# Cost and Performance Baseline for

Fossil Energy Plants

Volume 1 a : Bituminous Coal (PC) and

Natural Gas to Electricity

Revisio n 3

July 6, 2015

DOE/NETL

- 2015/1723 

## OFFICE OF FOSSIL ENE RGY 

# National Energy

Technology LaboratoryCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



# 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 implie d, 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 s pecific commercial product, process, or service by trade name,

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement,

recommendation, or favoring by the United States Government or any agency 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 thereof.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



# Author List :

National Energy Technology Laboratory (NETL)

Tim Fout

General Engineer

Office of Program Performance & Be nefits

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 Sec tor 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 performed

under ESPA T ask 341.03, Activity 17.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



# 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

Office 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 Sti egel

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.

Vladimir Vaysman

WorleyParsons Group, Inc.

Richard W einstein

WorleyParsons Group, Inc.



# DOE Contract Number DE

- FE0004001Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## i 

# Table of Contents

Executive Summary

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

Results Analysis

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

Sensitivities

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

1 Introduction

................................ ................................ ................................ ................................ . 22

2 General Evaluation Basis

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

2.1 Site Characteristics

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

2.2 Coal Characteristics

................................ ................................ ................................ ................. 26

2.3 Natural Gas Characteristics

................................ ................................ ................................ ...... 28

2.4 Environmental Targets

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

2.4.1 PC

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

2. 4.2 NGCC

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

2.4.3 Carbon Dioxide

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

2.5 Capacity Factor

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

2.5.1 Ca pacity Factor Assumptions

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

2.5.2 Existing Plant Data

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

2.5.3 Capacity Factor for Coal Units without Carbon Capture

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

2.5.4 Capacity Factor for Natural Gas Combined Cycle (NGCC) Plants

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

2.5.5 Capacity Factor for Plants with Carbon Capture

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

2.5.6 Perspective

................................ ................................ ................................ ............................ 37

2.6 Raw Water Withdrawal and Consumption

................................ ................................ .............. 37

2.7 Cost Estima ting Methodology

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

2.7.1 Capital Costs

................................ ................................ ................................ ......................... 39

2.7.2 Operation and Maintenance Costs

................................ ................................ ........................ 42

2.7.3 CO 2 

## Transport and Storage

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

2.7.4 Cost of CO 2 

## Captured and Avoided

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

3 Pulverized Coal Rankine Cycle Plan ts

................................ ................................ ....................... 47

3.1 PC Common Process Areas

................................ ................................ ................................ ..... 47

3.1.1 Coal, Activated Carbon, and Sorbent Receiving and Storage

................................ .............. 48

3.1.2 Steam Generator and Ancillaries

................................ ................................ .......................... 48

3.1.3 NOx Control System

................................ ................................ ................................ ............. 51

3.1.4 Activated Carbon I njection

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

3.1.5 Particulate Control

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

3.1.6 Mercury Removal

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

3 .1.7 Flue Gas Desulfurization

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

3.1.8 Carbon Dioxide Recovery Facility

................................ ................................ ....................... 59

3.1.9 Gas Compression and Drying System

................................ ................................ .................. 61

3.1.10 Power Generation

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

3.1.11 Balance of Plant

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

3.1.12 Accessory Electric Plant

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

3.1.13 Instrumentation and Control

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

3.1.14 Performance Summary Metrics

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

3.2 Subcritical PC Cases

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

3.2.1 Process Description

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

3.2.2 Key System Assumptions

................................ ................................ ................................ ..... 73

3.2.3 Sparing Philosophy

................................ ................................ ................................ ............... 74Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## ii 3.2.4 Case B11A Performance Results

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

3.2.5 Case B11A

– Majo r Equipment List

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

3.2.6 Case B11A

– Cost Estimating

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

3.2.7 Case B11B

– PC Subcritical Unit with CO 2 

## Capture

................................ ........................... 92

3.2.8 Case B11B Performance Results

................................ ................................ .......................... 92

3.2.9 Case B11B

– Major Equipment List

................................ ................................ ................... 103

3.2.10 Case B11B

– Cost Estimating

................................ ................................ ........................... 108

3.3 Supercritical PC cases

................................ ................................ ................................ ............ 115

3.3.1 Process Description

................................ ................................ ................................ ............. 115

3.3.2 Key System Assumptions

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

3.3.3 Sparing Philosophy

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

3.3.4 Case B12A Performance Results

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

3.3.5 Case B12A

– Major Equipment List

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

3.3.6 Case B12A

– Costs Estimating Results

................................ ................................ .............. 131

3.3.7 Case B12B

– Supercritical PC with CO 2 

## Capture

................................ .............................. 137

3.3.8 Case B12B Performance Results

................................ ................................ ........................ 137

3.3.9 Case B12B

– Major Equipment List

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

3.3.10 Case B12B

– Cost Estimating Basis

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

3.4 PC Case Summary

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

4 Natural Gas Combined Cycle Plants

................................ ................................ ......................... 167

4.1 NGCC Process Areas

................................ ................................ ................................ ............. 167

4.1.1 Natural Gas Supply System

................................ ................................ ................................ 167

4.1.2 Combustion Turbine

................................ ................................ ................................ ........... 167

4.1.3 Heat Recovery Steam Generator

................................ ................................ ......................... 169

4.1.4 NOx Control System

................................ ................................ ................................ ........... 169

4.1.5 Carbon Dioxide Recovery Facility

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

4.1.6 Steam Turbine

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

4.1.7 Water and Steam Systems

................................ ................................ ................................ ... 171

4.1.8 Accessory Electric Plant

................................ ................................ ................................ ..... 172

4.1.9 Waste Treatm ent/Miscellaneous Systems

................................ ................................ ........... 172

4.1.10 Instrumentation and Control

................................ ................................ ............................. 172

4.1.11 Performance Summary Metrics

................................ ................................ ........................ 173

4.2 NGCC Cases

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

4.2.1 Process Description

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

4.2.2 Key System Assumptions

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

4.2.3 Sparing Philosophy

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

4.2.4 Case B31A Performance Results

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

4.2.5 Case B31A

– Major Equipment List

................................ ................................ ................... 185

4.2.6 Case B31A

– Cost Estimating

................................ ................................ ............................. 188

4.2.7 Case B31B

– NGCC with CO 2 

## Capture

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

4.2.8 Case B31B Performance Results

................................ ................................ ........................ 193

4.2.9 Case B31B Major Equipment List

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

4.2.10 Case B31B

– Cost Estimating

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

4.3 NGCC Case Summary

................................ ................................ ................................ ........... 209

5 Results Analysis

................................ ................................ ................................ ........................ 215

5.1 Performance

................................ ................................ ................................ ........................... 215Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## iii 5.1.1 Energy Efficiency

................................ ................................ ................................ ............... 215

5.1.2 Environmental Emissions

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

5.1.3 Water Use

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

5.2 Cost Results

................................ ................................ ................................ ........................... 218

5.2.1 TOC and TASC

................................ ................................ ................................ ................... 218

5.2.2 COE

................................ ................................ ................................ ................................ ..... 219

5.2.3 CO 2 

## Emission Price Impact

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

5.2.4 CO 2 

## Sales Price Impact

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

5.3 Sensitivities

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

6 Revision Control

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

7 References

................................ ................................ ................................ ................................ . 232Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## iv 

# Exhibits

Exhibit ES

- 1 Case configuration summary

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

Exhibit ES

- 2 Performance summary and environmental profiles

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

Exhibit ES

- 3 Net plant efficiency (HHV basis)

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

Exhibit ES

- 4 Cost summary

................................ ................................ ................................ ......... 17

Exhibit ES

- 5 COE by cost component*

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

Exhibit ES

- 6 COE sensitivity to fuel costs

................................ ................................ .................. 19

Exhibit ES

- 7 Lowest cost tec hnology options at various natural gas and CO 2 

## sales prices

........ 20

Exhibit 1

- 1 Case descriptions

................................ ................................ ................................ ...... 24

Exhibit 2

- 1 Site characteristics

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

Exhibit 2

- 2 Site ambient conditions

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

Exhibit 2

- 3 Design coal

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

Exhibit 2

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

............ 28

Exhibit 2

- 5 Natural gas composition

................................ ................................ ........................... 28

Exhibit 2

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

## , NOx, and Hg

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

Exhibit 2

- 7 Environmental targets for PC cases

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

Exhibit 2

- 8 Environmental targets for NGCC cases

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

Exhibit 2

- 9 Coal plant availability and capacity factor data for units reporting in 2011

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

Exhibit 2

- 10 Coal plant availability and CF average data over the period 2007

- 2011

................ 34

Exhibit 2

- 11 Number of coal units included in the 2011 data

................................ ..................... 34

Exhibit 2

- 12 Number of coal units reporting capacity factors greater than 80%

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

Exhibit 2

- 13 U. S. coal electricity power generation

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

Exhibit 2

- 14 Capital cost levels and their elements

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

Exhibit 2

- 15 CO 2 

## transport and storage costs

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

Exhibit 3

- 1 Typical injection process flow diagram

................................ ................................ .... 55

Exhibit 3

- 2 Mercury removal across a fabric filter during a high

- sulfur bituminous test

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

Exhibit 3

- 3 Cansolv CO 2 

## capture process typical flow diagram

................................ ................. 60

Exhibit 3

- 4 CO 2 

## compressor interstage pressures

................................ ................................ ........ 61

Exhibit 3

- 5 Case B11A block flow diagram, subcritical unit without CO 2 

## capture

.................... 70

Exhibit 3

- 6 Case B11A stream table, subcritical unit without capture

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

Exhibit 3

- 7 Subcritical PC plant study configuration matrix

................................ ....................... 73

Exhibit 3

- 8 Balance of plant assumptions

................................ ................................ ................... 74

Exhibit 3

- 9 Case B11A plant performance summary

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

Exhibit 3

- 10 Case B11A plant power summary

................................ ................................ .......... 76

Exhibit 3

- 11 Case B11A air emissions

................................ ................................ ........................ 76

Exhibit 3

- 12 Case B11A carbon balance

................................ ................................ ..................... 77

Exhibit 3

- 13 Case B11A sulfur balance

................................ ................................ ....................... 77

Exhibit 3

- 14 Case B11A water balance

................................ ................................ ....................... 78

Exhibit 3

- 15 Case B11A heat and mass balance, subcritical PC boiler without CO 2 

## capture

..... 79

Exhibit 3

- 16 Case B11A heat and mass balance, subcritical steam cycle

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

Exhibit 3

- 17 Case B11A overall energy balance (0°C [3 2°F] reference)

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

Exhibit 3

- 18 Case B11A total plant cost details

................................ ................................ .......... 87

Exhibit 3

- 19 Case B11A owner’s costs

................................ ................................ ....................... 90

Exhibit 3

- 20 Case B11A initial and annual operating and maintenance costs

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

Exhibit 3

- 21 Case B11A COE breakdown

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

Exhibit 3

- 22 Case B11B block flow diagram, subcritical unit with CO 2 

## capture

....................... 93Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## v Exhibit 3

- 23 Case B11B stream table, subcritical unit with capture

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

Exhibit 3

- 24 Case B11B plant performance summary

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

Exhibit 3

- 25 Case B11B plant power summary

................................ ................................ .......... 98

Exhibit 3

- 26 Case B11B air emissions

................................ ................................ ........................ 98

Exhibit 3

- 27 Case B11B carbon balance

................................ ................................ ..................... 99

Exhibit 3

- 28 Case B1 1B sulfur balance

................................ ................................ ....................... 99

Exhibit 3

- 29 Case B11B water balance

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

Exhibit 3

- 30 Case B11B heat and mass balance, subcritical PC boile r with CO 2 

## capture

........ 101

Exhibit 3

- 31 Case B11B heat and mass balance, subcritical steam cycle

................................ . 102

Exhibit 3

- 32 Case B11B overall energy balance (0°C [32°F] reference)

................................ .. 103

Exhibit 3

- 33 Case B11B total plant cost details

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

Exhibit 3

- 34 Case B11B owner’s cos ts

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

Exhibit 3

- 35 Case B11B initial and annual operating and maintenance costs

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

Exhibit 3

- 36 Case B11B COE breakdown

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

Exhibit 3

- 37 Case B12A block flow diagram, supercritical unit without CO 2 

## capture

............. 116

Exhibit 3

- 38 Case B12A stream table, supercr itical unit without capture

................................ . 117

Exhibit 3

- 39 Supercritical PC plant study configuration matrix

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

Exhibit 3

- 40 Case B12A plant performance summary

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

Exhibit 3

- 41 Case B12A plant power summary

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

Exhibit 3

- 42 Case B12A air emissions

................................ ................................ ...................... 1 21

Exhibit 3

- 43 Case B12A carbon balance

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

Exhibit 3

- 44 Case B12A sulfur balance

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

Exhibit 3

- 45 Case B12A water balance

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

Exhibit 3

- 46 Case B12A heat and mass balance, supercritical PC boiler without CO 2 

## capture 124

Exhibit 3

- 47 Case B12A heat and mass balance, supercritical steam cycle

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

Exhibit 3

- 48 Case B12A overall energy balance (0°C [32°F] reference)

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

Exhibit 3

- 49 Case B12A total plant cost details

................................ ................................ ........ 132

Exhibit 3

- 50 Case B12A owner’s costs

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

Exhi bit 3

- 51 Case B12A initial and annual operating and maintenance costs

.......................... 136

Exhibit 3

- 52 Case B12A COE breakdown

................................ ................................ ................ 136

Exhibit 3

- 53 Case B12B block flow diagram, supercritical unit with CO 2 

## capture

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

Exhibit 3

- 54 Case B12B stream table, supercritical unit with capture

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

Exhibit 3

- 55 Case B12B plant performance summary

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

Exhibit 3

- 56 Case B12B plant power summary

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

Exhibit 3

- 57 Case B12B air emissions

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

Exhibit 3

- 58 Case B12B carbon balance

................................ ................................ ................... 144

Exhibit 3

- 59 Case B12B sulfur balance

................................ ................................ ..................... 144

Exhibit 3

- 60 Case B12B water balance

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

Exhibit 3

- 61 Case B12B heat and mass balance, supercritical PC boiler with CO 2 

## capture

..... 146

Exhibit 3

- 62 Case B12B heat and mass balance, supercritical steam cycle

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

Exhibit 3

- 63 Case B12B overall energy balance (0°C [32°F] refer ence)

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

Exhibit 3

- 64 Case B12B total plant cost details

................................ ................................ ........ 155

Exhibit 3

- 65 Case B12B owner’s costs

................................ ................................ ..................... 158

Exhibit 3

- 66 Case B12B initial and annual operating and maintenance costs

.......................... 159

Exhibit 3

- 67 Case B12B COE breakdown

................................ ................................ ................. 159

Exhibit 3

- 68 Estimated performance and cost results for PC cases

................................ ........... 160Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## vi Exhibit 3

- 69 Plant capital cost for PC cases

................................ ................................ .............. 162

Exhibit 3

- 70 COE for PC cases

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

Exhibit 3

- 71 Sensitivity of COE to capacity factor for PC cases

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

Exhibit 3

- 72 Sensitivity of COE to coal price for PC cases

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

Exhibit 3

- 73 Cost of CO 2 

## captured and avoided in PC cases

................................ .................... 165

Exhibit 3

- 74 Raw water withdrawal and consumption in PC cases

................................ .......... 166

Exhibit 4

- 1 Combustion turbine typical scope of supply

................................ ........................... 168

Exhibit 4

- 2 Case B31A block flow diagram, NGCC without CO 2 

## capture

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

Exhibit 4

- 3 Case B31A stream table, NGCC without capture

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

Exhibit 4

- 4 NGCC plant study configuration matrix

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

Exhibit 4

- 5 NGCC balance of plant assumptions

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

Exhibit 4

- 6 Case B31A plant perf ormance summary

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

Exhibit 4

- 7 Case B31A plant power summary

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

Exhibit 4

- 8 Case B31A air emissions

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

Exhibit 4

- 9 Case B31A carbon balance

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

Exhibit 4

- 10 Case B31A sulfur balance

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

Exhi bit 4

- 11 Case B31A water balance

................................ ................................ ..................... 181

Exhibit 4

- 12 Case B31A heat and mass balance, NGCC without CO 2 

## capture

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

Exhibit 4

- 13 Ca se B31A overall energy balance (0°C [32°F] reference)

................................ .. 185

Exhibit 4

- 14 Case B31A total plant cost details

................................ ................................ ........ 189

Exhibit 4

- 15 Case B31A owner’s costs

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

Exhibit 4

- 16 Case B31A initial and annual operating and maintenance costs

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

Exhibit 4

- 17 Case B31A COE breakdown

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

Exhibit 4

- 18 Case B31B block flow diagram, NGCC with CO 2 

## capture

................................ .. 193

Exhibit 4

- 19 Case B31B stream table, NGCC wit h capture

................................ ...................... 194

Exhibit 4

- 20 Case B31B plant performance summary

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

Exhibit 4

- 21 Case B31B plant power summary

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

Exhibit 4

- 22 Case B31B air emissions

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

Exhibit 4

- 23 Case B31B carbon balance

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

Exhibit 4

- 24 Case B31B sulfur balance

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

Exhibit 4

- 25 Case B31B water balance

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

Exhibit 4

- 26 Case B31B heat and mass bal ance, NGCC with CO 2 

## capture

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

Exhibit 4

- 27 Case B31B overall energy balance (0°C [32°F] reference)

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

Exhibit 4

- 28 Case B31B total plant cost details

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

Exhibit 4

- 29 Case B31B owner’s costs

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

Exhibit 4

- 30 Case B31B initial and annual operating and ma intenance costs

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

Exhibit 4

- 31 Case B31B COE breakdown

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

Exhibit 4

- 32 Estimated performance and cost results for NGCC cases

................................ .... 209

Exhibit 4

- 33 Plant capital cost for NGCC cases

................................ ................................ ........ 210

Exhibit 4

- 34 COE of NGCC cases

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

Exhibit 4

- 35 Sensitivity of COE to capacity factor in NGCC cases

................................ .......... 212

Exhibit 4

- 36 Sensitivity of COE to fuel price in NGCC cases

................................ .................. 212

Exhibit 4

- 37 First year cost of CO 2 

## captured and avoided in NGCC cases

............................... 213

Exhibit 4

- 38 Raw water withdrawal and consumption in NGCC cases

................................ .... 214

Exhibit 5

- 1 Performance summary and environmental profile for all cases

.............................. 215

Exhibit 5

- 2 Net plant efficiency (HHV basis)

................................ ................................ ........... 216Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## vii Exhibit 5

- 3 Raw water withdrawal and consumption

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

Exhibit 5

- 4 Cost summary for all cases

................................ ................................ ...................... 218

Exhibit 5

- 5 Plant capital costs

................................ ................................ ................................ .... 219

Exhibit 5

- 6 COE by cost component

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

Exhibit 5

- 7 Impact of carbon emissions price on study technologies

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

Exhibit 5

- 8 Lowest cost power generation options comparing NGCC and PC

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

Exhibit 5

- 9 Impact of carbo n sales price on study technologies

................................ ............... 223

Exhibit 5

- 10 Lowest cost power generation options comparing NGCC and coal

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

Exhibit 5

- 1 1 COE sensitivity to fuel costs

................................ ................................ ................. 225

Exhibit 5

- 12 COE sensitivity to capacity factor

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

Exhibit 6

- 1 Record of revisions

................................ ................................ ................................ . 227Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## viii 

# Acronyms and Abbreviations

a cfm Actual cubic feet per minute

ACI Activated carbon injection

AGR Acid gas removal

ANSI American National Standards

Institute

AR As received

Aspen Aspen Plus ®

atm Atmosphere (14.696 psi)

BACT B est available control technology

BAH Booz Allen Hamilton

BEC Bare erected cost

BFD Block flow diagram

BFW Boiler feed water

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

CCF Capital charge factor

CC S 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

CH 4 

### Methane

CL Closed

- loop

cm Centimeter

CO Carbon monoxide

CO 2 

### Carbon dioxide

COE Cost of electricity

COS Carbonyl sulfide

CS Carbon steel

CT Combustion turbine

CTG Combustion turbine

- generator

CWP Circulating water pump

CWS Circulating wat er system

CWT Cold water temperature

DCS Distributed control system

DI De

- ionized

DLN Dry low NOx

DOE Department of Energy DSI Dry sorbent injection

EAF Equivalent availability factor

EIA Energy Information Administration

EMF Emission modification factors

EPA Environmental Protection Agency

EPC Engineer/Procure/Construct

EPRI Electric Power Research Institute

EOR Enhanced oil recovery

ESPA Energy Sector Planning and Analysis

FD Forced draft

FE Fossil energy

FG Flue gas

FGD Flue gas desulfurization

FOAK F irst

- of

- a

- kind

FRP Fiberglass

- reinforced plastic

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

GDP Gross domestic product

GEE General Electric Energy

GJ Gigajou le

GJ/hr Gigajoules per hour

gpd Gallons per day

gpm Gallons per minute

gr/100 scf grains per one hundred standard cubic

feet

GRI Gas Research Institute

GWh Gigawatt

- hour

h, hr Hour

H 2 

### Hydrogen

H 2 

### O Water

H 2 

### S Hydrogen sulfide

H 2 

### SO 4 

### Sulfuric acid

HCl Hydroch loric acid

Hg Mercury

HHV Higher heating value

hp Horsepower

HP High pressure

HRSG Heat recovery steam generator

HSS Heat stable salts

HV High voltageCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## ix HVAC Heating, ventilating, and air

conditioning

HWT Hot water temperature

Hz Hertz

ICR Information Collec tion 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

IPM Integrated Planning Model

ISO International Organization for

Standardization

kg/GJ Kilograms per gigajoule

kg/hr Kilograms per hour

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 gallon

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

LHV Lower heating value

LNB Low NOx burner

LP Low pressure lpm Liters per minute

LV Low voltage

m Meter

m/min Meters per minute

m 3 

### /min Cubic meters per minute

md Millidarcy (a measure of

permeability)

MeOH Methanol

mi Mile

mpg Miles per gallon

M Thousand

Mbbl Thousand barrels

Mcf Thousand cubic feet

MA C M ain air compressor

MAF Moisture and ash free

MATS Mercury and Air Toxics Standards

MCR Maximum continuous rate

MDEA Methyldiethanolamine

MEA Monoethanolamine

MHz Megahertz

MJ/Nm 3 

### Megajoules per normal cubic meter

MM Million

MMBtu Million British thermal units

MMBtu/hr Million British thermal uni ts per hour

MMscf Million standard cubic feet

MMscfd Million standard cubic feet per day

MMscfy Million standard cubic feet per year

mole% Mole percent (percent by mole)

MNQC Multi Nozzle Quiet Combustor

MPa Megapascal

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 hy droxide

Neg. Negligible

NEMA National Electrical Manufacturers

Association

NEMS National Energy Modeling System

NERC North American Electric Reliability

CouncilCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## x NETL National Energy Technology

Laboratory

NG Natural gas

NGCC Natural gas combined cycle

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 Source Review

O 2 

### Oxygen

O&M Operation and maintenance

OD Outside diameter

OEM Original equipment manu facturers

OFA Overfire air

OPPA Office of Program Planning &

Analysis

OP/VWO Over pressure/valve wide open

OSHA Occupational Safety and Health

Administration

PA Primary air

PC Pulverized coal

p.f. Power factor

PFD Process flow diagram

PM Particulate matte r

PM 10 

### Particulate matter measuring 10 μm

(micrometers) or less

PO Purchase order

POTW Publicly owned treatment works

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

PAC Powdered activated carbon

PSD Prevention of significant deterioration

psi Pounds per square 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 RD&D Research, Development, and

Demonstration

RH Reheater

RSP Required selling price

RTO Regional transmiss ion

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 meter per hour

SC R Selective catalytic reduction process

or equipment

SG Specific gravity

SO 2 

### Sulfur dioxide

SOx Oxides of sulfur

SNCR Selective non

- catalytic reduction

process or equipment

SS Stainless steel

SS Amine SS Specialty Amine

st Short ton

STG Steam turbine gene rator

SubC PC Subcritical pulverized coal

SWS Sour water scrubber

Syngas Synthetic gas

T&D Transmission and distribution

TASC Total as

- spent cost

TCR Total capital requirement

TEWAC Totally Enclosed Water

- to

- Air

Cooled

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

T & S Transport and storage

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)

vol% Volume percent

WB Wet bulbCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## xi 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 g igajoule

$/kW Dollars per kilowatt $/MMBtu Dol lars per million British thermal

units

$M Millions of dollars

μS/cm micro Sieme ns per cm

°C Degrees Celsius

°F Degrees Fahrenheit

5

- 10s Fifty hour work weeksCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 12 

# Executive Summary

This report presents the cost and performance results of pulverized coal (PC) and natural gas

combined cycle (NGCC) plants, using a con sistent technical and economic approach that reflects

current market conditions. 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%/+30%), but in

application of a consistent approach to allow meaningful comparisons of relative costs among

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: C oal 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

The cost and performance data have been updated for all PC and NGCC cases in this report,

which c onstitutes Volume 1a. IGCC cases, previously integrated with the PC and NGCC cases

in Revision 2a, will be incorporated separately into a Volume 1b. Section 6 has a revision

control table listing the updates applied to this report.

Six power plant conf igurations were analyzed in this report, including four PC cases

– two

subcritical and two supercritical (SC) (with and without CO 2 

## capture); and two state

- of

- the

- art

2013 F

- Class combustion turbine

- based NGCC plants (with and without CO 2 

## capture). While

labeled as SC conditions, the SC steam cycle conditions utilized in this report are also generally

representative of commercial plants characterized as ultra

- supercritical (USC), particularly with

respect to temperature (1100°F). Because efficiency is more sensitive to steam cycle temperature

than pressure, the resulting performance is at or near that of top

- performing commercially

available USC PC plants. The Shell Cansolv CO 2 

## capture system utilized in this report is an

amine

- based solvent system. A sum mary of the case configurations in the report is shown in

Exhibit ES

- 1.

Exhibit ES

- 1 Case configuration summary

Case Unit

Cycle Steam Cycle,

psig/ ° F/ ° F Combustion Turbine Boiler

Technology CO 2 

### Separation

B11A PC 2400/1050/ 1050 N/A Subcritical

PC N/A

B11B PC 2400/1050/1050 N/A Subcritical

PC Cansolv

B12A PC 3500/1100/1100 N/A SC PC N/A

B12B PC 3500/1100/1100 N/A SC PC Cansolv

B31A NGCC 2400/1050/1050 2 x State

- of

- the

- art 2013 F

- Class HRSG N/A

B31B NGCC 2400/1050/1050 2 x State

- of

- the

- art 2013 F

- Class HRSG Cansolv



## All plant configurations were evaluated based on installation at a greenfield site. Capacity

factors (CF) are assumed to approximately equal availability at 85% for all configurations.

Achieving such capacity factors would require that these plants be near the top of the dispatch

list.

The nominal net plant output for this study targets 550 megawatts (MW). The actual net output

varies between technologies because the combustion turbines (CT) in the NGCC c ases areCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



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

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

550 MW, but the NGCC cases have net outputs of 559 MW ( with capture ) and 630 MW ( without

capture ).

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, SO 2 

## , NOx, and PM are actively controlled in all PC cases with dry sorbent injection

(DSI) and activ ated carbon injection (ACI); wet flue gas desulfurization (FGD); low NOx

burners (LNB) with overfire air (OFA) and selective catalytic reduction (SCR); and a baghouse,

respectively. NOx is controlled in both NGCC cases with LNBs and an SCR.

All of the pow er plant configurations with carbon capture in this report are designed to achieve

90 percent capture, resulting in atmospheric CO 2 

## emissions at levels far below proposed EPA

regulation. 1



## The methodology for developing the results presented in this report included performing steady

state simulations of the six power plant configurations using the Aspen Plus ® 

## (Aspen) process

modeling software. The major plant equipment performance and process limits were based upon

published reports, information obtained fr om vendors and users of the technology, performance

data from design/build utility projects, and/or best engineering judgment.

This revision reflects varying degrees of technology vendor input for updates to the pollution

control equipment for PC plants, a nd the CO 2 

## capture, CO 2 

## compression, and steam turbine

technology for PC and NGCC plants; however, the final assessment of performance and cost was

determined independently and is not endorsed by the individual vendors.

The mass and energy balance data fr om the Aspen models were used to size major pieces of

equipment. These equipment sizes formed the basis for the cost estimations. Capital and

operating costs for the major equipment and plant sub

- systems were estimated by WorleyParsons

based on simulatio n results and through scaled estimates from previous design/build projects.

Assumed fuel prices are $2.78/GJ ($2.94/MMBtu) for Illinois No. 6 coal and $5.81/GJ

($6.13/MMBtu) for natural gas, both on a higher heating value ( HHV ) basis , delivered to the

M idwest, and in 2011 United States (U.S.) dollars. 2



## The cost metric used in this study 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 o n 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

1 The Environmental Protection Agency (EPA) proposed a new source performance standard on April 13, 2012, for emissions of carb on 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. (46) The limit set by the proposed regulation is 1,100 lb

- CO 2 /MWh

- gross.

2 As specified in the Qua lity Guidelines for Energy System Studies (QGESS) document on “ Fuel Prices for Selected Feedstocks in NETL Studies.”

(45)Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 14 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 com bination 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

• Availa bility, reliability

, and environmental performance

• Current and future r egulation 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 r ecent commercial

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

Clean Coal and Carbon Management Program

3 Estimated using the FE/NETL CO 2 Transport Cost Model and the FE/NETL CO 2 Saline Storage Cost Model. Add itional detail on development

of these costs is available in the May 2014 revision of the QGESS document “Carbon Dioxide Transport and Storage Costs in NET L Studies.” (27)Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 15 

# Results Analysis

Exhibit ES

- 2 shows the performance and environmental profile summary for all cases. A graph

of the net plant efficienc y (HHV basis) is provided in Exhibit ES

- 3

.

Exhibit ES

- 2 P erformance s ummary and e nvironmental p rofile s

Pulverized Coal Boiler NGCC

PC Subcritical PC Supercritical State

- of

- the

- art 2013

F

- Class

Case Name (Old Case Name ) A 

### B11A (9) B11B (10) B12A (11) B12B (12) B31A (13) B31B (14)

PERFORMANCE

Gross Power Output (MWe) 581 644 580 642 641 601

Auxiliary Power Requirement (MWe) 31 94 30 91 11 42

Net Power Output (MWe) 550 550 550 550 630 559

Coal Flow rate (lb/hr) 412,00 5 516,170 395,053 495,578 N/A N/A

Natural Gas Flow rate (lb/hr) N/A N/A N/A N/A 185,484 185,484

HHV Thermal Input (kW t 

### ) 1,408,630 1,764,768 1,350,672 1,694,366 1,223,032 1,223,032

Net Plant HHV Efficiency (%) 39.0% 31.2% 40.7% 32.5% 51.5% 45.7%

Net Pla nt HHV Heat Rate (Btu/kWh) 8,740 10,953 8,379 10,508 6,629 7,466

Raw Water Withdrawal, gpm 5,538 8,441 5,105 7,882 2,646 4,023

Process Water Discharge, gpm 1,137 1,920 1,059 1,813 595 999

Raw Water Consumption, gpm 4,401 6,521 4,045 6,069 2,051 3,024

C O 2 

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

CO 2 Emissions (lb/MMBtu) 204 20 204 20 119 12

CO 2 Emissions (lb/MWh

- gross) 1,683 190 1,618 183 773 82

CO 2 Emissions (lb/MWh

- net) 1,779 223 1,705 214 786 89

SO 2 Emissions (lb/MMBtu) 0.085 0.000 0.085 0.000 0.001 0.000

SO 2 Emissions (lb/MWh

- gross) 0.700 0. 000 0.673 0.000 0.006 0.000

NOx Emissions (lb/MMBtu) 0.085 0.075 0.088 0.078 0.003 0.003

NOx Emissions (lb/MWh

- gross) 0.700 0.700 0.700 0.700 0.020 0.022

PM Emissions (lb/MMBtu) 0.011 0.010 0.011 0.010 0.000 0.000

PM Emissions (lb/MWh

- gross) 0.090 0.09 0 0.090 0.090 0.000 0.000

Hg Emissions (lb/TBtu) 0.363 0.321 0.377 0.333 0.000 0.000

Hg Emissions (lb/MWh

- gross) 3.00E

- 06 3.00E

- 06 3.00E

- 06 3.00E

- 06 0.00E+00 0.00E+00

A 

### Previous versions of this report us ed a different naming convention. The old case n umbers are provided

here, paired with the new case numbers for reference.



## The primary conclusions that can be drawn are:

• The NGCC cases have the highest net efficiency of all the technologies, both without

CO 2 

## capture (51.5 percent) and with CO 2 

## capture ( 4 5.7 percent). The next highest

efficiency is the non

- capture SC PC case, with an efficiency of 40.7 percent.

• For the PC cases, adding CO 2 

## capture results in a relative efficiency penalty of 20 percent

(8 percentage points).

• For the NGCC case, adding CO 2 

## c apture results in a relative efficiency penalty of 11

percent ( 6 percentage points ) . The NGCC penalty is less than the PC penalty because:

o Natural gas is less carbon intensive than coal (b ased on the fuel compositions

used in this study, natural gas conta ins 32 lb carbon/MM Btu of heat input and

coal contains 5 6 lb/MMBtu).

o The NGCC non

- capture plant is more efficient, thus there is less total CO 2 

## to

capture and compress (NGCC non

- capture CO 2 

## emissions are approximately 54

-Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 16 56 percent lower than the PC cases) when normalized to equivalent net power

outputs.

o These effects are offset slightly by the lower concentration of CO 2 

## in the NGCC

flue gas (4% vs. 13% for PC). When normalized to CO 2 

## captured, the energy

penalty is 0.16 kWh and 0.13 kWh per lb of CO 2 

## capt ured for NGCC and PC,

respectively.

• Estimated emissions of Hg, PM, NOx, and SO 2 

## are all at or below the applicable

regulatory limits currently in effect.

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: Revision 3



## 17 Exhibit ES

- 4 Cost summary

Pulverized Coal Boiler * NGCC *

PC Subcritical PC Supercritical State

- of

- the

- art 2013

F

- Cla ss

Case Name B11A B11B B12A B12B B31A B31B

COST

Total Plant Cost (2011$/kW) 1,960 3,467 2,026 3,524 685 1,481

**Bare Erected Cost** 1,582 2,665 1,646 2,716 561 1,117

**Home Office Expenses** 158 257 165 263 51 97

**Project Contingency** 220 427 216 430 73 19 3

**Process Contingency** 0 118 0 115 0 75

Total Overnight Cost (2011$ MM ) 1,336 2,346 1,37 9 2,384 52 8 1,008

Total Overnight Cost (2011$/kW ) 2,429 4,267 2,507 4,333 838 1,804

**Owner's Costs** 469 800 480 809 154 323

Total As

- Spent Cost (2011$ /kW) 2,755 4,86 5 2,842 4,940 901 1,945

COE ( $/MWh ) (excluding T&S) 82.0 133. 5 82.3 133. 2 57.6 83.3

**Capital Costs** 37.8 71.0 39.0 72. 2 11.8 26. 9

**Fixed Costs** 9.3 15.1 9.6 15.4 3. 4 6. 6

**Variable Costs** 9.2 15. 1 9. 1 14.7 1. 7 4.0

**Fuel Costs** 25. 7 32. 2 24.6 30. 9 40.7 45. 9

COE ( $/MWh ) (including T&S) 82.0 143. 5 82.3 142. 8 57.6 87. 3

**CO** 2 **T&S Costs** 0.0 10.0 0.0 9.6 0.0 4.0

CO 2 

### Captured Cost (excluding T&S)

, $/tonne N/A 56.2 N/A 58.2 N/A 71.1

CO 2 

### Avoided Cost (including T&S)

, $/tonne N/A 91.0 N/A 89.4 N/A 93.8

*Cases with out capture use conventional financing; all others use high

- risk financial asssumptions

consistent with NETL’s “QGESS: Cost Estimation Methodology for NETL Assessments of Power Plant

Performance

. ” (1)



## The primary conclusions t hat can be drawn are:

• Based on total overnight cost (TOC) in $/kW, NGCC ca pital costs are approximately

34 % and 42% of the PC capital costs for non

- capture and capture cases, respectively.

• Capital costs for subcritical and SC PC are essentially equivalen t within the accuracy of

this report for a constant power output.

• The addition of CO 2 

## capture increases the capital costs

– normalized to an equivalent n et

power output

– by 74% and 115 % for PC and NGCC, respectively.

• NGCC plant COEs are 70% and 61% of t he PC plant COEs, for non

- capture and capture

cases, respectively.

• The difference between the SC PC and subcritical PC COEs is minor, given the level of

accuracy of the study estimate.

• The capital cost component represents the largest portion of the COE in PC cases,

ranging from 46

- 51 percent of the total COE. The capital cost in NGCC cases represents

21

- 31 percent of the total COE.

• The fuel cost component represents the largest portion of the COE in NGCC cases,

ranging from 53

- 71 percent of the total CO E. The fuel cost in PC cases represents 22

- 31

percent of the total COE.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 18 • CO 2 

## T&S costs add between $ 4 /M W h (NGCC) and $ 10 /M Wh (PC) to the COE, which is

less than 7 percent of the total for all capture cases.

• The NGCC case incurs a smaller increase in COE by the addition of CO 2 

## capture than PC

cases (52 percent versus approximately 75 percent).

• Despite the higher net plant efficiency and lower increase in COE, both the costs of CO 2 

## avoided and captured are higher for NGCC cases than PC cases (costs of CO 2 

## avo ided are

essentially equivalent within the accuracy of this report with the NGCC case having a 3

- 5

percent greater cost than the PC cases) due to the relatively lower concentration and

amount of CO 2 

## available for capture.

• In the event that future legislati on assigns a cost to carbon emissions, all of the

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,

and coal

- based technologies will be impacted more than natural gas

- based technologies.

Exhibit ES

- 5 COE by cost component *

Source: NETL

*Cases without capture use conventional financing; all others use high

- risk financial asssumptions

consistent with NE TL’s “QGESS: Cost Estimation Methodology for NETL Assessments of Power Plant

Performance.” (1)



# Sensitivities

Exhibit ES

- 6 shows the COE sensitivity to fuel costs for the SC PC and NGCC cases. The bands

for the SC PC cases repr esent a variance of the coal price from $2.21

- $3.69/MMBtu (±25% of

the study value $2.94/MMBtu). This highlights r egions of competitiveness of NGCC with SCPC

systems for cases with and without CCS as a function of delivered natural gas price. As an

exa mple, at a coal cost of $3/MMBtu, the COE of the non

- capture SC PC case equals non

-Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 19 capture NGCC at a natural gas price of approximately $10 .0 /MMBtu. Similarly, the SC PC and

NGCC cases with capture have equivalent COEs at a coal price of $3 .0 /MMBtu and a natural gas price of approximately $13.5 /MMBtu.

Exhibit ES

- 6 COE sensitivity to fuel costs

Source: NETL



## Sale of the captured CO 2 

## for utilization and storage in CO 2 

## enhanced oil recovery (EOR) has the

potential to provide a revenue stream to both the SC PC and NGCC 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 impact of CO 2 

## sales price and the implications on th e competitiveness of the capture technologies can be considered in a “phase diagram” type plot, as

shown in Exhibit ES

- 7 . The lines in the plot represent COE parity between different pairs of

technologies.

The plot demonstrates the following points:

• Non

- c apture plants are the low

- cost option below a first

- year CO 2 

## price of $56/tonne

($51/ton).

• NGCC is preferred when natural gas prices are below $10/MMBtu with a CO 2 

## revenue below $56/tonne (and a capacity factor of 85 percent). The natural gas price

that p rovides parity between the various NGCC and PC cases drops off at higher CO 2 

## revenues reaching $6/MMBtu at approximately $100/tonne ($91/ton). 30 50 70 90 110 130 150 170 190

3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20COE with CO2T&S, $/MWh(2011$)

Delivered Natural Gas Price, $/MMBtu SCPC w/ CCS ($2.94/MMBtu coal)

SCPC w/o CCS ($2.94/MMBtu coal) $2.21

- $3.69 per

MMBtu $2.21

- $3.69 per

MMBtuCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 20 Exhibit ES

- 7 Lowest cost technology options at various natural gas and CO 2 

### sales prices

Source: NETL



# Special Considerations on Reported Costs

Capital Costs:

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

- 15%/+30%,

consistent with AACE Class 4 cost estimates (i.e., feasibility study ) (2) (3) (4) , based on the level

of engineering design performed. In all cases, the report intends to represent the next

commercial offering and relies on vendor cost estimates fo r 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 emerging technologies.

Costs of mature technologies and designs:

Th e cost estimates for plant designs that only contain fully mature technologies

, which have been

widely deployed at commercial scale (e.g., PC and NGCC power plants without CO 2 

## capture)

, reflect nth

- of

- a

- kind (NOAK) on the technology commercialization matur ity spectrum. The

costs of such plants have dropped over time due to “learning by doing” and risk reduction

benefits that result from serial deployments as well as from continuing R&D.

Costs of emerging technologies and designs:

The cost estimates for p lant designs that include technologies that are not yet fully mature (e.g.,

any plant with CO 2 

## capture) use the same cost estimating methodology as the mature plant

designs, which does not fully account for the unique cost premiums associated with the init ial,

complex integrations of emerging technologies in a commercial application. Thus, it isCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 21 anticipated that initial deployments of the capture plants may incur costs higher than those

reflected within this report.

Other factors:

Actual reported projec t costs for 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 environmental

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 r esult 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: Revision 3



## 22 

# 1 Introduction

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

performance of pulverized coal ( PC ) and natural gas combined cycle ( NGCC ) plants, using a

consistent technical and economic approach that reflects current market conditions.

This 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

The cost and performance data have been updated for all PC and NGCC cases in this report,

which constitutes Volume 1a. IGCC cases, previously integrated with the PC and NGCC cases

in Revision 2a, are incorporated separately into a Volume 1b. (5) Section 6 has a revision

control table listing the updates applied to this report.

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

• Capital and operating costs

• Overall energy efficiency

• Fuel prices

• Cost of Electricity ( C OE )

• Availabi lity, reliability

, and environmental performance

• Current and future r egulation 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 rec ent commercial

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

Clean Coal and Carbon Management Program

Six power plant configurations were analyzed in this report, including four PC cases

– two

subcritical and two supercritical (SC) (with and without CO 2 

## capture); and two state

- of

- the

- art

2013 F

- Class combustion turbine

- based NGCC plants (with and without CO 2 

## capture). While

labeled as SC conditions, the SC steam cycle conditions utilized in this report are also generally

representative of com mercial plants characterized as ultra

- supercritical (USC), particularly with

respect to temperature (1,100°F). Because efficiency is more sensitive to steam cycle

temperature than pressure, the resulting performance is at or near that of top

- performing

com mercially available USC PC plants. The Shell Cansolv CO 2 

## capture system utilized in this

report is an amine

- based solvent system. A summary of the case configurations in the report is

shown in Exhibit 1

- 1

.

This r evision reflects varying degrees of technology vendor input for updates to the pollution

control equipment for PC plants, and the CO 2 

## capture, CO 2 

## compression, and steam turbine

technology for PC and NGCC plants; however, the final assessment of performanc e and cost was

determined independently and is not endorsed by the individual vendors

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 23 

## Generating Unit Configurations

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

- 1

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

sections for each case.

The NGCC cases have different gross and net power outputs because of the combustion turbine

(CT) size constraint. The state

- of

- the

- art 2013 F

- class CT used to model the NGCC cases comes

in a standard size of 211 MW when operated at conditions set by the International Standards

Organization (ISO). Each case uses two CTs for a combined gross output of 422 MW. In the

combined cycle a heat recov ery steam generator (HRSG) extracts heat from the CT exhaust to

power a steam turbine.

The net output in the NGCC CO 2 

## capture case is significant ly reduced, compared to the non

capture case due to the high auxiliary power load and significant extraction steam requirement of

the CO 2 

## capture system.

While the two CTs provide 422 MW gross output in both NGCC cases, the overall combined

cycle gross output ranges from 601 to 641 MW, which results in a range of net output from 559

(Case B31B) to 630 MW (Case B3 1A). The natural gas feed rate is held constant in both cases

at 84,134 kg/hr (185,484 kb/hr)

.

All four PC cases have a net output of 550 MW. The boiler and steam turbine industry’s ability

to match unit size to a custom specification has been commercial ly demonstrated enabling a

common net output comparison of the PC cases in this report . The coal feed rate was increased

in the CO 2 

## capture cases to increase the gross steam turbine output and account for the higher

auxiliary load, resulting in a constant net output.

The balance of this report is organized as follows:

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

• Chapter 3 describes the PC technologies modeled and presents the results for the four

PC cases.

• Chapter 4 desc ribes the NGCC technologies modeled and presents the results for the

two NGCC cases.

• Chapter 5 provides a cross comparison of NGCC and PC cases

• Chapter 6 includes a record of report revisions.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 24 Exhibit 1

- 1 Case descriptions

Case

(Old Case Name A 

### ) Unit

Cycle Steam Cycle,

psig/ ° F/ ° F Combustion

Turbine Boiler

Technology Oxidant Sulfur Removal/

Recovery PM Control NOx

Control CO 2 

### Separation B



### B11A (9) PC 2400/1050/1050 N/A Subcritical PC Air Wet FGD/ Gypsum Bagh ouse LNB w/OFA

and SCR N/A

B11B (10) PC 2400/1050/1050 N/A Subcritical PC Air Wet FGD/ Gypsum Baghouse LNB w/OFA

and SCR Cansolv

B12A (11) PC 3500/1100/1100 N/A SC PC Air Wet FGD/ Gypsum Baghouse LNB w/OFA

and SCR N/A

B12B (12) PC 3500/1100/1100 N/A SC PC Air Wet FGD/ Gypsum Baghouse LNB w/OFA

and SCR Cansolv

B31A (13) NGCC 2400/1050/1050 2 x State

- of

- the

art 2013 F

- Class HRSG Air N/A N/A LNB and

SCR N/A

B31B (14) NGCC 2400/1050/1050 2 x State

- of

- the

art 2013 F

- Class HRSG Air N/A N/A LNB and

SCR Cansol v

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.

B 

### All cases have a nominal 90 percent removal rate based on the total feedstock minus unburned carbon in ash (PC cases). The rate of CO 2 

### capture from the f lue gas in the Cansolv systems varies. An explanation for the difference is provided in Section 2.4.3 . All cases sequester the

CO 2 

### offsite

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 25 

# 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 technolog y, performance data from design/build utility projects, and/or

best engineering judgment. Capital and operating costs were estimated by WorleyParsons based

on simulation results and through scaled estimates from previous design/build projects.

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 the st udy. Technology specific design

criteria are covered in subsequent chapters.



# 2.1 Site Characteristics

All plants in this report are assumed to be located at a generic plant site in Midwestern U.S., with

site characteristics and ambient conditions as presented in Exhibit 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 (Pulverized Coal), acres 300

Size (Natural Gas Combined Cycle), acres 100

Transportation Rail or Highway

Ash Disposal Off

- Site

Water 50% Municipal and 50% Ground Water

Exhi bit 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 Temperatu re, °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 

### 72.429

O 2 

### 25.352

Ar 1.761

H 2 

### O 0.382

CO 2 

### 0.076

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.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 26 The land area for PC cases assumes that 30 acres are required for the plant proper and t he

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 not included in this analysis) . In the NGCC cases it

was assumed the plant proper occupies about 10 acres le aving a buffer of 0.15 mi to the plant

fence line.

In all cases it was assumed that the steam turbine is enclosed in a turbine building ; in the PC

cases the boiler is also enclosed. The CTs in the NGCC cases are not enclosed.

The following design paramete rs 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/sno wfall criteria

• Seismic design

• Buildings/enclosures

• Local code height requirements

• Noise regulations

– Impact on site and surrounding area

• Other localized environmental concerns

• Weather delays



# 2.2 Coal Characteristics

The design coal is Illinois No. 6 with char acteristics 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

. ” (6)

Th e Power Systems Financial Model (PSFM) was used to derive the capital charge factors (CCF)

for this report

. (7) The PSFM requires that all cost inputs have a consistent cost year basis.

Because the capital and operating cost estimates are in June 20 11 dollars, the fuel costs must also

be in June 20 11 dollars.

Assumed fuel price is $2.78/GJ ($2.94/MMBtu) for Illinois No. 6 coal

, on a higher heating value

( HHV ) basis , delivered to the Midwest, and in 2011 United States (U.S.) d ollars. 4

4 As specified in the November 2012 QGESS document on “ Fuel Prices for Selected Feedstocks in NETL Studies.” (45)Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 27 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 3 4.99 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 arithmetic mean value of

0.09 ppm wd with standard deviation of 0.06 based on coal samples ship ped by Illinois mines. (8)

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 ppmwd . The coal mercury content for this report

was assumed to be 0.15 ppmwd for all PC cases, which corresponds to the mean plus one

standard deviation and encompasses about 84 percent of the samples. It was further assumed

that all of the coal Hg enters the gas p hase and none le aves with the bottom ash (9)

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 28 Exhibit 2

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

Source: NETL



# 2.3 Natural Gas Characteristic s

Natural gas is utilized as the fuel in Cases B31A and B31B (NGCC with and without CO 2 

## capture), and its composition is presented in Exhibit 2

- 5

. The natural gas properties are from the

January 2012 revis i on of the QGESS docu m en t “ Specification for Selected Feedstocks ” (10)

with the addition of m ethanethiol ( mercaptan ). (11)

Assumed fuel price is $5.81/GJ ($6.13/MMBtu) for natural gas, on a higher heating value ( HHV )

basis

, delivered to the Midwest, and in 2011 United States (U.S.) dollars. 5



### Exhibit 2

- 5 Natural gas composition

Component Volume Percentage

Methane CH 4 

### 93.1

Ethane C 2 

### H 6 

### 3.2

Propane C 3 

### H 8 

### 0.7

n

- Butane C 4 

### H 10 

### 0. 4

Carbon Dioxide CO 2 

### 1.0

Nitrogen N 2 

### 1.6

Methanethiol A 

### CH 4 

### S 5.7 5 x10

- 6



### Total 100.00

LHV HHV

kJ/kg ( Btu/lb ) 47,454 ( 20,410 ) 52,581 ( 22,600 )

MJ/scm (Btu/scf) 34.71 (932) 38.46 (1,032)

A 

### The sulfur content of natural gas is primarily composed of added

Mercaptan (methanethiol

, CH 4 

### S ) with trace levels of H 2 

### S (11)

. Note: Fuel composition is normalized and heating values are calculated

5 As specified in the November 2012 QGESS document on “ Fuel Prices for Selected Feedstocks in NETL Studies.” (45) 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: Revision 3



## 29 

# 2.4 Environmental Targets

Environmental targets were established for each of the technologies as follows:

• Mercury (Hg) and hydrochloric acid limits were set by the March 2013 update to the

Utility Merc ur y and Air Toxics Standards (MATS) for PC technologies

. (12)

, (13)

, (14)

• Particulate matter (PM) , sulfur dioxide (SO 2 

## ) , and nitrogen oxide (NOx) limits were set

by the February 2013 update to the New Source Perf ormance Standards (NSPS) for PC

and NGCC technologies

. (14)

, (15)

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 n on

- low rank. Therefore, 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 emission limits imposed by MATS and NSPS that apply to each technology in this report are provided in Exhibit 2

- 6

.

Exhibit 2

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

### , NOx, and Hg

Pollutant A 

### PC

(lb/ MWh

- gross) NGCC

(lb/ MWh

- gross)

SO 2 

### 1.00 0.90

NOx 0.70 0.43

PM (Filte rable) 0.09 N/A

Hg 3x10

- 6 

### N/A

HCl 0.010 N/A

A 

### CO emissions may be considered in later revisions of this report, if necessary.



## These new regulations apply to PC and NGCC technologies that begin construction after May 3,

2011. Furthermore, these regulatio ns state that (14)

, (16) :

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 po tential electric 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

f uels. To be capable 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 a rea, 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

avera ge 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.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 30 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 Ne w Source

Review (NSR) permitting process and Prevention of Significant Deterioration (PSD). The NSR

process requires installation of emission control technology

, meeting either BACT

determinations for new sources being located in areas meeting ambient air quality standards

(attainment areas), or Lowest Achievable Emission Rate (LAER) technology for sources being

located in areas not meeting ambient air quality standards (non

- attainment areas).

Environmental area designation varies by county and can be est ablished only for a specific site

location. Based on the EPA Green Book Non

- attainment Area Map relatively few areas in the

Midwestern U.S. are classified as “non

- attainment

, ” so the plant site for this report was assumed

to be in an attainment area. (15)

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

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

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

this report

.



## 2.4.1 PC

Exhibit 2

- 7 provides the emissions limits for PC plants as well as a brief summary of the control

technology utilized to satisfy the limits.

Exhibit 2

- 7 Environmental targets for PC cases

Pollutant PC

(lb/ MWh

- gross) Control Technology

SO 2 

### 1.00 Wet limestone scrubber

NOx 0.70 Low NOx burners, overfire air and SCR

PM

(Filterable) 0.09 Fabric filter

Hg 3x10

- 6 

### Co

- b enefit capture

, dry sorbent injection A 

### , activated carbon

injection

HCl 0.010 S O 2 

### surrogate B

A 

### Limits SO 3 

### levels and their detrimental effects on activated carbon injection (See Section 3.1.6)

A 

### SO 2 

### may be utilized as a surrogate for HCl measurement i f the EGU utilizes wet FGD

. (17)



## It was assumed that low NOx burners ( LNB ) and staged overfire air ( OFA ) would limit NOx

emissions to 0.5 lb/MMBtu and that selective catalytic reduction ( SCR ) technology would be 83

- 85 percent efficient. By adjusting the ammonia flow rate in the SCR, the NOx emissions limit

was able to be met exactly.

The wet limestone scrubber was assumed to be 98 percent efficient, which results in SO 2



## emissions below the NSPS SO 2 

## limit. Current technology allows wet flue gas desulfurizationCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 31 ( FGD ) removal efficiencies in excess of 99 percent, but based on NSPS requirements, such high

removal efficiency is not necessary.

The fabric filter was assumed to be capable of achieving an efficiency of greater than 99 .9

percent. As the required efficiency was approximately 99.9 percent for each case, the efficiency

was varied in order to meet the PM emissions limit exactly.

The mercury removal efficiency required to meet the emission limit is approximately 97 percent

in each case . It was assumed that the total mercury removal rate resulting from the combination

of pollution control technologies used (SCR, dry sorbent injection ( DSI )

, activated carbon

injection ( ACI ) , fabric filters, and FGD) would meet the limit exact ly. DSI is required to limit

the effects of SO 3 

## on Hg capture due to the high sulfur content of the coal in this study. Section

3.1.6 provides a detailed discussion regarding mercury removal and the various systems

involved.



## 2.4.2 NGCC

Exhibit 2

- 8 provides the emissions limits for NGCC plants as well as a brief summary of the

control technology utilized to satisfy the limits.

Exhibit 2

- 8 Environmental target s for NGCC cases

Pollutant NGCC

(lb/ MWh

- gross) Control Technology

SO 2 

### 0.90 Low sulfur content fuel

NOx 0.43 Dry l ow NOx burners and SCR

PM (Filterable) N/A N/A

Hg N/A N/A

HCl N/A N/A



## The NGCC cases were designed to achieve approximately 1.0 ppmvd NOx emissions

( referenced to 15 percent O 2 

## ) through the use of a dry low NOx ( DLN ) burner in the CTG

– t he

DLN burner s are a low NOx design and reduce the emissions to about 9 ppmvd (18) (assumed to

be approximately 98 percent NO a nd referenced to 15 percent O 2 

## )

– and an SCR (19)

.

While a state

- of

- the

- art 2013 F

- class CT alone produces NOx emissions below the limit shown

in Exhibit 2

- 8 , an SCR was included to ensure the plant me t the EPAs prevention of significant

deterioration (PSD) program by installing the best available control technology (BACT). The

SCR system is designed for 90 percent NO reduction while firing natural gas.

The total sulfur content of natural gas is typica lly limited by contr act terms and industry practice

to between 0.25 and 1.00 gr/100 sc f with the average total sulfur content being 0.34 gr/100 scf.

(11) For the purpose of this report, the natural gas was assumed to contain the average value of

total sulfur of 0.34 gr/100 scf (4.71x10

- 4 

## lb

- S/MMBtu). It was also assumed that the added

mercaptan (CH 4 

## S) was the sole contributor of sulfur to the natural gas. The mercaptan

concentration of the natural gas was provided in Exhibit 2

- 5 as 5.75x10

- 6 

## mol% (7.06x10

- 4 

## lb

CH 4 

## S/MMBtu).

If the natural gas contained 1.00 gr

- S/100 scf, the SO 2 

## emissions for the non

- capture case would

be 0.018 lb/MWh

- gross. The CO 2 

## capture system removes virtually all SO 2 

## from the flu e gas.

The pipeline natural gas was assumed to contain no particulate matter (PM), Hg, or HCl

, resulting in zero emissions.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 32 

## 2.4.3 Carbon Dioxide

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

carbon dioxide for new fossil f uel

- fired electric utility generating units. As of the publication of

this report, the EPA is finalizing a rule that may set CO 2 

## emissions limits below that of fossil

fuel

- fired electric utlity generation units without CO 2 

## capture.

The PC and NGCC case s both assume that all of the combusted carbon in the fuel is converted to

CO 2 

## in the flue gas . Carbon dioxide is also generated from limestone in the FGD system and

added as activated carbon (for mercury removal) . The CO 2 

## capture plant design is for 90

percent capture of the CO 2 

## exiting the FGD system , resulting in emissions of 180

- 190 lb/MWh

gross and 82 lb/MWh gross for PC and NGCC plants, respectively

.



# 2.5 Capacity Factor

2.5.1 Capacity Factor Assumptions

Availability is the percent of time during a specific period that 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 p eak availability to

counter lower availability in the first several years of operation.



## 2.5.2 Existing Plant Data

The North American Electric Reliability Council (NERC) Generating Availability Data System

(20) (GADS) provides infor mation on existing plants (e.g. Generating Analysis Reports,

Generating Availability Reports, Generating Unit Statistical Brochure, Historical Availability

Statistics). These data for coal plants (e.g. PC technology) include average availability and plant

capacity factor data, by fuel type and plant capacity

.

The GADS data base provides data on many p lant operating characteristics. Three metrics are

used in this report to evaluate existing plant availability and capacity factors (availability factor

(AF), net capacity factor (NCF), and equivalent availability factor (EAF))

. The metrics can be

defined by the following equations.

NNNNNN = NNNNNN

PPPP ∗ � GG

− CC

AAAA �

Where:

NAG

– Net actual generation

PH

– number of hours a unit was in the active stat e

GMC

– Gross maximum capacity

CU

– Capacity utilized for unit station service

Aux

– Auxiliaries

= PPPP

− ( PPPPPP + + )

PPPP

Where:

POH

– Planned outage hoursCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 33 FOH

– Forced outage hours

MOH

– Maintenance outage hours

EE = ( PPPP

− ( PPPPPP + + ) )

− ( EE EE + EE EE + EEEEEEEE )

PPPP

Where:

EUDH

– Equivalent un

- planned derated hours

EPDH

– Equivalent planned derated hours

ESEDH

– Equivalent seasonal derated hours

The EAF is essentially a measure of the plant CF

, assuming there is always a demand for the

output. The EAF accounts for planned and scheduled derated hours as well as seasonal derated

hours. As such, the EAF matches this report ’s definition of CF.



## 2.5.3 Capacity Factor for Coal Units without Carbon Capture

Exhibit 2

- 9 presents GADS coal unit availability and capacity factor data for generating plants in

2011. In order to provide perspective on these metrics over time, Exhibit 2

- 10 presents the same

metrics averaged over the perio d 2007

- 2011. The number of generating units included in the

2011 data is presented in Exhibit 2

- 11

.

Exhibit 2

- 9 Coal p lant a vailability and c apacity f actor d ata for u nits r eportin g in 2011

Source: NETLCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 34 Exhibit 2

- 10 Coal p lant a vailability and CF a verage d ata o ver the p eriod 2007

- 2011

Source: NETL

Exhibit 2

- 11 Number of c oal u nits i ncluded in the 2011 d ata

Source: NETLCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 35 The baseline study net unit capacity is 550 MW. The average EAF for coal

- fired plants in the

400

- 599 MW size range was 83.7 percent in 2011 and averaged 81.8 percent from 2007

- 2011.

The average net capacity facto r for these units is less than 70 percent, which reflects the demand

and how the plants were dispatched.

While the assumption for this report is that a unit will be dispatched when it is available, it is

useful to have perspective on the ability of coal un its to achieve high capacity factors. The

Ventyx Velocity Suite (21) database provides data on individual unit performance. Exhibit 2

- 12

presents data on the number of units that achi eved greater than 80 percent capacity factor in a

given year for each year from 2000 through 2012.

Exhibit 2

- 12 Number of c oal u nits r eporting c apacity f actors greater than 80%

Source: NETL



## The 2006

- 2 007 peak in the number of units operating with a given capacity factor is related to

the U.S. coal electricity demand. Exhibit 2

- 13 presents EIA data (22) on electricity generation

that shows a peak i n 2007.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 36 Exhibit 2

- 13 U. S. coal e lectricity power g eneration

Source: NETL



## The GADS data show an average coal unit availability greater than 80 percent and the individual

unit data from Ventyx Velocity sho w up to 162 coal units have operated in a given year with

capacity factors greater than 85 percent. The current study costs are based on mature plant

technology. Based on a review of the available data, an 85 percent capacity factor is selected for

the P C coal units

.



## 2.5.4 Capacity Factor for Natural Gas Combined Cycle (NGCC) Plants

Similar data as used for PC plants were reviewed for natural gas combin ed cycle plants. The

GADS data base shows an average availability of 87.8 percent for 160 combined cycle p lants in

2011. The data over the last ten yea rs show an availability of ~ 90 percent for each year. The

average availability from 1980 to 1995 ranged from 80

- 90 percent . An 85 percent capacity

factor is selected for NGCC plants.



## 2.5.5 Capacity Factor for Plan ts 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 components is

kept constant. A solvent

- based carbon capture technology is used in this report for both power plant configurations (PC and NGCC). The capture and CO 2 

## compression technologies have

commercial operating experience with demonstrated ability for high reliability. Given the use of

commercial tec hnology, albeit at smaller scale, 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 PC

and NGCC plants with capture is 85 percent

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 37 The DOE Energy Information Ag ency (EIA), in their Annual Energy Outlook 2013, projected a

capacity factor of 85 percent for new advanced coal with capture and 87 percent for new

advanced coal without capture.



## 2.5.6 Perspective

Reported unit data and reported plant experience support the c apability to achieve the selected

availability factors for the plants. Important factors required to achieve these availability

projections include a quality plant design that utilizes lessons learned from similar plant designs,

a focus on life cycle cost s, a smart predictive maintenance, a trained plant staff, and an economic

demand for unit power. An illustration of lessons learned and the resulting high plant

availability that can be obtained is reported by Richwine

. (23)

P lant availability 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 electricity (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 an o ptimum economic unit availability for a given application. The

current study 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 85 percent for each year over the life of the plant. It is recognized that the availability of a

given plant will v ary over the life of the 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 abov e and below the

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

selected value.



# 2.6 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 flue gas (in CO 2 

## capture cases) was applied to offset the water demand. The differ ence 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 withd rawn 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 fro m 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 co oling tower makeup, BFW makeup, ash handling makeup , and FGD system makeup. The

difference bet ween withdrawal and process water returned to the source is consumption.

