# Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture

May 27 , 201 1

DOE/NETL

- 2011/1498Carbon Dioxide Capture Sensitivity Analysis



# Disclaimer

This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy , completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference therein to any specific commercial product, process, or service by trade name,

trad emark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed therein do not necessarily state or reflect those of the United States Government or any agency thereof.Carbon Dioxide Capture Sensitivity Analysis



# Cost and Performance of PC and IGCC Plants for a
Range of Carbon Dioxide Capture

DOE/NETL

- 2011 / 1498

May 27

, 2011

NETL Contact:

K ristin Gerdes

Office of P rogram, Planning and Analysis

Prepared by:

Research and Development Solutions, LLC (RDS)

James B. Black, formerly of Parsons Corporation

John L. Haslbeck, formerly of Parsons Corporation

Andrew P. Jones

, formerly of Science Applications International Corporation

Wayne L. Lundberg

, form erly of Science Applications International Corporation

Vasant Shah, formerly of Parsons Corporation

Updated by:

Energy Sector Planning and Analysis (ESPA)

Allison Kyle, Booz Allen Hamilton

Eric Lewis, Booz Allen Hamilton

National Energy Technology Laboratory

www.netl.doe.govCarbon Dioxide Capture Sensitivity Analysis



# Acknowledgments

This report was initially prepared by Research and Development Solutions, LLC (RDS) for the United States Department of Energy (DOE) National Energy Technology Laboratory (NETL). The report was updated by the Energy Sector Planning and Analysis (ESPA) for DOE NETL . This work was completed

under DOE NETL Contract Number DE

- FE0004001 . This work was performed under ESPA T ask 410.01

.

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

Eric Grol , NETL Te chnical MonitorCarbon Dioxide Capture Sensitivity Analysis



### i 

# Table o f Contents

TABLE OF CONTENTS

................................ ................................ ................................ .............. I

LIST OF EXHIBITS

................................ ................................ ................................ .................. III

LIST OF ACRONYMS AND ABBREVIATIONS

................................ ................................ .... X

EXECUTIVE SUMMARY

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

P ULVERIZED 

### C OAL 

### P LANTS



### ................................ ................................ ................................ .......... 1

IGCC P LANTS



### ................................ ................................ ................................ ............................... 3

R ESULTS



### ................................ ................................ ................................ ................................ ....... 6

Performance

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

Economics

................................ ................................ ................................ ................................ ............................ 8
Cost and Performance Summary

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



### 1. INTRODUCTION

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

1.1 S TUDY 

### B ACKGROUND



### ................................ ................................ ................................ ..... 19

1.2 P ROJECT 

### O BJECTIVES



### ................................ ................................ ................................ ...... 19

2. GENERAL EVALUATION B ASIS

................................ ................................ ................... 21

2.1 S ITE 

### C HARACTERISTICS



### ................................ ................................ ................................ .. 25

2.2 C OAL 

### C HARACTERISTICS AND 

### C OST



### ................................ ................................ ............... 27

2.3 D ESIGN 

### S ORBENT 

### C OMPOSITION



### ................................ ................................ ..................... 31

2.4 E NVIRONMENTAL 

### T ARGETS



### ................................ ................................ ............................ 31

2.4.1 Supercritical PC Plant

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

2.4.2 GEE IGCC Plant

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

2.4.3 Carbon Dioxide

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



### 2.5 C APACITY 

### F ACTOR



### ................................ ................................ ................................ ......... 34

2.6 R

AW 

### W ATER 

### W ITHDRAWAL



### ................................ ................................ ........................... 35

2.7 C OST 

### E STIMATING 

### M ETHODOLOGY



### ................................ ................................ ................ 35

2.7.1 Capital Costs

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

2.7.2 System Code

- of

- Accounts

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

2. 7.3 CO 2 Removal Plant Maturity

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

2.7.4 Contracting Strategy

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

2.7.5 Estimate Scope

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

2.7.6 Capital Cost Assumptions

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

2. 7.7 Operations and Maintenance Costs

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

2.7.8 CO 2 Transport, Storage and Monitoring

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

2.7.9 Finance Structure, Discounted Cash Flow Analysis, and COE

................................ .......................... 50



### 2.8 IGCC S TUDY 

### C OST 

### E STIMATES 

### C OMPARED TO 

### I NDUSTRY 

### E STIMATES



### .......................... 54

3. CASE 1

- SUPERCRITICAL PC WIT H VARIABLE CO 2 

### CAPTURE

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

3.1 S YSTEM 

### D ESCRIPTIONS



### ................................ ................................ ................................ ... 57

3.1.1 Coal and Sorbent Receiving and Storage

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

3.1.2 Steam Generator and Ancillaries

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

3.1.3 NO

x Control System

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

3.1.4 Particulate Control

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

3.1.5 Flue Gas Desulfurization

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

3. 1.6 Flue Gas System/Stack

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

3.1.7 Carbon Dioxide Recovery Facility

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

3.1.8 Steam Turbine Generator System

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

3.1.9 Balance of Plant

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

3.1.10 Accessory Electric Plant

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

3.1.11 Instrumentation and Control

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



### 3.2 S UPERCRITICAL 

### PC CO 2 

### C APTURE 

### S ENSITIVITY



### ................................ ............................. 74

3.2.1 CO 2 Capture with Partial Bypass Performance Results

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

3.2.2 Full CO 2 Capture Performance Results

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

3.2.3 Economic Analysis for the Supercritical PC Cases

................................ ................................ ........... 151Carbon Dioxide Capture Sensitivity Analysis



### ii 3.2.4 Capital and Operating Cost Results

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

3.2.5 Supercritical PC Cost and Performance Summary

................................ ................................ ........... 187



### 4. CASE 2

– GEE IGCC WITH VARIAB LE CO 2 

### CAPTURE

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

4.1 G ASIFIER 

### B ACKGROUND



### ................................ ................................ ............................... 190

4.2 P ROCESS 

### D ESCRIPTION



### ................................ ................................ ................................ . 192

4.2.1 Co al Receiving and Storage

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

4.2.2 Coal Grinding and Slurry Preparation

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

4.2.3 Air Separation Unit (ASU) Choice and Integration

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

4.2.4 Gasification

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

4.2.5 Raw Gas Cooling/Particulate Removal

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

4.2.6 Syngas Scrubber/Sour Water Stripper

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

4.2.7 Water Gas Shift Reactors

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

4.2.8 Mercury Removal

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

4.2.9 Acid Gas Removal (AGR) Process Selection

................................ ................................ ..................... 200

4.2.10 CO 2 Compression and Dehydration

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

4.2.11 Sulfur Recovery/Tail Gas Cleanup Process Selection

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

4.2.12 Slag Handling

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

4.2.13 Power Island

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

4.2.14 Steam Generation Island

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

4.2.15 Accessory Electric Plant

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

4.2.16 Instrumentation and Control

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



### 4.3 GEE IGCC CO 2 

### C APTURE 

### S ENSITIVITY



### ................................ ................................ ....... 222

4.3.1 IGCC Design 1

– Without Water Gas Shift

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

4.3.2 IGCC Design 2

– Single Water Gas Shift Reactor

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

4.3.3 IGCC Design 3

– Two Water Gas Shift Reactors with Bypass

................................ .......................... 303

4.3.4 IGCC Design 4

– Two Water Gas Shift Reactors Without Bypass

................................ .................... 357

4.3.5 Economic Analysis for the GEE IGCC Cases

................................ ................................ ................... 395

4.3.6 Capital and Operating Cost Results

................................ ................................ ................................ .. 395

4.3.7 GEE IGCC Cost and Performance Summary

................................ ................................ ................... 467



### 5. RESULTS

................................ ................................ ................................ ........................... 46 9

5.2 P ERFORMANCE



### ................................ ................................ ................................ .............. 469

5.2.1 Energy Eff

iciency

................................ ................................ ................................ .............................. 469



### 5.3 E CONOMICS



### ................................ ................................ ................................ .................. 471

5.3.1 Total Overnight Cost

................................ ................................ ................................ ......................... 471

5.3. 2 Cost of Electricity

................................ ................................ ................................ .............................. 473

5.3.3 CO 2 Avoided Costs

................................ ................................ ................................ ............................ 476



### 5.4 C OST AND 

### P ERFORMANCE 

### S UMMARY



### ................................ ................................ ........... 478

5.4.1 Supercritical PC Cases

................................ ................................ ................................ ..................... 478

5.4.2 GEE IGCC Cases

................................ ................................ ................................ .............................. 479

5.4.3 SCPC and IGCC Comparisons

................................ ................................ ................................ ......... 479



### APPENDIX A

................................ ................................ ................................ ............................. 483

Supercritical PC Cost Algorithms

................................ ................................ ................................ ................... 484
GEE IGCC Cost Algorithms

................................ ................................ ................................ ............................ 489



### 6. REFERENCES

................................ ................................ ................................ ................... 495Carbon Dioxide Capture Sensitivity Analysis



### iii 

# List o f Exhibits

Exhibit ES

- 1 Case 1 Supercritical PC Plant Configuration Summary

................................ .......................... 2

Exhibit ES

- 2 Case 2 GEE IGCC Plant Configuration Summary

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

Exhibit ES

- 3 Net Efficiency and Cost as a Function of WGS Bypass Ratio for 60% CO 2 

### Removal with IGCC Design 3

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

Exhibit ES

- 4 Process Configurations for IGCC D2

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

Exhibit ES

- 5 Process Configurations for IGCC D3

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

Exhibit ES

- 6 Supercritical PC Net Plant Efficiency (HHV)

................................ ................................ ......... 7

Exhibit ES

- 7 IGCC Net Plant Efficiency (HHV)

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

Exhibit ES

- 8 Supercritical PC Total Overnight Cost

................................ ................................ .................... 9

Exhibit ES

- 9 IGCC Total Overnight Cost

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

Exhibit ES

- 10 Supercritical PC Cost of Electricity

................................ ................................ ..................... 11

Exhibit ES

- 11 IGCC Cost of Electricity

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

Exhibit ES

- 12 Supercritical PC CO 2 

### Avoided Costs

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

Exhibit ES

- 13 IGCC CO 2 

### Avoided Costs

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

Exhibit ES

- 14 Cost and Performance Results for the Supercritical PC Cases

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

Exhibit ES

- 15 Cost and Performance Results for the GEE IGCC Cases

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

Exhibit 2

- 1 Case 1 Supercritical PC Plant Configuration Summary

................................ ........................... 21

Exhibit 2

- 2 Case 2 GEE IGCC Plant Configuration Summary

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

Exhibit 2

- 3 Net Efficiency and Cost as a Function of WGS Bypass Ratio for 60% CO 2 

### Removal with IGCC Design 3

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

Exhibit 2

- 4 Process Configurations for IGCC D2

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

Exhibit 2

- 5 Process Configurations for IGCC D3

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

Exhibit 2

- 6 Site Ambient Conditions

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

Exhibit 2

- 7 Site Characteristics

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

Exhibit 2

- 8 Design Coal

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

Exhibit 2

- 9 Probability Distribution of Mercury Concentration in the Illinois No. 6 Coal

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

Exhibit 2

- 10 Sorbent Analysis

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

Exhibit 2

- 11 Standards of Performance for Electric Utility Steam Generating Units

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

Exhibit 2

- 12 Environmental Targets for PC Cases

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

Exhibit 2

- 13 Environmental Targets for IGCC Cases

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

Exhibit 2

- 14 Capital Cost Levels and their Elements

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

Exhibit 2

- 15 Features of an AACE Class 4 Cost Estimate

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

Exhibit 2

- 16 AACE Guidelines for Process Contingency

................................ ................................ ........... 41

Exhibit 2

- 17 TASC/TOC Factors

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

Exhibit 2

- 18 Owner‟s Costs Included in TOC

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

Exhibit 2

- 19 CO 2 

### Pipeline Specification

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

Exhibit 2

- 20 Deep, Saline Aquifer Specification

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

Exhibit 2

- 21 Global Economic Assumptions

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

Exhibit 2

- 22 Financial Structure for Investor Owned Utility High Risk Projects

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

Exhibit 2

- 23 Capital Charge Factors for COE Equation

................................ ................................ ............. 53

Exhibit 3

- 1 Typical B&W Wet FGD Process Flow Diagram

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

Exhibit 3

- 2 Wet Scrubber Arrangement

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

Exhibit 3

- 3 Fluor Econamine FG Plus SM 

### Typical Flow Diagram

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

Exhibit 3

- 4 CO 2 

### Compressor Interstage Pressures

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

Exhibit 3

- 5 Supercritical PC Combustion Configuration Modeling Assumptions

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

Exhibit 3

- 6 Cases 1A Through 1D Process Block Flow Diagram, Super critical PC with CO 2 

### Capture
Bypass

................................ ................................ ................................ ................................ ................... 78Carbon Dioxide Capture Sensitivity Analysis



### iv Exhibit 3

- 7 Case 1A Stream Table, Supercritical PC with 30% CO 2 

### Capture

................................ ............ 79

Exhibit 3

- 8 Case 1B Stream Table, Supercritical PC with 50% CO 2 

### Capture

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

Exhibit 3

- 9 Case 1C Stream Table, Supercritical PC with 70% CO 2 

### Capture

................................ ............ 83

Exhibit 3

- 10 Case 1D Stream Table, Supercritical PC with 85% CO 2 

### Capture

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

Exhibit 3

- 11 Cases 1A Through 1D Performance Modeling Results

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

Exhibit 3

- 12 Cases 1A through 1D Estimated Air Emission Rates

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

Exhibit 3

- 13 Cases 1A through 1D Carbon Balance

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

Exhibit 3

- 14 Cases 1A through 1D Sulfur Balance

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

Exhibit 3

- 15 Case 1A (30%) Wate r Balance

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

Exhibit 3

- 16 Case 1B (50%) Water Balance

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

Exhibit 3

- 17 Case 1C (70%) Water Balance

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

Exhibit 3

- 18 Case 1D (85%) Water Balance

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

Exhibit 3

- 19 Case 1A (30%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems 95

Exhibit 3

- 20 Case 1A (30%) Heat and Mass Balance, Power Block Systems

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

Exhibit 3

- 21 Case 1B (50%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems 97

Exhibit 3

- 22 Case 1B (50%) Heat and Mass Balance, Power Block Systems

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

Exhibit 3

- 23 Case 1C (70%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems 99

Exhibit 3

- 24 Case 1C (70%) Heat and Mass Balance, Power Block Systems

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

Exhibit 3

- 25 Case 1D (85%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

................................ ................................ ................................ ................................ ............................. 101

Exhibit 3

- 26 Case 1D (85%) Heat and Mass Balance, Power Block Systems

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

Exhibit 3

- 27 Case 1A (30%) Energy Balance

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

Exhibit 3

- 28 Case 1B (50%) Energy Balance

................................ ................................ ........................... 104

Exhibit 3

- 29 Case 1C (70%) Energy Balance

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

Exhibit 3

- 30 Case 1D (85%) Energy Balance

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

Exhibit 3

- 31 Case 1A Energy Balance Sankey Diagram

................................ ................................ .......... 107

Exhibit 3

- 32 Case 1B Energy Balance Sankey Diagram

................................ ................................ ........... 107

Exhibit 3

- 33 Case 1C Energy Balance Sankey Diagram

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

Exhibit 3

- 34 Case 1D Energy Balance Sankey Diagram

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

Exhibit 3

- 35 Cases 1E through 1G Process Block Flow Diagram, Supercritical PC with CO 2 

### Capture

.. 118

Exhibit 3

- 36 Case 1E Stream Table, Supercritical PC with 90% CO 2 

### Capture

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

Exhibit 3

- 37 Case 1F Stream Table, Supercritical PC with 95% CO 2 

### Capture

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

Exhibit 3

- 38 Case 1G St ream Table, Supercritical PC with 99% CO 2 

### Capture

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

Exhibit 3

- 39 Cases 1E through 1G Performance Modeling Results

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

Exhibit 3

- 40 Cases 1E through 1G Estimated Air Emission Rates

................................ ........................... 128

Exhibit 3

- 41 Cases 1E through 1G Carbon Balance

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

Exhibit 3

- 42 Cases 1E through 1G Sulfur Balance

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

Exhibit 3

- 43 Case 1E (90%) Water Balance

................................ ................................ ............................. 130

Exhibit 3

- 44 Case 1F (95%) Water Balance

................................ ................................ .............................. 130

Exhibit 3

- 45 Case 1G (99%) Water Balance

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

Exhibit 3

- 46 Case 1E (90%) Heat and Mass Ba lance, Supercritical PC Boiler and Gas Cleanup Systems

................................ ................................ ................................ ................................ ............................. 133

Exhibit 3

- 47 Case 1E (90%) Heat and Mass Balance, Power Block Systems

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

Exhibit 3

- 48 Case 1F (95%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

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

Exhibit 3

- 49 Case 1F (95%) Heat and Mass Balance, Power Block Systems

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

Exhibit 3

- 50 Case 1G (99%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

................................ ................................ ................................ ................................ ............................. 137Carbon Dioxide Capture Sensitivity Analysis



### v Exhibit 3

- 51 Case 1G (99%) Heat and Mass Balance, Power Block Systems

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

Exhibit 3

- 52 Case 1E (90%) Energy Balance

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

Exhibit 3

- 53 Case 1F (95%) Energy Balance

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

Exhibit 3

- 54 Case 1G (99%) Energy Balance

................................ ................................ ........................... 141

Exhibit 3

- 55 Case 1E Energy Balance Sankey Diagram

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

Exhibit 3

- 56 Case 1F Energy Balance Sankey Diagram

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

Exhibit 3

- 57 Case 1G Energy Balance Sankey Diagram

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

Exhibit 3

- 58 Case 1A (30%) Capital Costs

................................ ................................ ............................... 152

Exhibit 3

- 59 Case 1A Initial and Annual O&M Expenses

................................ ................................ ........ 156

Exhibit 3

- 60 Case 1B (50%) Capital Costs

................................ ................................ ............................... 157

Exhibit 3

- 61 Case 1B Initial and Annual O&M Expenses

................................ ................................ ........ 161

Exhibit 3

- 62 Case 1C (70%) Capital Costs

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

Exhibit 3

- 63 Case 1C Initial and Annual O&M Expenses

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

Exhibit 3

- 64 Case 1D (85%) Capital Costs

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

Exhibit 3

- 65 Case 1D Initial and Annual O&M Expenses

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

Exhibit 3

- 66 Case 1E (90%) Capital Costs

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

Exhibit 3

- 67 Case 1E Initial and Annual O&M Expenses

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

Exhibit 3

- 68 Case 1F (95%) Capi tal Costs

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

Exhibit 3

- 69 Case 1F Initial and Annual O&M Expenses

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

Exhibit 3

- 70 Case 1G (99%) Capital Costs

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

Exhibit 3

- 71 Case 1G Initial and Annual O&M Expenses

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

Exhibit 3

- 72 Cost and Performance Results for the Supercritical PC Cases

................................ ............. 187

Exhibit 4

- 1 Typical ASU Process Schematic

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

Exhibit 4

- 2 Flow Diagram for a Conventional AGR Unit

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

Exhibit 4

- 3 Common Chemical Reagents Used in AGR Processes

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

Exhibit 4

- 4 Physical Solvent AGR Process Simp lified Flow Diagram

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

Exhibit 4

- 5 Common Physical Solvents Used in AGR Processes

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

Exhibit 4

- 6 Common Mixed Solvents Used in AGR Processes

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

Exhibit 4

- 7 Equilibrium Solubility Data on H 2 

### S and CO 2 

### in Various Solvents

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

Exhibit 4

- 8 Generic Two

- Stage SelexolTM Process Flow Diagram

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

Exhibit 4

- 9 Typical Three

- Stage Claus Sulfur Plant

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

Exhibit 4

- 10 Advanced F Class Combustion Turbine Performance Characteristics Using Natural Gas

.. 213

Exhibit 4

- 11 Combustion Turbine Typical Scope of Supply

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

Exhibit 4

- 12 Typical Fuel Specification for F

- Class Machines

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

Exhibit 4

- 13 Allowable Gas Fuel Contaminant Level for F

- Class Machines

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

Exhibit 4

- 14 Case 2 GEE IGCC Plant Configuration Summary

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

Exhibit 4

- 15 Case 2 D1A Process Block Flow Diagram, IGCC without WGS (0% CO 2 

### Removal)

........ 226

Exhibit 4

- 16 Case 2 D1A Stream Table, IGCC without CO 2 

### Capture

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

Exhibit 4

- 17 Case 2 D1B Process Block Flow Diagram, IGCC without WGS (25% CO 2 

### Removal)

...... 229

Exhibit 4

- 18 Case 2 D1B Stream Table, IGCC with 25% CO 2 

### Capture

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

Exhibit 4

- 19 Case 2 D1 Performance Modeling Results

................................ ................................ ........... 232

Exhibit 4

- 20 Case 2 D1 Estimated Air Em ission Rates

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

Exhibit 4

- 21 Case 2 D1 Carbon Balance

................................ ................................ ................................ ... 235

Exhibit 4

- 22 Case 2 D1 Sulfur Balance

................................ ................................ ................................ ..... 235

Exhibit 4

- 23 Case 2 D1A (0%) Water Balance

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

Exhibit 4

- 24 Case 2 D1B (25%) Water Balance

................................ ................................ ....................... 237

Exhibit 4

- 25 Case 2 D1A (0%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .... 239

Exhibit 4

- 26 Case 2 D1A (0%) Heat and Mass Balance, Syngas Cleanup

................................ ............... 240Carbon Dioxide Capture Sensitivity Analysis



### vi Exhibit 4

- 27 Ca se 2 D1A (0%) Heat and Mass Balance, Power Block

................................ .................... 241

Exhibit 4

- 28 Case 2 D1B (25%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 242

Exhibit 4

- 29 Case 2 D1B (25%) Heat and Mass Balance, Syngas Cleanup

................................ ............. 243

Exhibit 4

- 30 Case 2 D1B (25%) Heat and Mass Balance, Power Block

................................ ................... 244

Exhibit 4

- 31 Case 2 D1A (0%) Energy Balance

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

Exhibit 4

- 32 Case 2 D1B (25%) Energy Balance

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

Exhibit 4

- 33 Case 2 D1A Energy Balance Sankey Diagram

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

Exhibit 4

- 34 Case 2 D1B Energy Balance Sankey Diagram

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

Exhibit 4

- 35 Case 2 D2 Process Block Flow Diagram, IGCC with Single WGS Reactor and Bypass

.... 258

Exhibit 4

- 36 Case 2 D2A Stream Table, 25% CO 2 

### Removal with Single WGS Bypass

.......................... 259

Exhibit 4

- 37 Case 2 D2B Stream Table, 45% CO 2 

### Capture with Single WGS Bypass

............................ 261

Exhibit 4

- 38 Case 2 D2C Stream Table, 60% CO 2 

### Capture with Single WGS Bypass

............................ 263

Exhibit 4

- 39 Case 2 D2D Stream Table, 75% CO 2 

### Capture with Single WGS Bypass

............................ 265

Exhibit 4

- 40 Case 2 D2 Performance Modeling Results

................................ ................................ ........... 267

Exhibit 4

- 41 Case 2 D2 Esti mated Air Emission Rates

................................ ................................ ............. 270

Exhibit 4

- 42 Case 2 D2 Carbon Balance

................................ ................................ ................................ ... 271

Exhibit 4

- 43 Case 2 D2 Sulfur Balance

................................ ................................ ................................ ..... 271

Exhibit 4

- 44 Case 2 D2A (25%) Water Balance

................................ ................................ ....................... 272

Exhibit 4

- 45 Case 2 D2B (45%) Water Balance

................................ ................................ ....................... 273

Exhibit 4

- 46 Case 2 D2C (60%) Water Balance

................................ ................................ ....................... 274

Exhibit 4

- 47 Case 2 D2D (75%) Water Balance

................................ ................................ ....................... 275

Exhibit 4

- 48 Case 2 D2A (25%) Heat and Mass Balance, GEE Gasifi er and ASU

................................ .. 277

Exhibit 4

- 49 Case 2 D2A (25%) Heat and Mass Balance, Syngas Cleanup

................................ ............. 278

Exhibit 4

- 50 Case 2 D2A (25%) Heat and Mass Balance, Power Block

................................ .................. 279

Exhibit 4

- 51 Case 2 D2B (45%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 280

Exhibit 4

- 52 Case 2 D2B (45%) Heat and Mass Balance, Syngas Cleanup

................................ ............. 281

Exhibit 4

- 53 Case 2 D2B (45%) Heat and Mass Balance, Power Block

................................ ................... 282

Exhibit 4

- 54 Case 2 D2C (60%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 283

Exhibit 4

- 55 Case 2 D2C (60%) Heat and Mass Balance, Syngas Cleanup

................................ ............. 284

Exhibit 4

- 56 Case 2 D2C (60%) Heat and Mass Balance, Power Block

................................ ................... 285

Exhibit 4

- 57 Case 2 D2D (75%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 286

Exhibit 4

- 58 Case 2 D2D (75%) Heat and Mass Balance, Syngas Cleanup

................................ ............. 287

Exhibit 4

- 59 Case 2 D2D (75%) Heat and Mass Balance, Power Block

................................ .................. 288

Exhibit 4

- 60 Case 2 D2A (25%) Energy Balance

................................ ................................ ..................... 289

Exhibit 4

- 61 Case 2 D2B (45%) Energy Balance

................................ ................................ ...................... 290

Exhibit 4

- 62 Case 2 D2C (60%) Energy Balance

................................ ................................ ...................... 291

Exhibit 4

- 63 Case 2 D2D (75%) Energy Balance

................................ ................................ ..................... 292

Exhibit 4

- 64 Case 2 D2A Energy Balance Sankey Diagram

................................ ................................ ..... 293

Exhibit 4

- 65 Case 2 D2B Energy Balance Sankey Diagram

................................ ................................ ..... 293

Exhibit 4

- 66 Case 2 D2C Energy Balance Sankey Diagram

................................ ................................ ..... 294

Exhibit 4

- 67 Case 2 D2D Energy Balance Sankey Diagram

................................ ................................ ..... 294

Exhibit 4

- 68 Case 2 D3 Process Block Flow Diagram, IGCC with Two WGS Reactors and Bypass

..... 304

Exhibit 4

- 69 Case 2 D3A Stream Table, 25% CO 2 

### Removal with Two WGS Bypass

............................. 305

Exhibit 4

- 70 Case 2 D3B Stream Table, 45% CO 2 

### Capture with Two WGS Bypass

............................... 3 07

Exhibit 4

- 71 Case 2 D3C Stream Table, 60% CO 2 

### Capture with Two WGS Bypass

............................... 309

Exhibit 4

- 72 Case 2 D3D Stream Table, 75% CO 2 

### Capture with Two WGS Bypass

............................... 311

Exhibit 4

- 73 Case 2 D3E Stream Table, 85% CO 2 

### Capture with Two WGS Bypass

............................... 313

Exhibit 4

- 74 Case 2 D3 Performance Modeling Results

................................ ................................ ........... 315Carbon Dioxide Capture Sensitivity Analysis



### vii Exhibit 4

- 75 Case 2 D3 Estimated Air Emission Rates

................................ ................................ ............. 318

Exhibit 4

- 76 Case 2 D3 Carbon Balance

................................ ................................ ................................ ... 319

Exhibit 4

- 77 Case 2 D3 Sulfur Balance

................................ ................................ ................................ ..... 319

Exhibit 4

- 78 Case 2 D3A (25%) Water Balance

................................ ................................ ....................... 320

Exhibit 4

- 79 Case 2 D3B (45%) Water Balance

................................ ................................ ....................... 321

Exhibit 4

- 80 Case 2 D3C (60%) Water Balance

................................ ................................ ....................... 322

Exhibit 4

- 81 Case 2 D3D (75%) Water Balance

................................ ................................ ....................... 323

Exhibit 4

- 82 Case 2 D3E (85%) Water Balance

................................ ................................ ........................ 324

Exhibit 4

- 83 Case 2 D3A (25%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 325

Exhibit 4

- 84 Case 2 D3A (25%) Heat an d Mass Balance, Syngas Cleanup

................................ ............. 326

Exhibit 4

- 85 Case 2 D3A (25%) Heat and Mass Balance, Power Block

................................ .................. 327

Exhibit 4

- 86 Case 2 D3B (45%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 328

Exhibit 4

- 87 Case 2 D3B (45%) Heat and Mass Balance, Syngas Cleanup

................................ ............. 329

Exhibit 4

- 88 Case 2 D3B (45%) Heat and Mass Balance, Power Block

................................ ................... 330

Exhibit 4

- 89 Case 2 D3C (60%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 331

Exhibit 4

- 90 Case 2 D3C (60%) Heat and Mass Balance, Syngas Cleanup

................................ ............. 332

Exhibit 4

- 91 Case 2 D3C (60%) Heat and Mass Balance, Power Block

................................ ................... 333

Exhibit 4

- 92 Case 2 D3D (75%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 334

Exhibit 4

- 93 Case 2 D3D (75%) Heat and Mass Balance, Syngas Cleanup

................................ ............. 335

Exhibit 4

- 94 Case 2 D3D (75%) Heat and Mass Balance, Power Block

................................ .................. 336

Exhibit 4

- 95 Case 2 D3E (85%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 337

Exhibit 4

- 96 Case 2 D3E (85%) Heat and Mass Balance, Syngas Cleanup

................................ .............. 338

Exhibit 4

- 97 Case 2 D3E (85%) Heat and Mass Balance, Power Block

................................ ................... 339

Exhibit 4

- 98 Case 2 D3A (25%) Energy Balance

................................ ................................ ..................... 341

Exhibit 4

- 99 Case 2 D3B (45%) Energy Balance

................................ ................................ ...................... 342

Exhibit 4

- 100 Case 2 D3C (60%) Energy Balance

................................ ................................ .................... 343

Exhibit 4

- 101 Case 2 D3D (75%) Energy Balance

................................ ................................ ................... 344

Exhibit 4

- 102 Case 2 D3E (85%) Energy Balance

................................ ................................ .................... 345

Exhibit 4

- 103 Case 2 D3A Energy Balance Sankey Diagram

................................ ................................ ... 346

Exhibit 4

- 104 Case 2 D3B Energy Balance Sankey Diagram

................................ ................................ ... 346

Exhibit 4

- 105 Case 2 D3C Energy Balance Sankey Diagram

................................ ................................ ... 347

Exhibit 4

- 106 Case 2 D3D Energy Balance Sankey Diagram

................................ ................................ ... 347

Exhibit 4

- 107 Case 2 D3E Energy Balance Sankey Diagram

................................ ................................ ... 348

Exhibit 4

- 108 Case 2 D4 Process Block Flow Diagram, IGCC with Two WGS Reactors

....................... 358

Exhibit 4

- 109 Case 2 D4A Stream Table, 90% CO 2 

### Removal

................................ ................................ .. 359

Exhibit 4

- 110 Case 2 D4B Stream Table, 95% CO 2 

### Capture

................................ ................................ .... 361

Exhibit 4

- 111 Case 2 D4C Stream Table, 97% CO 2 

### Capture

................................ ................................ .... 363

Exhibit 4

- 112 Case 2 D4 Performance Modeling Results

................................ ................................ ......... 365

Exhibit 4

- 113 Case 2 D4 Estimated Air Emission Rates

................................ ................................ ........... 368

Exhibit 4

- 114 Case 2 D4 Carbon Balance

................................ ................................ ................................ . 369

Exhibit 4

- 115 Case 2 D4 Sulfur Balance

................................ ................................ ................................ ... 369

Exhibit 4

- 116 Case 2 D4A (90%) Water Balance

................................ ................................ ..................... 370

Exhibit 4

- 117 Case 2 D4B (95%) Water Balance

................................ ................................ ..................... 371

Exhibit 4

- 118 Case 2 D4C (97%) Water Balance

................................ ................................ ..................... 372

Exhibit 4

- 119 Case 2 D4A (90%) Heat and Mass Balance, GEE Gasifier and ASU

................................ 373

Exhibit 4

- 120 Case 2 D4A (90%) Heat and Mass Balance, Syngas Cleanup

................................ ........... 374

Exhibit 4

- 121 Case 2 D4A (90%) Heat and Mass Balance, Power Block

................................ ................ 375

Exhibit 4

- 122 Case 2 D4B (95%) Heat and Mass Balance, GEE Gasifier and ASU

................................ 376Carbon Dioxide Capture Sensitivity Analysis



### viii Exhibit 4

- 123 Case 2 D4B (95%) Heat and Mass Balance, Syngas Cleanup

................................ ........... 377

Exhibit 4

- 124 Case 2 D4B (95%) Heat and Mass Balance, Power Block

................................ ................. 378

Exhibit 4

- 125 Case 2 D4C (97%) Heat and Mass Balance, GEE Gasifier and ASU

................................ 379

Exhibit 4

- 126 Case 2 D4C (97%) Heat and Mass Balance, Syngas Cleanup

................................ ........... 380

Exhibit 4

- 127 Case 2 D4C (97%) Heat and Mass Balance, Power Block

................................ ................. 381

Exhibit 4

- 128 Case 2 D4A (90%) Energy Balance

................................ ................................ ................... 383

Exhibit 4

- 129 Case 2 D4B (95%) Energy Balance

................................ ................................ .................... 384

Exhibit 4

- 130 Case 2 D4C (97%) Energy Balance

................................ ................................ .................... 385

Exhibit 4

- 131 Case 2 D4A Energy Balance Sankey Diagram

................................ ................................ ... 386

Exhibit 4

- 132 Case 2 D4B Energy Balance Sankey Diagram

................................ ................................ ... 386

Exhibit 4

- 133 Case 2 D4C Energy Balance Sankey Diagram

................................ ................................ ... 387

Exhibit 4

- 134 Case 2 D1A (0%) Capital Costs

................................ ................................ ......................... 396

Exhibit 4

- 135 Case 2 D1A Initial and Annual O&M Expenses

................................ ................................ 400

Exhibit 4

- 136 Case 2 D1B (25%) Capital Costs

................................ ................................ ........................ 401

Exhibit 4

- 137 Case 2 D1B Initial and Annual O&M Expenses

................................ ................................ 405

Exhibit 4

- 138 Case 2 D2A (25%) Capital Costs

................................ ................................ ....................... 406

Exhibit 4

- 139 Case 2 D2A Initial and Annual O&M Expenses

................................ ................................ 410

Exhibit 4

- 140 Case 2 D2B (45%) Capital Costs

................................ ................................ ........................ 411

Exhibit 4

- 141 Case 2 D2 B Initial and Annual O&M Expenses

................................ ................................ 415

Exhibit 4

- 142 Case 2 D2C (60%) Capital Costs

................................ ................................ ........................ 416

Exhibit 4

- 143 Case 2 D2C Initial and Annual O&M Expenses

................................ ................................ 420

Exhibit 4

- 144 Case 2 D2D (75%) Capital Costs

................................ ................................ ....................... 421

Exhibit 4

- 145 Case 2 D2D Initial and Annual O&M Expense s

................................ ................................ 425

Exhibit 4

- 146 Case 2 D3A (25%) Capital Costs

................................ ................................ ....................... 426

Exhibit 4

- 147 Case 2 D3A Initial and Annual O&M Expenses

................................ ................................ 430

Exhibit 4

- 148 Case 2 D3B (45%) Capital Costs

................................ ................................ ........................ 431

Exhibit 4

- 149 Case 2 D3B Initial and Annual O&M Expense s

................................ ................................ 435

Exhibit 4

- 150 Case 2 D3C (60%) Capital Costs

................................ ................................ ........................ 436

Exhibit 4

- 151 Case 2 D3C Initial and Annual O&M Expenses

................................ ................................ 440

Exhibit 4

- 152 Case 2 D3D (75%) Capital Costs

................................ ................................ ....................... 441

Exhibit 4

- 153 Case 2 D3D Initial and Annual O&M Expenses

................................ ................................ 445

Exhibit 4

- 154 Case 2 D3E (85%) Capital Costs

................................ ................................ ........................ 446

Exhibit 4

- 155 Case 2 D3E Initial and Annual O&M Expenses

................................ ................................ 45 0

Exhibit 4

- 156 Case 2 D4A (90%) Capital Costs

................................ ................................ ....................... 451

Exhibit 4

- 157 Case 2 D4A Initial and Annual O&M Expenses

................................ ................................ 455

Exhibit 4

- 158 Case 2 D4B (95%) Capital Costs

................................ ................................ ........................ 456

Exhibit 4

- 159 Case 2 D4B Initial and Annual O&M Expenses

................................ ................................ 460

Exhibit 4

- 160 Case 2 D4C (97%) Capital Costs

................................ ................................ ........................ 461

Exhibit 4

- 161 Case 2 D4C Initial and Annual O&M Expenses

................................ ................................ 465

Exhibit 4

- 162 Cost and Performance Results for the GEE IGCC Cases

................................ ................... 467

Ex hibit 5

- 1 Net Plant HHV Efficiency for the Supercritical PC Cases

................................ ..................... 470

Exhibit 5

- 2 Net Plant HHV Efficiency for the GEE IGCC Cases

................................ ............................. 471

Exhibit 5

- 3 TOC for the Supercritical PC Cases

................................ ................................ ....................... 472

Exhibit 5

- 4 TOC for the GEE IGCC Cases

................................ ................................ ............................... 473

Exhibit 5

- 5 COE for the Supercritical PC Cases

................................ ................................ ....................... 474

Exhibit 5

- 6 COE for the GEE IGCC Cases

................................ ................................ ............................... 475

Exhibit 5

- 7 CO 2 

### TS&M COE for the Supercritical PC Cases

................................ ................................ ... 475

Exhibit 5

- 8 CO 2 

### TS&M COE for the GEE IGCC Cases

................................ ................................ ........... 476Carbon Dioxide Capture Sensitivity Analysis



### ix Exhibit 5

- 9 CO 2 

### Avoided Costs for the Supercritical PC Cases

................................ ................................ 477

Exhibit 5

- 10 CO 2 

### Avoided Costs for the GEE IGCC Cases

................................ ................................ ...... 478

Exhibit 5

- 11 Cost and Performance Results for the Supercritical PC Cases

................................ ............. 481

Exhibit 5

- 12 Cost and Performance Results for the GEE IGCC Cases

................................ ..................... 482

Appendix A

- 1 Supercritical PC CO 2 

### Capture & Compression Cost, $000

................................ .............. 484 Appendix A

- 2 Supercritical PC CO 2 

### Capture & Compression Cost, $/kW

................................ ............. 484 Appendix A

- 3 Supercritical PC Total Overnight Cost, $000

................................ ................................ ... 485 Appendix A

- 4 Supercritical PC Total Overnight Cost, $/kW

................................ ................................ .. 485 Appendix A

- 5 Supercritical PC Incremental Capital Cost, $000

................................ ............................. 486 Appendix A

- 6 Supercritical PC Incremental Capital Cost, $/kW

................................ ............................ 486 Appendix A

- 7 Supercritical PC COE, mills/kWh

................................ ................................ .................... 487 Appendix A

- 8 Supercritical PC Incremental COE, mills/kWh

................................ ................................ 487 Appendix A

- 9 Supercritical PC Percent Increase in COE

................................ ................................ ........ 488 Appendix A

- 10 Supercritical PC CO 2 

### Capture Avoided Costs

................................ ................................ 488 Appendix A

- 11 GEE IGCC CO 2 

### Capture & Compr ession Cost, $000

................................ .................... 489 Appendix A

- 12 GEE IGCC CO 2 

### Capture & Compression Cost, $/kW

................................ ................... 489 Appendix A

- 13 GEE IGCC Total Overnight Cost, $000

................................ ................................ ......... 490 Appendix A

- 14 GEE IGCC Total Overnight Cost, $/kW

................................ ................................ ........ 490 Appendix A

- 15 GEE IGCC Incremental Capital Cost, $000

................................ ................................ ... 491 Appendix A

- 16 GEE IGCC Incremental Capital Cost, $/kW

................................ ................................ .. 491 Appendix A

- 17 GEE IGCC COE, mills/kWh

................................ ................................ .......................... 492 Appendix A

- 18 GEE IGCC Increme ntal COE, mills/kWh

................................ ................................ ...... 492 Appendix A

- 19 GEE IGCC Percent Increase in COE

................................ ................................ .............. 493 Appendix A

- 20 GEE IGCC CO 2 

### Capture Avoided Costs

................................ ................................ ........ 493Carbon Dioxide Capture Sensitivity Analysis



### x 

# List o f Acronyms a nd Abbreviations

AACE Association for the Advancement of Cost Engineering

acfm Actual cubic foot per minute

AEO Annual Energy Outlook

AGR Acid gas removal

AR As Received

ASU Air separation unit

BACT Best available control technology

BEC Bare erected cost

BFD Block flow diagram

BFW B oi ler feed water

Btu British thermal unit

Btu/h British thermal unit per hour

Btu/kWh British thermal unit per kilowatt hour

Btu/lb British thermal unit per pound

CA California

CCF Capital Charge Factor

CCS Carbon Capture and Sequestration

CF Capacity factor

CFM Cubic feet per minute

CFR Code of Federal Regulations

CGE Cold gas efficiency

CH 4 

### Methane

cm Centimeter

CO 2 

### Carbon dioxide

CO 2 e 

### Carbon dioxide equivalent

COE Cost of elec tricity

CoP ConocoPhillips

COS Carbonyl sulfide

CRP Conservation Reserve Program

CRT Cathode ray tube

CT Combustion turbine

CTG Combustion Turbine

- Generator

CWT Cold water temperature

DCS Distributed control system

Dia. Diameter

DOE Department of Energy

EAF Equivalent availability factor

E

- Gas TM 

### ConocoPhillips gasifier technology

EIA Energy Information Administration

EPA Environmental Protection Agency

EPC Engineer/Procure/ConstructCarbon Dioxide Capture Sensitivity Analysis



### xi EPCM Engineering/Procurement/Construction Management

EPRI Electric Power Research Institute

FOAK First of a kind

ft Foot, Feet

GADS Generating Availability Data System
gal Gallon

GDP Gross domestic product

GEE General Electric Energy

GHG Greenhouse gas

gpm Gallons per minute

GT Gas turbine

GW Gigawatt

GWP Global Warming Poten tial

h Hour

H 2 

### Hydrogen

H 2 

### S Hydrogen sulfide

Hg Mercury

HHV Higher heating value
hp Horsepower

HP High pressure

HRSG Heat recovery steam generator

HVAC Heating, ventilating, and air conditioning

IGVs Inlet guide vanes

IGCC Integrated gasification combined cycle

IOU Investor

- owned utility

IP Intermediate pressure

ISO International Standards Organization
kg/GJ Kilogram per gigajoule
kg/h Kilogram per hour

kJ Kilojoules
kJ/kg Kilojoules per kilogram

KO Knockout

kPa Kilopascal absolute

kV Kilovolt

kW Kilowatt

kWe Kilowatts electric

kWh Kilowatt

- hour

kWt Kilowatts thermal

LAER Lowest Achievable Emission Rate

lb Pound

lb/h Pounds per hour

lb/MMBtu Pounds per million British thermal units

lb/MWh Pounds per megawatt hourCarbon Dioxide Capture Sensitivity Analysis



### xii LF Fn 

### Levelization factor for category n fixed operating cost

LF Vn 

### Levelization factor for category n variable operating cost

LHV Lower heating value

LNB Low NOx burner

LP Low pressure

m Meters

MM$ Millions of Dollars

m/min Meters per minute

m 3 

### /min Cubic meter per minute

MDEA Methyldiethanolamine

MEA Monoethanolamine

MHz Megahertz

MMBtu Million British thermal units (also shown as 10 6 

### Btu)

MMBtu/h Million British thermal units (also shown as 10 6 

### Btu) per hour

MPa Megapascals

Mpg Miles per gallon

MW Megawatt

MWe Megawatts electric

MWh Megawatt

- hour

NAAQ S National ambient air quality standard

net

- MWh Net m egawatt

- hour

NERC North American Electric Reliability Council

NETL National Energy Technology Laboratory

NGCC Natural gas combined cycle

NOx Oxides of nitrogen

NSPS New Source Performance Standards

NSR N ew Source Review

NREL National Renewable Energy Laboratory

O&M Operation and maintenance

OC Fn 

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

PC Pulverized coal

PM Particulate matter

PM 10 

### Particulate matter measuring 10 μm or less

POTW Publicly Owned Treatment Works

ppm Parts per million
ppmd Parts per million, dry

ppmv Parts per million, volume

PRB Powder River Basin coal region

PSD Prevention of Significant Deterioration
psia Pounds per square inch absolute
psig Pounds per square inch gage

R&D Research and Development

RDS Research and Development Solutions, LLCCarbon Dioxide Capture Sensitivity Analysis



### xiii SC Supercritical

SCR Selective catalytic reduction

SGS Sour gas shift

SO 2 

### Sulfur dioxide

STG Steam turbine generator

SWS Sour water stripper

TASC Total As

- Spent Capital

TBtu Tr illion British thermal unit

TGTU Tail gas treating unit

TOC Total overnight cost

Tonne Metric Ton (1000 kg)

TPC Total plant cost

TPD Tons per day

TPH Tons per hour

TPI Total plant investment

TS&M Transport, storage and monitoring

TWh Terawatt

- hour

USDA United States Department of Agriculture

vol% Volume percent

WGS Water gas shift

wt% Weight percent

$/AR ton Dollars per As Received ton $/dry ton Dollars per dry ton

$/kW Dollars per kilowatt

$/MMBtu Dollars per million British thermal units

$/MMkJ Dollars per million kilojoule

$/MWh Dollars per Megawatt

- hour

$/ton Dollars per ton

5

- 10s Fifty hour work weeks (5 days, 10 hours/day)Carbon Dioxide Capture Sensitivity Analysis



### xiv This page intentionally left blank.Carbon Dioxide Capture Sensitivity Analysis



### 1 

# Executive Summary

The objective of this study was to establish the cost and performance for a range of carbon
dioxide (CO 2 

### ) capture level s for new supercritical (SC) pulverized coal (PC) and integrated gasification combined cycle (IGCC) power plants

. The SC PC cases (Case 1 series ) utilize

Fluor‟s Econamine FG Plus SM 

### process for post

- combustion CO 2 

### capture via temperature swing

a b sorption with a 30 wt% monoethanolamine (MEA) solution as the chemical solvent. The
IGCC cases (Case 2 series ) employ a slurry

- fed, entrained

- flow General Electric Energy (GEE) gasifier and leverage UOP‟s (formerly Universal Oil Products) two

- stage SelexolTM process for

bulk CO 2 

### capture and selective hydrogen sulfide (H 2 

### S) removal via pressure swing a b sorption. The SelexolTM process uses dimethyl ether of polyethylene glycol (DEPG ) as a physical solvent for pre

- combustion capture.

The CO 2 

### capture sensitivity analysis includes an evaluation of the cost, performance, and environmental profile of these facilities while operating at 0 feet of elevation (ISO conditions) in

the Illinoi s coal basin and firing Illinois #6 medium

- sulfur bituminous coal. The study include s compression of the captured CO 2 

### to pipeline pressure of 15.2 MPa ( 2,215 psia) , pipeline

transport 80 kilometers (50 miles ), storage in a saline formation at a depth of 1 ,239 meters (4,055
ft) , and monitoring for 80 years . The site will have appropriate access to rail transportation for delivery of coal. All local coal handling facilities are included in the design and cost e stimation portion of this study. The assumed start

- up date is 2015 and all cases are consider ed “first

- of

- a

kind” (FOAK). The methodology included performing steady

- state simulations of the technology using the A SPEN Plus ® 

### (Aspen) modeling program. Each configuration was tailored to achieve a specific level of carbon capture.



## Pulverized Coal Plants

An Aspen model for a SC PC power plant, coupled with detailed simulations of the Econamine

FG Plus SM 

### process using Optimized Gas Treating‟s ProTreatTM, was ut ilized to evaluate the technical and economic performance of post

- combustion CO 2 

### capture in the following

increments: 30, 50, 70, 85 , 90, 95, and 99 percent capture. For control of nitrogen oxides (NO

x 

### )

emissions, a combination of low

- NO

x 

### burners (LNB) wi th overfire air (OFA) and a selective catalytic reduction (SCR) system is used. A fabric filter is employed to minimize particulate matter emissions. A wet limestone flue gas desulfurization (FGD) system , i n conjunction with a sodium hydroxide polishing scrubber, is used to ensure that the flue gas entering the Econamine system has a sulfur dioxide (SO 2 

### ) concentration of 10 ppmv or less. The SC PC descriptions
(herein referred to as Case 1) are summarized in Exhibit ES

- 1

.Carbon Dioxide Capture Sensitivity Analysis



### 2 Exhibit ES

- 1 Case 1 Supercritical PC Plant Configuration Summary

Case CO 2 Capture Intended

Storage Boiler Steam psig/°F/°F Oxidant NO

x Control Sulfur

Control

1 A 30%

Saline

Formation Wall

- fired,

PC 3500/1100/110 0 Air LNB/OFA/SCR

0.07 lb/ MM Btu Wet FGD

0.1 lb/ MM Btu 1B 50%

1C 7 0%

1D 85 %

1E 90%

1F 95%

1G 99%



### Optimized Gas Treating‟s rate

- based ProTreatTM software was used to generate performance

estimates for the Econamine FG Plus SM 

### process

. Initially, 90 percent CO 2 

### removal was modeled by adjusting three key process parameters: (1) the MEA solution circulatio n rate ; (2) the reboiler steam flow rate; and (3) the height of packing material in the absorption and stripping columns.

For higher levels of CO 2 

### removal ( greater than 90 percent ) , the MEA and reboiler steam flow

rates were increased, as well as the absorber/stripper column packing height.

Recent studies typically focus on 90 percent CO 2 

### capture from coal

- fired power plants, but for the cases in this study that focus on less than 90 percent , two options exist. The first option is to pass the entire f

lue gas stream through the amine scrubbing unit, but at reduced solvent circulation rates. The second is to maintain the same high solvent circulation rate and stripping steam requirement, but only treat a portion of the flue gas by bypassing part of the gas stream

around the scrubber. A literat ure search was conducted to verify that less than 90 percent CO 2 

### capture is most economical using a “ slip

- stream ” (or bypass) approach. According to multiple

peer

- reviewed studies the slip

- stream appro ach is indee d more cost

- effective for lower degrees of

capture [ 1

, 2

, 3 ] . The cost of CO 2 

### ca pture with an amine scrubbing process is dependent on the volume of gas being treated

, and a reduction in flue gas flow rate will: (1) decrease the quantity of energy consumed by flue gas blowers; (2) reduce the size of the CO 2 

### absorption columns; and (3) trim the cooling water requirement of the direct contact cooling system

. As a result, the „slip

stream‟ approach for reduced levels of capture leads to low er capital and operating costs.

Due to the range of CO 2 

### capture levels analyzed in Case 1 , the Econamine capital and operating costs vary for the seven cases. While a factored approach that relies on the quantity of CO 2 

### captured for equipment sizing and cost estimation was employed, the cost est imates for the Econamine system were also developed based, in part, on output data from the ProTreatTM simulations. In particular, the ProTreatTM model output provided absorption and stripping column diameters for each case, which were used to determine the required number of absorption trains.

For this analysis, it was assumed that the maximum absorption column diameter is 20 meters (66
feet) , bas ed on information released by Fluor [ 4 ]. As a result, cases that i nclude carbon capture
up to 70% are based on a single absorption and compression train.Carbon Dioxide Capture Sensitivity Analysis



### 3 

## IGCC Plants

An Aspen model for a GE E IGCC power plant, coupled with analysis of different process configurations (i.e., water gas shift bypass ratio and SelexolTM CO 2 

### removal efficiency) , was
utilized to evaluate the technical and economic performance of pre

- combustion CO 2 

### capture for

the following four plant designs:

Design 1 (D1) has no water gas shift ( WGS ) reactor . T he minimum (0 percent ) and
maximum ( 25 percent ) CO 2 

### capture levels for this particular configuration are
modeled. The initial concept for D1 was to have a two

- stage Selexo lTM unit, and if no capture was desired, “turn off” the second stage (which would be dedicated for CO 2



### c ontrol ). However d ue to the high degree of integration between the H 2 

### S and CO 2 

### absorbers, it is not feasible to simply disable the second stage. Conseq uently

, D1A (0

percent capture) employs a one

- stage SelexolTM unit for H 2 

### S control , while D1B (25

percent capture) utilize s a two

- stage SelexolTM unit to maximize CO 2 

### capture from the unshifted syngas

. Design 2 (D2) has one

- stage of WGS

, with CO 2 

### capture ranging from 25 (upper limit

from D 1) to 75 percent ( maximum achievable limit for this particular configuration ).

The different levels of CO 2 

### capture were achieved by varying the WGS bypass ratio

and the two

- stage SelexolTM CO 2 

### removal efficiency

. The separation efficiency of a physical solvent

- based system such as the SelexolTM process is directly proportional

to the concentration of CO 2 

### in the syngas. Therefore, the level of CO 2 

### capture can be manipulated by varying the extent of the water gas shift reaction . In Design 2, the

amount of CO being converted to CO 2 

### is varied by only shifting a portion of the

syngas stream. The SelexolTM removal efficiency is changed by varying the solvent
circulation rate, which changes the size an d cost of the SelexolTM system.

Design 3 (D3) has two

- stage s of WGS with CO 2 

### capture ranging from 25 percent (upper limit from D 1) to the maximum achievable limit for this particular configuration (85 percent ) by varying the WGS bypass ratio and the two

- s tage

SelexolTM CO 2 

### removal efficiency

. The SelexolTM removal efficiency is changed by varying the solvent circulation rate, which changes the size and cost of the SelexolTM

system.

Design 4 (D4) has two

- stage s of WGS with no bypass (therefore the entire sy ngas stream is shifted) with CO 2 

### capture ranging from 90 percent to 9 7 percent

. To achieve greater than 90 percent CO 2 

### removal, the two

- stage SelexolTM CO 2 

### removal efficiency is increased by raising the solvent circulation rate, which increases the size

and cost of the SelexolTM system.

The Case 2 IGCC design descriptions are summarized in Exhibit ES

- 2

.Carbon Dioxide Capture Sensitivity Analysis



### 4 Exhibit ES

- 2 Case 2 GEE IGCC Plant Configuration Summary

Case CO 2 Capture CO 2

Separation Intended

Storage Gasifier Steam psig/°F/°F Oxidant WGS Sulfur

Control

D1A 0% N/A N/A

GE E

Radiant Only 1800/1050/

1050 95

mol%

O 2 N/A

Selexol

TM D1B 25%

SelexolTM

2 nd Stage Saline

Formation N/A

D2A 25% One

Stage

with

B ypass D2B 45%

D2C 60%

D2D 75%

D3A 25%

Two

Stage

with

B ypass D3B 45%

D3C 60%

D3D 75%

D3E 85%

D4A 90% Two

Stage

without

B ypass D4B 95%

D4C 97%



### To determine the process configuration s for less than 90 percent CO 2 

### removal ( IGCC D2 and

D3 ) , the WGS bypass ratio and SelexolTM CO 2 

### removal efficiency were varied over a series of Aspen simulations of the entire GEE IGCC power plant to evaluate the impact on WGS and

SelexolTM costs and net plant efficiency. As a starting poi nt, the SelexolTM CO 2 

### removal efficiency ( 92

. 4 percent ) used to model 90 percent CO 2 

### removal was fixed [ 5 ], and the WGS bypass ratio was adjusted t o achieve the desir ed level of capture. The CO 2 

### removal level was then held constant by decreasing both the WGS bypass ratio (i.e., routing more syngas through the WGS reactor(s)) and the SelexolTM CO 2 

### removal efficiency. These step changes in the WGS byp ass ratio lead to an increase in CO 2 

### partial pressure, which relaxes the CO 2 

### removal required by the SelexolTM process.

As shown in Exhibit ES

- 3 , the co st of the WGS system decreases as the WGS bypass ratio increases since the quantity of s yn gas being shifted declines. The SelexolTM system cost
increases with the WGS bypass ratio since a higher solvent circulation rate is required to

maintain 60 percent CO 2 

### removal as the CO 2 

### partial pressure decreases. However, the total cost of the WGS and SelexolTM systems, which is dominated by the cost of the SelexolTM system,
gradually increases with the WGS bypass ratio. Meanwhile, the net plant HHV efficiency pas ses through a maximum value over the range of WGS bypass ratios. As a result, the WGS bypass

ratios and SelexolTM CO 2 

### removal efficiencies used to model less than 90 percent CO 2 

### removal in this study (IGCC D2 and D3) correspond to the maximum net plant HHV efficiency.Carbon Dioxide Capture Sensitivity Analysis



### 5 Exhibit ES

- 3 Net Efficiency and Cost as a Function of WGS Bypass Ratio for 60% CO 2 Removal with IGCC Design 3



### This procedure was repeated for each level of total CO 2 

### removal analyzed for IGCC D2 and D3 to determine the optimal WGS bypass ratio and SelexolTM CO 2 

### removal efficiency for these intermediate capture points. Data for these optimal configurations are provided in Exhibit ES

- 4

and Exhibit ES

- 5 for IGCC D2 and D3, respectively. These results indicate that the Se lexolTM

CO 2 

### removal efficiency increases with CO 2 

### partial pressure, which is the expected trend with a physical solvent

- based system.

Exhibit ES

- 4 Process Configurations for IGCC D2

Total CO 2 Removal (%) WGS WGS Bypass

Ratio (%) SelexolTM CO 2

Removal (%) P CO2 (psia)

25

One

- Stage

with Bypass 99 .5 85

. 8 119.4

45 60 8 9 186.3

60 28.75 8 9.5 229.8

75 0 91 265.5Carbon Dioxide Capture Sensitivity Analysis



### 6 Exhibit ES

- 5 Process Configurations for IGCC D3

Total CO 2 Removal (%) WGS WGS Bypass

Ratio (%) SelexolTM CO 2

Removal (%) P CO2 (psia)

25

Two

- Stage

with Bypass 99.75 86

. 31 119. 7

45 6 9.4 90.04 186. 5

60 45 90.1 230.1

75 21 90.4 26 4.3

85 5 9 0.52 289. 3



### A typical offering from a commercial catalyst vendor is a steam

- to

- dry gas (S:DG) molar ratio of

0.3 at the outlet of the final WGS reactor. However

, for lower levels of CO 2 

### removal (IGCC D2
and D3), this study uses a S:DG molar ratio of 0. 25 at the outlet of the final WGS reactor. Operating with a lower S:DG ratio impedes the kinetics of carbon monoxide (CO) to CO 2 

### conversion. Consequently, larger and more costly WGS reactors are required for a similar degree of conversion. Although a reduction in S:DG ratio requires a larger reactor volume (this analys is assumes a catalyst volume increase of 30 percent , and subsequently a 30 percent increase in reactor cost), the re is the benefit of shift steam savings. This steam can then be expanded through the steam turb ine to produce additional power.

Thermal input to the IGCC plant is used to fu lly

- load the combustion turbines . Any remaining energy in the combustion turbine exhaust is extracted to the maximum extent possible in a heat recovery steam generator in order to raise steam to generate additi onal power. T he net power for

the IGCC cases ranges from 523 to 622 MW. The span in net out put is caused by the wide range
of CO 2 

### capture imposed from case

- to

- case. The differences in auxiliary loads are primarily

attributed to CO 2 

### compression and the n eed for extraction steam in the WGS reactions, which reduces steam turbine output.



## Results

The major results from the CO 2 

### capture sensitivity analysis are discussed below in the following

order:

Performance (efficiency)

Economics (total overnight cost, cost of electricity, and CO 2 

### avoided cost)

Performance and Cost summary



## Performance

Energy Efficiency

The net plant HHV efficiencies for the SC PC and GEE IGCC cases are presented in Exhibit

ES

- 6 and Exhibit ES

- 7 , respectively

. As the CO 2 

### capture requirement is increased for eithe r plant type, PC or IGCC, there is an increase in the auxiliary power required to support theCarbon Dioxide Capture Sensitivity Analysis



### 7 capture equipment (either Econamine or Selexol TM ) and the CO 2 

### compressor trains. Further, more steam is consumed by the capture equipment, and by the WGS reactor( s) in the IGCC case, making less available for supply to the steam turbine. Both effects (higher auxiliary load and reduced steam supply to the turbine) detract from the net power produced by the plant per unit of coal energy input, as evidenced by the ne t plant HHV efficiency trends v ersu s CO 2 

### capture level

.

Exhibit ES

- 6 Supercritical PC Net Plant Efficiency ( HHV )Carbon Dioxide Capture Sensitivity Analysis



### 8 Exhibit ES

- 7 IGCC Net Plant Efficiency ( HHV )



## Economics

Total Overnight Cost

All capital costs are presented as “overnight costs” expressed in J une 2007 dollars. The c apital costs are presented at the total overnight cost ( TOC ) level, which includes: (1) e quipment (complete with initial c hemical and catalyst loadings); (2) m a terials; (3) labor (direct and
indirect); (4) e ngineering and construction management; (5) c ont ingencies (process and project);

and (6) owner‟s costs

. The owner‟s costs, which are summarized in Exhibit 2

- 18 , include preproduction costs, inventory capital, land costs, financing costs, taxes and insurances, and

other owner‟s costs.

The TOC for the SC PC and GEE IGCC cases are presented in Exhibit ES

- 8 and Exhibit ES

- 9

, respectively. These exhibits categorize the TOC into five categories: (1) bare erected cost; (2) engineering, home office, construction management (CM), and fee s ; (3) project contingency; ( 4) process contingency; and (5) owner‟s costs.

The SC PC total overnight cost estimates apply to facilities designed with a fixed 550 MW net capacity. As the design is equipped for increased CO 2 

### capture, moving from Case 1A through

Case 1G, the TOC also increase s as a result of the need for larger power plant components forCarbon Dioxide Capture Sensitivity Analysis



### 9 power generation to offset the auxiliary power and steam requirements of the CO 2 

### capture and compression systems . Hence, the increase in installed TOC per net kW delivered.

Exhibit ES

- 8 Supercritical PC T otal O vernight C ost



### The IGCC total overnight cost estimates apply to facilities designed with a fixed gross

combustion turbine capacity of 464 MW (total for two turbines) . As the plant is equipped for

increased CO 2 

### capture, moving from Case 2 D1A through Case 2 D4C , the TOC also increase s
as a result of the need for larger components for power generation , while still maintaining the required gas turbine output . Hence

, the increase in i nstalled TOC per net kW delivered.Carbon Dioxide Capture Sensitivity Analysis



### 10 Exhibit ES

- 9 IGCC T otal O vernight C ost



### Cost of Electricity

The revenue requirement figure

- of

- merit in this report is the cost of electricity ( COE ) expressed

in mills/kWh (numerically equivalent to $ / M Wh). The capital expenditure and operational periods for the SC PC and IGCC power plants are 5 and 30 years, respectively

. The costs

associated with CO 2 

### transportation, storage, and monitoring (TS&M) are included for all cap ture

cases. All costs are expressed in June 2007 dollars, and the resulting COE is also expressed in June 2007 year dollars.

The COE for the SC PC and GEE IGCC cases are presented in Exhibit ES

- 10 and Exhibit ES

- 11

, respectively. These exhibits show the COE divided into five categ ories: (1) capital costs; (2)
fixed costs; (3) variable costs; (4) fuel costs; and (5) CO 2 

### TS&M costs.

The COE estimates are based on capacity factors of 85 percent and 80 percent for the SC PC and GEE IGCC cases, respectively.Carbon Dioxide Capture Sensitivity Analysis



### 11 Exhibit ES

- 10 Supercritical PC C ost of E lectricityCarbon Dioxide Capture Sensitivity Analysis



### 12 Exhibit ES

- 11 IGCC C ost of E lectricity



### CO 2 

### Avoided Costs

The CO 2 

### avoided cost was calculated as illustrated in Equation 1.

( 1 )

The CO 2 

### avoided costs for the SC PC and GEE IGCC cases are presented in Exhibit ES

- 12 and

Exhibit ES

- 13 , respectively. The SC PC cases use the corresponding non

- capture SC PC reference. The IGCC cases are presented both relative to the equivalent IGCC without carbon capture and SC PC without capture plants. For the SC PC plant, the CO 2 

### avoided costs decrease

as the CO 2 

### capture level increases until reaching minimum values at 95 percent capture (Case
1F).Carbon Dioxide Capture Sensitivity Analysis



### 13 Exhibit ES

- 12 Supercritical PC CO 2 Avoided Costs



### The CO 2 

### avoided costs for the GEE IGCC cases decrease as the CO 2 

### capture level increases

, until reaching minimum values at 85 to 90 percent capture (Case s D3E and D4A ). As a result, this analysis concludes that 85 to 90 percent is the optimal CO 2 

### capture level for a GEE IGCC power plant.Carbon Dioxide Capture Sensitivity Analysis



### 14 Exhibit ES

- 13 IGCC CO 2 Avoided Costs



## Cost and Performance Summary

The following conclusions can be drawn from this analysis.

At all levels of carbon capture considered in this analysis, an IGCC plant will operate more efficiently than a SC PC plant. This high er efficiency result s in lower fuel costs and reduced coal handling costs for the same level of power output

.

At lower levels of CO 2 

### capture, the COE of a SC PC plant is less than an IGCC plant.

However this COE advantage begins to disappear as capture level increases. For CCS greater than approximately 90 percent , IGCC and SC PC have costs of electricity that are nearly equal. This same trend applies to plant capital costs (expres sed in $/kW).

CO 2 

### avoided costs

, using analogous non

- capture plants as reference, are substantially

low er for IGCC than for SC PC, for all levels of capture. This is reflective of the

relative ly low er cost impact associated with adding CO 2 

### controls to an IGCC plant compared to SC PC. However, the avoided CO 2 

### costs for IGCC capture plants, using the

SC PC non

- capture reference plant, are higher due to the higher COE of non

- capture IGCC plants.Carbon Dioxide Capture Sensitivity Analysis



### 15 CO 2 

### avoided costs for SC PC plants are high f or low levels of CCS, and then start to

diminish as the capture increases. Gradually, a minimum is reached around 95% CCS,

before costs start to rise again slightly. This suggests that if a SC PC plant will lay out the additional capital required to inst all CO 2 

### controls, that equipment could be used most

cost

- effectively by capturing as much carbon dioxide as possible (up to about 95%).

CO 2 

### avoided costs for IGCC (relative to an IGCC non

- capture plant) are less volatile than SC PC over a wide range of cap ture. Although they generally decrease as the level of CCS increases (similar to SC PC), the spread between the high and low values is small

relative to SC PC. Since an IGCC system is a more complex process, it better lends itself to optimization than a SC PC plant. To accommodate the specified level of CO 2 

### capture, there were numerous variables that were manipulated simultaneously (including the number of water gas shift reactors, the amount of shift steam required, solvent circulation rate, and the syn gas bypass rate) to minimize the cost and performance impact

. The SC PC plant, although in most cases less expensive than IGCC, is a simpler process and therefore exhibits less potential for optimization.

A summary of SC PC and IGCC plant costs and perf ormance are shown in Exhibit ES

- 14 and

Exhibit ES

- 15 , respectively.Carbon Dioxide Capture Sensitivity Analysis



### 16 Exhibit ES

- 14 Cost and Performance Results for the Supercritical PC Cases

Case 0 1A 1B 1C 1D 1E 1F 1G

CO 2 Capture, % 0% 30% 50% 70% 85% 90% 95% 99%

Gross Power Output, MW
e 580.4 601.5 618.2 637.8 654.8 661.3 667.9 679.6

Net Power Output, MW
e 550.0 550.0 550.0 550.0 550.1 550.0 550.0 550.0

Net Plant Efficiency, % (HHV) 39.3 35.2 32.9 30.6 28.9 28.2 27.5 25.7

Net Plant Heat Rate, Btu/kWh (HHV) 8,687 9,695 10,379 11,151 11,819 12,083 12,400 13,269

Coal Flowrate (lb/hr) 409,550 457,066 489,316 525,764 557,283 569,672 584,578 625,561

Total CO 2 Captured, lb/MWh net NA 588 1,057 1,582 2,037 2,213 2,398 2,674

CO 2 Capture & Compression Cost, $x1000 NA $ 190,138 $ 266,902 $ 336,794 $ 441,781 $ 463,389 $ 485,273 $ 516,797

Total Plant Cost, $x1000 $905,901 $1,138,688 $1,258,942 $1,378,696 $1,525,453 $1,562,889 $1,602,389 $1,678,914

Owner’s Costs, $x1000 $ 207,800 $ 258,649 $ 285,448 $ 312,458 $ 344,744 $ 353,249 $ 362,267 $ 380,090

Total Overnight Cost, $x1000 $ 1,113,701 $ 1,397,338 $ 1,544,390 $ 1,691,155 $ 1,870,197 $ 1,916,138 $ 1,964,657 $ 2,059,004

Total Overnight Cost, $/kW $2,025 $2,541 $2,808 $3,075 $3,400 $3,484 $3,572 $3,744

Total As

- Spent Capital, $x1000 $ 1,262,937 $ 1,592,965 $ 1,760,604 $ 1,927,917 $ 2,132,024 $ 2,184,397 $ 2,239,708 $ 2,347,264

Total As

- Spent Capital, $/kW $ 2,296 $ 2,896 $ 3,201 $ 3,505 $ 3,876 $ 3,972 $ 4,072 $ 4,268

CO 2 Capital Cost Penalty a , $/kW NA $516 $783 $1,050 $1,375 $1,459 $1,548 $1,719

Cost of Electricity b , mills/kWh 58.90 76.64 84.38 92.75 101.49 104.29 107.00 112.65

COE CO 2 Penalty a , mills/kWh NA 17.7 25.5 33.8 42.6 45.4 48.1 53.8

Percent increase in COE a , % NA 30.1 43. 3 57. 5 72.3 77. 1 81. 7 91. 3

Cost of CO 2 Avoided a , $/tonne NA 102.8 79.1 69.2 67.2 65.9 64.7 68.2

CO 2 Emissions, lb/MMBtu 203.2 142.9 101.7 61.7 31.2 20.4 10.2 2.0

CO 2 Emissions, lb/MWh net 1,765 1,385 1,055 687 369 246 126 27

SO 2 Emissions, lb/MMBtu 0.086 0.064 0.050 0.036 0.017 0.017 0.016 0.016

SO 2 Emissions, lb/MWh 0.75 0.570 0.460 0.340 0.170 0.170 0.170 0.170

NO

x Emissions, lb/MMBtu 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070

NO

x Emissions, lb/MWh 0.608 0.621 0.646 0.673 0.695 0.703 0.715 0.752

PM Emissions, lb/MMBtu 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013

PM Emissions, lb/MWh 0.113 0.115 0.120 0.125 0.129 0.131 0.133 0.140

Hg Emissions, lb/TBtu 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14

Hg Emissions, lb/TWh 9.93 10.1 10.6 11.0 11.3 11.5 11.7 12.3

Raw Water Withdrawal, gpm 5,394 6,245 6,987 8,386 9,615 10,095 10,512 11,664

Raw Water Consumption, gpm 4,301 4,898 5,433 6,474 7,392 7,753 8,074 8,961

Raw Water Consumption, gal/MWh net 469 534 593 706 806 846 881 978

a Relative to Case 0 ( SC PC without capture from 2010 Bituminous Baseline study)

b Capacity factor is 85% for the SC PC casesCarbon Dioxide Capture Sensitivity Analysis



### 17 Exhibit ES

- 15 Cost and Performance Results for the GEE IGCC Cases

Case 2

- D1A 2

- D1B 2

- D2A 2

- D2B 2

- D2C 2

- D2D 2

- D3A 2

- D3B 2

- D3C 2

- D3D 2

- D3E 2

- D4A 2

- D4B 2

- D4C

CO 2 Capture, % 0% 25% 25% 45% 60% 75% 25% 45% 60% 75% 85% 90% 95% 97%

Gross Power Output, MW
e 747.8 750.4 750.4 746.9 745.2 742.0 750.4 746.2 744.2 741.6 739.8 734.0 726.6 723.6

Net Power Output, MW
e 622.0 607.2 607.0 590.8 578.4 563.9 607.0 590.0 577.4 563.8 554.5 543.2 528.5 522.9

Net Plant Efficiency, % (HHV) 39.0 38.4 38.4 36.8 35.5 34.3 38.4 36.7 35.5 34.2 33.4 32.6 31.8 31.5

Net Plant Heat Rate, Btu/kWh (HHV) 8,756 8,891 8,895 9,283 9,604 9,958 8,894 9,289 9,614 9,969 10,222 10,459 10,731 10,840

Coal Flowrate (lb/hr) 466,861 462,752 462,861 470,117 476,133 481,355 462,783 469,844 475,867 481,779 485,836 487,026 486,169 485,856

Total CO 2 Captured, lb/MWh net NA 425 430 809 1,127 1,476 429 810 1,125 1,467 1,710 1,899 2,159 2,269

CO 2 Capture & Compression Cost, $x1000 0 $ 166,439 $ 166,741 $ 193,350 $ 212,092 $ 231,604 $ 167,196 $ 194,185 $ 212,378 $ 230,775 $ 242,919 $ 251,958 $ 264,505 $ 228,358

Total Plant Cost, $x1000 $ 1,235,944 $ 1,345,298 $ 1,346,066 $ 1,389,128 $ 1,419,771 $ 1,449,191 $ 1,346,380 $ 1,390,235 $ 1,419,640 $ 1,447,904 $ 1,465,871 $ 1,472,866 $ 1,483,871 $ 1,488,149

Owner’s Costs, $x1000 $ 286,161 $ 308,679 $ 308,860 $ 319,113 $ 326,535 $ 333,624 $ 308,914 $ 319,358 $ 326,551 $ 333,508 $ 337,972 $ 338,851 $ 341,323 $ 342,287

Total Overnight Cost, $x1000 $ 1,522,105 $ 1,653,977 $ 1,654,925 $ 1,708,241 $ 1,746,306 $ 1,782,815 $ 1,655,294 $ 1,709,592 $ 1,746,192 $ 1,781,411 $ 1,803,843 $ 1,811,717 $ 1,825,194 $ 1,830,436

Total Overnight Cost, $/kW $ 2,447 $ 2,724 $ 2,726 $ 2,891 $ 3,019 $ 3,161 $ 2,727 $ 2,897 $ 3,024 $ 3,160 $ 3,253 $ 3,335 $ 3,453 $ 3,501

Total As

- Spent Capital, $x1000 $ 1,735,200 $ 1,885,534 $ 1,886,615 $ 1,947,394 $ 1,990,789 $ 2,032,409 $ 1,887,035 $ 1,948,935 $ 1,990,658 $ 2,030,809 $ 2,056,381 $ 2,065,358 $ 2,080,721 $ 2,086,697

Total As

- Spent Capital, $/kW $ 2,790 $ 3,105 $ 3,108 $ 3,296 $ 3,442 $ 3,604 $ 3,109 $ 3,303 $ 3,447 $ 3,602 $ 3,709 $ 3,802 $ 3,937 $ 3,991

CO 2 Capi tal Cost Penalty a , $/kW $0 $277 $279 $444 $572 $715 $280 $450 $577 $713 $806 $888 $1,007 $1,054

Cost of Electricity b , mills/kWh 76.3 85.3 85.4 90.8 95.2 100.0 85.4 91.0 95.3 100.0 103.1 105.7 109.3 110.8

COE CO 2 Penalty a , mills/kWh NA 9.0 9.1 14.5 18.9 23.7 9.1 14.7 19.0 23.7 26.8 29.4 33.0 34.4

Percent increase in COE a , % NA 11.8% 11.9% 19.0% 24.7% 31.0% 12.0% 19.2% 24.9% 31.0% 35.1% 38.5% 43.3% 45.1%

Cost of CO 2 Avoided a , $/tonne NA 48.7 48.6 44.9 43.1 42.5 48.7 45.4 43.6 42.5 41.7 42.7 45.2 46.0

CO 2 Emis sions, lb/MMBtu 196.8 147.8 147.3 108.8 78.9 49.7 147.3 108.8 79.2 49.7 30.1 19.7 10.4 6.5

CO 2 Emi s sions , lb/MWh net 1,723 1,314 1,310 1,010 758 495 1,310 1,011 762 496 308 206 112 71

SO 2 Emissions, lb/MMBtu 0.005 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002

SO 2 Emis sions, lb/MWh 0.040 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020

NO

x Emis sions, lb/MMBtu 0.059 0.055 0.055 0.053 0.051 0.050 0.055 0.053 0.052 0.050 0.049 0.049 0.049 0.049

NO

x Emis sions, lb/MWh 0.430 0.397 0.397 0.390 0.384 0.379 0.397 0.391 0.385 0.379 0.375 0.376 0.380 0.382

PM Emissions, lb/MMBtu 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071

PM Emiss ions, lb/MWh 0.052 0.051 0.051 0.052 0.053 0.054 0.051 0.052 0.053 0.054 0.054 0.055 0.055 0.056

Hg Emiss ions, lb/TBtu 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571

Hg Emiss ions, lb/TWh 4.16 4.11 4.11 4.20 4.26 4.32 4.11 4.20 4.26 4.33 4.38 4.42 4.46 4.48

Raw Water Withdrawal, gpm 4,734 4,692 4,697 5,038 5,300 5,530 4,695 5,040 5,307 5,569 5,748 5,817 5,739 5,707

Raw Wate r Consumption, gpm 3,755 3,722 3,727 4,033 4,270 4,481 3,725 4,034 4,276 4,514 4,677 4,741 4,679 4,654

Raw Wate r Consumption, gal/MWh net 362 368 368 410 443 477 368 410 444 480 506 524 531 534

a Relative to Case 2 D1A (0% CO 2 capture)

b Capacity factor is 80% for the GEE IGCC casesCarbon Dioxide Capture Sensitivity Analysis



### 18 This page intentionally left blankCarbon Dioxide Capture Sensitivity Analysis



### 19 

# 1. Introduction

1.1 Study Background

Coal

- fired power plants account for approximately 50 percent of the power generation in the United States and approximately 80 percent of the greenhouse gas ( GHG ) emissions produced by the power generation sector [ 6 ]. Because coal

- fired power generation is such a large contributor to both national energy security and overall GHG emissions, it is important to develop methods for reducing the carbon footprint of coal

- fired power plants to mitigate environmental concerns

while continuing to reliably satisfy power demand. The e ffects of GHG reduction in the power

indu stry could even be felt in the transportation industry if plug

- in hybrid electric vehicles, fueled by low

- GHG power, play a larger role in the overall transportation fleet

.

