 $464 $0 14.3 Administration Building $0 $793 $583 $0 $0 $1,375 $110 $0 14.4 Circulation Water Pumphouse $0 $156 $84 $0 $0 $240 $19 $0 14.5 Water Treatment Buildings $0 $399 $395 $0 $0 $794 $64 $0 14.6 Machine Shop $0 $406 $281 $0 $0 $687 $55 $0 14.7 Warehouse $0 $655 $428 $0 $0 $1,083 $86 $0 14.8 Other Buildings & Structures $0 $392 $310 $0 $0 $702 $56 $0 14.9 Waste Treating Building & Str. $0 $877 $1,698 $0 $0 $2,575 $214 $0 

SUBTOTAL 14. $0 $6,209 $7,240 $0 $0 $13,449 $1,095 $0 

TOTAL COST $559,240 $59,898 $219,767 $0 $0 $838,905 $70,010 $27,220 $1

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of Fossil Energy Power Plants 

187 

Exhibit 3-64 Case 3 Initial and Annual Operating and Maintenance Costs 

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006

Case 03 - ConocoPhillips 600MW IGCC w/o CO2 Heat Rate-net(Btu/kWh): 8,681

 MWe-net: 623

 Capacity Factor: (%): 80

 OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 33.00 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 Skilled Operator 2.0 2.0

 Operator 9.0 9.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 3.0 3.0

 TOTAL-O.J.'s 15.0 15.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $5,637,060 $9.043

Maintenance Labor Cost $11,924,540 $19.129

Administrative & Support Labor $4,390,400 $7.043

TOTAL FIXED OPERATING COSTS $21,951,999 $35.215

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $22,346,706 $0.00512

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

 Water(/1000 gallons) 0 5,410.08 1.03 $0 $1,627,136 $0.00037

 Chemicals

 MU & WT Chem.(lb) 112,811 16,116 0.16 $18,591 $775,520 $0.00018

 Carbon (Mercury Removal) (lb) 84,449 116 1.00 $84,449 $33,872 $0.00001

 COS Catalyst (m3) 375 0.26 2,308.40 $865,651 $173,030 $0.00004

 Water Gas Shift Catalyst(ft3) 0 0 475.00 $0 $0 $0.00000

 Selexol Solution (gal.) 0 0 12.90 $0 $0 $0.00000

 MDEA Solution (gal) 280 40 8.38 $2,345 $97,820 $0.00002

 Sulfinol Solution (gal) 0 0 9.68 $0 $0 $0.00000

 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

 Claus Catalyst(ft3) w/equip. 2.10 125.00 $0 $76,650 $0.00002

Subtotal Chemicals $971,037 $1,156,892 $0.00026

 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) 0 116 0.40 $0 $13,603 $0.00000

 Flyash (ton) 0 0 0.00 $0 $0 $0.00000

 Bottom Ash(ton) 0 566 15.45 $0 $2,555,311 $0.00058

 Subtotal-Waste Disposal $0 $2,568,914 $0.00059

 By-products & Emissions 

 Sulfur(tons) 0 139 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $971,037 $27,699,648 $0.00634

 Fuel(ton) 166,992 5,566 42.11 $7,032,052 $68,445,302 $0.01567
Cost and Performance Comparison of Fossil Energy Power Plants 

188 

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

This case is configured to produce electric power with CO2 capture. The plant configuration is 

the same as Case 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 combustion turbines, 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. 

The process description for Case 4 is similar to Case 2 with several notable exceptions to 

accommodate CO2 capture. A BFD and stream tables for Case 4 are shown in Exhibit 3-65 and 

Exhibit 3-66, respectively. Instead of repeating the entire process description, only differences 

from Case 3 are reported here. 

Coal Preparation and Feed Systems 

No differences from Case 3. 

Gasification 

The gasification process is the same as Case 3 with the exception that total coal feed to the two 

gasifiers is 5,203 tonnes/day (5,735 TPD) (stream 6) and the ASU provides 4,000 tonnes/day 

(4,420 TPD) of 95 mole percent oxygen to the gasifier and Claus plant (streams 5 and 3). 

Raw Gas Cooling/Particulate Removal 

Raw gas cooling and particulate removal are the same as Case 3 with the exception that 

approximately 483,170 kg/h (1,065,206 lb/h) of saturated steam at 13.8 MPa (2,000 psia) is 

generated in the SGC. 

Syngas Scrubber/Sour Water Stripper 

No differences from Case 3. 

Sour Gas Shift (SGS) 

The SGS process was described in Section 3.1.3. In Case 4 steam (stream 8) is added to the 

syngas exiting the scrubber to adjust the H2O:CO molar ratio to approximately 2:1 prior to the 

first WGS reactor. The hot syngas exiting the first stage of SGS is used to generate a portion of 

the steam that is added in stream 8. Two more stages of SGS (for a total of three) result in 97.6 

percent overall conversion of the CO to CO2. The syngas exiting the final stage of SGS still 

contains 2.4 vol% CH4 which is subsequently oxidized to CO2 in the CT and limits overall 

carbon capture to 88.4 percent. The warm syngas from the second stage of SGS is cooled to 

232°C (450°F) by producing IP steam that is sent to the reheater in the HRSG. The SGS catalyst 

also serves to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. 

Following the third stage of SGS, the syngas is further cooled to 35°C (95°F) prior to the 

mercury removal beds. 

Mercury Removal and Acid Gas Removal 

Mercury removal is the same as in Case 3. 
Cost and Performance Comparison of F

189 

Exhibit 3-65 Case 4 Process Flow Diagram, E-GasTM IGCC with CO2 Capture 
Cost and Performance Comparison of F

190 

Exhibit 3-66 Case 4 Stream Table, E-GasTM IGCC with CO2 Capture 

12345 6A 7 8 9 

V-L Mole Fraction 

Ar 0.0092 0.0263 0.0360 0.0023 0.0320 0.0000 0.0000 0.0000 0.0051 CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0238 

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0052 CO2 0.0003 0.0092 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3214 COS 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 0.4116 H2O 0.0099 0.2713 0.0000 0.0004 0.0000 1.0000 0.0000 1.0000 0.2185 

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0051 N2 0.7732 0.4665 0.0140 0.9919 0.0180 0.0000 0.0000 0.0000 0.0073 

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0019 O2 0.2074 0.2266 0.9500 0.0054 0.9500 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 

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 V-L Flowrate (lbmol/hr) 55,654 1,969 278 41,984 11,156 25,799 0 31,642 91,106 

V-L Flowrate (lb/hr) 1,606,000 52,498 8,944 1,178,060 359,031 249,436 0 570,044 1,827,120 Solids Flowrate (lb/hr) 0 0 0 0 0 424,717 48,622 0 0 Temperature (°F) 242 70 90 385 191 140 1,850 615 457 Pressure (psia) 190.0 16.4 125.0 460.0 740.0 850.0 850.0 600.0 516.0 Enthalpy (BTU/lb)B 57.3 26.7 12.5 88.0 34.4 --- 1,120 1300.1 384.8 

Density (lb/ft3) 0.729 0.103 0.683 1.424 3.412 --- --- 0.937 1.052 

Molecular Weight 28.86 26.67 32.23 28.06 32.18 --- --- 18.02 20.05 

A - Solids flowrate includes dry coal; V-L flowrate includes slurry water and water from coalB - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of F

191 

Exhibit 3-66 Case 4 Stream Table (Continued) 

12 13 14 15 16 17 18 19 

V-L Mole Fraction 

Ar 0.0109 0.0093 0.0093 0.0000 0.0000 0.0000 0.0205 0.0094 CH4 0.0508 0.0436 0.0436 0.0000 0.0000 0.0000 0.0880 0.0000 

CO 0.0112 0.0096 0.0096 0.0000 0.0000 0.0000 0.0003 0.0000 CO2 0.0243 0.0208 0.0208 1.0000 0.4321 0.0000 0.6024 0.0003 COS 0.0000 0.0000 0.0000 0.0000 0.0004 0.0000 0.0000 0.0000 H2 0.8888 0.7620 0.7620 0.0000 0.0000 0.0000 0.0215 0.0000 H2O 0.0001 0.1427 0.1427 0.0000 0.0554 0.0000 0.0006 0.0108 

H2S 0.0000 0.0000 0.0000 0.0000 0.4035 0.0000 0.0180 0.0000 N2 0.0139 0.0119 0.0119 0.0000 0.0774 0.0000 0.2486 0.7719 

NH3 0.0000 0.0000 0.0000 0.0000 0.0312 0.0000 0.0000 0.0000 O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2076 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 V-L Flowrate (lbmol/hr) 33,733 39,346 39,346 22,257 813 47 628 242,512 

V-L Flowrate (lb/hr) 162,487 263,603 263,603 979,537 29,677 11,954 22,868 6,996,340 

Solids Flowrate (lb/hr) 0 0 0 0 0 11,954 0 0 Temperature (°F) 99 299 385 156 120 375 95 59 Pressure (psia) 468.5 458.5 453.5 2214.7 30.5 25.4 767.5 14.7 Enthalpy (BTU/lb)B 97.3 699.4 795.2 -46.0 48.7 -96.2 14.5 13.8 

Density (lb/ft3) 0.376 0.378 0.335 30.793 0.179 --- 4.692 0.076 

Molecular Weight 4.82 6.70 6.70 44.01 36.49 --- 36.39 28.85 

B - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of Fossil Energy Power Plants 

192 

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 16) contains 40 percent H2S and 43 percent CO2 with 

the balance primarily N2. The CO2-rich stream is discussed further in the CO2 compression 

section.

CO2 Compression and Dehydration 

CO2 from the AGR process is generated at three pressure levels. The LP stream is compressed 

from 0.15 MPa (22 psia) to 1.1 MPa (160 psia) and then combined with the MP stream. The HP 

stream is combined between compressor stages at 2.1 MPa (300 psia). The combined stream is 

compressed from 2.1 MPa (300 psia) to a supercritical 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 93 percent CO2 with the balance primarily nitrogen and hydrogen. For modeling 

purposes it was assumed that the impurities were separated from the CO2 and combined with the 

clean syngas stream from the Selexol process. The pure CO2 (stream 15) 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. 

Claus Unit 

The Claus plant is the same as Case 3 with the following exceptions: 

• 5,423 kg/h (11,955 lb/h) of sulfur (stream 17) are produced 

• The waste heat boiler generates 17,296 kg/h (38,131 lb/h) of 4.0 MPa (585 psia) steam, 

which provides all of the Claus plant process needs and provides some additional steam 

to the medium pressure steam header. 

Power Block 

Clean syngas from the AGR plant is combined with a small amount of clean gas from the CO2

compression process (stream 12) and partially humidified because the nitrogen available from 

the ASU is insufficient to provide adequate dilution. The moisturized syngas is reheated (stream 

14) to 196°C (385°F) using HP boiler feedwater, diltuted 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 20) exits the CT at 567°C (1052°F) and enters the HRSG where additional 

heat is recovered. The flue gas exits the HRSG at 132°C (270°F) (stream 21) 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/538°C/538°C (1800 

psig/1000°F/1000°F) steam cycle. 

Air Separation Unit 

The elevated pressure ASU is the same as in other cases and produces 4,000 tonnes/day (4,420 

TPD) of 95 mole percent oxygen and 12,830 tonnes/day (14,140 TPD) of nitrogen. There is no 

integration between the ASU and the combustion turbine. 
Cost and Performance Comparison of Fossil Energy Power Plants 

193 

3.3.9 CASE 4 PERFORMANCE RESULTS

The Case 4 modeling assumptions were presented previously in Section 3.3.3. 

The plant produces a net output of 518 MWe at a net plant efficiency of 31.7 percent (HHV 

basis). Overall performance for the entire plant is summarized in Exhibit 3-67 which includes 

auxiliary power requirements. The ASU accounts for nearly 62 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 23 

percent of the auxiliary power load. The BFW pumps and cooling water system (circulating 

water pumps 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 Comparison of Fossil Energy Power Plants 

 194 

Exhibit 3-67 Case 4 Plant Performance Summary 

POWER SUMMARY (Gross Power at Generator Terminals, kWe) 

Gas Turbine Power 464,000 

Steam Turbine Power 229,840 

TOTAL POWER, kWe 693,840 

AUXILIARY LOAD SUMMARY, kWe 

Coal Handling 440 

Coal Milling 2,230 

Coal Slurry Pumps 580 

Slag Handling and Dewatering 1,140 

Air Separation Unit Auxiliaries 1,000 

Air Separation Unit Main Air Compressor 62,760 

Oxygen Compressor 8,490 

Nitrogen Compressor 36,330 

Syngas Recycle Blower 3,400 

Tail Gas Recycle Blower 1,090 

CO2 Compressor 25,970 

Boiler Feedwater Pumps 5,340 

Condensate Pump 270 

Flash Bottoms Pump 200 

Circulating Water Pumps 3,020 

Cooling Tower Fans 1,560 

Scrubber Pumps 70 

Double Stage Selexol Unit Auxiliaries 14,840 

Gas Turbine Auxiliaries 1,000 

Steam Turbine Auxiliaries 100 

Claus Plant/TGTU Auxiliaries 200 

Miscellaneous Balance of Plant (Note 1) 3,000 

Transformer Loss 2,570 

TOTAL AUXILIARIES, kWe 175,600 

NET POWER, kWe 518,240 

Net Plant Efficiency, % (HHV) 31.7 

Net Plant Heat Rate (Btu/kWh) 10,757 

CONDENSER COOLING DUTY 106 kJ/h (106 Btu/h) 1,224 (1,161) 

CONSUMABLES 

As-Received Coal Feed, kg/h (lb/h) 216,752 (477,855) 

Thermal Input, kWt 1,633,771 

Raw Water Usage, m3/min (gpm) 15.6 (4,135) 

Note 1: Includes plant control systems, lighting, HVAC and miscellaneous low voltage loads 
Cost and Performance Comparison of Fossil Energy Power Plants 

 195 

Environmental Performance 

The environmental targets for emissions of Hg, NOX, SO2, CO2 and particulate matter were 

presented in Section 2.4. A summary of the plant air emissions for Case 4 is presented in 

Exhibit 3-68. 

Exhibit 3-68 Case 4 Air Emissions 

kg/GJ 

(lb/106 Btu) 

Tonne/year 

(tons/year) 

80% capacity factor 

kg/MWh 

(lb/MWh) 

SO2 0.004 (0.0085) 151 (167) 0.031 (0.069) 

NOX 0.021 (0.050) 882 (972) 0.181 (0.400) 

Particulates 0.003 (0.0071) 126 (139) 0.026 (0.057) 

Hg 0.25x10-6

(0.57x10-6) 0.010 (0.011) 2.1x10-6(4.6x10-6) 

CO2 10.1 (23.6) 417,000 (460,000) 86 (189) 

CO2

1 115 (253) 

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 22 ppmv. This results in a 

concentration in the flue gas of less than 3 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 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. Because of the relatively high CH4 content in the syngas, this results in an overall 

carbon removal of 88.4 percent. 

The carbon balance for the plant is shown in Exhibit 3-69. 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 
Cost and Performance Comparison of Fossil Energy Power Plants 

 196 

carbon balance below 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 CO2 in the stack gas, ASU vent gas and the captured CO2 product. Carbon in the 

wastewater blowdown stream is calculated by difference to close the material balance. The 

carbon capture efficiency is defined as the amount of carbon in the CO2 product stream relative 

to the amount of carbon in the coal less carbon contained in the slag, represented by the 

following fraction: 

(Carbon in Product for Sequestration)/[(Carbon in the Coal)-(Carbon in Slag)] or 

267,147/(304,632-2,285) *100 or 

88.4 percent 

Exhibit 3-69 Case 4 Carbon Balance 

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) 

Coal 138,180 (304,632) Slag 1,037 (2,285) 

Air (CO2) 488 (1,077) Stack Gas 16,246 (35,817) 

CO2 Product 121,176 (267,147) 

ASU Vent 99 (218) 

Wastewater 110 (242) 

Total 138,668 (305,709) Total 138,668 (305,709) 

Exhibit 3-70 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, dissolved SO2 in the 

wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is 

considered to be negligible, and the sulfur content of the blowdown stream is calculated by 

difference to close the material balance. The total sulfur capture is represented by the following 

fraction: 

(Sulfur byproduct/Sulfur in the coal) or 

(11,954/11,994) or 

99.7 percent 

Exhibit 3-70 Case 4 Sulfur Balance 

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) 

Coal 5,440 (11,994) Elemental Sulfur 5,422 (11,954) 

Stack Gas 11 (24) 

Wastewater 7 (16) 

Total 5,440 (11,994) Total 5,440 (11,994) 

Exhibit 3-71 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 
Cost and Performance Comparison of Fossil Energy Power Plants 

 197 

process, primarily as syngas condensate, and that water is re-used as internal recycle. Raw water 

makeup is the difference between water demand and internal recycle. 

Exhibit 3-71 Case 4 Water Balance 

Water Use Water Demand, 

m3/min (gpm) 

Internal Recycle, 

m3/min (gpm) 

Raw Water Makeup, 

m3/min (gpm) 

Slurry 1.5 (392) 1.5 (392) 0 

Slag Handling 0.5 (126) 0.5 (126) 0 

Humidifier 0.8 (219) 0.8 (219) 0 

Shift Steam 4.3 (1,140) 0 4.3 (1,140) 

BFW Makeup 0.2 (46) 0 0.2 (46) 

Cooling Tower 

Makeup 11.7 (3,098) 0.6 (149) 11.1 (2,949) 

Total 19.0 (5,021) 3.4 (886) 15.6 (4,135) 

Heat and Mass Balance Diagrams 

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-72 through 

Exhibit 3-76: 

• Coal gasification and air separation unit 

• Syngas cleanup 

• Sulfur recovery and tail gas recycle 

• Combined cycle power generation 

• Steam and feedwater 

An overall plant energy balance is provided in tabular form in Exhibit 3-77. The power out is 

the combined combustion turbine and steam turbine power prior to generator losses. The power 

at the generator terminals (shown in Exhibit 3-67) is calculated by multiplying the power out by 

a combined generator efficiency of 98.4 percent. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 198 

This page intentionally left blank 
199 

Exhibit 3-72 Case 4 Coal Gasification and Air Separation Unit Heat and Mass Balan
200 

Exhibit 3-73 Case 4 Syngas Cleanup Heat and Mass Balance Schematic 
201 

Exhibit 3-74 Case 4 Sulfur Recover and Tail Gas Recycle Heat and Mass Balance 
202 

Exhibit 3-75 Case 4 Combined Cycle Power Generation Heat and Mass Balance 
203 

Exhibit 3-76 Case 4 Steam and Feedwater Heat and Mass Balance Schema
204 

This page intentionally left blank 
Cost and Performance Comparison of Fossil Energy Power Plants 

 205 

Exhibit 3-77 Case 4 Overall Energy Balance (0°C [32°F] Reference) 

HHV Sensible + Latent Power Total 

Heat In (MMBtu/hr) 

Coal 5,575.1 4.7 5,579.8 

ASU Air 21.1 21.1 

CT Air 96.3 96.3 

Water 16.9 16.9 

Auxiliary Power 599.2 599.2 

Totals 5,575.1 138.9 599.2 6,313.2 

Heat Out (MMBtu/hr) 

ASU Intercoolers 240.9 240.9 

ASU Vent 1.4 1.4 

Slag 32.2 22.2 54.4 

Sulfur 47.6 (1.1) 46.4 

Tail Gas Compressor 

Intercoolers 3.9 3.9 

CO2 Compressor 

Intercoolers 130.7 130.7 

CO2 Product (45.1) (45.1) 

HRSG Flue Gas 1,335.7 1,335.7 

Condenser 1,161.0 1,161.0 

Process Losses 980.4 980.4 

Power 2,403.5 2,403.5 

Totals 79.8 3,830.0 2,403.5 6,313.2 

(1) Process Losses are calculated by difference and reflect various gasification, turbine, 

HRSG and other heat and work losses. Aspen flowsheet balance is within 0.5 percent. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 206 

3.3.10 CASE 4 - MAJOR EQUIPMENT LIST

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 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 Operating 

Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0

3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0

5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling 

System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0

8 Reclaim Hopper N/A 2 1

9 Feeder Vibratory 2 1

10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor 

reduction 2 0

14 As-Fired Coal Sampling 

System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0

17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 3 0

N/A

354 tonne/h (390 tph)

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph)

N/A

1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)

1,134 tonne/h (1,250 tph)

45 tonne (50 ton)

181 tonne/h (200 tph)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

354 tonne/h (390 tph)

181 tonne (200 ton)

N/A

N/A

354 tonne/h (390 tph)

816 tonne (900 ton)
Cost and Performance Comparison of Fossil Energy Power Plants 

 207 

ACCOUNT 2 COAL PREPARATION AND FEED 

Equipment 

No. Description Type Operating Qty. Spares

1 Feeder Vibratory 3 0

2 Conveyor No. 6 Belt w/tripper 1 0

3 Rod Mill Feed Hopper Dual Outlet 1 0

4 Weigh Feeder Belt 2 0

5 Rod Mill Rotary 2 0

6 Slurry Water Storage Tank 

with Agitator Field erected 2 0

7 Slurry Water Pumps Centrifugal 2 2

10 Trommel Screen Coarse 2 0

11 Rod Mill Discharge Tank with 

Agitator Field erected 2 0

12 Rod Mill Product Pumps Centrifugal 2 2

13 Slurry Storage Tank with 

Agitator Field erected 2 0

14 Slurry Recycle Pumps Centrifugal 2 2

15 Slurry Product Pumps Positive 

displacement 2 2

Design Condition

82 tonne/h (90 tph)

236 tonne/h (260 tph)

481 tonne (530 ton)

118 tonne/h (130 tph)

312,678 liters (82,600 gal)

2,612 lpm (690 gpm)

833 lpm (220 gpm)

118 tonne/h (130 tph)

295,264 liters (78,000 gal)

172 tonne/h (190 tph)

2,612 lpm (690 gpm)

5,224 lpm (1,380 gpm)

946,361 liters (250,000 gal)
Cost and Performance Comparison of Fossil Energy Power Plants 

 208 

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT 

Equipment 

No. Description Type OperatingQty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 3 0

2 Condensate Pumps Vertical canned 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 2 0

4 Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage 2 1

6 High Pressure 

Feedwater Pump No. 2

Barrel type, multistage, centrifugal 2 1

7 Auxiliary Boiler Shop fabricated, water 

tube 1 0

8 Service Air 

Compressors Flooded Screw 2 1

9 Instrument Air Dryers Duplex, regenerative 2 1

10 Closed Cylce Cooling 

Heat Exchangers Plate and frame 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 2 1

12 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine 1 1

13 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal 1 1

14 Raw Water Pumps Stainless steel, single 

suction 2 1

15 Filtered Water Pumps Stainless steel, single 

suction 2 1

16 Filtered Water Tank Vertical, cylindrical 2 0

17 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 2 0

18 Liquid Waste Treatment 

System 1 0

5 2 1 High Pressure 

Feedwater Pump No. 1

Barrel type, multistage, centrifugal

1,968,429 liter (520,000 gal)

2,574 lpm (680 gpm)

10 years, 24-hour storm

4,088 lpm @ 49 m H2O

(1,080 gpm @ 160 ft H2O)

28 m3/min (1,000 scfm)

58 MMkJ/h (55 MMBtu/h) each

20,820 lpm @ 21 m H2O

(5,500 gpm @ 70 ft H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

8,707 lpm @ 18 m H2O

(2,300 gpm @ 60 ft H2O)

2,006 lpm @ 283 m H2O

(530 gpm @ 930 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C

(40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

Design Condition

2,237,196 liters (591,000 gal)

7,874 lpm @ 91 m H2O

(2,080 gpm @ 300 ft H2O)

577,877 kg/h (1,274,000 lb/h)

IP water: 1,476 lpm @ 223 m 

H2O (390 gpm @ 730 ft H2O)

HP water: 6,587 lpm @ 1,890 m 

H2O (1,740 gpm @ 6,200 ft 

H2O)
Cost and Performance Comparison of Fossil Energy Power Plants 

 209 

ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW 

TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Gasifier

Pressurized two-stage, 

slurry-feed entrained 

bed

2 0

2 Synthesis Gas Cooler Fire-tube boiler 2 0

3 Synthesis Gas Cyclone High efficiency 2 0

4 Candle Filter Pressurized filter with 

pulse-jet cleaning 2 0

5

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 2 0

6 Raw Gas Coolers Shell and tube with 

condensate drain 8 0

7 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator 2 0

8 Saturation Water 

Economizers Shell and tube 2 0

9 Fuel Gas Saturator Vertical tray tower 2 0

10 Saturator Water Pump Centrifugal 2 2

11 Synthesis Gas Reheater Shell and tube 2 0

12 Flare Stack

Self-supporting, carbon 

steel, stainless steel 

top, pilot ignition

2 0

13 ASU Main Air 

Compressor

Centrifugal, multistage

2 0

14 Cold Box Vendor design 2 0

15 Oxygen Compressor Centrifugal, multistage

2 0

16 Nitrogen Compressor Centrifugal, multistage

2 0

17 Nitrogen Boost 

Compressor

Centrifugal, multistage

2 0

metallic filters

299,825 kg/h (661,000 lb/h)

455,861 kg/h (1,005,000 lb/h)

351,988 kg/h, 38°C, 5.1 MPa

(776,000 lb/h, 100°F, 737 psia)

Design Condition

2,903 tonne/day, 4.2 MPa 

(3,200 tpd, 615 psia)

326,133 kg/h (719,000 lb/h)

313,433 kg/h (691,000 lb/h) 

Design efficiency 90%

455,861 kg/h (1,005,000 lb/h)

62,596 kg/h, 149°C, 3.2 MPa

(138,000 lb/h, 300°F, 458 psia)

3,785 lpm @ 15 m H2O

(1,000 gpm @ 50 ft H2O)

65,771 kg/h (145,000 lb/h)

510 m3/min @ 2.3 MPa

(18,000 scfm @ 340 psia)

299,825 kg/h (661,000 lb/h) 

syngas

5,493 m3/min @ 1.3 MPa

(194,000 scfm @ 190 psia)

2,177 tonne/day (2,400 tpd)

of 95% purity oxygen

1,104 m3/min @ 5.1 MPa

(39,000 scfm @ 740 psia)

3,653 m3/min @ 3.4 MPa

(129,000 scfm @ 490 psia)
Cost and Performance Comparison of Fossil Energy Power Plants 

 210 

ACCOUNT 5A SOUR GAS SHIFT AND SYNGAS CLEANUP 

Equipment 

No. Description Type OperatingQty. Spares

1 Mercury Adsorber Sulfated carbon 

bed 2 0

2 Sulfur Plant Claus type 1 0

3 Water Gas Shift Reactors Fixed bed, 

catalytic 6 0

4 Shift Reactor Heat Recovery 

Exhchangers Shell and Tube 4 0

5 Acid Gas Removal Plant Two-stage 

Selexol 2 0

6 Hydrogenation Reactor Fixed bed, 

catalytic 1 0

7 Tail Gas Recycle 

Compressor Centrifugal 1 0

Design Condition

320,690 kg/h (707,000 lb/h) 

34°C (93°F) 3.3 MPa (481 psia)

143 tonne/day (158 tpd)

Exchanger 1: 148 MMkJ/h (140 

MMBtu/h)

Exchanger 2: 32 MMkJ/h (30 

MMBtu/h)

11,975 kg/h @ 6.4 MPa

(26,400 lb/h @ 930 psia)

455,861 kg/h (1,005,000 lb/h) 

232°C (450°F) 3.9 MPa (562 psia)

292,567 kg/h (645,000 lb/h) 

35°C (95°F) 3.2 MPa (471 psia)

17,100 kg/h (37,700 lb/h)

232°C (450°F) 0.2 MPa (25 psia)

ACCOUNT 5B CO2 COMPRESSION

Equipment 

No. Description Type Operating 

Qty. Spares

1 CO2 Compressor Integrally geared, multistage centrifugal 4 1

Design Condition

1,096 m3/min @ 15.3 MPa

(38,715 scfm @ 2,215 psia)

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty. Spares

1 Gas Turbine Advanced F class 2 0

2 Gas Turbine Generator TEWAC 2 0

Design Condition

232 MW 

260 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase
Cost and Performance Comparison of Fossil Energy Power Plants 

 211 

ACCOUNT 7 HRSG, DUCTING, AND STACK 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Stack CS plate, type 409SS 

liner 1 0

2 2 0 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator

 Reheat steam - 304,874 kg/h, 

2.9 MPa/538°C (672,132 lb/h, 

420 psig/1,000°F)

Design Condition

76 m (250 ft) high x

8.5 m (28 ft) diameter

Main steam - 372,086 kg/h, 12.4 

MPa/538°C (820,307 lb/h, 1,800 

psig/1,000°F)

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitiation 1 0

3 Steam Bypass One per HRSG 2 0

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1 0

280 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase

50% steam flow @ design 

steam conditions

Design Condition

251 MW 

12.4 MPa/538°C/538°C 

(1800 psig/ 

1000°F/1000°F)

1,392 MMkJ/h (1,320 

MMBtu/h), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 

11°C (20°F)
Cost and Performance Comparison of Fossil Energy Power Plants 

 212 

ACCOUNT 9 COOLING WATER SYSTEM 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell1 0

Design Condition

302,835 lpm @ 30 m

(80,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT, 

1,687 MMkJ/h (1,600 MMBtu/h) 

heat duty

ACCOUNT 10 SLAG RECOVERY AND HANDLING 

Equipment 

No. Description Type Operating Qty. Spares

1 Slag Quench Tank Water bath 2 0

2 Slag Crusher Roll 2 0

3 Slag Depressurizer Proprietary 2 0

4 Slag Receiving Tank Horizontal, weir 2 0

5 Black Water Overflow Tank Shop fabricated 2

6 Slag Conveyor Drag chain 2 0

7 Slag Separation Screen Vibrating 2 0

8 Coarse Slag Conveyor Belt/bucket 2 0

9 Fine Ash Settling Tank Vertical, gravity 2 0

10 Fine Ash Recycle Pumps Horizontal 

centrifugal 2 2

11 Grey Water Storage Tank Field erected 2 0

12 Grey Water Pumps Centrifugal 2 2

13 Grey Water Recycle Heat 

Exchanger Shell and tube 2 0

14 Slag Storage Bin Vertical, field 

erected 2 0

15 Unloading Equipment Telescoping chute 1 0

Design Condition

230,912 liters (61,000 gal)

12 tonne/h (13 tph)

12 tonne/h (13 tph)

151,418 liters (40,000 gal)

12 tonne/h (13 tph)

12 tonne/h (13 tph)

12 tonne/h (13 tph)

71,923 liters (19,000 gal)

227,126 liters (60,000 gal)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

907 tonne (1,000 tons)

100 tonne/h (110 tph)

71,923 liters (19,000 gal)

265 lpm @ 433 m H2O

(70 gpm @ 1,420 ft H2O)

15,876 kg/h (35,000 lb/h)
Cost and Performance Comparison of Fossil Energy Power Plants 

 213 

ACCOUNT 11 ACCESSORY ELECTRIC PLANT 

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 750 kW, 480 V, 3-ph, 60 Hz 1 0

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

1 0

24 kV/4.16 kV, 191 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 29 MVA, 

3-ph, 60 Hz

Design Condition

24 kV/345 kV, 260 MVA, 

3-ph, 60 Hz

2 STG Transformer Oil-filled 24 kV/345 kV, 80 MVA, 

3-ph, 60 Hz

ACCOUNT 12 INSTRUMENTATION AND CONTROLS 

Equipment 

No. Description Type OperatingQty. 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

2 DCS - Processor

Microprocessor with 

redundant 

input/output

N/A 1 0

Fully redundant, 25% spare
Cost and Performance Comparison of Fossil Energy Power Plants 

 214 

3.3.11 CASE 4 - COST ESTIMATING RESULTS

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-78 shows 

the total plant capital cost summary organized by cost account and Exhibit 3-79 shows a more 

detailed breakdown of the capital costs. Exhibit 3-80 shows the initial and annual O&M costs. 

The estimated TPC of the CoP gasifier with CO2 capture is $2,431/kW. Process contingency 

represents 4.3 percent of the TPC and project contingency represents 13.7 percent. The 20-year 

LCOE, including CO2 TS&M costs of 4.1 mills/kWh, is 105.7 mills/kWh. 
Cost and Performance Comparison of F

 215 

Exhibit 3-78 Case 4 Total Plant Cost Summary 

Client: USDOE/NETL Report 

Project: Bituminous Baseline Study

Case: Case 04 - ConocoPhillips IGCC w/ CO2

Plant Size: 518.2 MW,net Estimate Type: Conceptual Cost Base (Dec) 200

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencie

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Proje

 1 COAL & SORBENT HANDLING $13,303 $2,480 $10,424 $0 $0 $26,207 $2,127 $0 $

 2 COAL & SORBENT PREP & FEED $22,651 $4,146 $13,827 $0 $0 $40,624 $3,263 $0 $ 3 FEEDWATER & MISC. BOP SYSTEMS $9,371 $7,975 $8,947 $0 $0 $26,292 $2,201 $0 $

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $93,113 $0 $57,142 $0 $0 $150,256 $12,324 $22,538 $2

4.2 Syngas Cooling ( w/ 4.1) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 

4.3 ASU/Oxidant Compression $142,779 $0 w/equip. $0 $0 $142,779 $12,175 $0 $1

4.4-4.9 Other Gasification Equipment $24,864 $8,707 $14,165 $0 $0 $47,736 $4,057 $0 $1

SUBTOTAL 4 $260,756 $8,707 $71,307 $0 $0 $340,771 $28,555 $22,538 $5

 5A Gas Cleanup & Piping $81,314 $4,446 $69,562 $0 $0 $155,321 $13,338 $21,481 $3

 5B CO2 REMOVAL & COMPRESSION $17,010 $0 $10,435 $0 $0 $27,445 $2,351 $0 $

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $88,000 $0 $5,325 $0 $0 $93,325 $7,865 $9,333 $1

6.2-6.9 Combustion Turbine Other $0 $684 $762 $0 $0 $1,446 $121 $0 

SUBTOTAL 6 $88,000 $684 $6,087 $0 $0 $94,771 $7,986 $9,333 $1

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,356 $0 $4,604 $0 $0 $36,960 $3,125 $0 $

7.2-7.9 Ductwork and Stack $3,222 $2,268 $3,011 $0 $0 $8,501 $703 $0 $

SUBTOTAL 7 $35,577 $2,268 $7,615 $0 $0 $45,461 $3,829 $0 $

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $25,224 $0 $4,105 $0 $0 $29,328 $2,518 $0 $

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $9,243 $828 $6,527 $0 $0 $16,598 $1,338 $0 $

SUBTOTAL 8 $34,466 $828 $10,632 $0 $0 $45,926 $3,856 $0 $

 9 COOLING WATER SYSTEM $6,318 $6,821 $5,729 $0 $0 $18,867 $1,553 $0 $

10 ASH/SPENT SORBENT HANDLING SYS $18,516 $1,396 $9,191 $0 $0 $29,103 $2,482 $0 $

11 ACCESSORY ELECTRIC PLANT $23,064 $11,396 $22,575 $0 $0 $57,035 $4,450 $0 $1

12 INSTRUMENTATION & CONTROL $10,183 $1,906 $6,836 $0 $0 $18,925 $1,562 $946 $

13 IMPROVEMENTS TO SITE $3,208 $1,891 $7,974 $0 $0 $13,073 $1,151 $0 $

14 BUILDINGS & STRUCTURES $0 $6,066 $6,992 $0 $0 $13,057 $1,063 $0 $

TOTAL COST $623,738 $61,009 $268,131 $0 $0 $952,878 $79,766 $54,298 $17

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 216 

Exhibit 3-79 Case 4 Total Plant Cost Details 

Client: USDOE/NETL Repor

Project: Bituminous Baseline Study

Case: Case 04 - ConocoPhillips IGCC w/ CO2

Plant Size: 518.2 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenc

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $3,493 $0 $1,725 $0 $0 $5,218 $418 $0 1.2 Coal Stackout & Reclaim $4,514 $0 $1,106 $0 $0 $5,620 $441 $0 1.3 Coal Conveyors $4,197 $0 $1,094 $0 $0 $5,291 $416 $0 1.4 Other Coal Handling $1,098 $0 $253 $0 $0 $1,351 $106 $0 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,480 $6,246 $0 $0 $8,726 $745 $0 

SUBTOTAL 1. $13,303 $2,480 $10,424 $0 $0 $26,207 $2,127 $0 

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying incl w/2.3 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,491 $355 $236 $0 $0 $2,082 $160 $0 2.3 Slurry Prep & Feed $20,340 $0 $9,140 $0 $0 $29,480 $2,356 $0 2.4 Misc.Coal Prep & Feed $820 $593 $1,807 $0 $0 $3,221 $265 $0 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,197 $2,644 $0 $0 $5,841 $483 $0 

SUBTOTAL 2. $22,651 $4,146 $13,827 $0 $0 $40,624 $3,263 $0 

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 FeedwaterSystem $3,088 $5,369 $2,836 $0 $0 $11,293 $934 $0 3.2 Water Makeup & Pretreating $537 $56 $300 $0 $0 $893 $76 $0 3.3 Other Feedwater Subsystems $1,705 $578 $521 $0 $0 $2,804 $225 $0 3.4 Service Water Systems $309 $632 $2,194 $0 $0 $3,135 $272 $0 3.5 Other Boiler Plant Systems $1,662 $638 $1,582 $0 $0 $3,882 $326 $0 3.6 FO Supply Sys & Nat Gas $299 $565 $527 $0 $0 $1,391 $119 $0 3.7 Waste Treatment Equipment $746 $0 $457 $0 $0 $1,203 $104 $0 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $1,024 $138 $531 $0 $0 $1,693 $146 $0 

SUBTOTAL 3. $9,371 $7,975 $8,947 $0 $0 $26,292 $2,201 $0 

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $93,113 $0 $57,142 $0 $0 $150,256 $12,324 $22,538 $

4.2 Syngas Cooling ( w/ 4.1 w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $142,779 $0 w/equip. $0 $0 $142,779 $12,175 $0 $4.4 LT Heat Recovery & FG Saturation $24,864 $0 $9,355 $0 $0 $34,219 $2,946 $0 4.5 Misc. Gasification Equipment w/4.1 & 4.2 w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 4.6 Other Gasification Equipment $0 $1,157 $471 $0 $0 $1,629 $139 $0 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $7,550 $4,339 $0 $0 $11,889 $972 $0 

SUBTOTAL 4. $260,756 $8,707 $71,307 $0 $0 $340,771 $28,555 $22,538 $

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 217 

Exhibit 3-79 Case 4 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Report Date: 

Project: Bituminous Baseline Study

Case: Case 04 - ConocoPhillips IGCC w/ CO2

Plant Size: 518.2 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project 

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $57,451 $0 $49,279 $0 $0 $106,730 $9,179 $21,346 $27,451 5A.2 Elemental Sulfur Plant $9,709 $1,927 $12,535 $0 $0 $24,170 $2,088 $0 $5,252 5A.3 Mercury Removal $1,531 $0 $1,166 $0 $0 $2,697 $232 $135 $613 5A.4 Shift Reactors $12,213 $0 $4,919 $0 $0 $17,133 $1,461 $0 $3,719 5A.5 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $410 $230 $130 $0 $0 $770 $65 $0 $167 5A.7 Fuel Gas Piping $0 $1,150 $793 $0 $0 $1,943 $159 $0 $420 5A.9 HGCU Foundations $0 $1,138 $739 $0 $0 $1,878 $154 $0 $609 

SUBTOTAL 5A. $81,314 $4,446 $69,562 $0 $0 $155,321 $13,338 $21,481 $38,231 

 5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $17,010 $0 $10,435 $0 $0 $27,445 $2,351 $0 $5,959 

SUBTOTAL 5B. $17,010 $0 $10,435 $0 $0 $27,445 $2,351 $0 $5,959 

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $88,000 $0 $5,325 $0 $0 $93,325 $7,865 $9,333 $11,052 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $684 $762 $0 $0 $1,446 $121 $0 $470 

SUBTOTAL 6. $88,000 $684 $6,087 $0 $0 $94,771 $7,986 $9,333 $11,522 

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,356 $0 $4,604 $0 $0 $36,960 $3,125 $0 $4,009 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,627 $1,179 $0 $0 $2,806 $221 $0 $605 7.4 Stack $3,222 $0 $1,211 $0 $0 $4,433 $378 $0 $481 7.9 HRSG,Duct & Stack Foundations $0 $641 $620 $0 $0 $1,262 $105 $0 $410 

SUBTOTAL 7. $35,577 $2,268 $7,615 $0 $0 $45,461 $3,829 $0 $5,505 

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $25,224 $0 $4,105 $0 $0 $29,328 $2,518 $0 $3,185 8.2 Turbine Plant Auxiliaries $168 $0 $385 $0 $0 $553 $48 $0 $60 8.3 Condenser & Auxiliaries $4,112 $0 $1,235 $0 $0 $5,348 $455 $0 $580 8.4 Steam Piping $4,962 $0 $3,497 $0 $0 $8,459 $647 $0 $2,276 8.9 TG Foundations $0 $828 $1,409 $0 $0 $2,237 $189 $0 $728 

SUBTOTAL 8. $34,466 $828 $10,632 $0 $0 $45,926 $3,856 $0 $6,829 

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $4,081 $0 $897 $0 $0 $4,978 $422 $0 $810 9.2 Circulating Water Pumps $1,284 $0 $77 $0 $0 $1,361 $104 $0 $220 9.3 Circ.Water System Auxiliaries $108 $0 $15 $0 $0 $123 $10 $0 $20 9.4 Circ.Water Piping $0 $4,606 $1,175 $0 $0 $5,781 $459 $0 $1,248 9.5 Make-up Water System $301 $0 $427 $0 $0 $729 $62 $0 $158 9.6 Component Cooling Water Sys $544 $650 $459 $0 $0 $1,653 $137 $0 $358 9.9 Circ.Water System Foundations& Structures $0 $1,564 $2,678 $0 $0 $4,242 $358 $0 $1,380 

SUBTOTAL 9. $6,318 $6,821 $5,729 $0 $0 $18,867 $1,553 $0 $4,194 

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $16,165 $0 $7,978 $0 $0 $24,143 $2,063 $0 $2,621 10.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $532 $0 $579 $0 $0 $1,111 $96 $0 $181 10.7 Ash Transport & Feed Equipment $718 $0 $172 $0 $0 $890 $73 $0 $145 10.8 Misc. Ash Handling Equipment $1,101 $1,350 $403 $0 $0 $2,854 $242 $0 $464 10.9 Ash/Spent Sorbent Foundation $0 $47 $59 $0 $0 $106 $9 $0 $34 

SUBTOTAL 10. $18,516 $1,396 $9,191 $0 $0 $29,103 $2,482 $0 $3,445 

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 218 

Exhibit 3-79 Case 4 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Repor

Project: Bituminous Baseline Study

Case: Case 04 - ConocoPhillips IGCC w/ CO2

Plant Size: 518.2 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenc

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $866 $0 $864 $0 $0 $1,730 $147 $0 11.2 Station Service Equipment $4,122 $0 $387 $0 $0 $4,509 $384 $0 11.3 Switchgear & Motor Control $7,876 $0 $1,444 $0 $0 $9,320 $773 $0 11.4 Conduit & Cable Tray $0 $3,748 $12,166 $0 $0 $15,914 $1,363 $0 11.5 Wire & Cable $0 $6,883 $4,630 $0 $0 $11,512 $754 $0 11.6 Protective Equipment $0 $624 $2,365 $0 $0 $2,989 $262 $0 11.7 Standby Equipment $208 $0 $211 $0 $0 $419 $36 $0 11.8 Main Power Transformers $9,992 $0 $132 $0 $0 $10,124 $687 $0 11.9 Electrical Foundations $0 $142 $376 $0 $0 $518 $44 $0 

SUBTOTAL 11. $23,064 $11,396 $22,575 $0 $0 $57,035 $4,450 $0 $

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,005 $0 $699 $0 $0 $1,705 $147 $85 12.5 Signal Processing Equipment W/12.7 $0 W/12.7 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $231 $0 $154 $0 $0 $385 $33 $19 12.7 Computer & Accessories $5,362 $0 $179 $0 $0 $5,541 $470 $277 12.8 Instrument Wiring & Tubing $0 $1,906 $3,990 $0 $0 $5,896 $448 $295 12.9 Other I & C Equipment $3,584 $0 $1,813 $0 $0 $5,398 $464 $270 

SUBTOTAL 12. $10,183 $1,906 $6,836 $0 $0 $18,925 $1,562 $946 

13 Improvements to Site

13.1 Site Preparation $0 $101 $2,167 $0 $0 $2,268 $200 $0 13.2 Site Improvements $0 $1,790 $2,397 $0 $0 $4,187 $368 $0 13.3 Site Facilities $3,208 $0 $3,410 $0 $0 $6,618 $582 $0 

SUBTOTAL 13. $3,208 $1,891 $7,974 $0 $0 $13,073 $1,151 $0 

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $221 $127 $0 $0 $348 $27 $0 14.2 Steam Turbine Building $0 $2,058 $2,971 $0 $0 $5,030 $414 $0 14.3 Administration Building $0 $814 $598 $0 $0 $1,412 $113 $0 14.4 Circulation Water Pumphouse $0 $153 $82 $0 $0 $235 $18 $0 14.5 Water Treatment Buildings $0 $427 $423 $0 $0 $850 $69 $0 14.6 Machine Shop $0 $417 $289 $0 $0 $705 $56 $0 14.7 Warehouse $0 $672 $440 $0 $0 $1,112 $88 $0 14.8 Other Buildings & Structures $0 $403 $318 $0 $0 $721 $58 $0 14.9 Waste Treating Building & Str. $0 $900 $1,744 $0 $0 $2,644 $220 $0 

SUBTOTAL 14. $0 $6,066 $6,992 $0 $0 $13,057 $1,063 $0 

TOTAL COST $623,738 $61,009 $268,131 $0 $0 $952,878 $79,766 $54,298 $1

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of Fossil Energy Power Plants 

219 

Exhibit 3-80 Case 4 Initial and Annual Operating and Maintenance Costs 

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006

Case 04 - ConocoPhillips IGCC w/ CO2 Heat Rate-net(Btu/kWh): 10,757

 MWe-net: 518

 Capacity Factor: (%): 80

 OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 33.00 $/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 $6,012,864 $11.602

Maintenance Labor Cost $13,171,520 $25.416

Administrative & Support Labor $4,796,096 $9.255

TOTAL FIXED OPERATING COSTS $23,980,481 $46.273

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $24,211,567 $0.00667

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

 Water(/1000 gallons) 0 5,954 1.03 $0 $1,790,845 $0.00049

 Chemicals

 MU & WT Chem.(lb) 124,161 17,737 0.16 $20,462 $853,547 $0.00024

 Carbon (Mercury Removal) (lb) 128,090 175 1.00 $128,090 $51,100 $0.00001

 COS Catalyst (m3) 0 0 2,308.40 $0 $0 $0.00000

 Water Gas Shift Catalyst(ft3) 11,053 7.57 475.00 $5,250,175 $1,049,363 $0.00029

 Selexol Solution (gal.) 462 66 12.90 $5,960 $248,630 $0.00007

 MDEA Solution (gal) 0 0 0.96 $0 $0 $0.00000

 Sulfinol Solution (gal) 0 0 9.68 $0 $0 $0.00000

 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

 Claus Catalyst(ft3) w/equip. 2.16 125.00 $0 $78,840 $0.00002

Subtotal Chemicals $5,404,687 $2,281,480 $0.00063

 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) 0 175 0.40 $0 $20,522 $0.00001

 Flyash (ton) 0 0 0.00 $0 $0 $0.00000

 Bottom Ash(ton) 0 583 15.45 $0 $2,632,348 $0.00072

 Subtotal-Waste Disposal $0 $2,652,870 $0.00073

 By-products & Emissions 

 Sulfur(tons) 0 143 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $5,404,687 $30,936,762 $0.00852

 Fuel(ton) 172,030 5,734 42.11 $7,244,210 $70,510,306 $0.01941
Cost and Performance Comparison of Fossil Energy Power Plants 

220 

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 Global Solutions (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 

sour gas shift 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 Decscription 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 GASIFIER BACKGROUND

Development and Current Status – Development of the Shell gasification process for partial 

oxidation of oil and gas began in the early 1950s. More than 75 commercial Shell partialoxidation plants have been built worldwide to convert a variety of hydrocarbon liquids and gases 

to carbon monoxide and hydrogen. 

Shell Internationale Petroleum Maatschappij B.V. began work on coal gasification in 1972. The 

coal gasifier is significantly different than the oil and gas gasifiers developed earlier. A 

pressurized, entrained-flow, slagging coal gasifier was built at Shell’s Amsterdam laboratories. 

This 5 tonnes/day (6 TPD) process development unit has operated for approximately 

12,000 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 Comparison of Fossil Energy Power Plants 

221 

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 

high-pressure 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 combustion turbine air compressor to feed the oxygen plant. 

Gasifier Capacity – The large gasifier operating in The Netherlands has a bituminous coalhandling capacity of 1,633 tonnes/day (1,800 TPD) and produces dry gas at a rate of 158,575 

Nm3

/h (5.6 million scf/h) with an energy content of about 1,792 MMkJ/h (1,700 MMBtu/h) 

(HHV). This gasifier was sized to match the fuel gas requirements for the Siemens/Kraftwerk 

Union V-94.2 combustion turbine and could easily be scaled up to match advanced F Class 

turbine requirements. 

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. 

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 Comparison of Fossil Energy Power Plants 

222 

A disadvantage of the Shell coal gasification technology is the high waste heat recovery 

(synthesis gas cooler) 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 changeouts 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 PROCESS DESCRIPTION

In this section the overall Shell gasification process for Case 5 is described. The system 

description follows the BFD in Exhibit 3-81 and stream numbers reference the same Exhibit. 

The tables in Exhibit 3-82 provide process data for the numbered streams in the BFD. 

Coal Preparation and Feed Systems 

Coal receiving and handling is common to all cases and was covered in Section 3.1.1. The 

receiving and handling subsystem ends at the coal silo. The Shell process uses a dry feed system 

which is sensitive to the coal moisture content. Coal moisture consists of two parts, surface 

moisture and inherent moisture. For coal to flow smoothly through the lock hoppers, the surface 

moisture must be removed. The 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 flue gas, with an oxygen content of 6 vol%, is then used 

to dry the coal in the mill. 