Consumption represents the net impact of the process on the water source.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 38 BFW blowdown and a portion of the sour water stripper blowdown were assumed to be treated

and recycled to th e cooling tower. The cooling tower blowdown and the balance of the SWS

blowdown streams were assumed to be treated and 90 percent returned to the water source with

the balance sent to the ash ponds for evaporation.

The largest consumer of raw water in all cases is cooling tower makeup. It was assumed that all

cases utilized a mechanical draft, evaporative cooling tower, and all process blowdown streams

were assumed to be treated and recycled to the cooling tower. The design ambient wet bulb

temperature o f 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 following

(24) :

• 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:

BB BB = EE

− 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 (4) was chosen for this report.

The water b alances presented in subsequent sections include the water demand of the major

water consumers within the process, the amount provided by internal recycle, the amount of raw

water withdrawal by difference, the amount of process water returned to the source

, and the raw

water consumption, again by difference.



# 2.7 Cost Estimating Methodology

Detailed information pertaining to topics such as contracting strategy, EPC contractor services,

estimation of capital cost contingencies, owner’s costs, cost estimate scope, economic

assumptions, 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

. ” (1) Select portio ns are repeated in this report for completeness.

Capital Costs:

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

- 15%/+30%,

consistent with AACE Class 4 cost estimates (i.e., feasibility study ) (2) (3) (4) , based on the level

of engineering design performed. In all cases, the report intends to represent the next

commercial offering, and relies on vendor cost estimates for component t echnologies. It also

applies process contingencies at the appropriate subsystem levels in an attempt to account for

expected but undefined costs (a challenge for emerging technologies).

Costs of mature technologies and designs:

The cost estimates for plan t designs that only contain fully mature technologies

, which have been

widely deployed at commercial scale (e.g., PC and NGCC power plants without CO 2 

## capture)

,Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 39 reflect nth

- of

- a

- kind (NOAK) on the technology commercialization maturity spectrum. The

costs of such plants have dropped over time due to “learning by doing” and risk reduction

benefits that result from serial deployments as well as from continuing R&D.

Costs of emerging technologies and designs:

The cost estimates for plant designs that include technologies that are not yet fully mature (e.g.,

any plant with CO 2 

## capture) use the same cost estimating methodology as for the mature plant

designs, which does not fully account for the unique cost premiums associated with the initial,

complex integrat ions of emerging technologies in a commercial application. Thus, it is

anticipated that initial deployments of the capture plants may incur costs higher than those

reflected within this report.

Other factors:

Actual reported project costs for all of th e 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 environmental

c oncerns, 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.



## 2.7.1 Capital Costs

As illustrated in Exhibit 2

- 14

, this report defines capital cost at five levels: BE C, 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 expendi ture period, which is assumed in most

NETL studies to last five years for coal plants and three years for natural gas 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 its 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 Engi neering, Procurement and Construction Cost (EPCC) comprises the BEC plus the cost

of services provided by the engineering, procurement and construction (EPC) contractor. EPC

services include: detailed design, contractor permitting (i.e., those permits t hat individual

contractors must obtain to perform their scopes of work, as opposed to project permitting, which

is not included here), and project/construction management costs. EPCC is an overnight cost

expressed in base

- year dollars.

The Total Plant Cos t (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” co st, 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: Revision 3



## 40 The Total As

- Spent Cost (TASC) is the sum of all capital expenditures as they are incurred

during the capital expenditure peri od including their escalation. TASC also includes interest

during construction. Accordingly, TASC is expressed in mixed, current

- year dollars over the

capital expenditure period

.

Exhibit 2

- 14 Capital cost levels and their elements

Source: NETL



## 2.7.1.1 Cost Estimate Basis and Classification

The TPC and Operation and Maintenance (O&M) costs for each of the cases in the study were

estimated by WorleyParsons us ing an in

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

- furnished and actual cost

data from recent design projects.

2.7.1.2 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 components of

a system or process so they are included in the specific system account. (This would not be the

case had a facility, area, or commodity account structure been chosen instead).

2.7.1.3 Estimate Scope

The estimates represent a complete power plant facility on a generic site

. The plant boundary

limit is defined as the total plant facility within the “fence line” including coal receiving and

water supply system, but terminati ng at the high voltage side of the main power transformers.

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

added to the COE.

2.7.1.4 Capital Cost Assumptions

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

- house

database and conceptual estimating models for each of the specific technologies. This database 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: Revision 3



## 41 and the respective models are maintained by WorleyParsons as part of a commercial power plant

design base of experienc e for similar equipment in the company’s range of power and proces s projects. 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 d ata provided in PAS, WorleyParsons used the weighted average

payroll plus fringe rate for a standard craft distribution as developed for the estimating

models. PAS presents information for eight separate regions. For this report , Region 5

(IL, IN, MI, MN , OH, and WI) was selected

.

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

craft labor available locally.

• Labor is based on a 50

- hour work

- week (5

- 10s). No additional incentives such as 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 estimates are based on a greenfield site.

• The site is considered to be Seismic Zone 1, relatively level, and free from hazardous

materials, archeological artifacts, or excessive rock. Soil c onditions 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 BE C. 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, docu ment control,

materials management, site safety, and field inspection.

2.7.1.5 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 whil e 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 (25) and the Gross Domestic Product Chain

- type Price Index (26)

, were used as

needed for these adjustments . While these overall indices are nearly constant, it should be noted

that the cost of individual equipment types may still deviate from the June 20 11 reference point.

2.7.1.6 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 t o review the consistency of the direction of the costs.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 42 In performing such a comparison, it is important to reference the technical parameters for each

specific item, as these are the basis for establishing the costs. Scope or assumption differences

can quickly e xplain any apparent anomalies.

2.7.1.6.1 Process Contingency

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

• Cansolv System

– 20 percent on all PC/NGCC capture cases

- post

- combustion

capture process unproven at commercial sc ale for power plant applications

• Instrumentation and Controls

– 5 percent on the PC and NGCC capture cases

– integration issues

2.7.1.7 Owner’s Costs

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

yard costs. Rail spur costs would only be applied to the PC cases; however, the switch yard costs

would be included in all cases.

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 (relatively flat level terrain) plus the costs of any switche s/turnouts

(approximately $50,000 each) and road crossings (approximately $300 per lineal 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 Assess ment of Power Plant

Performance” (1)

.



## 2.7.2 Operation and Maintenance Costs

The production costs or operating costs and related maintenance expenses (O&M) pertain to

those charges associated with operating and maintaining the power pl ants over their expected

life. These costs include:

• 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)

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

generation, and variable O&M, which is proportional to power generation. Taxes and insurance

are included as fixed O&M costs, totaling 2 percent of the TPC.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 43 2.7.2.1 Operating Labor

Operat ing 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.

2.7.2.2 Ma intenance 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 comp onent or section.

2.7.2.3 Administrative and Support Labor

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

O&M labor.

2.7.2.4 Consumables

The cost of consumables, including fuel, was determined on the basis of individual rate s of

consumption, the unit cost of each specific consumable commodity, and the plant annual

operating hours.

Quantities for major consumables such as fuel and sorbent were taken from technology

- specific

heat and mass balance diagrams developed for each p lant application. Other consumables were

evaluated on the basis of the quantity required using reference data.

The quantities for initial fills and daily consumables were calculated on a 100 percent operating

capacity basis. The annual cost for the dai ly 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.

2.7.2.5 Waste Disposal

Waste quantities and disposal costs were determined/evaluated similarly to the consumables. In

this report fly ash and bottom ash from the PC cases are considered a waste with a disposal cost

of $ 27.80 /tonne ($ 25.11 /ton).

2.7.2.6 Co

- Produc ts and By

- Products

By

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

variable marketability of these by

- products, specifically gypsum and sulfur, no credit was taken

for their potential salable value.

It should be noted that by

- product credits and/or disposal costs could potentially be an additional

determining factor in the choice of technology for some companies and in selecting some sites.

A high local value of the product can establish whether or not added capital should be included

in the plant costs to produce a particular co

- product. Ash is a potential by

- product in certain

markets; however, due to the activated carbon injection in the PC cases, the fly ash may not be

marketable

. A s stated above, the as h is considered a waste in this report with a concomitant

disposal cost.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 44 

## 2.7.3 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 Sto rage Cost Model.

Additional detail on development of these costs is available in the May 2014 revision of the

QGESS document “ Carbon Dioxide Transport and Storage Costs in NETL Studies

. ” (27)

T&S costs are reported as first

- ye ar 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

fac ility), 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 first year break

- even price they must charge 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

dedicat ed 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 pipeline is assumed to be

at the temperature of the surrounding soil, typically about 50 o 

## F. Th e 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 i s 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 capacit y, 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 determin es 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 whic h 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 b ased 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.

The financial parameters used in the FE/NETL CO 2 

## Transport Cost Model are:

• 

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

• 

## No minal interest rate on debt: 4.5%/year

• 

## Nominal IRROE: 12%

• 

## Escalation rate: 3%

• 

## Tax rate: 38%

• 

## Project contingency 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 o rder to cover all costs including the minimum return on

equity. The model uses a weighted average cost of capital methodology in determining theCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 45 break

- even first year CO 2 

## price. From the perspective of the CO 2 

## source, the break

- even price is

also the min imum cost of transporting CO 2



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

2011 dollars.

Storage 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 

## unde r U.S. Environmental

Protection Agency 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 signifi cant influence on cost

include financial parameters, the timelines for the various stages of storage and important

activities occurring in 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 c ontingency 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 select ion: 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 buildin gs, surface equipment, monitoring wells and

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, verification and

accounting (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.) The possible

financial implication of long

- term stewardship is included in the model as a state

sponsored trust fund that the storage operator pays into during operations

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

region

- specific storage and monitoring costs 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 NET L studies by taking 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 pl ant location

– Williston Basin

• Montana plant location

– Powder River BasinCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 46 CO 2 

## storage supply

- cost curves were developed for each of the four basins of interest with the

resulting cost for each basin at 25 gigatonnes (Gt) of potential storage shown in Exhibit 2

- 15

. 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 before 25 Gt of CO 2 

## is stored in

any of the four individual ba sins. 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 Exhibit 2

- 15 shows the total T&S costs used in NETL system studies fo r 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

- 15 CO 2 

### transpor t 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 R iver 21.81 24

A 

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



## 2.7.4 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 r eference non

- capture plant. The cost of captured CO 2 

## is

calculated using the following formula :

CCCCCC oo 2 

## CCCCCC CCCCCC = ( CCCCCC 

## − NNNNNN CCCCCC 

## )

2 

## CCCCCC CCCCCC

The cost of CO 2 

## avoided represents the minimum CO 2 

## emissions price that will , when applied to

both the capture and non

- capture plant, incentivize carbon capture in lieu of a defined reference

non

- capture plant. The cost of CO 2 

## avoided is calculated using the following formula:

CCCCCC oo 2 

## AA AA = ( CCCCCC wwwwww h TT & 

## − NNNNNN CCCCCC 

## )

2 

## EEEE EE NNNNNN CCCCCC 

## − 2 

## EEEE EE CCCCCC 

## 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 $/ MWh

o The CCS plant includes compression to 2,215 psia

o For CO 2 

## Captured, the COE excludes transportation and storage (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 r ate 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. Fo r a greenfield natural gas

- based power system, the reference plant used to calculate

the cost of captured and avoided CO 2 

## is a non

- capture natural gas

- based plant.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 47 

# 3 P ulverized Coal Rankine Cycle Plants

Four PC fired Rankine cycle power plant configurations were evaluated and the results are

presented in this section. Each design is based on a market

- ready technology that is assumed to

be commercially available in time for the plant startup date. All designs employ a one

- on

- one configuration comprised of a state

- of

- the art PC steam generator firing Illinois No. 6 coal and a

steam turbine.

The PC cases are evaluated with and without CO 2 

## capture on a common 550 MWe net basis.

The designs that include CO 2 

## capture have a larger gross unit size to compensate for the higher

auxiliary loads. The constant net output sizing basis is selected because it provides for a

meaningful side

- by

- side comparison of the results. The boiler and steam turbine industry ability

to match unit size to a custom specification has b een commercially demonstrated enabling

common net output comparison of the PC cases in this report

.

Steam conditions for the Rankine cycle cases were selected based on a survey of boiler and

steam turbine original equipment manufacturers (OEM), who were asked for the most advanced

steam conditions that they would guarantee for a commercial project in the US with subcritical

and SC PC units rated at nominal 550 MWe net capacities and firing Illinois No. 6 coal

. (28)

Based on th e OEM responses, the following single

- reheat steam conditions were selected for the

study:

 For subcritical cases ( B11A and B11B )

– 16.5 MPa/566°C/566°C

(2,400 psig/1,050°F/1,050°F)

 For SC cases ( B12A and B12B )

– 24.1 MPa/593°C/593°C (3,500 psig/1,100°F/1, 100°F)

S team temperature selection for boilers depends upon fuel corrosiveness. Most of the contacted

OEMs were of the opinion that the steam conditions in this range would be limited to low sulfur

coal applications (such as PRB). Their primary concern i s that elevated temperature operation

while firing high sulfur coal (such as Illinois No. 6) would result in an exponential increase of

the material wastage rates of the highest temperature portions of the superheater and reheater

( RH ) due to coal ash corr osion, requiring pressure parts replacement outages approximately

every 10 or 15 years. This cost would offset the value of fuel savings and emissions reduction

due to the higher efficiency. In addition, three of the most recently built SC units in North

America have steam cycles similar to this report ’s design basis, namely James E. Rogers Energy

Complex in North Carolina , which started operations in 2012 ( 27.0 MPa/5 68 °C/5 79 °C [ 3,922

psia/1,05 5 °F/1,0 75°F]) and Prairie State Energy Campus units 1 and 2 , w hich also started

operation in 201 2 ( 26.2 MPa/ 568 °C /568°C [ 3,800 psig/1,05 5 °F /1,055°F ]).

The evaluation basis details, including site ambient conditions, fuel composition and the

emissions control basis, are provided in Section 2 of this report.



# 3.1 PC Common Process Areas

The PC cases have process areas that are common to each plant configuration, such as coal

receiving and storage, emissions control technologies, power generation, etc. As detailed

descriptions of these process ar eas in each case section would be burdensome and repetitious,

they are presented in this section for general background information. The performance features

of these sections are then presented in the case

- specific sections.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 48 

## 3.1.1 Coal, Activated Carbon, and S orbent Receiving and Storage

The function of the Coal Receiving and Storage system is to unload, convey, prepare, and store

the coal delivered to the plant. The scope of the system is from the trestle bottom dumper and

coal receiving hoppers up to and inc luding the slide gate valves at the outlet of the coal storage

silos. The system is designed to support short

- term operation at the 5 percent over

pressure/valves wide open (OP/VWO) condition (16 hours) and long

- term operation of 90 days

or more at the ma ximum continuous rating (MCR).

The scope of the sorbent receiving and storage system includes truck roadways, turnarounds,

unloading hoppers, conveyors and the day storage bin.

Operation Description

- The coal is delivered to the site by 100

- car unit train s comprised of 91

tonne (100 ton) rail cars. The unloading is done by a trestle bottom dumper, which unloads the

coal into two receiving hoppers. Coal from each hopper is fed directly i nto a vibratory feeder.

The 8 cm x 0 (3" x 0) coal from the feeder i s 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 magn etic plate separator to remove tramp iron and then to the reclaim pile.

Coal from the reclaim pile is fed by two vibratory feeders, located under the pile, onto a belt

conveyor, which transfers the coal to the coal surge bin located in the crusher tower. The coal is

reduced in size to 2.5 cm x 0 (1" x 0) by the coal crushers. The coal is then transferred by

conveyor to the transfer tower. In the transfer tower the coal is routed to the tripper that loads

the coal into one of the six boiler silos.

Limest one is delivered to the site using 23 tonne (25 ton) trucks. The trucks empty into a below

grade hopper where a feeder transfers the limestone to a conveyor for delivery to the storage pile.

Limestone from the storage pile is transferred to a reclaim hop per and conveyed to a day bin.

Non

- halogenated powdered activated carbon (PAC) is delivered to the site using 18 tonne (20

ton) trucks. The trucks pneumatically unload into a storage silo where a feeder hopper transfers

the PAC to a screw feeder that conv eys the PAC into the drop tube. PAC is fed through the drop

tube directly into the eductor suction port. The carbon is transferred from the eductor suction

port through the piping system and injected through a distribution of lances across the flue gas

d uctwork upstream of the baghouse.

H ydrated lime is delivered and distributed in a manner very similar to that of the PAC: t he

sorbent is contained in the main storage silo and fed to a weigh hopper for conveying through

transport piping to the sorbent dist ribution manifold upstream of the air pre heater.



## 3.1.2 Steam Generator and Ancillaries

The steam generator for the subcritical PC plants is a drum

- type, wall

- fired, balanced draft,

natural circulation, totally enclosed dry bottom furnace, with superheate r, reh eater, economizer

and air pre heater.

The steam generator for the SC plants is a once

- throug h, spiral

- wound, Benson

- boiler, wall

- fired,

balanced draft type unit with a water

- cooled dry bottom furnace . It includes a superheater,

reheater, economizer, and ai r pre heater

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 49 The combustion systems for both subcritical and SC steam conditions are equipped with LNBs

and OFA. It is assumed for the purposes of this report that the power plant is designed for

operation as a base

- load unit but with some consideration f or daily or weekly cycling

.

3.1.2.1 Scope

The steam generator includes the following for both subcritical and SC PCs , except where

otherwise indicated :

 Drum

- type evaporator

(subcritical only)  Economizer  OFA system

 Once

- through type steam

generator (SC only)  Spr ay type desuperheater  Forced draft (FD) fans

 Startup circuit, including

integral separators (SC

only)  Soot blower system  Primary air (PA) fans

 Water

- cooled furnace,

dry bottom  Air preheaters

(Ljungstrom type)  Induced draft (ID) fans

 Two

- stage superheate r  Coal feeders and

pulverizers

 Reheater (RH)  Low NOx Coal burners

and light oil igniters/

warm

- up system

The following subsections describe the operation of the steam generator.

3.1.2.2 Feedwater and Steam

For the subcritical steam system feedwater ( FW ) enters the economizer, recovers heat from the

combustion gases exiting the steam generator, and then passes to the boiler drum, from where it

is distributed to the water wall circuits enclosing the furnace. After passing through the lower

and upper furnace circ uits and steam drum in sequence, the steam passes through the convection

enclosure circuits to the primary superheater and then to the secondary superheater.

The steam then exits the steam generator en route to the high pressure ( HP ) turbine. Steam from

t he HP turbine returns to the steam generator as cold reheat and returns to the intermediate

pressure ( IP ) turbine as hot reheat.

For the SC steam system FW enters the bottom header of the economizer and passes upward

through the economizer tube bank, thro ugh stringer tubes

, which support the primary

superheater, and discharges to the economizer outlet headers. From the outlet headers, water

flows to the furnace hopper inlet headers via external downcomers. Water then flows upward

through the furnace hopp er and furnace wall tubes. From the furnace, water flows to the steam

water separator. During low load operation (operation below the Benson point), the water from

the separator is returned to the economizer inlet with the boiler recirculating pump. Ope ration at

loads above the Benson point is once through.

Steam flows from the separator through the furnace roof to the convection pass enclosure walls,

primary superheater, through the first stage of water attemperation, to the furnace platens. From

the p latens, the steam flows through the second stage of attemperation and then to the

intermediate superheater. The steam then flows to the final superheater and on to the outlet pipeCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 50 terminal. Two stages of spray attemperation are used to provide tight temp erature control in all

high temperature sections during rapid load changes.

Steam returning from the turbine passes through the primary reheater surface, then through

crossover piping containing inter

- stage attemperation. The crossover piping feeds the st eam to

the final reheater banks and then out to the turbine. Inter

- stage attemperation is used to provide

outlet temperature control during load changes.

3.1.2.3 Air and Combustion Products

Combustion air from the FD fans i s heated in Ljungstrom type air pre heater s, recovering heat

energy from the exhaust gases exiting the boiler. This air is distributed to the burner windbox as

secondary air. Air for conveying PC to the burners is supplied by the PA fans. This air is heated

in the Ljungstrom type air preheaters to permit drying of the PC, and a portion of the air from the

PA fans bypasses the air preheaters to be used for regulating the outlet coal/air temperature

leaving the mills.

The PC and air mixture flows to the coal nozzles at various elevations of the furnace. The hot

combustion products rise to the top of the boiler and pass through the superheater and reheater

sections. The gases then pass through the economizer and air preheater. The gases exit the

steam generator at this point and flow to the SCR reactor

, dry sorbent injection (DSI) manifold,

activated carbon injection (ACI) manifold , fabric filter, ID fan, FGD system, and stack.

3.1.2.4 Fuel Feed

The crushed Illinois No. 6 bituminous coal is fed through feeders to each of the mills

(pulverizers), where i ts size is reduced to approximately 72 percent passing 200 mesh and less

than 0.5 percent remaining on 50 mesh

. (29) The PC exits each mill via the coal piping and is

distributed to the coal nozzles in the furnace walls using air supplied by the PA fans.

3.1.2.5 Ash Removal

The furnace bottom comprises several hoppers, with a clinker grinder under each hopper. The

hoppers are of welded steel construction, lined with refractory. The hopper design incorporates a

water

- filled seal troug h around the upper periphery for cooling and sealing. Water and ash

discharged from the hopper pass through the clinker grinder to an ash sluice system for

conveyance to hydrobins, where the ash is dewatered before it is transferred to trucks for offsite

disposal. The description of the balance of the bottom ash handling system is presented in

Secti on 3.1.11

. The steam generator incorporates fly ash hoppers under the economizer outlet

and air pre heater outlet.

3.1.2.6 Burners

A boiler of this capacity employs approximately 24 to 36 coal nozzles arranged at multiple

elevations. Each burner is designed as a low

- NOx configuration, with staging of the coal

combustion to minimize NOx formation. In addition, OFA nozzles ar e provided to further stage

combustion and thereby minimize NOx formation.

Oil

- fired pilot torches are provided for each coal burner for ignition, warm

- up and flame

stabilization at startup and low loads.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 51 3.1.2.7 Dry sorbent Injection

The hydrated lime injection m anifold is located directly before the air preheaters. This SO 3



## control system is discussed in detail in Section 3.1.6

.

3.1.2.8 Air Preheaters

Each steam generator is furnished with two vertical

- shaft Ljungstrom regenerative type air

preheaters. These units are driven by electric motors through gear reducers.

3.1.2.9 Soot Blowers

The soot

- blowing system utilizes an array of 50 to 150 retractable nozzles and lances that clean

the furnace walls and convection surfaces with jets of HP steam. Th e blowers are sequenced to

provide an effective cleaning cycle depending on the coal quality and design of the furnace and

convection surfaces. Electric motors drive the soot blowers through their cycles.



## 3.1.3 NOx Control System

The plant s are designed to achi eve the environmental target of 0. 7 0 lb / MWh

- gross . Two

measures are taken to reduce the NOx. The first is a combination of LNBs and the introduction

of staged OFA in the boiler. The LNBs and OFA reduce the emissions to about 0.5 lb/MMBtu.

The second m easure taken to reduce the NOx emissions is the installation of an SCR system

prior to the air heater. SCR uses ammonia and a catalyst to reduce NOx to N 2 

## and H 2 

## O. The

SCR system consists of three subsystems: reactor vessel, ammonia storage and injectio n, and

gas flow control. The SCR system is designed for 83

- 85 percent reduction with 2 ppmv

ammonia slip at the end of the catalyst life.

The SCR capital costs are included with the boiler costs, as is the cost for the initial load of

catalyst.

Selectiv e non

- catalytic reduction (SNCR) was considered for this application. However, with

the installation of the LNBs and OFA system, the boiler exhaust gas contains relatively small

amounts of NOx, which makes removal of the quantity of NOx with SNCR to reach the

emissions limit difficult. SNCR works better in applications that contain medium to high

quantities of NOx and require removal efficiencies in the range of 40 to 60 percent. Because of

the catalyst used, SCR can achieve higher efficiencies with lowe r concentrations of NOx.

3.1.3.1 SCR Operation Description

The reactor vessel is designed to allow proper retention time for the ammonia to contact the NOx

in the boiler exhaust gas. Ammonia is injected into the gas immediately prior to entering the

reactor vesse l. The catalyst contained in the reactor vessel enhances the reaction between the

ammonia and the NOx in the gas. Catalysts consist of various active materials such as titanium

dioxide, vanadium pentoxide, and tungsten trioxide. The operating range for vanadium/titanium

based catalysts is 260°C (500 ° F) to 455°C (850 ° F). The boiler is equipped with an economizer

bypass to provide flue gas to the reactors at the desired temperature during periods of low flow

rate, such as low load operation. Also include d with the reactor vessel is soot

- blowing

equipment used for cleaning the catalyst.

The ammonia storage and injection system consists of the unloading facilities, bulk storage tank,

vaporizers, dilution air skid, and injection grid.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 52 The flue gas flow contr ol consists of ductwork, dampers, and flow straightening devices required

to route the boiler exhaust to the SCR reactor and then to the air heater. The economizer bypass

and associated dampers for low load temperature control are also included.



## 3.1.4 Activated Carbon Injection

The PAC injection manifold is located directly before the baghouse. (30) This system will be

discussed in detail in Section 3.1.6

.



## 3.1.5 Particulate Control

The fabric filter (or baghous e) consists of two separate single

- stage, in

- line, multi

- compartment

units. Each unit is of high (0.9

- 1.5 m/min [3

- 5 ft/min]) air

- to

- cloth ratio design with a pulse

- jet

on

- line cleaning system. The ash is collected on the outside of the bags, which are s upported by

steel cages. The dust cake is removed by a pulse of compressed air. The bag material is

polyphenylensulfide (PPS) with intrinsic Teflon Polytetrafluoroethylene (PTFE) coating

. (31)

The bags are rated for a contin uous temperature of 180°C (356°F) and a peak temperature of

210°C (410°F). Each compartment contains a number of gas passages with filter bags, and

heated ash hoppers supported by a rigid steel casing. The fabric filter is provided with necessary

control devices, inlet gas distribution devices, insulators, inlet and outlet nozzles, expansion

joints, and other items as required.

The use of ACI and DSI increases the calcium content of the fly ash and adds an additional

burden to the fabric filter. The addi tion of calcium is not expected to increase the leaching of

trace metals from the fly ash significantly. The ACI and DSI systems increase the total amount

of particulate matter by approximately 26 percent

.

Fly ash from bituminous

- fired plants (Class F fly ash) is sometimes sold for use as filler material

in concrete mixtures. The use of Class F fly ash for concrete manufacture is not as common as

the use of Class C fly ash (from high

- calcium

- containing coals); the latter is more valuable as a

replacement for Portland cement in concrete mixtures. Class F fly ash must have a low unburned

carbon content to be used in cement mixtures. The inclusion of activated carbon and hydrated

lime (or, rather, the CaSO 4 

## reaction product) will render the fly ash unsuitab le for use in concrete

mixtures.



## 3.1.6 Mercury Removal 6



## Mercury removal is partially achieved through flue gas reactions between mercury and available

halogens and carbon.

Halogens in the coal, primarily chlorine, influence the fraction of oxidized mercury that is

formed as the flue gas passes through the SCR and air preheater. Therefore, the overall mercury

removal in control devi c es such as fabric filters and wet scrubbers is also influenced by halogens

in the coal (concentrations of chlorine greater than 500 ppm v do not appear to have any

additional impact on the rate of mercury oxidation (32) ).

The presence of an SCR can impact the amount of SO 3 

## or H 2 

## SO 4 

## that is present in the flue gas.

Sulfuric acid can impact the ability of u nburned carbon to adsorb mercury. Based on the

6 Much of the text, descrip tions, and images within this section were sourced, with permission, from a quote provided by ADA

- ES to NETL, unless

otherwise noted. The information relates to a mercury control system designed by ADA

- ES. The quote also provided all images credited to t hem.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 53 assumptions and design bases of the PC cases in this study, the estimated SO 3 

## concentration at

the inlet of the air preheater

, without mitigation

, is 59 ppm vd . At these levels, low mercury

removal is expecte d from either unburned carbon or added activated carbon. Therefore, dry

sorbent injection is included in the PC plant designs in order to reduce the SO 3 

## levels to

approximately 2 ppmvd , as discussed in Section 3.1.6.1

.

The rat e of mercury oxidation is also affected by the ammonia concentration. Since the SCR is

operated more aggressively for nitrogen oxide (NOx) control, the ammonia levels increase and

the fraction of oxidized mercury decreases. (33)

Unburned carbon can act as a catalyst to promote mercury oxidation as well as to adsorb

mercury. In general, sufficient unburned carbon is present at plants firing bituminous coals such

that one or both of these factors will have a significant influenc e on the overall mercury removal

achieved in the system. (34)

The presence of unburned carbon and/or activated carbon on the fabric filter surface, in

combination with relatively high levels of hydrogen halides (e.g. HCl) in t he flue gas, is expected

to result in high levels of oxidized mercury exiting the fabric filter. Oxidized mercury is water

soluble and should be readily removed in the wet scrubber. Depending on the chemistry in the

scrubber, some of the captured mercury may be reduced back to the relatively insoluble

elemental form, which will then be re

- emitted from the scrubber. The control systems employed

in this study minimize the amount of mercury entering the scrubber, which reduces the risk of

exceeding the emis sion limit. Even with low levels entering the scrubber, there is a risk of

periodic spikes in mercury at the stack if mercury collected and concentrated in a recirculating

scrubber is released. However, to a large extent, the periodic surges can be manag ed through

careful operations and, because the regulations specify a 30

- or 90

- day averaging period, the

impact of the surges on compliance can be minimized.

EPA used a statistical method to calculate the Hg co

- benefit capture from units using a “best

dem onstrated technology” approach, which for bituminous coals was considered to be a

combination of a fabric filter and an FGD system. The statistical analysis resulted in a co

- benefit

capture estimate of 86.7 percent with an efficiency range of 83.8 to 98.8 percent. (35) EPA’s

documentation for their Integrated Planning Model (IPM) provides mercury emission

modification factors (EMF) based on 190 combinations of boiler types and control technologies.

The EMF is simply one minus the removal efficiency.

For PC boilers (as opposed to cyclones, stokers, fluidized beds, and ‘others’) with a fabric filter,

SCR and wet FGD, the EMF is 0.1, which corresponds to a r emoval efficiency of 90 percent ;
(36) t he a verage reduction in total Hg emissions developed from EPA’s Information Collection

Request (ICR) data on U.S. coal

- fired boilers using bituminous coal, fabric filters, and wet FGD

is 98 percent. (37) The referenced sources bou nd the co

- benefit Hg capture for bituminous coal

units employing SCR, a fabric filter

, and a wet FGD system between 83.8 and 98 percent. It was

assumed that the co

- benefit potential of the equipment utilized in the PC cases of this report is 90

percent, a s it is near the mid

- point of the previously mentioned range, and it also matches the

value used by EPA in their IPM.

The potential co

- benefit capture of the systems utilized in the PC cases does not satisfy the

requirements of the mercury emission limit, therefore , a cost and performance estimate was

obtained from ADA

- ES

, which stated that activated carbon injection (ACI) and dry sorbent

injection (DSI) would be required.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 54 Location of the DSI relative to the air preheater impacts the mercury removal effic iency of the

ACI system. The mercury limit is assumed to be achievable with a DSI location downstream of

the air preheater ; h owever, t he upstream location of the air preheater allows for a lower flue gas

outlet temperature from the air preheater, which im proves plant performance as well as increases

the carbon e fficiency by up to 25 percent.

3.1.6.1 Dry Sorbent Injection

Illinois No. 6 coal contains relatively high levels of sulfur (2.82 wt% ). ADA

- ES estimate d that

nominally 36 ppm vd of sulfur trioxide (SO 3 

## ) will be present at the outlet of the air preheater

resulting from coal combustion and oxidation across the SCR.

SO 3 

## can be detrimental to the effectiveness of both unburned carbon and activated carbon for

mercury control, as evidenced by the r esults from a te sting program conducted at the M ercury

R esearch C enter . The test using an ESP

- configured system w ith an activated carbon injection

rate of 10 lb/MMacf upstream of the air preheater

, which showed that a t SO 3 

## levels above 20

ppm, less than 50 percent mercur y removal was achieved. At SO 3 

## levels above 10 and 3 ppm,

less than 70 and 80 percent mercury removal was achieved, respectively. (38)

Hydrated lime injection was selected for SO 3 

## control and located upstream of the air prehea ter,

which allows the air preheater to operate at a lower downstream flue gas temperature ( 290 °F)

and increase s the overall plant efficiency compared to a system with no DSI or DSI downstream

of the air preheater . Without SO 3 

## mitigation, the downstream fl ue gas temperature must be

maintained above the acid dew point temperature (approximately 337°F)

.

Operation Description

– The DSI and ACI injection systems are nearly identical, therefore, the

description provided below pertains to both systems.

As shown in Exhibit 3

- 1 , t he DSI system is based on dilute

- phase, pneumatic conveying of

hydrated lime at a metered rate from a bulk storage silo to the flue gas ductwork where it mixes

with the flue gas and reacts with the SO 3 

## to form Ca SO 4 

## , which is captured in the fabric filter.

The hydrated lime is delivered in 40,000 lb batches by self

- unloading pneumatic trucks. The

hydrated lime is unloaded from the truck via an on

- board compressor into the dry, welded

- steel

storage silo where th e displaced air is vented through a silo vent filter. The hydrated lime level

in the silo is measured by system instrumentation. A combination of compressed air fluidization

valves and nozzles is used to pulse compressed air, promoting mass flow of the h ydrated lime

out of the silo chisel

- type cone.

Fluidized hydrated lime is then transferred from the silo by a rotary valve into the feeder hopper

where it is temporarily stored until conveyed by the screw feeder into the drop tube. The speed

of the screw feeder determines the feed rate into the drop tube. Hydrated lime is fed through the

drop tube directly into the eductor suction port.

Motive air, provided by low

- pressure blowers and fed into the eductors, produces a vacuum at

the suction port. This hel ps draw the hydrated lime and air into the mixing zone directly

downstream of the eductor discharge. The hydrated lime is transported through the piping

system and is distributed to an array of injection lances specifically designed to disperse the

hydrat ed lime across the cross section of the flue gas ductwork upstream of the air preheater.

The DSI system is monitored and controlled by the distribut ed control system ( DCS ) to adjust to

varying demand.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 55 Exhibit 3

- 1 Typical injection process flow diagram

Source: Permission granted from ADA

- ES



## 3.1.6.2 Activated Carbon Injection

ADA

- ES conducted a mercury control trial using ACI and trona

- based DSI on a unit with an

installed fabric filter and high (greater than 20 pp m) levels of SO 3 

## in the flue gas. For this test,

the flue gas temperature was 380 ° F. Results from this test are presented in Exhibit 3

- 2 and

indicate that high mercury removal can be achieved when alkaline materials are present with

ac tivated carbon on a bag surface (i mproved performance is expected at lower temperature s)

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 56 Exhibit 3

- 2 Mercury removal across a fabric filter during a high

- sulfur bituminous test

Source: Permissio n granted from ADA

- ES



## In order to meet the mercury emission limit, PAC is injected at a rate of approximately 2.7

lb/MMacf in all PC cases.

Operation Description

– The ACI system’s injection manifold is located directly upstream of

the fabric filter and i s otherwise identical to that of the DSI system and is described in Section

3.1.6.1

.



## 3.1.7 Flue Gas Desulfurization

The FGD system is a wet limestone forced oxidation positive pressure absorber non

- reheat unit,

with wet

- stack, and gy psum production. The function of the FGD system is to scrub the boiler

exhaust gases to remove the SO 2 

## prior to release to the environment, or entering into the Carbon

Dioxide Removal (CDR) facility. Sulfur removal efficiency is 98 percent in the FGD uni t for all

cases. For Cases B11B and B12B with CO 2 

## capture, the SO 2 

## content of the scrubbed gases must

be further reduced to approximately 1 ppmv to minimize formation of amine heat stable salts

(HSS) during the CO 2 

## absorption process. The CDR unit includ es a polishing scrubber to reduce

the flue gas SO 2 

## concentration from about 37 ppmv at the FGD exit to the required level prior to

the CDR absorber. The scope of the FGD system is from the outlet of the ID fans to the stack

inlet (Cases B11A and B12A) or to the CDR process inlet (Cases B11B and B12B). The system

description is divided into three sections:

• Limestone Handling and Reagent Preparation

• FGD Scrubber

• Byproduct Dewatering 0 10 20 30 40 50 60 70 80 90 100

0 2 4 6 8Hg Removal (%)



### Inj Concentration (lb/Mmacf) 380F, 10 to 20 ppm SO3

380F, TronaCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 57 3.1.7.1 Limestone Handling and Reagent Preparation System

The function of the limes tone reagent preparation system is to grind and slurry the limestone

delivered to the plant. The scope of the system is from the day bin up to the limestone feed

system. The system is designed to support continuous base load operation.

Operation Descri ption

- Each day bin supplies a 100 percent capacity ball mill via a weigh

feeder. The wet ball mill accepts the limestone and grinds the limestone to 90 to 95 percent

passing 325 mesh (44 microns). Water is added at the inlet to the ball mill to create limestone

slurry. The reduced limestone slurry is then discharged into a mill slurry tank. Mill recycle

pumps, two per tank, pump the limestone water slurry to an assembly of hydrocyclones and

distribution boxes. The slurry is classified into several st reams, based on suspended solids

content and size distribution.

The hydrocyclone underflow with oversized limestone is directed back to the mill for further

grinding. The hydrocyclone overflow with correctly sized limestone is routed to a reagent

storage tank. Reagent distribution pumps direct slurry from the tank to the absorber module.

3.1.7.2 FGD Scrubber

The flue gas exiting the air preheater section of the boiler passes through one of two parallel

fabric filter units, then through the ID fans and into the on e 100 percent capacity absorber

module. The absorber module is designed to operate with counter

- current flow of gas and

reagent. Upon entering the bottom of the absorber vessel, the gas stream is subjected to an initial

quenching spray of reagent. The g as flows upward through the spray zone, which provides

enhanced contact between gas and reagent. Multiple spray elevations with header piping and

nozzles maintain a consistent reagent concentration in the spray zone. Continuing upward, the

reagent

- laden gas passes through several levels of moisture separators. These consist of

chevron

- shaped vanes that direct the gas flow through several abrupt changes in direction,

separating the entrained droplets of liquid by inertial effects. The scrubbed flue gas e xits at the

top of the absorber vessel and is routed to the plant stack or CDR process.

The scrubbing slurry falls to the lower portion of the absorber vessel, which contains a large

inventory of liquid. Oxidation air is added to promote the oxidation of calcium sulfite contained

in the slurry to calcium sulfate (gypsum). Multiple agitators operate continuously to prevent

settling of solids and enhance mixture of the oxidation air and the slurry. Recirculation pumps

recirculate the slurry from the lower portion of the absorber vessel to the spray level. Spare

recirculation pumps are provided to ensure availability of the absorber.

The absorber chemical equilibrium is maintained by continuous makeup of fresh reagent, and

blowdown of byproduct solids via t he bleed pumps. A spare bleed pump is provided to ensure

availability of the absorber. The byproduct solids are routed to the byproduct dewatering system.

The circulating slurry is monitored for pH and density.

This FGD system is designed for wet stack operation. Scrubber bypass or reheat, which may be

utilized at some older facilities to ensure the exhaust gas temperature is above the saturation

temperature, is not employed in this reference plant design because new scrubbers have

improved mist elimina tor efficiency, and detailed flow modeling of the flue interior enables the

placement of gutters and drains to intercept moisture that may be present and convey it to a

drain. Consequently, raising the exhaust gas temperature above the FGD discharge tempe rature

of 56 °C (13 3 °F) is not necessary.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 58 3.1.7.3 Byproduct Dewatering

The function of the byproduct dewatering system is to dewater the bleed slurry from the FGD

absorber modules. The dewatering process selected for this plant is gypsum dewatering

producing wallb oard grade gypsum. The scope of the system is from the bleed pump discharge

connections to the gypsum storage pile.

Operation Description

- The recirculating reagent in the FGD absorber vessel accumulates

dissolved and suspended solids on a continuous b asis as byproducts from the SO 2 

## absorption

process. Maintenance of the quality of the recirculating slurry requires that a portion be

withdrawn and replaced by fresh reagent. This is accomplished on a continuous basis by the

bleed pumps pulling off bypro duct solids and the reagent distribution pumps supplying fresh

reagent to the absorber.

Gypsum (calcium sulfate) is produced by the injection of oxygen into the calcium sulfite

produced in the absorber tower sump. The bleed from the absorber contains ap proximately

20 wt% gypsum. The absorber slurry is pumped by an absorber bleed pump to a primary

dewatering hydrocyclone cluster. The primary hydrocyclone performs two process functions.

The first function is to dewater the slurry from 20 wt% to 50 wt% s olids. The second function of

the primary hydrocyclone is to perform a CaCO 3 

## and CaSO 4 

## •2H 2 

## O separation. This process

ensures a limestone stoichiometry in the absorber vessel of 1.10 and an overall limestone

stoichiometry of 1.05. This system reduces the overall operating cost of the FGD system. The

underflow from the hydrocyclone flows into the filter feed tank, from which it is pumped to a

horizontal belt vacuum filter. Two 100 percent filter systems are provided for redundant

capacity.

3.1.7.4 Hydrocyclones

The hydrocyclone is a simple and reliable device (no moving parts) designed to increase the

slurry concentration in one step to approximately 50 wt%. This high slurry concentration is

necessary to optimize operation of the vacuum belt filter.

The hydrocyc lone feed enters tangentially and experiences centrifugal motion so that the heavy

particles move toward the wall and flow out the bottom. Some of the lighter particles collect at

the center of the cyclone and flow out the top. The underflow is thus conc entrated from 20 wt%

at the feed to 50 wt%.

Multiple hydrocyclones are used to process the bleed stream from the absorber. The

hydrocyclones are configured in a cluster with a common feed header. The system has two

hydrocyclone clusters, each with five 1 5 cm (6 inch) diameter units. Four cyclones are used to

continuously process the bleed stream at design conditions, and one cyclone is spare.

Cyclone overflow and underflow are collected in separate launders. The overflow from the

hydrocyclones still con tains about 5 wt% solids, consisting of gypsum, fly ash, and limestone

residues and is sent back to the absorber. The underflow of the hydrocyclones flows into the

filter feed tank from where it is pumped to the horizontal belt vacuum filters.

3.1.7.5 Horizontal Vacuum Belt Filters

The secondary dewatering system consists of horizontal vacuum belt filters. The pre

concentrated gypsum slurry (50 wt%) is pumped to an overflow pan through which the slurry

flows onto the vacuum belt. As the vacuum is pulled, a layer of cake is formed. The cake isCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 59 dewatered to approximately 90 wt% solids as the belt travels to the discharge. At the discharge

end of the filter, the filter cloth is turned over a roller where the solids are dislodged from the

filter cloth. This cake f alls through a chute onto the pile prior to the final byproduct uses. The

required vacuum is provided by a vacuum pump. The filtrate is collected in a filtrate tank that

provides surge volume for use of the filtrate in grinding the limestone. Filtrate t hat is not used

for limestone slurry preparation is returned to the absorber.



## 3.1.8 Carbon Dioxide Recovery Facility 7



## A C DR facility is used

, along with compressors and a dryer, in Cases B11B and B12B to remove

90 percent of the CO 2 

## in the flue gas exiting the F GD unit

. The facility then purif ies it and

compress es it to a supercritical condition. The flue gas exiting the FGD unit contains about

1 percent more CO 2 

## than the raw flue gas because of the CO 2 

## liberated from the limestone in the

FGD absorber vessel. The CDR is comprised of the pre

- scrubber , CO 2 

## absorber, CO 2 

## s tripper,

and absorbent purification unit.

The CO 2 

## recovery process for Cases B11B and B12B is based on data given by Shell Cansolv in

2012

. A typical flowsheet is shown in Exhibit 3

- 3 . This process is designed to recover high

purity CO 2 

## from low pressure ( LP ) streams that contain oxygen, such as flue gas from coal

- fired

power plants, CT exhaust gas, and other waste gases.

3.1.8.1 Pre

- scrubber Section

The flue gas from the FGD section is sent through a booster fan to drive the gas through

downstream equipment starting with the pre

- scrubber inlet cooling section. The cooler is

operated as a direct contact cooler that saturates and sub

- cools the flue gas. Satur ation and sub

cooling are beneficial to the system as they improve the amine absorption capacity, thus reducing

amine circulation rate. After the cooling section, the flue gas is scrubbed w ith caustic in the pre

scrubber sulfur polishing section. This st ep reduces the SO 2 

## concentration entering the CO 2



## absorber column to 1 ppmv, and also reduces the NO 2 

## concentration by 50 percent.

3.1.8.2 CO 2 

## Absorber Section

The Cansolv absorber is a single

, rectangular, acid resistant, brick

- lined concrete structure

containi ng stainless

- steel packing.

There are four packing sections in the Cansolv absorber. The first three are used for CO 2 

## absorption, and the final section is a water

- wash section. This specific absorber geometry and

design provides several cost advantages over more traditional column configurations while

maintaining equivalent or elevated performance. The flue gas enters the absorber and flows

counter

- current to the Cansolv solvent . Approximately 90 percent of the inlet CO 2 

## is absorbed

into the lean solv ent, and the remaining CO 2 

## exits the main absorber section and enters the

water

- wash section of the absorber. Prior to entering the bottom packing section, hot amine is

collected, removed, and pumped through a heat exchanger to provide intercooling and li mit

water losses. The cooled amine is then sent back to the absorber just above the final packing

section.

7 Much of the text and descriptions within this section were sourced, with permission, from data provided by Shell Cansolv to N ETL, unless

otherwise noted. The information relates to a CO 2 removal system designed by Shell Cansolv.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 60 Exhibit 3

- 3 Cansolv CO 2 

### capture process typical flow diagram

Source: NETL



## The water

- wash secti on at the top of the absorber is used to remove volatiles or entrained amine

from the flue gas, as well as to condense and retain water in the system. The wash water is

removed from the bottom of the wash section, pumped through a heat exchanger, and is t hen re

introduced at the top of the wash section. This wash water is made up of recirculated wash water

as well as water condensed from the flue gas. The flue gas treated in the water

- wash section is

then released to atmosphere.

3.1.8.3 Amine Regeneration Sect ion

The rich amine is collected at the bottom of the absorber and pumped through a rich/lean heat

exchanger where heat from the lean amine is exchanged with the rich amine. The Cansolv

rich/lean solvent heat exchanger is a stainless steel plate and frame type with a 5°C (9°F)

approach temperature. Additional options for heat integration in the Cansolv system include a

second heat exchanger after the rich/lean solvent heat exchanger where low

- pressure steam

condensate from the regenerator reboiler or inter mediate

- pressure steam condensate from the

amine purification section may be used to further pre

- heat the rich solvent. The rich amine

continues and enters the stripper near the top of the column. The stripper is a stainless steel

vessel using structured stainless steel packing. The regenerator reboiler uses low

- pressure steam

to produce water vapor that flows upwards, counter

- current to the rich amine flowing

downwards, and removes CO 2 

## from the amine. The Cansolv regenerator reboiler is a stainless

ste el plate and frame type with a 3°C (5°F) approach temperature. Lean amine is collected in the

stripper bottoms and flows to a flash vessel where water vapor is released. The water vapor is

then recompressed and recycled to the bottom of the stripper to c ontinue stripping CO 2 

## . The lean

amine is then pumped through the same rich/lean heat exchanger to exchange heat from the lean

amine to the rich amine and continues on to the lean amine tank.

The water vapor and stripped CO 2 

## flow up the stripper where th ey are contacted with recycled

reflux to condense a portion of the vapor. The remaining gas continues to the condenser where it

is partially condensed. The two

- phase mixture then flows to a reflux accumulator where the CO 2 

## product gas is separated and se nt to the CO 2 

## compressor at approximately 30 psia , and the

remaining water is collected and returned to the stripper as reflux.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 61 The flow of steam to the regenerator reboiler is proportional to the rich amine flow to the

stripper; however, the flow of low

- pressure steam is also dependent on the stripper top

temperature. For the steady

- state case described here, the low

- pressure steam requirement for

the reboiler only is calculated as approximately 1,100 Btu/lb CO 2 

## for the Cansolv process

, which

is satisfi ed by extracting steam from the crossover pipe between the IP and LP sections of the

steam turbine.

3.1.8.4 Amine Purification Section

The purpose of the amine purification section is to remove a portion of the HSS as well as ionic

and non

- ionic amine degradation products. The Cansolv amine purification process is performed

in batch.

3.1.8.4.1 Ion Exchange

The HSS form due to residual amounts of NO 2 

## and SO 2 

## in the flue gas. The acids formed by the

oxidative degradation of the amine

, as well as through reactions with NO 2 

## a nd SO 2 

## , neutralize a

portion of the amine making it inactive to further CO 2 

## absorption. Therefore, excess HSS are removed via an ion exchange (resin bed contained within a column).

3.1.8.4.2 Thermal Reclaimer

The ionic and non

- ionic amine degradation products are r emoved in the thermal reclaimer by

distilling a sl ipstream

– taken from the treated amine exiting the ion exchanger

– under vacuum

conditions to separate the water and amine . This process leaves the non

- ionic deg radation

products in the bottom, which are pumped to a storage tank

, diluted and cooled with process

water

, and then disposed. A portion of the condensed amine and water is returned to the

absorber column with the rest being sent to the lean amine tank.



## 3.1.9 Gas Compression and Drying System

The compre ssion system was modeled based on vendor supplied data, similar in design to that

presented in the Carbon Capture Simulation Initiative’s (CCSI) paper “Centrifugal Compressor

Simulation U ser M anual

. ” (39) The design was assume d to be an 8

- stage front

- loaded

centrifugal compressor with stage discharge pressures presented in Exhibit 3

- 4

.

Exhibit 3

- 4 CO 2 

### compressor interstage pressures

Stage Outlet Pressur e, MPa (psia) Stage Pressure

Ratio

1 0. 44 ( 64 ) 2.23

2 0. 92 (1 33 ) 2.14

3 1.7 2 (2 50 ) 1.90

4 3. 04 ( 441 ) 1.78

5 4.80 ( 696 ) 1.59

6 6.97 ( 1,011 ) 1.53

7 10.36 (1,502) 1.49

8 15.27 (2,215) 1.48



## Power consumption for this large compressor was estimated ass uming a polytropic efficiency of

8 9 percent and a mechanical efficiency of 9 7 percent for the first 7 stages and a polytropic

efficiency of 91 percent for the final stage

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 62 Intercooling is included for each stage with the first three stages including wate r knoc kout.

There is no aftercooler included in this design.

A triethylene glycol (TEG) dehydration unit is included between stages 4 and 5, operating at

3.03 MPa (439 psia), to reduce the moisture concentration of the CO 2 

## stream to 300 ppm w. The

dryer was designed based on a paper published by the Norwegian University of Science and

Technology (NTNU) (40) titled “Conditioning of CO 2 

## Coming from a CO 2 

## Capture Process for

Transport and Storage Purposes

. ”

In an absorption proc ess, such as in a TEG dehydration unit, the gas containing water flows up through a column while the TEG flows downward. The solvent binds the water by physical

absorption; water is more soluble in the solvent than in other components of the gas mixture.

The dried gas exits at the top of the column, while the solvent rich in water exits at the bottom.

After depressurization to around atmospheric pressure, the solvent is regenerated by heating it

and passing it through a regeneration column where the wate r is boiled off. Depending on

configuration a TEG unit can reduce water concentrations to below 10 ppm

. (41)

Several alternatives to rejecting the heat of CO 2 

## compression to cooling water were investigated

in a separate study

. (42) The first alternative consisted of using a portion of the heat to pre

- heat

BFW while the remaining heat was still rejected to cooling water. This configuration resulted in

an increase in net plant efficiency of 0.3 perc entage points (absolute). The second alternative

modified the CO 2 

## compression intercooling configuration to enable integration into a LiBr

- H 2 

## O

absorption refrigeration system, where water is the refrigerant. In the CO 2 

## compression section,

the single int ercooler between each compression stage was replaced with one kettle reboiler and

two counter

- current shell and tube heat exchangers. The kettle reboiler acts as the generator that

rejects heat from CO 2 

## compression to the LiBr

- H 2 

## O solution to enable the s eparation of the

refrigerant from the brine solution. The second heat exchanger rejects heat to the cooling water.

The evaporator heat exchanger acts as the refrigerator and cools the CO 2 

## compression stream by

vaporizing the refrigerant. Only five stage s of CO 2 

## compression were necessary for Approach 2.

The compression ratios were increased from the reference cases to create a compressor outlet

temperature of at least 93°C ( 200°F ) to maintain a temperature gradient of 6°C ( 10°F ) in the

kettle reboiler. This configuration resulted in a net plant efficiency increase of 0.1 percentage

points (absolute).

It was concluded that the small increase in efficiency did not justify the added cost and

operational complexity of the two configurations and hence they w ere not incorporated into the

base design.



## 3.1.10 Power Generation

The steam turbine is designed for long

- term operation (90 days or more) at MCR with throttle

control valves 95 percent open. It is also capable of a short

- term 5 percent OP/VWO condition

(16 hour s).

For the subcritical cases, the steam turbine is a tandem compound type, consisting of HP

- IP

- two

LP (double flow) sections enclosed in three casings, designed for condensing single reheat

operation, and equipped with non

- automatic extractions and four

- f low exhaust. The turbine

drives a hydrogen

- cooled generator. The turbine has DC motor

- operated lube oil pumps, and

main lube oil pumps, which are driven off the turbine shaft

. (43) The exhaust pressure is 50.8Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 63 cm (2 in) Hg i n the single pressure condenser. There are seven extraction points. The condenser

is two

- shell, transverse, single pressure with divided waterbox for each shell.

The steam

- turbine generator systems for the SC plants are similar in design to the subcritic al

systems. The differences include steam cycle conditions and steam extractions points . The

subcritical design has seven steam extraction points for both capture and non

- capture cases,

whereas the capture SC plant has only 6 extraction points and the no n

- capture SC plant has 8

extraction points

. The reason for the differences between the two SC plants (B12A and B12B) is

discussed in Section 3.1.11

.

Turbine bearings are lubricated by a closed

- loop, water

- cooled pressurized oi l system. Turbine

shafts are sealed against air in

- leakage or steam blowout using a labyrinth gland arrangement

connected to a LP steam seal system. The generator stator is cooled with a CL water system

consisting of circulating pumps, shell and tube or plate and frame type heat exchangers, filters,

and deionizers, all skid

- mounted. The generator rotor is cooled with a hydrogen gas

recirculation system using fans mounted on the generator rotor shaft.

Operation Description

- The turbine stop valves, con trol valves, reheat stop valves, and

intercept valves are controlled by an electro

- hydraulic control system. Main steam from the

boiler passes through the stop valves and control valves and enters the turbine at 16.5

MPa/566°C (2

, 400 psig/1

, 050oF) for the subcritical cases and 24.1MPa /593°C (3

, 500

psig/1

, 100° F ) for the SC cases. The steam initially enters the turbine near the middle of the HP

span, flows through the turbine, and returns to the boiler for reheating. The reheat steam flows

through the reh eat stop valves and intercept valves and enters the IP section at 566°C (1

, 050oF)

in the subcritical cases and 593°C (1

, 100°F) in the SC cases. After passing through the IP

section, the steam enters a crossover pipe, which transports the steam to the two LP sections.

The steam divides into four paths and flows through the LP sections exhausting downward into

the condenser. The last stages of the LP sections operate as condensing turbines with an exit

liquid fraction ranging from 9.2 percent to 9.5 percen t.

The turbine is designed to operate at constant inlet steam pressure over the entire load range.



## 3.1.11 Balance of Plant

The balance of plant components consist of the condensate, FW, main and reheat steam,

extraction steam, ash handling, ducting and stack, was te treatment and miscellaneous systems as

described below.

3.1.11.1 Condensate

The function of the condensate system is to pump condensate from the condenser hotwell to the

deaerator and through the LP FW heaters. Each system consists of one main condenser; two

va riable speed electric motor

- driven vertical condensate pumps eac h sized for 50 percent

capacity ; four LP heaters (two in Case B12B) ; and one deaerator with storage tank.

Condensate is delivered to a common discharge header through two separate pump dischar ge lines, each with a check valve and a gate valve. A common minimum flow recirculation line

discharging to the condenser is provided downstream of the gland steam condenser to maintain

minimum flow requirements for the gland steam condenser and the conde nsate pumps.

LP FW heaters 1 through 4 are 50 percent capacity, parallel flow, and are located in the

condenser neck. All remaining FW heaters are 100 percent capacity shell and U

- tube heatCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 64 exchangers. Each LP FW heater is provided with inlet/outlet isol ation valves and a full capacity

bypass. LP FW heater drains cascade down to the next lowest extraction pressure heater and

finally discharge into the condenser. Pneumatic level control valves control normal drain levels

in the heaters. High heater leve l dump lines discharging to the condenser are provided for each

heater for turbine water induction protection. Pneumatic level control valves control dump line

flow.

While Case B11B returns all process extraction steam (CO 2 

## capture and drying requirements )

condensate to the deaerator, the SC Case B12B requires this condensate to be returned after the

condenser upstream of the condensate polisher. This is required as the SC cases do not have a

blowdown stream. If the condensate was returned to the deaerat or, there would be a buildup of

contaminants. An impact of this design is that two of the LP FW heaters are not required in the

SC capture case (B12B), as the condensate return increases the FW temperature above that

which would be exiting the second LP F W heater.

3.1.11.2 Feedwater

The function of the FW system is to pump the FW from the deaerator storage tank through the

HP FW heaters to the economizer. One turbine

- driven BFW pump sized at 100 percent capacity

is provided to pump FW through the HP FW heaters. O ne 25 percent motor

- driven BFW pump

is provided for startup. The pumps are provided with inlet and outlet isolation valves, and

individual minimum flow recirculation lines discharging back to the deaerator storage tank. The

recirculation flow is controll ed by automatic recirculation valves, which are a combination check

valve in the main line and in the bypass, bypass control valve, and flow sensing element. The

suction of the boiler feed pump is equipped with startup strainers, which are utilized during

initial startup and following major outages or system maintenance.

Each HP FW heater is provided with inlet/outlet isolation valves and a full capacity bypass. FW

heater drains cascade down to the next lowest extraction pressure heater and finally discha rge

into the deaerator. Pneumatic level control valves control normal drain level in the heaters.

High heater level dump lines discharging to the condenser are provided for each heater for

turbine water induction protection. Dump line flow is controlled by pneumatic level control

valves.

The deaerator is a horizontal, spray tray type with internal direct contact stainless steel (SS) vent

condenser and storage tank.

The boiler feed pump turbine is driven by main steam up to 60 percent plant load. Above

60 percent load, extracti on from the IP turbine exhaust provides steam to the boiler feed pump

steam turbine.

3.1.11.3 Main and Reheat Steam

The function of the main steam system is to convey main steam from the boiler superheater

outlet to the HP turbine stop val ves. The function of the reheat system is to convey steam from

the HP turbine exhaust to the boiler reheater and from the boiler reheater outlet to the IP turbine

stop valves.

Main steam exits the boiler superheater through a motor

- operated stop/check val ve and a motor

operated gate valve and is routed in a single line feeding the HP turbine. A branch line off the IPCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 65 turbine exhaust feeds the boiler feed water pump turbine during unit operation starting at

approximately 60 percent load.

Cold reheat steam exits the HP turbine, flows through a motor

- operated isolation gate valve and

a flow control valve, and enters the boiler reheater. Hot reheat steam exits the boiler reheater

through a motor

- operated gate valve an d is routed to the IP turbine

.

3.1.11.4 Extractio n Steam

The function of the extraction steam system is to convey steam from turbine extraction points

through the following routes:

 From HP turbine extraction to heater 7 (and 8 in SC cases)

 From IP turbine extraction to heater 6 and the deaerator (heater 5)

 From LP turbine extraction to heaters 1, 2, 3, and 4

The turbine is protected from overspeed on turbine trip, from flash steam reverse flow from the

heaters through the extraction piping to the turbine. This protection is provided by positive

closing, balanced disc non

- return valves located in all extraction lines except the lines to the LP

FW heaters in the condenser neck. The extraction non

- return valves are located only in

horizontal runs of piping and as close to the turbine as possible.

The turbin e trip signal automatically trips the non

- return valves through relay dumps. The

remote manual control for each heater level control system is used to release the non

- return

valves to normal check valve service when required to restart the system.

3.1.11.5 Circula ting Water System

It is assumed that the plant is serviced by a public water facility and has access to groundwater

for use as makeup cooling water with minimal pretreatment. All filtration and treatment of the

circulating water are conducted on site. A mechanical draft, wood frame, counter

- flow cooling

tower is provided for the circulating water heat sink. Two 50 percent CWPs are provided. The

circulating water system ( CWS ) provides cooling water to the condenser, the auxiliary cooling

water system, an d the CDR facility and CO 2 

## compressors in capture cases.

The auxiliary cooling water system is a CL system. Plate and frame heat exchangers with

circulating water as the cooling medium are provided. This system provides cooling water to the

lube oil cool ers, turbine generator, boiler feed pumps, etc. All pumps, vacuum breakers, air

release valves, instruments, controls, etc. are included for a complete operable system.

The CDR and CO 2 

## compression system s in Cases B11B and B12B requires a substantial amou nt

of cooling water that is provided by the PC plant CWS. The additional cooling load s imposed by

the CDR and CO 2 

## compressors are reflected in the significantly larger CWPs and cooling tower

in those cases.

3.1.11.6 Ash Handling System

The function of the ash hand ling system is to provide the equipment required for conveying,

preparing, storing, and disposing of the fly ash and bottom ash produced on a daily basis by the

boiler , along with the hydrated lime and activated carbon injected for mercury control (discuss ed

in Section 3.1.6 ) . The scope of the system is from the baghouse hoppers, air heater and

economizer hopper collectors, and bottom ash hoppers to the hydrobins (for bottom ash) and

truck filling stations (for fly ash). The s ystem is designed to support short

- term operation at theCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 66 5 percent OP/VWO condition (16 hours) and long

- term operation at the 100 percent guarantee

point (90 days or more).

The fly ash collected in the baghouse and the air heaters is conveyed to the fly a sh storage silo.

A pneumatic transport system using LP air from a blower provides the transport mechanism for

the fly ash. Fly ash is discharged through a wet unloader, which conditions the fly ash and

conveys it through a telescopic unloading chute into a truck for disposal.

As mentioned in Section 3.1.5 , the use of ACI and DSI increases the calcium content of the fly

ash and adds an additional burden to the fabric filter. The addition of calcium is not expected to

increas e the leaching of trace metals from the fly ash significantly. The ACI and DSI systems

increase the total amount of particulate matter by approximately 26 percent.

The bottom ash from the boiler is fed into a clinker grinder. The clinker grinder is provi ded to

break up any clinkers that may form. From the clinker grinders the bottom ash is sluiced to

hydrobins for dewatering and offsite removal by truck.

Ash from the economizer hoppers and pyrites (rejected from the coal pulverizers) is conveyed

using wa ter to the economizer/pyrites transfer tank. This material is then sluiced on a periodic

basis to the hydrobins.

3.1.11.7 Ducting and Stack

One stack is provided with a single fiberglass

- reinforced plastic (FRP) liner. The stack is

constructed of reinforced concr ete. The stack is 152 m (500 ft) high for adequate particulate

dispersion.