Levels of CO 2 

### in the atmosphere have shown a steady rise from approximately 300 ppm in 1940

to more than 3 9 0 ppm in 20 10 [ 7 ]. At the same time, various studies have documented

noticeabl e changes in the earth‟s climate during recent years

, and model predictions suggest that

CO 2 

### levels play a role in these climate changes [ 8 ]. Given the potential implications surrounding global climate change and increasing concentrations of CO 2 

### in the atmosphere, technology and policy options are being investigated for avoiding CO 2 

### emissions.

The U.S. Department of Energy (DOE) seeks to develop technolo gy capable of capturing and sequestering 90 percent of the C O 2 

### produced in pulverized coal ( PC ) and integrated gasification combined cycle ( IGCC ) power pla nts that can achieve a significantly lower cost of electricity relative to the conventional technolog y components portrayed in this analysis.



## 1.2 Project Objectives

The study objective was to ident ify the optimal CO 2 

### capture leve l at new SC PC and IGCC power plants by employing state

- of

- the

- art control technologies in multiple process configurations.

The objective of Case 1 is to evaluate the technical and economic performance of a new SC PC power plant equipped with Econamine FG Plus SM 

### for post

- combustion CO 2 

### capture in the following increments: 30, 50, 70, 85 , 90, 95, and 99 percent capture. More de tailed, predictive acid gas removal (AGR) modeling is utilized to more accurately represent the performance of the

CO 2 

### separation process, and to determine if an optimum level of control exists. This case also
includes verification (via literature search) that less than 90 percent CO 2 

### capture is most economical using a „slip

- stream‟ approach.

The Case 2 objective is to evaluate the technical and economic performance of four des igns for a

new General Electric Energy ( GEE ) IGCC power plant with pre

- combustio n CO 2 

### capture using a physical solvent

- b ased SelexolTM system :

Design 1 (D1) has no water gas shift ( WGS ) reactor. T he minimum (0 percent ) and
maximum ( 25 percent ) CO 2 

### capture levels for this particular configuration areCarbon Dioxide Capture Sensitivity Analysis



### 20 modeled. Due to the high level of integration between the H 2 

### S and CO 2 

### absorbers, it

was not feasible to model no CO 2 

### capture with a two

- stage SelexolTM system.
Consequently, D1A (0 percent capture) emplo ys a one

- stage SelexolTM unit for
hydrogen sulfide ( H 2 

### S ) cont rol, while D1B (25 percent capture) utilizes a two

- stage

SelexolTM unit to maximize CO 2 

### capture from the unshifted syngas. D1 includes a carbonyl sulfide ( COS ) hydrolysis unit to treat the entire syngas stream.

Design 2 (D2) has one

- stage WGS with CO 2 

### capture ranging from 25 percent (upper

limit from D 1) to the maximum achievable limit for this particular configuration (75

percent ) by varying the WGS bypass ratio and the two

- stage SelexolTM CO 2 

### removal efficiency

. The SelexolTM removal efficiency is cha nged by varying the solvent circulation rate, which changes the size and cost of the SelexolTM system. The combined syngas stream (shi fted and unshifted gas) is routed through a COS hydrolysis unit.

Design 3 (D3) has two

- stage WGS with CO 2 

### capture ranging from 25 percent (upper

limit from D 1) to the maximum achievable limit for this particular configuration (85

percent ) by varying the WGS bypass ratio and the two

- stage SelexolTM CO 2 

### removal efficiency

. The SelexolTM removal efficiency is changed by varying t he solvent circulation rate, which changes the size and cost of the SelexolTM system. The WGS bypass stream passes through a COS hydrolysis unit.

Design 4 (D4) has two

- stage WGS and no bypass with CO 2 

### capture ranging from 90

to 97 percent . To achieve grea ter than 90 percent CO 2 

### removal, the two

- stage

SelexolTM CO 2 

### removal efficiency is increased by raising the solvent circulation rate, which increases the size and cost of the SelexolTM system. D4 does not include a
COS hydrolysis unit since sufficient COS t o H 2 

### S conversion occurs across the two

WGS reactors.

The facilities will be located in the Illinois coal basin using high

- sulfur bituminous Illinois No. 6 coal as the feedstock to produce electric power. The study include s compression of the captured

CO 2 

### to pipeline pressure (2,215 psia) , pipeline transport 80 kilometers (50 miles ), storage in a

saline formation at a depth of 1,239 meters (4,055 ft) , and monitoring for 80 years . The site will have appropriate access to rail transportation for delivery o f coal. All local coal handling facilities will be included in the design and cost estimation portion of this study.Carbon Dioxide Capture Sensitivity Analysis



### 21 

# 2. General Evaluation Basis

For Case 1, an Aspen model for a SC PC power plant, coupled with detailed simulations of the

Econami ne FG Plus SM 

### process using Optimized Gas Treating‟s ProTreatTM, was utilized to
evaluate the technical and economic performance of post

- combustion CO 2 

### capture in the following increments: 30, 50, 70, 85 , 90, 95, and 99 percent capture. The Case 1 SC PC

des criptions are summarized in Exhibit 2

- 1

.

Exhibit 2

- 1 Case 1 Supercritical PC Plant Configuration Summary

Case CO 2 Capture Intended

Storage Boiler Steam psig/°F/°F Oxidant NO

x Control Sulfur

Control

1 A 30%

Saline

Formation Wall

- fired,

PC 3500/1100/110 0 Air LNB/OFA/SCR

0.07 lb/ MM Btu Wet FGD

0.1 lb/ MM Btu 1B 50%

1C 7 0%

1D 85 %

1E 90%

1F 95%

1G 99%



### Optimized Gas Treating‟s rate

- based ProTreatTM software was used to generate performance

estimates for the Econamine FG Plus SM 

### process . Initially, 90 percent CO 2 

### removal was modeled by adjusting three key process parameters: (1) the circulation rate for th e 30 wt%

m onoethanolamine ( MEA ) solution; (2) the reboiler steam flow rate; and (3) the height of packing material in the absorption and stripping columns. For greater than 90 percent CO 2 

### removal, the MEA and reboiler steam flow rates were increased, while the packing height in the absorption and stripping columns was also raised to model 99 percent CO 2 

### removal.

A literat ure search was conducted to verify that <90 percent CO 2 

### capture is mo st economical using a “ slip

- stream ” (or bypass) approach. Indeed, the slip

- stream approach is more cost

effective for <90 percent CO 2 

### capture than removing reduced CO 2 

### fractions from the entire flue

gas stream , according to multiple peer

- reviewed studies [ 1

, 2

, 3 ] . The cost of CO 2 

### ca pture with

the Econamine process is dependent on the volume of gas being treated and a reduction in flue gas flow rate will (1) decrease the quantity of energy consumed by flue gas blowers; (2) reduce

the size of the CO 2 

### absorption columns; (3) trim the cooling water requirement of the direct contact cooling system; and (4) decrease the amount of fan power required to increase flue gas temperature and plume buoyancy. As a result, the „slip

- stream‟ appr oach for <90 percent CO 2 

### capture leads to low er capital and operating costs. Consequently, less than 90 percent CO 2 

### removal was modeled by bypassing a portion of the flue gas around the Econamine system. Thus, for these cases the inlet flue gas flow rate was adjusted in ProTreatTM, along with the MEA

and reboiler steam flow rates, to simulate CO 2 

### removals ranging from 30 percent to 85 percent

.Carbon Dioxide Capture Sensitivity Analysis



### 22 For each case, the CO 2 

### removal efficiency and reboiler steam duty obtained from ProTreatTM
were incorporated in to the complete SC PC power plant Aspen model to determine the coal feed rate required to maintain a net electric generation capacity of 550 MWe. This approach allows for an equitable comparison of the seven CO 2 

### capture cases.

Due to the range of CO 2 

### capt ure levels analyzed in Case 1, the Econamine capital and operating costs vary for the seven cases. While a factored approach that relies on the quantity of CO 2 

### captured for equipment sizing and cost estimation was employed, the cost estimates for the

Econ amine system were also developed based, in part, on output data from the ProTreatTM simulations. In particular, the ProTreatTM model output provided absorption and stripping
column diameters for each case, which were used to determine the required number of absorption trains.

For this analysis, it was assumed that the maximum absorption column diameter is 20 meters, based on information released by Fluor [ 4 ]. As a r esult, cost estimates for three CO 2 

### capture

levels

– 30 percent (1A), 50 percent (1B), and 70 percent (1C)

– are based on a single absorption and compression train. To calculate the capital cost for a single absorption train, it was assumed

that the absor ption columns represent 40 percent of the total capital cost for a two

- train Econamine system.

For Case 2, an Aspen model for a GE E IGCC power plant, coupled with analysis of different process configurations (i.e., water gas shift bypass ratio and SelexolTM CO 2 

### removal efficiency)

, was utilized to evaluate the technical and economic performance of pre

- combustion CO 2 

### capture for the four plant designs:

D1 has no WGS reactor. T he minimum (0 percent ) and maximum ( 25 percent ) CO 2 

### capture levels for this partic ular configuration are modeled. Due to the high level of integration between the H 2 

### S and CO 2 

### absorbers, it is not feasible to model no CO 2 

### capture with a two

- stage SelexolTM system. Consequently, D1A (0 percent capture) employs a one

- stage SelexolTM unit f or H 2 

### S control, while D1B (25 percent capture)

utilizes a two

- stage SelexolTM unit to maximize CO 2 

### capture from the unshif ted syngas. D1 includes a COS hydrolysis unit to treat the entire syngas stream.

D2 has one

- stage WGS with CO 2 

### capture ranging from 25 percent (upper limit from

D 1) to the maximum achievable limit for this particular configuration (75 percent ) by varying the WGS bypass ratio and the two

- stage SelexolTM CO 2 

### removal efficiency

. The SelexolTM removal efficiency is changed by varying the solvent circulation rate,

which changes the size and cost of the SelexolTM system. The combined syngas
stream (shi fted and unshifted gas) is routed through a COS hydrolysis unit.

D3 has two

- stage WG S with CO 2 

### capture ranging from 25 percent (upper limit from

D 1) to the maximum achievable limit for this particular configuration (85 percent ) by varying the WGS bypass ratio and the two

- stage SelexolTM CO 2 

### removal efficiency

. The SelexolTM removal efficie ncy is changed by varying the solvent circulation rate, which changes the size and cost of the SelexolTM system. The WGS bypass stream passes through a COS hydrolysis unit.

D4 has two

- stage WGS and no bypass with CO 2 

### capture ranging from 90 to 97

percent

. To achieve greater than 90 percent CO 2 

### removal, the two

- stage SelexolTMCarbon Dioxide Capture Sensitivity Analysis



### 23 CO 2 

### removal efficiency is increased by raising the solvent circulation rate, which increases the size and cost of the SelexolTM system. D4 does not include a COS
hydrolysis unit since sufficient COS to H 2 

### S conversion occurs across the two WGS

reactors.

The Case 2 IGCC design descriptions are summarized in Exhibit 2

- 2

.

Exhibit 2

- 2 Case 2 GEE IGCC Plant Configuration Summary

Case CO 2 Capture CO 2

Separation Intended

Storage Gasifier Steam psig/°F/°F Oxidant WGS Sulfur

Control

D1A 0% N/A N/A

GE E

Radiant Only 1800/1050/1050 95 mol%

O 2 N/A

SelexolTM D1B 25%

SelexolTM

2 nd Stage Saline

Formation N/A

D2A 25%

One

- Stage

with bypass D2B 45%

D2C 60%

D2D 75%

D3A 25%

Two

- Stage

with bypass D3B 45%

D3C 60%

D3D 75%

D3E 85%

D4A 90% Two

- Stage

without bypass D4B 95%

D4C 97%



### To determine the process configurations for less than 90 percent CO 2 

### removal (IGCC D2 and D3), the WGS bypass ratio and SelexolTM CO 2 

### removal efficiency were varied over a series of Aspen simulations of the entire GEE IGCC power plant to evaluate the impact on WGS and SelexolTM costs and net plant efficiency. As a starting point, the SelexolTM CO 2 

### removal efficiency (92.4 percent ) used to model 90 percent CO 2 

### removal was fixed [ 5 ], and the WGS bypass ratio was adjusted to achieve the desired level of capture. The CO 2 

### removal level was then held constant by decreasing both the WGS bypass ratio (i.e., routing more syngas through the WGS reactor(s)) and the SelexolTM CO 2 

### removal efficiency. These step changes in the WGS bypass ratio lead to an increase in CO 2 

### partial pressure, which relaxes the CO 2 

### removal required by the SelexolTM process.

As shown in Exhibit 2

- 3 , the cost of the WGS system decreases as the WGS bypass ratio

in creases since the quantity of s y n gas being shifted declines. The SelexolTM system cost
increases with the WGS bypass ratio sinc e a higher solvent circulation rate is required to

maintain 60 percent CO 2 

### removal as the CO 2 

### partial pressure at the SelexolTM inlet decreases. However, the total cost of the WGS and SelexolTM systems, which is dominated by the cost of the SelexolTM system, gradually increases with the WGS bypass ratio. Meanwhile, the net plantCarbon Dioxide Capture Sensitivity Analysis



### 24 higher heating value ( HHV ) efficiency passes through a maximum value over the range of WGS bypass ratios. As a result, the WGS bypass ratios and SelexolTM CO 2 

### removal efficiencies us ed

to model less than 90 percent CO 2 

### removal in this study (IGCC D2 and D3) correspond to the maximum net plant HHV efficiency.

Exhibit 2

- 3 Net Efficiency and Cost as a Function of WGS Bypass Ratio for 60% CO 2 Removal with IGCC Design 3



### This procedure was repeated for each level of total CO 2 

### removal analyzed for IGCC D2 and D3 to determine the optimal WGS bypass ratio and SelexolTM CO 2 

### remo val efficiency for these intermediate capture points. Data for these optimal configurations is provided in Exhibit 2

- 4 and

Exhibit 2

- 5 for IGCC D2 and D3, respectively. These results indicate that the SelexolTM CO 2 

### removal efficiency increases with CO 2 

### partial pressure, which is the expected trend w ith a physical solvent

- based system.

Exhibit 2

- 4 Process Configurations for IGCC D2

Total CO 2 Removal (%) WGS WGS Bypass

Ratio (%) SelexolTM CO 2

Removal (%) P CO2 (psia)

25

One

- Stage

with Bypass 99 .5 85

. 8 119.4

45 60 8 9 186.3

60 28.75 8 9.5 229.8

75 0 91 265.5Carbon Dioxide Capture Sensitivity Analysis



### 25 Exhibit 2

- 5 Process Configurations for IGCC D3

Total CO 2 Removal (%) WGS WGS Bypass

Ratio (%) SelexolTM CO 2

Removal (%) P CO2 (psia)

25

Two

- Stage

with Bypass 99.75 86

. 31 119. 7

45 6 9.4 90.04 186.5

60 45 90.1 230.1

75 21 90.4 26 4.3

85 5 9 0.52 289. 3



### A typical offering from a commercial catalyst vendor is a S:DG molar ratio of 0.3 at the outlet of

the final WGS reactor. However

, for less than 90 percent CO 2 

### capture (IGCC D2 and D3), this study uses a S:DG molar ratio of 0. 25 at the outlet of the final WGS reactor. Operating with a lower S:DG ratio impedes the kinetics of CO to CO 2 

### conversion. Consequently, larger and more costly WG S reactors are required for a similar degree of conversion. Although a reduction in S:DG ratio requires a larger reactor volume (this analysis assumes a volume increase of 30

percent , and subsequently a 30 percent increase in reactor cost), the benefit of steam savings

– which can then expanded through the steam turbine to produce additional power

– is more than adequate to offset the increase in capital cost.

Thermal input to the IGCC plant is used to fully

- load the combustion turbines. Any remaining

e nergy in the combustion turbine exhaust is extracted to the maximum extent possible in a heat recovery steam generator in order to raise steam to generate additional power. The net power for the IGCC cases ranges from 523 to 622 MW. The range in net outp ut is caused by the wide

variance of CO 2 

### capture imposed from case

- to

- case. The differences in auxiliary loads are primarily attributed to CO 2 

### compression and the need for extraction steam in the WGS reactions, which reduces steam turbine output.

For ea ch of the plant configurat ions in this study, an Aspen model was developed and used to generate material and energy balances. The material and energy balances were used as the basis for generating the capital and operating cost estimates. Ultimately a CO E was calculated for each of the cases and is reported as the revenue requirement figure

- of

- merit.

The balance of this section provides details on the site charac teristics, coal characteristics and

costs , the study environmental targets, assumed capacity f actor, raw water usage, and the cost estimating methodology

.



## 2.1 Site Characteristics

The SC PC and GE E IGCC plants are assumed to be located at a generic site in the m idwestern

United States . The ambient conditions, consistent with the International Standard Organization
(ISO) [ 9 ] , and site characteristics are presented in Exhibit 2

- 6 and Exhibit 2

- 7 , respectively.Carbon Dioxide Capture Sensitivity Analysis



### 26 Exhibit 2

- 6 Site Ambient Conditions

Elevation, ft 0

Barometric Pressure, psia 14.696

Design Ambient Temperature, Dry Bulb, F 59

Design Ambient Temperature, Wet Bulb, F 51.5

Design Ambient Relative Humidity, % 60

Exhibit 2

- 7 Site Characteristics

Location Greenfield, m idwestern United States 1

Topography Level

Size, acres 300

Transportation Rail

Ash Disposal Off Site

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

Access Land locked , having also access by train and highway

CO 2 Compressed to 15.3 MPa (2,215 psia), transported 50 miles and sequestered in a saline formation at a depth of
4,055 feet

1 

### Champaign County, Illinois

, is assumed for assessment of construction costs.

The following design parameters will be considered site

- specific, and will not be quantifi ed for this study. Allowances for normal conditions and construction will be included in the cost

estimates.

Flood plain considerations

Existing soil/site conditions

Water discharges and reuse

Rainfall/snowfall criteria

Seismic design

Buildings/enclosures

Fire protection

Local code height requirements

Noise regulations

– Impact on site and surrounding areaCarbon Dioxide Capture Sensitivity Analysis



### 27 

## 2.2 Coal Characteristics a nd Cost

The design coal char acteristics are presented in Exhibit 2

- 8 . All cases in this study were modeled using Illinois No. 6 bituminous coal.

Exhibit 2

- 8 Design Coal

Coal seam nomenclature Herrin (No. 6)

Coal name Illinois No. 6

Mine Old Ben No. 26

ASTM D388 Rank High Volatile A Bituminous

Proximate Analysis As

- Received Dry

Moisture 11.12% 0.00%

Volatile Matter 34.99% 39.37%

Ash 9.70% 10.91%

Fixed Carbon 44.19% 49.72%

Total 100.00% 100.00%

Ultimate Analysis As

- Received Dry

Carbon 63.75% 71.73%

Hydrogen 4.50% 5.06%

Nitrogen 1.25% 1.41%

Sulfur 2.51% 2.82%

Chlorine 0.29% 0.33%

Ash 9.70% 10.91%

Moisture 11.12% 0.00%

Oxygen 6.88% 7.74%

Total 100.00% 100.00%

Reported Heating Value As

- Received Dry

HHV (Btu/lb) 11,666 13,126

LHV (Btu/lb) 11,252 12,660

HHV (kJ/kg) 27,135 30,531

LHV (kJ/kg) 26,171 29,447Carbon Dioxide Capture Sensitivity Analysis



### 28 Exhibit 2

- 8 Design Coal (continued)

Typical Ash Mineral Analysis

Silica SiO 2 45.0%

Aluminum Oxide Al 2 O 3 18.0%

Titanium Dioxide TiO 2 1.0%

Iron Oxide Fe 2 O 3 20.0%

Calcium Oxide CaO 7.0%

Magnesium Oxide MgO 1.0%

Sodium Oxide Na 2 O 0.6%

Potassium Oxide K 2 O 1.9%

Phosphorus Pentoxide P 2 O 5 0.2%

Sulfur Trioxide SO 3 3.5%

Undetermined 1.8%

Total 100.0%

Typical Ash Fusion Temperatures (°F)

Reducing

Initial

– Limited deformation 1950 oF

Softening H=W 2030 oF

Hemispherical H=1/2W 2140 oF

Fluid 2150 oF

Oxidizing

Initial

– Limited deformation 2250 oF

Softening H=W 2300 oF

Hemispherical H=1/2W 2430 oF

Fluid 2450 oF

Hardgrove Grindability Index 60 HGICarbon Dioxide Capture Sensitivity Analysis



### 29 Exhibit 2

- 8 Design Coal (continued)

Average Trace Element Composition of Coal Shipped by

Illinois Mines, Dry basis, ppm

Trace Element Arithmetic

Mean Standard

Deviation

Arsenic As 7.5 8.1

Boron B 90 45

Beryllium Be 1.2 0.7

Cadmium Cd 0.5 0.9

Chlorine Cl 1671 1189

Cobalt Co 3.5 1.3

Chromium Cr 14 6

Copper Cu 9.2 2.5

Fluorine F 93 36

Mercury Hg 0.09 0.06

Lithium Li 9.4 7.1

Manganese Mn 38 32

Molybdenum Mo 8.4 5.7

Nickel Ni 14 5

Phosphorus Ph 87 83

Lead Pb 24 21

Tin Sb 0.9 0.7

Selenium Se 1.9 0.9

Thorium Th 1.5 0.4

Uranium Ur 2.2 1.9

Vanadium V 31 16

Zinc Zn 84.4 84.2

Note: Average trace element composition of coal shipped by Illinois mines is based on 34 samples, 2004 Keystone Coal Industry Manual [ 10 ]



### The mercury content in the Illinois No. 6 coal is reported as an arithmetic mean value of

0.09 ppm (dry basis) with standard deviation of 0.06. Hence, as illustrated in Exhibit 2

- 9 , there

is a 50 percent probability that the mercury content in the Illinois No. 6 coal would not exceed

0.09 ppm (dry basis), and 99.9 percent probability that the mercury content in th e Illinois No. 6

coal would not exceed 0.28 ppm (dry basis).Carbon Dioxide Capture Sensitivity Analysis



### 30 Exhibit 2

- 9 Probability Distribution of Mercury Concentration in the Illinois No. 6 Coal

Source: 2004 Keystone Coal Industry Manual, Mining Media Publication



### For the cases in this study, coal mercury content was assumed to be equal to the arithmetic mean mercury concentration plus one standard deviation, or 0.15 ppmd. About 84 percent of the coal samples represented in Exhibit 2

- 9 have a mercury concentration equal to or less than 0.15 ppmd.

The coal cost used in this study is $1.55/GJ ($1.64/MMBtu) (2007 cost of coal in June 2007
dollars) . This cost was determined using the following information from the EIA 2008 AEO:

The 2007 minemouth cost of Illinois No. 6 in 2006 dollars, $32.66/tonne ($29.63/ton), was obtained from Supplemental Table 112 of the EIA‟s 2008 AEO for

eastern interior high

- sulfur bituminous coal.

The cost of Illinois No. 6 coal was escalated to 2007 dollars using the gross domestic product (GDP) chain

- type price index from AEO 2008, resulting in a price of $33.67/tonne ($30.55/ton) [ 11 ].

Transportation costs for Illino is No. 6 were estimated to be 25 percent of the minemouth cost based on the average transportation rate of the respective coals to the surrounding regions [ 12 ]

. The final delivered costs for Illinois No. 6 coal used in the calculations is $42.09/tonne ($38 .18/ton) or $1.55/GJ ($1.64/MMBtu). (Note: The Illinois No. 6 coal cost of $1.6366/MMBtu was used in calculations, but only two decimal places are shown in the report.)Carbon Dioxide Capture Sensitivity Analysis



### 31 

## 2.3 Design Sorbent Composition

Limestone from Greer Limestone mine in Morgantown, WV

, is assumed as a design sorbent for

the SC PC plant [ 13 ]. Sorbent is delivered to plant storage by truck. Limestone analysis is presented in Exhibit 2

- 10

.

Exhibit 2

- 10 Sorbent Analysis

Supplier Greer Industries, Inc. Analysis, %

Calcium Carbonate CaCO 3 80.40

Magnesium Carbonate MgCO 3 3.50

Silica SiO 2 10.32

Aluminum Oxide Al 2 O 3 3.16

Iron Oxide Fe 2 O 3 1.24

Sodium Oxide Na 2 O 0.23

Potassium Oxide K 2 O 0.72

Balance 0.43

Total 100 .00



## 2.4 Environmental Targets

In setting the environmental targets

, a number of factors were considered, including current emission regulations, regulation trends, results from recent permitting activities, and the status of current best available control technology (BACT).

The current federal regulation governing new fos sil

- fuel fired electric utility steam generating
units is the New Source Performance Standards (NSPS) as amended in June 2007 and shown in

Exhibit 2

- 11

. This represents the minimum level of control that would be required for a new fossil energy plant [ 14 ]

. Stationary combustion turbine emission limits are further defined in 40 CFR Part 60, Subpart KKKK.

The new NSPS standards apply to units with the cap acity to generate greater than 73 MW of power by burning fossil fuels, as well as cogeneration units that sell more than 25 MW of power

and more than one

- third of their potential output capacity to any utility power distribution system. In cases where bot h an emission limit and a percent reduction are presented, the unit has the option of meeting one or the other. All limits with the unit lb/MWh are based on gross power

output.Carbon Dioxide Capture Sensitivity Analysis



### 32 Exhibit 2

- 11 Standards of Performance for Electric Utility Steam Generating Units

Built, Reconstructed, or Modified After February 28, 2005

New Units Reconstructed Units Modified Units

Emission

Limit %

Reduction Emission

Limit (lb/MMBtu) %

Reduction Emission

Limit (lb/MMBtu) %

Reduction

PM 0.015

lb/MMBtu 99.9 0.015 99.9 0.015 99.8

SO 2 1.4 lb/MWh 95 0.15 95 0.15 90

NO

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



### Other regulations that could affect emissions limits from a new plant include the New Source Review (NSR) permitting process and Prevention of Significant Deterioration (PSD). The NSR process requires installation of emission control technology meeting ei ther 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). The Clean Air Act authorizes EPA to establish regulations to prevent significant deterioration of air quality due to emissions of any pollutant for which a national ambient air quality standard (NAAQS) has been promulgated.

Environmen tal area designation varies by county and can be established only for a specific site

location. Based on the EPA Green Book Non

- attainment Area Map

, relatively few areas in the

m idwestern United States are classified as “non

- attainment”, and therefore BA CT is chosen here
rather than LAER [ 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 some judgment in setting the environmental targets for this study. For the purpose of this study, BACT was assumed to be adequate.



## 2.4.1 Supercritical PC Plant

The environmental approach for this study was to evaluate each case on the same regulatory design basis. A BACT approach was taken and used uniformly throughout the study. The BACT technologies assumed for this study meet the emission requirements of the 2006 NSPS. The emissions controls employed and the environmental targets are shown in Exhibit 2

- 12

.

The environmental target represents the maximum allowable emissions. In some cases actual emissions are less than the target. For exampl e, amine

- based CO 2 

### capture requires a polishing

scrubber to reduce SO 2 

### concentrations to less than 10 ppmv. As a result, the SO 2 

### emissions are substantially less than the environmental target.Carbon Dioxide Capture Sensitivity Analysis



### 33 Exhibit 2

- 12 Environmental Targets for PC Cases

Technology Pulverized Coal Boilers

Sulfur Control Technology Wet Limestone FGD

Sulfur Limits 98% efficiency or

≤ 0.10 lb SO 2 /10 6 Btu

NO

x Control Technology LNB w/OFA (or OFO) and SCR in

air

- based cases

NOx Limits 0.07 lb/10 6 Btu

PM Control Technology Fabric Filter

PM Limits 99.8% or ≤ 0.015 lb/10 6 Btu

Hg Control Technology Co

- benefit capture

Hg Limits 90% removal



## 2.4.2 GEE IGCC Plant

The IGCC environmental targets were chosen to match the Electric Power Research Institute‟s
(EPRI) design basis for their CoalFleet for Tomorrow Initiative and are shown in Exhibit 2

- 13

[ 16 ]

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

The BACT emission limits assumed for this study exceed the emission requirements of the NSPS

as amended in June 2007 [ 14 ]. It is possible that state and local requirements could supersede NSPS or BACT and impose even more stringent requirements.

Exhibit 2

- 13 Environmental Targets for IGCC Cases

Pollutant Environmental

Target NSPS

Limit Control

Technology

NO

x 15 ppm (dry) @

15% O 2 1.0

lb/MWh Low

- NO

x burners

and syngas nitrogen dilution

SO 2 0.0128 lb/MMBtu 1.4

lb/MWh SelexolTM or MDEA

Particulate

Matter (Filterable) 0.0071 lb/MMBtu 0.015

lb/MMBtu Quench and water

scrubber

Mercury > 90% capture 20 x 10

- 6

lb/MWh Carbon bed



## 2.4.3 Carbon Dioxide

CO 2 

### is not currently regulated. However, the possibility exists that carbon limits will be imposed

in the future

, and this study examines cases that include a reduction in CO 2 

### emissions. BecauseCarbon Dioxide Capture Sensitivity Analysis



### 34 the form of emission limits, should they be imposed, is not known, CO 2 

### emissions are reported on both a lb/(gross) MWh and lb/(net) MWh basis in each emissions table.

For the SC PC cases, it is assumed that all of the fuel carbon is converted to CO 2 

### in the flue gas.

T his study analyzes a wide range of CO 2 

### removal efficiencies by bypassing a portion of the flue gas around the amine

- based Econamine FG Plus SM 

### process.

Fo r the IGCC cases, t his study analyzes a wide range of CO 2 

### removal efficiencies, based on carbon input in the coal and excluding carbon that exits with the gasifier slag, by investigating various process configurations. Process parameters manipulated to co ntrol the level of total CO 2 

### removal include the number of WGS reactors employed, WGS bypass ratio, S:DG ratio at the
WGS outlet, and the SelexolTM CO 2 

### removal efficiency.



## 2.5 Capacity Factor

This study assumes that each new plant would be dispatched any time it is available and would be capable of generating maximum capacity when online; therefore, capacity factor and availability are equal. The availability for combustion cases was determined using the Generating Availability Data System (GADS) from the Nor th American Electric Reliability

Cou ncil (NERC) [ 17 ]

. Since there are only two operating IGCC plants in North America, the same database was not useful for determining IGCC availability. Rather, input from EPRI and

their work on the CoalFleet for Tomorrow Initiative were used to set the IGCC case capacity

factor.

NERC defines an equivalent availability factor (EAF) as a measure of the plant capacity factor assuming there is always a demand for the output. The EAF accounts for planned and scheduled

derated hours as well as seasonal derated hours. As such, the EAF matches this study‟s
definition of capacity factor.

The average EAF for coal

- fired plants in the 400

– 599 MW size range was 84.9 percent in 2004 and averaged 83.9 percent from 2000 to 2004. Given that many of the plants in this size range are older, the EAF was rounded up to 85 percent and that value was used as the SC PC plant capacity factor.

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

the reliabili ty factor (which looks at forced or unscheduled outage time only) for a single train IGCC (no spares) would be about 90 percent [ 18 ]. To get the availability factor, one has to

deduct the scheduled outage time. In reality, t he scheduled outage time s could differ amongst

the different gasifier technolog ies. However, the differences are relatively small and would have minimal impact on the capacity factor, so for this study it was assumed to be constant at a 30

- day planned outage per year (or two 15

- day out ages)

. The planned outage would amount to

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

- 8.2 percent), or

81. 8 percent

.

There are four operating IGCC‟s worldwide that use a solid feedstock and are primarily power
producers (Pol k, Wabash, Buggenum

, and Puertollano). A 2006 report by Higman et al. examined the reliability of these IGCC power generation units and concluded that typical annualCarbon Dioxide Capture Sensitivity Analysis



### 35 on

- stream times are around 80 percent [ 19 ] . The capacity factor would be somewhat less th an
the on

- stream time since most plants operate at less than full load for some portion of the operating year. Given the results of the EPRI study and the Higman paper, a capacity factor of 80 percent was chosen for IGCC with no spare gasifier required.

T he addition of CO 2 

### capture was assumed not to impact the capacity factor even without redundant pipelines, wells

, or subsurface infrastructure . This assumption was made to enable a comparison based on the impact of capital and variable operating costs only. Any reduction in assumed capacity factor would further increase the COE with CO 2 

### capture

.



## 2.6 Raw Water Withdrawal

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. Internal recycle water available from various sources like boiler feedwater blowdown and condensate from syngas was applied to offset the water demand. The difference between demand and recycle is raw water withdrawal. Raw water withdrawal is the water removed from the ground or diverted from a surface

- water source for use in the plant. Raw water consumption is also accounted f or and is defined as the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or

otherwise not returned to the water source it was withdrawn from.

Raw water withdrawal was assumed to be provided 50 percent by a publ icly owned treatment works (POTW) and 50 percent from groundwater. Raw water withdrawal is defined as the water metered from a raw water source and used in the plant processes for any and all purposes, such as cooling tower makeup, boiler feedwater makeup , quench system makeup, and slag handling makeup. The difference between withdrawal and process water returned to the source is consumption. Consumption represents the overall impact of the process on the water source.

The largest consumer of raw water i n all cases is cooling tower makeup. The plants included in this study use a conventional wet cooling tower . Boiler feedwater blowdown and a portion of the sour water stripper blowdown were assumed to be treated and recycled to the cooling tower.

The co oling tower blowdown and the balance of the sour water stripper ( 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.



## 2.7 Cost Estimating Methodology

The estimating methodology for capital costs, operations and maintenance costs, and CO 2 

### TS&M costs are described below. The finance structure, basis for the discounted cash flow analysis, and

first

- year COE cost calculations are also described.

2.7.1 Capital Costs

As illustr ated in Exhibit 2

- 14 , this study reports capital cost at four levels: Bare Erected Cost
( BEC )

, Total Plant Cost ( TPC )

, Total Overnight Cost ( TOC ) and Total As

- spent Capital ( TASC )

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

- year” dollars. The baseCarbon Dioxide Capture Sensitivity Analysis



### 36 year is the first year of capital expenditure, which for this study is assumed to be 2007. TASC is expressed in mixed

- year, cur rent

- year dollars over the entire capital expenditure period, which is assumed to last five years for coal plants (2007 to 201 2 ).

Exhibit 2

- 14 Capital Cost Levels and their Elements



### The BEC comprises t he cost of process equipment, on

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

- year (2007) dollars.

The TPC comprises the BEC plus the cost of services provided by the engineering, procurement and construction (EPC) contractor and project and process contingencies. EPC services include: detailed design, contractor permitting (i.e., those permits that individual contractors must obtain to perform their scopes of work, as opposed to project permitting, which is not included here), and project/construction management c osts. TPC is an overnight cost expressed in base

- year (2007) dollars.

The TOC comprises the TPC plus owner‟s costs. TOC is an “overnight” cost, expressed in base

year (2007) dollars and as such does not include escalation during construction or interest during

construction. TOC is an overnight cost expressed in base

- year (2007) dollars.

The TASC is the sum of all capital expenditures as they are incurred during the capital expenditure period including their escalation. TASC also includes interest during construction.Carbon Dioxide Capture Sensitivity Analysis



### 37 Accordingly, TASC is expressed in mixed, current

- year dollars over the capital expenditure period.

Cost Estimate Basis and Classification

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

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

- furnished and actual cost data from recent design projects.

Recommended Practice 18R

- 97 of the Association for the Advancement of Cost Engineering International (AACE) describes a Cost Estimate Classification System as applied in Engineering, Procurement and Construction for the process industries [ 20 ]

.

Most techno

- economic studies completed by NETL feature cost estimates intended for the purpose of a “Feasibility Study” (AACE Class 4). Exhibit 2

- 15 describes the characteristics of

an AACE Class 4 Cost Estimate. Cost estimates in this stud y have an expected accuracy range

of

- 15%/+30%.

Exhibit 2

- 15 Features of an AACE Class 4 Cost Estimate

Project

Definition Typical Engineering Completed Expected Accuracy

1 to 15% plant capacity, block schematics, indicated layout,

process flow diagrams for main process systems, and preliminary engineered process and utility equipment lists - 15% to

- 30% on the low side,

and

- 20% to +50% on the high

side



## 2.7.2 System Code

- of

- Accounts

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

code

- of

- account structur e 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).



## 2.7.3 CO 2 

## Re moval Plant Maturity

The post

- combustion CO 2 

### remova l technology for the PC capture cases is immature technology. This technology remains unproven at commercial scale in power generation applications.

The pre

- combustion CO 2 

### removal technology for the IG CC capture cases has a stronger commercial experience base. Pre

- combustion CO 2 

### removal from syngas streams has been proven in chemical processes with similar conditions to that in IGCC plants, but has not been demonstrated in IGCC applications. While no commercial IGCC plant yet uses CO 2 

### removalCarbon Dioxide Capture Sensitivity Analysis



### 38 technology in commercial service, there are currently IGCC plants with CO 2 

### capture well along in the planning stages.



## 2.7.4 Contracting Strategy

The estimates are based on an EPCM approach utilizing multiple subcontrac ts. This approach provides the Owner with greater control of the project, while minimizing, if not eliminating most of the risk premiums typically included in an Engineer/Procure/Construct (EPC) contract price.

In a traditional lump sum EPC contract, the Contractor assumes all risk for performance, schedule, and cost. However, as a result of current market conditions, EPC contractors appear

more reluctant to assume that overall level of risk. Rather, the curren t trend appears to be a modified EPC approach where much of the risk remains with the Owner. Where Contractors are willing to accept the risk in EPC type lump

- sum arrangements, it is reflected in the project cost. In today‟s market, Contractor premiums f or accepting these risks, particularly performance risk, can be substantial and increase the overall project costs dramatically.

The EPCM approach used as the basis for the estimates here is anticipated to be the most cost effective approach for the Owne r. While the Owner retains the risks, the risks become reduced with time, as there is better scope definition at the time of contract award(s).



## 2.7.5 Estimate Scope

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

. The plant boundary limit is defined as the total plant facility within the “fence line” including coal receiving and
water supply system, but terminating at the high voltage side of the main power transformers. TS&M cost is not included in the reported capital cos t or O&M costs, but is treated separately

and added to the COE.



## 2.7.6 Capital Cost Assumptions

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

- house database and conceptual estimating models for each of the specific techn ologies. This database and the respective models are maintained by WorleyParsons as part of a commercial power plant design base of experience for similar equipment in the company‟s range of power and process
projects. A reference bottoms

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

Other key estimate considerations include the following:

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

Gulf Coast and the labor has been factored to Midwest. The basis for the factors is the

PAS, Inc. (PAS) “Merit Shop Wage & Benefit Survey,” which is published annually.
Based on the data provided in PAS, WorleyParsons used the weighted average payroll plus fringe rate for a standard craft distri bution as developed for the estimating models.Carbon Dioxide Capture Sensitivity Analysis



### 39 PAS presents information for eight separate regions. For this study, Region 5 (IL, IN,

MI, MN, OH, and WI) was selected

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

cr aft labor available locally.

Labor is based on a 50

- hour work

- week (5

- 10s). No additional incentives such as per

diems 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 consi dered to be Seismic Zone 1, relatively level, and free from hazardous materials, archeological artifacts, or excessive rock. Soil conditions are considered adequate for spread footing foundations. The soil bearing capability is assumed adequate

such that piling is not needed to support the foundation loads.

Costs are limited to within the “fence line,” terminating at the high voltage side of the main power transformers with the exception of costs included for TS&M, which are

treated as an addition to CO E.

Engineering and Construction Management a re estimated a t 8

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

Price Fluctuations

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

- dated the 2007 year cost basis while others were received post

- 2007. All vendor quotes used to develop these estimates were adjusted to June 2007 dollars accounting for the price fluctuations. Adjustments o f costs pre

- dating 2007 benefitted from a vendor survey of actual and projected pricing increases from 2004 through

mid

- 2007 that WorleyParsons conducted for another project. The results of that survey were used to validate/recalibrate the corresponding e scalation factors used in the conceptual estimating models. The more recent economic down turn has resulted in a reduction of commodity prices such that many price indices have similar values in January 2010 compared to June 2007. For example, the Chemic al Engineering Plant Cost Index was 532.7 in June 2007 and 532.9 in January 2010, and the Gross Domestic Product Chain

- type Price Index was 106.7 on July 1, 2007 and 110.0 on January 1, 2010. While these overall indices are nearly constant, it

should be n oted that the cost of individual equipment types may still deviate from the June 2007 reference point.Carbon Dioxide Capture Sensitivity Analysis



### 40 Exclusions

The capital cost estimate includes all anticipated costs for equipment and materials, installation labor, professional services (Engineering and Construction Management), and contingency. The following items are excluded from the capital costs:

All taxes, with the exception of payroll and property taxes (property taxes are included
with the fixed O&M costs)

Site specific considerations

– including, but not limited to, seismic zone, accessibility, local regulatory requirements, excessive rock, piles, laydow n space, etc.

Labor incentives in excess of 5

- 10s

Additional premiums associated with an EPC contracting approach

Contingency

Process and project contingencies are included in estimates to account for unknown costs that are

omitted or unforeseen due to a lack of complete project definition and engineering. Contingencies are added because experience has shown that such costs are likely, and expected, to be incurred even though they cannot be explicitly determined at the time the estimate is prepared.

C apital cost contingencies do not cover uncertainties or risks associated with :

scope changes
changes in labor availability or productivity
delays in equipment deliveries
changes in regulatory requirements
unexpected cost escalation
performance of the plant after startup (e.g., availability, efficiency)

Process Contingency

Process contingency is intended to compensate for uncertainty in cost estimates caused by performance uncertainties associated with the development status of a technology. Process conting encies are applied to each plant section based on its current technology status.

As shown in Exhibit 2

- 16 , AACE International Recommended Practice 16R

- 90 provides guidelines for estimating process contingency based on EPRI philosophy [ 21 ]

.

Process contingencies have been applied to the estimates in this study as follows:

Slurry Prep and Feed

– 5 percent on all IGCC cases

Gasifiers and Syngas Coolers

– 15 percent on all IGCC cases

– next

- generation commercial offering and integration with the power island

Two Stage Selexol

– 20 percent on all IGCC capture cases

- unproven technology at

commercial scale in IGCC serviceCarbon Dioxide Capture Sensitivity Analysis



### 41 Mercury Removal

– 5 percent on all IGCC cases

– minimal commercial scale experience in IGCC applications

CO 2 Removal System

– 20 percent on all PC cases

- post

- combustion process unpro ven
at commercial scale for power plant applications

CTG

– 5 percent on all IGCC non

- capture cases

– syngas firing and ASU integration ; 10

percent on all IGCC capture cases

– high hydrogen firing.

Instrumentation and Controls

– 5 percent on all IGCC acco unts and 5 percent on the PC

cases

– integration issues

Exhibit 2

- 16 AACE Guidelines for Process Contingency

Technology Status Process Contingency

(% of Associated Process Capital)

New concept with limited data 40+

Concept with bench

- scale data 30

- 70

Small pilot plant data 20

- 35

Full

- sized modules have been operated 5

- 20

Process is used commercially 0

- 10



### Process contingency is typically not applied to costs that are set equal to a research goal or programmatic target since these values presume to reflect the total cost.

Project Contingency

AACE 16R

- 90 states that project contingency for a “budget

- type” estimate (AACE Class 4 or 5)

should be 15 to 30 percent of the sum of BEC, EPC fees and process contingency. This was used as a general guideline, but some project contingency values outside of this range occur based on WorleyParsons‟ in

- house experience.

Owner’s Costs

Exhibit 2

- 18 explains the estimation method for owner‟s costs. With some exceptions, the
estimation method follows guidelines in Sections 12.4.7 to 12.4.12 of AACE International

Recommend ed Practice No. 16R

- 90 [ 21 ] . The Electric Power Research Institute‟s “Technical
Assessment Guide (TAG®)

– Power Generation and Storage Technology Options” also h as guidelines for estimating owner‟s costs. The EPRI and AACE guidelines are very similar. In
instances where they differ, this study has sometimes adopted the EPRI approach

.

Interest during construction and escalation during construction are not include d as owner‟s costs
but are factored into the COE and are included in TASC. These costs vary based on the capital expenditure period and the financing scenario. Ratios of TASC/TOC determined from the PSFM

are used to account for escalation and interest du ring construction. Given TOC, TASC can be determined from the ratios given in Exhibit 2

- 17

.Carbon Dioxide Capture Sensitivity Analysis



### 42 Exhibit 2

- 17 TASC/TOC Factors

Finance Structure High Risk IOU Low Risk IOU

Capital Expenditure Period Five Years Five Years

TASC/TOC 1.140 1.134Carbon Dioxide Capture Sensitivity Analysis



### 43 Exhibit 2

- 18 Owner’s Costs Included in TOC



### Owner’s

Cost Estimate Basis

Prepaid Royalties Any technology royalties are assumed to be included in the associated equipment cost, and thus are not

included as an owner’s cost.

Preproduction (Start

- Up)

Costs 6 months operating labor

1 month maintenance materials at full capacity

1 month non

- fuel consumables at full capacity
1 month waste disposal 25% of one month’s fuel cost at full capacity

2% of TPC

Compared to AACE 16R

- 90, this includes additional costs for operating labor (6 months versus 1 month) to cover the cost of training the plant operators, including their participation in startup, and involving them occasionally during the design and construction. AACE 16R

- 90 and EPRI TAG® differ on the amount of fuel
cost to include; this estimate follows EPRI.

Working Capital Although inventory capital (see below) is accounted for, no additional costs are included for working capital.

Inventory Capital 0.5% of TPC for spare parts

60 day supply (at full capacity) of fuel.
60 day supply (at full capacity) of non

- fuel consumables (e.g., chemicals and catalysts) that are stored on site. Does not include catalysts and adsorbents that are ba tch replacements such as WGS, COS, and SCR catalysts and activated carbon.

AACE 16R

- 90 does not include an inventory cost for fuel, but EPRI TAG® does.

Land $3,000/acre (300 acres for IGCC and PC, 100 acres for NGCC)

Financing

Cost 2.7% of TPC

This financing cost (not included by AACE 16R

- 90) covers the cost of securing financing, including fees and closing costs but not including interest during construction (or AFUDC). The ―rule of thumb‖ estimate (2.7% of TPC) is based on a 2008 private communica tion with a capital services firm.Carbon Dioxide Capture Sensitivity Analysis



### 44 Owner’s

Cost Estimate Basis

Other

Owner’s

Costs 15% of TPC

This additional lumped cost is not included by AACE 16R

- 90 or EPRI TAG®. The ―rule of thumb‖ estimate (15% of TPC) is based on a 2009 private communication with WorleyParsons. Significant deviation from this value is possible as it is very site and owner specific. The lumped cost includes:

- Preliminary feasibility studies, including a Front

- End Engineering Design (FEED) study

- Economic development (costs for incentivizing local collaboratio n and support)

- Construction and/or improvement of roads and/or railroad spurs outside of site boundary

- Legal fees

- Permitting costs

- Owner’s engineering (staff paid by owner to give third

- party advice and to help the owner oversee/evaluate

the work of the EPC contractor and other contractors)

- Owner’s contingency (Sometimes called ―management reserve‖, these are funds to cover costs relating to delayed startup, fluctuations in equipment costs, unplanned labor incentives in excess of a five

- day/ten

hour

- per

- day work week. Owner’s contingency is NOT a part of project contingency.)

This lumped cost does NOT include:

- EPC Risk Premiums (Costs estimates are based on an Engineering Procurement Construction Management approach utilizing multip le subcontracts, in which the owner assumes project risks for performance, schedule and cost)

- Transmission interconnection: the cost of interconnecting with power transmission infrastructure beyond the plant busbar.

- Taxes on capital costs: all capital co sts are assumed to be exempt from state and local taxes.

- Unusual site improvements: normal costs associated with improvements to the plant site are included in the bare erected cost, assuming that the site is level and requires no environmental remediatio n. Unusual costs associated with the following design parameters are excluded: flood plain considerations, existing soil/site conditions, water discharges and reuse, rainfall/snowfall criteria, seismic design, buildings/enclosures, fire protection, local code height requirements, noise regulations.Carbon Dioxide Capture Sensitivity Analysis



### 45 2.7.7 Operations and Maintenance Costs

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

life. These costs include:

Operating labor

Maintenance

– material and labor

Administrative and support labor

Consumables

Fuel

Waste di sposal

Co

- p ro duct or b y

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

- products sold)

There are two components of O&M costs; fixed O&M, which is independent of power generation, and variable O&M, which is proportional to power generation.

Operating Labor

Operati ng 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 4.65 / hour . The

associated labor burden is estimated at 30 percent of the base labor rate. Ta xes and insurance are included as fixed O&M costs totaling 2 percent of the TPC.

Maintenance Material and Labor

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

Administrative and Support Labor

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

O&M labor.

Consumables

The co st of consumables, including fuel, was determined on the basis of individual rates of consumption, the unit cost of each specific consumable commodity, and the plant annual operating hours.

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

- specific heat and mass balance diagrams developed for each plant application. Other consumables were evaluated on the basis of the quantity required using reference data.

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

.Carbon Dioxide Capture Sensitivity Analysis



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

Waste Disposal

Waste quantities and disposal costs were determined/evaluated similarly to the consumable s. In this study both slag from the IGCC cases and fly ash and bottom ash from the PC cases are considered a waste with a disposal cost of $17.89/tonne ($16.23/ton). The carbon used for
mercury control in the IGCC cases is considered a hazardous waste wi th disposal cost of $926/tonne ($840/ton).

Co

- Products and By

- Products

By

- product quantities were also determined similarly to the consumables. However, due to the variable marketability of these by

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

for their potential salable value.

It should be noted that by

- product credits and/or disposal costs could potentially be an additional determining factor in the choice of technology for some companies and in selecting some sites. A high local valu e of the product can establish whether or not added capital should be included in the plant costs to produce a particular co

- product. Ash and slag are both potential by

- products in certain markets, and in the absence of activated carbon injection in the P C cases, the fly ash would remain uncontaminated and have potential marketability. However, as stated above, the ash and slag are considered wastes in this study with a concomitant disposal cost.

2.7.8 CO 2 

### Transport, Storage and Monitoring

T he capital and opera ting costs for CO 2 

### TS&M were independently estimated by NETL. Those

costs were converted to a TS&M COE increment that was added to the plant COE.

CO 2 

### TS&M was modeled based on the following assumptions:

CO 2 

### is supplied to the pipeline at the plant fence l ine at a pressure of 15.3 MPa (2,215 psia). The CO 2 

### product gas composition varies in the cases presented, but is expected to meet the specification described in Exhibit 2

- 19 [ 22 ]. A glycol dryer located near the

mid

- point of the compression train is used to meet the moisture specification.Carbon Dioxide Capture Sensitivity Analysis



### 47 Exhibit 2

- 19 CO 2 Pipeline Specification

Parameter Units Parameter Value

Inlet Pressure MPa (psia) 15.3 (2,215)

Outlet Pressure MPa (psia) 10.4 (1,515)

Inlet Temperature °C (°F) 35 (95)

N 2 Concentration ppmv < 300

O 2 Concentration ppmv < 40

Ar Concentration ppmv < 10

H 2 O Concentration ppmv < 150



### The CO 2 

### is transported 80 km (50 miles) via pipeline to a geologic sequestration field for injection into a saline formation.

The CO 2 

### is transported and injected as a SC fluid in order to avoid two

- phase flow and achieve maximum efficiency [ 23 ]

. The pipeline is a ssumed to have an outlet pressure
(above the SC pressure) of 8

. 3 MPa (1, 200 psia) with no recompression along the way. Accordingly, CO 2 

### flow in the pipeline was modeled to determine the pipe diameter that results in a pressure drop of 6

. 9 MPa ( 1,0 00 psi) over an 80 km (50 mile) pipeline length

[ 24 ]

. (Although not explored in this study, the use of boost compressors and a smaller pipeline diameter could possibly reduce capital costs for sufficiently long pipelines.) The diameter of the injection pi pe will be of sufficient size that frictional losses during injection are minimal and no booster compression is required at the well

- head in order to achieve an appropriate down

- hole pressure , with hydrostatic head making up the difference between the inje ction and reservoir pressure.

The saline formation is at a depth of 1,23 6 m (4,055 ft) and has a permeability of 22 millidarcy (md) (22 μm 2 

### ) and formation pressure of 8.4 MPa (1,220 psig) [ 22 ]

. This is considered an average storage site and requires roughly one injection well for each 9,360
tonnes (10,320 short tons) of CO 2 

### injected per day [ 22 ]

. The assumed aquifer

characteristics are tabulated in Exhibit 2

- 20

.

The cost metrics utilized in this study provide a best estimate of TS&M costs for a “ favorable ” sequestration project, and may vary significantly based on variables such as terrain to be crossed by the pipeline, reservoir characteristics, and number of land owners from whi ch sub

- surface rights must be acquired. Raw capital and operating costs are derived from detailed cost metrics

found in the literature, escalated to June 2007

- year dollars using appropriate price indices. These costs were then verified against values quo ted by industrial sources where possible. Where regulatory uncertainty exists or costs are undefined, such as liability costs and the acquisition of underground pore volume, analogous existing policies were used for representative cost

scenarios.Carbon Dioxide Capture Sensitivity Analysis



### 48 Exhibit 2

- 20 Deep, Saline Aquifer Specification

Parameter Units Base Case

Pressure MPa (psi) 8.4 (1,220)

Thickness m (ft) 161 (530)

Depth m (ft) 1,236 (4,055)

Permeability Md 22

Pipeline Distance km (miles) 80 (50)

Injection Rate per Well tonne (ton) CO 2 /day 9,360 (10,320)



### The following sections describe the sources and methodology used for each metric.

TS&M Captial Costs

TS&M capital costs include both a 20 percent process contingency and 30 percent project contingency.

In several areas, such as Pore Volume Acquisition, Monitoring, and Liability, cost outlays occur over a longer time period, up to 100 years. In these cases a capital fund is established based on the net present value of the cost outlay, and this fund is then levelized similar to the other costs.

Transport Costs

CO 2 

### transport costs are broken down into three categories: pipeline costs, related capital expenditures, and O&M costs.

Pipeline costs are derived from data published in the Oil and G as Journal‟s (O&GJ) annual
Pipeline Economics Report for existing natural gas, oil, and petroleum pipeline project costs from 1991 to 2003. These costs are expected to be analogous to the cost of building a CO 2 

### pipeline, as noted in various studies [ 2 2

, 23

, 25 ]

. The University of California performed a regression analysis to generate cost curves from the O&GJ data: (1) Pipeline Materials, (2) Direct Labor, (3) Indirect Costs, and (4) Right

- of

- w ay acquisition, with each represented as a function of pipeli ne length and diameter [ 25 ] . These cost curves were escalated to the June 2007 year dollars used in t his study.

Related capital expenditures were based on the findings of a previous study funded by DOE/NETL, Carbon Dioxide Sequestration in Saline Formations

– Engi neering and Economic

Assessment [ 22 ]

. This study utilized a similar basis for pipeline costs ( O&GJ Pipeline cost data up to the year 2000) but added a CO 2 

### surge tank and pipeline control system to the project.

Transport O&M costs were assessed using metrics published in a second DOE/NETL sponsored report entitled Economic Evaluation of CO 2 

### Stora ge and Sink Enhancement Options [ 23 ]. ThisCarbon Dioxide Capture Sensitivity Analysis



### 49 study was chosen due to the reporting of O&M costs in terms of pipeline length, whereas the other studies mentioned above either (a) do not report operating costs, or (b) report them in absolute terms for one pipeline, as opposed to as a length

- or di ameter

- based metric.

Storage Costs

Storage costs were divided into five categories: (1) Site Screening and Evaluation, (2) Injection Wells, (3) Injection Equipment, (4) O& M Costs, and (5) Pore Volume Acquisition. With the exception of Pore Volume Acquisition, all of the costs were obtained from Economic Evaluation

of CO 2 

### Storage and Sink Enhancement Options [ 23 ]

. These costs include all of the costs associated with determining, developing, and maintaining a CO 2 

### storage location, including site evaluation, well drilling, and the capital equipment required for distributing and inject ing CO 2



### .

Pore Volume Acquisition costs are the costs associated with acquiring rights to use the sub

surface volume where the CO 2 

### will be stored, i.e., the pore space in the geologic formation. These costs were based on recent research by Carnegie Mellon University

, which examined existing sub

- surface rights acquisition as it pertains to natural gas storage [ 26 ]

. The regulatory uncertainty in this area combined with unknowns regarding the number and type (private or government) of property owners, require a number of “best engineering judgment” decisions to

be made

. In this study it was assumed that long

- term lease rights were acquired from the property owners in the projected CO 2 

### plume growth region for a nominal fee, and that an annual “rent” was paid w hen the plume reached each individual acre of their property for a period of up to 100 years from the injection start date

. The present value of the life cycle pore volume costs

are assessed at a 10 percent discount rate and a capital fund is set up to pa y for these costs over

the 100 y ear rent scenario.

Liability Protection

Liability Protection addresses the fact that if damages are caused by injection and long

- term storage of CO 2 

### , the injecting party may bear financial liability. Several types of liabil ity protection schem e s have been suggested for CO 2 

### storage, including Bonding, Insurance, and Federal Compensation Systems combined with either tort law (as with the Trans

- Alaska Pipeline Fund), or with damage caps and preemption, as is used for nuclear energy under the Price

Anderson Act [ 27 ]

. However, a t present, a specific liability regime has yet to be dictated either at a Federal or (to our knowledge) State level. However, certain state governments have enacted legislation

, which assigns liability to the injecting party, either in perpetuity (Wyoming ) or until ten years after the cessation of injection operations, pending reservoir integrity certification, at which time liability is turned over to the state (North Dakota and Louisiana) [ 28

, 29

, 30 ]

. In the

case of Louisiana, a trust fund totaling five mil lion dollars is established over the first ten years (120 months) of injection operations for each injector . This fund is then used by the state for

CO 2 

### monitoring and, in the event of an at

- fault incident, damage payments.

Liability costs assume that a bond must be purchased before injection operations are permitted in order to establish the ability and good will of an injector to address damages where they are deemed liable. A figure of five million dollars was used for the bond based on the Louisiana

fund level. This b ond level may be conservative ly high , in that the Louisiana fund covers both liability and monitoring, but that fund also pertains to a certified reservoir where injectionCarbon Dioxide Capture Sensitivity Analysis



### 50 operations have ceased, having a reduced risk compared to active operations. The b ond cost was

not escalated.

Monitoring Costs

Monitoring costs were evaluated based on the methodology set forth in the International Energy
Agency ( IEA ) Greenhouse Gas (GHG) R&D Programme‟s Overview of Monitoring Projects for
Geologic Sto rage Projects report [ 31 ]

. In this scenario, operational monitoring of the CO 2 

### plume

occurs over 30 years (during plant operation) and closure monitoring occurs for the following fifty years (for a total of eighty years). Monitoring is via electromagnetic (EM) survey, gravity survey, and periodic seismic survey ; EM and gravity surveys are ongoing while seismic survey occurs in years 1, 2, 5, 10, 15, 20, 25, and 30 during the operational period, then in years 40, 50, 60, 70, and 80 after injection ceases.

2.7.9 F inance Structure, Discounted Cash Flow Analysis, and COE

The global economic assumptions are listed in Exhibit 2

- 21

.

Finance structures were chosen based on the assumed type of developer/owner (investor

- owned utility (IOU) or independent power producer) and the assumed risk profile of the plant being

ass essed . For this study the owner/developer was assumed to be an IOU

. Cases were considered

either high risk

, with the inclusion of CO 2 

### capture , or low risk

, without CO 2 

### capture

. Exhibit 2

- 22 describes the high

- risk and low

- risk IOU finance structures that w ere assumed for

t his study . Th ese finance structure s w ere recommended in a 2008 NETL report based on interviews with project developers/owners, financial organizations and law firms [ 32 ]

.Carbon Dioxide Capture Sensitivity Analysis



### 51 Exhibit 2

- 21 Global Economic Assumptions

Parameter Value

TAXES

Income Tax Rate 38% (Effective 34% Federal, 6% State)

Capital Depreciation 20 years, 150% declining balance

Investment Tax Credit 0%

Tax Holiday 0 years

CONTRACTING AND FINANCING TERMS

Contracting Strategy Engineering Procurement Construction Management ( owner assumes project risks for performance, schedule and cost)

Type of Debt Financing Non

- Recourse (collateral that secures debt is limited to the real assets of the project)

Repayment Term of Debt 15 years

Grace Period on Debt Repayment 0 years

Debt Reserve Fund None

ANALYSIS TIME PERIODS

Capital Expenditure Period 5 Years

Operational Period 30 years

Economic Analysis Period (used for IRROE) 35 Years (capital expenditure period plus operational period)

TREATMENT OF CAPITAL COSTS

Capital Cost Escalation During Capital Expenditure Period (nominal annual rate) 3.6% 1

Distribution of Total Overnight Capital over the Capital Expenditure Period (before escalation) 5

- Year Period: 10%, 30%, 25%, 20%, 15%

Working Capital zero for all parameters

% of Total Overnight Capital that is Depreciated 100% (this assumption introduces a very small

error even if a substantial amount of TOC is actually non

- depreciable)

ESCALATION OF OPERATING REVENUES AND COSTS

Escalation of COE (revenue), O&M Costs, and Fuel Costs (nominal annual rate) 3.0% 2

1 A nominal average annual rate of 3.6 percent is assumed for escalation of capital costs during construction. This
rate is equivalent to the nominal average annual escalation rate for process plant construction costs between 1947
and 2008 according to the Chemical Engineering Plant Cost Index.

2 An average annual inflation rate of 3.0 percent is assumed. This rate is equivalent to the average annual escalation
rate between 1947 and 2008 for the U.S. Department of Labor's Producer Price Index for Finished Goods, the so

called "headline" index of the various Producer Price Indices. (The Producer Price Index for the Electric Power Generation Industry may be more applicable, but that data does not provide a long

- term historical perspective since
it only dates back to December 2003.)Carbon Dioxide Capture Sensitivity Analysis



### 52 Exhibit 2

- 22 Financial Structure for Investor Owned Utility High Risk Projects

Type of Security % of Total Current (Nominal) Dollar

Cost Weighted

Current (Nominal) Cost After Tax

Weighted Cost of Capital

Low Risk

Debt 50 4.5% 2.25%

Equity 50 12% 6%

Total 8.25% 7.39%

High Risk

Debt 45 5.5% 2.475%

Equity 55 12% 6.6%

Total 9.075% 8.13%



### DCF Analysis and Cost of Electricity

The NETL Power Systems Financial Model (PSFM)

, a nominal

- dollar 3 

### (current dollar)
discounted cash flow (DCF) analysis tool

, was used to calculate COE 4



### . The COE is the revenue received by the generator per net megawatt

- hour during the power plant‟s first year of operation,
assuming that the COE escalates thereafter at a nominal annual rate equal to the general
inflation rate, i.e., that it remains constant in real terms over the operational period of the power
plant . To calculate the COE, the PSFM was used to determine a “base

- year” (2007) COE that,

when escalated at a n assumed nominal annual general inflation rate of 3 percent 5 

### , provided the
stipulated internal rate of return on equity over the entire economic analysis period (capital expenditure period plus thirty years of operation). Since this analysis assumes that COE

3 Since the analysis takes into account taxes and depreciation, a nominal dollar basis is preferred to properly reflect
the interplay between depreciation and inflation.

4 For this calculation, “cost of electricity” is somewhat of a misnomer because from the power plant‟s per spective it is actually the “price” received for the electricity generated to achieve the stated IRROE . However, since the price paid for generation is ultimately charged to the end user, from the customer‟s perspective it is part of the cost of

electrici ty.

5 This nominal escalation rate is equal to the average annual inflation rate between 1947 and 2008 for the U.S. Department of Labor‟s Producer Price Index for Finished Goods. This index was used instead of the Producer Price

Index for the Electric Powe r Generation Industry because the Electric Power Index only dates back to December

2003 and the Producer Price Index is considered the “headline” index for all of the various Producer Price Indices.Carbon Dioxide Capture Sensitivity Analysis



### 53 increases over the economic analysis period at the nominal annual general inflation rate, it

remains constant in real terms and the first

- year COE is equivalent to the base

- year COE when expressed in base

- year (2007) dollars. Since 2007 is the first year of the capital expenditure period, it is also the base year for the economic analysis. Accordingly, it is convenient to report the results of the economic analysis in base

- year (June 2007) dollars

.

Estimating COE with Capital Charge Factors

For scenarios that adhere to the global economic assumptions listed in Exhibit 2

- 21 and utilize

the finance structure listed in Exhibit 2

- 22 , the following simplified equation can be used to

estimate COE as a function of TOC 6 

### , fixed O&M, variable O&M (including fuel), capacity factor and net output. The equation requires the application of the capital charge factor s (CCF)

listed in Exhibit 2

- 23 . Th ese CCFs are valid only for the global economic assumptions listed in

Exhibit 2

- 21 , the stated finance structure, and the stated capital expenditure period.

Exhibit 2

- 23 Capital Charge Factors for COE Equation

Finance

Structure High Risk IOU Low Risk IOU

Capital Expenditure Period Five Years Five Years

Capital Charge Factor (CCF) 0.124 0.116



### All factors in the COE equation are expressed in base

- year dollars. The base year is the first year of capital expenditure, which for this study is assumed to be 2007. As shown in Exhibit 2

- 21 , all factors (COE, O&M and fuel) are assumed to escalate at a nominal annual general inflation rate

of 3.0 percent . Accordingly, all first

- year costs (COE and O&M) are equivalent to base

- year costs when expressed in base

- year (2007) dollars.

6 Although TOC is used in the simplified COE equation, th e CCF that multiplies it accounts for escalation during
construction and interest during construction (along with other factors related to the recovery of capital costs).Carbon Dioxide Capture Sensitivity Analysis



### 54 w here:

COE = revenue received by the generator ($/MWh, equivalent to mills/kWh)

during the power plant‟s first year of operation ( but expressed in base

year dollars ), assuming that the COE escalates thereafter at a nominal annual rate equal to the general inflation rate, i.e., that it remains constant in real terms over the operational period of the power plant.

CCF = capital charge factor taken from Exhibit 2

- 23 that matches the applicable

finance structure and capital expenditure period

TOC = total overnight capital, expressed in base

- year dollar s

OC FIX 

### = the sum of all fixed annual operating costs, expressed in base

- year dollars

OC VAR 

### = the sum of all variable annual operating costs, including fuel at 100

percent capacity factor, expressed in base

- year dollars

CF = plant capacity factor, assumed to be constant over the operational period

MWH = annual net megawatt

- hours of power generated at 100 percent capacity

factor

2.8 IGCC STUDY COST ESTI MATES COMPARED TO IN DUSTRY ESTIMATES

The estimated TOC for IGCC cases in this study ranges from $2, 447 for IGCC with 0% capture
to $ 3,501 /kW for IGCC with 97% capture . Plant size ranges from 523

- 622 MW (net) for 0% and 97% capture plants, respectively

.

Within the power industry there are several power producers interested in pursuing construction

of an IGCC plant. While these projects are still in the relatively early stages of development, some cost estimates have been published. Published estimates tend to be limited in detail, leaving it to the reader to speculate as to what is contained within the estimate. In November 2007, the Indiana Utility Regulatory Commission approved Duke Energy‟s proposal to build an
IGCC plant in Edwardsport, Indiana. The estimated cost to build the 630 MW plant is $4,472/kW in June 2007 dollars. Duke expects the pl ant to begin operation in 2012. Other published estimates for similar proposed non

- CO 2 

### capture gasification plants range fromCarbon Dioxide Capture Sensitivity Analysis



### 55 $2,483/kW to $3,122/kW in June 2007 dollars. Corresponding plant sizes range form 770

- 600

MW

, respectively. Published estimat es from similar CO 2 

### capture facilities range from $4,581/kW to $5,408/kW, in June 2007 dollars, with sizes ranging from 400 to 580 MW

[ 33

, 34

, 35

, 36 ]. 7



### Differences in Cost Estimates

Project Scope

For this report, the scope of work is generally limited to work inside the project “fence line”. For
outgoing power, the scope stops at the high side terminals of the Generator Step

- up Transformers
(GSUs).

Some typical examples of items outside the fenc eline include:

New access roads and railroad tracks
Upgrades to existing roads to accommodate increased traffic
Makeup water pipe outside the fenceline

Landfill for on

- site waste (slag) disposal
Natural gas line for backup fuel provisions
Plant switchyard

Electrical transmission lines & substation

Estimates in this report are based on a generic mid

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

Piles or caissons

Rock removal

Excessive dewat ering
Expansive soil considerations

Excessive seismic considerations
Extreme temperature considerations

Hazardous or contaminated soils
Demolition or relocation of existing structures
Leasing of offsite land for parking or laydown
Busing of craft to site
Costs of offsite storage

This report is based on a reasonably “standard” plant. No unusual or extraordinary process
equipment is included such as:

Excessive water treatment equipment

Air

- cooled condenser

7 Costs were adjusted to June 2007 using the Chemical Engineering Plant Cost IndexCarbon Dioxide Capture Sensitivity Analysis



### 56 Automated coal reclaim
Zero Liquid Discharge equipm ent SCR catalyst (IGCC cases only)

For non

- capture cases, which are likely the most appropriate comparison against industry published estimates, this report is based on plant equipment sized for non

- capture only. None of the equipment is sized to accommod ate a future conversion to CO 2 

### capture.

Labor

This report is based on Merit Shop (non

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

This repo rt is based on a 50 hour work week, with an adequate local supply of skilled craft labor. No additional incentives such as per

- diems or bonuses have been included to attract and retain

skilled craft labor.

Contracting Methodology

The estimates in this rep ort are based on a competitively bid, multiple subcontract approach, often referred to as EPCM. Accordingly, the estimates do not include premiums associated with an EPC approach. It is believed that, given current market conditions, the premium charged by an EPC contractor could be as much as 30 percent or more over an EPCM approach.Carbon Dioxide Capture Sensitivity Analysis



### 57 

# 3. Case 1

- Supercritical PC with Variable CO 2 

# Capture

3.1 System Descriptions

The SC PC system descriptions are provided in the subsections below.



## 3.1.1 Coal and Sorbent Receiving and Storage

The function of the coal portion of the Coal and Sorbent Receiving and Storage system is to provide the equipment required for unloading, conveying, preparing, and storing the fuel delivered to the plant. The scope of the system is from the coal conveyor receiving hoppers up to the coal storage silos. The system is designed to support short

- term operation at maximum

power output at the 5 percent over pressure/valves wide open (OP/VWO) condition (16 hours) and long

- term operation of 90 days or more at the maximum continuous rating (MCR).

The scope of the sorbent receiving and storage systems includes truck roadways, turnarounds, unloading hoppers, conveyors, and the day storage bin.

Operation Description

– T he 3" x 0 bituminous Illinois No. 6 coal is delivered to the site by

unit trains of 100

- ton rail cars. Each unit train consists of 100, 100

- ton rail cars. The unloading is done by a trestle bottom dumper, which unloads the coal to two receiving hoppers. Coal from each hopper is fed directly into a vibratory feeder. The 3" x 0 coal from the feeder is discharged onto a belt conveyor (No. 1). The coal is then transferred to a conveyor (No. 2) that transfers the coal to the reclaim area. The conveyor pass es under a magnetic plate separator to remove tramp iron, and then to the reclaim pile.

Coal from the reclaim pile is fed by two vibratory feeders, located under the pile, onto a belt conveyor (No. 3), which transfers the coal to the coal surge bin locat ed in the crusher tower. The coal is reduced in size to 11⁄4" x 0 by the coal crusher. The coal is then transferred by conveyor (No. 4) to the transfer tower. In the transfer tower the coal is routed to the tripper that loads the coal into one of the para llel boiler silos.

L ime is delivered to the site using 23 tonne (25 ton) trucks and conveyed to storage. Lime is stored in a bulk storage lime silo. The lime is pneumatically conveyed to a day bin.



## 3.1.2 Steam Generator and Ancillaries

The steam ge nerator for the supercritical plant is a once

- through, spiral

- wound, Benson

- boiler,

wall

- fired, balanced draft type unit with a water

- cooled dry bottom furnace. It includes a superheater, reheater, economizer, and air heater.

It is assumed for the purposes of this s tudy that the power plant is designed to be operated as a

base

- loaded unit but with some consideration for daily or weekly cycling, as can be cost effectively included in the base design.Carbon Dioxide Capture Sensitivity Analysis



### 58 The combustion systems for superc ritical steam conditions are equipp ed with low

- NO

x 

### burners
( LNBs ) and overfire air ( OFA )

.

3.1.2.1 Scope and General Arrangement

The steam generator comprises the following:

Once

- through type steam

generator Low NOx Coal burners and light oil igniters / warmup

system Startup circuit, including integral separators

Water

- cooled furnace, dry

bottom Soot blower system Primary air (PA) fans

Two

- stage superheater Air preheaters (Ljungstrom
type) Induced draft (ID) fans

Reheater Coal feeders and pulverizers Forced draft (FD) fans

Economizer Spray type desuperheater Overfire air system

The steam generator operates as follows:

3.1.2.2 Feedwater and Steam

Feedwater enters the botto m header of the economizer and passes upward through the

economizer tube bank , through stringer tubes that support the primary superheater, and discharges to the economizer outlet headers. From the outlet headers, water flows to the furnace hopper inlet headers via external downcomers. Water then flows upward through the furnace hopper and furnace wall tubes. From the furnace, water flows to the steam water separator. During low load operation (operation below the critical point), the water from the separator is returned to the economizer inlet with the boiler recirculating pump . Operation at loads above the

critical 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. Fr om the platens, the steam flows through the second stage of attemperation and then to the intermediate superheater. The steam then flows to the final superheater and on to the outlet pipe terminal. Two stages of spray attemperation are used to provide ti ght temperature control in all high temperature sections during rapid load changes.

Steam returning from the turbine passes through the primary reheater surface, then through crossover piping containing inter

- stage attemperation. The crossover piping feed s the steam to

the final reheater banks and then out to the turbine. Inter

- stage attemperation is used to provide outlet temperature control during load changes.

3.1.2.3 Air and Combustion Products

Combustion air from the FD fans is heated in Ljungstrom type air preheaters, recovering heat energy from the exhaust gases exiting the boiler. This air is distributed to the burner windbox asCarbon Dioxide Capture Sensitivity Analysis



### 59 secondary air. Air for conveying pulverized coal to the burners is supplied by the PA fans. This air is heated in the Ljungstr om type air preheaters to permit drying of the pulverized coal, and a portion of the air from the PA fans bypasses the air preheaters to be used for regulating the outlet coal/air temperature leaving the mills.

The pulverized coal and air mixture flows t o 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 s team generator at this point and flow to the Selective Catalytic Reduction (SCR) reactor, FGD system, fabric filter, ID fan, and stack.

3.1.2.4 Fuel Feed

The crushed coal is fed through feeders to each of the mills (pulverizers), where its size is reduced to appro ximately 72 percent passing 200 mesh with less than 0.5 percent remaining on

50 mesh [ 37 ]

. The pulverized coal exits each mill via the coal piping and is distributed to the coal nozzles in the furnace walls using air supplied by the PA fans.

