Cost and Performance 

Baseline for Fossil Energy 

Plants 

Volume 2: Coal to Synthetic 

Natural Gas and Ammonia

July 5, 2011

DOE/NETL- 2010/1402
Disclaimer

This report was prepared as an account of work sponsored by an agency of the 

United States Government. Neither the United States Government nor any 

agency thereof, nor any of their employees, makes any warranty, express or 

implied, or assumes any legal liability or responsibility for the accuracy, 

completeness, or usefulness of any information, apparatus, product, or process 

disclosed, or represents that its use would not infringe privately owned rights. 

Reference therein to any specific commercial product, process, or service by trade 

name, trademark, manufacturer, or otherwise does not necessarily constitute or 

imply its endorsement, recommendation, or favoring by the United States 

Government or any agency thereof. The views and opinions of authors expressed

therein do not necessarily state or reflect those of the United States Government 

or any agency thereof.
COST AND PERFORMANCE BASELINE FOR

FOSSIL ENERGY PLANTS

VOLUME 2: COAL TO SYNTHETIC NATURAL GAS 

AND AMMONIA

DOE/NETL-2010/1402

Final Report

July 5, 2011

NETL Contact:

Larry Rath

Senior Analyst

Office of Systems, Analyses and Planning

National Energy Technology Laboratory

www.netl.doe.gov
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Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Table of Contents

LIST OF EXHIBITS...................................................................................................................III

PREPARED BY .........................................................................................................................VII

ACKNOWLEDGMENTS.......................................................................................................VIII

LIST OF ACRONYMS AND ABBREVIATIONS..................................................................IX

EXECUTIVE SUMMARY ...........................................................................................................1

CONVERSION EFFICIENCY.............................................................................................................4

TOTAL OVERNIGHT COST .............................................................................................................5

FIRST YEAR COST OF PRODUCTION ...............................................................................................6

FIRST YEAR COST OF CO2 AVOIDED...........................................................................................12

ECONOMIC PATHWAYS ...............................................................................................................13

1. INTRODUCTION................................................................................................................19

2. GENERAL EVALUATION BASIS ...................................................................................21

2.1 SITE CHARACTERISTICS ..................................................................................................21

2.2 PLANT PRODUCTION CAPACITY ......................................................................................22

2.3 COAL CHARACTERISTICS ................................................................................................24

2.4 PRODUCT SPECIFICATIONS..............................................................................................29

2.5 ENVIRONMENTAL TARGETS ............................................................................................30

2.6 CAPACITY FACTOR .........................................................................................................31

2.7 RAW WATER WITHDRAWAL AND CONSUMPTION ...........................................................32

2.8 COST ESTIMATING METHODOLOGY ................................................................................33

2.8.1 Capital Costs .......................................................................................................................................33

2.8.2 Operations and Maintenance Costs.....................................................................................................42

2.8.3 CO2 Transport, Storage, and Monitoring ............................................................................................43

2.8.4 Finance Structure, Discounted Cash Flow Analysis, and First-Year Cost of SNG .............................47

2.8.5 Ammonia Price ....................................................................................................................................50

3. SNG AND SNG AND AMMONIA CO-PRODUCTION FACILITIES .........................55

3.1 MAJOR PROCESS AREAS .................................................................................................55

3.1.1 Coal Receiving and Storage.................................................................................................................55

3.1.2 Coal Drying .........................................................................................................................................56

3.1.3 Air Separation Unit Choice .................................................................................................................58

3.1.4 Gasifier................................................................................................................................................61

3.1.5 Water Gas Shift Reactors.....................................................................................................................62

3.1.6 Mercury Removal.................................................................................................................................63

3.1.7 Acid Gas Removal (AGR) Process Selection .......................................................................................64

3.1.8 Methanation, Synthetic Natural Gas Purification and Compression...................................................66

3.1.9 Pressure Swing Adsorber (Co-Production Cases Only)......................................................................67

3.1.10 Ammonia Synthesis (Co-Production Cases Only)................................................................................67

3.1.11 Zinc Oxide Guard Bed .........................................................................................................................68

3.1.12 Sulfur Recovery/Tail Gas Cleanup Process Selection .........................................................................69

3.1.13 Slag Handling ......................................................................................................................................71

3.1.14 Steam Generation Island .....................................................................................................................72

3.1.15 Accessory Electric Plant......................................................................................................................74

3.1.16 Instrumentation and Control................................................................................................................74

4. BITUMINOUS COAL CASES...........................................................................................77

4.1 SYNTHETIC NATURAL GAS PRODUCTION USING ILLINOIS NO. 6 COAL............................77

4.1.1 Process Description.............................................................................................................................77

4.1.2 Key System Assumptions......................................................................................................................87

4.1.3 Sparing Philosophy..............................................................................................................................89
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4.1.4 Cases 1 and 2 Performance Results.....................................................................................................89

4.1.5 Cases 1 and 2 Equipment Lists..........................................................................................................103

4.1.6 Cases 1 and 2 Cost Estimating ..........................................................................................................118

4.2 SYNTHETIC NATURAL GAS AND AMMONIA CO-PRODUCTION USING ILLINOIS NO. 6 COAL129

4.2.1 Process Description...........................................................................................................................129

4.2.2 Key System Assumptions....................................................................................................................139

4.2.3 Cases 3 and 4 Performance Results...................................................................................................140

4.2.4 Cases 3 and 4 Equipment Lists..........................................................................................................155

4.2.5 Cases 3 and 4 Cost Estimating ..........................................................................................................174

5. LOW RANK COAL CASES.............................................................................................185

5.1 SYNTHETIC NATURAL GAS PRODUCTION USING ROSEBUD PRB COAL........................185

5.1.1 Process Description...........................................................................................................................185

5.1.2 Key System Assumptions....................................................................................................................192

5.1.3 Cases 5 and 6 Performance Results...................................................................................................193

5.1.4 Cases 5 and 6 Equipment Lists..........................................................................................................207

5.1.5 Cases 5 and 6 Cost Estimating ..........................................................................................................223

5.2 SYNTHETIC NATURAL GAS PRODUCTION USING NORTH DAKOTA LIGNITE COAL........234

5.2.1 Process Description...........................................................................................................................234

5.2.2 Key System Assumptions....................................................................................................................241

5.2.3 Cases 7 and 8 Performance Results...................................................................................................242

5.2.4 Cases 7 and 8 Equipment Lists..........................................................................................................256

5.2.5 Cases 7 and 8 Cost Estimating ..........................................................................................................273

6. SUMMARY ........................................................................................................................285

6.1 PERFORMANCE..............................................................................................................285

6.2 ECONOMICS ..................................................................................................................288

6.3 CARBON DIOXIDE EMISSIONS/MITIGATION ..................................................................291

6.4 RAW WATER WITHDRAWAL AND CONSUMPTION.........................................................292

7. REFERENCES...................................................................................................................295
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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List of Exhibits

Exhibit ES-1 Case Descriptions..................................................................................................... 3

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

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

Exhibit ES-4 Total Overnight Cost and Total As-spent Capital..................................................... 7

Exhibit ES-5 Economic Parameters Used to Calculate FYCOP ................................................... 8

Exhibit ES-6 FYCOP by Cost Component.................................................................................... 9

Exhibit ES-7 FYCOP Sensitivity to ROE.................................................................................... 10

Exhibit ES-8 FYCOP Sensitivity to Fuel Costs........................................................................... 11

Exhibit ES-9 FYCOP Sensitivity to Capacity Factor .................................................................. 11

Exhibit ES-10 CO2 Avoided Cost................................................................................................. 12

Exhibit ES-11 Case 2 Economic Pathway with Favorable Financial Structure ........................... 14

Exhibit ES-12 Case 4 Economic Pathway with Favorable Financial Structure ........................... 15

Exhibit ES-13 Case 2 Economic Pathway with Mature Technology ........................................... 16

Exhibit ES-14 Case 4 Economic Pathway with Mature Technology ........................................... 17

Exhibit 2-1 Ambient Conditions.................................................................................................. 21

Exhibit 2-2 Site Characteristics ................................................................................................... 22

Exhibit 2-3 Proposed Capacity for SNG Plants in the United States .......................................... 23

Exhibit 2-4 U.S. Ammonia Plants................................................................................................ 23

Exhibit 2-5 Illinois No. 6 Bituminous, Old Ben Mine................................................................. 26

Exhibit 2-6 Montana Rosebud PRB, Area D, Western Energy Co. Mine ................................... 27

Exhibit 2-7 North Dakota Beulah-Zap Lignite, Freedom, ND Mine........................................... 28

Exhibit 2-8 SNG Pipeline Requirements..................................................................................... 29

Exhibit 2-9 Ammonia Quality Requirements.............................................................................. 30

Exhibit 2-10 Capital Cost Levels and their Elements.................................................................. 33

Exhibit 2-11 Features of an AACE Class 4 Cost Estimate........................................................... 35

Exhibit 2-12 AACE Guidelines for Process Contingency........................................................... 38

Exhibit 2-13 Owner’s Costs Included in TOC............................................................................. 40

Exhibit 2-14 CO2 Pipeline Specification ..................................................................................... 44

Exhibit 2-15 Deep Saline Aquifer Specification ......................................................................... 45

Exhibit 2-16 Global Economic Assumptions .............................................................................. 47

Exhibit 2-17 Financial Structure for High Risk Fuels Projects................................................... 48

Exhibit 2-18 Economic Parameters for FYCOP Calculation ...................................................... 49

Exhibit 2-19 Monthly U.S. Prices of Natural Gas and Ammonia ............................................... 51

Exhibit 2-20 Price Projections for Natural Gas Consumers ........................................................ 52

Exhibit 2-21 Global Ammonia Utilization .................................................................................. 52

Exhibit 2-22 U.S. Farmer Ammonia and Industrial Natural Gas Prices...................................... 53

Exhibit 3-1 WTA Process Schematic .......................................................................................... 58

Exhibit 3-2 Typical ASU Process Schematic .............................................................................. 61

Exhibit 3-3 Haldor Topsoe TREMPTM High Temperature Methanation Process ....................... 66

Exhibit 3-4 Ammonia Synthesis Loop Configuration ................................................................. 68

Exhibit 3-5 Typical Three-Stage Claus Sulfur Plant ................................................................... 70

Exhibit 4-1 Case 1 Block Flow Diagram, Bituminous Coal to SNG without Carbon 

Sequestration......................................................................................................................... 78
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Exhibit 4-2 Case 1 Stream Table, Bituminous Coal to SNG without Carbon Sequestration ...... 79

Exhibit 4-3 Case 2 Block Flow Diagram, Bituminous Coal to SNG with Carbon Sequestration81

Exhibit 4-4 Case 2 Stream Table, Bituminous Coal to SNG with Carbon Sequestration ........... 82

Exhibit 4-5 Cases 1 and 2 Plant Study Configuration Matrix ..................................................... 87

Exhibit 4-6 Balance of Plant Assumptions.................................................................................. 88

Exhibit 4-7 Cases 1 and 2 Plant Performance Summary ............................................................. 90

Exhibit 4-8 Cases 1 and 2 Air Emissions..................................................................................... 91

Exhibit 4-9 Cases 1 and 2 Carbon Balance.................................................................................. 92

Exhibit 4-10 Cases 1 and 2 Sulfur Balance ................................................................................. 93

Exhibit 4-11 Cases 1 and 2 Water Balance.................................................................................. 94

Exhibit 4-12 Case 1 Gasification and ASU Heat and Mass Balance........................................... 96

Exhibit 4-13 Case 1 Gas Cleanup Heat and Mass Balance ......................................................... 97

Exhibit 4-14 Case 1 Methanation and Power Block Heat and Mass Balance ............................. 98

Exhibit 4-15 Case 2 Gasifier and ASU Heat and Mass Balance ................................................. 99

Exhibit 4-16 Case 2 Gas Cleanup Heat and Mass Balance ....................................................... 100

Exhibit 4-17 Case 2 Methanation and Power Block Heat and Mass Balance ........................... 101

Exhibit 4-18 Cases 1 and 2 Energy Balance.............................................................................. 102

Exhibit 4-19 Case 1 Total Plant Cost Details............................................................................ 119

Exhibit 4-20 Case 1 Initial and Annual O&M Costs................................................................. 123

Exhibit 4-21 Case 2 Total Plant Cost Details............................................................................ 124

Exhibit 4-22 Case 2 Initial and Annual O&M Costs................................................................. 128

Exhibit 4-23 Case 3 Block Flow Diagram, Bituminous Coal to SNG and Ammonia without 

Carbon Sequestration .......................................................................................................... 131

Exhibit 4-24 Case 3 Stream Table, Bituminous Coal to SNG and Ammonia without Carbon 

Sequestration....................................................................................................................... 132

Exhibit 4-25 Case 4 Block Flow Diagram, Bituminous Coal to SNG and Ammonia with Carbon 

Sequestration....................................................................................................................... 135

Exhibit 4-26 Case 4 Stream Table, Bituminous Coal to SNG and Ammonia with Carbon 

Sequestration....................................................................................................................... 136

Exhibit 4-27 Cases 3 and 4 Plant Study Configuration Matrix ................................................. 139

Exhibit 4-28 Cases 3 and 4 Plant Performance Summary ......................................................... 141

Exhibit 4-29 Cases 3 and 4 Air Emissions................................................................................. 142

Exhibit 4-30 Cases 3 and 4 Carbon Balance.............................................................................. 143

Exhibit 4-31 Cases 3 and 4 Sulfur Balance ............................................................................... 144

Exhibit 4-32 Cases 3 and 4 Water Balance................................................................................ 145

Exhibit 4-33 Case 3 Gasification and ASU Heat and Mass Balance......................................... 146

Exhibit 4-34 Case 3 Gas Cleanup Heat and Mass Balance ....................................................... 147

Exhibit 4-35 Case 3 Methanation and Power Block Heat and Mass Balance ........................... 148

Exhibit 4-36 Case 3 Ammonia Production Heat and Mass Balance ......................................... 149

Exhibit 4-37 Case 4 Gasification and ASU Heat and Mass Balance......................................... 150

Exhibit 4-38 Case 4 Gas Cleanup Heat and Mass Balance ....................................................... 151

Exhibit 4-39 Case 4 Methanation and Power Block Heat and Mass Balance ........................... 152

Exhibit 4-40 Case 4 Ammonia Production Heat and Mass Balance ......................................... 153

Exhibit 4-41 Cases 3 and 4 Energy Balance.............................................................................. 154

Exhibit 4-42 Case 3 Total Plant Cost Details............................................................................ 175

Exhibit 4-43 Case 3 Initial and Annual O&M Costs................................................................. 179
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Exhibit 4-44 Case 4 Total Plant Cost Details............................................................................ 180

Exhibit 4-45 Case 4 Initial and Annual O&M Costs................................................................. 184

Exhibit 5-1 Case 5 Block Flow Diagram, Subbituminous Rosebud PRB Coal to SNG without 

Carbon Sequestration .......................................................................................................... 186

Exhibit 5-2 Case 5 Stream Table, Subbituminous Rosebud Coal to SNG without Carbon 

Sequestration....................................................................................................................... 187

Exhibit 5-3 Case 6 Block Flow Diagram, Subbituminous Rosebud Coal to SNG with Carbon 

Sequestration....................................................................................................................... 189

Exhibit 5-4 Case 6 Stream Table, Subbituminous Rosebud PRB Coal to SNG with Carbon 

Sequestration....................................................................................................................... 190

Exhibit 5-5 Cases 5 and 6 Plant Study Configuration Matrix ................................................... 192

Exhibit 5-6 Cases 5 and 6 Plant Performance Summary ........................................................... 194

Exhibit 5-7 Cases 5 and 6 Air Emissions................................................................................... 195

Exhibit 5-8 Cases 5 and 6 Carbon Balance................................................................................ 196

Exhibit 5-9 Cases 5 and 6 Sulfur Balance ................................................................................. 197

Exhibit 5-10 Cases 5 and 6 Water Balance................................................................................ 198

Exhibit 5-11 Case 5 Gasification and ASU Heat and Mass Balance......................................... 200

Exhibit 5-12 Case 5 Gas Cleanup Heat and Mass Balance ....................................................... 201

Exhibit 5-13 Case 5 Methanation and Power Block Heat and Mass Balance ........................... 202

Exhibit 5-14 Case 6 Gasification and ASU Heat and Mass Balance......................................... 203

Exhibit 5-15 Case 6 Gas Cleanup Heat and Mass Balance ....................................................... 204

Exhibit 5-16 Case 6 Methanation and Power Block Heat and Mass Balance ........................... 205

Exhibit 5-17 Cases 5 and 6 Energy Balance.............................................................................. 206

Exhibit 5-18 Case 5 Total Plant Cost Details............................................................................ 224

Exhibit 5-19 Case 5 Initial and Annual O&M Costs................................................................. 228

Exhibit 5-20 Case 6 Total Plant Cost Details............................................................................ 229

Exhibit 5-21 Case 6 Initial and Annual O&M Costs................................................................. 233

Exhibit 5-22 Case 7 Block Flow Diagram, North Dakota Lignite Coal to SNG without Carbon 

Sequestration....................................................................................................................... 235

Exhibit 5-23 Case 7 Stream Table, North Dakota Lignite Coal to SNG without Carbon 

Sequestration....................................................................................................................... 236

Exhibit 5-24 Case 8 Block Flow Diagram, North Dakota Lignite to SNG with Carbon 

Sequestration....................................................................................................................... 238

Exhibit 5-25 Case 8 Stream Table, North Dakota Lignite Coal to SNG with Carbon 

Sequestration....................................................................................................................... 239

Exhibit 5-26 Cases 7 and 8 Plant Study Configuration Matrix ................................................. 241

Exhibit 5-27 Cases 7 and 8 Plant Performance Summary ......................................................... 243

Exhibit 5-28 Cases 7 and 8 Air Emissions................................................................................. 244

Exhibit 5-29 Cases 7 and 8 Carbon Balance.............................................................................. 245

Exhibit 5-30 Cases 7 and 8 Sulfur Balance ............................................................................... 246

Exhibit 5-31 Cases 7 and 8 Water Balance................................................................................ 247

Exhibit 5-32 Case 7 Gasification and ASU Heat and Mass Balance......................................... 249

Exhibit 5-33 Case 7 Gas Cleanup Heat and Mass Balance ....................................................... 250

Exhibit 5-34 Case 7 Methanation and Power Block Heat and Mass Balance ........................... 251

Exhibit 5-35 Case 8 Gasification and ASU Heat and Mass Balance......................................... 252

Exhibit 5-36 Case 8 Gas Cleanup Heat and Mass Balance ....................................................... 253
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Exhibit 5-37 Case 8 Methanation and Power Block Heat and Mass Balance ........................... 254

Exhibit 5-38 Cases 7 and 8 Energy Balance.............................................................................. 255

Exhibit 5-39 Case 7 Total Plant Cost Details............................................................................ 274

Exhibit 5-40 Case 7 Initial and Annual O&M Costs................................................................. 278

Exhibit 5-41 Case 8 Total Plant Cost Details............................................................................ 279

Exhibit 5-42 Case 8 Initial and Annual O&M Costs................................................................. 283

Exhibit 6-1 Performance, Emissions, and Cost Results............................................................. 286

Exhibit 6-2 Net Plant Conversion Efficiency (HHV)................................................................ 287

Exhibit 6-3 SNG Heating Values............................................................................................... 287

Exhibit 6-4 Total Overnight Cost and Total As-spent Capital .................................................. 289

Exhibit 6-5 First Year Cost of Production ................................................................................. 290

Exhibit 6-6 First Year Cost of Production Components............................................................ 290

Exhibit 6-7 Impact of CO2 Tax on FYCOP............................................................................... 291

Exhibit 6-8 CO2 Emissions Normalized by Thermal Input ....................................................... 292

Exhibit 6-9 Raw Water Withdrawal and Consumption ............................................................. 293
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

vii

PREPARED BY

Research and Development Solutions, LLC (RDS)

:

UPDATED BY

Energy Sector Planning and Analysis (ESPA)

:

Robert D. Brasington

formerly of Parsons Corporation

John L. Haslbeck

Booz Allen Hamilton

Norma J. Kuehn

Booz Allen Hamilton

Eric G. Lewis

Booz Allen Hamilton

Lora L. Pinkerton

WorleyParsons Group, Inc.

Marc Turner

Booz Allen Hamilton

Elsy Varghese

WorleyParsons Group Inc.

Mark Woods

Booz Allen Hamilton

DOE Contract # DE-FE0004001
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

viii

Acknowledgments

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

United States Department of Energy’s (DOE) National Energy Technology Laboratory (NETL) 

under DOE NETL Contract Number DE-AM26-04NT41817; Subtask 41817-401.01.04. The 

report was updated by Booz Allen Hamilton Inc. under DOE NETL Contract Number DEFE0004001, Energy Sector Planning and Analysis.

The authors wish to acknowledge the excellent guidance, contributions, and cooperation of the 

NETL staff and other past contributors, particularly:

Larry Rath, Director of Performance Division of the Office of Program Planning, and Analysis

The authors also wish to acknowledge the valuable input to this study provided by Siemens 

Energy, Inc, and Leucadia Energy, LLC. However, participation by outside parties is not an 

endorsement of any technology or project nor does it imply that the outside party certifies or 

endorses the results of the work.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

ix

AACE Association for the Advancement of Cost Engineering

LIST OF ACRONYMS AND ABBREVIATIONS

AEO Annual Energy Outlook

AF Availability factor

AFUDC Allowance for funds used during construction

AGR Acid gas removal

Aspen AspenPlus®

ASU Air separation unit

BEC Bare erected cost

BFD Block flow diagram

BFP Boiler feed pump

BFW Boiler feedwater

Btu British thermal unit

Bscf Billion standard cubic foot

Btu/lb British thermal unit per pound

Btu/scf British thermal unit per standard cubic foot

C4+ Butane + higher paraffins

CCF Capital Charge Factor

CCPI Clean Coal Power Initiative

CCS Carbon capture and sequestration

CFBC Circulating fluidized bed combustor 

cfm Cubic feet per minute

CL Closed-loop

cm Centimeter

CO Carbon monoxide

CO2 Carbon dioxide

CoP Conoco Phillips

COP Cost of production

COS Carbonyl sulfide

CRT Cathode ray tube

CS Carbon steel

CS2 Carbon disulfide

CT Combustion turbine

CWP Circulating water pump

CWS Circulating water system

CWT Cold water temperature

DCS Distributed control system

DI De-ionized

DOE Department of Energy

EIA Energy Information Administration

EM Electromagnetic

EOR Enhanced oil recovery

EPA Environmental Protection Agency
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EPC Engineer/Procure/Construct

EPRI Electric Power Research Institute

EPCM Engineering/Procurement/Construction Management

FBG Fluidized bed gasifier

FEED Front-End Engineering Design

ESPA Energy Sector Planning and Analysis

FERC Federal Energy Regulatory Commission

FGT Florida gas transmission

FOAK First-of-a-kind

ft Foot, Feet

FW Feedwater

FYCOP First year cost of production

gal Gallon

GDP Gross domestic product

GEE General Electric Energy

GHG Greenhouse gas

GJ/hr Gigajoule per hour

gpm Gallons per minute

GRE Great River Energy

H2 Hydrogen

H2S Hydrogen sulfide

Hg Mercury

HHV Higher heating value

hp Horsepower

HP High-pressure

HVAC Heating, ventilating, and air conditioning

HWT Hot water temperature

Hz Hertz

ICR Information Collection Request

IDGCC Integrated Drying and Gasification Combined Cycle

IGCC Integrated gasification combined cycle

IP Intermediate-pressure

kg/GJ Kilogram per gigajoule

kg/hr Kilogram per hour

kJ/Nm3 Kilojoule per normal cubic meter

kJ/kg Kilojoule per kilogram

km Kilometer

KO Knockout

kV Kilovolt

kW, kWe Kilowatts electric

kWth Kilowatt thermal

lb/hr Pound per hour

lb/MMBtu Pound per million British thermal units
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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LCOP Levelized cost of production

LF Levelization Factor

LNG Liquefied natural gas

LHV Lower heating value

LP Low-pressure

lpm Liters per minute

m Meters

m3/min Cubic meter per minute

md Millidarcy

MMBtu Million British thermal units (also shown as 106 Btu)

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

MMkJ Million kilojoules (also shown as 106 kJ)

MMscf Million standard cubic feet

MNm3 Thousand normal cubic meters

BNm3 Billion normal cubic meters

mol% Mole percent

MPa Megapascal

MVA Mega volt-amp

MW Megawatt

MWh Megawatt-hour

MWth Megawatts thermal

N/A Not applicable

NDL North Dakota Lignite

NETL National Energy Technology Laboratory

NGCC Natural gas combined cycle

NH3 Ammonia

Nm3 Normal cubic meter

Nm3

/min Normal cubic meter per minute

NOAK Nth-of-a-kind

No. Number

NOx Oxides of nitrogen

O eqv Oxygen equivalents

O&GJ Oil and Gas Journal

O&M Operation and maintenance

O2 Oxygen

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

PAS PAS, Inc.

PC Pulverized coal 

PM Particulate matter 

POTW Publicly Owned Treatment Works

ppm Parts per million 

ppmv Parts per million volume

PRB Powder River Basin
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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PSA Pressure Swing Adsorption

PSFM Power Systems Financial Model

psi Pound per square inch 

psia Pound per square inch absolute

psig Pound per square inch gage

R&D Research and development

RDS Research and Development Solutions, LLC

ROE Return on equity

RWE Rheinisch-Wesfälisches Elektrizitatswerk (German company)

SC Supercritical

scf Standard cubic feet

scfm Standard cubic feet per minute

SCOT Shell Claus Off-gas Treating

SFG Siemens Fuel Gasification

SG Specific gravity

SGC Synthesis gas cooler

SGS Sour gas shift

SNG Synthetic Natural Gas

SO2 Sulfur dioxide

SRU Sulfur recovery unit

STG Steam turbine generator

Syngas Synthesis gas

TASC Total as-spent cost

TGTU Tail gas treating unit

TOC Total overnight cost

Tonne Metric Ton (1000 kg)

TPC Total plant cost

TPH Ton per hour

TS&M Transport, storage, and monitoring

USDA United States Department of Agricultural

vol% Volume percent

WB Wet bulb

WGS Water gas shift

wt% Weight percent

WTA German acronym for “fluidized bed dryer with integrated waste heat recovery”

ZnO Zinc oxide

$/GJ Dollars per gigajoule

$/MMBtu Dollars per million British thermal units

$/MMkJ Dollars per million kilojoule

$/ton Dollars per ton

°C Degrees Celsius

°F Degrees Fahrenheit

5-10s 50-hour work-week
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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

performance of bituminous, subbituminous, and lignite coal conversion systems, specifically for 

the production of synthetic natural gas (SNG) and ammonia, using a consistent economic 

approach that accurately reflects current market conditions for plants starting operation in the 

near term. This is Volume 2 of a four volume report. The four volume series consists of the 

following:

EXECUTIVE SUMMARY

• Volume 1: Bituminous Coal and Natural Gas to Electricity

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

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

• Volume 4: Bituminous Coal to Liquid Fuels with Carbon Capture

Volume 1 entitled Cost and Performance Baseline for Fossil Energy Power Plants Study, 

Volume 1: Bituminous Coal and Natural Gas to Electricity was recently revised and re-released

in November 2010. Volume 3 was published in 2011 and Volume 4 is scheduled for publication 

later in 2011.

The cost and performance of a coal-to-SNG plant, with and without ammonia co-production, 

were evaluated in this study. The results are expected to be valuable to policy makers and will 

help guide research and development (R&D) efforts necessary to make SNG more cost 

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

• Capital and operating costs;

• Overall conversion efficiency;

• Fuel prices;

• Cost of production (COP);

• Availability, reliability, and environmental performance; and

• Current and potential regulation of air, water, and solid waste discharges from fossil fuelbased production facilities, including a potential cap or tax on carbon dioxide (CO2)

emissions.

Eight coal-based plants using the Siemens gasifier were analyzed as listed in Exhibit ES-1. The 

list includes six SNG production cases using various coal ranks and two SNG and ammonia coproduction cases using bituminous coal only. All cases require carbon capture prior to the 

methanation reactors and the ammonia (NH3) plant in co-production cases. In some cases the 

removed CO2 is sequestered, and in other cases it is released to the atmosphere. Normally cases 

are designated as CO2 capture and non-capture, but since all cases are capture in this study, the 

designation used to differentiate between cases is sequestration and non-sequestration. Each 

specific scenario is presented without and with carbon sequestration. 

While input was sought from various technology vendors, the final assessment of performance 

and cost was determined independently, and may not represent the views of the technology 

vendors. The extent of collaboration with the technology vendors varied in scope for each of the 

processes within the plant, with minimal or no collaboration obtained from some vendors.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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The gasification scheme used in this study includes a partial quench followed by a syngas cooler. 

