# Cost and Performance Baseline for
Fossil Energy Plants

Volume 1 b : Bituminous Coal (IGCC) to
Electricity

Revision 2b

– Year Dollar Update

July 31, 2015

DOE/NETL

- 201 5/1727 

## OFFICE OF FOSSIL ENE RGY 

# National Energy Technology LaboratoryCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



# Disclaimer

This report was prepared as an account of work sponsored by an agency o f 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 in fringe privately owned rights. Reference therein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constit ute or imply its endorsement, recommendation, or favoring by the United States Government or any agency there of. The views and opinions of authors expressed therein do not necessarily state or reflect those of the United States Government or any agency the reof.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



# Author List :

National Energy Technology Laboratory (NETL)

Tim Fout General Engineer Office of Program Performance & Benefits

Energy Sector Planning and Analysis (ESPA)

Alexander Zoelle , Dale Keairns, Marc Turner, Mark Woods, Norma Kuehn,
Vasant Shah, Vincent Chou

Booz Allen Hamilton

Lora Pinkerton WorleyParsons Group, Inc.

This report was prepared by Energy Sector Planning and Analysis (ESPA) for the United States Department of Energy (DOE), National Energy Technology Laboratory (NETL) . This work was completed under DOE NETL Contract Number DE

- FE0004001 . This work was perf ormed

under ESPA T ask 341.03, Activity 17

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



# Acknowledgments

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

Tim Fout, NETL Technical Monitor

Kristin Gerdes

Director of OPPB

Travis Shultz
Director, Performance Division of OPPB

John Wimer

Director of OCPR&D

James Black

Daniel Cicero formerly of NETL

Jared Ciferno

Eric Grol

Jeffrey Hoffmann

Julianne Klara

Patrick Le

Michael Matuszewski formerly of NETL

Sean Plasynski

Larry Rath formerly of NETL

Walter Shelton

Gary Stiegel formerly of NETL

William Summers

Thomas J. Tarka, P.E.

Maria Vargas John L. Haslbeck formerly of Booz Allen Hamilton

Eric G. Lewis formerly of Booz Allen Hamilton

Pamela Capicotto formerly of Parsons Corporation

Michael Rutkowski formerly of Parsons Corporation

Ronald Schoff formerly of Parsons Corporation

Thomas Buchanan formerly of WorleyParsons Group, Inc.

James Simpson WorleyParsons Group, Inc.

Elsy Varghese formerly of WorleyParsons Group, Inc.

V ladimir Vaysman WorleyParsons Group, Inc.

Richard Weinstein WorleyParsons Group, Inc.



# DOE Contract Number DE

- FE0004001Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## i 

# Table of Contents

Executive Summary

................................ ................................ ................................ ......................... 1 Results Analysis

................................ ................................ ................................ ............................... 3

1 Introduction

................................ ................................ ................................ ................................ . 10

2 General Evaluation Basis

................................ ................................ ................................ ............ 13

2.1 Site Characteristics

................................ ................................ ................................ ................... 13

2.2 Coal Characteristics

................................ ................................ ................................ ................. 15

2.3 Environmental Targets

................................ ................................ ................................ ............. 16 2.3.1 Study Cases

................................ ................................ ................................ ........................... 18

2.3.2 Carbon Dioxide

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

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

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

................................ ................................ .......................... 19 2.4.3 Capacity Factor for Plants with Carbon Capture

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

................................ ................................ ................................ ............................ 20

2.5 Raw Water Withdrawal and Consumption

................................ ................................ .............. 20 2.6 Cost Estimating Methodology

................................ ................................ ................................ . 21 2.6.1 Capital Costs

................................ ................................ ................................ ......................... 22 2.6.2 Operation and Maintenance Costs

................................ ................................ ........................ 25

2.6.3 CO 2 

## Transport and Storage

................................ ................................ ................................ ... 27

2.6.4 Cost of CO 2 

## Captured and Avoided

................................ ................................ ...................... 29 2.7 Differences in IGCC Study Cost Estimates Compared to Industry Estimates

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

................................ ................................ ................................ ........................ 30

2.7.2 Labor

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

................................ ................................ ................................ ..... 31

3 IGCC Power Plants

................................ ................................ ................................ ..................... 32

3.1 IGCC Common Process Areas

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

................................ ................................ ................................ .. 32 3.1.2 Air Separation Unit (ASU) Choice and Integration

................................ .............................. 33

3.1.3 Water Gas Shift Reactors

................................ ................................ ................................ ...... 37 3.1.4 Mercury Removal

................................ ................................ ................................ ................. 38

3.1.5 Acid Gas Removal (AGR) Process Selection

................................ ................................ ....... 39 3.1.6 Sulfur Recovery/Tail Gas Cleanup Process Selection

................................ .......................... 42 3.1.7 Slag Handling

................................ ................................ ................................ ........................ 44

3.1.8 Power Island

................................ ................................ ................................ .......................... 45

3.1.9 Steam Generation Island

................................ ................................ ................................ ....... 48 3.1.10 Accessory Electric Plant

................................ ................................ ................................ ..... 51 3.1.11 Waste Treatment/Miscellaneous Systems

................................ ................................ ........... 52

3.1.12 Instrumentation and Control

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

................................ ................................ .......................... 52

3.2 Shell Global Solutions IGCC Cases

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

................................ ................................ ................................ ............. 54

3. 2.2 Process Description

................................ ................................ ................................ ............... 55 3.2.3 Key System Assumptions

................................ ................................ ................................ ..... 61 3.2.4 Sparing Philosophy

................................ ................................ ................................ ............... 63

3.2.5 Case B1A

- Performance Results

................................ ................................ .......................... 64Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## ii 3.2.6 Case B1A

- Major Equipment List

................................ ................................ ....................... 75

3.2.7 Case B1A

- Cost Estimating

................................ ................................ ................................ . 80

3.2.8 Case B1B

- Shell IGCC Power Plant with CO 2 

## Cap ture

................................ ...................... 86

3.2.9 Case B1B

- Performance Results

................................ ................................ .......................... 91

3.2.10 Case B1B

- Major Equipment List

................................ ................................ .................... 100

3.2.11 Case B1B

- Cost Estimating

................................ ................................ ............................. 105

3.3 CB&I E

- Gas TM 

## IGCC Cases

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

................................ ................................ ................................ ........... 111 3.3.2 Process Description

................................ ................................ ................................ ............. 112 3.3.3 Key System Assumptions

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

................................ ................................ ................................ ............. 118

3. 3.5 Case B4A

- Performance Results

................................ ................................ ........................ 119

3.3.6 Case B4A

- Major Equipment List

................................ ................................ ..................... 129

3.3.7 Case B4A

- Costs Estimating Results

................................ ................................ ................. 134

3.3.8 Case B4B

- E

- GasTM IGCC Power Plant with CO 2 

## Capture

................................ .............. 140

3.3.9 Case B4B

- Performance Results

................................ ................................ ........................ 145

3.3.10 Case B4B

- Major Equipment List

................................ ................................ .................... 154

3.3.11 Case B4B

- Cost Estimating Results

................................ ................................ ................. 159 3.4 General Electric Energy IGCC Cases

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

................................ ................................ ................................ ........... 165 3.4.2 Process Description

................................ ................................ ................................ ............. 166 3.4.3 Key System Assumptions

................................ ................................ ................................ ... 173 3.4.4 Sparing Philosophy

................................ ................................ ................................ ............. 175

3.4.5 Case B5A

- Performance Results

................................ ................................ ........................ 175

3.4.6 Case B5A

- Major Equipment List

................................ ................................ ..................... 186

3.4.7 Case B5A

- Cost Estimating

................................ ................................ ............................... 191

3.4.8 Case B5B

- GEE Radiant IGCC with CO 2 

## Capture

................................ ............................ 197

3.4.9 Case B5B

- Performance Results

................................ ................................ ........................ 201

3.4.10 Case B5B

- Major Equipment List

................................ ................................ .................... 211

3.4.11 Case B5B

- Cost Estimating

................................ ................................ ............................. 216

3.4.12 Case B5B

- Q

- GEE Quench IGCC with CO 2 

## Capture

................................ ..................... 222

3.4.13 Case B5B

- Q

- Performance Results

................................ ................................ .................. 226

3.4.14 Case B5B

- Q

- Major Equipment List

................................ ................................ ............... 236

3.4.15 Case B5B

- Q

- Cost Estimating

................................ ................................ ......................... 241 3.5 IGCC Case Summary

................................ ................................ ................................ ............. 247

3.5.1 Sens itivities

................................ ................................ ................................ ......................... 253

4 Revision Control

................................ ................................ ................................ ....................... 257

5 References

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



## iii 

# Exhibits

Exhibit ES

- 1 Case configuration summary

................................ ................................ ..................... 1

Exhibit ES

- 2 Performance summary and environmental profi le for all cases

................................ 4

Exhibit ES

- 3 Net plant efficiency (HHV basis)

................................ ................................ .............. 5

Exhibit ES

- 4 Cost summary for all cases

................................ ................................ ....................... 6

Exhibit ES

- 5 COE by cost component

................................ ................................ ............................ 8

Exhibit 1

- 1 Case descriptions

................................ ................................ ................................ ....... 12

Exhibit 2

- 1 Site characteristics

................................ ................................ ................................ ..... 13

Exhibit 2

- 2 Site ambient conditions

................................ ................................ .............................. 14

Exhibit 2

- 3 Design coal

................................ ................................ ................................ ................ 15

Exhibit 2

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

............. 16

Exhibit 2

- 5 MATS and NSPS emission limits for PM, HCl, SO 2 

## , NOx, and Hg

......................... 16

Exhibit 2

- 6 Environmental targets

................................ ................................ ................................ 18

Exhibit 2

- 7 Capital cost levels and their elemen ts

................................ ................................ ........ 23

Exhibit 2

- 8 CO 2 

## transport and storage costs

................................ ................................ ................. 29

Exhibit 3

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

- carbon

capture cases

................................ ................................ ................................ ......................... 35

Exhibit 3

- 2 Typical ASU process schematic

................................ ................................ ................ 36

Exhibi t 3

- 3 Flow diagram for a conventional AGR unit

................................ .............................. 40

Exhibit 3

- 4 Typical three

- stage Claus sulfur plant

................................ ................................ ....... 43

Exhibit 3

- 5 State

- of

- the

- art 2008 F

- class combustion turbine performance characteristics using natural gas (42)

................................ ................................ ................................ ..................... 45

Exhibit 3

- 6 Typical fuel specification for state

- of

- the

- art 2008 F

- class machines

....................... 46

Exhibit 3

- 7 Allowable gas fuel contaminant level for state

- of

- the

- art 2008 F

- class machines

.... 47

Exhibit 3

- 8 Case B1A block flow diagram, Shell IGCC without CO 2 

## capture

............................ 56

Exhibit 3

- 9 Case B1A str eam table, Shell IGCC without capture

................................ ................ 57

Exhibit 3

- 10 Shell IGCC plant study configuration matrix

................................ .......................... 62

Exhibit 3

- 11 Balance of plant assumptions

................................ ................................ .................. 63

Exhibit 3

- 12 Case B1A plant performance summary

................................ ................................ ... 65

Exhibit 3

- 13 Case B1A plant power summary

................................ ................................ ............. 66

Exhibit 3

- 14 Case B1A air emissions

................................ ................................ ........................... 67

Exhibit 3

- 15 Case B1A carbon balance

................................ ................................ ........................ 68

Exhibit 3

- 16 Case B1A sulfur balance

................................ ................................ .......................... 68

Exhibit 3

- 17 Case B1A water balance

................................ ................................ .......................... 69

Exhibit 3

- 18 Case B1A coal gasification and ASU heat and mass balance schematic

................ 71

Exhibi t 3

- 19 Case B1A syngas cleanup heat and mass balance schematic

................................ .. 72

Exhibit 3

- 20 Case B1A combined cycle power generation heat and m ass balance schematic

.... 73

Exhibit 3

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

................................ ....... 75

Exhibit 3

- 22 Case B1A total plant cost details

................................ ................................ ............. 81

Exhibit 3

- 23 Case B1A owner’s costs

................................ ................................ .......................... 84

Exhibit 3

- 24 Case B1A initial and annual operating and maintenance costs

............................... 85

Exhibit 3

- 25 Case B1A COE breakdown

................................ ................................ ..................... 85

Exhibit 3

- 26 Case B1B block flow diagram, Shell IGCC with CO 2 

## capture

............................... 88

Exhibit 3

- 27 Case B1B stream table, Shell IGCC with capture

................................ ................... 89

Exhibit 3

- 28 Case B1B pl ant performance summary

................................ ................................ ... 91

Exhibit 3

- 29 Case B1B plant power summary

................................ ................................ ............. 92Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## iv Exhibit 3

- 30 Case B1B air emissions

................................ ................................ ........................... 93

Exhibit 3

- 31 Case B1B carbon balance

................................ ................................ ........................ 94

Exhibit 3

- 32 Case B1B sulfur balance

................................ ................................ .......................... 94

Exhibit 3

- 33 Case B1B water balance

................................ ................................ .......................... 95

Exhibit 3

- 34 Case B1B coal gasification and ASU heat and mass balance schematic

................. 96

Exhibit 3

- 35 Case B1B syngas cleanup heat and mass balance schematic

................................ .. 97

Exhibit 3

- 36 Case B1B combined cycle power generation heat and mass balance schematic

..... 98

Exhibit 3

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

................................ ..... 100

Exhibit 3

- 38 Case B1B total plant cost details

................................ ................................ ........... 106

Exhibit 3

- 39 Case B1B owner’s costs

................................ ................................ ........................ 109

Exhibit 3

- 40 Case B1B initial and annual operating and maintenance costs

............................. 110

Exhibit 3

- 41 Case B1B COE breakdown

................................ ................................ .................... 110

Exhibit 3

- 42 Case B4A block flow diagram, E

- GasTM IGCC without CO 2 

## capture

.................. 113

Exhibit 3

- 43 Case B4A stream table, E

- GasTM IGCC without capture

................................ ...... 114

Exhibit 3

- 44 E

- Gas TM 

## IGCC plant study configuration matrix

................................ .................. 119

Exhibit 3

- 45 Case B4A plant pe rformance summary

................................ ................................ . 120

Exhibit 3

- 46 Case B4A plant power summary

................................ ................................ ........... 121

Exhibit 3

- 47 Case B4A air emissions

................................ ................................ ......................... 122

Exhibit 3

- 48 Case B4A carbon balance

................................ ................................ ...................... 123

Exhibit 3

- 49 Case B4A sulfur balance

................................ ................................ ........................ 123

Exhibit 3

- 50 Case B4A water balance

................................ ................................ ........................ 124

Exhibit 3

- 51 Case B4A coal gasification and ASU heat and mass balance schematic

.............. 125

Exhibit 3

- 52 Case B4A syngas cleanup heat and mass balance schematic

................................ 126

Exhibit 3

- 53 Case B4A combined cycle power generation heat and mass balance schematic

.. 127

Exhibit 3

- 54 Case B4A overall energy bal ance (0°C [32°F] reference)

................................ ..... 129

Exhibit 3

- 55 Case B4A total plant cost details

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

Exhibit 3

- 56 Case B4A owner’s costs

................................ ................................ ........................ 138

Exhibit 3

- 57 Case B4A initial and annual operating and maintenance costs

............................. 139

Exhibit 3

- 58 Case B4A COE breakdown

................................ ................................ ................... 139

Exhibit 3

- 59 Case B4B block flow diagram, E

- GasTM IGCC with CO 2 

## capture

........................ 142

Exhibit 3

- 60 Case B4B stream table, E

- GasTM IGCC with capture

................................ ............ 143

Exhibit 3

- 61 Case B4B plant performance summary

................................ ................................ . 145

Exhibit 3

- 62 Case B4B plant power summary

................................ ................................ ........... 146

Exhibit 3

- 63 Case B4B air emissions

................................ ................................ ......................... 147

Exhibit 3

- 64 Case B4B carbon balance

................................ ................................ ...................... 148

Exhibit 3

- 65 Case B4B sulfur balance

................................ ................................ ........................ 148

Exhibit 3

- 66 Case B4B water balance

................................ ................................ ........................ 149

Exhibit 3

- 67 Case B4B coal gasification and ASU heat and mass balance schematic

............... 150

Exhibit 3

- 68 Case B4B syngas cleanup heat and mass balance schematic

................................ 151

Exhibit 3

- 69 Case B4B combined cycle power generation heat and mass balance schematic

... 152

Exhibit 3

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

................................ ..... 154

Exhibit 3

- 71 Case B4B total plant cost details

................................ ................................ ........... 160

Exhibit 3

- 72 Case B4B owner’s costs

................................ ................................ ........................ 163

Exhibit 3

- 73 Case B4B initial and annual operating and maintenance costs

............................. 164

Exhibit 3

- 74 Case B4B COE breakdown

................................ ................................ .................... 164

Exhibit 3

- 75 Case B5A block flow diagram, GE E IGCC without CO 2 

## capture

......................... 169Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## v Exhibit 3

- 76 Case B5A stream table, GEE IGCC without capture

................................ ............ 170

Exhibit 3

- 77 GEE IGCC plant study configuration matrix

................................ ........................ 174

Exhibit 3

- 78 Case B5A plant performance summary

................................ ................................ . 176

Exhibit 3

- 79 Case B5A plant power summary

................................ ................................ ........... 177

Exhibit 3

- 80 Case B5A air emissions

................................ ................................ ......................... 178

Exhibit 3

- 81 Case B5A carbon balance

................................ ................................ ...................... 179

Exhibit 3

- 82 Case B5A sulfur balance

................................ ................................ ........................ 179

Exhibit 3

- 83 Case B5A water balance

................................ ................................ ........................ 180

Exhibit 3

- 84 Case B5A coal gasification and ASU heat and mass balance schematic

.............. 182

Exhibit 3

- 85 Case B5A syngas cleanup heat and mass balance schematic

................................ 183

Exhibit 3

- 86 Case B5A combined

- cycle power generation he at and mass balance schematic

.. 184

Exhibit 3

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

................................ ..... 186

Exhibit 3

- 88 Case B5A total plant cost details

................................ ................................ ........... 192

Exhibit 3

- 89 Case B5A owner’s costs

................................ ................................ ........................ 195

Exhibit 3

- 90 Case B5A initial and annual operating and maintenance costs

............................. 196

Exhibit 3

- 91 Case B5A COE breakdown

................................ ................................ ................... 196

Exhibit 3

- 92 Case B5B block flow diagram, GEE IGCC with CO 2 

## capture

.............................. 198

Exhibit 3

- 93 Case B5B stream table, GEE IGCC with capture

................................ .................. 199

Exhibit 3

- 94 Case B5B plant performance summary

................................ ................................ . 202

Exhibit 3

- 95 Case B5B plant power summary

................................ ................................ ........... 203

Exhibit 3

- 96 Case B5B air emissions

................................ ................................ ......................... 204

Exhibit 3

- 97 Case B5B carbon balance

................................ ................................ ...................... 205

Exhibit 3

- 98 Case B5B sulfur balance

................................ ................................ ........................ 205

Exhibit 3

- 99 Case B5B water balance

................................ ................................ ........................ 206

Exhibit 3

- 100 Case B5B coal gasification and ASU heat and mass balance schematic

............. 207

Exhibit 3

- 101 Case B5B syngas cleanu p heat and mass balance schematic

.............................. 208

Exhibit 3

- 102 Case B5B combined

- cycle power generation heat and mass balance schematic 209

Exhibit 3

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

................................ ... 211

Exhibit 3

- 104 Case B5B total plant cost details

................................ ................................ ......... 217

Exhibit 3

- 105 Case B5B owner’s costs

................................ ................................ ...................... 220

Exhibit 3

- 106 Case B5B initial and annual operating and maintenance costs

........................... 221

Exhibit 3

- 107 Case B5B COE breakdown

................................ ................................ .................. 221

Exhibit 3

- 108 Case B5B

- Q block flow diagram, GEE quench

- only IGCC with CO 2 

## capture

... 223

Exhibit 3

- 109 Case B5B

- Q stream table, GEE quench

- only IGCC with capture

...................... 224

Exhibit 3

- 110 Case B5B

- Q plant performance summary

................................ ........................... 227

Exhibit 3

- 111 Case B5B

- Q plant power summary

................................ ................................ ..... 228

Exhibit 3

- 112 Case B5B

- Q air emissions

................................ ................................ ................... 229

Exhibit 3

- 113 Case B5B

- Q carbon balance

................................ ................................ ................ 230

Exhibit 3

- 114 Case B5B

- Q sulfur balance

................................ ................................ .................. 230

Exhibit 3

- 115 Case B5B

- Q water balance

................................ ................................ .................. 231

Exhibit 3

- 116 Case B5B

- Q coal gasification and ASU heat and mass balance schematic

........ 232

Exhibit 3

- 117 Case B5B

- Q syngas cleanup heat and mass balance schematic

.......................... 233

Exhibit 3

- 118 Case B5B

- Q combined cycle power generation heat and mass balance schematic

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

Exhibit 3

- 119 Case B5B

- Q overall energy balance

................................ ................................ .... 236

Exhibit 3

- 120 Case B5B

- Q total plant cost details

................................ ................................ ..... 242Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## vi Exhibit 3

- 121 Case B5B

- Q owner’s costs

................................ ................................ .................. 245

Exhibit 3

- 122 Case B5B

- Q initial and annual operating and maintenance costs

....................... 246

Exhibi t 3

- 123 Case B5B

- Q COE breakdown

................................ ................................ ............. 246

Exhibit 3

- 124 Estimated performance and cost results for all cases

................................ .......... 247

Exhibit 3

- 125 Plant capital cost for all cases

................................ ................................ .............. 249

Exhibit 3

- 126 COE for all cases

................................ ................................ ................................ . 250

Exhibit 3

- 127 Cost of CO 2 

## captured and avoided in all cases

................................ .................... 251

Exhibit 3

- 128 Raw water withdrawal and consumption in all case s

................................ .......... 252

Exhibit 3

- 129 Capacity factor sensitivity of all cases

................................ ................................ . 253

Exhibit 3

- 130 Sensitivity of COE to coal price for all cases

................................ ...................... 254

Exhibit 3

- 131 Impact of carbon emissions price on study technologies

................................ .... 255

Exhibit 3

- 132 Impact o f carbon sales price on study technologies

................................ ............ 256

Exhibit 4

- 1 Record of revisions

................................ ................................ ................................ .. 257Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## vii 

# Acronyms and Abbreviations

AACE Association for the Advancement of Cost Engineering

acfm Actual cubic feet per minute

ACI Activated carbon injection

ADIP Aqueous di

- isoproponal

AEO Annual Energy Outlook

AF Available factor

AGR Acid gas removal

ANSI American National Standards

Institute

Ar Argon

AR As received

Aspen Aspen Plus ®

ASU Air separation unit

atm Atmosphere (14.696 psi)

BACT Best available control technology

BAH Booz Allen Hamilton

BDL Blowdown losses

BEC Bare erected cost

BFD Block flow diagram

BFW Boiler feedwater

Btu British thermal unit

Btu/hr British thermal units per hour

Btu/kWh British thermal units per kilowatt

hour

Btu/lb British thermal units per pound

Btu/scf British thermal units per standard

cubic foot

CAAA Clean Air Act Amendments of 1990

CAIR Clean Air Interstate Rule

CAMR Clean Air Mercury Rule

CB&I Chicago Bridge & Iron Company

CCF Capital charge factor

CCS Carbon capture and sequestration

CCS Carbon capture and storage

CDR Carbon dioxide recovery

cf Cubic feet

CF Capacity factor

cfm Cubic feet per minute

CFR Code of Federal Regulations

CGE Cold gas efficiency

CGCU Cold gas cleanup

CH 4 

### Methane

CL Closed

- loop

cm Centimeter

CO Carbon monoxide CO 2 

### Carbon dioxide

CO 2 

### E Carbon dioxide equivalent

COE Cost of electricity

COH Cost of hydrogen

COR Contracting Officer's Representative

COS Carbonyl sulfide

CRT Cathode ray tube

CS Carbon steel

CT Combustion turbine

CTG Co mbustion turbine

- generator

CWP Circulating water pump

CWR Cooling water return

CWS Circulating water system

CWT Cold water temperature

dB Decibel

DB Dry basis

DCA Direct contact absorber

DCS Distributed control system

DEA Diethanolamine

DI De

- ionized

Dia. Diameter

DIPA Diisopropanolamine

DLN Dry low NOx

DME Di

- methyl ether

DOE Department of Energy

DSCR Debt service coverage ratio

DSI Dry sorbent injection

DSRP Direct sulfur recovery process

eGRID Emissions & Generation Resource Integrated Database

E

- Gas TM 

### CB&I gasifier technology

EAF Equivalent availability factor

EGU Electric utility steam generating units

EIA Energy Information Administration

EM Electromagnetic

EMF Emission modification factors

EOR Enhanced oil recovery

EPA Environmental Protection Agenc y

EPC Engineer/Procure/Construct

EPCC Engineering, Procurement and

Construction Cost

EPRI Electric Power Research Institute

EPCM Engineering/Procurement/ Construction Management

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



## viii ESP Electrostatic precipitator

ESPA Energy Sector Planning and Analysis

ETE Effective thermal efficiency

FD Forced draft

FE Fossil energy

FERC Federal Energy Regulatory

Commission

FG Flue gas

FGD Flue gas desulfurization

FO&M Fixed operations and maintenance

FOAK First

- of

- a

- kind

FRP Fibergl ass

- reinforced plastic

FSQ Full

- slurry quench

ft Foot, Feet
ft, w.g. Feet of water gauge

FW Feedwater

GADS Generating Availability Data System

gal Gallon
gal/MWh Gallons per megawatt hour

GCV Gross calorific value

GDP Gross domestic product

GEE General Ele ctric Energy

GJ Gigajoule

GJ/hr Gigajoules per hour

GHG Greenhouse gas

GHGEV Greenhouse gas emission value
gpd Gallons per day

gpm Gallons per minute
gr/100 scf grains per one hundred standard cubic

feet

GRI Gas Research Institute

GSU Generator step

- up transformers

Gt Gigatonnes

GWh Gigawatt

- hour

h, hr Hour

H 2 

### Hydrogen

H 2 

### A DOE’s Hydrogen Advisory Group

H 2 

### O Water

H 2 

### S Hydrogen sulfide

H 2 

### SO 4 

### Sulfuric acid

HAP Hazardous air pollutant

HCl Hydrochloric acid

HCPV Hydrocarbon pore volume

HDPE High density polyet hylene

Hg Mercury

HHV Higher heating value

Horiz. Horizontal

hp Horsepower HP High pressure

HRSG Heat recovery steam generator

HSS Heat stable salts

HV High voltage

HVAC Heating, ventilating, and air conditioning

HWT Hot water temperature

Hz Hertz

ICR Inf ormation Collection Request

ID Induced draft

IEA International Energy Agency

IEEE Institute of Electrical and Electronics Engineers

IGCC Integrated gasification combined cycle

IGV Inlet guide vane

in. H 2 

### O Inch water
in. Hga Inch mercury (absolute pressure)

in. W.C. Inch water column

IOU Investor

- owned utility

IP Intermediate pressure

IPCC Intergovernmental Panel on Climate Change

IPM Integrated Planning Model

IPP Independent power producer

IRR Internal rate of return

IRROE Internal rate of return on equity

ISBL Inside battery limits

ISO International Organization for

Standardization
kg/GJ Kilograms per gigajoule

kg/hr Kilograms per hour
kg/s Kilograms per second

kgmol Kilogram mole
kgmol/hr Kilogram moles per hour

kJ Kilojoule

kJ/hr Kilojoules per hour

kJ/ kg Kilojoules per kilogram

km Kilometer

KO Knockout

kPa Kilopascal

kV Kilovolt

kW, kWe Kilowatt electric

kWh Kilowatt

- hour

kWt Kilowatt thermal

LAER Lowest Achievable Emission Rate

lb Pound

lb/gal Pound per gallonCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## ix lb/hr Pounds per hour

lb/ft 2 

### Pounds per square foot

lb/MMBtu Pounds per million British thermal

units

lbmol Pound mole

lbmol/hr Pound moles per hour

lb/MWh Pounds per megawatt hour

lb/TBtu Pounds per trillion British thermal

units

LC Life cycle

LCA Life cycle analysis

LCC Life cycle cost

LCI Li fe cycle inventory

LCIA Life cycle impact assessment

LGTI Louisiana Gasification Technology,

Inc.

LHV Lower heating value

LIBOR London Interbank Offered Rate

LMP Locational Marginal Price

LNG Liquified natural gas

LNB Low NOx burner

LP Low pressure

LPG L iquefied petroleum gas
lpm Liters per minute

LSE Load

- serving entities

LV Low voltage

M Thousand

m Meter

m/min Meters per minute

m 3 

### /min Cubic meters per minute

MAC Main air compressor

MAF Moisture and ash free

MATS Mercury and Air Toxics Standards

Mbbl Thousand barrels

Mcf Thousand cubic feet

MCR Maximum continuous rate

md Millidarcy (a measure of permeability)

MDEA Methyldiethanolamine

MeOH Methanol

MHz Megahertz

mi Mile

MJ/Nm 3 

### Megajoules per normal cubic meter

MM Million

MMBtu Million British thermal u nits

MMBtu/hr Million British thermal units per hour

MMscf Million standard cubic feet

MMscfd Million standard cubic feet per day MMscfy Million standard cubic feet per year

mol% Mole percent (percent by mole)

MNQC Multi Nozzle Quiet Combustor

MPa Megapa scal

mpg Miles per gallon

MTG Methanol to gasoline

MVA Mega volt

- amps

MW Megawatt

MWe Megawatt electric

MWh Megawatt

- hour

MWt Megawatt thermal

N 2 

### Nitrogen

N 2 

### O Nitrous oxide

N/A Not applicable

NAAQS National Ambient Air Quality

Standards

NaOH Sodium hydroxide

NCF Net capacity factor

Neg. Negligible

NEMA National Electrical Manufacturers

Association

NEMS National Energy Modeling System

NERC North American Electric Reliability

Council

NETL National Energy Technology Laboratory

NFPA National Fire Protection Association

NG Natural gas

NGCC Natural gas combined cycle

NGL Natural gas liquids

NH 3 

### Ammonia

Nm 3 

### Normal cubic meter

Nm 3 

### /hr Normal cubic meter per hour

NOAK N th



### - of

- a

- kind

NOx Oxides of nitrogen

NSPS New Source Performance Standards

NSR New So urce Review

O 2 

### Oxygen

O&GJ Oil & Gas Journal

O&M Operation and maintenance

OC Fn 

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

OC Vnq 

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

OD Outside diameter

OEM Original equipment manufacturers

OFA Overfire air

OPPA Office of Program Planning & AnalysisCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## x OP/VWO Over pressure/valve wide open

OSHA Occupational Safety and Health

Administration

PA Primary air

PAC Powdered activated carbon

PC Pulverized coal

PAS PAS, Inc.

PC Pulverized coal
p.f. Power factor

PFD Process flow diagram

PM Particulate matter

PM 10 

### Particulate matter measuring 10 μm (micrometers) or less

PO Purchase order

POTW Publicly owned treatment works
ppbw Parts per billion weight

ppm Parts per million

ppmv Parts per million volume

ppmvd Parts per million volume, dry

ppmw Parts per million weight

ppmwd Parts per million weight, dry

PRB Powder River Basin coal region

PSA Pressure swing adsorption

PSD Prevention of significant deterioration
psi Pounds per squ are inch

psia Pound per square inch absolute
psid Pound per square inch differential

psig Pound per square inch gage

PSFM Power systems financial model

PTFE Teflon (Polytetrafluoroethylene)

PV Present value

QGESS Quality Guidelines for Energy System Studies

Qty Quantity

R&D Research and development

RCRA Resource Conservation and Recovery

Act

RD&D Research, development, and

demonstration

RDS Research and Development Solutions,

LLC

RH Reheater

RSC Radiant syngas cooler

RSP Required selling price

RTO Re gional transmission operations/operator

SC Supercritical

SC PC Supercritical Pulverized Coal

scf Standard cubic feet scfd Standard cubic feet per day

scfh Standard cubic feet per hour

scfm Standard cubic feet per minute

Sch. Schedule

scmh Standard cubic m eter per hour

SCOT Shell Claus Off

- gas Treating

SCR Selective catalytic reduction process or equipment

SDA Spray dryer absorber

SEAP Office of Strategic Energy Analysis & Planning

SFC Synthetic Fuels Corporation

SG Specific gravity

SGC Synthesis gas cooler

SGS Sour gas shift

Shell Shell Global Solutions

SO 2 

### Sulfur dioxide

SOx Oxides of sulfur

SNCR Selective non

- catalytic reduction process or equipment

SNG Synthetic natural gas

SRU Sulfur recovery unit

SS Stainless steel

SS Amine SS Specialty Amine

s t Short ton

STG Steam turbine generator

SWS Sour water scrubber

Syngas Synthetic gas

T&D Transmission and distribution

T&S Transport and storage

TASC Total as

- spent cost

TCR Total capital requirement

TEWAC Totally Enclosed Water

- to

- Air

Cooled

TGTU Tail gas treating unit

tonne Metric ton (1,000 kg)

TOC Total overnight cost

TPC Total plant cost
tpd Ton per day

tph Tons per hour

TPI Total plant investment

U.S. United States

USC Ultra

- supercritical

V Volt

VOC Volatile organic compound

VO&M Variable operations and maintenance

V

- L Vapor liquid portion of stream (excluding solids)Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## xi vol% Volume percent

WB Wet bulb

wg Water gauge

WGCU Warm gas cleanup

WGS Water gas shift

wt% Weight percent

yr Year

ZnO Zinc oxide

ZnS Zinc sulfide

$/GJ Dollars per gigajoule $/kW Dollar s per kilowatt

$/MMBtu Dollars per million British thermal

units

$M Millions of dollars
μS/cm micro Siemens per cm

°C Degrees Celsius

°F Degrees Fahrenheit

5

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



## xii This page intentionally left blank.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 1 

# Executive Summary

This report presents the cost and performance results of an assessment of seven integrated gasification combined cycle (IGCC) plants

. The primary value of this report lies not in the absolute accuracy of the capital cost estimates for the individual cases (estimated to be

- 15

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

relative costs a mong the cases evaluated.

This report is part of an update to Volume 1 of a four

- volume series, which consists of:

• Volume 1: Bituminous Coal and Natural Gas to Electricity

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

• Volume 3: L ow Rank Coal and Natural Gas to Electricity

• Volume 4: Bituminous Coal to Liquid Fuels

This report , Volume 1b, retains the IGCC design and performance updates from the November 2010 release of Volume 1 (Revision 2) 1 

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

dollars. Volume 1a covers the cost and performance update of all pulverized coal ( PC ) and natural gas combined cycle ( NGCC ) cases. Section 4 has a revision control table listing the updates applied to this report.

Seven power plant configura tions were analyzed in this report, including two Shell Global Solutions (Shell) gasifiers (with and without carbon dioxide [ CO 2 

## ] capture), two Chicago Bridge and Iron ( CB&I ) E

- Gas TM 

## full

- slurry quench (FSQ) gasifiers (with and without CO 2 

## capture), and three General Electric Energy ( GEE ) gasifiers (one without and two with CO 2 

## capture [one

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

Exhibit ES

- 1

. Exhibit ES

- 1 Case configuration summary

Case Steam Cycle, psig/ ° F/ ° F Combustion

Turbine Gasifier Technology H 2 

### S Separation PM Control CO 2 

### Separation B



### B1A 1800/1050/1050 2 x State

- of

- the

art 2008 F

- Class Shell Sulfinol

- M Cyclone, candle filter,

and water scrubber N/A

B1B 1800/1000/1000 2 x State

- of

- the

art 2008 F

- Class Shell Selexol Cyclone, candle filter,

and water scrubber Selexol 2 nd


### stage

B4A 1800/1050/1050 2 x State

- of

- the

art 2008 F

- Class CB&I E

- GasTM Refrigerated

MDEA Cyclone, candle filter,

and water scrubber N/A

B4B 1800/1000/1000 2 x State

- of

- the

art 2008 F

- Class CB&I E

- GasTM Selexol Cyclone, candle filter,

and water scrubber Selexol 2 nd


### stage

B5A 1800/1050/1050 2 x State

- of

- the

art 2008 F

- Class GEE Radiant Selexol Quench, water scrubber, and AGR

adsorber N/A

B5B 1800/1000/1000 2 x State

- of

- the

art 2008 F

- Class GEE Radiant Selexol Quench, water scrubber, and AGR

adsorber Selexol 2 nd


### stage

B5B

- Q 1800/1000/1000 2 x State

- of

- the

art 2008 F

- Class GEE Quench Selexol Quench, water scrubber, and AGR

adsorber Selexol 2 nd


### stage

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



## 2 All plant configurations were evaluated based on installation at a greenfield site. Capacity factors (CF) are assumed to equal approximate availability at 8 0 percent for all configurations. Achieving such capacity factors would require that these plants be near the top of the dispatch

list.

The combustion turbines (CT) used in each of the configurations are manufactured in discre te sizes; each of the configurations utilizes an identical CT design with the output maximized. While the output of the combustion turbines is consistent between configurations, the cases have net outputs ranging fro m 494 (Case B 5 B

- Q ) to 6 29 MW (Case B1A). The range in net output is caused by the significant auxiliary load imposed in the CO 2 

## capture cases

– primarily due to CO 2 

## compression

– and the need for extraction steam for CO 2 

## capture and the sour gas shift (SGS)
reactions, which reduc es steam turbine output.

Environmental emission requirements are based on the mercury (Hg) and hydrochloric acid (HCl) limits set by the March 2013 update to the Utility Mercury and Air Toxics Standards (MATS)

, and particulate matter (PM), sulfur dioxide (SO 2 

## ), and nitrogen oxide (NOx) limits set by the February 2013 update to the New Source Performance Standards (NSPS).

Mercury is controlled with dual sulfur

- impregnated carbon beds; H 2 

## S is separated with an aci d gas removal (AGR) process and controlled with a Claus plant to limit SO 2 

## stack emissions ; NOx formation is minimized with low NOx burners (LNB) and nitrogen dilution; the particulate matter is controlled with a syngas scrubber, cyclone, and candle filter ; the HCl is primarily removed in the syngas scrubber with the remainder removed with the low temperature heat recovery condensate, and the combined effluent is treated with calcium hydroxide.

All of the power plant configurations with carbon capture in th is report are designed to achieve 90 percent capture, resulting in atmospheric CO 2 

## emissions at levels far below proposed Environmental Protection Agency (EPA) regulation

. 2



## The performance results presented in this repor t are unchanged from Revision 2. T h e methodology used in their development included performing steady

- state simulations of the

seven power plant configurations using the Aspen Plus ® 

## (Aspen) modeling program. The major plant equipment performance and process limits were based on published reports, information obtained from vendors and users of the technology, performance data from design/build utility projects, and/or best engineerin g judgment.

In Revision 2, mass and energy balance data from the Aspen models were used to size major pieces of equipment, which formed the basis for developing the cost estimates presented in that report. The capital and operating costs for the major equ ipment and plant sub

- systems had been estimated by WorleyParsons based on the simulation results using an in

- house database and conceptual estimating models. The cost results were further calibrated using a combination of adjusted vendor

- furnished data an d scaled estimates from previous design/build projects. All Revision 2 costs were reported in 2007 dollars.

It was the purpose of this report (Revision 2b) to update the costs to 2011 dollars. This effort was accomplished through scaled escalation and co rrections. The only exception was to address

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

for new fossil fuel

- fired electric utility generating units. As of the publication of this report, the proposed regulation has been published in the Federal Register. (54) The limit set by the propose d regulation is 1,100 lb

- CO 2 /MWh

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



## 3 the use of a dual carbon system for Hg removal, which was re

- costed from a single carbon system to address environmental targets discussed in Section 2.3

.

The b aseline fuel cost for this analysis is specified in the November 2012 revision of the Quality Guidelines for Energy System Studies (QGESS) document on “ Fuel Prices for Selected

Feedstocks in NETL Studies.” (1) The first year of capital expenditure price used is $2.78/GJ ($2.94/MMBtu) for Illinois No. 6 coal delivered to the Midwest

, on a higher heating value ( HHV ) basis and in 2011 United States (U.S.) dollars.

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

be received by the generator per net megawatt

- hour produced to meet the desired internal rate of return on equity. The COE is assumed to escalate at a nominal annual rate equal to the general
inflation rate, i.e., it remains constant or levelized in real terms over the operational period of the power plant. The cost of CO 2 

## transport and storage (T&S) of $11 per tonne of CO 2 

## is added to the COE and represents a 62 km (100 mile) CO 2 

## pipeline and storage in a deep saline formation

in the Midwest. 3



## The cost and performance of the various fossil fuel

- based technologies will be important in determining which combination of technologies will be utilized to meet the demands of the

power market in the future.

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

• Capital and operating costs

• Overall energy efficiency

• Fuel prices

• C OE

• Availability, reliability

, and environmental performance

• Current and potential r e gulation s governing air, water, and solid waste discharges from

fossil

- fueled power plants

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

of recent commercial

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

Clean Coal and Carbon Management Program



# Results Analysis

Exhibit ES

- 2 shows the performance and environmental profile summary for all cases. A g raph of the net plant efficiency (HHV basis) is provided in Exhibit ES

- 3

.

3 Estimated using the FE/NETL CO 2 Transport Cost Model and the FE/NETL CO 2 Saline Storage Cost Model. Additional detail on development of these costs is available in the May 2014 revision of the QGESS document “Ca rbon Dioxide Transport and Storage Costs in NETL Studies.” (26)Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 4 Exhibit ES

- 2 P erformance summary and environmental profile for all cases

Integrated Gasification Combined Cycle

Shell E

- Gas TM 

### FSQ GEE R+Q
Case Name (Old Case Name) A 

### B1A (5) B1B (6) B4A (3) B4B (4) B5A (1) B5B (2) B5B

- Q (2a)

PERFORMANCE
Gross Power Output (MWe) 737 673 738 704 748 734 684
Auxiliary Power Requirement (MWe) 108 177 113 190 126 191 190
Net Power Output (MWe) 629 497 625 513 622 543 494
Coal Flow rate (lb/hr) 436,646 465,264 459,956 484,212 466,898 487,005 486,978
Natural Gas Flow rate (lb/hr) N/A N/A N/A N/A N/A N/A N/A
HHV Thermal Input (kW t 

### ) 1,492,878 1,590,722 1,572,575 1,655,503 1,596,309 1,665,056 1,664,962
Net Plant HHV Efficiency (%) 42.1% 31.2% 39.7% 31.0% 39.0% 32.6% 29.7%
Net Plant HHV Heat Rate (Btu/kWh) 8,100 10,927 8,585 11,002 8,758 10,459 11,505

Raw Water Withdrawal, gpm 4,150 5,652 4,382 5,757 4,755 5,834 6,137
Process Water Discharge, gpm 788 1,021 905 1,095 984 1,080 1,129
Raw Water Consumption, gpm 3,362 4,631 3,477 4,662 3,771 4,754 5,008



### CO 2 

### Capture Rate (%) 0 90 0 90 0 90 90

CO 2 Emissions (lb/MMBtu) 197 20 199 20 197 20 20

CO 2 Emissions (lb/MWh

- gross) 1,361 161 1,448 158 1,434 152 165

CO 2 Emissions (lb/MWh

- net) 1,595 218 1,711 217 1,724 206 228

SO 2 Emissions (lb/MMBtu) 0.004 0.002 0.012 0.002 0.001 0.002 0.002

SO 2 Emissions (lb/MWh

- gross) 0.029 0.017 0.085 0.017 0.009 0.017 0.018
NOx Emissions (lb/MMBtu) 0.059 0.049 0.060 0.049 0.059 0.049 0.049
NOx Emissions (lb/MWh

- gross) 0.409 0.396 0.434 0.396 0.430 0.376 0.404
PM Emissions (lb/MMBtu) 0.007 0.007 0.007 0.007 0.007 0.007 0.007
PM Emissions (lb/MWh

- gross) 0.049 0.057 0.052 0.057 0.052 0.055 0.059
Hg Emissions (lb/TBtu) 0.434 0.372 0.413 0.374 0.412 0.388 0.361
Hg Emissions (lb/MWh

- gross) 3.00E

- 06 3.00E

- 06 3.00E

- 06 3.00E

- 06 3.00E

- 06 3.00E

- 06 3.00E

- 06

A 

### Previous versions of this report us ed a different naming convention. The old case numbers are provided here, paired with the new case numbers for reference.



## The primary conclusions that can be drawn are:

• In the non

- carbon capture cases the Shell gasifier has the highest net plant efficiency (42.1 percent), followed by the two

- stage E

- Gas TM 

## slurry fed gasifier (39.7 percent).

• The energy penalty associated with adding CO 2 

## capture is due to steam extraction for use in the SGS reaction, the auxiliary load for the CO 2 

## separation and compression equipment, and a slight derate of the gas turbine due to the higher moisture content of the flue gas. The reduction in net plant eff iciency ranges from 6 to 11 percentage points with the variability being due to the optimum gasifier designs (e.g.

, slurry vs. dry feed, syngas quench vs. syngas heat recovery)

. T he capture and non

- capture plant configurations may have different optimum g asifier designs

.

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

- capture plant design (slurry feed, water quench)

, which results in a high moisture content in the syngas and thus a low addition of shift steam for SGS for the capture plant design.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 5 • The highest energy penalty (11 percentage points) corresponds to the Shell gasifier cases. The design uses a dry feed system and, in the non

- capture configuration, has relatively high heat re covery in the syngas cooler with no water quench, resulting in very low moisture content in the syngas. For the capture configuration, a water quench is added

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

heat recovery in the syngas cooler.

• CB&I E

- Gas TM 

## has the highest SO 2 

## emissions ( 0.085 lb/MWh

- gross) of the seven cases because refrigerated MDEA has the lowest H 2 

## S removal efficiency of the AGR technologies.

• Emissions of Hg, PM, NOx, HCl, and SO 2 

## are all below the regulatory limits currently in effect and applicable to the technologies within this report.

Exhibit ES

- 3 Net plant efficiency (HHV basis)

Source: NETL



## The cost results for all cases are provided in Exhibit ES

- 4

. A graph of the COE is provided in

Exhibit ES

- 5

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



## 6 Exhibit ES

- 4 Cost summary for all cases

Integrated Gasification Combined Cycle A



### Shell E

- Gas TM 

### FSQ GEE R+Q

Case Name B1A B1B B4A B4B B5A B5B B5B

- Q

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

**Bare Erected Cost** 2,067 2,963 1,809 2,638 1,870 2,525 2,548
**Home Office Expenses** 207 296 181 264 187 253 255
**Project Contingency** 376 562 322 492 330 467 467
**Process Contingency** 75 160 61 147 61 143 135
Total Overnight Cost (2011$ M ) 2,107 2,442 1,830 2,252 1,888 2,27 9 2,08 6 Total Overnight Cost (2011$/kW) 3,351 4,917 2,929 4,386 3,036 4,195 4,224

**Owner's Costs** 626 936 557 846 587 807 819

Total As

- Spent Cost (2011$/kW) 3,820 5,605 3,339 5,000 3,461 4,782 4,815
COE ( $/MWh ) (excluding T&S) 107.0 152.6 99.8 141.9 102.6 135.4 138.7
**Capital Costs** 59.3 87.0 51.8 77.6 53.7 74.2 74.7

**Fixed Costs** 14.7 20.5 13.5 19.1 13.7 18.2 18.0

**Variable Costs** 9.3 13.0 9.2 12.8 9.4 12.2 12.2

**Fuel Costs** 23.8 32.1 25.2 32.3 25.7 30.7 33.8
**COE ( $/MWh**  **) (including T&S)** 107.0 162.4 99.8 151.8 102.6 144.7 148.9

**CO** 2 **T&S Costs** 0.0 9.8 0.0 9.9 0.0 9.2 10.2

CO 2 

### Captured Cost (excluding T&S) , $/tonne B 

### N/A 78.9 N/A 66.5 N/A 63.2 61.0

CO 2 

### Avoided Cost (including T&S) , $/tonne B 

### N/A 118.7 N/A 102.9 N/A 91.7 99.3

A 

### A ll cases use high

- risk financial assumptions consistent with NETL’s “QGESS: Cost Estimation Methodology for NETL Assessments of Power Plant Performance.” (2)

B 

### Both the costs of CO 2 

### captured and avoided were calculated based on the non

- capture supercritical pulverized coal (Case B12A ) data provided in the “ Cost and Performance Baseline for Fossil Energy Plants, Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity, Revision 3 ” report

. (3) Case

B 1 2A has a COE of $ 82.3 / MWh , a CO 2 

### emission rate of 1,618 lb/MWh

- gross, a gross plant output of

5 79

, 7 00 kW, and a net plant output of 550,012 kW.



## The primary conclusions that can be drawn are:

• E

- Gas TM 

## has the lowest total overnight cost (TOC) cost among the non

- capture cases.
The E

- Gas TM 

## 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

- Ga s TM 

## can use a firetube boiler because the two

- stage design reduces

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

needed.

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

which reduces th e height of the main gasifier structure. The E

- Gas TM 

## proprietary slag removal system

– used instead of lock hoppers below the gasifier

– also contributes to the lower structure height.

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

- Gas TM



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



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

the low

- cost technology in the CO 2 

## capture cases, with E

- Gas TM 

## normalized TOC approximatel y 5 percent higher and Shell approximately 17 percent higher.

• The ASU cost represents

, on average
, 12 percent of the TOC (range from 10

- 13 percent). The ASU cost includes oxygen and nitrogen compression, and in the non

- capture cases, it

also includes th e cost of the CT extraction air heat exchanger. With nitrogen dilution used to the maximum extent possible, nitrogen compression costs are significant.

• The normalized TOC premium for adding CO 2 

## capture averages 43 percent ($4,430/kW versus $3,105/kW).

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

• In the non

- capture cases the E

- Gas TM 

## gasifier has the lowest COE, but the differential with Shell is reduced ( relative to the normalized TOC comparison ) primarily beca use of the higher efficiency of the Shell gasifier. The Shell COE is 7 percent higher than E

Gas TM 

## (compared to 14 percent higher normalized TOC). The GEE gasifier COE is about 3 percent higher than E

- Gas TM



## .

• In the capture cases the variation in COE is s mall ; however

, the order of the GEE and E

Gas TM 

## gasifiers is reversed. The range i s from $144.7/M Wh for GEE Radiant to $162.4 / M Wh for Shell with GEE Quench and E

- Gas TM 

## intermediate at $148.9/MWh and
$151.8/M Wh, respectively. The COE CO 2 

## capture premium for the cases averages 47 percent (range of 41 to 52 percent).

• The CO 2 

## T&S COE component composes less than 7 percent of the total COE in all

capture cases.

• In the event that future legislation assigns a cost to carbon emissions, all of th e technologies examined in this report will become more expensive. The technologies without carbon capture will be impacted to a larger extent than those with carbon capture.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 8 Exhibit ES

- 5 COE by cost component

Source: NETL



# Special Considerations on Reported Costs

Capital Costs:

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

- 15

percent /+30 percent , consistent with Association for the Advancement of Cost Engineering ( AACE ) Class 4 cost estimates (i.e., feasibility study ) (4) (5) (6) , based on the level of engineering design performed. In all cases, the report intends to represent the nex t commercial offering and relies on vendor cost estimates for component technologies. It also applies process contingencies at the appropriate subsystem levels in an attempt to account for expected but

undefined costs , which can be a challenge for emergin g technologies.

Costs of E merging T echnologies and D esigns:

The cost estimates for plant designs that include technologies that are not yet fully mature (e.g., IGCC plants and any plant with CO 2 

## capture) use the same cost estimating methodology as for mature plant designs (e.g., PC and NGCC power plants without CO 2 

## capture) , which does not fully account for the unique cost premiums associated with the initial, complex integrations of emerging tec hnologies in a commercial application. Thus, it is anticipated that initial deployments of IGCC plants

– both with and without CO 2 

## capture

– may incur costs higher than those reflected within this report.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 9 Other F actors:

Actual reported project costs fo r all of the plant types are also expected to deviate from the cost estimates in this report due to project

- and site

- specific considerations (e.g.

, contracting strategy, local labor costs, seismic conditions, water quality, financing parameters, local env ironmental concerns, weather delays, etc.) that may make construction more costly. Such variations are not captured by the reported cost uncertainty.

Future Cost Trends:

Continuing research, development, and demonstration (RD&D) is expected to result in designs that are more advanced than those assessed by this report, leading to costs that are lower than

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



## 10 

# 1 Introduction

The objective of this report i s to present an accurate, independent assessment of the cost and performance of fossil energy power systems, specifically integrated gasification combined cycle ( IGCC ) plants, using a consistent technical and economic approach that reasonably reflects

current market conditions.

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

• Volume 1: Bituminous Coal and Natural Gas to Electricity

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

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

• Volume 4: Bituminous Coal to Liquid Fuels

This report , Volume 1b, retains the IGCC design and performance updates from the November 2010 release of Volume 1 (Revision 2) 4 

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

dollars. Volume 1a covers the cost and performance update of all pulverized coal (PC) and natural gas combined cycle (NGCC) cases (3) . Section 4 has a revision control table listing the updates applied to this report.

Selection of new g eneration 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 r egulation o f air, water, and solid waste discharges from fossil

fueled power plants

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

of recent commercial

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

Clean Coal and Carbon Management Program

Seven power plant configurations were analyzed

, as listed in Exhibit 1

- 1 . The list includes two
Shell Global Solutions (Shell) gasifiers (with and without carbon dioxide [ CO 2 

## ] capture), two

CB&I E

- Gas TM 

## full

- slurry quench (FSQ) gasifiers (with and without CO 2 

## capture), and three General Electric Energy (GEE) gasifiers (one without and two with CO 2 

## capture [ one radiant and

one quench ] ).

While input had previously been sought from various technology vendors during the development of the previous revision ( Revision 2) of this report, the final assessment of performance was determined independently and has not been reviewed by individual vendors.

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



## 11 

# Generating Unit Configurations

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

- 1

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

sections for each case.

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

size constraint. The state

- of

- the

- art 2008 F

- class CT used to model the cases comes in a standard size of 232 MW when operated on syngas at conditions set by the International Standards Organization (ISO). Each case uses two CTs f or a combined gross output of 464 MW. In the combined cycle a heat recovery steam generator (HRSG) extracts heat from the CT exhaust to power a steam turbine.

T he CO 2 

## capture cases consume more extraction steam than the non

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

than non

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

While the two CTs provide 464 MW gross output in all seven cases, the overall comb ined cycle gross output ranges from 673 to 748 MW, which results i n a range of net output from 494 (Case

B5 B

- Q) to 630 MW (Case B1A). The coal feed rate required to achieve the gross power output is also different between the six cases, ranging from 198,2 20 to 220,899 kg/hr (437,000 to 487,000 lb/hr).

The balance of this report is organized as follows:

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

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

seven cases.

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



## 12 Exhibit 1

- 1 Case descriptions

Case (Old Case Name A 

### ) Unit Cycle Steam Cycle, psig/ ° F/ ° F Combustion

Turbine Gasifier Technology Oxidant H 2 

### S Separation Sulfur

Removal PM Control NOx
Control CO 2 

### Separation B



### B1A (5) IGCC 1800/1050/1050 2 x State

- of

- the

art 2008 F

- Class Shell 95 mol%
O 2 

### Sulfinol

- M Claus

Plant Cyclone, candle filter,

and water scrubber LNB and

N 2 

### dilution

B1B (6) IGCC 1800/1000/1000 2 x State

- of

- the

art 2008 F

- Class Shell 95 mol%
O 2 

### Selexol Claus

Plant Cyclone, candle filter,

and water scrubber LNB and

N 2 

### dilution Selexol 2 nd


### stage

B4A (3) IGCC 1800/1050/1050 2 x State

- of

- the

art 2008 F

- Class CB&I E

- GasTM 95 mol%
O 2 

### Refrigerated

MDEA Claus

Plant Cyclone, candle filter,

and water scrubber LNB and

N 2 

### dilution

B4B (4) IGCC 1800/1000/1000 2 x State

- of

- the

art 2008 F

- Class CB&I E

- GasTM 95 mol%
O 2 

### Selexol Claus

Plant Cyclone, candle filter,

and water scrubber LNB and

N 2 

### dilution Selexol 2 nd


### stage

B5A (1) IGCC 1800/1050/1050 2 x State

- of

- the

art 2008 F

- Class GEE Radiant 95 mol%
O 2 

### Selexol Claus

Plant Quench, water scrubber,

and AGR adsorber LNB and

N 2 

### dilution

B5B (2) IGCC 1800/1000/1000 2 x State

- of

- the

art 2008 F

- Class GEE Radiant 95 mol%
O 2 

### Selexol Claus

Plant Quench, water scrubber,

and AGR adsorber LNB and

N 2 

### dilution Selexol 2 nd


### stage

B5B

- Q (2a) IGCC 1800/1000/1000 2 x State

- of

- the

art 2008 F

- Class GEE Quench 95 mol%
O 2 

### Selexol Claus

Plant Quench, water scrubber,
and AGR adsorber LNB and

N 2 

### dilution Selexol 2 nd


### stage

A 

### Previous versions of this report used a different naming convention. The change was made to provide consistent naming conventions across various baseline reports published by NETL. The old case numbers are provided in parenthesis in this table and are paired with the new case

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

B 

### All cases have a nominal 90 percent removal rate based on the total feedstoc k minus unburned carbon in slag. The rate of CO 2 

### capture from the

syngas in the Selexol s ystems varies. An explanation for the difference is provided in Section 2.3.2 . All capture cases sequester the CO 2 

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



## 13 

# 2 General Evaluation Basis

For each of the plant configurations analyzed in this report

, an Aspen Plus ® 

## (Aspen) model was developed and used to generate material and energy balances, which were, in turn

, used to provide a design basis for items in the major equipment list. The equipment list and material balances were used as the basis for generating the capital and operating cost estimates. Performance and process limits were based upon published reports, information obtained from

vendors and users of the technology, performance data from design/build utility projects, and/or best engineering judgment. Capital and operating costs were estimated by WorleyParsons based on simulation results using an in

- house database and conceptual estimating models. Costs were further calibrated using a combination of adjusted vendor

- furnished data and scaled estimates from previous design/build projects. These costs were established in 2007 dollars in prior reports and updated to 2011 dollars in this report. No changes were made to the performance or base cost methods in this update. Ultimately

, a COE was calculated for each of the cases and is reported as the revenue requirement figure

- of

- merit.

The balance of this section discus s es the design basis common to all technologies, as well as environmental targets and cost assumptions used in this report . Technology specific design

criteria are covered in su bsequent chapters.



# 2.1 Site Characteristics

All plants in this report are assumed to be located at a generic plant site in Midwestern United States ( U.S. ) , with site characteristics and ambient conditions as presented in E xhibit 2

- 1 and

Exhibit 2

- 2

. The ambient conditions are the same as ISO conditions

. Exhibit 2

- 1 Site characteristics

Parameter Value

Location Greenfield, Midwestern U.S.

Topography Level

Size, acres 300

Transportation Rail or Highway

Slag Disposal Off

- Site

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



## 14 Exhibit 2

- 2 Site ambient conditions

Parameter Value

Elevation, (ft) 0

Barometric Pressure, MPa (psia) 0.101 (14.696)

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

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

Design Ambient Relative Humidity, % 60

Cooling Water Temperature, °C ( ° F) A 

### 15.6 (60)

Air composition based on published psychrometric data , mass %

N 2 

### 75.055

O 2 

### 22.998

Ar 1.280

H 2 

### O 0.616

CO 2 

### 0.050

Total 100.00

A 

### The cooling water temperature is the cooling tower cooling water exit temperature.
This is set to 8.5°F above ambient wet bulb conditions in ISO cases.



## The land area assumes that 30 acres are required for the plant proper

, and the balance provides a buffer of approximately 0.25 mi to the fence line. The extra land could also provide for a rail loop if required (rail loop is not included in this report )

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

is not enclosed.

The following design parameters are considered site

- specific and are not quantified for this

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

• Flood plain considerations

• Existing soil/site conditions

• Water discharges and reuse

• Rainfall/snowfall criteria

• Seismic design

• Buildings/enclosures

• Local code height requirements

• Noise regulations

– Impact on site and surrounding area

• Other localized environmental concerns

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



## 15 

# 2.2 Coal Characteristics

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

- 3 . The coal properties are from the January 2012 revision of the Quality Guidelines for Energy System

Studies (QGESS) document “Detailed Coal Specifications

. ” (7)

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

“Fuel Prices for Selected Feedstocks in NETL St udies

. ” (8) The current coal price is $2.94/MMBtu (HHV basis) for Illinois No. 6 bituminous coal delivered to the Midwest in June

2011 dollars

.

Exhibit 2

- 3 Design coal

Rank Bituminous

Seam Illinois No. 6 (Herrin)

Source Old Ben Mine Proximate Analysis (weight %) A



### As Received Dry

Moisture 11.12 0.00

Ash 9.70 10.91

Volatile Matter 34.99 39.37

Fixed Carbon 44.19 49.72

Total 100 .00 100 .00

Sulfur 2.51 2.82 HHV, kJ/kg (Btu/lb) 27,113 (11,666) 30,506 (13,126)

LHV , Btu/lb (Btu/lb) 26,151 (11,252) 29,544 (12,712) Ultimate Analysis (weight %)

As Received Dry

Moisture 11.12 0.00

Carbon 63.75 71.72
Hydrogen 4.50 5.06 Nitrogen 1.25 1.41

Chlorine 0.29 0.33

Sulfur 2.51 2.82

Ash 9.70 10.91 Oxygen B 

### 6.88 7.75

Total 100 .00 100 .00

A 

### The proximate analysis assumes sulfur as volatile matter

B 

### By difference



## The mercury content of 34 samples of Illinois No. 6 coal has an ar ithmetic mean value of

0.09 ppmwd with standard deviation of 0.06 based o n coal samples shipped by Illinois mines. (9)
Hence, as illustrated in Exhibit 2

- 4 , there is a 50 percent probability that the mercury content in

the Illinois No. 6 coal would not exceed 0.09 ppm wd . The coal mercury content for this report was assumed to be 0.15 ppmwd for all cases, which corresponds to the mean plus one standard deviation and encompasses about 84 percent of the samples. It was further assumed that all of the coal Hg enters the gas phase and none leaves with the slag

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



## 16 Exh ibit 2

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

Source: NETL



# 2.3 Environmental Targets

The environmental performance of the IGCC configurations described in this report were determined based upon the IGCC performance capabilities at the time of the plant model development in prior revisions. Since that time

, spe ci fic environmental targets have been identified that require minimal adjustment to the previously designed systems. The only addition was the use of a dual bed carbon system for mercury (Hg) removal. The current e nvironmental

targets for this study are as follows:

• Mercury (Hg) and hydrochloric acid (HCl) limits were set by the March 2013 update to the Utility Merc ur y and Air Toxics Standards (MATS)

. (11)

, (12)

, (13)

• Particulate matter (PM) , sulfu r dioxide (SO 2 

## ) , and nitrogen oxide (NOx) limits were set by the February 2013 update to the New Source Performance Standards (NSPS)

. (13)

, (14)

The regulations divide the coal types into low rank and non

- low rank based on their heating

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

- matter free basis are consi dered non

- low rank. The refore, Illinois N o. 6 coal, with an HHV (moist, mineral

- matter free) of 12,900 Btu/lb, is considered a non

- low rank coal.

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

- 5

.

Exhibit 2

- 5 MATS and NSPS emission limits for PM, HCl, SO 2 

### , NOx, and Hg

Pollutant A 

### (lb/ MWh

- gross)

SO 2 

### 0.40

NOx 0.70 PM (Filterable) 0.07 Hg 3x10

- 6



### HCl 0.002

A 

### CO emissions may be considered in later revisions of this report, if necessary. 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

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

Mercury Concentraion in Coal, ppm dbProbability Illinois #6 Sample Will Be At or Below Value Arithmetic Mean = 0.09 ppm db Standard Deviation = 0.06 ppm dbCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 17 These new regulations apply to IGCC technologies that begin construction after May 3, 2011. Furthermore, these regulations state that (13)

, (15) :

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

fuel derived from such material.

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

- fired combustion unit of more than 25 megawatts electric (MWe) that serves a generator that produces electricity for sale. A fossil fuel

- fired unit that cogenerates steam and electricity and supplies more than one

- third of its potential electr ic output capacity and more than 25 MWe output to any utility power distribution system for sale is considered an electric utility steam generating unit.

Fossil fuel

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

fuels. To be c apable of combusting fossil fuels, an EGU would need to have these fuels allowed in its operating permit and have the appropriate fuel handling facilities on

- site or otherwise available (e.g., coal handling equipment, including coal storage area, belts and conveyers, pulverizers, etc.; oil storage facilities).

Coal

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

definition of “fossil fuel

- fired

, ” which is that it b urns coal for more than 10 percent of the average annual heat input during any three consecutive cale ndar years or for more than

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

Integrated gasification combined cycle electric utility steam generating unit s
, or IGCC s
, are defined as an EGU and meet the definition of “fossil fuel

- fired

, ” which is that it burns a synthetic gas derived from coal and/or solid oil

- derived fuel for more than 10 percent of the average annual heat input during any three consecutive cale ndar years or for more

than 15 percent of the annual heat input during any one calendar year in a combined

cycle combustion turbine. No solid coal or solid oil

- derived fuel is directly burned in the unit during operation.

Unit designed for low

- rank virgin coal subcategory is defined as any coal

- fired EGU that is designed to burn

, and that is burning

, non

- agglomerating virgin coal having a calorific value (moist, mineral matter

- free basis) of less than 19,305 kJ/kg (8,300 Btu/lb) that is constructed and operates at or near the mine that produces such coal.

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

- fired EGU that is

not a coal

- fired EGU in the “unit designed for low rank virgin coal” subcategory.

Other regulations that could affect emissions limits from a new plant include the New Source Review (NSR) permitting process and Prevention of Significant Deterioration (PSD). The NSR process requires installation of emission control technology

, meeting either the Best Available

Control Tec hnology ( 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’s ( EPA ) Green Book

Non

- attainment Area Map

, relatively few areas in the Midwes tern U.S. are classified as “non

attainment

, ” so the plant site for this report was assumed to be in an attainment area. (14)Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



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

regu lations on a new facility. However, since each new plant has unique environmental requirements, it was necessary to apply some judgment in setting the environmental targets for this report

.


# 2.3.1 Study Cases

Exhibit 2

- 6 provides the emissions limits for IGCC plants as well as a brief summary of the control technology utilized to satisfy the limits.

Exhibit 2

- 6 Environmental targets

Pollutant (lb/MWh

- g ross) Control Technology

SO 2 

### 0.40 Selexol, MDEA

, or Sulfinol (depending on gasifier technology) A



### NOx 0.70 Low NOx burners and syngas nitrogen dilution

PM (Filterable) 0.07 Quench, water scrubber, and/or cyclones and candle filters (depending on gasifier technology)

Hg 3x10

- 6 

### Dual c arbon bed

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

A 

### The sulfur control technologies are used to remove H 2 

### S formed in the gasifier to ultimately limit SO 2 

### emissions after the syngas is combusted in the CT.



## Based on published vendor literature, it was assumed that low NOx burners ( LNB ) and nitrogen dilution can achieve 15 ppmvd at 15 percent O 2 

## , and that value was used for all cases. (16)

, (17)

The SO 2 

## limit is met via an acid gas removal (AGR) process. As the emissions limit is based on the gross power production of the plant, the actual removal efficiency is dependent on the net plant efficiency . Therefore, the required AGR H 2 

## S removal efficiency va ries from 75 to 98 percent in the cases without CO 2 

## capture . Vendor data on the AGR processes used in the non

capture cases indicate that the required level of sulfur removal in each technology is possible. The sulfur removal efficiency of the CO 2 

## captur e cases is approximately 99.9 percent. The high

rate of H 2 

## S removal is a function of the CO 2 

## capture rate requirement (described in Section 2.3.2 )

of the two

- stage Selexol process.

Most of the coal ash is removed from the gasifier as slag. The ash that remains entrained in the syngas is captured in the downstream equipment , including the syngas scrubber, cyclone

, and either ceramic or metallic candle filters ( E

- Gas TM 

## and Shell). Each combination of particulate control devices can achieve the environmental target.

The Eastman Chemical plant, where syngas from a GEE gasifier is treated, achieved a mercury removal efficiency of 95 percent. Sulfur

- impregnated activate d carbon is used by Eastman as the adsorbent in the packed beds operated at 30°C (86°F) and 6.2 MPa (900 psig). Mercury removal between 90 and 95 percent has been reported with a bed life of 18 to 24 months. Removal efficiencies may be even higher, but

, at 95 percent

, the measurement precision limit was reached. Eastman has yet to experience any mercury contamination in its product. (18) As a mercury removal efficiency of up to 97 percent is required to meet the mercury emissi ons limit, a dual

sulfur

- impregnated carbon bed system (i.e.

, two beds in series) is required, which is capable of achieving greater than 99 percent mercury removal. It was assumed that the mercury removalCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 19 efficiency is linearly related to bed depth and

, therefore, the bed depths were chosen to meet the

emission limit.

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

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

The HCl removed in the syngas scrubber is sent to a treatment plant where calcium hydroxide is used to precipitate calcium chloride as a byproduct. The treated stream is mixed with the condensed water streams and sent to the sour water stripper, where the HC l is separated out with the vapor stream and sent to the Claus plant.



# 2.3.2 Carbon Dioxide

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

carbon dioxide for new fossil fuel

- fired electric utility generating units. As of th e publication of this report, the EPA is finalizing a rule that may set CO 2 

## emissions limits below that of fossil

fuel

- fired electric ut i lity generation units without CO 2 

## capture.

For the cases that have CO 2 

## capture, the basis is a nominal 90 percent ca rbon removal rate based on carbon input from the coal and excluding carbon that exits the gasifier with the slag. In the GEE and Shell cases, this was accomplished by using two sour gas shift ( SGS ) reactors, to

convert CO to CO 2 

## , and a two

- stage Selexol p rocess with a second stage CO 2 

## removal efficiency of 92 percent, a number that was supported by vendor quotes. All gasifiers, except E

- Gas TM



## , achieve a nominal carbon removal rate of 90 percent

. In the E

- Gas TM 

## case, in an effort to

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

, and the Selexol efficiency was increased to 95 percent (the maximum removal efficiency supported by vendor quotes). This was done because of the high syngas methane content (1.5 vol% compar ed to 0.10

vol% in the GEE radiant gasifier and 0.06 vol% in the Shell gasifier). The E

- Gas TM 

## capture case

resulted in 89.9 percent carbon capture

.



# 2.4 Capacity Factor

2.4.1 Capacity Factor Assumptions

Availability is the percent of time during a specific period th at a generating unit is capable of producing electricity. This report assumes that each new plant would be dispatched any time it is available and would be capable of generating the nameplate capacity when online. Therefore, the capacity factor (CF) and availability are equal. The operating period selected is also important. The calculations assume that the capacity factor and availability are constant over the life of the plant, but in actual operation may require that a plant have a higher peak availa bility to counter lower availability in the first several years of operation.



# 2.4.2 Capacity Factor for IGCC Plants

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

of 85 percent

. (19) Plants built before 2000 have achieved availability of 80 percent for limited periods of time. Common projections from technology suppliers and EPRI are that IGCC plants are capable of 80

- 85 percent availability without a sp are gasifier and could achieve greater than 90 percent availability with a spare gasifier

. (20)

, (21)

, (22)

, (23)

, (24)

, (25) While an availability of 85 percent is the goal, given the IGCC technology experience and the commercialization status compared with the more conventional plants (e.g.

, PC ) , a CF of 80

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



## 20 

# 2.4.3 Capacity Factor for Plants with Carbon Capture

The addition of carbon capture adds extra equipment to the power plant. Preliminary reliability analyses show small reductions in reliability if the reliability of the base plant co mponents is kept constant. A solvent

- based carbon capture technology is used in this report . The capture and

CO 2 

## compression technologies have commercial operating experience with demonstrated ability for high reliability. Given the use of commercial te chnology

, the assumption is made that the capacity factors for a given plant with and without carbon capture are the same. Thus, the capacity factor for IGCC plants with capture is 80 percent

.


# 2.4.4 Perspective

Important factors required to achieve the projec ted IGCC plant availability include a quality plant design that utilizes lessons learned from similar plant designs, a focus on life cycle costs, a smart predictive maintenance, a trained plant staff, and an economic demand for unit power.

Plant availabili ty is determined by the plant technology, the capital cost invested in the plant (e.g.

, what is the design approach with respect to minimizing scheduled and unplanned maintenance), the maintenance requirements

, and the customer requirements for the electri city (e.g.

, customer costs due to a unit not being available). Since the unavailability cost will decrease with increasing unit availability and the maintenance and capital costs increase with increasing unit availability, there will be optimum economic u nit availability for a given application. This report assumes that the plant design, plant maintenance

, and electricity demand are consistent with the selected availability.

The existing plant data have not been analyzed with regard to the performance of individual plant availability over the life of the plant. As stated, this report assumes a constant availability

of 80 percent for each year over the life of the plant. It is recognized that the availability of a given plant will vary over the life of th e plant. As demonstrated by existing plant data, coal plants can be designed and operated with yearly availability ranging from 85

- 100 percent . It is assumed that the plants in this report will have yearly availability factors above and below the

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

selected value.



# 2.5 Raw Water With drawal and C onsumption

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

, and internal recycle water available

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

CO 2 

## capture cases) was applie d to offset the water demand. The difference between demand and recycle is raw water withdrawal. Raw water withdrawal is the water removed from the ground

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

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

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

withdrawn.

Raw water makeup was assumed to be provided 50 percent by a publicly owned treatment works (POTW) and 50 percent from groundwater. Raw water withdrawal is defined as the water metered from a raw water source and used in the plant processes for any and all purposes, such as cooling tower makeup, BFW mak eup, slurry preparation mak eup , syngas humidification, andCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 21 quench system makeup . The difference between withdrawal and process water returned to the source is consumption. Consumption represents the net impact of the process on the water

source.

BFW blowdown and a portion of the s our water stripper blowdown were assumed to be treated and recycled to the cooling tower. The cooling tower blowdown and the balance of the SWS blowdown streams were assumed to be treated and 90 percent returned to the water source with

the balance sent t o the ash ponds for evaporation.

The largest consumer of raw water in all cases is cooling tower makeup. It was assumed that all cases utilized a mechanical draft, evaporative cooling tower, and all process blowdown streams

were assumed to be treated and recycled to the cooling tower. The design ambient wet bulb temperature of 11°C (51.5°F) ( Exhibit 2

- 1 and Exhibit 2

- 2 ) was used to achieve a cooling water temperature of 16°C (60°F) using an approach of 5°C (8.5°F). The cooling water range was assumed to be 11°C (20°F). The cooling tower makeup rate was determined using the follo wing (26) :

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

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

• Blowdown losses (BDL) were calculated as follows:

BBBBBB = EE

CCCC

− 1

Where:

EL

– Evaporative Losses

CC

– Cycles of concentration

The cycles of concentration are a measure of water qu ality and a mid

- range value of four was chosen for this report.

The water balances presented in subsequent sections include the water de mand of the major water consumers within the process, the amount provided by internal recycle, the amount of raw water withdrawal by difference, the amount of process water returned to the source

, and the raw water consumption, again by difference.



# 2.6 Cost Es timating Methodology

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

, and construction ( EPC ) contractor services, estimation of capital cost contingencies, owner’s costs, cost estimate scope, economic assump tions, finance structures, cost of electricity, etc. are
available in the April 2011 revision of the QGESS document “ Cost Estimation Methodology for

NETL Assessment of Power Plant Performance

. ” (2) Select portions are repeated in this report for completeness.

Capital Costs:

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

- 15

percent /+30 percent , consistent with Association for the Advancement of Cost Engineering ( AACE ) Class 4 cost estimates (i.e., feasibility study ) (4) (5) (6) , based on the level of engineering design performed. In all cases, th is report intends to represent the ne xt commercial offering and relies on vendor cost estimates for component technologies. It also applies processCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



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

undefined costs , which can be a challenge for emergi ng technologies.

Costs of E merging T echnologies and D esigns:

The cost estimates for plant designs that include technologies that are not yet fully mature (e.g., IGCC plants and any plant with CO 2 

## capture) use the same cost estimating methodology as for mature plant designs (e.g., PC and NGCC power plants without CO 2 

## capture) , which does not fully account for the unique cost premiums associated with the initial, complex integrations of emerging tec hnologies in a commercial application. Thus, it is anticipated that initial deployments of IGCC plants

– both with and without CO 2 

## capture

– may incur costs higher than those reflected within this report.

Other F actors:

Actual reported project costs fo r all of the plant types are also expected to deviate from the cost estimates in this report due to project

- and site

- specific considerations (e.g.

, contracting strategy, local labor costs, seismic conditions, water quality, financing parameters, local env ironmental concerns, weather delays, etc.) that may make construction more costly. Such variations are not captured by the reported cost uncertainty.

Future Cost Trends:

Continuing research, development, and demonstration (RD&D) is expected to result in designs that are more advanced than those assessed by this report, leading to costs that are lower than

those estimated herein.



# 2.6.1 Capital Costs

As illustrated in Exhibit 2

- 7

, this report defines capital cost at five levels: BEC, EPCC, TPC,

TOC

, and TASC. BEC, EPCC, TPC

, and TOC are “overnight” costs and are expressed in “base

year” dollars. The base year is the first year of capital expenditure. TASC is expressed in
mixed, current

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

NETL st udies to last five years for coal plants.

The Bare Erected Cost (BEC) comprises the cost of process equipment, on

- site facilities and infrastructure that support the plant (e.g., shops, offices, labs, road), and the direct and indirect labor required for i ts construction and/or installation. The cost of EPC services and contingencies are not included in BEC. BEC is an overnight cost expressed in base

- year dollars.

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

of services provided by the EPC contractor. EPC services include: detailed design, contractor permitting (i.e., those permits that individual contractors must obtain to perform their scopes of work, as opposed to project permitting, which is not included h ere), and project/construction management costs. EPCC is an overnight cost expressed in base

- year dollars.

The Total Plant Cost (TPC) comprises the EPCC plus project and process contingencies. TPC is an overnight cost expressed in base

- year dollars.

The Total Overnight Cost (TOC) comprises the TPC plus all other overnight costs, including owner’s costs. TOC is an “overnight” cost, expressed in base

- year dollars and as such does not include escalation during construction or interest during construction.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 23 The Total As

- Spent Cost (TASC) is the sum of all capital expenditures as they are incurred during the capital expenditure period including their escalation. TASC also includes interest during construction. Accordingly, TASC is expressed in mixed, curren t

- year dollars over the capital expenditure period

.

Exhibit 2

- 7 Capital cost levels and their elements

Source: NETL



## 2.6.1.1 Cost Estimate Basis and Classification

The TPC and Operation and Maintenance (O&M) costs for each of the cases in the report were estimated by WorleyParsons us ing an in

- house database and conceptual estimating models. Costs were further calibrated using a combination of adjusted vendor

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

2.6.1.2 System Code

- of

- Accounts

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

code

- of

- account structure has the advantage of grouping all reasonably allocable c omponents of a system or process so they are included in the specific system account. (This would not be the case had a facility, area, or commodity account structure been chosen instead).

2.6.1.3 Estimate Scope

The estimates represent a complete power plant f acility on a generic site

. The plant boundary limit is defined as the total plant facility within the “fence line” including coal receiving and water supply system, but terminating at the high voltage side of the main power transformers.