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 trough around the upper periphery for cooling and sealing. Water and ash discharged from the hopper pass through the clinker grinder to an ash sluice system for conveyance to hydrobins, where the ash is dewatered before it is transferred to trucks for offsite disposal. The bottom ash from the boiler is fed into a clinker grinder. The clinker grinder is provided to break up any clinkers that may form. From the clinker grinders the bottom ash is sluiced to hydrobins for dewatering and offsite removal by truck. The steam generator incorporates fly as h hoppers under the economizer outlet and air 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

- NO

x 

### configuration, with staging of the coal

combus tion to minimize NO

x 

### formation. In addition, overfire air nozzles are provided to further stage combustion and thereby minimize NO

x 

### formation.

Oil

- fired pilot torches are provided for each coal burner for ignition, warm

- up and flame

stabilization at start up and low loads.

3.1.2.7 Soot Blowers

The soot

- blowing system utilizes an array of 50 to 150 retractable nozzles and lances that clean the furnace walls and convection surfaces with jets of high

- pressure steam. The blowers are sequenced to provide an effective c leaning cycle depending on the coal quality and design of the furnace and convection surfaces. Electric motors drive the soot blowers through their cycles.Carbon Dioxide Capture Sensitivity Analysis



### 60 

## 3.1.3 NO

x 

## Control System

The plant is designed to achieve the environmental target of 0.07 lb NOx/MMBtu. Two

measures are taken to reduce the NO

x 

### . The first is a combination of low

- NOx burners and the introduction of staged overfire air in the boiler. The low

- NO

x 

### burners and overfire air reduce the

emissions to about 0.2 lb/MMBtu.

The second measure tak en to reduce the NOx emissions is the installation of a SCR system prior to the air heater. SCR uses aqueous ammonia and a catalyst to reduce NO

x 

### to N 2 

### and H 2 

### O. The SCR system consists of three subsystems: reactor vessel, ammonia storage and injection, and gas flow control. The SCR system is designed for 65 percent reduction with 2 ppmv ammonia slip at the end of the catalyst life. This, along with the low

- NO

x 

### burners, achieves the emission

limit of 0.07 lb/MMBtu.

The SCR capital costs are included wit h the boiler costs, as is the cost for the initial load of catalyst.

Selective non

- catalytic reduction (SNCR) was considered for this application. However, with

the installation of the low

- NO

x 

### burners and overfire air system, the boiler exhaust gas contai ns relatively small amounts of NO

x 

### , which makes removal of the quantity of NO

x 

### with SNCR to

reach the emissions limit of 0.07 lb/MMBtu difficult. SNCR works better in applications that contain medium to high quantities of NO

x 

### and require removal efficienc ies in the range of 40 to

60 percent. SCR, because of the catalyst used in the reaction, can achieve higher efficiencies

with lower concentrations of NO

x 

### .

Operation Description

– The reactor vessel is designed to allow proper retention time for the

ammoni a to contact the NOx 

### in the boiler exhaust gas. Ammonia is injected into the gas immediately prior to entering the reactor vessel. The catalyst contained in the reactor vessel

enhances the reaction between the ammonia and the NO

x 

### in the gas. Catalysts c onsist 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 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 included with the

reactor vessel is soot

- blowing equipment used for cleaning the catalyst.

The aqueous ammonia storage and inject ion system consists of the unloading facilities, bulk storage tank, vaporizers, dilution air skid, and injection grid.

The flue gas flow control consists of ductwork, dampers, and flow straightening devices required

to route the boiler exhaust to the SCR r eactor and then to the air heater. The economizer bypass and associated dampers for low load temperature control are also included.



## 3.1.4 Particulate Control

A pulse

- jet baghouse with air to cloth ratio of 3.5 ft/min is located after the air heater . The bagho use is provided with a spare compartment for off line cleaning to maintain the opacity at 10Carbon Dioxide Capture Sensitivity Analysis



### 61 percent or less. The waste will be pneumatically conveyed to a waste storage silo with a 3

- day storage capacity, which is in accordance with typical utility desig n.

Operation Description

– The bag house is designed to achieve 99.8 percent removal efficiency and consists of two separate single

- stage, in

- line, and 10

- compartment units. Each unit is a high

air

- to

- cloth ratio design with a pulse

- jet on

- line cleaning system. The ash is collected on the outside of the 8 meter long bags, which are supported by steel cages. The dust cake is removed by a pulse of compressed air. The bag material is polyphenylensulfide (PPS) with an intrinsic Teflon (PTFE) coating [ 38 ]. 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 nozzle s, expansion joints, and other items as required. T he fabric filter reduces particulate loading in the stack gas to below the required levels.



## 3.1.5 Flue Gas Desulfurization

3.1.5.1 Wet FGD Process

The limestone

- based, forced oxidation flue gas scrubbing system is de signed to remove 98

percent of the SO 2 

### from the flue gas. The design incorporates features which have been developed over many years of commercial operation and pilot work in utility flue gas cleaning.

Listed below are the major items that comprise the we t FGD portion of the tower systems.

1. Limestone silos with weigh feeders, capable of supplying the required limestone to the slurry handling systems

2. Limestone preparation systems

3. Absorber

4. Cyclone separators, with spares sufficient to meet the requirements of the FGD absorber systems for gypsum slurry primary dewatering

5. Oxidation air compressors

6. Vacuum filter system

Exhibit 3

- 1 sh ows a typical wet FGD process flow diagram.Carbon Dioxide Capture Sensitivity Analysis



### 62 Exhibit 3

- 1 Typical B&W Wet FGD Process Flow Diagram

Source: B&W FigureCarbon Dioxide Capture Sensitivity Analysis



### 63 3.1.5.2 Absorber Tower

Exhibit 3

- 2 shows a typical wet scr ubber absorber tower arrangement . The absorber tower includes two gas distribution devices (trays), two spray headers of countercurrent absorber

sprays, an d a two

- stage mist eliminator section. As the flue gas enters the absorber, it turns upward and is evenly distributed across the absorber cross

- section by the absorber tray. Experience has shown that such a gas distribution device is needed to optimize S O 2 

### removal. This experience parallels that of the electrostatic precipitator industry and their need for carefully designed gas distribution plates. In addition to providing an even gas flow for the main spray zone, the absorber tray also provides an are a of intimate contact between the flue gas and

limestone slurry

.

The gas leaving the absorber tray passes through several countercurrent spray levels, which are supplied with recirculating slurry from the absorber's reaction tank, and continues through two layers of Chevron type mist eliminators for water droplet removal before exiting the absorber tower through the outlet cone and outlet flue.

The in

- situ o xidation system provides oxygen to the absorber reaction tank via an ambient air

stream . This oxygen system forces calcium sulfite (CaSO 3 

### ·1⁄2H 2 

### O ) formed by the SO 2 

### removal process to be oxidized to calcium sulfate (CaSO 4 

### ·2H 2 

### O).

Absorber recirculation pumps mounted on modularized base plates provide assemblies for easy

installation. The assemblies can be bolted directly to concrete foundations. Four recirculation pumps are supplied. Three are required for operation at the normal operation design point.

Exhibit 3

- 2 Wet Scrubber Arrangement

Source: B& W FigureCarbon Dioxide Capture Sensitivity Analysis



### 64 3.1.5.3 Limestone Preparation System

The function of the limestone handling and reagent preparation system is to receive, store, convey, and grind the limestone delivered to the plant. The scope of the system is from the storage pile up to the limestone feed system. The system is designed to support continuous baseload operation. Truck roadways, turnarounds, and unloading hoppers are included in this reference plant design.

For the purposes of this conceptual design, limestone is assumed to be delivere d to the plant by

25

- ton trucks. The limestone is unloaded onto a storage pile located above vibrating feeders. The limestone is fed onto belt conveyors via vibrating feeders and then to day bins equipped with vent filters. Each day bin supplies a 100 p ercent capacity size 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 l imestone slurry is then discharged into a mill slurry tank. Mill recycle pumps, two per tank, pump the limestone water slurry to an assembly of hydrocyclones and distribution boxes. The slurry is classified into several streams, based on suspended solids content and size

distribution.

The hydrocyclone underflow with oversized limestone is directed back to the mill for further grinding. The hydrocyclone overflow with correctly sized limestone is routed to a reagent storage tank. Reagent distribution pump s direct slurry from the tank to the absorber module.

3.1.5.4 Gypsum Dewatering

Gypsum slurry is bled from the absorber by absorber blowdown pumps that feed a primary cyclone separator which concentrates the solids of the gypsum slurry stream. Hydrocyclone

overfl ow is gravity fed to the back to the absorber. Hydrocyclone underflow is gravity fed to the vacuum filters. Each hydrocyclone is supplied with a valve network which can isolate flow to individual hydrocyclones. To reduce the suspended solids in the syst em, a small volume of the hydrocyclone overflow is pumped by two purge pumps (1 operating, 1 spare) to the wastewater

treatment system.

Cyclone separator underflow gravity flows to the belt vacuum filters for further dewatering. The gypsum is dewatered to 90 percent solids and washed to produce wallboard quality gypsum, which drops from the belt vacuum filters onto a conveying system. The vacuum receiver filtrate pumps pump the filtrate from the belt vacuum filters to the filtrate water tank. The filtr ate water is recycled back to the FGD system by means of the filtrate water pumps.

One filtrate water tank is provided with minimum storage capacity of 4 hours of water usage by the absorber at full load normal operation. One wash tank for combined use of the mist eliminator wash system with a minimum storage capacity of 15 minutes is provided.

3.1.5.5 Mercury Removal

Removal of 90 percent of the mercury entering with the coal is achieved in a combination of equipment and processes. Since the Illinois No. 6 coal is relatively high in chlorine, most of the mercury entering with the coal will leave the boiler in an oxidized form (85

- 90 percent ). TheCarbon Dioxide Capture Sensitivity Analysis



### 65 SCR system will further promote the oxidation of Hg. Some additional oxidation will occur in

the airheater, and a sm all portion of the mercury (oxidized and elemental) will be captured with unburned carbon in the baghouse. The majority of the oxidized mercury will be captured in the wet scrubber. An inexpensive additive is injected into the wet scrubber to enhance mer cury removal and inhibit any re

- emission to achieve the 90 percent removal rate.



## 3.1.6 Flue Gas System/Stack

The flue gas from the air preheater will be sent to the absorbers. The gases enter the baghouse to collect the waste products and the fly ash. Flue gas exits the baghouse and enters the Induced
Draft (ID) fan suction.



## 3.1.7 Carbon Dioxide Recovery Facility

The CO 2 

### recovery fac ility consists of the Fluor Econamine FG Plus SM 

### system foll owed by compression and drying

.

3.1.7.1 Econamine FG Plus SM



### A Carbon Dioxide Recove ry (CDR) facility is used to remove 30 to 99 percent of the CO 2 

### in the flue gas exiting the FGD unit, purify it, and compress to a supercritical condition. The CDR is comprised of the flue gas supply, SO 2 

### polishing, CO 2 

### absorption, solvent stripping and

r eclaiming, and CO 2 

### compression and drying.

The CO 2 

### absorption/stripping/solvents recl aim process is based on the Fluor Econamine FG

Plus SM 

### technology [ 39 ]. A typical flow sheet is shown in Exhibit 3

- 3 . The Econamine FG

Plus SM 

### process uses a formulation of monethanolamine (MEA ) and a proprietary corrosion

inhibitor to recover CO 2 

### from the flue gas. This process is designed to recover high

- purity CO 2 

### from low

- pressure streams that contain oxygen, such as flue gas from coal

- fired power plants, gas turbine exh aust gas, and other waste gases.

SO 2 

### Polishing and Flue Gas Cooling

To prevent the accumulation of heat stable salts, the incoming flu e gas must have an SO 2 

### concentration of 10 ppmv or less. Th is is achieved by passing the gas exiting the FGD system through an SO 2 

### polishing step. The polishing step consists of a non

- plugging, low

- differential

pressure, spray

- baffle

- type scrubber using a 20 wt% solution of sodium hydroxide (NaOH). A removal efficiency of 80 to 85 percent is necessary to reduce SO 2 

### emissions from the FGD outlet to 10 ppmv as required by the Econamine process. The polishing scrubber proposed for this application has been demonstrated in numerous industrial applications throughout the world and can achieve removal efficiencies of over 95 percent if necessary.

The polishing scrubber also serves as the flue gas cooling system . Cooling water from the PC plant is used to reduce the temperature and hence moisture content of the saturated flue gas exiting the FGD system. Flue gas is cooled beyond the CO 2 

### absorption process requirements toCarbon Dioxide Capture Sensitivity Analysis



### 66 32 °C (90 °F) to account for the subsequent temperature increase of about 17 °C (30 °F) in the flue gas blower. Downstream from the Polishing Scrubber flue gas pressure is boosted in the Flue Gas Blowers by approximately 0.014 MPa (2 psi) to overcome pressure drop in the CO 2 

### absorber tower.

Circulating Water System

Coolin g water is provided from the PC plant circulating water system and returned to the plant cooling tower. The CDR facility requires a significant amount of cooling water for flue gas cooling, water wash cooling, absorber intercooling, reflux condenser duty, reclaimer cooling, the

lean solvent cooler, and CO 2 

### compression interstage cooling. The cooling water requirements for the CDR facility range from 246 m 3 

### /min (65,000 gpm) to 1,314 m 3 

### /min (347,000 gpm).

CO 2 

### Absorption

The cooled flue gas enters the botto m of the CO 2 

### Absorber and flows up through the tower

countercurrent to a stream of lean MEA

- based solvent (Econamine FG Plus SM 

### ). Depending on

the case, 90 to 99 percent of the CO 2 

### in the feed gas is absorbed into the lean solvent, and the rest

leaves the top of the absorber section and flows into the water wash section of the tower. The lean solvent enters the top of the absorber, absorbs the CO 2 

### from the flue gases, and leaves the

bottom of the absorber with the absorbed CO 2



### .

Water Wash Section

The purpose of the Water Wash section is to minimize solvent losses due to mechanical entrainment and evaporation. The flue gas from the top of the CO 2 

### Absorption section is

contacted with a re circulating stream of water for the removal of most of the lean so lvent. The scrubbed gases, along with unrecovered solvent, exit the top of the wash section for discharge to the atmosphere via the vent stack. The water stream from the bottom of the wash section is collected on a chimney tray. A portion of the water c ollected on the chimney tray spills over to the absorber section as water makeup for the amine with the remainder pumped via the Wash Water Pump and cooled by the Wash Water Cooler, and recirculated to the top of the CO 2 

### Absorber. The wash water level is maintained by water makeup from the Wash Water Makeup
Pump.Carbon Dioxide Capture Sensitivity Analysis



### 67 Exhibit 3

- 3 Fluor Econamine FG Plus SM Typical Flow DiagramCarbon Dioxide Capture Sensitivity Analysis



### 68 Rich/Lean Amine Heat Exchange System

The rich solvent from the bottom of the CO 2 

### Absorber is preheated by the lean solvent from the Solvent Stripper in the Rich Lean Solvent Exchanger. The heated rich solvent is routed to the Solvent Stripper for removal of the absorbed CO 2



### . The stripped solvent from the bottom of the Solvent Stripper is pumped via the Hot Lean Solvent Pumps through the Rich Lean Exchanger to the Solvent Surge Tank. Prior to entering the Solvent Surge Tank, a slipstream of the lean solvent is pumped via the Solvent Filter Feed Pump through the Solvent Filter Package to prevent buildup of contaminants in the solution. From the Solvent Surge Tank the lean solvent is pumped via the Warm Lean Solvent Pumps to the Lean Solvent Cooler for further cooling, after

wh ich the cooled lean solvent is returned to the CO 2 

### Absorber, completing the circulating solvent

circuit.

Solvent Stripper

The purpose of the Solvent Stripper is to separate the CO 2 

### from the rich solvent feed exiting the

bottom of the CO 2 

### Absorber. The ric h solvent is collected on a chimney tray below the bottom packed section of the Solvent Stripper and routed to the Solvent Stripper Reboilers where the rich solvent is heated by steam, stripping the CO 2 

### from the solution. Steam is provided from the

LP sec tion of the steam turbine at 0.51 MPa (74 psia) and 292 °C (557 °F). The hot wet vapor from the top of the stripper containing CO 2 

### , steam, and solvent vapor, is partially condensed in the Solvent Stripper Condenser by cross exchanging the hot wet vapor wi th cooling water. The partially condensed stream then flows to the Solvent Stripper Reflux Drum where the vapor and liquid are separated. The uncondensed CO 2 

### - rich gas is then delivered to the CO 2 

### product compressor. The condensed liquid from the Solvent Stripper Reflux Drum is pumped via the Solvent Stripper Reflux Pumps where a portion of condensed overhead liquid is used as make

- up
water for the Water Wash section of the CO 2 

### Absorber. The rest of the pumped liquid is routed back to the Solvent Strippe r as reflux, which aids in limiting the amount of solvent vapors entering the stripper overhead system.

Solvent Stripper Reclaimer

A small slipstream of the lean solvent from the Solvent Stripper bottoms is fed to the Solvent Stripper Reclaimer for the re moval of high

- boiling nonvolatile impurities (heat stable salts

- HSS), volatile acids and iron products from the circulating solvent solution. The solvent bound in the HSS is recovered by reaction with caustic and heating with steam. The solvent reclaim er system reduces corrosion, foaming and fouling in the solvent system. The reclaimed solvent is returned to the Solvent Stripper and the spent solvent is pumped via the Solvent Reclaimer Drain Pump to the Solvent Reclaimer Drain Tank.

Steam Condensate

St eam condensate from the Solvent Stripper Reclaimer accumulates in the Solvent Reclaimer

Condensate Drum and is level controlled to the Solvent Reboiler Condensate Drum. Steam condensate from the Solvent Stripper Reboilers is also collected in the Solvent ReboilerCarbon Dioxide Capture Sensitivity Analysis



### 69 Condensate Drum and returned to the steam cycle between boiler feedwater heaters 4 and 5 via the Solvent Reboiler Condensate Pumps.

Corrosion Inhibitor System

A proprietary corrosion inhibitor is continuously injected into the CO 2 

### Absorber rich so lvent bottoms outlet line, the Solvent Stripper bottoms outlet line and the Solvent Stripper top tray. This constant injection is to help control the rate of corrosion throughout the CO 2 

### recovery plant

system.

Gas Compression and Drying System

In the comp ression section, the CO 2 

### is compressed to 15.3 MPa (2,215 psia) by a six

- stage centrifugal compressor. The discharge pressures of the stages were balanced to give reasonable power distribution and discharge temperatures across the various stages as shown in Exhibit 3

- 4

.

Exhibit 3

- 4 CO 2 Compressor Interstage Pressures

Stage Outlet Pressure,

MPa (psia)

1 0.35 (51)

2 0.77 (112)

3 1.69 (245)

4 3.71 (538)

5 8.16 (1,184)

6 15.3 (2,215)



### Power consumption for this large compressor was estimated assuming a polytropic efficiency of 86 percent and mechanical efficiency of 98 percent. During compression to 15.3 MPa (2,215 psia) in the multiple

- stage, intercooled compressor, the CO 2 

### stream is dehydrated to a dewpoint

of

- 40 oC (

- 40 °F) with triethylene glycol. The virtually moisture

- free supercritical CO 2 

### stream is delivered to the plant battery limit as seq uestration

- ready. CO 2 

### TS&M costs were estimated and

included in COE using the methodology described in Section 2.7

.



## 3.1.8 Steam Turbine Generator System

The steam turbine is a tandem compound type, consisting of HP

- IP

- two LP (double flow) sections enclosed in three casings, designed for condensing single reheat operation, and equipped

with non

- automatic extractions and four

- flow exhaust. The turbine drives a hydrog en

- cooled generator. The turbine has DC motor

- operated lube oil pumps, and main lube oil pumps, whichCarbon Dioxide Capture Sensitivity Analysis



### 70 are driven off the turbine shaft [ 40 ]

. The exhaust pressure is 35.6 cm (1.4 in) Hg in the single pressure condenser. The condenser is two

- shell, transve rse, single pressure with divided

waterbox for each shell. 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 perce nt OP/VWO condition (16 hours).

Turbine bearings are lubricated by a closed

- loop, water

- cooled pressurized oil system. Turbine shafts are sealed against air in

- leakage or steam blowout using a labyrinth gland arrangement

connected to a low

- pressure steam seal system. The ge nerator stator is cooled with a closed

- loop water system consisting of circulating pumps, shell and tube or plate and frame type heat exchangers, filters, and deionizers, all skid

- mounted. The generator rotor is cooled with a hydrogen gas recirculation sy stem using fans mounted on the generator rotor shaft.

Operation Description

– The turbine stop valves, control valves, reheat stop valves, and intercept valves are controlled by an electro

- hydraulic control system. Main steam from the boiler passes thro ugh the stop valves and control valves and enters the turbine at 24.1 MPa/593 °C (3,500 psig/1,10 0 °F) . The steam initially enters the turbine near the middle of the high

pressure span, flows through the turbine, and returns to the boiler for reheating. The reheat steam flows through the reheat stop valves and intercept valves and enters the IP section at 593
°C (1,100 °F). After passing through the IP section, the steam enters a crossover pipe, which transports the steam to the two LP sections. The ste am divides into four paths and flows through the LP sections exhausting downward into the condenser.

The turbine is designed to operate at constant inlet steam press ure over the entire load range.

3.1.8.1 Supercritical Steam Turbine Cycle

The supercritical steam turb ine is equipped with six non

- automatic steam extractions, which along with the HP and IP section exhausts provide steam for four low pressure feedwater heaters, deaerator, and three high pressure feedwater heaters. All feedwater heaters (except the

d eaerator) are closed type. The condensate drains from the low pressure heater (#1 through #4) are cascaded to the condenser. The condensate drains from the high pressure heaters (#6 through #8) are cascaded to the deaerator. The deaerator storage tank p rovides suction to the boiler feedwater pumps. The deaerator is assumed to be placed at high elevation to assure sufficient Net Positive Suction Head (NPSH) for the feedwater pumps. Heater #7 is on cold reheat

extraction and heater #8 is a heater above t he reheat point (HARP).



## 3.1.9 Balance of Plant

The balance of plant components consist of the condensate, feedwater, main and reheat steam, extraction steam, ash handling, ducting and stack, waste treatment and miscellane ous systems as

described below.

3.1.9.1 Condensat e

The function of the condensate system is to pump condensate from the condenser hotwell to the deaerator, through the gland steam condenser and through the LP feedwater heaters. EachCarbon Dioxide Capture Sensitivity Analysis



### 71 system consists of one main condenser; one variable speed electric moto r

- driven vertical condensate pump with a 100 percent in

- line spare ; one gland steam condenser; four LP heaters; and one deaerator with storage tank.

Condensate is delivered to a common discharge header through two separate pump discharge

lines, each with a check valve and a gate valve. A common minimum flow recirculation line discharging to the condenser is provided downstream of the gland steam condenser to maintain minimum flow requirements for the gland steam condenser and the condensate pumps.

LP feedw ater heaters 1 through 4 are 50 percent capacity, parallel flow, and are located in the condenser neck. All remaining feedwater heaters are 100 percent capacity shell and U

- tube heat exchangers. Each LP feedwater heater is provided with inlet/outlet isol ation valves and a full capacity bypass. LP feedwater heater drains cascade down to the next lowest extraction pressure heater and finally discharge into the condenser. Pneumatic level control valves control normal drain levels in the heaters. High heat er level dump lines discharging to the condenser are provided for each heater for turbine water induction protection. Pneumatic level control valves control dump line flow.

3.1.9.2 Feedwater

The function of the feedwater system is to pump the feedwater from the d eaerator storage tank (s) through the HP feedwater heaters to the economizer. The SC plants have a single deaerator and

use o ne turbine

- driven boiler feedwater pump sized at 100 percent capacity (with a 100 percent
spare) to pump feedwater through the HP f eedwater heaters. One 25 percent motor

- driven boiler feedwater pump for each application is provided for startup. The pumps are provided with inlet and outlet isolation valves, and individual minimum flow recirculation lines discharging back to

the deaer ator storage tank. The recirculation flow is controlled by automatic recirculation valves, which are a combination check valve in the main line and in the bypass, bypass control valve, and flow sensing element. The suction of the boiler feed pump is equi pped with startup strainers, which are utilized during initial startup and following major outages or system

maintenance.

Each HP feedwater heater is provided with inlet/outlet isolation valves and a full capacity bypass. Feedwater heater drains cascade d own to the next lowest extraction pressure heater and finally discharge into the deaerator. Pneumatic level control valves control normal drain level in the heaters. High heater level dump lines discharging to the condenser are provided for each

heater f or turbine water induction protection. Dump line flow is controlled by pneumatic level

control valves.

The deaerator is a horizontal, spray tray type with internal direct contact stainless steel vent condenser and storage tank. The boiler feed pump turbi ne is driven by main steam up to

60 percent plant load. Above 60 percent load, extraction from the IP turbine exhaust provides steam to the boiler feed pump steam turbine.

3.1.9.3 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 valves. The function of the reheat system is to convey steam fromCarbon Dioxide Capture Sensitivity Analysis



### 72 the HP turbine exhaust to the boiler reheater and from the boiler reheater outlet to the IP turbine stop valves.

Main steam exits the boiler superheater through a motor

- operated stop/check valve and a motor

operated gate valve and is routed in a single line feeding the HP turbine. A branch line off the IP turbine exhaust feeds the boiler feed water pump turbine during unit operation starting at approximately 60 percent load.

Cold reheat steam exits the HP turbine, flows through a motor

- operated isolation gate valve and

a flow control valve, and enters the boiler reheater. Hot reheat steam exits the boiler reheater through a motor

- op erated gate valve and is routed to the IP turbine.

3.1.9.4 Extraction Steam

The function of the extraction steam system is to convey steam from turbine extraction points to

the feedwater heaters, deaerator, and CDR facility

.

The turbine is protected from overspee d 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

fee dwater heaters in the condenser neck. The extraction non

- return valves are located only in horizontal runs of piping and as close to the turbine as possible.

The turbine trip signal automatically trips the non

- return valves through relay dumps. The

remot e 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.

3.1.9.5 Circulating Water System

It is assumed that the plant is serviced by a public water facility a nd 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, counter

- flow cooling tower is provided for the circulating water heat sink. Two 50 percent circulating water pumps are provided. The circulating water system provides cooling water to the condenser, the CDR facility, and the auxiliary cooling water system.

The auxiliary cooling water system is a closed

- loop system. Plate and frame heat exchangers with circulating water as the cooling medium are provided. This system provides cooling water to the lube oil coolers, turbine generator, boiler feed pumps, etc. All pumps, vacuum breakers,

air release valves, instruments, cont rols, etc. are included for a complete operable system.

3.1.9.6 Ash Handling System

The function of the ash handling system is to provide the equipment required for conveying, preparing, storing, and disposing of the fly ash and bottom ash produced on a daily basi s by the boiler. The scope of the system is from the bag house hoppers, air heater hopper collectors, and bottom ash hoppers to the hydrobins (for bottom ash) and truck filling stations (for fly ash). TheCarbon Dioxide Capture Sensitivity Analysis



### 73 system is designed to support short

- term operatio n at the 5 percent OP/VWO condition
(16 hours) and long

- term operation at the 100 percent guarantee point (90 days or more).

The fly ash collected in the bag house and in the air heaters is conveyed to the fly ash storage silo. A pneumatic transport sys tem using low

- pressure air from a blower provides the transport mechanism for the fly ash. Fly ash is discharged through a wet unloader, which conditions the fly ash and conveys it through a telescopic unloading chute into a truck for disposal.

The bottom ash from the boiler is fed into a clinker grinder. The clinker grinder is provided to break up any clinkers that may form. From the clinker grinders the bottom ash is sluiced to hydrobins for dewatering and offsite removal by truck.

Ash from the economi zer hoppers and pyrites (rejected from the coal pulverizers) is conveyed by hydraulic means (water) to the economizer/pyrites transfer tank. This material is then sluiced, on a periodic basis, to the hydrobins.

3.1.9.7 Ducting and Stack

One stack is provided wi th a single fiberglass

- reinforced plastic (FRP) liner. The stack is
constructed of reinforced concrete. The stack is 152 m (500 ft) high for adequate particulate dispersion. The ID fans were sized large enough to allow for additional stack velocity to

o vercome the buoyancy losses resulting from colder than normal flue gas temperatures following

CO 2 

### capture

.

3.1.9.8 Waste Treatment/Miscellaneous Systems

An onsite water treatment facility treats all runoff, cleaning wastes, blowdown, and backwash to

within the U.S . EPA standards for suspended solids, oil and grease, pH, and miscellaneous metals. Waste treatment equipment is housed in a separate building. The waste treatment system consists of a water collection basin, three raw waste pumps, an acid neutralization system, an oxidation system, flocculation, clarification/thickening, and sludge dewatering. The water collection basin is a synthetic

- membrane

- lined earthen basin, which collects rainfall runoff, maintenance cleaning wastes, and backwash flows.

The raw w aste is pumped to the treatment system at a controlled rate by the raw waste pumps. The neutralization system neutralizes the acidic wastewater with hydrated lime in a two

- stage system, consisting of a lime storage silo/lime slurry makeup system, dry lime feeder, lime slurry tank, slurry tank mixer, and lime slurry feed pumps.

The oxidation system consists of an air compressor, which injects air through a sparger pipe into

the second

- stage neutralization tank. The flocculation tank is fiberglass with a va riable speed agitator. A polymer dilution and feed system is also provided for flocculation. The clarifier is a plate

- type, with the sludge pumped to the dewatering system. The sludge is dewatered in filter presses and disposed offsite. Trucking and di sposal costs are included in the cost estimate. The filtrate from the sludge dewatering is returned to the raw waste sump.

Miscellaneous systems consisting of fuel oil, service air, instrument air, and service water are provided. A storage tank provides a supply of No. 2 fuel oil used for startup and for a smallCarbon Dioxide Capture Sensitivity Analysis



### 74 auxiliary boiler. Fuel oil is delivered by truck. All truck roadways and unloading stations inside the fence area are provided.

3.1.9.9 Buildings and Structures

Foundations are provided for the support structures, pumps, tanks, and other plant components. The following buildings are included in the design basis:

Steam turbine building Fuel oil pump house Guard house

Boiler building Coal crusher building Runoff water pump house

Administration and service building Continuous emissions monitoring building Industrial waste treatment building

Makeup water and pretreatment building Pump house and electrical equipment building FGD system buildings



## 3.1.10 Accessory Electric Plant

The accessory electric plan t c onsists of switchgear and control equipment, generator equipment, station service equipment, conduit and cable trays, and wire and cable. It also includes the main power transformer, required foundations, and standby equipment.



## 3.1.11 Instrumentation and Control

An integrated plant

- wide control and monitoring distributed control system (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 avail ability. The plant equipment and the DCS are designed for automatic response to load changes from minimum load to 100 percent. Startup and shutdown routines are implemented as supervised manual, with operator selection of modular

automation routines avai lable.



## 3.2 Supercritical P C C O 2 

## Capture Sensitivity

The evaluation scope included developing heat and mass balances and estimating plant performance on a common 550 MWe net output basis while firing bituminous Illinois No. 6 coal. Equipment lists were developed for each design to support plant capital and operating costs

estimates.Carbon Dioxide Capture Sensitivity Analysis



### 75 The SC PC plants are assumed to be built on a “greenfield” site and utilize reci rculating evaporative cooling systems for cycle heat rejection. Major systems for each plant (described in

Section 3.1 ) include:

1. Steam Generator

2. Steam Turbine/Gen erator

3. Particulate control system

4. FGD system

5. SCR system

6. CO 2 

### Recovery

7. Balance of Plant

Support facilities include coal handling (receiving, crushing, and storing ), limestone handling (including receiving, crushing, storing, and feeding), solid waste disposa l, circulating water system with evaporative mechanical draft cooling towers, wastewater treatment, and other ancillary systems equipment necessary for an efficient, highly available, and completely operable facility.

The plant designs are based on using components suitable for a 30

- year life, with provision for periodic maintenance and replacement of critical parts. All equipment is based on compliance with the latest applicable codes and standards. ASME, ANSI, IEEE, NFPA, CAA, state regulations, and O SHA codes are all adhered to in the design approach.

The modeling assumptions that were used to generate the SC PC material and energy balances

are summarized in Exhibit 3

- 5

.Carbon Dioxide Capture Sensitivity Analysis



### 76 Exhibit 3

- 5 Supercritical PC Combustion Configuration Modeling Assumptions

Case 1 A Case 1B Case 1C Case 1D Case 1E Case 1F Case 1G

Throttle pressure, psig 3500 3500 3500 3500 3500 3500 3500

Throttle temperature, oF 110 0 110 0 110 0 110 0 110 0 110 0 110 0

Reheat temperature, oF 110 0 110 0 110 0 110 0 110 0 110 0 110 0

Condenser pressure, psia 0.98 0.98 0.98 0.98 0.98 0.98 0.98

Cooling water to condenser, oF 60 60 60 60 60 60 60

Cooling water from condenser, oF 80 80 80 80 80 80 80

Stack temperature saturation saturation saturation saturation saturation saturation saturation

Coal HHV (Illinois No. 6), Btu/lb 11,666 11,666 11,666 11,666 11,666 11,666 11,666

FGD efficiency 98% 98% 98% 98% 98% 98% 98%

SOx emissions, lb/MMBtu 0.1 0.1 0.1 0.1 0.1 0.1 0.1

SCR efficiency 86% 86% 86% 86% 86% 86% 86%

NOx emissions, lb/MMBtu 0.07 0.07 0.07 0.07 0.07 0.07 0.07

Ammonia slip (end of catalyst life), ppm 2 2 2 2 2 2 2

Baghouse efficiency 99.8% 99.8% 99.8% 99.8% 99.8% 99.8% 99.8%

Particulate emissions PM/PM 10 , lb/MMBtu 0.015 0.015 0.015 0.015 0.015 0.015 0.015

Mercury removal, % 90 90 90 90 90 90 90

CO 2 Capture Efficiency*, % 30 50 70 85 90 95 99

Product CO 2 Condition, psia/°F 2215/95 2215/95 2215/95 2215/95 2215/95 2215/95 2215/95

* Percentage of CO 2 removed from flue gasCarbon Dioxide Capture Sensitivity Analysis



### 77 

## 3.2.1 CO 2 

## Capture with Partial Bypass Performance Results

A process block flow diagram for Cases 1 A through 1D is shown in Exhibit 3

- 6 . These cases

represent superc ritical steam cycles with CO 2 

### capture ranging from 30 to 85 percent

. T he corresponding stream tables are contained in Exhibit 3

- 7

, Exhibit 3

- 8

, Exhibit 3

- 9 , and

Exhibit 3

- 10 for 30, 50, 70, and 85 percent CO 2 

### capture, respectively. A series of CO 2 

### capture levels was developed by varying the volume of flue gas that bypasses the Econamine FG Plus ®



### system via Stream 18. Further, the MEA solvent circulation rate and reboiler steam flow rate were adjusted to account for the volume of flue gas treated.

A literat ure search was conducted to verify that <90 percent CO 2 

### capture is most economical using a slip

- stream (or bypass) approach. Indeed, the „slip

- stream‟ approach is more cost

effective for <90 percent CO 2 

### capture than removing reduced CO 2 

### fractions from the entire flue

gas stream , according to multiple peer

- rev iewed studies [ 1

, 2

, 3 ] . The cost of CO 2 

### capture with

the Econamine FG Plus SM 

### process is dependent on the volume of gas being treated and a reduction in flue gas flow rate will (1) decrease the quantity of energy consumed by flue g as blowers; (2) reduce the size of the CO 2 

### absorption columns; (3) trim the cooling water requirement of the direct contact cooling system; and (4) decrease the amount of fan power required to increase the flue gas temperature and plume buoyancy. As a res ult, the slip

- stream approach for <90 percent CO 2 

### capture leads to lower capital and operating costs.

Overall performance for Cases 1 A through 1D is summarized in Exhibit 3

- 11 which includes auxiliary power requirements.

Material and energy balance information, environmental performance and a major e quipment list

are summarized in Sections 3.2.1.1 and 3.2.1.2

.Carbon Dioxide Capture Sensitivity Analysis



### 78 Exhibit 3

- 6 Cases 1A Through 1D Process Block Flow Diagram, Supercritical PC with CO 2 Capture BypassCarbon Dioxide Capture Sensitivity Analysis



### 79 Exhibit 3

- 7 Case 1A Stream Table, Supercritical PC wit h 30% CO 2 CaptureCarbon Dioxide Capture Sensitivity Analysis



### 80 Exhibit 3

- 7 Case 1A Stream Table, Supercritical PC with 30% CO 2 Capture (continued)Carbon Dioxide Capture Sensitivity Analysis



### 81 Exhibit 3

- 8 Case 1B Stream Table, Supercritical PC with 50% CO 2 CaptureCarbon Dioxide Capture Sensitivity Analysis



### 82 Exhibit 3

- 8 Case 1B Stream Table, Supercritical PC with 50% CO 2 Capture (continued)Carbon Dioxide Capture Sensitivity Analysis



### 83 Exhibit 3

- 9 Case 1C Stream Table, Supercritical PC with 70% CO 2 CaptureCarbon Dioxide Capture Sensitivity Analysis



### 84 Exhibit 3

- 9 Case 1C Stream Table, Supercritical PC with 70% CO2 Capture (continued)Carbon Dioxide Capture Sensitivity Analysis



### 85 Exhibit 3

- 10 Case 1D Stream Table, Supercritical PC with 85% CO 2 CaptureCarbon Dioxide Capture Sensitivity Analysis



### 86 Exhibit 3

- 10 Case 1D Stream Table, Supercritical PC with 85% CO2 Capture (continued)Carbon Dioxide Capture Sensitivity Analysis



### 87 Exhibit 3

- 11 Cases 1A Through 1D Performance Modeling Results

POWER SUMMARY (Gross Power at Generator

Terminals, kWe) Case 1A (30%) Case 1B (50%) Case 1C (70%) Case 1D (85%)

Steam Turbine Power 601,500 618,200 637,800 654,800

AUXILIARY LOAD SUMMARY, kWe 1

Coal Handling and Conveying 4 6 0 470 490 500

Limestone Handling & Reagent Preparation 1,0 1 0 1,0 8 0 1,160 1,2 3 0

Pulverizers 3, 11 0 3,3 3 0 3,5 8 0 3,7 9 0

Ash Handling 590 6 4 0 680 720

Primary Air Fans 1,4 5 0 1,5 5 0 1,6 7 0 1,7 7 0

Forced Draft Fans 1,8 5 0 1,9 8 0 2,1 3 0 2,2 6 0

Induced Draft Fans 8,020 8, 59 0 9, 23 0 9, 7 80

SCR 20 20 20 20

Baghouse 80 80 90 90

FGD Pumps and Agitators 3, 31 0 3,5 5 0 3, 81 0 4,0 4 0

Econamine FG Plus Auxiliaries 5,500 9, 9 00 14, 8 00 1 9,1 00

CO 2 Compression 11, 79 0 21, 200 31, 73 0 40, 86 0

Econamine Condensate Pump 40 7 0 110 140

Miscellaneous Balance of Plant 2 2,000 2,000 2,000 2,000

Steam Turbine Auxiliaries 400 400 400 400

Condensate Pumps 7 2 0 6 8 0 6 3 0 5 9 0

Circulating Water Pumps 5,820 6,710 8,26 0 9,600

Cooling Tower Fans 3, 40 0 3,920 4,820 5,610

Transformer Loss 1,940 2,0 4 0 2,1 5 0 2,2 5 0

TOTAL AUXILIARIES, kWe 51,510 68,210 87,760 104,750

NET POWER, kWe 549,990 549,990 550,040 550,050

Net Plant Efficiency, % (HHV) 35.2 % 32.9% 30.6% 28.9%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 10,229 ( 9,695 ) 10,950 (10,379) 11,765 (11,151) 12,470 (11,819)

CONDENSER COOLING DUTY GJ/hr (10 6 Btu/hr) 2,164 ( 2,051 ) 2,037 (1,931) 1,900 (1,801) 1,783 (1,690)

CONSUMABLES

As

- Received Coal Feed, kg/hr (lb/hr) 3 20 7,322 (45 7,066 ) 221,950 (489,316) 238,483 (525,764) 252,779 (557,283)

Thermal Input, kWt 1,562,693 1,672,956 1,797,570 1,905,333

Raw Water Withdrawal , m 3 /min (gpm) 23.6 (6,245) 26.4 (6,987) 31.7 (8,386) 36.4 (9,615)

Raw Water Consumption, m 3 /min (gpm) 18.5 (4,898) 20.6 (5,433) 24.5 (6,474) 28.0 (7,392)

Notes: 1. Boiler feed pumps are turbine driven

2. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

3. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)Carbon Dioxide Capture Sensitivity Analysis



### 88 3.2.1.1 Environmental Performance for Cases 1A t hrough 1D

Each case was designed to meet presumptive BACT standards utilizing the emissions control processes described in Section 2.4 . A summary of plant air emissions is presented in

Exhibit 3

- 12

.

SO 2 

### emissions are controlled using a wet limestone forced oxidation FGD that achieves a removal efficiency of 98%. To avoid the formation of heat stable salts in the Econamine

process, an SO 2 

### polishing step is included to reduce the sulfur content to 10 ppm prior to the CO 2 

### absorber

, and the balance of the SO 2 

### is absorbed by the MEA solution resulting in negligible stack emissions. 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 b yproduct credit was taken. The saturated flue gas exiting the FGD is vented through the plant stack.

Particulate emissions are controlled using a pulse jet fabric filter (baghouse) which operates at an efficiency of 99.8 percent . It was assumed that 20 p ercent of the ash exits the boiler as bottom ash and the remaining 80 percent exits the boiler in the flue gas [ 41 ].

Co

- benefit capture of Hg in the fabric filter and FGD system was assumed to achieve a 90

percent capture rate [ 42 ]. The high chlorine conten t of the Illinois No. 6 coal and the SCR system will convert most of the Hg in the system to an oxidized state [ 43 ]. An inexpensive FGD

system additive can be used to promote Hg capture if necessary, but was not included

.

The carbon balance for the four c ases is shown in Exhibit 3

- 13

. The carbon input to the plant

consists of carbon in the coal, limestone, and combustion and FGD forced oxidation air.

CO 2 

### capture efficiency is calculated as the pounds of CO 2 

### captured divided by the pounds of CO 2 

### produced. Most of the CO 2 

### produced comes from coal combustion, but a small amount is

formed in th e FGD system. The sum of these two sources is the amount produced.

(Carbon in Sequestration Product) / (Carbon in the Coal + Net Carbon from Limestone) or

8 8,274 / (2 91,355 + 4, 206 ) *100 = 30% (Case 1A)

15 8,670 / ( 311,913 + 4,502 ) *100 = 50% (Case 1B)

23 7,502 / (33 5,147 + 4,837 ) *100 = 70% (Case 1C)

30 5,794 / (35 5,239 + 5,128 ) *100 = 85% (Case 1D)

Exhibit 3

- 14 shows the sulfur balance for the four cases. Sulfur input comes solely from the sulfur in the coal. Sulfur output is the gypsum sulfur by product, and the sulfur emitted in the stack gas. The total sulfur capture is represented by the following fraction:

(Sulfur byproduct/Sulfur in the coal) or
(11, 227 /11, 456 )*100 = 98.0% (Case 1A)
( 12,019 /12, 264 )*100 = 98.0% (Case 1B)
(12, 914 /13, 178 )*100 = 98.0% (Case 1C)
(13, 688 /13, 968 )*100 = 98.0% (Case 1D)Carbon Dioxide Capture Sensitivity Analysis



### 89 T he overall water balance s for Case 1A, 1B, 1C, and 1D are shown in Exhibit 3

- 15

, Exhibit 3

- 16

, Exhibit 3

- 17 , and Exhibit 3

- 18 , respectively

. Raw water is obtained from groundwater (50
percent) and from municipal sources (50 percent). Water demand represents the total amount of water required for a particular process. Some water is recovered within t he process and that

water is re used as internal recycle. Raw water withdrawal is the differenc e between water demand and internal recycle. Process water discharged from the power plant is also account ed for in this study. Raw water consumption represents raw water withdrawal less process water discharge.

Heat and Mass Balance Diagrams

Heat and m ass balance diagrams are shown for the following subsystems in Exhibit 3

- 19 through

Exhibit 3

- 26

.

Boiler and flue gas cleanup

Steam and feedwater

An overall plant energy balance is provided in tabular form for Case 1A, 1B, 1C, and 1D in

Exhibit 3

- 27

, Exhibit 3

- 28

, Exhibit 3

- 29 , and Exhibit 3

- 30 , respectively . The power out is the steam turbine power after generato r losses. In addition, energy balance Sankey diagrams are provided in Exhibit 3

- 31

, Exhibit 3

- 32

, Exhibit 3

- 33 , and Exhibit 3

- 34 for Case 1A, 1B, 1C, and 1D, respectively.Carbon Dioxide Capture Sensitivity Analysis



### 90 Exhibit 3

- 12 Cases 1A through 1D Estimated Air Emission Rates

kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)

Case 1A Case 1B Case 1C Case 1D Case 1A Case 1B Case 1C Case 1D Case 1A Case 1B Case 1C Case 1D

SO 2 0.028

(0.064) 0.022

(0.050) 0.0 15

(0.0 36 ) 0.007

(0.017) 1,1 59

(1,27 8 ) 96 4

(1,06 3 ) 740

( 816 ) 370

(408) 0.259

(0.57 0 ) 0.210

(0.46 0 ) 0. 156

(0. 34 0 ) 0.076

(0.17 0 )

NO X 0.030

(0.070) 0.030

(0.070) 0.030

(0.070) 0.030

(0.070) 1,261

(1,390 ) 1,35 0

(1,4 88 ) 1,45 0

(1, 598 ) 1,537

(1,69 4 ) 0.281

(0.621) 0.293

(0.646) 0.305

(0.673) 0.315

(0.695)

PM 0.006

(0.0130) 0.006

(0.0130) 0.006

(0.0130) 0.006

(0.0130) 234

(258) 251

(27 6 ) 2 69

(297) 28 5

(315) 0.052

(0.115) 0.054

(0.120) 0.057

(0.125) 0.059

(0.129)

Hg 0.49x10 - 6

(1.14x10 - 6 ) 0.49x10 - 6

(1.14x10 - 6 ) 0.49x10 - 6

(1.14x10 - 6 ) 0.49x10 - 6

(1.14x10 - 6 ) 0.021

(0.023) 0.022

(0.024) 0.024

(0.026) 0.025

(0.028) 4.60x10 - 6

(10.1x10 - 6 ) 4.79x10 - 6

(10.6x10 - 6 ) 4.99x10 - 6

(11.0x10 - 6 ) 5.15x10 - 6

(11.3x10 - 6 )

CO 2 61.4

(142.9) 43.7

(101.7) 26.5

(61.7) 13.4

(31.2) 2,57 3,010

(2,83 6,258 ) 1,96 0,464

(2,16 1,042 ) 1,27 7,186

(1,40 7,857 ) 684, 813

(75 4,877 ) 574

(1,267) 426

(939) 269

(593) 140

(310)

CO 2 net 62 8 (1,38 5 ) 4 79 (1,05 5 ) 312 (68 7 ) 167 (369)Carbon Dioxide Capture Sensitivity Analysis



### 91 Exhibit 3

- 13 Cases 1A through 1D Carbon Balance

Carbon In, kg/hr (lb/hr)

Case 1A Case 1B Case 1C Case 1D

Coal 132, 157

(291, 355 ) 141, 481

(31 1,913 ) 152, 020

(335, 147 ) 161,1 34

(355, 239 )

Air (CO 2 ) 282 (622) 302 (66 6 ) 32 4 (71 5 ) 344 (758)

Limestone 2,1 29

(4,69 3 ) 2,2 79

(5,0 24 ) 2,43 6

(5,37 1 ) 2,59 3

(5,71 7 )

Total 13 4, 568

(29 6, 670 ) 14 4, 062

(31 7,603 ) 154, 780

(341, 233 ) 164, 071

(361,7 14 )

Carbon Out, kg/hr (lb/hr)

Stack Gas 94, 308

(20 7,913 ) 71, 856

(158, 416 ) 46,8 12

(103,2 04 ) 25,10 0

(55,3 37 )

CO 2 Product 40,0 41

(88, 274 ) 71,972

(158, 670 ) 107, 729

(237, 502 ) 138,7 06

(305, 794 )

Gypsum 221 (48 7 ) 237 (522) 242 (53 4 ) 267 (5 89 )

Convergence

Tolerance* - 2 (

- 4 )

- 3 (

- 5 )

- 3 (

- 7 )

- 2 (

- 6 )

Total 13 4, 568

( 296, 670 ) 14 4,062

(31 7,603 ) 154,780

(341,233) 164,071

(361,714)

Exhibit 3

- 14 Cases 1A through 1D Sulfur Balance

Sulfur In, kg/hr (lb/hr)

Case 1A Case 1B Case 1C Case 1D

Coal 5, 196

(11,4 56 ) 5,5 63

(12,2 6 4) 5,9 77

(13,1 78 ) 6,33 6

(13,9 68 )

Total 5, 196

(11, 4 56 ) 5,5 63

(12, 2 6 4) 5,9 77

(13, 1 78 ) 6, 33 6

(13, 9 68 )

Sulfur Out, kg/hr (lb/hr)

Gypsum 5,09 2

(11,2 27 ) 5,4 52

(12,0 1 9) 5,8 58

(12,9 14 ) 6,2 09

(13,6 88 )

Stack Gas 78 (172) 65 (143) 50 ( 110 ) 25 (55)

AGR 26 (57) 46 (102) 70 ( 154 ) 102 (224)

Convergence

Tolerance* 0 (0) 0 (0)

- 1 (0) 0 ( 1 )

Total 5, 196

(11, 456 ) 5,5 63

(12, 26 4) 5,9 77

(13, 178 ) 6, 336

(13, 968 )Carbon Dioxide Capture Sensitivity Analysis



### 92 Exhibit 3

- 15 Case 1A (30%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Econamine 0.04 (10) 0.0 (0) 0.04 (10) 0.0 (0) 0.04 (10)

FGD Makeup 4.14 (1

, 093) 0.0 (0) 4.14 (1

, 093) 0.0 (0) 4.14 (1

, 093)

BFW Makeup 0.30 (80) 0.0 (0) 0.30 (80) 0.0 (0) 0.30 (80)

Cooling Tower Makeup 22.7 (5,990) 3.51 (928) 19.2 (5,062) 5.10 (1

, 347) 14.06 (3

, 715)

Total 27.2 (7,174) 3.51 (928) 23.6 (6,245) 5.10 (1

, 347) 18.5 (4

, 898)

Total, gal/MWh net 783 101 681 147 534

Exhibit 3

- 16 Case 1B (50%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Econamine 0.07 (17) 0.0 (0) 0.07 (17) 0.0 (0) 0.07 (17)

FGD Makeup 4.43 (1

, 170) 0.0 (0) 4.43 (1

, 170) 0.0 (0) 4.43 (1

, 170)

BFW Makeup 0.33 (86) 0.0 (0) 0.33 (86) 0.0 (0) 0.33 (86)

Cooling Tower
Makeup 26.2 (6,909) 4.53 (1

, 196) 21.6 (5,713) 5.9 (1

, 554) 15.75 (4

, 159)

Total 31.0 (8,183) 4.53 (1

, 196) 26.4 (6,987) 5.9 (1

, 554) 20. 6 (5

, 433)

Total, gal/MWh net 893 130 762 170 593Carbon Dioxide Capture Sensitivity Analysis



### 93 Exhibit 3

- 17 Case 1C (70%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Econamine 0.10 (26) 0.0 (0) 0.10 (26) 0.0 (0) 0.10 (26)

FGD Makeup 4.75 (1

, 255) 0.0 (0) 4.75 (1

, 255) 0.0 (0) 4.75 (1

, 255)

BFW Makeup 0.35 (92) 0.0 (0) 0.35 (92) 0.0 (0) 0.35 (92)

Cooling Tower Makeup 32.2 (8,501) 5.64 (1

, 489) 26.5 (7,012) 7.2 (1

, 912) 19.31 (5

, 101)

Total 37.4 (9,875) 5.64 (1

, 489) 31.7 (8,386) 7.2 (1

, 912) 24.5 (6

, 474)

Total, gal/MWh net 1,077 162 915 209 706

Exhibit 3

- 18 Case 1D (85%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Econamine 0.13 (33) 0.0 (0) 0.13 (33) 0.0 (0) 0.13 (33)

FGD Makeup 5.04 (1

, 333) 0.0 (0) 5.04 (1

, 333) 0.0 (0) 5.04 (1

, 333)

BFW Makeup 0.37 (98) 0.0 (0) 0.37 (98) 0.0 (0) 0.37 (98)

Cooling Tower
Makeup 37.4 (9,882) 6.55 (1

, 731) 30.9 (8,151) 8.4 (2

, 222) 22.44 (5

, 929)

Total 42.9 (11,346) 6.55 (1

, 731) 36.4 (9,615) 8.4 (2

, 222) 28.0 (7

, 392)

Total, gal/MWh net 1,238 189 1,049 242 806Carbon Dioxide Capture Sensitivity Analysis



### 94 This page intentionally left blankCarbon Dioxide Capture Sensitivity Analysis



### 95 Exhibit 3

- 19 Case 1A (30%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup SystemsCarbon Dioxide Capture Sensitivity Analysis



### 96 Exhibit 3

- 20 Case 1A (30%) Heat and Mass Balance, Power Block SystemsCarbon Dioxide Capture Sensitivity Analysis



### 97 Exhibit 3

- 21 Case 1B (50%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup SystemsCarbon Dioxide Capture Sensitivity Analysis



### 98 Exhibit 3

- 22 Case 1B (50%) Heat and Mass Balance, Power Block SystemsCarbon Dioxide Capture Sensitivity Analysis



### 99 Exhibit 3

- 23 Case 1C (70%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup SystemsCarbon Dioxide Capture Sensitivity Analysis



### 100 Exhibit 3

- 24 Case 1C (70%) Heat and Mass Balance, Power Block SystemsCarbon Dioxide Capture Sensitivity Analysis



### 101 Exhibit 3

- 25 Case 1D (85%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup SystemsCarbon Dioxide Capture Sensitivity Analysis



### 102 Exhibit 3

- 26 Case 1D (85%) Heat and Mass Balance, Power Block SystemsCarbon Dioxide Capture Sensitivity Analysis



### 103 Exhibit 3

- 27 Case 1A (30%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,626 (5,332) 4.7 (4.5) 5,630 (5,337)

Combustion Air 62.7 (59.4) 62.7 (59.4)

Raw Water Makeup 93.1 (88.3) 93.1 (88.3)

Limestone 0.46 (0.43) 0.46 (0.43)

Totals 5,626 (5,332) 161.0 (152.6) 0.0 (0.0) 5,787 (5,485)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.5 (0.5) 0.5 (0.5)

Fly Ash + Gypsum 2.0 (1.9) 2.0 (1.9)

Flue Gas 533 (505) 533 (505)

CO 2 - 31 (

- 30)

- 31 (

- 30)

Cooling Tower * 2,384.4 (2,260.0) 2,384.4 (2,260.0)

Process Losses* * 917.8 (869.9) 917.8 (869.9)

Net Power 1,980 (1,877) 1,980

(1,877)

Totals 0.0 (0.0) 3,807 (3,608) 1,980 (1,877) 5,787

(5,485)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and Econamine cooling water. ** Process losses are estimated to match the heat input to the plant.
Process losses include losses from: steam turbine, combustion reac tions, gas cooling,

and Econamine steam.Carbon Dioxide Capture Sensitivity Analysis



### 104 Exhibit 3

- 28 Case 1B (50%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 6,023 (5,708) 5.0 (4.8) 6,028 (5,713)

Combustion Air 67.1 (63.6) 67.1 (63.6)

Raw Water Makeup 106.8 (101.3) 106.8 (101.3)

Limestone 0.49 (0.46) 0.49 (0.46)

Totals 6,023 (5,708) 179.5 (170.1) 0.0 (0.0) 6,202 (5,878)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.5 (0.5) 0.5 (0.5)

Fly Ash + Gypsum 2.2 (2.1) 2.2 (2.1)

Flue Gas 435 (412) 435 (412)

CO 2 - 56 (

- 53)

- 56 (

- 53)

Cooling Tower * 2,434.7 (2,307.7) 2,434.7 (2,307.7)

Process Losses* * 1,406.2 (1,332.8) 1,406.2 (1,332.8)

Net Power 1,980 (1,877) 1,980

(1,877)

Totals 0.0 (0.0) 4,222 (4,002) 1,980 (1,877) 6,202

(5,878)

Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and Econamine cooling water. ** Process losses are estimated to match the heat input to the plant. Process losses include losses from: steam turbine, combustion reactions, gas cooling,

and Econamine steam.Carbon Dioxide Capture Sensitivity Analysis



### 105 Exhibit 3

- 29 Case 1C (70%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 6,471 (6,134) 5.4 (5.1) 6,477 (6,139)

Combustion Air 72.1 (68.4) 72.1 (68.4)

Raw Water Makeup 130.3 (123.5) 130.3 (123.5)

Limestone 0.52 (0.49) 0.52 (0.49)

Totals 6,471 (6,134) 208.3 (197.4) 0.0 (0.0) 6,680 (6,331)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.6 (0.6) 0.6 (0.6)

Fly Ash + Gypsum 2.4 (2.2) 2.4 (2.2)

Flue Gas 325 (308) 325 (308)

CO 2 - 84 (

- 79)

- 84 (

- 79)

Cooling Tower * 2,777.1 (2,632.2) 2,777.1 (2,632.2)

Process Losses* * 1,677.9 (1,590.4) 1,677.9 (1,590.4)

Net Power 1,980 (1,877) 1,980

(1,877)

Totals 0.0 (0.0) 4,699 (4,454) 1,980 (1,877) 6,680

(6,331)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and Econamine cooling water. ** Process losses are estimated to match the heat input to the plant. Process losses include losses from: steam turbine, combustion reactions, gas cooling,

and Econamine steam.Carbon Dioxide Capture Sensitivity Analysis



### 106 Exhibit 3

- 30 Case 1D (85%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 6,859 (6,501) 5.7 (5.4) 6,865 (6,507)

Combustion Air 76.4 (72.5) 76.4 (72.5)

Raw Water Makeup 150.6 (142.7) 150.6 (142.7)

Limestone 0.56 (0.53) 0.56 (0.53)

Totals 6,859 (6,501) 233.3 (221.1) 0 (0) 7,092 (6,722)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.6 (0.6) 0.6 (0.6)

Fly Ash + Gypsum 2.5 (2.4) 2.5 (2.4)

Flue Gas 236 (224) 236 (224)

CO 2 - 108 (

- 102)

- 108 (

- 102)

Cooling Tower * 3,076.6 (2,916.1) 3,076.6 (2,916.1)

Process Losses* * 1,904.1 (1,804.8) 1,904.1 (1,804.8)

Net Power 1,980 (1,877) 1,980

(1,877)

Totals 5,112 (4,846) 1,980 (1,877) 7,092

(6,722)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and Econamine cooling water. ** Process losses are estimated to match the heat input to the plant.
Process losses include losses from: steam turbine, combustion reac tions, gas cooling,

and Econamine steam.Carbon Dioxide Capture Sensitivity Analysis



### 107 Exhibit 3

- 31 Case 1A Energy Balance Sankey Diagram

Exhibit 3

- 32 Case 1B Energy Balance Sankey DiagramCarbon Dioxide Capture Sensitivity Analysis



### 108 Exhibit 3

- 33 Case 1C Energy Balance Sankey Diagram

Exhibit 3

- 34 Case 1D Energy Balance Sankey DiagramCarbon Dioxide Capture Sensitivity Analysis



### 109 3.2.1.2 Major Equipment List for Cases 1A t hrough 1D

Major equipment items for the CO 2 

### capture bypass cases are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in t he cost estimates in Section 3.2.4 . In general

, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pu mps and fans.

ACCOUNT 1 FUEL AND SORBENT HANDLING

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

1 Bottom Trestle Dumper and

Receiving Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0)

3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

4 Transfer Tower No. 1 Enclosed N/A N/A N/A N/A 1 (0)

5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

6 As

- Received Coal Sampling

System Two

- stage N/A N/A N/A N/A 1 (0)

7 Stacker/Reclaimer Traveling Linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

8 Reclaim Hopper N/A 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 54 tonne (60 ton) 2 (1)

9 Feeder Vibratory 172 tonne/hr (190 tph) 181 tonne/hr (200 tph) 200 tonne/hr (220 tph) 209 tonne/hr (230 tph) 2 (1)

10 Conveyor No. 3 Belt w/tripper 345 tonne/hr (380 tph) 363 tonne/hr (400 tph) 390 tonne/hr (430 tph) 417 tonne/hr (460 tph) 1 (0)

11 Crusher Tower N/A N/A N/A N/A N/A 1 (0)

12 Coal Surge Bin w/ Vent

Filter Dual Outlet 172 tonne (190 ton) 181 tonne (200 ton) 200 tonne (220 ton) 209 tonne (230 ton) 2 (0)

13 Crusher Impactor

reduction 8 cm x 0

- 3 cm x 0 (3 in x 0

- 1

- 1/4 in x 0) 8 cm x 0

- 3 cm x 0 (3 in x 0

- 1

- 1/4 in x 0) 8 cm x 0

- 3 cm x 0 (3 in x 0

- 1

- 1/4 in x 0) 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 N/A N/A N/A 1 (1)

15 Conveyor No. 4 Belt w/tripper 345 tonne/hr (380 tph) 363 tonne/hr (400 tph) 390 tonne/hr (430 tph) 417 tonne/hr (460 tph) 1 (0)

16 Transfer Tower No. 2 Enclosed N/A N/A N/A N/A 1 (0)

17 Conveyor No. 5 Belt w/tripper 345 tonne/hr (380 tph) 363 tonne/hr (400 tph) 390 tonne/hr (430 tph) 417 tonne/hr (460 tph) 1 (0)

18 Coal Silo w/ Vent Filter and

Slide Gates Field Erected 726 tonne (800 ton) 816 tonne (900 ton) 907 tonne (1,000 ton) 907 tonne (1,000 ton) 3 (0)

19 Limestone Truck Unloading

Hopper N/A 36 tonne (40 ton) 36 tonne (40 ton) 36 tonne (40 ton) 36 tonne (40 ton) 1 (0)

20 Limestone Feeder Belt 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 100 tonne/hr (110 tph) 109 tonne/hr (120 tph) 1 (0)

21 Limestone Conveyor No. L1 Belt 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 100 tonne/hr (110 tph) 109 tonne/hr (120 tph) 1 (0)

22 Limestone Reclaim Hopper N/A 18 tonne (20 ton) 18 tonne (20 ton) 18 tonne (20 ton) 18 tonne (20 ton) 1 (0)

23 Limestone Reclaim Feeder Belt 73 tonne/hr (80 tph) 73 tonne/hr (80 tph) 82 tonne/hr (90 tph) 82 tonne/hr (90 tph) 1 (0)

24 Limestone Conveyor No. L2 Belt 73 tonne/hr (80 tph) 73 tonne/hr (80 tph) 82 tonne/hr (90 tph) 82 tonne/hr (90 tph) 1 (0)

25 Limestone Day Bin w/ actuator 281 tonne (310 ton) 299 tonne (330 ton) 318 tonne (350 ton) 336 tonne (370 ton) 2 (0)Carbon Dioxide Capture Sensitivity Analysis



### 110 ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

1 Coal Feeder Gravimetric 36 tonne/hr (40 tph) 36 tonne/hr (40 tph) 45 tonne/hr (50 tph) 45 tonne/hr (50 tph) 6 (0)

2 Coal Pulverizer Ball type or eq. 36 tonne/hr (40 tph) 36 tonne/hr (40 tph) 45 tonne/hr (50 tph) 45 tonne/hr (50 tph) 6 (0)

3 Limestone Weigh Feeder Gravimetric 23 tonne/hr (25 tph) 24 tonne/hr (27 tph) 26 tonne/hr (29 tph) 2 8 tonne/hr (3 1 tph) 1 (1)

4 Limestone Ball Mill Rotary 23 tonne/hr (25 tph) 24 tonne/hr (27 tph) 26 tonne/hr (29 tph) 2 8 tonne/hr (3 1 tph) 1 (1)

5 Limestone Mill Slurry

Tank with Agitator N/A 87,064 liters (23,000 gal) 94,635 liters (25,000 gal) 98,421 liters (26,000 gal) 105,992 liters (28,000 gal) 1 (1)

6 Limestone Mill Recycle

Pumps Horizontal centrifugal 1,476 lpm @ 12m H 2 O (390 gpm @ 40 ft H 2 O) 1,552 lpm @ 12m H 2 O (410 gpm @ 40 ft H 2 O ) 1,666 lpm @ 12m H 2 O (440 gpm @ 40 ft H 2 O) 1,779 lpm @ 12m H 2 O (470 gpm @ 40 ft H 2 O) 1 (1)

7 Hydroclone Classifier 4 active cyclones in a 5 cyclone bank 379 lpm (100 gpm) per cyclone 379 lpm (100 gpm) per cyclone 416 lpm (110 gpm) per cyclone 454 lpm (120 gpm) per cyclone 1 (1)

8 Distribution Box 2

- way N/A N/A N/A N/A 1 (1)

9 Limestone Slurry Storage

Tank with Agitator Field erected 499,674 liters (13 2 ,000 gal) 533,743 liters (14 1 ,000 gal) 571,597 liters (151,000 gal) 609,451 liters (1 61 ,000 gal) 1 (1)

10 Limestone Slurry Feed

Pumps Horizontal centrifugal 1,022 lpm @ 9m H 2 O (270 gpm @ 30 ft H 2 O) 1,098 lpm @ 9m H 2 O (290 gpm @ 30 ft H 2 O ) 1,173 lpm @ 9m H 2 O (310 gpm @ 30 ft H 2 O) 1,249 lpm @ 9m H 2 O (330 gpm @ 30 ft H 2 O) 1 (1)



### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

1 Demineralized Water

Storage Tank Vertical, cylindrical,

outdoor 1,20 3,761 liters (31 8 ,000 gal) 1,290,825 liters (341,000 gal) 1,385,461 liters (366,000 gal) 1,468,740 liters (388,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 20,820 lpm @ 213 m H 2 O (5,500 gpm @ 700 ft H 2 O) 19,684 lpm @ 213 m H 2 O (5,200 gpm @ 700 ft H 2 O) 18,549 lpm @ 213 m H 2 O (4,900 gpm @ 700 ft H 2 O) 17,413 lpm @ 213 m H 2 O (4,600 gpm @ 700 ft H 2 O) 1 (1)

3 Deaerator and Storage

Tank Horizontal spray
type 2,00 4,878 kg/hr (4,42 0 ,000 lb/hr), 5 min. tank 2,14 5,946 kg/hr (4,73 1 ,000 lb/hr), 5 min. tank 2,30 5,610 kg/hr (5,08 3 ,000 lb/hr), 5 min. tank 2,443

, 502 kg/hr (5,38 7 ,000 lb/hr), 5 min. tank 1 (0)

4 Boiler Feed

Pump/Turbine Barrel type, multi

stage, centrifugal 33,690 lpm @ 3,505 m H 2 O (8,900 gpm @ 11,500 ft H 2 O) 35,961 lpm @ 3,505 m H 2 O (9,500 gpm @ 11,500 ft H 2 O) 38,611 lpm @ 3,505 m H 2 O (10,200 gpm @ 11,500 ft

H 2 O) 40,882 lpm @ 3,505 m H 2 O

(10,800 gpm @ 11,500 ft

H 2 O) 1 (1)

5 Startup Boiler Feed

Pump, Electric Motor

Driven Barrel type, multi

stage, centrifugal 9,842 lpm @ 3,505 m H 2 O (2, 6 00 gpm @ 11,500 ft H 2 O) 10,599 lpm @ 3,505 m H 2 O (2,800 gpm @ 11,500 ft H 2 O) 11,356 lpm @ 3,505 m H 2 O (3,000 gpm @ 11,500 ft H 2 O) 12,113 lpm @ 3,505 m H 2 O (3,200 gpm @ 11,500 ft

H 2 O) 1 (0)

6 LP Feedwater Heater

1A/1B Horizontal U

- tube 625,957 kg/hr (1,380,000 lb/hr) 589,670 kg/hr (1,300,000 lb/hr) 548,847 kg/hr (1,210,000 lb/hr) 517,095 kg/hr (1,140,000 lb/hr) 2 (0)

7 LP Feedwater Heater

2A/2B Horizontal U

- tube 625,957 kg/hr (1,380,000 lb/hr) 589,670 kg/hr (1,300,000 lb/hr) 548,847 kg/hr (1,210,000 lb/hr) 517,095 kg/hr (1,140,000 lb/hr) 2 (0)

8 LP Feedwater Heater

3A/3B Horizontal U

- tube 625,957 kg/hr (1,380,000 lb/hr) 589,670 kg/hr (1,300,000 lb/hr) 548,847 kg/hr (1,210,000 lb/hr) 517,095 kg/hr (1,140,000 lb/hr) 2 (0)

9 LP Feedwater Heater

4A/4B Horizontal U

- tube 625,957 kg/hr (1,380,000 lb/hr) 589,670 kg/hr (1,300,000 lb/hr) 548,847 kg/hr (1,210,000 lb/hr) 517,095 kg/hr (1,140,000 lb/hr) 2 (0)

10 HP Feedwater Heater

6 Horizontal U

- tube 2,004,878 kg/hr (4,420,000 lb/hr) 2,1 45,492 kg/hr (4,7 3 0,000 lb/hr) 2,30 4,249 kg/hr (5,0 8 0,000 lb/hr) 2,444,863 kg/hr (5,390,000 lb/hr) 1 (0)

11 HP Feedwater Heater

7 Horizontal U

- tube 2,004,878 kg/hr (4,420,000 lb/hr) 2,1 45,492 kg/hr (4,7 3 0,000 lb/hr) 2,30 4,249 kg/hr (5,0 8 0,000 lb/hr) 2,444,863 kg/hr (5,390,000 lb/hr) 1 (0)

12 HP Feedwater heater 8 Horizontal U

- tube 2,004,878 kg/hr (4,420,000 lb/hr) 2,1 45,492 kg/hr (4,7 3 0,000 lb/hr) 2,30 4,249 kg/hr (5,0 8 0,000 lb/hr) 2,444,863 kg/hr (5,390,000 lb/hr) 1 (0)Carbon Dioxide Capture Sensitivity Analysis



### 111 Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

13 Auxiliary Boiler Shop fabricated,

water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa,

343°C (40,000 lb/hr, 400 psig, 650°F) 1 (0)

14 Fuel Oil System No. 2 fuel oil for light off 1,135,624 liter (300,000 gal) 1,135,624 liter (300,000 gal) 1,135,624 liter (300,000 gal) 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) 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 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) 28 m 3 /min (1,000 scfm) 28 m 3 /min (1,000 scfm) 28 m 3 /min (1,000 scfm) 2 (1)

17 Closed Cycl e Cooling

Heat Exchangers Shell and tube 53 GJ/hr (50 MMBtu/hr)

each 53 GJ/hr (50 MMBtu/hr)

each 53 GJ/hr (50 MMBtu/hr)

each 53 GJ/hr (50 MMBtu/hr)

each 2 (0)

18 Closed Cycle Cooling

Water Pumps Horizontal centrifugal 20,820 lpm @ 30 m H 2 O (5,500 gpm @ 100 ft H 2 O) 20,820 lpm @ 30 m H 2 O (5,500 gpm @ 100 ft H 2 O) 20,820 lpm @ 30 m H 2 O (5,500 gpm @ 100 ft H 2 O) 20,820 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) 3,785 lpm @ 88 m H 2 O (1,000 gpm @ 290 ft H 2 O) 3,785 lpm @ 88 m H 2 O (1,000 gpm @ 290 ft H 2 O) 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) 2,650 lpm @ 64 m H 2 O (700 gpm @ 210 ft H 2 O) 2,650 lpm @ 64 m H 2 O (700 gpm @ 210 ft H 2 O) 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 12, 870 lpm @ 43 m H 2 O (3,4 0 0 gpm @ 140 ft H 2 O) 14, 763 lpm @ 43 m H 2 O (3,9 0 0 gpm @ 140 ft H 2 O) 17,1 48 lpm @ 43 m H 2 O (4,5 3 0 gpm @ 140 ft H 2 O) 19,268 lpm @ 43 m H 2 O (5,090 gpm @ 140 ft H 2 O) 2 (1)

22 Filtered Water Pumps Stainless steel, single suction 568 lpm @ 49 m H 2 O (150 gpm @ 160 ft H 2 O) 644 lpm @ 49 m H 2 O (170 gpm @ 160 ft H 2 O) 719 lpm @ 49 m H 2 O (190 gpm @ 160 ft H 2 O) 757 lpm @ 49 m H 2 O (200 gpm @ 160 ft H 2 O) 2 (1)

23 Filtered Water Tank Vertical, cylindrical 560,241 liter (148,000 gal) 598,095 liter (1 58 ,000 gal) 681,374 liter (180,000 gal) 719,228 liter (190,000 gal) 1 (0)

24 Makeup Water

Demineralizer Multi

- media filter, cartridge filter, RO

membrane assembly,

electrodeionization

unit 719 lpm (190 gpm) 795 lpm (210 gpm) 871 lpm (230 gpm) 946 lpm (250 gpm) 1 (1)

25 Liquid Waste

Treatment System -- 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 1 (0)



### ACCOUNT 4 BOILER AND ACCESSORIES

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

1 Boiler Supercritical, drum,

wall

- fired, low NOx
burners, overfire air 2,004,878 kg/hr steam @

25.5 MPa/602°C/602°C (4,420,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 2,145,492 kg/hr steam @

25.5 MPa/602°C/602°C (4,730,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 2,304,249 kg/hr steam @

25.5 MPa/602°C/602°C (5,080,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 2,444,863 kg/hr steam @

25.5 MPa/602°C/602°C (5,390,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 1 (0)

2 Primary Air Fan Centrifugal 262,630 kg/hr, 3,585 m 3 /min @ 123 cm WG (579,000
lb/hr, 126,600 acfm @ 48 in.

WG) 281,227 kg/hr, 3,840 m 3 /min @ 123 cm WG (620,000
lb/hr, 135,600 acfm @ 48 in.

WG) 302,546 kg/hr, 4,126 m 3 /min @ 123 cm WG (667,000
lb/hr, 145,700 acfm @ 48 in.

WG) 320,236 kg/hr, 4,372 m 3 /min

@ 123 cm WG (706,000
lb/hr, 154,400 acfm @ 48 in.

WG) 2 (0)

3 Forced Draft Fan Centrifugal 855,475 kg/hr, 11,672 m 3 /min @ 51 cm WG (1,886,000 lb/hr, 412,200 acfm @ 20 in.

WG) 915,803 kg/hr, 12,496 m 3 /min

@ 51 cm WG (2,019,000 lb/hr, 441,300 acfm @ 20 in.

WG) 984,295 kg/hr, 13,425 m 3 /min

@ 51 cm WG (2,170,000 lb/hr, 474,100 acfm @ 20 in.