The coal is drawn from the surge hoppers and fed through a pressurization lock hopper system to 

a dense phase pneumatic conveyor, which uses nitrogen from the ASU to convey the coal to the 

gasifiers. 
Cost and Performance Comparison of F

223 

Exhibit 3-81 Case 5 Process Flow Diagram, Shell IGCC without CO2 Capture 
Cost and Performance Comparison of F

224 

Exhibit 3-82 Case 5 Stream Table, Shell IGCC without CO2 Capture 

12345678 9A 10A 1

V-L Mole Fraction 

Ar 0.0094 0.0263 0.0360 0.0024 0.0360 0.0000 0.0000 0.0105 0.0000 0.0000 0.0CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0004 0.0000 0.0000 0.0

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.6151 0.0000 0.0000 0.0CO2 0.0003 0.0091 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3122 0.0000 0.0000 0.0H2O 0.0104 0.2820 0.0000 0.0004 0.0000 1.0000 0.0000 0.0014 1.0000 1.0000 0.0

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0N2 0.7722 0.4591 0.0140 0.9918 0.0140 0.0000 1.0000 0.0599 0.0000 0.0000 0.0

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0O2 0.2077 0.2235 0.9500 0.0054 0.9500 0.0000 0.0000 0.0000 0.0000 0.0000 0.0SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0V-L Flowrate (lbmol/hr) 37,250 1,938 225 38,900 10,865 2,424 2,019 447 2,796 1,165 

V-L Flowrate (lb/hr) 1,074,830 51,432 7,250 1,091,540 350,168 43,673 56,553 8,949 50,331 20,982 0 

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 402,289 402,289 45,Temperature (°F) 232 70 90 385 518 650 560 124 59 215 2,6Pressure (psia) 190.6 16.4 125.0 460.0 740.0 740.0 815.0 516.7 14.7 14.7 61Enthalpy (BTU/lb)B 55.3 26.8 12.5 88.0 107.7 1311.5 132.2 33.1 11,676 --- 1,1

Density (lb/ft3) 0.741 0.104 0.683 1.424 2.272 1.119 2.086 1.651 --- --- -

Molecular Weight 28.854 26.545 32.229 28.060 32.229 18.015 28.013 20.011 --- --- -

A - Solids flowrate includes dry coal; V-L flowrate includes slurry water and water from coalB - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of F

225 

Exhibit 3-82 Case 5 Stream Table, Shell IGCC without CO2 Capture (continued) 

14 15 16 17 18 19 20 21 22 23 2

V-L Mole Fraction 

Ar 0.0097 0.0101 0.0101 0.0105 0.0086 0.0086 0.0003 0.0000 0.0041 0.0094 0.0CH4 0.0004 0.0004 0.0004 0.0004 0.0003 0.0003 0.0000 0.0000 0.0000 0.0000 0.0

CO 0.5699 0.5940 0.5940 0.6151 0.5080 0.5080 0.0112 0.0000 0.0674 0.0000 0.0CO2 0.0217 0.0226 0.0226 0.0006 0.0005 0.0005 0.6315 0.0000 0.4947 0.0003 0.0COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0H2 0.2893 0.3015 0.3015 0.3122 0.2579 0.2579 0.0062 0.0000 0.0179 0.0000 0.0H2O 0.0387 0.0015 0.0015 0.0014 0.1752 0.1752 0.0042 0.0000 0.3199 0.0108 0.0

H2S 0.0088 0.0091 0.0091 0.0000 0.0000 0.0000 0.2596 0.0000 0.0015 0.0000 0.0N2 0.0583 0.0608 0.0608 0.0599 0.0494 0.0494 0.0870 0.0000 0.0898 0.7719 0.7

NH3 0.0032 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2076 0.2SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0045 0.0000 0.0

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0V-L Flowrate (lbmol/hr) 40,353 38,715 38,715 36,914 44,695 44,695 1,353 0 2,088 248,660 16,

V-L Flowrate (lb/hr) 830,529 801,076 801,076 738,696 878,868 878,868 53,431 0 67,836 7,173,720 482Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 11,307 0 0 0 Temperature (°F) 351 95 95 124 312 385 124 344 280 59 8Pressure (psia) 549.7 529.7 519.7 516.7 465.0 460.0 60.0 23.6 23.6 14.7 23Enthalpy (BTU/lb)B 146.2 22.6 22.6 33.1 269.4 301.3 21.9 -102.1 255.2 13.8 20

Density (lb/ft3) 1.300 1.841 1.807 1.651 1.111 0.998 0.378 --- 0.097 0.076 0.4

Molecular Weight 20.581 20.692 20.692 20.011 19.664 19.664 39.490 --- 32.491 28.849 28.

B - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of Fossil Energy Power Plants 

226 

Gasifier 

There are two Shell dry feed, pressurized, upflow, entrained, slagging gasifiers, operating at 4.2 

MPa (615 psia) and processing a total of 4,927 tonnes/day (5,431 TPD) of as-received coal. 

Coal reacts with oxygen and steam at a temperature of 1427°C (2600°F) to produce principally 

hydrogen and carbon monoxide with little carbon dioxide formed. 

The gasifier includes a refractory-lined water wall that is also protected by molten slag that 

solidifies on the cooled walls. 

Raw Gas Cooling/Particulate Removal 

High-temperature heat recovery in each gasifier train is accomplished in three steps, including 

the gasifier jacket, which cools the syngas by maintaining the reaction temperature at 1427°C 

(2600°F). The product gas from the gasifier is cooled to 891°C (1635°F) by adding cooled 

recycled fuel gas to lower the temperature below the ash melting point. Gas (stream 12) then 

goes through a raw gas cooler, which lowers the gas temperature from 891°C (1635°F) to 316°C 

(600°F), and produces high-pressure steam for use in the steam cycle. The syngas is further 

cooled to 203°C (398°F) (stream 13) by heating water that is used to humidify the sweet syngas 

prior to the combustion turbine. 

After passing through the raw gas 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 particulate matter further downstream. 

Quench Gas Compressor 

About 45 percent of the raw gas from the filter is recycled back to the gasifier as quench gas. A 

single-stage compressor is utilized to boost the pressure of a cooled fuel gas stream from 4.0 

MPa (575 psia) to 4.2 MPa (615 psia) to provide quench gas to cool the gas stream from the 

gasifier.

Syngas Scrubber/Sour Water Stripper 

The raw synthesis gas exiting the ceramic particulate filter at 203°C (398°F) (stream 13) then 

enters the scrubber for removal of chlorides 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 110°C (230oF). The quench scrubber removes essentially all traces 

of entrained particles, principally unconverted carbon, slag, and metals. The bottoms from the 

scrubber are sent to the slag removal and handling system for processing. 

The sour water stripper removes 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 

scrubber and condensate from synthesis gas coolers. Sour water from the drum flows to the sour 

stripper, which consists of a packed column with a steam-heated reboiler. Sour gas is stripped 
Cost and Performance Comparison of Fossil Energy Power Plants 

227 

from the liquid and sent to the sulfur recovery unit. Remaining water is sent to wastewater 

treatment. 

COS Hydrolysis, Mercury Removal and Acid Gas Removal 

H2S and COS are at significant concentrations, requiring removal for the power plant to achieve 

the low design level of SO2 emissions. H2S is removed in an acid gas removal process; however, 

because COS is not readily removable, it is first catalytically converted to H2S in a COS 

hydrolysis unit. 

Following the water scrubber, the gas is reheated to 177°C (350°F) and fed to the COS 

hydrolysis reactor. The COS in the sour gas is hydrolyzed with steam over a catalyst bed to H2S, 

which is more easily removed by the AGR solvent. Before the raw fuel gas can be treated in the 

AGR process (stream 14), it must be cooled to about 35°C (95°F). During this cooling through a 

series of heat exchangers, part of the water vapor condenses. This water, which contains some 

NH3, is sent to the sour water stripper. The cooled syngas (stream 15) then passes through a 

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 low pressure 

with heat supplied through the stripper reboiler. The acid gas stream to sulfur recovery/tail gas 

cleanup is recovered as the flash gas from the stripper accumulator. The lean solvent from the 

bottom of the stripper is cooled in the lean/rich solvent exchanger and the lean solvent cooler. 

Most of the lean solvent is pumped to the HP contactor. A small amount goes to the LP 

contactor. 

The Sulfinol process removes essentially all of the CO2 along with the H2S and COS. The acid 

gas fed to the SRU contains 26 vol% H2S and 63 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 gas 
Cost and Performance Comparison of Fossil Energy Power Plants 

228 

turbine. However, the costs of the sulfur recovery/tail gas cleanup are higher than for a sulfur 

removal process producing an acid gas stream with a higher sulfur concentration. 

Claus Unit 

The sulfur recovery unit is a Claus bypass type sulfur recovery unit utilizing oxygen (stream 3) 

instead of air and followed by an amine-based SCOT tail gas unit. 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 combination of Claus technology and SCOT 

tail gas technology results in an overall sulfur recovery exceeding 99 percent. 

Utilizing oxygen instead of air in the Claus plant reduces the overall cost of the sulfur recovery 

plant. The sulfur plant produces approximately 123 tonnes/day (136 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. Vent gas from the tail gas treatment 

unit is combined with a slipstream of clean syngas (stream 8), passed through an incinerator, and 

the hot, nearly inert incinerator off gas is used to dry coal before being vented to the atmosphere. 

In the furnace waste heat boiler, 12,283 kg/h (27,080 lb/h) of 3.6 MPa (525 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 low-pressure steam header. 

Power Block 

Clean syngas exiting the Sulfinol absorber (stream 17) is humidified because there is not 

sufficient nitrogen from the ASU to provide the level of dilution required. The moisturized 

syngas (stream 18) is reheated (stream 19), further diluted with nitrogen from the ASU (stream 

4) and steam, and enters the advanced F Class combustion turbine (CT) burner. The CT 

compressor provides combustion air to the burner and also 31 percent of the air requirements in 

the ASU (stream 24). The exhaust gas exits the CT at 596°C (1,105°F) (stream 25) and enters 

the HRSG where additional heat is recovered until the flue gas exits the HRSG at 132°C (270°F) 

(stream 26) and is discharged through the plant stack. The steam raised in the HRSG is used to 

power an advanced, commercially available steam turbine using a 12.4 MPa/566°C/566°C (1800 

psig/1050°F/1050°F) steam cycle. 

Air Separation Unit (ASU) 

The ASU is designed to produce a nominal output of 3,900 tonnes/day (4,290 TPD) of 95 mole 

percent O2 for use in the gasifier (stream 5) and sulfur recovery unit (stream 3). The plant is 

designed with two production trains. The air compressor is powered by an electric motor. 

Approximately 11,900 tonnes/day (13,100 TPD) of nitrogen are also recovered, compressed, and 

used as dilution in the gas turbine combustor. About 6.7 percent of the gas turbine air is used to 

supply approximately 31 percent of the ASU air requirements. 

Balance of Plant 

Balance of plant items were covered in Sections 3.1.9, 3.1.10 and 3.1.11. 
Cost and Performance Comparison of Fossil Energy Power Plants 

229 

3.4.3 KEY SYSTEM ASSUMPTIONS

System assumptions for Cases 5 and 6, Shell IGCC with and without CO2 capture, are compiled 

in Exhibit 3-83. 

Balance of Plant – Cases 5 and 6 

The balance of plant assumptions are common to all cases and were presented previously in 

Exhibit 3-17. 
Cost and Performance Comparison of Fossil Energy Power Plants 

230 

Exhibit 3-83 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 0.827 0.827 

Carbon Conversion, % 99.5 99.5 

Syngas HHV at Gasifier Outlet, 

kJ/Nm3

 (Btu/scf) 10,610 (285) 10,610 (285) 

Steam Cycle, MPa/°C/°C 

(psig/°F/°F) 

12.4/566/566 

(1800/1050/1050) 

12.4/538/538 

(1800/1000/1000) 

Condenser Pressure, mm Hg 

 (in Hg) 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 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 

Sour Gas Shift No Yes 

H2S Separation Sulfinol-M Selexol 1st Stage 

Sulfur Removal, % 99.5 99.7 

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 

CO2 Capture N/A 90.8% from Syngas 

CO2 Sequestration N/A Off-site Saline Formation 
Cost and Performance Comparison of Fossil Energy Power Plants 

231 

3.4.4 SPARING PHILOSOPHY

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. 

The plant design consists of the following major subsystems: 

• Two air separation units (2 x 50%) 

• Two trains of coal drying and dry feed systems (2 x 50%) 

• Two trains of gasification, including gasifier, synthesis gas cooler, cyclone, and barrier 

filter (2 x 50%). 

• Two trains of syngas clean-up process (2 x 50%). 

• Two trains of Sulfinol-M acid gas 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 combustion turbine/HRSG tandems (2 x 50%). 

• One steam turbine (1 x 100%). 

3.4.5 CASE 5 PERFORMANCE RESULTS

The plant produces a net output of 636 MWe at a net plant efficiency of 41.1 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. [50] Accounting 

for coal drying would reduce the efficiency by only about 0.5-1 percentage points so the 

efficency results for the Shell case are still lower in this study than reported by the vendor. 

Overall performance for the entire plant is summarized in Exhibit 3-84 which includes auxiliary 

power requirements. The ASU accounts for over 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 circulating water pumps and 

cooling tower fan, accounts for over 4 percent of the auxiliary load, and the BFW pumps account 

for an additional 3.6 percent. All other individual auxiliary loads are less than 3 percent of the 

total. 
Cost and Performance Comparison of Fossil Energy Power Plants 

232 

Exhibit 3-84 Case 5 Plant Performance Summary 

POWER SUMMARY (Gross Power at Generator Terminals, kWe) 

Gas Turbine Power 464,030 

Steam Turbine Power 283,990 

TOTAL POWER, kWe 748,020 

AUXILIARY LOAD SUMMARY, kWe 

Coal Handling 430 

Coal Milling 2,110 

Slag Handling 540 

Air Separation Unit Auxiliaries 1,000 

Air Separation Unit Main Air Compressor 41,630 

Oxygen Compressor 10,080 

Nitrogen Compressor 37,010 

Syngas Recycle Compressor 1,650 

Incinerator Air Blower 160 

Boiler Feedwater Pumps 4,670 

Condensate Pump 230 

Flash Bottoms Pump 200 

Circulating Water Pumps 3,150 

Cooling Tower Fans 1,630 

Scrubber Pumps 120 

Sulfinol Unit Auxiliaries 660 

Gas Turbine Auxiliaries 1,000 

Steam Turbine Auxiliaries 100 

Claus Plant/TGTU Auxiliaries 250 

Miscellaneous Balance of Plant (Note 1) 3,000 

Transformer Loss 2,550 

TOTAL AUXILIARIES, kWe 112,170 

NET POWER, kWe 635,850 

Net Plant Efficiency, % (HHV) 41.1 

Net Plant Heat Rate (Btu/kWh) 8,306 

CONDENSER COOLING DUTY 106 kJ/h (106 Btu/h) 1,401 (1,329) 

CONSUMABLES 

As-Received Coal Feed, kg/h (lb/h) 205,305 (452,620) 

Thermal Input, kWt 1,547,493 

Raw Water Usage, m3/min (gpm) 14.4 (3,792) 

Note 1: Includes plant control systems, lighting, HVAC and miscellaneous low voltage loads 
Cost and Performance Comparison of Fossil Energy Power Plants 

233 

Environmental Performance 

The environmental targets for emissions of emissions of Hg, NOx, SO2 and particulate matter 

were presented in Section 2.4. A summary of the plant air emissions for Case 5 is presented in 

Exhibit 3-85. 

Exhibit 3-85 Case 5 Air Emissions 

kg/GJ 

(lb/106 Btu) 

Tonne/year 

(ton/year) 

80% capacity factor 

kg/MWh 

(lb/MWh) 

SO2 0.0053 (0.0124) 209 (230) 0.040 (0.088) 

NOX 0.025 (0.058) 982 (1,082) 0.187 (0.413) 

Particulates 0.003 (0.0071) 119 (131) 0.023 (0.050) 

Hg 0.25x10-6 

(0.57x10-6) 

0.010 (0.011) 1.8x10-6 (4.0x10-6) 

CO2 85.9 (200) 3,351,000 (3,694,000) 639 (1,409) 

CO2

1 752 (1,658) 

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 30 ppmv. This results in a concentration in the flue gas of less 

than 4 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, 

producing elemental sulfur. The Claus plant tail gas is treated using an amine based system to 

capture most of the remaining sulfur. The cleaned gas from the tail gas treatment unit is 

combined with a slipstream of clean syngas, passed through an incinerator, and the hot, inert 

incinerator offgas is used to dry coal prior to being vented to atmosphere. The SO2 emissions in 

Exhibit 3-85 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 3-86. 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 
Cost and Performance Comparison of Fossil Energy Power Plants 

234 

gas, ASU vent gas and coal dryer vent gas. Carbon in the wastewater blowdown stream is 

calculated by difference to close the material balance. 

Exhibit 3-86 Case 5 Carbon Balance 

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) 

Coal 130,882 (288,545) Slag 656 (1,446) 

Air (CO2) 471 (1,039) Stack Gas 124,162 (273,731) 

ASU Vent 96 (212) 

Coal Dryer 6,252 (13,783) 

Wastewater 187 (412) 

Total 131,353 (289,584) Total 131,353 (289,584) 

Exhibit 3-87 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, dissolved SO2 in the 

wastewater blowdown stream, sulfur in the coal drying gas, and sulfur emitted in the stack gas. 

Sulfur in the slag is considered to be negligible, and the sulfur content of the blowdown stream is 

calculated by difference to close the material balance. The total sulfur capture is represented by 

the following fraction: 

(Sulfur byproduct/Sulfur in the coal) or 

(11,307/11,361) or 

99.5 percent 

Exhibit 3-87 Case 5 Sulfur Balance 

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) 

Coal 5,153 (11,361) Elemental Sulfur 5,129 (11,307) 

Stack Gas 14 (30) 

Coal Dryer Vent 1 (3) 

Wastewater 9 (21) 

Total 5,153 (11,361) Total 5,153 (11,361) 

Exhibit 3-88 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 

makeup is the difference between water demand and internal recycle. 
Cost and Performance Comparison of Fossil Energy Power Plants 

235 

Exhibit 3-88 Case 5 Water Balance 

Water Use Water Demand, 

m3/min (gpm) 

Internal Recycle, 

m3/min (gpm) 

Raw Water Makeup, 

m3/min (gpm) 

Gasifier Steam 0.3 (87) 0 0.3 (87) 

Humidifier 1.1 (293) 0 1.1 (293) 

Slag Handling 0.5 (118) 0.5 (118) 0 

Scrubber 0.2 (61) 0 0.2 (61) 

CT Steam Dilution 0.5 (132) 0 0.5 (132) 

BFW Makeup 0.2 (39) 0 0.2 (39) 

Cooling Tower 

Makeup 12.2 (3,233) 0.2 (54) 12.0 (3,180) 

Total 15.0 (3,963) 0.7 (171) 14.3 (3,792) 

Heat and Mass Balance Diagrams 

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-89 through 

Exhibit 3-93: 

• Coal gasification and air separation unit 

• Syngas cleanup 

• Sulfur recovery and tail gas recycle 

• Combined cycle power generation 

• Steam and feedwater 

An overall plant energy balance is provided in tabular form in Exhibit 3-61. The power out is 

the combined combustion turbine and steam turbine power prior to generator losses. The power 

at the generator terminals (shown in Exhibit 3-84) is calculated by multiplying the power out by 

a combined generator efficiency of 98.3 percent. 
Cost and Performance Comparison of Fossil Energy Power Plants 

236 

This page intentionally left blank 
237 

Exhibit 3-89 Case 5 Coal Gasification and Air Separation Unit Heat and Mass Balan
238 

Exhibit 3-90 Case 5 Syngas Cleanup Heat and Mass Balance Schematic 
239 

Exhibit 3-91 Case 5 Sulfur Recovery and Tail Gas Recycle Heat and Mass Balance 
240 

Exhibit 3-92 Case 5 Combined Cycle Power Generation Heat and Mass Balance 
241 

Exhibit 3-93 Case 5 Steam and Feedwater Heat and Mass Balance Schema
242 

This page intentionally left blank 
Cost and Performance Comparison of Fossil Energy Power Plants 

 243 

Exhibit 3-94 Case 5 Overall Energy Balance (0°C [32°F] Reference) 

HHV Sensible + Latent Power Total 

Heat In (MMBtu/hr) 

Coal 5,280.2 4.4 5,284.6 

ASU Air 14.5 14.5 

CT Air 98.8 98.8 

Incinerator Air 1.2 1.2 

Water 9.4 9.4 

Auxiliary Power 382.7 382.7 

Totals 5,280.2 128.4 382.7 5,791.3 

Heat Out (MMBtu/hr) 

ASU Intercoolers 171.4 171.4 

ASU Vent 1.4 1.4 

Slag 20.4 32.5 52.9 

Sulfur 45.0 (1.2) 43.8 

Dryer Stack Gas 53.1 53.1 

HRSG Flue Gas 1015.9 1,015.9 

Condenser 1,329.0 1,329.0 

Process Losses 526.1 520.2 

Power 2,597.6 2,597.6 

Totals 65.4 3,128.3 2,597.6 5,791.3 

(1) Process Losses are calculated by difference and reflect various gasification, turbine, 

HRSG and other heat and work losses. Aspen flowsheet balance is within 0.5 percent. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 244 

3.4.6 CASE 5 - MAJOR EQUIPMENT LIST

Major equipment items for the Shell gasifier with no CO2 capture are shown in the following 

tables. The accounts used in the equipment list correspond to the account numbers used in the 

cost estimates in Section 3.4.7. 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 Operating 

Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0

3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0

5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling 

System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0

8 Reclaim Hopper N/A 2 1

9 Feeder Vibratory 2 1

10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor 

reduction 2 0

14 As-Fired Coal Sampling 

System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0

17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 3 0

N/A

336 tonne/h (370 tph)

726 tonne (800 ton)

45 tonne (50 ton)

172 tonne/h (190 tph)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

336 tonne/h (370 tph)

172 tonne (190 ton)

N/A

N/A

336 tonne/h (370 tph)

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph)

N/A

1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)

1,134 tonne/h (1,250 tph)
Cost and Performance Comparison of Fossil Energy Power Plants 

 245 

ACCOUNT 2 COAL PREPARATION AND FEED 

Equipment 

No. Description Type Operating Qty. Spares

1 Feeder Vibratory 3 0

2 Conveyor No. 6 Belt w/tripper 1 0

3 Roller Mill Feed Hopper Dual Outlet 1 0

4 Weigh Feeder Belt 2 0

5 Coal Drying and Pulverization Rotary 2 0

109 tonne/h (120 tph)

109 tonne/h (120 tph)

Design Condition

73 tonne/h (80 tph)

227 tonne/h (250 tph)

454 tonne (500 ton)
Cost and Performance Comparison of Fossil Energy Power Plants 

 246 

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT 

Equipment 

No. Description Type OperatingQty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 2 0

2 Condensate Pumps Vertical canned 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 2 0

4 Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage 2 1

6 High Pressure 

Feedwater Pump No. 2

Barrel type, multistage, centrifugal 2 1

7 Auxiliary Boiler Shop fabricated, water 

tube 1 0

8 Service Air 

Compressors Flooded Screw 2 1

9 Instrument Air Dryers Duplex, regenerative 2 1

10 Closed Cylce Cooling 

Heat Exchangers Plate and frame 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 2 1

12 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine 1 1

13 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal 1 1

14 Raw Water Pumps Stainless steel, single 

suction 2 1

15 Filtered Water Pumps Stainless steel, single 

suction 2 1

16 Filtered Water Tank Vertical, cylindrical 2 0

17 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 2 0

18 Liquid Waste Treatment 

System 1 0

151 lpm @ 302 m H2O

(40 gpm @ 990 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C

(40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

Design Condition

590,529 liters (156,000 gal)

6,360 lpm @ 91 m H2O

(1,680 gpm @ 300 ft H2O)

443,160 kg/h (977,000 lb/h)

IP water: 1,060 lpm @ 223 m 

H2O (280 gpm @ 730 ft H2O)

HP water: 7,344 lpm @ 1,890 m 

H2O (1,940 gpm @ 6,200 ft 

H2O)

1,590 lpm @ 49 m H2O

(420 gpm @ 160 ft H2O)

28 m3/min (1,000 scfm)

58 MMkJ/h (55 MMBtu/h) each

20,820 lpm @ 21 m H2O

(5,500 gpm @ 70 ft H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

7,987 lpm @ 18 m H2O

(2,110 gpm @ 60 ft H2O)

768,445 liter (203,000 gal)

151 lpm (40 gpm)

10 years, 24-hour storm

5 2 1 High Pressure 

Feedwater Pump No. 1

Barrel type, multistage, centrifugal
Cost and Performance Comparison of Fossil Energy Power Plants 

 247 

ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW 

TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION 

Equipment 

No. Description Type OperatingQty. Spares

1 Gasifier Pressurized dry-feed, 

entrained bed 2 0

2 Synthesis Gas Cooler Convective spiralwound tube boiler 2 0

3 Synthesis Gas Cyclone High efficiency 2 0

4 Candle Filter Pressurized filter with 

pulse-jet cleaning 2 0

5

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 2 0

6 Raw Gas Coolers Shell and tube with 

condensate drain 6 0

7 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator 2 0

8 Saturation Water 

Economizers Shell and tube 2 0

9 Fuel Gas Saturator Vertical tray tower 2 0

10 Saturator Water Pump Centrifugal 2 2

11 Synthesis Gas Reheater Shell and tube 2 0

12 Flare Stack

Self-supporting, carbon 

steel, stainless steel 

top, pilot ignition

2 0

13 ASU Main Air 

Compressor

Centrifugal, multistage

2 0

14 Cold Box Vendor design 2 0

15 Oxygen Compressor Centrifugal, multistage

2 0

16 Nitrogen Compressor Centrifugal, multistage

2 0

17 Nitrogen Boost 

Compressor

Centrifugal, multistage

2 0

18 Extraction Air Heat 

Exchanger

Gas-to-gas, vendor 

design 2 0

481 m3/min @ 2.3 MPa

(17,000 scfm @ 340 psia)

120,202 kg/h, 433°C, 1.6 MPa

(265,000 lb/h, 811°F, 232 psia)

206,838 kg/h (456,000 lb/h) 

syngas

3,681 m3/min @ 1.3 MPa

(130,000 scfm @ 190 psia)

2,177 tonne/day (2,400 tpd) of 

95% purity oxygen

1,076 m3/min @ 5.1 MPa

(38,000 scfm @ 740 psia)

3,540 m3/min @ 3.4 MPa

(125,000 scfm @ 490 psia)

207,292 kg/h (457,000 lb/h)

219,085 kg/h, 154°C, 3.2 MPa

(483,000 lb/h, 309°F, 465 psia)

2,650 lpm @ 12 m H2O

(700 gpm @ 40 ft H2O)

219,085 kg/h (483,000 lb/h)

Design Condition

2,722 tonne/day, 4.2 MPa

(3,000 tpd, 615 psia)

386,461 kg/h (852,000 lb/h)

207,292 kg/h (457,000 lb/h) 

Design efficiency 90%

metallic filters

206,838 kg/h (456,000 lb/h)

276,238 kg/h (609,000 lb/h)

200,488 kg/h, 35°C, 3.7 MPa

(442,000 lb/h, 95°F, 530 psia)
Cost and Performance Comparison of Fossil Energy Power Plants 

 248 

ACCOUNT 5 SYNGAS CLEANUP 

Equipment 

No. Description Type Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon 

bed 2 0

2 Sulfur Plant Claus type 1 0

3 COS Hydrolysis Reactor Fixed bed, 

catalytic 2 0

4 Acid Gas Removal Plant Sulfinol 2 0

5 Tail Gas Treatment Unit Proprietary amine, 

absorber/stripper 1 0

6 Tail Gas Treatment 

Incinerator N/A 1 0

30,255 kg/h (66,700 lb/h)

49°C (120°F) 0.1 MPa (16.4 psia)

200,034 kg/h (441,000 lb/h) 51°C 

(124°F) 3.6 MPa (520 psia)

64 MMkJ/h (61 MMBtu/h)

Design Condition

200,034 kg/h (441,000 lb/h) 35°C 

(95°F) 3.7 MPa (530 psia)

135 tonne/day (149 tpd)

207,292 kg/h (457,000 lb/h) 

177°C (350°F) 3.9 MPa (560 psia)

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty.

1 Gas Turbine Advanced F class 2

2 Gas Turbine Generator TEWAC 2

Design Condition

232 MW 

260 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

ACCOUNT 7 HRSG, DUCTING AND STACK 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Stack CS plate, type 409SS 

liner 1 0

Design Condition

76 m (250 ft) high x

8.4 m (28 ft) diameter

Main steam - 414,742 kg/h, 12.4 

MPa/566°C (914,348 lb/h, 1,800 

psig/1,050°F) 2 2 0 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator

 Reheat steam - 384,205 kg/h, 

3.1 MPa/566°C (847,027 lb/h, 

452 psig/1,050°F)
Cost and Performance Comparison of Fossil Energy Power Plants 

 249 

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitiation 1 0

3 Steam Bypass One per HRSG 2 0

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1 0

Design Condition

299 MW 

12.4 MPa/566°C/566°C 

(1800 psig/ 

1050°F/1050°F)

1,539 MMkJ/h (1,460 

MMBtu/h), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 

11°C (20°F)

330 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase

50% steam flow @ design 

steam conditions

ACCOUNT 9 COOLING WATER SYSTEM 

Equipment 

No. Description Type OperatingQty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell

1 0

Design Condition

314,192 lpm @ 30 m

(83,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

/ 1760 MMkJ/h (1670 MMBtu/h) 

heat duty
Cost and Performance Comparison of Fossil Energy Power Plants 

 250 

ACCOUNT 10 SLAG RECOVERY AND HANDLING 

Equipment 

No. Description Type Operating Qty. Spares

1 Slag Quench Tank Water bath 2 0

2 Slag Crusher Roll 2 0

3 Slag Depressurizer Lock Hopper 2 0

4 Slag Receiving Tank Horizontal, weir 2 0

5 Black Water Overflow Tank Shop fabricated 2

6 Slag Conveyor Drag chain 2 0

7 Slag Separation Screen Vibrating 2 0

8 Coarse Slag Conveyor Belt/bucket 2 0

9 Fine Ash Settling Tank Vertical, gravity 2 0

10 Fine Ash Recycle Pumps Horizontal 

centrifugal 2 2

11 Grey Water Storage Tank Field erected 2 0

12 Grey Water Pumps Centrifugal 2 2

13 Slag Storage Bin Vertical, field 

erected 2 0

14 Unloading Equipment Telescoping chute 1 0

211,985 liters (56,000 gal)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

816 tonne (900 tons)

91 tonne/h (100 tph)

68,138 liters (18,000 gal)

227 lpm @ 433 m H2O

(60 gpm @ 1,420 ft H2O)

140,061 liters (37,000 gal)

11 tonne/h (12 tph)

11 tonne/h (12 tph)

11 tonne/h (12 tph)

68,138 liters (18,000 gal)

Design Condition

215,770 liters (57,000 gal)

11 tonne/h (12 tph)

11 tonne/h (12 tph)
Cost and Performance Comparison of Fossil Energy Power Plants 

 251 

ACCOUNT 11 ACCESSORY ELECTRIC PLANT 

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, 260 MVA, 

3-ph, 60 Hz

2 STG Transformer Oil-filled 24 kV/345 kV, 200 MVA, 

3-ph, 60 Hz 1 0

24 kV/4.16 kV, 124 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 19 MVA, 

3-ph, 60 Hz

750 kW, 480 V, 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

ACCOUNT 12 INSTRUMENTATION AND CONTROLS 

Equipment 

No. Description Type OperatingQty. 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

2 DCS - Processor

Microprocessor with 

redundant 

input/output

N/A 1 0

Fully redundant, 25% spare
Cost and Performance Comparison of Fossil Energy Power Plants 

 252 

3.4.7 CASE 5 - COST ESTIMATING

Costs Results 

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-95 shows 

the total plant capital cost summary organized by cost account and Exhibit 3-96 shows a more 

detailed breakdown of the capital costs. Exhibit 3-97 shows the initial and annual O&M costs. 

The estimated TPC of the Shell gasifier with no CO2 capture is $1,977/kW. Process contingency 

represents 2.6 percent of the TPC and project contingency represents 13.7 percent. The 20-year 

LCOE is 80.5 mills/kWh. 
Cost and Performance Comparison of F

253 

Exhibit 3-95 Case 5 Total Plant Cost Summary 

Client: USDOE/NETL Report 

Project: Bituminous Baseline Study

Case: Case 05 - Shell IGCC w/o CO2

Plant Size: 635.9 MW,net Estimate Type: Conceptual Cost Base (Dec) 200

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencie

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Proj

 1 COAL & SORBENT HANDLING $12,864 $2,398 $10,080 $0 $0 $25,343 $2,296 $0 $

 2 COAL & SORBENT PREP & FEED $101,770 $8,108 $17,105 $0 $0 $126,983 $11,023 $0 $2 3 FEEDWATER & MISC. BOP SYSTEMS $9,612 $8,441 $8,983 $0 $0 $27,035 $2,523 $0 $ 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $133,051 $0 $58,510 $0 $0 $191,560 $17,125 $26,889 $34.2 Syngas Cooling (w/4.1) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 

4.3 ASU/Oxidant Compression $135,222 $0 w/equip. $0 $0 $135,222 $12,870 $0 $1

4.4-4.9 Other Gasification Equipment $15,596 $8,787 $10,765 $0 $0 $35,147 $3,316 $0 $

SUBTOTAL 4 $283,868 $8,787 $69,274 $0 $0 $361,929 $33,312 $26,889 $5

 5A Gas Cleanup & Piping $52,340 $6,552 $37,224 $0 $0 $96,117 $9,164 $82 $2 5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $82,000 $0 $5,071 $0 $0 $87,071 $8,191 $4,354 $

6.2-6.9 Combustion Turbine Other $0 $684 $762 $0 $0 $1,446 $135 $0 

SUBTOTAL 6 $82,000 $684 $5,833 $0 $0 $88,517 $8,326 $4,354 $1

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $34,073 $0 $4,848 $0 $0 $38,921 $3,674 $0 $

7.2-7.9 Ductwork and Stack $3,174 $2,235 $2,996 $0 $0 $8,405 $776 $0 $

SUBTOTAL 7 $37,247 $2,235 $7,844 $0 $0 $47,326 $4,450 $0 $

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $28,510 $0 $4,862 $0 $0 $33,372 $3,198 $0 $

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,015 $966 $7,277 $0 $0 $18,258 $1,646 $0 $

SUBTOTAL 8 $38,525 $966 $12,138 $0 $0 $51,630 $4,844 $0 $

 9 COOLING WATER SYSTEM $6,512 $7,397 $6,140 $0 $0 $20,049 $1,841 $0 $

10 ASH/SPENT SORBENT HANDLING SYS $17,384 $1,343 $8,631 $0 $0 $27,357 $2,605 $0 $11 ACCESSORY ELECTRIC PLANT $21,331 $6,784 $19,452 $0 $0 $47,567 $4,373 $0 $12 INSTRUMENTATION & CONTROL $9,443 $1,768 $6,339 $0 $0 $17,551 $1,617 $878 $13 IMPROVEMENTS TO SITE $3,166 $1,866 $7,871 $0 $0 $12,903 $1,268 $0 $14 BUILDINGS & STRUCTURES $0 $6,247 $7,291 $0 $0 $13,537 $1,231 $0 $

TOTAL COST $676,062 $63,575 $224,205 $0 $0 $963,842 $88,874 $32,202 $17

TOTAL PLANT COST SUMMARY
Cost and Performance Comparison of F

254 

Exhibit 3-96 Case 5 Total Plant Cost Details 

Client: USDOE/NETL Repor

Project: Bituminous Baseline Study

Case: Case 05 - Shell IGCC w/o CO2

Plant Size: 635.9 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenc

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $3,378 $0 $1,668 $0 $0 $5,046 $452 $0 1.2 Coal Stackout & Reclaim $4,365 $0 $1,069 $0 $0 $5,435 $477 $0 1.3 Coal Conveyors $4,059 $0 $1,058 $0 $0 $5,117 $449 $0 1.4 Other Coal Handling $1,062 $0 $245 $0 $0 $1,307 $114 $0 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,398 $6,040 $0 $0 $8,438 $804 $0 

SUBTOTAL 1. $12,864 $2,398 $10,080 $0 $0 $25,343 $2,296 $0 

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $38,663 $2,310 $5,692 $0 $0 $46,666 $4,033 $0 $2.2 Prepared Coal Storage & Feed $1,831 $436 $290 $0 $0 $2,557 $219 $0 2.3 Dry Coal Injection System $60,268 $706 $5,655 $0 $0 $66,630 $5,747 $0 $2.4 Misc.Coal Prep & Feed $1,007 $729 $2,220 $0 $0 $3,956 $363 $0 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,927 $3,247 $0 $0 $7,174 $662 $0 

SUBTOTAL 2. $101,770 $8,108 $17,105 $0 $0 $126,983 $11,023 $0 $

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 FeedwaterSystem $3,370 $5,859 $3,095 $0 $0 $12,325 $1,137 $0 3.2 Water Makeup & Pretreating $505 $53 $282 $0 $0 $839 $79 $0 3.3 Other Feedwater Subsystems $1,861 $631 $568 $0 $0 $3,060 $274 $0 3.4 Service Water Systems $291 $594 $2,063 $0 $0 $2,948 $285 $0 3.5 Other Boiler Plant Systems $1,563 $600 $1,487 $0 $0 $3,650 $342 $0 3.6 FO Supply Sys & Nat Gas $300 $567 $529 $0 $0 $1,397 $134 $0 3.7 Waste Treatment Equipment $702 $0 $430 $0 $0 $1,132 $110 $0 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $1,020 $137 $528 $0 $0 $1,685 $162 $0 

SUBTOTAL 3. $9,612 $8,441 $8,983 $0 $0 $27,035 $2,523 $0 

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $133,051 $0 $58,510 $0 $0 $191,560 $17,125 $26,889 $4.2 Syngas Cooling (w/4.1) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $135,222 $0 w/equip. $0 $0 $135,222 $12,870 $0 $4.4 LT Heat Recovery & FG Saturation $15,596 $0 $5,868 $0 $0 $21,464 $2,063 $0 4.5 Misc. Gasification Equipment w/4.1 & 4.2 w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 4.6 Other Gasification Equipment $0 $910 $371 $0 $0 $1,281 $122 $0 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $7,876 $4,526 $0 $0 $12,402 $1,131 $0 

SUBTOTAL 4. $283,868 $8,787 $69,274 $0 $0 $361,929 $33,312 $26,889 $

TOTAL PLANT COST SUMMARY
Cost and Performance Comparison of F

255 

Exhibit 3-96 Case 5 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Report Da

Project: Bituminous Baseline Study

Case: Case 05 - Shell IGCC w/o CO2

Plant Size: 635.9 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Projec

 5A GAS CLEANUP & PIPING

5A.1 Sulfinol Sustem $38,450 $0 $17,968 $0 $0 $56,417 $5,378 $0 $12,5A.2 Elemental Sulfur Plant $9,353 $1,856 $12,076 $0 $0 $23,285 $2,246 $0 $5,5A.3 Mercury Removal $926 $0 $705 $0 $0 $1,631 $156 $82 $5A.4 COS Hydrolysis $2,564 $0 $3,351 $0 $0 $5,916 $571 $0 $1,5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 5A.5 Blowback Gas Systems $1,047 $176 $99 $0 $0 $1,323 $125 $0 $5A.6 Fuel Gas Piping $0 $2,272 $1,566 $0 $0 $3,838 $350 $0 $5A.9 HGCU Foundations $0 $2,248 $1,460 $0 $0 $3,708 $339 $0 $1

SUBTOTAL 5A. $52,340 $6,552 $37,224 $0 $0 $96,117 $9,164 $82 $21,

 5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $82,000 $0 $5,071 $0 $0 $87,071 $8,191 $4,354 $96.2 Open $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $684 $762 $0 $0 $1,446 $135 $0 $

SUBTOTAL 6. $82,000 $684 $5,833 $0 $0 $88,517 $8,326 $4,354 $10,

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $34,073 $0 $4,848 $0 $0 $38,921 $3,674 $0 $47.2 Open $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,603 $1,191 $0 $0 $2,794 $246 $0 $7.4 Stack $3,174 $0 $1,193 $0 $0 $4,367 $415 $0 $7.9 HRSG,Duct & Stack Foundations $0 $632 $611 $0 $0 $1,243 $115 $0 $

SUBTOTAL 7. $37,247 $2,235 $7,844 $0 $0 $47,326 $4,450 $0 $5,

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $28,510 $0 $4,862 $0 $0 $33,372 $3,198 $0 $38.2 Turbine Plant Auxiliaries $196 $0 $450 $0 $0 $646 $63 $0 8.3 Condenser & Auxiliaries $4,511 $0 $1,442 $0 $0 $5,952 $565 $0 $8.4 Steam Piping $5,308 $0 $3,741 $0 $0 $9,048 $772 $0 $28.9 TG Foundations $0 $966 $1,645 $0 $0 $2,611 $246 $0 $

SUBTOTAL 8. $38,525 $966 $12,138 $0 $0 $51,630 $4,844 $0 $7,

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $4,206 $0 $924 $0 $0 $5,130 $486 $0 $9.2 Circulating Water Pumps $1,317 $0 $79 $0 $0 $1,397 $119 $0 $9.3 Circ.Water System Auxiliaries $117 $0 $17 $0 $0 $134 $13 $0 9.4 Circ.Water Piping $0 $4,978 $1,270 $0 $0 $6,248 $553 $0 $19.5 Make-up Water System $288 $0 $409 $0 $0 $697 $66 $0 $9.6 Component Cooling Water Sys $582 $697 $492 $0 $0 $1,771 $164 $0 $9.9 Circ.Water System Foundations& Structures $0 $1,723 $2,949 $0 $0 $4,672 $441 $0 $1

SUBTOTAL 9. $6,512 $7,397 $6,140 $0 $0 $20,049 $1,841 $0 $4,

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $15,123 $0 $7,464 $0 $0 $22,587 $2,154 $0 $2,10.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $511 $0 $557 $0 $0 $1,068 $103 $0 $10.7 Ash Transport & Feed Equipment $691 $0 $166 $0 $0 $856 $79 $0 $10.8 Misc. Ash Handling Equipment $1,059 $1,298 $388 $0 $0 $2,745 $259 $0 $10.9 Ash/Spent Sorbent Foundation $0 $45 $57 $0 $0 $102 $10 $0 

SUBTOTAL 10. $17,384 $1,343 $8,631 $0 $0 $27,357 $2,605 $0 $3,

TOTAL PLANT COST SUMMARY
Cost and Performance Comparison of F

256 

Exhibit 3-96 Case 5 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Repor

Project: Bituminous Baseline Study

Case: Case 05 - Shell IGCC w/o CO2

Plant Size: 635.9 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenc

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $905 $0 $902 $0 $0 $1,808 $172 $0 11.2 Station Service Equipment $3,411 $0 $320 $0 $0 $3,732 $354 $0 11.3 Switchgear & Motor Control $6,519 $0 $1,195 $0 $0 $7,714 $715 $0 11.4 Conduit & Cable Tray $0 $310 $10,070 $0 $0 $10,380 $1,259 $0 11.5 Wire & Cable $0 $5,697 $3,832 $0 $0 $9,529 $697 $0 11.6 Protective Equipment $0 $627 $2,378 $0 $0 $3,005 $294 $0 11.7 Standby Equipment $215 $0 $219 $0 $0 $434 $42 $0 11.8 Main Power Transformers $10,280 $0 $139 $0 $0 $10,419 $789 $0 11.9 Electrical Foundations $0 $150 $396 $0 $0 $546 $52 $0 

SUBTOTAL 11. $21,331 $6,784 $19,452 $0 $0 $47,567 $4,373 $0 

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 12.4 Other Major Component Control $932 $0 $649 $0 $0 $1,581 $152 $79 12.5 Signal Processing Equipment W/12.7 $0 W/12.7 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $214 $0 $143 $0 $0 $357 $34 $18 12.7 Computer & Accessories $4,973 $0 $166 $0 $0 $5,139 $487 $257 12.8 Instrument Wiring & Tubing $0 $1,768 $3,700 $0 $0 $5,468 $464 $273 12.9 Other I & C Equipment $3,324 $0 $1,682 $0 $0 $5,006 $480 $250 

SUBTOTAL 12. $9,443 $1,768 $6,339 $0 $0 $17,551 $1,617 $878 

13 Improvements to Site

13.1 Site Preparation $0 $99 $2,139 $0 $0 $2,238 $221 $0 13.2 Site Improvements $0 $1,767 $2,366 $0 $0 $4,132 $406 $0 13.3 Site Facilities $3,166 $0 $3,366 $0 $0 $6,532 $641 $0 

SUBTOTAL 13. $3,166 $1,866 $7,871 $0 $0 $12,903 $1,268 $0 

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $221 $127 $0 $0 $348 $31 $0 14.2 Steam Turbine Building $0 $2,337 $3,373 $0 $0 $5,710 $524 $0 14.3 Administration Building $0 $794 $584 $0 $0 $1,379 $123 $0 14.4 Circulation Water Pumphouse $0 $157 $84 $0 $0 $241 $21 $0 14.5 Water Treatment Buildings $0 $402 $398 $0 $0 $800 $72 $0 14.6 Machine Shop $0 $407 $282 $0 $0 $689 $61 $0 14.7 Warehouse $0 $657 $430 $0 $0 $1,086 $96 $0 14.8 Other Buildings & Structures $0 $393 $310 $0 $0 $704 $63 $0 14.9 Waste Treating Building & Str. $0 $879 $1,703 $0 $0 $2,582 $240 $0 

SUBTOTAL 14. $0 $6,247 $7,291 $0 $0 $13,537 $1,231 $0 

TOTAL COST $676,062 $63,575 $224,205 $0 $0 $963,842 $88,874 $32,202 $1

TOTAL PLANT COST SUMMARY
Cost and Performance Comparison of Fossil Energy Power Plants 

257 

Exhibit 3-97 Case 5 Initial and Annual Operating and Maintenance Costs 

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006

Case 05 - Shell IGCC w/o CO2 Heat Rate-net(Btu/kWh): 8,306

 MWe-net: 636

 Capacity Factor: (%): 80

 OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 33.00 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 Skilled Operator 2.0 2.0

 Operator 9.0 9.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 3.0 3.0

 TOTAL-O.J.'s 15.0 15.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $5,637,060 $8.865

Maintenance Labor Cost $12,260,125 $19.281

Administrative & Support Labor $4,474,296 $7.037

TOTAL FIXED OPERATING COSTS $22,371,481 $35.184

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $22,850,084 $0.00513

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

 Water(/1000 gallons) 0 5,460 1.03 $0 $1,642,294 $0.00037

 Chemicals

 MU & WT Chem.(lb) 113,862 16,266 0.16 $18,764 $782,745 $0.00018

 Carbon (Mercury Removal) (lb) 72,509 99 1.00 $72,509 $28,908 $0.00001

 COS Catalyst (m3) 1 0.19 2,308.40 $3,042 $126,875 $0.00003

 Water Gas Shift Catalyst(ft3) 0 0 475.00 $0 $0 $0.00000

 Selexol Solution (gal.) 0 0 12.90 $0 $0 $0.00000

 MDEA Solution (gal) 0 0 0.96 $0 $0 $0.00000

 Sulfinol Solution (gal) 525 75 9.68 $5,080 $211,900 $0.00005

 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

 Claus Catalyst(ft3) w/equip. 2.05 125.00 $0 $74,825 $0.00002

Subtotal Chemicals $99,395 $1,225,254 $0.00027

 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 99 0.40 $0 $11,609 $0.00000

 Flyash (ton) 0 0 0.00 $0 $0 $0.00000

 Bottom Ash(ton) 0 544 15.45 $0 $2,453,209 $0.00055

 Subtotal-Waste Disposal $0 $2,464,819 $0.00055

 By-products & Emissions 

 Sulfur(tons) 0 136 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $99,395 $28,182,450 $0.00632

 Fuel(ton) 162,977 5,433 42.11 $6,862,984 $66,799,712 $0.01499
Cost and Performance Comparison of Fossil Energy Power Plants 

258 

3.4.8 CASE 6 - SHELL IGCC POWER PLANT WITH CO2 CAPTURE

This case is configured to produce electric power with CO2 capture. The plant configuration is 

the same as Case 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 

combustion turbines, 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 (517 MW versus 636 

MW). 

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 3-98 and 

Exhibit 3-99, respectively. Instead of repeating the entire process description, only differences 

from Case 5 are reported here. 

Coal Preparation and Feed Systems 

No differences from Case 5. 

Gasification 

The gasification process is the same as Case 5 with the following exceptions: 

• The syngas exiting the gasifier (stream 12) is quenched to 399°C (750°F) with water 

rather than recycled syngas to provide a portion of the water required for water gas shift 

• Total coal feed (as-received) to the two gasifiers is 5,151 tonnes/day (5,678 TPD) 

(stream 9) 

• The ASU provides 4,070 tonnes/day (4,480 TPD) of 95 mole percent oxygen to the 

gasifier and Claus plant (streams 5 and 3) 

Raw Gas Cooling/Particulate Removal 

Following the water quench and particulate removal the syngas is cooled to 260°C (500°F) prior 

to the syngas scrubber (stream 13) by vaporizing HP BFW and pre-heating IP BFW. 

Syngas Scrubber/Sour Water Stripper 

Syngas exits the scrubber at 204°C (400°F). 

Sour Gas Shift (SGS) 

The SGS process was described in Section 3.1.3. In Case 6 the syngas after the scrubber is 

reheated to 285°C (545°F) and then steam (stream 14) is added to adjust the H2O:CO molar ratio 

to approximately 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 14. One more stage of SGS (for a total of 

two) results in 95.6 percent overall conversion of the CO to CO2. The warm syngas from the 

second stage of SGS is cooled to 241°C (465°F) by preheating the syngas prior to the first stage 

of SGS. The SGS catalylst also serves to hydrolyze COS thus eliminating the need for a separate 

COS hydrolysis reactor. Following the second stage of SGS, the syngas is further cooled to 

35°C (95°F) prior to the mercury removal beds. 

Mercury Removal and Acid Gas Removal 

Mercury removal is the same as in Case 5 
Cost and Performance Comparison of F

259 

Exhibit 3-98 Case 6 Process Flow Diagram, Shell IGCC with CO2 Capture 
Cost and Performance Comparison of F

260 

Exhibit 3-99 Case 6 Stream Table, Shell IGCC with CO2 Capture 

12345678 9A 10A 11 

V-L Mole Fraction 

Ar 0.0094 0.0263 0.0360 0.0024 0.0360 0.0000 0.0000 0.0102 0.0000 0.0000 0.0000 0CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0004 0.0000 0.0000 0.0000 0

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0265 0.0000 0.0000 0.0000 0CO2 0.0003 0.0091 0.0000 0.0000 0.0000 0.0000 0.0000 0.0211 0.0000 0.0000 0.0000 0COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.8874 0.0000 0.0000 0.0000 0H2O 0.0104 0.2820 0.0000 0.0004 0.0000 1.0000 0.0000 0.0001 1.0000 1.0000 0.0000 0

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0N2 0.7722 0.4591 0.0140 0.9918 0.0140 0.0000 1.0000 0.0543 0.0000 0.0000 0.0000 0

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0O2 0.2077 0.2235 0.9500 0.0054 0.9500 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1V-L Flowrate (lbmol/hr) 56,388 2,025 230 40,650 11,358 2,534 2,110 491 2,923 1,218 0 4

V-L Flowrate (lb/hr) 1,627,030 53,746 7,428 1,140,640 366,070 45,657 59,121 2,651 52,617 21,935 0 86Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 420,559 420,559 47,374 Temperature (°F) 238 70 90 385 518 750 560 121 59 215 2,595 2Pressure (psia) 190.0 16.4 125.0 460.0 740.0 740.0 815.0 469.6 14.7 14.7 614.7 6Enthalpy (BTU/lb)B 56.9 26.8 11.4 88.0 107.7 1409.5 132.2 113.8 --- --- --- 1

Density (lb/ft3) 0.732 0.104 0.688 1.424 2.272 1.027 2.086 0.407 --- --- --- 0

Molecular Weight 28.854 26.545 32.229 28.060 32.229 18.015 28.013 5.399 --- --- --- 2

A - Solids flowrate includes dry coal; V-L flowrate includes water from coalB - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of F

261 

Exhibit 3-99 Case 6 Stream Table (Continued) 

15 16 17 18 19 20 21 22 23 24 2

V-L Mole Fraction 

Ar 0.0046 0.0064 0.0064 0.0102 0.0099 0.0099 0.0000 0.0000 0.0000 0.0074 0.0CH4 0.0002 0.0002 0.0002 0.0004 0.0004 0.0004 0.0000 0.0000 0.0000 0.0000 0.0

CO 0.2697 0.0166 0.0166 0.0265 0.0256 0.0256 0.0000 0.0000 0.0000 0.0792 0.0CO2 0.0100 0.3771 0.3771 0.0211 0.0204 0.0204 1.0000 0.3526 0.0000 0.2293 0.0COS 0.0003 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0003 0.0H2 0.1369 0.5547 0.5547 0.8874 0.8584 0.8584 0.0000 0.0000 0.0000 0.0417 0.0H2O 0.5455 0.0014 0.0014 0.0001 0.0327 0.0327 0.0000 0.0502 0.0000 0.4003 0.0

H2S 0.0038 0.0050 0.0050 0.0000 0.0000 0.0000 0.0000 0.3122 0.0000 0.0013 0.0N2 0.0276 0.0385 0.0385 0.0543 0.0526 0.0526 0.0000 0.2845 0.0000 0.2379 0.7

NH3 0.0016 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0026 0.0

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0V-L Flowrate (lbmol/hr) 89,158 63,376 63,376 39,127 40,448 40,448 22,707 1,017 0 1,603 244

V-L Flowrate (lb/hr) 1,714,460 1,249,470 1,249,470 211,226 235,031 235,031 999,309 35,657 0 42,962 7,06Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 11,825 0 Temperature (°F) 574 95 95 121 213 385 156 124 352 280 5Pressure (psia) 544.7 482.6 472.6 469.6 453.9 448.9 2,214.7 60.0 23.6 23.6 14Enthalpy (BTU/lb)B 767.7 25.6 25.6 113.8 327.0 535.7 -46.4 37.9 -100.6 362.5 13

Density (lb/ft3) 0.944 1.598 1.565 0.407 0.365 0.288 30.929 0.343 329.618 0.080 0.0

Molecular Weight 19.229 19.715 19.715 5.399 5.811 5.811 44.010 35.063 256.528 26.798 28.

B - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of Fossil Energy Power Plants 

 262 

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 31 percent H2S and 35 percent CO2 with the balance primarily N2. 

The CO2-rich stream is discussed further in the CO2 compression section. 

CO2 Compression and Dehydration 

CO2 from the AGR process is generated at three pressure levels. The LP stream is compressed 

from 0.15 MPa (22 psia) to 1.1 MPa (160 psia) and then combined with the MP stream. The HP 

stream is combined between compressor stages at 2.1 MPa (300 psia). The combined stream is 

compressed from 2.1 MPa (300 psia) to a supercritical 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 93 percent CO2 with the balance primarily nitrogen and hydrogen. For modeling 

purposes it was assumed that the impurities were separated from the CO2 and combined with the 

clean syngas stream from the Selexol process. The pure 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. 

Claus Unit 

The Claus plant is the same as Case 5 with the following exceptions: 

• 5,364 kg/h (11,825 lb/h) of sulfur (stream 23) are produced 

• The waste heat boiler generates 14,099 kg/h (31,082 lb/h) of 4.7 MPa (679 psia) steam, 

which provides all of the Claus plant process needs and provides some additional steam 

to the medium pressure steam header. 

Power Block 

Clean syngas from the AGR plant is combined with a small amount of clean gas from the CO2

compression process (stream 18) and partially humidified because the nitrogen available from 

the ASU is insufficient to provide adequate dilution. The moisturized syngas is reheated to 

196°C (385°F) using HP boiler feedwater, diluted with nitrogen (stream 4), and then enters the 

CT burner. The exhaust gas (stream 26) exits the CT at 566°C (1051°F) and enters the HRSG 

where additional heat is recovered. The flue gas exits the HRSG at 132°C (270°F) (stream 27) 

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/538°C/538°C (1800 

psig/1000°F/1000°F) steam cycle. There is no integration between the CT and the ASU in this 

case. 

Air Separation Unit 

The same elevated pressure ASU is used as in Case 5 and produces 4,070 tonnes/day (4,480 

TPD) of 95 mole percent oxygen and 12,420 tonnes/day (13,690 TPD) of nitrogen. There is no 

integration between the ASU and the combustion turbine. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 263 

Balance of Plant 

Balance of plant items were covered in Sections 3.1.9, 3.1.10 and 3.1.11. 

3.4.9 CASE 6 PERFORMANCE RESULTS

The Case 6 modeling assumptions were presented previously in Section 3.4.3. 

The plant produces a net output of 517 MWe at a net plant efficiency of 32.0 percent (HHV 

basis). Overall performance for the plant is summarized in Exhibit 3-100 which includes 

auxiliary power requirements. The ASU accounts for approximately 64 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 

25 percent of the auxiliary power load. The BFW and circulating water system (circulating 

water pumps and cooling tower fan) comprise about 5 percent of the load, leaving 6 percent of 

the auxiliary load for all other systems. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 264 

Exhibit 3-100 Case 6 Plant Performance Summary 

POWER SUMMARY (Gross Power at Generator Terminals, kWe) 

Gas Turbine Power 463,630 

Steam Turbine Power 229,925 

TOTAL POWER, kWe 693,555 

AUXILIARY LOAD SUMMARY, kWe 

Coal Handling 440 

Coal Milling 2,210 

Slag Handling 570 

Air Separation Unit Auxiliaries 1,000 

Air Separation Unit Main Air Compressor 62,970 

Oxygen Compressor 10,540 

Nitrogen Compressor 38,670 

Syngas Recycle Compressor 0 

Incinerator Air Blower 160 

CO2 Compressor 28,050 

Boiler Feedwater Pumps 3,290 

Condensate Pump 310 

Flash Bottoms Pump 200 

Circulating Water Pumps 3,440 

Cooling Tower Fans 1,780 

Scrubber Pumps 390 

Double Stage Selexol Unit Auxiliaries 15,500 

Gas Turbine Auxiliaries 1,000 

Steam Turbine Auxiliaries 100 

Claus Plant/TGTU Auxiliaries 250 

Miscellaneous Balance of Plant (Note 1) 3,000 

Transformer Loss 2,550 

TOTAL AUXILIARIES, kWe 176,420 

NET POWER, kWe 517,135 

Net Plant Efficiency, % (HHV) 32.0 

Net Plant Heat Rate (Btu/kWh) 10,674 

CONDENSER COOLING DUTY 106 kJ/h (106 Btu/h) 1,465 (1,390) 

CONSUMABLES 

As-Received Coal Feed, kg/h (lb/h) 214,629 (473,176) 

Thermal Input, kWt 1,617,772 

Raw Water Usage, m3/min (gpm) 17.3 (4,563) 

Note 1: Includes plant control systems, lighting, HVAC and miscellaneous low voltage loads 
Cost and Performance Comparison of Fossil Energy Power Plants 

 265 

Environmental Performance 

The environmental targets for emissions of Hg, NOX, SO2, CO2 and particulate matter were 

presented in Section 2.4. A summary of the plant air emissions for Case 6 is presented in 

Exhibit 3-101. 

Exhibit 3-101 Case 6 Air Emissions 

kg/GJ 

(lb/106 Btu) 

Tonne/year 

(ton/year) 

80% capacity factor 

kg/MWh 

(lb/MWh) 

SO2 0.0045 (0.0105) 185 (204) 0.038 (0.084) 

NOX 0.021 (0.049) 856 (944) 0.176 (0.388) 

Particulates 0.003 (0.0071) 125 (137) 0.026 (0.057) 

Hg 0.25x10-6

(0.57x10-6) 

0.010 (0.011) 2.1x10-6

(4.5x10-6) 

CO2 8.0 (18.7) 328,000 (361,000) 67.4 (149) 

CO2

1 90.4 (199) 

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 22 ppmv. This results in a 

concentration in the flue gas of about 3 ppmv. The H2S-rich regeneration gas from the AGR 

system is fed to a Claus plant, producing elemental sulfur. The tail gas treatment unit removes 

most of the sulfur from the Claus tail gas, which is recycled to the Claus unit inlet. The clean gas 

from the tail gas treatment unit is sent to the coal dryer prior to being vented to atmosphere. 

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 of the CO is converted to CO2 in the shift reactors, the overall 

CO2 removal is 90.2 percent. 

The carbon balance for the plant is shown in Exhibit 3-102. 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, 
Cost and Performance Comparison of Fossil Energy Power Plants 

 266 

as dissolved CO2 in the wastewater blowdown stream, and CO2 in the stack gas, coal dryer vent 

gas, ASU vent gas and the captured CO2 product. Carbon in the wastewater blowdown stream is 

calculated by difference to close the material balance. The carbon capture efficiency is defined 

as the amount of carbon in the CO2 product stream relative to the amount of carbon in the coal 

less carbon contained in the slag, represented by the following fraction: 

(Carbon in Product for Sequestration)/[(Carbon in the Coal)-(Carbon in Slag)] or 

272,478/(301,649-1,511) *100 or 

90.8 percent 

Exhibit 3-102 Case 6 Carbon Balance 

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) 

Coal 136,826 (301,649) Slag 685 (1,511) 

Air (CO2) 500 (1,102) Stack Gas 10,610 (23,390) 

CO2 Product 123,595 (272,478) 

ASU Vent 101 (222) 

Coal Dryer 2,137 (4,712) 

Wastewater 198 (438) 

Total 137,326 (302,751) Total 137,326 (302,751) 

Exhibit 3-103 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, dissolved SO2 in the 

wastewater blowdown stream, 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, and the sulfur 

content of the blowdown stream is calculated by difference to close the material balance. The 

total sulfur capture is represented by the following fraction: 

(Sulfur byproduct/Sulfur in the coal) or 

(11,825/11,877) or 

99.6 percent 

Exhibit 3-103 Case 6 Sulfur Balance 

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) 

Coal 5,387 (11,877) Elemental 

Sulfur 

5,364 (11,825) 

Stack Gas 12 (27) 

Dryer Gas 1 (2) 

Wastewater 10 (23) 

Total 5,387 (11,877) Total 5,387 (11,877) 

Exhibit 3-104 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 
Cost and Performance Comparison of Fossil Energy Power Plants 

 267 

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 

makeup is the difference between water demand and internal recycle. 

Exhibit 3-104 Case 6 Water Balance 

Water Use Water Demand, 

m3/min (gpm) 

Internal Recycle, 

m3/min (gpm) 

Raw Water Makeup, 

m3/min (gpm) 

Gasifier Steam 0.3 (91) 0 0.3 (91) 

Shift Steam 1.6 (420) 0 1.6 (420) 

Humidifier 0.3 (67) 0.3 (67) 0 

Slag Handling 0.4 (123) 0.4 (123) 0 

Quench/Scrubber 4.9 (1,306) 2.6 (693) 2.3 (612) 

BFW Makeup 0.2 (45) 0 0.2 (45) 

Cooling Tower 

Makeup 13.4 (3,528) 0.5 (133) 12.9 (3,395) 

Total 21.1 (5,581) 3.8 (1,017) 17.3 (4,564) 

Heat and Mass Balance Diagrams 

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-105 

through Exhibit 3-109: 

• Coal gasification and air separation unit 

• Syngas cleanup 

• Sulfur recovery and tail gas recycle 

• Combined cycle power generation 

• Steam and feedwater 

An overall plant energy balance is provided in tabular form in Exhibit 3-110. The power out is 

the combined combustion turbine and steam turbine power prior to generator losses. The power 

at the generator terminals (shown in Exhibit 3-100) is calculated by multiplying the power out by 

a combined generator efficiency of 98.4 percent. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 268 

This page intentionally left blank 
269 

Exhibit 3-105 Case 6 Coal Gasification and Air Separation Unit Heat and Mass Bala
270 

Exhibit 3-106 Case 6 Syngas Cleanup Heat and Mass Balance Schemati
271 

Exhibit 3-107 Case 6 Sulfur Recovery and Tail Gas Recycle Heat and Mass Balanc
272 

Exhibit 3-108 Case 6 Combined Cycle Power Generation Heat and Mass Balance 
273 

Exhibit 3-109 Case 6 Steam and Feedwater Heat and Mass Balance Schem
274 

This page intentionally left blank 
Cost and Performance Comparison of Fossil Energy Power Plants 

 275 

Exhibit 3-110 Case 6 Overall Energy Balance (0°C [32°F] Reference) 

HHV Sensible + Latent Power Total 

Heat In (MMBtu/hr) 

Coal 5,520.2 4.6 5,524.8 

ASU Air 22.0 22.0 

CT Air 97.2 97.2 

Incinerator Air 1.3 1.3 

Water 23.2 23.2 

Auxiliary Power 602.0 602.0 

Totals 5,520.2 148.4 602.0 6,270.5 

Heat Out (MMBtu/hr) 

ASU Intercoolers 222.8 222.8 

ASU Vent 1.4 1.4 

Slag 21.3 33.9 55.2 

Sulfur 47.1 (1.2) 45.9 

Dryer Stack Gas 59.5 59.5 

CO2 Compressor 

Intercoolers 115.4 115.4 

CO2 Product (46.4) (46.4) 

HRSG Flue Gas 1,273.3 1,273.3 

Condenser 1,390.0 1,390.0 

Process Losses 748.8 748.8 

Power 2,404.6 2,404.6 

Totals 68.4 3,797.5 2,404.6 6,270.5 

(1) Process Losses are calculated by difference and reflect various gasification, turbine, 

HRSG and other heat and work losses. Aspen flowsheet balance is within 0.5 percent. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 276 

3.4.10 CASE 6 - MAJOR EQUIPMENT LIST

Major equipment items for the Shell gasifier with CO2 capture are shown in the following tables. 

The accounts used in the equipment list correspond to the account numbers used in the cost 

estimates in Section 3.4.11. In general, the design conditions include a 10 percent contingency 

for flows and heat duties and a 21 percent contingency for heads on pumps and fans. 

ACCOUNT 1 COAL HANDLING 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0

3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0

5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling 

System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0

8 Reclaim Hopper N/A 2 1

9 Feeder Vibratory 2 1

10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor 

reduction 2 0

14 As-Fired Coal Sampling 

System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0

17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 3 0

N/A

354 tonne/h (390 tph)

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph)

N/A

1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)

1,134 tonne/h (1,250 tph)

45 tonne (50 ton)

181 tonne/h (200 tph)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

354 tonne/h (390 tph)

181 tonne (200 ton)

N/A

N/A

354 tonne/h (390 tph)

816 tonne (900 ton)
Cost and Performance Comparison of Fossil Energy Power Plants 

 277 

ACCOUNT 2 COAL PREPARATION AND FEED 

Equipment 

No. Description Type Operating Qty. Spares

1 Feeder Vibratory 3 0

2 Conveyor No. 6 Belt w/tripper 1 0

3 Roller Mill Feed Hopper Dual Outlet 1 0

4 Weigh Feeder Belt 2 0

5 Coal Drying and Pulverization Rotary 2 0

118 tonne/h (130 tph)

118 tonne/h (130 tph)

Design Condition

82 tonne/h (90 tph)

236 tonne/h (260 tph)

472 tonne (520 ton)
Cost and Performance Comparison of Fossil Energy Power Plants 

 278 

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT 

Equipment 

No. Description Type OperatingQty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 3 0

2 Condensate Pumps Vertical canned 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 2 0

4 Intermediate Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage 2 1

6 High Pressure 

Feedwater Pump No. 2

Barrel type, multistage, centrifugal 2 1

7 Auxiliary Boiler Shop fabricated, water 

tube 1 0

8 Service Air 

Compressors Flooded Screw 2 1

9 Instrument Air Dryers Duplex, regenerative 2 1

10 Closed Cylce Cooling 

Heat Exchangers Plate and frame 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 2 1

12 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine 1 1

13 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal 1 1

14 Raw Water Pumps Stainless steel, single 

suction 2 1

15 Filtered Water Pumps Stainless steel, single 

suction 2 1

16 Filtered Water Tank Vertical, cylindrical 2 0

17 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 2 0

18 Liquid Waste Treatment 

System 1 0

5 2 1 High Pressure 

Feedwater Pump No. 1

Barrel type, multistage, centrifugal

1,048,567 liter (277,000 gal)

1,060 lpm (280 gpm)

10 years, 24-hour storm

4,353 lpm @ 49 m H2O

(1,150 gpm @ 160 ft H2O)

28 m3/min (1,000 scfm)

58 MMkJ/h (55 MMBtu/h) each

20,820 lpm @ 21 m H2O

(5,500 gpm @ 70 ft H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

9,577 lpm @ 18 m H2O

(2,530 gpm @ 60 ft H2O)

3,975 lpm @ 283 m H2O

(1,050 gpm @ 930 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C

(40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

Design Condition

927,433 liters (245,000 gal)

8,631 lpm @ 91 m H2O

(2,280 gpm @ 300 ft H2O)

603,732 kg/h (1,331,000 lb/h)

IP water: 1,173 lpm @ 223 m 

H2O (310 gpm @ 730 ft H2O)

HP water: 4,580 lpm @ 1,890 m 

H2O (1,210 gpm @ 6,200 ft 

H2O)
Cost and Performance Comparison of Fossil Energy Power Plants 

 279 

ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW 

TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Gasifier Pressurized dry-feed, 

entrained bed 2 0

2 Synthesis Gas Cooler Convective spiralwound tube boiler 2 0

3 Synthesis Gas Cyclone High efficiency 2 0

4 Candle Filter Pressurized filter with 

pulse-jet cleaning 2 0

5

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 2 0

6 Raw Gas Coolers Shell and tube with 

condensate drain 6 0

7 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator 2 0

8 Saturation Water 

Economizers Shell and tube 2 0

9 Fuel Gas Saturator Vertical tray tower 2 0

10 Saturator Water Pump Centrifugal 2 2

11 Synthesis Gas Reheater Shell and tube 2 0

12 Flare Stack

Self-supporting, carbon 

steel, stainless steel 

top, pilot ignition

2 0

13 ASU Main Air 

Compressor

Centrifugal, multistage

2 0

14 Cold Box Vendor design 2 0

15 Oxygen Compressor Centrifugal, multistage

2 0

16 Nitrogen Compressor Centrifugal, multistage

2 0

17 Nitrogen Boost 

Compressor

Centrifugal, multistage

2 0

metallic filters

375,121 kg/h (827,000 lb/h)

713,048 kg/h (1,572,000 lb/h)

312,072 kg/h, 35°C, 3.4 MPa

(688,000 lb/h, 95°F, 488 psia)

Design Condition

2,812 tonne/day, 4.2 MPa

(3,100 tpd, 615 psia)

379,204 kg/h (836,000 lb/h)

375,121 kg/h (827,000 lb/h) 

Design efficiency 90%

427,738 kg/h (943,000 lb/h)

58,513 kg/h, 101°C, 3.2 MPa

(129,000 lb/h, 213°F, 470 psia)

4,164 lpm @ 21 m H2O

(1,100 gpm @ 70 ft H2O)

58,513 kg/h (129,000 lb/h)

510 m3/min @ 2.3 MPa

(18,000 scfm @ 340 psia)

375,121 kg/h (827,000 lb/h) 

syngas

5,550 m3/min @ 1.3 MPa

(196,000 scfm @ 190 psia)

2,268 tonne/day (2,500 tpd) of 

95% purity oxygen

1,133 m3/min @ 5.1 MPa

(40,000 scfm @ 740 psia)

3,710 m3/min @ 3.4 MPa

(131,000 scfm @ 490 psia)
Cost and Performance Comparison of Fossil Energy Power Plants 

 280 

ACCOUNT 5 SYNGAS CLEANUP 

Equipment 

No. Description Type OperatingQty. Spares

1 Mercury Adsorber Sulfated carbon 

bed 2 0

2 Sulfur Plant Claus type 1 0

3 Water Gas Shift Reactors Fixed bed, 

catalytic 4 0

4 Shift Reactor Heat Recovery 

Exhchangers Shell and Tube 4 0

5 Acid Gas Removal Plant Two-stage 

Selexol 2 0

6 Tail Gas Treatment Unit Proprietary amine, 

absorber/stripper 1 0

7 Tail Gas Treatment 

Incinerator N/A 1 0

Design Condition

311,618 kg/h (687,000 lb/h)

35°C (95°F) 3.3 MPa (483 psia)

142 tonne/day (156 tpd)

Exchanger 1: 211 MMkJ/h (200 

MMBtu/h)

Exchanger 2: 63 MMkJ/h (60 

MMBtu/h)

17,645 kg/h (38,900 lb/h)

49°C (120°F) 0.1 MPa (16.4 psia)

427,738 kg/h (943,000 lb/h) 

302°C (575°F) 3.8 MPa (545 psia)

311,618 kg/h (687,000 lb/h) 

51°C (124°F) 3.3 MPa (473 psia)

67 MMkJ/h (64 MMBtu/h)

ACCOUNT 5B CO2 COMPRESSION

Equipment 

No. Description Type Operating 

Qty. Spares

1 CO2 

Compression

Integrally geared, multistage centrifugal 4 1

Design Condition

1,119 m3/min @ 15.3 MPa

(39,500 scfm @ 2,215 psia)

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Gas Turbine Advanced F class 2 0

2 Gas Turbine Generator TEWAC 2 0

Design Condition

232 MW 

260 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase
Cost and Performance Comparison of Fossil Energy Power Plants 

 281 

ACCOUNT 7 HRSG, DUCTING, AND STACK 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Stack CS plate, type 409SS 

liner 1 0

2 2 0 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator

 Reheat steam - 289,050 kg/h, 

2.9 MPa/538°C (637,245 lb/h, 

420 psig/1,000°F)

Design Condition

76 m (250 ft) high x

8.5 m (28 ft) diameter

Main steam - 258,851 kg/h, 12.4 

MPa/538°C (570,667 lb/h, 1,800 

psig/1,000°F)

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitiation 1 0

3 Steam Bypass One per HRSG 2 0

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1 0

270 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase

50% steam flow @ design 

steam conditions

Design Condition

242 MW 

12.4 MPa/538°C/538°C 

(1800 psig/ 

1000°F/1000°F)

1,613 MMkJ/h (1,530 

MMBtu/h), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 

11°C (20°F)
Cost and Performance Comparison of Fossil Energy Power Plants 

 282 

ACCOUNT 9 COOLING WATER SYSTEM 

Equipment 

No. Description Type OperatingQty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell1 0

Design Condition

344,475 lpm @ 30 m

(91,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

/ 1,919 MMkJ/h (1,820 

MMBtu/h) heat duty

ACCOUNT 10 SLAG RECOVERY AND HANDLING 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Slag Quench Tank Water bath 2 0

2 Slag Crusher Roll 2 0

3 Slag Depressurizer Lock Hopper 2 0

4 Slag Receiving Tank Horizontal, weir 2 0

5 Black Water Overflow Tank Shop fabricated 2

6 Slag Conveyor Drag chain 2 0

7 Slag Separation Screen Vibrating 2 0

8 Coarse Slag Conveyor Belt/bucket 2 0

9 Fine Ash Settling Tank Vertical, gravity 2 0

10 Fine Ash Recycle Pumps Horizontal 

centrifugal 2 2

11 Grey Water Storage Tank Field erected 2 0

12 Grey Water Pumps Centrifugal 2 2

13 Slag Storage Bin Vertical, field 

erected 2 0

14 Unloading Equipment Telescoping chute 1 0

Design Condition

227,126 liters (60,000 gal)

12 tonne/h (13 tph)

12 tonne/h (13 tph)

147,632 liters (39,000 gal)

12 tonne/h (13 tph)

12 tonne/h (13 tph)

12 tonne/h (13 tph)

68,138 liters (18,000 gal)

219,556 liters (58,000 gal)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

816 tonne (900 tons)

100 tonne/h (110 tph)

71,923 liters (19,000 gal)

265 lpm @ 433 m H2O

(70 gpm @ 1,420 ft H2O)
Cost and Performance Comparison of Fossil Energy Power Plants 

 283 

ACCOUNT 11 ACCESSORY ELECTRIC PLANT 

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 750 kW, 480 V, 3-ph, 60 Hz 1 0

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

1 0

24 kV/4.16 kV, 193 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 29 MVA, 

3-ph, 60 Hz

Design Condition

24 kV/345 kV, 260 MVA, 

3-ph, 60 Hz

2 STG Transformer Oil-filled 24 kV/345 kV, 70 MVA, 

3-ph, 60 Hz

ACCOUNT 12 INSTRUMENTATION AND CONTROLS 

Equipment 

No. Description Type OperatingQty. 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

2 DCS - Processor

Microprocessor with 

redundant 

input/output

N/A 1 0

Fully redundant, 25% spare
Cost and Performance Comparison of Fossil Energy Power Plants 

 284 

3.4.11 CASE 6 - COST ESTIMATING

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-111 shows 

the total plant capital cost summary organized by cost account and Exhibit 3-112 shows a more 

detailed breakdown of the capital costs. Exhibit 3-113 shows the initial and annual O&M costs. 

The estimated TPC of the Shell gasifier with CO2 capture is $2,668/kW. The gasifier in Case 6 

is slightly larger than Case 5, but the syngas cooler is much smaller in Case 6 (because of the 

quench configuration), which results in a lower overall cost for the Gasifier Account in Case 6. 

Process contingency represents 3.8 percent of the TPC and project contingency represents 14.0 

percent. The 20-year LCOE, including CO2 TS&M costs of 4.1 mills/kWh, is 110.4 mills/kWh. 
Cost and Performance Comparison of F

 285 

Exhibit 3-111 Case 6 Total Plant Cost Summary 

Client: USDOE/NETL Report D

Project: Bituminous Baseline Study

Case: Case 06 - Shell IGCC w/ CO2

Plant Size: 517.1 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Proje

 1 COAL & SORBENT HANDLING $13,222 $2,465 $10,360 $0 $0 $26,046 $2,360 $0 $5 2 COAL & SORBENT PREP & FEED $104,780 $8,348 $17,611 $0 $0 $130,739 $11,350 $0 $28 3 FEEDWATER & MISC. BOP SYSTEMS $8,804 $7,082 $8,709 $0 $0 $24,596 $2,304 $0 $6 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $102,271 $0 $44,114 $0 $0 $146,384 $13,107 $20,012 $27

4.2 Syngas Cooling (w/4.1) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 

4.3 ASU/Oxidant Compression $144,337 $0 w/equip. $0 $0 $144,337 $13,738 $0 $15

4.4-4.9 Other Gasification Equipment $25,903 $9,641 $15,020 $0 $0 $50,564 $4,796 $0 $11

SUBTOTAL 4 $272,511 $9,641 $59,134 $0 $0 $341,285 $31,641 $20,012 $55

 5A Gas Cleanup & Piping $80,918 $4,433 $69,321 $0 $0 $154,672 $14,826 $22,300 $38 5B CO2 REMOVAL & COMPRESSION $17,265 $0 $10,209 $0 $0 $27,475 $2,626 $0 $6

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $88,000 $0 $5,325 $0 $0 $93,325 $8,779 $9,332 $11

6.2-6.9 Combustion Turbine Other $0 $684 $762 $0 $0 $1,446 $135 $0 

SUBTOTAL 6 $88,000 $684 $6,087 $0 $0 $94,771 $8,914 $9,332 $11

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,181 $0 $4,579 $0 $0 $36,760 $3,470 $0 $4

7.2-7.9 Ductwork and Stack $3,222 $2,268 $3,041 $0 $0 $8,531 $788 $0 $1

SUBTOTAL 7 $35,402 $2,268 $7,620 $0 $0 $45,291 $4,258 $0 $5

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $24,587 $0 $4,106 $0 $0 $28,693 $2,750 $0 $3

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $8,905 $828 $6,089 $0 $0 $15,822 $1,435 $0 $3

SUBTOTAL 8 $33,492 $828 $10,195 $0 $0 $44,515 $4,184 $0 $6

 9 COOLING WATER SYSTEM $6,933 $7,764 $6,432 $0 $0 $21,129 $1,940 $0 $4

10 ASH/SPENT SORBENT HANDLING SYS $17,865 $1,375 $8,869 $0 $0 $28,109 $2,676 $0 $3

11 ACCESSORY ELECTRIC PLANT $22,955 $8,041 $22,625 $0 $0 $53,621 $4,967 $0 $1112 INSTRUMENTATION & CONTROL $10,193 $1,908 $6,843 $0 $0 $18,945 $1,746 $947 $3

13 IMPROVEMENTS TO SITE $3,207 $1,890 $7,973 $0 $0 $13,070 $1,284 $0 $4

14 BUILDINGS & STRUCTURES $0 $6,095 $7,021 $0 $0 $13,117 $1,192 $0 $2

TOTAL COST $715,547 $62,824 $259,009 $0 $0 $1,037,381 $96,266 $52,591 $193

TOTAL PLANT COST SUMMARY
Cost and Performance Comparison of F

 286 

Exhibit 3-112 Case 6 Total Plant Cost Details 

Client: USDOE/NETL Repor

Project: Bituminous Baseline Study

Case: Case 06 - Shell IGCC w/ CO2

Plant Size: 517.1 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenc

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $3,472 $0 $1,714 $0 $0 $5,186 $464 $0 1.2 Coal Stackout & Reclaim $4,487 $0 $1,099 $0 $0 $5,586 $490 $0 1.3 Coal Conveyors $4,171 $0 $1,087 $0 $0 $5,259 $462 $0 1.4 Other Coal Handling $1,091 $0 $252 $0 $0 $1,343 $118 $0 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,465 $6,207 $0 $0 $8,672 $826 $0 

SUBTOTAL 1. $13,222 $2,465 $10,360 $0 $0 $26,046 $2,360 $0 

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $39,807 $2,378 $5,861 $0 $0 $48,046 $4,152 $0 $2.2 Prepared Coal Storage & Feed $1,885 $449 $299 $0 $0 $2,633 $226 $0 2.3 Dry Coal Injection System $62,051 $727 $5,823 $0 $0 $68,601 $5,917 $0 $2.4 Misc.Coal Prep & Feed $1,037 $750 $2,286 $0 $0 $4,073 $373 $0 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $4,043 $3,343 $0 $0 $7,386 $681 $0 

SUBTOTAL 2. $104,780 $8,348 $17,611 $0 $0 $130,739 $11,350 $0 $

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 FeedwaterSystem $2,575 $4,477 $2,365 $0 $0 $9,417 $869 $0 3.2 Water Makeup & Pretreating $575 $60 $321 $0 $0 $955 $90 $0 3.3 Other Feedwater Subsystems $1,422 $482 $434 $0 $0 $2,338 $209 $0 3.4 Service Water Systems $331 $676 $2,347 $0 $0 $3,354 $324 $0 3.5 Other Boiler Plant Systems $1,779 $682 $1,693 $0 $0 $4,154 $389 $0 3.6 FO Supply Sys & Nat Gas $300 $567 $529 $0 $0 $1,397 $134 $0 3.7 Waste Treatment Equipment $798 $0 $489 $0 $0 $1,288 $125 $0 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $1,024 $138 $530 $0 $0 $1,692 $163 $0 

SUBTOTAL 3. $8,804 $7,082 $8,709 $0 $0 $24,596 $2,304 $0 

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $102,271 $0 $44,114 $0 $0 $146,384 $13,107 $20,012 $4.2 Syngas Cooling (w/4.1) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $144,337 $0 w/equip. $0 $0 $144,337 $13,738 $0 $4.4 LT Heat Recovery & FG Saturation $25,903 $0 $9,746 $0 $0 $35,649 $3,426 $0 4.5 Misc. Gasification Equipment w/4.1 & 4.2 w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 4.6 Other Gasification Equipment $0 $1,589 $647 $0 $0 $2,236 $213 $0 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $8,052 $4,627 $0 $0 $12,679 $1,157 $0 

SUBTOTAL 4. $272,511 $9,641 $59,134 $0 $0 $341,285 $31,641 $20,012 $

TOTAL PLANT COST SUMMARY
Cost and Performance Comparison of F

 287 

Exhibit 3-112 Case 6 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Report Da

Project: Bituminous Baseline Study

Case: Case 06 - Shell IGCC w/ CO2

Plant Size: 517.1 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Projec

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $59,698 $0 $51,207 $0 $0 $110,905 $10,647 $22,181 $285A.2 Elemental Sulfur Plant $9,156 $1,817 $11,821 $0 $0 $22,794 $2,198 $0 $45A.3 Mercury Removal $1,346 $0 $1,025 $0 $0 $2,371 $227 $119 $5A.4 Shift Reactors $8,816 $0 $3,551 $0 $0 $12,367 $1,177 $0 $25A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 5A.5 Blowback Gas Systems $1,903 $320 $180 $0 $0 $2,403 $226 $0 $5A.6 Fuel Gas Piping $0 $1,154 $795 $0 $0 $1,949 $178 $0 $5A.9 HGCU Foundations $0 $1,142 $741 $0 $0 $1,883 $172 $0 $

SUBTOTAL 5A. $80,918 $4,433 $69,321 $0 $0 $154,672 $14,826 $22,300 $38

 5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $17,265 $0 $10,209 $0 $0 $27,475 $2,626 $0 $6

SUBTOTAL 5B. $17,265 $0 $10,209 $0 $0 $27,475 $2,626 $0 $6

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $88,000 $0 $5,325 $0 $0 $93,325 $8,779 $9,332 $116.2 Open $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $684 $762 $0 $0 $1,446 $135 $0 $

SUBTOTAL 6. $88,000 $684 $6,087 $0 $0 $94,771 $8,914 $9,332 $11

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,181 $0 $4,579 $0 $0 $36,760 $3,470 $0 $47.2 Open $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,627 $1,209 $0 $0 $2,836 $249 $0 $7.4 Stack $3,222 $0 $1,211 $0 $0 $4,433 $422 $0 $7.9 HRSG,Duct & Stack Foundations $0 $641 $620 $0 $0 $1,262 $117 $0 $

SUBTOTAL 7. $35,402 $2,268 $7,620 $0 $0 $45,291 $4,258 $0 $5

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $24,587 $0 $4,106 $0 $0 $28,693 $2,750 $0 $38.2 Turbine Plant Auxiliaries $168 $0 $385 $0 $0 $554 $54 $0 8.3 Condenser & Auxiliaries $4,661 $0 $1,421 $0 $0 $6,082 $577 $0 $8.4 Steam Piping $4,076 $0 $2,873 $0 $0 $6,949 $593 $0 $18.9 TG Foundations $0 $828 $1,410 $0 $0 $2,238 $211 $0 $

SUBTOTAL 8. $33,492 $828 $10,195 $0 $0 $44,515 $4,184 $0 $6

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $4,467 $0 $981 $0 $0 $5,448 $516 $0 $9.2 Circulating Water Pumps $1,405 $0 $88 $0 $0 $1,494 $128 $0 $9.3 Circ.Water System Auxiliaries $124 $0 $18 $0 $0 $141 $13 $0 9.4 Circ.Water Piping $0 $5,260 $1,342 $0 $0 $6,602 $584 $0 $19.5 Make-up Water System $322 $0 $456 $0 $0 $777 $74 $0 $9.6 Component Cooling Water Sys $615 $736 $520 $0 $0 $1,871 $173 $0 $9.9 Circ.Water System Foundations& Structures $0 $1,768 $3,027 $0 $0 $4,795 $452 $0 $1

SUBTOTAL 9. $6,933 $7,764 $6,432 $0 $0 $21,129 $1,940 $0 $4

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $15,549 $0 $7,674 $0 $0 $23,223 $2,215 $0 $210.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $524 $0 $570 $0 $0 $1,094 $105 $0 $10.7 Ash Transport & Feed Equipment $707 $0 $170 $0 $0 $877 $81 $0 $10.8 Misc. Ash Handling Equipment $1,085 $1,329 $397 $0 $0 $2,811 $266 $0 $10.9 Ash/Spent Sorbent Foundation $0 $46 $58 $0 $0 $104 $10 $0 

SUBTOTAL 10. $17,865 $1,375 $8,869 $0 $0 $28,109 $2,676 $0 $3

TOTAL PLANT COST SUMMARY
Cost and Performance Comparison of F

 288 

Exhibit 3-112 Case 6 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Repor

Project: Bituminous Baseline Study

Case: Case 06 - Shell IGCC w/ CO2

Plant Size: 517.1 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenc

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $866 $0 $863 $0 $0 $1,729 $164 $0 11.2 Station Service Equipment $4,130 $0 $388 $0 $0 $4,518 $429 $0 11.3 Switchgear & Motor Control $7,893 $0 $1,447 $0 $0 $9,340 $865 $0 11.4 Conduit & Cable Tray $0 $376 $12,191 $0 $0 $12,567 $1,524 $0 11.5 Wire & Cable $0 $6,897 $4,639 $0 $0 $11,536 $843 $0 11.6 Protective Equipment $0 $627 $2,378 $0 $0 $3,005 $294 $0 11.7 Standby Equipment $208 $0 $211 $0 $0 $419 $40 $0 11.8 Main Power Transformers $9,858 $0 $132 $0 $0 $9,990 $757 $0 11.9 Electrical Foundations $0 $142 $376 $0 $0 $518 $49 $0 

SUBTOTAL 11. $22,955 $8,041 $22,625 $0 $0 $53,621 $4,967 $0 $

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,006 $0 $700 $0 $0 $1,706 $164 $85 12.5 Signal Processing Equipment W/12.7 $0 W/12.7 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $231 $0 $154 $0 $0 $386 $37 $19 12.7 Computer & Accessories $5,368 $0 $179 $0 $0 $5,547 $526 $277 12.8 Instrument Wiring & Tubing $0 $1,908 $3,994 $0 $0 $5,902 $500 $295 12.9 Other I & C Equipment $3,588 $0 $1,815 $0 $0 $5,403 $518 $270 

SUBTOTAL 12. $10,193 $1,908 $6,843 $0 $0 $18,945 $1,746 $947 

13 Improvements to Site

13.1 Site Preparation $0 $101 $2,167 $0 $0 $2,267 $223 $0 13.2 Site Improvements $0 $1,790 $2,396 $0 $0 $4,186 $411 $0 13.3 Site Facilities $3,207 $0 $3,410 $0 $0 $6,617 $650 $0 

SUBTOTAL 13. $3,207 $1,890 $7,973 $0 $0 $13,070 $1,284 $0 

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $221 $127 $0 $0 $348 $31 $0 14.2 Steam Turbine Building $0 $2,059 $2,972 $0 $0 $5,031 $462 $0 14.3 Administration Building $0 $814 $598 $0 $0 $1,412 $126 $0 14.4 Circulation Water Pumphouse $0 $153 $82 $0 $0 $235 $21 $0 14.5 Water Treatment Buildings $0 $457 $452 $0 $0 $909 $82 $0 14.6 Machine Shop $0 $416 $289 $0 $0 $705 $63 $0 14.7 Warehouse $0 $672 $440 $0 $0 $1,112 $98 $0 14.8 Other Buildings & Structures $0 $403 $318 $0 $0 $721 $64 $0 14.9 Waste Treating Building & Str. $0 $900 $1,744 $0 $0 $2,644 $246 $0 

SUBTOTAL 14. $0 $6,095 $7,021 $0 $0 $13,117 $1,192 $0 

TOTAL COST $715,547 $62,824 $259,009 $0 $0 $1,037,381 $96,266 $52,591 $1

TOTAL PLANT COST SUMMARY
Cost and Performance Comparison of Fossil Energy Power Plants 

 289 

Exhibit 3-113 Case 6 Initial and Annual Operating and Maintenance Costs 

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006

Case 06 - Shell IGCC w/ CO2 Heat Rate-net(Btu/kWh): 10,674

 MWe-net: 517

 Capacity Factor: (%): 80

 OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 33.00 $/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 $6,012,864 $11.627

Maintenance Labor Cost $12,084,712 $23.369

Administrative & Support Labor $4,524,394 $8.749

TOTAL FIXED OPERATING COSTS $22,621,970 $43.745

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $22,581,355 $0.00623

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

 Water(/1000 gallons) 0 6,551 1.03 $0 $1,970,146 $0.00054

 Chemicals

 MU & WT Chem.(lb) 136,592 19,513 0.16 $22,510 $939,005 $0.00026

 Carbon (Mercury Removal) (lb) 130,280 178 1.00 $130,280 $51,976 $0.00001

 COS Catalyst (m3) 0 0 0.96 $0 $0 $0.00000

 Water Gas Shift Catalyst(ft3) 6,922 4.74 475.00 $3,287,950 $657,438 $0.00018

 Selexol Solution (gal.) 469 67 12.90 $6,051 $252,397 $0.00007

 MDEA Solution (gal) 0 0 0.96 $0 $0 $0.00000

 Sulfinol Solution (gal) 0 0 9.68 $0 $0 $0.00000

 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

 Claus Catalyst(ft3) w/equip. 2.14 125.00 $0 $78,110 $0.00002

Subtotal Chemicals $3,446,791 $1,978,926 $0.00055

 Other

 Supplemental Fuel(MBtu) 0 0 0.00 $0 $0 $0.00000

 Gases,N2 etc.(/100scf) 0 0 0.00 $0 $0 $0.00000

 L.P. Steam(/1000 pounds) 0 0 0.00 $0 $0 $0.00000

Subtotal Other $0 $0 $0.00000

 Waste Disposal

 Spent Mercury Catalyst (lb) 0 178 0.40 $0 $20,874 $0.00001

 Flyash (ton) 0 0 0.00 $0 $0 $0.00000

 Bottom Ash(ton) 0 568 15.45 $0 $2,561,970 $0.00071

 Subtotal-Waste Disposal $0 $2,582,844 $0.00071

 By-products & Emissions 

 Sulfur(tons) 0 142 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $3,446,791 $29,113,271 $0.00803

 Fuel(ton) 170,338 5,678 42.11 $7,172,945 $69,816,668 $0.01926
Cost and Performance Comparison of Fossil Energy Power Plants 

 290 

3.5 IGCC CASE SUMMARY 

The performance results of the six IGCC plant configurations modeled in this study are 

summarized in Exhibit 3-114. 

Exhibit 3-114 Estimated Performance and Cost Results for IGCC Cases 

Case 1 Case 2 Case 3 Case 4 Case 5 Case 6

CO2 Capture No Yes No Yes No Yes

Gross Power Output (kWe) 770,350 744,960 742,510 693,840 748,020 693,555

Auxiliary Power Requirement (kWe) 130,100 189,285 119,140 175,600 112,170 176,420

Net Power Output (kWe) 640,250 555,675 623,370 518,240 635,850 517,135

Coal Flowrate (lb/hr) 489,634 500,379 463,889 477,855 452,620 473,176

Natural Gas Flowrate (lb/hr) N/A N/A N/A N/A N/A N/A

HHV Thermal Input (kWth) 1,674,044 1,710,780 1,586,023 1,633,771 1,547,493 1,617,772

Net Plant HHV Efficiency (%) 38.2% 32.5% 39.3% 31.7% 41.1% 32.0%

Net Plant HHV Heat Rate (Btu/kW-hr) 8,922 10,505 8,681 10,757 8,304 10,674

Raw Water Usage, gpm 4,003 4,579 3,757 4,135 3,792 4,563

Total Plant Cost ($ x 1,000) 1,160,919 1,328,209 1,080,166 1,259,883 1,256,810 1,379,524

Total Plant Cost ($/kW) 1,813 2,390 1,733 2,431 1,977 2,668

LCOE (mills/kWh)1 78.0 102.9 75.3 105.7 80.5 110.4

CO2 Emissions (lb/MWh)2 1,459 154 1,452 189 1,409 149

CO2 Emissions (lb/MWh)3 1,755 206 1,730 253 1,658 199

SO2 Emissions (lb/MWh)2 0.0942 0.0751 0.0909 0.0686 0.0878 0.0837

NOx Emissions (lb/MWh)2 0.406 0.366 0.433 0.400 0.413 0.388

PM Emissions (lb/MWh)2 0.053 0.056 0.052 0.057 0.050 0.057

Hg Emissions (lb/MWh)2 4.24E-06 4.48E-06 4.16E-06 4.59E-06 4.03E-06 4.55E-06 1

 Based on an 80% capacity factor

2 Value is based on gross output

3

 Value is based on net output

GEE CoP Shell

Integrated Gasification Combined Cycle

The TPC of the six IGCC cases is shown in Exhibit 3-115. The following observations are made 

with the caveat that the differences between cases are less than the estimate accuracy (± 30 

percent). However, all cases are evaluated using a common set of technical and economic 

assumptions allowing meaningful comparisons among the cases: 

• CoP has the lowest capital 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 TPC of the GEE gasifier is about 5 percent greater than CoP and Shell is about 12 

percent higher. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 291 

Exhibit 3-115 TPC for IGCC Cases 

1,813

2,390

1,733

2,431

1,977

2,668

0

500

1,000

1,500

2,000

2,500

3,000

Total Plant Cost, $/kW

GEE GEE w/ CO2

Capture

CoP CoP w/ CO2

Capture

Shell Shell w/ CO2

Capture

• The GEE gasifier is the low cost technology in the CO2 capture cases, with CoP about 2 

percent higher and Shell about 12 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 (instead of syngas recycle) that has been proposed by Shell in a patent 

application. [51] However, to date there have been no commercial applications of this 

configuration. 

• The ASU cost represents on average 14 percent of the TPC (range from 12.6-15.8 

percent). The ASU cost includes oxygen and nitrogen compression, and in the noncapture cases, also includes the cost of the combustion turbine extraction air heat 

exchanger. With nitrogen dilution used to the maximum extent possible, nitrogen 

compression costs are significant. 

• The capital cost premium for adding CO2 capture averages 36 percent ($2,496/kW versus 

$1,841/kW). 

The 20-year LCOE is shown for the IGCC cases in Exhibit 3-116. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 292 

Exhibit 3-116 LCOE for IGCC Cases 

78.0

102.9

75.3

105.7

80.5

110.4

0

20

40

60

80

100

120

140

LCOE, mills/kWh

GEE GEE w/ CO2

Capture

CoP CoP w/ CO2

Capture

Shell Shell w/ CO2

Capture

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs

The following observations can be made: 

• The LCOE is dominated by capital costs, at least 57 percent of the total in all cases. 

• In the non-capture cases the CoP gasifier has the lowest LCOE, but the differential with 

Shell is reduced (compared to the TPC) primarily because of the higher efficiency of the 

Shell gasifier. The Shell LCOE is 7 percent higher than CoP (compared to 12 percent 

higher TPC). The GEE gasifier LCOE is about 3.5 percent higher than CoP. 

• In the capture cases the variation in LCOE is small, however the order of the GEE and 

CoP gasifiers is reversed. The range is from 102.9 mills/kWh for GEE to 110.4 

mills/kWh for Shell with CoP intermediate at 105.7 mills/kWh. The LCOE CO2 capture 

premium for the IGCC cases averages 36 percent (range of 32 to 40 percent). 

• The CO2 TS&M LCOE component comprises less than 4 percent of the total LCOE in all 

capture cases. 

The effect of capacity factor and coal price on LCOE is shown in Exhibit 3-117 and 

Exhibit 3-118, respectively. 

The assumption implicit in Exhibit 3-117 is that each gasifier technology can achieve a capacity 

factor of up to 90 percent with no additional capital equipment. The cost differential between 

technologies decreases as capacity factor increases. At low capacity factor the capital cost 

differential is more magnified and the spread between technologies increases slightly. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 293 

Exhibit 3-117 Capacity Factor Sensitivity of IGCC Cases 

0

50

100

150

200

250

0 10 20 30 40 50 60 70 80 90 100

Capacity Factor, %

LCOE, mills/kWh

GEE No Capture

GEE w/CO2 Capture

CoP No Capture

CoP w/CO2 Capture

Shell No Capture

Shell w/CO2 Capture

Coal price of $1.80/MMBtu for all cases

LCOE is relatively insensitive to fuel costs for the IGCC cases as shown in Exhibit 3-118. A 

tripling of coal price from 1 to $3/MMBtu results in an average LCOE increase of only about 26-

31 percent for all cases. 

As presented in Section 2.4 the cost of CO2 capture was calculated in two ways, CO2 removed 

and CO2 avoided. The results for the IGCC carbon capture cases are shown in Exhibit 3-119. 

The cost of CO2 removed averages $30/ton for the three IGCC cases with a range of $27-

$32/ton. The CoP and Shell gasifier cases have nearly identical results but for different reasons. 

In the CoP case the cost per ton of CO2 removed is higher than GEE primarily because it has the 

lowest CO2 removal efficiency due to the higher syngas CH4 content. The Shell case is higher 

than GEE because it has the highest LCOE of the three gasifiers. 

The cost of CO2 avoided averages $39/ton with a range of $32-$42/ton. The cost of CO2 avoided 

follows the same trends as CO2 removed for the same reasons. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 294 

Exhibit 3-118 Coal Price Sensitivity of IGCC Cases 

0

20

40

60

80

100

120

140

0 0.5 1 1.5 2 2.5 3 3.5 4

Coal Price, $/MMBtu

LCOE, mills/kWh

GEE No Capture

GEE w/CO2 Capture

CoP No Capture

CoP w/CO2 Capture

Shell No Capture

Shell w/CO2 Capture

Capacity factor of 80% for all cases

Exhibit 3-119 Cost of CO2 Captured and Avoided in IGCC Cases 

27

32 32

41

31

42

0

5

10

15

20

25

30

35

40

45

$/ton, CO2

GEE IGCC CoP IGCC Shell IGCC

CO2 Removal Cost

CO2 Avoided Cost
Cost and Performance Comparison of Fossil Energy Power Plants 

 295 

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 (41.1 percent), followed by the two-stage CoP slurry fed gasifier (39.3 percent) 

and the single-stage GEE gasifier (38.2 percent). The absolute values of the GEE and 

CoP gasifiers are close to the reported values per the vendors. [48, 49] The Shell 

efficiency is slightly lower than reported by the vendor in other recent presentations. [50] 

• In the carbon capture cases the efficiency of the three gasifiers is nearly equal, ranging 

from 31.7 to 32.5 percent. 

• The dry fed Shell gasifier experiences the largest energy penalty (9.1 percent) primarily 

because addition of the steam required for the water gas shift reaction is provided as 

quench water to reduce the syngas temperature from 1427°C (2600°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 

891°C (1635°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. [51] 

• The CoP process experiences the second largest energy penalty (7.6 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 5.7 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 3-120 shows carbon conversion and slag 

carbon content. Carbon 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 3-120 Carbon Conversion Efficiency and Slag Carbon Content 

Gasifier Vendor Carbon Conversion, % Slag Carbon Content, wt% 

GEE 98.0 11.66 

CoP 99.2 4.70 

Shell 99.5 3.19 

• 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 
Cost and Performance Comparison of Fossil Energy Power Plants 

 296 

substantially below the NSPS requirement of 20 x 10-6 lb/MWh. Had 90 percent been 

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. 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. The CoP gasifier has the lowest SO2 emissions among CO2 capture 

cases because of maximizing CO2 capture to compensate for the higher CH4

concentration in the CoP raw syngas. 

Water demand, internal recycle and water usage are presented in Exhibit 3-121. The following 

observations can be made: 

• Raw water usage for all cases is dominated by cooling tower makeup requirements, 

which accounts for 84-92 percent of raw water usage in non-capture cases and 71-78 

percent in CO2 capture cases. 

• Water demand for the GEE non-capture case is 20 percent higher than the CoP noncapture case and 25 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 usage of the 

GEE process is only 6.5 percent higher than CoP and 5.5 percent higher than Shell. 

• The Shell non-capture case has the lowest water demand, but is approximately equal to 

CoP in raw water usage because very little water is available to recover for internal 

recycle in the Shell system. The GEE raw water usage is slightly higher than CoP and 

Shell primarily because the larger steam turbine output leads to higher cooling tower 

makeup requirements. 

• The water demand for the three CO2 capture cases varies by only 11 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 raw water usage in the CO2 capture cases also shows little variation with Shell and 

GEE having nearly identical requirements and CoP about 10 percent less. The main 

reason for the lower CoP water requirement is less cooling tower makeup because a 

significant amount of extraction steam is used for the SGS shift reaction. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 297 

Exhibit 3-121 Water Usage in IGCC Cases 

4,958

4,003

5,422

4,579

4,119

3,757

5,021

4,135 3,963 3,792

5,581

4,563

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Water, gpm

GEE GEE w/CO2

Capture

CoP CoP w/ CO2

Capture

Shell Shell w/ CO2

Capture

Water Demand

Internal Recycle

Raw Water Usage
Cost and Performance Comparison of Fossil Energy Power Plants 

 298 

This page intentionally left blank 
Cost and Performance Comparison of Fossil Energy Power Plants 

299 

4 PULVERIZED COAL RANKINE CYCLE PLANTS 

Four pulverized coal-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 to support a 2010 start up date. All designs 

employ a one-on-one configuration comprised of a state-of-the art pulverized coal steam 

generator firing Illinois No. 6 coal and a steam turbine. 

The PC cases are evaluated with and without carbon capture on a common 550 MWe net basis. 

The designs that include carbon 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 3, this was 

not possible in the IGCC cases because of the fixed output from the combustion turbine. 

However, the net output from the PC cases falls in the range of outputs from the IGCC cases, 

which average 530 MW for CO2 capture cases and 630 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 supercritical PC units rated at nominal 550 MWe net capacities and firing Illinois No. 6 

coal [52]. Based on the OEM responses, the following single-reheat steam conditions were 

selected for the study: 

3⁄4 For subcritical cycle cases (9 and 10) – 16.5 MPa/566°C/566°C (2400 psig/1050°F/1050°F) 

3⁄4 For supercritical cases (11 and 12) – 24.1 MPa/593°C/593°C (3500 psig/1100°F/1100°F) 

While the current DOE program for the ultra supercritical cycle materials development targets 

732°C/760°C (1350oF/1400oF) at 34.5 MPa (5000 psi) cycle conditions to be available by 2015, 

and a similar Thermie program in the European Union (EU) has targeted 700°C/720°C 

(1292oF/1328oF) at about 29.0 MPa (4200 psi) [53], 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 reheater 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 [54], has not been commercially demonstrated. In addition, the three most recently 

built supercritical 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 

[3625 psia/1058°F/1054°F]), Council Bluffs 4 in the United States, which is currently under 

construction (25.4 MPa/566°C/593°C [3690 psia/1050°F/1100°F]), and Oak Creek 1 and 2, 

which are currently under construction (24.1 MPa/566°C [3500 psig/1050°F]). 
Cost and Performance Comparison of Fossil Energy Power Plants 

300 

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 which 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 COAL AND SORBENT RECEIVING AND STORAGE

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). 