3.1.11.8 Waste Treatment/Miscellaneous Systems

An onsite water treatment facility treats all runoff, cleaning 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 (a long with the associated pumps, piping, etc.).

Miscellaneous systems consisting of fuel oil, service air, instrument air, and service water are

provided. A storage tank provides a supply of No. 2 fuel oil used for startup and for a small

auxiliary boile r. Fuel oil is delivered by truck. All truck roadways and unloading stations inside

the fence area are provided.

3.1.11.9 Buildings and Structures

Foundations are provided for the support structures, pumps, tanks, and other plant components.

The following buildi ngs are included in the design basis:Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 67  Steam turbine building  Fuel oil pump house  Guard house

 Boiler building  Coal crusher building  Runoff water pump house

 Administration and

service building  Continuous emissions

monitoring building  Industrial waste treat ment

building

 Makeup water and

pretreatment building  Pump house and electrical

equipment building  FGD system buildings



## 3.1.12 Accessory Electric Plant

The accessory electric plant consists of switchgear and control equipment, generator equipment,

station servic e equipment, conduit and cable trays, and wire and cable. It also includes the main

power transformer, required foundations, and standby equipment.



## 3.1.13 Instrumentation and Control

An integrated plant

- wide control and monitoring DCS is provided. The DCS is a redundant

microprocessor

- based, functionally distributed system. The control room houses an array of

multiple video monitor and keyboard units. The monitor/keyboard units are the primary

interface between the generating process and operations personnel. The DCS incorporates plant

monitoring and control functions for all the major plant equipment. The DCS is designed to

provide 99.5 percent availability. The plant equipment and the DCS are designed for automatic

response to load changes from minimum loa d to 100 percent. Startup and shutdown routines are

implemented as supervised manual, with operator selection of modular automation routines

available.



## 3.1.14 Performance Summary Metrics

This section details the methodologies of several metrics reported in the p erformance summaries

of the PC cases.

Steam Generator Efficiency

The steam generator efficiency is equal to the amount of heat transferred in the boiler divided by

the thermal input provided by the coal. This calculation is represented by the equation:

= BB

Where:

SGE

– steam generator efficiency

BH

– boiler thermal output

CH

– coal thermal input

The heat transferred in the boiler is provided by the Aspen models, and the thermal input of the

coal is the product of the coal feed rate and the heating value of the coal.

Steam Turbine Efficiency

The steam turbine efficiency is calculated by taking the steam turbine power produced and

dividing it by the difference between the thermal input and thermal consumption . This

calculation is represented by the equation:

SS = SS

( TT

− )Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 68 Where:

STE

– steam turbine efficiency

STP

– steam turbine power

TI

– thermal input

T C

– thermal consumption

The thermal input is considered to be the main steam

.

The thermal consumption is only present in the capture cases. It is the enthalpy difference

between the streams extracted for the capture and CO 2 

## dryer systems and the condensate returned

to the condenser (steam extraction

– condensate return).

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

, 412

Where:

STHR

– steam turbine heat rate , Btu/kWh

STE

– steam turbine efficiency , fraction



# 3.2 Subcritical PC Cases

This section contains an evaluation of plant designs for Cases B11A and B11B, which are based

on a subcritical PC plant with a nominal net output of 550 MWe. Both plants use a single reheat

16.5 MPa/566°C/566°C (2

, 400 psig/1

, 050 ° F/1

, 050 ° F) cycle. The main difference between the

two configurations is that Case B11B includes CO 2 

## capture while Case B11A does not.

The balanc e of this section is organized as follows:

• Process and System Description provides an overview of the technology operation as

applied to Case B11A. The systems that are common to all PC cases were covered in

Section 3.1 and on ly features that are unique to Case B11A are discussed further in this

section.

• Key Assumptions is a summary of study and modeling assumptions relevant to Cases

B11A and B11B.

• Sparing Philosophy is provided for both Cases B11A and B11B.

• Performance Results provides the main modeling results from Case B11A, including the

performance summary, environmental performance, carbon/sulfur balances, water

balance, mass and energy balance diagrams and energy balance table.

• Equipment List provides an itemized list of major equipment for Case B11A 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 B11A.

• Process and System Description, Performance Results, Equipm ent List and Cost

Estimates are discussed for Case B11B.



## 3.2.1 Process Description

In this section the subcritical PC process without CO 2 

## capture is described. The system

description follows the block flow diagram ( BFD ) in Exhibit 3

- 5 and stream numbers referenceCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 69 the same Exhibit. The tables in Exhibit 3

- 6 provide process data for the numbered streams in the

BFD.

Coal (stream 8) and PA (stream 4) are introduced into the boiler through the wall

- fired burners.

Additional combustion air, including the OFA, is provided by the FD fans (stream 1). The boiler

operates at a slight negative pressure so air leakage is into the boiler, and the infiltration air is

accounted for in stream 7. Streams 3 and 6 show Ljungstr om air preheater leakages from the FD

and PA fan outlet streams to the boiler exhaust.

Flue gas exits the boiler th rough the SCR reactor where ammonia is injected to reduce NOx

compounds, followed by hydrated lime injection (stream 10) for the reduction of SO 3



## . It then

passes through the combustion air preheater (where the air preheater leakages are introduced)

and is cooled to 143 °C ( 289 °F) (stream 11) before PAC is injected (stream 12) for mercury

reduction. The flue gas then passes through a fabric fil ter for particulate removal (stream 1 5 ).

An ID fan increases the flue gas temperature to 1 53 °C ( 308 °F) and provides the motive force for

the flue gas (stream 1 6 ) to pass through the FGD unit. FGD inputs and outputs include makeup

water (stream 1 8 ), oxida tion air (stream 1 9 ), limestone slurry (stream 1 7 ) and product gypsum

(stream 20 ). The clean, saturated flue gas exiting the FGD unit (stream 21 ) passes to the plant

stack and is discharged to the atmosphere.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 70 Exhibit 3

- 5 Case B11A block flow diagram, subcritical unit without CO 2 

### c apture

Source: NETL P ULVERIZED

C OAL

B OILER SCR B AGHOUSE FGD

G YPSUM L IMESTONE

S LURRY O XIDATION

A IR M AKEUP

W ATER

B OTTOM A SH C OAL F EED I NFILTRATION

AIR

1

4

8 7

9 14

F LY A SH 15 16 18 19

17 20 21

HP

TURBINE 22

23 24

IP

TURBINE LP TURBINE

CONDENSER

26 FEEDWATER

HEATER

SYSTEM

Note : Block Flow Diagram is not intended to

represent a complete material balance

. Only

major process streams and equipment are

shown

. 3 2

6

5 11

25 10

H YDRATED

L IME 12

13 A CTIVATED

C ARBON S TACK GAS

FD F ANS

PA F ANS ID F AN

B OILER

F EEDWATERCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 71 Exhibit 3

- 6 Case B11A stream table, subcritical unit without c apture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V

- L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0000 0.0088 0.0000 0.0088 0.0000

CO 2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.0000 0.1376 0.0000 0.1376 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 0.0000 0.0000 0.0000

H 2 O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0000 0.0831 0.0000 0.0831 0.0000

N 2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.0 000 0.7345 0.0000 0.7345 0.0000

O 2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0000 0.0340 0.0000 0.0340 0.3333

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0020 0.0000 0.0020 0.6667

Total 1.0000 1.000 0 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 51,529 51,529 1,526 15,829 15,829 2,179 1,126 0 0 0 72,228 0 72,228 3

V

- L Flowrate (kg/hr) 1,486,984 1,486,984 44,042 456,786 4 56,786 62,866 32,480 0 0 0 2,145,010 0 2,145,010 164

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 186,882 3,624 3,766 18,264 109 18,372 18,372

Temperature (°C) 15 19 19 15 25 25 15 15 149 27 143 27 143 143

Pressure (MPa, abs) 0.10 0.11 0.11 0.1 0 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10

Steam Table Enthalpy (kJ/kg) A 30.23 34.36 34.36 30.23 40.78 40.78 30.23

--- --- 0.00 0.00 0.00

--- --- AspenPlus Enthalpy (kJ/kg) B

- 97.58

- 93.45

- 93.45

- 97.58

- 87.03

- 87.03

- 97.58

- 2,114.05 97.18

- 13,3 06.82

- 2,399.51 3.40

- 2,399.39

- 2,632.02

Density (kg/m 3 ) 1.2 1.2 1.2 1.2 1.3 1.3 1.2

--- --- --- 0.9

--- 0.9 1.5

V

- L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857

--- --- --- 29.698

--- 29.698 53.376

V

- L Flowrate (lb

m ole /hr) 113,603 113,603 3,365 34,898 34,898 4,803 2,481 0 0 0 159,235 0 159,235 7

V

- L Flowrate (lb/hr) 3,278,239 3,278,239 97,095 1,007,041 1,007,041 138,595 71,605 0 0 0 4,728,938 0 4,728,938 362

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 412,005 7,990 8,303 40,264 240 40,504 40,504

Temperature (°F) 59 66 66 59 78 78 59 59 300 80 289 80 289 289

Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.4 14.7 14.4 14.7 14.4 14.4

Steam Table Enthalpy (Btu/lb) A 13.0 14.8 14.8 13.0 17.5 17.5 1 3.0

--- --- --- --- AspenPlus Enthalpy (Btu/lb) B

- 42.0

- 40.2

- 40.2

- 42.0

- 37.4

- 37.4

- 42.0

- 908.9 41.8

- 5,720.9

- 1,031.6 1.5

- 1,031.6

- 1,131.6

Density (lb/ft 3 ) 0.076 0.078 0.078 0.076 0.081 0.081 0.076

--- --- --- 0.053

--- 0.053 0.096

A 

### Steam table r eference 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: Revision 3



## 72 Exhibit 3

- 6 Case B11A stream table, subcritical unit without c aptu re (continued)

15 16 17 18 19 20 21 22 23 24 25 26

V

- L Mole Fraction

Ar 0.0088 0.0088 0.0000 0.0000 0.0092 0.0000 0.0082 0.0000 0.0000 0.0000 0.0000 0.0000

CO 2 0.1376 0.1376 0.0000 0.0000 0.0003 0.0001 0.1288 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 0.0000

H 2 O 0.0831 0.0831 1.0000 1.0000 0.0099 0.9999 0.1451 1.0000 1.0000 1.0000 1.0000 1.0000

N 2 0.7345 0.7345 0.0000 0.0000 0.7732 0.0000 0.6854 0.0000 0.0000 0.0000 0.0000 0.0000

O 2 0.0340 0.0340 0.0000 0.0000 0.2074 0.0000 0.0325 0.0000 0.0000 0.0000 0.0000 0.0000

SO 2 0.0020 0.0020 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1 .0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 72,225 72,225 2,394 9,596 764 177 78,266 87,854 82,001 82,001 72,119 73,186

V

- L Flowrate (kg/hr) 2,144,846 2,144,846 43,130 172,870 22,042 3,183 2,258,148 1,582,718 1,477,271 1,477,271 1,2 99,243 1,318,467

Solids Flowrate (kg/hr) 0 0 18,467 0 0 28,641 0 0 0 0 0 0

Temperature (°C) 143 153 15 27 167 56 56 593 355 566 38 39

Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.31 0.10 0.10 16.65 4.28 4.19 0.01 2.04

Steam Table Enthalpy (k J/kg) A 274.35 285.60

--- 111.65 184.48

--- 286.09 3,473.89 3,098.44 3,593.58 1,980.12 163.34

AspenPlus Enthalpy (kJ/kg) B

- 2,397.38

- 2,386.13

- 14,995.75

- 15,964.53 56.67

- 12,481.91

- 2,940.30

- 12,506.41

- 12,881.86

- 12,386.71

- 14,000.17

- 15,816.96

Density (kg/m 3 ) 0.8 0.9 1,003.6 992.3 2.4 833.1 1.1 47.7 16.0 11.1 0.1 993.6

V

- L Molecular Weight 29.697 29.697 18.015 18.015 28.857 18.018 28.852 18.015 18.015 18.015 18.015 18.015

V

- L Flowrate (lb mole /hr) 159,229 159,229 5,278 21,155 1,684 389 17 2,548 193,685 180,781 180,781 158,995 161,348

V

- L Flowrate (lb/hr) 4,728,575 4,728,575 95,086 381,114 48,595 7,018 4,978,363 3,489,296 3,256,825 3,256,825 2,864,341 2,906,721

Solids Flowrate (lb/hr) 0 0 40,712 0 0 63,142 0 0 0 0 0 0

Temper ature (°F) 289 308 59 80 332 133 133 1,050 671 1,050 101 101

Pressure (psia) 14.2 15.2 15.0 15.7 45.0 14.7 14.7 2,414.7 620.5 608.1 1.0 295.5

Steam Table Enthalpy (Btu/lb) A 117.9 122.8

--- 48.0 79.3

--- 123.0 1,493.5 1,332.1 1,545.0 851.3 70.2

AspenPlus Enthalpy (Btu/lb) B

- 1,030.7

- 1,025.9

- 6,447.0

- 6,863.5 24.4

- 5,366.3

- 1,264.1

- 5,376.8

- 5,538.2

- 5,325.3

- 6,019.0

- 6,800.1

Density (lb/ft 3 ) 0.052 0.055 62.650 61.950 0.153 52.011 0.067 2.975 1.000 0.692 0.004 62.028

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: Revision 3



## 73 

## 3.2.2 Key System Assumptions

System assumptions for Cases B11A and B11B

, subcritical PC with and without CO 2 

## capture,

ar e compiled in Exhibit 3

- 7

.

Exhibit 3

- 7 Subcritical PC plant study configuration matrix

Case B11A

w/o CO 2 

### Capture Case B11B

w/CO 2 

### Capture

Steam Cycle, MPa/°C/°C (psig/°F/°F) 16 .5/566/566

(2

, 400/1

, 050/1

, 050) 16.5/566/566

(2

, 400/1

, 050/1

, 050)

Coal Illinois No. 6 Illinois No. 6

Condenser pressure, mm Hg (in Hg) 50.8 (2) 50.8 (2)

Boiler Efficiency, HHV % 8 9 8 9

Cooling water to condenser, °C (oF) 16 (60) 16 (60)

Cooling water fro m condenser, °C (oF) 27 (80) 27 (80)

Stack temperature, °C (°F) 5 6 (13 3 ) 4 2 ( 107 )

SO 2 

### Control Wet Limestone Forced

Oxidation Wet Limestone

Forced Oxidation

FGD Efficiency, % (A) 98 98 (B, C)

NOx Control LNB w/OFA, SCR , and

Polishing Scrubber LNB w/OFA

, SCR , and

Polishing Scrubber

SCR Efficiency, % (A) 8 3 8 5

Ammonia Slip (end of catalyst life),

ppmv 2 2

Particulate Control Fabric Filter Fabric Filter

Fabric Filter efficiency, % (A) 99. 9 99. 9

Ash Distribution, Fly/Bottom 80% / 20% 80% / 20%

SO 3 

### Con trol DSI DSI

Mercury Control Co

- benefit Capture and ACI Co

- benefit Capture and ACI

CO 2 

### Control N/A Cansolv

Overall Carbon Capture (A) N/A 90%

CO 2 

### Sequestration N/A Off

- site Saline Formation

A 

### Removal efficiencies are based on the flue gas c ontent

B 

### An S O 2 

### polishing step is included to meet more stringent SOx content limits in the flue gas ( ~1

ppmv) to reduce formation of amine HSS during the CO 2 

### absorption process

C 

### SO 2 

### exiting the post

- FGD polishing step is absorbed in the CO 2 

### capture process making stac k

emissions negligible



## 3.2.2.1 Balance of Plant

– Cases B11A and B11B

The balance of plant assumptions are common to all cases and are presented in Exhibit 3

- 8

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 74 Exhibit 3

- 8 Balance of plant assumptions

Parameter Value

Cooling system Recirculating Wet Cooling Tower

Fuel and Other storage

Coal 30 days

Ash 30 days

Gypsum 30 days

Limestone 30 days

Hydrated lime 30 days

Activated carbon 30 days

Plant Distribution Voltag e

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 CT 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 DI water is drawn from

municipal sources.

Process Wastewate r 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

t reatment system. Sludge is hauled off site. Packaged

plant is sized for 5.68 cubic meters per day

(1,500 gallons per day)

Water Discharge Most of the process wastewater is recycled to the cooling

tower basin. Blowdown will be treated for chloride and

m etals, and discharged.



## 3.2.3 Sparing Philosophy

Single trains are used throughout the design with exceptions where equipment capacity requires

an additional train. There is no redundancy other than normal sparing of rotating equipment.

The plant design consis ts of the following major subsystems:

• One dry

- bottom, wall

- fired PC subcritical boiler (1 x 100%)

• Two SCR reactors (2 x 50%)

• One DSI system (1 x 100%)

• One ACI system (1 x 100%)

• Two single

- stage, in

- line, multi

- compartment fabric filters (2 x 50%)

• One wet l imestone forced oxidation positive pressure absorber (1 x 100%)

• One steam turbine (1 x 100%)

• For Case B11B only, one CO 2 

## absorption system , consisting of an absorber, stripper, and

ancillary equipment ( 1 x 100 %) and two CO 2 

## compression systems (2 x 50%)Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 75 

## 3.2.4 Ca se B11A Performance Results

The plant produces a net output of 550 MWe at a net plant efficiency of 39.0 percent (HHV

basis). Overall performance for the plant is summarized in Exhibit 3

- 9

. Exhibit 3

- 10 provides a

detailed breakdown of the auxiliary power requirements.

Exhibit 3

- 9 Case B11A plant performance summary

Performance Summary

Total Gross Power, MWe 581

CO
2 Capture/Removal Auxiliaries, kWe 0

CO
2 Compression, kWe 0

Balance of Plant, kWe 31,1 5 3

Total Auxiliaries, MWe 31

Net Power, MWe 550

HHV Net Plant Efficiency (%) 39.0%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,221 (8,740)

LHV Net Plant Efficiency (%) 40.5%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,894 (8,430)

HHV Boiler Efficiency, % 89.1%

LHV Boiler Efficiency, % 92.4%

Steam Turbine Cycle Efficiency, % 46.3%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 7,774 (7,369)

Condenser Duty, GJ/hr ( MM Btu/hr) 2,362 (2,239)

As

- Received Coal Feed, kg/hr (lb/hr) 186,882 (412,005)

Limestone Sorbent Feed, kg/hr (lb/hr) 18,467 (40,712)

HHV Thermal Input, kWt 1,408,630

LHV Thermal Input, kWt 1,358,641

Raw Water Withdrawal, ( m 3 

### / min)/MW net 

### (gpm/MW net 

### ) 0.038 (10.1)

Raw Water Consumption, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.030 (8.0)

Excess Air, % 20.9%Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 76 Exhibit 3

- 10 Case B11A plant power summary

Power Summary

Steam Turbine Power, MWe 581

Total Gross Power, MWe 581

Auxiliary Load Summary

Coal Handling and Conveying, kWe 440

Pulverizers, kWe 2,800

Sorbent Handling & Reagent Preparation, kWe 890

Ash Handling, kWe 650

Primary Air Fans, kWe 1,390

Forced Draft Fans, kWe 1,770

Induced Draft Fans, kWe 6,940

SC R, kWe 50

Activated Carbon Injection, kWe 23

Dry sorbent Injection, kWe 90

Baghouse, kWe 90

Wet FGD, kWe 2,950

CO
2 Capture/Removal Auxiliaries, kWe 0

CO
2 Compression, kWe 0

Miscellaneous Balance of Plant A,B 

### , kWe 2,000

Steam Turbine Auxiliaries, kWe 400

Condensate Pumps, kWe 990

Circulating Water Pumps, kWe 4,850

Ground Water Pumps, kWe 500

Cooling Tower Fans, kWe 2,510

Transformer Losses, kWe 1,820

Total Auxiliaries, MWe 31

Net Power, MWe 550

A 

### Boiler feed pumps are turbine driven

B 

### Includ es plant control systems, lighting, HVAC, and miscellaneous low voltage loads



## 3.2.4.1 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 B11A is presented in Exhibit 3

- 11

. SO 2



## emissions are utilized as a surrogate for HCl emissions, therefore HC l is not reported.

Exhibit 3

- 11 Case B11A air emissions

kg/GJ (lb/ MM Btu) Tonne/year (ton/year) A 

### kg/MWh (lb/MWh)

SO
2 0.036 (0.085) 1,374 (1,514) 0.318 (0.7 0 0)

NOx 0.036 (0.085) 1,374 (1,514) 0.318 (0.700)

Particulate 0.005 (0.01 1 ) 177 (195) 0.041 (0.090)

Hg 1.56E

- 7 (3.63E

- 7) 0.006 (0.006) 1.36E

- 6 (3.00E

- 6)

CO
2 B 

### 88 ( 204 ) 3,303,826 (3,641,844) 764 (1,683)

CO
2 C



### - - 8 07 (1,779)

mg/Nm 3



### Particulate Concentration D

, E 

### 14.66

A 

### Calculations based on an 8 5 percent capacity factor

B 

### CO 2 

### emissions based upon gross power

C 

### CO 2 

### emissions based on net power instead of gross power

D 

### Concentration of particles in the flue gas after t he baghouse

E 

### Normal conditions given at 32°F and 14.696 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 77 SO 2 

## emissions are controlled using a wet limestone forced oxidation scrubber that achieves a

removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site.

The wallboard grade material can potentially be marketed and sold, but since it is highly

dependent on local market conditions, no byproduct credit was taken. The saturated flue gas

exiting the scrubber is vented through the plant stack.

NOx emissions are co ntrolled to about 0.5 lb/ MM Btu through the use of LNBs and OFA. An

SCR unit then further reduces the NOx concentration by 8 3 percent to 0.0 8 lb/ MM Btu.

Particulate emissions are controlled using a pulse jet fabric filter, which operates at an efficiency

of 99. 9 percent.

The total reduction in mercury emission via the combined control equipment (SCR, ACI, fabric

filter, DSI, and wet FGD) is 96.8 percent.

CO 2 

## emissions represent the uncontrolled discharge from the process.

The carbon balance for the plant is shown in Exhibit 3

- 12

. The carbon input to the plant consists

of carbon in the coal , carbon in the air

, PAC, and carbon in the limestone reagent used in the

FGD absorber . Carbon in the air is not neglected here s ince the Aspen model accounts for air

components throughout. Carbon leaves the plant mostly as CO 2 

## through the stack , however, the

PAC is captured in the fabric filter and some leaves as gypsum.

Exhibit 3

- 12 Case B11A carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 119,128 (262,631) Stack Gas 121,094 (266,967)

Air (CO
2 ) 272 (599) FGD Product 179 (394)

PAC 109 (240) Baghouse 109 (240)

FGD Reagent 1,874 (4,131) CO
2 Product 0

CO 2 

### Dryer Vent 0

CO
2 Knockout 0

Total 121,382 (267,601) Total 121,382 (267,601)



## Exhibit 3

- 13 sho ws the sulfur balance for the plant. Sulfur input comes solely from the sulfur in

the coal. Sulfur output includes the sulfur recovered from the FGD as gypsum , sulfur captured in

the fabric filter via hydrated lime, and sulfur emitted in the stack gas.

E xhibit 3

- 13 Case B11A sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 4,684 (10,327) FGD Product 4,526 (9,978)

Stack Gas 92 (204)

Polishing Scrubber and Solvent Reclaiming 0

Baghouse 66 (145)

Total 4,684 (10,327) Total 4,684 (10,327)



## Exhibit 3

- 14 shows the water balance for Case B11A.

Water demand represents the total amount of water required for a particular process. Some water

is recovered wi thin the process and is re

- used as internal recycle. The difference between

demand and recycle is raw water withdrawal. Raw water withdrawal is defined as the waterCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 78 removed from the ground or diverted from a POTW for use in the plant and was assumed to b e 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

a ny and all purposes, such as FGD makeup, BFW makeup, and cooling tow er makeup. The

difference between water withdrawal and process water discharge is defined as water

consumption and can be represented by the portion of the raw water withdrawn that is

evaporated, transpired, incorporated into products or otherwise not ret urned to the water source

from which it was withdrawn. Water consumption represents the net impact of the plant process

on the water source.

Exhibit 3

- 14 Case B11A water balance

Water Use Water

Demand Inte rnal

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)

FGD Makeup 3.61 (952)

– 3.61 (952)

– 3.61 (952)

CO
2 Drying

– – – – – Capture System

Makeup – – – – –

Deaerator Vent

– – – 0.05 (14)

- 0.05 (

- 14)

Condenser Makeup 0.32 (85)

– 0.32 (85)

– 0.32 (85)

BFW Makeup 0.32 (85)

– 0.32 (85)

– 0.32 (85)

Cooling Tower 18.89

(4,991) 1.86

(491) 17.04 (4,500) 4.25 ( 1,123) 12.79 (3,378)

FGD Dewatering

– 1.86

(491) - 1.86 (

- 491)

– - 1.86 (

- 491)

CO
2 Capture

Recovery – – – – –

CO
2 Compression KO

– – – – –
BFW Blowdown

– 0.27 (71)

- 0.27 (

- 71)

– - 0.27 (

- 71)

Total 22.82

(6,029) 1.86

(491) 20.96 (5,538) 4.30 (1,13 7) 16.66 (4,401)



## 3.2.4.2 Heat and Mass Balance Diagrams

A heat and mass balance diagram is shown for the Case B11A PC boiler, the FGD unit, and

steam cycle as shown in Exhibit 3

- 15 and Exhibit 3

- 16

.

An overall p lant energy balance is provided in tabular form in Exhibit 3

- 17 . The power out is

the steam turbine power prior to generator losses. The power at the generator terminals (shown

in Exhibit 3

- 9 ) is calculated by multiplying the power out by a generator efficiency of 98. 5

percent.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 79 Exhibit 3

- 15 Case B11A heat and mass balance, subcritical PC boiler without CO 2 

### capture

Source: NETL Notes :

1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psia

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P AGES

1 OF 2 B ITUMINOUS B ASELINE S TUDY

C ASE B 11 A

S UBCRITICAL P ULVERIZED C OAL

B OILER AND G AS C LEANUP S YSTEMS

DWG

. NO

. BB

- HMB

- CS

- B 11 A

- PG

- 1 Pulverized

Coal

Boiler SCR Ammonia

Infiltration Air

Air

Air

Coal

Bottom Ash FGD

Fly Ash

Forced

Draft Fans

Primary

Air Fans

412

, 005 W

59 T

15 P 78 T

16 P

18 H 66 T

15 P

15 H 3

, 489

, 296 W

1

, 050 T

2

, 415 P

1

, 494 H

3

, 256

, 825 W

1

, 050 T

608 P

1

, 545 H

1

, 007

, 041 W

59 T

15 P

13 H 3

, 278

, 239 W

59 T

15 P

13 H 71

, 605 W

59 T

15 P

13 H 4

, 769

, 202 W

289 T

14 P

117 H

7

, 990 W

300 T

14 P 40

, 866 W

289 T

14 P

3

, 256

, 825 W

671 T

621 P

1

, 332 H

3

, 489

, 296 W

486 T

2

, 536 P

471 H 5 4

, 978

, 373 W

133 T

15 P

123 H

1 2

4 7

9 ID Fans 4

, 728

, 575 W

289 T

14 P

118 H

Gross Plant Power : 581 MWe

Auxiliary Load : 31 MWe

Net Plant Power : 550 MWe

Net Plant Efficiency

, HHV : 39

. 0 %

Net Plant Heat Rate : 8

, 740 Btu / kWh Oxidation

Air Make

- Up

Water

Limestone

Slurry Gypsum

18

17 14 4

, 728

, 575 W

308 T

15 P

123 H

135

, 798 W

59 T

15 P

423 H 48

, 595 W

332 T

45 P

79 H 381

, 124 W

80 T

16 P

48 H

70

, 160 W

133 T

15 P

1

, 499 H Baghouse

3

6

8 15 16 19

21

22

23 24

DOE / NETL

SC PC P LANT

C ASE B 11 A Hydrated

Lime 11

Single Reheat

Extraction from

HP Turbine

From Feedwater

Heaters Single Reheat

To IP Turbine Throttle Steam

To HP Turbine 8

, 303 W

80 T

15 P 10 Activated

Carbon

12 13

240 W

80 T

15 P

Stack W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical 4

, 769

, 442 W

289 T

14 P

117 H

20 Air

Coal / Ash

Slurry

Water Steam

Lime /

Limestone /

Gypsum

Flue Gas

Activated

Carbon

AmmoniaCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 80 Exhi bit 3

- 16 Case B11A heat and mass balance, subcritical steam cycle

Source: NETL H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Water Steam

P AGES

2 OF 2 DWG

. NO

. BB

- HMB

- CS

- B 11 A

- PG

- 2

B ITUMINOUS B ASELINE S TUDY

C ASE B 11 A

S UBCRITICAL P ULVERIZED C OAL

P OWER B LOCK S YSTEMS LP Turbine Generator HP

Turbine IP

Turbine

Condenser

Hot Well Boiler Feed Pump

Turbine Drives Throttle

Steam

Condensate

Pumps 3

, 489

, 296 W

1

, 050 T

2

, 415 P

1

, 494 H

182

, 562 W

887 T

336 P

1

, 466 H 232

, 471 W

669 T

596 P

1

, 332 H 3

, 256

, 825 W

671 T

621 P

1

, 332 H 131

, 872 W

694 T

164 P

1

, 373 H

131

, 872 W

126 T

2 P

1

, 085 H 2

, 236

, 743 W

101 T

1 P

1

, 009 H

2

, 906

, 721 W

101 T

1 P

69 H

2

, 906

, 721 W

101 T

296 P

70 H 2

, 906

, 721 W

155 T

284 P

124 H

495

, 726 W

111 T

1 P

79 H 360

, 720 W

165 T

5 P

133 H 2

, 906

, 721 W

290 T

251 P

259 H

415

, 033 W

381 T

198 P

354 H 2

, 906

, 721 W

262 T

261 P

231 H

232

, 471 W

440 T

382 P

419 H 3

, 489

, 296 W

430 T

2

, 642 P

410 H

Deaerator

Boiler Feed

Water Pumps 3

, 489

, 296 W

486 T

2

, 536 P

471 H 3

, 256

, 825 W

1

, 050 T

608 P

1

, 545 H

78

, 138 W

272 T

43 P

241 H 259

, 938 W

204 T

13 P

172 H 2

, 906

, 721 W

194 T

272 P

163 H 209

, 922 W

694 T

161 P

1

, 373 H 78

, 138 W

491 T

62 P

1

, 278 H 181

, 801 W

408 T

40 P

1

, 240 H 100

, 782 W

206 T

11 P

1

, 149 H 135

, 006 W

160 T

5 P

1

, 096 H 2

, 864

, 341 W

694 T

164 P

1

, 373 H 2

, 732

, 469 W

694 T

164 P

1

, 373 H

3

, 489

, 296 W

371 T

2

, 752 P

348 H 3

, 489

, 296 W

364 T

161 P

337 H Gross Plant Power : 581 MWe

Auxiliary Load : 31 MWe

Net Plant Power : 550 MWe

Net Plant Efficiency

, HHV : 39

. 0 %

Net Plant Heat Rate : 8

, 740 Btu / kWh FWH 1 FWH 2 FWH 3 FWH 4 FWH 5 FWH 6 22

26

DOE / NETL

SC PC P LANT

C ASE B 11 A 24

23 42

, 380 W

59 T

15 P

27 H

Blowdown Vent Notes :

1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psia Single Reheat

Extraction

From Boiler

Single Reheat

Extraction to

Boiler

To Boiler Steam Turbine

Makeup

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical 25Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 81 Exhibit 3

- 17 Case B11A overall energy balance (0°C [32°F] reference)

HHV S ensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,071 (4,806) 4.2 (4.0)

– 5,075 (4,810)

Air

– 59.7 (56.6)

– 59.7 (56.6)

Raw Water Makeup

– 78.8 (74.7)

– 78.8 (74.7)

Limestone

– 0.40 (0.38)

– 0.40 (0.38)

Auxiliary Power

– – 112 (106) 112 (1 06)

TOTAL 5,071 (4,806) 143.2 (135.7) 112 (106) 5,326 (5,048)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash

– 0.4 (0.4)

– 0.4 (0.4)

Fly Ash + FGD Ash

– 2.1 (2.0)

– 2.1 (2.0)

Stack Gas

– 646 (612)

– 646 (612)

Sulfur

– – – – Motor Losses and Design

Allowances – – 34 (33) 34 (33)

Condenser

– 2,362 (2,239)

– 2,362 (2,239)

Non

- Condenser Cooling Tower

Loads – 106 (100)

– 106 (100)

CO
2 – 0.0 (0.0)

– 0.0 (0.0)

Cooling Tower Blowdown

– 31.6 (29.9)

– 31.6 (29.9)

CO
2 Capture Losses

– – – –
Ambient Losses A



### – 107.7 (102.0)

– 107.7 (102.0)

Power

– – 2,092

(1,983) 2,092 (1,983)

TOTAL

– 3,255 (3,085) 2,126

(2,015) 5,382 (5,101)

Unaccounted Energy B



### – - 55 (

- 52)

– - 55 (

- 52)

A 

### Ambient losses include all losses to the environment through radiation, convection, etc. Source s of these

losses include the boiler , reheater, superheater, and transformers.

B 

### By difference



## 3.2.5 Case B11A

– Major Equipment List

Major equipment items for the subcritical PC plant with no CO 2 

## capture are shown in the

following tables. The accounts used in t he equipment list correspond to the account numbers

used in the cost estimates in Section 3.2.6 . In general, the design conditions include a 10 percent

contingency for flows and heat duties and a 21 percent contingency for hea ds on pumps and fans.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 82 Case B11A

– Account 1: Coal and Sorbent Handling

Equipmen

t No. Description Type Design Condition Operating

Qty. Spares

1 Bottom Trestle Dumper and

Receiving Hoppers N/A 180 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 Transfer Tower No. 1 Enclosed N/A 1 0

5 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

6 As

- Received Coal Sampling System Two

- stage N/A 1 0

7 Stacker/Reclaimer Traveling,

linear 1,130 tonn e/hr (1,250 tph) 1 0

8 Reclaim Hopper N/A 40 tonne (40 ton) 2 1

9 Feeder Vibratory 150 tonne/hr (170 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 310 tonne/hr (340 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 150 to nne (170 ton) 2 0

13 Crusher Impactor

reduction 8 cm x 0

- 3 cm x 0

(3 in x 0

- 1

- 1/4 in x 0) 2 0

14 As

- Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 310 tonne/hr (340 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 310 tonne/hr (340 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide

Gates Field erected 690 tonne (800 ton) 3 0

19 Activated Carbon Storage Silo and

Feeder System Shop

assembled Silo

- 29 tonne ( 32 ton)

Feeder

- 120 kg/hr

( 260 lb/hr) 1 0

20 Hydrated Lime Storage Silo and

Feeder System Shop

assembled Silo

- 200 tonne (220 ton)

Feeder

– 4,140 kg/hr (9,130 lb/hr) 1 0

21 Limestone Truck Unloading Hopper N/A 30 tonne (40 ton) 1 0

22 Limestone Feeder Belt 80 tonne/hr (90 tp h) 1 0

23 Limestone Conveyor No. L1 Belt 80 tonne/hr (90 tph) 1 0

24 Limestone Reclaim Hopper N/A 20 tonne (20 ton) 1 0

25 Limestone Reclaim Feeder Belt 60 tonne/hr (70 tph) 1 0

26 Limestone Conveyor No. L2 Belt 60 tonne/hr (70 tph) 1 0

27 Limestone D ay Bin w/ actuator 240 tonne (270 ton) 2 0



## Case B11A

– Account 2: Coal and Sorbent Preparation and Feed

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Coal Feeder Gravimetric 30 tonne/hr (40 tph) 6 0

2 Coal Pulverizer Ball type or equivalent 30 tonne/hr (40 tph) 6 0

3 Limestone Weigh Feeder Gravimetric 20 tonne/hr (22 tph) 1 1

4 Limestone Ball Mill Rotary 20 tonne/hr (22 tph) 1 1

5 Limestone Mill Slurry Tank

with Agitator N/A 77,200 liters (20,000 gal) 1 1

6 Limestone Mill Re cycle

Pumps Horizontal centrifugal 1,300 lpm @ 10m H

2 O

(340 gpm @ 40 ft H

2 O) 1 1

7 Hydroclone Classifier 4 active cyclones in a

5 cyclone bank 320 lpm (90 gpm)

per cyclone 1 1

8 Distribution Box 2

- way N/A 1 1

9 Limestone Slurry Storage

Tank with Agita tor Field erected 439,000 liters

(116,000 gal) 1 1

10 Limestone Slurry Feed Pumps Horizontal centrifugal 910 lpm @ 9m H

2 O

(240 gpm @ 30 ft H

2 O) 1 1Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 83 Case B11A

– 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 1,271,000 liters

(336,000 gal) 2 0

2 Condensate Pumps Vertical canned 24,300 lpm @ 300 m H

2 O

(6,400 gpm @ 800 ft H

2 O) 1 1

3 Deaerator and Storage

Tank Horizontal spray type 1,762,000 kg/hr

(3,885,000 lb/hr),

5 min. tank 1 0

4 Boiler Feed

Pump/Turbine Barrel type, multi

- stage,

centrifugal 29,200 lpm @ 2,200 m H

2 O

(7,700 gpm @ 7,200 ft H

2 O) 1 1

5 Startup Boiler Feed

Pump, Electric Motor

Driven Ba rrel type, multi

- stage,

centrifugal 8,700 lpm @ 2,200 m H

2 O

(2,300 gpm @ 7,200 ft H

2 O) 1 0

6 LP Feedwater Heater

1A/1B Horizontal U

- tube 730,000 kg/hr

(1,600,000 lb/hr) 2 0

7 LP Feedwater Heater

2A/2B Horizontal U

- tube 730,000 kg/hr

(1,600,000 lb/hr) 2 0

8 LP Feedwater Heater

3A/3B Horizontal U

- tube 730,000 kg/hr

(1,600,000 lb/hr) 2 0

9 LP Feedwater Heater

4A/4B Horizontal U

- tube 730,000 kg/hr

(1,600,000 lb/hr) 2 0

10 HP Feedwater Heater 6 Horizontal U

- tube 1,740,000 kg/hr

(3,840,000 lb/hr) 1 0

11 HP Feedwater Heater 7 Horizontal U

- tube 1,740,000 kg/hr

(3,840,000 lb/hr) 1 0

12 Auxiliary Boiler Shop fabricated, water

tube 20,000 kg/hr, 2.8 MPa,

343°C (40,000 lb/hr, 400

psig, 650°F) 1 0

13 Fuel Oil System No. 2 fuel oil for light off 1,135,624 l iter (300,000 gal) 1 0

14 Service Air Compressors Flooded Screw 28 m 3 / min @ 0.7 MPa

(1,000 scfm @ 100 psig) 2 1

15 Instrument Air Dryers Duplex, regenerative 28 m 3 / min (1,000 scfm) 2 1

16 Closed Cycle Cooling

Heat Exchangers Shell and tube 53 GJ/hr

(5 0 MMBtu/hr) each 2 0

17 Closed Cycle Cooling

Water Pumps Horizontal centrifugal 20,800 lpm @ 30 m H

2 O

(5,500 gpm @ 100 ft H

2 O) 2 1

18 Engine

- Driven Fire

Pump Vertical turbine, diesel

engine 3,785 lpm @ 88 m H

2 O

(1,000 gpm @ 290 ft H

2 O) 1 1

19 Fire Service Booster

Pump Two

- stage horizontal

centrifugal 2,650 lpm @ 64 m H

2 O

(700 gpm @ 210 ft H

2 O) 1 1

20 Raw Water Pumps Stainless steel, single

suction 6,070 lpm @ 20 m H

2 O

(1,600 gpm @ 60 ft H

2 O) 2 1

21 Ground Water Pumps Stainless steel, single

suction 2,430 lpm @ 270 m H

2 O

(640 gpm @ 880 ft H

2 O) 5 1

22 Filtered Water Pumps Stainless steel, single

suction 1,920 lpm @ 50 m H

2 O

(510 gpm @ 160 ft H

2 O) 2 1

23 Filtered Water Tank Vertical, cylindrical 1,839,000 liter (486,000 gal) 1 0

24 Makeup Water

Demineralizer Multi

- media filter,

cartridge filter, RO

membrane assembly,

electrodeionization unit 650 lpm (170 gpm) 1 1

25 Liquid Waste Treatment

System -- 10 years, 24

- hour storm 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 84 Case B11A

– Account 4: Boiler and Accessories

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Boiler Subcritical, drum wall

- fired,

low NOx burne rs, overfire

air 1,740,000 kg/hr steam

@ 17.9 MPa/574°C/574°C

(3,840,000 lb/hr steam

@ 2,600 psig/1,065°F/1,065°F) 1 0

2 Primary Air Fan Centrifugal 251,000 kg/hr, 3,400 m 3 / min

@ 123 cm WG

(554,000 lb/hr, 121,100 acfm

@ 48 in. WG) 2 0

3 Forced Draft

Fan Centrifugal 818,000 kg/hr, 11,200 m 3 / min

@ 47 cm WG

(1,803,000 lb/hr, 394,100 acfm

@ 19 in. WG) 2 0

4 Induced Draft

Fan Centrifugal 1,180,000 kg/hr, 23,400 m 3 / min

@ 89 cm WG

(2,601,000 lb/hr, 826,500 acfm

@ 35 in. WG) 2 0

5 SCR Reactor

Vessel Space for spare layer 2,360,000 kg/hr (5,200,000 lb/hr) 2 0

6 SCR Catalyst

-- -- 3 0

7 Dilution Air

Blower Centrifugal 130 m 3 / min @ 108 cm WG

(4,600 acfm @ 42 in. WG) 2 1

8 Ammonia

Storage Horizontal tank 142,000 liter (38,000 gal) 5 0

9 Ammonia Feed

Pump Centrifugal 27 lpm @ 90 m H

2 O

(7 gpm @ 300 ft H

2 O) 2 1



## Case B11A

– Account 5: F lue Gas Cleanup

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Fabric Filter Single stage, high

- ratio

with pulse

- jet online

cleaning system 1,18 0,000 kg/hr (2,601,000

lb/hr) 99.9% efficiency 2 0

2 Absorber Module Counter

- current open

spray 47,000 m 3 / min

(1,661,000 acfm) 1 0

3 Recirculation Pumps Horizontal centrifugal 164,000 lpm @ 65 m H

2 O

(43,000 gpm @ 210 ft H

2 O) 5 1

4 Bleed Pumps Horizont al centrifugal 3,980 lpm (1,050 gpm)

at 20 wt% solids 2 1

5 Oxidation Air Blowers Centrifugal 80 m 3 / min @ 0.3 MPa

(2,920 acfm @ 37 psia) 2 1

6 Agitators Side entering 50 hp 5 1

7 Dewatering Cyclones Radial assembly, 5 units

each 990 lpm (260 gpm) per

cyclone 2 0

8 Vacuum Filter Belt Horizontal belt 32 tonne/hr (35 tph) of 50 wt

% slurry 2 1

9 Filtrate Water Return

Pumps Horizontal centrifugal 610 lpm @ 13 m H

2 O

(160 gpm @ 40 ft H

2 O) 1 1

10 Filtrate Water Return

Storage Tank Vertical, lined 400,000 lpm (100,000 gal) 1 0

11 Process Makeup

Water Pumps Horizontal centrifugal 3,170 lpm @ 21 m H

2 O

(840 gpm @ 70 ft H

2 O) 1 1

12 Activated Carbon

Injectors --- 120 kg/hr ( 260 lb/hr) 1 0

13 Hydrated Lime

Injectors --- 4,140 kg/hr (9,130 lb/hr) 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 85 Case B11A

– Account 7: Ducting and Stack

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Stack Reinforced concrete

with FRP liner 152 m (500 ft) h igh x

5.8 m (19 ft) diameter 1 0



## Case B11A

– Account 8: Steam Turbine Generator and Auxiliaries

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Steam

Turbine Commercially available

advanced steam turbine 612 MW

16.5 MPa/566°C/566° C (2400 psig/

1050°F/1050°F) 1 0

2 Steam

Turbine

Generator Hydrogen cooled, static

excitation 680 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 1 0

3 Surface

Condenser Single pass, divided

waterbox including

vacuum pumps 2,600 GJ/hr (2,460 MMBtu/hr),

Inlet wate r temperature 16°C

(60°F),

Water temperature rise 11°C (20°F) 1 0



## Case B11A

– Account 9: Cooling Water System

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Circulating

Water Pumps Vertical, wet pit 487,000 lpm @ 30 m

(129,000 g pm @ 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 /

2710 GJ/hr (2570 MMBtu/hr) heat duty 1 0



## Case B11A

– Account 10: Ash and Spent Sorbent Recovery and Handling

Equipm en

t No. Description Type Design Condition Operating

Qty. Spares

1 Economizer Hopper (part of boiler scope

of supply) -- -- 4 0

2 Bottom Ash Hopper (part of boiler scope of

supply) -- -- 2 0

3 Clinker Grinder

-- 4.0 tonne/hr (4.4 tph) 1 1

4 Pyrites Hopp er (part of pulverizer scope of

supply included with boiler) -- -- 6 0

5 Hydroejectors

-- -- 12

6 Economizer /Pyrites Transfer Tank

-- -- 1 0

7 Ash Sluice Pumps Vertical,

wet pit 160 lpm @ 17 m H

2 O

(40 gpm @ 56 ft H

2 O) 1 1

8 Ash Seal Water Pumps Vert ical,

wet pit 7,570 lpm @ 9 m H

2 O

(2000 gpm @ 28 ft

H 2 O) 1 1

9 Hydrobins

-- 150 lpm (40 gpm) 1 1

10 Baghouse Hopper (part of baghouse

scope of supply) -- -- 24 0

11 Air Heater Hopper (part of boiler scope of

supply) -- -- 10 0

12 Air Blower

-- 20 m 3 / m in @ 0.2 MPa

(650 scfm @ 24 psi) 1 1

13 Fly Ash Silo Reinforce

d concrete 1,200 tonne (1,300 ton) 2 0

14 Slide Gate Valves

-- -- 2 0

15 Unloader

-- -- 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 86 Equipm en

t No. Description Type Design Condition Operating

Qty. Spares

16 Telescoping Unloading Chute

-- 110 tonne/hr (130 tph) 1 0



## Case B11A

– Account 11: Accessory E lectric Plant

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 STG Transformer Oil

- filled 24 kV/345 kV, 650

MVA, 3

- ph, 60 Hz 1 0

2 High Voltage Transformer Oil

- filled 345 kV/13.8 kV, 0

MVA, 3

- ph, 60 Hz 2 0

3 Medium Voltage Transfo rmer Oil

- filled 24 kV/4.16 kV, 33

MVA, 3

- ph, 60 Hz 1 1

4 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 5

MVA, 3

- ph, 60 Hz 1 1

5 STG Isolated Phase Bus Duct

and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 1 0

6 Medium Voltage Switchgear Meta l clad 4.16 kV, 3

- ph, 60 Hz 1 1

7 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 1 1

8 Emergency Diesel Generator Sized for emergency

shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 0



## Case B11A

– Account 12: Instrumentation and Control

Equipment

No. Des cription Type Design Condition Operating

Qty. Spares

1 DCS

- Main

Control Monitor/keyboard; Operator

printer (laser color); Engineering

printer (laser B&W) Operator stations/printers

and engineering

stations/printers 1 0

2 DCS

- Processor Microprocessor with redundant

input/output N/A 1 0

3 DCS

- Data

Highway Fiber optic Fully redundant, 25% spare 1 0



## 3.2.6 Case B11A

– Cost Estimating

The cost estimating methodology was described previously in Section 2.7

. Exhibit 3

- 18 shows a

detailed breakdown of the capital costs; Exhibit 3

- 19 shows the owner’s costs , along with the,

TOC, and TASC ; Exhibit 3

- 20 shows the initial and annual O&M costs; and Exhibit 3

- 21 shows

the COE breakdown.

The estimated TP C of the subcritical PC boiler with no CO 2 

## capture is $1,960 /kW. No process

contingency is included in this case because all elements of the technology are commercially

proven. The proj ect contingency is 11.2 percent of the TP C. The COE is $ 82.1 /M Wh.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 87 Exhibit 3

- 18 Case B11 A total plant cost details

Case: B11 A

– Subc ritical PC w/o CO 2 Estimate Type: Conceptual

Plant Size (MW,net): 550 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 ,103 $0 $1,849 $0 $5,952 $595 $0 $982 $7,529 $14

1.2 Coal Stackout & Reclaim $5,303 $0 $1,185 $0 $6,488 $649 $0 $1,071 $8,207 $15

1.3 Coal Conveyors $4,930 $0 $1,173 $0 $6,103 $610 $0 $1,007 $7,720 $14

1.4 Other Coal Handling $1,290 $0 $271 $0 $1,561 $1 56 $0 $258 $1,975 $4

1.5 Sorbent Receive & Unload $164 $0 $49 $0 $212 $21 $0 $35 $269 $0

1.6 Sorbent Stackout & Reclaim $2,644 $0 $478 $0 $3,122 $312 $0 $515 $3,949 $7

1.7 Sorbent Conveyors $943 $205 $228 $0 $1,376 $138 $0 $227 $1,741 $3

1.8 Other Sorb ent Handling $570 $134 $295 $0 $999 $100 $0 $165 $1,263 $2

1.9 Coal & Sorbent Hnd. Foundations $0 $4,756 $6,270 $0 $11,026 $1,103 $0 $1,819 $13,948 $25

Subtotal $19,948 $5,095 $11,797 $0 $36,840 $3,684 $0 $6,079 $46,602 $85

2 Coal & Sorbent Prep & Fee d

2.1 Coal Crushing & Drying $2,351 $0 $452 $0 $2,803 $280 $0 $462 $3,545 $6

2.2 Coal Conveyor to Storage $6,019 $0 $1,296 $0 $7,315 $731 $0 $1,207 $9,253 $17

2.5 Sorbent Prep Equipment $4,491 $194 $920 $0 $5,605 $560 $0 $925 $7,090 $13

2.6 Sorbent Sto rage & Feed $541 $0 $204 $0 $745 $75 $0 $123 $943 $2

2.9 Coal & Sorbent Feed Foundation $0 $548 $481 $0 $1,029 $103 $0 $170 $1,301 $2

Subtotal $13,401 $742 $3,353 $0 $17,496 $1,750 $0 $2,887 $22,133 $40

3 Feedwater & Miscellaneous BOP Systems

3.1 Fee dwater System $18,097 $0 $6,235 $0 $24,332 $2,433 $0 $4,015 $30,780 $56

3.2 Water Makeup & Pretreating $5,536 $0 $1,751 $0 $7,288 $729 $0 $1,603 $9,620 $17

3.3 Other Feedwater Subsystems $6,083 $0 $2,497 $0 $8,581 $858 $0 $1,416 $10,855 $20

3.4 Service Water Systems $1,109 $0 $580 $0 $1,689 $169 $0 $372 $2,229 $4

3.5 Other Boiler Plant Systems $7,482 $0 $7,074 $0 $14,556 $1,456 $0 $2,402 $18,413 $33

3.6 FO Supply Sys & Nat Gas $327 $0 $382 $0 $709 $71 $0 $117 $897 $2

3.7 Waste Treatment Equipment $3, 632 $0 $2,103 $0 $5,735 $573 $0 $1,262 $7,570 $14

3.8 Misc. Equip. (Cranes, Air Comp.,

Comm.) $3,205 $0 $991 $0 $4,197 $420 $0 $923 $5,540 $10

Subtotal $45,472 $0 $21,614 $0 $67,086 $6,709 $0 $12,109 $85,903 $156

4 Boiler & Accessories

4.1 PC Boiler & Accessories $152,353 $0 $99,495 $0 $251,848 $25,185 $0 $27,703 $304,736 $554

4.2 SCR w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0

Subtotal $152,353 $0 $99,495 $0 $251,848 $25,185 $0 $27,703 $304,736 $554

5A Gas Cleanup & Piping

5A.1 Absorber Vessels & Accessories $69,501 $0 $14,860 $0 $84,361 $8,436 $0 $9,280 $102,077 $186

5A.2 Other FGD $3,627 $0 $4,082 $0 $7,709 $771 $0 $848 $9,328 $17Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 88 Case: B11 A

– Subc ritical PC w/o CO 2 Estimate Type: Conceptual

Plant Size (MW,net): 550 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.3 Bag House & Accessories $19,695 $0 $12,414 $0 $32,109 $3,211 $0 $3,532 $38,852 $71

5A.4 Other Particulate Removal Materia ls $1,333 $0 $1,417 $0 $2,749 $275 $0 $302 $3,327 $6

5A.5 Gypsum Dewatering System $5,536 $0 $934 $0 $6,470 $647 $0 $712 $7,829 $14

5A.6 Mercury Removal System $4,205 $925 $4,135 $0 $9,265 $927 $0 $1,019 $11,211 $20

Subtotal $103,898 $925 $37,841 $0 $1 42,664 $14,266 $0 $15,693 $172,623 $314

7 HRSG, Ducting, & Stack

7.3 Ductwork $10,981 $0 $6,932 $0 $17,913 $1,791 $0 $2,956 $22,660 $41

7.4 Stack $10,920 $0 $6,346 $0 $17,267 $1,727 $0 $1,899 $20,893 $38

7.9 Duct & Stack Foundations $0 $1,190 $1,413 $ 0 $2,604 $260 $0 $573 $3,437 $6

Subtotal $21,902 $1,190 $14,692 $0 $37,784 $3,778 $0 $5,428 $46,990 $85

8 Steam Turbine Generator

8.1 Steam TG & Accessories $66,400 $0 $7,465 $0 $73,865 $7,387 $0 $8,125 $89,377 $163

8.2 Turbine Plant Auxiliaries $419 $0 $891 $0 $1,310 $131 $0 $144 $1,585 $3

8.3 Condenser & Auxiliaries $8,232 $0 $2,742 $0 $10,974 $1,097 $0 $1,207 $13,279 $24

8.4 Steam Piping $26,402 $0 $10,700 $0 $37,102 $3,710 $0 $6,122 $46,934 $85

8.9 TG Foundations $0 $1,249 $2,062 $0 $3,311 $331 $0 $728 $4,371 $8

Subtotal $101,453 $1,249 $23,861 $0 $126,563 $12,656 $0 $16,327 $155,546 $283

9 Cooling Water System

9.1 Cooling Towers $11,134 $0 $3,443 $0 $14,577 $1,458 $0 $1,604 $17,639 $32

9.2 Circulating Water Pumps $2,236 $0 $143 $0 $2,378 $238 $0 $262 $2,878 $5

9.3 Circ. Water System Auxiliaries $612 $0 $81 $0 $693 $69 $0 $76 $839 $2

9.4 Circ. Water Piping $0 $5,158 $4,671 $0 $9,829 $983 $0 $1,622 $12,434 $23

9.5 Make

- up Water System $554 $0 $712 $0 $1,266 $127 $0 $209 $1,602 $3

9.6 Com ponent Cooling Water Sys. $499 $0 $383 $0 $882 $88 $0 $146 $1,116 $2

9.9 Circ. Water Foundations & Structures $0 $2,726 $4,526 $0 $7,252 $725 $0 $1,595 $9,573 $17

Subtotal $15,035 $7,884 $13,960 $0 $36,879 $3,688 $0 $5,513 $46,080 $84

10 Ash & Spent S orbent Handling Systems

10.6 Ash Storage Silos $796 $0 $2,435 $0 $3,231 $323 $0 $355 $3,909 $7

10.7 Ash Transport & Feed Equipment $5,286 $0 $5,240 $0 $10,526 $1,053 $0 $1,158 $12,736 $23

10.9 Ash/Spent Sorbent Foundation $0 $180 $221 $0 $401 $40 $0 $88 $529 $1

Subtotal $6,081 $180 $7,896 $0 $14,157 $1,416 $0 $1,601 $17,174 $31

11 Accessory Electric Plant

11.1 Generator Equipment $1,945 $0 $311 $0 $2,256 $226 $0 $186 $2,667 $5

11.2 Station Service Equipment $3,348 $0 $1,122 $0 $4,470 $447 $0 $369 $ 5,286 $10

11.3 Switchgear & Motor Control $3,843 $0 $668 $0 $4,510 $451 $0 $496 $5,457 $10

11.4 Conduit & Cable Tray $0 $2,635 $8,513 $0 $11,148 $1,115 $0 $1,839 $14,103 $26

11.5 Wire & Cable $0 $5,017 $8,969 $0 $13,986 $1,399 $0 $2,308 $17,692 $32

11 .6 Protective Equipment $317 $0 $1,099 $0 $1,416 $142 $0 $156 $1,713 $3

11.7 Standby Equipment $1,499 $0 $35 $0 $1,534 $153 $0 $169 $1,856 $3

11.8 Main Power Transformers $9,846 $0 $206 $0 $10,052 $1,005 $0 $1,106 $12,163 $22

11.9 Electrical Foundations $0 $359 $914 $0 $1,274 $127 $0 $280 $1,681 $3

Subtotal $20,797 $8,012 $21,837 $0 $50,647 $5,065 $0 $6,909 $62,620 $114Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 89 Case: B11 A

– Subc ritical PC w/o CO 2 Estimate Type: Conceptual

Plant Size (MW,net): 550 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

12 Instrumentation & Control

12.1 PC Control Equipment w/12.7 $0 w/12.7 $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

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $528 $0 $323 $0 $850 $85 $0 $140 $1,076 $2

12.7 Distributed Control Sys. Equipment $5,328 $0 $950 $0 $6,278 $628 $0 $691 $7,596 $14

12.8 Instrument Wiring & Tubing $3,213 $0 $5,846 $0 $9,059 $906 $0 $1,495 $11,459 $21

12.9 Other I & C Equipment $1,506 $0 $3,486 $0 $4,992 $499 $0 $549 $6,040 $11

Subtotal $10,574 $0 $10,605 $0 $21,179 $2,118 $0 $2,875 $26,171 $48

13 Imp rovements to Site

13.1 Site Preparation $0 $56 $1,196 $0 $1,252 $125 $0 $275 $1,653 $3

13.2 Site Improvements $0 $1,866 $2,465 $0 $4,331 $433 $0 $953 $5,717 $10

13.3 Site Facilities $3,344 $0 $3,508 $0 $6,851 $685 $0 $1,507 $9,044 $16

Subtotal $3,344 $1,922 $7,168 $0 $12,434 $1,243 $0 $2,736 $16,413 $30

14 Buildings & Structures

14.1 Boiler Building $0 $10,193 $8,958 $0 $19,151 $1,915 $0 $5,266 $26,332 $48

14.2 Turbine Building $0 $14,726 $13,715 $0 $28,442 $2,844 $0 $7,821 $39,107 $71

14.3 Admini stration Building $0 $703 $743 $0 $1,446 $145 $0 $398 $1,988 $4

14.4 Circulation Water Pumphouse $0 $201 $160 $0 $361 $36 $0 $99 $497 $1

14.5 Water Treatment Buildings $0 $691 $629 $0 $1,320 $132 $0 $363 $1,815 $3

14.6 Machine Shop $0 $470 $316 $0 $786 $79 $0 $216 $1,080 $2

14.7 Warehouse $0 $319 $319 $0 $638 $64 $0 $175 $877 $2

14.8 Other Buildings & Structures $0 $260 $221 $0 $482 $48 $0 $132 $662 $1

14.9 Waste Treating Building & Str. $0 $498 $1,511 $0 $2,010 $201 $0 $553 $2,763 $5

Subtotal $0 $ 28,061 $26,573 $0 $54,634 $5,463 $0 $15,024 $75,122 $137

Total $514,258 $55,260 $300,691 $0 $870,209 $87,021 $0 $120,883 $1,078,113 $1,960Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 90 Exhibit 3

- 19 Case B11 A owner’s costs

Description $ / 1,000 $/kW

Pre

- Production Costs

6 Months All Labor $8,261 $15

1 Month Maintenance Materials $1,013 $2

1 Month Non

- fuel Consumables $2,245 $4

1 Month Waste Disposal $448 $1

25% of 1 Months Fuel Cost at 100% CF $2,577 $5

2% of TPC $21,562 $39

Total $36,106 $66

Inventory Capital

60 day supply of fuel and consumables at 100% CF $24,698 $45

0.5% of TPC (spare parts) $5,391 $10

Total $30,088 $55

Other Costs

Initial Cost for Catalyst and Chemicals $0 $0

Land $900 $2

Other Owner's Costs $161,717 $294

Financin g Costs $29,109 $53

Total Overnight Costs (TOC) $1,336,034 $2,429

TASC Multiplier (IOU, low

- risk, 35 year) 1.134

Total As

- Spent Cost (TASC) $1,515,063 $2,755Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 91 Exhibit 3

- 20 Case B11 A initial and annua l operating and maintenance costs

Case: B11 A

– Subcritical PC w/o CO 2 Cost Base: Jun 2011

Plant Size (MW,net): 550 Heat Rate

- net (Btu/kWh): 8,740 Capacity Factor (%): 8 5

Operating & Maintenance Labor

Operating Labor Operating Labor Requirements per Sh ift

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.: 2.0

Total: 14.0

Fixed Operating Costs

Annual Cost

($) ($/kW

- net)

Annual Operating Labor: $6,329,450 $11.509

Maintenance Labor: $6,888,918 $12.527

Administrative & Support Labor: $3,304,592 $6.009

Property Taxes and Insurance: $21,562,266 $39.209

Total: $38,085,227 $69.254

Variable Operating Costs

($) ($/M Wh

- net)

Maintenance Material: $10,333,377 $2.52347

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 3,987 $1.67 $0 $2,070,683 $ 0.50567

Makeup and Waste Water

Treatment Chemicals (lbs): 0 19,300 $0.27 $0 $1,603,749 $0.39164

Limestone (ton) 0 489 $33.48 $0 $5,074,576 $1.23924

Hydrated Lime (ton) 0 100 $155.00 $0 $4,791,509 $1.17011

Activated Carbon (ton) 0 3 $1,255.00 $0 $1,120, 453 $0.27362

Ammonia (19% NH 3 , ton) 0 72 $330.00 $0 $7,327,095 $1.78932

SCR Catalyst (m 3 ) 0 0.33 $8,938.80 $0 $908,626 $0.22189

Subtotal: $0 $22,896,691 $5.59150

Waste Disposal

Fly Ash (ton) 0 490 $25.11 $0 $3,816,576 $0.93203

Bottom Ash (ton) 0 96 $25.11 $0 $750,758 $0.18334

Subtotal: $0 $4,567,334 $1.11537

By

- Products

Gypsum (ton) 0 84 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000

Variable Operating Costs Total: $0 $37,797,401 $9.23034

Fuel Cost

Illinois Number 6 (ton): 0 4 ,944 $68.54 $0 $105,133,037 $25.67409

Total: $0 $105,133,037 $25.67409



### Exhibit 3

- 21 Case B 11A COE breakdown

Component Value, $/MWh Percentage

Capital 37.8 46%

Fixed 9.3 11%

Variable 9.2 11%

Fuel 25 .7 31%

Total (Excluding T&S) 82.1 N/A

CO 2 

### T&S 0.0 0%

Total (Including T&S) 82.1 N/ACost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 92 

## 3.2.7 Case B11B

– PC Subcritical Unit with CO 2 

## Capture

The plant configuration for Case B11B, subcritical PC, is the same as Case B11A with the

exception that the Cansolv s ystem was used for the CDR facility . The nominal net output was

maintained at 550 MW by increasing the boiler size and turbine/generator size to account for the

greater auxiliary load imposed by the CDR facility and CO 2 

## compressors . Unlike the NGCC

cases where gross output was fixed by the available size of the CTs, the PC cases utilize boilers

and steam turbines that can be procured at nearly any desired output making it possible to

maintain a constant net output.