Heat recovery was necessary to produce enough power to satisfy internal auxiliary loads with 

some excess power for export in most cases. This configuration is not currently a commercial 

offering by Siemens, but based on personal communications, it is a configuration they are 

planning to offer for future coal-to-SNG projects.

The methodology included performing steady-state simulations of the various technologies using 

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

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

cost estimating. Performance and process limits were based upon published reports, information 

obtained from vendors and users of the technology, performance data from design/build projects, 

and/or best engineering judgment. Capital and operating costs were estimated based on 

simulation results and through a combination of vendor quotes and scaled estimates. Baseline 

fuel costs for this analysis were determined using data from the Energy Information 

Administration’s (EIA) 2008 Annual Energy Outlook (AEO). The first year of capital 

expenditure (2007) costs used are 1.55 dollars per gigajoule ($/GJ) (1.64 dollars per million 

British thermal units [$/MMBtu]) for Illinois No. 6 coal, $0.84/GJ ($0.89/MMBtu) for Powder 

River Basin (PRB) coal, and $0.79/GJ ($0.83/MMBtu) for North Dakota lignite (NDL). All coal 

prices are on a higher heating value (HHV) basis and in 2007 United States (U.S.) dollars. The 

Illinois No. 6 and PRB coal prices include transportation costs while the NDL coal is assumed to 

be used at a minemouth location. Anhydrous ammonia selling prices were determined from the 

historic correlation between the cost of industrial natural gas (EIA) and the price of ammonia 

fertilizers as paid by U.S. farmers (United States Department of Agriculture [USDA] Economic 

Research Service). The first year selling price of ammonia for the non-sequestration SNG and 

ammonia co-production facility was determined to be $880/metric ton (tonne) ($799/ton) and 

$913/tonne ($828/ton) with carbon sequestration. All plant configurations are evaluated on 

installation at a greenfield site. SNG production is limited by a nominal thermal input of 500 

megawatt-thermal (MWth) to the gasifier. Based on vendor input, the actual gasifier thermal 

input varies according to the type of coal feed and ranges from 506 to 550 MWth. The nominal 

net plant production capacity of ammonia is 2,000 tonnes/day (2,204 tons/day) for the coproduction cases. All cases are based on a 90 percent plant capacity factor (CF). Exhibit ES-2

shows the cost, performance, and environmental profile summary for all cases. These plants are 

expected to operate at full capacity when available. Since variations in fuel costs, capacity

factor, and financing structure (required return on equity) can influence the economics of 

production, sensitivities of the first year cost of production (FYCOP) are evaluated and presented 

later in this Executive Summary.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

3

Exhibit ES-1 Case Descriptions

Case Product(s) Steam Cycle, 

psig/°F/°F1

Coal 

Type

Coal 

Drying 

Process

Gasifier 

Technology Oxidant

H2S 

Separation/ 

Removal

Sulfur 

Removal/ 

Recovery

CO2

Separation

CO2

Compression/

Sequestration

1 SNG 1800/1050/1000 Illinois 

No. 6 Standard Siemens 99 mol% O2

Selexol Claus Plant Selexol 2nd

stage N

2 SNG 1800/1050/1000 Illinois 

No. 6 Standard Siemens 99 mol% O2

Selexol Claus Plant Selexol 2nd

stage Y

3 SNG & 

Ammonia 1800/1050/1000 Illinois 

No. 6 Standard Siemens 99 mol% 

O2

Selexol Claus Plant Selexol 2nd

stage N

4 SNG & 

Ammonia 1800/1050/1000 Illinois 

No. 6 Standard Siemens 99 mol% 

O2

Selexol Claus Plant Selexol 2nd

stage Y

5 SNG 1800/1050/1000

Montana 

Rosebud 

PRB

WTA Siemens 99 mol% 

O2

Selexol Claus Plant Selexol 2nd

stage N

6 SNG 1800/1050/1000

Montana 

Rosebud 

PRB

WTA Siemens 99 mol% 

O2

Selexol Claus Plant Selexol 2nd

stage Y

7 SNG 1800/1050/1000

North 

Dakota 

Lignite

WTA Siemens 99 mol% 

O2

Selexol Claus Plant Selexol 2nd

stage N

8 SNG 1800/1050/1000

North 

Dakota 

Lignite

WTA Siemens 99 mol% 

O2

Selexol Claus Plant Selexol 2nd

stage Y

1 Steam cycle reheat temperatures are nominal.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

4

Exhibit ES-2 Cost and Performance Summary and Environmental Profile

CONVERSION EFFICIENCY 

The net plant conversion efficiency (HHV basis) for all eight cases is shown in Exhibit ES-3. 

The conversion efficiency is the HHV of the products divided by the HHV of the coal. The 

primary conclusions that can be drawn are:

• The SNG production facilities feeding PRB coal have the highest conversion efficiencies

of the coal types modeled in this study with a conversion efficiency of 63.1 percent for 

both the non-sequestration and carbon sequestration cases. This is primarily due to the 

low nitrogen content and high oxygen content in the design fuel, which enables the SNG

produced to have a relatively lower concentration of inerts.

• The remaining six cases have essentially constant conversion efficiency (61.3 to 61.5 

percent). The addition of carbon sequestration has only a minimal impact on conversion 

efficiency. The carbon sequestration impact is seen in the reduced available export 

power relative to the non-sequestration case.

PERFORMANCE Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 7 Case 8

CO2 Sequestration No Yes No Yes No Yes No Yes

SNG Production (Bscf/year)1 57 56 42 42 55 55 52 52

Ammonia Production (TPD)1 N/A N/A 2,204 2,204 N/A N/A N/A N/A

HHV Conversion Efficiency, % 61.4% 61.3% 61.5% 61.4% 63.1% 63.1% 61.5% 61.5%

Gross Power Output (kWe) 308,000 310,600 292,300 292,300 302,000 302,000 305,800 310,500

Auxiliary Power Requirement (kWe) 216,350 262,090 263,600 316,030 247,570 300,190 259,740 313,930

Net Power Output (kWe) 91,650 48,510 28,700 -23,730 54,430 1,810 46,060 -3,430

Coal Flowrate (lb/hr) 964,752 964,752 964,000 964,000 1,259,331 1,259,331 1,564,932 1,564,932

HHV Thermal Input (kWth) 3,298,455 3,298,455 3,295,885 3,295,885 3,160,745 3,160,745 3,034,796 3,034,796

Raw Water Withdrawal (gpm) 7,169 7,123 7,434 7,458 4,853 5,509 4,421 5,131

Process Water Discharge (gpm) 1,462 1,451 1,455 1,461 1,071 1,218 1,071 1,230

Raw Water Consumption (gpm) 5,708 5,672 5,979 5,997 3,783 4,291 3,350 3,901

CO2 Emissions (lb/MMBtu)2 128 5 147 10 140 0.7 147 0.9

SO2 Emissions (lb/MMBtu)2 0.0274 0.0003 0.0229 0.0006 0.0218 0.0000 0.0239 0.0000

NOx Emissions (lb/MMBtu)2 Negligible Negligible Negligible Negligible Negligible Negligible Negligible Negligible

PM Emissions (lb/MMBtu)2 0.007 0.007 0.007 0.007 0.007 0.007 0.007 0.007

Hg Emissions (lb/MMBtu)2 5.71E-07 5.71E-07 5.71E-07 5.71E-07 3.51E-07 3.51E-07 5.60E-07 5.60E-07

COST

Total Plant Cost ($ x 1,000) 2,628,754 2,692,997 3,048,463 3,119,611 2,741,044 2,813,258 2,864,478 2,941,335

Total Overnight Cost ($ x 1,000) 3,235,262 3,312,740 3,742,411 3,829,817 3,354,442 3,442,310 3,504,262 3,595,468

Total As-spent Capital ($ x 1,000) 3,885,549 3,978,601 4,494,636 4,599,610 4,028,684 4,134,215 4,208,619 4,318,158

SNG FYCOP ($/MMBtu)1 19.27 20.95 15.82 17.85 19.15 21.01 21.27 23.24

 CO2 TS&M Costs 0.00 0.91 0.00 1.29 0.00 0.96 0.00 1.03

 Fuel Costs 2.67 2.67 1.89 1.89 1.41 1.41 1.34 1.35

 Variable Costs 1.03 1.04 0.79 0.82 1.02 1.03 1.18 1.18

 Fixed Costs 1.76 1.79 1.41 1.45 1.84 1.86 2.03 2.06

 Electricity Costs -0.77 -0.41 -0.17 0.15 -0.46 -0.02 -0.42 0.03

 Capital Costs 14.58 14.94 11.90 12.25 15.34 15.76 17.13 17.59

Ammonia FYCOP3 ($/ton) - - 799 828 - - - - 1

 Based on a capacity factor of 90 percent for all cases

2

 Based on coal thermal input

3

 Ammonia price is correlated to historic natural gas costs

SNG Only

Illinois No. 6 Coal Rosebud PRB North Dakota Lignite

SNG Only SNG and Ammonia SNG Only
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

5

Exhibit ES-3 Net Plant Conversion Efficiency (HHV)

TOTAL OVERNIGHT COST

The Total Overnight Cost (TOC) for each plant was calculated by adding owner’s costs to the 

Total Plant Cost (TPC). The TPC was determined through a combination of vendor quotes and 

scaled estimates from previous design/build projects. TPC includes all equipment (complete 

with initial chemical and catalyst loadings), materials, labor (direct and indirect), engineering 

and construction management, and contingencies (process and project).

The capital costs have an estimated accuracy of -15%/+30%, consistent with the screening study 

level of design engineering applied to the various cases in the study. The value of the study lies 

not in the absolute accuracy of the individual cases, but in the fact that all cases were evaluated 

under the same set of technical and economic assumptions. The consistency of approach allows 

meaningful comparisons among the cases evaluated.

Project contingencies were added to the Engineering/Procurement/Construction Management 

(EPCM) capital accounts to cover project uncertainty and the cost of any additional equipment 

that would result from a detailed design. The contingencies represent costs that are expected to 

occur. Each bare erected cost (BEC) account was evaluated against the level of estimate detail 

and field experience to determine project contingency. Process contingency was added to cost 

account items that were deemed to pose significant risk due to lack of operating experience. The 

cost accounts that received a process contingency include:

0%

10%

20%

30%

40%

50%

60%

70%

SNG Illinois 6 SNG Illinois 6 

w/ Capture

SNG/NH3

Illinois 6

SNG/NH3 

Illinois 6 w/ 

Capture

SNG PRB SNG PRB w/ 

Capture

SNG Lignite SNG Lignite 

w/ Capture

61.4% 61.3% 61.5% 61.4%

63.1% 63.1%

61.5% 61.5%

% Conversion Efficiency (HHV Basis)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

6

• Gasifiers and Syngas Coolers – 15 percent on all cases – next-generation commercial 

offering and integration with the steam generation island

• Two Stage Selexol – 20 percent on all cases - unproven technology at commercial 

scale

• Mercury Removal – 5 percent on all cases – minimal commercial scale experience in 

gasification applications

• Methanation – 10 percent on all cases – unproven technology at commercial scale

• Instrumentation and Controls – 5 percent on all accounts for integration issues

The TOC is shown for each plant configuration in Exhibit ES-4. For reference, Total As-spent 

Capital (TASC) is also shown. TASC is the sum of TOC, escalation during the capital 

expenditure period, and interest on debt during the capital expenditure period. The following 

observations can be made:

• The SNG only case without carbon sequestration using Illinois No. 6 coal has the lowest 

TOC of $3.24 billion.

• For the SNG only cases without carbon sequestration, the TOC is higher for PRB coal by 

3.7 percent and lignite coal by 8.3 percent relative to the Illinois No. 6 coal cases.

• The TOC increase to add carbon sequestration for the SNG only cases is approximately 

2.4 percent for the Illinois No. 6 cases, 2.6 percent for the PRB coal cases and 2.6 percent 

for the lignite coal case. For the SNG and ammonia co-production case, the TOC 

increases by 2.4 percent to add carbon sequestration.

• The SNG and ammonia co-production cases increase the TOC by approximately 16

percent when compared to the SNG only cases using Illinois No. 6 coal.

FIRST YEAR COST OF PRODUCTION

The cost metric used in this study is the first year cost of production (FYCOP). The capital 

charge factor (CCF) shown in Exhibit ES-5, which was derived using the National Energy 

Technology Laboratory (NETL) Power Systems Financial Model (PSFM) [9], was used to 

calculate the FYCOP. The project financial structure is representative of a high-risk fuels project

with no loan guarantees or other government subsidies. The parameters were chosen to reflect 

the next commercial offering in which the technical and economic risks have not been reduced 

by the wide-scale demonstration of the technology.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

7

Exhibit ES-4 Total Overnight Cost and Total As-spent Capital

1,939 1,988 2,271 2,325 2,024 2,079 2,120 2,179

180 185

213 218

188 193 197 385 202 396

440 452

403 415 421 125 125 434

125 125

126 126 126 126 607 620

694 710

613 629 640 654

3,235 3,313

3,742 3,830

3,354 3,442 3,504 3,595

3,886 3,979

4,495 4,600

4,029 4,134 4,209 4,318

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC

SNG Illinois 6 SNG Illinois 6 w/ 

Capture

SNG/NH3

Illinois 6

SNG/NH3 Illinois 6 

w/ Capture

SNG PRB SNG PRB w/ 

Capture

SNG Lignite SNG Lignite w/ 

Capture

Capital Cost, $1,000,000

TASC

Owner's Cost

Process Contingency

Project Contingency

Home Office Expense

Bare Erected Cost
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

8

Exhibit ES-5 Economic Parameters Used to Calculate FYCOP

High Risk Fuels 

Financial Structure

First Year Capital Charge Factor 0.2449

The FYCOP was calculated as detailed in Section 2.8. The FYCOP is shown in Exhibit ES-6

with the capital cost, fixed operating cost, variable operating cost, electricity cost (or revenue),

and fuel costs shown separately. In the carbon sequestration cases, the CO2 transport, storage,

and monitoring (TS&M) costs are also shown as a separate bar segment. The following 

conclusions can be drawn, using first year cost as the basis for comparison:

• The co-production case using Illinois No. 6 coal without carbon sequestration has the 

lowest cost of the cases modeled in this study with an FYCOP of $15.82/MMBtu.

• The FYCOP is dominated by capital charges in all cases. The capital cost component of 

FYCOP, which includes owner’s costs, comprises 71 to 81 percent for the SNG only 

cases.

• The fuel cost component in the SNG only cases represents 13 percent for Illinois No. 6 

coal, 7 percent for the PRB coal, and 6 percent for the lignite coal.

• The TS&M component of FYCOP in the carbon sequestration cases is 4 percent, 5

percent, and 4 percent for the Illinois No. 6 coal, PRB coal, and lignite coal respectively. 

For the SNG and ammonia co-production case, the TS&M account for 7 percent of the 

total FYCOP.

• The SNG FYCOP increases by an average amount of 9 percent with the addition of

carbon sequestration for the SNG only cases and 13 percent for the co-production case. 

The cost of TS&M is shared between the two products in the co-production case based on 

the SNG-NH3 cost relationship.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

9

Exhibit ES-6 FYCOP by Cost Component

The EIA’s AEO 2009 shows a 2007 residential natural gas delivered price of $12.69/MMBtu. 

The EIA reference case projections show a price of $12.09/MMBtu in 2010, $12.50/MMBtu in 

2020, and $14.31/MMBtu in 2030. The price of SNG determined in this study is generally

higher than current or projected natural gas market prices. However, the assumed financing 

structure (addressed in Section 2.8 of this report) plays a significant role in the elevated prices. 

The assumed return on equity (ROE) is 20 percent. A sensitivity analysis on ROE was 

performed and is shown in Exhibit ES-7. As expected, as the ROE requirement increases, the 

cost of SNG and ammonia increases. At the assumed high-risk fuels scenario first year capital 

charge factor (CCF) and ROE, SNG prices range from $15.82 to $23.24/MMBtu and ammonia 

costs range from $799 to $828/ton. Adjusting the first year CCF to 0.1344, representative of a 

high-risk fuels project with a corresponding ROE of 12 percent, results in SNG FYCOP cost 

ranging from $9.85 to $14.85/MMBtu and ammonia cost ranging from $560 to $585/ton.

14.58 14.94

11.90 12.25

15.34 15.76 17.13 17.59

1.76 1.79

1.41 1.45

1.84 1.86

2.03 2.06

1.03 1.04

0.79 0.82

1.02 1.03

1.18 1.18

2.67 2.67

1.89 1.89

1.41 1.41

1.34 1.35 0.91

1.29

0.96

1.03

19.27

20.95

15.82

17.85

19.15

21.01 21.27

23.24

-5

0

5

10

15

20

25

30

35

40

SNG Illinois 6 SNG Illinois 6 w/ 

Capture

SNG/NH3

Illinois 6

SNG/NH3 Illinois 6 

w/ Capture

SNG PRB SNG PRB w/ 

Capture

SNG Lignite SNG Lignite w/ 

Capture

FYCOP, $/MMBtu

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs

Electricity Revenue/Cost
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

10

Exhibit ES-7 FYCOP Sensitivity to ROE 

Exhibit ES-8 shows the FYCOP sensitivity to fuel costs. As expected, all cases show a linear 

increase in FYCOP with the increase in coal price. Fuel cost represents a relatively minor 

fraction of the FYCOP so that even at a fuel price of zero, the FYCOP of SNG ranges from 

$13.73 to $21.89/MMBtu.

The sensitivity of FYCOP to CF is shown in Exhibit ES-9. All cases show a decrease in FYCOP 

with an increase in CF. The CF used in this study was 90 percent. The rate of decrease is 

relatively small above 90 percent with the maximum differential between 90 percent and 100 

percent capacity of $1.96/MMBtu for SNG only cases and $1.52/MMBtu for the co-production 

cases.

0

200

400

600

800

1000

1200

1400

0

5

10

15

20

25

30

35

40

45

50

5% 10% 15% 20% 25%

Ammonia LCOP ($/ton)

SNG FYCOP ($/MMBtu)

Return on Equity

Case 8 SNG Price

Case 2 SNG Price

Case 6 SNG Price

Case 7 SNG Price

Case 1 SNG Price

Case 5 SNG Price

Case 4 SNG Price

Case 3 SNG Price

Case 4 Ammonia Price

Case 3 Ammonia Price

High Risk Fuels Project

ROE - 12%

First Year CCF - 0.1344

High Risk Fuels Project: 

ROE - 20%

First Year CCF - 0.2449

Ammonia 

Price Curves
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

11

Exhibit ES-8 FYCOP Sensitivity to Fuel Costs 

Exhibit ES-9 FYCOP Sensitivity to Capacity Factor

0

5

10

15

20

25

30

35

0 0.5 1 1.5 2 2.5 3

FYCOP ($/MMBtu)

Coal Price ($/MMBtu)

SNG Lignite w/ Capture

SNG Lignite

SNG PRB w/ Capture

SNG Illinois 6 w/ Capture

SNG PRB

SNG Illinois 6

SNG/NH3 Illinois 6 w/ Capture

SNG/NH3 Illinois 6

Montana PRB

($0.89/MMBtu) ND Lignite

($0.83/MMBtu)

Illinois No. 6

($1.64/MMBtu)

0

10

20

30

40

50

60

70

80

30% 40% 50% 60% 70% 80% 90% 100%

FYCOP ($/MMBtu)

Capacity Factor (%)

SNG Lignite w/ Capture

SNG Lignite

SNG PRB w/ Capture

SNG Illinois 6 w/ Capture

SNG PRB

SNG Illinois 6

SNG/NH3 Illinois 6 w/ Capture

SNG/NH3 Illinois 6

Study Capacity

Factor
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

12

FIRST YEAR COST OF CO2 AVOIDED

In cases where the CO2 was sequestered, the associated costs of CO2 compression and TS&M 

were calculated as an avoided cost, relative to the analogous non-sequestration case, as 

illustrated in Equation ES-1:

Emissions Emissions tons MMBtu

FYCOP FYCOP MMBtu

Avoided Cost

w o sequestration with sequestration

with sequestration w o sequestration

{ } /

{ } $ /

/

/

−

− = (ES-1)

The resulting first year avoided costs are shown in Exhibit ES-10 for each of the four carbon 

sequestration cases. The cost of CO2 avoided for the SNG only cases averages $18.38/tonne 

($16.67/ton) within a very narrow range. The CO2 avoided costs are lower for the co-production 

cases because the increase in the selling price of ammonia for the carbon sequestration case 

absorbs some of the costs related to the addition of compression and TS&M. For integrated 

gasification combined cycle (IGCC) cases in Volume 1 of this series, CO2 avoided costs range 

from $43-61/tonne ($39-56/ton) avoided. The avoided costs for the SNG plants are significantly 

lower than IGCC plants because the capital cost increase is lower (there is capture in all cases; 

the incremental cost is for compression and carbon sequestration only). The TOC increase from 

non-sequestration to sequestration cases ranges from 2.4 to 2.6 percent for the cases in this study. 

The capital cost increase for the IGCC cases in Volume 1 is from 13.5 to 21.1 percent.

Exhibit ES-10 CO2 Avoided Cost

16.65

13.47

16.79 16.57

0

5

10

15

20

25

30

SNG Illinois 6 SNG/NH3

Illinois 6

SNG PRB SNG Lignite

CO2 Avoided Cost ($/ton)

CO2 Avoided Cost
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

13

ECONOMIC PATHWAYS

As stated above, the project financial structure used for the FYCOP calculations presented in this 

report is representative of a high-risk fuels project with no loan guarantees or other government 

subsidies. The parameters were chosen to reflect the next commercial offering in which the 

technical and economic risks have not been reduced by the wide-scale demonstration of the 

technology. The cost of producing SNG from coal can be substantially lower given more 

favorable financial and economic conditions. A more favorable structure could involve 

government loan guarantees, tax incentives, and shorter construction periods. Projects can also 

include different technologies and subsequently different capital costs, different O&M costs, 

production of other co-products, etc. that will impact the cost of SNG.

Exhibit ES-11 and Exhibit ES-12 show the results of adjusting selected economic assumptions 

for Cases 2 and 4 respectively to be representative of some of the parameters associated with a 

commercial coal-to-SNG project recently proposed. The modified parameters are highlighted in 

blue for each step. The combined modifications reduce the FYCOP by 48.6 percent for Case 2 

and by 50.5 percent for Case 4. The resulting values are comparable to those quoted in the 

proposed project.

Loan guarantees are a near term incentive to commercialize technologies that involve high risk. 

Ultimately the technology must stand on its own merits. A second economic pathway was 

investigated to demonstrate a financial structure that would not require loan guarantees, but still 

achieve a similar cost of SNG. Increased commercial application of technologies reduces risks 

and lowers capital cost requirements. The gasification production plant capital cost in this study

is based on commercial offerings; however, there have been very limited sales of these units. 

The costs listed reflect the “next commercial offering” level of cost rather than mature nth-of-akind (NOAK) cost. As technologies mature, overall costs decrease due to multiple plant 

completions and lessons learned. 

Exhibit ES-13 and Exhibit ES-14 show the results of adjusting the financial structure to values 

typically assumed for a low risk power project [1

Exhibit ES-11

]. Reductions in TOC of 21.5 percent for 

Case 2 and 22.6 percent for Case 4 reduce the FYCOP values to match those of the examples

shown in and Exhibit ES-12 respectively. While these percentages may be 

considered aggressive for typical first-of-a-kind (FOAK) to NOAK reductions, substantial 

improvements in the FYCOP are shown even when only the financial structure is modified to 

reflect the lower risk of mature technologies.

Additionally, after the technology matures, it may be possible for the project developer to obtain 

financing through the bond market and obtain longer debt payment terms than shown in Exhibit 

ES-13 and Exhibit ES-14 and subsequently require a lower cost of product to satisfy the equity 

investors. The specific financing structure options of a project developer will strongly depend on 

the financial wherewithal of the developer.

The FYCOP values reported in this study reflect the typical assumptions made for high risk fuels 

projects, which were developed for the specific purpose of comparing the relative cost of coal 

conversion technologies. They are not intended to represent definitive point costs; however 

these sensitivities to the assumed financial parameters indicate that the results are comparable to 

currently proposed projects.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

14

Exhibit ES-11 Case 2 Economic Pathway with Favorable Financial Structure

(SNG from Illinois 6 with CO2 Capture)

Parameter NETL Study Step 1a Step 1b Step 1c Step 2 Step 3 Step 4 Step 5

% Debt 50% 70% 70% 70% 70% 70% 70% 70%

% Equity 50% 30% 30% 30% 30% 30% 30% 30%

Interest Rate 9.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5%

Required IRROE 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0%

Repayment Term (years) 15 15 30 30 30 30 30 30

Capital Expenditure Period (Months)* 60 60 60 48 48 48 48 48

Capital Cost Escalation (%/yr) 3.6% 3.6% 3.6% 3.6% 0.0% 0.0% 0.0% 0.0%

Owner's Cost (%TPC) 23% 23% 23% 23% 23% 18% 18% 18%

Property Taxes and Insurance (%TPC) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 0.42% 0.42%

CO2 Credit ($/Tonne) $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $10.00

CO2 Captured (Tonne/Day) 15,134 15,134 15,134 15,134 15,134 15,134 15,134 15,134

TOC (1000$) 3,312,740 3,312,740 3,312,740 3,312,740 3,312,740 3,180,577 3,180,577 3,180,577

SNG COP $/MMBtu 

(excluding TS&M costs) 20.04 15.17 13.47 12.68 12.29 12.01 11.23 10.31

Incremental Step Reduction 24.3% 11.2% 5.9% 3.0% 2.3% 6.5% 8.2%

Cumulative Reduction 24.3% 32.8% 36.7% 38.7% 40.1% 44.0% 48.6%

* Capital Expenditure Period (Year-by-Year Distribution)

4 years (48 months) 10 % - 40 % - 30 % - 20 %

5 years (60 months) 10 % - 30 % - 25 % - 20 % - 15 %

Sensitivity Analysis Steps

1. Modify financing structure (debt/equity & interest rate)

1a Increase percentage of debt and decrease interest on debt

1b Increase loan repayment term

1c Decrease capital expenditure period

2. Reduce capital cost escalation during the capital expenditure period

3. Reduce owner’s cost

4. Reduce taxes and insurance in fixed O&M costs 

5. Assume CO2 revenue value for enhanced oil recovery
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

15

Exhibit ES-12 Case 4 Economic Pathway with Favorable Financial Structure

(SNG and Ammonia from Illinois 6 with CO2 Capture)

Parameter NETL Study Step 1a Step 1b Step 1c Step 2 Step 3 Step 4 Step 5

% Debt 50% 70% 70% 70% 70% 70% 70% 70%

% Equity 50% 30% 30% 30% 30% 30% 30% 30%

Interest Rate 9.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5%

Required IRROE 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0%

Repayment Term (years) 15 15 30 30 30 30 30 30

Capital Expenditure Period (Months)* 60 60 60 48 48 48 48 48

Capital Cost Escalation (%/yr) 3.6% 3.6% 3.6% 3.6% 0.0% 0.0% 0.0% 0.0%

Owner's Cost (%TPC) 23% 23% 23% 23% 23% 18% 18% 18%

Property Taxes and Insurance (%TPC) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 0.42% 0.42%

CO2 Credit ($/Tonne) $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $10.00

CO2 Captured (Tonne/Day) 16,763 16,763 16,763 16,763 16,763 16,763 16,763 16,763

TOC (1000$) 3,829,817 3,829,817 3,829,817 3,829,817 3,829,817 3,684,431 3,684,431 3,684,431

SNG COP $/MMBtu 

(excluding TS&M costs) 16.56 12.60 11.06 10.30 9.96 9.71 9.00 8.20

Incremental Step Reduction 23.9% 12.3% 6.8% 3.4% 2.5% 7.3% 8.8%

Cumulative Reduction 23.9% 33.2% 37.8% 39.9% 41.4% 45.7% 50.5%

* Capital Expenditure Period (Year-by-Year Distribution)

4 years (48 months) 10 % - 40 % - 30 % - 20 %

5 years (60 months) 10 % - 30 % - 25 % - 20 % - 15 %

Sensitivity Analysis Steps

1. Modify financing structure (debt/equity & interest rate)

1a Increase percentage of debt and decrease interest on debt

1b Increase loan repayment term

1c Decrease capital expenditure period

2. Reduce capital cost escalation during the capital expenditure period

3. Reduce owner’s cost

4. Reduce taxes and insurance in fixed O&M costs 

5. Assume CO2 revenue value for enhanced oil recovery
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Exhibit ES-13 Case 2 Economic Pathway with Mature Technology

(SNG from Illinois 6 with CO2 Capture)

Parameter NETL Study Step 1a Step 1b Step 2

% Debt 50% 50% 50% 50%

% Equity 50% 50% 50% 50%

Interest Rate 9.5% 4.5% 4.5% 4.5%

Required IRROE 20.0% 20.0% 12.0% 12.0%

Repayment Term (years) 15 15 15 15

Capital Expenditure Period (Months)* 60 60 60 60

Capital Cost %Escalation/yr 3.6% 3.6% 3.6% 3.6%

Owner's Cost %TPC 23% 23% 23% 23%

Property Taxes and Insurance %TPC 2.00% 2.00% 2.00% 2.00%

CO2 Credit ($/Tonne) $0.00 $0.00 $0.00 $0.00

CO2 Tonne/Day Captured 15,134 15,134 15,134 15,134

TOC (1000$) 3,312,740 3,312,740 3,312,740 2,602,157

Percent capital (TOC) reduction 0.0% 0.0% 0.0% 21.5%

SNG COP $/MMBtu 

(excluding TS&M costs) 20.04 18.54 12.21 10.31

Incremental Step Reduction 7.5% 34.1% 15.6%

Cumulative Reduction 7.5% 39.1% 48.6%

* Capital Expenditure Period (Year-by-Year Distribution)

5 years (60 months) 10 % - 30 % - 25 % - 20 % - 15 %

Sensitivity Analysis Steps

1. Modify financing structure (debt/equity & interest rate)

1a Decrease interest on debt

1b Decrease required internal rate of return on equity (IRROE)

2. Reduce capital cost to reflect FOAK to NOAK improvements
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Exhibit ES-14 Case 4 Economic Pathway with Mature Technology

(SNG and Ammonia from Illinois 6 with CO2 Capture)

Parameter NETL Study Step 1a Step 1b Step 2

% Debt 50% 50% 50% 50%

% Equity 50% 50% 50% 50%

Interest Rate 9.5% 4.5% 4.5% 4.5%

Required IRROE 20.0% 20.0% 12.0% 12.0%

Repayment Term (years) 15 15 15 15

Capital Expenditure Period (Months)* 60 60 60 60

Capital Cost %Escalation/yr 3.6% 3.6% 3.6% 3.6%

Owner's Cost %TPC 23% 23% 23% 23%

Property Taxes and Insurance %TPC 2.00% 2.00% 2.00% 2.00%

CO2 Credit ($/Tonne) $0.00 $0.00 $0.00 $0.00

CO2 Tonne/Day Captured 16,763 16,763 16,763 16,763

TOC (1000$) 3,829,817 3,829,817 3,829,817 2,962,746

Percent capital (TOC) reduction 0.0% 0.0% 0.0% 22.6%

SNG COP $/MMBtu 

(excluding TS&M costs) 16.56 15.67 10.02 8.20

Incremental Step Reduction 5.4% 36.0% 18.2%

Cumulative Reduction 5.4% 39.5% 50.5%

* Capital Expenditure Period (Year-by-Year Distribution)

5 years (60 months) 10 % - 30 % - 25 % - 20 % - 15 %

Sensitivity Analysis Steps

1. Modify financing structure (debt/equity & interest rate)

1a Decrease interest on debt

1b Decrease required internal rate of return on equity (IRROE)

2. Reduce capital cost to reflect FOAK to NOAK improvements
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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1.

