IECM User Documentation: User Manual

IECM User Documentation: User Manual Table of Contents • i

IECM User Documentation: User Manual

December 2018

IECM User Documentation: User Manual Table of Contents • ii

IECM User Documentation:

User Manual

Originally Prepared November 2009 by:

Michael B. Berkenpas

John J. Fry

Karen Kietzke

Edward S. Rubin

Revised December 2018 by:

Karen Kietzke

Haibo Zhai

The Integrated Environmental Control Model Team

Carnegie Mellon University

Pittsburgh, PA 15213

www.iecm-online.com

http://www.iecm-online.com/



IECM User Documentation: User Manual Table of Contents • iii

Table of Contents

1. Introduction 1

1.1. The Integrated Environmental Control Model ................................................................................................ 1 1.2. Purpose ........................................................................................................................................................... 1 1.3. System Requirements ..................................................................................................................................... 1

1.3.1. MacOS X and Linux ............................................................................................................................ 1 1.4. Uncertainty Features ....................................................................................................................................... 1 1.5. Sensitivity Analysis ........................................................................................................................................ 2 1.6. Software Used in Development ...................................................................................................................... 2 1.7. Disclaimer of Warranties and Limitation of Liabilities .................................................................................. 2 1.8. Copyright Notices ........................................................................................................................................... 3 1.9. User Documentation and Help ........................................................................................................................ 3

2. Microsoft® Windows Conventions 4

2.1. Windows ......................................................................................................................................................... 4 2.2. Using a Mouse or Touchscreen ....................................................................................................................... 4 2.3. Pull-Down Menus ........................................................................................................................................... 4

2.3.1. Choosing a Command from a Pull-Down Menu .................................................................................. 5 2.4. Keystroke Commands ..................................................................................................................................... 5

2.4.1. Alt Commands ..................................................................................................................................... 5 2.4.2. Ctrl Commands ................................................................................................................................... 5

2.5. Editing Text .................................................................................................................................................... 6 2.6. Using the Clipboard ........................................................................................................................................ 6 2.7. The Taskbar..................................................................................................................................................... 6

2.7.1. Switching Applications or Windows .................................................................................................... 7 2.7.2. The Start Button ................................................................................................................................... 7

2.7.2.1. The Start Menu .......................................................................................................................... 8 2.7.2.1.1. Start Menu Folders .......................................................................................................... 9 2.7.2.1.2. The Settings Button ......................................................................................................... 9

3. Installing the IECM 10

3.1. What's included in the Model Package ......................................................................................................... 10 3.2. Installation .................................................................................................................................................... 10

3.2.1. Installing the IECM on MacOS and Linux ......................................................................................... 10 3.2.1.1. MacOS ..................................................................................................................................... 10 3.2.1.2. Linux ........................................................................................................................................ 11

3.2.2. Installation Steps ................................................................................................................................ 11 3.2.2.1. Running the IECM Setup Application ..................................................................................... 11 3.2.2.2. Welcome Dialog....................................................................................................................... 11 3.2.2.3. License Agreement .................................................................................................................. 12 3.2.2.4. Information .............................................................................................................................. 12 3.2.2.5. Select Destination Location ..................................................................................................... 13 3.2.2.6. Select Start Menu Folder ......................................................................................................... 13 3.2.2.7. Select Additional Tasks ............................................................................................................ 14

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3.2.2.8. Ready to Install ........................................................................................................................ 15 3.2.2.9. Installation Progress ................................................................................................................. 15 3.2.2.10. Installation Complete ............................................................................................................. 16

3.2.3. Canceling the Installation ................................................................................................................... 16 3.2.4. Errors During Installation ................................................................................................................... 16

3.3. Removing the IECM Software ..................................................................................................................... 16 3.3.1. Uninstall the IECM Using the Included Uninstall Application .......................................................... 17 3.3.2. Uninstall the IECM Using Settings on Windows 10 .......................................................................... 17 3.3.3. Uninstall the IECM Using the Control Panel on Windows 7 ............................................................. 17 3.3.4. Uninstall the IECM Using the Control Panel on Windows XP .......................................................... 17

4. Using the IECM 19

4.1. The IECM Interface ...................................................................................................................................... 19 4.1.1. Starting the IECM Interface ............................................................................................................... 19 4.1.2. The Main Window .............................................................................................................................. 20

4.1.2.1. The Main Window Menu Bar .................................................................................................. 20 4.1.2.1.1. The File Menu ............................................................................................................... 21 4.1.2.1.2. The Help Menu .............................................................................................................. 21

4.1.2.2. The Main Window Toolbar ...................................................................................................... 22 4.1.3. Creating and Opening Sessions .......................................................................................................... 22

4.1.3.1. Creating a New Session from Model Defaults ......................................................................... 22 4.1.3.1.1. Choose a Plant Type ...................................................................................................... 23 4.1.3.1.2. Choose a Name .............................................................................................................. 23

4.1.3.2. Opening an Existing Session ................................................................................................... 23 4.1.3.2.1. Choose a Session Database ........................................................................................... 24

4.1.3.2.1.1. Opening a Session Database ................................................................................. 25 4.1.3.2.2. Choose a Session ........................................................................................................... 26

4.1.4. The Session Window .......................................................................................................................... 27 4.1.4.1. The Session Window Menu Bar ............................................................................................... 27

4.1.4.1.1. The File Menu ............................................................................................................... 28 4.1.4.1.1.1. The Export Menu .................................................................................................. 28

4.1.4.1.2. The Edit Menu ............................................................................................................... 29 4.1.4.1.3. The Go Menu................................................................................................................. 30 4.1.4.1.4. The Help Menu .............................................................................................................. 30

4.1.4.2. The Session Window Toolbar .................................................................................................. 30 4.1.4.2.1. The "New Session" Button ............................................................................................ 31 4.1.4.2.2. The "Open Session" Button ........................................................................................... 31 4.1.4.2.3. The "Save Session" Button ............................................................................................ 31 4.1.4.2.4. The "Save Session As" Button ....................................................................................... 31 4.1.4.2.5. The "Go to Previous Screen" Button ............................................................................. 32 4.1.4.2.6. The "Go to Next Screen" Button ................................................................................... 32 4.1.4.2.7. The "Go to Previous Screen in History" Button ............................................................ 32 4.1.4.2.8. The "Go to Next Screen in History" Button .................................................................. 32 4.1.4.2.9. The Location of the Current Screen .............................................................................. 32 4.1.4.2.10. The "Close Window" Button ....................................................................................... 33 4.1.4.2.11. The "Exit" Button ........................................................................................................ 33

4.1.4.3. The Status Bar .......................................................................................................................... 33 4.1.4.4. The Navigation Panel ............................................................................................................... 34

4.1.4.4.1. How to Use the Navigation Panel ................................................................................. 34 4.1.4.4.2. Organization of the Navigation Panel ........................................................................... 35

4.1.4.4.2.1. Program Areas ....................................................................................................... 36 4.1.4.4.2.2. Technologies ......................................................................................................... 36

IECM User Documentation: User Manual Table of Contents • v

4.1.4.4.2.3. Process Types ........................................................................................................ 38 4.1.4.4.2.4. Screens .................................................................................................................. 39

4.1.4.4.3. Organization in the Old Tab-Style Interface .................................................................. 40 4.1.5. Saving Sessions .................................................................................................................................. 40

4.1.5.1. The "Session Modified" Indicator in the Window Title ........................................................... 41 4.1.5.2. Save ......................................................................................................................................... 41 4.1.5.3. Save As .................................................................................................................................... 41

4.1.6. Closing Sessions ................................................................................................................................. 42 4.1.7. Deleting Sessions ............................................................................................................................... 43 4.1.8. Unlocking Sessions ............................................................................................................................ 43 4.1.9. Exiting the IECM Interface ................................................................................................................ 44

4.2. Configuring the Plant .................................................................................................................................... 45 4.2.1. The "CONFIGURE SESSION" Program Area .................................................................................. 45

4.2.1.1. The "Plant Design" Screen ....................................................................................................... 45 4.2.1.1.1. The Configuration Menus.............................................................................................. 46

4.2.1.1.1.1. The Overall Configuration Menu .......................................................................... 46 4.2.1.1.1.2. The Individual Configuration Menus .................................................................... 47

4.2.1.1.2. The Overall Plant Diagram ............................................................................................ 49 4.2.1.2. The "Plant Location" Screen .................................................................................................... 50 4.2.1.3. The "Unit Systems" Screen ...................................................................................................... 51

4.2.1.3.1. IECM Default Unit System ........................................................................................... 51 4.2.1.3.2. Current Session Unit System ......................................................................................... 52 4.2.1.3.3. Result Flow Rates .......................................................................................................... 52 4.2.1.3.4. Result Time Period ........................................................................................................ 52 4.2.1.3.5. Performance Table ......................................................................................................... 53 4.2.1.3.6. Cost Table ...................................................................................................................... 53

4.3. Setting Parameters ........................................................................................................................................ 54 4.3.1. Overview ............................................................................................................................................ 54 4.3.2. Diagram Screens ................................................................................................................................ 54

4.3.2.1. Overall Plant Diagram ............................................................................................................. 54 4.3.2.2. Technology and Process Type Overview Diagrams ................................................................. 55

4.3.3. Parameter Screens .............................................................................................................................. 55 4.3.3.1. Standard Parameters ................................................................................................................ 56

4.3.3.1.1. Title ............................................................................................................................... 56 4.3.3.1.2. Unc ................................................................................................................................ 56 4.3.3.1.3. Value .............................................................................................................................. 56

4.3.3.1.3.1. Menu Values ......................................................................................................... 56 4.3.3.1.3.2. Text Values ............................................................................................................ 57

4.3.3.1.4. Calc ............................................................................................................................... 57 4.3.3.1.5. Min ................................................................................................................................ 58 4.3.3.1.6. Max ............................................................................................................................... 58 4.3.3.1.7. Default ........................................................................................................................... 58

4.3.3.2. Read-Only Parameters ............................................................................................................. 58 4.3.3.3. The Uncertainty Editor ............................................................................................................ 59

4.3.3.3.1. #1: Parameter Information ............................................................................................. 59 4.3.3.3.2. #2: The Distribution Menu ............................................................................................ 60 4.3.3.3.3. #3: The "Use Nominal Values" Checkbox ..................................................................... 61 4.3.3.3.4. #4: The Sample Size ...................................................................................................... 61 4.3.3.3.5. #5: The Nominal Minimum & Maximum ..................................................................... 62 4.3.3.3.6. #6: Normalized Distribution Parameters ....................................................................... 62 4.3.3.3.7. #7: Nominal Distribution Parameters ............................................................................ 62 4.3.3.3.8. #8: Distribution Requirements ...................................................................................... 63

IECM User Documentation: User Manual Table of Contents • vi

4.3.3.3.9. #9: Status ....................................................................................................................... 63 4.3.3.3.10. #10: Distribution Information ..................................................................................... 63 4.3.3.3.11. Uncertainty on Menus ................................................................................................. 64 4.3.3.3.12. User-defined Distributions .......................................................................................... 64 4.3.3.3.13. Batch Processing ......................................................................................................... 66

4.3.3.4. The Database Button ................................................................................................................ 67 4.3.3.4.1. Coal Databases .............................................................................................................. 68 4.3.3.4.2. Reservoir Databases ...................................................................................................... 71

4.3.3.5. Highlighted Parameters ............................................................................................................ 74 4.3.3.6. The Right-Click Menu ............................................................................................................. 74

4.4. Getting Results ............................................................................................................................................. 75 4.4.1. Overview ............................................................................................................................................ 75 4.4.2. Diagram Screens ................................................................................................................................ 75

4.4.2.1. The Overall Plant Diagram ...................................................................................................... 75 4.4.2.2. Other Diagrams ........................................................................................................................ 75

4.4.2.2.1. Units .............................................................................................................................. 76 4.4.3. Table Screens ...................................................................................................................................... 76

4.4.3.1. One Table ................................................................................................................................. 76 4.4.3.2. Two Tables ............................................................................................................................... 78 4.4.3.3. Units ......................................................................................................................................... 80

4.4.4. The Right-Click Menu........................................................................................................................ 80 4.5. Analysis Tools ............................................................................................................................................... 80

4.5.1. Overview ............................................................................................................................................ 80 4.5.2. Sensitivity Analysis ............................................................................................................................ 80

4.5.2.1. Choose Independent Variable .................................................................................................. 81 4.5.2.1.1. Parameter Chooser ........................................................................................................ 81 4.5.2.1.2. Information .................................................................................................................... 82 4.5.2.1.3. Configuration ................................................................................................................ 82 4.5.2.1.4. Values ............................................................................................................................ 83

4.5.2.2. Choose Dependent Variable(s) ................................................................................................. 84 4.5.3. Uncertainty ......................................................................................................................................... 85

4.5.3.1. Configure Uncertainty ............................................................................................................. 85 4.5.3.1.1. Sample Size ................................................................................................................... 86 4.5.3.1.2. Sampling Method .......................................................................................................... 86 4.5.3.1.3. Uncertainty Areas .......................................................................................................... 87

4.5.3.1.3.1. Uncertainty Areas in a Pulverized Coal (PC) Plant............................................... 87 4.5.3.1.3.2. Uncertainty Areas in a Natural Gas Combined Cycle (NGCC) Plant ................... 87 4.5.3.1.3.3. Uncertainty Areas in an Integrated Gasification Combined Cycle (IGCC) Plant . 87

4.5.3.2. Choose Variable(s) ................................................................................................................... 88 4.6. Exporting Data .............................................................................................................................................. 88

5. How to Use the Modules Included With the IECM 90

5.1. Common Input and Result Screens ............................................................................................................... 90 5.1.1. Costs ................................................................................................................................................... 90

5.1.1.1. Capital Cost Inputs................................................................................................................... 90 5.1.1.2. Capital Cost Results ................................................................................................................. 93 5.1.1.3. Cost of CO2 Avoided & Captured ............................................................................................ 94 5.1.1.4. Cost Summary Results ............................................................................................................. 96 5.1.1.5. O&M Cost Inputs .................................................................................................................... 97 5.1.1.6. O&M Cost Results ................................................................................................................... 98 5.1.1.7. Total Cost Results .................................................................................................................... 99 5.1.1.8. Retrofit or Adjustment Factor Inputs ..................................................................................... 100

IECM User Documentation: User Manual Table of Contents • vii

5.1.2. Fuels ................................................................................................................................................. 100 5.1.2.1. Coal Properties ....................................................................................................................... 100

5.1.2.1.1. Ash Properties ............................................................................................................. 100 5.1.2.2. Natural Gas Properties ........................................................................................................... 101

5.1.3. Gas Streams ...................................................................................................................................... 101 5.1.3.1. Flue Gas Components ............................................................................................................ 101 5.1.3.2. Syngas Components ............................................................................................................... 102

5.1.4. Other ................................................................................................................................................. 104 5.1.4.1. Mass In/Out ........................................................................................................................... 104 5.1.4.2. Plant Performance .................................................................................................................. 105 5.1.4.3. T&S Config ........................................................................................................................... 107

5.2. Pulverized Coal (PC) Plant ......................................................................................................................... 107 5.2.1. CONFIGURE SESSION .................................................................................................................. 107

5.2.1.1. Plant Design ........................................................................................................................... 107 5.2.1.2. Plant Location ........................................................................................................................ 114 5.2.1.3. Unit Systems .......................................................................................................................... 115

5.2.2. SET PARAMETERS ........................................................................................................................ 115 5.2.2.1. Overall Plant .......................................................................................................................... 115

5.2.2.1.1. Diagram ....................................................................................................................... 116 5.2.2.1.2. Performance ................................................................................................................ 116 5.2.2.1.3. Region-Specific Cost Factors ...................................................................................... 117 5.2.2.1.4. Regulations & Taxes .................................................................................................... 118 5.2.2.1.5. Financing & Cost Year ................................................................................................ 120 5.2.2.1.6. Fuel & Land Cost ........................................................................................................ 122 5.2.2.1.7. Capital Cost ................................................................................................................. 123 5.2.2.1.8. O&M Cost ................................................................................................................... 123 5.2.2.1.9. Reference Plant ........................................................................................................... 125

5.2.2.2. Fuel ........................................................................................................................................ 125 5.2.2.2.1. Coal Properties ............................................................................................................ 126 5.2.2.2.2. Ash Properties ............................................................................................................. 127 5.2.2.2.3. Auxiliary Gas............................................................................................................... 128 5.2.2.2.4. Mercury ....................................................................................................................... 129 5.2.2.2.5. Cost ............................................................................................................................. 130

5.2.2.3. Base Plant .............................................................................................................................. 130 5.2.2.3.1. Boiler Diagram ............................................................................................................ 131 5.2.2.3.2. Air Preheater Diagram ................................................................................................. 131 5.2.2.3.3. Base Plant Performance ............................................................................................... 132 5.2.2.3.4. Steam Cycle Diagram .................................................................................................. 134 5.2.2.3.5. Steam Cycle Performance ........................................................................................... 134 5.2.2.3.6. Furnace Factors ........................................................................................................... 135 5.2.2.3.7. Capital Cost ................................................................................................................. 136 5.2.2.3.8. O&M Cost ................................................................................................................... 137 5.2.2.3.9. Retrofit or Adjustment Factors .................................................................................... 138

5.2.2.4. NOx Control ........................................................................................................................... 138 5.2.2.4.1. In-Furnace Controls ..................................................................................................... 138

5.2.2.4.1.1. In-Furnace Controls Diagram ............................................................................. 139 5.2.2.4.1.2. Config ................................................................................................................. 139 5.2.2.4.1.3. Performance ........................................................................................................ 141 5.2.2.4.1.4. Capital Cost......................................................................................................... 142 5.2.2.4.1.5. O&M Cost .......................................................................................................... 143

5.2.2.4.2. Hot-Side SCR .............................................................................................................. 144 5.2.2.4.2.1. Hot-Side SCR Diagram ....................................................................................... 144

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5.2.2.4.2.2. Config ................................................................................................................. 144 5.2.2.4.2.3. Performance ........................................................................................................ 146 5.2.2.4.2.4. Performance (continued) ..................................................................................... 148 5.2.2.4.2.5. Capital Cost......................................................................................................... 149 5.2.2.4.2.6. O&M Cost .......................................................................................................... 150 5.2.2.4.2.7. Retrofit or Adjustment Factors ............................................................................ 150

5.2.2.5. Mercury ................................................................................................................................. 151 5.2.2.5.1. Activated Carbon Inj. Diagram .................................................................................... 151 5.2.2.5.2. Removal Efficiency ..................................................................................................... 152 5.2.2.5.3. Carbon Injection .......................................................................................................... 154 5.2.2.5.4. Capital Cost ................................................................................................................. 154 5.2.2.5.5. O&M Cost ................................................................................................................... 155 5.2.2.5.6. Retrofit or Adjustment Factors .................................................................................... 155

5.2.2.6. TSP Control ........................................................................................................................... 156 5.2.2.6.1. Cold-Side ESP ............................................................................................................. 157

5.2.2.6.1.1. Cold-Side ESP Diagram ...................................................................................... 157 5.2.2.6.1.2. Performance ........................................................................................................ 157 5.2.2.6.1.3. Capital Cost......................................................................................................... 158 5.2.2.6.1.4. O&M Cost .......................................................................................................... 159 5.2.2.6.1.5. Retrofit or Adjustment Factors ............................................................................ 159

5.2.2.6.2. Fabric Filter ................................................................................................................. 160 5.2.2.6.2.1. Fabric Filter Diagram .......................................................................................... 160 5.2.2.6.2.2. Config ................................................................................................................. 160 5.2.2.6.2.3. Performance ........................................................................................................ 161 5.2.2.6.2.4. Capital Cost......................................................................................................... 163 5.2.2.6.2.5. O&M Cost .......................................................................................................... 163 5.2.2.6.2.6. Retrofit or Adjustment Factors ............................................................................ 163

5.2.2.7. SO2 Control ............................................................................................................................ 164 5.2.2.7.1. Wet FGD...................................................................................................................... 164

5.2.2.7.1.1. Wet FGD Diagram .............................................................................................. 164 5.2.2.7.1.2. Config ................................................................................................................. 165 5.2.2.7.1.3. Performance ........................................................................................................ 166 5.2.2.7.1.4. Oxidation ............................................................................................................ 168 5.2.2.7.1.5. Additives ............................................................................................................. 168 5.2.2.7.1.6. Capital Cost......................................................................................................... 169 5.2.2.7.1.7. O&M Cost .......................................................................................................... 170 5.2.2.7.1.8. Retrofit or Adjustment Factors ............................................................................ 171

5.2.2.7.2. Spray Dryer ................................................................................................................. 171 5.2.2.7.2.1. Spray Dryer Diagram .......................................................................................... 172 5.2.2.7.2.2. Config ................................................................................................................. 172 5.2.2.7.2.3. Performance ........................................................................................................ 173 5.2.2.7.2.4. Capital Cost......................................................................................................... 175 5.2.2.7.2.5. O&M Cost .......................................................................................................... 175 5.2.2.7.2.6. Retrofit or Adjustment Factors ............................................................................ 176

5.2.2.8. CO2 Capture, Transport & Storage ........................................................................................ 176 5.2.2.8.1. Amine System (CCS System) ...................................................................................... 176

5.2.2.8.1.1. Amine System Diagram ...................................................................................... 177 5.2.2.8.1.2. Config ................................................................................................................. 177 5.2.2.8.1.3. Performance ........................................................................................................ 180 5.2.2.8.1.4. Capture ................................................................................................................ 182 5.2.2.8.1.5. T&S Config ......................................................................................................... 184 5.2.2.8.1.6. Capital Cost......................................................................................................... 184

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5.2.2.8.1.7. Variable O&M Cost ............................................................................................ 185 5.2.2.8.1.8. Fixed O&M Cost ................................................................................................ 186 5.2.2.8.1.9. Retrofit or Adjustment Factors ............................................................................ 186

5.2.2.8.2. Ammonia System (CCS System)................................................................................. 188 5.2.2.8.2.1. Ammonia System Diagram ................................................................................. 188 5.2.2.8.2.2. Config ................................................................................................................. 189 5.2.2.8.2.3. Performance ........................................................................................................ 190 5.2.2.8.2.4. Capture ................................................................................................................ 192 5.2.2.8.2.5. T&S Config ......................................................................................................... 193 5.2.2.8.2.6. Capital Cost......................................................................................................... 194 5.2.2.8.2.7. O&M Cost .......................................................................................................... 194 5.2.2.8.2.8. Retrofit or Adjustment Factors ............................................................................ 195

5.2.2.8.3. Auxiliary Boiler System .............................................................................................. 196 5.2.2.8.3.1. Auxiliary Boiler Diagram ................................................................................... 196 5.2.2.8.3.2. Performance ........................................................................................................ 197

5.2.2.8.4. Chemical Looping (CCS System) ............................................................................... 197 5.2.2.8.4.1. Chemical Looping Diagram ................................................................................ 198 5.2.2.8.4.2. Air Separation Diagram ...................................................................................... 198 5.2.2.8.4.3. Heat Recovery System Diagram ......................................................................... 199 5.2.2.8.4.4. Chemical Looping Config ................................................................................... 200 5.2.2.8.4.5. Air Separation Config ......................................................................................... 201 5.2.2.8.4.6. Performance ........................................................................................................ 202 5.2.2.8.4.7. Carbonator .......................................................................................................... 203 5.2.2.8.4.8. Calciner ............................................................................................................... 204 5.2.2.8.4.9. T&S Config ......................................................................................................... 205 5.2.2.8.4.10. Capital Cost....................................................................................................... 205 5.2.2.8.4.11. O&M Cost ......................................................................................................... 206 5.2.2.8.4.12. Retrofit or Adjustment Factors .......................................................................... 207

5.2.2.8.5. Membrane System (CCS System) ............................................................................... 208 5.2.2.8.5.1. Config ................................................................................................................. 208 5.2.2.8.5.2. Membrane System Diagram................................................................................ 210 5.2.2.8.5.3. Performance ........................................................................................................ 211 5.2.2.8.5.4. Capture ................................................................................................................ 212 5.2.2.8.5.5. Purification.......................................................................................................... 216 5.2.2.8.5.6. T&S Config ......................................................................................................... 217 5.2.2.8.5.7. Capital Cost......................................................................................................... 218 5.2.2.8.5.8. O&M Cost .......................................................................................................... 218 5.2.2.8.5.9. Retrofit or Adjustment Factors ............................................................................ 219

5.2.2.8.6. Solid Sorbents PSA (CCS System) .............................................................................. 219 5.2.2.8.6.1. Solid Sorbents PSA ............................................................................................. 219 5.2.2.8.6.2. Config ................................................................................................................. 220 5.2.2.8.6.3. Performance ........................................................................................................ 222 5.2.2.8.6.4. Capture ................................................................................................................ 223 5.2.2.8.6.5. T&S Config ......................................................................................................... 224 5.2.2.8.6.6. Capital Cost......................................................................................................... 225 5.2.2.8.6.7. O&M Cost .......................................................................................................... 225 5.2.2.8.6.8. Retrofit or Adjustment Factors ............................................................................ 226

5.2.2.8.7. Solid Sorbents TSA (CCS System) ............................................................................. 226 5.2.2.8.7.1. Solid Sorbents TSA Diagram .............................................................................. 227 5.2.2.8.7.2. Config - Capture ................................................................................................. 227 5.2.2.8.7.3. Config - Bypass .................................................................................................. 229 5.2.2.8.7.4. Performance ........................................................................................................ 230

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5.2.2.8.7.5. Capture - Adsorber .............................................................................................. 232 5.2.2.8.7.6. Capture - Regenerator ......................................................................................... 233 5.2.2.8.7.7. T&S Config ......................................................................................................... 234 5.2.2.8.7.8. Capital Cost......................................................................................................... 235 5.2.2.8.7.9. O&M Cost .......................................................................................................... 235 5.2.2.8.7.10. Retrofit or Adjustment Factors .......................................................................... 236

5.2.2.8.8. Air Separation Unit ...................................................................................................... 237 5.2.2.8.9. FG Recycle & Purification .......................................................................................... 238

5.2.2.8.9.1. Diagram .............................................................................................................. 238 5.2.2.8.9.2. Config ................................................................................................................. 238 5.2.2.8.9.3. FG Recycle ......................................................................................................... 239 5.2.2.8.9.4. Purification.......................................................................................................... 240 5.2.2.8.9.5. T&S Config ......................................................................................................... 242 5.2.2.8.9.6. Capital Cost......................................................................................................... 242 5.2.2.8.9.7. O&M Cost .......................................................................................................... 243 5.2.2.8.9.8. Retrofit or Adjustment Factors ............................................................................ 244

5.2.2.8.10. Pipeline Transport ..................................................................................................... 244 5.2.2.8.10.1. Pipeline Transport Diagram .............................................................................. 244 5.2.2.8.10.2. Config ............................................................................................................... 245 5.2.2.8.10.3. Financing .......................................................................................................... 246 5.2.2.8.10.4. Capital Cost....................................................................................................... 246 5.2.2.8.10.5. O&M Cost......................................................................................................... 247 5.2.2.8.10.6. Retrofit or Adjustment Factors .......................................................................... 247

5.2.2.8.11. Pipeline Transport (ERROR) ..................................................................................... 248 5.2.2.8.12. User-Specified Transport ........................................................................................... 248 5.2.2.8.13. CO2 Storage ............................................................................................................... 249

5.2.2.8.13.1. CO2 Storage Diagram ....................................................................................... 249 5.2.2.8.13.2. Financing .......................................................................................................... 249 5.2.2.8.13.3. Reservoir ........................................................................................................... 250 5.2.2.8.13.4. Performance ...................................................................................................... 251 5.2.2.8.13.5. Pre-injection Cost ............................................................................................. 252 5.2.2.8.13.6. Operations Cost ................................................................................................. 252 5.2.2.8.13.7. Post-injection Cost ............................................................................................ 253

5.2.2.9. Water Systems ........................................................................................................................ 253 5.2.2.9.1. Hybrid Cooling System ............................................................................................... 253

5.2.2.9.1.1. Diagram .............................................................................................................. 254 5.2.2.9.1.2. Seasons ............................................................................................................... 254

5.2.2.9.2. Air Cooled Condenser or Dry Unit .............................................................................. 255 5.2.2.9.2.1. Air Cooled Condenser ......................................................................................... 255 5.2.2.9.2.2. Config ................................................................................................................. 255 5.2.2.9.2.3. Performance ........................................................................................................ 256 5.2.2.9.2.4. Capital Cost......................................................................................................... 257 5.2.2.9.2.5. O&M Cost .......................................................................................................... 258 5.2.2.9.2.6. Retrofit or Adjustment Factors ............................................................................ 258

5.2.2.9.3. Wet Cooling Tower or Wet Unit .................................................................................. 259 5.2.2.9.3.1. Cooling Tower Diagram ...................................................................................... 259 5.2.2.9.3.2. Slip Stream Diagram ........................................................................................... 260 5.2.2.9.3.3. Config ................................................................................................................. 260 5.2.2.9.3.4. Performance ........................................................................................................ 261 5.2.2.9.3.5. Capital Cost......................................................................................................... 262 5.2.2.9.3.6. O&M Cost .......................................................................................................... 263 5.2.2.9.3.7. Retrofit or Adjustment Factors ............................................................................ 263

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5.2.2.10. By-Prod. Mgmt .................................................................................................................... 264 5.2.2.10.1. Bottom Ash Pond Diagram ....................................................................................... 264 5.2.2.10.2. Fly Ash Disposal Diagram ........................................................................................ 265 5.2.2.10.3. Flue Gas Treatment Diagram .................................................................................... 265 5.2.2.10.4. Bottom Ash Performance .......................................................................................... 266 5.2.2.10.5. Wastewater Treatment Diagram ................................................................................ 266 5.2.2.10.6. Wastewater Treatment Perf. ...................................................................................... 267 5.2.2.10.7. Chemical Treatment Perf. .......................................................................................... 268 5.2.2.10.8. Vapor Comp/Evap Perf.............................................................................................. 268 5.2.2.10.9. Capital Cost ............................................................................................................... 269 5.2.2.10.10. O&M Cost............................................................................................................... 269 5.2.2.10.11. Retrofit or Adjustment Factors ................................................................................ 270

5.2.2.11. Water Life Cycle Assessment .............................................................................................. 270 5.2.2.11.1. Coal ........................................................................................................................... 271 5.2.2.11.2. Natural Gas ................................................................................................................ 271 5.2.2.11.3. Plant Infrastructure .................................................................................................... 273 5.2.2.11.4. Plant Operation .......................................................................................................... 273 5.2.2.11.5. Chemical Production ................................................................................................. 274

5.2.3. GET RESULTS ................................................................................................................................ 274 5.2.3.1. Overall Plant .......................................................................................................................... 274

5.2.3.1.1. Diagram ....................................................................................................................... 275 5.2.3.1.2. Plant Performance ....................................................................................................... 275 5.2.3.1.3. Mass In/Out ................................................................................................................. 276 5.2.3.1.4. Solids In/Out ............................................................................................................... 276 5.2.3.1.5. Gas In/Out ................................................................................................................... 277 5.2.3.1.6. Total Capital Cost ........................................................................................................ 278 5.2.3.1.7. Overall Plant Cost ....................................................................................................... 279 5.2.3.1.8. Cost Summary ............................................................................................................. 280

5.2.3.2. Fuel ........................................................................................................................................ 280 5.2.3.2.1. Coal (PC) or Diagram (IGCC) .................................................................................... 281 5.2.3.2.2. Auxiliary Gas (PC) or Diagram (NGCC) .................................................................... 282

5.2.3.3. Base Plant .............................................................................................................................. 282 5.2.3.3.1. Boiler ........................................................................................................................... 283

5.2.3.3.1.1. Diagram .............................................................................................................. 283 5.2.3.3.1.2. Flue Gas .............................................................................................................. 284 5.2.3.3.1.3. Capital Cost......................................................................................................... 284 5.2.3.3.1.4. O&M Cost .......................................................................................................... 285 5.2.3.3.1.5. Total Cost ............................................................................................................ 286

5.2.3.3.2. Air Preheater ................................................................................................................ 286 5.2.3.3.2.1. Diagram .............................................................................................................. 286 5.2.3.3.2.2. Flue Gas .............................................................................................................. 289 5.2.3.3.2.3. Oxidant ............................................................................................................... 290

5.2.3.3.3. Steam Cycle................................................................................................................. 291 5.2.3.3.3.1. Diagram .............................................................................................................. 291

5.2.3.4. NOx Control ........................................................................................................................... 291 5.2.3.4.1. In-Furnace Controls ..................................................................................................... 291


5.2.3.4.2. Hot-Side SCR .............................................................................................................. 297

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5.2.3.5. Mercury ................................................................................................................................. 303 5.2.3.5.1. Diagram ....................................................................................................................... 304 5.2.3.5.2. Flue Gas ...................................................................................................................... 305 5.2.3.5.3. Capital Cost ................................................................................................................. 306 5.2.3.5.4. O&M Cost ................................................................................................................... 307 5.2.3.5.5. Total Cost .................................................................................................................... 308

5.2.3.6. TSP Control ........................................................................................................................... 309 5.2.3.6.1. Cold-Side ESP ............................................................................................................. 309


5.2.3.6.2. Fabric Filter ................................................................................................................. 314 5.2.3.6.2.1. Diagram .............................................................................................................. 314 5.2.3.6.2.2. Flue Gas .............................................................................................................. 315 5.2.3.6.2.3. Capital Cost......................................................................................................... 316 5.2.3.6.2.4. O&M Cost .......................................................................................................... 317 5.2.3.6.2.5. Total Cost ............................................................................................................ 317

5.2.3.7. SO2 Control ............................................................................................................................ 318 5.2.3.7.1. Wet FGD...................................................................................................................... 318

5.2.3.7.1.1. Diagram .............................................................................................................. 318 5.2.3.7.1.2. Flue Gas .............................................................................................................. 320 5.2.3.7.1.3. Bypass ................................................................................................................. 321 5.2.3.7.1.4. Capital Cost......................................................................................................... 321 5.2.3.7.1.5. O&M Cost .......................................................................................................... 322 5.2.3.7.1.6. Total Cost ............................................................................................................ 323

5.2.3.7.2. Spray Dryer ................................................................................................................. 323 5.2.3.7.2.1. Diagram .............................................................................................................. 324 5.2.3.7.2.2. Flue Gas .............................................................................................................. 326 5.2.3.7.2.3. Capital Cost......................................................................................................... 326 5.2.3.7.2.4. O&M Cost .......................................................................................................... 327 5.2.3.7.2.5. Total Cost ............................................................................................................ 328

5.2.3.8. CO2 Capture, Transport & Storage ........................................................................................ 328 5.2.3.8.1. Amine System (CCS System) ...................................................................................... 328

5.2.3.8.1.1. Diagram .............................................................................................................. 329 5.2.3.8.1.2. Flue Gas .............................................................................................................. 330 5.2.3.8.1.3. Bypass ................................................................................................................. 331 5.2.3.8.1.4. Capital Cost......................................................................................................... 332 5.2.3.8.1.5. O&M Cost .......................................................................................................... 334 5.2.3.8.1.6. Total Cost ............................................................................................................ 335 5.2.3.8.1.7. Summary ............................................................................................................. 336

5.2.3.8.2. Ammonia System (CCS System)................................................................................. 337 5.2.3.8.2.1. Diagram .............................................................................................................. 337 5.2.3.8.2.2. Flue Gas .............................................................................................................. 339 5.2.3.8.2.3. Bypass ................................................................................................................. 340 5.2.3.8.2.4. Capital Cost......................................................................................................... 341

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5.2.3.8.2.5. O&M Cost .......................................................................................................... 342 5.2.3.8.2.6. Total Cost ............................................................................................................ 343 5.2.3.8.2.7. Summary ............................................................................................................. 344

5.2.3.8.3. Chemical Looping (CCS System) ............................................................................... 345 5.2.3.8.3.1. Chemical Looping Diagram ................................................................................ 345 5.2.3.8.3.2. Air Separation Diagram ...................................................................................... 346 5.2.3.8.3.3. Heat Recovery System Diagram ......................................................................... 347 5.2.3.8.3.4. Flue Gas .............................................................................................................. 348 5.2.3.8.3.5. Bypass ................................................................................................................. 349 5.2.3.8.3.6. Capital Cost......................................................................................................... 350 5.2.3.8.3.7. O&M Cost .......................................................................................................... 351 5.2.3.8.3.8. Total Cost ............................................................................................................ 352 5.2.3.8.3.9. Summary ............................................................................................................. 352

5.2.3.8.4. Membrane System (CCS System) ............................................................................... 353 5.2.3.8.4.1. Diagram .............................................................................................................. 354 5.2.3.8.4.2. Flue Gas .............................................................................................................. 356 5.2.3.8.4.3. Bypass ................................................................................................................. 357 5.2.3.8.4.4. Purif. Gas ............................................................................................................ 358 5.2.3.8.4.5. Capital Cost......................................................................................................... 359 5.2.3.8.4.6. O&M Cost .......................................................................................................... 360 5.2.3.8.4.7. Total Cost ............................................................................................................ 361 5.2.3.8.4.8. Summary ............................................................................................................. 361

5.2.3.8.5. Solid Sorbents PSA (CCS System) .............................................................................. 362 5.2.3.8.5.1. Diagram .............................................................................................................. 363 5.2.3.8.5.2. Flue Gas .............................................................................................................. 364 5.2.3.8.5.3. Bypass ................................................................................................................. 365 5.2.3.8.5.4. Capital Cost......................................................................................................... 366 5.2.3.8.5.5. O&M Cost .......................................................................................................... 367 5.2.3.8.5.6. Total Cost ............................................................................................................ 368 5.2.3.8.5.7. Summary ............................................................................................................. 368

5.2.3.8.6. Solid Sorbents TSA (CCS System) ............................................................................. 369 5.2.3.8.6.1. Diagram .............................................................................................................. 370 5.2.3.8.6.2. Flue Gas .............................................................................................................. 371 5.2.3.8.6.3. Bypass ................................................................................................................. 372 5.2.3.8.6.4. Capital Cost......................................................................................................... 373 5.2.3.8.6.5. O&M Cost .......................................................................................................... 375 5.2.3.8.6.6. Total Cost ............................................................................................................ 376 5.2.3.8.6.7. Summary ............................................................................................................. 376

5.2.3.8.7. Auxiliary Boiler ........................................................................................................... 377 5.2.3.8.7.1. Diagram .............................................................................................................. 378 5.2.3.8.7.2. Auxiliary Gas ...................................................................................................... 379 5.2.3.8.7.3. Flue Gas .............................................................................................................. 380 5.2.3.8.7.4. Costs ................................................................................................................... 380

5.2.3.8.8. Air Separation Unit ...................................................................................................... 380 5.2.3.8.9. FG Recycle & Purification .......................................................................................... 380

5.2.3.8.9.1. Diagram .............................................................................................................. 381 5.2.3.8.9.2. DCC Gas ............................................................................................................. 382 5.2.3.8.9.3. Purif. Gas ............................................................................................................ 383 5.2.3.8.9.4. Capital Cost......................................................................................................... 383 5.2.3.8.9.5. O&M Cost .......................................................................................................... 384 5.2.3.8.9.6. Total Cost ............................................................................................................ 385 5.2.3.8.9.7. Summary ............................................................................................................. 386

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5.2.3.8.10. Pipeline Transport ..................................................................................................... 387 5.2.3.8.10.1. Diagram ............................................................................................................ 387 5.2.3.8.10.2. Flue Gas ............................................................................................................ 388 5.2.3.8.10.3. Gas .................................................................................................................... 389 5.2.3.8.10.4. Capital Cost....................................................................................................... 390 5.2.3.8.10.5. O&M Cost......................................................................................................... 391 5.2.3.8.10.6. Total Cost .......................................................................................................... 392

5.2.3.8.11. CO2 Storage ............................................................................................................... 393 5.2.3.8.11.1. Diagram............................................................................................................. 393 5.2.3.8.11.2. Pre-Injection Cost ............................................................................................. 394 5.2.3.8.11.3. Operations Cost ................................................................................................. 395 5.2.3.8.11.4. Post-injection Cost ............................................................................................ 396 5.2.3.8.11.5. Total Cost .......................................................................................................... 397

5.2.3.9. Water Systems ........................................................................................................................ 397 5.2.3.9.1. Water ........................................................................................................................... 397

5.2.3.9.1.1. Makeup Water (PC) ............................................................................................ 397 5.2.3.9.1.2. Makeup Water (IGCC) ........................................................................................ 398 5.2.3.9.1.3. Water Consumption............................................................................................. 399 5.2.3.9.1.4. Cooling Water ..................................................................................................... 399

5.2.3.9.2. Hybrid Cooling System ............................................................................................... 400 5.2.3.9.2.1. Diagram .............................................................................................................. 400 5.2.3.9.2.2. Total Cost ............................................................................................................ 401

5.2.3.9.3. Air Cooled Condenser or Dry Unit .............................................................................. 401 5.2.3.9.3.1. Diagram .............................................................................................................. 401 5.2.3.9.3.2. Capital Cost......................................................................................................... 402 5.2.3.9.3.3. O&M Cost .......................................................................................................... 403 5.2.3.9.3.4. Total Cost ............................................................................................................ 404

5.2.3.9.4. Wet Cooling Tower or Wet Unit .................................................................................. 404 5.2.3.9.4.1. Cooling Tower Diagram ...................................................................................... 404 5.2.3.9.4.2. Slip Stream Diagram ........................................................................................... 406 5.2.3.9.4.3. Capital Cost......................................................................................................... 407 5.2.3.9.4.4. O&M Cost .......................................................................................................... 408 5.2.3.9.4.5. Total Cost ............................................................................................................ 408

5.2.3.10. By-Prod. Mgmt .................................................................................................................... 409 5.2.3.10.1. Bottom Ash Pond ...................................................................................................... 409 5.2.3.10.2. Fly Ash Disposal ....................................................................................................... 410 5.2.3.10.3. Flue Gas Treatment ................................................................................................... 411 5.2.3.10.4. Wastewater Treatment (chemical) ............................................................................. 412 5.2.3.10.5. Wastewater Treatment (mechanical) ......................................................................... 413 5.2.3.10.6. Capital Cost ............................................................................................................... 414 5.2.3.10.7. O&M Cost ................................................................................................................. 415 5.2.3.10.8. Total Cost .................................................................................................................. 416

5.2.3.11. Stack .................................................................................................................................... 416 5.2.3.11.1. Diagram ..................................................................................................................... 416 5.2.3.11.2. Flue Gas .................................................................................................................... 418 5.2.3.11.3. Emission Taxes .......................................................................................................... 419

5.2.3.12. Water Life Cycle Assessment .............................................................................................. 419 5.2.3.12.1. Water Withdrawals .................................................................................................... 420 5.2.3.12.2. Water Consumption ................................................................................................... 421

5.3. Natural Gas Comb. Cycle (NGCC) Plant ................................................................................................... 422 5.3.1. CONFIGURE SESSION .................................................................................................................. 422

5.3.1.1. Plant Design ........................................................................................................................... 422

IECM User Documentation: User Manual Table of Contents • xv

5.3.1.2. Plant Location ........................................................................................................................ 423 5.3.1.3. Unit Systems .......................................................................................................................... 423



5.3.2.2. Fuel ........................................................................................................................................ 428 5.3.2.2.1. Properties ..................................................................................................................... 428 5.3.2.2.2. Cost ............................................................................................................................. 428

5.3.2.3. Power Block........................................................................................................................... 428 5.3.2.3.1. Gas Turbine Diagram .................................................................................................. 429 5.3.2.3.2. Steam Turbine Diagram ............................................................................................... 430 5.3.2.3.3. Gas Turbine Performance ............................................................................................ 430 5.3.2.3.4. Steam Cycle Performance ........................................................................................... 432 5.3.2.3.5. Emission Factors ......................................................................................................... 433 5.3.2.3.6. Capital Cost ................................................................................................................. 433 5.3.2.3.7. O&M Cost ................................................................................................................... 433 5.3.2.3.8. Retrofit or Adjustment Factors .................................................................................... 434

5.3.2.4. CO2 Capture, Transport & Storage ........................................................................................ 434 5.3.2.4.1. Amine System (CCS System) ...................................................................................... 434 5.3.2.4.2. Ammonia System (CCS System)................................................................................. 434 5.3.2.4.3. Pipeline Transport ....................................................................................................... 434 5.3.2.4.4. User-Specified Transport ............................................................................................. 434 5.3.2.4.5. CO2 Storage ................................................................................................................. 435

5.3.2.5. Water Systems ........................................................................................................................ 435 5.3.2.6. Water Life Cycle Assessment................................................................................................. 435


5.3.3.1.1. Diagram ....................................................................................................................... 435 5.3.3.1.2. Plant Performance ....................................................................................................... 435 5.3.3.1.3. Mass In/Out ................................................................................................................. 436 5.3.3.1.4. Gas Emissions ............................................................................................................. 437 5.3.3.1.5. Total Capital Cost ........................................................................................................ 437 5.3.3.1.6. Overall Plant Cost ....................................................................................................... 438 5.3.3.1.7. Cost Summary ............................................................................................................. 439

5.3.3.2. Fuel ........................................................................................................................................ 439 5.3.3.3. Power Block........................................................................................................................... 439

5.3.3.3.1. Gas Turbine Diagram .................................................................................................. 440 5.3.3.3.2. Steam Turbine Diagram ............................................................................................... 441 5.3.3.3.3. Syngas ......................................................................................................................... 442 5.3.3.3.4. Flue Gas ...................................................................................................................... 443 5.3.3.3.5. Capital Cost ................................................................................................................. 443 5.3.3.3.6. O&M Cost ................................................................................................................... 444 5.3.3.3.7. Total Cost .................................................................................................................... 445

5.3.3.4. CO2 Capture, Transport & Storage ........................................................................................ 445

IECM User Documentation: User Manual Table of Contents • xvi

5.3.3.4.1. Amine System (CCS System) ...................................................................................... 445 5.3.3.4.2. Ammonia System (CCS System)................................................................................. 445 5.3.3.4.3. Auxiliary Boiler ........................................................................................................... 445 5.3.3.4.4. CO2 Transport System ................................................................................................. 445

5.3.3.5. Water Systems ........................................................................................................................ 445 5.3.3.6. Stack ...................................................................................................................................... 445 5.3.3.7. Water Life Cycle Assessment................................................................................................. 445

5.4. Int. Gasif. Comb. Cycle (IGCC) Plant ........................................................................................................ 446 5.4.1. CONFIGURE SESSION .................................................................................................................. 446

5.4.1.1. Plant Design ........................................................................................................................... 446 5.4.1.2. Plant Location ........................................................................................................................ 448 5.4.1.3. Unit Systems .......................................................................................................................... 448



5.4.2.2. Fuel ........................................................................................................................................ 453 5.4.2.2.1. Coal Properties ............................................................................................................ 453 5.4.2.2.2. Ash Properties ............................................................................................................. 454 5.4.2.2.3. Cost ............................................................................................................................. 455

5.4.2.3. Air Separation Unit ................................................................................................................ 455 5.4.2.3.1. Air Separation Diagram ............................................................................................... 455 5.4.2.3.2. Performance ................................................................................................................ 456 5.4.2.3.3. Capital Cost ................................................................................................................. 457 5.4.2.3.4. O&M Cost ................................................................................................................... 457 5.4.2.3.5. Retrofit or Adjustment Factors .................................................................................... 457

5.4.2.4. Gasifier Area .......................................................................................................................... 457 5.4.2.4.1. GE ............................................................................................................................... 457

5.4.2.4.1.1. GE Gasifier Diagram .......................................................................................... 457 5.4.2.4.1.2. Performance ........................................................................................................ 458 5.4.2.4.1.3. Syngas Out .......................................................................................................... 460 5.4.2.4.1.4. Capital Cost......................................................................................................... 460 5.4.2.4.1.5. O&M Cost .......................................................................................................... 461 5.4.2.4.1.6. Retrofit or Adjustment Factors ............................................................................ 461

5.4.2.4.2. Shell............................................................................................................................. 462 5.4.2.4.2.1. Shell Gasifier Diagram ....................................................................................... 462 5.4.2.4.2.2. Performance ........................................................................................................ 463 5.4.2.4.2.3. Syngas Out .......................................................................................................... 464 5.4.2.4.2.4. Capital Cost......................................................................................................... 465 5.4.2.4.2.5. O&M Cost .......................................................................................................... 465 5.4.2.4.2.6. Retrofit or Adjustment Factors ............................................................................ 465

5.4.2.5. Sulfur Removal ...................................................................................................................... 466 5.4.2.5.1. Selexol Sulfur Removal ............................................................................................... 466

5.4.2.5.1.1. Sulfur Capture System Diagram ......................................................................... 467 5.4.2.5.1.2. Performance ........................................................................................................ 468

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5.4.2.5.1.3. Capital Cost......................................................................................................... 469 5.4.2.5.1.4. O&M Cost .......................................................................................................... 470 5.4.2.5.1.5. Retrofit or Adjustment Factors ............................................................................ 471

5.4.2.5.2. Sulfinol Sulfur Removal .............................................................................................. 472 5.4.2.5.2.1. Sulfur Capture System Diagram ......................................................................... 472 5.4.2.5.2.2. Performance ........................................................................................................ 473 5.4.2.5.2.3. Capital Cost......................................................................................................... 474 5.4.2.5.2.4. O&M Cost .......................................................................................................... 475 5.4.2.5.2.5. Retrofit or Adjustment Factors ............................................................................ 476

5.4.2.6. CO2 Capture, Transport & Storage ........................................................................................ 476 5.4.2.6.1. Chemical Looping ....................................................................................................... 476

5.4.2.6.1.1. Chemical Looping Diagram ................................................................................ 477 5.4.2.6.1.2. Purification Unit Diagram ................................................................................... 477 5.4.2.6.1.3. Config ................................................................................................................. 478 5.4.2.6.1.4. Performance ........................................................................................................ 479 5.4.2.6.1.5. T&S Config ......................................................................................................... 480 5.4.2.6.1.6. Capital Cost......................................................................................................... 481 5.4.2.6.1.7. O&M Cost .......................................................................................................... 481 5.4.2.6.1.8. Retrofit or Adjustment Factors ............................................................................ 482

5.4.2.6.2. Water Gas Shift Reactor .............................................................................................. 482 5.4.2.6.2.1. Water Gas Shift Reactor Diagram ....................................................................... 482 5.4.2.6.2.2. Performance ........................................................................................................ 483 5.4.2.6.2.3. Capital Cost......................................................................................................... 483 5.4.2.6.2.4. O&M Cost .......................................................................................................... 484 5.4.2.6.2.5. Retrofit or Adjustment Factors ............................................................................ 484

5.4.2.6.3. Ionic Liquid CO2 Capture ............................................................................................ 485 5.4.2.6.3.1. Ionic Liquid Diagram .......................................................................................... 485 5.4.2.6.3.2. Config ................................................................................................................. 486 5.4.2.6.3.3. Performance ........................................................................................................ 486 5.4.2.6.3.4. Capture ................................................................................................................ 487 5.4.2.6.3.5. T&S Config ......................................................................................................... 488 5.4.2.6.3.6. Capital Cost......................................................................................................... 489 5.4.2.6.3.7. O&M Cost .......................................................................................................... 489 5.4.2.6.3.8. Retrofit or Adjustment Factors ............................................................................ 490

5.4.2.6.4. Selexol CO2 Capture ................................................................................................... 491 5.4.2.6.4.1. Selexol CO2 Capture Diagram ............................................................................ 492 5.4.2.6.4.2. Performance ........................................................................................................ 492 5.4.2.6.4.3. T&S Config ......................................................................................................... 493 5.4.2.6.4.4. Capital Cost......................................................................................................... 494 5.4.2.6.4.5. O&M Cost .......................................................................................................... 494 5.4.2.6.4.6. Retrofit or Adjustment Factors ............................................................................ 495

5.4.2.6.5. Pipeline Transport ....................................................................................................... 496 5.4.2.6.6. User-Specified Transport ............................................................................................. 496

5.4.2.7. Power Block........................................................................................................................... 496 5.4.2.8. Water Systems ........................................................................................................................ 496


5.4.3.1.1. Diagram ....................................................................................................................... 496 5.4.3.1.2. Plant Performance ....................................................................................................... 497 5.4.3.1.3. Mass In/Out ................................................................................................................. 498 5.4.3.1.4. Gas Emissions ............................................................................................................. 498 5.4.3.1.5. Total Capital Cost ........................................................................................................ 499

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5.4.3.1.6. Overall Plant Cost ....................................................................................................... 499 5.4.3.1.7. Cost Summary ............................................................................................................. 500

5.4.3.2. Fuel ........................................................................................................................................ 501 5.4.3.3. Air Separation Unit ................................................................................................................ 501

5.4.3.3.1. Diagram ....................................................................................................................... 501 5.4.3.3.2. Gas Flow ..................................................................................................................... 502 5.4.3.3.3. Capital Cost ................................................................................................................. 503 5.4.3.3.4. O&M Cost ................................................................................................................... 504 5.4.3.3.5. Total Cost .................................................................................................................... 504

5.4.3.4. Gasifier Area .......................................................................................................................... 504 5.4.3.4.1. GE ............................................................................................................................... 505

5.4.3.4.1.1. Diagram .............................................................................................................. 505 5.4.3.4.1.2. Oxidant ............................................................................................................... 506 5.4.3.4.1.3. Syngas ................................................................................................................. 507 5.4.3.4.1.4. Capital Cost......................................................................................................... 508 5.4.3.4.1.5. O&M Cost .......................................................................................................... 509 5.4.3.4.1.6. Total Cost ............................................................................................................ 509

5.4.3.4.2. Shell............................................................................................................................. 510 5.4.3.4.2.1. Diagram .............................................................................................................. 510 5.4.3.4.2.2. Oxidant ............................................................................................................... 511 5.4.3.4.2.3. Syngas ................................................................................................................. 512 5.4.3.4.2.4. Capital Cost......................................................................................................... 513 5.4.3.4.2.5. O&M Cost .......................................................................................................... 514 5.4.3.4.2.6. Total Cost ............................................................................................................ 514

5.4.3.5. Sulfur Removal ...................................................................................................................... 515 5.4.3.5.1. Sulfur Capture System (Selexol) ................................................................................. 515

5.4.3.5.1.1. Diagram .............................................................................................................. 515 5.4.3.5.1.2. Capital Cost......................................................................................................... 516 5.4.3.5.1.3. O&M Cost .......................................................................................................... 517 5.4.3.5.1.4. Total Cost ............................................................................................................ 518

5.4.3.5.2. Sulfur Capture System (Sulfinol) ................................................................................ 518 5.4.3.5.2.1. Diagram .............................................................................................................. 518 5.4.3.5.2.2. Capital Cost......................................................................................................... 519 5.4.3.5.2.3. O&M Cost .......................................................................................................... 520 5.4.3.5.2.4. Total Cost ............................................................................................................ 521

5.4.3.5.3. Hydrolyzer ................................................................................................................... 521 5.4.3.5.3.1. Syngas ................................................................................................................. 521

5.4.3.5.4. Selexol Sulfur System ................................................................................................. 522 5.4.3.5.4.1. Syngas ................................................................................................................. 522

5.4.3.5.5. Sulfinol Sulfur Capture ............................................................................................... 523 5.4.3.5.5.1. Syngas ................................................................................................................. 523

5.4.3.5.6. Claus Plant................................................................................................................... 524 5.4.3.5.6.1. Air ....................................................................................................................... 524 5.4.3.5.6.2. Treated Gas ......................................................................................................... 525

5.4.3.5.7. Beavon-Stretford Plant ................................................................................................ 526 5.4.3.5.7.1. Treated Gas ......................................................................................................... 526 5.4.3.5.7.2. Flue Gas .............................................................................................................. 527

5.4.3.6. CO2 Capture, Transport & Storage ........................................................................................ 527 5.4.3.6.1. Chemical Looping ....................................................................................................... 527

5.4.3.6.1.1. Diagram .............................................................................................................. 528 5.4.3.6.1.2. Air ....................................................................................................................... 529 5.4.3.6.1.3. Syngas ................................................................................................................. 530

IECM User Documentation: User Manual Table of Contents • xix

5.4.3.6.1.4. Capital Cost......................................................................................................... 530 5.4.3.6.1.5. O&M Cost .......................................................................................................... 531 5.4.3.6.1.6. Total Cost ............................................................................................................ 532 5.4.3.6.1.7. Summary ............................................................................................................. 532

5.4.3.6.2. Purification Unit .......................................................................................................... 533 5.4.3.6.2.1. Diagram .............................................................................................................. 533

5.4.3.6.3. Water Gas Shift Reactor .............................................................................................. 534 5.4.3.6.3.1. Diagram .............................................................................................................. 534 5.4.3.6.3.2. Syngas ................................................................................................................. 535 5.4.3.6.3.3. Capital Cost......................................................................................................... 535 5.4.3.6.3.4. O&M Cost .......................................................................................................... 536 5.4.3.6.3.5. Total Cost ............................................................................................................ 537

5.4.3.6.4. Ionic Liquid CO2 Capture ............................................................................................ 537 5.4.3.6.4.1. Diagram .............................................................................................................. 537 5.4.3.6.4.2. Syngas ................................................................................................................. 538 5.4.3.6.4.3. Capital Cost......................................................................................................... 539 5.4.3.6.4.4. O&M Cost .......................................................................................................... 540 5.4.3.6.4.5. Total Cost ............................................................................................................ 541 5.4.3.6.4.6. Summary ............................................................................................................. 541

5.4.3.6.5. Selexol CO2 Capture ................................................................................................... 542 5.4.3.6.5.1. Diagram .............................................................................................................. 542 5.4.3.6.5.2. Syngas ................................................................................................................. 543 5.4.3.6.5.3. Capital Cost......................................................................................................... 544 5.4.3.6.5.4. O&M Cost .......................................................................................................... 545 5.4.3.6.5.5. Total Cost ............................................................................................................ 546 5.4.3.6.5.6. Summary ............................................................................................................. 546

5.4.3.6.6. CO2 Transport System ................................................................................................. 547 5.4.3.7. Power Block........................................................................................................................... 547 5.4.3.8. Water Systems ........................................................................................................................ 547 5.4.3.9. Stack ...................................................................................................................................... 547

6. A Case Study 548

6.1. Introduction ................................................................................................................................................ 548 6.2. Start the IECM ............................................................................................................................................ 548 6.3. Create a New Session ................................................................................................................................. 549 6.4. Configure Session ....................................................................................................................................... 551 6.5. Set Parameters ............................................................................................................................................ 552

6.5.1. Overall Plant ..................................................................................................................................... 553 6.5.1.1. Performance ........................................................................................................................... 554

6.5.2. Fuel................................................................................................................................................... 555 6.5.2.1. Choose a Coal ........................................................................................................................ 555

6.5.3. Base Plant ......................................................................................................................................... 558 6.5.3.1. Base Plant Performance ......................................................................................................... 559

6.5.4. Other Input Areas and Technologies ................................................................................................ 564 6.6. Get Results .................................................................................................................................................. 565

6.6.1. Overall Plant ..................................................................................................................................... 566 6.6.1.1. Performance Summary .......................................................................................................... 567 6.6.1.2. Gas In/Out .............................................................................................................................. 568 6.6.1.3. Cost Summary ....................................................................................................................... 570

6.6.2. Base Plant ......................................................................................................................................... 570 6.6.2.1. Diagram ................................................................................................................................. 571 6.6.2.2. Capital Cost ........................................................................................................................... 572

IECM User Documentation: User Manual Table of Contents • xx

6.6.2.3. O&M Cost ............................................................................................................................. 573 6.7. Graphs ......................................................................................................................................................... 573

7. Introduction to Uncertainty Analysis 575

7.1. Uncertainty Analysis ................................................................................................................................... 575 7.2. Introduction ................................................................................................................................................ 575 7.3. Philosophy of Uncertainty Analysis ........................................................................................................... 575 7.4. Types of Uncertain Quantities .................................................................................................................... 576 7.5. Encoding Uncertainties as Probability Distributions .................................................................................. 576

7.5.1. Statistical Techniques ....................................................................................................................... 576 7.5.2. Judgments about Uncertainties ......................................................................................................... 577

7.5.2.1. Availability ............................................................................................................................. 577 7.5.2.2. Representativeness ................................................................................................................. 577 7.5.2.3. Anchoring and Adjustment .................................................................................................... 577 7.5.2.4. Motivational Bias ................................................................................................................... 577

7.6. Designing an Elicitation Protocol ............................................................................................................... 577 7.7. A Non-technical Example ........................................................................................................................... 578 7.8. A Technical Example .................................................................................................................................. 578

IECM User Documentation: User Manual Acknowledgments • xxi

Acknowledgments

This Integrated Environmental Control Model (IECM) was developed for the U.S. Department of

Energy’s National Energy Technology Laboratory (DOE/NETL). Any opinions, findings,

conclusions or recommendations expressed in this material are those of the authors alone and do not

reflect the views of any agency.

IECM User Documentation: User Manual Introduction • 1

1. Introduction

1.1. The Integrated Environmental Control Model This Integrated Environmental Control Model (IECM) was developed for the U.S. Department of

Energy’s National Energy Technology Laboratory (DOE/NETL).

1.2. Purpose The purpose of the model is to calculate the performance, emissions and cost of employing alternative

environmental control methods in a coal-fired or gas-fired power plant, including pulverized coal (PC)

plants, integrated gasification combined cycle (IGCC) plants, and natural gas combined cycle (NGCC)

plants. In each case, the model consists of a base plant and various control technology modules. These

modules may be implemented together in a variety of combinations.

1.3. System Requirements The IECM software runs in the following environments:

• Windows XP (32 bit only)

• Windows Vista, 7, 8, and 10

• MacOS X and Linux under Wine

The IECM requires approximately 65 Megabytes of disk space.

1.3.1. MacOS X and Linux

We do not currently provide Mac- or Linux-native versions of the IECM; however, the Windows

version runs under Wine. The IECM is currently a 32-bit application and requires 32-bit Wine. See

"3.2.1. Installing the IECM on MacOS and Linux" on page 10 for more information.

1.4. Uncertainty Features The ability to characterize uncertainties explicitly is a feature unique to this model. As many as one

hundred input parameters can be assigned probability distributions. When input parameters are uncertain,

an uncertainty distribution of results is available. Such result distributions give the likelihood of a

particular value, in contrast to conventional single-value estimates. (See "7. Introduction to Uncertainty

Analysis" on page 575.)


The IECM normally displays only single deterministic values. However, a graph or table of the

uncertainty distribution for any parameter or result may be requested—for instance, to analyze advanced

technology costs. (See "4.3.3.6. The Right-Click Menu" on page 74 and "4.4.4. The Right-Click Menu"

on page 80.)

The IECM also provides a list of all uncertain parameters and results, allowing the user to easily view

relevant results and detect any unanticipated effects. (See "4.5.3.2. Choose Variable(s)" on page 88.)

The uncertainty system can also be used for batch processing by giving each parameter to be varied a

"distribution" containing the desired values, where each "sample" is one set of input values. Result

distributions are then viewed as tables, allowing the user to see which result corresponds with each input

set. (See "4.3.3.3.13. Batch Processing" on page 66.)

1.5. Sensitivity Analysis The IECM allows most parameters to be used as independent variables in a sensitivity analysis. Once the

independent variable has been chosen and its values specified, a list of dependent variables is provided,

allowing the user to see the effects of the independent variable across the entire model as well as focus on

a specific result. (See "4.5.2. Sensitivity Analysis" on page 80.)

1.6. Software Used in Development The IECM is currently compiled using Code::Blocks (http://www.codeblocks.org/). The "mingw_fortran"

setup is used, which includes GCC/G++ and GFortran. The interface is written in C++, using the

wxWidgets GUI toolkit (http://wxwidgets.org/). The underlying engineering models are written in

Fortran. The necessary runtime libraries are included with the IECM Interface software.

All databases are in SQLite (http://sqlite.org/) format.

The installer is built using InnoSetup (http://www.jrsoftware.org/isinfo.php).

1.7. Disclaimer of Warranties and Limitation of Liabilities This report was prepared by the organization(s) named below as an account of work sponsored or

cosponsored by the U.S. Department of Energy National Energy Technology Laboratory (NETL).

NEITHER NETL, ANY MEMBER OF NETL, ANY COSPONSOR, THE ORGANIZATION(S)

NAMED BELOW, NOR ANY PERSON ACTING ON BEHALF OF THEM:

(A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED,

(I) WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS,

OR SIMILAR ITEM DISCLOSED IN THIS REPORT, INCLUDING MERCHANTABILITY AND

FITNESS FOR A PARTICULAR PURPOSE, OR (II) THAT SUCH USE DOES NOT INFRINGE ON

OR INTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY'S

INTELLECTUAL PROPERTY, OR (III) THAT THIS REPORT IS SUITABLE TO ANY PARTICULAR

USER'S CIRCUMSTANCE; OR

(B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER

(INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF DOE OR ANY DOE

REPRESENTATIVE HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES)

RESULTING FROM YOUR SELECTION OR USE OF THIS REPORT OR ANY INFORMATION,

APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS REPORT.

Organization(s) that prepared this report: Carnegie Mellon University

http://www.codeblocks.org/

http://wxwidgets.org/

http://sqlite.org/

http://www.jrsoftware.org/isinfo.php


1.8. Copyright Notices Integrated Environmental Control Model (IECM), Copyright © 1997-2017, Carnegie Mellon University.

All Rights Reserved.

Median Latin Hypercube and Hammersley Sequence Sampling, Copyright © 1997, Urmila Diwekar,

Carnegie Mellon University. All Rights Reserved. (Covered by the IECM license.)

WxWidgets, Copyright © 1992-2013 Julian Smart, Vadim Zeitlin, Stefan Csomor, Robert Roebling, and

other members of the wxWidgets team (full list and license at

<http://docs.wxwidgets.org/3.0/page_copyright.html>). Portions © 1996 Artificial Intelligence

Applications Institute.

Code::Blocks, Copyright © 2004-2013 Code::Blocks Team (license at

<http://www.codeblocks.org/license>).

MinGW+GCC, Copyright © 2012 Free Software Foundation, Inc. (license at

<http://www.mingw.org/license>).

Inno Setup, Copyright © 1997-2013 Jordan Russell. All rights reserved. Portions Copyright © 2000-2013

Martijn Laan. All rights reserved. (info including license at <http://www.jrsoftware.org/isinfo.php>).

1.9. User Documentation and Help The user manual (this document) is included with the IECM. Other documents, including technical

documentation, can be downloaded at http://www.iecm-online.com/iecm_docpubs.html.

http://docs.wxwidgets.org/3.0/page_copyright.html

http://www.codeblocks.org/license

http://www.mingw.org/license

http://www.jrsoftware.org/isinfo.php

http://www.iecm-online.com/iecm_docpubs.html

IECM User Documentation: User Manual Microsoft® Windows Conventions • 4

2. Microsoft® Windows Conventions

2.1. Windows The Windows operating environment is based on both graphics and text. Although it is designed to be

intuitive, a certain amount of learning is required to use it effectively. Please review the documentation

on Windows that came with your personal computer if you are new to the Windows environment.

2.2. Using a Mouse or Touchscreen Many commands in Windows are executed by moving the mouse pointer to an item and pressing the left

or right button on the mouse.

In this documentation, the following terms will be used for mouse operations:

Click - Place the mouse cursor onto a menu, button, field, etc., and press the left button on the mouse. (If

you are using a touchscreen, tap the menu, button, field, etc., with one finger.)

Right Click - Place the mouse cursor onto a menu, button, field, etc., and press the right button on the

mouse. (If you are using a touchscreen, touch and hold with one finger until a box or circle appears, then

lift your finger off the screen.)

Double-Click - Place the mouse cursor onto a menu, button, field, etc., and press the left button on the

mouse two times rapidly. (If you are using a touchscreen, rapidly tap twice with one finger.)

Click and Drag - Place the mouse cursor onto a menu, button, field, etc., press the left button on the

mouse, and—while holding the button down—move the mouse to another location. (If you are using a

touchscreen, tap and drag with one finger.)

2.3. Pull-Down Menus Pull-down menus appear frequently in Windows. Here are a couple of examples from the IECM:

Illustration 1: The IECM's main Menu Bar, with "File" and "Help" pull-down menus

Illustration 2: The "Fuel Type" pull-down menu on the IECM's "Plant Design" screen


2.3.1. Choosing a Command from a Pull-Down Menu

1. Activate the pull-down menu by doing one of the following:

◦ Place the mouse arrow on the title of the menu (first example) or the triangle on the side

of the menu (second example) and click.

◦ If a letter in the menu title is underlined, hold down the Alt key on the keyboard and

press the letter in the menu title which is underlined. For example, to access the "File"

menu in the first example, you would press Alt-F. (See "2.4. Keystroke Commands" on

page 5.)

2. Choose from the menu by doing one of the following:

◦ Place the mouse arrow on the action you want to perform and click.

◦ If a letter in the title is underlined, press that letter.

2.4. Keystroke Commands Many operations in Windows can be executed by a combination of keystrokes as well as a mouse click.

These keystroke combinations involve the Alt key and the Ctrl key.

NOTE: Once an Alt key combination is active, the Ctrl key combinations will not work. The Ctrl key

combinations are meant to bypass menus.

2.4.1. Alt Commands

When the name of an operation appears with one letter underlined, you may execute that operation by

holding down the Alt key while pressing the key for the underlined letter at the same time.

For example: "File - hold down the Alt key and press the F key to activate the 'File' pull-down menu."

In this documentation, instructions for Alt keystrokes are abbreviated in the form “Press Alt-X” where

X is the letter key. (NOTE: While the capital letter is given in this documentation, do not press the

shift key while entering the command.)

For example: "Press Alt-F to activate the 'File' menu."

2.4.2. Ctrl Commands

Some operations have been assigned specific keystroke combinations involving the Ctrl key. You may

execute them by holding down the Ctrl key while pressing the key for the appropriate letter. Most are

listed on the pull-down menu from which the command is normally selected.

In this documentation, instructions for Ctrl keystrokes are abbreviated in the form “Press Ctrl-X”

where X is the letter key. (NOTE: While the capital letter is given in this documentation, do not press

the shift key while entering the command.)

Some of the more common Ctrl commands are the following:

Ctrl-N – New Session Ctrl-O – Open Session Ctrl-S – Save Session

Ctrl-C – Copy Ctrl-X – Cut Ctrl-V – Paste

Ctrl-P – Print Ctrl-W – Close Window Ctrl-Q – Exit


2.5. Editing Text Editable text appears in many places, both in Windows and in the IECM. For example, most parameters

in the IECM are presented as editable text.

Clicking the mouse on the text will put a cursor (usually a blinking vertical bar) in the text at the point

where you clicked. You can then move the cursor with the arrow keys on your keyboard, delete text with

the backspace and/or Del keys, and type new text. (The backspace key deletes the character before the

cursor, while the Del key deletes the character after it.)

You can also select text. If you have text selected, backspace or Del will delete it, and typing new text

will replace it. You can select text in the following ways:

• Double-click the text. This will select a word. The definition of "word" varies somewhat

between applications, but typically it is a block of text delimited by spaces and certain

punctuation.

• Click and drag the mouse from one end of the desired selection to the other. (See "2.2. Using a

Mouse or Touchscreen" on page 4.)

• Click or use the arrow keys to move to one end of the selection, then press and hold the Shift

key while using the arrow keys to move to the other end.

Copy (Ctrl-C), Cut (Ctrl-X), and Paste (Ctrl-V) work in many places, even if they are not accessible

from the menu bar. These will be described in the following section.

When you are finished entering text in the IECM, you will generally want to press Enter or Tab to let the

IECM know that you are finished.

2.6. Using the Clipboard The clipboard is a temporary storage area that facilitates the movement of data between applications, or

between different parts of the same application. To use it, select the item you wish to copy, and use the

Copy command (Ctrl-C or "Copy" in the "Edit" menu) to copy it to the clipboard. You may use the Cut

command (Ctrl-X or "Cut" in the "Edit" menu) if you want to delete the selected item in addition to

copying it. Then, go to the location where you want the item to appear, switching applications if

necessary, and use the Paste command (Ctrl-P or "Paste" in the "Edit" menu) to insert the contents of the

clipboard at the new location.

2.7. The Taskbar The taskbar contains buttons for each running application. Clicking these buttons allows you to switch

between applications and/or windows.

This is the left side of a taskbar including buttons for three IECM windows:

In this case, the IECM is running with two open sessions. The main window is labeled "IECM

Interface..."

Illustration 3: The Left Side of the Taskbar


2.7.1. Switching Applications or Windows

You can switch to a different application or window by clicking the corresponding button on the

taskbar. You can also do this by pressing Alt-Tab. If you're using Alt-Tab, hold the Alt key down and

press Tab repeatedly until the window you want is selected, then release the Alt key.

2.7.2. The Start Button

The Start Button is located on the left side of the taskbar. It looks something like this:

The Start Button brings up the Start Menu, which gives you access to your applications, settings, and

files.

Illustration 4: The Start Button


2.7.2.1. The Start Menu

The Start Menu looks something like this:

You will, of course, have different applications installed, so the list on your Start Menu will be

different.

Illustration 5: The Start Menu


2.7.2.1.1. Start Menu Folders

The list of applications in the Start Menu includes some folders. For example, the IECM folder

will look something like this:

Start Menu folders are not expanded to show their contents by default. The folder may expand

when you hover the mouse pointer over it; if not, click on it to expand it:

2.7.2.1.2. The Settings Button

In Windows 10, the Settings button may not have a visible title. It is located on the left edge of

the Start Menu and looks something like this:

Illustration 6: The IECM Start Menu Folder

Illustration 7: The IECM Start Menu Folder Expanded

Illustration 8: The Settings Button

IECM User Documentation: User Manual Installing the IECM • 10

3. Installing the IECM

3.1. What's included in the Model Package The IECM package is contained in a single installation program in compressed form. This file is

available on the IECM web site (http://www.iecm-online.com/iecm_dl.html). It contains the following:

• The IECM Interface application: This includes the underlying engineering models as well as

the user interface.

• Runtime libraries needed by the IECM Interface: These include libraries needed by the

GFortran and GCC compilers.

• Images used by the IECM Interface: These include backgrounds and components of various

diagrams.

• Databases used by the IECM Interface: These include default fuels and reservoirs for CO2

storage, along with some case studies.

• License and readme files.

• The User Manual.

Note: Technical Manuals are not distributed with the model package, but can be downloaded from the

IECM web site at http://www.iecm-online.com/iecm_docpubs.html.

3.2. Installation To install the IECM, you must use the IECM setup application downloaded from the IECM web site

(http://www.iecm-online.com/iecm_dl.html).

3.2.1. Installing the IECM on MacOS and Linux

We do not currently provide Mac- or Linux-native versions if the IECM; however, the Windows

version runs under Wine. Wine is available at http://www.winehq.org/. Currently, the IECM is a 32-bit

application and requires 32-bit Wine.

The use of the IECM under Wine is not officially supported; however, we will try to avoid doing

anything that would cause it to stop working.

3.2.1.1. MacOS

If you are running MacOS X, we suggest you use Wineskin, available at

http://wineskin.urgesoftware.com/. The manual, available on the Wineskin web site

http://wineskin.urgesoftware.com/tiki-index.php?page=Manual, has some information on how to use

http://www.iecm-online.com/iecm_dl.html

http://www.iecm-online.com/iecm_docpubs.html

http://www.iecm-online.com/iecm_dl.html

http://www.winehq.org/

http://wineskin.urgesoftware.com/

http://wineskin.urgesoftware.com/tiki-index.php?page=Manual


it. Basically, you need to create a wrapper (section 2.3 Creating Wrappers) and then run the wrapper

and tell it to install the IECM (section 4.1 The Installer, "way 1" works best for the IECM). The

main executable file is "iecmint.exe".

If you need to change the configuration after you've installed it, e.g., to upgrade the wrapper and/or

engine, section 3.1 "A Look Inside a Wrapper" tells you how to get to the configuration.

3.2.1.2. Linux

Wine is probably available in whatever software manager your distro uses, or you can download it at

http://www.winehq.org/. PlayOnLinux also works well; if it's not available with your distro, you can

download it at http://www.playonlinux.com/.

RedHat Linux and related distributions do not currently include 32-bit Wine. If your distribution

doesn't include 32-bit Wine, instructions on how to build it yourself are available at

https://www.systutorials.com/239913/install-32-bit-wine-1-8-centos-7/.

3.2.2. Installation Steps

3.2.2.1. Running the IECM Setup Application

Go to the location where you saved the IECM setup application, typically in your Downloads folder,

and double-click it to run it. The setup application will begin.

3.2.2.2. Welcome Dialog

The first dialog which displays is the "Welcome" dialog. It introduces you to the IECM setup

application and recommends that you close all other applications before continuing the installation:

To quit other programs, you should click the "Cancel" button at the bottom of the "Welcome" dialog

first and then proceed to quit all other applications. Once other applications are closed, you can

restart the installation process.

If there are no other applications running, click the "Next" button to continue to the next dialog.

Illustration 9: The IECM Setup "Welcome" Dialog

http://www.winehq.org/

http://www.playonlinux.com/

https://www.systutorials.com/239913/install-32-bit-wine-1-8-centos-7/


3.2.2.3. License Agreement

The next dialog to appear displays the license agreement:

Read the license agreement by scrolling down the window. You cannot install and run the IECM

without agreeing to the license agreement. If you do not agree, the setup application will quit.

Click "I accept the agreement" to agree to the license, and then click the "Next" button to continue

to the next dialog.

3.2.2.4. Information

The next dialog displays information about the IECM:

Read this information by scrolling down the window.

Illustration 10: The IECM Setup "License Agreement" Dialog

Illustration 11: The IECM Setup "Information" Dialog


Click the "Next" button to continue to the next dialog.

3.2.2.5. Select Destination Location

The "Select Destination Location" installation dialog asks you to specify the location where the

setup application will put the IECM on your computer:

The default location for each version is different than the default used in previous versions; previous

versions will co-exist on your computer.

Click the "Next" button to continue to the next dialogs.

3.2.2.6. Select Start Menu Folder

This dialog asks you to specify the Start Menu folder that will contain the icons to launch the IECM

Interface application and view the included documentation:

Illustration 12: The IECM Setup "Select Destination Location" Dialog


The default Start Menu folder is different than the default used in previous versions; previous

versions will co-exist on your computer.

Click the "Next" button to continue to the next dialog.

3.2.2.7. Select Additional Tasks

This dialog allows you to specify additional options for the IECM installer:

Currently, the only additional option is to put an icon for the IECM Interface on the Desktop. This

option is not selected by default; check the box if you want an icon on your Desktop.

Click the "Next" button to continue to the next screen.

Illustration 13: The IECM Setup "Select Start Menu Folder" Dialog

Illustration 14: The IECM Setup "Select Additional Tasks" Dialog


3.2.2.8. Ready to Install

The IECM software is now ready to install:

The "Ready to Install" dialog allows you to go back one last time to check the options you have

chosen for installation.

Click the "Back" button to return to any of the previous screens to check or change the installation

options. Click the "Next" button to continue to install the software.

3.2.2.9. Installation Progress

The setup application now begins copying files onto your hard disk and preparing it for your use.

The progress of the activity is shown on the "Installing" dialog:

Illustration 15: The IECM Setup "Ready to Install" Dialog

Illustration 16: The IECM Setup "Installing" Dialog


3.2.2.10. Installation Complete

Once the setup application has completed installing the IECM software, the "Completing the IECM

Interface Setup Wizard" dialog will display:

This dialog gives you the option of running the newly-installed IECM Interface application

immediately. This option is selected by default. If you do not want to run the IECM right now,

uncheck the box before proceeding.

Click the "Finish" button to exit the installation program.

3.2.3. Canceling the Installation

You can stop the installation process at any time by clicking the Cancel button, which appears on each

screen, including the Installation Progress screen. Canceling the process stops all activity and exits the

setup application.

3.2.4. Errors During Installation

If you receive an error message while running Setup, restart the computer and run the installation

again. If Setup still returns an error message, contact technical support by electronic mail

([email protected]) or on our web site (http://www.iecm-online.com/support.html).

3.3. Removing the IECM Software To remove the IECM software completely, either use the "Uninstall" application included with it, or

uninstall it from the "Apps & Features" settings in Windows 10. (Older versions of Windows have a

"Programs and Features" control panel instead.)

NOTE: Do not just delete the files in the IECM folder, because there are files elsewhere on your system

that should also be cleaned up. Deleting the IECM folder could also cause a subsequent attempt to

uninstall the software correctly to fail.

Illustration 17: The IECM Setup "Completing the IECM Interface Setup Wizard"

Dialog

mailto:[email protected]

http://www.iecm-online.com/support.html


3.3.1. Uninstall the IECM Using the Included Uninstall Application

1. Click the Start button. (See "2.7.2. The Start Button" on page 7)

2. Click the folder corresponding to the version of the IECM that you want to remove. (See

"2.7.2.1.1. Start Menu Folders" on page 9.)

3. Click the "Uninstall..." application at the bottom of the list in that folder to run it:

4. Follow the instructions on the screen.

3.3.2. Uninstall the IECM Using Settings on Windows 10

1. Click the Start button.

2. Choose "Settings".

3. Click "Apps", then "Apps & Features".

4. Scroll down to find the IECM Interface on the list of installed software, and click on it to

select it.

5. Click the "Uninstall" button.


3.3.3. Uninstall the IECM Using the Control Panel on Windows 7


2. Choose "Settings", and then "Control Panel". (If "Control Panel" is shown in your Start Menu,

you may go there directly.)

3. In the "Programs" category, click "Uninstall a program".

4. Scroll down to find the IECM Interface on the list of installed software, and clock on it to

select it.

5. Click the "Uninstall" button near the top of the window.


3.3.4. Uninstall the IECM Using the Control Panel on Windows XP


Illustration 18: The IECM Uninstall Application


2. Choose "Settings", and then "Control Panel". (If "Control Panel" is shown in your Start Menu,

you may go there directly.)

3. Click "Add or Remove Programs"

4. Scroll down to find the IECM Interface on the list of installed software, and click on it to

select it.

5. Click the "Remove" button.


IECM User Documentation: User Manual Using the IECM • 19

4. Using the IECM

4.1. The IECM Interface

4.1.1. Starting the IECM Interface

To run the IECM Interface, do the following:

1. Click the Start button. (See "2.7.2. The Start Button" on page 7.)

2. Click the folder corresponding to the version of the IECM that you want to run. (See

"2.7.2.1.1. Start Menu Folders" on page 9.)

3. Click the "IECM Interface..." application at the top of the list in that folder to run it:

Illustration 19: The IECM Interface Application in the Start Menu


When the IECM starts, a Splash Screen is displayed:

The Splash Screen will disappear after a few seconds, leaving the Main Window. You may click on the

Splash Screen to dismiss it if you don't want to wait for it to go away on its own.

4.1.2. The Main Window

Once you have started the model, the Main Window displays:

The Main Window allows the user to create and open sessions (see "4.1.3. Creating and Opening

Sessions" on page 22), and to exit the IECM.

4.1.2.1. The Main Window Menu Bar

The menu bar appears at the top of the main window. (See "2.3. Pull-Down Menus" on page 4.) It

consists of two pull-down menus: "File" and "Help". These pull-down menus issue commands to the

IECM software.

Illustration 20: The IECM Splash Screen

Illustration 21: The IECM Main Window


4.1.2.1.1. The File Menu

The "File" menu is the left-most pull-down menu on the menu bar:

You may choose the following commands from the "File" menu:

• New Session...: Creates a new session from model defaults. (See "4.1.3.1. Creating a

New Session from Model Defaults" on page 22.)

• Open Session...: Opens a previously created session. (See "4.1.3.2. Opening an Existing

Session" on page 23.)

• Delete Session...: Deletes a session. (See "4.1.7. Deleting Sessions" on page 43.)

• Unlock Session...: Unlocks a session that was not closed normally, e.g., because of a

crash or loss of network connectivity. (See "4.1.8. Unlocking Sessions" on page 43.)

• Exit: Closes all sessions and exits the interface. (See "4.1.9. Exiting the IECM Interface"

on page 44.)

4.1.2.1.2. The Help Menu

The "Help" menu is the second pull-down menu on the menu bar:

You may choose the following commands from this menu:

• Help Topics: There is currently no help file for the IECM. This command refers you to

the PDF files that were installed with the IECM.

• About IECM Interface: Displays the Splash Screen.

• Show IECM Path: Displays information about where the IECM is installed on your

computer as well as the full version number.

Illustration 22: The Main Window File Menu

Illustration 23: The Main Window Help Menu


4.1.2.2. The Main Window Toolbar

The toolbar is a row of buttons that sits under the menu bar:

Clicking on a button executes a common command. All of the commands can also be executed from

pull-down menus.

When the mouse pointer is held over a toolbar button momentarily, a description of the button's

command displays.

4.1.3. Creating and Opening Sessions

A session is a complete collection of data—configuration settings, and input parameters—that

describes one power plant. The model uses the configuration settings and parameters in a session to

calculate the results.

You may run multiple power plant sessions at the same time in order to compare configurations,

results, etc.

4.1.3.1. Creating a New Session from Model Defaults

To create a new session, do one of the following:

• Open the "File" menu (see "4.1.2.1.1. The File Menu" on page 21) and choose "New

Session..."

• Click the "New Session" button on the toolbar in either the main window (see "4.1.2.2. The

Main Window Toolbar" on page 22) or a session window (see "4.1.4.2.1. The "New

Session" Button" on page 31).

• Type Ctrl-N.

All of these methods will work in a session window as well as in the main window. If you already

have a session open, you do not need to return to the main window to create a new one.

Once you have activated the "New Session" command, a "New Session" dialog will be displayed:

There are two properties of the session that can be set at this stage: the plant type and the name.

Illustration 24: The Main Window Toolbar

Illustration 25: The "New Session" Dialog


4.1.3.1.1. Choose a Plant Type

The first step in creating a new session is to choose a plant type. The plant type cannot be

changed after the session is created; this is your only opportunity to set it. Click the "Plant Type"

menu to see the available plant types:

You may choose from the following plant types:

• Pulverized Coal (PC)

• Natural Gas Combined Cycle (NGCC)

• Integrated Gasification Combined Cycle (IGCC)

4.1.3.1.2. Choose a Name

You may also set the name of the session here. (See "2.5. Editing Text" on page 6.) You will have

an opportunity to change the name when you save the session, so if you don't want to set it here,

just accept the default.

Click "Ok" to create the new session.

4.1.3.2. Opening an Existing Session

You may want to open a session that you have previously saved, or use one of the case studies

included with the IECM. To open an existing session, do one of the following:

• Open the "File" menu (see "4.1.2.1.1. The File Menu" on page 21) and choose "Open

Session..."