The process description for Case B11B is essentially the same as Case B11A with one notable

exception , the addition of CO 2 

## capture and compression . A BFD and stream tables for Case

B11B are shown in Exhibit 3

- 22 and Exhibit 3

- 23 , respectively. Since the CDR facility process

description was provided in Section 3.1.8 , it is not repeated here.



## 3.2.8 Case B11B Performance Results

The Case B11B modeling assumptions were presented previously in Section 3.2.2

.

The plant produces a net output of 550 MW at a net plant efficiency of 31.2 percent (HHV

basis). Overall plant performance is summarized in Exhibit 3

- 24 ; Exhibit 3

- 25 provides a

detailed brea kdown of the auxiliary power requirements. The CDR facility, including CO 2 

## compression, accounts for over half of the auxiliary plant load. The CWS (CWPs and cooling

tower fan) accounts for over 13 percent of the auxiliary load, largely due to the high c ooling

water demand of the CDR facility and CO 2 

## compressors

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 93 Exhibit 3

- 22 Case B11B block flow diagram , subcritical unit with CO 2 

### c apture

Source: NETL S TACK GAS

S TACK C ANSOLV 31 32

33

22

23

CO 2

P RODUCT R EBOILER

S TEAM R EBOILER

C ONDENSATE

P ULVERIZED

C OAL

B OILER SCR B AGHOUSE FGD

G YPSUM L IMESTONE

S LURRY O XIDATION

A IR M AKEUP

W ATER

B OTTOM A SH C OAL F EED I NFILTRATION

AIR

1

4

8 7

9 14

F LY A SH 15 16 18 19

17 20 21

HP

TURBINE 34

35 36

IP

TURBINE LP TURBINE

CONDENSER

38 FEEDWATER

HEATER

SYSTEM

Note : Block Flow Diagram is not intended to

represent a complete material balance

. Only

major process streams and equipment are

shown

. 3 2

6

5 11

37 10 H YDRATED

L IME 12

13 A CTIVATED

C ARBON

FD F ANS

PA F ANS ID F AN

CO 2 C OMPRESSORS

B OILER

F EEDWATER 29 R ECLAIMER

S TEAM 30

R ECLAIMER

C ONDENSATE

D RYER

27

CO 2 C OMPRESSORS 28 26 25 24 V ENT

D RYER S TEAM D RYER

C ONDENSATECost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 94 Exhibit 3

- 23 Case B11B stream table , subcritical unit with c apture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V

- L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0000 0.0088 0.0000 0.0088 0.0000

CO 2 0.0003 0.0003 0 .0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.0000 0.1376 0.0000 0.1376 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 0.0000 0.0000 0.0000

H 2 O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0 000 0.0831 0.0000 0.0831 0.0000

N 2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.0000 0.7345 0.0000 0.7345 0.0000

O 2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0000 0.0340 0.0000 0.0340 0.3333

SO 2 0.0000 0.0000 0 .0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0020 0.0000 0.0020 0.6667

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 64,558 64,558 1,912 19,831 19,831 2,729 1,410 0 0 0 90,489 0 90,489 4

V

- L Flowrate (kg/hr) 1,862,938 1,862,938 55,177 572,275 572,275 78,760 40,691 0 0 0 2,687,332 0 2,687,332 206

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 234,131 4,541 4,719 22,881 136 23,017 23,017

Temperature (°C) 15 19 19 15 25 25 15 15 149 27 143 27 143 143

Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10

Steam Table Enthalpy (kJ/kg) A 30.23 34.36 34.36 30.23 40.78 40.78 30.23

--- --- 0.00 0.00 0.00

--- - -- AspenPlus Enthalpy (kJ/kg) B

- 97.58

- 93.45

- 93.45

- 97.58

- 87.03

- 87.03

- 97.58

- 2,114.05 97.18

- 13,306.82

- 2,399.50 3.40

- 2,399.38

- 2,632.03

Density (kg/m 3 ) 1.2 1.2 1.2 1.2 1.3 1.3 1.2

--- --- --- 0.9

--- 0.9 1.5

V

- L Molecular Weight 28.857 28.857 28.8 57 28.857 28.857 28.857 28.857

--- --- --- 29.698

--- 29.698 53.376

V

- L Flowrate (lb mole /hr) 142,325 142,325 4,215 43,721 43,721 6,017 3,109 0 0 0 199,495 0 199,495 9

V

- L Flowrate (lb/hr) 4,107,075 4,107,075 121,644 1,261,650 1,261,650 17 3,636 89,709 0 0 0 5,924,552 0 5,924,552 454

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 516,170 10,010 10,403 50,444 300 50,745 50,745

Temperature (°F) 59 66 66 59 78 78 59 59 300 80 289 80 289 289

Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16. 1 14.7 14.7 14.4 14.7 14.4 14.7 14.4 14.4

Steam Table Enthalpy (Btu/lb) A 13.0 14.8 14.8 13.0 17.5 17.5 13.0

--- --- --- --- AspenPlus Enthalpy (Btu/lb) B

- 42.0

- 40.2

- 40.2

- 42.0

- 37.4

- 37.4

- 42.0

- 908.9 41.8

- 5,720.9

- 1,031.6 1.5

- 1,031.5

- 1,131.6

Den sity (lb/ft 3 ) 0.076 0.078 0.078 0.076 0.081 0.081 0.076

--- --- --- 0.053

--- 0.053 0.096

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: Revision 3



## 95 Exhibit 3

- 23 Case B11B stream table , subcritical unit with c apture ( c ontinued)

15 16 17 18 19 20 21 22 23 24 25 26 27 28

V

- L Mole Fraction

Ar 0.0088 0.0088 0.0000 0.0000 0.0092 0.000 0 0.0082 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 2 0.1376 0.1376 0.0000 0.0000 0.0003 0.0001 0.1288 0.9824 0.9977 0.0497 0.0000 0.0000 0.9993 0.9993

H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 0.0831 0.0831 1.0000 1.0000 0.0099 0.9999 0.1451 0.0176 0.0023 0.9503 1.0000 1.0000 0.0007 0.0007

N 2 0.7345 0.7345 0.0000 0.0000 0.7732 0.0000 0.6854 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O 2 0.0340 0.0340 0.0000 0.0000 0.2074 0.000 0 0.0325 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO 2 0.0020 0.0020 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.00 00 1.0000

V

- L Flowrate (kg mole /hr) 90,485 90,485 2,999 12,020 957 221 98,055 11,571 11,394 19 15 15 11,375 11,375

V

- L Flowrate (kg/hr) 2,687,126 2,687,126 54,035 216,549 27,615 3,988 2,829,081 503,956 500,768 364 264 264 500,404 500,404

Solids Flowrate (kg/hr) 0 0 23,136 0 0 35,882 0 0 0 0 0 0 0 0

Temperature (°C) 143 153 15 27 167 56 56 29 29 29 476 203 29 40

Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.31 0.10 0.10 0.20 3.03 3.03 2.42 1.70 2.89 15.27

Steam Table Enthalpy (kJ/kg) A 274.36 285.60

--- 111.65 184.48

--- 286.10 42.52

- 6.01 137.83 3,408.95 863.91

- 5.92

- 205.59

AspenPlus Enthalpy (kJ/kg) B

- 2,397.37

- 2,386.12

- 14,995.75

- 15,964.53 56.67

- 12,481.91

- 2,940.32

- 8,972.02

- 8,974.91

- 15,229.20

- 12,571.34

- 15,116.38

- 8 ,970.17

- 9,169.84

Density (kg/m 3 ) 0.8 0.9 1,003.6 992.3 2.4 833.2 1.1 3.5 63.3 374.4 7.1 861.8 59.9 789.2

V

- L Molecular Weight 29.697 29.697 18.015 18.015 28.857 18.018 28.852 43.553 43.950 19.308 18.015 18.015 43.991 43.991

V

- L Flowrate (lb mole /hr) 199,486 199,486 6,613 26,500 2,110 488 216,174 25,510 25,120 42 32 32 25,078 25,078

V

- L Flowrate (lb/hr) 5,924,098 5,924,098 119,126 477,408 60,881 8,792 6,237,055 1,111,033 1,104,005 803 581 581 1,103,202 1,103,202

Solids Flowrate (lb/hr) 0 0 51,005 0 0 79,106 0 0 0 0 0 0 0 0

Temperature (°F) 289 308 59 80 332 133 133 85 85 85 888 397 85 104

Pressure (psia) 14.2 15.2 15.0 15.7 45.0 14.7 14.7 28.7 439.4 439.4 350.5 247.3 419.4 2,214.7

Steam Table Enthalpy (Btu/lb) A 118.0 12 2.8

--- 48.0 79.3

--- 123.0 18.3

- 2.6 59.3 1,465.6 371.4

- 2.5

- 88.4

AspenPlus Enthalpy (Btu/lb) B

- 1,030.7

- 1,025.8

- 6,447.0

- 6,863.5 24.4

- 5,366.3

- 1,264.1

- 3,857.3

- 3,858.5

- 6,547.4

- 5,404.7

- 6,498.9

- 3,856.5

- 3,942.3

Density (lb/ft 3 ) 0.052 0.055 62.650 61.950 0.153 52.013 0.067 0.216 3.953 23.375 0.446 53.800 3.737 49.267

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: Revision 3



## 96 Exhibit 3

- 23 Case B11B stream table , subcritical unit with c apture ( c ontinued)

29 30 31 32 33 34 35 36 37 38

V

- L Mole Fraction

Ar 0.0000 0.0000 0.0000 0.0000 0.0103 0.0000 0.0000 0.0000 0.0000 0.0000

CO 2 0.0000 0.0000 0.0000 0.0000 0.0163 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

H 2 O 1.0000 1.0000 1.0000 1.0000 0.0671 1.0000 1.0000 1.0000 1.0000 1.0000

N 2 0.0000 0.0000 0.0000 0.0000 0.865 2 0.0000 0.0000 0.0000 0.0000 0.0000

O 2 0.0000 0.0000 0.0000 0.0000 0.0410 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

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 87 87 29,214 29,214 77,673 110,081 102,661 102,661 61,864 63,201

V

- L Flowrate (kg/hr) 1,561 1,561 526,301 526,300 2,166,238 1,983,144 1,849,458 1,849,458 1,114,489 1,138,575

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 355 215 266 151 41 566 355 566 38 39

Pressure (MPa, abs) 4.28 2.20 0.51 0.51 0.10 16.65 4.28 4.19 0.01 1.32

Steam Table Enthalpy (kJ/kg) A 3,098.44 921.65 2,994.07 635.95 151.94 3,473.89 3,098.44 3,593.58 1,976.98 1 62.43

AspenPlus Enthalpy (kJ/kg) B

- 12,881.86

- 15,058.64

- 12,986.23

- 15,344.34

- 794.66

- 12,506.41

- 12,881.86

- 12,386.71

- 14,003.31

- 15,817.87

Density (kg/m 3 ) 16.0 846.4 2.1 916.3 1.1 47.7 16.0 11.1 0.1 993.3

V

- L Molecular Weight 18.015 18.015 18.015 18.0 15 27.889 18.015 18.015 18.015 18.015 18.015

V

- L Flowrate (lb mole /hr) 191 191 64,406 64,406 171,241 242,688 226,328 226,328 136,386 139,333

V

- L Flowrate (lb/hr) 3,441 3,441 1,160,294 1,160,293 4,775,737 4,372,084 4,077,357 4,077,357 2,457,027 2,510,129

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 671 419 512 304 107 1,050 671 1,050 101 101

Pressure (psia) 620.5 319.0 73.5 73.5 14.7 2,414.7 620.5 608.1 1.0 190.7

Steam Table Enthalpy (Btu/lb) A 1,332.1 396.2 1,287. 2 273.4 65.3 1,493.5 1,332.1 1,545.0 850.0 69.8

AspenPlus Enthalpy (Btu/lb) B

- 5,538.2

- 6,474.0

- 5,583.1

- 6,596.9

- 341.6

- 5,376.8

- 5,538.2

- 5,325.3

- 6,020.3

- 6,800.5

Density (lb/ft 3 ) 1.000 52.840 0.129 57.202 0.068 2.975 1.000 0.692 0.004 62.010

A 

### Steam t able 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: Revision 3



## 97 Exhibit 3

- 24 Case B11B plant perfo rmance summary

Performance Summary

Total Gross Power, MWe 644

CO
2 Capture/Removal Auxiliaries, kWe 16,600

CO
2 Compression, kWe 36,560

Balance of Plant, kWe 41,1 61

Total Auxiliaries, MWe 94

Net Power, MWe 550

HHV Net Plant Efficiency (%) 31.2%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,556 (10,953)

LHV Net Plant Efficiency (%) 32.3%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,146 (10,565)

HHV Boiler Efficiency, % 89.1%

LHV Boiler Efficiency, % 92.4%

Steam Turbine Cycle Efficiency, % 52.5%

S team Turbine Heat Rate, kJ/kWh (Btu/kWh) 6,854 (6,497)

Condenser Duty, GJ/hr ( MM Btu/hr) 2,022 (1,916)

As

- Received Coal Feed, kg/hr (lb/hr) 234,131 (516,170)

Limestone Sorbent Feed, kg/hr (lb/hr) 23,136 (51,005)

HHV Thermal Input, kWt 1,764,768

LHV The rmal Input, kWt 1,702,141

Raw Water Withdrawal, ( m 3 

### / min)/MW net 

### (gpm/MW net 

### ) 0.058 (15.4)

Raw Water Consumption, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.045 (11.9)

Excess Air, % 20.9%Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 98 Exhibit 3

- 25 Case B11 B plant power summary

Power Summary

Steam Turbine Power, MWe 644

Total Gross Power, MWe 644

Auxiliary Load Summary

Coal Handling and Conveying, kWe 490

Pulverizers, kWe 3,510

Sorbent Handling & Reagent Preparation, kWe 1,110

Ash Handling, kWe 820

Primary A ir Fans, kWe 1,740

Forced Draft Fans, kWe 2,220

Induced Draft Fans, kWe 8,700

SCR, kWe 60

Activated Carbon Injection, kWe 28

Dry sorbent Injection, kWe 113

Baghouse, kWe 110

Wet FGD, kWe 3,700

CO
2 Capture/Removal Auxiliaries, kWe 16,600

CO
2 Compre ssion, kWe 36,560

Miscellaneous Balance of Plant A,B 

### , kWe 2,000

Steam Turbine Auxiliaries, kWe 400

Condensate Pumps, kWe 550

Circulating Water Pumps, kWe 8,210

Ground Water Pumps, kWe 760

Cooling Tower Fans, kWe 4,250

Transformer Losses, kWe 2,400

T otal Auxiliaries, MWe 94

Net Power, MWe 550

A 

### Boiler feed pumps are turbine driven

B 

### Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads



## 3.2.8.1 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 B11B is presented in Exhibit 3

- 26

. SO 2



## emissions are utilized as a surrogate for HCl emissions, therefore HCl is not reported.

E xhibit 3

- 26 Case B11B air emissions

kg/GJ (lb/ MM Btu) Tonne/year (ton/year) A 

### kg/MWh (lb/MWh)

SO
2 0.000 (0.000) 0 (0) 0.000 (0.0 0 0)

NOx 0.032 (0.075) 1,523 (1,679) 0.318 (0.700)

Particulate 0.004 (0.0 10 ) 196 (216) 0.041 (0.090)

Hg 1.38E

- 7 (3.21E

- 7) 0.007 (0.007) 1.36E

- 6 (3.00E

- 6)

CO
2 B 

### 9 (20) 413,912 (456,260) 86 (190)

CO
2 C



### - - 101 (223)

mg/Nm 3



### Particulate Concentration D

, E 

### 12.97

A 

### Calculations based on an 85 percent capacity factor

B 

### CO 2 

### emissions based on gross power

C 

### CO 2 

### emissions based on net power instead of gross power

D 

### Concentration of particles in the flue gas after the baghouse

E 

### Normal c onditions given at 32°F and 14.696 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 99 SO 2 

## emissions are controlled using a wet limestone forced oxidation scrubber that achieves a

removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site.

The wallboard grade mate rial can potentially be marketed and sold, but since it is highly

dependent on local market conditions, no byproduct credit was taken. The SO 2 

## emi ssions are

further reduced to 1 ppmv using a NaOH based polishing scrubber in the CDR facility. The

remainin g low concentration of SO 2 

## is essentially completely removed in the CDR absorber

vessel resulting in very low SO 2 

## emissions.

NOx emissions are controlled to about 0.5 lb/ MM Btu through the use of LNBs and OFA. An

SCR unit then further reduces the NOx conce ntration by 85 percent to 0.0 7 lb/ MM Btu.

Particulate emissions are controlled using a pulse jet fabric filter, which operates at an efficiency

of 99. 9 percent.

The total reduction in mercury emission via the combined control equipment (SCR, ACI, fabric

fil ter, DSI, and wet FGD) is 97.2 percent.

Ninety percent of the CO 2 

## in the flue gas is removed in CDR facility.

The carbon balance for the plant is shown in Exhibit 3

- 27

. The carbon input to the plant consists

of carbon in the coal , carbon in the air

, PAC, and carbon in the limestone reagent used in the

FGD absorber

. Carbon leaves the plant mostly as CO 2 

## through the stack , however, the PAC is

captured in the fabric filter and some leaves as gypsum. The carbon capture efficiency is defined

as one minus the amount of carbon in the stack gas relative to the total carbon in , represented by

the following fraction:

CCCCCCCC SSSS

( TT CCCCCCCC ) = � 1

− � 33

, 446

335

, 258 �

∗ � 100 = 90

. 0%

Exhibit 3

- 27 Case B11B carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 149,246 (329,0 31) Stack Gas 15,171 (33,446)

Air (CO
2 ) 340 (751) FGD Product 224 (494)

PAC 136 (300) Baghouse 136 (300)

FGD Reagent 2,348 (5,175) CO
2 Product 136,528 (300,992)

CO 2 

### Dryer Vent 11 (25)

CO
2 Knockout 0 (1)

Total 152,070 (335,258) Total 152,070 (335, 258)



## Exhibit 3

- 28 shows the su lfur balance for the plant. Sulfur input comes solely from the sulfur in

the coal. Sulfur output includes the sulfur recovered from the FGD as gypsum

, sulfur emitted in

the stack gas , and sulfur re moved in the polishing scrubber.

Exhibit 3

- 28 Case B11B sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 5,868 (12,937) FGD Product 5,670 (12,500)

Stack Gas 0 (0)

Polishing Scr ubber and Solvent Reclaiming 116 (255)

Baghouse 82 (182)

Total 5,868 (12,937) Total 5,868 (12,937)Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 100 Exhibit 3

- 29 shows the overall water balance for the plant. The exhibit is presented in an

identical manner a s was for Case B11A.

Exhibit 3

- 29 Case B11B 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)

FGD Makeup 4.52 (1,193)

– 4.52 (1,193)

– 4.52 (1,193)

CO
2 Drying

– – – 0.01 (2)

- 0.01 (

- 2)

Capture System

Makeup 0.02 (6)

– 0.02 (6)

– 0.02 (6)

Deaerator Vent

– – – 0.07 (18)

- 0.07 (

- 18)

Condenser Makeup 0.40 (106)

– 0.40 (10 6)

– 0.40 (106)

BFW Makeup 0.40 (106)

– 0.40 (106)

– 0.40 (106)

Cooling Tower 31.99

(8,451) 4.98 (1,315) 27.01

(7,136) 7.19 (1,900) 19.82 (5,235)

FGD Dewatering

– 2.33 (615)

- 2.33 (

- 615)

– - 2.33 (

- 615)

CO
2 Capture

Recovery – 2.65 (700)

- 2.65 (

- 700)

– - 2.65 (

- 700)

CO
2 Compression

KO – 0.05 (14)

- 0.05 (

- 14)

– - 0.05 (

- 14)

BFW Blowdown

– 0.34 (89)

- 0.34 (

- 89)

– - 0.34 (

- 89)

Total 36.93

(9,755) 4.98 (1,315) 31.95

(8,441) 7.27 (1,920) 24.68 (6,521)



## 3.2.8.2 Heat and Mass Balance Diagrams

A heat an d mass balance diagram is shown for the Case B11B PC boiler, the FGD unit, CDR

system and steam cycle in Exhibit 3

- 30 and Exhibit 3

- 31 . An overall plant energy balance is

provided in tabu lar form in Exhibit 3

- 32

.

The power out is the steam turbine power prior to generator losses. The power at the generator

terminals (shown in Exhibit 3

- 24 ) is calculated by multiplying t he power out by a generator

efficiency of 98. 5 percent. The capture process heat out stream represents heat rejected to

cooling water and ultimately to ambient via the cooling tower. The same is true of the condenser

heat out stream. The CO 2 

## compressor intercooler load is included in the capture process heat out

stream.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 101 Exhibit 3

- 30 Case B11B heat and mass balance, subcritical PC boiler with CO 2 

### capture

Source: NETL Notes :

1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psia

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P AGES

1 OF 2 B ITUMINOUS B ASELINE S TUDY

C ASE B 11 B

S UBCRITICAL P ULVERIZED C OAL

B OILER AND G AS C LEANUP S YSTEMS

DWG

. NO

. BB

- HMB

- CS

- B 11 B

- PG

- 1 Pulverized

Coal

Boiler SCR Ammonia

Infiltration Air

Air

Air

Coal

Bottom Ash FGD

Fly Ash

Forced

Draft Fans

Primary

Air Fans

516

, 170 W

59 T

15 P 78 T

16 P

18 H 66 T

15 P

15 H 4

, 372

, 084 W

1

, 050 T

2

, 415 P

1

, 494 H

4

, 077

, 357 W

1

, 050 T

608 P

1

, 545 H

1

, 261

, 650 W

59 T

15 P

13 H 4

, 107

, 075 W

59 T

15 P

13 H 89

, 709 W

59 T

15 P

13 H 5

, 974

, 996 W

289 T

14 P

117 H

10

, 010 W

300 T

14 P 51

, 199 W

289 T

14 P

4

, 077

, 357 W

671 T

621 P

1

, 332 H

4

, 372

, 084 W

486 T

2

, 536 P

471 H 5 4

, 775

, 737 W

107 T

15 P

65 H

1 2

4 7

9 ID Fans 5

, 924

, 098 W

289 T

14 P

118 H

Gross Plant Power : 644 MWe

Auxiliary Load : 94 MWe

Net Plant Power : 550 MWe

Net Plant Efficiency

, HHV : 31

. 2 %

Net Plant Heat Rate : 10

, 953 Btu / kWh Oxidation

Air Make

- Up

Water

Limestone

Slurry Gypsum

18

17 14 5

, 924

, 098 W

308 T

15 P

123 H

170

, 131 W

59 T

15 P

423 H 60

, 881 W

332 T

45 P

79 H 477

, 408 W

80 T

16 P

48 H

87

, 898 W

133 T

15 P

1

, 499 H Baghouse

3

6

8 15 16 19

34

35 36

DOE / NETL

SC PC P LANT

C ASE B 11 B Hydrated

Lime 11

Single Reheat

Extraction from

HP Turbine

From Feedwater

Heaters Single Reheat

To IP Turbine Throttle Steam

To HP Turbine 10

, 403 W

80 T

15 P 10 Activated

Carbon

12 13

300 W

80 T

15 P

CansolvStripperAbsorber Flue Gas Acid Gas 1

, 111

, 033 W

85 T

29 P

18 H 22 33 6

, 237

, 055 W

133 T

15 P

123 H

Stack 21

1

, 103

, 202 W

104 T

2

, 215 P

- 88 H CO 2
Product CO 2 Compression

( Interstage Cooling ) &

Drying 7

, 028 W

85 T

62 P

66 H

KO

- Water Dryer

Water

803 W

85 T

439 P

59 H 24

Dryer

28 23

27 1

, 103

, 202 W

85 T

419 P

- 3 H 1

, 104

, 005 W

85 T

439 P

- 3 H 5

, 975

, 297 W

289 T

14 P

117 H

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical 20 Air

Coal / Ash

Slurry

Water Steam

Lime /

Limestone /

Gypsum

Flue Gas

Activated

Carbon

Ammonia Carbon DioxideCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 102 Exhibit 3

- 31 Case B11B heat and mass balance, subcritical steam cycle

Source: NETL H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Water Steam

P AGES

2 OF 2 DWG

. NO

. BB

- HMB

- CS

- B 11 B

- PG

- 2

B ITUMINOUS B ASELINE S TUDY

C ASE B 11 B

S UBCRITICAL P ULVERIZED C OAL

P OWER B LOCK S YSTEMS LP Turbine Generator HP

Turbine IP

Turbine

Condenser

Hot Well Boiler Feed Pump

Turbine Drives Throttle

Steam

Condensate

Pumps 4

, 372

, 084 W

1

, 050 T

2

, 415 P

1

, 494 H

431

, 232 W

887 T

336 P

1

, 466 H 291

, 286 W

669 T

596 P

1

, 332 H 4

, 077

, 357 W

671 T

621 P

1

, 332 H 218

, 704 W

512 T

74 P

1

, 287 H

218

, 704 W

126 T

2 P

1

, 071 H 1

, 808

, 607 W

101 T

1 P

1

, 006 H

2

, 510

, 129 W

101 T

1 P

69 H

2

, 510

, 129 W

101 T

191 P

70 H 2

, 510

, 129 W

155 T

183 P

124 H

429

, 716 W

111 T

1 P

79 H 312

, 590 W

165 T

5 P

133 H 2

, 510

, 129 W

290 T

162 P

259 H

722

, 518 W

321 T

90 P

291 H 2

, 510

, 129 W

262 T

169 P

231 H

291

, 286 W

440 T

382 P

419 H 4

, 372

, 084 W

430 T

2

, 642 P

410 H

Deaerator

Boiler Feed

Water Pumps 4

, 372

, 084 W

486 T

2

, 536 P

471 H 4

, 077

, 357 W

1

, 050 T

608 P

1

, 545 H

67

, 760 W

272 T

43 P

241 H 225

, 307 W

204 T

13 P

172 H 2

, 510

, 129 W

194 T

176 P

163 H 28

, 224 W

511 T

72 P

1

, 287 H 67

, 760 W

484 T

62 P

1

, 275 H 157

, 547 W

402 T

40 P

1

, 237 H 87

, 283 W

200 T

11 P

1

, 146 H 117

, 126 W

160 T

5 P

1

, 094 H 3

, 617

, 320 W

512 T

74 P

1

, 287 H 2

, 238

, 323 W

512 T

74 P

1

, 287 H

2

, 752 P

4

, 372

, 084 W

305 T

72 P

275 H Gross Plant Power : 644 MWe

Auxiliary Load : 94 MWe

Net Plant Power : 550 MWe

Net Plant Efficiency

, HHV : 31

. 2 %

Net Plant Heat Rate : 10

, 953 Btu / kWh FWH 1 FWH 2 FWH 3 FWH 4 FWH 5 FWH 6 34

38

DOE / NETL

SC PC P LANT

C ASE B 11 B 36 53

, 102 W

59 T

15 P

27 H

Blowdown Vent Notes :

1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psia Single Reheat

Extraction

From Boiler

Single Reheat

Extraction to

Boiler

To Boiler Steam Turbine

Makeup

35

Reclaimer

Steam 29 581 W

888 T

351 P

1

, 466 H

Dryer

Steam Reboiler

Steam

1

, 160

, 294 W

512 T

74 P

1

, 287 H 25

31

32

30 Reboiler

Condensate

Reclaimer

Condensate

26

Dryer

Condensate 581 W

397 T

247 P

371 H 3

, 441 W

419 T

319 P

396 H 1

, 160

, 293 W

304 T

74 P

273 H W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical 37

3

, 441 W

671 T

621 P

1

, 332 HCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 103 Exhibit 3

- 32 Case B11B overall energy balance ( 0°C [ 32°F ] r eference)

HHV Sensible +

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 6,353

(6,022) 5.3 (5.0)

– 6,358 (6,027)

Air

– 74.8 (70.9)

– 74.8 (70.9)

Raw Water Makeup

– 120.1 (113.9)

– 120.1 (113.9)

Limestone

– 0.50 (0.48)

– 0.50 (0.48)

Auxiliary Power

– – 340 (322) 340 (322)

TOTAL 6,353

(6,022) 2 00.8 (190.3) 340 (322) 6,894 (6,534)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash

– 0.5 (0.5)

– 0.5 (0.5)

Fly Ash + FGD Ash

– 2.6 (2.5)

– 2.6 (2.5)

Stack Gas

– 329 (312)

– 329 (312)

Sulfur 2.1 (2.0) 0.0 (0.0)

– 2.2 (2.0)

Motor Losses and Design

Allowances – – 44 (42) 44 (42)

Condenser

– 2,022 (1,916)

– 2,022 (1,916)

Non

- Condenser Cooling

Tower Loads – 106 (100)

– 106 (100)

CO
2 – - 102.9 (

- 97.5)

– - 102.9 (

- 97.5)

Cooling Tower Blowdown

– 53.4 (50.7)

– 53.4 (50.7)

CO
2 Capture Losses

– 2,050 (1,943)

– 2,050 (1,943)

Ambient Losses A



### – 137.2 (130.0)

– 137.2 (130.0)

Power

– – 2,319 (2,198) 2,319 (2,198)

TOTAL 2.1 (2.0) 4,492 (4,35 8) 2,363 (2,240) 6,857 (6,599)

Unaccounted Energy B



### – 36 (

- 66)

– 36 (

- 66)

A 

### Ambient losses include all losses to the environment through radiation, convection, etc. Sources of these

losses include the boiler, reheater, superheater, and transformers.

B 

### By di fference



## 3.2.9 Case B11B

– Major Equipment List

Major equipment items for the subcritical PC plant 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 Sectio n 3.2.10 . In general, the design conditions include a 10 percent

contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

Case B11 B

– Account 1: Coal and Sorbent Handling

Equipmen

t No. De scription Type Design Condition Operating

Qty. Spares

1 Bottom Trestle Dumper and

Receiving Hoppers N/A 180 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 Transfer Tower No. 1 Enclose d N/A 1 0

5 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

6 As

- Received Coal Sampling System Two

- stage N/A 1 0

7 Stacker/Reclaimer Traveling,

linear 1,130 tonne/hr (1,250 tph) 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 104 Equipmen

t No. De scription Type Design Condition Operating

Qty. Spares

8 Reclaim Hopper N/A 50 tonne (50 ton) 2 1

9 Feeder Vibratory 190 tonne/hr (210 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 390 tonne/hr (430 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 190 tonne (210 ton) 2 0

13 Crusher Impactor

reduction 8 cm x 0

- 3 cm x 0

(3 in x 0

- 1

- 1/4 in x 0) 2 0

14 As

- Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 390 tonne/hr (430 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 390 tonne/hr (430 tph) 1 0

18 Coal Silo w/ Vent Filt er and Slide

Gates Field erected 860 tonne (900 ton) 3 0

19 Activated Carbon Storage Silo and

Feeder System Shop

assembled Silo

- 36 tonne (40 ton)

Feeder

- 150 kg/hr (330

lb/hr) 1 0

20 Hydrated Lime Storage Silo and

Feeder System Shop

assembled Silo

- 2 50 tonne (270 ton)

Feeder

- 5,190 kg/hr

(11,440 lb/hr) 1 0

21 Limestone Truck Unloading Hopper N/A 30 tonne (40 ton) 1 0

22 Limestone Feeder Belt 100 tonne/hr (110 tph) 1 0

23 Limestone Conveyor No. L1 Belt 100 tonne/hr (110 tph) 1 0

24 Limestone Recla im Hopper N/A 20 tonne (20 ton) 1 0

25 Limestone Reclaim Feeder Belt 80 tonne/hr (80 tph) 1 0

26 Limestone Conveyor No. L2 Belt 80 tonne/hr (80 tph) 1 0

27 Limestone Day Bin w/ actuator 310 tonne (340 ton) 2 0



## Case B11 B

– Account 2: Coal and Sorbent Pr eparation and Feed

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Coal Feeder Gravimetric 40 tonne/hr (50 tph) 6 0

2 Coal Pulverizer Ball type or

equivalent 40 tonne/hr (50 tph) 6 0

3 Limestone Weigh Feeder Gravimetric 25 tonne/ hr (28 tph) 1 1

4 Limestone Ball Mill Rotary 25 tonne/hr (28 tph) 1 1

5 Limestone Mill Slurry Tank

with Agitator N/A 97,700 liters (26,000 gal) 1 1

6 Limestone Mill Recycle

Pumps Horizontal centrifugal 1,620 lpm @ 10m H

2 O

(430 gpm @ 40 ft H

2 O) 1 1

7 Hydroclone Classifier 4 active cyclones in a

5 cyclone bank 410 lpm (110 gpm) per

cyclone 1 1

8 Distribution Box 2

- way N/A 1 1

9 Limestone Slurry Storage

Tank with Agitator Field erected 550,000 liters (145,000

gal) 1 1

10 Limestone Slurry Feed Pumps Horizontal centrifugal 1,150 lpm @ 9m H

2 O

(300 gpm @ 30 ft H

2 O) 1 1



## Case B11 B

– Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Demineral ized Water

Storage Tank Vertical, cylindrical,

outdoor 1,592,000 liters (421,000

gal) 2 0

2 Condensate Pumps Vertical canned 21,000 lpm @ 200 m H

2 O

(5,600 gpm @ 500 ft H

2 O) 1 1Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 105 Equipment

No. Description Type Design Condition Operating

Qty. Spares

3 Deaerator and Storage

Tank Horizontal spray type 2,208,000 kg/hr

(4,868,0 00 lb/hr),

5 min. tank 1 0

4 Boiler Feed

Pump/Turbine Barrel type, multi

- stage,

centrifugal 36,600 lpm @ 2,300 m H

2 O

(9,700 gpm @ 7,500 ft H

2 O) 1 1

5 Startup Boiler Feed

Pump, Electric Motor

Driven Barrel type, multi

- stage,

centrifugal 10,900 lpm @ 2,3 00 m H 2 O

(2,900 gpm @ 7,500 ft H

2 O) 1 0

6 LP Feedwater Heater

1A/1B Horizontal U

- tube 630,000 kg/hr

(1,380,000 lb/hr) 2 0

7 LP Feedwater Heater

2A/2B Horizontal U

- tube 630,000 kg/hr

(1,380,000 lb/hr) 2 0

8 LP Feedwater Heater

3A/3B Horizontal U

- tube 630,000 kg/hr

(1,380,000 lb/hr) 2 0

9 LP Feedwater Heater

4A/4B Horizontal U

- tube 630,000 kg/hr

(1,380,000 lb/hr) 2 0

10 HP Feedwater Heater 6 Horizontal U

- tube 2,180,000 kg/hr

(4,810,000 lb/hr) 1 0

11 HP Feedwater Heater 7 Horizontal U

- tube 2,180,00 0 kg/hr

(4,810,000 lb/hr) 1 0

12 Auxiliary Boiler Shop fabricated, water

tube 20,000 kg/hr, 2.8 MPa,

343°C (40,000 lb/hr, 400

psig, 650°F) 1 0

13 Fuel Oil System No. 2 fuel oil for light off 1,135,624 liter (300,000 gal) 1 0

14 Service Air Compressors Flooded Screw 28 m 3 / min @ 0.7 MPa

(1,000 scfm @ 100 psig) 2 1

15 Instrument Air Dryers Duplex, regenerative 28 m 3 / min (1,000 scfm) 2 1

16 Closed Cycle Cooling

Heat Exchangers Shell and tube 53 GJ/hr

(50 MMBtu/hr) each 2 0

17 Closed Cycle Cooling

Water Pumps Horizontal centrifugal 20,800 lpm @ 30 m H

2 O

(5,500 gpm @ 100 ft H

2 O) 2 1

18 Engine

- Driven Fire

Pump Vertical turbine, diesel

engine 3,785 lpm @ 88 m H

2 O

(1,000 gpm @ 290 ft H

2 O) 1 1

19 Fire Service Booster

Pump Two

- stage horizontal

centrifugal 2,650 lpm @ 64 m H

2 O

(700 gpm @ 210 ft H

2 O) 1 1

20 Raw Water Pumps Stainless steel, single

suction 9,170 lpm @ 20 m H

2 O

(2,420 gpm @ 60 ft H

2 O) 2 1

21 Ground Water Pumps Stainless steel, single

suction 3,670 lpm @ 270 m H

2 O

(970 gpm @ 880 ft H

2 O) 5 1

22 Filtered Water Pumps Stainless steel, single

suction 2,420 lpm @ 50 m H

2 O

(640 gpm @ 160 ft H

2 O) 2 1

23 Filtered Water Tank Vertical, cylindrical 2,318,000 liter (612,000 gal) 1 0

24 Makeup Water

Demineralizer Multi

- media filter,

cartridge filter, RO

membrane assembly,

electrodeionization unit 830 lpm (220 gpm) 1 1

25 Liquid Waste Treatment

System -- 10 years, 24

- hour storm 1 0



## Case B11 B

– Account 4: Boiler and Accessories

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Boiler Subcritical, drum wall

- fired,

low NOx burners , overfire

air 2,180,000 kg/hr steam

@ 17.9 MPa/574°C/574°C

(4,810,000 lb/hr steam

@ 2,600 psig/1,065°F/1,065°F) 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 106 Equipment

No. Description Type Design Condition Operating

Qty. Spares

2 Primary Air Fan Centrifugal 315,000 kg/hr, 4,300 m 3 / min

@ 123 cm WG

(694,000 lb/hr, 151,700 acfm

@ 48 in. WG) 2 0

3 Forced Draft

F an Centrifugal 1,025,000 kg/hr, 14,000 m 3 / min

@ 47 cm WG

(2,259,000 lb/hr, 493,800 acfm

@ 19 in. WG) 2 0

4 Induced Draft

Fan Centrifugal 1,478,000 kg/hr, 29,300 m 3 / min

@ 89 cm WG

(3,258,000 lb/hr, 1,035,400 acfm

@ 35 in. WG) 2 0

5 SCR Reactor

Vesse l Space for spare layer 2,960,000 kg/hr (6,520,000 lb/hr) 2 0

6 SCR Catalyst

-- -- 3 0

7 Dilution Air

Blower Centrifugal 170 m 3 / min @ 108 cm WG

(5,800 acfm @ 42 in. WG) 2 1

8 Ammonia

Storage Horizontal tank 182,000 liter (48,000 gal) 5 0

9 Ammonia Fee d

Pump Centrifugal 35 lpm @ 90 m H

2 O

(9 gpm @ 300 ft H

2 O) 2 1



## Case B11 B

– Account 5 A : F lue Gas Cleanup

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Fabric Filter Single stage, high

- ratio

with pulse

- jet online

cleaning system 1 ,478,000 kg/hr (3,259,000

lb/hr) 99.9% efficiency 2 0

2 Absorber Module Counter

- current open

spray 59,000 m 3 / min

(2,082,000 acfm) 1 0

3 Recirculation Pumps Horizontal centrifugal 205,000 lpm @ 65 m H

2 O

(54,000 gpm @ 210 ft H

2 O) 5 1

4 Bleed Pumps Horiz ontal centrifugal 4,990 lpm (1,320 gpm)

at 20 wt% solids 2 1

5 Oxidation Air Blowers Centrifugal 100 m 3 / min @ 0.3 MPa

(3,660 acfm @ 37 psia) 2 1

6 Agitators Side entering 50 hp 5 1

7 Dewatering Cyclones Radial assembly, 5 units

each 1,250 lpm (330 gpm ) per

cyclone 2 0

8 Vacuum Filter Belt Horizontal belt 39 tonne/hr (44 tph) of 50 wt

% slurry 2 1

9 Filtrate Water Return

Pumps Horizontal centrifugal 760 lpm @ 13 m H

2 O

(200 gpm @ 40 ft H

2 O) 1 1

10 Filtrate Water Return

Storage Tank Vertical, lined 500,000 lpm (130,000 gal) 1 0

11 Process Makeup

Water Pumps Horizontal centrifugal 3,980 lpm @ 21 m H

2 O

(1,050 gpm @ 70 ft H

2 O) 1 1

12 Activated Carbon

Injectors --- 15 0 kg/hr (330 lb/hr) 1 0

13 Hydrated Lime

Injectors --- 5,190 kg/hr (11,440 lb/hr) 1 0



## Case B11 B

– Account 5B: Carbon Dioxide Recovery

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Cansolv Amine

- based CO
2 capture technology 1,55 6,000 kg/hr (3,430,000 lb/hr)

19.6 wt % CO
2 concentration 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 107 Equipment

No. Description Type Design Condition Operating

Qty. Spares

2 Cansolv LP

Condensate

Pump Centrifugal 10,788 lpm @ 1 m H

2 O

(2,850 gpm @ 4 ft H

2 O) 1 1

3 Cansolv HP

Condensate

Pump Centrifugal 10,782 lpm @ 1.1 m H

2 O

(2,848 gpm @ 4 ft H

2 O) 1 1

4 CO
2 Dry er Triethylene glycol Inlet: 132.0 m 3 / min (4,655 acfm) @

3.0 MPa (439 psia) Outlet: 2.9 MPa

(419 psia) Water Recovered: 364

kg/hr (803 lb/hr) 1 0

5 CO
2 Compressor Integrally geared,

multi

- stage

centrifugal 275,140 kg/hr @ 15.3 MPa

(606,579 lb/hr @ 2,215 psia) 2 0



## Case B11 B

– Account 7: Ducting and Stack

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Stack Reinforced concrete

with FRP liner 152 m (500 ft) high x

5.6 m (19 ft) diameter 1 0



## Case B11 B

– Account 8: Steam Turbine Ge nerator and Auxiliaries

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Steam

Turbine Commercially available

advanced steam turbine 678 MW

16.5 MPa/566°C/566°C (2400 psig/

1050°F/1050°F) 1 0

2 Steam

Turbine

Generator Hydrogen cool ed, static

excitation 750 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 1 0

3 Surface

Condenser Single pass, divided

waterbox including

vacuum pumps 2,220 GJ/hr

(2,110 MMBtu/hr),

Inlet water temperature 16°C

(60°F),

Water temperature rise 11°C (20°F) 1 0



## Case B11 B

– Account 9: Cooling Water System

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Circulating

Water Pumps Vertical, wet pit 824,000 lpm @ 30 m

(218,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative,

mechanical draft,

multi

- c ell 11°C (51.5°F) wet bulb /

16°C (60°F) CWT /

27°C (80°F) HWT /

4600 GJ/hr (4360 MMBtu/hr) heat duty 1 0



## Case B11 B

– Account 10: Ash and Spent Sorbent Recovery and Handling

Equipmen

t No. Description Type Design Condition Operating

Qty. Spares

1 Econo mizer Hopper (part of boiler scope

of supply) -- -- 4 0

2 Bottom Ash Hopper (part of boiler scope of

supply) -- -- 2 0

3 Clinker Grinder

-- 5.0 tonne/hr (5.5 tph) 1 1

4 Pyrites Hopper (part of pulverizer scope of

supply included with boiler) -- -- 6 0

5 Hydroejectors

-- -- 12

6 Economizer /Pyrites Transfer Tank

-- -- 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 108 Equipmen

t No. Description Type Design Condition Operating

Qty. Spares

7 Ash Sluice Pumps Vertical,

wet pit 200 lpm @ 17 m H

2 O

(50 gpm @ 56 ft H

2 O) 1 1

8 Ash Seal Water Pumps Vertical,

wet pit 7,570 lpm @ 9 m H

2 O

(2000 gpm @ 28 ft

H 2 O) 1 1

9 Hydrobi ns

-- 190 lpm (50 gpm) 1 1

10 Baghouse Hopper (part of baghouse

scope of supply) -- -- 24 0

11 Air Heater Hopper (part of boiler scope of

supply) -- -- 10 0

12 Air Blower

-- 20 m 3 / min @ 0.2 MPa

(820 scfm @ 24 psi) 1 1

13 Fly Ash Silo Reinforce

d concre te 1,500 tonne (1,700 ton) 2 0

14 Slide Gate Valves

-- -- 2 0

15 Unloader

-- -- 1 0

16 Telescoping Unloading Chute

-- 140 tonne/hr (160 tph) 1 0



## Case B11 B

– Account 11: Accessory Electric Plant

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 STG Transformer Oil

- filled 24 kV/345 kV, 650

MVA, 3

- ph, 60 Hz 1 0

2 High Voltage Transformer Oil

- filled 345 kV/13.8 kV, 20

MVA, 3

- ph, 60 Hz 2 0

3 Medium Voltage Transformer Oil

- filled 24 kV/4.16 kV, 102

MVA, 3

- ph, 60 Hz 1 1

4 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 15

MVA, 3

- ph, 60 Hz 1 1

5 STG Isolated Phase Bus Duct

and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 1 0

6 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 1

7 Low Voltage Switchgear Metal enclo sed 480 V, 3

- ph, 60 Hz 1 1

8 Emergency Diesel Generator Sized for emergency

shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 0



## Case B11 B

– Account 12: Instrumentation and Control

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 DCS

- Main

Co ntrol Monitor/keyboard; Operator

printer (laser color); Engineering

printer (laser B&W) Operator stations/printers

and engineering

stations/printers 1 0

2 DCS

- Processor Microprocessor with redundant

input/output N/A 1 0

3 DCS

- Data

Highway Fiber optic Fully redundant, 25% spare 1 0



## 3.2.10 Case B11B

– Cost Estimating

The cost estimating methodology was described previously in Section 2.7

. Exhibit 3

- 33 shows a

detailed breakdown of the capital costs; Exhibit 3

- 34 shows the owner’s costs , TOC, and TASC ;

Exhibit 3

- 35 shows the initial and annual O&M costs; and Exhibit 3

- 36 shows the COE

breakdown.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 109 The estimated TP C of the subcrit ical PC boiler with CO 2 

## capture is $3, 467 /kW. Process

contingency represents 3. 4 percent of the TP C and project contingency represents 12. 3 percent.

The COE, including CO 2 

## T&S costs of $10.0 /M Wh, is $ 143.5 /M Wh.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 110 Exhibit 3

- 33 Case B11B total plant cost details

Case: B11B

– Subcritical PC w/ CO 2 Estimate Type: Conceptual

Plant Size (MW,net): 550 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 $4,719 $0 $2,126 $0 $6,845 $684 $0 $1,129 $8,658 $16

1.2 Coal Stackout & Reclaim $6,098 $0 $1,363 $0 $7,461 $746 $0 $1,231 $9,438 $17

1.3 Coal Conveyors $5,670 $0 $1,348 $0 $7,018 $702 $0 $1,158 $8,878 $ 16

1.4 Other Coal Handling $1,483 $0 $312 $0 $1,795 $180 $0 $296 $2,271 $4

1.5 Sorbent Receive & Unload $189 $0 $56 $0 $245 $25 $0 $40 $310 $1

1.6 Sorbent Stackout & Reclaim $3,054 $0 $552 $0 $3,606 $361 $0 $595 $4,562 $8

1.7 Sorbent Conveyors $1,090 $ 237 $264 $0 $1,590 $159 $0 $262 $2,011 $4

1.8 Other Sorbent Handling $658 $155 $340 $0 $1,154 $115 $0 $190 $1,459 $3

1.9 Coal & Sorbent Hnd. Foundations $0 $5,469 $7,211 $0 $12,680 $1,268 $0 $2,092 $16,040 $29

Subtotal $22,962 $5,861 $13,572 $0 $42,395 $4,239 $0 $6,995 $53,629 $98

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying $2,728 $0 $524 $0 $3,252 $325 $0 $537 $4,114 $7

2.2 Coal Conveyor to Storage $6,984 $0 $1,504 $0 $8,488 $849 $0 $1,401 $10,737 $20

2.5 Sorbent Prep Equipment $5,199 $225 $1,065 $0 $6,489 $649 $0 $1,071 $8,209 $15

2.6 Sorbent Storage & Feed $626 $0 $237 $0 $863 $86 $0 $142 $1,092 $2

2.9 Coal & Sorbent Feed Foundation $0 $635 $557 $0 $1,191 $119 $0 $197 $1,507 $3

Subtotal $15,538 $860 $3,886 $0 $20,284 $2,028 $0 $3, 347 $25,659 $47

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $21,284 $0 $7,333 $0 $28,618 $2,862 $0 $4,722 $36,201 $66

3.2 Water Makeup & Pretreating $7,468 $0 $2,362 $0 $9,830 $983 $0 $2,163 $12,975 $24

3.3 Other Feedwater Subsystems $7,155 $0 $2,937 $0 $10,092 $1,009 $0 $1,665 $12,766 $23

3.4 Service Water Systems $1,496 $0 $783 $0 $2,278 $228 $0 $501 $3,007 $5

3.5 Other Boiler Plant Systems $8,860 $0 $8,377 $0 $17,236 $1,724 $0 $2,844 $21,804 $40

3.6 FO Supply Sys & Nat Gas $348 $0 $406 $0 $754 $75 $0 $124 $953 $2

3.7 Waste Treatment Equipment $4,899 $0 $2,836 $0 $7,735 $774 $0 $1,702 $10,210 $19

3.8 Misc. Equip. (Cranes, Air Comp.,

Comm.) $3,406 $0 $1,054 $0 $4,460 $446 $0 $981 $5,887 $11

Subtotal $54,915 $0 $26,088 $0 $81,00 2 $8,100 $0 $14,702 $103,805 $189

4 Boiler & Accessories

4.1 PC Boiler & Accessories $178,369 $0 $116,485 $0 $294,854 $29,485 $0 $32,434 $356,773 $649

4.2 SCR w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0

Subtotal $178,369 $0 $116,485 $0 $294,854 $29,485 $0 $32,434 $ 356,773 $649

5A Gas Cleanup & Piping

5A.1 Absorber Vessels & Accessories $81,951 $0 $17,522 $0 $99,473 $9,947 $0 $10,942 $120,362 $219

5A.2 Other FGD $4,277 $0 $4,813 $0 $9,090 $909 $0 $1,000 $10,999 $20Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 111 Case: B11B

– Subcritical PC w/ CO 2 Estimate Type: Conceptual

Plant Size (MW,net): 550 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.3 Bag House & Accessories $23,533 $0 $14,833 $0 $38,366 $3,837 $0 $4,220 $46,423 $84

5A.4 Other Particulate Removal Materials $1,593 $0 $1,693 $0 $3,285 $329 $0 $361 $3,975 $7

5A.5 Gypsum Dewatering System $6,338 $0 $1,069 $0 $7,407 $741 $0 $815 $8,963 $16

5A.6 Mercury Removal System $4,817 $1,06 0 $4,736 $0 $10,613 $1,061 $0 $1,167 $12,842 $23

Subtotal $122,509 $1,060 $44,666 $0 $168,234 $16,823 $0 $18,506 $203,564 $370

5B CO 2 Removal & Compression

5B.1 CO
2 Removal System $172,746 $63,159 $134,933 $0 $370,838 $31,957 $63,914 $83,088 $549,796 $1,000

5B.2 CO
2 Compression & Drying $51,118 $7,668 $16,831 $0 $75,616 $7,562 $0 $16,636 $99,813 $182

Subtotal $223,863 $70,827 $151,763 $0 $446,454 $39,518 $63,914 $99,723 $649,609 $1,182

7 HRSG, Ducting, & Stack

7.3 Ductwork $11,362 $0 $7,172 $0 $1 8,533 $1,853 $0 $3,058 $23,445 $43

7.4 Stack $10,271 $0 $5,969 $0 $16,240 $1,624 $0 $1,786 $19,651 $36

7.9 Duct & Stack Foundations $0 $1,120 $1,329 $0 $2,449 $245 $0 $539 $3,233 $6

Subtotal $21,633 $1,120 $14,470 $0 $37,223 $3,722 $0 $5,383 $46,329 $8 4

8 Steam Turbine Generator

8.1 Steam TG & Accessories $70,000 $0 $8,020 $0 $78,020 $7,802 $0 $8,582 $94,404 $172

8.2 Turbine Plant Auxiliaries $452 $0 $961 $0 $1,412 $141 $0 $155 $1,709 $3

8.3 Condenser & Auxiliaries $7,394 $0 $2,956 $0 $10,350 $1,03 5 $0 $1,138 $12,523 $23

8.4 Steam Piping $30,222 $0 $12,249 $0 $42,471 $4,247 $0 $7,008 $53,725 $98

8.9 TG Foundations $0 $1,346 $2,223 $0 $3,569 $357 $0 $785 $4,712 $9

Subtotal $108,067 $1,346 $26,408 $0 $135,822 $13,582 $0 $17,669 $167,073 $304

9 C ooling Water System

9.1 Cooling Towers $16,119 $0 $4,985 $0 $21,104 $2,110 $0 $2,321 $25,536 $46

9.2 Circulating Water Pumps $3,228 $0 $228 $0 $3,456 $346 $0 $380 $4,181 $8

9.3 Circ. Water System Auxiliaries $839 $0 $111 $0 $950 $95 $0 $104 $1,149 $2

9 .4 Circ. Water Piping $0 $7,067 $6,400 $0 $13,466 $1,347 $0 $2,222 $17,035 $31

9.5 Make

- up Water System $714 $0 $917 $0 $1,631 $163 $0 $269 $2,063 $4

9.6 Component Cooling Water Sys. $684 $0 $525 $0 $1,209 $121 $0 $199 $1,529 $3

9.9 Circ. Water Foundati ons & Structures $0 $3,743 $6,215 $0 $9,958 $996 $0 $2,191 $13,145 $24

Subtotal $21,583 $10,810 $19,381 $0 $51,774 $5,177 $0 $7,687 $64,638 $118

10 Ash & Spent Sorbent Handling Systems

10.6 Ash Storage Silos $902 $0 $2,759 $0 $3,661 $366 $0 $403 $4,43 0 $8

10.7 Ash Transport & Feed Equipment $5,990 $0 $5,938 $0 $11,928 $1,193 $0 $1,312 $14,433 $26

10.9 Ash/Spent Sorbent Foundation $0 $204 $251 $0 $454 $45 $0 $100 $600 $1

Subtotal $6,892 $204 $8,948 $0 $16,044 $1,604 $0 $1,815 $19,463 $35

11 Access ory Electric Plant

11.1 Generator Equipment $2,066 $0 $330 $0 $2,396 $240 $0 $198 $2,833 $5

11.2 Station Service Equipment $5,368 $0 $1,800 $0 $7,168 $717 $0 $591 $8,476 $15

11.3 Switchgear & Motor Control $6,161 $0 $1,070 $0 $7,232 $723 $0 $795 $8,750 $16

11.4 Conduit & Cable Tray $0 $4,225 $13,651 $0 $17,876 $1,788 $0 $2,950 $22,613 $41

11.5 Wire & Cable $0 $8,045 $14,381 $0 $22,426 $2,243 $0 $3,700 $28,369 $52

11.6 Protective Equipment $317 $0 $1,099 $0 $1,416 $142 $0 $156 $1,713 $3Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 112 Case: B11B

– Subcritical PC w/ CO 2 Estimate Type: Conceptual

Plant Size (MW,net): 550 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

11.7 Standby Equipment $1,574 $0 $37 $0 $1,611 $161 $0 $177 $1,949 $4

11.8 Main Power Transformers $12,712 $0 $221 $0 $12,933 $1,293 $0 $1,423 $15,649 $28

11.9 Electrical Foundations $0 $386 $983 $0 $1,369 $137 $0 $301 $1,807 $3

Subtotal $28,198 $12,656 $33,572 $0 $74,426 $7,443 $0 $10,291 $92,160 $168

12 Instrumentation & Control

12.1 PC Control Equipment w/12.7 $0 w/12.7 $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

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $608 $0 $371 $0 $979 $98 $49 $169 $1,295 $2

12.7 Distributed Control Sys. Equipment $6,134 $0 $1,094 $0 $7,228 $723 $361 $831 $9,143 $17

12.8 Instrument Wiring & Tubing $3,699 $0 $6,731 $0 $10,429 $1,04 3 $521 $1,799 $13,793 $25

12.9 Other I & C Equipment $1,733 $0 $4,013 $0 $5,747 $575 $287 $661 $7,270 $13

Subtotal $12,174 $0 $12,209 $0 $24,383 $2,438 $1,219 $3,460 $31,501 $57

13 Improvements to Site

13.1 Site Preparation $0 $62 $1,318 $0 $1,380 $1 38 $0 $304 $1,822 $3

13.2 Site Improvements $0 $2,057 $2,718 $0 $4,775 $478 $0 $1,051 $6,303 $11

13.3 Site Facilities $3,687 $0 $3,868 $0 $7,554 $755 $0 $1,662 $9,972 $18

Subtotal $3,687 $2,119 $7,904 $0 $13,710 $1,371 $0 $3,016 $18,097 $33

14 Buildi ngs & Structures

14.1 Boiler Building $0 $10,735 $9,434 $0 $20,169 $2,017 $0 $3,328 $25,513 $46

14.2 Turbine Building $0 $15,664 $14,589 $0 $30,254 $3,025 $0 $4,992 $38,271 $70

14.3 Administration Building $0 $763 $807 $0 $1,570 $157 $0 $259 $1,986 $4

14.4 Circulation Water Pumphouse $0 $208 $165 $0 $374 $37 $0 $62 $473 $1

14.5 Water Treatment Buildings $0 $931 $849 $0 $1,780 $178 $0 $294 $2,252 $4

14.6 Machine Shop $0 $511 $343 $0 $853 $85 $0 $141 $1,080 $2

14.7 Warehouse $0 $346 $347 $0 $693 $69 $ 0 $114 $877 $2

14.8 Other Buildings & Structures $0 $283 $241 $0 $523 $52 $0 $86 $662 $1

14.9 Waste Treating Building & Str. $0 $541 $1,642 $0 $2,183 $218 $0 $360 $2,762 $5

Subtotal $0 $29,983 $28,416 $0 $58,399 $5,840 $0 $9,636 $73,875 $134

Total $8 20,390 $136,845 $507,769 $0 $1,465,004 $141,373 $65,133 $234,664 $1,906,174 $3,467Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 113 Exhibit 3

- 34 Case B11B owner’s costs

Description $ / 1,000 $/kW

Pre

- Production Costs

6 Months All Labor $11,919 $22

1 M onth Maintenance Materials $1,719 $3

1 Month Non

- fuel Consumables $3,776 $7

1 Month Waste Disposal $561 $1

25% of 1 Months Fuel Cost at 100% CF $3,228 $6

2% of TPC $38,123 $69

Total $59,326 $108

Inventory Capital

60 day supply of fuel and consumable s at 100% CF $32,759 $60

0.5% of TPC (spare parts) $9,531 $17

Total $42,289 $77

Other Costs

Initial Cost for Catalyst and Chemicals $0 $0

Land $900 $2

Other Owner's Costs $285,926 $520

Financing Costs $51,467 $94

Total Overnight Costs (TOC) $2,346, 083 $4,267

TASC Multiplier (IOU, high

- risk, 35 year) 1.140

Total As

- Spent Cost (TASC) $2,674,534 $4,865Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 114 Exhibit 3

- 35 Case B11B initial and annual operating and maintenance costs

Case: B11B

– Subcrit ical PC w/o CO 2 Cost Base: Jun 2011

Plant Size (MW,net): 550 Heat Rate

- net (Btu/kWh): 10,953 Capacity Factor (%): 8 5

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: 11.3

Labor O

- H Charge Rate: 25.00 % of labor Foreman: 1.0

Lab Tech's, etc.: 2.0

Total: 16.3

Fixed Operating Costs

Annual Cost

($) ($/kW

- net)

Annual Operating Labo r: $7,384,208 $13.431

Maintenance Labor: $11,686,525 $21.257

Administrative & Support Labor: $4,767,683 $8.672

Property Taxes and Insurance: $38,123,487 $69.343

Total: $61,961,903 $112.703

Variable Operating Costs

($) ($/M Wh

- net)

Maintenance Material: $17,529,787 $4.28219

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 6,077 $1.67 $0 $3,156,296 $0.77102

Makeup and Waste Water

Treatment Chemicals (lbs): 0 29,4 18 $0.27 $0 $2,444,559 $0.59716

Limestone (ton) 0 612 $33.48 $0 $6,357,560 $1.55303

Hydrated Lime (ton) 0 125 $155.00 $0 $6,002,945 $1.46640

Activated Carbon (ton) 0 4 $1,255.00 $0 $1,403,736 $0.34291

CO 2 Capture System Chemicals A Proprietary

Trieth ylene Glycol (gal) 0 407 $6.57 $0 $829,372 $0.20260

Ammonia (19% NH 3 , ton) 0 92 $330.00 $0 $9,376,827 $2.29058

SCR Catalyst (m 3 ) 0 0.41 $8,938.80 $0 $1,138,354 $0.27808

Subtotal: $0 $38,511,747 $9.40767

Waste Disposal

Fly Ash (ton) 0 614 $25.11 $0 $4,781,508 $1.16803

Bottom Ash (ton) 0 121 $25.11 $0 $940,569 $0.22976

Amine Purification Unit Waste (ton) 0 21 $0.00 $0 $0 $0.00000

Thermal Reclaimer Unit Waste (ton) 0 2 $0.00 $0 $0 $0.00000

Prescrubber Blowdown Waste (ton) 0 46 $0.00 $0 $0 $0.00000

Subtotal: $0 $5,722,077 $1.39779

By

- Products

Gypsum (ton) 0 106 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000

Variable Operating Costs Total: $0 $61,763,611 $15.08765

Fuel Cost

Illinois Number 6 (ton): 0 6,194 $68.54 $0 $131,713,383 $32.17501

Total: $0 $131,713,383 $32.17501

A 

### CO 2 

### Capture System Chemicals includes Ion Exchange Resin, NaOH, and Cansolv Solvent.

Exhibit 3

- 36 Case B 11B COE breakdown

Component Value, $/MWh Percentage

Capital 71.1 50%

Fixed 15.1 11%

Variable 15.1 11%

Fuel 32.2 22%

Total (Excluding T&S) 133.5 N/A

CO 2 

### T&S 10.0 7%

Total (Including T&S) 143.5 N/ACost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 115 

# 3.3 Supercritical PC cases

This section contains an evaluation of plant designs for Cases B12A and B12B, whic h are based

on a SC PC plant with a nominal net output of 550 MWe. Both plants use a single reheat 24.1

MPa/593°C/593°C (3,500 psig/1,100 ° F/1,100 ° F) cycle. The only difference between the two

plants is that Case B12B includes CO 2 

## capture while Case B12A does not.

The balance of this section is organized in an analogous manner to the subcritical PC section:

• Process and System Description for Case B12A

• Key Assumptions for Cases B12A and B12B

• Sparing Philosophy for Cases B12A and B12B

• Performance Results for Case B12A

• Equipment List for Case B12A

• Cost Estimates for Case B12A

• Process and System Description, Performance Results, Equipment List and Cost

Estimates for Case B12B



## 3.3.1 Process Description

In this section the SC PC process without CO 2 

## capture is described . The system description is

nearly identical to the subcritical PC case without CO 2 

## capture but is repeated here for

completeness. The description follows the BFD in Exhibit 3

- 37 and stream numbers reference

the same Exhibit. The tables in Exhibit 3

- 38 provide process data for the numbered streams in

the BFD.

Coal (stream 8) and PA (stream 4) are introduced into the boiler through the wall

- fired burners.