CO 2 

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

and added to the COE. process equipment

supporting facilities

direct and indirect

labor 

# BEC EPCC

TPC

TOC

TASC EPC contractor services

process contingency

project contingency

pre

- production costs

inventory capital

financing costs

other owner’s costs

escalation during capital expenditure period

interest on debt during capital expenditure period Bare Erected Cost 

## Engineering , Procurement

and Construction Cost

Total Plant Cost
Total Overnight Cost

Total As

- Spent Cost

BEC, EPCC, TPC and TOC are
all “overnight” costs
expressed in base

- year dollars.

TASC is expressed in mixed

year current dollars, spread
over the capital expenditure
period.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 24 2.6.1.4 Capital Cost Assumptions

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

- house database and conceptual estimat ing 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 proces s proje cts. A reference bottom

- up estimate for each major component provides the basis for the estimating models.

Other key estimate considerations include the following:

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

Gulf Coast and the labor has been factored to Midwest. The basis for the factors is the
PAS, Inc. (PAS) “Merit Shop Wage & Benefit Survey,” which is published annually. Based on the data provided in PAS, WorleyParsons used the weighted average payroll pl us fringe rate for a standard craft distribution as developed for the estimating

models. PAS presents information for eight separate regions. For this report , Region 5 (IL, IN, MI, MN, OH, and WI) was selected

.

• The estimates are based on a competitive bi dding environment, with adequate skilled craft labor available locally.

• Labor is based on a 50

- hour work

- week (5

- 10s). No additional incentives such as per

diem allowances or bonuses have been included to attract craft labor.

• While not included at this time, labor incentives may ultimately be required to attract and retain skilled labor depending on the amount of competing work in the region, and the availability of skilled craft in the area at the time the pr ojects proceed to construction.

• The estimate s are based on a greenfield site.

• The site is considered to be Seismic Zone 1, relatively level, and free from hazardous materials, archeological artifacts, or excessive rock. Soil conditions are considered adequate for spread footing foundations. The soil bearing capability is assumed adequate such that piling is not needed to support the foundation loads.

• Engineering and Construction Management a re estimated a t 8

- 10 percent of BEC. These costs consist of all home office engineering and procurement services as well as field construction management costs. Site staffing generally includes a construction manager, resident engineer, scheduler, and personnel for project controls, document control, materials management, site safety, and field inspection.

2.6.1.5 Price Fluctuations

During the course of this report , the prices of equipment and bulk materials fluctuated substantially. Some reference quotes pre

- dated the 20 11 year cost basis while others were received post

- 20 11 . All vendor quotes used to develop these estimates were adjusted to June

20 11 dollars accounting for the price fluctuations. Price indices, e.g.
, T he Chemical Engineering

Plant Cost Index (27) and the Gross Domestic Product Chain

- type Price Index (28)

, were used as needed for these adjustments

.

2.6.1.6 Cross

- comparisons

In all technology comparison studies, the relative differences in costs are often more significant than the absolute level of TPC. This requires cross

- account comparison between technologies to review the consistency of the direction of the costs.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 25 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 assu mption differences can quickly explain any apparent anomalies. There are a number of cases where differences in design philosophy occur. Some key examples are:

• The CT account in the GE E cases include s a syngas expander

, which is not required for

the E

- G as TM 

## or Shell cases.

• The CT s for the capture cases include an additional cost for firing a high h ydrogen

content fuel

.

• The Shell gasifier syngas cooling configuration is different between the CO 2



## - capture and

non

- CO 2



## - capture cases, resulting in a significant differential in thermal duty between the syngas coolers for the two cases.

2.6.1.6.1 Process Contingency

Process contingencies were applied to the estimates in this report as follows:

• Slurry Prep and Feed

– 5 percent on G E E cases

- systems are operating at approximately 800 psi a as compared to 600 psi a for the other cases

• Gasifiers and Syngas Coolers

– 15 percent on all cases

- next

- generation commercial offering and integration with the power island

• Two

- Stage Selexol

– 20 percent on all capture cases

- unproven technology at
commercial scale in IGCC service

• Mercury Removal

– 5 percent on all cases

- minimal commercial scale experience in IGCC applications

• CTG

– 5 percent on all non

- capture cases

- syngas firing and ASU int egration ; 10

percent on all capture cases

– high hydrogen firing.

• Instrumentation and Controls

– 5 percent on all accounts

– integration issues

2.6.1.7 Owner’s Costs

Two examples of what could be included in the “other” owner’s costs are rail spur and swit ch yard costs.

Switch yard costs are dependent on voltage, configuration, number of breakers, layout, and air

insulated vs. gas

- insulated. As a rule of thumb, a 345 kV switchyard (air

- insulated, ring bus) would cost roughly $850,000 per breaker.

On

- site only rails (excludes long runs) would be expected to cost in the range of $850,000 to $950,000 per mi le (relatively flat level terrain) plus the costs of any switches/turnouts (approximately $50,000 each) and road crossings (approximately $300 per lin ear foot).

Additional details and explanation of owner’s costs are available in the April 2011 revision of the QGESS document “Cost Estimation Methodology for NETL Assessment of Power Plant

Performance

. ” (2)



# 2.6.2 Operation and Mai ntenance Costs

The production costs or operating costs and related maintenance expenses (O&M) pertain to those charges associated with operating and maintaining the power plants over their expected

life. These costs include:Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 26 • Operating labor

• Maintenance

– material and labor

• Administrative and support labor

• Consumables

• Fuel

• Waste di sposal

• Co

- p roduct or b y

- p roduct credit (that is, a negative cost for any by

- products sold)

There are two components of O&M costs; fixed O&M, which is independent of power

generat ion, and variable O&M, which is proportional to power generation. Taxes and insurance are included as fixed O&M costs, totaling 2 percent of the TPC.

2.6.2.1 Operating Labor

Operating labor cost was determined based on of the number of operators required for each specific case. The average base labor rate used to determine annual cost is $3 9

. 70 / hour . The

associated labor burden is estimated at 30 percent of the base labor rate.

2.6.2.2 Maintenance Material and Labor

Maintenance cost was evaluated on the basis of relationships of maintenance cost to initial capital cost. This represents a weighted analysis in which the individual cost relationships were considered for each major plant component or section.

2.6.2.3 Administrative and Support Labor

Labor administration and overhead charges are assessed at a rate of 25 percent of the burdened

O&M labor.

2.6.2.4 Consumables

The cost of consumables, including fuel, was determined on the basis of individual rates of consumption, the unit cost of each specific consumable commodity, and t he 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 quan tity required using reference data.

The quantities for initial fills and daily consumables were calculated on a 100 percent operating capacity basis. The annual cost for the daily consumables was then adjusted to incorporate the annual plant operating basis, or CF

. Initial fills of the consumables, fuels and chemicals, are different from the initial chemical loadings , which are included with the equipment pricing in the capital cost.

2.6.2.5 Waste Disposal

Waste quantities and disposal costs were determined/evaluated similarly to the consumables. In this report slag is considered a waste with a disposal cost of $ 27.80 /tonne ($ 25.11 /ton). The

carbon used for mercury control is considered a hazardous waste with disposal cost of $ 1,433 /tonne ($ 1,300 /ton).Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 27 2.6.2.6 Co

- Products and By

- Products

By

- product quantities were also determined similarly to the consumables. However, due to the

variable marketability of these by

- products, specifically sulfur, no credit was taken for its potential salable value.

It should be noted that by

- product credits and/or disposal costs could potentially be an additional determining factor in the choice of technolo gy 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. S lag is a potential by

- product in certain

markets. A s stated above, the slag is considered a wa ste in this report with a concomitant disposal cost.



# 2.6.3 CO 2 

# Transport and Storage

The cost of CO 2 

## transport and storage (T&S) in a deep saline formation is estimated using the

FE/NETL CO 2 

## Transport Cost Model and the FE/NETL CO 2 

## Saline Storage Cost Model. Additional detail on development of these costs is available in the May 201 4 revision of the QGESS document “ Carbon Dioxide Transport and Storage Costs in NETL Studies

. ” (29)

T&S costs are reported as first

- year costs in $/tonne of CO 2 

## , increasing at a nominal rate of 3 percent per year, consistent with the general inflation rate assumed in NETL’s energy systems studies. From the perspective of the CO 2 

## source (e.g., a power plant or other energy conversion facility), these costs are treated as a disposal cost for each tonne of CO 2 

## captured during the

assumed 30

- year operational period. From the pipeline and storage site’s perspective, this cost

represents the minimum price that the operators must charge so that they receive the revenue

needed across the 30

- year operational period to cover all costs and provide the required internal rate of return on equity (IRROE). All costs are reported in 2011 dollars.

The Transport Cost Model provides cost estimates for the construction and operation of a dedicated pipeline for transporting CO 2 

## from a CO 2 

## source to a CO 2 

## storage site. The pipeline is

assumed to be buried in the shallow subsurface and the CO 2 

## along the pipe line is assumed to be at the temperature of the surrounding soil, typically about 50 o 

## F. The CO 2 

## entering the pipeline at the plant gate is assumed to be at a pressure of 2,200 psig and exit ing the pipeline at the storage site at a pressure of 1,200 psig. At these pressures, CO 2 

## is a liquid at temperatures from approximately

- 64°F to 88°F.

It is further assumed that the pipeline is 100 km long ( 62.1 mi ) and transports 3.2 million tonnes

of CO 2 

## each year on average or approximately 8,770 tonnes per day on average. The pipeline is designed to operate at 80 percent of its maximum mass flow capacity, so the design maximum daily mass flow rate of CO 2 

## is about 10,960 tonnes/day. The m odel determines the smallest standard diameter pipe that can transport this mass flow of CO 2 

## the required distance without boosting the pressure. The m odel also determines the smallest standard diameter pipe that can transport this mass flow of CO 2 

## the required distance assuming boost pumps are placed at equal intervals along the pipeline to boost the pressure from 1,200 psig to 2,200 psig. The model then determines which of these configurations (e.g., no boost pumps, one boost pump, two boost pumps, three boost pumps, etc.) is least expensive

. The capital and operating costs used in the

m odel were taken from the open literature. The capital costs for the pipeline are based on capital costs for natural gas pipelines reported in the Oil and Gas Journal with adjustments for the higher pressures used in CO 2 

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



## 28 The financial parameters used in the FE/NETL CO 2 

## Transport Cost Model are:

• 

## Debt to equity ratio: 50%/50%

• 

## Nominal interest rate on debt: 4.5%/year

• 

## Nominal IRROE: 12%

• 

## Escalation rate: 3%

• 

## Tax rate: 38%

• 

## Project c ontingency factor of 15%

The FE/NETL CO 2 

## Transport Cost Model determines the first

- year break

- even price that needs to be charged to transport the CO 2 

## in order to cover all costs including the minimum return on equity. The model uses a weighted average co st of capital methodology in determining the

break

- even first

- year CO 2 

## price. From the perspective of the CO 2 

## source, the break

- even price is also the minimum cost of transporting CO 2



## . Transport costs are estimated to be $2.24/tonne in

2011 dollars.

Stor age costs are based on the FE/NETL CO 2 

## Saline Storage Cost Model. This model provides detailed cost estimates for the injection and monitoring of CO 2 

## under EPA regulations for Class VI injection wells as well as monitoring and reporting requirements under Subpart RR of the Greenhouse Gas Reporting Rule.

Inputs to the FE/NETL CO 2 

## Saline Storage Cost Model that have a significant influence on cost include financial parameters, timelines for the various stages of storage

, and important activities occurring i n each stage. The financial parameters include:

• 

## Debt to equity ratio: 45%/55%

• 

## Nominal interest rate on debt: 5.5%/year

• 

## Nominal IRROE: 12%

• 

## Escalation rate: 3%

• 

## Financial responsibility requirements for post

- injection site care and site closure are met by pre

- funding a modified trust fund over the period of injection operations

• 

## Project contingency factor of 15% and process contingency factor of 20%

In the FE/NETL CO 2 

## Saline Storage Cost Model, the sequestration process is divided into six stages. The timelines and important activities impacting costs for these stages are as follows:

• Regional evaluation and initial site selection: 1 year

• Site characterization: 3 years; four sites undergo site characterization with one successful site selected; pore space rights are leased

• Permitting: 2 years; drill, test

, and complete injection wells

• Operations: 30 years; installation of buildings, surface equipment, monitoring wells an d other monitoring equipment; comply with permit requirements; fund modified trust fund to cover financial responsibility requirements for post

- injection site care and site closure

• Post

- injection site care and site closure: 50 years; continue monitoring, v erification and accounting ( mega volt

- amps [ MVA ] ) per permit; costs are covered by storage site operator’s trust fund

• Long

- term stewardship : This stage is not explicitly included in the model ; however, t he possible financial implication of long

- term stewa rdship is included in the model as a

state

- sponsored trust fund that the storage operator pays into during operationsCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 29 Due to the variances in the geologic formations that make up saline formations across the U.S., region

- specific storage and monitoring cos ts are developed to correspond to the plant locations

used in NETL techno

- economic studies of energy conversion facilities. Results from the

FE/NETL CO 2 

## Saline Storage Cost Model for storage and monitoring costs were aligned with the NETL studies by takin g four generic plant locations and overlaying them with possible sequestration basins from the cost model resulting in the following pairings:

• Midwest plant location

– Illinois Basin

• Texas plant location

– East Texas Basin

• North Dakota plant location

– Wil liston Basin

• Montana plant location

– Powder River Basin

CO 2 

## storage supply

- cost curves were developed for each of the 4 basins of interest with the resulting cost for each basin at 25 gigatonnes (Gt) of potential storage shown in Exhibit 2

- 8

. Choosing this point on the supply

- cost curves provides a conservative estimate of the storage cost since many decades, if not more than a century, will pass befo re 25 Gt of CO 2 

## is stored in any of the 4 individual basins. For example, 25 Gt of storage would be sufficient for 125 GW of coal power with 90 percent CO 2 

## capture operating over 30 years.

The far right column of Ex hibit 2

- 8 shows the total T& S costs used in NETL system studies for each plant location rounded to the nearest whole dollar. Only the $11/tonne value is used in this

volume of the baseline stud y report s i nce all cases are located in the Midwest.

Exhibit 2

- 8 CO 2 

### transport and storage c osts

Plant

Location Basin Transport (2011 $/tonne) Storage Cost at 25 Gt (2011 $/tonne) T&S Value for System

Studies A 

### (2011$/tonne)

Midwest Illinois

2.24 8.69 11

Texas East Texas 8.83 11

North Dakota Williston 13.95 16

Montana Powder River 21.81 24

A 

### The sum of transport and storage costs is rounded to the nearest dollar



# 2.6.4 Cost of CO 2 

# Captured and Avoided

The cost of captured CO 2 

## represents the minimum CO 2 

## plant gate sales price that will incentivize carbon capture in lieu of a defined reference non

- capture plant. The cost of captured CO 2 

## is calculated using the following formula :

CCCCCCCC oo CCCC 2 

## CCCCCCCCCCCCCCCC = ( CCCC CCCCCC 

## − CCCC NNNNNN CCCCCC 

## )

CCCC 2 

## CCCCCCCCCCCCCCCC

The cost of CO 2 

## avoided represents the minimum CO 2 

## emissions price , when applied to both the capture and non

- capture plant that will incentivize carbon capture in lieu of a defined reference

non

- capture plant. The cost of CO 2 

## avoided is c alculated using the following formula:

CCCCCCCC oo CCCC 2 

## AAAA AA = ( CCCC CCCCCC wwwwww h TT & 

## − CCCC NNNNNN CCCCCC 

## )

CCCC 2 

## EEEE EE NNNNNN CCCCCC 

## − CCCC 2 

## EEEE EE CCCCCCCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 30 where:

• CC S

– the capture plant for which the cost of CO 2 

## captured /avoided is being calculated

• Non

- CC S

– the reference non

- capture plant, as described below

• COE

– the cost of electricity, reported in $/M Wh

o The CCS plant includes compression to 2,215 psia

o For CO 2 

## Captured, the COE excludes T&S costs

o For CO 2 

## Avoi ded, the COE includes T&S costs

• CO 2 

## Captured

– the rate of CO 2 

## captured, reported in tonne/MWh

• CO 2 

## Emissions

– the rate of CO 2 

## emitted out the stack , reported in tonne/MWh

For today’s greenfield coal with CCS plants, the reference non

- capture plant used to calculate the cost of captured and avoided CO 2 

## is a supercritical pulverized coal (SCPC) plant without

capture.



# 2.7 Differences in IGCC Study Cost Estimates Compared to Industry

Estimates

2.7.1 Project Scope

For this report, the scope of work is generally limited to work inside the project “fence line

. ” For outgoing power, the scope stops at the high voltage side of the main power transformers

. Some typical examples of items outside the fenceline include:

• New access roads and railroad tracks

• Upgrades to existin g roads to accommodate increased traffic

• Makeup water pipe outside the fence line

• Landfill for on

- site waste (slag) disposal

• Electrical transmission lines & substation

Estimates in this report are based on a generic mid

- western greenfield site having “norm al” characteristics. Accordingly, the estimates do not address items such as:

• Piles or caissons

• Rock removal

• Excessive dewatering

• Expansive soil considerations

• Excessive seismic considerations

• Extreme temperature considerations

• Hazardous or contaminated soils

• Demolition or relocation of existing structures

• Leasing of offsite land for parking or laydown

• Busing of craft labor to site

• Costs of offsite storage

This report is based on a reasonably “standard” plant. Some unusual or extraordinary process equipm ent that is not included in the analysis are as follows :

• Excessive water treatment equipmentCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 31 • Air

- cooled condenser

• Automated coal reclaim

• Zero liquid d ischarge equipment

• SCR catalyst

T his report is based on plant equip ment sized for non

- capture only; n one of the equipment has

been sized to accommodate a future conversion to CO 2 

## capture.



# 2.7.2 Labor

This report is based on Merit Shop (non

- union) labor. If a project is to use u nion labor, there is a strong likelihood that overall labor costs will be greater than those estimated in this report.

This report is based on a 50 hour work week, with an adequate local supply of skilled craft labor.

No additio nal incentives such as pe r

- diem allowances or bonuses have been included to attract

and retain skilled craft labor.



# 2.7.3 Contracting Methodology

The estimates in this report are based on a competitively bid, multiple subcontract approach,

often referred to as Engineering/Procurement/Co nstruction Management ( EPCM ) . Accordingly, the estimates do not include premiums associated with an EPC approach. It is believed that, given current market conditions, the premium charged by an EPC contractor could be as much as 30 percent or more over a n EPCM approach.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 32 

# 3 IGCC Power Plants

Seven IGCC power plant configurations were evaluated

, and the results are presented in this section. Each design is based on a market

- ready technology that is assumed to be commercially available to support startup.

The seven cases are based on the GEE gasifier, the C B&I E

- GasTM gasifier

, and the Shell gasifier, each with and without CO 2 

## capture. As discussed in Section 1 , the net output for the

seven cases varies because of the constraint imposed by the fixed CT output and the high auxiliary loads imparted by the CO 2 

## capture process.

The CT is based on a state

- of

- the

- art 2008 F

- class design. The HRSG/steam turbine cycle varies

based on the CT exhaust conditions. Steam conditions are nominally 12.4 MPa/560°C/560°C (1800 psig/1040°F/1040°F) for all of the non

- CO 2 

## capture cases and 12.4 MPa/534°C/534°C (1800 psig/994°F/994°F) for all of the CO 2 

## capture cases. The capture cases h ave a lower main and reheat steam temperature primarily because the turbine firing temperature is reduced to allow for a parts life equivalent to NGCC operation with a high

- hydrogen content fuel, which results in a lower turbine exhaust temperature.

The e valuation 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 condit ions, fuel composition

, and environmental targets a re provided in Section 2 . Section 3.1 covers general

information that is common to all of the cases; case

- specific informat ion is subsequently presented in Sections 3.2

, 3.3

, and 3.4

.



# 3.1 IGCC Common Process Areas

The cases have process areas, which are common to each plant configuration such as coal receiving and storage, oxygen supply, gas cleanup, power g eneration, 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 performanc e features are presented in the relevant case sections.



# 3.1.1 Coal Receiving and Storage

The function of the c oal r eceiving and s torage system is to unload, convey, prepare, and store the coal delivered to the plant. The scope of the system is from the trestle bottom dumper and coal receiving hoppers up to and including the slide gate valves at the outlet of the coal storage silos. Coal receiving and storage is identical in design for all seven cases; however, coal preparation and feed are gasifier

- specific.

Ope ration 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 dir ectly into a vibratory feeder. The 8 cm x 0 (3" x 0) coal from the feeder is discharged onto a belt conveyor. Two conveyors with an intermediate transfer tower are assumed to convey the coal to the coal stacker, which transfer the coal to either the long

- term storage pile or to the reclaim area. The conveyor passes under a magnetic plate separator to remove tramp iron and then to the reclaim pile.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 33 The reclaimer loads the coal into two vibratory feeders located in the reclaim hopper under the pile. The f eeders transfer the coal onto a belt conveyor that transfers the coal to the coal surge bin located in the crusher tower. The coal is reduced in size to 3 cm x 0 (11⁄4" x 0) by the crusher. A conveyor then transfers the coal to a transfer tower. In the tr ansfer 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 an d 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 cons istent need to increase single train output. “Elevated pressure” air separation designs have been implemented that result in distillation column operating pressures that are about twice as high as traditional plants. In this report , the main air compress or discharge pressure was set at 1.3 MPa (190 psia) compared to a traditional ASU plant operating pressure of about 0.7 MPa (105 psia)

. (30) For IGCC designs the elevated pressure ASU process minimizes power consumption and decreases the size of some of the equipment items. When the air supply to the ASU is integrated with the

CT , the ASU operates at or near the supply pressure from the CT ’s air compressor.

The power requirement for the ASU used in this report is 0.039 kW/lb

- O 2 

## product for all cases and the total power requirement, including the oxygen and nitrogen compressors, ranges from

0.064 kW/lb

- O 2 

## product in the E

- Gas TM 

## CO 2 

## capture ca se (B4B) to 0.072 kW/lb

- O 2 

## product in

the Shell non

- capture case (B1A).

3.1.2.1 Residual Nitrogen Injection

The residual nitrogen that is available after gasifier oxygen and nitrogen requirements have been met is often compressed and sent to the CT . Since all pro duct streams are being compressed, the ASU air feed pressure is optimized to reduce the total power consumption and to provide a good match with available compressor frame sizes.

Increasing the diluent flow to the CT by injecting residual nitrogen from the ASU can have a number of benefits, depending on the design of the CT :

• Increased diluent increases mass flow through the turbine, thus increasing the power output of the CT while maintaining optimum firing temperatures for syngas operation. This is part icularly beneficial for locations where the ambient temperature and/or elevation are high and the CT would normally operate at reduced output.

• By mixing with the syngas or by being injected directly into the combustor, the diluent nitrogen lowers the firin g temperature (relative to natural gas) and reduces the formation

of thermal NOx.

In this report , the ASU nitrogen product was used as the primary diluent with a design target of reducing the syngas lower heating value (LHV) to 4.4

- 4.7 MJ/Nm 3 

## (119

- 125 Btu/ scf). If the amount of available nitrogen was not sufficient to meet this target, additional dilution was provided through syngas humidification ; if still more dilution was required, the third option was steam injection.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 34 3.1.2.2 Air Integration

Integration betwee n the ASU and the CT can be practiced by extracting some, or all, of the ASU’s air requirement from the CT . Medium Btu syngas streams result in a higher mass flow than natural gas to provide the same heat content to the CT . Some CT designs may need to

ex tract air to maintain stable compressor or turbine operation in response to increased fuel flow

rates. Other CT s may balance air extraction against injection of all of the available nitrogen

from the ASU. The amount of air extracted can also be varied as the ambient temperature changes at a given site to optimize year

- round performance.

An important aspect of air

- integrated designs is the need to efficiently recover the heat of compression contained in the air extracted from the CT . Extraction air temperature is normally in the range of 399

- 454°C (750

- 850°F) and must be cooled to the last stage main air compressor discharge temperature prior to admission to the ASU. High

- level recovery from the extracted air occurs by transfer ring heat to the nitrogen stream to be injected into the CT with a

gas

- to

- gas heat exchanger.

It was not a goal of this project to optimize the integration of the CT and the ASU, although several papers have shown that providing 25

- 30 percent of the ASU ai r from the turbine compressor provides the best balance between maximizing plant output and efficiency without compromising pl ant availability or reliability

. (31)

, (32)

3.1.2.3 Elevated Pressure ASU Experience in Gasification

The Buggenum, Netherlands unit built for Demkolec was the first elevated

- pressure, fully integrated ASU to be constructed. It was designed to produce up to 1,796 tonnes/day (1,980 tons per day [ tpd ]) of 95 percent purity oxygen for a Shell coal

- based gasification unit that fuels a

Siemens V94.2 CT . In normal operation at the Buggenum plant the ASU receives all of its air supply from and sends all residual nitrogen to the CT

. (23)

The Polk County, Fl orida ASU for the Tampa Electric IGCC is also an elevated

- pressure, 95 percent purity oxygen design that provides 1,832 tonnes/day (2,020 tpd ) of oxygen to a GEE

coal

- based gasification unit, which fuels a General Electric 7FA CT . All of the nitrogen prod uced in the ASU is used in the CT . The original design did not allow for air extraction from the CT. After a CT air compressor failure in January, 2005, a modification was made to allow air extraction, which in turn eliminated a bottleneck in ASU capacit y and increased overall

power output

. (33)

3.1.2.4 ASU Basis

For this report , air integration is used for the non

- carbon capture cases only. In the CO 2 

## capture cases, once the syngas is diluted to the target heating value, all of the available combustion air is required to maintain mass flow through the turbine and hence maintain power output.

The amount of air extracted from the CT in the non

- capture cases is determined through a process that includes the following constraints:

• The o utput of each CT must be maintained at 232 MW

• The diluted syngas must meet heating value requirements specified by a CT vendor, which ranged fro m 4.4

- 4.7 MJ/Nm 3 

## (119

- 125 Btu/scf)Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 35 Meeting the above constraints resulted in different levels of air extraction in the three non

- carbon capture cases as shown in Exhibit 3

- 1

.

Exhibit 3

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

- carbon capture cases

Case No. B1A B4A B5A

Gasifier Shell E

- Gas TM 

### GEE

Air Extracted from Combustion Turbine , % 4.0 4.0 4.0

Air Provided to ASU, % of ASU Total 19.4 18.9 16.8



## 3.1.2.5 Air Separation Plant Process Description

The air separation plant is designed to produce 95 percent by volume O 2 

## for use in the gasifier and Claus plant . The ASU is designed with two production train s, one for each gasifier . The air compressor is powered by an electric motor. Nitrogen, containing les s than 2 percent by volume

of O 2 

## , is recovered, compressed, and used as a diluent in the CT combustor. A process schematic of a typical ASU is shown in Exhibit 3

- 2

. (34)

The air feed to the ASU is supplied from two sources. A portion of the air is extracted from the compressor of the CT (non

- CO 2 

## capture cases only). The remaining air is supplied from a stand

alone compres sor. Air to the stand

- alone compressor is first filtered in a suction filter upstream of the compressor. This air filter removes particulate, which may tend to cause compressor wheel erosion and foul intercoolers. The filtered air is then compressed in the centrifugal compressor, with intercooling and aftercooling.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 36 Exhibit 3

- 2 Typical ASU process schematic

Source: NETL



## Air from the stand

- alone compressor is combined with the extraction air, and the combined

stream is cooled and fed to an adsorbent

- based pre

- purifier system. The adsorbent removes
water, CO 2 

## , and C 4 

## + saturated hydrocarbons in the air. After passing through the adsorption beds, the air is filtered with a dust filter to remove any adso rbent 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 thr ough the off

- stream bed(s) in a direction counter current to the normal airflow. The nitrogen is heated against extraction steam (1.7 MPa [250 psia]) in a shell and tube hea t exchanger. (34) The regeneration nitrogen drives of f 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 o n

- 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 th en cooled in an aftercooler against cooling water in the first stage and against chilled water in the second stage before it is fed to the cold box. The chiller utilizes low

pressure (LP) process steam at 0.3 MPa (50 psia) to drive the absorption refriger ation cycle. TheCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 37 remaining five percent of the air is fed to a turbine

- driven, single

- stage, centrifugal booster compressor. This stream is cooled in a shell and tube aftercooler against cooling water before it

is fed to the cold box. (34)

All three air feeds are cooled in the cold box to cryogenic temperatures against returning product oxygen and nitrogen streams in plate

- and

- fin heat exchangers. The large air stream is fed directly to the first distillation column to begin the separation process. The second largest air stream is liquefied against boiling liquid oxygen before it is fed to the distillation columns. The third, smallest air stream is fed to the cryogenic expander to produce refrigeration to sustain the

cryogen ic 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 vap orized against the high

- pressure (HP) air feed before being warmed to ambient temperature. The gaseous oxygen exits the cold box and is fed to the centrifugal compressor with intercooling between each stage of compression. The compressed oxygen is then f ed to the gasification unit.

Nitrogen is produced from the cold box at two pressure levels. LP nitrogen is split into two streams. The majority of the LP nitrogen is compressed and fed to the CT as diluent nitrogen. A small portion of the nitrogen is us ed as the regeneration gas for the pre

- purifiers and recombined with the diluent nitrogen. A HP nitrogen stream is also produced from the cold box and is further compressed before it is also supplied to the CT

.


# 3.1.3 Water Gas Shift Reactors

Selection of Techno logy

In the cases with CO 2 

## separation and capture, the gasifier product must be converted to hydrogen

- rich syngas. The first step is to convert most of the syngas CO to CO 2 

## by reacting the CO with water over a bed of catalyst , producing hydrogen (H 2 

## ) as a byproduct . The H 2 

## O: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 CO 2 

## separation and capture, CO shift convertors are not required.

Water Gas Shift: CO + H 2 

## O ↔ CO 2 

## + H 2


## The CO shift converter can be located either upstream of the AGR step ( sour gas shift ) or immediately downstream (sweet gas shift). If the CO converter is located downstream of the AGR, then the metallurgy of the unit is less stringent but additional equipment must be added to the process. This is because the CO converter promotes carbonyl sulfide (COS) hydrolysis without a separate catalyst bed. Products from the gasifier are humidified with steam or water and contain a portion of the water vapor necessary to meet the water

- to

- gas criteria at the reactor inlet. If the CO converter is located downstream of the AGR, then the gasifier product would

first ha ve to be cooled and the free water separated and treated. Then additional steam would have to be generated and re

- injected into the CO converter feed to meet the required water

- to

- gas ratio. Therefore, for this report the CO converter was located upstrea m of the AGR unit and is

referred to as SGS.

Process Description

- The SGS consists of two paths of parallel fixed

- bed reactors arranged in series. Two reactors in series are used in each parallel path to achieve sufficient conversion toCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 38 meet the 90 perce nt carbon capture target. In the E

- Gas TM 

## case, a third shift reactor is added to each path to increase the CO conversion because of the relatively high amount of CH 4 

## present in the syngas. With the third reactor added, carbon capture is 89.9 percent in t he E

- Gas TM 

## case.

Cooling is provided between the series of reactors to control the exothermic temperature rise. The parallel set of reactors is required due to the high gas mass flow rate. In all three CO 2 

## capture cases the heat exchanger after the first SGS reactor is used to vaporize water that is then used to adjust the syngas H 2 

## O:CO ratio to 2:1 on a molar basis. The heat exchanger after the

second SGS reactor is used to raise intermediate

- pressure (IP) steam, which then passes through the reheater ( RH) section of the HRSG in the GEE and E

- Gas TM 

## cases, and is used to preheat the syngas prior to the first SGS reactor in the Shell case. Approximately 97 percent conversion of the CO is achieved in the GEE and Shell cases, and about 98 percent conversion is achieved in

the E

- Gas TM 

## case.



# 3.1.4 Mercury Removal

An IGCC power plant has the potential of removing mercury in a more simple and cost

- effective manner than conventional plants (e.g.

, PC) . This is because mercury can be removed from the syngas at elevated pressure and prior to combustion where syngas volumes are much smaller

than combusted flue gas volumes in conventional plants . A conceptual design for a sulfur

impregnated, activated carbon bed adsorption system was developed for mercury control. Data

on the performance of carbon bed systems were obtained from the Eastman Chemical Company, which uses carbon beds at its syngas facility in Kingsport, Tennessee

. (18) The coal mercury content (0.15 ppm dry) and carbon bed removal ef ficiency ( greater than 99 percent) were discussed previously in Section s 2.2 and 2.3 , respectively

.
Carbon Bed Location

– The packed carbon bed vessels are located upstream of the sulfur recovery unit (SRU) and syngas enters at a temperature near 38°C (100°F). Consideration was given to locating the beds further upstream be fore the COS hydrolysis unit (in non

- CO 2 

## 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 remo val efficiency

. (35) Eastman Chemical also operates their beds ahead of their SRU at a temperature of 30°C (86°F)

. (18)

Consideration was also given to locating the beds downstream of the SRU. Howeve r, it was felt that removing the mercury and other contaminants before the SRU would enhance the performance of the SRU and increase the life of the various solvents.

Process Parameters

– An empty vessel basis gas residence time of approximately 20 seconds was used based on Eastman Chemical’s experience

. (18) Allowable gas velocities are limited by considerations of particle entrainment, bed agitation, and pres sure drop. One

- foot

- per

- second superficial velocity is in the middle of the range normally encountered (35) and was selected for this application.

The bed density of 30 lb/ft 3 

## was based on the Calgon Carbon Corporation HGR

- P s ulfur

impregnated pelletized activated carbon

. (36) These parameters determined the size of the vessels and the amount of carbon required. Each gasifier train has two mercury removal bed s and there are two gasifier trains in e ach case, resulting in four carbon beds per case.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 39 Carbon Replacement Time

– Eastman Chemicals replaces its bed every 18 to 24 months

. (18) However, bed replacement is not because of mercury loading, but for other reasons includ ing:

• A buildup in pressure drop

• A buildup of water in the bed

• A buildup of other contaminants

For this report a 24 month carbon replacement cycle was assumed. Under these assumptions, the mercury loading in the bed would build up to 0.6

- 1.1 weight perce nt (wt%). Mercury capacity

of sulfur

- impregnated carbon can be as high as 20 wt%

. (37) The mercury laden carbon is considered to be a hazardous waste, and the disposal cost estimate reflects this categorization.



# 3.1.5 Acid Gas Remov al (AGR) Process Selection

Gasification of coal to generate power produces a syngas that must be treated prior to further utilization. A portion of the treatment consists of AGR and sulfur recovery. This includes all sulfur species, but in particular the total of COS and H 2 

## S, thereby resulting in stack gas

emissions of less than 4 ppmv SO 2



## .

3.1.5.1 COS Hydrolysis

The use of COS hydrolysis pretreatment in the feed to the AGR process converts the COS to a more easily capturable H 2 

## S species . This method was first commercially proven at the Buggenum plant, and was also used at both the Tampa Electric and Wabash River IGCC projects. Several catalyst manufacturers

, including Haldor Topsoe and Porocel

, offer a catalyst that promotes the COS hydrolysis reaction. The n on

- carbon capture COS hydrolysis reactor designs are based on information from Porocel. In cases with CO 2 

## capture, the SGS reactors

reduce COS to H 2 

## S as discussed in Section 3.1.3

. The COS hydrolysis reaction is equimolar with a sligh tly exothermic heat of reaction, as shown in the following reaction:

COS + H 2 

## O ↔ CO 2 

## + H 2 

## S

Since the reaction is exothermic, higher conve rsion 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 i s critical to the amount of H 2 

## S 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, promote s the COS hydrolysis reaction without promoting reaction of H 2 

## S and CO to form COS and H 2



## . Although the reaction is exothermic, the heat of reaction is dissipated among the large amount of

non

- reacting components. Therefore, the reaction is essentially is othermal. The product gas, now containing less than 4 ppmv of COS, is cooled prior to entering the mercury removal process and the AGR.

3.1.5.2 Sulfur Removal

H 2 

## S removal generally consists of absorption by a regenerable solvent. The most commonly used technique is based on counter current contact with the solvent. Acid

- gas

- rich solution from the absorber is stripped of its acid gas in a regenerator, usually by application of heat. TheCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 40 regenerated lean solution is then cooled and recirculated to the top of the absorber, completing the cycle. Exhibit 3

- 3 is a simplified diagram of the AGR process

. (38)

Exhibit 3

- 3 Flow diagram for a conventional AGR unit

Source: NETL



## There are well over 30 AGR processes in common commercial use throughout the oil, chemical, and natural gas industries. However, in a 2002 report by SFA Pacific a list of 42 operating and planned gasifiers shows that only six AGR processes are represented: Rectisol, Sulfinol, MDEA, Selexol, aqueous di

- isoproponal (ADIP) amine, and FLEXSORB

. (39) These processes can be separated into three ge neral types: chemical reagents, physical solvents, and hybrid solvents.

3.1.5.3 AGR/Gasifier Pairings used in Non

- c apture Cases

There are numerous commercial AGR processes that could meet the sulfur environmental target

of this report . The most frequently used AG R systems (Selexol, Sulfinol, MDEA, and Rectisol) have all been used with the Shell and GEE gasifiers in various applications. Both existing E

Gas TM 

## gasifiers use MDEA, but could in theory use any o f the existing AGR technologies

. (38) The following selections were made for the AGR process in non

- CO 2 

## capture cases:

• GE E gasifier: Selexol was chosen based on the GE gasifier operating at the highest pressure (815 psia versus 615 psia for E

- Gas TM 

## and Shell)

, which favors the phys ical solvent used in the Selexol process.

• E

- Gas TM 

## gasifier: Refrigerated MDEA was chosen because the two operating E

- Gas TM


## gasifiers use MDEA and because Chicago Bridge & Iron Company ( C B&I ) lists MDEA as the selected AGR process on their website

. (39) Refrigerated MDEA was chosen over conventional MDEA because the sulfur emissions environmental target chosen is just outside of the range of conventional (higher temperature) MDEA. Treated

Gas

Cooler

Lean

Solvent L/R Exchanger

Rich Solvent Absorber

Lean Solvent Pump Reboiler Stripper Acid

Gas Condenser

Feed

Gas Treated

Gas

Cooler

Lean

Solvent L/R Exchanger

Rich Solvent Absorber

Lean Solvent Pump Reboiler Stripper Acid

Gas Condenser

Feed

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



## 41 • 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 thre e cases that require CO 2 

## capture. According to the previously referenced SFA Pacific report, “For future IGCC with CO 2 

## removal for sequestration, a two

- stage Selexol process presently appears to be the preferred AGR process

– as indicated by ongoing engin eering studies at EPRI and by various engineering firms with

IGCC interests.” (40)

3.1.5.4 AGR used in CO 2 

## Capture Cases

This section provides a brief process description of the two

- stage selexol process used for

capture cases.

S yngas enters the first of two absorbers where H 2 

## S is preferentially removed using loaded

solvent from the CO 2 

## absorber. The gas exiting the H 2 

## S absorber passes through the second

absorber where CO 2 

## is removed using first flash regenerated, chilled solvent follo wed by thermally regenerated solvent added near the top of the column. The treated gas exits the absorber and is sent either directly to the CT or is partially humidified prior to entering the CT. A portion of the gas can also be used for coal drying, wh en required.

The amount of hydrogen recovered from the syngas stream is dependent on the Selexol process design conditions. In this report , hydrogen recovery is 99.4 percent. The minimal hydrogen slip

to the CO 2 

## sequestration stream maximizes the overall plant efficiency. The Selexol plant cost estimates are based on a plant designed to recover this high percentage of hydrogen.

The CO 2 

## loaded solvent exits the CO 2 

## absorber

. A portion is sent to the H 2 

## S absorber , a portion

is sent to a reabsorber

, and the remainder is sent to a series of flash drums for regeneration. The

CO 2 

## product stream is obtained from the three flash drums

. A fter flash regeneration

, the solvent

is chilled and returned to the CO 2 

## absorber.

The rich solvent exiting the H 2 

## S 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 H 2 

## S concentrator and partially flashes. The rema ining liquid contacts nitrogen from

the ASU

, and a portion of the CO 2 

## along with lesser amounts of H 2 

## S and COS are stripped from the rich solvent. The stripped gases from the H 2 

## S concentrator are sent to the reabsorber where

the H 2 

## S and COS that were co

- stripped in the concentrator are transferred to a stream of loaded

solvent from the CO 2 

## absorber. The clean gas from the reabsorber is combined with the clean gas from the H 2 

## S absorber and sent to the CT.

The solvent exiting the H 2 

## S concentrator is sen t 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 maint ain 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 exchan ge with the product gas and finally chilled in the lean chiller before returning to the top of the CO 2 

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



## 42 

# 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 treati ng. The Claus process remains the mainstay for sulfur recovery. Conventional three

- stage Claus plants, with indirect reheat and feeds with a high H 2 

## S content, can approach 98 percent sulfur recovery efficiency. However, since environmental regulations h ave 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 pla nt selected for this report can be considered a separate option from the Claus process. In this context, it is often called a tail gas treating unit (TGTU)

process.

The Claus Process

The Claus process converts H 2 

## S to elemental sulfur via the following rea ctions:

H 2 

## S + 3/2 O 2 

## ↔ H 2 

## O + SO 2



## 2H 2 

## S + SO 2 

## ↔ 2H 2 

## O + 3S

The second reaction, the Claus reaction, is equilibrium limited. The overall reaction is:

3H 2 

## S + 3/2 O 2 

## ↔ 3H 2 

## O + 3S

The sulfur in the vapor phase exists as S 2 

## , S 6 

## , and S 8 

## molecular species, with the S 2 

## predominant at higher temperatures, and S 8 

## predominant at lower temperatures.

A simplified process flow diagram of a typical three

- stage Claus plant is shown in Exhibit 3

- 4

. (40) One

- third of the H 2 

## S is burned in the furnace with oxygen from the air to give sufficient

SO 2 

## to react with the remaining H 2 

## S. Since these reactions are highly exothermic, a waste heat

boiler that recovers this heat to generate HP steam usually follows the furnace. Sulfur is condensed in a condenser that follows the HP steam recovery section. LP steam is raised in the condenser. The tail gas from the first condenser then goes to several catalytic conversion st ages, usually two to three , where the remaining sulfur is recovered via the Claus reaction. Each catalytic stage consists of gas preheat, a catalytic reactor, and a sulfur condenser. The liquid sulfur goes to the sulfur pit, while the tail gas proceeds t o the incinerator or for further processing

in a TGTU.

3.1.6.1 Claus Plant Sulfur Recovery Efficiency

The Claus reaction is equilibrium limited, and sulfur conversion is sensitive to the reaction temperature. The highest sulfur conversion in the thermal zone is l imited to about 75 percent. Typical furnace temperatures are in the range of 1093 to 1427°C (2000 to 2600°F), and as the temperature decreases, conversion increases dramatically.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 43 Exhibit 3

- 4 Typical three

- s tage C laus sulfur plant

Source: Milton Beychok (41)



## Claus plant sulfur recovery efficiency depends on many factors:

• H 2 

## S 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 H 2 

## S, 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 st age, while the rest of the gas is oxidized in the furnace to mostly SO 2 

## . This results in a more stable temperature in the furnace.

3.1.6.2 Oxygen

- Blown Claus

Large diluent streams in the feed to the Claus plant, such as N 2 

## from combustion air, or a high

CO 2 

## conte nt 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 H 2 

## S streams is the oxygen

- blown Claus process.

Th e oxygen

- blown Claus process was originally developed to increase capacity at existing conventional Claus plants and to increase flame temperatures of low H 2 

## S 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 H 2 

## S feed streams, to provide operating flexibility at lower costs than would be the case for conventional Claus units. At least four of the gasification plants in Europe use oxygen enriched

Claus units.

Oxygen enrichment results in higher temperatures in the front

- end furnace, potentially reaching

temper atures as high as 1593 to 1649°C (2900 to 3000°F) as the enrichment moves beyond 40 to

70 vol% O 2 

## in the oxidant feed stream. Although oxygen enrichment has many benefits, itsCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 44 primary benefit for lean H 2 

## S feeds is a stable furnace temperature. Sulfur rec overy is not significantly enhanced by oxygen enrichment. Because the IGCC process already requires an ASU, the oxygen

- blown Claus plant was chosen for all cases.

3.1.6.3 Tail Gas Treating

In many refinery and other conventional Claus applications, tail gas treat ing involves the removal of the remaining sulfur compounds from gases exiting the SRU. Tail gas from a typical Claus process, whether a conventional Claus or one of the extended versions of the process, usually contains small but varying quantities of COS , CS 2 

## , H 2 

## S, SO 2 

## , and elemental sulfur vapors. In addition, there may be H 2 

## , CO, and CO 2 

## 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 H 2 

## S. Then, the r esulting H 2 

## S 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. T he 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 Trea ting (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 int o the system with the choice of location being technology dependent, or it can be treated with a SCOT

- type process. In each of the seven cases the Claus plant tail gas is hydrogenated, water is separated, the tail gas is compressed and then

returned to th e AGR process for further treatment.

3.1.6.4 Flare Stack

A self

- supporting, refractory

- lined, carbon steel (CS) flare stack is typically provided to combust and dispose of unreacted gas during startup, shutdown, and upset conditions. However, in all

seven cases a flare stack was provided for syngas dumping during startup, shutdown, etc. This flare stack eliminates the need for a separate Claus plant flare.



# 3.1.7 Slag Handling

The slag handling system conveys, stores, and disposes of slag removed from the gasification

p rocess. 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 pea

sized fragments. A slag/water slurry that is between 5 and 10 p ercent solids leaves the gasifier pressure boundary through either a proprietary pressure letdown device ( E

- Gas TM 

## ) 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 t hree technologies. The slag is dewatered, the water is clarified and recycled

, and the dried slag is transferred to a storage area for disposal. The specifics of slag handling vary among the gasification technologies regarding how the water is separated and the end uses of the water recycle streams.

In this report the slag bins were sized for a nominal holdup capacity of 72 hours of full

- load operation. At periodic intervals, a convoy of slag

- hauling trucks will transit the unloading

station underneath t he 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 plantCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 45 operating at nominal rated power. While the slag is suitable for use as a component of road paving mixtures, it was assumed in this report that the slag would be landfilled at a specified

cost.



# 3.1.8 Power Island

3.1.8.1 Combustion Turbine

The CT generator selected for this application is represent ative of the state

- of

- the

- art 2008 F

class turbines. This machine is an axial flow, single spool, and constant speed unit, with variable inlet guide vane (IGV). The turbine includes advanced bucket cooling techniques, compressor aerodynamic design and advanced alloys, enabling a higher firi ng temperature than the previous generation machines. The standard production version of this machine is fired with natural gas and is also commercially offered for use with IGCC derived syngas, although only earlier versions of the turbine are currently operating on syngas. For the purposes of this report , it was

assumed that the state

- of

- the

- art 2008 F

- class turbine will be commercially available for use on both conventional and high hydrogen content syngas representative of the cases with CO 2 

## capture. High H 2 

## fuel combustion issues like flame stability, flashback, and NOx formation were assumed to be solved in the time frame needed to support deployment. However, because these are FOAK applications, process contingencies were included in the cost esti mates as described in

Section 2.6 . Performance typical of a state

- of

- the

- art 2008 F

- class turbine on natural gas at ISO conditions is presented in Exhibit 3

- 5

.

Exhibit 3

- 5 State

- of

- the

- art 2008 F

- class combustion turbine performance characteristics using natural gas (42)

State

- of

- the

- art 2008

F

- Class

Firing Temperature Class, °C ( ° F) 1

, 371+ (2

, 500+)

Airflow, kg/s (lb/s) 431 ( 950 )

Pressure Ratio 18.5

Simple Cycle Output, MW 185

Combined cycle performance

Net Output, MW 280

Net Efficiency (LHV), % 57.5

Net Heat Rate (LHV), kJ/kWh (Btu/kWh) 6,256 ( 5,934 )



## In this service, with syngas from an IGCC plant, the machine requires some modifications to the burner and turbine nozzles in order to properly combust the low

- Btu gas and expand the

combu stion products in the turbine section of the machine.

The modifications to the machine include a redesign of the original can

- annular combustors. A second modification involves increasing the nozzle areas of the turbine to accommodate the mass

and volume flow of low

- Btu fuel gas combustion products, which are increased relative to those produced when firing natural gas. Other modifications include rearranging the various auxiliary skids that support the machine to accommodate the spatial requirements of t he plant ’s general arrangement. The generator is a standard hydrogen

- cooled machine with static exciter.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 46 3.1.8.2 Combustion Turbine Package Scope of Supply

The CT is typically supplied in several fully shop

- fabricated modules, complete with all mechanical, electrical, and control systems as required for CT operation. Site CT installation

involves module inter

- connection, and linking CT modules to the plant s ystems.

3.1.8.3 CT Firing Temperature Control Issue for Low Calorific Value Fuel

A CT when fired on LCV syngas has the potential to increase power output due to the increase in flow rate through the turbine. The higher turbine flow and moisture content of the c ombustion products can contribute to overheating of turbine components, affect rating criteria for the parts lives, and require a reduction in syngas firing temperatures (compared to the natural gas firing) to maintain design metal temperature

. (43) Uncontrolled syngas firing temperature could result in

more than 50 percent life cycle reduction of stage 1 buckets. Control systems for syngas applications include provisions to compensate for these effects by maintaining virtuall y constant generation output for the range of the specified ambient conditions. IGVs and firing temperature are used to maintain the turbine output at the maximum torque rating, producing a flat rating up to the IGV full open position. Beyond the IGV ful l open position, flat output may be extended to higher ambient air temperatures by steam/nitrogen injection.

In this report the firing temperature (defined as inlet rotor temperature) in the non

- capture cases
is 1333

- 1343°C (2432

- 2449°F) and in the CO 2 

## cap ture cases is 1317

- 1322°C (2402

- 2412°F). The reduction in firing temperature in the CO 2 

## capture cases is done to maintain parts life as the

H 2 

## O content of the combustion products increases from 6

- 9 vol% in the non

- capture cases to 12

- 14 vol% in the captur e cases. The decrease in temperature also results in the lower temperature steam cycle in the CO 2 

## capture cases, ranging from 12.4 MPa/534°C/534°C (1800 psig/993°F/993°F) to 12.4 MPa/534°C/534°C (1800 psig/994°F/994°F) for all of the CO 2 

## capture cases ver sus 12.4 MPa/559°C/559°C (1800 psig/1038°F/1038°F) to 12.4 MPa/562°C/562°C (1800 psig/1043°F/1043°F) for all of the non

- CO 2 

## capture cases.

3.1.8.4 Combustion Turbine Syngas Fuel Requirements

Typical fuel specifications and contaminant levels for successful CT op eration are provided in GE Power System’s “ Specification for Fuel Gases for Combustion in Heavy

- Duty Turbines ” and presented for state

- of

- the

- art 2008 F

- c lass machines in Exhibit 3

- 6 and Exhibit 3

- 7

. (44) The vast majority of published CT performance info rmation is specific to natural gas operation. Turbine performance using syngas requires vendor input as was obtained for this report

.

Exhibit 3

- 6 Typical fuel specification for state

- of

- the

- art 2008 F

- c lass machines

Max Min

LHV, kJ/m 3 

### (Btu/scf) None 3.0 (100)

Gas Fuel Pressure, MPa (psia) 3.1 (450)

Gas Fuel Temperature, °C ( ° F) A 

### Varies with gas

pressure B



### Flammability Limit Ratio, Rich

- to

- Lean,

Volume Basis C 

### 2:2.1

Sulfur D

A 

### The maximum fuel temperature is defined in GEK

- 4189 (45)Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 47 B 

### To ensure that the fuel gas supply to the CT is 100 percent free of liquids the minimum fuel gas temperature must meet the required superheat over the respective dew point. This requirement is independent of the hydrocarbon and moisture concentration. Superheat calculation shall be performed as de scribed in GEI

- 4140G (44)

C 

### Maximum flammability ratio limit is not defined. Fuel with flammability ratio significantly larger than those of natural gas may require start

- up fuel

D 

### The quantity of sulfur in syngas is not lim ited by specification. Experience has shown that fuel sulfur levels up to one percent by volume do not significantly affect oxidation/corrosion rates



## 3.1.8.5 Normal Operation

Inlet air is compressed in a single spool compressor to a pressure ratio of approximatel y 16:1. This pressure ratio was vendor specified and less than the 17 :1 ratio used in natural gas applications. The majority of compressor discharge air remains on board the machine and passes to the burner section to support combustion of the syngas. C ompressed 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 C T and ASU in CO 2 

## capture cases as well; however, in this report integration was considered only for non

- carbon capture cases.

Exhibit 3

- 7 Allowable gas fuel contaminant level for state

- of

- the

- art 2008 F

- c las s machines

Turbine Inlet Limit, ppbw Fuel Limit, ppmw

**Turbine Inlet Flow/Fuel Flow**

**50 12**  **4**

Lead 20 1.0 0.240 .080

Vanadium 10 0.5 0.120 0.040

Calcium 40 2.0 0.480 0.160

Magnesium 40 2.0 0.480 0.160

Sodium + Potassium

Na/K = 28 A 

### 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 B 

### 600 30 7.2 2.4

Above 10 microns 6 0.3 0.072 0.024

A 

### N ominal sea salt ratio

B 

### The fuel gas delivery system shall be designed to prevent generation or admittance of solid particulate to the CT gas fuel system



## Pressurized syngas is combusted in 14 parallel diffusion combustors

, and syngas dilution is used

to limit NOx formation. As d escribed 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

a chieve an LHV of 4.4

- 4.7 MJ/Nm 3 

## (119

- 125 Btu/scf) . The advantages of using nitrogen as the primary diluent include:

• Nitrogen from the ASU is already partially compressed and using it for dilution eliminates wasting the compression energy.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 4 8 • Limiting the wat er content reduces the need to de

- rate firing temperature, particularly in the high

- hydrogen (CO 2 

## capture) cases.

There are some disadvantages to using nitrogen as the primary diluent, and these include:

• There is a significant auxiliary power requirement t o further compress the large nitrogen flow from the ASU pressures of 0.4 and 1.3 MPa (56 and 182 psia) to the CT pressure of 3.2 MPa (465 psia).

• Low

- quality heat not otherwise useful for other applications can be used to preheat water for the syngas humidi fication process.

• Nitrogen is not as efficient as water in limiting NOx emissions

. It is not clear that one dilution method provides a significant advantage over the other. However,

in this report nitrogen was chosen as the primary diluent based on suggestions by turbine industry experts during peer review of the report.

Hot combustion products are expanded in the three

- stage turbine

- expander. Given the assumed
ambient conditions, back

- end loss, and HRSG pressure drop, the CT exhaust temperature is nominally 588°C (1

, 090°F) for non

- CO 2 

## capture cases and 562°C (1

, 044°F) for capture cases.

Gross turbine power, as measured prior to the generator terminals, is 232 MW per train . The CT generator is a standard hydrogen

- cooled machine with static exciter.



# 3.1.9 Steam Generation Island

3.1.9.1 Heat Recovery Steam Generator

The HRSG is a horizontal gas flow, drum

- type, multi

- pressure design that is matched to the

characteristics of the CT exhaust gas. High

- temperatu re flue gas exiting the CT is conveyed through the HRSG to recover the large quantity of thermal energy that remains. Flue gas travels through the HRSG gas path and exits at 132°C (270°F) for all 7 cases.

The HP drum produces steam at main steam pressure, while the IP drum produces process steam and turbine dilution steam, if required. The HRSG drum pressures are nominally 12.4/3.1 MPa (1

, 800/443 psia) for the HP/IP turbine sections, respectively. In addition to generating and superheating steam, the HRS G performs reheat duty for the cold/hot reheat steam for the steam turbine, provides condensate and feedwater (FW) heating, and also provides deaeration of the

condensate.

Natural circulation of steam is accomplished in the HRSG by utilizing differences in densities due to temperature differences of the steam. The natural circulation HRSG provides the most

cost

- effective and reliable design.

The HRSG drums include moisture separators, internal baffles, and piping for FW/steam. All tubes, including economi zers, 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 str uctural steel. Inlet and outlet duct is provided to route the gases from the CT outlet to the HRSG inlet and the HRSG outlet to the stack. A diverter valve is included in the inlet duct to bypass the gas when appropriate. Suitable expansion joints are a lso included.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 49 3.1.9.2 Steam Turbine Generator and Auxiliaries

The steam turbine consists of an HP section, an IP section, and one double

- flow LP section, all connected to the generator by a common shaft. The HP and IP sections are contained in a single

span, oppo sed

- 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 contr ol valves and enters the turbine at either 12.4 MPa/559°C to 562°C (1

, 800 psig/1

, 038°F to 1

, 043°F) for the non

- carbon capture cases, or 12.4 MPa/534°C (1

, 800 psig/993°F to 994°F) for the carbon capture cases. The steam initially enters the turbine near th e middle of the HP span, flows through the turbine, and returns to the HRSG for reheating. The reheat steam flows through the reheat stop valves and intercept valves and enters the IP section at 3.1 MPa/558°C to 561°C (443 psig/1

, 036°F to 1

, 041°F) for the non

- carbon capture cases or 3.1 MPa/532°C to 533°C (443 psig/990°F to 992°F) for the carbon capture cases. After passing through the IP section, the steam enters a crossover pipe, which transports the steam to the LP

section. The steam divides into two paths and flows through the LP sections, exhausting

downward into the condenser.

Turbine bearings are lubricated by a closed

- loop (CL), water

- cooled, pressurized oil system. The oil is contained in a reservoir located below the turbine floor. During star tup 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 en tering 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 arran gement connected to a n LP steam seal system. During startup, seal steam is provided from the main steam line. As the unit increases load, HP turbine gland leakage provides the seal steam. Pressure

- regulating valves control the gland header pressure and dump any excess steam to the condenser. A steam packing exhauster maintains a vacuum at the outer gland seals to prevent leakage of steam into the turbine room. Any steam collected is condensed in the packing exhauster and returned to the condensate

syst em.

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 hea t absorbed by the gas is removed as it passes over finned tube gas coolers mounted in the stator frame. Gas is prevented from escaping at the rotor shafts by a CL oil seal system. The oil seal system consists of storage tank, pumps, filters, and pressure controls, all skid

- mounted.

The STG is controlled by a triple

- redundant, microprocessor

- based electro

- hydraulic control system. The system provides digital control of the unit in accordance with programmed control algorithms, color cathode ray tube (CRT) operator interfacing, and datalink interfaces to the

balance

- of

- plant DCS, and incorporates on

- line repair capability.

3.1.9.3 Condensate System

The condensate system transfers condensate from the condenser hotwell to the deaerator, through the gland steam conden ser, gasifier, and the low

- temperature economizer section in the HRSG.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 50 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 f or the gland steam condenser and the condensate pumps.

3.1.9.4 Feedwater System

The function of the FW system is to pump the various FW streams from the deaerator storage tank in the HRSG to the respective steam drums. Two 50 percent capacity boiler feed pumps a re provided for each of 3 pressure levels, HP, IP, and LP. Each pump is provided with inlet and outlet isolation valves, and outlet check valve. Minimum flow recirculation to prevent overheating and cavitation of the pumps during startup and low loads is provided by an automatic recirculation valve and associated piping that discharges back to the deaerator storage

tank. Pneumatic flow control valves control the recirculation flow.

The FW pumps are supplied with instrumentation to monitor and alarm on low oil pressure, or high

- bearing temperature. FW pump suction pressure and temperature are also monitored. In addition, the suction of each boiler feed pump is equipped with a startup strainer.

3.1.9.5 Main and Reheat Steam Systems

The function of the main stea m system is to convey main steam generated in the synthesis gas cooler (SGC) and HRSG from the HRSG superheater outlet to the HP turbine stop valves. The function of the reheat system is to convey steam from the HP turbine exhaust to the HRSG RH,

and to t he turbine reheat stop valves.

Main steam at approximately 12.4 MPa/559°C to 562°C (1

, 800 psig/1

, 038°F to 1

, 043°F) (non

CO 2 

## capture cases) or 12.4 MPa/534°C (1

, 800 psig/993°F to 994°F) (CO 2 

## capture cases) exits the HRSG superheater through a motor

- operated stop/check valve and a motor

- operated gate valve, and is routed to the HP turbine. Cold reheat steam at approximately 3.5 MPa/349°C to 372°C (501 psia/661°F to 702°F) exits the HP turbine , flows through a motor

- operated isolation gate valve, to the HRSG reheater. Hot reheat steam at approximately 3.1 MPa/558 to 561°C (443 psig/1

, 036°F to 1

, 041°F) for the non

- carbon capture cases and 3.1 MPa/532°C to 533°C (443 psig/990°F to 992°F) for the CO 2 

## capture cases exits the HRSG RH through a motor

operated gate valve and is routed to the IP turbines.

Steam piping is sloped from the HRSG to the drip pots located near the steam turbine for

removal of condensate from the steam lines. Condensate coll ected in the drip pots and in low

point 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 header s.

Safety valves are installed to comply with appropriate codes and to ensure the safety of personnel and equipment.

3.1.9.6 Circulating Water System

The circulating water system (CWS) is a closed

- cycle cooling water system that supplies cooling

water to the condenser to condense the main turbine exhaust steam. The system also supplies cooling water to the AGR plant as required, and to the auxiliary cooling system. The auxiliaryCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 51 cooling system is a CL process that utilizes a higher quality water to remove he at 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 a pplications is removed by a mechanical draft cooling tower.

The system consists of two 50 percent capacity vertical CWPs, a mechanical draft evaporative cooling tower, and CS cement

- lined interconnecting piping. The pumps are single

- stage vertical

pumps. The piping system is equipped with butterfly isolation valves and all required expansion joints. The cooling tower is a multi

- cell wood frame counterflow mechanical draft cooling

tower.

The condenser is a single

- pass, horizontal type with divided water b oxes. 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 ai r extraction system to evacuate the condenser steam space

for removal of non

- condensable gases during steam turbine operation and to rapidly reduce the condenser pressure from atmospheric pressure before unit startup and admission of steam to the

condenser

.

3.1.9.7 Raw Water, Fire Protection, and Cycle Makeup Water Systems

The raw water system supplies cooling tower makeup, cycle makeup, service water and potable water requirements. The water source is 50 percent from a POTW and 50 percent from groundwater. Boost er pumps within the plant boundary provide the necessary pressure.

The fire protection system provides water under pressure to the fire hydrants, hose stations, and fixed water suppression system within the buildings and structures. The system consists of pumps, underground and aboveground supply piping, distribution piping, hydrants, hose stations, spray systems, and deluge spray systems. One motor

- operated booster pump is supplied on the intake structure of the cooling tower with a diesel engine backup pump installed on the water

inlet line.

The cycle makeup water system provides high

- quality demineralized water for makeup to the HRSG cycle, for steam injection ahead of the SGS reactors in CO 2 

## capture cases, and for injection steam to the auxiliary boile r 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 regenerati on 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 s ervice equipment, conduit and cable trays, and wire and cable. It also includes the main power transformer, all required foundations, and standby equipment.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 52 

# 3.1.11 Waste Treatment/Miscellaneous Systems

An onsite water treatment facility treats all runoff, cleani ng wastes, blowdown, and backwash. It is anticipated that the treated water will be suitable for discharge into existing systems and be within the EPA standards for suspended solids, oil and grease, pH, and miscellaneous metals.

The waste treatment system is minimal and consists, primarily, of neutralization and oil/water separators (along with the associated pumps, piping, etc.).

A natural gas supply line has been included in all cases for start

- up or emergency fuel.

Miscellaneous systems consisting of natural gas , service air, instrument air, and service water are provided. A natural gas supply line has been included in all cases for start

- up or emergency fuel. All truck roadways and unloading stations inside the fence area are provided.



# 3.1.12 Instrumentati on and Control

An integrated plant

- wide distributed control system (DCS) is provided. The DCS is a redundant microprocessor

- based, functionally DCS. The control room houses an array of multiple video monitor (CRT) and keyboard units. The CRT/keyboard un its are the primary interface between the generating process and operations personnel. The DCS incorporates plant monitoring and control functions for all the major plant equipment. The DCS is designed to be operational and accessible 99.5 percent of the time that it is required (99.5 percent availability). The plant equipment and the DCS are designed for automatic response to load changes from minimum load

to 100 percent. Startup and shutdown routines are manually implemented, with operator

selection o f 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 dist inct 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, temperature

and pressure

- dependent reaction. The critical controller utilizes a redundant microprocessor executing calculations and dynamic controls at 100

- to 200

- millisecond intervals. The enhanced execution speeds as well as evolved predictive controls allow the critical controller to mitigate process upsets and maintain the reactor operation within a stable set of operating parameters.



# 3.1.13 Performance Summary Metrics

This section details the methodologies of several metrics reported in the performance summaries.

Cold Gas Efficiency

The co ld gas efficiency is calculated by subtracting the heating value of any gas recycled to the gasifier from the heating value of the gas exiting the gasifier and dividing that difference by the thermal input to the gasifier. This calculation is represented by the equation:

CCCC = (

− RRRR )

TT Where:

CGE

– cold gas efficiency

GO

– heating value of gas exiting the gasifier

RI

– heating value of gas recycled to gasifierCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 53 TI

– thermal input to into the gasifier

The thermal input to the gasifier is calculated by taking the coal feed rate and multiplying by the heating value and converting the units to kW.

The components considered for the heating value of the gasifier exit gas and recycle gas are CO,

H 2 

## , CH 4 

## , H 2 

## S, NH 3 

## , and COS. Their mole fraction is extracted from the model, multiplied by the molar flow of the stream, and then multiplied by their individual heating values.

Combustion Turbine Efficiency

The combustion turbine efficiency is calculated by taking the combustion turbine power produced and dividing i t by the thermal input to the turbines. This calculation is represented by the equation:

CC = CC CC

TT Where:

C TE

– combustion turbine efficiency

C TP

– combustion turbine power

TI

– thermal input to turbines

The thermal input is calculated by taking the mole fraction of the individual gases (CO, H 2 

## , CH4,

H 2 

## S, NH 3 

## , and COS) multiplied by the molar flow rate of the total stream entering the

combustion turbine and then multiplying each by their individual heating values.

Steam Turbine Efficiency

The stea m turbine efficiency is calculated by taking the steam turbine power produced and dividing it by the difference between the thermal input and thermal output. This calculation is represented by the equation:

SS = SS
( TT

− TT )

Where:

STE

– steam turbi ne efficiency

STP

– steam turbine power

TI

– thermal input

TO

– thermal output

The thermal input is considered to be the main steam, the makeup water

, and the low pressure

steam from the BFW

. The thermal output is considered to be any extractions such as the gasifier steam, the 250 psia
header, and the BFW from the condenser.

The IP blowdown, HP blowdown, and superheater losses are also credited to the thermal input as they are extracted from t he cycle prior to the main steam but after the condensate BFW

.

Steam Turbine Heat Rate

The steam turbine heat rate is calculated by taking the inverse of the steam turbine efficiency. This calculation is represented by the equation:

SS SS = 1

SS ∗ 3

, 41 2Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 54 Where:

STHR

– steam turbine heat rate , Btu/kWh

STE

– steam turbine efficiency , fraction



# 3.2 Shell Global Solutions IGCC Cases

This section contains an evaluation of plant designs for cases B1A and B1B, which are based on the Shell gasifier. Cases B1A and B1 B are very similar in terms of process, equipment, scope and arrangement, except that Case B1B employs a syngas quench and includes SGS reactors,

CO 2 

## absorption/regeneration, and compression/transport systems. There are no provisions for

CO 2 

## removal in Ca se B1A.

The balance of this section is organized as follows:

• Gasifier Background

– provides information on the development and status of the Shell gasification technology.

• Process and System Description

– provides an overview of the technology operation as applied to Case B1A. The systems that are common to all gasifiers were covered in

Section 3.1 and only features that are unique to Case B1A are discussed further in this

section.

• Key Assumptions

– provides a summary of study and modeling assumptions relevant to

cases B1A and B1B.

• Sparing Philosophy

– provided for cases B1A and B1B

• Performance Results

– provides the main modeling results from Case B1A, including the performance summary, environmental performance, carbon balance, sulfur balance, water balance, mass and energy balance diagrams, and mass and energy balance tables.

• Equipment List

– provides an itemized list of major equipment for Case B1A with

account codes that correspond to the cost accounts in the Cost Estimates section.

• Cost Estimates

– provides a summary of capital and operating costs for Case B1A.

Process and System Description, Performance Results, Equipment List and Cost Estimates are repeated for Case B1B.



# 3.2.1 Gasifier Background

The “Coal Gasification Guidebook: Status, Application, and Technologies” report published by

the EPRI provides a detailed history of the development of several types of gasifier technology, including the Shell gasifier , as well as gasifier capacity, distinguishing characteristics, and important coal characteristics. (46)

As of 2009, Shell reported ten gasifiers in operation producing 100,000

- 150,000 Nm 3 

## /hr and

three of the same size in construc tion. Another three ranging from 150,000

- 250,000 Nm 3 

## /hr are

also in construction

. (47) The large gasifier operating in The Netherlands has a bituminous coal

handling capacity of 1,633 tonnes/day (1,800 tpd ) and produces dry g as at a rate of 158,575

Nm 3 

## /hr (5.6 million scf/hr) with an energy content of about 1,792 G J/hr (1,700 MMBtu/hr) (HHV). This gasifier was sized to match the fuel gas requirements for the Siemens/Kraftwerk

Union V

- 94.2 CT and could easily be scaled up to match state

- of

- the

- art 2008 F

- c lass turbine requirements

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



## 55 Shell gasifiers are capable of utilizing a wide variety of coal types

, and compared t o slurry fed gasifiers, the dry

- fed, cooled

- refractory lined, Shell gasifier has a lower oxygen requirement and produces a gas with a higher H 2 

## S/CO 2 

## ratio, which improves sulfur recovery. (46)

While the use of dry feed allows for lower oxygen consumption, the feed system

– which includes the coal dryin g system

– is more costly and complicated. (46)

Coal characteristics that are favorable when selecting a coal type for use with a Shell gasifier include low concentrations of ash with a moderate fusion temperature. If a coal is selected that has a high ash fusion temperature, flux addition may be necessary. The negative impact that high ash coals have on the operation of gasifiers are reduced in dry feed systems in comparison to slurry fed gasifiers. ( 46)



# 3.2.2 Process Description

In this section the overall Shell gasification process for Case B1A is described. The system description follows the block flow diagram ( BFD ) in Exhibit 3

- 8 and stream numbers reference

the same e xhibit. The tables in Exhibit 3

- 9 provide process data for the numbered streams in the

BF D.

3.2.2.1 Coal Preparation and Feed Systems

Coal receiving and handling is common to all cases and was covered in Section 3.1.1 . The receiving and handling subsystem ends at the coal silo. The Shell process uses a dry feed system, which is sensitive to the coal moisture content. Coal moisture consists of two parts,

surface moisture and inherent moisture. For coal to flow smoot hly through the lock hoppers, the

surface moisture must be removed. The Illinois No. 6 coal used in this report contains

11.12 percent total moisture on an as

- received basis (stream 9). It was assumed that the coal

must be dried to 5 percent moisture to allow for smooth flow through the dry feed system (stream 10).

The coal is simultaneously crushed and dried in the coal mill then delivered to a surge hopper with an approximate 2

- hour capacity. The drying medium is provided by combining the off

- gas from the Claus plant TGTU and a slipstream of clean syngas (stream 8) and passing them through an incinerator. The incinerator flue gas , with an oxygen content of 6 vol%, is then used to dry the coal in the mill.

The coal is drawn from the surge hoppers and fe d through a pressurization lock hopper system to a dense phase pneumatic conveyor, which uses nitrogen from the ASU to convey the coal to the gasifiers.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 56 Exhibit 3

- 8 Case B1A block flow diagram

, Shell IGCC without CO 2 

### c apture

Source: NETL G AS
T URBINE C OMBUSTOR D UCT / S YNGAS
C OOLERS G AS C OOLING
BFW H EATING
& K NOCKOUT S CRUBBER

& COS

H YDROLYSIS

E LEVATED
P RESSURE

ASU S HELL G ASIFIER M ERCURY
R EMOVAL S ULFINOL C LAUS
P LANT

S YNGAS
R EHEAT

HRSG 2 X S TATE

- OF

- THE

A RT F

- C LASS
G AS T URBINES 1 A IR TO ASU

2 3

V ENT G AS 5 10 11

G ASIFIER
O XIDANT D RY C OAL S LAG 14 15 20 21

19

4

23 24

T URBINE C OOLING A IR 25

A MBIENT A IR F LUE G AS S TACK G AS H YDROGENATION
R EACTOR AND G AS
C OOLER

22 C LEAN G AS

N ITROGEN D ILUENT

A IR S ULFUR
P RODUCT

S YNGAS C OAL
D RYER D RYING

G AS
P REP

9 W ET C OAL 17 8

6 13

12 A IR S YNGAS

S YNGAS Q UENCH
R ECYCLE T O S OUR
W ATER S TRIPPER A CID G AS

S TEAM S YNGAS
H UMIDIFICATION

18

7 T RANSPORT
N ITROGEN

26 C LAUS
P LANT O XIDANT C LAUS
P LANT O XIDANT

S TEAM
T URBINE 27 Note : Block Flow Diagram is not intended to represent a complete material balance

. Only major process streams and equipment are

shown

. 16Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 57 Exhibit 3

- 9 Case B1A stream table, Shell IGCC without c apture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V

- L Mole Fraction

Ar 0.0092 0.0262 0.0318 0.0023 0.0318 0.0000 0.0023 0.0100 0.0000 0.0000 0.0000 0.0095 0.0095 0.0096

CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0006 0.0006 0.0006

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.5980 0.0000 0.0000 0.0000 0.5797 0.5797 0.5833

CO 2 0.0003 0.0092 0.0000 0.0000 0.0000 0.0000 0.0000 0.0158 0.0000 0.0000 0.0000 0.0143 0.0143 0.0151

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0007 0.0007 0.0000

H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3142 0.0000 0.8090 0.0000 0.3006 0.3006 0.3024

H 2 O 0.0099 0.2378 0.0000 0.0003 0.0000 1.0000 0.0004 0.0013 0.0000 0.0935 0.0000 0.0252 0.0252 0.0194

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0030 0.0000 0.0009 0.0009 0.0001

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0081 0.0081 0.0089

N 2 0.7732 0.5018 0.0178 0.9919 0.0178 0.0000 0.9919 0.0601 0.0000 0.0163 0.0000 0.0567 0.0567 0.0570

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0036 0.0036 0.0036

O 2 0.2074 0.2251 0.9504 0.0054 0.9504 0.0000 0.0054 0.0000 0.0000 0.0782 0.0000 0.0000 0.0000 0.0000

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 18,364 812 88 16,375 4,591 1,061 882 252 0 0 0 25,096 17,567 17,460

V

- L Flowrate (kg/hr) 529,935 21,917 2,828 459,480 147,752 19,111 24,747 5,088 0 0 0 509,993 356,995 354,790 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 198,059 185,222 19,837 0 0 0

Temperature (°C) 15 21 32 93 32 343 32 45 15 16 1,427 1,079 191 177 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.10 5.41 3.65 0.10 5.79 4.24 4.24 4.03 3.90 Steam Table Enthalpy (kJ/kg) A 30.23 37.32 26.67 92.52 26.67 3,063.97 21.22 60.75

--- --- --- 1,749.13 330.23 297.65 AspenPlus Enthalpy (kJ/kg) B

- 97.58

- 2,651.61 4.13 63.38 4.13

- 12,907.38

- 8.35

- 3,577.38

- 2,116.95

- 768.33 2,165.43

- 2,101.56

- 3,520.45

- 3,497.87 Density (kg/m 3 ) 1.2 1.6 11.0 24.4 11.0 20.1 60.5 27.8

--- 16.5

--- 7.6 21.0 20.9

V

- L Molecular Weight 28.857 26.992 32.181 28.060 32.181 18.015 28.060 20.195

--- --- --- 20.322 20.322 20.320

V

- L Flowrate (lb mole /hr) 40,486 1,790 194 36,101 10,122 2,339 1,944 555 0 0 0 55,328 38,729 38,493

V

- L Flowrate (lb/hr) 1,168,307 48,319 6,236 1,012,980 325,738 42,132 54,557 11,218 0 0 0 1,124,342 787,039 782,178 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 436,646 408,345 43,732 0 0 0

Temperature (°F) 59 70 90 199 90 650 90 112 59 60 2,600 1,974 375 351 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 740.0 785.0 530.0 14.7 840.0 615.0 615.0 585.0 565.0 Steam Table Enthalpy (Btu/lb) A 13.0 16.0 11.5 39.8 11.5 1,317.3 9.1 26.1

--- --- --- 752.0 142.0 128.0 AspenPlus Enthalpy (Btu/lb) B

- 42.0

- 1,140.0 1.8 27.2 1.8

- 5,549.2

- 3.6

- 1,538.0

- 910.1

- 330.3 931.0

- 903.5

- 1,513.5

- 1,503.8 Density (lb/ft 3 ) 0.076 0.101 0.687 1.521 0.687 1.257 3.774 1.734

--- 1.029

--- 0.475 1.310 1.303

A 

### Steam table reference conditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atmCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 58 Exhibit 3

- 9 Case B1A stream table, Shell IGCC without c apture ( c ontinued)

15 16 17 18 19 20 21 22 23 24 25 26 27

V

- L Mole Fraction

Ar 0.0098 0.0098 0.0100 0.0079 0.0079 0.0004 0.0000 0.0058 0.0092 0.0092 0.0086 0.0086 0.0000

CH 4 0.0006 0.0006 0.0006 0.0005 0.0005 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.5962 0.5845 0.5980 0.4741 0.4741 0.0167 0.0000 0.1034 0.0000 0.0000 0.0000 0.0000 0.0000

CO 2 0.0155 0.0257 0.0158 0.0125 0.0125 0.4460 0.0000 0.2613 0.0003 0.0003 0.0752 0.0752 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 0.3091 0.3072 0.3142 0.2491 0.2491 0.0096 0.0000 0.0429 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 0.0014 0.0015 0.0013 0.2083 0.2083 0.0063 0.0000 0.4259 0.0099 0.0099 0.0906 0.0906 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 S 0.0091 0.0089 0.0000 0.0000 0.0000 0.3872 0.0000 0.0016 0.0000 0.0000 0.0000 0.0000 0.0000

N 2 0.0583 0.0618 0.0601 0.0476 0.0476 0.1338 0.0000 0.1585 0.7732 0.7732 0.7210 0.7210 0.0000

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.2074 0.1046 0.1046 0.0000

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 17,081 17,426 16,771 21,155 21,155 402 0 510 110,253 4,410 137,428 137,428 39,521

V

- L Flowrate (kg/hr) 347,994 358,740 338,688 417,666 417,666 14,964 0 13,723 3,181,557 127,262 3,962,154 3,962,154 711,987 Solids Flowrate (kg/hr) 0 0 0 0 0 0 4,959 0 0 0 0 0 0

Temperature (°C) 35 34 45 161 193 45 178 232 15 432 587 132 559 Pressure (MPa, abs) 3.72 3.69 3.65 3.21 3.17 3.65 0.41 0.41 0.10 1.62 0.10 0.10 12.51 Steam Table Enthalpy (kJ/kg) A 45.28 44.26 60.75 710.39 762.94 13.88

--- 1,007.13 30.23 463.79 791.04 280.13 3,496.26 AspenPlus Enthalpy (kJ/kg) B

- 3,555.60

- 3,652.99

- 3,577.38

- 5,259.88

- 5,207.33

- 5,041.46 142.76

- 7,809.89

- 97.58 335.98

- 1,163.40

- 1,674.31

- 12,474.05 Density (kg/m 3 ) 29.5 29.6 27.8 17.7 16.2 60.9 5,278.6 2.6 1.2 7.9 0.4 0.9 35.2

V

- L Molecular Weight 20.373 20.587 20.195 19.743 19.743 37.190

--- 26.923 28.857 28.857 28.831 28.831 18.015

V

- L Flowrate (lb mole /hr) 37,657 38,417 36,974 46,639 46,639 887 0 1,124 243,066 9,723 302,978 302,978 87,130

V

- L Flowrate (lb/hr) 767,195 790,887 746,680 920,796 920,796 32,989 0 30,253 7,014,133 280,565 8,735,054 8,735,054 1,569,663 Solids Flowrate (lb/hr) 0 0 0 0 0 0 10,933 0 0 0 0 0 0

Temperature (°F) 94 94 112 321 380 112 353 450 59 810 1,088 270 1,038 Pressure (psia) 540.0 535.0 530.0 465.0 460.0 530.0 59.3 58.9 14.7 234.9 15.2 15.2 1,814.7 Steam Table Enthalpy (Btu/lb) A 19.5 19.0 26.1 305.4 328.0 6.0

--- 433.0 13.0 199.4 340.1 120.4 1,503.1 AspenPlus Enthalpy (Btu/lb) B

- 1,528.6

- 1,570.5

- 1,538.0

- 2,261.3

- 2,238.7

- 2,167.4 61.4

- 3,357.6

- 42.0 144.4

- 500.2

- 719.8

- 5,362.9 Density (lb/ft 3 ) 1.844 1.850 1.734 1.103 1.011 3.805 329.535 0.163 0.076 0.495 0.026 0.056 2.200

A 

### Steam table reference conditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atmCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 59 3.2.2.2 Gasifier

There are two Shell dry feed, pressurized, upflow, entrained, slagging gasifiers, operating at 4.2

MPa (615 psia) and processing a total of 4,753 tonnes/day (5,240 tpd ) of as

- received coal. The air separation plant supplies 3,614 tonnes/day (3,984 tpd ) of 95 percent oxygen to the gasifiers (stream 5) and the Claus plant (stream 3). Coal reacts with oxygen and steam at a temperature of 1427°C (2600°F) in the gasifier to produce principally hydrogen and carbon monoxide with little

carbon dioxide formed.