• Click the "Open Session" button on the toolbar in either the main window (see

"4.1.2.2. The Main Window Toolbar" on page 22) or a session window (see "4.1.4.2.2. The

"Open Session" Button" on page 31).

• Type Ctrl-O.

All of these methods will work in a session window as well as in the main window. If you already

have a session open, you do not need to return to the main window to open a new one.

Once you have activated the "Open Session" command, an "Open Session" dialog will be displayed:

Illustration 26: Plant Types for a New Session

Illustration 27: The "Open Session" Dialog


4.1.3.2.1. Choose a Session Database

The first step in opening an existing session is choosing a session database. Session databases are

listed on the left side of the "Open Session" Dialog:

There are three columns in this list:

• Lock: A "*" in this column indicates that the database is "read-only", i.e., you cannot

save sessions in this database.

• File: This is the filename of the database. The IECM automatically creates a database,

"sessdb.sdb", where you can save sessions. The other databases shown in the illustration

are case studies, which are locked to prevent accidental modification.

• Path: This is the full path of the database. (It has been truncated in the illustration to

improve readability.) If you happen to have multiple databases with the same filename,

you can distinguish between them by looking at the path.

Click on the database containing the session you want to open.

Illustration 28: The List of Session Databases


4.1.3.2.1.1. Opening a Session Database

If the database you want is not in the list, click "Open DB" in the lower left corner of the

"Open Session" dialog. This will bring up a dialog that allows you to open a session database:

Use this dialog to navigate to the location of your database, then select it and click "Open".

If you want to prevent accidental modification of sessions in this file, click the "Read Only"

checkbox in the lower left corner of the "Open Database(s)" dialog. Note that this will only be

in effect until you either close the database or exit the IECM.

In some cases, you may have a session database with an extension other than ".sdb". Use the

"Files of type" menu in the bottom center of the dialog to change which files are shown:

Illustration 29: The "Open Database(s)" Dialog

Illustration 30: The "Files of type" Menu


4.1.3.2.2. Choose a Session

The right side of the "Open Session" Dialog (Illustration 27: The "Open Session" Dialog on page

23) contains a list of the sessions in the selected database. As an example, select the "NETL Case

b12a and b12b" database:

Selecting this database shows the sessions it contains:

The list of sessions contains two columns:

• Lock: A "*" in this column means that the session is "Read-Only". This means that you

cannot save any changes back to the original session. You may still change the session;

however, you will need to use "Save As..." if you want to save those changes.

• Session: The name of the session.

Checking the "Read Only" checkbox under the session list is equivalent to having a "*" in the

"Lock" column.

Illustration 31: Choose the NETL Case b12a and b12b Database

Illustration 32: Sessions in the NETL Case b12a and b12b Database


Click on the session you want to open, then click "Open" in the upper right corner of the dialog.

Note that you can select multiple sessions, as long as they are in the same database. To select a

contiguous region, click the session at one end, then press and hold the shift key while clicking

the session (Shift-Click) at the other end. You can also select or deselect individual sessions

using Ctrl-Click.

4.1.4. The Session Window

Once you have opened or created a session (see "4.1.3. Creating and Opening Sessions" on page 22), a

session window displays for the session you are working with:

The session window contains all the screens used by the session.

If additional windows are open in the IECM, they may be behind the new session window. If you want

to switch to another window that is partially visible, you may click on it to bring it to the front. If the

window is completely hidden, you will need to use Alt-Tab or the taskbar to switch to it. (See

"2.7.1. Switching Applications or Windows" on page 7.)

4.1.4.1. The Session Window Menu Bar

Like the main window, the session window has a menu bar. It consists of four pull-down menus:

"File", "Edit", "Go", and "Help". These pull-down menus issue commands to the IECM software.

Illustration 33: An IECM Session Window


4.1.4.1.1. The File Menu

The "File" menu is the left-most pull-down menu on the menu bar:

Some of the commands are the same as those available in the "File" menu on the main window.

See "4.1.2.1.1. The File Menu" on page 21, for a description of these commands.

The "File" menu on a session window contains the following additional commands:

• Save: Saves the current session in place. (See "4.1.5.2. Save" on page 41.)

• Save As...: Saves the current session with a different name and/or in a different database.

(See "4.1.5.3. Save As" on page 41.)

• Export: Exports data from the current session.

• Print preview...: Shows what would be printed with the Print command.

• Print...: Prints the current screen.

• Close Window: Closes the current session. You will be prompted to save the session if

changes have been made since your last save. (See "4.1.6. Closing Sessions" on page

42.)

4.1.4.1.1.1. The Export Menu

The Export menu is accessed from the Export command on the File menu:

Illustration 34: The Session Window File Menu



• Export Changed Parameters: Exports all parameters that have been changed from

their default values.

• Export All Parameters: Exports all parameters.

• Export Results: Exports all results.

• Export Samples: Exports all samples.

We recommend viewing the output from these commands in a spreadsheet.

4.1.4.1.2. The Edit Menu

The "Edit" menu is the second pull-down menu on the menu bar:

The "Edit" menu contains commands for working with the clipboard. (See "2.6. Using the

Clipboard" on page 6.) You may choose the following commands from this menu:

• Cut: Copies the current selection to the clipboard and deletes it.

• Copy: Copies the current selection and does not delete it.

• Paste: If there is a current selection, it is replaced by the contents of the clipboard;

otherwise, the contents of the clipboard are inserted at the current cursor position.

Illustration 35: The Export Sub-Menu

Illustration 36: The Session Window Edit Menu


• Copy Window as Bitmap: A bitmap image representing the current window is copied to

the clipboard.

• Copy Window as Text: A text representation of the current window is copied to the

clipboard.

4.1.4.1.3. The Go Menu

The "Go" menu is the third pull-down menu on the Menu bar:


• Previous Screen: Goes to the previous screen in the navigation panel. (See "4.1.4.4. The

Navigation Panel" on page 34.)

• Next Screen: Goes to the next screen in the navigation panel. (See "4.1.4.4. The

Navigation Panel" on page 34.)

• Back in History: Goes to the previous screen in the history. This is not currently

implemented.

• Forward in History: Goes to the next screen in the history. This is not currently

implemented.

• Expand All...: Expands the entire navigation panel. (See "4.1.4.4. The Navigation

Panel" on page 34.)

4.1.4.1.4. The Help Menu

The Help menu is the fourth pull-down menu on the Menu bar:

This is the same as the "Help" menu on the main window. (See “4.1.2.1.2. The Help Menu” on

page 21.)

4.1.4.2. The Session Window Toolbar

Like the main window, the session window has a toolbar. (See "4.1.2.2. The Main Window Toolbar"

on page 22.) However, the session window's toolbar has much more content:

Illustration 37: The Session Window Go Menu

Illustration 38: The Session Window Help Menu


The following items appear on the toolbar, from left to right:

4.1.4.2.1. The "New Session" Button

The first button on the left creates a new session. It corresponds to the "New Session" command

in the "File" Menu. (See "4.1.2.1.1. The File Menu" on page 21, and “4.1.3.1. Creating a New

Session from Model Defaults” on page 22.)

4.1.4.2.2. The "Open Session" Button

The second button from the left opens a previously-saved session. It corresponds to the "Open

Session" command in the "File" Menu. (See "4.1.2.1.1. The File Menu" on page 21, and

"4.1.3.2. Opening an Existing Session" on page 23.)

4.1.4.2.3. The "Save Session" Button

The third button from the left saves the current session. It corresponds to the "Save" command in

the "File" Menu. (See "4.1.2.1.1. The File Menu" on page 21, and "4.1.5.2. Save" on page 41.)

4.1.4.2.4. The "Save Session As" Button

The fourth button from the left saves a copy of the current session. It corresponds to the "Save

As..." command in the "File" Menu. (See "4.1.2.1.1. The File Menu" on page 21, and

"4.1.5.3. Save As" on page 41.)

Illustration 39: The Session Window's Toolbar

Illustration 40: The "New Session" Button

Illustration 41: The "Open Session" Button

Illustration 42: The "Save Session" Button

Illustration 43: The "Save Session As..." Button


4.1.4.2.5. The "Go to Previous Screen" Button

The fifth button from the left moves to the previous screen in the navigation panel. It corresponds

to the "Previous Screen" command in the "Go" Menu. (See "4.1.4.4. The Navigation Panel" on

page 34.)

4.1.4.2.6. The "Go to Next Screen" Button

The sixth button from the left moves to the next screen in the navigation panel. It corresponds to

the "Next Screen" command in the "Go" Menu. (See "4.1.4.4. The Navigation Panel" on page

34.)

4.1.4.2.7. The "Go to Previous Screen in History" Button

The seventh button from the left is currently not implemented. It corresponds to the "Back in

History" command in the "Go" Menu. (See "4.1.4.1.3. The Go Menu" on page 30.)

4.1.4.2.8. The "Go to Next Screen in History" Button

The eighth button from the left is currently not implemented. It corresponds to the "Forward in

History" command in the "Go" Menu. (See "4.1.4.1.3. The Go Menu" on page 30)

4.1.4.2.9. The Location of the Current Screen

The text in the middle of the toolbar between sets of buttons shows the location of the current

screen in the navigation panel. (See "4.1.4.4. The Navigation Panel" on page 34.) Different levels

Illustration 44: The "Go to Previous Screen" Button

Illustration 45: The "Go to Next Screen" Button

Illustration 46: The "Go to Previous Screen in History" Button

Illustration 47: The "Go to Next Screen in History" Button

Illustration 48: The Location of the Current Screen


are separated by a colon. In this case, we're in the "CONFIGURE SESSION" section, on the

"Plant Design" screen.

4.1.4.2.10. The "Close Window" Button

The second button from the right closes the current session window, prompting the user to save

any unsaved changes. It corresponds to the "Close Window" command in the "File" Menu. (See

"4.1.4.1.1. The File Menu" on page 28, and "4.1.6. Closing Sessions" on page 42.)

4.1.4.2.11. The "Exit" Button

The button all the way on the right closes all session windows, prompting the user to save any

unsaved changes, and exits the IECM. It corresponds to the "Exit" command in the "File" Menu.

(See "4.1.2.1.1. The File Menu" on page 21, and "4.1.9. Exiting the IECM Interface" on page 44.)

4.1.4.3. The Status Bar

The session window has a status bar along the bottom edge:

The status bar is divided into three parts. The left side shows descriptions of menu commands. If

you pull down one of the menus in the menu bar and hold the mouse pointer over a command, a

brief description of that command appears in the status bar.

The center shows this reminder: "(Right-click values for more options.)"

The right side contains a note indicating whether constant or current dollars are used, along with the

cost year. This applies to all costs displayed in the IECM. These parameters may be set on the

overall plant financing input screen, described in "5.2.2.1.5. Financing & Cost Year" on page 120.

Illustration 49: The "Close Window" Button

Illustration 50: The "Exit" Button

Illustration 51: The Session Window Status Bar


4.1.4.4. The Navigation Panel

Movement within the interface is accomplished primarily through the use of the navigation panel,

which sits on the left side of the session window:

4.1.4.4.1. How to Use the Navigation Panel

To use the navigation panel, locate the item you wish to view and click on it.

Items which contain other items have a small box containing either a "+" or a "–" to the left of the

title. The "+" indicates that there is content which is not shown; the "–" indicates that there is

content which may be hidden. Click the box to expand or hide the content, or use the "Expand

All" command in the "Go" menu to show all the content. (See "4.1.4.1.3. The Go Menu" on page

30.) Note that you cannot hide the screen currently being displayed.

For example, in the illustration above (Illustration 51: The Session Window Status Bar on page

33), the "CONFIGURE SESSION" section has been expanded to show its content: "Plant

Design", "Plant Location", and "Unit Systems". The other sections have not been expanded, and

their content is not currently visible.

Items which contain other items do not have screens associated with them. Clicking on one of

these items will take you to the first screen contained within that item.

Illustration 52: The Navigation Panel


For example, clicking on "SET PARAMETERS" in the illustration above (Illustration 51: The

Session Window Status Bar on page 33) produces the following result:

When "SET PARAMETERS" was clicked, the IECM expanded it and went to the first sub-item,

"Overall Plant". "Overall Plant" contains other items, so the IECM expanded it and went to its

first sub-item, "Diagram". "Diagram" does not contain any other items; it is a screen, so the

IECM displays it. The current location on the toolbar (see "4.1.4.2.9. The Location of the Current

Screen" on page 32) changes to reflect this:

4.1.4.4.2. Organization of the Navigation Panel

This section describes how the contents of the navigation panel are organized.

Older versions of the interface, which you may encounter in older documentation and videos,

used tabs. Although the new navigation panel looks different, the structure is essentially the same,

and we use the same terms to describe it. The relationship between the old tabs and the new

navigation panel will be briefly described here and in the following section (see "4.1.4.2.9. The

Location of the Current Screen" on page 32) to aid in understanding these older resources.

Illustration 53: Clicking "SET PARAMETERS" in the Navigation Panel

Illustration 54: Location after Clicking "SET PARAMETERS"


4.1.4.4.2.1. Program Areas

Each session contains 4 program areas: "CONFIGURE SESSION", "SET PARAMETERS",

"GET RESULTS" and "ANALYSIS TOOLS":

In the old tab-style interface, the program areas are in the row of large tabs at the top of the

session window.

4.1.4.4.2.2. Technologies

Inside each program area, the screens are grouped by technology. In the old tab-style interface,

technologies are in the row of smaller tabs beneath the program areas.

"CONFIGURE SESSION" has no technologies, as none of its screens are technology-specific.

"ANALYSIS TOOLS" contains 2 technologies: "Sensitivity Analysis" and "Uncertainty".

The list of technologies in "SET PARAMETERS" and "GET RESULTS" is different for each

plant type. Technologies that do not contain any screens in the current configuration will not be

shown.

4.1.4.4.2.2.1. Technologies in a Pulverized Coal (PC) Plant

The "SET PARAMETERS" and "GET RESULTS" program areas in a PC plant may contain

the following technologies:

• Overall Plant

• Fuel

• Base Plant

• NOx Control

• Mercury

• TSP Control

• SO2 Control

• CO2 Capture, Transport & Storage

• Water Systems

• By-Prod. Mgmt

• Stack

• Water Life Cycle Assessment

Illustration 55: Program Areas


4.1.4.4.2.2.2. Technologies in a Natural Gas Combined Cycle (NGCC) Plant

The "SET PARAMETERS" and "GET RESULTS" program areas in an NGCC plant may

contain the following technologies:

• Overall Plant

• Fuel

• Power Block

• NOx Control

• CO2 Capture, Transport & Storage

• Water Systems

• By-Prod. Mgmt

• Stack

• Water Life Cycle Assessment

4.1.4.4.2.2.3. Technologies in an Integrated Gasification Combined Cycle (IGCC) Plant

The "SET PARAMETERS" and "GET RESULTS" program areas in an IGCC plant may

contain the following technologies:

• Overall Plant

• Fuel

• Air Separation Unit

• Gasifier Area

• Sulfur Removal

• CO2 Capture Transport & Storage

• Power Block

• Water Systems

• By-Prod. Mgmt

• Stack


4.1.4.4.2.2.4. An Example: Technologies in a Typical New PC Plant

As an example, this illustration shows the technologies available under "SET

PARAMETERS" in a PC plant with the "Typical New Plant" configuration:

You may notice that "CO2 Capture, Transport & Storage" is missing. That is because this

configuration does not include CO2 capture.

These are the technologies available under "GET RESULTS" for the same configuration:

This list is slightly different from the "SET PARAMETERS" list. In particular, "Stack" only

appears in "GET RESULTS". The "Stack" module does not have any parameters, only

results, so it is hidden in "SET PARAMETERS".

4.1.4.4.2.3. Process Types

Your plant may have more than one process that falls into the same "technology" category. In

this case, the screens in the affected technologies will be grouped by process type. This

corresponds to the "Process Type" menu which is located in the lower left part of the screen,

just above the bottom row of tabs, in the old tab-style interface.

Illustration 56: "SET PARAMETERS" in a Typical New PC Plant

Illustration 57: "GET RESULTS" in a Typical New PC Plant


For example, in the Typical New PC plant we've been looking at, the "NOx Control"

technology has two different process types: "In-Furnace Controls" and "Hot-Side SCR". These

are the "NOx Control" screens available in the "SET PARAMETERS" program area:

If we go to the "CONFIGURE SESSION: Plant Design" screen and remove the in-furnace

controls, the list changes:

Since there is now only one process type, "Hot-Side SCR", it is not shown, and the Hot-Side

SCR screens are shown directly under the "NOx Control" technology.

4.1.4.4.2.4. Screens

Screens are the final level of organization in the navigation panel. They correspond to the tabs

at the bottom of the window (Input and Result tabs) in the old tab-style interface.

Each screen is a collection of related settings, parameters, diagrams, etc. which you may use to

set up the model or view your results. Click on the screen you want in the navigation panel to

display its contents.

Illustration 58: NOx Control with Process Types

Illustration 59: NOx Control without Process Types


4.1.4.4.3. Organization in the Old Tab-Style Interface

Older versions of the IECM used a tab-style interface instead of the navigation panel. You may

encounter this in older documentation or videos. The interface is organized the same way, except

it uses tabs:

Program areas (see "4.1.4.4.2.1. Program Areas" on page 36) are in the large row of tabs at the

top. Technologies (see "4.1.4.4.2.2. Technologies" on page 36) are in the medium-sized row of

tabs just under the program areas. Process types (see "4.1.4.4.2.3. Process Types" on page 38) are

in the menu on the lower left, just above the bottom row of tabs. Screens (see

"4.1.4.4.2.4. Screens" on page 39) are in the small row of tabs at the bottom.

Some configuration information, e.g., uncertainty, is in dialogs activated from the "View" menu

in older versions, which do not have an "ANALYSIS TOOLS" process area.

4.1.5. Saving Sessions

Before you start making any significant changes to a session, you will want to know how to save your

work. There are two ways to do this: "Save" and "Save As".

Illustration 60: Guide to Navigation in the Old Tab-Style Interface


4.1.5.1. The "Session Modified" Indicator in the Window Title

If a session contains unsaved changes, there will be a "*" to the left of the session name in the

window title:

Sometimes a previously saved session will show unsaved changes as soon as it is opened. This

happens when a session is opened in a newer version of the IECM than the one that saved it. This

will usually result in some internal changes; results may not be modified, but the session is

considered "modified" nonetheless. If you're opening one of your own saved sessions (as opposed to

an included case study) in a new version, it's generally a good idea to check whether any model

updates are affecting your results.

4.1.5.2. Save

If a session has been previously saved and is not read-only, you can save the session in place,

replacing its original configuration and parameters with any changes you have made. To save a

session in place, do one of the following:

• Open the "File" menu (see "4.1.4.1.1. The File Menu" on page 28) and choose "Save".

• Click the "Save" button on the toolbar. (See "4.1.4.2.9. The Location of the Current

Screen" on page 32.)

• Type Ctrl-S.

Note that this command will not be available if there are no unsaved changes.

4.1.5.3. Save As

In some cases, you may want to save your work under a different name, or in a different database. If

your session is read-only or has never been saved before, this is the only way you can save it. To

save a session with a different name and/or in a different database, do one of the following:

• Open the "File" menu (see "4.1.4.1.1. The File Menu" on page 28) and choose "Save As..."

• Click the "Save As" button on the toolbar. (See "4.1.4.2.9. The Location of the Current

Screen" on page 32.)

• Type Ctrl-Shift-S.

Illustration 61: This Session has Unsaved Changes


Activating the "Save As" command brings up the "Save Session As" dialog:

The top part of this dialog contains a list of session databases similar to the one in the "Open

Session" dialog, described here: "4.1.4.2.9. The Location of the Current Screen" on page 32. In this

case; however, locked databases are grayed out, since you cannot write session data to a read-only

database.

If you want to save your session to a database that is not on the list, use the "Open DB" button to

open an existing database, or the "New DB" button to create a new one. The "Open DB" button

works as described here: "4.1.3.2.1.1. Opening a Session Database" on page 25. (Note that in this

context you cannot open the database as "read-only" since the purpose of opening it is to save a

session.) The "New DB" button works the same as the "Open DB" button except that you are

creating a new database instead of opening an existing one.

Click a database in the list to use it for saving this session.

The bottom part of the "Save Session As" dialog contains the name to be used for saving the session.

Change this as needed to identify your session. (See "2.5. Editing Text" on page 6.)

Once you've chosen a database and specified a name, you can click "Ok" in the upper right part of

the dialog to save the session. The session window will now show the name you chose, and the

"Save" command will now use the name and database you specified to save any further changes.

4.1.6. Closing Sessions

To close a session, do one of the following:

• Open the "File" menu (see "4.1.4.1.1. The File Menu" on page 28) and choose "Close

Window".

• Click the "Close" button on the toolbar. (See "4.1.4.2.10. The "Close Window" Button" on

page 33.)

• Type Ctrl-W.

Illustration 62: The "Save Session As" Dialog


If your session contains unsaved changes, you will be prompted to save them:

If you click "No", the window will be closed without saving your changes.

If you click "Cancel", the "Close Window" command will be canceled, and the session will not be

closed.

If you click "Yes", the "Save" command (see "4.1.5.2. Save" on page 41) will be activated if it is

available. If it is not available, the "Save As" command (see "4.1.5.3. Save As" on page 41) will be

used. Once the session is saved, it will be closed. In this context, clicking "Cancel" in the "Save As"

dialog will also cancel the "Close Window" command, and the session will not be closed.

4.1.7. Deleting Sessions

To delete a session, open the "File" menu (see "4.1.2.1.1. The File Menu" on page 21) and select

"Delete Session...". This brings up a dialog which allows you to select which session(s) to delete. This

dialog is very similar to the one used in opening sessions; see "4.1.3.2. Opening an Existing Session"

on page 23, for details on how to use it. (Note that locked databases and sessions are grayed out, as you

are not allowed to delete them.)

Once you have selected a database and one or more sessions, click "Ok" to proceed. You will be asked

to confirm that you intend to delete the selected sessions; if you're sure, press "Yes" to continue,

otherwise press "No" to cancel.

Note that there is no recycle bin; the "Delete Session" command is permanent.

4.1.8. Unlocking Sessions

Sessions are locked as long as they are open to prevent conflicting changes. (A session will not be

locked if it is opened read-only.) If the session is not closed normally, it will remain locked. This can

happen if there is a crash, or if the database is on a network drive and connectivity is lost. The IECM

provides a way to override the lock in these situations.

Note that you cannot manually unlock sessions that are locked for other reasons; you cannot unlock the

included case studies, for example.

Illustration 63: Prompt to Save when Closing a Session with Unsaved Changes


To unlock a session, open the "File" menu (see "4.1.2.1.1. The File Menu" on page 21) and select

"Unlock Session...". This brings up a warning about the dangers of inappropriately overriding the lock:

If you are sure you want to proceed, click "Yes", otherwise click "No" to cancel.

Clicking "Yes" brings up a dialog which allows you to select which session(s) to unlock. This dialog is

very similar to the one used in opening sessions; see "4.1.3.2. Opening an Existing Session" on page

23, for details on how to use it.

Once you have selected a database and one or more sessions, click "Ok" to proceed.

You will be asked to confirm that you want to unlock the selected session(s). Click "Yes" to proceed,

"No" to cancel.

4.1.9. Exiting the IECM Interface

To close all sessions and exit the IECM Interface, do one of the following:

• Open the "File" menu (see "4.1.2.1.1. The File Menu" on page 21) and choose "Exit".

• Click the "Exit" button on the toolbar. (See "4.1.4.2.11. The "Exit" Button" on page 33.)

• Type Ctrl-Q.

If you have any open sessions with unsaved changes, you will be prompted to save them:

This is similar to what happens when you try to close an individual session with unsaved changes. (See

"4.1.6. Closing Sessions" on page 42.) However, in this case, there is one additional option: a checkbox

on the left labeled "Apply to all sessions". If this box is not checked, you will be asked about each

open session separately. If you check the box, your answer will be applied to all remaining open

sessions.

Illustration 64: The "Unlock Session" Warning

Illustration 65: Prompt to Save Sessions with Unsaved Changes on Exit


Assuming you have not canceled the command, the IECM Interface will exit after all sessions have

been closed.

4.2. Configuring the Plant

4.2.1. The "CONFIGURE SESSION" Program Area

"CONFIGURE SESSION" is the first of the four program areas. (See "4.1.4.4.2.1. Program Areas" on

page 36.) This program area is displayed when you first start working with a session. (See

"4.1.3. Creating and Opening Sessions" on page 22.)

This is where you choose the technologies implemented by the plant (see "4.2.1.1. The "Plant Design"

Screen" on page 45), configure region-specific options, (see "4.2.1.2. The "Plant Location" Screen" on

page 50) and choose the unit systems used in displaying parameters and results (see "4.2.1.3. The "Unit

Systems" Screen" on page 51).

Once you have chosen the options for your session, you may move on to the other program areas. You

may return to "CONFIGURE SESSION" at any time by clicking on it in the navigation panel. (See

"4.1.4.4. The Navigation Panel" on page 34.)

4.2.1.1. The "Plant Design" Screen

The "Plant Design" screen is the first screen in the "CONFIGURE SESSION" program area. (See

"4.1.4.4.2.1. Program Areas" on page 36.) This is the first screen that will be displayed when you

create or open a session. (See "4.1.3. Creating and Opening Sessions" on page 22.) This is where

you choose the technologies implemented in your plant:

Illustration 66: The "CONFIGURE SESSION: Plant Design" Screen


This plant design screen is for a Pulverized Coal (PC) plant; other plant types have different options

but function the same way. This screen consists of two parts: the configuration menus, and the

overall plant diagram.

4.2.1.1.1. The Configuration Menus

The configuration menus are between the navigation panel and the overall plant diagram. They

allow you to select the technologies to include in your plant:

To use these menus, click on the one you want to change, and choose the option you want. (See

"2.3.1. Choosing a Command from a Pull-Down Menu" on page 5.) Options that are not valid

with the current configuration will be grayed out. For example, the Amine system in a PC plant

requires some form of post-combustion NOx control.

4.2.1.1.1.1. The Overall Configuration Menu

The overall configuration menu, labeled "Configuration", is the first menu in the list. This is

the overall configuration menu for a Pulverized Coal (PC) plant:

Illustration 67: Configuration Menus


This menu allows you to quickly select common configurations. It may also include some

configurations (Oxyfuel for PC plants) that have complicated requirements, eliminating the

problem of having to select things in the correct order to avoid grayed-out options.

Choosing a configuration from this menu sets the individual configuration menus below it to

match the configuration you have chosen. You may further refine your choice using the

individual configuration menus. For example, you might choose "Typical New Plant" to start,

and then add post-combustion CO2 capture.

This menu automatically updates itself to match the configuration you have chosen. If the

current configuration does not match any of the predefined configurations, it will have the

value "<User Defined>".

4.2.1.1.1.2. The Individual Configuration Menus

Beneath the overall configuration menu, you will find a set of individual configuration menus

that allow you to select individual technologies. For example, the "Cooling System" menu in a

Pulverized Coal (PC) plant looks like this:

You may use these to modify a selection from the overall configuration menu, or if you prefer,

you may specify the entire configuration here.

Each plant type has its own set of configuration menus.

4.2.1.1.1.2.1. Pulverized Coal (PC) Plant Configuration Menus

A PC plant has the following configuration menus:

• Combustion Controls

◦ Fuel Type

◦ NOx Control

• Post-Combustion Controls

◦ NOx Control

◦ Mercury

Illustration 68: The Overall Configuration Menu

Illustration 69: The Cooling System Menu


◦ Particulates

◦ SO2 Control

◦ CO2 Capture

• Water and Solids Management

◦ Cooling System

◦ Wastewater

◦ Flyash Disposal

4.2.1.1.1.2.2. Natural Gas Combined Cycle (NGCC) Plant Configuration Menus

An NGCC plant has the following configuration menus:


◦ CO2 Capture


◦ Cooling System

4.2.1.1.1.2.3. Integrated Gasification Combined Cycle (IGCC) Plant Configuration

Menus

An IGCC plant has the following configuration menus:

• Gasification Options

◦ Gasifier

◦ H2S Control

◦ CO2 Capture


◦ Cooling System

◦ Slag

◦ Sulfur


4.2.1.1.2. The Overall Plant Diagram

The overall plant diagram is on the right side of the screen. It contains a graphical representation

of the choices made in the configuration menus:

The note beneath the plant diagram reminds you that some options may be grayed out if

requirements for their use are not met.

Illustration 70: The Overall Plant Diagram


4.2.1.2. The "Plant Location" Screen

The "Plant Location" screen is the second screen in the "CONFIGURE SESSION" program area.

(See "4.1.4.4.2.1. Program Areas" on page 36.) This screen allows you to specify the location of

your plant so that regional cost adjustments may be applied:

This is a standard parameter screen with one input: "Plant Location". (Parameter screens will be

described in more detail in "4.3.3. Parameter Screens" on page 55.) In the middle of the first line,

"Plant Location", you will find a menu which allows you to choose the region where the plant is

located. (See "2.3.1. Choosing a Command from a Pull-Down Menu" on page 5.) This menu

currently contains 6 U.S. regions and "Other":

The current regions are:

• US Midwest Region: IA, IL, IN, KY, MN, MO, ND, NE, MI, OH, SD, WI, WV

• US Northeast Region: CT, DE, MA, MD, ME, NJ, NY, PA, VT

• US Northwest Region: ID, MT, OR, WA, WY

• US South Central Region: AR, KS, LA, OK, TX

• US Southeast Region: AL, FL, GA, MS, NC, SC, TN, VA

• US Southwest Region: AZ, CA, CO, NM, NV, UT

• Other: This includes U.S. plants that are not in any of the states listed above, as well as

plants that are in different countries.

The plant location is also found on the "Overall Plant: Region-Specific Cost Factors" screen in the

"SET PARAMETERS" Program area. (See "4.1.4.4.2.1. Program Areas" on page 36.) That screen

also shows you the multipliers used for your chosen region and allows you to change them.

Illustration 71: The "Plant Location" Screen

Illustration 72: The "Plant Location" Menu


4.2.1.3. The "Unit Systems" Screen

The "Unit Systems" screen is the third screen in the "CONFIGURE SESSION" program area. (See

"4.1.4.4.2.1. Program Areas" on page 36.) This screen allows you to specify the unit systems that

will be used in the IECM:

Note that values are converted to match the unit systems you have chosen, if needed, so there may a

tiny bit of roundoff error in cases where conversions occur. Also, if a default parameter value

appears to be oddly precise, it may be in a different unit system internally. For example, consider the

ambient air temperature on the "SET PARAMETERS: Overall Plant: Performance" screen for a

Pulverized Coal (PC) plant. The default value in English units, the native unit system for that

parameter, is 66 degrees F. The default value in Metric units is 18.89 degrees C.

Each option includes a menu, similar to the configuration menus on the "Plant Design" screen. (See

"4.2.1.1.1. The Configuration Menus" on page 46.) The following sections describe the options

available on this screen.

4.2.1.3.1. IECM Default Unit System

The first menu on the "Unit Systems" screen is the "IECM Default Unit System" menu:

This menu allows you to choose the default unit system to be used for all sessions. It has the

following options:

• English

• Metric

The default for this menu is "English".

Illustration 73: The "Unit Systems" Screen

Illustration 74: The "IECM Default Unit System" Menu


4.2.1.3.2. Current Session Unit System

The second menu on the "Unit Systems" screen is the "Current Session Unit System" menu:

This menu allows you to override the default unit system for the current session. It has the

following options:

• Default: This option uses the IECM default unit system.

• English: This option uses English units regardless of the IECM default.

• Metric: This option uses Metric units regardless of the IECM default.

The default for this menu is "Default".

4.2.1.3.3. Result Flow Rates

The third menu on the "Unit Systems" screen is the "Result Flow Rates" menu:

Most flow rates can be shown with different types of units. As an example, consider the "GET

RESULTS: Overall Plant: Mass In/Out" screen in a Pulverized Coal (PC) plant, with English

units. The options in the "Performance Table" menu are:

• Default: This leaves the performance table units unchanged. In our example, the units

would be "tons/hr".

• flow/kWh: This uses performance table units based on the amount of power generated.

In our example, the units would be "lbs/kWh".

• flow/Btu in: This uses performance table units based on the amount of energy in the

fuel. In our example, the units would be "lbs/MBtu in".


4.2.1.3.4. Result Time Period

The fourth menu on the "Unit Systems" screen is the "Result Time Period" menu:

Illustration 75: The "Current Session Unit System" Menu

Illustration 76: The "Result Flow Rates" Menu

Illustration 77: The "Result Time Period" Menu


This menu allows you to set the time period used for results. It has the following options:

• Max Hourly: This is the maximum hourly value, e.g., "tons/hr".

• Annual Avg.: This is the annual average value, e.g., "tons/yr".

The default for this menu is "Max Hourly".

4.2.1.3.5. Performance Table

The fifth menu on the "Unit Systems" screen is the "Performance Table" menu:

Many performance tables can be shown with different types of units. As an example, consider the

"GET RESULTS: Overall Plant: Mass In/Out" screen in a Pulverized Coal (PC) plant, with

English units. The options in the "Performance Table" menu are:

• Default: This leaves the performance table units unchanged. In our example, the units

would be "tons/hr".

• % Total: This shows the percentage of each component in the associated total. In our

example, one set of values is: "Coal", "Auxiliary Gas", and "Total Fuels". "Total Fuels"

would be 100%, while "Coal" and "Auxiliary Gas" would show their respective

percentages in the total fuel. The units in this case are "wt %".


4.2.1.3.6. Cost Table

The last menu on the "Unit Systems" screen is the "Cost Table" menu:

Many cost tables can be shown with different types of units. As an example, consider the "Capital

Cost" and "O&M Cost" screens under "GET RESULTS: Base Plant: 1. Boiler" in a Pulverized

Coal (PC) plant. The options in the "Cost Table" menu are:

• $/kW(Cap), $/MWh(O&M): This uses cost table units based on the amount of power

produced. In our example, the "Capital Cost" table units are "$/kW-net" and the "O&M

Cost" table units are "$/MWh".

• M$(Cap), M$/yr(O&M): This shows cost table results on an annual basis. In our

example, the "Capital Cost" table units are "M$" and the "O&M Cost" table units are

"M$/yr".

Illustration 78: The "Performance Table" Menu

Illustration 79: The "Cost Table" Menu


4.3. Setting Parameters

4.3.1. Overview

Once you have finished configuring your plant, you are ready to move on to the "SET

PARAMETERS" program area. (See "4.1.4.4.2.1. Program Areas" on page 36.) "SET PARAMETERS"

allows you to view and modify the inputs associated with the options you chose in "CONFIGURE

SESSION". You may return to "SET PARAMTETER" at any time by clicking on it in the navigation

panel. (See "4.1.4.4. The Navigation Panel" on page 34.)

The "SET PARAMETERS" program area contains two types of screens: diagrams for your

information, and parameter screens which allow you to view and change input values. These screen

types are described in the following sections.

4.3.2. Diagram Screens

Diagram screens are provided to help you visualize either the overall plant or a specific technology or

process type. The types of "SET PARAMETERS" dialog screens are described in the following

sections.

4.3.2.1. Overall Plant Diagram

The overall plant diagram is found at "SET PARAMETERS: Overall Plant: Diagram" in all plant

types. This is the first screen in the "SET PARAMETERS" program area; it will be displayed if you

click on "SET PARAMETERS".

This is the overall plant diagram for a Pulverized Coal (PC) plant with the "Typical New Plant"

configuration:

This diagram is very similar to the "CONFIGURE SESSION: Plant Design" screen. (See

"4.2.1.1. The "Plant Design" Screen" on page 45.) The difference is that all of the settings are

displayed as static text rather than menus. This screen is provided for your reference; if you want to

change anything displayed here, you will need to return to "CONFIGURE SESSION".

Illustration 80: The Overall Plant Diagram


4.3.2.2. Technology and Process Type Overview Diagrams

Many technologies (see "4.1.4.4.2.2. Technologies" on page 36) and process types (see

"4.1.4.4.2.3. Process Types" on page 38) include a diagram to help you visualize what is happening

in that area of the plant. These diagrams do not contain any results; those will be found in "GET

RESULTS". (See "4.4.2.2. Other Diagrams" on page 75.)

For example, the following diagram is shown on "SET PARAMETERS: Base Plant: Boiler

Diagram" for a Pulverized Coal (PC) plant:

4.3.3. Parameter Screens

Parameter screens allow you to view and modify inputs. For example, this is one of the parameter

screens for water life cycle assessment:

Illustration 81: SET PARAMETERS: Base Plant: Boiler Diagram

Illustration 82: SET PARAMETERS: Water Life Cycle Assessment: Coal


Parameters generally occupy a single line and are in a standard format. The following sections will

introduce you to this format and the possible variations of it.

4.3.3.1. Standard Parameters

Each parameter screen has a row of headers at the top. Most parameters are organized using these

columns, with one parameter per row. (There are a few exceptions, which will be discussed in

subsequent sections.)

The header row looks like this:

4.3.3.1.1. Title

This is the title of the parameter, including its units.

In some cases, a line does not contain anything other than a title. Such lines may be used to

provide a heading for related parameters, or notes to clarify what is on the screen. In those cases,

the "title" may spill over into the other columns.

4.3.3.1.2. Unc

Most parameters support the use of uncertainty. Parameters which support uncertainty will have a

button in the Unc column. If the parameter currently has uncertainty, the button will have a

question mark in the middle:

If the parameter does not currently have uncertainty, the button will be blank:

Click on the button to bring up the Uncertainty Editor, which will be described in detail in

"4.3.3.3. The Uncertainty Editor" on page 59.

4.3.3.1.3. Value

This is the current value of the parameter. It will be editable unless the parameter is calculated

(see "4.3.3.1.4. Calc" on page 57) or read-only (see "4.3.3.2. Read-Only Parameters" on page 58).

4.3.3.1.3.1. Menu Values

Some parameters which have a fairly small number of discrete options are presented as menus.

An example of this is the plant location (see "4.2.1.2. The "Plant Location" Screen" on page

50):

Illustration 83: The Parameter Screen Header Row

Illustration 84: The Unc Button with Uncertainty

Illustration 85: The Unc Button with No Uncertainty


You may choose a value from the menu as described in "2.3.1. Choosing a Command from a

Pull-Down Menu" on page 5.

4.3.3.1.3.2. Text Values

Most parameters are presented as text boxes. An example of this is the CO2 Recovery Rate on

the Membrane System:

You can edit the value as described "2.5. Editing Text" on page 6. When you are done, press

Enter or Tab to signal the IECM to update the parameter with your new value. This causes the

model to be run so that any calculated parameters affected by the change will be updated.

Parameters are converted to IECM native units if needed, and are also rounded to 4 significant

figures. This may cause a tiny bit of roundoff error.

There are a few parameters that are not numeric. The coal name and source are examples of

this:

In these cases, the Calc, Min, Max and Default columns are not needed, so the Value occupies

those columns as well.

4.3.3.1.4. Calc

Some parameters can be calculated by the model. Parameters which have this option will have a

checkbox in the Calc column:

If the box is checked, the parameter is currently being calculated by the model and the value

cannot be edited. If you want to override a calculated parameter, click the checkbox to remove the

check and allow the value to be edited.

Illustration 86: The Plant Location Parameter (Menu)

Illustration 87: The CO2 Recovery Rate Parameter (Text Box)

Illustration 88: Non-Numeric Parameters on the "SET PARAMETERS: Fuel:

Coal Properties" Screen for PC Plants

Illustration 89: The Calc Checkbox


4.3.3.1.5. Min

This is the minimum value of the parameter. In some cases, the minimum value is strictly

enforced. However, in most cases you can use a value less than the minimum if you choose.

Generally, it is safe to go outside the range for economic parameters, but going outside the range

for performance parameters may put you outside the range in which the model is valid.

If the value is a menu, this column will say "Menu".

4.3.3.1.6. Max

This is the maximum value of the parameter. In some cases, this value is strictly enforced, but in

most cases you can use a value greater than the maximum if you choose. Generally, it is safe to

go outside the range for economic parameters, but going outside the range for performance

parameters may put you outside the range in which the model is valid.

If the value is a menu, this column will say "Menu".

4.3.3.1.7. Default

This is the default value of the parameter. If the parameter is calculated by default, this will say

"Calc".

4.3.3.2. Read-Only Parameters

Some parameters are read-only. These parameters are usually calculated and are grayed-out so that

you cannot modify them. They are provided for your information to assist you in setting other

parameters on the screen.

Read-only parameters generally fall into one of two categories. Some may be modified on a

different screen. These generally come with a note indicating where you can go to change them. One

example of this is "Gross Electrical Output" on the "SET PARAMETERS: Overall Plant:

Performance" screen in a Pulverized Coal (PC) plant:

The Gross Electrical Output is relevant on this screen, as you may want to be reminded of it while

setting the Capacity Factor, but it is one of the Base Plant parameters and would need to be set there.

Other read-only parameters cannot be modified, but are provided for your information. One example

of this is found on the Purification screen for the Membrane System, also in a PC plant:

In this case, the CO2 recovery rate you specify may not be achievable due to other constraints. The

current minimum, maximum, and actual recovery rates are provided for your information so that

you can be aware of this issue while you are setting the CO2 recovery rate.

Illustration 90: A Read-Only Parameter That Can Be Modified Elsewhere

Illustration 91: Read-Only Parameters That Cannot Be Modified Elsewhere


4.3.3.3. The Uncertainty Editor

The Uncertainty Editor allows you to add, change or remove uncertainty from parameters that

support it. (See "7. Introduction to Uncertainty Analysis" on page 575.) To activate the Uncertainty

Editor, click the Unc button on the left side of the value. (See "4.3.3.1.2. Unc" on page 56.) The

Uncertainty Editor looks like this:

The Uncertainty Editor is a Modal Dialog, meaning that it is on top of the other window(s) and you

have to close it before you can continue using other parts of the IECM. Note that if you somehow

manage to get it behind the other windows, you will need to locate it and bring it back to the front,

moving other windows if necessary. (This is a good thing to keep in mind in general - sometimes

Modal Dialogs, particularly for installers, inadvertently end up behind other windows, leaving the

application silently waiting for you while you wonder why it isn't doing anything.)

When you are finished editing the uncertainty, click the "Ok" button in the upper right corner to save

your changes, or "Cancel" to discard your changes.

The numbered components in the illustration are discussed below.

4.3.3.3.1. #1: Parameter Information

Information about the parameter whose uncertainty is being modified is shown at the top of the

dialog:

The title, current value, minimum value, and maximum value are shown.

Illustration 92: The Uncertainty Editor

Illustration 93: The Uncertainty Editor: Parameter Information


4.3.3.3.2. #2: The Distribution Menu

The distribution menu is shown on the left, under the parameter information:

This menu allows you to choose the distribution to apply to the parameter. (See "2.3.1. Choosing

a Command from a Pull-Down Menu" on page 5.) The following distributions are available:

• None: The parameter has no uncertainty.

• Lognormal: Lognormal(M,E) describes a skewed (lognormal) distribution where M is

the mean and E is the error factor. The standard deviation (s) of the underlying normal

distribution is given by ln(E)/1.645. The mean (m) of the underlying normal distribution

is given by ln(M) - 0.5*s^2. The range [e^(m-s)...e^(m+s)] encloses about 68% of the

probability. The range [e^(m-2s)...e^(m+2s)] encloses 95% of the probability, while

[e^(m-3s)...e^(m+3s)] includes 99%. Note that the error factor does not scale as other

parameters do, so the normalized and nominal values will be the same.

• Normal: Normal(m,s) refers to a normal or Gaussian distribution where m is the mean

and s is the standard deviation. The range [m-s...m+s] encloses about 68% of this

symmetrical bell-shaped distribution. The range [m-2s...m+2s] encloses 95% of the

probability, while [m-3s...m+3s] includes 99%.

• Triangular: Triangular(a,b,c) describes a triangular-shaped distribution where the

values a, b and c represent the minimum, most likely and maximum values, respectively.

• Uniform: Uniform(a,b) describes a uniform distribution between the deterministic

values of a and b. This distribution indicates the uniform probability of a value lying

anywhere in the range from a to b.

• Half Normal: Half Normal(m,s') is a shared distribution; m is the mean and s' is the

standard deviation. This distribution reflects the positive part of the normal distribution.

It returns the mean value when evaluated deterministically.

• NegHalf Normal: NegHalf Normal(m,s') is a shared distribution; m is the mean and s' is

the standard deviation. This distribution reflects the negative part of the normal

distribution. It returns the mean value when evaluated deterministically.

• User-defined: UserDefined([x0,x1,...,xn]) allows the user to specify their own samples,

bypassing the uncertainty engine. If the number of samples needed is greater than the

number of samples specified, the extra samples will all have a value of 1.0 (normalized)

or the current deterministic value (nominal). Samples beyond the current sample size

may be entered, but they will not be used unless the sample size is increased.

Illustration 94: The Uncertainty Editor: The Distribution Menu

Illustration 95: The Uncertainty Editor: Distribution Menu Options


4.3.3.3.3. #3: The "Use Nominal Values" Checkbox

This checkbox is located to the right of the distribution menu:

In order to understand this checkbox, you need to know what normalized and nominal values are.

The following relationship exists, where the deterministic value is the value of the parameter

before uncertainty is applied:

Nominal values are the values that are actually used. If the "Use Nominal Values" checkbox is

checked, the distribution you enter will be used directly, skipping the calculation above.

If "Use Nominal Values" is not checked, or if you are using an older version of the IECM that

does not have this checkbox, you will enter normalized values. There are some things you should

be aware of in this case:

• If the deterministic value is zero, the uncertainty will have no effect, since zero

multiplied by anything is still zero.

• Normalized uncertainty is applied to values in the IECM's native units. In the vast

majority of cases, this makes no difference, since most unit conversions are just factors.

However, converting between degrees C and F involves an offset as well as a factor,

which may produce different normalized values than you're expecting. In this case the

distribution information (see "4.3.3.3.10. #10: Distribution Information" on page 63)

will include a warning and a note indicating what units the IECM uses internally for that

parameter.

• Normalized uncertainty is applied to calculated variables one sample at a time, after the

deterministic value is calculated. If the value shifts, the nominal uncertainty will shift

with it.

For example, consider a normalized distribution with samples 0.5, 1.0 and 1.5. If the

parameter has a deterministic value of 2.0, this would result in the nominal samples 1.0,

2.0 and 3.0. If, however, the parameter is calculated, with a value of 1.9 on the first run,

2.0 on the second run, and 2.2 on the third run, this would result in nominal samples of

0.95, 2.0 and 3.3.

This situation can be avoided by unchecking the parameter's calc box (see

"4.3.3.1.4. Calc" on page 57), or checking the "Use Nominal Values" checkbox and

entering nominal values.

4.3.3.3.4. #4: The Sample Size

The sample size is located to the right of the "Use Nominal Values" checkbox:

nominal value= normalized value∗ deterministicvalue

Illustration 96: The Uncertainty Editor: The "Use Nominal Values" Checkbox

Illustration 97: The Uncertainty Editor: The Sample Size


This controls the number of samples that will be generated for your distribution. Note that the

model runs once for each sample, so a large number of samples may take a noticeable amount of

time to run.

You can adjust the sample size by clicking the up and down arrow buttons in the right, or by

typing in the desired value directly. (See "2.5. Editing Text" on page 6.) The current maximum is

10,000 samples; the minimum is 2.

4.3.3.3.5. #5: The Nominal Minimum & Maximum

The nominal minimum and maximum are located beneath the distribution menu:

This gives you an estimate of the range the samples will cover. Compare these values with the

minimum and maximum in the parameter info at the top of the dialog to ensure that your

distribution is not expected to put the parameter out of range.

Generally, it is safe to go outside the range for economic parameters, but going outside the range

for performance parameters may put you outside the range in which the model is valid.

4.3.3.3.6. #6: Normalized Distribution Parameters

The normalized distribution parameters are located beneath the nominal minimum and maximum:

The exact parameters that appear here depend on the distribution you have chosen. In this case,

we're using a uniform distribution, which has minimum and maximum values as its parameters.

If the "Use Normalized Values" checkbox is not checked, this is where you will enter the

parameters for your distribution. (See "2.5. Editing Text" on page 6.) Otherwise, the normalized

values will be calculated from the nominal values you have entered, if possible, and shown for

your reference. (If the deterministic value is zero, the normalized value cannot be calculated.)

4.3.3.3.7. #7: Nominal Distribution Parameters

The nominal distribution parameters are located beneath the normalized distribution parameters:

The parameters that appear here are the same ones that appear in the normalized set above.

If the "Use Normalized Values" checkbox is checked, this is where you will enter the parameters

for your distribution. (See "2.5. Editing Text" on page 6.) Otherwise, the nominal values will be

calculated from the normalized values you have entered and shown for your reference.

Illustration 98: The Uncertainty Editor: The Nominal Minimum & Maximum

Illustration 99: The Uncertainty Editor: Normalized Distribution Parameters

Illustration 100: The Uncertainty Editor: Nominal Distribution Parameters


4.3.3.3.8. #8: Distribution Requirements

The distribution requirements are located beneath the distribution parameters:

This shows you what requirements there are for your chosen distribution. The uniform

distribution, which has been chosen for this example, requires that the minimum be less than the

maximum.

4.3.3.3.9. #9: Status

The current status is located to the right of the distribution parameters and requirements:

This tells you if there are any problems with the distribution parameters that would prevent you

from saving them. If the "Ok" button in the upper right corner of the dialog is grayed-out, you

will find an explanation here.

4.3.3.3.10. #10: Distribution Information

The distribution information is located at the bottom of the dialog:

Illustration 101: The Uncertainty Editor: Distribution Requirements

Illustration 102: The Uncertainty Editor: Status


This gives you information about the distribution's parameters, shape and range, along with any

warnings and/or notes that apply to the current configuration.

4.3.3.3.11. Uncertainty on Menus

It may seem counter-intuitive, but it is possible to put uncertainty on a menu parameter. Menu

parameters are implemented internally as an index into a list of possible values. If the parameter

you're working with is a menu, the distribution information will be narrower, and a list of

possible values for the menu will appear to its right. For example, this is the list of possible

values for the plant location:

The IECM will map samples onto the nearest valid value, so any distribution may be used.

However, it generally makes the most sense to use a user-defined distribution with nominal

values and specify the values you're interested in. (See "4.3.3.3.12. User-defined Distributions"

on page 64.)

If you're looking at a menu parameter in isolation, it may be simpler to do a sensitivity analysis,

as described in "4.5.2. Sensitivity Analysis" on page 80.

4.3.3.3.12. User-defined Distributions

The "User-defined" distribution allows you to specify your own samples. This distribution would

be used if you want to use a specific set of samples rather than having the IECM generate them,

Illustration 103: The Uncertainty Editor: Distribution Information

Illustration 104: The Uncertainty Editor: Possible Menu Values


or if you want to do batch processing, which is described in "4.3.3.3.13. Batch Processing" on

page 66.

When this distribution is selected, the usual distribution parameters (see "4.3.3.3.6. #6:

Normalized Distribution Parameters" on page 62 and "4.3.3.3.7. #7: Nominal Distribution

Parameters" on page 62) are replaced with a table of samples:

The parameter in this case is the plant location, and the samples entered represent "US Midwest

Region" (1), "US Northeast Region" (2), and "US Northwest Region" (3).

As with the other distributions, the "Use Nominal Values" checkbox (see "4.3.3.3.3. #3: The "Use

Nominal Values" Checkbox" on page 61) determines whether nominal or normalized values are

used. One of the column headers will be in parens; the header that is not in parens is the one

being used/saved. In this case, the headers are "(Normalized)" and "Nominal", indicating that

nominal values are being used. You may enter values into either column; the other column will be

calculated for you if possible. (If the deterministic value is zero, the normalized value cannot be

calculated.)

If you are using this distribution, you probably have your samples in a spreadsheet. To copy a

column of numbers from a spreadsheet to the uncertainty editor, first go to the spreadsheet and

select the column. (One way to do this is to click the cell at the top, then press and hold the shift

key while clicking the cell (Shift-Click) at the bottom.) Copy the cells using your favorite

method - Ctrl-C should work. Then, go to the uncertainty editor, click the cell in the appropriate

column in the row where you want the first number to appear, and click the "Paste" button on the

right.

To clear the list of samples, click the cell in either column of the first row you want to clear.

Then, press the "Clear" button on the right to clear that row and everything below it.

Illustration 105: The Uncertainty Editor: User-defined Samples


You will probably want to set the sample size (see "4.3.3.3.4. #4: The Sample Size" on page 61)

to match the number of samples you have. When the "User-defined" distribution is selected, a

note appears beneath the sample size indicating how many samples have been entered:

The status (see "4.3.3.3.9. #9: Status" on page 63) will also contain a warning if the number of

samples entered does not match the sample size. If the number of samples needed is greater than

the number of samples specified, the extra samples will all have a value of 1.0 (normalized) or the

current deterministic value (nominal). Samples beyond the current sample size may be entered,

but they will not be used unless the sample size is increased.

4.3.3.3.13. Batch Processing

The "User-defined" distribution (see "4.3.3.3.12. User-defined Distributions" on page 64) can be

used for batch processing. In this case, each "sample" corresponds to one scenario. Results are

organized the same way, so "sample 1" is the result for the first scenario, "sample 2" for the

second scenario, etc. We recommend that you use nominal values when doing batch processing.

To illustrate how this works, let's consider a very simple example with only two scenarios:

1. A 500MW PC plant in Arizona.

2. A 650MW PC plant in Ohio.

The plants are configured identically aside from the stated differences; the exact configuration is

not important for this example.

This example involves two parameters: the gross plant size and the plant location. To start, create

a new plant with the desired configuration. (See “4.1.3.1. Creating a New Session from Model

Defaults” on page 22.)

The basic procedure for each parameter is:

1. Locate the parameter in the IECM Interface.

2. Determine what values the parameter should have. Check the units to see if any

conversions are necessary, or, if the parameter is a menu, open the uncertainty editor to

see which numeric values correspond to the values you want. If you are doing anything

more complicated than this example, you'll want to set up a spreadsheet with the values

in a column so that you can easily copy and paste them.

3. If you have not done so already, open the uncertainty editor.

4. Make sure "Use Nominal Values" is checked.

5. Set the sample size to match the number of scenarios. (Only necessary for the first

parameter.)

6. Choose the "User-defined" distribution.

7. Enter the values.

Illustration 106: The Uncertainty Editor: User-defined Sample Size


8. Click "Ok" to save the "uncertainty".

Starting with the first parameter, the gross plant size:

• This parameter is the first parameter, "Gross Electrical Output", on the "SET

PARAMETERS: Base Plant: Base Plant Performance" screen.

• The values we want are (1) 500MW and (2) 650 MW. This parameter's units are

"MWg", so no conversion is necessary.

• There are 2 scenarios, so we need to set the sample size to 2.

The second parameter, the plant location, is a little more complicated:

• This parameter can be found in two locations; however, "CONFIGURE SESSION: Plant

Location" shows the complete list of regions and states, not just the selected region, so it

will be easier to determine the values we need there.

• The plants are located in (1) Arizona, abbreviated AZ, and (2) Ohio, abbreviated OH.

◦ Looking at the list on the "Plant Location" screen, we see that the values we need

are (1) US Southwest Region and (2) US Midwest Region.

◦ Opening the uncertainty editor, we see that the corresponding numerical values are

(1) 6 and (2) 1. These are the values that will need to be entered in the user-defined

distribution for this parameter.

To view results, right-click the result and select "Copy this Result as Text". (This will be covered

in "4.4.4. The Right-Click Menu" on page 80.) Then go to a spreadsheet and paste the result so

that you can look at it. (Ctrl-V should work.) There will be some statistics, which are pretty

much meaningless in this case, followed by the list of "sample" values, listed in order. The first

value is the result for scenario 1, the second for scenario 2, etc. (Note that the IECM's graphs,

which show cumulative probability, are not meaningful here since we aren't using real

uncertainty. You'll need to use the tables to get the values in a meaningful form.)

You may also want to view the results in the "Choose Variable(s)" screen in the Uncertainty

Analysis Tool. (See "4.5.3.2. Choose Variable(s)" on page 88.)

4.3.3.4. The Database Button

There are a couple of screens which allow you to look up values in a database. Currently only coal

and CO2 reservoir property screens allow this. In this case, a button spanning the width of the screen

will make the database(s) available. The "SET PARAMETERS: Fuel: Coal Properties" screen in a

Pulverized Coal (PC) plant is one such screen, with the button at the top:

The button says, "Click here to retrieve a coal from the database."

Illustration 107: A Fuel Database Button


4.3.3.4.1. Coal Databases

Clicking the database button on the "Coal Properties" screen brings up this dialog:

This dialog allows you to look up coals in a database. It contains the following menus, starting

from the top:

• Mode: This menu allows you to switch between viewing and editing:

If you choose "Add/Edit", you will be able to edit all of the coal properties except the

rank, which is calculated. (See "2.5. Editing Text" on page 6.) The new or modified coal

may be saved in a database for future use.

• Under the heading "Coal Selection:"

Illustration 108: The Coal Database Lookup Dialog

Illustration 109: The Coal Database Mode Menu


◦ Database: This menu allows you to choose which database you want to use. This is

a list of all open fuel databases; it typically looks something like this:

"model_default_fuels.db" is the fuel database included with the IECM. It is opened

read-only and cannot be modified. If you want to change or add coals, you will need

to save them in a different database.

◦ Name: Use this menu to choose which coal you want to view. These are the coals

currently included with the IECM:

If you are in "Add/Edit" mode, this will be a text box where you can set the coal

name rather than a menu. (See "2.5. Editing Text" on page 6.)

• Coal Properties / Ash Properties: This menu allows you to switch between viewing

coal and ash properties:

There are also several buttons on the right side of the dialog. Starting from the top:

• Ok: This exits the dialog and imports the selected coal into the IECM.

• Cancel: This exits the dialog without importing the selected coal into the IECM. This

does not undo any changes that were made, e.g., adding, modifying or deleting coals.

• Under the heading "Coal:"

◦ Add/Save: In "Add/Edit" mode, click this to add or save the coal you have entered.

If the coal name matches one that is already in the database, you will be asked if

you want to replace it.

Illustration 110: The Coal Database Selection Menu

Illustration 111: The Coal Name Selection Menu

Illustration 112: The Coal/Ash Properties Selection Menu


◦ Default Ash: In "Add/Edit" mode, click this button to use a default set of ash

properties based on the coal rank.

◦ Show Errors: In "Add/Edit" mode, if the "Add/Save" button is grayed out, click

this button to find out why.

◦ Delete: In "View" mode, if the coal you are viewing is in a writable database, you

will have the option of deleting it. Click this button to delete the current coal.

• Under the heading "Database:"

◦ Create: Click this button to create a new coal database. The procedure is very

similar to the one for opening a new session database, except that in this case you

are creating a new database rather than opening an existing one. (See

"4.1.3.2.1.1. Opening a Session Database" on page 25.) The default file type is

"IECM Fuel Database (*.edb)".

◦ Open: Click this button to open an existing coal database. The procedure is the

same as the one for opening a session database, described in "4.1.3.2.1.1. Opening a

Session Database" on page 25. The default file type is "IECM Fuel Database

(*edb)".

◦ Close: Click this button to close the current database. You are not allowed to close

the model default fuels database.

◦ Show Path: Click this button to view the full path of the current database in the file

system. If you end up with two databases that have the same name, this can help

you distinguish between them.

The procedure for adding or modifying a coal is:

1. Locate the coal that you want to edit. If you're adding a new coal, it doesn't matter which

one you start with.

2. Switch to "Add/Edit" mode.

3. Enter the coal name and properties.

4. Either switch to "Ash Properties" and enter the ash properties, or click the "Default Ash"

button.

5. If you're adding a new coal, select the database you want to use, opening or creating it if

necessary.

6. If the "Add/Save" button is grayed out, click "Show Errors" and correct the problem.

7. Click the "Add/Save" button. You should receive confirmation that your changes have

been saved.

8. At this point your changes are saved, and you can exit the dialog using either the "Ok"

or the "Cancel" button.


4.3.3.4.2. Reservoir Databases

Clicking the database button on the "SET PARAMETERS: CO2 Capture, Transport & Storage: 5.

CO2 Storage: Reservoir" screen brings up this dialog:

This dialog allows you to look up CO2 reservoirs in a database. It contains the following menus,

starting from the top:

• Mode: This menu allows you to switch between viewing and editing:

If you choose "Add/Edit" you will be able to edit all of the reservoir properties. The new

or modified reservoir may be saved in a database for future use.

• Under the heading "Reservoir Selection":

◦ Database: This menu allows you to choose which database to use. This is a list of

all open reservoir databases. It looks something like this:

Illustration 113: The Reservoir Database Lookup Dialog

Illustration 114: The Reservoir Database Mode Menu


"model_default_reservoirs.db" is the reservoir database included with the IECM. It

is opened read-only and cannot be modified. If you want to change or add

reservoirs, you will need to save them in a different database.

◦ Region: This menu allows you to choose the region that will be shown. It is a list of

all the regions in the current database. In the current model default reservoirs

database, it looks like this:

These happen to be regions in the U.S.; however, there is no limit on what regions

can be used. Other databases might contain regions of other countries, or regions of

the world, for example.

If you are in "Add/Edit" mode, this will be a text box that you can edit, rather than a

menu. (See "2.5. Editing Text" on page 6.)

◦ State: This menu allows you to choose the state that will be shown. It is a list of all

the states in the specified region in the current database. In the Central region in the

current default reservoirs database, it looks like this:

These are the postal abbreviations for U.S. states; however, using them is not a

requirement. States do not have to be two characters, and in fact it is not even

required that they be states. If you were creating a database of reservoirs around the

world, for example, it might make more sense to use countries here rather than

states.

If you are in "Add/Edit" mode, this will be a text box that you can edit, rather than a


◦ Formation: This menu allows you to choose the formation that will be shown. It is

a list of all the formations in the specified region and state in the current database.

Illustration 115: The Reservoir Database Selection Menu

Illustration 116: The Reservoir Region Selection Menu

Illustration 117: The Reservoir State Selection Menu


In Colorado (CO) in the Central Region in the current model default reservoirs

database, it looks like this:

This is the name of the reservoir. It is unique within a particular region and state. If

you are in "Add/Edit" mode, this will be a text box that you can edit, rather than a


There are also several buttons on the right side of the dialog. Starting from the top:

• Ok: This exits the dialog and imports the selected reservoir into the IECM.

• Cancel: This exits the dialog without importing the selected reservoir into the IECM.

This does not undo any changes that were made, e.g., adding, modifying or deleting

reservoirs.

• Under the heading "Reservoir:"

◦ Add/Save: In "Add/Edit" mode, click this to add or save the reservoir you have

entered. If the formation matches one that is already in the database in the specified

region and state, you will be asked if you want to replace it.

◦ Show Errors: In "Add/Edit" mode, if the "Add/Save" button is grayed out, click

this button to find out why.

◦ Delete: In "View" mode, if the reservoir you are viewing is in a writable database,

you will have the option of deleting it. Click this button to delete the current

reservoir.

• Under the heading "Database:"

◦ Create: Click this button to create a new reservoir database. The procedure is very

similar to the one for opening a new session database, except that in this case you

are creating a new database rather than opening an existing one. (See

"4.1.3.2.1.1. Opening a Session Database" on page 25.) The default file type is

"IECM Reservoir Database (*.rdb)".

Illustration 118: The Reservoir Formation Selection Menu


◦ Open: Click this button to open an existing reservoir database. The procedure is the

same as the one for opening a session database, described in "4.1.3.2.1.1. Opening a

Session Database" on page 25. The default file type is "IECM Reservoir Database

(*.rdb)".

◦ Close: Click this button to close the current database. You are not allowed to close

the model default reservoirs database.

◦ Show Path: Click this button to view the full path of the current database in the file

system. If you end up with two databases that have the same name, this can help

you distinguish between them.

The procedure for adding or modifying a reservoir is:

1. Locate the reservoir that you want to edit. If you're adding a new reservoir, it doesn't

matter which one you start with.

2. Switch to "Add/Edit" mode.

3. Enter the region, state, formation, and all of the properties.

4. If you're adding a new reservoir, select the database you want to use, opening or creating

it if necessary.

5. If the "Add/Save" button is grayed out, click "Show Errors" and correct the problem.

6. Click the "Add/Save" button. You should receive confirmation that your changes have

been saved.

7. At this point your changes are saved, and you can exit the dialog using either the "Ok"

or the "Cancel" button.

4.3.3.5. Highlighted Parameters

Some particularly important parameters are highlighted to draw your attention to them. The

highlight does not affect the functionality of the parameter; you may change highlighted parameters

the same way you would change non-highlighted ones.

4.3.3.6. The Right-Click Menu

Right-clicking (see "2.2. Using a Mouse or Touchscreen" on page 4) a parameter gives you this

menu:

This menu gives you the following options:

• Copy this Line: This copies the line you clicked on to the clipboard. (See "2.6. Using the

Clipboard" on page 6.) This can be helpful if you want to put the displayed information

into something else, e.g., a paper or report.

• Copy this Parameter as Text: This copies all of the information about the parameter to the

clipboard, including information about its uncertainty and samples, if any. We recommend

pasting this into a spreadsheet for easier viewing.

Illustration 119: The Parameter Right-Click Menu


• Copy this Parameter as a Graph: This copies a graph of the Cumulative Distribution

Function (CDF) of the parameter's uncertainty to the clipboard.

• Display a Graph of this Parameter: This displays a graph of the CDF of the parameter's

uncertainty.

4.4. Getting Results

4.4.1. Overview

Once you have finished configuring your plant and setting parameters, you are ready to move on to the

"GET RESULTS" program area. (See "4.1.4.4.2.1. Program Areas" on page 36.) "GET RESULTS"

allows you to view result values; you may also view graphs if you've set up uncertainty as described in

"4.3.3.3. The Uncertainty Editor" on page 59. You may return to "CONFIGURE PLANT" or "SET

PARAMETERS" at any time to make adjustments, and come back to "GET RESULTS" by clicking on

it in the navigation panel. (See "4.1.4.4. The Navigation Panel" on page 34.)

The "GET RESULTS" program area contains two types of screens: diagrams and tables. These are

described in the following sections.

4.4.2. Diagram Screens

In some cases, a diagram is helpful in visualizing the results. Result diagrams are provided for the

overall plant, and for various technologies and process types.

4.4.2.1. The Overall Plant Diagram

The overall plant diagram is found at "GET RESULTS: Overall Plant: Diagram" in all plant types. It

is the first screen in the "GET RESULTS" program area; it will be displayed if you click on "GET

RESULTS".

This is the same plant overview screen that is displayed in the "SET PARAMETERS" program area;

see "4.3.2.1. Overall Plant Diagram" on page 54 for more details.

4.4.2.2. Other Diagrams

Many technologies (see "4.1.4.4.2.2. Technologies" on page 36) and process types (see

"4.1.4.4.2.3. Process Types" on page 38) include one or more diagrams to help you visualize what is

going on in that area of the plant. These diagrams typically include things like temperatures and

total flow rates.


For example, the following diagram is shown on "GET RESULTS: Base Plant: 1. Boiler: Diagram"

for a Pulverized Coal (PC) plant:

This is very similar to "" on page 579. It is actually the same diagram, except that this version

includes results rather than just labels.

Diagrams do not include economic results; those are all presented in tables. (See "4.4.3. Table

Screens" on page 76.)

4.4.2.2.1. Units

The units used for flow rates on result diagrams are determined by the result time period selected

in "CONFIGURE PLANT: Unit Systems". See "4.2.1.3.4. Result Time Period" on page 52 for

details.

4.4.3. Table Screens

Flow compositions, summaries, and economic results are generally shown in tables. Table screens have

either one or two tables, depending on the type of data being displayed.

4.4.3.1. One Table

Many technologies and process types have a "Flue Gas" table showing the flue gas composition at

various points in the process. These results are presented as a single table where each row is a flue

gas component. These tables generally show both the molecular flow rate and the mass flow rate.

Illustration 120: GET RESULTS: Base Plant: 1. Boiler: Diagram


Most of these tables have scroll bars at the bottom. As an example, the "GET RESULTS: Stack: Flue

Gas" screen looks something like this:

Pulverized Coal (PC) plants also have "Solids In/Out" and "Gas In/Out" in the "Overall Plant"

section which have this format.

Some economic summary screens also have this format, including "Overall Plant Cost" and "Cost

Summary" in the "Overall Plant" section, and the "Total Cost" tables found in many technologies

Illustration 121: GET RESULTS: Stack: Flue Gas


and process types. For example, the "GET RESULTS: Overall Plant: Overall Plant Cost" screen

looks something like this:

4.4.3.2. Two Tables

Some result screens consist of a collection of values that wouldn't work well in a diagram. These are

presented as two tables side-by-side to maximize the number of values that can be shown. Each of

these tables has two columns, where the first column contains the title and units, and the second

column contains the value.

Illustration 122: GET RESULTS: Overall Plant: Overall Plant Cost


This format is used in some performance summaries, including "Plant Performance" and "Mass

In/Out" in the "Overall Plant" section. For example, the "GET RESULTS: Overall Plant: Plant

Performance" screen looks something like this:

Some economic results are presented in this format as well, including the Capital and O&M Cost

screens in various technologies and process types, and the "Total Capital Cost" screen in the

"Overall Plant" Section. For example, the "GET RESULTS: Overall Plant: Total Capital Cost"

screen looks something like this:

Illustration 123: GET RESULTS: Overall Plant: Plant Performance

Illustration 124: GET RESULTS: Overall Plant: Total Capital Cost


4.4.3.3. Units

The result time period selected in "CONFIGURE PLANT: Unit Systems" affects performance tables

as well as diagrams. See "4.2.1.3.4. Result Time Period" on page 52 for details.

There are also two settings on that screen which specifically apply to tables: "Performance Table",

described in "4.2.1.3.5. Performance Table" on page 53 , and "Cost Table", described in

"4.2.1.3.6. Cost Table" on page 53. There are a few tables, e.g., "GET RESULTS: Overall Plant:

Cost Summary" that override these settings; however, most tables will follow them.

4.4.4. The Right-Click Menu

Right-clicking (see "2.2. Using a Mouse or Touchscreen" on page 4) any result gives you the following

menu:

This menu gives you the following options:

• Copy this Result as Text: This copies all of the information about the result to the clipboard.

(See "2.6. Using the Clipboard" on page 6.) This includes information about its uncertainty

and samples, if any. If you are doing batch processing, as described in "4.3.3.3.13. Batch

Processing" on page 66, this is how you will get your results. We recommend pasting this into

a spreadsheet for easier viewing.

• Copy this Result as a Graph: This copies a graph of the Cumulative Distribution Function

(CDF) of the result's uncertainty to the clipboard.

• Display a Graph of this Result: This displays a graph of the CDF of the result's uncertainty.

4.5. Analysis Tools

4.5.1. Overview

The "Analysis Tools" program area (see "4.1.4.4.2.1. Program Areas" on page 36) is a relatively recent

addition to the IECM. It contains tools that help you see the impact of uncertainty on your results.

These tools are described in the sections that follow.

4.5.2. Sensitivity Analysis

The sensitivity analysis tool allows you to vary a single parameter and observe its effect on calculated

parameters and results. You may look at specific results, or if you prefer, you may view all of the

affected results to see if there are any unanticipated effects.

Illustration 125: The Result Right-Click Menu


4.5.2.1. Choose Independent Variable

The first step in performing a sensitivity analysis is to choose and configure the independent

variable. The "ANALYSIS TOOLS: Sensitivity Analysis: Choose Independent Variable" screen

looks like this:

This screen has four parts which allow you to choose and configure the independent variable.

4.5.2.1.1. Parameter Chooser

The top part of the screen allows you to choose the independent variable. This is the parameter

chooser with "SET PARAMETERS: Base Plant: Base Plant Performance: Gross Electrical Output

(MWg)" selected:

Illustration 126: ANALYSIS TOOLS: Sensitivity Analysis: Choose Independent

Variable

Illustration 127: Sensitivity Analysis: Independent Variable Chooser


The list on the left is very similar to the navigation panel (see "4.1.4.4. The Navigation Panel" on

page 34) and is used in the same way. The difference is that it only contains the "SET

PARAMETERS" program area. (See "4.1.4.4.2.1. Program Areas" on page 36.) It also contains

an additional level of detail: all of the parameters which may be used as independent variables are

listed under each screen. Screens which do not contain any eligible parameters are not listed.

If you don't already know where the parameter you are interested in is located, you will probably

find it easier to visit the "SET PARAMETERS" program area and locate it there, where you have

additional formatting, headers and notes to guide you. Once you have located the parameter you

can come back here and select it.

Once you have selected the parameter you want in the list on the left, click the "Use Selected

Parameter" button on the right to use it. This extra step is there to allow you to browse the

parameter list without losing the currently chosen independent variable and its configuration.

4.5.2.1.2. Information

Underneath the parameter chooser, you will find information for the parameter that you are

currently using. The information for the parameter chosen in the illustration above looks like this:

This includes the parameter's location, its default value, and its minimum and maximum values,

or possible values if the parameter is a menu. You may need to use the scroll bar on the right to

see all of it.

This information is provided to help you choose an appropriate range when configuring the

variable.

4.5.2.1.3. Configuration

At the bottom of the screen, on the left side, you will find the configuration options for the

parameter you have chosen. This is the default configuration for the parameter we're using in this

example, the gross electrical output:

Illustration 128: Sensitivity Analysis: Independent Variable Information

Illustration 129: Sensitivity Analysis: Independent Variable Configuration


This area contains the following controls:

• Type of Variation: This menu allows you to choose between an automatically-generated

range ("Range") and a set of values that you specify ("Specific Values"):

• Number of Points: This allows you to specify the number of values to use for the

independent variable. You may use the arrow buttons at the right to increment or

decrement this value, or you may edit the text directly. (See "2.5. Editing Text" on page

6.) If the independent variable is a menu, and the type of variation is "Range", this value

will be determined by the minimum and maximum values, and you will not be able to

edit it directly.

• Minimum Value: If the type of variation is "Range", this is the low end of the range. It

is set to the minimum value of the parameter (or the first menu item for menus) by

default. If the type of variation is "Specific Values", the minimum value will be based on

the specific values you enter, and you will not be able to edit it directly.

• Maximum Value: If the type of variation is "Range", this is the high end of the range. It

is set to the maximum value of the parameter (or the last menu item for menus) by

default. If the type of variation is "Specific Values", the maximum value will be based

on the specific values you enter, and you will not be able to edit it directly.

4.5.2.1.4. Values

At the bottom of the screen, to the right of the configuration, you will find the list of values that

will be used. These are the default values for the default configuration for gross electrical output:

If there is a scroll bar on the right, you will need to use it to see all the values.

If the type of variation is "Range", these values are automatically generated based on the

minimum and maximum values, and the number of points. In this case, you will not be able to

edit these values directly.

If the type of variation is "Specific Values", this is where you will enter those values.

("2.5. Editing Text" on page 6.)

Illustration 130: Sensitivity Analysis: Type of Variation

Illustration 131: Sensitivity Analysis: Independent Variable Values


The procedure for entering values for menu parameters is slightly different. The values appear as

text by default. Click once to select the cell containing the value you want to change. You can use

Ctrl-C and Ctrl-V to copy and paste at this point. (See "2.6. Using the Clipboard" on page 6.) If

you click on the cell again, it will turn into a menu which you can use to select the value. (See

"2.3. Pull-Down Menus" on page 4.)

4.5.2.2. Choose Dependent Variable(s)

Once you have chosen and configured an independent variable, you are ready to choose dependent

variable(s). In this illustration, the net electrical output is chosen:

The upper left corner of this screen contains a variable chooser that is very similar to the parameter

chooser provided on the "Choose Independent Variable" screen. (See "4.5.2.1.1. Parameter Chooser"

on page 81.) This chooser contains both calculated parameters from the "SET PARAMETERS"

program area and results from the "GET RESULTS" program area. (See "4.1.4.4.2.1. Program

Areas" on page 36.)

The chooser only shows calculated parameters and results that are affected by the independent

variable. If you want to browse all affected variables, you can start at the top and press the down

arrow key repeatedly to go to the next variable. (If you interact with any of the other controls while

doing this, you will need to click on the chooser to put the focus back on it before pressing the down

arrow key again.)

If you are interested in one or more specific variables, you may find it easier to locate them in the

"SET PARAMETERS" and/or "GET RESULTS" program areas (see "4.1.4.4.2.1. Program Areas"

on page 36), where you can see them in context, before attempting to locate them here.

Illustration 132: ANALYSIS TOOLS: Sensitivity Analysis: Choose Dependent

Variable(s)


When you click on a parameter or result in the variable chooser, the screen is updated to show you

three things:

1. Summary: The summary appears below the variable chooser. It tells you where both

variables are located and what their ranges are. It also indicates that the independent

variable is on the X Axis, and the dependent variable on the Y Axis.

2. Table: The lower left part of the screen shows a table with the values of both variables. The

independent variable is in the first column, and the dependent variable in the second. You

can copy this table to the clipboard (see "2.6. Using the Clipboard" on page 6) by clicking

the "Copy Table to Clipboard" button to the right of the variable chooser. We suggest

pasting this table into a spreadsheet for easier viewing.

3. Graph: The lower right part of the screen shows a graph with the independent variable on

the X Axis and the dependent variable on the Y Axis. This graph is only intended to give

you a general idea of the relationship between the variables; it does not show any numbers.

If you want to see a more detailed graph, click the "Show Detailed Graph" button to the

right of the variable chooser. You may also copy the detailed graph to the clipboard (see

"2.6. Using the Clipboard" on page 6) by clicking the "Copy Detailed Graph to Clipboard"

button to the right of the variable chooser.

Note: Table units are not currently supported on the "Choose Dependent Variable(s)" screen. (See

"4.2.1.3.5. Performance Table" on page 53, and "4.2.1.3.6. Cost Table" on page 53.)

4.5.3. Uncertainty

The Uncertainty tool currently has two functions: it allows you to set options that are not available in

the Uncertainty Editor (see "4.3.3.3. The Uncertainty Editor" on page 59), and it allows you to easily

browse all of the calculated parameters and results that are affected by the current uncertainty.

4.5.3.1. Configure Uncertainty

This screen allows you to configure uncertainty:

Illustration 133: ANALYSIS TOOLS: Uncertainty: Configure Uncertainty


4.5.3.1.1. Sample Size

This is the number of samples that will be generated/used. It is generally set in the uncertainty

editor, but you may set it here as well. (See "4.3.3.3.4. #4: The Sample Size" on page 61.)

4.5.3.1.2. Sampling Method

This is a menu which allows you to select the method used to generate samples. (See "2.3. Pull-

Down Menus" on page 4.) The following options are available:

• Median LHS and Random LHS: Latin Hypercube is a stratified sampling method that

divides the sampling space into equally probable intervals, or strata. For each input

variable, the method samples each interval in a random order. When the samples from

each input variable are combined, one resultant output is determined. This process is

repeated m times, forming a final result of m output values. These m output values

contain the uncertainty of the output variable, based on all the uncertainties of the entire

set of input variables. The value m is referred to as the sample size.

The model contains two variations of Latin Hypercube sampling: Random and Median.

Random LHS samples each strata randomly, while Median LHS samples each strata by

its median value. (See: Diwekar, U.M. and J.R. Kalagnanam, (1997) "Efficient Sampling

Technique for Optimization under Uncertainty," AIChE Journal, Vol. 43, No. 2, pp. 440-

7.) Median LHS is the default sampling method.

Both forms of Latin Hypercube have the advantage of sampling more uniformly over the

input distributions relative to Monte Carlo sampling, resulting in less noise in the final

distribution. Another advantage is the reduced number of samples that must be taken to

satisfy a given precision. Latin Hypercube has the drawback that the precision is more

difficult to calculate using statistical methods. Finally, the output is random but not

independent.

• Random Sample: This is also known as Monte Carlo. Monte Carlo is the simplest and

best-known sampling method. It draws values at random from the uncertainty

distribution of each input variable in the decision tree. For a particular sampling run,

each input variable is randomly sampled once. The random samples from each input

result in one final output value. This process is repeated m times and results in a final

solution set. This set can then be evaluated with standard statistical techniques to

determine the mean, precision, and confidence.

This method has the advantage of providing an easy method of determining the precision

for a specific number of samples using standard statistical techniques. However, it

suffers from requiring a large number of samples for a given precision. It also has the

drawback of substantial noise in the resulting distribution. For these reasons, Latin

Hypercube sampling is preferred as the model default.

• Hammersley: The Hammersley sequence sampling technique is more efficient than

either the Monte Carlo or Latin-Hypercube sampling techniques. (See: Diwekar, U.M.

and J.R. Kalagnanam, (1997) "Efficient Sampling Technique for Optimization under

Uncertainty," AIChE Journal, Vol. 43, No. 2, pp. 440-7.) The sampling method is loosely

based on the Monte Carlo method. However, instead of using a random number

generator, it uses a quasi-random number generator based on Hammersley points to

uniformly sample a unit hypercube. These points are an optimal design for placing n

points on a k-dimensional hypercube. The sample points are then inverted over a

cumulative probability distribution to define the sample set for any uncertainty variable.

Hammersley has the advantage of high precision and consistent behavior in addition to

better computational efficiency. The method reduces the number of samples required


relative to the other sampling methods for calculating uncertainty by a factor of 2 to 100.

The actual sample reduction varies with the uncertainty function being sampled.

4.5.3.1.3. Uncertainty Areas

This is a set of checkboxes which allows you to enable or disable uncertainty in specific sections

of the plant. The "Select All" and "Select None" buttons beneath the checkboxes allow you to

easily select all or none of the areas. The list of areas varies by plant type.

4.5.3.1.3.1. Uncertainty Areas in a Pulverized Coal (PC) Plant

A PC plant has the following uncertainty areas:

• Overall Plant (PC)

• Base Plant (PC)

• Air Preheater

• Comb. NOx Control

• NOx Control

• Particulate Control

• SO2 Control

• CO2 Control

• Mercury Control

• Waste & Byproducts

• Cooling

4.5.3.1.3.2. Uncertainty Areas in a Natural Gas Combined Cycle (NGCC) Plant

An NGCC plant has the following uncertainty areas:

• Overall Plant (NGCC)

• Turbine Systems

• CO2 Capture

• Cooling

4.5.3.1.3.3. Uncertainty Areas in an Integrated Gasification Combined Cycle (IGCC) Plant

An IGCC plant has the following uncertainty areas:

• Overall Plant (IGCC)

• Oxidant & Fuel

• Gasifier Area

• Sulfur Control

• CO2 Control

• NOx Control

• Cooling


4.5.3.2. Choose Variable(s)

The "Choose Variable(s)" screen is very similar to the "Choose Dependent Variable(s)" screen in the

"Sensitivity Analysis" tool described in "4.5.2.2. Choose Dependent Variable(s)" on page 84. The

differences are:

• The parameters and results listed are those affected by the current uncertainty.

• The chosen variable is always on the X Axis; cumulative probability is always on the Y

Axis.

• The table on the lower left part of the screen shows the samples ordered by sample number.

This is not the same as the graph; in the graph, they are ordered by cumulative probability.

If you are doing batch processing, you may find it helpful to browse results using this table.

(See "4.3.3.3.13. Batch Processing" on page 66.)

• The "Copy Table to Clipboard" button is replaced by two buttons:

◦ Copy Samples to Clipboard: This copies a table containing the samples ordered by

sample number to the clipboard. If you are doing batch processing, this is the table you

want. (See "4.3.3.3.13. Batch Processing" on page 66.)

◦ Copy Graph Values to Clipboard: This copies a table containing the samples ordered

by cumulative probability to the clipboard. This table corresponds with the graph.

Note: This screen does not currently support table units. (See "4.2.1.3.5. Performance Table" on

page 53, and "4.2.1.3.6. Cost Table" on page 53.)

4.6. Exporting Data There are a number of ways to export data from the IECM. These have been described elsewhere in this

document; they are summarized here for your convenience:

• The Export Sub-menu in the File Menu: The "File" menu on the left side of the session

window's menu bar contains an "Export" menu which allows you to export various types of data

across the entire plant. These commands allow you to keep a human-readable record of your

session. See "4.1.4.1.1.1. The Export Menu" on page 28 for more information.

• Printing: The "File" menu on the left side of the session window's menu bar contains "Print

Preview" and "Print" commands which allow you to print most screens. See "4.1.4.1.1. The File

Menu" on page 28 for more information.

• The Right-Click Menu: The right-click menu for most parameters and results includes

commands which copy information to the clipboard. See "4.3.3.6. The Right-Click Menu" on

page 74 for more information on parameters, "4.4.4. The Right-Click Menu" on page 80 for

more information on results.

• "Copy" Buttons in Analysis Tools: The analysis tools contain buttons which allow you to copy

various result tables and graphs. See "4.5.2.2. Choose Dependent Variable(s)" on page 84 for

more information on sensitivity analysis results, "4.5.3.2. Choose Variable(s)" on page 88 for

more information on uncertainty results.

You may also want to copy session, coal and/or CO2 reservoir databases, for your own use on another

computer or to share them with others. Information on how to create and populate new databases is found

here:

• Session Databases: "4.1.5.3. Save As" on page 41 tells you how to save a copy of a session and

how to create a new session database.

• Coal Databases: "4.3.3.4.1. Coal Databases" on page 68 tells you how to work with coal

databases including adding and saving coals, and creating new databases.


• CO2 Reservoir Databases: "4.3.3.4.2. Reservoir Databases" on page 71 tells you how to work

with reservoir databases including adding and saving reservoirs, and creating new databases.

Note: There may be a couple of additional files associated with your databases. For example, the session

database "my-sessions.sdb" may also include the files "my-sessions.sdb-shm" and "my-sessions.sdb-wal".

These files are created in some cases by the database engine to record recent changes. If these files exist

when you copy your database, you will need to copy them as well.

IECM User Documentation: User Manual How to Use the Modules Included With the IECM • 90

5. How to Use the Modules Included

With the IECM

5.1. Common Input and Result Screens There are some screens, or parts of screens, that occur repeatedly in the IECM Interface. These are

described here to avoid duplication.

5.1.1. Costs

5.1.1.1. Capital Cost Inputs

Capital costs for most technologies are entered on a standard capital cost input screen.

Illustration 134: A Standard Capital Cost Input Screen


The necessary capital cost input parameters associated with a technology are on this input screen.

The capital cost parameters and terminology used in the IECM are based on the methodologies

developed by the Electric Power Research Institute (EPRI). They have prepared a Technical

Assessment Guide (TAG) in order to provide a consistent basis for reporting cost and revenues

associated with the electric power industry. This system of reporting is used by a wide audience,

including energy engineers, researchers, planners, and managers. The IECM has been developed

around this TAG system so that costs associated with various technologies can be compared directly

on a consistent basis and communicated in the language used by the audience listed above.