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

performance of fossil energy fuel systems, specifically the Siemens gasifier using bituminous 

and low rank coals to produce SNG and ammonia as a co-product, in a consistent technical and 

economic manner that accurately reflects current market conditions for plants starting operation 

in the near term. This report is Volume 2 of a four volume series. The four volumes are defined 

below with Volume 1 having been originally published in May 2007 and the most recent revision 

issued in November 2010. Volume 3 was released in March and May, 2011 and Volume 4 is

expected to be released later in 2011.

INTRODUCTION

• Volume 1: Bituminous Coal and Natural Gas to Electricity

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

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

• Volume 4: Bituminous Coal to Liquid Fuels with Carbon Capture

Eight cases are modeled and analyzed. Since all cases include CO2 capture the normal 

designation of capture and non-capture is not used in this study. Rather the cases are 

differentiated by the designation carbon sequestration or non-sequestration. The carbon 

sequestration cases assume that compression and drying are the only steps required to produce 

CO2 suitable for transportation and sequestration. Two cases use Illinois No. 6 bituminous coal 

for the production of SNG only, with and without carbon sequestration; two cases use Illinois 

No. 6 coal for the co-production of SNG and ammonia, with and without carbon sequestration; 

two cases use PRB subbituminous coal for the production of SNG only, with and without carbon 

sequestration; and two cases use NDL coal for the production of SNG only, also with and 

without carbon sequestration.

The gasification scheme used in this study includes a partial quench followed by a syngas cooler. 

Heat recovery was necessary to produce enough power to satisfy internal auxiliary loads with 

some excess power for export in most cases. This configuration is not currently a commercial 

offering by Siemens, but based on personal communications, it is a configuration they are 

considering for coal-to-SNG projects.

This Final Report covers the following eight cases:

Case 1 – This case consists of a coal to SNG plant without CO2 compression and sequestration 

based on a Siemens gasifier. Illinois No. 6 coal is the fuel and the plant is located at a generic 

site in Midwestern, U.S.

Case 2 – This case is the same as Case 1 except it includes CO2 compression and sequestration.

Case 3 – This case consists of a coal to SNG and ammonia co-production plant without CO2

compression and sequestration based on a Siemens gasifier. Illinois No. 6 coal is the fuel and the 

plant is located at a generic site in Midwestern, U.S. 

Case 4 – This case is the same as Case 3 except it includes CO2 compression and sequestration.

Case 5 – This case includes a coal to SNG plant without CO2 compression and sequestration 

based on a Siemens gasifier. Rosebud PRB coal is the fuel and the plant is located at a generic 

site in Western, U.S.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Case 6 – This case is the same as Case 5 except it includes CO2 compression and sequestration.

Case 7 – This case consists of a coal to SNG plant without CO2 compression and sequestration 

based on a Siemens gasifier. NDL coal is the fuel and the plant is located at a minemouth site in 

North Dakota, U.S.

Case 8 – This case is the same as Case 7 except it includes CO2 compression and sequestration.

While input was sought from various technology vendors, the final assessment of performance 

and cost was determined independently, and may not represent the views of the technology 

vendors.

Generating Unit Configurations

The six SNG only cases have a nominal gasifier thermal input of 500 MW. The actual capacity 

varies from 506 to 549 MWth depending on coal type. This translates into a production of 52 to 

57 billion standard cubic feet (Bscf)/year of SNG at 90 percent CF. This translates into a daily 

capacity of 158-172 million standard cubic feet (MMScf)/day of SNG. The two SNG and 

ammonia co-production cases are based on a standard-size 2,000 tonnes/day (2,204 tons/day) 

ammonia facility with the remainder of the syngas used for SNG production.

The balance of this report is organized as follows:

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

• Chapter 3 describes the major process systems for all eight cases

• Chapter 4 provides the detailed results of the four bituminous coal cases.

• Chapter 5 provides the detailed results of the four low rank coal cases.

• Chapter 0 summarizes the results of the eight cases.

• Chapter 7 contains the reference list.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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2.

For each of the plant configurations in this study an Aspen model was developed and used to 

generate material and energy balances, which in turn were used to provide a design basis for 

items in the major equipment list. The equipment list and material balances were used as the 

basis for generating the capital and operating cost estimates. Performance and process limits 

were based upon published reports, information obtained from vendors of the technology, 

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

and operating costs were estimated by WorleyParsons Group, Inc. (WorleyParsons) based on 

simulation results and through a combination of vendor quotes and scaled estimates from 

previous design/build projects. Ultimately a first year cost of production (FYCOP) of SNG was 

calculated for each of the cases and is reported as the economic figure-of-merit. Due to the 

process requirements for both SNG and ammonia production, all cases utilize an AGR system 

that removes or captures the CO2 from the syngas. Some cases simply release this removed CO2

to the atmosphere and are labeled “non-sequestration.” The cases that compress the removed 

CO2 and include TS&M are labeled “sequestration.”

GENERAL EVALUATION BASIS

The balance of this chapter documents the design basis, environmental targets, and cost 

assumptions used in the study.

2.1 SITE CHARACTERISTICS

The plants are located at three different generic plant sites. Plants using Illinois No. 6 coal are 

assumed to be located at a generic site in Midwestern, U.S. Plants using PRB coal are assumed 

to be located at a generic site in Montana. Plants using lignite coal are assumed to be located at a 

minemouth site in North Dakota. The ambient conditions for the three sites are shown in 

Exhibit 2-1.

Exhibit 2-1 Ambient Conditions

Location

Midwest Montana

North 

Dakota

Average Elevation, ft 0 3,400 1,900

Barometric Pressure, psia 14.7 13.0 13.8

Design Ambient Temperature, Dry Bulb, °F 59 42 40

Design Ambient Temperature, Wet Bulb, °F 51.5 37 36

Design Ambient Relative Humidity, % 60 62 68

The site characteristics are assumed to be the same for all plant locations, except where noted as 

shown in Exhibit 2-2.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Exhibit 2-2 Site Characteristics

Location Greenfield, Midwest (Illinois No. 6 coal), Montana 

(PRB coal) or North Dakota (lignite coal)

Topography Level

Size, acres 300

Transportation Rail

Ash/Slag Disposal Off Site

Water Municipal (50%) / Groundwater (50%)

Access Land locked, having access by railway and highway

CO2 Storage

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

kilometers (50 miles) and sequestered in a saline 

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

The land area for all the production plant cases assumes 30 acres are required for the plant proper 

and the balance provides a buffer of approximately 0.25 miles to the fence line. The extra land 

could also provide for a rail loop if required.

In all cases it was assumed that the steam turbine (ST) is enclosed in a turbine building, but the 

gasifier is not enclosed. The following design parameters are considered site-specific, and are 

not quantified for this study. Allowances for normal conditions and construction are included in 

the cost estimates.

• Flood plain considerations

• Existing soil/site conditions

• Water discharges and reuse

• Rainfall/snowfall criteria

• Seismic design

• Buildings/enclosures

• Fire protection

• Local code height requirements

• Noise regulations – Impact on site and surrounding area

2.2 PLANT PRODUCTION CAPACITY

Currently, the only operating SNG plant (and other co-products) within the U.S. is the Dakota 

Gasification Company’s Great Plains Synfuels Plant. This plant has an annual production of 

approximately 54 Bscf [

SNG Only Plant

2

Exhibit 2-3

]. In addition, there are several proposed SNG plants in the United 

States as listed in [3]. The gasifier capacity is coal-type dependent and the resulting 

SNG capacity varies accordingly. The six gasifier systems in this study result in average SNG 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

23

outputs of 56 Bscf/yr for bituminous coal, 55 Bscf/yr for PRB coal and 52 Bscf/yr for lignite coal 

at 90 percent CF. These capacities are consistent with the existing plant and announced projects

shown in Exhibit 2-3.

Exhibit 2-3 Proposed Capacity for SNG Plants in the United States

Project Location Feedstock Gasifier Capacity Units

Kentucky NewGas Kentucky Kentucky 

Bituminous

CoP 

E-Gas

1,700 – 1,980

(60-70)

MNm3/year 

(Bscf/year)

Hunton Energy Freeport Plant 

(Lockwood) Texas petcoke GEE 1,870 (66) MNm3

/year 

(Bscf/year)

South Heart North 

Dakota ND Lignite Lurgi 1,050 (37) MNm3

/year 

(Bscf/year)

Taylorville Energy Center Illinois Illinois 

Bituminous GEE 74 - 450(2.6-16)

MNm3/year 

(Bscf/year)

Southern Illinois Coal-to-SNG 

facility Illinois Illinois Bituminous GEE 1,420 (50) MNm3

/year 

(Bscf/year)

Secure Energy Decatur Gasification Illinois Illinois 

Bituminous Siemens 570 (20) MNm3

/year 

(Bscf/year)

Indiana SNG Project Indiana Illinois 

Bituminous GEE 1,130 (40) MNm3

/year 

(Bscf/year)

Lake Charles Cogeneration LLC Louisiana petcoke GEE unknown

Scriba Coal Gasification Plant New York coal unknown 2,830 (100) MNm3

/year 

(Bscf/year)

Mississippi SNG Project Mississippi petcoke CoP 

E-Gas 990 (35) MNm3

/year 

(Bscf/year)

Cash Creek SNG Project Kentucky Kentucky 

Bituminous GEE unknown

The co-production facility cases use the same coal type and coal feed rate as the Illinois No. 6 

bituminous coal non-sequestration and sequestration SNG only cases (Cases 1 and 2) with a 

portion of the syngas utilized to feed a large commercial size ammonia plant and the remaining 

syngas utilized for SNG production. Some currently operating ammonia plants in the United 

States and their associated feedstock and capacity are shown in 

SNG and Ammonia Co-Production Plant

Exhibit 2-4.

Exhibit 2-4 U.S. Ammonia Plants

Company Location Feedstock Capacity Units

Agrium Inc. Texas natural gas 1,342 

(1,479)

tonnes/day 

(tons/day)

CF Industries, Inc. Louisiana natural gas 5,589 

(6,156)

tonnes/day 

(tons/day)

Coffeyville Resources, Nitrogen 

Fertilizers, LLC Louisiana coal 1,027 (1,132)

tonnes/day 

(tons/day)

Dakota Gasification Co. North 

Dakota coal 995 (1,095)

tonnes/day 

(tons/day)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Company Location Feedstock Capacity Units

Honeywell International Inc. Virginia natural gas 1,452 

(1,599)

tonnes/day 

(tons/day)

Koch Nitrogen Co. Nebraska natural gas 726 

(800)

tonnes/day 

(tons/day)

Mosaic Co. Louisiana coal/petcoke 1,392 

(1,533)

tonnes/day 

(tons/day)

PCS Nitrogen, Inc., LP Georgia natural gas 1,885 

(2,076)

tonnes/day 

(tons/day)

Rentech Energy Midwest Corp. Illinois coal 762 

(839)

tonnes/day 

(tons/day)

The standard capacity for new ammonia plants being built today is approximately 2,000 

tonnes/day (2,204 tons/day) and is used as the basis for the ammonia portion of the coproduction facilities [4]. Advances in ammonia production technology have enabled even higher 

production rates. At higher operating pressures, higher ammonia conversion per pass is 

achieved. This allows ammonia plant production capacity to increase while maintaining 

reasonable reactor and equipment sizes [5

2.3 COAL CHARACTERISTICS

]. The remaining portion of the syngas is used to 

produce approximately 42 Bscf/year of SNG at 90 percent CF. 

There are three design coals, bituminous Illinois No. 6 coal, subbituminous PRB coal from 

Montana, and lignite coal from North Dakota. The coal properties are from NETL’s Coal 

Quality Guidelines and are shown in Exhibit 2-5, Exhibit 2-6, and Exhibit 2-7 [6

The coal mercury (Hg) content was not available from reference 

].

6 and was obtained through 

alternate means. Thirty-four samples of Illinois No. 6 coal have an arithmetic mean value of 

0.09 parts per million (ppm) (dry basis) with standard deviation of 0.06 based on coal samples 

shipped by Illinois mines [7 Exhibit 

2-5

]. The coal mercury content for Illinois No. 6 coal shown in 

was assumed to be 0.15 ppm (dry) for all Illinois No. 6 cases, which corresponds to the mean 

plus one standard deviation and encompasses about 84 percent of the samples. 

The mercury concentration for the low rank coals used in this study was determined from the 

Environmental Protection Agency’s (EPA) Information Collection Request (ICR) database. The 

ICR database has 137 records of Montana Rosebud subbituminous coal with an average Hg 

concentration of 0.056 ppm (dry) and a standard deviation of 0.025 ppm. There are 266 records 

for NDL from the Beulah seam with an average Hg concentration of 0.081 ppm (dry) and a 

standard deviation of 0.035 ppm. The mercury values in Exhibit 2-6 and Exhibit 2-7 are the 

mean plus one standard deviation, or 0.081 ppm (dry) for PRB coal and 0.116 ppm (dry) for 

NDL [8

The Power Systems Financial Model (PSFM) was used to derive the capital charge factor (CCF)

for this study [

]. It was further assumed that all of the coal Hg enters the gas phase and none leaves 

with the bottom ash or slag.

9

The coal cost used in this study is $1.55/GJ ($1.64/MMBtu) for Illinois No. 6 coal, $0.84/GJ 

($0.89/MMBtu) for PRB coal and $0.78/GJ ($0.83/MMBtu) for lignite coal (2007 cost of coal in 

]. The PSFM requires that all cost inputs have a consistent cost year basis. 

Because the capital and operating cost estimates are in June 2007 dollars, the fuel costs must also 

be in June 2007 dollars
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

25

June 2007 dollars). These costs were determined using the following information from the 

EIA’s 2008 AEO:

• The 2007 minemouth cost of Illinois No. 6 in 2006 dollars, $32.66/tonne 

($29.63/ton), was obtained from Supplemental Table 112 of the EIA’s 2008 AEO for 

eastern interior high-sulfur bituminous coal. From the same table the 2007 

minemouth cost of PRB coal in 2006 dollars is $13.02/tonne ($11.81/ton) and of 

NDL coal in 2006 dollars is $11.68/tonne ($10.59/ton).

• The cost of Illinois No. 6 coal was escalated to 2007 dollars using the gross domestic 

product (GDP) chain-type price index from AEO 2008, resulting in a price of 

$33.67/tonne ($30.55/ton) [10

• Transportation costs for Illinois No. 6 and PRB coal were estimated to be 25 percent

of the minemouth cost based on the average transportation rate of the respective coals 

to the surrounding regions [

]. Similarly, the cost of PRB coal in 2007 dollars is 

$13.42/tonne ($12.17/ton) and the cost of NDL in 2007 dollars is $12.04/tonne 

($10.92/ton). 

11]. The final delivered costs for Illinois No. 6 coal 

shown in the report is $42.09/tonne ($38.18/ton) or $1.55/GJ ($1.64/MMBtu). PRB 

coal has a final delivered cost of $16.77/tonne ($15.22/ton) or $0.84/GJ 

($0.89/MMBtu). The NDL plant is assumed to be located at the minemouth, so 

transportation costs are zero. (Note: The Illinois No. 6 coal cost of $1.6366/MMBtu 

was used in calculations, but only two decimal places are shown in the report. 

Similarly, the PRB and lignite fuel costs convert to $0.8884/MMBtu and 

$0.8251/MMBtu, respectively.)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Exhibit 2-5 Illinois No. 6 Bituminous, Old Ben Mine

Bituminous Design Coal Analysis

Proximate Analysis Dry Basis, % As Received, %

Moisture 0.0 11.12

Ash 10.91 9.70

Volatile Matter 39.37 34.99

Fixed Carbon 49.72 44.19

Total 100.0 100.0

Ultimate Analysis Dry Basis, % As Received, %

Carbon 71.72 63.75

Hydrogen 5.06 4.50

Nitrogen 1.41 1.25

Sulfur 2.82 2.51

Chlorine 0.33 0.29

Ash 10.91 9.70

Moisture 0.00 11.12

Oxygen (Note A) 7.75 6.88

Total 100.0 100.0

Heating Value Dry Basis As Received

HHV, kJ/kg 30,506 27,113

HHV, Btu/lb 13,126 11,666

LHV, kJ/kg 29,544 26,151

LHV, Btu/lb 12,712 11,252

Hardgrove Grindability Index 60

Ash Mineral Analysis %

Silica SiO2 45.0

Aluminum Oxide Al2O3 18.0

Iron Oxide Fe2O3 20.0

Titanium Dioxide TiO2 1.0

Calcium Oxide CaO 7.0

Magnesium Oxide MgO 1.0

Sodium Oxide Na2O 0.6

Potassium Oxide K2O 1.9

Sulfur Trioxide SO3 3.5

Phosphorous Pentoxide P2O5 0.2

Barium Oxide Ba2O 0.00

Strontium Oxide SrO 0.00

Unknown --- 1.8

Total 100.0

Trace Components ppmd

Mercury (Note B) Hg 0.15

Notes: A. By Difference

B. Mercury value is the mean plus one standard deviation using 2004 Keystone Coal Industry 

Manual
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Exhibit 2-6 Montana Rosebud PRB, Area D, Western Energy Co. Mine

Subbituminous Design Coal Analysis

Proximate Analysis Dry Basis, % As Received, %

Moisture 0.0 25.77

Ash 11.04 8.19

Volatile Matter 40.87 30.34

Fixed Carbon 48.09 35.70

Total 100.0 100.0

Ultimate Analysis Dry Basis, % As Received, %

Carbon 67.45 50.07

Hydrogen 4.56 3.38

Nitrogen 0.96 0.71

Sulfur 0.98 0.73

Chlorine 0.01 0.01

Ash 11.03 8.19

Moisture 0.00 25.77

Oxygen (Note A) 15.01 11.14

Total 100.0 100.0

Heating Value Dry Basis As Received

HHV, kJ/kg 26,787 19,920

HHV, Btu/lb 11,516 8,564

LHV, kJ/kg 25,810 19,195

LHV, Btu/lb 11,096 8,252

Hardgrove Grindability Index 57

Ash Mineral Analysis %

Silica SiO2 38.09

Aluminum Oxide Al2O3 16.73

Iron Oxide Fe2O3 6.46

Titanium Dioxide TiO2 0.72

Calcium Oxide CaO 16.56

Magnesium Oxide MgO 4.25

Sodium Oxide Na2O 0.54

Potassium Oxide K2O 0.38

Sulfur Trioxide SO3 15.08

Phosphorous Pentoxide P2O5 0.35

Barium Oxide Ba2O 0.00

Strontium Oxide SrO 0.00

Unknown --- 0.84

Total 100.0

Trace Components ppmd

Mercury (Note B) Hg 0.081

Notes: A. By Difference

B. Mercury value is the mean plus one standard deviation using EPA’s ICR data
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

28

Exhibit 2-7 North Dakota Beulah-Zap Lignite, Freedom, ND Mine

Lignite Design Coal Analysis

Proximate Analysis Dry Basis, % As Received, %

Moisture 0.0 36.08

Ash 15.43 9.86

Volatile Matter 41.49 26.52

Fixed Carbon 43.09 27.54

Total 100.0 100.0

Ultimate Analysis Dry Basis, % As Received, %

Carbon 61.88 39.55

Hydrogen 4.29 2.74

Nitrogen 0.98 0.63

Sulfur 0.98 0.63

Chlorine 0.00 0.00

Ash 15.43 9.86

Moisture 0.00 36.08

Oxygen (Note A) 16.44 10.51

Total 100.0 100.0

Heating Value Dry Basis As Received

HHV, kJ/kg 24,254 15,391

HHV, Btu/lb 10,427 6,617

LHV, kJ/kg 23,335 14,804

LHV, Btu/lb 10,032 6,364

Hardgrove Grindability Index Not applicable

Ash Mineral Analysis %

Silica SiO2 35.06

Aluminum Oxide Al2O3 12.29

Iron Oxide Fe2O3 5.12

Titanium Dioxide TiO2 0.58

Calcium Oxide CaO 14.39

Magnesium Oxide MgO 6.61

Sodium Oxide Na2O 5.18

Potassium Oxide K2O 0.64

Sulfur Trioxide SO3 16.27

Barium Oxide Ba2O 0.56

Strontium Oxide SrO 0.27

Manganese Dioxide MnO2 0.02

Unknown --- 3.00

Total 100.0

Trace Components ppmd

 Mercury (Note B) Hg 0.116

Notes: A. By Difference

B. Mercury value is the mean plus one standard deviation using EPA’s ICR data
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

29

2.4 PRODUCT SPECIFICATIONS

To be a viable pipeline replacement fuel for natural gas, the SNG must meet certain 

specifications. 

Synthetic Natural Gas

Exhibit 2-8 lists generic specifications for domestic and commercial natural gas 

from a pipeline handbook [12

Exhibit 2-8 SNG Pipeline Requirements

]. 

Parameter Value

Heating Value, kJ/Nm3 (Btu/scf) > 35,367 (950)

Sulfur Content, kg/100 Nm3 (lb/100 scf) < 0.0023 

(0.00014)

CO2 Content, vol % < 2

Moisture Content, kg/1000 Nm3 (lb/1000 

scf) < 62.5 (3.9)

Temperature, °C (°F) < 49 (120)

As liquefied natural gas (LNG) and other non-conventional gas sources become increasingly 

prevalent, more attention is being placed on natural gas specifications and its interchangeability. 

An administrative law judge at the Federal Energy Regulatory Commission (FERC) recently 

ruled in favor of Florida Gas Transmission (FGT) setting stringent specifications on LNG 

imported through the gulf coast [13

There is a wide range of fuel quality that is acceptable to most combustion equipment, but the 

same equipment often will not handle high variability in the fuel quality. The SNG produced in 

this study falls at the low end of the acceptable quality range with HHVs ranging from 965-975 

Btu/scf, Wobbe Indices in the range of 1,265-1,275, and inert concentrations ranging from 3-4.5

percent. The primary reason for the lower quality product is the absence of higher hydrocarbons. 

The methanation process produces only methane, and the balance of the SNG is necessarily 

inerts. Pure methane has a HHV of 1,012 Btu/scf and a Wobbe Index of 1,357, which represent 

the upper limits of the methanation process.

]. The ruling set an acceptable Wobbe Index range of 1,340-

1,396 and gross heating value range of 1,025-1,110 British thermal unit per standard cubic foot

(Btu/scf). The Wobbe Index is a measure of the energy carrying capacity of a given fuel and is 

found by dividing the fuel heating value by the square root of the specific gravity (SG). Notably 

the ruling was not applied to domestic gas received into FGT’s system.

The quality of the SNG produced in this study could be enhanced in a number of ways:

• Increase the oxygen purity from 99 percent to 99.5 percent (or greater) with a 

corresponding increase in air separation unit (ASU) cost.

• Upgrade the SNG purification system (pressure swing adsorption [PSA]) by increasing 

the bed depth or adding beds in series to remove additional CO2 (again at increased cost).

Ultimately the SNG purity requirements will be dictated by project location and fuel end use. 

The quality of the product is consistent across the cases modeled in this study.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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The two general quality specifications for commercial grade ammonia are shown in 

Ammonia

Exhibit 2-9

[14

Exhibit 2-9 Ammonia Quality Requirements

]. For the co-production cases, the commercial grade specification was used as the 

refrigeration grade specification requires further purification that was deemed beyond the scope 

of these baseline cases.

Parameter

Commercial 

Grade Refrigeration Grade

Purity (min wt%) 99.5 99.98

Water (max wt%) 0.5 0.015

Inerts (max mL/g) not specified 0.1

Oil (ppm by wt) 5.0 3.0

2.5 ENVIRONMENTAL TARGETS

There are relatively few emission sources associated with the SNG and ammonia production 

plants. The primary emissions occur when the SNG is consumed, presumably in a combustiontype process, which is outside of the battery limit of this study. The plants in this study have 

several point source emissions, but consist mostly of fugitive emissions, which are also beyond 

the scope of this study. Typical emission sources include particulate matter (PM) from the coal 

pile, coal transfer operations, slag handling, and the cooling tower; fugitive emissions from 

valves and other process equipment; and emissions from emergency generators and flare stacks. 

None of these operations are included in the Aspen model, and emissions from these sources are 

not quantified.

There are some point source emissions that are modeled and accounted for in the various cases:

• Drying in the bituminous coal cases includes combustion of a slipstream of clean syngas 

and Claus plant tail gas. The hot flue gases are used to dry the coal and then exhausted to 

atmosphere.

• In the NH3 co-production cases there is a waste heat boiler that is fueled by the PSA 

purification unit purge gas. Heat is recovered from the boiler exhaust gases prior to 

venting it to atmosphere.

• In all cases a portion of the lockhopper transport gas is vented to atmosphere.

• In all non-sequestration cases the CO2-rich gas from the two-stage Selexol process is 

vented to atmosphere. This stream is compressed and stored in a saline aquifer in the 

carbon sequestration cases. 

• In all non-sequestration cases the off gas from the PSA SNG purification unit is vented to 

atmosphere. This stream is compressed and stored in a saline aquifer in the carbon 

sequestration cases.
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The only emissions reported for each case are sulfur dioxide (SO2) and CO2. In the PRB and 

lignite coal cases, there are no combustion operations so no SO2 emissions are reported. PM in 

the SNG is not released until combustion occurs and fugitive dust sources are not quantified. 

Similarly, mercury remaining in the SNG is not released to the atmosphere until combustion 

occurs. Since the fuel in the two combustion operations (coal dryer in bituminous coal cases and 

waste heat boiler in NH3 co-production cases) is void of nitrogen, and thermal oxides of nitrogen 

(NOx) formation is minimal at the temperatures of combustion, NOx is not quantified as an 

emission. 

Since mercury is a methanation catalyst poison, essentially all of the mercury must be removed 

from the gas stream. The environmental target for mercury capture is greater than 90 percent. 