The gasifier ’s refractory

- lined water wall is protected by molten slag that solidifies on the cooled

wall s.

3.2.2.3 Raw Gas Cooling/Particulate Removal

High

- temperature heat recovery in each gasifier train is accomplished in three steps, including the gasifier jacket, which cools and solidifies slag touching the gasifier walls and maintains the

syngas temperature a t 1,427°C (2,600°F). The product gas from the gasifier is cooled to approximately 1,093 ° C (2,000 ° F) by adding cooled recycled fuel gas to lower the temperature below the ash melting point. Gas (stream 12) then goes through a duct cooler and syngas cooler

, which lower the gas temperature from approximately 1,093 ° C (2,000 ° F) to 316 ° C (600 ° F), and produce HP steam for use in the steam cycle.

After passing through the duct cooler and syngas cooler, the syngas passes through a cyclone and a raw gas candle fi lter 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 extinc tion. 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 sol ids from 4 .2 to 0.1 MPa ( 615 to 15 psia). The syngas scrubber removes additional PM further downstream.

After passing through the cyclone and ceramic candle filter array, the syngas is further cooled to 191°C (375°F) (stream 13) by raising IP steam.

3.2.2.4 Quench Gas Compressor

About 30 percent of the cooled syngas is recycled back to the gasifier exit as quench gas. A single

- stage compressor is utilized to boost the pressure of the cooled fuel gas stream from 4.0 MPa (575 psia) to 4.0 MPa (585 psia) to pro vide quench gas to cool the syn gas stream from the gasifier.

3.2.2.5 Syngas Scrubber/Sour Water Stripper

The raw syngas exiting the final raw gas cooler at 191 ° C (375 ° F) (stream 13) then enters the
scrubber for removal of chlorides, SO 2 

## , NH 3 

## and remaining particul ate. The quench scrubber washes the syngas in a counter

- current flow in two packed beds. The syngas leaves the scrubber saturated at a temperature of 94 ° C ( 201oF). The quench scrubber removes essentially all traces of entrained particles, principally un converted carbon, slag, and metals. The bottoms from the

scrubber are sent to the sour water stripper for processing.

The sour water stripper removes NH 3 

## , SO 2 

## , 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 gasCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 60 scrubber and condensate from SGC s. Sour water from the drum flows to the sour stripper, which consists of a packed column with a steam

- heated reboiler. Sour gas is stripped from the liquid

and sent to the SRU . Remaining water is sent to wastewater treatment.

3.2.2.6 COS Hydrolysis, Mercury Removal and AGR

H 2 

## S and COS are at significant concentrations, requiring removal for the power plant to achieve the low design level of SO 2 

## emissions. H 2 

## S is removed in an AGR process; however, because COS is not readily removable, it is first catalytically converted to H 2 

## S 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 H 2 

## S, 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

NH 3 

## , is sent to the sour water stripper. The cooled syngas (stream 15) then passes through a

series of 2 carbon beds to remove greater than 95 percent of the Hg (Secti on 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 com pounds 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 H 2 

## S, COS, CO 2 

## , and small amounts of H 2 

## 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 H 2 

## S and COS. The overhead from the LP contactor is flashed in the LP KO drum. This gas ca n be used as a utility fuel gas, consisting primarily of H 2 

## 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 H 2 

## S, COS, and CO 2 

## from the solvent at LP with heat supplied through the stripper reboiler. The acid gas stream to sulfur recovery/tail gas cleanup is

recovered as t he 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 CO 2 

## along with the H 2 

## S and COS. The acid gas fed to the SRU contains 39 vol% H 2 

## S and 45 vol% CO 2 

## . The CO 2 

## passes through the SRU, the TGTU and ultimately is vented through the coal dryer. Si nce the amount of CO 2 

## in the syngas is initially small, this does not have a significant effect on the mass flow reaching the CT

. However, the costs of the sulfur recovery/tail gas cleanup are higher than that for a sulfur removal process producing an acid gas stream with a higher sulfur concentration.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 61 3.2.2.7 Claus Unit

The SRU is a Claus bypass type SRU utilizing oxygen (stream 3) instead of air. The Claus plant produces molten sulfur (stream 21) by reacting approximately one third of the H 2 

## S in the feed to

SO 2 

## , then reacting the H 2 

## S and SO 2 

## to sulfur and water. The use of Claus technology results in an overall sulfur recovery exceeding 99 percent.

Utilizing oxygen instead of air in the Claus plant reduces the overall cost of the sulfur recovery plant. Th e sulfur plant produces approximately 119 tonnes/day (131 tpd ) of elemental sulfur. Feed for this case consists of acid gas from both the acid gas cleanup unit (stream 20) and a vent stream from the sour water stripper in the gasifier section. A slipstre am of clean syngas (stream 8) is passed through an incinerator and combusted with air. The hot, nearly inert incinerator off gas is used to dry coal before being vented to the atmosphere.

In the furnace waste heat boiler, 11,991 kg/hr (26,435 lb/hr) of 3. 0 MPa (430 psia) steam is generated. This steam is used to satisfy all Claus process preheating and reheating requirements as well as to provide some steam to the medium

- pressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) steam for th e LP steam header.

3.2.2.8 Power Block

Clean syngas exiting the Sulfinol absorber (stream 17) is humidified because there is not sufficient nitrogen from the ASU to provide the level of dilution required. The moisturized syngas (stream 18) is reheated (stream 19) , further diluted with nitrogen from the ASU (stream 4) and steam, and enters the state

- of

- the

- art 2008 F

- class CT burner. The CT compressor provides combustion air to the burner and also 19 percent of the air requirements in the ASU (stream 24). The exh aust gas exits the CT at 587°C (1,088°F) (stream 25) and enters the HRSG

where additional heat is recovered until the flue gas exits the HRSG at 132°C (270°F) (stream 26) and is discharged through the plant stack. The steam raised in the HRSG is used to p ower an advanced, commercially available steam turbine using a 12.4 MPa/559°C/559°C (1

, 800 psig/1

, 038°F/1

, 038°F) steam cycle.

3.2.2.9 Air Separation Unit (ASU)

The ASU is designed to produce a nominal output of 3,614 tonnes/day (3,984 tpd ) of 95 mol%

O 2 

## for use in the gasifier (stream 5) and SRU (stream 3). The plant is designed with two production trains. The air compressor is powered by an electric motor. Approximately 11,028 tonnes/day (12,156 tpd ) of nitrogen are also recovered, compressed, and used as dilut ion in the

CT combustor. About 4 percent of the CT air is used to supply approximately 19 percent of the ASU air requirements , in the non

- capture case

.

3.2.2.10 Balance of Plant

Balance of plant items were covered in Sections 3.1.9

, 3.1.10

, and 3.1.12

.


# 3.2.3 Key System Assumptions

System assumptions for Cases B1A and B1B ( Shell IGCC with and without CO 2 

## capture ) are compiled in Exhibit 3

- 10

.

3.2.3.1 Balance of Plant

– Cases B1A and B1B

The balance of plant assumptions are common to all cases and presented in Exhibit 3

- 11

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



## 62 Exhibit 3

- 10 Shell IGCC plant study configuration matrix

Case B1A B1B

Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O 2 

### :Coal Ratio, kg O 2 

### /kg dry coal 0.84 0.84

Carbon Conversion, % 99.5 99.5

Syngas HHV at Gasifier Outlet, kJ/Nm 3 

### (Btu/scf) 10,841 (291) 10,849 (291)

Steam Cycle, MPa/°C/°C (psig/ ° F/ ° F) 12.4/559/559 (1

, 800/1

, 038/1

, 038) 12.4/534/534 (1

, 800/993/993)

Condenser Pressure, mm Hg (in Hg) 51 (2.0) 51 (2.0)

CT 2x State

- of

- the

- art 2008

F

- Class (232 MW output each) 2x State

- of

- the

- art 2008 F

Class (232 MW output each)

Gasifier Technology Shell Shell

Oxidant 95 vol% Oxygen 95 vol% Oxygen

Coal Illinois No. 6 Illinois No. 6

Coal Feed Moisture Content, % 5 5

COS Hydrolysis Yes Occurs in SGS

SGS No Yes

H 2 

### S Separation Sulfinol

- M Selexol 1 st 

### Stage

Sulfur Removal, % 99.7 99.9

Sulfur Recovery Claus Plant with Tail Gas

Treatment / Elemental Sulfur Claus Plant with Tail Gas

Treatment / Elemental Sulfur

Particulate Control Cyclone, Candle Filter, Scrubber, and AGR Absorber Cyclone, Candle Filter, Scrubber, and AGR

Absorber

Mercury Control Carbon Bed Carbon Bed

NOx Control MNQC (LNB), N 2 

### Dilution,

Humidification and steam

dilution MNQC (LNB), N 2 

### Dilution

and Humidification

CO 2 

### Separation N/A Selexol 2 nd 

### Stage

Overall Carbon Capture N/A 90.0 %

CO 2 

### Sequestration N/A Off

- site Saline FormationCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 63 Exhibit 3

- 11 Balance of plant assumptions

Parameters Values

Cooling system Recirculating Wet Cooling Tower

Fuel and Other storage

Coal 30 days

Slag 30 days

Sulfur 30 days

Sorbent 30 days

Plant Distribution Voltage

Motors below 1 hp 110/220 V

Motors between 1 hp and 250 hp 480 V

Motors between 250 hp and 5,000 hp 4,160 V

Motors above 5,000 hp 13,800 V

Steam and Combustion Turbine
Generators 24,000 V

Grid Interconnection Voltage 345 kV

Water and Waste Water

Makeup Water The water supply is 50 percent from a local POTW and

50 percent from groundwater, and is assumed to be in sufficient quantities to meet plant makeup requirements.
Makeup for potable, process, and de

- ionized (DI) water is drawn from municipal sources

Process Wastewater Water associated with gasification acti vity 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 chlori de and metals, and discharged.



# 3.2.4 Sparing Philosophy

The sparing philosophy for cases B1A and B1B is provided below. Dual trains are used to accommodate the size of commercial CTs. There is no redundancy other than normal sparing of rotating equipment. Th e plant design consists of the following major subsystems:

• Two ASUs (2 x 50%)

• Two trains of coal drying and dry feed systems (2 x 50%)

• Two trains of gasification, including gasifier, SGC, cyclone, and barrier filter (2 x 50%)

• Two trains of syngas clean

- up process (2 x 50%)

• Two trains of Sulfinol

- M acid gas removal in Case B1A and two

- stag e Selexol in Case B1B (2 x 50%)Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 64 • Two CO 2 

## compression systems (2 x 50%) in Case B1B

• One train of Claus

- based sulfur recovery (1 x 100%)

• Two CT/HRSG tandems (2 x 50%)

• One steam turbine (1 x 100%)



# 3.2.5 Case B1A

- Performance Results

The plant produces a net output of 6 29 MWe at a net plant efficiency of 42. 1 percent (HHV basis). Shell has reported expected efficiencies using bituminous coal of around 44

- 45 percent (HHV basis), a lthough this value excluded the net power impact of coal drying

. (48) Accounting for coal drying would reduce the efficiency by only about 0.5

- 1 percentage points so the efficiency results for the Shell case are still lower in this report than those reported by the

vendor.

Overall performance for the entire plant is summarized in Exhibit 3

- 12 ; Exhibit 3

- 13 provides a

detailed breakdown of the auxiliary power requirements. The ASU accounts for approximately 79 percent of the total auxiliary load distributed between the main air compressor, oxyg en compressor, nitrogen compressor, and ASU auxiliaries. The cooling water system, including the CWPs and cooling tower fan, accounts for approximately 5 percent of the auxiliary load, and the BFW pumps account for an additional 4 percent. All other indi vidual auxiliary loads are 3 percent or less of the total.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 65 Exhibit 3

- 12 Case B1A plant performance summary

Performance Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 0

Steam Turbine Power, MWe 273

Total Gross Power, MWe 737

Air Separation Unit Main Air Compressor, kWe 45,190

Oxygen Compressor, kWe 8,890

Nitrogen Compressors, kWe 29,850

CO 2 Compression, kWe 0

Acid Gas Removal, kWe 620

Balance of Plant, kWe 2 3,550

Total Auxiliaries, MWe 108

Net Power, MWe 629

HHV Net Plant Efficiency (%) 42.1 %

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,546 (8,100)

HHV Cold Gas Efficiency, % 84.5%

HHV Combustion Turbine Efficiency, % 38.3%

LHV Net Plant Efficiency (%) 43.7%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,242 (7,812)

LHV Cold Gas Efficiency, % 82.8%

LHV Combustion Turbine Efficiency, % 40.5%

Steam Turbine Cycle Efficiency, % 44.8%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 8,037 (7,618)

Condenser Duty, GJ/hr ( MM Btu/hr) 1,397 (1,324)

As

- Received Coal Feed, kg/hr (lb/hr) 198,059 (436,646)

HHV Thermal Input, kWt 1,492,878

LHV Thermal Input, kWt 1,439,899

Raw Water Withdrawal, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.025 (6.6)

Raw Water Consumption, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.020 (5.3)

O 2 :Coal 0.705Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 66 Exhibit 3

- 13 Case B1A plant power summary

Power Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 0

Steam Turbine Power, MWe 273

Total Gross Power, MWe 737

Auxiliary Load Summary

Coal Handling, kWe 440

Coal Milling, kWe 2,040

Sour Water Recycle Slurry Pump, kWe 0

Slag Handling, kWe 520

Air Separation Unit Auxiliaries, kWe 1,000

Air Separation Unit Main Air Compressor, kWe 45,190

Oxygen Compressor, kWe 8,890

Nitrogen Compressors, kWe 29,850

Feedwater Pumps, kWe 4,500

Quench Water Pump, kWe 0

Syngas Recycle Compressor, kWe 680

CO 2 Compression, kWe 0

Scrubber Pumps, kWe 770

Acid Gas Removal, kWe 620

Combustion Turbine Auxiliaries, kWe 1,000

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 230

Circulating Water Pumps, kWe 3,400

Ground Water Pumps, kWe 380

Cooling Tower Fans, kWe 1,760

Claus Plant/TGTU Auxiliaries, kWe 250

Claus Plant TG Recycle Compressor, kWe 890

Miscellaneous Balance of Plant A 

### , kWe 3,000

Transformer Losses, kWe 2,590

Total Auxiliaries, MWe 108

Net Power, MWe 629

A 

### Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads



## 3.2.5.1 Environmental Performance

The environmental targets for emissions of Hg, NOx, SO 2 

## , and PM were presented in Section

2.3 . A summary of the plant air emissions for Case B1A is presented in Exhibit 3

- 14

. All HCl is

assumed to be removed and is, therefore, not reported.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 67 Exhibit 3

- 14 Case B1A air emissions

kg/GJ (lb/ MM Btu) Tonne/year (ton/year) A 

### kg/MWh (lb/MWh) B



### SO 2 

### 0.002 (0.004) 68 (75) 0.013 (0.029 )

NOx 0.025 (0.059) 957 (1,055) 0.185 (0.409)

Particulates 0.003 (0.0071) 115 (127) 0.022 (0.049)

Hg 1.87E

- 7 (4.34E

- 7) 0.007 (0.008) 1.36E

- 6 (3.00E

- 6)

CO 2 

### 85 ( 197 ) 3,188,643 (3,514,877) 617 (1,361)

CO 2 C



### - - 723 (1,595)

A 

### Calculations based on an 80 percent capacity factor

B 

### Emissions are based on gross power except where otherwise noted

C 

### CO 2 

### emissions based on net power instead of gross power



## The low level of SO 2 

## emissions is achieved by capturing the sulfur in the gas by the Sulfinol

- M AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel gas down to a level of less than 6 ppmv. This results in a concentration in the HRSG flue gas of

less than 2 ppmv. The H 2 

## S

- rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is compressed and recycled back to the AGR to capture most of the remaining sulfur. The SO 2 

## emissions in Exhibit 3

- 14 include both the stack emissions and the coal dryer emissions.

NO x emissions are limited by the use of nitrogen dilution, humidification

, and steam dilution to

15 ppmv d (as NO 2 

## @ 15 percent O 2 

## ). 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 NO x levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only.

Approximately 97 percent of the mercu ry is captured from the syngas by dual activated carbon

bed s

.

CO 2 

## emissions represent the uncontrolled discharge from the process.

The carbon balance for the plant is shown in Exhibit 3

- 15

. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since

the Aspen model accounts for air components throughout. Carbon leaves the plant as unbur ned carbon in the slag and as CO 2 

## in the stack gas and ASU vent gas.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 68 Exhibit 3

- 15 Case B1A carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 126,252 (278,339) Stack Gas 124,177 (273,764)

Air (CO 2 ) 508 (1,120) Coal Dryer Stack 1,863 (4,106)

CO 2 Product 0 (0)

ASU Vent 89 (197)

Slag 631 (1,392)

Total 126,760 (279,459) Total 126,760 (279,459)



## Exhibit 3

- 16 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur in the coal drying gas, and sulfur emitted in the stack gas. Sulfur in the slag is con sidered to be negligible.

Exhibit 3

- 16 Case B1A sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 4,964 (10,944) Stack Gas 5 (11)

Coal Dryer Stack 0 (0)

CO 2 Product 0 (0)

Elemental Sulfur 4,959 (10,933)

Total 4,964 (10,944) Total 4,964 (10,944)



## Exhibit 3

- 17 shows the overal l water balance for the plant.

Water demand represents the total amount of water required for a particular process. Some water is recovered within the process, primarily as s yngas condensate, and is re

- used as internal recycle. The difference between demand and recycle is raw water withdrawal. Raw water withdrawal is defined as the water removed from the ground or diverted from a municipal source for use in the plant and was assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water withdrawal can be represented by the water metered from a raw water source and used in the plant processes for any and all purposes, such as cooling tower makeup,

BFW makeup, quench system makeup, and slag handling makeup. The difference between water withdrawal and process water discharge is defined as water consumption and can be represented by the portion of the raw water withdrawn that is evaporated, transpired,

in corporated into products or otherwise not returned to the water source from which it was withdrawn. Water consumption represents the net impact of the plant process on the water

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



## 69 Exhibit 3

- 17 Case B1A water balance

Water Use Water

Demand Internal Recycle Raw Water

Withdrawal Process

Water Discharge Raw Water Consumption

m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm)

Slag Handling 0.43 (114) 0.17 (45) 0.26 (69)

– 0.26 (69)

Slurry Water

– – – – –
Quench/Wash

– – – – –

Humidifier 1.38 (365)

– 1.38 (365)

– 1.38 (365)

SWS Blowdown

– – – 0.00 (0.45) 0.00 (

- 0.45)

Condenser Makeup 1.07 (282)

– 1.07 (282)

– 1.07 (282)

BFW Makeup 0.23 (62)

– 0.23 (62)

– 0.23 (62)

Gasifier Steam 0.32 (84)

– 0.32 (84)

– 0.32 (84)

Shift Steam

– – – – –

CT Steam Dilution 0.51 (135)

– 0.51 (135)

– 0.51 (135)

Cooling Tower 13.25 (3,501) 0.25 (67) 13.00 (3,435) 2.98 (787) 10.02 (2,647)

BFW Blowdown

– 0.23 (62)

- 0.23 (

- 62)

– - 0.23 (

- 62)

SWS Blowdown

– 0.02 (4.50)

- 0.02 (

- 4.50)

– - 0.02 (

- 4.50)

Total 16.13 (4,261) 0.42 (112) 15.71 (4,150) 2.98 (788) 12.73 (3,362)



## 3.2.5.2 Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3

- 18 through

Exhibit 3

- 20 :

• Coal gasification and ASU

• Syngas cleanup, sulfur recovery, and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is provided in tabular form in Exhibit 3

- 21 . The power out is

the comb ined CT and steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 3

- 12 ) is calculated by multiplying t he power out by a combi ned generator efficiency of 98.5 percent.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 70 This page intentionally left blankCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 71 Exhibit 3

- 18 Case B1A coal gasification and ASU heat and mass balance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 1 A

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 1 A

S HELL G ASIFIER
ASU

, G ASIFICATION

, AND G AS C OOLING

DWG

. NO

. BB

- HMB

- CS

- B 1 A

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P AGES

1 OF 3 Ambient Air

Intercooled Air Compressor

Elevated

Pressure

ASU Intercooled Nitrogen Compressor

Intercooled Oxygen Compressor

Milled Coal

Slag

Removal Slag Gross Plant Power : 737 MWe Auxiliary Load : 108 MWe

Net Plant Power : 629 MWe Net Plant Efficiency

, HHV : 42

. 1 %

Net Plant Heat Rate : 8

, 100 Btu / kWh Dry Coal

Coal Feeding Boost Compressor

Recycle Compressor 280

, 565 W

220 T

225 P

51 H

337

, 302 W

393 T

625 P

147 H To Claus Plant

9 10 1

3 4

7

6

11 2 1

, 168

, 307 W

59 T

15 P

13 H

48

, 319 W

70 T

16 P

16 H

937

, 042 W

90 T

56 P

14 H 130

, 495 W

50 T

182 P

3 H

6

, 236 W

90 T

125 P

11 H 325

, 738 W

90 T

125 P

11 H

325

, 738 W

241 T

940 P

41 H 54

, 557 W

376 T

785 P

84 H

436

, 646 W

59 T

15 P 408

, 345 W

60 T

840 P

43

, 732 W

2

, 600 T

615 P 1

, 124

, 342 W

1

, 974 T

615 P

750 H

787

, 039 W

375 T

585 P

140 H 280

, 565 W

810 T

235 P

199 H 1

, 012

, 980 W

389 T

384 P

88 H

5

42

, 132 W

650 T

740 P

1

, 309 H

Coal Drying

Incinerator

Syngas Slip Stream Incinerator Air 11

, 218 W

112 T

530 P

26 H 53

, 179 W

59 T

15 P

13 H 92

, 698 W 12

8 1

, 067

, 536 W

199 T

384 P

40 H

337

, 302 W

375 T

585 P

140 H

Syngas

Cooler Duct Cooler

Steam

Generation

Shell

Gasifier

From HP

Economizer 2 Air From GT Compressor N 2 to GT Combustor

From HP

Economizer 2 To HP Economizer 1

1

, 124

, 342 W

600 T

595 P

221 H Pre Particulat

Cooler

Post

Particulate

Cooler Cyclone Candle

Filter To Superheater

From LP

Economizer

To LP Evaporator To Superheater

From HP

Economizer 2

Raw Syngas

to Scrubber

1

, 124

, 342 W

1

, 650 T

605 P

620 H 1

, 167

, 264 W

100 T

190 P

18 H

13 Incinerator

Exhaust

Steam Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

Water Steam

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical Flue Gas /

Combustion

Products Vent

ASU

Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 72 Exhibit 3

- 19 Case B1A syngas cleanup heat and mass balance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 1 A

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 1 A

S HELL G ASIFIER
G AS C LEANUP S YSTEM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Mercury

Removal

Knock

Out

Drum

Raw Syngas

Sour

Drum Claus Plant

Tail

Gas Furnace Catalytic

Reactor

Beds

Sulfur COS Hydrolysis

Reboiler

DWG

. NO

. BB

- HMB

- CS

- B 1 A

- PG

- 2 P AGES

2 OF 3 Sour Stripper Clean

Gas Acid

Gas

Syngas

Scrubber

Gross Plant Power : 737 MWe Auxiliary Load : 108 MWe

Net Plant Power : 629 MWe Net Plant Efficiency

, HHV : 42

. 1 %

Net Plant Heat Rate : 8

, 100 Btu / kWh 13 AGR

- Sulfinol

15 16 20

21

22

787

, 039 W

375 T

585 P

140 H 23

, 692 W

100 T

800 P

5 H 782

, 178 W

201 T

580 P

75 H 782

, 178 W

351 T

565 P

128 H

790

, 887 W

94 T

535 P

19 H

Syngas

Coolers From HP

Economizer 2 746

, 680 W

112 T

530 P

26 H

1

, 962 W

142 T

65 P

76 H 30

, 253 W

450 T

59 P

433 H 32

, 989 W

112 T

530 P

6 H

Knock Out Tailgas to AGR To Superheater 782

, 178 W

350 T

575 P

128 H

767

, 195 W

94 T

540 P

19 H

6

, 561 W

119 T

57 P

45 H Treated Syngas

14 Slip Stream to Coal Dryer 17 Humidification 18 Humidified Fuel Gas 19

8

Tailgas Recycle Compressor Hydrogenation

And Tail Gas

Cooling

24

, 042 W

120 T

57 P

38 H To Preheater and

LP Evaporator

From Tail Gas

Cooler and LP

Economizer

To Fuel Gas

Preheater To Fuel Gas

Preheater

992

, 575 W

195 T

580 P

159 H 992

, 575 W

150 T

1

, 205 P

113 H

To Water

Treatment Makeup Water 11

, 218 W

112 T

530 P

26 H 920

, 796 W

380 T

460 P

328 H

From Syngas

Scrubber and HP

Economizer 2 To Syngas Scrubber

and HP Economizer 1

920

, 796 W

321 T

465 P

305 H

From Gland Steam

Condenser To Syngas Cooling

110 T COS Hydrolysis

Preheater

56

, 804 W To Slag Quench 10

, 933 W

6

, 236 W

90 T

125 P

11 H 3 6

, 236 W

450 T

125 P

92 H

To

Deaerator

From IP

BFW Fuel Gas

Preheater

Claus Oxygen

Preheater

Oxygen Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas Sour Water Acid Gas

Tailgas Sour Gas

Sulfur Hydrogen

Water

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical Steam

Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 73 Exhibit 3

- 20 Case B1A combined cycle power generation heat and mass b alance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 1 A

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 1 A

GEE G ASIFIER
P OWER B LOCK S YSTEM

DWG

. NO

. BB

- HMB

- CS

- B 1 A

- PG

- 3 L EGEND

Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES
3 OF 3 Sour Gas

Sour Water

Water Steam

Flue Gas

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical

HP

Turbine IP

Turbine

Air Inlet

Filter Steam Seal Regulator

Gland

Steam

Condenser LP

Turbine Stack

Expander Compressor Generator

Generator Steam Turbine

State

- of

- the

- art 2008

F

- Class Turbine

7

, 014

, 133 W

59 T

15 P

13 H 1

, 548

, 142 W

101 T

1 P

69 H 8

, 735

, 054 W

270 T

15 P

120 H

920

, 796 W

380 T

460 P

328 H 1

, 569

, 663 W

1

, 038 T

1

, 815 P

1

, 495 H 12

, 478 W

298 T

65 P

1

, 171 H

1

, 395

, 353 W

537 T

65 P

1

, 293 H

1

, 548

, 142 W

103 T

120 P

71 H 1

, 400 W

658 T

65 P

1

, 352 H

1

, 400 W

212 T

15 P

180 H

20 24

19 23

Hot Well Condenser 140

, 852 W

59 T

15 P

27 H 8

, 841 W

698 T

501 P

1

, 348 H

9

, 537 W

658 T

65 P

1

, 352 H 782 W

1

, 038 T

1

, 815 P

1

, 495 H 1

, 314 W

537 T

65 P

1

, 293 H Preheater Deaerator

Heater HP

Economizer

1 LP

Economizer HP

Economizer

2 HP Evaporator Superheater

/ Reheater

From Syngas Cooler To Duct / Radiant Syngas / Pre

Particulate Coolers

and COS Preheater From Duct / Radiant Syngas / Pre

Particulate Coolers and COS

Preheater

To ASU and Fuel

Gas Preheater

Deaerator From ASU and Fuel

Gas Preheater

LP Evaporator From Claus

, Process Extraction

, and 250 PSIA Header

LP Extraction Spray

LP Blowdown Hot Reheat 8

, 735

, 054 W

1

, 088 T

15 P

340 H 22

To WWT

Condensate to Tail Gas Cooling Process

Extraction 235 T

274 T

1

, 712

, 806 W

274 T

45 P

242 H

1

, 604

, 593 W

279 T

2

, 251 P

247 H 8

, 564 W

274 T

79 P

242 H

19

, 460 W

274 T

79 P

242 H 35

, 526 W

276 T

615 P

244 H 571

, 152 W

351 T

2

, 251 P

319 H

305 T 585 T 636 T

34

, 923 W

585 T

2

, 001 P

585 H 636 T

1

, 190

, 740 W

585 T

2

, 001 P

585 H

1

, 446

, 064 W

698 T

501 P

1

, 348 H 571

, 152 W

585 T

2

, 001 P

585 H

1

, 012

, 980 W

385 T

389 P

87 H

21 Air Extraction

280

, 565 W

810 T

235 P

199 H 187

, 712 W

298 T

65 P

266 H

180 T

80

, 190 W

298 T

65 P

1

, 171 H

Steam to Gasifier

and Combustion

Turbine 109

, 842 W

688 T

745 P

1

, 327 H

Water Makeup

1

, 000 W

1

, 038 T

1

, 815 P

1

, 495 H 1

, 000 W

212 T

15 P

180 H 31

, 177 W

500 T

250 P

1

, 255 H IP Extraction Steam

to 250 PSIA Header

LP Extraction Spray # 1 1

, 038 T To Post

Particulate and Syngas

Coolers From Post

Particulate and Syngas

Coolers

LP Extraction Spray # 2

14

, 327 W

241 T

825 P

209 H Process Extraction 40

, 813 W

537 T

65 P

1

, 293 H

Nitrogen Diluent

Fuel Gas Steam Diluent

67

, 710 W

475 T

460 P

1

, 233 H IP to Claus

LP Pump IP Pump

HP Pump



### P LANT 

### P ERFORMANCE 

### S UMMARY

Gross Plant Power : 737 MWe Auxiliary Load : 108 MWe

Net Plant Power : 629 MWe Net Plant Efficiency

, HHV : 42

. 1 %

Net Plant Heat Rate : 8

, 100 Btu / kWh

Condensate

Pumps Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 74 This page intentionally left blankCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 75 Exhibit 3

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

HHV Sensible + Latent Power Total

Heat In (GJ/hr)

Coal 5,374 (5,094) 4.5 (4.3)

– 5,379 (5,098)

Air

– 112.9 (107.0)

– 112.9 (107.0)

Raw Water Makeup

– 59.1 (56.0)

– 59.1 (56.0)

Auxiliary Power

– – 389 (369) 389 (369)

TOTAL 5,374 (5,094) 176.5 (167.3) 389 (369) 5,940 (5,630)

Heat Out (GJ/hr)

ASU Vent

– 0.8 (0.8)

– 0.8 (0.8)

Slag 20.7 (19.6) 33.5 (31.7)

– 54.2 (51.4)

Stack Gas

– 1,110 (1,052)

– 1,110 (1,052)

Sulfur 46.0 (43.6) 0.6 (0.5)

– 46.5 (44.1)

Motor Losses and Design Allowances – – 51.8 (49.1) 51.8 (49.1)

Condenser

– 1,397 (1,324)

– 1,397 (1,324)

Non

- Condenser Cooling

Tower Loads – 246 (233)

– 246 (233)

CO 2 – – – –

Blowdown

– 22.9 (21.7)

– 22.9 (21.7)

CO 2 Capture Losses

– – – –

Ambient Losses A



### – 113.9 (108.0)

– 113.9 (108.0)

Power

– – 2,653 (2,515) 2,653 (2,515)

TOTAL 66.7 (63.2) 2,925 (2,772) 2,705 (2,564) 5,696 (5,399)

Unaccounted Energy B



### – 244 (231)

– 244 (231)

A 

### Ambient losses include all losses to the environment throu gh radiation, convection, etc. Sources of

these losses include the combustor, reheater, superheater, and transformers.

B 

### By difference



# 3.2.6 Case B1A

- Major Equipment List

Major equipment items for the Shell gasifier with no CO 2 

## capture are shown in the following tables. The accounts used in the equipment l ist 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 an d heat duties and a 21 percent contingency for heads on pumps and fans.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 76 Case B1A

– Account 1: Coal Handling

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

5 Stacker/Reclaimer Traveling, linear 1,130 tonne/hr (1,250 tph) 1 0

6 Reclaim Hopper N/A 40 tonne (50 ton) 2 1

7 Feeder Vibratory 160 tonne/hr (180 tph) 2 1

8 Conveyor No. 3 Belt w/ tripper 330 tonne/hr (360 tph) 1 0

9 Coal Surge Bin w/ Vent Filter Dual outlet 160 tonne (180 ton) 2 0

10 Crusher Impactor reduction 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 2 0

11 Conveyor No. 4 Belt w/ tripper 330 tonne/hr (360 tph) 1 0

12 Conveyor No. 5 Belt w/ tripper 330 tonne/hr (360 tph) 1 0

13 Coal Silo w/ Vent Filter and

Slide Gates Field erected 730 tonne (800 ton) 3 0



## Case B1A

– Account 2: Coal Preparation and Feed

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 70 tonne/hr (80 tph) 3 0

2 Conveyor No. 6 Belt w/ tripper 220 tonne/hr (240 tph) 1 0

3 Roller Mill Feed Hopper Dual Outlet 440 tonne (480 ton) 1 0

4 Weigh Feeder Belt 110 tonne/hr (120 tph) 2 0

5 Coal Dryer and Pulverizer Rotary 110 tonne/hr (120 tph) 2 0

6 Coal Dryer Feed Hopper Vertical Hopper 220 tonne (240 ton) 2 0



## Case B1A

– Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, c ylindrical,

outdoor 1,165,000 liters (308,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,480 lpm @ 90 m H 2 O (1,710 gpm @ 300 ft H 2 O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 436,000 kg/hr (962,000 lb/hr) 2 0

4 Intermediate

- Pressure Feedwater Pump Horizontal centrifugal, single stage 7,410 lpm @ 30 m H 2 O (1,960 gpm @ 90 ft H 2 O) 2 1

5 High

- Pressure Feedwater Pump No. 1 Barrel type, multi

stage, centrifugal HP water: 6,940 lpm @ 1,800 m H 2 O (1,830 gpm @ 6,100 ft H 2 O) 2 1

6 High

- Pressure Feedwater Pump No. 2 Barrel type, multi

stage, centrifugal IP water: 2,470 lpm @ 220 m

H 2 O (650 gpm @ 730 ft H 2 O) 2 1

7 Auxiliary Boiler Shop fabricated, water

tube 18,000 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air Compressors Flooded s crew 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m 3 

### min (1,000 scfm) 2 1

10 Closed Cy c l e Cooling Heat Exchangers Plate and frame 135 GJ/hr (128 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 48,500 lpm @ 20 m H 2 O (12,800 gpm @ 70 ft H 2 O) 2 1

12 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 110 m H 2 O (1,000 gpm @ 350 ft H 2 O) 1 1Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 77 Equipment

No. Description Type Design Condition Operating Qty. Spares

13 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 80 m H 2 O (700 gpm @ 250 ft H 2 O) 1 1

14 Raw Water Pumps Stainless steel, single

suction 4,400 lpm @ 20 m H 2 O (1,160 gpm @ 60 ft H 2 O) 2 1

15 Ground Water Pumps Stainless steel, single

suction 2,930 lpm @ 270 m H 2 O (780 gpm @ 880 ft H 2 O) 3 1

16 Filtered Water Pumps Stainless steel, single

suction 1,780 lpm @ 50 m H 2 O (470 gpm @ 160 ft H 2 O) 2 1

17 Filtered Water Tank Vertical, cylindrical 852,000 liter (225,000 gal) 2 0

18 Makeup Water

Demineralizer Anion, cation, and

mixed bed 320 lpm (90 gpm) 2 0

19 Liquid Waste Treatment System N/A 10 years, 24

- hour storm 1 0



## Case B1A

– Account 4: Gasifier, ASU, and Accessories Including Low Temperature Heat Recovery and Fuel Gas Saturation

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized dry

- feed,

entrained bed 2,600 tonne/day, 4.2 MPa (2,900 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler Convective spiral

wound tube boiler 280,000 kg/hr (618,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 280,000 kg/hr (618,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with pulse

- jet cleaning metallic filters 2 0

5 Syngas Scrubber Including Sour Water Stripper Vertical upflow 196,000 kg/hr (433,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with

condensate drain 193,000 kg/hr (425,000 lb/hr) 8 0

7 Raw Gas Knockout

Drum Vertical with mist

eliminator 192,000 kg/hr, 35°C, 3.8 MPa (423,000 lb/hr, 94°F, 545 psia) 2 0

8 Saturation Water

Economizers Shell and tube 131 GJ/hr (124 MMBtu/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 230,000 kg/hr, 161°C, 3.3 MPa (506,000 lb/hr, 321°F, 480 psia) 2 0

10 Saturator Water Pump Centrifugal 3,600 lpm @ 13 m H 2 O (900 gpm @ 42 ft H 2 O) 2 2

11 Synthesis Gas

Reheater Shell and tube 186,000 kg/hr (411,000 lb/hr) 2 0

12 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 196,000 kg/hr (433,000 lb/hr) syngas 2 0

13 ASU Main Air Compressor Centrifugal, multi

- stage 4,000 m 3 

### /min @ 1.3 MPa (141,000 scfm @ 190 psia) 2 0

14 Cold Box Vendor design 2,000 tonne/day (2,200 tpd) of 95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi

- stage 1,000 m 3 

### /min (35,000 scfm)

Suction

- 1.0 MPa (130 psia) Discharge

- 6.5 MPa (940 psia) 2 0

16 Primary Nitrogen Compressor Centrifugal, multi

- stage 3,000 m 3 

### /min (116,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 2 0

17 Secondary Nitrogen Compressor Centrifugal, single

stage 460 m 3 

### /min (16,000 scfm)

Suction

- 1.3 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 2 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 78 Equipment

No. Description Type Design Condition Operating Qty. Spares

18 Transport Nitrogen Boost Compressor Centrifugal, single

stage 190 m 3 

### /min (7,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 5.4 MPa (790 psia) 2 0

19 Extraction Air Heat Exchanger Gas

- to

- gas, vendor design 70,000 kg/hr, 432°C, 1.6 MPa (154,000 lb/hr, 810°F, 235 psia) 2 0



## Case B1A

– Account 5: Syngas Cleanup

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber 1 Sulfated carbon bed 191,000 kg/hr (422,000 lb/hr)

, 35°C (94°F)

, 3.7 MPa (540 psia) 2 0

2 Mercury Adsorber 2 Sulfated carbon bed 191,000 kg/hr (422,000 lb/hr)

, 35°C (94°F)

, 3.7 MPa (535 psia) 2 0

3 Sulfur Plant Claus type 131 tonne/day (144 tpd) 1 0

4 COS Hydrolysis

Reactor Fixed bed, catalytic 195,000 kg/hr (430,000 lb/hr)

, 177°C (350°F)

, 4.0 MPa (580 psia) 2 0

5 Acid Gas Removal

Plant Sulfinol 197,000 kg/hr (435,000 lb/hr)

, 34°C (94°F)

, 3.7 MPa (535 psia) 2 0

6 Hydrogenation

Reactor Fixed bed, catalytic 15,000 kg/hr (33,000 lb/hr)

, 232°C (450°F)

, 0.4 MPa (58.9 psia) 1 0

7 Tail Gas Recycle Compressor Centrifugal 12,000 kg/hr (26,000 lb/hr) each 1 0



## Case B1A

– Account 6: Combustion Turbine and Auxiliaries

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Combustion Turbine State

- of

- the

- art

2008 F

- c lass 230 MW 2 0

2 Combustion Turbine

Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 2 0



## Case B1A

– Account 7: HRSG, Ducting, and Stack

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type

409SS liner 76 m (250 ft) high x 8.4 m (28 ft) diameter 1 0

2 Heat Recovery
Steam Generator Drum, multi

pressure with

economizer section and integral

deaerator Main steam

- 391,593 kg/hr,

12.4 MPa/559°C (863,314 lb/hr, 1,800 psig/1,038°F) 2 0



## Case B1A

– Account 8: Steam Turbine Generator and Auxiliaries

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Steam

Turbine Commercially available

advanced steam turbine 287 MW
12.4 MPa/559°C/559°C (1,800 psig/ 1,038°F/1,038°F) 1 0

2 Steam

Turbine
Generator Hydrogen cooled, static

excitation 320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 1 0

3 Surface

Condenser Single pass, divided waterbox including

vacuum pumps 1,540GJ/hr (1,460 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 79 Equipment

No. Description Type Design Condition Operating Qty. Spares

4 Steam Bypass One per HRSG 50% steam flow @ design steam

conditions 2 0



## Case B1A

– Account 9: Cooling Water System

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 342,000 lpm @ 30 m (90,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative, mechanical draft,

multi

- cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 1,900 GJ/hr (1,800 MMBtu/hr) heat duty 1 0



## Case B1A

– Account 10: Slag Recovery and Handling

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 208,000 liters (55,000 gal) 2 0

2 Slag Crusher Roll 11 tonne/hr (12 tph) 2 0

3 Slag Depressurizer Lock Hopper 11 tonne/hr (12 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 125,000 liters (33,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 56,000 liters (15,000 gal) 2 0

6 Slag Conveyor Drag chain 11 tonne/hr (12 tph) 2 0

7 Slag Separation Screen Vibrating 11 tonne/hr (12 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 11 tonne/hr (12 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 178,000 liters (47,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 50 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 2 2

11 Grey Water Storage Tank Field erected 57,000 liters (15,000 gal) 2 0

12 Grey Water Pumps Centrifugal 200 lpm @ 430 m H 2 O (50 gpm @ 1,420 ft H 2 O) 2 2

13 Slag Storage Bin Vertical, field erected 800 tonne (900 tons) 2 0

14 Unloading Equipment Telescoping chute 90 tonne/hr (100 tph) 1 0



## Case B1A

– Account 11: Accessory Electric Plant

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 CTG Transformer Oil

- filled 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 2 0

2 STG Transformer Oil

- filled 24 kV/345 kV, 290 MVA, 3

- ph, 60 Hz 1 0

3 High Voltage Auxiliary

Transformer Oil

- filled 345 kV/13.8 kV, 47 MVA, 3

- ph, 60 Hz 2 0

4 Medium Voltage Transformer Oil

- filled 24 kV/4.16 kV, 23 MVA, 3

- ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 3 MVA, 3

- ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency

shutdown 750 kW, 480 V,

3

- ph, 60 Hz 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 80 Case B1A

– Account 12: Instrumentation and Control

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 DCS

- Main
Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B& W) Operator stations/printers and engineering stations/printers 1 0

2 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 0



# 3.2.7 Case B1A

- Cost Estimating

Costs Results

The cost estimating methodology was described previously in Section 2.6

. Exhibit 3

- 22 shows a

detailed breakd own of the capital costs; Exhibit 3

- 23 shows the owner’s costs , TOC, and TASC ; Exhibit 3

- 24 shows the initial and annual O&M costs; and Exhibit 3

- 25 shows the COE

breakdown.

The estimated TP C of the Shell gasifier with no CO 2 

## capture is $2,7 2 5 /kW. Process contingenc y represents 2.8 percent of the TP C

, and project contingency represents 13.8 percent. The COE is $ 107

. 0 /M Wh.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 81 Exhibit 3

- 22 Case B1A total plant cost details

Case: B1A

– Shell IGCC w/o CO 2 Estimate Type: Conceptual Plant Size (MW,net): 629 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $4,254 $0 $2,050 $0 $6,305 $630 $0 $1,387 $8,322 $13

1.2 Coal Stackout & Reclaim $5,498 $0 $1,314 $0 $6,812 $681 $0 $1,499 $8,992 $14

1.3 Coal Conveyors & Yd Crush $5,111 $0 $1,301 $0 $6,412 $641 $0 $1,411 $8,464 $13

1.4 Other Coal Handling $1,337 $0 $301 $0 $1,638 $164 $0 $360 $2,162 $3

1.9 Coal & Sorbent Hnd. Foundations $0 $2,841 $7,425 $0 $10,265 $1,027 $0 $2,258 $13,550 $22

Subtotal $16,200 $2,841 $12,391 $0 $31,432 $3,143 $0 $6,915 $41,491 $66

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying $48,619 $2,932 $6,987 $0 $58,539 $5,854 $0 $12,878 $77,271 $123

2.2 Prepared Coal Storage & Feed $2,303 $553 $356 $0 $3,212 $321 $0 $707 $4,240 $7

2.3 Dry Coal Injection System $75,787 $873 $6,942 $0 $83,603 $8,360 $0 $18,393 $110,356 $175

2.4 Misc. Coal Prep & Feed $1,266 $925 $2,725 $0 $4,917 $492 $0 $1,082 $6,490 $10

2.9 Coal & Sorbent Feed Foundation $0 $4,645 $3,986 $0 $8,631 $863 $0 $1,899 $11,392 $18

Subtotal $127,976 $9,929 $20,996 $0 $158,901 $15,890 $0 $34,958 $209,749 $334

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $3,734 $6,444 $3,379 $0 $13,557 $1,356 $0 $2,983 $17,896 $28

3.2 Water Makeup & Pretreating $688 $71 $378 $0 $1,137 $114 $0 $375 $1,626 $3

3.3 Other Feedwater Subsystems $2,099 $694 $620 $0 $3,413 $341 $0 $751 $4,505 $7

3.4 Service Water Systems $402 $802 $2,765 $0 $3,969 $397 $0 $1,310 $5,676 $9

3.5 Other Boiler Plant Systems $2,168 $810 $1,994 $0 $4,971 $497 $0 $1,094 $6,562 $10

3.6 FO Supply Sys & Nat Gas $17,736 $712 $660 $0 $19,108 $1,911 $0 $4,204 $25,223 $40

3.7 Waste Treatment Equipment $931 $0 $576 $0 $1,507 $151 $0 $497 $2,155 $3

3.8 Misc. Power Plant Equipment $1,267 $169 $658 $0 $2,094 $209 $0 $691 $2,994 $5

Subtotal $29,025 $9,703 $11,029 $0 $49,757 $4,976 $0 $11,904 $66,637 $106

4 Gasifier & Accessories

4.1 Syngas Cooler Gasifier System $203,552 $0 $88,237 $0 $291,789 $29,179 $40,524 $55,413 $416,905 $663

4.2 Syngas Cooler w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU & Oxidant Compression $177,729 $0 w/equip. $0 $177,729 $17,773 $0 $19,550 $215,052 $342

4.4 LT Heat Recovery & FG Saturation $18,617 $0 $7,073 $0 $25,691 $2,569 $0 $5,652 $33,911 $54

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,110 $449 $0 $1,559 $156 $0 $343 $2,058 $3

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $9,370 $5,588 $0 $14,957 $1,496 $0 $4,113 $20,567 $33

Subtotal $399,897 $10,480 $101,347 $0 $511,725 $51,172 $40,524 $85,072 $688,493 $1,095

5A Gas Cleanup & Piping

5A.1 Sulfinol System $45,130 $0 $38,032 $0 $83,162 $8,316 $0 $18,296 $109,774 $175

5A.2 Elemental Sulfur Plant $11,584 $2,258 $14,843 $0 $28,684 $2,868 $0 $6,311 $37,863 $60

5A.3 Mercury Removal $1,400 $0 $1,058 $0 $2,458 $246 $123 $565 $3,392 $5

5A.4 COS Hydrolysis $3,475 $0 $4,507 $0 $7,981 $798 $0 $1,756 $10,535 $17

5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 82 Case: B1A

– Shell IGCC w/o CO 2 Estimate Type: Conceptual Plant Size (MW,net): 629 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

5A.6 Blowback Gas Systems $1,945 $327 $183 $0 $2,455 $245 $0 $540 $3,240 $5

5A.7 Fuel Gas Piping $0 $979 $640 $0 $1,619 $162 $0 $356 $2,137 $3

5A.9 HGCU Foundations $0 $886 $597 $0 $1,483 $148 $0 $489 $2,120 $3

Subtotal $63,533 $4,449 $59,860 $0 $127,842 $12,784 $123 $28,313 $169,062 $269

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $104,201 $0 $7,506 $0 $111,707 $11,171 $5,585 $12,846 $141,309 $225

6.9 Combustion Turbine Foundations $0 $923 $1,068 $0 $1,992 $199 $0 $657 $2,848 $5

Subtotal $104,201 $923 $8,575 $0 $113,699 $11,370 $5,585 $13,504 $144,158 $229

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $31,100 $0 $6,022 $0 $37,122 $3,712 $0 $4,083 $44,918 $71

7.3 Ductwork $0 $2,085 $1,461 $0 $3,546 $355 $0 $780 $4,681 $7

7.4 Stack $4,023 $0 $1,501 $0 $5,524 $552 $0 $608 $6,684 $11

7.9 HRSG, Duct & Stack Foundations $0 $766 $769 $0 $1,535 $153 $0 $506 $2,195 $3

Subtotal $35,123 $2,851 $9,753 $0 $47,727 $4,773 $0 $5,978 $58,477 $93

8 Steam Turbine Generator

8.1 Steam TG & Accessories $38,584 $0 $5,922 $0 $44,506 $4,451 $0 $4,896 $53,852 $86

8.2 Turbine Plant Auxiliaries $241 $0 $549 $0 $791 $79 $0 $87 $957 $2

8.3 Condenser & Auxiliaries $3,110 $0 $1,755 $0 $4,865 $486 $0 $535 $5,886 $9

8.4 Steam Piping $16,344 $0 $7,088 $0 $23,432 $2,343 $0 $6,444 $32,218 $51

8.9 TG Foundations $0 $1,137 $2,009 $0 $3,146 $315 $0 $1,038 $4,499 $7

Subtotal $58,279 $1,137 $17,322 $0 $76,739 $7,674 $0 $13,000 $97,412 $155

9 Cooling Water System

9.1 Cooling Towers $3,610 $0 $1,090 $0 $4,700 $470 $0 $776 $5,946 $9

9.2 Circulating Water Pumps $1,751 $0 $120 $0 $1,871 $187 $0 $309 $2,367 $4

9.3 Circ. Water System Auxiliaries $157 $0 $22 $0 $179 $18 $0 $30 $227 $0

9.4 Circ. Water Piping $0 $6,965 $1,687 $0 $8,652 $865 $0 $1,903 $11,421 $18

9.5 Make

- up Water System $395 $0 $542 $0 $937 $94 $0 $206 $1,237 $2

9.6 Component Cooling Water Sys $796 $952 $654 $0 $2,403 $240 $0 $529 $3,171 $5

9.9 Circ. Water System Foundations $0 $2,272 $4,038 $0 $6,310 $631 $0 $2,082 $9,024 $14

Subtotal $6,709 $10,190 $8,153 $0 $25,052 $2,505 $0 $5,834 $33,392 $53

10 Ash & Spent Sorbent Handling Systems

10.1 Slag Dewatering & Cooling $18,726 $0 $9,172 $0 $27,898 $2,790 $0 $3,069 $33,756 $54

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $635 $0 $686 $0 $1,321 $132 $0 $218 $1,671 $3

10.7 Ash Transport & Feed Equipment $874 $0 $204 $0 $1,078 $108 $0 $178 $1,364 $2

10.8 Misc. Ash Handling Equipment $1,315 $1,612 $478 $0 $3,405 $341 $0 $562 $4,307 $7

10.9 Ash/Spent Sorbent Foundation $0 $53 $70 $0 $123 $12 $0 $41 $176 $0

Subtotal $21,550 $1,665 $10,610 $0 $33,826 $3,383 $0 $4,067 $41,275 $66

11 Accessory Electric Plant

11.1 Generator Equipment $1,155 $0 $1,125 $0 $2,280 $228 $0 $251 $2,758 $4

11.2 Station Service Equipment $4,293 $0 $395 $0 $4,687 $469 $0 $516 $5,672 $9Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 83 Case: B1A

– Shell IGCC w/o CO 2 Estimate Type: Conceptual Plant Size (MW,net): 629 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

11.3 Switchgear & Motor Control $7,923 $0 $1,473 $0 $9,396 $940 $0 $1,550 $11,885 $19

11.4 Conduit & Cable Tray $0 $4,026 $12,409 $0 $16,435 $1,643 $0 $4,520 $22,598 $36

11.5 Wire & Cable $0 $7,762 $4,722 $0 $12,484 $1,248 $0 $3,433 $17,165 $27

11.6 Protective Equipment $0 $797 $2,958 $0 $3,755 $375 $0 $620 $4,750 $8

11.7 Standby Equipment $275 $0 $274 $0 $548 $55 $0 $90 $693 $1

11.8 Main Power Transformers $17,455 $0 $173 $0 $17,628 $1,763 $0 $2,909 $22,299 $35

11.9 Electrical Foundations $0 $181 $493 $0 $674 $67 $0 $222 $963 $2

Subtotal $31,100 $12,765 $24,020 $0 $67,885 $6,789 $0 $14,110 $88,784 $141

12 Instrumentation & Control

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,195 $0 $814 $0 $2,010 $201 $100 $347 $2,658 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $275 $0 $180 $0 $454 $45 $23 $105 $627 $1

12.7 Computer & Accessories $6,376 $0 $208 $0 $6,585 $658 $329 $757 $8,330 $13

12.8 Instrument Wiring & Tubing $0 $2,455 $4,646 $0 $7,101 $710 $355 $2,042 $10,208 $16

12.9 Other I & C Equipment $4,262 $0 $2,112 $0 $6,374 $637 $319 $1,100 $8,430 $13

Subtotal $12,109 $2,455 $7,961 $0 $22,524 $2,252 $1,126 $4,350 $30,252 $48

13 Improvements to Site

13.1 Site Preparation $0 $117 $2,670 $0 $2,788 $279 $0 $920 $3,986 $6

13.2 Site Improvements $0 $2,089 $2,953 $0 $5,042 $504 $0 $1,664 $7,210 $11

13.3 Site Facilities $3,743 $0 $4,202 $0 $7,945 $794 $0 $2,622 $11,361 $18

Subtotal $3,743 $2,206 $9,825 $0 $15,774 $1,577 $0 $5,206 $22,557 $36

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $317 $179 $0 $496 $50 $0 $109 $655 $1

14.2 Steam Turbine Building $0 $2,909 $4,142 $0 $7,051 $705 $0 $1,163 $8,919 $14

14.3 Administration Building $0 $1,008 $731 $0 $1,739 $174 $0 $287 $2,199 $3

14.4 Circulation Water Pumphouse $0 $199 $105 $0 $304 $30 $0 $50 $384 $1

14.5 Water Treatment Buildings $0 $565 $551 $0 $1,117 $112 $0 $184 $1,413 $2

14.6 Machine Shop $0 $516 $353 $0 $869 $87 $0 $143 $1,099 $2

14.7 Warehouse $0 $833 $537 $0 $1,370 $137 $0 $226 $1,733 $3

14.8 Other Buildings & Structures $0 $499 $388 $0 $887 $89 $0 $195 $1,171 $2

14.9 Waste Treating Building & Str. $0 $1,115 $2,130 $0 $3,245 $325 $0 $714 $4,283 $7

Subtotal $0 $7,961 $9,116 $0 $17,077 $1,708 $0 $3,072 $21,857 $35

Total $909,446 $79,555 $310,959 $0 $1,299,960 $129,996 $47,358 $236,282 $1,713,596 $2,725Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 84 Exhibit 3

- 23 Case B1A owner’s costs

Description $ / 1,000 $/kW

Pre

- Production Costs

6 Months All Labor $15,220 $24

1 Month Maintenance Materials $3,484 $6

1 Month Non

- fuel Consumables $371 $1

1 Month Waste Disposal $405 $1

25% of 1 Months Fuel Cost at 100% CF $2,731 $4

2% of TPC $34,272 $54

Total $56,482 $90

Inventory Capital

60

- day supply of fuel and consumables at 100% CF $22,284 $35

0.5% of TPC (spare parts) $8,568 $14

Total $30,852 $49

Other Costs

Initial Cost for Catalyst and Chemicals $2,032 $3

Land $900 $1

Other Owner's Costs $257,039 $409

Financing Costs $46,267 $74

Total Overnight Costs (TOC) $2,107,169 $3,351

TASC Multiplier (IOU, high

- risk, 35 year) 1.140

Total As

- Spent Cost (TASC) $2,402,172 $3,820Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 85 Exhibit 3

- 24 Case B1A initial and annual operating and maintenance costs

Case: B1A

– Shell IGCC w/o CO 2 Cost Base: Jun 2011 Plant Size (MW,net): 6 29 Heat Rate

- net (Btu/kWh): 8, 100 Capacity Factor (%): 80
Operating & Maintenance Labor
Operating Labor Operating Labor Requirements per Shift
Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 Operating Labor Burden: 30.00 % of base Operator: 9.0

Labor O

- H Charge Rate: 25.00 % of labor Foreman: 1.0
Lab Tech's, etc.: 3.0

Total: 15.0 Fixed Operating Costs

Annual Cost ($) ($/kW

- net)
Annual Operating Labor: $6,781,554 $10.783

Maintenance Labor: $17,570,241 $27.938 Administrative & Support Labor: $6,087,949 $9.680

Property Taxes and Insurance: $34,271,927 $54.495

Total: $64,711,671 $102.897

Variable Operating Costs ($) ($/M Wh

- net)

Maintenance Material: $33,446,804 $7.58890

Consumables
Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill
Water (/1000 gallons): 0 2,988 $1.67 $0 $1,460,528 $0.33139 Makeup and Waste Water Treatment Chemicals (lbs): 0 17,801 $0.27 $0 $1,392,224 $0.31589

Carbon (Mercury Removal) (lb): 116,013 199 $5.50 $638,069 $319,034 $0.07239 COS Catalyst (m 3 ): 262 0.18 $3,751.70 $982,135 $196,427 $0.04457 Sulfinol Solution (gal): 26,146 18 $15.73 $411,337 $81,630 $0.01852

Claus Catalyst (ft 3 ): w/equip. 1.82 $203.15 $0 $108,246 $0.02456

Subtotal: $2,031,540 $3,558,089 $0.80731
Waste Disposal
Spent Mercury Catalyst (lb.): 0 199 $0.65 $0 $37,710 $0.00856 Flyash (ton): 0 0 $0.00 $0 $0 $0.00000

Slag (ton): 0 525 $25.11 $0 $3,847,802 $0.87305

Subtotal: $0 $3,885,512 $0.88160
By

- Products
Sulfur (tons): 0 131 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000 Variable Operating Costs Total: $2,031,540 $40,890,405 $9.27782

Fuel Cost
Illinois Number 6 (ton): 0 5,240 $68.54 $0 $104,866,703 $23.79370

Total: $0 $104,866,703 $23.79370



### Exhibit 3

- 25 Case B1A COE breakdown

Component Value

, $/M Wh Percentage

Capital 59. 3 

## 55%

Fixed 14. 7 

## 14%

Variable 9. 3 

## 9%

Fuel 23. 8 

## 22%

Total (Excluding T&S) 10 7.0 

## N/A

CO 2 

### T&S 0.0 

## 0%

Total (Including T&S) 107.0 

## N/ACost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 86 

# 3.2.8 Case B1B

- Shell IGCC Power Plant with CO 2 

# Capture

This case is configured to produce electric power with CO 2 

## capture. The plant configuration is the same as Case B1A, namely two Shell gasifier trains, two state

- of

- the

- art 2008 F

- class
turbines, two HRSGs

, and one steam turbine. The gross power output is constrained by the capacity of the two CTs, and since the CO 2 

## capture and compression process increases the auxiliary load on the plant, the net output is significantly reduced relative to Case B1A (497 MW

versus 6 29 MW).

The process description for Case B1B is similar to Case B1A with several notable exceptions to
accommodate CO 2 

## capture. A BFD and stream tables for Case B1B are shown in Exhibit 3

- 26

and Exhibit 3

- 27 , respectively. Instead of repeating the entire process description, only

differences from Case B1A are reported here.

3.2.8.1 Coal Preparation and Feed Systems

No differences from Case B1A.

3.2.8.2 Gasification

The gasification process is the same as Case B1 A with the exception that total coal feed to the two gasifiers is 5,065 tonnes/day (5,583 tpd ) (st ream 9) and the ASU provides 3,852 tonnes/day (4,246 tpd ) of 95 mol% oxygen to the gasifier and Claus plant (streams 5 and 3).

3.2.8.3 Raw Gas Cooling /Particulate Removal

After the raw syngas is cooled to approximately 1,093°C (2,000°F) by the syngas quench recycl e, syngas is further cooled to 899°C (1,650°F) by raising HP steam at 13.8 MPa (2,000 psia). A direct contact water quench follows to cool the raw syngas from 899°C (1,650°F) to 399°C (750°F) while providing a portion of the water required for SGS . The sy ngas is then cooled to 316°C (600°F) by raising steam, which is used in the SGS unit. After particulate filtration, the syngas is cooled to 232°C (450°F) by raising IP steam at 0.4 MPa (65 psia) before proceeding to the scrubber.

3.2.8.4 Syngas Scrubber/Sour Wate r Stripper

Syngas exits the scrubber at 191°C (376°F).

3.2.8.5 Sour Gas Shift

The SGS process was described in Section 3.1.3 . In Case B1B the syngas after the scrubber is reheated to 197°C (386°F) and then steam (stream 14) is added to adjust the H 2 

## O:CO molar ratio to approximately 1.8:1 prior to the first SGS reactor. The hot syngas exiting the first stage of SGS is used to preheat water used to humidify clean syngas prior to entering the CT. One more stage of SGS (for a total of two) results in 97.8 percent overall conversion of the CO to CO 2



## . The warm syngas from the second stage of SGS is cooled to 248°C (478°F) by preheating the syngas prior to the first stage of SGS. The SGS catalyst also serves to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. Following the second stage of SGS, the syngas is further cooled to 35°C (95°F) prior to the mercury removal beds.

3.2.8.6 Mercury Removal and AGR

Mercury removal is the same as in Case B1A.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 87 The AGR process in Case B1B is a two

- stage Selexol process where H 2 

## S is removed in the first stage and CO 2 

## in the second stage of absorption. The process results in three product streams, the clean syngas (stream 18) , a CO 2



## - rich stream and an acid gas feed to the Claus plant (stream 22) . The acid gas contains 34 percent H 2 

## S and 51 percent CO 2 

## with the balance primarily H 2



## . The CO 2



## - rich stream is discussed further in the CO 2 

## compression section.

3.2.8.7 CO 2 

## Com pression and Dehydration

CO 2 

## from the AGR process is flashed at three pressure levels to separate CO 2 

## and decrease H 2 

## losses to the CO 2 

## product pipeline. The HP CO 2 

## stream is flashed at 2.0 MPa (289.7 psia), compressed, and recycled back to the CO 2 

## absorb er. The MP CO 2 

## stream is flashed at 1.0 MPa (149.7 psia). The LP CO 2 

## stream is flashed at 0.1 MPa (16.7 psia), compressed to 1.0 MPa (149.5 psia), and combined with the MP CO 2 

## stream. The combined stream is compressed from 1.0 MPa (149.5 psia) to a n SC condition at 15.3 MPa (2215 psia) using a multiple

- stage, intercooled compressor. During compression, the CO 2 

## stream is dehydrated to a dew point

of

- 40oC (

- 40°F) with triethylene glycol. The raw CO 2 

## stream from the Selexol process contains over 99 percent CO 2 

## . The CO 2 

## (stream 21) is transported to the plant fence line and is sequestration ready. CO 2 

## T&S costs were estimated using the methodology described in Section

2.6

.

3.2.8.8 Claus Unit

The Claus plant is the same as Case B1A with the following exceptions:

• 5,277 kg/hr (11,634 lb/hr) of sulfur (stream 23) are produced

• The waste heat boiler generates 13,697 kg/hr ( 30,197 lb/hr) of 3.0 MPa (430 psia) steam, which provides all of the Claus plant process needs and provides some additional steam to the medium pressure steam header.

3.2.8.9 Power Block

Clean syngas from the AGR plant is combined with a small amount of clean gas from the CO 2 

## compression process (stream 18) and partially humidified because the nitrogen available from the ASU is insufficient to provide adequate dilution. The moisturized syngas is reheated to 193°C (380°F) using HP BFW, diluted with nitrogen (stream 4), and then enters the CT burner. The exhaust gas (stream 27) exits the CT at 562°C (1,043°F) and enters the HRSG where

additional heat is recovered. The flue gas exits the HRSG at 132°C (270°F) (stream 28) and is discharged through the plant stack. T he steam raised in the HRSG is used to power an advanced commercially available steam turbine using a 12.4 MPa/534°C/534°C (1

, 800 psig/993°F/993°F) steam cycle.

3.2.8.10 Air Separation Unit (ASU)

The same elevated pressure ASU is used as in Case B1A and produces 3, 852 tonnes/day (4,246 tpd ) of 95 mol% oxygen and 12,290 tonnes/day (13,547 tpd ) of nitrogen. There is no integration

between the ASU and the CT in the CO 2 

## capture case

.

3.2.8.11 Balance of Plant

Balance of plant items were covered in Sections 3.1.9

, 3.1.10

, and 3.1.12

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



## 88 Exhibit 3

- 26 Case B1B block flow diagram , Shell IGCC with CO 2 

### c apture

Source: NETL G AS
T URBINE C OMBUSTOR S YNGAS Q UENCH AND

C OOLING W ATER

- G AS
S HIFT R EACTORS
& G AS C OOLING W ATER S CRUBBER

E LEVATED
P RESSURE

ASU S HELL G ASIFIER M ERCURY
R EMOVAL D UAL

STAGE
S ELEXOL

U NIT

C LAUS
P LANT

S YNGAS
R EHEAT

HRSG 2 X S TATE

- OF

- THE

A RT F

- C LASS
G AS T URBINES 1 A IR TO ASU

2 3

V ENT G AS 5 10 11

G ASIFIER
O XIDANT D RY C OAL S LAG 16 17

22 23

4

26 T URBINE C OOLING A IR 27

A MBIENT A IR F LUE G AS S TACK G AS H YDROGENATION
R EACTOR AND G AS
C OOLING

24 C LEAN G AS

N ITROGEN D ILUENT S ULFUR
P RODUCT

S YNGAS C OAL
D RYER D RYING

G AS
P REP

9 W ET C OAL 18 8

6 13

12 A IR S YNGAS

S TEAM CO 2 C OMPRESSOR 21 14

15 CO 2 P RODUCT

20 S HIFT S TEAM

7 T RANSPORT
N ITROGEN

28 C LAUS
P LANT O XIDANT

C LAUS
P LANT O XIDANT

S TEAM
T URBINE 29 Note : Block Flow Diagram is not intended to represent a complete material balance

. Only major process streams and equipment are

shown

. S YNGAS Q UENCH
R ECYCLE 25 S OUR
W ATER S TRIPPER

W ATER R ECYCLE

TO P ROCESS

D EMAND S YNGAS
H UMIDIFI

CATION

19Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 89 Exhibit 3

- 27 Case B1B stream table, Shell IGCC with capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V

- L Mole Fraction

Ar 0.0092 0.0230 0.0318 0.0023 0.0318 0.0000 0.0023 0.0096 0.0000 0.0000 0.0000 0.0085 0.0061 0.0000

CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0005 0.0004 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0130 0.0000 0.0000 0.0000 0.5187 0.3712 0.0000

CO 2 0.0003 0.0079 0.0000 0.0000 0.0000 0.0000 0.0000 0.0455 0.0000 0.0000 0.0000 0.0126 0.0090 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0004 0.0000

H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.8727 0.0000 0.8090 0.0000 0.2691 0.1926 0.0000

H 2 O 0.0099 0.1984 0.0000 0.0003 0.0000 1.0000 0.0004 0.0001 0.0000 0.0935 0.0000 0.1278 0.3758 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0030 0.0000 0.0008 0.0006 0.0000

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0052 0.0000

N 2 0.7732 0.5759 0.0178 0.9919 0.0178 0.0000 0.9919 0.0585 0.0000 0.0163 0.0000 0.0507 0.0363 0.0000

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0033 0.0024 0.0000

O 2 0.2074 0.1948 0.9504 0.0054 0.9504 0.0000 0.0054 0.0000 0.0000 0.0782 0.0000 0.0000 0.0000 0.0000

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 24,277 1,004 102 17,310 4,886 1,130 940 308 0 5,809 0 26,493 29,249 11,003

V

- L Flowrate (kg/hr) 700,548 27,328 3,289 485,713 157,225 20,363 26,368 1,900 0 37,081 0 531,672 569,894 198,214 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 211,040 160,281 21,137 0 0 0

Temperature (°C) 15 20 32 93 32 343 32 35 15 16 1,427 1,082 232 288 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.10 5.62 3.59 0.10 5.79 4.24 4.24 4.03 5.52 Steam Table Enthalpy (kJ/kg) A 30.23 36.90 26.67 92.51 26.67 3,063.97 20.78 163.14

--- --- --- 2,047.11 1,220.20 2,918.18 AspenPlus Enthalpy (kJ/kg) B

- 97.58

- 2,197.43 4.13 63.47 4.13

- 12,907.38

- 8.79

- 3,104.81

- 2,116.95

- 768.33 2,165.43

- 2,946.51

- 6,659.43

- 13,053.16 Density (kg/m 3 ) 1.2 1.5 11.0 24.4 11.0 20.1 62.8 8.5

--- 16.5

--- 7.5 19.1 25.6

V

- L Molecular Weight 28.857 27.206 32.181 28.060 32.181 18.015 28.060 6.159

--- 6.383

--- 20.069 19.484 18.015

V

- L Flowrate (lb mole /hr) 53,521 2,215 225 38,162 10,771 2,492 2,072 680 0 12,807 0 58,407 64,482 24,256

V

- L Flowrate (lb/hr) 1,544,445 60,248 7,250 1,070,814 346,622 44,894 58,132 4,188 0 81,749 0 1,172,137 1,256,401 436,986 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 465,264 353,359 46,599 0 0 0

Temperature (°F) 59 68 90 199 90 650 90 94 59 60 2,600 1,980 450 550 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 740.0 815.0 520.0 14.7 840.0 615.0 615.0 585.0 800.0 Steam Table Enthalpy (Btu/lb) A 13.0 15.9 11.5 39.8 11.5 1,317.3 8.9 70.1

--- --- --- 880.1 524.6 1,254.6 AspenPlus Enthalpy (Btu/lb) B

- 42.0

- 944.7 1.8 27.3 1.8

- 5,549.2

- 3.8

- 1,334.8

- 910.1

- 330.3 931.0

- 1,266.8

- 2,863.0

- 5,611.9 Density (lb/ft 3 ) 0.076 0.097 0.687 1.521 0.687 1.257 3.918 0.531

--- 1.029

--- 0.468 1.190 1.597

A 

### Steam table reference conditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atmCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 90 Exhibit 3

- 27 Case B1B stream table, Shell IGCC with capture (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 28 29

V

- L Mole Fraction

Ar 0.0047 0.0062 0.0062 0.0096 0.0086 0.0086 0.0002 0.0017 0.0000 0.0065 0.0102 0.0092 0.0088 0.0088 0.0000

CH 4 0.0003 0.0004 0.0004 0.0006 0.0005 0.0005 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.2873 0.0084 0.0084 0.0130 0.0116 0.0116 0.0002 0.0025 0.0000 0.1143 0.0060 0.0000 0.0000 0.0000 0.0000

CO 2 0.0070 0.3776 0.3810 0.0455 0.0407 0.0407 0.9944 0.5141 0.0000 0.2866 0.6257 0.0003 0.0080 0.0080 0.0000

COS 0.0003 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 0.1491 0.5633 0.5593 0.8727 0.7819 0.7819 0.0050 0.1068 0.0000 0.0659 0.2694 0.0000 0.0000 0.0000 0.0000

H 2 O 0.5172 0.0016 0.0016 0.0001 0.1041 0.1041 0.0000 0.0300 0.0000 0.4715 0.0017 0.0099 0.1374 0.1374 1.0000

HCl 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 S 0.0040 0.0057 0.0057 0.0000 0.0000 0.0000 0.0000 0.3398 0.0000 0.0014 0.0057 0.0000 0.0000 0.0000 0.0000

N 2 0.0281 0.0368 0.0374 0.0585 0.0524 0.0524 0.0002 0.0047 0.0000 0.0516 0.0813 0.7732 0.7397 0.7397 0.0000

NH 3 0.0019 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1060 0.1060 0.0000

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0018 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 37,783 28,837 29,237 18,312 20,438 20,438 10,099 488 0 630 400 110,253 139,892 139,892 28,855

V

- L Flowrate (kg/hr) 723,426 562,223 574,690 112,786 151,092 151,092 442,270 17,202 0 16,585 12,466 3,181,557 3,818,362 3,818,362 519,836 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 5,277 0 0 0 0 0 0

Temperature (°C) 217 35 35 35 137 193 51 48 178 232 38 15 562 132 534 Pressure (MPa, abs) 3.96 3.62 3.59 3.59 3.21 3.17 15.27 0.16 0.12 0.08 5.51 0.10 0.10 0.10 12.51 Steam Table Enthalpy (kJ/kg) A 1,541.73 45.33 44.53 163.14 1,181.24 1,416.72

- 161.70 85.01

--- 1,114.50 8.30 30.23 866.14 371.29 3,432.00 AspenPlus Enthalpy (kJ/kg) B

- 8,063.86

- 7,695.78

- 7,701.53

- 3,104.81

- 5,307.37

- 5,071.89

- 9,118.58

- 6,131.59 142.40

- 8,838.52

- 7,960.81

- 97.58

- 720.70

- 1,215.55

- 12,538.31 Density (kg/m 3 ) 19.5 28.1 28.1 8.5 6.9 6.0 639.8 2.2 5,279.4 0.5 74.4 1.2 0.4 0.8 36.8

V

- L Molecular Weight 19.147 19.496 19.656 6.159 7.393 7.393 43.792 35.245

--- 26.336 31.160 28.857 27.295 27.295 18.015

V

- L Flowrate (lb mole /hr) 83,298 63,576 64,458 40,371 45,059 45,059 22,265 1,076 0 1,388 882 243,066 308,408 308,408 63,615

V

- L Flowrate (lb/hr) 1,594,881 1,239,491 1,266,974 248,650 333,100 333,100 975,038 37,925 0 36,563 27,484 7,014,133 8,418,047 8,418,047 1,146,042 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 11,634 0 0 0 0 0 0

Temperature (°F) 422 95 94 94 278 380 124 119 352 450 100 59 1,043 270 993 Pressure (psia) 575.0 525.0 520.0 520.0 465.0 460.0 2,214.7 23.7 17.3 12.3 799.5 14.7 15.2 15.2 1,814.7 Steam Table Enthalpy (Btu/lb) A 662.8 19.5 19.1 70.1 507.8 609.1

- 69.5 36.5

--- 479.1 3.6 13.0 372.4 159.6 1,475.5 AspenPlus Enthalpy (Btu/lb) B

- 3,466.8

- 3,308.6

- 3,311.1

- 1,334.8

- 2,281.8

- 2,180.5

- 3,920.3

- 2,636.1 61.2

- 3,799.9

- 3,422.5

- 42.0

- 309.8

- 522.6

- 5,390.5 Density (lb/ft 3 ) 1.218 1.753 1.753 0.531 0.431 0.374 39.942 0.135 329.584 0.033 4.646 0.076 0.026 0.053 2.295

A 

### Steam table reference conditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atmCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 91 

# 3.2.9 Case B1B

- Performance Results

The Case B1B modeling assumptions were presented previously in Section 3.2.3

. The plant produces a net output of 497 MWe at a net plant efficiency of 31.2 percent (HHV basis). Overall performance for the plant is summarized in Exhibit 3

- 28 ; Exhibit 3

- 29 provides a detailed breakdown of the auxiliary power requirements. The ASU accou nts for approximately 58 percent of the auxiliary load between the main air compressor, nitrogen compressor, oxygen

compressor
, and ASU auxiliaries. The two

- stage Selexol process and CO 2 

## compression account for an additional 28 percent of the auxiliary po wer load. The BFW and CWS (CWPs and cooling tower fan) compose approximately 4 percent of the load, leaving 10 percent of the auxiliary load for all other systems.