Total Plant Cost (TPC) is the sum of the process facilities capital, general facilities capital,

engineering and home office fees, and the contingencies (project and process). This is considered

the cost on an instantaneous basis (overnight), and expressed in December dollars of a reference

year.

Direct Capital Costs: Direct capital costs for each process area are calculated in the IECM. These

calculations are reduced form equations derived from more sophisticated models and reports. The

sum of the direct capital costs associated with each process area is defined as the process facilities

capital (PFC). This is the basis for all other capital cost parameters.

The process facilities capital for the technology is the total constructed cost of all on-site processing

and generating units, including all direct and indirect construction costs. All sales taxes and freight

costs are included where applicable implicitly. These direct capital costs are generally calculated by

the IECM and not presented directly on input screens. However, when important input variables are

required for these calculations, they are listed at the top of the input screen.

Indirect Capital Costs: Costs that are indirectly applied to the technology are based on the process

facilities cost. Each of the cost factors below is expressed as a percentage of the process facilities

cost, and is entered on this screen. Each parameter is described briefly below.

• Construction Time: This is the idealized construction period in years. It is used to

determine the allowance for funds used during construction (AFUDC). The construction

time for individual technologies is set to the construction time for the overall plant by

default.

• Some calculations, including some capital cost factors, only apply to part of the process

facilities capital (PFC). The following parameters determine the allocation of the PFC. The

remainder is allocated to construction labor:

◦ %PFC Allocated to Equipment

◦ %PFC Allocated to Materials

• General Facilities Capital (GFC): The general facilities include construction costs of

roads, office buildings, shops, laboratories, etc. Sales taxes and freight costs are included

implicitly. The cost typically ranges from 5-20% of the PFC.

• Engineering & Home Office Fees (E): The engineering & home office fees are a percent

of total direct capital cost. This is an overhead fee paid to the architect/engineering

company. These fees typically range from 7-15% of the PFC.

• Process Contingency Cost (C): This quantifies the design uncertainty and cost of a

commercial-scale system. This is generally applied on an area-by-area basis. Higher

contingency factors are applied to new regeneration systems tested at a pilot plant and

lower factors to full-size or commercial systems. This is a percentage of the PFC.

• Project Contingency Cost: This is factor covering the cost of additional equipment or

other costs resulting from a more detailed design. Higher contingency factors will be

applied to simplified or preliminary designs and lower factors to detailed or finalized

designs. This is a percentage of PFC + E + C, where E is Engineering & Home Office Fees,

and C is the Process Contingency Cost.


• Royalty Fees: Royalty charges may apply to some portions of generating units

incorporating new proprietary technologies. This is a percentage of the PFC.

• Pre-Production Costs: These costs consider the operator training, equipment checkout,

major changes in unit equipment, extra maintenance, and inefficient use of fuel or other

materials during start-up. These are typically applied to O&M costs over a specified period

of time (months).

◦ Fixed Operating Cost: This is the number of months of fixed operating costs

(operating and maintenance labor, administrative and support labor, and maintenance

materials) used for plant startup.

◦ Variable Operating Cost: This is the number of months of variable operating costs at

full capacity (chemicals, water, and other consumables, and waste disposal changes)

used for plant startup. Full capacity estimates of the variable operating costs will

assume operations at 100% load.

◦ Misc. Capital Cost: This is a percent of total plant investment (sum of TPC and

AFUDC) to cover expected changes to equipment to bring the system up to full

capacity.

• Inventory Capital: Percent of the total direct capital for raw material supply based on

100% capacity during a 60-day period. These materials are considered storage. The

inventory capital includes fuels, consumables, by-products, and spare parts. This is

typically 0.5% of the TPC.

• Financing Cost: This is a percentage of the TPC.

• Other Owner's Costs: This is a percentage of the TPC.

• %TCR Amortized: This is the percentage of the total capital required (TCR) that has been

amortized. This value is 0% for new equipment and may be set as high as 100% for

equipment that has been paid off.


5.1.1.2. Capital Cost Results

The Air Separation Capital Cost result screen displays tables for the capital costs. Capital costs are

typically expressed in either constant or current dollars for a specified year, as shown on the bottom

of the screen. This is one example:

The table on the left contains the capital cost process areas, which vary depending on the

technology. The last line of the left table is always:

• Process Facilities Capital: The process facilities capital is the total constructed cost of all

on-site processing and generating units listed above, including all direct and indirect

construction costs. All sales taxes and freight costs are included where applicable

implicitly. This result is highlighted in yellow.

The table on the right contains the plant costs:

• Process Facilities Capital: (see definition above)

• General Facilities Capital: The general facilities include construction costs of roads,

office buildings, shops, laboratories, etc. Sales taxes and freight costs are included

implicitly.

• Eng. & Home Office Fees: The engineering & home office fees are a percent of total

direct capital cost. This is an overhead fee paid to the architect/engineering company.

• Process Contingency Cost: Capital cost contingency factor applied to a new technology in

an effort to quantify the uncertainty in the technical performance and cost of the

commercial-scale equipment.

• Project Contingency Cost: Capital cost contingency factor covering the cost of additional

equipment or other costs that would result from a more detailed design of a definitive

project at the actual site.

• Interest Charges (AFUDC): Allowance for funds used during construction, also referred

to as interest during construction, is the time value of the money used during construction

and is based on an interest rate equal to the before-tax weighted cost of capital. This

interest is compounded on an annual basis (end of year) during the construction period for

all funds spent during the year or previous years.

Illustration 135: PC: GET RESULTS: Base Plant: Boiler: Capital Cost


• Royalty Fees: Royalty charges may apply to some portions of generating units

incorporating new proprietary technologies.

• Preproduction (Startup) Cost: These costs consider the operator training, equipment

checkout, major changes in unit equipment, extra maintenance, and inefficient use of fuel

or other materials during start up.

• Inventory (Working) Capital: The raw material supply based on 100% capacity during a

60-day period. These materials are considered storage. The inventory capital includes fuels,

consumables, by products, and spare parts.

• Financing Cost: This is the cost of securing financing (e.g., fees and closing costs).

• Other Owner's Costs: This is an additional lumped cost, including preliminary feasibility

studies, economic development, construction and/or improvement of roads and/or railroad

spurs outside of site boundary, legal fees, permitting costs, owner’s engineering, and

owner’s contingency. This cost is site and owner specific.

• Total Capital Requirement (TCR): Money that is placed (capitalized) on the books of the

utility on the service date. TCR includes all the items above. This result is highlighted in

yellow.

• Effective TCR: The TCR that is used in determining the total power plant cost. The

effective TCR is determined by the % TCR Amortized, which is specified on the capital

cost input screen as described in "5.1.1.1. Capital Cost Inputs" on page 90.

5.1.1.3. Cost of CO2 Avoided & Captured

Most CO2 capture systems have a summary result screen. This is an example:

The table on the left varies depending on the technology, but the table on the right is fairly

consistent:

• Cost of CO2 Avoided & Captured: Many analysts like to express the cost of an

environmental control system in terms of the cost per ton of pollutant removed or avoided.

For energy-intensive CO2 controls there is a big difference between the cost per ton CO2

removed and the cost per ton "avoided" based on net plant capacity. Since the purpose of

Illustration 136: PC: GET RESULTS: CO2 Capture, Transport & Storage:

CCS System (Amine): Summary


adding a CO2 unit is to reduce the CO2 emissions per net kWh delivered, the cost of CO2

avoidance is the economic indicator that is widely used in this field.

◦ Power Plant with CCS

▪ CO2 Emitted: This is the amount of CO2 vented to the air for every kilowatt hour

of electricity produced in the power plant that is using CO2 Capture Technology.

▪ CO2 Captured: This is the amount of CO2 captured for every kilowatt hour of

electricity produced in the power plant that is using CO2 Capture Technology.

▪ Cost of Electricity: The IECM framework calculates the cost of electricity (COE)

for the overall Capture Plant by dividing the total annualized plant cost ($/yr) by

the net electricity generated (kWh/yr).

▪ Cost of Electricity, excl. T&S: This is the value above minus the cost of CO2

transport and storage.

◦ Reference Plant

▪ CO2 Emitted: This is the amount of CO2 vented to the air for every kilowatt hour

of electricity produced in the power plant with NO CO2 Capture.

▪ Cost of Electricity: The IECM framework calculates the cost of electricity (COE)

for the overall Reference Plant by dividing the total annualized plant cost ($/yr) by

the net electricity generated (kWh/yr).

▪ Added Cost of CCS: This is the difference in the cost of electricity between the

capture and reference plants.

Added Cost of CCS = (Cost of Electricity cap. - Cost of Electricity ref.)

▪ Cost of CO2 Avoided: This is the economic indicator widely used in the field,

calculated as the difference between the cost of electricity in the capture plant and

the reference plant divided by the difference between the CO2 emissions in the

reference plant and the capture plant.

Cost of CO2 Avoided = (Cost of Electricity cap. - Cost of Electricity ref.) / (CO2

emissions ref. - CO2 emissions cap.)

▪ Cost of CO2 Captured: This is the cost of capturing CO2.

Cost of CO2 Captured = (Cost of Electricity Excl. T&S cap. - Cost of Electricity

ref.) / (CO2 emissions cap.)


5.1.1.4. Cost Summary Results

The Cost Summary result screen displays costs associated with the power plant as a whole. The

costs summarized on this screen are expressed in either constant or current dollars for a specified

year, as shown on the bottom of the screen. This is one example:

The list of technologies (rows) is different for each plant type. Each cost category (column) is

described briefly below.

• Capital Required: The total capital requirement (TCR). This is the money that is placed

(capitalized) on the books of the utility on the service date. The total cost includes the total

plant investment plus capitalized plant startup. Escalation and allowance for funds used

during construction (AFUDC) are also included. The capital cost is given on both a total

and an annualized basis.

• Revenue Required: Amount of money that must be collected from customers to

compensate a utility for all expenditures in capital, goods, and services. The revenue

requirement is equal to the carrying charges plus expenses. The revenue required is given

on both an annualized and a net power output basis.

Illustration 137: PC: GET RESULTS: Overall Plant: Cost Summary


5.1.1.5. O&M Cost Inputs

Inputs for O&M costs are entered on an O&M Cost input screen. This is one example:

The EPRI TAG method of categorization has been used for operating and maintenance costs

screens. It provides a consistent basis of reporting for a wider audience of users.

O&M costs are typically expressed on an average annual basis and are provided in either constant or

current dollars for a specified year, as shown on the bottom of the screen. All O&M cost input

screens contain the following inputs:

• Electricity Price (Internal): This is the price of electricity as specified on the Overall

Plant Fuel & Land Cost input screen. (See "5.2.2.1.6. Fuel & Land Cost" on page 122.)

• Number of Operating Jobs: This is the total number of operating jobs that are required to

operate the plant per eight-hour shift.

• Number of Operating Shifts: This is the total number of equivalent operating shifts in the

plant per day. The number takes into consideration paid time off and weekend work (3

shifts/day * 7 days/5-day week * 52 weeks/(52 weeks - 6 weeks PTO) = 4.75 equiv.

Shifts/day)

• Operating Labor Rate: The hourly cost of labor is specified in the base plant O&M cost

screen. The same value is used throughout the other technologies.

• Total Maintenance Cost: This is the annual maintenance cost as a percentage of the total

plant cost. Maintenance cost estimates can be developed separately for each process area.

• Maint. Cost Allocated to Labor: Maintenance cost allocated to labor as a percentage of

the total maintenance cost.

• Administrative & Support Cost: This is the percentage of the total operating and

maintenance labor associated with administrative and support labor.

• Taxes & Insurance: This is the cost of taxes and insurance as a percentage of the total

plant cost. This value is specified on the Overall Plant O&M Cost input screen. (See

"5.2.2.1.8. O&M Cost" on page 123.)

Some O&M cost screens contain additional inputs; these generally appear at the top of the screen.

Illustration 138: An Example O&M Cost Input Screen


5.1.1.6. O&M Cost Results

O&M costs are typically expressed on an average annual basis and are provided in either constant or

current dollars for a specific year, as shown on the bottom of the screen. This is one example of an

O&M cost result screen:

The EPRI TAG method of categorization has been used for operating and maintenance costs

screens. It provides a consistent basis of reporting for a wider audience of users.

O&M costs are expressed on an average annual basis and are provided in either constant or current

dollars for a specified year, as shown on the bottom of the screen. The costs are broken down into

two categories: variable and fixed.

Variable costs include the costs of reagents, chemicals, water, and other materials consumed during

plant operation. Variable operating costs and consumables are directly proportional to the amount of

kilowatts produced and are referred to as incremental costs.

Fixed costs are associated with labor and overhead charges. Fixed operating costs are essentially

independent of actual capacity factor, number of hours of operation, or amount of kilowatts

produced.

All operating costs are subject to inflation.

The table on the left shows the variable cost components, which vary depending on the technology.

The last line is the total:

• Total Variable Costs: This is the sum of all the variable O&M costs listed above. This

result is highlighted in yellow.

The table on the right shows the fixed cost components. Fixed operating costs are essentially

independent of actual capacity factor, number of hours of operation, or amount of kilowatts

produced. All the costs are subject to inflation. The following results are shown in this table:

• Operating Labor: Operating labor cost is based on the operating labor rate, the number of

personnel required to operate the plant per eight-hour shift, and the average number of

shifts per day over 40 hours per week and 52 weeks.

Illustration 139: PC: GET RESULTS: Base Plant: Boiler: O&M Cost


• Maintenance Labor: The maintenance labor is determined as a fraction of the total

maintenance cost.

• Maintenance Material: The cost of maintenance material is the remainder of the total

maintenance cost, considering the fraction associated with maintenance labor.

• Admin. & Support Labor: The administrative and support labor is the only overhead

charge. It is taken as a fraction of the total operating and maintenance labor costs.

• Taxes & Insurance: This is the cost of taxes and insurance. This cost is included as fixed

O&M costs and is estimated empirically as a percent of the TPC.

• Total Fixed Costs: This is the sum of all the fixed O&M costs listed above. This result is

highlighted in yellow.

• Total O&M Costs: This is the sum of the total variable and total fixed O&M costs. It is

used to determine the base plant total revenue requirement. This result is highlighted in

yellow.

5.1.1.7. Total Cost Results

The Total Cost result screen displays a table which totals the annual fixed, variable, operations and

maintenance, and capital costs associated with a technology. This is an example:

Total costs are typically expressed in either constant or current dollars for a specified year, as shown

on the bottom of the screen. Results are typically given in the following units:

• M$/yr

• $/MWh

• $/ton pollutant removed (if applicable)

• Percent Total

Each Cost Component is described briefly below.

• Annual Fixed Cost: The operating and maintenance fixed costs are given as an annual

total. This number includes all maintenance materials and all labor costs.

• Annual Variable Cost: The operating and maintenance variables costs are given as an

annual total. This includes all reagent, chemical, steam, and power costs.

• Total Annual O&M Cost: This is the sum of the annual fixed and variable operating and

maintenance costs above. This result is highlighted in yellow.

Illustration 140: PC: GET RESULTS: NOx Control: In-Furnace Controls:

Total Cost


• Annualized Capital Cost: This is the total capital cost expressed on an annualized basis,

taking into consideration the levelized carrying charge factor, or fixed charge factor, over

the entire book life.

• Total Levelized Annual Cost: The total annual cost is the sum of the total annual O&M

cost and annualized capital cost items above. This result is highlighted in yellow.

5.1.1.8. Retrofit or Adjustment Factor Inputs

The retrofit cost factor of each process is a multiplicative cost adjustment, which considers the cost

of retrofitted capital equipment relative to similar equipment installed in a new plant. These factors

affect the capital costs directly and the operating and maintenance costs indirectly.

Direct capital costs for each process area are calculated in the IECM. These calculations are reduced

form equations derived from more sophisticated models and reports. The sum of the direct capital

costs associated with each process area is defined as the process facilities capital (PFC). The retrofit

cost factor provided for each of the process areas can be used as a tool for adjusting the anticipated

costs and uncertainties across the process area separate from the other areas.

Uncertainty can be applied to the retrofit cost factor for each process area in each technology. Thus,

uncertainty can be applied as a general factor across an entire process area, rather than as a specific

uncertainty for the particular cost on the capital or O&M input screens. Any uncertainty applied to a

process area through the retrofit cost factor compounds any uncertainties specified in the capital and

O&M cost input screens.

The set of capital cost process areas on the retrofit cost input screen varies with the technology.

5.1.2. Fuels

5.1.2.1. Coal Properties

Some screens deal with the composition of coal. The coal properties are:

• Heating Value: Higher heating value (HHV) is the thermal energy produced in Btu/lb of

fuel (wet) from completely burning the fuel to produce carbon dioxide and liquid water.

The latent heat of condensation is included in the value.

• Carbon: The weight percent of carbon in the fuel on an elemental (C) and wet basis.

• Hydrogen: This is the weight percent of hydrogen in the fuel on an elemental (H) and wet

basis.

• Oxygen: This is the weight percent of oxygen in the fuel on an elemental (O) and wet

basis.

• Chlorine: This is the weight percent of chlorine in the fuel on an elemental (Cl) and wet

basis.

• Sulfur: This is the weight percent of sulfur in the fuel on an elemental (S) and wet basis.

• Nitrogen: This is the weight percent of nitrogen in the fuel on an elemental (N) and wet

basis.

• Ash: This is the weight percent of ash in the fuel on a wet basis.

• Moisture: This is the weight percent of moisture in the fuel on a wet basis.

5.1.2.1.1. Ash Properties

Some screens deal with the composition of ash in the coal. The ash properties are:

• SiO2: The percent by weight of silicon dioxide in the ash.


• Al2O3: The percent by weight of Aluminum Oxide in the ash.

• Fe2O3: The percent by weight of ferric oxide in the ash.

• CaO: The percent by weight of calcium oxide in the ash.

• MgO: The percent by weight of magnesium oxide in the ash.

• Na2O: The percent by weight of sodium oxide in the ash.

• K2O: The percent by weight of potassium oxide in the ash.

• TiO2: The percent by weight of titanium dioxide in the ash.

• MnO2: The percent by weight of manganese dioxide in the ash.

• P2O5: The percent by weight of phosphorus pentoxide in the ash.

• SO3: The percent by weight of sulfur trioxide in the ash.

5.1.2.2. Natural Gas Properties

Some screens deal with the composition of natural gas. The natural gas properties are:

• Heating Value: Higher heating value (HHV) is the thermal energy produced in Btu/lb of

fuel from completely burning the fuel to produce carbon dioxide and liquid water. The

latent heat of condensation is included in the value.

• Methane (CH4): The volume, by percent, of methane in the natural gas.

• Ethane (C2H6): The volume, by percent, of ethane in the natural gas.

• Propane (C3H8): The volume, by percent, of propane in the natural gas.

• Carbon Dioxide (CO2): The volume, by percent, of carbon dioxide in the natural gas.

• Oxygen (O2): The volume, by percent, of oxygen in the natural gas.

• Nitrogen (N2): The volume, by percent, of nitrogen in the natural gas.

• Hydrogen Sulfide (H2S): The volume, by percent, of hydrogen sulfide in the natural gas.

5.1.3. Gas Streams

5.1.3.1. Flue Gas Components

Most technologies have at least one result screen that deals with flue gas. This is one example:


Rows contain a standard set of flue gas components. Each column contains one result. Results are

typically given in both lb-moles/hr and tons/hr. The flue gas components (rows) are:

• Nitrogen (N2): Total mass of nitrogen.

• Oxygen (O2): Total mass of oxygen.

• Water Vapor (H2O): Total mass of water vapor.

• Carbon Dioxide (CO2): Total mass of carbon dioxide.

• Carbon Monoxide (CO): Total mass of carbon monoxide.

• Hydrochloric Acid (HCl): Total mass of hydrochloric acid.

• Sulfur Dioxide (SO2): Total mass of sulfur dioxide.

• Sulfuric Acid (equivalent SO3): Total mass of sulfuric acid.

• Nitric Oxide (NO): Total mass of nitric oxide.

• Nitrogen Dioxide (NO2): Total mass of nitrogen dioxide.

• Ammonia (NH3): Total mass of ammonia.

• Argon (Ar): Total mass of argon.

• Total: Total of the individual components listed above. This item is highlighted in yellow.

5.1.3.2. Syngas Components

There are a number of screens that deal with syngas. This is one example:

Illustration 141: PC: GET RESULTS: Overall Plant: Gas In/Out


Most of the screens dealing with syngas are result screens, where the rows contain a standard set of

syngas components, and each column contains one result. Results are typically given in lb-moles/hr

and tons/hr. For input screens, the composition is given in vol %. The syngas components are:

• Carbon Monoxide (CO): Total mass of carbon monoxide.

• Hydrogen (H2): Total mass or percent of hydrogen.

• Methane (CH4): Total mass or percent of methane.

• Ethane (C2H6): Total mass or percent of ethane.

• Propane (C3H8): Total mass or percent of propane.

• Hydrogen Sulfide (H2S): Total mass or percent of hydrogen sulfide.

• Carbonyl Sulfide (COS): Total mass or percent of carbonyl sulfide.

• Ammonia (NH3): Total mass or percent of ammonia.

• Hydrochloric Acid (HCl): Total mass or percent of hydrochloric acid.

• Carbon Dioxide (CO2): Total mass or percent of carbon dioxide.

• Water Vapor (H2O): Total mass or percent of water vapor.

Illustration 142: A Syngas Result Screen


• Nitrogen (N2): Total mass or percent of nitrogen.

• Argon (Ar): Total mass or percent of argon.

• Oxygen (O2): Total mass or percent of oxygen.

• Total: Total of the individual components listed above. This item is highlighted in yellow.

5.1.4. Other

5.1.4.1. Mass In/Out

The "Mass In/Out" result screen displays the flow rates of fuels and chemicals into the plant and

solid and liquid flow rates out of the plant. This is an example:

The details vary slightly between plant types, as indicated below, but the information shown is very

similar.

The following plant inputs are displayed:

• Coal: Flow rate of coal used in the power plant.

• Oil: Flow rate of oil used in the power plant.

• Natural Gas: Flow rate of natural gas used in the power plant

• Petroleum Coke: (NGCC and IGCC Only) Total mass of petroleum coke used in the

power plant

• Other Fuels: (NGCC and IGCC Only) Flow rate of other fuels used in the power plant

• Total Fuels: This is the flow rate of fuel entering the power plant. This result is highlighted

in yellow.

• Lime/Limestone: Total mass of this reagent used in the power plant on a wet basis.

• Sorbent: Total mass of sorbent used in the power plant

• Ammonia: Total mass of ammonia used in the power plant.

Illustration 143: PC: GET RESULTS: Overall Plant: Mass In/Out


• Urea: (PC Only) Total mass of urea used in the power plant. Urea is the reagent used to

reduce NOx in the SNCR technology.

• Dibasic Acid: (PC Only) Total mass of dibasic acid used in the power plant.

• Activated Carbon: Flow rate of activated carbon injected in the power plant.

• Other Chemicals, Solvents & Catalyst: (NGCC and IGCC Only) Flow rate of other

chemicals, solvents and catalysts used in the power plant.

• Total Chemicals: Flow rate of reagent entering the power plant. This result is highlighted

in yellow.

• Oxidant: (IGCC Only) Flow rate of oxidant entering the power plant. This includes

oxygen, nitrogen and argon.

• Process Water: (NGCC and IGCC Only) Flow rate of water used in the power plant.

Plant Outputs:

• Bottom Ash Disposed: (PC Only) Total mass of bottom ash collected in the power plant on

a dry basis.

• Slag: (NGCC and IGCC Only) Flow rate of slag from the power plant on a dry basis.

• Fly Ash Disposed: (PC Only) Total mass of fly ash collected in the power plant on a dry

basis.

• Ash Disposed: (NGCC and IGCC Only) Flow rate of ash from the power plant on a dry

basis.

• Scrubber Solids Disposed: (PC and NGCC Only) Total mass of scrubber solid wastes

collected in the power plant on a dry basis.

• Other Solids Disposed: (IGCC Only) Flow rate of scrubber and other treatment solid

wastes from the power plant on a dry basis.

• Particulate Emissions to Air: Flow rate of particulates emitted to the air from the plant.

• Captured CO2: Flow rate of the captured CO2.

• Byproduct Ash Sold: Flow rate of ash (bottom and fly ash) sold in commerce as a by-

product on a dry basis.

• Byproduct Gypsum Sold: Flow rate of flue gas treatment solids sold in commerce as a by-

product on a dry basis.

• Byproduct Sulfur Sold: Flow rate of elemental sulfur recovered from flue gas and sold in

commerce as a by-product on a dry basis.

• Byproduct Sulfuric Acid Sold: Total mass of sulfuric acid recovered from the flue gas and

sold in commerce as a by-product.

• Total: This is the total wet solid mass exiting the power plant. This result is highlighted in

yellow.

• Water Evaporated (Consumptive): This is the amount of water lost due to evaporation.

• Cooling Water Discharge: (Only shown when Once-Through Cooling is in use.) This is

the total cooling water required.

5.1.4.2. Plant Performance

The Plant Performance result screen displays performance results for the plant as a whole. Heat rates

and power in and out of the power plant are given. This is an example:


The content of the table on the right, "Plant Energy Requirements", varies depending on the plant

type. The table on the left, "Performance Parameters", is fairly standard. Each performance

parameter is described briefly below:

• Net Electrical Output: This is the net plant capacity, which is the gross plant capacity

minus the losses due to plant equipment and pollution equipment (energy penalties).

• Net Elec. Output (Annual Avg.): (Only shown when Hybrid Cooling is used.) A hybrid

cooling system uses different cooling systems at different times of the year; thus, the net

plant capacity varies. In this case, the value shown above is a worst-case value. This

value gives the average net plant capacity across the entire year.

• Primary Fuel Power Input: (PC Only) This is the fuel energy input for the plant, given

on an hourly basis (maximum capacity). This rate is also referred to as the fuel power

input.

• Aux. Fuel Power Input: (PC and NGCC Only) This is the fuel energy input for the

auxiliary natural gas boiler if used with the Amine System. This is additional fuel energy

used by the plant, given on an hourly basis. This rate is also referred to as the auxiliary

fuel power input.

• Total Plant Power Input: This is the total of all the fuel energy used by the plant, given

on an hourly basis (maximum capacity). This rate is also referred to as the total plant

power input.

• Gross Plant Heat Rate: This is the heat rate of the gross cycle including the effects of

the boiler efficiency. This is considered the gross heat rate.

• Net Plant Heat Rate: This is the net heat rate, which includes the effect of plant

equipment and pollution control equipment.

• Annual Operating Hours: This is the number of hours per year that the plant is in

operation. If a plant runs 24 hours per day, seven days per week, with no outages, the

calculation is 24 hours * 365 days. or 8,760 hours/year.

• Annual Power Generation: This is the net annual power production of the plant. The

capacity factor and all energy credits or penalties are used in determining its value.

Illustration 144: PC: GET RESULTS: Overall Plant: Plant Performance


• Net Plant Efficiency: The net plant efficiency is displayed here on an HHV basis.

5.1.4.3. T&S Config

All of the CO2 capture technologies have in input screen where the transport and storage

methods may be specified. Many of these screens have additional inputs; however, the

following are always available:

• CO2 Transport Method: This is the method used to transport the CO2 product to the

sequestration site. The following options are available:

◦ Pipeline: (This is the default.) CO2 is transported via pipeline to the sequestration

site. Additional parameters related to the pipeline are found in the "Pipeline

Transport" process type as described in "5.2.2.8.10. Pipeline Transport" on page

244. Note that the pipeline has a minimum required CO2 product pressure; an

error will be displayed if the pressure is too low.

◦ User-Specified: This option may be chosen if the pipeline model is not suitable.

It does not have a minimum inlet pressure. Additional parameters are found in the

"User-Specified Transport" process type as described in "5.2.2.8.12. User-

Specified Transport" on page 248.

• CO2 Storage Method:

◦ Geologic: (This is the default.) Geological Reservoir. Additional parameters are

found in the "CO2 Storage" process type as described in "5.2.2.8.13. CO2

Storage" on page 249.

◦ EOR: Enhanced Oil Recovery. There are no additional parameters for this

option.

5.2. Pulverized Coal (PC) Plant

5.2.1. CONFIGURE SESSION

5.2.1.1. Plant Design

This screen allows you to choose the technologies that will be implemented in your plant. See

"4.2.1.1. The "Plant Design" Screen" on page 45 for a general description of this screen and how to

use it. The screen looks like this:

Illustration 145: PC: SET PARAMETERS: CO2 Capture, Transport & Storage:

CCS System: T&S Config


Predefined configurations can be selected using the "Configuration" menu at the top of the screen.

The following options are available:

• No Devices: This is the default. All technology selection menus are set to their default

values:

◦ Coal

◦ Once-Through Cooling (See "5.2.3.9.1. Water" on page 397.)

◦ Ash Pond (See "5.2.2.10. By-Prod. Mgmt" on page 264.)

◦ No Mixing

• Typical New Plant: This configuration is intended to meet the EPA's New Source

Performance Standards (NSPS) requirements:

◦ Coal

◦ In-Furnace Controls (See "5.2.2.4.1. In-Furnace Controls" on page 138 and

"5.2.3.4.1. In-Furnace Controls" on page 291.)

◦ Hot-Side SCR (See "5.2.2.4.2. Hot-Side SCR" on page 144 and "5.2.3.4.2. Hot-Side

SCR" on page 297.)

◦ Cold-Side ESP (See "5.2.2.6.1. Cold-Side ESP" on page 157 and "5.2.3.6.1. Cold-

Side ESP" on page 309.)

◦ Wet FGD (See "5.2.2.7.1. Wet FGD" on page 164 and 5.2.3.7.1. Wet FGD" on page

318.)

◦ Wet Cooling Tower (See "5.2.2.9.3. Wet Cooling Tower or Wet Unit" on page 259 and

"5.2.3.9.4. Wet Cooling Tower or Wet Unit" on page 404.)


◦ No Mixing

• Oxyfuel Low S (<0.5%): This is an Oxyfuel configuration for low-sulfur coals. The

oxyfuel system has some very specific configuration requirements that make it difficult to

Illustration 146: PC Plant: CONFIGURE SESSION: Plant Design


select in the menus directly. We recommend that you start with this configuration and make

adjustments as needed:

◦ Coal



◦ Fabric Filter (See "5.2.2.6.2. Fabric Filter" on page 160 and "5.2.3.6.2. Fabric Filter"

on page 314.)

◦ Lime Spray Dryer (See "5.2.2.7.2. Spray Dryer" on page 171 and "5.2.3.7.2. Spray

Dryer" on page 323.)

◦ Oxyfuel Low S (<0.5%) (See "5.2.2.8.9. FG Recycle & Purification" on page 238 and

"5.2.3.8.9. FG Recycle & Purification" on page 380.)




◦ No Mixing

• Oxyfuel Med S (0.5%-1.5%): This is an Oxyfuel configuration for medium-sulfur coals.

The oxyfuel system has some very specific configuration requirements that make it

difficult to select in the menus directly. We recommend that you start with this

configuration and make adjustments as needed:

◦ Coal




on page 314.)



◦ Oxyfuel Med S (0.5%-1.5%) (See "5.2.2.8.9. FG Recycle & Purification" on page

238 and "5.2.3.8.9. FG Recycle & Purification" on page 380.)




◦ No Mixing

• Oxyfuel High S (>1.5%): This is an Oxyfuel configuration for high-sulfur coals. The

oxyfuel system has some very specific configuration requirements that make it difficult to

select in the menus directly. We recommend that you start with this configuration and make

adjustments as needed:

◦ Coal




on page 314.)



318.)

◦ Oxyfuel High S (>1.5%) (See "5.2.2.8.9. FG Recycle & Purification" on page 238

and "5.2.3.8.9. FG Recycle & Purification" on page 380Wet Cooling Tower (See

"5.2.2.9.3. Wet Cooling Tower or Wet Unit" on page 259 and "5.2.3.9.4. Wet Cooling

Tower or Wet Unit" on page 404.)


◦ No Mixing

• ESP+FGD: This is a simple configuration with just a Cold-Side ESP and a Wet FGD:

◦ Coal




318.)



◦ No Mixing

• SCR+ESP+FGD: This is a simple configuration with just a Hot-Side SCR, Cold-Side ESP

and Wet FGD:

◦ Coal

◦ Hot-Side SCR (See "5.2.2.4.2. Hot-Side SCR" on page 144 and "5.2.3.4.2. Hot-Side

SCR" on page 297.)




318.)



◦ No Mixing

• SD+FF: This is a simple configuration with just a Spray Dryer and a Fabric Filter:

◦ Coal


on page 314.)





◦ No Mixing

• <User Defined>: This is shown when the current configuration does not match any of the

predefined configurations.


Technologies may also be chosen individually. You may either start with one of the predefined

configurations and adjust it, or create your own configuration from scratch. The available options

are described below:

• Combustion Controls: These configuration options determine the type of furnace and any

technologies for reducing NOx emissions.

◦ Fuel Type:

▪ Coal: This is currently the only fuel type supported in the PC plant.

◦ NOx Control:

▪ None: This is the default.

▪ In-Furnace Controls: Controls include an assortment of options which combine

low NOx burners (LNB) with overfire air (OFA), selective non-catalytic reduction

(SNCR), and natural gas reburn. These options are selected from a pull-down

menu on the configuration input screen. (See "5.2.2.4.1. In-Furnace Controls" on

page 138 and "5.2.3.4.1. In-Furnace Controls" on page 291.)

• Post-Combustion Controls: These configuration options determine the presence and type

of post-combustion emissions controls.

◦ NOx Control:

▪ None: This is the default. No post-combustion NOx control is used.

▪ Hot Side SCR: for a Hot-Side Selective Catalytic Reduction technology.

Although an SCR technology can be positioned at various points along the flue

gas train, the IECM considers only the hot-side, high dust configuration. "Hot

Side SCR" may be used together with In-Furnace Controls. (See "5.2.2.4.2. Hot-

Side SCR" on page 144 and "5.2.3.4.2. Hot-Side SCR" on page 297.)

◦ Mercury:

▪ None: This is the default. No post-combustion mercury control is used.

▪ Carbon Injection: Although some mercury removal is accomplished naturally in

a power plant. It is believed that some mercury is captured or trapped in ash and is

removed with bottom ash and fly ash. Carbon injection is provided as a

technology to achieve higher removals by injecting fine particles of activated

carbon into the flue gas after the air preheater. This option requires some form of

particulate control to assure the removal of the injected carbon immediately

downstream of the air preheater. (See "5.2.2.5. Mercury" on page 151 and

"5.2.3.5. Mercury" on page 303.)

◦ Particulates:

▪ None: This is the default. No post-combustion particulate control is used. This

option is not available when the mercury technology "Carbon Injection" is chosen.

This assures the removal of the carbon being injected immediately downstream of

the air preheater.

▪ Cold Side ESP: A Cold-Side Electrostatic Precipitator is used. (See

"5.2.2.6.1. Cold-Side ESP" on page 157 and "5.2.3.6.1. Cold-Side ESP" on page

309.)

▪ Fabric Filter: You may choose the type of fabric filter on the configuration input

screen. (See "5.2.2.6.2. Fabric Filter" on page 160 and "5.2.3.6.2. Fabric Filter" on

page 314.)

◦ SO2 Control:


▪ None: This is the default. No post-combustion SO2 control is used. Some CO2

removal technologies require SO2 control; if one of those is chosen, this option

will be disabled.

▪ Wet FGD: A Wet Flue Gas Desulfurization technology is used. Multiple reagent

options are available on the configuration input screen. (See "5.2.2.7.1. Wet FGD"

on page 164 and 5.2.3.7.1. Wet FGD" on page 318.)

▪ Lime Spray Dryer: A dry scrubber using lime as a reagent. The interface places

this technology before the particulate control technology in the plant design and

diagrams. (See "5.2.2.7.2. Spray Dryer" on page 171 and "5.2.3.7.2. Spray Dryer"

on page 323.)

◦ CO2 Capture:

▪ None: This is the default. No CO2 capture is used.

▪ Amine System: This option puts an amine scrubber at the end of the flue gas

train. This option requires post-combustion NOx control.

▪ Ammonia System: An ammonia-based CO2 capture process is used. This option

requires post-combustion NOx and SO2 control. (See "5.2.2.8.2. Ammonia System

(CCS System)" on page 188 and "5.2.3.8.2. Ammonia System (CCS System)" on

page 337.)

▪ Membrane System: A polymeric membrane system is used for CO2 capture. This

option requires post-combustion NOx and SO2 control. (See "5.2.2.8.5. Membrane

System (CCS System)" on page 208 and "5.2.3.8.4. Membrane System (CCS

System)" on page 353.)

▪ Solid Sorbents PSA: A solid sorbents-based pressure swing adsorption (PSA)

system is used for CO2 capture. This option requires post-combustion NOx and

SO2 control. (See "5.2.2.8.6. Solid Sorbents PSA (CCS System)" on page 219 and

"5.2.3.8.5. Solid Sorbents PSA (CCS System)" on page 362.

▪ Solid Sorbents TSA: A solid sorbents-based temperature swing adsorption (TSA)

system is used for CO2 capture. This option requires post-combustion NOx and

SO2 control. (See "5.2.2.8.7. Solid Sorbents TSA (CCS System)" on page 226 and

"5.2.3.8.6. Solid Sorbents TSA (CCS System)" on page 369.)

▪ Oxyfuel Low S (<0.5%): This is an oxyfuel system for use with low-sulfur

(<0.5%) coals. This option requires a specific configuration; we recommend that

you start with the predefined configuration of the same name in the

"Configuration" menu to access it and make any adjustments needed from there.

(See "5.2.2.8.9. FG Recycle & Purification" on page 238 and "5.2.3.8.9. FG

Recycle & Purification" on page 380.)

▪ Oxyfuel Med S (0.5%-1.5%): This is an oxyfuel system for use with medium-

sulfur (0.5% - 1.5%) coals. This option requires a specific configuration; we

recommend that you start with the predefined configuration of the same name in

the "Configuration" menu to access it and make any adjustments needed from

there. (See "5.2.2.8.9. FG Recycle & Purification" on page 238 and "5.2.3.8.9. FG


▪ Oxyfuel High S (>1.5%): This is an oxyfuel system for use with high-sulfur

(>1.5%) coals. This option requires a specific configuration; we recommend that

you start with the predefined configuration of the same name in the

"Configuration" menu to access it and make any adjustments needed from there.

(See "5.2.2.8.9. FG Recycle & Purification" on page 238 and "5.2.3.8.9. FG



▪ Chemical Looping: Post-combustion chemical looping uses a calcium looping

(CaL) process for CO2 capture. This option requires post-combustion NOx control.

It is not compatible with the hybrid cooling system. (See "5.2.2.8.4. Chemical

Looping (CCS System)" on page 197 and "5.2.3.8.3. Chemical Looping (CCS

System)" on page 345.)


◦ Cooling System: This option determines the cooling technology:

▪ Once-Through: (This is the default.) Cooling water is withdrawn from a natural

waterbody, passed through the steam condenser and returned to the waterbody.

(See "5.2.3.9.1. Water" on page 397.)

▪ Wet Cooling Tower: Cooling water is recirculated through the wet tower and

back to the condenser. The tower mainly relies on the latent heat of water

evaporation to transfer waste heat to the atmosphere. (See "5.2.2.9.3. Wet Cooling

Tower or Wet Unit" on page 259 and "5.2.3.9.4. Wet Cooling Tower or Wet Unit"

on page 404.)

▪ Air Cooled Condenser: The air cooled condenser utilizes the sensible heating of

atmospheric air passed across finned-tube heat exchangers to reject heat. (See

"5.2.2.9.2. Air Cooled Condenser or Dry Unit" on page 255 and "5.2.3.9.3. Air

Cooled Condenser or Dry Unit" on page 401.)

▪ Hybrid Cooling System: A hybrid cooling system consists of both wet and dry

cooling units and uses a dry cooling unit as the primary cooling system and a wet

cooling system just during the summer or a peak period, thereby reducing water

consumption. This option is not compatible with the chemical looping CO2

capture technology. (See "5.2.2.9.1. Hybrid Cooling System" on page 253 and

"5.2.3.9.2. Hybrid Cooling System" on page 400.)

◦ Wastewater:

▪ Ash Pond: (This is the default.) Bottom ash is sluiced with water and transported

to a bottom ash pond. (See "5.2.2.10. By-Prod. Mgmt" on page 264.)

▪ Chemical Treatment: A chemical treatment system is used to remove pollutants

from the wastewater. (See "5.2.2.10. By-Prod. Mgmt" on page 264.)

▪ Mechanical Treatment: A vapor compression evaporation (VCE) system is used

to remove pollutants from the wastewater. (See "5.2.2.10. By-Prod. Mgmt" on

page 264.)

◦ Flyash Disposal: This configuration setting determines how flyash is disposed. Fly

ash collected from a particulate removal system is typically combined with other solid

waste streams if other waste streams exist. The waste disposal option has little effect

on the rest of the IECM. The choices are:

▪ No Mixing: This is the default. The flyash is disposed separately. (See

"5.2.2.10. By-Prod. Mgmt" on page 264.)

▪ Mixed w/FGD Wastes: This option disposes flyash with FGD wastes. It is only

available if a wet FGD and some form of particulate control are configured. (See


▪ Mixed w/ Bottom Ash: This option disposes flyash with bottom ash (e.g., in the

pond). It is only available if some form of particulate control is configured. (See



5.2.1.2. Plant Location

This screen is the same for all plant types.

The plant location is used to provide some default cost multipliers, which may be viewed and

modified in detail in the overall plant parameters. (See "5.2.2.1.3. Region-Specific Cost Factors" on

page 117.)

This screen contains a single parameter, the plant location. It is a menu which has the following

options:

• US Midwest Region: This is the default. It includes the following US states:

◦ Iowa (IA)

◦ Illinois (IL)

◦ Indiana (IN)

◦ Kentucky (KY)

◦ Michigan (MI)

◦ Minnesota (MN)

◦ Missouri (MO)

◦ North Dakota (ND)

◦ Nebraska (NE)

◦ Ohio (OH)

◦ South Dakota (SD)

◦ Wisconsin (WI)

◦ West Virginia (WV)

• US Northeast Region: This region includes the following US states:

◦ Connecticut (CT)

◦ Delaware (DE)

◦ Massachusetts (MA)

◦ Maryland (MD)

◦ Maine (ME)

◦ New Jersey (NJ)

◦ New York (NY)

◦ Pennsylvania (PA)

◦ Vermont (VT)

• US Northwest Region: This region includes the following US states:

◦ Idaho (ID)

◦ Montana (MT)

◦ Oregon (OR)

◦ Washington (WA)


◦ Wyoming (WY)

• US South Central Region: This region includes the following US states:

◦ Arkansas (AR)

◦ Kansas (KS)

◦ Louisiana (LA)

◦ Oklahoma (OK)

◦ Texas (TX)

• US Southeast Region: This region includes the following US states:

◦ Alabama (AL)

◦ Florida (FL)

◦ Georgia (GA)

◦ Mississippi (MS)

◦ North Carolina (NC)

◦ South Carolina (SC)

◦ Tennessee (TN)

◦ Virginia (VA)

• US Southwest Region: This region includes the following US states:

◦ Arizona (AZ)

◦ California (CA)

◦ Colorado (CO)

◦ New Mexico (NM)

◦ Nevada (NV)

◦ Utah (UT)

• Other: This includes any location not explicitly listed above. The cost multipliers will all

be set to 1.0, as the IECM does not include data for them. You may provide your own

multipliers in the overall plant parameters, as described in "5.2.2.1.3. Region-Specific Cost

Factors" on page 117.

5.2.1.3. Unit Systems

This screen allows you to choose the unit systems used in displaying parameters and results See

"4.2.1.3. The "Unit Systems" Screen" on page 51 for more details.

5.2.2. SET PARAMETERS

5.2.2.1. Overall Plant

The input parameter screens described in the following sections are available when "Pulverized Coal

(PC)" is selected as the plant type from the "New Session" pull down menu. These screens apply to

the power plant as a whole, not to specific technologies.


5.2.2.1.1. Diagram

This Diagram appears in the "SET PARAMETERS" and "GET RESULTS" program areas. The

screen displays the plant configuration settings on the left side of the page and a diagram of the

configured plant on the right of the page. No input parameters or results are displayed on this

screen.

5.2.2.1.2. Performance

The parameters available on this screen establish the plant availability, electrical requirements,

and ambient conditions for the power plant. These parameters have a major impact on the

performance and costs of each of the individual technologies.

• Gross Electrical Output: This is the gross output of the generator(s) in megawatts

(MWg). The value does not include auxiliary power requirements. The model uses this

information to calculate key mass flow rates. The value here is shown for reference only.

Illustration 147: PC: SET PARAMETERS: Overall Plant: Diagram

Illustration 148: Combustion Overall Plant - Performance Input Screen


The value can be changed for a combustion plant by navigating to the "Base Plant

Performance" input screen, described in "5.2.2.3.3. Base Plant Performance" on page

132.

• Capacity Factor: This is an annual average value, representing the percent of equivalent

full load operation during a year. The capacity factor is used to calculate annual average

emissions and materials flows.

• Ambient Air Temperature (Dry Bulb Average): This is the inlet temperature of the

ambient combustion air prior to entering the preheater. The model presumes an annual

average temperature. Inlet air temperature affects the boiler energy balance and

efficiency. It provides a reference point for the calculation of pressure throughout the

system. Currently, the model cannot have temperatures below 15ºF or above 100ºF.

• Ambient Air Pressure (Average): This is the absolute pressure of the air inlet stream to

the boiler. The air pressure is used to convert flue gas molar flow rates to volume flow

rates.

• Relative Humidity: This is the relative humidity of the inlet combustion air.

• Ambient Air Humidity (Average): This is the water content of the inlet combustion air.

This value is used in calculating the total water vapor content of the flue gas stream. The

value is referred to as the specific humidity ratio, expressed as a ratio of the water mass

to the dry air mass. It is calculated based on the temperature, pressure and relative

humidity specified above and is shown here for reference only.

• Water Life Cycle Assessment Enabled?: This allows you to disable water life cycle

assessment if you are not interested in it. It is enabled by default. See "5.2.2.11. Water

Life Cycle Assessment" on page 270 for a list of parameters and "5.2.3.12. Water Life

Cycle Assessment" on page 419 for a list of results controlled by this option.

5.2.2.1.3. Region-Specific Cost Factors

This screen is the same for all plant types.

The first parameter, "Plant Location" is also available in the "CONFIGURE SESSION" program

area and is described in "5.2.1.2. Plant Location" on page 114.

Illustration 149: Region-Specific Cost Factors


The following capital cost multipliers are based on the plant location. You may override the

calculated values if you wish to change them:

• Construction Equipment Cost: This parameter measures the ratio of local construction

equipment cost to default construction equipment cost.

• Construction Materials Cost: This parameter measures the ratio of local construction

materials cost to default construction material cost.

• Construction Labor Cost: This parameter measures the ratio of local construction labor

cost to default construction labor cost.

• Construction Labor Requirement: This parameter measures the ratio of local labor

need to default labor need.

• Seismicity Factor: This parameter measures the ratio of local seismicity to default

seismicity, which is applied to the construction equipment and materials.

5.2.2.1.4. Regulations & Taxes

This screen accepts input for the allowable emission limits for sulfur dioxide, nitrogen oxides and

particulate matter. Mercury and carbon dioxide are constrained by their removal efficiencies

across the entire plant.

The default values for the calculated inputs reflect current United States New Source

Performance Standards (NSPS), which are applicable to all units constructed since 1978. SO2

emission limits are based on the NSPS limits that are a function of the sulfur content of the coal.

The emission constraints determine the removal efficiencies of control systems for SO2, NOx, and

particulate matter required to comply with the specified emission constraints. As discussed later,

however, user-specified values for control technology performance may cause the plant to over-

comply or under-comply with the emission constraints specified in this screen. Each emission

constraint is described briefly below.

• Sulfur Dioxide Emission Constraint: The emission constraint is defined by the 1979

revised NSPS. The calculated value is determined by the potential emission of the raw

coal, minus the amount of sulfur retained in the ash streams. The emission limit is

dependent on the fuel type and is used to determine the removal efficiency of SOx

control systems.

Illustration 150: PC: SET PARAMETERS: Overall Plant: Regulations & Taxes


• Nitrogen Oxide Emission Constraint: The combined emissions of NO2 and NO3 of

present power plants are constrained by NSPS standards. The limit is a function of the

coal rank and fuel type and is used to determine the removal efficiency of NOx control

systems.

• Particulate Emission Constraint: The emission constraint of the total suspended

particulates is defined by the NSPS standards of 1978. The limit is a function of the fuel

type and is used to determine the removal efficiency of particulate control systems.

• Total Mercury Removal Efficiency: This is the overall removal of mercury, including

all forms, from the entire power plant. It is used to determine the particular removals in

other technologies.

• Total CO2 Removal Efficiency: This is the overall CO2 capture efficiency required to

meet the emission standard.

This screen also allows the user to enter the taxes on emissions in dollars per ton. The final costs

determined from these inputs are available in the Stack results section of the IECM. (See

"5.2.3.11.3. Emission Taxes" on page 419.) The costs are added to the overall plant cost, not a

particular technology. The following taxes on emissions may be specified:

• Sulfur Dioxide (SO2): The user may enter a cost to the plant of emitting sulfur dioxide

in dollars per ton.

• Nitrogen Oxide (equiv. NOx): The user may enter a cost to the plant of emitting

nitrogen oxide in dollars per ton.

• Carbon Dioxide (CO2): The user may enter a cost to the plant of emitting carbon

dioxide in dollars per ton.


5.2.2.1.5. Financing & Cost Year

Inputs for the financing costs of the base plant itself are entered on this input screen:

This screen describes the factors required to determine the carrying charge for all capital

investments. The carrying charge is defined as the revenue required for the capital investment.

The total charge can also be expressed as a levelized cost factor or fixed charge factor. The fixed

charge factor is a function of many items. The fixed charge factor can be specified directly or

calculated from the other input quantities below it on the financial input screen.

Each parameter is described briefly below.

• Year Costs Reported: This is the year in which all costs are given or displayed, both in

the input screens and the results. A cost index is used by the IECM to scale all costs to

the cost year specified by this parameter. The cost year is reported on every input and

result screen associated with costs throughout the interface.

• Constant or Current Dollars: Constant dollar analysis does not include the effect of

inflation, although real escalation is included. Current dollar analysis includes inflation

and real escalation. This choice allows you to choose the mode of analysis for the entire

IECM economics. The cost basis is reported on every input and result screen associated

with costs throughout the interface.

• Discount Rate (Before Taxes): This is also known as the cost of money. Discount rate

(before taxes) is equal to the sum of return on debt plus return on equity and is the time

value of money used in before-tax present worth arithmetic (i.e., levelization).

• Fixed Charge Factor (FCF): The fixed charge factor is one of the most important

parameters in the IECM. It determines the revenue required to finance the power plant

based on the capital expenditures. Put another way, it is a levelized factor which

Illustration 151: PC: SET PARAMETERS: Overall Plant: Financing & Cost

Year


accounts for the revenue per dollar of total plant cost that must be collected from

customers in order to pay the carrying charges on that capital investment.

One may specify a fixed charge factor, or fill in the following inputs and the model will calculate

the FCF based on them:

• Inflation Rate: (This parameter is only visible when current dollars are selected.) This is

the rise in price levels caused by an increase in the available currency and credit without

a proportionate increase in available goods or services. It does not include real

escalation.

• Plant or Project Book Life: This is the years of service expected from a capital

investment. It is also the period over which an investment is recovered through book

depreciation.

• Real Bond Interest Rate: This is a debt security associated with a loan or mortgage. It

is the most secure form of security but the lowest in its return.

• Real Preferred Stock Return: This equity security is the second most speculative type

and pays the second highest rate of return. The holder of the stock is a part owner of the

company.

• Real Common Stock Return: This is the most speculative type of equity security sold

by a utility and pays the highest relative return. The holder of the stock is a part owner of

the company.

• Percent Debt: This is the percent of the total capitalization that is associated with debt

money. This includes loans and mortgage bonds.

• Percent Equity (Preferred Stock): This is the percent of the total capitalization that is

associated with the sale of preferred stock.

• Percent Equity (Common Stock): This value is the remainder of the capitalization,

calculated as 100% minus the percent debt, minus the percent equity in preferred stock.

• Federal Tax Rate: This is the federal tax rate. It is used to calculate the amount of taxes

paid and deferred.

• State Tax Rate: This is the state tax rate. It is used to calculate the amount of taxes paid

and deferred.

• Property Tax Rate: The property tax rate, or ad valorem, is used to calculate the

carrying charge.

• Investment Tax Credit: This is an immediate reduction in income taxes equal to a

percentage of the installed cost of a new capital investment. It is zero by default. It is

used to set the initial balance and the book depreciation.


5.2.2.1.6. Fuel & Land Cost

This screen allows you to specify values related to the fuel and land use costs for the overall

plant. It is available for all plant types:

The parameters are:

• Fuel Cost

◦ As-Delivered Coal Cost: (Not shown for NGCC plants.) This is the total cost of

delivered coal on a wet ton basis in dollars per ton. It is assumed to contain any

costs of cleaning and transportation. This parameter is also shown on the fuel cost

input screen, described in "5.2.2.2.5. Cost" on page 130; any changes you make will

be reflected in both places.

◦ Natural Gas Cost (PC) or Auxiliary Gas Cost (IGCC): Natural gas is an auxiliary

fuel used as an option for the combustion NOx control and the amine CO2 capture

configurations. This is the cost of natural gas in units of $/mscf. This parameter is

also shown on the fuel cost input screen, described in "5.2.2.2.5. Cost" on page 130;

any changes you make will be reflected in both places.

◦ Real Escalation Rate (fuel) (%/yr): This is the annual rate of increase of an

expenditure due to factors such as resource depletion, increased demand, and

improvements in design, manufacturing or construction techniques (negative rate).

The real escalation rate does not include inflation.

• Internal Cost of Electricity for Component Allocations: This is a menu that

determines the method for determining electricity costs within the power plant. The

selection of this menu determines the actual internal electricity price on the next line.

The options are:

◦ Base Plant: The base plant for the PC model is assumed to be a coal pile,

combustion boiler, air preheater, and disposal sites.

◦ User-Specified

◦ Total Plant COE

• Internal Electricity Price: This is the price of electricity. If "User-Specified" is chosen

on the line above, you may specify the cost of electricity here; otherwise this value is

calculated and provided for reference purposes only.

Illustration 152: PC: SET PARAMETERS: Overall Plant: Fuel & Land Cost


• Land Cost

◦ Land Use Cost: This parameter measures the cost of the land area required for

power plants.

◦ Total Land Requirement: This is the total amount of land required for the plant,

normalized by MWg.

5.2.2.1.7. Capital Cost

This screen allows you to specify capital costs that affect the overall plant. It is the same for all

plant types:

The parameters are:

• Construction Time: This is the idealized construction period in years. It is used to

determine the allowance for funds used during construction (AFUDC). The construction

time for individual technologies will be set to this number by default. (See

"5.1.1.1. Capital Cost Inputs" on page 90.)

• Financing Cost: This parameter covers the cost of securing financing (e.g., fees and

closing costs).

• Other Owner's Costs: This parameter measures an additional lumped cost, including

preliminary feasibility studies, economic development, construction and/or improvement

of roads and/or railroad spurs outside of site boundary, legal fees, permitting costs,

owner’s engineering, and owner’s contingency. This parameter is site and owner

specific.

5.2.2.1.8. O&M Cost

This screen combines the variable O&M unit costs from all the model components and places

them in one spot. These values will also appear in the technology input screens where they are

actually used. Values changed on this screen will reflect exactly the same change everywhere else

Illustration 153: PC: SET PARAMETERS: Overall Plant: Capital Cost


they appear. O&M costs are typically expressed on an average annual basis and are provided in

either constant or current dollars for a specified year, as shown on the bottom of the screen.

The following costs may be specified:

• Activated Carbon Cost: This is the cost of activated carbon in dollars per ton.

• Alum Cost: This is the cost of alum in dollars per ton.

• Ammonia Cost: This is the cost of ammonia in dollars per ton.

• Caustic (NaOH) Cost: This is the cost of caustic (NaOH) gas in dollars per ton.

• Dibasic Acid Cost: This is the cost of dibasic acid in dollars per ton.

• Flocculant Polymer Cost: This is the cost of flocculant polymer in dollars per ton.

• Lime Cost: This is the cost of lime in dollars per ton.

• Limestone Cost: This is the cost of limestone in dollars per ton.

• MEA/Amines Cost: This is the cost of MEA in dollars per ton.

• SCR Catalyst Cost: This is the cost of SCR catalyst in dollars per cubic foot.

• Urea Cost: This is the cost of urea in dollars per ton.

• Water Cost: This is the cost of water in dollars per thousand gallons.

• Hydrated Lime Cost: This is the cost of hydrated lime in dollars per ton.

• Taxes & Insurance: This is the cost of taxes and insurance. This parameter is included

as fixed O&M costs and is estimated empirically as a percent of the TPC.

• Operating Labor Rate: This is the hourly cost of labor. This same value is used

throughout the individual technologies. (See "5.1.1.5. O&M Cost Inputs" on page 97.)

Illustration 154: PC: SET PARAMETERS: Overall Plant: O&M Cost


• Real Escalation Rate (for all above) (%/yr): This is the annual rate of increase of an


improvements in design, manufacturing or construction techniques (negative rate). The

real escalation rate does not include inflation.

5.2.2.1.9. Reference Plant

This screen is only available when some form of CO2 capture is selected on the plant design

screen. (See "5.2.1.1. Plant Design" on page 107.) It is the same for all plant types:

The following reference plant inputs are specified to determine the cost of CO2 avoided. The

default value is zero for both parameters, requiring the user to specify the actual reference plant

values. Reference values can be obtained by simulating the same plant configuration without CO2

capture. The reference plant parameters required are:

• CO2 Emission Rate: This is the emission rate for the reference power plant (without

CO2 capture).

• Cost of Electricity: This is the cost of electricity for the reference power plant (without

CO2 capture).

5.2.2.2. Fuel

The screens associated with the Fuel Technology Navigation Tab display and define the composition

and cost of the fuels used in the plant. Default properties of fuels are provided, but user-specified

properties can also be easily substituted.

The combustion model currently supports the use of pulverized coal in the furnace, with natural gas

available as a reburn option to the in-furnace NOx controls and an optional natural gas auxiliary

boiler. The coal and natural gas properties can be modified. Coal properties may also be stored in

and retrieved from databases.

Illustration 155: PC: SET PARAMETERS: Overall Plant: Reference Plant


5.2.2.2.1. Coal Properties

This screen allows you to select a coal and modify its properties:

The default coal is Appalachian Medium Sulfur. You may look up and/or save coals in a database

as described in "4.3.3.4. The Database Button" on page 67. Or, if you prefer, you may enter or

edit the properties directly on this screen.

The following information is displayed at the top of the screen to help identify the coal:

• Coal Name: This is the name of the fuel, it may be the trade name or a unique identifier

supplied by the user.

• Coal Rank: The rank of a coal refers to the degree of coalification endured by the

organic matter. It is estimated by measuring the moisture content, specific energy,

reflectance of vitrinite or volatile matter (these are known as rank parameters).

• Coal Source: The model provides the values for default fuel properties, these can be

used "as is" or modified and used. Modified fuels maybe stored in a new database or an

existing database. Source displays the database file from which the data was retrieved, or

indicates that the data has been entered by the user.

Next, the coal properties are displayed. See "5.1.2.1. Coal Properties" on page 100 for a

description of the coal properties that may be edited on this screen. The total percentage of all the

components, highlighted in yellow, is provided for reference.

The default cost is also shown here, below the coal properties. This is the total as-delivered cost

of the coal on a wet basis. A default value is provided for the default coals provided in the model.

This value can be updated on this input screen or the fuel cost screen.

At the bottom of the screen, there is a warning that uncertainty on this screen should only be used

for batch processing. (See "4.3.3.3.13. Batch Processing" on page 66 for a description of batch

Illustration 156: PC: SET PARAMETERS: Fuel: Coal Properties


processing.) Varying the components independently does not make sense - if one percentage is

higher, another percentage will need to be lower to keep the total at 100%.


This screen allows you to specify the ash properties of the coal specified on the previous screen

("5.2.2.2.1. Coal Properties" on page 126):

This screen displays the oxide content of the ash in coal on a percent of total ash basis. The ash

content is used to determine the resistivity of the ash. This, in turn, determines the specific

collection area (SCA) of the cold-side ESP. The editable ash properties are described in

"5.1.2.1.1. Ash Properties" on page 100.

There are two additional values displayed, highlighted in yellow, beneath the ash properties

referenced above:

• Other: If the percentages above add up to less than 100%, it is assumed that the ash

includes some other component(s) that are not listed. This is the percentage of other

component(s) required to bring the total up to 100%.

• Total: This is the total percentage of all components. It should always be 100%.

As with the coal properties, it does not make sense to vary component percentages independently

on this screen. See "4.3.3.3.13. Batch Processing" on page 66 for information on how to use batch

processing to vary them together.

Illustration 157: PC: SET PARAMETERS: Fuel: Ash Properties


5.2.2.2.3. Auxiliary Gas

Auxiliary natural gas may be used in PC plant configurations that include CO2 Capture with an

Auxiliary Natural Gas Boiler or In-Furnace NOx Control with Gas Reburn. This screen allows

you to edit the natural gas properties:

Inputs include the natural gas properties described in "5.1.2.2. Natural Gas Properties" on page

101. The first input, "Higher Heating Value", is calculated from the other properties and cannot be

changed by the user. The following input is also provided below the other properties:

• Natural Gas Density: The natural gas density is a weighted average of the individual

densities of the natural gas constituents. This value is used in many unit conversion

operations.

The default natural gas is a common Pennsylvania natural gas.

As with the other fuel properties, it does not make sense to vary component percentages

independently on this screen. See "4.3.3.3.13. Batch Processing" on page 66 for information on

how to use batch processing to vary them together.

Illustration 158: PC: SET PARAMETERS: Fuel: Auxiliary Gas


5.2.2.2.4. Mercury

The concentration of mercury in the as-fired coal and speciation of mercury after combustion are

entered on the Mercury input screen:

Each parameter is described briefly below:

• Concentration on a Dry Basis: Trace elements found in fuels are typically measured

and reported as a mass concentration given on a dry basis. The IECM uses this

concentration in conjunction with the fuel flow rate and fuel moisture to determine the

mass flow rate. Currently Mercury is the only trace species tracked in the IECM.

◦ Mercury in Coal (elemental): This input parameter specifies the mass

concentration of total mercury in the coal given on a dry basis. The mercury

concentration should be given on an elemental basis, not on a mercury compound

basis. The default value is a function of the coal rank.

◦ Mercury in Auxiliary Gas (elemental): This input parameter specifies the mass

concentration of total mercury in the natural gas. The mercury concentration should

be given on an elemental basis, not on a mercury compound basis.

• Mercury Speciation: Once the fuel is combusted, the mercury can be identified in

primarily two chemical states: elemental (Hg0) and oxidized (Hg+2). Although mercury

can alternatively be reported as particulate or gas phase, the IECM assumes Mercury is

reported on an elemental and oxidized basis.

◦ Elemental: This is the percent of total mercury that is in an elemental state (Hg0)

after combustion. Elemental mercury is typically unreactive and passes through a

power plant. The default value is a function of the coal rank.

◦ Oxidized: This is the percent of total mercury that is in an oxidized state (Hg+2)

after combustion. Oxidized mercury is very reactive and typically forms mercury

compounds. The default value is a function of the coal rank.

◦ Particulate: This parameter is not currently used in the IECM. Its value is set to

force the sum of the speciation types to be 100%.

Illustration 159: PC: SET PARAMETERS: Fuel: Mercury


5.2.2.2.5. Cost

The coal and auxiliary natural gas costs are accessed on this screen:


• Coal Costs: Coal is the primary fuel for the combustion plant type. The costs associated

with the coal have been simplified and contain only the total as-fired cost.

◦ Total Delivered Cost (as-fired): This is the total cost of delivered coal on a wet ton

basis in dollars per ton. It is assumed to contain any costs of cleaning and

transportation. The total cost in units of $/ton is by default the value shown on the

coal properties screen.

◦ Total Delivered Cost (as-fired): This is also provided in units of $/MBtu. This

value cannot be edited. It is based on the value given above in units of $/ton.

• Auxiliary Gas Costs: Natural gas is an auxiliary fuel used as an option for the

combustion NOx control and some CO2 capture configurations.

◦ Auxiliary Gas Cost: This is the cost of natural gas in units of $/mscf.

◦ Auxiliary Gas Cost: This is also provided in units of $/MBtu. This value cannot be

edited.

5.2.2.3. Base Plant

The Base Plant Technology Navigation Tab screens display and define the performance and costs

directly associated with the combustion power plant, particularly the boiler. Pre-combustion and

post-combustion control technologies are not considered part of the Base Plant. The screens

described in this chapter all apply to the Pulverized Coal (PC) plant type.

Illustration 160: PC: SET PARAMETERS: Fuel: Cost


5.2.2.3.1. Boiler Diagram

This screen gives an overview of the flows entering and exiting the boiler. It does not contain any

numbers and is strictly for reference:

5.2.2.3.2. Air Preheater Diagram

This screen gives an overview of the flows entering and exiting the air preheater. It does not

contain any numbers and is strictly for reference:

Illustration 161: PC: SET PARAMETERS: Base

Plant: Boiler Diagram


Plant: Air Preheater Diagram


5.2.2.3.3. Base Plant Performance

Inputs for the major flow rates and concentrations of the gas and solids streams are entered on

this screen:

The first seven inputs are highlighted in blue. Each parameter is described briefly below:

• Gross Electrical Output: This is the gross output of the generator in megawatts


information to calculate key mass flow rates.

• Unit Type: This is the type of steam turbine system being used. The possible selections

are: Sub-Critical, Super-Critical, and Ultra- Supercritical. This selection determines the

steam cycle heat rate default value.

• Steam Cycle Heat Rate: This is the gross amount of energy in steam needed to produce

a kilowatt-hour (kWh) of electricity at the generator. This variable does not consider

auxiliary power requirements. This heat rate, plus the boiler efficiency, is used to figure

out the overall plant performance (i.e., the gross cycle heat rate).

• Boiler Firing Type: Combination boilers are most often represented by three types:

Wall, Tangential, and Cyclone. The Wall category is the most general and represents

variations such as opposed, top, cell, and others. The selection of boiler type affects the

boiler efficiency and furnace emission factors.

• Boiler Efficiency: This is the percentage of fuel input energy transferred to steam in the

boiler. The model default is to calculate the boiler efficiency using standard algorithms

described in the literature. The efficiency is a function of energy losses due to inefficient

heat transfer across the preheater, latent heat of evaporation, incomplete combustion,

radiation losses, and unaccounted losses.

Illustration 163: PC: SET PARAMETERS: Base Plant: Base Plant Performance


• Excess Air for Furnace: This is the excess theoretical air used for combustion. It is

added to the stoichiometric air requirement calculated by the model. The value is

calculated and based on the fuel type and boiler type.

• Leakage Air at Preheater: This is the additional excess air introduced because of

leakage into the system at or beyond the air preheater. It is based on the stoichiometric

air required for combustion. The leakage air increases the total gas volume downstream

of the air preheater.

• Gas Temperature Exiting Economizer: This is the temperature of the flue gas exiting

the economizer. The temperature is used in the calculation of the flue gas volume and air

preheater performance.

• Gas Temperature Exiting Air Preheater: This is the temperature of the flue gas exiting

the air preheater. The temperature is used in the calculation of the flue gas volume and

air preheater performance.

• Percent Water in Bottom Ash Sluice: Bottom ash collected can be removed from the

combustion boiler and disposed by sluicing the bottom ash with water. This is the

percent water in the sluice.

• Hydrated Lime for SO3 Removal: Hydrated lime is injected for flue gas treatment at

the inlet of the air preheater to remove SO3.

• Base Plant Power Requirements: These parameters specify the electrical power

requirements of pulverizers, steam pumps, forced draft fans, cooling system equipment

(fans and pumps), and other miscellaneous equipment excluding gas cleanup systems.

These power requirements or penalties are expressed as a percent of a gross plant

capacity and are used to calculate the net plant performance.

◦ Coal Pulverizer: This is the power needed to run the coal pulverizers prior to the

coal being blown into the boiler. It is also referred to as an energy penalty to the

base plant. The value is calculated and based on the fuel type. It is expressed as a

percentage of the gross plant capacity.

◦ Steam Cycle Pumps: This is the power needed to operate the pumps in the steam

cycle. It is also referred to as an energy penalty to the base plant. It is expressed as a

percentage of the gross plant capacity.

◦ Forced/Induced Draft Fans: This is the power required for the forced draft fans

and primary air fan expressed as a percentage of the gross plant capacity. It is also

referred to as an energy penalty for the base plant.

◦ Once-Through Cooling System: (Only visible when once-through cooling is

selected.) This is the power needed to run the pumps and other equipment for the

once-through cooling system. It is expressed as a percentage of the gross plant

capacity. It is also referred to as a base plant energy penalty.

◦ Miscellaneous: This is the power used by any other miscellaneous equipment in the

base plant, not including equipment used for pollution control equipment. It is

expressed as a percentage of the gross plant capacity. It is also referred to as a base

plant energy penalty.


5.2.2.3.4. Steam Cycle Diagram

This screen gives an overview of the steam cycle. It does not contain any numbers and is strictly

for reference:

5.2.2.3.5. Steam Cycle Performance

The following parameters may be set on this screen:

• Steam Energy Added in Boiler: The heat content of the steam changes as it moves

throughout the steam turbines, reheaters, and superheaters. This parameter captures the

average heat content of the steam, taking into consideration the heat lost in the cycle.

• Boiler Blowdown (% Recirculating Water): The boiler blowdown is a percent of the

feedwater removed in order to reduce the suspended solids that have accumulated in the

cooling water system.

• Miscellaneous Steam Losses (% Primary Steam Cycle): A small amount of steam is

lost in the steam cycle.


Plant: Steam Cycle Diagram

Illustration 165: PC: SET PARAMETERS: Base Plant: Steam Cycle

Performance


• Demineralizer Underflow (% Demineralizer Inlet): The boiler makeup water is

treated in a demineralizer. This parameter determines the amount of water in the

underflow.

• Cooling Water Temperature Rise: This measures the increase in cooling water

temperature after the once-through cooling water removes thermal energy from the

exhaust steam. (This parameter is not available when an Air Cooled Condenser is

selected.)

• Auxiliary Heat Exchanger Load (% Primary Steam Cycle): The load on the auxiliary

condenser is expressed as a percentage of the load on the primary condenser. This

parameter determines the amount of recirculating cooling water used to extract heat

from the auxiliary condenser.

5.2.2.3.6. Furnace Factors

Inputs for the furnace factors that affect the major flow rates and concentrations of the gas and

solids streams are entered on the Furnace Factors input screen. This screen accepts inputs for the

flue gas and ash products emitted from the boiler into the flue gas and ash streams. Factors in

emissions include: incomplete combustion and thermodynamic equilibrium between gas species

associated with the combustion products.

This screen’s inputs are needed to calculate boiler efficiency and air pollutant emissions. The

emission of carbon, ash, sulfur and nitrogen are specified by the United States Government’s

Environmental Protection Agency’s (EPA) compilation of emission factors. Also included from

the compilation are the incomplete transfer percentages of solid and gaseous forms of these

substances.

This screen is available for all plant configurations.


• Percent Ash Entering Flue Gas Stream: The default values for this parameter are a

function of the fuel and boiler types and are based on the AP-42 EPA emission factors.

Ash not entering the flue gas stream is assumed to be removed as bottom ash. This is

also referred to as the overhead ash fraction.

• Sulfur Retained in Flyash: This parameter gives the percent of total sulfur input to the

boiler that is retained in the flyash stream of a coal-fired power plant. The default values

are a function of the selected boiler type and the coal rank as specified by the AP-42

EPA compilation of emission factors.

Illustration 166: PC: SET PARAMETERS: Base Plant: Furnace Factors


• Percent of SOx as SO3: This parameter quantifies the sulfur species in the flue gas

stream. Sulfur not converted to SO2 is assumed to be converted to SO3. The default

value is based on emission factors derived by Southern Company1 and are a function of

the selected coal.

• Preheater SO3 Removal Efficiency: Sulfuric acid (H2SO4) is created downstream of the

boiler by the reaction of SO3 with H2O. A percent of the sulfuric acid is condensed on

particulates in the preheater and removed from the flue gas. This parameter specifies the

amount of SO3 removed from the flue gas in the preheater as a function of the coal rank.

The default value is taken from the removal efficiency reported in the literature

(references are below). This efficiency then determines the mass of SO3 removed from

the flue gas in the collector. For more information see also:

◦ http://www.netl.doe.gov/publications/proceedings/98/98fg/hardman.pdf

◦ http://www.netl.doe.gov/publications/proceedings/98/98fg/rubin.pdf

• Nitrogen Oxide Emission Rate: This parameter establishes the level of NOx emissions

from the boiler. The default values reflect the AP-42 EPA emission factors. It is a

function of boiler firing method and the coal rank. The model calculates this value and

expresses it in pounds of equivalent NO2 per ton of coal.

• Percent of NOx as NO: This parameter establishes the level of nitric oxide (NO) in the

flue gas stream. The remainder of the total NOx emissions is assumed to be nitrogen

dioxide (NO2). The default parameters reflect the AP-42 EPA emission factors and are

dependent on the fuel type.

• Concentration of Carbon in Collected Ash: This parameter accounts for retention of

carbon in the fly ash and bottom ash. The amount of carbon in the collected ash streams

is typically known. It is used to calculate the total unburned carbon in coal, boiler

efficiency and flue gas composition.

• Percent of Burned Carbon as CO: This parameter accounts for any incomplete

combustion in the furnace, and is used to calculate boiler efficiency and flue gas

composition. The remainder is assumed to be CO2 or unburned carbon.


This is a standard capital cost input screen as described in "5.1.1.1. Capital Cost Inputs" on page

90.

1 Hardman, R., R. Stacy, et al. (1998). Estimating Total Sulfuric Acid Emissions from Coal-Fired Power

Plants, Southern Company Services.

http://www.netl.doe.gov/publications/proceedings/98/98fg/hardman.pdf

http://www.netl.doe.gov/publications/proceedings/98/98fg/rubin.pdf


5.2.2.3.8. O&M Cost

Inputs for the operation and maintenance costs of the Combustion (Boiler) base plant itself are

entered on the O&M Cost input screen:

The base plant considers a more detailed breakdown for the costs associated with the fuel.

Together they characterize the fuel costs. The following inputs are included at the top of the

screen:

• As-Delivered Coal Cost: This is the cost of the delivered coal in dollars per wet ton.

The value is calculated by the IECM from the particular regional coal selected. It does

not include any cleaning costs.

• Waste Disposal Cost: This is the bottom ash disposal cost for the base plant.

• Water Cost: This is the cost of water used for the base plant.

• Hydrated Lime Cost: This is the cost of hydrated lime used by the base plant.

The remainder of the screen is described in "5.1.1.5. O&M Cost Inputs" on page 97.

Illustration 167: PC: SET PARAMETERS: Base Plant: O&M Cost


5.2.2.3.9. Retrofit or Adjustment Factors

Inputs for the capital costs of modifications to process areas of the base plant itself are entered on

this screen:

See "5.1.1.8. Retrofit or Adjustment Factor Inputs" on page 100 for an explanation of retrofit

costs. The base plant has the following capital cost process areas:

• Steam Generator: This area accounts for the steam cycle equipment and pumps.

• Turbine Island: This area accounts for the turbine island and associated pumps.

• Coal Handling: This area accounts for the mechanical collection and transport

equipment of coal in the plant.

• Ash Handling: This area accounts for the mechanical collection and transport of ash in

the plant.

• Water Treatment: This area accounts for the pumps, tanks, and transport equipment

used for water treatment.

• Auxiliaries: Any miscellaneous auxiliary equipment is treated in this process area.

5.2.2.4. NOx Control

The "NOx Control" Technology Navigation Tab contains screens that address combustion or post-

combustion air pollution technologies for Nitrogen Oxides. If you have selected both In-Furnace

Controls and a Hot-Side SCR for NOx control, you may switch between the two sets of screens that

configure these technologies by using the "Process Type" pull-down menu at the bottom of the

screen.

5.2.2.4.1. In-Furnace Controls

These screens are available if the In-Furnace Controls for the PC plant type configurations have

been selected for NOx control under Combustion Controls. If you have selected both In-Furnace

Controls and a Hot-Side SCR for NOx control, these screens will be displayed under the "In-

Furnace Controls" process type; otherwise, these screens will be displayed directly under the

"NOx Control" technology. (See "4.1.4.4.2.3. Process Types" on page 38.)

Illustration 168: PC: SET PARAMETERS: Base Plant: Retrofit or Adjustment

Factors


5.2.2.4.1.1. In-Furnace Controls Diagram

This diagram gives an overview of the in-furnace controls. It will vary slightly depending on

the options chosen on the next screen, "Config". This diagram does not contain any numbers

and is strictly for reference:

5.2.2.4.1.2. Config

Inputs for configuring the In-Furnace NOx Control technology are entered on this screen:


• In-Furnace Controls: This pull-down menu chooses what type of in-furnace NOx

controls are used. These technologies reduce NOx between the primary fuel injection

into the furnace and the economizer. These can be used in addition to the SCR:

◦ LNB: (This is the default.) Low NOx burners are a combustion NOx control.

These burners replace the upper coal nozzle of the standard two-nozzle cell

burner with a secondary air port. The lower burner coal nozzle is enlarged to the

same fuel input capacity as the two standard coal nozzles. The LNB operates on

the principle of staged combustion to reduce NOx emissions. Approximately 70%

of the total air (primary, secondary, and excess air) is supplied through or around

the coal-feed nozzle. The remainder of the air is directed to the upper port of each

cell to complete the combustion process. The fuel-bound nitrogen compounds are

converted to nitrogen gas, and the reduced flame temperature minimizes the

formation of thermal NOx. The net effect of this technology is greater than 50%

Illustration 169: PC: SET PARAMETERS: NOx

Control: In-Furnace Controls: In-Furnace

Controls Diagram

Illustration 170: PC: SET PARAMETERS: NOx Control: In-Furnace Controls:

Config


reduction in NOx formation with no boiler pressure part changes and no impact

on boiler operation or performance.

◦ LNB & OFA: Low NOx burners (see above) with overfire air is another

combustion NOx reduction method. Overfire air is an enhancement to LNB to

reduce NOx formation by further separating the air injection locations. An

addition of approximately 10% NOx is reduced by the addition of OFA. A portion

of the secondary air used by LNB is diverted to injection ports located above the

primary combustion zone, reducing available oxygen in the primary combustion

zone. Overfire air in the IECM refers to separated OFA for both wall and

tangential-fired boilers.

◦ Gas Reburn: Gas reburn is a post-combustion NOx reduction method. Gas

reburn substitutes up to one-fourth of the heat input of coal with natural gas,

reducing the NOx up to 60% as a function of the amount of reburn. The natural

gas is injected above the primary combustion zone to create a reducing zone.

Reburn has been shown to be effective for wall and tangential-fired boilers and

more recently for cyclone boilers.

◦ SNCR: Selective non-catalytic reduction is a post-combustion NOx reduction

method. This process removes NOx from flue gas by injecting one of two

nitrogen-based reagents, ammonia or urea, in the presence of oxygen to form

nitrogen and water vapor. Optimum removal is achieved in a temperature

window of 1600-2000 F. Although the technology is very simple, the narrow

temperature window provides the primary challenge. Ammonia slip and ash

contamination are additional concerns that must be considered with SNCR.

◦ LNB & SNCR: Low NOx burners can be used in conjunction with SNCR to

achieve very high NOx removals. Both technologies are described in detail above.

• SNCR Reagent Type: This parameter is only displayed when SNCR or

LNB & SNCR have been selected in the In-Furnace Controls pull-down menu.

Nitrogen-based reagent injection is used in an SNCR to reduce NOx in the presence of

oxygen to form nitrogen and water vapor. The reagent choices are:

◦ Urea: (This is the default.) Urea (CO(NH2)2) is typically diluted to a 15-20%

concentration with water. Urea has the advantage of safety and ease of storage

and handling.

◦ Ammonia: Ammonia can be supplied in two forms: anhydrous (NH3) and

aqueous (NH4OH). The IECM considers only anhydrous ammonia. Ammonia

may be an advantage when using an SNCR in conjunction with an SCR system.


5.2.2.4.1.3. Performance

Inputs for the performance of the In-Furnace Controls NOx control technology are entered on

this screen:

The following parameters are available:

• Combustion NOx Controls: These inputs will display if any combustion technology

is used in the option selected in the In-Furnace Controls pull-down menu. This

includes the LNB, LNB & OFA, Gas Reburn, and the LNB & SNCR options.

◦ Actual NOx Removal Efficiency: This is the NOx removal efficiency of the

LNB, LNB & OFA, and Gas Reburn options, and the LNB removal portion of the

LNB & SNCR option. The percent reduction of NOx is calculated by comparing

the actual NOx emission to the uncontrolled NOx emission. The removal is a

function of the In-Furnace Control type selected in the pull-down menu, the

boiler type, and the maximum removal efficiency (below). Note that the removal

is not a function of the NOx emission constraint. This input is highlighted in blue.

◦ Maximum NOx Removal Efficiency: The maximum removal efficiency of NOx

sets the upper bound for the actual NOx removal efficiency (above). The

maximum removal is a function of the In-Furnace control type and the boiler

type.

◦ Auxiliary Gas Heat Input: This input will only display if Gas Reburn is selected

in the In-Furnace Controls pull-down menu. (It is not shown in the illustration

above.) The flow rate of natural gas injected is determined by this input on a Btu

heat input basis.

• SNCR NOx Control: These inputs will only display if SNCR or LNB & SNCR is

selected in the In-Furnace Controls pull-down menu.

◦ Actual NOx Removal Efficiency: The actual NOx removal efficiency is a

function of the maximum NOx removal efficiency (below) and the NOx emission

constraint. This input is highlighted in blue.

◦ Maximum NOx Removal Efficiency: The maximum removal efficiency is

calculated as a function of the gross electrical output. Because of difficulty

mixing the reagent in the flue gas for larger boilers, the maximum efficiency

decreases with increasing plant size.


Performance


◦ Urea Concentration Injected: Urea is typically injected as a liquid diluted by

water. This parameter defines the amount of water used to dilute the urea prior to

injection.

◦ SNCR Power Requirement: As mentioned above, the power requirement for the

SNCR is a function of gross electrical output of the power plant. The value is

determined by the need for tank heaters when urea reagent is used.

5.2.2.4.1.4. Capital Cost

Unlike most capital cost input screens, the in-furnace controls' costs are provided as total

capital costs on an energy input basis.

The Combustion Modifications inputs will not display if SNCR is not selected in the In-

Furnace Controls pull-down menu. The SNCR Boiler Modifications inputs will only display if

SNCR or LNB & SNCR is selected.

The following parameters are on this screen:

• Base Capital Costs: The base capital costs (excluding retrofit, using gross KW)

specify the total base capital costs, not considering any retrofit factors. No detailed

information about direct or indirect costs is given. The costs are given as a total in

units of dollars per gross kilowatt.

◦ Combustion Modifications: This is the base capital cost of the LNB,

LNB & OFA, and Gas Reburn options, and the LNB removal portion of the

LNB & SNCR option. This parameter is not shown when one of these options is

not selected.

◦ SNCR Boiler Modifications: This specifies the total base capital cost for the

SNCR boiler NOx removal equipment alone. This parameter is not shown when

one of the SNCR options is not selected.

• Retrofit Capital Cost Factors: Retrofit cost factors allow you to differentiate

between the base cost of purchasing the capital equipment and the actual cost


Capital Cost


incurred. These factors vary from unit to unit. See "5.1.1.8. Retrofit or Adjustment

Factor Inputs" on page 100 for more information.

◦ Combustion Modifications: This is the retrofit cost factor for the LNB,


LNB & SNCR option. This parameter is not shown when one of these options is

not selected.

◦ SNCR Boiler Modifications: This is the retrofit cost factor for the SNCR option

alone. This parameter is not shown when one of the SNCR options is not selected

• Total Capital Costs:

◦ Combustion Modifications: This is the total capital cost of the LNB,


LNB & SNCR option. This combines the base capital cost with the retrofit cost

factor. This parameter is not shown when one of these options is not selected.

◦ SNCR Boiler Modifications: This specifies the total capital cost for the SNCR

boiler NOx removal equipment alone. This parameter is not shown when one of

the SNCR options is not selected.

• %TCR Amortized: This is the percentage of the total capital required (TCR) that has

been amortized. This value is 0% for new equipment and may be set as high as 100%

for equipment that has been paid off.

5.2.2.4.1.5. O&M Cost

O&M costs are typically expressed on an average annual basis and are provided in either

constant or current dollars for a specified year, as shown on the bottom of the screen. Each

parameter is described briefly below.

• Variable O&M Costs:

◦ Urea Cost: This is the cost of urea used for any of the SNCR options. This input

will only display if SNCR or LNB & SNCR is selected.

◦ Ammonia Cost: This is the cost of ammonia used for any of the SNCR options.

This input will only display if SNCR or LNB & SNCR is selected.


O&M Cost


◦ Auxiliary Gas Cost: This is the cost of natural gas used for the Gas Reburn

option. This input will only display if Gas Reburn is selected. (It is not shown in

the illustration above.)

◦ Electricity Price (Internal): This is the price of electricity as specified on the

Overall Plant Fuel & Land Cost input screen. (See "5.2.2.1.6. Fuel & Land Cost"

on page 122.)

• Fixed O&M Cost: Fixed O&M costs are given as a total cost, rather than itemized

costs broken down by individual maintenance and labor costs. The results are given as

a percent of the total capital cost.

◦ Combustion Modifications: This is the total fixed operating and maintenance

cost for boiler NOx modifications made in the combustion zone (LNB, OFA,

natural gas reburn). This parameter is not shown if one of these options is not

selected.

◦ SNCR Boiler Modifications: This is the total fixed O&M cost for the SNCR

equipment alone. This input is not shown if one of the SNCR options is not

selected.

5.2.2.4.2. Hot-Side SCR

These input screens are available when a Hot-Side SCR has been selected. If you have selected

both In-Furnace Controls and a Hot-Side SCR for NOx control, these screens will be displayed

under the "Hot-Side SCR" process type; otherwise, these screens will be displayed directly under

the "NOx Control" technology. (See "4.1.4.4.2.3. Process Types" on page 38.)