Additional combu stion air, including the OFA, is provided by the FD fans (stream 1). The boiler

operates at a slight negative pressure so air leakage is into the boiler, and the infiltration air is

accounted for in stream 7. Streams 3 and 6 show Ljungstrom air preheater leakages from the FD

and PA fan outlet streams to the boiler exhaust.

Flue gas exits the boiler through the SCR reactor where hydrated lime is injected (stream 10) for

the reduction of SO 3 

## . It then passes through the combustion air preheater (where the a ir

preheater leakages are introduced) and is cooled to 143°C (289°F) (stream 11) before PAC is

injected (stream 12) for mercury reduction. The flue gas then passes through a fabric filter for

particulate removal (stream 15). An ID fan increases the flue gas temperature to 153°C (308°F)

and provides the motive force for the flue gas (stream 16) to pass through the FGD unit. FGD

inputs and outputs include makeup water (stream 18), oxidation air (stream 19), limestone slurry

(stream 17) and product gypsum ( stream 20). The clean, saturated flue gas exiting the FGD unit

(stream 21) passes to the plant stack and is discharged to the atmosphere.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 116 Exhibit 3

- 37 Case B12A block flow diagram , su perc ritical unit witho ut CO 2 

### c apture

Source: NETL P ULVERIZED

C OAL

B OILER SCR B AGHOUSE FGD

G YPSUM L IMESTONE

S LURRY O XIDATION

A IR M AKEUP

W ATER

B OTTOM A SH C OAL F EED I NFILTRATION

AIR

1

4

8 7

9 14

F LY A SH 15 16 18 19

17 20 21

HP

TURBINE 22

23 24

IP

TURBINE LP TURBINE

CONDENSER

26 FEEDWATER

HEATER

SYSTEM

Note : Block Flow Diagram is not intended to

represent a complete material balance

. Only

major process streams and equipment are

shown

. 3 2

6

5 11

25 10

H YDRATED

L IME 12

13 A CTIVATED

C ARBON S TACK GAS

FD F ANS

PA F ANS ID F AN

B OILER

F EEDWATERCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 117 Exhibit 3

- 38 Case B12A stream table , su per critical unit without c apture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V

- L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.00 92 0.0092 0.0092 0.0000 0.0000 0.0000 0.0088 0.0000 0.0088 0.0000

CO 2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.0000 0.1376 0.0000 0.1376 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 0.0000 0.0000 0.0000

H 2 O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0000 0.0831 0.0000 0.0831 0.0000

N 2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.0000 0.7345 0.0000 0.7345 0.0000

O 2 0.2074 0.2074 0.2074 0.2074 0.20 74 0.2074 0.2074 0.0000 0.0000 0.0000 0.0340 0.0000 0.0340 0.3333

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0020 0.0000 0.0020 0.6667

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 0.0000 1.0000 0.0 000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 49,410 49,410 1,463 15,178 15,178 2,089 1,079 0 0 0 69,258 0 69,258 3

V

- L Flowrate (kg/hr) 1,425,833 1,425,833 42,230 438,001 438,001 60,280 31,143 0 0 0 2,056,795 0 2,056,795 158

Solids Flowrat e (kg/hr) 0 0 0 0 0 0 0 179,193 3,475 3,611 17,512 104 17,616 17,616

Temperature (°C) 15 19 19 15 25 25 15 15 149 27 143 27 143 143

Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10

Steam Table Ent halpy (kJ/kg) A 30.23 34.36 34.36 30.23 40.78 40.78 30.23

--- --- 0.00 0.00 0.00

--- --- AspenPlus Enthalpy (kJ/kg) B

- 97.58

- 93.45

- 93.45

- 97.58

- 87.03

- 87.03

- 97.58

- 2,114.05 97.18

- 13,306.82

- 2,399.46 3.40

- 2,399.34

- 2,632.07

Density (kg/m 3 ) 1.2 1.2 1. 2 1.2 1.3 1.3 1.2

--- --- --- 0.9

--- 0.9 1.5

V

- L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857

--- --- --- 29.698

--- 29.698 53.376

V

- L Flowrate (lb mole /hr) 108,931 108,931 3,226 33,463 33,463 4,605 2,379 0 0 0 152,68 7 0 152,687 7

V

- L Flowrate (lb/hr) 3,143,424 3,143,424 93,102 965,627 965,627 132,896 68,659 0 0 0 4,534,456 0 4,534,456 347

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 395,053 7,661 7,962 38,608 230 38,838 38,838

Temperature (°F) 59 66 66 59 78 78 59 59 300 80 289 80 289 289

Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.4 14.7 14.4 14.7 14.4 14.4

Steam Table Enthalpy (Btu/lb) A 13.0 14.8 14.8 13.0 17.5 17.5 13.0

--- --- --- --- AspenPlus Enthalpy (Btu/lb) B

- 42.0

- 40.2

- 40.2

- 42.0

- 37.4

- 37.4

- 42.0

- 908.9 41.8

- 5,720.9

- 1,031.6 1.5

- 1,031.5

- 1,131.6

Density (lb/ft 3 ) 0.076 0.078 0.078 0.076 0.081 0.081 0.076

--- --- --- 0.053

--- 0.053 0.096

A 

### Steam table reference conditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic refere nce 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: Revision 3



## 118 Exhibit 3

- 38 Case B12A stream table , su per critical unit without c apture ( c ontinued)

15 16 17 18 19 20 21 22 23 24 25 26

V

- L Mole Fract ion

Ar 0.0088 0.0088 0.0000 0.0000 0.0092 0.0000 0.0082 0.0000 0.0000 0.0000 0.0000 0.0000

CO 2 0.1376 0.1376 0.0000 0.0000 0.0003 0.0001 0.1288 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 0.0 000 0.0000 0.0000 0.0000

H 2 O 0.0831 0.0831 1.0000 1.0000 0.0099 0.9999 0.1451 1.0000 1.0000 1.0000 1.0000 1.0000

N 2 0.7345 0.7345 0.0000 0.0000 0.7732 0.0000 0.6854 0.0000 0.0000 0.0000 0.0000 0.0000

O 2 0.0340 0.0340 0.0000 0.0000 0.2074 0.0000 0.0325 0 .0000 0.0000 0.0000 0.0000 0.0000

SO 2 0.0020 0.0020 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 69 ,255 69,255 2,296 9,201 732 169 75,048 88,629 74,095 74,095 66,938 67,115

V

- L Flowrate (kg/hr) 2,056,637 2,056,637 41,356 165,764 21,135 3,052 2,165,283 1,596,685 1,334,839 1,334,839 1,205,905 1,209,098

Solids Flowrate (kg/hr) 0 0 17,707 0 0 27,462 0 0 0 0 0 0

Temperature (°C) 143 153 15 27 167 56 56 593 342 593 38 39

Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.31 0.10 0.10 24.23 4.90 4.80 0.01 1.80

Steam Table Enthalpy (kJ/kg) A 274.35 285.60

--- 111.65 184.48

--- 286.10 3,477.96 3,049.83 3,652.36 1,978.90 163.04

AspenPlus Enthalpy (kJ/kg) B

- 2,397.32

- 2,386.08

- 14,995.75

- 15,964.53 56.67

- 12,481.91

- 2,940.27

- 12,502.33

- 12,930.47

- 12,327.94

- 14,001.40

- 15,817.25

Density (kg/m 3 ) 0.8 0.9 1,003.6 992.3 2.4 833.1 1.1 69.2 19.2 12.3 0.1 993.5

V

- L Molecular Weight 29.697 29.697 18.015 18.015 28.857 18.018 28.852 18.015 18.015 18.015 18.015 18.015

V

- L Flowrate (lb mole /hr) 152,680 152,680 5,061 20,285 1,615 373 165,452 195,395 163,351 163,351 147,573 147,964

V

- L Flowrate (lb/hr) 4 ,534,108 4,534,108 91,174 365,446 46,596 6,729 4,773,632 3,520,088 2,942,815 2,942,815 2,658,565 2,665,605

Solids Flowrate (lb/hr) 0 0 39,037 0 0 60,544 0 0 0 0 0 0

Temperature (°F) 289 308 59 80 332 133 133 1,100 648 1,100 101 101

Pressur e (psia) 14.2 15.2 15.0 15.7 45.0 14.7 14.7 3,514.7 710.8 696.6 1.0 261.6

Steam Table Enthalpy (Btu/lb) A 118.0 122.8

--- 48.0 79.3

--- 123.0 1,495.3 1,311.2 1,570.2 850.8 70.1

AspenPlus Enthalpy (Btu/lb) B

- 1,030.7

- 1,025.8

- 6,447.0

- 6,863.5 24.4

- 5,366.3

- 1,264.1

- 5,375.0

- 5,559.1

- 5,300.1

- 6,019.5

- 6,800.2

Density (lb/ft 3 ) 0.052 0.055 62.650 61.950 0.153 52.011 0.067 4.319 1.197 0.768 0.004 62.022

A 

### Steam table reference conditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic reference state is the com ponent’s constituent elements in an ideal gas state at 25°C and 1 atmCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 119 

## 3.3.2 Key System Assumptions

System assumptions for Cases B12A and B12B

, SC PC with and without CO 2 

## capture, are

compiled in Exhibit 3

- 39

.

Exhibit 3

- 39 Supercritical PC plant study configuration matrix

Case B12A

w/o CO 2 

### Capture Case B12B

w/CO 2 

### Capture

Steam Cycle, MPa/°C/°C (psig/°F/°F) 24.1/593/593

(3

, 500/1

, 100/1

, 100) 24.1/593/593

(3

, 500/1

, 100/1

, 100)

Coal Illi nois No. 6 Illinois No. 6

Condenser pressure, mm Hg (in Hg) 50.8 (2) 50.8 (2)

Boiler Efficiency, HHV % 8 9 8 9

Cooling water to condenser, °C (oF) 16 (60) 16 (60)

Cooling water from condenser, °C (oF) 27 (80) 27 (80)

Stack temperature, °C (°F) 5 6 (13 3 ) 4 2 ( 107 )

SO 2 

### Control Wet Limestone Forced

Oxidation Wet Limestone

Forced Oxidation

FGD Efficiency, % (A) 98 98 (B, C)

NOx Control LNB w/OFA, SCR , and

Polishing Scrubber LNB w/OFA, SCR , and

Polishing Scrubber

SCR Efficiency, % (A) 8 3 8 5

Ammonia Slip ( end of catalyst life), ppmv 2 2

Particulate Control Fabric Filter Fabric Filter

Fabric Filter efficiency, % (A) 99. 9 99. 9

Ash Distribution, Fly/Bottom 80% / 20% 80% / 20%

SO 3 

### Control DSI DSI

Mercury Control Co

- benefit Capture and

ACI Co

- benefit Captur e and

ACI

CO 2 

### Control N/A Cansolv

Overall Carbon Capture (A) N/A 90%

CO 2 

### Sequestration N/A Off

- site Saline

Formation

A 

### Removal efficiencies are based on the flue gas content

B 

### An SO 2 

### polishing step is included to meet more stringent SOx content limits in the flue gas ( ~1

ppmv) to reduce formation of amine HSS during the CO 2 

### absorption process

C 

### SO 2 

### exiting the post

- FGD polishing step is absorbed in the CO 2 

### capture process making stack

emissions negligible



## 3.3.2.1 Balance of Plant

– Cases B12A and B12B

The balance of plant assumptions are common to all cases and were presented previously in

Exhibit 3

- 8

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 120 

## 3.3.3 Sparing Philosophy

Single trains are used throughout the design with exceptions where equipment capacity requires

an additional train. T here is no redundancy other than normal sparing of rotating equipment.

The plant design consists of the following major subsystems:

• One dry

- bottom, wall

- fired PC SC boiler (1 x 100%)

• Two SCR reactors (2 x 50%)

• One DSI system (1 x 100%)

• One ACI system (1 x 100%)

• Two single

- stage, in

- line, multi

- compartment fabric filters (2 x 50%)

• One wet limestone forced oxidation positive pressure absorber (1 x 100%)

• One steam turbine (1 x 100%)

• For Case B12B only, one CO 2 

## absorption system , consisting of an absorber, str ipper, and

ancillary equipment (1 x 100%) and two CO 2 

## compression systems (2 x 50%)



## 3.3.4 Case B1 2 A Performance Results

The plant produces a net output of 550 MWe at a net plant efficiency of 40.7 percent (HHV

basis). Overall performance for the plant is summari zed in Exhibit 3

- 40 ; Exhibit 3

- 41 provides a

detailed breakdown of the auxiliary power requirements.

Exhibit 3

- 40 Case B1 2A plant performance summary

Performance Summary

Total Gross Power, MWe 580

CO
2 Capture/Removal Auxiliaries, kWe 0

CO
2 Compression, kWe 0

Balance of Plant, kWe 29,68 8

Total Auxiliaries, MWe 30

Net Power, MWe 550

HHV Net Plant Efficiency (%) 40.7%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,841 (8,379)

LHV Net Plant Efficiency (%) 42.2%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,527 (8,082)

HHV Boiler Efficiency, % 89.1%

LHV Boiler Efficiency, % 92.4%

Steam Turbine Cycle Efficiency, % 48.2%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 7,473 (7,083)

Condenser Duty, GJ/hr ( MM Btu/hr) 2,192 (2,078)

As

- Received Coal Feed, kg/hr (lb/hr) 179,193 (395,053)

Limestone Sorbent Feed, kg/hr (lb/hr) 17,707 (39,037)

HHV Thermal Input, kWt 1,350,672

LHV Thermal Input, kWt 1,302,740

Raw Water Withdrawal, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.035 (9.3)

Raw Water Consumption, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.028 (7.4)

Excess Air, % 20.9%Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 121 Exhibit 3

- 41 Case B12A plant power summary

Power Summary

Steam Turbine Power, MWe 580

Total Gross Power, MWe 580

Auxiliary Load Summary

Coal Handling and Conveying, kWe 430

Pulverizers, kWe 2,690

Sorbent Handling & Reagent Preparation, kWe 850

Ash Handling, kWe 620

Primary Air Fans, kWe 1,330

Forced Draft Fans, kWe 1,700

Induced Draft Fans, kWe 6,660

SCR , kWe 40

Activated Carbon Injection, kWe 22

Dry sorbent Injection, kWe 86

Baghouse, kWe 90

Wet FGD, kWe 2,830

CO
2 Capture/Removal Auxiliaries, kWe 0

CO
2 Compression, kWe 0

Miscellaneous Balance of Plant A,B 

### , kWe 2,000

Steam Turbine Auxiliaries, kWe 400

Condensate Pumps, kWe 800

Circulating Water Pumps, kWe 4,520

Ground Water Pumps, kWe 460

Cooling Tower Fans, kWe 2,340

Transformer Losses, kWe 1,820

Total Auxiliaries, MWe 30

Net Power, MWe 550

A 

### Boiler feed pumps are turbine driven

B 

### Include s plant control systems, lighting, HVAC, and miscellaneous low voltage loads



## 3.3.4.1 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 B12A is pre sented in Exhibit 3

- 42

.

Exhibit 3

- 42 Case B12A air emissions

kg/GJ (lb/ MM Btu) Tonne/year (ton/year) A 

### kg/MWh (lb/MWh)

SO
2 0.036 (0.085) 1,317 (1,452) 0.305 (0.673 )

NOx 0.038 (0.088) 1,371 (1,511) 0.318 (0.700)

Particulate 0.005 (0.011) 176 (194) 0.041 (0.090)

Hg 1.62E

- 7 (3.77E

- 7) 0.006 (0.006) 1.36E

- 6 (3.00E

- 6)

CO
2 B 

### 87 (204) 3,167,890 (3,492,001) 734 (1,618)

CO
2 C



### - - 774 (1,705)

mg/Nm 3



### Particulate Concentra tion D

, E 

### 15.25

A 

### Calculations based on an 85 percent capacity factor

B 

### CO 2 

### emissions based on gross power

C 

### CO 2 

### emissions based on net power instead of gross power

D 

### Concentration of particles in the flue gas after the baghouse

E 

### Normal conditions given at 32°F and 14.696 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 122 SO 2 

## emissions are controlled using a wet limestone forced oxidation scrubber that achieves a

removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site.

The wallboard grade material can potentially be marketed and sold, but since it is highly

dependent on local market conditions, no byproduct credit was taken. The saturated flue gas

exiting the scrubber is vented through the plant stack.

NOx emissions are controlled to about 0.5 lb/ MM Btu through the u se of LNBs and OFA. An

SCR unit then further reduces the NOx concentration by 8 3 percent to 0.0 9 lb/ MM Btu.

Particulate emissions are controlled using a pulse jet fabric filter, which operates at an efficiency

of 99. 9 percent.

The total reduction in mercur y emission via the combined control equipment (SCR, ACI, fabric

filter, DSI, and wet FGD) is 96.7 percent.

CO 2 

## emissions represent the uncontrolled discharge from the process.

The carbon balance for the plant is shown in Exhibit 3

- 43

. The carbon input to the plant consists

of carbon in the coal , carbon in the air

, PAC, and carbon in the limestone reagent used in the

FGD. Carbon in the air is not neglected here since the Aspen model accounts for air components

throu ghout. Carbon leaves the plant mostly as CO 2 

## through the stack , however, the PAC is

captured in the fabric filter and some leaves as gypsum.

Exhibit 3

- 43 Case B12A carbon balance

Carbon In Carbon Out

kg /hr (lb/hr) kg/hr (lb/hr)

Coal 114,226 (251,825) Stack Gas 116,112 (255,983)

Air (CO
2 ) 261 (574) FGD Product 171 (378)

PAC 104 (230) Baghouse 104 (230)

FGD Reagent 1,797 (3,961) CO
2 Product 0

CO
2 Dryer Vent 0

CO
2 Knockout 0

Total 116,388 (256,591) Total 116,388 (256,591)



## Exhibit 3

- 44 shows the sulfur ba lance for the plant. Sulfur input comes solely from the sulfur in

the coal. Sulfur output includes the sulfur recovered from the FGD as gypsum , sulfur captured in

the fabric filter via hydrated lime, and sulfur emitted in the stack gas.

Exhibit 3

- 44 Case B12A sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 4,491 (9,902) FGD Product 4,340 (9,567)

Stack Gas 89 (195)

Polishing Scrubber and Solvent Reclaiming 0

Baghouse 63 (13 9)

Total 4,491 (9,902) Total 4,491 (9,902)



## Exhibit 3

- 45 s hows the overall water balance for the plant.

Water demand represents the total amount of water required for a particular process. Some water

is recover ed within the process and is re

- used as internal recycle. The difference between

demand and recycle is raw water withdrawal. Raw water withdrawal is defined as the waterCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 123 removed from the ground or diverted from a POTW 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 FGD makeup, BFW makeup, and coolin g tower makeup. The

difference between water withdrawal and process water discharge is defined as water

consumption and can be represented by the portion of the raw water withdrawn that is

evaporated, transpired, incorporated into products or otherwise no t returned to the water source

from which it was withdrawn. Water consumption represents the net impact of the plant process

on the water source balance.

Exhibit 3

- 45 Case B12A water balance

Water Use Wate r

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)

FGD Makeup 3.46 (913)

– 3.46 (913)

– 3.46 (913)

CO
2 Drying

– – – – – Capture System

Makeup – – – – –

Deaerator Vent

– – – 0.05 (14)

- 0.05 (

- 14)

Condenser Makeup 0.05 (14)

– 0.05 (14)

– 0.05 (14)

BFW Makeup 0.05 (14)

– 0.05 (14)

– 0.05 (14)

Cooling Tower 17.59

(4,648) 1.78

(471) 15.81 (4,177) 3.96 ( 1,045) 11.86 (3,132)

FGD Dewatering

– 1.78

(471) - 1.78 (

- 471)

– - 1.78 (

- 471)

CO
2 Capture

Recovery – – – – –

CO
2 Compression KO

– – – – –
BFW Blowdown

– – – – –

Total 21.11

(5,575) 1.78

(471) 19.32 (5,105) 4.01 (1,059) 15.31 (4,045)



## 3.3.4.2 Heat and M ass Balance Diagrams

A heat and mass balance diagram is shown for the Case B12A PC boiler, the FGD unit and

steam cycle in Exhibit 3

- 46 and Exhibit 3

- 47

.

An overall plant energy balance is provided in t abular form in Exhibit 3

- 48 . The power out is

the steam turbine power prior to generator losses. The power at the generator terminals (shown

in Exhibit 3

- 40 ) is calculated by multiplying the power out b y a generator efficiency of 98.5

percent.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 124 Exhibit 3

- 46 Case B12A heat and mass balance, supercritical PC boiler without CO 2 

### capture

Source: NETL Notes :

1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psia

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Air

Coal / Ash

Slurry

Water Steam

P AGES

1 OF 2 B ITUMINOUS B ASELINE S TUDY

C ASE B 12 A

S UBCRITICAL P ULVERIZED C OAL

B OILER AND G AS C LEANUP S YSTEMS

DWG

. NO

. BB

- HMB

- CS

- B 12 A

- PG

- 1 Pulverized

Coal

Boiler SCR Ammonia

Infiltration Air

Air

Air

Coal

Bottom Ash FGD

Fly Ash

Forced

Draft Fans

Primary

Air Fans

395

, 053 W

59 T

15 P 78 T

16 P

18 H 66 T

15 P

15 H 3

, 520

, 088 W

1

, 100 T

3

, 515 P

1

, 495 H

2

, 942

, 815 W

1

, 100 T

697 P

1

, 570 H

965

, 627 W

59 T

15 P

13 H 3

, 143

, 424 W

59 T

15 P

13 H 68

, 659 W

59 T

15 P

13 H 4

, 573

, 064 W

289 T

14 P

117 H

7

, 661 W

300 T

14 P 39

, 185 W

289 T

14 P

2

, 942

, 815 W

648 T

711 P

1

, 311 H

3

, 520

, 088 W

500 T

3

, 845 P

488 H 5 4

, 773

, 632 W

133 T

15 P

123 H

1 2

4 7

9 ID Fans 4

, 534

, 108 W

289 T

14 P

118 H

Gross Plant Power : 580 MWe

Auxiliary Load : 30 MWe

Net Plant Power : 550 MWe

Net Plant Efficiency

, HHV : 40

. 7 %

Net Plant Heat Rate : 8

, 379 Btu / kWh Lime /

Limestone /

Gypsum

Flue Gas Oxidation

Air Make

- Up

Water

Limestone

Slurry Gypsum

18

17 14 4

, 534

, 108 W

308 T

15 P

123 H

130

, 211 W

59 T

15 P

423 H 46

, 596 W

332 T

45 P

79 H 365

, 446 W

80 T

16 P

48 H

67

, 273 W

133 T

15 P

1

, 499 H Baghouse

3

6

8 15 16 19

21

22

23 24

DOE / NETL

SC PC P LANT

C ASE B 12 A Hydrated

Lime 11

Single Reheat

Extraction from

HP Turbine

From Feedwater

Heaters Single Reheat

To IP Turbine Throttle Steam

To HP Turbine 7

, 962 W

80 T

15 P 10 Activated

Carbon

12

Activated

Carbon 13

230 W

80 T

15 P

Stack W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical 4

, 573

, 293 W

289 T

14 P

117 H

20

AmmoniaCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 125 Exhibit 3

- 47 Case B12A heat and mass balance, supercritical steam cycle

Source: NETL H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Water Steam

P AGES

2 OF 2 DWG

. NO

. BB

- HMB

- CS

- B 12 A

- PG

- 2

B ITUMINOUS B ASELINE S TUDY

C ASE B 12 A

S UBCRITICAL P ULVERIZED C OAL

P OWER B LOCK S YSTEMS LP Turbine Generator HP

Turbine IP

Turbine

Condenser

Hot Well Boiler Feed Pump

Turbine Drives Throttle

Steam

Condensate

Pumps 3

, 520

, 088 W

1

, 100 T

3

, 515 P

1

, 495 H

163

, 399 W

861 T

298 P

1

, 453 H 317

, 057 W

645 T

682 P

1

, 311 H 2

, 942

, 815 W

648 T

711 P

1

, 311 H 218

, 567 W

653 T

135 P

1

, 353 H

218

, 567 W

126 T

2 P

1

, 083 H 1

, 968

, 852 W

101 T

1 P

1

, 010 H

2

, 665

, 605 W

101 T

1 P

69 H

2

, 665

, 605 W

101 T

262 P

70 H 2

, 665

, 605 W

141 T

251 P

110 H

471

, 146 W

111 T

1 P

79 H 380

, 391 W

151 T

4 P

119 H 2

, 665

, 605 W

298 T

222 P

268 H

740

, 671 W

369 T

170 P

341 H 2

, 665

, 605 W

219 T

231 P

187 H

577

, 272 W

429 T

339 P

406 H 3

, 520

, 088 W

419 T

4

, 005 P

399 H

Deaerator

Boiler Feed

Water Pumps 3

, 520

, 088 W

555 T

3

, 691 P

551 H 2

, 942

, 815 W

1

, 100 T

697 P

1

, 570 H

196

, 118 W

229 T

20 P

197 H 294

, 039 W

188 T

9 P

156 H 2

, 665

, 605 W

178 T

241 P

146 H 120

, 852 W

652 T

132 P

1

, 353 H 196

, 118

W

519 T

70 P

1

, 291 H 97

, 921 W

281 T

18 P

1

, 183 H 86

, 352 W

183 T

8 P

1

, 128 H 90

, 754 W

146 T

3 P

1

, 077 H 2

, 658

, 565 W

653 T

135 P

1

, 353 H 2

, 439

, 998 W

653 T

135 P

1

, 353 H

4

, 172 P

3

, 520

, 088 W

349 T

132 P

320 H Gross Plant Power : 580 MWe

Auxiliary Load : 30 MWe

Net Plant Power : 550 MWe

Net Plant Efficiency

, HHV : 40

. 7 %

Net Plant Heat Rate : 8

, 379 Btu / kWh FWH 1 FWH 2 FWH 3 FWH 4 FWH 5 FWH 6 22

26

DOE / NETL

SC PC P LANT

C ASE B 12 A 24

23 7

, 040 W

59 T

15 P

27 H

Vent Notes :

1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psia Single Reheat

Extraction

From Boiler

Single Reheat

Extraction to

Boiler

To Boiler Steam Turbine

Makeup

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical 25

260

, 215 W

757 T

1

, 071 P

1

, 358 H

260

, 215 W

510 T

746 P

500 H 3

, 520

, 088 W

500 T

3

, 845 P

488 H FWH 7Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 126 Exhibit 3

- 48 Case B12A overall energy balance (0°C [32°F] reference)

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr )

Coal 4,862 (4,609) 4.1 (3.9)

– 4,866 (4,613)

Air

– 57.3 (54.3)

– 57.3 (54.3)

Raw Water Makeup

– 72.7 (68.9)

– 72.7 (68.9)

Limestone

– 0.38 (0.36)

– 0.38 (0.36)

Auxiliary Power

– – 107 (101) 107 (101)

TOTAL 4,862 (4,609) 134.4 (127.4) 107 (101) 5,10 4 (4,837)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash

– 0.4 (0.3)

– 0.4 (0.3)

Fly Ash + FGD Ash

– 2.0 (1.9)

– 2.0 (1.9)

Stack Gas

– 619 (587)

– 619 (587)

Sulfur

– – – – Motor Losses and Design

Allowances – – 34 (32) 34 (32)

Condenser

– 2,192 (2,078)

– 2,19 2 (2,078)

Non

- Condenser Cooling

Tower Loads – 106 (100)

– 106 (100)

CO
2 – 0.0 (0.0)

– 0.0 (0.0)

Cooling Tower Blowdown

– 29.4 (27.9)

– 29.4 (27.9)

CO
2 Capture Losses

– – – –
Ambient Losses A



### – 104.7 (99.2)

– 104.7 (99.2)

Power

– – 2,087 (1,978) 2,087 (1,978)

TOTAL

– 3,054 (2,894) 2,121 (2,010) 5,175 (4,905)

Unaccounted Energy B



### – - 71 (

- 67)

– - 71 (

- 67)

A 

### Ambient losses include all losses to the environment through radiation, convection, etc. Sources of these

losses include the boiler, reheater, superhe ater, and transformers.

B 

### By difference



## 3.3.5 Case B12A

– Major Equipment List

Major equipment items for the SC PC plant 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 3.3.6 . In general, the design conditions include a 10 percent

contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 127 Case B12A

– Account 1: Coal and Sorbent Handling

Equipmen

t No. Description Type Design Condition Operating

Qty. Spares

1 Bottom Trestle Dumper and

Receiving Hoppers N/A 180 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 Tr ansfer Tower No. 1 Enclosed N/A 1 0

5 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

6 As

- Received Coal Sampling System Two

- stage N/A 1 0

7 Stacker/Reclaimer Traveling,

linear 1,130 tonne/hr (1,250 tph) 1 0

8 Reclaim Hopper N/A 40 tonne (40 ton) 2 1

9 Feeder Vibratory 150 tonne/hr (160 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 300 tonne/hr (330 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 150 tonne (160 ton) 2 0

13 Crusher Impactor

reduction 8 cm x 0

- 3 c m x 0

(3 in x 0

- 1

- 1/4 in x 0) 2 0

14 As

- Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 300 tonne/hr (330 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 300 tonne/hr (330 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide

Gates Field erected 660 tonne (700 ton) 3 0

19 Activated Carbon Storage Silo and

Feeder System Shop

assembled Silo

- 28 tonne (30 ton)

Feeder

- 110 kg/hr

(250 lb/hr) 1 0

20 Hydrated Lime Storage Silo and

Feeder Sys tem Shop

assembled Silo

- 190 tonne (210 ton)

Feeder

- 3,970 kg/hr

(8,760 lb/hr) 1 0

21 Limestone Truck Unloading Hopper N/A 30 tonne (40 ton) 1 0

22 Limestone Feeder Belt 70 tonne/hr (80 tph) 1 0

23 Limestone Conveyor No. L1 Belt 70 tonne/hr (80 tph) 1 0

24 Limestone Reclaim Hopper N/A 10 tonne (20 ton) 1 0

25 Limestone Reclaim Feeder Belt 60 tonne/hr (60 tph) 1 0

26 Limestone Conveyor No. L2 Belt 60 tonne/hr (60 tph) 1 0

27 Limestone Day Bin w/ actuator 230 tonne (260 ton) 2 0



## Case B1 2 A

– Account 2: Coal and Sorbent Preparation and Feed

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Coal Feeder Gravimetric 30 tonne/hr (40 tph) 6 0

2 Coal Pulverizer Ball type or

equivalent 30 tonne/hr (40 tph) 6 0

3 Limestone Weigh Feeder Gravimetric 19 tonne/hr (21 tph) 1 1

4 Limestone Ball Mill Rotary 19 tonne/hr (21 tph) 1 1

5 Limestone Mill Slurry Tank

with Agitator N/A 75,000 liters (20,000 gal) 1 1

6 Limestone Mill Recycle

Pumps Horizontal centrifugal 1,240 lpm @ 10m H

2 O

(330 gpm @ 40 ft H

2 O) 1 1

7 Hydroclone Classifier 4 active cyclones in a

5 cyclone bank 310 lpm (80 gpm)

per cyclone 1 1

8 Distribution Box 2

- way N/A 1 1

9 Limestone Slurry Storage

Tank with Agitator Field erected 421,000 liters

(111,000 gal) 1 1

10 Limestone Slurry Feed Pumps Horizontal centrifugal 880 lpm @ 9m H

2 O

(230 gpm @ 30 ft H

2 O) 1 1Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 128 Case B1 2 A

– Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Deminerali zed Water

Storage Tank Vertical, cylindrical,

outdoor 211,000 liters (56,000 gal) 2 0

2 Condensate Pumps Vertical canned 22,300 lpm @ 200 m H

2 O

(5,900 gpm @ 700 ft H

2 O) 1 1

3 Deaerator and Storage

Tank Horizontal spray type 1,760,000 kg/hr

(3,880,000 l b/hr),

5 min. tank 1 0

4 Boiler Feed

Pump/Turbine Barrel type, multi

- stage,

centrifugal 29,500 lpm @ 3,400 m H

2 O

(7,800 gpm @ 11,300 ft

H 2 O) 1 1

5 Startup Boiler Feed

Pump, Electric Motor

Driven Barrel type, multi

- stage,

centrifugal 8,800 lpm @ 3,400 m H 2 O

(2,300 gpm @ 11,300 ft

H 2 O) 1 0

6 LP Feedwater Heater

1A/1B Horizontal U

- tube 670,000 kg/hr

(1,470,000 lb/hr) 2 0

7 LP Feedwater Heater

2A/2B Horizontal U

- tube 670,000 kg/hr

(1,470,000 lb/hr) 2 0

8 LP Feedwater Heater

3A/3B Horizontal U

- tube 670 ,000 kg/hr

(1,470,000 lb/hr) 2 0

9 LP Feedwater Heater

4A/4B Horizontal U

- tube 670,000 kg/hr

(1,470,000 lb/hr) 2 0

10 HP Feedwater Heater 6 Horizontal U

- tube 1,760,000 kg/hr

(3,870,000 lb/hr) 1 0

11 HP Feedwater Heater 7 Horizontal U

- tube 1,760,000 k g/hr

(3,870,000 lb/hr) 1 0

12 HP Feedwater heater 8 Horizontal U

- tube 1,760,000 kg/hr

(3,870,000 lb/hr) 1 0

13 Auxiliary Boiler Shop fabricated, water

tube 20,000 kg/hr, 2.8 MPa,

343°C (40,000 lb/hr, 400

psig, 650°F) 1 0

14 Fuel Oil System No. 2 fuel oil for light off 1,135,624 liter (300,000 gal) 1 0

15 Service Air Compressors Flooded Screw 28 m 3 / min @ 0.7 MPa

(1,000 scfm @ 100 psig) 2 1

16 Instrument Air Dryers Duplex, regenerative 28 m 3 / min (1,000 scfm) 2 1

17 Closed Cycle Cooling

Heat Exchanger s Shell and tube 53 GJ/hr (50 MMBtu/hr)

each 2 0

18 Closed Cycle Cooling

Water Pumps Horizontal centrifugal 20,800 lpm @ 30 m H

2 O

(5,500 gpm @ 100 ft H

2 O) 2 1

19 Engine

- Driven Fire

Pump Vertical turbine, diesel

engine 3,785 lpm @ 88 m H

2 O

(1,000 gpm @ 290 ft H

2 O) 1 1

20 Fire Service Booster

Pump Two

- stage horizontal

centrifugal 2,650 lpm @ 64 m H

2 O

(700 gpm @ 210 ft H

2 O) 1 1

21 Raw Water Pumps Stainless steel, single

suction 5,670 lpm @ 20 m H

2 O

(1,500 gpm @ 60 ft H

2 O) 2 1

22 Ground Water Pumps Stainless steel, single

suction 2,270 lpm @ 270 m H

2 O

(600 gpm @ 880 ft H

2 O) 5 1

23 Filtered Water Pumps Stainless steel, single

suction 1,690 lpm @ 50 m H

2 O

(450 gpm @ 160 ft H

2 O) 2 1

24 Filtered Water Tank Vertical, cylindrical 1,619,000 liter (428,000 gal) 1 0

25 Makeup Water

Demineralizer Multi

- media filter,

cartridge filter, RO

membrane assembly,

electrodeionization unit 330 lpm (90 gpm) 1 1

26 Liquid Waste Treatment

System -- 10 years, 24

- hour storm 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 129 Case B1 2 A

– Account 4: Boiler and Accessories

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Boiler Supercritical, drum, wall

fired, low NOx burne rs,

overfire air 1,760,000 kg/hr steam

@ 25.5 MPa/602°C/602°C

(3,870,000 lb/hr steam

@ 3,700 psig/1,115°F/1,115°F) 1 0

2 Primary Air Fan Centrifugal 241,000 kg/hr, 3,300 m 3 / min

@ 123 cm WG

(531,000 lb/hr, 116,100 acfm

@ 48 in. WG) 2 0

3 Forced Draft

Fan Centrifugal 784,000 kg/hr, 10,700 m 3 / min

@ 47 cm WG

(1,729,000 lb/hr, 377,900 acfm

@ 19 in. WG) 2 0

4 Induced Draft

Fan Centrifugal 1,131,000 kg/hr, 22,400 m 3 / min

@ 89 cm WG

(2,494,000 lb/hr, 792,500 acfm

@ 35 in. WG) 2 0

5 SCR Reactor

Vessel Space for spare layer 2,260,000 kg/hr (4,990,000 lb/hr) 2 0

6 SCR Catalyst

-- -- 3 0

7 Dilution Air

Blower Centrifugal 120 m 3 / min @ 108 cm WG

(4,300 acfm @ 42 in. WG) 2 1

8 Ammonia

Storage Horizontal tank 135,000 liter (36,000 gal) 5 0

9 Ammonia Feed

Pump Centrifugal 26 lpm @ 90 m H

2 O

(7 gpm @ 300 ft H

2 O) 2 1



## Case B1 2 A

– Account 5: Flue Gas Cleanup

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Fabric Filter Single stage, high

- ratio

with pulse

- jet online

cleaning system 1,13 1,000 kg/hr (2,494,000

lb/hr) 99.9% efficiency 2 0

2 Absorber Module Counter

- current open

spray 45,000 m 3 / min

(1,593,000 acfm) 1 0

3 Recirculation Pumps Horizontal centrifugal 157,000 lpm @ 65 m H

2 O

(41,000 gpm @ 210 ft H

2 O) 5 1

4 Bleed Pumps Horizont al centrifugal 3,820 lpm (1,010 gpm)

at 20 wt% solids 2 1

5 Oxidation Air Blowers Centrifugal 80 m 3 / min @ 0.3 MPa

(2,800 acfm @ 37 psia) 2 1

6 Agitators Side entering 50 hp 5 1

7 Dewatering Cyclones Radial assembly, 5 units

each 960 lpm (250 gpm) per

cyclone 2 0

8 Vacuum Filter Belt Horizontal belt 30 tonne/hr (33 tph) of 50 wt

% slurry 2 1

9 Filtrate Water Return

Pumps Horizontal centrifugal 580 lpm @ 13 m H

2 O

(150 gpm @ 40 ft H

2 O) 1 1

10 Filtrate Water Return

Storage Tank Vertical, lined 380,000 lpm (100,000 gal) 1 0

11 Process Makeup

Water Pumps Horizontal centrifugal 3,040 lpm @ 21 m H

2 O

(800 gpm @ 70 ft H

2 O) 1 1

12 Activated Carbon

Injectors --- 110 kg/hr ( 250 lb/hr) 1 0

13 Hydrated Lime

Injectors --- 3,970 kg/hr (8,760 lb/hr) 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 130 Case B1 2 A

– Account 7: Ducting and Stack

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Stack Reinforced concrete

with FRP liner 152 m (500 ft) h igh x

5.7 m (19 ft) diameter 1 0



## Case B1 2 A

– Account 8: Steam Turbine Generator and Auxiliaries

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Steam

Turbine Commercially available

advanced steam turbine 610 MW

24.1 MPa/593°C/593° C (3500 psig/

1100°F/1100°F) 1 0

2 Steam

Turbine

Generator Hydrogen cooled, static

excitation 680 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 1 0

3 Surface

Condenser Single pass, divided

waterbox including

vacuum pumps 2,410 GJ/hr (2,290 MMBtu/hr),

Inlet wate r temperature 16°C

(60°F),

Water temperature rise 11°C (20°F) 1 0



## Case B1 2 A

– Account 9: Cooling Water System

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Circulating

Water Pumps Vertical, wet pit 453,000 lpm @ 30 m

(120,000 g pm @ 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 /

2530 GJ/hr (2400 MMBtu/hr) heat duty 1 0



## Case B1 2 A

– Account 10: Ash and Spent Sorbent Recovery and Handling

Equipm en

t No. Description Type Design Condition Operating

Qty. Spares

1 Economizer Hopper (part of boiler scope

of supply) -- -- 4 0

2 Bottom Ash Hopper (part of boiler scope of

supply) -- -- 2 0

3 Clinker Grinder

-- 3.8 tonne/hr (4.2 tph) 1 1

4 Pyrites Hopp er (part of pulverizer scope of

supply included with boiler) -- -- 6 0

5 Hydroejectors

-- -- 12

6 Economizer /Pyrites Transfer Tank

-- -- 1 0

7 Ash Sluice Pumps Vertical,

wet pit 150 lpm @ 17 m H

2 O

(40 gpm @ 56 ft H

2 O) 1 1

8 Ash Seal Water Pumps Vert ical,

wet pit 7,570 lpm @ 9 m H

2 O

(2000 gpm @ 28 ft

H 2 O) 1 1

9 Hydrobins

-- 150 lpm (40 gpm) 1 1

10 Baghouse Hopper (part of baghouse

scope of supply) -- -- 24 0

11 Air Heater Hopper (part of boiler scope of

supply) -- -- 10 0

12 Air Blower

-- 20 m 3 / m in @ 0.2 MPa

(630 scfm @ 24 psi) 1 1

13 Fly Ash Silo Reinforce

d concrete 1,200 tonne (1,300 ton) 2 0

14 Slide Gate Valves

-- -- 2 0

15 Unloader

-- -- 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 131 16 Telescoping Unloading Chute

-- 110 tonne/hr (120 tph) 1 0



## Case B1 2 A

– Account 11: Accessory E lectric Plant

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 STG Transformer Oil

- filled 24 kV/345 kV, 650

MVA, 3

- ph, 60 Hz 1 0

2 High Voltage Transformer Oil

- filled 345 kV/13.8 kV, 0

MVA, 3

- ph, 60 Hz 2 0

3 Medium Voltage Transfo rmer Oil

- filled 24 kV/4.16 kV, 31

MVA, 3

- ph, 60 Hz 1 1

4 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 5

MVA, 3

- ph, 60 Hz 1 1

5 STG Isolated Phase Bus Duct

and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 1 0

6 Medium Voltage Switchgear Meta l clad 4.16 kV, 3

- ph, 60 Hz 1 1

7 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 1 1

8 Emergency Diesel Generator Sized for emergency

shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 0



## Case B1 2 A

– Account 12: Instrumentation and Control

Equipment

No. Des cription Type Design Condition Operating

Qty. Spares

1 DCS

- Main

Control Monitor/keyboard; Operator

printer (laser color); Engineering

printer (laser B&W) Operator stations/printers

and engineering

stations/printers 1 0

2 DCS

- Processor Microprocessor with redundant

input/output N/A 1 0

3 DCS

- Data

Highway Fiber optic Fully redundant, 25% spare 1 0



## 3.3.6 Case B12A

– Costs Estimating Results

The cost estimating methodology was described previously in Section 2.7

. Exhibit 3

- 49 shows a

detailed breakdown of the capital costs; Exhibit 3

- 50 shows the owner’s costs , TOC, and TASC ;

Exhibit 3

- 51 shows the initial and annual O&M costs; and Exhibit 3

- 52 shows the COE

breakdown.

The estimated TP C of the SC PC boiler with no CO 2 

## capture is $2,026 /kW. No process

contingency was included in this case because all elements of the technology are commercially

proven. The project contingency is 10.7 percent of the TP C. The COE is $ 82.3 /M Wh.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 132 Exhibit 3

- 49 Case B12 A total plant cost details

Case: B11 A

– Supercritical PC w/o CO 2 Estimate Type: Conceptual

Plant Size (MW,net): 550 Cost B ase: 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 $3,998 $0 $1,8 01 $0 $5,799 $580 $0 $957 $7,336 $13

1.2 Coal Stackout & Reclaim $5,167 $0 $1,155 $0 $6,321 $632 $0 $1,043 $7,996 $15

1.3 Coal Conveyors $4,804 $0 $1,142 $0 $5,946 $595 $0 $981 $7,522 $14

1.4 Other Coal Handling $1,257 $0 $264 $0 $1,521 $152 $0 $251 $1, 924 $3

1.5 Sorbent Receive & Unload $159 $0 $47 $0 $207 $21 $0 $34 $262 $0

1.6 Sorbent Stackout & Reclaim $2,574 $0 $465 $0 $3,039 $304 $0 $501 $3,844 $7

1.7 Sorbent Conveyors $918 $199 $222 $0 $1,340 $134 $0 $221 $1,695 $3

1.8 Other Sorbent Handling $ 555 $131 $287 $0 $972 $97 $0 $160 $1,230 $2

1.9 Coal & Sorbent Hnd. Foundations $0 $4,633 $6,109 $0 $10,743 $1,074 $0 $1,773 $13,590 $25

Subtotal $19,431 $4,963 $11,493 $0 $35,888 $3,589 $0 $5,921 $45,398 $83

2 Coal & Sorbent Prep & Feed

2.1 Coal Cru shing & Drying $2,287 $0 $439 $0 $2,726 $273 $0 $450 $3,448 $6

2.2 Coal Conveyor to Storage $5,854 $0 $1,260 $0 $7,115 $711 $0 $1,174 $9,000 $16

2.5 Sorbent Prep Equipment $4,370 $189 $895 $0 $5,454 $545 $0 $900 $6,899 $13

2.6 Sorbent Storage & Feed $52 6 $0 $199 $0 $725 $73 $0 $120 $918 $2

2.9 Coal & Sorbent Feed Foundation $0 $533 $468 $0 $1,001 $100 $0 $165 $1,266 $2

Subtotal $13,037 $722 $3,262 $0 $17,021 $1,702 $0 $2,808 $21,531 $39

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $ 21,709 $0 $6,999 $0 $28,708 $2,871 $0 $4,737 $36,316 $66

3.2 Water Makeup & Pretreating $5,225 $0 $1,653 $0 $6,878 $688 $0 $1,513 $9,079 $17

3.3 Other Feedwater Subsystems $6,829 $0 $2,803 $0 $9,632 $963 $0 $1,589 $12,185 $22

3.4 Service Water Systems $1,046 $0 $548 $0 $1,594 $159 $0 $351 $2,104 $4

3.5 Other Boiler Plant Systems $8,284 $0 $7,832 $0 $16,116 $1,612 $0 $2,659 $20,387 $37

3.6 FO Supply Sys & Nat Gas $327 $0 $382 $0 $708 $71 $0 $117 $896 $2

3.7 Waste Treatment Equipment $3,428 $0 $1,985 $ 0 $5,413 $541 $0 $1,191 $7,145 $13

3.8 Misc. Equip. (Cranes, Air Comp.,

Comm.) $3,201 $0 $990 $0 $4,191 $419 $0 $922 $5,532 $10

Subtotal $50,049 $0 $23,192 $0 $73,241 $7,324 $0 $13,079 $93,644 $170

4 Boiler & Accessories

4.1 PC Boiler & Accessories $ 179,905 $0 $102,509 $0 $282,414 $28,241 $0 $31,066 $341,722 $621

4.2 SCR w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rig ging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0

Subtotal $179,905 $0 $102,509 $0 $282,414 $28,241 $0 $31,066 $341,722 $621

5A Gas Cleanup & Piping

5A.1 Absorber Vessels & Accessories $67,346 $0 $1 4,399 $0 $81,745 $8,175 $0 $8,992 $98,912 $180

5A.2 Other FGD $3,514 $0 $3,955 $0 $7,470 $747 $0 $822 $9,038 $16Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 133 Case: B11 A

– Supercritical PC w/o CO 2 Estimate Type: Conceptual

Plant Size (MW,net): 550 Cost B ase: 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.3 Bag House & Accessories $19,040 $0 $12,001 $0 $31,041 $3,104 $0 $3,415 $37,560 $68

5A.4 Other Particulate Removal Materials $1,289 $0 $ 1,369 $0 $2,658 $266 $0 $292 $3,216 $6

5A.5 Gypsum Dewatering System $5,399 $0 $911 $0 $6,309 $631 $0 $694 $7,634 $14

5A.6 Mercury Removal System $4,093 $900 $4,024 $0 $9,018 $902 $0 $992 $10,911 $20

Subtotal $100,681 $900 $36,660 $0 $138,241 $13,824 $ 0 $15,207 $167,272 $304

7 HRSG, Ducting, & Stack

7.3 Ductwork $10,663 $0 $6,731 $0 $17,394 $1,739 $0 $2,870 $22,004 $40

7.4 Stack $10,604 $0 $6,162 $0 $16,766 $1,677 $0 $1,844 $20,287 $37

7.9 Duct & Stack Foundations $0 $1,156 $1,373 $0 $2,528 $253 $0 $556 $3,337 $6

Subtotal $21,267 $1,156 $14,266 $0 $36,689 $3,669 $0 $5,271 $45,629 $83

8 Steam Turbine Generator

8.1 Steam TG & Accessories $75,300 $0 $8,211 $0 $83,511 $8,351 $0 $9,186 $101,049 $184

8.2 Turbine Plant Auxiliaries $418 $0 $890 $0 $1, 308 $131 $0 $144 $1,582 $3

8.3 Condenser & Auxiliaries $7,830 $0 $2,737 $0 $10,567 $1,057 $0 $1,162 $12,786 $23

8.4 Steam Piping $26,525 $0 $10,751 $0 $37,276 $3,728 $0 $6,151 $47,154 $86

8.9 TG Foundations $0 $1,247 $2,059 $0 $3,305 $331 $0 $727 $4,363 $8

Subtotal $110,073 $1,247 $24,647 $0 $135,967 $13,597 $0 $17,370 $166,934 $304

9 Cooling Water System

9.1 Cooling Towers $10,613 $0 $3,282 $0 $13,895 $1,390 $0 $1,529 $16,814 $31

9.2 Circulating Water Pumps $2,125 $0 $133 $0 $2,258 $226 $0 $248 $2 ,732 $5

9.3 Circ. Water System Auxiliaries $586 $0 $78 $0 $664 $66 $0 $73 $803 $1

9.4 Circ. Water Piping $0 $4,939 $4,473 $0 $9,412 $941 $0 $1,553 $11,906 $22

9.5 Make

- up Water System $528 $0 $678 $0 $1,206 $121 $0 $199 $1,525 $3

9.6 Component Cooling Water Sys. $478 $0 $367 $0 $845 $84 $0 $139 $1,069 $2

9.9 Circ. Water Foundations & Structures $0 $2,616 $4,344 $0 $6,960 $696 $0 $1,531 $9,188 $17

Subtotal $14,330 $7,555 $13,355 $0 $35,240 $3,524 $0 $5,273 $44,037 $80

10 Ash & Spent Sorbent Handling Systems

10.6 Ash Storage Silos $777 $0 $2,379 $0 $3,156 $316 $0 $347 $3,819 $7

10.7 Ash Transport & Feed Equipment $5,164 $0 $5,119 $0 $10,283 $1,028 $0 $1,131 $12,443 $23

10.9 Ash/Spent Sorbent Foundation $0 $176 $216 $0 $392 $39 $0 $86 $517 $1

Subt otal $5,941 $176 $7,714 $0 $13,831 $1,383 $0 $1,564 $16,778 $31

11 Accessory Electric Plant

11.1 Generator Equipment $1,942 $0 $310 $0 $2,253 $225 $0 $186 $2,664 $5

11.2 Station Service Equipment $3,283 $0 $1,101 $0 $4,384 $438 $0 $362 $5,184 $9

11.3 Switchgear & Motor Control $3,769 $0 $655 $0 $4,423 $442 $0 $487 $5,352 $10

11.4 Conduit & Cable Tray $0 $2,584 $8,349 $0 $10,934 $1,093 $0 $1,804 $13,831 $25

11.5 Wire & Cable $0 $4,921 $8,796 $0 $13,717 $1,372 $0 $2,263 $17,352 $32

11.6 Protective Eq uipment $306 $0 $1,063 $0 $1,370 $137 $0 $151 $1,658 $3

11.7 Standby Equipment $1,497 $0 $35 $0 $1,532 $153 $0 $169 $1,854 $3

11.8 Main Power Transformers $9,846 $0 $206 $0 $10,052 $1,005 $0 $1,106 $12,163 $22

11.9 Electrical Foundations $0 $359 $913 $0 $1,271 $127 $0 $280 $1,678 $3

Subtotal $20,644 $7,864 $21,428 $0 $49,936 $4,994 $0 $6,806 $61,735 $112Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 134 Case: B11 A

– Supercritical PC w/o CO 2 Estimate Type: Conceptual

Plant Size (MW,net): 550 Cost B ase: 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

12 Instrumentation & Control

12.1 PC Control Equipment w/12.7 $0 w/12.7 $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

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $531 $0 $324 $0 $855 $86 $0 $141 $1,082 $2

12.7 Distributed Control Sys. Equipment $5,357 $0 $955 $0 $6,313 $631 $0 $694 $7,638 $14

12. 8 Instrument Wiring & Tubing $3,230 $0 $5,878 $0 $9,109 $911 $0 $1,503 $11,522 $21

12.9 Other I & C Equipment $1,514 $0 $3,505 $0 $5,019 $502 $0 $552 $6,073 $11

Subtotal $10,632 $0 $10,663 $0 $21,296 $2,130 $0 $2,891 $26,316 $48

13 Improvements to Sit e

13.1 Site Preparation $0 $56 $1,194 $0 $1,250 $125 $0 $275 $1,651 $3

13.2 Site Improvements $0 $1,864 $2,462 $0 $4,326 $433 $0 $952 $5,710 $10

13.3 Site Facilities $3,340 $0 $3,504 $0 $6,843 $684 $0 $1,506 $9,033 $16

Subtotal $3,340 $1,920 $7,160 $0 $12,420 $1,242 $0 $2,732 $16,394 $30

14 Buildings & Structures

14.1 Boiler Building $0 $9,916 $8,714 $0 $18,629 $1,863 $0 $3,074 $23,566 $43

14.2 Turbine Building $0 $14,161 $13,189 $0 $27,349 $2,735 $0 $4,513 $34,597 $63

14.3 Administration Building $0 $702 $742 $0 $1,444 $144 $0 $238 $1,827 $3

14.4 Circulation Water Pumphouse $0 $201 $160 $0 $361 $36 $0 $60 $457 $1

14.5 Water Treatment Buildings $0 $652 $594 $0 $1,246 $125 $0 $206 $1,576 $3

14.6 Machine Shop $0 $470 $315 $0 $785 $79 $0 $130 $993 $2

14.7 Warehouse $0 $318 $319 $0 $637 $64 $0 $105 $806 $1

14.8 Other Buildings & Structures $0 $260 $221 $0 $481 $48 $0 $79 $609 $1

14.9 Waste Treating Building & Str. $0 $498 $1,510 $0 $2,008 $201 $0 $331 $2,540 $5

Subtotal $0 $27,177 $25,764 $0 $5 2,941 $5,294 $0 $8,735 $66,971 $122

Total $549,332 $53,681 $302,113 $0 $905,125 $90,513 $0 $118,723 $1,114,361 $2,026Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 135 Exhibit 3

- 50 Case B12A owner’s costs

Description $ / 1,000 $/kW

Pre

- Production Costs

6 Months All Labor $8,509 $15

1 Month Maintenance Materials $1,071 $2

1 Month Non

- fuel Consumables $2,133 $4

1 Month Waste Disposal $429 $1

25% of 1 Months Fuel Cost at 100% CF $2,471 $4

2% of TPC $22,287 $41

Total $36,901 $67

Inventory Capital

6 0 day supply of fuel and consumables at 100% CF $23,659 $43

0.5% of TPC (spare parts) $5,572 $10

Total $29,231 $53

Other Costs

Initial Cost for Catalyst and Chemicals $0 $0

Land $900 $2

Other Owner's Costs $167,154 $304

Financing Costs $30,088 $55

Total Overnight Costs (TOC) $1,378,634 $2,507

TASC Multiplier (IOU, low

- risk, 35 year) 1.134

Total As

- Spent Cost (TASC) $1,563,371 $2,842Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 136 Exhibit 3

- 51 Case B12A initial and annual operating and maint enance costs

Case: B12 A

– Supercritical PC w/o CO 2 Cost Base: Jun 2011

Plant Size (MW,net): 550 Heat Rate

- net (Btu/kWh): 8,379 Capacity Factor (%): 8 5

Operating & Maintenance Labor

Operating Labor Operating Labor Requirements per Shift

Operating La bor 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.: 2.0

Total: 14.0

Fixed Operating Costs

Annual Cost

($) ($/kW

- net)

Annual Operating Labor: $6,329,450 $11.508

Maintenance Labor: $7,284,427 $13.244

Administrative & Support Labor: $3,403,469 $6.188

Property Taxes and Insurance: $22,287,220 $40.521

Total: $39,304,567 $71.4 61

Variable Operating Costs

($) ($/M Wh

- net)

Maintenance Material: $10,926,640 $2.66803

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 3,675 $1.67 $0 $1,908,776 $0.46608

Makeup and Waste Water

Treatment Chemicals (lbs): 0 17,791 $0.27 $0 $1,478,352 $0.36098

Limestone (ton) 0 468 $33.48 $0 $4,865,781 $1.18811

Hydrated Lime (ton) 0 96 $155.00 $0 $4,594,464 $1.12186

Activated Carbon (ton) 0 3 $1,255.00 $0 $1,074,374 $0.26234

Ammoni a (19% NH 3 , ton) 0 68 $330.00 $0 $6,967,794 $1.70137

SCR Catalyst (m 3 ) 0 0.31 $8,938.80 $0 $871,258 $0.21274

Subtotal: $0 $21,760,800 $5.31349

Waste Disposal

Fly Ash (ton) 0 470 $25.11 $0 $3,659,558 $0.89358

Bottom Ash (ton) 0 92 $25.11 $0 $719,87 1 $0.17578

Subtotal: $0 $4,379,428 $1.06936

By

- Products

Gypsum (ton) 0 81 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000

Variable Operating Costs Total: $0 $37,066,868 $9.05088

Fuel Cost

Illinois Number 6 (ton): 0 4,741 $68.54 $0 $100, 807,335 $24.61483

Total: $0 $100,807,335 $24.61483



### Exhibit 3

- 52 Case B 12A COE breakdown

Component Value, $/MWh Percentage

Capital 39.0 47%

Fixed 9.6 12%

Variable 9.1 11%

Fuel 24.6 30%

Total (Exclu ding T&S) 82.3 N/A

CO 2 

### T&S 0.0 0%

Total (Including T&S) 82.3 N/ACost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 137 

## 3.3.7 Case B12B

– Supercritical PC with CO 2 

## Capture

The plant configuration for Case B12B, SC PC, is the same as Case B12A with the exception

that the Cansolv system was used for the CDR facil ity . The nominal net output is maintained at

550 MW by increasing the boiler size and turbine/generator size to account for the greater

auxiliary load imposed by the CDR facility and CO 2 

## compressors . Unlike the NGCC cases where gross output was fixed by the available size of the CTs, the PC cases utilize boilers and

steam turbines that can be procured at nearly any desired output making it possible to maintain a

constant net output.

The process description for Case B12B is essentially the same as Case B12 A with one notable

exception , the addition of CO 2 

## capture. A BFD and stream tables for Case B12B are shown in

Exhibit 3

- 53 and Exhibit 3

- 54 , respectively. Since the CDR facility process description was

provided in Section 3.1.8 , it is not repeated here.



## 3.3.8 Case B12B Performance Results

The Case B12B modeling assumptions were presented previously in Section 3.3.2

.