Exhibit 3

- 28 Case B1 B plant performance su mmary

Performance Summary

Combustion Turbine Power, MWe 464
Sweet Gas Expander Power, MWe 0

Steam Turbine Power, MWe 209

Total Gross Power, MWe 673
Air Separation Unit Main Air Compressor, kWe 59,740
Oxygen Compressor, kWe 9,460
Nitrogen Compressors, kWe 32,910

CO 2 Compression, kWe 30,210

Acid Gas Removal, kWe 18,650

Balance of Plant, kWe 25,690

Total Auxiliaries, MWe 177

Net Power, MWe 497
HHV Net Plant Efficiency (%) 31.2%
HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,528 (10,927)
HHV Cold Gas Efficiency, % 84.5%

HHV Combustion Turbine Efficiency, % 35.9%
LHV Net Plant Efficiency (%) 32.4%
LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,119 (10,539)
LHV Cold Gas Efficiency, % 82.9%

LHV Combustion Turbine Efficiency, % 42.3%
Steam Turbine Cycle Efficiency, % 39.0%
Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 9,238 (8,756)
Condenser Duty, GJ/hr ( MM Btu/hr) 1,335 (1,265)

As

- Received Coal Feed, kg/hr (lb/hr) 211,040 (465,264)

HHV Thermal Input, kWt 1,590,722
LHV Thermal Input, kWt 1,534,271
Raw Water Withdrawal, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.043 (11.4)
Raw Water Consumption, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.035 (9.3)

O 2 :Coal 0.704Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 92 Exhibit 3

- 29 Case B1 B plant power summary

Power Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 0

Steam Turbine Power, MWe 209

Total Gross Power, MWe 673

Auxiliary Load Summary

Coal Handling, kWe 460

Coal Milling, kWe 2,170

Sour Water Recycle Slurry Pump, kWe 0

Slag Handling, kWe 550

Air Separation Unit Auxiliaries, kWe 1,000

Air Separation Unit Main Air Compressor, kWe 59,740

Oxygen Compressor, kWe 9,460

Nitrogen Compressors, kWe 32,910

Feedwater Pumps, kWe 3,500

Quench Water Pump, kWe 610

Syngas Recycle Compressor, kWe 790

CO 2 Compression, kWe 30,210

Scrubber Pumps, kWe 360

Acid Gas Removal, kWe 18,650

Combustion Turbine Auxiliaries, kWe 1,000

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 280

Circulating Water Pumps, kWe 4,380

Ground Water Pumps, kWe 510

Cooling Tower Fans, kWe 2,270

Claus Plant/TGTU Auxiliaries, kWe 250

Claus Plant TG Recycle Compressor, kWe 1,830

Miscellaneous Balance of Plant A 

### , kWe 3,000

Transformer Losses, kWe 2,630

Total Auxiliaries, MWe 177

Net Power, MWe 497

A 

### Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads



## 3.2.9.1 Environmental Performance

The environmental targets for emissions of Hg, NO x , SO 2 

## , CO 2 

## , and PM were presented in Section 2.4. A summary of the plant air emissions for Case B1B is presented in Exhibit 3

- 30

. All HCl is assumed to be remo ved and is, therefore, not reported.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 93 Exhibit 3

- 30 Case B1B air emissions

kg/GJ (lb/ MM Btu) Tonne/year (ton/year) A 

### kg/MWh (lb/MWh) B



### SO 2 

### 0.001 (0.002) 37 (40) 0.008 (0.0 17 )

NOx 0.021 (0.049) 847 (934) 0.180 (0.396)

Particulates 0.003 (0.0071) 123 (135) 0.026 (0.057)

Hg 1.60E

- 7 (3.72E

- 7) 0.006 (0.007) 1.36E

- 6 (3.00E

- 6)

CO 2 

### 9 (20 ) 344,507 (379,754) 73 (161)

CO 2 C



### - - 99 (218)

A 

### Calculations based on an 80 percent capacity factor

B 

### Emissions are based on gross power except where otherwise noted

C 

### CO 2 

### emissions based on net power instead of gross power



## The low level of SO 2 

## emissions is achieved by capturing the sulfur in the gas by the two

- stage Selexol AGR process. The CO 2 

## capture target results in the sulfur compounds being removed to a greater extent than required in the environmental targets of Section 2.3 . The clean syngas

exit ing the AGR process has a sulfur concentration of approximately 4 ppmv. This results in a

concentration in the HRSG flue gas of less than 1 ppmv. The H 2 

## S

- rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is compressed and recycled back to the AGR where most of the remaining sulfur is removed.

NO x emissions are limited by the use of nitrogen dilution and humidification to 15 ppmvd (as

NO 2 

## @ 15 percent O 2 

## ). Ammonia in the syngas is remo ved with process condensate prior to the

low

- temperature AGR process and subsequently destroyed in the Claus plant burner. This helps

lower NO x levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cycl one and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only.

Approximately 97 percent of mercury is captured from the syngas by dual activated carbon bed s

. Ninety two percent of the CO 2 

## from the syngas is captured in the AGR system and compressed for sequestration. Because not all CO is converted to CO 2 

## in the shift reactors, the overall carbon

removal is 90.0 percent.

The carbon balance for the plant is shown in Exhibit 3

- 31

. The carbon input to the plant consists

of carbon in the air in a ddition to carbon in the coal. Carbon leaves the plant as unburned carbon in the slag and as CO 2 

## in the stack gas, coal dryer vent gas, ASU vent gas

, and the captured CO 2 

## product. The carbon capture efficiency is defined as one minus the amount of carbon in the stack

gas relative to the total ca rbon in less carbon contained in the slag , represented by the following

fraction:

CCCCCCCCCC SS SSSS
( TT TT CCCCCCCCCC )

− ( CCCCCCCCCC SS SS ) = � 1

− � 29

, 578

297

, 754

− 1

, 483 �

∗ � 100 = 90

. 0%Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 94 Exhibit 3

- 31 Case B 1B carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 134,527 (296,581) Stack Gas 13,416 (29,578)

Air (CO 2 ) 532 (1,173) Coal Dryer Stack 223 (491)

CO 2 Product 120,652 (265,992)

ASU Vent 95 (210)

Slag 673 (1,483)

Total 135,059 (297,754) Total 135,059 (297,754)



## Exhibit 3

- 32 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the stack ga s
, and sulfur from the tail gas unit that is vented through the coal dryer. Sulfur in the slag is considered negligible.

Exhibit 3

- 32 Case B1B sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 5,290 (11,661) Stack Gas 3 (6)

Coal Dryer Stack 0 (0)

CO 2 Product 10 (22)

Elemental Sulfur 5,277 (11,634)

Total 5,290 (11,661) Total 5,290 (11,661)



## Exhibit 3

- 33 shows the overall water balance for the plant. The exhibit is presented in an

identical manner as for Case B1A

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



## 95 Exhibit 3

- 33 Case B1B water balance

Water Use Water

Demand Internal Recycle Raw Water

Withdrawal Process

Water Discharge Raw Water Consumption

m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm)

Slag Handling 0.46 (121) 0.46 (121)

– – – Slurry Water

– – – – –
Quench/Wash 3.17 (836) 2.22 (587) 0.94 (250)

– 0.94 (250)

Humidifier 0.67 (177) 0.67 (177)

– – –

SWS Blowdown

– – – 0.03 (7.08)

- 0.03 (

- 7.08)

Condenser Makeup 3.83 (1,012)

– 3.83 (1,012)

– 3.83 (1,012)

BFW Makeup 0.18 (48)

– 0.18 (48)

– 0.18 (48)

Gasifier Steam 0.34 (90)

– 0.34 (90)

– 0.34 (90)

Shift Steam 3.31 (874)

– 3.31 (874)

– 3.31 (874)

CT Steam Dilution

– – – – – Cooling Tower 17.07 (4,510) 0.45 (119) 16.62 (4,391) 3.84 (1,014) 12.78 (3,377)

BFW Blowdown

– 0.18 (48)

- 0.18 (

- 48)

– - 0.18 (

- 48)

SWS Blowdown

– 0.27 (70.80) - 0.27 (

- 70.80) – - 0.27 (

- 70.80)

Total 25.20 (6,657) 3.80 (1,004) 21.40 (5,652) 3.87 (1,021) 17.53 (4,631)



## 3.2.9.2 Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3

- 34 through

Exhibit 3

- 36 :

• Coal gasification and ASU

• Syngas cleanup including sulfur recovery and tail gas recycle

• Combined cycle power generation, steam, and FW An overall plant energy balance is provided in tabular form in Exhibit 3

- 37 . The power out is

the combined CT and steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 3

- 28 ) is calculated by multiplying the power out by a combi n ed generator efficiency of 98.5 percent.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 96 Exhibit 3

- 34 Case B1B coal gasification and ASU heat and mass balance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 1 B

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 1 B

S HELL G ASIFIER
ASU

, G ASIFICATION

, AND G AS C OOLING

DWG

. NO

. BB

- HMB

- CS

- B 1 B

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES

1 OF 3 Ambient Air

Intercooled Air Compressor

Elevated

Pressure

ASU Intercooled Nitrogen Compressor

Intercooled Oxygen Compressor

Milled Coal Water Steam

Slag

Removal Slag Gross Plant Power : 673 MWe Auxiliary Load : 177 MWe

Net Plant Power : 497 MWe Net Plant Efficiency

, HHV : 31

. 2 %

Net Plant Heat Rate : 10

, 927 Btu / kWh Dry Coal

Coal Feeding Steam

Candle

Filter Cyclone N 2 to GT Combustor

Boost Compressor

Recycle Compressor

Raw Syngas

to Scrubber 333

, 980 W

520 T

625 P

552 H To Claus Plant

9 10 1

3

7

6

11 13 2 1

, 544

, 445 W

59 T

15 P

13 H

60

, 248 W

68 T

16 P

16 H

989

, 843 W

90 T

56 P

14 H 139

, 103 W

50 T

182 P

3 H

7

, 250 W

90 T

125 P

11 H 346

, 622 W

90 T

125 P

11 H

346

, 622 W

241 T

940 P

41 H 58

, 132 W

387 T

815 P

87 H

465

, 264 W

59 T

15 P 435

, 108 W

60 T

840 P

46

, 599 W

2

, 600 T

615 P 1

, 172

, 137 W

1

, 980 T

615 P

878 H

1

, 256

, 401 W

450 T

585 P

523 H W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical 687

, 451 W

385 T

384 P

87 H

5

44

, 894 W

650 T

740 P

1

, 309 H

Coal Drying

Incinerator

Syngas Slip Stream Incinerator Air Flue Gas /

Combustion

Products

4

, 188 W

94 T

520 P

70 H 63

, 439 W

59 T

15 P

13 H 97

, 783 W

8 1

, 128

, 946 W

199 T

384 P

40 H

333

, 980 W

450 T

585 P

523 H

Syngas

Quench

Cooler Quench Water

418

, 244 W

420 T

1

, 200 P

388 H

To Reheater

, Shift Steam

, and gasifier To LP Evaporator

From IP BFW From LP

Economizer N 2 Compressor

12

1

, 590

, 381 W

600 T

595 P

585 H 1

, 590

, 381 W

750 T

605 P

647 H 1

, 543

, 066 W

100 T

190 P

18 H

383

, 362 W

385 T

469 P

87 H

Syngas

Cooler Duct Cooler

Steam

Generation

Shell

Gasifier

Pre Particulat

Cooler

Post

Particulate

Cooler From HP

Economizer 2 To HP Economizer 1

To Superheater

From HP

Economizer 2 Incinerator

Exhaust ASU

Vent

N 2 to GT Combustor

Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 97 Exhibit 3

- 35 Case B1B syngas cleanup heat and mass balance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 1 B

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 1 B

S HELL G ASIFIER
G AS C LEANUP S YSTEM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

Mercury

Removal

Knock

Out

Drum

Raw Syngas

Sour

Drum Claus Plant

Tail

Gas Furnace Catalytic

Reactor

Beds

Sulfur Sour Water

Reboiler Acid Gas

Tailgas Carbon Dioxide

Sour Gas

Sulfur Hydrogen

DWG

. NO

. BB

- HMB

- CS

- B 1 B

- PG

- 2 P AGES

2 OF 3 Sour Stripper Syngas

Scrubber

Gross Plant Power : 673 MWe Auxiliary Load : 177 MWe

Net Plant Power : 497 MWe Net Plant Efficiency

, HHV : 31

. 2 %

Net Plant Heat Rate : 10

, 927 Btu / kWh Water

13 16 17 22

23 24

1

, 256

, 401 W

450 T

585 P

523 H 27

, 484 W

100 T

800 P

4 H 436

, 986 W

550 T

800 P

1

, 246 H 1

, 594

, 881 W

485 T

565 P

424 H 1

, 266

, 974 W

94 T

520 P

19 H

Syngas

Coolers 248

, 650 W

94 T

520 P

70 H

3

, 022 W

228 T

65 P

370 H 36

, 563 W

450 T

12 P

479 H 37

, 925 W

119 T

24 P

37 H

Knock Out Tailgas to AGR 1

, 594

, 881 W

422 T

575 P

663 H

1

, 239

, 491 W

95 T

525 P

19 H W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical

9

, 080 W

114 T

11 P

40 H Treated Syngas

18 Humidification 19 Humidified Fuel Gas 20

8

Shift Steam High Temperature

Shift # 1 Low Temperature

Shift # 2

Fuel Gas

Humidification

1

, 157

, 895 W

376 T

580 P

435 H 1

, 157

, 895 W

386 T

575 P

439 H

1

, 594

, 881 W

478 T

560 P

421 H 14 15

Two

- Stage

Selexol Clean

Gas

CO 2 Acid

Gas

Interstage Knockout 21 Multistage

Intercooled CO 2

Compressor 975

, 038 W

124 T

2

, 215 P

- 70 H 25

Tailgas Recycle Compressor Hydrogenation

And Tail Gas

Cooling

To Fuel Gas

Preheater From Fuel Gas

Preheater

411

, 354 W

376 T

580 P

380 H 411

, 354 W

150 T

1

, 205 P

118 H 4

, 188 W

94 T

520 P

70 H 333

, 100 W

278 T

465 P

508 H 333

, 100 W

380 T

460 P

609 H

From IP BFW

, LP

BFW

, and Tail Gas Cooling To Syngas Cooling From Gland Steam

Condenser

109 T To LP Turbine

, Preheater

WGS / Gasifier Steam

and Reheater

29

, 998 W

120 T

11 P

115 H To Water

Treatment Makeup Water

478

, 771 W To Slag Quench 7

, 250 W

90 T

125 P

11 H 3 7

, 250 W

450 T

125 P

92 H

Claus Oxygen

Preheater

To

Deaerator

From IP

BFW 11

, 634 W

CO 2 Product From Syngas

Scrubber and HP

Economizer 2 To Syngas Scrubber

and HP Economizer 1

Fuel Gas

Preheater

Oxygen Steam Slip Stream to Coal Dryer

Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 98 Exhibit 3

- 36 Case B1B combined cycle power generation heat and mass balance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 1 B

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 1 B

S HELL G ASIFIER
P OWER B LOCK S YSTEM

DWG

. NO

. BB

- HMB

- CS

- B 1 B

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES
3 OF 3 Sour Gas

Sour Water

Water Steam

Flue Gas

HP

Turbine IP

Turbine

Air Inlet

Filter Steam Seal Regulator

Gland

Steam

Condenser LP

Turbine Stack

Expander Compressor Generator

Generator Steam Turbine

State

- of

- the

- art 2008

F

- Class Turbine

7

, 014

, 133 W

59 T

15 P

13 H 1

, 911

, 334 W

101 T

1 P

69 H 8

, 418

, 047 W

270 T

15 P

160 H

333

, 100 W

380 T

460 P

609 H 1

, 146

, 042 W

993 T

1

, 815 P

1

, 468 H 8

, 328 W

298 T

65 P

1

, 171 H

1

, 393

, 093 W

440 T

65 P

1

, 244 H

1

, 911

, 334 W

103 T

120 P

71 H 1

, 400 W

614 T

65 P

1

, 331 H

1

, 400 W

212 T

15 P

180 H

21 24

16 23

Hot Well Condenser 506

, 076 W

59 T

15 P

27 H 9

, 028 W

660 T

501 P

1

, 326 H

9

, 765 W

614 T

65 P

1

, 331 H 30

, 983 W

500 T

250 P

1

, 255 H 799 W

993 T

1

, 815 P

1

, 468 H 1

, 338 W

504 T

65 P

1

, 276 H Preheater Deaerator

Heater HP

Economizer

1 LP

Economizer HP

Economizer

2 HP Evaporator Superheater

/ Reheater

From Syngas Cooler To Duct and Radiant Syngas

Coolers From Duct and Radiant Syngas Coolers

To ASU and

Humidifier

Deaerator From ASU and

Humidifier

LP Evaporator

IP to Pre Particulate and Syngas Coolers IP From Syngas and Pre

Particulate Cooler

WGS Shift Steam From Claus

, Process Extraction

, and 250 PSIA Header

LP Extraction Spray

LP Blowdown LP To Syngas

Coolers Cold Reheat

Hot Reheat

8

, 418

, 047 W

1

, 043 T

15 P

372 H 22 To WWT

Condensate to Tail Gas Cooling IP Extraction Steam

to 250 PSIA Header Process

Extraction LP From Syngas Coolers

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical 235 T

274 T

1

, 843

, 260 W

274 T

45 P

242 H

1

, 169

, 363 W

279 T

2

, 251 P

247 H 9

, 216 W

274 T

79 P

242 H

25

, 067 W

274 T

79 P

242 H 271

, 164 W

274 T

79 P

242 H

41

, 443 W

276 T

615 P

244 H 282

, 770 W

351 T

2

, 251 P

319 H

305 T 585 T 636 T

23

, 308 W

585 T

2

, 001 P

585 H 294

, 918 W

550 T

625 P

1

, 244 H 325

, 216 W

550 T

625 P

1

, 244 H 636 T

480

, 228 W

585 T

2

, 001 P

585 H

981

, 188 W

661 T

501 P

1

, 327 H 282

, 770 W

585 T

2

, 001 P

585 H 290

, 257 W

298 T

65 P

266 H

217

, 834 W

298 T

65 P

1

, 171 H 271

, 164 W

298 T

65 P

1

, 171 H 325

, 216 W

275 T

640 P

243 H

Nitrogen Diluent 1

Fuel Gas IP To Claus 0 W

30

, 298 W

550 T

625 P

1

, 244 H Gasifier Steam To Post

Particulate

Cooler From Post

Particulate

Cooler

LP Extraction Spray # 1 LP Extraction Spray # 2

Steam to Gasifier

and WGS 20

, 429 W

241 T

825 P

209 H 156

, 625 W

649 T

740 P

1

, 303 H

1

, 000 W

993 T

1

, 815 P

1

, 468 H 1

, 000 W

212 T

15 P

180 H 993 T 195 T

Water Makeup Nitrogen Diluent 2 383

, 362 W

385 T

384 P

87 H

687

, 451 W

385 T

469 P

87 H HP Pump LP Pump IP Pump

Gross Plant Power : 673 MWe Auxiliary Load : 177 MWe

Net Plant Power : 497 MWe Net Plant Efficiency

, HHV : 31

. 2 %

Net Plant Heat Rate : 10

, 927 Btu / kWh

Condensate

Pumps Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 99 Th is page intentionally left blankCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 100 Exhibit 3

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

HHV Sensible +

Latent Power Total

Heat In (GJ/hr)

Coal 5,727 (5,428) 4.8 (4.5)

– 5,731 (5,432)

Air

– 118.2 (112.1)

– 118.2 (112.1)

Raw Water Makeup

– 80.5 (76.3)

– 80.5 (76.3)

Auxiliary Power

– – 636 (603) 636 (603)

TOTAL 5,727 (5,428) 203.5 (192.9) 636 (603) 6,566 (6,223)

Heat Out (GJ/hr)

ASU Vent

– 1.0 (1.0)

– 1.0 (1.0)

Slag 22.1 (20.9) 35.7 (33.8)

– 57.7 (54.7)

Stack Gas

– 1,418 (1,344)

– 1,418 (1,344)

Sulfur 48.9 (46.3) 0.6 (0.6)

– 49.5 (46.9)

Motor Losses and Design

Allowances – – 55.5 (52.6) 55.5 (52.6)

Condenser

– 1,335 (1,265)

– 1,335 (1,265)

Non

- Condenser Cooling Tower

Loads – 724 (686)

– 724 (686)

CO 2 – - 71.5 (

- 67.8)

– - 71.5 (

- 67.8)

Blowdown

– 41.3 (39.1)

– 41.3 (39.1)

CO 2 Capture Losses

– 171.0 (162.1)

– 171.0 (162.1)

Ambient Losses A



### – 115.3 (109.3)

– 115.3 (109.3)

Power

– – 2,424 (2,298) 2,424 (2,298)

TOTAL 71.0 (67.2) 3,769 (3,573) 2,480 (2,350) 6,320 (5,990)

Unaccounted Energy B



### – 246 (233)

– 246 (233)

A 

### Ambient losses include all losses to the environment throu gh radiation, convection, etc. Sources of these losses include the combustor, reheater, superheater, and transformers.

B 

### By difference



# 3.2.10 Case B1B

- Major Equipment List

Major equipment items for the Shell gasifier with CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the costCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 101 estimates in Section 3.2.11 . In general, the design conditions include a 10 percent contingency

for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

Case B1B

– Account 1: Coal Handling

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

5 Stacker/Reclaimer Traveling, linear 1,130 tonne/hr (1,250 tph) 1 0

6 Reclaim Hopper N/A 40 tonne (50 ton) 2 1

7 Feeder Vibratory 170 tonne/hr (190 tph) 2 1

8 Conveyor No. 3 Belt w/ tripper 350 tonne/hr (380 tph) 1 0

9 Coal Surge Bin w/ Vent Filter Dual outlet 170 tonne (190 ton) 2 0

10 Crusher Impactor reduction 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 2 0

11 Conveyor No. 4 Belt w/ tripper 350 tonne/hr (380 tph) 1 0

12 Conveyor No. 5 Belt w/ tripper 350 tonne/hr (380 tph) 1 0

13 Coal Silo w/ Vent Filter and

Slide Gates Field erected 800 tonne (900 ton) 3 0



## Case B1B

– Account 2: Coal Preparation and Feed

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 80 tonne/hr (90 tph) 3 0

2 Conveyor No. 6 Belt w/ tripper 230 tonne/hr (260 tph) 1 0

3 Roller Mill Feed Hopper Dual Outlet 460 tonne (510 ton) 1 0

4 Weigh Feeder Belt 120 tonne/hr (130 tph) 2 0

5 Coal Dryer and Pulverizer Rotary 120 tonne/hr (130 tph) 2 0

6 Coal Dryer Feed Hopper Vertical Hopper 230 tonne (260 ton) 2 0



## Case B1B

– Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical,

outdoor 987,000 liters (261,000 gal) 2 0

2 Condensate Pumps Vertical canned 8,000 lpm @ 90 m H 2 O (2,110 gpm @ 300 ft H 2 O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 551,000 kg/hr (1,215,000 lb/hr) 2 0

4 Intermediate

- Pressure Feedwater Pump Horizontal centrifugal, single stage 7,970 lpm @ 30 m H 2 O (2,110 gpm @ 90 ft H 2 O) 2 1

5 High

- Pressure Feedwater Pump No. 1 Barrel type, multi

stage, centrifugal HP water: 5,060 lpm @ 1,800 m H 2 O (1,340 gpm @ 6,100 ft H 2 O) 2 1

6 High

- Pressure Feedwater Pump No. 2 Barrel type, multi

stage, centrifugal IP water: 1,220 lpm @ 220 m

H 2 O (320 gpm @ 730 ft H 2 O) 2 1

7 Auxiliary Boiler Shop fabricated, water

tube 18,000 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air Compressors Flooded Screw 28 m 3 

### / min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m 3 

### / min (1,000 scfm) 2 1

10 Closed Cycle Cooling Heat Exchangers Plate and frame 398 GJ/hr (377 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 142,800 lpm @ 20 m H 2 O (37,700 gpm @ 70 ft H 2 O) 2 1Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 102 Equipment

No. Description Type Design Condition Operating Qty. Spares

12 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 110 m H 2 O (1,000 gpm @ 350 ft H 2 O) 1 1

13 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 80 m H 2 O (700 gpm @ 250 ft H 2 O) 1 1

14 Raw Water Pumps Stainless steel, single

suction 5,950 lpm @ 20 m H 2 O (1,570 gpm @ 60 ft H 2 O) 2 1

15 Ground Water Pumps Stainless steel, single

suction 2,980 lpm @ 270 m H 2 O (790 gpm @ 880 ft H 2 O) 4 1

16 Filtered Water Pumps Stainless steel, single

suction 4,640 lpm @ 50 m H 2 O (1,230 gpm @ 160 ft H 2 O) 2 1

17 Filtered Water Tank Vertical, cylindrical 2,226,000 liter (588,000 gal) 2 0

18 Makeup Water

Demineralizer Anion, cation, and

mixed bed 2,090 lpm (550 gpm) 2 0

19 Liquid Waste Treatment System N/A 10 years, 24

- hour storm 1 0



## Case B1B

– Account 4: Gasifier, ASU, and Accessories Including Low Temperature Heat Recovery and Fuel Gas Saturation

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized dry

- feed,

entrained bed 2,800 tonne/day, 4.2 MPa (3,100 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler Convective spiral

wound tube boiler 397,000 kg/hr (875,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 313,000 kg/hr (691,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with pulse

- jet cleaning metallic filters 2 0

5 Syngas Scrubber Including Sour Water Stripper Vertical upflow 313,000 kg/hr (691,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with

condensate drain 398,000 kg/hr (877,000 lb/hr) 8 0

7 Raw Gas Knockout

Drum Vertical with mist

eliminator 310,000 kg/hr, 35°C, 3.7 MPa (683,000 lb/hr, 95°F, 530 psia) 2 0

8 Saturation Water

Economizers Shell and tube 78 GJ/hr (74 MMBtu/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 83,000 kg/hr, 137°C, 3.6 MPa (183,000 lb/hr, 278°F, 520 psia) 2 0

10 Saturator Water Pump Centrifugal 1,700 lpm @ 13 m H 2 O (500 gpm @ 42 ft H 2 O) 2 2

11 Synthesis Gas

Reheater Shell and tube 83,000 kg/hr (183,000 lb/hr) 2 0

12 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 313,000 kg/hr (691,000 lb/hr)

syngas 2 0

13 ASU Main Air Compressor Centrifugal, multi

- stage 5,000 m 3 

### / min @ 1.3 MPa (186,000 scfm @ 190 psia) 2 0

14 Cold Box Vendor design 2,100 tonne/day (2,300 tpd) of 95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi

- stage 1,000 m 3 

### / min (37,000 scfm)

Suction

- 1.0 MPa (130 psia) Discharge

- 6.5 MPa (940 psia) 2 0

16 Primary Nitrogen Compressor Centrifugal, multi

- stage 3,000 m 3 

### / min (123,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 2 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 103 Equipment

No. Description Type Design Condition Operating Qty. Spares

17 Secondary Nitrogen Compressor Centrifugal, single

stage 490 m 3 

### / min (17,000 scfm)

Suction

- 1.3 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 2 0

18 Gasifier Purge Nitrogen Boost Compressor Centrifugal, single

stage 1,000 m 3 

### / min (48,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470 psia) 2 0



## Case B1B

– Account 5: Syngas Cleanup

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber 1 Sulfated carbon bed 309,000 kg/hr (682,000 lb/hr)

, 35°C (95°F)

, 3.6 MPa (525 psia) 2 0

2 Mercury Adsorber 2 Sulfated carbon bed 309,000 kg/hr (682,000 lb/hr)

, 35°C (95°F)

, 3.6 MPa (520 psia) 2 0

3 Sulfur Plant Claus type 139 tonne/day (154 tpd) 1 0

4 Water Gas Shift

Reactors Fixed bed, catalytic 199,000 kg/hr (439,000 lb/hr)

, 216°C (420°F)

, 4.0 MPa (580 psia) 4 0

5 Shift Reactor Heat Recovery Exchangers Shell and T ube Exchanger 1: 121 GJ/hr (114 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 4 0

6 Acid Gas Removal

Plant Two

- stage s elexol 316,000 kg/hr (697,000 lb/hr)

, 35°C (94°F)

, 3.6 MPa (520 psia) 2 0

7 Hydrogenation

Reactor Fixed bed, catalytic 18,000 kg/hr (40,000 lb/hr) 232°C (450°F) 0.1 MPa (12.2959488 psia) 1 0

8 Tail Gas Recycle Compressor Centrifugal 14,000 kg/hr (30,000 lb/hr) each 1 0

9 CO 2 

### Compressor Integrally geared,

multi

- stage centrifugal 1,100 m 3 

### / min @ 15.3 MPa (38,700 scfm @ 2,215 psia) 4 0



## Case B1B

– Account 6: Combustion Turbine and Auxiliaries

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Combustion Turbine State

- of

- the

- art

2008 F

- c lass 230 MW 2 0

2 Combustion Turbine

Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 2 0



## Case B1B

– Account 7: HRSG, Ducting, and Stack

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type

409SS liner 76 m (250 ft) high x 8.5 m (28 ft) diameter 1 0

2 Heat Recovery
Steam Generator Drum, multi

pressure with

economizer section and integral

deaerator Main steam

- 285,910 kg/hr,

12.4 MPa/534°C (630,323 lb/hr, 1,800 psig/99 3°F) 2 0



## Case B1B

– Account 8: Steam Turbine Generator and Auxiliaries

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Steam

Turbine Commercially available

advanced steam turbine 220 MW 12.4 MPa/534°C/534°C (1,800 psig/ 993°F/993°F) 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 104 Equipment

No. Description Type Design Condition Operating Qty. Spares

2 Steam

Turbine
Generator Hydrogen cooled, static

excitation 240 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 1 0

3 Surface

Condenser Single pass, divided waterbox including

vacuum pumps 1,470GJ/hr (1,390 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1 0

4 Steam Bypass One per HRSG 50% steam flow @ design steam

conditions 2 0



## Case B1B

– Account 9: Cooling Water System

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 440,000 lpm @ 30 m (116,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative, mechanical draft,

multi

- cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,450 GJ/hr (2,320 MMBtu/hr) heat duty 1 0



## Case B1B

– Account 10: Slag Recovery and Handling

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 222,000 liters (59,000 gal) 2 0

2 Slag Crusher Roll 12 tonne/hr (13 tph) 2 0

3 Slag Depressurizer Lock h opper 12 tonne/hr (13 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 133,000 liters (35,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 60,000 liters (16,000 gal) 2 0

6 Slag Conveyor Drag chain 12 tonne/hr (13 tph) 2 0

7 Slag Separation Screen Vibrating 12 tonne/hr (13 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 12 tonne/hr (13 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 190,000 liters (50,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 50 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 2 2

11 Grey Water Storage Tank Field erected 60,000 liters (16,000 gal) 2 0

12 Grey Water Pumps Centrifugal 210 lpm @ 430 m H 2 O (60 gpm @ 1,420 ft H 2 O) 2 2

13 Slag Storage Bin Vertical, field erected 800 tonne (900 tons) 2 0

14 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 1 0



## Case B1B

– Account 11: Accessory Electric Plant

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 CTG Transformer Oil

- filled 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 2 0

2 STG Transformer Oil

- filled 24 kV/345 kV, 200 MVA, 3

- ph, 60 Hz 1 0

3 High Voltage Auxiliary

Transformer Oil

- filled 345 kV/13.8 kV, 74 MVA, 3

- ph, 60 Hz 2 0

4 Medium Voltage Transformer Oil

- filled 24 kV/4.16 kV, 46 MVA, 3

- ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 7 MVA, 3

- ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 105 Equipment

No. Description Type Design Condition Operating Qty. Spares

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency

shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 0



## Case B1B

– Account 12: Instrumentation and Control

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 DCS

- Main
Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 0



# 3.2.11 Case B1B

- Cost Estimating

The cost estimating methodology was described previously in Section 2.6

. Exhibit 3

- 38 shows a detailed breakdown of the capita l costs ; Exhibit 3

- 39 shows the owner’s costs , TOC, and TASC ; Exhibit 3

- 40 shows the initial and annual O&M costs ; and Exhibit 3

- 41 shows the COE

breakdown

.

The estimated TP C of the Shell gasifier with CO 2 

## capture is $3,9 81 /kW. Process contingency

represents 4.0 percent of the TP C

, and p roject contingency represents 14.1 percent. The COE, including CO 2 

## T&S costs of $ 9.8 /M Wh, is $ 162.4 /MWh

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



## 106 Exhibit 3

- 38 Case B1B total plant cost details

Case: B1B

– Shell IGCC w/ CO 2 Estimate Type: Conceptual Plant Size (MW,net): 497 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $4,425 $0 $2,133 $0 $6,558 $656 $0 $1,443 $8,656 $17

1.2 Coal Stackout & Reclaim $5,718 $0 $1,367 $0 $7,086 $709 $0 $1,559 $9,353 $19

1.3 Coal Conveyors & Yd Crush $5,316 $0 $1,353 $0 $6,669 $667 $0 $1,467 $8,803 $18

1.4 Other Coal Handling $1,391 $0 $313 $0 $1,704 $170 $0 $375 $2,249 $5

1.9 Coal & Sorbent Hnd. Foundations $0 $2,955 $7,723 $0 $10,677 $1,068 $0 $2,349 $14,094 $28

Subtotal $16,851 $2,955 $12,889 $0 $32,694 $3,269 $0 $7,193 $43,156 $87

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying $50,700 $3,058 $7,286 $0 $61,043 $6,104 $0 $13,430 $80,577 $162

2.2 Prepared Coal Storage & Feed $2,401 $577 $371 $0 $3,350 $335 $0 $737 $4,422 $9

2.3 Dry Coal Injection System $79,030 $911 $7,239 $0 $87,180 $8,718 $0 $19,180 $115,078 $232

2.4 Misc. Coal Prep & Feed $1,321 $965 $2,842 $0 $5,127 $513 $0 $1,128 $6,767 $14

2.9 Coal & Sorbent Feed Foundation $0 $4,844 $4,156 $0 $9,000 $900 $0 $1,980 $11,880 $24

Subtotal $133,452 $10,354 $21,894 $0 $165,700 $16,570 $0 $36,454 $218,724 $440

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $2,970 $5,126 $2,687 $0 $10,784 $1,078 $0 $2,372 $14,234 $29

3.2 Water Makeup & Pretreating $857 $89 $471 $0 $1,416 $142 $0 $467 $2,024 $4

3.3 Other Feedwater Subsystems $1,670 $552 $493 $0 $2,715 $271 $0 $597 $3,584 $7

3.4 Service Water Systems $501 $999 $3,443 $0 $4,942 $494 $0 $1,631 $7,068 $14

3.5 Other Boiler Plant Systems $2,699 $1,009 $2,483 $0 $6,191 $619 $0 $1,362 $8,172 $16

3.6 FO Supply Sys & Nat Gas $17,717 $675 $625 $0 $19,017 $1,902 $0 $4,184 $25,103 $51

3.7 Waste Treatment Equipment $1,159 $0 $718 $0 $1,877 $188 $0 $619 $2,683 $5

3.8 Misc. Power Plant Equipment $1,261 $168 $655 $0 $2,085 $208 $0 $688 $2,981 $6

Subtotal $28,834 $8,617 $11,575 $0 $49,026 $4,903 $0 $11,921 $65,849 $133

4 Gasifier & Accessories

4.1 Syngas Cooler Gasifier System $171,383 $0 $73,493 $0 $244,876 $24,488 $33,487 $46,617 $349,467 $704

4.2 Syngas Cooler w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU & Oxidant Compression $207,843 $0 w/equip. $0 $207,843 $20,784 $0 $22,863 $251,490 $506

4.4 LT Heat Recovery & FG Saturation $30,655 $0 $11,647 $0 $42,303 $4,230 $0 $9,307 $55,840 $112

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,694 $685 $0 $2,379 $238 $0 $523 $3,141 $6

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $9,672 $5,768 $0 $15,440 $1,544 $0 $4,246 $21,230 $43

Subtotal $409,881 $11,366 $91,593 $0 $512,841 $51,284 $33,487 $83,556 $681,168 $1,371

5 A Gas Cleanup & Piping

5A.1 Double Stage Selexol $162,818 $0 w/equip. $0 $162,818 $16,282 $32,564 $42,333 $253,996 $511

5A.2 Elemental Sulfur Plant $12,076 $2,354 $15,473 $0 $29,902 $2,990 $0 $6,579 $39,471 $79

5A.3 Mercury Removal $2,022 $0 $1,528 $0 $3,550 $355 $177 $816 $4,899 $10

5A.4 Shift Reactors $8,880 $0 $3,550 $0 $12,429 $1,243 $0 $2,734 $16,406 $33

5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 107 Case: B1B

– Shell IGCC w/ CO 2 Estimate Type: Conceptual Plant Size (MW,net): 497 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

5A.6 Blowback Gas Systems $2,562 $431 $241 $0 $3,234 $323 $0 $711 $4,269 $9

5A.7 Fuel Gas Piping $0 $1,043 $683 $0 $1,726 $173 $0 $380 $2,278 $5

5A.9 HGCU Foundations $0 $944 $636 $0 $1,581 $158 $0 $522 $2,261 $5

Subtotal $188,356 $4,773 $22,111 $0 $215,240 $21,524 $32,741 $54,075 $323,580 $651

5B CO 2 Compression

5B.2 CO 2 Compression & Drying $39,421 $5,913 $16,551 $0 $61,885 $6,188 $0 $13,615 $81,688 $164

Subtotal $39,421 $5,913 $16,551 $0 $61,885 $6,188 $0 $13,615 $81,688 $164

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $111,210 $0 $7,881 $0 $119,091 $11,909 $11,909 $14,291 $157,201 $316

6.9 Combustion Turbine Foundations $0 $923 $1,068 $0 $1,992 $199 $0 $657 $2,848 $6

Subtotal $111,210 $923 $8,950 $0 $121,083 $12,108 $11,909 $14,948 $160,049 $322

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $29,630 $0 $5,739 $0 $35,369 $3,537 $0 $3,891 $42,796 $86

7.3 Ductwork $0 $2,111 $1,480 $0 $3,591 $359 $0 $790 $4,740 $10

7.4 Stack $4,074 $0 $1,520 $0 $5,594 $559 $0 $615 $6,769 $14

7.9 HRSG, Duct & Stack Foundations $0 $776 $779 $0 $1,554 $155 $0 $513 $2,222 $4

Subtotal $33,704 $2,887 $9,517 $0 $46,108 $4,611 $0 $5,809 $56,527 $114

8 Steam Turbine Generator

8.1 Steam TG & Accessories $35,245 $0 $4,790 $0 $40,035 $4,003 $0 $4,404 $48,442 $98

8.2 Turbine Plant Auxiliaries $199 $0 $453 $0 $651 $65 $0 $72 $788 $2

8.3 Condenser & Auxiliaries $3,020 $0 $1,697 $0 $4,717 $472 $0 $519 $5,708 $11

8.4 Steam Piping $13,533 $0 $5,869 $0 $19,402 $1,940 $0 $5,335 $26,677 $54

8.9 TG Foundations $0 $937 $1,655 $0 $2,592 $259 $0 $855 $3,707 $7

Subtotal $51,997 $937 $14,463 $0 $67,397 $6,740 $0 $11,185 $85,322 $172

9 Cooling Water System

9.1 Cooling Towers $4,330 $0 $1,310 $0 $5,640 $564 $0 $931 $7,135 $14

9.2 Circulating Water Pumps $2,088 $0 $154 $0 $2,242 $224 $0 $370 $2,836 $6

9.3 Circ. Water System Auxiliaries $183 $0 $26 $0 $208 $21 $0 $34 $264 $1

9.4 Circ. Water Piping $0 $8,098 $1,962 $0 $10,060 $1,006 $0 $2,213 $13,280 $27

9.5 Make

- up Water System $475 $0 $653 $0 $1,128 $113 $0 $248 $1,489 $3

9.6 Component Cooling Water Sys $926 $1,107 $760 $0 $2,794 $279 $0 $615 $3,687 $7

9.9 Circ. Water System Foundations $0 $2,651 $4,711 $0 $7,362 $736 $0 $2,429 $10,527 $21

Subtotal $8,001 $11,857 $9,575 $0 $29,434 $2,943 $0 $6,840 $39,217 $79

10 Ash & Spent Sorbent Handling Systems

10.1 Slag Dewatering & Cooling $19,503 $0 $9,552 $0 $29,055 $2,905 $0 $3,196 $35,156 $71

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $658 $0 $711 $0 $1,368 $137 $0 $226 $1,731 $3

10.7 Ash Transport & Feed Equipment $905 $0 $211 $0 $1,117 $112 $0 $184 $1,413 $3

10.8 Misc. Ash Handling Equipment $1,362 $1,670 $495 $0 $3,527 $353 $0 $582 $4,462 $9

10.9 Ash/Spent Sorbent Foundation $0 $55 $73 $0 $128 $13 $0 $42 $183 $0

Subtotal $22,428 $1,725 $11,042 $0 $35,195 $3,519 $0 $4,230 $42,945 $86Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 108 Case: B1B

– Shell IGCC w/ CO 2 Estimate Type: Conceptual Plant Size (MW,net): 497 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

11 Accessory Electric Plant

11.1 Generator Equipment $1,096 $0 $1,067 $0 $2,162 $216 $0 $238 $2,616 $5

11.2 Station Service Equipment $5,293 $0 $487 $0 $5,780 $578 $0 $636 $6,994 $14

11.3 Switchgear & Motor Control $9,770 $0 $1,816 $0 $11,586 $1,159 $0 $1,912 $14,657 $30

11.4 Conduit & Cable Tray $0 $4,964 $15,302 $0 $20,266 $2,027 $0 $5,573 $27,866 $56

11.5 Wire & Cable $0 $9,571 $5,823 $0 $15,394 $1,539 $0 $4,233 $21,167 $43

11.6 Protective Equipment $0 $798 $2,963 $0 $3,761 $376 $0 $621 $4,758 $10

11.7 Standby Equipment $263 $0 $262 $0 $525 $53 $0 $87 $664 $1

11.8 Main Power Transformers $18,593 $0 $162 $0 $18,756 $1,876 $0 $3,095 $23,726 $48

11.9 Electrical Foundations $0 $170 $462 $0 $632 $63 $0 $209 $904 $2

Subtotal $35,016 $15,503 $28,345 $0 $78,864 $7,886 $0 $16,603 $103,353 $208

12 Instrumentation & Control

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,274 $0 $868 $0 $2,143 $214 $107 $370 $2,834 $6

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $293 $0 $192 $0 $484 $48 $24 $111 $669 $1

12.7 Computer & Accessories $6,798 $0 $222 $0 $7,020 $702 $351 $807 $8,880 $18

12.8 Instrument Wiring & Tubing $0 $2,617 $4,953 $0 $7,570 $757 $379 $2,176 $10,882 $22

12.9 Other I & C Equipment $4,544 $0 $2,251 $0 $6,796 $680 $340 $1,172 $8,987 $18

Subtotal $12,909 $2,617 $8,487 $0 $24,013 $2,401 $1,201 $4,637 $32,252 $65

13 Improvements to Site

13.1 Site Preparation $0 $118 $2,686 $0 $2,804 $280 $0 $925 $4,010 $8

13.2 Site Improvements $0 $2,101 $2,970 $0 $5,072 $507 $0 $1,674 $7,252 $15

13.3 Site Facilities $3,765 $0 $4,227 $0 $7,992 $799 $0 $2,637 $11,429 $23

Subtotal $3,765 $2,219 $9,883 $0 $15,868 $1,587 $0 $5,236 $22,691 $46

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $317 $179 $0 $496 $50 $0 $109 $655 $1

14.2 Steam Turbine Building $0 $2,481 $3,532 $0 $6,014 $601 $0 $992 $7,607 $15

14.3 Administration Building $0 $1,027 $745 $0 $1,772 $177 $0 $292 $2,242 $5

14.4 Circulation Water Pumphouse $0 $193 $102 $0 $295 $29 $0 $49 $373 $1

14.5 Water Treatment Buildings $0 $704 $686 $0 $1,391 $139 $0 $229 $1,759 $4

14.6 Machine Shop $0 $526 $360 $0 $885 $89 $0 $146 $1,120 $2

14.7 Warehouse $0 $849 $548 $0 $1,397 $140 $0 $230 $1,767 $4

14.8 Other Buildings & Structures $0 $508 $396 $0 $904 $90 $0 $199 $1,193 $2

14.9 Waste Treating Building & Str. $0 $1,137 $2,171 $0 $3,307 $331 $0 $728 $4,366 $9

Subtotal $0 $7,742 $8,718 $0 $16,460 $1,646 $0 $2,975 $21,081 $42

Total $1,095,825 $90,388 $285,594 $0 $1,471,807 $147,181 $79,338 $279,277 $1,977,603 $3,981Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 109 Exhibit 3

- 39 Case B1B owner’s costs

Description $ / 1,000 $/kW

Pre

- Production Costs

6 Months All Labor $15,919 $32

1 Month Maintenance Materials $3,587 $7

1 Month Non

- fuel Consumables $682 $1

1 Month Waste Disposal $434 $1

25% of 1 Months Fuel Cost at 100% CF $2,910 $6

2% of TPC $39,552 $80

Total $63,083 $127

Inventory Capital

60

- day supply of fuel and consumables at 100% CF $24,228 $49

0.5% of TPC (spare parts) $9,888 $20

Total $34,116 $69

Other Costs

Initial Cost for Catalyst and Chemicals $16,739 $34

Land $900 $2

Other Owner's Costs $296,640 $597

Financing Costs $53,395 $107

Total Overnight Costs (TOC) $2,442,476 $4,917

TASC Multiplier (IOU, high

- risk, 35 year) 1.140

Total As

- Spent Cost (TASC) $2,784,423 $5,605Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 110 Exhibit 3

- 40 Case B1B initial and annual operating and maintenance costs

Case: B1B

– Shell IGCC w/ CO 2 Cost Base: Jun 2011 Plant Size (MW,net): 497 Heat Rate

- net (Btu/kWh): 10,927 Capacity Factor (%): 80
Operating & Maintenance Labor
Operating Labor Operating Labor Requirements per Shift
Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 Operating Labor Burden: 30.00 % of base Operator: 10.0

Labor O

- H Charge Rate: 25.00 % of labor Foreman: 1.0
Lab Tech's, etc.: 3.0

Total: 16.0 Fixed Operating Costs

Annual Cost ($) ($/kW

- net)
Annual Operating Labor: $7,233,658 $14.562

Maintenance Labor: $18,236,067 $36.711 Administrative & Support Labor: $6,367,431 $12.818

Property Taxes and Insurance: $39,552,053 $79.623

Total: $71,389,208 $143.715
Variable Operating Costs ($) ($/ M Wh

- net)

Maintenance Material: $34,437,835 $9.89265

Consumables
Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill
Water (/1000 gallons): 0 4,070 $1.67 $0 $1,989,343 $0.57146 Makeup and Waste Water Treatment Chemicals (lbs): 0 24,247 $0.27 $0 $1,896,308 $0.54474

Carbon (Mercury Removal) (lb): 201,639 345 $5.50 $1,109,016 $554,508 $0.15929 Shift Catalyst (ft 3 ): 6,470 4.43 $771.99 $4,994,685 $998,937 $0.28696 Selexol Solution (gal): 289,068 92 $36.79 $10,635,172 $989,212 $0.28416

Claus Catalyst (ft 3 ): w/equip. 1.93 $203.15 $0 $114,583 $0.03292

Subtotal: $16,738,872 $6,542,891 $1.87952
Waste Disposal
Spent Mercury Catalyst (lb.): 0 345 $0.65 $0 $65,542 $0.01883 Flyash (ton): 0 0 $0.00 $0 $0 $0.00000

Slag (ton): 0 559 $25.11 $0 $4,099,990 $1.17777

Subtotal: $0 $4,165,532 $1.19660
By

- Products
Sulfur (tons): 0 140 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000 Variable Operating Costs Total: $16,738,872 $45,146,258 $12.96876

Fuel Cost
Illinois Number 6 (ton): 0 5,583 $68.54 $0 $111,739,739 $32.09848

Total: $0 $111,739,739 $32.09848



### Exhibit 3

- 41 Case B1 B COE breakdown

Component Value, $/M Wh Percentage
Capital 87.0 57%

Fixed 20.5 13%

Variable 13.0 8%

Fuel 32.1 21%

Total (Excluding T&S) 152.6 N/A

CO 2 

### T&S 9.8 6%
Total (Including T&S) 162.4 N/ACost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 111 

# 3.3 C B&I E

- Gas TM 

# IGCC Cases

This section contains an evaluation of plant designs for c ases B4A and B4B, which are based on

the C B&I E

- GasTM gasifier. Cases B4A and B4B are very similar in terms of process, equipment, scope and arrangement, except that Case B4B includes SGS reactors, CO 2 

## absorption/regeneration and compression/transport systems. There are no provisions for CO 2 

## removal in Case B4A.

The balance of this sectio n is organized in an analogous manner to Section 3.2 :

• Gasifier Background

• Process System Description for Case B4A

• Key Assumptions for Cases B4A and B4B

• Sparing Philosophy for Cases B4A and B4B

• Performance Results for Case B4A

• Equipment List for Case B4A

• Cost Estimates for Case B4A

• Process and System Description, Performance Results, Equipment List, and Cost

Estimate for Case B4B



# 3.3.1 Gasifier Background

As mentioned in Section 3.2.1 , the “Coal Gasification Guidebook: Status, Application, and

Techno logies” report published by EPRI provides a detailed history of the development of several types of gasifier technology, including the Shell gasifier, as well as gasifier capacity, distinguishing characteristics, and important coal characteristics. (46)

In Ja nuary of 2000, CB&I completed construction of an E

- GAS TM 

## demonstration facility, located at the Wabash River Generating Station in West Terre Haute, Indiana. It is still operational as a

baseload unit. (39)

The Wabash River uni t has a coal handling capacity of 1,678 tonnes/day (1,850 tons/day)

– on a moisture and ash

- free (MAF) basis

– for bituminous coal with a high sulfur content. The unit produces dry gas at a rate of 189,724 Nm 3 

## /hr (6.7 million scf/hr) with an energy conten t of about 1,950 GJ/hr (1,850 MMBtu/hr) (HHV). This size matches the CT, which is a GE 7FA. (46)

The E

- Gas TM 

## gasifier has significant operating experience with bituminous coal at full commercial scale via the Wabash plant. (46)

Compared to a single stage slurry

- fed gasifier, the E

- Gas TM 

## technology demonstrates superior efficiency and lower oxygen requirements. (46)

Notable characteristics of the E

- Gas TM 

## gasifier are t he relatively short refractory life and the high waste heat recovery rate, resulting from the high operating temperature. The E

- Gas TM 

## gasifier produces a syngas with a higher CH 4 

## content than other single

- stage slurry fed gasifiers, due to the use of quen ching in the second stage. However, in CO 2 

## capture cases the CH 4 

## passes through the SGS reactors without change, and is also not separated by the AGR thus limiting the amount of carbon that can be captured. (46)

Bituminous coa ls with low moisture content are desired for use with the E

- Gas TM 

## gasifier as it benefits the slurry concentration and lowers the oxygen requirement. As with all slagging gasifiers, low concentrations of ash with low to moderate ash fusion temperatures ar e preferred. (46)Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 112 

# 3.3.2 Process Description

In this section the overall E

- Gas TM 

## gasification process is described. The system description

follows the BFD in Exhibit 3

- 42 and stream numbers reference the same exhibit. The tables in

Exhibit 3

- 43 provide process data for th e numbered streams in the BFD.

3.3.2.1 Coal Grinding and Slurry Preparation

Coal receiving and handling is common to all cases and was covered in Section 3.1.1 . The

recei ving 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

conve yor 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 s lurry 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 concentr ation of 62

- 68 percent using bituminous coal

, and ConocoPhillips presented a paper showing the slurry concentration of Illinois No. 6 coal as 63 percent

. (49)

The coal grinding system is equipped with a dust suppression syste m 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 th e 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. P iping

is fabricated of HDPE.

3.3.2.2 Gasification

This plant utilizes two gasification trains to process a total of 5,007 tonnes/day (5,519 tpd ) of Illinois No. 6 coal. Each of the 2 x 50 percent gasifiers operate at maximum capacity. The E

Gas TM 

## two

- stage coal gasification technology features an oxygen

- blown, entrained

- flow, refractory

- lined gasifier with continuous slag removal. About 78 percent of the total slurry feed is fed to the first (or bottom) stage of the gasifier. The air separation p lant supplies 3,711 tonnes/day (4,090 tpd ) of 95 percent oxygen to the gasifiers (stream 5) and the Claus plant (stream 3). All oxygen for gasification is fed to this stage of the gasifier at a pressure of 4.2 MPa (615 psia). This stage is best described as a horizontal cylinder with two horizontally opposed burners. The highly exothermic gasification/oxidation reactions take place rapidly at temperatures of 1,316 to 1,427°C (2,400 to 2,600 ° F). The hot raw gas from the first stage enters the second (top ) stage, which is a vertical cylinder perpendicular to the first stage. The remaining 22 percent of coal slurry is injected into this hot raw gas. The endothermic gasification/devolatilization reaction in this stage reduces the gasifier exit temperature to about
1,038°C (1,900 ° F). Total slurry to both stages is shown as stream 7 in Exhibit 3

- 42

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



## 113 Exhibit 3

- 42 Case B4A block flow diagram, E

- GasTM IGCC without CO 2 

### c apture

Source: NETL G AS
T URBINE C OMBUSTOR S YNGAS
S CRUBBER G AS C OOLING
BFW H EATING
& K NOCKOUT COS

H YDROLYSIS

E LEVATED
P RESSURE

ASU E

- G AS TM

G ASIFIER S OUR
W ATER S TRIPPER M ERCURY
R EMOVAL MDEA C LAUS
P LANT

S YNGAS
R EHEAT

HRSG 2 X S TATE

- OF

- THE

A RT F

- C LASS
G AS T URBINES 1 A IR TO ASU

2 3

V ENT G AS 5 7

G ASIFIER
O XIDANT A S

- R ECEIVED
C OAL

S LAG 10 11 12 17 18

14

16

4

21 22

T URBINE C OOLING A IR 23 24 W ATER R ECYCLE TO
S LURRY P REPARATION

F LUE G AS S TACK G AS H YDROGENATION
R EACTOR AND G AS
C OOLER

19

T AIL G AS R ECYCLE TO
MDEA

N OTE : T AIL G AS B OOST
C OMPRESSOR M ODELED

, BUT

NOT SHOWN C LEAN G AS

N ITROGEN D ILUENT

A IR E XTRACTION S ULFUR
P RODUCT

S YNGAS N OTE : F LASH G AS B OOST
C OMPRESSOR M ODELED

, BUT NOT SHOWN N OTE : SYNGAS RECYCLE

COMPRESSOR MODELED

, BUT NOT SHOWN N OTE : ACID GAS BOOST

COMPRESSOR MODELED

, BUT NOT SHOWN

T AIL G AS

S YNGAS
C OOLING

, C YCLONES &

F ILTERS S YNGAS
H UMIDIFICATION

15 R ECYCLE TO

G ASIFIER

C LAUS
P LANT O XIDANT C LAUS
P LANT O XIDANT

S TEAM
T URBINE 25 Note : Block Flow Diagram is not intended to represent a complete

material balance

. Only major process streams and equipment are shown

. S LURRY
M IXER

8 9 20 13

T AIL G AS R ECYCLE
F ROM C LAUS P LANT

6 S TEAMCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 114 Exhibit 3

- 43 Case B4A stream table, E

- GasTM IGCC without capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V

- L Mole Fraction

Ar 0.0092 0.0241 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0078 0.0078 0.0096 0.0095 0.0098

CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0465 0.0465 0.0575 0.0555 0.0576

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3011 0.3011 0.3727 0.3597 0.3734

CO 2 0.0003 0.0083 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1556 0.1559 0.1929 0.2137 0.1931

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0003 0.0000 0.0000 0.0000 0.0000

H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2725 0.2725 0.3372 0.3299 0.3425

H 2 O 0.0099 0.2164 0.0000 0.0003 0.0000 1.0000 0.0000 0.9968 0.0000 0.1888 0.1885 0.0015 0.0015 0.0015

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0002 0.0000 0.0000 0.0000

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0072 0.0075 0.0092 0.0090 0.0000

N 2 0.7732 0.5456 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0000 0.0157 0.0157 0.0194 0.0213 0.0221

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0032 0.0000 0.0045 0.0045 0.0000 0.0000 0.0000

O 2 0.2074 0.2055 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 18,975 915 111 17,428 4,694 3,766 0 4,758 0 21,815 21,815 17,626 18,275 17,601

V

- L Flowrate (kg/hr) 547,573 24,798 3,567 489,025 151,055 67,847 0 85,706 0 459,698 459,698 384,238 408,328 380,348 Solids Flowrate (kg/hr) 0 0 0 0 0 0 208,633 0 21,295 0 0 0 0 0

Temperature (°C) 15 20 32 93 32 343 15 149 1,038 186 186 35 34 45 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.10 0.10 5.79 4.24 4.07 4.00 3.83 3.79 3.76 Steam Table Enthalpy (kJ/kg) A 30.23 36.92 26.67 92.52 26.67 3,063.97

--- 567.36

--- 673.89 673.68 39.55 36.82 55.08 AspenPlus Enthalpy (kJ/kg) B

- 97.58

- 2,404.24 4.13 63.38 4.13

- 12,907.38

- 2,116.95

- 15,363.86 1,005.43

- 6,602.13

- 6,602.13

- 5,592.59

- 5,753.40

- 5,625.00 Density (kg/m 3 ) 1.2 1.6 11.0 24.4 11.0 20.1

--- 862.4

--- 22.7 22.3 33.0 33.7 31.0

V

- L Molecular Weight 28.857 27.090 32.181 28.060 32.181 18.015

--- 18.012

--- 21.073 21.073 21.799 22.344 21.610

V

- L Flowrate (lb mole /hr) 41,834 2,018 244 38,422 10,348 8,303 0 10,490 0 48,093 48,093 38,859 40,289 38,803

V

- L Flowrate (lb/hr) 1,207,192 54,670 7,864 1,078,115 333,020 149,578 0 188,950 0 1,013,462 1,013,462 847,100 900,209 838,525 Solids Flowrate (lb/hr) 0 0 0 0 0 0 459,956 0 46,947 0 0 0 0 0

Temperature (°F) 59 69 90 199 90 650 59 300 1,900 367 367 95 94 112 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 740.0 14.7 840.0 615.0 590.0 580.0 555.0 550.0 545.0 Steam Table Enthalpy (Btu/lb) A 13.0 15.9 11.5 39.8 11.5 1,317.3

--- 243.9

--- 289.7 289.6 17.0 15.8 23.7 AspenPlus Enthalpy (Btu/lb) B

- 42.0

- 1,033.6 1.8 27.2 1.8

- 5,549.2

- 910.1

- 6,605.3 432.3

- 2,838.4

- 2,838.4

- 2,404.4

- 2,473.5

- 2,418.3 Density (lb/ft 3 ) 0.076 0.098 0.687 1.521 0.687 1.257

--- 53.837

--- 1.416 1.391 2.061 2.105 1.938

A 

### Steam table reference conditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atmCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 115 Exhibit 3

- 43 Case B4A stream table

, E

- GasTM IGCC without capture ( continued)

15 16 17 18 19 20 21 22 23 24 25

V

- L Mole Fraction

Ar 0.0085 0.0085 0.0000 0.0000 0.0041 0.0055 0.0092 0.0092 0.0087 0.0087 0.0000

CH 4 0.0500 0.0500 0.0002 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.3241 0.3241 0.0010 0.0000 0.0848 0.0061 0.0000 0.0000 0.0000 0.0000 0.0000

CO 2 0.1676 0.1676 0.7537 0.0000 0.4983 0.7790 0.0003 0.0003 0.0803 0.0803 0.0000

COS 0.0000 0.0000 0.0001 0.0000 0.0003 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 0.2973 0.2973 0.0009 0.0000 0.0209 0.1311 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 0.1333 0.1333 0.0000 0.0000 0.3350 0.0018 0.0099 0.0099 0.0860 0.0860 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 S 0.0000 0.0000 0.2443 0.0000 0.0014 0.0043 0.0000 0.0000 0.0000 0.0000 0.0000

N 2 0.0192 0.0192 0.0000 0.0000 0.0537 0.0723 0.7732 0.7732 0.7250 0.7250 0.0000

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.2074 0.1000 0.1000 0.0000

SO 2 0.0000 0.0000 0.0000 0.0000 0.0013 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 20,276 20,276 674 0 873 649 110,253 4,410 137,247 137,247 40,181

V

- L Flowrate (kg/hr) 428,547 428,547 27,980 0 28,108 24,090 3,181,557 127,262 3,971,867 3,971,867 723,870 Solids Flowrate (kg/hr) 0 0 0 5,215 0 0 0 0 0 0 0

Temperature (°C) 143 193 45 175 232 38 15 432 588 132 561 Pressure (MPa, abs) 3.21 3.17 3.76 0.41 0.41 5.51 0.10 1.62 0.10 0.10 12.51 Steam Table Enthalpy (kJ/kg) A 489.40 569.86

- 0.67

--- 731.47

- 6.63 30.23 463.79 783.86 272.30 3,500.61 AspenPlus Enthalpy (kJ/kg) B

- 6,348.13

- 6,267.67

- 7,288.11 140.10

- 8,672.98

- 8,318.28

- 97.58 335.98

- 1,186.76

- 1,698.31

- 12,469.70 Density (kg/m 3 ) 19.7 17.3 73.5 5,285.4 3.1 96.3 1.2 7.9 0.4 0.9 35.2

V

- L Molecular Weight 21.135 21.135 41.529

--- 32.209 37.141 28.857 28.857 28.940 28.940 18.015

V

- L Flowrate (lb mole /hr) 44,702 44,702 1,485 0 1,924 1,430 243,066 9,723 302,577 302,577 88,584

V

- L Flowrate (lb/hr) 944,784 944,784 61,685 0 61,967 53,109 7,014,133 280,565 8,756,467 8,756,467 1,595,860 Solids Flowrate (lb/hr) 0 0 0 11,497 0 0 0 0 0 0 0

Temperature (°F) 290 380 112 347 450 100 59 810 1,091 270 1,041 Pressure (psia) 465.0 460.0 545.0 59.3 58.9 799.5 14.7 234.9 15.2 15.2 1,814.7 Steam Table Enthalpy (Btu/lb) A 210.4 245.0

- 0.3

--- 314.5

- 2.8 13.0 199.4 337.0 117.1 1,505.0 AspenPlus Enthalpy (Btu/lb) B

- 2,729.2

- 2,694.6

- 3,133.3 60.2

- 3,728.7

- 3,576.2

- 42.0 144.4

- 510.2

- 730.1

- 5,361.0 Density (lb/ft 3 ) 1.230 1.081 4.586 329.954 0.195 6.012 0.076 0.495 0.026 0.056 2.194

A 

### Steam table reference conditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atmCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 116 The syngas produced by the E

- Gas TM 

## gasifier is higher in methane content than either the GEE or Shell gasifier. The two

- stage design allows for improved cold gas efficiency (CGE) and lower oxygen consumption, but the quenched second stage allows some CH 4 

## to remain. The syngas

CH 4 

## concent ration exiting the gasifier in Case B4A is 4.3 vol% (compared to 0.10 vol% in Case B5A [GEE] and 0.001 vol% in Case B1A [Shell]). The relatively high CH 4 

## concentration impacts carbon capture efficiency as discussed in Section 3.3. 8

.

3.3.2.3 Raw Gas Cooling/Particulate Removal

The raw syngas, less than 1,038°C (1,900 ° F), from the second stage of the gasifier is cooled to 316°C (600°F) in the waste heat recovery (SGC) unit, w hich consists of a fire

- tube boiler and convective superheating and economizing sectio ns. 554,830 kg/hr (1,223,171 lb/hr) of HP saturated steam is raised as a result of the raw gas cooling. Fire

- tube boilers cost markedly less than comparable duty water

- tube boilers. This is because of the large savings in high

- grade steel associated with containing the hot HP syngas in relatively small tubes.

The coal ash is converted to molten slag, which flows down through a tap hole. The molten slag is quenched in w ater and removed through a proprietary continuous

- pressure letdown/dewatering system (stream 9). Char is produced in the second gasifier stage and is captured and recycled to the hotter first stage to be gasified.

The cooled gas from the SGC is cleaned of remaining particulate via a cyclone collector followed by a ceramic candle filter. Recycled syngas is used as the pulse gas to clean the candle filters. The recovered fines are pneumatically returned to the first stage of the gasifier. The

combination of recycled char and recycled particulate results in high overall carbon conversion (99.2 percent used in this report ).

Following particulate removal, additional heat is removed from the syngas to raise saturated IP steam at 0.4 MPa (65 psia). In this m anner the syngas is cooled to 232°C (450°F) prior to the syngas scrubber.

3.3.2.4 Syngas Scrubber/Sour Water Stripper

Syngas exiting the second of the two low

- temperature heat exchangers passes to a syngas
scrubber where a water wash is used to remove chlorides, SO 2 

## , NH 3 

## , and particulate. The syngas exits the scrubber saturated at 169°C (337°F).

The sour water stripper removes NH 3 

## , SO 2 

## , and impurities from the scrubber and other waste streams. The stripper consists of a sour drum that accumulates sour water from the gas scrubber and condensate from SGCs. Sour water from the drum flows to the sour stripper, which consists of a packed column with a steam

- heated reboiler. Sour gas is stripped from the liquid and sent to the SRU. Remaining water is sent to wastewa ter treatment.

3.3.2.5 COS Hydrolysis, Mercury Removal and Acid Gas Removal

Syngas exiting the scrubber is reheated to 186°C (367°F) by using HP steam from the HRSG evaporator prior to entering a COS hydrolysis reactor (stream 10). About 99.5 percent of the

COS is converted to CO 2 

## and H 2 

## O (Section 3.1.5 ). The gas exiting the COS reactor (stream 11) passes through a series of heat exchangers and KO drums to lower the syngas temperature to 35°C (95°F) and to separate entrained water. The cooled syngas (stream 12) then passes through

a carbon bed to remove approximately 97 percent of the Hg (Section 3.1.4 ).Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 117 Cool, particulate

- free syngas (stream 13) enters the absorber unit at approximately 3.8 MPa (550 psia) and 34°C (94°F). In the absorber, H 2 

## S is preferentially removed from the fuel gas stream by contact with MDEA. The absorber colu mn is operated at 44°C (112°F) by refrigerating the lean MDEA solvent. The lower temperature is required to achieve an outlet H 2 

## S concentration of less than 30 ppmv in the sweet syngas. The stripper acid gas stream (stream 17), consisting of 24 percent H 2 

## S and 75 percent CO 2 

## , is sent to the Claus unit. The acid gas is combined with the sour water stripper off gas and introduced into the Claus plant burner section.

3.3.2.6 Claus Unit

Acid gas from the MDEA unit is preheated to 232°C (450°F). A portion of the aci d 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, H 2 

## S is catalytically oxidized to SO 2 

## at a furnace temperature of 1,316°C (2,400°F), which must be maintained in order to thermally decompose all of the NH 3 

## 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 H 2 

## S conversion of approximately 99.5 percent. The Claus Plant tail

gas is hydrogenated and recycled back to the gasifier (stream 20). In the furnace waste heat boiler, 13,866 kg/hr (30,568 lb/hr) of 3.0 MPa (430 psia) steam is generated. This steam is used to satisfy all Claus process preheating and reheating requirements a s well as to provide some

steam to the medium

- pressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) steam for the LP steam header and IP steam at 2.9 MPa (415 psig).

A flow rate of 5,215 kg/hr (11,497 lb/hr) of elemental sulfur (stream 1 8) is recovered from the fuel gas stream. This value represents an overall sulfur recovery efficiency of 99.7 percent.

3.3.2.7 Power Block

Clean syngas exiting the MDEA absorber (stream 14) is partially humidified (stream 15) because

there is not sufficient nitro gen from the ASU to provide the level of dilution required to reach the target syngas heating value. The moisturized syngas stream is reheated (stream 16), further diluted with nitrogen from the ASU (stream 4) an d enters the state

- of

- the

- art 2008 F

- class CT burner. The CT compressor provides combustion air to the burner and also 19 percent of the total ASU air requirement (stream 22). The exhaust gas exits the CT at 588°C (1,091°F) (stream 23) and enters the HRSG where additional heat is recovered until the flue gas exits the HRSG at 132°C (270°F) (stream 24) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced, commercially available steam turbine using a 12.4 MPa/561°C/561°C (1

, 800 psig/1

, 041°F/1

, 041°F) steam cycle.

3.3.2.8 Air Separation Unit

The elevated pressure ASU was described in Section 3.1.2 . In Case B4A, the ASU is designed to produce a nominal output of 3,711 t onnes/day (4,091 tpd ) of 95 mol% O 2 

## for use in the gasifier (stream 5) and Claus plant (stream 3). The plant is designed with two production trains. The air compressor is powered by an electric motor. Approximately 11,736 tonnes/day (12,937 tpd ) of nitr ogen is also recovered, compressed, and used as dilution in the CT combustor (stream 4). About 4 percent of the CT air is used to supply approximately 19 percent of the ASU air requirements (stream 22) in the non

- capture case

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



## 118 3.3.2.9 Balance of Plant

Balance of plant items were covered in Sections 3.1.9

, 3.1.10 , and 3.1.12

.


# 3.3.3 Key System Assumptions

System assumptions for cases B4A and B4B, E

- Gas TM 

## IGCC with and without CO 2 

## capture, are compiled in Exhibit 3

- 44

.

3.3.3.1 Balance of Plant

– Cases B4A and B4B

The balance of plant assumptions are common to all cases and were presented previously in

Exhibit 3

- 11

.


# 3.3.4 Sparing Philosophy

The sparing philosophy for cases B4A and B4B is provided below. Dual trains are used to accommodate the size of commercial CTs. There is no redundancy other than normal sparing of rotating equipment. The plant design consists of the following major subsystems:

• Two ASUs (2 x 50%)

• Two trains of slurry preparation and slurry pumps (2 x 50%)

• Two trains of gasification, including gasifier, SGC, cyclone, and candle filter (2 x 50%)

• Two trains of syngas clean

- up process (2 x 50%)

• Two trains of refrigerated MDEA AGR in Case B4A and two

- stage Selexol in Case B4B (2 x 50%)

• Two CO 2 

## compression systems (2 x 50%) in Case B4B

• One train of Claus

- based sulfur recovery (1 x 100%)

• Two C T/HRSG tandems (2 x 50%)

• One steam turbine (1 x 100%)Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 119 Exhibit 3

- 44 E

- Gas TM 

### IGCC plant study configuration matrix

Case B4A B4B

Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O 2 

### :Coal Ratio, kg O 2 

### /kg dry coal 0.81 0.88

Carbon Conversion, % 99.2 99.2

Syngas HHV at Gasifier Outlet, kJ/Nm 3 

### (Btu/scf) 8,319 (223) 7,021 (189)

Steam Cycle, MPa/°C/°C (psig/ ° F/ ° F) 12.4/561/561 (1

, 800/1

, 041/1

, 041) 12.4/534/534 (1

, 800/994/994)

Condenser Pressure, mm Hg (in Hg) 51 (2.0) 51 (2.0)

CT 2x State

- of

- the

- Art 2008 F

- Class (232 MW output each) 2x State

- of

- the

- Art 2008 F

- Class (232 MW output each)

Gasifier Technology C B&I E

- GasTM C B&I E

- GasTM

Oxidant 95 vol% Oxygen 95 vol% Oxygen

Coal Illinois No. 6 Illinois No. 6

Coal Slurry Solids Content, % 63 63

COS Hydrolysis Yes Occurs in SGS

SGS No Yes

H 2 

### S Separation Refrigerated MDEA Selexol 1 st 

### Stage

Sulfur Removal, % 99.7 99.9

Sulfur Recovery Claus Plant with Tail Gas Recycle

to Gasifier/ Elemental Sulfur Claus Plant with Tail Gas Recycle

to Gasifier/ Elemental Sulfur

Particulate Control Cyclone, Candle Filter, Scrubber,

and AGR Absorber Cyclone, Candle Filter, Scrubber,

and AGR Absorber

Mercury Control Carbon Bed Carbon Bed

NOx Control MNQC (LNB), N 2 

### Dilution and

Humidification MNQC (LNB), N 2 

### Dilution and

Humidification

CO 2 

### Separation N/A Selexol 2 nd 

### Stage

Overall Carbon Capture N/A 89.9 %

CO 2 

### Sequestration N/A Off

- site Saline Formation



# 3.3.5 Case B4A

- Performance Results

The plant produces a net output of 62 5 MWe at a net plant efficiency of 39. 7 percent (HHV basis).

Overall performance for the entire plant is summarized in Exhibit 3

- 45 ; Exhibit 3

- 46 provides a detailed breakdown of the auxiliary power requirements. The ASU accounts for approximately 76 percent of the total auxiliary load distributed between the main air compressor, oxygen compressor, nitrogen compressor, and ASU auxiliaries. The cooling water system, including the CWPs and cooling tower fan, accounts f or approximately 5 percent of the auxiliary load, and theCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 120 BFW pumps account for an additional 3.9 percent. All other individual auxiliary loads are less than 3.5 percent of the total.

Exhibit 3

- 45 Case B4A plant performance summary

Performance Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 0

Steam Turbine Power, MWe 274

Total Gross Power, MWe 738

Air Separation Unit Main Air Compressor, kWe 46,700

Oxygen Compressor, kWe 7,920

Nitrogen Compressors, kWe 29,910

CO 2 Compression, kWe 0

Acid Gas Removal, kWe 3,150

Balance of Plant, kWe 25,530

Total Auxiliaries, MWe 113

Net Power, MWe 625

HHV Net Plant Efficiency (%) 39.7 %

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,058 (8,585)

HHV Cold Gas Efficiency, % 82.0%

HHV Combustion Turbine Efficiency, % 37.2%

LHV Net Plant Efficiency (%) 41.2%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,737 (8,281)

LHV Cold Gas Efficiency, % 78.2%

LHV Combustion Turbine Efficiency, % 40.4%

Steam Turbine Cycle Efficiency, % 45.3%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 7,951 (7,536)

Condenser Duty, GJ/hr ( MM Btu/hr) 1,415 (1,341)

As

- Received Coal Feed, kg/hr (lb/hr) 208,633 (459,956)

HHV Thermal Input, kWt 1,572,575

LHV Thermal Input, kWt 1, 516,768

Raw Water Withdrawal, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.027 (7.0)

Raw Water Consumption, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.021 (5.6)

O 2 :Coal 0.684Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 121 Exhibit 3

- 46 Case B4A plant power summary

Power Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 0

Steam Turbine Power, MWe 274

Total Gross Power, MWe 738

Auxiliary Load Summary

Coal Handling, kWe 460

Coal Milling, kWe 2,150

Sour Water Recycle Slurry Pump, kWe 180

Slag Handling, kWe 1,100

Air Separation Unit Auxiliaries, kWe 1,000

Air Separation Unit Main Air Compressor, kWe 46,700

Oxygen Compressor, kWe 7,920

Nitrogen Compressors, kWe 29,910

Feedwater Pumps, kWe 4,410

Quench Water Pump, kWe 0

Syngas Recycle Compressor, kWe 810

CO 2 Compression, kWe 0

Scrubber Pumps, kWe 320

Acid Gas Removal, kWe 3,150

Combustion Turbine Auxiliaries, kWe 1,000

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 240

Circulating Water Pumps, kWe 3,890

Ground Water Pumps, kWe 400

Cooling Tower Fans, kWe 2,010

Claus Plant/TGTU Auxiliaries, kWe 250

Claus Plant TG Recycle Compressor, kWe 1,610

Miscellaneous Balance of Plant A 

### , kWe 3,000

Transformer Losses, kWe 2,600

Total Auxiliaries, MWe 113

Net Power, MWe 625

A 

### Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads



## 3.3.5.1 Environmental Performance

The environmental targets for emissions of Hg, NOx, SO 2 

## , and PM were presented in Section

2.3 . A summary of the plant air emissions for Case B4A is presented in Exhibit 3

- 47

. All HCl is

assumed to be removed and is, therefore, not reported.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 122 Exhibit 3

- 47 Case B4A air emissions

kg/GJ (lb/ MM Btu) Tonne/year (ton/year) A 

### kg/MWh (lb/MWh) B



### SO 2 

### 0.005 (0.012) 200 (220) 0.039 (0.0 85 )

NOx 0.026 (0.060) 1,017 (1,122) 0.197 (0.434)

Particulates 0.003 (0.0071) 121 (133) 0.023 (0.052)

Hg 1.77E

- 7 (4.13E

- 7) 0.007 (0.008) 1.36E

- 6 (3.00E

- 6)

CO 2 

### 86 (199) 3,398,347 (3,746,036) 657 (1,448)

CO 2 C



### - - 776 (1,711)

A 

### Calculations based on an 80 percent capacity factor

B 

### Emissions are based on gross power except where otherwise noted

C 

### CO 2 

### emissions based on net power instead of gross power



## The low level of SO 2 

## in the plant emissions is achieved by captur ing the sulfur in the gas by the refrigerated MDEA AGR process. The AGR process removes 99.7 percent of the sulfur compounds in the fuel gas down to a level of less than 30 ppmv. This results in a concentration

in the flue gas of less than 4 ppmv. The H 2 

## S

- 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 H 2 

## S and then recycled back to the gasifier, thereby eliminating the need for a tail ga s treatment unit.

NO x emissions are limited by the use of nitrogen dilution (primarily) and humidification (to a lesser extent) to 15 ppmvd (as NO 2 

## @ 15 percent O 2 

## ). 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 NO x 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 w ashing effect of the AGR absorber. The particulate emissions represent filterable particulate only.

Approximately 97 percent of the mercury is captured from the syngas by dual activated carbon

beds.

CO 2 

## emissions represent the uncontrolled discharge from the process.

The carbon balance for the plant is shown in Exhibit 3

- 48

. The carbon input to the plant consists

of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since

the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag and as CO 2 

## in the stack gas and ASU vent gas.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 123 Exhibit 3

- 48 Case B4A carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 132,992 (293,198) Stack Gas 132,344 (291,768)

Air (CO 2 ) 507 (1,118) CO 2 Product 0 (0)

ASU Vent 92 (202)

Slag 1,064 (2,346)

Total 133,499 (294,316) Total 133,499 (294,316)



## Exhibit 3

- 49 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfu r recovered in the Claus plant and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 3

- 49 Case B4A sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 5,229 (11,528) Stack Gas 14 (31)

CO 2 Product 0 (0)

Elemental Sulfur 5,215 (11,497)

Total 5,229 (11,528) Total 5,229 (11,528)



## Exhibit 3

- 50 shows the overall water balance for the plant. The water balance was explained in

Case B 1 A [ Shell ], but is also presented here for completeness.