5.2.2.4.2.1. Hot-Side SCR Diagram

This diagram gives an overview of the hot-side SCR. This diagram does not contain any


5.2.2.4.2.2. Config

Illustration 174: PC: SET PARAMETERS: NOx

Control: Hot-Side SCR: Hot-Side SCR Diagram


Inputs for configuring the Hot–Side SCR NOx Control technology are entered on the Config

input screen:


• Catalyst Replacement Scheme: Catalyst is installed in the SCR as a series of layers.

These activity or effectiveness of these layers decreases with time due to fouling and

poisoning. The layers are replaced with clean layers on a regular basis in one of two

ways: all at once or one layer at time (staggered). The selection of the replacement

scheme involves trade-offs between capital and annual costs via the initial catalyst

requirement and the replacement interval. More specifically:

◦ Each: (This is the default.) Individual Layers. Replacing individual layers

sequentially, rather than simultaneously, increases the effective catalyst life for a

given volume of catalyst, decreasing the replacement interval. This reduces the

O&M cost relative to simultaneous replacement.

◦ All: All Layers: Simultaneous replacement may lead to a smaller initial catalyst

volume to achieve the same design activity as a sequential replacement scheme.

This reduces the capital cost but increases the O&M cost.

Illustration 175: PC: SET PARAMETERS: NOx Control: Hot-Side SCR:

Config



Inputs for the performance of the Hot–Side SCR NOx control technology are entered on the on

the Performance input screen:


• Actual NOx Removal Efficiency: The actual removal efficiency is dependent on the

minimum and maximum removal efficiencies of the SCR and the emission constraint

for NOx. The model assumes a minimum removal of 50%. The actual removal is set

to match the constraint, if feasible. It is possible that the SCR may under or over

comply with the emission constraint. This input is highlighted in blue.

• Maximum NOx Removal Efficiency: This parameter specifies the maximum

efficiency possible for the absorber on an annual average basis. The value is used as a

limit in calculating the actual NOx removal efficiency for compliance.

• Particulate Removal Efficiency: The ash in the high dust gas entering the SCR

collects on the catalyst layers and causes fouling. Ash removal is not a design goal;

rather, it is a reality which is taken into consideration by this parameter.

• Number of SCR Trains: This is the total number of SCR equipment trains. It is used

primarily to calculate the capital costs. The value must be an integer.

• Number of Spare SCR Trains: This is the total number of spare SCR equipment

trains. It is used primarily to calculate capital costs. The value must be an integer.

• Number of Catalyst Layers: The total number of catalyst layers is a sum of the

dummy, initial and spares used. All catalyst layer types are of equal dimensions,

geometry, and catalyst formulation. You specify each value; the value must be an

integer. The catalyst layer types and quantities are combined with pressure drop

information to determine the auxiliary power requirements and the capital cost of the


Performance


SCR technology. A layer may be interpreted as either a full layer (e.g., typically 1

meter deep), or a half layer (e.g., typically 0.5 meters deep) to represent alternative

SCR catalyst replacement schemes. There is a limit of 8 total initial and reserve

layers. The following inputs allow you to specify the number of catalyst layers:

◦ Number of Dummy Catalyst Layers: This is the number of dummy catalyst

layers. The value must be an integer. A dummy layer corrects the flow

distribution. It is used to calculate the total pressure drop across the SCR and the

auxiliary power requirements.

◦ Number of Initial Catalyst Layers: This is the number of initial active catalyst

layers. The value must be an integer. Three layers are installed initially. It is used

to calculate the total pressure drop across the SCR and the auxiliary power

requirements.

◦ Number of Reserve Catalyst Layers: This is the number of reserve or extra

catalyst layers. These are available for later catalyst additions. The value must be

an integer. It is used to calculate the total pressure drop across the SCR and the

auxiliary power requirements.

• Catalyst Replacement Interval: This parameter calculates the operating hour

interval between catalyst replacements. The interval is determined by the decision to

replace all at once or each of them separately after each interval. Currently, the model

is not set up to replace two half layers simultaneously.

• Catalyst Space Velocity: The calculated space velocity is determined by several

factors, including many of the reference parameters in the next Section. The space

velocity is used to determine the catalyst volume required.

• Ammonia Stoichiometry: This is the molar stoichiometry ratio of ammonia to NOx

entering the SCR device. The calculated quantity is based on an assumed NOx

removal reaction stoichiometry of 1:1 for both NO and NO2, and a specified ammonia

slip. It affects the amount of ammonia used and the amount of NOx converted to

moisture.

• Steam to Ammonia Ratio: The molar ratio of steam to ammonia is used to determine

the amount of steam injected to vaporize the ammonia. The value assumes the steam

is saturated at 450 degrees Fahrenheit and the ammonia is diluted to 5 volume percent

of the injected gas.

• Steam for Soot Ratio: This is the steam required for soot blowing.

• Total Pressure Drop Across SCR: The total is determined from the individual

pressure drops due to air preheater deposits, the active catalyst layers, the dummy

catalyst layers, the ammonia injection system and the duct work. It is used to calculate

the total pressure drop across the SCR and the auxiliary power requirements.

• Oxidation of SO2 to SO3: The oxidation rate is calculated for a high sulfur catalyst

and affects the flue gas composition. It uses the space velocity and the inlet

temperature. The SO3 produced acts as an ash-conditioning agent if an ESP is used

downstream.

• Hot-Side SCR Power Requirement: The default calculation of auxiliary power is

based on the additional pressure drop, electricity to operate pumps and compressors,

and equivalent energy for steam consumed. It is expressed as a percent of the gross

plant capacity.


5.2.2.4.2.4. Performance (continued)

The Hot-Side SCR system has additional inputs for performance entered on this screen:

Many of the calculated quantities on the Performance screen are determined by the reference

parameters described below:

• Reference Parameters: The first set of reference parameters is primarily used to

determine the actual space velocity. The values are used with actual operating

conditions through a series of correction factors in the IECM. If you set the actual

space velocity displayed on the Performance screen, this set of input parameters is not

used by the IECM and does not have to be set.

◦ Space Velocity: This is the reference space velocity for a high dust system. It is

used to calculate the actual space velocity.

◦ Catalyst Replacement Interval: This is the reference operating life in hours

associated with the reference space velocity for the high dust catalyst. It is used

to calculate the actual space velocity.

◦ Ammonia Slip: Ammonia slip accounts for the ammonia passing through the

reactor unchanged and further downstream. The value is based on an 80 percent

or lower NOx removal efficiency. It is used in calculating the ammonia

stoichiometry and actual space velocity.

◦ Temperature: This is the operating temperature associated with the reference

space velocity. It is used to determine the actual space velocity.

◦ NOx Removal Efficiency: This is the NOx removal efficiency associated with the

reference design specifications for the SCR system. It is used to determine the

actual space velocity.


Performance (continued)


◦ NOx Concentration: This is the inlet NOx concentration associated with the

reference design specifications for the SCR system. It is used to determine the

actual space velocity.

• Reference Catalyst Activity: Catalyst activity decreases with operating time due to

plugging and catalyst poisoning. The loss is a complex function of the catalyst

formulation and geometry, the operating conditions associated with the flue gas,

including temperature and composition, and the loading and composition of the fly

ash. This complex function is represented by an exponential decay formula in the

IECM. The following parameters are used to determine the reference catalyst activity,

assuming the initial activity has a value of unity:

◦ Minimum Activity: The minimum activity is a lower limit for catalyst activity

decay. The actual activity approaches this value over a long period of time.

◦ Reference Time: This is the time that corresponds to a particular activity known

for the catalyst. It is used to determine a decay rate constant.

◦ Activity at Reference Time: A second activity reference point is needed to

determine the activity decay rate. The activity should correspond to the reference

time specified. It is used to determine a decay rate constant.

• Ammonia Deposition on Preheater: This is the percent of the ammonia slip that is

deposited as ammonium salts in the air preheater. It is treated like a partition

coefficient.

• Ammonia Deposition on Fly Ash: This is the percent of the ammonia slip that is

absorbed onto the fly ash. It is treated like a partition coefficient. This is important for

high dust systems.

• Ammonia in High Concentration Wash Water: The ammonia that deposits in the

air preheater is periodically removed by washing. It is initially highly concentrated

and requires denitrification pretreatment prior to regular treatment. This is the average

concentration in that stream.

• Ammonia in Low Concentration Wash Water: The ammonia that deposits in the air

preheater is periodically removed by washing. The concentration is initially high, but

gradually decreases. This is the average concentration of the low concentration

stream.

• Ammonia Removed from Wash Water: The ammonia that deposits in the air

preheater is periodically removed by washing. This is the average amount of ammonia

removed from the high and low concentrated streams.


This is a standard capital cost input screen as described in "5.1.1.1. Capital Cost Inputs" on

page 90.


5.2.2.4.2.6. O&M Cost

This is an O&M cost input screen as described in "5.1.1.5. O&M Cost Inputs" on page 97. The

Hot-Side SCR system has the following additional inputs at the top of the screen:

• Catalyst Cost: This is the cost of the catalyst used for the SCR technology.

• Ammonia Cost: This is the cost of the ammonia used for the SCR technology.

5.2.2.4.2.7. Retrofit or Adjustment Factors


costs. The Hot-Side SCR system has the following capital cost process areas:

• Reactor Housing: The reactor housing costs include carbon steel reactor vessel with

six inches of mineral wool insulation, vessel internals and supports, steam

sootblowers, reactor crane and hoist, installation, labor, foundations, structures,

piping, and electrical equipment.

Illustration 178: PC: SET PARAMETERS: NOx Control: Hot-Side SCR: O&M

Cost


Retrofit or Adjustment Factors


• Ammonia Injection: The ammonia unloading, storage, and supply system includes a

storage vessel with a seven-day capacity, an ammonia vaporizer, mixer, injection grid,

ductwork, dampers, and a truck unloading station.

• Ducts: The ductwork includes economizer bypass and outlet ducts, SCR inlet and

outlet ducts, SCR and economizer control dampers, air preheater inlet plenum,

various expansion joints in the ductwork, and air preheater cross-over ducting.

• Air Preheater Modifications: Thicker and smoother material is used for the heat

transfer surfaces in the preheater. A larger motor is provided for the heat exchanger.

High pressure steam soot blowers and water wash spray nozzles are also added.

• ID Fan Differential: The ID fans must be sized to deal with the increased flue gas

pressure drop resulting from the additional ductwork and the SCR reactor.

• Structural Support: The costs of this area are related primarily to the structural

support required for the SCR reactor housing, ductwork, and air preheater.

• Misc. Equipment: This area includes the capital costs incurred for ash handling

addition, water treatment addition, and flow modeling for a hot-side SCR system.

5.2.2.5. Mercury

Mercury Control is a Technology Navigation Tab in the Set Parameters and in the Get Results

program area. These screens define and display results for the performance and costs directly

associated with the removal of mercury from each technology in the power plant Pre-combustion

and post-combustion control technologies are all considered. Special consideration is given to flue

gas conditioning used to enhance mercury removal. Water and activated carbon injection are

currently considered as conditioning agents.

5.2.2.5.1. Activated Carbon Inj. Diagram

This diagram gives an overview of the activated carbon injection system. This diagram does

not contain any numbers and is strictly for reference:

Illustration 180: PC: SET PARAMETERS: Mercury: Activated Carbon Inj.

Diagram


5.2.2.5.2. Removal Efficiency

This screen is only available for the Combustion (Boiler) plant type. Inputs for the removal of the

speciated mercury from the flue gas stream are entered on this input screen:


• Removal Efficiency of Mercury: The removal of mercury for each control technology

configured is given as a percent of the total entering the control technology. The user is

given the opportunity to specify the removal separately for each speciation type. Control

technologies not currently configured are hidden.

◦ Furnace Removal (total): Mercury present in ash is removed from the furnace

through the removal of bottom ash. The speciation is not known, so the removal is

specified as a total removal. The mercury removed in bottom ash is not credited

toward the required removal to meet the mercury emission constraint.

• Spray Dryer (only shown when a spray dryer is configured)

◦ Spray Dryer (oxidized): Oxidized mercury is assumed to pass through the lime

spray dryer. Although soluble in water, moisture injected into the spray dryer

evaporates, resulting in the mercury remaining in the flue gas. The default value is

zero.

◦ Spray Dryer (elemental): Elemental mercury is assumed to pass through the lime

spray dryer. It is assumed that elemental mercury is present in the flue gas and is

unreactive.

◦ Spray Dryer (particulate): This is the amount of particulate mercury removed by

the spray dryer.

• Fabric Filter (only shown if a fabric filter is configured)

◦ Fabric Filter (total w/o control): Mercury present in ash is removed from the

fabric filter through the removal of captured fly ash. The speciation is not known, so

the removal is specified as a total removal. The value shown is determined without

Illustration 181: PC: SET PARAMETERS: Mercury: Removal Efficiency


regard to particular mercury control methods. It has a substantial effect on the

amount of activated carbon needed to meet the required removal of mercury.

◦ Fabric Filter (oxidized): The fabric filter typically removes some mercury without

adding a specific mercury control technology. This mercury is present in the ash and

is removed with the collected ash. When a mercury control technology is added, the

removal is enhanced. The default value is set to meet the overall removal efficiency

constraint, with consideration given to the mercury removed by flue gas

desulfurization and elemental mercury oxidized in a NOx control technology. The

lower limit is set by the removal efficiency of ash alone as specified by "Fabric

Filter (total w/o control)" specified above.

◦ Fabric Filter (elemental): Elemental mercury is assumed to be removed with the

same efficiency as the removal of oxidized mercury specified above.

• Cold-Side ESP (only shown if a cold-side ESP is configured)

◦ Cold-Side ESP (total w/o control): Mercury present in ash is removed from the

cold-side ESP through the removal of captured fly ash. The speciation is not known,

so the removal is specified as a total removal. The value shown is determined

without regard to particular mercury control methods. It has a substantial effect on

the amount of activated carbon needed to meet the required removal of mercury.

◦ Cold-Side ESP (oxidized): The cold-side ESP typically removes some mercury

without adding a specific mercury control technology. This mercury is present in the

ash and is removed with the collected ash. When a mercury control technology is

added, the removal is enhanced. The default value is set to meet the overall removal

efficiency constraint, with consideration given to the mercury removed by flue gas

desulfurization and elemental mercury oxidized in a NOx control technology. The

lower limit is set by the removal efficiency of ash alone as specified by "Cold-Side

ESP (total w/o control)" specified above.

◦ Cold-Side ESP (elemental): Elemental mercury is assumed to be removed with the

same efficiency as the removal of oxidized mercury specified above.

• Wet FGD (only shown when a wet FGD is configured)

◦ Wet FGD (oxidized): The wet lime/limestone FGD typically removes all the

oxidized mercury due to its high solubility in water.

◦ Wet FGD (elemental): Elemental mercury is assumed to pass through the wet

lime/limestone FGD. It is assumed that elemental mercury is present in the flue gas

and is unreactive.

◦ Wet FGD (particulate): This is the amount of particulate mercury removed by the

Wet FGD.

• Percent Increase in Speciation: Although NOx control technologies do not remove

mercury from the flue gas, they can change the mercury from one form to another. This

is particularly true when catalysts are present. In this case, elemental mercury is

converted to oxidized mercury. The parameters in this section define the percent increase

in oxidized mercury across the control technology.

◦ In-furnace NOx (oxidized): Low NOx burners with or without overfire air and gas

reburn can affect the amount of oxidized mercury. At present, there is insufficient

information available to specify a default value. The default is set to zero.

◦ SNCR (oxidized): An SNCR does not affect the relative amounts of oxidized and

elemental mercury. The default is set to zero.


◦ Hot-Side SCR (oxidized): Hot-side SCR as a control technology chances elemental

mercury to oxidized mercury. It is believed that the catalyst is responsible for this

shift in speciation. The default value is a function of the coal rank.

5.2.2.5.3. Carbon Injection

This screen is only available for the Combustion (Boiler) plant type. Inputs for activated carbon

and water injected into the flue gas are entered on this input screen. Water can be optionally

added to reduce the flue gas temperature and enhance the effect of the carbon on removing

mercury. Note that the actual removal of the carbon and mercury are accomplished in particulate

and flue gas desulfurization control technologies downstream.


• Activated Carbon Injection: Injection of water to reduce the flue gas temperature and

activated carbon to enhance mercury removal are the only control technologies presently

incorporated into the IECM.

◦ Carbon Injection Rate: The flue gas temperature, the mercury removal efficiency

in the particulate device, the coal rank, and the mercury removal efficiency without

control, determines the injection rate of activated carbon into the flue gas. Mercury

removal due to the ash removed in a cold-side ESP or fabric filter in the absence of

enhanced mercury control methods is specified in the input screen. The default

value is most sensitive to the flue gas temperature and the mercury removal

efficiency without control. Note that overriding the calculated value does not

change the removal efficiencies on the previous screen.

◦ Carbon Injection Power Requirement: The power required for the water and

carbon injection system is a function of carbon injection rate, the water injection

rate, and the flue gas flow rate. This assumes the addition of a fan in the flue gas to

balance the pressure drop. The default value is calculated as the ratio of the actual

energy consumption by the gross electrical output of the power plant.



90.

Illustration 182: PC: SET PARAMETERS: Mercury: Carbon Injection


5.2.2.5.5. O&M Cost


mercury control technology provides the following additional inputs at the top of the screen:

• Activated Carbon Cost (w. shipping): This is the cost for the activated carbon,

including the cost of shipping.

• Disposal Cost: This is the disposal cost for the particulate control system. It is assumed

that the ash is not hazardous, therefore can be disposed with the collected fly ash.


Inputs for the capital costs of modifications to process areas of the activated carbon and water

injection system are entered on this screen:

Illustration 183: PC: SET PARAMETERS: Mercury: O&M Cost

Illustration 184: PC: SET PARAMETERS: Mercury: Retrofit or Adjustment

Factors



costs. The activated carbon and water injection system has the following capital cost process

areas:

• Spray Cooling Water: This capital cost area represents the materials and equipment

necessary to inject water into the flue gas duct for the purpose of cooling the flue gas to

a prerequisite temperature. Equipment includes water storage tanks, pumps, transport

piping, injection grid with nozzles, and a control system. The direct capital cost is a

function of the water flow rate.

• Sorbent Injection: This capital cost area represents the materials and equipment

necessary to deliver the activated carbon into the flue gas. Equipment includes silo

pneumatic loading system, storage silos, hoppers, blowers, transport piping, and a

control system. The direct capital cost is a function of the sorbent flow rate.

• Sorbent Recycle: This capital cost area represents the materials and equipment

necessary to recycle ash and activated carbon from the particulate collector back into the

duct injection point. The purpose is to create an equilibrium state where the carbon is

reintroduced to improve performance. Equipment includes hoppers, blowers, transport

piping, and a control system. The direct capital cost is a function of the recycle rate of

ash and spent sorbent.

NOTE: Sorbent recycling is a feature which may be added in a future version of the

IECM.

• Additional Ductwork: This capital cost area represents materials and equipment for

ductwork necessary beyond the other process areas. Extra ductwork may be required for

difficult retrofit installations.

NOTE: Future versions of the IECM may include parameters to determine a capital

cost for this area. The current version assumes no additional ductwork.

• Sorbent Disposal: This capital cost area represents materials and equipment required to

house and dispose the collected sorbent. Equipment includes hoppers, blowers, transport

piping, and a control system. This is in excess of existing hoppers, tanks, and piping

used for existing particulate collectors. The direct capital cost is determined by the

incremental increase in collected solids in the particulate collector.

• CEMS Upgrade: This capital cost area represents materials and equipment required to

install a continuous emissions monitoring system (CEMS) upgrade. The direct capital

cost is determined by the net electrical output of the power plant.

• Pulse-Jet Fabric Filter: This capital costs area represents an upgrade to an existing

cold-side ESP, where one section at the back end of the unit is replaced with a pulse-jet

fabric filter. This can be considered a pseudo-COHPAC. Equipment includes pulse-jet

FF, filter bags, ductwork, dampers, and MCCs, instrumentation and PLC controls for

baghouse operation. Equipment excludes ash removal system, power distribution and

power supply, and distributed control system. The direct capital cost is a function of the

flue gas flow rate and the air to cloth ratio of the fabric filter.

NOTE: The IECM currently does not support multiple particulate devices in the same

configuration nor a modified cold-side ESP.

5.2.2.6. TSP Control

The TSP Control Technology screens define and display flows and costs related to the particulate

control technology.


5.2.2.6.1. Cold-Side ESP

These screens are available only if the Cold-Side ESP TSP control technology is selected in the

Pulverized Coal (PC) plant type configurations.

5.2.2.6.1.1. Cold-Side ESP Diagram

This diagram gives an overview of the cold-side ESP system. This diagram does not contain

any numbers and is strictly for reference:


Inputs for the performance of the Cold-Side ESP TSP control technology are entered on this

screen:

ESPs consist of a series of parallel plates with rows of electrodes in between them and carry a

high voltage of opposite polarity. As the particle laden flue gas enters the unit, the particles are

charged by the electrodes and is attracted to the plates. At controlled intervals the plates are

rapped which shakes the dust to a hopper below. However, some of the dust is re-entrained and

Illustration 185: PC: SET PARAMETERS: TSP

Control: Cold-Side ESP Diagram

Illustration 186: PC: SET PARAMETERS: TSP Control: Cold-Side ESP:

Performance


carried to the next zone or out of the stack. Most ESPs use rigid collecting plates with shielded

air pockets (baffles) through which ash falls into the hoppers after rapping.

The major design parameters which can significantly impact the total system capital cost are

gas flow volume (which depends on the generating unit size), SCA, the collecting plate area per

transformer-rectifier (T-R) set and the spacing between collector plates.

Many of the parameters are calculated by the IECM. Each parameter is described briefly

below:

• Particulate Removal Efficiency: The calculated value determines the removal

efficiency needed to comply with the specified particulate emission limit set earlier.

This efficiency then determines the mass of particulate matter removed in the

collector.

• Actual SO3 Removal Efficiency: The default value is taken from the removal

efficiency reported in the literature (references are below). This efficiency then

determines the mass of SO3 removed from the flue gas in the collector. For more

information see also:



• Collector Plate Spacing: The collector plate spacing is typically 12 inches. The

spacing is used to determine the specific collection area.

• Specific Collection Area: The specific collection area (SCA) is the ratio of the total

plate area and flue gas volume. It sizes the ESP. The value is calculated from the

removal efficiency, plate spacing, and the drift velocity. It is used to determine the

capital cost and the total collection area required.

• Plate Area per T-R Set: This is the total surface area of one T-R set of plates. It is

used to determine the total number of T-R sets needed and the capital costs.

• Percent Water in ESP Discharge: This is the water content of the collected fly ash.

Fly ash disposed with bottom ash is assumed to be sluiced with water and dry

otherwise. The occluded water in wet fly ash is difficult to remove, resulting in a

rather high water content when the fly ash is mixed with bottom ash.

• Cold-Side ESP Power Requirement: The default calculation is based on the T-R set

power consumption with estimates for auxiliary power requirements and electro-

mechanical efficiencies of fan motors. The T-R set power consumption is a function

of removal efficiency.



page 90.




5.2.2.6.1.4. O&M Cost

This is an O&M cost input screen as described in "5.1.1.5. O&M Cost Inputs" on page 97. It

includes the following additional inputs at the top of the screen:

• Water Cost: This is the cost of water.

• Waste Disposal Cost: This is the disposal cost for the particulate control system.


Inputs for the capital costs of modifications to process areas to implement the Particulate

control technology are entered on this screen:


costs. The Cold-Side ESP has the following capital cost process areas:

• Particulate Collector: This area covers the material and labor, flange to flange, for

the equipment and labor cost for installation of the entire collection system.

• Ductwork: This area includes the material and labor for the ductwork needed to

distribute flue gas to the inlet flange, and from the outlet flange to a common duct

leading to the suction side of the ID fan.


O&M Cost




• Fly Ash Handling: The complete fly ash handling cost includes the conveyor system

and ash storage silos.

• Differential ID Fan: The complete cost of the ID fan and motor due to the pressure

loss that results from particulate collectors.

5.2.2.6.2. Fabric Filter

These screens are available only if the Fabric Filter TSP control technology is selected in the

Pulverized Coal (PC) plant type configurations.

5.2.2.6.2.1. Fabric Filter Diagram

This diagram gives an overview of the fabric filter system. This diagram does not contain any


5.2.2.6.2.2. Config

This screen allows you to configure the fabric filter:

• Fabric Filter Type: Fabric filters consist of a large number of long tubular filter bags

arranged in parallel flow paths. As the ash-laden flue gas passes through these filters,

much of the particulate matter is removed. Ash accumulated on the bags is removed

periodically by various methods of cleaning. Choose the cleaning method on the

"Config." input screen. The available methods are:

◦ Reverse Gas (RG): A reverse gas fabric filter uses an off-line bag cleaning

technique in which an auxiliary fan forces a relatively gentle flow of filtered flue

Illustration 189: PC: SET PARAMETERS: TSP

Control: Fabric Filter Diagram

Illustration 190: PC: SET PARAMETERS: TSP Control: Fabric Filter: Config


gas backwards through the bags causing them to partially collapse and dislodge

the dust cake. Over 90% of baghouses in U.S. utilities use reverse-gas cleaning.

◦ Reverse Gas with Sonic (RG + S): A reverse gas sonic fabric filter uses a

variation of reverse gas cleaning in which low frequency pneumatic horns sound

simultaneously with the flow of reverse gas to add energy to the dust cake

removal process.

◦ Shake and Deflate (Sh + D): A shake & deflate fabric filter uses a method for

off-line cleaning in which the bags are mechanically shaken immediately after or

while a small quantity of filtered gas is forced back to relax the bags. The amount

of filtered gas used is smaller than that used in Reverse Gas cleaning.

◦ Pulse-jet (PJ): A pulse-jet fabric filter uses a method for on-line cleaning in

which pulses of compressed air are blown down inside and through the bags to

remove dust cake while the bags are filtering flue gas. Wire support cages are

used to prevent bag collapse during filtration and ash is collected outside of the

bags.


The baghouse system is very efficient in removing particulate matter from the flue gas. Its

model design is simple, requiring few parameters to characterize its effects on the overall

performance of the plant. For properly designed fabric filters, the size of the system is

independent of the removal efficiency.

Although the performance is determined by very few parameters, there are several design

parameters necessary to determine the cost. These factors are also determined in this section.

The major design parameters that can significantly impact the total system cost of the fabric

filter are gas flow volume (which depends on the generating unit size), A/C ratio, the flange-to-

flange pressure drop in the baghouse and the bag life.

Illustration 191: PC: SET PARAMETERS: TSP Control: Fabric Filter:

Performance


• Particulate Removal Efficiency: The calculated removal is set to comply with the

particulate emission limit set earlier. The mass removed is then determined. If you

select a spray dryer, the particulate removal efficiency applies to the combined mass

of flyash and sulfur-laden wastes. This input is highlighted in blue.







• Solids Loading Out: This is the fabric filter output loading. It is an average value

based on typical fabric filter units. The value is used to determine the particulate

removal efficiency.

• Number of Baghouse Units: This is the number of baghouse units. The value is

based on the gross plant size. The value must be an integer. Each unit contains several

compartments. It is used to calculate the capital cost of the baghouse.

• Number of Compartments per Unit: This parameter specifies the average number

of compartments used per baghouse unit. It is used to calculate the capital cost of the

baghouse.

• Number of Bags per Compartment: The number of individual bags per

compartment is calculated by comparing the required bag surface area to the bag

dimensions and the total number of compartments. It is used to calculate the capital

cost of the baghouse.

• Bag Length: Bag length generally fall into two size categories: 30-36 ft or 20 -22 ft

in length. It is based on the fabric filter type and used to calculate the capital cost of

the baghouse.

• Bag Diameter: Bags are generally between 2/3 and 1 foot in diameter. The value is

based on the fabric filter type and used to calculate the capital cost of the baghouse.

• Bag Life: Bag life is typically between 3-5 years. The bag life values are dependent

on the fabric filter type and are used to calculate the cost of the baghouse.

• Air to Cloth Ratio: The Air to Cloth ratio is the most important baghouse parameter.

It is the ratio of volumetric flue gas flow rate and total bag cloth area. The calculated

value is a function of fabric filter type. It is used to determine the cost and power use

of the baghouse.

• Total Pressure Drop across Fabric Filter: Baghouse pressure drop (flange-to-

flange) is caused by pressure losses in gas flow as it moves through the bag fabric and

dust cake. Typical values range from 6 to 8 in. H2O and depend on the baghouse type

selected. The value affects the power consumption.

• Percent Water in Fabric Filter Discharge: This is the water content of the collected

fly ash. Fly ash disposed with bottom ash is assumed to be sluiced with water and dry

otherwise. The occluded water in wet fly ash is difficult to remove, resulting in a

rather high water content when the fly ash is mixed with bottom ash.

• Fabric Filter Power Requirement: The default calculation is based on the air-to-

cloth ratio and the flue gas flow rate. The power accounts for the auxiliary power

requirements and electro-mechanical efficiencies of fan motors.






page 90.

5.2.2.6.2.5. O&M Cost


following additional inputs are provided at the top of the screen:

• Fabric Filter Bag Cost: This is the cost of a fabric filter bag as used for the fabric

filter technology.

• Waste Disposal Cost: This is the disposal cost for the particulate control system.


Inputs for the capital costs of modifications to process areas to implement the Particulate


Illustration 192: PC: SET PARAMETERS: Fabric Filter: O&M Cost

Illustration 193: PC: SET PARAMETERS: TSP Control: Fabric Filter:




costs. The fabric filter has the following capital cost process areas:

• Particulate Collector: This is the cost for the collecting equipment, based on actual

vendor prices. Included in the cost are the mechanical equipment and labor,

particulate removal system, alternate cleaning system, gas conditioning system,

structural supports, electrical, and instrumentation.

• Ductwork: This is the cost of all the mechanical, electrical, and supports of the

ductwork to and from the collector.

• Fly Ash Handling: This is the cost of all the mechanical, conveyors, storage, and

electrical portions of the ash handling system. The costs are based on actual vendor

prices.

• Differential ID Fan: This area includes the additional cost of the ID fan and the

motor due to the pressure loss that results from the particulate collectors. Also

included are the erection, piping, electrical, and foundation costs.

5.2.2.7. SO2 Control

The SO2 Control Technology contains screens that address post-combustion air pollution

technologies for Sulfur Dioxide.

5.2.2.7.1. Wet FGD

The model includes options for a Wet FGD. The screens are available if this SO2 control

technology has been selected for the Combustion (Boiler) plant type.

5.2.2.7.1.1. Wet FGD Diagram

This diagram gives an overview of the wet FGD system. This diagram does not contain any


Illustration 194: PC: SET PARAMETERS: SO2 Control:

Wet FGD Diagram


5.2.2.7.1.2. Config

Inputs for configuration of the Wet FGD SO2 control technology are entered on this screen:


• Reagent: For Wet FGD systems, the choice of reagent affects nearly all of the

performance and economic parameters of the FGD. Three choices are available:

◦ Limestone: (This is the default.) Limestone with Forced Oxidation - A limestone

slurry is used in an open spray tower with in-situ oxidation to remove SO2 and

form a gypsum sludge. The main advantages as compared to conventional

systems are easier dewatering, more economical disposal of scrubber products,

and decreased scaling on tower walls.

◦ LS w/ Additives: Limestone with Dibasic Acid Additive - Dibasic acid (DBA) is

added to the Limestone to act as a buffer/catalyst in the open spray tower. The

main advantages are increased SO2 removal and decreased liquid to gas ratio.

◦ Lime: Magnesium Enhanced Lime System - A magnesium sulfite and lime slurry

(maglime) is used to remove SO2 and form a precipitate high in calcium sulfite.

The high alkalinity of the maglime slurry allows very high SO2 removal.

However, the reagent cost is also higher and solid waste is not easily disposed.

• Flue Gas Bypass Control: This popup selection menu controls whether or not a

portion of the inlet flue gas may bypass the scrubber and recombine with the treated

flue gas. Bypass allows the scrubber to operate at full efficiency while allowing some

of the flue gas to go untreated. Two choices are available:

◦ No Bypass: (This is the default.) This option forces the entire flue gas to pass

through the scrubber.

◦ Bypass: This option allows for the possibility of a portion of the flue gas to

bypass the scrubber. The amount of bypass is controlled by several additional

input parameters described below. These parameters are only visible when this

option is selected:

▪ Maximum SO2 Removal Efficiency: This parameter specifies the

maximum efficiency possible for the absorber on an annual average basis.

The value is used as a limit in calculating the actual SO2 removal efficiency

for compliance.

Illustration 195: PC: SET PARAMETERS: SO2 Control: Wet FGD: Config


▪ Overall SO2 Removal Efficiency: This value is the SO2 removal efficiency

required for the entire power plant to meet the SO2 emission constraint set

earlier. It is used to determine the actual flue gas bypass above.

▪ Scrubber SO2 Removal Efficiency: This is the actual removal efficiency of

the scrubber alone. It is a function of the SO2 emission constraint and the

actual flue gas bypass. This value is also shown on the next input screen.

▪ Minimum Bypass: This specifies the trigger point for allowing flue gas to

bypass the scrubber. No bypass is allowed until the allowable amount

reaches the minimum level set by this parameter.

▪ Allowable Bypass: This is the amount of flue gas that is allowed to bypass

the scrubber, based on the actual and maximum performance of the SO2

removal. It is provided for reference only. The model determines the bypass

that produces the maximum SO2 removal and compares this potential bypass

with the minimum bypass value specified above. Bypass is only allowed

when the potential bypass value exceeds the minimum bypass value.

▪ Actual Bypass: This displays the actual bypass being used in the model. It is

based on all of the above and is provided for reference purposes only.

• Demister for Outlet Flue Gas: This parameter determines whether a demister is used

to remove water from the flue gas exiting the FGD. The default is "No Demister".

• Demister Water Removed: (Only shown when a demister is used) This is the amount

of water removed by the demister.


Inputs for performance of the Wet FGD SO2 control technology are entered on this screen:

Illustration 196: PC: SET PARAMETERS: SO2 Control: Wet FGD:

Performance



• Maximum SO2 Removal Efficiency: This parameter specifies the maximum


limit in calculating the actual SO2 removal efficiency for compliance.

• Scrubber SO2 Removal Efficiency: This is the annual average SO2 removal

efficiency achieved in the absorber. The calculated value assumes compliance with

the SO2 emission limit specified earlier, if possible. The efficiency is used to

determine the liquid to gas ratio and emissions. This input is highlighted in blue.

• Scrubber SO3 Removal Efficiency: The default value is taken from the removal






• Particulate Removal Efficiency: This is the percent removal of particulate matter

entering the FGD system from the upstream particulate collector. Particulate

collectors are designed to comply with the specified particulate emission limit. This is

additional particulate removal.

• Absorber Capacity: This is the percent of the flue gas treated by each operating

absorber. This value is used to determine the number of operating absorbers and the

capital costs.

• Number of Operating Absorbers: This is the number of operating scrubber towers.

The number is determined by the absorber capacity and is used to calculate the capital

costs. The value must be an integer.

• Number of Spare Absorbers: This is the total number of spare absorber vessels. It is

used primarily to calculate capital costs. The value must be an integer.

• Liquid to Gas Ratio: The design of spray towers for high efficiency is achieved by

using high liquid-to-gas (L/G) ratios. The calculated value is a function of the reagent

type, the removal efficiency, and stoichiometry. It determines the power requirement

and capital cost.

• Reagent Stoichiometry: This is the moles of calcium per mole of sulfur removed

from the absorber. The stoichiometry is calculated as a function of the reagent type. It

is used to determine the liquid to gas ratio, reagent usage, reagent waste, and capital

cost.

• Reagent Purity: This is the percent of the reagent that is lime (CaO) or limestone

(CaCO3). The calculated value is a function of the reagent type. This parameter

determines the waste solids produced and the reagent needed to remove the necessary

SO2.

• Reagent Moisture Content: This is the moisture content of the reagent. The

remaining reagent impurities are assumed to be inert substances such as silicon

dioxide (sand). This parameter is used to determine the waste solids produced.

• Total Pressure Drop across FGD: This is the total pressure drop across the FGD

vessel prior to the reheater. This is used in the calculations of the power requirements

(or energy penalty) and thermodynamic properties of the flue gas.

• Temperature Rise Across ID Fan: An induced draft (ID) fan is assumed to be

located upstream of the FGD system. The fan raises the temperature of the flue gas

due to dissipation of electro-mechanical.




• Gas Temperature Exiting Scrubber: A thermodynamic equation is used to calculate

this equilibrium flue gas temperature exiting the scrubber. The gas is assumed to be

saturated with water at the exiting temperature and pressure. The value determines the

water evaporated in the scrubber.

• Gas Temperature Exiting Reheater: This is the desired temperature of flue gas after

the reheater. It is assumed to be equal to the stack gas exit temperature. If scrubber

bypass is employed, reheat requirements are reduced or eliminated. It determines the

reheat energy required.

• Entrained Water Past Demister: This is a liquid water entrained in the flue gas

leaving the demister expressed as a percentage of the total water evaporated in the

absorber.

• Wet FGD Power Requirement: This is the equivalent electrical output of thermal

(steam) energy used for reheat, plus the actual electrical output power required for

pumps and booster fans.

5.2.2.7.1.4. Oxidation

The parameters are described briefly below:

• Oxidation of CaSO3 to CaSO4: This parameter determines the mixture of chemical

species (calcium sulfite and calcium sulfate) in the solid waste stream. The default

values depend on the selection of forced or natural oxidation.

• Excess Air for Oxidation: This is the amount of excess air used for oxidation.

• Excess Water for Oxidation: This is the amount of excess water used for oxidation.

5.2.2.7.1.5. Additives

The parameters are described briefly below.

• Chloride Removal Efficiency: Chlorides in the flue gas inlet stream are removed by

the lime/limestone slurry. This parameter determines the amount of chlorides

removed.

• The following parameters are only shown when "LS w/ Additives" is chosen as the

reagent on the "Config" screen. (See "5.2.2.7.1.2. Config" on page 165.)

Illustration 197: PC: SET PARAMETERS: SO2 Control: Wet FGD: Oxidation

Illustration 198: PC: SET PARAMETERS: SO2 Control: Wet FGD: Additives


◦ Dibasic Acid Concentration: Dibasic acid (DBA) is added to limestone to

reduce the liquid to gas ratio, enhancing the removal of SO2. This is the

concentration of DBA in the limestone slurry.

◦ Dibasic Acid Makeup: DBA is not completely recovered in the reagent feedback

loop. This parameter is used to determine the makeup flow rate of DBA.



page 90.

If bypass is enabled (see "5.2.2.7.1.2. Config" on page 165), an additional parameter appears

before "General Facilities Capital":

• Bypass Duct Cost Adder: (This is only available for technologies that support

bypass.) The bypass capital costs are not specified with the other process areas. This

parameter allows any direct capital costs incurred by the addition of bypass ducts to

be added to the Flue Gas System process area (see retrofit cost screen for a list of the

direct cost process areas).

Illustration 199: PC: SET PARAMETERS: SO2 Control: Wet FGD: Capital

Cost


5.2.2.7.1.7. O&M Cost


Wet FGD system includes the following additional inputs at the top of the screen:

• Bulk Reagent Storage Time: This is the number of days of bulk storage of reagent.

This factor is used to determine the inventory capital cost.

• Limestone Cost: This is the cost of Limestone for the Wet FGD system.

• Lime Cost: This is the cost of Lime for the Wet FGD system.

• Dibasic Acid Cost: (Only shown when "LS w/ Additives" is chosen as the reagent on

the "Config" screen - see "5.2.2.7.1.2. Config" on page 165.) This is the cost of the

Dibasic Acid for the Wet FGD system.

• Stacking Cost: This is the stacking cost as used for the Wet FGD system.

• Waste Disposal Cost: This is the sludge disposal cost for the Wet FGD system.

Illustration 200: PC: SET PARAMETERS: SO2 Control: Wet FGD: O&M Cost



Inputs for capital costs of modifications to process areas to implement the Wet FGD SO2



costs. The Wet FGD has the following capital cost process areas:

• Reagent Feed System: This area includes all equipment for storage, handling and

preparation of raw materials, reagents, and additives used.

• SO2 Removal System: This area deals with the cost of equipment for SO2 scrubbing,

such as absorption tower, recirculation pumps, and other equipment.

• Flue Gas System: This area treats the cost of the duct work and fans required for flue

gas distribution to SO2 system, plus gas reheat equipment.

• Solids Handling System: This area includes the cost of the equipment for fixation,

treatment, and transportation of all sludge/dry solids materials produced by scrubbing.

• General Support Area: The cost associated with the equipment required to support

FGD system operation such as makeup water and instrument air are treated here.

• Miscellaneous Equipment: Any miscellaneous equipment is treated in this process

area.

5.2.2.7.2. Spray Dryer

The model includes options for a Lime Spray Dryer. A spray dryer is sometimes used instead of a

wet scrubber because it provides simpler waste disposal and can be installed with lower capital

costs. These screens are available if the Lime Spray Dryer SO2 control technology has been

selected for the Pulverized Coal (PC) plant type.

Illustration 201: PC: SET PARAMETERS: SO2 Control: Wet FGD - Retrofit

Cost Input Screen


5.2.2.7.2.1. Spray Dryer Diagram

This diagram gives an overview of the spray dryer. This diagram does not contain any numbers


5.2.2.7.2.2. Config

Inputs for configuration of the Lime Spray Dryer SO2 control technology are entered on this

screen:


• Reagent: For the Lime Spray Dryer the only option is Lime.

◦ Lime: Magnesium Enhanced Lime System - A magnesium sulfite and lime slurry

(maglime) is used to remove SO2 and form a precipitate high in calcium sulfite.

The high alkalinity of the maglime slurry allows very high SO2 removal.

However, the reagent cost is also higher and solid waste is not easily disposed.

Illustration 202: PC: SET PARAMETERS: SO2

Control: Spray Dryer Diagram

Illustration 203: PC: SET PARAMETERS: SO2 Control: Spray Dryer: Config



Inputs for performance of the Lime Spray Dryer SO2 control technology are entered on this

screen:

In a Lime Spray Dryer, an atomized spray of a mixture of lime slurry and recycled solids is

brought into contact with the hot flue gas. The water in the slurry evaporates leaving dry

reaction products and flyash, which drops out of the scrubber. A particulate control device such

as a baghouse is also used to remove the rest of the dry products from the flue gas before

releasing it. The SO2 removal efficiency is the total of SO2 removed in the scrubber and the

baghouse.

Many lime spray dryer input parameters are similar to those defined for wet lime/limestone

systems. (See "5.2.2.7.1.3. Performance" on page 166.) Each parameter is described briefly

below:

• Actual SO2 Removal Efficiency: This is the annual average SO2 removal efficiency

achieved in the absorber. The calculated default value assumes compliance with the

SO2 emission limit specified earlier, if possible. The default value reflects other model

parameter values, including the sulfur retained in bottom ash. This input is

highlighted in blue.

• Maximum SO2 Removal Efficiency: This parameter specifies the maximum


limit in calculating the actual SO2 removal efficiency for compliance.





Illustration 204: PC: SET PARAMETERS: SO2 Control: Spray Dryer:

Performance




• Particulate Removal Efficiency: Ash and particulate matter are assumed to be

removed by a separate particulate removal device, such as a fabric filter. However,

this parameter is provided for conditions where particulates are removed directly from

the scrubber.

• Absorber Capacity: This is the percent of the flue gas treated by each operating

absorber. This value is used to determine the number of operating absorbers and the

capital costs.

• Number of Operating Absorbers: This is the number of operating scrubber towers.

The number is determined by the absorber capacity and is used to calculate the capital

costs. The value must be an integer.



• Reagent Stoichiometry: This is the moles of calcium per mole of sulfur into the

absorber. The stoichiometry is calculated as a function of the required SO2 removal

efficiency, inlet flue gas temperature, inlet sulfur concentration, and approach to

saturation temperature.

• CaO Content of Lime: This is the percent of reagent that is pure lime (CaO). This

parameter determines the waste solids produced and the reagent mass requirements,

given the stoichiometry needed for SO2 removal.

• H2O Content of Lime: This is the moisture content of the lime (CaO). The remaining

reagent impurities are assumed to be inert substances such as silicon dioxide (sand).

This parameter is used to determine the waste solids produced.

• Total Pressure Drop Across FGD: This is the total pressure drop across the spray

dryer vessel prior to the reheater. This is used in the calculations of the power

requirements (or energy penalty) and thermodynamic properties of the flue gas.

• Approach to Saturation Temperature: This defines the gas temperature exiting the

absorber. The approach is the increment over the water saturation temperature at the

exit pressure. As the approach to saturation temperature increases, the evaporation

time decreases thereby decreasing removal efficiency.

• Temperature Rise Across ID Fan: An induced draft (ID) fan is assumed to be

located upstream of the FGD system. The fan raises the temperature of the flue gas

due to dissipation of electro-mechanical energy.

• Gas Temperature Exiting Scrubber: A thermodynamic equation is used to calculate

this equilibrium flue gas temperature exiting the scrubber. The gas is assumed to be

saturated with water at the exiting temperature and pressure. The value determines the

water evaporated in the scrubber.

• Oxidation of CaSO3 to CaSO4: This parameter determines the mixture of the two

chemical species in the solid waste stream.

• Slurry Recycle Ratio: An atomized spray of a mixture of lime slurry and recycled

solids is brought into contact with the hot flue gas. This parameter specifies the

amount of solid waste recycled and lime slurry used. It is calculated from the sulfur

content of the coal.

• Spray Dryer Power Requirement: This is the equivalent electrical output of thermal

(steam) energy used for reheat, plus the actual electrical output power required for







page 90.

5.2.2.7.2.5. O&M Cost


spray dryer has the following additional inputs at the top of the screen:

• Bulk Reagent Storage Time: This is the number of days of bulk storage of reagent.

This factor is used to determine the inventory capital cost.

• Lime Cost: This is the cost of Lime for the Lime Spray Dryer system.

• Waste Disposal Cost: This is the sludge disposal cost for the Lime Spray Dryer

system.

Illustration 205: PC: SET PARAMETERS: SO2 Control: Spray Dryer: O&M

Cost



Inputs for capital costs of modifications to process areas to implement the SO2 control

technology are entered on this screen:


costs. The spray dryer has the following capital cost process areas:












area.

5.2.2.8. CO2 Capture, Transport & Storage

5.2.2.8.1. Amine System (CCS System)

The amine CO2 scrubber is a post-combustion capture technology. It may be used in the

Pulverized Coal (PC) and Natural Gas Combined Cycle (NGCC) plant types.

Illustration 206: PC: SET PARAMETERS: SO2 Control: Spray Dryer: Retrofit

or Adjustment Factors


5.2.2.8.1.1. Amine System Diagram

This diagram gives an overview of the amine system. This diagram does not contain any


5.2.2.8.1.2. Config


CCS System (Amine): Amine System Diagram

Illustration 208: PC: SET PARAMETERS: CO2 Capture, Transport &

Storage: CCS System (Amine): Config



• System Used: The type of absorber used. The following options are available:

◦ MEA: Monoethanolamine (MEA)is an amine which can be used to remove CO2

and H2S.

◦ FG+: (This is the default.) This process uses MEA along with an oxygen

inhibitor to reduce sorbent degradation and equipment corrosion.

◦ Cansolv: The Shell Cansolv system is an amine-based CO2 capture system. It is

used in the "NETL Case B12B" session in the session library. Note that this is not

a generalized Cansolv model.

• Auxiliary Gas Boiler?: An auxiliary natural gas-fired boiler can be added to the

amine system. When used, the original steam cycle of the power plant remains

undisturbed and the net power generation capacity of the power plant is not adversely

affected. The auxiliary boiler comes at an additional cost of capital requirement for

the boiler (and turbine) and the cost of supplemental fuel. Also, the auxiliary boiler

adds to the CO2 and NOx emissions. When an auxiliary boiler is added, an additional

process type is added. (See "4.1.4.4.2.3. Process Types" on page 38,

"5.2.2.8.3. Auxiliary Boiler System" on page 196 and "5.2.3.8.7. Auxiliary Boiler" on

page 377.) The following options are available:

◦ None: (This is the default.) An auxiliary gas boiler is not used.

◦ Steam Only: An auxiliary gas boiler is used to generate low pressure steam for

sorbent regeneration.

◦ Steam + Power: An auxiliary gas boiler is used to generate low pressure steam

for sorbent regeneration and separate power for the amine system.

• CO2 Product Compressor Used: The CO2 product stream may need to be

compressed for transportation to a sequestration site. This parameter determines

whether or not a CO2 product compressor is used. If a CO2 product compressor is

used, the following parameter is also shown:

◦ Compressor Type: If a CO2 product compressor is used, this parameter

determines whether it is a 6- or 8-stage compressor.




of the flue gas to go untreated. Two choices are available: No Bypass and Bypass. The

no bypass option is the default and forces the entire flue gas to pass through the

scrubber. The bypass option allows for the possibility of a portion of the flue gas to

bypass the scrubber. The amount of bypass is controlled by several additional input

parameters described below.

• Direct Contact Cooler (DCC) Used: A DCC is configured by default to cool the flue

gas before it enters the amine system. The lower flue gas temperature enhances the

absorption reaction (absorption of CO2 in MEA sorbent is an exothermic process) and

decreases the flue gas volume. The typically acceptable range of flue gas temperature

is about 120-140ºF. A DCC is often not needed if a wet FGD is installed upstream.

• SO2 Polisher Used: (PC plants only) This parameter determines whether or not an

SO2 polisher is used to reduce the flue gas SO2 concentration. Standard wet FGD or

sprayer units do not reduce the SO2 concentration sufficiently to the designated level

for carbon capture pre-treatment. If an SO2 polisher is used, the following parameter

is also displayed:


◦ SO2 Polisher Outlet Concentration: This is the SO2 concentration exiting the

polisher, if one is in use. This value is used to determine the amount of reagent

required. The default is based on the sorbent.

• Temperature Exiting DCC: (Only displayed when a DCC is used.) This is the

temperature exiting the DCC. The desirable temperature of the flue gas entering the

CO2 capture system is about 113-122ºF. If the inlet temperature to the DCC is at or

below this temperature, the DCC is not used.

• Flue Gas Bypass: These parameters control the amount of bypass. They are only

displayed if bypass is chosen above:

◦ Maximum CO2 Removal Efficiency: This parameter specifies the maximum

efficiency possible for the absorber on an annual average basis. The value is used

as a limit in calculating the actual CO2 removal efficiency for compliance.

◦ Overall CO2 Removal Efficiency: This value is the CO2 removal efficiency

required for the entire power plant to meet the CO2 emission constraint set earlier.

It is used to determine the actual flue gas bypass above.

◦ Absorber CO2 Removal Efficiency: This is the actual removal efficiency of the

absorber alone. It is a function of the CO2 emission constraint and the actual flue

gas bypass.

◦ Minimum Bypass: This specifies the trigger point for allowing flue gas to

bypass the scrubber. No bypass is allowed until the allowable amount reaches the

minimum level set by this parameter.

◦ Allowable Bypass: This is the amount of flue gas that is allowed to bypass the

scrubber, based on the actual and maximum performance of the CO2 removal. It

is provided for reference only. The model determines the bypass that produces

the maximum CO2 removal and compares this potential bypass with the

minimum bypass value specified above. Bypass is only allowed when the

potential bypass value exceeds the minimum bypass value.

◦ Actual Bypass: This displays the actual bypass being used in the model. It is




The amine-based absorption system for CO2 removal is a wet scrubbing operation. This

process removes other acid gases and particulate matter in addition to CO2 from the flue gas.


• Maximum CO2 Removal Efficiency: (PC plants only) This parameter specifies the

maximum efficiency possible for the absorber on an annual average basis. The value

is used as a limit in calculating the actual CO2 removal efficiency for compliance.

When the Cansolv system is chosen, this parameter is fixed at 90%.

• Absorber CO2 Removal Efficiency: This is the actual removal efficiency of the

absorber alone.

When the Cansolv system is chosen, this parameter is fixed at 90%.

• Other Removals:

◦ SO2 Removal Efficiency: SO2 is removed at a very high rate. The default

efficiency is 100%.


efficiency is 99.5%.

◦ NO2 Removal Efficiency: A small amount of NO2 is removed. The default

efficiency is 0%.

◦ HCl Removal Efficiency: HCl is removed at a high rate. The default efficiency

is 95%.

◦ Particulate Removal Efficiency: Particulates are removed in any wet scrubbing

system at a rate of approximately 50%.


CCS System (Amine): Performance


• Trace Removals: (currently only shown in NGCC plants)

◦ Mercury Removal Efficiency (oxidized): This is the removal efficiency of the

oxidized portion of mercury from the CO2 absorber. The removed portion can be

found in the bottom ash and the remainder found in the flue gas.

◦ Mercury Removal Efficiency (elemental): This is the removal efficiency of the

elemental portion of mercury from the CO2 absorber. The removed portion can be

found in the bottom ash and the remainder found in the flue gas.

• Maximum Train CO2 Capacity: The default maximum train size is used with the

actual CO2 capture rate to determine the number of trains required.

• Number of Operating Absorbers: This is the total number of operating absorber

vessels. It is determined by the train capacity specified above and is used primarily to

calculate capital costs. The value must be an integer.


used primarily to calculate capital costs. Up to two spare absorbers may be specified.

• Maximum CO2 Compressor Capacity: This is the maximum amount of CO2

product that can be compressed per hour at the specified pressure (see the storage

input screen).

• Number of Operating CO2 Compressors: This is the total number of operating CO2

compressors. It is used primarily to calculate capital costs. The value must be an

integer.

• Number of Spare CO2 Compressors: This is the total number of spare CO2

compressors. It is used primarily to calculate capital costs. Up to two spare CO2

compressors may be specified.

• Makeup H2O Factor for Aux. Cooling: (Only shown when an Air Cooled

Condenser is used for plant cooling.) When CCS and an Air Cooled Condenser are

used, the CCS system uses an auxiliary cooling system. This parameter specifies the

amount of makeup water required for the auxiliary cooling system.

• Amine Scrubber Power Requirement: This is the equivalent electrical output of

thermal (steam) energy used for reheat, plus the actual electrical power required for



5.2.2.8.1.4. Capture

The absorber is the vessel where the flue gas makes contact with the MEA-based sorbent, and

some of the CO2 from the flue gas is dissolved in the sorbent. The column may be plate-type or

a packed one. Most of the CO2 absorbers are packed columns using some kind of polymer-

based packing to provide large interfacial area. The following parameters apply to the

absorber:

• Sorbent Concentration: (Not shown for Cansolv.) The solvent used for CO2

absorption is a mixture of monoethanolamine (MEA) with water. MEA is a highly

corrosive liquid, especially in the presence of oxygen and carbon dioxide, and hence

needs to be diluted. Today the commercially available MEA-based technology

supplied by Fluor Daniel uses 30% w/w MEA solvent with the help of some corrosion

inhibitors. Other suppliers, who do not use this inhibitor, prefer to use lower MEA

concentrations in the range of 15%-20% by weight.

• Lean CO2 Loading: Ideally, the solvent will be completely regenerated on

application of heat in the regenerator section. Actually, even on applying heat, not all

the MEA molecules are freed from CO2. So, the regenerated (or lean) solvent contains

some "left-over" CO2. The level of lean solvent CO2 loading mainly depends upon the

initial CO2 loading in the solvent and the amount of regeneration heat supplied, or

alternatively, the regeneration heat requirement depends on the allowable level of lean

sorbent loading.

• Sorbent Losses (excluding acid gasses): (Not shown for Cansolv.) MEA is a reactive

solvent. In spite of dilution with water and use of inhibitors, a small quantity of MEA

is lost through various unwanted reactions, mainly the polymerization reaction (to

form long-chained compounds) and the oxidation reaction forming organic acids and

liberating ammonia. It is assumed that 50% of this MEA loss is due to polymerization

and the remaining 50% of the MEA loss is due to oxidation to acids.


CCS System (Amine): Capture


• Sorbent Recovered: (Not shown for Cansolv.) This is the amount of sorbent

regenerated by caustic added to the reclaimer.

• Liquid to Gas Ratio: (Not shown for Cansolv.) The liquid to gas ration is the ratio of

total molar flow rate of the liquid (MEA sorbent plus water) to the total molar flow

rate of flue gas being treated in the absorber.

• Ammonia Generation: (Not shown for Cansolv.) The oxidation of MEA to organic

acids (oxalic, formic, etc.) also leads to formation of NH3. Each mole of MEA lost in

oxidation, liberates a mole of ammonia (NH3).

• Gas Phase Pressure Drop: (Not shown for Cansolv.) This is the pressure drop that

the flue gas has to overcome as it passes through a very tall absorber column,

countercurrent to the sorbent flow.

• ID Fan Efficiency: The cooled flue gas is pressurized using a flue gas blower before

it enters the absorber. This is the efficiency of the fan/blower to convert electrical

power input into mechanical work output.

• Makeup Water for Wash Section: This is the amount of makeup water required by

the wash section, expressed as a percent of the weight of the raw flue gas.

• Activated Carbon Used: (Not shown for Cansolv.) This is the amount of activated

carbon in the sorbent circuit to help remove the polymeric sorbent compounds.

The regenerator is the column where the weak intermediate compound (carbamate) formed

between the MEA-based sorbent and dissolved CO2 is broken down with the application of

heat and CO2 gets separated from the sorbent to leave reusable sorbent behind. In case of

unhindered amines like MEA, the carbamate formed is stable and it takes large amount of

energy to dissociate. It also consists of a flash separator where CO2 is separated from most of

the moisture and evaporated sorbent, to give a fairly rich CO2 stream. The following

parameters apply to the regenerator:

• Regeneration Heat Requirement: This is the total amount of heat energy required in

the reboiler for sorbent regeneration.

• Steam Heat Content: The regeneration heat is provided in the form of LP steam

extracted from the steam turbine (in case of coal-fired power plants and combined-

cycle gas plants), through the reboiler (a heat exchanger). In case of simple cycle

natural gas fired power plants, a heat recovery unit maybe required. This is the

enthalpy or heat content of the steam used for solvent regeneration.

• Heat-to-Electricity Efficiency: (Only shown when an auxiliary boiler is not used.)

This is the efficiency of converting low pressure steam to electricity. The value

reflects the loss of electricity to the base plant when the LP steam is used for

regenerator heat.

• Solvent Pumping Head: The solvent has to flow through the absorber column

(generally through packed media) countercurrent to the flue gas flowing upwards. So,

some pressure loss is encountered in the absorber column and sufficient solvent head

has to be provided to overcome these pressure losses. Solvent circulation pumps are

used to provide the pressure head.

• Pump Efficiency: This is the efficiency of the solvent circulation pumps to convert

electrical power input into mechanical power output.

• Percent Solids in Reclaimer Waste: (Not shown for Cansolv.) This is the amount of

solids typically present in the reclaimer waste.

• Capture System Cooling Duty: This is the total amount of cooling water normalized

by CO2 product.


5.2.2.8.1.5. T&S Config

This screen characterizes the compression and storage methods for the product CO2. A separate

pipeline model is provided to specify inputs for that sub-system. See "5.2.2.8.10. Pipeline

Transport" on page 244.

• CO2 Product Stream: The concentrated CO2 product stream obtained from sorbent

regeneration is compressed and dried using a multi-stage compressor with inter-stage

cooling.

◦ CO2 Product Pressure: (Only shown when a CO2 product compressor is configured.)

The CO2 product may have to be carried over long distances. Hence it is necessary to

compress (and liquefy) it to very high pressures, so that it may be delivered to the

required destination in liquid form and (as far as possible) without recompression

facilities en route. The critical pressure for CO2 is about 1070 psig. The typically

reported value of final pressure to which the product CO2 stream has to be pressurized

using compressors before it is transported is about 2000 psig.

◦ CO2 Product Purity: This is the percentage of the product that is carbon dioxide.

◦ CO2 Compressor Efficiency: (Only shown when a CO2 product compressor is

configured.) This is the effective efficiency of the compressors used to compress CO2

to the designated pressure.

◦ CO2 Unit Compression Energy: (Only shown when a CO2 product compressor is

configured.) This is the electrical energy required to compress a unit mass of CO2

product stream to the designated pressure. Compression of CO2 to high pressures

requires substantial energy and is a principle contributor to the overall energy penalty

of a CO2 capture unit in a power plant.

The transport and storage methods are specified as described in "5.1.4.3. T&S Config" on page

107.



page 90.


Storage: CCS System (Amine): T&S Config


5.2.2.8.1.7. Variable O&M Cost

O&M Cost inputs are described in "5.1.1.5. O&M Cost Inputs" on page 97. This screen only

contains inputs for the amine system's variable O&M costs:

The parameters are:

• MEA Cost: (Not shown for Cansolv.) This is the unit cost of the makeup MEA.

• Inhibitor Cost: (Not shown for Cansolv.) Addition of inhibitor makes it possible to

use higher concentrations of MEA solvent in the system with minimal corrosion

problems. Inhibitors are special compounds that come at a cost premium. The cost of

inhibitor is estimated as a percent of the cost of MEA. The model default is 20%.

• Activated Carbon Cost: (Not shown for Cansolv.) This is the cost of the activated

carbon in $ per ton.

• Caustic (NaOH) Cost: (Not shown for Cansolv.) This is the cost of the caustic

(NaOH) in $ per ton.

• Process Chemicals: (Only shown for Cansolv.) Process chemicals include Ion

Exchange Resin, NaOH, Cansolv Solvent and Triethylene Glycol.

• Water Cost: Water is mainly required for cooling and also as process makeup. Cost

of water may vary depending upon the location of the power plant.

• Auxiliary Gas Cost: This is the cost of natural gas. It is only visible if an auxiliary

boiler is specified.

• Auxiliary CCS Cooling Cost: (Only shown when an air cooled condenser is

configured.) This is the cost of the auxiliary cooling system needed when an Air

Cooled Condenser is used as the plant cooling system.

• Reclaimer Waste Disposal Cost: (Not shown for Cansolv.) The unit cost of waste

disposal for the reclaimer waste.

• Electricity Price (internal): See "5.1.1.5. O&M Cost Inputs" on page 97.


Storage: CCS System (Amine): Variable O&M Cost


• CO2 Transport Cost (Levelized): Transportation of CO2 product is assumed to take

place via pipelines. This is the unit cost of CO2 transport in $/ton-mile. The cost is

calculated from the pipeline sub-process model.

• CO2 Storage Cost: This is the unit cost of CO2 disposal. Depending upon the method

of CO2 disposal or storage, either there may be some revenue generated (Enhanced

Oil Recovery) which may be treated as a "negative cost", or additional cost (all other

disposal methods).

5.2.2.8.1.8. Fixed O&M Cost

This screen contains inputs for the amine system's fixed O&M costs:

All of the parameters on this screen are described in "5.1.1.5. O&M Cost Inputs" on page 97



Storage: CCS System (Amine): Fixed O&M Cost


CCS System (Amine): Retrofit or Adjustment Factors



costs. The amine system has the following capital cost process areas:

• SO2 Polisher/Direct Contact Cooler (PC) or Direct Contact Cooler (NGCC): For

PC plants, an SO2 polisher may be used to reduce the SO2 concentration to very low

levels. For all plant types, a direct contact cooler is typically used in plant

configurations that do not include a wet FGD. A direct contact cooler is a large vessel

where the incoming hot flue gas is placed in contact with cooling water. The cost is a

function of the gas flow rate and temperature of the flue gas.

• Flue Gas Blower: The flue gas enters the bottom of the absorber column and flows

upward, countercurrent to the sorbent flow. Blowers are required to overcome the

substantial pressure drop as it passes through a very tall absorber column. The cost is

a function of the volumetric flow rate of the flue gas.

• CO2 Absorber Vessel: The capital cost of the absorber will go down with higher

MEA concentration and higher CO2 loading level of the solvent, and lower CO2

content in the lean solvent. Therefore, a power law relationship based on flue gas flow

rate is used. This is based on cost and flow rate data from Fluor Daniel, Inc. The cost

assumes one absorber vessel per train. The cost is a function of the volumetric flow

rate of the flue gas and the flue gas temperature.

• Heat Exchangers: The CO2-loaded sorbent must be heated in order to strip off CO2

and regenerate the sorbent. In addition, the regenerated sorbent must be cooled down

before it can be recirculated back to the absorber column. Heat exchangers are used to

accomplish these two tasks. This area is a function of the sorbent flow rate.

• Circulation Pumps: Circulation pumps are required to take the sorbent, introduced at

atmospheric pressure, and lift it to the top of the absorber column. This area is a

function of the sorbent flow rate.

• Sorbent Regenerator: The regenerator (or stripper) is a column where the weak

intermediate compound (carbamate) is broken down by the application of heat. The

result is the release of CO2 (in concentrated form) and return of the recovered sorbent

back to the absorber. This process is accomplished by the application of heat using a

heat exchanger and low-pressure steam. MEA requires substantial heat to dissociate

the carbamate. Therefore, a flash separator is also required, where the CO2 is

separated from the moisture and evaporated sorbent to produce a concentrated CO2

stream. This area is a function of the sorbent flow rate.

• Reboiler: The regenerator is connected to a reboiler, which is a heat exchanger that

utilizes low pressure steam to heat the loaded sorbent. The reboiler is part of the

sorbent regeneration cycle. The cost is a function of the sorbent and steam flow rates.

• Steam Extractor: Steam extractors are installed to take low pressure steam from the

steam turbines in the power plant. The cost is a function of the steam flow rate.

• Sorbent Reclaimer: A portion of the sorbent stream is distilled in the reclaimer in

order to avoid accumulation of heat stable salts in the sorbent stream. Caustic is added

to recover some of the MEA in this vessel. The reclaimer cost is a function of the

sorbent makeup flow rate.

• Sorbent Processing: The sorbent processing area primarily consists of a sorbent

cooler, MEA storage tank, and a mixer. The regenerated sorbent is further cooled with

the sorbent cooler and MEA added to make up for sorbent losses. This area is a

function of the sorbent makeup flow rate.

• CO2 Drying and Compression Unit: The product CO2 must be separated from the

water vapor (dried) and compressed to liquid form in order to transport it over long

distances. The multi-stage compression unit with inter-stage cooling and drying yields


a final CO2 product at the nominal pressure of 2000 psig. This area is a function of the

CO2 flow rate.

• Auxiliary Gas Boiler: An auxiliary natural gas boiler is typically combined with a

steam turbine to generate some additional power and/or low pressure steam. The cost

is a function of the steam flow rate generated by the boiler. The boiler cost is lower if

electricity is not being produced.

• Auxiliary Steam Turbine: The steam turbine is used in conjunction with the natural

gas boiler to generate some additional power and/or low pressure steam. The cost is a

function of the secondary power generated by the turbine.

5.2.2.8.2. Ammonia System (CCS System)

The ammonia-based CO2 scrubber is a post-combustion capture technology. It may be used in the


5.2.2.8.2.1. Ammonia System Diagram

This diagram gives an overview of the ammonia system. This diagram does not contain any



CCS System (Ammonia): Ammonia System Diagram


5.2.2.8.2.2. Config


• System Used: The type of absorber used. Ammonia is currently the only option.















• CO2 Product Compressor Used: A CO2 product compressor is used by default.












Storage: CCS System (Ammonia): Config










gas bypass.














CCS System (Ammonia): Performance



• Maximum CO2 Removal Efficiency: This parameter specifies the maximum


limit in calculating the actual CO2 removal efficiency for compliance.


absorber alone.

• Other Removals:


efficiency is 1005%.


efficiency is 99.5%.

◦ NO2 Removal Efficiency: A small amount of NO2 is removed. The default

efficiency is 0%.

◦ HCl Removal Efficiency: HCl is removed at a high rate. The default efficiency

is 95%.

◦ Particulate Removal Efficiency: Particulates are removed in any wet scrubbing


• Trace Removals:

◦ Mercury Removal Efficiency (oxidized)

◦ Mercury Removal Efficiency (elemental)

• Maximum Train CO2 Capacity: The default maximum train size is used with the

actual CO2 capture rate to determine the number of trains required.

• Number of Operating Absorbers: This is the total number of operating absorber

vessels. It is determined by the train capacity specified above and is used primarily to

calculate capital costs. The value must be an integer.



• Maximum CO2 Compressor Capacity: (Only shown if a CO2 product compressor is

used.) This is the maximum amount of CO2 product that can be compressed per hour

at the specified pressure (see the storage input screen).

• Number of Operating CO2 Compressors: (Only shown if a CO2 product

compressor is used.) This is the total number of operating CO2 compressors. It is used

primarily to calculate capital costs. The value must be an integer.

• Number of Spare CO2 Compressors: (Only shown if a CO2 product compressor is

used.) This is the total number of spare CO2 compressors. It is used primarily to

calculate capital costs. Up to two spare CO2 compressors may be specified.





• Amine Scrubber Power Requirement: This is the equivalent electrical output of

thermal (steam) energy used for reheat, plus the actual electrical power required for



5.2.2.8.2.4. Capture

The following parameters are shown:

• Absorber

◦ Ammonia Concentration: This is the concentration of reagent in water as

injected into the CO2 absorber.

◦ Overall Ammonia Slip: This is the ammonia slip above the water wash.

◦ Absorber NH3 Slip: This is the ammonia slip above the absorber.

◦ Circulating Water Flow Rate: This is the DCC circulating water flow rate.

◦ Gas Phase Pressure Drop: This is the pressure drop that the flue gas has to

overcome as it passes through a very tall absorber column, countercurrent to the

sorbent flow.

◦ ID Fan Efficiency: The cooled flue gas is pressurized using a flue gas blower

before it enters the absorber. This is the efficiency of the fan/blower to convert

electrical power input into mechanical work output.

• Chiller System

◦ Capture System Cooling Duty: This is the total amount of cooling water

normalized by CO2 product.

◦ Percent Cooling Supply by Chillers: This is the percent of cooling provided by

the chillers, as opposed to external sources.

◦ Power Requirement by Chillers: This is the amount of power required by the

chillers.


CCS System (Ammonia): Capture


• Regenerator

◦ Regeneration Heat Requirement: This is the total amount of heat energy

required in the reboiler for sorbent regeneration.

◦ Regeneration Steam Heat Content: The regeneration heat is provided in the

form of LP steam extracted from the steam turbine (in case of coal-fired power

plants and combined-cycle gas plants), through the reboiler (a heat exchanger). In

case of simple cycle natural gas fired power plants, a heat recovery unit maybe

required. This is the enthalpy or heat content of the steam used for solvent

regeneration.

◦ Heat-to-Electricity Efficiency: (Only shown when an auxiliary boiler is not

used.) This is the efficiency of converting low pressure steam to electricity. The

value reflects the loss of electricity to the base plant when the LP steam is used

for regenerator heat.

◦ Pump Efficiency: This is the efficiency of the solvent circulation pumps.

◦ Percent Solids in Reclaimer Waste: This is the amount of solids typically

present in the reclaimer waste.

5.2.2.8.2.5. T&S Config






cooling.










Storage: CCS System (Ammonia): T&S Config








requires substantial energy, and is a principle contributor to the overall energy penalty



107.



page 90.

5.2.2.8.2.7. O&M Cost


Ammonia system has the following additional inputs at the top of the screen:

• Ammonia Cost: This is the cost of ammonia.

• Water Cost: This is the cost of water.

• Auxiliary CCS Cooling Cost: This is the cost of the auxiliary cooling system needed

when an Air Cooled Condenser is used as the plant cooling system.

• Reclaimer Waste Disposal Cost: The unit cost of waste disposal for the reclaimer

waste.


CCS System (Ammonia): O&M Cost


The following additional inputs are provided at the bottom of the screen:

• Transport and Storage Costs

◦ CO2 Transport Cost (Levelized): This is the cost of moving the CO2 (i.e.,

pipeline, truck) to the place where it will be sequestered.

◦ CO2 Disposal Cost: This is the cost of sequestering the CO2.



costs. The ammonia system has the following capital cost process areas:

• Direct Contact Coolers: A direct contact cooler is a large vessel where the incoming

hot flue gas is placed in contact with cooling water. The cost is a function of the gas

flow rate and temperature of the flue gas.





• Chiller System: The total cost for the Chiller System is based on the chilling loads

required by the ammonia-based CO2 capture system.

• CO2 Absorber Vessel: This includes absorber towers and circulating water pumps.





• Circulation Pumps: This includes solvent circulation pumps and cooling water

circulation pumps.

• Sorbent Regenerator: This includes the CO2 stripper and regeneration reboiler.


CCS System (Ammonia): Retrofit or Adjustment Factors


• Ammonia Water Wash: A water wash is used to remove ammonia from absorber

gasses before they are released to the stack.



• Sorbent Processing and Reclaimer: This section prepares the sorbent for reuse.

• CO2 Drying and Compression Unit: The product CO2 must be separated from the

water vapor (dried) and compressed to liquid form in order to transport it over long



CO2 flow rate.

• NH3 Stripping: This includes the NH3 stripper and cleanup pumps.








5.2.2.8.3. Auxiliary Boiler System

Some of the CO2 capture technologies available in PC and NGCC plants include an option for an

auxiliary natural gas boiler. These screens are shown when an auxiliary boiler is used.

5.2.2.8.3.1. Auxiliary Boiler Diagram

This diagram gives an overview of the auxiliary boiler system. This diagram does not contain

any numbers and is strictly for reference:

Illustration 222: PC: SET PARAMETERS: CO2 Capture,

Transport & Storage: Auxiliary Boiler System: Auxiliary Boiler

Diagram




• Gas Boiler Efficiency: This is the percentage of fuel input energy transferred to

steam in the boiler. The model default is based on standard algorithms described in

the literature. It takes into consideration the energy losses due to inefficient heat

transfer across the preheater, latent heat of evaporation, incomplete combustion,

radiation losses, and unaccounted losses.

• Excess Air: This is the excess theoretical air used for combustion in the auxiliary

boiler.

• Nitrogen Oxide Emission Rate: This parameter establishes the level of NOx

emissions from the boiler. The default value reflects the AP-42 EPA emission factor,

which is a function of boiler firing method and the coal rank. The value is given in

pounds of equivalent NO2 per ton of coal.

• Percent of NOx as NO: This parameter establishes the level of nitric oxide (NO) in

the flue gas stream. The remainder of the total NOx emissions is assumed to be

nitrogen dioxide (NO2). The default parameter reflects the AP-42 EPA emission

factor, which is dependent on the fuel type.

• Thermal Efficiency: This is the thermal efficiency of the auxiliary power system for

electricity generation.

5.2.2.8.4. Chemical Looping (CCS System)

Post-combustion chemical looping uses a calcium looping (CaL) process for CO2 capture. This

process has 2 steps: calcination and carbonation. The calciner heats calcium carbonate (CaCO3),

thereby breaking it down into CaO and CO2. The CO2 is removed for purification and storage.

The CaO is removed from the calciner and fed to the carbonator, which cools it and exposes it to

the flue gas. The CaO combines with the CO2 in the flue gas to produce CaCO3, thereby reducing

the concentration of CO2 in the flue gas.

Illustration 223: PC: SET PARAMETERS: CO2 Capture, Transport & Storage


5.2.2.8.4.1. Chemical Looping Diagram

This diagram gives an overview of the chemical looping system. This diagram does not


5.2.2.8.4.2. Air Separation Diagram

This diagram gives an overview of the chemical looping system's air separation unit. This

diagram does not contain any numbers and is strictly for reference:


CCS System (Chemical Looping): Chemical Looping Diagram

Illustration 225: PC: SET PARAMETERS: CO2 Capture,

Transport & Storage: CCS System (Chemical Looping): Air

Separation Diagram


5.2.2.8.4.3. Heat Recovery System Diagram

This diagram gives an overview of the chemical looping system's heat recovery system. This

diagram does not contain any numbers and is strictly for reference:


CCS System (Chemical Looping): Heat Recovery System Diagram


5.2.2.8.4.4. Chemical Looping Config

This screen allows you to configure the chemical looping system:


• System Used: Limestone is currently the only option.

• Calciner Oxy-combustion Fuel: Coal is currently the only option.

• CO2 Product Compressor Used: Determines whether a CO2 product compressor is

used.









• SO2 Polisher Used: (PC plants only) This parameter determines whether or not an

SO2 polisher is used to reduce the flue gas SO2 concentration. Standard wet FGD or

sprayer units do not reduce the SO2 concentration sufficiently. If an SO2 polisher is

used, the following parameter is also displayed:



required.


Storage: CCS System (Chemical Looping): Chemical Looping Config












gas bypass.












5.2.2.8.4.5. Air Separation Config

This screen allows you to configure the chemical looping system's air separation unit:


• Oxidant (Ox) Composition

o Oxygen (O2): This is the percent of oxygen that is in the oxidant that is

produced by the air separation unit.

o Argon (Ar): This is the percent of argon that is in the oxidant that is



Storage: CCS System (Chemical Looping): Air Separation Config


o Nitrogen (N2): This is the percent of nitrogen that is in the oxidant that is


• Final Oxidant Pressure: The final oxidant stream from the ASU can be provided at a

high pressure. The default value is determined by the plant type being used.

• Maximum Train Capacity: The maximum production rate of oxidant is specified

here. It is used to determine the number of operating trains required.

• Number of Operating Trains: This is the total number of operating trains. It is used


• Number of Spare Trains: This is the total number of spare trains. It is used primarily

to calculate capital costs. The value must be an integer.

• ASU Power for Calciner Heating: This is the electric power use of ASU that is

employed to generate pure O2 for burning to generate heat required for calciner.







absorber alone.

• Limestone Purity: This is the purity of the limestone used.

• Other Removals:

◦ SO2 Removal Efficiency: This parameter measures the percent of SO2 removed

by the CO2 capture system. The default efficiency is 100%.


CCS System (Chemical Looping): Performance




◦ NO2 Removal Efficiency: This parameter measures the percent of NO2 removed


◦ HCl Removal Efficiency: This parameter measures the percent of HCl removed


◦ Particulate Removal Efficiency: This parameter measures the percent of

particulates removed by the CO2 capture system. The default efficiency is 0%.



input screen).



integer.




• Makeup H2O Factor for Aux. Cooling: (Only shown when an Air-Cooled

Condenser is used for plant cooling.) When CCS and an Air-Cooled Condenser are



• Calcium Looping Power Requirement: This is the electrical power required for the

chemical looping system.

5.2.2.8.4.7. Carbonator


• Carbonator Temperature: This is the carbonator reactor temperature.

• Degree of Carbonation: This is the ratio of the loading difference in the carbonator

to the maximum loading difference.

• Makeup Limestone/Recirculating Sorbent: This is the ratio of makeup sorbent to

recirculating sorbent.


CCS System (Chemical Looping): Carbonator


• Maximum CaO Conversion: This is the maximum possible fraction of CaO

converted to CaCO3 in the carbonator.

• Actual CaO Conversion: This is the actual fraction of CaO converted to CaCO3 in

the carbonator.

• Residence Time of Solids: This is the residence time of solids in the carbonator.

• Gas Phase Pressure Drop: This is the pressure drop of flue gas in the carbonator.

The flue gas has to be pressurized to overcome this pressure drop, so as to maintain

the gas-flow in the CO2 removal system.

• ID Fan Efficiency: This is the efficiency of the fan used to raise the flue gas pressure.

• Makeup Sorbent Temperature: This is the temperature of the makeup sorbent.

5.2.2.8.4.8. Calciner


• Calciner Temperature: This is the calciner reactor temperature.

• Decree of Calcination: This is the ratio of the loading difference in the calciner to the

maximum loading difference.

• CaCO3 Conversion in Calciner: This is the fraction of CaCO3 in the calciner outlet

stream.

• Residence Time of Solids: This is the residence time of solids in the calciner.

• Gas Phase Pressure Drop: This is the pressure drop of flue gas in the calciner. The

flue gas has to be pressurized to overcome this pressure drop, so as to maintain the

gas-flow in the CO2 removal system.

• Fraction of Gas Recycling: This is the fraction of the gas stream that is recycled.

• Calciner Recycling Stream Temperature: This is the temperature of the recycling

gas stream.

• System Heat Recovery Power: This is the waste heat recovery power credit.

• Capture System Cooling Duty: This is the total amount of cooling water normalized

by CO2 product.


CCS System (Chemical Looping): Calciner


5.2.2.8.4.9. T&S Config






cooling.









• CO2 Compressor Efficiency: (Only shown when a CO2 product compressor is

configured.) This is the effective efficiency of the compressors used to compress CO2 to

the designated pressure.

• CO2 Unit Compression Energy: (Only shown when a CO2 product compressor is

configured.) This is the electrical energy required to compress a unit mass of CO2 product

stream to the designated pressure. Compression of CO2 to high pressures requires

substantial energy and is a principle contributor to the overall energy penalty of a CO2

capture unit in a power plant.


107.



page 90.


Storage: CCS System (Chemical Looping): T&S Config


5.2.2.8.4.11. O&M Cost



• Limestone Cost: This is the cost of limestone.

• Coal Cost: This is the cost of coal.

• Caustic (NaOH) Cost: This is the cost of the caustic (NaOH) in $ per ton.



• Waste Disposal Cost: The unit cost of waste disposal.

• Solid By-product Price: Treated solid wastes are sold as by-product, which is an

income component.







CCS System (Chemical Looping): O&M Cost




costs. The chemical looping system has the following capital cost process areas:

• Carbonator: The carbonator converts CaO and CO2 to CaCO3, thereby reducing the

concentration of CO2 in the flue gas.

• Calciner: The calciner converts CaCO3 to CaO and CO2. The CO2 is sent to storage.

• ASU: The Air Separation Unit (ASU) provides pure oxygen to the calciner.

• Blowers: Blowers are used to offset pressure drops in both the calciner and the

carbonator.

• CO2 Product Compressor: The product CO2 must be separated from the water vapor

(dried) and compressed to liquid form in order to transport it over long distances. The

multi-stage compression unit with inter-stage cooling and drying yields a final CO2

product at the nominal pressure of 2000 psig. This area is a function of the CO2 flow

rate.

• CO2 Purification Unit: The product CO2 is purified before being compressed.

• Coal Handling Equipment for ASU: This is the coal handling equipment used by

the Air Separation Unit (ASU).

• Solids Handling Equipment: This is the solids handling equipment for the calciner

and carbonator.

• Steam Turbine for Power Generation: A steam turbine is used to generate power for

the chemical looping system.


CCS System (Chemical Looping): Retrofit or Adjustment Factors


5.2.2.8.5. Membrane System (CCS System)

This process uses a CO2-permeable membrane to capture CO2.

5.2.2.8.5.1. Config


• CO2 Absorber

o System Configuration: The following options are available:

▪ 2-Step w/ Air Sweep: (This is the default.) Two membrane modules

are used in the system, in which boiler combustion air is used as

sweep gas for one membrane module. The first is a cross-flow

membrane module; the permeate stream from this membrane is sent

to a cryogenic purification unit for further purification and

compression. The second membrane module is a counter-flow

membrane with boiler combustion air used as a sweep gas; the

permeate stream is recycled back to the boiler.

▪ NETL 2-Step w/ Sweep: This is a version of the "2-Step w/ Air

Sweep" configuration which is based on a 2012 NETL study. It is

not a complete model; most performance parameters are read-only,

for reference only.

▪ 2-Stage Cascade: Two membrane modules are used to produce a

CO2-rich permeate stream.

o Membrane Used: This is the type of membrane used. "Polymer" is currently

the only option available.

o CO2 Product Compressor Used?: (Not shown for 2-Step w/ Air Sweep)

The CO2 product stream must be compressed into supercritical phase for

transport to a sequestration site. This parameter determines whether or not a


Storage: CCS System (Membrane): Config


CO2 product compressor is used. A CO2 product compressor is always used

in the "NETL 2-Step w/ Sweep" configuration; this parameter is only shown

for reference in that case.

o CO2 Purification Config: (Only shown for 2-Step w/ Air Sweep) This

parameter determines the purity of the CO2 product stream. The following

options are available:

▪ Low Purity

▪ ~95% Purity

▪ 99.99% Purity: This is the default.

▪ NETL Case 5A

o SO2 Polisher Used?: (Only editable in 2-Stage Cascade) This parameter

determines whether or not an SO2 polisher is used to reduce the flue gas SO2

concentration. Standard wet FGD or sprayer units do not reduce the SO2

concentration sufficiently.

o SO2 Polisher Outlet Concentration: (Only shown when an SO2 polisher is

used.) This is the SO2 concentration exiting the polisher, if one is in use. This

value is used to determine the amount of reagent required. This parameter is

only editable in the "2-Stage Cascade" configuration.

o Flue Gas Bypass Control: (Only shown for 2-Stage Cascade) This popup

selection menu controls whether or not a portion of the inlet flue gas may

bypass the scrubber and recombine with the treated flue gas. Bypass allows

the scrubber to operate at full efficiency while allowing some of the flue gas

to go untreated. Two choices are available: No Bypass and Bypass. The no

bypass option is the default and forces the entire flue gas to pass through the

scrubber. The bypass option allows for the possibility of a portion of the flue

gas to bypass the scrubber. The amount of bypass is controlled by several

additional input parameters described below.

• Flue Gas Bypass: (Only available for 2-Stage Cascade) These parameters control the

amount of bypass. They are only displayed if bypass is chosen above:

o Maximum CO2 Removal Efficiency: This parameter specifies the

maximum efficiency possible for the absorber on an annual average basis.

The value is used as a limit in calculating the actual CO2 removal efficiency

for compliance.

o Overall CO2 Removal Efficiency: This value is the CO2 removal efficiency

required for the entire power plant to meet the CO2 emission constraint set

earlier. It is used to determine the actual flue gas bypass.

o Absorber CO2 Removal Efficiency: This is the actual removal efficiency of

the absorber alone. It is a function of the CO2 emission constraint and the

actual flue gas bypass.

o Minimum Bypass: This specifies the trigger point for allowing flue gas to

bypass the scrubber. No bypass is allowed until the allowable amount

reaches the minimum level set by this parameter.

o Allowable Bypass: This is the amount of flue gas that is allowed to bypass

the scrubber, based on the actual and maximum performance of the CO2

removal. It is provided for reference only. The model determines the bypass

that produces the maximum CO2 removal and compares this potential bypass

with the minimum bypass value specified above. Bypass is only allowed

when the potential bypass value exceeds the minimum bypass value.


o Actual Bypass: This displays the actual bypass being used in the model. It is


5.2.2.8.5.2. Membrane System Diagram

This diagram gives an overview of the membrane system. This diagram does not contain any



CCS System (Membrane): Membrane System Diagram (2-Step w/ Air Sweep)


CCS System (Membrane): Membrane System Diagram 2-Stage Cascade)




• Maximum CO2 Removal Efficiency: (Only shown for 2-Stage Cascade) This

parameter specifies the maximum efficiency possible for the absorber on an annual

average basis. The value is used as a limit in calculating the actual CO2 removal

efficiency for compliance.