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 STEAM GENERATOR AND ANCILLARIES

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. 

The steam generator for the supercritical 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 Comparison of Fossil Energy Power Plants 

301 

It is assumed for the purposes of this study that the power plant is designed to be operated as a 

base-loaded unit but with some consideration for daily or weekly cycling, as can be cost 

effectively included in the base design. 

The combustion systems for both subcritical and supercritical 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. 

Scope 

The steam generator comprises the following for both subcritical and supercritical PCs: 

3⁄4 Drum-type evaporator 

(subcritical only) 

3⁄4 Economizer 3⁄4 Overfire air system 

3⁄4 Once-through type steam 

generator (supercritical 

only) 

3⁄4 Spray type desuperheater 3⁄4 Forced draft (FD) fans 

3⁄4 Startup circuit, including 

integral separators 

(supercritical only) 

3⁄4 Soot blower system 3⁄4 Primary air (PA) fans 

3⁄4 Water-cooled furnace, 

dry bottom 

3⁄4 Air preheaters 

(Ljungstrom type) 

3⁄4 Induced draft (ID) fans 

3⁄4 Two-stage superheater 3⁄4 Coal feeders and 

pulverizers 

3⁄4 Reheater 3⁄4 Low NOx Coal burners 

and light oil ignitors/ 

warmup system 

The steam generator operates as follows: 

Feedwater and Steam 

For the subcritical steam system feedwater 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. 

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 supercritical steam system feedwater 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 
Cost and Performance Comparison of Fossil Energy Power Plants 

302 

from the separator is returned to the economizer inlet with the boiler recirculating pump. 

Operation at loads above the Benson point is once through. 

Steam flows from the separator through the furnace roof to the convection pass enclosure walls, 

primary superheater, through the first stage of water attemperation, to the furnace platens. From 

the platens, the steam flows through the second stage of attemperation and then to the 

intermediate superheater. The steam then flows to the final superheater and on to the outlet pipe 

terminal. Two stages of spray attemperation are used to provide tight temperature control in all 

high temperature sections during rapid load changes. 

Steam returning from the turbine passes through the primary reheater surface, then through 

crossover piping containing inter-stage attemperation. The crossover piping feeds the steam to 

the final reheater banks and then out to the turbine. Inter-stage attemperation is used to provide 

outlet temperature control during load changes. 

Air and Combustion Products 

Combustion air from the FD fans is heated in Ljungstrom type air preheaters, recovering heat 

energy from the exhaust gases exiting the boiler. This air is distributed to the burner windbox as 

secondary air. Air for conveying pulverized coal to the burners is supplied by the PA fans. This 

air is heated in the Ljungstrom type air preheaters to permit drying of the pulverized coal, and a 

portion of the air from the PA fans bypasses the air preheaters to be used for regulating the outlet 

coal/air temperature leaving the mills. 

The pulverized coal and air mixture flows to the coal nozzles at various elevations of the furnace. 

The hot combustion products rise to the top of the boiler and pass through the superheater and 

reheater sections. The gases then pass through the economizer and air preheater. The gases exit 

the steam generator at this point and flow to the SCR reactor, fabric filter, ID fan, FGD system, 

and stack. 

Fuel Feed 

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% passing 200 mesh and less than 

0.5% remaining on 50 mesh [55]. The pulverized coal exits each mill via the coal piping and is 

distributed to the coal nozzles in the furnace walls using air supplied by the PA fans. 

Ash Removal 

The furnace bottom comprises several hoppers, with a clinker grinder under each hopper. The 

hoppers are of welded steel construction, lined with refractory. The hopper design incorporates a 

water-filled seal trough around the upper periphery for cooling and sealing. Water and ash 

discharged from the hopper pass through the clinker grinder to an ash sluice system for 

conveyance to hydrobins, where the ash is dewatered before it is transferred to trucks for offsite 

disposal. The description of the balance of the bottom ash handling system is presented in 

Section 4.1.9. The steam generator incorporates fly ash hoppers under the economizer outlet and 

air heater outlet. 

Burners 

A boiler of this capacity employs approximately 24 to 36 coal nozzles arranged at multiple 

elevations. Each burner is designed as a low-NOx configuration, with staging of the coal 
Cost and Performance Comparison of Fossil Energy Power Plants 

303 

combustion to minimize NOx formation. In addition, overfire air nozzles are provided to further 

stage combustion and thereby minimize NOx formation. 

Oil-fired pilot torches are provided for each coal burner for ignition, warm-up and flame 

stabilization at startup and low loads. 

Air Preheaters 

Each steam generator is furnished with two vertical-shaft Ljungstrom regenerative type air 

preheaters. These units are driven by electric motors through gear reducers. 

Soot Blowers 

The soot-blowing system utilizes an array of 50 to 150 retractable nozzles and lances that clean 

the furnace walls and convection surfaces with jets of high-pressure steam. The blowers are 

sequenced to provide an effective cleaning cycle depending on the coal quality and design of the 

furnace and convection surfaces. Electric motors drive the soot blowers through their cycles. 

4.1.3 NOX CONTROL SYSTEM

The plant is designed to achieve the environmental target of 0.07 lb NOx/MMBtu. Two 

measures are taken to reduce the NOx. The first is a combination of low-NOx burners and the 

introduction of staged overfire air in the boiler. The low-NOx burners and overfire air reduce the 

emissions to about 0.5 lb/MMBtu. 

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 low-NOx burners, achieves the emission 

limit of 0.07 lb/MMBtu. 

The SCR capital costs are included with the boiler costs, as is the cost for the initial load of 

catalyst. 

Selective non-catalytic reduction (SNCR) was considered for this application. However, with 

the installation of the low-NOx burners and overfire air system, the boiler exhaust gas contains 

relatively small amounts of NOx, which makes removal of the quantity of NOx with SNCR to 

reach the emissions limit of 0.07 lb/MMBtu difficult. SNCR works better in applications that 

contain medium to high quantities of NOx and require removal efficiencies in the range of 40 to 

60 percent. SCR, because of the catalyst used in the reaction, can achieve higher efficiencies 

with lower concentrations of NOx. 

SCR Operation Description 

The reactor vessel is designed to allow proper retention time for the ammonia to contact the NOx 

in the boiler exhaust gas. Ammonia is injected into the gas immediately prior to entering the 

reactor vessel. The catalyst contained in the reactor vessel enhances the reaction between the 

ammonia and the NOx in the gas. Catalysts consist of various active materials such as titanium 

dioxide, vanadium pentoxide, and tungsten trioxide. The operating range for vanadium/titaniumbased catalysts is 260°C (500°F) to 455°C (850°F). The boiler is equipped with economizer 

bypass to provide flue gas to the reactors at the desired temperature during periods of low flow 
Cost and Performance Comparison of Fossil Energy Power Plants 

304 

rate, such as low load operation. Also included with the reactor vessel is soot-blowing 

equipment used for cleaning the catalyst. 

The ammonia storage and injection system consists of the unloading facilities, bulk storage tank, 

vaporizers, dilution air skid, and injection grid. 

The flue gas flow control consists of ductwork, dampers, and flow straightening devices required 

to route the boiler exhaust to the SCR reactor and then to the air heater. The economizer bypass 

and associated dampers for low load temperature control are also included. 

4.1.4 PARTICULATE CONTROL

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 (PTFE) coating [56]. 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. 

4.1.5 MERCURY REMOVAL

Mercury removal is based on a coal Hg content of 0.15 ppmd. The basis for the coal Hg 

concentration was discussed in Section 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 FLUE GAS DESULFURIZATION

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 

during the CO2 absorption process. The CDR unit includes a polishing scrubber to reduce the 

flue gas SO2 concentration from about 38 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: 

• Limestone Handling and Reagent Preparation 

• FGD Scrubber 
Cost and Performance Comparison of Fossil Energy Power Plants 

305 

• Byproduct Dewatering 

Reagent Preparation System 

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 baseload operation. 

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. 

FGD Scrubber 

The flue gas 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 

reagent-laden 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 flue gas exits at the 

top of the absorber vessel and is routed to the plant stack or CDR process. 

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 
Cost and Performance Comparison of Fossil Energy Power Plants 

306 

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. 

Byproduct Dewatering 

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. 

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.

Hydrocyclones 

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. 

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. 
Cost and Performance Comparison of Fossil Energy Power Plants 

307 

Horizontal Vacuum Belt 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 

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 CARBON DIOXIDE RECOVERY FACILITY

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 supercritical 

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. 

The CO2 absorption/stripping/solvent reclaim process for Cases 10 and 12 is based on the Fluor 

Econamine FG Plus technology. [57] A typical flowsheet is shown in Exhibit 4-1. The 

Econamine FG Plus process uses a formulation of monoethanolamine (MEA) and a proprietary 

inhibitor to recover CO2 from the flue gas. This process is designed to recover high-purity CO2

from low-pressure streams that contain oxygen, such as flue gas from coal-fired power plants, 

gas turbine exhaust gas, and other waste gases. The Econamine process used in this study differs 

from previous studies, including the 2004 IEA study, [57] in the following ways: 

• The complexity of the control and operation of the plant is significantly decreased 

• Solvent consumption is decreased 

• Hard to dispose waste from the plant is eliminated 

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). [58] 
Cost and Performance Comparison of F

308 

Exhibit 4-1 Fluor Econamine FG Plus Typical Flow Diagram 
Cost and Performance Comparison of Fossil Energy Power Plants 

309 

SO2 Polishing and Flue Gas Cooling and Supply 

To prevent the accumulation of heat stable salts, 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, lowdifferential-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. 

The polishing scrubber also serves as the flue gas cooling system. Cooling water from the PC 

plant is used to reduce the temperature and hence moisture content of the saturated flue gas 

exiting the FGD system. Flue gas is cooled beyond the CO2 absorption process requirements to 

32°C (90°F) to account for the subsequent flue gas temperature increase of about 17°C (30°F) in 

the flue gas blower. Downstream from the Polishing Scrubber flue gas pressure is boosted in the 

Flue Gas Blowers by approximately 0.014 MPa (2 psi) to overcome pressure drop in the CO2

absorber tower. 

Circulating Water System 

Cooling water is provided from the PC plant circulating water system and returned to the 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 1,514,180-1,703,450 lpm (400,000-

450,000 gpm), which greatly exceeds the PC plant cooling water requirement of 719,235-

870,650 lpm (190,000-230,000 gpm).

CO2 Absorption 

The cooled flue gas enters the bottom of the CO2 Absorber and flows up through the tower 

countercurrent to a stream of lean MEA-based solvent called Econamine FG Plus. 

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 gases and leaves 

the bottom of the absorber with the absorbed CO2. 

Water Wash Section 

The purpose of the Water Wash section is to minimize solvent losses due to mechanical 

entrainment and evaporation. The flue gas from the top of the CO2 Absorption section is 

contacted with a 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
Cost and Performance Comparison of Fossil Energy Power Plants 

310 

Absorber. The wash water level is maintained by water makeup from the Wash Water Makeup 

Pump. 

Rich/Lean Amine Heat Exchange System 

The rich solvent from the bottom of the CO2 Absorber is preheated by the lean solvent from the 

Solvent Stripper in the Rich Lean Solvent Exchanger. The heated rich solvent is routed to the 

Solvent Stripper for removal of the absorbed CO2. The stripped solvent from the bottom of the 

Solvent Stripper is pumped via the Hot Lean Solvent Pumps through the Rich Lean Exchanger to 

the Solvent Surge Tank. Prior to entering the Solvent Surge Tank, a slipstream of the lean 

solvent is pumped via the Solvent Filter Feed Pump through the Solvent Filter Package to 

prevent buildup of contaminants in the solution. From the Solvent Surge Tank the lean solvent is 

pumped via the Warm Lean Solvent Pumps to the Lean Solvent Cooler for further cooling, after 

which the cooled lean solvent is returned to the CO2 Absorber, completing the circulating solvent 

circuit. 

Solvent Stripper 

The purpose of the Solvent Stripper is to separate the CO2 from the rich solvent feed exiting the 

bottom of the CO2 Absorber. The rich solvent is collected on a chimney tray below the bottom 

packed section of the Solvent Stripper and routed to the Solvent Stripper Reboilers where the 

rich solvent is heated by steam, stripping the CO2 from the solution. Steam is provided from the 

LP section of the steam turbine and is between 0.9-1.2 MPa (130-170 psia) and 366-396°C (690-

745°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 Solvent Stripper Condenser by cross 

exchanging the hot wet vapor with cooling water. The partially condensed stream then flows to 

the Solvent Stripper Reflux Drum where the vapor and liquid are separated. The uncondensed 

CO2-rich gas is then delivered to the CO2 product compressor. The condensed liquid from the 

Solvent Stripper Reflux Drum is pumped via the Solvent Stripper Reflux Pumps where a portion 

of condensed overhead liquid is used as make-up water for the Water Wash section of the CO2

Absorber. The rest of the pumped liquid is routed back to the Solvent Stripper as reflux, which 

aids in limiting the amount of solvent vapors entering the stripper overhead system. 

Solvent Stripper Reclaimer 

A small slipstream of the lean solvent from the Solvent Stripper bottoms is fed to the Solvent 

Stripper Reclaimer for the removal of high-boiling nonvolatile impurities (heat stable salts - 

HSS), volatile acids and iron products from the circulating solvent solution. The solvent bound 

in the HSS is recovered by reaction with caustic and heating with steam. The solvent reclaimer 

system reduces corrosion, foaming and fouling in the solvent system. The reclaimed solvent is 

returned to the Solvent Stripper and the spent solvent is pumped via the Solvent Reclaimer Drain 

Pump to the Solvent Reclaimer Drain Tank. 

Steam Condensate 

Steam condensate from the Solvent Stripper Reclaimer accumulates in the Solvent Reclaimer 

Condensate Drum and is level controlled to the Solvent Reboiler Condensate Drum. Steam 

condensate from the Solvent Stripper Reboilers is also collected in the Solvent Reboiler 

Condensate Drum and returned to the the steam cycle between boiler feedwater heaters 4 and 5 

via the Solvent Reboiler Condensate Pumps. 
Cost and Performance Comparison of Fossil Energy Power Plants 

311 

Corrosion Inhibitor System 

A proprietary corrosion inhibitor is continuously injected into the CO2 Absorber rich solvent 

bottoms outlet line, the Solvent Stripper bottoms outlet line and the Solvent Stripper top tray. 

This constant injection is to help control the rate of corrosion throughout the CO2 recovery plant 

system. 

Gas Compression and Drying System 

In the compression section, the CO2 is compressed to 15.3 MPa (2,215 psia) by a six-stage 

centrifugal compressor. The discharge pressures of the stages were balanced to give reasonable 

power distribution and discharge temperatures across the various stages as shown in Exhibit 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 an isentropic efficiency of 

84 percent. During compression to 15.3 MPa (2,215 psia) in the multiple-stage, intercooled 

compressor, the CO2 stream is dehydrated to a dewpoint of -40oC (-40°F) with triethylene glycol. 

The virtually moisture-free supercritical CO2 stream is delivered to the plant battery limit as 

sequestration ready. CO2 TS&M costs were estimated and included in LCOE using the 

methodology described in Section 2.7. 

4.1.8 POWER GENERATION

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). 

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 [59]. The exhaust pressure is 50.8 cm 
Cost and Performance Comparison of Fossil Energy Power Plants 

312 

(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. 

The steam-turbine generator systems for the supercritical 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. 

Turbine bearings are lubricated by a closed-loop, water-cooled pressurized oil system. Turbine 

shafts are sealed against air in-leakage or steam blowout using a labyrinth gland arrangement 

connected to a low-pressure steam seal system. The generator stator is cooled with a closed-loop 

water system consisting of circulating pumps, shell and tube or plate and frame type heat 

exchangers, filters, and deionizers, all skid-mounted. The generator rotor is cooled with a 

hydrogen gas recirculation system using fans mounted on the generator rotor shaft. 

Operation Description - The turbine stop valves, control valves, reheat stop valves, and 

intercept valves are controlled by an electro-hydraulic control system. Main steam from the 

boiler passes through the stop valves and control valves and enters the turbine at 16.5 

MPa/566°C (2400 psig/1050oF) for the subcritical cases and 24.1MPa /593°C (3500psig/1100°F) 

for the supercritical cases. The steam initially enters the turbine near the middle of the highpressure span, flows through the turbine, and returns to the boiler for reheating. The reheat 

steam flows through the reheat stop valves and intercept valves and enters the IP section at 

566°C (1050oF) in the subcritical cases and 593°C (1100°F) in the supercritical 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 BALANCE OF PLANT

The balance of plant components consist of the condensate, feedwater, main and reheat steam, 

extraction steam, ash handling, ducting and stack, waste treatment and miscellaneous systems as 

described below. 

Condensate 

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 feedwater 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 is delivered to a common discharge header through two separate pump discharge 

lines, each with a check valve and a gate valve. A common minimum flow recirculation line 

discharging to the condenser is provided downstream of the gland steam condenser to maintain 

minimum flow requirements for the gland steam condenser and the condensate pumps. 

LP feedwater heaters 1 through 4 are 50 percent capacity, parallel flow, and are located in the 

condenser neck. All remaining feedwater heaters are 100 percent capacity shell and U-tube heat 

exchangers. Each LP feedwater heater is provided with inlet/outlet isolation valves and a full 

capacity bypass. LP feedwater heater drains cascade down to the next lowest extraction pressure 

heater and finally discharge into the condenser. Pneumatic level control valves control normal 
Cost and Performance Comparison of Fossil Energy Power Plants 

313 

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. 

Feedwater 

The function of the feedwater system is to pump the feedwater from the deaerator storage tank 

through the HP feedwater heaters to the economizer. One turbine-driven boiler feedwater pump 

sized at 100 percent capacity is provided to pump feedwater through the HP feedwater heaters. 

One 25 percent motor-driven boiler feedwater 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. 

Each HP feedwater heater is provided with inlet/outlet isolation valves and a full capacity 

bypass. Feedwater heater drains cascade down to the next lowest extraction pressure heater and 

finally discharge into the deaerator. Pneumatic level control valves control normal drain level in 

the heaters. High heater level dump lines discharging to the condenser are provided for each 

heater for turbine water induction protection. Dump line flow is controlled by pneumatic level 

control valves. 

The deaerator is a horizontal, spray tray type with internal direct contact stainless steel vent 

condenser and storage tank. The boiler feed pump turbine is driven by main steam up to 

60 percent plant load. Above 60 percent load, extraction from the IP turbine exhaust (1.05 

MPa/395°C [153 psig/743°F]) provides steam to the boiler feed pump steam turbine. 

Main and Reheat Steam 

The function of the main steam system is to convey main steam from the boiler superheater 

outlet to the HP turbine stop valves. The function of the reheat system is to convey steam from 

the HP turbine exhaust to the boiler reheater and from the boiler reheater outlet to the IP turbine 

stop valves. 

Main steam exits the boiler superheater through a motor-operated stop/check valve and a motoroperated gate valve and is routed in a single line feeding the HP turbine. A branch line off the IP 

turbine exhaust feeds the boiler feed water pump turbine during unit operation starting at 

approximately 60 percent load. 

Cold reheat steam exits the HP turbine, flows through a motor-operated isolation gate valve and 

a flow control valve, and enters the boiler reheater. Hot reheat steam exits the boiler reheater 

through a motor-operated gate valve and is routed to the IP turbine. A branch connection from 

the cold reheat piping supplies steam to feedwater heater 7. 
Cost and Performance Comparison of Fossil Energy Power Plants 

314 

Extraction Steam 

The function of the extraction steam system is to convey steam from turbine extraction points 

through the following routes: 

3⁄4 From HP turbine exhaust (cold reheat) to heater 7 

3⁄4 From IP turbine extraction to heater 6 and the deaerator (heater 5) 

3⁄4 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 

feedwater heaters in the condenser neck. The extraction non-return valves are located only in 

horizontal runs of piping and as close to the turbine as possible. 

The turbine trip signal automatically trips the non-return valves through relay dumps. The 

remote manual control for each heater level control system is used to release the non-return 

valves to normal check valve service when required to restart the system. 

Circulating Water System 

It is assumed that the plant is serviced by a public water facility and has access to groundwater 

for use as makeup cooling water with minimal pretreatment. All filtration and treatment of the 

circulating water are conducted on site. A mechanical draft, wood frame, counter-flow cooling 

tower is provided for the circulating water heat sink. Two 50 percent circulating water pumps 

are provided. The circulating water system provides cooling water to the condenser, the 

auxiliary cooling water system, and the CDR facility in capture cases. 

The auxiliary cooling water system is a closed-loop system. Plate and frame heat exchangers 

with circulating water as the cooling medium are provided. This system provides cooling water 

to the lube oil coolers, turbine generator, boiler feed pumps, etc. All pumps, vacuum breakers, 

air release valves, instruments, controls, etc. are included for a complete operable system. 

The CDR system in Cases 10 and 12 requires a substantial amount of cooling water that is 

provided by the PC plant circulating water system. The additional cooling load imposed by the 

CDR is reflected in the significantly larger circulating water pumps and cooling tower in those 

cases. 

Ash Handling System 

The function of the ash handling system is to provide the equipment required for conveying, 

preparing, storing, and disposing of the fly ash and bottom ash produced on a daily basis by the 

boiler. The scope of the system is from the baghouse hoppers, air heater and economizer hopper 

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 low-pressure air from a blower provides the transport 

mechanism for the fly ash. Fly ash is discharged through a wet unloader, which conditions the 

fly ash and conveys it through a telescopic unloading chute into a truck for disposal. 
Cost and Performance Comparison of Fossil Energy Power Plants 

315 

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. 

Ducting and Stack 

One stack is provided with a single fiberglass-reinforced plastic (FRP) liner. The stack is 

constructed of reinforced concrete. The stack is 152 m (500 ft) high for adequate particulate 

dispersion. 

Waste Treatment/Miscellaneous Systems 

An onsite water treatment facility treats all runoff, cleaning wastes, blowdown, and backwash to 

within the U.S. EPA standards for suspended solids, oil and grease, pH, and miscellaneous 

metals. Waste treatment equipment is housed in a separate building. The waste treatment 

system consists of a water collection basin, three raw waste pumps, an acid neutralization 

system, an oxidation system, flocculation, clarification/thickening, and sludge dewatering. The 

water collection basin is a synthetic-membrane-lined earthen basin, which collects rainfall 

runoff, maintenance cleaning wastes, and backwash flows. 

The raw waste is pumped to the treatment system at a controlled rate by the raw waste pumps. 

The neutralization system neutralizes the acidic wastewater with hydrated lime in a two-stage 

system, consisting of a lime storage silo/lime slurry makeup system, dry lime feeder, lime slurry 

tank, slurry tank mixer, and lime slurry feed pumps. 

The oxidation system consists of an air compressor, which injects air through a sparger pipe into 

the second-stage neutralization tank. The flocculation tank is fiberglass with a variable speed 

agitator. A polymer dilution and feed system is also provided for flocculation. The clarifier is a 

plate-type, with the sludge pumped to the dewatering system. The sludge is dewatered in filter 

presses and disposed offsite. Trucking and disposal costs are included in the cost estimate. The 

filtrate from the sludge dewatering is returned to the raw waste sump. 

Miscellaneous systems consisting of fuel oil, service air, instrument air, and service water are 

provided. A storage tank provides a supply of No. 2 fuel oil used for startup and for a small 

auxiliary boiler. Fuel oil is delivered by truck. All truck roadways and unloading stations inside 

the fence area are provided. 
Cost and Performance Comparison of Fossil Energy Power Plants 

316 

Buildings and Structures 

Foundations are provided for the support structures, pumps, tanks, and other plant components. 

The following buildings are included in the design basis: 

3⁄4 Steam turbine building 3⁄4 Fuel oil pump house 3⁄4 Guard house 

3⁄4 Boiler building 3⁄4 Coal crusher building 3⁄4 Runoff water pump house 

3⁄4 Administration and 

service building 

3⁄4 Continuous emissions 

monitoring building 

3⁄4 Industrial waste treatment 

building 

3⁄4 Makeup water and 

pretreatment building 

3⁄4 Pump house and electrical 

equipment building 

3⁄4 FGD system buildings 

4.1.10 ACCESSORY ELECTRIC PLANT

The accessory electric plant consists of switchgear and control equipment, generator equipment, 

station service equipment, conduit and cable trays, and wire and cable. It also includes the main 

power transformer, required foundations, and standby equipment. 

4.1.11 INSTRUMENTATION AND CONTROL

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. 
Cost and Performance Comparison of Fossil Energy Power Plants 

317 

4.2 SUBCRITICAL PC CASES 

This section contains an evalution 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. 

• Performance Results provides the main modeling results from Case 9, including the 

performance summary, environmental performance, 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 PROCESS DESCRIPTION

In this section the subcritical PC process without CO2 capture is described. The system 

description follows the block flow diagram (BFD) in 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 6) and primary air (stream 4) are introduced into the boiler through the wall-fired 

burners. Additional combustion air, including the overfire air, is provided by the forced draft 

fans (stream 2). 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. 

Flue gas exits the boiler through the SCR reactor (stream 8) and is cooled to 177°C (350°F) in 

the combustion air preheater (not shown) before passing through a fabric filter for particulate 

removal (stream 10). An ID fan increases the flue gas temperature to 188°C (370°F) and 

provides the motive force for the flue gas (stream 11) to pass through the FGD unit. FGD inputs 

and outputs include makeup water (stream 13), oxidation air (stream 14), limestone slurry 

(stream 12) and product gypsum (stream 15). The clean, saturated flue gas exiting the FGD unit 

(stream 16) passes to the plant stack and is discharged to atmosphere. 
Cost and Performance Comparison of F

318 

Exhibit 4-3 Case 9 Process Flow Diagram, Subcritical Unit without CO2 Capture 
Cost and Performance Comparison of Fossil Energy Power Plants 

 319 

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

1 2 3 4 56 7 8

V-L Mole Fraction 

 Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087

 CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450

 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

 H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870

 N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324

 O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247

 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000

V-L Flow (lbmol/hr) 114,117 114,117 35,055 35,055 2,636 0 0 160,576

V-L Flow (lb/hr) 3,293,060 3,293,060 1,011,590 1,011,590 76,071 0 0 4,775,980

Solids Flowrate 0 0 0 0 0 437,699 8,489 33,954

Temperature (°F) 59 66 59 78 59 78 350 350

Pressure (psia) 14.70 15.25 14.70 16.14 14.70 14.70 14.40 14.40

Enthalpy (BTU/lb)A 13.1 14.9 13.1 17.7 13.1 11,676 51.4 135.7

Density (lb/ft3

) 0.08 0.08 0.08 0.08 0.08 -- -- 0.05

Avg. Molecular Weight 28.86 28.86 28.86 28.86 28.86 -- -- 29.74

9 10 11 12 13 14 15 16

V-L Mole Fraction 

 Ar 0.0000 0.0087 0.0087 0.0000 0.0000 0.0092 0.0000 0.0079

 CO2 0.0000 0.1450 0.1450 0.0000 0.0000 0.0003 0.0014 0.1317

 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

 H2O 0.0000 0.0870 0.0870 1.0000 1.0000 0.0099 0.9978 0.1725

 N2 0.0000 0.7324 0.7324 0.0000 0.0000 0.7732 0.0007 0.6644

 O2 0.0000 0.0247 0.0247 0.0000 0.0000 0.2074 0.0000 0.0234

 SO2 0.0000 0.0021 0.0021 0.0000 0.0000 0.0000 0.0000 0.0000

Total 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flow (lbmol/hr) 0 160,576 160,576 5,701 26,948 1,901 15,077 179,211

V-L Flow (lb/hr) 0 4,775,980 4,775,980 102,702 485,483 54,846 272,302 5,122,540

Solids Flowrate 33,954 0 0 43,585 0 0 67,754 0

Temperature (°F) 350 350 370 59 59 59 135 135

Pressure (psia) 14.20 14.20 15.26 14.70 14.70 14.70 14.70 14.70

Enthalpy (BTU/lb)A 51.4 136.3 141.5 -- 32.4 13.1 88.0 139.1

Density (lb/ft3

) -- 0.05 0.05 62.62 62.62 0.08 39.65 0.07

Avg. Molecular Weight -- 29.74 29.74 18.02 18.02 28.86 18.06 28.58

A - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of Fossil Energy Power Plants 

 320 

4.2.2 KEY SYSTEM ASSUMPTIONS

System assumptions for Cases 9 and 10, subcritical PC with and without CO2 capture, are 

compiled in 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, % 89 89 

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 FG Plus 

CO2 Capture, % (A) N/A 90 

CO2 Sequestration N/A Off-site Saline 

Formation 

A. Removal efficiencies are based on the flue gas content 

B. An SO2 polishing step is included to meet more stringent SOx content limits in 

the flue gas (< 10 ppmv) to reduce formation of amine heat stable salts during 

the CO2 absorption process 

C. SO2 exiting the post-FGD polishing step is absorbed in the CO2 capture process 

making stack emissions negligible 
Cost and Performance Comparison of Fossil Energy Power Plants 

 321 

Balance of Plant – Cases 9 and 10 

The balance of plant assumptions are common to all cases and are presented in Exhibit 4-6. 

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 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 Publicly 

Owned Treatment Works (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 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 Comparison of Fossil Energy Power Plants 

 322 

4.2.3 SPARING PHILOSOPHY

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: 

• 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 FG Plus CO2 absorption systems, with each 

system consisting of two absorbers, strippers and ancillary equipment (2 x 50%) 

4.2.4 CASE 9 PERFORMANCE RESULTS

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 Exhibit 4-7 which includes auxiliary power 

requirements. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 323 

Exhibit 4-7 Case 9 Plant Performance Summary 

POWER SUMMARY (Gross Power at Generator Terminals, kWe) 

TOTAL (STEAM TURBINE) POWER, kWe 583,315 

AUXILIARY LOAD SUMMARY, kWe (Note 1) 

Coal Handling and Conveying 420 

Limestone Handling & Reagent Preparation 950 

Pulverizers 2,980 

Ash Handling 570 

Primary Air Fans 1,390 

Forced Draft Fans 1,770 

Induced Draft Fans 7,590 

SCR 60 

Baghouse 100 

FGD Pumps and Agitators 3,170 

Amine System Auxiliaries N/A 

CO2 Compression N/A 

Condensate Pumps 1,390 

Miscellaneous Balance of Plant (Note 2) 2,000 

Steam Turbine Auxiliaries 400 

Circulating Water Pumps 5,440 

Cooling Tower Fans 2,810 

Transformer Loss 1,830 

TOTAL AUXILIARIES, kWe 32,870 

NET POWER, kWe 550,445 

Net Plant Efficiency (HHV) 36.8% 

Net Plant Heat Rate (Btu/kWh) 9,276 

CONDENSER COOLING DUTY 106 kJ/h (106 Btu/h) 2,656 (2,520) 

CONSUMABLES 

As-Received Coal Feed, kg/h (lb/h) 198,537 (437,699) 

Limestone Sorbent Feed, kg/h (lb/h) 19,770 (43,585) 

Thermal Input, kWt 1,496,479 

Makeup water, m3/min (gpm) 23.5 (6,212) 

Notes: 1. Boiler feed pumps are steam turbine driven 

2. Includes plant control systems, lighting, HVAC and miscellanous low 

voltage loads 
Cost and Performance Comparison of Fossil Energy Power Plants 

 324 

Environmental Performance 

The environmental targets for emissions of Hg, NOx, SO2 and particulate matter were presented 

in Section 2.4. A summary of the plant air emissions for Case 9 is presented in Exhibit 4-8. 

Exhibit 4-8 Case 9 Air Emissions 

kg/GJ 

(lb/106 Btu) 

Tonne/year 

(ton/year) 

85% capacity factor 

kg/MWh 

(lb/MWh) 

SO2 0.037 (0.085) 1,463 (1,613) 0.337 (0.743) 

NOX 0.030 (0.070) 1,331 (1,207) 0.278 (0.613) 

Particulates 0.006 (0.013) 224 (247) 0.052 (0.114) 

Hg 0.49 x 10-6

(1.14 x 10-6) 0.020 (0.022) 4.5 x 10-6 (10.0 x 10-6) 

CO2 87.5 (203) 3,506,000 

(3,865,000) 807 (1,780) 

CO2

1 855 (1,886) 

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 flue gas 

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. 

Exhibit 4-9 shows the overall water balance for the plant. Raw water is obtained from 

groundwater (50 percent) and from municipal sources (50 percent). The water usage represents 

only the contribution of raw water makeup. In some cases the water demand is greater than raw 

water makeup because of internal water recycle streams. For example, the boiler feedwater 

blowdown stream is re-used as makeup to the cooling tower, thus reducing the raw water 

requirement by that amount. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 325 

Exhibit 4-9 Case 9 Water Balance 

Water Use Water Demand, 

m3/min (gpm) 

Internal Recycle, 

m3/min (gpm) 

Raw Water Makeup, 

m3/min (gpm) 

FGD Makeup 2.4 (625) 0 2.4 (625) 

BFW Makeup 0.3 (74) 0 0.3 (74) 

Cooling Tower Makeup 21.2 (5,587) 0.3 (74) 20.9 (5,513) 

Total 23.9 (6,286) 0.3 (74) 23.6 (6,212) 

Heat and Mass Balance Diagrams 

A heat and mass balance diagram is shown for the Case 9 PC boiler, the FGD unit and steam 

cycle in Exhibit 4-10. 

An overall plant energy balance is provided in tabular form in Exhibit 4-11. 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 Comparison of Fossil Energy Power Plants 

 326 

This page intentionally left blank 
327 

Exhibit 4-10 Case 9 Heat and Mass Balance, Subcritical PC Boiler without CO2 
328 

This page intentionally left blank 
Cost and Performance Comparison of Fossil Energy Power Plants 

 329 

Exhibit 4-11 Case 9 Overall Energy Balance (0°C [32°F] Reference) 

HHV Sensible + Latent Power Total 

Heat In (MMBtu/hr) 

Coal 5,106.2 4.3 5,110.5 

Ambient Air 56.5 56.5 

Infiltration Air 1.0 1.0 

Limestone 0.2 0.2 

FGD Oxidant 0.7 0.7 

Water 19.0 19.0 

Auxiliary Power 112.2 112.2 

Totals 5,106.2 81.8 112.2 5,300.1 

Heat Out (MMBtu/hr) 

Bottom Ash 0.4 0.4 

Fly Ash 1.7 1.7 

Flue Gas Exhaust 735.5 735.5 

Gypsum Slurry 29.9 29.9 

Condenser 2,520.0 2,520.0 

Process Losses (1) 15.9 15.9 

Power 2,019.6 2,019.6 

Totals 0.0 3,280.5 2,019.6 5,300.1 

(1) 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 Comparison of Fossil Energy Power Plants 

 330 

4.2.5 CASE 9 – MAJOR EQUIPMENT LIST

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 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 Operating 

Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0

3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0

5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling 

System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0

8 Reclaim Hopper N/A 2 1

9 Feeder Vibratory 2 1

10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor 

reduction 2 0

14 As-Fired Coal Sampling 

System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0

17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 3 0

19 Limestone Truck Unloading 

Hopper N/A 1 0

20 Limestone Feeder Belt 1 0

21 Limestone Conveyor No. L1 Belt 1 0

22 Limestone Reclaim Hopper N/A 1 0

23 Limestone Reclaim Feeder Belt 1 0

24 Limestone Conveyor No. L2 Belt 1 0

25 Limestone Day Bin w/ actuator 2 0

36 tonne (40 ton)

82 tonne/h (90 tph)

82 tonne/h (90 tph)

263 tonne (290 ton)

18 tonne (20 ton)

64 tonne/h (70 tph)

64 tonne/h (70 tph)

726 tonne (800 ton)

N/A

327 tonne/h (360 tph)

N/A

45 tonne (50 ton)

163 tonne/h (180 tph)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

327 tonne/h (360 tph)

163 tonne (180 ton)

N/A

327 tonne/h (360 tph)

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph)

N/A

1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)

1,134 tonne/h (1,250 tph)
Cost and Performance Comparison of Fossil Energy Power Plants 

 331 

ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED 

Equipment 

No. Description Type Operating Qty. Spares

1 Coal Feeder Gravimetric 6 0

2 Coal Pulverizer Ball type or 

equivalent 6 0

3 Limestone Weigh Feeder Gravimetric 1 1

4 Limestone Ball Mill Rotary 1 1

5 Limestone Mill Slurry Tank 

with Agitator N/A 1 1

6 Limestone Mill Recycle 

Pumps

Horizontal 

centrifugal 1 1

7 Hydroclone Classifier

4 active 

cyclones in a 5 

cyclone bank

1 1

8 Distribution Box 2-way 1 1

9 Limestone Slurry Storage 

Tank with Agitator Field erected 1 1

10 Limestone Slurry Feed 

Pumps

Horizontal 

centrifugal 1 1

469,395 liters (124,000 gal)

336 lpm @ 12 m H2O

(370 gpm @ 40 ft H2O)

N/A

236 lpm @ 9 m H2O

(260 gpm @ 30 ft H2O)

82 lpm (90 gpm) per cyclone

83,280 liters (22,000 gal)

Design Condition

36 tonne/h (40 tph)

36 tonne/h (40 tph)

22 tonne/h (24 tph)

22 tonne/h (24 tph)
Cost and Performance Comparison of Fossil Energy Power Plants 

 332 

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT 

Equipment 

No. Description Type OperatingQty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 2 0

2 Condensate Pumps Vertical canned 1 1

3 Deaerator and Storage 

Tank Horizontal spray type 1 0

4 Boiler Feed Pump and 

Steam Turbine Drive

Barrel type, multistage, centrifugal 1 1

6 LP Feedwater Heater 

1A/1B Horizontal U-tube 2 0

7 LP Feedwater Heater 

2A/2B Horizontal U-tube 2 0

8 LP Feedwater Heater 

3A/3B Horizontal U-tube 2 0

9 LP Feedwater Heater 

4A/4B Horizontal U-tube 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 1 0

11 HP Feedwater Heater 7 Horizontal U-tube 1 0

12 Auxiliary Boiler Shop fabricated, water 

tube 1 0

13 Fuel Oil System No. 2 fuel oil for light 

off 1 0

14 Service Air 

Compressors Flooded Screw 2 1

15 Instrument Air Dryers Duplex, regenerative 2 1

16 Closed Cycle Cooling 

Heat Exchangers Shell and tube 2 0

17 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 2 1

18 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine 1 1

19 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal 1 1

20 Raw Water Pumps Stainless steel, single 

suction 2 1

21 Filtered Water Pumps Stainless steel, single 

suction 2 1

22 Filtered Water Tank Vertical, cylindrical 1 0

23 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly, 

electrodeionization unit

1 1

24 Liquid Waste Treatment 

System -- 1 0

Design Condition

1,112,920 liters (294,000 gal)

25,741 lpm @ 335 m H2O

(6,800 gpm @ 1,100 ft H2O)

1,852,020 kg/h (4,083,000 lb/h)

5 min. tank

31,041 lpm @ 2,499 m H2O

(8,200 gpm @ 8,200 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C 

(40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

762,036 kg/h (1,680,000 lb/h)

762,036 kg/h (1,680,000 lb/h)

762,036 kg/h (1,680,000 lb/h)

762,036 kg/h (1,680,000 lb/h)

1,850,659 kg/h (4,080,000 lb/h)

1,850,659 kg/h (4,080,000 lb/h)

1,135,632 liter (300,000 gal)

53 MMkJ/h (50 MMBtu/h) each

20,820 lpm @ 30 m H2O

(5,500 gpm @ 100 ft H2O)

28 m3/min (1,000 scfm)

1,540,675 liter (407,000 gal)

606 lpm (160 gpm)

10 years, 24-hour storm

5 0

Startup Boiler Feed 

Pump, Electric Motor 

Driven

Barrel type, multistage, centrifugal9,085 lpm @ 2,499 m H2O

(2,400 gpm @ 8,200 ft H2O) 1

3,785 lpm @ 88 m H2O

(1,000 gpm @ 290 ft H2O)

2,650 lpm @ 64 m H2O

(700 gpm @ 210 ft H2O)

13,098 lpm @ 43 m H2O 

(3,460 gpm @ 140 ft H2O)

1,590 lpm @ 49 m H2O

(420 gpm @ 160 ft H2O)
Cost and Performance Comparison of Fossil Energy Power Plants 

 333 

ACCOUNT 4 BOILER AND ACCESSORIES 

Equipment 

No. Description Type OperatingQty. Spares

1 Boiler

Subcritical, drum 

wall-fired, low NOx 

burners, overfire air

1 0

2 Primary Air Fan Centrifugal 2 0

3 Forced Draft Fan Centrifugal 2 0

4 Induced Draft Fan Centrifugal 2 0

5 SCR Reactor Vessel Space for spare layer 2 0

6 SCR Catalyst -- 3 0

7 Dilution Air Blower Centrifugal 2 1

8 Ammonia Storage Horizontal tank 5 0

9 Ammonia Feed 

Pump Centrifugal 2 1

142 m3/min @ 108 cm WG 

(5,000 scfm @ 42 in. WG)

155,203 liter (41,000 gal)

30 lpm @ 91 m H2O

(8 gpm @ 300 ft H2O)

1,191,589 kg/h, 25,301 m3/min @ 

90 cm WG (2,627,000 lb/h, 

893,500 acfm @ 36 in. WG)

2,381,363 kg/h (5,250,000 lb/h)

--

Design Condition

1,850,659 kg/h steam @ 16.5 

MPa/566°C/566°C 

(4,080,000 lb/h steam @ 2,400 

psig/1,050°F/1,050°F)

252,198 kg/h, 3,455 m3/min @ 

123 cm WG (556,000 lb/h, 

122,000 acfm @ 48 in. WG)

821,457 kg/h, 11,248 m3/min @ 

47 cm WG (1,811,000 lb/h, 

397,200 acfm @ 19 in. WG)
Cost and Performance Comparison of Fossil Energy Power Plants 

 334 

ACCOUNT 5 FLUE GAS CLEANUP 

Equipment 

No. Description Type OperatingQty. Spares

1 Fabric Filter

Single stage, highratio with pulsejet online cleaning 

system

2 0

2 Absorber Module Counter-current 

open spray

1 0

3 Recirculation Pumps Horizontal 

centrifugal 5 1

4 Bleed Pumps Horizontal 

centrifugal 2 1

5 Oxidation Air Blowers Centrifugal 2 1

6 Agitators Side entering 5 1

7 Dewatering Cyclones Radial assembly, 

5 units each 2 0

8 Vacuum Filter Belt Horizontal belt 2 1

9 Filtrate Water Return 

Pumps

Horizontal 

centrifugal 1 1

10 Filtrate Water Return 

Storage Tank Vertical, lined 1 0

11 Process Makeup Water 

Pumps

Horizontal 

centrifugal 1 1

187 m3/min @ 0.3 MPa

(6,620 acfm @ 37 psia)

34 tonne/h (37 tph) of 50 wt % 

slurry

4,278 lpm (1,130 gpm) at 

20 wt% solids

50 hp

1,060 lpm (280 gpm) per cyclone

644 lpm @ 12 m H2O

(170 gpm @ 40 ft H2O)

416,399 lpm (110,000 gal)

2,612 lpm @ 21 m H2O

(690 gpm @ 70 ft H2O)

Design Condition

1,191,589 kg/h (2,627,000 lb/h) 

99.8% efficiency

40,295 m3/min (1,423,000 acfm)

140,061 lpm @ 64 m H2O

(37,000 gpm @ 210 ft H2O)

ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES 

 N/A 

ACCOUNT 7 HRSG, DUCTING & STACK 

Equipment 

No. Description Type Operating Qty. Spares

1 Stack Reinforced concrete 

with FRP liner 1 0

Design Condition

152 m (500 ft) high x

5.8 m (19 ft) diameter
Cost and Performance Comparison of Fossil Energy Power Plants 

 335 

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitation 1 0

3 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1 0

610 MW 

16.5 MPa/566°C/566°C 

(2400 psig/ 

1050°F/1050°F)

2,920 MMkJ/h (2,770 

MMBtu/h), Inlet water 

temperature 16oC (60oF), 

Water temperature rise 

11oC (20oF)

680 MVA @ 0.9 p.f., 

24 kV, 60 Hz

Design Condition

ACCOUNT 9 COOLING WATER SYSTEM 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

1 0

Design Condition

545,104 lpm @ 30.5 m 

(144,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

3,036 MMkJ/h (2,880 MMBtu/h) 

heat load
Cost and Performance Comparison of Fossil Energy Power Plants 

 336 

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING 

Equipment 

No. Description Type 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 -- 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 1 1

8 Ash Seal Water Pumps Vertical, wet pit 1 1

9 Hydrobins -- 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 -- 1 1

13 Fly Ash Silo Reinforced 

concrete

2 0

14 Slide Gate Valves -- 2 0

15 Unloader -- 1 0

16 Telescoping Unloading 

Chute -- 1 0

151 lpm (40 gpm)

--

--

--

--

16 m3/min @ 0.2 MPa

(550 scfm @ 24 psi)

499 tonne (1,100 ton)

91 tonne/h (100 tph)

--

--

151 lpm @ 17 m H2O

(40 gpm @ 56 ft H2O)

7,571 lpm @ 9 m H2O

(2000 gpm @ 28 ft H2O)

--

Design Condition

--

--

4.5 tonne/h (5 tph)
Cost and Performance Comparison of Fossil Energy Power Plants 

 337 

ACCOUNT 11 ACCESSORY ELECTRIC PLANT 

Equipment 

No. Description Type Operating Qty. Spares

1 STG Transformer Oil-filled 1 0

2 Auxiliary 

Transformer Oil-filled 1 1

3 Low Voltage 

Transformer Dry ventilated 1 1

4

STG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, self-cooled 1 0

5 Medium Voltage 

Switchgear Metal clad 1 1

6 Low Voltage 

Switchgear Metal enclosed 1 1

7 Emergency Diesel 

Generator

Sized for emergency 

shutdown 1 0

24 kV/4.16 kV, 35 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 5 MVA, 

3-ph, 60 Hz

Design Condition

24 kV/345 kV, 650 MVA, 

3-ph, 60 Hz

750 kW, 480 V, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz

ACCOUNT 12 INSTRUMENTATION AND CONTROL 

Equipment 

No. Description Type OperatingQty. 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 Comparison of Fossil Energy Power Plants 

 338 

4.2.6 CASE 9 – COST ESTIMATING

The cost estimating methodology was described previously in Section 2.6. Exhibit 4-12 shows 

the total plant capital cost summary organized by cost account and Exhibit 4-13 shows a more 

detailed breakdown of the capital costs. Exhibit 4-14 shows the initial and annual O&M costs. 