Water demand represents the total amount of w ater required for a particular process. Some water is recovered within the process, primarily as syngas condensate, and is re

- used as internal recycle. The difference between demand and recycle is raw water withdrawal. Raw water

withdrawal is defined as the water removed from the ground or diverted from a surface

- water source for use in the plant and was assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water withdrawal can be represented by the water metered from

a raw wa ter source and used in the plant processes for any and all purposes, such as cooling tower makeup, BFW makeup, quench system makeup, and slag handling makeup. The difference between water withdrawal and process water discharge is defined as water

consumpt ion and can be represented by the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not returned to the water source from which it was withdrawn. Water consumption represents the net impact of the p lant process

on the water source balance.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 124 Exhibit 3

- 50 Case B4A water balance

Water Use Water

Demand Internal Recycle Raw Water

Withdrawal Process

Water Discharge Raw Water Consumption

m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm)

Slag Handling 0.46 (122) 0.46 (122)

– – – Slurry Water 1.43 (378) 0.99 (262) 0.44 (115)

– 0.44 (115)

Quench/Wash

– – – – – Humidifier 0.84 (222) 0.84 (222)

– – – SWS Blowdown

– – – 0.01 (3.84)

- 0.01 (

- 3.84) Condenser Makeup 1.34 (354)

– 1.34 (354)

– 1.34 (354)

BFW Makeup 0.21 (55)

– 0.21 (55)

– 0.21 (55)

Gasifier Steam 1.13 (299)

– 1.13 (299)

– 1.13 (299)

Shift Steam

– – – – – CT Steam Dilution

– – – – – Cooling Tower 15.16 (4,006) 0.35 (93) 14.81 (3,913) 3.41 (901) 11.40 (3,012)

BFW Blowdown

– 0.21 (55)

- 0.21 (

- 55)

– - 0.21 (

- 55)

SWS Blowdown

– 0.15 (38.44) - 0.15 (

- 38.44) – - 0.15 (

- 38.44)

Total 19.24 (5,082) 2.65 (700) 16.59 (4,382) 3.42 (905) 13.16 (3,477)



## 3.3.5.2 Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3

- 51 through

Exhibit 3

- 53 :

• Coal gasification and ASU

• Syngas cleanup, sulfur recovery, and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is provided in tabular form in Exhibit 3

- 54 . The power out is the combined CT and steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 3

- 45 ) is calculated by multiplying the power out by a combined generator efficiency of 98. 5 percent.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 125 Exhibit 3

- 51 Case B4A coal gasification and ASU heat and mass balance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 4 A

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 4 A

C O P G ASIFIER
ASU AND G ASIFICATION

DWG

. NO

. BB

- HMB

- CS

- B 4 A

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P AGES

1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated

Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU

Vent 1

, 207

, 192 W

59 T

15 P

13 H

333

, 020 W

90 T

125 P

11 H

333

, 020 W

223 T

740 P

38 H To Claus Plant

7

, 864 W

90 T

125 P

11 H

54

, 670 W

69 T

16 P

16 H

957

, 130 W

90 T

56 P

14 H 133

, 997 W

50 T

182 P

3 H 5 1

3 2

Candle Filter Slurry Mix

Tank

E

- Gas TM

Gasifier Milled Coal

Water

Slag Cyclones Fire

Tube

Boiler 459

, 956 W

59 T

15 P

188

, 950 W

300 T

840 P

244 H

46

, 947 W

1

, 900 T

615 P 1

, 241

, 587 W

600 T

605 P

422 H

9 648

, 906 W

162 T

840 P 1

, 241

, 587 W

600 T

605 P

422 H 1

, 241

, 587 W

1

, 834 T

615 P

969 H 144

, 018 W

159 T

800 P

37 H

1

, 241

, 587 W

450 T

600 P

361 H 1

, 206

, 115 W

100 T

190 P

18 H

7

8 Steam

149

, 578 W

650 T

740 P

1

, 309 H Syngas Recycle Compressor 144

, 018 W

105 T

600 P

19 H

From LP

Economizer To LP Evaporator 1

, 061

, 557 W

450 T

600 P

361 H 6 280

, 565 W

220 T

225 P

51 H

280

, 565 W

810 T

235 P

199 H 1

, 078

, 115 W

389 T

384 P

88 H

Air From GT Compressor N 2 to GT Combustor

From HP

Economizer 2 To HP Economizer 1

13

, 012 W

376 T

785 P

84 H Boost Compressor 22 1

, 078

, 115 W

199 T

384 P

40 H 4

To Superheater

From HP

Economizer 2

Post

Particulate

Cooler Raw Syngas

to Scrubber

Gross Plant Power : 738 MWe Auxiliary Load : 113 MWe

Net Plant Power : 625 MWe Net Plant Efficiency

, HHV : 39

. 7 %

Net Plant Heat Rate : 8

, 585 Btu / kWh Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

Water Steam

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical Flue Gas /

Combustion

Products

Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 126 Exhibit 3

- 52 Case B4A syngas cleanup heat and mass balance schematic

Source: NETL Mercury

Removal

Knock

Out

Drum

Raw Syngas Humidified Fuel Gas

Sour

Drum

To Coal Slurry and Slag Quench Claus Plant

Tail

Gas Furnace Catalytic

Reactor

Beds

Sulfur

Knock Out From

ASU

Syngas

Coolers

Sour Stripper Syngas

Scrubber

1

, 061

, 557 W

450 T

600 P

361 H 1

, 013

, 462 W

337 T

595 P

284 H 900

, 209 W

94 T

550 P

16 H 944

, 784 W

290 T

465 P

210 H

61

, 685 W

112 T

545 P

0 H 944

, 784 W

380 T

460 P

245 H

11

, 497 W 61

, 967 W

450 T

59 P

314 H

3

, 916 W

191 T

65 P

190 H 7

, 864 W

90 T

125 P

11 H

DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 4 A

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 4 A

C O P G ASIFIER
G AS CLEANUP SYSTEM

DWG

. NO

. BB

- HMB

- CS

- B 4 A

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P AGES

2 OF 3 14

18

12 16

20 847

, 100 W

95 T

555 P

17 H

8

, 858 W

119 T

57 P

45 H 3

53

, 109 W

100 T

800 P

- 3 H Humidification 15

838

, 525 W

112 T

545 P

24 H

7

, 864 W

450 T

125 P

92 H COS Hydrolysis 1

, 013

, 462 W

367 T

580 P

289 H 1

, 013

, 462 W

367 T

590 P

289 H

10 11

19 Clean

Gas Acid

Gas

13

AGR

- MDEA 17

Tail Gas Compressor Hydrogenation

And Tail Gas

Cooling 388

, 450 W

150 T

1

, 205 P

117 H

388

, 450 W

337 T

595 P

326 H From Fuel Gas

Preheater

To Fuel Gas

Preheater

249

, 929 W From Gland Steam

Condenser To Syngas Cooling

113 T

53

, 768 W

120 T

57 P

33 H To Preheater and

LP Evaporator

From Tail Gas

Cooler and LP

Economizer COS Hydrolysis

Preheater From HP

Economizer 2 To Superheater

To Water

Treatment Makeup Water

Reboiler From Syngas

Scrubber and HP

Economizer 2 To Syngas

Scrubber and HP

Economizer 1

Claus Oxygen

Preheater

To

Deaerator

From IP

BFW Fuel Gas

Preheater

Gross Plant Power : 738 MWe Auxiliary Load : 113 MWe

Net Plant Power : 625 MWe Net Plant Efficiency

, HHV : 39

. 7 %

Net Plant Heat Rate : 8

, 585 Btu / kWh Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas Sour Water Acid Gas

Tailgas Sour Gas

Sulfur Hydrogen

Water

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical Steam

Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 127 Exhibit 3

- 53 Case B4A combined cycle power generation heat and mass balance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 4 A

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 4 A

C O P G ASIFIER
P OWER B LOCK S YSTEM

DWG

. NO

. BB

- HMB

- CS

- B 4 A

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES
3 OF 3 Sour Gas

Sour Water

Water Steam

Flue Gas

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical

HP

Turbine IP

Turbine

Air Inlet

Filter Steam Seal Regulator

Gland

Steam

Condenser LP

Turbine Stack

Expander Compressor Generator

Generator

Condensate Pumps Steam Turbine

State

- of

- the

- art 2008

F

- Class Turbine

7

, 014

, 133 W

59 T

15 P

13 H 1

, 602

, 981 W

101 T

1 P

69 H 8

, 756

, 467 W

270 T

15 P

117 H

944

, 784 W

380 T

460 P

245 H 1

, 595

, 860 W

1

, 041 T

1

, 815 P

1

, 497 H 9

, 989 W

298 T

65 P

1

, 171 H

1

, 414

, 148 W

540 T

65 P

1

, 294 H

1

, 400 W

660 T

65 P

1

, 353 H

1

, 400 W

212 T

15 P

180 H

21 25

16 24

Hot Well Condenser 176

, 911 W

59 T

15 P

27 H 8

, 829 W

700 T

501 P

1

, 350 H

9

, 522 W

660 T

65 P

1

, 353 H 1

, 313 W

540 T

65 P

1

, 294 H Preheater Deaerator

Heater HP

Economizer

1 LP

Economizer HP

Economizer

2 HP Evaporator Superheater

/ Reheater

From Syngas Cooler

Blowdown

Flash Deaerator LP Evaporator From Claus

, Process Extractions

, and 250 PSIA Header

LP Extraction Spray

LP Blowdown Hot Reheat 8

, 756

, 467 W

1

, 091 T

15 P

337 H 23

To WWT

Condensate to Tail Gas Cooling Process

Extraction 46

, 042 W

276 T

615 P

244 H 1

, 872

, 987 W

274 T

45 P

242 H 24

, 616 W

274 T

79 P

242 H

9

, 365 W

274 T

79 P

242 H 1

, 623

, 815 W

279 T

2

, 251 P

247 H 306

, 059 W

298 T

65 P

266 H

235 T 305 T 585 T 636 T 117

, 894 W

351 T

2

, 251 P

319 H

117

, 894 W

585 T

2

, 001 P

585 H

27

, 956 W

585 T

2

, 001 P

585 H 1

, 223

, 167 W

585 T

2

, 001 P

585 H 636 T

215

, 192 W

298 T

65 P

1

, 171 H

1

, 437

, 747 W

701 T

501 P

1

, 350 H

22

280

, 565 W

810 T

235 P

199 H 195 T

Process Extraction 14

, 000 W

540 T

65 P

1

, 294 H

1

, 078

, 115 W

385 T

389 P

87 H Steam to Gasifier 149

, 578 W

690 T

745 P

1

, 328 H LP Extraction

Spray # 2

19

, 510 W

241 T

825 P

209 H

Water Makeup

1

, 000 W

1

, 041 T

1

, 815 P

1

, 497 H 1

, 000 W

212 T

15 P

180 H 781 W

1

, 041 T

1

, 815 P

1

, 497 H 30

, 828 W

500 T

250 P

1

, 255 H IP Extraction Steam

to 250 PSIA Header

LP Extraction Spray # 1

1

, 602

, 981 W

103 T

120 P

71 H 274 T To Post

Particulate and Syngas

Coolers From Post

Particulate and Syngas

Coolers From ASU and Fuel

Gas Preheater

To ASU and Fuel

Gas Preheater

To Fire Tube Boiler

and COS Preheater From Fire Tube Boiler and COS

Preheater

1

, 041 T To Claus

Nitrogen Diluent

Fuel Gas

Air Extraction

Ambient Air HP Pump LP Pump IP Pump

Gross Plant Power : 738 MWe Auxiliary Load : 113 MWe

Net Plant Power : 625 MWe Net Plant Efficiency

, HHV : 39

. 7 %

Net Plant Heat Rate : 8

, 585 Btu / kWh

Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 128 This page intentionally left blankCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 129 Exhibit 3

- 54 Ca se B4A overall energy balance (0°C [32°F] reference)

HHV Sensible +

Latent Power Total

Heat In (GJ/hr)

Coal 5,661 (5,366) 4.7 (4.5)

– 5,666 (5,370)

Air – 112.7 (106.8)

– 112.7 (106.8) Raw Water Makeup

– 62.4 (59.1)

– 62.4 (59.1) Auxiliary Power

– – 408 (386) 408 (386)

TOTAL 5,661 (5,366) 179.8 (170.4) 408 (386) 6,249 (5,923) Heat Out (GJ/hr)

ASU Vent

– 0.9 (0.9)

– 0.9 (0.9) Slag 34.9 (33.1) 23.9 (22.7)

– 58.8 (55.7)

Stack Gas – 1,082 (1,025)

– 1,082 (1,025)

Sulfur 48.3 (45.8) 0.6 (0.6)

– 48.9 (46.4) Motor Losses and Design

Allowances – – 52.3 (49.6) 52.3 (49.6)

Condenser – 1,415 (1,341)

– 1,415 (1,341)

Non

- Condenser Cooling Tower

Loads – 445 (421)

– 445 (421)

CO 2 – – – – Blowdown

– 32.2 (30.5)

– 32.2 (30.5)

CO 2 Capture Losses

– – – –

Ambient Losses A 

### – 157.4 (149.2)

– 157.4 (149.2)

Power – – 2,658 (2,519) 2,658 (2,519)

TOTAL 83.2 (78.9) 3,157 (2,992) 2,710 (2,568) 5,950 (5,639) Unaccounted Energy B



### – 299 (283)

– 299 (283)

A 

### Ambient losses include all losses to the environment through radiation, convection, etc. Sources of these losses include the combustor, reheater, superheater, and transformers.

B 

### By difference



# 3.3.6 Case B4A

- Major Equipment List

Major equipment items for the E

- Gas TM 

## gasifier with no CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the

cost estimates in Section 3.3.7 . In general, the design conditions include a 10 percent contingency for flows and heat duties

, and a 21 percent contingency for heads on pumps and

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



## 130 Case B4A

– Account 1: Coal Handling

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

5 Stacker/Reclaimer Traveling, linear 1,130 tonne/hr (1,250 tph) 1 0

6 Reclaim Hopper N/A 40 tonne (50 ton) 2 1

7 Feeder Vibratory 170 tonne/hr (190 tph) 2 1

8 Conveyor No. 3 Belt w/ tripper 340 tonne/hr (380 tph) 1 0

9 Coal Surge Bin w/ Vent Filter Dual outlet 170 tonne (190 ton) 2 0

10 Crusher Impactor reduction 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 2 0

11 Conveyor No. 4 Belt w/ tripper 340 tonne/hr (380 tph) 1 0

12 Conveyor No. 5 Belt w/ tripper 340 tonne/hr (380 tph) 1 0

13 Coal Silo w/ Vent Filter and
Slide Gates Field erected 760 tonne (840 ton) 3 0



## Case B4A

– Account 2: Coal Preparation and Feed

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 80 tonne/h (80 tph) 3 0

2 Conveyor No. 6 Belt w/ tripper 230 tonne/h (250 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 460 tonne (510 ton) 1 0

4 Weigh Feeder Belt 110 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 110 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank with Agitator Field erected 283,240 liters (74,820 gal) 2 0

7 Slurry Water Pumps Centrifugal 790 lpm (210 gpm) 2 1

8 Trommel Screen Coarse 160 tonne/h (180 tph) 2 0

9 Rod Mill Discharge Tank with Agitator Field erected 370,530 liters (97,880 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,100 lpm (800 gpm) 2 2

11 Slurry Storage Tank with Agitator Field erected 1,111,600 liters (293,600 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,200 lpm (1,600 gpm) 2 2

13 Slurry Product Pumps Positive displacement 3,100 lpm (800 gpm) 2 2



## Case B4A

– Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical,

outdoor 1,083,000 liters (286,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,710 lpm @ 90 m H 2 O (1,770 gpm @ 300 ft H 2 O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 479,000 kg/hr (1,055,000 lb/hr) 2 0

4 Intermediate

- Pressure Feedwater Pump Horizontal centrifugal, single stage 8,100 lpm @ 30 m H 2 O (2,140 gpm @ 90 ft H 2 O) 2 1

5 High

- Pressure Feedwater Pump No. 1 Barrel type, multi

stage, centrifugal HP water: 7,020 lpm @ 1,800 m H 2 O (1,860 gpm @ 6,100 ft H 2 O) 2 1

6 High

- Pressure Feedwater Pump No. 2 Barrel type, multi

stage, centrifugal IP water: 510 lpm @ 220 m

H 2 O (130 gpm @ 730 ft H 2 O) 2 1Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 131 Equipment

No. Description Type Design Condition Operating Qty. Spares

7 Auxiliary Boiler Shop fabricated, water

tube 18,000 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air Compressors Flooded Screw 28 m 3 

### / min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m 3 

### / min (1,000 scfm) 2 1

10 Closed Cycle Cooling Heat Exchangers Plate and frame 245 GJ/hr (232 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 87,700 lpm @ 20 m H 2 O (23,200 gpm @ 70 ft H 2 O) 2 1

12 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 110 m H 2 O (1,000 gpm @ 350 ft H 2 O) 1 1

13 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 80 m H 2 O (700 gpm @ 250 ft H 2 O) 1 1

14 Raw Water Pumps Stainless steel, single

suction 4,240 lpm @ 20 m H 2 O (1,120 gpm @ 60 ft H 2 O) 2 1

15 Ground Water Pumps Stainless steel, single

suction 2,830 lpm @ 270 m H 2 O (750 gpm @ 880 ft H 2 O) 3 1

16 Filtered Water Pumps Stainless steel, single

suction 1,640 lpm @ 50 m H 2 O (430 gpm @ 160 ft H 2 O) 2 1

17 Filtered Water Tank Vertical, cylindrical 787,000 liter (208,000 gal) 2 0

18 Makeup Water

Demineralizer Anion, cation, and

mixed bed 300 lpm (80 gpm) 2 0

19 Liquid Waste Treatment System N/A 10 years, 24

- hour storm 1 0



## Case B4A

– Account 4: Gasifier, ASU, and Accessories Including Low Temperature Heat Recovery and Fuel Gas Saturation

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized two

- stage, slurry

- feed entrained

bed 2,800 tonne/day, 4.2 MPa (3,000 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler Fire

- tube boiler 310,000 kg/hr (683,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 310,000 kg/hr (683,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with pulse

- jet cleaning metallic filters 2 0

5 Syngas Scrubber Including Sour Water Stripper Vertical upflow 265,000 kg/hr (584,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with

condensate drain 213,000 kg/hr (469,000 lb/hr) 8 0

7 Raw Gas Knockout

Drum Vertical with mist

eliminator 212,000 kg/hr, 35°C, 3.9 MPa (468,000 lb/hr, 95°F, 560 psia) 2 0

8 Saturation Water

Economizers Shell and tube 91 GJ/hr (86 MMBtu/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 236,000 kg/hr, 143°C, 3.3 MPa (520,000 lb/hr, 290°F, 480 psia) 2 0

10 Saturator Water Pump Centrifugal 2,100 lpm @ 13 m H 2 O (600 gpm @ 42 ft H 2 O) 2 2

11 Synthesis Gas

Reheater Shell and tube 209,000 kg/hr (461,000 lb/hr) 2 0

12 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 265,000 kg/hr (584,000 lb/hr)

syngas 2 0

13 ASU Main Air Compressor Centrifugal, multi

- stage 4,000 m 3 

### / min @ 1.3 MPa (146,000 scfm @ 190 psia) 2 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 132 Equipment

No. Description Type Design Condition Operating Qty. Spares

14 Cold Box Vendor design 2,000 tonne/day (2,200 tpd) of 95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi

- stage 1,000 m 3 

### / min (36,000 scfm)

Suction

- 1.0 MPa (130 psia) Discharge

- 5.1 MPa (740 psia) 2 0

16 Primary Nitrogen Compressor Centrifugal, multi

- stage 3,000 m 3 

### / min (119,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 2 0

17 Secondary Nitrogen Compressor Centrifugal, single

stage 470 m 3 

### / min (17,000 scfm)

Suction

- 1.3 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 2 0

18 Transport Nitrogen

Boost Compressor Centrifugal, single

stage 50 m 3 

### / min (2,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 5.4 MPa (790 psia) 2 0

19 Extraction Air Heat Exchanger Gas

- to

- gas, vendor design 70,000 kg/hr, 432°C, 1.6 MPa (154,000 lb/hr, 810°F, 235 psia) 2 0



## Case B4A

– Account 5: Syngas Cleanup

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber 1 Sulfated carbon bed 211,000 kg/hr (466,000 lb/hr)

, 35°C (95°F)

, 3.8 MPa (555 psia) 2 0

2 Mercury Adsorber 2 Sulfated carbon bed 211,000 kg/hr (466,000 lb/hr)

, 35°C (95°F)

, 3.8 MPa (550 psia) 2 0

3 Sulfur Plant Claus type 138 tonne/day (152 tpd) 1 0

4 COS Hydrolysis

Reactor Fixed bed, catalytic 253,000 kg/hr (557,000 lb/hr)

, 188°C (370°F)

, 4.1 MPa (590 psia) 2 0

5 Acid Gas Removal

Plant MDEA 225,000 kg/hr (495,000 lb/hr)

, 34°C (94°F)

, 3.8 MPa (550 psia) 2 0

6 Hydrogenation

Reactor Fixed bed, catalytic 31,000 kg/hr (68,000 lb/hr)

, 232°C (450°F)

, 0.4 MPa (58.9 psia) 1 0

7 Tail Gas Recycle Compressor Centrifugal 26,000 kg/hr (58,000 lb/hr) each 1 0



## Case B4A

– Account 6: Combustion Turbine and Auxiliaries

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Combustion Turbine State

- of

- the

- art

2008 F

- c lass 230 MW 2 0

2 Combustion Turbine

Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 2 0



## Case B4A

– Account 7: HRSG, Ducting, and Stack

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type

409SS liner 76 m (250 ft) high x 8.4 m (28 ft) diameter 1 0

2 Heat Recovery
Steam Generator Drum, multi

pressure with

economizer section and integral

deaerator Main steam

- 398,129 kg/hr,

12.4 MPa/561°C (877,723 lb/hr, 1,800 psig/1,041°F) 2 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 133 Case B4A

– Account 8: Steam Turbine Generator and Auxiliaries

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Steam

Turbine Commercially available

advanced steam turbine 289 MW
12.4 MPa/561°C/561°C (1,800 psig/ 1,041°F/1,041°F) 1 0

2 Steam

Turbine
Generator Hydrogen cooled, static

excitation 320 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 1 0

3 Surface

Condenser Single pass, divided waterbox including

vacuum pumps 1,560GJ/hr (1,480 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1 0

4 Steam Bypass One per HRSG 50% steam flow @ design steam

conditions 2 0



## Case B4A

– Account 9: Cooling Water System

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 391,000 lpm @ 30 m (103,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative, mechanical draft,

multi

- cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,180 GJ/hr (2,060 MMBtu/hr) heat duty 1 0



## Case B4A

– Account 10: Slag Recovery and Handling

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 223,000 liters (59,000 gal) 2 0

2 Slag Crusher Roll 12 tonne/hr (13 tph) 2 0

3 Slag Depressurizer Proprietary 12 tonne/hr (13 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 134,000 liters (36,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 61,000 liters (16,000 gal) 2 0

6 Slag Conveyor Drag chain 12 tonne/hr (13 tph) 2 0

7 Slag Separation Screen Vibrating 12 tonne/hr (13 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 12 tonne/hr (13 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 191,000 liters (50,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 50 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 2 2

11 Grey Water Storage Tank Field erected 61,000 liters (16,000 gal) 2 0

12 Grey Water Pumps Centrifugal 220 lpm @ 430 m H 2 O (60 gpm @ 1,420 ft H 2 O) 2 2

13 Slag Storage Bin Vertical, field erected 800 tonne (900 tons) 2 0

14 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 134 Case B4A

– Account 11: Accessory Electric Plant

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 CTG Transformer Oil

- filled 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 2 0

2 STG Transformer Oil

- filled 24 kV/345 kV, 290 MVA, 3

- ph, 60 Hz 1 0

3 High Voltage Auxiliary

Transformer Oil

- filled 345 kV/13.8 kV, 47 MVA, 3

- ph, 60 Hz 2 0

4 Medium Voltage Transformer Oil

- filled 24 kV/4.16 kV, 29 MVA, 3

- ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 4 MVA, 3

- ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency

shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 0



## Case B4A

– Account 12: Instrumentation and Control

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 DCS

- Main
Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 0



# 3.3.7 Case B4A

- Costs Estimating Results

The cost estimating methodology was described previously in Section 2.6

. Exhibit 3

- 55 shows a detailed breakdown of the capital costs ; Exhibit 3

- 56 shows the owner’s costs, TOC, and TASC ; Exhibit 3

- 57 shows the initial and annual O&M costs; and Exhibit 3

- 58 shows the COE

breakdown.

The estimated TP C of the E

- Gas TM 

## gasifier with no CO 2 

## capture is $ 2,372 /kW. Process contingency represents 2.6 percent of the TP C

, and project contingency is 13.6 percent. The

COE is $ 99.8 / M Wh.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 135 Exhibit 3

- 55 Case B4 A total plant cost details

Case: B4 A

– E

- Gas TM IGCC w/o CO 2 Estimate Type: Conceptual Plant Size (MW,net): 625 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $4,394 $0 $2,118 $0 $6,511 $651 $0 $1,433 $8,595 $14

1.2 Coal Stackout & Reclaim $5,678 $0 $1,358 $0 $7,035 $704 $0 $1,548 $9,287 $15

1.3 Coal Conveyors & Yd Crush $5,279 $0 $1,343 $0 $6,622 $662 $0 $1,457 $8,741 $14

1.4 Other Coal Handling $1,381 $0 $311 $0 $1,692 $169 $0 $372 $2,233 $4

1.9 Coal & Sorbent Hnd. Foundations $0 $2,934 $7,668 $0 $10,602 $1,060 $0 $2,332 $13,994 $22

Subtotal $16,731 $2,934 $12,797 $0 $32,462 $3,246 $0 $7,142 $42,850 $69

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying w/2.3 $0 w/2.3 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,872 $450 $290 $0 $2,612 $261 $0 $575 $3,447 $6

2.3 Slurry Prep & Feed $25,543 $0 $11,204 $0 $36,748 $3,675 $0 $8,084 $48,507 $78

2.4 Misc. Coal Prep & Feed $1,030 $752 $2,216 $0 $3,997 $400 $0 $879 $5,277 $8

2.9 Coal & Sorbent Feed Foundation $0 $3,777 $3,241 $0 $7,017 $702 $0 $1,544 $9,263 $15

Subtotal $28,445 $4,979 $16,950 $0 $50,374 $5,037 $0 $11,082 $66,494 $106

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $3,767 $6,501 $3,408 $0 $13,676 $1,368 $0 $3,009 $18,052 $29

3.2 Water Makeup & Pretreating $715 $74 $393 $0 $1,182 $118 $0 $390 $1,690 $3

3.3 Other Feedwater Subsystems $2,118 $700 $626 $0 $3,443 $344 $0 $757 $4,545 $7

3.4 Service Water Systems $418 $834 $2,874 $0 $4,125 $413 $0 $1,361 $5,899 $9

3.5 Other Boiler Plant Systems $2,253 $842 $2,072 $0 $5,167 $517 $0 $1,137 $6,821 $11

3.6 FO Supply Sys & Nat Gas $17,737 $713 $660 $0 $19,110 $1,911 $0 $4,204 $25,225 $40

3.7 Waste Treatment Equipment $967 $0 $599 $0 $1,566 $157 $0 $517 $2,240 $4

3.8 Misc. Power Plant Equipment $1,268 $169 $659 $0 $2,096 $210 $0 $692 $2,997 $5

Subtotal $29,243 $9,832 $11,290 $0 $50,365 $5,036 $0 $12,067 $67,468 $108

4 Gasifier & Accessories

4.1 Syngas Cooler Gasifier System $144,797 $0 $80,864 $0 $225,661 $22,566 $31,351 $42,853 $322,431 $516

4.2 Syngas Cooler w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU & Oxidant Compression $174,614 $0 w/equip. $0 $174,614 $17,461 $0 $19,208 $211,284 $338

4.4 LT Heat Recovery & FG Saturation $20,488 $0 $7,784 $0 $28,273 $2,827 $0 $6,220 $37,320 $60

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,778 $719 $0 $2,496 $250 $0 $549 $3,295 $5

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $9,517 $5,676 $0 $15,193 $1,519 $0 $4,178 $20,891 $33

Subtotal $339,900 $11,295 $95,043 $0 $446,238 $44,624 $31,351 $73,008 $595,220 $952

5A Gas Cleanup & Piping

5A.1 MDEA

- LT AGR System $42,958 $0 $36,202 $0 $79,161 $7,916 $0 $17,415 $104,492 $167

5A.2 Elemental Sulfur Plant $11,980 $2,335 $15,351 $0 $29,667 $2,967 $0 $6,527 $39,160 $63

5A.3 Mercury Removal $1,390 $0 $1,051 $0 $2,441 $244 $122 $562 $3,369 $5

5A.4 COS Hydrolysis $3,852 $0 $4,996 $0 $8,849 $885 $0 $1,947 $11,680 $19

5A.5 Particulate Removal w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 136 Case: B4 A

– E

- Gas TM IGCC w/o CO 2 Estimate Type: Conceptual Plant Size (MW,net): 625 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

5A.6 Blowback Gas Systems $601 $337 $188 $0 $1,127 $113 $0 $248 $1,487 $2

5A.7 Fuel Gas Piping $0 $984 $644 $0 $1,628 $163 $0 $358 $2,149 $3

5A.9 HGCU Foundations $0 $891 $600 $0 $1,491 $149 $0 $492 $2,132 $3

Subtotal $60,783 $4,547 $59,033 $0 $124,363 $12,436 $122 $27,548 $164,470 $263

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $104,200 $0 $7,506 $0 $111,706 $11,171 $5,585 $12,846 $141,308 $226

6.9 Combustion Turbine Foundations $0 $923 $1,068 $0 $1,992 $199 $0 $657 $2,848 $5

Subtotal $104,200 $923 $8,575 $0 $113,698 $11,370 $5,585 $13,504 $144,157 $231

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $31,180 $0 $6,038 $0 $37,218 $3,722 $0 $4,094 $45,034 $72

7.3 Ductwork $0 $2,084 $1,461 $0 $3,544 $354 $0 $780 $4,679 $7

7.4 Stack $4,021 $0 $1,500 $0 $5,522 $552 $0 $607 $6,681 $11

7.9 HRSG, Duct & Stack Foundations $0 $766 $768 $0 $1,534 $153 $0 $506 $2,194 $4

Subtotal $35,201 $2,849 $9,768 $0 $47,818 $4,782 $0 $5,987 $58,588 $94

8 Steam Turbine Generator

8.1 Steam TG & Accessories $38,955 $0 $5,943 $0 $44,898 $4,490 $0 $4,939 $54,326 $87

8.2 Turbine Plant Auxiliaries $242 $0 $551 $0 $793 $79 $0 $87 $960 $2

8.3 Condenser & Auxiliaries $3,140 $0 $1,774 $0 $4,914 $491 $0 $541 $5,946 $10

8.4 Steam Piping $16,507 $0 $7,158 $0 $23,665 $2,367 $0 $6,508 $32,540 $52

8.9 TG Foundations $0 $1,141 $2,015 $0 $3,156 $316 $0 $1,042 $4,513 $7

Subtotal $58,844 $1,141 $17,441 $0 $77,426 $7,743 $0 $13,116 $98,285 $157

9 Cooling Water System

9.1 Cooling Towers $3,980 $0 $1,210 $0 $5,190 $519 $0 $856 $6,565 $11

9.2 Circulating Water Pumps $1,923 $0 $137 $0 $2,060 $206 $0 $340 $2,605 $4

9.3 Circ. Water System Auxiliaries $170 $0 $24 $0 $194 $19 $0 $32 $246 $0

9.4 Circ. Water Piping $0 $7,546 $1,828 $0 $9,374 $937 $0 $2,062 $12,373 $20

9.5 Make

- up Water System $408 $0 $560 $0 $968 $97 $0 $213 $1,278 $2

9.6 Component Cooling Water Sys $863 $1,032 $708 $0 $2,603 $260 $0 $573 $3,436 $5

9.9 Circ. Water System Foundations $0 $2,470 $4,389 $0 $6,859 $686 $0 $2,264 $9,809 $16

Subtotal $7,343 $11,048 $8,857 $0 $27,248 $2,725 $0 $6,340 $36,313 $58

10 Ash & Spent Sorbent Handling Systems

10.1 Slag Dewatering & Cooling $20,022 $0 $9,806 $0 $29,828 $2,983 $0 $3,281 $36,092 $58

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $660 $0 $714 $0 $1,374 $137 $0 $227 $1,738 $3

10.7 Ash Transport & Feed Equipment $909 $0 $212 $0 $1,121 $112 $0 $185 $1,418 $2

10.8 Misc. Ash Handling Equipment $1,368 $1,676 $497 $0 $3,542 $354 $0 $584 $4,480 $7

10.9 Ash/Spent Sorbent Foundation $0 $55 $73 $0 $128 $13 $0 $42 $184 $0

Subtotal $22,959 $1,732 $11,302 $0 $35,994 $3,599 $0 $4,320 $43,913 $70

11 Accessory Electric Plant

11.1 Generator Equipment $1,156 $0 $1,126 $0 $2,282 $228 $0 $251 $2,761 $4

11.2 Station Service Equipment $4,391 $0 $404 $0 $4,795 $479 $0 $527 $5,802 $9Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 137 Case: B4 A

– E

- Gas TM IGCC w/o CO 2 Estimate Type: Conceptual Plant Size (MW,net): 625 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

11.3 Switchgear & Motor Control $8,105 $0 $1,506 $0 $9,611 $961 $0 $1,586 $12,158 $19

11.4 Conduit & Cable Tray $0 $4,118 $12,694 $0 $16,812 $1,681 $0 $4,623 $23,116 $37

11.5 Wire & Cable $0 $7,940 $4,831 $0 $12,770 $1,277 $0 $3,512 $17,559 $28

11.6 Protective Equipment $0 $798 $2,961 $0 $3,759 $376 $0 $620 $4,755 $8

11.7 Standby Equipment $275 $0 $274 $0 $548 $55 $0 $90 $694 $1

11.8 Main Power Transformers $17,611 $0 $173 $0 $17,785 $1,778 $0 $2,934 $22,497 $36

11.9 Electrical Foundations $0 $181 $493 $0 $674 $67 $0 $223 $964 $2

Subtotal $31,538 $13,036 $24,462 $0 $69,036 $6,904 $0 $14,367 $90,306 $144

12 Instrumentation & Control

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,186 $0 $808 $0 $1,994 $199 $100 $344 $2,637 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $273 $0 $178 $0 $451 $45 $23 $104 $622 $1

12.7 Computer & Accessories $6,326 $0 $207 $0 $6,533 $653 $327 $751 $8,264 $13

12.8 Instrument Wiring & Tubing $0 $2,435 $4,610 $0 $7,045 $705 $352 $2,025 $10,127 $16

12.9 Other I & C Equipment $4,229 $0 $2,095 $0 $6,324 $632 $316 $1,091 $8,364 $13

Subtotal $12,014 $2,435 $7,898 $0 $22,347 $2,235 $1,117 $4,315 $30,014 $48

13 Improvements to Site

13.1 Site Preparation $0 $118 $2,672 $0 $2,790 $279 $0 $921 $3,990 $6

13.2 Site Improvements $0 $2,090 $2,955 $0 $5,046 $505 $0 $1,665 $7,215 $12

13.3 Site Facilities $3,746 $0 $4,205 $0 $7,951 $795 $0 $2,624 $11,370 $18

Subtotal $3,746 $2,208 $9,833 $0 $15,787 $1,579 $0 $5,210 $22,575 $36

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $317 $179 $0 $496 $50 $0 $109 $655 $1

14.2 Steam Turbine Building $0 $2,917 $4,153 $0 $7,069 $707 $0 $1,166 $8,943 $14

14.3 Administration Building $0 $1,008 $731 $0 $1,740 $174 $0 $287 $2,201 $4

14.4 Circulation Water Pumphouse $0 $199 $105 $0 $304 $30 $0 $50 $384 $1

14.5 Water Treatment Buildings $0 $588 $573 $0 $1,161 $116 $0 $192 $1,468 $2

14.6 Machine Shop $0 $516 $353 $0 $869 $87 $0 $143 $1,099 $2

14.7 Warehouse $0 $833 $538 $0 $1,371 $137 $0 $226 $1,734 $3

14.8 Other Buildings & Structures $0 $499 $388 $0 $888 $89 $0 $195 $1,172 $2

14.9 Waste Treating Building & Str. $0 $1,116 $2,131 $0 $3,247 $325 $0 $714 $4,286 $7

Subtotal $0 $7,993 $9,151 $0 $17,144 $1,714 $0 $3,083 $21,942 $35

Total $750,947 $76,953 $302,400 $0 $1,130,300 $113,030 $38,175 $201,088 $1,482,594 $2,372Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 138 Exhibit 3

- 56 Case B4 A owner’s costs

Description $ / 1,000 $/kW

Pre

- Production Costs

6 Months All Labor $14,793 $24

1 Month Maintenance Materials $3,377 $5

1 Month Non

- fuel Consumables $399 $1

1 Month Waste Disposal $434 $1

25% of 1 Months Fuel Cost at 100% CF $2,877 $5

2% of TPC $29,652 $47

Total $51,532 $82

Inventory Capital

60

- day supply of fuel and consumables at 100% CF $23,491 $38

0.5% of TPC (spare parts) $7,413 $12

Total $30,904 $49

Other Costs

Initial Cost for Catalyst and Chemicals $2,218 $4

Land $900 $1

Other Owner's Costs $222,389 $356

Financing Costs $40,030 $64

Total Overnight Costs (TOC) $1,830,567 $2,929

TASC Multiplier (IOU, high

- risk, 35 year) 1.140

Total As

- Spent Cost (TASC) $2,086,847 $3,339Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 139 Exhibit 3

- 57 Case B 4 A initial and annual operating and maintenance costs

Case: B4 A

– E

- Gas TM IGCC w/o CO 2 Cost Base: Jun 2011 Plant Size (MW,net): 625 Heat Rate

- net (Btu/kWh): 8, 585 Capacity Factor (%): 80
Operating & Maintenance Labor
Operating Labor Operating Labor Requirements per Shift
Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 Operating Labor Burden: 30.00 % of base Operator: 9.0

Labor O

- H Charge Rate: 25.00 % of labor Foreman: 1.0
Lab Tech's, etc.: 3.0

Total: 15.0 Fixed Operating Costs

Annual Cost ($) ($/kW

- net)
Annual Operating Labor: $6,781,554 $10.851

Maintenance Labor: $16,886,458 $27.019 Administrative & Support Labor: $5,917,003 $9.467

Property Taxes and Insurance: $29,651,871 $47.444

Total: $59,236,887 $94.781
Variable Operating Costs ($) ($/M Wh

- net)

Maintenance Material: $32,421,135 $7.40220

Consumables
Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill
Water (/1000 gallons): 0 3,155 $1.67 $0 $1,542,265 $0.35212 Makeup and Waste Water Treatment Chemicals (lbs): 0 18,798 $0.27 $0 $1,470,139 $0.33565

Carbon (Mercury Removal) (lb): 115,489 198 $5.50 $635,191 $317,595 $0.07251 COS Catalyst (m 3 ): 327 0.22 $3,751.70 $1,227,074 $245,415 $0.05603 MDEA Solution (gal): 26,146 37 $13.62 $356,095 $146,323 $0.03341

Claus Catalyst (ft 3 ): w/equip. 1.91 $203.15 $0 $113,350 $0.02588

Subtotal: $2,218,360 $3,835,086 $0.87560
Waste Disposal
Spent Mercury Catalyst (lb.): 0 198 $0.65 $0 $37,539 $0.00857 Flyash (ton): 0 0 $0.00 $0 $0 $0.00000

Slag (ton): 0 563 $25.11 $0 $4,130,607 $0.94308

Subtotal: $0 $4,168,147 $0.95165
By

- Products
Sulfur (tons): 0 138 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000 Variable Operating Costs Total: $2,218,360 $40,424,368 $9.22946

Fuel Cost
Illinois Number 6 (ton): 0 5,519 $68.54 $0 $110,464,984 $25.22072

Total: $0 $110,464,984 $25.22072



### Exhibit 3

- 58 Case B 4A COE breakdown

Component Value, $/M Wh Percentage

Capital 51.8 52%

Fixed 13.5 14%

Variable 9.2 9%

Fuel 25.2 25%

Total (Excluding T&S) 99.8 N/A

CO 2 

### T&S 0.0 0%

Total (Including T&S) 99.8 N/ACost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 140 

# 3.3.8 Case B4B

- E

- GasTM IGCC Power Plant with CO 2 

# Capture

This case is configured to produce electric power with CO 2 

## capture. The plant configuration is the same as Case B4A, namely two gasifier trains, two state

- of

- the

- art 2008 F

- class turbines, two HRSGs, and one steam turbine. The gross power output from the plant is constrained by the capacity of the two CTs, and since the CO 2 

## capture and compression process increases the auxiliary load on t he plant, the net output is significantly reduced relative to Case B4A.

Th e process description for Case B4B is similar to Case B4A with several notable exceptions to

accommodate CO 2 

## capture. A BFD and stream tables for Case B4B are shown in Exhibit 3

- 59

and Exhibit 3

- 60 , respectively. Instead of re peating the entire process description, only

differences from Case B4A are reported here.

3.3.8.1 Coal Preparation and Feed Systems

No differences from Case B4A.

3.3.8.2 Gasification

The gasification process is the same as Case B4A with the exception that total coal feed to the two gasifiers is 5,271 tonnes/day (5,811 tpd ) (stream 8) and the ASU provides 4,234 tonnes/day (4,668 tpd ) of 95 mol% oxygen to the gasifier and Claus plant (streams 5 and 3).

3.3.8.3 Raw Gas Cooling /Particulate Removal

Raw gas cooling and particulate remov al are the same as Case B4A with the exception that approximately 418,710 kg/hr (923,082 lb/hr) of saturated steam at 13.8 MPa (2,000 psia) is generated in the SGC.

3.3.8.4 Syngas Scrubber/Sour Water Stripper

No differences from Case B4A.

3.3.8.5 Sour Gas Shift

The SGS process was described in Section 3.1.3 . In Case B4B steam (stream 11) is added to the syngas exiting the scrubber to adjust the H 2 

## O:CO molar ratio to approximately 2.25:1 prior to the

first S GS reactor. The hot syngas exiting the first stage of SGS is used to preheat a portion of the water used to humidify the clean syngas leaving the AGR. The final stage of SGS brings the

overall conversion of the CO to CO 2 

## to 98 .5 percent. The syngas exiting the final stage of SGS

still contains 1.2 vol% CH 4 

## , which is subsequently oxidized to CO 2 

## in the CT and results in a carbon capture of 89.9 percent. The warm syngas exiting the second stage of the SGS at 204°C (400°F) (stre am 12) is cooled to 201°C (393°F) by preheating the syngas entering the first SGS reactor. The SGS catalyst also serves to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. The syngas is further dehydrated and cooled to 35°C (95°F) in syngas coolers prior to the mercury removal beds.

3.3.8.6 Mercury Removal and Acid Gas Removal

Mercury removal is the same as in Case B4A.

The AGR process in Case B4B is a two

- stage Selexol process where H 2 

## S is removed in the first stage and CO 2 

## 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 CO 2



## - rich stream, an d an acid gas feed to the Claus plant. The acid gas (stream 19) contains 21.5 percent H 2 

## S and 70 percent CO 2Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 141 with the balance primarily H 2 

## . The CO 2



## - rich stream is discussed further in the CO 2 

## compression

section.

3.3.8.7 CO 2 

## Compression and Dehydration

CO 2 

## from the AGR process is flashed at three pressure levels to separate CO 2 

## and decrease H 2 

## losses to the CO 2 

## product pipeline. The HP CO 2 

## stream is flashed at 2.0 MPa (289.7 psia), compressed, and recycled back to the CO 2 

## absorber. The MP CO 2 

## stream is fl ashed at 1.0 MPa (149.7 psia). The LP CO 2 

## stream is flashed at 0.1 MPa (16.7 psia), compressed to 1.0 MPa (149.5 psia), and combined with the MP CO 2 

## stream. The combined stream is compressed from 1.0 MPa (149.5 psia) to a n SC condition at 15.3 MPa (2215 psia) using a multiple

- stage, intercooled compressor. During compression, the CO 2 

## stream is dehydrated to a dew point

of

- 40oC (

- 40°F) with triethylene glycol. The raw CO 2 

## stream from the Selexol process contains over 99 percent CO 2 

## . The CO 2 

## (stream 18) is transported to the plant fence line and is sequestration ready. CO 2 

## T&S costs were estimated using the methodology described in

Section 2.6

.

3.3.8.8 Claus Unit

The Cla us plant is the same as Case B4A with the following exceptions:

• 5,494 kg/hr (12,112 lb/hr) of sulfur (stream 20) are produced

• The waste heat boiler generates 12,679 kg/hr (27,953 lb/hr) of 3.0 MPa (430 psia) steam, which provides all of the Claus plant pro cess needs and provides some additional steam to the medium pressure steam header

3.3.8.9 Power Block

Clean syngas from the AGR plant is partially humidified to 4 percent because the nitrogen available from the ASU is insufficient to provide adequate dilution. Th e moisturized syngas is reheated (stream 17) to 193°C (380°F) using HP BFW, diluted with nitrogen (stream 4), and then enters the CT burner. There is no integration between the CT and the ASU in this case. The exhaust gas (stream 23) exits the CT at 562° C (1044°F) and enters the HRSG where additional

heat is recovered. The flue gas exits the HRSG at 132°C (270°F) (stream 24) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced commercially available steam turbine using a 12.4 MPa/534°C/534°C (1,800 psig/994°F/994°F) steam cycle.

3.3.8.10 Air Separation Unit (ASU)

The elevated pressure ASU is the same as in other cases and produces 4,234 tonnes/day (4,668 tpd ) of 95 mol% oxygen and 14,230 tonnes/day (15,686 tpd ) of n itrogen. There is no integration

between the ASU and the CT for the CO 2 

## capture case

.

3.3.8.11 Balance of Plant

Balance of plant items were covered in Sections 3.1.9

, 3.1.10

, and 3.1.12

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



## 142 Exhibit 3

- 59 Case B4B block flow diagram , E

- GasTM IGCC with CO 2 

### c apture

Source: NETL S YNGAS
S CRUBBER G AS C OOLING
BFW H EATING
& K NOCKOUT S HIFT
R EACTORS

E LEVATED
P RESSURE ASU E

- G AS TM

G ASIFIER S OUR
W ATER S TRIPPER M ERCURY
R EMOVAL D UAL S TAGE
S ELEXOL

U NIT

C LAUS
P LANT

HRSG

A MBIENT A IR H YDROGENATION
R EACTOR AND G AS
C OOLER

G AS
T URBINE C OMBUSTOR

T URBINE C OOLING A IR S YNGAS
C OOLING

, C YCLONES &

F ILTERS CO 2 C OMPRESSION

1 5 11 12 13

17 19

20 18

8 10

2 3 4

22 23 24 A IR TO ASU A S

- R ECEIVED
C OAL

S LAG S HIFT S TEAM

W ATER R ECYCLE

TO S LURRY
P REPARATION

N ITROGEN D ILUENT S YNGAS C LEAN G AS CO 2 S TREAMS CO 2 P RODUCT

S ULFUR

T AIL G AS
R ECYCLE TO

S ELEXOL N OTE : T AIL G AS B OOST
C OMPRESSOR MODELED

, BUT NOT SHOWN

F LUE G AS S TACK G AS

V ENT G AS 14

S YNGAS
R EHEATER N OTE : S YNGAS RECYCLE

MODELED

, BUT NOT SHOWN

G ASIFIER
O XIDANT R ECYCLE TO
G ASIFIER
O UTLET

2 X S TATE

- OF

- THE

A RT F

- C LASS
G AS T URBINES

C LAUS
P LANT O XIDANT C LAUS
P LANT O XIDANT

S TEAM
T URBINE 25

Note : Block Flow Diagram is not intended to represent a complete material balance

. Only major process streams and equipment are

shown

. S LURRY
M IXER

9 S LURRY
W ATER 21
T AIL G AS
R ECYCLE F ROM
C LAUS P LANT

6 7

S OUR W ATER S TEAM S YNGAS
H UMIDIFICATION 15

16Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 143 Exhibit 3

- 60 Case B4B stream table , E

- GasTM IGCC with c apture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V

- L Mole Fraction

Ar 0.0092 0.0209 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0054 0.0071 0.0071

CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0125 0.0164 0.0159

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0028 0.0037 0.0038

CO 2 0.0003 0.0071 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3103 0.4090 0.4172

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.4128 0.5441 0.5341

H 2 O 0.0099 0.1780 0.0000 0.0003 0.0000 1.0000 1.0000 0.0000 0.9963 0.0000 1.0000 0.2376 0.0015 0.0015

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0048 0.0063 0.0062

N 2 0.7732 0.6187 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0090 0.0119 0.0142

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0037 0.0000 0.0000 0.0046 0.0000 0.0000

O 2 0.2074 0.1754 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 26,685 1,231 145 19,704 5,338 1,287 4,969 0 5,009 0 9,357 37,866 26,948 27,761

V

- L Flowrate (kg/hr) 770,042 33,603 4,654 552,893 171,782 23,193 89,523 0 90,226 0 168,565 748,369 547,649 575,208

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 219,635 0 22,418 0 0 0 0

Temperature (°C) 15 19 32 93 32 154 343 15 171 1,038 288 204 35 34
Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.79 5.10 0.10 5.79 4.24 5.52 4.07 3.79 3.76 Steam Table Enthalpy (kJ/kg) A 30.23 36.49 26.67 92.50 26.67 646.63 3,062.93

--- 673.50

--- 2,917.15 874.40 40.91 39.04 AspenPlus Enthalpy (kJ/kg) B

- 97.58

- 1,964.01 4.13 63.47 4.13

- 15,372.01

- 12,907.38

- 2,116.95

- 15,251.86 1,005.43

- 13,053.16

- 8,872.57

- 8,024.73

- 8,027.16
Density (kg/m 3 ) 1.2 1.5 11.0 24.4 11.0 857.7 20.1

--- 836.0

--- 25.6 20.6 30.9 31.3

V

- L Molecular Weight 28.857 27.295 32.181 28.060 32.181 18.015 18.015

--- 18.012

--- 18.015 19.764 20.322 20.720

V

- L Flowrate (lb mole /hr) 58,830 2,714 319 43,440 11,768 2,838 10,955 0 11,044 0 20,628 83,479 59,411 61,202

V

- L Flowrate (lb/hr) 1,697,652 74,082 10,260 1,218,920 378,715 51,133 197,365 0 198,914 0 371,622 1,649,872 1,207,359 1,268,117
Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 484,212 0 49,422 0 0 0 0

Temperature (°F) 59 67 90 199 90 310 650 59 340 1,900 550 400 95 94
Pressure (psia) 14.7 16.4 125.0 384.0 125.0 840.0 740.0 14.7 840.0 615.0 800.0 590.0 550.0 545.0 Steam Table Enthalpy (Btu/lb) A 13.0 15.7 11.5 39.8 11.5 278.0 1,316.8

--- 289.6

--- 1,254.1 375.9 17.6 16.8 AspenPlus Enthalpy (Btu/lb) B

- 42.0

- 844.4 1.8 27.3 1.8

- 6,608.8

- 5,549.2

- 910.1

- 6,557.1 432.3

- 5,611.9

- 3,814.5

- 3,450.0

- 3,451.1
Density (lb/ft 3 ) 0.076 0.095 0.687 1.521 0.687 53.543 1.257

--- 52.192

--- 1.597 1.285 1.928 1.953

A 

### Steam table reference conditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atmCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 144 Exhibit 3

- 60 Case B4B stream table , E

- GasTM IGCC with c apture ( c ontinued)

15 16 17 18 19 20 21 22 23 24 25

V

- L Mole Fraction

Ar 0.0119 0.0114 0.0114 0.0002 0.0011 0.0000 0.0068 0.0092 0.0090 0.0090 0.0000

CH 4 0.0262 0.0251 0.0251 0.0008 0.0045 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0063 0.0060 0.0060 0.0001 0.0007 0.0000 0.0076 0.0000 0.0000 0.0000 0.0000

CO 2 0.0352 0.0338 0.0338 0.9945 0.7021 0.0000 0.6907 0.0003 0.0082 0.0082 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 0.8964 0.8588 0.8588 0.0044 0.0591 0.0000 0.2007 0.0000 0.0000 0.0000 0.0000

H 2 O 0.0001 0.0421 0.0421 0.0000 0.0162 0.0000 0.0017 0.0099 0.1246 0.1246 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 S 0.0000 0.0000 0.0000 0.0000 0.2153 0.0000 0.0026 0.0000 0.0000 0.0000 0.0000

N 2 0.0239 0.0229 0.0229 0.0001 0.0010 0.0000 0.0901 0.7732 0.7529 0.7529 0.0000

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1052 0.1052 0.0000

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 16,435 17,155 17,155 10,499 800 0 812 110,253 139,694 139,694 34,515

V

- L Flowrate (kg/hr) 83,813 96,780 96,780 459,855 31,069 0 27,560 3,181,557 3,831,230 3,831,230 621,792 Solids Flowrate (kg/hr) 0 0 0 0 0 5,494 0 0 0 0 0

Temperature (°C) 34 108 193 51 48 176 38 15 562 132 534 Pressure (MPa, abs) 3.76 3.21 3.17 15.27 0.16 0.12 5.51 0.10 0.10 0.10 12.51 Steam Table Enthalpy (kJ/kg) A 196.11 903.06 1,360.50

- 162.35 62.13

--- 1.77 30.23 839.77 348.19 3,432.70 AspenPlus Enthalpy (kJ/kg) B

- 3,190.25

- 4,169.46

- 3,712.02

- 9,119.38

- 7,323.59 140.70

- 8,075.42

- 97.58

- 608.99

- 1,100.57

- 12,537.61 Density (kg/m 3 ) 7.4 5.6 4.6 641.8 2.4 5,283.7 83.6 1.2 0.4 0.9 36.7

V

- L Molecular Weight 5.100 5.642 5.642 43.800 38.814

--- 33.925 28.857 27.426 27.426 18.015

V

- L Flowrate (lb mole /hr) 36,233 37,820 37,820 23,146 1,765 0 1,791 243,066 307,972 307,972 76,092

V

- L Flowrate (lb/hr) 184,776 213,363 213,363 1,013,808 68,496 0 60,759 7,014,133 8,446,417 8,446,417 1,370,817 Solids Flowrate (lb/hr) 0 0 0 0 0 12,112 0 0 0 0 0

Temperature (°F) 94 227 380 124 119 349 100 59 1,044 270 994 Pressure (psia) 545.0 465.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Steam Table Enthalpy (Btu/lb) A 84.3 388.2 584.9

- 69.8 26.7

--- 0.8 13.0 361.0 149.7 1,475.8 AspenPlus Enthalpy (Btu/lb) B

- 1,371.6

- 1,792.5

- 1,595.9

- 3,920.6

- 3,148.6 60.5

- 3,471.8

- 42.0

- 261.8

- 473.2

- 5,390.2 Density (lb/ft 3 ) 0.461 0.352 0.285 40.067 0.149 329.851 5.220 0.076 0.026 0.053 2.293

A 

### Steam table reference conditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atmCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 145 

# 3.3.9 Case B4B

- Performance Results

The Case B4B modeling assumptions were presented previously in Section 3.3.3

. The plant produces a net output of 51 3 MWe at a net plant efficiency of 31.0 percent (HHV basis). Overall performance for the entire plant is summarized in Exhibit 3

- 6 1 ; Exhibit 3

- 62 provides a detailed breakdown of the auxiliary power requirements. The ASU account s for nearly 58 percent of the auxiliary load between the main air compressor, nitrogen compressor, oxygen compressor, and ASU auxiliaries. The two

- stage Selexol process and CO 2 

## compression account for an additional 27 percent of the auxiliary power load. The BFW pumps and cooling water system (CWPs and cooling tower fan) compose nearly 6 percent of the load, leaving 9 percent of the auxiliary load for all other systems.

Exhibit 3

- 61 Case B4B plant performance summary

Performance Summary

Combustion Turbine Power, MWe 464
Sweet Gas Expander Power, MWe 0

Steam Turbine Power, MWe 240

Total Gross Power, MWe 704
Air Separation Unit Main Air Compressor, kWe 65,670
Oxygen Compressor, kWe 9,010
Nitrogen Compressors, kWe 35,340

CO 2 Compression, kWe 31,380

Acid Gas Removal, kWe 19,900

Balance of Plant, kWe 28,950

Total Auxiliaries, MWe 190

Net Power, MWe 513
HHV Net Plant Efficiency (%) 31.0%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,607 (11,002)
HHV Cold Gas Efficiency, % 81.0%

HHV Combustion Turbine Efficiency, % 36.1%
LHV Net Plant Efficiency (%) 32.2%
LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,195 (10,611)
LHV Cold Gas Efficiency, % 76.9%

LHV Combustion Turbine Efficiency, % 42.4%
Steam Turbine Cycle Efficiency, % 41.5%
Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 8,668 (8,216)
Condenser Duty, GJ/hr ( MM Btu/hr) 1,408 (1,334)

As

- Received Coal Feed, kg/hr (lb/hr) 219,635 (484,212)

HHV Thermal Input, kWt 1,655,503
LHV Thermal Input, kWt 1,596,753
Raw Water Withdrawal, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.042 (11.2)
Raw Water Consumption, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.034 (9.1)

O 2 :Coal 0.739Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 146 Exhibit 3

- 62 Case B4B plant power summary

Power Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 0

Steam Turbine Power, MWe 240

Total Gross Power, MWe 704

Auxiliary Load Summary

Coal Handling, kWe 470

Coal Milling, kWe 2,260

Sour Water Recycle Slurry Pump, kWe 200

Slag Handling, kWe 1,160

Air Separation Unit Auxiliaries, kWe 1,000

Air Separation Unit Main Air Compressor, kWe 65,670

Oxygen Compressor, kWe 9,010

Nitrogen Compressors, kWe 35,340

Feedwater Pumps, kWe 4,160

Quench Water Pump, kWe 0

Syngas Recycle Compressor, kWe 520

CO 2 Compression, kWe 31,380

Scrubber Pumps, kWe 400

Acid Gas Removal, kWe 19,900

Combustion Turbine Auxiliaries, kWe 1,000

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 310

Circulating Water Pumps, kWe 4,700

Ground Water Pumps, kWe 520

Cooling Tower Fans, kWe 2,430

Claus Plant/TGTU Auxiliaries, kWe 250

Claus Plant TG Recycle Compressor, kWe 3,700

Miscellaneous Balance of Plant A 

### , kWe 3,000

Transformer Losses, kWe 2,770

Total Auxiliaries, MWe 190

Net Power, MWe 513

A 

### Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads



## 3.3.9.1 Environmental Performance

The environmental targets for emissions of Hg, NO x , SO 2 

## , CO 2 

## , and PM were presented in

Section 2.3 . A summary of the plant air emissions for Case B4B is presented in Exhibit 3

- 63

. All HCl is assumed to be removed and is, therefore

, not reported.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 147 Exhibit 3

- 63 Case B4B air emissions

kg/GJ (lb/ MM Btu) Tonne/year (ton/year) A 

### kg/MWh (lb/MWh) B



### SO 2 

### 0.001 (0.002) 39 (43) 0.008 (0.017 )

NOx 0.021 (0.049) 885 (976) 0.180 (0.396)

Particulates 0.003 (0.0071) 127 (141) 0.026 (0.057)

Hg 1.61E

- 7 (3.74E

- 7) 0.007 (0.007) 1.36E

- 6 (3.00E

- 6)

CO 2 

### 8 ( 20 ) 354,267 (390,512) 72 (158)

CO 2 C



### - - 98 (217)

A 

### Calculations based on an 80 percent capacity factor

B 

### Emissions are based on gross power except where otherwise noted

C 

### CO 2 

### emissions based on net power instead of gross power



## The low level of SO 2 

## emissions is achieved by captur ing the sulfur in the gas by the two

- stage Selexol AGR process. The CO 2 

## ca pture target results in the sulfur compounds being removed to a greater extent than required in the environmental targets of Section 2.3 . The clean syngas exiting the AGR process has a sulfur concentration of approximately 5 ppmv. This results in a

concentration in the flue gas of less than 1 ppmv. The H 2 

## S

- rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus pla nt tail gas is hydrogenated to convert all sulfur species to H 2 

## S, and then recycled back to the Selexol, thereby eliminating the need for a tail gas treatment unit.

NO x emissions are limited by the use of humidification and nitrogen dilution to 15 ppmvd (N O 2 

## @ 15 percent O 2 

## ). 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

NO x levels as well.

Particulate discharge to the atmosphere is lim ited to extremely low values by the use of a cyclone and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only.

Approximately 97 percent of the m ercury is captured from the syngas by dual activated carbon

beds.

Ninety five percent of the CO 2 

## from the syngas is captured in the AGR system and compressed for sequestration. Because not all CO is converted to CO 2 

## in the shift reactors, the overall carbon removal is 89.9 percent.

The carbon balance for the plant is shown in Exhibit 3

- 64

. The carbon input to the plant consists

of carbon in the air in a ddition to carbon in the coal. Carbon leaves the plant as unburned carbon in the slag and as CO 2 

## in the stack gas, ASU vent gas
, and the captured CO 2 

## product. The carbon capture efficiency is defined as one minus the amount of carbon in the stack gas relative to the total carbon in less carbon contained in the slag , represented by the following fraction:

CCCCCCCCCC SS
( TT TT CCCCCCCCCC )

− ( CCCCCCCCCC SS SS ) = � 1

− � 30

, 416

309

, 844

− 2

, 469 �

∗ � 100 = 89

. 9%Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 148 The high methane content of the syngas, relative to the GEE and Shell cases, prevented reaching the nominal 90 percent carbon capture. In order to achieve 90 percent capture, the two

- stage
Selexol CO 2 

## removal efficiency was increased from 92 to 95 percent.

Exhibit 3

- 64 Case B4B carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 140,006 (308,659) Stack Gas 13,796 (30,416)

Air (CO 2 ) 537 (1,185) CO 2 Product 125,522 (276,728)

ASU Vent 105 (231)

Slag 1,120 (2,469)

140,543 (309,844) Total 140,543 (309,844)



## Exhibit 3

- 65 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the stack ga s, and sulfur in the CO 2 

## product. Sulfur in the slag is considered to be negligible.

Exhibit 3

- 65 Case B4B sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 5,505 (12,136) Stack Gas 3 (6)

CO 2 Product 8 (18)

Elemental Sulfur 5,494 (12,112)

Total 5,505 (12,136) Total 5,505 (12,136)



## Exhibit 3

- 66 shows the overall water balance for the plant. The exhibit is presented in an

identical manner for cases B1A through B4A.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 149 Exhibit 3

- 66 Case B4B water balance

Water Use Water

Demand Internal Recycle Raw Water

Withdrawal Process

Water Discharge Raw Water Consumption

m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm)

Slag Handling 0.49 (128) 0.49 (128)

– – – Slurry Water 1.51 (398) 1.51 (398)

– – –
Quench/Wash

– 0.00 ()

– – –

Humidifier 0.23 (61) 0.23 (61)

– – –

SWS Blowdown

– – – 0.03 (6.78)

- 0.03 (

- 6.78)

Condenser Makeup 4.52 (1,193)

– 4.52 (1,193)

– 4.52 (1,193)

BFW Makeup 0.21 (55)

– 0.21 (55)

– 0.21 (55)

Gasifier Steam 1.49 (395)

– 1.49 (395)

– 1.49 (395)

Shift Steam 2.81 (743)

– 2.81 (743)

– 2.81 (743)

CT Steam Dilution

– – – – – Cooling Tower 18.32 (4,839) 1.04 (274) 17.28 (4,565) 4.12 (1,088) 13.16 (3,476)

BFW Blowdown

– 0.21 (55)

- 0.21 (

- 55)

– - 0.21 (

- 55)

SWS Blowdown

– 0.26 (67.78) - 0.26 (

- 67.78) – - 0.26 (

- 67.78)

Total 25.05 (6,618) 3.26 (861) 21.79 (5,757) 4.14 (1,095) 17.65 (4,662)



## 3.3.9.2 Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3

- 67 through

Exhibit 3

- 69 :

• Coal gasification and ASU

• Syngas cleanup including sulfur recovery and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is provided in tabular form in Exhibit 3

- 70 . The power out is the combined CT and steam turbine power prior to generator losses. The power at the generator terminals (show n in Exhibit 3

- 61 ) is calculated by multiplying the power out by a combined generator efficiency of 98. 5 percent.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 150 Exhibit 3

- 67 Case B4B coal gasification and ASU heat and mass balance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 4 B

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 4 B

C O P G ASIFIER
ASU AND G ASIFICATION

DWG

. NO

. BB

- HMB

- CS

- B 4 B

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P AGES

1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated

Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU

Vent 1

, 697

, 652 W

59 T

15 P

13 H

378

, 715 W

90 T

125 P

11 H

378

, 715 W

223 T

740 P

38 H To Claus Plant

10

, 260 W

90 T

125 P

11 H

74

, 082 W

67 T

16 P

16 H

1

, 080

, 178 W

90 T

56 P

14 H 152

, 901 W

50 T

182 P

3 H 5 1

3 2

457

, 753 W

385 T

469 P

87 H

Candle Filter Slurry Mix

Tank

E

- Gas TM

Gasifier

Slag Cyclones Syngas Recycle Fire

Tube

Boiler

484

, 212 W

59 T

15 P

198

, 914 W

340 T

840 P

290 H

49

, 422 W

1

, 900 T

615 P 1

, 355

, 003 W

600 T

605 P

486 H 761

, 167 W

385 T

384 P

87 H

10 683

, 126 W

179 T

840 P 1

, 355

, 003 W

600 T

605 P

486 H 1

, 355

, 003 W

1

, 802 T

615 P

1

, 029 H Boost Compressor

79

, 928 W

161 T

800 P

43 H

1

, 355

, 003 W

450 T

600 P

423 H 1

, 696

, 136 W

100 T

190 P

18 H

8

9 7 6 197

, 365 W

650 T

740 P

1

, 309 H 51

, 133 W

310 T

840 P

278 H Syngas Recycle Compressor 79

, 928 W

105 T

585 P

22 H

From LP

Economizer To LP Evaporator To Superheater

From HP

Economizer 2

Post

Particulate

Cooler Raw Syngas

to Scrubber From HP

Economizer 2 To HP Economizer 1

N 2 to GT Combustor N 2 to GT Combustor

14

, 159 W

387 T

815 P

87 H Boost Compressor 4 Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

Water Steam

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical Flue Gas /

Combustion

Products

Gross Plant Power : 704 MWe Auxiliary Load : 190 MWe

Net Plant Power : 513 MWe Net Plant Efficiency

, HHV : 31

. 0 %

Net Plant Heat Rate : 11

, 002 Btu / kWh Sour Water

Steam

Water Milled Coal Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 151 Exhibit 3

- 68 Case B4B syngas cleanup heat and mass balance schematic

Source: NETL Mercury

Removal

Knock

Out

Drum Multistage

Intercooled CO 2

Compressor

Raw Syngas Humidified Fuel Gas

Sour

Drum

To Coal Slurrry and Slag Quench Interstage Knockout Claus Plant

Tail

Gas Furnace Catalytic

Reactor

Beds

Sulfur High Temperature

Shift # 1 Low Temperature

Shift # 2

Knock Out Shift Steam

Syngas

Coolers

Sour Stripper Two

- Stage

Selexol Clean

Gas

CO 2 Acid

Gas

Syngas

Scrubber 371

, 622 W

550 T

800 P

1

, 246 H

1

, 278

, 250 W

363 T

590 P

340 H

1

, 355

, 003 W

450 T

600 P

423 H 1

, 278

, 250 W

353 T

595 P

344 H 1

, 268

, 117 W

94 T

545 P

17 H 213

, 363 W

227 T

465 P

388 H

68

, 496 W

119 T

24 P

27 H

1

, 013

, 808 W

124 T

2

, 215 P

- 70 H 1

, 547

, 580 W

393 T

585 P

372 H 213

, 363 W

380 T

460 P

585 H

12

, 112 W 72

, 809 W

280 T

17 P

313 H

6

, 165 W

195 T

65 P

206 H

DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 4 B

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 4 B

C O P G ASIFIER
G AS CLEANUP SYSTEM

DWG

. NO

. BB

- HMB

- CS

- B 4 B

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P AGES

2 OF 3 1

, 649

, 872 W

398 T

590 P

546 H 1

, 649

, 872 W

400 T

590 P

398 H 15

20 19

18 14

13 12 17

21

72

, 809 W

550 T

11 P

333 H 1

, 207

, 359 W

95 T

550 P

18 H

12

, 050 W

112 T

11 P

37 H 3 Syngas Recycle 11

60

, 759 W

100 T

800 P

1 H 1

, 649

, 872 W

400 T

590 P

376 H 1

, 649

, 872 W

698 T

590 P

533 H

102

, 292 W

393 T

585 P

372 H Humidification 16

184

, 776 W

94 T

545 P

84 H

Tail Gas Compressor Hydrogenation

And Tail Gas

Cooling

469

, 170 W

353 T

595 P

347 H 469

, 170 W

150 T

1

, 205 P

116 H

To Fuel Gas

Preheater From Fuel

Gas Preheater

338

, 892 W To Water

Treatment Makeup Water

Reboiler 10

, 260 W

90 T

125 P

11 H 10

, 260 W

450 T

125 P

92 H

Claus Oxygen

Preheater

To

Deaerator

From IP

BFW From Syngas

Scrubber and HP

Economizer 2 To Syngas

Scrubber and HP

Economizer 1

From IP BFW

, LP

BFW

, and Tail Gas Cooling To LP Turbine

, Preheater

WGS / Gasifier Steam

and Reheater Fuel Gas

Humidification

CO 2 Product From Gland Steam

Condenser To Syngas Cooling

111 T Fuel Gas

Preheater

COS Hydrolysis

Preheater Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas Sour Water Acid Gas

Tailgas Carbon Dioxide

Sour Gas

Sulfur Hydrogen

Water

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical Steam

Gross Plant Power : 704 MWe Auxiliary Load : 190 MWe

Net Plant Power : 513 MWe Net Plant Efficiency

, HHV : 31

. 0 %

Net Plant Heat Rate : 11

, 002 Btu / kWh

Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 152 Exhibit 3

- 69 Case B4B combined cycle power generation heat and mass balance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 4 B

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 4 B

C O P G ASIFIER
P OWER B LOCK S YSTEM

DWG

. NO

. BB

- HMB

- CS

- B 4 B

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES
3 OF 3 Sour Gas

Sour Water

Water Steam

Flue Gas

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical

HP

Turbine IP

Turbine

Air Inlet

Filter Steam Seal Regulator

Gland

Steam

Condenser LP

Turbine Stack

Expander Compressor Generator

Generator

Condensate Pumps Steam Turbine

State

- of

- the

- art 2008

F

- Class Turbine

7

, 014

, 133 W

59 T

15 P

13 H 2

, 068

, 815 W

101 T

1 P

69 H 8

, 446

, 417 W

270 T

15 P

150 H

213

, 363 W

380 T

460 P

585 H 1

, 370

, 817 W

994 T

1

, 815 P

1

, 468 H 9

, 744 W

298 T

65 P

1

, 171 H

1

, 460

, 272 W

465 T

65 P

1

, 257 H

1

, 400 W

615 T

65 P

1

, 331 H

1

, 400 W

212 T

15 P

180 H

21 25

16 24

Hot Well Condenser 596

, 381 W

59 T

15 P

27 H 9

, 026 W

660 T

501 P

1

, 327 H

9

, 762 W

615 T

65 P

1

, 331 H 1

, 337 W

505 T

65 P

1

, 277 H Preheater Deaerator

Heater HP

Economizer

1 LP

Economizer HP

Economizer

2 HP Evaporator Superheater

/ Reheater

From Syngas Cooler

Blowdown

Flash Deaerator LP Evaporator From Claus

, Process Extractions

, and 250 PSIA Header

LP Extraction Spray

LP Blowdown Hot Reheat 8

, 446

, 417 W

1

, 044 T

15 P

361 H 23

To WWT

Condensate to Tail Gas Cooling Process

Extraction 1

, 973

, 163 W

274 T

45 P

242 H 26

, 434 W

274 T

79 P

242 H

9

, 866 W

274 T

79 P

242 H 1

, 398

, 140 W

279 T

2

, 251 P

247 H 353

, 694 W

298 T

65 P

266 H

235 T 305 T 585 T 636 T 300

, 993 W

351 T

2

, 251 P

319 H

300

, 993 W

585 T

2

, 001 P

585 H

27

, 273 W

585 T

2

, 001 P

585 H 923

, 082 W

585 T

2

, 001 P

585 H 636 T

265

, 292 W

298 T

65 P

1

, 171 H

1

, 195

, 395 W

661 T

501 P

1

, 327 H 205 T

761

, 167 W

385 T

469 P

87 H Steam to Gasifier 168

, 786 W

650 T

740 P

1

, 303 H LP Extraction

Spray # 2

22

, 016 W

241 T

825 P

209 H

Water Makeup

1

, 000 W

994 T

1

, 815 P

1

, 468 H 1

, 000 W

212 T

15 P

180 H 798 W

994 T

1

, 815 P

1

, 468 H 29

, 461 W

500 T

250 P

1

, 255 H IP Extraction Steam

to 250 PSIA Header

LP Extraction Spray # 1

2

, 068

, 815 W

103 T

120 P

71 H 274 T To Post

Particulate

Cooler From Post

Particulate

Cooler From ASU and Fuel

Gas Preheater

To ASU and Fuel

Gas Preheater

To Fire Tube Boiler From Fire Tube Boiler

994 T

Nitrogen Diluent

Fuel Gas

Ambient Air LP Pump

HP Pump IP Pump IP From Syngas and Pre

Particulate Cooler

WGS Shift Steam Cold Reheat

261

, 370 W

550 T

600 P

1

, 247 H 400

, 181 W

550 T

600 P

1

, 247 H 0 W

138

, 811 W

550 T

600 P

1

, 247 H Gasifier Steam LP To Syngas

Coolers

264

, 385 W

274 T

79 P

242 H LP From Syngas Coolers

264

, 385 W

298 T

65 P

1

, 171 H IP to Pre Particulate and Syngas Coolers

58

, 909 W

276 T

615 P

244 H 400

, 181 W

275 T

615 P

243 H

IP To Claus

Gross Plant Power : 704 MWe Auxiliary Load : 190 MWe

Net Plant Power : 513 MWe Net Plant Efficiency

, HHV : 31

. 0 %

Net Plant Heat Rate : 11

, 002 Btu / kWh

Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 153 This page intentionally left blankCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 154 Exhibit 3

- 70 C ase B4B overall energy balance (0°C [32°F] reference)

HHV Sensible +

Latent Power Total

Heat In (GJ/hr)

Coal 5,960 (5,649) 5.0 (4.7)

– 5,965 (5,654)

Air

– 119.4 (113.2)

– 119.4 (113.2) Raw Water Makeup

– 81.9 (77.7)

– 81.9 (77.7) Auxiliary Power

– – 685 (649) 685 (649)

TOTAL 5,960 (5,649) 206.4 (195.6) 685 (649) 6,851 (6,494) Heat Out (GJ/hr)

ASU Vent

– 1.2 (1.2)

– 1.2 (1.2) Slag 36.7 (34.8) 25.2 (23.9)

– 61.9 (58.7)

Stack Gas

– 1,334 (1,264)

– 1,334 (1,264)

Sulfur 50.9 (48.3) 0.6 (0.6)

– 51.5 (48.8) Motor Losses and Design

Allowances – – 58.6 (55.6) 58.6 (55.6)

Condenser

– 1,408 (1,334)

– 1,408 (1,334)

Non

- Condenser Cooling Tower

Loads – 801 (760)

– 801 (760)

CO 2 – - 74.7 (

- 70.8)

– - 74.7 (

- 70.8)

Blowdown

– 42.7 (40.5)

– 42.7 (40.5)

CO 2 Capture Losses

– 182.6 (173.0)

– 182.6 (173.0)

Ambient Losses A



### – 168.2 (159.5)

– 168.2 (159.5)

Power

– – 2,533 (2,401) 2,533 (2,401)

TOTAL 87.6 (83.1) 3,889 (3,686) 2,592 (2,457) 6,569 (6,226) Unaccounted Energy B



### – 282 (268)

– 282 (268)

A 

### Ambient losses include all losses to the environment through radiation, convection, etc. Sources of these losses include the combustor, reheater, superheater, and transformers.

B 

### By difference



# 3.3.10 Case B4B

- Major Equipment List

Major equipment items for the E

- Gas TM 

## gasifier with CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the

cost estimates in Section 3.3.11 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 155 Case B4B

– Account 1: Coal Handling

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

5 Stacker/Reclaimer Traveling, linear 1,130 tonne/hr (1,250 tph) 1 0

6 Reclaim Hopper N/A 50 tonne (50 ton) 2 1

7 Feeder Vibratory 180 tonne/hr (200 tph) 2 1

8 Conveyor No. 3 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

9 Coal Surge Bin w/ Vent Filter Dual outlet 180 tonne (200 ton) 2 0

10 Crusher Impactor reduction 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 2 0

11 Conveyor No. 4 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

12 Conveyor No. 5 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

13 Coal Silo w/ Vent Filter and
Slide Gates Field erected 800 tonne (900 ton) 3 0



## Case B4B

– Account 2: Coal Preparation and Feed

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 80 t onne/h (90 tph) 3 0

2 Conveyor No. 6 Belt w/ tripper 240 tonne/h (270 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 480 tonne (530 ton) 1 0

4 Weigh Feeder Belt 120 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 120 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank with Agitator Field erected 298,180 liters (78,770 gal) 2 0

7 Slurry Water Pumps Centrifugal 830 lpm (220 gpm) 2 1

8 Trommel Screen Coarse 170 tonne/h (190 tph) 2 0

9 Rod Mill Discharge Tank with Agitator Field erected 390,070 liters (103,040 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,300 lpm (900 gpm) 2 2

11 Slurry Storage Tank with Agitator Field erected 1,170,200 liters (309,100 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,500 lpm (1,700 gpm) 2 2

13 Slurry Product Pumps Positive displacement 3,300 lpm (900 gpm) 2 2



## Case B4B

– Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical,

outdoor 1,100,000 liters (291,000 gal) 2 0

2 Condensate Pumps Vertical canned 8,660 lpm @ 90 m H 2 O (2,290 gpm @ 300 ft H 2 O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 607,000 kg/hr (1,338,000 lb/hr) 2 0

4 Intermediate

- Pressure Feedwater Pump Horizontal centrifugal, single stage 8,540 lpm @ 30 m H 2 O (2,260 gpm @ 90 ft H 2 O) 2 1

5 High

- Pressure Feedwater Pump No. 1 Barrel type, multi

stage, centrifugal HP water: 6,050 lpm @ 1,800 m H 2 O (1,600 gpm @ 6,100 ft H 2 O) 2 1

6 High

- Pressure Feedwater Pump No. 2 Barrel type, multi

stage, centrifugal IP water: 1,300 lpm @ 220 m

H 2 O (340 gpm @ 730 ft H 2 O) 2 1Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 156 Equipment

No. Description Type Design Condition Operating Qty. Spares

7 Auxiliary Boiler Shop fabricated, water

tube 18,000 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air Compressors Flooded Screw 28 m 3 

### / min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m 3 

### / min (1,000 scfm) 2 1

10 Closed Cycle Cooling Heat Exchangers Plate and frame 441 GJ/hr (418 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 158,100 lpm @ 20 m H 2 O (41,800 gpm @ 70 ft H 2 O) 2 1

12 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 110 m H 2 O (1,000 gpm @ 350 ft H 2 O) 1 1

13 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 80 m H 2 O (700 gpm @ 250 ft H 2 O) 1 1

14 Raw Water Pumps Stainless steel, single

suction 5,660 lpm @ 20 m H 2 O (1,490 gpm @ 60 ft H 2 O) 2 1

15 Ground Water Pumps Stainless steel, single

suction 2,830 lpm @ 270 m H 2 O (750 gpm @ 880 ft H 2 O) 4 1

16 Filtered Water Pumps Stainless steel, single

suction 3,070 lpm @ 50 m H 2 O (810 gpm @ 160 ft H 2 O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,471,000 liter (389,000 gal) 2 0

18 Makeup Water

Demineralizer Anion, cation, and

mixed bed 1,850 lpm (490 gpm) 2 0

19 Liquid Waste Treatment System N/A 10 years, 24

- hour storm 1 0



## Case B4B

– Account 4: Gasifier, ASU, and Accessories Including Low Temperature Heat Recovery and Fuel Gas Saturation

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized two

- stage, slurry

- feed entrained

bed 2,900 tonne/day, 4.2 MPa (3,200 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler Fire

- tube boiler 338,000 kg/hr (745,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 338,000 kg/hr (745,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with pulse

- jet cleaning metallic filters 2 0

5 Syngas Scrubber Including Sour Water Stripper Vertical upflow 338,000 kg/hr (745,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with

condensate drain 386,000 kg/hr (851,000 lb/hr) 8 0

7 Raw Gas Knockout

Drum Vertical with mist

eliminator 303,000 kg/hr, 35°C, 3.8 MPa (668,000 lb/hr, 95°F, 555 psia) 2 0

8 Saturation Water

Economizers Shell and tube 36 GJ/hr (34 MMBtu/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 53,000 kg/hr, 108°C, 3.8 MPa (117,000 lb/hr, 227°F, 545 psia) 2 0

10 Saturator Water Pump Centrifugal 700 lpm @ 13 m H 2 O (200 gpm @ 42 ft H 2 O) 2 2

11 Synthesis Gas

Reheater Shell and tube 53,000 kg/hr (117,000 lb/hr) 2 0

12 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 338,000 k g/hr (745,000 lb/hr)

syngas 2 0

13 ASU Main Air Compressor Centrifugal, multi

- stage 6,000 m 3 

### / min @ 1.3 MPa (205,000 scfm @ 190 psia) 2 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 157 Equipment

No. Description Type Design Condition Operating Qty. Spares

14 Cold Box Vendor design 2,300 tonne/day (2,600 tpd) of 95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi

- stage 1,000 m 3 

### / min (41,000 scfm)

Suction

- 1.0 MPa (130 psia) Discharge

- 5.1 MPa (740 psia) 2 0

16 Primary Nitrogen Compressor Centrifugal, multi

- stage 4,000 m 3 

### / min (134,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 2 0

17 Secondary Nitrogen Compressor Centrifugal, single

stage 540 m 3 

### / min (19,000 scfm)

Suction

- 1.3 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 2 0

18 Gasifier Purge Nitrogen Boost Compressor Centrifugal, single

stage 2,000 m 3 

### / min (57,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470 psia) 2 0



## Case B4B

– Account 5: Syngas Cleanup

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber 1 Sulfated carbon bed 301,000 kg/hr (664,000 lb/hr)

, 35°C (95°F)

, 3.8 MPa (550 psia) 2 0

2 Mercury Adsorber 2 Sulfated carbon bed 301,000 kg/hr (664,000 lb/hr)

, 35°C (95°F)

, 3.8 MPa (550 psia) 2 0

3 Sulfur Plant Claus type 145 tonne/day (160 tpd) 1 0

4 Water Gas Shift

Reactors Fixed bed, catalytic 206,000 kg/hr (454,000 lb/hr)

, 204°C (400°F)

, 4.1 MPa (590 psia) 4 0

5 Shift Reactor Heat Recovery Exchangers Shell and Tube Exchanger 1: 94 GJ/hr (89 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 4 0

6 Acid Gas Removal

Plant Two

- stage Selexol 316,000 kg/hr (697,000 lb/hr)

, 34°C (94°F)

, 3.8 MPa (545 psia) 2 0

7 Hydrogenation

Reactor Fixed bed, catalytic 36,000 kg/hr (80,000 lb/hr)

, 232°C (450°F)

, 0.1 MPa (12. 3 psia) 1 0

8 Tail Gas Recycle Compressor Centrifugal 30,000 kg/hr (67,000 lb/hr) each 1 0

9 CO 2 Compressor Integrally geared,

multi

- stage centrifugal 1,100 m 3 

### / min @ 15.3 MPa (40,300 scfm @ 2,215 psia) 4 0



## Case B4B

– Account 6: Combustion Turbine and Auxiliaries

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Combustion Turbine State

- of

- the

- art

2008 F

- c lass 230 MW 2 0

2 Combustion Turbine

Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 2 0



## Case B4B

– Account 7: HRSG, Ducting, and Stack

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS

liner 76 m (250 ft) high x 8.5 m (28 ft) diameter 1 0

2 Heat Recovery
Steam Generator Drum, multi

- pressure with economizer section and integral deaerator Main steam

- 341,986 kg/hr,

12.4 MPa/534°C (753,949 lb/hr, 1,800 psig/994°F) 2 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 158 Case B4B

– Account 8: Steam Turbine Generator and Auxiliaries

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Steam

Turbine Commercially available

advanced steam turbine 252 MW
12.4 MPa/534°C/534°C (1,800 psig/ 994°F/994°F) 1 0

2 Steam

Turbine
Generator Hydrogen cooled, static

excitation 280 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 1 0

3 Surface

Condenser Single pass, divided waterbox including

vacuum pumps 1,550GJ/hr (1,470 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1 0

4 Steam Bypass One per HRSG 50% steam flow @ design steam

conditions 2 0



## Case B4B

– Account 9: Cooling Water System

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 472,000 lpm @ 30 m (125,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative, mechanical draft,

multi

- cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,630 GJ/hr (2,490 MMBtu/hr) heat duty 1 0



## Case B4B

– Account 10: Slag Recovery and Handling

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 235,000 liters (62,000 gal) 2 0

2 Slag Crusher Roll 12 tonne/hr (14 tph) 2 0

3 Slag Depressurizer Proprietary 12 tonne/hr (14 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 142,000 liters (37,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 64,000 liters (17,000 gal) 2 0

6 Slag Conveyor Drag chain 12 tonne/hr (14 tph) 2 0

7 Slag Separation Screen Vibrating 12 tonne/hr (14 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 12 tonne/hr (14 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 201,000 liters (53,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 50 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 2 2

11 Grey Water Storage Tank Field erected 64,000 liters (17,000 gal) 2 0

12 Grey Water Pumps Centrifugal 230 lpm @ 430 m H 2 O (60 gpm @ 1,420 ft H 2 O) 2 2

13 Grey Water Recycle Heat Exchanger Shell and tube 52,200 kg/hr (30,000 lb/hr) 2 0

14 Slag Storage Bin Vertical, field erected 890 tonne (980 tons) 2 0

15 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 1 0



## Case B4B

– Account 11: Accessory Electric Plant

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 CTG Transformer Oil

- filled 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 2 0

2 STG Transformer Oil

- filled 24 kV/345 kV, 230 MVA, 3

- ph, 60 Hz 1 0

3 High Voltage Auxiliary

Transformer Oil

- filled 345 kV/13.8 kV, 79 MVA, 3

- ph, 60 Hz 2 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 159 4 Medium Voltage Transformer Oil

- filled 24 kV/4.16 kV, 51 MVA, 3

- ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 8 MVA, 3

- ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency

shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 0



## Case B4B

– Account 12: Instrumentation and Control

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 DCS

- Main
Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 0



# 3.3.11 Case B4B

- Cost Estimating Res ults

The cost estimating methodology was described previously in Section 2.6

. Exhibit 3

- 71 shows a detailed breakdown of the capital costs ; Exhibit 3

- 72 shows the owner’s costs, TOC, and TASC ; Exhibit 3

- 73 shows the initial and annual O&M costs; and Exhibit 3

- 74 shows the COE

breakdown.