• CO2 Removed in Cross-flow Membrane: (Not shown for 2-Stage Cascade) This is

the CO2 removal efficiency of the cross-flow membrane. It is shown for reference

only.

• Absorber CO2 Removal Efficiency: (Only shown for 2-Stage Cascade) This is the

actual removal efficiency of the absorber alone.

• CO2 Removed in Counter-current Membrane (%): (Not shown for 2-Stage

Cascade) This parameter is only shown for reference in the "NETL 2-Step w/ Sweep"

configuration. In the "2-Step w/ Air Sweep" configuration, it has the following

options:

◦ 90: This is the default.

◦ 50

• CO2 Removed in Membrane System: (Only shown for 2-Step w/ Air Sweep) This is

the CO2 removal efficiency of the membrane system alone, excluding the CPU. This

value is shown for reference only.

• Overall Plant CO2 Removal Efficiency: (Only shown for 2-Step w/ Air Sweep) This

is the overall CO2 removal efficiency of the membrane system. This value is shown

for reference only.


CCS System (Membrane): Performance


• Other Removals:





◦ NO2 Removal Efficiency: This parameter measures the percent of NO2 removed


◦ HCl Removal Efficiency: This parameter measures the percent of HCl removed


◦ Particulate Removal Efficiency: This parameter measures the percent of

particulate removed by the CO2 capture system. The default efficiency is 100%.

◦ Mercury Removal From CO2 Absorber: This parameter measures the percent

of mercury removed by the CO2 capture system. The default is 0%.

• Makeup H2O Factor for Aux. Cooling: (Only shown when an Air-Cooled

Condenser is used for plant cooling.) When CCS and an Air-Cooled Condenser are



• Membrane Separation Power Requirement: This is the electrical power required

for the membrane system.

5.2.2.8.5.4. Capture

5.2.2.8.5.4.1. 2-Step w/ Air Sweep


• Membrane Operation Temperature: This is the operation temperature of the

membrane system.


CCS System (Membrane): Capture (2-Step w/ Air Sweep)


• CO2 Permeance (S.T.P.): This is the CO2 permeance.

• CO2/N2 Selectivity (S.T.P.): This is the CO2/N2 selectivity.

• CO2/H2O Selectivity (S.T.P.): This is the CO2/H2O selectivity.

• CO2/O2 Selectivity (S.T.P.): This is the CO2/O2 selectivity.

• CO2/Ar Selectivity (S.T.P.): This is the CO2/Ar selectivity

• Stage Cut @ Crossflow: This is the fraction of feed gas that permeates the cross-

flow membrane.

• Stage Cut @ Counterflow: This is the fraction of feed gas that permeates the

counter-flow membrane.

• Pressure Drop @ Crossflow: This is the feed-side pressure drop in the cross-flow

module. This value is shown for reference only.

• Vacuum Pressure in Cross-Flow Membrane: This is the permeate-side vacuum

pressure in the cross-flow module.

• Vacuum Pump Efficiency: This is the efficiency of the permeate-side vacuum

pump.

• Added Cooling Duty for CO2 Capture: This is the total amount of cooling water


5.2.2.8.5.4.2. NETL 2-Step w/ Sweep

The following parameters are shown; most are for reference only:


membranes.

• CO2 Permeance (S.T.P.): This is the CO2 permeance.

• CO2/N2 Selectivity (S.T.P.): This is the CO2/N2 selectivity.


CCS System (Membrane): Capture (NETL 2-Step w/ Sweep)


• CO2/H2O Selectivity (S.T.P.): This is the CO2/H2O selectivity.

• CO2/O2 Selectivity (S.T.P.): This is the CO2/O2 selectivity.

• CO2/Ar Selectivity (S.T.P.): This is the CO2/Ar selectivity.

• Stage Cut @ Crossflow: This is the fraction of feed gas that permeates the cross-

flow membrane.

• Stage Cut @ Counterflow: This is the fraction of feed gas that permeates the

counter-flow membrane.

• Pressure Drop on Flue Gas: This is the feed-side pressure drop in the cross-flow

module.

• Pressure Drop on Sweep Side: This is the sweep-side pressure drop in the

counter-flow module.

• Vacuum Pressure in Cross-Flow Membrane: This is the permeate-side vacuum

pressure in the cross-flow module.

• Added Cooling Duty for CO2 Capture: This is the total amount of cooling water

normalized by CO2 product. This is the only editable parameter on this screen.

5.2.2.8.5.4.3. 2-Stage Cascade



membrane system.

• Ideal CO2 Permeance (S.T.P.): This is the ideal CO2 permeance of the

membranes.


CCS System (Membrane): Capture (2-Stage Cascade)


• Ideal CO2/N2 Selectivity (S.T.P.): This is the ideal CO2/N2 selectivity of the

membranes.

• Percent of Ideal CO2 Permeance: This is the percent of ideal CO2 permeance that

is actually achieved.

• Percent of Ideal CO2/N2 Selectivity: This is the percent of ideal CO2/N2

selectivity that is actually achieved.

• Permeate-side Pressure: This is the permeate-side pressure in the membrane

module.

• Pressure Ratio at Stages 1 and 2: This is the feed vs. permeate side pressure ratio

across the membrane. It is shown for reference only.

• Feed-Side Pressure: This is the feed-side pressure in the membrane module. It is

shown for reference only.

• Stage Cut at 1st Stage: This is the fraction of feed gas that permeates the first

membrane. This value is shown for reference only.

• Stage Cut at 2nd Stage: This is the fraction of feed gas that permeates the second

membrane. This value is shown for reference only.

• Feed-side Compressor Efficiency: This is the efficiency of the feed-side

compressor.

• Vacuum Pump Efficiency: This is the efficiency of the permeate-side vacuum

pump.

• Expander Efficiency: This is the efficiency of the expander.

• Capture System Cooling Duty: This is the total amount of cooling water



5.2.2.8.5.5. Purification

This screen is only shown in the "2-Step w/ Air Sweep" configuration:

The following parameters are shown, depending on the purify selected earlier:

• CO2 Recovery Rate: This parameter is shown for reference only in the "Low Purity"

configuration. In the "~95% Purity" and "99.99% Purity" configurations, the

minimum, maximum and actual CO2 recovery rates are shown below this parameter.

The actual recovery rate will be different from the specified rate if the specified rate is

out of range.

• CO2 Product Purity: This parameter is shown for reference only in the "Low Purity"

and "99.99% Purity" configurations. In the "~95% Purity" configuration, the

minimum, maximum and actual purity are shown below this parameter. The actual

purity will be different from the specified purity if the specified purity is out of range.

• CO2 Product Pressure: The product CO2 must be separated from the water vapor




rate.

• CO2 Compressor Efficiency: (Not shown for NETL Case 5A) This is the compressor

efficiency.

• Unit CPU Energy: This is the electrical energy required to purify a unit mass of CO2

product stream.

• CPU Energy: This is the total energy required to purify the CO2 product.

• Cooling Duty for CO2 Compr.: (Only shown for NETL Case 5A) This is the cooling

duty for the CO2 compression.


CCS System (Membrane): Purification


• Overall CPU Cooling Duty: (Only shown for NETL Case 5A) This is the cooling

duty for the cryogenic purification unit (CPU).

• Unit CPU Cost (PFC): (Only shown for NETL Case 5A) This is the cost, in 2007 US

Dollars, of purifying a unit mass of CO2 product.

5.2.2.8.5.6. T&S Config




• CO2 Product Stream: (Not shown for 2-Step w/ Air Sweep) The concentrated CO2

product stream obtained from sorbent regeneration is compressed and dried using a multi-

stage compressor with inter-stage cooling.







using compressors before it is transported is about 2000 psig. This parameter is shown

for reference only in the "NETL 2-Step w/ Sweep" configuration.


This parameter is shown for reference only in the "NETL 2-Step w/ Sweep"

configuration.










107.


Storage: CCS System (Membrane): T&S Config




page 90.

5.2.2.8.5.8. O&M Cost



• Membrane Module Cost: This is the cost of a membrane module per unit of

membrane area.

• Membrane Material Life: This is the lifetime of membrane material in years.

• Membrane Material Replacement Cost: This is the cost of replacing membrane

material per unit of membrane area.



• Caustic (NaOH) Cost: (Only shown for 2-Stage Cascade) This is the cost of the

caustic (NaOH) in $ per ton.







CCS System (Membrane): O&M Cost




costs. We do not recommend using the "2-Step w/ Air Sweep" or "NETL 2-Step w/ Sweep"

configurations for retrofit analysis. The membrane system has the following capital cost

process areas:

• Membrane Module: (Not shown for NETL 2-Step w/ Sweep) This is the direct cost

of the membrane module.

• Membrane Frame: (Not shown for NETL 2-Step w/ Sweep) This is the direct cost of

the membrane frame structure.

• Compressors: (Only shown for 2-Stage Cascade) This is the direct cost of the feed-

side compressors.

• Expander: (Only shown for 2-Stage Cascade) This is the direct cost of the expander.

• Vacuum Pumps: (Not shown for NETL 2-Step w/ Sweep) This is the direct cost of

the permeate-side vacuum pumps.

• Heat Exchangers: (Only shown for 2-Stage Cascade) This is the direct cost of the

heat exchangers.

• CO2 Drying and Compression Unit: (Only shown for 2-Stage Cascade) CO2 is dried

and compressed to liquid form for transport over long distances.

• CO2 Cryogenic Purification Unit: (Only shown for 2-Step w/ Air Sweep) The CPU

purifies, dries and compresses the CO2.

• CO2 Removal System: (Only shown for NETL 2-Step w/ Sweep) This is the direct

cost of the CO2 removal system.

• CO2 Compression: (Only shown for NETL 2-Step w/ Sweep) This is the direct cost

of the CO2 compression system.

5.2.2.8.6. Solid Sorbents PSA (CCS System)

This is a solid sorbents-based pressure swing adsorption (PSA) system for CO2 removal.

5.2.2.8.6.1. Solid Sorbents PSA

This diagram gives an overview of the solid sorbents PSA system. This diagram does not



CCS System (Membrane): Retrofit or Adjustment Factors


5.2.2.8.6.2. Config


• CO2 Absorber

◦ Solid Sorbent Type: The following options are available:

▪ ZIF-78 (This is the default.)

▪ SU-MAC

▪ Zeolite 5A

◦ System Configuration: The following options are available:

▪ Single Stage PSA (This is the default.)

▪ Two Stage PSA

◦ CO2 Product Compressor Used: The CO2 product stream may need to be


whether or not a CO2 product compressor is used. A CO2 product compressor is

used by default.


CCS System (Solid Sorbents PSA): Solid Sorbents PSA


Storage: CCS System (Solid Sorbents PSA): Config


◦ Flue Gas Bypass Control: This popup selection menu controls whether or not a

portion of the inlet flue gas may bypass the scrubber and recombine with the

treated flue gas. Bypass allows the scrubber to operate at full efficiency while

allowing some of the flue gas to go untreated. Two choices are available: No

Bypass and Bypass. The no bypass option is the default and forces the entire flue

gas to pass through the scrubber. The bypass option allows for the possibility of a

portion of the flue gas to bypass the scrubber. The amount of bypass is controlled

by several additional input parameters described below.

◦ SO2 Polisher Used: This parameter determines whether or not an SO2 polisher is

used to reduce the flue gas SO2 concentration. Standard wet FGD or sprayer units

do not reduce the SO2 concentration sufficiently to the designated level for

carbon capture pre-treatment. If an SO2 polisher is used, the following parameter

is also displayed:

▪ SO2 Polisher Outlet Concentration: This is the SO2 concentration exiting

the polisher, if one is in use. This value is used to determine the amount of

reagent required. The default is based on the sorbent.









◦ Minimum Adsorber CO2 Removal Efficiency: This is the minimum CO2

removal efficiency that will allow the model to run correctly. It is shown for

reference only.



gas bypass.


















• Minimum Adsorber CO2 Removal Efficiency: This is the minimum CO2 removal

efficiency that will allow the model to run correctly. It is shown for reference only.

• Adsorber CO2 Removal Efficiency: This is the actual removal efficiency of the

adsorber alone.

• Other Removals:

◦ SO2 Removal Efficiency: This is the SO2 removal efficiency of the PSA process.

◦ SO3 Removal Efficiency: This is the SO3 removal efficiency of the PSA process.

◦ NO2 Removal Efficiency: This is the NO2 removal efficiency of the PSA

process.

◦ HCl Removal Efficiency: This is the HCl removal efficiency of the PSA

process.

◦ Particulate Removal Efficiency: This is the particulate removal efficiency of the

PSA process.

◦ Mercury Removal from CO2 Adsorber: This is the mercury removal efficiency

of the adsorber alone.





• PSA Process Power Requirement: This is the electrical power required by the PSA

process


CCS System (Solid Sorbents PSA): Performance


5.2.2.8.6.4. Capture


• Adsorber Temperature: This is the operating temperature of the adsorber.

• Adsorber Pressure: This is the operating pressure of the adsorber.

• Desorption Pressure: This is the pressure at which desorption occurs.

• Sorbent Degradation Rate: This is the sorbent degradation rate.

• Sorbent Replacement Rate: This is the annual sorbent replacement rate.

• Flue Gas Compressor Efficiency: This is the efficiency of the flue gas compressor.

• Vacuum Pump Efficiency: This is the efficiency of the vacuum pump.

• Expander Efficiency: This is the efficiency of the expander.

• Capture System Cooling Duty: This is the amount of cooling water needed,



CCS System (Solid Sorbents PSA): Capture


5.2.2.8.6.5. T&S Config






cooling.








◦ CO2 Product Purity before CPU: This is the percentage of the product entering the

CPU that is carbon dioxide.

◦ Minimum CO2 Product Purity after CPU: This is the minimum percentage of the

product leaving the CPU that is carbon dioxide.

◦ CO2 Recovery Rate by CPU: This is the rate at which CO2 is recovered by the

cryogenic purification unit (CPU).










107.


Storage: CCS System (Solid Sorbents PSA): T&S Config




page 90.

5.2.2.8.6.7. O&M Cost


Solid Sorbents TSA system has the following additional inputs at the top of the screen:

• MOF Sorbent Cost: This is the cost of the sorbent.









CCS System (Solid Sorbents PSA): O&M Cost




costs. The solid sorbents PSA system has the following capital cost process areas:

• Flue Gas Cooler and Condenser: This is the cooler and condenser for inlet flue gas.

• PSA System: This is a fixed-bed PSA system.









• Exhaust Flue Gas Expander: This is the expander for flue gas exiting the PSA

system.

• Vacuum Pump: This is the vacuum pump used for the CO2 product stream.

• Compressing CO2 Product Stream: The CO2 product stream is compressed to

atmospheric pressure from vacuum.

• CO2 Purification and Compression: A cryogenic purification unit (CPU) is used to

purify, dry and compress the CO2 in preparation for transport.

5.2.2.8.7. Solid Sorbents TSA (CCS System)

This is a solid sorbents-based temperature swing adsorption (TSA) system for CO2 removal.


CCS System (Solid Sorbents PSA): Retrofit or Adjustment Factors


5.2.2.8.7.1. Solid Sorbents TSA Diagram

This diagram gives an overview of the solid sorbents TSA system. This diagram does not


5.2.2.8.7.2. Config - Capture


CCS System (Solid Sorbents TSA): Solid Sorbents TSA Diagram


Storage: CCS System (Solid Sorbents TSA): Config - Capture



• System Used: "CCSI/NETL 32D" is currently the only choice.















• CO2 Product Compressor Used: The CO2 product stream may need to be


whether or not a CO2 product compressor is used. If a CO2 product compressor is

used, the following parameter is also shown:

◦ Compressor Type: If a CO2 product compressor is used, this parameter

determines whether it is a 6- or 8-stage compressor.

• Direct Contact Cooler (DCC) Used?: A DCC is configured by default to cool the

flue gas before it enters the solid sorbents TSA system. The lower flue gas

temperature enhances the absorption reaction and decreases the flue gas volume. The

typically acceptable range of flue gas temperature is about 120-140ºF. A DCC is often

not needed if a wet FGD is installed upstream.

• SO2 Polisher Used: This parameter determines whether or not an SO2 polisher is used

to reduce the flue gas SO2 concentration. Standard wet FGD or sprayer units do not

reduce the SO2 concentration sufficiently to the designated level for carbon capture

pre-treatment. If an SO2 polisher is used, the following parameter is also displayed:



required. The default is based on the sorbent.

• Temperature Exiting DCC: (Only displayed when a DCC is used.) This is the

temperature exiting the DCC. The desirable temperature of the flue gas entering the

CO2 capture system is about 113-122ºF. If the inlet temperature to the DCC is at or

below this temperature, the DCC is not used.

• Sorbent Properties

◦ Name: "NETL 32D" is currently the only option.

◦ Specific Heat: This is the specific heat of the sorbent.

• Langmuir (single-site) Model Parameters

◦ Maximum CO2 Adsorption Capacity: This is the maximum CO2 adsorption

capacity of the sorbent.

◦ Water Effect on CO2 Capacity: This is the effect of water on the CO2

adsorption capacity of the sorbent. It is added to the parameter above.


◦ Langmuir Parameter: This is the Langmuir constant.

◦ Heat of Reaction: This is the heat of reaction.

5.2.2.8.7.3. Config - Bypass








bypass the scrubber. The following parameters control the amount of bypass. They are

only displayed if bypass is chosen above:









gas bypass.













Storage: CCS System (Solid Sorbents TSA): Config - Bypass








absorber alone.

• SO2 Removal Efficiency: SO2 is removed at a very high rate. The default efficiency

is 99.5%.

• SO3 Removal Efficiency: SO3 is removed at a very high rate. The default efficiency

is 99.5%.

• NO2 Removal Efficiency: A small amount of NO2 is removed. The default efficiency

is 0%.

• HCl Removal Efficiency: HCl is removed at a high rate. The default efficiency is

95%.

• Particulate Removal Efficiency: Particulates are removed in any wet scrubbing


• Adsorber Max Heat Transfer Area: This is the maximum heat transfer area in the

adsorber.

• Number of Operating Adsorbers: This is the total number of operating adsorber

vessels. It is used primarily to calculate capital costs. The value must be an integer.


CCS System (Solid Sorbents TSA): Performance


• Number of Spare Adsorbers: This is the total number of spare adsorber vessels. It is


• Regenerator Max Heat Transfer Area: This is the maximum heat transfer area in

the regenerator

• Number of Operating Regenerators: This is the total number of operating

regenerators. It is used primarily to calculate capital costs. The value must be an

integer.

• Number of Spare Regenerators: This is the total number of spare regenerators. It is

used primarily to calculate capital costs. Up to two spare regenerators may be

specified.



input screen).



integer.








• Solid Sorbents TSA Power Requirement: This is the electrical power required for

the solid sorbents TSA system.


5.2.2.8.7.5. Capture - Adsorber


• Reactor Type: "2-stage Bub. FB" is currently the only option.

• Adsorber Operating Temperature: This is the operating temperature of the

adsorber.

• SO2 Sorbent Loading: This is the SO2 sorbent loading.

• Rich Sorbent Loading: This is the rich sorbent loading, estimated based on detailed

data from CCSI.

• Approach to Equilibrium: This is the ratio of rich sorbent loading to rich sorbent

loading at equilibrium expressed as a percentage.

• Water Vapor Captured: This is the percentage of water vapor captured.

• Makeup Sorbent: This is the amount of makeup sorbent required.

• Adsorber Heat Transfer Coefficient: This is the heat transfer coefficient of the

adsorber.

• Pressure Drop in Adsorber: This is the pressure drop in the adsorber.

• ID Fan Efficiency: This is the efficiency of the ID fans.

• Cold Side Heat Exchanger Heat Transfer Coeff.: This is the heat transfer

coefficient of the cold-side head exchanger.

• Cold Side Heat Exchanger Exit Temp*: This is the outlet temperature of the cold-

side heat exchanger. The minimum, maximum, and actual values used for this

parameter are shown below it. The actual value (the value used) may be different

from the specified value if the specified value is out of range.)


CCS System (Solid Sorbents TSA): Capture - Adsorber


5.2.2.8.7.6. Capture - Regenerator


• Reactor Type: "Moving Bed" is currently the only option.

• Regenerator Operating Temperature: This is the operating temperature of the

regenerator.

• Regenerator Equilibrium CO2 Pressure: This is the CO2 partial pressure in the

product stream.

• Lean Sorbent Loading: This is the sorbent loading of CO2 after the regenerator. It

determines the amount of sorbent needed to remove sufficient CO2.

• Approach to Equilibrium: This is the ratio of lean sorbent loading to lean sorbent

loading at equilibrium expressed as a percentage.

• Water Vapor Regenerated: This is the percentage of captured water vapor that is

regenerated.

• Regenerator Heat Transfer Coefficient: This is the heat transfer coefficient of the

regenerator.

• Regenerator Heat Requirement: This is the heat required for regeneration of the

loaded sorbent.

• Regenerator Steam Heat Content: Low pressure steam is extracted from the base

plant at approximately 400C/0.4 MPa to use for regenerator heat. This is the heat

content of that steam.

• Heat-to-Electricity Efficiency: This is the efficiency of converting low pressure

steam to electricity.


CCS System (Solid Sorbents TSA): Capture - Regenerator


• Hot Side Heat Exchanger Heat Transfer Coeff.: This is the hot-side heat transfer

coefficient of a heat exchanger.

• Hot Side Heat Exchanger Exit Temp.*: This is the outlet temperature of the hot-side

heat exchanger. The minimum, maximum, and actual values used for this parameter

are shown below it. The actual value (the value used) may be different from the

specified value if the specified value is out of range.)

• Solids Conveyor Systems Energy Use: This is the energy used for the conveyor belts

that move solids through the system.

• Capture System Cooling Duty: This is the amount of cooling water needed,


5.2.2.8.7.7. T&S Config






cooling.

◦ Water in CO2 Product: The amount of moisture in the CO2 product stream.













Storage: CCS System (Solid Sorbents TSA): T&S Config





requires substantial energy and is a principle contributor to the overall energy penalty



107.



page 90.

5.2.2.8.7.9. O&M Cost


Solid Sorbents TSA system has the following additional inputs at the top of the screen:

• Sorbent Cost: This is the cost of the sorbent.

• Caustic (NaOH) Cost: This is the cost of the caustic (NaOH) in $ per ton.

• Water Cost: Water is mainly required for cooling and also as process makeup. Cost

of water may vary depending upon the location of the power plant.

• Auxiliary Gas Cost: This is the cost of natural gas. It is only visible if an auxiliary

boiler is specified.




CCS System (Solid Sorbents TSA): O&M Cost


• Reclaimer Waste Disposal Cost: The unit cost of waste disposal for the reclaimer

waste.








costs. The solid sorbents TSA system has the following capital cost process areas:

• CO2 Absorber Vessel: This area deals with the absorber. The capital cost of the

absorber will go down with higher MEA concentration and higher CO2 loading level

of the solvent, and lower CO2 content in the lean solvent.

• Sorbent Regenerator: This area deals with the sorbent regenerator. The regenerator

(or stripper) is a column where the weak intermediate compound (carbamate) is

broken down by the application of heat. The result is the release of CO2 (in

concentrated form) and return of the recovered sorbent back to the absorber. This

process is accomplished by the application of heat using a heat exchanger and low-

pressure steam. MEA requires substantial heat to dissociate the carbamate. Therefore,

a flash separator is also required, where the CO2 is separated from the moisture and

evaporated sorbent to produce a concentrated CO2 stream.

• Heat Exchangers: This area deals with the heat exchangers. The CO2-loaded sorbent

must be heated in order to strip off CO2 and regenerate the sorbent. In addition, the

regenerated sorbent must be cooled down before it can be recirculated back to the

absorber column. Heat exchangers are used to accomplish these two tasks. This area

is a function of the sorbent flow rate.


CCS System (Solid Sorbents TSA): Retrofit or Adjustment Factors


• Sorbent Handling: This area deals with the sorbent handling. The sorbent processing

area primarily consists of a sorbent cooler, MEA storage tank, and a mixer. The

regenerated sorbent is further cooled with the sorbent cooler and MEA added to make

up for sorbent losses.

• Circulation Pumps: This area deals with the circulation pumps. Circulation pumps

are required to take the sorbent, introduced at atmospheric pressure, and lift it to the

top of the absorber column. This area is a function of the sorbent flow rate.

• CO2 Drying and Compression: This area deals with the CO2 drying and

compression. The product CO2 must be separated from the water vapor (dried) and

compressed to liquid form in order to transport it over long distances. The multi-stage

compression unit with inter-stage cooling and drying yields a final CO2 product at the

nominal pressure of 2000 psig. This area is a function of the CO2 flow rate.

• Flue Gas Blower: This area deals with the flue gas blower. The flue gas enters the

bottom of the absorber column and flows upward, countercurrent to the sorbent flow.

Blowers are required to overcome the substantial pressure drop as it passes through a

very tall absorber column. The cost is a function of the volumetric flow rate of the

flue gas.

• Sorbent Storing: This area deals with the sorbent storing. A portion of the sorbent

stream is distilled in the reclaimer in order to avoid accumulation of heat stable salts

in the sorbent stream. Caustic is added to recover some of the MEA in this vessel. The

reclaimer cost is a function of the sorbent makeup flow rate.

• Steam Extractor: This area deals with the steam extractor. Steam extractors are

installed to take low pressure steam from the steam turbines in the power plant. The

cost is a function of the steam flow rate.

• Direct Contact Cooler: This area deals with the direct contact cooler. A direct

contact cooler is typically used in plant configurations that do not include a wet FGD.

A direct contact cooler is a large vessel where the incoming hot flue gas is placed in

contact with cooling water. The cost is a function of the gas flow rate and temperature

of the flue gas.

• Cyclone Bank: This area deals with the cyclone bank. The regenerator is connected

to a reboiler, which is a heat exchanger that utilizes low pressure steam to heat the

loaded sorbent. The reboiler is part of the sorbent regeneration cycle. The cost is a

function of the sorbent and steam flow rates.

• Auxiliary Gas Boiler: This area deals with the auxiliary gas boiler. An auxiliary

natural gas boiler is typically combined with a steam turbine to generate some

additional power and/or low pressure steam. The cost is a function of the steam flow

rate generated by the boiler. The boiler cost is lower if electricity is not being

produced.

• Auxiliary Steam Turbine: This area deals with the auxiliary steam turbine. The

steam turbine is used in conjunction with the natural gas boiler to generate some

additional power and/or low-pressure steam. The cost is a function of the secondary

power generated by the turbine.

• Steam Compressor: This area deals with the steam compressor. Water and steam are

used to transfer heat between the heat exchangers.

5.2.2.8.8. Air Separation Unit

See "5.4.2.3. Air Separation Unit" on page 455 for a description of the screens in this process

type.


5.2.2.8.9. FG Recycle & Purification

Oxyfuel is a post-combustion technology used for CO2 capture. It is sometimes referred to as

"O2-CO2 Recycle". Two systems are associated with this technology, Air Separation and Flue Gas

Recycle. The following sections describe the input screens for the Flue Gas Recycle System.

Please refer to the air separation chapter "5.4.2.3. Air Separation Unit" on page 455) for help with

the oxidant feed input parameters.

5.2.2.8.9.1. Diagram

This diagram gives an overview of the flue gas recycle and purification system. This diagram

does not contain any numbers and is strictly for reference:

5.2.2.8.9.2. Config

• Is this a Retrofit Unit?: The user may decide whether the unit is added to a new or

existing plant.

• CO2 Purification Config: This parameter determines the purity of the CO2 product

stream. The following options are available:

◦ Low Purity

◦ ~95% Purity

◦ 99.99% Purity: (This is the default.)


Storage: FG Recycle & Purification: Diagram


Storage: FG Recycle & Purification: Config


◦ NETL Case 5A

5.2.2.8.9.3. FG Recycle

• Flue Gas Recycle Stream

◦ Flue Gas Recycled: This is the percentage of the total flue gas that is to be

recycled.

◦ Maximum Recycle Moisture: This is the maximum amount of moisture in

combined recycle.

◦ Particulate Removal Efficiency: This is the percentage of particulates that are

removed by the Flue Gas Recycle system.

◦ Flue Gas Cooling Power Requirement: This is the percentage of the total gross

power of the plant required to cool the flue gas being recycled.

◦ DCCPS Exit Temperature: This is the temperature of the gas streams exiting

the direct contact cooler and polishing systems.

◦ Recycle Fan Pressure Head: A fan is used to provide a small pressure head for

the recycled flue gas stream going back to the boiler. This FGR fan pressure head

along with the recycled flue gas flow rate, determine the power used by the fan.

◦ Recycle Fan Efficiency: This is the efficiency of the fan converting electrical

power input into mechanical work output.

◦ Flue Gas Recycle Power Requirement: This is the percentage of the total gross

power of the plant required to recycle the flue gas.

◦ FGR Cool. Duty Recov. as Heat Integration: This is the fraction of cooling

duty recovered as heat integration.

• Maximum DCC Train Capacity: This is the maximum capacity of a direct contact

cooler train.


Storage: FG Recycle & Purification: FG Recycle


• Number of DCC Trains: This is the number of trains in the direct contact cooler.

• Pressure Drop Across DCC: This is the pressure drop on gas going through the

direct contact cooler.

5.2.2.8.9.4. Purification

Parameters related to the flue gas purification unit are found on this screen. The contents of the

screen vary depending on which configuration was chosen on the "Config" screen earlier. (See

"5.2.2.8.9.2. Config" on page 238.) This screen looks similar for all configurations except

"NETL Case 5A". It looks like this when the "~95%" configuration is chosen:

Each parameter is described below:

• CO2 Recovery Rate: This is the percentage of CO2 recovered by the purification

system. If you have chosen "Low Purity", this parameter will be read-only, for

reference only. If you have chosen "~95% Purity" or "99.99% Purity", this parameter

will be editable, and the following additional values will be shown for reference:

◦ Minimum CO2 Recovery Rate

◦ Maximum CO2 Recovery Rate

◦ Actual CO2 Recovery Rate: This is the CO2 recovery rate which will be used by

the model. The CO2 recovery rate is required be within the range specified by the

previous two parameters. If the value you specified is in range, it will be used. If

not, the maximum or minimum value will be used, depending on whether the

value you specified is above or below the range.

• CO2 Product Purity: This is the percentage of the product that is carbon dioxide. If

you have chosen "Low Purity" or "99.99% Purity", this parameter will be read-only,


Storage: FG Recycle & Purification: Purification (~95%)


for reference only. If you have chosen "~95% Purity", this parameter will be editable,

and the following additional values will be shown for reference:

◦ Minimum CO2 Product Purity

◦ Maximum CO2 Product Purity

◦ Actual CO2 Product Purity: This is the CO2 product purity which will be used

by the model. The CO2 product purity is required to be within the range specified

by the previous two parameters. If the value you specified is in range, it will be

used. If not, the maximum or minimum value will be used, depending on whether

the value you specified is above or below the range.

• Maximum CO2 Train Capacity: This is the maximum capacity of a CO2 train.

• Number of Trains: This is the number of CO2 trains.

• CO2 Product Pressure: The CO2 product may have to be carried over long distances.

Hence it is necessary to compress (and liquefy) it to very high pressures, so that it

may be delivered to the required destination in liquid form and (as far as possible)

without recompression facilities en route. The critical pressure for CO2 is about 1070

psig. The typically reported value of final pressure to which the product CO2 stream

has to be pressurized using compressors, before it is transported is about 2000 psig.

• CO2 Compressor Efficiency: This is the effective efficiency of the compressors used

to compress CO2 to the designated pressure.

• Unit CPU Energy: This is the electrical energy required to purify a unit mass of CO2

product stream.


If you have chosen the "NETL Case 5A" configuration, the "Purification" input screen will

look like this:


• CO2 Recovery Rate: Unlike the other configurations, the value you specify here will

be assumed to be in range and will be used without further checking.


FG Recycle & Purification: Purification (NETL Case 5A)


• CO2 Product Purity: This is the percentage of the product that is carbon dioxide.

Unlike the other configurations, the value you specify here will be assumed to be in

range and will be used without further checking.

• CO2 Product Pressure: The CO2 product may have to be carried over long distances.

Hence it is necessary to compress (and liquefy) it to very high pressures, so that it

may be delivered to the required destination in liquid form and (as far as possible)

without recompression facilities en route. The critical pressure for CO2 is about 1070

psig. The typically reported value of final pressure to which the product CO2 stream

has to be pressurized using compressors, before it is transported is about 2000 psig.

• Unit CPU Energy: This is the electrical energy required to purify a unit mass of CO2.


• Cooling Duty for CO2 Compr.: This is the cooling duty for the CO2 compressor.

• Overall CPU Cooling Duty: This is the overall cooling duty for the cryogenic

purification system.

• Unit CPU Cost: This is the cost, in 2007 US Dollars, of purifying a unit mass of CO2

product.

5.2.2.8.9.5. T&S Config

This screen allows you to choose the CO2 transport and storage methods as described in

"5.1.4.3. T&S Config" on page 107.



page 90.


5.2.2.8.9.7. O&M Cost



• Miscellaneous Chemicals Cost: This is the annual cost of chemicals that are used in

the Flue Gas Recycle area of the plant. The cost is reported in dollars per ton of CO2

captured.

• Wastewater Treatment Cost: This is the annual cost of treating the wastewater that

is used in the Flue Gas Recycle area of the plant. The cost is reported in dollars per

ton.


• CO2 Transportation Cost (Levelized): Transportation of CO2 product is assumed to

take place via pipelines. This is the unit cost of CO2 transport in $/ton –mile.

• CO2 Storage Cost: This is the unit cost of CO2 disposal. Depending upon the method

of CO2 disposal or storage, either there may be some revenue generated (Enhanced

Oil Recovery) which may be treated as a “negative cost”, or additional cost (all other

disposal methods).


Storage: FG Recycle & Purification: O&M Cost




costs. The O2-CO2 recycle system has the following capital cost process areas:

• Boiler Modifications: In case of a pre-existing PC plant being retrofitted for CO2

capture, the boiler must be modified to suit the new oxyfuel combustion system. The

cost for these modifications is estimated as a percentage of the cost of the boiler.

• Flue Gas Recycle Fan: The cost of the fan required for recycling part of the flue gas

is scaled on the basis of the flow rate of the flue gas being recycled.

• Flue Gas Recycle Ducts: Additional ducting is necessary to recycle part of the flue

gas in the oxyfuel combustion system. The cost of this ducting is assumed to be a

function of the flow rate of recycled flue gas.

• Direct Contact Cooler: The cost of the flue gas cooler is scaled on the basis of the

flow rate of the flue gas.

• CO2 Cryogenic Purification Unit: The CPU purifies, dries, and compresses the CO2

product stream for transport over long distances.

5.2.2.8.10. Pipeline Transport

The CO2 Transport System models the transport via pipeline of carbon dioxide (CO2) captured at

a power plant from plant site to sequestration site. It is shown when "Pipeline" is chosen as the

CO2 transport method and is available in all plant types.

5.2.2.8.10.1. Pipeline Transport Diagram

This diagram gives an overview of the pipeline transport system. This diagram does not



FG Recycle & Purification: Retrofit or Adjustment Factors


Storage: Pipeline Transport: Pipeline Transport Diagram


5.2.2.8.10.2. Config

Each configuration parameter is described briefly below:

• Pipeline Region: The capital (labor portion) and O&M costs are dependent on the US

region of the country where the pipeline is built. These regions are based on the EIA

natural gas pipeline regions. Possible values are:

◦ Central US

◦ Midwest US (This is the default.)

◦ Northeast US

◦ Southeast US

◦ Southwest US

◦ Western US

• Total Pipeline Length: This is the total length of the pipe between the plant site and

the sequestration site.

• Net Pipeline Elevation Change (Plant->Inj.): The pipeline may traverse hilly

terrain; this is the overall elevation change from plant site to injection site.

• Number of Booster Stations: The cost of CO2 transport may be lowered by adding

booster stations for longer pipeline lengths. This is the number of those stations that

are to be modeled.

• Compressor/Pump Driver: This is the type of motor that drives the compressor or

pump; electric, diesel or natural gas.

• Booster Pump Efficiency: This is the efficiency of the pump, and accounts for all

frictional losses.


Pipeline Transport: Config


• Design Pipeline Flow (% plant cap): This is the flow of liquid CO2 that the pipeline

has been designed to handle as a percent of the total that the plant is capable of

producing.

• Actual Pipeline Flow: This is the amount of liquid CO2 that flows through the

pipeline in tons per year.

• Inlet Pressure (@ power plant): The inlet pressure is shown here for reference only

and may be modified in the parameters for the CO2 capture device (e.g., amine

scrubber, Selexol scrubber)

• Min. Outlet Pressure (@ storage site): This the minimum outlet pressure of the CO2

at the storage site.

• Average Ground Temperature: This is the average temperature of the ground where

the pipeline will traverse.

• Pipe Material Roughness: The roughness measure is the average size of the bumps

on the pipe wall, for commercial pipes this is usually a very small number. Note that

perfectly smooth pipes would have a roughness of zero.

5.2.2.8.10.3. Financing

• Year Costs Reported: This is the year in which all costs are given or displayed, both

in the input screens and the results. A cost index is used by the IECM to scale all costs

to the cost year specified by this parameter.

• Discount Rate (Before Taxes): This is also known as the cost of money. Discount

rate (before taxes) is equal to the sum or return on debt plus return on equity, and is

the time value of money used in before-tax present worth arithmetic (i.e.,

levelization).

• Fixed Charge Factor (FCF): This parameter, also known as the capital recovery

factor, is used to find the uniform annual amount needed to repay a loan or investment

with interest. It is one of the most important parameters in the IECM. It determines

the revenue required to finance the power plant based on the capital expenditures. Put

another way, it is a levelized factor which accounts for the revenue per dollar of total

plant cost that must be collected from customers in order to pay the carrying charges

on that capital investment.

• Inflation Rate: This is the rise in price levels caused by an increase in the available

currency and credit without a proportionate increase in available goods or services. It

does not include real escalation.



page 90.


Pipeline Transport: Financing


5.2.2.8.10.5. O&M Cost

Inputs for operation and maintenance are entered on the O&M Cost input. O&M costs are

typically expressed on an average annual basis and are provided in either constant or current

dollars for a specified year, as shown on the bottom of the screen.


• Booster Pump Operating Cost: This is the cost of operating a booster pump as a

percent of the process facilities capital.

• Fixed O&M Cost: These are the operating and maintenance fixed costs including all

maintenance materials and all labor costs and is given in dollars per mile of pipeline

per year.



costs. The CO2 transport system has the following capital cost process areas:

• Material Cost: This includes the cost of line pipe, pipe coatings, and cathodic

protection.

• Labor Costs: This covers the cost of labor during pipeline construction.

• Right-of-way Cost: This is the cost of obtaining right-of-way for the pipeline. This

cost not only includes compensating landowners for signing easement agreements but

landowners may be also be paid for loss of certain uses of the land during and after

construction, loss of any other resources, and any damage to property.

• Booster Pump Cost: This is the total capital cost of a booster pump.

• Miscellaneous Cost: This includes the costs of: surveying, engineering, supervision,

contingencies, telecommunications equipment, freight, taxes, allowances for funds

used during construction (AUFDC), administration and overheads, and regulatory

filing fees.


Storage: Pipeline Transport: O&M Cost


Pipeline Transport: Retrofit or Adjustment Factors


5.2.2.8.11. Pipeline Transport (ERROR)

This process type consists of a single screen which is shown if the inlet pressure is insufficient for

the pipeline model to run:

This screen provides access to some key parameters which may be needed to resolve the

situation. See "5.2.2.8.10. Pipeline Transport" on page 244 above for a description of the

parameters.

5.2.2.8.12. User-Specified Transport

This process type is shown when "User-Specified" is chosen as the CO2 transport method. It is

the same for all plant types. There is only one screen:


Pipeline Transport (ERROR): ERROR


User-Specified Transport: Misc



• Inlet Pressure (@ power plant): This is the inlet pressure for the transport system. It is

determined by the CCS system and will typically be shown on the T&S Config

parameter screen. It is shown here for reference only.

• Outlet Pressure (@ storage site): This is the outlet pressure for the transport system.

• Transportation Cost (Levelized): This is the cost of transporting the CO2.

5.2.2.8.13. CO2 Storage

This process type is shown when "Geologic" is chosen as a CO2 storage method. The screens are

the same for all plant types.

5.2.2.8.13.1. CO2 Storage Diagram

This diagram gives an overview of the CO2 storage system. This diagram does not contain any


5.2.2.8.13.2. Financing


• Year Costs Reported: This is the cost year, set in the overall plant parameters. (See

"5.2.2.1.5. Financing & Cost Year" on page 120.) It is shown here for reference only.


CO2 Storage: CO2 Storage Diagram


CO2 Storage: Financing


• Constant or Current Dollars?: This determines whether constant or current dollars

are used. It is set in the overall plant parameters. (See "5.2.2.1.5. Financing & Cost

Year" on page 120.) It is shown here for reference only.

• Discounting Rate: This is the discount rate as set in the overall plant parameters. (See

"5.2.2.1.5. Financing & Cost Year" on page 120.) It is set to the overall plant discount

rate by default; however, you may override it here if needed.

5.2.2.8.13.3. Reservoir

This screen allows you to select the reservoir used for CO2 storage and edit its properties:

You may look up and/or save reservoirs in a database as described in "4.3.3.4. The Database

Button" on page 67. Or, if you prefer, you may enter or edit the properties directly on this

screen.

The following information is displayed at the top of the screen to help identify the reservoir:

• Name: This is the name of the reservoir.

• Source: The model provides the values for default reservoir properties; these can be

used "as is" or modified and used. Modified reservoirs maybe stored in a new database

or an existing database. Source displays the database file from which the data was

retrieved or indicates that the data has been entered by the user.

The remainder of the screen contains the reservoir properties:

• State: This is the state in which the reservoir is located.

• Reservoir Depth: This is the depth of the reservoir.

• Reservoir Thickness: This is the useable (net pay) thickness of the reservoir.

• Reservoir Horizontal Permeability: This is the horizontal permeability of the

reservoir.

• Reservoir Porosity: This is the porosity of the reservoir.

• Storage Coefficient: This is the storage coefficient of the reservoir.


CO2 Storage: Reservoir


• Reservoir Surface Temperature: This is the temperature at the top of the reservoir.

• Geographical Area for CO2 Storage: This is the size of the geographical area that

defines the reservoir.


The following parameters are displayed:

• Performance Model: There are two models available: Law & Bachu, and Advanced

Research Institute. Law & Bachu is the default.

• Project Average Injection Rate: This is the project average injection rate per year.

• Design Maximum Injection Rate: This is the maximum injection rate per well per

year.

• Monitoring Well Density

o Wells in Reservoir: This is the density of monitoring wells in the reservoir.

o Wells Above Seal: This is the density of monitoring wells above the seal.

o Wells that are Dual Completed: This is the density of dual completion

monitoring wells.

o Wells Groundwater: This is the number of groundwater monitoring wells.

o Wells Vadose Zone: This is the number of monitoring wells in the vadose

zone.

o Dual Completed Wells in Reservoir: This is the percentage of dual

completion wells in the reservoir.

• Margins

o AOR Margin 3D: This is the 3D allowable operating region (AOR) margin

for the reservoir.


CO2 Storage: Performance


5.2.2.8.13.5. Pre-injection Cost


• Regional Evaluation Duration: This is the number of years required for a regional

evaluation.

• Site Characterization Duration: This is the number of years required for site

characterization.

• Permitting Duration: This is the number of years required for permitting.

The remainder of the parameters are described in "5.1.1.1. Capital Cost Inputs" on page 90.

5.2.2.8.13.6. Operations Cost


CO2 Storage: Pre-injection Cost


CO2 Storage: Operations Cost



• Operation Duration: This is the number of years of operation.

• Contingency Factor: This is the operation process contingency factor.

• Geophysical Survey: 3D Seismic: This is the cost of 3D seismic monitoring.

• Labor Rates: These are the labor rates for the personnel associated with the reservoir.

o Geologist

o Engineer

o Landman

• Miscellaneous Operations: This is a miscellaneous operations cost, expressed as a

percentage of the annual operations cost (based on the net present value). The total

operations cost is the sum of the two.

5.2.2.8.13.7. Post-injection Cost


• PISC and Site Closure Duration: This is the number or years required for post-

injection site care (PISC) and site closure.

• Well Seismic: VSP Tool Costs: This is the cost of vertical seismic profile (VSP)

tools.

• Miscellaneous PISC and Site Closure: This is a miscellaneous PISC and site closure

cost, expressed as a percentage of the annualized PISC and site closure cost (based on

the net present value). The total annualized PISC and site closure cost is the sum of

the two.

5.2.2.9. Water Systems

5.2.2.9.1. Hybrid Cooling System

A hybrid cooling system uses both closed-loop dry and wet units. Dry and wet cooling units are

arranged in parallel that splits the steam flow between air-cooled condensers (ACC) and a surface

condenser coupled with a wet tower unit. The dry cooling unit employs ACC and is primarily

used to serve the steam cycle. When the ambient air temperature reaches higher levels than the

design, and the dry cooling unit cannot maintain a low turbine exhaust pressure, part of the

exhaust steam is routed to the supplemental wet unit. See "5.2.2.9.2. Air Cooled Condenser or

Dry Unit" on page 255 and "5.2.2.9.3. Wet Cooling Tower or Wet Unit on page 259.

The hybrid cooling system may be used in all plant types.


CO2 Storage: Post-injection Cost


5.2.2.9.1.1. Diagram

This diagram gives an overview of the hybrid cooling system. It does not contain any numbers


5.2.2.9.1.2. Seasons

This screen specifies the summer and non-summer seasons:


• Summer

o Ambient Air Temp (Dry Bulb Avg.): This is the average dry bulb

temperature during the summer months.

o Avg. Air Relative Humidity: This is the average relative humidity during

the summer months.

Illustration 283: PC: SET PARAMETERS: Water Systems: Hybrid

Cooling System: Diagram


Cooling System: Seasons


o Air Wet Bulb Temp (Avg.): This is the average wet bulb temperature during

the summer months. It is calculated based on the dry bulb temperature and

the humidity. It is shown for reference only.

o Ambient Air Pressure (Avg.): This is the average ambient air pressure

during the summer months.

o Duration of Summer: This is the number of summer months in the year.

• Non-Summer

o Peak Season Ambient Air Temp (Dry Bulb): This is the highest dry bulb

temperature during the non-summer months.

o Avg. Air Relative Humidity: This is the average relative humidity during

the non-summer months.

o Air Wet Bulb Temp (Avg.): This is the average wet bulb temperature during

the non-summer months. It is calculated based on the dry bulb temperature

and the humidity. It is shown for reference only.

o Ambient Air Pressure (Avg.): This is the average ambient air pressure

during the non-summer months.

5.2.2.9.2. Air Cooled Condenser or Dry Unit

The air cooled condenser is available in all plant types. It may be configured as a standalone

system or as the dry unit of a hybrid cooling system.

5.2.2.9.2.1. Air Cooled Condenser

This diagram gives an overview of the air cooled condenser. It does not contain any numbers


5.2.2.9.2.2. Config

Inputs for configuration of the Air Cooled Condenser are entered on this screen:

Illustration 285: PC: SET PARAMETERS: Water

Systems: Air Cooled Condenser



• Condenser Type: This menu controls the configuration of the condenser. In practice,

there are two condenser types (Single Row or Multiple Row). There is only a

Multiple-Row condenser modeled in the current version.

• Configuration: This menu shows the geometry of the dry cooling system framework.

An air cooled condenser is comprised of fin tube bundles grouped together in parallel

and arranged typically in an A-frame configuration. The A-Frame configuration

usually has an apex angle of 60º. This is currently the only option available.


Inputs for performance of the Air Cooled Condenser technology are entered on this screen:


• Air Cooled Condenser

◦ Peak Ambient Air Temp (Dry Bulb): (Not shown for hybrid cooling systems.)

This refers basically to the ambient air temperature measured by a thermometer.

This input specifies the peak ambient temperature.

Illustration 286: PC: SET PARAMETERS: Water Systems: Air Cooled

Condenser: Config


Condenser: Performance


◦ Ambient Air Temperature (Dry Bulb Avg.): (Not shown for hybrid cooling

systems.) This refers basically to the ambient air temperature measured by a

thermometer. This input specifies the annual average ambient temperature.

◦ Inlet Steam Temperature: This is the temperature of exhaust steam entering the

air cooled condenser system. It is calculated as a function of the steam turbine

back pressure. The difference between inlet steam and ambient air temperatures

significantly affects the performance and cost of the dry cooling system.

◦ Fan Efficiency: This parameter specifies the electricity efficiency of fan drive

system. That is a percent of electrical power inputs to the fans.

◦ Condenser Plot Area (per cell): This parameter specifies the footprint or plot

area of one cell. One cell typically consists of multiple condenser bundles and is

served by a large axial flow fan located at the floor of each cell.

• Steam Cycle

◦ Turbine Back Pressure: This parameter specifies the quantity of steam turbine

back pressure. For the plant installed with a wet cooling system, the steam back

pressure ranges from 1.5 to 2.0 inches of Mercury (inches Hg) whereas the steam

back pressure for the plant installed with a dry cooling system ranges from 2.0 to

8.0 inches Hg. Turbine back pressure affects the steam cycle heat rate, and

indirectly has an effect on the cooling system size when air cooled condensers are

loaded.

◦ Aux. Heat Exchanger Load: This parameter specifies additional heat load on

the auxiliary condenser and is expressed as a percentage of the load on the

primary condenser.

• Air Cooled Condenser Power Requirement: This parameter specifies the power

needed to operate the big fans in the dry cooling system. It is also referred to as an

energy penalty to the base plant. The electricity required for these big fans is

estimated using the air cooled condenser performance model and is expressed as a

percentage of the gross plant capacity. It is a function of the initial temperature

difference between inlet steam and air and ambient pressure.



page 90.


5.2.2.9.2.5. O&M Cost


following additional input is provided at the top of the screen:

• Waste Disposal Cost: This is the waste disposal cost for the air cooled condenser.


Inputs for capital costs of modifications to process areas to implement the Air Cooled

Condenser are entered on this screen:


costs. The air cooled condenser system has the following capital cost process areas:

• Condenser Structure: This area deals with the air cooled condenser equipment

including finned tube heat exchanger elements, fans and motors, ACC support

structure, steam exhaust duct, piping and valves, air removal equipment and support

for start-up, training, and testing. The erection and installation of the ACC at the site

is also included in this area.


Condenser: O&M Cost


Condenser: Retrofit or Adjustment Factors


• Steam Duct Support: This area deals with steam duct support and column

foundations.

• Electrical & Control Equipment: This area deals with fan, pump motor wiring and

controls, etc.

• Auxiliary Cooling: This deals with separate fin-fan unit or others. Typically, it is 5%

additional heat load.

• Clearing System: This area handles with cleaning finned tube surfaces. It is small but

required at most sites.

5.2.2.9.3. Wet Cooling Tower or Wet Unit

The wet cooling tower is available in all plant types. It may be configured as a standalone system

or as the wet unit of a hybrid cooling system.

5.2.2.9.3.1. Cooling Tower Diagram

This diagram gives an overview of the wet cooling tower. It does not contain any numbers and

is strictly for reference:

Illustration 290: PC: SET PARAMETERS: Water Systems: Wet Cooling Tower:

Cooling Tower Diagram


5.2.2.9.3.2. Slip Stream Diagram

This diagram gives an overview of the slip stream treatment system. It is only shown when the

slip stream treatment system is chosen on the next screen (Config). It does not contain any


5.2.2.9.3.3. Config

Inputs for configuration of the Wet Cooling Tower are entered on this screen:


• Air Flow Draft Control Type: This option determines the type of air flow draft. The

"Forced" draft uses the fan at the intake to force air through the tower. "Forced" is

currently the only option available.

• Slip Stream Treatment System: This option determines whether a slip stream

treatment system is loaded. The choice ("Yes" or "No") of a slip stream treatment

system depends on site-specific quality of cooling water in the closed-loop

recirculating system.

• Makeup Water Treatment System: This option determines whether a makeup water

treatment system is needed. The choice ("Yes" or "No") of a makeup water treatment

system depends on site-specific quality of makeup water for the cooling system.

• Cooling Duty of Wet Unit in Summer: (Only shown for hybrid cooling.) This is the

fraction of total cooling duty assigned to the wet unit in the summer.

Illustration 291: PC: SET PARAMETERS: Water Systems: Wet

Cooling Tower: Slip Stream Diagram


Config



Inputs for performance of the Wet Cooling Tower technology are entered on this screen:


• Ambient Air Temp (Dry Bulb Average): (Not shown for hybrid cooling systems.)

This refers basically to the ambient air temperature measured by a thermometer. This

input specifies annual average ambient temperature.

• Air Wet Bulb Temperature (Average): (Not shown for hybrid cooling systems.)

This refers to the temperature of air that is cooled adiabatically to saturation at a

constant pressure by evaporation of water into it. That is calculated in terms of

ambient dry bulb temperature and humidity. That is the lowest temperature that can be

reached by evaporating water into the air.

• Cooling Water Inlet Temperature: This is the temperature of the cooling water

entering the wet tower.

• Cooling Water Temperature Drop: This parameter specifies the temperature drop

range of cooling water across the wet tower.

• Cycles of Concentration: This is a measure of the degree to which dissolved solids

are being concentrated in the circulating water and is estimated in terms of

concentration ratio of dissolved solids in the circulating versus makeup water. It is

reversely related to the blowdown. Improving the quality of makeup water for the

cooling system can increase the cycle of concentration and decrease the amount of

tower blowdown.

• Tower Drift Loss: This parameter specifies a percent of the quantity of cooling water

as drift loss.

Illustration 293: Wet Cooling Tower- Performance Input Screen


• Auxiliary Cooling Load: This parameter specifies additional heat load on the

auxiliary equipment and is expressed as a percentage of the load on the primary steam

cycle. The default value comes from the PISCES model.

• Tower Overdesign Factor: This parameter overdesigns the wet tower size.

• Slip Stream Treatment System: These parameters are only shown when the slip

stream treatment system is selected on the "Config" screen. (See "5.2.2.9.3.3. Config"

on page 260.)

◦ Slip Stream Inlet: This parameter specifies the underflow as a percent of the

quantity of cooling water. This option is only available when the Slip Stream

Treatment System is loaded.

◦ Slip Stream Underflow: This parameter specifies the underflow as a percent of

the quantity of slip stream. This option is only available when the Slip Stream

Treatment System is loaded.

• Cooling Makeup Treatment System: These parameters are only shown when the

makeup water treatment system is selected on the "Config" screen. (See

"5.2.2.9.3.3. Config" on page 260.)

◦ Cooling Makeup Underflow: This parameter specifies the underflow as a

percent of the quantity of entering water treated. This option is only available

when the Makeup Water Treatment System is loaded.

◦ Alum Dosage (Coagulant): (Not shown for hybrid cooling systems.) This is the

alum dosage for makeup water treatment.

• Power Requirement: This is the power needed to run the pumps and other equipment

for the water cooling system. It is also referred to as an energy penalty. In PC power

plants, it is expressed as a percentage of the gross plant capacity. In IGCC plants, it is

calculated based on the steam turbine power output and expressed as a scaled

percentage of the total gross power outputs including the gas and steam turbines.



page 90.


5.2.2.9.3.6. O&M Cost




• Alum Cost: This is the cost of alum in dollars per ton.

• Waste Disposal Cost: This is the waste disposal cost for the wet tower.


Inputs for capital costs of modifications to process areas to implement the Wet Cooling Tower

are entered on this screen:


O&M Cost





costs. The wet cooling tower has the following capital cost process areas:

• Cooling Tower Structure: This area deals with the cooling tower and installation.

The erected tower includes structure, fans, motors, gear boxes, fill, drift eliminators,

etc.

• Circulation Pumps: This area deals with the circulating cooling water pumps.

• Auxiliary Systems: This area deals with a closed-loop process that utilizes a higher

quality water to remove heat from ancillary equipment and transfers that heat to the

main circulating cooling water system.

• Piping: This area deals with the circuiting cooling water piping. The piping system is

equipped with butterfly isolation valves and all required expansion joints.

• Makeup Water System: This area deals with the capital equipment to provide

makeup water for the cooling system.

• Component Cooling Water System: This area deals with the component cooling

water system.

• Foundation & Structures: This area deals with the circulating water system

foundation and structures.

5.2.2.10. By-Prod. Mgmt

These screens display and design the management of by products and waste disposal.

5.2.2.10.1. Bottom Ash Pond Diagram

This diagram gives an overview of the bottom ash pond. It does not contain any numbers and is

strictly for reference:

Illustration 296: PC: SET PARAMETERS: By-

Prod. Mgmt: Bottom Ash Pond Diagram


5.2.2.10.2. Fly Ash Disposal Diagram

(Only shown when particulate control is configured and fly ash is not mixed with FGD wastes or

bottom ash.) This diagram gives an overview of the fly ash disposal. It does not contain any


5.2.2.10.3. Flue Gas Treatment Diagram

(Only shown when Wet FGD is configured.) This diagram gives an overview of the flue gas

treatment system. It does not contain any numbers and is strictly for reference:

Illustration 297: PC: SET

PARAMETERS: By-Prod. Mgmt: Fly

Ash Disposal Diagram

Illustration 298: PC: SET PARAMETERS:

By-Prod. Mgmt: Flue Gas Treatment

Diagram


5.2.2.10.4. Bottom Ash Performance

The following parameter is available on this screen:

• Water Content of Residue: This is the ultimate water content of disposed ash residue in

the ash pond.

5.2.2.10.5. Wastewater Treatment Diagram

(Only shown when wastewater treatment is chosen.) This diagram gives an overview of the

wastewater treatment system. It does not contain any numbers and is strictly for reference.

This screen is shown for chemical treatment:

Illustration 299: PC: SET PARAMETERS: By-Prod. Mgmt: Bottom Ash

Performance

Illustration 300: PC: SET PARAMETERS: By-Prod.

Mgmt: Wastewater Treatment Diagram (chemical

treatment)


This screen is shown for mechanical treatment:

5.2.2.10.6. Wastewater Treatment Perf.

The following parameters are available on this screen:

• Fireside Cleaning Wastewater: This is the fireside washing wastewater volume rate.

• Air Preheater Cleaning Wastewater: This is the air preheater cleaning wastewater

volume rate.

• Floor & Yard Drain Wastewater: This is the floor and yard drain wastewater volume

rate.

• Average Annual Rainfall: This is the average yearly rainfall. It is used in calculating

the amount of runoff from the coal pile.

• Coal Pile Height: This is the height of the coal pile. It is used in calculating the amount

of runoff from the coal pile.

Illustration 301: PC: SET

PARAMETERS: By-Prod. Mgmt:

Wastewater Treatment Diagram

(mechanical treatment)

Illustration 302: PC: SET PARAMETERS: By-Prod. Mgmt: Wastewater

Treatment Perf.


5.2.2.10.7. Chemical Treatment Perf.

This screen is only shown when chemical treatment is selected:


• Lime Dosage (Precipitator): This is the lime dosage for precipitation.

• Alum Dosage (Coagulant): This is the alum dosage for coprecipitation as coagulants.

• Polymer Dosage: This is the polymer dosage for the precipitation process.

• Sludge Production: This is the production rate of sludges that are generated from the

precipitation process.

• Sludge Solids Content: This is the sludge solids concentration by weight.

• Rapid Mix Time: This is the rapid mix time.

• Flocculator Time: This is the flocculator time.

• Clarifier Overflow: This is the clarifier overflow rate.

• Power Requirement: This is the power needed to run the chemical treatment system. It

is also referred to as an energy penalty. It is expressed as a percentage of the gross plant

capacity.

5.2.2.10.8. Vapor Comp/Evap Perf.

This screen is only shown when mechanical treatment is selected:

Illustration 303: PC: SET PARAMETERS: By-Prod. Mgmt: Chemical

Treatment Perf.

Illustration 304: PC: SET PARAMETERS: By-Prod. Mgmt: Vapor Comp/Evap

Perf.



• Brine Solid Content Limit: This is the total solids limit in the brine.

• Influent Solid Content Limit: This is the total solids limit in the influent.

• Power Requirement: This is the power needed to run the vapor

compression/evaporation system. It is also referred to as an energy penalty. It is

expressed as a percentage of the gross plant capacity.


This screen is only shown when one of the wastewater treatment options (chemical or

mechanical) is chosen. It applies to the wastewater treatment system.


90.

5.2.2.10.10. O&M Cost


mechanical) is chosen. It applies to the wastewater treatment system:



• Lime Cost: The cost of lime in dollars per ton.

• Alum Cost: The cost of alum in dollars per ton.

• Flocculant Polymer Cost: The cost of flocculant polymer in dollars per ton.

• Waste Disposal Cost: This is the waste disposal cost for the wastewater treatment

system.

Illustration 305: PC: SET PARAMETERS: By-Prod Mgmt: O&M Cost




mechanical) is chosen. Inputs for capital costs of modifications to process areas to implement the

wastewater treatment system are entered on this screen:


costs. The wastewater treatment systems have the following capital cost process areas:

• Chemical Precipitation: This is the chemical treatment system.

• Vapor Compression Evaporation: This is the mechanical (VCE) treatment system.

5.2.2.11. Water Life Cycle Assessment

This section evaluates the water use associated with all the major stages of electricity generation,

including fuel acquisition, processing and transport, power plant operation, production of chemicals

used in power plants, and power plant infrastructure.

There are two types of parameters and results:

• Water Withdrawal: This is the total amount of water removed from a water source. Some

of this water may be returned to the source for later reuse.

• Water Consumption: This is the amount of water consumed that is not returned to the

water source, mainly because of evaporation and other losses.

This technology is available for PC and NGCC plants. It is controlled by the "Water Life Cycle

Enabled?" parameter on the overall plant performance screen. (See "5.2.2.1.2. Performance" on page

116 for PC plants, "5.3.2.1.2. Performance" on page 424 for NGCC plants.) The screens for both

plant types are described below.

Illustration 306: PC: SET PARAMETERS: By-Prod Mgmt: Retrofit or

Adjustment Factors


5.2.2.11.1. Coal

This screen is only shown for PC plants:


• Fuel Extraction Method: Coal can be extracted by surface mining or underground

mining. Surface mining is the default.

• Fuel Transport Method: Coal can be transported by train or slurry pipeline. Train is the

default.

• Fuel Extraction: The following parameters specify the water needed for coal extraction:

o Water Withdrawal Factor: This parameter measures the water withdrawal

intensity in gallons of water per ton of coal extracted.

o Water Consumption Factor: This parameter measures the water consumption

intensity in gallons of water per ton of coal extracted.

• Fuel Processing: The following parameters specify the water needed for coal

processing:


intensity in gallons of water per ton of coal processed.


intensity in gallons of water per ton of coal processed.

• Fuel Transport: The following factors specify the water needed for coal transport:


intensity in gallons of water per ton of coal transported.


intensity in gallons of water per ton of coal transported.

5.2.2.11.2. Natural Gas

This screen is shown for both PC and NGCC plants:

Illustration 307: PC: SET PARAMETERS: Water Life Cycle Assessment: Coal



• Fuel Extraction Method: Natural gas can be extracted by conventional drilling or

hydraulic fracturing. Conventional drilling is the default.

• Fuel Transport Method: Natural gas can be transported by pipeline or as Liquefied

natural gas (LNG). Pipeline is the default.

• Fuel Extraction: The following parameters specify the water needed for natural gas

extraction:


intensity in gallons of water per volume (MMscf) of natural gas extracted.


intensity in gallons of water per volume (MMscf) of natural gas extracted.

• Fuel Processing: The following parameters specify the water needed for natural gas

processing:


intensity in gallons of water per volume (MMscf) of natural gas processed.


intensity in gallons of water per volume (MMscf) of natural gas processed.

• Fuel Transport: The following parameters specify the water needed for natural gas

transport:


intensity in gallons of water per volume (MMscf) of natural gas transported.


intensity in gallons of water per volume (MMscf) of natural gas transported.

Illustration 308: PC: SET PARAMETERS: Water Life Cycle Assessment:

Natural Gas


5.2.2.11.3. Plant Infrastructure


The following parameters specify the water required for plant infrastructure:

• Water Withdrawal Factor: This parameter measures the water withdrawal intensity for

manufacturing of many components (e.g., coal and sorbent handling systems, and

combustion turbines) and plant construction in gallons of water per megawatt hour of


• Water Consumption Factor: This parameter measures the water consumption intensity

for manufacturing of many components (e.g., coal and sorbent handling systems, and

combustion turbines) and plant construction in gallons of water per megawatt hour of


5.2.2.11.4. Plant Operation


The following parameters specify the water required for plant operation:

• Water Withdrawal Factor: This parameter measures the water withdrawal intensity for

generating electricity in gallons of water per megawatt hour of electricity generation.

• Water Consumption Factor: This parameter measures the water consumption intensity

for generating electricity in gallons of water per megawatt hour of electricity generation.

Illustration 309: PC: SET PARAMETERS: Water Life Cycle Assessment: Plant

Infrastructure

Illustration 310: PC: SET PARAMETERS: Water Life Cycle Assessment: Plant

Operation


5.2.2.11.5. Chemical Production



• Ammonia: The following parameters specify the water used in ammonia production:


intensity in gallons of water per pound of ammonia production.


intensity in gallons of water per pound of ammonia production.

• Limestone: The following parameters specify the water used in limestone production:


intensity in gallons of water per pound of limestone production.


intensity in gallons of water per pound of limestone production.

• Amine (30-wt% MEA): The following parameters specify the water used in amine

production:


intensity in gallons of water per pound of amine production.


intensity in gallons of water per pound of amine production.

5.2.3. GET RESULTS


The result screens described in the following sections are available when "Combustion (Boiler)" is

selected as the plant type from the "New Session" pull down menu. These screens apply to the

power plant as a whole, not to specific technologies.

Illustration 311: PC: SET PARAMETERS: Water Life Cycle Assessment:

Chemical Production


5.2.3.1.1. Diagram

This is the same diagram that appears in the "SET PARAMETERS" program area. See

"5.2.2.1.1. Diagram" on page 116 for its description.

5.2.3.1.2. Plant Performance

This screen displays performance results for the plant as a whole. Heat rates and power in and out

of the power plant are given. The performance parameters in the table on the left are described in

"5.1.4.2. Plant Performance" on page 105.

The plant energy requirements in the table on the right provide a breakdown of the internal power

consumption for the individual technology areas. These are all given in units of megawatts.

Individual plant sub-components will only be displayed when they are configured in the

Configure Plant section of the model. The following results are shown in the table on the right:



information to calculate key mass flow rates. The value is an input parameter.

• Auxiliary Power Produced: (Only shown when a CO2 capture system with an option

for an auxiliary boiler is in use.) This is the additional power produced by the auxiliary

boiler. It will be zero if no auxiliary boiler is configured.

• Component Electrical Uses: Power used by various plant and pollution control

equipment is reported in the middle portion of the second column. The number

displayed varies as a function of the components configured in the power plant.


plus any auxiliary electrical output minus the losses due to plant equipment and

pollution equipment (energy penalties). This is the same value used in the first column.

• Amine Steam Use (Elec. Equiv.): (Only shown when an amine-based CO2 capture

system is in use without an auxiliary boiler.) This is the electrical equivalent energy for

the regeneration steam required by the CO2 capture system. It is taken from the steam

cycle.

Illustration 312: PC: GET RESULTS: Overall Plant: Plant Performance


5.2.3.1.3. Mass In/Out

This screen is described in "5.1.4.1. Mass In/Out" on page 104.

5.2.3.1.4. Solids In/Out

The Solids In/Out result screen displays the values for the flow of the solid components in the gas

and condensed streams throughout the various stages of the power plant. Each result is described

briefly below. Each column represents the flow rate at the exit of the technology specified at the

Illustration 313: PC: GET RESULTS: Overall Plant: Mass In/Out

Illustration 314: PC: GET RESULTS: Overall Plant: Solids In/Out


top of the column. Use the scroll bar at the bottom to see additional columns. Note that the solids

are not reported in this detail inside the technology result screens.

Solid Components:

• Ash: Total mass of ash (primarily solid oxides).

• Lime (CaO): Total mass flow of lime. This is typically added as a reagent and will react

with the flue gas to form another compound.

• Limestone (CaCO3): Total mass flow of limestone. This is typically added as a reagent

and will react with the flue gas to form another compound.

• Calcium Sulfite (CaSO3-0.5H2O): Total mass flow of calcium sulfite, a byproduct of

lime or limestone reacting with sulfur in the flue gas.

• Gypsum (CaSO4-2H2O): Total mass flow of gypsum, a byproduct of lime or limestone

reacting with sulfur in the flue gas.

• Calcium Sulfate (CaSO4): Total mass flow of calcium sulfate, a byproduct of lime or

limestone reacting with sulfur in the flue gas.

• Calcium Chloride (CaCl2): Total mass flow of calcium sulfate, a byproduct of lime or

limestone reacting with chlorine or chlorine compounds in the flue gas.

• Miscellaneous (UCB, Sulfur): Total mass flow of other solids in the flue gas. This

includes unburned carbon or unburned sulfur from the boiler.

• Water: Total mass flow of condensed water associated with the solids stream. This is

more clearly represented in what is considered liquid streams. See the Gas In/Out screen,

described in "5.2.3.1.5. Gas In/Out" on page 277, for a summary of the evaporated water

flow rate through the power plant.

5.2.3.1.5. Gas In/Out

Illustration 315: PC: GET RESULTS: Overall Plant: Gas In/Out


The Gas In/Out result screen displays the values for the flow of the gas components in the flue

gas throughout the various stages of the power plant. Each column represents the flow rate at the

exit of the technology specified at the top of the column. Use the scroll bar to view more

columns. These are also reported elsewhere in the particular technology "Flue Gas" result screens

but duplicated here to provide a broad look at gas emissions.

Note that only molar flow rates are shown here; the "Flue Gas" results for the individual

technologies show both molar and mass flow rates.

See "5.1.3.1. Flue Gas Components" on page 101 for a description of the rows.

5.2.3.1.6. Total Capital Cost

This screen consists of two tables. The table on the left contains the Process Facilities Capital

(PFC) for each technology. The technologies (rows) are described in more detail in the next

section, "5.2.3.1.7. Overall Plant Cost" on page 279.

The table on the right contains the capital costs for the entire plant. See "5.1.1.2. Capital Cost

Results" on page 93 for more details on the results provided here.

Illustration 316: PC: GET RESULTS: Overall Plant: Total Capital Cost


5.2.3.1.7. Overall Plant Cost

The Total Cost result screen displays a table which totals the annual fixed, variable, operations,

maintenance, and capital costs associated with the power plant as a whole. The costs summarized

on this screen are expressed on an average annual basis and are provided in either constant or

current dollars for a specified year, as shown on the bottom of the screen.

The technologies (rows) are:

• In-Furnace NOx Control: In-Furnace NOx controls.

• Post-Combustion NOx Control: Post-Combustion NOx removal modules.

• Mercury Control: Mercury control modules.

• TSP Control: Conventional particulate removal modules.

• SO2 Control: SO2 conventional removal modules.

• Combined SOx/NOx: Combined SOx/NOx advanced removal modules.

• CO2 Capture, Transport & Storage: The CO2 capture, transport and storage modules.

• Subtotal: The total of all of the technologies listed above. This is the total abatement

cost. The subtotal is highlighted in yellow.

• Cooling Tower: Cooling tower modules.

• Wastewater Control: Wastewater treatment modules.

• Base Plant: The base plant without consideration of any abatement technologies. This

can be used to compare with other power plant types.

• Land: The total cost of land required for the plant.

• Emission Taxes: The total cost of taxes assessed to stack emissions.

• Total: The total of all modules listed above. This result is highlighted in yellow.

Illustration 317: PC: GET RESULTS: Overall Plant: Overall Plant Cost


The columns correspond with the rows of a standard total cost result table as described in

"5.1.1.7. Total Cost Results" on page 99.

5.2.3.1.8. Cost Summary



year, as shown on the bottom of the screen. The technologies (rows) are described in more detail

in the previous section, "5.2.3.1.7. Overall Plant Cost" on page 279.

See "5.1.1.4. Cost Summary Results" on page 96 for a description of the cost categories

(columns).

5.2.3.2. Fuel

The result screens associated with the Fuel technology display the composition of the fuel(s) used in

the plant. The IECM supports the use of various fuels, ranging from coals of various rank, fuel oil of

various weight, and natural gas of various places of origin.

The combustion model currently supports the use of pulverized coal in the furnace, with natural gas

available as a reburn option to the in-furnace NOx controls and an optional natural gas auxiliary

boiler.

The natural gas combined cycle (NGCC) plant configurations all assume natural gas for fuel.

The integrated gasification combined cycle (IGCC) plant configurations assume coal gasification to

produce a synthetic fuel gas.

Illustration 318: PC: GET RESULTS: Overall Plant: Cost Summary


5.2.3.2.1. Coal (PC) or Diagram (IGCC)

This screen is available in the PC and IGCC plant types:

The Coal Diagram result screen displays fuel composition and flow rate information, which is


• Name: (Only shown for PC plants.) This is the name of the coal being used.

• Source: (Only shown for PC plants.) This is the source of the coal data being used. This

will generally identify which database the coal data came from.

• Rank: This is the rank of the coal based on the higher heating value. This is primarily

determined by the higher heating value and to a lesser degree by the sulfur and ash

content.

• Coal Flow Rate: Coal flow rate into the boiler on a wet basis. Waste products removed

prior to the burners are not considered here.

• The coal properties described in "5.1.2.1. Coal Properties" on page 100 are in the lower

left corner.

• Trace Element Flows: (Only shown in PC plants.) Trace elements are now supported in

the IECM. The mass flow rate is reported in units of pounds per unit of time. All values

reflect the elemental mass flow rate.

◦ Mercury: This is the elemental mercury flow rate in coal.

Illustration 319: PC: GET RESULTS: Fuel: Coal


5.2.3.2.2. Auxiliary Gas (PC) or Diagram (NGCC)

The Natural Gas Diagram result screen displays fuel composition and flow rate information,

which is described briefly below. This screen is available for PC and NGCC plants:

• Gas Flow Rate: The natural gas flow rate to the turbine.

• The natural gas properties described in "5.1.2.2. Natural Gas Properties" on page 101 are

in the lower left corner.

5.2.3.3. Base Plant

The Base Plant Technology Navigation Tab screens display the performance and costs directly

associated with the combustion power plant, particularly the boiler. Pre-combustion and post-

combustion control technologies are not considered part of the Base Plant. The screens described in

this chapter all apply to the PC plant type.

Illustration 320: PC: GET RESULTS: Fuel: Auxiliary Gas


5.2.3.3.1. Boiler

5.2.3.3.1.1. Diagram

This screen displays an icon for the Combustion Boiler and values for major flows in and out

of it:

Each result is described briefly below in flow order (not from top to bottom and left to right as

they display on the screen).

• Fuel Entering Boiler

◦ Fuel In: Fuel flow rate into the boiler on a wet basis. Waste products removed

prior to the burners are not considered here.

◦ Mercury In: This is the mass flow rate of total mercury entering the boiler. The

mass reflects the molecular weight of elemental mercury.

• Boiler Performance

◦ Ash Entering Flue Gas: Percent of the ash in coal exiting the boiler in the flue

gas.

◦ Mercury Removal: Percent of the total mercury in coal removed from the boiler

in the bottom ash.

• Air Entering Boiler

◦ Heated Air In: Volumetric flow rate of the air at the burners, based on the air

temperature at the burners and atmospheric pressure.

◦ Temperature: Heated air temperature measured at the burners. This is generally

determined by the combustion air temperature exiting the air preheater.

• Water

◦ Boiler Makeup: This is the water flow rate into the demineralizer system

(treating boiler makeup water).

◦ Cooling Water: This is the cooling water required for the steam cycle.

• Flue Gas Exiting the Economizer

Illustration 321: PC: GET RESULTS: Base Plant: Boiler: Diagram


◦ Temperature Out: Temperature of the flue gas at the exit of the economizer.

◦ Flue Gas Out: Volumetric flow rate of the flue gas at the exit of the economizer,

based on the temperature at the exit of the economizer and atmospheric pressure.

◦ Fly Ash Out: Total solids mass flow rate in the flue gas at the exit of the

economizer. This includes ash, unburned carbon and unburned sulfur.

◦ Mercury Out: Total mass of mercury exiting the economizer. The value is a sum

of all the forms of mercury (elemental, oxidized, and particulate).

• Bottom Ash

◦ Sluice Water Makeup: Water added to the dry bottom ash. This water is added

for transportation purposes.

◦ Dry Bottom Ash: Total solids mass flow rate of the bottom ash. This includes

ash, unburned carbon and unburned sulfur. The value is given on a dry basis.

◦ Wet Bottom Ash: Total solids mass flow rate of the bottom ash for waste

management. This includes dry bottom ash and sluice water. The value is given

on a wet basis.

5.2.3.3.1.2. Flue Gas

This screen displays a table of quantities of flue gas components entering the combustion

boiler in heated air and exiting the boiler in the flue gas. For each component, quantities are

given in both moles and mass per hour:

See "5.1.3.1. Flue Gas Components" on page 101 for a description of the Major Flue Gas

Components.


Illustration 322: PC: GET RESULTS: Base Plant: Boiler: Flue Gas


This screen displays tables for the direct and indirect capital costs related to the Combustion

Boiler:

This is a capital cost result screen as described in "5.1.1.2. Capital Cost Results" on page 93.

The direct capital costs described here apply to the "base power plant" without any of the

environmental control options that are separately modeled in the IECM. While the purpose of

the IECM is to model the cost and performance of emission control systems, costs for the base

plant are also needed to properly account for pre-combustion control options that increase the

cost of fuel, and affect the characteristics or performance of the base plant. Base plant costs are

also needed to calculate the internal cost of electricity which determines pollution control

energy costs.

Each process area direct capital cost is a reduced-form model based on regression analysis of

data collected from several reports and analyses. They are described in general below. The

primary factors in the model that effect the capital cost of the base plant are the plant size, the

coal rank, and the geographic location of the plant.

• Steam Generator: This area accounts for the steam cycle equipment and pumps.

• Turbine Island: This area accounts for the turbine island and associated pumps.

• Coal Handling: This area accounts for the mechanical collection and transport

equipment of coal in the plant.

• Ash Handling: This area accounts for the mechanical collection and transport of ash

in the plant.

• Water Treatment: This area accounts for the pumps, tanks, and transport equipment

used for water treatment.

• Auxiliaries: Any miscellaneous auxiliary equipment is treated in this process area.

5.2.3.3.1.4. O&M Cost

The O&M Cost result screen displays tables for the variable and fixed operation and

maintenance costs involved with the combustion base plant. The variable O&M costs are

Illustration 323: PC: GET RESULTS: Base Plant: Boiler: Capital Cost


calculated from the variable costs for fuel, water consumption and bottom ash disposal (from

the furnace). The fixed O&M costs are based on maintenance and labor costs.

This is an O&M cost result screen as described in "5.1.1.6. O&M Cost Results" on page 98.

The base plant includes the following variable cost components:

• Fuel: The total cost of as-fired fuel. Minemouth cost, coal cleaning costs and

transportation costs are all included.

• Water: The total cost of water consumed by the base plant for direct or reheat use.

• Disposal: The total cost of bottom ash disposal. The value is given on a wet ash basis.

This does not consider by-product ash sold in commerce.

• Hydrated Lime: The total cost of hydrated lime for SO3 removal. Hydrated lime is

injected for flue gas treatment at the inlet of the air preheater to remove SO3.

• Internal Electricity Cost: Power consumed by abatement technologies result in

lower net power produced and lost revenue. The IECM charges each technology for

the internal use of electricity and treats the charge as a credit for the base plant. When

comparing individual components of the plant, these utility charges are taken into

consideration. For total plant costs they balance out and have no net effect on the

plant O&M costs.

5.2.3.3.1.5. Total Cost

This is a standard total cost result table as described in "5.1.1.7. Total Cost Results" on page

99.

5.2.3.3.2. Air Preheater

The "Air Preheater" Technology Navigation Tab in the "Get Results" program area contains result

screens that display the flow rates and temperatures of substances through the air preheater. This

is only available in the PC plant type.

5.2.3.3.2.1. Diagram

Illustration 324: PC: GET RESULTS: Base Plant: Boiler: O&M Cost


This screen displays an icon for the Air Preheater and values for major flows in and out of it:


they display on the screen).

• Recycled Flue Gas Entering Preheater: Flue gas can be recycled back into the

boiler when an O2-CO2 Recycle configuration is specified in Configure Plant. This is

more commonly known as an "oxyfuel" configuration. Flue gas is not recycled in any

other configuration.

◦ Recycled Flue Gas: Volumetric flow rate of the recycled flue gas entering the

induced-draft fan.

◦ Temperature: Temperature of the recycled flue gas entering the induced-draft

fan.

• Atmospheric Air Entering Preheater

◦ Ambient Air: Volumetric flow rate of air entering the induced-draft fan, based on

the atmospheric air temperature and atmospheric pressure.

◦ Temperature: Temperature of the atmospheric air entering the induced-draft fan.

• Heated Air Exiting Preheater

◦ Total Oxidant: Volumetric flow rate of the combustion air or recycled flue gas

exiting the air preheater, based on the combustion air temperature and

atmospheric pressure.

◦ Temperature: Heated combustion air or recycled flue gas temperature exiting

the air preheater. This is a complicated function of the heat content and

temperatures of the flue gas.

• Leakage Air

◦ Leakage Air: Volumetric flow rate of the atmospheric air leaking across the air

preheater into the flue gas. This is based on the leakage temperature and

atmospheric pressure.

◦ Temperature: Temperature of the atmospheric air leaking across the air

preheater into the flue gas. This is determined by the leakage parameter on the

base plant performance input screen.

Illustration 325: PC: GET RESULTS: Base Plant: Air Preheater: Diagram


• Flue Gas Entering Preheater

◦ Temperature In: Temperature of the flue gas entering the air preheater. This is

determined by the flue gas outlet temperature of the module upstream of the air

preheater (e.g., the boiler economizer).

◦ Flue Gas In: Volumetric flow rate of the flue gas entering the air preheater, based

on the flue gas inlet temperature and atmospheric pressure.

◦ Fly Ash In: Total solids mass flow rate in the flue gas entering the air preheater.

This is determined by the solids exiting the module upstream of the air preheater

(e.g., the boiler economizer).

◦ Mercury In: Total mass of mercury entering the air preheater in the flue gas. The

value is a sum of all the forms of mercury (elemental, oxidized, and particulate).

• Hydrated Lime

◦ Hydrated Lime In: Total mass of hydrated lime entering the air preheater.

Hydrated lime is injected for flue gas treatment at the inlet of the air preheater to

remove SO3.

• Air Preheater Performance

◦ SO3 Removal: Percent of the SO3 removed from the flue gas.

• Cooled Flue Gas Exiting Preheater

◦ Temperature Out: Temperature of the flue gas exiting the air preheater. This is

determined by the parameter on the base plant performance input screen.

◦ Flue Gas Out: Volumetric flow rate of the flue gas exiting the air preheater,

based on the flue gas exit temperature and atmospheric pressure.

◦ Fly Ash Out: Total solids mass flow rate in the flue gas exiting the air preheater.

This is a function of the percent ash entering the flue gas (furnace emissions

input parameter) and the ash content of the fuel.

◦ Mercury Out: Total mass of mercury exiting the air preheater in the flue gas.

The value is a sum of all the forms of mercury (elemental, oxidized, and

particulate).


5.2.3.3.2.2. Flue Gas

This screen displays a table of quantities of flue gas components entering and exiting the air

preheater:

For each component entering and exiting in flue gas, values are given in both moles and mass

per hour. For each component entering in atmospheric air, values are given in moles per hour.

Use the scroll bar at the bottom to view the whole table.


Components.

Illustration 326: PC: GET RESULTS: Base Plant: Air Preheater: Flue Gas


5.2.3.3.2.3. Oxidant

This screen displays a table of quantities of air or recycled flue gas components entering and

exiting the air preheater:

For each component entering and exiting in flue gas, values are given in both moles and mass

per hour. For each component entering in atmospheric air, values are given in moles per hour.


See ""5.1.3.1. Flue Gas Components" on page 101 for a description of the Major Air

Components.

Illustration 327: PC: GET RESULTS: Base Plant: Air Preheater: Oxidant


5.2.3.3.3. Steam Cycle

5.2.3.3.3.1. Diagram

This screen shows the steam cycle:

The following values are displayed:

• Total Steam Flow: This is the steam flow rate circulating in the boiler system.

• Boiler Blowdown: This is the amount of feedwater removed on order to reduce the

suspended solids that have accumulated in the cooling water system.

• Demin. Out: The demineralizer regenerant waste is produced during the regeneration

cycle of makeup water in the condensate polisher ion exchange beds. The waste

contains salts of the material removed from the water and an excess of the regenerant.

• Misc. Steam Loss: This is the steam flow rate lost due to leaks in the boiler system.

• Cooling Water: This is the cooling water required for the steam cycle.

• Boiler Makeup: This is the flow rate of boiler makeup water into the demineralizer

system.

5.2.3.4. NOx Control

5.2.3.4.1. In-Furnace Controls

This technology contains screens that address combustion or post-combustion air pollution

technologies for Nitrogen Oxides. These screens are available if the In-Furnace Controls for the

PC plant type configurations have been selected for NOx control under Combustion Controls. If

you have selected both In-Furnace Controls and a Hot-Side SCR for NOx control, these screens

will be displayed under the "In-Furnace Controls" process type; otherwise, these screens will be

displayed directly under the "NOx Control" technology. (See "4.1.4.4.2.3. Process Types" on page

38.)

Illustration 328: PC: GET RESULTS: Base Plant: Steam Cycle: Diagram


5.2.3.4.1.1. Diagram

This screen displays an icon for the In-Furnace Controls NOx technology selected and values

for major flows in and out of it:


• Fuel Entering Boiler

◦ Wet Coal In: Fuel flow rate into the boiler on a wet basis. Waste products

removed prior to the burners are not considered here.

◦ Mercury In: This is the mass flow rate of total mercury entering the boiler. The

mass reflects the molecular weight of elemental mercury.

• Air Entering Boiler

◦ Heated Air: Volumetric flow rate of the air at the burners, based on the air

temperature at the burners and atmospheric pressure.

◦ Temperature: Heated air temperature measured at the burners. This is generally

determined by the combustion air temperature exiting the air preheater.

• Flue Gas Exiting Convective Zone: This the area of the furnace between the

combustion zone and the SNCR (if present). Changes in the flue gas after combustion

due to in-furnace combustion NOx controls are reflected here.