The plant produces a net output of 55 0 MW at a net plant efficiency of 32.5 percent (HHV

basis). Overall plant performance is summarized in Exhibit 3

- 55 ; Exhibit 3

- 56 provides a

detailed breakdown of the auxiliary power requirements. The C DR facility, including CO 2 

## compression, accounts for over half of the auxiliary plant load. The CWS (CWPs and cooling

tower fan) accounts for nearly 13 percent of the auxiliary load, largely due to the high cooling

water demand of the CDR facility and CO 2 

## compressors.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 138 Exhibit 3

- 53 Case B12B block flow diagram , su per critical unit with CO 2 

### c apture

Source: NETL S TACK GAS

S TACK C ANSOLV 31 32

33

22

23

CO 2

P RODUCT R EBOILER

S TEAM R EBOILER

C ONDENSATE

P ULVERIZED

C OAL

B OILER SCR B AGHOUSE FGD

G YPSUM L IMESTONE

S LURRY O XIDATION

A IR M AKEUP

W ATER

B OTTOM A SH C OAL F EED I NFILTRATION

AIR

1

4

8 7

9 14

F LY A SH 15 16 18 19

17 20 21

HP

TURBINE 34

35 36

IP

TURBINE LP TURBINE

CONDENSER

38 FEEDWATER

HEATER

SYSTEM

Note : Block Flow Diagram is not intended to

represent a complete material balance

. Only

major process streams and equipment are

shown

. 3 2

6

5 11

37 10 H YDRATED

L IME 12

13 A CTIVATED

C ARBON

FD F ANS

PA F ANS ID F AN

CO 2 C OMPRESSORS

B OILER

F EEDWATER 29 R ECLAIMER

S TEAM 30

R ECLAIMER

C ONDENSATE

D RYER

27

CO 2 C OMPRESSORS 28 26 25 24 V ENT

D RYER S TEAM D RYER

C ONDENSATECost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 139 Exhibit 3

- 54 Case B12B stream table , su per crit ical unit with c apture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V

- L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0000 0.0088 0.0000 0.0088 0.0000

CO 2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0 000 0.0000 0.1376 0.0000 0.1376 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 0.0000 0.0000 0.0000

H 2 O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0000 0.0831 0.0000 0.0831 0.0000

N 2 0.7732 0 .7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.0000 0.7345 0.0000 0.7345 0.0000

O 2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0000 0.0340 0.0000 0.0340 0.3333

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0 000 0.0000 0.0020 0.0000 0.0020 0.6667

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 61,983 61,983 1,836 19,040 19,040 2,620 1,354 0 0 0 86,880 0 86,880 4

V

- L Flowrate (kg/hr) 1,788,627 1,788,627 52,976 549,448 549,448 75,618 39,068 0 0 0 2,580,136 0 2,580,136 198

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 224,791 4,360 4,530 21,968 131 22,099 22,099

Temperature (°C) 15 19 19 15 25 25 15 15 149 27 143 27 143 143

Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10

Steam Table Enthalpy (kJ/kg) A 30.23 34.36 34.36 30.23 40.78 40.78 30.23

--- --- --- --- --- --- --- AspenPlus Enthalpy (kJ/kg) B

- 97.58

- 93.45

- 93.45

- 97.58

- 87.03

- 87.03

- 97.58

- 2,114.05 97.18

- 13,306.82

- 2,399.49 3.40

- 2,399.37

- 2,632.04

Density (kg/m 3 ) 1.2 1.2 1.2 1.2 1.3 1.3 1.2

--- --- --- 0.9

--- 0.9 1.5

V

- L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857

--- --- --- 29.6 98

--- 29.698 53.376

V

- L Flowrate (lb mole /hr) 136,648 136,648 4,047 41,977 41,977 5,777 2,985 0 0 0 191,537 0 191,537 8

V

- L Flowrate (lb/hr) 3,943,248 3,943,248 116,791 1,211,325 1,211,325 166,710 86,130 0 0 0 5,688,226 0 5,688,226 436

S olids Flowrate (lb/hr) 0 0 0 0 0 0 0 495,578 9,611 9,988 48,432 288 48,720 48,720

Temperature (°F) 59 66 66 59 78 78 59 59 300 80 289 80 289 289

Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.4 14.7 14.4 14.7 14.4 14.4

Steam Table Enthalpy (Btu/lb) A 13.0 14.8 14.8 13.0 17.5 17.5 13.0

--- --- --- --- --- --- --- AspenPlus Enthalpy (Btu/lb) B

- 42.0

- 40.2

- 40.2

- 42.0

- 37.4

- 37.4

- 42.0

- 908.9 41.8

- 5,720.9

- 1,031.6 1.5

- 1,031.5

- 1,131.6

Density (lb/ft 3 ) 0.076 0.078 0.078 0.076 0. 081 0.081 0.076

--- --- --- 0.053

--- 0.053 0.096

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: Revision 3



## 140 E xhibit 3

- 54 Case B12B stream table , su per critical unit with c apture (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 28

V

- L Mole Fraction

Ar 0.0088 0.0088 0.0000 0.0000 0.0092 0.0000 0.0082 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0. 0000

CO 2 0.1376 0.1376 0.0000 0.0000 0.0003 0.0001 0.1288 0.9824 0.9977 0.0492 0.0000 0.0000 0.9993 0.9993

H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 0.0831 0.0831 1.0000 1.0000 0.0099 0.9999 0.1451 0.0176 0.0023 0.9508 1.0000 1.0000 0.0007 0.0007

N 2 0.7345 0.7345 0.0000 0.0000 0.7732 0.0000 0.6854 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O 2 0.0340 0.0340 0.0000 0.0000 0.2074 0.0000 0.0325 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0. 0000

SO 2 0.0020 0.0020 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 8 6,876 86,876 2,880 11,542 919 213 94,143 11,109 10,940 18 14 14 10,921 10,921

V

- L Flowrate (kg/hr) 2,579,938 2,579,938 51,879 207,939 26,514 3,829 2,716,229 483,852 480,793 352 255 255 480,441 480,441

Solids Flowrate (kg/hr) 0 0 22,213 0 0 34,451 0 0 0 0 0 0 0 0

Temperature (°C) 143 153 15 27 167 56 56 29 29 29 461 203 29 40

Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.31 0.10 0.10 0.20 3.03 3.03 2.14 1.64 2.89 15.27

Steam Table Enthalpy (kJ/kg) A 274.36 285.60

--- 111.65 184.48

--- 286.10 42.52

- 6.00 138.07 3,379.59 863.65

- 5.93

- 205.61

AspenPlus Enthalpy (kJ/kg) B

- 2,397.36

- 2,386.11

- 14,995.75

- 15,964.53 56.67

- 12,481.91

- 2,940.30

- 8,972.02

- 8,974.94

- 15,237.30

- 12,600.71

- 15,116.65

- 8,970.17

- 9,169.86

Density (kg/m 3 ) 0.8 0.9 1,003.6 99 2.3 2.4 833.1 1.1 3.5 63.3 377.5 6.4 861.8 59.9 789.2

V

- L Molecular Weight 29.697 29.697 18.015 18.015 28.857 18.018 28.852 43.553 43.950 19.294 18.015 18.015 43.991 43.991

V

- L Flowrate (lb mole /hr) 191,529 191,529 6,349 25,447 2,026 468 2 07,551 24,492 24,118 40 31 31 24,078 24,078

V

- L Flowrate (lb/hr) 5,687,790 5,687,790 114,374 458,428 58,452 8,441 5,988,260 1,066,711 1,059,968 776 563 563 1,059,192 1,059,192

Solids Flowrate (lb/hr) 0 0 48,970 0 0 75,950 0 0 0 0 0 0 0 0

Temperature (°F) 289 308 59 80 332 133 133 85 85 85 861 397 85 104

Pressure (psia) 14.2 15.2 15.0 15.7 45.0 14.7 14.7 28.7 439.4 439.4 310.1 237.4 419.4 2,214.7

Steam Table Enthalpy (Btu/lb) A 118.0 122.8

--- 48.0 79.3

--- 123.0 18.3

- 2.6 59.4 1,453.0 37 1.3

- 2.5

- 88.4

AspenPlus Enthalpy (Btu/lb) B

- 1,030.7

- 1,025.8

- 6,447.0

- 6,863.5 24.4

- 5,366.3

- 1,264.1

- 3,857.3

- 3,858.5

- 6,550.9

- 5,417.3

- 6,499.0

- 3,856.5

- 3,942.3

Density (lb/ft 3 ) 0.052 0.055 62.650 61.950 0.153 52.011 0.067 0.216 3.953 23.565 0.402 5 3.801 3.737 49.270

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: Revision 3



## 141 Exhibit 3

- 54 Case B12B stream t able , su per critical unit with c apture (continued)

29 30 31 32 33 34 35 36 37 38

V

- L Mole Fraction

Ar 0.0000 0.0000 0.0000 0.0000 0.0103 0.0000 0.0000 0.0000 0.0000 0.0000

CO 2 0.0000 0.0000 0.0000 0.0000 0.0163 0.0000 0.0000 0.0000 0.0000 0.0 000

H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 1.0000 1.0000 1.0000 1.0000 0.0671 1.0000 1.0000 1.0000 1.0000 1.0000

N 2 0.0000 0.0000 0.0000 0.0000 0.8652 0.0000 0.0000 0.0000 0.0000 0.0000

O 2 0.0000 0.0000 0.0000 0.00 00 0.0410 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

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 85 85 27,975 27,977 7 4,575 111,201 92,880 92,880 51,680 51,902

V

- L Flowrate (kg/hr) 1,533 1,533 503,979 504,008 2,079,831 2,003,325 1,673,260 1,673,260 931,021 935,036

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 342 215 269 151 41 593 342 593 38 39

Pressure (MPa, abs) 4.90 2.11 0.51 0.49 0.10 24.23 4.90 4.80 0.01 1.37

Steam Table Enthalpy (kJ/kg) A 3,049.83 921.30 3,000.13 635.93 151.94 3,477.96 3,049.83 3,652.36 2,166.50 162.50

AspenPlus Enthalpy (kJ/kg) B

- 12,930.47

- 15,058.99

- 12,980.16

- 15, 344.37

- 794.66

- 12,502.33

- 12,930.47

- 12,327.94

- 13,813.79

- 15,817.80

Density (kg/m 3 ) 19.2 846.4 2.1 916.3 1.1 69.2 19.2 12.3 0.1 993.3

V

- L Molecular Weight 18.015 18.015 18.015 18.015 27.889 18.015 18.015 18.015 18.015 18.015

V

- L Flowrate ( lb mole /hr) 188 188 61,675 61,678 164,410 245,157 204,765 204,765 113,934 114,425

V

- L Flowrate (lb/hr) 3,379 3,379 1,111,084 1,111,147 4,585,242 4,416,576 3,688,906 3,688,906 2,052,550 2,061,401

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0

Tem perature (°F) 648 419 517 304 107 1,100 648 1,100 101 101

Pressure (psia) 710.8 306.2 73.5 70.6 14.7 3,514.7 710.8 696.6 1.0 198.7

Steam Table Enthalpy (Btu/lb) A 1,311.2 396.1 1,289.8 273.4 65.3 1,495.3 1,311.2 1,570.2 931.4 69.9

AspenPlus Enthalpy (Btu /lb) B

- 5,559.1

- 6,474.2

- 5,580.5

- 6,596.9

- 341.6

- 5,375.0

- 5,559.1

- 5,300.1

- 5,938.9

- 6,800.4

Density (lb/ft 3 ) 1.197 52.841 0.128 57.201 0.068 4.319 1.197 0.768 0.004 62.011

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: Revision 3



## 142 Exhibit 3

- 55 Case B12B plant performance summary

Performance Summary

Total Gross Power, MWe 642

CO
2 Capture/Removal Auxiliaries, kWe 16,000

CO
2 Compression, kWe 35,690

Balance of Plant, kWe 39,595

Total Auxiliaries, MWe 91

Net Power, MWe 550

HHV Net Plant Efficiency (%) 32.5%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,086 (10,508)

LHV Net Plan t Efficiency (%) 33.7%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 10,693 (10,135)

HHV Boiler Efficiency, % 89.1%

LHV Boiler Efficiency, % 92.4%

Steam Turbine Cycle Efficiency, % 54.5%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 6,608 (6,263)

Condenser D uty, GJ/hr ( MM Btu/hr) 1,867 (1,770)

As

- Received Coal Feed, kg/hr (lb/hr) 224,791 (495,578)

Limestone Sorbent Feed, kg/hr (lb/hr) 22,213 (48,970)

HHV Thermal Input, kWt 1,694,366

LHV Thermal Input, kWt 1,634,237

Raw Water Withdrawal, ( m 3 

### / min)/MW net 

### (gp m/MW net 

### ) 0.054 (14.3)

Raw Water Consumption, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.042 (11.0)

Excess Air, % 20.9%Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 143 Exhibit 3

- 56 Case B1 2 B plant power summary

Power Summary

Steam Turbine Power, MWe 642

Total Gr oss Power, MWe 642

Auxiliary Load Summary

Coal Handling and Conveying, kWe 480

Pulverizers, kWe 3,370

Sorbent Handling & Reagent Preparation, kWe 1,070

Ash Handling, kWe 780

Primary Air Fans, kWe 1,670

Forced Draft Fans, kWe 2,130

Induced Draft Fan s, kWe 8,350

SCR, kWe 60

Activated Carbon Injection, kW 27

Dry sorbent Injection, kW 108

Baghouse, kWe 110

Wet FGD, kWe 3,550

CO
2 Capture/Removal Auxiliaries, kWe 16,000

CO
2 Compression, kWe 35,690

Miscellaneous Balance of Plant A,B 

### , kWe 2,000

Stea m Turbine Auxiliaries, kWe 400

Condensate Pumps, kWe 640

Circulating Water Pumps, kWe 7,750

Ground Water Pumps, kWe 710

Cooling Tower Fans, kWe 4,010

Transformer Losses, kWe 2,380

Total Auxiliaries, MWe 91

Net Power, MWe 550

A 

### Boiler feed pumps ar e turbine driven

B 

### Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads



## 3.3.8.1 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 B12B is presented in Exhibit 3

- 57

. SO 2



## emissions are utilized as a surrogate for HCl emissions, therefore HC l is not reported.

Exhibit 3

- 57 Case B12B air emissions

kg/GJ (lb/ MM Btu) Tonne/year (ton/year) A 

### kg/MWh (lb/MWh)

SO
2 0.000 (0.000) 0 (0) 0.000 (0.000)

NOx 0.033 (0.078) 1,517 (1,672) 0.318 (0.700)

Particulate 0.004 (0.010) 195 (215) 0.041 (0.090)

Hg 1.43E

- 7 (3.33E

- 7) 0.006 (0.007) 1.36E

- 6 (3.00E

- 6)

CO
2 B 

### 9 (20) 397,399 (438,058) 83 (183)

CO
2 C



### - - 97 (214)

mg/Nm 3



### Particulate Concentration D

, E 

### 13.45

A 

### Calculations based on an 85 percent capacity factor

B 

### CO 2 

### emissions based on gross power

C 

### CO 2 

### emissions based on net power instead of gross power

D 

### Concentration of particles in the flue gas after the baghouse

E 

### Normal co nditions given at 32°F and 14.696 psiaCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 144 SO 2 

## emissions are controlled using a wet limestone forced oxidation scrubber that achieves a

removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site.

The wallboard grade mater ial can potentially be marketed and sold, but since it is highly

dependent on local market conditions, no byproduct credit was taken. The SO 2 

## emi ssions are

further reduced to 1 ppmv using a NaOH based polishing scrubber in the CDR facility. The

remaining low concentration of SO 2 

## is essentially completely removed in the CDR absorber

vessel resulting in very low SO 2 

## emissions.

NOx emissions are controlled to about 0.5 lb/ MM Btu through the use of LNBs and OFA. An

SCR unit then further reduces the NOx concen tration by 8 5 percent to 0.0 8 lb/ MM Btu.

Particulate emissions are controlled using a pulse jet fabric filter, which operates at an efficiency

of 99. 9 percent.

The total reduction in mercury emission via the combined control equipment (SCR, ACI, fabric

filt er, DSI, and wet FGD) is 97. 1 percent.

Ninety (90) percent of the CO 2 

## in the flue gas is removed in CDR facility.

The carbon input to the plant consists of carbon in the coal , carbon in the air

, PAC, and carbon in

the lim estone reagent used in the FGD

. Ca rbon leaves the plant mostly as CO 2 

## through the stack

, however, the PAC is captured in the fabric filter and some leaves as gypsum. The carbon

capture efficiency is defined as one minus the amount of carbon in the stack gas relative to the

total carbon in , represented by the following fraction:

CCCCCCCC SSSS

( TT CCCCCCCC ) = �

1

− � 32

, 112

321

, 883 � �

∗ 100 = 90

. 0%

Exhibit 3

- 58 Case B12B carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 143,292 (315,9 05) Stack Gas 14,566 (32,112)

Air (CO
2 ) 327 (721) FGD Product 215 (474)

PAC 131 (288) Baghouse 131 (288)

FGD Reagent 2,254 (4,969) CO
2 Product 131,081 (288,984)

CO
2 Dryer Vent 11 (24)

CO
2 Knockout 0 (1)

Total 146,004 (321,883) Total 146,004 (321, 883)



## Exhibit 3

- 59 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in

the coal. Sulfur output includes the sulfur recovered from the FGD as gypsum

, sulfur emitted in

the stack gas , and sulfur re moved in the polishing scrubber.

Exhibit 3

- 59 Case B12B sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 5,634 (12,421) FGD Product 5,444 (12,002)

Stack Gas 0 (0)

Polishing Scr ubber and Solvent Reclaiming 111 (245)

Baghouse 79 (175)

Total 5,634 (12,421) Total 5,634 (12,421)Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 145 Exhibit 3

- 60 s hows the overall water balance for the plant. The exhibit is presented in an

identical manner as for Case B12A.

Exhibit 3

- 60 Case B12B 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)

FGD Makeup 4.34 (1,146)

– 4.34 (1,146)

– 4.34 (1,146)

CO
2 Drying

– – – 0.01 (2)

- 0.01 (

- 2)

Capture System

Makeup 0.02 (5)

– 0.02 (5)

– 0.02 (5)

Deaerator Vent

– – – 0.07 (18)

- 0.07 (

- 18)

Condenser Makeup 0.07 (18)

– 0.07 (18)

– 0.07 (18)

BFW Makeup 0.07 (18)

– 0.07 (18)

– 0.07 (18)

Cooling Tower 30.19

(7,976) 4.78 (1,262) 25.41

(6,714) 6.79 (1,794) 18.62 (4,920)

FGD Dewatering

– 2.24 (591)

- 2.24 (

- 591)

– - 2.24 (

- 591)

CO
2 Capture

Recovery – 2.54 (672)

- 2.54 (

- 672)

– - 2.54 (

- 672)

C O
2 Compression

KO – 0.05 (13)

- 0.05 (

- 13)

– - 0.05 (

- 13)

BFW Blowdown

– – – – –

Total 34.62

(9,145) 4.78 (1,262) 29.84

(7,882) 6.86 (1,813) 22.97 (6,069)



## 3.3.8.2 Heat and Mass Balance Diagrams

A heat and mass balance diagram is shown for the Case B12B PC bo iler, the FGD unit, CDR

system, and steam cycle in Exhibit 3

- 61 and Exhibit 3

- 62 . An overall plant energy balance is

provided in tabular form in Exhibit 3

- 63

.

The power out is the steam turbine power prior to generator losses. The power at the generator

terminals (shown in Exhibit 3

- 55 ) is calculated by multiplying the power out by a generator

efficiency of 98.5 percent. The c apture process heat out stream represents heat rejected to

cooling water and ultimately to ambient via the cooling tower. The same is true of the condenser

heat out stream. The CO 2 

## compressor intercooler load is included in the capture process heat out

stream.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 146 Exhibit 3

- 61 Case B12B heat and mass balance, supercritical PC boiler with CO 2 

### capture

Source: NETL Notes :

1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psia

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Air

Coal / Ash

Slurry

Water Steam

P AGES

1 OF 2 B ITUMINOUS B ASELINE S TUDY

C ASE B 12 B

S UBCRITICAL P ULVERIZED C OAL

B OILER AND G AS C LEANUP S YSTEMS

DWG

. NO

. BB

- HMB

- CS

- B 12 B

- PG

- 1 Pulverized

Coal

Boiler SCR Ammonia

Infiltration Air

Air

Air

Coal

Bottom Ash FGD

Fly Ash

Forced

Draft Fans

Primary

Air Fans

495

, 578 W

59 T

15 P 78 T

16 P

18 H 66 T

15 P

15 H 4

, 416

, 576 W

1

, 100 T

3

, 515 P

1

, 495 H

3

, 688

, 906 W

1

, 100 T

697 P

1

, 570 H

1

, 211

, 325 W

59 T

15 P

13 H 3

, 943

, 248 W

59 T

15 P

13 H 86

, 130 W

59 T

15 P

13 H 5

, 736

, 658 W

289 T

14 P

117 H

9

, 611 W

300 T

14 P 49

, 156 W

289 T

14 P

3

, 688

, 906 W

648 T

711 P

1

, 311 H

4

, 416

, 576 W

555 T

3

, 691 P

551 H 5 4

, 585

, 242 W

107 T

15 P

65 H

1 2

4 7

9 ID Fans 5

, 687

, 790 W

289 T

14 P

118 H

Gross Plant Power : 642 MWe

Auxiliary Load : 91 MWe

Net Plant Power : 550 MWe

Net Plant Efficiency

, HHV : 32

. 5 %

Net Plant Heat Rate : 10

, 508 Btu / kWh Lime /

Limestone /

Gypsum

Flue Gas Oxidation

Air Make

- Up

Water

Limestone

Slurry Gypsum

18

17 14 5

, 687

, 790 W

308 T

15 P

123 H

163

, 344 W

59 T

15 P

423 H 58

, 452 W

332 T

45 P

79 H 458

, 428 W

80 T

16 P

48 H

84

, 392 W

133 T

15 P

1

, 499 H Baghouse

3

6

8 15 16 19

34

35 36

DOE / NETL

SC PC P LANT

C ASE B 12 B Hydrated

Lime 11

Single Reheat

Extraction from

HP Turbine

From Feedwater

Heaters Single Reheat

To IP Turbine Throttle Steam

To HP Turbine 9

, 988 W

80 T

15 P 10 Activated

Carbon

12

Activated

Carbon 13

288 W

80 T

15 P

CansolvStripperAbsorber Flue Gas Acid Gas 1

, 066

, 711 W

85 T

29 P

18 H 22 33 5

, 988

, 260 W

133 T

15 P

123 H

Stack 21

1

, 059

, 192 W

104 T

2

, 215 P

- 88 H CO 2
Product CO 2 Compression

( Interstage Cooling ) &

Drying 6

, 743 W

85 T

62 P

66 H

KO

- Water Dryer

Water

776 W

85 T

439 P

59 H 24

Dryer

28 23

27 1

, 059

, 192 W

85 T

419 P

- 3 H 1

, 059

, 968 W

85 T

439 P

- 3 H Carbon Dioxide 5

, 736

, 946 W

289 T

14 P

117 H

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical 20

AmmoniaCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 147 Exhibit 3

- 62 Case B12B heat and mass balance, supercritical steam cyc le

Source: NETL H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Water Steam

P AGES

2 OF 2 DWG

. NO

. BB

- HMB

- CS

- B 12 B

- PG

- 2

B ITUMINOUS B ASELINE S TUDY

C ASE B 12 B

S UBCRITICAL P ULVERIZED C OAL

P OWER B LOCK S YSTEMS LP Turbine Generator HP

Turbine IP

Turbine

Condenser

Hot Well Boiler Feed Pump

Turbine Drives Throttle

Steam

Condensate

Pumps 4

, 416

, 576 W

1

, 100 T

3

, 515 P

1

, 495 H

341

, 791 W

861 T

298 P

1

, 453 H 397

, 804 W

645 T

682 P

1

, 311 H 3

, 688

, 906 W

648 T

711 P

1

, 311 H 336

, 231 W

517 T

74 P

1

, 290 H

336

, 231 W

126 T

2 P

1

, 073 H 1

, 508

, 246 W

101 T

1 P

1

, 008 H

2

, 061

, 401 W

101 T

1 P

69 H

3

, 176

, 490 W

173 T

176 P

142 H

208

, 074 W

183 T

8 P

151 H 3

, 176

, 490 W

241 T

162 P

210 H

1

, 066

, 082 W

324 T

94 P

294 H 3

, 176

, 490 W

193 T

169 P

161 H

724

, 291 W

429 T

339 P

406 H 4

, 416

, 576 W

419 T

4

, 005 P

399 H

Deaerator

Boiler Feed

Water Pumps 4

, 416

, 576 W

555 T

3

, 691 P

551 H 3

, 688

, 906 W

1

, 100 T

697 P

1

, 570 H

149

, 092 W

203 T

12 P

171 H 182

, 855 W

517 T

72 P

1

, 290 H 149

, 092

W

344 T

28 P

1

, 211 H 58

, 981 W

199 T

11 P

1

, 146 H 3

, 163

, 697 W

517 T

74 P

1

, 290 H 1

, 716

, 320 W

517 T

74 P

1

, 290 H

4

, 172 P

4

, 416

, 576 W

305 T

72 P

275 H Gross Plant Power : 642 MWe

Auxiliary Load : 91 MWe

Net Plant Power : 550 MWe

Net Plant Efficiency

, HHV : 32

. 5 %

Net Plant Heat Rate : 10

, 508 Btu / kWh FWH 3 FWH 4 FWH 5 FWH 6 34

38

DOE / NETL

SC PC P LANT

C ASE B 12 B 36 8

, 851 W

59 T

15 P

27 H

Vent Notes :

1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psia Single Reheat

Extraction

From Boiler

Single Reheat

Extraction to

Boiler

To Boiler Steam Turbine

Makeup

35

Reclaimer

Steam 29 563 W

861 T

310 P

1

, 453 H

Dryer

Steam Reboiler

Steam

1

, 111

, 084 W

517 T

74 P

1

, 290 H 25 31

Reboiler

Condensate Reclaimer

Condensate Dryer

Condensate

563 W

397 T

237 P

371 H 3

, 379 W

419 T

306 P

396 H 1

, 111

, 147 W

304 T

71 P

273 H W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical 37

326

, 487 W

757 T

1

, 071 P

1

, 358 H

326

, 487 W

510 T

746 P

500 H 4

, 416

, 576 W

500 T

3

, 845 P

488 H FWH 6 3

, 379 W

648 T

711 P

1

, 311 H

32 30 26Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 148 Exhibit 3

- 63 Case B12B overall energy balance ( 0°C [ 32°F ] r eference)

HHV Sensible +

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 6,100

(5,781) 5.1 (4.8)

– 6,105 (5,786)

Air

– 71.9 (68.1)

– 71.9 (68.1)

Raw Water Makeup

– 112.2 (106.3)

– 112.2 (106.3)

Limestone

– 0.48 (0.46)

– 0.48 (0.46)

Auxiliary Power

– – 329 (311) 329 (311)

TOTAL 6,100

(5,781) 189.6 (179.7) 329 (311) 6,618 (6,273)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash

– 0.5 (0.4)

– 0.5 (0.4)

Fly Ash + FGD Ash

– 2.5 (2.4)

– 2.5 (2.4)

Stack Gas

– 316 (300)

– 316 (300)

Sulfur 2.1 (1.9) 0.0 (0.0)

– 2.1 (2.0)

Motor Losses and Design

Allowances – – 44 (42) 44 (42)

Condenser

– 1,867 (1,770)

– 1,867 (1,770)

Non

- Condenser Coolin g

Tower Loads – 106 (100)

– 106 (100)

CO
2 – - 98.8 (

- 93.6)

– - 98.8 (

- 93.6)

Cooling Tower Blowdown

– 50.4 (47.8)

– 50.4 (47.8)

CO
2 Capture Losses

– 1,970 (1,868)

– 1,970 (1,868)

Ambient Losses A



### – 133.5 (126.5)

– 133.5 (126.5)

Power

– – 2,309 (2,189) 2,309 (2,189)

TOTAL 2.1 (1.9) 4,347 (4,120) 2,353 (2,231) 6,703 (6,353)

Unaccounted Energy B



### – - 85 (

- 80)

– - 85 (

- 80)

A 

### Ambient losses include all losses to the environment through radiation, convection, etc. Sources of these

losses include the boiler, reheater, superheater, and transformers.

B 

### By di fference



## 3.3.9 Case B12B

– Major Equipment List

Major equipment items for the SC PC plant 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 3.3.10 . In general, the design conditions include a 10 percent contingency

for flows and heat duties and a 21 percent contingency for heads on pumps and fans.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 149 Case B12B

– Account 1: Coal and Sorbent Handling

Equipmen

t No. Descripti on Type Design Condition Operating

Qty. Spares

1 Bottom Trestle Dumper and

Receiving Hoppers N/A 180 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 Transfer Tower No. 1 Enclosed N/A 1 0

5 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

6 As

- Received Coal Sampling System Two

- stage N/A 1 0

7 Stacker/Reclaimer Traveling,

linear 1,130 tonne/hr (1,250 tph) 1 0

8 Reclaim Hopper N/A 50 tonne (50 ton) 2 1

9 Feeder Vibratory 190 tonne/h r (200 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 370 tonne/hr (410 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 190 tonne (200 ton) 2 0

13 Crusher Impactor

reduction 8 cm x 0

- 3 cm x 0

(3 in x 0

- 1

- 1/4 in x 0) 2 0

14 As

- Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 370 tonne/hr (410 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 370 tonne/hr (410 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide

Gates Field erected 820 tonne (900 ton) 3 0

19 Activated Carbon Storage Silo and

Feeder System Shop

assembled Silo

- 35 tonne (38 ton)

Feeder

- 140 kg/hr (320

lb/hr) 1 0

20 Hydrated Lime Storage Silo and

Feeder System Shop

assembled Silo

- 240 tonn e (260 ton)

Feeder

- 4,980 kg/hr

(10,990 lb/hr) 1 0

21 Limestone Truck Unloading Hopper N/A 30 tonne (40 ton) 1 0

22 Limestone Feeder Belt 90 tonne/hr (100 tph) 1 0

23 Limestone Conveyor No. L1 Belt 90 tonne/hr (100 tph) 1 0

24 Limestone Reclaim Hopper N/A 20 tonne (20 ton) 1 0

25 Limestone Reclaim Feeder Belt 70 tonne/hr (80 tph) 1 0

26 Limestone Conveyor No. L2 Belt 70 tonne/hr (80 tph) 1 0

27 Limestone Day Bin w/ actuator 290 tonne (320 ton) 2 0



## Case B12B

– Account 2: Coal and Sorbent Preparation and Feed

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Coal Feeder Gravimetric 40 tonne/hr (50 tph) 6 0

2 Coal Pulverizer Ball type or

equivalent 40 tonne/hr (50 tph) 6 0

3 Limestone Weigh Feeder Gravimetric 24 tonne/hr (27 tp h) 1 1

4 Limestone Ball Mill Rotary 24 tonne/hr (27 tph) 1 1

5 Limestone Mill Slurry Tank

with Agitator N/A 93,100 liters (25,000 gal) 1 1

6 Limestone Mill Recycle

Pumps Horizontal centrifugal 1,570 lpm @ 10m H

2 O

(410 gpm @ 40 ft H

2 O) 1 1

7 Hydroclone Classifier 4 active cyclones in a

5 cyclone bank 390 lpm (100 gpm)

per cyclone 1 1

8 Distribution Box 2

- way N/A 1 1

9 Limestone Slurry Storage

Tank with Agitator Field erected 528,000 liters (140,000

gal) 1 1

10 Limestone Slurry Feed Pumps Horizontal centrifugal 1,100 lpm @ 9m H

2 O

(290 gpm @ 30 ft H

2 O) 1 1Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 150 Case B12B

– Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Deminera lized Water

Storage Tank Vertical, cylindrical,

outdoor 265,000 liters (70,000 gal) 2 0

2 Condensate Pumps Vertical canned 17,300 lpm @ 200 m H

2 O

(4,600 gpm @ 600 ft H

2 O) 1 1

3 Deaerator and Storage

Tank Horizontal spray type 2,208,000 kg/hr

(4,868,000 lb/hr),

5 min. tank 1 0

4 Boiler Feed

Pump/Turbine Barrel type, multi

- stage,

centrifugal 37,000 lpm @ 3,500 m H

2 O

(9,800 gpm @ 11,400 ft

H 2 O) 1 1

5 Startup Boiler Feed

Pump, Electric Motor

Driven Barrel type, multi

- stage,

centrifugal 11,000 lpm @ 3,50 0 m H 2 O

(2,900 gpm @ 11,400 ft

H 2 O) 1 0

6 LP Feedwater Heater

1A/1B Horizontal U

- tube 510,000 kg/hr

(1,130,000 lb/hr) 2 0

7 LP Feedwater Heater

2A/2B Horizontal U

- tube 510,000 kg/hr

(1,130,000 lb/hr) 2 0

8 LP Feedwater Heater

3A/3B Horizontal U

- tube 510,000 kg/hr

(1,130,000 lb/hr) 2 0

9 LP Feedwater Heater

4A/4B Horizontal U

- tube 510,000 kg/hr

(1,130,000 lb/hr) 2 0

10 HP Feedwater Heater 6 Horizontal U

- tube 2,200,000 kg/hr

(4,860,000 lb/hr) 1 0

11 HP Feedwater Heater 7 Horizontal U

- tube 2,200,00 0 kg/hr

(4,860,000 lb/hr) 1 0

12 HP Feedwater heater 8 Horizontal U

- tube 2,200,000 kg/hr

(4,860,000 lb/hr) 1 0

13 Auxiliary Boiler Shop fabricated, water

tube 20,000 kg/hr, 2.8 MPa,

343°C (40,000 lb/hr, 400

psig, 650°F) 1 0

14 Fuel Oil System No. 2 fu el oil for light off 1,135,624 liter (300,000 gal) 1 0

15 Service Air Compressors Flooded Screw 28 m 3 / min @ 0.7 MPa

(1,000 scfm @ 100 psig) 2 1

16 Instrument Air Dryers Duplex, regenerative 28 m 3 / min (1,000 scfm) 2 1

17 Closed Cycle Cooling

Heat Exchan gers Shell and tube 53 GJ/hr (50 MMBtu/hr)

each 2 0

18 Closed Cycle Cooling

Water Pumps Horizontal centrifugal 20,800 lpm @ 30 m H

2 O

(5,500 gpm @ 100 ft H

2 O) 2 1

19 Engine

- Driven Fire

Pump Vertical turbine, diesel

engine 3,785 lpm @ 88 m H

2 O

(1,000 gpm @ 290 ft H

2 O) 1 1

20 Fire Service Booster

Pump Two

- stage horizontal

centrifugal 2,650 lpm @ 64 m H

2 O

(700 gpm @ 210 ft H

2 O) 1 1

21 Raw Water Pumps Stainless steel, single

suction 8,630 lpm @ 20 m H

2 O

(2,280 gpm @ 60 ft H

2 O) 2 1

22 Ground Water Pumps Stainless steel, single

suction 3,450 lpm @ 270 m H

2 O

(910 gpm @ 880 ft H

2 O) 5 1

23 Filtered Water Pumps Stainless steel, single

suction 2,080 lpm @ 50 m H

2 O

(550 gpm @ 160 ft H

2 O) 2 1

24 Filtered Water Tank Vertical, cylindrical 1,999,000 liter (528,000 gal) 1 0

25 Makeup Water

Demineralizer Multi

- media filter,

cartridge filter, RO

membrane assembly,

electrodeionization unit 360 lpm (90 gpm) 1 1

26 Liquid Waste Treatment

System -- 10 years, 24

- hour storm 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 151 Case B12B

– Account 4: Boiler and Accessories

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Boiler Supercritical, drum, wall

fired, low NOx burne rs,

overfire air 2,200,000 kg/hr steam

@ 25.5 MPa/602°C/602°C

(4,860,000 lb/hr steam

@ 3,700 psig/1,115°F/1,115°F) 1 0

2 Primary Air Fan Centrifugal 302,000 kg/hr, 4,100 m 3 / min

@ 123 cm WG

(666,000 lb/hr, 145,600 acfm

@ 48 in. WG) 2 0

3 Forced Draft

Fan Centrifugal 984,000 kg/hr, 13,400 m 3 / min

@ 47 cm WG

(2,169,000 lb/hr, 474,100 acfm

@ 19 in. WG) 2 0

4 Induced Draft

Fan Centrifugal 1,419,000 kg/hr, 28,200 m 3 / min

@ 89 cm WG

(3,128,000 lb/hr, 994,100 acfm

@ 35 in. WG) 2 0

5 SCR Reactor

Vessel Space for spare layer 2,840,000 kg/hr (6,260,000 lb/hr) 2 0

6 SCR Catalyst

-- -- 3 0

7 Dilution Air

Blower Centrifugal 160 m 3 / min @ 108 cm WG

(5,600 acfm @ 42 in. WG) 2 1

8 Ammonia

Storage Horizontal tank 174,000 liter (46,000 gal) 5 0

9 Ammonia Feed

Pump Centrifugal 33 lpm @ 90 m H

2 O

(9 gpm @ 300 ft H

2 O) 2 1



## Case B12B

– Account 5A: Flue Gas Cleanup

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Fabric Filter Single stage, high

- ratio

with pulse

- jet online

cleaning system 1,4 19,000 kg/hr (3,129,000

lb/hr) 99.9% efficiency 2 0

2 Absorber Module Counter

- current open

spray 57,000 m 3 / min

(1,999,000 acfm) 1 0

3 Recirculation Pumps Horizontal centrifugal 197,000 lpm @ 65 m H

2 O

(52,000 gpm @ 210 ft H

2 O) 5 1

4 Bleed Pumps Horizon tal centrifugal 4,790 lpm (1,260 gpm)

at 20 wt% solids 2 1

5 Oxidation Air Blowers Centrifugal 100 m 3 / min @ 0.3 MPa

(3,510 acfm @ 37 psia) 2 1

6 Agitators Side entering 50 hp 5 1

7 Dewatering Cyclones Radial assembly, 5 units

each 1,190 lpm (320 gpm) per cyclone 2 0

8 Vacuum Filter Belt Horizontal belt 38 tonne/hr (42 tph) of 50 wt

% slurry 2 1

9 Filtrate Water Return

Pumps Horizontal centrifugal 730 lpm @ 13 m H

2 O

(190 gpm @ 40 ft H

2 O) 1 1

10 Filtrate Water Return

Storage Tank Vertical, lined 480,000 lpm (130,000 gal) 1 0

11 Process Makeup

Water Pumps Horizontal centrifugal 3,820 lpm @ 21 m H

2 O

(1,010 gpm @ 70 ft H

2 O) 1 1

12 Activated Carbon

Injectors --- 14 0 kg/hr ( 320 lb/hr) 1 0

13 Hydrated Lime

Injectors --- 4,980 kg/hr (10,990 lb/hr) 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 152 Case B12B

– Account 5B: Carbon Dioxide Recovery

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Cansolv Amine

- based CO
2 capture technology 1,49 4,000 kg/hr (3,294,000 lb/hr)

19.6 wt % CO
2 concentration 1 0

2 Cansolv LP

Condensate

Pump Centrifugal 1,098 lpm @ 1 m H

2 O

(290 gpm @ 4 ft H

2 O) 1 1

3 Cansolv HP

Condensate

Pump Centrifugal 1,099 lpm @ 1.1 m H

2 O (290 gpm

@ 4 ft H

2 O) 1 1

4 CO
2 Dryer Trie thylene glycol Inlet: 127.0 m 3 / min (4,469 acfm) @

3.0 MPa (439 psia) Outlet: 2.9 MPa

(419 psia) Water Recovered: 352

kg/hr (776 lb/hr) 1 0

5 CO
2 Compressor Integrally geared,

multi

- stage

centrifugal 264,163 kg/hr @ 15.3 MPa

(582,381 lb/hr @ 2,215 psia) 2 0



## Case B12B

– Account 7: Ducting and Stack

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Stack Reinforced concrete

with FRP liner 152 m (500 ft) high x

5.5 m (18 ft) diameter 1 0



## Case B12B

– Account 8: Steam Turbine Generator and Auxiliaries

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Steam

Turbine Commercially available

advanced steam turbine 675 MW

24.1 MPa/593°C/593°C (3500 psig/

1100°F/1100°F) 1 0

2 Steam

Turbine

Generator Hydrogen cooled, stat ic

excitation 750 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 1 0

3 Surface

Condenser Single pass, divided

waterbox including

vacuum pumps 2,050 GJ/hr

(1,950 MMBtu/hr),

Inlet water temperature 16°C

(60°F),

Water temperature rise 11°C (20°F) 1 0



## Case B12B

– Account 9: Cooling Water System

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Circulating

Water Pumps Vertical, wet pit 778,000 lpm @ 30 m

(206,000 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 /

4340 GJ/hr (4110 MMBtu/hr) heat duty 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 153 Case B12B

– Account 10: Ash and Spent Sorbent Recovery and Handling

Equipmen

t No. Description Type Design Condition Operating

Qty. Spares

1 Economizer Hopper (part of boiler scope

of supply) -- -- 4 0

2 Bottom Ash Hopper (part of boiler scope of

supply) -- -- 2 0

3 Clinker Grinder

-- 4.8 tonne/hr (5.3 tph) 1 1

4 Pyrites Hopper (part of pulverizer scope of

supply included with boiler) -- -- 6 0

5 Hyd roejectors

-- -- 12

6 Economizer /Pyrites Transfer Tank

-- -- 1 0

7 Ash Sluice Pumps Vertical,

wet pit 190 lpm @ 17 m H

2 O

(50 gpm @ 56 ft H

2 O) 1 1

8 Ash Seal Water Pumps Vertical,

wet pit 7,570 lpm @ 9 m H

2 O

(2000 gpm @ 28 ft

H 2 O) 1 1

9 Hydrobins

-- 190 lpm (50 gpm) 1 1

10 Baghouse Hopper (part of baghouse

scope of supply) -- -- 24 0

11 Air Heater Hopper (part of boiler scope of

supply) -- -- 10 0

12 Air Blower

-- 20 m 3 / min @ 0.2 MPa

(790 scfm @ 24 psi) 1 1

13 Fly Ash Silo Reinforce

d concrete 1, 500 tonne (1,600 ton) 2 0

14 Slide Gate Valves

-- -- 2 0

15 Unloader

-- -- 1 0

16 Telescoping Unloading Chute

-- 140 tonne/hr (150 tph) 1 0



## Case B12B

– Account 11: Accessory Electric Plant

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 STG Transformer Oil

- filled 24 kV/345 kV, 650

MVA, 3

- ph, 60 Hz 1 0

2 High Voltage Transformer Oil

- filled 345 kV/13.8 kV, 20

MVA, 3

- ph, 60 Hz 2 0

3 Medium Voltage Transformer Oil

- filled 24 kV/4.16 kV, 99

MVA, 3

- ph, 60 Hz 1 1

4 Low Voltage Transf ormer Dry ventilated 4.16 kV/480 V, 15

MVA, 3

- ph, 60 Hz 1 1

5 STG Isolated Phase Bus Duct

and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 1 0

6 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 1

7 Low Voltage Switchgear Metal enclosed 48 0 V, 3

- ph, 60 Hz 1 1

8 Emergency Diesel Generator Sized for emergency

shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 0



## Case B12B

– 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

- Processor Microprocessor with redundant

input/output N/A 1 0

3 DCS

- Data

Highway Fiber optic Fully redundant, 25% spare 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 154 

## 3.3.10 Case B12B

– Cost Estimating Basis

The cost estimating methodology was described previously in Section 2.7

. Exhibit 3

- 64 shows a

detailed brea kdown of the capital costs ; Exhibit 3

- 65 shows the owner’s costs , TOC, and TASC ;

Exhibit 3

- 66 shows the initial and annual O&M costs; and Exhibit 3

- 67 shows the COE

breakdown.

The estimated TP C of the SC PC boiler with CO 2 

## capture is $ 3,524 /kW. Process contingency

represents 3. 3 percent of the TP C and project contingency represents 12.2 percent. The COE,

including CO 2 

## T&S costs of $ 9.6 / M Wh, is $ 142.8 /M Wh.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 155 Exhibit 3

- 64 Case B12B total plant cost details

Case: B12B

– Supercritical PC w/ CO 2 Estimate Type: Conceptual

Plant Size (MW,net): 550 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 $4,601 $0 $2,073 $0 $6,674 $667 $0 $1,101 $8,443 $15

1.2 Coal Stackout & Reclaim $5,946 $0 $1,329 $0 $7,275 $728 $0 $1,200 $9,203 $17

1.3 Coal Conveyors $5,529 $0 $1,315 $0 $6,843 $684 $0 $1,129 $8,657 $ 16

1.4 Other Coal Handling $1,446 $0 $304 $0 $1,751 $175 $0 $289 $2,215 $4

1.5 Sorbent Receive & Unload $184 $0 $55 $0 $239 $24 $0 $39 $302 $1

1.6 Sorbent Stackout & Reclaim $2,976 $0 $538 $0 $3,513 $351 $0 $580 $4,444 $8

1.7 Sorbent Conveyors $1,062 $ 231 $257 $0 $1,549 $155 $0 $256 $1,960 $4

1.8 Other Sorbent Handling $641 $151 $332 $0 $1,124 $112 $0 $185 $1,422 $3

1.9 Coal & Sorbent Hnd. Foundations $0 $5,333 $7,031 $0 $12,364 $1,236 $0 $2,040 $15,640 $28

Subtotal $22,386 $5,714 $13,233 $0 $41,333 $4,133 $0 $6,820 $52,286 $95

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying $2,656 $0 $510 $0 $3,166 $317 $0 $522 $4,005 $7

2.2 Coal Conveyor to Storage $6,799 $0 $1,464 $0 $8,263 $826 $0 $1,363 $10,453 $19

2.5 Sorbent Prep Equipment $5,063 $219 $1,037 $0 $6,320 $632 $0 $1,043 $7,994 $15

2.6 Sorbent Storage & Feed $610 $0 $230 $0 $840 $84 $0 $139 $1,063 $2

2.9 Coal & Sorbent Feed Foundation $0 $618 $542 $0 $1,160 $116 $0 $191 $1,468 $3

Subtotal $15,128 $837 $3,784 $0 $19,749 $1,975 $0 $3, 259 $24,983 $45

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $25,158 $0 $8,112 $0 $33,270 $3,327 $0 $5,489 $42,086 $76

3.2 Water Makeup & Pretreating $7,114 $0 $2,250 $0 $9,365 $936 $0 $2,060 $12,361 $22

3.3 Other Feedwater Subsystems $7,914 $0 $3,249 $0 $11,163 $1,116 $0 $1,842 $14,121 $26

3.4 Service Water Systems $1,425 $0 $746 $0 $2,170 $217 $0 $477 $2,865 $5

3.5 Other Boiler Plant Systems $9,820 $0 $9,284 $0 $19,103 $1,910 $0 $3,152 $24,166 $44

3.6 FO Supply Sys & Nat Gas $347 $0 $405 $0 $752 $75 $0 $124 $951 $2

3.7 Waste Treatment Equipment $4,667 $0 $2,702 $0 $7,369 $737 $0 $1,621 $9,727 $18

3.8 Misc. Equip. (Cranes, Air Comp.,

Comm.) $3,398 $0 $1,051 $0 $4,449 $445 $0 $979 $5,873 $11

Subtotal $59,843 $0 $27,798 $0 $87,641 $8,764 $0 $15,745 $112,150 $204

4 Boiler & Accessories

4.1 PC Boiler & Accessories $211,004 $0 $120,229 $0 $331,234 $33,123 $0 $36,436 $400,793 $728

4.2 SCR $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0

Subtotal $211,004 $0 $120,229 $0 $331,234 $33,123 $0 $36,436 $400,793 $728

5A Gas Cleanup & Piping

5A.1 Absorber Vessels & Accessories $79,487 $0 $16,995 $0 $96,482 $9,648 $0 $10,613 $116,743 $212

5A.2 Other FGD $4,148 $0 $4,668 $0 $8,816 $882 $0 $970 $10,668 $19Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 156 Case: B12B

– Supercritical PC w/ CO 2 Estimate Type: Conceptual

Plant Size (MW,net): 550 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.3 Bag House & Accessories $22,779 $0 $14,358 $0 $37,1 37 $3,714 $0 $4,085 $44,936 $82

5A.4 Other Particulate Removal Materials $1,542 $0 $1,638 $0 $3,180 $318 $0 $350 $3,848 $7

5A.5 Gypsum Dewatering System $6,185 $0 $1,043 $0 $7,229 $723 $0 $795 $8,747 $16

5A.6 Mercury Removal System $4,702 $1,034 $4,623 $0 $10,359 $1,036 $0 $1,139 $12,534 $23

Subtotal $118,843 $1,034 $43,325 $0 $163,202 $16,320 $0 $17,952 $197,475 $359

5B CO 2 Removal & Compression

5B.1 CO
2 Removal System $167,289 $61,389 $131,144 $0 $359,822 $31,060 $62,120 $80,756 $533,757 $970

5B. 2 CO
2 Compression & Drying $50,211 $7,532 $16,788 $0 $74,531 $7,453 $0 $16,397 $98,381 $179

Subtotal $217,500 $68,921 $147,932 $0 $434,354 $38,513 $62,120 $97,152 $632,139 $1,149

7 HRSG, Ducting, & Stack

7.3 Ductwork $11,042 $0 $6,970 $0 $18,013 $1,80 1 $0 $2,972 $22,786 $41

7.4 Stack $9,983 $0 $5,801 $0 $15,784 $1,578 $0 $1,736 $19,099 $35

7.9 Duct & Stack Foundations $0 $1,088 $1,292 $0 $2,380 $238 $0 $524 $3,142 $6

Subtotal $21,025 $1,088 $14,064 $0 $36,177 $3,618 $0 $5,232 $45,027 $82

8 Steam Turbine Generator

8.1 Steam TG & Accessories $79,100 $0 $8,815 $0 $87,915 $8,791 $0 $9,671 $106,377 $193

8.2 Turbine Plant Auxiliaries $450 $0 $958 $0 $1,408 $141 $0 $155 $1,704 $3

8.3 Condenser & Auxiliaries $6,997 $0 $2,374 $0 $9,370 $937 $0 $1,031 $1 1,338 $21

8.4 Steam Piping $30,410 $0 $12,325 $0 $42,735 $4,273 $0 $7,051 $54,060 $98

8.9 TG Foundations $0 $1,342 $2,217 $0 $3,559 $356 $0 $783 $4,698 $9

Subtotal $116,957 $1,342 $26,688 $0 $144,987 $14,499 $0 $18,690 $178,176 $324

9 Cooling Water S ystem

9.1 Cooling Towers $15,466 $0 $4,783 $0 $20,250 $2,025 $0 $2,227 $24,502 $45

9.2 Circulating Water Pumps $3,102 $0 $228 $0 $3,330 $333 $0 $366 $4,030 $7

9.3 Circ. Water System Auxiliaries $811 $0 $107 $0 $918 $92 $0 $101 $1,111 $2

9.4 Circ. Water Piping $0 $6,831 $6,186 $0 $13,016 $1,302 $0 $2,148 $16,466 $30

9.5 Make

- up Water System $685 $0 $880 $0 $1,565 $157 $0 $258 $1,980 $4

9.6 Component Cooling Water Sys. $661 $0 $507 $0 $1,168 $117 $0 $193 $1,478 $3

9.9 Circ. Water Foundations & Structur es $0 $3,613 $5,999 $0 $9,612 $961 $0 $2,115 $12,688 $23

Subtotal $20,725 $10,443 $18,691 $0 $49,860 $4,986 $0 $7,408 $62,254 $113

10 Ash & Spent Sorbent Handling Systems

10.6 Ash Storage Silos $882 $0 $2,698 $0 $3,579 $358 $0 $394 $4,331 $8

10.7 Ash Transport & Feed Equipment $5,856 $0 $5,806 $0 $11,662 $1,166 $0 $1,283 $14,111 $26

10.9 Ash/Spent Sorbent Foundation $0 $199 $245 $0 $444 $44 $0 $98 $586 $1

Subtotal $6,738 $199 $8,748 $0 $15,685 $1,569 $0 $1,774 $19,028 $35

11 Accessory Electric Pl ant

11.1 Generator Equipment $2,061 $0 $329 $0 $2,390 $239 $0 $197 $2,826 $5

11.2 Station Service Equipment $5,290 $0 $1,773 $0 $7,063 $706 $0 $583 $8,352 $15

11.3 Switchgear & Motor Control $6,072 $0 $1,055 $0 $7,126 $713 $0 $784 $8,623 $16

11.4 Cond uit & Cable Tray $0 $4,164 $13,452 $0 $17,616 $1,762 $0 $2,907 $22,284 $41

11.5 Wire & Cable $0 $7,928 $14,171 $0 $22,100 $2,210 $0 $3,646 $27,956 $51

11.6 Protective Equipment $306 $0 $1,063 $0 $1,370 $137 $0 $151 $1,658 $3Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 157 Case: B12B

– Supercritical PC w/ CO 2 Estimate Type: Conceptual

Plant Size (MW,net): 550 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

11.7 Standby Equipment $1,57 1 $0 $37 $0 $1,608 $161 $0 $177 $1,945 $4

11.8 Main Power Transformers $14,769 $0 $221 $0 $14,990 $1,499 $0 $1,649 $18,138 $33

11.9 Electrical Foundations $0 $385 $980 $0 $1,365 $136 $0 $300 $1,802 $3

Subtotal $30,069 $12,477 $33,082 $0 $75,628 $7,563 $0 $10,394 $93,584 $170

12 Instrumentation & Control

12.1 PC Control Equipment w/12.7 $0 w/12.7 $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

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $611 $0 $373 $0 $984 $98 $49 $170 $1,301 $2

12.7 Distributed Control Sys. Equipment $6,164 $0 $1,099 $0 $7,263 $726 $363 $835 $9,188 $17

12.8 Instrument Wiring & Tubing $3,717 $0 $6,763 $0 $10,480 $1,048 $524 $1,808 $ 13,860 $25

12.9 Other I & C Equipment $1,742 $0 $4,033 $0 $5,775 $577 $289 $664 $7,305 $13

Subtotal $12,233 $0 $12,269 $0 $24,502 $2,450 $1,225 $3,477 $31,654 $58

13 Improvements to Site

13.1 Site Preparation $0 $62 $1,316 $0 $1,378 $138 $0 $303 $1,8 19 $3

13.2 Site Improvements $0 $2,053 $2,713 $0 $4,766 $477 $0 $1,049 $6,291 $11

13.3 Site Facilities $3,680 $0 $3,860 $0 $7,540 $754 $0 $1,659 $9,953 $18

Subtotal $3,680 $2,115 $7,889 $0 $13,684 $1,368 $0 $3,010 $18,063 $33

14 Buildings & Structure s

14.1 Boiler Building $0 $10,432 $9,168 $0 $19,599 $1,960 $0 $3,234 $24,793 $45

14.2 Turbine Building $0 $15,048 $14,015 $0 $29,063 $2,906 $0 $4,795 $36,765 $67

14.3 Administration Building $0 $762 $806 $0 $1,568 $157 $0 $259 $1,984 $4

14.4 Circulatio n Water Pumphouse $0 $208 $165 $0 $373 $37 $0 $62 $472 $1

14.5 Water Treatment Buildings $0 $887 $808 $0 $1,696 $170 $0 $280 $2,145 $4

14.6 Machine Shop $0 $510 $342 $0 $852 $85 $0 $141 $1,078 $2

14.7 Warehouse $0 $346 $346 $0 $692 $69 $0 $114 $875 $2

14.8 Other Buildings & Structures $0 $282 $240 $0 $523 $52 $0 $86 $661 $1

14.9 Waste Treating Building & Str. $0 $541 $1,639 $0 $2,180 $218 $0 $360 $2,758 $5

Subtotal $0 $29,016 $27,530 $0 $56,547 $5,655 $0 $9,330 $71,531 $130

Total $856,131 $133,187 $505,263 $0 $1,494,582 $144,536 $63,345 $236,680 $1,939,143 $3,524Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 158 Exhibit 3

- 65 Case B12B owner’s costs

Description $ / 1,000 $/kW

Pre

- Production Costs

6 Months All Labor $12,156 $22

1 Month Maintenanc e Materials $1,774 $3

1 Month Non

- fuel Consumables $3,605 $7

1 Month Waste Disposal $539 $1

25% of 1 Months Fuel Cost at 100% CF $3,099 $6

2% of TPC $38,783 $70

Total $59,957 $109

Inventory Capital

60 day supply of fuel and consumables at 100% CF $3 1,429 $57

0.5% of TPC (spare parts) $9,696 $18

Total $41,125 $75

Other Costs

Initial Cost for Catalyst and Chemicals $0 $0

Land $900 $2

Other Owner's Costs $290,871 $529

Financing Costs $52,357 $95

Total Overnight Costs (TOC) $2,384,352 $4,333

TAS C Multiplier (IOU, high

- risk, 35 year) 1.140

Total As

- Spent Cost (TASC) $2,718,161 $4,940Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 159 Exhibit 3

- 66 Case B12B initial and annual operating and maintenance costs

Case: B12B

– Supercritical PC w/o C O 2 Cost Base: Jun 2011

Plant Size (MW,net): 550 Heat Rate

- net (Btu/kWh): 10,508 Capacity Factor (%): 85

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: 11.3

Labor O

- H Charge Rate: 25.00 % of labor Foreman: 1.0

Lab Tech's, etc.: 2.0

Total: 16.3

Fixed Operating Costs

Annual Cost

($) ($/kW

- net)

Annual Operating Labo r: $7,384,208 $13.421

Maintenance Labor: $12,065,150 $21.928

Administrative & Support Labor: $4,862,340 $8.837

Property Taxes and Insurance: $38,782,850 $70.487

Total: $63,094,548 $114.673

Variable Operating Costs

($) ($/M Wh

- net)

Maintenance Material: $18,097,725 $4.41742

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 5,675 $1.67 $0 $2,947,503 $0.71945

Makeup and Waste Water

Treatment Chemicals (lbs): 0 27,4 72 $0.27 $0 $2,282,848 $0.55721

Limestone (ton) 0 588 $33.48 $0 $6,103,937 $1.48989

Hydrated Lime (ton) 0 120 $155.00 $0 $5,763,495 $1.40679

Activated Carbon (ton) 0 3 $1,255.00 $0 $1,347,742 $0.32897

CO 2 Capture System Chemicals A Proprietary

Trieth ylene Glycol (gal) 0 394 $6.57 $0 $802,687 $0.19593

Ammonia (19% NH 3 , ton) 0 87 $330.00 $0 $8,943,423 $2.18297

SCR Catalyst (m 3 ) 0 0.39 $8,938.80 $0 $1,092,946 $0.26677

Subtotal: $0 $36,775,427 $8.97641

Waste Disposal

Fly Ash (ton) 0 589 $25.11 $0 $4,590,762 $1.12055

Bottom Ash (ton) 0 116 $25.11 $0 $903,048 $0.22042

Amine Purification Unit Waste (ton) 0 20 $0.00 $0 $0 $0.00000

Thermal Reclaimer Unit Waste (ton) 0 2 $0.00 $0 $0 $0.00000

Prescrubber Blowdown Waste (ton) 0 45 $0.00 $0 $0 $0.00000

Subtotal: $0 $5,493,809 $1.34097

By

- Products

Gypsum (ton) 0 101 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000

Variable Operating Costs Total: $0 $60,366,961 $14.73480

Fuel Cost

Illinois Number 6 (ton): 0 5,947 $68.54 $0 $126,458,921 $30.86699

Total: $0 $126,458,921 $30.86699

A 

### CO 2 

### Capture System Chemicals includes Ion Exchange Resin, NaOH, and Cansolv Solvent.

Exhibit 3

- 67 Case B 12B COE breakdown

Component Value, $/MWh Percentage

Capital 72.2 51%

Fixed 15.4 11%

Variable 14.7 10%

Fuel 30.9 22%

Total (Excluding T&S) 133.2 N/A

CO 2 

### T&S 9.6 7%

Total (Including T&S) 142.8 N/ACost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 160 

# 3.4 PC Case Summary

The performance results of the four PC plant configurations are summarized in Exhibit 3

- 68

.

Exhibit 3

- 68 Estimated performance and cost results for PC cases

Pulverized Coal Boiler

PC Subcritical PC Supercritical

Case B11A Case B11B Case B12A Case B12B

PERFORMA NCE

Nominal CO 2 Capture 0% 90% 0% 90%

Capacity Factor 85% 85% 85% 85%

Gross Power Output (MWe) 581 644 580 642

Auxiliary Power Requirement (MWe) 31 94 30 91

Net Power Output (MWe) 550 550 550 550

Coal Flow rate (lb/hr) 412,005 516,170 395,053 495,578

Natural Gas Flow rate (lb/hr) N/A N/A N/A N/A

HHV Thermal Input (kW t 

### ) 1,408,630 1,764,768 1,350,672 1,694,366

Net Plant HHV Efficiency (%) 39.0% 31.2% 40.7% 32.5%

Net Plant HHV Heat Rate (Btu/kWh) 8,740 10,953 8,379 10,508

Raw Water Withdrawal, gpm 5 ,538 8,441 5,105 7,882

Process Water Discharge, gpm 1,137 1,920 1,059 1,813

Raw Water Consumption, gpm 4,401 6,521 4,045 6,069

CO 2 Emissions (lb/MMBtu) 204 20 204 20

CO 2 Emissions (lb/MWh

- gross) 1,683 190 1,618 183

CO 2 Emissions (lb/MWh

- net) 1,779 223 1,705 214

SO 2 Emissions (lb/MMBtu) 0.085 0.000 0.085 0.000

SO 2 Emissions (lb/MWh

- gross) 0.700 0.000 0.673 0.000

NOx Emissions (l b/MMBtu) 0.085 0.075 0.088 0.078

NOx Emissions (lb/MWh

- gross) 0.700 0.700 0.700 0.700

PM Emissions (lb/MMBtu) 0.011 0.010 0.011 0.010

PM Emissions (lb/MWh

- gross) 0.090 0.090 0.090 0.090

Hg Emissions (lb/TBtu) 0.363 0.321 0.377 0.333

Hg Emissions (lb/M Wh

- gross) 3.00E

- 06 3.00E

- 06 3.00E

- 06 3.00E

- 06

COST

Total Plant Cost (2011$/kW) 1,960 3,467 2,026 3,524

**Bare Erected Cost** 1,582 2,665 1,646 2,716

**Home Office Expenses** 158 257 165 263

**Project Contingency** 220 427 216 430

**Process Contingency** 0 118 0 115

T otal Overnight Cost (2011$/MM ) 1,336 2,346 1,37 9 2,384

Total Overnight Cost (2011$/kW) 2,429 4,267 2,507 4,333

**Owner's Costs** 469 800 480 809

Total As

- Spent Cost (2011$/kW) 2,755 4,865 2,842 4,940

COE ( $/MWh ) (excluding T&S) 82.1 133.5 82.3 133. 2

**Capital Costs** 37.8 71.1 39.0 72.2

**Fixed Costs** 9.3 15.1 9.6 15.4

**Variable Costs** 9.2 15.1 9.1 14.7

**Fuel Costs** 25.7 32.2 24.6 30.9

**COE ( $/MWh**  **) (including T&S)** 82.1 143.5 82.3 142.8

**CO** 2 **T&S Costs** 0.0 10.0 0.0 9.6Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 161 The following observations can be made regarding plant performance:

• The addition of CO 2 

## capture and compression t o the two PC cases results in an efficiency

penalty of 7.8 absolute percent in the subcritical PC case and 8.2 absolute percent in the

SC PC case. The efficiency is negatively impacted by the large auxiliary loads of the

capture process and CO 2 

## compression, as well as the large increase in cooling water

requirement, which increases the CWP and cooling tower fan a uxiliary loads. The

auxiliary load increases by 63 MW in the subcritical PC case and by 62 MW in the SC

PC case.

• Since the PC cases utilized a wet FGD system, SO 2 

## emissions could be used as a

surrogate for HCl (17) . Provided the SO 2 

## emissions limit is not exceeded, it can be

assumed per the MATS regulation that the HCl emissions limit is also satisfied.

• The SO 2 

## emissions for non

- capture cases are nearly identical

, with the subcritical PC

emissions being higher than SC when nor malized by gross output because of the lower

efficiency. The CO 2 

## capture process polishing scrubber and absorber vessel result in

negligible SO 2 

## emissions in CO 2 

## capture cases.

• Uncontrolled CO 2 

## emissions on a mass basis are greater for subcritical PC comp ared to

SC because of the lower efficiency. The capture cases result in a 90 percent reduction of

carbon for both subcritical and SC PC.

The components of TOC and overall TASC are shown for each PC case in Exhibit 3

- 69

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 162 Exhibit 3

- 69 Plant capital cost for PC cases

Source: NETL



## The following observations about TOC can be made:

• The TOC of the non

- capture SC PC case is approximately 3.2 percent greater than non

captur e subcritical PC. The TOC of SC PC with CO 2 

## capture is approximately 1.6

percent greater than subcritical PC with CO 2 

## capture.

• The TOC penalty for adding CO 2 

## captu re in the subcritical case is 76 percent and is 7 3

percent in the SC case. In addition to t he high cost of the capture process, there is a

significant increase in the cost of the cooling towers and CWPs in the CO 2 

## capture cases

because of the larger cooling water demand discussed previously. Also , the gross output

of the two PC plants increases by 63 MW (subcritical) and 62 MW (SC) to maintain the

net output at 550 MW. The increased gross output results in higher coal flow rate and

consequently higher costs for all cost accounts in the estimate.

The COE is shown for the four PC cases in Exhibit 3

- 70 (including T&S in the capture cases)

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 163 Exhibit 3

- 70 COE for PC cases

Source: NETL

*Cases without capture use conventional financing; all others use high

- risk financial asssump tions

consistent with NETL’s “QGESS: Cost Estimation Methodology for NETL Assessments of Power Plant

Performance.” (1)



## The following observations can be made:

• Capital costs represent the largest fraction of COE in all cases, b ut particularly so in the

CO 2 

## capture cases. Fuel cost is the second largest component of COE, and capital

charges and fuel costs combined represe nt 72 to 77 percent of the total in all cases.

• In the non

- capture cases, the slight increase in capital cost in the SC case is almost offset

by the efficiency gain so that the COE for SC PC is only approximately 0.3 percent more

than subcritical despite having more than a 3 percent greater TOC.

• In the CO 2 

## capture cases, the increase in capital is even lower than in the non

- capture

case and is more than offset by the efficiency gain so that the COE for SC PC is

approximately 0. 2 percent lower than the subcritical case, despite having a TOC that is

nearly 2 percent greater. The COE of the non

- capture subcritical PC case and the non

capture SC PC case is well within the limits of the study accuracy. The same is true of

the two CO 2 

## capture cases.

The sensitivity of COE to capacity factor is shown in Exhibit 3

- 71 . Implicit in the curves is t he

assumption that a capacity factor of greater than 85 percent can be achieved without the

expenditure of additional capital. The subcritical and SC cases are nearly identical making it

difficult to distinguish between the two lines. The COE increases s lightly more rapidly at low

CF because the relatively high capital component is spread over fewer kilowatt

- hours of

generation.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 164 Exhibit 3

- 71 Sensitivity of COE to capacity factor for PC cases

Source: NETL



## COE is relatively insensitive to fuel costs for the PC cases, as shown in Exhibit 3

- 72 . A tripling

of coal price from $1

- $3/MMBtu results in an approximate COE increase of about 26 percent in

the non

- capture cases and 18 percent in the CO 2 

## capture cases.

Exhibit 3

- 72 Sensitivity of COE to coal price for PC cases

Source: NETLCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 165 As presented in Section 2.7.4 the CO 2 

## captured and avoided costs were calcul ated and the results

for the PC CO 2 

## capture cases

– using SC PC as the non

- capture reference case

– are shown in

Exhibit 3

- 73

. T he costs are nearly identical for the subcritical and SC PC cases.