WG) 1,043,262 kg/hr, 14,232

m 3 /min @ 51 cm WG (2,300,000 lb/hr, 502,600 acfm @ 20 in. WG) 2 (0)

4 Induced Draft Fan Centrifugal 1,243,750 kg/hr, 26,618

m 3 /min @ 91 cm WG (2,742,000 lb/hr, 940,000 acfm @ 36 in. WG) 1,331,294 kg/hr, 28,495

m 3 /min @ 91 cm WG (2,935,000 lb/hr, 1,006,300 acfm @ 36 in. WG) 1,430,630 kg/hr, 30,619

m 3 /min @ 91 cm WG (3,154,000 lb/hr, 1,081,300 acfm @ 36 in. WG) 1,516,359 kg/hr, 32,454

m 3 /min @ 91 cm WG (3,343,000 lb/hr, 1,146,100 acfm @ 36 in. WG) 2 (0)Carbon Dioxide Capture Sensitivity Analysis



### 112 Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

5 SCR Reactor Vessel Space for spare layer 2,485,686 kg/hr (5,480,000 lb/hr) 2,662,587 kg/hr (5,870,000 lb/hr) 2,862,168 kg/hr (6,310,000 lb/hr) 3,034,533 kg/hr (6,690,000 lb/hr) 2 (0)

6 SCR Catalyst

-- -- -- -- -- 3 (0)

7 Dilution Air Blower Centrifugal 45 m 3 /min @ 108 cm WG (1,600 acfm @ 42 in. WG) 48 m 3 /min @ 108 cm WG (1,700 acfm @ 42 in. WG) 51 m 3 /min @ 108 cm WG (1,800 acfm @ 42 in. WG) 54 m 3 /min @ 108 cm WG (1,900 acfm @ 42 in. WG) 2 (1)

8 Ammonia Storage Horizontal tank 49,210 liter (13,000 gal) 52,996 liter (14,000 gal) 56,781 liter (15,000 gal) 60,567 liter (16,000 gal) 5 (0)

9 Ammonia Feed Pump Centrifugal 9 lpm @ 91 m H 2 O (2 gpm @ 300 ft H 2 O) 10 lpm @ 91 m H 2 O (3 gpm @ 300 ft H 2 O) 11 lpm @ 91 m H 2 O (3 gpm @ 300 ft H 2 O) 11 lpm @ 91 m H 2 O (3 gpm @ 300 ft H 2 O) 2 (1)



### ACCOUNT 5 FLUE GAS CLEANUP

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

1 Fabric Filter Single stage, high

- ratio with pulse

- jet online cleaning
system 1,243,750 kg/hr (2,742,000 lb/hr) 99.8% efficiency 1,331,294 kg/hr (2,935,000 lb/hr) 99.8% efficiency 1,430,630 kg/hr (3,154,000 lb/hr) 99.8% efficiency 1,516,359 kg/hr (3,343,000 lb/hr) 99.8% efficiency 2 (0)

2 Absorber Module Counter

- current open spray 41,059 m 3 /min (1,450,000 acfm) 43,948 m 3 /min (1,552,000 acfm) 47,233 m 3 /min (1,668,000 acfm) 50,064 m 3 /min (1,768,000 acfm) 1 (0)

3 Recirculation Pumps Horizontal centrifugal 143,846 lpm @ 64 m H 2 O (38,000 gpm @ 210 ft H 2 O) 151,416 lpm @ 64 m H 2 O (40,000 gpm @ 210 ft H 2 O) 162,773 lpm @ 64 m H 2 O (43,000 gpm @ 210 ft H 2 O) 174,129 lpm @ 64 m H 2 O (46,000 gpm @ 210 ft H 2 O) 5 (1)

4 Bleed Pumps Horizontal centrifugal 4,505 lpm (1,190 gpm) at

20 wt% solids 4,807 lpm (1,270 gpm) at

20 wt% solids 5,148 lpm (1,360 gpm) at

20 wt% solids 5,489 lpm (1,450 gpm) at

20 wt% solids 2 (1)

5 Oxidation Air Blowers Centrifugal 184 m 3 /min @ 0.3 MPa (6,500 acfm @ 42 psia) 194 m 3 /min @ 0.3 MPa (6,860 acfm @ 42 psia) 211 m 3 /min @ 0.3 MPa (7,440 acfm @ 42 psia) 224 m 3 /min @ 0.3 MPa (7,910 acfm @ 42 psia) 2 (1)

6 Agitators Side entering 50 hp 50 hp 50 hp 50 hp 5 (1)

7 Dewatering Cyclones Radial assembly, 5 units

each 1,136 lpm (300 gpm) per cyclone 1,211 lpm (320 gpm) per cyclone 1,287 lpm (340 gpm) per cyclone 1,363 lpm (360 gpm) per cyclone 2 (0)

8 Vacuum Filter Belt Horizontal belt 35 tonne/hr (39 tph) of 50 wt % slurry 38 tonne/hr (42 tph) of 50 wt % slurry 41 tonne/hr (45 tph) of 50 wt % slurry 44 tonne/hr (48 tph) of 50 wt % slurry 2 (1)

9 Filtrate Water Return

Pumps Horizontal centrifugal 681 lpm @ 12 m H 2 O (180 gpm @ 40 ft H 2 O) 719 lpm @ 12 m H 2 O (190 gpm @ 40 ft H 2 O) 795 lpm @ 12 m H 2 O (210 gpm @ 40 ft H 2 O) 833 lpm @ 12 m H 2 O (220 gpm @ 40 ft H 2 O) 1 (1)

10 Filtrate Water Return

Storage Tank Vertical, lined 454,249 lpm (120,000 gal) 492,104 lpm (130,000 gal) 529,958 lpm (140,000 gal) 529,958 lpm (140,000 gal) 1 (1)

11 Process Makeup

Water Pumps Horizontal centrifugal 454 lpm @ 21 m H 2 O (120 gpm @ 70 ft H 2 O) 492 lpm @ 21 m H 2 O (130 gpm @ 70 ft H 2 O) 530 lpm @ 21 m H 2 O (140 gpm @ 70 ft H 2 O) 568 lpm @ 21 m H 2 O (150 gpm @ 70 ft H 2 O) 1 (1)Carbon Dioxide Capture Sensitivity Analysis



### 113 ACCOUNT 5B CARBON DIOXIDE RECOVERY

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D*

1 Econamine FG Plus Amine

- based CO 2 capture technology 876,340 kg/h (1,932,000 lb/h) 20.6 wt % CO 2 concentration 1,566,708 kg/h (3,454,000 lb/h) 20.6 wt % CO 2 concentration 2,355,505 kg/h (5,193,000 lb/h) 20.6 wt % CO 2 concentration 1,514,999 kg/h (3 ,340,000 lb/h) 20.6 wt % CO 2 concentration 1 (0)

2 Econamine Condensate

Pump Centrifugal 3,899 lpm @ 52 m H 2 O (1,030 gpm @ 170 ft H 2 O) 7,003 lpm @ 52 m H 2 O (1,850 gpm @ 170 ft H 2 O) 10,448 lpm @ 52 m H 2 O (2,760 gpm @ 170 ft H 2 O) 13,438 lpm @ 52 m H 2 O (3,550 gpm @ 170 ft H 2 O) 1 (1)

3 CO 2 Compressor Centrifugal 161,385 kg/h @ 15.3 MPa (355,793 lb/h @ 2,215 psia) 290,084 kg/h @ 15.3 MPa (639,526 lb/h @ 2,215 psia) 434,206 kg/h @ 15.3 MPa (957,260 lb/h @ 2,215 psia) 279,530 kg/h @ 15.3 MPa (616,257 lb/h @ 2,215 psia) 1 (0)

* Case 1D is equipped with two operating CO 2 absorption and compression trains, which is reflected in the design conditions.



### ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES

N/A

ACCOUNT 7 DUCTING AND STACK

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

1 Stack Reinforced concrete with FRP liner 152 m (500 ft) high x

5. 7 m (1 9 ft) diameter 152 m (500 ft) high x

5. 6 m (1 9 ft) diameter 152 m (500 ft) high x
5.6 m ( 18 ft) diameter 152 m (500 ft) high x

5.6 m ( 18 ft) diameter 

### 1 (0)

ACCOUNT 8 STEAM TURBINE GENERATOR

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

1 Steam Turbine

Generator Commercially available,

advanced steam turbine 633 MW

24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 651 MW

24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 671 MW

24.1 MPa/593°C/593 °C (3500 psig/ 1100°F/1100°F) 689 MW

24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 

### 1 (0)

2 Steam Turbine

Generator Hydrogen cooled, static

excitation 700 MVA @ 0.9 p.f., 24 kV,

60 Hz, 3

- phase 720 MVA @ 0.9 p.f., 24 kV,

60 Hz, 3

- phase 750 MVA @ 0.9 p.f., 24 kV,

60 Hz, 3

- phase 770 MVA @ 0.9 p.f., 24

kV, 60 Hz, 3

- phase 

### 1 (0)

3 Surface Condenser Single pass, divided waterbox including vacuum

pumps 2,384 GJ/hr (2,260 MMBtu/hr), Inlet water temperature 16°C (60°F),

Water temperature rise 11°C

(20°F) 2,237 GJ/hr (2,120 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C

(20°F) 2,089 GJ/hr (1,980 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C

(20°F) 1,962 GJ/hr (1,860

MMBt u/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 

### 1 (0)Carbon Dioxide Capture Sensitivity Analysis



### 114 ACCOUNT 9 COOLING WATER SYSTEM

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

1 Circulating Water

Pumps Vertical, wet pit 583,000 lpm @ 30 m (154,000 gpm @ 100 ft) 673,800 lpm @ 30 m (178,000 gpm @ 100 ft) 829,000 lpm @ 30 m (219,000 gpm @ 100 ft) 965,300 lpm @ 30 m (255,000 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 / 3260 GJ/hr (3090 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 3756 GJ/hr (3560 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 4621 GJ/hr (4380 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 5370 GJ/hr (5090 MMBtu/hr) heat duty 1 ( 0 )



### ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

1 Economizer Hopper (part of boiler scope

of supply) -- -- -- -- -- 4 (0)

2 Bottom Ash Hopper (part of boiler scope of

supply) -- -- -- -- -- 2 (0)

3 Clinker Grinder

-- 4.5 tonne/hr (5 tph) 4.5 tonne/hr (5 tph) 5.4 tonne/hr (6 tph) 5.4 tonne/hr (6 tph) 1 (1)

4 Pyrites Hopper (part of pulverizer scope of

supply included with boiler) -- -- -- -- -- 6 (0)

5 Hydroejectors

-- -- -- -- -- 12 (0)

6 Economizer/Pyrites Transfer Tank

-- -- -- -- -- 1 (0)

7 Ash Sluice Pumps Vertical, wet pit 189 lpm @ 17 m H 2 O (50 gpm @ 56 ft H 2 O) 189 lpm @ 17 m H 2 O (50 gpm @ 56 ft H 2 O) 189 lpm @ 17 m H 2 O (50 gpm @ 56 ft H 2 O) 227 lpm @ 17 m H 2 O (60 gpm @ 56 ft H 2 O) 1 (1)

8 Ash Seal Water Pumps Vertical, wet pit 7,571 lpm @ 9 m H 2 O (2000 gpm @ 28 ft H 2 O) 7,571 lpm @ 9 m H 2 O (2000 gpm @ 28 ft H 2 O) 7,571 lpm @ 9 m H 2 O (2000 gpm @ 28 ft H 2 O) 7,571 lpm @ 9 m H 2 O (2000 gpm @ 28 ft H 2 O) 1 (1)

9 Hydrobins

-- 189 lpm (50 gpm) 189 lpm (50 gpm) 189 lpm (50 gpm) 227 lpm (60 gpm) 1 (1)

10 Baghouse Hopper (part of baghouse

scope of supply) --

-- -- -- -- 24 (0)

11 Air Heater Hopper (part of boiler scope of

supply) --

-- -- -- -- 10 (0)

12 Air Blower

-- 16 m 3 /min @ 0.2 MPa (570 scfm @ 24 psi) 17 m 3 /min @ 0.2 MPa (610 scfm @ 24 psi) 1 9 m 3 /min @ 0.2 MPa (6 6 0 scfm @ 24 psi) 20 m 3 /min @ 0.2 MPa (690 scfm @ 24 psi) 1 (1)

13 Fly Ash Silo Reinforced

concrete 544 tonne (1,200 ton) 5 90 tonne (1, 3 00 ton) 590 tonne (1,300 ton) 635 tonne (1,400 ton) 2 (0)

14 Slide Gate Valves

-- -- -- -- -- 2 (0)

15 Unloader

-- -- -- -- -- 1 (0)

16 Telescoping Unloading Chute

-- 100 tonne/hr (110 tph) 109 tonne/hr (120 tph) 1 18 tonne/hr (1 3 0 tph) 118 tonne/hr (130 tph) 1 (0)Carbon Dioxide Capture Sensitivity Analysis



### 115 ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

1 STG Transformer Oil

- filled 24 kV/345 kV, 650 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 650 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 650 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 650 MVA,

3

- ph, 60 Hz 1 (0)

2 Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 55 MVA,

3

- ph, 60 Hz 24 kV/4.16 kV, 7 4 MVA,

3

- ph, 60 Hz 24 kV/4.16 kV, 9 5 MVA,

3

- ph, 60 Hz 24 kV /4.16 kV, 114
MVA, 3

- ph, 60 Hz 1 (1)

3 L ow V oltage Transformer Dry ventilated 4.16 kV/480 V, 8 MVA,

3

- ph, 60 Hz 4.16 kV/480 V, 11 MVA,

3

- ph, 60 Hz 4.16 kV/480 V, 14 MVA,

3

- ph, 60 Hz 4.16 kV/480 V, 17 MVA,

3

- ph, 60 Hz 1 (1)

4 STG Isolated Phase Bus Duct

and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 1 (0)

5 Medium Voltage Switchgear Metal Clad 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 1 (1)

6 Low Voltage Switchgear Metal Enclosed 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 1 (1)

7 Emergency Diesel Generator Sized for emergency

shutdown 750 kW, 480 V, 3

- ph, 60

Hz 750 kW, 480 V, 3

- ph, 60

Hz 750 kW, 480 V, 3

- ph, 60

Hz 750 kW, 480 V, 3

- ph, 60

Hz 1 (0)



### ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

1 DCS

- Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator Stations/Printers and Engineering

Stations/Printers Operator Stations/Printers and Engineering

Stations/Printers Operator Stations/Printers and Engineering

Stations/Printers Operator Stations/Printers and Engineering

Stations/Printers 1 (0)

2 DCS

- Processor Microprocessor with redundant input/output N/A N/A N/A N/A 1 (0)

3 DCS

- Data Highway Fiber optic Fully redundant,

25% spare Fully redundant,

25% spare Fully redundant,

25% spare Fully redundant,

25% spare 1 (0)Carbon Dioxide Capture Sensitivity Analysis



### 116 This page intentionally left blankCarbon Dioxide Capture Sensitivity Analysis



### 117 

## 3.2.2 Full CO 2 

## Capture Performance Results

A process block flow diagram for Cases 1 E through 1G is shown in Exhibit 3

- 35 . These cases represent supercritical steam cycles with CO 2 

### capture ranging from 90 percent to 99 percent

. The corresponding stream tables are contained in Exhibit 3

- 36

, Exhibit 3

- 37 , and Exhibit 3

- 38

for 90 percent , 95 percent , and 99 percent CO 2 

### capture, respectively.

Overall performance for Cases 1E through 1G is summarized i n Exhibit 3

- 39 which includes auxiliary power requirements.

Material and energy balance information, environmental performance and a major e quipment list

are summarized in Sections 3.2.2.1 and 3.2.2.2

.Carbon Dioxide Capture Sensitivity Analysis



### 118 Exhibit 3

- 35 Cases 1E through 1G Process Block Flow Diagram, Supercritical PC with CO 2 CaptureCarbon Dioxide Capture Sensitivity Analysis



### 119 Exhibit 3

- 36 Case 1E Stream Table, Supercritical PC with 90% CO 2 CaptureCarbon Dioxide Capture Sensitivity Analysis



### 120 Exhibit 3

- 36 Case 1E Stream Table, Supercritical PC with 90% CO 2 Capture (continued)Carbon Dioxide Capture Sensitivity Analysis



### 121 Exhibit 3

- 37 Case 1F Stream Table, Supercritical PC with 95% CO 2 CaptureCarbon Dioxide Capture Sensitivity Analysis



### 122 Exhibit 3

- 37 Case 1F Stream Table, Supercritical PC with 95% CO 2 Capture (continued)Carbon Dioxide Capture Sensitivity Analysis



### 1 23 Exhibit 3

- 38 Case 1G Stream Table, Supercritical PC with 99% CO 2 C aptureCarbon Dioxide Capture Sensitivity Analysis



### 124 Exhibit 3

- 38 Case 1G Stream Table, Supercritical PC with 99% CO2 Capture (continued)Carbon Dioxide Capture Sensitivity Analysis



### 125 Exhibit 3

- 39 Cases 1E through 1G Performance Modeling Results

POWER SUMMARY (Gross Power at Generator

Terminals, kWe) Case 1 E ( 9 0%) Case 1 F ( 95 %) Case 1 G ( 99 %)

Steam Turbine Power 661,300 667,900 679,600

AUXILIARY LOAD SUMMARY, kWe 1

Coal Handling and Conveying 5 1 0 510 540

Limestone Handling & Reagent Preparation 1,2 6 0 1,290 1,3 8 0

Pulverizers 3,8 7 0 3,9 8 0 4,2 5 0

Ash Handling 7 4 0 7 6 0 8 1 0

Primary Air Fans 1, 81 0 1,8 6 0 1,9 9 0

Forced Draft Fans 2, 31 0 2,3 7 0 2,5 3 0

Induced Draft Fans 10,000 10, 26 0 10, 92 0

SCR 20 20 20

Baghouse 100 100 110

FGD Pumps and Agitators 4, 13 0 4, 24 0 4, 54 0

Econamine FG Plus Auxiliaries 20, 7 00 22, 4 00 2 5,0 00

CO 2 Compression 4 4,39 0 48,080 53, 610

Econamine Condensate Pump 160 170 2 3 0

Miscellaneous Balance of Plant 2 2,000 2,000 2,000

Steam Turbine Auxiliaries 400 400 400

Condensate Pumps 5 8 0 5 5 0 4 7 0

Circulating Water Pumps 10,120 10,480 11,620

Cooling Tower Fans 5, 91 0 6,150 6,820

Transformer Loss 2,2 8 0 2,3 2 0 2,3 9 0

TOTAL AUXILIARIES, kWe 111,290 117,940 129,630

NET POWER, kWe 550,010 549,960 549,970

Net Plant Efficiency, % (HHV) 28.2% 27.5% 25.7%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 12,748 (12,083) 13,083 (12,400) 14,000 (13,269)

CONDENSER COOLING DUTY GJ/hr (10 6 Btu/hr) 1,735 (1,645) 1,665 (1,578) 1,400 (1,327)

CONSUMABLES

As

- Received Coal Feed, kg/hr (lb/hr) 3 258,399 (569,672) 265,160 (584,578) 283,750 (625,561)

Thermal Input, kWt 1,947,689 1,998,654 2,138,774

Raw Water Withdrawal , m 3 /min (gpm) 38.2 (10,095) 39.8 (10,512) 44.2 (11,664)

Raw Water Consumption

, m 3 /min (gpm) 29.3 (7,753) 30.6 (8,074) 33.9 (8,961)

Notes: 1. Boiler feed pumps are turbine driven

2. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

3. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)Carbon Dioxide Capture Sensitivity Analysis



### 126 3.2.2.1 Environmental Performance for Cases 1E t hrough 1G

Each case was designed to meet presumptive BACT standards utilizing the emissions control processes described in Section 2.4 . A summary of plant air emissions for Case 1E (90 percent ),
1F (95 percent ), and 1G (99 percent ) is presented in Exhibit 3

- 40

.

SO 2 

### emissions are controlled using a wet limestone forced oxidation FGD that achieves a removal efficiency of 98 percent . To avoid the formation of heat stable salts in the Econ amine

process, an SO 2 

### polishing step is included to reduce the sulfur content to 10 ppm prior to the CO 2 

### absorber

, and the balance of the SO 2 

### is absorbed by the MEA solution resulting in negligible stack emissions. The byproduct calcium sulfate is dewater ed 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 FGD is vented through the plant stack

.

Particulate emissions are controlled using a pulse jet fabric filter (baghouse) which operates at an efficiency of 99.8 percent . It was assumed that 20 percent of the ash exits the boiler as bottom ash and the remaining 80 percent exits the boiler in th e flue gas [ 41 ].

Co

- benefit capture of Hg in the fabric filter and FGD system was assumed to achieve a 90

percent capture rate [ 42 ]. The high chlorine content of the Illinois No. 6 coal and the SCR system will convert most of the Hg in the system to an oxidized state [ 43 ] . An inexpensive FGD

system additive can be used to promote Hg capture if necessary, but was not included

.

The carbon balance for the three cases is shown in Exhibit 3

- 41

. The carbon input to the plant

consists of carbon in the coal, limestone, and combustion and FGD forced oxidation air.

CO 2 

### capture efficiency is calculated as the pou nds of CO 2 

### captured divided by the pounds of CO 2 

### produced. Most of the CO 2 

### produced comes from coal combustion, but a small amount is

formed in th e FGD system. The sum of these two sources is the amount produced.

(Carbon in Sequestration Product) / (Carbon in the Coal + Net Carbon from Limestone) or

3 32,243 / (3 63,136 + 5, 242 ) *100 = 90% (Case 1E)

35 9,878 / (3 72,638 + 5,378 ) *100 = 95% (Case 1F)

401,323 / ( 398,762 + 5,756 ) *10 0 = 99% (Case 1G)

Exhibit 3

- 42 shows the sulfur balance for the three cases. Sulfur input comes solely from the sulfur in the coal. Sulfur output is the gypsum sulfur byproduct, and the sulfur emitted in the stack gas. The total sulfur capture is represented by the following fraction:

(Sulfur byproduct/Sulfur in the coal) or
(13,993/14,278)*100 = 98.0% (Case 1E)
(14,359/14,652)*100 = 98.0% (Case 1F)
(15,366/15,679)*100 = 98.0% (Case 1G)

The overall water balance s for C ase 1E, 1G, and 1F are shown in Exhibit 3

- 43

, Exhibit 3

- 44 , and

Exhibit 3

- 45 , respectively. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water d emand represents the total amount of water req uired for a particular process. Some water is recovered within t he process and that water is re used asCarbon Dioxide Capture Sensitivity Analysis



### 127 internal recycle. Raw water withdrawal is the difference between water demand and internal recycle. Proc ess water discharged from the power plant is also account ed for in this study. Raw water consumption represents raw water withdrawal less process water discharge.

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3

- 46 through

Exhibit 3

- 51

.

Boiler and flue gas cleanup

Steam and feedwater

An overall plant energy balance is provided in tabular form for Case 1E, 1F, and 1G in

Exhibit 3

- 52

, Exhibit 3

- 53 , and Exhibit 3

- 54 , respectively. The power out is the steam turbine power after generator losses. In addition, energy balance Sankey diagrams are provided in

Exhibit 3

- 55

, Exhibit 3

- 56 , and Exhibit 3

- 57 for Case 1E, 1F, and 1G, respectively.Carbon Dioxide Capture Sensitivity Analysis



### 128 Exhibit 3

- 40 Cases 1E through 1G Estimated Air Emission Rates

kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh )

Case 1E Case 1F Case 1G Case 1E Case 1F Case 1G Case 1E Case 1F Case 1G

SO 2 0.007

(0.017) 0.007

(0.016) 0.007

(0.016) 372

(410) 378 (417) 402 (443) 0.076 (0.170) 0.076 (0.170) 0.079 (0.170)

NO X 0.030

(0.070) 0.030

(0.070) 0.030

(0.070) 1,571

(1,732) 1,612

(1,777) 1,725 (1,902) 0.319 (0.703) 0.324 (0.715) 0.341 (0.752)

PM 0.006

(0.013) 0.006

(0.013) 0.006

(0.013) 292

(322) 299 (330) 320 (353) 0.059 (0.131) 0.060 (0.133) 0.063 (0.140)

Hg 0.49x10 - 6

(1.14x10 - 6 ) 0.49x10 - 6

(1.14x10 - 6 ) 0.49x10 - 6

(1.14x10 - 6 ) 0.026

(0.028) 0.026

(0.029) 0.028 (0.031) 5.21x10 - 6

(11.5x10 - 6 ) 5.29x10 - 6

(11.7x10 - 6 ) 5.57x10 - 6

(12.3x10 - 6 )

CO 2 8.8

(20.4) 4.4

(10.2) 0.9

(2.0) 456,848

(503,588) 234,401

(258,383) 50,167

(55,299) 93

(205) 47

(104) 10

(22)

CO 2 net 112 (246) 57 (126) 12 (27)Carbon Dioxide Capture Sensitivity Analysis



### 129 Exhibit 3

- 41 Cases 1E through 1G Carbon Balance

Carbon In, kg/hr (lb/hr)

Case 1E Case 1F Case 1G

Coal 164,716

(363,136) 169,026

(372,638) 180,876

(398,762)

Air (CO 2 ) 352 (775) 361 (795) 386 (851)

Limestone 2,652 (5,848) 2,724 (6,005) 2,906 (6,406)

Total 167,720

(369,759) 172,110

(379,438) 184,168

(406,019)

Carbon Out, kg/hr (lb/hr)

Stack Gas 16,745

(36,916) 8,591

(18,941) 1,839 (4,054)

CO 2 Product 150,703

(332,243) 163,238

(359,878) 182,037

(401,323)

Gypsum 275 (606) 284 (627) 295 (650)

Convergence

Tolerance* - 3 (

- 6)

- 3 (

- 7)

- 3 (

- 7)

Total 167,720

(369,759) 172,110

(379,438) 184,168

(406,019)

Exhibit 3

- 42 Cases 1E through 1G Sulfur Balance

Sulfur In, kg/hr (lb/hr)

Case 1E Case 1F Case 1G

Coal 6,4 77 (14, 278 ) 6,646 (14,652) 7,112 (15,679)

Total 6,4 77 (14, 278 ) 6, 646 (14, 652 ) 7, 112 (15, 679 )

Sulfur Out, kg/hr (lb/hr)

Gypsum 6,347 (13,993) 6,513 (14,359) 6,970 (15,366)

Stack Gas 25 (55) 25 (56) 27 (60)

AGR 104 (230) 107 (237) 115 (254)

Convergence

Tolerance* 1 (0) 1 (0) 0 (

- 1)

Total 6,4 77 (14, 278 ) 6, 646 (14, 652 ) 7, 112 (15, 679 )Carbon Dioxide Capture Sensitivity Analysis



### 130 Exhibit 3

- 43 Case 1E (90%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Econamine 0.14 (36) 0.0 (0) 0.14 (36) 0.0 (0) 0.14 (36)

FGD Makeup 5.16 (1,363) 0.0 (0) 5.16 (1,363) 0.0 (0) 5.16 (1,363)

BFW Makeup 0.38 (100) 0.0 (0) 0.38 (100) 0.0 (0) 0.38 (100)

Cooling Tower Makeup 39.4 (10,415) 6.88 (1,818) 32.5 (8,597) 8.87 (2,342) 23.7 (6,254)

Total 45.1 (11,914) 6.88 (1,818) 38.2 (10,095) 8.87 (2,342) 29.3 (7,753)

Total, gal/MWh net 1,300 198 1,101 256 846

Exhibit 3

- 44 Case 1F (95%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Econamine 0.15 (39) 0.0 (0) 0.15 (39) 0.0 (0) 0.15 (39)

FGD Makeup 5.29 (1,399) 0.0 (0) 5.29 (1,399) 0.0 (0) 5.29 (1,399)

BFW Makeup 0.39 (103) 0.0 (0) 0.39 (103) 0.0 (0) 0.39 (103)

Cooling Tower Makeup 41.0 (10,840) 7.07 (1,869) 34.0 (8,971) 9.23 (2,438) 24.7 (6,534)

Total 46.9 (12,380) 7.07 (1,869) 39.8 (10,512) 9.23 (2,438) 30.6 (8,074)

Total, gal/MWh net 1,351 204 1,147 266 881Carbon Dioxide Capture Sensitivity Analysis



### 131 Exhibit 3

- 45 Case 1G (99%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Econamine 0.16 (44) 0.0 (0) 0.16 (44) 0.0 (0) 0.16 (44)

FGD Makeup 5.66 (1,495) 0.0 (0) 5.66 (1,495) 0.0 (0) 5.66 (1,495)

BFW Makeup 0.42 (110) 0.0 (0) 0.42 (110) 0.0 (0) 0.42 (110)

Cooling Tower Makeup 45.5 (12,017) 7.58 (2,002) 37.9 (10,016) 10.2 (2,703) 27.7 (7,313)

Total 51.7 (13,666) 7.58 (2,002) 44.2 (11,664) 10.2 (2,703) 33.9 (8,961)

Total, gal/MWh net 1,491 218 1,273 295 978Carbon Dioxide Capture Sensitivity Analysis



### 132 This page intentionally left blank.Carbon Dioxide Capture Sensitivity Analysis



### 133 Exhibit 3

- 46 Case 1E (90%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup SystemsCarbon Dioxide Capture Sensitivity Analysis



### 134 Exhibit 3

- 47 Case 1E (90%) Heat and Mass Balance, Power Block SystemsCarbon Dioxide Capture Sensitivity Analysis



### 135 Exhibit 3

- 48 Case 1F (95%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup SystemsCarbon Dioxide Capture Sensitivity Analysis



### 136 Exhibit 3

- 49 Case 1F (95%) Heat and Mass Balance, Power Block SystemsCarbon Dioxide Capture Sensitivity Analysis



### 137 Exhibit 3

- 50 Case 1G (99%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup SystemsCarbon Dioxide Capture Sensitivity Analysis



### 138 Exhibit 3

- 51 Case 1G (99%) Heat and Mass Balance, Power Block SystemsCarbon Dioxide Capture Sensitivity Analysis



### 139 Exhibit 3

- 52 Case 1E (90%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 7,012 (6,646) 5.9 (5.6) 7,018 (6,651)

Combustion Air 78.1 (74.1) 78.1 (74.1)

Raw Water Makeup 158.4 (150.1) 158.4 (150.1)

Limestone 0.57 (0.54) 0.57 (0.54)

Totals 7,012 (6,646) 243.0 (230.3) 0.0 (0.0) 7,255 (6,876)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.6 (0.6) 0.6 (0.6)

Fly Ash + Gypsum 2.6 (2.4) 2.6 (2.4)

Flue Gas 205 (195) 205 (195)

CO 2 - 117 (

- 111)

- 117 (

- 111)

Cooling Tower * 3,187.8 (3,021.4) 3,187.8 (3,021.4)

Process Losses* * 1,995.6 (1,891.5) 1,995.6 (1,891.5)

Net Power 1,980 (1,877) 1,980

(1,877)

Totals 0.0 (0.0) 5,275 (4,999) 1,980 (1,877) 7,255

(6,876)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and Econamine cooling water. ** Process losses are estimated to match the heat input to the plant. Process losses include losses from: steam turbine, combustion reactions, gas cooling,

and Econamine steam.Carbon Dioxide Capture Sensitivity Analysis



### 140 Exhibit 3

- 53 Case 1F (95%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 7,195 (6,820) 6.0 (5.7) 7,201 (6,825)

Combustion Air 80.2 (76.0) 80.2 (76.0)

Raw Water Makeup 164.7 (156.1) 164.7 (156.1)

Limestone 0.58 (0.55) 0.58 (0.55)

Totals 7,195 (6,820) 251.5 (238.4) 0.0 (0.0) 7,447 (7,058)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.7 (0.6) 0.7 (0.6)

Fly Ash + Gypsum 2.6 (2.5) 2.6 (2.5)

Flue Gas 209 (198) 209 (198)

CO 2 - 127 (

- 120)

- 127 (

- 120)

Cooling Tower * 3,195.0 (3,028.3) 3,195.0 (3,028.3)

Process Losses* * 2,187.0 (2,072.8) 2,187.0 (2,072.8)

Net Power 1,980 (1,877) 1,980

(1,877)

Totals 0.0 (0.0) 5,467 (5,182) 1,980 (1,877) 7,447

(7,058)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and Econamine cooling water. ** Process losses are estimated to match the heat input to the plant.

Process losses include losses f rom: steam turbine, combustion reactions, gas cooling,

and Econamine steam.Carbon Dioxide Capture Sensitivity Analysis



### 141 Exhibit 3

- 54 Case 1G (99%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 7,700 (7,298) 6.4 (6.1) 7,706 (7,304)

Combustion Air 85.8 (81.3) 85.8 (81.3)

Raw Water Makeup 182.2 (172.7) 182.2 (172.7)

Limestone 0.62 (0.59) 0.62 (0.59)

Totals 7,700 (7,298) 275.1 (260.7) 0.0 (0.0) 7,975 (7,559)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash 0.7 (0.7) 0.7 (0.7)

Fly Ash + Gypsum 2.8 (2.7) 2.8 (2.7)

Flue Gas 221 (210) 221 (210)

CO 2 - 142 (

- 134)

- 142 (

- 134)

Cooling Tower * 3,125.1 (2,962.1) 3,125.1 (2,962.1)

Process Losses* * 2,786.4 (2,641.0) 2,786.4 (2,641.0)

Net Power 1,980 (1,877) 1,980

(1,877)

Totals 0.0 (0.0) 5,995 (5,682) 1,980 (1,877) 7,975

(7,559)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and Econamine cooling water. ** Process losses are estimated to match the heat input to the plant.
Process losses include losses from: steam turbine, combustion reac tions, gas cooling,

and Econamine steam.Carbon Dioxide Capture Sensitivity Analysis



### 142 Exhibit 3

- 55 Case 1E Energy Balance Sankey Diagram

Exhibit 3

- 56 Case 1F Energy Balance Sankey DiagramCarbon Dioxide Capture Sensitivity Analysis



### 143 Exhibit 3

- 57 Case 1G Energy Balance Sankey DiagramCarbon Dioxide Capture Sensitivity Analysis



### 144 This page intentionally left blankCarbon Dioxide Capture Sensitivity Analysis



### 145 3.2.2.2 Major Equipment List for Cases 1E t hrough 1G

Major equipment items for the CO 2 

### capture without bypass cases are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in t he cost estimates in Section 3.2.4 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for he ads on pumps and fans.

ACCOUNT 1 FUEL AND SORBENT HANDLING

Equipment

No. Description Type Design Condit ion Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 Bottom Trestle Dumper with

Receiving Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0)

3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

4 Transfer Tower No. 1 Enclosed N/A N/A N/A 1 (0)

5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

6 As

- Received Coal Sampling

System Two

- stage N/A N/A N/A 1 (0)

7 Stacker/Reclaim Traveling Linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

8 Reclaim Hopper N/A 54 tonne (60 ton) 54 tonne (60 ton) 6 4 tonne ( 7 0 ton) 2 (1)

9 Feeder Vibratory 209 tonne/hr (230 tph) 218 tonne/hr (240 tph) 236 tonne/hr (260 tph) 2 (1)

10 Conveyor No. 3 Belt w/tripper 4 26 tonne/hr (4 7 0 tph) 435 tonne/hr (480 tph) 4 72 tonne/hr (5 2 0 tph) 1 (0)

11 Crusher Tower N/A N/A N/A N/A 1 (0)

12 Coal Surge Bin w/ Vent Filter Dual Outlet 209 tonne (230 ton) 218 tonne (240 ton) 236 tonne (260 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) 8 cm x 0

- 3 cm x 0 (3 in x 0

- 1

- 1/4 in x 0) 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 N/A N/A 1 (1)

15 Conveyor No. 4 Belt w/tripper 4 26 tonne/hr (4 7 0 tph) 435 tonne/hr (480 tph) 4 72 tonne/hr (5 2 0 tph) 1 (0)

16 Transfer Tower No. 2 Enclosed N/A N/A N/A 1 (0)

17 Conveyor No. 5 Belt w/tripper 4 26 tonne/hr (4 7 0 tph) 435 tonne/hr (480 tph) 4 72 tonne/hr (5 2 0 tph) 1 (0)

18 Coal Silo w/ Vent Filter and

Slide Gates Field Erected 907 tonne (1,000 ton) 998 tonne (1,100 ton) 998 tonne (1,100 ton) 3 (0 )

19 Limestone Truck Unloading

Hopper N/A 36 tonne (40 ton) 36 tonne (40 ton) 36 tonne (40 ton) 1 (0)

20 Limestone Feeder Belt 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 118 tonne/hr (130 tph) 1 (0)

21 Limestone Conveyor No. L1 Belt 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 118 tonne/hr (130 tph) 1 (0)

22 Limestone Reclaim Hopper N/A 18 tonne (20 ton) 18 tonne (20 ton) 27 tonne (30 ton) 1 (0)

23 Limestone Reclaim Feeder Belt 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 1 (0)

24 Limestone Conveyor No. L2 Belt 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 1 (0)

25 Limestone Day Bin w/ actuator 345 tonne (380 ton) 354 tonne (390 ton) 3 81 tonne (4 2 0 ton) 2 (0)Carbon Dioxide Capture Sensitivity Analysis



### 146 ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 Coal Feeder Gravimetric 45 tonne/hr (50 tph) 45 tonne/hr (50 tph) 54 tonne/hr (60 tph) 6 (0)

2 Coal Pulverizer Ball type or eq. 45 tonne/hr (50 tph) 45 tonne/hr (50 tph) 54 tonne/hr (60 tph) 6 (0)

3 Limestone Weigh Feeder Gravimetric 2 9 tonne/hr (3 2 tph) 30 tonne/hr (3 3 tph) 3 2 tonne/hr (3 5 tph) 1 (1)

4 Limestone Ball Mill Rotary 2 9 tonne/hr (3 2 tph) 30 tonne/hr (3 3 tph) 3 2 tonne/hr (3 5 tph) 1 (1)

5 Limestone Mill Slurry

Tank with Agitator N/A 109,777 liters (29,000 gal) 113,562 liters (30,000 gal) 121,133 liters (32,000 gal) 1 (1)

6 Limestone Mill Recycle

Pumps Horizontal centrifugal 1,855 lpm @ 12m H 2 O (490 gpm @ 40 ft H 2 O) 1,893 lpm @ 12m H 2 O (500 gpm @ 40 ft H 2 O) 2,006 lpm @ 12m H 2 O (530 gpm @ 40 ft H 2 O) 1 (1)

7 Hydroclone Classifier 4 active cyclones in

a 5 cyclone bank 454 lpm (120 gpm) per cyclone 492 lpm (130 gpm) per cyclone 492 lpm (130 gpm) per cyclone 1 (1)

8 Distribution Box 2

- way N/A N/A N/A 1 (1)

9 Limestone Slurry Storage

Tank with Agitator Field erected 620,808 liters ( 16 4 ,000 gal) 639,735 liters (16 9 ,000 gal) 681,374 liters (1 80 ,000 gal) 1 (1)

10 Limestone Slurry Feed

Pumps Horizontal centrifugal 1,287 lpm @ 9m H 2 O (340 gpm @ 30 ft H 2 O) 1,325 lpm @ 9m H 2 O (350 gpm @ 30 ft H 2 O) 1,401 lpm @ 9m H 2 O (370 gpm @ 30 ft H 2 O) 1 (1)



### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 Demineralized Water

Storage Tank Vertical, cylindrical, outdoor 1,499,023 liters (396,000 gal) 1,540,663 liters (407,000 gal) 1,646,654 liters (435,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 17,034 lpm @ 213 m H 2 O (4,500 gpm @ 700 ft H 2 O) 16,277 lpm @ 213 m H 2 O (4,300 gpm @ 700 ft H 2 O) 13,627 lpm @ 213 m H 2 O (3,600 gpm @ 700 ft H 2 O) 1 (1)

3 Deaerator and Storage

Tank Horizontal spray type 2,497,480 kg/hr (5,506,000 lb/hr),

5 min. tank 2,562,797 kg/hr (5,650,000 lb/hr),

5 min. tank 2,741,966 kg/hr (6,045,000 lb/hr),

5 min. tank 1 (0)

4 Boiler Feed

Pump/Turbine Barrel type, multi

- stage, centrifugal 42,018 lpm @ 3,505 m H 2 O (11,100 gpm @ 11,500 ft H 2 O) 43,154 lpm @ 3,505 m H 2 O (11,400 gpm @ 11,500 ft H 2 O) 46,182 lpm @ 3,505 m H 2 O (12,200 gpm @ 11,500 ft H 2 O) 1 (1)

5 Startup Boiler Feed

Pump, Electric Motor

Driven Barrel type, multi

- stage, centrifugal 12,492 lpm @ 3,505 m H 2 O (3,300 gpm @ 11,500 ft H 2 O) 12,870 lpm @ 3,505 m H 2 O (3,400 gpm @ 11,500 ft H 2 O) 13,627 lpm @ 3,505 m H 2 O (3,600 gpm @ 11,500 ft H 2 O) 1 (0)

6 LP Feedwater Heater

1A/1B Horizontal U

- tube 503,488 kg/hr (1,110,000 lb/hr) 480,808 kg/hr (1,060,000 lb/hr) 408,233 kg/hr (900,000 lb/hr) 2 (0)

7 LP Feedwater Heater

2A/2B Horizontal U

- tube 503,488 kg/hr (1,110,000 lb/hr) 480,808 kg/hr (1,060,000 lb/hr) 408,233 kg/hr (900,000 lb/hr) 2 (0)

8 LP Feedwater Heater

3A/3B Horizontal U

- tube 503,488 kg/hr (1,110,000 lb/hr) 480,808 kg/hr (1,060,000 lb/hr) 408,233 kg/hr (900,000 lb/hr) 2 (0)

9 LP Feedwater Heater

4A/4B Horizontal U

- tube 503,488 kg/hr (1,110,000 lb/hr) 480,808 kg/hr (1,060,000 lb/hr) 408,233 kg/hr (900,000 lb/hr) 2 (0)

10 HP Feedwater Heater

6 Horizontal U

- tube 2,499,294 kg/hr (5,510,000 lb/hr) 2,562,797 kg/hr (5,650,000 lb/hr) 2,744,234 kg/hr (6,050,000 lb/hr) 1 (0)

11 HP Feedwater Heater

7 Horizontal U

- tube 2,499,294 kg/hr (5,510,000 lb/hr) 2,562,797 kg/hr (5,650,000 lb/hr) 2,744,234 kg/hr (6,050,000 lb/hr) 1 (0)

12 HP Feedwater heater 8 Horizontal U

- tube 2,499,294 kg/hr (5,510,000 lb/hr) 2,562,797 kg/hr (5,650,000 lb/hr) 2,744,234 kg/hr (6,050,000 lb/hr) 1 (0)

13 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 (0)Carbon Dioxide Capture Sensitivity Analysis



### 147 Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

14 Fuel Oil System No. 2 fuel oil for light off 1,135,624 liter (300,000 gal) 1,135,624 liter (300,000 gal) 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) 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 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) 28 m 3 /min (1,000 scfm) 28 m 3 /min (1,000 scfm) 2 (1)

17 Closed Cylce Cooling

Heat Exchangers Shell and tube 53 GJ/hr (50 MMBtu/hr) each 53 GJ/hr (50 MMBtu/hr) each 53 GJ/hr (50 MMBtu/hr) each 2 (0)

18 Closed Cycle Cooling

Water Pumps Horizontal centrifugal 20,820 lpm @ 30 m H 2 O (5,500 gpm @ 100 ft H 2 O) 20,820 lpm @ 30 m H 2 O (5,500 gpm @ 100 ft H 2 O) 20,820 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) 3,785 lpm @ 88 m H 2 O (1,000 gpm @ 290 ft H 2 O) 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) 2,650 lpm @ 64 m H 2 O (700 gpm @ 210 ft H 2 O) 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 20,101 lpm @ 43 m H 2 O (5,310 gpm @ 140 ft H 2 O) 20,933 lpm @ 43 m H 2 O (5,530 gpm @ 140 ft H 2 O) 23,280 lpm @ 43 m H 2 O (6,150 gpm @ 140 ft H 2 O) 2 (1)

22 Filtered Water Pumps Stainless steel, single suction 757 lpm @ 49 m H 2 O (200 gpm @ 160 ft H 2 O) 795 lpm @ 49 m H 2 O (210 gpm @ 160 ft H 2 O) 871 lpm @ 49 m H 2 O (230 gpm @ 160 ft H 2 O) 2 (1)

23 Filtered Water Tank Vertical, cylindrical 738,155 liter (195,000 gal) 760,868 liter (201,000 gal) 817,649 liter (216,000 gal) 1 (0)

24 Makeup Water

Demineralizer Multi

- media filter, cartridge

filter, RO membrane assembly,

electrodeionization unit 984 lpm (260 gpm) 1,022 lpm (270 gpm) 1,098 lpm (290 gpm) 1 (1)

25 Liquid Waste

Treatment System -- 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 1 (0)



### ACCOUNT 4 BOILER AND ACCESSORIES

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 Boiler Supercritical, drum,

wall

- fired, low NOx
burners, overfire air 2,499,294 kg/hr steam @ 25.5

MPa/602°C/602°C (5,510,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 2,562,797 kg/hr steam @ 25.5

MPa/602°C/602°C (5,650,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 2,744,234 kg/hr steam @ 25.5

MPa/602°C/602°C (6,050,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 1 (0)

2 Primary Air Fan Centrifugal 327,494 kg/hr, 4,468 m 3 /min @ 123 cm WG (722,000 lb/hr, 157,800 acfm

@ 48 in. WG) 336,112 kg/hr, 4,584 m 3 /min @ 123 cm WG (741,000 lb/hr, 161,900 acfm @

48 in. WG) 359,699 kg/hr, 4,907 m 3 /min @ 123 cm WG (793,000 lb/hr, 173,300 acfm @

48 in. WG) 2 (0)

3 Forced Draft Fan Centrifugal 1,066,396 kg/hr, 14,546 m 3 /min @ 51 cm WG (2,351,000 lb/hr, 513,700 acfm @ 20 in. WG) 1,094,065 kg/hr, 14,929 m 3 /min @ 51 cm WG (2,412,000 lb/hr, 527,200 acfm

@ 20 in. WG) 1,171,175 kg/hr, 15,974 m 3 /min @ 51 cm WG (2,582,000 lb/hr, 564,100 acfm

@ 20 in. WG) 2 (0)

4 Induced Draft Fan Centrifugal 1,550,379 kg/hr, 33,176 m 3 /min @ 91 cm WG (3,418,000 lb/hr, 1,171,600 acfm @ 36 in. WG) 1,590,748 kg/hr, 34,045 m 3 /min @ 91 cm WG (3,507,000 lb/hr, 1,202,300 acfm @ 36 in. WG) 1,702,332 kg/hr, 36,430 m 3 /min @ 91 cm WG (3,753,000 lb/hr, 1,286,500 acfm @ 36 in. WG) 2 (0)

5 SCR Reactor Vessel Space for spare layer 3,102,572 kg/hr (6,840,000 lb/hr) 3,179,683 kg/hr (7,010,000 lb/hr) 3,406,479 kg/hr (7,510,000 lb/hr) 2 (0)

6 SCR Catalyst

-- -- -- -- 3 (0)

7 Dilution Air Blower Centrifugal 57 m 3 /min @ 108 cm WG (2,000 acfm @ 42 in. WG) 57 m 3 /min @ 108 cm WG (2,000 acfm @ 42 in. WG) 62 m 3 /min @ 108 cm WG (2,200 acfm @ 42 in. WG) 2 (1)

8 Ammonia Storage Horizontal tank 60,567 liter (16,000 gal) 64,352 liter (17,000 gal) 68,137 liter (18,000 gal) 5 (0)

9 Ammonia Feed Pump Centrifugal 12 lpm @ 91 m H 2 O (3 gpm @ 300 ft H 2 O) 12 lpm @ 91 m H 2 O (3 gpm @ 300 ft H 2 O) 13 lpm @ 91 m H 2 O (3 gpm @ 300 ft H 2 O) 2 (1)Carbon Dioxide Capture Sensitivity Analysis



### 148 ACCOUNT 5 FLUE GAS CLEANUP

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 Fabric Filter Single stage, high

- ratio with pulse

- jet online cleaning system 1,550,379 kg/hr (3,418,000 lb/hr) 99.8% efficiency 1,590,748 kg/hr (3,507,000 lb/hr) 99.8% efficiency 1,702,332 kg/hr (3,753,000 lb/hr) 99.8% efficiency 2 (0)

2 Absorber Module Counter

- current open spray 51,169 m 3 /min (1,807,000 acfm) 52,499 m 3 /min (1,854,000 acfm) 56,181 m 3 /min (1,984,000 acfm) 1 (0)

3 Recirculation Pumps Horizontal centrifugal 177,914 lpm @ 64 m H 2 O (47,000 gpm @ 210 ft H 2 O) 181,700 lpm @ 64 m H 2 O (48,000 gpm @ 210 ft H 2 O) 196,841 lpm @ 64 m H 2 O (52,000 gpm @ 210 ft H 2 O) 5 (1)

4 Bleed Pumps Horizontal centrifugal 5,602 lpm (1,480 gpm) at 20

wt% solids 5,754 lpm (1,520 gpm) at 20 wt%

solids 6,170 lpm (1,630 gpm) at 20

wt% solids 2 (1)

5 Oxidation Air Blowers Centrifugal 229 m 3 /min @ 0.3 MPa (8,100 acfm @ 42 psia) 235 m 3 /min @ 0.3 MPa (8,310 acfm @ 42 psia) 251 m 3 /min @ 0.3 MPa (8,870 acfm @ 42 psia) 2 (1)

6 Agitators Side entering 50 hp 50 hp 50 hp 5 (1)

7 Dewatering Cyclones Radial assembly, 5 units each 1,401 lpm (370 gpm) per cyclone 1,438 lpm (380 gpm) per cyclone 1,552 lpm (410 gpm) per cyclone 2 (0)

8 Vacuum Filter Belt Horizontal belt 44 tonne/hr (49 tph) of 50 wt % slurry 45 tonne/hr (50 tph) of 50 wt % slurry 49 tonne/hr (54 tph) of 50 wt % slurry 2 (1)

9 Filtrate Water Return

Pumps Horizontal centrifugal 871 lpm @ 12 m H 2 O (230 gpm @ 40 ft H 2 O) 871 lpm @ 12 m H 2 O (230 gpm @ 40 ft H 2 O) 946 lpm @ 12 m H 2 O (250 gpm @ 40 ft H 2 O) 1 (1)

10 Filtrate Water Return

Storage Tank Vertical, lined 567,812 lpm (150,000 gal) 567,812 lpm (150,000 gal) 605,666 lpm (160,000 gal) 1 (1)

11 Process Makeup

Water Pumps Horizontal centrifugal 568 lpm @ 21 m H 2 O (150 gpm @ 70 ft H 2 O) 568 lpm @ 21 m H 2 O (150 gpm @ 70 ft H 2 O) 606 lpm @ 21 m H 2 O (160 gpm @ 70 ft H 2 O) 1 (1)



### ACCOUNT 5B CARBON DIOXIDE RECOVERY

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 Econamine FG Plus Amine

- based CO 2 capture technology 1,640,190 kg/h (3,616,000 lb/h)

20.6 wt % CO 2 concentration 1,683,281 kg/h (3,711,000 lb/h)

20.6 wt % CO 2 concentration 1,801,215 kg/h (3,971,000 lb/h)

20.6 wt % CO 2 concentration 2 (0)

2 Econamine

Condensate Pump Centrifugal 14,650 lpm @ 52 m H 2 O (3,870 gpm @ 170 ft H 2 O) 16,202 lpm @ 52 m H 2 O (4,280 gpm @ 170 ft H 2 O) 21,236 lpm @ 52 m H 2 O (5,610 gpm @ 170 ft H 2 O) 1 (1)

3 CO 2 Compressor Centrifugal 303,707 kg/h @ 15.3 MPa (669,559 lb/h @ 2,215 psia) 328,968 kg/h @ 15.3 MPa (725,250 lb/h @ 2,215 psia) 366,853 kg/h @ 15.3 MPa (808,773 lb/h @ 2,215 psia) 2 (0)



### ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES

N/A

ACCOUNT 7 DUCTING AND STACK

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1GCarbon Dioxide Capture Sensitivity Analysis



### 149 Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 Stack Reinforced concrete with FRP liner 152 m (500 ft) high x

5.6 m ( 18 ft) diameter 152 m (500 ft) high x

5.6 m ( 18 ft) diameter 152 m (500 ft) high x

5.8 m ( 19 ft) diameter 

### 1 (0)

ACCOUNT 8 STEAM TURBINE GENERATOR

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 Steam Turbine

Generator Commercially available, advanced

steam turbine 696 MW

24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 703 MW

24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 715 MW

24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 

### 1 (0)

2 Steam Turbine

Generator Hydrogen cooled, static excitation 770 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 780 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 790 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 

### 1 (0)

3 Surface Condenser Single pass, divided waterbox including

vacuum pumps 1,910 GJ/hr (1,810 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise

11°C (20°F) 1,836 GJ/hr (1,740 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise

11°C (20°F) 1,540 GJ/hr (1,460 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise

11°C (20°F) 

### 1 (0)



### ACCOUNT 9 COOLING WATER SYSTEM

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 Circulating Water

Pumps Vertical, wet pit 1,014,500 lpm @ 30 m (268,000 gpm @ 100 ft) 1,056,100 lpm @ 30 m (279,000 gpm @ 100 ft) 1,173,500 lpm @ 30 m (310,000 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 / 5666 GJ/hr (5370 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 5898 GJ/hr (5590 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 6531 GJ/hr (6190 MMBtu/hr) heat duty 1 ( 0 )



### ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 Economizer Hopper (part of boiler

scope of supply) -- -- -- -- 4 (0)

2 Bottom Ash Hopper (part of boiler

scope of supply) -- -- -- -- 2 (0)

3 Clinker Grinder

-- 5.4 tonne/hr (6 tph) 5.4 tonne/hr (6 tph) 6.4 tonne/hr (7 tph) 1 (1)

4 Pyrites Hopper (part of pulverizer

scope of supply included with boiler) -- -- -- -- 6 (0)

5 Hydroejectors

-- -- -- -- 12 (0)

6 Economizer /Pyrites Transfer Tank

-- -- -- -- 1 (0)

7 Ash Sluice Pumps Vertical, wet pit 227 lpm @ 17 m H 2 O (60 gpm @ 56 ft H 2 O) 227 lpm @ 17 m H 2 O (60 gpm @ 56 ft H 2 O) 227 lpm @ 17 m H 2 O (60 gpm @ 56 ft H 2 O) 1 (1)

8 Ash Seal Water Pumps Vertical, wet pit 7,571 lpm @ 9 m H 2 O (2000 gpm @ 28 ft H 2 O) 7,571 lpm @ 9 m H 2 O (2000 gpm @ 28 ft H 2 O) 7,571 lpm @ 9 m H 2 O (2000 gpm @ 28 ft H 2 O) 1 (1)

9 Hydrobins

-- 227 lpm (60 gpm) 227 lpm (60 gpm) 227 lpm (60 gpm) 1 (1)

10 Baghouse Hopper (part of

baghouse scope of supply) -- -- -- -- 24 (0)Carbon Dioxide Capture Sensitivity Analysis



### 150 Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

11 Air Heater Hopper (part of boiler

scope of supply) -- -- -- -- 10 (0)

12 Air Blower

-- 20 m 3 /min @ 0.2 MPa (7 1 0 scfm @ 24 psi) 2 1 m 3 /min @ 0.2 MPa (7 3 0 scfm @ 24 psi) 22 m 3 /min @ 0.2 MPa (7 8 0 scfm @ 24 psi) 1 (1)

13 Fly Ash Silo Reinforced

concrete 6 80 tonne (1, 5 00 ton) 680 tonne (1,500 ton) 726 tonne (1,600 ton) 2 (0)

14 Slide Gate Valves

-- -- -- -- 2 (0)

15 Unloader

-- -- -- -- 1 (0)

16 Telescoping Unloading Chute

-- 1 27 tonne/hr (1 4 0 tph) 127 tonne/hr (140 tph) 136 tonne/hr (150 tph) 1 (0)



### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 STG Transformer Oil

- filled 24 kV/345 kV, 650 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 650 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 650 MVA,

3

- ph, 60 Hz 1 (0)

2 Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 1 21 MVA,

3

- ph, 60 Hz 24 kV/4.16 kV, 12 8 MVA,

3

- ph, 60 Hz 24 kV/4.16 kV, 1 41 MVA,

3

- ph, 60 Hz 1 (1)

3 L ow Voltage Transformer Dry ventilated 4.16 kV/480 V, 18 MVA,

3

- ph, 60 Hz 4.16 kV/480 V, 19 MVA,

3

- ph, 60 Hz 4.16 kV/480 V, 21 MVA,

3

- ph, 60 Hz 1 (1)

4 STG Isolated Phase Bus Duct

and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 1 (0)

5 Medium Voltage Switchgear Metal Clad 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 1 (1)

6 Low Voltage Switchgear Metal Enclosed 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 1 (1)

7 Emergency Diesel Generator Sized for emergency

shutdown 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 1 (0)



### ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment

No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 DCS

- Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator Stations/Printers and Engineering

Stations/Printers Operator Stations/Printers and Engineering

Stations/Printers Operator Stations/Printers and Engineering

Stations/Printers 1 (0)

2 DCS

– Processor Microprocessor with redundant input/output N/A N/A N/A 1 (0)

3 DCS

- Data Highway Fiber optic Fully redundant,

25% spare Fully redundant,

25% spare Fully redundant,

25% spare 1 (0)Carbon Dioxide Capture Sensitivity Analysis



### 151 

## 3.2.3 Economic Analysis for the Supercritical PC Cases

The capital and operating costs for Cases 1 A through 1G are presented in Section 3.2.4 . A cost and performance summary table ( Exhibit 3

- 72 ) for the SC PC cases is shown in Section 3.2.5

.

Due to the range of CO 2 

### capture levels analyzed in Case 1, the Econamine capital and operating costs vary for the seven cases. While a factored approach that relies on the quantity of CO 2 

### captured for equipment sizing and cost estimation was employed, the cost estimates for the Econamine system were also developed based, in part, on output data from the ProTreatTM simulations. In particular, the ProTreatTM model output provided absorption and stripping
column diameters for each case, which were used to determine the required numb er of absorption trains.

For this analysis, it was assumed that the maximum absorption column diameter is 20 meters, based on information released by Fluor [ 4 ]. As a result, cost estimates for three CO 2 

### capture

levels

– 30 percent (1A), 50 percent (1B), and 70 percent (1C)

– are based on a single absorption and compression train. To calculate the capital cost for a single absorption train, it was assumed

that the absorption columns represent 40 percent of the total capital cost for a two

- train Econamine system.



## 3.2.4 Capital and Operating Cost Results

The capital and operating costs for Cases 1 A through 1G are shown in Exhibit 3

- 58 through

Exhibit 3

- 71

. The capital costs for each case include the TPC, the owner‟s costs, TOC, and the

total as

- spent capital TASC cost. The c apital and operating cost estimating methodology is explained in Sec tion 2.7

.Carbon Dioxide Capture Sensitivity Analysis



### 152 Exhibit 3

- 58 Case 1A (30%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 153 Exhibit 3

- 58 Case 1A (30%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 154 Exhibit 3

- 58 Case 1A (30%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 155 Exhibit 3

- 58 Case 1A (30%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 156 Exhibit 3

- 59 Case 1A Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 157 Exhibit 3

- 60 Case 1B (50%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 158 Exhibit 3

- 60 Case 1B (50%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 159 Exhibit 3

- 60 Case 1B (50%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 160 Exhibit 3

- 60 Case 1B (50%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 161 Exhibit 3

- 61 Case 1B Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 162 Exhibit 3

- 62 Case 1C (70%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 163 Exhibit 3

- 62 Case 1C (70%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 164 Exhibit 3

- 62 Case 1C (70%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 165 Exhibit 3

- 62 Case 1C (70%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 166 Exhibit 3

- 63 Case 1C Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 167 Exhibit 3

- 64 Case 1D (85%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 168 Exhibit 3

- 64 Case 1D (85%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 169 Exhibit 3

- 64 Case 1D (85%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 170 Exhibit 3

- 64 Case 1D (85%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 171 Exhibit 3

- 65 Case 1D Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 172 Exhibit 3

- 66 Case 1E (90%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 173 Exhibit 3

- 66 Case 1E (90%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 174 Exhibit 3

- 66 Case 1E (90%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 175 Exhibit 3

- 66 Case 1E (90%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 176 Exhibit 3

- 67 Case 1E Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 177 Exhibit 3

- 68 Case 1F (95%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 178 Exhibit 3

- 68 Case 1F (95%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 179 Exhibit 3

- 68 Case 1F (95%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 180 Exhibit 3

- 68 Case 1F (95%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 181 Exhibit 3

- 69 Case 1F Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 182 Exhibit 3

- 70 Case 1G (99%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 183 Exhibit 3

- 70 Case 1G (99%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 184 Exhibit 3

- 70 Case 1G (99%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 185 Exhibit 3

- 70 Case 1G (99%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 186 Exhibit 3

- 71 Case 1G Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 187 

## 3.2.5 Supercritical PC Cost and Performance Summary

A summary of plant costs and performance for the SC PC cases is shown in Exhibit 3

- 72

.

Exhibit 3

- 72 Cost and Performance Results for the Supercritical PC Cases

Case 0 1A 1B 1C 1D 1E 1F 1G

CO 2 Capture, % 0% 30% 50% 70% 85% 90% 95% 99%

Gross Power Output, MW

e 580.4 601.5 618.2 637.8 654.8 661.3 667.9 679.6

Net Power Output, MW

e 550.0 550.0 550.0 550.0 550.1 550.0 550.0 550.0

Net Plant Efficiency, % (HHV) 39.3 35.2 32.9 30.6 28.9 28.2 27.5 25.7

Net Plant Heat Rate, Btu/kWh (HHV) 8,687 9,695 10,379 11,151 11,819 12,083 12,400 13,269

Coal Flowrate (lb/hr) 409,550 457,066 489,316 525,764 557,283 569,672 584,578 625,561

Total CO 2 Captured, lb/MWh net NA 588 1,057 1,582 2,037 2,213 2,398 2,674

CO 2 Capture & Compression Cost, $x1000 NA $ 190,138 $ 266,902 $ 336,794 $ 441,781 $ 463,389 $ 485,273 $ 516,797

Total Plant Cost, $x1000 $905,901 $1,138,688 $1,258,942 $1,378,696 $1,525,453 $1,562,889 $1,602,389 $1,678,914

Owner’s Costs, $x1000 $207,800 $258,649 $285,448 $312,458 $344,744 $353,249 $362,267 $380,090

Total Overnight Cost, $x1000 $1,113,701 $1,397,338 $1,544,390 $1,691,155 $1,870,197 $1,916,138 $1,964,657 $2,059,004

Total Overnight Cost, $/kW $2,025 $2,541 $2,808 $3,075 $3,400 $3,484 $3,572 $3,744

Total As

- Spent Capital, $x1000 $1,262,937 $1,592,965 $1,760,604 $1,927,917 $2,132,024 $2,184,397 $2,239,708 $2,347,264

Total As

- Spent Capital, $/kW $2,296 $2,896 $3,201 $3,505 $3,876 $3,972 $4,072 $4,268

CO 2 Capital Cost Penalty a , $/kW NA $516 $783 $1,050 $1,375 $1,459 $1,548 $1,719

Cost of Electricity b , mills/kWh 58.90 76.64 84.38 92.75 101.49 104.29 107.00 112.65

COE CO 2 Penalty a , mills/kWh NA 17.7 25.5 33.8 42.6 45.4 48.1 53.8

Percent increase in COE a , % NA 30.1 43. 3 57. 5 72.3 77. 1 81. 7 91. 3

Cost of CO 2 Avoided a , $/tonne NA 102.8 79.1 69.2 67.2 65.9 64.7 68.2

CO 2 Emissions, lb/MMBtu 203.2 142.9 101.7 61.7 31.2 20.4 10.2 2.0

CO 2 Emissions, lb/MWh net 1,765 1,385 1,055 687 369 246 126 27

SO 2 Emissions, lb/MMBtu 0.086 0.064 0.050 0.036 0.017 0.017 0.016 0.016

SO 2 Emissions, lb/MWh 0.75 0.570 0.460 0.340 0.170 0.170 0.170 0.170

NOx Emissions, lb/MMBtu 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070

NOx Emissions, lb/MWh 0.608 0.621 0.646 0.673 0.695 0.703 0.715 0.752

PM Emissions, lb/MMBtu 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013

PM Emissions, lb/MWh 0.113 0.115 0.120 0.125 0.129 0.131 0.133 0.140

Hg Emissions, lb/TBtu 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14

Hg Emissions, lb/TWh 9.93 10.1 10.6 11.0 11.3 11.5 11.7 12.3

Raw Water Withdrawal, gpm 5,394 6,245 6,987 8,386 9,615 10,095 10,512 11,664

Raw Water Consumption, gpm 4,301 4,898 5,433 6,474 7,392 7,753 8,074 8,961

Raw Water Consumption, gal/MWh net 469 534 593 706 806 846 881 978

a Relative to Case 0 ( SC PC without capture from 2010 Bituminous Baseline study) b Capacity factor is 85% for the SC PC casesCarbon Dioxide Capture Sensitivity Analysis



### 188 This page intentionally left blankCarbon Dioxide Capture Sensitivity Analysis



### 189 

# 4. Case 2

– GEE IGCC w ith Variable C O 2 

# Capture

This section evaluates a range of CO 2 

### capture levels for four IGCC plant designs, which are based on the GEE gasifier in the “radiant only” configuration. GEE offers three design
configurations [ 44 ]:

Quench: In this configuration, the hot syngas exiting the ga sifier passes through a pool of water to quench the temperature to less than 260 °C (500 °F) before entering the syngas scrubber. It is the simplest and lowest capital cost design, but also the least efficient.

Radiant

- Only: In this configuration, the hot syngas exiting the gasifier passes through a radiant syngas cooler where it is cooled from about 1

, 316 °C (2

, 400 °F) to 677 °C (1

, 250 °F), then through a water quench where the syngas is further cooled to about 223 °C (450 °F) prior to entering the syngas scrubber. Relative to the qu ench configuration, the

radiant

- only design offers increased output, higher efficiency, improved reliability/availability, and results in the lowest COE . This configuration was chosen by GEE and Bechtel for the design of thei r reference plant.

Radiant

- Convective: In this configuration, the hot syngas exiting the gasifier passes through a radiant syngas cooler where it is cooled from about 1

, 316 °C ( 2

, 400 °F) to 760
°C (1

, 400 °F), passes over a pool of water where particulate i s removed but t he syngas is not quenched, through a convective syngas cooler where the syngas is further cooled to

about 371 °C (700 °F) prior to entering additional heat exchangers or the scrubber. This configuration has the highest overall efficiency, b ut at the expense of highest capital cost and the lowest availability. This is the configuration used at Tampa Electric‟s Polk

Power Station.

Note that the radiant

- only configuration includes a water quench and, based on functionality, would be more appro priately named ra diant

- quench. The term radiant

- only is used to distinguish

it from the radiant

- convectiv e configuration. Since radiant

- only is the terminology used by GEE, it will be used throughout this report.

The balance of Section 4 is organized as follows:

Gasifier Background provides information on the development and status of the GEE gasification technology.

Process Description provides an overview of the technology operation for IGCC Designs 2 through 4, which include WGS reactor(s) and a two

- stage SelexolTM unit.

Performance Results provides the main modeling results from Design s 1

– 4 including the performance summary, environmental per formance, carbon balance, sulfur balance, water

balance, mass and ene rgy balance diagrams, mass and energy balance tables.

Equipment List provides an itemized list of major equipment for Design s 1

– 4 with account codes that correspond to the cost accounts i n the Cost Estimates section.Carbon Dioxide Capture Sensitivity Analysis



### 190 Cost Estimates details the capital and O&M costs for IGCC Designs 1

– 4



## 4.1 Gasifier Background

Development and Current Status [ 45 ]

– Initial development of the GEE gasification technology (formerly licensed by Texaco and then Chevr onTexaco) was conducted in the 1940s at Texaco‟s Montebello, California laboratories. From 1946 to 1954 the Montebello pilot plant
produced synthesis gas (hydrogen and carbon monoxide) by partial oxidation of a variety of feedstocks, including natural gas , oil, asphalt, coal tar, and coal. From 1956 to 1958, coal was gasified in a 91 tonne/day (100 TPD) Texaco coal gasifier at the Olin Mathieson Chemical Plant in Morgantown, West Virginia, for the production of ammonia.

The oil price increases and supply disruptions of the 1970s renewed interest in the Texaco partial

- oxidation process for gasification of coal or other solid opportunity fuels. Three 14 tonne/day (15 TPD) pilot plants at the Montebello laboratories have be en used to test numerous coals. Two larger pilot plants were also built. The first gasified 150 tonne/day (165 TPD) of coal and was built to test synthesis gas generation by Rührchemie and Rührkohle at Oberhausen, Germany, and included a synthesis gas co oler. The second gasified 172 tonne/day (190 TPD) of coal using a quench

- only gasifier cooler and was built to make hydrogen at an existing TVA ammonia plant at Muscle Shoals, Alabama. These two large

- scale pilot plants successfully operated for several years during the 1980s and tested a number of process variables and

numerous coals.

The first commercial Texaco coal gasification plant was built for Tennessee Eastman at Kingsport, Tennessee, and started up in 1983. To date, 24 gasifiers have been built in 12 plants for coal and petroleum coke. Several of the plants require a hydrogen

- rich gas and therefore directly water

- quench the raw gas to add the water for shifting the CO to H 2 

### , and have no synthesis gas coolers.

The Cool Water plant was the first c ommercial

- scale Texaco coal gasification project for the electric utility industry. This facility gasified 907 tonne/day (1,000 TPD) (dry basis) of bituminous coal and generated 120 MW of electricity by IGCC operation. In addition, the plant

was the firs t commercial

- sized Texaco gasifier used with a synthesis gas cooler. The Cool Water plant operated from 1984 to 1989 and was a success in terms of operability, availability, and environmental performance.

The Tampa Electric IGCC Clean Coal Technology Dem onstration Project built on the Cool Water experience to demonstrate the use of the Texaco coal gasification process in an IGCC plant. The plant utilizes approximately 2,268 tonne/day (2,500 TPD) of coal in a single Texaco gasifier to generate a net of ap proximately 250 MW e . The syngas is cooled in a high

temperature radiant heat exchanger, generating high

- pressure steam, and further cooled in convective heat exchangers (the radiant

- convective configuration). The particles in the cooled gas are removed i n a water

- based scrubber. The cleaned gas then enters a hydrolysis reactor

where COS is converted to H 2 

### S. After additional cooling, the syngas is sent to a conventional

AGR unit, where H 2 

### S is absorbed by reaction with an amine solvent. H 2 

### S is removed from the amine by steam stripping and sent to a sulfuric acid plant. The cleaned gas is sent to a General
Electric MS 7001FA combustion turbine (CT).Carbon Dioxide Capture Sensitivity Analysis



### 191 The Delaware Clean Energy Project is a coke gasification and CT repowering of an existing

1 30 MW coke

- fired boiler cogeneration power plant at the Motiva oil refinery in Delaware City, Delaware. The Texaco coal gasification process was modified to gasify 1,814 tonne/day
(2,000 TPD) of this low

- quality petroleum coke. The plant is designed to u se all the fluid petroleum coke generated at Motiva‟s Delaware City Plant and produce a nominal 238,136 kg/h
(525,000 lb/h) of 8.6 MPa (1

, 250 psig) steam, and 120,656 kg/h (266,000 lb/h) of 1.2 MPa
(175 psig) steam for export to the refinery and the use/sa le of 120 MW of electrical power. Environmentally, these new facilities help satisfy tighter NO

x 

### and SO 2 

### emission limitations at the Delaware City Plant.

Gasifier Capacity

– The largest GEE gasifier is the unit at Tampa Electric, which consists of the

rad iant

- convective configuration. The daily coal

- handling capacity of this unit is 2,268 tonnes
(2,500 tons) of bituminous coal. The dry gas production rate is 0.19 million Nm 3 

### /h (6.7 million scfh) with an energy content of about 1,897 million kJ/h (HHV) (1 ,800 million Btu/h). This size matches the F Class CTs that are used at Tampa.

Distinguishing Characteristics

– A key advantage of the GEE coal gasification technology is the extensive operating experience at full commercial scale. Furthermore, Tampa Ele ctric is an IGCC power generation facility, operated by conventional electric utility staff, and is environmentally one of the cleanest coal

- fired power plants in the world. The GEE gasifier also operates at the highest pressure of the three gasifiers in this study, 5.6 MPa (815 psia) compared to 4.2 MPa (615 psia) for CoP and Shell.

Entrained

- flow gasifiers have fundamental environmental advantages over fluidized

- bed and moving

- bed gasifiers. They produce no hydrocarbon liquids, and the only solid waste is an inert slag. The relatively high H 2 

### /CO ratio and CO 2 

### content of GEE gasification fuel gas helps

achieve low nitrogen oxide (NO

x 

### ) and CO emissions in even the higher

- temperature advanced

CTs.

The key disadvantages of the GEE coal gasification technolo gy are the limited refractory life, the relatively high oxygen requirements and high waste heat recovery duty (synthesis gas cooler design). As with the other entrained

- flow slagging gasifiers, the GEE process has this disadvantage due to its high operati ng temperature. The disadvantage is magnified in the single

stage, slurry feed design. The quench design significantly reduces the capital cost of syngas cooling, while innovative heat integration maintains good overall thermal efficiency although

lower than the synthesis gas cooler design. Another disadvantage of the GEE process is the limited ability to economically handle low

- rank coals relative to moving

- bed and fluidized

- bed gasifiers or to entrained

- flow gasifiers with dry feed. For slurry fed ent rained gasifiers using

low

- rank coals, developers of two

- stage slurry fed gasifiers claim advantages over single

- stage slurry fed.

Important Coal Characteristics

– The slurry feeding system and the recycle of process condensate water as the principal slurr ying liquid make low levels of ash and soluble salts desirable coal characteristics for use in the GEE coal gasification process. High ash levels

increase the ratio of water

- to

- carbon in the feed slurry, thereby increasing the oxygen requirements. The sl urry feeding also favors the use of high

- rank coals, such as bituminous coal,Carbon Dioxide Capture Sensitivity Analysis



### 192 since their low inherent moisture content increases the moisture

- free solids content of the slurry and thereby reduces oxygen requirements.



## 4.2 Process Description

In this section the overall GEE gasification process is described. The system description follows the Designs 2 through 4 block flow diagrams.



## 4.2.1 Coal Receiving and Storage

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

the coal delivered to the plant. The scope of the system is from the trestle bottom dumper and coal receiving hoppers up to and including the slide gate valves at the outlet of the coal storage silos. Coal receiving and storage is identical for all four IGCC plant designs.

Operation Description

– The coal is delivered to the site by 100

- car unit trains comprised of 91 tonne (100 ton) rail cars. The unloading is done by a trestle bottom dumper, which unloads the coal into two receiving hoppers. Coal from each hopper is fed directly into a vibratory feeder.
The 8 cm x 0 (3" x 0) coal from the feeder is discharged onto a belt conveyor. Two conveyors with an intermediate transfer tower are assumed to convey the coal to the coal stacker, which

transfer the coal to either the long

- term storage pile or to the reclaim area. The conveyor passes under a magnetic plate separator to remove tramp iron and then to the reclaim pile.

The reclaimer loads the coal into two vibratory feeders located in the reclaim hopper unde r the pile. The feeders transfer the coal onto a belt conveyor that transfers the coal to the coal surge
bin located in the crusher tower. The coal is reduced in size to 3 cm x 0 (11⁄4" x 0) by the crusher. A conveyor then transfers the coal to a transfer tower. In the transfer tower the coal is routed to the tripper, which loads the coal into one of three silos. Two sampling systems are supplied: the as

- received sampling system and the as

- fired sampling system. Data from the analyses are used to suppo rt the reliable and efficient operation of the plant.



## 4.2.2 Coal Grinding and Slurry Preparation

Coal is fed onto a conveyor by vibratory feeders located below each silo. The conveyor feeds the coal to an inclined conveyor that delivers the coal to the rod mill feed hopper. The feed hopper provides a surge capacity of about two hours and contains two hopper outlets. Each hopper outlet discharges onto a weigh feeder, which in turn feeds a rod mill. Each rod mill is sized to process 55 percent of the coal feed requirements of the gasifier. The rod mill grinds the coal and wets it with treated slurry water transferred from the slurry water tank by the slurry water pumps. The coal slurry is discharged through a trommel screen into the rod mill discharge

tank, an d then the slurry is pumped to the slurry storage tanks. The dry solids concentration of the final slurry is 63 percent. The Polk Power Station operates at a slurry concentration of 62

– 68

percent using bituminous coal [ 46 ].

The coal grinding system is equ ipped with a dust suppression system consisting of water sprays aided by a wetting agent. The degree of dust suppression required depends on localCarbon Dioxide Capture Sensitivity Analysis



### 193 environmental regulations. All of the tanks are equipped with vertical agitators to keep the coal slurry so lids suspended.

The equipment in the coal grinding and slurry preparation system is fabricated of materials appropriate for the abrasive environment present in the system. The tanks and agitators are rubber lined. The pumps are either rubber

- lined or har dened metal to minimize erosion. Piping is fabricated of high

- density polyethylene (HDPE).



## 4.2.3 Air Separation Unit (ASU) Choice and Integration

In order to economically and efficiently support IGCC projects, air separation equipment has

been modified and improved in response to production requirements and the consistent need to increase single train output. “Elevated pressure” air separation designs have been implemented
that result in distillation column operating pressures that are about twice as high a s traditional plants. In this study, the main air compressor discharge pressure was set at 1.3 MPa (190 psia) compared to a traditional ASU plant operating pressure of about 0.7 MPa (105 psia) [ 47 ]. For IGCC designs the elevated pressure ASU process minim izes power consumption and decreases the size of some of the equipment items. When the air supply to the ASU is integrated with the gas turbine, the ASU operates at or near the supply pressure from the gas turbine‟s air

compressor.

4.2.3.1 Residual Nitrogen Injection

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

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

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

By mixing with the syngas or by being injected directly into the combustor, the diluent nitrogen lowers the firing temperature (relative to natural gas) and r educes the formation

of NOx.