The estimated TPC of the subcritical PC boiler with no CO2 capture is $1,548/kW. No process 

contingency is included in this case because all elements of the technology are commercially 

proven. The project contingency is 11.2 percent of the TPC. The 20-year LCOE is 64.0 

mills/kWh 
Cost and Performance Comparison of F

 339 

Exhibit 4-12 Case 9 Total Plant Cost Summary 

Client: USDOE/NETL Report Da

Project: Bituminous Baseline Study

Case: Case 9 - Subcritical PC w/o CO2

Plant Size: 550.4 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Projec

 1 COAL & SORBENT HANDLING $16,102 $4,348 $9,748 $0 $0 $30,198 $2,706 $0 $4 2 COAL & SORBENT PREP & FEED $10,847 $629 $2,750 $0 $0 $14,227 $1,247 $0 $2 3 FEEDWATER & MISC. BOP SYSTEMS $37,503 $0 $18,011 $0 $0 $55,514 $5,071 $0 $9

 4 PC BOILER

4.1 PC Boiler & Accessories $127,763 $0 $82,570 $0 $0 $210,334 $20,391 $0 $234.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $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 

SUBTOTAL 4 $127,763 $0 $82,570 $0 $0 $210,334 $20,391 $0 $23

 5 FLUE GAS CLEANUP $83,756 $0 $28,598 $0 $0 $112,354 $10,675 $0 $12

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 

6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 6 $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 

7.2-7.9 HRSG Accessories, Ductwork and Stack $17,476 $1,006 $11,965 $0 $0 $30,447 $2,787 $0 $4

SUBTOTAL 7 $17,476 $1,006 $11,965 $0 $0 $30,447 $2,787 $0 $4

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $47,000 $0 $6,220 $0 $0 $53,220 $5,095 $0 $5

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $22,612 $1,045 $12,107 $0 $0 $35,764 $3,134 $0 $5

SUBTOTAL 8 $69,612 $1,045 $18,328 $0 $0 $88,984 $8,230 $0 $11

 9 COOLING WATER SYSTEM $11,659 $6,571 $11,683 $0 $0 $29,913 $2,792 $0 $4

10 ASH/SPENT SORBENT HANDLING SYS $4,383 $138 $5,829 $0 $0 $10,350 $985 $0 $1

11 ACCESSORY ELECTRIC PLANT $15,802 $6,032 $17,773 $0 $0 $39,607 $3,506 $0 $5

12 INSTRUMENTATION & CONTROL $8,006 $0 $8,413 $0 $0 $16,419 $1,503 $0 $2

13 IMPROVEMENTS TO SITE $2,833 $1,629 $5,752 $0 $0 $10,214 $1,003 $0 $2

14 BUILDINGS & STRUCTURES $0 $22,304 $21,358 $0 $0 $43,662 $3,934 $0 $11

TOTAL COST $405,742 $43,703 $242,779 $0 $0 $692,224 $64,830 $0 $95

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 340 

Exhibit 4-13 Case 9 Total Plant Cost Details 

Client: USDOE/NETL Report 

Project: Bituminous Baseline Study

Case: Case 9 - Subcritical PC w/o CO2

Plant Size: 550.4 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenc

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Proj

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $3,308 $0 $1,527 $0 $0 $4,834 $432 $0 1.2 Coal Stackout & Reclaim $4,275 $0 $979 $0 $0 $5,254 $460 $0 1.3 Coal Conveyors $3,975 $0 $968 $0 $0 $4,943 $433 $0 1.4 Other Coal Handling $1,040 $0 $224 $0 $0 $1,264 $110 $0 1.5 Sorbent Receive & Unload $133 $0 $40 $0 $0 $173 $15 $0 1.6 Sorbent Stackout & Reclaim $2,145 $0 $397 $0 $0 $2,542 $221 $0 1.7 Sorbent Conveyors $765 $165 $190 $0 $0 $1,119 $97 $0 1.8 Other Sorbent Handling $462 $108 $245 $0 $0 $815 $72 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $4,076 $5,178 $0 $0 $9,254 $865 $0 $

SUBTOTAL 1. $16,102 $4,348 $9,748 $0 $0 $30,198 $2,706 $0 $

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $1,900 $0 $374 $0 $0 $2,274 $198 $0 2.2 Coal Conveyor to Storage $4,864 $0 $1,073 $0 $0 $5,936 $519 $0 2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $3,645 $156 $765 $0 $0 $4,566 $398 $0 2.6 Sorbent Storage & Feed $439 $0 $170 $0 $0 $609 $54 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $473 $369 $0 $0 $842 $78 $0 

SUBTOTAL 2. $10,847 $629 $2,750 $0 $0 $14,227 $1,247 $0 $

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 FeedwaterSystem $15,086 $0 $5,277 $0 $0 $20,363 $1,787 $0 $3.2 Water Makeup & Pretreating $4,700 $0 $1,511 $0 $0 $6,211 $582 $0 $3.3 Other Feedwater Subsystems $4,982 $0 $2,114 $0 $0 $7,095 $632 $0 $3.4 Service Water Systems $928 $0 $501 $0 $0 $1,429 $133 $0 3.5 Other Boiler Plant Systems $5,826 $0 $5,699 $0 $0 $11,525 $1,081 $0 $3.6 FO Supply Sys & Nat Gas $248 $0 $305 $0 $0 $552 $51 $0 3.7 Waste Treatment Equipment $3,168 $0 $1,815 $0 $0 $4,982 $483 $0 $3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,566 $0 $790 $0 $0 $3,356 $322 $0 

SUBTOTAL 3. $37,503 $0 $18,011 $0 $0 $55,514 $5,071 $0 $

 4 PC BOILER

4.1 PC Boiler & Accessories $127,763 $0 $82,570 $0 $0 $210,334 $20,391 $0 $24.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 4.4 Boiler BoP (w/ ID Fans) $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 4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 

SUBTOTAL 4. $127,763 $0 $82,570 $0 $0 $210,334 $20,391 $0 $2

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 341 

Exhibit 4-13 Case 9 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Report Da

Project: Bituminous Baseline Study

Case: Case 9 - Subcritical PC w/o CO2

Plant Size: 550.4 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Projec

 5 FLUE GAS CLEANUP

5.1 Absorber Vessels & Accessories $58,310 $0 $12,562 $0 $0 $70,872 $6,708 $0 $7,5.2 Other FGD $3,043 $0 $3,451 $0 $0 $6,494 $626 $0 $5.3 Bag House & Accessories $16,683 $0 $10,596 $0 $0 $27,279 $2,609 $0 $2,5.4 Other Particulate Removal Materials $1,129 $0 $1,209 $0 $0 $2,338 $225 $0 $5.5 Gypsum Dewatering System $4,591 $0 $780 $0 $0 $5,372 $508 $0 $5.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 5. $83,756 $0 $28,598 $0 $0 $112,354 $10,675 $0 $12,

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 6. $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 7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $8,649 $0 $5,645 $0 $0 $14,295 $1,249 $0 $2,7.4 Stack $8,826 $0 $5,169 $0 $0 $13,995 $1,337 $0 $1,7.9 Duct & Stack Foundations $0 $1,006 $1,151 $0 $0 $2,157 $201 $0 $

SUBTOTAL 7. $17,476 $1,006 $11,965 $0 $0 $30,447 $2,787 $0 $4,

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $47,000 $0 $6,220 $0 $0 $53,220 $5,095 $0 $5,8.2 Turbine Plant Auxiliaries $335 $0 $718 $0 $0 $1,054 $102 $0 $8.3 Condenser & Auxiliaries $7,062 $0 $2,211 $0 $0 $9,272 $880 $0 $1,8.4 Steam Piping $15,215 $0 $7,516 $0 $0 $22,731 $1,897 $0 $3,8.9 TG Foundations $0 $1,045 $1,663 $0 $0 $2,708 $255 $0 $

SUBTOTAL 8. $69,612 $1,045 $18,328 $0 $0 $88,984 $8,230 $0 $11,

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $8,335 $0 $2,730 $0 $0 $11,065 $1,051 $0 $1,9.2 Circulating Water Pumps $1,938 $0 $127 $0 $0 $2,065 $177 $0 $9.3 Circ.Water System Auxiliaries $516 $0 $69 $0 $0 $585 $55 $0 9.4 Circ.Water Piping $0 $4,162 $3,969 $0 $0 $8,131 $749 $0 $1,9.5 Make-up Water System $458 $0 $607 $0 $0 $1,065 $101 $0 $9.6 Component Cooling Water Sys $412 $0 $326 $0 $0 $738 $69 $0 $9.9 Circ.Water System Foundations& Structures $0 $2,409 $3,855 $0 $0 $6,265 $590 $0 $1,

SUBTOTAL 9. $11,659 $6,571 $11,683 $0 $0 $29,913 $2,792 $0 $4,

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 10.6 Ash Storage Silos $583 $0 $1,798 $0 $0 $2,381 $232 $0 $10.7 Ash Transport & Feed Equipment $3,800 $0 $3,869 $0 $0 $7,669 $725 $0 $10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $138 $163 $0 $0 $301 $28 $0 

SUBTOTAL 10. $4,383 $138 $5,829 $0 $0 $10,350 $985 $0 $1,

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 342 

Exhibit 4-13 Case 9 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Report 

Project: Bituminous Baseline Study

Case: Case 9 - Subcritical PC w/o CO2

Plant Size: 550.4 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenc

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $1,527 $0 $250 $0 $0 $1,777 $165 $0 11.2 Station Service Equipment $2,671 $0 $914 $0 $0 $3,585 $343 $0 11.3 Switchgear & Motor Control $3,174 $0 $544 $0 $0 $3,717 $344 $0 11.4 Conduit & Cable Tray $0 $2,038 $6,935 $0 $0 $8,973 $859 $0 $11.5 Wire & Cable $0 $3,696 $7,305 $0 $0 $11,002 $927 $0 $11.6 Protective Equipment $252 $0 $894 $0 $0 $1,146 $112 $0 11.7 Standby Equipment $1,178 $0 $28 $0 $0 $1,206 $114 $0 11.8 Main Power Transformers $7,000 $0 $166 $0 $0 $7,166 $544 $0 11.9 Electrical Foundations $0 $298 $737 $0 $0 $1,035 $98 $0 

SUBTOTAL 11. $15,802 $6,032 $17,773 $0 $0 $39,607 $3,506 $0 $

12 INSTRUMENTATION & CONTROL

12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 12.4 Other Major Component Control $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 12.6 Control Boards,Panels & Racks $410 $0 $256 $0 $0 $666 $64 $0 12.7 Distributed Control System Equipment $4,139 $0 $754 $0 $0 $4,893 $466 $0 12.8 Instrument Wiring & Tubing $2,287 $0 $4,638 $0 $0 $6,924 $590 $0 $12.9 Other I & C Equipment $1,170 $0 $2,766 $0 $0 $3,935 $383 $0 

SUBTOTAL 12. $8,006 $0 $8,413 $0 $0 $16,419 $1,503 $0 $

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $48 $959 $0 $0 $1,007 $99 $0 13.2 Site Improvements $0 $1,581 $1,978 $0 $0 $3,559 $349 $0 13.3 Site Facilities $2,833 $0 $2,815 $0 $0 $5,648 $554 $0 $

SUBTOTAL 13. $2,833 $1,629 $5,752 $0 $0 $10,214 $1,003 $0 $

14 BUILDINGS & STRUCTURES

14.1 Boiler Building $0 $8,070 $7,192 $0 $0 $15,261 $1,371 $0 $14.2 Turbine Building $0 $11,680 $11,031 $0 $0 $22,711 $2,045 $0 $14.3 Administration Building $0 $555 $594 $0 $0 $1,149 $104 $0 14.4 Circulation Water Pumphouse $0 $159 $128 $0 $0 $287 $26 $0 14.5 Water Treatment Buildings $0 $620 $518 $0 $0 $1,138 $102 $0 14.6 Machine Shop $0 $371 $253 $0 $0 $624 $55 $0 14.7 Warehouse $0 $251 $256 $0 $0 $507 $46 $0 14.8 Other Buildings & Structures $0 $205 $177 $0 $0 $383 $34 $0 14.9 Waste Treating Building & Str. $0 $393 $1,209 $0 $0 $1,603 $151 $0 

SUBTOTAL 14. $0 $22,304 $21,358 $0 $0 $43,662 $3,934 $0 $

TOTAL COST $405,742 $43,703 $242,779 $0 $0 $692,224 $64,830 $0 $9

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of Fossil Energy Power Plants 

 343 

Exhibit 4-14 Case 9 Initial and Annual Operating and Maintenance Costs 

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006

Case 9 - Subcritical PC w/o CO2 Heat Rate-net(Btu/kWh): 9,276

 MWe-net: 550

 Capacity Factor: (%): 85

 OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 33.00 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 Skilled Operator 2.0 2.0

 Operator 9.0 9.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 2.0 2.0

 TOTAL-O.J.'s 14.0 14.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $5,261,256 $9.558

Maintenance Labor Cost $5,602,943 $10.179

Administrative & Support Labor $2,716,050 $4.934

TOTAL FIXED OPERATING COSTS $13,580,249 $24.672

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $8,404,415 $0.00205

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

 Water(/1000 gallons) 0 4,472.64 1.03 $0 $1,429,266 $0.00035

 Chemicals

 MU & WT Chem.(lb) 151,553 21,650 0.16 $24,976 $1,106,970 $0.00027

 Limestone (ton) 3,661 523 20.60 $75,419 $3,342,699 $0.00082

 Carbon (Mercury Removal) (lb) 0 0 0.00 $0 $0 $0.00000

 MEA Solvent (ton) 0 0 2,142.40 $0 $0 $0.00000

 NaOH (tons) 0 0 412.96 $0 $0 $0.00000

 H2SO4 (tons) 0 0 132.15 $0 $0 $0.00000

 Corrosion Inhibitor 0 0 0.00 $0 $0 $0.00000

 Activated Carbon(lb) 0 0 1.00 $0 $0 $0.00000

 Ammonia (28% NH3) ton 550 79 123.60 $67,984 $3,013,146 $0.00074

Subtotal Chemicals $168,379 $7,462,815 $0.00182

 Other

 Supplemental Fuel(MBtu) 0 0 0.00 $0 $0 $0.00000

 SCR Catalyst(m3) w/equip. 0.47 5,500.00 $0 $794,147 $0.00019

 Emission Penalties 0 0 0.00 $0 $0 $0.00000

Subtotal Other $0 $794,147 $0.00019

 Waste Disposal

 Flyash (ton) 0 102 15.45 $0 $488,290 $0.00012

 Bottom Ash(ton) 0 407 15.45 $0 $1,953,046 $0.00048

 Subtotal-Waste Disposal $0 $2,441,336 $0.00060

 By-products & Emissions 

 Gypsum (tons) 0 823 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $168,379 $20,531,979 $0.00501

 Fuel(ton) 157,562 5,252 42.11 $6,634,942 $68,616,356 $0.01674
Cost and Performance Comparison of Fossil Energy Power Plants 

 344 

4.2.7 CASE 10 – PC SUBCRITICAL UNIT WITH CO2 CAPTURE

The plant configuration for Case 10, subcritical PC, is the same as Case 9 with the exception that 

the Econamine FG Plus 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 combustion turbines, 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. 

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 4-15 

and Exhibit 4-16, respectively. Since the CDR facility process description was provided in 

Section 4.1.7, it is not repeated here. 

4.2.8 CASE 10 PERFORMANCE RESULTS

The Case 10 modeling assumptions were presented previously in Section 4.2.2. 

The plant produces a net output of 550 MW at a net plant efficiency of 24.9 percent (HHV 

basis). Overall plant performance is summarized in Exhibit 4-17 which includes auxiliary power 

requirements. The CDR facility, including CO2 compression, accounts for over half of the 

auxiliary plant load. The circulating water system (circulating water pumps and cooling tower 

fan) accounts for over 15 percent of the auxiliary load, largely due to the high cooling water 

demand of the CDR facility. 
Cost and Performance Comparison of F

 345 

Exhibit 4-15 Case 10 Process Flow Diagram, Subcritical Unit with CO2 Capture 

FORCED DRAFT FANS

BAGHOUSE FGD

INDUCED DRAFT

FANS

GYPSUM

LIMESTONE

SLURRY

OXIDATION

AIR

MAKEUP

WATER

BOTTOM ASH

COAL FEED

INFILTRATION

AIR

8

1 2

PRIMARY AIR FANS

3 4

65

7

9

FLY ASH

10 11

13 14

12

15

16

AIRCOMBUSTIONPRODUCTSWATERCOAL/ASH

SOLID/WATER SLURRY

LEGEND

PULVERIZED

COAL

BOILER

SCR

ECONAMINE

FG+

17

18

CO2 COMPR

19

REB

S

CONDENSATE

RETURN

CO2

HP 

TURBINE

IP

TURBINE LP TURBINE

CONDENSER

FEEDWATER 

HEATER

 SYSTEM

MAIN STEAM

COLD REHEAT

HOT REHEAT

BOILER FEEDWATER
Cost and Performance Comparison of F

 346 

Exhibit 4-16 Case 10 Stream Table, Subcritical Unit with CO2 Capture 

1 2 3 4 5 6 7 8 9 

V-L Mole Fraction 

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1448 0.0000 

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0869 0.0000 

N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7325 0.0000 

O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0250 0.0000 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 V-L Flowrate (lbmol/hr) 168,844 168,844 51,867 51,867 3,894 0 0 237,558 0 

V-L Flowrate (lb/hr) 4,872,330 4,872,330 1,496,730 1,496,730 112,375 0 0 7,065,320 0 Solids Flowrate (lb/hr) 0 0 0 0 0 646,589 12,540 50,159 50,159 Temperature (°F) 59 66 59 78 59 78 350 350 350 Pressure (psia) 14.7 15.3 14.7 16.1 14.7 14.7 14.4 14.4 14.2 Enthalpy (BTU/lb)A 13.1 14.9 13.1 17.7 13.1 11,676 51.4 135.7 51.4 

Density (lb/ft3) 0.08 0.08 0.08 0.08 0.08 -- -- 0.05 -- Molecular Weight 28.86 28.86 28.86 28.86 28.86 -- -- 29.74 -- 

12 13 14 15 16 17 18 19 20 

V-L Mole Fraction 

Ar 0.0000 0.0000 0.0092 0.0000 0.0079 0.0000 0.0000 0.0000 0.0000 CO2 0.0000 0.0000 0.0003 0.0014 0.1314 0.0000 0.0000 0.9856 1.0000 

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2O 1.0000 1.0000 0.0099 0.9978 0.1725 1.0000 1.0000 0.0144 0.0000 

N2 0.0000 0.0000 0.7732 0.0007 0.6644 0.0000 0.0000 0.0000 0.0000 

O2 0.0000 0.0000 0.2074 0.0000 0.0237 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 

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (lbmol/hr) 8,120 40,086 2,816 22,176 265,166 110,756 110,756 31,826 31,369 

V-L Flowrate (lb/hr) 146,287 722,155 81,276 400,501 7,578,830 1,995,300 1,995,300 1,388,770 1,380,530 

Solids Flowrate (lb/hr) 63,956 0 0 99,659 0 0 0 0 0 Temperature (°F) 59 59 59 135 135 743 367 69 124 Pressure (psia) 14.7 14.7 14.7 14.7 14.7 167.7 167.7 23.5 2,215.0 Enthalpy (BTU/lb)A --- 32.4 13.1 88.0 143.6 1397.7 340.1 13.7 -70.8 

Density (lb/ft3) 62.62 62.62 0.08 40.44 0.07 0.24 54.94 0.18 40.76 

Molecular Weight 18.02 18.02 28.86 18.06 28.58 18.02 18.02 43.64 44.01 

A - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of Fossil Energy Power Plants 

 347 

Exhibit 4-17 Case 10 Plant Performance Summary 

POWER SUMMARY (Gross Power at Generator Terminals, kWe) 

TOTAL (STEAM TURBINE) POWER, kWe 679,923 

AUXILIARY LOAD SUMMARY, kWe (Note 1) 

Coal Handling and Conveying 520 

Limestone Handling & Reagent Preparation 1,400 

Pulverizers 4,400 

Ash Handling 840 

Primary Air Fans 2,060 

Forced Draft Fans 2,620 

Induced Draft Fans 11,180 

SCR 80 

Baghouse 100 

FGD Pumps and Agitators 4,680 

Amine System Auxiliaries 23,500 

CO2 Compression 51,610 

Condensate Pumps 1,210 

Miscellaneous Balance of Plant (Note 2) 2,000 

Steam Turbine Auxiliaries 400 

Circulating Water Pumps 14,060 

Cooling Tower Fans 7,270 

Transformer Loss 2,380 

TOTAL AUXILIARIES, kWe 130,310 

NET POWER, kWe 549,613 

Net Plant Efficiency (HHV) 24.9% 

Net Plant Heat Rate (Btu/kWh) 13,724 

CONDENSER COOLING DUTY 106 kJ/h (106 Btu/h) 2,318 (2,199) 

CONSUMABLES 

As-Received Coal Feed, kg/h (lb/h) 293,288 (646,589) 

Limestone Sorbent Feed, kg/h (lb/h) 29,010 (63,956) 

Thermal Input, kWt 2,210,668 

Makeup water, m3/min (gpm) 53.4 (14,098) 

Notes: 1. Boiler feed pumps are steam turbine driven 

2. Includes plant control systems, lighting, HVAC and miscellanous low voltage loads 
Cost and Performance Comparison of Fossil Energy Power Plants 

 348 

Environmental Performance 

The environmental targets for emissions of Hg, NOx, SO2, and particulate matter were presented 

in Section 2.4. A summary of the plant air emissions for Case 10 is presented in Exhibit 4-18. 

Exhibit 4-18 Case 10 Air Emissions 

kg/GJ 

(lb/106 Btu) 

Tonne/year 

(ton/year) 

85% capacity factor 

kg/MWh 

(lb/MWh) 

SO2 Negligible Negligible Negligible 

NOX 0.030 (0.070) 1,783 (1,966) 0.352 (0.777) 

Particulates 0.006 (0.013) 331 (365) 0.065 (0.144) 

Hg 0.49 x 10-6

(1.14 x 10-6) 0.029 (0.032) 5.8 x 10-6 (12.7 x 10-6) 

CO2 8.7 (20) 517,000 (570,000) 102 (225) 

CO2

1 126 (278) 

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 an 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 negligible 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 flue gas is removed in CDR facility. 

Exhibit 4-19 shows the overall water balance for the plant. Raw water is obtained from 

groundwater (50 percent) and from municipal sources (50 percent). The water usage represents 

only the contribution of raw water makeup. In some cases the actual consumption is greater than 

raw water makeup because of internal water recycle streams. For example, the boiler feedwater 

blowdown stream and condensate from cooling the flue gas prior to the CDR facility are re-used 

as makeup to the cooling tower, thus reducing the raw water requirement by that amount. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 349 

Exhibit 4-19 Case 10 Water Balance 

Water Use Water Demand, 

m3/min (gpm) 

Internal Recycle, 

m3/min (gpm) 

Raw Water Makeup, 

m3/min (gpm) 

FGD Makeup 3.5 (926) 0 3.5 (926) 

BFW Makeup 0.4 (109) 0 0.4 (109) 

Cooling Tower Makeup 54.7 (14,453) 5.3 (1,390) 49.4 (13,063) 

Total 58.6 (15,488) 5.3 (1,390) 53.3 (14,098) 

Heat and Mass Balance Diagrams 

A heat and mass balance diagram is shown for the Case 10 PC boiler, the FGD unit, CDR system 

and steam cycle in Exhibit 4-20. 

An overall plant energy balance is provided in tabular form in Exhibit 4-21. The power out is 

the steam turbine power prior to generator losses. The power at the generator terminals (shown 

in Exhibit 4-17) is calculated by multiplying the power out by a generator efficiency of 98.4 

percent. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 350 

This page intentionally left blank 
351 

Exhibit 4-20 Case 10 Heat and Mass Balance, Subcritical PC Boiler with CO2 C
352 

This page intentionally left blank 
Cost and Performance Comparison of Fossil Energy Power Plants 

 353 

Exhibit 4-21 Case 10 Overall Energy Balance (0°C [32°F] Reference) 

HHV Sensible + Latent Power Total 

Heat In (MMBtu/hr) 

Coal 7,543.1 6.3 7,549.4 

Ambient Air 83.6 83.6 

Infiltration Air 1.5 1.5 

Limestone 0.3 0.3 

FGD Oxidant 1.1 1.1 

Water 28.1 28.1 

Auxiliary Power 444.6 444.6 

Totals 7,543.1 120.9 444.6 8,108.6 

Heat Out (MMBtu/hr) 

Bottom Ash 0.6 0.6 

Fly Ash 2.6 2.6 

Flue Gas Exhaust 253.0 253.0 

CO2 Product (97.7) (97.7) 

CO2 Steam Losses 2,110.0 2,110.0 

CO2 Cooling Losses 278.0 278.0 

CO2 System Losses 777.0 777.0 

Gypsum Slurry 44.0 44.0 

Condenser 2,200.0 2,200.0 

Process Losses (1) 181.9 181.9 

Power 2,359.2 2,359.2 

Totals 0.0 5,749.4 2,359.2 8,108.6 

(1) 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 Comparison of Fossil Energy Power Plants 

 354 

4.2.9 CASE 10 – MAJOR EQUIPMENT LIST

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 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 Operating Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0

3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0

5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling 

System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0

8 Reclaim Hopper N/A 2 1

9 Feeder Vibratory 2 1

10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor 

reduction 2 0

14 As-Fired Coal Sampling 

System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0

17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 3 0

19 Limestone Truck Unloading 

Hopper N/A 1 0

20 Limestone Feeder Belt 1 0

21 Limestone Conveyor No. L1 Belt 1 0

22 Limestone Reclaim Hopper N/A 1 0

23 Limestone Reclaim Feeder Belt 1 0

24 Limestone Conveyor No. L2 Belt 1 0

25 Limestone Day Bin w/ actuator 2 0

36 tonne (40 ton)

118 tonne/h (130 tph)

118 tonne/h (130 tph)

381 tonne (420 ton)

27 tonne (30 ton)

100 tonne/h (110 tph)

100 tonne/h (110 tph)

1,089 tonne (1,200 ton)

N/A

481 tonne/h (530 tph)

N/A

64 tonne (70 ton)

245 tonne/h (270 tph)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

481 tonne/h (530 tph)

245 tonne (270 ton)

N/A

481 tonne/h (530 tph)

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph)

N/A

1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)

1,134 tonne/h (1,250 tph)
Cost and Performance Comparison of Fossil Energy Power Plants 

 355 

ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Coal Feeder Gravimetric 6 0

2 Coal Pulverizer Ball type or 

equivalent 6 0

3 Limestone Weigh Feeder Gravimetric 1 1

4 Limestone Ball Mill Rotary 1 1

5 Limestone Mill Slurry Tank 

with Agitator N/A 1 1

6 Limestone Mill Recycle 

Pumps

Horizontal 

centrifugal 1 1

7 Hydroclone Classifier

4 active 

cyclones in a 5 

cyclone bank

1 1

8 Distribution Box 2-way 1 1

9 Limestone Slurry Storage 

Tank with Agitator Field erected 1 1

10 Limestone Slurry Feed 

Pumps

Horizontal 

centrifugal 1 1

688,950 liters (182,000 gal)

490 lpm @ 12m H2O

(540 gpm @ 40 ft H2O)

N/A

345 lpm @ 9m H2O

(380 gpm @ 30 ft H2O)

127 lpm (140 gpm) per cyclone

121,134 liters (32,000 gal)

Design Condition

54 tonne/h (60 tph)

54 tonne/h (60 tph)

32 tonne/h (35 tph)

32 tonne/h (35 tph)
Cost and Performance Comparison of Fossil Energy Power Plants 

 356 

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT 

Equipment 

No. Description Type OperatingQty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 2 0

2 Condensate Pumps Vertical canned 1 1

3 Deaerator and Storage 

Tank Horizontal spray type 1 0

4 Boiler Feed Pump and 

Steam Turbine Drive

Barrel type, multistage, centrifugal 1 1

6 LP Feedwater Heater 

1A/1B Horizontal U-tube 2 0

7 LP Feedwater Heater 

2A/2B Horizontal U-tube 2 0

8 LP Feedwater Heater 

3A/3B Horizontal U-tube 2 0

9 LP Feedwater Heater 

4A/4B Horizontal U-tube 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 1 0

11 HP Feedwater Heater 7 Horizontal U-tube 1 0

12 Auxiliary Boiler Shop fabricated, water 

tube 1 0

13 Fuel Oil System No. 2 fuel oil for light 

off 1 0

14 Service Air 

Compressors Flooded Screw 2 1

15 Instrument Air Dryers Duplex, regenerative 2 1

16 Closed Cycle Cooling 

Heat Exchangers Shell and tube 2 0

17 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 2 1

18 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine 1 1

19 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal 1 1

20 Raw Water Pumps Stainless steel, single 

suction 2 1

21 Filtered Water Pumps Stainless steel, single 

suction 2 1

22 Filtered Water Tank Vertical, cylindrical 1 0

23 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly, 

electrodeionization unit

1 1

24 Liquid Waste Treatment 

System -- 1 0

2,730,629 kg/h (6,020,000 lb/h)

2,730,629 kg/h (6,020,000 lb/h)

1,135,632 liter (300,000 gal)

Design Condition

1,639,096 liters (433,000 gal)

22,334 lpm @ 335 m H2O

(5,900 gpm @ 1,100 ft H2O)

2,730,629 kg/h (6,020,000 lb/h)

5 min. tank

3,785 lpm @ 88 m H2O

(1,000 gpm @ 290 ft H2O)

2,650 lpm @ 64 m H2O

(700 gpm @ 210 ft H2O)

29,602 lpm @ 43 m H2O

(7,820 gpm @ 140 ft H2O)

45,804 lpm @ 2,499 m H2O

(12,100 gpm @ 8,200 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C

(40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

662,246 kg/h (1,460,000 lb/h)

662,246 kg/h (1,460,000 lb/h)

662,246 kg/h (1,460,000 lb/h)

662,246 kg/h (1,460,000 lb/h)

2,377,257 liter (628,000 gal)

1,098 lpm (290 gpm)

10 years, 24-hour storm

2,461 lpm @ 49 m H2O

(650 gpm @ 160 ft H2O)

5 0

Startup Boiler Feed 

Pump, Electric Motor 

Driven

Barrel type, multistage, centrifugal13,628 lpm @ 2,499 m H2O

(3,600 gpm @ 8,200 ft H2O) 1

53 MMkJ/h (50 MMBtu/h) each

20,820 lpm @ 30 m H2O

(5,500 gpm @ 100 ft H2O)

28 m3/min (1,000 scfm)
Cost and Performance Comparison of Fossil Energy Power Plants 

 357 

ACCOUNT 4 BOILER AND ACCESSORIES 

Equipment 

No. Description Type OperatingQty. Spares

1 Boiler

Subcritical, drum 

wall-fired, low NOx 

burners, overfire air

1 0

2 Primary Air Fan Centrifugal 2 0

3 Forced Draft Fan Centrifugal 2 0

4 Induced Draft Fan Centrifugal 2 0

5 SCR Reactor Vessel Space for spare layer 2 0

6 SCR Catalyst -- 3 0

7 Dilution Air Blower Centrifugal 2 1

8 Ammonia Storage Horizontal tank 5 0

9 Ammonia Feed 

Pump Centrifugal 2 1

210 m3/min @ 108 cm WG

(7,400 acfm @ 42 in. WG)

230,912 liter (61,000 gal)

44 lpm @ 91 m H2O

(12 gpm @ 300 ft H2O)

1,762,662 kg/h, 37,427 m3/min @ 

90 cm WG (3,886,000 lb/h, 

1,321,700 acfm @ 36 in. WG)

3,524,417 kg/h (7,770,000 lb/h)

--

Design Condition

2,730,629 kg/h steam @ 16.5 

MPa/566°C/566°C 

(6,020,000 lb/h steam @ 2,400 

psig/1,050°F/1,050°F)

373,307 kg/h, 5,111 m3/min @ 

123 cm WG (823,000 lb/h, 

180,500 acfm @ 48 in. WG)

1,215,629 kg/h, 16,642 m3/min @ 

47 cm WG (2,680,000 lb/h, 

587,700 acfm @ 19 in. WG)
Cost and Performance Comparison of Fossil Energy Power Plants 

 358 

ACCOUNT 5 FLUE GAS CLEANUP 

Equipment 

No. Description Type OperatingQty. Spares

1 Fabric Filter

Single stage, highratio with pulsejet online cleaning 

system

2 0

2 Absorber Module Counter-current 

open spray

1 0

3 Recirculation Pumps Horizontal 

centrifugal 5 1

4 Bleed Pumps Horizontal 

centrifugal 2 1

5 Oxidation Air Blowers Centrifugal 2 1

6 Agitators Side entering 5 1

7 Dewatering Cyclones Radial assembly, 

5 units each 2 0

8 Vacuum Filter Belt Horizontal belt 2 1

9 Filtrate Water Return 

Pumps

Horizontal 

centrifugal 1 1

10 Filtrate Water Return 

Storage Tank Vertical, lined 1 0

11 Process Makeup Water 

Pumps

Horizontal 

centrifugal 1 1

278 m3/min @ 0.3 MPa

(9,800 acfm @ 42 psia)

50 tonne/h (55 tph)

50 wt % slurry

6,284 lpm (1,660 gpm) at 

20 wt% solids

50 hp

1,590 lpm (420 gpm) per cyclone

946 lpm @ 12 m H2O

(250 gpm @ 40 ft H2O)

643,525 lpm (170,000 gal)

3,861 lpm @ 21 m H2O

(1,020 gpm @ 70 ft H2O)

Design Condition

1,762,662 kg/h (3,886,000 lb/h) 

99.8% efficiency

59,607 m3/min (2,105,000 acfm)

208,199 lpm @ 64 m H2O

(55,000 gpm @ 210 ft H2O)

ACCOUNT 5B CARBON DIOXIDE RECOVERY 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Econamine FG 

Plus

Amine-based CO2 

capture technology 2 0

2 CO2 

Compressor

Integrally geared, 

multi-stage 

centrifugal

2 0

Design Condition

1,890,575 kg/h (4,168,000 lb/h) 

20.2 wt % CO2

inlet concentration

344,408 kg/h @ 15.3 MPa 

(759,289 lb/h @ 2,215 psia)
Cost and Performance Comparison of Fossil Energy Power Plants 

 359 

ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES 

 N/A 

ACCOUNT 7 HRSG, DUCTING & STACK 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Stack Reinforced concrete 

with FRP liner 1 0

Design Condition

152 m (500 ft) high x

6.1 m (20 ft) diameter

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitation 1 0

3 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1 0

800 MVA @ 0.9 p.f., 

24 kV, 60 Hz

Design Condition

720 MW 

16.5 MPa/566°C/566°C 

(2400 psig/ 

1050°F/1050°F)

2,551 MMkJ/h (2,420 

MMBtu/h), Inlet water 

temperature 16oC (60oF), 

Water temperature rise 

11oC (20oF)

ACCOUNT 9 COOLING WATER SYSTEM 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 4 2

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

1 0

Design Condition

704,092 lpm @ 30.5 m

(186,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

6,821 MMkJ/h (6,470 MMBtu/h) 

heat load
Cost and Performance Comparison of Fossil Energy Power Plants 

 360 

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING 

Equipment 

No. Description Type 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 -- 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 1 1

8 Ash Seal Water Pumps Vertical, wet pit 1 1

9 Hydrobins -- 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 -- 1 1

13 Fly Ash Silo Reinforced 

concrete

2 0

14 Slide Gate Valves -- 2 0

15 Unloader -- 1 0

16 Telescoping Unloading 

Chute -- 1 0

265 lpm (70 gpm)

--

--

--

--

23 m3/min @ 0.2 MPa

(810 scfm @ 24 psi)

771 tonne (1,700 ton)

136 tonne/h (150 tph)

--

--

265 lpm @ 17 m H2O

(70 gpm @ 56 ft H2O)

7,571 lpm @ 9 m H2O

(2000 gpm @ 28 ft H2O)

--

Design Condition

--

--

6.4 tonne/h (7 tph)
Cost and Performance Comparison of Fossil Energy Power Plants 

 361 

ACCOUNT 11 ACCESSORY ELECTRIC PLANT 

Equipment 

No. Description Type Operating Qty. Spares

1 STG Transformer Oil-filled 1 0

2 Auxiliary 

Transformer Oil-filled 1 1

3 Low Voltage 

Transformer Dry ventilated 1 1

4

STG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, self-cooled 1 0

5 Medium Voltage 

Switchgear Metal clad 1 1

6 Low Voltage 

Switchgear Metal enclosed 1 1

7 Emergency Diesel 

Generator

Sized for emergency 

shutdown 1 0

24 kV/4.16 kV, 140 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 21 MVA, 

3-ph, 60 Hz

Design Condition

24 kV/345 kV, 650 MVA, 

3-ph, 60 Hz

750 kW, 480 V, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz

ACCOUNT 12 INSTRUMENTATION AND CONTROL 

Equipment 

No. Description Type OperatingQty. 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

2 DCS - Processor

Microprocessor with 

redundant 

input/output

N/A 1 0

Fully redundant, 25% spare
Cost and Performance Comparison of Fossil Energy Power Plants 

 362 

4.2.10 CASE 10 – COST ESTIMATING

The cost estimating methodology was described previously in Section 2.6. Exhibit 4-22 shows 

the total plant capital cost summary organized by cost account and Exhibit 4-23 shows a more 

detailed breakdown of the capital costs. Exhibit 4-24 shows the initial and annual O&M costs. 

The estimated TPC of the subcritical PC boiler with CO2 capture is $2,888/kW. Process 

contingency represents 3.6 percent of the TPC and project contingency represents 12.6 percent. 

The 20-year LCOE, including CO2 TS&M costs of 4.3 mills/kWh, is 118.8 mills/kWh. 
Cost and Performance Comparison of F

 363 

Exhibit 4-22 Case 10 Total Plant Cost Summary 

Client: USDOE/NETL Report D

Project: Bituminous Baseline Study

Case: Case 10 - Subcritical PC w/ CO2

Plant Size: 549.6 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Projec

 1 COAL & SORBENT HANDLING $20,525 $5,540 $12,420 $0 $0 $38,485 $3,449 $0 $6

 2 COAL & SORBENT PREP & FEED $13,990 $807 $3,544 $0 $0 $18,342 $1,608 $0 $2

 3 FEEDWATER & MISC. BOP SYSTEMS $53,307 $0 $25,510 $0 $0 $78,817 $7,217 $0 $14

 4 PC BOILER

4.1 PC Boiler & Accessories $167,758 $0 $108,417 $0 $0 $276,176 $26,774 $0 $30

4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 

4.3 Open $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 

SUBTOTAL 4 $167,758 $0 $108,417 $0 $0 $276,176 $26,774 $0 $30

 5 FLUE GAS CLEANUP $109,618 $0 $37,721 $0 $0 $147,340 $14,000 $0 $16

 5B CO2 REMOVAL & COMPRESSION $243,432 $0 $74,100 $0 $0 $317,532 $30,138 $56,039 $80

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 

6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 6 $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 

7.2-7.9 HRSG Accessories, Ductwork and Stack $19,363 $1,062 $13,228 $0 $0 $33,653 $3,074 $0 $4

SUBTOTAL 7 $19,363 $1,062 $13,228 $0 $0 $33,653 $3,074 $0 $4

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $52,758 $0 $6,989 $0 $0 $59,747 $5,720 $0 $6

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $26,773 $1,170 $15,006 $0 $0 $42,949 $3,737 $0 $6

SUBTOTAL 8 $79,532 $1,170 $21,995 $0 $0 $102,697 $9,457 $0 $13

 9 COOLING WATER SYSTEM $21,405 $11,272 $20,092 $0 $0 $52,768 $4,916 $0 $7

10 ASH/SPENT SORBENT HANDLING SYS $5,440 $171 $7,234 $0 $0 $12,844 $1,223 $0 $1

11 ACCESSORY ELECTRIC PLANT $20,789 $10,729 $30,669 $0 $0 $62,187 $5,554 $0 $8

12 INSTRUMENTATION & CONTROL $9,150 $0 $9,615 $0 $0 $18,765 $1,718 $938 $2

13 IMPROVEMENTS TO SITE $3,201 $1,840 $6,500 $0 $0 $11,541 $1,133 $0 $2

14 BUILDINGS & STRUCTURES $0 $24,892 $23,781 $0 $0 $48,672 $4,385 $0 $7

TOTAL COST $767,510 $57,483 $394,827 $0 $0 $1,219,819 $114,645 $56,977 $199

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 364 

Exhibit 4-23 Case 10 Total Plant Cost Details 

Client: USDOE/NETL Report 

Project: Bituminous Baseline Study

Case: Case 10 - Subcritical PC w/ CO2

Plant Size: 549.6 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenci

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $4,213 $0 $1,944 $0 $0 $6,158 $550 $0 1.2 Coal Stackout & Reclaim $5,445 $0 $1,246 $0 $0 $6,692 $586 $0 1.3 Coal Conveyors $5,062 $0 $1,233 $0 $0 $6,296 $552 $0 1.4 Other Coal Handling $1,324 $0 $285 $0 $0 $1,610 $141 $0 1.5 Sorbent Receive & Unload $170 $0 $52 $0 $0 $221 $20 $0 1.6 Sorbent Stackout & Reclaim $2,741 $0 $508 $0 $0 $3,249 $283 $0 1.7 Sorbent Conveyors $978 $210 $242 $0 $0 $1,431 $124 $0 1.8 Other Sorbent Handling $591 $138 $313 $0 $0 $1,042 $92 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $5,192 $6,596 $0 $0 $11,787 $1,102 $0 

SUBTOTAL 1. $20,525 $5,540 $12,420 $0 $0 $38,485 $3,449 $0 

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $2,458 $0 $484 $0 $0 $2,942 $257 $0 2.2 Coal Conveyor to Storage $6,292 $0 $1,388 $0 $0 $7,680 $672 $0 2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $4,677 $201 $981 $0 $0 $5,859 $510 $0 2.6 Sorbent Storage & Feed $563 $0 $218 $0 $0 $782 $69 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $607 $473 $0 $0 $1,080 $99 $0 

SUBTOTAL 2. $13,990 $807 $3,544 $0 $0 $18,342 $1,608 $0 

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 FeedwaterSystem $20,059 $0 $7,016 $0 $0 $27,075 $2,376 $0 3.2 Water Makeup & Pretreating $8,410 $0 $2,704 $0 $0 $11,114 $1,042 $0 3.3 Other Feedwater Subsystems $6,624 $0 $2,810 $0 $0 $9,434 $841 $0 3.4 Service Water Systems $1,660 $0 $896 $0 $0 $2,556 $237 $0 3.5 Other Boiler Plant Systems $7,807 $0 $7,637 $0 $0 $15,444 $1,449 $0 3.6 FO Supply Sys & Nat Gas $271 $0 $333 $0 $0 $605 $56 $0 3.7 Waste Treatment Equipment $5,668 $0 $3,247 $0 $0 $8,915 $864 $0 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,808 $0 $865 $0 $0 $3,674 $353 $0 

SUBTOTAL 3. $53,307 $0 $25,510 $0 $0 $78,817 $7,217 $0 $

 4 PC BOILER

4.1 PC Boiler & Accessories $167,758 $0 $108,417 $0 $0 $276,176 $26,774 $0 $4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 4.4 Boiler BoP (w/ ID Fans) $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 4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 

SUBTOTAL 4. $167,758 $0 $108,417 $0 $0 $276,176 $26,774 $0 $

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 365 

Exhibit 4-23 Case 10 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Report Date: 

Project: Bituminous Baseline Study

Case: Case 10 - Subcritical PC w/ CO2

Plant Size: 549.6 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project 

 5 FLUE GAS CLEANUP

5.1 Absorber Vessels & Accessories $75,926 $0 $16,357 $0 $0 $92,284 $8,734 $0 $10,105.2 Other FGD $3,962 $0 $4,493 $0 $0 $8,456 $815 $0 $925.3 Bag House & Accessories $22,462 $0 $14,266 $0 $0 $36,728 $3,513 $0 $4,025.4 Other Particulate Removal Materials $1,520 $0 $1,628 $0 $0 $3,148 $303 $0 $345.5 Gypsum Dewatering System $5,747 $0 $977 $0 $0 $6,724 $635 $0 $735.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $

SUBTOTAL 5. $109,618 $0 $37,721 $0 $0 $147,340 $14,000 $0 $16,13

 5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $214,986 $0 $65,208 $0 $0 $280,194 $26,593 $56,039 $72,56

5B.2 CO2 Compression & Drying $28,446 $0 $8,892 $0 $0 $37,338 $3,545 $0 $8,17

SUBTOTAL 5B. $243,432 $0 $74,100 $0 $0 $317,532 $30,138 $56,039 $80,74

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $

SUBTOTAL 6. $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 $7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $7.3 Ductwork $10,045 $0 $6,556 $0 $0 $16,601 $1,450 $0 $2,707.4 Stack $9,318 $0 $5,457 $0 $0 $14,775 $1,412 $0 $1,61

7.9 Duct & Stack Foundations $0 $1,062 $1,215 $0 $0 $2,278 $212 $0 $49

SUBTOTAL 7. $19,363 $1,062 $13,228 $0 $0 $33,653 $3,074 $0 $4,82

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $52,758 $0 $6,989 $0 $0 $59,747 $5,720 $0 $6,548.2 Turbine Plant Auxiliaries $375 $0 $804 $0 $0 $1,179 $114 $0 $128.3 Condenser & Auxiliaries $6,425 $0 $2,475 $0 $0 $8,900 $847 $0 $978.4 Steam Piping $19,973 $0 $9,866 $0 $0 $29,839 $2,490 $0 $4,848.9 TG Foundations $0 $1,170 $1,861 $0 $0 $3,031 $285 $0 $66

SUBTOTAL 8. $79,532 $1,170 $21,995 $0 $0 $102,697 $9,457 $0 $13,16

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $14,689 $0 $4,810 $0 $0 $19,499 $1,852 $0 $2,139.2 Circulating Water Pumps $4,326 $0 $310 $0 $0 $4,636 $397 $0 $509.3 Circ.Water System Auxiliaries $912 $0 $122 $0 $0 $1,034 $98 $0 $119.4 Circ.Water Piping $0 $7,355 $7,015 $0 $0 $14,370 $1,324 $0 $2,359.5 Make-up Water System $749 $0 $993 $0 $0 $1,742 $165 $0 $289.6 Component Cooling Water Sys $728 $0 $575 $0 $0 $1,304 $122 $0 $219.9 Circ.Water System Foundations& Structures $0 $3,917 $6,267 $0 $0 $10,185 $959 $0 $2,22

SUBTOTAL 9. $21,405 $11,272 $20,092 $0 $0 $52,768 $4,916 $0 $7,83

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $10.6 Ash Storage Silos $723 $0 $2,231 $0 $0 $2,954 $288 $0 $3210.7 Ash Transport & Feed Equipment $4,716 $0 $4,801 $0 $0 $9,517 $900 $0 $1,0410.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $10.9 Ash/Spent Sorbent Foundation $0 $171 $203 $0 $0 $373 $35 $0 $8

SUBTOTAL 10. $5,440 $171 $7,234 $0 $0 $12,844 $1,223 $0 $1,44

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 366 

Exhibit 4-23 Case 10 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Repor

Project: Bituminous Baseline Study

Case: Case 10 - Subcritical PC w/ CO2

Plant Size: 549.6 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenci

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $1,672 $0 $274 $0 $0 $1,946 $180 $0 11.2 Station Service Equipment $4,842 $0 $1,658 $0 $0 $6,499 $622 $0 11.3 Switchgear & Motor Control $5,754 $0 $986 $0 $0 $6,740 $624 $0 11.4 Conduit & Cable Tray $0 $3,695 $12,573 $0 $0 $16,268 $1,557 $0 11.5 Wire & Cable $0 $6,702 $13,245 $0 $0 $19,947 $1,681 $0 11.6 Protective Equipment $253 $0 $898 $0 $0 $1,152 $113 $0 11.7 Standby Equipment $1,268 $0 $30 $0 $0 $1,298 $123 $0 11.8 Main Power Transformers $7,000 $0 $185 $0 $0 $7,185 $546 $0 11.9 Electrical Foundations $0 $332 $821 $0 $0 $1,153 $110 $0 

SUBTOTAL 11. $20,789 $10,729 $30,669 $0 $0 $62,187 $5,554 $0 

12 INSTRUMENTATION & CONTROL

12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 12.4 Other Major Component Control $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 12.6 Control Boards,Panels & Racks $469 $0 $292 $0 $0 $761 $73 $38 12.7 Distributed Control System Equipment $4,731 $0 $861 $0 $0 $5,592 $533 $280 12.8 Instrument Wiring & Tubing $2,613 $0 $5,301 $0 $0 $7,914 $674 $396 12.9 Other I & C Equipment $1,337 $0 $3,161 $0 $0 $4,498 $438 $225 

SUBTOTAL 12. $9,150 $0 $9,615 $0 $0 $18,765 $1,718 $938 

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $54 $1,084 $0 $0 $1,138 $112 $0 13.2 Site Improvements $0 $1,786 $2,235 $0 $0 $4,022 $395 $0 13.3 Site Facilities $3,201 $0 $3,181 $0 $0 $6,382 $626 $0 

SUBTOTAL 13. $3,201 $1,840 $6,500 $0 $0 $11,541 $1,133 $0 

14 BUILDINGS & STRUCTURES

14.1 Boiler Building $0 $8,723 $7,774 $0 $0 $16,497 $1,481 $0 14.2 Turbine Building $0 $12,815 $12,103 $0 $0 $24,918 $2,244 $0 14.3 Administration Building $0 $613 $657 $0 $0 $1,270 $115 $0 14.4 Circulation Water Pumphouse $0 $281 $227 $0 $0 $508 $45 $0 14.5 Water Treatment Buildings $0 $1,110 $926 $0 $0 $2,036 $182 $0 14.6 Machine Shop $0 $410 $279 $0 $0 $689 $61 $0 14.7 Warehouse $0 $278 $282 $0 $0 $560 $51 $0 14.8 Other Buildings & Structures $0 $227 $196 $0 $0 $423 $38 $0 14.9 Waste Treating Building & Str. $0 $435 $1,336 $0 $0 $1,771 $167 $0 

SUBTOTAL 14. $0 $24,892 $23,781 $0 $0 $48,672 $4,385 $0 

TOTAL COST $767,510 $57,483 $394,827 $0 $0 $1,219,819 $114,645 $56,977 $1

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of Fossil Energy Power Plants 

367 

Exhibit 4-24 Case 10 Initial and Annual Operating and Maintenance Costs 

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006

Case 10 - Subcritical PC w/ CO2 Heat Rate-net(Btu/kWh): 13,724

 MWe-net: 550

 Capacity Factor: (%): 85

 OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 33.00 $/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 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 $6,138,007 $11.168

Maintenance Labor Cost $10,295,213 $18.732

Administrative & Support Labor $4,108,305 $7.475

TOTAL FIXED OPERATING COSTS $20,541,525 $37.375

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $15,442,820 $0.00377

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

 Water(/1000 gallons) 0 10,151 1.03 $0 $3,243,688 $0.00079

 Chemicals

 MU & WT Chem.(lb) 343,946 49,135 0.16 $56,682 $2,512,244 $0.00061

 Limestone (ton) 5,372 767 20.60 $110,669 $4,905,029 $0.00120

 Carbon (Mercury Removal) (lb) 0 0 0.00 $0 $0 $0.00000

 MEA Solvent (ton) 1,174 1.67 2,142.40 $2,515,178 $1,108,686 $0.00027

 NaOH (tons) 82 8.18 412.96 $33,863 $1,048,541 $0.00026

 H2SO4 (tons) 79 7.91 132.15 $10,440 $324,224 $0.00008

 Corrosion Inhibitor 0 0 0.00 $162,300 $7,730 $0.00000

 Activated Carbon(lb) 0 1,992 1.00 $0 $618,018 $0.00015

 Ammonia (28% NH3) ton 813 116 123.60 $100,439 $4,451,615 $0.00109

Subtotal Chemicals $2,989,571 $14,976,086 $0.00366

 Other

 Supplemental Fuel(MBtu) 0 0 0.00 $0 $0 $0.00000

 SCR Catalyst(m3) w/equip. 0.68 5,500.00 $0 $1,168,014 $0.00029

 Emission Penalties 0 0 0.00 $0 $0 $0.00000

Subtotal Other $0 $1,168,014 $0.00029

 Waste Disposal

 Flyash (ton) 0 144 15.45 $0 $690,819 $0.00017

 Bottom Ash(ton) 0 577 15.45 $0 $2,763,393 $0.00068

 Subtotal-Waste Disposal $0 $3,454,212 $0.00084

 By-products & Emissions 

 Gypsum (tons) 0 1,196 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $2,989,571 $38,284,819 $0.00936

 Fuel(ton) 232,764 7,759 42.11 $9,801,707 $101,365,989 $0.02477
Cost and Performance Comparison of Fossil Energy Power Plants 

368 

4.3 SUPERCRITICAL PC CASES 

This section contains an evalution of plant designs for Cases 11 and 12 which are based on a 

supercritical PC plant with a nominal net output of 550 MWe. Both plants use a single reheat 

24.1 MPa/593°C/593°C (3500 psig/1100°F/1100°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 subcrtical 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 PROCESS DESCRIPTION

In this section the supercritical 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 block flow diagram (BFD) in Exhibit 4-25 and 

stream numbers reference the same Exhibit. The tables in Exhibit 4-26 provide process data for 

the numbered streams in the BFD. 

Coal (stream 6) and primary air (stream 4) are introduced into the boiler through the wall-fired 

burners. Additional combustion air, including the overfire air, is provided by the forced draft 

fans (stream 2). 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. 

Flue gas exits the boiler through the SCR reactor (stream 8) and is cooled to 177°C (350°F) in 

the combustion air preheater (not shown) before passing through a fabric filter for particulate 

removal (stream 10). An ID fan increases the flue gas temperature to 188°C (370°F) and 

provides the motive force for the flue gas (stream 11) to pass through the FGD unit. FGD inputs 

and outputs include makeup water (stream 13), oxidation air (stream 14), limestone slurry 

(stream 12) and product gypsum (stream 15). The clean, saturated flue gas exiting the FGD unit 

(stream 16) passes to the plant stack and is discharged to atmosphere 
Cost and Performance Comparison of F

369 

Exhibit 4-25 Case 11 Process Flow Diagram, Supercritical Unit without CO2 Capture 
Cost and Performance Comparison of Fossil Energy Power Plants 

 370 

Exhibit 4-26 Case 11 Stream Table, Supercritical Unit without CO2 Capture 

1 2 3 4 567 8

V-L Mole Fractions 

 Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087

 CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450

 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

 H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870

 N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324

 O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247

 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000

V-L Flow (lbmol/hr) 107,211 107,211 32,934 32,934 2,477 0 0 150,861

V-L Flow (lb/hr) 3,093,780 3,093,780 950,376 950,376 71,480 0 0 4,487,030

Solids Flowrate 0 0 0 0 0 411,282 7,976 31,905

Temperature (°F) 59 66 59 78 59 59 350 350

Pressure (psia) 14.70 15.25 14.70 16.14 14.70 14.70 14.40 14.40

Enthalpy (BTU/lb)A 13.1 14.9 13.1 17.7 13.1 11,676 51.4 135.6

Density (lb/ft3

) 0.08 0.08 0.08 0.08 0.08 --- --- 0.05

Avg. Molecular Weight 28.86 28.86 28.86 28.86 28.86 --- --- 29.74

9 10 11 12 13 14 15 16

V-L Mole Fractions 

 Ar 0.0000 0.0087 0.0087 0.0000 0.0000 0.0092 0.0000 0.0080

 CO2 0.0000 0.1450 0.1450 0.0000 0.0000 0.0003 0.0016 0.1326

 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

 H2O 0.0000 0.0870 0.0870 1.0000 1.0000 0.0099 0.9976 0.1669

 N2 0.0000 0.7324 0.7324 0.0000 0.0000 0.7732 0.0008 0.6690

 O2 0.0000 0.0247 0.0247 0.0000 0.0000 0.2074 0.0000 0.0235

 SO2 0.0000 0.0021 0.0021 0.0000 0.0000 0.0000 0.0000 0.0000

Total 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flow (lbmol/hr) 0 150,861 150,861 5,111 24,381 1,705 14,140 167,129

V-L Flow (lb/hr) 0 4,487,030 4,487,030 92,067 439,223 49,200 255,432 4,789,380

Solids Flowrate 31,905 0 0 40,819 0 0 63,529 0

Temperature (°F) 350 350 370 59 60 59 134 134

Pressure (psia) 14.20 14.20 15.26 14.70 14.70 14.70 14.70 14.70

Enthalpy (BTU/lb)A 51.4 136.2 141.5 --- 33.3 13.1 87.0 139.1

Density (lb/ft3

) --- 0.05 0.05 62.62 62.59 0.08 36.10 0.07

Avg. Molecular Weight --- 29.74 29.74 18.02 18.02 28.86 18.06 28.66

A - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of Fossil Energy Power Plants 

 371 

4.3.2 KEY SYSTEM ASSUMPTIONS

System assumptions for Cases 11 and 12, supercritical PC with and without CO2 capture, are 

compiled in Exhibit 4-27. 