Based on experience at the Eastman Chemical plant, where synthesis gas (syngas) from a 

General Electric Energy (GEE) gasifier is treated, the actual mercury removal efficiency used is 

95 percent. Sulfur-impregnated activated carbon is used by Eastman as the adsorbent in the 

packed beds operated at 30°C (86°F) and 6.2 megapascals (MPa) (900 pounds per square inch 

gage [psig]). Mercury removal between 90 and 95 percent has been reported with a bed life of 

18 to 24 months. Removal efficiencies may be even higher, but at 95 percent the measurement 

precision limit was reached. Eastman has yet to experience any mercury contamination in its 

product [15

Since momentum for carbon regulations continues to build, CO2 emissions are also reported for 

each case. Because the form of emission limits, should they be imposed, is not known, CO2

emissions are reported on a pounds per million British thermal units (lb/MMBtu) heat input to 

the gasifier basis as well as total tons per year. The emission values were used to quantify the 

impact of a carbon tax later in the report.

]. Mercury removals of greater than 99 percent can be achieved by the use of dual 

beds, i.e., two beds in series. However, this study assumes that the use of sulfur-impregnated 

carbon in a single carbon bed achieves 95 percent reduction of mercury emissions, which 

reduces the Hg content in the clean syngas to less than 0.45 ppb in all cases.

Ultimately, the environmental regulations for an SNG or SNG and ammonia co-production plant 

will be established by state and local jurisdictions. However, since the emissions profiles of 

these plants are relatively benign, it is assumed that environmental permits will be attainable.

2.6 CAPACITY FACTOR

Electric Power Research Institute (EPRI) examined the historical forced and scheduled outage 

times for IGCCs and concluded that the reliability factor (which looks at forced or unscheduled 

outage time only) for a single train IGCC (no spares) would be about 90 percent [16

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

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

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

on-stream times are around 80 percent [

]. To get the 

AF, one has to deduct the scheduled outage time. In reality the scheduled outage time differs 

from gasifier technology-to-gasifier technology, but the differences are relatively small and 

would have minimal impact on the CF.

17

Previous NETL studies utilizing IGCC technology have assumed a CF of 80 percent based on 

EPRI’s studies and Higman’s report. However, a 90 percent CF was assumed for the six gasifier 

]. The CF would be somewhat less than the on-stream 

time since most plants operate at less than full load for some portion of the operating year. 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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gasification island used in this study, which has been supported by Siemens Energy, Inc. [18

The addition of CO2 capture or an ammonia co-production facility was assumed not 

to impact the AF, nor was the addition of compression and sequestration. This assumption was 

made to enable a comparison based on the impact of capital and variable operating costs only.

Any reduction in assumed CF would further increase the FYCOP for the carbon sequestration 

cases and ammonia co-production cases as shown in the sensitivity analysis in 

]. It 

was assumed that if one of the six gasifiers stopped operation for maintenance or repair, reducing

the CF to 83 percent, the system could operate at 100 percent capacity long enough to 

compensate for the down time.

Exhibit ES-9.

2.7 RAW WATER WITHDRAWAL AND CONSUMPTION

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

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

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

to offset the water demand. The difference between demand and recycle is raw water 

withdrawal. Raw water withdrawal is the water removed from the ground or diverted from a 

surface-water source for use in the plant. Raw water consumption is also accounted for as the 

portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or 

otherwise not returned to the water source it was withdrawn from.

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

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

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

as cooling tower makeup, BFW makeup, slag handling makeup and quench system makeup. The 

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

Consumption represents the net impact of the process on the water source.

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

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

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

the balance sent to the ash ponds for evaporation.

The largest consumer of raw water in all cases is cooling tower makeup. The bituminous coal 

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

were assumed to be treated and recycled to the cooling tower. It was assumed that the PRB and 

NDL coal cases utilized a parallel cooling system with half of the turbine exhaust steam 

condensed in an air-cooled condenser and half in a water-cooled condenser. 

The design ambient wet bulb (WB) temperature of 11°C (51.5°F) at the Midwestern site was 

used to achieve a cooling water temperature of 16°C (60°F) using an approach of 5°C (8.5°F). 

The conditions of 3°C (37°F) at the Montana site and 2°C (36°F) at the North Dakota site 

(Exhibit 2-1) were used to achieve a cooling water temperature of 9°C (48°F) and 8°C (47°F), 

respectively at the two sites using an approach of 6°C (11°F). The cooling water range was 

assumed to be 11°C (20°F) for all cases. The cooling tower makeup rate was determined using 

the following:[19

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

]

• Drift losses of 0.001 percent of the circulating water flow rate
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• Blowdown losses were calculated as follows:

o Blowdown Losses = Evaporative Losses / (Cycles of Concentration - 1)

Where cycles of concentration are a measure of water quality and a mid-range 

value of 4 was chosen for this study.

The water balances presented in subsequent sections include the water demand of the major 

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

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

water consumption, again by difference.

2.8 COST ESTIMATING METHODOLOGY

The estimating methodology for capital costs, operations and maintenance costs, and CO2 TS&M 

costs are described below. The finance structure, basis for the discounted cash flow analysis, and 

first-year SNG cost calculations are also described.

2.8.1

As illustrated in 

Capital Costs

Exhibit 2-10, this study reports capital cost at four levels: Bare Erected Cost 

(BEC), Total Plant Cost (TPC), Total Overnight Cost (TOC) and Total As-spent Capital (TASC). 

BEC, TPC and TOC are “overnight” costs and are expressed in “base-year” dollars. The base 

year is the first year of capital expenditure, which for this study is assumed to be 2007. TASC is 

expressed in mixed-year, current-year dollars over the entire capital expenditure period, which is 

assumed to last five years (2007 to 2011).

Exhibit 2-10 Capital Cost Levels and their Elements

process equipment

supporting facilities

direct and indirect labor

BEC

TPC

TOC

TASC

EPC contractor services

process contingency

project contingency

preproduction costs

inventory capital

financing costs

other owner’s costs

escalation during capital expenditure period

interest on debt during capital expenditure period

Bare Erected Cost

Total Plant Cost

Total Overnight Cost

Total As-Spent Cost

BEC, TPC and TOC are all 

“overnight” costs expressed 

in base-year dollars.

TASC is expressed in mixed- year current dollars, spread 

over the capital expenditure 

period.
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The BEC

The 

comprises the cost of process equipment, on-site facilities and infrastructure that 

support the plant (e.g., shops, offices, labs, road), and the direct and indirect labor required for its 

construction and/or installation. The cost of EPC services and contingencies is not included in 

BEC. BEC is an overnight cost expressed in base-year (2007) dollars.

TPC

The 

comprises the BEC plus the cost of services provided by the engineering, procurement 

and construction (EPC) contractor and project and process contingencies. EPC services include: 

detailed design, contractor permitting (i.e., those permits that individual contractors must obtain 

to perform their scopes of work, as opposed to project permitting, which is not included here), 

and project/construction management costs. TPC is an overnight cost expressed in base-year 

(2007) dollars.

TOC

The 

comprises the TPC plus owner’s costs. TOC is an “overnight” cost, expressed in baseyear (2007) dollars and as such does not include escalation during construction or interest during 

construction. TOC is an overnight cost expressed in base-year (2007) dollars.

TASC

Cost Estimate Basis and Classification

is the sum of all capital expenditures as they are incurred during the capital 

expenditure period including their escalation. TASC also includes interest during construction. 

Accordingly, TASC is expressed in mixed, current-year dollars over the capital expenditure 

period.

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

estimated by WorleyParsons using an in-house database and conceptual estimating models. 

Costs were further calibrated using a combination of adjusted vendor-furnished and actual cost 

data from recent design projects.

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

each of the cases to ensure an accurate representation of the relative cost differences between the 

cases and accounts.

Recommended Practice 18R-97 of the Association for the Advancement of Cost Engineering 

International (AACE) describes a Cost Estimate Classification System as applied in Engineering, 

Procurement and Construction for the process industries [20

Most techno-economic studies, including this coal-to-SNG study, completed by NETL feature 

cost estimates intended for the purpose of a “Feasibility Study” (AACE Class 4). 

].

Exhibit 2-11

describes the characteristics of an AACE Class 4 Cost Estimate. Cost estimates in this study

have an expected accuracy range of -15%/+30%.

System Code-of-Accounts 

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

code-of-account structure has the advantage of grouping all reasonably allocable components of 

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

case had a facility, area, or commodity account structure been chosen instead).
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Exhibit 2-11 Features of an AACE Class 4 Cost Estimate

Project 

Definition Typical Engineering Completed Expected Accuracy

1 to 15%

plant capacity, block schematics, indicated 

layout, process flow diagrams for main process

systems, and preliminary engineered process and 

utility equipment lists

-15% to -30% on the low side, 

and +20% to +50% on the 

high side

Gasification Plant Maturity

The gasification production plant is based on commercial offerings; however, there have been 

very limited sales of these units. The costs listed reflect the “next commercial offering” level of 

cost rather than mature nth-of-a-kind (NOAK) cost. Thus, each of these cases reflects the 

expected cost for the next commercial sale of the gasification technology. 

CO2 Removal Maturity 

Pre-combustion CO2 removal from syngas streams has been proven in chemical processes with 

similar conditions to that in gasification plants in this study, and has been demonstrated at the 

Great Plains Synfuels plan and in hundreds of syngas processing plants such as ammonia, 

methanol, hydrogen, and other petrochemical plants worldwide. 

Contracting Strategy 

The estimates are based on an EPCM approach utilizing multiple subcontracts. This approach 

provides the Owner with greater control of the project, while minimizing, if not eliminating most 

of the risk premiums typically included in an Engineer/Procure/Construct (EPC) contract price. 

In a traditional lump sum EPC contract, the Contractor assumes significant financial risk for 

performance, schedule, and cost up to stipulated contractual levels. However, as a result of 

current market conditions, EPC contractors appear more unwilling to accept significant project 

completion and performance risk. Rather, the current trend appears to be a modified EPC 

approach where much of the risk remains with the Owner. Where Contractors are willing to 

accept the risk in EPC type lump-sum arrangements, it is reflected in the project cost. In today’s 

market, Contractor premiums for accepting these risks, particularly performance risk, can be 

substantial and increase the overall project costs dramatically. 

The EPCM approach used as the basis for the estimates here is anticipated to be the most likely 

contracting model for SNG/ammonia projects today. While the Owner retains the risks, the risks 

become reduced with time, as there is better scope definition at the time of contract award(s).

Estimate Scope 

The estimates represent a complete synfuels production facility, and in the co-production cases, a 

complete NH3 production facility on a generic site. 

The plant boundary limit is defined as the total plant facility within the “fence line” including 

coal receiving and water supply system, but terminating at the high voltage side of the main 

power transformers and the compression of the SNG. The single exception to the fence line limit 

is in the carbon sequestration cases where costs are included for TS&M of the CO2.
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Capital Costs 

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

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

and the respective models are maintained by WorleyParsons as part of a commercial gasification 

design base of experience for similar equipment in the company’s range of power and process 

projects. A reference bottoms-up estimate for each major system provides the basis for the 

estimating models.

Other key estimate considerations include the following:

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

Gulf Coast and the labor has been factored to Midwest. The basis for the factors is the 

PAS, Inc. (PAS) “Merit Shop Wage & Benefit Survey,” which is published annually.

Based on the data provided in PAS, WorleyParsons used the weighted average payroll 

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

PAS presents information for eight separate regions. For this study, Region 5 (IL, IN, 

MI, MN, OH, and WI) was selected. The weighted average rate for Region 8 (CO, MT, 

ND, SD, UT, and WY) is within one-half of one percent of that for Region 5. Given the 

accuracy limits of the studies, the differential is insignificant. 

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

craft labor available locally.

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

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

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

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

• The estimates are based on a greenfield sites. 

• The sites are considered to be Seismic Zone 1, relatively level, and free from hazardous 

materials, archeological artifacts, or excessive rock. Soil conditions are considered 

adequate for spread footing foundations. The soil bearing capability is assumed adequate 

such that piling is not needed to support the foundation loads. 

• Costs are limited to within the “fence line,” terminating at the high voltage side of the 

main power transformers with the exception of costs included for TS&M of CO2 in all 

carbon sequestration cases.

• Engineering and Construction Management are estimated at 10 percent of BEC. These 

costs consist of all home office engineering and procurement services as well as field 

construction management costs. Site staffing generally includes a construction manager, 

resident engineer, scheduler, and personnel for project controls, document control, 

materials management, site safety, and field inspection.

• All capital costs are presented as “Overnight Costs” in June 2007 dollars. Escalation to 

period-of-performance is specifically excluded in the TPC. However, the CCF used to 

calculate FYCOP includes capital cost escalation during construction of 3.6 percent.
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Price Fluctuations

During the course of this study, the prices of equipment and bulk materials fluctuated quite 

substantially. Some reference quotes pre-dated the 2007 year cost basis while others were 

received post-2007. All vendor quotes used to develop these estimates were adjusted to June 

2007 dollars accounting for the price fluctuations. Adjustments of costs pre-dating 2007 

benefitted from a vendor survey of actual and projected pricing increases from 2004 through 

mid-2007 that WorleyParsons conducted for another project. The results of that survey were 

used to validate/recalibrate the corresponding escalation factors used in the conceptual 

estimating models. The more recent economic down turn has resulted in a reduction of 

commodity prices such that many price indices have similar values in January 2010 compared to 

June 2007. For example, the Chemical Engineering Plant Cost Index was 532.7 in June 2007 

and 532.9 in January 2010, and the Gross Domestic Product Chain-type Price Index was 106.7 

on July 1, 2007 and 110.0 on January 1, 2010. While these overall indices are nearly constant, it 

should be noted that the cost of individual equipment types may still deviate from the June 2007 

reference point.

Exclusions

The capital cost estimate includes all anticipated costs for equipment and materials, installation 

labor, professional services (Engineering and Construction Management), and contingency. The 

following items are excluded from the capital costs:

• Escalation to period-of-performance

• Owner’s costs – these are accounted for separately and are described below.

• All taxes, with the exception of payroll and property taxes (property taxes are included 

with the fixed O&M costs)

• Site specific considerations – including, but not limited to, seismic zone, accessibility, 

local regulatory requirements, excessive rock, piles, laydown space, etc. 

• Labor incentives in excess of a 5-10s

• Additional premiums associated with an EPC contracting approach 

Contingency

Process and project contingencies are included in estimates to account for unknown costs that are 

omitted or unforeseen due to a lack of complete project definition and engineering. 

Contingencies are added because experience has shown that such costs are likely, and expected, 

to be incurred even though they cannot be explicitly determined at the time the estimate is 

prepared. 

Capital cost contingencies do not cover uncertainties or risks associated with

• scope changes

• changes in labor availability or productivity

• delays in equipment deliveries

• changes in regulatory requirements

• unexpected cost escalation

• performance of the plant after startup (e.g., availability, efficiency)
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Process Contingency

Process contingency is intended to compensate for uncertainty in cost estimates caused by 

performance uncertainties associated with the development status of a technology. Process 

contingencies are applied to each plant section based on its current technology status.

As shown in Exhibit 2-12, AACE International Recommended Practice 16R-90 provides 

guidelines for estimating process contingency based on EPRI philosophy [21

Process contingencies have been applied to the estimates in this study as follows:

].

• Gasifiers and Syngas Coolers – 15 percent on all cases – next-generation commercial 

offering

• Two Stage Selexol – 20 percent on all cases - unproven technology at commercial 

scale

• Methanation Process – 10 percent on all cases – unproven technology at commercial 

scale

• Mercury Removal – 5 percent on all cases – minimal commercial scale experience in 

gasification applications

• Instrumentation and Controls – 5 percent for integration issues

Exhibit 2-12 AACE Guidelines for Process Contingency

Technology Status Process Contingency

(% of Associated Process Capital)

New concept with limited data 40+

Concept with bench-scale data 30-70

Small pilot plant data 20-35

Full-sized modules have been operated 5-20

Process is used commercially 0-10

Process contingency is typically not applied to costs that are set equal to a research goal or 

programmatic target since these values presume to reflect the total cost.

Project Contingency

AACE 16R-90 states that project contingency for a “budget-type” estimate (AACE Class 4 or 5) 

should be 15 to 30 percent of the sum of BEC, EPC fees and process contingency. This was 

used as a general guideline, but some project contingency values outside of this range occur 

based on WorleyParsons’ in-house experience.
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Owner’s Costs

Exhibit 2-13 explains the estimation method for owner’s costs. With some exceptions, the 

estimation method follows guidelines in Sections 12.4.7 to 12.4.12 of AACE International 

Recommended Practice No. 16R-90 [21]. The Electric Power Research Institute’s “Technical 

Assessment Guide (TAG®) – Power Generation and Storage Technology Options” also has 

guidelines for estimating owner’s costs. The EPRI and AACE guidelines are very similar. In 

instances where they differ, this study has sometimes adopted the EPRI approach.
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Exhibit 2-13 Owner’s Costs Included in TOC

Owner’s 

Cost Estimate Basis

Prepaid 

Royalties

Any technology royalties are assumed to be included in the associated equipment cost, and thus are not included as an owner’s

cost.

Preproduction 

(Start-Up) 

Costs

• 6 months operating labor

• 1 month maintenance materials at full capacity

• 1 month non-fuel consumables at full capacity

• 1 month waste disposal 

• 25% of one month’s fuel cost at full capacity

• 2% of TPC

Compared to AACE 16R-90, this includes additional costs for operating labor (6 months versus 1 month) to cover the cost of 

training the plant operators, including their participation in startup, and involving them occasionally during the design and 

construction. AACE 16R-90 and EPRI TAG® differ on the amount of fuel cost to include; this estimate follows EPRI.

Working 

Capital

Although inventory capital (see below) is accounted for, no additional costs are included for working capital.

Inventory 

Capital

• 0.5% of TPC for spare parts

• 60 day supply (at full capacity) of fuel. Not applicable for natural gas.

• 60 day supply (at full capacity) of non-fuel consumables (e.g., chemicals and catalysts) that are stored on site. Does not 

include catalysts and adsorbents that are batch replacements such as WGS, COS, and SCR catalysts and activated carbon.

AACE 16R-90 does not include an inventory cost for fuel, but EPRI TAG® does.

Land • $3,000/acre (300 acres for IGCC and PC, 100 acres for NGCC)

Financing 

Cost

• 2.7% of TPC

This financing cost (not included by AACE 16R-90) covers the cost of securing financing, including fees and closing costs but 

not including interest during construction (or AFUDC). The “rule of thumb” estimate (2.7% of TPC) is based on a 2008 

private communication with a capital services firm.
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Owner’s 

Cost Estimate Basis

Other 

Owner’s 

Costs

• 15% of TPC

This additional lumped cost is not included by AACE 16R-90 or EPRI TAG®. The “rule of thumb” estimate (15% of TPC) is 

based on a 2009 private communication with WorleyParsons. Significant deviation from this value is possible as it is very site 

and owner specific. The lumped cost includes:

- Preliminary feasibility studies, including a Front-End Engineering Design (FEED) study

- Economic development (costs for incentivizing local collaboration and support)

- Construction and/or improvement of roads and/or railroad spurs outside of site boundary

- Legal fees

- Permitting costs

- Owner’s engineering (staff paid by owner to give third-party advice and to help the owner oversee/evaluate the work of 

the EPC contractor and other contractors)

- Owner’s contingency (Sometimes called “management reserve”, these are funds to cover costs relating to delayed startup, 

fluctuations in equipment costs, unplanned labor incentives in excess of a five-day/ten-hour-per-day work week. Owner’s 

contingency is NOT a part of project contingency.)

This lumped cost does NOT include:

- EPC Risk Premiums (Costs estimates are based on an Engineering Procurement Construction Management approach 

utilizing multiple subcontracts, in which the owner assumes project risks for performance, schedule and cost)

- Transmission interconnection: the cost of interconnecting with power transmission infrastructure beyond the plant busbar.

- Taxes on capital costs: all capital costs are assumed to be exempt from state and local taxes.

- Unusual site improvements: normal costs associated with improvements to the plant site are included in the bare erected 

cost, assuming that the site is level and requires no environmental remediation. Unusual costs associated with the 

following design parameters are excluded: flood plain considerations, existing soil/site conditions, water discharges and 

reuse, rainfall/snowfall criteria, seismic design, buildings/enclosures, fire protection, local code height requirements, noise 

regulations.
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2.8.2

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

those charges associated with operating and maintaining the plants over their expected life. 

These costs include: 

Operations and Maintenance Costs

• Operating labor

• Maintenance – material and labor

• Administrative and support labor

• Consumables

• Fuel

• Waste disposal

• Co-product or by-product credit (that is, a negative cost for any by-products sold)

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

production, and variable O&M, which is proportional to product production. 

Operating Labor

Operating labor cost was determined based on of the number of operators required for each 

specific case. The average base labor rate used to determine annual cost is $34.65/hour (hr) in 

2007 dollars. The associated labor burden is estimated at 30 percent of the base labor rate.

All cases have two skilled operators, one foreman, and three laboratory technician positions. 

The co-production plants have 13 operator positions, whereas the SNG only plants have 12 

operator positions. This differs from Volumes 1 and 3 of the Baseline Series, which use nine 

operator positions for the non-capture cases and ten for the capture cases. The number of the 

other labor personnel remains the same. 

Maintenance Material and Labor

Maintenance cost was evaluated on the basis of relationships of maintenance cost to initial 

capital cost. This represents a weighted analysis in which the individual cost relationships were 

considered for each major plant component or section.

Administrative and Support Labor

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

O&M labor.

Consumables

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

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

operating hours. 

Quantities for major consumables such as fuel were taken from technology-specific heat and 

mass balance diagrams developed for each plant application. Other consumables were evaluated 

on the basis of the quantity required using reference data. 
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The quantities for initial fills and daily consumables were calculated on a 100 percent operating 

capacity basis. The annual cost for the daily consumables was then adjusted to incorporate the 

annual plant operating basis, or CF. 

Initial fills of the consumables, fuels and chemicals, are different from the initial chemical 

loadings, which are included with the equipment pricing in the capital cost.

Waste Disposal

Waste quantities and disposal costs were determined similarly to the consumables. The slag and 

spent ZnO sorbent from each case are considered wastes with disposal costs of $17.89/tonne 

($16.23/ton). The carbon used for mercury control is considered a hazardous waste with disposal 

cost of $919/tonne ($834/ton). 

Co-Products and By-Products 

The primary products in this study are SNG in all cases and ammonia in the co-production cases. 

The by-products include sulfur, electricity, and potentially CO2. Due to the variable 

marketability of the sulfur, no credit or disposal cost was used. The electricity produced in 

excess of internal requirements was assumed sold on the open market at a price of 

$58/megawatt-hour (MWh). CO2 was assumed to be a waste product that is either vented to 

atmosphere or compressed and sequestered with the associated costs. A sensitivity analysis was 

done to determine the economic impact of selling the CO2 for enhanced oil recovery (EOR) at 

one extreme and debiting the project for CO2 emissions assuming a carbon tax at the other 

extreme.

It should be noted that by-product credits and/or disposal costs could potentially be an additional 

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

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

in the plant costs to produce a particular co-product. Slag is a potential by-product in certain 

markets and would have potential marketability. However, as stated above, the slag is 

considered waste in this study with a concomitant disposal cost.

2.8.3

For those cases that feature carbon sequestration, the capital and operating costs for CO2 TS&M 

were independently estimated by NETL. Those costs were converted to a FYCOP and combined 

with the plant capital and operating costs to produce an overall FYCOP. The TS&M costs were 

initially levelized over a 30-year period using the methodology described in the next subsection 

of this report, and subsequently converted to first year costs by dividing by the levelization 

factor.

CO2 Transport, Storage, and Monitoring

CO2 TS&M costs were estimated based on the following assumptions:

• CO2 is supplied to the pipeline at the plant fence line at a pressure of 15.3 MPa (2,215 

psia). The CO2 product gas composition varies in the cases presented, but is expected to 

meet the specification described in Exhibit 2-14. A glycol dryer located near the midpoint of the compression train is used to meet the moisture specification.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

44

Exhibit 2-14 CO2 Pipeline Specification

Parameter Units Parameter Value

Inlet Pressure MPa (psia) 15.3 (2,215)

Outlet Pressure MPa (psia) 10.4 (1,515)

Inlet Temperature °C (°F) 35 (95)

N2 Concentration ppmv < 300

O2 Concentration ppmv < 40

Ar Concentration ppmv < 10

H2O Concentration ppmv < 150

• The CO2 is transported 80 kilometers (km) (50 miles) via pipeline to a geologic 

sequestration field for injection into a saline formation.

• The CO2 is transported and injected as a supercritical (SC) fluid in order to avoid twophase flow and achieve maximum efficiency [22]. The pipeline is assumed to have an 

outlet pressure (above the SC pressure) of 8.3 MPa (1,200 psia) with no recompression 

along the way. Accordingly, CO2 flow in the pipeline was modeled to determine the pipe 

diameter that results in a pressure drop of 6.9 MPa (1,000 psi) over an 80 km (50 mile) 

pipeline length [23

• The saline formation is at a depth of 1,239 m (4,055 ft) and has a permeability of 22 

millidarcy (md) (22 μm2

) and formation pressure of 8.4 MPa (1,220 psig) [

]. (Although not explored in this study, the use of boost compressors 

and a smaller pipeline diameter could possibly reduce capital costs for sufficiently long 

pipelines.) The diameter of the injection pipe will be of sufficient size that frictional 

losses during injection are minimal and no booster compression is required at the wellhead in order to achieve an appropriate down-hole pressure, with hydrostatic head 

making up the difference between the injection and reservoir pressure.

24

24

]. This is 

considered an average storage site and requires roughly one injection well for each 9,360 

tonnes (10,320 tons) of CO2 injected per day [ ]. The assumed aquifer characteristics 

are tabulated in Exhibit 2-15.

The cost metrics utilized in this study provide a best estimate of TS&M costs for a “typical” 

sequestration project, and may vary significantly based on variables such as terrain to be crossed 

by the pipeline, reservoir characteristics, and number of land owners from which sub-surface 

rights must be acquired. Raw capital and operating costs are derived from detailed cost metrics 

found in the literature, escalated to June 2007-year dollars using appropriate price indices. These 

costs were then verified against values quoted by industrial sources where possible. Where 

regulatory uncertainty exists or costs are undefined, such as liability costs and the acquisition of 

underground pore volume, analogous existing policies were used for representative cost 

scenarios.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Exhibit 2-15 Deep Saline Aquifer Specification

Parameter Units Base Case

Pressure MPa (psi) 8.4 (1,220)

Thickness m (ft) 161 (530)

Depth m (ft) 1,236 (4,055)

Permeability md (μm2) 22 (22)

Pipeline Distance Km (miles) 80 (50)

Injection Rate per Well Tonne (ton) CO2/day 9,360 (10,320)

The following subsections describe the sources and methodology used for each metric.

Cost Levelization and Conversion to First Year Costs

Capital and operating costs were levelized over a 35-year period (30-year operational period plus 

5-year capital expenditure period) and include both a 20 percent process contingency and 30

percent project contingency. 

In several areas, such as Pore Volume Acquisition, Monitoring, and Liability, cost outlays occur 

over a longer time period, up to 100 years. In these cases a capital fund is established based on 

the net present value of the cost outlay, and this fund is then levelized similar to the other costs.

First year costs are calculated by dividing the levelized cost by the levelization factor. It is the 

first year cost that is used in this study.

Transport Costs

CO2 transport costs are divided into three categories: pipeline costs, related capital expenditures, 

and O&M costs.

Pipeline costs are derived from data published in the Oil and Gas Journal’s (O&GJ) annual 

Pipeline Economics Report for existing natural gas, oil, and petroleum pipeline project costs 

from 1991 to 2003. These costs are expected to be analogous to the cost of building a CO2

pipeline, as noted in various studies [22,24,25

25

]. The University of California performed a 

regression analysis to generate cost curves from the O&GJ data for: (1) Pipeline Materials, (2) 

Direct Labor, (3) Indirect Costs, and (4) Right-of-way acquisition, with each represented as a 

function of pipeline length and diameter [ ]. These cost curves were escalated to the June 2007 

year dollars used in this study.

Related capital expenditures were based on the findings of a previous study funded by NETL, 

Carbon Dioxide Sequestration in Saline Formations – Engineering and Economic Assessment

[24]. This study utilized a similar basis for pipeline costs (O&GJ Pipeline cost data up to the 

year 2000), but added a CO2 surge tank and pipeline control system to the project. 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

46

Transport O&M costs were assessed using metrics published in a second NETL sponsored report 

entitled Economic Evaluation of CO2 Storage and Sink Enhancement Options [22]. This study 

was chosen due to the reporting of O&M costs in terms of pipeline length, whereas the other 

studies mentioned above either (a) do not report operating costs, or (b) report them in absolute 

terms for one pipeline, as opposed to a length- or diameter-based metric. 