In this study, the ASU nitrogen product was used as the primary diluent with a design target of reducing the syngas lower heating value (LHV) to 4.5

- 4.8 MJ/Nm 3 

### (120

- 128 Btu/scf). If the amount of available nitrogen was not suf ficient to meet this target, additional dilution was provided through syngas humidification, and if still more dilution was required, the third option was steam injection.Carbon Dioxide Capture Sensitivity Analysis



### 194 4.2.3.2 Air Integration

Integration between the ASU and the CT can be practiced by extractin g some, or all, of the ASU‟s air requirement from the gas turbine. Medium Btu syngas streams result in a higher mass
flow than natural gas to provide the same heat content to the gas turbine. Some gas turbine designs may need to extract air to maintain s table compressor or turbine operation in response to increased fuel flow rates. Other gas turbines may balance air extraction against injection of all of the available nitrogen from the ASU. The amount of air extracted can also be varied as the

ambient t emperature changes at a given site to optimize year

- round performance.

An important aspect of air

- integrated designs is the need to efficiently recover the heat of compression contained in the air extracted from the gas turbine. Extraction air temperatu re is normally in the range of 399

– 454 °C (750

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

- level recovery from the extracted air occurs by transferring heat to the gas turbine nitrogen diluents stream with a gas

- to

gas heat exchanger.

4.2.3.3 Elevated Pressure ASU Experience in Gasification

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

- pressure, fully integrated ASU to be constructed. It was designed to prod uce up to 1,796 tonnes/day
(1,980 TPD) of 95 percent purity oxygen for a Shell coal

- based gasification unit that fuels a Siemens V94.2 gas turbine. In normal operation at the Buggenum plant

, the ASU receives all of its air supply from

, and sends all resid ual nitrogen to

, the gas turbine.

The Polk County, Florida

, ASU for the Tampa Electric IGCC is also an elevated

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

coal

- based gasification unit, which fuel s a General Electric 7FA gas turbine. All of the nitrogen produced in the ASU is used in the gas turbine. The original design did not allow for air extraction from the CT. After a CT air compressor failure in January 2005, a modification was

made to all ow air extraction which in turn eliminated a bottleneck in ASU capacity and increased overall power output [ 48 ].

4.2.3.4 ASU Basis

For this study, air integration is used for Design 1 only. For Designs 2 through 4

, where higher

CO 2 

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

The amount of air extracted from the gas turbine in Design 1 is determined t hrough a process that includes the following constraints:

The CT output must be maintained at 232 MW.

The diluted syngas must meet heating value requirements specified by a CT vendor, which ranged from 4.5

– 4.8 MJ/Nm 3 

### (120

– 128 Btu/scf) (LHV).Carbon Dioxide Capture Sensitivity Analysis



### 195 For Design 1, about 4 percent of the pressurized CT air supply was extracted, which accounts for approximately 16.8 percent of the total ASU air requirement. It was not a goal of this project to optimize the integration of the CT and the ASU, although several recent pa pers have shown that providing 25

- 30 percent of the ASU air from the turbine compressor provides the best balance between maximizing plant output and efficiency without compromising plant availability or reliability [ 49

, 50 ].

4.2.3.5 Air Separation Plant Process De scription [ 51 ]

The ASU is designed to produce 95 mole percent O 2 

### for use in the gasifier. The plant is designed with two production trains, one for each gasifier. The air compressor is powered by an electric motor. Nitrogen is also recovered, compressed, and used as a diluent in the gas turbine combustor. A process schematic of a typical ASU is shown in Exhibit 4

- 1

.

The air feed to the ASU is from on e or two sources, depending on the plant design. The bulk of the air is supplied from a stand

- alone compressor, while a portion is extracted from the compressor of the gas turbine in Design 1 only. Air to the stand

- alone compressor is first filtered

in a suction filter upstream of the compressor. This air filter removes particulate, which may tend to cause compressor wheel erosion and foul intercoolers. The filtered air is then compressed in the centrifugal compressor, with intercooling between each sta ge.

Air from the stand

- alone compressor is combined with the extraction air in Design 1, and the

combined stream is cooled and fed to an adsorbent

- based pre

- purifier system. The adsorbent

removes water, CO 2 

### , and C 4 

### + saturated hydrocarbons in the air. After passing through the adsorption beds, the air is filtered with a dust filter to remove any adsorbent fines that may be present. Downstream of the dust filter a small stream of air is withdrawn to supply the instrument air requirements o f the ASU.

Regeneration of the adsorbent in the pre

- purifiers is accomplished by passing a hot nitrogen stream through the off

- stream bed(s) in a direction countercurrent to the normal airflow. The nitrogen is heated against extraction steam (1.7 MPa [250 psia]) in a shell and tube heat exchanger. The regeneration nitrogen drives off the adsorbed contaminants. Following regeneration, the heated bed is cooled to near normal operating temperature by passing a cool nitrogen stream through the adsorbent beds . The bed is re

- pressurized with air and placed on

stream so that the current on

- stream bed(s) can be regenerated.

The air from the pre

- purifier is then split into three streams. About 70 percent of the air is fed directly to the cold box. About 25 perc ent of the air is compressed in an air booster compressor. This boosted air is then cooled in an aftercooler against cooling water in the first stage and against chilled water in the second stage before it is fed to the cold box. The chiller utilizes low pressure process steam at 0.3 MPa (50 psia). The remaining 5 percent of the air is fed to a

turbine

- driven, single

- stage, centrifugal booster compressor. This stream is cooled in a shell and tube aftercooler against cooling water before it is fed to the cold box.

All three air feeds are cooled in the cold box to cryogenic temperatures against returning product oxygen and nitrogen streams in plate

- and

- fin heat exchangers. The large air stream is fed directly to the first distillation column to begin the separation process. The second largest airCarbon Dioxide Capture Sensitivity Analysis



### 196 stream is liquefied against boiling liquid oxygen before it is fed to the distillation columns. The third, smallest air stream is fed to the cryogenic expander to produce refrigeration to sustain the cryogenic s eparation process.

Inside the cold box the air is separated into oxygen and nitrogen products. The oxygen product is withdrawn from the distillation columns as a liquid and is pressurized by a cryogenic pump. The pressurized liquid oxygen is then vaporiz ed against the high

- pressure air feed before being warmed to ambient temperature. The gaseous oxygen exits the cold box and is fed to the centrifugal compressor with intercooling between each stage of compression. The compressed oxygen is then fed to the gasification unit.

Nitrogen is produced from the cold box at two pressure levels. Low

- pressure nitrogen is split into two streams. The majority of the low

- pressure nitrogen is compressed and fed to the gas turbine as diluent nitrogen. A small portion o f the nitrogen is used as the regeneration gas for the

pre

- purifiers and recombined with the diluent nitrogen. A high

- pressure nitrogen stream is also produced from the cold box and is further compressed before it is also supplied to the gas

turbine.

Exhibit 4

- 1 Typical ASU Process SchematicCarbon Dioxide Capture Sensitivity Analysis



### 197 

## 4.2.4 Gasification

Each IGCC plant design in this study utilizes two gasification trains to process the Illinois No. 6 coal. Each of the 2 x 50 percent gasifiers opera tes at maximum capacity. The largest operating GEE gasifier is the 2,268 tonne/day (2,500 TPD) unit at Polk Power Station. However, that unit operates at about 2.8 MPa (400 psia). The gasifier in this study, which operates at 5.6 MPa (815 psia), will be able to process more coal and maintain the same gas residence time.

The slurry feed pump takes suction from the slurry run tank, and the discharge is sent to the feed injector of the GEE gasifier. Oxygen from the ASU is vented during preparation for star tup and is sent to the feed injector during normal operation. The ASU supplies 95 mole percent oxygen to the GEE gasifiers and the Claus plant. Carbon conversion in the gasifier is assumed to be 98

percent

, including a fines recycle stream.

The gasifier vessel is a refractory

- lined, high

- pressure combustion chamber. The coal slurry feedstock and oxygen are fed through a fuel injector at the top of the gasifier vessel. The coal
slurry and the oxygen react in the gasifier at 5.6 MPa (815 psia) and 1,316 ° C (2,400 F) to produce syngas.

The syngas consists primarily of hydrogen and carbon monoxide, with lesser amounts of water vapor and CO 2 

### , and small amounts of hydrogen sulfide, carbonyl sulfide, methane, argon, and nitrogen. The heat in the gasifier liqu efies coal ash. Hot syngas and molten solids from the reactor flow downward into a radiant heat exchanger where the syngas is cooled.



## 4.2.5 Raw Gas Cooling/Particulate Removal

Syngas is cooled from 1,316 °C (2,400 °F) to 677 °C (1

, 250 °F) in the radiant synthes is gas cooler and the molten slag solidifies in the process. The solids collect in the water sump at the bottom of the gasifier and are removed periodically using a lock hopper system. The waste heat from this cooling is used to generate high

- pressure sa turated steam. Boiler feedwater in the tubes is saturated, and then steam and water are separated in a steam drum. This steam then forms part of the general heat recovery system that provides steam to the steam turbine.

The syngas exiting the radiant coo ler is directed downwards by a dip tube into a water sump. Most of the entrained solids are separated from the syngas at the bottom of the dip tube as the syngas goes upwards through the water. The syngas exits the quench chamber saturated at a

temperatu re of 223 °C (450 °F)

.

The slag handling system removes solids from the gasification process equipment. These solids consist of a small amount of unconverted carbon and essentially all of the ash contained in the

feed coal. These solids are in the form of glass, which fully encapsulates any metals. Solids collected in the water sump below the radiant synthesis gas cooler are removed by gravity and forced circulation of water from the lock hopper circulating pump. The fine solids not removed

from the bo ttom of the quench water sump remain entrained in the water circulating through the quench chamber. In order to limit the amount of solids recycled to the quench chamber, a continuous blowdown stream is removed from the bottom of the syngas quench. The b lowdownCarbon Dioxide Capture Sensitivity Analysis



### 198 is sent to the vacuum flash drum in the black water flash section. The circulating quench water is pumped by circulating pumps to the quench gasifier.



## 4.2.6 Syngas Scrubber/Sour Water Stripper

Syngas exiting the water quench passes to a syngas scrubber where a water wash is used to remove remaining chlorides and particulate. The syngas exits the scrubber still saturated at 206
°C (403 °F).

The sour water stripper removes NH 3 

### , SO 2 

### , and other impurities from the scrubber and other

waste streams. The stri pper consists of a sour drum that accumulates sour water from the gas scrubber and condensate from synthesis gas coolers. Sour water from the drum flows to the sour stripper, which consists of a packed column with a steam

- heated reboiler. Sour gas is str ipped from the liquid and sent to the sulfur recovery unit. Remaining water is sent to wastewater

treatment.



## 4.2.7 Water Gas Shift Reactors

In this study, IGCC Designs 2 through 4 include water gas shift (WGS) reactor(s). The WGS

reaction convert s most of the syngas carbon monoxide (CO) to hydrogen and CO 2 

### by reacting the CO with water over a bed of catalyst. A typical offering from a commercial catalyst vendor

is a steam

- to

- dry gas (S:DG) molar ratio of 0.3 at the outlet of the final shift reactor. The

funct ion of this excess steam is to drive the shift equilibrium toward the products. The reaction consumes one mol of water per mol of CO converted, and releases heat in the process:

H 2 

### O + CO  H 2 

### + CO 2 

### H

rxn 

### =

- 17,697 Btu/lb

- mol (1)

The WGS reactor(s) can be located either upstream of the AGR system (sour gas shift) or immediately downstream (sweet gas shift). If the WGS is located downstream of the AGR, then the metallurgy of the unit is less stringent but additional equipment must be added to the process. Products from the gasifier are humidified and contain a portion of the water vapor necessary to

meet the water

- to

- gas criteria at the reactor inlet. If the CO converter is located downstream of the AGR, then the gasifier product would first have to be cooled and the free water separated and treated. Then additional steam would have to be generated and re

- injected into the WGS feed to meet the required water

- to

- gas ratio. If the CO converter is located upstream of the AGR, no additional equipme nt is re quired since the WGS reactor(s) also promote carbonyl sulfide (COS) hydrolysis without a separate catalyst bed.

COS + H 2 

### O  H 2 

### S + CO 2 

### H

rxn 

### =

- 14,526 Btu/lb

- mol (2)

This reaction converts sulfur to a form (H 2 

### S) that is removed more readily than COS in an AGR system, helping to meet emission specifications. The SelexolTM solvent‟s affinity for H 2 

### S is nearly 4 times greater than it is for COS [ 52 ]. Since this physical solvent‟s driving force is
partial pressure, and sulfur concentrations are relati vely low to begin with, conversion to H 2 

### S (which the SelexolTM solvent can separate more easily) is effective in reducing the size of the SelexolTM process, while achieving the low sulfur levels required by local permitting agenciesCarbon Dioxide Capture Sensitivity Analysis



### 199 (this analysis assumes 0. 0128 lb SO 2 

### /MMBtu). Therefore , for this study the WGS was located upstream of the AGR and is referred to as sour gas shift (SGS).

Depending on the plant design, the SGS consists of either two paths of parallel fixed

- bed reactors arranged in series, or a s ingle, parallel fixed

- bed reactor. Cooling is provided between the series of reactors to control the exothermic temperature rise. The parallel set of reactors is required due to the high gas mass flow rate. The heat exchanger after the first SGS reactor is used to vaporize water. The heat exchanger after the second SGS reactor is used to raise IP steam, which then passes through the reheater section of the HRSG in the GEE IGCC plant design. Approximately 96 percent conversion of the CO is achieved in t he GEE design.

The default S:DG ratio (0.3) represents a typical offering by a commercial catalyst vendor. The WGS and COS hydrolysis reactions occur at locations within the catalyst matrix, referred to as active sites, where water molecules have formed w ea k chemical bonds with the catalyst material

. In order for chemical bonding of water molecules to occur on the catalyst surface, diffusion of

H 2 

### O through the bulk syngas must first occur. At the base case S:DG ratio, diffusion rates are fast enough such that there are adequate active catalyst sites on which the reactions can occur. This helps to maintain reasonable reactor sizes and costs.

A key portion of this study is devoted to optimizing the WGS step for lower degrees of carbon capture. The three methods that will be investigated are : ( 1) to bypass a portion of syn gas around the shift reactor(s); ( 2) to use less shift steam (a S :DG ratio of 0.25 will be used); and ( 3)

to use one shift reactor instea d of two (D 2). These will be used in combination with one another in order to arrive at the optimum configuration for each level of CO 2 

### capture.



## 4.2.8 Mercury Removal

An IGCC power plant has the potential of removing mercury in a more simple and cost

- effective manner than conventional PC plants. This is beca use mercury can be removed from the syngas at elevated pressure and prior to combustion so that syngas volumes are much smaller than flue gas volumes in comparable PC cases. A conceptual design for a carbon bed adsorption system was developed for mercury control in the IGCC plants being studied. Data on the performance of carbon bed systems were obtained from the Eastman Chemical Company, which uses carbon beds at its syngas facility in Kingsport, Tennessee [ 53 ]. The coal mercury content (0.15 ppm dry) an d carbon bed removal efficiency (95 percent) were discussed previously in Sections 2.2

and 2.4 . IGCC

- specific design considerations are discussed below.

Carbon Bed Location

– The packed carbon bed vessels are located upstream of the sulfur recovery unit and syngas enters at a temperature near 35 °C (95 °F). Eastman Chemical also operates their beds ahead of their sulfur recovery unit at a temperature of 30 °C (86 °F) [ 53 ].

Process Parameters

– An empty vessel basi s gas residence time of approximately 20 seconds was used based on Eastman Chemical‟s experience [ 53 ]. Allowable gas velocities are limited by

considerations of particle entrainment, bed agitation, and pressure drop. One

- foot

- per

- second superficial velocity is in the middle of the range normally encountered and was selected for this application.Carbon Dioxide Capture Sensitivity Analysis



### 200 The bed density of 30 lb/ft 3 

### was based on the Calgon Carbon Corpor ation HGR

- P sulfur

impregnated pelletized activated carbon. These parameters determined the size of the vessels and the amount of carbon required. Each gasifier train has one mercury removal bed and there are two gasifier trains in each IGCC case, result ing in two carbon beds per case.

Carbon Replacement Time

– Eastman Chemicals replaces its bed every 18 to 24 months [ 53 ]. However, bed replacement is not because of mercury loading, but for other reasons including:

A buildup in pressure drop

A buildup of water in the bed

A buildup of other contaminants

For this study, a 24 month carbon replacement cycle was assumed. Under these assumptions, the mercury loading in the bed would build up to 0.6

– 1.1 weight percent (wt%). Mercury capacity

of sulfur

- impregnated carbon can be as high as 20 wt%. The mercury

- laden carbon is considered to be a hazardous waste, and the disposal cost estimate reflects this categorization.



## 4.2.9 A cid Gas Removal (AGR) Process Selection

Gasification of coal to generate power produces a syngas that must be treated prior to further utilization. A portion of the treatment consists of acid gas removal (AGR) and sulfur recovery. The environmental targe t for these IGCC plant designs is 0.0128 lb SO 2 

### /MMBtu, which requires that the total sulfur content of the syngas be reduced to less than 30 ppmv. This includes all sulfur species, but in particular the total of COS and hydrogen sulfide (H 2 

### S), thereby res ulting in stack gas emissions of less than 4 ppmv SO 2



### .

4.2.9.1 COS Hydrolysis

The use of COS hydrolysis pretreatment in the feed to the AGR process provides a means to reduce the COS concentration. This method was first commercially proven at the Buggenum plant, and was also used at both the Tampa Electric and Wabash River IGCC projects. Several catalyst manufacturers including Haldor Topsoe and Porocel offer a catalyst that promotes the COS hydrolysis reaction. The COS hydrolysis reactor design employed in this study

, for IGCC Designs 1 through 3

, is based on information from Porocel. However, the WGS reactor ( s ) also

reduce COS to H 2 

### S as discussed in Section 4.2.7

.

The COS hydrolysis reaction is equimolar with a slightly exothermic heat of reaction. The

rea ction is represented as follows:

COS + H 2 

### O ↔ CO 2 

### + H 2 

### S

Since the reaction is exothermic, higher conversion is achieved at lower temperatures. However, at lower temperatures the reaction kinetics are slower. Based on the feed gas for this evaluation, Porocel recommended a temperature of 177 to 204°C (350 to 400°F). Since the exit gas COS

concentrat ion is critical to the amount of H 2 

### S that must be removed with the AGR process, a

retention time of 50

- 75 seconds was used to achieve 99.5 percent conversion of the COS. TheCarbon Dioxide Capture Sensitivity Analysis



### 201 Porocel activated alumina

- based catalyst, designated as Hydrocel 640 catalyst, pr omotes the COS hydrolysis reaction without promoting reaction of H 2 

### S and CO to form COS and H 2



### .

Although the reaction is exothermic, the heat of reaction is dissipated among the large amount of

non

- reacting components. Therefore, the reaction is essential ly isothermal. The product gas, now containing less than 4 ppmv of COS, is cooled prior to entering the mercury removal process and the AGR.

4.2.9.2 Sulfur Removal

H 2 

### S removal generally consists of absorption by a regenerable solvent. The most commonly

used tec hnique is based on countercurrent contact with the solvent. Acid gas

- rich solution from the absorber is stripped of its acid gas in a regenerator, usually by application of heat. The regenerated lean solution is then cooled and recirculated to the top of the absorber, completing the cycle. Exhibit 4

- 2 is a simplified diagram of the AGR process [ 52 ].

There are well over 30 AGR processes in common commercial use throughout the oil, chemical, and natural gas industries. However, in a 2002 report by SFA Pacific a list of 42 operating and planned gasifiers shows that only six AGR processes are represented: Rectisol ® 

### , Sulfinol, methyldiethanolamine (MDEA), SelexolTM, aqueous di

- isoproponal amine (DIPA), and

FLEXSORB [ 52 ]. These processes can be separated into three general types: chemical reagents, physical solvents, and hybrid solvents.

Exhibit 4

- 2 Flow Diagram for a Conventional AGR Unit



### Chemical Solvents

Frequently used for AGR, chemical solvents are more suitable than physical or hybrid solvents for applications at lower operating pressures. The chemical nature of acid gas absorption makes solution loading and circulation less dependent on the acid gas partial pressure. Because theCarbon Dioxide Capture Sensitivity Analysis



### 202 solution is aqueous, co

- absorption of hydrocarbons is minimal. In a conventional amine unit, the chemical solvent reacts exothermically with the acid gas constituents. They form a weak

chemical bond that can be bro ken, releasing the acid gas and regenerating the solvent for reuse.

In recent years MDEA, a tertiary amine, has acquired a much larger share of the gas

- treating market. Compared with primary and secondary amines, MDEA has superior capabilities for

selecti vely removing H 2 

### S in the presence of CO 2 

### , is resistant to degradation by organic sulfur compounds, has a low tendency for corrosion, has a relatively low circulation rate, and consumes less energy. Several MDEA

- based solvents that are formulated for high H 2 

### S selectivity are commercially

- available.

Chemical reagents are used to remove the acid gases by a reversible chemical reaction of the acid gases with an aqueous solution of various alkanolamines or alkaline salts in water. Exhibit 4

- 3 lists commonly used chemical reagents along with principal licensors that use them in their processes. The process consists of an absorber and regenerator, which are connected by a circulation of the chemical reagent aqueous solution. The absorber contacts the lean solution with the main gas stream (at pressure) to remove the acid gases by absorption/ reaction with the

chemical solution. The acid

- gas

- rich solution is reduced to low pressure and heated in the stripper to reverse the reactions and strip the acid gas. The acid

- gas

- lean solution leaves the bottom of the regenerator stripper and is cooled, pumped to the required pressure and

recirculated back to the absor ber. For some amines, a filter and a separate reclaiming section (not shown) are needed to remove undesirable reaction byproducts.

Exhibit 4

- 3 Common Chemical Reagents Used in AGR Processes

Chemical Reagent Acronym Process Licensors Using the Reagent

Monoethanolamine MEA Dow, Exxon, Lurgi, Union Carbide

Diethanolamine DEA Elf, Lurgi

Diglycolamine DGA Texaco, Fluor

Triethanolamine TEA AMOCO

Diisopropanolamine DIPA Shell

Methyldiethanolamine MDEA BASF, Dow, Elf, Snamprogetti, Shell, Union
Carbide, Coastal Chemical

Hindered amine Exxon

Potassium carbonate ―hot pot‖ Eickmeyer, Exxon, Lurgi,

Union Carbide



### Typically, the absorber temperature is 27 to 49 °C (80 to 120 °F) for amine processes, and the regeneration temperature is the boiling point of the solutions, generally 104 to 127 °C (220 to

260 °F). The liquid circulation rates can vary widely, depending on the amount of acid gas being captured. However, the most suitable processes are those that will dissolve 2 to 10 scf acid gas per gallon of solution circulated. Steam consumption can vary widely also: 0.7 to 1.5 pounds per gallon of liquid is typical

.Carbon Dioxide Capture Sensitivity Analysis



### 203 The major advantage of these systems is the ability to remove acid gas to low levels a t low to

moderate H 2 

### S partial pressures.

Physical Solvents

Physical solvents involve absorption of acid gases into certain organic solvents that have a high solubility for acid gases. As the name implies, physical solvents involve only the physical

solu tion of acid gas

– the acid gas loading in the solvent is proportional to the acid gas partial pressure (Henry‟s Law). Physical solvent absorbers are usually operated at lower temperatures
than is the case for chemical solvents. The solution step occurs at high pressure and at or below ambient temperature while the regeneration step (dissolution) occurs by pressure letdown and indirect stripping with low

- pressure 0.45 MPa (65 psia) steam. It is generally accepted that physical solvents become increasingl y economical, and eventually superior to amine capture, as the partial pressure of acid gas in the syngas increases.

The physical solvents are regenerated by multistage flashing to low pressures. Because the solubility of acid gases increases as the tempe rature decreases, absorption is generally carried out at lower temperatures, and refrigeration is often required.

Most physical solvents are capable of removing organic sulfur compounds. Exhibiting higher solubility of H 2 

### S than CO 2 

### , they can be designed f or selective H 2 

### S or total acid gas removal. In applications where CO 2 

### capture is desired the CO 2 

### is flashed off at various pressures, which reduces the compression work and parasitic power load associated with sequestration.

Physical solvents co

- absorb he avy hydrocarbons from the feed stream. Since heavy hydrocarbons cannot be recovered by flash regeneration, they are stripped along with the acid gas during heated regeneration. These hydrocarbon losses result in a loss of valuable product and may lead to CO 2 

### contamination.

Several physical solvents that use anhydrous organic solvents have been commercialized. They include the SelexolTM process, which uses dimethyl ether of polyethylene glycol as a solvent;

Rectisol ® 

### , with methanol as the solvent; Puriso l, which uses N

- methyl

- 2

- pyrrolidone (NMP) as a solvent; and the propylene

- carbonate process.

Exhibit 4

- 4 is a simplified flow diagram for a physical r eagent type acid gas removal process

[ 52 ]. Common physical solvent processes, along with their licensors, are listed in Exhibit 4

- 5

.Carbon Dioxide Capture Sensitivity Analysis



### 204 Exhibit 4

- 4 Physical Solvent AGR Process Simplified Flow Diagram

Exhibit 4

- 5 Common Physical Solvents Used in AGR Processes



### Solvent Solvent/Process

Trade Name Process

Licensors

Dimethyl ether of poly ethylene glycol SelexolTM UOP

Methanol Rectisol ® Linde AG and Lurgi

Methanol and toluene Rectisol II Linde AG

N

— methyl pyrrolidone Purisol Lurgi

Polyethylene glycol and dialkyl

ethers Sepasolv MPE BASF

Propylene carbonate Fluor Solvent Fluor

Tetrahydrothiophenedioxide Sulfolane Shell

Tributyl phosphate Estasolvan Uhde and IFP



### Hybrid Solvents

Hybrid solvents combine the high treated

- gas purity offered by chemical solvents with the flash regeneration and lower energy requirements of physical solvents. Some examples of hybrid

solvents are Sulfinol, Flexsorb PS, and Ucarsol LE.Carbon Dioxide Capture Sensitivity Analysis



### 205 Sulfinol is a mixture of sulfolane (a phys ical solvent), DIPA or MDEA (chemical solvent), and water. DIPA is used when total acid gas removal is specified, while MDEA provides for

selective removal of H 2 

### S.

Flexsorb PS is a mixture of a hindered amine and an organic solvent. Physically similar to Sulfinol, Flexsorb PS is very stable and resistant to chemical degradation. High treated

- gas purity, with less than 50 ppmv of CO 2 

### and 4 ppmv of H 2 

### S, can be achieved. Both Ucarsol LE

701, for selective removal, and LE

- 702, for total acid gas removal, ar e formulated to remove mercaptans from feed gas.

Mixed chemical and physical solvents combine the features of both systems. The mixed solvent allows the solution to absorb an appreciable amount of gas at high pressure. The amine portion

is effective as a reagent to remove the acid gas to low levels when high purity is desired.

Mixed solvent processes generally operate at absorber temperatures similar to those of the

amine

- type chemical solvents and do not require refrigeration. They also retain some adva ntages of the lower steam requirements typical of the physical solvents. Common mixed chemical and physical solvent processes, along with their licensors, are listed in Exhibit 4

- 6 . The key advantage of mixed solvent processes is their apparent ability to remove H 2 

### S and, in some cases, COS to meet very stringent purified gas specifications.

Exhibit 4

- 6 Common Mixed Solvents Used in AGR Processes

Solvent/Chemical Reagent Solvent/Process

Trade Name Process

Licensors

Methanol/MDEA or diethylamine Amisol Lurgi

Sulfolane/MDEA or DIPA Sulfinol Shell

Methanol and toluene Selefining Snamprogetti

(Unspecified) /MDEA FLEXSORB PS Exxon



### Exhibit 4

- 7 shows reported equilibrium solubility data for H 2 

### S and CO 2 

### in various representative
solvents [ 52 ]. The solubility is expressed as standard cubic feet of gas per gallon liquid per atmosphere gas partial pressure.

The figure illustrates the relative solubilities of CO 2 

### and H 2 

### S in different solvents and the effects of temperature. More importantly, it shows an order of magnitude higher solubility of H 2 

### S over

CO 2 

### at a given temperature, which gives rise to the selective absorption of H 2 

### S in physical solvents. It also illustrates that the acid gas solubility in physical solvents increases with lower

sol vent temperatures.Carbon Dioxide Capture Sensitivity Analysis



### 206 Exhibit 4

- 7 Equilibrium Solubility Data on H 2 S and CO 2 in Various Solvents



### The ability of a process to selectively absorb H 2 

### S may be further enhanced by the relative absorption rates of H 2 

### S and CO 2 

### . Thus, some processes, besides using equilibrium solubility differences, will use absorption rate differences between the two acid gases to achieve selectivity. This is particularly true of the amine processes where the CO 2 

### and H 2 

### S absorptio n rates are very different.

4.2.9.3 SelexolTM System

There are numerous commercial AGR processes that could meet the sulfur environmental target of this study. The most frequently used AGR systems (SelexolTM, Sulfinol, MDEA, and

Rectisol ® 

### ) have all been used with the GE E gasifier in various applications. For Design 1, aCarbon Dioxide Capture Sensitivity Analysis



### 207 single

- stage SelexolTM system was chosen based on the GE E gasifier operating at a high pressure (815 psia), which favors the physical solvent used in the SelexolTM process.

For Designs 2 through 4, a two

- stage SelexolTM process was employed for selective H 2 

### S removal

and bulk CO 2 

### capture. The two

- stage SelexolTM system was chosen based on the GE E gasifier operating at a high pressure (815 psia), which favors the physical solvent used in the SelexolTM

pro cess. A brief process description follows.

Untreated syngas enters the first of two absorbers where H 2 

### S is preferentially removed using

loaded solvent from the CO 2 

### absorber. The gas exiting the H 2 

### S absorber passes through the

second absorber where CO 2 

### is removed using first flash regenerated, chilled solvent followed by thermally regenerated solvent added near the top of the column. The treated gas exits the absorber and is sent either directly to the CT or is partially humidified prior to entering the C T

. A portion of the gas can also be used for coal drying, when required.

The amount of hydrogen recovered from the syngas stream is dependent on the SelexolTM
process design conditions. In this study, hydrogen recovery is 99.4 percent. The minimal hydrog en slip to the CO 2 

### sequestration stream maximizes the overall plant efficiency. The SelexolTM plant cost estimates are based on a plant designed to recover this high percentage of
hydrogen. For model simplification, a nominal recovery of 100 percent was u sed with the assumption that the additional 0.6 percent hydrogen sent to the CT would have a negligible impact on overall system performance.

The CO 2 

### loaded solvent exits the CO 2 

### absorber and a portion is sent to the H 2 

### S absorber, a portion is sent to a re absorber and the remainder is sent to a series of flash drums for regeneration. The CO 2 

### product stream is obtained from the three flash drums, and after flash regeneration the solvent is chilled and returned to the CO 2 

### absorber.

The rich solvent exiting t he H 2 

### S absorber is combined with the rich solvent from the reabsorber and the combined stream is heated using the lean solvent from the stripper. The hot, rich solvent

enters the H 2 

### S concentrator and partially flashes. The remaining liquid contacts nitro gen from the ASU and a portion of the CO 2 

### along with lesser amounts of H 2 

### S and COS are stripped from the rich solvent. The stripped gases from the H 2 

### S concentrator are sent to the reabsorber where

the H 2 

### S and COS that were co

- stripped in the concentrator are transferred to a stream of loaded

solvent from the CO 2 

### absorber. The clean gas from the reabsorber is combined with the clean gas from the H 2 

### S absorber and sent to the CT

.

The solvent exiting the H 2 

### S concentrator is sent to the stripper where the abso rbed gases are liberated by hot gases flowing up the column from the steam heated reboiler. Water in the overhead vapor from the stripper is condensed and returned as reflux to the stripper or exported as necessary to maintain the proper water content of the lean solvent. The acid gas from the stripper is sent to the Claus plant for further processing. The lean solvent exiting the stripper is first cooled by providing heat to the rich solvent, then further cooled by exchange with the product gas and fina lly chilled in the lean chiller before returning to the top of the CO 2 

### absorber. A Selexol process flow diagram is shown in Exhibit 4

- 8

.Carbon Dioxide Capture Sensitivity Analysis



### 20 8 Exhibit 4

- 8 Generic Two

- Stage SelexolTM Process Flow Diagram



## 4.2.10 CO 2 

## Compression and Dehydration

CO 2 

### from the two

- stage SelexolTM unit in IGCC Designs 2 through 4 is flashed at three pressure

levels to separate CO 2 

### and decrease H 2 

### losses to the CO 2 

### pipeline. The HP CO 2 

### stream is flashed at 2.0 MPa (289.7 psia), compressed, and recycled back to the CO 2 

### absorber. The MP CO 2 

### stream is flashed at 1.0 MPa (149.7 psia). The LP CO 2 

### stream, is flashed at 0.1 MPa (16.7 psia), and is compressed to 1.0 MPa (149.5 psia) and combined with the MP CO 2 

### stream. The combined stream is compressed from 2.1 MPa (300 psi a) to a supercritical condition at 15.3 MPa
(2

, 215 psia) using a multiple

- stage, intercooled compressor. During compression, the CO 2 

### stream is dehydrated to a dewpoint of

- 40 oC (

- 40 °F) with triethylene glycol. The raw CO 2 

### stream from the SelexolTM proce ss contains over 99 percent CO 2 

### with the balance primarily hydrogen. The CO 2 

### is transported to the plant fence line and is sequestration ready. CO 2 

### TS&M costs were estimated using the methodology described in Section 2.7

.



## 4.2.11 Sulfur Recovery/Tail Gas Cleanup Process Selection

Currently, most of the world‟s sulfur is produced from the acid gases coming from gas treating.
The Claus process remains the mainstay for sulfu r recovery. Conventional three

- stage Claus plants, with indirect reheat and feeds with a high H 2 

### S content, can approach 98 percent sulfur recovery efficiency. However, since environmental regulations have become more stringent, sulfur recovery plants are required to recover sulfur with over 99.8 percent efficiency. To meet these stricter regulations, the Claus process underwent various modifications and add

- ons.Carbon Dioxide Capture Sensitivity Analysis



### 209 The add

- on modification to the Claus plant selected for this study can be considered a separa te option from the Claus process. In this context, it is often called a tail gas treating unit (TGTU)

process.

4.2.11.1 The Claus Process

The Claus process converts H 2 

### S to elemental sulfur via the following reactions:

H 2 

### S + 3/2 O 2 

### ↔ H 2 

### O + SO 2



### 2H 2 

### S + SO 2 

### ↔ 2H 2 

### O + 3S

The second reaction, the Claus reaction, is equilibrium limited. The overall reaction is:

3H 2 

### S + 3/2 O 2 

### ↔ 3H 2 

### O + 3S

The sulfur in the vapor phase exists as S 2 

### , S 6 

### , and S 8 

### molecular species, with the S 2 

### predominant at higher temperatures, and S 8 

### predomi nant at lower temperatures.

A simplified process flow diagram of a typical three

- stage Claus plant is shown in Exhibit 4

- 9

[ 52 ]. One

- third of the H 2 

### S is burned in the furnace with oxygen from the air to give sufficient

SO 2 

### to react with the remaining H 2 

### S. Since these reactions are highly exothermic, a waste h eat boiler that recovers this heat to generate high

- pressure steam usually follows the furnace. Sulfur is condensed in a condenser that follows the high

- pressure steam recovery section. Low

- pressure steam is raised in the condenser. The tail gas from th e first condenser then goes to several catalytic conversion stages, usually 2 to 3, where the remaining sulfur is recovered via the Claus reaction. Each catalytic stage consists of gas preheat, a catalytic reactor, and a sulfur condenser. The liquid sulf

ur goes to the sulfur pit, while the tail gas proceeds to the incinerator or for further processing in a TGTU.

4.2.11.2 Claus Plant Sulfur Recovery Efficiency

The Claus reaction is equilibrium limited, and sulfur conversion is sensitive to the reaction

temperature. The highest sulfur conversion in the thermal zone is limited to about 75 percent. Typical furnace temperatures are in the range from 1

, 093 to 1427 °C (2

, 000 to 2

, 600 °F), and as the temperature decreases, conversion increases dramatically.Carbon Dioxide Capture Sensitivity Analysis



### 210 Exhibit 4

- 9 Typical Three

- Stage Claus Sulfur Plant



### Claus plant sulfur r ecovery efficiency depends on many factors , including :

H 2 

### S concentration of the feed gas

Number of catalytic stages

Gas reheat method

In order to keep Claus plant recovery efficiencies approaching 94 to 96 percent for feed gases

that contain about 20 to 50 percent H 2 

### S, a split

- flow design is often used. In this version of the Claus plant, part of the feed gas is bypassed around the furnace to the first catalytic stage, while the rest of the gas is oxidized in the furnace to mostly SO 2 

### . This results in a more stable temperature in the furnace.

4.2.11.3 Oxygen

- Blown Claus

Large diluent streams in the feed to the Claus plant, such as N 2 

### from combustio n air, or a high

CO 2 

### content in the feed gas, lead to higher cost Claus processes and any add

- on or tail gas units. One way to reduce diluent flows through the Claus plant and to obtain stable temperatures in the

furnace for dilute H 2 

### S streams is the oxyg en

- blown Claus process.

The oxygen

- blown Claus process was originally developed to increase capacity at existing conventional Claus plants and to increase flame temperatures of low H 2 

### S content gases. The process has also been used to provide the capacity and operating flexibility for sulfur plants where the feed gas is variable in flow and composition such as often found in refineries. The application of the process has now been extended to grass roots installations, even for rich H 2 

### SCarbon Dioxide Capture Sensitivity Analysis



### 211 feed streams, to pro vide operating flexibility at lower costs than would be the case for conventional Claus units. At least four of the recently built gasification plants in Europe use oxygen enriched Claus units.

Oxygen enrichment results in higher temperatures in the front

- end furnace, potentially reaching temperatures as high as 1

, 593 to 1

, 649 °C (2

, 900 to 3

, 000 °F) as the enrichment moves beyond

40 to 70 vol percent O 2 

### in the oxidant feed stream. Although oxygen enrichment has many benefits, its primary benefit for lean H 2 

### S feeds is a stable furnace temperature. Sulfur recovery is not significantly enhanced by oxygen enrichment. Because the IGCC process already requires an ASU, the oxygen

- blown Claus plant was chosen for all plant designs.

4.2.11.4 Tail Gas Treating

In many refi nery and other conventional Claus applications, tail gas treating involves the removal of the remaining sulfur compounds from gases exiting the sulfur recovery unit. Tail gas from a typical Claus process, whether a conventional Claus or one of the extende d versions of the process, usually contains small but varying quantities of COS, CS 2 

### , H 2 

### S, SO 2 

### , and elemental sulfur vapors. In addition, there may be H 2 

### , CO, and CO 2 

### in the tail gas. In order to remove the rest of the sulfur compounds from the tail gas, all of the sulfur

- bearing species must first be

converted to H 2 

### S. Then, the resulting H 2 

### S is absorbed into a solvent and the clean gas vented or recycled for further processing. The clean gas resulting from the hydrolysis step can undergo further cleanup in a dedicated absorption unit or be integrated with an upstream AGR unit. The latter option is particularly suitable with physical absorption solvents. The approa ch of treating the tail gas in a dedicated amine absorption unit and recycling the resulting acid gas to the Claus plant is the one used by the Shell Claus Off

- gas Treating (SCOT) process. With tail gas treatment, Claus plants can achieve overall removal efficiencies in excess of 99.9 percent.

In the case of IGCC applications, the tail gas from the Claus plant can be catalytically hydrogenated and then recycled back into the system with the choice of location being technology dependent, or it can be treate d with a SCOT

- type process. For the GEE gasifier, the Claus plant tail gas is hydrogenated, water is separated, and the tail gas is compressed and returned to the SelexolTM process for further treatment. GEE experience at the Polk Power

Station is not rel evant to this study since the acid gas is converted to sulfuric acid rather than sulfur and the tail gas, containing 150

- 250 ppm SO 2 

### , is discharged through a dedicated stack

[ 46 ].

4.2.11.5 Flare Stack

A self

- supporting, refractory

- lined, carbon steel flare stack is typically provided to combust and dispose of unreacted gas during startup, shutdown, and upset conditions. However, in each IGCC plant design a flare stack was provided for syngas dumping during startup, shutdown, etc. This flare stack eliminates the need for a separate Claus plant flare.



## 4.2.12 Slag Handling

The slag handling system conveys, stores, and disposes of slag removed from the gasification
process. Spent m aterial drains from the gasifier bed into a water bath in the bottom of theCarbon Dioxide Capture Sensitivity Analysis



### 212 gasifier vessel. A slag crusher receives slag from the water bath and grinds the material into pea

sized fragments. A slag/water slurry that is between 5 and 10 percent solids le aves the GEE gasifier pressure boundary through the use of lockhoppers to a series of dewatering bins.

The slag is dewatered, the water is clarified and recycled and the dried slag is transferred to a storage area for disposal. The specifics of slag handl ing vary among the gasification technologies regarding how the water is separated and the end uses of the water recycle streams.

In this study, the slag bins were sized for a nominal holdup capacity of 72 hours of full

- load operation. At periodic interval s, a convoy of slag

- hauling trucks will transmit the unloading station underneath the hopper and remove a quantity of slag for disposal. Approximately ten truckloads per day are required to remove the total quantity of slag produced by the plant operating at nominal rated power. While the slag is suitable for use as a component of road paving mixtures, it was assumed in this study that the slag would be landfilled at a specified cost just as the ash from the PC boiler cases is assumed to be landfilled at the same per ton cost.



## 4.2.13 Power Island

4.2.13.1 Combustion Turbine

The gas turbine generator selected for this application is representative of the advanced F Class turbines. This machine is an axial flow, single spool, and constant speed unit, with variable inlet guide vanes. The turbine includes advanced bucket cooling techniques, compressor aerodynamic design and advanced alloys, enabling a higher firing temperature than the previous generation machines. The standard production version of this machine is fired with natural gas and is also commercially offered for use with IGCC derived syngas, although only earlier versions of the turbine are currently operating on syngas. For the purposes of this study, it was assumed that the

advanced F Class turbine will be c ommercially available to support a 20 15 startup date on both conventional and high hydrogen content syngas representative of the cases with CO 2 

### capture. High H 2 

### fuel combustion issues like flame stability, flashback and NOx formation were assumed

to be so lved in the time frame needed to support deployment. However, because these are first

of

- a

- kind applications, process contingencies were included in the cost estimates as described in

Section 2.7 . Performance typical of an advanced F class turbine on natural gas at ISO conditions is presented in Exhibit 4

- 10

.Carbon Dioxide Capture Sensitivity Analysis



### 213 Exhibit 4

- 10 Advanced F Class Combustion Turbine Performance

Characteristics Using Natural Gas

Advanced F Class

Firing Temperature Class, °C ( F) 1371+ (2500+)

Airflow, kg/s (lb/s) 431 (950)

Pressure Ratio 18.5

NOx Emissions, ppmv 25

Simple Cycle Output, MW 185

Combined cycle performance

Net Output, MW 280

Net Efficiency (LHV), % 57.5

Net Heat Rate (LHV), kJ/kWh (Btu/kWh) 6,256 (5,934)



### In this service, with syngas from an IGCC plant, the machine requires some modifications to the burner and turbine nozzles in order to properly combust the low

- Btu gas and expand the combustion products in the turbine section of the machine.

The modifications to the machine inc lude some redesign of the original can

- annular combustors. A second modification involves increasing the nozzle areas of the turbine to accommodate the

mass and volume flow of low

- Btu fuel gas combustion products, which are increased relative to those pro duced when firing natural gas. Other modifications include rearranging the various auxiliary skids that support the machine to accommodate the spatial requirements of the plant general arrangement. The generator is a standard hydrogen

- cooled machine with static exciter.

4.2.13.2 Combustion Turbine Package Scope of Supply

The CT is typically supplied in several fully shop

- fabricated modules, complete with all mechanical, electrical and control systems as required for CT operation. Site CT installation

involves mod ule inter

- connection, and linking CT modules to the plant systems. The CT package scope of supply for combined cycle applications, while project specific, does not vary much from project

- to

- project. The typical scope of supply is presented in Exhibit 4

- 11

.

Exhibit 4

- 11 Combustion Turbine Typical Scope of Supply

System System Scope

1.0 Engine Assembly Coupling to Generator, Dry Chemical Exhaust Bearing Fire Protection System,
Insulation Blankets, Platforms, Stairs and Ladders

1.1 Engine Assembly with Bedplate Variable Inlet Guide, Vane System Compressor, Bleed System, Purge Air System,

Bearing Seal Sir System, Combustors, Dual Fuel Nozzles Turbine Rotor Air Cooler

1.2 Walk

- in acoustical

enclosure HVAC, Lighting, and Low Pressure CO 2 Fire Protection SystemCarbon Dioxide Capture Sensitivity Analysis



### 214 System System Scope

2.0 Mechanical Package HVAC and Lighting, Air Compressor for Pneumatic System, Low Pressure CO 2

Fire Protection System

2.1

2.2 Lubricating Oil System and

Control Oil System Lube Oil Reservoir, Accumulators, 2x100% AC Driven Oil Pumps DC Emergency

Oil Pump with Starter, 2x100% Oil Coolers, Duplex Oil Filter, Oil Temperature and

Pressure Control Valves, Oil Vapor Exhaust Fans and Demister Oil Heaters Oil Interconnect Piping (SS and CS) Oil System Instrumentation Oil for Flushing and First Filling

3.0 Electrical Package HVAC and Lighting, AC and DC Motor Control Centers, Generator Voltage Regulati ng Cabinet, Generator Protective Relay Cabinet, DC Distribution Panel, Battery Charger, Digital Control System with Local Control Panel (all control and monitoring functions as well as data logger and sequence of events recorder), Control System Valves and Instrumentation Communication link for interface with plant DCS Supervisory System, Bentley Nevada Vibration Monitoring System, Low

Pressure CO 2 Fire Protection System, Cable Tray and Conduit Provisions for Performance Testing including Test Ports, Thermowells, Instrumentation and DCS

interface cards

4.0 Inlet And Exhaust Systems Inlet Duct Trash Screens, Inlet Duct and Silencers, Self Cleaning F ilters, Hoist

System For Filter Maintenance, Evaporative Cooler System, Exhaust Duct Expansion Joint, Exhaust Silencers Inlet and Exhaust Flow, Pressure and Temperature Ports and Instrumentation

5.0 Fuel Systems

5.1 Fuel Syngas System Gas Valves Including Vent, Throttle and Trip Valves Gas Filter/Separator Gas

Supply Instruments and Instrument Panel

5.2 Backup Fuel System Specific to backup fuel type

6.0 Starting System Enclosure, Starting Motor or Static Start System, Turning Gear and Clutch Assembly, Starting Clutch Torque Converter

7.0 Generator Static or Rotating Exciter (Excitation transformer to be included for a static system), Line Termination Enclosure with CTs, VTs, Surge Arrestors, and Surge Capacitors, Neutral Cubicle with CT, Neut ral Tie Bus, Grounding Transformer, and Secondary Resistor, Generator Gas Dryer, Seal Oil System (including Defoaming Tank, Reservoir, Seal Oil Pump, Emergency Seal Oil Pump, Vapor Extractor, and Oil Mist Eliminator), Generator Auxiliaries Control Enclosur e, Generator Breaker,

Iso

- Phase bus connecting generator and breaker, Grounding System Connectors

7.1 Generator Cooling TEWAC System (including circulation system, interconnecting piping and controls), or Hydrogen Cooling System (including H 2 to Glycol and Glycol to Air heat exchangers, liquid level detector circulation system, interconnecting piping and controls)

8.0 Miscellaneous Interconnecting Pipe, Wire, Tubing and Cable, Instrument Air System Including Air Dryer, On Line and Off Line Water Wash System, LP CO 2 Storage Tank, Drain System, Drain Tanks, Coupling, Coupling Cover and Associated HardwareCarbon Dioxide Capture Sensitivity Analysis



### 215 4.2.13.3 CT Firing Temperature Control Issue for Low Calorific Value Fuel

A gas turbine when fired on low calorific value syngas has the potential to increase power output due to the increase in flow rate through the turbine. The higher turbine flow and moisture content of the combustion products can contribute to overheating of turbine components, affect rating criteria for the parts lives, and req uire a reduction in syngas firing temperatures (compared to the natural gas firing) to maintain design metal temperature. [ 54 ] Uncontrolled syngas firing temperature could result in more than 50 percent life cycle reduction of stage 1 buckets. Control

sys tems for syngas applications include provisions to compensate for these effects by maintaining virtually constant generation output for the range of the specified ambient conditions. Inlet guide vanes (IGV) and firing temperature are used to maintain the turbine output at the maximum torque rating, producing a flat rating up to the IGV full open position. Beyond the IGV full open position, flat output may be extended to higher ambient air temperatures by steam/nitrogen injection.

In this study, the firing temperature (defined as inlet rotor temperature) with CO 2 

### capture is

1

, 318

– 1

, 327 °C (2

, 405

– 2

, 420° F). A reduction in firing temperature with CO 2 

### capture is done to maintain parts life as the water content of the combustion products increases to 14

– 16 vol%. The decrease in temperature also results in the lower temperature steam cycle with CO 2 

### capture

538 °C/538 °C [1

, 000 °F/1

, 000 °F].

4.2.13.4 Combustion Turbine Syngas Fuel Requirements

Typical fuel specifications and contaminant levels for successful CT o peration are presented for

F Class machines in Exhibit 4

- 12 and Exhibit 4

- 13 [ 55 ]. The vast majority of published CT performance information is specific to natural gas operation. Turbine performance using syngas requires vendor input as was obtained for this study.Carbon Dioxide Capture Sensitivity Analysis



### 216 Exhibit 4

- 12 Typical Fuel Specification for F

- Class Machines

Max Min

LHV, kJ/m 3 (Btu/scf) None 3.0 (100)

Gas Fuel Pressure, MPa (psia) 3.1 (450)

Gas Fuel Temperature, °C ( F) (1) Varies with gas pressure (2)

Flammability Limit Ratio, Rich

- to

- Lean,

Volume Basis (3) 2:2.1

Sulfur (4)

Notes:



### 1. The maximum fuel temperature is defined in reference [ 56 ]



### 2. To ensure that the fuel gas supply to the gas turbine is 100 percent free of liquids the minimum fuel gas temperature must meet the required superheat over the respective dew point. This requirement is independent of the hydrocarbon and moisture concentration. Superheat calculation shall be performed as described in GEI

- 4140G [ 55 ].



### 3. Maximum flammability ratio limit is not defined. Fuel with flammability ratio significantly larger than those of natural gas may require start

- up fuel



### 4. The quantity of sulfur in syngas is not limited by specification. Experience has shown that fuel sulfur levels up to 1 percent by volume do not significantly affect oxidation/corrosion

rates.



### 4.2.13.5 Normal Operation

Inlet air is compressed in a single spool compressor to a pressure ratio of approximately 16:1. This pressure ratio was vendor specified and less than the 18.5:1 ratio used in natural gas applications. The majority of compressor discharge air remains on

- board the machine and passes

to the burner section to support combustion of the syngas. Compressed air is also used in burner, transition, and film cooling services. About 4 percent of the compressor air is extracted and integrated with the air supply of the ASU in Design 1. It may be technically possible to integrate

the CT and ASU in CO 2 

### capture cases (Designs 2

– 4) as well; however, in this study integration was considered only for Design 1.Carbon Dioxide Capture Sensitivity Analysis



### 217 Exhibit 4

- 13 Allowable Gas Fuel Contaminant Level for F

- Class Machines

Turbine Inlet Limit, ppbw Fuel Limit, ppmw

Turbine Inlet Flow/Fuel Flow

50 12 4

Lead 20 1.0 0.240 .080

Vanadium 10 0.5 0.120 0.040

Calcium 40 2.0 0.480 0.160

Magnesium 40 2.0 0.480 0.160

Sodium + Potassium

Na/K = 28 (1) 20 1.0 0.240 0.080

Na/K = 3 10 0.5 0.120 0.40

Na/K ≤ 1 6 0.3 0.072 0.024

Particulates Total (2) 600 30 7.2 2.4

Above 10 microns 6 0.3 0.072 0.024

Notes:

1. Na/K=28 is nominal sea salt ratio

2. The fuel gas delivery system shall be designed to prevent generation or admittance of solid particulate to the gas turbine gas fuel system



### Pressurized syngas is combusted in several (14) parallel diffusion combustors and syngas

dilution is used to limit NOx formation. As described in Section 4.2.3.1 nitrogen from the ASU is used as the primary diluent followed by syngas humidification and finally by steam dilution, if

necessary, to achieve an LHV of 4.5

– 4.8 MJ/Nm 3 

### (120

– 128 Btu/scf). The advantages of using nitrogen as the primary diluent include:

Nitrogen from the ASU is already partially compressed and using it for dilution eliminates wasting the compression energy.

Limiting the water content reduces the need to de

- rate firing temperature for the high

hydrogen (CO 2 

### capture) cases.

There are some disadvantages to using nitrogen as the primary diluent, and these include:

There is a significant auxiliary power requirement to furt her compress the large nitrogen flow from the ASU pressures of 0.4 and 1.3 MPa (56 and 182 psia) to the CT pressure of 3.2 MPa (465 psia).

The low quality heat used in the syngas humidification process does not provide significant benefit to the process in other applications.

Nitrogen is not as efficient as water in limiting NO

x 

### emissions

It is not clear that one dilution method provides a significant advantage over the other. However, in this study nitrogen was chosen as the primary diluent based on sugge stions by turbine industry experts during peer review of the report.Carbon Dioxide Capture Sensitivity Analysis



### 218 Hot combustion products are expanded in the three

- stage turbine

- expander. Given the assumed

ambient conditions, back

- end loss, and HRSG pressure drop, the CT exhaust temperature is

nomin ally 566 °C (1

, 050 °F) with CO 2 

### capture.

Gross turbine power, as measured prior to the generator terminals, is 232 MW. The CT generator is a standard hydrogen

- cooled machine with static exciter.



## 4.2.14 Steam Generation Island

4.2.14.1 Heat Recovery Steam Generator

The heat recovery steam generator (HRSG) is a horizontal gas flow, drum

- type, multi

- pressure design that is matched to the characteristics of the gas turbine exhaust gas when firing medium

Btu gas. High

- temperature flue gas exiting the CT is conveyed through the HRSG to recover the large quantity of thermal energy that remains. Flue gas travels through the HRSG gas path and

exits at 132 °C (270 °F) for all four IGCC plant designs.

The high pressure (HP) drum produces steam at main steam pressure, while the i ntermediate pressure (IP) drum produces process steam and turbine dilution steam, if required. The HRSG drum pressures are nominally 12.4/2.9 MPa (1

, 800/420 psia) for the HP/IP turbine sections, respectively. In addition to generating and superheating st eam, the HRSG performs reheat duty for the cold/hot reheat steam for the steam turbine, provides condensate and feedwater heating, and also provides deaeration of the condensate.

Natural circulation of steam is accomplished in the HRSG by utilizing differe nces in densities due to temperature differences of the steam. The natural circulation HRSG provides the most

cost

- effective and reliable design.

The HRSG drums include moisture separators, internal baffles, and piping for feedwater/steam.

All tubes, inc luding economizers, superheaters, and headers and drums, are equipped with

drains.

Safety relief valves are furnished in order to comply with appropriate codes and ensure a safe work place.

Superheater, boiler, and economizer sections are supported by shop

- assembled structural steel. Inlet and outlet duct is provided to route the gases from the gas turbine outlet to the HRSG inlet and the HRSG outlet to the stack. A diverter valve is included in the inlet duct to bypass the gas when appropriate. Suitable expansion joints are also included.

4.2.14.2 Steam Turbine Generator and Auxiliaries

The steam turbine consists of an HP section, an IP section, and one double

- flow LP section, all connected to the generator by a common shaft. The HP and IP sections are contained in a single

span, opposed

- flow casing, with the double

- flow LP section in a separate casing. The LP turbine has a last stage bucket length of 76 cm (30 in).Carbon Dioxide Capture Sensitivity Analysis



### 219 Main steam from the HRSG and gasifier island is combined in a header, and then passes through

the stop valves and control valves and enters the turbine at 12.4 MPa/538 °C (1

, 800 psig/1

, 000
°F) with CO 2 

### capture. The steam initially enters the turbine near the middle of the high

- pressure span, flows through the turbine, and returns to the HRSG for reheating. The reheat steam flows through the reheat stop valves and intercept valves and enters the IP sec tion at 2.6 to 2.9

MPa/538 °C (375 to 420 psig/1

, 000 °F) with CO 2 

### capture. After passing through the IP section, the steam enters a crossover pipe, which transports the steam to the LP section. The steam divides into two paths and flows through the LP s ections, exhausting downward into the

condenser.

Turbine bearings are lubricated by a closed

- loop, water

- cooled , pressurized oil system. The oil is contained in a reservoir located below the turbine floor. During startup or unit trip an emergency oil pum p mounted on the reservoir pumps the oil. When the turbine reaches

95 percent of synchronous speed, the main pump mounted on the turbine shaft pumps oil. The oil flows through water

- cooled heat exchangers prior to entering the bearings. The oil then flo ws through the bearings and returns by gravity to the lube oil reservoir.

Turbine shafts are sealed against air in

- leakage or steam blowout using a modern positive pressure variable clearance shaft sealing design arrangement connected to a low

- pressure ste am seal system. During startup, seal steam is provided from the main steam line. As the unit increases load, HP turbine gland leakage provides the seal steam. Pressure

- regulating valves control the gland header pressure and dump any excess steam to the condenser. A steam packing exhauster maintains a vacuum at the outer gland seals to prevent leakage of steam into the turbine room. Any steam collected is condensed in the packing exhauster and returned to the condensate system.

The generator is a hydrogen

- cooled synchronous type, generating power at 24 kV. A static, transformer type exciter is provided. The generator is cooled with a hydrogen gas recirculation system using fans mounted on the generator rotor shaft. The heat absorbed by the gas i s removed as it passes over finned tube gas coolers mounted in the stator frame. Gas is prevented from escaping at the rotor shafts by a closed

- loop oil seal system. The oil seal system consists of storage tank, pumps, filters, and pressure controls, all skid

- mounted.

The steam turbine generator is controlled by a triple

- redundant, microprocessor

- based electro

hydraulic control system. The system provides digital control of the unit in accordance with programmed control algorithms, color CRT operator int erfacing, and datalink interfaces to the

balance

- of

- plant DCS, and incorporates on

- line repair capability.

4.2.14.3 Condensate System

The condensate system transfers condensate from the condenser hotwell to the deaerator, through the gland steam condenser, gasifier , and the low

- temperature economizer section in the HRSG. The system consists of one main condenser; two 50 percent capacity, motor

- driven, vertical condensate pumps; one gland steam condenser; and a low

- temperature tube bundle in the HRSG.

Condensate is delivered to a common discharge header through separate pump discharge lines, each with a check valve and a gate valve. A common minimum flow recirculation lineCarbon Dioxide Capture Sensitivity Analysis



### 220 discharging to the condenser is provided to maintain minimum flow requirements for the gland steam condenser and the condensate pumps.

4.2.14.4 Feedwater System

The function of the feedwater system is to pump the various feedwater streams from the deaerator storage tank in the HRSG to the respective steam drums. Two 50 percent capacity boiler feed pumps are provided for each of three pressure levels, HP, IP, and LP. Each pump is provided with inlet and outlet isolation valves, and outlet check valve. Minimum flow recirculation to prevent overheating and cavitation of the pumps during startup and low loa ds is provided by an automatic recirculation valve and associated piping that discharges back to the deaerator storage tank. Pneumatic flow control valves control the recirculation flow.

The feedwater pumps are supplied with instrumentation to monitor a nd alarm on low oil pressure, or high bearing temperature. Feedwater pump suction pressure and temperature are also monitored. In addition, the suction of each boiler feed pump is equipped with a startup

strainer.

4.2.14.5 Main and Reheat Steam Systems

The functi on of the main steam system is to convey main steam generated in the synthesis gas cooler and HRSG from the HRSG superheater outlet to the HP turbine stop valves. The function of the reheat system is to convey steam from the HP turbine exhaust to the HRSG reheater, and to the turbine reheat stop valves.

With CO 2 

### capture, main steam at approximately 12.4 MPa/538 °C (1

, 800 psig/1

, 000 °F) exits the HRSG superheater through a motor

- operated stop/check valve and a motor

- operated gate valve,

and is routed to the HP turbine. Cold reheat steam at approximately 3.1 to 3.4 MPa/341 °C (450

to 500 psia/645 °F) exits the HP turbine, flows through a motor

- operated isolation gate valve, to the HRSG reheater. Hot reheat steam at approximately 2.9 MPa/538 °C (420 psia/1

, 0 00 °F) exits the HRSG reheater through a motor

- operated gate valve and is routed to the IP turbines.

Steam piping is sloped from the HRSG to the drip pots located near the steam turbine for

removal of condensate from the steam lines. Condensate collected in the drip pots and in low

point drains is discharged to the condenser through the drain system.

Steam flow is measured by means of flow nozzles in the steam piping. The flow nozzles are located upstream of any branch connections on the main headers.

Saf ety valves are installed to comply with appropriate codes and to ensure the safety of personnel and equipment.

4.2.14.6 Circulating Water System

The circulating water system is a closed

- cycle cooling water system that supplies cooling water

to the condenser to cond ense the main turbine exhaust steam. The system also supplies cooling water to the AGR plant as required, and to the auxiliary cooling system. The auxiliary cooling system is a closed

- loop process that utilizes a higher quality water to remove heat fromCarbon Dioxide Capture Sensitivity Analysis



### 221 compressor intercoolers, oil coolers and other ancillary equipment and transfers that heat to the main circulating cooling water system in plate and frame heat exchangers. The heat transferred to the circulating water in the condenser and other applicatio ns is removed by a mechanical draft cooling tower.

The system consists of two 50 percent capacity vertical circulating water pumps, a mechanical draft evaporative cooling tower, and carbon steel cement

- lined interconnecting piping. The pumps are single

- st age vertical pumps. The piping system is equipped with butterfly isolation valves and all required expansion joints. The cooling tower is a multi

- cell wood frame counterflow mechanical draft cooling tower.

The condenser is a single

- pass, horizontal type with divided water boxes. There are two separate circulating water circuits in each box. One

- half of the condenser can be removed from service for cleaning or for plugging tubes. This can be done during normal operation at reduced load.

The condenser is equipped with an air extraction system to evacuate the condenser steam space

for removal of non

- condensable gases during steam turbine operation and to rapidly reduce the condenser pressure from atmospheric pressure before unit startup and admission of st eam to the

condenser.

4.2.14.7 Raw Water, Fire Protection, and Cycle Makeup Water Systems

The raw water system supplies cooling tower makeup, cycle makeup, service water and potable water requirements. The water source is 50 percent from a POTW and 50 percent from groundwater. Booster pumps within the plant boundary provide the necessary pressure.

The fire protection system provides water under pressure to the fire hydrants, hose stations, and fixed water suppression system within the buildings and structures. Th e system consists of pumps, underground and aboveground supply piping, distribution piping, hydrants, hose stations, spray systems, and deluge spray systems. One motor

- operated booster pump is supplied on the intake structure of the cooling tower with a d iesel engine backup pump installed on the water

inlet line.

The cycle makeup water system provides high quality demineralized water for makeup to the HRSG cycle, for steam injection ahead of the water gas shift reactor(s) for appropriate plant designs, and for injection steam to the auxiliary boiler for control of NOx emissions, if required.

The cycle makeup system consists of two 100 percent trains, each with a full

- capacity activated carbon filter, primary cation exchanger, primary anion exchanger, mixed bed exchanger, recycle pump, and regeneration equipment. The equipment is skid

- mounted and includes a control panel and associated piping, valves, and instrumentation.



## 4.2.15 Accessory Electric Plant

The accessory electric plant consists of switchgear and control equipment, generator equipment, station service equipment, conduit and cable trays, and wire and cable. It also includes the main power transformer, all required foundations, and standby equipment.Carbon Dioxide Capture Sensitivity Analysis



### 222 

## 4.2.16 Instrumentation and Control

An integrated plant

- w ide distributed control system (DCS) is provided. The DCS is a redundant microprocessor

- based, functionally distributed control system. The control room houses an array of multiple video monitor (CRT) and keyboard units. The CRT/keyboard units are the p rimary interface between the generating process and operations personnel. The DCS incorporates plant monitoring and control functions for all the major plant equipment. The DCS is designed to be operational and accessible 99.5 percent of the time it is r equired (99.5 percent availability). The plant equipment and the DCS are designed for automatic response to load changes from

minimum load to 100 percent. Startup and shutdown routines are manually implemented, with operator selection of modular automati on routines available. The exception to this, and an important facet of the control system for gasification, is the critical controller system, which is a part of the license package from the gasifier supplier and is a dedicated and distinct hardware

segm ent of the DCS.

This critical controller system is used to control the gasification process. The partial oxidation of the fuel feed and oxygen feed streams to form a syngas product is a stoichiometric, temperature

and pressure

- dependent reaction. The cr itical controller utilizes a redundant microprocessor executing calculations and dynamic controls at 100

- to 200

- millisecond intervals. The enhanced execution speeds as well as evolved predictive controls allow the critical controller to mitigate

process upsets and maintain the reactor operation within a stable set of operating parameters.



## 4.3 GEE IGCC C O 2 

## Capture Sensitivity

The evaluation scope included developing heat and mass balances and estimating GE E IGCC power plant performance while gasifying bituminous Illinois No. 6 coal. Equipment lists were developed for each design to support plant capital and operating costs estimates.

The IGCC plants are assumed to be built on a “green

- field” site and utilize recirculating wet evaporative cooling sys tems for cycle heat rejection. Major systems for each plant (described in

Section 4.2 ) include:

1. GEE radiant

- only gasifier

2. ASU

3. Water gas shift

4. Acid gas removal

5. CO 2 

### Recovery

6. Balance of Plant

Support facilities include coal handling (receiving, crushing, slurry preparation, and storing), solid waste disposal, circulating water system with evaporative mechanical draft cooling towers, wastewater treatment, and other ancillary systems equipment necessary for an efficient, highly available, and completely operable facility.Carbon Dioxide Capture Sensitivity Analysis



### 223 The plant design s are based on using components suitable for a 30

- year life, with provision for periodic maintenance and replacement of critical parts. All equipment is based on compliance with the latest applicable codes and standards. ASME, ANSI, IEEE, NFPA, CAA, stat e regulations, and OSHA codes are all adhered to in the design approach.

IGCC Plant Designs

The Case 2 IGCC plant designs used to analyze the full range of potential CO 2 

### capture levels are

shown in Exhibit 4

- 14

. While each of these plant designs includes the process and ancillary equipment described in Section 4.2 , the designs are unique in te rms of the WGS and AGR sections. In particular, the WGS section, as described below, is different for each plant design.

D1 has no WGS reactor. T he minimum (0 percent ) and maximum ( 25 percent ) CO 2 

### capture levels for t his particular configuration are modeled. Due to the high level of integration between the H 2 

### S and CO 2 

### absorbers, it is not feasible to model no CO 2 

### capture with a two

- stage SelexolTM system. Consequently, D1A (0 percent capture) employs a one

- stage SelexolTM unit for H 2 

### S control, while D1B (25 percent capture)

utilizes a two

- stage SelexolTM unit to maximize CO 2 

### capture from the unshifted syngas. D1 includes a COS hydrolysis unit to treat the entire syngas stream.

D2 has o ne

- stage WGS with CO 2 

### capture ranging from 25 percent (upper limit from

D 1) to the maximum achievable limit for this particular configuration (75 percent ) by varying the WGS bypass ratio and the two

- stage SelexolTM CO 2 

### removal efficiency

. The SelexolTM remo val efficiency is changed by varying the solvent circulation rate, which changes the size and cost of the SelexolTM system. The combined syngas
stream (shi fted and unshifted gas) is routed through a COS hydrolysis unit.

D3 has two

- stage WGS with CO 2 

### captur e ranging from 25 percent (upper limit from

D 1) to the maximum achievable limit for this particular configuration (85 percent ) by varying the WGS bypass ratio and the two

- stage SelexolTM CO 2 

### removal efficiency

. The SelexolTM removal efficiency is changed by varying the solvent circulation rate, which changes the size and cost of the SelexolTM system. The WGS bypass stream
passes through a COS hydrolysis unit.

D4 has two

- stage WGS and no bypass with CO 2 

### capture ranging from 90 to 97

percent . To achieve great er than 90 percent CO 2 

### removal, the two

- stage SelexolTM

CO 2 

### removal efficiency is increased by raising the solvent circulation rate, which increases the size and cost of the SelexolTM system. D4 does not include a COS
hydrolysis unit since sufficient COS to H 2 

### S conversion occurs across the two WGS

reactors.Carbon Dioxide Capture Sensitivity Analysis



### 224 Exhibit 4

- 14 Case 2 GEE IGCC Plant Configuration Summary

Case CO 2 Capture CO 2

Separation Intended

Storage Gasifier Steam psig/°F/°F Oxidant WGS Sulfur

Control

D1A 0% N/A N/A

GE E

Radiant Only 1800/1050/1050 95 mol%

O 2 N/A

SelexolTM D1B 25%

SelexolTM

2 nd Stage Saline

Formation N/A

D2A 25%

One

- Stage

with bypass D2B 45%

D2C 60%

D2D 75%

D3A 25%

Two

- Stage

with bypass D3B 45%

D3C 60%

D3D 75%

D3E 85%

D4A 90% Two

- Stage

without bypass D4B 95%

D4C 97%



## 4.3.1 IGCC Design 1

– Without Water Gas Shift

Design 1 (D1) represents an IGCC plant without WGS reactors. As a result, the entire syngas stream is passed through a COS hydrolysis unit to ensure that the low sulfur levels required by local permitting agencies (this analysis assumes 0.0128 lb SO 2 

### /MMBtu) are achieved.

The Case 2 D1 analysis involves the development of cost and performance estimates for no CO 2 

### capture (D1A) and the maximum level of CO 2 

### removal (25 percent ) that can be achieved without WGS (D1B). Due to the high level of integration between the H 2 

### S and CO 2 

### absorbers in the

two

- stage S elexolTM system (see Exhibit 4

- 8 ), it is assumed in this analysis that it is not possible to operate the two stages independently, and therefore is not feasible to model 0 percent CO 2 

### capture with this system. Since the first stage is designed to operate synergistically with the

second, some level of CO 2 

### removal is unavoidable. Consequently, D1A (0 percent capture) employs a one

- stage SelexolTM unit for H 2 

### S control, while D1B (25 percent capture) utilizes a

two

- stage SelexolTM unit to maximize CO 2 

### capture from the unshifted syngas.

The process block flow diagram for Case 2 D1A is shown in Exhibit 4

- 15 . This process results

in no CO 2 

### removal since a one

- stage SelexolTM unit is employed exclusively for H 2 

### S removal. Case 2 D1A also includes air integration between the ASU and CT (stream 21) where about 4

percent of the pressurized CT air supply is extracted, accounting for approximately 16.8 percent of the total ASU air requirement. The corresponding stream tables for Case 2 D1A are contained

in Exhibit 4

- 16

.Carbon Dioxide Capture Sensitivity Analysis



### 225 The process block flow diagram for Case 2 D1B is shown in Exhibit 4

- 17 . To maximize CO 2 

### removal, this process employs a two

- stage SelexolTM unit for selective H 2 

### S removal and bulk

CO 2 

### capture. Note that D1B does not include air integration between the ASU and CT , which, along with a different h eat integration scheme, explains the decreased coal feed rate observed for

D1B . The corresponding stream tables for Case 2 D1B are contained in Exhibit 4

- 18

.

Overall performance for Case 2

- D1 is summarized in Exhibit 4

- 19 which includes auxiliar y power requirements.

Material and energy balance information, environmental performance and a major e quipment list

are summarized in Sections 4.3.1.1 and 4.3.1.2

.Carbon Dioxide Capture Sensitivity Analysis



### 226 Exhibit 4

- 15 Case 2 D1A Process Block Flow Diagram, IGCC without WGS (0% CO 2 Removal)Carbon Dioxide Capture Sensitivity Analysis



### 227 Exhibit 4

- 16 Case 2 D1A Stream Table, IGCC without CO 2 CaptureCarbon Dioxide Capture Sensitivity Analysis



### 228 Exhibit 4

- 16 Case 2 D1A Stream Table, IGCC without CO 2 Capture (continued)Carbon Dioxide Capture Sensitivity Analysis



### 229 Exhibit 4

- 17 Case 2 D1B Process Block Flow Diagram, IGCC without WGS (25% CO 2 Removal)Carbon Dioxide Capture Sensitivity Analysis



### 230 Exhibit 4

- 18 Case 2 D1B Stream Table, IGCC with 25% CO 2 CaptureCarbon Dioxide Capture Sensitivity Analysis



### 231 Exhibit 4

- 18 Case 2 D1B Stream Table, IGCC with 25% CO 2 Capture (continued)Carbon Dioxide Capture Sensitivity Analysis



### 232 Exhibit 4

- 19 Case 2 D1 Performance Modeling Results

POWER SUMMARY (Gross Power at Generator

Terminals, kWe) D1A (0%) D1B

(25%)

Gas Turbine Power 464,000 464,000

Sweet Gas Expander Power 7,500 5,800

Steam Turbine Power 276,300 280, 6 00

Total 747,800 750, 4 00

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 4 59 4 5 7

Coal Milling 2,1 78 2,1 59

Sour Water Recycle Slurry Pump 18 3 18 1

Slag Handling 1,1 15 1,1 06

Air Separation Unit Auxiliaries 1,000 1, 000

Air Separation Unit Main Air Compressor 53,8 17 64,0 10

Oxygen Compressor 10,25 5 10,1 6 4

Nitrogen Compressors 33,370 31,38 6

CO 2 Compressor 0 8,41 0

Boiler Feedwater Pumps 3,9 75 3,9 6 8

Condensate Pump 23 5 2 49

Quench Water Pump 5 19 51 3

Circulating Water Pump 4,20 4 4,1 65

Ground Water Pumps 4 28 4 25

Cooling Tower Fans 2,17 2 2,15 2

Scrubber Pumps 2 16 21 2

Acid Gas Removal 2,5 88 4,8 0 7

Gas Turbine Auxiliaries 1,000 1,000

Steam Turbine Auxiliaries 100 100

Claus Plant/TGTU Auxiliaries 250 250

Claus Plant TG Recycle Compressor 2,08 5 8 2 8

Miscellaneous Balance of Plant 1 3,000 3,000

Transformer Losses 2,6 06 2,6 6 6

TOTAL AUXILIARIES, kWe 125,755 143,208

NET POWER, kWe 622,04 5 60 7,192

Net Plant Efficiency, % (HHV) 39.0 % 38. 4 %

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,238 ( 8,756 ) 9,38 0 ( 8,89 1 )

Condenser Duty, GJ/hr (10 6 Btu/hr) 1,540 (1,460) 1,625 (1,540)

CONSUMABLES

As

- Received Coal Feed, kg/hr (lb/hr) 211,765 ( 466,861 ) 209,9 01 ( 462, 752 )

Thermal Input, kW th 2 1, 596,183 1,582, 134

Raw Water Withdrawal

, m 3 /min (gpm) 17.9 ( 4,734 ) 17.8 ( 4,69 2 )

Raw Water Consumption, m 3 /min (gpm) 14.2 (3,755) 14.1 (3,72 2 )

Notes: 1. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage

loads

2. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)Carbon Dioxide Capture Sensitivity Analysis



### 233 4.3.1.1 Environmental Performance for Case 2 D1A and D1B

The environmental targets for emissions of Hg, NO

x 

### , SO 2 

### , and particulate matter were presented

in Section 2.4 . A summary of the plant air emissions for Case 2 D1A and D1B is presented in

Exhibit 4

- 20

.

For Case 2 D1A and D1B, SO 2 

### emissions are controlled by sulfur capture across the one

- stage

and two

- stage SelexolTM AGR processes, respectively. The one

- stage SelexolTM unit removes

over 99 percent of the sulfur compounds in the fuel gas down to a lev el of less than 15 ppmv, resulting in a concentration in the flue gas of less than 3 ppmv. For D1B, the clean syngas exiting the two

- stage SelexolTM unit has a sulfur concentration of less than 10 ppmv, resulting in
a concentration in the flue gas of less than 2 ppmv. The H 2 

### S

- rich regeneration gas produced in both D1A and D1B is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H 2 

### S and then recycled back to the SelexolTM unit,

thereb y eliminating the need for a tail gas treatment unit.

For both D1A and D1B, NOx emissions are limited by nitrogen dilution of the syngas to 15 ppmvd (as NO 2 

### @ 15 percent O 2 

### ). Ammonia in the syngas is removed with process condensate prior to the low

- tem perature AGR process, and ultimately incinerated in the Claus plant burner. This also assists in lowering NOx levels.

Particulate discharge to the atmosphere for D1A and D1B is limited to extremely low values by the use of the syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only.

Ninety

- five percent of the mercury is captured from the syngas by an activated carbon bed.