Exhibit 4-27 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, % 89 89 

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 FG Plus 

CO2 Capture, % (A) N/A 90 

CO2 Sequestration N/A Off-site Saline 

Formation 

A. Removal efficiencies are based on the flue gas content 

B. An SO2 polishing step is included to meet more stringent SOx content limits in 

the flue gas (< 10 ppmv) to reduce formation of amine heat stable salts during 

the CO2 absorption process 

C. SO2 exiting the post-FGD polishing step is absorbed in the CO2 capture process 

making stack emissions negligible 
Cost and Performance Comparison of Fossil Energy Power Plants 

 372 

Balance of Plant – Cases 11 and 12 

The balance of plant assumptions are common to all cases and were presented previously in 

Exhibit 4-6. 

4.3.3 SPARING PHILOSOPHY

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: 

• One dry-bottom, wall-fired PC supercritical 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 FG Plus CO2 absorption systems, with each 

system consisting of two absorbers, strippers and ancillary equipment (2 x 50%) 

4.3.4 CASE 11 PERFORMANCE RESULTS

The plant produces a net output of 550 MWe at a net plant efficiency of 39.1 percent (HHV 

basis). 

Overall performance for the plant is summarized in Exhibit 4-28 which includes auxiliary power 

requirements. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 373 

Exhibit 4-28 Case 11 Plant Performance Summary 

POWER SUMMARY (Gross Power at Generator Terminals, kWe) 

TOTAL (STEAM TURBINE) POWER, kWe 580,260 

AUXILIARY LOAD SUMMARY, kWe (Note 1) 

Coal Handling and Conveying 410 

Limestone Handling & Reagent Preparation 890 

Pulverizers 2,800 

Ash Handling 530 

Primary Air Fans 1,310 

Forced Draft Fans 1,660 

Induced Draft Fans 7,130 

SCR 50 

Baghouse 100 

FGD Pumps and Agitators 2,980 

Econamine FG Plus Auxiliaries N/A 

CO2 Compression N/A 

Miscellaneous Balance of Plant (Note 2) 2,000 

Steam Turbine Auxiliaries 400 

Condensate Pumps 790 

Circulating Water Pumps 4,770 

Cooling Tower Fans 2,460 

Transformer Loss 1,830 

TOTAL AUXILIARIES, kWe 30,110 

NET POWER, kWe 550,150 

Net Plant Efficiency (HHV) 39.1% 

Net Plant Heat Rate (Btu/kWh) 8,721 

CONDENSER COOLING DUTY, 106 kJ/h (106 Btu/h) 2,314 (2,195) 

CONSUMABLES 

As-Received Coal Feed, kg/h (lb/h) 186,555 (411,282) 

Limestone Sorbent Feed, kg/h (lb/h) 18,515 (40,819) 

Thermal Input, kWt 1,406,161 

Makeup Water, m3/min (gpm) 20.6 (5,441) 

Notes: 1. Boiler feed pumps are steam turbine driven 

 2. Includes plant control systems, lighting, HVAC and miscellanous low voltage loads 
Cost and Performance Comparison of Fossil Energy Power Plants 

 374 

Environmental Performance 

The environmental targets for emissions of Hg, NOx, SO2 and particulate matter were presented 

in Section 2.4. A summary of the plant air emissions for Case 11 is presented in Exhibit 4-29. 

Exhibit 4-29 Case 11 Air Emissions 

kg/GJ 

(lb/106 Btu) 

Tonne/year 

(ton/year) 

85% capacity factor 

kg/MWh 

(lb/MWh) 

SO2 0.036 (0.085) 1,373 (1,514) 0.318 (0.701) 

NOX 0.030 (0.070) 1,134 (1,250) 0.263 (0.579) 

Particulates 0.006 (0.013) 211 (232) 0.049 (0.107) 

Hg 0.49 x 10-6

(1.14 x 10-6) 0.018 (0.020) 4.3 x 10-6 (9.4 x 10-6) 

CO2 87.5 (203) 3,295,000 

(3,632,000) 763 (1,681) 

CO2

1 804 (1,773) 

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 flue gas 

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. 

Exhibit 4-30 shows the overall water balance for the plant. Raw water is obtained from 

groundwater (50 percent) and from municipal sources (50 percent). The water usage represents 

only the contribution of raw water makeup. In some cases the water demand is greater than raw 

water makeup because of internal water recycle streams. For example, the boiler feedwater 

blowdown stream is re-used as makeup to the cooling tower, thus reducing the raw water 

requirement by that amount. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 375 

Exhibit 4-30 Case 11 Water Balance 

Water Use Water Demand, 

m3/min (gpm) 

Internal Recycle, 

m3/min (gpm) 

Raw Water Makeup, 

m3/min (gpm) 

FGD Makeup 2.1 (546) 0 2.1 (546) 

BFW Makeup 0.3 (73) 0 0.3 (73) 

Cooling Tower Makeup 18.5 (4,895) 0.3 (73) 18.2 (4,822) 

Total 20.9 (5,514) 0.3 (73) 20.6 (5,441) 

Heat and Mass Balance Diagrams 

A heat and mass balance diagram is shown for the Case 11 PC boiler, the FGD unit and steam 

cycle in Exhibit 4-31. 

An overall plant energy balance is provided in tabular form in Exhibit 4-32. The power out is 

the steam turbine power prior to generator losses. The power at the generator terminals (shown 

in Exhibit 4-28) is calculated by multiplying the power out by a generator efficiency of 98.4 

percent. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 376 

This page intentionally left blank 
377 

Exhibit 4-31 Case 11 Heat and Mass Balance, Supercritical PC Boiler without CO
378 

This page intentionally left blank 
Cost and Performance Comparison of Fossil Energy Power Plants 

 379 

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

HHV Sensible + Latent Power Total 

Heat In (MMBtu/hr) 

Coal 4,798.0 4.0 4,802.0 

Ambient Air 53.1 53.1 

Infiltration Air 0.9 0.9 

Limestone 0.2 0.2 

FGD Oxidant 0.6 0.6 

Water 17.6 17.6 

Auxiliary Power 102.0 102.0 

Totals 4,798.0 76.5 102.0 4,976.5 

Heat Out (MMBtu/hr) 

Bottom Ash 0.4 0.4 

Fly Ash 1.6 1.6 

Flue Gas Exhaust 666.1 666.1 

Gypsum Slurry 27.7 27.7 

Condenser 2,195.0 2,195.0 

Process Losses (1) 74.3 74.3 

Power 2,011.4 2,011.4 

Totals 0.0 2,965.1 2,011.4 4,976.5 

(1) 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 Comparison of Fossil Energy Power Plants 

 380 

4.3.5 CASE 11 – MAJOR EQUIPMENT LIST 

Major equipment items for the supercritical 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 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 Operating Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0

3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0

5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling 

System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0

8 Reclaim Hopper N/A 2 1

9 Feeder Vibratory 2 1

10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor 

reduction 2 0

14 As-Fired Coal Sampling 

System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0

17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 3 0

19 Limestone Truck Unloading 

Hopper N/A 1 0

20 Limestone Feeder Belt 1 0

21 Limestone Conveyor No. L1 Belt 1 0

22 Limestone Reclaim Hopper N/A 1 0

23 Limestone Reclaim Feeder Belt 1 0

24 Limestone Conveyor No. L2 Belt 1 0

25 Limestone Day Bin w/ actuator 2 0

36 tonne (40 ton)

82 tonne/h (90 tph)

82 tonne/h (90 tph)

245 tonne (270 ton)

18 tonne (20 ton)

64 tonne/h (70 tph)

64 tonne/h (70 tph)

726 tonne (800 ton)

N/A

308 tonne/h (340 tph)

N/A

36 tonne (40 ton)

154 tonne/h (170 tph)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

308 tonne/h (340 tph)

154 tonne (170 ton)

N/A

308 tonne/h (340 tph)

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph)

N/A

1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)

1,134 tonne/h (1,250 tph)
Cost and Performance Comparison of Fossil Energy Power Plants 

 381 

ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Coal Feeder Gravimetric 6 0

2 Coal Pulverizer Ball type or 

equivalent 6 0

3 Limestone Weigh Feeder Gravimetric 1 1

4 Limestone Ball Mill Rotary 1 1

5 Limestone Mill Slurry Tank 

with Agitator N/A 1 1

6 Limestone Mill Recycle 

Pumps

Horizontal 

centrifugal 1 1

7 Hydroclone Classifier

4 active 

cyclones in a 5 

cyclone bank

1 1

8 Distribution Box 2-way 1 1

9 Limestone Slurry Storage 

Tank with Agitator Field erected 1 1

10 Limestone Slurry Feed 

Pumps

Horizontal 

centrifugal 1 1

439,111 liters (116,000 gal)

308 lpm @ 12m H2O

(340 gpm @ 40 ft H2O)

N/A

218 lpm @ 9m H2O

(240 gpm @ 30 ft H2O)

82 lpm (90 gpm) per cyclone

75,709 liters (20,000 gal)

Design Condition

36 tonne/h (40 tph)

36 tonne/h (40 tph)

20 tonne/h (22 tph)

20 tonne/h (22 tph)
Cost and Performance Comparison of Fossil Energy Power Plants 

 382 

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 1 1

3 Deaerator and Storage 

Tank Horizontal spray type 1 0

4 Boiler Feed Pump and 

Steam Turbine Drive

Barrel type, multistage, centrifugal 1 1

6 LP Feedwater Heater 

1A/1B Horizontal U-tube 2 0

7 LP Feedwater Heater 

2A/2B Horizontal U-tube 2 0

8 LP Feedwater Heater 

3A/3B Horizontal U-tube 2 0

9 LP Feedwater Heater 

4A/4B Horizontal U-tube 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 1 0

11 HP Feedwater Heater 7 Horizontal U-tube 1 0

12 HP Feedwater heater 8 Horizontal U-tube 1 0

13 Auxiliary Boiler Shop fabricated, water 

tube 1 0

14 Fuel Oil System No. 2 fuel oil for light 

off 1 0

15 Service Air 

Compressors Flooded Screw 2 1

16 Instrument Air Dryers Duplex, regenerative 2 1

17 Closed Cycle Cooling 

Heat Exchangers Shell and tube 2 0

18 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 2 1

19 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine 1 1

20 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal 1 1

21 Raw Water Pumps Stainless steel, single 

suction 2 1

22 Filtered Water Pumps Stainless steel, single 

suction 2 1

23 Filtered Water Tank Vertical, cylindrical 1 0

24 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly, 

electrodeionization unit

1 1

25 Liquid Waste Treatment 

System -- 1 0

Design Condition

1,097,778 liters (290,000 gal)

23,091 lpm @ 213 m H2O

(6,100 gpm @ 700 ft H2O)

1,828,433 kg/h (4,031,000 lb/h)

5 min. tank

30,662 lpm @ 3,475 m H2O

(8,100 gpm @ 11,400 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C

(40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

689,461 kg/h (1,520,000 lb/h)

689,461 kg/h (1,520,000 lb/h)

689,461 kg/h (1,520,000 lb/h)

689,461 kg/h (1,520,000 lb/h)

1,827,979 kg/h (4,030,000 lb/h)

1,827,979 kg/h (4,030,000 lb/h)

1,135,632 liter (300,000 gal)

1,377,901 liter (364,000 gal)

606 lpm (160 gpm)

10 years, 24-hour storm

1,438 lpm @ 49 m H2O

(380 gpm @ 160 ft H2O)

5 0

Startup Boiler Feed 

Pump, Electric Motor 

Driven

Barrel type, multistage, centrifugal9,085 lpm @ 3,475 m H2O

(2,400 gpm @ 11,400 ft H2O) 1

53 MMkJ/h (50 MMBtu/h) each

20,820 lpm @ 30 m H2O

(5,500 gpm @ 100 ft H2O)

1,827,979 kg/h (4,030,000 lb/h)

28 m3/min (1,000 scfm)

3,785 lpm @ 88 m H2O

(1,000 gpm @ 290 ft H2O)

2,650 lpm @ 64 m H2O

(700 gpm @ 210 ft H2O)

11,470 lpm @ 43 m H2O

(3,030 gpm @ 140 ft H2O)
Cost and Performance Comparison of Fossil Energy Power Plants 

 383 

ACCOUNT 4 BOILER AND ACCESSORIES 

Equipment 

No. Description Type OperatingQty. Spares

1 Boiler

Supercritical, drum, 

wall-fired, low NOx 

burners, overfire air

1 0

2 Primary Air Fan Centrifugal 2 0

3 Forced Draft Fan Centrifugal 2 0

4 Induced Draft Fan Centrifugal 2 0

5 SCR Reactor Vessel Space for spare layer 2 0

6 SCR Catalyst -- 3 0

7 Dilution Air Blower Centrifugal 2 1

8 Ammonia Storage Horizontal tank 5 0

9 Ammonia Feed 

Pump Centrifugal 2 1

133 m3/min @ 108 cm WG

(4,700 acfm @ 42 in. WG)

147,632 liter (39,000 gal)

28 lpm @ 91 m H2O

(7 gpm @ 300 ft H2O)

1,119,467 kg/h, 23,769 m3/min @ 

90 cm WG (2,468,000 lb/h, 

839,400 acfm @ 36 in. WG)

2,240,749 kg/h (4,940,000 lb/h)

--

Design Condition

1,827,979 kg/h steam @ 24.1 

MPa/593°C/593°C 

(4,030,000 lb/h steam @ 3,500 

psig/1,100°F/1,100°F)

237,229 kg/h, 3,245 m3/min @ 

123 cm WG (523,000 lb/h, 

114,600 acfm @ 48 in. WG)

772,015 kg/h, 10,568 m3/min @ 

47 cm WG (1,702,000 lb/h, 

373,200 acfm @ 19 in. WG)
Cost and Performance Comparison of Fossil Energy Power Plants 

 384 

ACCOUNT 5 FLUE GAS CLEANUP 

Equipment 

No. Description Type OperatingQty. Spares

1 Fabric Filter

Single stage, highratio with pulsejet online cleaning 

system

2 0

2 Absorber Module Counter-current 

open spray

1 0

3 Recirculation Pumps Horizontal 

centrifugal 5 1

4 Bleed Pumps Horizontal 

centrifugal 2 1

5 Oxidation Air Blowers Centrifugal 2 1

6 Agitators Side entering 5 1

7 Dewatering Cyclones Radial assembly, 

5 units each 2 0

8 Vacuum Filter Belt Horizontal belt 2 1

9 Filtrate Water Return 

Pumps

Horizontal 

centrifugal 1 1

10 Filtrate Water Return 

Storage Tank Vertical, lined 1 0

11 Process Makeup Water 

Pumps

Horizontal 

centrifugal 1 1

168 m3/min @ 0.3 MPa

(5,930 acfm @ 42 psia)

32 tonne/h (35 tph)

50 wt % slurry

4,013 lpm (1,060 gpm) at 

20 wt% solids

50 hp

1,022 lpm (270 gpm) per cyclone

606 lpm @ 12 m H2O

(160 gpm @ 40 ft H2O)

416,399 lpm (110,000 gal)

2,271 lpm @ 21 m H2O

(600 gpm @ 70 ft H2O)

Design Condition

1,119,467 kg/h (2,468,000 lb/h) 

99.8% efficiency

37,662 m3/min (1,330,000 acfm)

132,490 lpm @ 64 m H2O

(35,000 gpm @ 210 ft H2O)

ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES 

 N/A 

ACCOUNT 7 HRSG, DUCTING & STACK 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Stack Reinforced concrete 

with FRP liner 1 0

Design Condition

152 m (500 ft) high x

5.8 m (19 ft) diameter
Cost and Performance Comparison of Fossil Energy Power Plants 

 385 

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitation 1 0

3 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1 0

680 MVA @ 0.9 p.f., 

24 kV, 60 Hz

Design Condition

610 MW 

24.1 MPa/593°C/593°C 

(3500 psig/ 

1100°F/1100°F)

2,541 MMkJ/h (2,410 

MMBtu/h), Inlet water 

temperature 16oC (60oF), 

Water temperature rise 

11oC (20oF)

ACCOUNT 9 COOLING WATER SYSTEM 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

1 0

Design Condition

476,966 lpm @ 30.5 m

(126,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

2,657 MMkJ/h (2,520 MMBtu/h) 

heat load
Cost and Performance Comparison of Fossil Energy Power Plants 

 386 

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING 

Equipment 

No. Description Type 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 -- 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 1 1

8 Ash Seal Water Pumps Vertical, wet pit 1 1

9 Hydrobins -- 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 -- 1 1

13 Fly Ash Silo Reinforced 

concrete

2 0

14 Slide Gate Valves -- 2 0

15 Unloader -- 1 0

16 Telescoping Unloading 

Chute -- 1 0

151 lpm (40 gpm)

--

--

--

--

14 m3/min @ 0.2 MPa

(510 scfm @ 24 psi)

499 tonne (1,100 ton)

91 tonne/h (100 tph)

--

--

151 lpm @ 17 m H2O

(40 gpm @ 56 ft H2O)

7,571 lpm @ 9 m H2O

(2000 gpm @ 28 ft H2O)

--

Design Condition

--

--

3.6 tonne/h (4 tph)
Cost and Performance Comparison of Fossil Energy Power Plants 

 387 

ACCOUNT 11 ACCESSORY ELECTRIC PLANT 

Equipment 

No. Description Type Operating Qty. Spares

1 STG Transformer Oil-filled 1 0

2 Auxiliary 

Transformer Oil-filled 1 1

3 Low Voltage 

Transformer Dry ventilated 1 1

4

STG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, self-cooled 1 0

5 Medium Voltage 

Switchgear Metal clad 1 1

6 Low Voltage 

Switchgear Metal enclosed 1 1

7 Emergency Diesel 

Generator

Sized for emergency 

shutdown 1 0

24 kV/4.16 kV, 10 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 5 MVA, 

3-ph, 60 Hz

Design Condition

24 kV/345 kV, 640 MVA, 

3-ph, 60 Hz

750 kW, 480 V, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz

ACCOUNT 12 INSTRUMENTATION AND CONTROL 

Equipment 

No. Description Type OperatingQty. 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 Comparison of Fossil Energy Power Plants 

 388 

4.3.6 CASE 11 – COSTS ESTIMATING RESULTS

The cost estimating methodology was described previously in Section 2.6. Exhibit 4-33 shows 

the total plant capital cost summary organized by cost account and Exhibit 4-34 shows a more 

detailed breakdown of the capital costs. Exhibit 4-35 shows the initial and annual O&M costs. 

The estimated TPC of the supercritical PC boiler with no CO2 capture is $1,574/kW. No process 

contingency was included in this case because all elements of the technology are commercially 

proven. The project contingency is 10.7 percent of the TPC. The 20-year LCOE is 63.3 

mills/kWh. 
Cost and Performance Comparison of F

 389 

Exhibit 4-33 Case 11 Total Plant Cost Summary 

Client: USDOE/NETL Report 

Project: Bituminous Baseline Study

Case: Case 11 - Supercritical PC w/o CO2

Plant Size: 550.2 MW,net Estimate Type: Conceptual Cost Base (Dec) 200

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencie

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Proje

 1 COAL & SORBENT HANDLING $15,481 $4,183 $9,376 $0 $0 $29,040 $2,602 $0 $

 2 COAL & SORBENT PREP & FEED $10,405 $603 $2,638 $0 $0 $13,646 $1,196 $0 $

 3 FEEDWATER & MISC. BOP SYSTEMS $40,107 $0 $18,856 $0 $0 $58,963 $5,369 $0 $1

 4 PC BOILER

4.1 PC Boiler & Accessories $148,766 $0 $83,888 $0 $0 $232,654 $22,535 $0 $24.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 

4.3 Open $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 

SUBTOTAL 4 $148,766 $0 $83,888 $0 $0 $232,654 $22,535 $0 $2

 5 FLUE GAS CLEANUP $78,075 $0 $26,700 $0 $0 $104,775 $9,955 $0 $1

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 

6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 6 $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 

7.2-7.9 HRSG Accessories, Ductwork and Stack $16,653 $959 $11,402 $0 $0 $29,013 $2,656 $0 $

SUBTOTAL 7 $16,653 $959 $11,402 $0 $0 $29,013 $2,656 $0 $

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $48,728 $0 $6,532 $0 $0 $55,260 $5,291 $0 $

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $23,094 $1,042 $12,656 $0 $0 $36,792 $3,213 $0 $

SUBTOTAL 8 $71,822 $1,042 $19,188 $0 $0 $92,052 $8,504 $0 $1

 9 COOLING WATER SYSTEM $11,816 $6,553 $11,613 $0 $0 $29,981 $2,799 $0 $

10 ASH/SPENT SORBENT HANDLING SYS $4,232 $133 $5,628 $0 $0 $9,992 $951 $0 $

11 ACCESSORY ELECTRIC PLANT $15,533 $5,832 $17,190 $0 $0 $38,556 $3,411 $0 $

12 INSTRUMENTATION & CONTROL $8,069 $0 $8,480 $0 $0 $16,549 $1,515 $0 $

13 IMPROVEMENTS TO SITE $2,827 $1,625 $5,741 $0 $0 $10,194 $1,001 $0 $

14 BUILDINGS & STRUCTURES $0 $21,560 $20,672 $0 $0 $42,232 $3,805 $0 $

TOTAL COST $423,786 $42,490 $241,370 $0 $0 $707,646 $66,300 $0 $9

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 390 

Exhibit 4-34 Case 11 Total Plant Cost Details 

Client: USDOE/NETL Report 

Project: Bituminous Baseline Study

Case: Case 11 - Supercritical PC w/o CO2

Plant Size: 550.2 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenc

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Proj

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $3,183 $0 $1,469 $0 $0 $4,652 $415 $0 1.2 Coal Stackout & Reclaim $4,113 $0 $942 $0 $0 $5,055 $442 $0 1.3 Coal Conveyors $3,824 $0 $932 $0 $0 $4,756 $417 $0 1.4 Other Coal Handling $1,001 $0 $216 $0 $0 $1,216 $106 $0 1.5 Sorbent Receive & Unload $127 $0 $39 $0 $0 $166 $15 $0 1.6 Sorbent Stackout & Reclaim $2,056 $0 $381 $0 $0 $2,437 $212 $0 1.7 Sorbent Conveyors $734 $158 $182 $0 $0 $1,073 $93 $0 1.8 Other Sorbent Handling $443 $103 $235 $0 $0 $781 $69 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $3,922 $4,982 $0 $0 $8,904 $832 $0 $

SUBTOTAL 1. $15,481 $4,183 $9,376 $0 $0 $29,040 $2,602 $0 $

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $1,823 $0 $359 $0 $0 $2,182 $190 $0 2.2 Coal Conveyor to Storage $4,668 $0 $1,030 $0 $0 $5,698 $498 $0 2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $3,493 $150 $733 $0 $0 $4,376 $381 $0 2.6 Sorbent Storage & Feed $421 $0 $163 $0 $0 $584 $52 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $453 $353 $0 $0 $807 $74 $0 

SUBTOTAL 2. $10,405 $603 $2,638 $0 $0 $13,646 $1,196 $0 $

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 FeedwaterSystem $17,490 $0 $5,725 $0 $0 $23,214 $2,033 $0 $3.2 Water Makeup & Pretreating $4,278 $0 $1,376 $0 $0 $5,654 $530 $0 $3.3 Other Feedwater Subsystems $5,404 $0 $2,293 $0 $0 $7,697 $686 $0 $3.4 Service Water Systems $844 $0 $456 $0 $0 $1,300 $121 $0 3.5 Other Boiler Plant Systems $6,403 $0 $6,264 $0 $0 $12,667 $1,188 $0 $3.6 FO Supply Sys & Nat Gas $247 $0 $304 $0 $0 $551 $51 $0 3.7 Waste Treatment Equipment $2,883 $0 $1,652 $0 $0 $4,535 $439 $0 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,558 $0 $788 $0 $0 $3,346 $321 $0 

SUBTOTAL 3. $40,107 $0 $18,856 $0 $0 $58,963 $5,369 $0 $

 4 PC BOILER

4.1 PC Boiler & Accessories $148,766 $0 $83,888 $0 $0 $232,654 $22,535 $0 $24.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 4.4 Boiler BoP (w/ ID Fans) $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 4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 

SUBTOTAL 4. $148,766 $0 $83,888 $0 $0 $232,654 $22,535 $0 $2

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 391 

Exhibit 4-34 Case 11 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Report Da

Project: Bituminous Baseline Study

Case: Case 11 - Supercritical PC w/o CO2

Plant Size: 550.2 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Projec

 5 FLUE GAS CLEANUP

5.1 Absorber Vessels & Accessories $54,227 $0 $11,683 $0 $0 $65,910 $6,238 $0 $75.2 Other FGD $2,830 $0 $3,209 $0 $0 $6,039 $582 $0 $5.3 Bag House & Accessories $15,654 $0 $9,942 $0 $0 $25,596 $2,448 $0 $25.4 Other Particulate Removal Materials $1,059 $0 $1,134 $0 $0 $2,194 $211 $0 $5.5 Gypsum Dewatering System $4,304 $0 $732 $0 $0 $5,036 $476 $0 $5.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 5. $78,075 $0 $26,700 $0 $0 $104,775 $9,955 $0 $11,

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 6. $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 7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $8,242 $0 $5,379 $0 $0 $13,621 $1,190 $0 $27.4 Stack $8,411 $0 $4,925 $0 $0 $13,336 $1,274 $0 $17.9 Duct & Stack Foundations $0 $959 $1,097 $0 $0 $2,056 $192 $0 $

SUBTOTAL 7. $16,653 $959 $11,402 $0 $0 $29,013 $2,656 $0 $4,

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $48,728 $0 $6,532 $0 $0 $55,260 $5,291 $0 $68.2 Turbine Plant Auxiliaries $334 $0 $716 $0 $0 $1,050 $102 $0 $8.3 Condenser & Auxiliaries $6,405 $0 $2,204 $0 $0 $8,610 $818 $0 $8.4 Steam Piping $16,354 $0 $8,078 $0 $0 $24,433 $2,039 $0 $38.9 TG Foundations $0 $1,042 $1,658 $0 $0 $2,699 $254 $0 $

SUBTOTAL 8. $71,822 $1,042 $19,188 $0 $0 $92,052 $8,504 $0 $11,

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $8,669 $0 $2,702 $0 $0 $11,371 $1,079 $0 $19.2 Circulating Water Pumps $1,765 $0 $111 $0 $0 $1,876 $160 $0 $9.3 Circ.Water System Auxiliaries $515 $0 $69 $0 $0 $583 $55 $0 9.4 Circ.Water Piping $0 $4,150 $3,958 $0 $0 $8,108 $747 $0 $19.5 Make-up Water System $457 $0 $605 $0 $0 $1,062 $101 $0 $9.6 Component Cooling Water Sys $411 $0 $324 $0 $0 $735 $69 $0 $9.9 Circ.Water System Foundations& Structures $0 $2,403 $3,844 $0 $0 $6,247 $588 $0 $1

SUBTOTAL 9. $11,816 $6,553 $11,613 $0 $0 $29,981 $2,799 $0 $4,

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 10.6 Ash Storage Silos $563 $0 $1,735 $0 $0 $2,298 $224 $0 $10.7 Ash Transport & Feed Equipment $3,669 $0 $3,735 $0 $0 $7,403 $700 $0 $10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $133 $158 $0 $0 $291 $27 $0 

SUBTOTAL 10. $4,232 $133 $5,628 $0 $0 $9,992 $951 $0 $1

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 392 

Exhibit 4-34 Case 11 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Report 

Project: Bituminous Baseline Study

Case: Case 11 - Supercritical PC w/o CO2

Plant Size: 550.2 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenc

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Proj

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $1,524 $0 $249 $0 $0 $1,773 $164 $0 11.2 Station Service Equipment $2,578 $0 $882 $0 $0 $3,460 $331 $0 11.3 Switchgear & Motor Control $3,063 $0 $525 $0 $0 $3,588 $332 $0 11.4 Conduit & Cable Tray $0 $1,967 $6,693 $0 $0 $8,660 $829 $0 $11.5 Wire & Cable $0 $3,568 $7,051 $0 $0 $10,619 $895 $0 $11.6 Protective Equipment $243 $0 $861 $0 $0 $1,104 $108 $0 11.7 Standby Equipment $1,176 $0 $28 $0 $0 $1,204 $114 $0 11.8 Main Power Transformers $6,950 $0 $165 $0 $0 $7,116 $541 $0 11.9 Electrical Foundations $0 $297 $735 $0 $0 $1,032 $98 $0 

SUBTOTAL 11. $15,533 $5,832 $17,190 $0 $0 $38,556 $3,411 $0 $

12 INSTRUMENTATION & CONTROL

12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 12.4 Other Major Component Control $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 12.6 Control Boards,Panels & Racks $413 $0 $258 $0 $0 $671 $65 $0 12.7 Distributed Control System Equipment $4,172 $0 $760 $0 $0 $4,932 $470 $0 12.8 Instrument Wiring & Tubing $2,305 $0 $4,674 $0 $0 $6,979 $594 $0 $12.9 Other I & C Equipment $1,179 $0 $2,787 $0 $0 $3,966 $386 $0 

SUBTOTAL 12. $8,069 $0 $8,480 $0 $0 $16,549 $1,515 $0 $

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $48 $958 $0 $0 $1,005 $99 $0 13.2 Site Improvements $0 $1,578 $1,974 $0 $0 $3,552 $349 $0 13.3 Site Facilities $2,827 $0 $2,809 $0 $0 $5,637 $553 $0 $

SUBTOTAL 13. $2,827 $1,625 $5,741 $0 $0 $10,194 $1,001 $0 $

14 BUILDINGS & STRUCTURES

14.1 Boiler Building $0 $7,843 $6,990 $0 $0 $14,833 $1,332 $0 $14.2 Turbine Building $0 $11,220 $10,597 $0 $0 $21,817 $1,964 $0 $14.3 Administration Building $0 $554 $594 $0 $0 $1,147 $104 $0 14.4 Circulation Water Pumphouse $0 $159 $128 $0 $0 $286 $26 $0 14.5 Water Treatment Buildings $0 $565 $471 $0 $0 $1,036 $93 $0 14.6 Machine Shop $0 $370 $252 $0 $0 $623 $55 $0 14.7 Warehouse $0 $251 $255 $0 $0 $506 $46 $0 14.8 Other Buildings & Structures $0 $205 $177 $0 $0 $382 $34 $0 14.9 Waste Treating Building & Str. $0 $393 $1,208 $0 $0 $1,601 $151 $0 

SUBTOTAL 14. $0 $21,560 $20,672 $0 $0 $42,232 $3,805 $0 $

TOTAL COST $423,786 $42,490 $241,370 $0 $0 $707,646 $66,300 $0 $9

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of Fossil Energy Power Plants 

 393 

Exhibit 4-35 Case 11 Initial and Annual Operating and Maintenance Costs 

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006

Case 11 - Supercritical PC w/o CO2 Heat Rate-net(Btu/kWh): 8,721

 MWe-net: 550

 Capacity Factor: (%): 85

 OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 33.00 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 Skilled Operator 2.0 2.0

 Operator 9.0 9.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 2.0 2.0

 TOTAL-O.J.'s 14.0 14.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $5,261,256 $9.563

Maintenance Labor Cost $5,818,574 $10.576

Administrative & Support Labor $2,769,958 $5.035

TOTAL FIXED OPERATING COSTS $13,849,788 $25.175

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $8,727,862 $0.00213

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

 Water(/1000 gallons) 0 3,918 1.03 $0 $1,251,873 $0.00031

 Chemicals

 MU & WT Chem.(lb) 132,743 18,963 0.16 $21,876 $969,578 $0.00024

 Limestone (ton) 3,429 490 20.60 $70,633 $3,130,564 $0.00076

 Carbon (Mercury Removal) (lb) 0 0 1.00 $0 $0 $0.00000

 MEA Solvent (ton) 0 0 2,142.40 $0 $0 $0.00000

 NaOH (tons) 0 0 412.96 $0 $0 $0.00000

 H2SO4 (tons) 0 0 132.15 $0 $0 $0.00000

 Corrosion Inhibitor 0 0 0.00 $0 $0 $0.00000

 Activated Carbon(lb) 0 0 1.00 $0 $0 $0.00000

 Ammonia (28% NH3) ton 517 74 123.60 $63,883 $2,831,382 $0.00069

Subtotal Chemicals $156,392 $6,931,524 $0.00169

 Other

 Supplemental Fuel(MBtu) 0 0 0.00 $0 $0 $0.00000

 SCR Catalyst(m3) w/equip. 0.44 5,500.00 $0 $747,563 $0.00018

 Emission Penalties 0 0 0.00 $0 $0 $0.00000

Subtotal Other $0 $747,563 $0.00018

 Waste Disposal

 Flyash (ton) 0 96 15.45 $0 $458,782 $0.00011

 Bottom Ash(ton) 0 383 15.45 $0 $1,835,187 $0.00045

 Subtotal-Waste Disposal $0 $2,293,969 $0.00056

 By-products & Emissions 

 Gypsum (tons) 0 739 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $156,392 $19,952,791 $0.00487

 Fuel(ton) 148,057 4,935 42.11 $6,234,675 $64,476,927 $0.01574
Cost and Performance Comparison of Fossil Energy Power Plants 

 394 

4.3.7 CASE 12 – SUPERCRITICAL PC WITH CO2 CAPTURE

The plant configuration for Case 12, supercritical PC, is the same as Case 11 with the exception 

that the Econamine FG Plus 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 combustion turbines, 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. 

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 4-36 and Exhibit 4-37, respectively. Since the CDR facility process description was 

provided in Section 4.1.7, it is not repeated here. 

4.3.8 CASE 12 PERFORMANCE RESULTS

The Case 12 modeling assumptions were presented previously in Section 4.3.2. 

The plant produces a net output of 546 MW at a net plant efficiency of 27.2 percent (HHV 

basis). Overall plant performance is summarized in Exhibit 4-38 which includes auxiliary power 

requirements. The CDR facility, including CO2 compression, accounts for over 58 percent of the 

auxiliary plant load. The circulating water system (circulating water pumps and cooling tower 

fan) accounts for over 15 percent of the auxiliary load, largely due to the high cooling water 

demand of the CDR facility. 
Cost and Performance Comparison of F

 395 

Exhibit 4-36 Case 12 Process Flow Diagram, Supercritical Unit with CO2 Capture 

FORCED DRAFT FANS

BAGHOUSE FGD

INDUCED

DRAFT FANS

GYPSUM

LIMESTONE

SLURRY

OXIDATION

AIR

MAKEUP

WATER

BOTTOM ASH

COAL FEED

INFILTRATION

AIR

8

1 2

PRIMARY AIR FANS

3 4

65

7

9

FLY ASH

10 11

13 14

12

15

16

AIRCOMBUSTIONPRODUCTSWATERCOAL/ASH

SOLID/WATER SLURRY

LEGEND

PULVERIZED

COAL

BOILER

SCR

ECONAMINE

FG+

17

18

CO2 COMP

19

RE

S

CONDENSATE

RETURN

CO2

HP 

TURBINE

IP

TURBINE LP TURBINE

CONDENSER

FEEDWATER 

HEATER

 SYSTEM

MAIN STEAM

COLD REHEAT

HOT REHEAT

BOILER FEEDWATER
Cost and Performance Comparison of F

 396 

Exhibit 4-37 Case 12 Stream Table, Supercritical Unit with CO2 Capture 

1 2 3 4 5 6 7 8 9 

V-L Mole Fractions 

 Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 

 CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 

 H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 

 H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 

 N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 

 O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 

 SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 

V-L Flow (lbmol/hr) 153,570 153,570 47,175 47,175 2,650 0 0 215,146 0 

V-L Flow (lb/hr) 4,431,560 4,431,560 1,361,330 1,361,330 76,466 0 0 6,399,090 0 Solids Flowrate 0 0 0 0 0 586,627 11,377 45,507 45,507 

Temperature (°F) 59 66 59 78 59 59 350 350 350 

Pressure (psia) 14.70 15.25 14.70 16.14 14.70 14.70 14.40 14.40 14.20 

Enthalpy (BTU/lb)A 13.1 14.9 13.1 17.7 13.1 11,676 51.4 135.6 51.4 

Density (lb/ft3) 0.08 0.08 0.08 0.08 0.08 --- --- 0.05 --- 

Avg. Molecular Weight 28.86 28.86 28.86 28.86 28.86 --- --- 29.74 --- 

12 13 14 15 16 17 18 19 20 

V-L Mole Fraction 

Ar 0.0000 0.0000 0.0092 0.0000 0.0080 0.0000 0.0000 0.0000 0.0000 CO2 0.0000 0.0000 0.0003 0.0015 0.1326 0.0000 0.0000 0.9862 1.0000 

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H2O 1.0000 1.0000 0.0099 0.9977 0.1668 1.0000 1.0000 0.0138 0.0000 

N2 0.0000 0.0000 0.7732 0.0008 0.6690 0.0000 0.0000 0.0000 0.0000 

O2 0.0000 0.0000 0.2074 0.0000 0.0235 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 

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (lbmol/hr) 7,537 34,486 2,535 20,128 238,453 100,792 100,792 28,856 28,458 

V-L Flowrate (lb/hr) 135,788 621,279 73,155 363,564 6,833,360 1,815,800 1,815,800 1,259,600 1,252,440 Solids Flowrate (lb/hr) 58,054 0 0 90,446 0 0 0 0 0 Temperature (°F) 59 60 59 135 135 692 348 69 124 Pressure (psia) 14.70 14.70 14.70 15.20 15.20 130.86 130.86 23.52 2215.00 Enthalpy (BTU/lb)A --- 33.3 13.1 88.0 139.4 1373.8 319.5 11.4 -70.8 

Density (lb/ft3) 62.62 62.59 0.08 39.94 0.07 0.19 55.67 0.18 40.76 

Molecular Weight 18.02 18.02 28.86 18.06 28.66 18.02 18.02 43.65 44.01 

A - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of Fossil Energy Power Plants 

 397 

Exhibit 4-38 Case 12 Plant Performance Summary 

POWER SUMMARY (Gross Power at Generator Terminals, kWe) 

TOTAL (STEAM TURBINE) POWER, kWe 663,445 

AUXILIARY LOAD SUMMARY, kWe (Note 1) 

Coal Handling and Conveying 490 

Limestone Handling & Reagent Preparation 1,270 

Pulverizers 3,990 

Ash Handling 760 

Primary Air Fans 1,870 

Forced Draft Fans 2,380 

Induced Draft Fans 10,120 

SCR 70 

Baghouse 100 

FGD Pumps and Agitators 4,250 

Econamine FG Plus Auxiliaries 21,320 

CO2 Compression 46,900 

Miscellaneous Balance of Plant (Note 2) 2,000 

Steam Turbine Auxiliaries 400 

Condensate Pumps 630 

Circulating Water Pumps 12,260 

Cooling Tower Fans 6,340 

Transformer Loss 2,300 

TOTAL AUXILIARIES, kWe 117,450 

NET POWER, kWe 545,995 

Net Plant Efficiency (HHV) 27.2% 

Net Plant Heat Rate (Btu/kWh) 12,534 

CONDENSER COOLING DUTY, 106 kJ/h (106 Btu/h) 1,884 (1,787) 

CONSUMABLES 

As-Received Coal Feed, kg/h (lb/h) 266,090 (586,627) 

Limestone Sorbent Feed, kg/h (lb/h) 26,333 (58,054) 

Thermal Input, kWt 2,005,660 

Makeup Water, m3/min (gpm) 46.0 (12,159) 

Notes: 1. Boiler feed pumps are steam turbine driven 

 2. Includes plant control systems, lighting, HVAC and miscellanous low voltage loads 
Cost and Performance Comparison of Fossil Energy Power Plants 

 398 

Environmental Performance 

The environmental targets for emissions of Hg, NOx, SO2, and particulate matter were presented 

in Section 2.4. A summary of the plant air emissions for Case 12 is presented in Exhibit 4-39. 

Exhibit 4-39 Case 12 Air Emissions 

kg/GJ 

(lb/106 Btu) 

Tonne/year 

(ton/year) 

85% capacity factor 

kg/MWh 

(lb/MWh) 

SO2 Negligible Negligible Negligible 

NOX 0.030 (0.070) 1,618 (1,784) 0.328 (0.722) 

Particulates 0.006 (0.013) 300 (331) 0.061 (0.134) 

Hg 0.49 x 10-6

(1.14 x 10-6) 0.026 (0.029) 5.3 x 10-6 (11.8 x 10-6) 

CO2 8.7 (20) 468,000 (516,000) 95 (209) 

CO2

1 115 (254) 

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 negligible 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 flue gas is removed in CDR facility. 

Exhibit 4-40 shows the overall water balance for the plant. Raw water is obtained from 

groundwater (50 percent) and from municipal sources (50 percent). The water usage represents 

only the contribution of raw water makeup. In some cases the water demand is greater than raw 

water makeup because of internal water recycle streams. For example, the boiler feedwater 

blowdown stream and condensate recovered from cooling the flue gas prior to the CO2 absorber 

are re-used as makeup to the cooling tower, thus reducing the raw water requirement by that 

amount. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 399 

Exhibit 4-40 Case 12 Water Balance 

Water Use Water Demand, 

m3/min (gpm) 

Internal Recycle, 

m3/min (gpm) 

Raw Water Makeup, 

m3/min (gpm) 

FGD Makeup 2.9 (779) 0 2.9 (779) 

BFW Makeup 0.4 (105) 0 0.4 (105) 

Cooling Tower Makeup 47.7 (12,600) 5.0 (1,324) 42.7 (11,276) 

Total 51.0 (13,483) 5.0 (1,324) 46.0 (12,159) 

Heat and Mass Balance Diagrams 

A heat and mass balance diagram is shown for the Case 12 PC boiler, the FGD unit, CDR system 

and steam cycle in Exhibit 4-41. 

An overall plant energy balance is provided in tabular form in Exhibit 4-42. The power out is 

the steam turbine power prior to generator losses. The power at the generator terminals (shown 

in Exhibit 4-38) is calculated by multiplying the power out by a generator efficiency of 98.5 

percent. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 400 

This page intentionally left blank 
401 

Exhibit 4-41 Case 12 Heat and Mass Balance, Supercritical PC Boiler with CO2 
402 

This page intentionally left blank 
Cost and Performance Comparison of Fossil Energy Power Plants 

 403 

Exhibit 4-42 Case 12 Overall Energy Balance (0°C [32°F] Reference) 

HHV Sensible + Latent Power Total 

Heat In (MMBtu/hr) 

Coal 6,843.6 5.7 6,849.3 

Ambient Air 76.1 76.1 

Infiltration Air 1.0 1.0 

Limestone 0.3 0.3 

FGD Oxidant 1.0 1.0 

Water 25.1 25.1 

Auxiliary Power 400.8 400.8 

Totals 6,843.6 109.1 400.8 7,353.4 

Heat Out (MMBtu/hr) 

Bottom Ash 0.6 0.6 

Fly Ash 2.3 2.3 

Flue Gas Exhaust 146.7 146.7 

CO2 Product (88.7) (88.7) 

CO2 Steam Losses 1,914.0 1,914.0 

CO2 Cooling Losses 253.2 253.2 

CO2 System Losses 762.8 762.8 

Gypsum Slurry 40.0 40.0 

Condenser 1,787.0 1,787.0 

Process Losses (1) 236.0 236.0 

Power 2,299.5 2,299.5 

Totals 0.0 5,053.9 2,299.5 7,353.4 

(1) 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 Comparison of Fossil Energy Power Plants 

 404 

4.3.9 CASE 12 – MAJOR EQUIPMENT LIST

Major equipment items for the supercritical 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 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 Operating Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0

3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0

5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling 

System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0

8 Reclaim Hopper N/A 2 1

9 Feeder Vibratory 2 1

10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor 

reduction 2 0

14 As-Fired Coal Sampling 

System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0

17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 3 0

19 Limestone Truck Unloading 

Hopper N/A 1 0

20 Limestone Feeder Belt 1 0

21 Limestone Conveyor No. L1 Belt 1 0

22 Limestone Reclaim Hopper N/A 1 0

23 Limestone Reclaim Feeder Belt 1 0

24 Limestone Conveyor No. L2 Belt 1 0

25 Limestone Day Bin w/ actuator 2 0

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph)

N/A

1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)

1,134 tonne/h (1,250 tph)

54 tonne (60 ton)

218 tonne/h (240 tph)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

435 tonne/h (480 tph)

218 tonne (240 ton)

N/A

435 tonne/h (480 tph)

998 tonne (1,100 ton)

N/A

435 tonne/h (480 tph)

N/A

36 tonne (40 ton)

109 tonne/h (120 tph)

109 tonne/h (120 tph)

345 tonne (380 ton)

18 tonne (20 ton)

91 tonne/h (100 tph)

91 tonne/h (100 tph)
Cost and Performance Comparison of Fossil Energy Power Plants 

 405 

ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Coal Feeder Gravimetric 6 0

2 Coal Pulverizer Ball type or 

equivalent 6 0

3 Limestone Weigh Feeder Gravimetric 1 1

4 Limestone Ball Mill Rotary 1 1

5 Limestone Mill Slurry Tank 

with Agitator N/A 1 1

6 Limestone Mill Recycle 

Pumps

Horizontal 

centrifugal 1 1

7 Hydroclone Classifier

4 active 

cyclones in a 5 

cyclone bank

1 1

8 Distribution Box 2-way 1 1

9 Limestone Slurry Storage 

Tank with Agitator Field erected 1 1

10 Limestone Slurry Feed 

Pumps

Horizontal 

centrifugal 1 1

109,778 liters (29,000 gal)

Design Condition

45 tonne/h (50 tph)

45 tonne/h (50 tph)

29 tonne/h (32 tph)

29 tonne/h (32 tph)

624,598 liters (165,000 gal)

445 lpm @ 12m H2O

(490 gpm @ 40 ft H2O)

N/A

308 lpm @ 9m H2O

(340 gpm @ 30 ft H2O)

109 lpm (120 gpm) per cyclone
Cost and Performance Comparison of Fossil Energy Power Plants 

 406 

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 1 1

3 Deaerator and Storage 

Tank Horizontal spray type 1 0

4 Boiler Feed Pump and 

Steam Turbine Drive

Barrel type, multistage, centrifugal 1 1

6 LP Feedwater Heater 

1A/1B Horizontal U-tube 2 0

7 LP Feedwater Heater 

2A/2B Horizontal U-tube 2 0

8 LP Feedwater Heater 

3A/3B Horizontal U-tube 2 0

9 LP Feedwater Heater 

4A/4B Horizontal U-tube 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 1 0

11 HP Feedwater Heater 7 Horizontal U-tube 1 0

12 HP Feedwater heater 8 Horizontal U-tube 1 0

13 Auxiliary Boiler Shop fabricated, water 

tube 1 0

14 Fuel Oil System No. 2 fuel oil for light 

off 1 0

15 Service Air 

Compressors Flooded Screw 2 1

16 Instrument Air Dryers Duplex, regenerative 2 1

17 Closed Cycle Cooling 

Heat Exchangers Shell and tube 2 0

18 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 2 1

19 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine 1 1

20 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal 1 1

21 Raw Water Pumps Stainless steel, single 

suction 2 1

22 Filtered Water Pumps Stainless steel, single 

suction 2 1

23 Filtered Water Tank Vertical, cylindrical 1 0

24 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly, 

electrodeionization unit

1 1

25 Liquid Waste Treatment 

System -- 1 0

28 m3/min (1,000 scfm)

3,785 lpm @ 88 m H2O

(1,000 gpm @ 290 ft H2O)

2,650 lpm @ 64 m H2O

(700 gpm @ 210 ft H2O)

25,514 lpm @ 43 m H2O

(6,740 gpm @ 140 ft H2O)

2,120 lpm @ 49 m H2O

(560 gpm @ 160 ft H2O)

5 0

Startup Boiler Feed 

Pump, Electric Motor 

Driven

Barrel type, multistage, centrifugal13,249 lpm @ 3,475 m H2O

(3,500 gpm @ 11,400 ft H2O) 1

53 MMkJ/h (50 MMBtu/h) each

20,820 lpm @ 30 m H2O

(5,500 gpm @ 100 ft H2O)

2,612,695 kg/h (5,760,000 lb/h)

2,040,353 liter (539,000 gal)

1,022 lpm (270 gpm)

10 years, 24-hour storm

43,911 lpm @ 3,475 m H2O

(11,600 gpm @ 11,400 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C

(40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

557,919 kg/h (1,230,000 lb/h)

557,919 kg/h (1,230,000 lb/h)

557,919 kg/h (1,230,000 lb/h)

557,919 kg/h (1,230,000 lb/h)

2,612,695 kg/h (5,760,000 lb/h)

2,612,695 kg/h (5,760,000 lb/h)

1,135,632 liter (300,000 gal)

Design Condition

1,570,958 liters (415,000 gal)

18,927 lpm @ 213 m H2O

(5,000 gpm @ 700 ft H2O)

2,614,963 kg/h (5,765,000 lb/h)

5 min. tank
Cost and Performance Comparison of Fossil Energy Power Plants 

 407 

ACCOUNT 4 BOILER AND ACCESSORIES 

Equipment 

No. Description Type OperatingQty. Spares

1 Boiler

Supercritical, drum, 

wall-fired, low NOx 

burners, overfire air

1 0

2 Primary Air Fan Centrifugal 2 0

3 Forced Draft Fan Centrifugal 2 0

4 Induced Draft Fan Centrifugal 2 0

5 SCR Reactor Vessel Space for spare layer 2 0

6 SCR Catalyst -- 3 0

7 Dilution Air Blower Centrifugal 2 1

8 Ammonia Storage Horizontal tank 5 0

9 Ammonia Feed 

Pump Centrifugal 2 1

1,596,647 kg/h, 33,898 m3/min @ 

90 cm WG (3,520,000 lb/h, 

1,197,100 acfm @ 36 in. WG)

3,193,294 kg/h (7,040,000 lb/h)

--

Design Condition

2,612,695 kg/h steam @ 24.1 

MPa/593°C/593°C 

(5,760,000 lb/h steam @ 3,500 

psig/1,100°F/1,100°F)

339,741 kg/h, 4,650 m3/min @ 

123 cm WG (749,000 lb/h, 

164,200 acfm @ 48 in. WG)

1,105,406 kg/h, 15,135 m3/min @ 

47 cm WG (2,437,000 lb/h, 

534,500 acfm @ 19 in. WG)

190 m3/min @ 108 cm WG

(6,700 acfm @ 42 in. WG)

208,199 liter (55,000 gal)

40 lpm @ 91 m H2O

(11 gpm @ 300 ft H2O)
Cost and Performance Comparison of Fossil Energy Power Plants 

 408 

ACCOUNT 5 FLUE GAS CLEANUP 

Equipment 

No. Description Type OperatingQty. Spares

1 Fabric Filter

Single stage, highratio with pulsejet online cleaning 

system

2 0

2 Absorber Module Counter-current 

open spray

1 0

3 Recirculation Pumps Horizontal 

centrifugal 5 1

4 Bleed Pumps Horizontal 

centrifugal 2 1

5 Oxidation Air Blowers Centrifugal 2 1

6 Agitators Side entering 5 1

7 Dewatering Cyclones Radial assembly, 

5 units each 2 0

8 Vacuum Filter Belt Horizontal belt 2 1

9 Filtrate Water Return 

Pumps

Horizontal 

centrifugal 1 1

10 Filtrate Water Return 

Storage Tank Vertical, lined 1 0

11 Process Makeup Water 

Pumps

Horizontal 

centrifugal 1 1

Design Condition

1,596,647 kg/h (3,520,000 lb/h) 

99.8% efficiency

52,160 m3/min (1,842,000 acfm)

181,701 lpm @ 64 m H2O

(48,000 gpm @ 210 ft H2O)

250 m3/min @ 0.3 MPa

(8,820 acfm @ 42 psia)

45 tonne/h (50 tph)

50 wt % slurry

5,716 lpm (1,510 gpm)

20 wt% solids

50 hp

1,438 lpm (380 gpm) per cyclone

871 lpm @ 12 m H2O

(230 gpm @ 40 ft H2O)

567,816 lpm (150,000 gal)

3,255 lpm @ 21 m H2O

(860 gpm @ 70 ft H2O)

ACCOUNT 5C CARBON DIOXIDE RECOVERY 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Econamine FG 

Plus

Amine-based CO2 

capture technology 2 0

2 CO2 

Compressor

Integrally geared, 

multi-stage 

centrifugal

2 0

Design Condition

1,704,602 kg/h (3,758,000 lb/h) 

20.4 wt % CO2

inlet concentration

312,453 kg/h @ 15.3 MPa

(688,840 lb/h @ 2,215 psia)
Cost and Performance Comparison of Fossil Energy Power Plants 

 409 

ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES 

 N/A 

ACCOUNT 7 HRSG, DUCTING & STACK 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Stack Reinforced concrete 

with FRP liner 1 0

Design Condition

152 m (500 ft) high x

5.5 m (18 ft) diameter

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty. Spares

1 Steam Turbine

Commercially 

available advanced 

steam turbine

1 0

2 Steam Turbine Generator Hydrogen cooled, 

static excitation 1 0

3 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1 0

780 MVA @ 0.9 p.f., 

24 kV, 60 Hz

Design Condition

700 MW 

24.1 MPa/593°C/593°C 

(3500 psig/ 

1100°F/1100°F)

2,077 MMkJ/h (1,970 

MMBtu/h), Inlet water 

temperature 16oC (60oF), 

Water temperature rise 

11oC (20oF)

ACCOUNT 9 COOLING WATER SYSTEM 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 4 2

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

1 0

Design Condition

613,241 lpm @ 30.5 m

(162,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

5,914 MMkJ/h (5,610 MMBtu/h) 

heat load
Cost and Performance Comparison of Fossil Energy Power Plants 

 410 

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING 

Equipment 

No. Description Type 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 -- 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 1 1

8 Ash Seal Water Pumps Vertical, wet pit 1 1

9 Hydrobins -- 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 -- 1 1

13 Fly Ash Silo Reinforced 

concrete

2 0

14 Slide Gate Valves -- 2 0

15 Unloader -- 1 0

16 Telescoping Unloading 

Chute -- 1 0

Design Condition

--

--

5.4 tonne/h (6 tph)

--

--

227 lpm @ 17 m H2O

(60 gpm @ 56 ft H2O)

7,571 lpm @ 9 m H2O

(2000 gpm @ 28 ft H2O)

--

227 lpm (60 gpm)

--

--

--

--

21 m3/min @ 0.2 MPa

(730 scfm @ 24 psi)

680 tonne (1,500 ton)

127 tonne/h (140 tph)
Cost and Performance Comparison of Fossil Energy Power Plants 

 411 

ACCOUNT 11 ACCESSORY ELECTRIC PLANT 

Equipment 

No. Description Type Operating Qty. Spares

1 STG Transformer Oil-filled 1 0

2 Auxiliary 

Transformer Oil-filled 1 1

3 Low Voltage 

Transformer Dry ventilated 1 1

4

STG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, self-cooled 1 0

5 Medium Voltage 

Switchgear Metal clad 1 1

6 Low Voltage 

Switchgear Metal enclosed 1 1

7 Emergency Diesel 

Generator

Sized for emergency 

shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0

24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz

24 kV/4.16 kV, 128 MVA, 

3-ph, 60 Hz

4.16 kV/480 V, 19 MVA, 

3-ph, 60 Hz

Design Condition

24 kV/345 kV, 640 MVA, 

3-ph, 60 Hz

ACCOUNT 12 INSTRUMENTATION AND CONTROL 

Equipment 

No. Description Type OperatingQty. 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 Comparison of Fossil Energy Power Plants 

 412 

4.3.10 CASE 12 – COST ESTIMATING BASIS

The cost estimating methodology was described previously in Section 2.6. Exhibit 4-43 shows 

the total plant capital cost summary organized by cost account and Exhibit 4-44 shows a more 

detailed breakdown of the capital costs. Exhibit 4-45 shows the initial and annual O&M costs. 