Storage Costs

Storage costs were divided into five categories: (1) Site Screening and Evaluation, (2) Injection 

Wells, (3) Injection Equipment, (4) O&M Costs, and (5) Pore Volume Acquisition. With the 

exception of Pore Volume Acquisition, all of the costs were obtained from Economic Evaluation 

of CO2 Storage and Sink Enhancement Options [22]. These costs include all of the costs 

associated with determining, developing, and maintaining a CO2 storage location, including site 

evaluation, well drilling, and the capital equipment required for distributing and injecting CO2.

Pore Volume Acquisition costs are the costs associated with acquiring rights to use the subsurface volume where the CO2 will be stored, i.e. the pore space in the geologic formation. 

These costs were based on recent research by Carnegie Mellon University, which examined 

existing sub-surface rights acquisition as it pertains to natural gas storage [26

Liability Protection

]. The regulatory 

uncertainty in this area combined with unknowns regarding the number and type (private or 

government) of property owners, require a number of “best engineering judgment” decisions to 

be made. In this study it was assumed that long-term lease rights were acquired from the 

property owners in the projected CO2 plume growth region for a nominal fee, and that an annual 

“rent” was paid when the plume reached each individual acre of their property for a period of up 

to 100 years from the injection start date. The present value of the life cycle pore volume costs 

are assessed at a 10 percent discount rate and a capital fund is set up to pay for these costs over 

the 100 year rent scenario.

Liability Protection addresses the fact that if damages are caused by injection and long-term 

storage of CO2, the injecting party may bear financial liability. Several types of liability 

protection schemes have been suggested for CO2 storage, including Bonding, Insurance, and 

Federal Compensation Systems combined with either tort law (as with the Trans-Alaska Pipeline 

Fund), or with damage caps and preemption, as is used for nuclear energy under the Price 

Anderson Act [27]. However, at present, a specific liability regime has yet to be dictated either 

at a Federal or (to our knowledge) State level. However, certain state governments have enacted 

legislation, which assigns liability to the injecting party, either in perpetuity (Wyoming) or until 

ten years after the cessation of injection operations, pending reservoir integrity certification, at 

which time liability is turned over to the state (North Dakota and Louisiana) [28,29,30

Liability costs assume that a bond must be purchased before injection operations are permitted in 

order to establish the ability and good will of an injector to address damages where they are 

deemed liable. A figure of five million dollars was used for the bond based on the Louisiana 

fund level. This bond level may be conservatively high, in that the Louisiana fund covers both 

liability and monitoring, but that fund also pertains to a certified reservoir where injection 

]. In the 

case of Louisiana, a trust fund totaling five million dollars is established over the first ten years 

(120 months) of injection operations for each injector. This fund is then used by the state for 

CO2 monitoring and, in the event of an at-fault incident, damage payments. 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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operations have ceased, having a reduced risk compared to active operations. The bond cost was 

not escalated.

Monitoring Costs

Monitoring costs were evaluated based on the methodology set forth in the IEA Greenhouse Gas 

(GHG) R&D Programme’s Overview of Monitoring Projects for Geologic Storage Projects 

report [31

2.8.4

]. In this scenario, operational monitoring of the CO2 plume occurs over thirty years 

(during plant operation) and closure monitoring occurs for the following fifty years (for a total of 

eighty years). Monitoring is via electromagnetic (EM) survey, gravity survey, and periodic 

seismic survey; EM and gravity surveys are ongoing while seismic survey occurs in years 1, 2, 5, 

10, 15, 20, 25, and 30 during the operational period, then in years 40, 50, 60, 70, and 80 after 

injection ceases.

The global economic assumptions are listed in 

Finance Structure, Discounted Cash Flow Analysis, and First-Year Cost of SNG

Exhibit 2-16. 

The finance structure was chosen based on the assumption of a high-risk fuels project. Exhibit 

2-17 describes the finance structure that was assumed. This finance structure was based on 

information presented in a 2008 NETL report, "Recommended Project Finance Structures for the 

Economic Analysis of Fossil-Based Energy Projects”, based on interviews with project 

developers/owners, financial organizations and law firms.

Exhibit 2-16 Global Economic Assumptions

Parameter Value

TAXES

Income Tax Rate 38% (Effective 34% Federal, 6% State)

Capital Depreciation 20 years, 150% declining balance

Investment Tax Credit 0%

Tax Holiday 0 years

CONTRACTING AND FINANCING 

TERMS

Contracting Strategy

Engineering Procurement Construction 

Management (owner assumes project risks for 

performance, schedule and cost)

Type of Debt Financing Non-Recourse (collateral that secures debt is 

limited to the real assets of the project)

Repayment Term of Debt 15 years

Grace Period on Debt Repayment 0 years

Debt Reserve Fund None

ANALYSIS TIME PERIODS

Capital Expenditure Period 5 Years

Operational Period 30 years

Economic Analysis Period (used for IRROE) 35 Years (capital expenditure period plus 

operational period)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Parameter Value

TREATMENT OF CAPITAL COSTS

Capital Cost Escalation During Capital 

Expenditure Period (nominal annual rate) 3.6%1

Distribution of Total Overnight Capital over the 

Capital Expenditure Period (before escalation) 10%, 30%, 25%, 20%, 15%

Working Capital zero for all parameters

% of Total Overnight Capital that is Depreciated

100% (this assumption introduces a very small 

error even if a substantial amount of TOC is 

actually non-depreciable)

ESCALATION OF OPERATING 

REVENUES AND COSTS

Escalation of COP (revenue), O&M Costs, and 

Fuel Costs (nominal annual rate) 3.0%2

Exhibit 2-17 Financial Structure for High Risk Fuels Projects

Type of 

Security

% of Total Current (Nominal) 

Dollar Cost

Weighted Current 

(Nominal) Cost

After Tax 

Weighted Cost 

of Capital

Debt 50 9.5% 4.75%

Equity 50 20% 10%

Total 100 N/A 14.75% 12.94%

The NETL Power Systems Financial Model (PSFM) is a nominal-dollar3

9

(current dollar) 

discounted cash flow (DCF) analysis tool [ ]. As explained below, the PSFM was used to 

calculate first-year cost of production (FYCOP)

4

. 

• The FYCOP

 

1 A nominal average annual rate of 3.6% is assumed for escalation of capital costs during construction. This rate is 

equivalent to the nominal average annual escalation rate for process plant construction costs between 1947 and 2008 

according to the Chemical Engineering Plant Cost Index.

is the revenue received by the generator per net unit of production (bbl, 

MMBtu, kg, etc.) during the plant’s first year of operation. To calculate the first-year 

COP, the PSFM was used to determine a “base-year” (2007) COP that, when escalated at 

2 An average annual inflation rate of 3.0% is assumed. This rate is equivalent to the average annual escalation rate 

between 1947 and 2008 for the U.S. Department of Labor's Producer Price Index for Finished Goods, the so-called 

"headline" index of the various Producer Price Indices. (The Producer Price Index for the Electric Power Generation 

Industry may be more applicable, but that data does not provide a long-term historical perspective since it only dates 

back to December 2003.)

3 Since the analysis takes into account taxes and depreciation, a nominal dollar basis is preferred to properly reflect 

the interplay between depreciation and inflation.

4 For this calculation, “cost of product” is somewhat of a misnomer because from the production plant’s perspective 

it is actually the “price” received for the product generated. However, since the price paid to the plant for the 

product is ultimately charged to the end user, from the customer’s perspective it is part of the cost of product.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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an assumed nominal annual general inflation rate of 3 percent5, provided the stipulated 

internal rate of return on equity over the entire economic analysis period (capital 

expenditure period plus thirty years of operation). Since this analysis assumes that COP

increases over the economic analysis period at the nominal annual general inflation rate, 

it remains constant in real terms and the first-year COP is equivalent to the base-year 

COP when expressed in base-year (2007) dollars. 

Since 2007 is the first year of the capital expenditure period it is also the base year for the 

economic analysis. Accordingly, all costs are expressed in base-year (June 2007) dollars except 

for TASC, which is expressed in mixed-year, current dollars.

All capital costs included in this analysis, including project development and construction costs, 

are assumed to be incurred during the capital expenditure period. The plants are assumed to 

have a capital expenditure period of five years. Since the plants begin expending capital in the 

base year (2007), this means that the analysis assumes that they begin operating in 2012. In 

addition to the capital expenditure period, the economic analysis considers thirty years of 

operation.

Estimating First-Year COE with Capital Charge Factors

For scenarios that adhere to the global economic assumptions listed in Exhibit 2-16 and utilize 

the finance structure listed in Exhibit 2-17, the following simplified equation can be used to 

estimate first-year COP as a function of TOC, fixed O&M, variable O&M (including fuel), 

capacity factor and net production. The equation requires the application of the capital charge 

factor (CCF) listed in Exhibit 2-18. This first year CCF is valid only for the global economic 

assumptions listed in Exhibit 2-16, the stated finance structure, and the stated capital expenditure 

period.

Exhibit 2-18 Economic Parameters for FYCOP Calculation

High Risk Fuels 

Financial Structure

First Year Capital Charge Factor 0.2449

All factors in the first-year COP equation are expressed in base-year dollars. The base year is the 

first year of capital expenditure, which for this study is assumed to be 2007. As shown in

Exhibit 2-16, all factors (COP, O&M and fuel) are assumed to escalate at a nominal annual 

 

5 This nominal escalation rate is equal to the average annual inflation rate between 1947 and 2008 for the U.S. 

Department of Labor’s Producer Price Index for Finished Goods. This index was used instead of the Producer Price 

Index for the Electric Power Generation Industry because the Electric Power Index only dates back to December 

2003 and the Producer Price Index is considered the “headline” index for all of the various Producer Price Indices.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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general inflation rate of 3.0 percent. Accordingly, all first-year costs (COP and O&M) are 

equivalent to base-year costs when expressed in base-year (2007) dollars.

of product generated

annual quantity

costs

variableoperating

first year

costs

fixed operating

first year

capital charge

first year

First Year COP

+ +

=

(CF)(Qty)

(CCF)(TOC) OC (CF)(OC ) First Year COP + FIX + VAR =

where:

First Year COP= current-dollar first-year cost of product expressed in base-year dollars 

per unit of product ($/bbl, $/kg, $/MMBtu, etc.))

CCF = capital charge factor taken from Exhibit 2-18 that matches the 

applicable finance structure and capital expenditure period

TOC = total overnight capital, expressed in base-year dollars

OCFIX = the sum of all fixed annual operating costs, expressed in base-year 

dollars

OCVAR = the sum of all variable annual operating costs, including fuel at 100

percent capacity factor, expressed in base-year dollars

CF = plant capacity factor, assumed to be constant over the operational 

period

Qty = annual quantity of product generated at 100 percent capacity factor

2.8.5

Historically, the price of ammonia has been predominantly dependent on ammonia demand. 

However, recent volatility of natural gas prices has caused the price of ammonia to become 

increasingly dependent on the cost of natural gas. A report issued by the USDA found that the 

price correlation between natural gas and ammonia was weak at 0.17 to 0.07 prior to 2000, but 

became strong at 0.8 to 0.7 as natural gas prices rose after 2000 [

Ammonia Price

32

Exhibit 2-19

]. The same report states that 

from 2000 to 2006, rising natural gas prices resulted in a decrease of U.S. ammonia production 

by 44 percent while ammonia prices paid by farmers increased by 130 percent. 

shows historic prices of natural gas and ammonia [32]. This trend is expected to continue as 

natural gas prices are expected to rise. Exhibit 2-20 shows AEO 2009 price projections to 2030 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

51

for residential, industrial and electric power natural gas users along with high and low economic 

growth scenarios shown as range bars [33].

Exhibit 2-19 Monthly U.S. Prices of Natural Gas and Ammonia

A cost correlation between the historic prices of U.S. industrial use natural gas ($/MMBtu) and 

the price of ammonia paid by U.S. farmers (dollars per ton [$/ton]) was developed to estimate the 

selling price of ammonia in the co-production facilities [33,34

Exhibit 2-21

]. The correlation was made to the 

ammonia price paid by U.S. farmers because 84 percent of global ammonia production is utilized 

by the fertilizer industry. illustrates ammonia end use [35

The selling price of ammonia serves as a basis to adequately compare if the synergies created 

from the co-production facility enhance or serve to detriment the FYCOP of SNG. 

]. Non-fertilizer 

applications account for only 16 percent of worldwide ammonia. Direct application of ammonia 

for fertilization accounts for 3 percent of the total production.

Exhibit 2-22

shows the data trend for U.S. farmer ammonia prices and industrial natural gas prices. Because 

other secondary factors such as ammonia supply and demand and cost differences across regions 

influence the cost of ammonia, the trend is not entirely linear. However, as natural gas prices 

rise, so does the cost of ammonia.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Exhibit 2-20 Price Projections for Natural Gas Consumers

Exhibit 2-21 Global Ammonia Utilization

0

2

4

6

8

10

12

14

16

1985 1990 1995 2000 2005 2010 2015 2020 2025 2030 2035

Natural Gas Price (2007$/MMBtu)

Year

Residential NG Price

Industrial NG Price

Electric Power NG Price
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Exhibit 2-22 U.S. Farmer Ammonia and Industrial Natural Gas Prices

The following correlation was derived from Exhibit 2-22:

This correlation was used to relate the first year price of ammonia to the first year cost of 

synthetic natural gas.

0

100

200

300

400

500

600

0 1 2 3 4 5 6 7 8 9 10

Ammonia Prices Paid by U.S. Farmers (2007$/ton)

Cost of Industrial NG (2007$/MMBtu)

Farmer Price Correlation
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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3.

Six SNG only and two SNG and ammonia co-production configurations were evaluated and the 

major process area descriptions are presented in this section. Each design is based on a marketready technology that is assumed to be commercially available to support startup in the near 

term.

SNG AND SNG AND AMMONIA CO-PRODUCTION FACILITIES

All eight cases are based on the Siemens gasifier using either bituminous, PRB, or lignite coal, 

with and without carbon sequestration. As discussed in Section 2, the thermal input for the six 

SNG only cases varies by coal type based on vendor input [18]. The output of SNG for the coproduction cases is reduced because a portion of the syngas is used to produce 2,000 tonnes/day 

(2,204 tons/day) of ammonia.

The evaluation scope included developing heat and mass balances and estimating plant 

performance. Equipment lists were developed for each design to support plant capital and 

operating cost estimates. The evaluation basis details, including site ambient conditions, fuel 

composition and environmental targets, were provided in Section 2. Section 3.1 covers general 

information for the major process areas of the SNG only and co-production plants.

3.1 MAJOR PROCESS AREAS

All eight cases have process areas, which are common to each plant configuration such as coal 

receiving and storage, coal drying, oxygen supply, gas cleanup, power generation, etc. As 

detailed descriptions of these process areas for each case would be burdensome and repetitious, 

they are presented in this section for general background information, where information is 

present that is specific to a particular case or set of cases it is explicitly stated.

3.1.1

The function of the Coal Receiving and Storage system is to provide the equipment required for 

unloading, conveying, preparing, and storing the fuel delivered to the plant. The scope of the 

system is from the coal conveyor receiving hoppers up to the slide gate valves at the outlet of the 

coal storage silos.

Coal Receiving and Storage

Operation Description – The lignite plants are located at the minemouth and coal is delivered to 

the plant from the mine by conveyor to the plant storage and reclaim piles. Coal is delivered to 

the Illinois No. 6 and PRB plants by 100-car unit trains comprised of 91 tonne (100 ton) rail cars. 

The unloading is done by a trestle bottom dumper, which unloads the coal into two receiving 

hoppers. 

Coal from the reclaim pile is fed directly into a vibratory feeder. The 8 centimenter (cm) x 0 

(3" x 0) coal from the feeder is discharged onto a belt conveyor. Two conveyors with an 

intermediate transfer tower are assumed to convey the coal to the coal stacker, which transfer the 

coal to either the long-term storage pile or to the reclaim area. The conveyor passes under a 

magnetic plate separator to remove tramp iron and then to the reclaim pile.

The reclaimer loads the coal into two vibratory feeders located in the reclaim hopper under the 

pile. The feeders transfer the coal onto a belt conveyor that transfers the coal to the coal surge 

bin located in the crusher tower. The coal is reduced in size to 3 cm x 0 (11⁄4" x 0) by the 

crusher. A conveyor then transfers the coal to a transfer tower. In the transfer tower the coal is 

routed to the tripper, which loads the coal into one of three silos. Two sampling systems are 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

56

supplied: the as-received sampling system and the as-fired sampling system. Data from the 

analyses are used to support the reliable and efficient operation of the plant.

3.1.2

Reduction in coal moisture content improves the efficiency of dry-feed gasifiers, but there is in 

addition a materials handling requirement. It is necessary to reduce most, if not all, of the 

surface moisture for coal transport properties to be acceptable. Coal moisture consists of two 

components, surface moisture and inherent moisture. Low rank coals have higher inherent 

moisture content and total moisture content than bituminous and other high rank coals and two 

different drying schemes are used due to this difference. After drying the coal is drawn from the 

surge hoppers and fed through a pressurization lock hopper system to a dense phase pneumatic 

conveyor, which uses CO2 from the Selexol unit that is further pressurized and used to convey 

the coal to the gasifiers.

Coal Drying

The coal is simultaneously crushed and dried in the coal mill then delivered to a surge hopper 

with an approximate 2-hour capacity. The drying medium is provided by combining off-gas 

from the Claus plant tail gas treatment unit (TGTU) and a slipstream of clean syngas and passing 

them through an incinerator. The incinerator flue gas, with an oxygen content of 6 volume 

percent (vol%), is then used to dry the coal in the mill. The removed moisture is vented to 

atmosphere through the plant stack along with the incinerator flue gas. The bituminous coal in 

this study is dried to 6 percent from 11.12 percent [

Bituminous Coal

18].

No specific coal drying technique is recommended by Siemens either in publications or their 

response to modeling questions. Therefore, the WTA drying process was chosen primarily based 

on a previous analysis done for the Shell gasification system that is equally applicable to a 

Siemens gasification system. In a recent GTC paper, Shell examined the WTA process for 

drying low rank coals and considered two cases [

Low Rank Coals

36

1) Case 1: Lignite coal dried from 53 to 12 percent

]: 

2) Case 2: Subbituminous coal dried from 30 to 6 percent

For the Siemens gasification cases it is assumed that the subbituminous coal is dried to 6 percent 

moisture and the lignite to 12 percent moisture [18]. Coal drying options that were evaluated 

prior to selecting the WTA process included:

• Option 1: Use conventional IGCC coal drying methods, which consist of deriving heat 

from the combustion of natural gas and/or syngas and using the flue gas either directly or 

indirectly, by heating a nitrogen stream, for use in drying the coal. Some examples 

include the following:

o At the Buggenum facility bituminous coal is ground in a conventional roller mill 

and simultaneously dried using a heated inert recycle gas stream that carries the 

evaporated water from the system as it sweeps the PC through an internal, rotating 

classifier. The inert gas generator is fueled by the in-line combustion of treated 

syngas. Excess gas is vented on pressure control [37].
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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o At the Puertollano facility, coal is ground in mills using nitrogen for drying from 

10 percent to less than 2 percent moisture. The drying circuit is heated to about 

250°C (482°F) by intermediate-pressure (IP)-steam and additional burning of 

natural gas. The report notes that a dual drying circuit using only natural gas and 

the produced syngas could be studied [38

• Option 2: Dry the coal using a scheme similar to the Great River Energy (GRE) 

Clean Coal Power Initiative (CCPI) project approach. In the case of gasification 

where the drying requirements are greater than in PC plants, higher grade heat than is 

available from the cooling water exiting the condenser will be required. However, 

there are many sources of low-level waste heat in a gasification-to-fuels plant and 

integration of this heat into the drying circuit is possible. Because of the tendency for 

low rank coals to spontaneously combust after the moisture is removed, it may be 

necessary to fluidize the coal bed with something other than air. Depending on the 

source of the fluidization gas, the process could become cost prohibitive.

].

• Option 3: Use the WTA process (German acronym for “fluidized bed dryer with 

integrated waste heat recovery” [39]) proposed by RWE, which consists of a fluid 

bed dryer utilizing a heat pump-type cycle with recovered coal moisture used for 

fluidizing the coal bed and used as the working fluid [40

• Option 4: Use a process similar to the Integrated Drying and Gasification Combined 

Cycle (IDGCC) being developed in Australia.

].

Conventional coal drying methods would be suitable for the low rank coals used in this study, 

but there is an efficiency penalty involved with burning either syngas or natural gas as a heat 

source and there are additional CO2 emissions generated by the process. Using steam as the heat 

source also impacts the production of electricity.

The GRE process has potential because of the many sources of low-grade heat in the gasification 

process. However, the fluidization gas source would have to be identified assuming ambient air 

cannot be used because of the combustion tendencies of dried, low rank coals.

The RWE process has the advantage of using steam and coal moisture as the fluidizing medium 

thus eliminating the spontaneous combustion concerns. However, the vapor compressor imposes 

a significant auxiliary load.

The IDGCC process is being commercialized by HRL Ltd. (Australia) and Harbin Power 

(China). They recently announced plans for a 400 MW demonstration plant in Australia [41]. 

The process utilizes hot syngas from an air blown fluidized bed gasifier (FBG) to dry brown coal 

prior to entering the gasifier. Sulfur is captured in the fluid bed and particulates are removed in a 

downstream candle filter. The warm, humidified syngas is then burned in a combustion turbine

(GT) [42

The technology is being developed for an air-blown FBG and has features that make it less 

attractive in the case of an entrained-flow, oxygen-blown gasifier like the Siemens process. The 

coal is crushed to 10 mm top size and pressurized to 2.5 MPa (363 psi) through a lock hopper 

system. The FBG can accept 10 mm coal, and at that size and high moisture content the coal 

will still flow through the lock hoppers. However, in the case of the Siemens gasifier, the coal 

top size is significantly smaller (Siemens states that conventional coal pulverizers are used,

].
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

58

which likely results in an average coal size of ≤ 500 μm for bituminous coal) and the coal must 

be dried prior to pressurizing to avoid lock hopper flow problems.

The WTA coal drying system was ultimately chosen for this evaluation largely because of its 

ability to recover the water from the coal in liquid state for use in the process (recycled to the 

cooling tower) and the fact that syngas is not used to provide heat for drying. In conventional 

dryers, the water is mixed with the heating gas and discharged to atmosphere as vapor. Recovery 

of the coal moisture in a liquid state results in a sizable auxiliary load.

The ‘closed’ WTA process has been demonstrated at pilot scale. Plans for a commercial 

demonstration of an ‘open’ version of the process have been delayed. In spite of the uncertainty 

of the commercial demonstration, the potential benefit of the technology was viewed to be 

significant enough to use the ‘closed version’ of the process in this study. A process schematic is 

shown in Exhibit 3-1 [43

Exhibit 3-1 WTA Process Schematic

].

3.1.3

In order to economically and efficiently support gasification projects, air separation equipment 

has been modified and improved in response to production requirements and the consistent need 

to increase single train output. “Elevated pressure” air separation designs have been 

implemented that result in distillation column operating pressures that are about twice as high as 

traditional plants. In this study, the main air compressor discharge pressure was set at 1.3 MPa 

Air Separation Unit Choice
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

59

(190 psia) compared to a traditional ASU plant operating pressure of about 0.7 MPa (105 psia)

[44

Elevated Pressure ASU Experience in Gasification

]. For gasification applications the elevated pressure ASU process minimizes power 

consumption and decreases the size of some of the equipment items.

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

integrated ASU to be constructed. It was designed to produce up to 1,796 tonnes/day (1,980 tons 

per day [TPD]) of 95 percent purity oxygen for a Shell coal-based gasification unit that fuels a 

Siemens V94.2 GT. In normal operation at the Buggenum plant the ASU receives all of its air 

supply from and sends all residual nitrogen to the GT.

The Polk County, Florida ASU for the Tampa Electric IGCC is also an elevated-pressure, 

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

coal-based gasification unit, which fuels a General Electric 7FA GT. All of the nitrogen 

produced in the ASU is used in the GT. The original design did not allow for air extraction from 

the combustion turbine (CT). After a CT air compressor failure in January, 2005, a modification 

was made to allow air extraction, which in turn eliminated a bottleneck in ASU capacity and 

increased overall power output [45

Air Separation Plant Process Description

].

The air separation plant is designed to produce 99 mole percent (mol%) oxygen (O2) for use in 

the gasifier [46

Exhibit 3-2

]. Conventional IGCC plants typically use oxygen purities of 95 mol%. 

However, the SNG product specification requires higher purity oxygen be used in the gasifier. 

The plant is designed with four production trains. The air compressor is powered by an electric 

motor. Nitrogen is also recovered, compressed, and used in the PSA process and the ammonia 

synthesis loop in the co-production cases only. An additional nitrogen compressor is required in 

the co-production cases to deliver the nitrogen to the ammonia process at a pressure of 13.6 MPa 

(1,975 psia). In the SNG only cases, most of the nitrogen is vented to the atmosphere without 

compression. A process schematic of a typical ASU is shown in .

The air is supplied from a stand-alone compressor. Air to the stand-alone compressor is first 

filtered in a suction filter upstream of the compressor. This air filter removes particulate, which 

may tend to cause compressor wheel erosion and foul intercoolers. The filtered air is then 

compressed in the centrifugal compressor, with intercooling between each stage. The power 

requirement of the stand-alone compressor is affected by elevation. This effect is accounted for 

in the plant performance.

Air from the stand-alone compressor is cooled and fed to an adsorbent-based pre-purifier system. 

The adsorbent removes water, CO2, butane + higher paraffins (C4+), and saturated hydrocarbons 

from the air. After passing through the adsorption beds, the air is filtered with a dust filter to

remove any adsorbent fines that may be present. Downstream of the dust filter a small stream of 

air is withdrawn to supply the instrument air requirements of the ASU.

Regeneration of the adsorbent in the pre-purifiers is accomplished by passing a hot nitrogen 

stream through the off-stream bed(s) in a direction countercurrent to the normal airflow. The 

nitrogen is heated against extraction steam (1.7 MPa [250 psia]) in a shell and tube heat 

exchanger. The regeneration nitrogen drives off the adsorbed contaminants. Following 

regeneration, the heated bed is cooled to near normal operating temperature by passing a cool 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

60

nitrogen stream through the adsorbent beds. The bed is re-pressurized with air and placed on 

stream so that the current on-stream bed(s) can be regenerated.

The air from the pre-purifier is then split into three streams. About 70 percent of the air is fed 

directly to the cold box. About 25 percent of the air is compressed in an air booster compressor. 

This boosted air is then cooled in an aftercooler against cooling water in the first stage and 

against chilled water in the second stage before it is fed to the cold box. The chiller utilizes lowpressure (LP) process steam at 0.45 MPa (65 psia). The remaining 5 percent of the air is fed to a 

turbine-driven, single-stage, centrifugal booster compressor. This stream is cooled in a shell and 

tube aftercooler against cooling water before it is fed to the cold box.

All three air feeds are cooled in the cold box to cryogenic temperatures against returning product 

oxygen and nitrogen streams in plate-and-fin heat exchangers. The large air stream is fed 

directly to the first distillation column to begin the separation process. The second largest air 

stream is liquefied against boiling liquid oxygen before it is fed to the distillation columns. The 

third, smallest air stream is fed to the cryogenic expander to produce refrigeration to sustain the 

cryogenic separation process.

Inside the cold box the air is separated into oxygen and nitrogen products. The oxygen product 

is withdrawn from the distillation columns as a liquid and is pressurized by a cryogenic pump. 

The pressurized liquid oxygen is then vaporized against the high-pressure (HP) air feed before 

being warmed to ambient temperature. The gaseous oxygen exits the cold box and is fed to the 

centrifugal compressor with intercooling between each stage of compression. The compressed 

oxygen is then fed to the gasification unit. Nitrogen is produced from the cold box at two 

pressure levels and is compressed to fulfill the needs of the PSA systems and the ammonia 

synthesis loop in the co-production cases only. In the SNG only cases, the nitrogen is vented to 

the atmosphere.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Exhibit 3-2 Typical ASU Process Schematic

Cryogenic Air 

Separation Unit

Single Train

Oxygen 

Compressor

HP Oxygen

Nitrogen 

Compressor

HP Nitrogen

Regen

Heater

Condensate

Steam

Regeneration

Nitrogen

Prepurifiers

Two Stage

DCA

Booster Air

Compressor

Air

Main Air

Compressor Air Filter

CWR

CWS

Chiller CWS

CWR

Steam

Cond

Regen. N2

Blower

Liq. Oxygen

Pump Turbine Turbine Air

Booster

3.1.4

The Siemens gasifier was chosen for this study to allow the use of a single gasifier across all coal 

types and the vendor was cooperative in providing process information for this and other studies 

that could be applied to this study. The configuration of processing equipment downstream of 

the gasifier, such as syngas cooling and degree of quench, may vary with coal type and may not 

be representative of the latest commercial technology offering.