Exhibit 3

- 73 C ost of CO 2 

### captured and avoided in PC cases

Source: NETL



## The normalized water withdrawal, process discharge and raw water consumption are shown

in Exhibit 3

- 74 for each of the PC cases.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 166 Exhibit 3

- 74 Raw water withdrawal and consumption in PC cases

Source: NETL



## Raw water consumption for all cases is dominated by cooling tower makeup requirements, which

accounts for about 81 percent of raw water in non

- capture cases and 85 percent of raw water in

CO 2 

## capture cases. The amount of raw water consumption in the CO 2 

## capture cases is greatly

increased by the cooling water requirements of the capture process. Cooling water is required to:

o Reduce the flue gas temperature from 56°C (133°F) (FGD exit temperature) to

30°C (86°F) (CO 2 

## absorber operating temperature), which also requires

condensing water from the flue gas that co mes saturated from the FGD unit

o Remove the heat input by the stripping steam to cool the solvent

o Remove the heat input from the auxiliary electric loads

o Remove heat in the CO 2 

## compressor intercoolers

In the CO 2 

## capture cases, additional water is recovered from the flue gas as it is co oled to the

absorber temperatur e . The condensate is treate d and used as cooling tower makeup.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 167 

# 4 Natural Gas Combined Cycle Plants

Two NGCC power plant configurations were evaluated and are presented in this section. Each

design is based on a market

- ready technology that is assumed to be commercially ava ilable in

time to support start

- up. Each design con sists of two state

- of

- the

- art 2013 F

- class CTGs, two

HRSG s

, and one STG in a multi

- shaft 2x2x1 configuration.

The NGCC cases are evaluated with and without CO 2 

## capture on a common thermal input basis.

The NGC C designs that include CDR have a smaller plant net output resulting from the

additional CDR facility and CO 2 

## compressors auxiliary loads. T he gross output of the NGCC

cases w as largely determined by the output of the commercially available CT. Hence, e valuation

of the two NGCC designs on a common net output basis was not possible.

The Rankine cycle portion of both designs uses a single reheat 16.5 MPa/566°C/566°C

(2

, 400 psig/1

, 050 ° F/1

, 050 ° F) steam cycle. A more aggressive steam cycle was considered b ut

not chosen because there are very few HRSGs in operation that would support such conditions

. (28)



# 4.1 NGCC Process Areas

The two NGCC cases are nearly identical in configuration with the exception that Case B31B

includes CO 2 

## ca pture while Case B31A does not. The process areas that are common to the two

plant configurations are presented in this section.



## 4.1.1 Natural Gas Supply System

It was assumed that a natural gas main with adequate capacity is in close proximity (within 16

km [1 0 mi]) to the site fence line and that a suitable right

- of

- way is available to install a branch

line to the site. For the purposes of this report it was also assumed that the gas will be delivered

to the plant custody transfer point at 3.0 MPa (435 psig) and 38°C (100oF), which matches the

state

- of

- the

- art 2013 F

- class fuel system requirements. Hence, neither a pressure reducing

station with gas preheating (to prevent moisture and hydrocarbon condensation), nor a fuel

booster compressor is required.

As di scussed in Section 2.4.2 , it was assumed that the natural gas had an added mercaptan

composition of 5.75x10

- 6 

## mol%. (11)

A new gas metering station is assumed to be added on the site, adjacent to the new CT. The

meter may be of the rate

- of

- flow type, with input to the plant computer for summing and

recording, or may be of the positive displacement type. In either case, a complete time line

record of gas consumption rates and cumulative consumption is provided.



## 4.1.2 Combustion Turbine

The combined cycle plant is based on two CTG s. The CTG is representative of the state

- of

- the

art 2013 F

- class turbines with an ISO base rating of 211 M W when firing natural gas (18)

. This

machine is an axial flow, single spool, constant speed unit, with variable IGVs, and dry LNB

combustion system.

Each CTG is provided with inlet air filtration systems

, inlet silencers

, lube and control oil

systems including cooling

, electric motor starting systems

, acoustical enclosures includingCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 168 heating and ventilation

, control systems including supervisory, fire protection, and fuel systems.

No back up fuel was envisioned for th ese cases

.

The CTG is typically supplied in several fully shop

- fabricated modules, co mplete with all

mechanical, electrical, and control systems required for CTG operation. Site CTG installation

involves module interconnection and linking CTG modules to the plant systems. The CTG

package scope of supply for combined cycle application, wh ile project specific, does not vary

much from project

- to

- project. A typical scope of supply is presented in Exhibit 4

- 1

.

Exhibit 4

- 1 Combustion turbine typical scope of supply

Syst em System Scope

ENGINE

ASSEMBLY Coupling to Generator, Dry Chemical Exhaust Bearing Fire Protection System,

Insulation Blankets, Platforms, Stairs and Ladders

Engine Assembly

with Bedplate Variable Inlet Guide Vane System, Compressor, Bleed System, Purge Air System,

Bearing Seal Air System, Combustors, Dual Fuel Nozzles, Turbine Rotor Cooler

Walk

- in acoustical

enclosure HVAC, Lighting, and LP CO 2 Fire Protection System

MECHANICAL

PACKAGE HVAC, Lighting, Air Compressor for Pneumatic System, LP CO 2 Fire P rotection

System

Lubricating Oil

System and

Control Oil System Lube Oil Reservoir, Accumulators, 2x100% AC Driven Oil Pumps, DC Emergency

Oil Pump with Starter, 2x100% Oil Coolers, Duplex Oil Filter, Oil Temperature and

Pressure Control Valves, Oil Vapor Exhaust Fans and Demister, Oil Heaters, Oil

Interconnect Piping (SS and CS), Oil System Instrumentation, Oil for Flushing and

First Filling

ELECTRICAL

PACKAGE HVAC, Lighting, AC and DC Motor Control Centers, Generator Voltage Regulating

Cabinet, Generator Protective Relay Cabinet, DC Distribution Panel, Battery

Charger, Digital Control System with Local Control Panel (all control and

monitoring functions as well as data logger and sequence of events recorder),

Control System Valves and Instrumentation Comm unication link for interface with

plant DCS Supervisory System, Bentley Nevada Vibration Monitoring System, LP

CO 2 Fire Protection System, Cable Tray and Conduit Provisions for Performance

Testing including Test Ports, Thermowells, Instrumentation and DCS interface

cards

INLET AND

EXHAUST

SYSTEMS Inlet Duct Trash Screens, Inlet Duct and Sile ncers, Self

- Cleaning Filters, Hoist

System For Filter Maintenance, Evaporative Cooler System, Exhaust Duct

Expansion Joint, Exhaust Silencers Inlet and Exhaust Flow, Pr essure and

Temperature Ports and Instrumentation

FUEL SYSTEMS

NG System Gas Valves Including Vent, Throttle and Trip Valves, Gas Filter/Separator, Gas

Supply Instruments and Instrument Panel

STARTING

SYSTEM Enclosure, Starting Motor or Static Start Sys tem, Turning Gear and Clutch

Assembly, Starting Clutch, Torque Converter

GENERATOR Static or Rotating Exciter (Excitation transformer to be included for a static

system), Line Termination Enclosure with CTs, VTs, Surge Arrestors, and Surge

Capacitors, Neu tral Cubicle with CT, Neutral Tie Bus, Grounding Transformer, and

Secondary Resistor, Generator Gas Dryer, Seal Oil System (including Defoaming

Tank, Reservoir, Seal Oil Pump, Emergency Seal Oil Pump, Vapor Extractor, and

Oil Mist Eliminator), Generator Au xiliaries Control Enclosure, Generator Breaker,

Iso

- Phase bus connecting generator and breaker, Grounding System Connectors

Generator Cooling Totally Enclosed Water

- to

- Air

- Cooled (TEWAC) System (including circulation

system, interconnecting piping and co ntrols), or Hydrogen Cooling System

(including H 2 to Glycol and Glycol to Air heat exchangers, liquid level detector

circulation system, interconnecting piping and controls)

MISCELLANEOUS Interconnecting Pipe, Wire, Tubing and Cable Instrument Air System Including Air

Dryer On Line and Off Line Water Wash System LP CO 2 Storage Tank Drain

System Drain Tanks Coupling, Coupling Cover and Associated HardwareCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 169 Electrical generators are provided with the CT package. The generators are assumed to be

24 kV, 3

- pha se, 60 Hz , constructed to meet American National Standards Institute (ANSI) and

National Electrical Manufacturers Association (NEMA) standards for turbine

- driven

synchronous generators. The generator is TEWAC, complete with excitation system, cooling,

and protective relaying.



## 4.1.3 Heat Recovery Steam Generator

The HRSG is configured with HP, IP, and LP steam drums, and superheater, reheater, and

economizer sections. The HP drum is supplied with FW by the HP boiler feed pump to generate

HP steam, which passes t o the superheater section for heating to 566°C (1

, 050°F). The IP drum

is supplied with FW by the IP boiler feed pump. The IP steam from the drum is superheated to

482 °C ( 900 °F) and mixed the HP turbine exhaust before being reheated to 566°C (1

, 050oF). T he

combined flows are admitted into the IP section of the steam turbine. The LP drum provides

steam to the LP turbine.

The economizer sections heat condensate and FW (in separate tube bundles). The HRSG tubes

are typically comprised of bare surface and/o r finned tubing or pipe material. The high

temperature portions are type P91 or P22 ferritic alloy material; the low

- temperature portions

( less than 399°C [750°F]) are carbon steel ( CS ) . Each HRSG exhausts directly to the stack,

which is fabricated from CS plate materials and lined with Type 409 SS. The stack for the

NGCC cases is assumed to be 46 m (150 ft) high, and the cost is included in the HRSG account.



## 4.1.4 NOx Control System

Two measures are taken to reduce the NOx. The first is a DLN burner in the C TG. The DLN

burners are a low NOx design and reduce the emissions to about 9 ppmvd (18) (assumed to be

approximately 98 percent NO and referenced to 15 percent O 2 

## )

.

While a state

- of

- the

- art 2013 F

- class CT alone produces NOx e missions below the limits

described in Section 2.4.2 , an SCR was included as a second measure to ensure the plant met the

EPA’s PSD program by installing the BACT.

A SCR uses ammo nia and a catalyst to reduce NO to N 2 

## and H 2 

## O. The SCR system consists of a reactor, and ammonia supply and storage system. The SCR system is designed for 90 percent

reduction while firing natural gas (19)

.

Operation Description

- The SCR reactor is located in the flue g as path inside the HRSG

between the HP and IP sections. The SCR reactor is equipped with one catalyst layer consisting

of catalyst modules stacked in line on a supporting structural frame. The SCR reactor has space

for installation of an additional layer . Ammonia is injected into the gas immediately prior to

entering the SCR reactor. The ammonia injection grid is arranged into several sections, and

consists of multiple pipes with nozzles. The a mmonia flow rate into each injection grid section

is contro lled taking into account imbalances in the flue gas flow distribution across the HRSG.

The catalyst contained in the reactor enhances the reaction between the ammonia and the NOx in

the gas. The catalyst consists of various active materials such as titan ium dioxide, vanadium

pentoxide, and tungsten trioxide. The optimum inlet flue gas temperature range for the catalyst

is 260°C (500 ° F) to 343°C (650 ° F).

The ammonia storage and injection system consists of the unloading facilities, bulk storage tank,

va porizers, and dilution air skid.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 170 

## 4.1.5 Carbon Dioxide Recovery Facility

A CDR facility is used in Case B31B to remove 90 percent of the CO 2 

## in the flue gas exiting the

HRSG, purify it, and compress it to a SC condition. It is assumed that all of the carbon in t he

natural gas is converted to CO 2 

## . The CDR is comprised of flue gas supply, CO 2 

## absorption,

solvent stripping and reclaiming, and CO 2 

## compression and drying.

The CO 2 

## absorption/stripping/solvent reclaim ation process for Case B31B is based on the

Cansolv system, previously described in Section 3.1.8

, with the exception that no SO 2 

## polishing

step is required in the NGCC case , as the pipeline natural gas sulfur content produces a flue gas

with an SO 2 

## content below the concentrati on in the outlet of the polishing scrubber used in the

PC cases.

Any potential advantage that the natural gas case with CO 2 

## capture would have over the coal

cases with CO 2 

## capture due to the significantly lower rate of chloride present in the feedstock

(w hich forms HSS in the CO 2 

## absorber) and SO 2 

## and NOx gases in the flue gas (which

contribute to amine degradation) is minim al as the prescrubber included in the coal cases

removes the majority of these contaminants.

Due to the larger volumetric flow rate in the NGCC case compared to the PC cases (147 million

ft 3 

## /hr in Case B31B and 90 million ft 3 

## /hr in Case B12B) and the low CO 2 

## concentration (4.9

mol% in Case B31B and 12.9 mol% in Case B12B) , the natural gas case requires a CO 2 

## absorber

over 1.5 times as la rge as the coal cases. However, as a result of the lower CO 2 

## content, the CO 2 

## stripper used in Case B31B is only 40 percent of the volume as the one used in Case B12B.



## 4.1.6 Steam Turbine

The steam turbine consists of an HP section, an IP section, and a doubl e

- flow LP section, all

connected to the generator by a common shaft. The HP and IP sections are contained in a single

span, opposed

- flow casing, with the double

- flow LP section in a separate casing.

Main steam from the boiler passes through the stop val ves and control valves and enters the

turbine at 16.5 MPa/566°C (2

, 400 psig/1

, 050°F). The steam initially enters the turbine near the

middle of the HP span, flows through the turbine, and is combined with steam from the IP

superheater before being return e d to the HRSG for reheating. The reheat steam flows through

the reheat stop valves and intercept valves and enters the IP section at 4.2 MPa/566°C

( 608 psia/1

, 050°F). After passing through the IP section, the steam enters a cross

- over pipe,

which transpo rts the steam to the LP section. A branch line equipped with combined

stop/intercept valves conveys LP steam from the HRSG LP drum to a tie

- in at the cross

- over line. The steam divides into two paths and flows through the LP sections exhausting downward

into the condenser.

Turbine bearings are lubricated by a CL, water

- cooled pressurized oil system. Turbine shafts are

sealed against air in

- leakage or steam blowout using a modern positive pressure variable

clearance shaft sealing design arrangement connec ted to a LP steam seal system. The open

- air

cooled generator produces power at 24 kV. A static, transformer type exciter is provided. The

STG is controlled by a triple

- redundant microprocessor

- based electro

- hydraulic control system.

The system provides digital control of the unit in accordance with programmed control

algorithms, color monitor/operator interfacing, and datalink interfaces to the balance

- of

- plant

DCS, and incorporates on

- line repair capability.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 171 

## 4.1.7 Water and Steam Systems

4.1.7.1 Condensate

The funct ion of the condensate system is to pump condensate from the condenser hotwell to the

deaerator, through the gland steam condenser; and the low

- temperature economizer section in the

HRSG.

The system consists of one main condenser; two 50 percent capacity, m otor

- driven vertical

multistage condensate pumps (total of two pumps for the plant); one gland steam condenser;

condenser air removal vacuum pumps, condensate polisher, and a low

- temperature tube bundle

in the HRSG.

Condensate is delivered to a common disc harge header through two separate pump discharge

lines, each with a check valve and a gate valve. A common minimum flow recirculation line

discharging to the condenser is provided to maintain minimum flow requirements for the gland

steam condenser and the condensate pumps.

4.1.7.2 Feedwater

The function of the feedwater ( FW ) system is to pump the various FW streams from the

deaerator storage tank in the HRSG to the respective steam drums. One 100 percent capacity

motor

- driven feed pump is provided per each HRSG ( total of two pumps for the plant). The FW

pumps are equipped with an interstage takeoff to provide IP and LP FW. Each pump is provided

with inlet and outlet isolation valves, outlet check valves, and individual minimum flow

recirculation lines dischargin g back to the deaerator storage tank. The recirculation flow is

controlled by pneumatic flow control valves. In addition, the suctions of the boiler feed pumps

are equipped with startup strainers, which are utilized during initial startup and following m ajor

outages or system maintenance.

4.1.7.3 Steam System

Main, intermediate, and low pressure steam exits the HRSG superheater section through motor

operated stop/check valve s and motor

- operated gate valve s. The main steam is routed to the HP

turbine stop valve. The intermediate steam is combined with the HP turbine exhaust and is

conveyed through a motor

- operated isolation gate valve to the HRSG reheater and from the

HRSG reheater outlet through a motor

- operated gate valve to the IP turbines. The low pressure

s team is combined with the IP turbine exhaust and is conveyed through a motor

- operated

isolation gate valve to the LP turbines.

4.1.7.4 Circulating Water System

The function of the CWS is to supply cooling water to condense the main turbine exhaust steam,

for the auxiliary cooling system

, and for the CDR facility in Case B31B. The system consists of

two 50 percent capacity vertical CWPs (total of two pumps for the plant), a mechanical draft

evaporative cooling tower, and interconnecting piping. The condenser is a single pass,

horizontal type with divided water boxes. There are two separate circulating water circuits in

each box. One

- half of the condenser can be removed from service for cleaning or plugging

tubes. This can be done during normal operation at red uced load.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 172 The auxiliary cooling system is a CL system. Plate and frame heat exchangers with circulating

water as the cooling medium are provided. The system provides cooling water to the following

systems:

1. CTG lube oil coolers

2. CTG air coolers

3. STG lube oil coolers

4. STG hydrogen coolers

5. Boiler feed water pumps

6. Air compressors

7. Generator seal oil coolers (as applicable)

8. Sample room chillers

9. Blowdown coolers

10. Condensate extraction pump

- motor coolers

The CDR system in Case B31B requires a substantial amount o f cooling water that is provided

by the NGCC plant CWS. The additional cooling load imposed by the CDR is reflected in the

significantly larger CWPs and cooling tower in that case.

4.1.7.5 Buildings and Structures

Structures assumed for NGCC cases can be summariz ed as follows:

1. Generation Building housing the STG

2. CWP House

3. Administra tion / Office / Control Room / Maintenance Building

4. Water Treatment Building

5. Fire Water Pump House



## 4.1.8 Accessory Electric Plant

The accessory electric plant consists of all switchgear and control equipment, generator

equipment, station service equipment, conduit and cable trays, wire, and cable. It also includes

the main transformer, required foundations, and standby equipment.



## 4.1.9 Waste Treatment/Miscellaneous Systems

An onsite water treatmen t facility treats all runoff, cleaning 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 miscellaneou s metals.

The waste treatment system is minimal and consists, primarily, of neutralization and oil/water

separators (along with the associated pumps, piping, etc.).

Miscellaneous systems consisting of service air, instrument air, and service water are pr ovided.

All truck roadways and unloading stations inside the fence area are provided.



## 4.1.10 Instrumentation and Control

An integrated plant

- wide DCS is provided. The DCS is a redundant microprocessor

- based,

functionally distributed system. The control room ho uses an array of video monitors and

keyboard units. The monitor/keyboard units are the primary interface between the generatingCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 173 process and operations personnel. The DCS incorporates plant monitoring and control functions

for all the major plant equipmen t. The DCS is designed to provide 99.5 percent availability.

The plant equipment and the DCS are designed for automatic response to load changes from

minimum load to 100 percent. Startup and shutdown routines are implemented as supervised

manual procedur es with operator selection of modular automation routines available.



## 4.1.11 Performance Summary Metrics

This section details the method s used to calculate several metrics reported in the performance

summaries of the NGCC cases.

Combustion Turbine Efficiency

The c ombustion turbine efficiency is calculated by taking the CT power produced and dividing it

by the thermal input to the turbines. This calculation is represented by the equation:

= TT

Where:

CTE

– combustion turbine efficiency

C TP

– combus tion turbine power

TI

– thermal input to turbines

The thermal input is calculated by taking the natural gas feed rate and multiplying it by the

heating value of the natural gas and converting it to kWs.

Steam Turbine Efficiency

The steam turbine efficiency is calculated by taking the steam turbine power produced and

dividing it by the difference between the thermal input and thermal consumption . This

calculation is represented by the equation:

SS = SS

( TT

− )

Where:

STE

– steam turbine efficiency

STP

– steam turbine power

TI

– thermal input

T C

– thermal consumption

The thermal input is calculated by taking the enthalpy of the flue gas to the HRSG and

subtracting the enthalpy of the flue gas exiting the HRSG.

The thermal consumption is only present in the capture cases. It is the enthalpy difference

between the streams extracted for the capture and CO 2 

## dryer systems and the condensate returned

to the condenser (steam extraction

– con densate return).Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 174 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

, 412

Where:

STHR

– steam turbine heat rate , Btu/kWh

STE

– steam turbine efficiency , fraction



# 4.2 NGCC Cases

This section contains an evaluation of plant designs for Cases B31A and B31B. The balance of

this section is organized as follows :

• Process and System Description provides an overview of the technology operation as

applied to Case B31A. The systems that are common to all NGCC cases were covered in

Section 4.1 and only features that are unique to Case B31 A are discussed further in this

section.

• Key Assumptions is a summary of study and modeling assumptions relevant to Cases

B31A and B31B.

• Sparing Philosophy is provided for both Cases B31A and B31B.

• Performance Results provides the main modeling results fro m Case B31A, including the

performance summary, environmental performance, carbon balance, water balance, mass

and energy balance diagrams, and energy balance table.

• Equipment List provides an itemized list of major equipment for Case B31A with

account cod es that correspond to the cost accounts in the Cost Estimates section.

• Cost Estimates provides a summary of capital and operating costs for Case B31A.

• Process and System Description, Performance Results, Equipment List and Cost

Estimates are reported for C ase B31B.



## 4.2.1 Process Description

In this section the NGCC process without CO 2 

## capture is described. The system description

follows the BFD in Exhibit 4

- 2 and stream numbers reference the same exhibit. The tables in

Exhibit 4

- 3 provide process data for the numbered streams in the BFD. The BFD shows only

one of the two CT/HRSG trains , but the flow rates in the stream table are the total for two

systems.

Ambient air (stream 1) is supplied to an inlet filter and compressed before being combined with

natural gas (stream 2) in the dry LNB, which is operated to control the rotor inlet temperature at

1

, 3 59 °C (2 ,479 °F). The flue gas exits the turbine at 6 03 °C (1

, 1 18 °F) (stream 3) and passes into

the HRSG. The HRSG generates both the main steam and reheat steam for the steam turbine.

F lue gas exits the HRSG at 1 17 °C ( 2 43 ° F) and passes to the plant stack

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 175 Exhibit 4

- 2 Case B31A block fl ow diagram, NGCC without CO 2 

### capture

Source: NETL 1

HRSG 3

S TACK 

### 2

A IR 

### N ATURAL



### G AS



### S TEAM



### T URBINE 

### 5 6

C ONDENSER 

### 4

Note : Block Flow Diagram is not intended to

represent a complete material balance

. Only

major process streams and equipment are

shown

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 176 Exhibit 4

- 3 Case B31A stream table, NGCC without capture

1 2 3 4 5 6

Ar 0.0092 0.0000 0.0089 0.0089 0.0000 0.0000

CH 4 0.0000 0.9310 0.0000 0.0000 0 .0000 0.0000

CH 4 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

C 2 H 6 0.0000 0.0320 0.0000 0.0000 0.0000 0.0000

C 3 H 8 0.0000 0.0070 0.0000 0.0000 0.0000 0.0000

C 4 H 10 0.0000 0.0040 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 2 0.0003 0.0100 0.0391 0.0391 0.0000 0.0000

H 2 O 0.0099 0.0000 0.0841 0.0841 1.0000 1.0000

N 2 0.7732 0.0160 0.7442 0.7442 0.0000 0.0000

O 2 0.2074 0.0000 0.1238 0.1238 0.0000 0.0000

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 125,541 4,855 130,538 130,538 24,398 32,637

V

- L Flowrate (kg/hr) 3,622,750 84,134 3,706,884 3,706,884 439,533 587,969

Solids Flowrate (kg/hr) 0 0 0 0 0 0

Temperature (°C) 15 38 603 117 566 38

Pr essure (MPa, abs) 0.10 3.10 0.10 0.10 16.65 0.01

Steam Table Enthalpy (kJ/kg) A 30.22 46.29 800.33 256.77 3,473.89 160.78

AspenPlus Enthalpy (kJ/kg) B

- 97.57

- 4,462.93

- 616.98

- 1,160.55

- 12,506.41

- 15,819.51

Density (kg/m 3 ) 1.2 22.2 0.4 0.9 47.7 992.8

V

- L Molecular Weight 28.857 17.328 28.397 28.397 18.015 18.015

V

- L Flowrate (lb mole /hr) 276,771 10,704 287,786 287,786 53,788 71,953

V

- L Flowrate (lb/hr) 7,986,797 185,484 8,172,281 8,172,281 969,004 1,296,250

Solids Flowrate (lb/hr) 0 0 0 0 0 0

Temperature (°F) 59 100 1,118 243 1,050 101

Pressure (psia) 14.7 450.0 15.1 14.8 2,414.7 1.0

Steam Table Enthalpy (Btu/lb) A 13.0 19.9 344.1 110.4 1,493.5 69.1

AspenPlus Enthalpy (Btu/lb) B

- 41.9

- 1,918.7

- 265.3

- 498.9

- 5,376.8

- 6,801.2

Density (lb/ft 3 ) 0.076 1.384 0.025 0.056 2.975 61.977

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 id eal gas state at

25°C and 1 atm

.



## 4.2.2 Key System Assumptions

System as sumptions for Cases B31A and B31B

, NGCC with and without CO 2 

## capture, are

compiled in Exhibit 4

- 4

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 177 Exhibit 4

- 4 NGCC plant study configuration matrix

Case B31A

w/o CO 2 

### Capture Case B31B

w/CO 2 

### Capture

Steam Cycle, MPa/°C/°C (psig/°F/°F) 16.5/566/566

(2

, 400/1

, 050/1

, 050) 16.5/566/566

(2

, 400/1

, 050/1

, 050)

Fuel Natural Gas Natural Gas

Fuel Pressure at Plant Battery Limit MPa (psia) 3.1 (450) 3.1 (450)

Condenser Pres sure, mm Hg (in Hg) 50.8 (2) 50.8 (2)

Cooling Water to Condenser, °C (oF) 16 (60) 16 (60)

Cooling Water from Condenser, °C (oF) 27 (80) 27 (80)

Stack Temperature, °C (°F) 1 1 7 ( 243 ) 35 ( 95 )

SO 2 

### Control Low Sulfur Fuel Low Sulfur Fuel

NOx Control LNB an d SCR LNB and SCR

SCR Efficiency, % A 

### 90 90

Ammonia Slip (End of Catalyst Life), ppmv 10 10

Particulate Control N/A N/A

Mercury Control N/A N/A

CO 2 

### Control N/A Cansolv

Overall Carbon Capture A 

### N/A 90 %

CO 2 

### Sequestration N/A Off

- site Saline Formation

A 

### Removal efficiencies are based on the flue gas content



## 4.2.2.1 Balance of Plant

– Cases B31A and B31B

The balance of plant assumptions are common to both NGCC cases and are presented in

Exhibit 4

- 5

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 178 Exhibit 4

- 5 NGCC balance of plant assumptions

Parameter Value

Cooling System Recirculating Wet Cooling Tower

Fuel and Other Storage

Natural Gas Pipeline supply at 3.1 MPa (450 psia) and 38°C (100°F)

Plant Distribution Voltag e

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 CT 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 DI water is drawn from

municipal sources.

Process Wastewate r 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

t reatment system. Sludge is hauled off site. Packaged

plant is sized for 5.68 m 3 

### /d (1,500 gpd)

Water Discharge Most of the process wastewater is recycled to the cooling

tower basin. Blowdown is treated for chloride and

metals, and discharged.



## 4.2.3 Sparing P hilosophy

Dual trains are used to accommodate the size of commercial C Ts. There is no redundancy other

than normal sparing of rotating equipment. The plant design consists of the following major

subsystems:

• Two state

- of

- the

- art 2013 F

- Class CTGs (2 x 50% )

• Two 3

- pressure reheat HRSGs with self

- supporting stacks and SCR systems (2 x 50%)

• One 3

- pressure reheat, triple

- admission STG (1 x 100%)

• For Case B31B only, one CO 2 

## absorption systems, consisting of an absorber, stripper,

and ancillary equipment (1 x 100 %) and two CO 2 

## compression systems (2 x 50%)



## 4.2.4 Case B31A Performance Results

The plant produces a net output of 6 30 MW at a net plant efficiency of 5 1

. 5 percent (HHV

basis).

Overall plant performance is summarized in Exhibit 4

- 6 ; Exhibit 4

- 7 provides a detailed

breakdown of the auxiliary power requirements.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 179 Exhibit 4

- 6 Case B31A plant performance summary

Performance Summary

Combustion Turbine Power, MWe 422

Steam Turbine Power, MWe 219

Total Gross Power, MWe 641

CO
2 Capture/Removal Auxiliaries, kWe 0

CO
2 Compression, kWe 0

Balance of Plant, kWe 11

Total Auxiliaries, MWe 11

Net Power, MWe 630

HHV Net Plant Efficiency ( %) 51.5%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 6,994 (6,629)

HHV Combustion Turbine Efficiency, % 34.5%

LHV Net Plant Efficiency (%) 57.0%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 6,320 (5,990)

LHV Combustion Turbine Efficiency, % 38.1%

Steam Tu rbine Cycle Efficiency, % 39.1%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 9,201 (8,721)

Condenser Duty, GJ/hr ( MM Btu/hr) 1,281 (1,215)

Natural Gas Feed Flow, kg/hr (lb/hr) 84,134 (185,483)

HHV Thermal Input, kWt 1,223,032

LHV Thermal Input, kWt 1,105, 162

Raw Water Withdrawal, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.016 (4.2)

Raw Water Consumption, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.012 (3.3)

Exhibit 4

- 7 Case B 3 1A plant power summary

Power Summary

Combustion Turbine Power, MWe 422

Steam Turbine Power, MWe 219

Total Gross Power, MWe 641

Auxiliary Load Summary

Feedwater Pumps, kWe 3,550

SCR, kWe 2

CO
2 Capture/Removal Auxiliaries, kWe 0

CO
2 Compression, kWe 0

Miscellaneous Balance of Plant A 

### , kWe 500

Combustion Turbine Auxiliaries, kWe 700

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 130

Circulating Water Pumps, kWe 2,570

Ground Water Pumps, kWe 240

Cooling Tower Fans, kWe 1,330

Transformer Losses, kWe 1,950

Total Auxiliaries, MWe 11

Net Power, MWe 630

A 

### Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads



## 4.2.4.1 Environmental Performance

The environmental t argets for emissions of NOx, SO 2 

## , and PM were presented in Section 2.4. A

summary of the plant air emissions for Case B31A is presented in Exhibit 4

- 8

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 180 Exhibit 4

- 8 Case B31A air emissions

kg/GJ (lb/ MM Btu) Tonne/year (ton/year) A 

### kg/MWh (lb/MWh)

SO
2 0.000 (0.001) 13 (15) 0.003 (0.006)

NOx 0.001 (0.003) 44 (49) 0.009 (0.020)

Particulate 0.000 (0.000) 0 (0) 0.000 (0.000)

Hg 0.00E+0 (0.00E+0) 0.000 (0.000) 0.00E+0 (0.00E+0)

CO
2 B 

### 51 (119) 1,671,433 (1,842,440) 350 (773)

CO
2 C



### - - 357 (786)

A 

### Calculations based on an 85 percent capacity factor

B 

### CO 2 

### emissions based on gross power

C 

### CO 2 

### emissions based on net power instead of gross power



## For the purpose of this report, the natural gas was assumed to contain the average value of total

sulfur of 0.34 gr/100 scf (4.71x10

- 4 

## lb

- S/MMBtu). (11) It was also assumed that the added

mercaptan (CH 4 

## S) was the sole contributor of sulfur to the natural gas. No sulfur capture

systems were required.

The NGCC cases were designed to achieve approximately 1.0 ppmvd NOx emissions (at 15

percent O 2 

## ) through the use of a DLN burner in the CTG

– the DLN burners reduce the

emissions to about 9 ppmvd (at 15 percent O 2 

## ) (18)

– and an SCR

– the SCR system is designed

for 90 percent NO reduction (19)

.

The pipeline natural gas was assumed to contain no particulate matter (PM), Hg, or HCl

, resulting in zero emissions.

CO 2 

## emissions are reduced relative to those produced by burning coal given the same power

output because of the higher heat content of natural gas, the lower carbon intensity of gas relative

to coal, and the higher overall efficiency of the NGCC plant rela tive to a coal

- fired plant.

The carbon balance for the plant is shown in Exhibit 4

- 9 . The carbon input to the plant consists

of carbon in the natural gas and carbon as CO 2 

## in the CT air. Carbon leaves the plant as CO 2 

## through the stack.

Exhibit 4

- 9 Case B31A carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Natural Gas 60,768 (133,97 1 ) Stack Gas 61,263 (135,06 1 )

Air (CO
2 ) 494 (1,090) CO
2 Product 0 (0)

CO 2 

### KO 0 (0)

CO 2 

### Dryer Vent 0 (0)

Total 61,262 (135, 06 1 ) Total 61,263 (135,06 1 )



## As shown in Exhibit 4

- 10 , the sulfur content of the natural gas is insignificant

. All sulfur in the

natural gas is emitted in the stack gas.

Exhibit 4

- 10 Case B31A sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Natural Gas 1 (2 ) Stack Gas 1 ( 2 )

Polishing Scrubber/HSS 0 (0)

Total 1 (2 ) Total 1 (2 )Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 181 Exhibit 4

- 11 shows the water balance for Case B31A. Water demand represents the total amount

of water required for a particular process. Some water is recovered within the process and is re

used as inte rnal 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 b y a POTW

and 50 percent from groundwater. Raw water withdrawal can be represented by the water

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

as condenser and cooling tower makeup. The difference between wa ter withdrawal and process

water discharge is defined as water consumption and can be represented by the portion of the raw

water withdrawn that is evaporated, transpired, incorporated into products or otherwise not

returned to the water source from which it was withdrawn. Water consumption represents the

net impact of the plant process on the water source balance.

Exhibit 4

- 11 Case B31A water balance

Water Use Water

Demand Internal

Recycle Raw Water

Withdr awal 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)

CO
2 Drying

– – – – – Capture System Makeup

– – – – – Condenser Makeup 0.10 (26)

– 0.10 (26)

– 0.10 (26)

BFW Makeup 0.10 (26)

– 0.10 (26)

– 0.10 (26)

Cooling Tower 10.01 (2,646) 0.10 (26) 9.92 (2,620) 2.25 (595) 7.66 (2,025)

CO
2 Capture Recovery

– – – – – CO
2 Compression

Recovery – – – – –

BFW Blowdown

– 0.10 (26)

- 0.10 (

- 26)

– – Total 10.11 (2,672) 0.10 (26) 10.01 (2,646) 2. 25 (595) 7.76 (2,051)



## 4.2.4.2 Heat and Mass Balance Diagrams

A heat and mass balance diagram is shown for the NGCC in Exhibit 4

- 12 . An overall plant

energy balance is provided in tabular form in Exhibit 4

- 13 . The power out is the combined CT

and steam turbine power prior to generator losses. The power at the generator terminals (shown

in Exhibit 4

- 6 ) is calculated by multiplying the powe r out by a combined generator efficiency of

98. 5 percent.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 18 2 This page intentionally left blankCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 183 Exhibit 4

- 12 Case B31A heat and mass balance, NGCC without CO 2 

### capture

Source: NETL Notes :

1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psia

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Air

Nitrogen Natural Gas

Water Steam

P AGES

1 OF 1 N ATURAL GAS COMBINED CYCLE PLANT

C ASE B 31 A

2 X S TATE

- OF

- THE

- ART 2013 F

- CLASS C T

2400 / 1050 / 1050

DWG

. NO

. BB

- HMB

- CS

- B 31 A

- PG

- 1 Flue Gas

Gross Plant Power : 641 MWe

Auxiliary Load : 11 MWe

Net Plant Power : 630 MWe

Net Plant Efficiency

, HHV : 51

. 5 %

Net Plant Heat Rate : 6

, 629 Btu / kWh

DOE / NETL

NGCC P LANT

C ASE B 31 A

Ambient

Air 1 7

, 986

, 797 W

59 T

15 P

13 H State

- of

- the

- art 2013 F

Class Turbine Natural

gas 185

, 483 W

100 T

450 P

20 H 2 8

, 172

, 280 W

243 T

15 P

110 H

Generator

Condensate

Pumps 1

, 296

, 250 W

101 T

87 P

69 H 1

, 296

, 250 W

101 T

1 P

69 H 1

, 000 W

1

, 050 T

2

, 415 P

1

, 494 H 979

, 965 W

517 T

74 P

1

, 290 H 1

, 282

, 288 W

522 T

74 P

1

, 292 H

1

, 282

, 288 W

101 T

1 P

1

, 017 H

Hot Well Condenser Stack

Steam Turbine

makeup

12

, 963 W

59 T

15 P

27 H

Air Inlet

Filter Gland Seal

Condenser 1

, 000 W

212 T

15 P

180 H LP Turbine HP

Turbine IP

Turbine 979

, 965 W

1

, 050 T

608 P

1

, 545 H

6 Preheater HP Economizer 2 /

LP Superheater IP Economizer /

HP Economizer 1 HP

Evaporator HP Pre

Superheater /

IP Superheater HP

Superheater

/ Reheater IP

Evaporator

3 LP

Evaporator LP

Economizer

305

, 377 W

300 T

84 P

270 H

12

, 082 W

301 T

707 P

272 H 978

, 792 W

306 T

3

, 010 P

282 H 1

, 296

, 250 W

253 T

80 P

222 H HP

BlowdownMain Steam

969

, 004 W

1

, 050 T

2

, 415 P

1

, 494 H 5 IP

BlowdownCold ReheatHot ReheatIP Steam LP Blowdown

11

, 961 W

900 T

621 P

1

, 462 H 968

, 004 W

673 T

621 P

1

, 333 H 302

, 323 W

537 T

74 P

1

, 300 HLP Steam

1

, 296

, 250 W

102 T

83 P

70 H 882 T 678 T 495 T 310 T 684 T 500 T 425 T

312 T

8

, 172

, 280 W

1

, 118 T

15 P

344 H

W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical 3

, 054 W

312 T

80 P

283 H 121 W

500 T

679 P

487 H 9

, 788 W

684 T

2

, 774 P

766 H

HP Pump

IP Pump LP Pump 4Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 184 This pa ge intentionally left blankCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 185 Exhibit 4

- 13 Case B31A overall energy balance ( 0°C [ 32°F ] r eference)

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Natural Gas 4,403 (4,173) 2.9 (2.8)

– 4,406 ( 4,176)

Air

– 109.5 (103.8)

– 109.5 (103.8)

Raw Water Makeup

– 37.7 (35.7)

– 37.7 (35.7)

Auxiliary Power

– – 40 (38) 40 (38)

TOTAL 4,403 (4,173) 150.1 (142.3) 40 (38) 4,593 (4,353)

Heat Out GJ/hr (MMBtu/hr)

Stack Gas

– 952 (902)

– 952 (902)

Sulfur

– – – – Motor Losses and Design

Allowances – – 41 (39) 41 (39)

Condenser

– 1,281 (1,215)

– 1,281 (1,215)

Non

- Condenser Cooling Tower

Loads – 26 (25)

– 26 (25)

CO
2 – – – – Cooling Tower Blowdown

– 16.7 (15.9)

– 16.7 (15.9)

CO
2 Capture Losses

– – – –
Ambient Losses A



### – 34.6 (32.8)

– 34.6 (32.8)

Power

– – 2,306

(2,186) 2,306 (2,186)

TOTAL

– 2,311 (2,190) 2,347

(2,225) 4,658 (4,415)

Unaccounted Energy B



### – - 65 (

- 62 )

– - 65 (

- 62)

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



## 4.2.5 Case B31A

– Major Equipment List

Major equipment items for the NGCC plant 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 4.2.6 . In general, the design co nditions include a 10 percent

contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

Case B3 1A

– Account 2: Fuel and Sorbent Preparation and Feed

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Gas Pipeline Underground, coated

carbon steel,

wrapped cathodic

protection 70 m 3 / min @ 3.1 MPa

(2,456 acfm @ 450 psia)

39 cm (16 in) standard wall pipe 16 km

(10 mi ) 0

2 Gas Metering Station

-- 70 m 3 / min (2,456 acfm) 1 0



## Case B3 1A

– Account 3: Feedw ater and Miscellaneous Systems and Equipment

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Demineralized Water

Storage Tank Vertical, cylindrical,

outdoor 776,000 liters (205,000 gal) 2 0

2 Condensate Pumps Vertical canned 5,430 lpm @ 70 m H

2 O

(1,430 gpm @ 240 ft H

2 O) 2 1Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 186 Equipment

No. Description Type Design Condition Operating

Qty. Spares

3 Boiler Feedwater

Pump Horizontal, split case,

multi

- stage, centrifugal,

with interstage bleed for

IP and LP feedwater HP water:

4,100 lpm @ 2,500 m H

2 O

(1,080 gpm @ 8,210 ft H

2 O)

IP water:

050 lpm @ 540 m H

2 O

(10 gpm @ 1,790 ft H

2 O)

LP water:

1,280 lpm @ 14.0 m H

2 O

(340 gpm @ 50 ft H

2 O) 2 1

4 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

5 Service Air

Compressors Flooded Screw 13 m 3 / min @ 0.7 MPa

(450 scfm @ 100 psig) 2 1

6 Instrument Air Dryers Duplex, regenerative 13 m 3 / min (450 scfm) 2 1

7 Closed Cycle Cooling

Heat Exchangers Plate and frame 13 MMkJ/hr (13 MMBtu/hr) 2 0

8 Closed Cycle Cooling

Water Pumps Horizontal centrifugal 5,200 lpm @ 20 m H

2 O

(1,400 gpm @ 70 ft H

2 O) 2 1

9 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

10 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

11 Ra w Water Pumps Stainless steel, single

suction 5,600 lpm @ 20 m H

2 O

(1,500 gpm @ 60 ft H

2 O) 2 1

12 Filtered Water Pumps Stainless steel, single

suction 150 lpm @ 50 m H

2 O

(40 gpm @ 160 ft H

2 O) 2 1

13 Filtered Water Tank Vertical, cylindrical 145,000 liter (38,000 gal) 1 0

14 Makeup Water

Demineralizer Multi

- media filter,

cartridge filter, RO

membrane assembly

and electro

- deionization

unit 330 lpm (90 gpm) 1 0

15 Liquid Waste

Treatment System 10 years, 24

- hour storm 1 0



## Case B 3 1A

– Account 6 : Combustion Turbine and Accessories

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Combustion

Turbine State

- of

- the

- art 2013 F

- c lass

w/ dry low

- NOx burner 210 MW 2 0

2 Combustion

Turbine

Generator TEWAC 230 MVA @ 0.9 p.f.,

24 kV, 60 Hz, 3

- phase 2 0



## Case B 3 1A

– Account 7 : HRSG, Ducting, and Stack

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Stack CS plate, type 409SS

liner 46 m (150 ft) high x

8.1 m (27 ft) diameter 2 0

2 Heat Recovery

Steam Generator Drum, mult i

- pressure

with economizer section

and integral deaerator Main steam

- 241,743 kg/hr,

16.5 MPa/566°C

(532,952 lb/hr, 2,400

psig/1,050°F)

Reheat steam

- 244,478 kg/hr,

4.1 MPa/566°C

(538,981 lb/hr, 593

psig/1,050°F) 2 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 187 Equipment

No. Description Type Design Condition Operating

Qty. Spares

3 SCR Reactor Space for spare la yer 2,040,000 kg/hr (4,490,000

lb/hr) 2 0

4 SCR Catalyst

-- Space available for an

additional catalyst layer 1 layer 0

5 Dilution Air Blowers Centrifugal 10 m 3 / min @ 108 cm WG

(190 scfm @ 42 in WG) 2 1

6 Ammonia Feed Pump Centrifugal 1.2 lpm @ 90 m H

2 O

(0.3 gpm @ 300 ft H

2 O) 2 1

7 Ammonia Storage

Tank Horizontal tank 33,000 liter (9,000 gal) 1 0



## Case B 3 1A

– Account 8 : Steam Turbine Generator and Auxiliaries

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Steam Turbine Commercia lly available

advanced steam turbine 231 MW

16.5 MPa/566°C/566°C (2400

psig/ 1050°F/1050°F) 1 0

2 Steam Turbine

Generator Hydrogen cooled, static

excitation 260 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 1 0

3 Surface Condenser Single pass, divided

waterbox i ncluding

vacuum pumps 1,410 GJ/hr (1,340 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 B 3 1A

– Account 9: Cooling Water System

Equip ment

No. Description Type Design Condition Operating

Qty. Spares

1 Circulating

Water Pumps Vertical, wet pit 258,000 lpm @ 30 m

(68,000 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 /

1440 GJ/hr (1360 MMBtu/hr) heat duty 1 0



## Case B 3 1A

– Account 11: Accessory Electric Plant

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 CTG Transformer Oil

- filled 24 kV/345 kV, 230

MVA, 3

- ph, 60 Hz 2 0

2 S TG Transformer Oil

- filled 24 kV/345 kV, 250

MVA, 3

- ph, 60 Hz 1 0

3 High Voltage Auxiliary

Transformer Oil

- filled 345 kV/13.8 kV, 0

MVA, 3

- ph, 60 Hz 2 0

4 Medium Voltage Transformer Oil

- filled 24 kV/4.16 kV, 10

MVA, 3

- ph, 60 Hz 1 1

5 Low Voltage Transfor mer Dry ventilated 4.16 kV/480 V, 2

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 Switc hgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 1 1Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 188 Equipment

No. Description Type Design Condition Operating

Qty. Spares

10 Emergency Diesel Generator Sized for emergency

shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 0



## Case B 3 1A

– Account 12: Instrumentation and Control

Equipm ent

No. Description Type Design Condition Operating

Qty. Spares

1 DCS

- Main

Control Monitor/keyboard; Operator

printer (laser color); Engineering

printer (laser B&W) Operator stations/printers

and engineering

stations/printers 1 0

2 DCS

- Processor Micr oprocessor with redundant

input/output N/A 1 0

3 DCS

- Data

Highway Fiber optic Fully redundant, 25% spare 1 0



## 4.2.6 Case B31A

– Cost Estimating

The cost estimating methodology was described previously in Section 2.7

. Exhibit 4

- 14 shows a

detailed breakdown of the capital costs ; Exhibit 4

- 15 shows the owner’s costs , TOC, and TASC ;

Exhibit 4

- 16 shows the initial and annual O&M costs; and Exhibit 4

- 17 shows the COE

breakdown.

T he estimated TP C of the NGCC with no CO 2 

## capture is $ 685 /kW. No process contingency was

included in this case because all elements of the technology are commercially proven. The

project contingency is 10.7 percent of TP C. The COE is $ 57.6 /M Wh.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 189 Exhibit 4

- 14 Case B31 A total plant cost details

Case: B31 A

– 2x1 CT NGCC w/o CO 2 Estimate Type: Conceptual

Plant Size (MW,net): 630 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

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $3,215 $3,329 $2,719 $0 $9,263 $834 $0 $1,515 $11,611 $18

3.2 Water Makeup & Pretreating $1,974 $204 $1,013 $0 $3,191 $287 $0 $696 $4,174 $7

3.3 Other Feedwater Subsystems $1,506 $498 $416 $0 $ 2,420 $218 $0 $396 $3,033 $5

3.4 Service Water Systems $238 $475 $1,531 $0 $2,245 $202 $0 $489 $2,937 $5

3.5 Other Boiler Plant Systems $1,606 $600 $1,380 $0 $3,586 $323 $0 $586 $4,496 $7

3.6 Natural Gas, incl. pipeline $17,706 $656 $567 $0 $18,929 $1,7 04 $0 $3,095 $23,728 $38

3.7 Waste Treatment Equipment $689 $0 $399 $0 $1,089 $98 $0 $237 $1,424 $2

3.8 Misc. Equip. (Cranes, Air Comp.,

Comm.) $1,165 $156 $566 $0 $1,887 $170 $0 $411 $2,469 $4

Subtotal $28,101 $5,918 $8,592 $0 $42,611 $3,835 $0 $7,425 $53,871 $86

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $104,200 $0 $6,341 $0 $110,541 $9,949 $0 $12,049 $132,539 $211

6.9 Combustion Turbine Foundations $0 $879 $950 $0 $1,829 $165 $0 $399 $2,392 $4

Subtotal $104,200 $879 $7 ,291 $0 $112,370 $10,113 $0 $12,448 $134,931 $214

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $33,050 $0 $6,116 $0 $39,166 $3,525 $0 $4,269 $46,960 $75

7.2 SCR System $1,973 $829 $1,156 $0 $3,957 $356 $0 $647 $4,960 $8

7.9 HRSG, Duct & Stack Foundations $0 $551 $517 $0 $1,068 $96 $0 $233 $1,397 $2

Subtotal $35,023 $1,379 $7,788 $0 $44,190 $3,977 $0 $5,149 $53,316 $85

8 Steam Turbine Generator

8.1 Steam TG & Accessories $36,973 $0 $4,914 $0 $41,887 $3,770 $0 $4,566 $50,223 $80

8.2 T urbine Plant Auxiliaries $205 $0 $468 $0 $673 $61 $0 $73 $807 $1

8.3 Condenser & Auxiliaries $2,920 $0 $1,401 $0 $4,321 $389 $0 $471 $5,181 $8

8.4 Steam Piping $12,237 $0 $4,959 $0 $17,196 $1,548 $0 $2,812 $21,555 $34

8.9 TG Foundations $0 $968 $1,599 $ 0 $2,567 $231 $0 $560 $3,357 $5

Subtotal $52,335 $968 $13,341 $0 $66,644 $5,998 $0 $8,481 $81,123 $129

9 Cooling Water System

9.1 Cooling Towers $2,950 $0 $900 $0 $3,850 $347 $0 $420 $4,616 $7

9.2 Circulating Water Pumps $1,428 $0 $84 $0 $1,512 $136 $0 $165 $1,813 $3

9.3 Circ. Water System Auxiliaries $120 $0 $16 $0 $135 $12 $0 $15 $162 $0

9.4 Circ. Water Piping $0 $3,710 $840 $0 $4,550 $409 $0 $744 $5,703 $9

9.5 Make

- up Water System $310 $0 $398 $0 $708 $64 $0 $116 $887 $1

9.6 Component Cooling W ater Sys $239 $285 $183 $0 $707 $64 $0 $116 $886 $1

9.9 Circ. Water System Foundations $0 $1,678 $2,786 $0 $4,464 $402 $0 $973 $5,839 $9

Subtotal $5,046 $5,673 $5,207 $0 $15,926 $1,433 $0 $2,548 $19,907 $32

11 Accessory Electric Plant

11.1 Generator Equipment $5,327 $0 $3,151 $0 $8,477 $763 $0 $693 $9,933 $16

11.2 Station Service Equipment $1,527 $0 $131 $0 $1,659 $149 $0 $136 $1,944 $3

11.3 Switchgear & Motor Control $1,879 $0 $326 $0 $2,206 $199 $0 $240 $2,645 $4Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 190 Case: B31 A

– 2x1 CT NGCC w/o CO 2 Estimate Type: Conceptual

Plant Size (MW,net): 630 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 $98 2 $2,830 $0 $3,812 $343 $0 $623 $4,778 $8

11.5 Wire & Cable $0 $3,156 $1,795 $0 $4,951 $446 $0 $809 $6,206 $10

11.6 Protective Equipment $0 $722 $2,506 $0 $3,228 $291 $0 $352 $3,871 $6

11.7 Standby Equipment $128 $0 $120 $0 $248 $22 $0 $27 $297 $0

11.8 Main Power Transformers $12,475 $0 $190 $0 $12,666 $1,140 $0 $1,381 $15,186 $24

11.9 Electrical Foundations $0 $164 $417 $0 $581 $52 $0 $127 $760 $1

Subtotal $21,337 $5,025 $11,466 $0 $37,828 $3,405 $0 $4,388 $45,621 $72

12 Instrumentation & Control

12.4 Other Major Component Control $900 $0 $573 $0 $1,473 $133 $0 $241 $1,846 $3

12.6 Control Boards, Panels & Racks $269 $0 $164 $0 $433 $39 $0 $71 $543 $1

12.7 Computer & Accessories $4,304 $0 $131 $0 $4,435 $399 $0 $483 $5,318 $8

12.8 Instrument Wir ing & Tubing $0 $801 $1,417 $0 $2,217 $200 $0 $363 $2,779 $4

12.9 Other I & C Equipment $1,604 $0 $3,715 $0 $5,319 $479 $0 $580 $6,378 $10

Subtotal $7,077 $801 $6,000 $0 $13,878 $1,249 $0 $1,737 $16,864 $27

13 Improvements to Site

13.1 Site Preparati on $0 $110 $2,335 $0 $2,445 $220 $0 $533 $3,198 $5

13.2 Site Improvements $0 $1,008 $1,331 $0 $2,339 $210 $0 $510 $3,059 $5

13.3 Site Facilities $2,057 $0 $2,158 $0 $4,215 $379 $0 $919 $5,514 $9

Subtotal $2,057 $1,117 $5,824 $0 $8,999 $810 $0 $1,962 $1 1,770 $19

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $303 $160 $0 $463 $42 $0 $76 $581 $1

14.2 Steam Turbine Building $0 $2,477 $3,295 $0 $5,772 $519 $0 $944 $7,235 $11

14.3 Administration Building $0 $568 $385 $0 $952 $86 $0 $156 $1,19 4 $2

14.4 Circulation Water Pumphouse $0 $190 $94 $0 $283 $26 $0 $46 $355 $1

14.5 Water Treatment Buildings $0 $419 $382 $0 $801 $72 $0 $131 $1,004 $2

14.6 Machine Shop $0 $493 $315 $0 $807 $73 $0 $132 $1,012 $2

14.7 Warehouse $0 $318 $192 $0 $510 $46 $0 $83 $639 $1

14.8 Other Buildings & Structures $0 $95 $69 $0 $165 $15 $0 $27 $206 $0

14.9 Waste Treating Building & Str. $0 $373 $665 $0 $1,038 $93 $0 $170 $1,301 $2

Subtotal $0 $5,235 $5,557 $0 $10,791 $971 $0 $1,764 $13,527 $21

Total $255,176 $2 6,995 $71,067 $0 $353,237 $31,791 $0 $45,902 $430,931 $685Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 191 Exhibit 4

- 15 Case B31A owner’s costs

Description $ / 1,000 $/kW

Pre

- Production Costs

6 Months All Labor $3,632 $6

1 Month Maintenance Materials $522 $1

1 Month Non

- fuel Consumables $242 $0

1 Month Waste Disposal $0 $0

25% of 1 Months Fuel Cost at 100% CF $4,679 $7

2% of TPC $8,619 $14

Total $17,695 $28

Inventory Capital

60 day supply of fuel and consumables at 100% CF $291 $0

0.5% of TPC (spare parts) $2,155 $3

Total $2,446 $4

Other Costs

Initial Cost for Catalyst and Chemicals $0 $0

Land $300 $0

Other Owner's Costs $64,640 $103

Financing Costs $11,635 $18

Total Overnight Costs (TOC) $527,646 $838

TASC Multiplier (IOU, low

- risk, 33 year) 1.075

Total As

- Spent Cost (TASC) $567,219 $901Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 192 Exhibit 4

- 16 Case B31A initial and annual operating and maintenance costs

Case: B31 A

– 2x1 CT NGCC w/o CO 2 Cost Base: Jun 2011

Plant Size (MW,ne t): 630 Heat Rate

- net (Btu/kWh): 6,629 Capacity Factor (%): 8 5

Operating & Maintenance Labor

Operating Labor Operating Labor Requirements per Shift

Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 1.0

Operating Labor Burden: 30.00 % of base Operator: 2.0

Labor O

- H Charge Rate: 25.00 % of labor Foreman: 1.0

Lab Tech's, etc.: 1.0

Total: 5.0

Fixed Operating Costs

Annual Cost

($) ($/kW

- net)

Annual Operating Labor: $2,260,518 $3.591

Maintenance Labor: $3,551,114 $5.641

Administrative & Support Labor: $1,452,908 $2.308

Property Taxes and Insurance: $8,618,615 $13.691

Total: $15,883,155 $25.230

Variable Operating Costs

($) ($/M Wh

- net)

Maintenance Material: $5,326,671 $1.13636

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 1,905 $1.67 $0 $989,284 $0.21105

Makeup and Waste Water

Treatment Chemicals (lbs): 0 11,348 $0.27 $0 $943,019 $0.20118

SCR Catalyst (m 3 ): w/eq uip. 0.08 $8,938.80 $0 $229,246 $0.04891

Ammonia (19% NH 3 , ton): 0 3.05 $330.00 $0 $311,902 $0.06654

Subtotal: $0 $2,473,451 $0.52767

Variable Operating Costs Total: $0 $7,800,123 $1.66404

Fuel Cost

Natural Gas (MMBtu): 0 100,38 4 $6.13 $0 $190,9 12,983 $40.72840

Total: $0 $190,912,983 $40.72840



### Exhibit 4

- 17 Case B 31A COE breakdown

Component Value, $/MWh Percentage

Capital 11.8 21%

Fixed 3.4 6%

Variable 1.7 3%

Fuel 40.7 71%

Total (Excludin g T&S) 57.6 N/A

CO 2 

### T&S 0.0 0%

Total (Including T&S) 57.6 N/A



## 4.2.7 Case B31B

– NGCC with CO 2 

## Capture

The plant configuration for Case B31B is the same as Case B31A with the exception that the

CDR technology was added for CO 2 

## capture. The nominal net output decreases to 5 59 MW

because the CT designed output is fixed and the CDR facility significantly increases the auxiliary

power load . Additionally, the CDR facility’s steam requirements reduces the power output of

the steam turbine.

The process description f or Case B31B is essentially the same as Case B31A with one notable

exception , the addition of CO 2 

## capture. A BFD and stream tables for Case B31B are shown inCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 193 Exhibit 4

- 18 and Exhibit 4

- 19 , respectively. Since the CDR facility process description was

provided in Section 4.1.5 , it is not repeated here.



## 4.2.8 Case B31B Performance Results

The Case B31B modeling assumptions were presented previously in Section 4.2.2

.

The plant produces a net output of 559 MW at a net plant efficiency of 45.7 percent (HHV

basis). Overall plant performance is summarized in Exhibit 4

- 20 ; Exhibit 4

- 21 provides a

detailed break down of the auxiliary power requirements. The CDR facility, including CO 2 

## compression, accounts for over 6 7 percent of the auxiliary plant load. The CWS (CWPs and

cooling tower fan) accounts for nearly 1 6 percent of the auxiliary load, largely due to the high

cooling water demand of the CDR facility.

Exhibit 4

- 18 Case B31B block flow diagram, NGCC with CO 2 

### capture

Source: NETL 1 HRSG 3

A MINE

U NIT S TACK 4

15

16

6

12 5 2

A IR N ATURAL

G AS

R EBOILER S TEAM

R EBOILER C ONDENSATE

CO 2

P RODUCT S TEAM

T URBINE 13 14

Note : Block Flow Diagram is not intended to

represent a complete material balance

. Only

major process streams and equipment are

shown

.