◦ Temperature: Temperature of the flue gas exiting the convective zone.

◦ Flue Gas: Volumetric flow rate of the flue gas exiting the convective zone, based

on the temperature exiting the convective zone and atmospheric pressure.

◦ Fly Ash: Total solids mass flow rate in the flue gas exiting the convective zone.

This includes ash, unburned carbon and unburned sulfur.

◦ Mercury: Total mass of mercury in the flue gas exiting the convective zone. The


• Flue Gas Exiting the Economizer

◦ Temperature Out: Temperature of the flue gas at the exit of the economizer.


Diagram


◦ Flue Gas Out: Volumetric flow rate of the flue gas at the exit of the economizer,

based on the temperature at the exit of the economizer and atmospheric pressure.

◦ Fly Ash Out: Total solids mass flow rate in the flue gas at the exit of the

economizer. This includes ash, unburned carbon and unburned sulfur.

◦ Mercury Out: Total mass of mercury in the flue gas exiting the economizer. The


• Gas Reburn: (Only shown if the "Gas Reburn" configuration is chosen.)

◦ Reburn Gas: This is the flow rate of natural gas into the boiler.

• SNCR: (Only shown if the "SNCR" or "LNB & SNCR" configuration is chosen. The

SNCR is located in the upper portion of the boiler. Several parameters are reported as

a summary.

▪ Stoic.: This is the actual reagent stoichiometry used in the SNCR. Note that

urea has double the moles of nitrogen relative to that of ammonia.

▪ SNCR Reagent: This is the mass flow rate of reagent (urea or ammonia)

injected by the SNCR into the boiler. Note that water used to dilute the urea

is included in this flow rate.

▪ Reagent Water: This is the water used to dilute the reagent.

• NOx Removal Performance

◦ Boiler NOx Removal: (Not shown if the "SNCR" configuration is chosen.) This

is the composite removal efficiency of the boiler NOx technologies associated

with low NOx burners, overfire air, and reburn. It does not include the removal

efficiency of an SNCR system.

◦ SNCR NOx Removal: (Only shown if the "SNCR" or "LNB & SNCR"

configuration is chosen.) This is the removal efficiency of the SNCR system

alone. It does not take into consideration any other NOx reduction prior to the

SNCR.


5.2.3.4.1.2. Flue Gas

This screen displays a table of quantities of gas components entering and exiting the

combustion zone:

For each component, quantities are given in both moles and mass per hour. It also displays

quantities of gas components exiting the convective zone in moles per hour. Use the scroll bar

at the bottom to view the whole table.


Components.


Flue Gas



This screen displays a table for the capital costs related to the In-Furnace Controls NOx control

technology:

Capital costs are typically expressed in either constant or current dollars for a specified year, as

shown in the status bar at the bottom of the screen. (See "4.1.4.3. The Status Bar" on page 33.)

The following values are shown:

• Combustion NOx Capital Requirement: The total capital costs, including retrofit

costs, for the LNB, OFA, and gas reburn technologies are included here. A zero is

displayed when none of these technologies are installed.

• SNCR Capital Requirement: The total capital costs, including retrofit costs, for the

SNCR technology is included here. A zero is displayed when an SNCR is not

installed.

• Total Capital Requirement: Sum of the above.

• Effective TCR: The TCR of the retrofit NOx controls that is used in determining the

total power plant cost. The effective TCR is determined by the "TCR Recovery

Factor" for the hot-side SCR.

Illustration 331: PC: GET RESULTS: NOx

Control: In-Furnace Controls: Capital

Cost


5.2.3.4.1.4. O&M Cost

This screen displays tables for the variable and fixed operation and maintenance costs involved

with the In-Furnace Controls NOx control technology:

O&M costs are typically expressed on an average annual basis and are provided in either

constant or current dollars for a specified year, as shown in the status bar at the bottom of the

screen. (See "4.1.4.3. The Status Bar" on page 33.) Each result is described briefly below:

• Variable Cost Components: Variable operating costs and consumables are directly

proportional to the amount of kilowatts produced and are referred to as incremental

costs. All the costs are subject to inflation.

◦ Fuel: The total fuel costs associated with gas reburn are included here.

◦ Reagent: The total reagent costs (urea and ammonia) used for the SNCR system

are included here.

◦ Water: This is the cost of the water used to dilute the urea for the SNCR.

◦ Electricity: This is the power used for the pumps to move reagents and water in

the SNCR.

◦ Total Variable Costs: This is the sum of the entire variable O&M costs listed

above. This result is highlighted in yellow.

• Fixed Cost Components: Fixed operating costs are essentially independent of actual

capacity factor, number of hours of operation, or amount of kilowatts produced. All

the costs are subject to inflation.

◦ Combustion NOx Costs: This is the fixed O&M costs associated with the LNB,

OFA, and gas reburn systems.

◦ SNCR Boiler Costs: This is the fixed O&M costs associated with the SNCR

system.

Illustration 332: In-Furnace Controls - O&M Cost Result Screen


◦ Total Fixed Costs: This is the sum of all the fixed O&M costs listed above. This


◦ Total O&M Costs: This is the sum of the total variable and total fixed O&M

costs. It is used to determine the base plant total revenue requirement. This result

is highlighted in yellow.

5.2.3.4.1.5. Total Cost


99. Note that all costs expressed in "Equivalent NO2 Removal ($/ton rem)" assume tons of

equivalent NO2.

5.2.3.4.2. Hot-Side SCR

This technology contains screens that address combustion or post-combustion air pollution

technologies for Nitrogen Oxides in the Combustion (Boiler) plant type configurations.

These input screens are available when a Hot-Side SCR has been selected. If you have selected

both In-Furnace Controls and a Hot-Side SCR for NOx control, these screens will be displayed

under the "Hot-Side SCR" process type; otherwise, these screens will be displayed directly under

the "NOx Control" technology. (See "4.1.4.4.2.3. Process Types" on page 38.)


Total Cost


5.2.3.4.2.1. Diagram

This screen displays an icon for the Hot–Side SCR NOx technology selected and values for

major flows in and out of it:


• Reagent

◦ Ammonia Inj.: The total mass flow rate of ammonia injected into the SCR. This

is a function of the NOx concentration in the flue gas and the ammonia

stoichiometric performance input value.

◦ Steam for Inj.: The total mass flow rate of steam into the SCR. This is the

amount of steam added to the SCR to vaporize and transport ammonia into the

inlet gas stream. This is determined by the steam to ammonia ratio input value

and the ammonia injection.

• Catalyst

◦ Steam for Soot: This is the amount of steam blown into the hot-side SCR to

remove soot buildup on the catalyst layers. The soot blowing steam is assumed to

be directly proportional to catalyst volume.

◦ Initial Catalyst Layers: This is the number of initial active catalyst layers. Three

layers are installed initially. It is used to calculate the total pressure drop across

the SCR and the auxiliary power requirements. This is set by the input parameter.

◦ Reserve Catalyst Layers: This is the number of reserve or extra catalyst layers.

These are available for later catalyst additions. It is used to calculate the total

pressure drop across the SCR and the auxiliary power requirements. This is set by

the input parameter.

◦ Dummy Catalyst Layers: This is the number of dummy catalyst layers. A

dummy layer corrects the flow distribution. It is used to calculate the total

pressure drop across the SCR and the auxiliary power requirements. This is set by

the input parameter.

◦ Active Catalyst Layers: This is the number of initial active catalyst layers. Three

layers are installed initially. It is used to calculate the total pressure drop across

Illustration 334: PC: GET RESULTS: NOx Control: Hot-Side SCR:

Diagram


the SCR and the auxiliary power requirements. It is equal to the number of initial

and reserve catalyst layers.

◦ Layers Replaced Yearly: Average catalyst layer replacement rate per year. This

assumes that all catalyst layers are of equal depth.

• Flue Gas Entering SCR

◦ Temperature In: Temperature of the flue gas entering the SCR. This is

determined by the flue gas outlet temperature of the module upstream of the SCR

(e.g., the boiler economizer)

◦ Flue Gas In: Volumetric flow rate of flue gas entering the SCR, based on the flue

gas temperature entering the SCR and atmospheric pressure.

◦ Fly Ash In: Total solids mass flow rate in the flue gas entering the SCR. This is

determined by the solids exiting from the module upstream of the SCR (e.g., the

boiler economizer).

◦ Mercury In: Total mass of mercury entering the hot-side SCR in the flue gas.


particulate).

• Flue Gas Exiting SCR

◦ Temperature Out: Temperature of the flue gas exiting the SCR. The model

currently does not alter this temperature through the SCR.

◦ Flue Gas Out: Volumetric flow rate of the flue gas exiting the SCR, based on the

flue gas temperature exiting the SCR and atmospheric pressure.

◦ Fly Ash Out: Total solids mass flow rate in the flue gas exiting the SCR. This is

a function of the ash removal parameter on the SCR performance input screen.

◦ Mercury Out: Total mass of mercury exiting the hot-side SCR in the flue gas.


particulate).

◦ Ammonia Slip: Total mass flow rate of ammonia that is unreacted and exits the

SCR in the flue gas stream. This is a function if the ammonia injection flow rate,

NOx concentration in the flue gas, and NOx removal efficiency.

• SCR Performance

◦ NOx Removal: Actual removal efficiency of NOx in the SCR. This is a function

of the minimum (50%) and maximum removal efficiencies (SCR performance

input parameter) and the emission constraint for NOx (emission constraints input

parameter). It is possible that the SCR may over or under-comply with the

emission constraint.

◦ TSP Removal: Actual particulate removal efficiency in the SCR. This is set by

the SCR input parameter.

• Collected Solids

◦ Dry Solids: Total solids mass flow rate of solids removed from the SCR. This is

a function of the solids content in the flue gas and the particulate removal

efficiency of the SCR.

• Wash Water

◦ Wash Water: The ammonia that deposits in the air preheater is periodically

removed by washing.


5.2.3.4.2.2. Flue Gas

This screen displays a table of quantities of flue gas components entering and exiting the SCR:

For each component, quantities are given in both moles and mass per hour. See "5.1.3.1. Flue

Gas Components" on page 101 for a description of the Major Flue Gas Components.


Illustration 335: PC: GET RESULTS: NOx Control: Hot-Side SCR: Flue

Gas

Illustration 336: PC: GET RESULTS: NOx Control: Hot-Side SCR: Capital

Cost




data collected from several reports and analyses of hot-side SCR units. They are described in

general with specific model parameters that affect them described in particular. The Hot-Side

SCR system has the following process areas:

• Reactor Housing: The reactor housing costs include carbon steel reactor vessel with

six inches of mineral wool insulation, vessel internals and supports, steam soot

blowers, reactor crane and hoist, installation labor, foundations, structures, piping,

and electrical equipment. The costs are a function of the number of vessels, including

spares, and the volume of catalyst required. Catalyst costs are excluded.

• Ammonia Injection: The ammonia unloading, storage, and supply system includes a

storage vessel with a seven-day capacity, an ammonia vaporizer, mixer, injection grid,

ductwork, dampers, and a truck unloading station. The costs are a function of the

ammonia injected.

• Ducts: The ductwork includes economizer bypass and outlet ducts, SCR inlet and

outlet ducts, SCR and economizer control dampers, air preheater inlet plenum,

various expansion joints in the ductwork, and air preheater cross-over ducting. The

costs are a function of the flue gas flow rate through the SCR.

• Air Preheater Modifications: Thicker and smoother material is used for the heat

transfer surfaces in the preheater. A larger motor is provided for the heat exchanger.

High pressure steam soot blowers and water wash spray nozzles are also added. The

costs are a function of the number of operating vessels, and the heat transfer

efficiency of the air preheater (UA product).

• ID Fan Differential: The ID fans must be sized to deal with the increased flue gas

pressure drop resulting from the additional ductwork and the SCR reactor. The costs

are a function of the flue gas flow rate and pressure drop across the SCR.

• Structural Support: The costs of this area are related primarily to the structural

support required for the SCR reactor housing, ductwork, and air preheater. The costs

are a function of the reactor housing costs, duct costs and air preheater modification

costs above.

• Miscellaneous Equipment: This area includes the capital costs incurred for ash

handling addition, water treatment addition, and flow modeling for a hot-side SCR

system. The costs are a function of the gross plant capacity.

• Initial Catalyst: The cost of the initial catalyst charge is included in the total direct

cost, because it is such a large and integral part of the SCR system. The costs are a

function of the initial catalyst charge.

5.2.3.4.2.4. O&M Cost



The Hot-Side SCR system has the following variable cost components:

• Catalyst: Replacement catalyst cost per year for the hot-side SCR. This is a function

of the number of catalyst layers, the number of layers replaced each year, and the

catalyst space velocity (all three are performance input parameters).

• Ammonia: Ammonia reagent cost per year for the hot-side SCR. This is a function of

the concentration of NOx in the flue gas and the ammonia mass flow rate.

• Water: Cost of water used to wash ammonia that deposits in the air preheater. This is

a function of the efficiency and concentration of ammonia removed by wash water

performance input parameters and the amount of ammonia salts deposited on the air

preheater.

• Electricity: Cost of electricity consumption of the hot-side SCR. This is a function of

the gross plant capacity and the SCR energy penalty performance input parameter.

Illustration 337: PC: GET RESULTS: NOx Control: Hot-Side SCR: O&M

Cost


5.2.3.4.2.5. Total Cost


99. Note that all costs expressed "Equivalent NO2 Removal ($/ton rem)" assume tons of

equivalent NO2.

5.2.3.5. Mercury

These screens display results for the performance and costs directly associated with the removal of

mercury from each technology in the power plant. Pre-combustion and post-combustion control

technologies are all considered. Special consideration is given to flue gas conditioning used to

enhance mercury removal. Water and activated carbon injection are currently considered as

conditioning agents.

Illustration 338: PC: GET RESULTS: NOx Control: Hot-Side SCR: Total Cost


5.2.3.5.1. Diagram

This screen displays an icon for the water and carbon injection systems, both part of the overall

mercury control option and values for major flows in and out of it:


they display on the screen):

• Flue Gas Prior to Injection

◦ Temperature In: Temperature of the flue gas prior to flue gas conditioning.

◦ Flue Gas In: Volumetric flow rate of the flue gas prior to flue gas conditioning,

based on the temperature prior to flue gas conditioning and atmospheric pressure.

◦ Fly Ash In: Total solids mass flow rate in the flue gas prior to flue gas conditioning.

This includes ash, unburned carbon and unburned sulfur.

◦ Mercury In: Total mass of mercury in the flue gas prior to flue gas conditioning.


particulate).

• Flue Gas After Injection

◦ Temperature Out: Temperature of the flue gas after flue gas conditioning. This

should be above the acid dew point temperature at the bottom of the screen.

◦ Flue Gas Out: Volumetric flow rate of the flue gas after flue gas conditioning,

based on the temperature after flue gas conditioning and atmospheric pressure.

◦ Fly Ash Out: Total solids mass flow rate in the flue gas after flue gas conditioning.

This includes ash, unburned carbon, activated carbon, and unburned sulfur.

◦ Mercury Out: Total mass of mercury in the flue gas after flue gas conditioning. The


◦ Acid Dew Point: This is the temperature that H2SO4 vapor condenses into the liquid

phase.

Illustration 339: PC: GET RESULTS: Mercury: Diagram


• Flue Gas Conditioning

◦ Water Injected: Water added to the flue gas to reduce the temperature No water is

injected if water injection is not specified in the configuration or the inlet

temperature is within the approach to saturation relative to the acid dew point.

◦ Carbon Injected: Total activated carbon mass flow rate injected into the flue gas.

NOTE: Carbon injected into the flue gas is collected downstream in the

particulate control device (e.g., the cold-side ESP).

5.2.3.5.2. Flue Gas

This screen displays a table of quantities of flue gas components entering and exiting the flue gas

conditioning area. For each component, quantities are given in both moles and mass per hour:


Components.

Illustration 340: PC: GET RESULTS: Mercury: Flue Gas



This screen displays tables for the direct and indirect capital costs related to the water and carbon

injection systems, both part of the overall mercury control option:

This is a capital cost result screen as described in "5.1.1.2. Capital Cost Results" on page 93. The

direct capital costs described here apply to the various mercury control equipment added to the

power plant. These controls may physically be part of other control technologies, but have their

particular capital costs considered here.

Each process area direct capital cost is a reduced-form model based on regression analysis of data

collected from several reports and analyses. They are described in general below. The primary

factors in the model that effect the capital cost of the base plant are the plant size, the amount of

water injected, the amount of activated carbon injected, and the sulfur and moisture content of the

coal.

• Spray Cooling Water: This capital cost area represents the materials and equipment

necessary to inject water into the flue gas duct for the purpose of cooling the flue gas to

a prerequisite temperature. Equipment includes water storage tanks, pumps, transport

piping, injection grid with nozzles, and a control system. The direct capital cost is a

function of the water flow rate.

• Sorbent Injection: This capital cost area represents the materials and equipment

necessary to deliver the activated carbon into the flue gas. Equipment includes silo

pneumatic loading system, storage silos, hoppers, blowers, transport piping, and a

control system. The direct capital cost is a function of the sorbent flow rate.

• Sorbent Recycle: This capital cost area represents the materials and equipment

necessary to recycle ash and activated carbon from the particulate collector back into the

duct injection point. The purpose is to create an equilibrium state where the carbon is

reintroduced to improve performance. Equipment includes hoppers, blowers, transport

piping, and a control system. The direct capital cost is a function of the recycle rate of

ash and spent sorbent.

Illustration 341: PC: GET RESULTS: Mercury: Capital Cost


NOTE: Sorbent recycling is a feature that may be added in a future version of the

IECM.

• Additional Ductwork: This capital cost area represents materials and equipment for

ductwork necessary beyond the other process areas. Extra ductwork may be required for

difficult retrofit installations.

NOTE: Future versions of the IECM may include parameters to determine a capital

cost for this area. The current version assumes no additional ductwork.

• Sorbent Disposal: This capital cost area represents materials and equipment required to

house and dispose the collected sorbent. Equipment includes hoppers, blowers, transport

piping, and a control system. This is in excess of existing hoppers, tanks, and piping

used for existing particulate collectors. The direct capital cost is determined by the

incremental increase in collected solids in the particulate collector.

• CEMS Upgrade: This capital cost area represents materials and equipment required to

install a continuous emissions monitoring system (CEMS) upgrade. The direct capital

cost is determined by the net electrical output of the power plant.

• Pulse-Jet Fabric Filter: This capital costs area represents an upgrade to an existing

cold-side ESP, where one section at the back end of the unit is replaced with a pulse-jet

fabric filter. This can be considered a pseudo-COHPAC. Equipment includes pulse-jet

FF, filter bags, ductwork, dampers, and MCCs, instrumentation and PLC controls for

baghouse operation. Equipment excludes ash removal system, power distribution and

power supply, and distributed control system. The direct capital cost is a function of the

flue gas flow rate and the air to cloth ratio of the fabric filter.

NOTE: The IECM currently does not support multiple particulate devices in the same

configuration nor a modified cold-side ESP.

5.2.3.5.4. O&M Cost

This screen displays tables for the variable and fixed operation and maintenance costs related to

the water and carbon injection systems, both part of the overall mercury control option. The

variable O&M costs are calculated from the variable costs for carbon, water consumption and fly


ash disposal (from the particulate control device). The fixed O&M costs are based on

maintenance and labor costs:

This is an O&M cost result screen as described in "5.1.1.6. O&M Cost Results" on page 98. The

mercury control option has the following variable cost components:

• Activated Carbon: This is the activated carbon cost for flue gas conditioning.

• Water: This is the water cost for flue gas conditioning.

• Additional Waste Disposal: This is the solid disposal cost per year for the flue gas

conditioning. Only the removal of carbon from the particulate device is considered here.

• Electricity: This is the power utilization cost per year for the flue gas conditioning.

5.2.3.5.5. Total Cost

This screen displays a table which totals the annual fixed, variable, operations and maintenance,

and capital costs related to the water and carbon injection systems, both part of the overall

mercury control option:

Illustration 342: PC: GET RESULTS: Mercury: O&M Cost

Illustration 343: PC: GET RESULTS: Mercury: Total Cost


This is a standard total cost result table as described in "5.1.1.7. Total Cost Results" on page 99.

5.2.3.6. TSP Control

5.2.3.6.1. Cold-Side ESP

The TSP Control Technology Navigation screens display flows and costs related to the particulate

control technology. These screens are available only if the Cold-Side ESP TSP control technology

is selected in a PC plant.

5.2.3.6.1.1. Diagram

This screen displays an icon for the particulate control technology selected and values for


Each result is described briefly below:

• Flue Gas Entering ESP

◦ Temperature In: Temperature of the flue gas entering the particulate control

technology. This is determined by the flue gas outlet temperature of the module

upstream of the air preheater (e.g., the air preheater).

◦ Flue Gas In: Volumetric flow rate of the flue gas entering the particulate control

technology, based on the flue gas inlet temperature and atmospheric pressure.


This is determined by the solids exiting the module upstream of the particulate

control technology (e.g., the air preheater).

◦ Mercury In: Total mass of mercury entering the particulate control technology.


particulate).

• Flue Gas Exiting ESP

◦ Temperature Out: Temperature of the flue gas exiting the particulate control

technology. The model currently does not alter this temperature through the

particulate control technology.

◦ Flue Gas Out: Volumetric flow rate of the flue gas exiting the particulate control

technology, based on the flue gas exit temperature and atmospheric pressure.

Illustration 344: PC: GET RESULTS: TSP Control: Cold-Side ESP: Diagram


◦ Fly Ash Out: Total solids mass flow rate in the flue gas exiting the particulate

control technology. This is a function of the ash content of the inlet flue gas and

the ash removal efficiency performance input parameter.

◦ Mercury Out: Total mass of mercury exiting the particulate control technology.


particulate).

• ESP Performance

◦ Ash Removal: Ash removal efficiency of the particulate control technology. This

is a function of the ash emission constraint and the inlet ash mass flow rate.

◦ SO3 Removal: Percent of SO3 in the flue gas removed from the particulate

control technology. The SO3 is assumed to combine with H2O and leave with the

ash solids as a sulfate (in the form of H2SO4).

◦ Mercury Removal: Percent of the total mercury removed from the particulate

control technology. The value reflects a weighted average based on the particular

species of mercury present (elemental, oxidized, and particulate).

• Collected Fly Ash

◦ Dry Ash: Total mass flow rate of the solids removed from the ESP. This is a

function of the solids content in the flue gas and the particulate removal

efficiency of the ESP. The value is given on a dry basis.

◦ Sluice Water: Water added to the dry fly ash. This water is added for

transportation purposes.

◦ Wet Ash: Total mass flow rate of the solids removed for waste management. This

includes dry fly ash and sluice water. The value is given on a wet basis.


5.2.3.6.1.2. Flue Gas

This screen displays a table of quantities of flue gas components entering and exiting the

Particulate Control Technology. For each component, quantities are given in both moles and

mass per hour:


Components.

Illustration 345: PC: GET RESULTS: TSP Control: Cold-Side ESP: Flue Gas



This screen displays tables for the direct and indirect capital costs related to the particulate

control technology:



data collected from several reports and analyses of particulate control technology units. They

are described in general below. The primary factors in the model that effect the capital costs of

the cold-side ESP are the specific and total collection areas of the T-R plate sets, and the flue

gas flow rate through the ESP. The ESP has the following capital cost process areas:

• Particulate Collector: This area covers the material and labor, flange to flange, for

the equipment and labor cost for installation of the entire collection system.






• Differential ID Fan: The complete cost of the ID fan and motor due to the pressure

loss that results from particulate collectors.

Illustration 346: PC: GET RESULTS: TSP Control: Cold-Side ESP: Capital

Cost


5.2.3.6.1.4. O&M Cost


with the Cold-Side ESP TSP particulate control technology:


the ESP has the following variable cost components:

• Water: This is the cost of sluice water.

• Solid Waste Disposal: Total cost to dispose the collected fly ash. This does not

consider by-product ash sold in commerce.

• Electricity: Cost of power consumption of the particulate control technology. This is

a function of the flue gas flow rate, ash removal efficiency and the type of coal (ash

properties).

5.2.3.6.1.5. Total Cost


99.

Illustration 347: PC: GET RESULTS: TSP Control: Cold-Side ESP: O&M

Cost

Illustration 348: PC: GET RESULTS: TSP Control: Total Cost


5.2.3.6.2. Fabric Filter

These screen display flows and costs related to the particulate control technology. They are

available in PC plants that have a fabric filter configured.

5.2.3.6.2.1. Diagram

This screen displays an icon for the Fabric Filter particulate control technology selected and

values for major flows in and out of it:


• Flue Gas Entering Filter

◦ Temperature In: Temperature of the flue gas entering the particulate control

technology. This is determined by the flue gas outlet temperature of the module

upstream of the air preheater (e.g., the air preheater).

◦ Flue Gas In: Volumetric flow rate of the flue gas entering the particulate control

technology, based on the flue gas inlet temperature and atmospheric pressure.


This is determined by the solids exiting the module upstream of the particulate

control technology (e.g., the air preheater).

◦ Mercury In: Total mass of mercury entering the particulate control technology.


particulate).

• Flue Gas Exiting Filter

◦ Temperature Out: Temperature of the flue gas exiting the particulate control

technology. The model currently does not alter this temperature through the

particulate control technology.

◦ Flue Gas Out: Volumetric flow rate of the flue gas exiting the particulate control

technology, based on the flue gas exit temperature and atmospheric pressure.

◦ Fly Ash Out: Total solids mass flow rate in the flue gas exiting the particulate

control technology. This is a function of the ash content of the inlet flue gas and

the ash removal efficiency performance input parameter.

Illustration 349: PC: GET RESULTS: TSP Control: Fabric Filter: Diagram


◦ Mercury Out: Total mass of mercury exiting the particulate control technology.


particulate).

• Fabric Filter Performance

◦ Ash Removal: Ash removal efficiency of the fabric filter technology. This is a

function of the ash emission constraint and the inlet ash mass flow rate.

◦ SO3 Removal: Percent of SO3 in the flue gas removed from the particulate

control technology. The SO3 is assumed to combine with H2O and leave with the

ash solids as a sulfate (in the form of H2SO4).

◦ Mercury Removal: Percent of the total mercury removed from the particulate

control technology. The value reflects a weighted average based on the particular

species of mercury present (elemental, oxidized, and particulate).

• Collected Fly Ash

◦ Dry Ash: Total mass flow rate of the solids removed from the fabric filter. This is

a function of the solids content in the flue gas and the particulate removal

efficiency of the fabric filter. The value is given on a dry basis.

◦ Sluice Water: Water added to the dry fly ash. This water is added for

transportation purposes.

◦ Wet Ash: Total mass flow rate of the solids removed for waste management. This

includes dry fly ash and sluice water. The value is given on a wet basis.

5.2.3.6.2.2. Flue Gas


Particulate Control Technology. For each component, quantities are given in both moles and

mass per hour:

Illustration 350: PC: GET RESULTS: TSP Control: Fabric Filter: Flue Gas



Components.


This screen displays tables for the direct and indirect capital costs related to the particulate

control technology:




are described in general below. The primary model factors that affect the capital costs of the

fabric filter are the fabric filter type, the air to cloth ratio, the number of bags and

compartments, and the flue gas flow rate through the fabric filter. The fabric filter has the

following process areas:

• Collector: This area covers the material and labor, flange to flange, for the equipment

and labor cost for installation of the entire collection system.






• Differential: The complete cost of the ID fan and motor due to the pressure loss that

results from particulate collectors.

Illustration 351: PC: GET RESULTS: TSP Control: Fabric Filter: Capital

Cost


5.2.3.6.2.4. O&M Cost


with the particulate control technology:


The fabric filter has the following variable cost components:

• Solid Waste Disposal: Total cost to dispose the collected fly ash. This does not

consider by-product ash sold in commerce.

• Electricity: Cost of power consumption of the particulate control technology. This is

a function of the flue gas flow rate, ash removal efficiency and the type of coal (ash

properties).

5.2.3.6.2.5. Total Cost


99.

Illustration 352: PC: GET RESULTS: TSP Control: Fabric Filter: O&M Cost

Illustration 353: PC: GET RESULTS: TSP Control: Fabric Filter: Total Cost


5.2.3.7. SO2 Control

5.2.3.7.1. Wet FGD

These screens address post-combustion air pollution technologies for Sulfur Dioxide. The model

includes options for a Wet FGD. The screens are available if this SO2 control technology has been

selected in a PC plant.

5.2.3.7.1.1. Diagram

This screen displays an icon for the Wet FGD SO2 control technology selected and values for


Each result is described briefly below.

• Reagent

◦ Dry Reagent: The total mass flow rate of lime, limestone or limestone with

dibasic acid injected into the scrubber. This is a function of the SO2 removal

efficiency, the reagent purity and the reagent stoichiometric (all performance

input parameters).

◦ Makeup Water: Water needed to replace the evaporated water in the reagent

sluice circulation stream.

• Oxidation

◦ Oxidation Air: This is the amount of air used for oxidation.

◦ Oxidation H2O: This is the amount of water used for oxidation.

• Flue Gas Entering FGD

◦ Temperature In: Temperature of the flue gas entering the scrubber. This is

determined by the flue gas outlet temperature of the module upstream of the

scrubber (e.g., a particulate removal technology).

◦ Flue Gas In: Volumetric flow rate of flue gas entering the scrubber, based on the

flue gas temperature entering the scrubber and atmospheric pressure.

Illustration 354: PC: GET RESULTS: SO2 Control: Wet FGD: Diagram


◦ Fly Ash In: Total solids mass flow rate in the flue gas entering the scrubber. This

is determined by the solids exiting from the module upstream of the scrubber

(e.g., a particulate removal technology).

◦ Mercury In: Total mass of mercury entering the scrubber. The value is a sum of

all the forms of mercury (elemental, oxidized, and particulate).

◦ Temperature: Temperature of the flue gas entering the scrubber after the forced

draft fan. This is determined by the flue gas inlet temperature of the FGD and the

temperature rise across ID fan input parameter.

• Flue Gas Exiting FGD

◦ Temperature: Temperature of the flue gas immediately on exiting the scrubber,

prior to any flue gas bypass remixing and prior to reheating.

◦ Temperature Out: Temperature of the flue gas exiting the scrubber. This is a

function of flue gas bypass, saturation temperature, reheater and the flue gas

component concentrations.

◦ Flue Gas Out: Volumetric flow rate of the flue gas exiting the scrubber after the

reheater, based on the flue gas temperature exiting the scrubber and atmospheric

pressure.

◦ Fly Ash Out: Total solids mass flow rate in the flue gas exiting the scrubber after

the reheater. This is a function of the ash removal and flue gas bypass input

parameters.

◦ Mercury Out: Total mass of mercury exiting the scrubber after the reheater. The


• FGD Performance

◦ Ash Removal: Actual particulate removal efficiency in the scrubber. This is set

by the scrubber ash removal input parameter.

◦ SO2 Removal: Actual removal efficiency of SO2 in the scrubber. This is a

function of the maximum removal efficiency (scrubber performance input

parameter) and the emission constraint for SO2 (emission constraints input

parameter). It is possible that the scrubber may over or under-comply with the


◦ SO3 Removal: Percent of SO3 in the flue gas removed from the scrubber. The

SO3 is assumed to combine with H2O and leave with the ash solids or sluice

water as a sulfate (in the form of H2SO4).

◦ Mercury Removal: Percent of the total mercury removed from the scrubber. The

value reflects a weighted average based on the particular species of mercury

present (elemental, oxidized, and particulate).


◦ Wet FGD Solids: Total solids mass flow rate of solids removed from the

scrubber. This is a function of the solids content in the flue gas and the particulate

removal efficiency of the scrubber. The solids are shown on a wet basis.


5.2.3.7.1.2. Flue Gas

This screen displays a table of quantities of flue gas components entering and exiting the Wet

FGD SO2 Control Technology. For each component, quantities are given in both moles and

mass per hour:


Components.

Illustration 355: PC: GET RESULTS: SO2 Control: Wet FGD: Flue Gas


5.2.3.7.1.3. Bypass

This screen displays a table of quantities of flue gas components entering and bypassing the

Wet FGD SO2 Control Technology. For each component, quantities are given in both moles

and mass per hour:


Components.


This screen displays tables for the direct and indirect capital costs related to the SO2 control

technology:

Illustration 356: PC: GET RESULTS: SO2 Control: Wet FGD: Bypass

Illustration 357: PC: GET RESULTS: SO2 Control: Wet FGD: Capital Cost






the scrubbers are the flue gas flow rate through the scrubber, the composition of the flue gas,

the reagent stoichiometry, and the reagent flow rate. The Wet FGD contains the following

process areas:












area.

5.2.3.7.1.5. O&M Cost


with the SO2 control technology:


The Wet FGD has the following variable cost components:

• Reagent: The total mass flow rate of lime or limestone injected into the scrubber on a

wet basis. This is a function of the SO2 concentration in the flue gas and the reagent


Illustration 358: PC: GET RESULTS: SO2 Control: Wet FGD: O&M Cost


• Dibasic Acid: (Only shown when "LS w/ Additives" is chosen as the reagent.) This is

the cost of dibasic acid (DBA) used for the wet FGD.

• Solid Waste Disposal: Total cost to dispose the collected flue gas waste solids. This

does not consider by-product gypsum sold in commerce.

• Electricity: Cost of power consumption of the scrubber. This is a function of the

gross plant capacity and the scrubber energy penalty performance input parameter.

• Water: Cost of water for reagent sluice in the scrubber. This is a function of the liquid

to gas ratio performance input parameter for the wet FGD. The cost is a function of

the flue gas flow rate and the slurry recycle ratio performance input parameter for the

spray dryer.

5.2.3.7.1.6. Total Cost


99.

5.2.3.7.2. Spray Dryer

These screens that address post-combustion air pollution technologies for Sulfur Dioxide. The

model includes options for a Lime Spray Dryer. A spray dryer is sometimes used instead of a wet

scrubber because it provides simpler waste disposal and can be installed with lower capital costs.

These screens are available if the Lime Spray Dryer SO2 control technology has been selected for

the PC plant type.

Illustration 359: PC: GET RESULTS: SO2 Control: Wet FGD: Total Cost


5.2.3.7.2.1. Diagram

The Diagram result screen displays an icon for the Lime Spray Dryer SO2 control technology

selected and values for major flows in and out of it:


• Reagent

◦ Dry Reagent: The total mass flow rate of lime, limestone or limestone with

dibasic acid injected into the scrubber. This is a function of the SO2 removal

efficiency, the reagent purity and the reagent stoichiometric (all performance

input parameters). The reagent is assumed to be dry.

• Makeup Water

◦ Makeup Water: This is the amount of water needed to replace water evaporated

in the scrubber.

• Flue Gas Entering Dryer

◦ Temperature In: Temperature of the flue gas entering the scrubber. This is

determined by the flue gas outlet temperature of the module upstream of the

scrubber (e.g., a particulate removal technology).

◦ Flue Gas In: Volumetric flow rate of flue gas entering the scrubber, based on the

flue gas temperature entering the scrubber and atmospheric pressure.

◦ Fly Ash In: Total solids mass flow rate in the flue gas entering the scrubber. This

is determined by the solids exiting from the module upstream of the scrubber

(e.g., a particulate removal technology).

◦ Mercury In: Total mass of mercury entering the scrubber. The value is a sum of

all the forms of mercury (elemental, oxidized, and particulate).

• Flue Gas Exiting Dryer

◦ Temperature: Temperature of the flue gas immediately after exiting the

scrubber. This is a function of saturation temperature, and the flue gas component

concentrations. This temperature is used to determine the flue gas bypass

required.

Illustration 360: PC: GET RESULTS: SO2 Control: Spray Dryer: Diagram


◦ Temperature: Temperature of the flue gas immediately after exiting the induced

draft fan. This is a function of flue gas temperature exiting the scrubber, the flue

gas bypass and the temperature rise across ID fan input parameter.

◦ Temperature Out: Temperature of the flue gas immediately after exiting the

reheater. This is determined by the gas temperature exiting reheater input

parameter.

◦ Flue Gas Out: Volumetric flow rate of the flue gas exiting the reheater, based on

the flue gas temperature exiting the scrubber and atmospheric pressure.

◦ Solids Out: Total solids mass flow rate in the flue gas exiting the reheater. This is

a function of the ash removal parameter on the scrubber performance input

screen.

◦ Mercury Out: Total mass of mercury exiting the scrubber after the reheater. The


• Spray Dryer Performance

◦ Ash Removal: Actual particulate removal efficiency in the scrubber. This is set

by the scrubber performance input parameter.

◦ SO2 Removal: Actual removal efficiency of SO2 in the scrubber. This is a

function of the maximum removal efficiency (scrubber performance input

parameter) and the emission constraint for SO2 (emission constraints input

parameter). It is possible that the scrubber may over or under-comply with the


◦ SO3 Removal: Percent of SO3 in the flue gas removed from the scrubber. The

SO3 is assumed to combine with H2O and leave with the ash solids or sluice

water as a sulfate (in the form of H2SO4).

◦ Mercury Removal: Percent of the total mercury removed from the scrubber. The

value reflects a weighted average based on the particular species of mercury

present (elemental, oxidized, and particulate).


◦ Dry Solids: Total solids mass flow rate of solids removed from the scrubber. This

is a function of the solids content in the flue gas and the particulate removal

efficiency of the scrubber. The solids are assumed to be dry.


5.2.3.7.2.2. Flue Gas


Components.




Illustration 361: PC: GET RESULTS: SO2 Control: Spray Dryer: Flue Gas

Illustration 362: PC: GET RESULTS: SO2 Control: Spray Dryer: Capital

Cost




the scrubbers are the flue gas flow rate through the scrubber, the composition of the flue gas,

the reagent stoichiometry, and the reagent flow rate. The spray dryer has the following process

areas:










spray dryer system operation such as makeup water and instrument air are treated

here.


area.

5.2.3.7.2.4. O&M Cost


The spray dryer has the following variable cost components:

• Reagent: Annual cost of lime or limestone injected into the scrubber on a wet basis.

This is a function of the SO2 concentration in the flue gas and the reagent


• Solid Waste Disposal: Total cost to dispose the collected flue gas waste solids. This

does not consider by-product gypsum sold in commerce.

Illustration 363: PC: GET RESULTS: SO2 Control: Spray Dryer: O&M Cost



gross plant capacity and the scrubber energy penalty performance input parameter.

• Water: Cost of water for reagent sluice in the scrubber. This is a function of the liquid

to gas ratio performance input parameter for the wet FGD. The cost is a function of

the flue gas flow rate and the slurry recycle ratio performance input parameter for the

spray dryer.

5.2.3.7.2.5. Total Cost


99.



The amine CO2 scrubber is a post-combustion capture technology. It is only used in the PC and

NGCC plant types.

Illustration 364: PC: GET RESULTS: SO2 Control: Spray Dryer: Total Cost


5.2.3.8.1.1. Diagram

This screen shows a diagram of the amine system:


• Reagent

◦ Sorbent Makeup: (N/A for Cansolv.) The mass flow rate of fresh sorbent needed

to replace the amount used in the process.

◦ Water: This is the flow rate of water that is used to mix with the Sorbent

Makeup.

• Flue Gas Entering Amine System

◦ Temperature In: Temperature of the flue gas entering the amine system area,

prior to any processing. This is determined by the flue gas outlet temperature of

the process area upstream.

◦ Flue Gas In: Volumetric flow rate of flue gas entering the amine system.

◦ Fly Ash In: Total solids mass flow rate in the flue gas entering the Amine

System. This is determined by the solids exiting from the module upstream.

◦ Mercury In: Total mass of mercury entering the amine system. The value is a

sum of all the forms of mercury (elemental, oxidized, and particulate).

◦ Temperature: Temperature of the flue gas entering the amine scrubber system.

◦ NaOH Caustic: This is the amount of NaOH Caustic required for the SO2

polisher.

◦ Water: This is the flow rate of water into the Direct Contact Cooler.

• Flue Gas Exiting Amine System

◦ Temperature Out: Temperature of the flue gas exiting the amine scrubber

system.


CCS System (Amine): Diagram


◦ Flue Gas Out: Volumetric flow rate of the flue gas exiting the amine scrubber.

◦ Fly Ash Out: Total solids mass flow rate in the flue gas exiting the amine

scrubber.

◦ Mercury Out: Total mass of mercury exiting the amine scrubber. The value is a


• Amine System Performance

◦ NH3 Generation: The flow rate of ammonia by product produced in the amine

scrubbing process.

◦ CO2 Removal: Actual removal efficiency of CO2 in the amine scrubber.

◦ Sorbent Circ.: (Not shown for Cansolv.) The flow rate of the sorbent through the

amine scrubber system.

◦ CO2 Product: Actual amount of CO2 produced as a result of the amine

scrubbing.

◦ CO2 Pressure: Compressed CO2 product pressure. The product stream is

compressed and sent through the pipeline system to the configured sequestration

system.


◦ Reclaimer Waste: (Not shown for Cansolv.) Total solids mass flow rate of solids

removed from the amine scrubber.

5.2.3.8.1.2. Flue Gas


amine system. For each component, quantities are given in both moles and mass per hour:


CCS System (Amine): Flue Gas



Components. Use the scroll bar at the bottom to view the whole table.

5.2.3.8.1.3. Bypass






CCS System (Amine): Bypass




The amine system has the following process areas:

• SO2 Polisher/Direct Contact Cooler (PC) or Direct Contact Cooler (NGCC): This

area includes the equipment required to cool the flue gas in order to improve

absorption of CO2 into the amine sorbent. For PC plants, an SO2 polisher may be used

to reduce the SO2 concentration to very low levels. For all plant types, a direct contact

cooler is typically used in plant configurations that do not include a wet FGD. A direct

contact cooler is a large vessel where the incoming hot flue gas is placed in contact

with cooling water. The cost is a function of the gas flow rate and temperature of the

flue gas. In case of coal-fired power plant applications that have a wet FGD (flue gas

desulfurization) unit upstream of the amine system, the wet scrubber helps in

substantial cooling of the flue gases, and additional cooler may not be required

• Flue Gas Blower: The flue gas has to overcome a substantial pressure drop as it

passes through a very tall absorber column, countercurrent to the sorbent flow. Hence

the cooled flue gas has to be pressurized using a blower before it enters the absorber.

• CO2 Absorber Vessel: This is the vessel where the flue gas is made to contact with

the MEA-based sorbent, and some of the CO2 from the flue gas gets dissolved in the

sorbent. The column may be plate-type or a packed one. Most of the CO2 absorbers

are packed columns using some kind of polymer-based packing to provide large

interfacial area.

• Heat Exchangers: The CO2-loaded sorbent needs to be heated in order to strip off

CO2 and regenerate the sorbent. On the other hand, the regenerated (lean) sorbent

coming out of the regenerator has to be cooled down before it could be circulated

back to the absorber column. Hence these two sorbent streams are passed through a

cross heat exchanger, where the rich (CO2-loaded) sorbent gets heated and the lean

(regenerated) sorbent gets cooled.

• Circulation Pumps: The cost associated with the equipment required to support FGD

system operation such as makeup water and instrument air are treated here.


CCS System (Amine): Capital Cost


• Sorbent Regenerator: This is the column where the weak intermediate compound

(carbamate) formed between the MEA-based sorbent and dissolved CO2 is broken

down with the application of heat and CO2 gets separated from the sorbent to leave

reusable sorbent behind. In case of unhindered amines like MEA, the carbamate

formed is stable and it takes large amount of energy to dissociate. It also consists of a

flash separator where CO2 is separated from most of the moisture and evaporated

sorbent, to give a fairly rich CO2 stream.

• Reboiler: The regenerator is connected with a reboiler which is basically a heat

exchanger where low-pressure steam extracted from the power plant is used to heat

the loaded sorbent.

• Steam Extractor: In case of coal-fired power plants that generate electricity in a

steam turbine, a part of the LP/IP steam has to be diverted to the reboiler for sorbent

regeneration. Steam extractors are installed to take out steam from the steam turbines.

• Sorbent Reclaimer: Presence of acid gas impurities (SO2, SO3, NO2 and HCl) in the

flue gas leads to formation of heat stable salts in the sorbent stream, which cannot be

dissociated even on application of heat. In order to avoid accumulation of these salts

in the sorbent stream and to recover some of this lost MEA sorbent, a part of the

sorbent stream is periodically distilled in this vessel. Addition of caustic helps in

freeing of some of the MEA. The recovered MEA is taken back to the sorbent stream

while the bottom sludge (reclaimer waste) is sent for proper disposal.

• Sorbent Processing: The regenerated sorbent has to be further cooled down even

after passing through the rich/lean cross heat exchanger using a cooler, so that the

sorbent temperature is brought back to acceptable level (about 40 deg C). Also, in

order to make up for the sorbent losses, a small quantity of fresh MEA sorbent has to

be added to the sorbent stream. So, the sorbent processing area primarily consists of

sorbent cooler, MEA storage tank, and a mixer. It also consists of an activated carbon

bed filter that adsorbs impurities (degradation products of MEA) from the sorbent

stream.

• Drying and Compression Unit: The CO2 product may have to be carried very long

distances via pipelines. Hence it is desirable that it does not contain any moisture in

order to avoid corrosion in the pipelines. Also, it has to be compressed to very high

pressures so that it gets liquefied and can overcome the pressure losses during the

pipeline transport. The multi-stage compression unit with inter-stage cooling and

drying yields a final CO2 product at the specified pressure (about 2000 psig) that

contains moisture and other impurities (e.g., N2) at acceptable levels.

• Auxiliary Natural Gas Boiler: The cost of the natural gas boiler is estimated on the

basis of the steam flow rate generated from the auxiliary boiler.

• Auxiliary Steam Turbine: The regeneration heat is provided in the form of low

pressure (LP) steam extracted from the steam turbine (in case of coal-fired power

plants and combined-cycle gas plants), through the reboiler (a heat exchanger). In

case of simple cycle natural gas fired power plants, a heat recovery unit maybe

required.


5.2.3.8.1.5. O&M Cost


The amine system has the following variable cost components:

• Sorbent: (Not shown for Cansolv.) This is the annual cost of the sorbent used in the

system. This is a function of the concentration of CO2 in the flue gas and the flue gas

flow rate.

• Process Chemicals: (Only shown for Cansolv.) Process Chemicals include Ion

Exchange Resin, NaOH, Cansolv Solvent and Triethylene Glycol.

• Auxiliary Gas (PC) or Natural Gas (NGCC): If the user has added an auxiliary

natural gas boiler, the cost of the natural gas used to fuel the boiler is added here.

• Corrosion Inhibitor: (Not shown for Cansolv.) The inhibitor helps in two ways:

reduced sorbent degradation and reduced equipment corrosion. This is the annual cost

of the corrosion inhibitor.

• Activated Carbon: (Not shown for Cansolv.) This is the cost of activated carbon

used to adsorb impurities from the sorbent (degradation products of MEA).

• Caustic (NaOH): (Not shown for Cansolv.) This is the annual cost of caustic. The

presence of acid gas impurities (SO2, SO3, NO2 and HCl) in the flue gas leads to

formation of heat stable salts in the sorbent stream, which cannot be dissociated even

on application of heat. In order to avoid accumulation of these salts in the sorbent

stream and to recover some of this lost MEA sorbent, a part of the sorbent stream is

periodically distilled in this vessel. Addition of caustic helps in freeing of some of the

MEA. The recovered MEA is taken back to the sorbent stream while the bottom

sludge (reclaimer waste) is sent for proper disposal.

• Reclaimer Waste Disposal: (Not shown for Cansolv.) This is the reclaimer waste

disposal cost per year.

• Electricity: The cost of electricity consumed by the Amine System.


CCS System (Amine): O&M Cost


• Auxiliary Power Credit: An auxiliary natural gas boiler can be added by the user to

provide steam and power for the Amine System. If it is added by the user then the

additional power it provides is subtracted from the overall operating and maintenance

cost.

• Water: This is the annual cost for water to the amine scrubber system; it is mainly

required for cooling and also as process makeup.

• CO2 Transport: The CO2 captured at the power plant site has to be carried to the

appropriate storage/disposal site. Transport of CO2 to a storage site is assumed to be

via pipeline. This is the annual cost of maintaining those pipelines.

• CO2 Storage: Once the CO2 is captured, it needs to be securely stored (sequestered).

This cost is based on option chosen on the "T&S Config" parameter screen. (See


• Auxiliary CCS Cooling System: (Only shown when an air cooled condenser is



5.2.3.8.1.6. Total Cost


99.


CCS System (Amine): Total Cost


5.2.3.8.1.7. Summary

The table on the left displays a summary of information that is key to the model calculations.

This information is also available elsewhere in the model. The following important

performance and cost factors are shown:

• Net Plant Size (MW): This is the net plant capacity, which is the gross plant capacity


• Annual Operating Hours (hours): This is the number of hours per year that the

plant is in operation. If a plant runs 24 hours per day, seven days per week, with no

outages, the calculation is 24 hours * 365 days, or 8,760 hours/year.

• Annual CO2 Removed (ton/yr): This is the amount of CO2 removed from the flue

gas by the CO2 capture system per year.

• Annual SO2 Removed (ton/yr): This is the amount of SO2 removed from the flue gas

by the CO2 capture system per year.



• Annual NO2 Removed (ton/yr): This is the amount of NO2 removed from the flue


• Annual HCl Removed (ton/yr): This is the amount of HCl removed from the flue


• Flue Gas Fan Use (MW): The flue gas has to be compressed in a flue gas blower so

that it can overcome the pressure drop in the absorber tower. This is the electrical

power required by the blower.

• Sorbent Pump Use (MW): The solvent has to flow through the absorber column

(generally through packed media) countercurrent to the flue gas flowing upwards.

This is the power required by the solvent circulation pumps to supply pressure to

overcome the pressure losses encountered by the solvent in the absorber column.

• CO2 Compression Use (MW): This is the electrical power required to compress the

CO2 product stream to the designated pressure. Compression of CO2 to high pressures




takes lot of power, and is a principle contributor to the overall energy penalty of a

CO2 capture unit in a power plant.

• Auxiliary Power Produced (MW): If an auxiliary natural gas boiler is used to

provide steam and power for the Amine System, this is the additional electricity that it

produces.

• Sorbent Regeneration Equiv. Energy (MW): This is the electrical equivalent power

for the regeneration steam required (taken from the steam cycle). The equivalent

electricity penalty is about 10-15% of the actual regeneration heat requirement.

• Makeup Water for Auxiliary Cooling: (Only shown when an Air Cooled Condenser

is configured.) An auxiliary cooling system is needed for amine-based carbon capture

when an air-cooled condenser (for dry cooling) is chosen as the plant cooling system.

This is the makeup water required for the auxiliary cooling system.

See "5.1.1.3. Cost of CO2 Avoided & Captured" on page 94 for a description of the table on the

right.


The ammonia-based CO2 scrubber is a post-combustion capture technology. It may be used in the


5.2.3.8.2.1. Diagram

This screen shows a diagram of the ammonia system:


• Reagent

◦ Lean Solv. Flow: This is the lean solvent circulation flow rate.

◦ Ammonia: This is the makeup solvent.

◦ Water: This is the water used to dilute the makeup solvent.


CCS System (Ammonia): Diagram


• DCC

◦ Makeup Water: This is the amount of makeup water required.

◦ Reclaimer Waste: Total solids mass flow rate of solids removed from the

ammonia scrubber.

◦ Cooling Water: This is the total cooling water required for the ammonia system.

◦ Chilled Water: This is the amount of chilled water required for all of the chillers

in the ammonia system.

◦ Bleed Water: This is the amount of bleed water.

◦ Refrig. Req.: This is the amount of refrigeration required for all of the chillers in

the ammonia system.

• Flue Gas Entering Ammonia System

◦ Temperature In: Temperature of the flue gas entering the ammonia system.

◦ Flue Gas In: Volumetric flow rate of flue gas entering the ammonia system.

◦ Fly Ash In: Total solids mass flow rate in the flue gas entering the ammonia

system. This is determined by the solids exiting from the module upstream.

◦ Mercury In: Total mass of mercury entering the ammonia system. The value is a


• Flue Gas Exiting Ammonia System

◦ Temperature Out: Temperature of the flue gas exiting the ammonia system.

◦ Flue Gas Out: Volumetric flow rate of the flue gas exiting the ammonia system

◦ Fly Ash Out: Total solids mass flow rate in the flue gas exiting the ammonia

system.

◦ Mercury Out: Total mass of mercury exiting the ammonia system. The value is a


• Ammonia System Performance

◦ CO2 Product: Actual amount of CO2 produced.

◦ CO2 Pressure: Compressed CO2 product pressure. The product stream is

compressed for transport to a sequestration site.

◦ CO2 Removal: Actual removal efficiency of CO2.

◦ Rich Stream Solids: This is the percentage by weight of solids in the rich

solution.


5.2.3.8.2.2. Flue Gas


ammonia system. For each component, quantities are given in both moles and mass per hour:


Components.


CCS System (Ammonia): Flue Gas


5.2.3.8.2.3. Bypass






CCS System (Ammonia): Bypass




The amine system has the following process areas:

• Direct Contact Coolers: A direct contact cooler is a large vessel where the incoming

hot flue gas is placed in contact with cooling water. The cost is a function of the gas

flow rate and temperature of the flue gas.





• Chiller System: The total cost for the Chiller System is based on the chilling loads

required by the ammonia-based CO2 capture system.

• CO2 Absorber Vessel: This includes absorber towers and circulating water pumps.





• Circulation Pumps: This includes solvent circulation pumps and cooling water

circulation pumps.

• Sorbent Regenerator: This includes the CO2 stripper and regeneration reboiler.

• Ammonia Water Wash: A water wash is used to remove ammonia from absorber

gasses before they are released to the stack.



• Sorbent Processing and Reclaimer: This section prepares the sorbent for reuse.


CCS System (Ammonia): Capital Cost


• Drying and Compression Unit: The product CO2 must be separated from the water

vapor (dried) and compressed to liquid form in order to transport it over long



CO2 flow rate.

• NH3 Stripping: This includes the NH3 stripper and cleanup pumps.








5.2.3.8.2.5. O&M Cost


The ammonia system has the following variable cost components:

• Ammonia: This is the annual cost of ammonia used in the system. This is a function

of the concentration of CO2 in the flue gas and the flue gas flow rate.

• Auxiliary Gas: If the user has added an auxiliary natural gas boiler, the cost of the

natural gas used to fuel the boiler is added here.

• Reclaimer Waste Disposal: This is the reclaimer waste disposal cost per year.

• Electricity: The cost of electricity consumed by the ammonia system.


provide steam and power for the Amine System. If it is added by the user then the

additional power it provides is subtracted from the overall operating and maintenance

cost.


CCS System (Ammonia): O&M Cost


• Water: This is the annual cost for water to the ammonia system; it is mainly required

for cooling and also as process makeup.










5.2.3.8.2.6. Total Cost


99.


CCS System (Ammonia): Total Cost


5.2.3.8.2.7. Summary




• Net Electrical Output (MW): This is the net plant capacity, which is the gross plant

capacity minus the losses due to plant equipment and pollution equipment (energy

penalties).














• Flue Gas Blower (MW): The flue gas has to be compressed in a flue gas blower so



• Total Pump Use (MW): This is the total power use by all of the pumps in the

ammonia system.

• Chiller Use: This is the total power use by all of the chillers in the ammonia system.




CCS System (Ammonia): Summary




• Auxiliary Power Produced (MW): If an auxiliary natural gas boiler is used to

provide steam and power for the Amine System, this is the additional electricity that it

produces.

• Steam Equivalent Energy (MW): This is the electrical equivalent power for the

regeneration steam required (taken from the steam cycle). The equivalent electricity

penalty is about 10-15% of the actual regeneration heat requirement.

• Makeup Water for Aux. Cooling: (Only shown when an Air Cooled Condenser is

configured.) This is the makeup water for the auxiliary cooling system needed when

an Air Cooled Condenser is used as the plant cooling system.


right.

5.2.3.8.3. Chemical Looping (CCS System)

Post-combustion chemical looping uses a calcium looping (CaL) process for CO2 capture. This

process has 2 steps: calcination and carbonation. The calciner heats calcium carbonate (CaCO3),

thereby breaking it down into CaO and CO2. The CO2 is removed for purification and storage.

The CaO is removed from the calciner and fed to the carbonator, which cools it and exposes it to

the flue gas. The CaO combines with the CO2 in the flue gas to produce CaCO3, thereby reducing

the concentration of CO2 in the flue gas.


This screen shows a diagram of the chemical looping system:


• Flue Gas In: This is the flow rate of flue gas entering the carbonator.

• Temperature: This is the temperature of flue gas entering the carbonator.

• Flue Gas Out: This is the flow rate of flue gas exiting the carbonator.


CCS System (Chemical Looping): Chemical Looping Diagram


• Temperature: This is the temperature of the flue gas exiting the carbonator.

• Rich Sorbent: This is the flow rate of rich sorbent exiting the carbonator.

• Temperature: This is the temperature of rich sorbent exiting the carbonator.

• Makeup LS: This is the flow rate of makeup sorbent (Limestone).

• Lean Sorbent: This is the flow rate of lean sorbent exiting the calciner.

• Temperature: This is the temperature of lean sorbent exiting the calciner.

• Solids Purge: This is the sorbent purge flow rate.

• Coal: This is the flow rate of coal entering the calciner.

• CO2 Product: This is the CO2 (and impurities) captured and exiting from the sorbent

regenerator after being treated in the CO2 absorber.

• Ox. from ASU: This is the flow rate of oxidant from the ASU.

5.2.3.8.3.2. Air Separation Diagram

This screen shows a diagram of the chemical looping system's air separation unit:

Each result is described briefly below in flow order:

• Atmospheric Air

o Temperature In: Temperature of the atmospheric air entering the air

separation unit.

o Air In: Mass flow rate of air entering the air separation unit, based on the

atmospheric air temperature and atmospheric pressure.

o Air In: Volumetric flow rate of air entering the air separation unit, based on

the atmospheric air temperature and atmospheric pressure.


CCS System (Chemical Looping): Air Separation Diagram


• Nitrogen

o Nitrogen Out: Mass flow rate of the nitrogen exiting the Air Separation

Unit.

o Nitrogen Out: Volumetric flow rate of the nitrogen exiting the Air

Separation Unit.

• Oxidant

o Temperature Out: Temperature of the oxidant exiting the Air Separation

Unit.

o Oxidant Out: Mass flow rate of the oxidant exiting the Air Separation Unit.

o Oxidant Out: Volumetric flow rate of the oxidant exiting the Air Separation

Unit.

• Water

o Water Out: This is the amount of water precipitated out of the ASU.

5.2.3.8.3.3. Heat Recovery System Diagram

This screen shows a diagram of the chemical looping system's heat recovery system:


• Flue Gas Exhaust In: This is the flue gas exiting the carbonator and entering the heat

recovery system. The following attributes are reported:

o Flow

o Temperature

• Calciner CO2 Exhaust In: This is the CO2 product stream exiting the sorbent

regenerator and entering the calciner. The following attributes are reported:

o Flow

o Temperature


CCS System (Chemical Looping): Heat Recovery System Diagram


• Calciner CO2 Exhaust Out: This is the CO2 product stream exiting the calciner. The

following attributes are reported:

o Flow

o Temperature

• Flue Gas Exhaust Out: This is the flue gas exiting the heat recovery system. The

following attributes are shown:

o Flow

o Temperature

• Steam from Carbonator Cooling

o Flow: This is the flow rate of steam produced by the cooling process.

• Water

o Cooling Water: This is the amount of water required by the heat recovery

system.

o Cond. Steam: This is the amount of condensed steam on the heat recovery

system.

5.2.3.8.3.4. Flue Gas


chemical looping system. For each component, quantities are given in both moles and mass per

hour:




CCS System (Chemical Looping): Flue Gas


5.2.3.8.3.5. Bypass


chemical looping system. For each component, quantities are given in both moles and mass per

hour:




CCS System (Chemical Looping): Bypass




The chemical looping system has the following process areas:

• Carbonator: The carbonator converts CaO and CO2 to CaCO3, thereby reducing the

concentration of CO2 in the flue gas.

• Calciner: The calciner converts CaCO3 to CaO and CO2. The CO2 is sent to storage.

• ASU: The Air Separation Unit (ASU) provides pure oxygen to the calciner.

• Blowers: Blowers are used to offset pressure drops in both the calciner and the

carbonator.

• CO2 Product Compressor: The product CO2 must be separated from the water vapor




rate.

• CO2 Purification Unit: The product CO2 is purified before being compressed.

• Coal Handling Equipment for ASU: This is the coal handling equipment used by

the Air Separation Unit (ASU).

• Solids Handling Equipment: This is the solids handling equipment for the calciner

and carbonator.

• Steam Turbine for Power Generation: A steam turbine is used to generate power for

the chemical looping system.


CCS System (Chemical Looping): Capital Cost


5.2.3.8.3.7. O&M Cost



• Sorbent: This is the annual cost of the sorbent used in the system. This is a function


• Coal: This is the cost of coal.

• Caustic (NaOH): This is the cost of NaOH caustic used by the SO2 polisher.

• Waste Disposal: This is the waste disposal cost per year.

• Solid By-product Credit: This is the annual income from selling the solid by-

product.

• Electricity: The cost of electricity consumed by the Chemical Looping System.

• Auxiliary Power Credit: This is the annual credit for power generated by the

recovered heat.











CCS System (Chemical Looping): O&M Cost


5.2.3.8.3.8. Total Cost


99.

5.2.3.8.3.9. Summary


CCS System (Chemical Looping): Total Cost


CCS System (Chemical Looping): Summary







penalties).














• Flue Gas Fan Use (MW): The flue gas has to be compressed in a flue gas blower so



• Oxidant Blower Use (MW): This is the power required for pumping the oxidant

exiting the air separation unit.





• ASU Power Use: This is the electrical power used by the air separation unit.

• Auxiliary Power Produced (MW): This is the power produced by the heat recovery

system.


right.

5.2.3.8.4. Membrane System (CCS System)

This process uses a CO2-permeable membrane to capture CO2.


5.2.3.8.4.1. Diagram

5.2.3.8.4.1.1. "2-Step w/ Air Sweep" and "NETL 2-Step w/ Sweep"

The following results are shown:

• Temperature In: This is the temperature of flue gas entering the membrane

system.

• Flue Gas In: This is the flow rate of flue gas entering the membrane system.

• Water: (Only shown for 2-Step w/ Air Sweep) This is the amount of water

condensed out from the permeate stream.

• Total Membrane Area: This is the total membrane surface area.

• Air + CO2 to Boiler: This is the flow rate of combustion air + permeated CO2

recycled to the boiler.

• Air: This is the flow rate of combustion air used as a sweep gas.

• Temperature Out: This is the temperature of flue gas exiting the membrane

system.

• Flue Gas Out: This is the flow rate of flue gas exiting the membrane system.

• CO2 Product: This is the amount of CO2 captured.

• Water: This is the amount of water removed by the CPU.

• Vented Gas: This is the amount of CO2 vented at the CPU. In the "2-Step w/ Air

Sweep" case, all components of the vented gas are included, not just CO2.


CCS System (Membrane): Diagram (2-Step w/ Air Sweep)


5.2.3.8.4.1.2. 2-Stage Cascade


• Temperature In: This is the temperature of flue gas entering the membrane

system.

• Flue Gas In: This is the flow rate of flue gas entering the membrane system.

• Fly Ash In: This is the flow rate of fly ash entering the membrane system.

• Mercury In: This is the flow rate of mercury entering the membrane system.

• NaOH Caustic: This is the flow rate of NaOH caustic required for the SO2

polisher.

• Membrane Size

o 1st Stage: This is the separation area of the first-stage membrane.

o 2nd Stage: This is the separation area of the second-stage membrane.

• Design Pressure

o Feed Side: This is the feed-side pressure.

o Permeate Side: This is the permeate-side pressure.

• Temperature Out: This is the temperature of flue gas exiting the membrane

system.

• Flue Gas Out: This is the flow rate of flue gas exiting the membrane system.

• Fly Ash Out: This is the flow rate of fly ash exiting the membrane system.

• Mercury Out: This is the flow rate of mercury exiting the membrane system.

• CO2 Captured: This is the amount of CO2 captured.

• Impurities: This is the amount of impurities in the CO2 product.


CCS System (Membrane): Diagram (2-Stage Cascade)


• CO2 Pressure: This is the compressed CO2 product pressure. The product stream is

compressed and sent through the pipeline system to the configured sequestration

system.

• CO2 Removal: This is the CO2 removal efficiency.

5.2.3.8.4.2. Flue Gas


membrane system. For each component, quantities are given in both moles and mass per hour:



Note that the "Polisher Out" columns are not shown for the "2-Stage Cascade" configuration.


CCS System (Membrane): Flue Gas


5.2.3.8.4.3. Bypass

This screen displays a table of quantities of flue gas components entering and bypassing the 2-

Stage Cascade membrane system. (It is only shown for that configuration.) For each

component, quantities are given in both moles and mass per hour:




CCS System (Membrane): Bypass


5.2.3.8.4.4. Purif. Gas

(Only shown for the "2-Step w/ Air Sweep" configuration.) This screen shows the flow of flue

gas through the CPU.




CCS System (Membrane): Purif. Gas




The membrane system has the following process areas:

• Membrane Module: (Not shown for NETL 2-Step w/ Sweep) This is the direct cost

of the membrane module.

• Membrane Frame: (Not shown for NETL 2-Step w/ Sweep) This is the direct cost of

the membrane frame structure.

• Compressors: (Only shown for 2-Stage Cascade) This is the direct cost of the feed-

side compressors.

• Expander: (Only shown for 2-Stage Cascade) This is the direct cost of the expander.

• Vacuum Pumps: (Not shown for NETL 2-Step w/ Sweep) This is the direct cost of

the permeate-side vacuum pumps.

• Heat Exchangers: (Only shown for 2-Stage Cascade) This is the direct cost of the

heat exchangers.

• CO2 Drying and Compression Unit: (Only shown for 2-Stage Cascade) CO2 is dried

and compressed to liquid form for transport over long distances.

• CO2 Cryogenic Purification Unit: (Only shown for 2-Step w/ Air Sweep) The CPU

purifies, dries and compresses the CO2.

• CO2 Removal System: (Only shown for NETL 2-Step w/ Sweep) This is the direct

cost of the CO2 removal system.

• CO2 Compression: (Only shown for NETL 2-Step w/ Sweep) This is the direct cost

of the CO2 compression system.


CCS System (Membrane): Capital Cost


5.2.3.8.4.6. O&M Cost



• Membrane Replacement Cost

• Electricity: The cost of electricity consumed by the Amine System.

• Caustic (NaOH): (Only shown for 2-Stage Cascade) This is the cost of NaOH caustic

used by the SO2 polisher.

• Water: (Only shown for 2-Stage Cascade) This is the annual cost for water.











CCS System (Amine): O&M Cost


5.2.3.8.4.7. Total Cost

This is a standard total cost result table as described in ""5.1.1.7. Total Cost Results" on page

99.

5.2.3.8.4.8. Summary


CCS System (Membrane): Total Cost







• Net Electrical Output: This is the net plant capacity, which is the gross plant


penalties).



calculation is 24 hours * 365 days, or 8,760 hours/year.

• Annual CO2 Removed: This is the amount of CO2 removed from the flue gas by the

CO2 capture system per year.

• Annual SO2 Removed: This is the amount of SO2 removed from the flue gas by the




• Annual NO2 Removed: This is the amount of NO2 removed from the flue gas by the


• Annual HCl Removed: (Only shown for 2-Stage Cascade) This is the amount of HCl

removed from the flue gas by the CO2 capture system per year.

• Feed Compressors Use: (Only shown for 2-Stage Cascade) This is the energy

required to compress the flue gas feed.

• Expander Power Recovery: (Only shown for 2-Stage Cascade) This is the energy

recovered by the expander.

• Vacuum Pump Power Use: This is the energy used by the permeate-side vacuum

pumps.

• CO2 Compression Power Use: (Not shown for 2-Step w/ Air Sweep) This is the

electrical power required to compress the CO2 product stream to the designated

pressure. Compression of CO2 to high pressures takes lot of power and is a principle

contributor to the overall energy penalty of a CO2 capture unit in a power plant.

• CO2 Purification Use: (Only shown for 2-Step w/ Air Sweep) This is the energy

required by the CPU.

• Total Membrane Area: This is the total membrane surface area.





right.

5.2.3.8.5. Solid Sorbents PSA (CCS System)

This is a solid sorbents-based pressure swing adsorption (PSA) system for CO2 removal.


5.2.3.8.5.1. Diagram

This screen shows a diagram of the solid sorbents PSA system:


• Sorbent

◦ Sorbent Makeup: This is the amount of sorbent makeup required to replace

degraded sorbent.

◦ Sorbent Req.: This is the total amount of sorbents required.

• Condenser

◦ Water Removed: This is the water removed from the flue gas by the cooler &

condenser.

• Flue Gas Entering Solid Sorbents PSA System

◦ Temperature In: This is the temperature of the flue gas entering the PSA

process.

◦ Gas Flow In: This is the volumetric flow rate of flue gas entering the PSA

process.

◦ Fly Ash In: This is the total solids mass flow rate in the flue gas entering the PSA

process. It is determined by the solids exiting from the module upstream.

◦ Mercury In: This is the total mass of mercury entering the PSA process. The


◦ NaOH Caustic: This is the NaOH caustic required by the SO2 polisher.

• Flue Gas Exiting Solid Sorbents PSA System

◦ Temperature Out: This is the temperature of the flue gas exiting the PSA

process.

◦ Flue Gas Out: This is the volumetric flow rate of the flue gas exiting the PSA

process.


CCS System (Solid Sorbents PSA): Diagram


◦ Fly Ash Out: This is the total solids mass flow rate in the flue gas exiting the

PSA process.

◦ Mercury Out: This is the total mass of mercury exiting the ammonia system.


particulate).

• Solid Sorbents PSA System Performance

◦ CO2 Captured: This is the flow rate of CO2 in the CO2 product stream.

◦ Impurities: This is the flow rate of impurities in the CO2 product stream.

◦ CO2 Pressure: This is the CO2 product pressure as it leaves the compressor. The

product stream is compressed and sent through the pipeline system to the

configured sequestration system.

◦ CO2 Removal Eff.: This is the actual removal efficiency of CO2.

5.2.3.8.5.2. Flue Gas

This screen displays a table of quantities of flue gas components entering and exiting the solid

sorbents PSA system. For each component, quantities are given in both moles and mass per

hour:


Components.


CCS System (Solid Sorbents PSA): Flue Gas


5.2.3.8.5.3. Bypass


solid sorbents PSA system. For each component, quantities are given in both moles and mass

per hour:




CCS System (Solid Sorbents PSA): Bypass



This is a capital cost result screen as described in ""5.1.1.2. Capital Cost Results" on page 93.

The solid sorbents PSA system has the following process areas:

• Flue Gas Cooler and Condenser: This is the cooler and condenser for inlet flue gas.

• PSA System: This is a fixed-bed PSA system.









• Exhaust Flue Gas Expander: This is the expander for flue gas exiting the PSA

system.

• Vacuum Pump: This is the vacuum pump used for the CO2 product stream.

• Compressing CO2 Product Stream: The CO2 product stream is compressed to

atmospheric pressure from vacuum.

• CO2 Purification and Compression: A cryogenic purification unit (CPU) is used to

purify, dry and compress the CO2 in preparation for transport.


CCS System (Solid Sorbents PSA): Capital Cost


5.2.3.8.5.5. O&M Cost


The solid sorbents PSA system has the following variable cost components:

• Cooler and Condenser:

• Sorbent: This is the annual cost of the sorbent used in the system. This is a function


• Electricity: The cost of electricity consumed by the solid sorbents PSA system.


• Water: This is the annual cost for water to the amine scrubber system; it is mainly












CCS System (Solid Sorbents PSA): O&M Cost


5.2.3.8.5.6. Total Cost


99.

5.2.3.8.5.7. Summary


CCS System (Solid Sorbents PSA): Total Cost


CCS System (Solid Sorbents PSA): Summary







penalties).














• Feed Blower Power Use (MW): This is the amount of power used by the flue gas

blower.

• Expander Power Recovery (MW): This is the amount of power recovered by the

expander.

• Vacuum Pump: This is the amount of power used by the vacuum pump.









right.

5.2.3.8.6. Solid Sorbents TSA (CCS System)

This is a solid sorbents-based temperature swing adsorption (TSA) system for CO2 removal.


5.2.3.8.6.1. Diagram

This screen shows a diagram of the solid sorbents TSA system:


• Flue Gas from Polisher: This is the flow rate of flue gas exiting the SO2 polisher and

entering the CO2 adsorber.

• Makeup Sorb: This is the flow rate of makeup sorbent entering the adsorber.

• Lean Sorbent: This is the flow rate of lean sorbent leaving the regenerator and

entering the adsorber.

• Rich Sorbent: This is the flow rate of rich sorbent leaving the adsorber and entering

the regenerator.

• Cooling Water: Water and steam are used to transfer heat between the heat

exchangers.

• Regen Steam: This is the steam used to heat the solids in the regenerator.

• Purge Steam: This is the steam used to achieve the desired CO2 partial pressure in

the regenerator.

• Sorbent Purge: This is the total purge flow rate exiting the regenerator.

• Flue Gas to Stack: This is the flow rate of flue gas leaving the adsorber.

• CO2 Product: This is the flow rate of CO2 product from the cryogenic purification

unit (CPU).


CCS System (Solid Sorbents TSA): Diagram


5.2.3.8.6.2. Flue Gas

This screen displays a table of quantities of flue gas components entering and exiting the solid

sorbents TSA system. For each component, quantities are given in both moles and mass per

hour:


Components. Use the scroll bar at the bottom to see the whole table.


CCS System (Solid Sorbents TSA): Flue Gas


5.2.3.8.6.3. Bypass


solid sorbents TSA system. For each component, quantities are given in both moles and mass

per hour:




CCS System (Solid Sorbents TSA): Bypass




The solid sorbents PSA system has the following process areas:

• CO2 Absorber Vessel: This area deals with the absorber. The capital cost of the

absorber will go down with higher MEA concentration and higher CO2 loading level

of the solvent, and lower CO2 content in the lean solvent.

• Sorbent Regenerator: This area deals with the sorbent regenerator. The regenerator

(or stripper) is a column where the weak intermediate compound (carbamate) is

broken down by the application of heat. The result is the release of CO2 (in

concentrated form) and return of the recovered sorbent back to the absorber. This

process is accomplished by the application of heat using a heat exchanger and low-

pressure steam. MEA requires substantial heat to dissociate the carbamate. Therefore,

a flash separator is also required, where the CO2 is separated from the moisture and

evaporated sorbent to produce a concentrated CO2 stream.

• Heat Exchangers: This area deals with the heat exchangers. The CO2-loaded sorbent

must be heated in order to strip off CO2 and regenerate the sorbent. In addition, the

regenerated sorbent must be cooled down before it can be recirculated back to the

absorber column. Heat exchangers are used to accomplish these two tasks. This area

is a function of the sorbent flow rate.

• Sorbent Handling: This area deals with the sorbent handling. The sorbent processing

area primarily consists of a sorbent cooler, MEA storage tank, and a mixer. The

regenerated sorbent is further cooled with the sorbent cooler and MEA added to make

up for sorbent losses.

• Circulation Pumps: This area deals with the circulation pumps. Circulation pumps

are required to take the sorbent, introduced at atmospheric pressure, and lift it to the

top of the absorber column. This area is a function of the sorbent flow rate.

• CO2 Drying and Compression: This area deals with the CO2 drying and

compression. The product CO2 must be separated from the water vapor (dried) and


CCS System (Solid Sorbents TSA): Capital Cost


compressed to liquid form in order to transport it over long distances. The multi-stage

compression unit with inter-stage cooling and drying yields a final CO2 product at the

nominal pressure of 2000 psig. This area is a function of the CO2 flow rate.

• Flue Gas Blower: This area deals with the flue gas blower. The flue gas enters the

bottom of the absorber column and flows upward, countercurrent to the sorbent flow.

Blowers are required to overcome the substantial pressure drop as it passes through a

very tall absorber column. The cost is a function of the volumetric flow rate of the

flue gas.

• Sorbent Storing: This area deals with the sorbent storing. A portion of the sorbent

stream is distilled in the reclaimer in order to avoid accumulation of heat stable salts

in the sorbent stream. Caustic is added to recover some of the MEA in this vessel. The

reclaimer cost is a function of the sorbent makeup flow rate.

• Steam Extractor: This area deals with the steam extractor. Steam extractors are

installed to take low pressure steam from the steam turbines in the power plant. The

cost is a function of the steam flow rate.

• Direct Contact Cooler: This area deals with the direct contact cooler. A direct

contact cooler is typically used in plant configurations that do not include a wet FGD.

A direct contact cooler is a large vessel where the incoming hot flue gas is placed in

contact with cooling water. The cost is a function of the gas flow rate and temperature

of the flue gas.

• Cyclone Bank: This area deals with the cyclone bank. The regenerator is connected

to a reboiler, which is a heat exchanger that utilizes low pressure steam to heat the

loaded sorbent. The reboiler is part of the sorbent regeneration cycle. The cost is a

function of the sorbent and steam flow rates.

• Auxiliary Gas Boiler: This area deals with the auxiliary gas boiler. An auxiliary

natural gas boiler is typically combined with a steam turbine to generate some

additional power and/or low pressure steam. The cost is a function of the steam flow

rate generated by the boiler. The boiler cost is lower if electricity is not being

produced.

• Auxiliary Steam Turbine: This area deals with the auxiliary steam turbine. The

steam turbine is used in conjunction with the natural gas boiler to generate some

additional power and/or low-pressure steam. The cost is a function of the secondary

power generated by the turbine.

• Steam Compressor: This area deals with the steam compressor. Water and steam are

used to transfer heat between the heat exchangers.


5.2.3.8.6.5. O&M Cost


The solid sorbents TSA system has the following variable cost components:

• Solid Sorbent: This is the annual cost of the solid sorbent used in the system. This is

a function of the concentration of CO2 in the flue gas and the flue gas flow rate.

• Auxiliary Gas: If the user has added an auxiliary natural gas boiler, the cost of the

natural gas used to fuel the boiler is added here.


• Reclaimer Waste Disposal: This is the reclaimer waste disposal cost per year.

• Electricity: The cost of electricity consumed by the solid sorbents TSA system.


provide steam and power for the Solid Sorbents TSA System. If it is added by the user

then the additional power it provides is subtracted from the overall operating and

maintenance cost.

• Water: This is the annual cost for water to the solid sorbents TSA system; it is mainly












CCS System (Solid Sorbents TSA): O&M Cost


5.2.3.8.6.6. Total Cost


99.

5.2.3.8.6.7. Summary


CCS System (Solid Sorbents TSA): Total Cost


CCS System (Solid Sorbents TSA): Summary







penalties).



calculation is 24 hours * 365 days, or 8,760 hours/year.







• Annual NO2 Removed: This is the amount of NO2 removed from the flue gas by the


• Annual HCl Removed: This is the amount of HCl removed from the flue gas by the


• Flue Gas Fan Use: The flue gas has to be compressed in a flue gas blower so that it

can overcome the pressure drop in the absorber tower. This is the electrical power

required by the blower.

• HX Fluid Pump Use: This is the energy required to pump water and steam between

the heat exchangers.

• Steam Compressor Use: This is the energy required to run the steam compressor for

the heat exchangers.

• CO2 Compression Use: This is the electrical power required to compress the CO2




• Auxiliary Power Produced: If an auxiliary natural gas boiler is used to provide

steam and power for the Amine System, this is the additional electricity that it

produces.

• Sorbent Regeneration Equiv. Energy: This is the electrical equivalent power for the

regeneration steam required (taken from the steam cycle). The equivalent electricity

penalty is about 10-15% of the actual regeneration heat requirement.





right.

5.2.3.8.7. Auxiliary Boiler

Some of the CO2 capture technologies available in PC and NGCC plants include an option for an

auxiliary natural gas boiler. These screens are shown when an auxiliary boiler is used.


5.2.3.8.7.1. Diagram

The Diagram result screen displays an icon for the Auxiliary Boiler and values for major flows

in and out of it:

Each result is described briefly below.

• Air and Fuel

◦ Air In: The mass flow rate of fresh air is provided. This is the stoichiometric

amount of air and excess air as specified on the "CO2 Capture" input screen.

◦ Auxiliary Gas In: This is the flow rate of natural gas necessary to provide the

heat necessary to provide regeneration heat to the MEA regenerator.

• Steam and Power Generation

◦ Steam Supply: This is the total steam energy required by the CO2 regenerator.

The steam is supplied to the MEA regenerator.

◦ Electricity: Low pressure steam generated by the auxiliary boiler may be used to

generate electricity in a steam turbine. This electricity supplements that produced

by the base plant.

• Flue Gas Exiting Aux. Boiler System

◦ CO2: This is the emission rate of carbon dioxide from the auxiliary boiler. It is

emitted from a secondary stack.

◦ Equivalent SO2: This is the emission rate of sulfur dioxide from the auxiliary

boiler. It is emitted from a secondary stack.

◦ Equivalent NO2: This is the emission rate of nitrogen dioxide from the auxiliary

boiler. It is emitted from a secondary stack.

◦ Flue Gas Out: This is the mass flow rate of flue gas exiting the auxiliary boiler.

It is emitted from a secondary stack.


Auxiliary Boiler System: Diagram


5.2.3.8.7.2. Auxiliary Gas

This screen is only available for PC Plants:

The breakdown of components in the natural gas entering the auxiliary boiler are presented

using the syngas properties described in "5.1.3.2. Syngas Components" on page 102.


Auxiliary Boiler System: Auxiliary Gas


5.2.3.8.7.3. Flue Gas

Natural gas fired in the auxiliary boiler produces a flue gas. This flue gas is emitted to the

atmosphere via a secondary stack:

See "5.1.3.1. Flue Gas Components" on page 101 for a description of the Major Glue Gas

Components.

5.2.3.8.7.4. Costs

The auxiliary boiler does not have its own cost screens. Costs for the auxiliary boiler are

included in the cost screens for the CCS modules that use it.

5.2.3.8.8. Air Separation Unit

See "5.4.3.3. Air Separation Unit" on page 501 for a description of the screens in this process

type.

5.2.3.8.9. FG Recycle & Purification

Oxyfuel is a post-combustion technology used for CO2 capture. It is sometimes referred to as

"O2-CO2 Recycle". Two systems are associated with this technology, Air Separation and Flue Gas

Recycle. The following sections describe the input screens for the Flue Gas Recycle System.


Auxiliary Boiler System: Flue Gas


Please refer to the air separation chapter ("5.4.3.3. Air Separation Unit" on page 501) for help

with the oxidant feed input parameters and results.

5.2.3.8.9.1. Diagram

• Primary Recycle: The primary split occurs after the direct contact cooler. The

following results refer to the primary flue gas recycle stream:

◦ Temperature: This is the temperature of the flue gas.

◦ Flue Gas Flow: This is the volumetric flow rate of the flue gas.

• Secondary Recycle: The secondary split occurs before the spray dryer. The following

results refer to the secondary flue gas recycle stream:



• Combined Recycle Flue Gas: The following results refer to the combined recycled

flue gas:



◦ Fly Ash Flow: This is the flow rate of fly ash in the flue gas.

◦ Water Fraction: This is the fraction of water in the flue gas.

• Direct Contact Cooler

◦ Temperature In: The temperature of the flue gas, to be recycled, entering the


◦ Flue Gas In: The mass flow rate of the flue gas, to be recycled, entering the


◦ Fly Ash In: The mass flow rate of fly ash in to the direct contact cooler.

Illustration 414: PC: GET RESULTS: CO2 Capture, Transport & Storage: FG

Recycle & Purification: Diagram


◦ Condensed H2O: The mass flow rate of condensed water leaving the direct

contact cooler.

◦ Sulfur Removed: This is the amount of sulfur removed on the direct contact

cooler.

• Released to Atmosphere

◦ Temperature Out: The temperature of the flue gas being released to the

atmosphere.

◦ Flue Gas Out: The mass flow rate of the flue gas being released to the

atmosphere.

◦ Fly Ash Out: The mass flow rate of the fly ash being released to the atmosphere.

• Other

◦ Condensed H2O: The mass flow rate of condensed water.

◦ CO2 Product Pressure: This is the target pressure of product CO2 being sent to

storage.

◦ CO2 to Storage: The mass flow rate of CO2 being sent to storage.

5.2.3.8.9.2. DCC Gas




Recycle & Purification: DCC Gas


5.2.3.8.9.3. Purif. Gas





Recycle & Purification: Purif. Gas


Recycle & Purification: Capital Cost



The following process area costs are shown:

• Boiler Modifications: In case of a pre-existing PC plant being retrofitted for CO2

capture, the boiler must be modified to suit the new oxyfuel combustion system. The

cost for these modifications is estimated as a percentage of the cost of the boiler.

• Flue Gas Recycle Fan: The cost of the fan required for recycling part of the flue gas

is scaled on the basis of the flow rate of the flue gas being recycled.

• Flue Gas Recycle Ducts: Additional ducting is necessary to recycle part of the flue

gas in the oxyfuel combustion system. The cost of this ducting is assumed to be a

function of the flow rate of recycled flue gas.

• Direct Contact Cooler: The cost of the flue gas cooler is scaled on the basis of the

flow rate of the flue gas.

• CO2 Cryogenic Purification Unit: This area shows the direct capital cost of the

CPU. The CPU purifies, dries, and compresses the CO2 product stream for transport

over long distances.

5.2.3.8.9.5. O&M Cost


The following variable cost components are shown:

• Miscellaneous Chemicals: A small quantity of chemicals is used in this process,

including chemicals, desiccant and lubricants. The aggregate cost of these chemicals

is estimated based on the flow rate of CO2 captured.

• Wastewater Treatment: The user may enter a cost for treating the moisture

condensed from the flue gas.


appropriate storage/ disposal site. Transport of CO2 to a storage site is assumed to be

via pipeline This is the annual cost of maintaining those pipelines.


Recycle & Purification: O&M Cost



This cost is based upon the storage option chosen on the "CO2 Storage" input screens.

(See "5.2.2.8.13. CO2 Storage" on page 249.

• Electricity: The cost of electricity consumed by the Flue Gas Recycle System.

5.2.3.8.9.6. Total Cost


99.


Recycle & Purification: Total Cost


5.2.3.8.9.7. Summary






penalties).



calculation is 24 hours * 365 days. or 8,760 hours/year.



• ASU Use: This is the electrical power required by the air separation unit.

• Flue Gas Fan Use: The flue gas has to be compressed in a flue gas blower so that it

can overcome the pressure drop in the absorber tower. This is the electrical power

required by the blower.