Gasifier

Development and Current Status – The Siemens Fuel Gasification (SFG) process is based on 

the Noell process, also known under the name GSP, developed by Deutsches Brennstoffinstitut 

Freiberg in 1975 for the gasification of domestic brown coal and other solid fuels. The Noell 

Group acquired the technology in 1991 and did further development to gasify waste materials 

and liquid residues. The gasifier was marketed under the Future Energy GmbH Company and 

was sold to Siemens in 2006. The first gasifier of this type was a 200 MW thermal input unit 

built at Schwarze Pumpe, Germany in 1984, firing high sodium lignite. It was converted to 

gasify natural gas and waste liquids in 1991. Other installations include a 5 MW test plant in 

Freiberg, Germany where alternative feed testing is ongoing and a 130 MW autothermal oil 

conversion plant in the Czech Republic, commissioned in 2008. Current gasifier projects include 

the JinCheng 1000 MW Chinese anthracite coal-to-ammonia plant (under development)[18], the 

Ningxia Coal Based Polypropylene Project with capacity of 2500 MW of coal to polypropylene 

production (scheduled for startup in April/May 2010), and the Secure Energy Decatur Coal-to-
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

62

SNG project. Scale-up risks should be minimized with start-up of the Ningxia project, although 

a process contingency is still included in the cost estimates for this project.

The Siemens gasifier, which is a single-stage, entrained-flow, dry-feed gasifier, is modeled as an 

equilibrium reactor. Many literature references support this modeling strategy [39,47

Gasifier Capacity – The largest current commercial offering from Siemens is a nominal 500 

MW thermal input gasifier, with two trains used in the JinCheng project, five trains for the 

Ningxia project and two trains used in the Secure Energy project. For this study, all cases use six 

gasifiers. Actual thermal input to each gasifier is coal-type dependent and was based on input 

from Siemens. The thermal input ranges from 549 MW for bituminous coal to 506 MW for 

lignite coal with PRB intermediate at 527 MW [

]. Steam 

injection is based on published data for other single-stage, entrained-flow, dry-feed gasifiers, and 

the oxygen injection is controlled to maintain estimated heat losses for the gasifier. It is assumed 

that the gasifier cooling screen that insulates the reactor walls generates LP steam. 

18].

Distinguishing Characteristics – The key advantage of the Siemens coal gasification 

technology is its high carbon conversion with a variety of coals and reliability. Similar to other 

dry feed systems, the Siemens gasifier allows for minimal diluent to be used to inject the 

feedstock into the gasifier, which has undergone long term testing to characterize a wide range of 

fuels. The cooling screen is used to control the gasifier shell temperature and creates a solid and 

liquid slag lining along the gasifier walls instead of a refractory lining, which improves 

availability, startup and turndown time, and reduces the concerns surrounding coal, and 

specifically, ash properties. The raw syngas is tar free due to the high gasification temperatures, 

which improves the downstream gas cleanup. The water quench simplifies the high temperature 

syngas cooling, improving reliability, resulting in syngas with a high water content, which 

contributes to the water gas shift (WGS) reaction, benefitting CO2 capture and chemical 

synthesis applications where hydrogen (H2) and CO2 is preferable to carbon monoxide (CO)

production.

The main disadvantage to this, and all dry feed systems, is the need to dry the coal for transport 

and injection into the gasifier. Water content is generally inversely proportional to coal rank, so, 

while this gasifier can handle a wide range of fuels, the coal processing and drying can impact 

performance with different rank coals.

Important Coal Characteristics – The Siemens gasifier is generally able to fire any type of 

coal, petcoke, and mixed feeds. 

3.1.5

Selection of Technology - In all cases, the gasifier product must be converted to satisfy the 

requirements for the SNG methanation process and/or the ammonia synthesis loop. The 

methanation process requires a 3:1 H2 to CO ratio, while the ammonia synthesis loop requires 

that the maximum amount of hydrogen is produced that is technically and economically feasible. 

Water Gas Shift Reactors

The concept is to convert the syngas carbon monoxide to hydrogen and CO2 by reacting the CO 

with water over a bed of catalyst. 

Water Gas Shift: CO + H2O ↔ CO2 + H2
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

63

The CO shift converter can be located either upstream of the acid gas removal (AGR) step (SGS 

[sour gas shift]) or immediately downstream (sweet gas shift). If the CO converter is located 

downstream of the AGR, then the metallurgy of the unit is less stringent, but additional 

equipment must be added to the process. Products from the gasifier are quenched with water and 

contain a portion of the water vapor necessary to meet the water-to-gas criteria at the reactor 

inlet. If the CO converter is located downstream of the AGR, then the gasifier product would 

first have to be cooled and the free water separated and treated. Then additional steam would 

have to be generated and re-injected into the CO converter feed to meet the required water-to-gas 

ratio. If the CO converter is located upstream of the AGR step, no additional equipment is 

required. This is because the CO converter promotes carbonyl sulfide (COS) hydrolysis without 

a separate catalyst bed. Therefore, for this study the CO converter was located upstream of the 

AGR unit and is referred to as SGS.

Process Description – The two methods to control the amount of shift achieved are the H2O:CO 

molar ratio and/or the amount of bypass around the shift reactor.

The individual process descriptions for the SNG and co-production portions of the SGS reactors, 

including steam requirements and bypass ratios, are presented in Sections 4.1 through 5.2.

3.1.6

A gasification facility has the potential of removing mercury in a more simple and cost-effective 

manner than conventional PC plants. This is because mercury can be removed from the syngas 

at elevated pressure and prior to product synthesis so that syngas volumes are much smaller than 

flue gas volumes in comparable PC cases. A conceptual design for a carbon bed adsorption 

system was developed for mercury control in the gasification plants being studied. Data on the 

performance of carbon bed systems were obtained from the Eastman Chemical Company, which 

uses carbon beds at its syngas facility in Kingsport, Tennessee [

Mercury Removal

15]. The coal mercury content 

(0.15 ppm dry for Illinois No. 6, 0.081 ppm dry for PRB, and 0.116 ppm dry for lignite) and 

carbon bed removal efficiency (95 percent) were discussed previously in Section 2.5. 

Gasification-specific design considerations are discussed below.

Carbon Bed Location – The packed carbon bed vessels are located upstream of the AGR 

process and syngas enters at a temperature near 38°C (100°F). Consideration was given to 

locating the beds further upstream before the COS hydrolysis/SGS unit at a temperature near 

204°C (400°F). However, while the mercury removal efficiency of carbon has been found to be 

relatively insensitive to pressure variations, temperature adversely affects the removal efficiency

[48

15

]. Eastman Chemical also operates their beds ahead of their sulfur recovery unit (SRU) at a 

temperature of 30°C (86°F) [ ]. 

Consideration was also given to locating the beds downstream of the AGR. However, it was felt 

that removing the mercury and other contaminants before the AGR unit would enhance the 

performance of both the AGR and SRU and increase the life of the various solvents.

Process Parameters – An empty vessel basis gas residence time of approximately 20 seconds 

was used based on Eastman Chemical’s experience [15]. Allowable gas velocities are limited by 

considerations of particle entrainment, bed agitation, and pressure drop. One-foot-per-second 

superficial velocity is in the middle of the range normally encountered [48] and was selected for 

this application. 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

64

The bed density of 30 lb/ft3 was based on the Calgon Carbon Corporation HGR-P sulfurimpregnated pelletized activated carbon [49

Carbon Replacement Time – Eastman Chemicals replaces its bed every 18 to 24 months [

]. These parameters determined the size of the 

vessels and the amount of carbon required. Each gasifier train has one mercury removal bed and 

there are three gasifier trains in each case, resulting in three carbon beds per case.

15]. 

However, bed replacement is not because of mercury loading, but for other reasons including:

• A buildup in pressure drop

• A buildup of water in the bed

• A buildup of other contaminants

For this study a 24 month carbon replacement cycle was assumed. Under these assumptions, the 

mercury loading in the bed would build up to 0.64 weight percent (wt%). Mercury capacity of 

sulfur-impregnated carbon can be as high as 20 wt% [50

3.1.7

]. The mercury laden carbon is 

considered to be a hazardous waste, and the disposal cost estimate reflects this categorization.

Gasification of coal to generate a chemical product produces a syngas that must be treated prior 

to further utilization. A portion of the treatment consists of AGR and sulfur recovery. To 

protect the methanation catalyst, the sulfur content of the syngas must be reduced to below 1 

ppm to achieve reasonable catalyst life [

Acid Gas Removal (AGR) Process Selection

51,52]. This includes all sulfur species, but in particular 

the total of COS and hydrogen sulfide (H2S). A two-stage Selexol Process is capable of cleaning 

the syngas to these low sulfur levels [53

COS Hydrolysis

].

The use of COS hydrolysis pretreatment in the feed to the AGR process provides a means to 

reduce the COS concentration. The WGS catalyst also serves to hydrolyze COS, so only the 

portion of the syngas bypassing the shift reactors must pass through a COS reactor. In the low 

rank coal cases the syngas sulfur content and WGS bypass fraction are low enough to eliminate 

the need for a COS reactor in the bypass stream.

This method was first commercially proven at the Buggenum plant, and was also used at both the 

Tampa Electric and Wabash River IGCC projects. Several catalyst manufacturers including 

Haldor Topsoe and Porocel offer a catalyst that promotes the COS hydrolysis reaction. The COS 

hydrolysis reactor designs are based on information from Porocel. The SGS reactors also reduce 

COS to H2S as discussed in Section 3.1.5.

The COS hydrolysis reaction is equimolar with a slightly exothermic heat of reaction. The 

reaction is represented as follows:

COS + H2O ↔ CO2 + H2S

Since the reaction is exothermic, higher conversion is achieved at lower temperatures. However, 

at lower temperatures, the reaction kinetics are slower. Since the exit gas COS concentration is 

critical to the amount of H2S that must be removed with the AGR process, a retention time of 50-

75 seconds was used to achieve 99.5 percent conversion of the COS. The Porocel activated 

alumina-based catalyst, designated as Hydrocel 640 catalyst, promotes the COS hydrolysis 

reaction without promoting reaction of H2S and CO to form COS and H2.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

65

Although the reaction is exothermic, the heat of reaction is dissipated among the large amount of 

non-reacting components. Therefore, the reaction is essentially isothermal. The product gas, 

now containing less than 4 parts per million volume (ppmv) of COS, is cooled prior to entering 

the mercury removal process and the AGR.

Acid Gas Removal

All cases in this study require the removal of hydrogen sulfide and carbon dioxide from the 

syngas stream. Since the two-stage Selexol process has demonstrated the ability to achieve the 

low sulfur levels required, and it is also an effective process to remove CO2, it was used for all 

cases in this study. The Rectisol process would be equally effective in this application, but at 

greater capital and operating costs. A brief process description follows.

Untreated syngas enters the first of two absorbers where H2S is preferentially removed using 

loaded solvent from the CO2 absorber. The gas exiting the H2S absorber passes through the 

second absorber where CO2 is removed using first flash regenerated, chilled solvent followed by 

thermally regenerated solvent added near the top of the column. The treated gas exits the 

absorber and is sent either to the methanation reactors for SNG production or to the ammonia 

synthesis loop.

The amount of hydrogen remaining in the syngas stream is dependent on the Selexol process 

design conditions. In this study, hydrogen recovery is 99.4 percent. The minimal hydrogen slip 

to the carbon sequestration stream maximizes the overall plant efficiency. The Selexol plant cost 

estimates are based on a plant designed to recover this high percentage of hydrogen. The 

balance of the hydrogen is either co-sequestered with the CO2, destroyed in the Claus plant 

burner, or recycled to the gasifier.

The CO2 loaded solvent exits the CO2 absorber and a portion is sent to the H2S absorber, a 

portion is sent to a reabsorber and the remainder is sent to a series of flash drums for 

regeneration. The CO2 product stream is obtained from the three flash drums, and after flash 

regeneration the solvent is chilled and returned to the CO2 absorber.

The rich solvent exiting the H2S absorber is combined with the rich solvent from the reabsorber 

and the combined stream is heated using the lean solvent from the stripper. The hot, rich solvent 

enters the H2S concentrator and partially flashes. The remaining liquid contacts nitrogen from 

the ASU and a portion of the CO2 along with lesser amounts of H2S and COS are stripped from 

the rich solvent. The stripped gases from the H2S concentrator are sent to the reabsorber where 

the H2S and COS that were co-stripped in the concentrator are transferred to a stream of loaded 

solvent from the CO2 absorber. The clean gas from the reabsorber is combined with the clean 

gas from the H2S absorber and sent to SNG and/or NH3 production.

The solvent exiting the H2S concentrator is sent to the stripper where the absorbed gases are 

liberated by hot gases flowing up the column from the steam heated reboiler. Water in the 

overhead vapor from the stripper is condensed and returned as reflux to the stripper or exported 

as necessary to maintain the proper water content of the lean solvent. The acid gas from the 

stripper is sent to the Claus plant for further processing. The lean solvent exiting the stripper is 

first cooled by providing heat to the rich solvent, then further cooled by exchange with the 

product gas and finally chilled in the lean chiller before returning to the top of the CO2 absorber.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

66

3.1.8

Methanation is the hydrogenation of carbon monoxide to methane, typically performed over a 

nickel-based catalyst. There are two highly exothermic reactions:

Methanation, Synthetic Natural Gas Purification and Compression

CO + 3H2 ↔ CH4 + H2O (ΔH0

298 = -206 kJ/mol)

CO2 + 4H2 ↔ CH4 + 2H2O (ΔH0

298 = -165 kJ/mol)

Due to the highly exothermic nature of the reactions, temperature control and high temperature 

tolerant catalysts must be implemented. 

The methanation system used in this study is based on the high temperature TREMPTM Process 

by Haldor Topsoe [54

Exhibit 3-3

]. The TREMPTM process was chosen primarily because it operates at 

high-temperature and because of the availability of process data in the public domain. A general 

schematic of the methanation process in this study is shown in . The process uses two 

different catalysts to account for the adiabatic temperature rise. The high temperature catalyst 

used in the first and second reactor can operate a range of 300°C (572°F) to 700°C (1290°F) and 

the low temperature catalyst in the “clean up” reactor can operate at inlet temperatures as low as 

200°C (392°F). The process has the ability to make superheated steam at two pressure levels: 

12.41 MPa/566°C (1,800 psia/1,050°F) and 4.14 MPa/288°C (600 psia/550°F). The HP steam is 

used to drive a subcritical turbine, and the medium pressure steam is used for process 

requirements like shift steam in the WGS reactors.

Exhibit 3-3 Haldor Topsoe TREMPTM High Temperature Methanation Process

High Temperature

Reactor

High Temperature

Reactor

Low Temperature

“Clean Up” Reactor

Superheater

Knock

-out

Drum

HP 

Boiler HP

Boiler

HP

Boiler

BFW

Heater

Recycle

Compressor

Synthetic Natural Gas

to Purification and Compression

Condensate

Syngas from

Selexol Unit

The syngas from the Selexol Unit, with a H2 to CO ratio of approximately 3:1, is combined with 

a recycle stream and fed to the first high temperature reactor after being preheated to the 

minimum catalyst temperature. The reactor temperature for the first high temperature reactor is 

maintained below the catalyst threshold by varying the amount of recycle mixed with the syngas. 

After the second high temperature reactor, the syngas is fed to a low temperature “clean up” 

reactor that reduces the hydrogen content of the SNG product to 0.5 to 1 vol%.

After the methanation reactors the process condensate is removed from the product stream and 

the SNG product is then passed through a molecular sieve where it removes nearly all of the 

remaining water and 98.5 vol% of the CO2, which is vented through the plant stack [55]. The 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

67

SNG product is further compressed to 6.21 MPa (900 psia) to meet pipeline pressure 

specifications [56

3.1.9

]. 

The PSA unit is used to purify the syngas from the NH3-production Selexol unit and the purge 

gas from the ammonia synthesis loop. The operation of a PSA unit for ammonia production 

based on syngas derived from gasification has been demonstrated at the Coffeyville Resources 

Fertilizer Complex albeit at a smaller scale. 

Pressure Swing Adsorber (Co-Production Cases Only)

The PSA unit produces 98.8 vol% hydrogen with a recovery efficiency of 94 vol%. Typical 

recovery efficiencies are from 88 to 90 vol%. The use of nitrogen as the purging medium in the 

desorption cycle enables the high recovery efficiency used in this study [57

The PSA process is accomplished in a series of five steps. The gas is fed to the unit at HP, 

where impurities are adsorbed and the hydrogen product is produced. When the first adsorber is 

at capacity, it is taken off-line and the syngas is feed to another adsorber. Hydrogen remains 

trapped in the adsorbent space. To recover this hydrogen, the adsorber is co-currently 

depressurized from the product side, and the hydrogen is withdrawn. Nitrogen is used to 

repressurize and purge other adsorbers. After the hydrogen recovery is complete, the impurities 

have migrated to the top of the adsorbent bed, filling the bed to capacity. The bed is partly 

regenerated by depressurization towards the feed end, and the impurities are rejected to the PSA 

off-gas. The adsorbent is purged with more nitrogen at constant off-gas pressure to further 

regenerate the bed. The adsorber is repressurized with hydrogen from the co-current 

depressurization and with a slipstream from the hydrogen product prior to the introduction of the 

feed gas [

].

14].

3.1.10

Ammonia synthesis occurs through the hydrogenation of nitrogen over an iron based catalyst. 

The hydrogen is derived from the shifted syngas purified by a two-stage Selexol unit and the 

PSA unit. The nitrogen is produced from the ASU. Co-production cases include the cost and 

performance adjustments for nitrogen compression. 

Ammonia Synthesis (Co-Production Cases Only)

N2 + 3H2 ↔ 2NH3 (ΔH0

298 = -46 kJ/mol)

The synthesis of ammonia typically takes place at pressure in the range of 10.00 to 24.99 MPa 

(1,450 to 3,625 psia) at a temperature of 343°C to 550°C (650 to 1,022°F) [58

Exhibit 3-4

]. For this study 

the gas enters the reactor at 14.00 MPa (2,030 psia) and 343°C (650°F). The configuration 

modeled in this study is based on the Haldor Topsoe S-300 Ammonia Synthesis Loop and is 

shown in . The path of the feed gas through the system is shown in red.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

68

Exhibit 3-4 Ammonia Synthesis Loop Configuration

Recycle

Compressor

Liquid NH3

Cooler

Liquid NH3

Cooler

HP

Boiler

Final

Reheater

Recycle Loop

Heater

Recycle Loop

Heater

Superheater

Radial Bed

Reactor

Purge Gas

to PSA System

Make-up

Compressor

H2/N2

Feed Gas

Ammonia

Product

The makeup gas from the PSA system is introduced into the synthesis loop before the separation 

of the ammonia product. Each reactor pass converts only 20 to 30 percent due to the unfavorable 

equilibrium conditions. Due to the exothermic nature of the reaction, superheated steam at 

12.51 MPa (1,815 psia) and HP steam at 4.14 MPa (600 psia) can be generated in the synthesis 

loop. The ammonia is separated/condensed by a refrigeration system. 

Purge gas is removed from the system to reduce the concentration of catalyst poisons and inerts 

such as argon and methane. Permanent poisons are sulfur containing compounds. Temporary 

catalyst poisons can cause deactivation during the time of exposure. Typical poisons are oxygen 

containing compounds, such as carbon oxides, water, and oxygen. Catalyst poisoning is a 

function of the total concentration of oxygen equivalents (O eqv) [59

ppm O eqv = 2 x (ppm O2) + 2 x (ppm CO2) + ppm CO + ppm H2O

].

Less than 2 ppm O eqv is considered ideal and at higher concentrations the catalyst will begin to 

show a loss of activity. Cases 3 and 4 achieve below 1 total ppm O equivalent.

3.1.11

The sulfur removal requirements for the methanation and ammonia processes are at the extreme 

limit of Selexol’s capabilities. To protect against system upsets or fluctuations in coal sulfur 

content, a zinc oxide guard bed was included in each case to remove trace sulfur contaminants.

Zinc Oxide Guard Bed

A zinc oxide bed can absorb over 99.99 percent of the inlet H2S and can absorb a maximum of 

39.3 pounds of sulfur per pound of pure zinc oxide (ZnO). In this study it was assumed that the 

bed would reach 70 percent of saturation at breakthrough.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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3.1.12

Currently, most of the world’s sulfur is produced from the acid gases coming from gas treating. 

The Claus process remains the mainstay for sulfur recovery. Conventional three-stage Claus 

plants, with indirect reheat and feeds with a high H2S content, can approach 98 percent sulfur 

recovery efficiency. However, since environmental regulations have become more stringent, 

sulfur recovery plants are required to recover sulfur with over 99.8 percent efficiency. To meet

these stricter regulations, the Claus process underwent various modifications and add-ons.

Sulfur Recovery/Tail Gas Cleanup Process Selection

The add-on modification to the Claus plant selected for this study can be considered a separate 

option from the Claus process. In this context, it is often called a TGTU process.

The Claus Process

The Claus process converts H2S to elemental sulfur via the following reactions:

H2S + 3/2 O2 ↔ H2O + SO2

2H2S + SO2 ↔ 2H2O + 3S

The second reaction, the Claus reaction, is equilibrium limited. The overall reaction is:

3H2S + 3/2 O2 ↔ 3H2O + 3S

The sulfur in the vapor phase exists as S2, S6, and S8 molecular species, with the S2 predominant 

at higher temperatures, and S8 predominant at lower temperatures.

A simplified process flow diagram of a typical three-stage Claus plant is shown in Exhibit 3-5

[60]. One-third of the H2S is burned in the furnace with oxygen from the air to give sufficient 

SO2 to react with the remaining H2S. Since these reactions are highly exothermic, a waste heat

boiler that recovers this heat to generate HP steam usually follows the furnace. Sulfur is 

condensed in a condenser that follows the HP steam recovery section. LP steam is raised in the 

condenser. The tail gas from the first condenser then goes to several catalytic conversion stages, 

usually two to three, where the remaining sulfur is recovered via the Claus reaction. Each 

catalytic stage consists of gas preheat, a catalytic reactor, and a sulfur condenser. The liquid 

sulfur goes to the sulfur pit, while the tail gas proceeds to the incinerator or for further processing 

in a TGTU.
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Exhibit 3-5 Typical Three-Stage Claus Sulfur Plant

Claus Plant Sulfur Recovery Efficiency

The Claus reaction is equilibrium limited, and sulfur conversion is sensitive to the reaction 

temperature. The highest sulfur conversion in the thermal zone is limited to about 75 percent. 

Typical furnace temperatures are in the range from 1,093 to 1,427°C (2,000 to 2,600°F), and as 

the temperature decreases, conversion increases dramatically.

Claus plant sulfur recovery efficiency depends on many factors:

• H2S concentration of the feed gas

• Number of catalytic stages

• Gas reheat method

In order to keep Claus plant recovery efficiencies approaching 94 to 96 percent for feed gases 

that contain about 20 to 50 percent H2S, a split-flow design is often used. In this version of the 

Claus plant, part of the feed gas is bypassed around the furnace to the first catalytic stage, while 

the rest of the gas is oxidized in the furnace to mostly SO2. This results in a more stable 

temperature in the furnace.

Oxygen-Blown Claus

Large diluent streams in the feed to the Claus plant, such as N2 from combustion air, or a high 

CO2 content in the feed gas, lead to higher cost Claus processes and any add-on or tail gas units. 

One way to reduce diluent flows through the Claus plant and to obtain stable temperatures in the 

furnace for dilute H2S streams is the oxygen-blown Claus process.

The oxygen-blown Claus process was originally developed to increase capacity at existing 

conventional Claus plants and to increase flame temperatures of low H2S content gases. The 
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process has also been used to provide the capacity and operating flexibility for sulfur plants 

where the feed gas is variable in flow and composition such as often found in refineries. The 

application of the process has now been extended to grass roots installations, even for rich H2S 

feed streams, to provide operating flexibility at lower costs than would be the case for 

conventional Claus units. At least four of the recently built gasification plants in Europe use 

oxygen enriched Claus units.

Oxygen enrichment results in higher temperatures in the front-end furnace, potentially reaching 

temperatures as high as 1,593 to 1,649°C (2,900 to 3,000°F) as the enrichment moves beyond 40 

to 70 vol% O2 in the oxidant feed stream. Although oxygen enrichment has many benefits, its 

primary benefit for lean H2S feeds is a stable furnace temperature. Sulfur recovery is not 

significantly enhanced by oxygen enrichment. Because the gasification process already requires 

an ASU, the oxygen-blown Claus plant was chosen for all cases.

Tail Gas Treating

In many refinery and other conventional Claus applications, tail gas treating involves the 

removal of the remaining sulfur compounds from gases exiting the SRU. Tail gas from a typical 

Claus process, whether a conventional Claus or one of the extended versions of the process, 

usually contains small, but varying quantities of COS, carbon disulfide (CS2), H2S, SO2, and 

elemental sulfur vapors. In addition, there may be H2, CO, and CO2 in the tail gas. In order to 

remove the rest of the sulfur compounds from the tail gas, all of the sulfur-bearing species must 

first be converted to H2S. Then, the resulting H2S is absorbed into a solvent and the clean gas 

vented or recycled for further processing. The clean gas resulting from the hydrolysis step can 

undergo further cleanup in a dedicated absorption unit or be integrated with an upstream AGR 

unit. The latter option is particularly suitable with physical absorption solvents. The approach 

of treating the tail gas in a dedicated amine absorption unit and recycling the resulting acid gas to 

the Claus plant is the one used by the SCOT process. With tail gas treatment, Claus plants can 

achieve overall removal efficiencies in excess of 99.9 percent.

In the case of gasification-based applications, the tail gas from the Claus plant can be 

catalytically hydrogenated and then recycled back into the system with the choice of location 

being technology dependent, or it can be treated with a SCOT-type process. The low rank coal 

cases in this report all use a catalytic hydrogenation step with tail gas recycle to the AGR. The 

bituminous coal cases utilize the SCOT process with acid gas recycled back to the AGR and the 

clean gas used for coal drying. The Shell Puertollano plant treats the tail gas in a similar manner, 

but the recycle endpoint is not specified [38].

Flare Stack

A self-supporting, refractory-lined, carbon steel (CS) flare stack is typically provided to combust 

and dispose of unreacted gas during startup, shutdown, and upset conditions. However, in all 

eight cases a flare stack was provided for syngas dumping during startup, shutdown, etc. This 

flare stack eliminates the need for a separate Claus plant flare.

3.1.13

The slag handling system conveys, stores, and disposes of slag removed from the gasification 

process. Spent material drains from the gasifier bed into a water bath in the bottom of the 

gasifier vessel. A slag crusher receives slag from the water bath and grinds the material into peaSlag Handling
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sized fragments. A slag/water slurry that is between 5 and 10 percent solids leaves the gasifier 

pressure boundary through the use of lockhoppers to a series of dewatering bins.

The slag is dewatered, the water is clarified and recycled and the dried slag is transferred to a 

storage area for disposal.

In this study the slag bins were sized for a nominal holdup capacity of 72 hours of full-load 

operation. At periodic intervals, a convoy of slag-hauling trucks will transit the unloading 

station underneath the hopper and remove a quantity of slag for disposal. Approximately 30-50 

truckloads per day are required to remove the total quantity of slag produced by the plant, 

depending on coal type, operating at nominal rated power. While the slag is suitable for use as a 

component of road paving mixtures, it was assumed in this study that the slag would be 

landfilled at a specified cost.

3.1.14

Steam Turbine Generator and Auxiliaries

Steam Generation Island

The ST consists of an HP section, an IP section, and one double-flow LP section, all connected 

to the generator by a common shaft. The HP and IP sections are contained in a single-span, 

opposed-flow casing, with the double-flow LP section in a separate casing.

Superheated main steam is combined in a header, and then passes through the stop valves and 

control valves and enters the turbine at 12.4 MPa/566°C (1800 psig/1050°F). The steam initially 

enters the turbine near the middle of the HP span, flows through the turbine. After passing 

through the IP section, the steam enters a crossover pipe, which transports the steam to the LP 

section. The steam divides into two paths and flows through the LP sections, exhausting 

downward into the condenser. In the Midwestern location cases the single condenser is watercooled. In the Montana and North Dakota location cases the steam exiting the turbine splits 

evenly between a water–cooled condenser and an air-cooled condenser.

The generator is a hydrogen-cooled synchronous type, generating power at 24 kilovolt (kV). A 

static, transformer type exciter is provided. The generator is cooled with a hydrogen gas 

recirculation system using fans mounted on the generator rotor shaft. The heat absorbed by the 

gas is removed as it passes over finned tube gas coolers mounted in the stator frame. Gas is 

prevented from escaping at the rotor shafts by a closed-loop (CL) oil seal system. The oil seal 

system consists of storage tank, pumps, filters, and pressure controls, all skid-mounted.