For D1A, CO 2 

### emissions rep resent the uncontrolled discharge from the process. The carbon

balance for D1A is shown in Exhibit 4

- 21 . The carbon input to the plant consists of c arbon in the air and coal. Carbon in the air is not neglected here since the Aspen Plus ® 

### model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, as

dissolved CO 2 

### in the wastewater blowdown stream, and as CO 2 

### in the stack gas and ASU vent gas. Carbon in the wastewater blowdown stream is calculated by difference to close the material

balance.

Twenty

- five percent of the CO 2 

### from the syngas in D1B is captured in the two

- stage SelexolTM
unit and compressed for seq uestration. The carbon balance for D1B is also shown in

Exhibit 4

- 21 . The carbon input to the plant consists of carbon in the air and coal. Carbon i n the air is not neg lected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, as dissolved CO 2 

### in the wastewater blowdown

stream, and as CO 2 

### in the stack gas, ASU vent gas, and the ca ptured CO 2 

### product. Carbon in th e wastewater blowdown stream is calculated by difference to close the material balance. The carbon capture efficiency is defined as the pounds of carbon in the CO 2 

### product stream relative

to the amount of carbon in the coa l

, less carbon contained in the slag , represented by the following fraction:

(Carbon in CO 2 

### Product)/[(Carbon in the Coal)

- (Carbon in Slag)] or

72,256/(294,980

- 5,900)*100 = 25.0%Carbon Dioxide Capture Sensitivity Analysis



### 234 Exhibit 4

- 22 shows the sulfur balance for Case 2 D1A and D1B. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the pounds of sulfur recovered in the Claus plant,

dissolved SO 2 

### in the wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible, and the sulfur content of the blowdown stream is calculated by difference to close the material balance. The total sulfur capture is represented by the following fraction:

(Sulfur byproduct/Sulfur in the coal) or
(11,688/11,701)*100 = 99.8% (D1A)
(11,581/11,598)*100 = 99.8% (D1B)

The overall water balance s for Case 2 D1A and D1B are shown in Exhibit 4

- 23 and Exhibit 4

- 24

, respectively. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the total amount of water required for a particular process. Some water is recovered within the process and that w ater is re used as internal recycle.

Raw water withdrawal is t he difference between water demand and internal recycle. Process water discharged from the power plant is also account ed for in this study. Raw water consumption represents raw water withdrawal less process water discharge.

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 4

- 25 through

Exhibit 4

- 30

.

Gasifier and ASU

Syngas Cleanup

Power Block

An overall plant energy balance is provided in tabular form for Case 2 D1A and D1B in

Exhibit 4

- 31 and Exhibit 4

- 32 , respectively. The power out is the combined combustion turbine,

steam tur bine and expander power after generator losses. In addition, energy balance Sankey diagrams are provided for D1A and D1B in Exhibit 4

- 33 and Exhibit 4

- 34 , respectively

.

Exhibit 4

- 20 Case 2 D1 Estimated Air Emission Rates

kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)

D1A D1B D1A D1B D1A D1B

SO 2 0.0 02

(0.005 ) 0.0 01

(0.002 ) 84 (93) 37 (40) 0.016 (0.04) 0.007 (0.02)

NO X 0.0 25

(0.0 59 ) 0.0 24

(0.0 55 ) 1,023 (1,128) 947 (1,044) 0.195 (0.430) 0.180 (0.397)

P M 0.00 3

(0.0 071 ) 0.00 3

(0.0 071 ) 123 (135) 122 (134) 0.023 (0.052) 0.023 (0.051)

Hg 0. 246 x10 - 6

( 0.571 x10 - 6 ) 0. 246 x10 - 6

( 0.571 x10 - 6 ) 0.010 (0.011) 0.010 (0.011) 1.89 x10 - 6

(4.16 x10 - 6 ) 1.87 x10 - 6

(4.11 x10 - 6 )

CO 2 84.6 ( 196.8 ) 63.5 ( 147.8 ) 3,407,608 (3,756,245) 2,53 6,560

(2,796, 079 ) 650 (1,434) 48 2 (1,06 3 )

CO 2 net 782 (1,723) 59 6 (1,31 4 )Carbon Dioxide Capture Sensitivity Analysis



### 235 Exhibit 4

- 21 Case 2 D1 Carbon Balance

Carbon In, kg/hr (lb/hr)

D1A D1B

Coal 134,989 (297,599) 133,8 01 (29 4,980 )

Air (CO 2 ) 518 (1,143) 535 (1,179)

Total 135,507 (298,742) 134,3 36 (296, 159 )

Carbon Out, kg/hr (lb/hr)

Slag 2,700 (5,952) 2,67 6 (5,90 0 )

Stack Gas 132,704 (292,563) 98, 783 (217, 779 )

ASU Vent 103 (227) 102 (225)

CO 2 Product 0 (0) 32,7 75 (72,2 56 )

Convergence Tolerance 0 (0) 0 (

- 1 )

Total 135,507 ( 298,742 ) 134,336 (296,159)

Exhibit 4

- 22 Case 2 D1 Sulfur Balance

Sulfur In, kg/hr (lb/hr)

D1A D1B

Coal 5,308 (11,701) 5,26 1 (11, 598 )

Total 5,308 (11,701) 5,26 1 (11, 598 )

Sulfur Out, kg/hr (lb/hr)

Elemental Sulfur 5,302 (11,688) 5,25 3 (11,58 1 )

Stack Gas 6 (13) 3 (6)

CO 2 Product 0 (0) 5 (12)

Convergence Tolerance 0 (0) 0 (

- 1 )

Total 5,308 (11,701) 5,261 (11,598)Carbon Dioxide Capture Sensitivity Analysis



### 236 Exhibit 4

- 23 Case 2 D1A (0%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Slag Handling 0.50 (133) 0.50 (133) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.7 (726) 0.90 (237) 1.9 (489) 0.0 (0) 1.9 (489)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (8)

- 0.03 (

- 8)

Condenser Makeup 0.2 (54) 0.0 (0) 0.2 (54) 0.0 (0) 0.2 (54)

Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

Shift Steam 0.0 (0) 0.0 (0) 0.0 (0)

C T Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

BFW Makeup 0.20 (54) 0.0 (0) 0.20 (54)

Cooling Tower 16.4 (4,321) 0.49 (129) 15.9 (4,191) 3.7 (972) 12.2 (3,220)

BFW Blowdown 0.0 (0) 0.20 (54)

- 0.20 (

- 54)

SWS Blowdown 0.0 (0) 0.29 (75)

- 0.29 (

- 75)

SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 21.3 (5,617) 3.34 (883) 17.9 (4,734) 3.7 (979) 14.2 (3,755)

Total, gal/MWh net 542 85 457 94 362Carbon Dioxide Capture Sensitivity Analysis



### 237 Exhibit 4

- 24 Case 2 D1B (25%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Slag Handling 0.50 (132) 0.50 (132) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.7 (719) 0.88 (232) 1.8 (487) 0.0 (0) 1.8 (487)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7)

Condenser Makeup 0.2 (55) 0.0 (0) 0.2 (55) 0.0 (0) 0.2 (55)

Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

Shift Steam 0.0 (0) 0.0 (0) 0.0 (0)

C T Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 16.2 (4,280) 0.49 (129) 15.7 (4,150) 3.6 (963) 12.1 (3,188)

BFW Blowdown 0.0 (0) 0.21 (55)

- 0.21 (

- 55)

SWS Blowdown 0.0 (0) 0.28 (74)

- 0.28 (

- 74)

SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 21.1 (5,566) 3.31 (874) 17.8 (4,692) 3.7 (970) 14.1 (3,722)

Total, gal/MWh net 550 86 464 96 368Carbon Dioxide Capture Sensitivity Analysis



### 238 This page intentionally left blankCarbon Dioxide Capture Sensitivity Analysis



### 239 Exhibit 4

- 25 Case 2 D1A (0%) Heat and Mass Balance, GEE Gasifier and ASUCarbon Dioxide Capture Sensitivity Analysis



### 240 Exhibit 4

- 26 Case 2 D1A (0%) Heat and Mass Balance, Syngas CleanupCarbon Dioxide Capture Sensitivity Analysis



### 241 Exhibit 4

- 27 Case 2 D1A (0%) Heat and Mass Balance, Power BlockCarbon Dioxide Capture Sensitivity Analysis



### 242 Exhibit 4

- 28 Case 2 D1B (25%) Heat and Mass Balance, GEE Gasifier and ASUCarbon Dioxide Capture Sensitivity Analysis



### 243 Exhibit 4

- 29 Case 2 D1B (25%) Heat and Mass Balance, Syngas CleanupCarbon Dioxide Capture Sensitivity Analysis



### 244 Exhibit 4

- 30 Case 2 D 1B (25%) Heat and Mass Balance, Power BlockCarbon Dioxide Capture Sensitivity Analysis



### 245 Exhibit 4

- 31 Case 2 D1A (0%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,746 (5,446) 4.8 (4.6) 0 (0) 5,751 (5,451)

ASU Air 0 (0) 19.1 (18.1) 0 (0) 19 (18)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 67.4 (63.9) 0 (0) 67 (64)

Totals 5,746 (5,446) 187.4 (177.7) 0 (0) 5,934 (5,624)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.0 (1.0) 0 (0) 1 (1)

Slag 89 (84) 36.3 (34.4) 0 (0) 125 (118)

Sulfur 49 (47) 0.6 (0.6) 0 (0) 50 (47)

Gasifier Heat Loss 0 (0) 41.2 (39.0) 0 (0) 41 (39)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 939 (890) 0 (0) 939 (890)

Cooling Tower* 0 (0) 1,986 (1,882) 0 (0) 1,986 (1,882)

Process Losses* * 0 (0) 489 (464) 0 (0) 489 (464)

Net Power 0 (0) 0.0 (0.0) 2,239 (2,123) 2,239

(2,123)

Totals 138 (130) 3,557 (3,371) 2,239 (2,123) 5,934

(5,624)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 compressor intercoolers,

sour water s tripper condenser, syngas cooler (low level heat rejection), and extraction

air cooler. ** Calculated by difference to close the energy balance.Carbon Dioxide Capture Sensitivity Analysis



### 246 Exhibit 4

- 32 Case 2 D1B (25%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,696 (5,398) 4.8 (4.5) 0 (0) 5,700 (5,403)

ASU Air 0 (0) 22.7 (21.5) 0 (0) 23 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 66.8 (63.3) 0 (0) 67 (63)

Totals 5,696 (5,398) 190.4 (180.5) 0 (0) 5,886 (5,579)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.9 (1.8) 0 (0) 2 (2)

Slag 88 (83) 36.0 (34.1) 0 (0) 124 (117)

Sulfur 49 (46) 0.6 (0.6) 0 (0) 49 (47)

CO 2 0 (0)

- 12.8 (

- 12.2) 0 (0)

- 13 (

- 12)

Gasifier Heat Loss 0 (0) 42.4 (40.2) 0 (0) 42 (40)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 936 (887) 0 (0) 936 (887)

Cooling Tower* 0 (0) 2,072 (1,964) 0 (0) 2,072 (1,964)

Process Losses* * 0 (0) 424 (402) 0 (0) 424 (402)

Net Power 0 (0) 0.0 (0.0) 2,186 (2,072) 2,186

(2,072)

Totals 136 (129) 3,564 (3,378) 2,186 (2,072) 5,886

(5,579)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

air cooler. ** Calculated by difference to close the energy balance.Carbon Dioxide Capture Sensitivity Analysis



### 247 Exhibit 4

- 33 Case 2 D1A Energy Balance Sankey Diagram

Exhibit 4

- 34 Case 2 D1B Energy Balance Sankey DiagramCarbon Dioxide Capture Sensitivity Analysis



### 248 4.3.1.2 Major Equipment List for Case 2 D1

Major equipment items for Case 2 D1A and D1B are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates. In general , the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 COAL HANDLING

Equipment

No. Description Type Design Conditions Opr Qty. (Spares) D1A D1B

1 Bottom Trestle Dumper and Receiving

Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0)

3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

4 Transfer Tower No. 1 Enclosed N/A N/A 1 (0)

5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

6 As

- Received Coal Sampling System Two

- stage N/A N/A 1 (0)

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

8 Reclaim Hopper N/A 45 tonne (50 ton) 45 tonne (50 ton) 2 (1)

9 Feeder Vibratory 172 tonne/hr (190 tph) 172 tonne/hr (190 tph) 2 (1)

10 Conveyor No. 3 Belt w/ tripper 354 tonne/hr (390 tph) 345 tonne/hr (380 tph) 1 (0)

11 Crusher Tower N/A N/A N/A 1 (0)

12 Coal Surge Bin w/ Vent Filter Dual outlet 172 tonne (190 ton) 172 tonne (190 ton) 2 (0)

13 Crusher Impactor

reduction 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 2 (0)

14 As

- Fired Coal Sampling System Swing hammer N/A N/A 1 (1)

15 Conveyor No. 4 Belt w/tripper 354 tonne/hr (390 tph) 345 tonne/hr (380 tph) 1 (0)

16 Transfer Tower No. 2 Enclosed N/A N/A 1 (0)

17 Conveyor No. 5 Belt w/ tripper 354 tonne/hr (390 tph) 345 tonne/hr (380 tph) 1 (0)

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 816 tonne (900 ton) 726 tonne (800 ton) 3 (0)Carbon Dioxide Capture Sensitivity Analysis



### 249 ACCOUNT 2 COAL PREPARATION AND FEED

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

1 Feeder Vibratory 82 tonne/h (90 tph) 73 tonne/h (80 tph) 3 (0)

2 Conveyor No. 6 Belt w/tripper 236 tonne/h (260 tph) 227 tonne/h (250 tph) 1 (0)

3 Rod Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 463 tonne (510 ton) 1 (0)

4 Weigh Feeder Belt 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)

5 Rod Mill Rotary 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)

6 Slurry Water Storage

Tank with Agitator Field erected 287,504 liters (75,950 gal) 284,968 liters (75,280 gal) 2 (0)

7 Slurry Water Pumps Centrifugal 795 lpm (210 gpm) 795 lpm (210 gpm) 2 (1)

8 Trommel Screen Coarse 163 tonne/h (180 tph) 163 tonne/h (180 tph) 2 (0)

9 Rod Mill Discharge Tank

with Agitator Field erected 376,084 liters (99,350 gal) 372,790 liters (98,480 gal) 2 (0)

10 Rod Mill Product Pumps Centrifugal 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 2 (2)

11 Slurry Storage Tank with

Agitator Field erected 1,128,440 liters (298,100 gal) 1,118,220 liters (295,400 gal) 2 (0)

12 Slurry Recycle Pumps Centrifugal 6,435 lpm (1,700 gpm) 6,057 lpm (1,600 gpm) 2 (2)

13 Slurry Product Pumps Positive displacement 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 2 (2)



### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

1 Demineralized Water Storage Tank Vertical, cylindrical,

outdoor 1,082,628 liters (286,000 gal) 1,086,413 liters (287,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 6,624 lpm @ 91 m H 2 O (1,750 gpm @ 300 ft H 2 O) 7,041 lpm @ 91 m H 2 O (1,860 gpm @ 300 ft H 2 O) 2 (1)

3 Deaerator (integral w/

HRSG) Horizontal spray type 493,508 kg/hr (1,088,000 lb/hr) 483,983 kg/hr (1,067,000 lb/hr) 2 (0)

4 Intermediate Pressure

Feedwater Pump Horizontal centrifugal, single stage 8,366 lpm @ 27 m H 2 O (2,210 gpm @ 90 ft H 2 O) 8,101 lpm @ 27 m H 2 O (2,140 gpm @ 90 ft H 2 O) 2 (1)Carbon Dioxide Capture Sensitivity Analysis



### 250 Equipment

No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

5 High Pressure Feedwater

Pump No. 1 Barrel type, multi

stage, centrifugal HP water: 6,246 lpm @ 1,859

m H 2 O (1,650 gpm @ 6,100 ft

H 2 O) HP water: 6,132 lpm @ 1,859

m H 2 O (1,620 gpm @ 6,100

ft H 2 O) 2 ( 1 )

6 High Pressure Feedwater

Pump No. 2 Barrel type, multi

stage, centrifugal IP water: 1,060 lpm @ 223 m
H 2 O (280 gpm @ 730 ft H 2 O) IP water: 1,476 lpm @ 223 m

H 2 O (390 gpm @ 730 ft H 2 O) 2 ( 1 )

7 Auxiliary Boiler Shop fabricated, water

tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 (0)

8 Service Air Compressors Flooded Screw 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 ( 1 )

9 Instrument Air Dryers Duplex, regenerative 28 m 3 /min (1,000 scfm) 28 m 3 /min (1,000 scfm) 2 ( 1 )

10 Closed Cylce Cooling

Heat Exchangers Plate and frame 247 GJ/hr (233.7595997 MMBtu/hr) each 247 GJ/hr (234.1323798 MMBtu/hr) each 2 (0)

11 Closed Cycle Cooling

Water Pumps Horizontal centrifugal 88,579 lpm @ 21 m H 2 O (23,400 gpm @ 70 ft H 2 O) 88,579 lpm @ 21 m H 2 O (23,400 gpm @ 70 ft H 2 O) 2 ( 1 )

12 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H 2 O (1,000 gpm @ 350 ft H 2 O) 3,785 lpm @ 107 m H 2 O (1,000 gpm @ 350 ft H 2 O) 1 ( 1 )

13 Fire Service Booster

Pump Two

- stage horizontal centrifugal 2,650 lpm @ 76 m H 2 O (700 gpm @ 250 ft H 2 O) 2,650 lpm @ 76 m H 2 O (700 gpm @ 250 ft H 2 O) 1 ( 1 )

14 Raw Water Pumps Stainless steel, single

suction 4,618 lpm @ 18 m H 2 O (1,220 gpm @ 60 ft H 2 O) 4,580 lpm @ 18 m H 2 O (1,210 gpm @ 60 ft H 2 O) 2 ( 1 )

15 Ground Water Pumps Stainless steel, single

suction 3,066 lpm @ 268 m H 2 O (810 gpm @ 880 ft H 2 O) 3,028 lpm @ 268 m H 2 O (800 gpm @ 880 ft H 2 O) 3 (1)

16 Filtered Water Pumps Stainless steel, single

suction 2,082 lpm @ 49 m H 2 O (550 gpm @ 160 ft H 2 O) 2,082 lpm @ 49 m H 2 O (550 gpm @ 160 ft H 2 O) 2 (1)

17 Filtered Water Tank Vertical, cylindrical 1,003,134 liter (265,000 gal) 995,563 liter (263,000 gal) 2 (0)

18 Makeup Water

Demineralizer Anion, cation, and

mixed bed 303 lpm (80 gpm) 303 lpm (80 gpm) 2 ( 0 )

19 Liquid Waste Treatment

System 10 years, 24

- hour storm 10 years, 24

- hour storm 1 ( 0 )Carbon Dioxide Capture Sensitivity Analysis



### 251 ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

1 Gasifier Pressurized slurry

feed, entrained bed 2,812 tonne/day, 5.6 MPa (3,100 tpd, 815 psia) 2,812 tonne/day, 5.6 MPa (3,100 tpd, 814.96 psia) 2 (0)

2 Synthesis Gas Cooler Vertical downflow

radiant heat exchanger with outlet quench chamber 245,393 kg/hr (541,000 lb/hr) 243,126 kg/hr (536,000 lb/hr) 2 (0)

3 Synthesis Gas

Cyclone High efficiency 335,658 kg/hr (740,000 lb/hr) Design efficiency 90% 332,937 kg/hr (734,000 lb/hr) Design efficiency 90% 2 (0)

4 Candle Filter Pressurized filter with pulse

- jet cleaning metallic filters metallic filters 2 (0)

5 Syngas Scrubber

Including Sour Water Stripper Vertical upflow 335,658 kg/hr (740,000 lb/hr) 332,937 kg/hr (734,000 lb/hr) 2 (0)

6 Raw Gas Coolers Shell and tube with

condensate drain 215,910 kg/hr (476,000 lb/hr) 287,578 kg/hr (634,000 lb/hr) 8 (0)

7 Raw Gas Knockout

Drum Vertical with mist

eliminator 215,456 kg/hr, 35°C, 5.3 MPa (475,000 lb/hr, 95°F, 765 psia) 213,188 kg/hr, 35°C, 5.2 MPa (470,000 lb/hr, 95°F, 750 psia) 2 (0)

8 Flare Stack Self

- supporting,
carbon steel, stainless steel top, pilot ignition 335,658 kg/hr (740,000 lb/hr)

syngas 332,937 kg/hr (734,000 lb/hr)

syngas 2 (0)

9 ASU Main Air

Compressor Centrifugal, multi

stage 4,757 m 3 /min @ 1.3 MPa (168,000 scfm @ 190 psia) 5,635 m 3 /min @ 1.3 MPa (199,000 scfm @ 190 psia) 2 (0)

10 Cold Box Vendor design 2,268 tonne/day (2,500 tpd) of 95% purity oxygen 2,268 tonne/day (2,500 tpd) of 95% purity oxygen 2 (0)

11 Oxygen Compressor Centrifugal, multi

stage 1,161 m 3 /min (41,000 scfm)

Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940 psia) 1,133 m 3 /min (40,000 scfm)

Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940

psia) 2 (0)

12 Primary Nitrogen

Compressor Centrifugal, multi

stage 3,766 m 3 /min (133,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 3,540 m 3 /min (125,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390

psia) 2 (0)Carbon Dioxide Capture Sensitivity Analysis



### 252 Equipment

No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

13 Secondary Nitrogen

Compressor Centrifugal, single

stage 538 m 3 /min (19,000 scfm)

Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 538 m 3 /min (19,000 scfm)

Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390

psia) 2 (0)

14 Syngas Dilution

Nitrogen Boost Compressor Centrifugal, single

stage 0 m 3 /min (0 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470 psia) 0 m 3 /min (0 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470

psia) 2 (0)

15 AGR Nitrogen Boost

Compressor Centrifugal, single

stage 85 m 3 /min (3,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 5.4 MPa (790 psia) N/A 2 (0)

16 Extraction Air Heat

Exchanger Gas

- to

- gas, vendor design 69,853 kg/hr, 432°C, 1.6 MPa (154,000 lb/hr, 810°F, 235 psia) N/A 2 (0)



### ACCOUNT 5A SYNGAS CLEANUP

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

1 Mercury Adsorber Sulfated carbon bed 215,003 kg/hr (474,000 lb/hr) 35°C (95°F) 5.2 MPa (760 psia) 212,735 kg/hr (469,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 2 (0)

2 Sulfur Plant Claus type 140 tonne/day (154 tpd) 139 tonne/day (153 tpd) 1 (0)

3 COS Hydrolysis

Reactor Fixed bed, catalytic 303,907 kg/hr (670,000 lb/hr) 221°C (430°F) 5.4 MPa (790 psia) 301,185 kg/hr (664,000 lb/hr) 204°C (400°F) 5.5 MPa (800 psia) 2 (0)

4 Acid Gas Removal

Plant Selexol 232,239 kg/hr (512,000 lb/hr)

35°C (94°F) 5.2 MPa (755 psia) 214,096 kg/hr (472,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 2 (0)

5 Hydrogenation

Reactor Fixed bed, catalytic 36,155 kg/hr (79,709 lb/hr) 232°C (450°F) 0.4 MPa (58.9 psia) 6,346 kg/hr (13,990 lb/hr) 232°C (450°F)

0.1 MPa (12.3 psia) 1 (0)

6 Tail Gas Recycle

Compressor Centrifugal 31993 kg/hr (70533.3901 lb/hr) 3,062 kg/hr (6,750 lb/hr) 1 (0)Carbon Dioxide Capture Sensitivity Analysis



### 253 ACCOUNT 5B CO 2 

### COMPRESSION

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

1 CO 2 Compressor Integrally geared, multi

stage centrifugal N/A 300 m 3 /min @ 15.3 MPa (10,600 scfm @ 2,215 psia) 4 (0)



### ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

1 Gas Turbine Advanced F class 230 MW 230 MW 2 (0)

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV,

60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV,

60 Hz, 3

- phase 2 (0)

3 Syngas Expansion

Turbine/Generator Turbo Expander 218,359 kg/h (481,400 lb/h) 5.1 MPa (745 psia) Inlet 3.2 MPa (460 psia) Outlet 144,877 kg/h (319,400 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 2 (0)



### ACCOUNT 7 HRSG, DUCTING

, AND STACK

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

1 Stack CS plate, type

409SS liner 76 m (250 ft) high x 8.4 m (27 ft) diameter 76 m (250 ft) high x 8.4 m (28 ft) diameter 1 (0)

2 Heat Recovery

Steam

Generator Drum, multi

pressure with

economizer section and integral

deaerator Main steam

- 352,655 kg/hr, 12.4 MPa/561°C (777,471 lb/hr, 1,800 psig/1,042°F)

Reheat steam

- 345,662 kg/hr, 3.1 MPa/561°C (762,055 lb/hr, 452 psig/1,042°F) Main steam

- 346,935 kg/hr, 12.4 MPa/554°C (764,862 lb/hr, 1,800 psig/1,030°F)

Reheat steam

- 346,574 kg/hr, 3.1 MPa/554°C (764,065
lb/hr, 452 psig/1,030°F) 2 (0)Carbon Dioxide Capture Sensitivity Analysis



### 254 ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

1 Steam Turbine Commercially

available advanced

steam turbine 291 MW 12.4 MPa/561°C/561°C (1,800 psig/ 1042°F/1042°F) 295 MW 12.4 MPa/554°C/554°C (1,800 psig/ 1030°F/1030°F) 1 (0)

2 Steam Turbine

Generator Hydrogen cooled,

static excitation 320 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 330 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design

steam conditions 50% steam flow @ design

steam conditions 2 (0)

4 Surface

Condenser Single pass, divided

waterbox including

vacuum pumps 1,688 GJ/hr (1,600 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise

11°C (20°F) 1,783 GJ/hr (1,690 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise

11°C (20°F) 1 (0)



### ACCOUNT 9 COOLING WATER SYSTEM

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

1 Circulating

Water Pumps Vertical, wet pit 420,181 lpm @ 30 m (111,000 gpm @ 100 ft) 416,395 lpm @ 30 m (110,000 gpm @ 100 ft) 2 (1)

2 Cooling Tower Evaporative,
mechanical draft,

multi

- cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F)
HWT / 2,353 GJ/hr (2,230 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,332 GJ/hr (2,210 MMBtu/hr) heat duty 1 (0)



### ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

1 Slag Quench Tank Water bath 242,266 liters (64,000 gal) 242,266 liters (64,000 gal) 2 (0)

2 Slag Crusher Roll 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 2 (0)

3 Slag Depressurizer Lock Hopper 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 2 (0)

4 Slag Receiving Tank Horizontal, weir 147,631 liters (39,000 gal) 143,846 liters (38,000 gal) 2 (0)Carbon Dioxide Capture Sensitivity Analysis



### 255 Equipment

No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

5 Black Water Overflow

Tank Shop fabricated 64,352 liters (17,000 gal) 64,352 liters (17,000 gal) 2 (0)

6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 2 (0)

7 Slag Separation

Screen Vibrating 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 2 (0)

8 Coarse Slag

Conveyor Belt/bucket 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 2 (0)

9 Fine Ash Settling

Tank Vertical, gravity 208,198 liters (55,000 gal) 208,198 liters (55,000 gal) 2 (0)

10 Fine Ash Recycle

Pumps Horizontal centrifugal 38 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 38 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 2 (2)

11 Grey Water Storage

Tank Field erected 68,137 liters (18,000 gal) 64,352 liters (17,000 gal) 2 (0)

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H 2 O (60 gpm @ 1,850 ft H 2 O) 227 lpm @ 564 m H 2 O (60 gpm @ 1,850 ft H 2 O) 2 (2)

13 Slag Storage Bin Vertical, field erected 907 tonne (1,000 tons) 907 tonne (1,000 tons) 2 (0)

14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 1 (0)



### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

1 CTG Step

- up
Transformer Oil

- filled 24 kV/345 kV, 260 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 260 MVA,

3

- ph, 60 Hz 2 (0)

2 STG Step

- up

Transformer Oil

- filled 24 kV/345 kV, 320 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 330 MVA,

3

- ph, 60 Hz 1 (0)

3 High Voltage Auxiliary

Transformer Oil

- filled 345 kV/13.8 kV, 54 MVA,

3

- ph, 60 Hz 345 kV/13.8 kV, 63 MVA,

3

- ph, 60 Hz 2 (0)

4 Medium Voltage

Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 29 MVA,

3

- ph, 60 Hz 24 kV/4.16 kV, 30 MVA,

3

- ph, 60 Hz 1 (1)

5 Low Voltage

Transformer Dry ventilated 4.16 kV/480 V, 4 MVA,

3

- ph, 60 Hz 4.16 kV/480 V, 4 MVA,

3

- ph, 60 Hz 1 (1)

6 CTG Isolated Phase

Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 2 (0)Carbon Dioxide Capture Sensitivity Analysis



### 256 Equipment

No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

7 STG Isolated Phase

Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 1 (0)

8 Medium Voltage

Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 1 (1)

9 Low Voltage

Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 1 (1)

10 Emergency Diesel

Generator Sized for emergency

shutdown 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 1 (0)



### ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

1 DCS

- Main

Control Monitor/keyboard;

Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers Operator stations/printers and engineering stations/printers 1 (0)

2 DCS

-

Processor Microprocessor with

redundant input/output N/A N/A 1 (0)

3 DCS

- Data

Highway Fiber optic Fully redundant, 25% spare Fully redundant, 25% spare 1 (0)Carbon Dioxide Capture Sensitivity Analysis



### 257 

## 4.3.2 IGCC Design 2

– Single Water Gas Shift Reactor

A proces s block flow diagram for Case 2 Design 2 (D2) is shown in Exhibit 4

- 35 . D2 represents an IGCC plant with a sing le WGS reactor and bypass stream (stream 13). This IGCC design

uses a S:DG molar ratio of 0.25 at the outlet of the WGS reactor. The WGS bypass ratio and the

two

- stage SelexolTM CO 2 

### removal efficiency are adjusted to control the total CO 2 

### capture level. The SelexolTM removal efficiency is altered by varying the solvent circulation rate, which changes the size and cost of the SelexolTM system.

The WGS bypass ratio impacts the degree of CO to CO 2 

### and COS to H 2 

### S conversion across the WGS reactor. Consequently , a downstream COS h ydolysis unit is included in this design to

ensure that sulfur emissions are below the limit of 0.0128 lb SO 2 

### /MMBtu.

Four levels of total CO 2 

### removal were modeled for Case 2 D2: 25 percent (D2A), 45 percent (D2B), 60 percent (D2C), and 75 percent (D2D). The corresponding stream tables are contained

in Exhibit 4

- 36

, Exhibit 4

- 37

, Exhibit 4

- 38 , and Exhibit 4

- 39 , respectively.

Overall performance for Case 2 D2 is summarized in Exhibit 4

- 40 which includes auxi liary power requirements.

Material and energy balance information, environmental performance and a major equipment list

are summarized in Sections 4.3.2.1 and 4.3.2.2

.Carbon Dioxide Capture Sensitivity Analysis



### 258 Exhibit 4

- 35 Case 2 D2 Process Block Flow Diagram, IGCC with Single WGS Reactor and BypassCarbon Dioxide Capture Sensitivity Analysis



### 259 Exhibit 4

- 36 Case 2 D2A Stream Table, 25% CO 2 Removal with Single WGS BypassCarbon Dioxide Capture Sensitivity Analysis



### 260 Exhibit 4

- 36 Case 2 D2A Stream Table, 25% CO 2 Removal with Single WGS Bypass (continued)Carbon Dioxide Capture Sensitivity Analysis



### 261 Exhibit 4

- 37 Case 2 D2B Stream Table, 45% CO 2 Capture with Single WGS BypassCarbon Dioxide Capture Sensitivity Analysis



### 262 Exhibit 4

- 37 Case 2 D2B Stream Table, 45% CO 2 Capture with Single WGS Bypass (continued)Carbon Dioxide Capture Sensitivity Analysis



### 263 Exhibit 4

- 38 Case 2 D2C Stream Table, 60% CO 2 Capture with Single WGS BypassCarbon Dioxide Capture Sensitivity Analysis



### 264 Exhibit 4

- 38 Case 2 D2C Stream Table, 60% CO2 Capture with Single WGS Bypass (continued)Carbon Dioxide Capture Sensitivity Analysis



### 265 Exhibit 4

- 39 Case 2 D2D Stream Table, 75% CO 2 Capture with Single WGS BypassCarbon Dioxide Capture Sensitivity Analysis



### 266 Exhibit 4

- 39 Case 2 D2D Stream Table, 75% CO 2 Capture with Single WGS Bypass (continued)Carbon Dioxide Capture Sensitivity Analysis



### 267 Exhibit 4

- 40 Case 2 D2 Performance Modeling Results

POWER SUMMARY (Gross Power at Generator Terminals, kWe) D2A (25%) D2B

(45%) D2C

(60%) D2D

(75%)

Gas Turbine Power 464,000 464,000 464,000 464,000

Sweet Gas Expander Power 5,800 6, 0 00 6, 1 00 6, 2 00

Steam Turbine Power 280, 6 00 276, 9 00 275, 1 00 271,800

Total 750, 4 00 746,900 745, 2 00 742, 0 00

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 4 5 7 4 61 46 3 4 66

Coal Milling 2,1 59 2,19 3 2,22 1 2,2 46

Sour Water Recycle Slurry Pump 18 1 18 3 18 5 1 86

Slag Handling 1,1 06 1,12 3 1,1 38 1,150

Air Separation Unit Auxiliaries 1,000 1,000 1,000 1,000

Air Separation Unit Main Air Compressor 64,0 24 65,0 36 65,8 75 66,5 47

Oxygen Compressor 10, 1 6 7 10,3 2 6 10,4 0 4 10,5 18

Nitrogen Compressors 31,38 9 32,02 7 33,0 61 34,2 81

CO 2 Compressor 8,4 97 15,0 47 20,3 3 5 25,6 05

Boiler Feedwater Pumps 3,9 70 4,00 1 4,0 35 4,06 2

Condensate Pump 2 5 0 2 5 6 260 26 2

Quench Water Pump 5 1 3 5 18 5 23 5 27

Circulating Water Pump 4, 1 65 4,3 12 4,4 2 0 4,51 3

Ground Water Pumps 4 25 4 56 480 50 1

Cooling Tower Fans 2,1 5 3 2,23 1 2,2 87 2,33 1

Scrubber Pumps 2 1 2 2 16 2 18 220

Acid Gas Removal 4,8 61 8,91 2 12,1 49 15,5 19

Gas Turbine Auxiliaries 1,000 1,000 1,000 1,000

Steam Turbine Auxiliaries 100 100 100 100

Claus Plant/TGTU Auxiliaries 250 250 250 250

Claus Plant TG Recycle Compressor 8 28 7 56 699 1,05 2

Miscellaneous Balance of Plant 1 3,000 3,000 3,000 3,000

Transformer Losses 2,6 6 7 2,69 3 2,7 19 2,74 1

TOTAL AUXILIARIES, kWe 143,374 156,097 166,822 178,077

NET POWER, kWe 60 7,026 590, 803 578, 378 56 3,923

Net Plant Efficiency, % (HHV) 38. 4 % 36. 8 % 35.5 % 34. 3 %

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9, 3 85 (8, 895 ) 9,796 (9,285) 10,13 2 (9,604) 10,50 6 (9,95 8 )

Condenser Duty, GJ/hr (10 6 Btu/hr) 1, 625 (1, 54 0) 1,614 (1,530) 1,593 (1,510) 1,561 (1,480)

CONSUMABLES

As

- Received Coal Feed, kg/hr (lb/hr) 209,9 50 ( 462, 86 1 ) 213,2 42 (470,1 17 ) 21 5,970 (476, 133 ) 218,3 39 (481, 355 )

Thermal Input, kW th 2 1, 582, 508 1,607, 315 1,62 7,884 1,64 5,739

Raw Water Withdrawal, m 3 /min (gpm) 17. 8 (4, 697 ) 19.1 (5,03 8 ) 20.1 (5,30 0 ) 20.9 (5,53 0 )

Raw Water Consumption, m 3 /min (gpm) 14. 1 (3,7 2 7 ) 15.3 (4,03 3 ) 16.2 (4,27 0 ) 17.0 (4,48 1 )

Notes: 1. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

2. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)Carbon Dioxide Capture Sensitivity Analysis



### 268 4.3.2.1 Environmental Performance for Case 2 D2

The environmental targets for emissions of Hg, NO

x 

### , SO 2 

### , and particulate matter were presented

in Section 2.4 . A summary of the p lant air emissions for Case 2 D2A, D2 B , D2C, and D2D is presented in Exhibit 4

- 41

.

For Case 2 D2, SO 2 

### emissions are controlled by sulfur capture across the two

- stage SelexolTM
unit. The clean syngas exiting the AGR unit has a sulfur concentration of about 10 ppmv, resulting in a concentration in the flue gas of less than 2 ppmv. The H 2 

### S

- rich regeneration gas produced in Case 2 D2 is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H 2 

### S and then recycled back to the SelexolTM
unit, thereby eliminating the need for a tail gas treatmen t unit.

NO

x 

### emissions are limited by nitrogen dilution of the syngas to 15 ppmvd (as NO 2 

### @ 15 percent

O 2 

### ). Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process, and ultimately incinerated in the Claus plant burner. This also assists in lowering

NOx levels.

Particulate discharge to the atmosphere is limited to extremely low values by the use of the syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particul ate emissions represent filterable particulate only.

Ninety

- five percent of the mercury is captured from the syngas by an activated carbon bed.

For Case 2 D2, varying levels of the CO 2 

### [25 percent (D2A), 45 percent (D2B), 60 percent (D2C), and 75 percent (D2D)] in the syngas are captured in the two

- stage SelexolTM unit and
compressed for sequestration. The carbon balance for Case 2 D2 is shown in Exhibit 4

- 42 . The carbon input to the plant consists of carbon in the air and coal. Carbon in the air is not neg lected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, as dissolved CO 2 

### in the wastewater blowdown stream, and as CO 2 

### in the stack gas, ASU vent gas, and the captured CO 2 

### product. Carbon in the wastewater blowdown stream is calculated by difference to close the material balance. The carbon capture efficiency is defined as the pounds of carbon in the CO 2 

### product stream relative to the amount of

carbon in the coal

, less carbon contained in the slag , represented by the following fraction:

(Carbon in CO 2 

### Product)/[(Carbon in the Coal)

- (Carbon in Slag)] or

73,037/(295,050

- 5,901)*100=25.3% (D2A)
131,784/(299,675

- 5,993)*100=44.9% (D2B)
178,734/(303,510

- 6,070)*100=60.1% (D2C)
225,516/(306,839

- 6,137)*100=75.0% (D2D)

Exhibit 4

- 43 shows the sulfur balance for Case 2 D2. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the pounds of sulfur recovered in the Claus plant, dissolved

SO 2 

### in the wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible, and the sulfur content of the blowdown stream is calculated by

difference to close the material balance. The total sulfur capture is repr esented by the following

fraction:Carbon Dioxide Capture Sensitivity Analysis



### 269 (Sulfur byproduct/Sulfur in the coal) or
(11, 583 /11, 601 )*100 = 99.8 % (D2 A)
(11,76 5 /11,78 3 )*100 = 99.8% (D2B)
(11,91 6 /11,93 4 )*100 = 99.8% (D2C)
(12,04 7 /12,06 5 )*100 = 99.8% (D2D)

The overall water balance s for Case 2 D2A, D2B, D2C, and D2D are shown i n Exhibit 4

- 44

, Exhibit 4

- 45

, Exhibit 4

- 46 , and Exhibit 4

- 47 , respectively. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the total amount of water required for a particular process. Some water is recovered within t he

proces s and that water is re used as internal recycle. Raw water withdrawal is the difference between water demand and internal recycle. Process water discharged from the power plant is

also account ed for in this study. Raw water consumption represents raw water withdrawal less process water discharge.

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 4

- 48 through

Exhibit 4

- 59

.

Gasifier and ASU

Syngas Cleanup

Power Block

An overall plant energy balance for Case D2A, D2B, D2C, and D2D is provided in tabular form

in Exhibit 4

- 60

, Exhibit 4

- 61

, Exhibit 4

- 62 , and Exhibit 4

- 63 , respectively. The power out is the combined combustion turbine, steam turbine and expander power after generator losses. In addition, energy balance Sankey diagrams are provided for D2A, D2B, D2C, and D2D in Exhibit

4

- 64

, Exhibit 4

- 65

, Exhibit 4

- 66 , and Exhibit 4

- 67 , respectively.Carbon Dioxide Capture Sensitivity Analysis



### 270 Exhibit 4

- 41 Case 2 D2 Estimated Air Emission Rates

kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)

D2A D2B D2C D2D D2A D2B D2C D2D D2A D2B D2C D2D

SO 2 0.001

(0.002) 0.001

(0.002) 0.001

(0.002) 0.001

(0.002) 37 (40) 37 (41) 38 (42) 38 (42) 0.007 (0.02) 0.007

(0.02) 0.007

(0.02) 0.007

(0.02)

NO X 0.024

(0.055) 0.023

(0.053) 0.022

(0.051) 0.022

(0.050) 947 (1,044) 926 (1,021) 909 (1,002) 894 (985) 0.180 (0.397) 0.177

(0.390) 0.174

(0.384) 0.172

(0.379)

PM 0.003

(0.0071) 0.003

(0.0071) 0.003

(0.0071) 0.003

(0.0071) 122 (134) 124 (136) 125 (138) 127 (140) 0.023 (0.051) 0.024

(0.052) 0.024

(0.053) 0.024

(0.054)

Hg 0.246x10 - 6

(0.571x10 - 6 ) 0.246x10 - 6

(0.571x10 - 6 ) 0.246x10 - 6

(0.571x10 - 6 ) 0.246x10 - 6

(0.571x10 - 6 ) 0.010

(0.011) 0.010

(0.011) 0.010

(0.011) 0.010

(0.011) 1.87x10 - 6

(4.11x10 - 6 ) 1.90x10 - 6

(4.20x10 - 6 ) 1.93x10 - 6

(4.26x10 - 6 ) 1.96x10 - 6

(4.32x10 - 6 )

CO 2 63. 3

(147. 3 ) 46.8 (108.8) 33.9 (78.9) 21.4 (49.7) 2,5 2 8,260 (2,7 8 6,929 ) 1,89 6,795

(2,09 0,859 ) 1,393, 730

(1,536, 324 ) 886, 830

(977, 563 ) 48 1 (1,06 0 ) 362 (799) 267 (588) 171 (376)

CO 2 net 59 4 (1,31 0 ) 458 (1,010) 344 (758) 224 (495)Carbon Dioxide Capture Sensitivity Analysis



### 271 Exhibit 4

- 42 Case 2 D2 Carbon Balance

Carbon In, kg/hr (lb/hr)

D2A D2B D2C D2D

Coal 133,8 32

(295,0 50 ) 135,9 30

(299, 675 ) 137,6 70

(303,5 10 ) 139, 180

(306,8 39 )

Air (CO 2 ) 535

(1,179) 536

(1,183) 538

(1,18 5 ) 539

(1,188)

Total 13 4,3 67

(29 6,2 29 ) 136,4 66

(300, 858 ) 138,2 08

(304, 695 ) 139,7 19

(308,0 2 7)
Carbon Out, kg/hr (lb/hr)

Slag 2,677

(5,90 1 ) 2,719

(5,99 3 ) 2,75 3

(6,07 0 ) 2,784

(6,13 7 )

Stack Gas 98, 459

(217, 066 ) 73,8 68

(162,8 51 ) 54,2 77

(119,6 60 ) 34,5 36

(76,1 40 )

ASU Vent 102 (225) 104 (229) 105 (232) 106 (234)

CO 2 Product 33, 129

(7 3,037 ) 59,7 76

(131, 784 ) 81,0 72

(178,7 34 ) 102, 292

(225,5 16 )
Convergence

Tolerance 0 (0)

- 1 (1) 1 (

- 1) 1 (0)

Total 13 4,367

(29 6,229 ) 136,466

(300,858) 138,208

(304,695) 139,719

(308,027)

Exhibit 4

- 43 Case 2 D2 Sulfur Balance

Sulfur In, kg/hr (lb/hr)

D2A D2B D2C D2D

Coal 5,26 2 (11,60 1 ) 5,34 5

(11,78 3 ) 5,41 3

(11,93 4 ) 5,47 2

(12,06 5 )

Total 5, 26 2 (11, 60 1 ) 5,34 5

(11,78 3 ) 5,41 3

(11,93 4 ) 5,47 2

(12,06 5 )
Sulfur Out, kg/hr (lb/hr)

Elemental Sulfur 5,25 4 (11,58 3 ) 5,337

(11,76 5 ) 5,40 5

(11,91 6 ) 5,46 4

(12,04 7 )

Stack Gas 3 (6) 3 (6) 3 (6) 3 (6)

CO 2 Product 5 ( 12 ) 5 (12) 5 (12) 5 (12)

Convergence

Tolerance* 0 (0) 0 (0) 0 (0) 0 (0)

Total 5, 262 (11, 601 ) 5,345

(11,783) 5,413

(11,934) 5,472

(12,065)Carbon Dioxide Capture Sensitivity Analysis



### 272 Exhibit 4

- 44 Case 2 D2A (25%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Slag Handling 0.50 (132) 0.50 (132) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.7 (719) 0.88 (233) 1.8 (486) 0.0 (0) 1.8 (486)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7)

Condenser Makeup 0.2 (59) 0.0 (0) 0.2 (59) 0.0 (0) 0.2 (59)

Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

Shift Steam 0.0 (4) 0.0 (0) 0.0 (4)

C T Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 16.2 (4,282) 0.49 (130) 15.7 (4,153) 3.6 (963) 12.1 (3,190)

BFW Blowdown 0.0 (0) 0.21 (55)

- 0.21 (

- 55)

SWS Blowdown 0.0 (0) 0.28 (75)

- 0.28 (

- 75)

SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 21.1 (5,572) 3.31 (875) 17.8 (4,697) 3.7 (970) 14.1 (3,727)

Total, gal/MWh net 551 86 464 96 368Carbon Dioxide Capture Sensitivity Analysis



### 273 Exhibit 4

- 45 Case 2 D2B (45%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Slag Handling 0.51 (134) 0.51 (134) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.8 (730) 0.63 (167) 2.1 (564) 0.0 (0) 2.1 (564)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7)

Condenser Makeup 0.6 (161) 0.0 (0) 0.6 (161) 0.0 (0) 0.6 (161)

Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

Shift Steam 0.4 (105) 0.0 (0) 0.4 (105)

C T Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 16.8 (4,437) 0.47 (124) 16.3 (4,313) 3.8 (998) 12.5 (3,315)

BFW Blowdown 0.0 (0) 0.21 (55)

- 0.21 (

- 55)

SWS Blowdown 0.0 (0) 0.26 (69)

- 0.26 (

- 69)

SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 22.1 (5,848) 3.07 (811) 19.1 (5,038) 3.8 (1,005) 15.3 (4,033)

Total, gal/MWh net 594 82 512 102 410Carbon Dioxide Capture Sensitivity Analysis



### 274 Exhibit 4

- 46 Case 2 D2C (60%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Slag Handling 0.51 (136) 0.51 (136) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.8 (740) 0.43 (113) 2.4 (626) 0.0 (0) 2.4 (626)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.02 (6)

- 0.02 (

- 6)

Condenser Makeup 0.9 (244) 0.0 (0) 0.9 (244) 0.0 (0) 0.9 (244)

Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

Shift Steam 0.7 (189) 0.0 (0) 0.7 (189)

C T Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 17.2 (4,548) 0.45 (119) 16.8 (4,429) 3.9 (1,023) 12.9 (3,406)

BFW Blowdown 0.0 (0) 0.21 (55)

- 0.21 (

- 55)

SWS Blowdown 0.0 (0) 0.24 (64)

- 0.24 (

- 64)

SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 22.9 (6,059) 2.87 (759) 20.1 (5,300) 3.9 (1,029) 16.2 (4,270)

Total, gal/MWh net 629 79 550 107 443Carbon Dioxide Capture Sensitivity Analysis



### 275 Exhibit 4

- 47 Case 2 D2D (75%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Slag Handling 0.52 (137) 0.52 (137) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.8 (748) 0.24 (62) 2.6 (686) 0.0 (0) 2.6 (686)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.02 (6)

- 0.02 (

- 6)

Condenser Makeup 1.2 (322) 0.0 (0) 1.2 (322) 0.0 (0) 1.2 (322)

Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

Shift Steam 1.0 (268) 0.0 (0) 1.0 (268)

C T Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

BFW Makeup 0.21 (54) 0.0 (0) 0.21 (54)

Cooling Tower 17.6 (4,636) 0.43 (114) 17.1 (4,522) 3.9 (1,043) 13.2 (3,480)

BFW Blowdown 0.0 (0) 0.21 (54)

- 0.21 (

- 54)

SWS Blowdown 0.0 (0) 0.23 (59)

- 0.23 (

- 59)

SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 23.6 (6,239) 2.68 (709) 20.9 (5,530) 4.0 (1,049) 17.0 (4,481)

Total, gal/MWh net 664 75 588 112 477Carbon Dioxide Capture Sensitivity Analysis



### 276 This page intentionally left blankCarbon Dioxide Capture Sensitivity Analysis



### 277 Exhibit 4

- 48 Case 2 D2A (25%) Heat and Mass Balance, GEE Gasifier and ASUCarbon Dioxide Capture Sensitivity Analysis



### 278 Exhibit 4

- 49 Case 2 D2A (25%) Heat and Mass Balance, Syngas CleanupCarbon Dioxide Capture Sensitivity Analysis



### 279 Exhibit 4

- 50 Case 2 D 2A (25%) Heat and Mass Balance, Power BlockCarbon Dioxide Capture Sensitivity Analysis



### 280 Exhibit 4

- 51 Case 2 D2B (45%) Heat and Mass Balance, GEE Gasifier and ASUCarbon Dioxide Capture Sensitivity Analysis



### 281 Exhibit 4

- 52 Case 2 D2B (45%) Heat and Mass Balance, Syngas CleanupCarbon Dioxide Capture Sensitivity Analysis



### 282 Exhibit 4

- 53 Case 2 D2B (45%) Heat and Mass Balance, Power BlockCarbon Dioxide Capture Sensitivity Analysis



### 283 Exhibit 4

- 54 Case 2 D2C (60%) Heat and Mass Balance, GEE Gasifier and ASUCarbon Dioxide Capture Sensitivity Analysis



### 284 Exhibit 4

- 55 Case 2 D2C (60%) Heat and Mass Balance, Syngas CleanupCarbon Dioxide Capture Sensitivity Analysis



### 285 Exhibit 4

- 56 Case 2 D2C (60%) Heat and Mass Balance, Power BlockCarbon Dioxide Capture Sensitivity Analysis



### 286 Exhibit 4

- 57 Case 2 D2D (75%) Heat and Mass Balance, GEE Gasifier and ASUCarbon Dioxide Capture Sensitivity Analysis



### 287 Exhibit 4

- 58 Case 2 D2D (75%) Heat and Mass Balance, Syngas CleanupCarbon Dioxide Capture Sensitivity Analysis



### 288 Exhibit 4

- 59 Case 2 D2D (75%) Heat and Mass Balance, Power BlockCarbon Dioxide Capture Sensitivity Analysis



### 289 Exhibit 4

- 60 Case 2 D2A (25%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,697 (5,400) 4.8 (4.5) 0 (0) 5,702 (5,404)

ASU Air 0 (0) 22.7 (21.5) 0 (0) 23 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 66.9 (63.4) 0 (0) 67 (63)

Totals 5,697 (5,400) 190.5 (180.5) 0 (0) 5,888 (5,580)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.9 (1.8) 0 (0) 2 (2)

Slag 88 (83) 36.0 (34.1) 0 (0) 124 (117)

Sulfur 49 (46) 0.6 (0.6) 0 (0) 49 (47)

CO 2 0 (0)

- 13.1 (

- 12.4) 0 (0)

- 13 (

- 12)

Gasifier Heat Loss 0 (0) 42.4 (40.2) 0 (0) 42 (40)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 937 (889) 0 (0) 937 (889)

Cooling Tower* 0 (0) 2,073 (1,965) 0 (0) 2,073 (1,965)

Process Losses* * 0 (0) 424 (402) 0 (0) 424 (402)

Net Power 0 (0) 0.0 (0.0) 2,185 (2,071) 2,185

(2,071)

Totals 136 (129) 3,566 (3,380) 2,185 (2,071) 5,888

(5,580)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

air cooler. ** Calculated by difference to close the energy balance.Carbon Dioxide Capture Sensitivity Analysis



### 290 Exhibit 4

- 61 Case 2 D2B (45%) Energ y Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,786 (5,484) 4.8 (4.6) 0 (0) 5,791 (5,489)

ASU Air 0 (0) 23.1 (21.8) 0 (0) 23 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 71.7 (68.0) 0 (0) 72 (68)

Totals 5,786 (5,484) 195.8 (185.5) 0 (0) 5,982 (5,670)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.9 (1.8) 0 (0) 2 (2)

Slag 89 (84) 36.5 (34.6) 0 (0) 126 (119)

Sulfur 49 (47) 0.6 (0.6) 0 (0) 50 (47)

CO 2 0 (0)

- 31.7 (

- 30.1) 0 (0)

- 32 (

- 30)

Gasifier Heat Loss 0 (0) 43.1 (40.8) 0 (0) 43 (41)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,051 (996) 0 (0) 1,051 (996)

Cooling Tower* 0 (0) 2,113 (2,003) 0 (0) 2,113 (2,003)

Process Losses* * 0 (0) 439 (416) 0 (0) 439 (416)

Net Power 0 (0) 0.0 (0.0) 2,127 (2,016) 2,127

(2,016)

Totals 139 (131) 3,717 (3,523) 2,127 (2,016) 5,982

(5,670)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

air cooler. ** Calculated by difference to close the energy balance.Carbon Dioxide Capture Sensitivity Analysis



### 291 Exhibit 4

- 62 Case 2 D2C (60%) Energ y Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,860 (5,555) 4.9 (4.6) 0 (0) 5,865 (5,559)

ASU Air 0 (0) 23.4 (22.1) 0 (0) 23 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 75.4 (71.5) 0 (0) 75 (71)

Totals 5,860 (5,555) 199.9 (189.4) 0 (0) 6,060 (5,744)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.9 (1.8) 0 (0) 2 (2)

Slag 90 (86) 37.0 (35.1) 0 (0) 127 (121)

Sulfur 50 (47) 0.6 (0.6) 0 (0) 51 (48)

CO 2 0 (0)

- 45.9 (

- 43.5) 0 (0)

- 46 (

- 43)

Gasifier Heat Loss 0 (0) 43.6 (41.4) 0 (0) 44 (41)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,143 (1,083) 0 (0) 1,143 (1,083)

Cooling Tower* 0 (0) 2,139 (2,028) 0 (0) 2,139 (2,028)

Process Losses* * 0 (0) 455 (431) 0 (0) 455 (431)

Net Power 0 (0) 0.0 (0.0) 2,082 (1,974) 2,082

(1,974)

Totals 140 (133) 3,838 (3,637) 2,082 (1,974) 6,060

(5,744)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

air cooler. ** Calculated by difference to close the energy balance.Carbon Dioxide Capture Sensitivity Analysis



### 292 Exhibit 4

- 63 Case 2 D2D (75%) Energ y Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,925 (5,615) 5.0 (4.7) 0 (0) 5,930 (5,620)

ASU Air 0 (0) 23.6 (22.4) 0 (0) 24 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 78.7 (74.6) 0 (0) 79 (75)

Totals 5,925 (5,615) 203.4 (192.8) 0 (0) 6,128 (5,808)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.8 (1.7) 0 (0) 2 (2)

Slag 91 (86) 37.4 (35.4) 0 (0) 129 (122)

Sulfur 51 (48) 0.6 (0.6) 0 (0) 51 (49)

CO 2 0 (0)

- 59.7 (

- 56.6) 0 (0)

- 60 (

- 57)

Gasifier Heat Loss 0 (0) 44.1 (41.8) 0 (0) 44 (42)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,230 (1,166) 0 (0) 1,230 (1,166)

Cooling Tower* 0 (0) 2,152 (2,040) 0 (0) 2,152 (2,040)

Process Losses* * 0 (0) 486 (461) 0 (0) 486 (461)

Net Power 0 (0) 0.0 (0.0) 2,030 (1,924) 2,030

(1,924)

Totals 142 (134) 3,956 (3,750) 2,030 (1,924) 6,128

(5,808)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

air cooler. ** Calculated by difference to close the energy balance.Carbon Dioxide Capture Sensitivity Analysis



### 293 Exhibit 4

- 64 Case 2 D2A Energy Balance Sankey Diagram

Exhibit 4

- 65 Case 2 D2B Energy Balance Sankey DiagramCarbon Dioxide Capture Sensitivity Analysis



### 294 Exhibit 4

- 66 Case 2 D2C Energy Balance Sankey Diagram

Exhibit 4

- 67 Case 2 D2D Energy Balance Sankey DiagramCarbon Dioxide Capture Sensitivity Analysis



### 295 4.3.2.2 Major Equipment List for Case 2 D2

Major equipment items for Case 2 D2 (single WGS with bypass) are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cos t estimate s . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contin gency for heads on pumps and fans.

ACCOUNT 1 COAL HANDLING

Equipment

No. Description Type Design Conditions Opr Qty. (Spares) D2A D2B D2C D2D

1 Bottom Trestle Dumper and

Receiving Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0)

3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

4 Transfer Tower No. 1 Enclosed N/A N/A N/A N/A 1 (0)

5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

6 As

- Received Coal Sampling

System Two

- stage N/A N/A N/A N/A 1 (0)

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

8 Reclaim Hopper N/A 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 2 (1)

9 Feeder Vibratory 172 tonne/hr (190 tph) 172 tonne/hr (190 tph) 181 tonne/hr (200 tph) 181 tonne/hr (200 tph) 2 (1)

10 Conveyor No. 3 Belt w/ tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 1 (0)

11 Crusher Tower N/A N/A N/A N/A N/A 1 (0)

12 Coal Surge Bin w/ Vent

Filter Dual outlet 172 tonne (190 ton) 172 tonne (190 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

13 Crusher Impactor

reduction 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 2 (0)

14 As

- Fired Coal Sampling

System Swing hammer N/A N/A N/A N/A 1 (1)

15 Conveyor No. 4 Belt w/tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 1 (0)

16 Transfer Tower No. 2 Enclosed N/A N/A N/A N/A 1 (0)

17 Conveyor No. 5 Belt w/ tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 1 (0)

18 Coal Silo w/ Vent Filter and

Slide Gates Field erected 726 tonne (800 ton) 816 tonne (900 ton) 816 tonne (900 ton) 816 tonne (900 ton) 3 (0)



### ACCOUNT 2 COAL PREPARATION AND FEED

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

1 Feeder Vibratory 73 tonne/h (80 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 3 (0)

2 Conveyor No. 6 Belt w/tripper 227 tonne/h (250 tph) 236 tonne/h (260 tph) 236 tonne/h (260 tph) 236 tonne/h (260 tph) 1 (0)

3 Rod Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 472 tonne (520 ton) 472 tonne (520 ton) 481 tonne (530 ton) 1 (0)

4 Weigh Feeder Belt 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)

5 Rod Mill Rotary 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)

6 Slurry Water Storage

Tank with Agitator Field erected 285,044 liters (75,300 gal) 289,511 liters (76,480 gal) 293,220 liters (77,460 gal) 296,438 liters (78,310 gal) 2 (0)

7 Slurry Water Pumps Centrifugal 795 lpm (210 gpm) 795 lpm (210 gpm) 833 lpm (220 gpm) 833 lpm (220 gpm) 2 (1)

8 Trommel Screen Coarse 163 tonne/h (180 tph) 163 tonne/h (180 tph) 163 tonne/h (180 tph) 172 tonne/h (190 tph) 2 (0)Carbon Dioxide Capture Sensitivity Analysis



### 296 Equipment

No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

9 Rod Mill Discharge Tank

with Agitator Field erected 372,866 liters (98,500 gal) 378,696 liters (100,040 gal) 383,541 liters (101,320 gal) 387,781 liters (102,440 gal) 2 (0)

10 Rod Mill Product Pumps Centrifugal 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,407 lpm (900 gpm) 2 (2)

11 Slurry Storage Tank with

Agitator Field erected 1,118,598 liters (295,500 gal) 1,136,011 liters (300,100 gal) 1,150,774 liters (304,000 gal) 1,163,266 liters (307,300 gal) 2 (0)

12 Slurry Recycle Pumps Centrifugal 6,057 lpm (1,600 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 2 (2)

13 Slurry Product Pumps Positive displacement 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,407 lpm (900 gpm) 2 (2)



### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

1 Demineralized Water Storage

Tank Vertical, cylindrical,

outdoor 1,086,413 liters (287,000 gal) 1,090,199 liters (288,000 gal) 1,078,842 liters (285,000 gal) 1,067,486 liters (282,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 7,041 lpm @ 91 m H 2 O (1,860 gpm @ 300 ft H 2 O) 7,230 lpm @ 91 m H 2 O (1,910 gpm @ 300 ft H 2 O) 7,344 lpm @ 91 m H 2 O (1,940 gpm @ 300 ft H 2 O) 7,382 lpm @ 91 m H 2 O (1,950 gpm @ 300 ft H 2 O) 2 (1)

3 Deaerator (integral w/ HRSG) Horizontal spray type 484,437 kg/hr (1,068,000 lb/hr) 495,323 kg/hr (1,092,000 lb/hr) 501,220 kg/hr (1,105,000 lb/hr) 505,755 kg/hr (1,115,000 lb/hr) 2 (0)

4 Intermediate Pressure

Feedwater Pump Horizontal centrifugal, single stage 8,101 lpm @ 27 m H 2 O (2,140 gpm @ 90 ft H 2 O) 8,139 lpm @ 27 m H 2 O (2,150 gpm @ 90 ft H 2 O) 7,912 lpm @ 27 m H 2 O (2,090 gpm @ 90 ft H 2 O) 7,684 lpm @ 27 m H 2 O (2,030 gpm @ 90 ft H 2 O) 2 (1)

5 High Pressure Feedwater Pump

No. 1 Barrel type, multi

stage, centrifugal HP water: 6,132 lpm @ 1,859

m H 2 O (1,620 gpm @ 6,100

ft H 2 O) HP water: 6,132 lpm @

1,859 m H 2 O (1,620 gpm @
6,100 ft H 2 O) HP water: 6,057 lpm @

1,859 m H 2 O (1,600 gpm @
6,100 ft H 2 O) HP water: 5,981 lpm @

1,859 m H 2 O (1,580 gpm @
6,100 ft H 2 O) 2 (1)

6 High Pressure Feedwater Pump

No. 2 Barrel type, multi

stage, centrifugal IP water: 1,476 lpm @ 223 m

H 2 O (390 gpm @ 730 ft H 2 O) IP water: 1,514 lpm @ 223

m H 2 O (400 gpm @ 730 ft

H 2 O) IP water: 1,628 lpm @ 223

m H 2 O (430 gpm @ 730 ft

H 2 O) IP water: 1,703 lpm @ 223

m H 2 O (450 gpm @ 730 ft

H 2 O) 2 (1)

7 Auxiliary Boiler Shop fabricated, water

tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa,

343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa,

343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa,

343°C (40,000 lb/hr, 400 psig, 650°F) 1 (0)

8 Service Air Compressors Flooded Screw 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 (1)

9 Instrument Air Dryers Duplex, regenerative 28 m 3 /min (1,000 scfm) 28 m 3 /min (1,000 scfm) 28 m 3 /min (1,000 scfm) 28 m 3 /min (1,000 scfm) 2 (1)

10 Closed Cylce Cooling Heat

Exchangers Plate and frame 248 GJ/hr (234.6264965 MMBtu/hr) each 275 GJ/hr (260.9758943 MMBtu/hr) each 299 GJ/hr (283.58088495 MMBtu/hr) each 324 GJ/hr (306.6532524 MMBtu/hr) each 2 (0)

11 Closed Cycle Cooling Water

Pumps Horizontal centrifugal 88,957 lpm @ 21 m H 2 O (23,500 gpm @ 70 ft H 2 O) 98,799 lpm @ 21 m H 2 O (26,100 gpm @ 70 ft H 2 O) 107,506 lpm @ 21 m H 2 O (28,400 gpm @ 70 ft H 2 O) 116,212 lpm @ 21 m H 2 O (30,700 gpm @ 70 ft H 2 O) 2 (1)

12 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H 2 O (1,000 gpm @ 350 ft H 2 O) 3,785 lpm @ 107 m H 2 O (1,000 gpm @ 350 ft H 2 O) 3,785 lpm @ 107 m H 2 O (1,000 gpm @ 350 ft H 2 O) 3,785 lpm @ 107 m H 2 O (1,000 gpm @ 350 ft H 2 O) 1 (1)

13 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 76 m H 2 O (700 gpm @ 250 ft H 2 O) 2,650 lpm @ 76 m H 2 O (700 gpm @ 250 ft H 2 O) 2,650 lpm @ 76 m H 2 O (700 gpm @ 250 ft H 2 O) 2,650 lpm @ 76 m H 2 O (700 gpm @ 250 ft H 2 O) 1 (1)

14 Raw Water Pumps Stainless steel, single

suction 4,580 lpm @ 18 m H 2 O (1,210 gpm @ 60 ft H 2 O) 4,921 lpm @ 18 m H 2 O (1,300 gpm @ 60 ft H 2 O) 5,186 lpm @ 18 m H 2 O (1,370 gpm @ 60 ft H 2 O) 5,413 lpm @ 18 m H 2 O (1,430 gpm @ 60 ft H 2 O) 2 (1)

15 Ground Water Pumps Stainless steel, single

suction 3,028 lpm @ 268 m H 2 O (800 gpm @ 880 ft H 2 O) 3,293 lpm @ 268 m H 2 O (870 gpm @ 880 ft H 2 O) 2,574 lpm @ 268 m H 2 O (680 gpm @ 880 ft H 2 O) 2,725 lpm @ 268 m H 2 O (720 gpm @ 880 ft H 2 O) 3 (1)

16 Filtered Water Pumps Stainless steel, single

suction 2,082 lpm @ 49 m H 2 O (550 gpm @ 160 ft H 2 O) 2,309 lpm @ 49 m H 2 O (610 gpm @ 160 ft H 2 O) 2,498 lpm @ 49 m H 2 O (660 gpm @ 160 ft H 2 O) 2,688 lpm @ 49 m H 2 O (710 gpm @ 160 ft H 2 O) 2 (1)

17 Filtered Water Tank Vertical, cylindrical 999,349 liter (264,000 gal) 1,112,911 liter (294,000 gal) 1,207,546 liter (319,000 gal) 1,290,825 liter (341,000 gal) 2 (0)

18 Makeup Water Demineralizer Anion, cation, and

mixed bed 303 lpm (80 gpm) 530 lpm (140 gpm) 681 lpm (180 gpm) 871 lpm (230 gpm) 2 (0)Carbon Dioxide Capture Sensitivity Analysis



### 297 Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

19 Liquid Waste Treatment System 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 1 (0)



### ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

1 Gasifier Pressurized slurry

feed, entrained bed 2,812 tonne/day, 5.6 MPa (3,100 tpd, 814.96 psia) 2,812 tonne/day, 5.6 MPa (3,100 tpd, 814.96 psia) 2,812 tonne/day, 5.6 MPa (3,100 tpd, 814.96 psia) 2,903 tonne/day, 5.6 MPa (3,200 tpd, 814.96 psia) 2 (0)

2 Synthesis Gas Cooler Vertical downflow

radiant heat exchanger with outlet quench chamber 243,126 kg/hr (536,000 lb/hr) 247,208 kg/hr (545,000 lb/hr) 250,383 kg/hr (552,000 lb/hr) 253,105 kg/hr (558,000 lb/hr) 2 (0)

3 Synthesis Gas Cyclone High efficiency 332,937 kg/hr (734,000 lb/hr) Design efficiency 90% 337,926 kg/hr (745,000 lb/hr) Design efficiency 90% 342,462 kg/hr (755,000 lb/hr) Design efficiency 90% 346,091 kg/hr (763,000 lb/hr) Design efficiency 90% 2 (0)

4 Candle Filter Pressurized filter with pulse

- jet cleaning metallic filters metallic filters metallic filters metallic filters 2 (0)

5 Syngas Scrubber Including Sour

Water Stripper Vertical upflow 332,937 kg/hr (734,000 lb/hr) 337,926 kg/hr (745,000 lb/hr) 342,462 kg/hr (755,000 lb/hr) 346,091 kg/hr (763,000 lb/hr) 2 (0)

6 Raw Gas Coolers Shell and tube with

condensate drain 288,031 kg/hr (635,000 lb/hr) 319,329 kg/hr (704,000 lb/hr) 333,844 kg/hr (736,000 lb/hr) 346,998 kg/hr (765,000 lb/hr) 8 (0)

7 Raw Gas Knockout Drum Vertical with mist

eliminator 213,642 kg/hr, 35°C, 5.1 MPa (471,000 lb/hr, 95°F, 745

psia) 240,404 kg/hr, 35°C, 5.2

MPa (530,000 lb/hr, 95°F, 750

psia) 262,630 kg/hr, 35°C, 5.1

MPa (579,000 lb/hr, 95°F, 745

psia) 283,042 kg/hr, 35°C, 5.1

MPa (624,000 lb/hr, 95°F, 745

psia) 2 (0)

8 Flare Stack Self

- supporting,
carbon steel, stainless steel top, pilot ignition 332,937 kg/hr (734,000 lb/hr)

syngas 337,926 kg/hr (745,000 lb/hr) syngas 342,462 kg/hr (755,000 lb/hr) syngas 346,091 kg/hr (763,000 lb/hr) syngas 2 (0)

9 ASU Main Air Compressor Centrifugal, multi

stage 5,663 m 3 /min @ 1.3 MPa (200,000 scfm @ 190 psia) 5,748 m 3 /min @ 1.3 MPa (203,000 scfm @ 190 psia) 5,805 m 3 /min @ 1.3 MPa (205,000 scfm @ 190 psia) 5,862 m 3 /min @ 1.3 MPa (207,000 scfm @ 190 psia) 2 (0)

10 Cold Box Vendor design 2,268 tonne/day (2,500 tpd) of 95% purity oxygen 2,268 tonne/day (2,500 tpd) of 95% purity oxygen 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2 (0)

11 Oxygen Compressor Centrifugal, multi

stage 1,133 m 3 /min (40,000 scfm)

Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940

psia) 1,161 m 3 /min (41,000 scfm)

Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940

psia) 1,161 m 3 /min (41,000 scfm)

Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940

psia) 1,189 m 3 /min (42,000 scfm)

Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940

psia) 2 (0)

12 Primary Nitrogen Compressor Centrifugal, multi

stage 3,540 m 3 /min (125,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390

psia) 3,596 m 3 /min (127,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390

psia) 3,653 m 3 /min (129,000 scfm)

Su ction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390

psia) 3,710 m 3 /min (131,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390

psia) 2 (0)

13 Secondary Nitrogen

Compressor Centrifugal, single

stage 538 m 3 /min (19,000 scfm)

Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390

psia) 538 m 3 /min (19,000 scfm)

Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390

psia) 538 m 3 /min (19,000 scfm)

Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390

psia) 538 m 3 /min (19,000 scfm)

Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390

psia) 2 (0)

14 Syngas Dilution Nitrogen Boost

Compressor Centrifugal, single

stage 0 m 3 /min (0 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470

psia) 57 m 3 /min (2,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470

psia) 680 m 3 /min (24,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470

psia) 1,331 m 3 /min (47,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470

psia) 2 (0)Carbon Dioxide Capture Sensitivity Analysis



### 298 ACCOUNT 5A SYNGAS CLEANUP

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

1 Mercury

Adsorber Sulfated carbon

bed 213,188 kg/hr (470,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 239,950 kg/hr (529,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 262,176 kg/hr (578,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 282,588 kg/hr (623,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 2 (0)

2 Sulfur Plant Claus type 139 tonne/day (153 tpd) 141 tonne/day (155 tpd) 143 tonne/day (157 tpd) 144 tonne/day (159 tpd) 1 (0)

3 Water Gas Shift

Reactor Fixed bed,

catalytic 1,814 kg/hr (4,000 lb/hr) 232°C (450°F) 5.4 MPa (790 psia) 135,624 kg/hr (299,000 lb/hr) 221°C (430°F) 5.4 MPa (790 psia) 244,486 kg/hr (539,000 lb/hr) 221°C (430°F) 5.4 MPa (790 psia) 346,998 kg/hr (765,000 lb/hr) 221°C (430°F) 5.4 MPa (790 psia) 2 (0)

4 Shift Reactor

Heat Recovery Exchangers Shell and Tube Exchanger 1: 02 GJ/hr (02 MMBtu/hr) Exchanger 2: 6 GJ/hr (6 MMBtu/hr) Exchanger 1: 109 GJ/hr (103 MMBtu/hr) Exchanger 2: 6 GJ/hr (6 MMBtu/hr) Exchanger 1: 196 GJ/hr (186 MMBtu/hr) Exchanger 2: 6 GJ/hr (6 MMBtu/hr) Exchanger 1: 278 GJ/hr (264 MMBtu/hr) Exchanger 2: 6 GJ/hr (6 MMBtu/hr) 2 (0)

5 COS Hydrolysis

Reactor Fixed bed,

catalytic 301,639 kg/hr (665,000 lb/hr) 210°C (410°F) 5.4 MPa (790 psia) 319,329 kg/hr (704,000 lb/hr) 210°C (410°F) 5.4 MPa (790 psia) 333,844 kg/hr (736,000 lb/hr) 204°C (400°F) 5.4 MPa (790 psia) 346,998 kg/hr (765,000 lb/hr) 204°C (400°F) 5.4 MPa (790 psia) 2 (0)

6 Acid Gas

Removal Plant Two

- stage

Selexol 214,549 kg/hr (473,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 241,311 kg/hr (532,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 263,084 kg/hr (580,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 285,310 kg/hr (629,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 2 (0)

7 Hydrogenation

Reactor Fixed bed,

catalytic 6,340 kg/hr (13,978 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 6,081 kg/hr (13,407 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 5,879 kg/hr (12,961 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 9,424 kg/hr (20,776 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 1 (0)

8 Tail Gas Recycle

Compressor Centrifugal 3,053 kg/hr (6,730 lb/hr) 2,497 kg/hr (5,506 lb/hr) 2,052 kg/hr (4,524 lb/hr) 5,537 kg/hr (12,206 lb/hr) 1 (0)



### ACCOUNT 5B CO 2 

### COMPRESSION

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

1 CO 2 Compressor Integrally geared, multi

stage centrifugal 30 3 m 3 /min @ 15.3 MPa (10, 7 00 scfm @ 2,215 psia) 544 m 3 /min @ 15.3 MPa

(19,200 scfm @ 2,215 psia) 736 m 3 /min @ 15.3 MPa

(26,000 scfm @ 2,215 psia) 929 m 3 /min @ 15.3 MPa

(32,800 scfm @ 2,215 psia) 4 (0)



### ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

1 Gas Turbine Advanced F class 230 MW 230 MW 230 MW 230 MW 2 (0)

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV,

60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV,

60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV,

60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV,

60 Hz, 3

- phase 2 (0)

3 Syngas Expansion

Turbine/Generator Turbo Expander 144,560 kg/h (318,700 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 117,435 kg/h (258,900 lb/h) 5.0 MPa (730 psia) Inlet 3.2 MPa (460 psia) Outlet 96,207 kg/h (212,100 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 73,663 kg/h (162,400 lb/h) 5.0 MPa (730 psia) Inlet 3.2 MPa (460 psia) Outlet 2 (0)Carbon Dioxide Capture Sensitivity Analysis



### 299 ACCOUNT 7 HRSG, DUCTING

, AND STACK

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

1 Stack CS plate, type

409SS liner 76 m (250 ft) high x 8.4 m (28 ft) diameter 76 m (250 ft) high x 8.4 m (28 ft) diameter 76 m (250 ft) high x 8.4 m (28 ft) diameter 76 m (250 ft) high x 8.4 m (28 ft) diameter 1 (0)

2 Heat Recovery

Steam

Generator Drum, multi

pressure with

economizer section and integral

deaerator Main steam

- 346,953 kg/hr, 12.4 MPa/554°C (764,901 lb/hr, 1,800 psig/1,029°F)

Reheat steam

- 346,475 kg/hr, 3.1 MPa/554°C (763,846 lb/hr, 452 psig/1,029°F) Main steam

- 345,876 kg/hr, 12.4 MPa/548°C (762,527 lb/hr, 1,800 psig/1,019°F)

Reheat steam

- 342,768 kg/hr, 3.1 MPa/548°C (755,673 lb/hr, 452 psig/1,019°F) Main steam

- 342,439 kg/hr, 12.4 MPa/544°C (754,948 lb/hr, 1,800 psig/1,011°F)

Reheat steam

- 346,896 kg/hr, 3.1 MPa/544°C (764,776 lb/hr, 452 psig/1,011°F) Main steam

- 338,862 kg/hr, 12.4 MPa/539°C (747,063 lb/hr, 1,800 psig/1,002°F)

Reheat steam

- 350,486 kg/hr, 3.1 MPa/539°C (772,688 lb/hr, 452 psig/1,002°F) 2 (0)



### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

1 Steam Turbine Commercially

available advanced

steam turbine 295 MW 12.4 MPa/554°C/554°C (1,800 psig/ 1029°F/1029°F) 292 MW 12.4 MPa/548°C/548°C (1,800 psig/ 1019°F/1019°F) 290 MW 12.4 MPa/544°C/544°C (1,800 psig/

1011°F/1 011°F) 286 MW 12.4 MPa/539°C/539°C (1,800 psig/ 1002°F/1002°F) 1 (0)

2 Steam Turbine

Generator Hydrogen cooled,

static excitation 330 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 320 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 320 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 320 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design

steam conditions 50% steam flow @ design

steam conditions 50% steam flow @ design

steam conditions 50% steam flow @ design

steam conditions 2 (0)

4 Surface

Condenser Single pass, divided

waterbox including

vacuum pumps 1,783 GJ/hr (1,690 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise

11°C (20°F) 1,772 GJ/hr (1,680 MMBtu/hr),

Inlet water temperature 16°C (60°F), Water temperature rise

11°C (20°F) 1,751 GJ/hr (1,660 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise

11°C (20°F) 1,720 GJ/hr (1,630 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise

11°C (20°F) 1 (0)



### ACCOUNT 9 COOLING WATER SYSTEM

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

1 Circulating Water Pumps Vertical, wet pit 416,395 lpm @ 30 m (110,000 gpm @ 100 ft) 431,537 lpm @ 30 m (114,000 gpm @ 100 ft) 442,893 lpm @ 30 m (117,000 gpm @ 100 ft) 450,464 lpm @ 30 m (119,000 gpm @ 100 ft) 2 (1)

2 Cooling Tower Evaporative,
mechanical draft,

multi

- cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,332 GJ/hr (2,210 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,416 GJ/hr (2,290 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,469 GJ/hr (2,340 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,522 GJ/hr (2,390 MMBtu/hr) heat duty 1 (0)



### ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

1 Slag Quench Tank Water bath 242,266 liters (64,000 gal) 246,052 liters (65,000 gal) 249,837 liters (66,000 gal) 249,837 liters (66,000 gal) 2 (0)

2 Slag Crusher Roll 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 2 (0)

3 Slag Depressurizer Lock Hopper 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 2 (0)

4 Slag Receiving Tank Horizontal, weir 143,846 liters (38,000 gal) 147,631 liters (39,000 gal) 151,416 liters (40,000 gal) 151,416 liters (40,000 gal) 2 (0)

5 Black Water Overflow

Tank Shop fabricated 64,352 liters (17,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)Carbon Dioxide Capture Sensitivity Analysis



### 300 Equipment

No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 2 (0)

7 Slag Separation

Screen Vibrating 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 2 (0)

8 Coarse Slag

Conveyor Belt/bucket 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 2 (0)

9 Fine Ash Settling

Tank Vertical, gravity 208,198 liters (55,000 gal) 208,198 liters (55,000 gal) 211,983 liters (56,000 gal) 215,768 liters (57,000 gal) 2 (0)

10 Fine Ash Recycle

Pumps Horizontal centrifugal 38 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 38 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 38 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 38 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 2 (2)

11 Grey Water Storage

Tank Field erected 64,352 liters (17,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H 2 O (60 gpm @ 1,850 ft H 2 O) 227 lpm @ 564 m H 2 O (60 gpm @ 1,850 ft H 2 O) 227 lpm @ 564 m H 2 O (60 gpm @ 1,850 ft H 2 O) 227 lpm @ 564 m H 2 O (60 gpm @ 1,850 ft H 2 O) 2 (2)

13 Slag Storage Bin Vertical, field erected 907 tonne (1,000 tons) 907 tonne (1,000 tons) 907 tonne (1,000 tons) 907 tonne (1,000 tons) 2 (0)

14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 1 (0)



### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

1 CTG Step

- up
Transformer Oil

- filled 24 kV/345 kV, 260 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 260 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 260 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 260 MVA,

3

- ph, 60 Hz 2 (0)

2 STG Step

- up

Transformer Oil

- filled 24 kV/345 kV, 330 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 320 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 320 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 320 MVA,

3

- ph, 60 Hz 1 (0)

3 High Voltage Auxiliary

Transformer Oil

- filled 345 kV/13.8 kV, 63 MVA,

3

- ph, 60 Hz 345 kV/13.8 kV, 68 MVA,

3

- ph, 60 Hz 345 kV/13.8 kV, 72 MVA,

3

- ph, 60 Hz 345 kV/13.8 kV, 76 MVA,

3

- ph, 60 Hz 2 (0)

4 Medium Voltage

Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 30 MVA,

3

- ph, 60 Hz 24 kV/4.16 kV, 34 MVA,

3

- ph, 60 Hz 24 kV/4.16 kV, 38 MVA,

3

- ph, 60 Hz 24 kV/4.16 kV, 43 MVA,

3

- ph, 60 Hz 1 (1)

5 Low Voltage

Transformer Dry ventilated 4.16 kV/480 V, 4 MVA,

3

- ph, 60 Hz 4.16 kV/480 V, 5 MVA,

3

- ph, 60 Hz 4.16 kV/480 V, 6 MVA,

3

- ph, 60 Hz 4.16 kV/480 V, 6 MVA,

3

- ph, 60 Hz 1 (1)

6 CTG Isolated Phase

Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 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 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 1 (0)

8 Medium Voltage

Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 1 (1)

9 Low Voltage

Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 1 (1)

10 Emergency Diesel

Generator Sized for emergency

shutdown 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 1 (0)Carbon Dioxide Capture Sensitivity Analysis



### 301 ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

1 DCS

- Main

Control Monitor/keyboard;

Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers Operator stations/printers and engineering stations/printers Operator stations/printers and engineering stations/printers Operator stations/printers and

en gineering stations/printers 1 (0)

2 DCS

-

Processor Microprocessor with

redundant input/output N/A N/A N/A N/A 1 (0)

3 DCS

- Data

Highway Fiber optic Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare 1 (0)Carbon Dioxide Capture Sensitivity Analysis



### 302 This page intentionally left blankCarbon Dioxide Capture Sensitivity Analysis



### 303 

## 4.3.3 IGCC Design 3

– Two Water Gas Shift Reactors with Bypass

A proces s block flow diagram for Case 2 Design 3 (D3) is shown in Exhibit 4

- 68 . D3 represents an IGCC plant with two WGS reactors and a bypass stream (stream 13). This IGCC design uses

a S:DG molar ratio of 0.25 at the outlet of the second WGS reactor. The WGS bypa ss ratio and

the two

- stage SelexolTM CO 2 

### removal efficiency are adjusted to control the total CO 2 

### capture

level. The SelexolTM removal efficiency is altered by varying the solvent circulation rate, which changes the size and cost of the SelexolTM system.