• Flue Gas Cooling Use: This is the electric power required for flue gas cooling.

• CO2 Purification Use: This is the electric power required for CO2 purification.

• Total Recycle/Purification Use: This is the total amount of electrical power required

by the FG recycle & purification system.


right.


Recycle & Purification: Summary




a power plant from plant site to sequestration site. It may be used in all of the plant type

configurations, and the screens for all plant types are described here.

5.2.3.8.10.1. Diagram

• From Plant

◦ Pressure In: This is the pressure of the CO2 from the plant into the pipeline in

absolute pounds per square inch.

◦ CO2 Stream In: This is the flow of the CO2 from the plant into the pipeline in

actual cubic feet per minute.

• To CO2 Transport System

◦ No. of Booster Pumps: This is the number of booster pumps used (if any).

◦ Ground Temperature: Average ground temperature that the pipeline traverses.

◦ Pipe Segments: Total number of pipe segments from plant to injection site.

◦ Pipe Size: Outer diameter of the pipe in inches.

• To Storage

◦ Pressure Out: This is the pressure of the CO2 when it enters the storage site in

absolute pounds per square inch.

◦ CO2 Stream Out: This is the flow of the CO2 from the pipeline into the storage

site in actual cubic feet per minute.


Pipeline Transport: Diagram


5.2.3.8.10.2. Flue Gas

This screen is shown for PC and NGCC plants:


Components.


Pipeline Transport: Flue Gas


5.2.3.8.10.3. Gas

This screen is shown for IGCC plants:

See "5.1.3.2. Syngas Components" on page 102 for a description of the Major Gas

Components.

Illustration 423: IGCC: GET RESULTS: CO2 Capture, Transport &

Storage: Pipeline Transport: Gas




The following process area costs are shown:

• Material Cost: This includes the cost of line pipe, pipe coatings, and cathodic

protection.

• Labor Costs: This covers the cost of labor during pipeline construction.

• Right-of-way Cost: This is the cost of obtaining right-of-way for the pipeline. This

cost not only includes compensating landowners for signing easement agreements but

landowners may be also be paid for loss of certain uses of the land during and after

construction, loss of any other resources, and any damage to property.

• Booster Pump Cost: This is the total capital cost of a booster pump.

• Miscellaneous Cost: This includes the costs of: surveying, engineering, supervision,

contingencies, telecommunications equipment, freight, taxes, allowances for funds

used during construction (AUFDC), administration and overheads, and regulatory

filing fees.


Pipeline Transport: Capital Cost


5.2.3.8.10.5. O&M Cost

The O&M Cost result screen displays tables for the variable and fixed operation and

maintenance costs involved with the CO2 Capture technology. O&M costs are typically

expressed on an average annual basis and are provided in either constant or current dollars for

a specified year, as shown on the bottom of the screen. Each result is described briefly below:

• Variable Cost Components: Variable operating costs and consumables are directly

proportional to the amount of kilowatts produced and are referred to as incremental

costs. All the costs are subject to inflation.

◦ Booster Pump Operating Cost: This is the total capital cost of a booster pump.

◦ Total Variable Costs: This is the sum of all the variable O&M costs listed above.

This result is highlighted in yellow.

• Fixed Cost Components: Fixed operating costs are essentially independent of actual

capacity factor, number of hours of operation, or amount of kilowatts produced. All

the costs are subject to inflation.

◦ Total Fixed Costs: This is the sum of all the fixed O&M costs listed above. This


• Total O&M Costs: This is the sum of the total variable and total fixed O&M costs. It

is used to determine the base plant total revenue requirement. This result is



Pipeline Transport: O&M Cost


5.2.3.8.10.6. Total Cost


99.


Pipeline Transport: Total Cost


5.2.3.8.11. CO2 Storage

This process type is shown when "Geologic" is chosen as a CO2 storage method. The screens are

the same for all plant types.

5.2.3.8.11.1. Diagram


• CO2 Storage Resource: This is the amount of CO2 that can be stored at the reservoir.

• CO2 Plume Size: This is the CO2 injection plume size.

• Num. of CO2 Inj. Wells: This is the number of CO2 injection wells in the reservoir.

• Final Dimensions

o 3D Seismic Area: This is the final area of the 3D seismic margin.

o 3D AOR Area: This is the final area of the 3D allowable operating region

(AOR) margin.

o 2D Seismic Length: This is the length of the 2D seismic margin.

• Final Number of Monitoring Wells

o In Reservoir

o Above Seal

o Dual Completion

o Groundwater

o Vadose Zone


CO2 Storage: Diagram


5.2.3.8.11.2. Pre-Injection Cost


• Site Evaluation: This is the cost of regional evaluation.

• Site Characterization: This is the cost of site characterization.

• Permitting: This is the cost of permitting.

• Miscellaneous Capital Cost: This covers costs not included above.

• Total Capital Requirement (TCR): Money that is placed (capitalized) on the books

of the utility on the service date. TCR includes all the items above. This result is


• Effective TCR: The TCR that is used in determining the total power plant cost. The

effective TCR is determined by the % TCR Amortized, which is specified on the

capital cost input screen as described in "5.1.1.1. Capital Cost Inputs" on page 90.

Illustration 428: PC: GET RESULTS:

CO2 Capture, Transport & Storage: CO2

Storage: Pre-Injection Cost


5.2.3.8.11.3. Operations Cost


• Drilling Costs: This is the annual cost of drilling.

• Geophysical Survey: 3D Seismic: This is the annual cost of 3D seismic monitoring.

• Well Seismic: VSP Tool: This is the annual cost of vertical seismic profile (VSP)

tools.

• Fluid & Gas Samples: This is the annual cost of fluid and gas samples.

• Injection Well Monitoring: This is the annual cost of injection well monitoring.

• Wireline (Geophysical) Logging: This is the annual cost of wireline logging.

• Annual Mechanical Integrity Test: This is the annual cost of mechanical integrity

testing.

• Monitor Well Downhole Equipment: This is the annual cost of downhole equipment

to allow real-time monitoring.

• Operations & Maintenance: This is the annual cost of operations and maintenance.

• Atmospheric Monitoring: This is the annual cost of atmospheric monitoring.

• Corrective Action: This is the annual cost of corrective action.

• Periodic Reports: This is the annual cost of periodic reports.

• Trust & Oversight Funds: This is the annual cost of trust and oversight funds,

including a state long-term stewardship trust fund and a state operational oversight

fund.

• Miscellaneous Operations: This is the annual cost of miscellaneous operations.



Storage: Operations Cost


• Total Operations Cost: This is the sum of all the costs listed above. It is highlighted

in yellow.

5.2.3.8.11.4. Post-injection Cost


• Geophysical Survey: 3D Seismic: This is the annual cost of 3D seismic monitoring.

• Fluid & Gas Samples: This is the annual cost of fluid and gas samples.

• Plug & Abandon: This is the annual cost of removing equipment and restoring the

site.

• Miscellaneous Site Closure Costs: These are additional miscellaneous site closure

costs.

• Periodic Reports: This is the annual cost of periodic reports.

• Total Post-injection Cost: This is the sum of the costs listed above. It is highlighted

in yellow.



Storage: Post-Injection Cost


5.2.3.8.11.5. Total Cost


99.


5.2.3.9.1. Water

This process type is used by all plant types; the screens for all plant types are described here.

5.2.3.9.1.1. Makeup Water (PC)

This screen is shown for PC plants:

Major outputs are briefly described below:

• Plant Inlet: this variable presents the total amount of makeup water required by the

plant for boiler, cooling system, bottom ash sluice, fly ash sluice, FGD, and carbon

capture system if applicable.


CO2 Storage: Total Cost

Illustration 432: PC: GET RESULTS: Water Systems: Water: Makeup Water


• Boiler Makeup: This variable presents the amount of makeup water for the main

steam cycle to supplement boiler blowdown and miscellaneous steam losses, which

mainly depends on the boiler blowdown rate.

• Cool. Makeup: This variable presents the amount of makeup water for the cooling

system. There is no makeup water required for once through and air cooled condenser

systems. For the wet cooling tower, the makeup water is required to supplement the

evaporation, blowdown and drift losses.

• Bot. Ash Sluice: This variable presents the amount of makeup water used for sluicing

bottom ash that is collected at the bottom of the boiler. In a wet sluicing system,

bottom ash is sluiced with water and transported to a bottom ash pond where the ash

settles in the pond. There may be no need of makeup water to sluice bottom ash as the

blowdown from the wet tower and bottom ash pond overflow can be reused as sluice

water.

• CS-ESP Sluice: This variable presents the amount of makeup water used for sluicing

fly ash that is entrained in the flue gas and removed by air pollution control system

equipment such as ESP. There may be no need of makeup water to sluice fly ash as

the blowdown from the wet tower and bottom ash pond overflow can be reused as

sluice water.

• SCR Makeup: This is the amount of makeup water required for the hot-side SCR.

• SNCR Makeup: This is the amount of makeup water required for in-furnace NOx

control.

• FGD Makeup: The variable presents the amount of makeup water needed to replace

the evaporated water in the reagent sluice circulation stream.

• CCS Makeup: The variable presents the amount of makeup water needed to replace

the loss from contact cooler evaporation, dilute the makeup MEA, and supplement the

reclaimer loss when amine-based capture system is used.

5.2.3.9.1.2. Makeup Water (IGCC)

This screen is shown for IGCC plants:


• Plant Inlet: This is the total amount of makeup water required by the plant.

• Process: This is the amount of makeup water required for everything except the

cooling system.

Illustration 433: IGCC: GET RESULTS: Water Systems: Water: Makeup

Water


• Cooling: This is the amount of makeup water required for the cooling system.

5.2.3.9.1.3. Water Consumption

This screen is only available for PC plants. It summarizes water consumption across the entire

plant:


• Water Consumption: This variable presents the total amount of water consumed

across the entire plant including associated environmental control technologies.

• Evaporation

◦ FGD: This variable presents the amount of evaporation water in FGD when it is

loaded.

◦ Wet Tower: This variable presents the amount of evaporation and drift losses in

the wet tower when the wet cooling tower system is loaded.

◦ CCS: This variable presents the amount of evaporation loss in the CO2 capture

system.

5.2.3.9.1.4. Cooling Water

This screen is available for all plant types:


• Steam Cycle: This is the amount of cooling water through the main steam cycle.

Illustration 434: PC: GET RESULTS: Water Systems: Water: Water

Consumption

Illustration 435: PC: GET RESULTS: Water Systems: Water: Cooling Water


• CO2 Capture System or CCS System: This label indicates which CO2 capture

system, if any, is in use. It is not shown for IGCC plants, since the ASU, which is

shown in this section, is still used even if there is no CCS. The following results may

appear in this section:

◦ ASU: This is the amount of cooling water required by the air separation unit.

◦ Capture Process or Added Cooling: This is the amount of cooling water

required by the CO2 capture process.

◦ CO2 Compressor: This is the amount of cooling water required by the CO2

product compressor.

◦ DCC or Direct Contact Coolers: This is the amount of cooling water required

by the direct contact cooler.

◦ Heat Recovery System: This is the amount of cooling water required by the heat

recovery system.

• Total Cooling: This is the amount of cooling water through the main steam cycle plus

auxiliary cooling.

5.2.3.9.2. Hybrid Cooling System

A hybrid cooling system uses both closed-loop dry and wet units. Dry and wet cooling units are

arranged in parallel that splits the steam flow between air-cooled condensers (ACC) and a surface

condenser coupled with a wet tower unit. The dry cooling unit employs ACC and is primarily

used to serve the steam cycle. When the ambient air temperature reaches higher levels than the

design, and the dry cooling unit cannot maintain a low turbine exhaust pressure, part of the

exhaust steam is routed to the supplemental wet unit. See "5.2.3.9.3. Air Cooled Condenser or

Dry Unit" on page 401 and "5.2.3.9.4. Wet Cooling Tower or Wet Unit" on page 404.

The hybrid cooling system may be used in all plant types.

5.2.3.9.2.1. Diagram

This screen shows a summary of the Dry and Wet units:

Illustration 436: PC: GET RESULTS: Water Systems: Hybrid Cooling

System: Diagram


See the dry unit diagram, "5.2.3.9.3.1. Diagram" on page 401, and the wet unit diagram,

"5.2.3.9.4.1. Cooling Tower Diagram" on page 404 for more information on the results shown

here.

5.2.3.9.2.2. Total Cost


99.

5.2.3.9.3. Air Cooled Condenser or Dry Unit

The air cooled condenser is available in all plant types. It may be configured as a standalone

system or as the dry unit of a hybrid cooling system.

5.2.3.9.3.1. Diagram

This screen displays an icon for the Air Cooled Condenser and values for major flows in and

out of it and its size:


Cooling System: Total Cost

Illustration 438: PC: GET RESULTS: Water Systems: Air Cooled Condenser:

Diagram



• Number of Cells: Number of cells in the dry cooling system. Each cell has eight heat

exchanger bundles in the default. The heat exchanger bundle consists of two-row

staggered plat-finned flat tubes.

• Footprint Area: The plot area of the dry cooling system. That is a function of initial

temperature difference between inlet steam and air and ambient pressure.

• Steam In: The total mass flow rate of the exhaust steam. That depends on the plant

size and steam cycle heat rate.

• Steam Temperature: The temperature of exhaust steam entering the air cooled

condensers. That is empirically estimated in terms of the steam turbine back pressure.

• Initial Temp. Diff.: That is the temperature difference between inlet steam and steam

of the dry cooling system. This variable significantly affects the performance and cost

of the dry cooling system.


This screen displays tables for the direct and indirect capital costs related to the Air Cooled

Condenser technology:


The air cooled condenser system has the following process area costs:

• Condenser Structure: This area deals with the cost of air cooled condenser

equipment, erection and installation of the air cooled condensers at the site. The cost

of the ACC equipment is estimated as a function of initial temperature difference

between inlet steam and air based on the cost data estimated by Electric Power

Research Institute. The erection accounted for approximately 30% of the sum of the

equipment and erection cost, which is equivalent to about 43% of the ACC equipment

cost.


Capital Cost


• Steam Duct Support: This area deals with the cost of steam duct support and column

foundations.

• Electrical & Control Equipment: This area deals with the cost of fan, pump motor

wiring and controls, etc.

• Auxiliary Cooling: That deals with the cost of auxiliary cooling including separate

fin-fan unit or others.

• Clearing System: That deals with the cost of clearing finned tube surfaces.

5.2.3.9.3.3. O&M Cost


with the Air Cooled Condenser technology:


The air cooled condenser system has the following variable cost components:

• Disposal: Total cost to dispose the collected cleaning wastes.


gross plant capacity and the cooling system energy penalty performance input

parameter.


O&M Cost


5.2.3.9.3.4. Total Cost


99.

5.2.3.9.4. Wet Cooling Tower or Wet Unit

The wet cooling tower is available in all plant types. It may be configured as a standalone system

or as the wet unit of a hybrid cooling system.

5.2.3.9.4.1. Cooling Tower Diagram

This screen displays an icon for the Wet Cooling Tower and values for major flows in and out

of it:


• Cooling Water Entering Wet Tower

◦ Water In: The amount of recirculating cooling water entering the wet tower. That

depends on the plant size, steam cycle heat rate and cooling water temperature


Total Cost

Illustration 442: PC: GET RESULTS: Water Systems: Wet Cooling Tower:

Cooling Tower Diagram


drop range. That is the sum of cooling water through the main steam cycle, and

amine-based carbon capture system if applicable.

◦ Temperature In: The temperature of recirculating cooling water entering the wet

tower.

• Cooling Water Exiting Wet Tower

◦ Water Out: The amount of recirculating cooling water exiting the wet tower.

That is equal to the amount of cooling water entering the wet tower based on

water mass balance. That is the sum of cooling water through the main steam

cycle, and amine-based carbon capture system if applicable.

◦ Temperature Out: The temperature of recirculating cooling water exiting the

wet tower. That is calculated in terms of the inlet cooling water temperature and

cooling water temperature drop range.

• Wet Tower Performance

◦ Makeup Water: The cooling tower operation is maintained by making up fresh

water at the same rate as the water losses (evaporation, blowdown, and drift loss)

from the tower.

◦ Makeup Underflow: This output gives the amount of wastes from cooling

makeup water treatment system.

◦ Evaporation: In wet cooling towers, water has direct contact with ambient air

and cooling is achieved mainly by the evaporation process in which some of the

water leaves with the air. The evaporation process is the largest source of cooling

tower water losses. That is estimated based on the mass and energy balance

mode. Evaporation loss varies with meteorological conditions and displays a

seasonal pattern.

◦ Blowdown: Because water evaporated in the cooling tower consists of pure

water, the concentration of salts or other impurities will increase in the

recirculating water. To avoid a high concentration and subsequent scaling of the

surface within the tower, it is necessary to blow down a portion of the water that

depends on the cycle of concentration and evaporation loss.

◦ Drift Loss: A relatively small amount of entrained water lost as fine droplets in

the air discharge from a tower, which is frequently referred to as tower drift loss.

◦ Basin Sludge: This output specifies the amount of the basin sludge of the cooling

tower system. That is an intermittent waste stream that contains collected soil,

dust, and suspended solids in the tower basin.


5.2.3.9.4.2. Slip Stream Diagram

This screen is only shown when the slip stream treatment system is enabled:

A slip or blowdown stream is removed from the wet cooling tower to reduce the concentration

of impurities in the cooling water. The slipstream treatment system removes the impurities

from the slip stream.

The following results are displayed:

• Water In: This is the amount of water entering the slip stream treatment system from

the cooling tower.

• Water Out: This is the amount of water processed by the slip stream system. It is

returned to the recirculating cooling water stream.

• Wastewater: This is the amount of wastewater leaving the slip stream treatment

system. It is sent to the wastewater treatment facility.


Slip Stream Diagram



This screen displays tables for the direct and indirect capital costs related to the Wet Cooling

Tower technology:


The wet cooling tower has the following process area costs:

• Cooling Tower Structure: This area deals with the cost for the cooling tower and

installation.

• Circulation Pumps: This area deals with the cost for the circulating cooling water

pumps.

• Auxiliary Systems: This area deals with the cost for a closed-loop process that

utilizes a higher quality water to remove heat from ancillary equipment and transfers

that heat to the main circulating cooling water system.

• Piping: This area deals with the cost for the circuiting cooling water piping.

• Makeup Water System: This area deals with the cost for the capital equipment to

provide makeup water for the cooling system.

• Cooling Water System: This area deals with the cost for the component cooling

water system.

• Foundation & Structures: This area deals with the cost for the circulating water

system foundation and structures.


Capital Cost


5.2.3.9.4.4. O&M Cost


with the Wet Cooling Tower technology:


The wet cooling tower has the following variable cost components:

• Alum: This is the cost of alum used for makeup water treatment.

• Disposal: Total cost to dispose the collected tower waste solids and wastewater.


gross plant capacity and the cooling system energy penalty performance input

parameter.

• Water: This is the annual cost of the water used by the cooling system.

5.2.3.9.4.5. Total Cost


O&M Cost


Total Cost



99.

5.2.3.10. By-Prod. Mgmt

These screens display the flow rates of solid and liquid substances collected which require

management (disposal or recovery). If a wastewater treatment system is configured, costs for that

system are also shown. These screens are only available for PC plants.

5.2.3.10.1. Bottom Ash Pond

The Bottom Ash Pond Diagram result screen displays an icon for the Pond and values for major

flows into it. Each result is described briefly below:

• Bottom Ash Pond Inputs: Solids mixed with sluice water that are collected in the

bottom of the boiler and by the particulate removal technologies are transported to the

Pond for treatment. The IECM currently provides no additional treatment or

consideration of these substances, and therefore simply reports the quantities entering

the technology.

◦ Wastewater: This is the total wastewater entering the bottom ash pond. This value

is zero when wastewater treatment is configured.

◦ Wet Bottom Ash: Mass flow rate of bottom ash solids on a wet basis.

◦ Mercury (contained in Bottom Ash): Mass flow rate of mercury present in the

bottom ash solids on a wet basis.

◦ Wet Fly Ash: Mass flow rate of total fly ash solids on a wet basis. This value is zero

when the fly ash is disposed in a landfill.

◦ Mercury (contained in Fly Ash): Mass flow rate of mercury present in the fly ash

solids on a wet basis.

• Bottom Ash Pond – Totals

◦ Wet Total Solids: The sum of the fly ash and bottom ash solids on a wet basis.

◦ Total Mercury: Mass flow rate of mercury present in the combined bottom ash and

fly ash solids on a wet basis.

◦ Effluent: This is the total effluent leaving the bottom ash pond.

Illustration 447: PC: GET RESULTS: By-Prod. Mgmt: Bottom Ash Pond


5.2.3.10.2. Fly Ash Disposal

This screen is only shown when particulate control is configured and fly ash is not mixed with

FGD wastes or bottom ash:


• Fly Ash Disposal Inputs: Solids mixed with sluice water are collected in the particulate

removal technologies and may be transported to the Landfill for treatment. The IECM

currently provides no additional treatment or consideration of these substances, and

therefore simply reports the quantities entering the technology.

◦ Wet Fly Ash: Mass flow rate of total fly ash solids on a wet basis.

◦ Mercury: Mass flow rate of mercury present in the fly ash solids on a wet basis.

• Fly Ash Disposal Totals

◦ Wet Total Solids: The sum of the fly ash and FGD solids on a wet basis.

◦ Total Mercury: Mass flow rate of mercury present in the combined fly ash and

FGD solids on a wet basis.


By-Prod. Mgmt: Fly Ash Disposal


5.2.3.10.3. Flue Gas Treatment

This screen is only shown when a Wet FGD is configured:

The Flue Gas Treatment Diagram result screen displays an icon for the Landfill and values for

major flows into it. Each result is described briefly below:

• Flue Gas Treatment Inputs: Solids mixed with sluice water that are collected in the

bottom of the boiler and by the particulate removal technologies are transported to the

Pond for treatment. The IECM currently provides no additional treatment or

consideration of these substances, and therefore simply reports the quantities entering

the technology.

◦ Wet Fly Ash: Mass flow rate of total fly ash solids on a wet basis. This value is zero

when the fly ash is disposed in a landfill.

◦ Mercury (contained in Fly Ash): Mass flow rate of mercury present in the fly ash

solids on a wet basis.

◦ Wet FGD Solids: Mass flow rate of wet FGD solids.

◦ Mercury (contained in Wet FGD Solids): Mass flow rate of mercury present in the

Wet FGD solids.

• Flue Gas Treatment Totals

◦ Wet Total Solids: The sum of the wet FGD solids and the fly ash on a wet basis.

◦ Total Mercury: Mass flow rate of mercury present in the combined wet FGD solids

and fly ash solids on a wet basis.

Illustration 449: PC: GET RESULTS: By-Prod. Mgmt: Flue Gas Treatment


5.2.3.10.4. Wastewater Treatment (chemical)

This screen is only shown when chemical wastewater treatment is configured:


• Wastewater Treatment Inputs:

◦ Wastewater In: This is the water flow rate into the wastewater treatment system.

◦ Lime: This is the amount of lime added to the wastewater treatment system.

◦ Alum: This is the amount of alum added to the wastewater treatment system.

◦ Flocculant Polymer: This is the amount of flocculant polymer added to the

wastewater treatment system.

• Wastewater Treatment Totals:

◦ Evaporation: This is the amount of water evaporated from the wastewater

treatment system.

◦ Sludge: This is the flow rate of sludge from the wastewater treatment system.

Illustration 450: PC: GET RESULTS: By-Prod. Mgmt: Wastewater Treatment

(chemical)


5.2.3.10.5. Wastewater Treatment (mechanical)

This screen is only shown when mechanical wastewater treatment is configured:


• Wastewater Treatment Inputs:

◦ Wastewater In: This is the water flow rate into the wastewater treatment system.

• Wastewater Treatment Totals:

◦ Evaporation: This is the amount of water evaporated from the wastewater

treatment system.

◦ Brine: This is the flow rate of brine from the wastewater treatment system.

Illustration 451: PC: GET RESULTS: By-Prod. Mgmt:

Wastewater Treatment (mechanical)



This screen displays the capital costs associated with the wastewater treatment system:


wastewater treatment system has the following process area costs:

• Chemical Precipitation: This area shows the direct capital cost of the chemical

treatment system.

• Vapor Compression Evaporation: This area shows the direct capital cost of the

mechanical treatment system.

Illustration 452: PC: GET RESULTS: By-Prod. Mgmt: Capital Cost


5.2.3.10.7. O&M Cost

This screen displays tables for the variable and fixed operation and maintenance costs associated

with the wastewater treatment system:


wastewater treatment system has the following variable cost components:

• Lime: The annual cost of lime.

• Alum: The annual cost of alum.

• Flocculant Polymer: The annual cost of flocculant polymer.

• Disposal: The total annual cost to dispose of wastewater treatment system wastes.

• Electricity: The total annual cost of electricity used by the wastewater treatment system.

Illustration 453: PC: GET RESULTS: By-Prod. Mgmt: O&M Cost



This screen displays the total costs associated with the wastewater treatment system:

This is a standard total cost result table as described in ""5.1.1.7. Total Cost Results" on page 99.

5.2.3.11. Stack

These screens are available in all plant types. There are some slight variations depending on the

plant type; these are all described here.

5.2.3.11.1. Diagram

This screen displays an icon for the stack and values for major flows out of it:


• Flue Gas Out

◦ Temperature Out: Temperature of the flue gas exiting the stack.

◦ Flue Gas Out: Volumetric flow rate of flue gas exiting the stack, based on the flue

gas temperature exiting the stack and atmospheric pressure.

◦ Fly Ash Out: Mass flow rate of solids in the flue gas exiting the stack.

Illustration 454: PC: GET RESULTS: By-Prod. Mgmt: Total Cost

Illustration 455: PC: GET RESULTS: Stack: Diagram


• Flue Gas Emission

◦ CO2: This is the number of pounds of CO2 vented to the air for every MBtu.

◦ Equivalent SO2: This is the number of pounds of Equivalent SO2 vented to the air

for every MBtu.

◦ Equivalent NO2: This is the number of pounds of Equivalent NO2 vented to the air

for every MBtu.

◦ Particulate (PC and NGCC) or Ash (IGCC): This is the number of pounds of

Particulate vented to the air for every MBtu.

• Mercury Emission (Not shown for IGCC plants.)

◦ Elemental: This is the number of pounds of Elemental Mercury vented to the air for

every MBtu.

◦ Oxidized: This is the number of pounds of Oxidized Mercury vented to the air for

every MBtu.

◦ Total: This is the number of pounds of Total Mercury vented to the air for every

MBtu.

• Mercury Exiting Stack (Not shown for IGCC plants.)

◦ Elemental Mercury: Mass flow rate of elemental mercury (Hg0) in the flue gas

exiting the stack.

◦ Oxidized Mercury: Mass flow rate of oxidized mercury (Hg+2) in the flue gas

exiting the stack.

◦ Total Mercury: Mass flow rate of total mercury in the flue gas exiting the stack

(elemental, oxidized, and particulate).

• Flue Gas (Only shown for IGCC plants.)

◦ Primary: This is the portion of the flue gas that comes from the combustor.

◦ Other: This is the portion of the flue gas that comes from other parts of the plant

(e.g., Beavon-Stretford).

• Makeup Water: (Only shown for PC plants.) This is the total makeup water that is

required by the plant.


5.2.3.11.2. Flue Gas

The Flue Gas result screen displays a table of quantities of flue gas components exiting the stack.

For each component, quantities are given in both moles and mass per hour:

PC and NGCC plants have the following columns:

• Auxiliary Boiler Out: This is the flue gas entering the stack from the auxiliary boiler, if

there is one.

• Stack Out: This is the primary flue gas entering the stack.

• Total Out: The sum of the quantities above.

IGCC plants have the following columns:

• By-Product Area: This is the flue gas entering the stack from other portions of the

plant.

• Power Block Area: This is the primary flue gas entering the stack.

• Total Flue Gas: This is the sum of the quantities above.

Use the scroll bar at the bottom to view all the columns. See "5.1.3.1. Flue Gas Components" on

page 101 for a description of the Major Flue Gas Components.

Illustration 456: PC: GET RESULTS: Stack: Flue Gas


5.2.3.11.3. Emission Taxes

This screen shows the cost of to the plant for emissions:

The Taxes on Emissions are entered by the user. (See "5.2.2.1.4. Regulations & Taxes" on page

118.)

Tax on Emissions:

• Sulfur Dioxide (SO2): The cost (as a result of user entered data) to the plant of emitting

sulfur dioxide in dollars per ton.

• Nitrogen Oxide (Equivalent NO2): The cost (as a result of user entered data) to the

plant of emitting nitrogen oxide in dollars per ton.

• Carbon Dioxide (CO2): The cost (as a result of user entered data) to the plant of

emitting carbon dioxide in dollars per ton.

• Total Emission Taxes: This is the sum of the emission taxes displayed above. It is



This section evaluates the water use associated with all the major stages of electricity generation,

including fuel acquisition, processing and transport, power plant operation, production of chemicals

used in power plants, and power plant infrastructure.

There are two types of parameters and results:

• Water Withdrawal: This is the total amount of water removed from a water source. Some

of this water may be returned to the source for later reuse.

• Water Consumption: This is the amount of water consumed that is not returned to the

water source, mainly because of evaporation and other losses.

This technology is available for PC and NGCC plants. It is controlled by the "Water Life Cycle

Enabled?" parameter on the overall plant performance screen. (See "5.2.2.1.2. Performance" on page

116 for PC plants, 5.3.2.1.2. Performance" on page 424 for NGCC plants.) The screens for both

plant types are described below.

Illustration 457: PC: GET RESULTS: Stack:

Emission Taxes


5.2.3.12.1. Water Withdrawals


The table on the left shows the following results:

• Fuel Supply: Water withdrawals are shown for the following aspects of the fuel supply:

o Fuel Extraction: This is the amount of water withdrawal for fuel extraction per

megawatt hour of electricity generation.

o Fuel Processing: This is the amount of water withdrawal for fuel processing

per megawatt hour of electricity generation.

o Fuel Transport: This is the amount of water withdrawal for fuel transport per


o Total Fuel Supply: This is the sum of the results listed above. It is highlighted

in yellow.

• Plant Infrastructure: This is the water withdrawal for the plant infrastructure. It is


• Chemical Production: Water withdrawals are shown for production of the following

chemicals:

o Ammonia: This is the amount of water withdrawal for ammonia production per


o Limestone; This is the amount of water withdrawal for limestone production


o Amine (30-wt% MEA): This is the amount of water withdrawal for (makeup)

amine production per megawatt hour of electricity generation.

o Total Chemical Production: This is the sum of the results listed above. It is


• Plant Operation: This is the water withdrawal for plant operation. It is highlighted in

yellow.

Illustration 458: PC: GET RESULTS: Water Life Cycle Assessment: Water

Withdrawals


The table on the right shows the highlighted values from the table on the left along with the

following result:

• Total Life Cycle: This is the sum of the results above. It is highlighted in yellow.

5.2.3.12.2. Water Consumption


The table on the left shows the following results:

• Fuel Supply: Water consumption is shown for the following aspects of the fuel supply:

o Fuel Extraction: This is the amount of water consumption for fuel extraction


o Fuel Processing: This is the amount of water consumption for fuel processing


o Fuel Transport: This is the amount of water consumption for fuel transport per


o Total Fuel Supply: This is the sum of the results listed above. It is highlighted

in yellow.

• Plant Infrastructure: This is the water consumption of the plant infrastructure. It is


• Chemical Production: Water consumption is shown for production of the following

chemicals:

o Ammonia: This is the amount of water consumption for ammonia production


o Limestone: This is the amount of water consumption for limestone production


o Amine (30-wt% MEA): This is the amount of water consumption for

(makeup) amine production per megawatt hour of electricity generation.

Illustration 459: PC: GET RESULTS: Water Life Cycle Assessment: Water

Consumption


o Total Chemical Production: This is the sum of the results listed above. It is


• Plant Operation: This is the water consumption for plant operation. It is highlighted in

yellow.

The table on the right shows the highlighted values from the table on the left along with the

following result:

• Total Life Cycle: This is the sum of the results above. It is highlighted in yellow.

5.3. Natural Gas Comb. Cycle (NGCC) Plant




"4.2.1.1. The "Plant Design" Screen" on page 45 for a general description of this screen and how to




• No Devices: This is the default. All technology selection menus are set to their default

values:




◦ Wet Cooling Tower ("5.2.2.9.3. Wet Cooling Tower or Wet Unit" on page 259 and


Illustration 460: NGCC Plant: CONFIGURE SESSION: Plant Design


• MEA Scrubber: This is a "Typical New Plant" with the addition of an amine system for

CO2 capture:

◦ Amine System (See "5.2.2.8.1. Amine System (CCS System)" on page 176 and

"5.2.3.8.1. Amine System (CCS System)" on page 328.)









◦ CO2 Capture:


▪ Amine System: This is an MEA scrubber for capturing CO2. (See

"5.2.2.8.1. Amine System (CCS System)" on page 176 and "5.2.3.8.1. Amine

System (CCS System)" on page 328.)

▪ Ammonia System: An ammonia-based CO2 capture process is used. (See

"5.2.2.8.2. Ammonia System (CCS System)" on page 188 and

"5.2.3.8.2. Ammonia System (CCS System)" on page 337.)


◦ Cooling System:

▪ Once-Through: This is the default. Cooling water is withdrawn from a natural


(See "5.2.3.9.1. Water" on page 397.)



evaporation to transfer waste heat to the atmosphere. ("5.2.2.9.3. Wet Cooling

Tower or Wet Unit" on page 259 and "5.2.3.9.4. Wet Cooling Tower or Wet Unit"

on page 404.)


atmospheric air passed across finned-tube heat exchangers to reject heat. (See

"5.2.2.9.2. Air Cooled Condenser or Dry Unit" on page 255 and "5.2.3.9.3. Air

Cooled Condenser or Dry Unit" on page 401.)

▪ Hybrid Cooling System: This combines a wet cooling tower and an air cooled

condenser. (See "5.2.2.9.1. Hybrid Cooling System" on page 253 and

"5.2.3.9.2. Hybrid Cooling System" on page 400.)


This screen is the same in all plant types. See "5.2.1.2. Plant Location" on page 114 for its

description.


This screen is the same in all plant types. See "5.2.1.3. Unit Systems" on page 115 for its

description.




These screens apply to the power plant as a whole, not to specific technologies.

5.3.2.1.1. Diagram




screen.


Illustration 461: NGCC: SET PARAMETERS: Overall Plant: Diagram

Illustration 462: NGCC: SET PARAMETERS: Overall Plant: Performance





• Number of Gas Turbines: This is the number of gas turbines. Since each turbine is able

to produce a fixed output, the number of turbines will determine the plant size (e.g.,

gross plant size). This number is shown here for reference only. You may set it in the

Power Block parameters. (See "5.4.2.7. Power Block" on page 496.)




The value is controlled primarily by the number of gas turbines selected in the Power

Block parameters. (See "5.4.2.7. Power Block" on page 496.)








system. Currently, the model cannot have temperatures below 15ºF.

• Ambient Air Pressure (Average): This is the absolute pressure of the air inlet stream to

the boiler. The air pressure is used to convert flue gas molar flow rates to volume flow

rates. The default value is 14.7 psia.


• Ambient Air Humidity (Average): This is the water content of the inlet combustion air.

This value is used in calculating the total water vapor content of the flue gas stream. The

value is referred to as the specific humidity ratio, expressed as a ratio of the water mass

to the dry air mass. The default value is 0.018.

• Water Life Cycle Assessment Enabled?: This allows you to disable water life cycle

assessment if you are not interested in it. It is enabled by default. See "5.2.2.11. Water

Life Cycle Assessment" on page 270 for a list of parameters and "5.2.3.12. Water Life

Cycle Assessment" on page 419 for a list of results controlled by this option.


This screen is the same for all plant types. See "5.2.2.1.3. Region-Specific Cost Factors" on page

117 for details.


This screen defines the emission constraints as they apply to the gases emitted from the power

plant. Constraints for sulfur dioxide, nitrogen dioxides, particulates, and mercury are not needed

due to the cleaner emissions from NGCC plants.


The emission constraints determine the removal efficiencies of control systems that capture CO2.

The level of capture is set to comply with the specified emission constraints. As discussed later,

however, user-specified values for control technology performance may cause the plant to over-

comply or under-comply with the emission constraints specified in this screen. Each parameter is


• Total CO2 Removal Constraint: The emission constraint applies to all the air emission

sources in the power plant, primary or secondary. The default value is based on recent

discussions and is not based on any currently enforced law.






in dollars per ton.






See "5.2.2.1.5. Financing & Cost Year" on page 120 for a description of this screen.


See "5.2.2.1.6. Fuel & Land Cost" on page 122 for a description of this screen.


See "5.2.2.1.7. Capital Cost" on page 123 for a description of this screen.

5.3.2.1.8. O&M Cost




Illustration 463: NGCC: SET PARAMETERS: Overall Plant: Regulations &

Taxes




The following parameters are shown on this screen:




• Lime Cost: This is the cost of lime in dollars per ton.

• Limestone Cost: This is the cost of limestone in dollars per ton.

• MEA/Amines Cost: This is the cost of MEA/Amines in dollars per ton.

• Urea Cost: This is the cost of urea in dollars per ton.



plant cost.








See "5.2.2.1.9. Reference Plant" on page 125 for a description of this screen.

Illustration 464: NGCC: SET PARAMETERS: Overall Plant: O&M Cost


5.3.2.2. Fuel

These screens display and define the composition and cost of the fuels used in the plant. Default

properties of fuels are provided, but user-specified properties can also be easily substituted.

The natural gas combined cycle (NGCC) plant configurations all assume natural gas for fuel. The

properties can be specified by the user.

5.3.2.2.1. Properties

This screen allows you to edit the natural gas properties. The default natural gas is a common

Pennsylvania natural gas. See "5.2.2.2.3. Auxiliary Gas" on page 128 for a description of this

screen.

5.3.2.2.2. Cost

This screen allows you to specify the cost of natural gas:

• Auxiliary Gas Cost: This is the cost of natural gas in units of $/mscf.

• Auxiliary Gas Cost: This is also provided in units of $/MBtu. This value cannot be

edited.

5.3.2.3. Power Block

The power block technology area includes all the equipment necessary to convert the potential and

kinetic energy of natural gas or syngas fuels into steam and electricity.

Illustration 465: NGCC: SET PARAMETERS: Fuel: Properties

Illustration 466: NGCC: SET PARAMETERS: Fuel: Cost


The process equipment is divided into several areas: the gas turbine/generator, the air compressor,

the combustor, the steam turbine, and the heat recovery steam generator.

These screens are available for the NGCC and IGCC plant types; both plant types are described

here.

5.3.2.3.1. Gas Turbine Diagram

This diagram gives an overview of the gas turbine. It does not contain any numbers and is strictly

for reference:

Illustration 467: NGCC: SET PARAMETERS: Power Block: Gas Turbine

Diagram


5.3.2.3.2. Steam Turbine Diagram

This diagram gives an overview of the steam turbine. It does not contain any numbers and is

strictly for reference:

5.3.2.3.3. Gas Turbine Performance

Illustration 468: NGCC: SET PARAMETERS: Power Block: Steam Turbine Diagram

Illustration 469: IGCC: SET PARAMETERS: Power Block: Gas Turbine

Performance


• Gas Turbine/Generator

◦ Gas Turbine Model: This is a selection of the type of turbine model used. The type

determines the inlet temperature, pressure ratio, and size parameters. The following

options are available:

▪ GE 7FA: This is an older model found in many already constructed NGCC

plants.

▪ GE 7FB: (This is the default.) This is an advanced turbine that has a higher

inlet temperature, pressure ratio, and adiabatic efficiency, which result in a

lower net heat rate.

◦ No. of Gas Turbines: This is the number of gas turbines. Since each turbine is able


gross plant size).

◦ Total Gas Turbine Output: This parameter is provided for reference purposes only.

It provides the gross power generated from the gas turbines alone.

◦ Fuel Gas Moisture Content: (Only shown for IGCC) Steam is typically added to

the fuel gas prior to being combusted. This increases the volume of the fuel gas and

results in a higher power output in the gas turbine.

◦ Turbine Inlet Temperature: The turbine inlet temperature is carefully controlled to

prevent damage or fatigue of the first stage stator and rotor blades. This temperature

is one of the two most important parameters that impacts system efficiency.

◦ Turbine Back Pressure: The turbine exit pressure must be higher than atmospheric

pressure to provide a positive pressure on the flue gas exiting the turbine.

◦ Adiabatic Turbine Efficiency: The adiabatic turbine efficiency adjusts for

inefficiencies in real turbines. The ratio is an estimate of real to ideal performance.

◦ Shaft/Generator Efficiency: The combined shaft/generator efficiency adjusts for

inefficiencies in generator and shaft between the compressor and the generator. The

ratio is an estimate of real to ideal performance.

• Air Compressor

◦ Pressure Ratio (outlet/inlet): This is the ratio of the compressor exit pressure to the

inlet ambient air pressure. Compression takes place approximately adiabatically.

◦ Adiabatic Compressor Efficiency: The adiabatic compressor efficiency adjusts for

inefficiencies in real compressors. The ratio is an estimate of real to ideal

performance.

• Combustor

◦ Combustor Inlet Pressure: The combustor inlet pressure is currently fixed at a

single value. It is provided for reference purposes only.

◦ Combustor Pressure Drop: Although the combustor operates at essentially

constant pressure, a small pressure drop is typically observed in the combustor exit

from the compressor exit.

◦ Excess Air For Combustor: This is the excess theoretical air used for combustion.

It is added to the stoichiometric air requirement calculated by the model. This value

is based on the required mass flow rate of syngas through the combustor, the heat

content of the syngas, and the flame temperature of the combustor.


5.3.2.3.4. Steam Cycle Performance

• Heat Recovery Steam Generator

◦ HRSG Outlet Temperature: This is the desired output temperature from the heat

recovery steam generator (HRSG).

◦ Steam Cycle Heat Rate, HHV: This is the steam cycle heat rate for the heat

recovery steam generator. In IGCC plants, this is the nominal steam cycle heat rate;

the actual heat rate depends on steam generated in the gasifier cooler.

◦ Cooling Water Temperature Rise: (Not shown when an Air Cooled Condenser is

used.) This measures the increase in cooling water temperature after the once-

through cooling water removes thermal energy from the exhaust steam.

◦ Auxiliary Heat Exchanger Load (% Primary Steam Cycle): The load on the

auxiliary condenser or cooler is expressed as a percent of the load on the primary

condenser. This parameter determines the amount of recirculating cooling water

used to extract heat from the auxiliary condenser or cooler.

• Steam Turbine

◦ Total Steam Turbine Output: This is the net electricity produced by the steam

turbine associated with the HRSG (steam cycle). This value cannot be edited. It is

provided for reference only.

• Power Block Totals

◦ Power Requirement: This is the electricity for internal use. It is expressed as a

percent of the gross plant capacity.

Illustration 470: IGCC: SET PARAMETERS: Power Block: Steam Cycle

Performance


5.3.2.3.5. Emission Factors

Emission Factors Input Parameters:

• Percent SOx as SO3: This is the volume percent of SOx that is SO3. The remainder is

SO2.

• NOx Emission Rate: This is the concentration of NOx emitted from the gas turbine after

combustion.

• Percent NOx as NO: This is the volume percent of NOx that is NO. The remainder is

NO2.

• Percent Total Carbon as CO: This is the volume percent of the total carbon in the

syngas entering the combustor that is emitted from the gas turbine as CO.



90.

5.3.2.3.7. O&M Cost

Illustration 471: IGCC: SET PARAMETERS: Power Block: Emission Factors

Illustration 472: IGCC: SET PARAMETERS: Power Block: O&M Cost



following additional input is included at the top of the screen:

• Water Cost: (Only shown for NGCC) This is the cost of water.



costs. The power block has the following capital cost process areas:

• Gas Turbine: The Gas Turbine retrofit factor is a ratio of the costs of retrofitting an

existing facility versus a new facility, using the same equipment.

• Heat Recovery Steam Generator: The Heat Recovery Steam Generator retrofit factor

is a ratio of the costs of retrofitting an existing facility versus a new facility, using the

same equipment.

• Steam Turbine: The Steam Turbine retrofit factor is a ratio of the costs of retrofitting an

existing facility versus a new facility, using the same equipment.

• HRSG Feedwater System: The Boiler Feedwater retrofit factor is a ratio of the costs of

retrofitting an existing facility versus a new facility, using the same equipment.



See "5.2.2.8.1. Amine System (CCS System)" on page 176 for information on the amine system.


See "5.2.2.8.2. Ammonia System (CCS System)" on page 188 for information on the ammonia

system.


See "5.2.2.8.10. Pipeline Transport" on page 244 for a description of the pipeline transport

parameter screens.


See "5.2.2.8.12. User-Specified Transport" on page 248 for a description of the user-specified

transport parameters.

Illustration 473: IGCC: SET PARAMETERS: Power Block: Retrofit or

Adjustment Factors


5.3.2.4.5. CO2 Storage

See "5.2.2.8.13. CO2 Storage" on page 249 for a description of the screens available in this

section.


See "5.2.2.9. Water Systems" on page 253 for a description of the screens available in this section.


See "5.2.2.11. Water Life Cycle Assessment" on page 270 for a description of the screens available

in this section.

5.3.3. GET RESULTS


The result screens described in the following sections are available when "Combustion (Turbine)" is

selected as the plant type from the "New Session" pull down menu. These screens apply to the

power plant as a whole, not to specific technologies.

5.3.3.1.1. Diagram

This is the same screen that is shown in the "SET PARAMETERS" program area. It is described

in "5.3.2.1.1. Diagram" on page 424.


The Plant Perf. result screen displays performance results for the plant as a whole. Heat rates and

power in and out of the power plant are given. The performance parameters in the table on the left

are described in "5.1.4.2. Plant Performance" on page 105.



Illustration 474: NGCC: GET RESULTS: Overall Plant: Plant Performance



CONFIGURE SESSION section of the model. The following results are shown:

• Turbine Generator Output: This is the power generated by the turbine.

• Air Compressor Use: The power required to operate the air compressor.

• Turbine Shaft Losses: This value accounts for any turbine electricity losses other than

power used for the air compressor.

• Net Turbine Output: This if the net power generated by the turbine. This is the gross

output of the turbine minus the power required by the air compressor and any

miscellaneous losses.

• Miscellaneous Power Block Use: This is the power required to operate pumps and

motors associated with the power block area.

• Absorption CO2 Capture Use: (Only shown when a CO2 Capture system is in use.)

This is the power required to operate the CO2 capture system.

• Auxiliary Power Produced: (Only shown when a CO2 capture system with an option

for an auxiliary boiler is in use.) This is the additional power produced by the auxiliary

boiler. It will be zero if no auxiliary boiler is configured.






• Amine Steam Use (Elec. Equiv.): (Only shown when an amine-based CO2 capture

system is in use without an auxiliary boiler.) This is the electrical equivalent energy for

the regeneration steam required by the CO2 capture system. It is taken from the steam

cycle.


This screen is described "5.1.4.1. Mass In/Out" on page 104.


5.3.3.1.4. Gas Emissions

See "5.1.3.1. Flue Gas Components" on page 101 for a description of the Stack Gas Components

given in the table on the left. The table on the right contains the following:

• Total SOx (equivalent SO2): Total mass of SOx as equivalent SO2.

• Total NOx (equivalent NO2): Total mass of NOx as equivalent NO2.





Illustration 475: NGCC: GET RESULTS: Overall Plant: Gas Emissions

Illustration 476: NGCC: GET RESULTS: Overall Plant: Total Capital Cost





The Total Cost result screen displays a table which totals the annual fixed, variable, operations,

maintenance, and capital costs associated with the power plant as a whole. Each technology (row)

is described briefly below.

• CO2 Capture, Transport & Storage: The total cost of all the CO2 capture, transport

and storage modules used.

• Power Block: The total cost of the power block without consideration of any abatement

technologies. The Power Block contains the air compressor, gas turbine, steam turbine

and heat recovery steam generator areas.

• Post-Combustion NOx Control: The total cost of all the Post Combustion NOx removal

modules used.

• Subtotal: This is the cost of the conventional and advanced abatement technology

modules alone. This is the total abatement cost. The subtotal is highlighted in yellow.

• Cooling Tower: This is the cost of the cooling tower modules.

• Land: This is the total cost of land required for the plant.

• Emission Taxes: This is the total cost of taxes assessed to stack emissions.

• Total: This is the total cost of the entire power plant. This result is highlighted in yellow.



Illustration 477: NGCC: GET RESULTS: Overall Plant: Overall Plant Cost







The cost categories (columns) are described in "5.1.1.7. Total Cost Results" on page 99.

5.3.3.2. Fuel

This section displays the composition and cost of the fuels used in the plant. The natural gas

combined cycle (NGCC) plant configurations all assume natural gas for fuel.

This section is shared with the other plant types and is described in "5.2.3.2. Fuel" on page 280.





the combustor, the steam turbine, and the heat recovery steam generator.

These screens are available for the NGCC and IGCC plant types; both plant types are described

here.

Illustration 478: NGCC: GET RESULTS: Overall Plant: Cost Summary


5.3.3.3.1. Gas Turbine Diagram


• Air Entering Compressor

◦ Temperature In: Temperature of the atmospheric air entering the air compressor.

◦ Air In: Volumetric flow rate of the air entering the air compressor.

• Syngas Entering Combustor

◦ Temperature In: Temperature of the syngas entering the fuel heater and saturator.

◦ Pressure In: This is the pressure of the syngas as it enters the fuel heater and

saturator.

◦ Syngas In: This is the mass flow rate of the syngas to the fuel heater and saturator.

• Heated Syngas Entering Combustor

◦ Temperature In: Temperature of the heated and saturated syngas entering the

combustor.

◦ Pressure In: This is the pressure of the heated and saturated syngas as it enters the

combustor.

◦ Syngas In: This is the mass flow rate of the heated and saturated syngas to the

combustor.

• Flue Gas Exiting Gas Turbine

◦ Temperature Out: Temperature of the flue gas exiting the gas turbine.

◦ Flue Gas Out: Volumetric flow rate of the flue gas exiting the gas turbine.

Illustration 479: NGCC: GET RESULTS: Power Block: Gas Turbine Diagram


5.3.3.3.2. Steam Turbine Diagram


• Flue Gas Exiting Steam Generator

◦ Temperature Out: Temperature of the flue gas exiting the HRSG system.

◦ Flue Gas Out: Volumetric flow rate of the flue gas exiting the HRSG.

• Flue Gas Entering Steam Generator

◦ Temperature In: Temperature of the flue gas entering the HRSG.

◦ Flue Gas In: Volumetric flow rate of flue gas entering the HRSG.

Illustration 480: NGCC: GET RESULTS: Power Block: Steam Turbine

Diagram


5.3.3.3.3. Syngas

See "5.1.3.2. Syngas Components" on page 102 for a description of the Major Syngas

Components.

Illustration 481: NGCC: GET RESULTS: Power Block: Syngas


5.3.3.3.4. Flue Gas


Components.


Illustration 482: NGCC: GET RESULTS: Power Block: Flue Gas

Illustration 483: NGCC: GET RESULTS: Power Block: Capital Cost



following process area costs are displayed:

• Gas Turbine: The capital cost of the gas turbines, the air compressor, and the

combustor.

• Heat Recovery Steam Generator: The heat recovery steam generator is a set of heat

exchangers in which heat is removed from the gas turbine exhaust gas to generate steam

for the steam turbine.

• Steam Turbine: The cost of a steam turbine depends on the mass flow rate of steam

through the turbine, the pressures in each stage, and the generator output.

• HRSG Feedwater System: The boiler feedwater system consists of equipment for

handling raw water and polished water in the steam cycle, including a water

mineralization unit for raw water, a demineralized water storage tank, a condensate

water, a condensate polishing unit, and a blowdown flash drum.

5.3.3.3.6. O&M Cost


power block has the following variable cost components:

• Natural Gas: (Only shown for NGCC plants.) The total cost of natural gas used by the

power block.

• Internal Electricity Cost: Power consumed by abatement technologies result in lower

net power produced and lost revenue. The IECM charges each technology for the

internal use of electricity and treats the charge as a credit for the base plant. When

comparing individual components of the plant, these utility charges are taken into

consideration. For total plant costs they balance out and have no net effect on the plant

O&M costs.

Illustration 484: NGCC: GET RESULTS: Power Block: O&M Cost






See "5.2.3.8.1. Amine System (CCS System)" on page 328 for information on the amine system.


See "5.2.3.8.2. Ammonia System (CCS System)" on page 337 for information on the ammonia

system.

5.3.3.4.3. Auxiliary Boiler

An Auxiliary Boiler System is available as an option from within the amine scrubber system in

PC and NGCC plants. See "5.2.3.8.7. Auxiliary Boiler" on page 377 for more details.

5.3.3.4.4. CO2 Transport System



configurations. See "5.2.3.8.10. Pipeline Transport" on page 387 for a description of the CO2

Transport System results.



5.3.3.6. Stack

See "5.2.3.11. Stack" on page 416 for a description of the stack result screens.


See "5.2.3.12. Water Life Cycle Assessment" on page 419 for a description of the screens available

in this section.

Illustration 485: NGCC: GET RESULTS: Power Block: Total Cost


5.4. Int. Gasif. Comb. Cycle (IGCC) Plant




'"4.2.1.1. The "Plant Design" Screen" on page 45 for a general description of this screen and how to




• Basic Plant: This is the default. All technology selection menus are set to their default

values:

◦ GE (Quench) (See "5.4.2.4.1. GE" on page 457 and "5.4.3.4.1. GE" on page 505.)

◦ Selexol H2S Control (See "5.4.2.5.1. Selexol Sulfur Removal" on page 466 and

"5.4.3.5. Sulfur Removal" on page 515.)


◦ Landfill

◦ Sulfur Plant



◦ GE (Quench) (See "5.4.2.4.1. GE" on page 457 and "5.4.3.4.1. GE" on page 505.)

◦ Selexol H2S Control (See "5.4.2.5.1. Selexol Sulfur Removal" on page 466 and

"5.4.3.5. Sulfur Removal" on page 515.)



Illustration 486: IGCC Plant: CONFIGURE SESSION: Plant Design


◦ Landfill

◦ Sulfur Plant






• Gasification Options

◦ Gasifier:

▪ GE (Quench): (This is the default.) GE gasification is a form of entrained flow

gasification in which coal is fed to the gasifier in a water slurry. A quench cooling

system is used in all cases. See "5.4.2.4.1. GE" on page 457 and "5.4.3.4.1. GE"

on page 505.

▪ Shell: The shell gasification system is a dry-feed entrained flow gasification

technology. Radiant syngas cooling is used for non-capture cases, and a quench

cooling system is used for capture cases. See "5.4.2.4.2. Shell " on page 462 and

"5.4.3.4.2. Shell" on page 510.

◦ H2S Control: See "5.4.2.5. Sulfur Removal" on page 466 and "5.4.3.5. Sulfur

Removal" on page 515.

▪ Sulfinol: The Sulfinol process uses a combination of physical (Sulfolane) and

chemical (DIPA or MDEA) solvents to remove hydrogen sulfide, carbonyl sulfide

and mercaptans from the raw syngas. This option cannot be used with "Sour Shift

+ Selexol" CO2 capture. See "5.4.2.5.2. Sulfinol Sulfur Removal" on page 472 and

"5.4.3.5. Sulfur Removal" on page 515.

▪ Selexol: (This is the default.) The Selexol process uses dimethyl ether of

polyethylene glycol to remove hydrogen sulfide and some CO2 from the raw

syngas. See "5.4.2.5.1. Selexol Sulfur Removal" on page 466 and "5.4.3.5. Sulfur

Removal" on page 515.

◦ CO2 Capture:


▪ Sour Shift + Selexol: A CO2 capture system is used, which consists of gas shift

reactors and a Selexol-based CO2 removal system. This option requires Selexol

Sulfur Removal. See "5.4.2.6.2. Water Gas Shift Reactor" on page 482,

"5.4.2.6.4. Selexol CO2 Capture" on page 491, "5.4.3.6.3. Water Gas Shift

Reactor" on page 534 and "5.4.3.6.5. Selexol CO2 Capture" on page 542.

▪ Chemical Looping: In the Chemical Looping Combustion process, fuel is

combusted with the aid of an Oxygen Carrier rather than through direct contact

with air. The products of combustion include only water and CO2, allowing a very

high purity CO2 stream to be obtained by condensing the water vapor. See

"5.4.2.6.1. Chemical Looping" on page 476, "5.4.3.6.1. Chemical Looping" on

page 527, and "5.4.3.6.2. Purification Unit" on page 533.

▪ Sour Shift + Ionic Liquid: A CO2 capture system is used, which consists of gas

shift reactors and an ionic liquid-based CO2 removal system. See "5.4.2.6.2. Water

Gas Shift Reactor" on page 482, "5.4.2.6.3. Ionic Liquid CO2 Capture" on page

485, "5.4.3.6.3. Water Gas Shift Reactor" on page 534, and "5.4.3.6.4. Ionic

Liquid CO2 Capture" on page 537.



◦ Cooling System:

▪ Once-Through: This is the default. Cooling water is withdrawn from a natural


(See "5.2.3.9. Water Systems" on page 397.)



evaporation to transfer waste heat to the atmosphere. (See "5.2.2.9. Water

Systems" on page 253 and "5.2.3.9. Water Systems" on page 397.)


atmospheric air passed across finned-tube heat exchangers to reject heat.

("5.2.2.9. Water Systems" on page 253 and "5.2.3.9. Water Systems" on page

397.)

▪ Hybrid Cooling System: This combines a wet cooling tower and an air cooled

condenser. (See "5.2.2.9. Water Systems" on page 253 and "5.2.3.9. Water

Systems" on page 397.)

◦ Slag:

▪ Landfill: The slag collected is disposed in a landfill. This option is the only one

currently available in the model.

◦ Sulfur: Sulfur captured can be processed by the following equipment options:

▪ Sulfur Plant: Sulfur is processed into a solid form. This option is the only one

currently available in the model.


This screen is the same in all plant types. See "5.2.1.2. Plant Location" on page 114 for its

description.


This screen is the same in all plant types. See "5.2.1.3. Unit Systems" on page 115 for its

description.





5.4.2.1.1. Diagram




screen.





• Number of Gas Turbines: This is the number of gas turbines. Since each turbine is able


gross plant size). This number is shown here for reference only. You may set it in the

Power Block parameters. (See "5.4.2.7. Power Block" on page 496.)



Illustration 487: IGCC: SET PARAMETERS: Overall Plant: Diagram

Illustration 488: IGCC: SET PARAMETERS: Overall Plant: Performance



The value is controlled primarily by the number of gas turbines selected in the Power

Block parameters. (See "5.4.2.7. Power Block" on page 496.)




• Process Water Demand Factor: Process water demand factors account for water

required for Slurry, Slag Handling, Quench/Scrubber, BFW Makeup and Shift steam

(when CO2 is captured).





system. Currently, the model cannot have temperatures below 15ºF.

• Ambient Air Pressure: This is the absolute pressure of the air inlet stream to the boiler.

The air pressure is used to convert flue gas molar flow rates to volume flow rates.


• Ambient Air Humidity: This is the water content of the inlet combustion air. This value

is used in calculating the total water vapor content of the flue gas stream. The value is

referred to as the specific humidity ratio, expressed as a ratio of the water mass to the

dry air mass.


This screen is the same for all plant types. See "5.2.2.1.3. Region-Specific Cost Factors" on page

117 for details.


This screen defines the emission constraints as they apply to the gases emitted from the power

plant. Constraints for sulfur dioxide, nitrogen dioxides, carbon dioxide, and mercury are not

needed due to the cleaner emissions from IGCC plants.

The emission constraints determine the removal efficiencies of control systems that capture

particulates. The level of capture is set to comply with the specified emission constraints. As

discussed later, however, user-specified values for control technology performance may cause the

plant to over-comply or under-comply with the emission constraints specified in this screen. Each

parameter is described briefly below.

Illustration 489: IGCC: SET PARAMETERS: Overall Plant: Regulations &

Taxes


• Particulate Emission Constraint: The emission constraint of the total suspended

particulates is a function of the fuel type and is used to determine the removal efficiency

of particulate control systems (if used).






in dollars per ton.






See "5.2.2.1.5. Financing & Cost Year" on page 120 for a description of this screen.


See "5.2.2.1.6. Fuel & Land Cost" on page 122 for a description of this screen.


See "5.2.2.1.7. Capital Cost" on page 123 for a description of this screen.

5.4.2.1.8. O&M Cost










• Beavon-Stretford Catalyst Cost: This is the cost of the catalyst used for the Beavon-

Stretford sulfur recovery system.


• Claus Plant Catalyst Cost: This is the cost of the catalyst used by the Claus sulfur

recovery system.

• Glycol Cost: This is the cost of glycol used by the Selexol CO2 capture system.

• Shift Reactor Catalyst (Hi-T): This is the cost of the high temperature catalyst used for

first WGSR stage.

• Shift Reactor Catalyst (Low-T): This is the cost of the low temperature catalyst used

for the second WGSR stage.

• Urea Cost: This is the cost of natural gas in dollars per ton.

• Ionic Liquid Cost: This is the cost of the solvent used by the Ionic Liquid CO2 capture

system.



plant cost.

Illustration 490: IGCC: SET PARAMETERS: Overall Plant: O&M Cost




• Sulfur Byproduct Credit: This is the credit for sulfur sold on the market as collected by

the Claus and Beavon-Stretford plants.






This screen is the same for all plant types and is described in "5.2.2.1.9. Reference Plant" on page

125.

5.4.2.2. Fuel

These screens display and define the composition and cost of the fuels used in the plant. Default

properties of fuels are provided, but user-specified properties can also be easily substituted.

The integrated gasification combined cycle (IGCC) plant configurations assume coal gasification to

produce a synthetic fuel gas. The coal properties may be chosen from a predetermined set of coals,

or a custom coal may be entered.

5.4.2.2.1. Coal Properties

The first parameter on this screen is a menu that allows you to choose the coal. The options are:

• Appl. Low Sulfur

• Appl. Med. Sulfur (this is the default)

• Illinois 6

Illustration 491: IGCC: SET PARAMETERS: Fuel: Coal Properties


• ND Lignite

• WPC Utah

• Wyoming PRB

• Custom

All of the options except "Custom" have a fixed set of properties that cannot be edited. See

"5.1.2.1. Coal Properties" on page 100 for a description of coal properties. Note that while the

default cost is read-only, you can change the actual cost used on the "Cost" screen. (See

"5.4.2.2.3. Cost" on page 455.)

If you want to specify your own coal and/or import an arbitrary coal from a database, you may

choose the "Custom" coal. This enables the database button and gives you full access to the

properties. See "5.2.2.2.1. Coal Properties" on page 126 for a description of how to use the screen

in this mode.

At the bottom of the screen, there is a warning that uncertainty on this screen should only be used

for batch processing. (See "4.3.3.3.13. Batch Processing" on page 66 for a description of batch

processing.) Varying the components independently does not make sense - if one percentage is

higher, another percentage will need to be lower to keep the total at 100%.

If you choose "Custom" as the coal, you will be required to specify the syngas composition. See

"5.4.2.4.1.3. Syngas Out" on page 460 or "5.4.2.4.2.3. Syngas Out" on page 464 for more

information.


This is similar to the "Ash Properties" screen for PC plants, described in "5.2.2.2.2. Ash

Properties" on page 127. If you have chosen the "Custom" coal on the previous screen, the ash

properties will be editable; otherwise they are for reference only.

Illustration 492: IGCC: SET PARAMETERS: Fuel: Ash Properties


5.4.2.2.3. Cost

This screen has the following coal cost parameters:

• Total Delivered Cost (as-fired): This is the total cost of delivered coal on a wet ton

basis in dollars per ton. It is assumed to contain any costs of cleaning and transportation.

The total cost in units of $/ton is by default the value shown on the coal properties

screen.

• Total Delivered Cost (as-fired): This is also provided in units of $/MBtu. This value

cannot be edited. It is based on the value given above in units of $/ton.

5.4.2.3. Air Separation Unit

This chapter illustrates the configuration and inputs of the air separation technology. It is primarily

used in IGCC plants, although oxyfuel systems in PC plants use it as well.

5.4.2.3.1. Air Separation Diagram

This diagram gives an overview of the air separation unit. This diagram does not contain any


Illustration 493: IGCC: SET PARAMETERS: Fuel: Cost

Illustration 494: IGCC: SET PARAMETERS: Air

Separation Unit: Air Separation Diagram




• Oxidant Composition

◦ Oxygen (O2): This is the percent of oxygen that is in the oxidant that is produced

by the air separation unit. The value is fixed for the IGCC plant type.

◦ Argon (Ar): This is the percent of argon that is in the oxidant that is produced by

the air separation unit.

◦ Nitrogen (N2): This is the percent of nitrogen that is in the oxidant that is


• Final Oxidant Pressure: The final oxidant stream from the ASU can be provided at a

high pressure. The default value is determined by the plant type being used.

• Maximum Train Capacity: The maximum production rate of oxidant is specified

here. It is used to determine the number of operating trains required.





• Unit Separation ASU Energy: The main air compressor (MAC) pressurizes

atmospheric air to approximately 550 kPA (65 psig). The MAC is a multi-staged,

intercooled compressor that can be treated as isothermal. This measures the electric

power use per unit of air flow (kW/ton).

• Total Cryogenic ASU Energy: This is the electricity used by the air separation unit

for internal use. A majority of the power is used for the main air compressor and a

secondary amount used for the product stream compressor (if required). It is

expressed as a percent of the gross plant capacity.

Illustration 495: IGCC: SET PARAMETERS: Air Separation Unit:

Performance


When this screen appears in a PC plant, the following input is also included:

• ASU Cool. Duty Recov. as Heat Integration: This is the fraction of cooling duty

recovered as heat integration.



90.

5.4.2.3.4. O&M Cost

This is a standard O&M cost input screen as described in "5.1.1.5. O&M Cost Inputs" on page

97. It does not contain any additional inputs.



costs. The air separation unit has the following capital cost process areas:

• Air Separation Unit: The retrofit factor is a ratio of the costs of retrofitting an existing

facility with an air separation unit versus a new facility, using the same equipment.

• Final Oxidant Compression: The final oxidant may need to be compressed to a higher

pressure than 20psia. This typically applies to IGCC plants.

5.4.2.4. Gasifier Area

This chapter describes the coal gasification equipment used in the IGCC plant types.

5.4.2.4.1. GE

GE gasification is a form of entrained flow gasification in which coal is fed to the gasifier in a

water slurry. A quench cooling system is used in all cases.

5.4.2.4.1.1. GE Gasifier Diagram

This diagram gives an overview of the GE gasifier. This diagram does not contain any numbers


Illustration 496: IGCC: SET PARAMETERS: Air Separation Unit: Retrofit or

Adjustment Factors



Illustration 497: IGCC: SET PARAMETERS: Gasifier

Area: GE: GE Gasifier Diagram

Illustration 498: IGCC: SET PARAMETERS: Gasifier Area: GE:

Performance



• Gasifier Area

◦ Gasifier Temperature: This is the temperature of the syngas exiting GE

Entrained-Flow Reactor. You may choose from the following values:

▪ 2350F

▪ 2450F (this is the default)

▪ 2550F

◦ Gasifier Pressure: This is the pressure of the syngas exiting GE Entrained-Flow

Reactor. This value is provided for reference only.

◦ Total Water or Steam Input: This is the ratio of water to carbon in the coal

slurry.

◦ Oxygen Input from ASU: The GE gasifier requires a constant value for the

oxygen (O2) in the oxidant to carbon (C) in coal ratio. This value is provided for

reference only.

◦ Total Carbon in Slag: This the percent of carbon in the fuel that is lost in the

slag. You may choose from the following options:

▪ 1

▪ 3 (this is the default)

▪ 5

◦ Sulfur Loss to Solids: This is the percent of the sulfur in coal that is lost in the

slag.

◦ Coal Ash in Raw Syngas: This is the percent of ash in the coal that is in the

syngas.

◦ Percent Water in Slag Sluice: This is the percent of the slag sluice that is water.


primarily to calculate capital costs. The value must be an integer



• Raw Gas Cleanup Area

◦ Particulate Removal Efficiency: This is the percentage of the ash which is

removed by the raw gas cleanup process.

• Power Requirement: This is the equivalent electrical output of thermal (steam)

energy used for reheat, plus the actual electrical output power required.


5.4.2.4.1.3. Syngas Out

The syngas generated by the gasifier is calculated as a function of the coal, water, and oxidant

input flow rates, the carbon loss, and the gasifier temperature. The composition may be

changed by the user. The location of this syngas composition is after the gasification but prior

to the low temperature cooling and water quench. Hence, the steam content of the syngas is

typically in the 10–15% by volume range.

If a custom coal is used, the syngas composition must be specified by the user.

See "5.1.3.2. Syngas Components" on page 102 for a description of the Raw Syngas

Composition.

At the bottom of the screen, there is a warning that uncertainty on this screen should only be

used for batch processing. (See "4.3.3.3.13. Batch Processing" on page 66 for a description of

batch processing.) Varying the components independently does not make sense - if one

percentage is higher, another percentage will need to be lower to keep the total at 100%.



page 90.

Illustration 499: IGCC: SET PARAMETERS: Gasifier Area: GE: Syngas Out


5.4.2.4.1.5. O&M Cost



• Slag Disposal Cost: This is the solid disposal cost per ton.

• Water Cost: This is the cost of the water per 1000 gallons.



costs. The gasifier has the following capital cost process areas:

• Coal Handling: Coal handling involves unloading coal from a train, storing the coal,

moving the coal to the grinding mills, and feeding the gasifier with positive

displacement pumps. A typical coal handling section contains one operating train and

no spare train. A train consists of a bottom dump railroad car unloading hopper,

vibrating feeders, conveyors, belt scale, magnetic separator, sampling system, deal

coal storage, stacker, reclaimer, as well as some type of dust suppression system.

Slurry preparation trains typically have one to five operating trains with one spare

train. The typical train consists of vibrating feeders, conveyors, belt scale, rod mills,

storage tanks, and positive displacement pumps to feed the gasifiers. All of the

equipment for both the coal handling and the slurry feed are commercially available.

Illustration 500: IGCC: SET PARAMETERS: Gasifier Area: GE: O&M Cost

Illustration 501: IGCC: SET PARAMETERS: Gasifier Area: GE: Retrofit or

Adjustment Factors


A regression model was developed for the direct cost of coal handling and slurry

preparation using the data collected for possible independent variables affecting direct

capital cost. Coal feed rate to the gasifier on as-received basis is the most common

and easily available independent variable. The direct cost model for the coal handling

is based upon the overall flow to the plant rather than on a per train basis.

• Gasifier Area: The gasifier area of an IGCC plant contains gasifier, gas cooling, slag

handling, and ash handling sections.

• Low Temperature Gas Cooling: The low temperature gas cooling section includes a

series of three shell and tube exchangers. The number of operating trains are

estimated based on the total syngas mass flow rate and the range of syngas flow rates

per train used.

• Process Condensate Treatment: This model is based upon one data point from AP-

5950. Because the treated process condensate is used as make-up to the gas scrubbing

unit, and because blowdown from the gas scrubbing unit is the larger of the flow

streams entering the process condensate treatment section, it is expected that process

condensate treatment cost will depend primarily on the scrubber blowdown flow rate.

5.4.2.4.2. Shell

The shell gasification system is a dry-feed entrained flow gasification technology. Radiant syngas

cooling is used for non-capture cases and a quench cooling system is used for capture cases.

5.4.2.4.2.1. Shell Gasifier Diagram

This diagram gives an overview of the Shell gasifier. This diagram does not contain any


Illustration 502: IGCC: SET PARAMETERS: Gasifier Area: Shell: Shell

Gasifier Diagram




• Gasifier Area

◦ Gasifier Temperature: This is the temperature of the syngas exiting Shell

Entrained-Flow Reactor. You may choose from the following options:

▪ 2500F

▪ 2600F (this is the default)

▪ 2700F

◦ Gasifier Pressure: This is the pressure of the syngas exiting Shell Entrained-

Flow Reactor. This value is provided for reference only.

◦ Moisture in Dried Coal: This is the percentage of moisture in the coal exiting

the coal dryer. This value is provided for reference only.

◦ Total Water or Steam Input: This is the ratio of water to carbon in the coal

slurry.

◦ Oxygen Input from ASU: The Shell gasifier requires a constant value for the

oxygen (O2) in the oxidant to carbon (C) in coal ratio. This value is provided for

reference only.

◦ Total Carbon Loss: This the percent of carbon in the fuel that is lost in the slag.

You may choose from the following options:

▪ 0.5 (this is the default)

Illustration 503: IGCC: SET PARAMETERS: Gasifier Area: Shell:

Performance


▪ 1.0

▪ 1.5

◦ Sulfur Loss to Solids: This is the percent of the sulfur in coal that is lost in the

slag.

◦ Coal Ash in Raw Syngas: This is the percent of ash in the coal that is in the

syngas.

◦ Percent Water in Slag Sluice: This is the percent of the slag sluice that is water.


primarily to calculate capital costs. The value must be an integer


to calculate capital costs.

• Raw Gas Cleanup Area

◦ Particulate Removal Efficiency: This is the percentage of the ash which is

removed by the raw gas cleanup process.

• Power Requirement: This is the equivalent electrical output of thermal (steam)

energy used for reheat, plus the actual electrical output power required.

5.4.2.4.2.3. Syngas Out

The syngas generated by the gasifier is calculated as a function of the coal, water, and oxidant

input flow rates, the carbon loss, and the gasifier temperature. The composition may be

changed by the user. The location of this syngas composition is after the gasification but prior

to the low temperature cooling and water quench. Hence, the steam content of the syngas is

typically in the 10–15% by volume range.

Illustration 504: IGCC: SET PARAMETERS: Gasifier Area: Shell: Syngas

Out


If a custom coal is used, the syngas composition must be specified by the user.

See "5.1.3.2. Syngas Components" on page 102 for a description of the Raw Syngas

Composition.

At the bottom of the screen, there is a warning that uncertainty on this screen should only be

used for batch processing. (See "4.3.3.3.13. Batch Processing" on page 66 for a description of

batch processing.) Varying the components independently does not make sense - if one

percentage is higher, another percentage will need to be lower to keep the total at 100%.



page 90.

5.4.2.4.2.5. O&M Cost



• Slag Disposal Cost: This is the solid disposal cost per ton.

• Water Cost: This is the cost of the water per 1000 gallons.


Illustration 505: IGCC: SET PARAMETERS: Gasifier Area: Shell: O&M Cost



costs. The gasifier has the following capital cost process areas:

• Coal Handling: Coal handling involves unloading coal from a train, storing the coal,

moving the coal to the grinding mills, and feeding the gasifier with positive

displacement pumps. A typical coal handling section contains one operating train and

no spare train. A train consists of a bottom dump railroad car unloading hopper,

vibrating feeders, conveyors, belt scale, magnetic separator, sampling system, deal

coal storage, stacker, reclaimer, as well as some type of dust suppression system.

Slurry preparation trains typically have one to five operating trains with one spare

train. The typical train consists of vibrating feeders, conveyors, belt scale, rod mills,

storage tanks, and positive displacement pumps to feed the gasifiers. All of the

equipment for both the coal handling and the slurry feed are commercially available.

A regression model was developed for the direct cost of coal handling and slurry

preparation using the data collected for possible independent variables affecting direct

capital cost. Coal feed rate to the gasifier on as-received basis is the most common

and easily available independent variable. The direct cost model for the coal handling

is based upon the overall flow to the plant rather than on a per train basis.

• Gasifier Area: The gasifier area of an IGCC plant contains gasifier, gas cooling, slag

handling, and ash handling sections.

• Low Temperature Gas Cooling: The low temperature gas cooling section includes a

series of three shell and tube exchangers. The number of operating trains are

estimated based on the total syngas mass flow rate and the range of syngas flow rates

per train used.

• Process Condensate Treatment: This model is based upon one data point from AP-

5950. Because the treated process condensate is used as make-up to the gas scrubbing

unit, and because blowdown from the gas scrubbing unit is the larger of the flow

streams entering the process condensate treatment section, it is expected that process

condensate treatment cost will depend primarily on the scrubber blowdown flow rate.

• Activated Carbon Injection: Activated carbon is used to remove mercury.

5.4.2.5. Sulfur Removal

5.4.2.5.1. Selexol Sulfur Removal

SO2 emissions from IGCC systems are controlled by removing sulfur species from the syngas

prior to combustion in the gas turbine. The syngas is assumed to be scrubbed of particulates

prior to entering the sulfur removal system and is further cooled to 101°F prior to entering a

Selexol acid gas separation unit. H2S and COS are removed from the syngas in the Selexol unit

and sent to a Claus plant and a Beavon-Stretford tail gas treatment unit for sulfur recovery. The

Illustration 506: IGCC: SET PARAMETERS: Gasifier Area: Shell: Retrofit or

Adjustment Factors


sulfur recovered can be sold as a by-product and credited to the sulfur removal technology

area.

5.4.2.5.1.1. Sulfur Capture System Diagram

This diagram gives an overview of the Selexol sulfur capture system. This diagram does not


Illustration 507: IGCC: SET PARAMETERS: Sulfur Removal: Selexol: Sulfur

Capture System Diagram



The acid gas removal system employs the Selexol process for selective removal of hydrogen

sulfide (H2S) and carbonyl sulfide (COS). Usually COS is present in much smaller quantities

than H2S. In this unit, most of the H2S is removed by absorption in the Selexol solvent, with a

typical removal efficiency of 95 to 98 percent. Typically, only about one third of COS in the

syngas will be absorbed. A hydrolyzer is used to convert the captured COS to H2S in

preparation for the stripping of H2S from the Selexol solvent, along with sour gas from the

process water treatment unit. This concentrated gas stream is then sent to the Claus sulfur plant

for recovery of elemental sulfur.

• Hydrolyzer (or Shift Reactor)

◦ COS to H2S Conversion Efficiency: This is the efficiency with which carbonyl

sulfide is converted to hydrogen sulfide.

• Sulfur Removal Unit

◦ H2S Removal Efficiency: This is the removal efficiency of H2S from the inlet

syngas stream. The H2S is removed by an absorption process that is very

effective at capture of H2S.

◦ COS Removal Efficiency: This is the removal efficiency of COS. The

absorption process is not very effective at capturing COS, so the removal

efficiency default is very low.

◦ CO2 Removal Efficiency: This is removal efficiency of CO2 for the sulfur

recovery system. This system is optimized to capture sulfur-bearing components

of a syngas, but maintains an affinity for CO2. The CO2 removed is eventually

vented to the atmosphere from the Beavon-Stretford technology.

Illustration 508: IGCC: SET PARAMETERS: Sulfur Removal: Selexol:

Performance


◦ Max Syngas Capacity per Train: This is the maximum flow rate of one Selexol-

based sulfur recovery vessel. It is used to determine the number of absorber

vessels required to treat the syngas.

◦ Number of Operating Absorbers: This is the number of absorbers required to

treat the entire syngas stream. It is used primarily to determine the cost of the

sulfur control area. This must be an integer.

◦ Power Requirement: This is the equivalent electrical output of thermal (steam)

energy used for reheat, plus the actual electrical output power required. It is

calculated as a function of the syngas flow rate.

• Claus Plant

◦ Sulfur Recovery Efficiency: This is the recovery efficiency of the Claus Plant in

converting H2S to elemental sulfur.

◦ Max Sulfur Capacity per Train: This is the maximum capacity of elemental

sulfur from one Claus train.

◦ Number of Operating Absorbers: The number of trains is estimated from the

recovered sulfur mass flow rate and the allowable range of recovered sulfur mass

flow rate per train. This must be an integer.



calculated as a function of the sulfur flow from the Claus plant.

• Tailgas Treatment: (Note: The number of trains for this area is the same as the

number of trains for the Claus plant process area.)

◦ Sulfur Recovery Efficiency: This is the recovery efficiency of the Beavon-

Stretford plant in generating elemental sulfur. The remainder is oxidized to SO2

and sent to a stack.



calculated as a function of the sulfur flow rate from the Beavon-Stretford plant.



page 90.


5.4.2.5.1.4. O&M Cost



• Selexol Solvent Cost: This is the unit cost of Selexol.

• Claus Plant Catalyst Cost: This is the unit cost of catalyst used in the Claus plant.

• Beavon-Stretford Catalyst Cost: This is the unit cost of catalyst used in the Beavon-

Stretford plant.

• Sulfur Byproduct Credit: This is the unit price of sulfur sold on the market.

• Sulfur Disposal Cost: This is the unit cost of any disposal wastes generated by the

sulfur recovery processes.

• Sulfur Sold on Market: This is the fraction of the collected sulfur that is sold on the

market. Any remaining sulfur is assumed to be utilized at no cost (i.e., neither

disposed nor sold).

Illustration 509: IGCC: SET PARAMETERS: Sulfur Removal: Selexol: O&M

Cost



See "5.1.1.8. Retrofit or Adjustment Factor Inputs" on page 100for an explanation of retrofit

costs. The sulfur removal system has the following capital cost process areas:

• COS Conversion System - Hydrolyzer: The Hydrolyzer helps to separate the carbon

from the sulfur by converting carbonyl sulfide to hydrogen sulfide.

• Sulfur Removal System – Selexol: H2S in the syngas is removed through counter-

current contact with Selexol solvent. The cost of the Selexol section includes the acid

gas absorber, syngas knock-out drum, syngas heat exchanger, flash drum, lean solvent

cooler, mechanical refrigeration unit, lean/rich solvent heat exchanger, solvent

regenerator, regenerator air-cooled overhead condenser, acid gas knock-out drum,

regenerator reboiler, and pumps and expanders associated with the Selexol process.

• Sulfur Recovery System – Claus: The Claus plant contains a two-stage sulfur

furnace, sulfur condensers, and catalysts.

• Tail Gas Treatment - Beavon-Stretford: The capital cost of a Beavon-Stretford unit

varies with the volume flow rate of the input gas streams and with the mass flow rate

of the sulfur produced. The regression model is based only on the sulfur produced by

the Beavon-Stretford process.

Illustration 510: IGCC: SET PARAMETERS: Sulfur Removal: Selexol:



5.4.2.5.2. Sulfinol Sulfur Removal

5.4.2.5.2.1. Sulfur Capture System Diagram

This diagram gives an overview of the Sulfinol sulfur capture system. This diagram does not


Illustration 511: IGCC: SET PARAMETERS: Sulfur Removal: Sulfinol: Sulfur

Capture System Diagram



The acid gas removal system employs the Sulfinol process for selective removal of hydrogen

sulfide (H2S) and carbonyl sulfide (COS). A hydrolyzer is used to convert the captured COS to

H2S in preparation for the stripping of H2S from the solvent, along with sour gas from the

process water treatment unit. This concentrated gas stream is then sent to the Claus sulfur plant

for recovery of elemental sulfur.


• Hydrolyzer (or Shift Reactor)

◦ COS to H2S Conversion Efficiency: This is the efficiency with which carbonyl

sulfide is converted to hydrogen sulfide.

• Sulfinol Sulfur Removal Unit

◦ H2S Removal Efficiency: This is the removal efficiency of H2S from the inlet

syngas stream. The H2S is removed by an absorption process that is very

effective at capture of H2S.

◦ COS Removal Efficiency: This is the removal efficiency of COS. The

absorption process is not very effective at capturing COS, so the removal

efficiency default is very low.

◦ CO2 Removal Efficiency: This is removal efficiency of CO2 for the sulfur

recovery system. This system is optimized to capture sulfur-bearing components

of a syngas, but maintains an affinity for CO2. The CO2 removed is eventually

vented to the atmosphere from the Beavon-Stretford technology.

◦ Maximum Syngas Capacity per Train: This is the maximum flow rate of one

Selexol-based sulfur recovery vessel. It is used to determine the number of

absorber vessels required to treat the syngas.

Illustration 512: IGCC: SET PARAMETERS: Sulfur Removal: Sulfinol:

Performance


◦ Number of Operating Absorbers: This is the number of absorbers required to

treat the entire syngas stream. It is used primarily to determine the cost of the

sulfur control area. This must be an integer.



calculated as a function of the syngas flow rate.

• Claus Plant

◦ Sulfur Recovery Efficiency: This is the recovery efficiency of the Claus Plant in

converting H2S to elemental sulfur.

◦ Max Sulfur Capacity per Train: This is the maximum capacity of elemental

sulfur from one Claus train.

◦ Number of Operating Absorbers: The number of trains is estimated from the

recovered sulfur mass flow rate and the allowable range of recovered sulfur mass

flow rate per train. This must be an integer.



calculated as a function of the sulfur flow from the Claus plant.

• Tailgas Treatment: (Note: The number of trains for this area is the same as the

number of trains for the Claus plant process area.)

◦ Sulfur Recovery Efficiency: This is the recovery efficiency of the Beavon-

Stretford plant in generating elemental sulfur. The remainder is oxidized to SO2

and sent to a stack.



calculated as a function of the sulfur flow rate from the Beavon-Stretford plant.



page 90.


5.4.2.5.2.4. O&M Cost



• Selexol Solvent Cost: This is the unit cost of Selexol.

• Claus Plant Catalyst Cost: This is the unit cost of catalyst used in the Claus plant.

• Beavon-Stretford Catalyst Cost: This is the unit cost of catalyst used in the Beavon-

Stretford plant.

• Sulfur Byproduct Credit: This is the unit price of sulfur sold on the market.

• Sulfur Disposal Cost: This is the unit cost of any disposal wastes generated by the

sulfur recovery processes.

• Sulfur Sold on Market: This is the fraction of the collected sulfur that is sold on the

market. Any remaining sulfur is assumed to be utilized at no cost (i.e., neither

disposed nor sold).

Illustration 513: IGCC: SET PARAMETERS: Sulfur Removal: Sulfinol: O&M

Cost




costs. The sulfur removal system has the following capital cost process areas:

• COS Conversion System - Hydrolyzer: The Hydrolyzer helps to separate the carbon

from the sulfur by converting carbonyl sulfide to hydrogen sulfide.

• Sulfur Removal System – Sulfinol: H2S in the syngas is removed through counter-

current contact with the solvent. The cost of the Sulfinol section includes the acid gas

absorber, syngas knock-out drum, syngas heat exchanger, flash drum, lean solvent



regenerator reboiler, and pumps and expanders associated with the Sulfinol process.

• Sulfur Recovery System – Claus: The Claus plant contains a two-stage sulfur


• Tail Gas Treatment - Beavon-Stretford: The capital cost of a Beavon-Stretford unit





5.4.2.6.1. Chemical Looping

Chemical looping combustion (CLC) is an indirect process in which fuel is combusted without

direct contact with air. Transfer of oxygen between air and fuel takes place with the aid of an

oxygen-carrier (OC). The oxygen-carrier extracts O2 from air in one reactor and then transfers it

to fuel in a subsequent reactor. Since the fuel does not come in direct contact with air, the

products of combustion contain only carbon dioxide (CO2) and water (H2O). A CO2 stream of

very high purity can be obtained by condensing the water vapor.