The estimated TPC of the subcritical PC boiler with CO2 capture is $2,868/kW. Process 

contingency represents 3.5 percent of the TPC and project contingency represents 12.4 percent. 

The 20-year LCOE, including CO2 TS&M costs of 3.9 mills/kWh, is 114.8 mills/kWh. 
Cost and Performance Comparison of F

 413 

Exhibit 4-43 Case 12 Total Plant Cost Summary 

Client: USDOE/NETL Report Da

Project: Bituminous Baseline Study

Case: Case 12 - Supercritical PC w/ CO2

Plant Size: 546.0 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Projec

 1 COAL & SORBENT HANDLING $19,316 $5,215 $11,691 $0 $0 $36,222 $3,246 $0 $5,

 2 COAL & SORBENT PREP & FEED $13,126 $758 $3,326 $0 $0 $17,210 $1,508 $0 $2,

 3 FEEDWATER & MISC. BOP SYSTEMS $54,477 $0 $25,648 $0 $0 $80,126 $7,317 $0 $14,

 4 PC BOILER

4.1 PC Boiler & Accessories $190,969 $0 $107,678 $0 $0 $298,647 $28,927 $0 $32,

4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $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 

SUBTOTAL 4 $190,969 $0 $107,678 $0 $0 $298,647 $28,927 $0 $32,

 5 FLUE GAS CLEANUP $101,747 $0 $34,963 $0 $0 $136,710 $12,990 $0 $14,

 5B CO2 REMOVAL & COMPRESSION $229,832 $0 $69,851 $0 $0 $299,683 $28,443 $52,879 $76,

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 

6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 6 $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 

7.2-7.9 HRSG Accessories, Ductwork and Stack $17,889 $981 $12,221 $0 $0 $31,091 $2,840 $0 $4,

SUBTOTAL 7 $17,889 $981 $12,221 $0 $0 $31,091 $2,840 $0 $4,

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $53,763 $0 $7,192 $0 $0 $60,956 $5,836 $0 $6,

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $26,923 $1,148 $14,942 $0 $0 $43,013 $3,724 $0 $6,

SUBTOTAL 8 $80,687 $1,148 $22,134 $0 $0 $103,969 $9,561 $0 $13,

 9 COOLING WATER SYSTEM $21,479 $11,200 $19,881 $0 $0 $52,559 $4,900 $0 $7,

10 ASH/SPENT SORBENT HANDLING SYS $5,154 $162 $6,854 $0 $0 $12,169 $1,158 $0 $1,11 ACCESSORY ELECTRIC PLANT $20,196 $10,240 $29,287 $0 $0 $59,723 $5,331 $0 $8,12 INSTRUMENTATION & CONTROL $9,195 $0 $9,662 $0 $0 $18,857 $1,726 $943 $2,13 IMPROVEMENTS TO SITE $3,162 $1,818 $6,421 $0 $0 $11,402 $1,120 $0 $2,14 BUILDINGS & STRUCTURES $0 $23,760 $22,735 $0 $0 $46,495 $4,189 $0 $7,

TOTAL COST $767,230 $55,282 $382,352 $0 $0 $1,204,865 $113,256 $53,822 $195,

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 414 

Exhibit 4-44 Case 12 Total Plant Cost Details 

Client: USDOE/NETL Repor

Project: Bituminous Baseline Study

Case: Case 12 - Supercritical PC w/ CO2

Plant Size: 546.0 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenci

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $3,967 $0 $1,831 $0 $0 $5,797 $518 $0 1.2 Coal Stackout & Reclaim $5,126 $0 $1,174 $0 $0 $6,300 $551 $0 1.3 Coal Conveyors $4,766 $0 $1,161 $0 $0 $5,927 $520 $0 1.4 Other Coal Handling $1,247 $0 $269 $0 $0 $1,516 $132 $0 1.5 Sorbent Receive & Unload $160 $0 $49 $0 $0 $208 $18 $0 1.6 Sorbent Stackout & Reclaim $2,576 $0 $477 $0 $0 $3,053 $266 $0 1.7 Sorbent Conveyors $919 $198 $228 $0 $0 $1,345 $116 $0 1.8 Other Sorbent Handling $555 $129 $294 $0 $0 $979 $87 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $4,888 $6,210 $0 $0 $11,097 $1,037 $0 

SUBTOTAL 1. $19,316 $5,215 $11,691 $0 $0 $36,222 $3,246 $0 

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $2,305 $0 $454 $0 $0 $2,759 $241 $0 2.2 Coal Conveyor to Storage $5,901 $0 $1,301 $0 $0 $7,203 $630 $0 2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $4,391 $188 $922 $0 $0 $5,501 $479 $0 2.6 Sorbent Storage & Feed $529 $0 $205 $0 $0 $734 $65 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $570 $444 $0 $0 $1,014 $93 $0 

SUBTOTAL 2. $13,126 $758 $3,326 $0 $0 $17,210 $1,508 $0 

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 FeedwaterSystem $22,090 $0 $7,230 $0 $0 $29,320 $2,567 $0 3.2 Water Makeup & Pretreating $7,572 $0 $2,435 $0 $0 $10,007 $938 $0 3.3 Other Feedwater Subsystems $6,826 $0 $2,896 $0 $0 $9,722 $866 $0 3.4 Service Water Systems $1,495 $0 $807 $0 $0 $2,301 $214 $0 3.5 Other Boiler Plant Systems $8,357 $0 $8,175 $0 $0 $16,533 $1,551 $0 3.6 FO Supply Sys & Nat Gas $267 $0 $329 $0 $0 $596 $55 $0 3.7 Waste Treatment Equipment $5,103 $0 $2,923 $0 $0 $8,027 $778 $0 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,768 $0 $853 $0 $0 $3,621 $348 $0 

SUBTOTAL 3. $54,477 $0 $25,648 $0 $0 $80,126 $7,317 $0 $

 4 PC BOILER

4.1 PC Boiler & Accessories $190,969 $0 $107,678 $0 $0 $298,647 $28,927 $0 $4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 4.4 Boiler BoP (w/ ID Fans) $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 4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 

SUBTOTAL 4. $190,969 $0 $107,678 $0 $0 $298,647 $28,927 $0 $

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 415 

Exhibit 4-44 Case 12 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Report Date: 

Project: Bituminous Baseline Study

Case: Case 12 - Supercritical PC w/ CO2

Plant Size: 546.0 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project 

 5 FLUE GAS CLEANUP

5.1 Absorber Vessels & Accessories $70,491 $0 $15,186 $0 $0 $85,677 $8,109 $0 $9,379 5.2 Other FGD $3,679 $0 $4,172 $0 $0 $7,850 $756 $0 $861 5.3 Bag House & Accessories $20,751 $0 $13,179 $0 $0 $33,931 $3,245 $0 $3,718 5.4 Other Particulate Removal Materials $1,404 $0 $1,504 $0 $0 $2,908 $280 $0 $319 5.5 Gypsum Dewatering System $5,422 $0 $922 $0 $0 $6,344 $599 $0 $694 5.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 5. $101,747 $0 $34,963 $0 $0 $136,710 $12,990 $0 $14,970 

 5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $202,944 $0 $61,453 $0 $0 $264,397 $25,093 $52,879 $68,474 5B.2 CO2 Compression & Drying $26,888 $0 $8,398 $0 $0 $35,286 $3,350 $0 $7,727 

SUBTOTAL 5. $229,832 $0 $69,851 $0 $0 $299,683 $28,443 $52,879 $76,201 

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 6. $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 7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $9,280 $0 $6,057 $0 $0 $15,337 $1,340 $0 $2,501 7.4 Stack $8,609 $0 $5,041 $0 $0 $13,650 $1,304 $0 $1,495 7.9 Duct & Stack Foundations $0 $981 $1,123 $0 $0 $2,104 $196 $0 $460 

SUBTOTAL 7. $17,889 $981 $12,221 $0 $0 $31,091 $2,840 $0 $4,457 

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $53,763 $0 $7,192 $0 $0 $60,956 $5,836 $0 $6,679 8.2 Turbine Plant Auxiliaries $368 $0 $789 $0 $0 $1,158 $112 $0 $127 8.3 Condenser & Auxiliaries $5,563 $0 $1,956 $0 $0 $7,519 $715 $0 $823 8.4 Steam Piping $20,992 $0 $10,369 $0 $0 $31,362 $2,617 $0 $5,097 8.9 TG Foundations $0 $1,148 $1,827 $0 $0 $2,975 $280 $0 $651 

SUBTOTAL 8. $80,687 $1,148 $22,134 $0 $0 $103,969 $9,561 $0 $13,377 

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $15,181 $0 $4,731 $0 $0 $19,911 $1,890 $0 $2,180 9.2 Circulating Water Pumps $3,928 $0 $285 $0 $0 $4,213 $361 $0 $457 9.3 Circ.Water System Auxiliaries $907 $0 $121 $0 $0 $1,028 $97 $0 $112 

9.4 Circ.Water Piping $0 $7,315 $6,977 $0 $0 $14,292 $1,317 $0 $2,341 9.5 Make-up Water System $740 $0 $981 $0 $0 $1,721 $163 $0 $283 9.6 Component Cooling Water Sys $723 $0 $571 $0 $0 $1,294 $121 $0 $212 9.9 Circ.Water System Foundations& Structures $0 $3,884 $6,215 $0 $0 $10,099 $951 $0 $2,210 

SUBTOTAL 9. $21,479 $11,200 $19,881 $0 $0 $52,559 $4,900 $0 $7,796 

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $685 $0 $2,113 $0 $0 $2,799 $273 $0 $307 10.7 Ash Transport & Feed Equipment $4,468 $0 $4,548 $0 $0 $9,016 $853 $0 $987 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $162 $192 $0 $0 $354 $33 $0 $77 

SUBTOTAL 10. $5,154 $162 $6,854 $0 $0 $12,169 $1,158 $0 $1,371 

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 416 

Exhibit 4-44 Case 12 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Repor

Project: Bituminous Baseline Study

Case: Case 12 - Supercritical PC w/ CO2

Plant Size: 546.0 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenci

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $1,647 $0 $270 $0 $0 $1,917 $178 $0 11.2 Station Service Equipment $4,617 $0 $1,581 $0 $0 $6,197 $593 $0 11.3 Switchgear & Motor Control $5,487 $0 $940 $0 $0 $6,427 $595 $0 11.4 Conduit & Cable Tray $0 $3,523 $11,989 $0 $0 $15,512 $1,485 $0 11.5 Wire & Cable $0 $6,390 $12,630 $0 $0 $19,020 $1,603 $0 11.6 Protective Equipment $243 $0 $861 $0 $0 $1,104 $108 $0 11.7 Standby Equipment $1,253 $0 $30 $0 $0 $1,282 $121 $0 11.8 Main Power Transformers $6,950 $0 $182 $0 $0 $7,132 $542 $0 11.9 Electrical Foundations $0 $326 $806 $0 $0 $1,133 $108 $0 

SUBTOTAL 11. $20,196 $10,240 $29,287 $0 $0 $59,723 $5,331 $0 

12 INSTRUMENTATION & CONTROL

12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 12.4 Other Major Component Control $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 12.6 Control Boards,Panels & Racks $471 $0 $294 $0 $0 $765 $74 $38 12.7 Distributed Control System Equipment $4,754 $0 $866 $0 $0 $5,620 $535 $281 12.8 Instrument Wiring & Tubing $2,626 $0 $5,327 $0 $0 $7,953 $677 $398 12.9 Other I & C Equipment $1,343 $0 $3,176 $0 $0 $4,520 $440 $226 

SUBTOTAL 12. $9,195 $0 $9,662 $0 $0 $18,857 $1,726 $943 

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $53 $1,071 $0 $0 $1,124 $111 $0 13.2 Site Improvements $0 $1,765 $2,208 $0 $0 $3,973 $390 $0 13.3 Site Facilities $3,162 $0 $3,142 $0 $0 $6,305 $619 $0 

SUBTOTAL 13. $3,162 $1,818 $6,421 $0 $0 $11,402 $1,120 $0 

14 BUILDINGS & STRUCTURES

14.1 Boiler Building $0 $8,384 $7,472 $0 $0 $15,857 $1,424 $0 14.2 Turbine Building $0 $12,152 $11,477 $0 $0 $23,629 $2,128 $0 14.3 Administration Building $0 $608 $651 $0 $0 $1,259 $114 $0 14.4 Circulation Water Pumphouse $0 $279 $225 $0 $0 $503 $45 $0 14.5 Water Treatment Buildings $0 $999 $834 $0 $0 $1,833 $164 $0 14.6 Machine Shop $0 $406 $277 $0 $0 $683 $61 $0 14.7 Warehouse $0 $275 $280 $0 $0 $555 $50 $0 14.8 Other Buildings & Structures $0 $225 $194 $0 $0 $419 $38 $0 14.9 Waste Treating Building & Str. $0 $431 $1,325 $0 $0 $1,756 $166 $0 

SUBTOTAL 14. $0 $23,760 $22,735 $0 $0 $46,495 $4,189 $0 

TOTAL COST $767,230 $55,282 $382,352 $0 $0 $1,204,865 $113,256 $53,822 $1

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of Fossil Energy Power Plants 

417 

Exhibit 4-45 Case 12 Initial and Annual Operating and Maintenance Costs 

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006

Case 12 - Supercritical PC w/ CO2 Heat Rate-net(Btu/kWh): 12,534

 MWe-net: 546

 Capacity Factor: (%): 85

 OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 33.00 $/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 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 $6,138,007 $11.242

Maintenance Labor Cost $10,271,860 $18.813

Administrative & Support Labor $4,102,467 $7.514

TOTAL FIXED OPERATING COSTS $20,512,333 $37.569

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $15,407,790 $0.00379

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

 Water(/1000 gallons) 0 8,755 1.03 $0 $2,797,790 $0.00069

 Chemicals

 MU & WT Chem.(lb) 296,665 42,381 0.16 $48,890 $2,166,895 $0.00053

 Limestone (ton) 4,877 697 20.60 $100,457 $4,452,382 $0.00110

 Carbon (Mercury Removal) (lb) 0 0 1.00 $0 $0 $0.00000

 MEA Solvent (ton) 1,065 1.51 2,142.40 $2,281,656 $1,004,996 $0.00025

 NaOH (tons) 74 7.36 412.96 $30,559 $942,457 $0.00023

 H2SO4 (tons) 72 7.18 132.15 $9,515 $294,213 $0.00007

 Corrosion Inhibitor 0 0 0.00 $147,250 $7,000 $0.00000

 Activated Carbon(lb) 657,450 1,800 1.00 $657,450 $558,450 $0.00014

 Ammonia (28% NH3) ton 813 116 123.60 $100,439 $4,451,615 $0.00109

Subtotal Chemicals $3,376,216 $13,878,007 $0.00341

 Other

 Supplemental Fuel(MBtu) 0 0 0.00 $0 $0 $0.00000

 SCR Catalyst(m3) w/equip. 0.62 5,500.00 $0 $1,058,976 $0.00026

 Emission Penalties 0 0 0.00 $0 $0 $0.00000

Subtotal Other $0 $1,058,976 $0.00026

 Waste Disposal

 Flyash (ton) 0 137 15.45 $0 $654,409 $0.00016

 Bottom Ash(ton) 0 546 15.45 $0 $2,617,579 $0.00064

 Subtotal-Waste Disposal $0 $3,271,988 $0.00080

 By-products & Emissions 

 Gypsum (tons) 0 1,085 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $3,376,216 $36,414,550 $0.00896

 Fuel(ton) 211,183 7,039 42.11 $8,892,927 $91,967,691 $0.02262
Cost and Performance Comparison of Fossil Energy Power Plants 

418 

4.4 PC CASE SUMMARY 

The performance results of the four PC plant configurations modeled in this study are 

summarized in Exhibit 4-46. 

Exhibit 4-46 Estimated Performance and Cost Results for Pulverized Coal Cases 

Case 9 Case 10 Case 11 Case 12

CO2 Capture No Yes No Yes

Gross Power Output (kWe) 583,315 679,923 580,260 663,445

Auxiliary Power Requirement (kWe) 32,870 130,310 30,110 117,450

Net Power Output (kWe) 550,445 549,613 550,150 545,995

Coal Flowrate (lb/hr) 437,699 646,589 411,282 586,627

Natural Gas Flowrate (lb/hr) N/A N/A N/A N/A

HHV Thermal Input (kWth) 1,496,479 2,210,668 1,406,161 2,005,660

Net Plant HHV Efficiency (%) 36.8% 24.9% 39.1% 27.2%

Net Plant HHV Heat Rate (Btu/kW-hr) 9,276 13,724 8,721 12,534

Raw Water Usage, gpm 6,212 14,098 5,441 12,159

Total Plant Cost ($ x 1,000) 852,612 1,591,277 866,391 1,567,073

Total Plant Cost ($/kW) 1,549 2,895 1,575 2,870

LCOE (mills/kWh)1 64.0 118.8 63.3 114.8

CO2 Emissions (lb/MWh)2 1,780 225 1,681 209

CO2 Emissions (lb/MWh)3 1,886 278 1,773 254

SO2 Emissions (lb/MWh)2 0.7426 Negligible 0.7007 Negligible

NOx Emissions (lb/MWh)2 0.613 0.777 0.579 0.722

PM Emissions (lb/MWh)2 0.114 0.144 0.107 0.134

Hg Emissions (lb/MWh)2 1.00E-05 1.27E-05 9.45E-06 1.18E-05

1

 Based on an 85% capacity factor

2 Value is based on gross output

3

 Value is based on net output

Pulverized Coal Boiler

PC Subcritical PC Supercritical

The TPC for each of the PC cases is shown in Exhibit 4-47. 

The following observations can be made: 

• The TPC of the non-capture supercritical PC case is only incrementally greater than 

subcritical PC (less than 2 percent). The TPC of supercritical PC with CO2 capture is 0.9 

percent less than subcritical PC. 

• The capital cost penalty for adding CO2 capture in the subcritical case is 87 percent and 

in the supercritical case is 82 percent. The Econamine FG Plus cost includes a process 

contingency of approximately $100/kW in both the subcritical and supercritical cases. 

Eliminating the process contingency results in a CO2 capture cost penalty of 76 and 80 

percent for the supercritical and subcritical 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 circulating water pumps 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 97 MW (subcritical) and 83 MW (supercritical) to maintain the net 
Cost and Performance Comparison of Fossil Energy Power Plants 

419 

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 4-47 Total Plant Cost for PC Cases 

1,549

2,895

1,575

2,870

0

500

1,000

1,500

2,000

2,500

3,000

Total Plant Cost, $/kW

Subcritical PC Subcritical PC w/ CO2

Capture

Supercritical PC Supercritical PC w/ CO2

Capture

The LCOE is shown for the four PC cases in Exhibit 4-48. The following observations can be 

made: 

• Capital costs represent the largest fraction of LCOE in all cases, but particularly so in the 

CO2 capture cases. Fuel cost is the second largest component of LCOE, and capital 

charges and fuel costs combined represent about 83 percent of the total in all cases. 

• In the non-capture case the slight increase in capital cost in the supercritical case is more 

than offset by the efficiency gain so that the LCOE for supercritical PC is 1 percent less 

than subcritical despite having a nearly 2 percent higher TPC. 

• In the CO2 capture case, the cost differential between subcritical and supercritical PC is 

negligible (less than 1 percent), but the supercritical PC has a 3 percent lower LCOE 

because of the higher efficiency. 
Cost and Performance Comparison of Fossil Energy Power Plants 

420 

Exhibit 4-48 LCOE for PC Cases 

64.0

118.8

63.3

114.8

0

20

40

60

80

100

120

140

LCOE, mills/kWh

Subcritical PC Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2

Capture

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs

The sensitivity of LCOE to capacity factor is shown in Exhibit 4-49. Implicit in the curves is the 

assumption that an efficiency of greater than 85 percent can be achieved without the expenditure 

of additional capital. The subcritical and supercritical cases with no CO2 capture are nearly 

identical making it difficult to distinguish between the two lines. The LCOE increases more 

steeply at low capacity factor because the relatively high capital component is spread over fewer 

kilowatt-hours of generation. 

The sensitivity of LCOE to coal price is shown in Exhibit 4-50. As in the IGCC cases, the 

LCOE in the PC cases is relatively insensitive to coal price. 

As presented in Section 2.4 the cost of CO2 capture was calculated in two ways, CO2 removed 

and CO2 avoided. The results for the PC carbon capture cases are shown in Exhibit 4-51. 

The cost of CO2 captured and avoided is nearly identical for the subcritical and supercritical PC 

cases. The avoided cost is significantly higher than the captured cost because the gross output of 

the capture case is 83-96 MW higher than the non-capture case which reduces the amount of CO2

avoided between cases. 
Cost and Performance Comparison of Fossil Energy Power Plants 

421 

Exhibit 4-49 Sensitivity of LCOE to Capacity Factor for PC Cases 

0

50

100

150

200

250

300

0 10 20 30 40 50 60 70 80 90 100

Capacity Factor, %

LCOE, mills/kWh

Subcritical No Capture

Subcritical w/CO2 Capture

Supercritical No Capture

Supercritical w/CO2 Capture

Coal price is $1.80/MMBtu for all cases

Exhibit 4-50 Sensitivity of LCOE to Coal Price for PC Cases 

0

20

40

60

80

100

120

140

160

0 0.5 1 1.5 2 2.5 3 3.5 4

Fuel Price, $/MMBtu

LCOE, mills/kWh

Subcritical No Capture

Subcritical w/CO2 Capture

Supercritical No Capture

Supercritical w/CO2 Capture

Capacity Factor is 85 percent for all cases
Cost and Performance Comparison of Fossil Energy Power Plants 

422 

Exhibit 4-51 Cost of CO2 Captured and Avoided in PC Cases 

44

68

45

68

0

10

20

30

40

50

60

70

80

$/ton, CO2

Subcritical PC Supercritical PC

CO2 Removal Cost

CO2 Avoided Cost

The following observations can be made regarding plant performance with reference to 

Exhibit 4-46: 

• The efficiency of the supercritical PC plant is 2.3 percentage points higher than than the 

equivalent subcritical PC plant (39.1 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 [60] 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 (2400 psig/1000°F/1000°F). The 

higher steam cycle temperature in this study 566°C/566°C (1050°F/1050°F) results in a 

higher net efficiency. The same study reported a supercritical plant efficiency of 38.3 

percent with a steam cycle of 24.1 MPa/566°C/566°C (3500 psig/1050°F/1050°F). 

Again, the more aggressive steam conditions in this study, 593°C/593°C 

(1100°F/1100°F) resulted in a higher net efficiency. 

Similar results from an EPRI study using Illinois No. 6 coal were reported as follows 

[61]: 

o Subcritical PC efficiency of 35.7 percent with a steam cycle of 16.5 

MPa/538°C/538°C (2400 psig/1000°F/1000°F). 

o Supercritical PC efficiency of 38.3 percent with a steam cycle of 24.8 

MPa/593°C/593°C (3600 psig/1100°F/1100°F). 
Cost and Performance Comparison of Fossil Energy Power Plants 

423 

• The addition of CO2 capture to the two PC cases results in the same absolute efficiency 

impact, namely an 11.9 percentage point decrease. 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 circulating water 

pump and cooling tower fan auxiliary loads. The auxiliary load increases by 97 MW in 

the subcritical PC case and by 87 MW in the supercritical 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 supercritical cases and are higher for CO2 capture cases than 

non-capture cases because of the higher efficiencies of supercritical 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 

supercritical 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 

supercritical because of the lower efficiency. The capture cases result in a 90% reduction 

of CO2 for both subcritical and supercritical PC. 

• Raw water usage for all cases is dominated by cooling tower makeup requirements, 

which accounts for about 89 percent of raw water in non-capture cases and 93 percent of 

raw water in CO2 capture cases. The amount of raw water usage in the CO2 capture cases 

is greatly increased by the cooling water requirements of the Econamine process. 

Cooling water is required to: 

o Reduce the flue gas 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 flue gas 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 water demand, internal recycle and raw water usage are shown in Exhibit 4-52 for each 

of the PC cases. The only internal recycle stream that affects the overall balance in the noncapture cases is the boiler feedwater blowdown stream which is recycled to the cooling 

tower as makeup water. In the CO2 capture cases, additional water is recovered from the 

flue gas as it is cooled to the absorber temperature of 32°C (89°F). The condensate is 

treated and also used as cooling tower makeup. 
Cost and Performance Comparison of Fossil Energy Power Plants 

424 

Exhibit 4-52 Water Usage in PC Cases 

6,286 6,212

15,488

14,098

5,514 5,441

13,483

12,159

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

Water, gpm

Subcritical PC Subcritical PC w/

CO2 Capture

Supercritical PC Supercritical PC w/

CO2 Capture

Water Demand

Internal Recycle

Raw Water Usage
Cost and Performance Comparison of Fossil Energy Power Plants 

425 

5 NATURAL GAS COMBINED CYCLE PLANTS

Two natural gas combined cycle (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 a 2010 start up date. Each design consists of two 

advanced F class combustion turbine generators (CTG), two HRSG’s and one steam turbine 

generator (STG) in a multi-shaft 2x2x1 configuration. 

The NGCC cases are evaluated with and without carbon 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 combustion turbine. 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/510°C 

(2400 psig/1050°F/950°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. [52] 

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 NATURAL GAS SUPPLY SYSTEM

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. 

A new gas metering station is assumed to be added on the site, adjacent to the new combustion 

turbine. 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 COMBUSTION TURBINE

The combined cycle plant is based on two CTG’s. The combustion turbine generator is 

representative of the advanced F Class turbines with an ISO base rating of 184,400 kW when 

firing natural gas. [62] This machine is an axial flow, single spool, constant speed unit, with 

variable inlet guide vanes and dry LNB combustion system. 

Each combustion turbine generator 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. 
Cost and Performance Comparison of Fossil Energy Power Plants 

426 

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 Inlet Guide Vane 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 Low Pressure CO2 Fire Protection System 

MECHANICAL 

PACKAGE 

HVAC and Lighting, Air Compressor for Pneumatic System, Low Pressure 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 and Lighting, AC and DC Motor Control Centers, Generator Voltage 

Regulating Cabinet, Generator Protective Relay Cabinet, DC Distribution Panel, 

Battery Charger, Digital Control System with Local Control Panel (all control and 

monitoring functions as well as data logger and sequence of events recorder), 

Control System Valves and Instrumentation Communication link for interface with 

plant DCS Supervisory System, Bentley Nevada Vibration Monitoring System, Low 

Pressure CO2 Fire Protection System, Cable Tray and Conduit Provisions for 

Performance Testing including Test Ports, Thermowells, Instrumentation and DCS 

interface cards

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 

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 Comparison of Fossil Energy Power Plants 

427 

The generators would typically be provided with the combustion turbine 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 totally enclosed, water-air 

cooled (TEWAC), complete with excitation system, cooling, and protective relaying. 

5.1.3 HEAT RECOVERY STEAM GENERATOR

The HRSG is configured with HP, IP, and LP steam drums, and superheater, reheater, and 

economizer sections. The HP drum is supplied with feedwater 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 feedwater from an interstage bleed on the HP boiler feed pump. The IP 

steam from the drum is superheated to 482°C (900°F) and mixed with hot reheat steam from the 

reheat section at 510°C (950oF) and a portion of HP steam also at 510°C (950oF). The combined 

flows are admitted into the IP section of the steam turbine. The LP drum provides steam to the 

integral deaerator, and also to the LP turbine. 

The economizer sections heat condensate and feedwater (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 carbon steel. Each HRSG exhausts directly to the stack, which is 

fabricated from carbon steel plate materials and lined with Type 409 stainless steel. 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 NOX CONTROL SYSTEM

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 dry low 

NOx burner in the CTG. The dry LNB burners are a low NOx design and reduce the emissions 

to about 25 ppmvd (referenced to 15 percent O2). [63] 

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 flue gas path inside the HRSG 

between the high pressure and intermediate pressure 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 flue gas 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 flue gas 

temperature range for the catalyst is 260°C (500°F) to 343°C (650°F). 
Cost and Performance Comparison of Fossil Energy Power Plants 

428 

The ammonia storage and injection system consists of the unloading facilities, bulk storage tank, 

vaporizers, and dilution air skid. 

5.1.5 CARBON DIOXIDE RECOVERY FACILITY

A CDR facility is used in Case 14 to remove 90 percent of the CO2 in the flue gas exiting the 

HRSG, purify it, and compress it to a supercritical condition. It is assumed that all of the carbon 

in the natural gas is converted to CO2. The CDR is comprised of flue gas supply, CO2

absorption, solvent stripping and reclaiming, and CO2 compression and drying. 

The CO2 absorption/stripping/solvent reclaim process for Case 14 is based on the Fluor 

Econamine FG Plus 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 

flue gas 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. 

Flue Gas Cooling and Supply 

The function of the flue gas cooling and supply system is to transport flue gases from the HRSG 

to the CO2 absorption tower, and condition flue gas pressure, temperature and moisture content 

so it meets the requirements of the Econamine process. Temperature and hence moisture content 

of the flue gas exiting the HRSG is reduced in the Direct Contact Flue Gas Cooler, where flue 

gas is cooled using cooling water. 

The water condensed from the flue gas is collected in the bottom of the Direct Contact Flue Gas 

Cooler section and re-circulated to the top of the Direct Contact Flue Gas Cooler section via the 

Flue Gas Circulation Water Cooler, which rejects heat to the plant circulating water system. 

Level in the Direct Contact Flue Gas Cooler is controlled by directing the excess water to the 

cooling water return line. In the Direct Contact Flue Gas Cooler, flue gas is cooled beyond the 

CO2 absorption process requirements to 33°C (91°F) to account for the subsequent flue gas 

temperature increase of 14°C (25°F) in the flue gas blower. Downstream from the Direct 

Contact Flue Gas Cooler flue gas pressure is boosted in the flue gas blowers by approximately 

0.01 MPa (2 psi) to overcome pressure drop in the CO2 absorber tower. 

Circulating Water System 

Cooling water is provided from the NGCC plant circulating water system and returned to the 

NGCC 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 NGCC capture case is about 681,380 lpm (180,000 

gpm), which greatly exceeds the NGCC plant cooling water requirement of about 227,125 lpm 

(60,000 gpm).
Cost and Performance Comparison of Fossil Energy Power Plants 

429 

CO2 Absorption 

The cooled flue gas enters the bottom of the CO2 Absorber and flows up through the tower 

countercurrent to a stream of lean MEA-based solvent called Econamine FG Plus. 

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 gases and leaves 

the bottom of the absorber with the absorbed CO2. 

Water Wash Section 

The purpose of the Water Wash section is to minimize solvent losses due to mechanical 

entrainment and evaporation. The flue gas from the top of the CO2 Absorption section is 

contacted with a 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. 

Rich/Lean Amine Heat Exchange System 

The rich solvent from the bottom of the CO2 Absorber is preheated by the lean solvent from the 

Solvent Stripper in the Rich Lean Solvent Exchanger. The heated rich solvent is routed to the 

Solvent Stripper for removal of the absorbed CO2. The stripped solvent from the bottom of the 

Solvent Stripper is pumped via the Hot Lean Solvent Pumps through the Rich Lean Exchanger to 

the Solvent Surge Tank. Prior to entering the Solvent Surge Tank, a slipstream of the lean 

solvent is pumped via the Solvent Filter Feed Pump through the Solvent Filter Package to 

prevent buildup of contaminants in the solution. From the Solvent Surge Tank the lean solvent is 

pumped via the Warm Lean Solvent Pumps to the Lean Solvent Cooler for further cooling, after 

which the cooled lean solvent is returned to the CO2 Absorber, completing the circulating solvent 

circuit. 

Solvent Stripper 

The purpose of the Solvent Stripper is to separate the CO2 from the rich solvent feed exiting the 

bottom of the CO2 Absorber. The rich solvent is collected on a chimney tray below the bottom 

packed section of the Solvent Stripper and routed to the Solvent Stripper Reboilers where the 

rich solvent is heated by steam, stripping the CO2 from the solution. Steam is provided from the 

LP section of the steam turbine at about 0.47 MPa (68 psia) and 291°C (555°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 
Cost and Performance Comparison of Fossil Energy Power Plants 

430 

routed back to the Solvent Stripper as reflux, which aids in limiting the amount of solvent vapors 

entering the stripper overhead system. 

Solvent Stripper Reclaimer 

A small slipstream of the lean solvent from the Solvent Stripper bottoms is fed to the Solvent 

Stripper Reclaimer for the removal of high-boiling nonvolatile impurities (heat stable salts – 

HSS), volatile acids and iron products from the circulating solvent solution. The solvent bound 

in the HSS is recovered by reaction with caustic and heating with steam. The solvent reclaimer 

system reduces corrosion, foaming and fouling in the solvent system. The reclaimed solvent is 

returned to the Solvent Stripper and the spent solvent is pumped via the Solvent Reclaimer Drain 

Pump to the Solvent Reclaimer Drain Tank. 

Steam Condensate 

Steam condensate from the Solvent Stripper Reclaimer accumulates in the Solvent Reclaimer 

Condensate Drum and 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. 

Corrosion Inhibitor System 

A proprietary corrosion inhibitor is continuously injected into the CO2 Absorber rich solvent 

bottoms outlet line, the Solvent Stripper bottoms outlet line and the Solvent Stripper top tray. 

This constant injection is to help control the rate of corrosion throughout the CO2 recovery plant 

system. 

Gas Compression and Drying System 

In the compression section, the CO2 is compressed to 15.3 MPa (2,215 psia) by a six-stage 

centrifugal compressor. The discharge pressures of the stages were balanced to give reasonable 

power distribution and discharge temperatures across the various stages as shown in Exhibit 5-2. 

Power consumption for this large compressor was estimated assuming an isentropic efficiency of 

84 percent. During compression to 15.3 MPa (2,215 psia) in the multiple-stage, intercooled 

compressor, the CO2 stream is dehydrated to a dewpoint of -40oC (-40°F) with triethylene glycol. 

The virtually moisture-free supercritical CO2 stream is delivered to the plant battery limit as 

sequestration ready. CO2 TS&M costs were estimated and included in LCOE using the 

methodology described in Section 2.7. 

5.1.6 STEAM TURBINE

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. 

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 high-pressure span, flows through the turbine, and returns to the HRSG for 

reheating. The reheat steam flows through the reheat stop valves and intercept valves and enters 

the IP section at 2.3 MPa/510°C (328 psia/950°F). After passing through the IP section, the 
Cost and Performance Comparison of Fossil Energy Power Plants 

431 

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. 

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 closed-loop, 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 low-pressure 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 steam turbine 

generator 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 

distributed control system (DCS), and incorporates on-line repair capability. 

5.1.7 WATER AND STEAM SYSTEMS

Condensate 

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. 

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 
Cost and Performance Comparison of Fossil Energy Power Plants 

432 

discharging to the condenser is provided to maintain minimum flow requirements for the gland 

steam condenser and the condensate pumps. 

Feedwater 

The function of the feedwater (FW) system is to pump the various feedwater 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 feedwater. Each pump is 

provided with inlet and outlet isolation valves, outlet check valves, and individual minimum flow 

recirculation lines 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. 

Steam System 

The steam system is comprised of main, reheat, intermediate, and low-pressure 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. 

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. 

Circulating Water System 

The function of the circulating water system 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 circulating water pumps (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. 

The auxiliary cooling system is a closed loop 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. Combustion turbine generator lube oil coolers 

2. Combustion turbine generator air coolers 

3. Steam turbine generator lube oil coolers 

4. Steam turbine generator hydrogen coolers 

5. Boiler feed water pumps 

6. Air compressors 
Cost and Performance Comparison of Fossil Energy Power Plants 

433 

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 circulating water system. The additional cooling load imposed by the CDR is 

reflected in the significantly larger circulating water pumps and cooling tower in that case. 

Buildings and Structures 

Structures assumed for NGCC cases can be summarized as follows: 

1. Generation Building housing the STG 

2. Circulating Water Pump House 

3. Administration / Office / Control Room / Maintenance Building 

4. Water Treatment Building 

5. Fire Water Pump House 

5.1.8 ACCESSORY ELECTRIC PLANT

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. 

5.1.9 INSTRUMENTATION AND CONTROL

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. 

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 Comparison of Fossil Energy Power Plants 

434 

5.2 NGCC CASES 

This section contains an evalution 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/510°C (2400 psig/1050°F/950°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 relavant 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, 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 PROCESS DESCRIPTION

In this section the NGCC process without CO2 capture is described. The system description 

follows the block flow diagram (BFD) in 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 combustion turbine/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 1399°C (2550°F). The flue gas exits the turbine 

at 631°C (1167°F) (stream 3) and passes into the HRSG. The HRSG generates both the main 

steam and reheat steam for the steam turbine. Flue gas exits the HRSG at 104°C (220°F) and 

passes to the plant stack 
Cost and Performance Comparison of F

435 

Exhibit 5-3 Case 13 Process Flow Diagram, NGCC without CO2 Capture
Cost and Performance Comparison of Fossil Energy Power Plants 

 436 

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

123 4

V-L Mole Fraction 

Ar 0.0092 0.0000 0.0089 0.0089

CH4 0.0000 0.9390 0.0000 0.0000

C2H6 0.0000 0.0320 0.0000 0.0000

C3H8 0.0000 0.0070 0.0000 0.0000

C4H10 0.0000 0.0040 0.0000 0.0000

CO2 0.0003 0.0100 0.0405 0.0405

H2O 0.0099 0.0000 0.0869 0.0869

N2 0.7732 0.0080 0.7430 0.7430

O2 0.2074 0.0000 0.1207 0.1207

SO2 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (lbmol/hr) 120,220 4,793 250,304 250,304

V-L Flowrate (lb/hr) 3,469,190 82,591 7,103,560 7,103,560

Temperature (°F) 59 100 1,167 220

Pressure (psia) 14.7 450.0 15.2 15.2

Enthalpy (BTU/lb)A 13.1 34.4 360.5 106.6

Density (lb/ft3

) 0.076 1.291 0.025 0.059

Molecular Weight 28.857 17.232 28.380 28.380

A - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of Fossil Energy Power Plants 

 437 

5.2.2 KEY SYSTEM ASSUMPTIONS

System assumptions for Cases 13 and 14, NGCC with and without CO2 capture, are compiled in 

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) 16.5/566/510 

(2400/1050/950) 

16.5/566/510 

(2400/1050/950) 

Fuel Natural Gas Natural Gas 

Fuel Pressure at Plant Battery Limit MPa 

(psig) 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) 104 (220) 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 FG Plus 

CO2 Capture, % (A) N/A 90 

CO2 Sequestration N/A Off-site Saline 

Formation 

A. Removal efficiencies are based on the flue gas content 

Balance of Plant – Cases 13 and 14 

The balance of plant assumptions are common to both NGCC cases and are presented in 

Exhibit 5-6. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 438 

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) 

Ash N/A 

Gypsum N/A 

Limestone N/A 

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 Publicly 

Owned Treatment Works (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 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 is treated for 

chloride and metals, and discharged. 

5.2.3 SPARING PHILOSOPHY

Dual trains are used to accommodate the size of commercial gas turbines. There is no 

redundancy other than normal sparing of rotating equipment. The plant design consists of the 

following major subsystems: 

• Two advanced F class combustion turbine generators (2 x 50%) 

• Two 3-pressure reheat HRSGs with self supporting stacks and SCR systems (2 x 50%) 

• One 3-pressure reheat, triple-admission steam turbine generator (1 x 100%) 
Cost and Performance Comparison of Fossil Energy Power Plants 

 439 

• Two trains of Econamine FG Plus CO2 capture (2 x 50%) (Case 14 only) 

5.2.4 CASE 13 PERFORMANCE RESULTS

The plant produces a net output of 560 MW at a net plant efficiency of 50.8 percent (HHV 

basis). 

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 370,170 

Steam Turbine Power 200,030 

TOTAL POWER, kWe 570,200 

AUXILIARY LOAD SUMMARY, kWe 

Condensate Pumps 130 

Boiler Feedwater Pumps 2,970 

Miscellaneous Balance of Plant (Note 1) 500 

Gas Turbine Auxiliaries 700 

Steam Turbine Auxiliaries 100 

Amine System Auxiliaries N/A 

CO2 Compression N/A 

Circulating Water Pumps 2,450 

Cooling Tower Fans 1,260 

Transformer Loss 1,730 

TOTAL AUXILIARIES, kWe 9,840 

NET POWER, kWe 560,360 

Net Plant Efficiency (HHV) 50.8% 

Net Plant Heat Rate (Btu/kWh) 6,719 

CONDENSER COOLING DUTY, 106 kJ/h (106 Btu/h) 1,162 (1,102) 

CONSUMABLES 

Natural Gas, kg/h (lb/h) 74,926 (165,182) 

Thermal Input, kWt (HHV) 1,103,363 

Raw Water Usage, m3/min (gpm) 9.5 (2,512) 

Notes: 

1. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads 
Cost and Performance Comparison of Fossil Energy Power Plants 

 440 

Environmental Performance 

The environmental targets for emissions of NOx, SO2 and particulate matter were presented in 

Section 2.4. A summary of the plant air emissions for Case 13 is presented in Exhibit 5-8. 

Exhibit 5-8 Case 13 Air Emissions 

kg/GJ 

(lb/106 Btu) 

Tonne/year 

(ton/year) 

85% capacity factor 

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 (119) 1,507,000 

(1,662,000) 355 (783) 

CO2

1 361 (797) 

1

 CO2 emissions based on net power instead of gross power 

The operation of the modern, state-of-the-art gas turbine 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 capacity factor, 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. 

Exhibit 5-9 shows the overall water balance for the plant. Raw water is obtained from 

groundwater (50 percent) and from municipal sources (50 percent). The water usage represents 

only the contribution of raw water makeup. In some cases the water demand is greater than raw 

water makeup because of internal water recycle streams. For example, the boiler feedwater 

blowdown stream is re-used as makeup to the cooling tower, thus reducing the raw water 

requirement by that amount. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 441 

Exhibit 5-9 Case 13 Water Balance 

Water Use Water Demand, 

m3/min (gpm) 

Internal Recycle, 

m3/min (gpm) 

Raw Water Makeup, 

m3/min (gpm) 

BFW Makeup 0.1 (23) 0 0.1 (23) 

Cooling Tower Makeup 9.5 (2,511) 0.1 (23) 9.4 (2,488) 

Total 9.6 (2,534) 0.1 (23) 9.5 (2,511) 

Heat and Mass Balance Diagrams 

A heat and mass balance diagram is shown for the NGCC in Exhibit 5-10. 

An overall plant energy balance is provided in tabular form in Exhibit 5-11. The power out is 

the combined combustion turbine 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 Comparison of Fossil Energy Power Plants 

 442 

This page intentionally left blank 
443 

Exhibit 5-10 Case 13 Heat and Mass Balance, NGCC without CO2 Captu
444 

This page intentionally left blank 
Cost and Performance Comparison of Fossil Energy Power Plants 

 445 

Exhibit 5-11 Case 13 Overall Energy Balance (0°C [32°F] Reference) 

HHV Sensible + Latent Power Total 

Heat In (MMBtu/hr) 

Natural Gas 3,764.8 5.7 3,770.5 

Ambient Air 45.6 45.6 

Water 0.3 0.3 

Auxiliary Power 33.6 33.6 

Totals 3,764.8 51.5 33.6 3,850.0 

Heat Out (MMBtu/hr) 

Flue Gas Exhaust 757.5 757.5 

Condenser 1,102.0 1,102.0 

Process Losses (1) 13.2 13.2 

Power 1,977.3 1,977.3 

Totals 0.0 1,872.7 1,977.3 3,850.0 

(1) 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 Comparison of Fossil Energy Power Plants 

 446 

5.2.5 CASE 13 – MAJOR EQUIPMENT LIST

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 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

56 m3/min @ 3.1 MPa

(1,991 acfm @ 450 psia)

41 cm (16 in) standard wall 

pipe

56 m3/min (1,991 acfm)
Cost and Performance Comparison of Fossil Energy Power Plants 

 447 

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT 

Equipment 

No. Description Type OperatingQty. 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 electrodeionization 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)

5,300 lpm @ 18 m H2O

(1,400 gpm @ 60 ft H2O)

151 lpm @ 49 m H2O

(40 gpm @ 160 ft H2O)

13 m3/min (450 scfm)

15,520 lpm @ 21 m H2O

(4,100 gpm @ 70 ft H2O)

2

HP water: 4,088 lpm @ 2,103 m 

H2O (1,080 gpm @ 6,900 ft 

H2O)

IP water: 114 lpm @ 274 m H2O 

(30 gpm @ 900 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: 681 lpm @ 9.1 m H2O 

(180 gpm @ 30 ft H2O)

Design Condition

696,521 liters (184,000 gal)

4,883 lpm @ 85 m H2O

(1,290 gpm @ 280 ft H2O)

40 MMkJ/hr (38 MMBtu/hr)

3 Boiler Feedwater Pump

Horizontal, split case, 

multi-stage, 

centrifugal, with 

interstage bleed for IP 

and LP feedwater
Cost and Performance Comparison of Fossil Energy Power Plants 

 448 

ACCOUNT 4 GASIFIER, BOILER AND ACCESSORIES 

 N/A 

ACCOUNT 5 FLUE GAS CLEANUP 

 N/A 

ACCOUNT 6 COMBUSTION TURBINE GENERATORS AND AUXILIARIES 

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

185 MW 

210 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase

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 - 231,539 kg/h, 2.3 

MPa/510°C (510,456 lb/h, 335 

psig/950°F)

Design Condition

46 m (150 ft) high x

5.2 m (17 ft) diameter

Main steam - 240,660 kg/h, 16.5 

MPa/566°C (530,564 lb/h, 2,400 

psig/1,050°F)

1,773,548 kg/h (3,910,000 lb/h)

Space available for an additional 

catalyst layer

21 m3/min @ 91 cm WG

(750 scfm @ 36 in WG)

3.8 lpm @ 82 m H2O

(1 gpm @ 270 ft H2O)

87,065 liter (23,000 gal)
Cost and Performance Comparison of Fossil Energy Power Plants 

 449 

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES 

Equipment 

No. Description Type Operating 

Qty. Spares

1 Steam Turbine

Tandem compound, 

HP, IP, and twoflow LP turbines1 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

211 MW 

16.5 MPa/566°C/510°C 

(2400 psig/ 

1050°F/950°F)

1,276 MMkJ/hr, (1,210 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 

11°C (20°F)

230 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase

50% steam flow @ design 

steam conditions

Design Condition

ACCOUNT 9 COOLING WATER SYSTEM 

Equipment 

No. Description Type OperatingQty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell1 0

Design Condition

246,054 lpm @ 30.5 m

(65,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

1,365 MMkJ/hr (1,295 MMBtu/hr) 

heat load

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING 

 N/A 
Cost and Performance Comparison of Fossil Energy Power Plants 

 450 

ACCOUNT 11 ACCESSORY ELECTRIC PLANT 

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

2 STG Transformer Oil-filled 1 0

24 kV/4.16 kV, 09 MVA, 

3-ph, 60 Hz

Design Condition

24 kV/345 kV, 210 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 220 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

ACCOUNT 12 INSTRUMENTATION AND CONTROL 

Equipment 

No. Description Type OperatingQty. 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

2 DCS - Processor

Microprocessor with 

redundant 

input/output

N/A 0

Fully redundant, 25% spare

Design Condition

Operator stations/printers and 

engineering stations/printers

1
Cost and Performance Comparison of Fossil Energy Power Plants 

 451 

5.2.6 CASE 13 – COST ESTIMATING

The cost estimating methodology was described previously in Section 2.6. Exhibit 5-12 shows 

the total plant capital cost summary organized by cost account and Exhibit 5-13 shows a more 

detailed breakdown of the capital costs. Exhibit 5-14 shows the initial and annual O&M costs. 