The WGS bypass impacts the degree of CO to CO 2 

### and COS to H 2 

### S conversion across the WGS reactor. Consequently, the WGS bypass stream is routed through a COS h ydolysis unit to ensure

that sulfur emissions are below the limit of 0.0128 lb SO 2 

### /MMBtu.

Fi ve levels of total CO 2 

### removal were modeled for Case 2 D3: 25 percent (D3A), 45 percent (D3B), 60 percent (D3C), 75 percent (D3D), and 85 percent (D3E). The corresponding stream

tables are contained in Exhibit 4

- 69

, Exhibit 4

- 70

, Exhibit 4

- 71

, Exhibit 4

- 72 , and Exhibit 4

- 73

, respectively.

Overall performance for Case 2 D3 is summarized in Exhibit 4

- 74 which includes auxiliary power requirements.

Material and energy balance information, environmental performance and a major e quipment list

are summarized in Sections 4.3.3.1 and 4.3.3.2

.Carbon Dioxide Capture Sensitivity Analysis



### 304 Exhibit 4

- 68 Case 2 D3 Process Block Flow Diagram, IGCC with Two WGS Reactors and BypassCarbon Dioxide Capture Sensitivity Analysis



### 305 Exhibit 4

- 69 Case 2 D3A Stream Table, 25% CO 2 Removal with Two WGS BypassCarbon Dioxide Capture Sensitivity Analysis



### 306 Exhibit 4

- 69 Case 2 D3A Stream Table, 25% CO 2 Removal with Two WGS Bypass (continued)Carbon Dioxide Capture Sensitivity Analysis



### 307 Exhibit 4

- 70 Case 2 D3B Stream Table, 45% CO 2 Capture with Two WGS BypassCarbon Dioxide Capture Sensitivity Analysis



### 308 Exhibit 4

- 70 Case 2 D3B Stream Table, 45% CO 2 Capture with Two WGS Bypass (continued)Carbon Dioxide Capture Sensitivity Analysis



### 309 Exhibit 4

- 71 Case 2 D3C Stream Table, 60% CO 2 Capture with Two WGS BypassCarbon Dioxide Capture Sensitivity Analysis



### 310 Exhibit 4

- 71 Case 2 D3C Stream Table, 60% CO2 Capture with Two WGS Bypass (continued)Carbon Dioxide Capture Sensitivity Analysis



### 311 Exhibit 4

- 72 Case 2 D3D Stream Table, 75% CO 2 Capture with Two WG S BypassCarbon Dioxide Capture Sensitivity Analysis



### 312 Exhibit 4

- 72 Case 2 D3D Stream Table, 75% CO 2 Capture with Two WGS Bypass (continued)Carbon Dioxide Capture Sensitivity Analysis



### 313 Exhibit 4

- 73 Case 2 D3E Stream Table, 85% CO 2 Capture with Two WGS BypassCarbon Dioxide Capture Sensitivity Analysis



### 314 Case 2 D3E Stream Table, 85% CO 2 Capture with Two WGS Bypass (continued)Carbon Dioxide Capture Sensitivity Analysis



### 315 Exhibit 4

- 74 Case 2 D3 Performance Modeling Results

POWER SUMMARY (Gross Power at Generator Terminals, kWe) D3 A (25%) D 3 B

(45%) D 3 C

(60%) D3D

(75%) D 3E

( 8 5%)

Gas Turbine Power 464,000 464,000 464,000 464,000 464,000

Sweet Gas Expander Power 5,800 5,900 6, 1 00 6, 2 00 6, 3 00

Steam Turbine Power 280,600 276, 3 00 274, 1 00 271,400 269,500

Total 750,400 746, 2 00 744, 2 00 741, 6 00 739,800

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 4 57 460 46 3 4 66 4 68

Coal Milling 2,1 59 2,19 2 2,220 2,2 4 7 2,2 6 6

Sour Water Recycle Slurry Pump 18 1 18 3 1 85 1 87 1 88

Slag Handling 1,1 06 1,12 2 1,1 37 1,15 1 1,16 1

Air Separation Unit Auxiliaries 1,000 1,000 1,000 1,000 1,000

Air Separation Unit Main Air Compressor 64,0 15 64,998 65,8 39 66,6 36 67, 188

Oxygen Compressor 10, 1 6 5 10,32 0 10, 398 10,5 28 10,6 1 6

Nitrogen Compressors 31,4 21 32,1 22 33,1 2 0 34,1 81 34,90 5

CO 2 Compressor 8,4 9 2 15,0 38 20,2 75 25,6 16 29,2 6 1

Boiler Feedwater Pumps 3,9 6 8 4,0 0 9 4,05 3 4, 096 4,1 25

Condensate Pump 2 49 2 59 26 4 2 69 27 3

Quench Water Pump 5 1 3 5 19 52 4 5 29 53 3

Circulating Water Pump 4, 1 65 4,3 2 0 4,4 28 4,5 36 4,6 06

Ground Water Pumps 4 25 4 5 6 480 50 4 520

Cooling Tower Fans 2,1 5 3 2,2 3 3 2,29 0 2,34 4 2,38 1

Scrubber Pumps 2 1 2 2 16 2 18 220 22 3

Acid Gas Removal 4,8 5 8 8,9 0 7 12,11 2 15,4 2 5 17,6 76

Gas Turbine Auxiliaries 1,000 1,000 1,000 1,000 1,000

Steam Turbine Auxiliaries 100 100 100 100 100

Claus Plant/TGTU Auxiliaries 250 250 250 250 250

Claus Plant TG Recycle Compressor 8 28 7 58 70 1 77 2 8 19

Miscellaneous Balance of Plant 1 3,000 3,000 3,000 3,000 3,000

Transformer Losses 2,6 6 5 2,69 1 2,7 1 7 2,74 1 2,7 5 7

TOTAL AUXILIARIES, kWe 143,382 156,153 166,774 177,798 185,316

NET POWER, kWe 607,018 590, 047 577, 4 26 563,802 554, 484

Net Plant Efficiency, % (HHV) 38. 4 % 36.7% 35. 5 % 34.2% 33. 4 %

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9, 3 8 4 (8, 894 ) 9, 801 (9,28 9 ) 10,14 3 (9,61 4 ) 10,51 8 (9,96 9 ) 10,78 4 (10,2 22 )

Condenser Duty, GJ/hr (10 6 Btu/hr) 1, 625 (1, 54 0) 1,614 (1,530) 1,593 (1,510) 1,572 (1,490) 1,551 (1,470)

CONSUMABLES

As

- Received Coal Feed, kg/hr

(lb/hr) 209,9 15 ( 462, 783 ) 213,1 18

(469, 844 ) 215,8 50

(475, 867 ) 218,5 31

(481, 779 ) 220, 372

(485, 836 )

Thermal Input, kW th 2 1, 582, 239 1,606, 380 1,62 6,975 1,647, 185 1,661, 057

Raw Water Withdrawal, m 3 /min (gpm) 17. 8 (4, 695 ) 19.1 (5,04 0 ) 20.1 (5,30 7 ) 21.1 (5,5 69 ) 21.8 (5,74 8 )

Raw Water Consumption, m 3 /min (gpm) 14. 1 (3,7 2 5 ) 15.3 (4,0 34 ) 16.2 (4,27 6 ) 17.1 (4,51 4 ) 17.7 (4,67 7 )

Notes: 1. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

2. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)Carbon Dioxide Capture Sensitivity Analysis



### 316 4.3.3.1 Environmental Performance for Case 2 D3

The environmental targets for emissions of Hg, NO

x 

### , SO 2 

### , and particulate matter were presented

in Section 2.4 . A summary of the p lant air emissions for Case 2 D3A, D3 B , D3C, D3D, and

D3E is presented in Exhibit 4

- 75

.

For Case 2 D3, SO 2 

### emissions are controlled by sulfur capture across the two

- stage SelexolTM
unit. The clean syngas exiting the AGR unit has a sulfur concentration of about 10 ppmv, resulting in a concentration in the flue gas of less than 2 ppmv. The H 2 

### S

- rich regeneration gas produced in Case 2 D3 is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H 2 

### S and then recycled back to the SelexolTM
unit, thereby eliminating the need for a tail gas treatmen t unit.

NOx emissions are limited by nitrogen dilution of the syngas to 15 ppmvd (as NO 2 

### @ 15 percent

O 2 

### ). Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process, and ultimately incinerated in the Claus plant burner. This also assists in lowering

NOx levels.

Particulate discharge to the atmosphere is limited to extremely low values by the use of the syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particul ate emissions represent filterable particulate only.

Ninety

- five percent of the mercury is captured from the syngas by an activated carbon bed.

For Case 2 D3, varying levels of the CO 2 

### [25 percent (D3A), 45 percent (D3B), 60 percent (D3C), 75 percent (D3 D), and 85 percent (D3E)] in the syngas are captured in the two

- stage SelexolTM unit and compressed for sequestration. The carbon balance for Case 2 D3 is shown in

Exhibit 4

- 76 . The carbon input to the plant consists of carbon in the air and coal. Carbon in the

air is not n eglected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the sla g, as dissolved CO 2 

### in the wastewater blowdown

stream, and as CO 2 

### in the stack gas, ASU vent gas, and the captured CO 2 

### product. Carbon in the wastewater blowdown stream is calculated by difference to close the material balance. The carbon capture efficie ncy is defined as the pounds of carbon in the CO 2 

### product stream relative

to the amount of carbon in the coal

, less carbon contained in the slag , represented by the following fraction:

(Carbon in CO 2 

### Product)/[(Carbon in the Coal)

- (Carbon in Slag)] or

72,992/(295,000

- 5,900)*100=25.2% (D3A)

131,7 28 /(299,5 01

- 5,99 0 )*100=44.9% (D3B)

178,2 10 /(303, 340

- 6,06 7 )*100=59.9% (D 3 C)

225,6 30 /(307,1 08

- 6,14 2 )*100=75.0% (D3D)

257,847 /( 309,695

- 6,1 94 )*100= 8 5.0% (D3 E )

Exhibit 4

- 77 shows the sulf ur balance for Case 2 D3 . Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the pounds of sulfur recovered in the Claus plant, dissolved

SO 2 

### in the w astewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible, and the sulfur content of the blowdown stream is calculated byCarbon Dioxide Capture Sensitivity Analysis



### 317 difference to close the material balance. The total sulfur capture is repres ented by the following

fraction:

(Sulfur byproduct/Sulfur in the coal) or
(11, 581 /11, 599 )*100 = 99.8 % (D3 A)
(11,75 4 /11,77 6 )*100 = 99.8% (D3B)
(11,90 2 /11,9 27 )*100 = 99.8% (D3C)
(12,0 47 /12,07 5 )*100 = 99.8% (D3D)
(12, 146 /12, 177 )*100 = 99.8% (D3 E )

The overall water balance s for Case 2 D3A, D3B, D3C, D3D, and D3E are shown in

Exhibit 4

- 78

, Exhibit 4

- 79

, Exhibit 4

- 80

, Exhibit 4

- 81 , and Exhibit 4

- 82 , respectively. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the total amount of water required for a particular process. Some wa ter

is recovered within t he process and that water is re used as internal recycle. Raw water

withdrawal is the difference between water demand and internal recycle. Process water discharged from the power plant is also account ed for in this study. Raw wa ter consumption represents raw water withdrawal less process water discharge.

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 4

- 83 through

Exhibit 4

- 97

.

Gasifier and ASU

Syngas Cleanup

Power Block

An overall plant energy balance for Case D3A, D3B, D3C, D3D, and D3E is provided in tabular

form in Exhibit 4

- 98

, Exhibit 4

- 99

, Exhibit 4

- 100

, Exhibit 4

- 101 , and Exhibit 4

- 102

, respectively. The power out is the combined combustion turbine, steam turbine and expander power after generator losses. In addition, energy balance Sankey diagrams are provided for

D3A, D3B, D3C, D3D, and D3E in Exhibit 4

- 103

, Exhibit 4

- 104

, Exhibit 4

- 105

, Exhibit 4

- 106

, and Exhibit 4

- 107 , respectively

.Carbon Dioxide Capture Sensitivity Analysis



### 318 Exhibit 4

- 75 Case 2 D3 Estimated Air Emission Rates

kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)

D3A D3B D3C D3A D3B D3C D3A D3B D3C

SO 2 0. 001 (0.0 02 ) 0. 001 (0.0 02 ) 0. 001 (0.0 02 ) 37 (40) 37 (41) 38 (42) 0.007 (0.020) 0.007 (0.020) 0.007 (0.020)

NO X 0.0 24 (0.0 55 ) 0.0 23 (0.0 53 ) 0.0 22 (0.0 52 ) 947 (1,044) 927 (1,022) 910 (1,003) 0.180 (0.397) 0.177 (0.391) 0.174 (0.385)

PM 0.00 3 (0.0 071 ) 0.00 3 (0.0 071 ) 0.00 3 (0.0 071 ) 122 (134) 124 (136) 125 (138) 0.023 (0.051) 0.024 (0.052) 0.024 (0.053)

Hg 0. 246 x10 - 6

( 0.571 x10 - 6 ) 0. 246 x10 - 6

( 0.571 x10 - 6 ) 0. 246 x10 - 6

( 0.571 x10 - 6 ) 0.010 (0.011) 0.010 (0.011) 0.010 (0.011) 1.87 x10 - 6

( 4.11 x10 - 6 ) 1.90 x10 - 6

( 4.20 x10 - 6 ) 1.93 x10 - 6

( 4.26 x10 - 6 )

CO 2 63. 3 (147. 3 ) 46.8 (108.8) 34.1 (79.2) 2,5 28, 207 (2, 78 6,871) 1,895, 466

(2,089, 393 ) 1,39 7,892

(1,54 0,913 ) 48 1 (1,06 0 ) 362 (799) 268 (591)

CO 2 net 59 4 (1,31 0 ) 458 (1,01 1 ) 345 (762)

Exhibit 4

- 75 Case 2 D3 Estimated Air Emission Rates (continued)

kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)

D3D D3E D3D D3E D3D D3E

SO 2 0. 001

(0.0 02 ) 0. 001

(0.0 02 ) 38 (42) 39 (42) 0.007 (0.020) 0.007 (0.020)

NO X 0.0 21

(0.0 50 ) 0.0 21

(0.0 49 ) 893 (985) 882 (972) 0.172 (0.379) 0.170 (0.375)

PM 0.00 3

(0.0 071 ) 0.00 3

(0.0 071 ) 127 (140) 128 (141) 0.024 (0.054) 0.025 (0.054)

Hg 0. 246 x10 - 6

( 0.571 x10 - 6 ) 0. 246 x10 - 6

( 0.571 x10 - 6 ) 0.010 (0.011) 0.010 (0.011) 1.96 x10 - 6

( 4.33 x10 - 6 ) 1.99 x10 - 6

( 4.38 x10 - 6 )

CO 2 21.4 (49.7) 13.0 (30.1) 888, 578 (979, 489 ) 542, 862

(598, 402 ) 171 (377) 105 (231)

CO 2 net 225 (496) 140 (308)Carbon Dioxide Capture Sensitivity Analysis



### 319 Exhibit 4

- 76 Case 2 D3 Carbon Balance

Carbon In, kg/hr (lb/hr)

D3A D3B D3C D3D D3E

Coal 133,8 10

(295, 000 ) 135,8 51

(299,5 01 ) 137, 593

(303, 340 ) 139,3 02

(307,1 08 ) 140, 475

(309, 695 )

Air (CO 2 ) 535

(1,179) 536

(1,182) 538

(1,185) 539 (1,188) 540 (1,190)

Total 13 4,3 45

(29 6, 179 ) 136, 387

(300, 683 ) 138,1 31

(304,5 25 ) 139,8 41

(308, 296 ) 141,0 15

(310, 885 )
Carbon Out, kg/hr (lb/hr)

Slag 2,67 6

(5,90 0 ) 2,71 7

(5,99 0 ) 2,752

(6,06 7 ) 2,78 6

(6,14 2 ) 2,810

(6,19 4 )

Stack Gas 98, 4 57

(217, 061 ) 73,8 16

(162,7 37 ) 54,4 39

(120,017 ) 34,6 04

(76, 290 ) 21,14 1

(46,6 08 )

ASU Vent 102 (225) 104 (229) 105 (23 1 ) 106 (234) 107 (236)

CO 2 Product 33,1 09

( 7 2,992 ) 59,7 51

(131,7 28 ) 80,8 35

(178,2 10 ) 102,3 44

(225,6 30 ) 116,9 57

(257, 847 )
Convergence

Tolerance 1 ( 1)

- 1 (

- 1 ) 0 ( 0 ) 1 (0) 0 (0)

Total 13 4,345

(29 6,179 ) 136,387

(300,683) 138,131

(304,525) 139,841

(308,296) 141,015

(310,885)

Exhibit 4

- 77 Case 2 D3 Sulfur Balance

Sulfur In, kg/hr (lb/hr)

D3A D3B D3C D3D D3E

Coal 5,26 1 (11, 599 ) 5,34 2

(11,77 6 ) 5,41 0

(11,9 27 ) 5,47 7

(12,07 5 ) 5,52 3

(12,1 77 )

Total 5, 26 1 (11, 599 ) 5,34 2

(11,77 6 ) 5,41 0

(11,9 27 ) 5,47 7

(12,07 5 ) 5,52 3

(12,1 77 )
Sulfur Out, kg/hr (lb/hr)

Elemental Sulfur 5,25 3 (11,58 1 ) 5,33 2

(11,75 4 ) 5, 399

(11,90 2 ) 5,46 4

(12,0 47 ) 5,5 09

(12,14 6 )

Stack Gas 3 (6) 3 (6) 3 (6) 3 (6) 3 (6)

CO 2 Product 6 ( 12 ) 7 (16) 9 (19) 10 (22) 11 (25)

Convergence

Tolerance - 1 (0) 0 (0)

- 1 ( 0 ) 0 (0) 0 (0)

Total 5, 261 (11, 599 ) 5,34 2

(11,77 6 ) 5,41 0

(11,9 27 ) 5,47 7

(12,07 5 ) 5,52 3

(12,1 77 )Carbon Dioxide Capture Sensitivity Analysis



### 320 Exhibit 4

- 78 Case 2 D3A (25%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Slag Handling 0.50 (132) 0.50 (132) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.7 (719) 0.87 (231) 1.8 (488) 0.0 (0) 1.8 (488)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7)

Condenser Makeup 0.2 (55) 0.0 (0) 0.2 (55) 0.0 (0) 0.2 (55)

Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

Shift Steam 0.0 (0) 0.0 (0) 0.0 (0)

C T Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 16.2 (4,282) 0.49 (129) 15.7 (4,152) 3.6 (963) 12.1 (3,190)

BFW Blowdown 0.0 (0) 0.21 (55)

- 0.21 (

- 55)

SWS Blowdown 0.0 (0) 0.28 (74)

- 0.28 (

- 74)

SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 21.1 (5,568) 3.30 (872) 17.8 (4,695) 3.7 (970) 14.1 (3,725)

Total, gal/MWh net 550 86 464 96 368Carbon Dioxide Capture Sensitivity Analysis



### 321 Exhibit 4

- 79 Case 2 D3B (45%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Slag Handling 0.51 (134) 0.51 (134) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.8 (730) 0.72 (191) 2.0 (538) 0.0 (0) 2.0 (538)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7)

Condenser Makeup 0.7 (187) 0.0 (0) 0.7 (187) 0.0 (0) 0.7 (187)

Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

Shift Steam 0.5 (132) 0.0 (0) 0.5 (132)

C T Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 16.8 (4,441) 0.48 (127) 16.3 (4,314) 3.8 (999) 12.6 (3,316)

BFW Blowdown 0.0 (0) 0.21 (55)

- 0.21 (

- 55)

SWS Blowdown 0.0 (0) 0.27 (71)

- 0.27 (

- 71)

SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 22.3 (5,878) 3.17 (838) 19.1 (5,040) 3.8 (1,006) 15.3 (4,034)

Total, gal/MWh net 598 85 513 102 410Carbon Dioxide Capture Sensitivity Analysis



### 322 Exhibit 4

- 80 Case 2 D3C (60%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Slag Handling 0.51 (136) 0.51 (136) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.8 (739) 0.60 (157) 2.2 (582) 0.0 (0) 2.2 (582)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7)

Condenser Makeup 1.1 (294) 0.0 (0) 1.1 (294) 0.0 (0) 1.1 (294)

Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

Shift Steam 0.9 (239) 0.0 (0) 0.9 (239)

C T Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 17.2 (4,555) 0.47 (124) 16.8 (4,431) 3.9 (1,024) 12.9 (3,407)

BFW Blowdown 0.0 (0) 0.21 (55)

- 0.21 (

- 55)

SWS Blowdown 0.0 (0) 0.26 (68)

- 0.26 (

- 68)

SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 23.1 (6,115) 3.06 (808) 20.1 (5,307) 3.9 (1,031) 16.2 (4,276)

Total, gal/MWh net 635 84 551 107 444Carbon Dioxide Capture Sensitivity Analysis



### 323 Exhibit 4

- 81 Case 2 D3D (75%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Slag Handling 0.52 (137) 0.52 (137) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.8 (748) 0.47 (123) 2.4 (625) 0.0 (0) 2.4 (625)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.02 (7)

- 0.02 (

- 7)

Condenser Makeup 1.5 (402) 0.0 (0) 1.5 (402) 0.0 (0) 1.5 (402)

Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

Shift Steam 1.3 (347) 0.0 (0) 1.3 (347)

C T Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 17.7 (4,663) 0.46 (121) 17.2 (4,542) 4.0 (1,049) 13.2 (3,494)

BFW Blowdown 0.0 (0) 0.21 (55)

- 0.21 (

- 55)

SWS Blowdown 0.0 (0) 0.25 (66)

- 0.25 (

- 66)

SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 24.0 (6,347) 2.94 (777) 21.1 (5,569) 4.0 (1,055) 17.1 (4,514)

Total, gal/MWh net 675 83 593 112 480Carbon Dioxide Capture Sensitivity Analysis



### 324 Exhibit 4

- 82 Case 2 D3E (85%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Slag Handling 0.52 (138) 0.52 (138) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.9 (755) 0.38 (99) 2.5 (655) 0.0 (0) 2.5 (655)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.02 (6)

- 0.02 (

- 6)

Condenser Makeup 1.8 (475) 0.0 (0) 1.8 (475) 0.0 (0) 1.8 (475)

Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

Shift Steam 1.6 (420) 0.0 (0) 1.6 (420)

C T Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

BFW Makeup 0.21 (55) 0.0 (0) 0.21 (55)

Cooling Tower 17.9 (4,736) 0.45 (119) 17.5 (4,618) 4.0 (1,065) 13.4 (3,553)

BFW Blowdown 0.0 (0) 0.21 (55)

- 0.21 (

- 55)

SWS Blowdown 0.0 (0) 0.24 (64)

- 0.24 (

- 64)

SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 24.6 (6,504) 2.86 (756) 21.8 (5,748) 4.1 (1,072) 17.7 (4,677)

Total, gal/MWh net 704 82 622 116 506Carbon Dioxide Capture Sensitivity Analysis



### 325 Exhibit 4

- 83 Case 2 D3A (25%) Heat and Mass Balance, GEE Gasifier and ASUCarbon Dioxide Capture Sensitivity Analysis



### 326 Exhibit 4

- 84 Case 2 D3A (25%) Heat and Mass Balance, Syngas CleanupCarbon Dioxide Capture Sensitivity Analysis



### 327 Exhibit 4

- 85 Case 2 D3A (25%) Heat and Mass Balance, Power BlockCarbon Dioxide Capture Sensitivity Analysis



### 328 Exhibit 4

- 86 Case 2 D3B (45%) Heat and Mass Balance, GEE Gasifier and ASUCarbon Dioxide Capture Sensitivity Analysis



### 329 Exhibit 4

- 87 Case 2 D3B (45%) Heat and Mass Balance, Syngas CleanupCarbon Dioxide Capture Sensitivity Analysis



### 330 Exhibit 4

- 88 Case 2 D3B (45%) Heat and Mass Balance, Power BlockCarbon Dioxide Capture Sensitivity Analysis



### 331 Exhibit 4

- 89 Case 2 D3C (60%) Heat and Mass Balance, GEE Gasifier and ASUCarbon Dioxide Capture Sensitivity Analysis



### 332 Exhibit 4

- 90 Case 2 D3C (60%) Heat and Mass Balance, Syngas CleanupCarbon Dioxide Capture Sensitivity Analysis



### 333 Exhibit 4

- 91 Case 2 D3C (60%) Heat and Mass Balance, Power BlockCarbon Dioxide Capture Sensitivity Analysis



### 334 Exhibit 4

- 92 Case 2 D3D (75%) Heat and Mass Balance, GEE Gasifier and ASUCarbon Dioxide Capture Sensitivity Analysis



### 335 Exhibit 4

- 93 Case 2 D3D (75%) Heat and Mass Balance, Syngas CleanupCarbon Dioxide Capture Sensitivity Analysis



### 336 Exhibit 4

- 94 Case 2 D3D (75%) Heat and Mass Balance, Power BlockCarbon Dioxide Capture Sensitivity Analysis



### 337 Exhibit 4

- 95 Case 2 D3E (85%) Heat and Mass Balance, GEE Gasifier and ASUCarbon Dioxide Capture Sensitivity Analysis



### 338 Exhibit 4

- 96 Case 2 D3E (85%) Heat and Mass Balance, Syngas CleanupCarbon Dioxide Capture Sensitivity Analysis



### 339 Exhibit 4

- 97 Case 2 D3E (85%) Heat and Mass Balance, Power BlockCarbon Dioxide Capture Sensitivity Analysis



### 340 This page intentionally left blankCarbon Dioxide Capture Sensitivity Analysis



### 341 Exhibit 4

- 98 Case 2 D3A (25%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,696 (5,399) 4.8 (4.5) 0 (0) 5,701 (5,403)

ASU Air 0 (0) 22.7 (21.5) 0 (0) 23 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 66.8 (63.3) 0 (0) 67 (63)

Totals 5,696 (5,399) 190.5 (180.5) 0 (0) 5,887 (5,579)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.9 (1.8) 0 (0) 2 (2)

Slag 88 (83) 36.0 (34.1) 0 (0) 124 (117)

Sulfur 49 (46) 0.6 (0.6) 0 (0) 49 (47)

CO 2 0 (0)

- 13.0 (

- 12.4) 0 (0)

- 13 (

- 12)

Gasifier Heat Loss 0 (0) 42.4 (40.2) 0 (0) 42 (40)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 937 (888) 0 (0) 937 (888)

Cooling Tower* 0 (0) 2,073 (1,965) 0 (0) 2,073 (1,965)

Process Losses* * 0 (0) 424 (402) 0 (0) 424 (402)

Net Power 0 (0) 0.0 (0.0) 2,185 (2,071) 2,185

(2,071)

Totals 136 (129) 3,565 (3,379) 2,185 (2,071) 5,887

(5,579)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

air cooler. ** Calculated by difference to close the energy balance.Carbon Dioxide Capture Sensitivity Analysis



### 342 Exhibit 4

- 99 Case 2 D3B (45%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,783 (5,481) 4.8 (4.6) 0 (0) 5,788 (5,486)

ASU Air 0 (0) 23.0 (21.8) 0 (0) 23 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 71.7 (68.0) 0 (0) 72 (68)

Totals 5,783 (5,481) 195.8 (185.6) 0 (0) 5,979 (5,667)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.8 (1.7) 0 (0) 2 (2)

Slag 89 (84) 36.5 (34.6) 0 (0) 126 (119)

Sulfur 49 (47) 0.6 (0.6) 0 (0) 50 (47)

CO 2 0 (0)

- 31.7 (

- 30.0) 0 (0)

- 32 (

- 30)

Gasifier Heat Loss 0 (0) 43.1 (40.8) 0 (0) 43 (41)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,048 (994) 0 (0) 1,048 (994)

Cooling Tower* 0 (0) 2,115 (2,005) 0 (0) 2,115 (2,005)

Process Losses* * 0 (0) 439 (416) 0 (0) 439 (416)

Net Power 0 (0) 0.0 (0.0) 2,124 (2,013) 2,124

(2,013)

Totals 138 (131) 3,716 (3,522) 2,124 (2,013) 5,979

(5,667)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

air cooler. ** Calculated by difference to close the energy balance.Carbon Dioxide Capture Sensitivity Analysis



### 343 Exhibit 4

- 100 Case 2 D3C (60%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,857 (5,551) 4.9 (4.6) 0 (0) 5,862 (5,556)

ASU Air 0 (0) 23.3 (22.1) 0 (0) 23 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 75.5 (71.6) 0 (0) 76 (72)

Totals 5,857 (5,551) 199.9 (189.5) 0 (0) 6,057 (5,741)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.8 (1.7) 0 (0) 2 (2)

Slag 90 (86) 37.0 (35.0) 0 (0) 127 (121)

Sulfur 50 (47) 0.6 (0.6) 0 (0) 51 (48)

CO 2 0 (0)

- 45.7 (

- 43.3) 0 (0)

- 46 (

- 43)

Gasifier Heat Loss 0 (0) 43.6 (41.3) 0 (0) 44 (41)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,140 (1,080) 0 (0) 1,140 (1,080)

Cooling Tower* 0 (0) 2,143 (2,031) 0 (0) 2,143 (2,031)

Process Losses* * 0 (0) 455 (431) 0 (0) 455 (431)

Net Power 0 (0) 0.0 (0.0) 2,079 (1,970) 2,079

(1,970)

Totals 140 (133) 3,838 (3,638) 2,079 (1,970) 6,057

(5,741)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

air cooler. ** Calculated by difference to close the energy balance.Carbon Dioxide Capture Sensitivity Analysis



### 344 Exhibit 4

- 101 Case 2 D3D (75%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,930 (5,620) 5.0 (4.7) 0 (0) 5,935 (5,625)

ASU Air 0 (0) 23.6 (22.4) 0 (0) 24 (22)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 79.3 (75.1) 0 (0) 79 (75)

Totals 5,930 (5,620) 204.0 (193.4) 0 (0) 6,134 (5,814)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.8 (1.7) 0 (0) 2 (2)

Slag 91 (87) 37.4 (35.5) 0 (0) 129 (122)

Sulfur 51 (48) 0.6 (0.6) 0 (0) 51 (49)

CO 2 0 (0)

- 59.7 (

- 56.6) 0 (0)

- 60 (

- 57)

Gasifier Heat Loss 0 (0) 44.1 (41.8) 0 (0) 44 (42)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,232 (1,168) 0 (0) 1,232 (1,168)

Cooling Tower* 0 (0) 2,167 (2,054) 0 (0) 2,167 (2,054)

Process Losses* * 0 (0) 476 (451) 0 (0) 476 (451)

Net Power 0 (0) 0.0 (0.0) 2,030 (1,924) 2,030

(1,924)

Totals 142 (135) 3,962 (3,755) 2,030 (1,924) 6,134

(5,814)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

air cooler. ** Calculated by difference to close the energy balance.Carbon Dioxide Capture Sensitivity Analysis



### 345 Exhibit 4

- 102 Case 2 D3E (85%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,980 (5,668) 5.0 (4.7) 0 (0) 5,985 (5,673)

ASU Air 0 (0) 23.8 (22.6) 0 (0) 24 (23)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 81.8 (77.6) 0 (0) 82 (78)

Totals 5,980 (5,668) 206.8 (196.0) 0 (0) 6,187 (5,864)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.8 (1.8) 0 (0) 2 (2)

Slag 92 (87) 37.7 (35.8) 0 (0) 130 (123)

Sulfur 51 (48) 0.6 (0.6) 0 (0) 52 (49)

CO 2 0 (0)

- 69.2 (

- 65.6) 0 (0)

- 69 (

- 66)

Gasifier Heat Loss 0 (0) 44.5 (42.2) 0 (0) 45 (42)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,295 (1,228) 0 (0) 1,295 (1,228)

Cooling Tower* 0 (0) 2,183 (2,069) 0 (0) 2,183 (2,069)

Process Losses* * 0 (0) 490 (465) 0 (0) 490 (465)

Net Power 0 (0) 0.0 (0.0) 1,996 (1,892) 1,996

(1,892)

Totals 143 (136) 4,047 (3,836) 1,996 (1,892) 6,187

(5,864)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

air cooler. ** Calculated by difference to close the energy balance.Carbon Dioxide Capture Sensitivity Analysis



### 346 Exhibit 4

- 103 Case 2 D3A Energy Balanc e Sankey Diagram

Exhibit 4

- 104 Case 2 D3B Energy Balance Sankey DiagramCarbon Dioxide Capture Sensitivity Analysis



### 347 Exhibit 4

- 105 Case 2 D3C Energy Balance Sankey Diagram

Exhibit 4

- 106 Case 2 D3D Energy Balance Sankey DiagramCarbon Dioxide Capture Sensitivity Analysis



### 348 Exhibit 4

- 107 Case 2 D3E Energy Balance Sankey DiagramCarbon Dioxide Capture Sensitivity Analysis



### 349 4.3.3.2 Major Equipment List for Case 2 D3

Major equipment items for Case 2 D3 (two WGS with bypass) are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cos t estimates. In general, the design

conditions inclu de a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 COAL HANDLING

Equipment

No. Description Type Design Conditions Opr Qty. (Spares) D3A D3B D3C D3D D3E

1 Bottom Trestle Dumper and

Receiving Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0)

3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

4 Transfer Tower No. 1 Enclosed N/A N/A N/A N/A N/A 1 (0)

5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

6 As

- Received Coal Sampling

System Two

- stage N/A N/A N/A N/A N/A 1 (0)

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

8 Reclaim Hopper N/A 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 2 (1)

9 Feeder Vibratory 172 tonne/hr (190 tph) 172 tonne/hr (190 tph) 181 tonne/hr (200 tph) 181 tonne/hr (200 tph) 181 tonne/hr (200 tph) 2 (1)

10 Conveyor No. 3 Belt w/ tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0)

11 Crusher Tower N/A N/A N/A N/A N/A N/A 1 (0)

12 Coal Surge Bin w/ Vent

Filter Dual outlet 172 tonne (190 ton) 172 tonne (190 ton) 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

13 Crusher Impactor

reduction 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 2 (0)

14 As

- Fired Coal Sampling

System Swing hammer N/A N/A N/A N/A N/A 1 (1)

15 Conveyor No. 4 Belt w/tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0)

16 Transfer Tower No. 2 Enclosed N/A N/A N/A N/A N/A 1 (0)

17 Conveyor No. 5 Belt w/ tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0)

18 Coal Silo w/ Vent Filter and

Slide Gates Field erected 726 tonne (800 ton) 816 tonne (900 ton) 816 tonne (900 ton) 816 tonne (900 ton) 816 tonne (900 ton) 3 (0)



### ACCOUNT 2 COAL PREPARATION AND FEED

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D3A D3B D3C D3D D3E

1 Feeder Vibratory 73 tonne/h (80 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 3 (0)

2 Conveyor No. 6 Belt w/tripper 227 tonne/h (250 tph) 236 tonne/h (260 tph) 236 tonne/h (260 tph) 236 tonne/h (260 tph) 245 tonne/h (270 tph) 1 (0)

3 Rod Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 472 tonne (520 ton) 472 tonne (520 ton) 481 tonne (530 ton) 481 tonne (530 ton) 1 (0)

4 Weigh Feeder Belt 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)

5 Rod Mill Rotary 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)

6 Slurry Water Storage

Tank with Agitator Field erected 284,968 liters (75,280 gal) 289,321 liters (76,430 gal) 293,031 liters (77,410 gal) 296,665 liters (78,370 gal) 299,163 liters (79,030 gal) 2 (0)Carbon Dioxide Capture Sensitivity Analysis



### 350 Equipment

No. Description Type Design Condition Opr Qty. (Spares) D3A D3B D3C D3D D3E

7 Slurry Water Pumps Centrifugal 795 lpm (210 gpm) 795 lpm (210 gpm) 833 lpm (220 gpm) 833 lpm (220 gpm) 833 lpm (220 gpm) 2 (1)

8 Trommel Screen Coarse 163 tonne/h (180 tph) 163 tonne/h (180 tph) 163 tonne/h (180 tph) 172 tonne/h (190 tph) 172 tonne/h (190 tph) 2 (0)

9 Rod Mill Discharge Tank

with Agitator Field erected 372,790 liters (98,480 gal) 378,506 liters (99,990 gal) 383,352 liters (101,270 gal) 388,121 liters (102,530 gal) 391,377 liters (103,390 gal) 2 (0)

10 Rod Mill Product Pumps Centrifugal 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 2 (2)

11 Slurry Storage Tank with

Agitator Field erected 1,118,598 liters (295,500 gal) 1,135,633 liters (300,000 gal) 1,150,017 liters (303,800 gal) 1,164,402 liters (307,600 gal) 1,174,244 liters (310,200 gal) 2 (0)

12 Slurry Recycle Pumps Centrifugal 6,057 lpm (1,600 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 2 (2)

13 Slurry Product Pumps Positive displacement 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 2 (2)



### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D3A D3B D3C D3D D3E

1 Demineralized Water

Storage Tank Vertical, cylindrical,

outdoor 1,086,413 liters (287,000 gal) 1,097,769 liters (290,000 gal) 1,090,199 liters (288,000 gal) 1,078,842 liters (285,000 gal) 1,075,057 liters (284,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 7,041 lpm @ 91 m H 2 O (1,860 gpm @ 300 ft H 2 O) 7,306 lpm @ 91 m H 2 O (1,930 gpm @ 300 ft H 2 O) 7,457 lpm @ 91 m H 2 O (1,970 gpm @ 300 ft H 2 O) 7,609 lpm @ 91 m H 2 O (2,010 gpm @ 300 ft H 2 O) 7,684 lpm @ 91 m H 2 O (2,030 gpm @ 300 ft H 2 O) 2 (1)

3 Deaerator (integral w/

HRSG) Horizontal spray type 483,983 kg/hr (1,067,000 lb/hr) 499,859 kg/hr (1,102,000 lb/hr) 509,384 kg/hr (1,123,000 lb/hr) 518,456 kg/hr (1,143,000 lb/hr) 524,353 kg/hr (1,156,000 lb/hr) 2 (0)

4 Intermediate Pressure

Feedwater Pump Horizontal centrifugal, single stage 8,101 lpm @ 27 m H 2 O (2,140 gpm @ 90 ft H 2 O) 8,176 lpm @ 27 m H 2 O (2,160 gpm @ 90 ft H 2 O) 8,025 lpm @ 27 m H 2 O (2,120 gpm @ 90 ft H 2 O) 7,874 lpm @ 27 m H 2 O (2,080 gpm @ 90 ft H 2 O) 7,760 lpm @ 27 m H 2 O (2,050 gpm @ 90 ft H 2 O) 2 (1)

5 High Pressure Feedwater

Pump No. 1 Barrel type, multi

stage, centrifugal HP water: 6,132 lpm @
1,859 m H 2 O (1,620 gpm @ 6,100 ft H 2 O) HP water: 6,132 lpm @
1,859 m H 2 O (1,620 gpm @ 6,100 ft H 2 O) HP water: 6,095 lpm @
1,859 m H 2 O (1,610 gpm @ 6,100 ft H 2 O) HP water: 6,057 lpm @
1,859 m H 2 O (1,600 gpm @
6,100 ft H 2 O) HP water: 6,019 lpm @
1,859 m H 2 O (1,590 g pm @
6,100 ft H 2 O) 2 (1)

6 High Pressure Feedwater

Pump No. 2 Barrel type, multi

stage, centrifugal IP water: 1,476 lpm @ 223

m H 2 O (390 gpm @ 730 ft H 2 O) IP water: 1,514 lpm @ 223

m H 2 O (400 gpm @ 730 ft H 2 O) IP water: 1,590 lpm @

223 m H 2 O (420 gpm @

730 ft H 2 O) IP water: 1,666 lpm @ 223

m H 2 O (440 gpm @ 730 ft

H 2 O) IP water: 1,741 lpm @ 223

m H 2 O (460 gpm @ 730 ft

H 2 O) 2 (1)

7 Auxiliary Boiler Shop fabricated, water

tube 18,144 kg/hr, 2.8 MPa,

343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa,

343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa,

343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa,

343°C (40,000 lb/hr, 4 00 psig, 650°F) 18,144 kg/hr, 2.8 MPa,

343°C (40,000 lb/hr, 400 psig, 650°F) 1 (0)

8 Service Air Compressors Flooded Screw 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 (1)

9 Instrument Air Dryers Duplex, regenerative 28 m 3 /min (1,000 scfm) 28 m 3 /min (1,000 scfm) 28 m 3 /min (1,000 scfm) 28 m 3 /min (1,000 scfm) 28 m 3 /min (1,000 scfm) 2 (1)

10 Closed Cylce Cooling Heat

Exchangers Plate and frame 247 GJ/hr (234.44802645 MMBtu/hr) each 277 GJ/hr (262.36186405 MMBtu/hr) each 301 GJ/hr (285.73317245 MMBtu/hr) each 327 GJ/hr (309.64151075 MMBtu/hr) each 345 GJ/hr (326.5623988 MMBtu/hr) each 2 (0)

11 Closed Cycle Cooling Water

Pumps Horizontal centrifugal 88,579 lpm @ 21 m H 2 O (23,400 gpm @ 70 ft H 2 O) 99,178 lpm @ 21 m H 2 O (26,200 gpm @ 70 ft H 2 O) 108,263 lpm @ 21 m H 2 O (28,600 gpm @ 70 ft H 2 O) 117,348 lpm @ 21 m H 2 O (31,000 gpm @ 70 ft H 2 O) 123,783 lpm @ 21 m H 2 O (32,700 gpm @ 70 ft H 2 O) 2 (1)

12 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H 2 O (1,000 gpm @ 350 ft H 2 O) 3,785 lpm @ 107 m H 2 O (1,000 gpm @ 350 ft H 2 O) 3,785 lpm @ 107 m H 2 O (1,000 gpm @ 350 ft H 2 O) 3,785 lpm @ 107 m H 2 O (1,000 gpm @ 350 ft H 2 O) 3,785 lpm @ 107 m H 2 O (1,000 gpm @ 350 ft H 2 O) 1 (1)

13 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 76 m H 2 O (700 gpm @ 250 ft H 2 O) 2,650 lpm @ 76 m H 2 O (700 gpm @ 250 ft H 2 O) 2,650 lpm @ 76 m H 2 O (700 gpm @ 250 ft H 2 O) 2,650 lpm @ 76 m H 2 O (700 gpm @ 250 ft H 2 O) 2,650 lpm @ 76 m H 2 O (700 gpm @ 250 ft H 2 O) 1 (1)

14 Raw Water Pumps Stainless steel, single

suction 4,580 lpm @ 18 m H 2 O (1,210 gpm @ 60 ft H 2 O) 4,921 lpm @ 18 m H 2 O (1,300 gpm @ 60 ft H 2 O) 5,186 lpm @ 18 m H 2 O (1,370 gpm @ 60 ft H 2 O) 5,451 lpm @ 18 m H 2 O (1,440 gpm @ 60 ft H 2 O) 5,640 lpm @ 18 m H 2 O (1,490 gpm @ 60 ft H 2 O) 2 (1)

15 Ground Water Pumps Stainless steel, single

suction 3,028 lpm @ 268 m H 2 O (800 gpm @ 880 ft H 2 O) 3,293 lpm @ 268 m H 2 O (870 gpm @ 880 ft H 2 O) 2,612 lpm @ 268 m H 2 O (690 gpm @ 880 ft H 2 O) 2,725 lpm @ 268 m H 2 O (720 gpm @ 880 ft H 2 O) 2,839 lpm @ 268 m H 2 O (750 gpm @ 880 ft H 2 O) 3 (1)Carbon Dioxide Capture Sensitivity Analysis



### 351 Equipment

No. Description Type Design Condition Opr Qty. (Spares) D3A D3B D3C D3D D3E

16 Filtered Water Pumps Stainless steel, single

suction 2,082 lpm @ 49 m H 2 O (550 gpm @ 160 ft H 2 O) 2,385 lpm @ 49 m H 2 O (630 gpm @ 160 ft H 2 O) 2,612 lpm @ 49 m H 2 O (690 gpm @ 160 ft H 2 O) 2,877 lpm @ 49 m H 2 O (760 gpm @ 160 ft H 2 O) 3,028 lpm @ 49 m H 2 O (800 gpm @ 160 ft H 2 O) 2 (1)

17 Filtered Water Tank Vertical, cylindrical 995,563 liter (263,000 gal) 1,139,409 liter (301,000 gal) 1,256,757 liter (332,000 gal) 1,374,104 liter (363,000 gal) 1,453,598 liter (384,000 gal) 2 (0)

18 Makeup Water

Demineralizer Anion, cation, and

mixed bed 303 lpm (80 gpm) 568 lpm (150 gpm) 795 lpm (210 gpm) 1,022 lpm (270 gpm) 1,173 lpm (310 gpm) 2 (0)

19 Liquid Waste Treatment

System 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 1 (0)



### ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E

1 Gasifier Pressurized slurry

feed, entrained bed 2,812 tonne/day, 5.6 MPa (3,100 tpd, 814.96 psia) 2,812 tonne/day, 5.6 MPa (3,100 tpd, 814.96 psia) 2,812 tonne/day, 5.6 MPa (3,100 tpd, 814.96 psia) 2,903 tonne/day, 5.6 MPa (3,200 tpd, 814.96 psia) 2,903 tonne/day, 5.6 MPa (3,200 tpd, 814.96 psia) 2 (0)

2 Synthesis Gas Cooler Vertical downflow

radiant heat exchanger with outlet quench chamber 243,126 kg/hr (536,000 lb/hr) 246,754 kg/hr (544,000 lb/hr) 249,929 kg/hr (551,000 lb/hr) 253,105 kg/hr (558,000 lb/hr) 255,373 kg/hr (563,000 lb/hr) 2 (0)

3 Synthesis Gas Cyclone High efficiency 332,937 kg/hr (734,000 lb/hr) Design efficiency 90% 337,926 kg/hr (745,000 lb/hr) Design efficiency 90% 342,462 kg/hr (755,000 lb/hr) Design efficiency 90% 346,545 kg/hr (764,000 lb/hr) Design efficiency 90% 349, 266 kg/hr (77 0 ,000 lb/hr) Design efficiency 90% 2 (0)

4 Candle Filter Pressurized filter with pulse

- jet cleaning metallic filters metallic filters metallic filters metallic filters metallic filters 2 (0)

5 Syngas Scrubber

Including Sour Water Stripper Vertical upflow 332,937 kg/hr (734,000 lb/hr) 337,926 kg/hr (745,000 lb/hr) 342,462 kg/hr (755,000 lb/hr) 346,545 kg/hr (764,000 lb/hr) 349, 266 kg/hr (77 0 ,000 lb/hr) 2 (0)

6 Raw Gas Coolers Shell and tube with

condensate drain 287,578 kg/hr (634,000 lb/hr) 322,504 kg/hr (711,000 lb/hr) 339,741 kg/hr (749,000 lb/hr) 356,977 kg/hr (787,000 lb/hr) 368,771 kg/hr (813,000 lb/hr) 8 (0)

7 Raw Gas Knockout Drum Vertical with mist

eliminator 213,642 kg/hr, 35°C, 5.2

MPa (471,000 lb/hr, 95°F, 750

psia) 239,950 kg/hr, 35°C, 5.2

MPa (529,000 lb/hr, 95°F, 750

psia) 261,723 kg/hr, 35°C, 5.2

MPa (577,000 lb/hr, 95°F, 750

psia) 283,949 kg/hr, 35°C, 5.2

MPa (626,000 lb/hr, 95°F, 750

psia) 298,917 kg/hr, 35°C, 5.2

MPa (659,000 lb/hr, 95°F, 750

psia) 2 (0)

8 Flare Stack Self

- supporting,
carbon steel, stainless steel top, pilot ignition 332,937 kg/hr (734,000 lb/hr) syngas 337,926 kg/hr (745,000 lb/hr) syngas 342,462 kg/hr (755,000 lb/hr) syngas 346,545 kg/hr (764,000 lb/hr) syngas 349, 266 kg/hr (77 0 ,000 lb/hr) syngas 2 (0)

9 ASU Main Air

Compressor Centrifugal, multi

stage 5,6 35 m 3 /min @ 1.3 MPa ( 199 ,000 scfm @ 190 psia) 5,748 m 3 /min @ 1.3 MPa (203,000 scfm @ 190 psia) 5,805 m 3 /min @ 1.3 MPa (205,000 scfm @ 190 psia) 5,890 m 3 /min @ 1.3 MPa (208,000 scfm @ 190 psia) 5,918 m 3 /min @ 1.3 MPa (209,000 scfm @ 190 psia) 2 (0)

10 Cold Box Vendor design 2,268 tonne/day (2,500 tpd) of 95% purity oxygen 2,268 tonne/day (2,500 tpd) of 95% purity oxygen 2,359 tonne/day (2,600 tpd)

of 95% purity oxygen 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2 (0)

11 Oxygen Compressor Centrifugal, multi

stage 1,133 m 3 /min (40,000 scfm)

Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940

psia) 1,161 m 3 /min (41,000 scfm)

Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940

psia) 1,161 m 3 /min (41,000 scfm)

Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940

psia) 1,189 m 3 /min (42,000 scfm)

Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940

psia) 1,189 m 3 /min (42,000 scfm)

Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940

psia) 2 (0)

12 Primary Nitrogen

Compressor Centrifugal, multi

stage 3,540 m 3 /min (125,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390

psia) 3,625 m 3 /min (128,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390

psia) 3,653 m 3 /min (129,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390

psia) 3,710 m 3 /min (13 1,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390

psia) 3,738 m 3 /min (132,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390

psia) 2 (0)Carbon Dioxide Capture Sensitivity Analysis



### 352 Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E

13 Secondary Nitrogen

Compressor Centrifugal, single

stage 538 m 3 /min (19,000 scfm)

Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390

psia) 538 m 3 /min (19,000 scfm)

Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390

psia) 538 m 3 /min (19,000 scfm)

Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390

psia) 538 m 3 /min (19,000 scfm)

Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390

psia) 538 m 3 /min (19,000 scfm)

Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390

psia) 2 (0)

14 Syngas Dilution Nitrogen

Boost Compressor Centrifugal, single

stage 0 m 3 /min (0 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470

psia) 28 m 3 /min (1,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470

psia) 680 m 3 /min (24,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470

psia) 1,331 m 3 /min (47,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470

psia) 1,784 m 3 /min (63,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470

psia) 2 (0)



### ACCOUNT 5A SYNGAS CLEANUP

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E

1 Mercury Adsorber Sulfated

carbon bed 212,735 kg/hr (469,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 239,497 kg/hr (528,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 261,269 kg/hr (576,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 283,495 kg/hr (625,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 298,464 kg/hr (658,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 2 (0)

2 Sulfur Plant Claus type 139 tonne/day (153 tpd) 141 tonne/day (155 tpd) 143 tonne/day (157 tpd) 144 tonne/day (159 tpd) 145 tonne/day (160 tpd) 1 (0)

3 Water Gas Shift

Reactors Fixed bed, catalytic 907 kg/hr (2,000 lb/hr) 210°C (410°F) 5.4 MPa (790 psia) 110,223 kg/hr (243,000 lb/hr) 221°C (430°F) 5.4 MPa (790 psia) 200,034 kg/hr (441,000 lb/hr) 221°C (430°F) 5.4 MPa (790 psia) 291,206 kg/hr (642,000 lb/hr) 221°C (430°F) 5.4 MPa (790 psia) 352,895 kg/hr (778,000 lb/hr) 221°C (430°F) 5.4 MPa (790 psia) 4 (0)

4 Shift Reactor Heat

Recovery Exchangers Shell and

Tube Exchanger 1: 00 GJ/hr (00 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) Exchanger 1: 45 GJ/hr (42 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) Exchanger 1: 81 GJ/hr (77 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) Exchanger 1: 118 GJ/hr (112 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) Exchanger 1: 143 GJ/hr (135 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/ hr) 4 (0)

5 COS Hydrolysis

Reactor Fixed bed, catalytic 300,732 kg/hr (663,000 lb/hr) 210°C (410°F) 5.4 MPa (790 psia) 212,281 kg/hr (468,000 lb/hr) 210°C (410°F) 5.4 MPa (790 psia) 139,253 kg/hr (307,000 lb/hr) 210°C (410°F) 5.4 MPa (790 psia) 65,771 kg/hr (145,000 lb/hr) 210°C (410°F) 5.4 MPa (790 psia) 15,876 kg/hr (35,000 lb/hr) 210°C (410°F) 5.4 MPa (790 psia) 2 (0)

6 Acid Gas Removal

Plant Two

- stage

Selexol 214,549 kg/hr (473,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 240,858 kg/hr (531,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 262,630 kg/hr (579,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 284,856 kg/hr (628,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 300,278 kg/hr (662,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 2 (0)

7 Hydrogenation

Reactor Fixed bed, catalytic 6,347 kg/hr (13,992 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 6,104 kg/hr (13,457 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 5,915 kg/hr (13,039 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 6,798 kg/hr (14,988 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 7,423 kg/hr (16,364 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 1 (0)

8 Tail Gas Recycle

Compressor Centrifugal 3,059 kg/hr (6,744 lb/hr) 2,514 kg/hr (5,543 lb/hr) 2,073 kg/hr (4,570 lb/hr) 2,784 kg/hr (6,138 lb/hr) 3,281 kg/hr (7,233 lb/hr) 1 (0)



### ACCOUNT 5B CO 2 

### COMPRESSION

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E

1 CO 2 Compressor Integrally geared, multi

stage centrifugal 30 3 m 3 /min @ 15.3 MPa (10, 7 00 scfm @ 2,215 psia) 544 m 3 /min @ 15.3 MPa (19,200 scfm @ 2,215 psia) 736 m 3 /min @ 15.3 MPa (26,000 scfm @ 2,215 psia) 9 29 m 3 /min @ 15.3 MPa (32, 8 00 scfm @ 2,215 psia) 1,062 m 3 /min @ 15.3 MPa (37,500 scfm @ 2,215 psia) 4 (0)Carbon Dioxide Capture Sensitivity Analysis



### 353 ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E

1 Gas Turbine Advanced F class 230 MW 230 MW 230 MW 230 MW 230 MW 2 (0)

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV,
60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV,

60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV,

60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV,

60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV,

60 Hz, 3

- phase 2 (0)

3 Syngas Expansion

Turbine/Generator Turbo Expander 144,378 kg/h (318,300 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 116,800 kg/h (257,500 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 95,935 kg/h (211,500 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 74,344 kg/h (163,900 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 59,693 kg/h (131,600 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 2 (0)



### ACCOUNT 7 HRSG, DUCTING

, AND STACK

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E

1 Stack CS plate, type

409SS liner 76 m (250 ft) high x 8.4 m (28 ft) diameter 76 m (250 ft) high x 8.4 m (28 ft) diameter 76 m (250 ft) high x 8.4 m (28 ft) diameter 76 m (250 ft) high x 8.4 m (28 ft) diameter 76 m (250 ft) high x 8.5 m (28 ft) diameter 1 (0)

2 Heat Recovery

Steam

Generator Drum, multi

pressure with

economizer section and integral

deaerator Main steam

- 346,899 kg/hr, 12.4 MPa/554°C (764,782 lb/hr, 1,800 psig/1,029°F)

Reheat steam

- 346,477 kg/hr, 3.1 MPa/554°C (763,852 lb/hr, 452 psig/1,029°F) Main steam

- 346,705 kg/hr, 12.4 MPa/548°C (764,354 lb/hr, 1,800 psig/1,019°F)

Reheat steam

- 340,285 kg/hr, 3.1 MPa/548°C (750,200 lb/hr, 452 psig/1,019°F) Main steam

- 344,019 kg/hr, 12.4 MPa/544°C (758,433 lb/hr, 1,800 psig/1,011°F)

Reheat steam

- 342,563 kg/hr, 3.1 MPa/544°C (755,223 lb/hr, 452 psig/1,011°F) Main steam

- 341,230 kg/hr, 12.4 MPa/539°C (752,283 lb/hr, 1,800 psig/1,002°F)

Reheat steam

- 344,795 kg/hr, 3.1 MPa/539°C (760,143 lb/hr, 452 psig/1,002°F) Main steam

- 339,379 kg/hr, 12.4 MPa/536°C (748,203 lb/hr, 1,800 psig/997°F)

Reheat steam

- 346,307 kg/hr, 3.1 MPa/536°C (763,477 lb/hr, 452 psig/997°F) 2 (0)



### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E

1 Steam Turbine Commercially

available advanced

steam turbine 295 MW 12.4

MPa/554°C/554°C (1,800 psig/ 1029°F/1029°F) 291 MW 12.4 MPa/548°C/548°C (1,800 psig/ 1019°F/1019°F) 289 MW 12.4 MPa/544°C/544°C (1,800 psig/ 1011°F/1011°F) 286 MW 12.4 MPa/539°C/539°C ( 1,800 psig/ 1002°F/1002°F) 284 MW 12.4 MPa/536°C/536°C (1,800 psig/ 997°F/997°F) 1 (0)

2 Steam Turbine

Generator Hydrogen cooled,

static excitation 330 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 320 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 320 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 320 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 320 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design

steam conditions 50% steam flow @ design

steam conditions 50% steam flow @ design

steam conditions 50% steam flow @ design

steam conditions 50% steam flow @ design

steam conditions 2 (0)

4 Surface

Condenser Single pass, divided

waterbox including

vacuum pumps 1,783 GJ/hr (1,690 MMBtu/hr),

Inlet water temperature 16°C (60°F), Water temperature rise

11°C (20°F) 1,772 GJ/hr (1,680 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise

11°C (20°F) 1,751 GJ/hr (1,660 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise

11°C (20°F) 1,730 GJ/hr (1,640 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise

11°C (20°F) 1,709 GJ/hr (1,620 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise

11°C (20°F) 1 (0)Carbon Dioxide Capture Sensitivity Analysis



### 354 ACCOUNT 9 COOLING WATER SYSTEM

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E

1 Circulating Water Pumps Vertical, wet pit 416,395 lpm @ 30 m (110,000 gpm @ 100 ft) 431,537 lpm @ 30 m (114,000 gpm @ 100 ft) 442,893 lpm @ 30 m (117,000 gpm @ 100 ft) 454,249 lpm @ 30 m (120,000 gpm @ 100 ft) 461,820 lpm @ 30 m (122,000 gpm @ 100 ft) 2 (1)

2 Cooling Tower Evaporative,
mechanical draft,

multi

- cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,332 GJ/hr (2,210 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,416 GJ/hr (2,290 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,479 GJ/hr (2,350 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,532 GJ/hr (2,400 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,574 GJ/hr (2,440 MMBtu/hr) heat duty 1 (0)



### ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E

1 Slag Quench Tank Water bath 242,266 liters (64,000 gal) 246,052 liters (65,000 gal) 249,837 liters (66,000 gal) 249,837 liters (66,000 gal) 253,623 liters (67,000 gal) 2 (0)

2 Slag Crusher Roll 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

3 Slag Depressurizer Lock Hopper 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

4 Slag Receiving Tank Horizontal, weir 143,846 liters (38,000 gal) 147,631 liters (39,000 gal) 151,416 liters (40,000 gal) 151,416 liters (40,000 gal) 151,416 liters (40,000 gal) 2 (0)

5 Black Water Overflow

Tank Shop fabricated 64,352 liters (17,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)

6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

7 Slag Separation

Screen Vibrating 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

8 Coarse Slag

Conveyor Belt/bucket 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

9 Fine Ash Settling

Tank Vertical, gravity 208,198 liters (55,000 gal) 208,198 liters (55,000 gal) 211,983 liters (56,000 gal) 215,768 liters (57,000 gal) 215,768 liters (57,000 gal) 2 (0)

10 Fine Ash Recycle

Pumps Horizontal centrifugal 38 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 38 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 38 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 38 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 38 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 2 (2)

11 Grey Water Storage

Tank Field erected 64,352 liters (17,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H 2 O (60 gpm @ 1,850 ft H 2 O) 227 lpm @ 564 m H 2 O (60 gpm @ 1,850 ft H 2 O) 227 lpm @ 564 m H 2 O (60 gpm @ 1,850 ft H 2 O) 227 lpm @ 564 m H 2 O (60 gpm @ 1,850 ft H 2 O) 227 lpm @ 564 m H 2 O (60 gpm @ 1,850 ft H 2 O) 2 (2)

13 Slag Storage Bin Vertical, field erected 907 tonne (1,000 tons) 907 tonne (1,000 tons) 907 tonne (1,000 tons) 907 tonne (1,000 tons) 998 tonne (1,100 tons) 2 (0)

14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 1 (0)Carbon Dioxide Capture Sensitivity Analysis



### 355 ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E

1 CTG Step

- up
Transformer Oil

- filled 24 kV/345 kV, 260 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 260 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 260 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 260 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 260 MVA,

3

- ph, 60 Hz 2 (0)

2 STG Step

- up

Transformer Oil

- filled 24 kV/345 kV, 330 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 320 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 320 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 320 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 320 MVA,

3

- ph, 60 Hz 1 (0)

3 High Voltage Auxiliary

Transformer Oil

- filled 345 kV/13.8 kV, 63 MVA,

3

- ph, 60 Hz 345 kV/13.8 kV, 68 MVA,

3

- ph, 60 Hz 345 kV/13.8 kV, 72 MVA,

3

- ph, 60 Hz 345 kV/13.8 kV, 76 MVA,

3

- ph, 60 Hz 345 kV/13.8 kV, 79 MVA,

3

- ph, 60 Hz 2 (0)

4 Medium Voltage

Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 30 MVA,

3

- ph, 60 Hz 24 kV/4.16 kV, 34 MVA,

3

- ph, 60 Hz 24 kV/4.16 kV, 38 MVA,

3

- ph, 60 Hz 24 kV/4.16 kV, 42 MVA,

3

- ph, 60 Hz 24 kV/4.16 kV, 45 MVA,

3

- ph, 60 Hz 1 (1)

5 Low Voltage

Transformer Dry ventilated 4.16 kV/480 V, 4 MVA,

3

- ph, 60 Hz 4.16 kV/480 V, 5 MVA,

3

- ph, 60 Hz 4.16 kV/480 V, 6 MVA,

3

- ph, 60 Hz 4.16 kV/480 V, 6 MVA,

3

- ph, 60 Hz 4.16 kV/480 V, 7 MVA,

3

- ph, 60 Hz 1 (1)

6 CTG Isolated Phase

Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 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 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 1 (0)

8 Medium Voltage

Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 1 (1)

9 Low Voltage

Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 1 (1)

10 Emergency Diesel

Generator Sized for emergency

shutdown 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 1 (0)



### ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E

1 DCS

- Main

Control Monitor/keyboard;

Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers Operator stations/printers and engineering stations/printers Operator stations/printers and engineering stations/printers Operator stations/printers and engineering stations/printers Operator stations/printers and engineering stations/printers 1 (0)

2 DCS

-

Processor Microprocessor with

redundant input/output N/A N/A N/A N/A N/A 1 (0)

3 DCS

- Data

Highway Fiber optic Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare 1 (0)Carbon Dioxide Capture Sensitivity Analysis



### 356 This page intentionally left blankCarbon Dioxide Capture Sensitivity Analysis



### 357 

## 4.3.4 IGCC Design 4

– Two Water Gas Shift Reactors Without Bypass

A proces s block flow diagram for Case 2 Design 4 (D4) is shown in Exhibit 4

- 108 . D4 represents an IGCC plant with two WGS reactors and no bypass stream, which maximizes total

CO 2 

### capture. This IGCC design uses a S:DG molar ratio of 0.3 at the outlet of the second WGS

r eactor. To achieve greater than 90 percent CO 2 

### removal, the two

- stage SelexolTM CO 2 

### removal efficiency is increased by raising the solvent circulation rate, which increases the size and cost of the SelexolTM system. According to UOP, two

- stage SelexolTM sys tems have been designed for
up to 97 percent CO 2 

### recovery and this level of control was deemed the maximum for this study

[ 57 ]. D4 does not include a COS h ydrolysis unit since the entire syngas stream passes th rough

two WGS reactors.

Three levels of total CO 2 

### removal were modeled for Case 2 D4: 90 percent (D4A), 95 percent (D4B), and 97 percent (D4C). The corresponding stream tables are contained in Exhibit 4

- 109

, Exhibit 4

- 110 , and Exhibit 4

- 111 , respectively.

Overall performance for Case 2 D4 is summarized in Exhibit 4

- 112 which includes auxiliary power requirements. Note that the coal feed rate remains essentially constant at CO 2 

### capture

levels of 90 percent and higher , but a small decrease (~0.2 percent ) is observed. This anomaly can be expl ained by a significant increase in the quantity of nitrogen sent to the CT for dilution and temperature control. The excess nitrogen increases the total mass flow to the CT, which

lead s to a CT power output greater than 464 MW. As a result, the Aspen model reduce s the coal

feed rate slightly to maintain a CT gross power output of 464 MW (based on two turbines) since

an advanced F Class turbine is designed for a gross output of 232 MW

. However, as expected, the net power output and net plant efficiency decrease as the CO 2 

### capture level increases.

Material and energy balance information, environmental performance and a major e quipment list

are summarized in Sections 4.3.4.1 a nd 4.3.4.2

.Carbon Dioxide Capture Sensitivity Analysis



### 358 Exhibit 4

- 108 Case 2 D4 Process Block Flow Diagram, IGCC with Two WGS ReactorsCarbon Dioxide Capture Sensitivity Analysis



### 359 Exhibit 4

- 109 Case 2 D4A Stream Table, 90% CO 2 RemovalCarbon Dioxide Capture Sensitivity Analysis



### 360 Exhibit 4

- 109 Case 2 D4A Stream Table, 90% CO 2 Removal (continued)Carbon Dioxide Capture Sensitivity Analysis



### 361 Exhibit 4

- 110 Case 2 D4B Stream Table, 95% CO 2 CaptureCarbon Dioxide Capture Sensitivity Analysis



### 362 Exhibit 4

- 110 Case 2 D4B Stream Table, 95% CO 2 Capture (continued)Carbon Dioxide Capture Sensitivity Analysis



### 363 Exhibit 4

- 111 Case 2 D4C Stream Table, 97% CO 2 CaptureCarbon Dioxide Capture Sensitivity Analysis



### 364 Exhibit 4

- 111 Case 2 D4C Stream Table, 97% CO2 Capture (continued)Carbon Dioxide Capture Sensitivity Analysis



### 365 Exhibit 4

- 112 Case 2 D4 Performance Modeling Results

POWER SUMMARY (Gross Power at Generator Terminals, kWe) D 4 A ( 90 %) D 4 B

( 95 %) D 4 C

( 97 %)

Gas Turbine Power 464,000 464,000 464,000

Sweet Gas Expander Power 6, 3 00 6, 0 00 6, 0 00

Steam Turbine Power 263,700 256,600 253,600

Total 734, 0 00 726, 6 00 723, 6 00

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 4 69 4 68 4 68

Coal Milling 2, 27 2 2, 2 6 8 2, 2 67

Sour Water Recycle Slurry Pump 1 9 0 1 9 0 1 89

Slag Handling 1,1 6 4 1,1 6 1 1,1 6 1

Air Separation Unit Auxiliaries 1,000 1,000 1,000

Air Separation Unit Main Air Compressor 67,3 62 67, 291 67,2 72

Oxygen Compressor 10, 64 2 10, 6 2 4 10, 6 1 7

Nitrogen Compressors 35,64 5 36,97 5 37,0 84

CO 2 Compressor 31,1 6 1 32,7 23 33,3 76

Boiler Feedwater Pumps 4,1 78 4,1 67 4,16 3

Condensate Pump 2 79 2 66 2 6 1

Quench Water Pump 5 38 5 37 5 36

Circulating Water Pump 4, 62 1 4, 55 1 4, 52 1

Ground Water Pumps 5 27 5 19 5 17

Cooling Tower Fans 2, 390 2, 35 2 2, 3 37

Scrubber Pumps 2 26 2 2 1 2 2 1

Acid Gas Removal 19,23 0 21,2 7 3 22,1 25

Gas Turbine Auxiliaries 1,000 1,000 1,000

Steam Turbine Auxiliaries 100 100 100

Claus Plant/TGTU Auxiliaries 250 250 250

Claus Plant TG Recycle Compressor 1,760 4,40 0 5,49 3

Miscellaneous Balance of Plant 1 3,000 3,000 3,000

Transformer Losses 2, 7 5 2 2, 7 5 4 2, 75 1

TOTAL AUXILIARIES, kWe 190,756 198,090 200,709

NET POWER, kWe 543, 244 528, 510 522,891

Net Plant Efficiency, % (HHV) 32.6 % 31.8 % 31.5 %

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,03 5 (10,45 9 ) 11,3 22 (10,7 31 ) 11,43 7 (10,8 40 )

Condenser Duty, GJ/hr (10 6 Btu/hr) 1, 519 (1, 44 0) 1, 435 (1, 36 0) 1, 403 (1, 33 0)

CONSUMABLES

As

- Received Coal Feed, kg/hr (lb/hr) 220,9 11 ( 487, 026 ) 220,5 22 ( 486, 169 ) 220, 380 ( 485, 856 )

Thermal Input, kW th 2 1, 665, 125 1, 662, 195 1, 661, 125

Raw Water Withdrawal, m 3 /min (gpm) 22.0 ( 5,81 7 ) 21.7 ( 5,7 39 ) 21.6 ( 5,70 7 )

Raw Water Consumption, m 3 /min (gpm) 17.9 ( 4,74 1 ) 17.7 ( 4,6 79 ) 17.6 ( 4,65 4 )

Notes: 1. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

2. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)Carbon Dioxide Capture Sensitivity Analysis



### 366 4.3.4.1 Environmental Performance for Case 2 D4

The environmental targets for emissions of Hg, NOx, SO 2 

### , and particulate matter were prese nted

in Section 2.4 . A summary of the p lant air emissions for Case 2 D4A, D4 B , and D4C is presented in Exhibit 4

- 113

.
For Case 2 D4, SO 2 

### emissions are controlled by sulfur capture across the two

- stage SelexolTM
unit. The clean syngas exiting the AGR unit has a sulfur concentration of about 10 ppmv, resulting in a concentration in the flue gas of less than 2 ppmv. The H 2 

### S

- rich regeneration gas produced in Case 2 D4 is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H 2 

### S and then recycled back to the SelexolTM
unit, thereby eliminating the need for a tail gas treatment unit.

NOx emissions are limited by nitrogen dilution of the syngas to 15 ppmvd (as NO 2 

### @ 15 percent

O 2 

### ). Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process, and ultimately incinerated in the Claus plant burner. This also assists in lowering

NOx levels.