The STG is controlled by a triple-redundant, microprocessor-based electro-hydraulic control 

system. The system provides digital control of the unit in accordance with programmed control 

algorithms, color cathode ray tube (CRT) operator interfacing, and data link interfaces to the 

balance-of-plant distributed control system (DCS), and incorporates on-line repair capability.

Feedwater System

The function of the feedwater (FW) system is to pump the various FW streams from the 

deaerator storage tank to the respective vaporizers. Two 50 percent capacity boiler feed pumps

(BFPs) are provided for each of three pressure levels, HP, IP, and LP. Each pump is provided 

with inlet and outlet isolation valves, and outlet check valve. Minimum flow recirculation to 

prevent overheating and cavitation of the pumps during startup and low loads is provided by an 

automatic recirculation valve and associated piping that discharges back to the deaerator storage 

tank. Pneumatic flow control valves control the recirculation flow. 
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The FW pumps are supplied with instrumentation to monitor and alarm on low oil pressure, or 

high bearing temperature. FW pump suction pressure and temperature are also monitored. In 

addition, the suction of each BFP is equipped with a startup strainer.

Main and Reheat Steam Systems

The function of the main steam system is to convey main steam generated in the raw gas coolers 

and the methanation and ammonia synthesis superheater (where applicable) outlets to the HP 

turbine stop valves.

Main steam at approximately 12.4 MPa/566°C (1800 psig/1050°F) exits through a motoroperated stop/check valve and a motor-operated gate valve, and is routed to a single line feeding 

the HP turbine. Cold reheat steam at 3.5 MPa/376°C (501 psia/708°F) exits the HP turbine, 

flows through a motor-operated isolation gate valve, to the syngas cooler. Hot reheat steam at 

approximately 3.5 MPa/538°C (501 psia/1000°F) exits the syngas cooler and is routed to the IP 

turbines.

Safety valves are installed to comply with appropriate codes and to ensure the safety of 

personnel and equipment.

Circulating Water System

The circulating water system (CWS) is a closed-cycle cooling water system that supplies cooling 

water to the condenser to condense the main turbine exhaust steam (all of the exhaust steam in 

Midwestern locations and half of the steam in the Montana and North Dakota locations). The 

system also supplies cooling water to the AGR plant as required, and to the auxiliary cooling 

system. The auxiliary cooling system is a CL process that utilizes a higher quality water to 

remove heat from compressor intercoolers, oil coolers and other ancillary equipment and 

transfers that heat to the main circulating cooling water system in plate and frame heat 

exchangers. The heat transferred to the circulating water in the condenser and other applications 

is removed by a mechanical draft cooling tower.

The system consists of two 50 percent capacity vertical CWPs, a mechanical draft evaporative 

cooling tower, and CS cement-lined interconnecting piping. The pumps are single-stage vertical 

pumps. The piping system is equipped with butterfly isolation valves and all required expansion 

joints. The cooling tower is a multi-cell wood frame counter flow mechanical draft cooling 

tower.

The condenser is a single-pass, horizontal type with divided water boxes. All of the steam is 

condensed using cooling water for the bituminous coal cases. There are two separate circulating 

water circuits in each box. One-half of the condenser can be removed from service for cleaning 

or for plugging tubes. This can be done during normal operation at reduced load.

Midwestern Location Cases

The condenser is equipped with an air extraction system to evacuate the condenser steam space 

for removal of non-condensable gases during ST operation and to rapidly reduce the condenser 

pressure from atmospheric pressure before unit startup and admission of steam to the condenser.

Exhaust steam from the ST is split 50/50 to a surface condenser cooled with cooling water and to 

an air-cooled condenser used ambient air and forced convection. A decision to use a parallel 

Montana and North Dakota Location Cases
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wet/dry cooling system was based primarily on the plans for the Xcel Energy Comanche 3 PC 

plant currently in start up, and the desire to reduce the plant water requirement in western 

locations where water constraints are frequently encountered. With the relatively low ambient 

temperature, the performance impact from the parallel cooling, as compared to wet cooling, is 

minor.

The major impact of parallel cooling is a significant reduction in water requirement when 

compared to a wet cooling system. This impact is included in the water balance presented later 

in this report.

With this cooling system and the specific ambient temperature, a condenser pressure of 0.005 

MPa (0.698 psia) (condensing temperature of 32°C [90°F]) is used in the Western location cases 

as compared to 0.007 MPa (0.983 psia) (condensing temperature of 38°C [101°F]) used in the 

Midwestern location cases.

Raw Water, Fire Protection, and Cycle Makeup Water Systems

The raw water system supplies cooling tower makeup, cycle makeup, service water, and potable 

water requirements. The water source is 50 percent from a POTW and 50 percent from 

groundwater. Booster pumps within the plant boundary provide the necessary pressure.

The fire protection system provides water under pressure to the fire hydrants, hose stations, and 

fixed water suppression system within the buildings and structures. The system consists of 

pumps, underground and aboveground supply piping, distribution piping, hydrants, hose stations, 

spray systems, and deluge spray systems. One motor-operated booster pump is supplied on the 

intake structure of the cooling tower with a diesel engine backup pump installed on the water 

inlet line.

The cycle makeup water system provides high quality demineralized water for makeup to the 

steam cycle, for steam injection ahead of the WGS reactors and gasifier, and for injection steam 

to the auxiliary boiler for control of NOx emissions, if required.

The cycle makeup system consists of two 100 percent trains, each with a full-capacity activated 

carbon filter, primary cation exchanger, primary anion exchanger, mixed bed exchanger, recycle 

pump, and regeneration equipment. The equipment is skid-mounted and includes a control panel 

and associated piping, valves, and instrumentation.

3.1.15

The accessory electric plant consists of switchgear and control equipment, generator equipment, 

station service equipment, conduit and cable trays, and wire and cable. It also includes the main 

power transformer, all required foundations, and standby equipment.

Accessory Electric Plant

3.1.16

An integrated plant-wide DCS is provided. The DCS is a redundant microprocessor-based, 

functionally DCS. The control room houses an array of multiple video monitor (CRT) and 

keyboard units. The CRT/keyboard units are the primary interface between the generating 

process and operations personnel. The DCS incorporates plant monitoring and control functions 

for all the major plant equipment. The DCS is designed to be operational and accessible 99.5 

Instrumentation and Control
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

75

percent of the time it is required (99.5 percent availability). The plant equipment and the DCS 

are designed for automatic response to load changes from minimum load to 100 percent. Startup 

and shutdown routines are manually implemented, with operator selection of modular 

automation routines available. The exception to this, and an important facet of the control 

system for gasification, is the critical controller system, which is a part of the license package 

from the gasifier supplier and is a dedicated and distinct hardware segment of the DCS.

This critical controller system is used to control the gasification process. The partial oxidation of 

the fuel feed and oxygen feed streams to form a syngas product is a stoichiometric, temperatureand pressure-dependent reaction. The critical controller utilizes a redundant microprocessor 

executing calculations and dynamic controls at 100- to 200-millisecond intervals. The enhanced 

execution speeds as well as evolved predictive controls allow the critical controller to mitigate 

process upsets and maintain the reactor operation within a stable set of operating parameters.
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Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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4.

This section contains an evaluation of plant designs for Cases 1 through 4, which are based on 

the Siemens gasifier using Illinois No. 6 coal as the fuel. All cases capture CO2 from the syngas 

stream because of the necessary process conditions for chemical production, but in one case CO2

is released to the atmosphere and in the other it is compressed and sequestered. Cases 1 and 2 

are very similar in terms of process, equipment, scope and arrangement, except that Case 2 

utilizes a CO2 compression train to enable transportation and sequestration. The same is true for 

Cases 3 and 4. 

BITUMINOUS COAL CASES

Section 4.1 covers the two SNG cases using Illinois No. 6 coal. Section 4.2 covers the two SNG 

and ammonia co-production cases using Illinois No. 6 coal. Each section is structured 

analogously as follows:

• Process and System Description provides an overview of the technology operation as 

applied.

• Key Assumptions is a summary of relevant study and modeling assumptions.

• Sparing Philosophy is provided.

• Performance Results provide the main modeling results, including the performance 

summary, environmental performance, carbon balance, sulfur balance, water balance, 

mass and energy balance diagrams, and mass and energy balance tables.

• Equipment List provides an itemized list of major equipment with account codes that 

correspond to the cost accounts in the Cost Estimates section.

• Cost Estimates provides a summary of capital and operating costs.

If the information is identical to that presented for the non-sequestration cases, a reference is 

made to the earlier section rather than repeating the information.

4.1 SYNTHETIC NATURAL GAS PRODUCTION USING ILLINOIS NO. 6 COAL

4.1.1

In this section the overall Siemens gasification process for the production of SNG for Cases 1 

and 2 is described. The only major process difference is that Case 2 employs CO2 compression 

and sequestration. The system description follows the block flow diagrams (BFDs) in 

Process Description

Exhibit 

4-1 and Exhibit 4-3 and stream numbers reference the same exhibit. The tables in Exhibit 4-2

and Exhibit 4-4 provide process data for the numbered streams in the BFD.

Coal Preparation and Feed Systems

Coal receiving and handling is covered in Section 3.1.1. The receiving and handling subsystem 

ends at the coal silo. The Siemens process uses a dry feed system which is sensitive to the coal 

moisture content. Coal moisture consists of two parts, surface moisture and inherent moisture. 

For coal to flow smoothly through the lock hoppers, the surface moisture must be removed. The 

bituminous coal used in this study contains 11.12 percent moisture on an as-received basis 

(stream 6). It was assumed that the bituminous coal must be dried to 6 percent moisture to allow 

for smooth flow through the dry feed system (stream 10).
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Exhibit 4-1 Case 1 Block Flow Diagram, Bituminous Coal to SNG without Carbon Sequestration

PARTIAL RAW

GAS QUENCH

AND COOLING

WATER-GAS

SHIFT REACTORS

& GAS COOLING

WATER

SCRUBBER

ELEVATED

PRESSURE

ASU

SIEMENS

GASIFIER

MERCURY

REMOVAL

DUALSTAGE

SELEXOL

UNIT

CLAUS

PLANT

1

AIR TO ASU

2 3

VENT

GAS

SULFUR

PLANT

OXIDANT

4

10

13

GASIFIER

OXIDANT

DRIED

COAL

SLAG

16

31

32

TAIL GAS

HYDROLYSIS AND

TREATMENT UNIT

33

SULFUR

PRODUCT SYNGAS

COAL

DRYER 6

WET

COAL

9

5

15

TO SOUR

WATER

STRIPPER

STEAM

30 19

CO2 VENT

22

SHIFT

STEAM

11

STACK

GAS

12

34

14 QUENCH

WATER

17

METHANATION

REACTORS

26

SNG 

PURIFICATION

28

SNG FOR

EXPORT

27 PURIFICATION

OFF-GAS

25

PILOT

FUEL

WGS 

BYPASS

11

STEAM

TURBINE

36 37

PROCESS

STEAM

CONDENSATE

DRY GAS

PREP

23

24

7

AIR

8

20

SNG 

COMPRESSION 29

21

COS 

HYDROLYSIS 18

LOCKHOPPER

VENT

TRANSPORT

CO2

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown. See H&MB diagram for more detail.

TRANSPORT

CO2

35
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Exhibit 4-2 Case 1 Stream Table, Bituminous Coal to SNG without Carbon Sequestration

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19

V-L Mole Fraction

Ar 0.0092 0.0091 0.0101 0.0101 0.0000 0.0000 0.0092 0.0084 0.0064 0.0000 0.0001 0.0000 0.0000 0.0000 0.0019 0.0020 0.0020 0.0020 0.0000

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0119 0.0015 0.0000 0.0000 0.4228 0.4387 0.4387 0.4387 0.0000

CO2 0.0003 0.0004 0.0000 0.0000 0.0000 0.0000 0.0003 0.1134 0.0869 0.0000 0.9736 0.1231 0.0000 0.0000 0.0380 0.0394 0.0394 0.0400 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0005 0.0006 0.0006 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0127 0.6936 0.0000 0.0000 0.2001 0.2076 0.2076 0.2076 0.0000

H2O 0.0099 0.0039 0.0000 0.0000 1.0000 0.0000 0.0099 0.1726 0.3661 0.0000 0.0015 0.0979 0.0000 1.0000 0.3261 0.3009 0.3009 0.3004 1.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0058 0.0060 0.0060 0.0066 0.0000

N2 0.7732 0.9790 0.0004 0.0004 0.0000 0.0000 0.7732 0.6276 0.4809 0.0000 0.0001 0.0171 0.0000 0.0000 0.0046 0.0047 0.0047 0.0047 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.2074 0.0076 0.9895 0.9895 0.0000 0.0000 0.2074 0.0780 0.0597 0.0000 0.0000 0.0668 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 51,091 40,346 151 10,249 3,445 0 3,513 4,336 5,659 0 3,569 14,109 0 14,021 53,959 52,011 7,721 7,721 14,746

V-L Flowrate (kg/hr) 1,474,339 1,134,515 4,838 328,760 62,065 0 101,361 123,623 147,458 0 154,354 158,594 0 252,597 1,091,692 1,056,587 156,847 156,847 265,661

Solids Flowrate (kg/hr) 0 0 0 0 0 437,604 0 0 0 413,769 0 332,351 43,828 0 0 0 0 0 0

Temperature (°C) 15 24 32 32 343 15 15 1,278 143 71 83 18 1,500 216 260 215 215 215 288

Pressure (MPa, abs) 0.10 0.11 0.86 0.86 5.10 0.10 0.10 0.10 0.10 0.10 5.62 5.62 4.24 8.274 3.89 3.76 3.76 3.69 4.14

Enthalpy (kJ/kg) 30.93 30.58 26.94 26.94 3,177.81 --- 30.93 1,884.17 835.89 --- 31.45 4,685.53 --- 1,017.873 1,148.27 1,011.50 1,011.50 1,011.03 3,070.04

Density (kg/m3

) 1.2 1.3 11.0 11.0 20.1 --- 1.2 0.2 0.8 --- 98.9 28.4 --- 782.0 17.9 19.0 19.0 18.7 18.2

V-L Molecular Weight 28.857 28.120 32.078 32.078 18.015 --- 28.857 28.514 26.059 --- 43.248 11.241 --- 18.015 20.232 20.314 20.314 20.314 18.015

V-L Flowrate (lbmol/hr) 112,637 88,948 332 22,595 7,595 0 7,744 9,558 12,475 0 7,868 31,105 0 30,912 118,960 114,666 17,022 17,022 32,510

V-L Flowrate (lb/hr) 3,250,361 2,501,177 10,665 724,793 136,831 0 223,464 272,542 325,090 0 340,292 349,640 0 556,880 2,406,768 2,329,375 345,789 345,789 585,682

Solids Flowrate (lb/hr) 0 0 0 0 0 964,752 0 0 0 912,204 0 732,709 96,625 0 0 0 0 0 0

Temperature (°F) 59 74 90 90 650 59 59 2,332 290 160 181 65 2,732 420 500 418 418 419 550

Pressure (psia) 14.7 16.4 125.0 125.0 740.0 14.7 14.7 14.7 14.7 14.4 815.0 815.0 614.7 1,200.0 564.7 544.7 544.7 534.7 600.0

Enthalpy (Btu/lb) 13.3 13.1 11.6 11.6 1,366.2 --- 13.3 810.0 359.4 --- 13.5 2,014.4 --- 437.6 493.7 434.9 434.9 434.7 1,319.9

Density (lb/ft3

) 0.076 0.081 0.685 0.685 1.257 --- 0.076 0.014 0.048 --- 6.174 1.774 --- 48.817 1.120 1.189 1.189 1.166 1.135

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Exhibit 4-2 Case 1 Stream Table, Bituminous Coal to SNG without Carbon Sequestration (continued)

20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37

V-L Mole Fraction

Ar 0.0021 0.0020 0.0029 0.0029 0.0029 0.0029 0.0103 0.0000 0.0118 0.0118 0.0000 0.0005 0.0000 0.0021 0.0000 0.0077 0.0000 0.0000

CH4 0.0000 0.0000 0.0001 0.0001 0.0001 0.0001 0.8334 0.0000 0.9495 0.9495 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.1648 0.1644 0.2366 0.2366 0.2366 0.2366 0.0000 0.0000 0.0000 0.0000 0.0028 0.0484 0.0000 0.1158 0.0000 0.0327 0.0000 0.0000

CO2 0.3242 0.3256 0.0361 0.0361 0.0361 0.0361 0.1217 0.9811 0.0021 0.0021 0.9896 0.4310 0.0000 0.3134 0.9589 0.0713 0.0000 0.0000

COS 0.0001 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0017 0.0000 0.0005 0.0001 0.0000 0.0000 0.0000

H2 0.4956 0.4945 0.7172 0.7172 0.7172 0.7172 0.0076 0.0000 0.0086 0.0086 0.0028 0.0927 0.0000 0.0623 0.0006 0.1325 0.0000 0.0000

H2O 0.0018 0.0018 0.0001 0.0001 0.0001 0.0001 0.0023 0.0189 0.0000 0.0000 0.0045 0.0330 0.0000 0.5017 0.0059 0.0258 1.0000 1.0000

H2S 0.0066 0.0067 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3921 0.0000 0.0021 0.0345 0.0000 0.0000 0.0000

N2 0.0048 0.0048 0.0070 0.0070 0.0070 0.0070 0.0246 0.0000 0.0280 0.0280 0.0000 0.0006 0.0000 0.0008 0.0000 0.5758 0.0000 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1542 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0012 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 50,897 51,011 34,955 638 115 34,202 9,763 1,193 8,570 8,570 11,619 868 0 991 114 4,726 41,891 64,580

V-L Flowrate (kg/hr) 1,036,367 1,041,318 348,816 6,363 1,152 341,301 194,158 51,931 142,227 142,227 508,119 30,029 0 26,262 4,952 123,623 754,680 1,163,420

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0 0 0 10,888 0 0 0 0 0

Temperature (°C) 35 34 31 31 31 31 35 35 35 35 18 48 178 232 21 23 566 39

Pressure (MPa, abs) 3.31 3.24 3.24 3.24 3.24 3.24 2.731 0.138 2.627 6.202 0.9 0.163 0.119 0.085 3.272 0.103 12.512 0.827

Enthalpy (kJ/kg) 45.27 44.52 86.41 86.41 86.41 86.41 42.166 48.781 47.826 13.195 8.0 91.877 --- 1,202.561 -13.721 67.724 3,513.235 164.567

Density (kg/m3) 26.7 26.3 12.6 12.6 12.6 12.6 22.4 2.4 17.8 44.6 17.8 2.1 5,280.4 0.5 73.9 1.1 34.9 992.9

V-L Molecular Weight 20.362 20.414 9.979 9.979 9.979 9.979 19.887 43.519 16.597 16.597 44 34.607 --- 26.492 43.489 26.158 18.015 18.015

V-L Flowrate (lbmol/hr) 112,209 112,460 77,063 1,406 255 75,402 21,523 2,631 18,893 18,893 25,616 1,913 0 2,185 251 10,419 92,354 142,374

V-L Flowrate (lb/hr) 2,284,798 2,295,714 769,007 14,028 2,540 752,440 428,046 114,489 313,557 313,557 1,120,211 66,204 0 57,897 10,916 272,542 1,663,785 2,564,903

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0 0 0 24,003 0 0 0 0 0

Temperature (°F) 95 94 87 87 87 87 95 95 95 95 65 119 352 450 70 74 1,050 103

Pressure (psia) 479.7 469.7 469.6 469.6 469.6 469.6 396.1 20.1 381.0 899.5 135.0 23.7 17.3 12.3 474.5 14.9 1,814.7 120.0

Enthalpy (Btu/lb) 19.5 19.1 37.1 37.1 37.1 37.1 18.1 21.0 20.6 5.7 3.4 39.5 --- 517.0 -5.9 29.1 1,510.4 70.8

Density (lb/ft3) 1.667 1.639 0.789 0.789 0.789 0.789 1.401 0.148 1.114 2.785 1.11 0.133 329.643 0.033 4.616 0.068 2.177 61.987
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

81

Exhibit 4-3 Case 2 Block Flow Diagram, Bituminous Coal to SNG with Carbon Sequestration

PARTIAL RAW

GAS QUENCH

AND COOLING

WATER-GAS

SHIFT REACTORS

& GAS COOLING

WATER

SCRUBBER

ELEVATED

PRESSURE

ASU

SIEMENS

GASIFIER

MERCURY

REMOVAL

DUALSTAGE

SELEXOL

UNIT

CLAUS

PLANT

1

AIR TO ASU

2 3

VENT

GAS

SULFUR

PLANT

OXIDANT

4

10

13

GASIFIER

OXIDANT

DRIED

COAL

SLAG

16

31

32

TAIL GAS

HYDROLYSIS AND

TREATMENT UNIT

33

SULFUR

SYNGAS PRODUCT

COAL

DRYER 6

WET

COAL

9

5

15

TO SOUR

WATER

STRIPPER

STEAM

30

19 CO2

PRODUCT

22

SHIFT

STEAM

STACK

GAS

34

14 QUENCH

WATER

17

METHANATION

REACTORS

26

SNG 

PURIFICATION

28

27

PURIFICATION OFFGAS TO CO2

COMPRESSION

25

PILOT

FUEL

WGS 

BYPASS

11

STEAM

TURBINE

36 37

PROCESS

STEAM

CONDENSATE

DRY GAS

PREP

35

23

24

7

AIR

8

20

CO2

COMPRESSION

27

SNG FOR

EXPORT

SNG 

COMPRESSION 29

21

COS 

HYDROLYSIS 18

TRANSPORT

CO2

11

LOCKHOPPER

VENT

TRANSPORT

CO2

12

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown. See H&MB diagram for more detail.

PURIFICATION

OFF-GAS

TO CO2

COMPRESSOR

FROM LOCK

HOPPERS
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

82

Exhibit 4-4 Case 2 Stream Table, Bituminous Coal to SNG with Carbon Sequestration

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19

V-L Mole Fraction

Ar 0.0092 0.0091 0.0101 0.0101 0.0000 0.0000 0.0092 0.0084 0.0064 0.0000 0.0001 0.0000 0.0000 0.0000 0.0019 0.0020 0.0020 0.0020 0.0000

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0046 0.0006 0.0000 0.0000 0.4229 0.4388 0.4388 0.4388 0.0000

CO2 0.0003 0.0004 0.0000 0.0000 0.0000 0.0000 0.0003 0.1133 0.0869 0.0000 0.9902 0.1240 0.0000 0.0000 0.0381 0.0395 0.0395 0.0401 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0005 0.0006 0.0006 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0048 0.6935 0.0000 0.0000 0.1999 0.2074 0.2074 0.2074 0.0000

H2O 0.0099 0.0039 0.0000 0.0000 1.0000 0.0000 0.0099 0.1718 0.3648 0.0000 0.0001 0.0978 0.0000 1.0000 0.3262 0.3010 0.3010 0.3004 1.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0058 0.0060 0.0060 0.0066 0.0000

N2 0.7732 0.9790 0.0004 0.0004 0.0000 0.0000 0.7732 0.6281 0.4817 0.0000 0.0000 0.0172 0.0000 0.0000 0.0046 0.0047 0.0047 0.0047 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.2074 0.0076 0.9895 0.9895 0.0000 0.0000 0.2074 0.0785 0.0602 0.0000 0.0000 0.0669 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 51,089 40,345 151 10,248 3,445 0 3,531 4,355 5,678 0 3,530 14,089 0 14,016 53,935 51,984 7,779 7,779 14,732

V-L Flowrate (kg/hr) 1,474,284 1,134,472 4,848 328,738 62,065 0 101,888 124,203 148,038 0 154,354 158,594 0 252,508 1,091,580 1,056,432 158,081 158,081 265,396

Solids Flowrate (kg/hr) 0 0 0 0 0 437,604 0 0 0 413,769 0 332,351 43,828 0 0 0 0 0 0

Temperature (°C) 15 24 32 32 343 15 15 1,274 143 71 82 18 1,500 216 260 215 215 215 288

Pressure (MPa, abs) 0.10 0.11 0.86 0.86 5.10 0.10 0.10 0.10 0.10 0.10 5.62 5.62 4.24 8.274 3.89 3.76 3.76 3.69 4.14

Enthalpy (kJ/kg) 30.93 30.58 26.94 26.94 3,177.81 --- 30.93 1,875.99 833.13 --- 27.52 4,692.64 --- 1,017.873 1,148.09 1,011.26 1,011.26 1,010.79 3,070.04

Density (kg/m3

) 1.2 1.3 11.0 11.0 20.1 --- 1.2 0.2 0.8 --- 101.2 28.5 --- 782.0 17.9 19.1 19.1 18.7 18.2

V-L Molecular Weight 28.857 28.120 32.078 32.078 18.015 --- 28.857 28.521 26.073 --- 43.732 11.256 --- 18.015 20.239 20.322 20.322 20.322 18.015

V-L Flowrate (lbmol/hr) 112,633 88,944 333 22,593 7,595 0 7,784 9,601 12,518 0 7,781 31,061 0 30,901 118,905 114,606 17,149 17,149 32,478

V-L Flowrate (lb/hr) 3,250,240 2,501,083 10,688 724,742 136,831 0 224,625 273,820 326,368 0 340,292 349,640 0 556,684 2,406,522 2,329,035 348,508 348,508 585,098

Solids Flowrate (lb/hr) 0 0 0 0 0 964,752 0 0 0 912,204 0 732,709 96,625 0 0 0 0 0 0

Temperature (°F) 59 74 90 90 650 59 59 2,325 290 160 179 65 2,732 420 500 418 418 419 550

Pressure (psia) 14.7 16.4 125.0 125.0 740.0 14.7 14.7 14.7 14.7 14.4 815.0 815.0 614.7 1,200.0 564.7 544.7 544.7 534.7 600.0

Enthalpy (Btu/lb) 13.3 13.1 11.6 11.6 1,366.2 --- 13.3 806.5 358.2 --- 11.8 2,017.5 --- 437.6 493.6 434.8 434.8 434.6 1,319.9

Density (lb/ft3

) 0.076 0.081 0.685 0.685 1.257 --- 0.076 0.014 0.048 --- 6.320 1.778 --- 48.817 1.120 1.190 1.190 1.167 1.135

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

83

Exhibit 4-4 Case 2 Stream Table, Bituminous Coal to SNG with Carbon Sequestration (continued)

20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37

V-L Mole Fraction

Ar 0.0020 0.0020 0.0029 0.0029 0.0029 0.0029 0.0103 0.0000 0.0118 0.0118 0.0001 0.0005 0.0000 0.0021 0.0000 0.0036 0.0000 0.0000

CH4 0.0000 0.0000 0.0001 0.0001 0.0001 0.0001 0.8318 0.0000 0.9495 0.9495 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.1652 0.1649 0.2372 0.2372 0.2372 0.2372 0.0000 0.0000 0.0000 0.0000 0.0046 0.0485 0.0000 0.1153 0.0000 0.0065 0.0000 0.0000

CO2 0.3241 0.3255 0.0361 0.0361 0.0361 0.0361 0.1236 0.9814 0.0021 0.0021 0.9902 0.4310 0.0000 0.3149 0.9630 0.5446 0.0000 0.0000

COS 0.0001 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0017 0.0000 0.0005 0.0000 0.0000 0.0000 0.0000

H2 0.4953 0.4942 0.7166 0.7166 0.7166 0.7166 0.0075 0.0000 0.0085 0.0085 0.0048 0.0927 0.0000 0.0611 0.0006 0.2924 0.0000 0.0000

H2O 0.0018 0.0018 0.0001 0.0001 0.0001 0.0001 0.0023 0.0186 0.0000 0.0000 0.0001 0.0330 0.0000 0.5024 0.0059 0.1514 1.0000 1.0000

H2S 0.0066 0.0067 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3920 0.0000 0.0021 0.0304 0.0000 0.0000 0.0000

N2 0.0048 0.0048 0.0070 0.0070 0.0070 0.0070 0.0245 0.0000 0.0280 0.0280 0.0000 0.0006 0.0000 0.0008 0.0000 0.0014 0.0000 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 50,851 50,965 34,927 638 115 34,174 9,775 1,212 8,562 8,562 14,470 867 0 992 114 576 42,211 65,028

V-L Flowrate (kg/hr) 1,035,837 1,040,786 349,074 6,379 1,152 341,543 194,891 52,765 142,126 142,126 632,824 29,996 0 26,303 4,949 15,936 760,442 1,171,495

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0 0 0 10,891 0 0 0 0 0

Temperature (°C) 35 34 31 31 80 31 35 35 35 35 32 48 178 232 21 51 566 39

Pressure (MPa, abs) 3.31 3.24 3.24 3.24 5.10 3.24 2.73 0.138 2.627 6.202 15.272 0.2 0.119 0.085 3.272 0.103 12.512 0.827

Enthalpy (kJ/kg) 45.24 44.50 86.27 86.27 234.71 86.27 42.02 48.480 47.817 13.183 -216.068 91.9 --- 1,202.323 -13.694 240.482 3,513 164.549

Density (kg/m3) 26.7 26.3 12.7 12.7 17.0 12.7 22.5 2.4 17.9 44.6 799.5 2.1 5,279.9 0.5 74.0 1.1 34.9 992.9

V-L Molecular Weight 20.370 20.422 9.994 9.994 9.994 9.994 19.938 43.526 16.599 16.599 43.732 35 --- 26.526 43.529 27.652 18.015 18.015

V-L Flowrate (lbmol/hr) 112,108 112,359 77,001 1,407 254 75,340 21,549 2,673 18,877 18,877 31,902 1,911 0 2,186 251 1,271 93,059 143,362

V-L Flowrate (lb/hr) 2,283,630 2,294,540 769,577 14,063 2,540 752,974 429,662 116,328 313,334 313,334 1,395,138 66,130 0 57,988 10,910 35,132 1,676,488 2,582,704

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0 0 0 24,010 0 0 0 0 0

Temperature (°F) 95 94 87 87 177 87 95 95 95 95 90 119 352 450 70 123 1,050 103

Pressure (psia) 479.7 469.7 469.6 469.6 740.0 469.6 396.1 20.1 381.0 899.5 2,215.0 23.7 17.3 12.3 474.5 14.9 1,814.7 120.0

Enthalpy (Btu/lb) 19.5 19.1 37.1 37.1 100.9 37.1 18.1 20.8 20.6 5.7 -92.9 39.5 --- 516.9 -5.9 103.4 1,510 70.7

Density (lb/ft3) 1.667 1.640 0.790 0.790 1.061 0.790 1.405 0.148 1.114 2.786 49.913 0 329.612 0.033 4.620 0.069 2.177 61.987
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

84

The coal is simultaneously crushed and dried in the coal mill then delivered to a surge hopper 

with an approximate 2-hour capacity. The drying medium is provided by combining the off-gas 

from the Claus plant TGTU and a slipstream of clean syngas (stream 23) and passing them 

through the incinerator. The incinerator flue gas, with an oxygen content of 8 vol%, is then used 

to dry the coal in the mill (stream 8).