The estimated TP C of the E

- Gas TM 

## gasifier with CO 2 

## capture is $3,540 /kW. Process contingency represents 4.1 percent of the TP C

, and project contingency represents 13.9 percent. The COE, including CO 2 

## T&S costs of $ 9.8 /M Wh, is $ 151.8 /M Wh.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 160 Exhibit 3

- 71 Case B4B total plant cost details

Case: B 4B

– E

- Gas TM IGCC w/ CO 2 Estimate Type: Conceptual Plant Size (MW,net): 514 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $4,536 $0 $2,186 $0 $6,722 $672 $0 $1,479 $8,873 $17

1.2 Coal Stackout & Reclaim $5,862 $0 $1,402 $0 $7,263 $726 $0 $1,598 $9,587 $19

1.3 Coal Conveyors & Yd Crush $5,450 $0 $1,387 $0 $6,836 $684 $0 $1,504 $9,024 $18

1.4 Other Coal Handling $1,426 $0 $321 $0 $1,747 $175 $0 $384 $2,306 $4

1.9 Coal & Sorbent Hnd. Foundations $0 $3,029 $7,916 $0 $10,945 $1,095 $0 $2,408 $14,447 $28

Subtotal $17,273 $3,029 $13,211 $0 $33,513 $3,351 $0 $7,373 $44,238 $86

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying w/2.3 $0 w/2.3 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,937 $465 $300 $0 $2,702 $270 $0 $594 $3,566 $7

2.3 Slurry Prep & Feed $26,425 $0 $11,591 $0 $38,015 $3,802 $0 $8,363 $50,180 $98

2.4 Misc. Coal Prep & Feed $1,065 $778 $2,292 $0 $4,135 $414 $0 $910 $5,459 $11

2.9 Coal & Sorbent Feed Foundation $0 $3,907 $3,352 $0 $7,259 $726 $0 $1,597 $9,582 $19

Subtotal $29,427 $5,150 $17,535 $0 $52,112 $5,211 $0 $11,465 $68,788 $134

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $3,381 $5,834 $3,059 $0 $12,274 $1,227 $0 $2,700 $16,202 $32

3.2 Water Makeup & Pretreating $868 $90 $477 $0 $1,434 $143 $0 $473 $2,051 $4

3.3 Other Feedwater Subsystems $1,901 $628 $561 $0 $3,090 $309 $0 $680 $4,079 $8

3.4 Service Water Systems $507 $1,012 $3,488 $0 $5,007 $501 $0 $1,652 $7,160 $14

3.5 Other Boiler Plant Systems $2,735 $1,022 $2,515 $0 $6,272 $627 $0 $1,380 $8,279 $16

3.6 FO Supply Sys & Nat Gas $17,726 $693 $642 $0 $19,061 $1,906 $0 $4,193 $25,160 $49

3.7 Waste Treatment Equipment $1,174 $0 $727 $0 $1,901 $190 $0 $627 $2,719 $5

3.8 Misc. Power Plant Equipment $1,294 $173 $672 $0 $2,140 $214 $0 $706 $3,060 $6

Subtotal $29,586 $9,452 $12,142 $0 $51,179 $5,118 $0 $12,413 $68,710 $134

4 Gasifier & Accessories

4.1 Syngas Cooler Gasifier System $137,262 $0 $76,506 $0 $213,769 $21,377 $29,564 $40,623 $305,333 $594

4.2 Syngas Cooler w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU & Oxidant Compression $222,841 $0 w/equip. $0 $222,841 $22,284 $0 $24,513 $269,638 $525

4.4 LT Heat Recovery & FG Saturation $28,817 $0 $10,949 $0 $39,766 $3,977 $0 $8,749 $52,492 $102

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,981 $801 $0 $2,782 $278 $0 $612 $3,672 $7

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $9,765 $5,824 $0 $15,589 $1,559 $0 $4,287 $21,434 $42

Subtotal $388,921 $11,746 $94,080 $0 $494,747 $49,475 $29,564 $78,784 $652,569 $1,271

5A Gas Cleanup & Piping

5A.1 Double Stage Selexol $162,818 $0 w/equip. $0 $162,818 $16,282 $32,564 $42,333 $253,996 $495

5A.2 Elemental Sulfur Plant $12,406 $2,418 $15,897 $0 $30,721 $3,072 $0 $6,759 $40,552 $79

5A.3 Mercury Removal $1,867 $0 $1,411 $0 $3,278 $328 $164 $754 $4,524 $9

5A.4 Shift Reactors $8,605 $0 $3,440 $0 $12,044 $1,204 $0 $2,650 $15,898 $31

5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 161 Case: B 4B

– E

- Gas TM IGCC w/ CO 2 Estimate Type: Conceptual Plant Size (MW,net): 514 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

5A.6 Blowback Gas Systems $657 $369 $206 $0 $1,232 $123 $0 $271 $1,626 $3

5A.7 Fuel Gas Piping $0 $926 $606 $0 $1,532 $153 $0 $337 $2,022 $4

5A.9 HGCU Foundations $0 $838 $565 $0 $1,403 $140 $0 $463 $2,007 $4

Subtotal $186,353 $4,551 $22,125 $0 $213,029 $21,303 $32,727 $53,566 $320,626 $624

5B CO 2 Compression

5B.2 CO 2 Compression & Drying $40,408 $6,061 $17,509 $0 $63,978 $6,398 $0 $14,075 $84,451 $164

Subtotal $40,408 $6,061 $17,509 $0 $63,978 $6,398 $0 $14,075 $84,451 $164

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $111,210 $0 $7,881 $0 $119,091 $11,909 $11,909 $14,291 $157,201 $306

6.9 Combustion Turbine Foundations $0 $923 $1,068 $0 $1,992 $199 $0 $657 $2,848 $6

Subtotal $111,210 $923 $8,950 $0 $121,083 $12,108 $11,909 $14,948 $160,049 $312

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $29,570 $0 $5,725 $0 $35,295 $3,530 $0 $3,882 $42,707 $83

7.3 Ductwork $0 $2,109 $1,479 $0 $3,588 $359 $0 $789 $4,736 $9

7.4 Stack $4,071 $0 $1,519 $0 $5,590 $559 $0 $615 $6,763 $13

7.9 HRSG, Duct & Stack Foundations $0 $775 $778 $0 $1,553 $155 $0 $512 $2,221 $4

Subtotal $33,641 $2,884 $9,501 $0 $46,026 $4,603 $0 $5,799 $56,428 $110

8 Steam Turbine Generator

8.1 Steam TG & Accessories $36,358 $0 $5,336 $0 $41,695 $4,169 $0 $4,586 $50,450 $98

8.2 Turbine Plant Auxiliaries $219 $0 $500 $0 $719 $72 $0 $79 $870 $2

8.3 Condenser & Auxiliaries $3,130 $0 $1,764 $0 $4,894 $489 $0 $538 $5,922 $12

8.4 Steam Piping $15,068 $0 $6,534 $0 $21,603 $2,160 $0 $5,941 $29,703 $58

8.9 TG Foundations $0 $1,034 $1,827 $0 $2,861 $286 $0 $944 $4,091 $8

Subtotal $54,776 $1,034 $15,962 $0 $71,771 $7,177 $0 $12,089 $91,037 $177

9 Cooling Water System

9.1 Cooling Towers $4,540 $0 $1,466 $0 $6,006 $601 $0 $991 $7,597 $15

9.2 Circulating Water Pumps $2,187 $0 $164 $0 $2,351 $235 $0 $388 $2,974 $6

9.3 Circ. Water System Auxiliaries $190 $0 $27 $0 $217 $22 $0 $36 $274 $1

9.4 Circ. Water Piping $0 $8,426 $2,041 $0 $10,468 $1,047 $0 $2,303 $13,817 $27

9.5 Make

- up Water System $480 $0 $660 $0 $1,140 $114 $0 $251 $1,505 $3

9.6 Component Cooling Water Sys $963 $1,152 $791 $0 $2,907 $291 $0 $639 $3,837 $7

9.9 Circ. Water System Foundations $0 $2,765 $4,913 $0 $7,678 $768 $0 $2,534 $10,980 $21

Subtotal $8,360 $12,344 $10,063 $0 $30,767 $3,077 $0 $7,142 $40,985 $80

10 Ash & Spent Sorbent Handling Systems

10.1 Slag Dewatering & Cooling $20,691 $0 $10,134 $0 $30,825 $3,083 $0 $3,391 $37,299 $73

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $680 $0 $734 $0 $1,414 $141 $0 $233 $1,789 $3

10.7 Ash Transport & Feed Equipment $935 $0 $218 $0 $1,154 $115 $0 $190 $1,459 $3

10.8 Misc. Ash Handling Equipment $1,408 $1,725 $512 $0 $3,644 $364 $0 $601 $4,610 $9

10.9 Ash/Spent Sorbent Foundation $0 $57 $75 $0 $132 $13 $0 $44 $189 $0

Subtotal $23,714 $1,782 $11,674 $0 $37,169 $3,717 $0 $4,459 $45,346 $88Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 162 Case: B 4B

– E

- Gas TM IGCC w/ CO 2 Estimate Type: Conceptual Plant Size (MW,net): 514 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

11 Accessory Electric Plant

11.1 Generator Equipment $1,124 $0 $1,095 $0 $2,219 $222 $0 $244 $2,685 $5

11.2 Station Service Equipment $5,488 $0 $505 $0 $5,993 $599 $0 $659 $7,252 $14

11.3 Switchgear & Motor Control $10,130 $0 $1,883 $0 $12,013 $1,201 $0 $1,982 $15,196 $30

11.4 Conduit & Cable Tray $0 $5,147 $15,866 $0 $21,013 $2,101 $0 $5,779 $28,893 $56

11.5 Wire & Cable $0 $9,924 $6,038 $0 $15,961 $1,596 $0 $4,389 $21,947 $43

11.6 Protective Equipment $0 $799 $2,967 $0 $3,766 $377 $0 $621 $4,764 $9

11.7 Standby Equipment $269 $0 $268 $0 $536 $54 $0 $88 $678 $1

11.8 Main Power Transformers $19,358 $0 $167 $0 $19,525 $1,952 $0 $3,222 $24,699 $48

11.9 Electrical Foundations $0 $175 $477 $0 $652 $65 $0 $215 $933 $2

Subtotal $36,369 $16,045 $29,264 $0 $81,678 $8,168 $0 $17,200 $107,046 $208

12 Instrumentation & Control

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,292 $0 $880 $0 $2,173 $217 $109 $375 $2,873 $6

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $297 $0 $194 $0 $491 $49 $25 $113 $678 $1

12.7 Computer & Accessories $6,893 $0 $225 $0 $7,119 $712 $356 $819 $9,005 $18

12.8 Instrument Wiring & Tubing $0 $2,654 $5,023 $0 $7,677 $768 $384 $2,207 $11,035 $21

12.9 Other I & C Equipment $4,608 $0 $2,283 $0 $6,891 $689 $345 $1,189 $9,113 $18

Subtotal $13,090 $2,654 $8,606 $0 $24,350 $2,435 $1,217 $4,702 $32,705 $64

13 Improvements to Site

13.1 Site Preparation $0 $121 $2,743 $0 $2,864 $286 $0 $945 $4,095 $8

13.2 Site Improvements $0 $2,146 $3,033 $0 $5,179 $518 $0 $1,709 $7,406 $14

13.3 Site Facilities $3,845 $0 $4,316 $0 $8,161 $816 $0 $2,693 $11,670 $23

Subtotal $3,845 $2,266 $10,092 $0 $16,203 $1,620 $0 $5,347 $23,171 $45

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $317 $179 $0 $496 $50 $0 $109 $655 $1

14.2 Steam Turbine Building $0 $2,691 $3,831 $0 $6,521 $652 $0 $1,076 $8,250 $16

14.3 Administration Building $0 $1,042 $756 $0 $1,798 $180 $0 $297 $2,274 $4

14.4 Circulation Water Pumphouse $0 $196 $104 $0 $299 $30 $0 $49 $378 $1

14.5 Water Treatment Buildings $0 $713 $696 $0 $1,409 $141 $0 $232 $1,782 $3

14.6 Machine Shop $0 $533 $365 $0 $898 $90 $0 $148 $1,136 $2

14.7 Warehouse $0 $861 $556 $0 $1,417 $142 $0 $234 $1,792 $3

14.8 Other Buildings & Structures $0 $516 $401 $0 $917 $92 $0 $202 $1,211 $2

14.9 Waste Treating Building & Str. $0 $1,153 $2,202 $0 $3,356 $336 $0 $738 $4,430 $9

Subtotal $0 $8,023 $9,089 $0 $17,112 $1,711 $0 $3,086 $21,909 $43

Total $976,972 $87,945 $289,801 $0 $1,354,718 $135,472 $75,418 $252,447 $1,818,056 $3,540Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 163 Exhibit 3

- 72 Case B4B owner’s costs

Description $ / 1,000 $/kW

Pre

- Production Costs

6 Months All Labor $16,220 $32

1 Month Maintenance Materials $3,663 $7

1 Month Non

- fuel Consumables $690 $1

1 Month Waste Disposal $459 $1

25% of 1 Months Fuel Cost at 100% CF $3,028 $6

2% of TPC $36,361 $71

Total $60,421 $118

Inventory Capital

60

- day supply of fuel and consumables at 100% CF $25,185 $49

0.5% of TPC (spare parts) $9,090 $18

Total $34,275 $67

Other Costs

Initial Cost for Catalyst and Chemicals $17,040 $33

Land $900 $2

Other Owner's Costs $272,708 $531

Financing Costs $49,088 $96

Total Overnight Costs (TOC) $2,252,488 $4,386

TASC Multiplier (IOU, high

- risk, 35 year) 1.140

Total As

- Spent Cost (TASC) $2,567,836 $5,000Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 164 Exhibit 3

- 73 Case B4B initial and annual operating and maintenance costs

Case: B4B

– E

- Gas TM IGCC w/ CO 2 Cost Base: Jun 2011 Plant Size (MW,net): 514 Heat Rate

- net (Btu/kWh): 1 1,002 Capacity Factor (%): 80
Operating & Maintenance Labor
Operating Labor Operating Labor Requirements per Shift
Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 Operating Labor Burden: 30.00 % of base Operator: 10.0

Labor O

- H Charge Rate: 25.00 % of labor Foreman: 1.0
Lab Tech's, etc.: 3.0

Total: 16.0 Fixed Operating Costs

Annual Cost ($) ($/kW

- net)
Annual Operating Labor: $7,233,658 $14.084

Maintenance Labor: $18,718,137 $36.444 Administrative & Support Labor: $6,487,949 $12.632

Property Taxes and Insurance: $36,361,120 $70.795

Total: $68,800,863 $133.955
Variable Operating Costs ($) ($/M Wh

- net)

Maintenance Material: $35,160,939 $9.76861

Consumables
Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill
Water (/1000 gallons): 0 4,145 $1.67 $0 $2,026,257 $0.56295 Makeup and Waste Water Treatment Chemicals (lbs): 0 24,697 $0.27 $0 $1,931,496 $0.53662

Carbon (Mercury Removal) (lb): 177,789 304 $5.50 $977,839 $488,920 $0.13583 Shift Catalyst (ft 3 ): 6,484 4.44 $771.99 $5,005,557 $1,001,111 $0.27813 Selexol Solution (gal): 300,533 98 $36.79 $11,056,980 $1,055,946 $0.29337

Claus Catalyst (ft 3 ): w/equip. 2.00 $203.15 $0 $118,896 $0.03303

Subtotal: $17,040,376 $6,622,626 $1.83994
Waste Disposal
Spent Mercury Catalyst (lb.): 0 304 $0.65 $0 $57,790 $0.01606 Flyash (ton): 0 0 $0.00 $0 $0 $0.00000

Slag (ton): 0 593 $25.11 $0 $4,348,431 $1.20811

Subtotal: $0 $4,406,221 $1.22416
By

- Products
Sulfur (tons): 0 145 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000 Variable Operating Costs Total: $17,040,376 $46,189,787 $12.83271

Fuel Cost
Illinois Number 6 (ton): 0 5,811 $68.54 $0 $116,290,256 $32.30842

Total: $0 $116,290,256 $32.30842



### Exhibit 3

- 74 Case B 4B COE breakdown

Component Value, $/M Wh Percentage

Capital 77.6 55%

Fixed 19.1 13%

Variable 12.8 9%

Fuel 32.3 23%

Total (Excluding T&S) 141.9 N/A

CO 2 

### T&S 9.9 7%

Total (Including T&S) 151.8 N/ACost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 165 

# 3.4 General Electric Energy IGCC Cases

This section contains an evaluation of three GEE plant designs (radiant

- only [with and without

CO 2 

## capture] and quench

- only [with CO 2 

## capture] ). Cases B5A and B5B are based on the GEE gasifier in the “radiant

- only” configuration and Case B5B

- Q is based on the GEE gasifier in the “quench

- only” configuration. GEE offers three design configurations (50) :

• Quench: In this configuration, the hot syngas exiting the gasifier passes through a pool of water to quench the temperature to 289°C (550°F) before entering the syngas scrubber. It is the simplest and lowest capital cost design, but also the least efficient.

• Radiant : In this configuration, t he hot syngas exiting the gasifier passes through a radiant syngas cooler where it is cooled from about 1

, 316°C (2

, 400°F) to 677°C (1

, 250°F), and

then passes through a water quench where the syngas is further cooled to about 232°C (450°F) prior to entering the syngas scrubber. Relative to the quench configuration, the

radiant design offers increased output, higher efficiency, improved reliability/availability, and results in the lowest COE. This configuration was chosen by GEE and Bechtel for the design o f their reference plant.

• Radiant

- Convective: In this configuration, the hot syngas exiting the gasifier passes through a radiant syngas cooler where it is cooled from about 1

, 316°C (2

, 400°F) to 760°C (1

, 400°F), then passes over a pool of water where partic ulate 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 eff iciency, but at the expense of highest capital cost and the lowest availability. This is the configuration used at Tampa

Electric’s Polk Power Station.

Note that the radiant configuration includes a water quench and, based on functionality, would be

more appropriately named radiant

- quench. The term radiant is used to distinguish it from the

radiant

- convective configuration. Since radiant is the terminology used by GEE, it will be used throughout this report.

The balance of this section is organized in an analogous manner to Sections 3.2 and 3.3 :

• Gasifier Background

• Process System Description for Case B5A

• Key Assumptions for Cases B5A, B5B, and B5B

- Q

• Sparing Philosophy for Cases B5A, B5B, and B5B

- Q

• Performance Results for Case B5A

• Equipment List for Case B5A

• Cost Estimates for Case B5A

• Process and System Description, Performance Results, Equipment List, and Cost

Estimate for Cases B5B and B5B

- Q



# 3.4.1 Gasifier Background

As mentioned in Sections 3.2.1 and 3.3.1

, the “Coal Gasification Guidebook: Status, Application, and Technologies” report published by the EPRI provides a detailed history of the development of several types of gasifier technology, including the GEE gasifier, as well as gasifier capacity, distingu ishing characteristics, and important coal characteristics. (46)Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 166 The largest GEE gasifier is the unit at Tampa Electric, which consists of the rad iant

- 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 Nm 3 

## /hr (6.7 million scfh) with an energy content of about 1,897 million kJ/hr (HHV) (1,800 million Btu/hr). This size matches the

F

- Class CTs that are used at Tampa.

T he GEE gasifier operates at the highest pressure of the three gasifiers in this report , 5.6 MPa (815 psia) compared to 4.2 MPa (615 psia) for E

- Gas TM 

## and Shell.

The relatively high H 2 

## /CO ratio and CO 2 

## content of GEE gasificat ion fuel gas helps achieve low

NO x and CO emissions in even the higher

- temperature advanced CTs. (46)

In contrast to the Shell and E

- Gas TM 

## gasification technologies, the GEE gasifier has a relatively low refractory life and a h igh oxygen requirement. These characteristics are more prevalent in the single

- stage quench design , with a lower efficiency. However, the quench design has a significantly lower capital cost for syngas cooling. (46)

Coals with low concentrations of ash and soluble salts are preferred for use with the GEE gasifiers, as high levels of ash increase the oxygen requirement and soluble salts may build

- up in concentration with high levels of process condensate recycle is used. (46)

The slurry feeding also favors the use of high

- rank coals, such as bituminous coal, since their

low inherent moisture content increases the moisture

- free solids content of the slurry and thereby reduces oxygen requirements. (46)



# 3.4.2 Process Description

In this section the overall GEE gasification process is described. The system description follows

the BFD in Exhibit 3

- 75 and stream numbers reference the same exhibit. The tables in

Exhibit 3

- 76 provide stream compositions, temperature, pressure, enthalpy, and flow rates for the

numbered streams in the BFD.

3.4.2.1 Coal Grinding and Slurry Preparation

Coal receiving and handling is common to all cases and was covered in Section 3.1.1 . The

rec eiving 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 p rovides 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. T he 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 t he 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 Co noco P hillips presented a paper showing the slurry concentration of Illinois No. 6 coal as 63 percent

. (49)

The coal grinding system is equipped with a dust suppression system consisting of water sprays aided by a wetting agent. The degr ee 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.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 167 The equipment in the coal grinding and slurry preparation system is fabricated of m aterials appropriate for the abrasive environment present in the system. The tanks and agitators are rubber lined. The pumps are either rubber

- lined or hardened metal to minimize erosion. Piping is fabricated of high

- density polyethylene (HDPE).

3.4.2.2 Gasific ation

This plant utilizes two gasification trains to process a total of 5,083 tonnes/day (5,603 tpd ) of

Illinois No. 6 coal. Each of the 2 x 50 percent gasifiers operates at maximum capacity. The largest operating GEE gasifier is the 2,268 tonne/day (2,5 00 tpd ) unit at Polk Power Station. However, that unit operates at about 2.8 MPa (400 psia). The gasifier in this report , which operates at 5.6 MPa (815 psia), will be able to process more coal and maintain the same gas

residence time.

The slurry feed pu mp 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 separ ation plant supplies 4,171 tonnes/day (4,597 tpd ) of 95 mol% oxygen to the gasifiers (stream 5) and the Claus plant (stream 3). Carbon conversion in the gasifier is assumed to be 98 percent

, including a fines recycle stream.

The gasifier vessel is a refra ctory

- lined, HP combustion chamber. The coal slurry feedstock and oxygen are fed through a fuel injector at the top of the gasifier vessel. The coal slurry and the oxygen react in the gasifier at 5.6 MPa (815 psia) and 1,316°C (2,400 ° F) to produce syngas

. The syngas consists primarily of hydrogen and carbon monoxide, with lesser amounts of water vapor and carbon dioxide, and small amounts of hydrogen sulfide, COS, methane, argon, and nitrogen. The heat in the gasifier liquefies coal ash. Hot syngas and molten solids from the reactor flow downward into a radiant heat exchanger where the syngas is cooled.

3.4.2.3 Raw Gas Cooling/Particulate Removal

Syngas is cooled from 1,316°C (2,400°F) to 677°C (1,250°F) in the radiant SGC (stream 9)

, and the molten slag solidif ies in the process. The solids collect in the water sump at the bottom of the gasifier and are removed periodically using a lock hopper system (stream 8). The waste heat from this cooling is used to generate HP steam. BFW in the tubes is saturated, and then steam and water are separated in a steam drum. Approximately 412,096 kg/hr (908,500 lb/hr) of saturated steam at 13.8 MPa (2,000 psia) is produced. This steam then forms part of the general heat recovery system that provides steam to the steam turbi ne.

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 q uench chamber saturated at a temperature of 232°C (450°F).

The slag handling system removes solids from the gasification process equipment. These solids consist of a small amount of unconverted carbon and essentially all of the ash contained in the

feed coal. These solids are in the form of glass, which fully encapsulates any metals. Solids collected in the water sump below the radiant SGC are removed by gravity and forced circulation of water from the lock hopper circulating pump. The fine solids not removed from the bottom of the quench water sump remain entrained in the water circulating through the quench chamber. InCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 168 order to limit the amount of solids recycled to the quench chamber, a continuous blowdown stream is removed from the bottom of the sy ngas quench. The blowdown is sent to the vacuum flash drum in the black water flash section. The circulating quench water is pumped by circulating pumps to the quench gasifier.

3.4.2.4 Syngas Scrubber/Sour Water Stripper

Syngas exiting the water quench passes to a syngas scrubber where a water wash is used to remove remaining chlorides, NH 3 

## , SO 2 

## , and PM. The syngas exits the scrubber still saturated at 206°C (403°F) before it is preheated to 223°C (433°F) (stream 10) prior to entering the COS hydrolysis reactor.

The sour water stripper removes NH 3 

## , SO 2 

## , and other impurities from the scrubber and other waste streams. The stripper consists of a sour drum that accumulates sour water from the gas

scrubber and condensate from SGCs. Sour water from the drum flows to the sour stripper, which consists of a packed column with a steam

- heated reboiler. Sour gas is stripped from the liquid and sent to the SRU. Remaining water is sent to wastewater treatment.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 169 Exhibit 3

- 75 Case B5A block flow diagram, GEE IGCC without CO 2 

### c apture

Source: NETL G AS
T URBINE C OMBUSTOR Q UENCH

A ND S YNGAS
S CRUBBER G AS C OOLING
BFW H EATING
& K NOCKOUT COS

H YDROLYSIS

E LEVATED
P RESSURE

ASU GEE G ASIFIER

S ECTION ( R ADIANT C OOLER ) S OUR
W ATER S TRIPPER M ERCURY
R EMOVAL S ELEXOL
U NIT C LAUS
P LANT

S YNGAS

H / P

R EHEAT

HRSG 2 X S TATE

- OF

- THE

A RT F

- C LASS
G AS T URBINES 1 A IR TO ASU

2 3

V ENT G AS 5 6 8

G ASIFIER
O XIDANT A S

- R ECEIVED
C OAL

S LAG 9 10 11 12 13 14 15

17

18

19 4

20 21

T URBINE C OOLING A IR 22 W ATER R ECYCLE TO
P ROCESS D EMAND

A MBIENT A IR F LUE G AS S TACK G AS S YNGAS
E XPANDER N OTE : W ATER FROM T AIL

GAS COOLER MODELED

, BUT NOT SHOWN

H YDROGENATION
R EACTOR AND G AS
C OOLER

16

T AIL G AS R ECYCLE TO
S ELEXOL

N OTE : T AIL G AS B OOST
C OMPRESSOR M ODELED

, BUT

NOT SHOWN C LEAN G AS

N ITROGEN D ILUENT

A IR S ULFUR
P RODUCT

S YNGAS C LAUS P LANT O XIDANT

23 C LAUS P LANT

O XIDANT

S TEAM
T URBINE 24 Note : Block Flow Diagram is not intended to represent a complete

material balance

. Only major process streams and equipment are shown

. S LURRY
M IXER

7

S LURRY

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



## 170 Exhibit 3

- 76 Case B5A stream table, GEE IGCC without capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V

- L Mole Fraction

Ar 0.0092 0.0234 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0068 0.0099 0.0097 0.0000

CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0012 0.0009 0.0009 0.0013 0.0013 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3579 0.2825 0.2825 0.4151 0.3977 0.0002

CO 2 0.0003 0.0081 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1366 0.1078 0.1079 0.1586 0.1811 0.6124

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 0.0000 0.0000

H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3416 0.2696 0.2696 0.3961 0.3812 0.0000

H 2 O 0.0099 0.2084 0.0000 0.0003 0.0000 0.0000 0.9994 0.0000 0.1358 0.3181 0.3180 0.0012 0.0012 0.0128

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0002 0.0000 0.0000 0.0000

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0059 0.0085 0.0086 0.1817

N 2 0.7732 0.5614 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0080 0.0063 0.0063 0.0092 0.0191 0.1905

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0021 0.0020 0.0020 0.0000 0.0000 0.0000

O 2 0.2074 0.1987 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0023

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 21,872 1,065 102 19,382 5,298 0 4,829 0 22,212 28,142 28,142 19,153 19,992 951

V

- L Flowrate (kg/hr) 631,159 28,895 3,290 543,851 170,484 0 87,000 0 446,029 552,590 552,590 390,592 422,589 36,883 Solids Flowrate (kg/hr) 0 0 0 0 0 211,781 0 23,236 0 0 0 0 0 0

Temperature (°C) 15 20 32 93 32 15 146 1,316 677 223 223 35 35 45 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.48 5.41 5.24 5.21 5.17 Steam Table Enthalpy (kJ/kg) A 30.23 36.81 26.67 92.52 26.67

--- 558.58

--- 1,427.78 1,067.54 1,067.44 40.35 36.92

- 1.24 AspenPlus Enthalpy (kJ/kg) B

- 97.58

- 2,311.18 4.13 63.39 4.13

- 2,116.95

- 15,404.71

- 727.24

- 5,219.35

- 7,386.27

- 7,386.27

- 5,336.38

- 5,478.96

- 6,427.70 Density (kg/m 3 ) 1.2 1.6 11.0 24.4 11.0

--- 866.9

--- 13.9 26.7 26.3 41.9 43.4 95.0

V

- L Molecular Weight 28.857 27.130 32.181 28.060 32.181

--- 18.015

--- 20.081 19.636 19.636 20.393 21.138 38.795

V

- L Flowrate (lb mole /hr) 48,220 2,348 225 42,729 11,679 0 10,647 0 48,969 62,042 62,042 42,225 44,075 2,096

V

- L Flowrate (lb/hr) 1,391,468 63,703 7,253 1,198,986 375,853 0 191,802 0 983,326 1,218,253 1,218,253 861,109 931,649 81,312 Solids Flowrate (lb/hr) 0 0 0 0 0 466,898 0 51,227 0 0 0 0 0 0

Temperature (°F) 59 68 90 199 90 59 295 2,400 1,250 433 433 95 94 112

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 795.0 785.0 760.0 755.0 750.0 Steam Table Enthalpy (Btu/lb) A 13.0 15.8 11.5 39.8 11.5

--- 240.1

--- 613.8 459.0 458.9 17.3 15.9

- 0.5 AspenPlus Enthalpy (Btu/lb) B

- 42.0

- 993.6 1.8 27.3 1.8

- 910.1

- 6,622.8

- 312.7

- 2,243.9

- 3,175.5

- 3,175.5

- 2,294.2

- 2,355.5

- 2,763.4 Density (lb/ft 3 ) 0.076 0.098 0.687 1.521 0.687

--- 54.120

--- 0.870 1.665 1.643 2.617 2.712 5.932

A 

### Steam table reference conditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atmCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 171 Exhibit 3

- 76 Case B5A stream table, GEE IGCC without capture (contin ued)

15 16 17 18 19 20 21 22 23 24

V

- L Mole Fraction

Ar 0.0000 0.0040 0.0100 0.0100 0.0100 0.0092 0.0092 0.0089 0.0089 0.0000

CH 4 0.0000 0.0000 0.0013 0.0013 0.0013 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0021 0.4089 0.4089 0.4089 0.0000 0.0000 0.0000 0.0000 0.0000

CO 2 0.0000 0.6947 0.1562 0.1562 0.1562 0.0003 0.0003 0.0807 0.0807 0.0000

COS 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 0.0000 0.0415 0.3920 0.3920 0.3920 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 0.0000 0.0018 0.0006 0.0006 0.0006 0.0099 0.0099 0.0638 0.0638 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 S 0.0000 0.0111 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N 2 0.0000 0.2448 0.0309 0.0309 0.0309 0.7732 0.7732 0.7427 0.7427 0.0000

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.2074 0.1039 0.1039 0.0000

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 0 839 19,445 19,445 19,445 110,253 4,410 136,883 136,883 35,596

V

- L Flowrate (kg/hr) 0 31,996 397,044 397,044 397,044 3,181,557 127,262 3,995,191 3,995,191 641,268 Solids Flowrate (kg/hr) 5,307 0 0 0 0 0 0 0 0 0

Temperature (°C) 174 38 45 241 196 15 432 589 132 561 Pressure (MPa, abs) 0.41 5.51 5.17 5.14 3.17 0.10 1.62 0.10 0.10 12.51 Steam Table Enthalpy (kJ/kg) A

--- - 5.04 54.55 365.19 296.11 30.23 463.79 741.45 235.13 3,502.79 AspenPlus Enthalpy (kJ/kg) B 138.98

- 7,219.57

- 5,220.07

- 4,909.43

- 4,978.51

- 97.58 335.98

- 999.91

- 1,506.23

- 12,467.52 Density (kg/m 3 ) 5,288.2 97.7 40.0 24.1 16.4 1.2 7.9 0.4 0.9 35.1

V

- L Molecular Weight

--- 38.145 20.419 20.419 20.419 28.857 28.857 29.187 29.187 18.015

V

- L Flowrate (lb mole /hr) 0 1,849 42,869 42,869 42,869 243,066 9,723 301,776 301,776 78,475

V

- L Flowrate (lb/hr) 0 70,540 875,333 875,333 875,333 7,014,133 280,565 8,807,888 8,807,888 1,413,754 Solids Flowrate (lb/hr) 11,699 0 0 0 0 0 0 0 0 0

Temperature (°F) 345 100 112 465 386 59 810 1,093 270 1,043 Pressure (psia) 59.3 799.5 750.0 745.0 460.0 14.7 234.9 15.2 15.2 1,814.7

Steam Table Enthalpy (Btu/lb) A

--- - 2.2 23.5 157.0 127.3 13.0 199.4 318.8 101.1 1,505.9 AspenPlus Enthalpy (Btu/lb) B 59.8

- 3,103.9

- 2,244.2

- 2,110.7

- 2,140.4

- 42.0 144.4

- 429.9

- 647.6

- 5,360.1 Density (lb/ft 3 ) 330.129 6.098 2.499 1.508 1.026 0.076 0.495 0.027 0.057 2.191

A 

### Steam table reference conditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atmCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 172 3.4.2.5 COS Hydrolysis, Mercury Removal and Acid Gas Remov al

Syngas exiting the scrubber (stream 10) passes through a COS hydrolysis reactor where about 99.5 percent of the COS is converted to CO 2 

## and H 2 

## S (Section 3.1.5 ). The gas exiting the COS reactor (stream 11) passes through a series of heat exchangers and knockout (KO) drums to lower the syngas temperature to 35°C (95°F) and to separate entrained water. The cooled syngas ( stream 12) then passes through dual carbon bed s to remove approximately 97 percent of the Hg (Section 3.1.4 ).

Cool, particulate

- free syngas (stream 13) enters the Selexol absorber unit at approximately

5.2 MPa (755 psia) and 34°C (94°F). In this absorber, H 2 

## S is preferentially removed from the fuel gas stream along with smaller amounts of CO 2 

## , 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 H 2 

## S concentrator. A portion of the non

- sulfur bearing absorbed gases is driven from the solvent in the H 2 

## S concentrator using N 2 

## from the ASU as the stripping medium. The temperature of the H 2 

## S concentrator overhead stream is reduced prior to entering the reabsorber where a second stage of H 2 

## S absorption occurs. The rich solvent from

the reabsorber is combined with the rich solvent from the absorber and sent to the stripper where it is regenerated through the indirect application of thermal energy via condensation of LP steam in a reboiler. The stripper acid gas stream (stream 14), consisting of 18 percent H 2 

## S and

61 percent CO 2 

## (with the balance mostly N 2 

## ), is then sent to the Claus unit.

3.4.2.6 Claus Unit

Acid gas from the first

- stage stripper of the Selexol unit is routed to the Claus plant. The Claus plant partially oxidizes the H 2 

## S in the acid gas to elemental sulfur. About 5,307 kg/hr (11,699 lb/hr) of elemental sulfur (stream 15) are recovered from the fuel gas stream. This value represents an overall sulfur recovery efficiency of 99.6 percent.

Acid gas from the Selexol unit is preheated to 232°C (450°F). A portion of the acid gas along with all of the sour gas from the stripper and oxygen from the ASU are fed to the Claus furnace.
In the furnace, H 2 

## S is catalytically oxidized to SO 2 

## at a furnace temperature greater than 1,343°C (2,450°F), which must be maintained in order to thermally decompose all of the NH 3 

## present in the sour gas stream.

Following the thermal stage and condensation of sulfur, two reheater and two sulfur converters are used to obtain a per

- pass H 2 

## S conversion of approximately 9 9.9 percent. The Claus Plant tail gas is hydrogenated and recycled back to the Selexol process (stream 16). In the furnace waste heat boiler, 12,432 kg/hr (27,408 lb/hr) of 4.2 MPa (605 psia) steam are generated. This steam is used to satisfy all Claus process preheating and reheating requirements as well as to produce

some steam for the medium

- pressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) of steam for the LP steam header and 2.9 MPa (415 psig) for IP steam.

3.4.2.7 Power Block

Clean s yngas exiting the Selexol absorber is re

- heated (stream 18) using HP BFW and then expanded to 3.2 MPa (460 psia) using an expansion turbine (stream 19). The syngas stream is diluted with nitrogen from the ASU (stream 4) and enters the state

- of

- the

- art 200 8 F

- class CT burner. The CT compressor provides combustion air to the burner and also 17 percent of the air requirements in the ASU (stream 21). The exhaust gas exits the CT at 589°C (1,093°F) (stream 22) and enters the HRSG where additional heat is reco vered until the flue gas exits the HRSG atCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 173 132°C (270°F) (stream 23) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced, commercially available steam turbine using a 12.4 MPa/562°C/562°C (1,800 psig/1,043° F/1,043°F) steam cycle 132°C (270°F) (stream 23) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced, commercially available steam turbine using a 12.4 MPa/562°C/562°C (1

, 800 psig/1

, 043°F/1

, 043°F) steam cyc le

.

3.4.2.8 Air Separation Unit

The elevated pressure ASU was described in Section 3.1.2 . In Case B5A the ASU is designed to produce a nominal output of 4,171 tonnes/day ( 4,597 tpd ) of 95 mol% O 2 

## for use in the gasifier (stream 5) and Claus plant (stream 3). The plant is designed with two production trains. The air compressor is powered by an electric motor. Approximately 13,051 tonnes/day (14,387 tpd ) of nitrogen is also recovered, compressed, and used for dilution in the CT combustor (stream 4). About 4 percent of the CT air is used to supply approximately 17 percent of the ASU air requirements (stream 21) in the non

- capture case

.

3.4.2.9 Balance of Plant

Balance of plant items were covered in Sections 3.1.9

, 3.1.10 , and 3.1.12

.


# 3.4.3 Key System Assumptions

System assumptions for c ases B5A , B5B, and B5B

- Q , GEE IGCC with and without CO 2 

## capture, are presented in Exhibit 3

- 7 7

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



## 174 Exhibit 3

- 77 GEE IGCC plant study configuration matrix

Case B5A B5B B5B

- Q

Gasifier Pressure, MPa (psia) 5.6 (815) 5.6 (815) 5.6 (815)

O 2 

### :Coal Ratio, kg O 2 

### /kg dry

coal 0.91 0.91 0.91

Carbon Conversion, % 98 98 98

Syngas HHV at Gasifier Outlet, kJ/Nm 3 

### (Btu/scf) 8,663 (233) 8,644 (232) 8,655 (232)

Steam Cycle, MPa/°C/°C (psig/ ° F/ ° F) 12.4/562/562 (1,800/1,043/1,043) 12.4/534/534 (1,800/994/994) 12.4/534/534 (1,800/994/994)

Condenser Pressure, mm Hg (in Hg) 51 (2.0) 51 (2.0) 51 (2.0)

Combustion Turbine 2x State

- of

- the

- Art 2008

F

- Class (232 MW output each) 2x State

- of

- the

- Art 2008

F

- Class (232 MW output each) 2x State

- of

- the

- Art 2008

F

- Class (232 MW output each)

Gasifier Technology GEE Radiant GEE Radiant GEE Quench

Oxidant 95 vol% Oxygen 95 vol% Oxygen 95 vol% Oxygen

Coal Illinois No. 6 Illinois No. 6 Illinois No. 6

Coal Slurry Solids Content,

% 63 63 63

COS Hydrolysis Yes Occurs in SGS Occurs in SGS

Sour Gas Shift No Yes Yes

H 2 

### S Separation Selexol Selexol 1 st 

### Stage Selexol 1 st 

### Stage

Sulfur Removal, % 99.7 99.9 99.8

Sulfur Recovery Claus Plant with Tail Gas Recycle to Selexol/

Elemental Sulfur Claus Plant with Tail Gas Recycle to Selexol/

Elemental Sulfur Claus Plant with Tail Gas Recycle to Selexol/

Elemental Sulfur

Particulate Control Water Quench, Scrubber,

and AGR Absorber Water Quench, Scrubber,

and AGR Absorber Water Quench, Scrubber,

and AGR A bsorber

Mercury Control Carbon Bed Carbon Bed Carbon Bed

NOx Control Multi Nozzle Quiet Combustor (MNQC) (LNB) and N 2 

### Dilution MNQC (LNB) and N 2 

### Dilution MNQC (LNB) and N 2 

### Dilution

CO 2 

### Separation N/A Selexol 2 nd 

### Stage Selexol 2 nd 

### Stage

Overall Carbon Capture N/A 90.0% 90.0%

CO 2 

### Sequestration N/A Off

- site Saline Formation Off

- site Saline FormationCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 175 3.4.3.1 Balance of Plant

– Cases B5A

, B5B , and B5B

- Q

The balance of plant assumptions are common to all cases and are presented in Exhibit 3

- 11

.


# 3.4.4 Sparing Philosophy

The sparing philosophy for cases B5A , B5B, and B5B

- Q is provided below. Dual trains are used

to accommodate the size of commercial CTs. There is no redundancy other than normal sparing of rotating equipment. The plant design consists of the following major subsystems:

• Two ASUs (2 x 50%)

• Two trains of slurry preparation and slurry pumps (2 x 50%)

• Two trains of gasification, including gasifier, SGC, qu ench and scrubber (2 x 50%)

• Two trains of syn gas clean

- up process (2 x 50%)

• Two trains of Selexol AGR, single

- stage in Case B5A and two

- stage in Case B5B, (2 x 50%) and o ne Claus

- based SRU (1 x 100%)

• Two CO 2 

## compression systems (2 x 50%) in cases B5B and B 5B

- Q

• Two CT/HRSG tandems (2 x 50%)

• One s team turbine (1 x 100%)



# 3.4.5 Case B5A

- Performance Results

The plant produces a net output of 622 MWe at a net plant efficiency of 39.0 percent (HHV basis). GEE has reported a net plant efficiency of 38.5 percent for th eir reference plant, and they also presented a range of efficiencies of 38.5

- 40 percent depending on fuel type

. (16)

, (51) Typically the higher efficiencies result from fuel blends that include petroleum coke.

Overall performance for the plant is summarized in Exhibit 3

- 78 ; Exhibit 3

- 79 provides a detailed breakdown of the auxiliary power requirements. The ASU accounts for approximately 78 percent of the auxiliary load between the m ain air compressor, nitrogen compressor, oxygen

compressor
, and ASU auxiliaries. The cooling water system, including the CWPs and the cooling tower fan, account s for approximately 5 percent of the auxiliary load, and the BFW pumps account for an additiona l 3 percent. All other individual auxiliary loads are less than 3 percent of the total.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 176 Exhibit 3

- 78 Case B5A plant performance summary

Performance Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 8

Steam Turbine Power, MWe 276

Total Gross Power, MWe 748

Air Separation Unit Main Air Compressor, kWe 53,820

Oxygen Compressor, kWe 10,260

Nitrogen Compressors, kWe 33,350

CO 2 Compression, kWe 0

Acid Gas Removal, kWe 2,590

Balance of Plant, kWe 25,840

Total Auxiliaries, MWe 126

Net Power, MWe 622

HHV Net Plant Efficiency (%) 39.0%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,240 (8,758)

HHV Cold Gas Efficiency, % 79.6%

HHV Combustion Turbine Efficiency, % 37.5%

LHV Net Plant Efficiency (%) 40.4%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,912 (8,447)

LHV Cold Gas Efficiency, % 76.2%

LHV Combustion Turbine Efficiency, % 40.6%

Steam Turbine Cycle Efficiency, % 43.3%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 8,323 (7,889)

Condenser Duty, GJ/hr ( MM Btu/hr) 1,536 (1,456)

As

- Received Coal Feed, kg/hr (lb/hr) 211,781 (466,898)

HHV Thermal Input, kWt 1,596,309

LHV Thermal Input, kWt 1,539,660

Raw Water Withdrawal, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.029 (7.6)

Raw Water Consumption, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.023 (6.1)

O 2 :Coal 0.761Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 177 Exhibit 3

- 79 Case B5A plant power summary

Power Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 8

Steam Turbine Power, MWe 276

Total Gross Power, MWe 748

Auxiliary Load Summary

Coal Handling, kWe 460

Coal Milling, kWe 2,180

Sour Water Recycle Slurry Pump, kWe 180

Slag Handling, kWe 1,120

Air Separation Unit Auxiliaries, kWe 1,000

Air Separation Unit Main Air Compressor, kWe 53,820

Oxygen Compressor, kWe 10,260

Nitrogen Compressors, kWe 33,350

Feedwater Pumps, kWe 3,980

Quench Water Pump, kWe 520

Syngas Recycle Compressor, kWe 0

CO 2 Compression, kWe 0

Scrubber Pumps, kWe 220

Acid Gas Removal, kWe 2,590

Combustion Turbine Auxiliaries, kWe 1,000

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 230

Circulating Water Pumps, kWe 4,220

Ground Water Pumps, kWe 430

Cooling Tower Fans, kWe 2,180

Claus Plant/TGTU Auxiliaries, kWe 250

Claus Plant TG Recycle Compressor, kWe 2,090

Miscellaneous Balance of Plant A,B 

### , kWe 3,000

Transformer Losses, kWe 2,680

Total Auxiliaries, MWe 126

Net Power, MWe 622

A 

### Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads



## 3.4.5.1 Environmental Performance

The environmental targets for emissions of Hg, NOx, SO 2 

## , and PM were presented in Section 2.4. A summary of the plant air emissions for Case B5A is presented in Exhibit 3

- 80

. All HCl is

assumed to be removed and is, therefore

, not reported.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 178 Exhibit 3

- 80 Case B5A air emissions

kg/GJ (lb/ MM Btu) Tonne/year (ton/year) A 

### kg/MWh (lb/MWh) B



### SO 2 

### 0.001 (0.001) 21 (24) 0.004 (0.0 09 )

NOx 0.025 (0.059) 1,023 (1,128) 0.195 (0.430)

Particulates 0.003 (0.0071) 123 (136) 0.023 (0.052)

Hg 1.77E

- 7 (4.12E

- 7) 0.007 (0.008) 1.36E

- 6 (3.00E

- 6)

CO 2 

### 85 ( 197 ) 3,407,878 (3,756,542) 650 (1,434)

CO 2 C



### - - 782 (1,724)

A 

### Calculations based on an 80 percent capacity factor

B 

### Emissions are based on gross power except where otherwise noted

C 

### CO 2 

### emissions based on net power instead of gross power



## The low level of SO 2 

## emissions is achieved by captur ing 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 H 2 

## S

- 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 H 2 

## S and then recycled back to the Selexol process, thereby eliminating the need for a tail gas

treatment unit.

NO x emissions are limited by nitrogen dilution of the syngas to 15 ppmvd (as NO 2 

## @15 percent

O 2 

## ). Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process and ul timately destroyed in the Claus plant burner. This helps lower NO x levels as

well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of the syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only.

Approximately 97 percent of the mercury is captured from the syngas by dual activated carbon

beds.

CO 2 

## emissions represent the uncontrolled discharge from the process.

The carbon balance for the plant is shown in Exhibit 3

- 81

. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since

the Aspen model accounts for air components thr oughout. Carbon leaves the plant as unburned carbon in the slag and as CO 2 

## in the stack gas and ASU vent gas.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 179 Exhibit 3

- 81 Case B5A carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 134,999 (297,623) Stack Gas 132,715 (292,586)

Air (CO 2 ) 519 (1,143) CO 2 Product 0 (0)

ASU Vent 103 (227)

Slag 2,700 (5,952)

Total 135,518 (298,766) Total 135,518 (298,766)



## Exhibit 3

- 82 shows the sulfur balances for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur emitted in the

stac k gas. Sulfur in the slag is considered to be negligible.

Exhibit 3

- 82 Case B5A sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 5,308 (11,702) Stack Gas 2 (3)

CO 2 Product 0 (0)

Elemental Sulfur (11,699)

Total 5,308 (11,702) Total 5,308 (11,702)



## Exhibit 3

- 83 shows the overall water balance for the plant. The water balance was explained in

cases B1A ( Shell ) and B4A ( E

- Gas TM 

## ), but is also presented here for completeness

Water demand represents the total amount of water required for a particular process. Some water is recovered within the process, primarily as syngas condensate, and is re

- used as internal recycle. The difference between demand and recycle is raw water withdrawal. Raw water

withdr awal is defined as the water removed from the ground or diverted from a surface

- water source for use in the plant . For this report, it was assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water withdrawal can be represented by the water metered from a raw water source and used in the plant processes for any and all purposes, such as cooling tower makeup, BFW makeup, quench system makeup, and slag handling makeup. The difference between water withdrawal and process water dis charge is defined as water consumption and can be represented by the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products

, or otherwise not returned to the water source from which it was withdrawn. Water consumptio n represents the net impact of the plant process

on the water source balance.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 180 Exhibit 3

- 83 Case B5A water balance

Water Use Water

Demand Internal Recycle Raw Water

Withdrawal Process

Water Discharge Raw Water Consumption

m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm)

Slag Handling 0.50 (133) 0.50 (133)

– – – Slurry Water 1.45 (384) 1.45 (384)

– – – Quench/Wash 2.75 (726) 0.90 (237) 1.85 (489)

– 1.85 (489)

Humidifier

– – – – – SWS Blowdown

– – – 0.03 (7.54)

- 0.03 (

- 7.54)
Condenser Makeup 0.20 (54)

– 0.20 (54)

– 0.20 (54)

BFW Makeup 0.20 (54)

– 0.20 (54)

– 0.20 (54)

Gasifier Steam

– – – – – Shift Steam

– – – – – CT Steam Dilution

– – – – – Cooling Tower 16.43 (4,341) 0.49 (129) 15.94 (4,211) 3.70 (976) 12.25 (3,235)

BFW Blowdown

– 0.20 (54)

- 0.20 (

- 54)

– - 0.20 (

- 54)

SWS Blowdown

– 0.29 (75.38) - 0.29 (

- 75.38) – - 0.29 (

- 75.38)

Total 21.34 (5,638) 3.34 (883) 18.00 (4,755) 3.72 (984) 14.27 (3,771)



## 3.4.5.2 Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3

- 84 through

Exhibit 3

- 86 :

• Coal gasification and ASU

• Syngas cleanup, sulfur recovery

, and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is provided in tabular form in Exhibit 3

- 87 . The power out is
the combined CT, steam t urbine

, and expander power prior to generator losses. The power at the generator terminals (shown in Exhibit 3

- 78 ) is calculated by multiplying the power out by a

co mbined generator efficiency of 98. 5 percent.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 181 This page intentionally left blankCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 182 Exhibit 3

- 84 Case B5A coal gasification and ASU heat and mass balance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 5 A

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 5 A

GEE G ASIFIER
ASU AND G ASIFICATION

DWG

. NO

. BB

- HMB

- CS

- B 5 A

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P AGES

1 OF 3 Four Stage Air Compressor

Elevated

Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU

Vent

1

, 391

, 468 W

59 T

15 P

13 H

375

, 853 W

90 T

125 P

11 H

375

, 853 W

241 T

940 P

41 H To Claus Plant 7

, 253 W

90 T

125 P

11 H 63

, 703 W

68 T

16 P

16 H

1

, 073

, 388 W

90 T

56 P

14 H

150

, 594 W

50 T

182 P

3 H 5 1

3 2

Slurry Mix

Tank

Slag 466

, 898 W

59 T

15 P

191

, 802 W

295 T

840 P

240 H

51

, 227 W

2

, 400 T

815 P 1

, 198

, 986 W

389 T

384 P

88 H

658

, 700 W

160 T

840 P 1

, 390

, 226 W

100 T

190 P

18 H

6 Air From GT Compressor 280

, 565 W

220 T

225 P

51 H

280

, 565 W

810 T

235 P

199 H 1

, 198

, 986 W

199 T

384 P

40 H

21

N 2 Boost Compressor 24

, 996 W

199 T

384 P

40 H 24

, 996 W

376 T

785 P

84 H

GE Energy

Gasifier

Radiant Syngas

Cooler Raw Fuel Gas

Syngas

Scrubber

Slag Quench

Section

Drag Conveyor 4

983

, 326 W

1

, 250 T

805 P

612 H 1

, 218

, 253 W

403 T

800 P

446 H

Syngas

Quench 1

, 346

, 408 W

450 T

805 P

536 H

8 9

363

, 082 W

371 T

1

, 200 P

329 H 370

, 996 W

403 T

800 P

418 H To Fuel Gas

Preheater From Fuel Gas

Preheater

To Sour Water Stripper

From Sour Water Stripper 66

, 538 W

293 T

115 P

236 H 7 370

, 996 W

150 T

1

, 205 P

118 H N 2 to GT

Combustor To HP Economizer 1

From HP

Economizer 2

N 2 to AGR Ambient Air

To Superheater From HP

Economizer 2 Notes : Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

Water Steam

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical Flue Gas /

Combustion

Products

Gross Plant Power : 748 MWe Auxiliary Load : 126 MWe

Net Plant Power : 622 MWe Net Plant Efficiency

, HHV : 39

. 0 %

Net Plant Heat Rate : 8

, 758 Btu / kWh Milled Coal

1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 183 Exhibit 3

- 85 Case B5A syngas cleanup heat and mass balance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 5 A

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 5 A

GEE G ASIFIER
G AS CLEANUP SYSTEM

DWG

. NO

. BB

- HMB

- CS

- B 5 A

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P AGES

2 OF 3 Mercury

Removal

Knock

Out

Drum

Sour

Drum Claus Plant

Tail

Gas Furnace Catalytic

Reactor

Beds

Sulfur

Syngas

Coolers

Sour Stripper 1

, 218

, 253 W

403 T

800 P

458 H 931

, 649 W

94 T

755 P

16 H 81

, 312 W

112 T

750 P

- 1 H 875

, 333 W

386 T

460 P

127 H

11

, 699 W

79

, 720 W

450 T

59 P

250 H

2

, 855 W

235 T

65 P

405 H 15

12

16

71

, 391 W

120 T

57 P

32 H 861

, 109 W

95 T

760 P

17 H

9

, 181 W

118 T

57 P

44 H 70

, 540 W

100 T

800 P

- 2 H 17 875

, 333 W

112 T

750 P

23 H

COS Hydrolysis 1

, 218

, 253 W

433 T

785 P

459 H 1

, 218

, 253 W

433 T

795 P

459 H

10 11

Clean

Gas Acid

Gas

13

AGR

- Selexol 14 Fuel Gas Expander 19

875

, 333 W

465 T

745 P

157 H 18

N 2 to AGR

24

, 996 W

90 T

785 P

9 H

Hydrogenation

and Tail Gas

Cooling

Tail Gas Recycle

Compressor

621

, 422 W Blowdown to Waste

Water Treatment Raw Syngas COS Hydrolysis

Preheater To Superheater From HP

Economizer 2

From Syngas

Scrubber Makeup Water

Reboiler

To Coal Slurry

, Syngas

Quench

, and Slag Quench Knock Out From Gland Steam

Condenser To Syngas Cooling

115 T 7

, 253 W

90 T

125 P

11 H 3 7

, 253 W

450 T

125 P

92 H

Claus Oxygen

Preheater

To

Deaerator

From IP

BFW From ASU Fuel Gas To CT To Syngas

Scrubber and HP

Economizer 1

Fuel Gas

Preheater

From Syngas

Scrubber and HP

Economizer 2

To Preheater and

LP Evaporator

From Tail Gas

Cooler and LP

Economizer Notes : Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas Sour Water Acid Gas

Tailgas Sour Gas

Sulfur Hydrogen

Water

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical Steam

1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psia

Gross Plant Power : 748 MWe Auxiliary Load : 126 MWe

Net Plant Power : 622 MWe Net Plant Efficiency

, HHV : 39

. 0 %

Net Plant Heat Rate : 8

, 758 Btu / kWhCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 184 Exhibit 3

- 86 Case B5A combined

- cycle power generation heat and mass b alance schematic

Source: NETL Notes :

DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 5 A

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 5 A

GEE G ASIFIER
P OWER B LOCK S YSTEM

DWG

. NO

. BB

- HMB

- CS

- B 5 A

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES
3 OF 3 Sour Gas

Sour Water

Water Steam

Flue Gas

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical

HP

Turbine IP

Turbine Nitrogen Diluent

Air Inlet

Filter

Ambient Air Steam Seal Regulator Blowdown

Flash

Gland

Steam

Condenser LP

Turbine Stack

Expander Compressor Fuel Gas Generator

Generator

Condensate Pumps Steam Turbine

State

- of

- the

- art 2008

F

- Class Turbine

7

, 014

, 133 W

59 T

15 P

13 H 1

, 581

, 175 W

101 T

1 P

69 H 8

, 807

, 888 W

270 T

15 P

101 H

875

, 333 W

386 T

460 P

127 H 1

, 413

, 754 W

1

, 043 T

1

, 815 P

1

, 498 H 9

, 644 W

298 T

65 P

1

, 171 H

1

, 542

, 249 W

512 T

65 P

1

, 280 H

1

, 581

, 175 W

103 T

120 P

71 H 1

, 400 W

662 T

65 P

1

, 354 H

1

, 400 W

212 T

15 P

180 H

20 24

19 23

Hot Well Condenser Make

- up

27

, 011 W

59 T

15 P

27 H 8

, 822 W

702 T

501 P

1

, 350 H

9

, 515 W

662 T

65 P

1

, 354 H 780 W

1

, 043 T

1

, 815 P

1

, 498 H 1

, 312 W

541 T

65 P

1

, 294 H Preheater Deaerator

Heater HP

Economizer

1 LP

Economizer HP

Economizer

2 HP Evaporator Superheater

/ Reheater

From Syngas Cooler To Radiant Syngas Cooler From Radiant Syngas

Cooler

To ASU and Fuel

Gas Preheater

Deaerator

HP Pump IP Pump From ASU and Fuel

Gas Preheater

LP Evaporator From Claus

, Process Extraction

, and 250 PSIA Header

LP Extraction Spray

LP Blowdown Hot Reheat 8

, 807

, 888 W

1

, 093 T

15 P

319 H 22

To WWT Process Extraction

LP Pump 235 T

274 T

1

, 932

, 503 W

274 T

45 P

242 H

1

, 440

, 746 W

279 T

2

, 251 P

247 H 9

, 663 W

274 T

79 P

242 H

7

, 083 W

274 T

79 P

242 H 45

, 731 W

276 T

615 P

244 H 240

, 921 W

351 T

2

, 251 P

319 H

305 T 585 T 636 T

26

, 992 W

585 T

2

, 001 P

593 H 636 T

908

, 447 W

585 T

2

, 001 P

585 H

1

, 385

, 727 W

702 T

501 P

1

, 351 H 240

, 921 W

585 T

2

, 001 P

585 H

1

, 198

, 986 W

385 T

389 P

87 H

21 Air Extraction

280

, 565 W

810 T

235 P

199 H 387

, 415 W

298 T

65 P

266 H

1

, 581

, 175 W

185 T

105 P

153 H

299

, 058 W

298 T

65 P

1

, 171 H

1

, 000 W

1

, 043 T

1

, 815 P

1

, 498 H 1

, 000 W

212 T

15 P

180 H 42

, 626 W

500 T

250 P

1

, 255 H IP Extraction Steam

to 250 PSIA Header

LP Extraction Spray # 1

Condensate to Tail Gas Cooling To Claus To Syngas

Coolers From Syngas

Coolers

1

, 043 T

Gross Plant Power : 748 MWe Auxiliary Load : 126 MWe

Net Plant Power : 622 MWe Net Plant Efficiency

, HHV : 39

. 0 %

Net Plant Heat Rate : 8

, 758 Btu / kWh

1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 185 This page intentionally left blankCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 186 Exhibit 3

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

HHV Sensible +

Latent Power Total

Heat In (GJ/hr)

Coal 5,747 (5,447) 4.8 (4.6)

– 5,752 (5,451)

Air

– 115.2 (109.2)

– 115.2 (109.2)

Raw Water Makeup

– 67.7 (64.1)

– 67.7 (64.1)

Auxiliary Power

– – 453 (429) 453 (429)

TOTAL 5,747 (5,447) 187.7 (177.9) 453 (429) 6,388 (6,054)

Heat Out (GJ/hr)

ASU Vent

– 1.1 (1.0)

– 1.1 (1.0)

Slag 88.5 (83.9) 36.3 (34.4)

– 124.8 (118.3)

Stack Gas

– 939 (890)

– 939 (890)

Sulfur 49.2 (46.6) 0.6 (0.6)

– 49.8 (47.2)

Motor Losses and Design

Allowances – – 53.9 (51.1) 53.9 (51.1)

Condenser

– 1,536 (1,456)

– 1,536 (1,456)

Non

- Condenser Cooling Tower

Loads – 458 (434)

– 458 (434)

CO 2 – – – –

Blowdown

– 41.0 (38.9)

– 41.0 (38.9)

CO 2 Capture Losses

– – – –

Ambient Losses A



### – 157.9 (149.6)

– 157.9 (149.6)

Power

– – 2,692 (2,552) 2,692 (2,552)

TOTAL 137.7 (130.5) 3,171 (3,005) 2,746 (2,603) 6,055 (5,739)

Unaccounted Energy B



### – 333 (316)

– 333 (316)

A 

### Ambient losses include all losses to the environment through radiation, convection, etc. Sources of these losses include the combustor, reheater, superheater, and transforme rs.

B 

### By difference

. 

# 3.4.6 Case B5A

- Major Equipment List

Major equipment items for the GEE gasifier with no CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in theCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 187 cost estimates in S ection 3.4.7 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

Case B5A

– Account 1: Coal Handling

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

5 Stacker/Reclaimer Traveling, linear 1,130 tonne/hr (1,250 tph) 1 0

6 Reclaim Hopper N/A 40 tonne (50 ton) 2 1

7 Feeder Vibratory 170 tonne/hr (190 tph) 2 1

8 Conveyor No. 3 Belt w/ tripper 350 tonne/hr (390 tph) 1 0

9 Coal Surge Bin w/ Vent Filter Dual outlet 170 tonne (190 ton) 2 0

10 Crusher Impactor reduction 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 2 0

11 Conveyor No. 4 Belt w/ tripper 350 tonne/hr (390 tph) 1 0

12 Conveyor No. 5 Belt w/ tripper 350 tonne/hr (390 tph) 1 0

13 Coal Silo w/ Vent Filter and

Slide Gates Field erected 780 tonne (860 ton) 3 0



## Case B5A

– Account 2: Coal Preparation and Feed

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 80 tonne/h (90 tph) 3 0

2 Conveyor No. 6 Belt w/ tripper 230 tonne/h (260 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 470 tonne (510 ton) 1 0

4 Weigh Feeder Belt 120 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 120 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank with Agitator Field erected 287,520 liters (75,950 gal) 2 0

7 Slurry Water Pumps Centrifugal 800 lpm (210 gpm) 2 1

8 Trommel Screen Coarse 160 tonne/h (180 tph) 2 0

9 Rod Mill Discharge Tank with Agitator Field erected 376,120 liters (99,360 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,100 lpm (800 gpm) 2 2

11 Slurry Storage Tank with Agitator Field erected 1,128,400 liters (298,100 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,300 lpm (1,700 gpm) 2 2

13 Slurry Product Pumps Positive displacement 3,100 lpm (800 gpm) 2 2



## Case B5A

– Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical,

outdoor 1,083,000 liters (286,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,620 lpm @ 90 m H 2 O (1,750 gpm @ 300 ft H 2 O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 494,000 kg/hr (1,088,000 lb/hr) 2 0

4 Intermediate

- Pressure Feedwater Pump Horizontal centrifugal, single stage 8,360 lpm @ 30 m H 2 O (2,210 gpm @ 90 ft H 2 O) 2 1

5 High

- Pressure Feedwater Pump No. 1 Barrel type, multi

stage, centrifugal HP water: 6,230 lpm @ 1,800 m H 2 O (1,650 gpm @ 6,100 ft H 2 O) 2 1Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 188 Equipment

No. Description Type Design Condition Operating Qty. Spares

6 High

- Pressure Feedwater Pump No. 2 Barrel type, multi

stage, centrifugal IP water: 1,040 lpm @ 220 m

H 2 O (280 gpm @ 730 ft H 2 O) 2 1

7 Auxiliary Boiler Shop fabricated, water

tube 18,000 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air Compressors Flooded Screw 28 m 3 

### / min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m 3 

### / min (1,000 scfm) 2 1

10 Closed Cycle Cooling Heat Exchangers Plate and frame 252 GJ/hr (239 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 90,400 lpm @ 20 m H 2 O (23,900 gpm @ 70 ft H 2 O) 2 1

12 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 110 m H 2 O (1,000 gpm @ 350 ft H 2 O) 1 1

13 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 80 m H 2 O (700 gpm @ 250 ft H 2 O) 1 1

14 Raw Water Pumps Stainless steel, single

suction 4,630 lpm @ 20 m H 2 O (1,220 gpm @ 60 ft H 2 O) 2 1

15 Ground Water Pumps Stainless steel, single

suction 3,080 lpm @ 270 m H 2 O (810 gpm @ 880 ft H 2 O) 3 1

16 Filtered Water Pumps Stainless steel, single

suction 2,090 lpm @ 50 m H 2 O (550 gpm @ 160 ft H 2 O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,002,000 liter (265,000 gal) 2 0

18 Makeup Water

Demineralizer Anion, cation, and

mixed bed 300 lpm (80 gpm) 2 0

19 Liquid Waste Treatment System N/A 10 years, 24

- hour storm 1 0



## Case B5A

– Account 4: Gasifier, ASU, and Accessories Including Low Temperature Heat Recovery and Fuel Gas Saturation

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized slurry

- feed,

entrained bed 2,800 tonne/day, 5.6 MPa (3,100 tpd, 815 psia) 2 0

2 Synthesis Gas Cooler Vertical downflow radiant heat exchanger

with outlet quench

chamber 245,000 kg/hr (541,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 336,000 kg/hr (741,000 lb/hr) Design efficiency 90% 2 0

4 Raw Gas Coolers Shell and tube with

condensate drain 216,000 kg/hr (476,000 lb/hr) 8 0

5 Raw Gas Knockout

Drum Vertical with mist

eliminator 215,000 kg/hr, 35°C, 5.3 MPa (475,000 lb/hr, 95°F, 765 psia) 2 0

6 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 336,000 kg/hr (741,000 lb/hr)

syngas 2 0

7 ASU Main Air Compressor Centrifugal, multi

- stage 5,000 m 3 

### / min @ 1.3 MPa (168,000 scfm @ 190 psia) 2 0

8 Cold Box Vendor design 2,300 tonne/day (2,500 tpd) of 95% purity oxygen 2 0

9 Oxygen Compressor Centrifugal, multi

- stage 1,000 m 3 

### / min (41,000 scfm)

Suction

- 1.0 MPa (130 psia) Discharge

- 6.5 MPa (940 psia) 2 0

10 Primary Nitrogen Compressor Centrifugal, multi

- stage 4,000 m 3 

### / min (133,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 2 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 189 Equipment

No. Description Type Design Condition Operating Qty. Spares

11 Secondary Nitrogen Compressor Centrifugal, single

stage 530 m 3 

### / min (19,000 scfm)

Suction

- 1.3 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 2 0

12 AGR Nitrogen Boost Compressor Centrifugal, single

stage 90 m 3 

### / min (3,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 5.4 MPa (790 psia) 2 0

13 Extraction Air Heat Exchanger Gas

- to

- gas, vendor design 70,000 kg/hr, 432°C, 1.6 MPa (154,000 lb/hr, 810°F, 235 psia) 2 0



## Case B5A

– Account 5: Syngas Cleanup

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber 1 Sulfated carbon bed 215,000 kg/hr (474,000 lb/hr)

, 35°C (95°F)

, 5.2 MPa (760 psia) 2 0

2 Mercury Adsorber 2 Sulfated carbon bed 215,000 kg/hr (474,000 lb/hr)

, 35°C (95°F)

, 5.2 MPa (760 psia) 2 0

3 Sulfur Plant Claus type 140 tonne/day (154 tpd) 1 0

4 COS Hydrolysis

Reactor Fixed bed, catalytic 304,000 kg/hr (670,000 lb/hr)

, 221°C (430°F)

, 5.4 MPa (790 psia) 2 0

5 Acid Gas Removal

Plant Selexol 232,000 kg/hr (512,000 lb/hr)

, 35°C (94°F)

, 5.2 MPa (755 psia) 2 0

6 Hydrogenation

Reactor Fixed bed, catalytic 40,000 kg/hr (88,000 lb/hr) 232°C (450°F) 0.4 MPa (58.9 psia) 1 0

7 Tail Gas Recycle Compressor Centrifugal 35,000 kg/hr (78,000 lb/hr) each 1 0



## Case B5A

– Account 6: Combustion Turbine and Auxiliaries

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Combustion Turbine State

- of

- the

- art

2008 F

- c lass 230 MW 2 0

2 Combustion Turbine

Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 2 0

3 Syngas Expansion

Turbine/Generator Turbo Expander 218,400 kg/h (481,400 lb/h) 5.1 MPa (745 psia) Inlet 3.2 MPa (460 psia) Outlet 2 0



## Case B5A

– Account 7: HRSG, Ducting, and Stack

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type

409SS liner 76 m (250 ft) high x 8.4 m (27 ft) diameter 1 0

2 Heat Recovery

Steam Generator Drum, multi

pressure with

economizer section and integral

deaerator Main steam

- 352,698 kg/hr,

12.4 MPa/561°C (777,565 lb/hr, 1,800 psig/1,043°F) 2 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 190 Case B5A

– Account 8: Steam Turbine Generator and Auxiliaries

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Steam

Turbine Commercially available

advanced steam turbine 291 MW
12.4 MPa/561°C/561°C (1,800 psig/ 1,043°F/1,043°F) 1 0

2 Steam

Turbine
Generator Hydrogen cooled, static

excitation 320 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 1 0

3 Surface

Condenser Single pass, divided waterbox including

vacuum pumps 1,690GJ/hr (1,600 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1 0

4 Steam Bypass One per HRSG 50% steam flow @ design steam

conditions 2 0



## Case B5A

– Account 9: Cooling Water System

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 423,000 lpm @ 30 m (112,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative, mechanical draft,

multi

- cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,360 GJ/hr (2,240 MMBtu/hr) heat duty 1 0



## Case B5A

– Account 10: Slag Recovery and Handling

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 244,000 liters (64,000 gal) 2 0

2 Slag Crusher Roll 13 tonne/hr (14 tph) 2 0

3 Slag Depressurizer Lock Hopper 13 tonne/hr (14 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 147,000 liters (39,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 66,000 liters (17,000 gal) 2 0

6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 2 0

7 Slag Separation Screen Vibrating 13 tonne/hr (14 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 13 tonne/hr (14 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 208,000 liters (55,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 50 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 2 2

11 Grey Water Storage Tank Field erected 66,000 liters (18,000 gal) 2 0

12 Grey Water Pumps Centrifugal 240 lpm @ 560 m H 2 O (60 gpm @ 1,850 ft H 2 O) 2 2

13 Slag Storage Bin Vertical, field erected 900 tonne (1,000 tons) 2 0

14 Unloading Equipment Telescoping chute 110 tonne/hr (120 tph) 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 191 Case B5A

– Account 11: Accessory Electric Plant

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 CTG Transformer Oil

- filled 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 2 0

2 STG Transformer Oil

- filled 24 kV/345 kV, 290 MVA, 3

- ph, 60 Hz 1 0

3 High Voltage Auxiliary

Transformer Oil

- filled 345 kV/13.8 kV, 54 MVA, 3

- ph, 60 Hz 2 0

4 Medium Voltage Transformer Oil

- filled 24 kV/4.16 kV, 29 MVA, 3

- ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 4 MVA, 3

- ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency

shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 0



## Case B5A

– Account 12: Instrumentation and Control

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 DCS

- Main
Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 0



# 3.4.7 Case B5A

- Cost Estimating

The cost estimating methodology was described previously in Section 2.6

. Exhibit 3

- 88 shows a detailed breakdown of the capital costs ; Exhibit 3

- 89 shows the owner’s costs, TOC, and TASC ; Exhibit 3

- 90 shows the initial and annual O&M costs; and Exhibit 3

- 91 shows the COE

breakdown.