R ECLAIMER S TEAM

R ECLAIMER C ONDENSATE 17

18

7 CO 2 C OMPRESSORS

D RYER 11

CO 2 C OMPRESSORS

10 9 8 V ENT

D RYER S TEAM D RYER

C ONDENSATECost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 194 Exhibit 4

- 19 Case B31B str eam table, NGCC with capture

1 2 3 4 5 6 7 8 9

V

- L Mole Fraction

Ar 0.0092 0.0000 0.0089 0.0089 0.0096 0.0000 0.0000 0.0000 0.0000

CH 4 0.0000 0.9310 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CH 4 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.00 00 0.0000 0.0000 0.0000

C 2 H 6 0.0000 0.0320 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

C 3 H 8 0.0000 0.0070 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

C 4 H 10 0.0000 0.0040 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 2 0.0003 0.0100 0.0391 0.0391 0.0042 0.9824 0.9977 0.0503 0.0000

H 2 O 0.0099 0.0000 0.0841 0.0841 0.0468 0.0176 0.0023 0.9497 1.0000

N 2 0.7732 0.0160 0.7442 0.7442 0.8054 0.0000 0.0000 0.0000 0.0000

O 2 0.2074 0.0000 0.1238 0.1238 0.1340 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

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 125,541 4,855 130,538 13 0,538 120,611 4,673 4,601 8 7

V

- L Flowrate (kg/hr) 3,622,750 84,134 3,706,884 3,706,884 3,408,725 203,504 202,217 148 121

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0

Temperature (°C) 15 38 603 117 35 29 29 29 356

Pressure (MPa, abs) 0.10 3.10 0.10 0.10 0.10 0.20 3.03 3.03 4.28

Steam Table Enthalpy (kJ/kg) A 30.22 46.29 800.33 255.91 110.58 42.52

- 6.00 137.73 3,100.49

AspenPlus Enthalpy (kJ/kg) B

- 97.57

- 4,462.93

- 616.98

- 1,161.40

- 449.13

- 8,972.02

- 8,974.93

- 15,221.43

- 12,879.81

Density (kg/m 3 ) 1.2 22.2 0.4 0.9 1.1 3.5 63.3 372.7 16.0

V

- L Molecular Weight 28.857 17.328 28.397 28.397 28.262 43.553 43.950 19.322 18.015

V

- L Flowrate (lb mole /hr) 276,771 10,704 287,786 287,786 265,902 10,301 10,144 17 15

V

- L Flowrate (lb/hr) 7,986,797 185,484 8,172,281 8,172,281 7,514,952 448,649 445,812 327 267

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0

Temperature (°F) 59 100 1,118 242 95 85 85 85 673

Pressure (psia) 14.7 450.0 15.1 14.8 14.7 28.7 439.4 439.4 620.5

Steam Table Enthalpy (Btu/lb) A 13.0 19.9 344.1 110.0 47.5 18.3

- 2.6 59.2 1,333.0

AspenPlus Enthalpy (Btu/lb) B

- 41.9

- 1,918.7

- 265.3

- 499.3

- 193.1

- 3,857.3

- 3,858.5

- 6,544.0

- 5,537.3

Density (lb/ft 3 ) 0.076 1.384 0.025 0.056 0.070 0.216 3.953 23.269 0.998

A 

### Steam table referen ce conditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic reference state is the component’s constituent elements in an id eal gas state at

25°C and 1 atmCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 195 Exhibit 4

- 19 Case B31B stream table, NGCC with capture ( continued)

10 11 12 13 14 15 16 17 18

V

- L Mole Fraction

Ar 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CH 4 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

C 2 H 6 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

C 3 H 8 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

C 4 H 10 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0 .0000 0.0000 0.0000 0.0000 0.0000

CO 2 0.0000 0.9993 0.9993 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 1.0000 0.0007 0.0007 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

N 2 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

SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V

- L Flowrate (kg mole /hr) 7 4,593 4,593 24,409 32,641 12,609 12,609 42 42

V

- L Flowrate (kg/hr) 121 202,069 202,069 439,734 588,035 227,150 227,150 751 751

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0

Temperature (°C) 203 29 40 566 38 270 151 356 215

Pressure (MPa, abs) 1.64 2.89 15.27 16.65 0.01 0.51 0.49 4.28 2.11

Steam Table Enthalpy (kJ/kg) A 863.65

- 5.93

- 205.61 3,473.89 160.78 3,000.52 635.93 3,100.49 921.30

AspenPlus Enthalpy (kJ/kg) B

- 15,116.65

- 8,970.17

- 9,169.86

- 12,506.41

- 15,819.51

- 12,979.77

- 15,344.37

- 12,879.81

- 15,058.99

Density (kg/m 3 ) 861.8 59 .9 513.0 47.7 992.8 2.1 916.3 16.0 846.4

V

- L Molecular Weight 18.015 43.991 43.991 18.015 18.015 18.015 18.015 18.015 18.015

V

- L Flowrate (lb mole /hr) 15 10,127 10,127 53,813 71,961 27,797 27,797 92 92

V

- L Flowrate (lb/hr) 267 445,486 445,486 969,448 1 ,296,395 500,779 500,779 1,656 1,656

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0

Temperature (°F) 397 85 104 1,050 101 517 304 673 419

Pressure (psia) 237.4 419.4 2,214.7 2,414.7 1.0 73.5 70.6 620.5 306.2

Steam Table Enthalpy (Btu/lb) A 371.3

- 2.5

- 88.4 1,493.5 69.1 1,290.0 273.4 1,333.0 396.1

AspenPlus Enthalpy (Btu/lb) B

- 6,499.0

- 3,856.5

- 3,942.3

- 5,376.8

- 6,801.2

- 5,580.3

- 6,596.9

- 5,537.3

- 6,474.2

Density (lb/ft 3 ) 53.801 3.737 32.024 2.975 61.977 0.128 57.201 0.998 52.841

A 

### Steam table reference co nditions are 32.02°F & 0.089 psia

B 

### Aspen thermodynamic reference state is the component’s constituent elements in an id eal gas state at

25°C and 1 atmCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 196 Exhibit 4

- 20 Case B31B plant performance summary

Perfo rmance Summary

Combustion Turbine Power, MWe 422

Steam Turbine Power, MWe 179

Total Gross Power, MWe 601

CO
2 Capture/Removal Auxiliaries, kWe 13,000

CO
2 Compression, kWe 15,010

Balance of Plant, kWe 13,722

Total Auxiliaries, MWe 42

Net Power, MWe 559

HHV Net Plant Efficiency (%) 45.7%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 7,877 (7,466)

HHV Combustion Turbine Efficiency, % 34.5%

LHV Net Plant Efficiency (%) 50.6%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 7,118 (6,746)

LHV Combustion Turbine Efficiency, % 38.1%

Steam Turbine Cycle Efficiency, % 43.5%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 8,269 (7,838)

Condenser Duty, GJ/hr ( MM Btu/hr) 888 (842)

Natural Gas Feed Flow, kg/hr (lb/hr) 84,134 (185,483)

HHV Thermal Input, kWt 1,223,032

LHV Thermal Input, kWt 1,105,162

Raw Water Withdrawal, ( m 3 

### / min)/MW net 

### (gpm/MW net 

### ) 0.027 (7.2)

Raw Water Consumpt ion, (m 3 

### /min)/MW net 

### (gpm/MW net 

### ) 0.020 (5.4)

Exhibit 4

- 21 Case B31B plant power summary

Power Summary

Combustion Turbine Power, MWe 422

Steam Turbine Power, MWe 179

Total Gross Power, MWe 601

Auxiliary Load Summary

Feedwater Pumps, kWe 3,550

SCR, kWe 2

CO
2 Capture/Removal Auxiliaries, kWe 13,000

CO
2 Compression, kWe 15,010

Miscellaneous Balance of Plant A 

### , kWe 500

Combustion Turbine Auxiliaries, kWe 700

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 130

Circulating Water Pumps, kWe 4,310

Gr ound Water Pumps, kWe 360

Cooling Tower Fans, kWe 2,230

Transformer Losses, kWe 1,840

Total Auxiliaries, MWe 42

Net Power, MWe 559

A 

### Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads



## 4.2.8.1 Environmental Performance

The env ironmental targets for emissions of NOx, SO 2 

## , and PM were presented in Section 2.4. A

summary of the plant air emissions for Case B31B is presented in Exhibit 4

- 22

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 197 Exhibit 4

- 22 Case B31B air emissions

kg/GJ (lb/ MM Btu) Tonne/year (ton/year) A 

### kg/MWh (lb/MWh)

SO
2 0.000 (0.000) 0 (0) 0.000 (0.000)

NOx 0.001 (0.003) 44 (49) 0.010 (0.022)

Particulate 0.000 (0.000) 0 (0) 0.000 (0.000)

Hg 0.00E+0 (0.00E+0) 0.000 (0.0 00) 0.00E+0 (0.00E+0)

CO
2 B 

### 5 (12) 167,143 (184,244) 37 (82)

CO
2 C



### - - 40 (89)

A 

### Calculations based on an 85 percent capacity factor

B 

### CO 2 

### emissions based on gross power

C 

### CO 2 

### emissions based on net power instead of gross power



## For the purpose of this report , the natural gas was assumed to contain the average value of total

sulfur of 0.34 gr/100 scf (4.71x10

- 4 

## lb

- S/MMBtu). (11) It was also assumed that the added

mercaptan (CH 4 

## S) was the sole contributor of sulfur to the natural gas . No sulfur capture

systems were required.

The NGCC cases were designed to achieve approximately 1.0 ppmvd NOx emissions (at 15

percent O 2 

## ) through the use of a DLN burner in the CTG

– the DLN burners reduce the

emissions to about 9 ppmvd (at 15 percent O 2 

## ) (18)

– and an SCR

– the SCR system is designed

for 90 percent NO reduction (19)

.

The pipeline natural gas was assumed to contain no particulate matter (PM), Hg, or HCl

, resulting in zero emissions

.

CO 2 

## emissions are reduced relative to those produced by burning coal given the same power

output because of the higher heat content of natural gas, the lower carbon intensity of gas relative

to coal, and the higher overall efficiency of the NGCC plant re lative to a coal

- fired plant.

Ninety percent of the CO 2 

## in the flue gas is removed in CDR facility.

The carbon balance for the plant is shown in Exhibit 4

- 23

. The carbon input to the plant consists

of carbon in the natural gas in addition to carbon in the CT air. Carbon leaves the plant as CO 2 

## in the stack gas

, the CO 2 

## dryer’s vent, 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

carb on in , represented by the following fraction:

CCCCCCCC SSSS

( TT CCCCCCCC ) = �

1

− � 13

, 506

135

, 061 � �

∗ 100 = 90

. 0%

Exhibit 4

- 23 Case B31B carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Natural Gas 60,768 (133,971) Stack Gas 6,126 (13,506)

Air (CO
2 ) 494 (1,090) CO
2 Product 55,131 (121,544)

CO 2 

### KO 0 (0)

CO 2 

### Dryer Vent 5 (10)

Total 61,262 (135,061) Total 61,262 (135,061)Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 198 As shown in Exhibit 4

- 24 , the sulfur content of the natural gas is insignificant, comprised

entirely of mercaptan (CH 4 

## S) (used as an odorant). (11) All sulfur in the natural gas is removed

in the polishing scrubber of the CDR system.

Exhibit 4

- 24 Case B31B sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Natural Gas 1 (2 ) Stack Gas 0 (0)

Polishing Scrubber/HSS 1 (2 )

Total 1 (2 ) Total 1 (2 )



## Exhibit 4

- 25 s hows the overall water balance for the plant.

Exhibit 4

- 25 Case B31B water balance

Water Use Water

Demand Internal

Recycle Raw Water

Withdrawal Process

Water

Discharge Raw Water

Consumptio n

m 3 

### /min

(gpm) m 3 

### /min

(gpm) m 3 

### /min

(gpm) m 3 

### /min (gpm) m 3 

### /min (gpm)

CO
2 Drying

– – – 0.00 (1) 0.00 (

- 1)

Capture System

Makeup 0.02 (6)

– 0.02 (6)

– 0.02 (6)

Condenser Makeup 0.10 (26)

– 0.10 (26)

– 0.10 (26)

BFW Makeup 0.10 (26)

– 0.10 (26)

– 0.10 (26)

Cooling Tower 16.81

(4,440) 1.70 (449) 15.11

(3,991) 3.78 (998) 11. 33 (2,992)

CO
2 Capture

Recovery – 1.58 (417)

- 1.58 (

- 417)

– –

CO
2 Compression

Recovery – 0.02 (6)

- 0.02 (

- 6)

– - 0.02 (

- 6)

BFW Blowdown

– 0.10 (26)

- 0.10 (

- 26)

– –

Total 16.93

(4,472) 1.70 (449) 15.23

(4,023) 3.78 (999) 11.45 (3,024)



## 4.2.8.2 Heat and Mas s Balance Diagrams

A heat and mass balance diagram is shown for the NGCC in Exhibit 4

- 26 . An overall plant

energy balance is provided in tabular form in Exhibit 4

- 27

.

The power out is the combined CT and steam turbine power prior to generator losses. The power

at the generator terminals (shown in Exhibit 4

- 20 ) is calculated by multiplying the power out by

a combined generator efficiency of 98. 5 percent. The capture process heat out stream represents

heat rejected to cooling water and ultimately to ambient via the cooling tower. The same is true

of the condenser heat out stream. The CO 2 

## compressor intercooler load is included in the capture

process heat out stream.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 199 Exhibit 4

- 26 Case B31B heat and mass balance, NGCC with CO 2 

### capture

Source: NETL Notes :

1

. Enthalpy reference point is natural state

at 32 °F and 0

. 08865 psia

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Air

Nitrogen Natural Gas

Carbon Dioxide

Water Steam

P AGES

1 OF 1 N ATURAL GAS COMBINED CYCLE PLANT

C ASE B 31 B

2 X S TATE

- OF

- THE

- ART 2013 F

- C LASS C T

2400 / 1050 / 1050

DWG

. NO

. BB

- HMB

- CS

- B 31 B

- PG

- 1 Flue Gas

445

, 486 W

104 T

2

, 215 P

- 88 H CO 2
Product

Ambient

Air 1 7

, 986

, 797 W

59 T

15 P

13 H CO 2 Compression

( Interstage Cooling ) &

Drying 448

, 649 W

85 T

29 P

18 H

Knockout

Water 208

, 676 W

216 T

15 P

803 H Gross Plant Power : 601 MWe

Auxiliary Load : 42 MWe

Net Plant Power : 559 MWe

Net Plant Efficiency

, HHV : 45

. 7 %

Net Plant Heat Rate : 7

, 466 Btu / kWh

State

- of

- the

- art 2013 F

Class Turbine

Cansolv Natural

gas 185

, 483 W

100 T

450 P

20 H 2 7

, 514

, 952 W

95 T

15 P

48 H

8

, 172

, 280 W

242 T

15 P

110 H Generator

Condensate

Pumps 1

, 296

, 395 W

101 T

87 P

69 H 1

, 296

, 395 W

101 T

1 P

69 H 1

, 000 W

1

, 050 T

2

, 415 P

1

, 494 H 978

, 472 W

517 T

74 P

1

, 290 H 779

, 729 W

525 T

74 P

1

, 294 H

Hot Well Condenser

Stack Condensate

From Reboiler

Steam Turbine

makeup

12

, 964 W

59 T

15 P

27 H

Air Inlet

FilterStripperAbsorber Flue Gas Acid Gas

Blower 500

, 780 W

517 T

74 P

1

, 290 H

KO

- Water 2

, 837 W

85 T

62 P

66 H

Gland Seal

Condenser 1

, 000 W

212 T

15 P

180 H LP Turbine Steam to reboiler

HP

Turbine IP

Turbine

6 15

500

, 780 W

304 T

71 P

273 H

14 Preheater HP Economizer 2 /

LP Superheater IP Economizer /

HP Economizer 1 HP

Evaporator HP Pre

Superheater /

IP Superheater HP

Superheater

/ Reheater IP

Evaporator 3 LP

Evaporator LP

Economizer

305

, 087 W

300 T

84 P

270 H

12

, 067 W

301 T

707 P

272 H 979

, 241 W

306 T

3

, 010 P

282 H HP Pump

IP Pump LP Pump 1

, 296

, 395 W

253 T

80 P

222 H HP

BlowdownMain Steam

969

, 448 W

1

, 050 T

2

, 415 P

1

, 494 H IP

BlowdownCold ReheatHot ReheatIP Steam LP Blowdown

11

, 947 W

900 T

621 P

1

, 462 H 966

, 525 W

673 T

621 P

1

, 333 H 302

, 036 W

537 T

74 P

1

, 300 HLP Steam

DOE / NETL

NGCC P LANT

C ASE B 31 B W Flowrate

, lbm / hr

T Temperature

, °F

P Absolute Pressure

, PSIA

H Enthalpy

, Btu / lbm

MWe Power

, Megawatts Electrical

5 Knockout Water

1

, 296

, 395 W

102 T

83 P

70 H 684 T 678 T 882 T 425 T

500 T 310 T

312 T

3

, 051 W

312 T

80 P

283 H

121 W

500 T

679 P

487 H 9

, 792 W

684 T

2

, 774 P

766 H

Condensate

From Dryer Condensate

From Reclaimer Reclaimer Steam Dryer Steam

1

, 656 W

673 T

621 P

1

, 333 H 267 W

673 T

621 P

1

, 333 H 13

978

, 472 W

1

, 050 T

608 P

1

, 545 H

779

, 729 W

101 T

1 P

1

, 018 H 8

, 172

, 280 W

1

, 118 T

15 P

344 H

16 17

18 495 T

1

, 656 W

419 T

306 P

396 H 267 W

397 T

237 P

371 H

4 Vent

327 W

85 T

439 P

59 H 8 9

10

Dryer

12 7

11 445

, 486 W

85 T

419 P

- 3 H 445

, 813 W

85 T

439 P

- 3 HCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 200 This page intentionally left blankCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 201 Exhibit 4

- 27 Case B31B overall energ y balance (0°C [32°F] r eference)

HHV Sensible +

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Natural Gas 4,403

(4,173) 2.9 (2.8)

– 4,406 (4,176)

Air

– 109.5 (103.8)

– 109.5 (103.8)

Raw Water Makeup

– 57.3 (54.3)

– 57.3 (54.3)

Auxiliary Power

– – 150 ( 142) 150 (142)

TOTAL 4,403

(4,173) 169.7 (160.8) 150 (142) 4,723 (4,476)

Heat Out GJ/hr (MMBtu/hr)

Stack Gas

– 377 (357)

– 377 (357)

Sulfur 0 (0) 0.0 (0.0)

– 0.0 (0.0)

Motor Losses and Design

Allowances – – 42 (40) 42 (40)

Condenser

– 888 (842)

– 888 (842)

Non

- Condenser Cooling

Tower Loads – 26 (25)

– 26 (25)

CO
2 – - 41.5 (

- 39.4)

– - 41.5 (

- 39.4)

Cooling Tower Blowdown

– 28.1 (26.6)

– 28.1 (26.6)

CO
2 Capture Losses

– 1,280 (1,213)

– 1,280 (1,213)

Ambient Losses A



### – 37.4 (35.5)

– 37.4 (35.5)

Power

– – 2,163 (2,050) 2,163 (2,050)

TOTAL 0 (0) 2,595 (2,460) 2,205 (2,090) 4,800 (4,550)

Unaccounted Energy B



### – - 77 (

- 73)

– - 77 (

- 73)

A 

### Ambient losses include all losses to the environment through radiation, convection, etc. Sources of these

losses include th e combustor, reheater, superheater, and transformers.

B 

### By difference



## 4.2.9 Case B31B Major Equipment List

Major equipment items for the NGCC plant with CO 2 

## capture are shown in the following tables.

The accounts used in the equipment list correspond to the acco unt numbers used in the cost

estimates in Section 4.2.10 . In general, the design conditions include a 10 percent contingency

for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

Case B31B

– Accou nt 2: Fuel and Sorbent Preparation and Feed

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Gas Pipeline Underground, coated

carbon steel,

wrapped cathodic

protection 70 m 3 / min @ 3.1 MPa

(2,456 acfm @ 450 psia)

39 cm (16 in) standa rd wall pipe 16 km (10

mi ) 0

2 Gas Metering Station

-- 70 m 3 / min (2,456 acfm) 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 202 Case B31B

– Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Demineralized Water

Sto rage Tank Vertical, cylindrical,

outdoor 776,000 liters (205,000 gal) 2 0

2 Condensate Pumps Vertical canned 5,430 lpm @ 70 m H

2 O

(1,430 gpm @ 240 ft H

2 O) 2 1

3 Boiler Feedwater

Pump Horizontal, split case,

multi

- stage, centrifugal,

with interstage bleed for

IP and LP feedwater HP water:

4,100 lpm @ 2,500 m H

2 O

(1,080 gpm @ 8,210 ft H

2 O)

IP water:

050 lpm @ 540 m H

2 O

(10 gpm @ 1,790 ft H

2 O)

LP water:

1,280 lpm @ 14.0 m H

2 O

(340 gpm @ 50 ft H

2 O) 2 1

4 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

5 Service Air

Compressors Flooded Screw 13 m 3 / min @ 0.7 MPa

(450 scfm @ 100 psig) 2 1

6 Instrument Air Dryers Duplex, regenerative 13 m 3 / min (450 scfm) 2 1

7 Closed Cycle Cooling

Heat Exchangers Plate and frame 13 MMkJ/hr (13 MMBtu/hr) 2 0

8 Closed Cycle Cooling

Water Pumps Horizontal centrifugal 5,200 lpm @ 20 m H

2 O

(1,400 gpm @ 70 ft H

2 O) 2 1

9 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

10 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

11 Ra w Water Pumps Stainless steel, single

suction 8,500 lpm @ 20 m H

2 O

(2,200 gpm @ 60 ft H

2 O) 2 1

12 Filtered Water

Pumps Stainless steel, single

suction 170 lpm @ 50 m H

2 O

(50 gpm @ 160 ft H

2 O) 2 1

13 Filtered Water Tank Vertical, cylindrical 164,000 liter (43,000 gal) 1 0

14 Makeup Water

Demineralizer Multi

- media filter,

cartridge filter, RO

membrane assembly

and electro

- deionization

unit 360 lpm (100 gpm) 1 0

15 Liquid Waste

Treatment System N/A 10 years, 24

- hour storm 1 0



## Case B31B

– Account 5B: Carbo n Dioxide Recovery

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Cansolv Amine

- based CO
2 capture technology 4,078,000 kg/hr (8,990,000 lb/hr)

6.1 wt % CO
2 concentration 1 0

2 Cansolv LP

Condensate Pump Centrifugal 492 lpm @ 1 m H

2 O

(130 gpm @ 4 ft H

2 O) 1 1

3 Cansolv HP

Condensate Pump Centrifugal 2 lpm @ 5 m H

2 O

(1 gpm @ 15 ft H

2 O) 1 1

4 CO
2 Dryer Triethylene glycol Inlet: 53.0 m 3 / min (1,880 acfm)

@ 3.0 MPa (439 psia)

Outlet: 2.9 MPa (419 psia)

Water Recovered: 148 kg/hr

(327 lb/hr) 1 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 203 Equipment

No. Description Type Design Condition Operating

Qty. Spares

5 CO
2 Compressor Integrally geared,

multi

- stage

centrifugal 111,105 kg/hr @ 15.3 MPa

(244,944 lb/hr @ 2,215 psia) 2 0



## Case B31B

– Account 6: Combustion Turbine and Accessories

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Combustion

Turbine State

- of

- the

- a rt 2013 F

- c lass

w/ dry low

- NOx burner 210 MW 2 0

2 Combustion

Turbine

Generator TEWAC 230 MVA @ 0.9 p.f.,

24 kV, 60 Hz, 3

- phase 2 0



## Case B31B

– Account 7: HRSG, Ducting, and Stack

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Stack CS plate, type 409SS

liner 46 m (150 ft) high x

7.0 m (23 ft) diameter 2 0

2 Heat Recovery

Steam Generator Drum, multi

- pressure

with economizer section

and integral deaerator Main steam

- 241,854 kg/hr,

16.5 MPa/566°C

(533,197 lb/hr, 2,400

psig/1 ,050°F)

Reheat steam

- 244,105 kg/hr,

4.1 MPa/566°C

(538,160 lb/hr, 593

psig/1,050°F) 2 0

3 SCR Reactor Space for spare layer 1,870,000 kg/hr

(4,130,000 lb/hr) 2 0

4 SCR Catalyst

-- Space available for an

additional catalyst layer 1 layer 0

5 Dilutio n Air Blowers Centrifugal 10 m 3 / min @ 108 cm WG

(190 scfm @ 42 in WG) 2 1

6 Ammonia Feed Pump Centrifugal 1.2 lpm @ 90 m H

2 O

(0.3 gpm @ 300 ft H

2 O) 2 1

7 Ammonia Storage

Tank Horizontal tank 33,000 liter (9,000 gal) 1 0



## Case B31B

– Account 8: Steam Tur bine Generator and Auxiliaries

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Steam Turbine Commercially available

advanced steam turbine 189 MW

16.5 MPa/566°C/566°C (2400

psig/ 1050°F/1050°F) 1 0

2 Steam Turbine

Generator Hydrog en cooled, static

excitation 210 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 1 0

3 Surface Condenser Single pass, divided

waterbox including

vacuum pumps 980 GJ/hr (930 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 0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 204 Case B31B

– Account 9: Cooling Water System

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 Circulating

Water Pumps Vertical, wet pit 433,000 lpm @ 30 m

(1 14,000 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 /

2410 GJ/hr (2290 MMBtu/hr) heat duty 1 0



## Case B31B

– Account 11: Accessory Electric Plant

Equipment

No. Des cription Type Design Condition Operating

Qty. Spares

1 CTG Transformer Oil

- filled 24 kV/345 kV, 230

MVA, 3

- ph, 60 Hz 2 0

2 STG Transformer Oil

- filled 24 kV/345 kV, 180

MVA, 3

- ph, 60 Hz 1 0

3 High Voltage Auxiliary

Transformer Oil

- filled 345 kV/13.8 kV, 8

MVA, 3

- ph, 60 Hz 2 0

4 Medium Voltage Transformer Oil

- filled 24 kV/4.16 kV, 28

MVA, 3

- ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 4

MVA, 3

- ph, 60 Hz 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 Gen erator Sized for emergency

shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 0



## Case B31B

– Account 12: Instrumentation and Control

Equipment

No. Description Type Design Condition Operating

Qty. Spares

1 DCS

- Main

Control Monitor/keyboard; Operator

printer (laser co lor); Engineering

printer (laser B&W) Operator stations/printers

and engineering

stations/printers 1 0

2 DCS

- Processor Microprocessor with redundant

input/output N/A 1 0

3 DCS

- Data

Highway Fiber optic Fully redundant, 25% spare 1 0



## 4.2.10 Case B31B

– Cost Estimating

The cost estimating methodology was described previously in Section 2.7

. Exhibit 4

- 28 shows a

detailed breakdown of the capital costs ; Exhibit 4

- 29 shows the owner’s costs , TOC, and TASC ;

Exhibit 4

- 30 shows the initial and annual O&M costs; and Exhibit 4

- 31 shows the COE

breakdown.

T h e estimated TP C of the NGCC with CO 2 

## capture is $1,4 81 /kW. Process contingency

represents 5. 0 percent of the TP C and project contingency represents 13. 0 percent. The COE,

including CO 2 

## T&S costs of $ 4.0 /M Wh, is $ 87. 3 /M Wh.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 205 Exhibit 4

- 28 Case B31B total plant cost details

Case: B31B

– 2x1 CT NGCC w/ CO 2 Estimate Type: Conceptual

Plant Size (MW,net): 559 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencie s Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $ /1,000 $/kW

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $3,216 $3,330 $2,720 $0 $9,266 $834 $0 $1,515 $11,615 $21

3.2 Water Makeup & Pretreating $2,58 7 $267 $1,328 $0 $4,182 $376 $0 $912 $5,470 $10

3.3 Other Feedwater Subsystems $1,507 $498 $416 $0 $2,421 $218 $0 $396 $3,034 $5

3.4 Service Water Systems $312 $623 $2,007 $0 $2,942 $265 $0 $641 $3,849 $7

3.5 Other Boiler Plant Systems $2,105 $786 $1,80 9 $0 $4,700 $423 $0 $768 $5,892 $11

3.6 Natural Gas, incl. pipeline $17,693 $631 $546 $0 $18,871 $1,698 $0 $3,085 $23,655 $42

3.7 Waste Treatment Equipment $904 $0 $523 $0 $1,427 $128 $0 $311 $1,866 $3

3.8 Misc. Equip. (Cranes, Air Comp.,

Comm.) $1,206 $161 $586 $0 $1,953 $176 $0 $426 $2,555 $5

Subtotal $29,530 $6,297 $9,935 $0 $45,762 $4,119 $0 $8,055 $57,936 $104

5B CO 2 Removal & Compression

5B.1 CO
2 Removal System $99,453 $41,537 $86,184 $0 $227,175 $18,462 $41,028 $52,926 $339,591 $608

5B.2 CO
2 Compression & Drying $18,852 $2,828 $7,821 $0 $29,501 $2,655 $0 $6,431 $38,587 $69

Subtotal $118,305 $44,365 $94,006 $0 $ 256,676 $21,118 $41,028 $59,357 $378,178 $677

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $104,200 $0 $6,341 $0 $110,541 $9,949 $0 $12,049 $132,539 $237

6.9 Combustion Turbine Foundations $0 $879 $950 $0 $1,829 $165 $0 $399 $2,3 92 $4

Subtotal $104,200 $879 $7,291 $0 $112,370 $10,113 $0 $12,448 $134,931 $241

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $31,120 $0 $5,773 $0 $36,893 $3,320 $0 $4,021 $44,235 $79

7.2 SCR System $1,973 $829 $1,156 $0 $3,957 $356 $0 $647 $4,960 $9

7.9 HRSG, Duct & Stack Foundations $0 $442 $415 $0 $857 $77 $0 $187 $1,121 $2

Subtotal $33,093 $1,271 $7,344 $0 $41,707 $3,754 $0 $4,855 $50,316 $90

8 Steam Turbine Generator

8.1 Steam TG & Accessories $32,860 $0 $4,812 $0 $37,672 $3,3 90 $0 $4,106 $45,168 $81

8.2 Turbine Plant Auxiliaries $195 $0 $434 $0 $629 $57 $0 $69 $754 $1

8.3 Condenser & Auxiliaries $2,260 $0 $1,210 $0 $3,470 $312 $0 $378 $4,160 $7

8.4 Steam Piping $12,240 $0 $4,961 $0 $17,201 $1,548 $0 $2,812 $21,561 $39

8.9 TG Foundations $0 $836 $1,380 $0 $2,216 $199 $0 $483 $2,899 $5

Subtotal $47,555 $836 $12,796 $0 $61,188 $5,507 $0 $7,848 $74,543 $133

9 Cooling Water System

9.1 Cooling Towers $4,260 $0 $1,290 $0 $5,550 $500 $0 $605 $6,654 $12

9.2 Circulating Water P umps $2,038 $0 $125 $0 $2,163 $195 $0 $236 $2,593 $5

9.3 Circ. Water System Auxiliaries $162 $0 $21 $0 $184 $17 $0 $20 $220 $0

9.4 Circ. Water Piping $0 $5,032 $1,139 $0 $6,171 $555 $0 $1,009 $7,735 $14

9.5 Make

- up Water System $389 $0 $500 $0 $889 $80 $0 $145 $1,115 $2

9.6 Component Cooling Water Sys $324 $387 $248 $0 $959 $86 $0 $157 $1,202 $2

9.9 Circ. Water System Foundations $0 $2,294 $3,809 $0 $6,103 $549 $0 $1,330 $7,982 $14

Subtotal $7,173 $7,712 $7,133 $0 $22,018 $1,982 $0 $3,502 $27,502 $49Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 206 Case: B31B

– 2x1 CT NGCC w/ CO 2 Estimate Type: Conceptual

Plant Size (MW,net): 559 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencie s 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 $7,182 $0 $4,248 $0 $11,430 $1,029 $0 $934 $13,393 $24

11.2 Station Service Equipment $2,478 $0 $213 $0 $2,690 $242 $0 $220 $3,153 $6

11.3 Switchgear & Motor Control $3,049 $0 $530 $0 $3,578 $322 $0 $390 $4,290 $8

11.4 Conduit & Cable Tray $0 $1,593 $4,590 $0 $6,183 $556 $0 $1,011 $7,750 $14

11.5 Wire & Cable $0 $5,120 $2,911 $0 $8,031 $723 $0 $1,313 $10,067 $18

11.6 Protective Equipment $0 $713 $2,474 $0 $3,187 $287 $0 $347 $3,821 $7

11.7 Stan dby Equipment $125 $0 $116 $0 $241 $22 $0 $26 $288 $1

11.8 Main Power Transformers $13,433 $0 $182 $0 $13,615 $1,225 $0 $1,484 $16,324 $29

11.9 Electrical Foundations $0 $157 $399 $0 $556 $50 $0 $121 $727 $1

Subtotal $26,265 $7,583 $15,662 $0 $49,510 $4,456 $0 $5,847 $59,813 $107

12 Instrumentation & Control

12.4 Other Major Component Control $998 $0 $636 $0 $1,634 $147 $82 $279 $2,142 $4

12.6 Control Boards, Panels & Racks $298 $0 $182 $0 $481 $43 $24 $82 $630 $1

12.7 Computer & Accessories $4,77 5 $0 $146 $0 $4,921 $443 $246 $561 $6,170 $11

12.8 Instrument Wiring & Tubing $0 $888 $1,572 $0 $2,460 $221 $123 $421 $3,225 $6

12.9 Other I & C Equipment $1,780 $0 $4,121 $0 $5,901 $531 $295 $673 $7,400 $13

Subtotal $7,851 $888 $6,657 $0 $15,396 $1,38 6 $770 $2,016 $19,568 $35

13 Improvements to Site

13.1 Site Preparation $0 $112 $2,378 $0 $2,490 $224 $0 $543 $3,257 $6

13.2 Site Improvements $0 $1,026 $1,356 $0 $2,382 $214 $0 $519 $3,115 $6

13.3 Site Facilities $2,095 $0 $2,198 $0 $4,293 $386 $0 $9 36 $5,615 $10

Subtotal $2,095 $1,138 $5,931 $0 $9,164 $825 $0 $1,998 $11,987 $21

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $303 $160 $0 $463 $42 $0 $76 $581 $1

14.2 Steam Turbine Building $0 $2,195 $2,921 $0 $5,116 $460 $0 $836 $6,412 $11

14.3 Administration Building $0 $584 $395 $0 $979 $88 $0 $160 $1,227 $2

14.4 Circulation Water Pumphouse $0 $186 $92 $0 $277 $25 $0 $45 $348 $1

14.5 Water Treatment Buildings $0 $549 $500 $0 $1,049 $94 $0 $172 $1,315 $2

14.6 Machine Shop $0 $506 $ 324 $0 $830 $75 $0 $136 $1,040 $2

14.7 Warehouse $0 $327 $197 $0 $524 $47 $0 $86 $657 $1

14.8 Other Buildings & Structures $0 $98 $71 $0 $169 $15 $0 $28 $212 $0

14.9 Waste Treating Building & Str. $0 $383 $684 $0 $1,067 $96 $0 $174 $1,337 $2

Subtotal $0 $5,131 $5,344 $0 $10,475 $943 $0 $1,713 $13,130 $23

Total $376,068 $76,100 $172,100 $0 $624,267 $54,201 $41,798 $107,639 $827,904 $1,481Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 207 Exhibit 4

- 29 Case B31B owner’s costs

Description $ / 1,000 $/k W

Pre

- Production Costs

6 Months All Labor $5,405 $10

1 Month Maintenance Materials $851 $2

1 Month Non

- fuel Consumables $767 $1

1 Month Waste Disposal $0 $0

25% of 1 Months Fuel Cost at 100% CF $4,679 $8

2% of TPC $16,558 $30

Total $28,260 $51

Inv entory Capital

60 day supply of fuel and consumables at 100% CF $1,239 $2

0.5% of TPC (spare parts) $4,140 $7

Total $5,378 $10

Other Costs

Initial Cost for Catalyst and Chemicals $0 $0

Land $300 $1

Other Owner's Costs $124,186 $222

Financing Costs $22,353 $40

Total Overnight Costs (TOC) $1,008,381 $1,804

TASC Multiplier (IOU, high

- risk, 33 year) 1.078

Total As

- Spent Cost (TASC) $1,087,034 $1,945Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 208 Exhibit 4

- 30 Case B31B initial and annual opera ting and maintenance costs

Case: B31B

– 2x1 CT NGCC w/ CO 2 Cost Base: Jun 2011

Plant Size (MW,net): 559 Heat Rate

- net (Btu/kWh): 7,466 Capacity Factor (%): 85

Operating & Maintenance Labor

Operating Labor Operating Labor Requirements per Shift

Oper ating Labor Rate (base): 39.70 $/hour Skilled Operator: 1.0

Operating Labor Burden: 30.00 % of base Operator: 3.3

Labor O

- H Charge Rate: 25.00 % of labor Foreman: 1.0

Lab Techs, etc.: 1.0

Total: 6.3

Fixed Operating Costs

Annu al Cost

($) ($/kW

- net)

Annual Operating Labor: $2,861,816 $5.120

Maintenance Labor: $5,785,827 $10.351

Administrative & Support Labor: $2,161,911 $3.868

Property Taxes and Insurance: $16,558,081 $29.623

Total: $27,367,635 $48 .961

Variable Operating Costs

($) ($/M Wh

- net)

Maintenance Material: $8,678,741 $2.08520

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 2,897 $1.67 $0 $1,504,337 $0.36144

Makeup an d Waste Water

Treatment Chemicals (lbs): 0 17,257 $0.27 $0 $1,433,984 $0.34454

CO 2 Capture System Chemicals A Proprietary

SCR Catalyst (m 3 ): w/equip. 0.08 $8,938.80 $0 $229,246 $0.05508

Triethylene Glycol (gal) 0 165 $6.57 $0 $337,099 $0.08099

Ammonia (19% NH 3 , ton): 0 3.05 $330.00 $0 $311,902 $0.07494

Subtotal: $0 $7,820,762 $1.87905

Waste Disposal

Amine Purification Unit Waste (ton) 0 4.01 $0.00 $0 $0 $0.00000

Thermal Reclaimer Unit Waste (ton) 0 0.37 $0.00 $0 $0 $0.00000

Prescrubber Blowdown Waste (ton) 0 0.00 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000

Variable Operating Costs Total: $0 $16,499,502 $3.96425

Fuel Cost

Natural Gas (MMBtu): 0 100,384 $6.13 $0 $190,912,983 $45.86966

Total: $0 $190,912,983 $45.86966

A 

### CO 2 

### Ca pture System Chemicals includes Ion Exchange Resin, NaOH, and Cansolv Solvent.

Exhibit 4

- 31 Case B31B COE breakdown

Component Value, $/MWh Percentage

Capital 26.9 31%

Fixed 6.6 8%

Variable 4.0 5%

Fuel 4 5.9 53%

Total (Excluding T&S) 83.3 N/A

CO 2 

### T&S 4.0 5%

Total (Including T&S) 87.3 N/ACost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 209 

# 4.3 NGCC Case Summary

The performance results of the two NGC C plant configurations modeled in this report are

summarized in Exhi bit 4

- 32

.

Exhibit 4

- 32 Estimated performance and cost results for NGCC cases

NGCC

State

- o f

- the

- a rt 2013 F

- Class

Case B31A Case B31B

PERFORMANCE

Nominal CO 2 Capture 0% 90%

Capacity Factor 85% 85%

Gross Power Output (MWe) 641 601

Auxiliary Power Requirement (MWe) 11 42

Net Power Output (MWe) 630 559

Coal Flow rate (lb/hr) N/A N/A

Natural Gas Flow rate (lb/hr) 185,484 185,484

HHV Thermal Input (kW t 

### ) 1,223,032 1,223,032

Net Plant HHV Efficienc y (%) 51.5% 45.7%

Net Plant HHV Heat Rate (Btu/kWh) 6,629 7,466

Raw Water Withdrawal, gpm 2,646 4,023

Process Water Discharge, gpm 595 999

Raw Water Consumption, gpm 2,051 3,024

CO 2 Emissions (lb/MMBtu) 119 12

CO 2 Emissions (lb/MWh

- gross) 773 82

CO 2 Emissions (lb/MWh

- net) 786 89

SO 2 Emissions (lb/MMBtu) 0.001 0.000

SO 2 Emissions (lb/MWh

- gross) 0.006 0.000

NOx Emissions (lb/MMBtu) 0.003 0.003

NOx Emissions (lb/MWh

- gross) 0.020 0.022

PM Emissions (lb/MMBtu) 0.000 0.000

PM Emissions (lb/MWh

- gross) 0.000 0.000

Hg Emissions (lb/TBtu) 0.000 0.000

Hg Emissions (lb/MWh

- gross) 0.00E

- 06 0.00E

- 06

COST

Total Plant Cost (2011$/kW) 685 1,481

**Bare Erected Cost** 561 1,117

**Home Office Expenses**  51 97

**Project Contingency** 73 193

**Process Contingency** 0 75

T otal Overnight Cost (2011$/MM ) 528 1,008

Total Overnight Cost (2011$/kW) 838 1,804

**Owner's Costs** 154 323

Total As

- Spent Cost (2011$/kW) 901 1,945

COE ($/MWh) (excluding T&S) 57.6 83.3

**Capital Costs** 11.8 26. 9

**Fixed Costs** 3. 4 6. 6

**Variable Costs** 1. 7 4.0

**Fuel Costs** 40.7 45. 9

**COE ($/MWh) (including T&S)** 57.6 87. 3

**CO** 2 **T&S Costs** 0.0 4.0Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 210 The following observations can be made regarding plant performance with reference to

Exhibit 4

- 32 :

• The efficiency of the NGCC case with no CO 2 

## capture is 51.5 percent (HHV basis).

Gas Turbine World provides estimated performance for a state

- of

- the

- art 2013 F

- class

turbine operated on natural gas in a combined cycle mode, and the reported efficiency

is 58.0 percent (LHV basis). (44) Adjusting the result from this report to an LHV

basis results in an efficiency of 57.0 percent.

• The efficiency penalty to add CO 2 

## capture in t he NGCC case is 5.8 absolute percent.

The efficiency reduction is caused primarily by the auxiliary loads of the capture

system and CO 2 

## compression as well as the significantly increased cooling water

requirement, which increases the auxiliary load of the CWPs and the cooling tower

fan. CO 2 

## capture results in a 31 MW increase in auxiliary load compared to the non

capture case.

The components of TOC and overall TASC are shown for the two NGCC cases in Exhibit 4

- 33

. The addition o f CO 2 

## capture more than doubles the TOC cost of the NGCC plant. The process

contingency included for the capture process totals $ 75 /kW, which represents approximately 4

percent of the TOC.

Exhibit 4

- 33 Pla nt capital cost for NGCC cases

Source: NETL



## Exhibit 4

- 34 shows that at the study natural gas price, the fuel represents a significant fraction of

the total. The fuel component of COE represents 71 percent of the total in the non

- capture case

and 53 percent of the total in the CO 2 

## capture case. The CO 2 

## T&S component of COE is only 5

percent of the total in the CO 2 

## capture case.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 211 Exhibit 4

- 34 COE of NGCC cases

Sou rce: NETL



## The sensitivity of NGCC COE to CF is shown in Exhibit 4

- 35 . NGCC is relatively insensitive to

CF but highly sensitive to fuel cost ( as shown in Exhibit 4

- 36 ) b ec ause of the relatively small

capital comp onent

. As the capacity factor drops, t he decrease in net production is nearly offset

by a corresponding decrease in fuel cost. A 33 percent increase in natural gas price (from $6 .13

to $8 .15 /MMBtu) results in a CO E increase of 23 percent in the non

- capture case and 17 percent

in the CO 2 

## capture case. Because of the higher capital cost in the CO 2 

## capture case, the impact

of fuel price changes is slightly diminished.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 212 Exhibit 4

- 35 Sensitivity of COE to capacity factor in NGCC cases

Source: NETL

Exhibit 4

- 36 Sensitivity of COE to fuel price in NGCC cases

Source: NETL



## T he first year CO 2 

## avoided and captured costs were calculated (the methodology and equations

were provided in Section 2.7.4 ), and the results for the NGCC cases are presented in ExhibitCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 213 4

- 37

. The cost of CO 2 

## captured is $ 71 /tonne ($ 65 /ton) and the co st of CO 2 

## avoided is $ 94 /tonne

($ 85 /ton) using NGCC without CO 2 

## capture as the reference.

Exhibit 4

- 37 First year cost of CO 2 

### captured and avoided in NGCC cases

Source: NETL



## The normalized water withdra wal, process discharge and raw water consumption are shown in

Exhibit 4

- 38

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 214 Exhibit 4

- 38 Raw water withdrawal and consumption in NGCC cases

Source: NETL



## The followi ng observations can be made:

• Normalized water withdrawal increases 71 percent and normalized raw water

consumption 66 percent in the CO 2 

## capture case. The high cooling water demand of

the capture process results in a large increase in cooling tower makeup requirements.

• Cooling tower makeup comprises approximately 99 percent of the raw water

consumption in both NGCC cases. The only internal recycle stream in the non

capture case is the BFW blowdown, which is recycled to the cooling tower. In the

CO 2 

## captu re cases, condensate is recovered from the flue gas as it is cooled to the

absorber temperature of 30°C (86°F) and is also recycled to the cooling tower.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 215 

# 5 Results Analysis

Summaries of the indiv id ual technologies were provided in Sections 3 and 4 . This section

provides the results of all technologies for cross

- comparison.



# 5.1 Performance

Exhibit 5

- 1 provides a summary of the performance and environmental profile for all cases.

Exhibit 5

- 1 P erformance summary and environmental profile for all cases

Pulverized Coal Boiler NGCC

PC Subcritical PC Supercritical State

- of

- the

- art 2013

F

- Class

Case Name B11A B11B B12A B12B B31A B31 B

PERFORMANCE

Gross Power Output (MWe) 581 644 580 642 641 601

Auxiliary Power Requirement (MWe) 31 94 30 91 11 42

Net Power Output (MWe) 550 550 550 550 630 559

Coal Flow rate (lb/hr) 412,005 516,170 395,053 495,578 N/A N/A

Natural Gas Flow rate (lb /hr) N/A N/A N/A N/A 185,484 185,484

HHV Thermal Input (kW t 

### ) 1,408,630 1,764,768 1,350,672 1,694,366 1,223,032 1,223,032

Net Plant HHV Efficiency (%) 39.0% 31.2% 40.7% 32.5% 51.5% 45.7%

Net Plant HHV Heat Rate (Btu/kWh) 8,740 10,953 8,379 10,508 6,629 7 ,466

Raw Water Withdrawal, gpm 5,538 8,441 5,105 7,882 2,646 4,023

Process Water Discharge, gpm 1,137 1,920 1,059 1,813 595 999

Raw Water Consumption, gpm 4,401 6,521 4,045 6,069 2,051 3,024

CO 2 

### Capture Rate, % 0 90 0 90 0 90

CO 2 Emissions (lb/MMBtu) 204 20 204 20 119 12

CO 2 Emissions (lb/MWh

- gross) 1,683 190 1,618 183 773 82

CO 2 Emissions (lb/MWh

- net) 1,779 223 1,705 214 786 89

SO 2 Emissions (lb/MMBtu) 0.085 0.000 0.085 0.000 0.001 0.000

SO 2 Emissions (lb/MWh

- gross) 0.700 0. 000 0.673 0.000 0.006 0.000

NOx Emissions (lb/MMBtu) 0.085 0.075 0.088 0.078 0.003 0.003

NOx Emissions (lb/MWh

- gross) 0.700 0.700 0.700 0.700 0.020 0.022

PM Emissions (lb/MMBtu) 0.011 0.010 0.011 0.010 0.000 0.000

PM Emissions (lb/MWh

- gross) 0.090 0.09 0 0.090 0.090 0.000 0.000

Hg Emissions (lb/TBtu) 0.363 0.321 0.377 0.333 0.000 0.000

Hg Emissions (lb/MWh

- gross) 3.00E

- 06 3.00E

- 06 3.00E

- 06 3.00E

- 06 0.00E+00 0.00E+00



## 5.1.1 Energy Efficiency

A graph of the net plant efficiency (HHV basis) is provided in Exhibit 5

- 2

.

The primary conclusions that can be drawn are:

• The NGCC cases have the highest net efficiency of all the technologies, both without

CO 2 

## capture (51.5 percent) and with CO 2 

## capture (45.7 percent). The next highest

efficien cy is the non

- capture SC PC case, with an efficiency of 40.7 percent.

• For the PC cases, adding CO 2 

## capture results in a relative efficiency penalty of 20 percent

(8 percentage points).

• For the NGCC case, adding CO 2 

## capture results in a relative efficiency penalty of 11

percent ( 6 percentage points ) . The NGCC penalty is less than the PC penalty because:Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 216 o Natural gas is less carbon intensive than coal (b ased on the fuel compositions

used in this study, natural gas contains 32 lb carbon/MM Btu of heat input and

coal contains 5 6 lb/MMBtu).

o The NGCC non

- capture plant is more efficient, thus there is less total CO 2 

## to

capture and compress (NGCC non

- capture CO 2 

## emissions are approximately 54

- 56 percent lower than the PC cases) when normalized to equivalent net power

outputs.

o These effects are offset slightly by the lower concentration of CO 2 

## in the NGCC

flue gas (4% vs. 13% for PC). When normalized to CO 2 

## captured, the energy

penalty is 0.16 kWh and 0.13 kWh per lb of CO 2 

## captured for NGCC and PC,

respectively.

Exhi bit 5

- 2 Net plant efficiency (HHV basis)

Source: NETL



## 5.1.2 Environmental Emissions

Natural gas does not contain Hg, PM, or HCl, which makes its environmental profile more

attractive compared to PC cases. In t his report it was assumed that the only sulfur present in

natural gas is from the addition of the odorant, mercaptan. This results in a n SO 2 

## emission rate

below the regulatory limits without any further control

.

Estimated emissions of Hg, PM, NOx, and SO 2 

## are all at or below the applicable regulatory

limits currently in effect for all cases (PC and NGCC)



## 5.1.3 Water Use

Three water values are presented for each technology in Exhibit 5

- 3 : raw water withdrawal,

process discharge, and raw water consumption. Each value is normalized by net output.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 217 Exhibit 5

- 3 Raw water withdrawal and consumption

Source: NETL



## The primary conclusions that can be drawn are:

• NGCC has the lowest raw water cons umption of all cases for both non

- capture and

CO 2 

## capture cases with the relative normalized raw water consumption for the

technologies being 2.2:1.0 (SCPC:NGCC). The relat ive results are expected given

the higher steam turbine output in the PC cases

, whi ch results in higher condenser

duties, higher cooling water flows, and

, ultimately

, higher cooling water makeup

.

• CO 2 

## capture imposes a significant water demand on all technologies. The post

combustion capture technology has a significant cooling water d emand that results in

increased raw water consumption because of increased cooling tower blowdown and

cooling tower evaporative losses. The normalized raw water consumption increases

by 62 percent for the NGCC case, 50 percent for the SC PC case, and 48 p ercent for

the subcritical PC case. The relative increases reflect the smaller non

- capture water

requirements that result from less power output generated by the steam turbine.

Despite the lower relative water consumption increase for the PC cases, they still

have the largest normalized raw water consumption of the capture technologies:

2. 0 :1.0 (PC: NGCC).Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 218 

# 5.2 C ost Results

Exhibit 5

- 4 provides a summary of the costs for all cases.

Exhibit 5

- 4 Cost summary for all cases

Pulverized Coal Boiler NGCC

PC Subcritical PC Supercritical State

- of

- the

- art 2013

F

- Class

Case Name B11A B11B B12A B12B B31A B31B

COST

Total Plant Cost (2011$/kW) 1,960 3,467 2,026 3,524 685 1,481

**Bare Erect ed Cost**  1,582 2,665 1,646 2,716 561 1,117

**Home Office Expenses** 158 257 165 263 51 97

**Project Contingency** 220 427 216 430 73 193

**Process Contingency** 0 118 0 115 0 75

T otal Overnight Cost (2011$/MM ) 1,336 2,346 1,379 2,384 528 1,008

Total Overnight C ost (2011$ /kW ) 2,429 4,267 2,507 4,333 838 1,804

**Owner's Costs** 469 800 480 809 154 323

Total As

- Spent Cost (2011$ /kW ) 2,755 4,865 2,842 4,940 901 1,945

COE ( $/MWh ) (excluding T&S) 82.1 133.5 82.3 133. 2 57.6 83.3

**Capital Costs** 37.8 71.1 39.0 72.2 11.8 26. 9

**Fixed Costs** 9.3 15.1 9.6 15.4 3. 4 6. 6

**Variable Costs** 9.2 15.1 9.1 14.7 1. 7 4.0

**Fuel Costs** 25.7 32.2 24.6 30.9 40.7 45. 9

COE ( $/MWh ) (including T&S) 82.1 143.5 82.3 142.8 57.6 87. 3

**CO** 2 **T&S Costs** 0.0 10.0 0.0 9.6 0.0 4.0

CO 2 

### Captured Cost (excluding T&S)

, $/tonne N/A 56.2 N/A 58.2 N/A 71.1

CO 2 

### Avoided Cost (including T&S)

, $/tonne N/A 91.0 N/A 89.4 N/A 93.8

*Cases without capture use conventional financing; all others use high

- risk f inancial asssumptions

consistent with NETL’s “QGESS: Cost Estimation Methodology for NETL Assessments of Power Plant

Performance.” (1)



## 5.2.1 TOC and TASC

In Exhibit 5

- 5 , the normalized components of TOC and overall TASC are shown for each

technology.

The following conclusions can be drawn:

• Based on total overnight cost (TOC) in $/kW, NGCC ca pital costs are approximately

34 % and 42% of the PC capital costs for non

- capture and capture cases, respectively.

• The NGCC cost advantage over PC is partially enabled by the lack of emission

control equipment necessitated for the adherence to current regulations.

• The addition of CO 2 

## capture technology significantly impacts all technologies. The

TOC increases by 76 perce nt for subcritical PC, 73 percent for SC PC, and 115

percent for NGCC.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 219 Exhibit 5

- 5 Plant capital costs

Source: NETL

Note: TOC expressed in 2011 dollars. TASC expressed in 2011 to 2015 mixed

- year dollars for PC and

2011 to 2013 mixed

- year dollars for NGCC



## 5.2.2 COE

A graph of the net plant efficiency (HHV basis) is provided in Exhibit 5

- 6

.

The primary conclusions that can be drawn are:

• NGCC plant COEs are 70% and 61% of the PC plant COE s, for non

- capture and capture

cases, respectively.

• The capital cost component represents the largest portion of the COE in PC cases,

ranging from 46

- 51 percent of the total COE. The capital cost in NGCC cases represents

21

- 31 percent of the total COE.

• The fuel cost component represents the largest portion of the COE in NGCC cases,

ranging from 53

- 71 percent of the total COE. The fuel cost in PC cases represents 22

- 31

percent of the total COE.

• CO 2 

## T&S costs add between $ 4/M Wh (NGCC) and $ 10 /M Wh (PC) to the COE, which is

le ss than 7 percent of the total for all capture cases.

• While NGCC plants were impacted the most significantly by the addition of CO 2 

## capture

in terms of TOC, due to the small capital component of NGCC plants without CO 2 

## capture (the cos t of fuel is the most significant aspect of the COE for NGCC cases), the

NGCC based plants incurred a smaller increase i n COE than PC based plants (52 percent

versus 74

- 75 percent)

.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 220 Exhibit 5

- 6 COE by cost component

Source: NETL



## 5.2.3 CO 2 

## Emission Price Impact

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

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

will be impact ed to a larger extent than those with carbon capture, and coal

- based technologies

will be impacted more than natural gas

- based technologies.

The cost of CO 2 

## avoided is shown in Exhibit 5

- 7 as the intersection of the CO 2 

## capture PC case

lines with the line for the SC PC non

- capture case and the intersection of the NGCC CO 2 

## capture

case line with the line for the NGCC non

- capture case. For example, the cost of CO 2 

## avoided is

$89 .4 /tonne ($81 .1 /ton) for SC PC and $93 .8 /tonne ($8 5.1 /to n) for NGCC.

The curves in Exhibit 5

- 7 represent the study design conditions (capacity factor) and fuel prices

used for each technology; namely an 8 5 percent capacity factor and $2.78/GJ ($2.94/MMBtu) for

coal and $5.81/GJ ($6.13 /MMBtu) for natural gas.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 221 Exhibit 5

- 7 Impact of carbon emissions price on study technologies

Source: NETL



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

• The CO 2 

## emission pric e impact on COE for the subcritical PC and SC PC cases is

indistinguishable for both the CO 2 

## capture cases and the non

- capture cases.

• At the baseline study conditions, non

- capture SC PC diverges rapidly from non

capture NGCC as the CO 2 

## emission cost increa ses. The lower carbon intensity of

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

account for this effect.

The impact of CO 2 

## emissions price and natural gas price and the implications on the

competitiveness of the capture t echnologies can also be considered in a “phase diagram” type

plot

, as shown in Exhibit 5

- 8 . The lines in the plot represent cost parity between different pairs

of technologies.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 222 Exhibit 5

- 8 Lowest cost power generation options c omparing NGCC and PC

Source: NETL



## The plot demonstrates the following points:

• Non

- capture plants are the low

- cost option below a CO 2 

## price of $78/tonne ($71/ton).

• NGCC is always preferred when natural gas prices are below $10/MMBtu (and a

capacity factor of 85 percent).

• Coal plants are always preferred when natural gas prices are above $1 5 /MMBtu.



## 5.2.4 CO 2 

## Sales Price Impact

Sale of the captured CO 2 

## for utilization and storage in CO 2 

## enhanced oil recovery (EOR) has the

potential to provide a revenue stream to both the SC PC and NGCC 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 re presents 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 

## captured is shown in Exhibit 5

- 9 as the intersection of the CO 2 

## capture PC ca se

lines with the line for the SC PC non

- capture case

, and the intersection of the NGCC CO 2 

## capture case line with the line for the NGCC non

- capture case. For example, when looking at the

exhibit, the cost of CO 2 

## captured is $58/tonne ($53/ton) for SC PC a nd $71/tonne ($64/ton) for

NGCC.

The curves in Exhibit 5

- 9 represent the study design conditions (capacity factor) and fuel prices

used for each technology; namely 85 percent for PC and NGCC plants, and $2.78/GJ

($2.94/MMBtu) for coal and $5.81/GJ ($6.13 /MMBtu) for natural gas.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 223 Exhibit 5

- 9 Impact of carbon sales price on study technologies

Source: NETL



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

• Th e CO 2 

## sales price impact on COE for the subcritical PC and SC PC cases is

indistinguishable for both the CO 2 

## capture cases and the non

- capture cases.

• At the baseline study conditions, increasing the price of CO 2 

## for EOR sales has a

greater effect on PC tha n on NGCC.

• At a CO 2 

## sales price of $90/tonne, the cost of NGCC with CO 2 

## capture is nearly equal

to that of the subcritical PC and SC PC CO 2 

## capture cases.

Like technologies and CO 2 

## emission pricing, the impact of CO 2 

## sales price and natural gas price

a nd the implications on the competitiveness of the capture technologies can also be considered in

a “phase diagram” type plot

, as shown in Exhibit 5

- 10 . The lines in the plot represent COE

parity between different pairs of technologies.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 224 Exhibit 5

- 10 Lowest cost power generation options c omparing NGCC and coal

Source: NETL



## The plot demonstrates the following points:

• Non

- capture plants are the low

- cost option below a first

- year CO 2 

## price of $56/tonne

($51/ton).

• NGCC is preferred when natural gas prices are below $10/MMBtu with a CO 2 

## revenue below $ 56 /tonne (and a capacity factor of 85 percent). The natural gas price

that provides parity between the various NGCC and PC cases drops off at higher CO 2 

## revenues reaching $6/MMBtu at approximately $100/tonne ($91/ton).



# 5.3 Sensitivities

Exhibit 5

- 11 shows the COE sensitivity to fuel costs for the SC PC and NGCC cases. The bands

for the SC PC cases re present a variance of the coal price from $2.21

- $3.69/MMBtu ( ±25% of

the study value $2.94/MMBtu). This highlights regions of competitiveness of NGCC with SCPC

systems for cases with and without CCS as a function of delivered natural gas price. As an

e xample, at a coal cost of $3/MMBtu, the COE of the non

- capture SC PC case equals non

capture NGCC at a natural gas price of approximately $10/MMBtu. Similarly, the SC PC and

NGCC cases with capture have equivalent COEs at a coal price of $3/MMBtu and a na tural gas

price of approximately $13.5/MMBtu.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 225 Exhibit 5

- 11 COE sensitivity to fuel costs

Source: NETL



## In Exhibit 5

- 12 , t he sensitivity of COE to CF is shown for all technologies. The subcritical and

SC PC cases are nearly identical so that the curves are indistinguishable on the graph. The CF is

plotted from 30 to 95 percent. The baseline CF is 85 percent for both PC and NGCC

technologies . The curves plotted in Exhibit 5

- 12 for the PC and NGCC cases assume that the CF

could be extended to 95 percent with no additional capital equipment.

Technologies with high capital cost (PC with CO 2 

## capture) show a greater increase in COE with

decreased CF. Converse ly, NGCC with no CO 2 

## capture is relatively flat because the COE is

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

from Exhibit 5

- 12 include:

• At any CF shown, NGCC has the lowest COE o ut of the non

- capture cases.

• The COE of NGCC with CO 2 

## capture is the lowest of the capture technologies, and

the advantage increases as the CF decreases. The relatively low capital cost

component of NGCC accounts for the increased cost differential with decreased CF.

• At around a 60 percent CF, the COE of NGCC with CO 2 

## capture crosses over with

the COEs of both PC non

- capture cases, with the NGCC case having a higher COE at

increasing CFs. 30 50 70 90 110 130 150 170 190

3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20COE with CO2T&S, $/MWh(2011$)

Delivered Natural Gas Price, $/MMBtu SCPC w/ CCS ($2.94/MMBtu coal)

SCPC w/o CCS ($2.94/MMBtu coal) $2.21

- $3.69 per

MMBtu $2.21

- $3.69 per

MMBtuCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 226 Exhibit 5

- 12 COE sensitivity to capacity factor

Source: NETLCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 227 

# 6 Revision Control

The initial issue of this report was published in May of 2007 and an updated revision was

published in November of 2010. Subsequent to the re

- issue date, updates have been made to

various re port sections. These modifications were made for clarification and aesthetic purposes

as well as to update the report with more current performance and cost estimates and to bring all

costs to a 2011 year dollar basis.

Exhibit 6

- 1 contains information added, changed

, or deleted in successive revisions.

Exhibit 6

- 1 Record of revisions

Revision

Number Revision

Date Description of Change Comments

1 8/23/07 Added discl aimer to

Executive Summary and

Introduction Disclaimer involves clarification on extent of

participation of technology vendors.

Removed reference to

Cases 7 and 8 in Exhibits

ES

- 1 and 1

- 1 since they no

longer exist

. SNG cases moved to Volume 2 of this r eport 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 f rom 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 Exhibit s ES

- 4, 3

- 121, 4

- 52 and 5

- 30 The old water usage figures were in gpm

(absolute) and in the new figures the water

numbers are normalized by net plant output.

Updated Selexol process

description Text was added to Section 3.1.5 to describe how

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

tu rbines

– 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”

Added Supplemental

Chapter 7 “Dry and Parallel

Cooling”Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 228 Revision

Number Revision

Date Description of Change Comments

Added Supplemental

Chapter 8 “GEE IGCC in

Quench

- Only Configuration

with CO 2 

### Capture”

Added Supplemental

Chapter 9 “Sensitivity to

MEA System Performance

and Cost Bituminous

Baseline Case B12BA”

Updated Aspen models Major Aspen model updates incl uded:

• 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 captu re 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

withdrawa l 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)

Update d report tables,

figures and text to reflect

the revision 2 changes

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.Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 229 Revision

Number Revision

Date Description of Change Comments

3 7 / 6 /201 5 Volume 1 has been spli t

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)

• Executiv e 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.

Separated Supplemental

Chapter 7 “Impa ct of Dry

and Parallel Cooling

Systems on Cost and

Performance of Fossil Fuel

Power Plants” into a stand

alone report.”

Removed Supplemental

Chapter 9 “Sensitivity to

MEA System Performance

and Cost Bituminous

Baseline Case 12A”

Updated the environ mental

targets to current limits

published by the EPA and

presented in Section 2.4 MATS and NSPS regulate SO 2 

### , NOx, Filterable

PM, Hg, and HCl on a lb/ MWh

- gross basis.

Updated Section 2.5

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 2.7 concerning cost

estimating methodology Many QGESS documents have been published

that detail information generic to a number of

studies published by NETL. In an effort to reduce

the size of this report, text provided in these

QGESS documents h as been removed and

references have been inserted that provide the

QGESS document title and revision notation.

Cost of CO 2 

### Captured

methodology and results

have been added. The Cost of CO 2 

### avoided methodology has been

moved from the executive summary an d

combined with the Cost of CO 2 

### Captured

methodology in Section 2.7.4

.

Section 2.8 has been

updated to reflect current

informationCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 230 Revision

Number Revision

Date Description of Change Comments

The Combustion turbine

performance characteristics

have been updated The performance provided in this report reflects a

state

- of

- the

- art 2013 F

- class combustion turbine

for NGCC cases

Updated Natural Gas

Composition Methanethiol was added to the composition

Improved the BFD

depiction of the HRSGs in

NGCC Case

All cas es have been

updated to a new case

naming convention. Ex. Revision 2’s Case 9 is now Case B 11 A

Performance tables have

been updated Major updates include:

• Table is split into two sections

o Performance summary

o Plant power and auxil iary load

breakdown

• PC

o Steam generator efficiency

o Excess air

o Steam turbine cycle efficiency and

heat rate

o LHV basis efficiency and heat rate

• NGCC

o Combustion turbine efficiency

o Steam turbine efficiency and heat

rate

o LHV basis efficiency and heat rate

Updated case performance

r esults 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

lossesCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 231 Revision

Number Revision

Date Description of Change Comments

Updated Aspen models Major Aspen model upd ates included:

• Updated steam turbine efficiency

• Incorporated exhaust losses into LP turbine

efficiency

• Changed Capture system in NGCC and PC

cases to Cansolv system

• Updated many pressure drops to percent of

inlet

• Corrected temperature approaches

• Corrected pressure drops across various

systems

• Converted to Aspen 8.2

• Converted to Hierarchy models

• Converted steam property method to

SteamNBS

• Updated CO 2 

### compression system to front

loaded 8 stage design in NGCC and PC

cases

• ACI and DSI systems were added to PC

c ases

• Boiler air preheater exit temperature was

reduced to 300°F

• Excess O 2 

### is controlled at the flue gas exiting

the boiler at 2.7% dry

• Combustion turbine for NGCC cases was

updated

• Added steam extraction for CO 2 

### dryer

Completed updating case

economic re sults Major updates included:

• Updating to 2011 year dollars

• Updating the T&S costing methodology

• Updating the capital charge factors

• Updating fuel prices

• Re

- costing of cases based on the updated

performance results

• Updating cost estimates based on recently

obtained vendor quotes

Updated report tables,

figures and text to reflect

the revision 3 changesCost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3



## 232 

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### www.netl.doe.gov

Pittsburgh, PA • Morgantown, WV • Albany, OR • Sugar Land, TX • Anchorage, AK

(800) 553

- 7681 

# Tim Fout

Timothy.Fout@NETL.DOE.GOV 

# Mark Woods

M ark.Woods@CONTR.NETL.DOE.GOV