Particulate discharge to the atmosphere is limited to extremely low values by the use of the

syngas quen ch in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only.

Ninety

- five percent of the mercury is captured from the syngas by an activated carbon bed.

For Case 2 D4, varying levels of the CO 2 

### [90 percent (D4A), 95 percent (D4B), and 97 percent (D4C)] in the syngas are captured in the two

- stage SelexolTM unit and compressed for
sequestration. The carbon balance for Case 2 D4 is shown in Exhibit 4

- 114 . The carbon input to the plant consists of carbon in the air and coal. Carbon in the air is not neg lected here since the
Aspen model accounts for air components th roughout. Carbon leaves the plant as unburned carbon in the slag, as dissolved CO 2 

### in the wastewater blowdown stream , and as CO 2 

### in the stack gas, ASU vent gas, and the captured CO 2 

### product. Carbon in the wastewater blowdown stream is calculated by diffe rence to close the material balance. The carbon capture efficiency is

defined as the pounds of carbon in the CO 2 

### product stream relative to the amount of carbon in the

coal

, less carbon contained in the slag , represented by the following fraction:

(Carbon in CO 2 

### Product)/[(Carbon in the Coal)

- (Carbon in Slag)] or

274,684/(310,453

- 6,209)*100=90.3% (D4A)

288,563 /( 309,907

- 6,198 )*100= 95.0 % (D 4 B)

294,371 /( 309,708

- 6, 194 )*100= 97.0 % (D 4 C)

Exhibit 4

- 115 shows the sulfur balance for Case 2 D2. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the pounds of sulfur recovered in the Claus plant, dissolved

SO 2 

### in the wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible, and the sulfur content of the blowdown stream is calculated by

difference to close the material balance. The total sulfur capture is repr esented by the following

fraction:Carbon Dioxide Capture Sensitivity Analysis



### 367 (Sulfur byproduct/Sulfur in the coal) or
(12,178/12,207)*100 = 99.8% (D4A)
(12,156/12,185)*100 = 99.8% (D4B)
(12,148/12,178)*100 = 99.8% (D4C)

The overall water balance s for Case 2 D4A, D4B, and D4C are shown in Exhibit 4

- 116

, Exhibit 4

- 117 , and Exhibit 4

- 118 , respectively. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the t otal amount of water required for a particular process. Some water is recovered within t he process and that

water is re used as internal recycle. Raw water withdrawal is the difference between water demand and internal recycle. Process water discharged f rom the power plant is also account ed for in this study. Raw water consumption represents raw water withdrawal less proce ss water discharge.

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 4

- 119 through Exhibit 4

- 127

.

Gasifier and ASU

Syngas Cleanup

Power Block

An overall plant energy balance for Case D4A, D4B, and D4C is provided in tabular form in

Exhibit 4

- 128

, Exhibit 4

- 129 , and Exhibit 4

- 130 , respectively. The power out is the combined combustion turbine, steam turbine and expander power after generator losses. In addition, energy balance Sankey diagrams are provided for D4A, D4B, and D4C in Exhibit 4

- 131

, Exhibit

4

- 132 , and Exhibit 4

- 133 , respectively.Carbon Dioxide Capture Sensitivity Analysis



### 368 Exhibit 4

- 113 Case 2 D4 Estimated Air Emission Rates

kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh net (lb/MWh net )

D 4 A D 4 B D 4 C D 4 A D 4 B D 4 C D 4 A D 4 B D 4 C

SO 2 0. 001 (0.0 02 ) 0. 001 (0.0 02 ) 0. 001 (0.0 02 ) 39 (43) 39 (43) 39 (43) 0.008 (0.020) 0.008 (0.020) 0.008 (0.020)

NO X 0.0 21 (0.0 49 ) 0.0 21 (0.0 49 ) 0.0 21 (0.0 49 ) 878 (967) 878 (968) 878 (968) 0.171 (0.376) 0.172 (0.380) 0.173 (0.382)

PM 0.00 3 (0.0 071 ) 0.00 3 (0.0 071 ) 0.00 3 (0.0 071 ) 128 (141) 128 (141) 128 (141) 0.025 (0.055) 0.025 (0.055) 0.025 (0.056)

Hg 0. 246 x10 - 6

( 0.571 x10 - 6 ) 0. 246 x10 - 6

( 0.571 x10 - 6 ) 0. 246 x10 - 6

( 0.571 x10 - 6 ) 0.010 (0.011) 0.010 (0.011) 0.010 (0.011) 2.01 x10 - 6

( 4.42 x10 - 6 ) 2.02 x10 - 6

( 4.46 x10 - 6 ) 2.03 x10 - 6

( 4.48 x10 - 6 )

CO 2 8.5 (19.7) 4.5 (10.4) 2.8 (6.5) 355,4 05 (391, 767 ) 187, 497

(206, 680 ) 117, 588

(129,6 19 ) 69 (152) 37 (81) 23 (51)

CO 2 net 93 (206) 51 (112) 32 (71)Carbon Dioxide Capture Sensitivity Analysis



### 369 Exhibit 4

- 114 Case 2 D4 Carbon Balance

Carbon In, kg/hr (lb/hr)

D4A D4B D4C

Coal 140,8 19

(310, 453 ) 140, 571

(309,9 07 ) 140, 481

(309,7 08 )

Air (CO 2 ) 540 (1,191) 540 (1,19 0 ) 540 (1,190)

Total 141,3 59

(311, 644 ) 141,1 11

(311, 097 ) 141,0 21

(310, 898 )
Carbon Out, kg/hr (lb/hr)

Slag 2,81 6 (6,2 09 ) 2,81 1 (6, 198 ) 2,810

(6,19 4 )

Stack Gas 13,84 1

(30,5 14 ) 7,30 2

(16, 098 ) 4,5 79

(10,09 6 )

ASU Vent 107 (237) 107 (237) 107 (237)

CO 2 Product 124, 595

(274, 684 ) 130, 890

(288, 563 ) 133,5 25

(294, 371 )
Convergence

Tolerance 0 (0) 1 ( 1 ) 0 ( 0 )

Total 141,359

(311,644) 141,111

(311,097) 141,021

(310,898)

Exhibit 4

- 115 Case 2 D4 Sulfur Balance

Sulfur In, kg/hr (lb/hr)

D4A D4B D4C

Coal 5,53 7 (12,2 07 ) 5,52 7

(12,18 5 ) 5,52 4

(12,1 78 )

Total 5,53 7 (12,2 07 ) 5,52 7

(12,18 5 ) 5,52 4

(12,1 78 )
Sulfur Out, kg/hr (lb/hr)

Elemental Sulfur 5,52 4 (12,1 78 ) 5,51 4

(12,15 6 ) 5,51 0

(12,1 48 )

Stack Gas 3 (6) 3 (6) 3 (6)

CO 2 Product 10 (23) 11 (23) 11 (24)

Convergence

Tolerance 0 (0)

- 1 (0) 0 (0)

Total 5,53 7 (12,2 07 ) 5,52 7

(12,18 5 ) 5,52 4

(12,1 78 )Carbon Dioxide Capture Sensitivity Analysis



### 370 Exhibit 4

- 116 Case 2 D4A (90%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Slag Handling 0.53 (139) 0.53 (139) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.9 (757) 0.72 (191) 2.1 (566) 0.0 (0) 2.1 (566)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7)

Condenser Makeup 2.4 (627) 0.0 (0) 2.4 (627) 0.0 (0) 2.4 (627)

Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

Shift Steam 2.2 (571) 0.0 (0) 2.2 (571)

C T Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

BFW Makeup 0.21 (56) 0.0 (0) 0.21 (56)

Cooling Tower 18.0 (4,753) 0.49 (129) 17.5 (4,625) 4.0 (1,069) 13.5 (3,556)

BFW Blowdown 0.0 (0) 0.21 (56)

- 0.21 (

- 56)

SWS Blowdown 0.0 (0) 0.28 (73)

- 0.28 (

- 73)

SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 25.3 (6,676) 3.25 (858) 22.0 (5,817) 4.1 (1,076) 17.9 (4,741)

Total, gal/MWh net 737 95 643 119 524Carbon Dioxide Capture Sensitivity Analysis



### 371 Exhibit 4

- 117 Case 2 D4B (95%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Slag Handling 0.52 (139) 0.52 (139) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.9 (755) 0.71 (189) 2.1 (567) 0.0 (0) 2.1 (567)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7)

Condenser Makeup 2.4 (622) 0.0 (0) 2.4 (622) 0.0 (0) 2.4 (622)

Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

Shift Steam 2.1 (566) 0.0 (0) 2.1 (566)

C T Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

BFW Makeup 0.21 (56) 0.0 (0) 0.21 (56)

Cooling Tower 17.7 (4,679) 0.49 (128) 17.2 (4,551) 4.0 (1,052) 13.2 (3,498)

BFW Blowdown 0.0 (0) 0.21 (56)

- 0.21 (

- 56)

SWS Blowdown 0.0 (0) 0.28 (73)

- 0.28 (

- 73)

SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 25.0 (6,594) 3.24 (855) 21.7 (5,739) 4.0 (1,060) 17.7 (4,679)

Total, gal/MWh net 749 97 652 120 531Carbon Dioxide Capture Sensitivity Analysis



### 372 Exhibit 4

- 118 Case 2 D4C (97%) Water Balance

Water Use Water Demand,

m 3 /min (gpm) Internal Recycle,

m 3 /min (gpm) Raw Water Withdrawal,

m 3 /min (gpm) Process Water Discharge,

m 3 /min (gpm) Raw Water Consumption,

m 3 /min (gpm)

Slag Handling 0.52 (138) 0.52 (138) 0.0 (0) 0.0 (0) 0.0 (0)

Quench/Wash 2.9 (755) 0.72 (189) 2.1 (566) 0.0 (0) 2.1 (566)

Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)

SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7)

Condenser Makeup 2.4 (622) 0.0 (0) 2.4 (622) 0.0 (0) 2.4 (622)

Gasifier Steam 0.0 (0) 0.0 (0) 0.0 (0)

Shift Steam 2.1 (566) 0.0 (0) 2.1 (566)

C T Steam Dilution 0.0 (0) 0.0 (0) 0.0 (0)

BFW Makeup 0.21 (56) 0.0 (0) 0.21 (56)

Cooling Tower 17.6 (4,648) 0.49 (128) 17.1 (4,519) 4.0 (1,045) 13.2 (3,474)

BFW Blowdown 0.0 (0) 0.21 (56)

- 0.21 (

- 56)

SWS Blowdown 0.0 (0) 0.28 (73)

- 0.28 (

- 73)

SWS Excess Water 0.0 (0) 0.0 (0) 0.0 (0)

Humidifier Tower Blowdown 0.0 (0) 0.0 (0) 0.0 (0)

Total 24.8 (6,562) 3.24 (855) 21.6 (5,707) 4.0 (1,052) 17.6 (4,654)

Total, gal/MWh net 753 98 655 121 534Carbon Dioxide Capture Sensitivity Analysis



### 373 Exhibit 4

- 119 Case 2 D4A (90%) Heat and Mass Balance, GEE Gasifier and ASUCarbon Dioxide Capture Sensitivity Analysis



### 374 Exhibit 4

- 120 Case 2 D4A (90%) Heat and Mass Balance, Syngas CleanupCarbon Dioxide Capture Sensitivity Analysis



### 375 Exhibit 4

- 121 Case 2 D4A (90%) Heat and Mass Balance, Power BlockCarbon Dioxide Capture Sensitivity Analysis



### 376 Exhibit 4

- 122 Case 2 D4B (95%) Heat and Mass Balance, GEE Gasifier and ASUCarbon Dioxide Capture Sensitivity Analysis



### 377 Exhibit 4

- 123 Case 2 D4B (95%) Heat and Mass Balance, Syngas CleanupCarbon Dioxide Capture Sensitivity Analysis



### 378 Exhibit 4

- 124 Case 2 D4B (95%) Heat and Mass Balance, Power BlockCarbon Dioxide Capture Sensitivity Analysis



### 3 79 Exhibit 4

- 125 Case 2 D4C (97%) Heat and Mass Balance, GEE Gasifier and ASUCarbon Dioxide Capture Sensitivity Analysis



### 380 Exhibit 4

- 126 Case 2 D4C (97%) Heat and Mass Balance, Syngas CleanupCarbon Dioxide Capture Sensitivity Analysis



### 381 Exhibit 4

- 127 Case 2 D4C (97%) Heat and Mass Balance, Power BlockCarbon Dioxide Capture Sensitivity Analysis



### 382 This page intentionally left blankCarbon Dioxide Capture Sensitivity Analysis



### 383 Exhibit 4

- 128 Case 2 D4A (90%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,994 (5,682) 5.0 (4.7) 0 (0) 5,999 (5,686)

ASU Air 0 (0) 23.9 (22.6) 0 (0) 24 (23)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 82.8 (78.5) 0 (0) 83 (78)

Totals 5,994 (5,682) 207.9 (197.0) 0 (0) 6,202 (5,879)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.6 (1.5) 0 (0) 2 (2)

Slag 92 (88) 37.8 (35.9) 0 (0) 130 (123)

Sulfur 51 (49) 0.6 (0.6) 0 (0) 52 (49)

CO 2 0 (0)

- 74.1 (

- 70.3) 0 (0)

- 74 (

- 70)

Gasifier Heat Loss 0 (0) 44.6 (42.3) 0 (0) 45 (42)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,318 (1,249) 0 (0) 1,318 (1,249)

Cooling Tower* 0 (0) 2,177 (2,063) 0 (0) 2,177 (2,063)

Process Losses* * 0 (0) 534 (506) 0 (0) 534 (506)

Net Power 0 (0) 0.0 (0.0) 1,956 (1,854) 1,956

(1,854)

Totals 144 (136) 4,103 (3,889) 1,956 (1,854) 6,202

(5,879)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

air cooler. ** Calculated by difference to close the energy balance.Carbon Dioxide Capture Sensitivity Analysis



### 384 Exhibit 4

- 129 Case 2 D4B (95%) Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,984 (5,672) 5.0 (4.7) 0 (0) 5,989 (5,676)

ASU Air 0 (0) 23.9 (22.6) 0 (0) 24 (23)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 81.7 (77.4) 0 (0) 82 (77)

Totals 5,984 (5,672) 206.7 (195.9) 0 (0) 6,191 (5,868)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 1.0 (0.9) 0 (0) 1 (1)

Slag 92 (87) 37.8 (35.8) 0 (0) 130 (123)

Sulfur 51 (48) 0.6 (0.6) 0 (0) 52 (49)

CO 2 0 (0)

- 78.1 (

- 74.0) 0 (0)

- 78 (

- 74)

Gasifier Heat Loss 0 (0) 44.5 (42.2) 0 (0) 45 (42)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,316 (1,247) 0 (0) 1,316 (1,247)

Cooling Tower* 0 (0) 2,121 (2,010) 0 (0) 2,121 (2,010)

Process Losses* * 0 (0) 639 (605) 0 (0) 639 (605)

Net Power 0 (0) 0.0 (0.0) 1,903 (1,803) 1,903

(1,803)

Totals 143 (136) 4,145 (3,928) 1,903 (1,803) 6,191

(5,868)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

air cooler. ** Calculated by difference to close the energy balance.Carbon Dioxide Capture Sensitivity Analysis



### 385 Exhibit 4

- 130 Case 2 D4C (97%) Ener gy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,980 (5,668) 5.0 (4.7) 0 (0) 5,985 (5,673)

ASU Air 0 (0) 23.8 (22.6) 0 (0) 24 (23)

GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91)

Water 0 (0) 81.2 (77.0) 0 (0) 81 (77)

Totals 5,980 (5,668) 206.2 (195.5) 0 (0) 6,186 (5,863)

Heat Out GJ/hr (MMBtu/hr)

ASU Vent 0 (0) 0.9 (0.9) 0 (0) 1 (1)

Slag 92 (87) 37.8 (35.8) 0 (0) 130 (123)

Sulfur 51 (48) 0.6 (0.6) 0 (0) 52 (49)

CO 2 0 (0)

- 79.7 (

- 75.5) 0 (0)

- 80 (

- 76)

Gasifier Heat Loss 0 (0) 44.5 (42.2) 0 (0) 45 (42)

Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)

HRSG Flue Gas 0 (0) 1,315 (1,247) 0 (0) 1,315 (1,247)

Cooling Tower* 0 (0) 2,097 (1,988) 0 (0) 2,097 (1,988)

Process Losses* * 0 (0) 681 (645) 0 (0) 681 (645)

Net Power 0 (0) 0.0 (0.0) 1,882 (1,784) 1,882

(1,784)

Totals 143 (136) 4,161 (3,944) 1,882 (1,784) 6,186

(5,863)

Note: Italicized numbers are estimated

Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction

air cooler. ** Calculated by difference to close the energy balance.Carbon Dioxide Capture Sensitivity Analysis



### 386 Exhibit 4

- 131 Case 2 D4A Energy Balanc e Sankey Diagram

Exhibit 4

- 132 Case 2 D4B Energy Balance Sankey DiagramCarbon Dioxide Capture Sensitivity Analysis



### 387 Exhibit 4

- 133 Case 2 D4C Energy Balance Sankey DiagramCarbon Dioxide Capture Sensitivity Analysis



### 388 This page intentionally left blankCarbon Dioxide Capture Sensitivity Analysis



### 389 4.3.4.2 Major Equipment List for Case 2 D4

Major equipment items for Case 2 D4 (two WGS reactors without bypass) are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cos t estimates. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contin gency for heads on pumps and fans.

ACCOUNT 1 COAL HANDLING

Equipment

No. Description Type Design Conditions Opr Qty. (Spares) D 4 A D 4 B D 4 C

1 Bottom Trestle Dumper and

Receiving Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0)

3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

4 Transfer Tower No. 1 Enclosed N/A N/A N/A 1 (0)

5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

6 As

- Received Coal Sampling

System Two

- stage N/A N/A N/A 1 (0)

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

8 Reclaim Hopper N/A 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 2 (1)

9 Feeder Vibratory 181 tonne/hr (200 tph) 181 tonne/hr (200 tph) 181 tonne/hr (200 tph) 2 (1)

10 Conveyor No. 3 Belt w/ tripper 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0)

11 Crusher Tower N/A N/A N/A N/A 1 (0)

12 Coal Surge Bin w/ Vent

Filter Dual outlet 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

13 Crusher Impactor

reduction 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 2 (0)

14 As

- Fired Coal Sampling

System Swing hammer N/A N/A N/A 1 (1)

15 Conveyor No. 4 Belt w/tripper 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0)

16 Transfer Tower No. 2 Enclosed N/A N/A N/A 1 (0)

17 Conveyor No. 5 Belt w/ tripper 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0)

18 Coal Silo w/ Vent Filter and

Slide Gates Field erected 816 tonne (900 ton) 816 tonne (900 ton) 816 tonne (900 ton) 3 (0)



### ACCOUNT 2 COAL PREPARATION AND FEED

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

1 Feeder Vibratory 82 tonne/h (90 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 3 (0)

2 Conveyor No. 6 Belt w/tripper 245 tonne/h (270 tph) 245 tonne/h (270 tph) 245 tonne/h (270 tph) 1 (0)

3 Rod Mill Feed Hopper Dual Outlet 490 tonne (540 ton) 481 tonne (530 ton) 481 tonne (530 ton) 1 (0)

4 Weigh Feeder Belt 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)

5 Rod Mill Rotary 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)

6 Slurry Water Storage

Tank with Agitator Field erected 299,921 liters (79,230 gal) 299,391 liters (79,090 gal) 299,201 liters (79,040 gal) 2 (0)

7 Slurry Water Pumps Centrifugal 833 lpm (220 gpm) 833 lpm (220 gpm) 833 lpm (220 gpm) 2 (1)

8 Trommel Screen Coarse 172 tonne/h (190 tph) 172 tonne/h (190 tph) 172 tonne/h (190 tph) 2 (0)Carbon Dioxide Capture Sensitivity Analysis



### 390 Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

9 Rod Mill Discharge Tank

with Agitator Field erected 392,323 liters (103,640 gal) 391,642 liters (103,460 gal) 391,377 liters (103,390 gal) 2 (0)

10 Rod Mill Product Pumps Centrifugal 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 2 (2)

11 Slurry Storage Tank with

Agitator Field erected 1,176,894 liters (310,900 gal) 1,175,001 liters (310,400 gal) 1,174,244 liters (310,200 gal) 2 (0)

12 Slurry Recycle Pumps Centrifugal 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 2 (2)

13 Slurry Product Pumps Positive displacement 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 2 (2)



### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

1 Demineralized Water Storage

Tank Vertical, cylindrical,

outdoor 1,093,984 liters (289,000 gal) 1,093,984 liters (289,000 gal) 1,093,984 liters (289,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 7,874 lpm @ 91 m H 2 O (2,080 gpm @ 300 ft H 2 O) 7,495 lpm @ 91 m H 2 O (1,980 gpm @ 300 ft H 2 O) 7,344 lpm @ 91 m H 2 O (1,940 gpm @ 300 ft H 2 O) 2 (1)

3 Deaerator (integral w/ HRSG) Horizontal spray type 546,579 kg/hr (1,205,000 lb/hr) 549,754 kg/hr (1,212,000 lb/hr) 551,568 kg/hr (1,216,000 lb/hr) 2 (0)

4 Intermediate Pressure

Feedwater Pump Horizontal centrifugal, single stage 8,025 lpm @ 27 m H 2 O (2,120 gpm @ 90 ft H 2 O) 8,063 lpm @ 27 m H 2 O (2,130 gpm @ 90 ft H 2 O) 8,063 lpm @ 27 m H 2 O (2,130 gpm @ 90 ft H 2 O) 2 (1)

5 High Pressure Feedwater Pump

No. 1 Barrel type, multi

stage, centrifugal HP water: 6,057 lpm @ 1,859 m H 2 O (1,600 gpm @ 6,100 ft H 2 O) HP water: 6,019 lpm @ 1,859 m H 2 O (1,590 gpm @ 6,100 ft H 2 O) HP water: 6,019 lpm @ 1,859 m

H 2 O (1,590 gpm @ 6,100 ft H 2 O) 2 (1)

6 High Pressure Feedwater Pump

No. 2 Barrel type, multi

stage, centrifugal IP water: 1,703 lpm @ 223 m H 2 O (450 gpm @ 730 ft H 2 O) IP water: 1,741 lpm @ 223 m H 2 O (460 gpm @ 730 ft H 2 O) IP water: 1,703 lpm @ 223 m H 2 O (450 gpm @ 730 ft H 2 O) 2 (1)

7 Auxiliary Boiler Shop fabricated, water

tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 (0)

8 Service Air Compressors Flooded Screw 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 (1)

9 Instrument Air Dryers Duplex, regenerative 28 m 3 /min (1,000 scfm) 28 m 3 /min (1,000 scfm) 28 m 3 /min (1,000 scfm) 2 (1)

10 Closed Cylce Cooling Heat

Exchangers Plate and frame 362 GJ/hr (343.5076381 MMBtu/hr)

each 375 GJ/hr (355.39736925 MMBtu/hr)

each 380 GJ/hr (360.46720325 MMBtu/hr) each 2 (0)

11 Closed Cycle Cooling Water

Pumps Horizontal centrifugal 130,218 lpm @ 21 m H 2 O (34,400 gpm @ 70 ft H 2 O) 134,382 lpm @ 21 m H 2 O (35,500 gpm @ 70 ft H 2 O) 136,275 lpm @ 21 m H 2 O (36,000 gpm @ 70 ft H 2 O) 2 (1)

12 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H 2 O (1,000 gpm @ 350 ft H 2 O) 3,785 lpm @ 107 m H 2 O (1,000 gpm @ 350 ft H 2 O) 3,785 lpm @ 107 m H 2 O (1,000 gpm @ 350 ft H 2 O) 1 (1)

13 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 76 m H 2 O (700 gpm @ 250 ft H 2 O) 2,650 lpm @ 76 m H 2 O (700 gpm @ 250 ft H 2 O) 2,650 lpm @ 76 m H 2 O (700 gpm @ 250 ft H 2 O) 1 (1)

14 Raw Water Pumps Stainless steel, single

suction 5,716 lpm @ 18 m H 2 O (1,510 gpm @ 60 ft H 2 O) 5,640 lpm @ 18 m H 2 O (1,490 gpm @ 60 ft H 2 O) 5,602 lpm @ 18 m H 2 O (1,480 gpm @ 60 ft H 2 O) 2 (1)

15 Ground Water Pumps Stainless steel, single

suction 2,839 lpm @ 268 m H 2 O (750 gpm @ 880 ft H 2 O) 2,801 lpm @ 268 m H 2 O (740 gpm @ 880 ft H 2 O) 2,801 lpm @ 268 m H 2 O (740 gpm @ 880 ft H 2 O) 3 (1)

16 Filtered Water Pumps Stainless steel, single

suction 3,369 lpm @ 49 m H 2 O (890 gpm @ 160 ft H 2 O) 3,331 lpm @ 49 m H 2 O (880 gpm @ 160 ft H 2 O) 3,331 lpm @ 49 m H 2 O (880 gpm @ 160 ft H 2 O) 2 (1)

17 Filtered Water Tank Vertical, cylindrical 1,608,800 liter (425,000 gal) 1,605,015 liter (424,000 gal) 1,601,229 liter (423,000 gal) 2 (0)

18 Makeup Water Demineralizer Anion, cation, and

mixed bed 1,476 lpm (390 gpm) 1,476 lpm (390 gpm) 1,476 lpm (390 gpm) 2 (0)

19 Liquid Waste Treatment System 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 1 (0)Carbon Dioxide Capture Sensitivity Analysis



### 391 ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

1 Gasifier Pressurized slurry

feed, entrained bed 2,903 tonne/day, 5.6 MPa (3,200 tpd, 814.96 psia) 2,903 tonne/day, 5.6 MPa (3,200 tpd, 814.96 psia) 2,903 tonne/day, 5.6 MPa (3,200 tpd, 814.96 psia) 2 (0)

2 Synthesis Gas Cooler Vertical downflow

radiant heat exchanger with outlet quench chamber 255,826 kg/hr (564,000 lb/hr) 255,373 kg/hr (563,000 lb/hr) 255,373 kg/hr (563,000 lb/hr) 2 (0)

3 Synthesis Gas Cyclone High efficiency 350,173 kg/hr (772,000 lb/hr) Design efficiency 90% 349,720 kg/hr (771,000 lb/hr) Design efficiency 90% 349,720 kg/hr (771,000 lb/hr) Design efficiency 90% 2 (0)

4 Candle Filter Pressurized filter with pulse

- jet cleaning metallic filters metallic filters metallic filters 2 (0)

5 Syngas Scrubber Including Sour

Water Stripper Vertical upflow 350,173 kg/hr (772,000 lb/hr) 349,720 kg/hr (771,000 lb/hr) 349,720 kg/hr (771,000 lb/hr) 2 (0)

6 Raw Gas Coolers Shell and tube with

condensate drain 388,275 kg/hr (856,000 lb/hr) 387,368 kg/hr (854,000 lb/hr) 387,368 kg/hr (854,000 lb/hr) 8 (0)

7 Raw Gas Knockout Drum Vertical with mist

eliminator 304,360 kg/hr, 35°C, 5.2 MPa (671,000 lb/hr, 95°F, 750 psia) 303,907 kg/hr, 35°C, 5.2 MPa (670,000 lb/hr, 95°F, 750 psia) 303,453 kg/hr, 35°C, 5.2 MPa (669,000 lb/hr, 95°F, 750 psia) 2 (0)

8 Flare Stack Self

- supporting,
carbon steel, stainless steel top, pilot ignition 350,173 kg/hr (772,000 lb/hr) syngas 349,720 kg/hr (771,000 lb/hr) syngas 349,720 kg/hr (771,000 lb/hr)

syngas 2 (0)

9 ASU Main Air Compressor Centrifugal, multi

stage 5,947 m 3 /min @ 1.3 MPa (210,000 scfm @ 190 psia) 5,947 m 3 /min @ 1.3 MPa (210,000 scfm @ 190 psia) 5,947 m 3 /min @ 1.3 MPa (210,000 scfm @ 190 psia) 2 (0)

10 Cold Box Vendor design 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2 (0)

11 Oxygen Compressor Centrifugal, multi

stage 1,189 m 3 /min (42,000 scfm)

Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940 psia) 1,189 m 3 /min (42,000 scfm)

Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940 psia) 1,189 m 3 /min (42,000 scfm)

Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940 psia) 2 (0)

12 Primary Nitrogen Compressor Centrifugal, multi

stage 3,794 m 3 /min (134,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 3,936 m 3 /min (139,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 3,964 m 3 /min (140,000 scfm)

Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 2 (0)

13 Secondary Nitrogen

Compressor Centrifugal, single

stage 538 m 3 /min (19,000 scfm)

Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 538 m 3 /min (19,000 scfm)

Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 538 m 3 /min (19,000 scfm)

Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 2 (0)

14 Syngas Dilution Nitrogen Boost

Compressor Centrifugal, single

stage 1,982 m 3 /min (70,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470 psia) 2,095 m 3 /min (74,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470 psia) 2,152 m 3 /min (76,000 scfm)

Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470 psia) 2 (0)



### ACCOUNT 5A SYNGAS CLEANUP

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

1 Mercury

Adsorber Sulfated carbon

bed 303,907 kg/hr (670,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 303,453 kg/hr (669,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 303,000 kg/hr (668,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 2 (0)

2 Sulfur Plant Claus type 146 tonne/day (161 tpd) 146 tonne/day (160 tpd) 146 tonne/day (160 tpd) 1 (0)

3 Water Gas Shift

Reactors Fixed bed,

catalytic 388,275 kg/hr (856,000 lb/hr) 227°C (440°F) 5.4 MPa (790 psia) 387,368 kg/hr (854,000 lb/hr) 227°C (440°F) 5.4 MPa (790 psia) 387,368 kg/hr (854,000 lb/hr) 227°C (440°F) 5.4 MPa (790 psia) 4 (0)Carbon Dioxide Capture Sensitivity Analysis



### 392 Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

4 Shift Reactor

Heat Recovery Exchangers Shell and Tube Exchanger 1: 157 GJ/hr (149 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) Exchanger 1: 157 GJ/hr (149 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) Exchanger 1: 157 GJ/hr (149 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 4 (0)

5 Acid Gas

Removal Plant Two

- stage

Selexol 310,711 kg/hr (685,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 324,772 kg/hr (716,000 lb/hr) 34°C (94°F) 5.1 MPa (740 psia) 330,669 kg/hr (729,000 lb/hr) 34°C (93°F) 5.1 MPa (740 psia) 2 (0)

6 Hydrogenation

Reactor Fixed bed,

catalytic 18,095 kg/hr (39,892 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 47,591 kg/hr (104,920 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 59,856 kg/hr (131,960 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 1 (0)

7 Tail Gas Recycle

Compressor Centrifugal 13,779 kg/hr (30,378 lb/hr) 43,068 kg/hr (94,949 lb/hr) 55,244 kg/hr (121,793 lb/hr) 1 (0)



### ACCOUNT 5B CO 2 

### COMPRESSION

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

1 CO 2 Compressor Integrally geared, multi

stage centrifugal 1,133 m 3 /min @ 15.3 MPa (40,000 scfm @ 2,215 psia) 1,189 m 3 /min @ 15.3 MPa (42,000 scfm @ 2,215 psia) 1,212 m 3 /min @ 15.3 MPa (42,800 scfm @ 2,215 psia) 4 (0)



### ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

1 Gas Turbine Advanced F class 230 MW 230 MW 230 MW 2 (0)

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV,

60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV,

60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV,

60 Hz, 3

- phase 2 (0)

3 Syngas Expansion

Turbine/Generator Turbo Expander 49,578 kg/h (109,300 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 36,333 kg/h (80,100 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 30,799 kg/h (67,900 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 2 (0)



### ACCOUNT 7 HRSG, DUCTING

, AND STACK

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

1 Stack CS plate, type

409SS liner 76 m (250 ft) high x 8.5 m (28 ft) diameter 76 m (250 ft) high x 8.5 m (28 ft) diameter 76 m (250 ft) high x 8.5 m (28 ft) diameter 1 (0)

2 Heat Recovery

Steam

Generator Drum, multi

pressure with

economizer section and integral

deaerator Main steam

- 341,834 kg/hr, 12.4 MPa/534°C (753,614 lb/hr, 1,800 psig/994°F)

Reheat steam

- 336,639 kg/hr, 3.1 MPa/534°C (742,162 lb/hr, 452 psig/994°F) Main steam

- 340,240 kg/hr, 12.4 MPa/533°C (750,102 lb/hr, 1,800 psig/991°F)

Reheat steam

- 335,536 kg/hr, 3.1 MPa/533°C (739,731 lb/hr, 452 psig/991°F) Main steam

- 339,6 79 kg/hr, 12.4 MPa/532°C (748,864 lb/hr, 1,800 psig/990°F)

Reheat steam

- 334,930 kg/hr, 3.1 MPa/532°C (738,395 lb/hr, 452 psig/990°F) 2 (0)Carbon Dioxide Capture Sensitivity Analysis



### 393 ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

1 Steam Turbine Commercially

available advanced

steam turbine 278 MW 12.4 MPa/534°C/534°C (1,800 psig/ 994°F/994°F) 270 MW 12.4 MPa/533°C/533°C (1,800 psig/ 991°F/991°F) 267 MW 12.4 MPa/532°C/532°C (1,800 psig/ 990°F/990°F) 1 (0)

2 Steam Turbine

Generator Hydrogen cooled,

static excitation 310 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 300 MVA @ 0.9 p.f., 24 kV, 60

Hz, 3

- phase 300 MVA @ 0.9 p.f., 24 kV, 60
Hz, 3

- phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design

steam conditions 50% steam flow @ design

steam conditions 50% steam flow @ design

steam conditions 2 (0)

4 Surface

Condenser Single pass, divided

waterbox including

vacuum pumps 1,667 GJ/hr (1,580 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise

11°C (20°F) 1,583 GJ/hr (1,500 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise

11°C (20°F) 1,540 GJ/hr (1,460 MMBtu/hr),

Inlet water temperature 16°C (60°F), Water temperature rise

11°C (20°F) 1 (0)



### ACCOUNT 9 COOLING WATER SYSTEM

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

1 Circulating Water Pumps Vertical, wet pit 461,820 lpm @ 30 m (122,000 gpm @ 100 ft) 458,035 lpm @ 30 m (121,000 gpm @ 100 ft) 454,249 lpm @ 30 m (120,000 gpm @ 100 ft) 2 (1)

2 Cooling Tower Evaporative,
mechanical draft,

multi

- cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,585 GJ/hr (2,450 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,543 GJ/hr (2,410 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,532 GJ/hr (2,400 MMBtu/hr) heat duty 1 (0)



### ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

1 Slag Quench Tank Water bath 253,623 liters (67,000 gal) 253,623 liters (67,000 gal) 253,623 liters (67,000 gal) 2 (0)

2 Slag Crusher Roll 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

3 Slag Depressurizer Lock Hopper 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

4 Slag Receiving Tank Horizontal, weir 151,416 liters (40,000 gal) 151,416 liters (40,000 gal) 151,416 liters (40,000 gal) 2 (0)

5 Black Water Overflow

Tank Shop fabricated 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)

6 Slag Conveyor Drag chain 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

7 Slag Separation

Screen Vibrating 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

8 Coarse Slag

Conveyor Belt/bucket 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

9 Fine Ash Settling

Tank Vertical, gravity 215,768 liters (57,000 gal) 215,768 liters (57,000 gal) 215,768 liters (57,000 gal) 2 (0)

10 Fine Ash Recycle

Pumps Horizontal centrifugal 38 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 38 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 38 lpm @ 14 m H 2 O (10 gpm @ 46 ft H 2 O) 2 (2)

11 Grey Water Storage

Tank Field erected 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H 2 O (60 gpm @ 1,850 ft H 2 O) 227 lpm @ 564 m H 2 O (60 gpm @ 1,850 ft H 2 O) 227 lpm @ 564 m H 2 O (60 gpm @ 1,850 ft H 2 O) 2 (2)Carbon Dioxide Capture Sensitivity Analysis



### 394 Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

13 Slag Storage Bin Vertical, field erected 998 tonne (1,100 tons) 998 tonne (1,100 tons) 998 tonne (1,100 tons) 2 (0)

14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 1 (0)



### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

1 CTG Step

- up
Transformer Oil

- filled 24 kV/345 kV, 260 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 260 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 260 MVA,

3

- ph, 60 Hz 2 (0)

2 STG Step

- up

Transformer Oil

- filled 24 kV/345 kV, 310 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 300 MVA,

3

- ph, 60 Hz 24 kV/345 kV, 300 MVA,

3

- ph, 60 Hz 1 (0)

3 High Voltage Auxiliary

Transformer Oil

- filled 345 kV/13.8 kV, 80 MVA,

3

- ph, 60 Hz 345 kV/13.8 kV, 82 MVA,

3

- ph, 60 Hz 345 kV/13.8 kV, 82 MVA,

3

- ph, 60 Hz 2 (0)

4 Medium Voltage

Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 48 MVA,

3

- ph, 60 Hz 24 kV/4.16 kV, 53 MVA,

3

- ph, 60 Hz 24 kV/4.16 kV, 55 MVA,

3

- ph, 60 Hz 1 (1)

5 Low Voltage

Transformer Dry ventilated 4.16 kV/480 V, 7 MVA,

3

- ph, 60 Hz 4.16 kV/480 V, 8 MVA,

3

- ph, 60 Hz 4.16 kV/480 V, 8 MVA,

3

- ph, 60 Hz 1 (1)

6 CTG Isolated Phase

Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 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 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 1 (0)

8 Medium Voltage

Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 1 (1)

9 Low Voltage

Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 1 (1)

10 Emergency Diesel

Generator Sized for emergency
shutdown 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 1 (0)



### ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment

No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

1 DCS

- Main

Control Monitor/keyboard;

Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers Operator stations/printers and engineering stations/printers Operator stations/p rinters and engineering stations/printers 1 (0)

2 DCS

-

Processor Microprocessor with

redundant input/output N/A N/A N/A 1 (0)

3 DCS

- Data

Highway Fiber optic Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare 1 (0)Carbon Dioxide Capture Sensitivity Analysis



### 395 

## 4.3.5 Economic Analysis for the GEE IGCC Cases

The capital and operating costs for Case 2 Designs 1

- 4 are presented in Section 4.3.6 . A cost and performance summary table ( Exhibit 4

- 162 ) for the GEE IGCC cases is show n in Section 4.3.7

.



## 4.3.6 Capital and Operating Cost Results

The capital and operating costs for Case 2 Designs 1

- 4 are shown in Exhibit 4

- 134 through

Exhibit 4

- 161

. The capital costs for each case include the total plant cost (TPC), the owner‟s
costs, the total overnight cost (TOC), and the total as

- spent capital (TASC) cost. The c apital and operating cost estimating methodology is explained in Section 2.7

.Carbon Dioxide Capture Sensitivity Analysis



### 396 Exhibit 4

- 134 Case 2 D1A (0%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 397 Exhibit 4

- 134 Case 2 D1A (0%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 398 Exhibit 4

- 134 Case 2 D1A (0%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 399 Exhibit 4

- 134 Case 2 D1A (0%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 400 Exhibit 4

- 135 Case 2 D1A Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 401 Exhibit 4

- 136 Case 2 D1B (25%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 402 Exhibit 4

- 136 Case 2 D1B (25%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 403 Exhibit 4

- 136 Case 2 D1B (25%) Capital Costs (continue d)Carbon Dioxide Capture Sensitivity Analysis



### 404 Exhibit 4

- 136 Case 2 D1B (25%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 405 Exhibit 4

- 137 Case 2 D1B Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 406 Exhibit 4

- 138 Case 2 D2A (25%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 407 Exhibit 4

- 138 Case 2 D2A (25%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 408 Exhibit 4

- 138 Case 2 D2A (25%) Capital Costs (continue d)Carbon Dioxide Capture Sensitivity Analysis



### 409 Exhibit 4

- 138 Case 2 D2A (25%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 410 Exhibit 4

- 139 Case 2 D2A Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 411 Exhibit 4

- 140 Case 2 D2B (45%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 412 Exhibit 4

- 140 Case 2 D2B (45%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 413 Exhibit 4

- 140 Case 2 D2B (45%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 414 Exhibit 4

- 140 Case 2 D2B (45%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 415 Exhibit 4

- 141 Case 2 D2B Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 416 Exhibit 4

- 142 Case 2 D2C (60%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 417 Exhibit 4

- 142 Case 2 D2C (60%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 418 Exhibit 4

- 142 Case 2 D2C (60%) Capital Costs (continue d)Carbon Dioxide Capture Sensitivity Analysis



### 419 Exhibit 4

- 142 Case 2 D2C (60%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 420 Exhibit 4

- 143 Case 2 D2C Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 421 Exhibit 4

- 144 Case 2 D2D (75%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 422 Exhibit 4

- 144 Case 2 D2D (75%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 423 Exhibit 4

- 144 Case 2 D2D (75%) Capital Costs (continue d)Carbon Dioxide Capture Sensitivity Analysis



### 424 Exhibit 4

- 144 Case 2 D2D (75%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 425 Exhibit 4

- 145 Case 2 D2D Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 426 Exhibit 4

- 146 Case 2 D3A (25%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 427 Exhibit 4

- 146 Case 2 D3A (25%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 428 Exhibit 4

- 146 Case 2 D3A (25%) Capital Costs (continue d)Carbon Dioxide Capture Sensitivity Analysis



### 429 Exhibit 4

- 146 Case 2 D3A (25%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 430 Exhibit 4

- 147 Case 2 D3A Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 431 Exhibit 4

- 148 Case 2 D3B (45%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 432 Exhibit 4

- 148 Case 2 D3B (45%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 433 Exhibit 4

- 148 Case 2 D3B (45%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 434 Exhibit 4

- 148 Case 2 D3B (45%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 435 Exhibit 4

- 149 Case 2 D3B Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 436 Exhibit 4

- 150 Case 2 D3C (60%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 437 Exhibit 4

- 150 Case 2 D3C (60%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 438 Exhibit 4

- 150 Case 2 D3C (60%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 439 Exhibit 4

- 150 Case 2 D3C (60%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 440 Exhibit 4

- 151 Case 2 D3C Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 441 Exhibit 4

- 152 Case 2 D3D (75%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 442 Exhibit 4

- 152 Case 2 D3D (75%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 443 Exhibit 4

- 152 Case 2 D3D (75%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 444 Exhibit 4

- 152 Case 2 D3D (75%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 445 Exhibit 4

- 153 Case 2 D3D Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 446 Exhibit 4

- 154 Case 2 D3E (85%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 447 Exhibit 4

- 154 Case 2 D3E (85%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 448 Exhibit 4

- 154 Case 2 D3E (85%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 449 Exhibit 4

- 154 Case 2 D3E (85%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 450 Exhibit 4

- 155 Case 2 D3E Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 451 Exhibit 4

- 156 Case 2 D4A (90%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 452 Exhibit 4

- 156 Case 2 D4A (90%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 453 Exhibit 4

- 156 Case 2 D4A (90%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 454 Exhibit 4

- 156 Case 2 D4A (90%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 455 Exhibit 4

- 157 Case 2 D4A Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 456 Exhibit 4

- 158 Case 2 D4B (95%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 457 Exhibit 4

- 158 Case 2 D4B (95%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 458 Exhibit 4

- 158 Case 2 D4B (95%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 459 Exhibit 4

- 158 Case 2 D4B (95%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 460 Exhibit 4

- 159 Case 2 D4B Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 461 Exhibit 4

- 160 Case 2 D4C (97%) Capital CostsCarbon Dioxide Capture Sensitivity Analysis



### 462 Exhibit 4

- 160 Case 2 D4C (97%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 463 Exhibit 4

- 160 Case 2 D4C (97%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 46 4 Exhibit 4

- 160 Case 2 D4C (97%) Capital Costs (continued)Carbon Dioxide Capture Sensitivity Analysis



### 465 Exhibit 4

- 161 Case 2 D4C Initial and Annual O&M ExpensesCarbon Dioxide Capture Sensitivity Analysis



### 466 This page intentionally left blankCarbon Dioxide Capture Sensitivity Analysis



### 467 

## 4.3.7 GEE IGCC Cost and Performance Summary

A summary of plant costs and performance for the GEE IGCC cases is shown in Exhibit 4

- 162

.

Exhibit 4

- 162 Cost and Performance Results for the GEE IGCC Cases

Case 2

- D1A 2

- D1B 2

- D2A 2

- D2B 2

- D2C 2

- D2D 2

- D3A 2

- D3B 2

- D3C 2

- D3D 2

- D3E 2

- D4A 2

- D4B 2

- D4C

CO 2 Capture, % 0% 25% 25% 45% 60% 75% 25% 45% 60% 75% 85% 90% 95% 97%

Gross Power Output, MW

e 747.8 750.4 750.4 746.9 745.2 742.0 750.4 746.2 744.2 741.6 739.8 734.0 726.6 723.6

Net Power Output, MW

e 622.0 607.2 607.0 590.8 578.4 563.9 607.0 590.0 577.4 563.8 554.5 543.2 528.5 522.9

Net Plant Efficiency, % (HHV) 39.0 38.4 38.4 36.8 35.5 34.3 38.4 36.7 35.5 34.2 33.4 32.6 31.8 31.5

Net Plant Heat Rate, Btu/kWh (HHV) 8,756 8,891 8,895 9,283 9,604 9,958 8,894 9,289 9,614 9,969 10,222 10,459 10,731 10,840

Coal Flowrate (lb/hr) 466,861 462,752 462,861 470,117 476,133 481,355 462,783 469,844 475,867 481,779 485,836 487,026 486,169 485,856

Total CO 2 Captured, lb/MWh net NA 425 430 809 1,127 1,476 429 810 1,125 1,467 1,710 1,899 2,159 2,269

CO 2 Capture & Compression Cost, $x1000 0 $ 166,439 $ 166,741 $ 193,350 $ 212,092 $ 231,604 $ 167,196 $ 194,185 $ 212,378 $ 230,775 $ 242,919 $ 251,958 $ 264,505 $ 228,358

Total Plant Cost, $x1000 $ 1,235,944 $ 1,345,298 $ 1,346,066 $ 1,389,128 $ 1,419,771 $ 1,449,191 $ 1,346,380 $ 1,390,235 $ 1,419,640 $ 1,447,904 $ 1,465,871 $ 1,472,866 $ 1,483,871 $ 1,488,149

Owner’s Costs, $x1000 $286,161 $308,679 $308,860 $319,113 $326,535 $333,624 $308,914 $319,358 $326,551 $333,508 $337,972 $338,851 $341,323 $342,287

Total Overnight Cost, $x1000 $1,522,105 $1,653,977 $1,654,925 $1,708,241 $1,746,306 $1,782,815 $1,655,294 $1,709,592 $1,746,192 $1,781,411 $1,803,843 $1,811,717 $1,825,194 $1,830,436

Total Overnight Cost, $/kW $2,447 $2,724 $2,726 $2,891 $3,019 $3,161 $2,727 $2,897 $3,024 $3,160 $3,253 $3,335 $3,453 $3,501

Total As

- Spent Capital, $x1000 $1,735,200 $1,885,534 $1,886,615 $1,947,394 $1,990,789 $2,032,409 $1,887,035 $1,948,935 $1,990,658 $2,030,809 $2,056,381 $2,065,358 $2,080,721 $2,086,697

Total As

- Spent Capital, $/kW $2,790 $3,105 $3,108 $3,296 $3,442 $3,604 $3,109 $3,303 $3,447 $3,602 $3,709 $3,802 $3,937 $3,991

CO 2 Capital Cost Penalty a , $/kW $0 $277 $279 $444 $572 $715 $280 $450 $577 $713 $806 $888 $1,007 $1,054

Cost of Electricity b

, mills /kWh 76.3 85.3 85.4 90.8 95.2 100.0 85.4 91.0 95.3 100.0 103.1 105.7 109.3 110.8

COE CO 2 Penalty a

, mills /kWh NA 9.0 9.1 14.5 18.9 23.7 9.1 14.7 19.0 23.7 26.8 29.4 33.0 34.4

Percent increase in COE a , % NA 11.8% 11.9% 19.0% 24.7% 31.0% 12.0% 19.2% 24.9% 31.0% 35.1% 38.5% 43.3% 45.1%

Cost of CO 2 Avoided a , $/tonne NA 48.7 48.6 44.9 43.1 42.5 48.7 45.4 43.6 42.5 41.7 42.7 45.2 46.0

CO 2 Emissions, lb/MMBtu 196.8 147.8 147.3 108.8 78.9 49.7 147.3 108.8 79.2 49.7 30.1 19.7 10.4 6.5

CO 2 Emissions, lb/MWh net 1,723 1,314 1,310 1,010 758 495 1,310 1,011 762 496 308 206 112 71

SO 2 Emissions, lb/MMBtu 0.005 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002

SO 2 Emissions, lb/MWh 0.040 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020

NOx Emissions, lb/MMBtu 0.059 0.055 0.055 0.053 0.051 0.050 0.055 0.053 0.052 0.050 0.049 0.049 0.049 0.049

NOx Emissions, lb/MWh 0.430 0.397 0.397 0.390 0.384 0.379 0.397 0.391 0.385 0.379 0.375 0.376 0.380 0.382

PM Emissions, lb/MMBtu 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071

PM Emissions, lb/MWh 0.052 0.051 0.051 0.052 0.053 0.054 0.051 0.052 0.053 0.054 0.054 0.055 0.055 0.056

Hg Emissions, lb/TBtu 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571

Hg Emissions, lb/TWh 4.16 4.11 4.11 4.20 4.26 4.32 4.11 4.20 4.26 4.33 4.38 4.42 4.46 4.48

Raw Water Withdrawal, gpm 4,734 4,692 4,697 5,038 5,300 5,530 4,695 5,040 5,307 5,569 5,748 5,817 5,739 5,707

Raw Water Consumption, gpm 3,755 3,722 3,727 4,033 4,270 4,481 3,725 4,034 4,276 4,514 4,677 4,741 4,679 4,654

Raw Water Consumption, gal/MWh net 362 368 368 410 443 477 368 410 444 480 506 524 531 534

a Relative to Case 2 D1A ( IGCC 0% CO 2 capture) b Capacity factor is 80% for the GEE IGCC casesCarbon Dioxide Capture Sensitivity Analysis



### 468 This page intentionally left blankCarbon Dioxide Capture Sensitivity Analysis



### 469 

# 5. Results

The objective of this study was to ident ify the optimal CO 2 

### capture level at new SC PC and

IGCC power plants by employing state

- of

- the

- art control technologies in multiple process configurations. The SC PC cases (Case 1) utilize Fluor‟s Econamine FG Plus SM 

### process for

post

- combustion CO 2 

### capture, while t he IGCC cases (Case 2) employ a slurry

- fed, entrained

fl ow GEE gasifier and leverage UOP‟s two

- stage SelexolTM process for pre

- combustion CO 2 

### capture

.

T he major results from the CO 2 

### capture sensitivity analysis are discussed below in the following

order:

Performance (efficiency)

Economics (total overnight cost, cost of electricity, and CO 2 

### avoided cost)

Performance and Cost summary



## 5.2 Performance

5.2.1 Energy Efficiency

The net plant HHV efficiencies for the SC PC and GEE IGCC cases are presented in Exhibit 5

- 1

and Exhibit 5

- 2 , respectively

. As the CO 2 

### capture requirement is increased for either plant type,

PC or IGCC, there is an increase in the auxiliary power required to support the capture equipment (either Econamine or Selexol TM ) and the CO 2 

### compressor trains. Further, more steam is consumed by the capture equipment, and by the WGS reactor(s) in the IGCC case, making less available for supply to the steam turbine. Both effects (higher auxiliary load and reduced steam supply to the turbine) detract from the net power produced by the plant per unit of coal energy input, as evidenced by the predicted net plant HHV efficiency trends v ersu s CO 2 

### capture level

.Carbon Dioxide Capture Sensitivity Analysis



### 470 Exhibit 5

- 1 Net Plant HHV Efficiency for the Supercritical PC CasesCarbon Dioxide Capture Sensitivity Analysis



### 471 Exhibit 5

- 2 Net Plant HHV Efficiency for the GEE IGCC Cases



## 5.3 Econom ics

5.3.1 Total Overnight Cost

All capital costs are presented as “overnight costs” expressed in J une 2007 dollars. The c apital costs are presented at the TOC level, which includes: (1) e quipment (complete with initial

c hemical and catalyst loadings); (2) m a terials; (3) labor (direct and indirect); (4) e ngineering and construction management; (5) c ont ingencies (process and project); and (6) owner‟s costs

. The
owner‟s costs, which are summarized in Exhibit 2

- 18 , include preproduction costs, inventory capital, land costs, financing costs, initial cost for catalysts/chemicals, taxes and insurances, and

other owner‟s costs.

The TOC for the SC PC and GEE IGCC cases are presented in Exhibit 5

- 3 and Exhibit 5

- 4

, respectively. These exhibits categorize d the TOC into five categories: (1) bare erected cost ; (2) engineering, home offi ce, CM , and fee; (3) project contingency; (4) process contingency; and (5)

owner‟s costs.Carbon Dioxide Capture Sensitivity Analysis



### 472 The SC PC Ca se 1 TOC estimates apply to facilities designed with a fixed 550 MW net capacity. As the design is equipped for increased CO 2 

### capture, moving from Case 1A through Case 1G,

the TOC also increase s as a result of the need for larger power plant components for power generation to offset the auxiliary power and steam requirements of the CO 2 

### capture and compression systems . Hence

, the increase in installed TOC per net kW delivered.

Exhibit 5

- 3 TOC for the Supercritical PC Cases



### The Ca se 2 GEE IGCC TOC estimates apply to facilities d esigned with a fixed gross combustion

turbine capacity of 464 MW . As the plant is equipped for increased CO 2 

### capture, moving from

Case 2 D1A through Case 2 D4C , the TOC also increase s as a res ult of the need for larger plant components for pow er generation to offset the auxiliary power and steam requirements of the
WGS reactor(s) and the CO 2 

### capture and compression systems . Hence

, the increase in installed TOC per net kW delivered.Carbon Dioxide Capture Sensitivity Analysis



### 473 Exhibit 5

- 4 TOC for the GEE IGCC Cases



## 5.3.2 Cost of Electricity

The revenue requirement figure

- of

- merit in this report is COE expressed in mills/kWh (numerically equivalent to $/MWh). The capital expenditure and operating periods for SC PC and IGCC power plants are 5 and 30 years, respectively. The costs associated with CO 2 

### TS&M are included for all capture cases. All costs are expressed in June 2007 dollars, and the resulting

COE is also expressed in June 2007 year dollars.

The COE for the SC PC and GEE IGCC cases are presented in Exhibit 5

- 5 and Exhibit 5

- 6

, respectively. These exhibits categorized the COE into five categories: (1) capital costs; (2) fixed
costs; (3) variable costs; (4) fuel costs; and (5) CO 2 

### TS&M costs.

The COE estimates are based on capacity factors of 85 and 80 percent for the SC PC and GEE IGCC cases, respectively.Carbon Dioxide Capture Sensitivity Analysis



### 474 Exhibit 5

- 5 COE for the Supercritical PC CasesCarbon Dioxide Capture Sensitivity Analysis



### 475 Exhibit 5

- 6 COE for the GEE IGCC Cases



### The CO 2 

### TS&M cost s were developed using reference data and scaled estimates , as discussed in

Section 2.7 . In general, the CO 2 

### TS&M costs account for about two to three p ercent of the total

COE . A breakdown of the CO 2 

### TS&M costs for the SC PC and GEE IGCC cases are shown in

Exhibit 5

- 7 and Exhibit 5

- 8 , respectively

.

Exhibit 5

- 7 CO 2 TS&M COE for the Supercritical PC Cases

Study Case (CO 2 Capture Level) mills /kWh

CO 2 Transport CO 2

Storage CO 2

Monitoring TS&M

COE Total

COE

Case 1A (30%) 1.84 0.77 0.30 2.92 76.64

Case 1B (50%) 2.06 1.04 0.55 3.64 84.38

Case 1C (70%) 2.55 1.38 0.82 4.75 92.75

Case 1D (85%) 2.55 1.64 1.05 5.24 101.49

Case 1E (90%) 2.83 1.74 1.14 5.71 104.29

Case 1F (95%) 2.83 1.84 1.24 5.91 107.00

Case 1G (99%) 2.83 1.99 1.38 6.20 112.65Carbon Dioxide Capture Sensitivity Analysis



### 476 Exhibit 5

- 8 CO 2 TS&M COE for the GEE IGCC Cases

Study Case (CO 2 Capture Level) mills /kWh

CO 2 Transport CO 2

Storage CO 2

Monitoring TS&M

COE Total

COE

Case 2 D1A (0%) 0.00 0.00 0.00 0.00 76.31

Case 2 D1B (25%) 1.77 0.67 0.23 2.67 85.35

Case 2 D2A (25%) 1.78 0.67 0.23 2.68 85.41

Case 2 D2B (45%) 2.03 0.90 0.43 3.36 90.83

Case 2 D2C (60%) 2.31 1.08 0.59 3.98 95.16

Case 2 D2D (75%) 2.64 1.28 0.76 4.68 99.98

Case 2 D3A (25%) 1.78 0.67 0.23 2.68 85.43 Case 2 D3B (45%) 2.04 0.90 0.43 3.36 90.99 Case 2 D3C (60%) 2.32 1.09 0.59 3.99 95.31 Case 2 D3D (75%) 2.64 1.28 0.76 4.68 99.96 Case 2 D3E (85%) 2.68 1.48 0.89 5.05 103.08 Case 2 D4A (90%) 2.74 1.57 0.96 5.27 105.70 Case 2 D4B (95%) 2.82 1.67 1.04 5.53 109.32 Case 2 D4C (97%) 2.85 1.72 1.07 5.63 110.75



## 5.3.3 CO 2 

## Avoided Costs

The CO 2 

### avoided cost was calculated as illustrated in Equation 1.

( 1 )

The CO 2 

### avoided costs for the SC PC and GEE IGCC cases are presented in Exhibit 5

- 9 and

Exhibit 5

- 10 , respectively. The IGCC cases are presented both relative to the equivalent IGCC without carbon capture and SC PC without capture plants. For the SC PC plant, the CO 2 

### avoided

costs decrease as the CO 2 

### capture level increases until reaching minimum values at 95 percent
capture (Case 1F).Carbon Dioxide Capture Sensitivity Analysis



### 477 Exhibit 5

- 9 CO 2 Avoided Costs for the Supercritical PC Cases



### The CO 2 

### avoided costs for the GEE IGCC cases decrease as the CO 2 

### capture level increases, until reaching minimum values at 85 to 90 percent capture (Cases D3E and D4A). As a result, this analysis concludes that 85 to 90 percent is the optimal CO 2 

### capture level f or a GEE IGCC power plant.Carbon Dioxide Capture Sensitivity Analysis



### 478 Exhibit 5

- 10 CO 2 Avoided Costs for the GEE IGCC Cases



## 5.4 Cost a nd Performance Summary

The following conclusions can be drawn from this analysis.



## 5.4.1 Supercritical PC Cases

 The „slip

- stream‟ approach is more cost

- effective for <90 percent CO 2 

### capture than removing reduced CO 2 

### fractions from the entire flue gas stream. The cost of CO 2 

### ca pture

with the Econamine process is dependent on the volume of gas being treated and a

reducti on in flue gas flow rate will: (1) decrease the quantity of energy consumed by flue gas blowers; (2) reduce the size of the CO 2 

### absorption columns; (3) trim the cooling water requirement of the direct contact cooling system; and (4) decrease the amount of

fan power required to increase flue gas temperature and plume buoyancy.

 With partial bypass around the Econamine system, CO 2 

### capture is limited to 85 percent

. To achieve 90 percent or greater CO 2 

### capture, the entire flue gas stream must be treated.

 On a $/ton ne CO 2 

### avoided basis, 95 percent (Case 1F) is the optimal CO 2 

### capture level.Carbon Dioxide Capture Sensitivity Analysis



### 479 

## 5.4.2 GEE IGCC Cases

 For the GEE gasifier, CO 2 

### capture is limited to 25 percent without WGS.

 Due to the high level of integration between the H 2 

### S and CO 2 

### absorbers in the two

- stage SelexolTM system ( see Exhibit 4

- 8 ), it is assumed in this analysis that it is not possible to operate the two stages indepe ndently, and therefore is not feasible to model 0 percent

CO 2 

### capture with this system. Since the first stage is designed to operate synergistically

with the second, some level of CO 2 

### removal is unavoidable.

 With a S:DG ratio of 0.25, CO 2 

### capture is lim ited to: (1) 75 percent with one

- stage WGS;
and (2) 85 percent with two

- stage WGS and five percent WGS bypass.

 For 90 percent or greater CO 2 

### capture, two WGS reactors without bypass and a S:DG ratio of 0.3 are required.

 The performance and cost for interme diate levels of CO 2 

### capture (25 to 75 percent ) are

similar with one

- and two

- stage WGS. The two

- stage WGS system requires more shift

steam for the two reactors, but the one

- stage WGS system requires a larger COS hydrolysis unit to treat the entire syngas stream, which adds capital cost.

 On a $/ton ne CO 2 

### avoided basis, 85 to 90 percent is the optimal CO 2 

### capture level.



## 5.4.3 SCPC and IGCC Comparisons

The following conclusions can be drawn from this analysis.

At all levels of carbon capture considered in this analysis, an IGCC plant will operate more efficiently than a SC PC plant. This higher efficiency results in lower fuel costs and reduced coal handling costs for the same level of power output.

At lower levels of CO 2 

### capture, the COE of a SC PC plant is le ss than an IGCC plant. However this COE advantage begins to disappear as capture level increases. For CCS greater than approximately 90 percent, IGCC and SC PC have costs of electricity that are nearly equal. This same trend applies to plant capital cos ts (expressed in $/kW).

CO 2 

### avoided costs, using analogous non

- capture plants as reference, are substantially lower for IGCC than for SC PC, for all levels of capture. This is reflective of the relatively lower cost impact associated with adding CO 2 

### contr ols to an IGCC plant compared to SC PC. However, the avoided CO 2 

### costs for IGCC capture plants, using the

SC PC non

- capture reference plant, are higher due to the higher COE of non

- capture IGCC plants.

CO 2 

### avoided costs for SC PC plants are high for low levels of CCS, and then start to diminish as the capture increases. Gradually, a minimum is reached around 95% CCS, before costs start to rise again slightly. This suggests that if a SC PC plant will lay outCarbon Dioxide Capture Sensitivity Analysis



### 480 the additional capital required to install CO 2 

### controls, that equipment could be used most

cost

- effectively by capturing as much carbon dioxide as possible (up to about 95%).

CO 2 

### avoided costs for IGCC (relative to an IGCC non

- capture plant) are less volatile than SC PC over a wide range of capture. Although they generally decrease as the level of CCS increases (similar to SC PC), the spread between the high and low values is small relative to SC PC. Since an IGCC system is a more complex process, it better lends itself to optimization than a SC PC plant. To accommodate the specified level of CO 2 

### capture, there were numerous variables that were manipulated simultaneously (including the number of water gas shift reactors, the amount of shift steam required, solvent circulation rate, and the syngas by pass rate) to minimize the cost and performance impact. The SC PC plant, although in most cases less expensive than IGCC, is a simpler process and therefore exhibits less potential for optimization.

A summary of SC PC and GEE IGCC plant costs and perfor mance are shown in Exhibit 5

- 11

and Exhibit 5

- 12 , resp ectively

.Carbon Dioxide Capture Sensitivity Analysis



### 481 Exhibit 5

- 11 Cost and Performance Results for the Supercritical PC Cases

Case 0 1A 1B 1C 1D 1E 1F 1G

CO 2 Capture, % 0% 30% 50% 70% 85% 90% 95% 99%

Gross Power Output, MW
e 580.4 601.5 618.2 637.8 654.8 661.3 667.9 679.6

Net Power Output, MW
e 550.0 550.0 550.0 550.0 550.1 550.0 550.0 550.0

Net Plant Efficiency, % (HHV) 39.3 35.2 32.9 30.6 28.9 28.2 27.5 25.7

Net Plant Heat Rate, Btu/kWh (HHV) 8,687 9,695 10,379 11,151 11,819 12,083 12,400 13,269

Coal Flowrate (lb/hr) 409,550 457,066 489,316 525,764 557,283 569,672 584,578 625,561

Total CO 2 Captured, lb/MWh net NA 588 1,057 1,582 2,037 2,213 2,398 2,674

CO 2 Capture & Compression Cost, $x1000 NA $ 190,138 $ 266,902 $ 336,794 $ 441,781 $ 463,389 $ 485,273 $ 516,797

Total Plant Cost, $x1000 $905,901 $1,138,688 $1,258,942 $1,378,696 $1,525,453 $1,562,889 $1,602,389 $1,678,914

Owner’s Costs, $x1000 $207,800 $258,649 $285,448 $312,458 $344,744 $353,249 $362,267 $380,090

Total Overnight Cost, $x1000 $1,113,701 $1,397,338 $1,544,390 $1,691,155 $1,870,197 $1,916,138 $1,964,657 $2,059,004

Total Overnight Cost, $/kW $2,025 $2,541 $2,808 $3,075 $3,400 $3,484 $3,572 $3,744

Total As

- Spent Capital, $x1000 $1,262,937 $1,592,965 $1,760,604 $1,927,917 $2,132,024 $2,184,397 $2,239,708 $2,347,264

Total As

- Spent Capital, $/kW $2,296 $2,896 $3,201 $3,505 $3,876 $3,972 $4,072 $4,268

CO 2 Capital Cost Penalty a , $/kW NA $516 $783 $1,050 $1,375 $1,459 $1,548 $1,719

Cost of Electricity b , mills/kWh 58.90 76.64 84.38 92.75 101.49 104.29 107.00 112.65

COE CO 2 Penalty a , mills/kWh NA 17.7 25.5 33.8 42.6 45.4 48.1 53.8

Percent increase in COE a , % NA 30.1 43. 3 57. 5 72.3 77. 1 81. 7 91. 3

Cost of CO 2 Avoided a , $/tonne N A 102.8 79.1 69.2 67.2 65.9 64.7 68.2

CO2 Emissions, lb/MMBtu 203.2 142.9 101.7 61.7 31.2 20.4 10.2 2.0

CO 2 Emi ssions , lb/MWh net 1,765 1,385 1,055 687 369 246 126 27

SO 2 Emissions, lb/MMBtu 0.086 0.064 0.050 0.036 0.017 0.017 0.016 0.016

SO 2 Emissions, lb/MWh 0.75 0.570 0.460 0.340 0.170 0.170 0.170 0.170

NOx Emissions, lb/MMBtu 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070

NOx Emissions, lb/MWh 0.608 0.621 0.646 0.673 0.695 0.703 0.715 0.752

PM Emissions, lb/MMBtu 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013

PM Emissions, lb/MWh 0.113 0.115 0.120 0.125 0.129 0.131 0.133 0.140

Hg Emissions, lb/TBtu 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14

Hg Emissions, lb/TWh 9.93 10.1 10.6 11.0 11.3 11.5 11.7 12.3

Raw Water Withdrawal, gpm 5,394 6,245 6,987 8,386 9,615 10,095 10,512 11,664

Raw Water Consumption, gpm 4,301 4,898 5,433 6,474 7,392 7,753 8,074 8,961

Raw Water Consumption, gal/MWh net 469 534 593 706 806 846 881 978

a Relative to Case 0 ( SC PC without capture from 20 10 Bituminous Baseline study)

b Capacity factor is 85% for the SC PC casesCarbon Dioxide Capture Sensitivity Analysis



### 482 Exhibit 5

- 12 Cost and Performance Results for the GEE IGCC Cases

Case 2

- D1A 2

- D1B 2

- D2A 2

- D2B 2

- D2C 2

- D2D 2

- D3A 2

- D3B 2

- D3C 2

- D3D 2

- D3E 2

- D4A 2

- D4B 2

- D4C

CO 2 Capture, % 0% 25% 25% 45% 60% 75% 25% 45% 60% 75% 85% 90% 95% 97%

Gross Power Output, MW
e 747.8 750.4 750.4 746.9 745.2 742.0 750.4 746.2 744.2 741.6 739.8 734.0 726.6 723.6

Net Power Output, MW
e 622.0 607.2 607.0 590.8 578.4 563.9 607.0 590.0 577.4 563.8 554.5 543.2 528.5 522.9

Net Plant Efficiency, % (HHV) 39.0 38.4 38.4 36.8 35.5 34.3 38.4 36.7 35.5 34.2 33.4 32.6 31.8 31.5

Net Plant Heat Rate, Btu/kWh (HHV) 8,756 8,891 8,895 9,283 9,604 9,958 8,894 9,289 9,614 9,969 10,222 10,459 10,731 10,840

Coal Flowrate (lb/hr) 466,861 462,752 462,861 470,117 476,133 481,355 462,783 469,844 475,867 481,779 485,836 487,026 486,169 485,856

Total CO 2 Captured, lb/MWh net 0 425 430 809 1,127 1,476 429 810 1,125 1,467 1,710 1,899 2,159 2,269

CO 2 Capture & Compression Cost, $x1000 0 $166,439 $166,741 $193,350 $212,092 $231,604 $167,196 $194,185 $212,378 $230,775 $242,919 $251,958 $264,505 $228,358

Total Plant Cost, $x1000 $1,235,944 $1,345,298 $1,346,066 $1,389,128 $1,419,771 $1,449,191 $1,346,380 $1,390,235 $1,419,640 $1,447,904 $1,465,871 $1,472,866 $1,483,871 $1,488,149

Owner’s Costs, $x1000 $286,161 $308,679 $308,860 $319,113 $326,535 $333,624 $308,914 $319,358 $326,551 $333,508 $337,972 $338,851 $341,323 $342,287

Total Overnight Cost, $x1000 $1,522,105 $1,653,977 $1,654,925 $1,708,241 $1,746,306 $1,782,815 $1,655,294 $1,709,592 $1,746,192 $1,781,411 $1,803,843 $1,811,717 $1,825,194 $1,830,436

Total Overnight Cost, $/kW $2,447 $2,724 $2,726 $2,891 $3,019 $3,161 $2,727 $2,897 $3,024 $3,160 $3,253 $3,335 $3,453 $3,501

Total As

- Spent Capital, $x1000 $1,735,200 $1,885,534 $1,886,615 $1,947,394 $1,990,789 $2,032,409 $1,887,035 $1,948,935 $1,990,658 $2,030,809 $2,056,381 $2,065,358 $2,080,721 $2,086,697

Total As

- Spent Capital, $/kW $2,790 $3,105 $3,108 $3,296 $3,442 $3,604 $3,109 $3,303 $3,447 $3,602 $3,709 $3,802 $3,937 $3,991

CO 2 Capi tal Cost Penalty a , $/kW $0 $277 $279 $444 $572 $715 $280 $450 $577 $713 $806 $888 $1,007 $1,054

Cost of Electricity b , mills/kWh 76.3 85.3 85.4 90.8 95.2 100.0 85.4 91.0 95.3 100.0 103.1 105.7 109.3 110.8

COE CO 2 Penalty a , mills/kWh 0.0 9.0 9.1 14.5 18.9 23.7 9.1 14.7 19.0 23.7 26.8 29.4 33.0 34.4

Percent increase in COE a , % NA 11.8% 11.9% 19.0% 24.7% 31.0% 12.0% 19.2% 24.9% 31.0% 35.1% 38.5% 43.3% 45.1%

Cost of CO 2 Avoided a , $/tonne NA 48.7 48.6 44.9 43.1 42.5 48.7 45.4 43.6 42.5 41.7 42.7 45.2 46.0

CO2 Emissions, lb/MMBtu 196.8 147.8 147.3 108.8 78.9 49.7 147.3 108.8 79.2 49.7 30.1 19.7 10.4 6.5

CO 2 Emi s sions , lb/MWh net 1,723 1,314 1,310 1,010 758 495 1,310 1,011 762 496 308 206 112 71

SO 2 Emissions, lb/MMBtu 0.005 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002

SO 2 Emis sions, lb/MWh 0.040 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020

NOx Emis sions, lb/MMBtu 0.059 0.055 0.055 0.053 0.051 0.050 0.055 0.053 0.052 0.050 0.049 0.049 0.049 0.049

NOx Emissions, lb/MWh 0.430 0.397 0.397 0.390 0.384 0.379 0.397 0.391 0.385 0.379 0.375 0.376 0.380 0.382

PM Emissions, lb/MMBtu 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071

PM Emiss ions, lb/MWh 0.052 0.051 0.051 0.052 0.053 0.054 0.051 0.052 0.053 0.054 0.054 0.055 0.055 0.056

Hg Emissions, lb/TBtu 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571

Hg Emissions, lb/TWh 4.16 4.11 4.11 4.20 4.26 4.32 4.11 4.20 4.26 4.33 4.38 4.42 4.46 4.48

Raw Wate r Withdrawal, gpm 4,734 4,697 4,700 5,039 5,301 5,531 4,701 5,048 5,308 5,571 5,749 5,818 5,740 5,708

Raw Water Consumption, gpm 3,755 3,726 3,729 4,034 4,271 4,482 3,729 4,040 4,277 4,515 4,678 4,742 4,680 4,655

Raw Water Consumption, gal/MWh net 362 368 369 410 443 477 369 411 444 480 506 524 531 534

a Relative to Case 0 ( GEE IGCC without capture from 20 10 Bituminous Baseline study)

b Capacity factor is 80% for the GEE IGCC casesCarbon Dioxide Capture Sensitivity Analysis



### 483 

# Appendix ACarbon Dioxide Capture Sensitivity Analysis



### 484 As part of this study, various cost curves and algorithms were generated as a function of th e CO 2 

### capture level. The algorithms can be used to estimate and predict the cost of CO 2 

### capture over a full range of removal efficiencies. The following figures present the results of this effort for both

the SC PC and GEE IGCC cases.

Supercritical PC Cost Algorithms

Appendix A

- 1 Supercritical PC CO 2 Capture & Compression Cost, $000

Appendix A

- 2 Supercritical PC CO 2 Capture & Compression Cost, $/kWCarbon Dioxide Capture Sensitivity Analysis



### 485 Appendix A

- 3 Supercritical PC Total Overnight Cost, $000

Appendix A

- 4 Supercritical PC Total Overnight Cost, $/kWCarbon Dioxide Capture Sensitivity Analysis



### 486 Appendix A

- 5 Supercritical PC Incremental Capital Cost, $000

Appendix A

- 6 Supercritical PC Incremental Capital Cost, $/kWCarbon Dioxide Capture Sensitivity Analysis



### 487 Appendix A

- 7 Supercritical PC COE , mills/kWh

Appendix A

- 8 Supercritical PC Incremental COE , mills/kWhCarbon Dioxide Capture Sensitivity Analysis



### 488 Appendix A

- 9 Supercritical PC Percent Increase in COE

Appendix A

- 10 Supercritical PC CO 2 Capture Avoided CostsCarbon Dioxide Capture Sensitivity Analysis



### 489 GEE IGCC Cost Algorithms

Appendix A

- 11 GEE IGCC CO 2 Capture & Compression Cost, $000

Appendix A

- 12 GEE IGCC CO 2 Capture & Compression Cost, $/kWCarbon Dioxide Capture Sensitivity Analysis



### 490 Appendix A

- 13 GEE IGCC Total Overnight Cost, $000

Appendix A

- 14 GEE IGCC Total Overnight Cost, $/kWCarbon Dioxide Capture Sensitivity Analysis



### 491 Appendix A

- 15 GEE IGCC Incremental Capital Cost, $000

Appendix A

- 16 GEE IGCC Incremental Capital Cost, $/kWCarbon Dioxide Capture Sensitivity Analysis



### 492 Appendix A

- 17 GEE IGCC COE , mills/kWh

Appendix A

- 18 GEE IGCC Incremental COE , mills/kWhCarbon Dioxide Capture Sensitivity Analysis



### 493 Appendix A

- 19 GEE IG CC Percent Increase in COE

Appendix A

- 20 GEE IGCC CO 2 Capture Avoided CostsCarbon Dioxide Capture Sensitivity Analysis



### 494 This page intentionally left blankCarbon Dioxide Capture Sensitivity Analysis



### 495 

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