The estimated TP C of the GEE gasifier with no CO 2 

## capture is $2,449 /kW. Process contingency

represents 2.5 percent of the TP C

, an d project contingency represents 13.5 percent. The COE is $ 102.6 /M Wh.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 192 Exhibit 3

- 88 Case B5 A total plant cost details

Case: B5 A

– GEE Radiant IGCC w/o CO 2 Estimate Type: Conceptual Plant Size (MW,net): 622 Cost Base : Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $4,435 $0 $2,137 $0 $6,572 $657 $0 $1,446 $8,675 $14

1.2 Coal Stackout & Reclaim $5,731 $0 $1,370 $0 $7,101 $710 $0 $1,562 $9,373 $15

1.3 Coal Conveyors & Yd Crush $5,328 $0 $1,356 $0 $6,684 $668 $0 $1,470 $8,823 $14

1.4 Other Coal Handling $1,394 $0 $314 $0 $1,708 $171 $0 $376 $2,254 $4

1.9 Coal & Sorbent Hnd. Foundations $0 $2,961 $7,739 $0 $10,701 $1,070 $0 $2,354 $14,125 $23

Subtotal $16,887 $2,961 $12,917 $0 $32,765 $3,277 $0 $7,208 $43,250 $70

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying w/ 2.3 $0 w/ 2.3 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,891 $454 $292 $0 $2,638 $264 $0 $580 $3,482 $6

2.3 Slurry Prep & Feed $25,812 $0 $11,252 $0 $37,064 $3,706 $1,853 $8,525 $51,149 $82

2.4 Misc. Coal Prep & Feed $1,040 $760 $2,238 $0 $4,037 $404 $0 $888 $5,329 $9

2.9 Coal & Sorbent Feed Foundation $0 $3,814 $3,273 $0 $7,087 $709 $0 $1,559 $9,355 $15

Subtotal $28,743 $5,028 $17,055 $0 $50,826 $5,083 $1,853 $11,552 $69,314 $111

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $3,461 $5,974 $3,132 $0 $12,567 $1,257 $0 $2,765 $16,589 $27

3.2 Water Makeup & Pretreating $758 $78 $416 $0 $1,252 $125 $0 $413 $1,791 $3

3.3 Other Feedwater Subsystems $1,946 $643 $575 $0 $3,164 $316 $0 $696 $4,176 $7

3.4 Service Water Systems $443 $883 $3,045 $0 $4,372 $437 $0 $1,443 $6,251 $10

3.5 Other Boiler Plant Systems $2,388 $892 $2,196 $0 $5,476 $548 $0 $1,205 $7,228 $12

3.6 FO Supply Sys & Nat Gas $17,740 $718 $665 $0 $19,123 $1,912 $0 $4,207 $25,242 $41

3.7 Waste Treatment Equipment $1,025 $0 $635 $0 $1,660 $166 $0 $548 $2,374 $4

3.8 Misc. Power Plant Equipment $1,277 $170 $664 $0 $2,111 $211 $0 $697 $3,019 $5

Subtotal $29,037 $9,360 $11,328 $0 $49,725 $4,972 $0 $11,973 $66,670 $107

4 Gasifier & Accessories

4.1 Syngas Cooler Gasifier System $136,778 $0 $75,333 $0 $212,111 $21,211 $29,509 $40,271 $303,102 $487

4.2 Syngas Cooler w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU & Oxidant Compression $195,452 $0 w/equip. $0 $195,452 $19,545 $0 $21,500 $236,496 $380

4.4 Scrubber & LT Heat Recovery $7,080 $5,763 $5,957 $0 $18,800 $1,880 $0 $4,136 $24,816 $40

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.6 Soot Recovery & SARU $2,159 $1,025 $2,013 $0 $5,197 $520 $0 $1,143 $6,860 $11

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $7,429 $6,482 $0 $13,911 $1,391 $0 $3,826 $19,128 $31

Subtotal $341,469 $14,218 $89,784 $0 $445,471 $44,547 $29,509 $70,875 $590,403 $949

5A Gas Cleanup & Piping

5A.1 Single Stage Selexol $50,584 $0 $42,628 $0 $93,212 $9,321 $0 $20,507 $123,040 $198

5A.2 Elemental Sulfur Plant $12,121 $2,363 $15,532 $0 $30,015 $3,002 $0 $6,603 $39,620 $64

5A.3 Mercury Removal $1,515 $0 $1,145 $0 $2,661 $266 $133 $612 $3,672 $6

5A.4 COS Hydrolysis $4,309 $0 $5,589 $0 $9,898 $990 $0 $2,178 $13,066 $21

5A.7 Fuel Gas Piping $0 $882 $577 $0 $1,459 $146 $0 $321 $1,926 $3Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 19 3 Case: B5 A

– GEE Radiant IGCC w/o CO 2 Estimate Type: Conceptual Plant Size (MW,net): 622 Cost Base : Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

5A.9 HGCU Foundations $0 $798 $538 $0 $1,336 $134 $0 $441 $1,911 $3

Subtotal $68,530 $4,043 $66,009 $0 $138,582 $13,858 $133 $30,662 $183,234 $295

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $104,200 $0 $7,506 $0 $111,706 $11,171 $5,585 $12,846 $141,308 $227

6.2 Syngas Expander $7,146 $0 $981 $0 $8,126 $813 $0 $1,341 $10,280 $17

6.9 Combustion Turbine Foundations $0 $1,016 $1,175 $0 $2,191 $219 $0 $723 $3,133 $5

Subtotal $111,346 $1,016 $9,662 $0 $122,024 $12,202 $5,585 $14,910 $154,721 $249

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $31,080 $0 $6,019 $0 $37,099 $3,710 $0 $4,081 $44,890 $72

7.3 Ductwork $0 $2,080 $1,458 $0 $3,538 $354 $0 $778 $4,670 $8

7.4 Stack $4,014 $0 $1,498 $0 $5,511 $551 $0 $606 $6,669 $11

7.9 HRSG, Duct & Stack Foundations $0 $764 $767 $0 $1,531 $153 $0 $505 $2,190 $4

Subtotal $35,094 $2,844 $9,741 $0 $47,679 $4,768 $0 $5,971 $58,418 $94

8 Steam Turbine Generator

8.1 Steam TG & Accessories $38,955 $0 $5,979 $0 $44,934 $4,493 $0 $4,943 $54,370 $87

8.2 Turbine Plant Auxiliaries $243 $0 $554 $0 $798 $80 $0 $88 $965 $2

8.3 Condenser & Auxiliaries $3,300 $0 $1,878 $0 $5,178 $518 $0 $570 $6,265 $10

8.4 Steam Piping $15,350 $0 $6,657 $0 $22,006 $2,201 $0 $6,052 $30,258 $49

8.9 TG Foundations $0 $1,147 $2,027 $0 $3,174 $317 $0 $1,047 $4,539 $7

Subtotal $57,848 $1,147 $17,094 $0 $76,089 $7,609 $0 $12,699 $96,397 $155

9 Cooling Water System

9.1 Cooling Towers $4,180 $0 $1,270 $0 $5,450 $545 $0 $899 $6,894 $11

9.2 Circulating Water Pumps $2,012 $0 $146 $0 $2,158 $216 $0 $356 $2,730 $4

9.3 Circ. Water System Auxiliaries $177 $0 $25 $0 $202 $20 $0 $33 $256 $0

9.4 Circ. Water Piping $0 $7,847 $1,901 $0 $9,747 $975 $0 $2,144 $12,867 $21

9.5 Make

- up Water System $428 $0 $589 $0 $1,017 $102 $0 $224 $1,342 $2

9.6 Component Cooling Water Sys $897 $1,073 $737 $0 $2,707 $271 $0 $595 $3,573 $6

9.9 Circ. Water System Foundations $0 $2,576 $4,576 $0 $7,152 $715 $0 $2,360 $10,227 $16

Subtotal $7,695 $11,495 $9,243 $0 $28,433 $2,843 $0 $6,612 $37,889 $61

10 Ash & Spent Sorbent Handling Systems

10.1 Slag Dewatering & Cooling $14,251 $7,858 $15,855 $0 $37,965 $3,797 $0 $4,176 $45,938 $74

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $693 $0 $749 $0 $1,442 $144 $0 $238 $1,825 $3

10.7 Ash Transport & Feed Equipment $954 $0 $223 $0 $1,177 $118 $0 $194 $1,489 $2

10.8 Misc. Ash Handling Equipment $1,436 $1,760 $522 $0 $3,718 $372 $0 $613 $4,703 $8

10.9 Ash/Spent Sorbent Foundation $0 $58 $76 $0 $135 $13 $0 $44 $193 $0

Subtotal $17,335 $9,676 $17,426 $0 $44,437 $4,444 $0 $5,266 $54,147 $87

11 Accessory Electric Plant

11.1 Generator Equipment $1,165 $0 $1,134 $0 $2,299 $230 $0 $253 $2,782 $4

11.2 Station Service Equipment $4,601 $0 $423 $0 $5,024 $502 $0 $553 $6,080 $10

11.3 Switchgear & Motor Control $8,493 $0 $1,579 $0 $10,071 $1,007 $0 $1,662 $12,740 $20Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 194 Case: B5 A

– GEE Radiant IGCC w/o CO 2 Estimate Type: Conceptual Plant Size (MW,net): 622 Cost Base : Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

11.4 Conduit & Cable Tray $0 $4,315 $13,302 $0 $17,617 $1,762 $0 $4,845 $24,223 $39

11.5 Wire & Cable $0 $8,320 $5,062 $0 $13,382 $1,338 $0 $3,680 $18,400 $30

11.6 Protective Equipment $0 $805 $2,988 $0 $3,793 $379 $0 $626 $4,798 $8

11.7 Standby Equipment $276 $0 $275 $0 $552 $55 $0 $91 $698 $1

11.8 Main Power Transformers $18,037 $0 $175 $0 $18,211 $1,821 $0 $3,005 $23,037 $37

11.9 Electrical Foundations $0 $183 $498 $0 $680 $68 $0 $225 $973 $2

Subtotal $32,572 $13,623 $25,436 $0 $71,630 $7,163 $0 $14,938 $93,732 $151

12 Instrumentation & Control

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,187 $0 $809 $0 $1,996 $200 $100 $344 $2,640 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $273 $0 $178 $0 $451 $45 $23 $104 $623 $1

12.7 Computer & Accessories $6,332 $0 $207 $0 $6,539 $654 $327 $752 $8,272 $13

12.8 Instrument Wiring & Tubing $0 $2,438 $4,614 $0 $7,052 $705 $353 $2,027 $10,137 $16

12.9 Other I & C Equipment $4,233 $0 $2,097 $0 $6,330 $633 $317 $1,092 $8,372 $13

Subtotal $12,025 $2,438 $7,906 $0 $22,368 $2,237 $1,118 $4,319 $30,043 $48

13 Improvements to Site

13.1 Site Preparation $0 $118 $2,689 $0 $2,807 $281 $0 $926 $4,014 $6

13.2 Site Improvements $0 $2,103 $2,973 $0 $5,077 $508 $0 $1,675 $7,260 $12

13.3 Site Facilities $3,769 $0 $4,231 $0 $8,000 $800 $0 $2,640 $11,440 $18

Subtotal $3,769 $2,222 $9,893 $0 $15,884 $1,588 $0 $5,242 $22,714 $37

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $317 $179 $0 $496 $50 $0 $109 $655 $1

14.2 Steam Turbine Building $0 $2,930 $4,172 $0 $7,102 $710 $0 $1,172 $8,984 $14

14.3 Administration Building $0 $1,013 $734 $0 $1,747 $175 $0 $288 $2,210 $4

14.4 Circulation Water Pumphouse $0 $200 $106 $0 $305 $31 $0 $50 $386 $1

14.5 Water Treatment Buildings $0 $623 $607 $0 $1,230 $123 $0 $203 $1,556 $3

14.6 Machine Shop $0 $518 $354 $0 $873 $87 $0 $144 $1,104 $2

14.7 Warehouse $0 $837 $540 $0 $1,377 $138 $0 $227 $1,742 $3

14.8 Other Buildings & Structures $0 $501 $390 $0 $891 $89 $0 $196 $1,177 $2

14.9 Waste Treating Building & Str. $0 $1,121 $2,140 $0 $3,261 $326 $0 $717 $4,304 $7

Subtotal $0 $8,059 $9,222 $0 $17,282 $1,728 $0 $3,107 $22,117 $36

Total $762,350 $88,130 $312,716 $0 $1,163,195 $116,320 $38,199 $205,336 $1,523,050 $2,449Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 195 Exhibit 3

- 89 Case B5A owner’s costs

Description $ / 1,000 $/kW

Pre

- Production Costs

6 Months All Labor $14,667 $24

1 Month Maintenance Materials $3,346 $5

1 Month Non

- fuel Consumables $452 $1

1 Month Waste Disposal $473 $1

25% of 1 Months Fuel Cost at 100% CF $2,920 $5

2% of TPC $30,461 $49

Total $52,318 $84

Inventory Capital

60

- day supply of fuel and consumables at 100% CF $23,916 $38

0.5% of TPC (spare parts) $7,615 $12

Total $31,532 $51

Other Costs

Initial Cost for Catalyst and Chemicals $11,013 $18

Land $900 $1

Other Owner's Costs $228,457 $367

Financing Costs $41,122 $66

Total Overnight Costs (TOC) $1,888,393 $3,036

TASC Multiplier (IOU, high

- risk, 35 year) 1.140

Total As

- Spent Cost (TASC) $2,152,768 $3,461Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 196 Exhibit 3

- 90 Case B5A initial and annual operating and maintenance costs

Case: B5 A

– GEE Radiant IGCC w/o CO 2 Cost Base: Jun 2011 Plant Size (MW,net): 622 Heat Rate

- net (Btu/kWh): 8, 758 Capacity Factor (%): 80
Operating & Maintenance Labor
Operating Labor Operating Labor Requirements per Shift
Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 Operating Labor Burden: 30.00 % of base Operator: 9.0

Labor O

- H Charge Rate: 25.00 % of labor Foreman: 1.0
Lab Tech's, etc.: 3.0

Total: 15.0 Fixed Operating Costs

Annual Cost ($) ($/kW

- net)
Annual Operating Labor: $6,781,554 $10.904

Maintenance Labor: $16,685,386 $26.828 Administrative & Support Labor: $5,866,735 $9.433

Property Taxes and Insurance: $30,460,991 $48.977

Total: $59,794,666 $96.142
Variable Operating Costs ($) ($/M Wh

- net)

Maintenance Material: $32,119,526 $7.36931

Consumables
Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill
Water (/1000 gallons): 0 3,423 $1.67 $0 $1,673,317 $0.38392 Makeup and Waste Water Treatment Chemicals (lbs): 0 20,395 $0.27 $0 $1,595,062 $0.36596

Carbon (Mercury Removal) (lb): 92,086 158 $5.50 $506,474 $253,237 $0.05810 COS Catalyst (m 3 ): 422 0.29 $3,751.70 $1,582,971 $316,594 $0.07264 Selexol Solution (gal): 242,554 36 $36.79 $8,923,873 $386,544 $0.08869

Claus Catalyst (ft 3 ): w/equip. 1.94 $203.15 $0 $115,175 $0.02643

Subtotal: $11,013,317 $4,339,929 $0.99573
Waste Disposal
Spent Mercury Catalyst (lb.): 0 158 $0.65 $0 $29,932 $0.00687 Flyash (ton): 0 0 $0.00 $0 $0 $0.00000

Slag (ton): 0 615 $25.11 $0 $4,507,185 $1.03410

Subtotal: $0 $4,537,118 $1.04097
By

- Products
Sulfur (tons): 0 140 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000 Variable Operating Costs Total: $11,013,317 $40,996,573 $9.40600

Fuel Cost
Illinois Number 6 (ton): 0 5,603 $68.54 $0 $112,132,176 $25.72691

Total: $0 $112,132,176 $25.72691



### Exhibit 3

- 91 Case B 5A COE breakdown

Component Value, $/M Wh Percentage

Capital 53.7 52%

Fixed 13.7 13%

Variable 9.4 9%

Fuel 25.7 25%

Total (Excluding T&S) 102.6 N/A

CO 2 

### T&S 0.0 0%

Total (Including T&S) 102.6 N/ACost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 197 

# 3.4.8 Case B5B

- GEE Radiant IGCC with CO 2 

# Capture

Case B5B is configured to produce electric power with CO 2 

## capture. The plant configuration is the same as Case B5A, namely two gasifier trains, two state

- of

- the

- art 2008 F

- class turbines, two HRSGs, and one steam turbine. The gross power output from the plant is constrained by the capacity of the two CTs, and since the CO 2 

## capture process increases the auxiliary load on the plant, the net output is significantly reduced rel ative to Case B5A.

The process description for Case B5B is similar to Case B5A with several notable exceptions to

accommodate CO 2 

## capture. A BFD and stream tables for Case B5B are shown in Exhibit 3

- 92

and Exhibit 3

- 93 , respectively. Instead of repeating the entire process description, only

differe nces from Case B5A are reported here.

3.4.8.1 Gasification

The gasification process is the same as Case B5A with the exception that total coal feed to the two gasifiers is 5,302 tonnes/day (5,844 tpd ) (stream 6) and the ASU provides 4,342 tonnes/day (4,786 tpd ) of 95 percent oxygen to the gasifier and Claus plant (streams 3 and 5).

3.4.8.2 Raw Gas Cooling /Particulate Removal

Raw gas cooling and particulate removal are the same as Case B5A with the exception that approximately 443,118 kg/hr (976,891 lb/hr) of saturated steam at 13.8 MPa (2,000 psia) is generated in the radiant SGCs.

3.4.8.3 Syngas Scrubber/Sour Water Stripper

No differences from Case B5A.

3.4.8.4 Sour Gas Shift

The SGS process was described in Section 3.1.3 . In Case B5B steam (stream 11) is added to the syngas exiting the scrubber to adjust the H 2 

## O: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 th at is added in stream 11. A second stage of SGS results in 97 percent overall conversion of the CO to CO 2 

## . The warm syngas from the second stage of SGS (stream 12) is cooled to 236°C (456°F) by preheating the unshifted syngas prior to the SGS. The SGS c atalyst also serves to hydrolyze COS

, thus eliminating the need for a separate COS hydrolysis reactor. Following the second SGS cooler

, the syngas is further cooled to 35°C (95°F) prior to the mercury removal beds.

3.4.8.5 Mercury Removal and AGR

Mercury removal is the same as in Case B5A.

The AGR process in Case B5B is a two

- stage Selexol process where H 2 

## S is removed in the first stage and CO 2 

## 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 CO 2



## - rich stream and an acid gas feed to the Claus plant. The acid gas (stream 18) contains 35 percent H 2 

## S and 52 percent CO 2 

## with

the balanc e primarily N 2 

## . The CO 2



## - rich stream is discussed further in the CO 2 

## compression

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



## 198 Exhibit 3

- 92 Case B5B block flow diagram , GEE IGCC with CO 2 

### capture

Source: NETL G AS
T URBINE C OMBUSTOR

T URBINE C OOLING A IR Q UENCH AND

S YNGAS
S CRUBBER G AS C OOLING
BFW H EATING
& K NOCKOUT S HIFT
R EACTORS

E LEVATED
P RESSURE

ASU GEE G ASIFIER

S ECTION ( R ADIANT C OOLER ) S OUR
W ATER S TRIPPER M ERCURY
R EMOVAL D UAL S TAGE
S ELEXOL

U NIT

C LAUS
P LANT

HRSG

A MBIENT A IR S YNGAS
E XPANDER

H YDROGENATION
R EACTOR AND G AS
C OOLER CO 2 C OMPRESSION

1 5 9 10 11 12 13 14

17 19

20

21 18

6 8

2 3 4

22 23 24 A IR TO ASU A S

- R ECEIVED
C OAL

S LAG S HIFT S TEAM

W ATER R ECYCLE

TO P ROCESS

D EMAND N OTE : W ATER FROM T AIL G AS C OOLER MODELED

,

BUT NOT SHOWN

N ITROGEN D ILUENT S YNGAS C LEAN G AS CO 2 S TREAMS CO 2 P RODUCT

S ULFUR

T AIL G AS
R ECYCLE TO

S ELEXOL N OTE : T AIL G AS B OOST
C OMPRESSOR MODELED

, BUT NOT SHOWN

F LUE G AS S TACK G AS

V ENT G AS C LAUS
P LANT O XIDANT

2 X S TATE

- OF

- THE

A RT F

- C LASS
G AS T URBINES S YNGAS
H / P

R EHEAT

15

16

C LAUS
P LANT O XIDANT

S TEAM
T URBINE 25

Note : Block Flow Diagram is not intended to represent a complete material balance

. Only major process streams and equipment are

shown

. 20

T AIL G AS
R ECYCLE F ROM
C LAUS P LANT

S LURRY
M IXER

7 S LURRY
W ATERCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 199 Exhibit 3

- 93 Case B5B stream table , GEE IGCC with c apture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V

- L Mole Fraction

Ar 0.0092 0.0166 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0054 0.0071 0.0071

CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0007 0.0009 0.0009

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2823 0.0000 0.0060 0.0078 0.0077

CO 2 0.0003 0.0054 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1089 0.0000 0.3082 0.4019 0.4055

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 0.0000 0.0000

H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2689 0.0000 0.4366 0.5692 0.5649

H 2 O 0.0099 0.1363 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3190 1.0000 0.2325 0.0012 0.0013

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0001 0.0000 0.0000

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0047 0.0061 0.0061

N 2 0.7732 0.7061 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0044 0.0058 0.0064

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0013 0.0000 0.0000

O 2 0.2074 0.1356 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 27,361 1,650 96 20,050 5,526 0 5,037 0 23,122 29,284 7,193 36,477 27,978 28,367

V

- L Flowrate (kg/hr) 789,549 45,326 3,080 562,613 177,826 0 90,747 0 465,238 575,977 129,586 705,563 552,385 564,913 Solids Flowrate (kg/hr) 0 0 0 0 0 220,902 0 24,237 0 0 0 0 0 0

Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 240 35 35 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.52 5.52 5.41 5.14 5.10 Steam Table Enthalpy (kJ/kg) A 30.23 35.64 26.67 92.50 26.67

--- 537.77

--- 1,428.30 1,066.52 2,917.15 942.88 37.11 36.40 AspenPlus Enthalpy (kJ/kg) B

- 97.58

- 1,492.10 4.13 63.47 4.13

- 2,116.95

- 15,427.03

- 727.24

- 5,246.11

- 7,406.90

- 13,053.16

- 8,863.69

- 8,084.69

- 8,087.64 Density (kg/m 3 ) 1.2 1.5 11.0 24.4 11.0

--- 872.0

--- 14.0 27.2 25.6 24.8 40.7 40.9

V

- L Molecular Weight 28.857 27.476 32.181 28.060 32.181

--- 18.015

--- 20.121 19.669 18.015 19.343 19.744 19.914

V

- L Flowrate (lb mole /hr) 60,320 3,637 211 44,204 12,182 0 11,105 0 50,975 64,560 15,858 80,418 61,680 62,539

V

- L Flowrate (lb/hr) 1,740,658 99,926 6,790 1,240,349 392,039 0 200,062 0 1,025,674 1,269,812 285,687 1,555,499 1,217,800 1,245,421 Solids Flowrate (lb/hr) 0 0 0 0 0 487,005 0 53,433 0 0 0 0 0 0

Temperature (°F) 59 65 90 199 90 59 287 2,400 1,250 403 550 463 95 95 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0 745.0 740.0 Steam Table Enthalpy (Btu/lb) A 13.0 15.3 11.5 39.8 11.5

--- 231.2

--- 614.1 458.5 1,254.1 405.4 16.0 15.7 AspenPlus Enthalpy (Btu/lb) B

- 42.0

- 641.5 1.8 27.3 1.8

- 910.1

- 6,632.4

- 312.7

- 2,255.4

- 3,184.4

- 5,611.9

- 3,810.7

- 3,475.8

- 3,477.1 Density (lb/ft 3 ) 0.076 0.091 0.687 1.521 0.687

--- 54.440

--- 0.871 1.699 1.597 1.550 2.544 2.552

A 

### Steam table reference conditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atmCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 200 Exhibit 3

- 93 Case B5B stream table , GEE IGCC with c apture (c ontinued)

15 16 17 18 19 20 21 22 23 24 25

V

- L Mole Fraction

Ar 0.0115 0.0115 0.0115 0.0002 0.0018 0.0000 0.0103 0.0092 0.0091 0.0091 0.0000

CH 4 0.0015 0.0015 0.0015 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0124 0.0124 0.0124 0.0002 0.0022 0.0000 0.0064 0.0000 0.0000 0.0000 0.0000

CO 2 0.0502 0.0502 0.0502 0.9948 0.5214 0.0000 0.6664 0.0003 0.0083 0.0083 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 0.9139 0.9139 0.9139 0.0048 0.1028 0.0000 0.2562 0.0000 0.0000 0.0000 0.0000

H 2 O 0.0001 0.0001 0.0001 0.0000 0.0226 0.0000 0.0017 0.0099 0.1222 0.1222 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 S 0.0000 0.0000 0.0000 0.0000 0.3477 0.0000 0.0050 0.0000 0.0000 0.0000 0.0000

N 2 0.0105 0.0105 0.0105 0.0000 0.0008 0.0000 0.0541 0.7732 0.7541 0.7541 0.0000

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1064 0.1064 0.0000

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 17,423 17,423 17,423 10,425 497 0 390 110,253 139,657 139,657 34,514

V

- L Flowrate (kg/hr) 90,178 90,178 90,178 456,650 17,683 0 12,529 3,181,557 3,834,349 3,834,349 621,772 Solids Flowrate (kg/hr) 0 0 0 0 0 5,524 0 0 0 0 0

Temperature (°C) 35 241 196 51 48 178 38 15 562 132 534 Pressure (MPa, abs) 5.10 5.07 3.17 15.27 0.16 0.12 5.51 0.10 0.10 0.10 12.51 Steam Table Enthalpy (kJ/kg) A 195.53 1,389.05 1,124.24

- 162.31 74.87

--- 5.30 30.23 834.76 343.83 3,432.88 AspenPlus Enthalpy (kJ/kg) B

- 4,051.34

- 2,857.82

- 3,122.63

- 9,120.19

- 6,107.59 141.99

- 8,217.57

- 97.58

- 587.80

- 1,078.73

- 12,537.44 Density (kg/m 3 ) 10.1 6.0 4.2 641.8 2.2 5,280.5 77.9 1.2 0.4 0.9 36.7

V

- L Molecular Weight 5.176 5.176 5.176 43.805 35.588

--- 32.150 28.857 27.456 27.456 18.015

V

- L Flowrate (lb mole /hr) 38,412 38,412 38,412 22,983 1,095 0 859 243,066 307,891 307,891 76,089

V

- L Flowrate (lb/hr) 198,808 198,808 198,808 1,006,740 38,985 0 27,621 7,014,133 8,453,292 8,453,292 1,370,772 Solids Flowrate (lb/hr) 0 0 0 0 0 12,178 0 0 0 0 0

Temperature (°F) 95 465 384 124 119 352 100 59 1,044 270 994 Pressure (psia) 740.0 735.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Steam Table Enthalpy (Btu/lb) A 84.1 597.2 483.3

- 69.8 32.2

--- 2.3 13.0 358.9 147.8 1,475.9 AspenPlus Enthalpy (Btu/lb) B

- 1,741.8

- 1,228.6

- 1,342.5

- 3,921.0

- 2,625.8 61.0

- 3,532.9

- 42.0

- 252.7

- 463.8

- 5,390.1 Density (lb/ft 3 ) 0.630 0.377 0.260 40.068 0.137 329.649 4.864 0.076 0.026 0.053 2.293

A 

### Steam table reference conditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atmCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 201 3.4.8.6 CO 2 

## Compression and Dehydration

CO 2 

## from the AGR process is flashed at three pressure levels to separate CO 2 

## and decrease H 2 

## losses to the CO 2 

## product pipeline. The HP CO 2 

## stream is flashed at 2.0 MPa (289.7 psia), compressed, and recycled back to the CO 2 

## absorber. The MP CO 2 

## stream is flashed at 1.0 MPa (149.7 psia). The LP CO 2 

## stream is flashed at 0.1 MPa (16.7 psia), compressed to 1.0 MPa (149.5 psia), and combined wit h the MP CO 2 

## stream. The combined stream is compressed from 2.1 MPa (149.5 psia) to a n SC condition at 15.3 MPa (2,215 psia) using a multiple

- stage, intercooled compressor. During compression, the CO 2 

## stream is dehydrated to a dew point

of

- 40oC (

- 40°F) with triethylene glycol. The raw CO 2 

## stream from the Selexol process contains over 99 percent CO 2 

## . The CO 2 

## (stream 17) is transported to the plant fence line and is sequestration ready. CO 2 

## T&S costs were estimated using the methodology described in Sec tion

2.6

.

3.4.8.7 Claus Unit

The Claus plant is the same as Case B5A with the following exceptions:

• 5,528 kg/hr (12,178 lb/hr) of sulfur (stream 19) are produced

• The waste heat boiler generates 13,555 kg/hr (29,884 lb/hr) of 4.0 MPa (575 psia) steam of which 12,679 kg/hr (27,953 lb/hr) is available to the medium pressure steam header

3.4.8.8 Power Block

Clean syngas from the AGR plant is heated to 241°C (465°F) using HP BFW before p assing through an expansion turbine. The clean syngas (stream 16) is diluted with nitrogen (stream 4) and then enters the CT burner. There is no integration between the CT and the ASU in this case. The exhaust gas (stream 22) exits the CT at 562°C (1

, 04 4°F) and enters the HRSG where

additional heat is recovered. The flue gas exits the HRSG at 132°C (270°F) (stream 23) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced commercially available steam turbin e using a 12.4 MPa/534°C/534°C (1

, 800 psig/994°F/994°F) steam cycle.

3.4.8.9 Air Separation Unit (ASU)

The same elevated pressure ASU is used in Case B5B and produces 4,342 tonnes/day (4,786 tpd ) of 95 mol% oxygen and 14,591 tonnes/day (16,084 tpd ) of nitrogen. There is no integration

between the ASU and the CT in the CO 2 

## capture case

.


# 3.4.9 Case B5B

- Performance Results

The Case B5B modeling assumptions were presented previously in Section 3.4.3

. The plant produces a net output of 543 MW at a net plant efficiency of 32.6 percent (HHV basis). Overall performance for the entire plant is summarized in Exhibit 3

- 94 ; Exhibit 3

- 95 provides a detailed breakdown of the auxiliary power requirements. The ASU accounts for nearly 60 percent of the auxiliary loa d between the main air compressor, nitrogen compressor, oxygen compressor, and ASU auxiliaries. The two

- stage Selexol process and CO 2 

## compression account for an additional 26 percent of the auxiliary power load. The BFW pumps and cooling water system (CW Ps and cooling tower fan) compose over 6 percent of the load, leaving 8 percent of the auxiliary load for all other systems.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 202 Exhibit 3

- 94 Case B 5B plant performance summary

Performance Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 7

Steam Turbine Power, MWe 264

Total Gross Power, MWe 734

Air Separation Unit Main Air Compressor, kWe 67,330

Oxygen Compressor, kWe 10,640

Nitrogen Compressors, kWe 35,640

CO 2 Compression, kWe 31,160

Acid Gas Removal, kWe 19,230

Balance of Plant, kWe 26,870

Total Auxiliaries, MWe 191

Net Power, MWe 543

HHV Net Plant Efficiency (%) 32.6%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,034 (10,459)

HHV Cold Gas Efficiency, % 79.2%

HHV Combustion Turbine Efficiency, % 36.0%

LHV Net Plant Efficiency (%) 33.8%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 10,643 (10,087)

LHV Cold Gas Efficiency, % 75.9%

LHV Combustion Turbine Efficiency, % 42.4%

Steam Turbine Cycle Efficiency, % 42.4%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 8,496 (8,053)

Condenser Duty, GJ/hr ( MM Btu/hr) 1,513 (1,434)

As

- Received Coal Feed, kg/hr (lb/hr) 220,902 (487,005)

HHV Thermal Input, kWt 1,665,056

LHV Thermal Input, kWt 1,605,967

Raw Water Withdrawal, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.041 (10.7)

Raw Water Consumption, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.033 (8.8)

O 2 :Coal 0.761Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 203 Exhibit 3

- 95 Case B 5B plant power summary

Power Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 7

Steam Turbine Power, MWe 264

Total Gross Power, MWe 734

Auxiliary Load Summary

Coal Handling, kWe 470

Coal Milling, kWe 2,270

Sour Water Recycle Slurry Pump, kWe 190

Slag Handling, kWe 1,160

Air Separation Unit Auxiliaries, kWe 1,000

Air Separation Unit Main Air Compressor, kWe 67,330

Oxygen Compressor, kWe 10,640

Nitrogen Compressors, kWe 35,640

Feedwater Pumps, kWe 4,180

Quench Water Pump, kWe 540

Syngas Recycle Compressor, kWe 0

CO 2 Compression, kWe 31,160

Scrubber Pumps, kWe 230

Acid Gas Removal, kWe 19,230

Combustion Turbine Auxiliaries, kWe 1,000

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 280

Circulating Water Pumps, kWe 4,630

Ground Water Pumps, kWe 530

Cooling Tower Fans, kWe 2,400

Claus Plant/TGTU Auxiliaries, kWe 250

Claus Plant TG Recycle Compressor, kWe 1,780

Miscellaneous Balance of Plant A,B 

### , kWe 3,000

Transformer Losses, kWe 2,860

Total Auxiliaries, MWe 191

Net Power, MWe 543

A 

### Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loadsCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 204 3.4.9.1 Environmental Performance

The environmental targets for emissions of Hg, NOx, SO 2 

## , and PM were presented in Section 2.4. A summary of the plant air emissions for Case B5B is presented in Exhibit 3

- 96

. All HCl is

assumed to be removed and is, therefore

, not reported.

Exhibit 3

- 96 Case B5B air emissions

kg/GJ (lb/ MM Btu) Tonne/year (ton/year) A 

### kg/MWh (lb/MWh) B



### SO 2 

### 0.001 (0.002) 39 (43) 0.008 (0.0 17 )

NOx 0.021 (0.049) 878 (967) 0.171 (0.376)

Particulates 0.003 (0.0071) 128 (141) 0.025 (0.055)

Hg 1.67E

- 7 (3.88E

- 7) 0.007 (0.008) 1.36E

- 6 (3.00E

- 6)

CO 2 

### 8 ( 20 ) 355,435 (391,800) 69 (152)

CO 2 C



### - - 93 (206)

A 

### Calculations based on an 80 percent capacity factor

B 

### Emissions are based on gross power except where otherwise noted

C 

### CO 2 

### emissions based on net power instead of gross power



## The low level of SO 2 

## emissions is achieved by captur ing the sulfur in the gas by the two

- stage Selexol AGR process. As a result of achieving the 90 percent CO 2 

## removal target, the sulfur compounds are removed to an extent that exceeds the environmental target in Section 2.3 . The clean syngas exiting the AGR process has a sulfur concentration of approximately 5 ppmv. This

results in a concentration in the flue gas of less than 1 ppmv. The H 2 

## S

- 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 H 2 

## S and then recycled back to the Selexol process, thereby eliminating the need for a tail gas treatment unit.

NO x emissions are limited by nitrogen dilution to 15 ppmvd (as NO 2 

## @15 percent O 2 

## ). Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process. This helps lower NO x levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of the syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only.

Approximately 97 percent of the mercury is captured from the syngas by dual activated carbon

beds.

Ninety two percent of the CO 2 

## from the syngas is captured in the AGR system and compressed for sequestration. Because not all CO is conver ted to CO 2 

## in the shift reactors, the overall carbon removal is 90.0 percent.

The carbon balance for the plant is shown in Exhibit 3

- 97

. The carbon input to the plant consists

of carbon in the air in a ddition to carbon in the coal. Carbon leaves the plant as unburned carbon in the slag and as CO 2 

## in the stack gas, ASU vent gas, and the captured CO 2 

## product. The carbon capture efficiency is defined as one minus the amount of carbon in the stack gas relative to the total carbon in less carbon contained in the slag , represented by the following fraction:Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 205 CCCCCCCCCC SS SSSS
( TT TT CCCCCCCCCC )

− ( CCCCCCCCCC SS SS ) = � 1

− � 30

, 516

311

, 631

− 6

, 209 �

∗ � 100 = 90

. 0%

Exhibit 3

- 97 Case B5B carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 140,813 (310,440) Stack Gas 13,842 (30,516)

Air (CO 2 ) 540 (1,191) CO 2 Product 124,589 (274,672)

ASU Vent 107 (237)

Slag 2,816 (6,209)

Total 141,353 (311,631) Total 141,353 (311,631)



## Exhibit 3

- 98 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur emitted in the

stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 3

- 98 Case B5B sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 5,537 (12,206) Stack Gas 3 (6)

CO 2 Product 10 (23)

Elemental Sulfur 5,524 (12,178)

Total 5,537 (12,206) Total 5,537 (12,206)



## Exhibit 3

- 99 shows the overall water balance for the plant. The exhibit is presented in an

identical manner as for cases B1 A

- B5A

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



## 206 Exhibit 3

- 99 Case B5B water balance

Water Use Water

Demand Internal Recycle Raw Water

Withdrawal Process

Water Discharge Raw Water Consumption

m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm)

Slag Handling 0.53 (139) 0.53 (139)

– – –
Slurry Water 1.51 (400) 1.51 (400)

– – –

Quench/Wash 2.86 (757) 0.72 (191) 2.14 (566)

– 2.14 (566)

Humidifier

– – – – –

SWS Blowdown

– – – 0.03 (7.30)

- 0.03 (

- 7.30)

Condenser Makeup 2.37 (627)

– 2.37 (627)

– 2.37 (627)

BFW Makeup 0.21 (56)

– 0.21 (56)

– 0.21 (56)

Gasifier Steam

– – – – –

Shift Steam 2.16 (571)

– 2.16 (571)

– 2.16 (571)

CT Steam Dilution

– – – – –

Cooling Tower 18.06 (4,770) 0.49 (129) 17.57 (4,641) 4.06 (1,073) 13.51 (3,568)

BFW Blowdown

– 0.21 (56)

- 0.21 (

- 56)

– - 0.21 (

- 56)

SWS Blowdown

– 0.28 (72.96) - 0.28 (

- 72.96) – - 0.28 (

- 72.96)

Total 25.33 (6,692) 3.25 (858) 22.08 (5,834) 4.09 (1,080) 18.00 (4,754)



## 3.4.9.2 Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3

- 100 through Exhibit 3

- 102 :

• Coal gasification and ASU

• Syngas cleanup, sulfur recovery, and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is presented in tabular form in Exhibit 3

- 103 . The power out is
the combined CT, steam turbine

, and expander power prior to generator losses. The power at the generator terminals (shown in Exhibit 3

- 94 ) is calculated by multiplying the power out by a combined generator efficiency of 98. 5 percent.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 207 Exhibit 3

- 100 Case B5B coal gasification and ASU heat and mass balance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 5 B

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 5 B

GEE G ASIFIER
ASU AND G ASIFICATION

DWG

. NO

. BB

- HMB

- CS

- B 5 B

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P AGES

1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated

Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU

Vent

1

, 740

, 658 W

59 T

15 P

13 H

392

, 039 W

90 T

125 P

11 H

392

, 039 W

241 T

940 P

41 H To Claus Plant 6

, 790 W

90 T

125 P

11 H 99

, 926 W

65 T

16 P

15 H

1

, 083

, 575 W

90 T

56 P

14 H

156

, 775 W

50 T

182 P

3 H 5 1

3 2

Slurry Mix

Tank

Slag 487

, 005 W

59 T

15 P

200

, 062 W

287 T

840 P

231 H

53

, 433 W

2

, 400 T

815 P 676

, 490 W

385 T

384 P

87 H

687

, 067 W

156 T

840 P 1

, 739

, 104 W

100 T

190 P

18 H

6 676

, 490 W

199 T

384 P

40 H

N 2 Boost Compressor 563

, 859 W

199 T

384 P

40 H 563

, 859 W

385 T

469 P

87 H

GE Energy

Gasifier

Radiant Syngas

Cooler Syngas

Scrubber

Slag Quench

Section

Drag Conveyor 4

1

, 025

, 674 W

1

, 250 T

805 P

612 H 1

, 269

, 812 W

403 T

800 P

458 H

Syngas

Quench 1

, 403

, 971 W

450 T

805 P

536 H

8 9 10

378

, 297 W

371 T

1

, 200 P

329 H

From Sour Water Stripper To Fuel Gas

Preheater From Fuel Gas

Preheater

386

, 894 W

403 T

800 P

419 H 386

, 894 W

150 T

1

, 205 P

118 H

To Sour Water Stripper

69

, 404 W

286 T

115 P

228 H 7 N 2 to GT Combustor

N 2 to GT Combustor

Raw Fuel Gas From HP

Economizer 2 To HP Economizer 1

To Superheater

From HP

Economizer 2 Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

Water Steam

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical Flue Gas /

Combustion

Products

Gross Plant Power : 734 MWe Auxiliary Load : 191 MWe

Net Plant Power : 543 MWe Net Plant Efficiency

, HHV : 32

. 6 %

Net Plant Heat Rate : 10

, 459 Btu / kWh Milled Coal

Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 208 Exhibit 3

- 101 Case B5B syngas cleanup heat and mass balance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 5 B

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 5 B

GEE G ASIFIER
G AS CLEANUP SYSTEM

DWG

. NO

. BB

- HMB

- CS

- B 5 B

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P AGES

2 OF 3 Mercury

Removal

Knock

Out

Drum

Sour

Drum Claus Plant

Tail

Gas Furnace Catalytic

Reactor

Beds

Sulfur

Knock Out Syngas

Coolers

Sour Stripper 1

, 269

, 812 W

403 T

800 P

458 H 1

, 245

, 421 W

95 T

740 P

16 H 38

, 985 W

119 T

24 P

32 H 198

, 808 W

384 T

460 P

483 H

12

, 178 W 36

, 092 W

450 T

12 P

458 H

2

, 495 W

239 T

65 P

442 H 19

13 20

36

, 092 W

550 T

11 P

419 H 1

, 217

, 800 W

95 T

745 P

16 H

8

, 470 W

114 T

11 P

40 H 27

, 621 W

100 T

800 P

2 H 15 198

, 808 W

95 T

740 P

84 H

18 Fuel Gas Expander 16

198

, 808 W

465 T

735 P

597 H

High Temperature

Shift # 1 Low Temperature

Shift # 2

12 11

1

, 269

, 812 W

413 T

795 P

450 H 285

, 687 W

550 T

800 P

1

, 246 H 1

, 555

, 499 W

436 T

795 P

598 H 1

, 555

, 499 W

776 T

795 P

582 H 1

, 555

, 499 W

400 T

795 P

408 H

1

, 555

, 499 W

463 T

785 P

405 H

1

, 555

, 499 W

456 T

780 P

402 H Two

- Stage

Selexol Clean

Gas

CO 2 Acid

Gas

Multistage

Intercooled CO 2

Compressor

Interstage Knockout 17

10 14

1

, 006

, 740 W

124 T

2

, 215 P

- 70 H

Tail Gas Recycle

Compressor Hydrogenation

and Tail Gas

Cooling From IP

BFW To Reheater

and Shift Steam

From IP BFW

, LP BFW

, and Tail Gas Cooling

647

, 763 W From Syngas

Scrubber

To Coal Slurry

, Syngas Quench

, and Slag Quench To Water

Treatment Makeup Water Raw Syngas COS Hydrolysis

Preheater

Reboiler From Syngas

Scrubber and HP

Economizer 2 To Syngas

Scrubber and HP

Economizer 1

Fuel Gas

Preheater Fuel Gas to CT

3 6

, 790 W

90 T

125 P

11 H 6

, 790 W

450 T

125 P

92 H

To

Deaerator

From IP

BFW Claus Oxygen

Preheater

From Gland Steam

Condenser To Syngas Cooling

109 T CO 2 Product To LP Turbine

, Preheater

WGS / Gasifier Steam

and Reheater Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas Sour Water Acid Gas

Tailgas Carbon Dioxide

Sour Gas

Sulfur Hydrogen

Water

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical Steam

Gross Plant Power : 734 MWe Auxiliary Load : 191 MWe

Net Plant Power : 543 MWe Net Plant Efficiency

, HHV : 32

. 6 %

Net Plant Heat Rate : 10

, 459 Btu / kWh Shift Steam

Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 209 Exhibit 3

- 102 Case B5B combined

- cycle power generation heat and mass balance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 5 B

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 5 B

GEE G ASIFIER
P OWER B LOCK S YSTEM

DWG

. NO

. BB

- HMB

- CS

- B 5 B

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES
3 OF 3 Sour Gas

Sour Water

Water Steam

Flue Gas

HP

Turbine IP

Turbine

Air Inlet

Filter Steam Seal Regulator

Gland

Steam

Condenser LP

Turbine Stack

Expander Compressor Generator

Generator

Condensate Pumps Steam Turbine

State

- of

- the

- art 2008

F

- Class Turbine

7

, 014

, 133 W

59 T

15 P

13 H 1

, 875

, 814 W

101 T

1 P

69 H 8

, 453

, 292 W

270 T

15 P

148 H

198

, 808 W

384 T

460 P

483 H 1

, 370

, 772 W

994 T

1

, 815 P

1

, 468 H 10

, 302 W

298 T

65 P

1

, 171 H

1

, 550

, 148 W

475 T

65 P

1

, 262 H

1

, 875

, 814 W

103 T

120 P

71 H 1

, 400 W

615 T

65 P

1

, 331 H

1

, 400 W

212 T

15 P

180 H

21 24

16 23

Hot Well Condenser Make

- up

313

, 504 W

59 T

15 P

27 H 9

, 026 W

660 T

501 P

1

, 327 H

9

, 761 W

615 T

65 P

1

, 331 H 798 W

994 T

1

, 815 P

1

, 468 H 1

, 337 W

505 T

65 P

1

, 277 H Preheater Deaerator

Heater HP

Economizer

1 LP

Economizer HP

Economizer

2 HP Evaporator Superheater

/ Reheater

From Syngas

Cooler HP BFW to

Radiant Syngas Cooler From Radiant Syngas

Cooler

To ASU and Fuel

Gas Preheater

Deaerator

HP Pump IP Pump LP Evaporator

IP to Syngas and

WGS Coolers WGS Shift

Steam From Claus

, Process Extraction

, and 250 PSIA Header

LP Extraction Spray

LP Blowdown LP To Syngas

Coolers Cold Reheat

Hot Reheat 8

, 453

, 292 W

1

, 044 T

15 P

359 H 22

To WWT Process

Extraction

LP Pump LP From Syngas Coolers

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical 235 T

274 T

1

, 857

, 220 W

274 T

45 P

242 H

1

, 398

, 890 W

279 T

2

, 251 P

247 H 9

, 286 W

274 T

79 P

242 H

6

, 109 W

274 T

79 P

242 H 294

, 721 W

274 T

79 P

242 H 39

, 399 W

276 T

615 P

244 H 397

, 467 W

351 T

2

, 251 P

319 H

305 T 585 T 636 T

28

, 833 W

585 T

2

, 001 P

585 H 285

, 687 W

550 T

805 P

1

, 221 H 550 T 636 T

976

, 880 W

585 T

2

, 001 P

585 H

1

, 342

, 123 W

661 T

501 P

1

, 327 H 397

, 467 W

585 T

2

, 001 P

585 H 303

, 963 W

298 T

65 P

266 H

195 T

224

, 565 W

298 T

65 P

1

, 171 H 148

, 214 W

298 T

65 P

1

, 171 H 293

, 460 W

276 T

820 P

244 H

1

, 000 W

994 T

1

, 815 P

1

, 468 H 1

, 000 W

212 T

15 P

180 H 40

, 696 W

500 T

250 P

1

, 255 H IP Extraction Steam

to 250 PSIA Header

LP Extraction Spray # 1

Condensate to Tail Gas Cooling 676

, 490 W

385 T

469 P

87 H Nitrogen Diluent

Fuel Gas

Ambient Air 7

, 773 W

550 T

805 P

1

, 221 H IP From Syngas and WGS

Coolers

994 T 298 T From ASU and Fuel

Gas Preheater

Nitrogen Diluent

563

, 859 W

385 T

384 P

87 H Blowdown

Flash

Gross Plant Power : 734 MWe Auxiliary Load : 191 MWe

Net Plant Power : 543 MWe Net Plant Efficiency

, HHV : 32

. 6 %

Net Plant Heat Rate : 10

, 459 Btu / kWh To Claus

Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 210 This page intentionally left blankCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 211 Exhibit 3

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

HHV Sensible +

Latent Power Total

Heat In (GJ/hr)

Coal 5,994 (5,681) 5.0 (4.7)

– 5,999 (5,686)

Air

– 120.0 (113.8)

– 120.0 (113.8)

Raw Water Makeup

– 83.0 (78.7)

– 83.0 (78.7)

Auxiliary Power

– – 687 (651) 687 (651)

TOTAL 5,994 (5,681) 208.1 (197.2) 687 (651) 6,889 (6,530)
Heat Out (GJ/hr)

ASU Vent

– 1.6 (1.5)

– 1.6 (1.5)
Slag 92.3 (87.5) 37.8 (35.9)

– 130.2 (123.4)

Stack Gas

– 1,318 (1,250)

– 1,318 (1,250)

Sulfur 51.2 (48.5) 0.6 (0.6)

– 51.8 (49.1)

Motor Losses and Design

Allowances – – 60.1 (57.0) 60.1 (57.0)

Condenser

– 1,513 (1,434)

– 1,513 (1,434)

Non

- Condenser Cooling Tower

Loads – 668 (633)

– 668 (633)

CO 2 – - 74.1 (

- 70.2)

– - 74.1 (

- 70.2)

Blowdown

– 43.3 (41.0)

– 43.3 (41.0)

CO 2 Capture Losses

– 176.4 (167.2)

– 176.4 (167.2)

Ambient Losses A



### – 162.4 (154.0)

– 162.4 (154.0)

Power

– – 2,643 (2,505) 2,643 (2,505)

TOTAL 143.5 (136.0) 3,848 (3,647) 2,703 (2,562) 6,694 (6,345)

Unaccounted Energy B



### – 195 (185)

– 195 (185)

A 

### Ambient losses include all losses to the environment through radiation, convection, etc. Sources of these losses include the combustor, reheater, superheater, and transformers.



# 3.4.10 Case B5B

- Major Equipment List

Major equipment items for the GEE gasifier with CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost

estimates in Section 3.4.11 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 212 Case B5 B

– Account 1: Coal Handling

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

5 Stacker/Reclaimer Traveling, linear 1,130 tonne/hr (1,250 tph) 1 0

6 Reclaim Hopper N/A 50 tonne (50 ton) 2 1

7 Feeder Vibratory 180 tonne/hr (200 tph) 2 1

8 Conveyor No. 3 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

9 Coal Surge Bin w/ Vent Filter Dual outlet 180 tonne (200 ton) 2 0

10 Crusher Impactor reduction 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 2 0

11 Conveyor No. 4 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

12 Conveyor No. 5 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

13 Coal Silo w/ Vent Filter and
Slide Gates Field erected 800 tonne (900 ton) 3 0



## Case B5B

– Account 2: Coal Preparation and Feed

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 80 tonne/h (90 tph) 3 0

2 Conveyor No. 6 Belt w/ tripper 240 tonne/h (270 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 490 tonne (540 ton) 1 0

4 Weigh Feeder Belt 120 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 120 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank with Agitator Field erected 299,900 liters (79,220 gal) 2 0

7 Slurry Water Pumps Centrifugal 830 lpm (220 gpm) 2 1

8 Trommel Screen Coarse 170 tonne/h (190 tph) 2 0

9 Rod Mill Discharge Tank with Agitator Field erected 392,320 liters (103,640 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,300 lpm (900 gpm) 2 2

11 Slurry Storage Tank with Agitator Field erected 1,176,900 liters (310,900 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,500 lpm (1,700 gpm) 2 2

13 Slurry Product Pumps Positive displacement 3,300 lpm (900 gpm) 2 2



## Case B5B

– Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical,

outdoor 1,094,000 liters (289,000 gal) 2 0

2 Condensate Pumps Vertical canned 7,850 lpm @ 90 m H 2 O (2,070 gpm @ 300 ft H 2 O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 546,000 kg/hr (1,205,000 lb/hr) 2 0

4 Intermediate

- Pressure Feedwater Pump Horizontal centrifugal, single stage 8,030 lpm @ 30 m H 2 O (2,120 gpm @ 90 ft H 2 O) 2 1

5 High

- Pressure Feedwater Pump No. 1 Barrel type, multi

stage, centrifugal HP water: 6,050 lpm @ 1,800 m H 2 O (1,600 gpm @ 6,100 ft H 2 O) 2 1

6 High

- Pressure Feedwater Pump No. 2 Barrel type, multi

stage, centrifugal IP water: 1,720 lpm @ 220 m

H 2 O (450 gpm @ 730 ft H 2 O) 2 1Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 213 Equipment

No. Description Type Design Condition Operating Qty. Spares

7 Auxiliary Boiler Shop fabricated, water

tube 18,000 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air Compressors Flooded Screw 28 m 3 

### / min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m 3 

### / min (1,000 scfm) 2 1

10 Closed Cycle Cooling Heat Exchangers Plate and frame 368 GJ/hr (348 MMBtu/hr)

each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 131,900 lpm @ 20 m H 2 O (34,800 gpm @ 70 ft H 2 O) 2 1

12 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 110 m H 2 O (1,000 gpm @ 350 ft H 2 O) 1 1

13 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 80 m H 2 O (700 gpm @ 250 ft H 2 O) 1 1

14 Raw Water Pumps Stainless steel, single

suction 5,730 lpm @ 20 m H 2 O (1,510 gpm @ 60 ft H 2 O) 2 1

15 Ground Water Pumps Stainless steel, single

suction 2,870 lpm @ 270 m H 2 O (760 gpm @ 880 ft H 2 O) 4 1

16 Filtered Water Pumps Stainless steel, single

suction 3,350 lpm @ 50 m H 2 O (890 gpm @ 160 ft H 2 O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,610,000 liter (425,000 gal) 2 0

18 Makeup Water

Demineralizer Anion, cation, and

mixed bed 1,490 lpm (390 gpm) 2 0

19 Liquid Waste Treatment System N/A 10 years, 24

- hour storm 1 0



## Case B5B

– Account 4: Gasifier, ASU, and Accessories Including Low Temperature Heat Recovery and Fuel Gas Saturation

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized slurry

- feed,

entrained bed 2,900 tonne/day, 5.6 MPa (3,200 tpd, 815 psia) 2 0

2 Synthesis Gas Cooler Vertical downflow radiant heat exchanger with outlet quench

chamber 256,000 kg/hr (564,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 350,000 kg/hr (772,000 lb/hr) Design efficiency 90% 2 0

4 Raw Gas Coolers Shell and tube with

condensate drain 388,000 kg/hr (856,000 lb/hr) 8 0

5 Raw Gas Knockout

Drum Vertical with mist

eliminator 304,000 kg/hr, 35°C, 5.2 MPa (671,000 lb/hr, 95°F, 750 psia) 2 0

6 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 350,000 kg/hr (772,000 lb/hr) syngas 2 0

7 ASU Main Air Compressor Centrifugal, multi

- stage 6,000 m 3 

### / min @ 1.3 MPa (210,000 scfm @ 190 psia) 2 0

8 Cold Box Vendor design 2,400 tonne/day (2,600 tpd) of 95% purity oxygen 2 0

9 Oxygen Compressor Centrifugal, multi

- stage 1,000 m 3 

### / min (42,000 scfm)

Suction

- 1.0 MPa (130 psia) Discharge

- 6.5 MPa (940 psia) 2 0

10 Primary Nitrogen Compressor Centrifugal, multi

- stage 4,000 m 3 

### / min (134,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 2 0

11 Secondary Nitrogen Compressor Centrifugal, single

stage 550 m 3 

### / min (19,000 scfm)

Suction

- 1.3 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 2 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 214 Equipment

No. Description Type Design Condition Operating Qty. Spares

12 Syngas Dilution Nitrogen Boost Compressor Centrifugal, single

stage 2,000 m 3 

### / min (70,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470 psia) 2 0



## Case B5B

– Account 5: Syngas Cleanup

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber 1 Sulfated carbon bed 304,000 kg/hr (670,000 lb/hr)

, 35°C (95°F)

, 5.1 MPa (745 psia) 2 0

2 Mercury Adsorber 2 Sulfated carbon bed 304,000 kg/hr (670,000 lb/hr)

, 35°C (95°F)

, 5.1 MPa (745 psia) 2 0

3 Sulfur Plant Claus type 146 tonne/day (161 tpd) 1 0

4 Water Gas Shift

Reactors Fixed bed, catalytic 194,000 kg/hr (428,000 lb/hr)

, 227°C (440°F)

, 5.4 MPa (790 psia) 4 0

5 Shift Reactor Heat Recovery Exchangers Shell and Tube Exchanger 1: 157 GJ/hr (149 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 4 0

6 Acid Gas Removal

Plant Two

- stage Selexol 311,000 kg/hr (685,000 lb/hr)

, 35°C (95°F)

, 5.1 MPa (740 psia) 2 0

7 Hydrogenation

Reactor Fixed bed, catalytic 18,000 kg/hr (40,000 lb/hr)

, 232°C (450°F)

, 0.1 MPa (12. 3 psia) 1 0

8 Tail Gas Recycle Compressor Centrifugal 14,000 kg/hr (30,000 lb/hr) each 1 0

9 CO 2 Compressor Integrally geared,

multi

- stage centrifugal 1,100 m 3 

### / min @ 15.3 MPa (40,000 scfm @ 2,215 psia) 4 0



## Case B5B

– Account 6: Combustion Turbine and Auxiliaries

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Combustion Turbine State

- of

- the

- art

2008 F

- c lass 230 MW 2 0

2 Combustion Turbine

Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 2 0

3 Syngas Expansion

Turbine/Generator Turbo Expander 49,600 kg/h (109,300 lb/h) 5.1 MPa (735 psia) Inlet 3.2 MPa (460 psia) Outlet 2 0



## Case B5B

– Account 7: HRSG, Ducting, and Stack

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type

409SS liner 76 m (250 ft) high x 8.5 m (28 ft) diameter 1 0

2 Heat Recovery
Steam Generator Drum, multi

pressure with

economizer section and integral

deaerator Main steam

- 341,975 kg/hr,

12.4 MPa/534°C (753,925 lb/hr, 1,800 psig/994°F) 2 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 215 Case B5B

– Account 8: Steam Turbine Generator and Auxiliaries

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Steam

Turbine Commercially available

advanced steam turbine 277 MW 12.4 MPa/534°C/534°C (1,800 psig/ 994°F/994°F) 1 0

2 Steam

Turbine
Generator Hydrogen cooled, static

excitation 310 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 1 0

3 Surface

Condenser Single pass, divided waterbox including

vacuum pumps 1,660GJ/hr (1,580 MMBtu/hr), Inlet water temperature 16°C (60°F),

Water temperature rise 11°C (20°F) 1 0

4 Steam Bypass One per HRSG 50% steam flow @ design steam

conditions 2 0



## Case B5B

– Account 9: Cooling Water System

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 465,000 lpm @ 30 m (123,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative, mechanical draft,

multi

- cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,590 GJ/hr (2,460 MMBtu/hr) heat duty 1 0



## Case B5B

– Account 10: Slag Recovery and Handling

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 254,000 liters (67,000 gal) 2 0

2 Slag Crusher Roll 13 tonne/hr (15 tph) 2 0

3 Slag Depressurizer Lock Hopper 13 tonne/hr (15 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 153,000 liters (40,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 69,00 0 liters (18,000 gal) 2 0

6 Slag Conveyor Drag chain 13 tonne/hr (15 tph) 2 0

7 Slag Separation Screen Vibrating 13 tonne/hr (15 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 13 tonne/hr (15 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 217,000 liters (57,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 60 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 2 2

11 Grey Water Storage Tank Field erected 69,000 liters (18,000 gal) 2 0

12 Grey Water Pumps Centrifugal 250 lpm @ 560 m H 2 O (60 gpm @ 1,850 ft H 2 O) 2 2

13 Slag Storage Bin Vertical, field erected 1,000 tonne (1,100 tons) 2 0

14 Unloading Equipment Telescoping chute 110 tonne/hr (120 tph) 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 216 Case B5B

– Account 11: Accessory Electric Plant

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 CTG Transformer Oil

- filled 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 2 0

2 STG Transformer Oil

- filled 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 1 0

3 High Voltage Auxiliary

Transformer Oil

- filled 345 kV/13.8 kV, 80 MVA, 3

- ph, 60 Hz 2 0

4 Medium Voltage Transformer Oil

- filled 24 kV/4.16 kV, 48 MVA, 3

- ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 7 MVA, 3

- ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency

shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 0



## Case B5B

– Account 12: Instrumentation and Control

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 DCS

- Main
Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 0



# 3.4.11 Case B5B

- Cost Estimating

The cost estimating methodology was described previously in Section 2.6

. Exh ibit 3

- 104 shows a detailed breakdown of the capital costs ; Exhibit 3

- 105 shows the owner’s costs, TOC, and

TASC ; Exhibit 3

- 106 shows the initial and annual O&M costs; and Exhibit 3

- 107 shows

the COE breakdown.

The estimated TP C of the GEE gasifier with CO 2 

## capture is $3,3 87 /kW. Process contingency

represents 4.2 percent of the TPC

, and project contingency represents 13.8 percent. The COE, including CO 2 

## T&S costs of $ 9.2 /M Wh

, is $ 144.7 /M Wh.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 217 Exhibit 3

- 104 Case B5B total plant cost details

Case: B5B

– GEE Radiant IGCC w/ CO 2 Estimate Type: Conceptual Plant Size (MW,net): 543 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $4,552 $0 $2,194 $0 $6,746 $675 $0 $1,484 $8,905 $16

1.2 Coal Stackout & Reclaim $5,882 $0 $1,407 $0 $7,289 $729 $0 $1,604 $9,621 $18

1.3 Coal Conveyors & Yd Crush $5,469 $0 $1,392 $0 $6,861 $686 $0 $1,509 $9,056 $17

1.4 Other Coal Handling $1,431 $0 $322 $0 $1,753 $175 $0 $386 $2,314 $4

1.9 Coal & Sorbent Hnd. Foundations $0 $3,040 $7,944 $0 $10,984 $1,098 $0 $2,417 $14,499 $27

Subtotal $17,335 $3,040 $13,259 $0 $33,633 $3,363 $0 $7,399 $44,396 $82

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying w/2.3 $0 w/2.3 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,944 $467 $301 $0 $2,712 $271 $0 $597 $3,580 $7

2.3 Slurry Prep & Feed $26,551 $0 $11,574 $0 $38,125 $3,812 $1,906 $8,769 $52,612 $97

2.4 Misc. Coal Prep & Feed $1,069 $781 $2,301 $0 $4,151 $415 $0 $913 $5,479 $10

2.9 Coal & Sorbent Feed Foundation $0 $3,922 $3,365 $0 $7,287 $729 $0 $1,603 $9,619 $18

Subtotal $29,564 $5,170 $17,541 $0 $52,275 $5,227 $1,906 $11,882 $71,290 $131

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $3,381 $5,835 $3,059 $0 $12,275 $1,227 $0 $2,700 $16,203 $30

3.2 Water Makeup & Pretreating $876 $91 $481 $0 $1,448 $145 $0 $478 $2,071 $4

3.3 Other Feedwater Subsystems $1,901 $628 $561 $0 $3,090 $309 $0 $680 $4,079 $8

3.4 Service Water Systems $512 $1,022 $3,521 $0 $5,055 $505 $0 $1,668 $7,228 $13

3.5 Other Boiler Plant Systems $2,761 $1,032 $2,539 $0 $6,331 $633 $0 $1,393 $8,358 $15

3.6 FO Supply Sys & Nat Gas $17,735 $710 $658 $0 $19,104 $1,910 $0 $4,203 $25,217 $46

3.7 Waste Treatment Equipment $1,185 $0 $734 $0 $1,919 $192 $0 $633 $2,745 $5

3.8 Misc. Power Plant Equipment $1,326 $177 $689 $0 $2,193 $219 $0 $724 $3,135 $6

Subtotal $29,677 $9,494 $12,243 $0 $51,415 $5,142 $0 $12,479 $69,035 $127

4 Gasifier & Accessories

4.1 Syngas Cooler Gasifier System $140,246 $0 $77,258 $0 $217,504 $21,750 $30,249 $41,297 $310,800 $572

4.2 Syngas Cooler w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU & Oxidant Compression $234,789 $0 w/equip. $0 $234,789 $23,479 $0 $25,827 $284,094 $523

4.4 Scrubber & LT Heat Recovery $7,292 $5,935 $6,135 $0 $19,363 $1,936 $0 $4,260 $25,560 $47

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.6 Soot Recovery & SARU $2,224 $1,056 $2,073 $0 $5,353 $535 $0 $1,178 $7,066 $13

4.8 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $7,429 $6,482 $0 $13,911 $1,391 $0 $3,826 $19,128 $35

Subtotal $384,551 $14,421 $91,949 $0 $490,920 $49,092 $30,249 $76,387 $646,648 $1,190

5A Gas Cleanup & Piping

5A.1 Double Stage Selexol $160,990 $0 w/equip. $0 $160,990 $16,099 $32,198 $41,857 $251,145 $462

5A.2 Elemental Sulfur Plant $12,451 $2,427 $15,954 $0 $30,833 $3,083 $0 $6,783 $40,699 $75

5A.3 Mercury Removal $1,973 $0 $1,491 $0 $3,464 $346 $173 $797 $4,780 $9

5A.4 Shift Reactors $11,566 $0 $4,624 $0 $16,190 $1,619 $0 $3,562 $21,370 $39

5A.7 Fuel Gas Piping $0 $812 $531 $0 $1,344 $134 $0 $296 $1,774 $3Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 218 Case: B5B

– GEE Radiant IGCC w/ CO 2 Estimate Type: Conceptual Plant Size (MW,net): 543 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

5A.9 HGCU Foundations $0 $735 $495 $0 $1,231 $123 $0 $406 $1,760 $3

Subtotal $186,980 $3,974 $23,096 $0 $214,051 $21,405 $32,371 $53,701 $321,528 $592

5B CO 2 Compression

5B.2 CO 2 Compression & Drying $40,237 $6,036 $17,430 $0 $63,703 $6,370 $0 $14,015 $84,088 $155

Subtotal $40,237 $6,036 $17,430 $0 $63,703 $6,370 $0 $14,015 $84,088 $155

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $111,210 $0 $7,881 $0 $119,091 $11,909 $11,909 $14,291 $157,201 $289

6.2 Syngas Expander $6,691 $0 $918 $0 $7,609 $761 $0 $1,256 $9,626 $18

6.9 Combustion Turbine Foundations $0 $1,016 $1,175 $0 $2,191 $219 $0 $723 $3,133 $6

Subtotal $117,901 $1,016 $9,975 $0 $128,892 $12,889 $11,909 $16,270 $169,960 $313

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $29,560 $0 $5,723 $0 $35,283 $3,528 $0 $3,881 $42,693 $79

7.3 Ductwork $0 $2,109 $1,478 $0 $3,587 $359 $0 $789 $4,735 $9

7.4 Stack $4,070 $0 $1,519 $0 $5,589 $559 $0 $615 $6,762 $12

7.9 HRSG, Duct & Stack Foundations $0 $775 $778 $0 $1,553 $155 $0 $512 $2,220 $4

Subtotal $33,630 $2,884 $9,498 $0 $46,012 $4,601 $0 $5,797 $56,411 $104

8 Steam Turbine Generator

8.1 Steam TG & Accessories $37,100 $0 $5,758 $0 $42,858 $4,286 $0 $4,714 $51,858 $95

8.2 Turbine Plant Auxiliaries $235 $0 $535 $0 $771 $77 $0 $85 $932 $2

8.3 Condenser & Auxiliaries $3,290 $0 $1,868 $0 $5,158 $516 $0 $567 $6,241 $11

8.4 Steam Piping $15,068 $0 $6,534 $0 $21,602 $2,160 $0 $5,941 $29,703 $55

8.9 TG Foundations $0 $1,108 $1,958 $0 $3,067 $307 $0 $1,012 $4,385 $8

Subtotal $55,693 $1,108 $16,654 $0 $73,456 $7,346 $0 $12,319 $93,121 $171

9 Cooling Water System

9.1 Cooling Towers $4,490 $0 $1,360 $0 $5,850 $585 $0 $965 $7,400 $14

9.2 Circulating Water Pumps $2,175 $0 $163 $0 $2,338 $234 $0 $386 $2,957 $5

9.3 Circ. Water System Auxiliaries $189 $0 $27 $0 $216 $22 $0 $36 $273 $1

9.4 Circ. Water Piping $0 $8,386 $2,031 $0 $10,417 $1,042 $0 $2,292 $13,751 $25

9.5 Make

- up Water System $484 $0 $665 $0 $1,150 $115 $0 $253 $1,517 $3

9.6 Component Cooling Water Sys $959 $1,147 $787 $0 $2,893 $289 $0 $636 $3,818 $7

9.9 Circ. Water System Foundations $0 $2,738 $4,866 $0 $7,604 $760 $0 $2,509 $10,874 $20

Subtotal $8,296 $12,271 $9,900 $0 $30,467 $3,047 $0 $7,077 $40,591 $75

10 Ash & Spent Sorbent Handling Systems

10.1 Slag Dewatering & Cooling $14,630 $8,067 $16,277 $0 $38,975 $3,897 $0 $4,287 $47,159 $87

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $710 $0 $767 $0 $1,476 $148 $0 $244 $1,868 $3

10.7 Ash Transport & Feed Equipment $977 $0 $228 $0 $1,205 $120 $0 $199 $1,524 $3

10.8 Misc. Ash Handling Equipment $1,470 $1,801 $534 $0 $3,806 $381 $0 $628 $4,814 $9

10.9 Ash/Spent Sorbent Foundation $0 $60 $78 $0 $138 $14 $0 $46 $197 $0

Subtotal $17,787 $9,928 $17,885 $0 $45,600 $4,560 $0 $5,403 $55,563 $102

11 Accessory Electric PlantCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 219 Case: B5B

– GEE Radiant IGCC w/ CO 2 Estimate Type: Conceptual Plant Size (MW,net): 543 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

11.1 Generator Equipment $1,152 $0 $1,122 $0 $2,274 $227 $0 $250 $2,752 $5

11.2 Station Service Equipment $5,513 $0 $507 $0 $6,020 $602 $0 $662 $7,285 $13

11.3 Switchgear & Motor Control $10,176 $0 $1,891 $0 $12,068 $1,207 $0 $1,991 $15,266 $28

11.4 Conduit & Cable Tray $0 $5,170 $15,938 $0 $21,109 $2,111 $0 $5,805 $29,024 $53

11.5 Wire & Cable $0 $9,969 $6,065 $0 $16,034 $1,603 $0 $4,409 $22,047 $41

11.6 Protective Equipment $0 $806 $2,995 $0 $3,801 $380 $0 $627 $4,808 $9

11.7 Standby Equipment $274 $0 $273 $0 $547 $55 $0 $90 $692 $1

11.8 Main Power Transformers $19,599 $0 $172 $0 $19,771 $1,977 $0 $3,262 $25,011 $46

11.9 Electrical Foundations $0 $180 $491 $0 $672 $67 $0 $222 $961 $2

Subtotal $36,715 $16,126 $29,455 $0 $82,297 $8,230 $0 $17,319 $107,845 $199

12 Instrumentation & Control

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,321 $0 $900 $0 $2,221 $222 $111 $383 $2,937 $5

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $304 $0 $199 $0 $502 $50 $25 $116 $693 $1

12.7 Computer & Accessories $7,046 $0 $230 $0 $7,277 $728 $364 $837 $9,205 $17

12.8 Instrument Wiring & Tubing $0 $2,713 $5,135 $0 $7,847 $785 $392 $2,256 $11,280 $21

12.9 Other I & C Equipment $4,710 $0 $2,334 $0 $7,044 $704 $352 $1,215 $9,316 $17

Subtotal $13,381 $2,713 $8,797 $0 $24,891 $2,489 $1,245 $4,807 $33,431 $62

13 Improvements to Site

13.1 Site Preparation $0 $123 $2,799 $0 $2,922 $292 $0 $964 $4,178 $8

13.2 Site Improvements $0 $2,189 $3,095 $0 $5,284 $528 $0 $1,744 $7,556 $14

13.3 Site Facilities $3,923 $0 $4,404 $0 $8,327 $833 $0 $2,748 $11,907 $22

Subtotal $3,923 $2,312 $10,297 $0 $16,532 $1,653 $0 $5,456 $23,641 $44

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $317 $179 $0 $496 $50 $0 $109 $655 $1

14.2 Steam Turbine Building $0 $2,849 $4,056 $0 $6,904 $690 $0 $1,139 $8,734 $16

14.3 Administration Building $0 $1,057 $766 $0 $1,823 $182 $0 $301 $2,306 $4

14.4 Circulation Water Pumphouse $0 $198 $105 $0 $303 $30 $0 $50 $384 $1

14.5 Water Treatment Buildings $0 $720 $702 $0 $1,422 $142 $0 $235 $1,799 $3

14.6 Machine Shop $0 $541 $370 $0 $911 $91 $0 $150 $1,152 $2

14.7 Warehouse $0 $873 $563 $0 $1,437 $144 $0 $237 $1,818 $3

14.8 Other Buildings & Structures $0 $523 $407 $0 $930 $93 $0 $205 $1,228 $2

14.9 Waste Treating Building & Str. $0 $1,169 $2,233 $0 $3,403 $340 $0 $749 $4,492 $8

Subtotal $0 $8,248 $9,382 $0 $17,630 $1,763 $0 $3,175 $22,568 $42

Total $975,671 $98,741 $297,361 $0 $1,371,773 $137,177 $77,680 $253,485 $1,840,115 $3,387Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 220 Exhibit 3

- 105 Case B5B owner’s costs

Description $ / 1,000 $/kW

Pre

- Production Costs

6 Months All Labor $16,298 $30

1 Month Maintenance Materials $3,682 $7

1 Month Non

- fuel Consumables $676 $1

1 Month Waste Disposal $494 $1

25% of 1 Months Fuel Cost at 100% CF $3,046 $6

2% of TPC $36,802 $68

Total $60,998 $112

Inventory Capital

60

- day supply of fuel and consumables at 100% CF $25,290 $47

0.5% of TPC (spare parts) $9,201 $17

Total $34,491 $63

Other Costs

Initial Cost for Catalyst and Chemicals $16,548 $30

Land $900 $2

Other Owner's Costs $276,017 $508

Financing Costs $49,683 $91

Total Overnight Costs (TOC) $2,278,752 $4,195

TASC Multiplier (IOU, high

- risk, 35 year) 1.140

Total As

- Spent Cost (TASC) $2,597,777 $4,782Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 221 Exhibit 3

- 106 Case B5B initial and annual operating and maintenance costs

Case: B5B

– GEE Radiant IGCC w/ CO 2 Cost Base: Jun 2011 Plant Size (MW,net): 543 Heat Rate

- net (Btu/kWh): 10,459 Capacity Factor (%): 80
Operating & Maintenance Labor
Operating Labor Operating Labor Requirements per Shift
Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 Operating Labor Burden: 30.00 % of base Operator: 10.0

Labor O

- H Charge Rate: 25.00 % of labor Foreman: 1.0
Lab Tech's, etc.: 3.0

Total: 16.0 Fixed Operating Costs

Annual Cost ($) ($/kW

- net)
Annual Operating Labor: $7,233,658 $13.316

Maintenance Labor: $18,843,231 $34.687 Administrative & Support Labor: $6,519,222 $12.001

Property Taxes and Insurance: $36,802,296 $67.747

Total: $69,398,406 $127.751
Variable Operating Costs ($) ($/M Wh

- net)

Maintenance Material: $35,348,580 $9.28526

Consumables
Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill
Water (/1000 gallons): 0 4,201 $1.67 $0 $2,053,253 $0.53934 Makeup and Waste Water Treatment Chemicals (lbs): 0 25,026 $0.27 $0 $1,957,230 $0.51412

Carbon (Mercury Removal) (lb): 135,182 231 $5.50 $743,501 $371,751 $0.09765 Shift Catalyst (ft 3 ): 6,246 4.28 $771.99 $4,822,025 $964,405 $0.25333 Selexol Solution (gal): 298,498 95 $36.79 $10,982,126 $1,020,094 $0.26796

Claus Catalyst (ft 3 ): w/equip 2.01 $203.15 $0 $119,487 $0.03139

Subtotal: $16,547,652 $6,486,219 $1.70378
Waste Disposal
Spent Mercury Catalyst (lb.): 0 231 $0.65 $0 $43,941 $0.01154 Flyash (ton): 0 0 $0.00 $0 $0 $0.00000

Slag (ton): 0 641 $25.11 $0 $4,701,292 $1.23492

Subtotal: $0 $4,745,232 $1.24646
By

- Products
Sulfur (tons): 0 146 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000 Variable Operating Costs Total: $16,547,652 $46,580,031 $12.23551

Fuel Cost
Illinois Number 6 (ton): 0 5,844 $68.54 $0 $116,961,258 $30.72304

Total: $0 $116,961,258 $30.72304



### Exhibit 3

- 107 Case B 5B COE breakdown

Component Value, $/M Wh Percentage

Capital 74.2 55%

Fixed 18.2 13%

Variable 12.2 9%

Fuel 30.7 23%

Total (Excluding T&S) 135.4 N/A

CO 2 

### T&S 9.2 7%

Total (Including T&S) 144. 7 N/ACost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 222 

# 3.4.12 Case B5B

- Q

- GEE Quench IGCC with CO 2 

# Capture

Case B5B

- Q is configured to produce electric power with CO 2 

## capture

. The plant configuration

is the same as Case B5B, namely two gasifier trains, two state

- of

- the

- art 2008 F

- class turbines,
two HRSGs, and one steam turbine.

The process description for Case B5B

- Q is similar to Case B5B with the exception that the gasifier is operated in quench

- only mode

. A BFD and stream tables for Case B5B

- Q are shown

in Exhibit 3

- 108 and Exhibit 3

- 109 , respectively. Rather than repeating the entire process description, only differences from Case B5B are reported here.

3.4.12.1 Gasification

The gasification process is the same as Case B5B with the exception that the syngas exiting the gasifier passes through a water quench where the temperature is reduced from 1

, 316°C (2

, 400°F) to 288°C (550°F). The total coal feed to the two gasifiers is 5,301 tonnes/day (5,844 tpd ) (stream 6) and the ASU provides 4,343 tonnes/day (4,787 tpd ) of 95 percent oxygen to the gasifier and Claus plant (streams 3 and 5).

3.4.12.2 Raw Gas Cooling/Particulate Removal

Particulate is largely removed in the quench tank and no additional heat recovery occurs prior to the syngas scrubber.

3.4.12.3 Syngas Scrubber/Sour Water Stripper

The outlet temperature from the syngas scrubber is 227°C (440°F) (stream 10).