Illustration 514: IGCC: SET PARAMETERS: Sulfur Removal: Sulfinol:




This diagram gives an overview of the chemical looping CO2 capture system. This diagram

does not contain any numbers and is strictly for reference:

5.4.2.6.1.2. Purification Unit Diagram

This diagram gives an overview of the Cryogenic Purification Unit (CPU). This diagram does


Illustration 515: IGCC: SET PARAMETERS: CO2 Capture, Transport &

Storage: Chemical Looping: Chemical Looping Diagram


Storage: Chemical Looping: Purification Unit Diagram


5.4.2.6.1.3. Config

This screen allows you to configure the chemical looping CO2 capture system:


• Chemical Looping

◦ Metal Oxide (MeO) Type: The type of oxygen carrier. Currently the only

supported type is NiO.

◦ Inert Support Material: The inert support material for the oxygen carrier.

Currently the only supported type is Al2O3.

◦ MeO % in Oxygen Carrier (OC): The percentage of MeO in the oxygen carrier.

◦ CO2 Product Compressor Used?: This determines whether or not the chemical

looping system includes a CO2 product compressor.

• CO2 Product Stream (only shown when a CO2 product compressor is used)

◦ Maximum CO2 Compressor Capacity: The maximum capacity of the

compressor used to compress the captured CO2.

◦ Number of Operating CO2 Compressors: The number of operating CO2

compressors; the number is determined by comparing the maximum CO2

compressor capacity with the CO2 flow rate captured in the absorber. This value

must be an integer.

◦ Number of Spare CO2 Compressors: The number of spare CO2 compressors.


Storage: Chemical Looping: Config




• Air Reactor

◦ Air Reactor Temperature: The temperature of the air reactor. The following

choices are available:

▪ 900C

▪ 1000C

▪ 1100C

▪ 1200C

◦ Inlet Excess MeO: The mole flow of OC is expressed as a function of excess

amount of NiO exiting the fuel reactor. This NiO is the excess amount compared

with the stoichiometric amount of OC required for the fuel. The mole flow rate of

OC determines the adiabatic temperature in the fuel reactor.

◦ Excess Air Ratio: In order to maintain the air reactor temperature at the specified

value, the amount of excess air has to be varied. The adiabatic temperature

depends on the air flow rate and temperature, oxygen carrier (OC) flow rate and

temperature.

◦ Superficial Gas Inlet Velocity: Superficial gas velocity at the air reactor inlet.

◦ Residence Time of Solids: Residence time of solids in the air reactor.

• Fuel Reactor

◦ Fuel Reactor Temperature: The temperature of the fuel reactor.


Storage: Chemical Looping: Performance


◦ Stoichiometric Ratio: The stoichiometric ratio of O2 versus fuel.

◦ Combustion Efficiency: The fuel reactor combustion efficiency.

◦ Residence Time of Solids: The residence time of solids in the fuel reactor.

◦ OC Degeneration Rate: Oxygen carrier solid degradation rate.

• Maximum Train Diameter: This is the maximum diameter for either the air reactor

or the fuel reactor.

• Number of Operating Trains: This is the number of operating air reactors. It must be

an integer.

• Number of Spare Trains: This is the number of spare air reactors; each reactor

assumes a full train of assorted equipment.

• CLC Power Requirement: This is the electricity used by the chemical looping

system for internal use. It is expressed as a percent of the gross plant capacity.

5.4.2.6.1.5. T&S Config

This screen characterizes the compression and storage methods for the product CO2:




cooling.







using compressors, before it is transported is about 2000 psig.


◦ Compression & Cryogenic Purif. Energy: (Only shown when a CO2 product

compressor is configured.) This is the electrical energy required to compress a unit

mass of CO2 product stream to the designated pressure. Compression of CO2 to high


Storage: Chemical Looping: T&S Config


pressures requires substantial energy, and is a principle contributor to the overall

energy penalty of a CO2 capture unit in a power plant.


107.



page 90.

5.4.2.6.1.7. O&M Cost



• Oxygen Carrier Cost: This is the cost of the Oxygen Carrier used in the chemical

looping process.



◦ CO2 Transportation Cost: This is the cost of moving the CO2 (i.e., pipeline,

truck) to the place where it will be sequestered.



Storage: Chemical Looping: O&M Cost




costs. Retrofit ratios can be specified for the following process areas:

• Air Reactor: The oxygen carrier (OC) is oxidized in the air reactor.

• Fuel Reactor: The oxygen carrier (OC) is reduced in the fuel reactor.

• Cryogenic Purification Unit: The flue gas is compressed, dried and then purified

using a partial condensation and distillation process.

• Solids Handling Equipment: Make-up sorbent and purged sorbent are transported

using the solids handling equipment.

5.4.2.6.2. Water Gas Shift Reactor

5.4.2.6.2.1. Water Gas Shift Reactor Diagram

This diagram gives an overview of the water gas shift reactor (WGSR). This diagram does not



Storage: Chemical Looping: Retrofit or Adjustment Factors


Storage: Water Gas Shift Reactor: Water Gas Shift Reactor Diagram




• Water Gas Shift Reactor Unit

◦ CO to CO2 Conversion Efficiency: Most of the CO in the raw syngas is

converted into CO2 through the Water Gas Shift reaction. CO2 is removed from

the shifted syngas through a physical absorption unit. This variable is the

percentage of CO that is converted to CO2 in the reaction.

◦ COS to H2S Conversion Efficiency: COS is difficult to remove in the Selexol

unit, so a polishing unit is added to convert COS to H2S. This is the conversion

efficiency of the polishing unit.

◦ Steam Added: This parameter determines the amount of water added to the shift

reactor in converting CO to CO2. The moles of steam added is proportional to the

moles of CO converted.

◦ Maximum Train CO2 Capacity: The maximum production rate of CO2 is

specified here. It is used to determine the number of operating trains required.

◦ Number of Operating Trains: This is the total number of operating trains. It is


◦ Number of Spare Trains: This is the total number of spare trains. It is used


• Thermal Energy Credit: The Water Gas Shift reaction is an exothermic process,

producing heat that can be extracted and converted to steam for use in generating

electricity. This is the thermal energy credit for steam produced and used in the steam

cycle.



page 90.


Storage: Water Gas Shift Reactor: Performance


5.4.2.6.2.4. O&M Cost



• High Temperature Catalyst Cost: This is the unit cost of the iron-based high

temperature catalyst.

• Low Temperature Catalyst Cost: This is the unit cost of the copper-based low

temperature catalyst.

• Water Cost: This is unit cost of water used to drive the water gas shift reaction.



costs. The water gas shift reactor has the following capital cost process areas:

• High Temperature Reactor: This area accounts for the high temperature reactor

vessel used for water gas shift. The iron-based catalyst is designed to be effective at

high temperatures (650-1100 °F). The high temperature reactor has a high reaction

rate and converts a large amount of CO into CO2.


Storage: Water Gas Shift Reactor: O&M Cost


Storage: Water Gas Shift Reactor: Retrofit or Adjustment Factors


• Low Temperature Reactor: This area accounts for the low temperature reactor

vessel used for water gas shift. The copper-based catalyst is designed to be effective

at lower temperatures (450-650 °F). The low temperature reactor has a lower reaction

rate, but converts a very high percentage of the remaining CO into CO2.

• Heat Exchangers: The water gas shift process involves substantial cooling because

of the exothermic reaction. Heat is recovered and temperature control is maintained

through heat exchangers added after each reactor. This process area accounts for the

heat exchangers used. Steam generated in the heat exchangers is sent to the steam

cycle.

5.4.2.6.3. Ionic Liquid CO2 Capture

Ionic liquids (ILs) can be used as solvents to capture CO2. The solvent for CO2 capture is

[P2228][2-CNpyr], one of tetraalkylphosphonium 2-cyanopyrrolide ionic liquids (ILs)

synthesized by researchers at the University of Notre Dame. Such ILs can react chemically with

CO2. Thus, the typical absorption and stripping configuration is adopted for pre-combustion CO2

capture using [P2228][2-CNpyr].

5.4.2.6.3.1. Ionic Liquid Diagram

This diagram gives an overview of the Ionic Liquid CO2 capture system. This diagram does



Storage: Ionic Liquid CO2 Capture: Ionic Liquid Diagram


5.4.2.6.3.2. Config

This screen allows you to configure the ionic liquid CO2 capture system:

The following parameter is shown:

• CO2 Product Compressor Used?: This parameter determines whether or not the

ionic liquid system includes a CO2 product compressor.



• Carbon Dioxide Removal Unit

◦ CO2 Removal Efficiency: CO2 removal is specified by the user and is used to

determine the solvent makeup flow, capital cost, and operating and maintenance

costs.

◦ H2S Removal Efficiency: H2S is naturally removed with CO2. This parameter

specifies the amount that is captured.

◦ Mercury Removal Efficiency (oxidized): This is the removal efficiency of the

oxidized portion of mercury from the CO2 capture with Ionic Liquid. The

removed portion can be found in the bottom ash and the remainder found in the

syngas.

◦ Mercury Removal Efficiency (elemental): This is the removal efficiency of the

elemental portion of mercury from the CO2 capture with Ionic Liquid. The


Storage: Ionic Liquid CO2 Capture: Config


Storage: Ionic Liquid CO2 Capture: Performance



syngas.

◦ Mercury Removal Efficiency (particulate): This is the removal efficiency of

the particulate portion of mercury from the CO2 capture with Ionic Liquid. The


syngas.

◦ Max Syngas Capacity per Train: Each train contains one absorber vessel that

has a maximum flow rate. This parameter determines the maximum flow rate

through the vessel.

◦ Number of Operating Absorbers: This is the total number of operating absorber

vessels. The calculated value is determined by comparing the total flow rate of

syngas through the Selexol process and the maximum syngas capacity per train.

The value must be an integer.

◦ Number of Spare Absorbers: This is the total number of spare absorber vessels.

It is used primarily to calculate capital costs.

◦ Power Requirement: This is the electricity used by the Ionic Liquid CO2

Capture System for internal use. It is expressed as a percent of the gross plant

capacity.

5.4.2.6.3.4. Capture


• Absorber

◦ Lean CO2 Loading: This is the solvent loading of CO2 in the system after the

regenerator; although not technically a stoichiometry, it determines the amount of

solvent needed to remove sufficient CO2.

◦ Sorbent Losses: This is the amount of sorbent lost in the absorber.


Storage: Ionic Liquid CO2 Capture: Capture


◦ Liquid-to-Gas Ratio: This is the liquid to gas ratio (L/G) of solvent circulating

to syngas gas treated.

◦ Absorption Temp: This is the operating temperature of absorption by ionic

liquid.

◦ Absorption Pressure: This is the operating pressure of absorption by ionic

liquid.

• Regenerator

◦ Regeneration Temp: This is the operating temperature of solvent regeneration.

◦ Regeneration Pressure: This is the operating pressure of solvent regeneration.

◦ Regen. Heat Requirement: This is the heat required for the regeneration of the

loaded solvent in the stripper/regenerator section.

◦ Regeneration Steam Heat Content: Low pressure steam is extracted from the

base plant to use for regenerator heat. This is the heat content of that steam.

◦ Heat-to Electricity Efficiency: This is the efficiency of converting low pressure

steam to electricity. The value reflects the loss of electricity to the base plant

when the LP steam is used for regenerator heat.

5.4.2.6.3.5. T&S Config





cooling.









Storage: Ionic Liquid CO2 Capture: T&S Config











107.



page 90.

5.4.2.6.3.7. O&M Cost



• Ionic Liquid Cost: This is the cost in $/ton for ionic liquid.

• Waste Disposal Cost: Solid waste disposal cost, includes spent sorbent.




Storage: Ionic Liquid CO2 Capture: O&M Cost








• Absorbers: The IL-based absorbers use chemical absorption to capture CO2.

• Solvent Circulation Pumps: The CO2-lean solvent is pumped back to the absorber

operating pressure by a solvent circulation pump.

• Absorption Intercoolers: Intercoolers are used to bring the ionic liquid temperature

back down to the absorption operating temperature.

• Lean Solvent Coolers: Gases from the slump tank are recycled back into the

absorber. A compressor is used to compress the gases to the operating pressure of the

absorber.

• Solvent Regenerators: Thermal energy is used to regenerate the solvent.

• Rich & Lean Solvent Heat Exchangers: The CO2-rich solvent must be heated in

order to strip off CO2 and regenerate the solvent. In addition, the regenerated solvent

must be cooled down before it can be recirculated back to the absorber column. Heat

exchangers are used to accomplish these two tasks. This area is a function of the

solvent flow rate.

• Reboilers: The regenerator is connected to a reboiler, which is a heat exchanger that

utilizes low pressure steam to heat the loaded solvent. The reboiler is part of the

solvent regeneration cycle.

• Solvent Reclaimers: A portion of the sorbent stream is distilled in the reclaimer in



Storage: Ionic Liquid CO2 Capture: Retrofit or Adjustment Factors


to recover some of the solvent in this vessel. The reclaimer cost is a function of the

solvent makeup flow rate.

• Solvent Processing: The sorbent processing area primarily consists of a sorbent

cooler, solvent storage tank, and a mixer. The regenerated sorbent is further cooled

with the sorbent cooler and solvent added to make up for sorbent losses. This area is a




• CO2 Product Compressors: The product CO2 must be separated from the water




CO2 flow rate.

• Syngas Heat Exchangers: Heat exchangers are used to cool down inlet syngas when

the absorption temperature is less than the inlet syngas temperature.

• CO2 Product Coolers: Heat exchangers are used to cool down CO2 product stream

when the compression temperature is less than the CO2 product stream temperature.

5.4.2.6.4. Selexol CO2 Capture

IGCC systems use less energy-intensive physical absorption processes to capture CO2 than post-

combustion chemical absorption processes required by the Combustion (Boiler) or Combustion

(Turbine) plant types. Physical absorption using Selexol solvent is currently the most effective

technique for removing CO2 from IGCC fuel gases. The CO2 capture using Selexol is described

in the following section.


5.4.2.6.4.1. Selexol CO2 Capture Diagram

This diagram gives an overview of the Selexol CO2 capture system. This diagram does not




• Carbon Dioxide Removal Unit

◦ CO2 Removal Efficiency: CO2 removal is specified by the user and is used to

determine the solvent makeup flow, capital cost, and operating and maintenance

costs.


Storage: Selexol CO2 Capture: Selexol CO2 Capture: Diagram


Storage: Selexol CO2 Capture: Performance


◦ H2S Removal Efficiency: H2S is naturally removed with CO2. This parameter

specifies the amount that is captured.

◦ Max Syngas Capacity per Train: Each train contains one absorber vessel that

has a maximum flow rate. This parameter determines the maximum flow rate

through the vessel.

◦ Number of Operating Absorbers: This is the total number of operating absorber

vessels. The calculated value is determined by comparing the total flow rate of

syngas through the Selexol process and the maximum syngas capacity per train.

The value must be an integer.

◦ Number of Spare Absorbers: This is the total number of spare absorber vessels.

It is used primarily to calculate capital costs.

◦ CO2 Product Compressor Used?: This determines whether a CO2 product

compressor will be used.

◦ Power Requirement: This is the electricity used by the Selexol CO2 Capture

System for internal use. It is expressed as a percent of the gross plant capacity.

5.4.2.6.4.3. T&S Config





cooling.










Storage: Selexol CO2 Capture: T&S Config











107.



page 90.

5.4.2.6.4.5. O&M Cost



• Bulk Reagent Storage Time: This is the reagent stored at the plant.

• Glycol Cost: This is the cost in $/ton for glycol that is used by the Selexol CO2

capture system.

• Waste Disposal Cost: This is the cost of disposing the water that is used in the

Selexol CO2 capture process.


Storage: Selexol CO2 Capture: O&M Cost




◦ CO2 Transportation Cost: This is the cost of moving the CO2 (i.e., pipeline,

truck) to the place where it will be sequestered.





• Absorbers: The Selexol absorbers use physical absorption to capture CO2. Because

the solubility of CO2 in the solvent is proportional to its partial pressure in the gas

phase, the performance of the absorbers increases with increasing CO2 partial

pressures.

• Power Recovery Turbines: The CO2-rich solvent from the absorber is fed into a set

of hydraulic power recovery turbines to recover some of the pressure energy before it

is fed into the slump tanks.

• Slump Tanks: A slight pressure drop in the slump tanks releases a majority of H2 and

CH4 and a small amount of CO2. This process area enriches the CO2 concentration.

• Recycle Compressors: Gases from the slump tank are recycled back into the


absorber.

• Flash Tanks: CO2 is released in multiple stages by reducing the pressure in

successive flash tanks. Three flash tanks are typically used in a single train. The

staging process reduces the power of CO2 compression later.

• Selexol Pumps: The CO2-lean solvent is pumped back to the absorber operating

pressure by a Selexol circulation pump.

• Refrigeration: CO2-lean solvent must be cooled to the absorber operating

temperature before being returned to the absorber vessel. A refrigeration unit is used

to reduce the temperature of the solvent.


Storage: Selexol CO2 Capture: Retrofit or Adjustment Factors


• CO2 Compressors: CO2 released from the first two flash tanks is compressed to the

flashing pressure of the first flash tank. The two CO2 streams are then combined and

sent to the final product compressors.

• Final Product Compressors: The product CO2 must be separated from the water




CO2 flow rate.

• Heat Exchangers: This process area considers miscellaneous heat exchangers used in

the overall process.


See "5.2.2.8.10. Pipeline Transport" on page 244 for a description of the pipeline transport

parameter screens.


See "5.2.2.8.12. User-Specified Transport" on page 248 for a description of the user-specified

transport parameters.





the combustor, the steam turbine, and the heat recovery steam generator. These are all available in

the Combustion (Turbine) and IGCC plant types.

See "5.3.2.3. Power Block" on page 428 for a description of the power block input screens.



5.4.3. GET RESULTS



5.4.3.1.1. Diagram

This is the same diagram that appears in the "SET PARAMETERS" program area. It is described

in "5.4.2.1.1. Diagram" on page 449.



This screen displays performance results for the plant as a whole. Heat rates and power in and out

of the power plant are given:

The performance parameters in the table on the left are described in "5.1.4.2. Plant Performance"

on page 105.




Configure Plant section of the model. The following results are displayed:

• Total Generator Output: This is the gross power generated by the turbine.

• Air Compressor Use: The power required to operate the air compressor.

• Turbine Shaft Losses: This variable accounts for any turbine electricity losses that are

not incorporated into the losses due to air compressor use.

• Gross Plant Output: This is the net power generated by the turbine. This is the gross

output of the turbine minus the power required by the air compressor and any

miscellaneous losses.

• Misc. Power Block Use: This is the electrical power required to operate pumps and

motors associated with the power block area.

• Air Separation Unit Use: This is the power utilization of the compressors in the air

separation system.

• Gasifier Use: This is the power utilization of the gasification system.

• Sulfur Capture Use: This is the power utilization of the sulfur capture system (this does

not include the Claus or Beavon-Stretford systems).

• Claus Plant Use: This is the power utilization of the Claus plant equipment.

• Beavon Stretford Use: This is the power utilization of the Beavon-Stretford system.

Illustration 538: IGCC: GET RESULTS: Overall Plant: Plant Performance







Also included are credits from steam generated and reused to produce electricity.

• IL Steam Use (Elec. Equiv.): (Only shown when the Ionic Liquid CO2 capture system

is in use.) This is the electrical equivalent energy for the regeneration steam required by

the Ionic Liquid CO2 capture system. It is taken from the steam cycle.


This screen is described in "5.1.4.1. Mass In/Out" on page 104.

5.4.3.1.4. Gas Emissions

See "5.1.3.1. Flue Gas Components" on page 101 for a description of the Stack Gas Components

in the table in the left. The table on the right contains the following:

• Total SOx (equivalent SO2): Total mass of SOx as equivalent SO2.

• Total NOx (equivalent NO2): Total mass of NOx as equivalent NO2.

Illustration 539: IGCC: GET RESULTS: Overall Plant: Gas Emissions









Illustration 540: IGCC: GET RESULTS: Overall Plant: Total Capital Cost

Illustration 541: IGCC: GET RESULTS: Overall Plant: Overall Plant Cost


This screen displays a table which totals the annual fixed, variable, operations, maintenance, and

capital costs associated with the power plant as a whole. Each technology (row) is described

briefly below:

• Air Separation Unit: This is the capital cost for the Air Separation process area of the

plant.

• Gasifier Area: This is the capital cost for the equipment in the gasifier process area of

the plant.

• Particulate Control: This is the capital cost for the equipment that performs particulate

capture in the plant.

• Sulfur Control: This is the capital cost for the equipment that performs sulfur capture in

the plant.

• CO2 Capture, Transport & Storage: This is the capital cost for the equipment that

performs CO2 capture, transport and storage in the plant.

• Power Block: This is the capital cost for the power block process area of the plant.

• Post-Combustion NOx Control: This is the capital cost for the equipment that captures

post-combustion NOx in the plant.

• Subtotal: This is the cost of the conventional and advanced abatement technology

modules alone. This is the total abatement cost. The subtotal is highlighted in yellow.

• Cooling Tower: This is the cost of the cooling tower modules.

• Land: This is the total cost of land required for the plant.

• Emission Taxes: This is the sum of the user assessed taxes on the plant emissions of

SO2, NOx and CO2.

• Total: This is the total cost of the entire power plant. This result is highlighted in yellow.




Illustration 542: IGCC: GET RESULTS: Overall Plant: Cost Summary






The cost categories (columns) are described in "5.1.1.7. Total Cost Results" on page 99.

5.4.3.2. Fuel

This section displays the composition and cost of the fuels used in the plant. The integrated

gasification combined cycle (IGCC) plant configurations assume coal gasification to produce a

synthetic fuel gas. The coal properties must be chosen from a predetermined set of coals.

This section is shared with the other plant types and is described in "5.2.3.2. Fuel" on page 280.

5.4.3.3. Air Separation Unit

This chapter illustrates the results of the air separation technology. It is primarily used in IGCC

plants, although oxyfuel systems in PC plants use it as well.

5.4.3.3.1. Diagram

This screen displays an icon for the Air Separation Unit and values for major flows in and out of

it:


• Atmospheric Air

◦ Temperature In: Temperature of the atmospheric air entering the air separation

unit.

◦ Air In: Mass flow rate of air entering the air separation unit, based on the


◦ Air In: Volumetric flow rate of air entering the air separation unit, based on the


Illustration 543: IGCC: GET RESULTS: Air Separation Unit: Diagram


• Nitrogen

◦ Nitrogen Out: Mass flow rate of the nitrogen exiting the Air Separation Unit.

◦ Nitrogen Out: Volumetric flow rate of the nitrogen exiting the Air Separation Unit.

• Oxidant

◦ Temperature Out: Temperature of the oxidant exiting the Air Separation Unit.

◦ Oxidant Out: Mass flow rate of the oxidant exiting the Air Separation Unit.

◦ Oxidant Out: Volumetric flow rate of the oxidant exiting the Air Separation Unit.

• Water

◦ Water Out: This is the amount of water precipitated out of the main air compressor.

5.4.3.3.2. Gas Flow

See "5.1.3.1. Flue Gas Components" on page 101 for a description of the Major Gas Components.


Illustration 544: IGCC: GET RESULTS: Air Separation Unit: Gas Flow



This is a capital cost result screen ad described in "5.1.1.2. Capital Cost Results" on page 93. It

includes the following process area costs:

• Air Separation Unit: The cost of oxygen plants depends mostly on the oxygen feed rate

to the gasifier, because size and cost of compressors and air separation systems are

proportional to this flow rate. The number of trains is determined based on the total mass

flow rate of oxygen. The minimum number of operating trains is two.

• Final Oxidant Compression: The final oxidant may need to be compressed to a higher

pressure than 20psia. This typically applies to IGCC plants.

Illustration 545: IGCC: GET RESULTS: Air Separation Unit: Capital Cost


5.4.3.3.4. O&M Cost

This is an O&M cost result screen as described in "5.1.1.6. O&M Cost Results" on page 98. It

includes the following variable cost component:

• Electricity: The cost of electricity consumed by the Air Separation System.



5.4.3.4. Gasifier Area

This gasifier chapter describes the coal gasification equipment used in the IGCC plant types.

Illustration 546: IGCC: GET RESULTS: Air Separation Unit: O&M Cost

Illustration 547: IGCC: GET RESULTS: Air Separation Unit: Total Cost


5.4.3.4.1. GE

GE gasification is a form of entrained flow gasification in which coal is fed to the gasifier in a

water slurry. A quench cooling system is used in all cases.

5.4.3.4.1.1. Diagram

The Gasifier Diagram result screen displays an icon for the Gasifier Unit and values for major

flows in and out of it. Each result is described briefly below in flow order:

• Cold Gas Eff.: This is the ratio of the heat contents calculated at room temperature of

the syngas fuel output and the coal fuel input. The higher heating value is used here.

• Temperature In: This is the temperature of the oxidant stream into the gasifier.

• Oxidant In: This is the mass flow of oxidant into the gasifier.

• Water In: This is additional mass flow of water added to the coal. (Wet coal already

contains some water).

• Coal In: This is the mass flow of coal into the gasifier on a wet-basis.

• Sluice Water: Slag collected can be removed from the gasifier and disposed by

sluicing the slag with water.

• Temperature Out: This is the syngas temperature exiting the raw gas quench.

• Pressure Out: This is the approximate pressure of the syngas exiting the raw gas

quench.

• Syngas Out: This is the mass flow rate of syngas exiting the gasification but prior to

the raw gas quench process.

• Syngas Out: This is the volumetric flow rate of syngas exiting the gasification but

prior to the raw gas quench process.

• Wet Slag: Slag collected is removed from the gasifier. Sluice water may or may not

be used to facilitate its transportation. This is the total slag flow rate leaving the

gasifier on a wet basis.

Illustration 548: IGCC: GET RESULTS: Gasifier Area: GE: Diagram


5.4.3.4.1.2. Oxidant

See "5.1.3.1. Flue Gas Components" on page 101 for a description of the Major Oxidant

Components.

Illustration 549: IGCC: GET RESULTS: Gasifier Area: GE:

Oxidant


5.4.3.4.1.3. Syngas


Components.

Illustration 550: IGCC: GET RESULTS: Gasifier Area: GE:

Syngas




The following process areas are shown:

• Coal Handling: This is the cost associated with the coal handling process area. Coal

handling involves unloading coal from a train, storing the coal, moving the coal to the

grinding mills, and feeding the gasifier with positive displacement pumps. A typical

coal handling section contains one operating train and no spare train. A train consists

of a bottom dump railroad car unloading hopper, vibrating feeders, conveyors, belt

scale, magnetic separator, sampling system, deal coal storage, stacker, reclaimer, as

well as some type of dust suppression system. Slurry preparation trains typically have

one to five operating trains with one spare train. The typical train consists of vibrating

feeders, conveyors, belt scale, rod mills, storage tanks, and positive displacement

pimps to feed the gasifiers. All of the equipment for both the coal handling and the

slurry feed are commercially available. The direct cost model for the coal handling is

based upon the overall flow to the plant rather than on a per train basis.

• Gasifier Area: The GE gasification section of an IGCC plant contains gasifier, gas

cooling, slag handling, and ash handling sections. For IGCC plants of 400 MW to

1100 MW, typically 4 to 8 operating gasification trains are used along with one spare

train.

• Low Temperature Gas Cooling: This is the cost associated with the Low

Temperature Gas Cooling process area. The low temperature gas cooling section

includes a series of three shell and tube exchangers. The number of operating trains

are estimated based on the total syngas mass flow rate and the range of syngas flow

rates per train used.

• Process Condensate Treatment: The treated process condensate is used as make-up

to the gas scrubbing unit, and because blowdown from the gas scrubbing unit is the

larger of the flow streams entering the process condensate treatment section, it is

expected that process condensate treatment cost will depend primarily on the scrubber

blowdown flow rate.

Illustration 551: IGCC: GET RESULTS: Gasifier Area: GE: Capital Cost


5.4.3.4.1.5. O&M Cost



• Coal: This is the annual cost of the coal used by the gasifier.

• Oil: This is the annual cost of the oil consumed by the gasifier.

• Other Fuels: This is the annual cost of any other fuels used by the gasifier.

• Misc. Chemicals: This is the annual cost of the miscellaneous chemicals used by the

gasifier.

• Electricity: The cost of electricity consumed by the processes in the gasifier area.

• Water: This is the annual cost of the water used by the gasifier.

• Slag Disposal: This is the solid disposal cost per year for the GE entrained-flow

reactor.

5.4.3.4.1.6. Total Cost

Illustration 552: IGCC: GET RESULTS: Gasifier Area: GE: O&M Cost

Illustration 553: IGCC: GET RESULTS: Gasifier Area: GE: Total Cost



99.

5.4.3.4.2. Shell

The shell gasification system is a dry-feed entrained flow gasification technology. Radiant syngas

cooling is used for non-capture cases and a quench cooling system is used for capture cases.

5.4.3.4.2.1. Diagram

The Gasifier Diagram result screen displays an icon for the Gasifier Unit and values for major

flows in and out of it. Each result is described briefly below in flow order:

• Cold Gas Eff.: This is the ratio of the heat contents calculated at room temperature of

the syngas fuel output and the coal fuel input. The higher heating value is used here.

• Temperature In: This is the temperature of the oxidant stream into the gasifier.

• Oxidant In: This is the mass flow of oxidant into the gasifier.

• Steam In: This is the flow rate of steam used for the coal slurry into the Shell

entrained-flow gasifier.

• Dried Coal In: This is the flow rate of dry coal into the Shell entrained-flow gasifier.

The coal flow rate is on a wet basis.

• Wet Coal: This is the flow rate of wet coal entering the coal dryer.

• Sluice Water: Slag collected can be removed from the gasifier and disposed by

sluicing the slag with water.

• Temperature Out: This is the syngas temperature exiting the Shell entrained-flow

gasifier.

• Pressure Out: This is the approximate pressure of the syngas exiting the Shell

entrained-flow gasifier.

• Syngas Out: This is the mass flow rate of syngas exiting the Shell entrained-flow

gasifier.

Illustration 554: IGCC: GET RESULTS: Gasifier Area: Shell: Diagram


• Syngas Out: This is the volumetric flow rate of syngas exiting the Shell entrained-

flow gasifier.

• Wet Slag: Slag collected is removed from the gasifier. Sluice water may or may not

be used to facilitate its transportation. This is the total slag flow rate leaving the

gasifier on a wet basis.

5.4.3.4.2.2. Oxidant

See "5.1.3.1. Flue Gas Components" on page 101 for a description of the Major Oxidant

Components.

Illustration 555: IGCC: GET RESULTS: Gasifier Area:

Shell: Oxidant


5.4.3.4.2.3. Syngas


Components.

Illustration 556: IGCC: GET RESULTS: Gasifier Area:

Shell: Syngas




The following process areas are shown:

• Coal Handling: This is the cost associated with the coal handling process area. Coal

handling involves unloading coal from a train, storing the coal, moving the coal to the

grinding mills, and feeding the gasifier with positive displacement pumps. A typical

coal handling section contains one operating train and no spare train. A train consists

of a bottom dump railroad car unloading hopper, vibrating feeders, conveyors, belt

scale, magnetic separator, sampling system, deal coal storage, stacker, reclaimer, as

well as some type of dust suppression system. Slurry preparation trains typically have

one to five operating trains with one spare train. The typical train consists of vibrating

feeders, conveyors, belt scale, rod mills, storage tanks, and positive displacement

pimps to feed the gasifiers. All of the equipment for both the coal handling and the

slurry feed are commercially available. The direct cost model for the coal handling is

based upon the overall flow to the plant rather than on a per train basis.

• Gasifier Area: The Shell gasification section of an IGCC plant contains gasifier, gas

cooling, slag handling, and ash handling sections. For IGCC plants of 400 MW to

1100 MW, typically 4 to 8 operating gasification trains are used along with one spare

train.

• Low Temperature Gas Cooling: This is the cost associated with the Low

Temperature Gas Cooling process area. The low temperature gas cooling section

includes a series of three shell and tube exchangers. The number of operating trains

are estimated based on the total syngas mass flow rate and the range of syngas flow

rates per train used.

• Process Condensate Treatment: The treated process condensate is used as make-up

to the gas scrubbing unit, and because blowdown from the gas scrubbing unit is the

larger of the flow streams entering the process condensate treatment section, it is

expected that process condensate treatment cost will depend primarily on the scrubber

blowdown flow rate.

• Activated Carbon Injection: Activated carbon is used to remove mercury.

Illustration 557: IGCC: GET RESULTS: Gasifier Area: Shell: Capital Cost


5.4.3.4.2.5. O&M Cost



• Coal: This is the annual cost of the coal used by the gasifier.

• Oil: This is the annual cost of the oil consumed by the gasifier.

• Other Fuels: This is the annual cost of any other fuels used by the gasifier.

• Miscellaneous Chemicals: This is the annual cost of the miscellaneous chemicals

used by the gasifier.

• Electricity: The cost of electricity consumed by the processes in the gasifier area.

• Water: This is the annual cost of the water used by the gasifier.

• Slag Disposal: This is the solid disposal cost per year for the GE entrained-flow

reactor.

5.4.3.4.2.6. Total Cost

Illustration 558: IGCC: GET RESULTS: Gasifier Area: Shell: O&M Cost

Illustration 559: IGCC: GET RESULTS: Gasifier Area: Shell: Total Cost



99.

5.4.3.5. Sulfur Removal

5.4.3.5.1. Sulfur Capture System (Selexol)

SO2 emissions from IGCC systems are controlled by removing sulfur species from the syngas

prior to combustion in the gas turbine. The syngas is assumed to be scrubbed of particulates

prior to entering the sulfur removal system and is further cooled to 101°F prior to entering a

Selexol acid gas separation unit. H2S and COS are removed from the syngas in the Selexol unit

and sent to a Claus plant and a Beavon-Stretford tail gas treatment unit for sulfur recovery. The

sulfur recovered can be sold as a by-product and credited to the sulfur removal technology

area.

5.4.3.5.1.1. Diagram

This screen displays an icon for the Sulfur Removal Unit (Selexol), the Claus Plant, the

Beavon Stretford Plant and values for major flows in and out of it:

Each result shown on the Sulfur Removal Diagram is described briefly below in flow order:

• Temperature In: Temperature of the syngas entering the Selexol-based sulfur

removal unit.

• Pressure In: Pressure of the syngas entering the Selexol-based sulfur removal unit.

• Syngas In: Flow rate of the syngas entering the Selexol-based sulfur removal unit.

• Makeup Solvent: This is the Selexol solvent makeup rate into the sulfur removal unit

expressed on a continuous basis.

• Makeup Catalyst: This is the catalyst makeup rate for the Claus plant expressed on a

continuous basis.

• Temperature Out: Temperature of the syngas exiting the Selexol-based sulfur

removal unit.

Illustration 560: IGCC: GET RESULTS: Sulfur Removal: Sulfur Capture

System (Selexol): Diagram


• Pressure Out: Pressure of the syngas exiting the Selexol-based sulfur removal unit.

• Syngas Out: Flow rate of the syngas exiting the Selexol-based sulfur removal unit.

• Makeup Catalyst: This is the catalyst makeup rate for the Beavon-Stretford plant


• Sulfur Out: Flow rate of the elemental sulfur collected in both the Claus and Beavon-

Stretford plants.

• Flue Gas Out: The exhaust gas from the Beavon-Stretford plant is completely burned

and sent to a stack. This is the flow rate of combusted exhaust gases.



The following process area costs are displayed:

• Sulfur Removal System - Hydrolyzer: This is the capital cost for the hydrolyzer

system, which converts carbonyl sulfide to hydrogen sulfide.

• Sulfur Removal System - Selexol: H2S in the syngas is removed through counter-

current contact with Selexol solvent. The cost of the Selexol section includes the acid

gas absorber, syngas knock-out drum, syngas heat exchanger, flash drum, lean solvent



regenerator reboiler, and pumps and expanders associated with the Selexol process.

• Sulfur Recovery System - Claus: The Claus plant contains a two-stage sulfur


• Tail Gas Clean Up - Beavon-Stretford: The capital cost of a Beavon-Stretford unit





System (Selexol): Capital Cost


5.4.3.5.1.3. O&M Cost



• Makeup Selexol Solvent: This is the annual cost of makeup Selexol.

• Makeup Claus Catalyst: This is the annual cost of makeup catalyst used in the Claus

plant.

• Makeup Beavon-Stretford Catalyst: This is the annual cost of makeup catalyst used

in the Beavon-Stretford plant.

• Sulfur Byproduct Credit: This is the annual profit for sulfur sold on the market.

• Disposal Cost: This is the annual cost of all wastes generated by the sulfur recovery

processes and disposed.

• Selexol Electricity: This is the annual cost of electricity used by the Selexol-based

sulfur capture process area. It is based on the electricity price of the base plant and the

power consumed in the process areas.

• Claus Electricity: This is the annual cost of electricity used by the Claus plant

process area. It is based on the electricity price of the base plant and the power

consumed in the process areas.

• Beavon-Stretford Electricity: This is the annual cost of electricity used by the

Beavon-Stretford process area. It is based on the electricity price of the base plant and

the power consumed in the process areas.


System (Selexol): O&M Cost


5.4.3.5.1.4. Total Cost


99.

5.4.3.5.2. Sulfur Capture System (Sulfinol)

5.4.3.5.2.1. Diagram

This screen displays an icon for the Sulfur Removal Unit (Sulfinol), the Claus Plant, the

Beavon Stretford Plant and values for major flows in and out of it:

Each result shown on the Sulfur Removal Diagram is described briefly below in flow order:

• Temperature In: Temperature of the syngas entering the Sulfinol sulfur removal unit.

• Pressure In: Pressure of the syngas entering the Sulfinol sulfur removal unit.

• Syngas In: Flow rate of the syngas entering the Sulfinol sulfur removal unit.


System (Selexol): Total Cost


System (Sulfinol): Diagram


• Makeup Solvent: This is the solvent makeup rate into the sulfur removal unit


• Makeup Catalyst: This is the catalyst makeup rate for the Claus plant expressed on a

continuous basis.

• Temperature Out: Temperature of the syngas exiting the Sulfinol sulfur removal

unit.

• Pressure Out: Pressure of the syngas exiting the Sulfinol sulfur removal unit.

• Syngas Out: Flow rate of the syngas exiting the Sulfinol sulfur removal unit.

• Makeup Catalyst: This is the catalyst makeup rate for the Beavon-Stretford plant


• Sulfur Out: Flow rate of the elemental sulfur collected in both the Claus and Beavon-

Stretford plants.

• Flue Gas Out: The exhaust gas from the Beavon-Stretford plant is completely burned

and sent to a stack. This is the flow rate of combusted exhaust gases.




• Sulfur Removal System - Hydrolyzer: This is the capital cost for the hydrolyzer

system, which converts carbonyl sulfide to hydrogen sulfide.

• Sulfur Removal System - Sulfinol: H2S in the syngas is removed through counter-

current contact with the solvent. The cost of the Sulfinol section includes the acid gas

absorber, syngas knock-out drum, syngas heat exchanger, flash drum, lean solvent



regenerator reboiler, and pumps and expanders associated with the Sulfinol process.


System (Sulfinol): Capital Cost


• Sulfur Recovery System - Claus: The Claus plant contains a two-stage sulfur


• Tail Gas Clean Up - Beavon-Stretford: The capital cost of a Beavon-Stretford unit




5.4.3.5.2.3. O&M Cost



• Makeup Amine Solvent: This is the annual cost of makeup solvent.

• Makeup Claus Catalyst: This is the annual cost of makeup catalyst used in the Claus

plant.

• Makeup Beavon-Stretford Catalyst: This is the annual cost of makeup catalyst used

in the Beavon-Stretford plant.

• Sulfur Byproduct Credit: This is the annual profit for sulfur sold on the market.

• Disposal Cost: This is the annual cost of all wastes generated by the sulfur recovery

processes and disposed.

• Sulfinol Electricity: This is the annual cost of electricity used by the Sulfinol sulfur

capture process area. It is based on the electricity price of the base plant and the

power consumed in the process areas.

• Claus Electricity: This is the annual cost of electricity used by the Claus plant

process area. It is based on the electricity price of the base plant and the power

consumed in the process areas.

• Beavon-Stretford Electricity: This is the annual cost of electricity used by the

Beavon-Stretford process area. It is based on the electricity price of the base plant and

the power consumed in the process areas.


System (Sulfinol): O&M Cost


5.4.3.5.2.4. Total Cost


99.

5.4.3.5.3. Hydrolyzer

5.4.3.5.3.1. Syngas


Components.


System (Sulfinol): Total Cost

Illustration 568: IGCC: GET RESULTS: Sulfur Removal: Hydrolyzer:

Syngas


5.4.3.5.4. Selexol Sulfur System

5.4.3.5.4.1. Syngas


Components.

Illustration 569: IGCC: GET RESULTS: Sulfur Removal: Selexol Sulfur

System: Syngas


5.4.3.5.5. Sulfinol Sulfur Capture

5.4.3.5.5.1. Syngas


Components.

Illustration 570: IGCC: GET RESULTS: Sulfur Removal: Sulfinol Sulfur

Capture: Syngas


5.4.3.5.6. Claus Plant

5.4.3.5.6.1. Air


Components.

Illustration 571: IGCC: GET RESULTS: Sulfur Removal:

Claus Plant: Air


5.4.3.5.6.2. Treated Gas


Components.

Illustration 572: IGCC: GET RESULTS: Sulfur Removal: Claus Plant:

Treated Gas


5.4.3.5.7. Beavon-Stretford Plant

5.4.3.5.7.1. Treated Gas


Components.


Beavon-Stretford Plant: Treated Gas


5.4.3.5.7.2. Flue Gas

See "5.1.3.1. Flue Gas Components" on page 101 for a description of the Major Gas

Components.


5.4.3.6.1. Chemical Looping

Chemical looping combustion (CLC) is an indirect process in which fuel is combusted without

direct contact with air. Transfer of oxygen between air and fuel takes place with the aid of an

oxygen-carrier (OC). The oxygen-carrier extracts O2 from air in one reactor and then transfers it

to fuel in a subsequent reactor. Since the fuel does not come in direct contact with air, the

products of combustion contain only carbon dioxide (CO2) and water (H2O). A CO2 stream of

very high purity can be obtained by condensing the water vapor.


Beavon-Stretford Plant: Flue Gas


5.4.3.6.1.1. Diagram

This screen displays an icon for the chemical looping CO2 capture unit and values for major

flows in and out of it:


• Air Flow into Air Reactor

◦ Air In: Mass flow rate of air into the air reactor.

◦ Temperature: Temperature of air entering the air reactor.

• Depleted Air Flow out of Air Reactor

◦ Air Out: Mass flow rate of depleted air out of the air reactor.

◦ Temperature: Temperature of depleted air.

• Oxygen Carrier

◦ Oxidized Oxygen Carrier

▪ Oxidized OC: Mass flow rate of oxidized oxygen carrier into the fuel

reactor.

▪ Temperature: Temperature of oxidized oxygen carrier entering the fuel

reactor.

▪ OC Makeup: Mass flow rate of oxygen carrier makeup.

◦ Reduced Oxygen Carrier

▪ Reduced OC: Mass flow rate of reduced oxygen carrier out of the fuel

reactor.

▪ Temperature: Temperature of reduced oxygen carrier leaving the fuel

reactor.

▪ OC Degradation: Oxygen carrier lost to degradation.


Storage: Chemical Looping: Diagram


• Syngas Flow into the Fuel Reactor

◦ Syngas In: Mass flow rate of syngas into the fuel reactor.

◦ Temperature: Temperature of syngas entering the fuel reactor.

• Syngas Flue Gas Flow out of the Fuel Reactor

◦ Flue Gas Out: Mass flow rate of syngas leaving the fuel reactor.

◦ Temperature: Temperature of syngas leaving the fuel reactor.

5.4.3.6.1.2. Air


Components.


Storage: Chemical Looping: Air


5.4.3.6.1.3. Syngas


Components.



Storage: Chemical Looping: Syngas


Storage: Chemical Looping: Capital Cost




• Air Reactor: This area shows the direct capital cost of the air reactor.

• Fuel Reactor: This area shows the direct capital cost of the fuel reactor.

• Cryogenic Purification Unit: This area shows the direct capital cost of the cryogenic

purification unit.

• Solids Handling Equipment: This area shows the direct capital cost of the solids

handling equipment.

5.4.3.6.1.5. O&M Cost

This is an O&M cost result screen ad described in "5.1.1.6. O&M Cost Results" on page 98.


• Oxygen Carrier: The cost of oxygen carrier used in the fuel reactor.

• Electricity: The cost of electricity consumed by the chemical looping system.





This annual cost is based upon the storage option chosen.


Storage: Chemical Looping: O&M Cost


5.4.3.6.1.6. Total Cost


99.

5.4.3.6.1.7. Summary


Storage: Chemical Looping: Total Cost


Storage: Chemical Looping: Summary







penalties).



outages, the calculation is 24 hours * 365 days or 8,760 hours/year.


right.

5.4.3.6.2. Purification Unit

5.4.3.6.2.1. Diagram

The cryogenic purification unit (CPU) purifies and compresses the concentrated CO2 stream.

The flue gas is compressed, dried and then purified using a partial condensation and distillation

process.

This screen displays an icon for the CPU and values for major flows in and out of it:


• Flue Gas In: Flue gas entering the CPU.

• Water Out: Condensed water leaving the compression and drying unit.

• Purge Out: Purge out of the CPU.

• CO2 Product: CO2 product leaving the CPU.

• CO2 Prod. Pressure: CO2 product pressure leaving the CPU.

• CO2 Removal: CPU CO2 capture efficiency.


Storage: Purification Unit: Diagram


5.4.3.6.3. Water Gas Shift Reactor

5.4.3.6.3.1. Diagram

This screen displays an icon for the Water Gas Shift Reactor Unit and values for major flows in

and out of it:


• Steam: This is the flow rate of steam added. The steam reacts with CO to produce H2

and CO2 in the presence of the catalyst in the two reactors.

• Temperature In: Temperature of the syngas entering the high temperature reactor.

• Syngas In: Flow rate of the syngas entering the high temperature reactor.

• Temperature Out: Temperature of the syngas exiting the final heat exchanger.

• Syngas Out: Flow rate of the syngas exiting the final heat exchanger.


Storage: Water Gas Shift Reactor: Diagram


5.4.3.6.3.2. Syngas


Components.



Storage: Water Gas Shift Reactor: Syngas


Storage: Water Gas Shift Reactor: Capital Cost



following process area costs are shown:

• High Temperature Reactor: This area accounts for the high temperature reactor vessel used

for water gas shift. The iron-based catalyst is designed to be effective at high temperatures

(650-1100 °F). The high temperature reactor has a high reaction rate and converts a large

amount of CO into CO2.

• Low Temperature Reactor: This area accounts for the low temperature reactor vessel used

for water gas shift. The copper-based catalyst is designed to be effective at lower temperatures

(450-650 °F). The low temperature reactor has a lower reaction rate, but converts a very high

percentage of the remaining CO into CO2.

• Heat Exchangers: The water gas shift process involves substantial cooling because of the

exothermic reaction. Heat is recovered and temperature control is maintained through heat

exchangers added after each reactor. This process area accounts for the heat exchangers used.

Steam generated in the heat exchangers is sent to the steam cycle.

5.4.3.6.3.4. O&M Cost



• High Temperature Catalyst: This is the replacement cost of the iron-based high

temperature catalyst. The initial cost is not included in this parameter.

• Low Temperature Catalyst: This is the replacement cost of the copper-based low

temperature catalyst. The initial cost is not included.

• Electricity: The cost of electricity consumed by the water gas shift process areas.

• Thermal Power Credit: The credit for thermal power generated from steam provided

by the heat exchangers in the water shift reactor vessels.

• Water: This is total cost of water used to drive the water gas shift reaction.


Storage: Water Gas Shift Reactor: O&M Cost


5.4.3.6.3.5. Total Cost


99.

5.4.3.6.4. Ionic Liquid CO2 Capture

Ionic liquids (ILs) can be used as solvents to capture CO2. The solvent for CO2 capture is

[P2228][2-CNpyr], one of tetraalkylphosphonium 2-cyanopyrrolide ionic liquids (ILs)

synthesized by researchers at the University of Notre Dame. Such ILs can react chemically with

CO2. Thus, the typical absorption and stripping configuration is adopted for pre-combustion CO2

capture using [P2228][2-CNpyr].

5.4.3.6.4.1. Diagram

This screen displays an icon for the Ionic Liquid CO2 capture unit and values for major flows

in and out of it:


Storage: Water Gas Shift Reactor: Total Cost


Storage: Ionic Liquid CO2 Capture: Diagram



• Temperature In: Temperature of the syngas entering the CO2 absorber unit.

• Syngas In: Flow rate of the syngas entering the CO2 absorber unit.

• Pressure In: Pressure of the syngas entering the CO2 absorber unit.

• Ionic Liquid

◦ Recirculation: This is the total flow rate of ionic liquid through the system.

◦ Makeup: Flow rate of ionic liquid added to the regenerator.

• Temperature Out: Temperature of the syngas exiting the CO2 absorber unit.

• Syngas Out: Flow rate of the syngas exiting the CO2 absorber unit.

• Pressure Out: Pressure of the syngas exiting the CO2 absorber unit.

• CO2 Product: Flow rate of the CO2 product exiting the regenerator.

• CO2 Pressure: CO2 product pressure entering the pipeline.

5.4.3.6.4.2. Syngas


Components.


Storage: Ionic Liquid CO2 Capture: Syngas





• Absorbers: The IL-based absorbers use chemical absorption to capture CO2.

• Solvent Circulation Pumps: The CO2-lean solvent is pumped back to the absorber

operating pressure by a solvent circulation pump.

• Absorption Intercoolers: Intercoolers are used to bring the ionic liquid temperature

back down to the absorption operating temperature.

• Lean Solvent Coolers: Gases from the slump tank are recycled back into the


absorber.

• Solvent Regenerators: Thermal energy is used to regenerate the solvent.

• Rich & Lean Solvent Heat Exchangers: The CO2-rich solvent must be heated in

order to strip off CO2 and regenerate the solvent. In addition, the regenerated solvent

must be cooled down before it can be recirculated back to the absorber column. Heat

exchangers are used to accomplish these two tasks. This area is a function of the

solvent flow rate.

• Reboilers: The regenerator is connected to a reboiler, which is a heat exchanger that

utilizes low pressure steam to heat the loaded solvent. The reboiler is part of the

solvent regeneration cycle.

• Solvent Reclaimers: A portion of the sorbent stream is distilled in the reclaimer in


to recover some of the solvent in this vessel. The reclaimer cost is a function of the

solvent makeup flow rate.

• Solvent Processing: The sorbent processing area primarily consists of a sorbent

cooler, solvent storage tank, and a mixer. The regenerated sorbent is further cooled


Storage: Ionic Liquid CO2 Capture: Capital Cost


with the sorbent cooler and solvent added to make up for sorbent losses. This area is a




• CO2 Product Compressors: The product CO2 must be separated from the water




CO2 flow rate.

• Syngas Heat Exchangers: Heat exchangers are used to cool down inlet syngas when

the absorption temperature is less than the inlet syngas temperature.

• CO2 Product Coolers: Heat exchangers are used to cool down CO2 product stream

when the compression temperature is less than the CO2 product stream temperature.

5.4.3.6.4.4. O&M Cost

This is an O&M cost result screen ad described in "5.1.1.6. O&M Cost Results" on page 98.


• Ionic Liquid: This is the annual cost of the makeup solvent.

• Disposal: This is the annual cost of waste disposal for this process. It does not include

the CO2 product stream disposal cost.

• Electricity: The cost of electricity consumed by the CO2 Selexol system.







Storage: Ionic Liquid CO2 Capture: O&M Cost


5.4.3.6.4.5. Total Cost


99.

5.4.3.6.4.6. Summary


Storage: Ionic Liquid CO2 Capture: Total Cost


Storage: Ionic Liquid CO2 Capture: Summary







penalties).



calculation is 24 hours * 365 days or 8,760 hours/year.


right.

5.4.3.6.5. Selexol CO2 Capture

IGCC systems use less energy-intensive physical absorption processes to capture CO2 than post-

combustion chemical absorption processes required by the Combustion (Boiler) or Combustion

(Turbine) plant types. Physical absorption using Selexol solvent is currently the most effective

technique for removing CO2 from IGCC fuel gases. The CO2 capture using Selexol is described

in the following section.

5.4.3.6.5.1. Diagram

This screen displays an icon for the Selexol CO2 capture unit and values for major flows in and

out of it:


• Temperature In: Temperature of the syngas entering the CO2 absorber unit.

• Syngas In: Flow rate of the syngas entering the CO2 absorber unit.

• Pressure In: Pressure of the syngas entering the CO2 absorber unit.

• Solvent Recirc.: This is the total flow rate of Selexol solvent through the system.

• Solvent Makeup: Flow rate of the Selexol solvent added to the regenerator.


Storage: Selexol CO2 Capture: Diagram


• Temperature Out: Temperature of the syngas exiting the CO2 absorber unit.

• Syngas Out: Flow rate of the syngas exiting the CO2 absorber unit.

• Pressure Out: Pressure of the syngas exiting the CO2 absorber unit.

• CO2 Product: Flow rate of the CO2 product exiting the regenerator.

• CO2 Pressure: CO2 product pressure entering the pipeline.

5.4.3.6.5.2. Syngas


Components.


Storage: Selexol CO2 Capture: Syngas





• Absorbers: This is the series of columns where the syngas is made to contact with the

Selexol solvent. Some of the CO2 is absorbed by the CO2-lean solvent at high

pressure in the counter flow absorber. This process area PFC is a function of the

solvent flow rate, the capture CO2 flow rate, and the inlet temperature.

• Power Recovery Turbines: The pressure energy in the CO2-rich solvent is recovered

with one or two hydro turbines. This process area PFC is a function of the turbine

horsepower and the turbine outlet pressure.

• Slump Tanks: H2, CO, and CH4 entrained or absorbed in the solvent is released in the

slump tank and recycled back to the absorber. Because extra Selexol is used in the

absorber, only a small amount of CO2 is released in the slump tank. This process area

PFC is a function of the solvent flow rate.

• Recycle Compressors: The lean solvent is compressed and cooled in preparation for

recycling back into the absorbers. This process area PFC is a function of the

compressor horse power.

• Flash Tanks: Most of the CO2 absorbed by the solvent is recovered through flashing.

The captured CO2 is then ready for transport and sequestration. To reduce the

compression power, three flashing tanks with different pressures are used. There is no

heat demand for solvent regeneration because solvent recovery is possible through

flashing. This process area PFC is a function of the solvent flow rate.

• Selexol Pumps: The lean solvent fed back into the absorber via pumps. This process

area PFC is a function of the pump horse power.

• Refrigeration: The solvent must be cooled down to the absorber operating

temperature (30°F) by refrigeration. This process PFC is a function of the solvent

flow rate and the temperature difference.


Storage: Selexol CO2 Capture: Capital Cost


• CO2 Compressors: The CO2 from the flash tanks is compressed to high pressure

(>1000psia) for storage using a multi-stage, inter-stage cooling compressor. This

process area PFC is a function of the compressor horse power.

• Final Product Compressors: Compressed CO2 from the CO2 compressors must be

further compressed to the final product pressure. This process area PFC is a function

of the compressor horse power.

• Heat Exchangers: Gas-gas heat exchangers are used to extract heat from the syngas.

This process PFC is a function of the heat load of the exchangers and the temperature

difference across them.

5.4.3.6.5.4. O&M Cost



• Glycol: Selexol is a commercially available physical solvent that is a mixture of

dimethyl ether and polyethylene glycol. This is the annual cost of the makeup solvent.

• Disposal: This is the annual cost of waste disposal for this process. It does not include

the CO2 product stream disposal cost.

• Electricity: The cost of electricity consumed by the CO2 Selexol system.







Storage: Selexol CO2 Capture: O&M Cost


5.4.3.6.5.5. Total Cost


99.

5.4.3.6.5.6. Summary


Storage: Selexol CO2 Capture: Total Cost


Storage: Selexol CO2 Capture: Summary







penalties).



calculation is 24 hours * 365 days or 8,760 hours/year.


right.

5.4.3.6.6. CO2 Transport System



configurations. See "5.2.3.8.10. Pipeline Transport" on page 387 for a description of the CO2

Transport System results.





the combustor, the steam turbine, and the heat recovery steam generator. These are all available in

the Combustion (Turbine) and IGCC plant types.

See "5.3.3.3. Power Block" on page 439 for a description of the power block result screens.



5.4.3.9. Stack

See "5.2.3.11. Stack" on page 416 for a description of the stack result screens.

IECM User Documentation: User Manual A Case Study • 548

6. A Case Study

6.1. Introduction This chapter is meant to be used with the IECM Interface installed and running. The case study takes you

to the commonly used screens described in the previous chapter. It is recommended that you:

1. Follow the directions to set up a plant, enter input parameters, and look at results for the sample

plant.

2. Compare the screen shots to the screens you see.

If you have not already done so, you will need to install the IECM software as described in "3. Installing

the IECM" on page 10.

A detailed description of all available screens is found in "5. How to Use the Modules Included With the

IECM" on page 90.

6.2. Start the IECM To start the IECM Interface, click on it in the Start Menu. (For more detailed instructions, see

"4.1.1. Starting the IECM Interface" on page 19.) When the IECM launches, a Splash Screen is displayed:

Illustration 600: The IECM Splash Screen


The Splash Screen will disappear after a few seconds, or you can click on it to dismiss it if you don't want

to wait.

Once the IECM has started, the Main Window displays:

See "4.1.2. The Main Window" on page 20 for more information.

6.3. Create a New Session The first time you use the software, you will have to create a new session. At subsequent startups, you can

create a new session or use a previously saved session. See "4.1.3. Creating and Opening Sessions" on

page 22 for more details.

To create a new session, do one of the following:

• Open the "File" menu (see "4.1.2.1.1. The File Menu" on page 21) and choose "New Session...".

• Click the "New Session" button on the toolbar in either the main window (see "4.1.2.2. The

Main Window Toolbar" on page 22) or a session window (see "4.1.4.2.1. The "New Session"

Button" on page 31).

• Type Ctrl-N.

Once you have activated the "New Session" command, a "New Session" dialog will be displayed:

Choose the "Pulverized Coal (PC)" plant type, and name it "Case Study". The dialog should look like

this:

Illustration 601: The IECM Main Window

Illustration 602: The "New Session" Dialog


Click the "Ok" button to create the session.

Once you have created a session, a session window will display. It contains all the screens used by the

session. The screen should look like this:

See "4.1.4. The Session Window" on page 27 for more details.

The Navigation Panel on the left is used to select which screen will be displayed:

Illustration 603: The "New Session" Dialog: Case Study

Illustration 604: The Session Window


See "4.1.4.4. The Navigation Panel" on page 34 for more information on how the Navigation Panel is

organized and how to use it.

6.4. Configure Session The "Plant Design" screen in the "CONFIGURE SESSION" program area will be the first screen

displayed in the session window. See "4.2. Configuring the Plant" on page 45 for more details.

On this screen, choose "Typical New Plant" from the "Configuration" menu at the top of the screen, and

notice how the menus for individual technologies are updated. (See "2.3. Pull-Down Menus" on page 4

for details on how to use the pull-down menus.)

Next, under "Post-Combustion Controls", set the "Mercury" option to "Carbon Injection". Notice that the

value of the "Configuration" menu at the top changes to "<User Defined>" when you do this.

Detailed descriptions of the settings on this screen are given in "5.2.1.1. Plant Design" on page 107.

The screen should now look like this:

We will accept the model default values for the other screens in "CONFIGURE SESSION". See

"4.2.1.2. The "Plant Location" Screen" on page 50 and "4.2.1.3. The "Unit Systems" Screen" on page 51

for more details on these screens.

Illustration 605: The Navigation Panel

Illustration 606: The Plant Design Screen


You may return to "CONFIGURE SESSION" at any time by clicking on it in the Navigation Panel.

6.5. Set Parameters Click the "SET PARAMETERS" program area in the Navigation Panel. (See "4.1.4.4. The Navigation

Panel" on page 34.) The screen should look like this:

You may return to "SET PARAMETERS" and change the inputs at any time by clicking on it in the

Navigation Panel. (See "4.1.4.4. The Navigation Panel" on page 34.) Information on how to use the

parameter screens is found in "4.3. Setting Parameters" on page 54. Detailed descriptions of all inputs

available in the PC plant are given "5.2.2. SET PARAMETERS" on page 115.

Illustration 607: The "SET PARAMETERS" Program Area


6.5.1. Overall Plant

The first screen in the "SET PARAMETERS" program area is the "Overall Plant Diagram":

This screen displays the plant configuration settings on the left side of the page and a diagram of the

plant as configured at the right of the page. No inputs are entered on this screen.

You can navigate to the other Technologies by clicking on them in the Navigation Panel:

See "4.1.4.4. The Navigation Panel" on page 34 for details on how to use the Navigation Panel.

Illustration 608: SET PARAMETERS: Overall Plant: Diagram

Illustration 609: SET PARAMETERS in the Navigation Panel


6.5.1.1. Performance

Click "Performance", which is the second screen in the "Overall Plant" technology. The screen

should look like this:

The inputs on this screen affect the overall plant, not just one component. A detailed description of

this screen may be found in "5.2.2.1.2. Performance" on page 116.

The capacity factor is highlighted in blue to point out its importance. Select the value in the "Value"

column for "Capacity Factor", change it to 80, and press the return key. (See "4.3.3.1.3. Value" on

page 56 for more information on how to enter inputs.)

The screen should now look like this:

Illustration 610: The Overall Plant Performance Parameter Screen

Illustration 611: 80% Capacity Factor


6.5.2. Fuel

Next, click "Fuel", the second technology in the Navigation Panel. This will open the first screen in the

"Fuel" technology, which in this case is "Coal Properties":

Inputs in the "Fuel" technology define the composition and cost of the fuel(s) used in the plant. The

"Coal Properties" screen in particular defines the composition and cost of the coal. It looks like this:

A detailed description of this screen may be found in "5.2.2.2.1. Coal Properties" on page 126.

6.5.2.1. Choose a Coal

Looking at the second line on the "Coal Properties" screen, we see that the name of the current coal

is "Appalachian Medium Sulfur". We will be using "Illinois #6" for this case study. We will obtain

the properties and cost of "Illinois #6" by retrieving it from the model default coals database, which

is included with the IECM.

Illustration 612: Fuel Parameters in the Navigation Panel

Illustration 613: Coal Properties


At the top of the screen, above the coal rank, name, etc., there is a button covering the entire width

of the screen, labeled "Click here to retrieve a coal from the database." Click that button to bring up

this dialog:

Illustration 614: The Coal Database Lookup Dialog


Looking at the "Coal Selection" section near the top of the dialog, we see that the model default

fuels database, "model_default_fuels.db" is already selected. Choose "Illinois #6" from the "Name:"

menu. (See "2.3. Pull-Down Menus" on page 4.) The dialog should now look like this:

Press the "Ok" button in the upper right corner to import the coal. The IECM will display a dialog to

let you know that the coal was imported successfully:

Illustration 615: The Coal Database Lookup Dialog: Illinois #6

Illustration 616: Coal Imported Successfully


Click the "Ok" button to dismiss this dialog. You should now be back at the "Coal Properties"

parameter screen, which looks like this:

For more information on how to use databases, see "4.3.3.4. The Database Button" on page 67.

6.5.3. Base Plant

Click the "Base Plant" technology, located just below "Fuel", in the Navigation Panel:

Illustration 617: The Coal Properties Parameter Screen: Illinois #6

Illustration 618: SET PARAMETERS: Base Plant


Inputs in this technology define performance and costs directly associated with the power plant,

particularly the boiler. The first screen in this technology, which is shown when you click on it, is the

"Boiler Diagram":

This diagram gives you an overview of the boiler. It does not include results. See "4.3.2. Diagram

Screens" on page 54 for more information about diagrams in the "SET PARAMETERS" program area.

6.5.3.1. Base Plant Performance

Click "Base Plant Performance" under the "Base Plant" technology to go to the "Base Plant

Performance" parameter screen:

Illustration 619: SET PARAMETERS: Base Plant: Boiler Diagram

Illustration 620: SET PARAMETERS: Base Plant: Base Plant Performance


The "Base Plant Performance" parameter screen looks like this:

Inputs for the major flow rates and concentrations of the gas and solids streams are entered on this

screen.

The first seven inputs are highlighted in blue to point out their importance. Detailed descriptions of

all inputs are given in "5.2.2.3.3. Base Plant Performance" on page 132. Descriptions of how to

enter inputs and replace calculated values are given in "4.3.3.1.3. Value" on page 56 and

"4.3.3.1.4. Calc" on page 57, respectively.

When you change an input, the model is run to ensure that calculated inputs are correct. You may

notice a slight delay as this happens.

Enter the following values for the first seven inputs:

• Gross Electrical Output: 600 MW (override calculated value)

• Unit Type: Supercritical (the default value)

• Steam Cycle Heat Rate: 8100 Btu/kWh (override calculated value)

• Boiler Firing Type: Tangential (the default value)

• Boiler Efficiency: this is calculated by the model – do not change it

• Excess Air For Furnace: this is calculated by the model – do not change it

• Leakage Air at Preheater: 10% (override calculated value)

Illustration 621: The Base Plant Performance Parameter Screen


When you are finished, the screen should look like this:

Illustration 622: The Updated Base Plant Performance Parameter Screen


Next, define a triangular distribution for boiler efficiency:

1. Click the "Boiler Efficiency (%)" uncertainty button in the "Unc" column. (See

"4.3.3.1.2. Unc" on page 56.) This will bring up the Uncertainty Editor:

See "4.3.3.3. The Uncertainty Editor" on page 59 for more information on how to use the

Uncertainty Editor.

Illustration 623: The Uncertainty Editor


2. Select "Triangular" from the "Distribution:" drop-down menu. The Uncertainty Editor


Illustration 624: The Uncertainty Editor: Triangular Distribution


3. Assume the boiler efficiency can be 1% higher or lower than the nominal value calculated

by the IECM. This would be represented by entering 0.99, 1.00, and 1.01 in the Min,

Mode, and Max input fields respectively. Notice that these are multiplicative factors. The

nominal or actual values are displayed immediately below the normalized values you

entered.

After you are finished entering the triangular distribution parameters, the screen should

look like this:

4. 4. Click the "Ok" button in the upper right corner to save your changes and close the

Uncertainty Editor.

Notice that a “?” appears inside the uncertainty button. This is a reminder that uncertainty has been

applied to this input parameter:

6.5.4. Other Input Areas and Technologies

Default parameters will be used for all the other input areas for the base plant and other technology

tabs. You may browse these input screens to view the defaults. All input screens available for the PC

plant are described in detail in "5.2.2. SET PARAMETERS" on page 115.

Illustration 625: The Uncertainty Editor: Case Study Triangular

Distribution

Illustration 626: The Boiler Efficiency Unc Button Indicates Uncertainty


6.6. Get Results Click the "GET RESULTS" program area in the Navigation Panel. You may need to scroll down to get to

it. (See "4.1.4.4. The Navigation Panel" on page 34.) The screen should look like this:

You may return to "GET RESULTS" to look at results at any time by clicking on it in the Navigation

Panel. (See "4.1.4.4. The Navigation Panel" on page 34.) Information on how to use the result screens is

found in "4.4. Getting Results" on page 75. Detailed descriptions of all results available in the PC plant

are given in "5.2.3. GET RESULTS" on page 274.

Illustration 627: The "GET RESULTS" Program Area


6.6.1. Overall Plant

The first screen in the "GET RESULTS" program area is the "Overall Plant Diagram":

This screen displays the plant configuration settings on the left side of the page and a diagram of the

plant as configured on the right side of the page. It is the same as the "Overall Plant Diagram" found in

"SET PARAMETERS".

Illustration 628: GET RESULTS: Overall Plant: Diagram


You can navigate to the other Technologies by clicking on them in the Navigation Panel:

See "4.1.4.4. The Navigation Panel" on page 34 for details on how to use the Navigation Panel.

6.6.1.1. Performance Summary

Click "Plant Performance", the second screen under "Overall Plant". It displays performance results

for the plant as a whole. Values for the major input and outputs of the power plant are given. The

screen should look like this:

Illustration 629: GET RESULTS in the Navigation Panel

Illustration 630: GET RESULTS: Overall Plant: Plant Performance


You should notice that the Gross Plant Size is the same as you entered earlier. The other parameters

are calculated by the model as a function of the other input parameters and technologies loaded.

Each result is described in detail in "5.2.3.1.2. Plant Performance" on page 275.

6.6.1.2. Gas In/Out

Click "Gas In/Out", the fifth screen under "Overall Plant". It shows the flow of gas components in,

through, and out of the power plant. The screen should look like this:

Note the scroll bar at the bottom of the screen. This table contains more columns than will fit on the

screen at one time; use the scroll bar to view the rest of the columns.

The total is highlighted in yellow. Each result is described in detail in "5.2.3.1.5. Gas In/Out" on

page 277.

The results above are based on a maximum hourly flow rate which assumes 100% capacity. To see

the annual average values, which takes into consideration the capacity factor you entered earlier, do

the following:

1. Return to the "CONFIGURE SESSION" program area (see "4.1.4.4. The Navigation

Panel" on page 34) and click on the third screen in that area, "Unit Systems". The screen


Illustration 631: GET RESULTS: Overall Plant: Gas In/Out

Illustration 632: CONFIGURE SESSION: Unit Systems


2. Select "Annual Avg." from the "Result Time Period" menu. (See "2.3. Pull-Down Menus"

on page 4.) The screen should now look like this:

3. Return to the "GET RESULTS" program area and click on the "Gas In/Out" screen in the

"Overall Plant" technology. (See "4.1.4.4. The Navigation Panel" on page 34.) The screen


Notice that the values are now in lb-moles/yr instead of lb-moles/hr.

Illustration 633: CONFIGURE SESSION: Unit Systems

Illustration 634: GET RESULTS: Overall Plant: Gas In/Out (Annual Avg.)


6.6.1.3. Cost Summary

Click "Cost Summary", the last screen under "Overall Plant". It displays costs associated with the

power plant as a whole. The screen should look like this:

The cost year is displayed on the right side of the status bar along the bottom edge of the window

(see "4.1.4.3. The Status Bar" on page 33.) Since we didn't change it, the default is used, currently

constant 2016 dollars. You may change this and other related financial parameters on the "SET

PARAMETERS: Overall Plant: Financing" parameter screen (see "5.2.2.1.5. Financing & Cost

Year" on page 120) if needed.

Each result is described in detail in "5.2.3.1.8. Cost Summary" on page 280.

6.6.2. Base Plant

Click the "Base Plant" technology in the "GET RESULTS" program area:

This area contains result screens for flows and costs related to the base plant.

Illustration 635: GET RESULTS: Overall Plant: Cost Summary

Illustration 636: GET RESULTS: Base Plant


The first process type in the "Base Plant" technology, which will be automatically selected when you

click it, is "1. Boiler". (See "4.1.4.4. The Navigation Panel" on page 34.) This area contains result

screens for flows and costs related to the boiler itself.

6.6.2.1. Diagram

The first screen in the "1. Boiler" process type is the boiler diagram. This screen displays an icon for

the Boiler and values for major flows in and out of it.

Since the boiler diagram is the first screen in the "Base Plant" technology, it will be automatically

selected when you click "Base Plant". The screen should look like this:

The flow rates are shown in annual average units (tons/yr) due to the unit change made earlier. Due

to the trace flow rates of mercury, its flow rate is reported in lb/yr.

Each result is described in detail in "5.2.3.3.1.1. Diagram" on page 283.

Illustration 637: GET RESULTS: Base Plant: 1. Boiler: Diagram


6.6.2.2. Capital Cost

Click the third screen in the "1. Boiler" process type, "Capital Cost". This screen displays tables for

the direct and indirect capital costs related to the boiler. The screen looks like this:

The cost year is always shown on the right side of the status bar at the bottom of the window. (See

"4.1.4.3. The Status Bar" on page 33.) You may change this and other related financial parameters

on the "SET PARAMETERS: Overall Plant: Financing" parameter screen if needed.

Totals are highlighted in yellow. Each result is described in detail in "5.2.3.3.1.3. Capital Cost" on

page 284.

Illustration 638: GET RESULTS: Base Plant: 1. Boiler: Capital Cost


6.6.2.3. O&M Cost

Click the fourth screen in the "1. Boiler" process type, "O&M Cost". This screen displays tables for

the variable and fixed O&M costs involved with the Boiler. It looks like this:

As with "Capital Cost", the cost year may be found on the right side of the status bar. Totals are

highlighted in yellow. Each result is described in detail in "5.2.3.3.1.4. O&M Cost" on page 285.

6.7. Graphs On the "GET RESULTS: Base Plant: 1. Boiler: O&M Cost" screen, locate the "Total Variable Costs" line.

This line is toward the middle of the left table and is highlighted in yellow. Right-click this line and

choose "Display a Graph of this Result" from the menu that pops up:

Illustration 639: GET RESULTS: Base Plant: 1. Boiler: O&M Cost

Illustration 640: Total Variable Costs Right-click Menu


Double-click the result value on the Boiler—3. O&M Cost result screen for the Total Variable costs. A

graph of the value will display. The graph should look something like this:

When you first bring up a graph, there may be a short delay as all result samples are calculated. Once all

the samples are calculated, there should be little more than a split-second delay when you choose another

graph. (However, if you change the plant configuration or input values and then return to "GET

RESULTS", the samples will have to be recalculated, causing another delay.)

While all of the values displayed in diagrams and tables are deterministic, some have uncertainty in their

calculation. If there is no uncertainty in the value’s calculation, the graph displays "(No Uncertainty)". If

uncertainty is present, the graph displays a curve of all possible values.

See "4.3.3.6. The Right-Click Menu" on page 74 for information on options (including graphs) available

on the right-click menu for parameters. "4.4.4. The Right-Click Menu" on page 80 gives similar

information for results. Additional options for viewing graphs are also available in the "Uncertainty" tool

in the "ANALYSIS TOOLS" program area as described in "4.5.3. Uncertainty" on page 85.

Illustration 641: Graph of Total Variable Costs (Uncertain)

IECM User Documentation: User Manual Introduction to Uncertainty Analysis • 575

7. Introduction to Uncertainty

Analysis

7.1. Uncertainty Analysis The following section is provided as a means of introducing uncertainty analysis as a tool for model

design and operation. However, you should consult standard statistical and other texts (e.g., Morgan and

Henrion, Uncertainty, Cambridge Press, 1990) to develop a more complete understanding of the subject.

7.2. Introduction Nearly all analyses of energy and environmental control technologies involve uncertainties. The most

common approach to handling uncertainties is either to ignore them or to use simple sensitivity analysis.

In sensitivity analysis, the value of one or a few model input parameters are varied, usually from low to

high values, and the effect on a model output parameter is observed. Meanwhile, all other model

parameters are held at their nominal values. In practical problems with many input variables which may

be uncertain, the combinatorial explosion of possible sensitivity scenarios (e.g., one variable "high,"

another "low," and so on) becomes unmanageable. Furthermore, sensitivity analysis provides no insight

into the likelihood of obtaining any particular result.

A more robust approach is incorporated in the IECM to represent uncertainties in model parameters using

probability distributions. Using probabilistic simulation techniques, uncertainties in any number of model

input parameters can be propagated through the model simultaneously to determine their combined effect

on model outputs. The result of a probabilistic simulation includes both the possible range of values for

model output parameters and information about the likelihood of obtaining various results. You may have

seen probabilistic analysis referred to elsewhere as "range estimating" or "risk assessment."

The development of ranges and probability distributions for model input parameters can be based either

on statistical data analysis and/or engineering judgments. The approaches to developing probability

distributions for model parameters are similar in many ways to the approach you might take to pick a

single "best guess" number for deterministic (point-estimate) analysis, or to select a range of values to use

in sensitivity analysis.

7.3. Philosophy of Uncertainty Analysis The classical approach to probability theory requires that estimates for probability distributions be based

on empirical data. However, in many practical cases, the available data may not be available or relevant

to the problem at hand. Thus, statistical manipulation of data may be an insufficient basis for estimating

uncertainty. Engineering analysis or judgments about the data may be required.


An alternative approach is the "Bayesian" view. It differs in how probability distributions are interpreted.

The probability of an outcome is your "degree of belief" that the outcome will occur, based on all of the

relevant information you currently have about the system. Thus, the probability distribution may be based

on empirical data and/or other considerations, such as your own technically-informed judgments. The

assessment of uncertainties requires thought about all possible outcomes and their likelihood, not just the

"most likely" outcome. The advantage to thinking systematically and critically about uncertainties is the

likelihood of anticipating otherwise overlooked problems, or identifying potential payoffs that might

otherwise be overlooked.

7.4. Types of Uncertain Quantities There are a number of types of uncertainty to consider when developing a probability distribution for a

variable. Some of these are summarized briefly here.

Statistical error is associated with imperfections in measurement techniques. Statistical analysis of test

data is thus one method for developing a representation of uncertainty in a variable.

Empirical measurements also involve systematic error. The mean value of a quantity may not converge to

the "true" mean value because of biases in measurement and procedures. Such biases may arise from

imprecise calibration, faulty reading of meters, and inaccuracies in the assumptions used to infer the

actual quantity of interest from the observed readings of other quantities. Estimating the possible

magnitude of systematic error may involve an element of engineering judgment.

Variability can be represented as a probability distribution. Some quantities are variable over time. For

example, the composition of a coal (or perhaps a sorbent) may vary over time.

Uncertainty may also arise due to lack of actual experience with a process. This type of uncertainty often

cannot be treated statistically, because it requires predictions about something that has yet to be built or

tested. This type of uncertainty can be represented using technical estimates about the range and

likelihood of possible outcomes. These judgments may be based on a theoretical foundation or experience

with analogous systems.

7.5. Encoding Uncertainties as Probability Distributions As indicated in the previous sections, there are two fundamental approaches for encoding uncertainty in

terms of probability distributions. These include statistical estimation techniques and engineering

judgments. A combination of both methods may be appropriate in many practical situations. For example,

a statistical analysis of measured test data for a new emission control technology may be a starting point

for thinking about uncertainties in a hypothetical commercial scale system. You must then consider the

effect that systematic errors, variability, or uncertainties about scaling-up the process might have on

interpreting test results for commercial-scale design applications.

7.5.1. Statistical Techniques

Statistical estimation techniques involve estimating probability distributions from available data. The

fit of data to a particular probability distribution function can be evaluated using various statistical

tests. For example, the cumulative probability distribution of a set of data may be plotted on

"probability" paper. If the data plot as a straight line, then the distribution is normal. Procedures for

fitting probability distribution functions are discussed in many standard texts on probability and are not

reviewed here.

Such procedures can be utilized to obtain distribution functions for many of the power plant

parameters in the IECM when data are available for operating plants. In other cases, especially where

data are limited, expert technical judgments may be necessary to develop appropriate distribution

functions for model parameters. The emphasis of the discussion below is on the situations where

statistical analysis alone may be insufficient.


7.5.2. Judgments about Uncertainties

In making judgments about a probability distribution for a quantity, there are a number of approaches

(heuristics) that people use which psychologists have observed. Some of these can lead to biases in the

probability estimate. Some of the most common are briefly summarized.

7.5.2.1. Availability

The probability experts assign to a particular possible outcome may be linked to the ease

(availability) with which they can recall past instances of the outcome. For example, if tests have

yielded high sorbent utilization, it may be easier to imagine obtaining a high sorbent utilization in

the future than obtaining lower utilization. Thus, one tends to expect experts to be biased toward

outcomes they have recently observed or can easily imagine, as opposed to other possible outcomes

that have not been observed in tests.

7.5.2.2. Representativeness

Representativeness has also been termed the "law of small numbers." People may tend to assume

that the behavior they observe in a small set of data must be representative of the behavior of the

system, which may not be completely characterized until substantially more data are collected.

Thus, one should be cautious in inferring patterns from data with a small number of samples.

7.5.2.3. Anchoring and Adjustment

Anchoring and adjustment involves using a natural starting point as the basis for making

adjustments. For example, an expert might choose to start with a "best guess" value, which

represents perhaps an average or most likely (modal) value, and then make adjustments to the best

guess to achieve "worst" and "best" outcomes as bounds. The "worst" and "best" outcomes may be

intended to represent a 90 percent probability range for the variable. However, the adjustment from

the central "best guess" value to the extreme values is often insufficient, with the result that the

probability distribution is too tight and biased toward the central value. This phenomenon is

overconfidence, because the expert's judgment reflects less uncertainty in the variable than it should.

The "anchor" can be any value, not just a central value. For example, if an expert begins with a

"worst" case value, the entire distribution may be biased toward that value.

7.5.2.4. Motivational Bias

Judgments also may be biased for other reasons. One common concern is motivational bias. This

bias may occur for reasons such as:

• A person may want to influence a decision to go a certain way.

• The person may perceive that they will be evaluated based on the outcome and might tend

to be conservative in their estimates.

• The person may want to suppress uncertainty that they actually believe is present in order

to appear knowledgeable or authoritative.

• The expert has taken a strong stand in the past and does not want to appear to contradict

himself by producing a distribution that lends credence to alternative views.

7.6. Designing an Elicitation Protocol Studies of uncertainty judgment show that the most frequent problem encountered is overconfidence.

Knowledge of how people make judgments about probability distributions can be used to design a

procedure for eliciting these judgments. The appropriate procedure depends on the background of the

expert and the quantity for which the judgment is being elicited. For example, if you have some prior

knowledge about the shape of the distribution for the quantity, then it may be appropriate to ask you to


think about extreme values of the distribution and then to draw the distribution yourself. On the other

hand, if you have little statistical background, it may be more appropriate to ask you a series of questions.

For example, you might be asked the probability of obtaining a value less than or equal to some value x,

and then the question is repeated for a few other values of x. Your judgment can then be graphed by an

elicitor, who would review the results of the elicitation with you to see if you are comfortable with your

answers.

To overcome the typical problem of overconfidence, consider extreme high or low values before asking

about central values of the distribution. In general, experts' judgments about uncertainties tend to improve

when:

• The expert is forced to consider how things could turn out differently than expected (e.g., high

and low extremes).

• The expert is asked to list reasons for obtaining various outcomes.

While the development of expert judgments may be flawed in some respects, it does permit a more robust

analysis of uncertainties in a process when limited data are available. Furthermore, in many ways, the

assessment of probability distributions is qualitatively no different than selecting single "best guess"

values for use in a deterministic estimate. For example, a "best guess" value often represents a judgment

about the single most likely value that one expects to obtain. The "best guess" value may be selected after

considering several possible values. The types of heuristics and biases discussed above may play a similar

role in selecting the value. Thus, even when only a single "best guess" number is used in an analysis, a

seasoned engineer usually has at least a "sense" for "how good that number really is." This may be why

engineers are usually able to make judgments about uncertainties, because they implicitly make these

types of judgments routinely.

7.7. A Non-technical Example To illustrate the process of defining a subjective probability distribution, let's turn to a simple example of

eating lunch in a cafeteria. How long does it take from the time you enter the cafeteria to the time you pay

the cashier? Assume that you enter at 12:05 p.m. on a weekday and that you purchase your entire meal at

the cafeteria. The answer you give may depend on your recent experiences in the cafeteria. Think about

the shortest possible time that it could take (suppose nobody else is getting lunch) or the longest possible

time (everyone shows up at the same time). What is the probability that it will take 2 minutes or less? 45

minutes or less? Is the probability that it takes 10 minutes or less greater than 50 percent? etc. After

asking yourself a number of questions such as these, it should be possible to draw a distribution for your

judgment regarding the time require to obtain and purchase lunch at the cafeteria. Such a distribution

might take the form of a fractile distribution giving the probabilities of different waiting times to purchase

lunch. For example, your evaluation may conclude that there is only a 1 percent (1 in 100) chance it will

take one minute or less, a 60 percent chance of 1 to 10 minutes, a 25 percent likelihood of 10 to 15

minutes, and a 14 percent chance of up to 25 minutes. These probability intervals can be drawn as a

histogram and translated into a fractile distribution for a probabilistic analysis.

7.8. A Technical Example A second example focuses on a performance parameter for an advanced pollution control system. This

parameter has an important effect on system performance and cost.

The example focuses on an assessment of uncertainty in the performance of an innovative emission

control system for coal-fired power plants. In this system, a chemical sorbent circulates between a

fluidized bed reactor, where SO2 in the flue gas is removed by chemical reaction with the sorbent, and a

regenerator, in which SO2 is evolved in a reaction of the sulfated sorbent with methane. There is no

commercial experience with this system; the largest test unit has been sized to handle 100 scfm of flue

gas. Furthermore, the test units have used batch, rather than continuous, regeneration.


One of the key parameters affecting the performance and cost of this system is the regeneration

efficiency, which is defined as the fraction of the spent sorbent which is converted for reuse. In small-

scale tests in which the regeneration efficiency has been estimated, the efficiency was found to be roughly

30 to 50 percent. In a more recent test, the regeneration efficiency was not measured due to

instrumentation difficulties; however, it may have been lower than the previously obtained values.

Regeneration residence times were typically greater than 30 minutes.

A detailed modeling study of the regenerator estimated that a properly sized and designed unit, coupled

with heating of the sorbent to a sufficiently high reaction temperature, would result in a regeneration

efficiency of just over 99 percent at a 30-minute residence time.

A potential problem that may be occurring in the test units is that regenerated sorbent in the regenerator

may be reabsorbing some of the evolved SO2. However, this was not considered in the modeling study of

the regenerator.

Based on this information, it appears that it may be possible to achieve the design target of over 99

percent regeneration efficiency. Clearly, however, it is possible that the actual efficiency may be

substantially less than this target value. As a worst case, we might consider the known test results as a

lower bound. Thus, there is a small chance the regeneration efficiency may be less than 50 percent. We

expect the regeneration efficiency to tend toward the target value of 99.2 percent. Thus, to represent the

expectation that the efficiency will be near the target value, but may be substantially less, we can use a

negatively skewed distribution. In this case, we assume a triangle with a range from, say, 50 to 99.2

percent with a mode also at 99.2 percent. The triangle in this case gives us a distribution with a mean of

about 83 percent and a median of about 85 percent. This type of triangular distribution, in which a

minimum, maximum, and modal value are specified, is often a convenient way of expressing uncertainty

distributions when a little information is available.

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IECM User Documentation: User Manual