The estimated TPC of the NGCC with no CO2 capture is $554/kW. No process contingency was 

included in this case because all elements of the technology are commercially proven. The 

project contingency is 10.7 percent of TPC. The 20-year LCOE is 68.4 mills/kWh. 
Cost and Performance Comparison of F

 452 

Exhibit 5-12 Case 13 Total Plant Cost Summary 

Client: USDOE/NETL Report 

Project: Bituminous Baseline Study

Case: Case 13 - NGCC w/o CO2

Plant Size: 560.4 MW,net Estimate Type: Conceptual Cost Base (Dec) 200

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencie

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Proje

 1 COAL & SORBENT HANDLING $0 $0 $0 $0 $0 $0 $0 $0  2 COAL & SORBENT PREP & FEED $0 $0 $0 $0 $0 $0 $0 $0  3 FEEDWATER & MISC. BOP SYSTEMS $21,803 $4,553 $6,567 $0 $0 $32,923 $2,758 $0 $ 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 

4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 

4.3 ASU/Oxidant Compression $0 $0 w/equip. $0 $0 $0 $0 $0 

4.4-4.9 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 4 $0 $0 $0 $0 $0 $0 $0 $0 

 5 Gas Cleanup & Piping $0 $0 $0 $0 $0 $0 $0 $0 

 5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $72,000 $0 $4,588 $0 $0 $76,589 $6,456 $0 $

6.2-6.9 Combustion Turbine Other $0 $681 $709 $0 $0 $1,390 $116 $0 

SUBTOTAL 6 $72,000 $681 $5,298 $0 $0 $77,979 $6,571 $0 $

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,000 $0 $4,200 $0 $0 $36,200 $3,060 $0 $

7.2-7.9 SCR System, Ductwork and Stack $1,177 $881 $1,044 $0 $0 $3,101 $263 $0 

SUBTOTAL 7 $33,177 $881 $5,244 $0 $0 $39,301 $3,323 $0 $

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $22,464 $0 $3,675 $0 $0 $26,139 $2,244 $0 $

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $8,415 $755 $5,340 $0 $0 $14,511 $1,171 $0 $

SUBTOTAL 8 $30,880 $755 $9,016 $0 $0 $40,651 $3,415 $0 $

 9 COOLING WATER SYSTEM $5,474 $4,330 $3,883 $0 $0 $13,686 $1,128 $0 $

10 ASH/SPENT SORBENT HANDLING SYS $0 $0 $0 $0 $0 $0 $0 $0 

11 ACCESSORY ELECTRIC PLANT $15,227 $3,466 $7,567 $0 $0 $26,261 $1,986 $0 $

12 INSTRUMENTATION & CONTROL $5,308 $555 $4,596 $0 $0 $10,459 $884 $0 $

13 IMPROVEMENTS TO SITE $1,635 $888 $4,384 $0 $0 $6,907 $608 $0 $

14 BUILDINGS & STRUCTURES $0 $3,920 $4,225 $0 $0 $8,145 $661 $0 $

TOTAL COST $185,504 $20,029 $50,779 $0 $0 $256,312 $21,334 $0 $3

TOTAL PLANT COST SUMMARY
Cost and Performance Comparison of F

 453 

Exhibit 5-13 Case 13 Total Plant Cost Details 

Client: USDOE/NETL Report 

Project: Bituminous Baseline Study

Case: Case 13 - NGCC w/o CO2

Plant Size: 560.4 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenc

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Proj

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 1.2 Coal Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 1.3 Coal Conveyors $0 $0 $0 $0 $0 $0 $0 $0 1.4 Other Coal Handling $0 $0 $0 $0 $0 $0 $0 $0 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 1. $0 $0 $0 $0 $0 $0 $0 $0 

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying incl w/2.3 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.3 Slurry Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 2. $0 $0 $0 $0 $0 $0 $0 $0 

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 FeedwaterSystem $2,501 $2,609 $2,147 $0 $0 $7,256 $597 $0 $3.2 Water Makeup & Pretreating $1,459 $152 $761 $0 $0 $2,373 $201 $0 3.3 Other Feedwater Subsystems $1,151 $390 $328 $0 $0 $1,869 $150 $0 3.4 Service Water Systems $174 $355 $1,151 $0 $0 $1,679 $145 $0 3.5 Other Boiler Plant Systems $1,167 $448 $1,037 $0 $0 $2,652 $222 $0 3.6 FO Supply Sys & Nat Gas $13,960 $483 $421 $0 $0 $14,864 $1,251 $0 $3.7 Waste Treatment Equipment $524 $0 $300 $0 $0 $824 $71 $0 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $869 $117 $421 $0 $0 $1,406 $121 $0 

SUBTOTAL 3. $21,803 $4,553 $6,567 $0 $0 $32,923 $2,758 $0 $

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS $0 $0 $0 $0 $0 $0 $0 $0 

4.2 Syngas Cooling ( w/ 4.1 w/4.1 $0 w/4.1 w/4.1 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $0 $0 w/equip. $0 $0 $0 $0 $0 4.4 LT Heat Recovery & FG Saturation $0 $0 $0 $0 $0 $0 $0 $0 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 4.6 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 w/4.1 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 4. $0 $0 $0 $0 $0 $0 $0 $0 

TOTAL PLANT COST SUMMARY
Cost and Performance Comparison of F

 454 

Exhibit 5-13 Case 13 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Report Dat

Project: Bituminous Baseline Study

Case: Case 13 - NGCC w/o CO2

Plant Size: 560.4 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project 

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $0 $0 $0 $0 $0 $0 $0 $0 5A.2 Elemental Sulfur Plant $0 $0 $0 $0 $0 $0 $0 $0 5A.3Mercury Removal $0 $0 $0 $0 $0 $0 $0 $0 5A.4 Shift Reactors $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 5A.7 Fuel Gas Piping $0 $0 $0 $0 $0 $0 $0 $0 5A.9 HGCU Foundations $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 5. $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 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $72,000 $0 $4,588 $0 $0 $76,589 $6,456 $0 $8,36.2 Open $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $681 $709 $0 $0 $1,390 $116 $0 $3

SUBTOTAL 6. $72,000 $681 $5,298 $0 $0 $77,979 $6,571 $0 $8,6

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,000 $0 $4,200 $0 $0 $36,200 $3,060 $0 $3,97.2 SCR System $1,177 $494 $694 $0 $0 $2,365 $202 $0 $37.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 7.9 HRSG,Duct & Stack Foundations $0 $386 $349 $0 $0 $736 $61 $0 $1

SUBTOTAL 7. $33,177 $881 $5,244 $0 $0 $39,301 $3,323 $0 $4,4

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $22,464 $0 $3,675 $0 $0 $26,139 $2,244 $0 $2,88.2 Turbine Plant Auxiliaries $153 $0 $352 $0 $0 $505 $44 $0 $8.3 Condenser & Auxiliaries $4,112 $0 $1,053 $0 $0 $5,165 $439 $0 $58.4 Steam Piping $4,150 $0 $2,733 $0 $0 $6,884 $524 $0 $1,18.9 TG Foundations $0 $755 $1,202 $0 $0 $1,957 $165 $0 $4

SUBTOTAL 8. $30,880 $755 $9,016 $0 $0 $40,651 $3,415 $0 $4,9

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $3,850 $0 $525 $0 $0 $4,375 $370 $0 $49.2 Circulating Water Pumps $1,122 $0 $67 $0 $0 $1,189 $91 $0 $19.3 Circ.Water System Auxiliaries $93 $0 $12 $0 $0 $105 $9 $0 $9.4 Circ.Water Piping $0 $2,752 $656 $0 $0 $3,409 $270 $0 $59.5 Make-up Water System $228 $0 $302 $0 $0 $529 $45 $0 $9.6 Component Cooling Water Sys $181 $217 $143 $0 $0 $541 $45 $0 $9.9 Circ.Water System Foundations& Structures $0 $1,361 $2,177 $0 $0 $3,538 $298 $0 $7

SUBTOTAL 9. $5,474 $4,330 $3,883 $0 $0 $13,686 $1,128 $0 $2,1

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $0 $0 $0 $0 $0 $0 $0 10.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $0 $0 $0 $0 $0 $0 $0 $0 10.7 Ash Transport & Feed Equipment $0 $0 $0 $0 $0 $0 $0 $0 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 10. $0 $0 $0 $0 $0 $0 $0 $0 

TOTAL PLANT COST SUMMARY
Cost and Performance Comparison of F

 455 

Exhibit 5-13 Case 13 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Report 

Project: Bituminous Baseline Study

Case: Case 13 - NGCC w/o CO2

Plant Size: 560.4 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenc

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $2,320 $0 $1,405 $0 $0 $3,724 $314 $0 11.2 Station Service Equipment $1,115 $0 $98 $0 $0 $1,213 $103 $0 11.3 Switchgear & Motor Control $1,421 $0 $243 $0 $0 $1,664 $138 $0 11.4 Conduit & Cable Tray $0 $695 $2,110 $0 $0 $2,805 $240 $0 11.5 Wire & Cable $0 $2,128 $1,338 $0 $0 $3,467 $225 $0 11.6 Protective Equipment $0 $519 $1,838 $0 $0 $2,356 $206 $0 11.7 Standby Equipment $95 $0 $90 $0 $0 $185 $16 $0 11.8 Main Power Transformers $10,277 $0 $140 $0 $0 $10,416 $707 $0 $11.9 Electrical Foundations $0 $124 $306 $0 $0 $430 $37 $0 

SUBTOTAL 11. $15,227 $3,466 $7,567 $0 $0 $26,261 $1,986 $0 $

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 12.4 Other Major Component Control $675 $0 $439 $0 $0 $1,114 $96 $0 12.5 Signal Processing Equipment W/12.7 $0 w/12.7 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $202 $0 $126 $0 $0 $328 $28 $0 12.7 Computer & Accessories $3,228 $0 $101 $0 $0 $3,329 $283 $0 12.8 Instrument Wiring & Tubing $0 $555 $1,085 $0 $0 $1,640 $124 $0 12.9 Other I & C Equipment $1,203 $0 $2,845 $0 $0 $4,049 $353 $0 

SUBTOTAL 12. $5,308 $555 $4,596 $0 $0 $10,459 $884 $0 $

13 Improvements to Site

13.1 Site Preparation $0 $87 $1,757 $0 $0 $1,845 $163 $0 13.2 Site Improvements $0 $801 $1,002 $0 $0 $1,803 $159 $0 13.3 Site Facilities $1,635 $0 $1,624 $0 $0 $3,259 $287 $0 

SUBTOTAL 13. $1,635 $888 $4,384 $0 $0 $6,907 $608 $0 $

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $212 $113 $0 $0 $325 $26 $0 14.2 Steam Turbine Building $0 $1,855 $2,503 $0 $0 $4,357 $357 $0 14.3 Administration Building $0 $429 $294 $0 $0 $723 $57 $0 14.4 Circulation Water Pumphouse $0 $143 $72 $0 $0 $215 $17 $0 14.5 Water Treatment Buildings $0 $317 $293 $0 $0 $610 $49 $0 14.6 Machine Shop $0 $372 $241 $0 $0 $613 $49 $0 14.7 Warehouse $0 $240 $147 $0 $0 $387 $31 $0 14.8 Other Buildings & Structures $0 $72 $53 $0 $0 $125 $10 $0 14.9 Waste Treating Building & Str. $0 $281 $509 $0 $0 $791 $66 $0 

SUBTOTAL 14. $0 $3,920 $4,225 $0 $0 $8,145 $661 $0 $

TOTAL COST $185,504 $20,029 $50,779 $0 $0 $256,312 $21,334 $0 $3

TOTAL PLANT COST SUMMARY
Cost and Performance Comparison of Fossil Energy Power Plants 

 456 

Exhibit 5-14 Case 13 Initial and Annual Operating and Maintenance Cost Summary 

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006

Case 13 - NGCC w/o CO2 Heat Rate-net(Btu/kWh): 6,719

 MWe-net: 560

 Capacity Factor: (%): 85

 OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 33.00 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 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 $1,879,020 $3.353

Maintenance Labor Cost $2,521,575 $4.500

Administrative & Support Labor $1,100,149 $1.963

TOTAL FIXED OPERATING COSTS $5,500,743 $9.816

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $3,782,362 $0.00091

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

 Water(/1000 gallons) 0 1,808 1.03 $0 $577,734 $0.00014

 Chemicals

 MU & WT Chem.(lb) 75,397 10,771 0.16 $12,425 $550,716 $0.00013

 Carbon (Mercury Removal) (lb.) 0 0 1.00 $0 $0 $0.00000

 COS Catalyst (lb) 0 0 0.60 $0 $0 $0.00000

 MEA Solvent (ton) 0 0 2,142.40 $0 $0 $0.00000

 Activated Carbon(lb) 0 0 1.00 $0 $0 $0.00000

 Corrosion Inhibitor 0 0 0.00 $0 $0 $0.00000

 SCR Catalyst (m3) w/equip. 0.08 5,500.00 $0 $140,093 $0.00003

 Ammonia (28% NH3) ton 55 8 190.00 $10,438 $462,620 $0.00011

Subtotal Chemicals $22,863 $1,153,429 $0.00028

 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 0 0.00 $0 $0 $0.00000

 Flyash (ton) 0 0 0.00 $0 $0 $0.00000

 Bottom Ash(ton) 0 0 0.00 $0 $0 $0.00000

 Subtotal-Waste Disposal $0 $0 $0.00000

 By-products & Emissions 

 Sulfur(tons) 0 0 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $22,863 $5,513,526 $0.00132

 Fuel(MMBtu) 2,710,842 90,361 6.75 $18,298,186 $189,233,740 $0.04535
Cost and Performance Comparison of Fossil Energy Power Plants 

 457 

5.2.7 CASE 14 – NGCC WITH CO2 CAPTURE

The plant configuration for Case 14 is the same as Case 13 with the exception that the 

Econamine FG Plus CDR technology was added for CO2 capture. The nominal net output 

decreases to 482 MW because, like the IGCC cases, the combustion turbine fixes the output and 

the CDR facility significantly increases the auxiliary power load. 

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 5-15 and Exhibit 5-16, respectively. Since the CDR facility process description was 

provided in Section 4.1.7, it is not repeated here. 

5.2.8 CASE 14 PERFORMANCE RESULTS

The Case 14 modeling assumptions were presented previously in Section 5.2.2. 

The plant produces a net output of 482 MW at a net plant efficiency of 43.7 percent (HHV 

basis). Overall plant performance is summarized in Exhibit 5-17 which includes auxiliary power 

requirements. The CDR facility, including CO2 compression, accounts for over 64 percent of the 

auxiliary plant load. The circulating water system (circulating water pumps and cooling tower 

fan) accounts for nearly 20 percent of the auxiliary load, largely due to the high cooling water 

demand of the CDR facility. 
Cost and Performance Comparison of F

 458 

Exhibit 5-15 Case 14 Process Flow Diagram, NGCC with CO2 Capture 
Cost and Performance Comparison of F

 459 

Exhibit 5-16 - Case 14 Stream Table, NGCC with CO2 Capture 

1234567

V-L Mole Fraction 

Ar 0.0092 0.0000 0.0089 0.0089 0.0098 0.0000 0.0000 CH4 0.0000 0.9390 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 C3H8 0.0000 0.0070 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 CO2 0.0003 0.0100 0.0405 0.0405 0.0045 0.9767 1.0000 H2O 0.0099 0.0000 0.0869 0.0869 0.0339 0.0233 0.0000 

N2 0.7732 0.0080 0.7430 0.7430 0.8188 0.0000 0.0000 

O2 0.2074 0.0000 0.1207 0.1207 0.1330 0.0000 0.0000 SO2 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 V-L Flowrate (lbmol/hr) 120,220 4,793 125,152 250,304 227,129 9,347 9,130 

V-L Flowrate (lb/hr) 3,469,190 82,591 3,551,780 7,103,560 6,448,730 405,714 401,794 Temperature (°F) 59 100 1,167 283 85 69 124 Pressure (psia) 14.7 450.0 15.2 15.2 14.7 23.5 2,214.7 Enthalpy (BTU/lb)A 13.1 34.4 360.5 122.6 36.1 11.2 -70.8 

Density (lb/ft3) 0.08 1.29 0.02 0.05 0.07 0.18 40.75 

Molecular Weight 28.86 17.23 28.38 28.38 28.39 43.40 44.01 

A - Reference conditions are 32.02 F & 0.089 PSIA 
Cost and Performance Comparison of Fossil Energy Power Plants 

 460 

Exhibit 5-17 Case 14 Plant Performance Summary 

POWER SUMMARY (Gross Power at Generator Terminals, kWe) 

Gas Turbine Power 370,170 

Steam Turbine Power 149,920 

TOTAL POWER, kWe 520,090 

AUXILIARY LOAD SUMMARY, kWe 

Condensate Pumps 60 

Boiler Feedwater Pumps 2,920 

Miscellaneous Balance of Plant (Note 1) 500 

Gas Turbine Auxiliaries 700 

Steam Turbine Auxiliaries 100 

Amine System Auxiliaries 9,580 

CO2 Compression 15,040 

Circulating Water Pumps 5,040 

Cooling Tower Fans 2,600 

Transformer Loss 1,660 

TOTAL AUXILIARIES, kWe 38,200 

NET POWER, kWe 481,890 

Net Plant Efficiency (HHV) 43.7% 

Net Plant Heat Rate (Btu/kWh) 7,813 

CONDENSER COOLING DUTY, 106 kJ/h (106 Btu/h) 550 (522) 

CONSUMABLES 

Natural Gas kg/h (lb/h) 74,926 (165,182) 

Thermal Input, kWt (HHV) 1,103,363 

Raw Water Usage, m3/min (gpm) 17.7 (4,680) 

 Notes: 

1. Includes plant control systems, lighting, HVAC and miscellaneous low voltage 

loads 
Cost and Performance Comparison of Fossil Energy Power Plants 

 461 

Environmental Performance 

The environmental targets for emissions of NOx, SO2 and particulate matter were presented in 

Section 2.4. A summary of the plant air emissions for Case 14 is presented in Exhibit 5-18. 

Exhibit 5-18 Case 14 Air Emissions 

kg/GJ 

(lb/106 Btu) 

Tonne/year 

(ton/year) 

85% capacity factor 

kg/MWh 

(lb/MWh) 

SO2 Negligible Negligible Negligible 

NOX 0.004 (0.009) 115 (127) 0.030 (0.066) 

Particulates Negligible Negligible Negligible 

Hg Negligible Negligible Negligible 

CO2 5.1 (12) 151,000 (166,000) 39 (86) 

CO2

1 42 (93) 

1

 CO2 emissions based on net power instead of gross power 

The operation of the modern, state-of-the-art gas turbine 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 capacity factor, 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 flue gas is removed in CDR facility. 

Exhibit 5-19 shows the overall water balance for the plant. Raw water is obtained from 

groundwater (50 percent) and from municipal sources (50 percent). The water usage represents 

only the contribution of raw water makeup. In some cases the water demand is greater than raw 

water makeup because of internal water recycle streams. For example, the boiler feedwater 

blowdown stream and condensate recovered from the flue gas prior to the CO2 absorber are reused as makeup to the cooling tower, thus reducing the raw water requirement by that amount. 

Exhibit 5-19 Case 14 Water Balance 

Water Use Water Demand, 

m3/min (gpm) 

Internal Recycle, 

m3/min (gpm) 

Raw Water Makeup, 

m3/min (gpm) 

BFW Makeup 0.1 (23) 0 0.1 (23) 

Cooling Tower Makeup 19.6 (5,176) 2.0 (518) 17.6 (4,658) 

Total 19.7 (5,199) 2.0 (518) 17.7 (4,681) 
Cost and Performance Comparison of Fossil Energy Power Plants 

 462 

Heat and Mass Balance Diagrams 

A heat and mass balance diagram is shown for the NGCC in Exhibit 5-20. 

An overall plant energy balance is provided in tabular form in Exhibit 5-21. The power out is 

the combined combustion turbine and steam turbine power prior to generator losses. The power 

at the generator terminals (shown in Exhibit 5-17) is calculated by multiplying the power out by 

a combined generator efficiency of 98.3 percent. 
463 

Exhibit 5-20 Case 14 Heat and Mass Balance, NGCC with CO2 Capture 
464 

This page intentionally left blank 
Cost and Performance Comparison of Fossil Energy Power Plants 

 465 

Exhibit 5-21 Case 14 Overall Energy Balance (0°C [32°F] Reference) 

HHV Sensible + Latent Power Total 

Heat In (MMBtu/hr) 

Natural Gas 3,764.8 5.7 3,770.5 

Ambient Air 45.6 45.6 

Water 0.3 0.3 

Auxiliary Power 130.3 130.3 

Totals 3,764.8 51.5 130.3 3,946.7 

Heat Out (MMBtu/hr) 

Flue Gas Exhaust 232.7 232.7 

Condenser 522.0 522.0 

CO2 Product (28.4) (28.4) 

CO2 Intercooling 80.9 80.9 

CO2 Process Losses 631.2 631.2 

CO2 Steam Losses 638.0 638.0 

Process Losses (1) 65.9 65.9 

Power 1,804.4 1,804.4 

Totals 0.0 2,142.3 1,804.4 3,946.7 

(1) 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 Comparison of Fossil Energy Power Plants 

 466 

5.2.9 CASE 14 MAJOR EQUIPMENT LIST

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 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

56 m3/min @ 3.1 MPa

(1,990 acfm @ 450 psia)

41 cm (16 in) standard wall pipe

56 m3/min (1,990 acfm)
Cost and Performance Comparison of Fossil Energy Power Plants 

 467 

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT 

Equipment 

No. Description Type OperatingQty. 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 electrodeionization unit

1 0

15 Liquid Waste Treatment 

System 1 0

1

166,559 liter (44,000 gal)

379 lpm (100 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)

10,978 lpm @ 18 m H2O

(2,900 gpm @ 60 ft H2O)

174 lpm @ 49 m H2O

(46 gpm @ 160 ft H2O)

13 m3/min (450 scfm)

15,520 lpm @ 21 m H2O

(4,100 gpm @ 70 ft H2O)

2

HP water: 3,937 lpm @ 2,103 m 

H2O (1,040 gpm @ 6,900 ft 

H2O)

IP water: 757 lpm @ 274 m H2O 

(200 gpm @ 900 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: 303 lpm @ 09 m H2O 

(80 gpm @ 30 ft H2O)

Design Condition

348,261 liters (92,000 gal)

2,309 lpm @ 85 m H2O

(610 gpm @ 280 ft H2O)

40 MMkJ/hr (38 MMBtu/hr)

3 Boiler Feedwater Pump

Horizontal, split case, 

multi-stage, 

centrifugal, with 

interstage bleed for IP 

and LP feedwater
Cost and Performance Comparison of Fossil Energy Power Plants 

 468 

ACCOUNT 4 GASIFIER, BOILER AND ACCESSORIES 

 N/A 

ACCOUNT 5B CARBON DIOXIDE RECOVERY 

Equipment 

No. Description Type OperatingQty. Spares

1 Econamine FG 

Plus

Amine-based carbon 

dioxide capture system 2 0

2

Carbon Dioxide 

Compression 

System

Integrally geared, multistage centrifugal 2 0

Design Condition

Flue gas flow rate: 1,772,187 kg/h 

(3,907,000 lb/h), Inlet CO2 

concentration: 6.3 wt%

100,698 kg/h @ 15.3 MPa

(222,000 lb/h @ 2,215 psia)

ACCOUNT 6 COMBUSTION TURBINE GENERATORS AND AUXILIARIES 

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

185 MW 

210 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase
Cost and Performance Comparison of Fossil Energy Power Plants 

 469 

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 - 223,433 kg/h, 2.3 

MPa/510°C (492,585 lb/h, 335 

psig/950°F)

Design Condition

46 m (150 ft) high x

4.5 m (15 ft) diameter

Main steam - 232,553 kg/h, 16.5 

MPa/566°C (512,691 lb/h, 2,400 

psig/1,050°F)

1,610,255 kg/h (3,550,000 lb/h)

Space available for an additional 

catalyst layer

21 m3/min @ 91 cm WG

(750 scfm @ 36 in WG)

3.8 lpm @ 82 m H2O

(1 gpm @ 270 ft H2O)

87,065 liter (23,000 gal)

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty.

1 Steam Turbine

Tandem compound, 

HP, IP, and twoflow LP turbines1

2 Steam Turbine Generator Hydrogen cooled, 

static excitation 1

3 Steam Bypass One per HRSG 2

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1

180 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase

50% steam flow @ design 

steam conditions

Design Condition

158 MW 

16.5 MPa/566°C/510°C 

(2400 psig/ 

1050°F/950°F)

601 MMkJ/hr, (570 

MMBtu/hr), Inlet water 

temperature 16°C (60°F), 

Water temperature rise 

11°C (20°F)
Cost and Performance Comparison of Fossil Energy Power Plants 

 470 

ACCOUNT 9 COOLING WATER SYSTEM 

Equipment 

No. Description Type OperatingQty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, multicell1 0

Design Condition

503,464 lpm @ 30.5 m

(133,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C 

(60°F) CWT / 27°C (80°F) HWT 

2,393 MMkJ/hr (2,270 MMBtu/hr) 

heat load

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING 

 N/A 

ACCOUNT 11 ACCESSORY ELECTRIC PLANT 

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

2 STG Transformer Oil-filled 1 0

24 kV/4.16 kV, 41 MVA, 

3-ph, 60 Hz

Design Condition

24 kV/345 kV, 210 MVA, 

3-ph, 60 Hz

24 kV/345 kV, 130 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, 6 MVA, 

3-ph, 60 Hz

750 kW, 480 V, 3-ph, 60 Hz
Cost and Performance Comparison of Fossil Energy Power Plants 

 471 

ACCOUNT 12 INSTRUMENTATION AND CONTROL 

Equipment 

No. Description Type OperatingQty. 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 Comparison of Fossil Energy Power Plants 

 472 

5.2.10 CASE 14 – COST ESTIMATING

The cost estimating methodology was described previously in Section 2.6. Exhibit 5-22 shows 

the total plant capital cost summary organized by cost account and Exhibit 5-23 shows a more 

detailed breakdown of the capital costs. Exhibit 5-24 shows the initial and annual O&M costs. 

The estimated TPC of the NGCC with CO2 capture is $1,169/kW. Process contingency 

represents 5.0 percent of the TPC and project contingency represents 13.3 percent. The 20-year 

LCOE, including CO2 TS&M costs of 2.9 mills/kWh, is 97.4 mills/kWh. 
Cost and Performance Comparison of F

 473 

Exhibit 5-22 Case 14 Total Plant Cost Summary 

Client: USDOE/NETL Report D

Project: Bituminous Baseline Study

Case: Case 14 - NGCC w/ CO2

Plant Size: 481.9 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencie

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Proje

 1 COAL & SORBENT HANDLING $0 $0 $0 $0 $0 $0 $0 $0 

 2 COAL & SORBENT PREP & FEED $0 $0 $0 $0 $0 $0 $0 $0 

 3 FEEDWATER & MISC. BOP SYSTEMS $23,544 $4,970 $8,285 $0 $0 $36,798 $3,088 $0 $6 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $0 $0 w/equip. $0 $0 $0 $0 $0 

4.4-4.9 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 4 $0 $0 $0 $0 $0 $0 $0 $0 

 5 Gas Cleanup & Piping $0 $0 $0 $0 $0 $0 $0 $0 

 5B CO2 REMOVAL & COMPRESSION $121,446 $0 $35,469 $0 $0 $156,915 $13,337 $27,564 $39

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $72,000 $0 $4,588 $0 $0 $76,588 $6,456 $0 $8

6.2-6.9 Combustion Turbine Other $0 $681 $709 $0 $0 $1,390 $116 $0 

SUBTOTAL 6 $72,000 $681 $5,298 $0 $0 $77,979 $6,571 $0 $8

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,000 $0 $4,200 $0 $0 $36,200 $3,060 $0 $3

7.2-7.9 SCR System, Ductwork and Stack $1,177 $881 $1,044 $0 $0 $3,101 $263 $0 

SUBTOTAL 7 $33,177 $881 $5,244 $0 $0 $39,301 $3,323 $0 $4

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $19,753 $0 $3,134 $0 $0 $22,887 $1,964 $0 $2

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $7,020 $606 $4,906 $0 $0 $12,532 $1,003 $0 $1

SUBTOTAL 8 $26,772 $606 $8,041 $0 $0 $35,419 $2,967 $0 $4

 9 COOLING WATER SYSTEM $8,060 $6,365 $5,482 $0 $0 $19,908 $1,638 $0 $3

10 ASH/SPENT SORBENT HANDLING SYS $0 $0 $0 $0 $0 $0 $0 $0 11 ACCESSORY ELECTRIC PLANT $15,809 $5,267 $9,893 $0 $0 $30,969 $2,356 $0 $312 INSTRUMENTATION & CONTROL $6,914 $723 $5,986 $0 $0 $13,622 $1,151 $681 $1

13 IMPROVEMENTS TO SITE $1,643 $893 $4,406 $0 $0 $6,942 $611 $0 $1

14 BUILDINGS & STRUCTURES $0 $3,885 $4,066 $0 $0 $7,952 $644 $0 $1

TOTAL COST $309,365 $24,270 $92,170 $0 $0 $425,805 $35,687 $28,245 $74

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 474 

Exhibit 5-23 Case 14 Total Plant Cost Details 

Client: USDOE/NETL Report 

Project: Bituminous Baseline Study

Case: Case 14 - NGCC w/ CO2

Plant Size: 481.9 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenci

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Proj

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 1.2 Coal Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 1.3 Coal Conveyors $0 $0 $0 $0 $0 $0 $0 $0 1.4 Other Coal Handling $0 $0 $0 $0 $0 $0 $0 $0 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 1. $0 $0 $0 $0 $0 $0 $0 $0 

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying incl w/2.3 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.3 Slurry Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 2. $0 $0 $0 $0 $0 $0 $0 $0 

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 FeedwaterSystem $2,425 $2,530 $2,082 $0 $0 $7,037 $579 $0 $3.2 Water Makeup & Pretreating $2,271 $237 $1,185 $0 $0 $3,692 $312 $0 3.3 Other Feedwater Subsystems $1,116 $378 $318 $0 $0 $1,813 $145 $0 3.4 Service Water Systems $270 $552 $1,791 $0 $0 $2,613 $226 $0 3.5 Other Boiler Plant Systems $1,815 $696 $1,614 $0 $0 $4,126 $346 $0 3.6 FO Supply Sys & Nat Gas $13,946 $458 $399 $0 $0 $14,803 $1,246 $0 $3.7 Waste Treatment Equipment $815 $0 $467 $0 $0 $1,282 $111 $0 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $885 $119 $428 $0 $0 $1,432 $124 $0 

SUBTOTAL 3. $23,544 $4,970 $8,285 $0 $0 $36,798 $3,088 $0 $

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS $0 $0 $0 $0 $0 $0 $0 $0 

4.2 Syngas Cooling ( w/ 4.1 w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $0 $0 w/equip. $0 $0 $0 $0 $0 4.4 LT Heat Recovery & FG Saturation $0 $0 $0 $0 $0 $0 $0 $0 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 4.6 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 w/4.1 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 4. $0 $0 $0 $0 $0 $0 $0 $0 

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 475 

Exhibit 5-23 Case 14 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Report Dat

Project: Bituminous Baseline Study

Case: Case 14 - NGCC w/ CO2

Plant Size: 481.9 MW,net Estimate Type: Conceptual Cost Base (Dec) 2006 

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies 

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project 

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $0 $0 $0 $0 $0 $0 $0 $0 5A.2 Elemental Sulfur Plant $0 $0 $0 $0 $0 $0 $0 $0 5A.3Mercury Removal $0 $0 $0 $0 $0 $0 $0 $0 5A.4 Shift Reactors $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 5A.7 Fuel Gas Piping $0 $0 $0 $0 $0 $0 $0 $0 5A.9 HGCU Foundations $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 

 5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $106,600 $0 $31,220 $0 $0 $137,821 $11,715 $27,564 $35,45B.2 CO2 Compression & Drying $14,846 $0 $4,248 $0 $0 $19,094 $1,623 $0 $4,1

SUBTOTAL 5. $121,446 $0 $35,469 $0 $0 $156,915 $13,337 $27,564 $39,5

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $72,000 $0 $4,588 $0 $0 $76,588 $6,456 $0 $8,36.2 Open $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $681 $709 $0 $0 $1,390 $116 $0 $3

SUBTOTAL 6. $72,000 $681 $5,298 $0 $0 $77,979 $6,571 $0 $8,6

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,000 $0 $4,200 $0 $0 $36,200 $3,060 $0 $3,97.2 SCR System $1,177 $494 $694 $0 $0 $2,365 $202 $0 $37.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 7.9 HRSG,Duct & Stack Foundations $0 $386 $349 $0 $0 $736 $61 $0 $1

SUBTOTAL 7. $33,177 $881 $5,244 $0 $0 $39,301 $3,323 $0 $4,4

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $19,753 $0 $3,134 $0 $0 $22,887 $1,964 $0 $2,48.2 Turbine Plant Auxiliaries $135 $0 $303 $0 $0 $438 $38 $0 $8.3 Condenser & Auxiliaries $2,643 $0 $845 $0 $0 $3,488 $297 $0 $38.4 Steam Piping $4,242 $0 $2,794 $0 $0 $7,036 $535 $0 $1,18.9 TG Foundations $0 $606 $964 $0 $0 $1,570 $132 $0 $3

SUBTOTAL 8. $26,772 $606 $8,041 $0 $0 $35,419 $2,967 $0 $4,3

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $5,487 $0 $749 $0 $0 $6,236 $527 $0 $69.2 Circulating Water Pumps $1,832 $0 $117 $0 $0 $1,949 $149 $0 $29.3 Circ.Water System Auxiliaries $141 $0 $19 $0 $0 $160 $14 $0 $9.4 Circ.Water Piping $0 $4,191 $999 $0 $0 $5,191 $411 $0 $89.5 Make-up Water System $325 $0 $430 $0 $0 $755 $64 $0 $19.6 Component Cooling Water Sys $276 $330 $218 $0 $0 $824 $68 $0 $19.9 Circ.Water System Foundations& Structures $0 $1,844 $2,950 $0 $0 $4,794 $404 $0 $1,0

SUBTOTAL 9. $8,060 $6,365 $5,482 $0 $0 $19,908 $1,638 $0 $3,0

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $0 $0 $0 $0 $0 $0 $0 10.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $0 $0 $0 $0 $0 $0 $0 $0 10.7 Ash Transport & Feed Equipment $0 $0 $0 $0 $0 $0 $0 $0 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $0 $0 $0 $0 $0 $0 $0 

SUBTOTAL 10. $0 $0 $0 $0 $0 $0 $0 $0 

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of F

 476 

Exhibit 5-23 Case 14 Total Plant Cost Details (Continued) 

Client: USDOE/NETL Report 

Project: Bituminous Baseline Study

Case: Case 14 - NGCC w/ CO2

Plant Size: 481.9 MW,net Estimate Type: Conceptual Cost Base (Dec) 20

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingenci

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Pro

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $2,198 $0 $1,331 $0 $0 $3,529 $298 $0 11.2 Station Service Equipment $1,829 $0 $160 $0 $0 $1,989 $169 $0 11.3 Switchgear & Motor Control $2,330 $0 $399 $0 $0 $2,729 $226 $0 11.4 Conduit & Cable Tray $0 $1,140 $3,460 $0 $0 $4,600 $393 $0 11.5 Wire & Cable $0 $3,490 $2,194 $0 $0 $5,685 $369 $0 11.6 Protective Equipment $0 $520 $1,844 $0 $0 $2,364 $207 $0 11.7 Standby Equipment $91 $0 $86 $0 $0 $177 $15 $0 11.8 Main Power Transformers $9,361 $0 $131 $0 $0 $9,492 $644 $0 11.9 Electrical Foundations $0 $116 $287 $0 $0 $403 $34 $0 

SUBTOTAL 11. $15,809 $5,267 $9,893 $0 $0 $30,969 $2,356 $0 

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 12.4 Other Major Component Control $879 $0 $572 $0 $0 $1,451 $125 $73 12.5 Signal Processing Equipment W/12.7 $0 w/12.7 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $263 $0 $164 $0 $0 $427 $37 $21 12.7 Computer & Accessories $4,205 $0 $131 $0 $0 $4,336 $368 $217 12.8 Instrument Wiring & Tubing $0 $723 $1,413 $0 $0 $2,136 $161 $107 12.9 Other I & C Equipment $1,568 $0 $3,706 $0 $0 $5,273 $460 $264 

SUBTOTAL 12. $6,914 $723 $5,986 $0 $0 $13,622 $1,151 $681 

13 Improvements to Site

13.1 Site Preparation $0 $88 $1,766 $0 $0 $1,854 $164 $0 13.2 Site Improvements $0 $805 $1,007 $0 $0 $1,812 $159 $0 13.3 Site Facilities $1,643 $0 $1,633 $0 $0 $3,276 $288 $0 

SUBTOTAL 13. $1,643 $893 $4,406 $0 $0 $6,942 $611 $0 

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $222 $119 $0 $0 $341 $27 $0 14.2 Steam Turbine Building $0 $1,593 $2,149 $0 $0 $3,742 $307 $0 14.3 Administration Building $0 $437 $300 $0 $0 $736 $59 $0 14.4 Circulation Water Pumphouse $0 $167 $84 $0 $0 $250 $20 $0 14.5 Water Treatment Buildings $0 $484 $447 $0 $0 $931 $75 $0 14.6 Machine Shop $0 $379 $245 $0 $0 $624 $49 $0 14.7 Warehouse $0 $245 $150 $0 $0 $394 $31 $0 14.8 Other Buildings & Structures $0 $73 $54 $0 $0 $127 $10 $0 14.9 Waste Treating Building & Str. $0 $287 $519 $0 $0 $805 $67 $0 

SUBTOTAL 14. $0 $3,885 $4,066 $0 $0 $7,952 $644 $0 

TOTAL COST $309,365 $24,270 $92,170 $0 $0 $425,805 $35,687 $28,245 $

TOTAL PLANT COST SUMMARY 
Cost and Performance Comparison of Fossil Energy Power Plants 

 477 

Exhibit 5-24 Case 14 Initial and Annual Operating and Maintenance Cost Summary 

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006

Case 14 - NGCC w/ CO2 Heat Rate-net(Btu/kWh): 7,813

 MWe-net: 482

 Capacity Factor: (%): 85

 OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 33.00 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 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 $2,378,839 $4.936

Maintenance Labor Cost $4,034,866 $8.373

Administrative & Support Labor $1,603,426 $3.327

TOTAL FIXED OPERATING COSTS $8,017,131 $16.637

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $6,052,299 $0.00169

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

 Water(/1000 gallons) 0 3,370.32 1.00 $0 $1,045,642 $0.00029

 Chemicals

 MU & WT Chem.(lb) 140,555.73 20,079.39 0.16 $21,888 $970,101 $0.00027

 Carbon (Mercury Removal) (lb.) 0.00 0.00 1.00 $0 $0 $0.00000

 COS Catalyst (lb) 0.00 0.00 0.60 $0 $0 $0.00000

 MEA Solvent (ton) 342.00 0.48 2,142.40 $732,701 $319,046 $0.00009

 Activated Carbon(lb) 210,384.00 576.00 1.00 $210,384 $178,704 $0.00005

 Corrosion Inhibitor 1.00 0.00 0.00 $47,000 $2,250 $0.00000

 SCR Catalyst (m3) w/equip. 0.08 5,500.00 $0 $140,093 $0.00004

 Ammonia (28% NH3) ton 54.94 7.85 190.00 $10,438 $462,620 $0.00013

Subtotal Chemicals $1,022,410 $2,072,814 $0.00058

 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

 Spent Mercury Catalyst (lb.) 0.00 0.00 0.00 $0 $0 $0.00000

 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 & Emissions 

 Sulfur(tons) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $1,022,410 $9,170,755 $0.00256

 Fuel(MMbtu) 2,710,805 90,360 6.75 $18,297,932 $189,231,113 $0.05274
Cost and Performance Comparison of Fossil Energy Power Plants 

 478 

5.3 NGCC CASE SUMMARY 

The performance results of the two NGCC plant configurations modeled in this study are 

summarized in Exhibit 5-25. 

Exhibit 5-25 Estimated Performance and Cost Results for NGCC Cases 

Case 13 Case 14

CO2 Capture No Yes

Gross Power Output (kWe) 570,200 520,090

Auxiliary Power Requirement (kWe) 9,840 38,200

Net Power Output (kWe) 560,360 481,890

Coal Flowrate (lb/hr) N/A N/A

Natural Gas Flowrate (lb/hr) 165,182 165,182

HHV Thermal Input (kWth) 1,103,363 1,103,363

Net Plant HHV Efficiency (%) 50.8% 43.7%

Net Plant HHV Heat Rate (Btu/kW-hr) 6,719 7,813

Raw Water Usage, gpm 2,511 4,681

Total Plant Cost ($ x 1,000) 310,710 564,628

Total Plant Cost ($/kW) 554 1,172

LCOE (mills/kWh)1 68.4 97.4

CO2 Emissions (lb/MWh)2 783 85.8

CO2 Emissions (lb/MWh)3 797 93

SO2 Emissions (lb/MWh)2 Negligible Negligible

NOx Emissions (lb/MWh)2 0.060 0.066

PM Emissions (lb/MWh)2 Negligible Negligible

Hg Emissions (lb/MWh)2 Negligible Negligible

1

 Based on an 85% capacity factor

2 Value is based on gross output

3

 Value is based on net output

NGCC

Advanced F Class

The TPC for the two NGCC cases is shown in Exhibit 5-26. The capital cost of the non-capture 

case, $554/kW, is the lowest of all technologies studied by at least 64 percent. Addition of CO2

capture more than doubles the capital cost, but NGCC with capture is still the least capital 

intensive of all the capture technologies by at least 51 percent. The process contingency 

included for the Econamine process totals $57/kW, which represents 5 percent of TPC. 

The LCOE for NGCC cases is heavily dependent on the price of natural gas as shown in 

Exhibit 5-27. The fuel component of LCOE represents 78 percent of the total in the non-capture 

case and 63 percent of the total in the CO2 capture case. Because LCOE has a small capital 

component, it is less sensitive to capacity factor than the more capital intensive PC and IGCC 

cases. The decrease in net kilowatt-hours produced is nearly offset by a corresponding decrease 

in fuel cost. The CO2 TS&M component of LCOE is only 3 percent of the total in the CO2

capture case. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 479 

Exhibit 5-26 TPC of NGCC Cases 

554

1,172

0

200

400

600

800

1,000

1,200

1,400

Total Plant Cost, $/kW

NGCC NGCC w/ CO2 Capture

Exhibit 5-27 LCOE of NGCC Cases 

68.4

97.4

0

20

40

60

80

100

120

LCOE, mills/kWh

NGCC NGCC w/ CO2 Capture

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs
Cost and Performance Comparison of Fossil Energy Power Plants 

 480 

The sensitivity of NGCC to capacity factor is shown in Exhibit 5-28. Unlike the PC and IGCC 

case, NGCC is relatively insensitive to capacity factor but highly sensitive to fuel cost as shown 

in Exhibit 5-29. A 33 percent increase in natural gas price (from $6 to $8/MMBtu) results in a 

LCOE 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 cost of CO2 capture was calculated in two ways, CO2 removed 

and CO2 avoided. In the NGCC case the cost of CO2 removed is $70/ton and the cost of CO2

avoided is $83/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. 

Exhibit 5-28 Sensitivity of LCOE to Capacity Factor in NGCC Cases 

0

20

40

60

80

100

120

140

160

180

0 10 20 30 40 50 60 70 80 90 100

Capacity Factor, %

LCOE, mills/kWh

NGCC No Capture

NGCC w/CO2

Capture

Natural gas price is $6.75/MMBtu in all cases

The following observations can be made regarding plant performance with reference to 

Exhibit 5-25: 

• The efficiency of the NGCC case with no CO2 capture is 50.8 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). [64] Adjusting the result from this study to an LHV basis results in an 

efficiency of 56.3 percent. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 481 

Exhibit 5-29 Sensitivity of LCOE to Fuel Price in NGCC Cases 

0

20

40

60

80

100

120

140

0 2 4 6 8 10 12

Natural Gas Price, $/MMBtu

LCOE, mills/kWh

NGCC No Capture

NGCC w/CO2 Capture

Capacity factor is 85 percent for all cases

• The efficiency penalty to add CO2 capture in the NGCC case is 7.1 percentage points. 

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 circulating water pumps and 

the cooling tower fan. CO2 capture results in a 28 MW increase in auxiliary load 

compared to the non-capture case. 

• The energy penalty for NGCC is less than PC (7.1 percentage points for NGCC 

compared to 11.9 percentage points for PC) mainly because natural gas has a lower 

carbon intensity than coal. In the PC cases, about 589,670 kg/h (1.3 million lb/h) of 

CO2 must be captured and compressed while in the NGCC case only about 181,437 

kg/h (400,000 lb/h) 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. 
Cost and Performance Comparison of Fossil Energy Power Plants 

 482 

• NOx emissions are identical for the two NGCC cases on a heat input and mass basis. 

This is a result of the fixed output from the gas turbine (25 ppmv at 15 percent O2) 

and the fixed efficiency of the SCR (90 percent). 

The water demand, internal recycle and raw water usage are shown in Exhibit 5-30 for the 

NGCC cases. The following observations can be made: 

• Water demand increases 105 percent and raw water usage 86 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 over 99 percent of the raw water usage in both 

NGCC cases. The only internal recycle stream in the non-capture case is the boiler 

feedwater blowdown, which is recycled to the cooling tower. In the CO2 capture case 

condensate is recovered from the flue gas as it is cooled to the absorber temperature 

of 32°C (89°F) and is also recycled to the cooling tower. 

Exhibit 5-30 Water Usage in NGCC Cases 

2,534 2,511

5,199

4,681

0

1,000

2,000

3,000

4,000

5,000

6,000

Water, gpm

NGCC NGCC w/ CO2 Capture

Water Demand

Internal Recycle

Raw Water Usage
Cost and Performance Comparison of Fossil Energy Power Plants 

 483 

6 REFERENCES

1 Coal Specifications for Quality Guidelines, Revision 0, May 31, 2005 (Unpublished) 

2 Personal Communication between John Wimer (NETL) and Diane Kearney (EIA), AEO 

2007 Reference Case NEMS model forecasted that the average cost of delivering 

(transport cost only) Eastern Interior coal to electric utilities in Illinois and surrounding 

states would be $2.28 (year 2005 dollars) in 2010, March 27, 2007 

3 “Annual Energy Outlook 2007 with Projections to 2030,” AEO Reference Case Table 19, 

EIA, February 2007 

4 Quality Guidelines for Energy System Studies, prepared by DOE NETL Office of 

Systems and Policy Support, June 4, 2003 

5 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

6 US EPA Green Book Nonattainment Area Map, 

http://www.epa.gov/oar/oaqps/greenbk/mapnpoll.html

7 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 

8 2004 Keystone Coal Industry Manual, A Mining Media Publication 

9 CoalFleet User Design Basis Specification for Coal-Based Integrated Gasification 

Combined Cycle (IGCC) Power Plants: Version 4, EPRI, Palo Alto, CA: 2006. 1012227 

10 Thomas, Greg, “Delivering the IGCC Solution”, GE Energy January 31, 2006 

11 Morehead, Harry and Hannemann, Frank, “Siemens Technology Improvements Enhance 

IGCC Plant Economics,” Gasification Technologies 2005, San Francisco, CA, October 

2005

12 Telephone communication with David Denton, Eastman Chemical Co. 

13 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 

14 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 

15 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 
Cost and Performance Comparison of Fossil Energy Power Plants 

 484 

16 Gleitz, Robert, “Advanced GT Technology”, GE Power Systems, July 2003 

17 Eldrid, Roberta, Kaufman, Lynda and Marks, Paul, “The 7FB: The Next Evolution of the 

F Gas Turbine”, GER-4194, April 2001 

18 “Resolution of “Natural Gas” and “Pipeline Natural Gas” Definition Issues, EPA’s Clean 

Air Market Programs, http://www.epa.gov/airmarkt/monitoring/gasdef/

19 North American Electric Reliability Council website, http://www.nerc.com/~gads/

20 “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 

21 Higman, Christopher, DellaVilla, Sal, and Steele, Bob, “The Reliability of Integrated 

Gasification Combined Cycle (IGCC) Power Generation Units, Achema 2006, May 2006 

22 Cooling Tower Fundamentals, ed. John C. Hensley, 2nd Edition, The Marley Cooling 

Tower Company, Mission, Kansas, 1985 

23 Economic Evaluation of CO2 Storage and Sink Enhancement Options, Tennessee Valley 

Authority, NETL and EPRI, December 2002

24 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

25 Ciferno, Jared P. and McIlvried, Howard, “CO2 Flow Modeling and Pipe Diameter 

Determination,” February, 2003

26 “Overview of Monitoring Requirements for Geologic Storage Projects,” International 

Energy Agency Greenhouse Gas R&D Programme, Report Number PH4/29, November 

2004

27 Power Systems Financial Model Version 5.0, September 2006 

28 Universal Industrial Gases, Inc., http://www.uigi.com/cryodist.html

29 Jenkins, Steve, “Real-World Experience with IGCC – Lessons Learned in Design, 

Permitting, Operations and Maintenance,” URS Corporation, August 17, 2005 

30 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 

31 Jaeger, Harry, “Plant Design Net Rated 644 MW and 38% HHV on Low Rank Coal,” 

Gas Turbine World, March-April 2006 

32 Personal communication, Ray Drnevich, Praxair, Inc., ray_drnevich@praxair.com, 

November 2002 

33 http://www.calgoncarbon.com/bulletins/Mercury_Removal_Gas_Streams.htmn 

34 http://www.calgoncarbon.com/bulletins/HGR-P.htm 

35 http://www.calgoncarbon.com/bulletins/TYPE_HGR.htm 
Cost and Performance Comparison of Fossil Energy Power Plants 

 485 

36 “Process Screening Study of Alternative Gas Treating and Sulfur Removal Systems for 

IGCC Power Plant Applications,” EPRI AP-5505, December 1987 

37 http://www.coptechnologysolutions.com/egas/process_overview/index.htm

38 “Process Screening Analysis of Alternative Gas Treating and Sulfur Removal for 

Gasification,” Revised Final Report, December 2002, SFA Pacific for NETL 

39 Tampa Electric Polk Power Station Integrated Gasification Combined Cycle Project, 

Final Technical Report, August 2002 

40 Wabash River Coal Gasification Repowering Project, Final Technical Report, August 

2000 

41 IGCC Puertollano: A Clean Coal Gasification Plant, ELCOGAS, 2001 

42 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 

43 GEI-41040G, “Process Specification for Fuel Gases for Combustion in Heavy-Duty 

Turbines,” January 2002 

44 GEK-4189, “Design Considerations for Heated Gas Fuel” 

45 Rigdon, Robert and Schmoe, Lee, “The IGCC Reference Plant,” Gasification 

Technologies Conference 2005, San Francisco, CA, October 2005 

46 Coal Gasification Guidebook: Status, Applications, and Technologies, TR-102034, EPRI, 

December 1993 

47 Breton, David and Keeler, Clifton, “Comparative IGCC Performance and Costs for 

Domestic Coals,” Gasification Technologies Council, San Francisco, CA, October 2005 

48 Thomas, Greg, “Delivering the IGCC Solution,” GE Energy, January 31, 2006 

49 Rigdon, Robert and Miles, Kevin, “The Cleaner Coal Option,” Power Engineering 

International, July 2006 

50 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 

51 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 

52 Steam Conditions for PC Plant Designs Market Based Advanced Coal Power Systems 

Comparison Study, WorleyParsons, June 2005 

53 Laffont, Patrick, Bartelemy, Jacques, Scarlin, Brendon and Kervenec, Christian, “A 

Clean and Efficient Supercritical Circulating Fluidized Bed Power Plant,” Alstom Power 

54 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
Cost and Performance Comparison of Fossil Energy Power Plants 

 486 

55 Richard F. Storm, Optimizing Combustion in Boilers with Low NOx Burners, Storm 

Engineering & Associates, Power Magazine, October 1993 

56 Peter Wieslanger, Fabric Filters for Power Applications, ALSTOM Power Environmental 

Systems AB, 2000, www.power.alstom.com 

57 Improvement in Power Generation with Post-Combustion Capture of CO2, IEA 

Greenhouse Gas R&D Programme, Report PH4/33, November 2004 

58 Updated Coal Power Systems Study, Pulverized Coal Boiler, Fluor Subcontract Report 

for Carbon Dioxide Capture Unit, Fluor, December 2005 

59 W.G. Gorman, J.K. Reinker, Steam Turbines for Utility Applications, GER-3646C, GE 

Power Generation, 1994 

60 “Environmental Footprints and Costs of Coal-Based Integrated Gasification Combined 

Cycle and Pulverized Coal Technologies,” Final Report, EPA-430/R-06/006, July 2006 

61 Booras, George and Holt, Neville, “Pulverized Coal and IGCC Plant Cost and 

Performance Estimates,” Gasfication Technologies 2004, Washington DC, October 2004 

62 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

63 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

64 Gas Turbine World 2006 Performance Specifications, December 2006