3.4.12.4 Sour Gas Shift

The SGS process is the same as described for Case B5B with a 97 percent overall conversion of

the CO to CO 2 

## . The warm syngas from the second stage of SGS (stream 12) is cooled to 244°C (471°F) by heating the syngas entering the first shift reactor. The syngas is then cooled to 193°C ( 380°F) by producing IP steam that is sent to the RH in the HRSG. The SGS catalyst also serves to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. Following the second SGS cooler the syngas is further cooled to 35°C (95°F) be fore entering the mercury

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



## 223 Exhibit 3

- 108 Case B5B

- Q block flow diagram, GEE quench

- only IGCC with CO 2 

### capture

Source: NETL G AS
T URBINE C OMBUSTOR

T URBINE C OOLING A IR Q UENCH AND

S YNGAS
S CRUBBER G AS C OOLING
BFW H EATING
& K NOCKOUT S HIFT
R EACTORS

E LEVATED
P RESSURE

ASU GEE G ASIFIER

S ECTION S OUR
W ATER S TRIPPER M ERCURY
R EMOVAL D UAL S TAGE
S ELEXOL

U NIT

C LAUS
P LANT

HRSG

A MBIENT A IR S YNGAS
E XPANDER

H YDROGENATION
R EACTOR AND G AS
C OOLER CO 2 C OMPRESSION

1 5 9 10 11 12 13 14

17 19

20

21 18

8

2 3 4

22 23 24 A IR TO ASU S LAG S HIFT S TEAM

W ATER R ECYCLE

TO P ROCESS

D EMAND N OTE : W ATER FROM T AIL G AS C OOLER MODELED

,

BUT NOT SHOWN

N ITROGEN D ILUENT S YNGAS C LEAN G AS CO 2 S TREAMS CO 2 P RODUCT

S ULFUR

T AIL G AS
R ECYCLE TO

S ELEXOL N OTE : T AIL G AS B OOST
C OMPRESSOR MODELED

, BUT NOT SHOWN

F LUE G AS S TACK G AS

V ENT G AS C LAUS
P LANT O XIDANT

2 X S TATE

- OF

- THE

A RT F

- C LASS
G AS T URBINES S YNGAS
H / P

R EHEAT

15

16

C LAUS
P LANT O XIDANT

S TEAM
T URBINE 25 S LURRY
M IXER 6 A S

R ECEIVED

C OAL

7

S LURRY
W ATER G ASIFIER
O XIDANT

Note : Block Flow Diagram is not intended to represent a complete material balance

. Only major process streams and equipment are

shown

. 20

T AIL G AS
R ECYCLE F ROM
C LAUS P LANTCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 224 Exhibit 3

- 109 Case B5B

- Q stream table, GEE quench

- only IGCC with capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V

- L Mole Fraction

Ar 0.0092 0.0165 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0053 0.0000 0.0053 0.0071 0.0071

CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0007 0.0000 0.0007 0.0009 0.0009

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2197 0.0000 0.0060 0.0081 0.0081

CO 2 0.0003 0.0054 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.0848 0.0000 0.2985 0.4017 0.4053

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 0.0000 0.0000

H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2093 0.0000 0.4229 0.5690 0.5647

H 2 O 0.0099 0.1355 0.0000 0.0003 0.0000 0.0000 0.9997 0.0000 0.1369 0.4700 1.0000 0.2562 0.0012 0.0012

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0001 0.0000 0.0001 0.0000 0.0000

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0045 0.0000 0.0046 0.0061 0.0061

N 2 0.7732 0.7077 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0043 0.0000 0.0043 0.0058 0.0065

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0003 0.0000 0.0019 0.0013 0.0000 0.0013 0.0000 0.0000

O 2 0.2074 0.1349 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 27,367 1,660 97 20,046 5,526 0 5,037 0 23,121 37,625 0 37,625 27,964 28,358

V

- L Flowrate (kg/hr) 789,736 45,606 3,132 562,476 177,816 0 90,741 0 465,212 726,201 0 726,201 552,117 564,722 Solids Flowrate (kg/hr) 0 0 0 0 0 220,890 0 24,235 0 0 0 0 0 0

Temperature (°C) 15 18 32 93 32 15 146 1,316 1,316 227 288 249 35 35 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.62 5.58 5.52 5.45 5.17 5.14 Steam Table Enthalpy (kJ/kg) A 30.23 35.62 26.67 92.50 26.67

--- 559.14

--- 2,635.52 1,479.99 2,918.18 1,017.28 36.94 36.25 AspenPlus Enthalpy (kJ/kg) B

- 97.58

- 1,483.25 4.13 63.47 4.13

- 2,116.95

- 15,408.22

- 727.24

- 4,038.89

- 8,545.15

- 13,053.16

- 8,965.22

- 8,082.42

- 8,084.87 Density (kg/m 3 ) 1.2 1.5 11.0 24.4 11.0

--- 867.1

--- 8.5 25.9 25.6 24.5 41.0 41.2

V

- L Molecular Weight 28.857 27.479 32.181 28.060 32.181

--- 18.015

--- 20.121 19.301 18.015 19.301 19.744 19.914

V

- L Flowrate (lb mole /hr) 60,334 3,659 215 44,193 12,182 0 11,105 0 50,972 82,949 0 82,949 61,649 62,518

V

- L Flowrate (lb/hr) 1,741,069 100,544 6,906 1,240,047 392,017 0 200,051 0 1,025,616 1,600,998 0 1,600,998 1,217,210 1,244,998 Solids Flowrate (lb/hr) 0 0 0 0 0 486,978 0 53,430 0 0 0 0 0 0

Temperature (°F) 59 65 90 199 90 59 295 2,400 2,400 440 550 481 95 95 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 815.0 810.0 800.0 790.0 750.0 745.0 Steam Table Enthalpy (Btu/lb) A 13.0 15.3 11.5 39.8 11.5

--- 240.4

--- 1,133.1 636.3 1,254.6 437.4 15.9 15.6 AspenPlus Enthalpy (Btu/lb) B

- 42.0

- 637.7 1.8 27.3 1.8

- 910.1

- 6,624.3

- 312.7

- 1,736.4

- 3,673.8

- 5,611.9

- 3,854.3

- 3,474.8

- 3,475.9 Density (lb/ft 3 ) 0.076 0.091 0.687 1.521 0.687

--- 54.131

--- 0.530 1.619 1.597 1.529 2.562 2.570

A 

### Steam table reference conditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atmCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 225 Exhibit 3

- 109 Case B5B

- Q stream table, GEE quench

- only IGCC with capture (continued)

15 16 17 18 19 20 21 22 23 24 25

V

- L Mole Fraction

Ar 0.0115 0.0115 0.0115 0.0002 0.0018 0.0000 0.0103 0.0092 0.0091 0.0091 0.0000

CH 4 0.0015 0.0015 0.0015 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0130 0.0130 0.0130 0.0002 0.0023 0.0000 0.0061 0.0000 0.0000 0.0000 0.0000

CO 2 0.0501 0.0501 0.0501 0.9948 0.5218 0.0000 0.6606 0.0003 0.0083 0.0083 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 0.9133 0.9133 0.9133 0.0048 0.1029 0.0000 0.2596 0.0000 0.0000 0.0000 0.0000

H 2 O 0.0001 0.0001 0.0001 0.0000 0.0225 0.0000 0.0017 0.0099 0.1222 0.1222 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 S 0.0000 0.0000 0.0000 0.0000 0.3472 0.0000 0.0043 0.0000 0.0000 0.0000 0.0000

N 2 0.0105 0.0105 0.0105 0.0000 0.0008 0.0000 0.0574 0.7732 0.7541 0.7541 0.0000

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1064 0.1064 0.0000

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 17,424 17,424 17,424 10,415 496 0 394 110,253 139,653 139,653 20,013

V

- L Flowrate (kg/hr) 90,438 90,438 90,438 456,223 17,655 0 12,604 3,181,557 3,834,472 3,834,472 360,534 Solids Flowrate (kg/hr) 0 0 0 0 0 5,523 0 0 0 0 0

Temperature (°C) 35 241 195 51 48 178 38 15 562 132 534 Pressure (MPa, abs) 5.14 5.10 3.17 15.27 0.16 0.12 5.51 0.10 0.10 0.10 12.51 Steam Table Enthalpy (kJ/kg) A 194.96 1,385.17 1,117.49

- 162.29 74.70

--- 5.84 30.23 834.65 343.46 3,432.96 AspenPlus Enthalpy (kJ/kg) B

- 4,047.98

- 2,857.76

- 3,125.45

- 9,120.15

- 6,110.54 141.95

- 8,192.39

- 97.58

- 588.07

- 1,079.26

- 12,537.35 Density (kg/m 3 ) 10.2 6.1 4.2 641.8 2.2 5,280.6 77.3 1.2 0.4 0.9 36.7

V

- L Molecular Weight 5.190 5.190 5.190 43.804 35.590

--- 31.966 28.857 27.457 27.457 18.015

V

- L Flowrate (lb mole /hr) 38,414 38,414 38,414 22,961 1,094 0 869 243,066 307,882 307,882 44,120

V

- L Flowrate (lb/hr) 199,383 199,383 199,383 1,005,800 38,923 0 27,788 7,014,133 8,453,564 8,453,564 794,842 Solids Flowrate (lb/hr) 0 0 0 0 0 12,177 0 0 0 0 0

Temperature (°F) 95 465 383 124 119 352 100 59 1,044 270 994 Pressure (psia) 745.0 740.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Steam Table Enthalpy (Btu/lb) A 83.8 595.5 480.4

- 69.8 32.1

--- 2.5 13.0 358.8 147.7 1,475.9 AspenPlus Enthalpy (Btu/lb) B

- 1,740.3

- 1,228.6

- 1,343.7

- 3,921.0

- 2,627.1 61.0

- 3,522.1

- 42.0

- 252.8

- 464.0

- 5,390.1 Density (lb/ft 3 ) 0.636 0.381 0.261 40.066 0.137 329.655 4.823 0.076 0.026 0.053 2.293

A 

### Steam table reference conditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atmCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 226 3.4.12.5 Mercury Removal and Acid Gas Removal

Mercury removal and the AGR process are the same as in Case B5B

. The AGR process in Case B5B

- Q is a two

- stage Selexol process where H 2 

## S is remo ved in the first stage and CO 2 

## 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 CO 2



## - rich stream and an acid gas feed to the Claus plant. The acid gas (stream 18) contains 35 percent H 2 

## S and 52 percent CO 2 

## with the balance primarily H 2



## .

3.4.12.6 CO 2 

## Compression and Dehydration

The CO 2 

## compression and dehydration scheme is the same as for Case B5B

.

3.4.12.7 Claus Unit

The Claus plant is the same as Case B5B with the following exceptions:

• 5,523 kg/h r (12,177 lb/h r ) of sulfur (stream 19) are produced

• The waste heat boiler generates 12,957 kg/h r (2 8,564 lb/h r ) of 3.0 MPa (430 psia) steam

3.4.12.8 Power Block

Clean syngas from the AGR plant is heated to 241°C (465°F) first using hot water from the syngas scrubber followed by HP BFW before passing through an expansion turbine. The clean syngas (stream 16) is diluted with nitrogen (stream 4) and then enters the CT burner. There is no integration between the CT and the ASU in this case. The exhaust gas (stream 22) exits the CT at 562°C (1

, 044°F) and enters the HRSG where additional heat is recovered. The flue gas exits the HRSG at 132°C (270°F) (stream 23) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced commercially available steam turbine using a nominal 12.4 MPa/538°C/538°C (1

, 800 psig/1

, 000°F/1

, 000°F) st eam cycle.

3.4.12.9 Air Separation Unit

The same elevated pressure ASU is used in Case B5B

- Q and produces 4,343 tonnes/day (4,787 tpd ) of 95 mol% oxygen and 14,595 tonnes/day (16,087 tpd ) of nitrogen. There is no integration

between the ASU and the CT in the CO 2 

## c apture cases

.


# 3.4.13 Case B5B

- Q

- Performance Results

The plant produces a net output of 494 MW at a net plant efficiency of 29.7 percent (HHV basis). Overall performance for the entire plant is summarized in Exhibit 3

- 110 and

Exhibit 3

- 111

, which includes auxiliary power requirements. The ASU accounts for 60 percent

of t he auxiliary load between the main air compressor, nitrogen compressor, oxygen compressor

, and ASU auxiliaries. The two

- stage Selexol process and CO 2 

## compression account for an additional 26 percent of the auxiliary power load. The BFW pumps and cooling water system ( CWP s and cooling tower fan) comp os e about 5 percent of the load, leaving 9 percent of the auxiliary load for all other systems.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 227 Exhibit 3

- 110 Case B 5B

- Q plant performance summary

Performance Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 7

Steam Turbine Power, MWe 214

Total Gross Power, MWe 684

Air Separation Unit Main Air Compressor, kWe 67,350

Oxygen Compressor, kWe 10,640

Nitrogen Compressors, kWe 35,630

CO 2 Compression, kWe 31,130

Acid Gas Removal, kWe 19,210

Balance of Plant, kWe 26,450

Total Auxiliaries, MWe 190

Net Power, MWe 494

HHV Net Plant Efficiency (%) 29.7%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 12,138 (11,505)

HHV Cold Gas Efficiency, % 79.2%

HHV Combustion Turbine Efficiency, % 36.0%

LHV Net Plant Efficiency (%) 30.7%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,708 (11,097)

LHV Cold Gas Efficiency, % 75.9%

LHV Combustion Turbine Efficiency, % 42.4%

Steam Turbine Cycle Efficiency, % 38.1%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 9,443 (8,950)

Condenser Duty, GJ/hr ( MM Btu/hr) 1,452 (1,376)

As

- Received Coal Feed, kg/hr (lb/hr) 220,890 (486,978)

HHV Thermal Input, kWt 1,664,962

LHV Thermal Input, kWt 1,605,876

Raw Water Withdrawal, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.047 (12.4)

Raw Water Consumption, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.038 (10.1)

O 2 :Coal 0.761Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 228 Exhibit 3

- 111 Case B 5B

- Q plant power summary

Power Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 7

Steam Turbine Power, MWe 214

Total Gross Power, MWe 684

Auxiliary Load Summary

Coal Handling, kWe 470

Coal Milling, kWe 2,270

Sour Water Recycle Slurry Pump, kWe 200

Slag Handling, kWe 1,160

Air Separation Unit Auxiliaries, kWe 1,000

Air Separation Unit Main Air Compressor, kWe 67,350

Oxygen Compressor, kWe 10,640

Nitrogen Compressors, kWe 35,630

Feedwater Pumps, kWe 2,620

Quench Water Pump, kWe 1,270

Syngas Recycle Compressor, kWe 0

CO 2 Compression, kWe 31,130

Scrubber Pumps, kWe 480

Acid Gas Removal, kWe 19,210

Combustion Turbine Auxiliaries, kWe 1,000

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 230

Circulating Water Pumps, kWe 4,830

Ground Water Pumps, kWe 560

Cooling Tower Fans, kWe 2,500

Claus Plant/TGTU Auxiliaries, kWe 250

Claus Plant TG Recycle Compressor, kWe 1,800

Miscellaneous Balance of Plant A,B 

### , kWe 3,000

Transformer Losses, kWe 2,710

Total Auxiliaries, MWe 190

Net Power, MWe 494

A 

### Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loadsCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 229 3.4.13.1 Environmental Performance

The environmental targets for emissions of Hg, NOx, SO 2 

## , and PM were presented in

Section 2.3 . A summary of the plant air emissions for Case B5B

- Q is presented in

Exhibit 3

- 112

. All HCl is assumed to be removed and is, therefore

, not reported.

Exhibit 3

- 112 Case B5B

- Q air emissions

kg/GJ (lb/ MM Btu) Tonne/year (ton/year) A 

### kg/MWh (lb/MWh) B



### SO 2 

### 0.001 (0.002) 39 (43) 0.008 (0.018 )

NOx 0.021 (0.049) 878 (968) 0.183 (0.404)

Particulates 0.003 (0.007) 128 (141) 0.027 (0.059)

Hg 1.55E

- 7 (3.61E

- 7) 0.007 (0.007) 1.36E

- 6 (3.00E

- 6)

CO 2 

### 8 ( 20 ) 358,178 (394,824) 75 (165)

CO 2 C



### - - 104 (228)

A 

### Calculations based on an 80 percent capacity factor

B 

### Emissions are based on gross power except where otherwise noted

C 

### CO 2 

### emissions based on net power instead of gross power



## The low level of SO 2 

## emissions is achieved by capturing the sulfur in the gas by the two

- stage Selexol AGR process. As a resul t of achieving the 90 percent CO 2 

## removal target, the sulfur compounds are removed to an extent that exceeds the environmental target in Section 2.3 . The clean syngas exiting the AGR process has a sulfur concentration of approximately 5 ppmv . This

results in a concentration in the flue gas of less than less than 1 ppmv . The H 2 

## S

- rich regeneration gas from the AGR system is fed to a Claus plant, prod ucing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H 2 

## S and then recycled back to the Selexol process, thereby eliminating the need for a tail gas treatment unit.

NO x emissions are limited by nitrogen dilution to 15 ppmvd (as NO 2 

## @15 percent O 2 

## ). Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process. This helps lower NO x levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by th e use of the syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only.

Approximately 97 percent of the mercury is captured from the syngas by dual acti vated carbon

beds.

Ninety two percent of the CO 2 

## from the syngas is captured in the AGR system and compressed for sequestration. Because not all CO is converted to CO 2 

## in the shift reactors, the overall carbon removal is 90.0 percent.

The carbon balance f or the plant is shown in Exhibit 3

- 113

. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon leaves the plant as

un burned carbon in the slag and as CO 2 

## in the stack gas, ASU vent gas, and the captured CO 2 

## product. The carbon capture efficiency is defined as one minus the amount of carbon in the stack gas relative to the total carbon in less carbon contained in the slag , represented by the following

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



## 230 CCCCCCCCCC SS SSSS
( TT TT CCCCCCCCCC )

− ( CCCCCCCCCC SS SS ) = � 1

− � 30

, 752

311

, 614

− 6

, 208 �

∗ � 100 = 90

. 0%

Exhibit 3

- 113 Case B5B

- Q carbon balance

Car bon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 140,805 (310,423) Stack Gas 13,949 (30,752)

Air (CO 2 ) 540 (1,191) CO 2 Product 124,473 (274,417)

ASU Vent 107 (237)

Slag 2,816 (6,208)

Total 141,346 (311,614) Total 141,346 (311,614)



## Exhibit 3

- 114 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur co

- sequestered

with the CO 2 

## product, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 3

- 114 Case B5B

- Q sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 5,536 (12,206) Stack Gas 3 (6)

CO 2 Product 10 (23)

Elemental Sulfur 5,523 (12,177)

Total 5,536 (12,206) Total 5,536 (12,206)



## Exhibit 3

- 115 shows the overall water balance for the plant. The exhibit is presented in an

identical manner as for cases B1A

- B5B.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 231 Exhibit 3

- 115 Case B5B

- Q water balance

Water Use Water

Demand Internal Recycle Raw Water

Withdrawal Process

Water Discharge Raw Water Consumption

m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm) m 3 

### /min (gpm)

Slag Handling 0.53 (139) 0.53 (139)

– – –
Slurry Water 1.51 (400) 1.51 (400)

– – –

Quench/Wash 6.66 (1,759) 1.86 (493) 4.79 (1,267)

– 4.79 (1,267)

Humidifier

– – – – –

SWS Blowdown

– – – 0.04 (10.32)

- 0.04 (

- 10.32)

Condenser Makeup 0.15 (40)

– 0.15 (40)

– 0.15 (40)

BFW Makeup 0.15 (40)

– 0.15 (40)

– 0.15 (40)

Gasifier Steam

– – – – –

Shift Steam

– – – – –

CT Steam Dilution

– – – – –

Cooling Tower 18.83 (4,974) 0.54 (143) 18.29 (4,831) 4.23 (1,119) 14.05 (3,712)

BFW Blowdown

– 0.15 (40)

- 0.15 (

- 40)

– - 0.15 (

- 40)

SWS Blowdown

– 0.39 (103.15) - 0.39

(

- 103.15) – - 0.39

(

- 103.15)

Total 27.68 (7,311) 4.45 (1,174) 23.23 (6,137) 4.27 (1,129) 18.96 (5,008)



## 3.4.13.2 Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3

- 116 through Exhibit 3

- 118 :

• Coal gasification and ASU

• Syngas cleanup, sulfur recovery, and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is provided in tabular form in Exhibit 3

- 119 . The power out is the combined CT, steam turbine, and expander power prior to generator losses. The power at the generator terminals (shown in Exhibit 3

- 118 ) is calculated by multiplying the power out by a combined generator efficiency of 98. 5 percent.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 232 Exhibit 3

- 116 Case B5B

- Q coal gasification and ASU heat and mass balance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 5 B

- Q

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 5 B

- Q

GEE G ASIFIER
ASU AND G ASIFICATION

DWG

. NO

. BB

- HMB

- CS

- B 5 B

- Q

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P AGES

1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated

Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU

Vent

1

, 741

, 069 W

59 T

15 P

13 H

392

, 017 W

90 T

125 P

11 H

392

, 017 W

241 T

940 P

41 H To Claus Plant 6

, 906 W

90 T

125 P

11 H 100

, 544 W

65 T

16 P

15 H

1

, 083

, 235 W

90 T

56 P

14 H

156

, 812 W

50 T

182 P

3 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 486

, 978 W

59 T

15 P

200

, 051 W

295 T

840 P

240 H

53

, 430 W

2

, 400 T

815 P 677

, 219 W

385 T

384 P

87 H

687

, 029 W

160 T

840 P 1

, 739

, 515 W

100 T

190 P

18 H

6 677

, 219 W

199 T

384 P

40 H

N 2 Boost Compressor 562

, 828 W

199 T

384 P

40 H 562

, 828 W

385 T

469 P

87 H

GE Energy

Gasifier Syngas

Scrubber

Slag Quench

Section

Drag Conveyor 4

1

, 025

, 616 W

2

, 400 T

815 P

1

, 131 H 1

, 600

, 998 W

440 T

810 P

636 H

Syngas

Quench 1

, 905

, 244 W

550 T

815 P

761 H

8 9 10

879

, 627 W

371 T

1

, 200 P

329 H

From Sour Water Stripper To Fuel Gas

Preheater From Fuel Gas

Preheater

809

, 952 W

440 T

810 P

475 H 809

, 952 W

150 T

1

, 205 P

118 H

To Sour Water Stripper

69

, 400 W

329 T

115 P

277 H 7 N 2 to GT Combustor

N 2 to GT Combustor

Raw Fuel Gas From HP

Economizer 2 To HP Economizer 1 Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

Water Steam

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical Flue Gas /

Combustion

Products

Gross Plant Power : 684 MWe Auxiliary Load : 190 MWe

Net Plant Power : 494 MWe Net Plant Efficiency

, HHV : 29

. 7 %

Net Plant Heat Rate : 11

, 505 Btu / kWh

Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 233 Exhibit 3

- 117 Case B5B

- Q syngas cleanup heat and mass balance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 5 B

- Q

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 5 B

- Q

GEE G ASIFIER
G AS CLEANUP SYSTEM

DWG

. NO

. BB

- HMB

- CS

- B 5 B

- Q

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P AGES

2 OF 3 Mercury

Removal

Knock

Out

Drum

Sour

Drum Claus Plant

Tail

Gas Furnace Catalytic

Reactor

Beds

Sulfur

Knock Out Syngas

Coolers

Sour Stripper 1

, 600

, 998 W

440 T

810 P

636 H 1

, 244

, 998 W

95 T

745 P

16 H 38

, 923 W

119 T

24 P

32 H 199

, 383 W

383 T

460 P

480 H

12

, 177 W 36

, 695 W

450 T

12 P

467 H

3

, 043 W

246 T

65 P

500 H 19

13 20

36

, 695 W

550 T

11 P

429 H 1

, 217

, 210 W

95 T

750 P

16 H

8

, 907 W

114 T

11 P

40 H 27

, 788 W

100 T

800 P

3 H 15 199

, 383 W

95 T

745 P

84 H

18 Fuel Gas Expander 16

199

, 383 W

465 T

740 P

596 H

High Temperature

Shift # 1 Low Temperature

Shift # 2

12 1

, 600

, 998 W

450 T

805 P

621 H 1

, 600

, 998 W

782 T

800 P

606 H 1

, 600

, 998 W

425 T

800 P

440 H

1

, 600

, 998 W

481 T

790 P

437 H

1

, 600

, 998 W

471 T

785 P

432 H Two

- Stage

Selexol Clean

Gas

CO 2 Acid

Gas

Multistage

Intercooled CO 2

Compressor

Interstage Knockout 17

10 14

1

, 005

, 800 W

124 T

2

, 215 P

- 70 H

Tail Gas Recycle

Compressor Hydrogenation

and Tail Gas

Cooling From IP

BFW To Reheater

and Shift Steam

From IP BFW

, LP BFW

, and Tail Gas Cooling

1

, 149

, 078 W From Syngas

Scrubber

To Coal Slurry

, Syngas Quench

, and Slag Quench To Water

Treatment Makeup Water Raw Syngas COS Hydrolysis

Preheater

Reboiler From Syngas

Scrubber and HP

Economizer 2 To Syngas

Scrubber and HP

Economizer 1

Fuel Gas

Preheater Fuel Gas to CT

3 6

, 906 W

90 T

125 P

11 H 6

, 906 W

450 T

125 P

92 H

To

Deaerator

From IP

BFW Claus Oxygen

Preheater

From Gland Steam

Condenser To Syngas Cooling

111 T CO 2 Product To LP Turbine

, Preheater

WGS / Gasifier Steam

and Reheater Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas Sour Water Acid Gas

Tailgas Carbon Dioxide

Sour Gas

Sulfur Hydrogen

Water

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical Steam

Gross Plant Power : 684 MWe Auxiliary Load : 190 MWe

Net Plant Power : 494 MWe Net Plant Efficiency

, HHV : 29

. 7 %

Net Plant Heat Rate : 11

, 505 Btu / kWh

Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 234 Exhibit 3

- 118 Case B5B

- Q combined cycle power generation heat and mass balance schematic

Source: NETL DOE / NETL

D UAL T RAIN IGCC P LANT C ASE B 5 B

- Q

H EAT AND M ATERIAL F LOW D IAGRAM

B ITUMINOUS BASELINE S TUDY C ASE B 5 B

- Q

GEE G ASIFIER
P OWER B LOCK S YSTEM

DWG

. NO

. BB

- HMB

- CS

- B 5 B

- Q

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES
3 OF 3 Sour Gas

Sour Water

Water Steam

Flue Gas

HP

Turbine IP

Turbine

Air Inlet

Filter Steam Seal Regulator Blowdown

Flash

Gland

Steam

Condenser LP

Turbine Stack

Expander Compressor Generator

Generator

Condensate Pumpa Steam Turbine

State

- of

- the

- art 2008

F

- Class Turbine

7

, 014

, 133 W

59 T

15 P

13 H 1

, 523

, 777 W

101 T

1 P

69 H 8

, 453

, 564 W

270 T

15 P

148 H

199

, 383 W

383 T

460 P

480 H 794

, 842 W

994 T

1

, 815 P

1

, 468 H 6

, 775 W

298 T

65 P

1

, 171 H

1

, 491

, 802 W

441 T

65 P

1

, 245 H

1

, 523

, 777 W

103 T

120 P

71 H 1

, 400 W

615 T

65 P

1

, 331 H

1

, 400 W

212 T

15 P

180 H

21 24

16 23

Hot Well Condenser Make

- up

19

, 815 W

59 T

15 P

27 H 9

, 026 W

661 T

501 P

1

, 327 H

9

, 761 W

615 T

65 P

1

, 331 H 798 W

994 T

1

, 815 P

1

, 468 H 1

, 337 W

505 T

65 P

1

, 277 H Preheater Deaerator

Heater HP

Economizer

1 LP

Economizer HP

Economizer

2 HP Evaporator Superheater

/ Reheater

From Syngas

Cooler To ASU and Fuel

Gas Preheater

Deaerator

HP Pump IP Pump To Claus LP Evaporator

IP to Syngas and

WGS Coolers From Claus

, Process Extraction

, and 250 PSIA Header

LP Extraction Spray

LP Blowdown LP To Syngas

Coolers Cold Reheat

Hot Reheat 8

, 453

, 564 W

1

, 044 T

15 P

359 H 22

To WWT Process

Extraction

LP Pump LP From Syngas Coolers

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical 235 T

274 T

1

, 525

, 679 W

274 T

45 P

242 H

813

, 794 W

279 T

2

, 251 P

247 H 7

, 628 W

274 T

79 P

242 H

5

, 928 W

274 T

79 P

242 H 342

, 287 W

274 T

79 P

242 H 40

, 181 W

276 T

615 P

244 H 367

, 487 W

351 T

2

, 251 P

319 H

305 T 585 T 636 T

18

, 961 W

585 T

2

, 001 P

585 H 550 T

766

, 193 W

661 T

501 P

1

, 327 H 367

, 487 W

585 T

2

, 001 P

585 H 332

, 253 W

298 T

65 P

266 H

170 T

252

, 538 W

298 T

65 P

1

, 171 H 356

, 041 W

298 T

65 P

1

, 171 H 296

, 945 W

276 T

820 P

244 H

1

, 000 W

994 T

1

, 815 P

1

, 468 H 1

, 000 W

212 T

15 P

180 H 39

, 537 W

500 T

250 P

1

, 255 H IP Extraction Steam

to 250 PSIA Header

LP Extraction Spray # 1

Condensate to Tail Gas Cooling 677

, 219 W

385 T

469 P

87 H Nitrogen Diluent

Fuel Gas

Ambient Air IP From WGS and Syngas

Coolers

994 T 298 T From ASU and Fuel

Gas Preheater

Nitrogen Diluent

562

, 828 W

385 T

384 P

87 H Gross Plant Power : 684 MWe Auxiliary Load : 190 MWe

Net Plant Power : 494 MWe Net Plant Efficiency

, HHV : 29

. 7 %

Net Plant Heat Rate : 11

, 505 Btu / kWh

Notes : 1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 235 This page intentionally left blankCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 236 Exhibit 3

- 119 Case B5B

- Q overall en ergy balance

HHV Sensible +

Latent Power Total

Heat In (GJ/hr)

Coal 5,994 (5,681) 5.0 (4.7)

– 5,999 (5,686)

Air

– 120.0 (113.8)

– 120.0 (113.8) Raw Water Makeup

– 87.4 (82.8)

– 87.4 (82.8) Auxiliary Power

– – 685 (650) 685 (650)

TOTAL 5,994 (5,681) 212.4 (201.3) 685 (650) 6,892 (6,532) Heat Out (GJ/hr)

ASU Vent

– 1.6 (1.5)

– 1.6 (1.5) Slag 92.3 (87.5) 37.8 (35.9)

– 130.2 (123.4)

Stack Gas

– 1,317 (1,248)

– 1,317 (1,248)

Sulfur 51.2 (48.5) 0.6 (0.6)

– 51.8 (49.1) Motor Losses and Design

Allowances – – 57.1 (54.2) 57.1 (54.2)

Condenser

– 1,452 (1,376)

– 1,452 (1,376)

Non

- Condenser Cooling Tower

Loads – 830 (787)

– 830 (787)

CO 2 – - 74.0 (

- 70.2)

– - 74.0 (

- 70.2)

Blowdown

– 50.0 (47.4)

– 50.0 (47.4)

CO 2 Capture Losses

– 176.2 (167.0)

– 176.2 (167.0)

Ambient Losses A



### – 163.1 (154.6)

– 163.1 (154.6)

Power

– – 2,463 (2,335) 2,463 (2,335)

TOTAL 143.5 (136.0) 3,955 (3,748) 2,520 (2,389) 6,618 (6,273) Unaccounted Energy B



### – 273 (259)

– 273 (259)

A 

### Ambient losses include all losses to the environment through radiation, convection, etc. Sources of these losses include the combustor, reheater, superheater, and transformers.

B 

### By difference



# 3.4.14 Case B5B

- Q

- Major Equipment List

Major equipment items for the GEE quench

- only gasifier with CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers

used in the cost estimates in Section 3.4.15 . In general, the design conditions include a

10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 237 Case B5B

- Q

– Account 1: Coal Handling

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

5 Stacker/Reclaimer Traveling, linear 1,130 tonne/hr (1,250 tph) 1 0

6 Reclaim Hopper N/A 50 tonne (50 ton) 2 1

7 Feeder Vibratory 180 tonne/hr (200 tph) 2 1

8 Conveyor No. 3 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

9 Coal Surge Bin w/ Vent Filter Dual outlet 180 tonne (200 ton) 2 0

10 Crusher Impactor reduction 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 2 0

11 Conveyor No. 4 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

12 Conveyor No. 5 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

13 Coal Silo w/ Vent Filter and

Slide Gates Field erected 800 tonne (900 ton) 3 0



## Case B5B

- Q

– Account 2: Coal Preparation and Feed

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 80 tonne/h (90 tph) 3 0

2 Conveyor No. 6 Belt w/ tripper 240 tonne/h (270 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 490 tonne (540 ton) 1 0

4 Weigh Feeder Belt 120 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 120 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank with Agitator Field erected 299,880 liters (79,220 gal) 2 0

7 Slurry Water Pumps Centrifugal 830 lpm (220 gpm) 2 1

8 Trommel Screen Coarse 170 tonne/h (190 tph) 2 0

9 Rod Mill Discharge Tank with Agitator Field erected 392,290 liters (103,630 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,300 lpm (900 gpm) 2 2

11 Slurry Storage Tank with Agitator Field erected 1,176,900 liters (310,900 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,500 lpm (1,700 gpm) 2 2

13 Slurry Product Pumps Positive displacement 3,300 lpm (900 gpm) 2 2



## Case B5B

- Q

– Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical,

outdoor 811,000 liters (214,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,380 lpm @ 90 m H 2 O (1,690 gpm @ 300 ft H 2 O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 465,000 kg/hr (1,025,000 lb/hr) 2 0

4 Intermediate

- Pressure Feedwater Pump Horizontal centrifugal, single stage 6,600 lpm @ 30 m H 2 O (1,740 gpm @ 90 ft H 2 O) 2 1

5 High

- Pressure Feedwater Pump No. 1 Barrel type, multi

stage, centrifugal HP water: 3,520 lpm @ 1,800 m H 2 O (930 gpm @ 6,100 ft H 2 O) 2 1

6 High

- Pressure Feedwater Pump No. 2 Barrel type, multi

stage, centrifugal IP water: 1,590 lpm @ 220 m

H 2 O (420 gpm @ 730 ft H 2 O) 2 1Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 238 Equipment

No. Description Type Design Condition Operating Qty. Spares

7 Auxiliary Boiler Shop fabricated, water

tube 18,000 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air Compressors Flooded Screw 28 m 3 

### / min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m 3 

### / min (1,000 scfm) 2 1

10 Closed Cycle Cooling Heat Exchangers Plate and frame 457 GJ/hr (433 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 163,800 lpm @ 20 m H 2 O (43,300 gpm @ 70 ft H 2 O) 2 1

12 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 110 m H 2 O (1,000 gpm @ 350 ft H 2 O) 1 1

13 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 80 m H 2 O (700 gpm @ 250 ft H 2 O) 1 1

14 Raw Water Pumps Stainless steel, single

suction 6,030 lpm @ 20 m H 2 O (1,590 gpm @ 60 ft H 2 O) 2 1

15 Ground Water Pumps Stainless steel, single

suction 3,010 lpm @ 270 m H 2 O (800 gpm @ 880 ft H 2 O) 4 1

16 Filtered Water Pumps Stainless steel, single

suction 4,170 lpm @ 50 m H 2 O (1,100 gpm @ 160 ft H 2 O) 2 1

17 Filtered Water Tank Vertical, cylindrical 2,003,000 liter (529,000 gal) 2 0

18 Makeup Water

Demineralizer Anion, cation, and

mixed bed 230 lpm (60 gpm) 2 0

19 Liquid Waste Treatment System N/A 10 years, 24

- hour storm 1 0



## Case B5B

- Q

– Account 4: Gasifier, ASU, and Accessories Including Low Temperature Heat Recovery and Fuel Gas Saturation

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized slurry

- feed,

entrained bed 2,900 tonne/day, 5.6 MPa (3,200 tpd, 815 psia) 2 0

2 Synthesis Gas Cooler Vertical downflow radiant heat exchanger with outlet quench

chamber 256,000 kg/hr (564,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 475,000 kg/hr (1,048,000 lb/hr) Design efficiency 90% 2 0

4 Raw Gas Coolers Shell and tube with

condensate drain 399,000 kg/hr (881,000 lb/hr) 8 0

5 Raw Gas Knockout

Drum Vertical with mist

eliminator 304,000 kg/hr, 35°C, 5.2 MPa (671,000 lb/hr, 95°F, 755 psia) 2 0

6 Synthesis Gas

Reheater Shell and Tube 50,000 kg/hr (110,000 lb/hr)

7 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 475,000 kg/hr (1,048,000 lb/hr)

syngas 2 0

8 ASU Main Air Compressor Centrifugal, multi

- stage 6,000 m 3 

### / min @ 1.3 MPa (210,000 scfm @ 190 psia) 2 0

9 Cold Box Vendor design 2,400 tonne/day (2,600 tpd) of 95% purity oxygen 2 0

10 Oxygen Compressor Centrifugal, multi

- stage 1,000 m 3 

### / min (42,000 scfm)

Suction

- 1.0 MPa (130 psia) Discharge

- 6.5 MPa (940 psia) 2 0

11 Primary Nitrogen Compressor Centrifugal, multi

- stage 4,000 m 3 

### / min (134,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 2 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 239 Equipment

No. Description Type Design Condition Operating Qty. Spares

12 Secondary Nitrogen Compressor Centrifugal, single

stage 550 m 3 

### / min (19,000 scfm)

Suction

- 1.3 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 2 0

13 Syngas Dilution Nitrogen Boost Compressor Centrifugal, single

stage 2,000 m 3 

### / min (70,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470 psia) 2 0



## Case B5B

- Q

– Account 5: Syngas Cleanup

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber 1 Sulfated carbon bed 304,000 kg/hr (669,000 lb/hr)

, 35°C (95°F)

, 5.2 MPa (750 psia) 2 0

2 Mercury Adsorber 2 Sulfated carbon bed 304,000 kg/hr (669,000 lb/hr)

, 35°C (95°F)

, 5.2 MPa (750 psia) 2 0

3 Sulfur Plant Claus type 146 tonne/day (161 tpd) 1 0

4 Water Gas Shift

Reactors Fixed bed, catalytic 200,000 kg/hr (440,000 lb/hr)

, 232°C (450°F)

, 5.5 MPa (800 psia) 4 0

5 Shift Reactor Heat Recovery Exchangers Shell and Tube Exchanger 1: 154 GJ/hr (146 MMBtu/hr) Exchanger 2: 4 GJ/hr (4 MMBtu/hr) 4 0

6 Acid Gas Removal

Plant Two

- stage Selexol 311,000 kg/hr (685,000 lb/hr)

, 35°C (95°F)

, 5.1 MPa (745 psia) 2 0

7 Hydrogenation

Reactor Fixed bed, catalytic 18,000 kg/hr (40,000 lb/hr)

, 232°C (450°F)

, 0.1 MPa (12.3 psia) 1 0

8 Tail Gas Recycle Compressor Centrifugal 14,000 kg/hr (31,000 lb/hr) each 1 0

9 CO 2 Compressor Integrally geared,

multi

- stage centrifugal 1,100 m 3 

### / min @ 15.3 MPa (39,900 scfm @ 2,215 psia) 4 0



## Case B5B

- Q

– Account 6: Combustion Turbine and Auxiliaries

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Combustion Turbine State

- of

- the

- art

2008 F

- c lass 230 MW 2 0

2 Combustion Turbine

Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 2 0

3 Syngas Expansion

Turbine/Generator Turbo Expander 49,700 kg/h (109,700 lb/h) 5.1 MPa (740 psia) Inlet 3.2 MPa (460 psia) Outlet 2 0



## Case B5B

- Q

– Account 7: HRSG, Ducting, and Stack

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type

409SS liner 76 m (250 ft) high x 8.5 m (28 ft) diameter 1 0

2 Heat Recovery
Steam Generator Drum, multi

pressure with

economizer section and integral

deaerator Main steam

- 198,294 kg/hr,

12.4 MPa/534°C (437,163 lb/hr, 1,800 psig/994°F) 2 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 240 Case B5B

- Q

– Account 8: Steam Turbine Generator and Auxiliaries

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Steam

Turbine Commercially available

advanced steam turbine 225 MW 12.4 MPa/534°C/534°C (1,800 psig/ 994°F/994°F) 1 0

2 Steam

Turbine
Generator Hydrogen cooled, static

excitation 250 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 1 0

3 Surface

Condenser Single pass, divided

waterbox including

vacuum pumps 1,600GJ/hr (1,510 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1 0

4 Steam Bypass One per HRSG 50% steam flow @ design steam

conditions 2 0



## Case B5B

- Q

– Account 9: Cooling Water System

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 485,000 lpm @ 30 m (128,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative, mechanical draft,

multi

- cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,700 GJ/hr (2,560 MMBtu/hr) heat duty 1 0



## Case B5B

- Q

– Account 10: Slag Recovery and Handling

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 254,000 liters (67,000 gal) 2 0

2 Slag Crusher Roll 13 tonne/hr (15 tph) 2 0

3 Slag Depressurizer Lock Hopper 13 tonne/hr (15 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 153,000 liters (40,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 69,000 liters (18,000 gal) 2 0

6 Slag Conveyor Drag chain 13 tonne/hr (15 tph) 2 0

7 Slag Separation Screen Vibrating 13 tonne/hr (15 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 13 tonne/hr (15 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 217,000 liters (57,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 60 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 2 2

11 Grey Water Storage Tank Field erected 69,000 liters (18,000 gal) 2 0

12 Grey Water Pumps Centrifugal 250 lpm @ 560 m H 2 O (60 gpm @ 1,850 ft H 2 O) 2 2

13 Slag Storage Bin Vertical, field erected 1,000 tonne (1,100 tons) 2 0

14 Unloading Equipment Telescoping chute 110 tonne/hr (120 tph) 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 241 Case B5B

- Q

– Account 11: Accessory Electric Plant

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 CTG Transformer Oil

- filled 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 2 0

2 STG Transformer Oil

- filled 24 kV/345 kV, 200 MVA, 3

- ph, 60 Hz 1 0

3 High Voltage Auxiliary

Transformer Oil

- filled 345 kV/13.8 kV, 80 MVA, 3

- ph, 60 Hz 2 0

4 Medium Voltage Transformer Oil

- filled 24 kV/4.16 kV, 48 MVA, 3

- ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 7 MVA, 3

- ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 0



## Case B5B

- Q

– Account 12: Instrumentation and Control

Equipment

No. Description Type Design Condition Operating Qty. Spares

1 DCS

- Main
Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 0



# 3.4.15 Case B5B

- Q

- Cost Estimating

The cost estimating methodology was described previously in Section 2.6

. Exhibit 3

- 120 shows a detailed breakdown of the capital costs; Exhibit 3

- 121 shows the owner’s costs , TOC, and

TASC ; Exhibit 3

- 122 shows the initial and annual O&M costs; and Exhibit 3

- 123 sho ws the

COE breakdown.

The estimated TP C of the GEE gasifier with CO 2 

## capture in quench

- only configuration is $3, 405/kW. Pr ocess conti ngency represents 4.0 percent of the TOC and project contingency

represents 13.7 percent. The COE, including CO 2 

## T&S co sts of $ 10.2 /M Wh, is $ 148.9 /M Wh. For comparison, the T P C and COE for Case B5B , GEE in radiant

- only configuration with CO 2 

## capture

, are $3,3 87 /kW and $ 144.7 /M Wh.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 242 Exhibit 3

- 120 Case B5B

- Q total plant cost details

Case: B5B

- Q

– GEE Quench IGCC w/ CO 2 Estimate Type: Conceptual Plant Size (MW,net): 494 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $4,552 $0 $2,194 $0 $6,746 $675 $0 $1,484 $8,905 $18

1.2 Coal Stackout & Reclaim $5,882 $0 $1,406 $0 $7,289 $729 $0 $1,604 $9,621 $19

1.3 Coal Conveyors & Yd Crush $5,469 $0 $1,392 $0 $6,861 $686 $0 $1,509 $9,056 $18

1.4 Other Coal Handling $1,431 $0 $322 $0 $1,753 $175 $0 $386 $2,314 $5

1.9 Coal & Sorbent Hnd. Foundations $0 $3,040 $7,944 $0 $10,984 $1,098 $0 $2,416 $14,499 $29

Subtotal $17,334 $3,040 $13,258 $0 $33,632 $3,363 $0 $7,399 $44,394 $90

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying w/2.3 $0 w/2.3 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,944 $467 $301 $0 $2,712 $271 $0 $597 $3,580 $7

2.3 Slurry Prep & Feed $23,378 $0 $14,694 $0 $38,072 $3,807 $1,904 $8,757 $52,539 $106

2.4 Misc. Coal Prep & Feed $1,069 $781 $2,301 $0 $4,151 $415 $0 $913 $5,479 $11

2.9 Coal & Sorbent Feed Foundation $0 $3,922 $3,365 $0 $7,287 $729 $0 $1,603 $9,618 $19

Subtotal $26,391 $5,170 $20,660 $0 $52,221 $5,222 $1,904 $11,869 $71,217 $144

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $2,281 $3,936 $2,064 $0 $8,280 $828 $0 $1,822 $10,930 $22

3.2 Water Makeup & Pretreating $908 $94 $499 $0 $1,501 $150 $0 $495 $2,146 $4

3.3 Other Feedwater Subsystems $1,282 $424 $379 $0 $2,085 $208 $0 $459 $2,752 $6

3.4 Service Water Systems $531 $1,059 $3,650 $0 $5,240 $524 $0 $1,729 $7,493 $15

3.5 Other Boiler Plant Systems $2,862 $1,069 $2,632 $0 $6,563 $656 $0 $1,444 $8,663 $18

3.6 FO Supply Sys & Nat Gas $17,720 $682 $631 $0 $19,033 $1,903 $0 $4,187 $25,124 $51

3.7 Waste Treatment Equipment $1,229 $0 $761 $0 $1,990 $199 $0 $657 $2,845 $6

3.8 Misc. Power Plant Equipment $1,273 $170 $661 $0 $2,104 $210 $0 $694 $3,009 $6

Subtotal $28,086 $7,433 $11,277 $0 $46,795 $4,680 $0 $11,487 $62,962 $128

4 Gasifier & Accessories

4.1 Quench Gasifier System $79,525 $0 $68,344 $0 $147,869 $14,787 $19,355 $28,338 $210,349 $426

4.3 ASU & Oxidant Compression $231,253 $0 w/equip. $0 $231,253 $23,125 $0 $25,438 $279,816 $567

4.4 Scrubber & LT Heat Recovery $8,555 $0 $0 $0 $8,555 $855 $0 $1,882 $11,292 $23

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $3,060 $2,670 $0 $5,730 $573 $0 $1,576 $7,879 $16

Subtotal $319,333 $3,060 $71,014 $0 $393,407 $39,341 $19,355 $57,233 $509,336 $1,031

5A Gas Cleanup & Piping

5A.1 Double Stage Selexol $160,990 $0 w/equip. $0 $160,990 $16,099 $32,198 $41,857 $251,145 $509

5A.2 Elemental Sulfur Plant $12,451 $2,427 $15,954 $0 $30,831 $3,083 $0 $6,783 $40,697 $82

5A.3 Mercury Removal $1,967 $0 $1,487 $0 $3,454 $345 $173 $794 $4,767 $10

5A.4 Shift Reactors $12,108 $0 $4,841 $0 $16,949 $1,695 $0 $3,729 $22,373 $45

5A.7 Fuel Gas Piping $0 $810 $530 $0 $1,340 $134 $0 $295 $1,769 $4

5A.9 HGCU Foundations $0 $733 $494 $0 $1,227 $123 $0 $405 $1,755 $4

Subtotal $187,516 $3,970 $23,306 $0 $214,792 $21,479 $32,371 $53,863 $322,505 $653Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 243 Case: B5B

- Q

– GEE Quench IGCC w/ CO 2 Estimate Type: Conceptual Plant Size (MW,net): 494 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

5B CO 2 Compression

5B.2 CO 2 Compression & Drying $40,213 $6,032 $17,419 $0 $63,663 $6,366 $0 $14,006 $84,035 $170

Subtotal $40,213 $6,032 $17,419 $0 $63,663 $6,366 $0 $14,006 $84,035 $170

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $111,210 $0 $7,881 $0 $119,091 $11,909 $11,909 $14,291 $157,201 $318

6.2 Syngas Expander $6,686 $0 $918 $0 $7,604 $760 $0 $1,255 $9,619 $19

6.9 Combustion Turbine Foundations $0 $1,016 $1,175 $0 $2,191 $219 $0 $723 $3,133 $6

Subtotal $117,896 $1,016 $9,974 $0 $128,886 $12,889 $11,909 $16,269 $169,953 $344

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $29,570 $0 $5,726 $0 $35,296 $3,530 $0 $3,883 $42,708 $86

7.3 Ductwork $0 $2,109 $1,478 $0 $3,587 $359 $0 $789 $4,734 $10

7.4 Stack $4,069 $0 $1,518 $0 $5,587 $559 $0 $615 $6,761 $14

7.9 HRSG, Duct & Stack Foundations $0 $775 $778 $0 $1,552 $155 $0 $512 $2,220 $4

Subtotal $33,639 $2,883 $9,499 $0 $46,022 $4,602 $0 $5,798 $56,423 $114

8 Steam Turbine Generator

8.1 Steam TG & Accessories $35,245 $0 $4,866 $0 $40,111 $4,011 $0 $4,412 $48,535 $98

8.2 Turbine Plant Auxiliaries $206 $0 $470 $0 $676 $68 $0 $74 $818 $2

8.3 Condenser & Auxiliaries $3,200 $0 $1,812 $0 $5,012 $501 $0 $551 $6,064 $12

8.4 Steam Piping $10,865 $0 $4,712 $0 $15,577 $1,558 $0 $4,284 $21,418 $43

8.9 TG Foundations $0 $951 $1,680 $0 $2,630 $263 $0 $868 $3,761 $8

Subtotal $49,516 $951 $13,540 $0 $64,006 $6,401 $0 $10,190 $80,597 $163

9 Cooling Water System

9.1 Cooling Towers $4,640 $0 $1,400 $0 $6,040 $604 $0 $997 $7,641 $15

9.2 Circulating Water Pumps $2,236 $0 $170 $0 $2,405 $241 $0 $397 $3,043 $6

9.3 Circ. Water System Auxiliaries $194 $0 $27 $0 $221 $22 $0 $36 $280 $1

9.4 Circ. Water Piping $0 $8,587 $2,080 $0 $10,667 $1,067 $0 $2,347 $14,081 $29

9.5 Make

- up Water System $499 $0 $686 $0 $1,185 $118 $0 $261 $1,564 $3

9.6 Component Cooling Water Sys $982 $1,174 $806 $0 $2,962 $296 $0 $652 $3,910 $8

9.9 Circ. Water System Foundations $0 $2,811 $4,995 $0 $7,806 $781 $0 $2,576 $11,162 $23

Subtotal $8,550 $12,572 $10,164 $0 $31,286 $3,129 $0 $7,265 $41,680 $84

10 Ash & Spent Sorbent Handling Systems

10.1 Slag Dewatering & Cooling $14,630 $8,067 $16,277 $0 $38,974 $3,897 $0 $4,287 $47,158 $96

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $710 $0 $767 $0 $1,476 $148 $0 $244 $1,868 $4

10.7 Ash Transport & Feed Equipment $977 $0 $228 $0 $1,205 $120 $0 $199 $1,524 $3

10.8 Misc. Ash Handling Equipment $1,470 $1,801 $534 $0 $3,805 $381 $0 $628 $4,814 $10

10.9 Ash/Spent Sorbent Foundation $0 $60 $78 $0 $138 $14 $0 $46 $197 $0

Subtotal $17,786 $9,928 $17,884 $0 $45,598 $4,560 $0 $5,403 $55,561 $113

11 Accessory Electric Plant

11.1 Generator Equipment $1,106 $0 $1,077 $0 $2,183 $218 $0 $240 $2,641 $5

11.2 Station Service Equipment $5,479 $0 $504 $0 $5,983 $598 $0 $658 $7,240 $15Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 244 Case: B5B

- Q

– GEE Quench IGCC w/ CO 2 Estimate Type: Conceptual Plant Size (MW,net): 494 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

11.3 Switchgear & Motor Control $10,113 $0 $1,880 $0 $11,993 $1,199 $0 $1,979 $15,171 $31

11.4 Conduit & Cable Tray $0 $5,139 $15,840 $0 $20,978 $2,098 $0 $5,769 $28,845 $58

11.5 Wire & Cable $0 $9,907 $6,028 $0 $15,935 $1,594 $0 $4,382 $21,911 $44

11.6 Protective Equipment $0 $806 $2,995 $0 $3,801 $380 $0 $627 $4,808 $10

11.7 Standby Equipment $265 $0 $264 $0 $529 $53 $0 $87 $669 $1

11.8 Main Power Transformers $18,924 $0 $164 $0 $19,088 $1,909 $0 $3,149 $24,146 $49

11.9 Electrical Foundations $0 $172 $468 $0 $639 $64 $0 $211 $914 $2

Subtotal $35,887 $16,024 $29,218 $0 $81,130 $8,113 $0 $17,103 $106,346 $215

12 Instrumentation & Control

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,271 $0 $866 $0 $2,138 $214 $107 $369 $2,827 $6

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $292 $0 $191 $0 $483 $48 $24 $111 $667 $1

12.7 Computer & Accessories $6,782 $0 $222 $0 $7,004 $700 $350 $805 $8,860 $18

12.8 Instrument Wiring & Tubing $0 $2,611 $4,942 $0 $7,553 $755 $378 $2,171 $10,857 $22

12.9 Other I & C Equipment $4,534 $0 $2,246 $0 $6,780 $678 $339 $1,170 $8,966 $18

Subtotal $12,879 $2,611 $8,467 $0 $23,957 $2,396 $1,198 $4,626 $32,177 $65

13 Improvements to Site

13.1 Site Preparation $0 $119 $2,706 $0 $2,826 $283 $0 $932 $4,041 $8

13.2 Site Improvements $0 $2,117 $2,993 $0 $5,110 $511 $0 $1,686 $7,307 $15

13.3 Site Facilities $3,794 $0 $4,259 $0 $8,053 $805 $0 $2,657 $11,516 $23

Subtotal $3,794 $2,236 $9,958 $0 $15,988 $1,599 $0 $5,276 $22,864 $46

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $317 $179 $0 $496 $50 $0 $109 $655 $1

14.2 Steam Turbine Building $0 $2,511 $3,575 $0 $6,086 $609 $0 $1,004 $7,698 $16

14.3 Administration Building $0 $1,033 $749 $0 $1,781 $178 $0 $294 $2,253 $5

14.4 Circulation Water Pumphouse $0 $194 $103 $0 $296 $30 $0 $49 $375 $1

14.5 Water Treatment Buildings $0 $746 $728 $0 $1,474 $147 $0 $243 $1,865 $4

14.6 Machine Shop $0 $529 $361 $0 $890 $89 $0 $147 $1,126 $2

14.7 Warehouse $0 $853 $551 $0 $1,404 $140 $0 $232 $1,776 $4

14.8 Other Buildings & Structures $0 $511 $398 $0 $909 $91 $0 $200 $1,200 $2

14.9 Waste Treating Building & Str. $0 $1,143 $2,182 $0 $3,325 $332 $0 $731 $4,389 $9

Subtotal $0 $7,836 $8,825 $0 $16,661 $1,666 $0 $3,009 $21,337 $43

Total $898,821 $84,762 $274,464 $0 $1,258,047 $125,805 $66,737 $230,797 $1,681,386 $3,405Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 245 Exhibit 3

- 121 Case B5B

- Q owner’s costs

Description $ / 1,000 $/kW

Pre

- Production Costs

6 Months All Labor $14,334 $29

1 Month Maintenance Materials $3,191 $6

1 Month Non

- fuel Consumables $700 $1

1 Month Waste Disposal $494 $1

25% of 1 Months Fuel Cost at 100% CF $3,046 $6

2% of TPC $33,628 $68

Total $55,393 $112

Inventory Capital

60

- day supply of fuel and consumables at 100% CF $25,317 $51

0.5% of TPC (spare parts) $8,407 $17

Total $33,724 $68

Other Costs

Initial Cost for Catalyst and Chemicals $16,691 $34

Land $900 $2

Other Owner's Costs $252,208 $511

Financing Costs $45,397 $92

Total Overnight Costs (TOC) $2,085,698 $4,224

TASC Multiplier (IOU, high

- risk, 35 year) 1.140

Total As

- Spent Cost (TASC) $2,377,696 $4,815Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 246 Exhibit 3

- 122 Case B5B

- Q initial and annual operating and maintenance costs

Case: B5B

- Q

– GEE Quench IGCC w/ CO 2 Cost Base: Jun 2011 Plant Size (MW,net): 494 Heat Rate

- net (Btu/kWh): 11,505 Capacity Factor (%): 80
Operating & Maintenance Labor
Operating Labor Operating Labor Requirements per Shift
Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 Operating Labor Burden: 30.00 % of base Operator: 10.0

Labor O

- H Charge Rate: 25.00 % of labor Foreman: 1.0
Lab Tech's, etc.: 3.0

Total: 16.0 Fixed Operating Costs

Annual Cost ($) ($/kW

- net)
Annual Operating Labor: $7,233,658 $14.649

Maintenance Labor: $15,699,956 $31.795 Administrative & Support Labor: $5,733,403 $11.611

Property Taxes and Insurance: $33,627,713 $68.101

Total: $62,294,730 $126.156
Variable Operating Costs ($) ($/M Wh

- net)

Maintenance Material: $30,633,669 $8.85243

Consumables
Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 4,419 $1.67 $0 $2,159,895 $0.62416 Makeup and Waste Water Treatment Chemicals (lbs): 0 26,325 $0.27 $0 $2,058,884 $0.59497

Carbon (Mercury Removal) (lb): 135,505 232 $5.50 $745,276 $372,638 $0.10768 Shift Catalyst (ft 3 ): 6,443 4.41 $771.99 $4,973,767 $994,753 $0.28746 Selexol Solution (gal): 298,221 95 $36.79 $10,971,928 $1,019,146 $0.29451

Claus Catalyst (ft 3 ): w/equip 2.01 $203.15 $0 $119,480 $0.03453

Subtotal: $16,690,971 $6,724,798 $1.94331
Waste Disposal
Spent Mercury Catalyst (lb.): 0 232 $0.65 $0 $44,045 $0.01273 Flyash (ton): 0 0 $0.00 $0 $0 $0.00000

Slag (ton): 0 641 $25.11 $0 $4,701,028 $1.35849

Subtotal: $0 $4,745,073 $1.37122
By

- Products
Sulfur (tons): 0 146 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000 Variable Operating Costs Total: $16,690,971 $42,103,540 $12.16696

Fuel Cost
Illinois Number 6 (ton): 0 5,844 $68.54 $0 $116,954,695 $33.79724

Total: $0 $116,954,695 $33.79724



### Exhibit 3

- 123 Case B 5B

- Q COE breakdown

Component Value, $/M Wh Percentage

Capital 74.7 54%

Fixed 18.0 13%

Variable 12. 2 9%

Fuel 33.8 24%

Total (Excluding T&S) 138.7 N/A

CO 2 

### T&S 10. 2 7%

Total (Including T&S) 148. 9 N/ACost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 247 

# 3.5 IGCC Case Summary

The performance results of the seven IGCC plant configurations modeled in this report are summarized in Exhibit 3

- 124

.

Exhibit 3

- 124 Estimated performance and cost results for all cases

Integrated Gasification Combined Cycle A

Shell E

- Gas TM FSQ GEE R+Q

Case B1A B1B B4A B4B B5A B5B B5B

- Q

PERFORMANCE

Nominal CO 2 Capture 0% 90% 0% 90% 0% 90% 90% Capacity Factor 80% 80% 80% 80% 80% 80% 80%
Gross Power Output (MWe) 737 673 738 704 748 734 684 Auxiliary Power Requirement (MWe) 108 177 113 190 126 191 190 Net Power Output (MWe) 629 497 625 513 622 543 494 Coal Flow rate (lb/hr) 436,646 465,264 459,956 484,212 466,898 487,005 486,978 Natural Gas Flow rate (lb/hr) N/A N/A N/A N/A N/A N/A N/A

HHV Thermal Input (kW t ) 1,492,878 1,590,722 1,572,575 1,655,503 1,596,309 1,665,056 1,664,962 Net Plant HHV Efficiency (%) 42.1% 31.2% 39.7% 31.0% 39.0% 32.6% 29.7% Net Plant HHV Heat Rate (Btu/kWh) 8,100 10,927 8,585 11,002 8,758 10,459 11,505

Raw Water Withdrawal, gpm 4,150 5,652 4,382 5,757 4,755 5,834 6,137 Process Water Discharge, gpm 788 1,021 905 1,095 984 1,080 1,129 Raw Water Consumption, gpm 3,362 4,631 3,477 4,662 3,771 4,754 5,008 CO2 Captur e Rate (%) 0 90 0 90 0 90 90

CO 2 Emissions (lb/MMBtu) 197 20 199 20 197 20 20

CO 2 Emissi ons (lb/MWh

- gross) 1,361 161 1,448 158 1,434 152 165

CO 2 Emissions (lb/MWh

- net) 1,595 218 1,711 217 1,724 206 228

SO 2 Emissions (lb/MMBtu) 0.004 0.002 0.012 0.002 0.001 0.002 0.002

SO 2 Emissions (lb/MWh

- gross) 0.029 0.017 0.085 0.017 0.009 0.017 0.018 NOx Emissions (lb/MMBtu) 0.059 0.049 0.060 0.049 0.059 0.049 0.049 NOx Emissions (lb/MWh

- gross) 0.409 0.396 0.434 0.396 0.430 0.376 0.404 PM Emissions (lb/MMBtu) 0.007 0.007 0.007 0.007 0.007 0.007 0.007 PM Emissions (lb/MWh

- gross) 0.049 0.057 0.052 0.057 0.052 0.055 0.059 Hg Emissions (lb/TBtu) 0.434 0.372 0.413 0.374 0.412 0.388 0.361 Hg Emissions (lb/MWh

- gross) 3.00E

- 06 3.00E

- 06 3.00E

- 06 3.00E

- 06 3.00E

- 06 3.00E

- 06 3.00E

- 06

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

Bare Erected Cost 2,067 2,963 1,809 2,638 1,870 2,525 2,548 Home Office Expenses 207 296 181 264 187 253 255 Project Contingency 376 562 322 492 330 467 467 Process Contingency 75 160 61 147 61 143 135 Total Overnight Cost (2011$M) 2,107 2,442 1,830 2,252 1,888 2,279 2,086 Total Overnight Cost (2011$/kW) 3,351 4,917 2,929 4,386 3,036 4,195 4,224

Owner's Costs 626 936 557 846 587 807 819

Total As

- Spent Cost (2011$/kW) 3,820 5,605 3,339 5,000 3,461 4,782 4,815 COE ($/MWh) (excluding T&S) 107.0 152.6 99.8 141.9 102.6 135.4 138.7 Capital Costs 59.3 87.0 51.8 77.6 53.7 74.2 74.7

Fixed Costs 14.7 20.5 13.5 19.1 13.7 18.2 18.0

Variable Costs 9.3 13.0 9.2 12.8 9.4 12.2 12.2

Fuel Costs 23.8 32.1 25.2 32.3 25.7 30.7 33.8 COE ($/MWh) (including T&S) 107.0 162.4 99.8 151.8 102.6 144.7 148.9

CO 2 T&S Costs 0.0 9.8 0.0 9.9 0.0 9.2 10.2 CO2 Captured Cost (excluding T&S), $/tonne B N/A 78.9 N/A 66.5 N/A 63.2 61.0 CO2 Avoided Cost (including T&S), $/tonne B N/A 118.7 N/A 102.9 N/A 91.7 99.3

A 

### All cases use high

- risk financial assumptions consistent with NETL’s “QGESS: Cost Estimation Methodology for NETL Assessments of Power Plant Performance.” (2)

B 

### Both the costs of CO 2 

### captured and avoided were calculated based on the non

- capture supercritical pulverized coal (Case B12A ) data provided in the “ Cost and Performance Baseline for Fossil Energy Plants, Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity, Rev ision 3 ” report

. (3) Case

B 1 2A has a COE of $82.3/MWh , a CO 2 

### emission rate of 1,618 lb/MWh

- gross, a gross plant output of

5 79

, 7 00 kW, and a net plant output of 550,012 kW.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 248 The following observations can be made regarding plant performance:

• In the non

- carbon capture cases the dry fed Shell gasifier has the highest net plant efficiency (42.1 percent), followed by the two

- stage E

- Gas TM 

## slurry fed gasifier (39.7 percent) and the single

- stage slurry fed GEE gasifier (39.0 percent). The absolute values

of the GEE and E

- Gas TM 

## gasifiers are close to the reported values per the vendors. (16)

, (51) The Shell efficiency is slightly lower than reported by the vendor in other

presen tations. (48)

• The energy penalty associated with adding CO 2 

## capture is due to steam extraction for use in the SGS reaction, the auxiliary load for the CO 2 

## separation and compression equipment, and a slight derate of the gas turbine due to the higher moisture content of the flue gas. The reduction in net plant efficiency ranges from 6 to 11 percentage points with the variability being due to the optimum gas ifier designs (e.g.

, slurry vs. dry feed, syngas quench vs. syngas heat recovery) which may vary between the capture and non

- capture plant configurations.

• The lowest energy penalty (6 percentage points) corresponds to the GEE Radiant gasifier cases primar ily due to the non

- capture plant design (slurry feed, water quench) which results in a high moisture content in the syngas and thus a low addition of shift steam for SGS for the capture plant design.

• The highest energy penalty (11 percentage points) corre sponds to the Shell gasifier cases. The design uses a dry feed system and, in the non

- capture configuration, has relatively high heat recovery in the syngas cooler with no water quench , resulting in very low moisture content in the syngas. For the captur e configuration, a water quench is added which increases the moisture content of the syngas for the SGS reaction but decreases the heat recovery in the syngas cooler.

• CB&I E

- Gas TM 

## has the highest SO 2 

## emissions ( 0.085 lb/MWh

- gross ) of the seven cases

beca use refrigerated MDEA has the lowest H 2 

## S removal efficiency of the AGR technologies.

The components of TOC and the overall TASC of the seven cases are shown in Exhibit 3

- 125

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



## 249 Exhibit 3

- 125 Plant capital cost for all cases

Source: NETL



## The following TOC observations are made with the caveat that the differences between cases are

less than the estimate accuracy (

- 15 percent /+30 percent ). However, all cases are evaluated using a common set of technical and economic assumptions allowing meaningful comparisons among the cases:

• E

- Gas TM 

## has the lowest TOC cost among the non

- capture cases. The E

- Gas TM



## techn ology 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 TM 

## can use a firetube boiler because the two

- stage design reduces the gas temperature (slurry quench) into a range where a radiant

cooler is not needed.

o The firetube syngas cooler sits next to the gasifier instead of above or below it, which reduces the heig ht of the main gasifier structure. The E

- Gas TM


## proprietary slag removal system

– used instead of lock hoppers below the gasifier

– also contributes to the lower structure height.

• The normalized TOC of the GEE Radiant gasifier case is approximately 4 perce nt greater
than E

- Gas TM



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



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

the low

- cost technology in the CO 2 

## capture cases with E

- Gas TM 

## normalized TOC approximately 5 percent higher and Shell approximately 17 percent higher.

• The ASU cost represents

, on average
, 12 pe rcent of the TOC (range from 10

- 13 percent). The ASU cost includes oxygen and nitrogen compression, and in the non

- capture cases, it

also includes the c ost of the CT extraction air heat exchanger. With nitrogen dilution used to the maximum extent possible, nitrogen compression costs are significant.

• The normalized TOC premium for adding CO 2 

## capture averages 43 percent ($ 4,430 /kW versus $ 3,105 /kW).

The CO E is shown for all seven cases in Exhibit 3

- 126

.

Exhibit 3

- 126 COE for all cases

Source: NETL



## The following observations can be made:

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

• In the non

- capture cases the E

- Gas TM 

## gasifier has the lowest COE, but the differential with Shell is reduced ( relative to the n ormalized TOC comparison) primarily because of the higher efficiency of the Shell gasifier. The Shell COE is 7 percent higher than E

Gas TM 

## (compared to 14 percent higher normalized TOC). The GEE gasifier COE is about 3 percent higher than E

- Gas TM



## .

• In the capture cases the variation in COE is small ; however

, the order of the GEE and E

Gas TM 

## gasifiers is reversed. The range is from $ 144.7 /M Wh for GEE Radiant to $ 162.4 /M Wh for Shell with GEE Quench and E

- Gas TM 

## intermediate at $ 148.9/ M Wh andCost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 251 $ 151.8/ M Wh, resp ectively . The COE CO 2 

## capture premium aver ages 47 percent (range

of 41 to 52 percent).

• The CO 2 

## T&S COE component composes less than 7 percent of the total COE in all

capture cases.

As presented in Section 2.6.4

, the CO 2 

## captured and avoided costs were calculated

, and the

results for the CO 2 

## capture cases are shown in Exhibit 3

- 127

. The cost of captured CO 2 

## represents the minimum CO 2 

## plant gate sales price that will incentivize carbon capture in lieu of

a defined reference non

- capture plant. The cost of CO 2 

## avoided represents the minimum CO 2 

## emissions price , wh en applied to both the capture and non

- capture plant that will incentivize carbon capture in lieu of a defined reference non

- capture plant. Both the costs of CO 2 

## captured

and avoided were calculated based on the non

- capture supercritical pulverized coal ( Case B12A ) data provided in the “ Cost and Performance Baseline for Fossil Energy Plants, Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity, Revision 3 ” report

. (3) This case is representative of the lowest cost non

- capture coal plant option. Case B12A has a COE of $ 82.3 /M Wh , a CO 2 

## emission rate of 1, 618 lb/MWh

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

Exhibit 3

- 127 Cost of CO 2 

### captured and avoided in all cases

Source: NETL



## The cost of CO 2 

## captured using SC PC as the non

- capture reference case averages $ 6 7 /tonne ($ 61 /ton) with a range of $ 6 1

- $ 79 /tonne ($ 55

- $ 72 /ton). The cost of CO 2 

## avoided averages $ 10 3 /tonne ($ 94 /ton ) with a range of $ 92

- $ 11 9 /tonne ($ 8 3

- $ 10 8 /ton).Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 252 The normalized w ater withdrawal, process discharge, and water consumption are presented in

Exhibit 3

- 128

.

Exhibit 3

- 128 Raw water withdrawal and consumption in all cases

Source: N ETL



## The following observations can be made:

• Raw water consumption for all cases is dominated by cooling tower mak eup requirements, which account for 79

- 87 percent of raw water consumption in non

- capture
cases and 73

- 75 percent in CO 2 

## capture cases.

• Normalized water consumption for the GEE non

- capture case is 9 percent h igher than the

E

- Gas TM 

## non

- capture case and 13 percent higher than the Shell non

- capture case primarily because of the large quench water requirement.

• While both the normalized raw water consumption and withdrawal rates are 9 percent greater in the GEE R adiant non

- capture case than in the E

- Gas TM 

## case, the normalized raw water withdrawal and consumption rates are 6 percent and 4 percent greater, respectively, in the E

- Gas TM 

## non

- capture case than the Shell case. The discrepancy

between withdrawal and cons umption is because very little water is available to recover for internal recycle in the dry

- fed Shell system

• The normalized raw water consumption for the four CO 2 

## capture cases varies by 9 percent from the highest to the lowest. The variation between cas es is small because each technology requires approximately the same amount of water in the syngas prior to the shift reactors. The difference in technologies is where and how the water is introduced. Much of the water is introduced in the quench sections of the GEE and Shell cases while

steam is added in the E

- Gas TM 

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



## 253 

# 3.5.1 Sensitivities

The effect of CF and coal price on COE is shown in Exhibit 3

- 129 and Exhibit 3

- 130

, respectively. The assumption implicit in Exhibit 3

- 129 is that each gasifier technology can

achieve a CF of up to 95 percent with no additional capital equipment cost.

Exhibit 3

- 129 Capacity factor sensitivity of all cases

Source: NETL



## The cost differential between technologies decreases as CF increase s. At low CF the capital cost differential is more magnified and the spread between technologies increases slightly.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 254 Exhibit 3

- 130 Sensitivity of COE to c oal price for all cases

Source: NETL



## COE is relatively insensitive to fuel costs ; a tripling of coal price from $1

- $3/MMBtu results in an average COE increase of about 17

- 20 percent for all cases.

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

examin ed in this report will become more expensive. The technologies without carbon capture will be impacted to a larger extent than those with carbon capture.

The curves in Exhibit 3

- 131 represent the study design conditions ( capacity factor) and fuel price

used ; namely an 80 percent capacity factor and $2.78/GJ ($2.94/MMBtu) for coal

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



## 255 Exhibit 3

- 131 Impact of carbon emission s price on study technologies

Source: NETL



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

• The impact of an increasing CO 2 

## emission price has a significantly greater impact on

the COE of the non

- capture plants than the CO 2 

## c apture plants.

• At $60/tonne, the COEs of both the Shell and GEE Radiant cases without CO 2 

## capture are nearly equal to the COE of the GEE Radiant case with CO 2 

## capture.

Sale of the captured CO 2 

## for utilization and storage in CO 2 

## EOR has the potential to pro vide a

revenue stream to the IGCC capture plant configurations. The plant gate CO 2 

## sales price will ultimately depend on a number of factors including plant location and crude oil prices. The cost

of CO 2 

## captured represents the minimum CO 2 

## plant gate sales price that will incentivize carbon capture in lieu of a defined reference non

- capture plant.

The curves in Exhibit 3

- 132 represent the study desig n conditions (capacity factor) and fuel price used; namely an 80 percent capacity factor and $2.78/GJ ($2.94/MMBtu) for coal

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



## 256 Exhibit 3

- 132 Impact of carbon sales price on study technologies

Source: NETL



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

• At $51.1/tonne, the COEs of the Shell CO 2 

## capture and non

- capture cases are equal.

• At $47.0/tonne, the COEs of the E

- Gas TM 

## CO 2 

## capture and non

- capture cases are equal.

• At $39.1/tonn e, the COEs of both the GEE Radiant and GEE Quench CO 2 

## capture cases are equal to the GEE Radiant only non

- capture case.Cost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 257 

# 4 Revision Control

The initial issue of this report was published in May 2007

, and an updated revision was published in November 2010. Subsequent to the reissue date, updates have been made to various report sections. These modifications were made for clarification and aesthetic purposes as well as to bring all costs to 2011 year dollar basis.

Exhibit 4

- 1 contains information that was added, changed

, or deleted in successive revisions.

Exhibit 4

- 1 Record of revisions

Revision

Number Revision

Date Description of Change Comments

1 8/23/07 Added disclaimer to Executive Summary and

Introduction Disclaimer involves clarification on extent of participation of technology vendors.

Removed reference to c ases 7 and 8 in Exhibits ES

- 1 and

1

- 1 since they no longer

exist

. SNG cases moved to Volume 2 of this report as explained in the Executive Summary and Section

1.

Added Section 2.8 Explains differences in IGCC TPC estimates in

this report versus costs reported by other

sources.

Added Exhibit ES

- 14 Mercury emissions are now shown in a separate
exhibit from SO 2 

### , NOx

, and PM because of the different y

- axis scale.

Corrected PC and NGCC

CO 2 

### capture case water

balances The capture process cooling water requirement
for the PC and NGCC CO 2 

### capture cases was

overstated and has been revised.

Replaced Exhibits ES

- 4, 3

- 121, 4

- 52

, and 5

- 30 The old water usage figures were in gpm (absolute) and in the new figures the water

numbers are n ormalized by net plant output.
Updated Selexol process description Text was added to Section 3.1.5 to describe how

H 2 

### slip was handled in the models.

Revised PC and NGCC CO 2 

### capture case energy balances (Exhibits 4

- 21, 4

- 42 and 5

- 21) The earlier version of the energy balances improperly accounted for the capture process heat losses. The heat removed from the capture process is rejected to the cooling tower.

Corrected Exhibit 4

- 13 and

Exhibit 4

- 27. Sensible heat for combustion air in the two NGCC cases was for only one of the two combustion

turbines

– corrected to account for both turbines

2 10/27/10 Updated circulating water
flow rate values in Section

3.1.8. Revision 1 changes to capture system cooling

water flow rate were not made in the text in

Section 3.1.8 (Circulating Water System).
Added Suppl e mental Chapter 6 “Effect of Higher

Natural Gas Prices and Dispatch

- Based Capacity

Factors” N/A

Added Supplemental Chapter 7 “Dry and Parallel Cooling” N/ACost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 258 Revision

Number Revision

Date Description of Change Comments

Added Supplemental Chapter 8 “GEE IGCC in
Quench

- Only Configuration

with CO 2 

### Capture” N/A

Added Supplemental Chapter 9 “Sensitivity to MEA System Performance

and Cost Bituminous

Baseline Case B12BA” N/A

Updated Aspen models Major Aspen model updates included:

• Converting FORTRAN code

- based steam cycles to Aspen blocks

• Using the Peng

- Robinson property method in the Aspen gasifier section

• Modifying the AGR used in the IGCC cases to more closely represent commercially available technology

• Increasing the capture efficiency of the E

Gas TM 

### plant with capture to achieve 90 percent

• Correcting a steam condition error in the supercritical PC cases with capture

Updated case performance

results Major updates included:

• Revising the water balances to include withdrawal and consumption

• CAD

- based HMB diagrams were replaced

with Visio versions

Completed updating case

economic results Major updates included:

• Adding owner’s costs to the total plant costs to generate total overnight cost

• Updating fuel costs

• Revising the T&S methodology to include the July, 2007 Handy

- Whitman Index, pore space acquisition costs, and liability costs

• Re

- costing of cases based on the updated performance results

• Switching to COE as the primary cost metric (as opposed to levelized COE)
Updated report tables, figures

, and text to reflect the revision 2 changes N/A

2a 9/19/2013 Section 2.7.1 was revised to clarify the text that explains the level of technology maturity reflected in the plant

level cost estimates. N/ACost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 259 Revision

Number Revision

Date Description of Change Comments

2b 7 / 13 /201 5 Volume 1 has been split into

two sub volumes. Major updates included:

• IGCC cases are reported in Volume 1b with a

cost

- only update (issued as an update to revision 2a)

• PC and NGCC cases are reported in Volume 1a with a cost and performance update (issued as revision 3)

• Executive summary significantly revised and

shortened

• Results analysis section added
Separated Suppl e mental Chapter 6 “Effect of Higher

Natural Gas Prices and Dispatch

- Based Capacity

Factors” into a stand

- alone report. N/A

Separated Supplemental Chapter 7 “Impact of Dry and Parallel Cooling Systems on

Cost and Performance of

Fossil Fuel Power Plants”

into a stand

- alone report. N/A

Incorporated the Supplemental Chapter 8

“GEE IGCC in Quench

- Only Configuration with CO 2 

### Capture” into the body of the
report. The supplemental chapter was broken down and the information regarding the case describe within it is presented similar to cases B5A and B5B in
Section 3.4.12.

Removed Supplem ental Chapter 9 “Sensitivity to MEA System Performance

and Cost Bituminous

Baseline Case 12A” N/A

Updated the environmental targets to current limits published by the EPA and presented in Section 2.3 MATS and NSPS regulate SO 2 

### , NOx, Filterable PM, Hg, and HCl on a lb/ MWh

- gross basis.

Updated Section 2.4 covering Capacity Factors Additional information has been included that supports the assumptions made regarding the capacity factors used for each technology type.

Removed portions of Section

2.6 concerning cost estimating methodology Many QGESS documents have been published that detail information generic to a number of studies publishe d by NETL. In an effort to reduce the size of this report, text provided in these
QGESS documents has been removed and references have been inserted that provide the
QGESS document title and revision notation.

Added c ost of CO 2 

### Captured methodology and results. The Cost of CO 2 

### avoided methodology has been moved from the executive summary and

combined with the Cost of CO 2 

### Captured methodology in Section 2.6.4

. Removed Section 2.7 N/ACost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 260 Revision

Number Revision

Date Description of Change Comments

Updated Section 3.1.4 to
reflect the use of a dual

carbon bed. N/A

Updated Section 3.1.5 Superfluous information has been removed and the remaining information has been re

- organized, especially concerning AGR/Gasifier pairings used

in non

- capture cases
Improved the BFD depict ion
of the HRSGs N/A

Updated a ll cases to a new case naming convention. Ex. Revision 2’s Case 1 is now Case B5A

Updated p erformance tables Major updates include:

• Table is split into two sections

o Performance summary

o Plant power and auxil iary load

breakdown

o O 2 

### :Coal ratio

o Cold gas efficiency

o Combustion turbine efficiency

o Steam turbine efficiency and heat

rate

o LHV basis efficiency and heat rate

Updated case performance

results Major updates included:

• Added particle concentration to emissions

results

• Updated Energy Balance tables by adding Motor Losses and Design Allowances, Non

Condenser cooling tower loads, and ambient

losses

Completed updating case

economic results Major updates included:

• Updat ed to 2011 year dollars

• Revised the engineering an d construction management costs

• Added NG supply line

• Updat ed the T&S costing methodology

• Updat ed fuel prices
Updated report tables, figures

, and text to reflect the

R evision 2b changes N/ACost and Performance Baseline for Fossil Energy Plants Volume 1 b : Revision 2b



## 261 

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