The coal is drawn from the surge hoppers and fed through a pressurization lock hopper system to 

a dense phase pneumatic conveyor, which uses CO2 from the Selexol unit (stream 11) to convey 

the coal to the gasifiers. CO2 is chosen instead of N2 as the transport medium due to the process 

needs of the methanation section, which requires a low level of inerts for a more high value 

product and also eliminates the need for further SNG product purification. Approximately 50 

percent of the coal transport CO2 is vented from the lock hopper. In the non-sequestration case, 

the CO2 is simply vented to the atmosphere and in the sequestration case approximately 97 

percent of the CO2 is recovered and compressed for sequestration. 

Gasifier

There are six Siemens dry feed, pressurized, down flow, entrained, slagging gasifiers, operating 

at 4.24 MPa (615 psia). Coal reacts with oxygen (stream 4) and steam (stream 5) at a 

temperature of 1,499°C (2,730°F) to produce principally hydrogen and carbon monoxide. The 

clean syngas recycle stream is used as pilot fuel for the gasifier burners. The Siemens gasifiers 

use a ‘cooling screen’ (heat exchanger tubes) in the gasification zone of the gasifier. Circulating 

water passes through these heat exchangers and LP steam is generated in an external steam drum. 

Molten slag builds up a layer on the cooling screen and protects the cooling screen against the 

high reaction temperatures. Liquid slag from the reaction phase only comes in contact with the 

solidified slag layer and hence no corrosion of the reactor wall can take place. The gasifier 

reaction temperature is maintained by setting the oxygen/feedstock (primary) and steam to 

feedstock (secondary) ratios within precise limits.

Raw Gas Cooling/Particulate Removal

The Siemens system in this study uses a partial water quench to 899°C (1,650°F) with a syngas 

cooler for steam generation. High-temperature heat recovery in each gasifier train is 

accomplished in three steps, including the gasifier cooling screen. The product gas from the 

gasifier is cooled using quench water (stream 14) to lower the temperature below the ash melting 

point. Syngas then goes through a raw gas cooler, which lowers the gas temperature to 260°C 

(500°F), and produces HP steam for use in the steam cycle.

The ash that is not carried out with the gas forms slag and runs down the interior walls, exiting 

the gasifier in liquid form. The slag is solidified in a quench tank for disposal (stream 13). 

Lockhoppers are used to reduce the pressure of the solids from 4.24 MPa (615 psia) to ambient.

Syngas Scrubber/Sour Water Stripper

Downstream of the quench section is a raw gas scrubber system including two venturi scrubbers 

and a partial condenser. In two successive venturi scrubbers the raw gas is intensely mixed with 

water to remove the fine ash and soot particles. Cyclone-type separators remove water and 

particles from the raw gas flow. The scrubbers run on circuit water and additional water (e.g.,

gas condensate from the downstream gas cooling after CO shift, if applicable). To reduce fine 

particles and the salty fogs from the raw gas, a partial condensation of the raw gas is done 

downstream of the scrubber unit. In the partial condenser the raw gas is cooled down to 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

85

condense a portion of the water content and separate fine particles. This generated gas 

condensate is separated from the raw gas and collected in a separator drum with a demister.

The sour water stripper removes NH3, SO2, and other impurities from the waste stream of the 

scrubber. The sour gas stripper consists of a sour drum that accumulates sour water from the gas 

scrubber and condensate from synthesis gas coolers (SGCs). Sour water from the drum flows to 

the sour stripper, which consists of a packed column with a steam-heated reboiler. Sour gas is 

stripped from the liquid and sent to the SRU. Remaining water is sent to wastewater treatment.

Sour Gas Shift and COS Hydrolysis

The SGS and COS hydrolysis units are employed in combination to achieve a 3:1 H2 to CO ratio 

required for methanation and to reduce the amount of COS entering the AGR system. H2S and 

COS are at significant concentrations, requiring removal to achieve the low design level 

necessary for methanation synthesis. H2S is removed in an AGR process; however, because 

COS is not readily removed, it is catalytically converted to H2S in the SGS reactor and COS 

hydrolysis unit.

Following the water scrubber, the gas is reheated to 214°C (418°F) and fed to the SGS and COS 

hydrolysis reactors. This raw gas reheat temperature is controlled to achieve a nominal 

temperature of 232°C (450°F) entering the SGS reactor when combined with steam injection. 

Approximately 85 percent of the raw gas stream exiting the scrubber is sent to the SGS reactor. 

Steam (stream 19) is injected into the SGS reactor at 288°C (550°F) and 4.14 MPa (600 psia) to 

drive the shift reaction and maintain a 0.3 H2O to dry gas ratio exiting the reactor. The 

remaining raw gas from the scrubber is sent to the hydrolysis reactor in the bypass (stream 17) 

and COS is hydrolyzed with steam over a catalyst bed to H2S, which is more easily removed by 

the AGR solvent.

Mercury Removal and Acid Gas Removal

Before the raw fuel gas can be treated in the AGR process, it must be cooled to about 35°C 

(95°F). During this cooling through a series of heat exchangers, most of the water vapor 

condenses. This water, which contains some NH3, is sent to the sour water stripper. The cooled 

syngas (stream 20) then passes through a carbon bed to remove 95 percent of the Hg (Section 

3.1.6).

The AGR process is a two stage Selexol process where H2S is removed in the first stage and CO2

in the second stage of absorption. The process results in three product streams, the clean syngas 

(stream 22), a CO2-rich stream (streams 11 and 30), and an acid gas feed to the Claus plant 

(stream 31). In both cases, the acid gas contains about 40 percent H2S and 45 percent CO2 with 

the balance primarily H2 and CO. The CO2-rich stream is discussed further in the CO2

compression section. 

CO2 Compression

CO2 from the AGR process is generated at two pressure levels, a LP stream at 0.12 MPa 

(17 psia) and an HP stream at 1.03 MPa (150 psia). For the non-sequestration case (Case 1), a 

portion of the captured CO2 from the HP stream is further compressed to 5.62 MPa (815 psia) to 

provide the transport medium in the coal feed/lock hopper system and the remaining CO2 is 

vented to the atmosphere. For the carbon sequestration case (Case 2), the LP stream is 

compressed to 1.0 MPa (150 psia) and then combined with the HP stream. The combined 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

86

stream is further compressed to a SC condition at 15.3 MPa (2,215 psia) using a multiple-stage, 

intercooled compressor. At 5.17 MPa (750 psia), a portion of the CO2 compression stream is 

withdrawn, further compressed to 5.86 MPa (850 psia) using a boost compressor (stream 11), 

and sent to the lock hopper system. During compression, the CO2 stream is dehydrated to a 

dewpoint of -40oC (-40°F) with triethylene glycol prior to extraction of the transport CO2. The 

raw CO2 stream from the Selexol process contains over 99 percent CO2. The dehydrated CO2

(stream 30 in Exhibit 4-3) is transported to the plant fence line and is sequestration ready. CO2

TS&M costs were estimated using the methodology described in Section 2.8.

Methanation System and SNG Compression

Clean syngas from the Selexol unit (stream 25) is sent to the methanation reactors after syngas is 

withdrawn to fulfill the requirements of the gasifier (stream 24) and the coal drying system 

(stream 23). The syngas is reacted over three methanation reactors with interstage cooling that 

generates superheated HP and medium pressure steam as described in Section 3.1.8. Process 

condensate is removed from the SNG product (stream 26), which now contains approximately 83

vol% CH4. The SNG product is further purified by a molecular sieve, which removes 98.5 vol% 

of the CO2 and all of the water. The purification off-gas (stream 27) contains over 98 vol% CO2

and is either vented in the non-sequestration case or sent to CO2 compression for sequestration in 

the carbon sequestration case. The purified SNG product stream (stream 28) is compressed to 

6.21 MPa (900 psia) to meet natural gas pipeline specifications (stream 29).

Claus Unit

The SRU is a Claus bypass type SRU utilizing oxygen instead of air. The Claus plant produces 

molten sulfur (stream 32) by reacting approximately one third of the H2S in the feed to SO2, then 

reacting the H2S and SO2 to sulfur and water. The combination of Claus technology and SCOT 

tail gas technology results in an overall sulfur recovery exceeding 99 percent.

Utilizing oxygen instead of air in the Claus plant reduces the overall cost of the sulfur recovery 

plant. The sulfur plant produces elemental sulfur. Feed for each case consists of acid gas from 

both the acid gas cleanup unit (stream 31) and a vent stream from the sour water stripper in the 

gasifier section.

In the furnace waste heat boiler steam is generated. This steam is used to satisfy all Claus 

process preheating and reheating requirements as well as to provide some steam to the mediumpressure steam header. The sulfur condensers produce 0.45 MPa (65 psia) steam for the LP 

steam header.

Power Block

The methanation system and syngas cooler in the gasifier generates superheated steam that is 

used to power a commercially available ST using a 12.4MPa/566°C (1800 psig/1050°F) steam 

cycle (stream 36). 

Air Separation Unit (ASU)

The ASU is designed to produce 99 mol% O2 for use in the gasifier (stream 4) and SRU (stream 

3). The plant is designed with four production trains. The main air compressor is powered by an 

electric motor. Nitrogen is vented to the atmosphere or used for ammonia synthesis in the coproduction cases.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

87

Balance of Plant

Balance of plant items were covered in Section 3.1.

4.1.2

System assumptions for Cases 1 and 2, Siemens gasifier using Illinois No. 6 coal with and 

without carbon sequestration, are compiled in 

Key System Assumptions

Exhibit 4-5.

Exhibit 4-5 Cases 1 and 2 Plant Study Configuration Matrix

Case 1 Case 2

Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O2:Coal Ratio, kg O2/kg dry coal 0.784 0.784

Carbon Conversion, % 99.5 99.5

Syngas HHV at Gasifier Outlet, 

kJ/Nm3 (Btu/scf) 10,283 (276) 10,283 (276)

Steam Cycle, MPa/°C (psig/°F) 12.4/566/534

(1800/1050/994)

12.4/566/533

(1800/1050/992)

Condenser Pressure, mm Hg

(in Hg) 51 (2.0) 51 (2.0)

Combustion Turbine N/A N/A

Gasifier Technology Siemens Siemens

Oxidant 99 vol% Oxygen 99 vol% Oxygen

Coal Illinois No. 6 Illinois No. 6

Coal Feed Moisture Content, % 11.12 11.12

COS Hydrolysis Reactor Yes Yes

Water Gas Shift Yes Yes

H2S Separation Selexol (1st Stage) Selexol (1st Stage)

Sulfur Removal, % 99.3 99.9

CO2 Separation Selexol (2nd Stage) Selexol (2nd Stage)

CO2 Sequestered, % N/A 62.3

Sulfur Recovery

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Methanation System Based on Haldor Topsoe 

TREMPTM Process

Based on Haldor Topsoe 

TREMPTM Process

Particulate Control Scrubber and AGR 

Absorber

Scrubber and AGR 

Absorber

Mercury Control Carbon Bed Carbon Bed

NOx Control N/A N/A
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

88

Balance of Plant – All Cases

The balance of plant assumptions are common to all cases and are presented in Exhibit 4-6.

Exhibit 4-6 Balance of Plant Assumptions

Cooling water system Recirculating Wet Cooling Tower

Fuel and Other storage

Coal 30 days

Slag 30 days

Sulfur 30 days

Sorbent 30 days

Plant Distribution Voltage

Motors below 1hp 110/220 volt

Motors between 1 hp and 

250 hp 480 volt

Motors between 250 hp and 

5,000 hp 4,160 volt

Motors above 5,000 hp 13,800 volt

Steam Generators 24,000 volt

Grid Interconnection Voltage 345 kV

Water and Waste Water

Makeup Water

The water supply is 50 percent from a local Publicly 

Owned Treatment Works and 50 percent from 

groundwater, and is assumed to be in sufficient 

quantities to meet plant makeup requirements.

Makeup for potable, process, and de-ionized (DI) 

water is drawn from municipal sources

Process Wastewater

Water associated with gasification activity and storm 

water that contacts equipment surfaces is collected 

and treated for discharge through a permitted 

discharge.

Sanitary Waste Disposal

Design includes a packaged domestic sewage 

treatment plant with effluent discharged to the 

industrial wastewater treatment system. Sludge is 

hauled off site. Packaged plant was sized for 5.68 

cubic meters per day (1,500 gallons per day)

Water Discharge

Most of the process wastewater is recycled to the 

cooling tower basin. Blowdown is treated for 

chloride and metals, and discharged.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

89

4.1.3

The sparing philosophy for Cases 1 and 2 is provided below. Single trains are utilized 

throughout with exceptions where equipment capacity requires an additional train. There is no 

redundancy other than normal sparing of rotating equipment.

Sparing Philosophy

The plant design consists of the following major subsystems:

• Three ASUs (3 x 33%).

• Six trains of coal drying and dry feed systems (6 x 17%).

• Six trains of gasification, including gasifier and SGC (6 x 17%).

• Three trains of syngas clean-up process (3 x 33%).

• Three trains of two-stage Selexol (3 x 33%).

• Three trains of methanation reactors (3 x 33%).

• Two trains of Claus-based sulfur recovery (2 x 50%). 

• One ST (1 x 100%).

4.1.4

The Siemens SNG plant without and with carbon sequestration and using Illinois No. 6 coal 

produces an average net output of 57 Bscf/year at 90 percent CF. The HHV conversion 

efficiency of the non-sequestration case is 61.4 percent and 61.3 percent for the carbon 

sequestration case. 

Cases 1 and 2 Performance Results

Overall performance for the two plants is summarized in Exhibit 4-7, which includes auxiliary 

power requirements and production values. The ASU accounts for approximately 68 percent of 

the total auxiliary load in the non-sequestration case and 54 percent in the carbon sequestration

case, distributed between the main air compressor, the oxygen compressor, and ASU auxiliaries. 

CO2 compression accounts for about 19 percent of the total auxiliary load for the carbon 

sequestration case. The AGR process accounts for about 13 percent and 11 percent of the 

auxiliary load for the non-sequestration and sequestration cases, respectively. All other 

individual auxiliary loads are less than 3 percent of the total.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

90

Exhibit 4-7 Cases 1 and 2 Plant Performance Summary

POWER SUMMARY 

(Gross Power at Generator Terminals, kWe) Case 1 Case 2

Steam Turbine Power 308,000 310,600

TOTAL POWER, kWe 308,000 310,600

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 700 700

Coal Milling 4,500 4,500

Slag Handling 1,140 1,140

Air Separation Unit Auxiliaries 1,000 1,000

Air Separation Unit Main Air Compressor 120,220 120,220

Oxygen Compressor 20,910 20,910

CO2 Solid Feed System Compressors 4,950 240

SNG Compressors 6,290 6,290

Methanation Plant Recycle Compressor 5,840 5,840

Gasifier Pilot Fuel Compressor and Incinerator Air 

Blower 300 300

CO2 Compressor 0 50,400

Boiler Feedwater Pumps 4,980 5,000

Condensate Pump 420 430

Quench Water Pump 640 640

Circulating Water Pump 6,240 6,200

Ground Water Pumps 650 640

Cooling Tower Fans 3,640 3,610

Scrubber Pumps 1,000 1,000

Acid Gas Removal 27,790 27,750

Steam Turbine Auxiliaries 100 100

Claus Plant/TGTU Auxiliaries 250 250

Claus Plant TG Recycle Compressor 280 280

Miscellaneous Balance of Plant2 3,000 3,000

Transformer Losses 1,510 1,650

TOTAL AUXILIARIES, kWe 216,350 262,090

NET POWER, kWe 91,650 48,510

SNG Production Rate, MNm3/hr (Mscf/hr) 202.9 (7,169) 202.7 (7,163)

Capacity Factor 90% 90%

Net Exported Power Efficiency (HHV) 2.8% 1.5%

SNG Conversion Efficiency (HHVproduct/HHVcoal), % 61.4% 61.3%

Coal to SNG Product Yield, MNm3

SNG/tonnecoal

(MscfSNG/toncoal) 0.44 (14.9) 0.44 (14.8)

Coal Feed Flow Rate, kg/hr (lb/hr) 437,604 (964,752) 437,604 (964,752)

Thermal Input,

1 kWth 3,298,455 3,298,455

Condenser Cooling Duty, GJ/hr (MMBtu/hr) 1,709 (1,620) 1,730 (1,640)

Raw Water Withdrawal, m3/min (gpm) 27.1 (7,169) 27.0 (7,123)

Raw Water Consumption, m3/min (gpm) 21.6 (5,708) 21.5 (5,672)

1 - HHV of Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)

2 - Includes plant control systems, lighting, heating, ventilating, and air conditioning (HVAC), and 

miscellaneous low voltage loads
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

91

Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, and PM were discussed in Section 

2.5. A summary of the plant air emissions for Cases 1 and 2 is presented in Exhibit 4-8. The 

first emissions metric is based on coal heat input to the gasifier.

Exhibit 4-8 Cases 1 and 2 Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

90% capacity factor

Case 1 Case 2 Case 1 Case 2

SO2

0.012 

(0.027)

0.0001 

(0.0003)

1,103

(1,216) 11 (12)

NOX Negligible Negligible Negligible Negligible

Particulates 0.003 

(0.0071)

0.003 

(0.0071) 286 (315) 286 (315)

Hg 2.46E-7 

(5.71E-7)

2.46E-7 

(5.71E-7)

0.023

(0.025)

0.023

(0.025)

CO2 55 (128) 2.1 (4.9) 5,169,343 

(5,698,226)

195,324 

(215,308)

The low level of SO2 emissions in Case 2 is achieved by capture of the sulfur in the gas by the 

two-stage Selexol AGR process and co-sequestration with the CO2 product stream. The clean 

syngas exiting the AGR process has a sulfur concentration of less than 5 ppmv in both cases. 

The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental 

sulfur. The Claus plant tail gas is treated using an amine based system to capture most of the 

remaining sulfur. The clean syngas from the tail gas treatment unit is combined with a 

slipstream of clean syngas from the Selexol process, passed through an incinerator, and the hot, 

inert incinerator offgas is used to dry coal prior to being vented to the atmosphere. The higher 

sulfur emissions in Case 1 are due to the sulfur contained in the CO2-rich stream from the 

Selexol process, which is vented rather than sequestered.

NOX emissions are negligible because no CT is used for power generation.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a syngas 

scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent 

filterable particulate only.

Ninety five percent of mercury is captured from the syngas by an activated carbon bed. CO2

emissions represent the uncontrolled (Case 1) and controlled (Case 2) discharge from the 

process.

The carbon balance for the two cases is shown in Exhibit 4-9. The carbon input to the plant 

consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not used in the 

carbon capture equation below, but it is not neglected in the balance since Aspen accounts for air 

components throughout. Carbon leaves the plant as SNG product, unburned carbon in the slag, 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

92

CO2 in the coal dryer incinerator stack gas and ASU vent gas, and the CO2 product (either vented 

or sequestered). The carbon capture efficiency is presented in two distinct ways. The first way 

defines capture as the amount of carbon in the CO2 product for sequestration relative to the 

amount of carbon in the coal less carbon contained in the slag, and is represented by the 

following fraction:

(Carbon in Product for Sequestration)/[(Carbon in the Coal)-(Carbon in Slag)] or

Non sequestration (Case 1)

381,246/(614,979-3,075)*100 = 62.3% (Case 2)

The second way does not penalize the production facility for the carbon converted to SNG

product, as the end use of the SNG is unknown. In a carbon constrained scenario, the SNG may 

or may not be used in a scenario where carbon capture and sequestration (CCS) is implemented 

(or to what extent the capture is accomplished). For this method the burden of carbon mitigation 

falls on the end-user. The following fraction represents this scenario: 

[(Carbon in Product for Sequestration) + (Carbon in SNG Product)]/[(Carbon in the Coal)-

(Carbon in Slag)] or

(0 + 215,937)/(614,979 – 3,075)*100 = 35.3% (Case 1)

(381,246 + 215,774)/(614,979-3,075)*100 = 97.6% (Case 2)

Exhibit 4-9 Cases 1 and 2 Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Case 1 Case 2 Case 1 Case 2

Coal 278,950 

(614,979)

278,950 

(614,979) Slag 1,395 (3,075) 1,395 (3,075)

Air (CO2) 214 (472) 214 (473) SNG Purification 

Off-Gas

14,062 

(31,001) N/A

ASU Vent 201 (442) 200 (442)

SNG 97,947 

(215,937)

97,874 

(215,774)

CO2 Selexol Vent 138,526 

(305,398) N/A

CO2 Lock Hopper 

Vent

21,126 

(46,575) 841 (1,855)

CO2 Product N/A 172,930 

(381,246)

Stack 5,907 

(13,023)

5,924 

(13,061)

Total 279,164 

(615,451)

279,164 

(615,451) Total 279,164 (615,451)

279,164 

(615,451)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

93

Exhibit 4-10 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the 

stack gas, and sulfur co-sequestered with the CO2 product. Sulfur in the slag is considered 

negligible. The total sulfur capture is represented by the following fraction:

(Sulfur byproduct + Sulfur in CO2 product)/Sulfur in the coal or 

(24,003 + 0)/24,181 = 99.3% (Case 1) 

(24,010 + 157)/24,181 = 99.9% (Case 2)

Exhibit 4-10 Cases 1 and 2 Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Case 1 Case 2 Case 1 Case 2

Coal 10,968 

(24,181)

10,968 

(24,181)

Elemental 

Sulfur

10,888 

(24,003)

10,891 

(24,010)

SNG 5 (12) 5 (12)

CO2 Vent 

Streams/Stack 75 (166) 1 (3)

CO2 Product N/A 71 (157)

Total 10,968 

(24,181)

10,968 

(24,181) Total 10,968 (24,181)

10,968 

(24,181)

Exhibit 4-11 shows the overall water balance for the plant. Water demand represents the total 

amount of water required for a particular process. Some water is recovered within the process, 

primarily as syngas condensate, and is re-used as internal recycle. The difference between 

demand and recycle is raw water withdrawal. Raw water withdrawal is defined as the water 

removed from the ground or diverted from a surface-water source for use in the plant and was 

assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water 

withdrawal can be represented by the water metered from a raw water source and used in the 

plant processes for any and all purposes, such as cooling tower makeup, BFW makeup, quench 

system makeup, and slag handling makeup. The difference between water withdrawal and 

process water discharge is defined as water consumption and can be represented by the portion 

of the raw water withdrawn that is evaporated, transpired, incorporated into products or 

otherwise not returned to the water source from which it was withdrawn. Water consumption 

represents the net impact of the plant process on the water source.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

94

Exhibit 4-11 Cases 1 and 2 Water Balance

Case 1 Case 2

Water Demand, m3/min (gpm)

Slag Handling 0.95 (251) 0.95 (251)

Quench/Wash 4.2 (1,114) 4.2 (1,113)

Condenser Makeup 5.9 (1,548) 5.9 (1,547)

 Gasifier Steam 1.0 (274) 1.0 (274)

 Shift Steam 4.4 (1,171) 4.4 (1,170)

 BFW Makeup 0.39 (103) 0.39 (103)

Cooling Tower 24.3 (6,417) 24.1 (6,370)

Total 35.3 (9,330) 35.1 (9,282)

Internal Recycle, m3/min (gpm)

Slag Handling 0.95 (251) 0.95 (251)

Quench/Wash 4.2 (1,114) 4.2 (1,113)

Condenser Makeup 0.0 (0) 0.0 (0)

Cooling Tower 3.0 (796) 3.0 (794)

 Water from Coal Drying 0.0 (0) 0.0 (0)

 BFW Blowdown 0.39 (103) 0.39 (103)

 SWS Blowdown 0.71 (187) 0.71 (187)

 SWS Excess 1.9 (505) 1.9 (504)

Total 8.2 (2,161) 8.2 (2,159)

Raw Water Withdrawal, m3/min (gpm)

Slag Handling 0.0 (0) 0.0 (0)

Quench/Wash 0.0 (0) 0.0 (0)

Condenser Makeup 5.9 (1,548) 5.9 (1,547)

 Gasifier Steam 1.0 (274) 1.0 (274)

 Shift Steam 4.4 (1,171) 4.4 (1,170)

 BFW Makeup 0.39 (103) 0.39 (103)

Cooling Tower 21.3 (5,621) 21.1 (5,576)

Total 27.1 (7,169) 27.0 (7,123)

Process Water Discharge, m3/min (gpm)

SWS Blowdown 0.07 (19) 0.07 (19)

Cooling Tower Blowdown 5.5 (1,443) 5.4 (1,433)

Total 5.5 (1,462) 5.5 (1,451)

Raw Water Consumption, m3/min (gpm)

Slag Handling 0.0 (0) 0.0 (0)

Quench/Wash 0.0 (0) 0.0 (0)

SWS Blowdown -0.07 (-19) -0.07 (-19)

Condenser Makeup 5.9 (1,548) 5.9 (1,547)

Cooling Tower 15.8 (4,178) 15.7 (4,144)

Total 21.6 (5,708) 21.5 (5,672)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

95

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 4-12 through 

Exhibit 4-17:

• Coal gasification and ASU

• Syngas cleanup (including sulfur recovery and tail gas recycle)

• Methanation, SNG purification, compression, and power cycle

An overall plant energy balance is provided in tabular form in Exhibit 4-18 for the two cases.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

96

Exhibit 4-12 Case 1 Gasification and ASU Heat and Mass Balance

Claus Tail Gas

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ILLINOIS NO. 6 SNG PLANT

CASE 1

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 1

ASU AND GASIFICATION

DWG. NO.

BL-HMB-CS-1-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

PAGES

1 OF 3

Ambient Air

Intercooled

Air Compressor

Elevated

Pressure

ASU

Intercooled

Oxygen Compressor

Milled Coal

ASU

Vent

Slag

Removal

Slag

GROSS PLANT POWER: 308 MWE

AUXILIARY LOAD: 216 MWE

NET PLANT POWER: 92 MWE

SNG PRODUCTION: 7,169 MSCF/HR

Dried Coal Coal

Feeding

Steam

CO2 to Lock Hoppers

Boost

Compressor

Siemens Gasifier

964,752 W

3,250,361 W

59.0 T

14.7 P

13.3 H

724,793 W

90.0 T

125.0 P

11.6 H

724,793 W

516.2 T

740.0 P

107.1 H

136,831 W

650.0 T

740.0 P

1,316.8 H

96,625 W

ENG UNITS

To Claus Plant

10,665 W

90.0 T

125.0 P

11.6 H

2,501,177 W

74.4 T

16.4 P

13.1 H

325,090 W

290.0 T

14.7 P

359.4 H

272,542 W

2,332.4 T

14.7 P

810.0 H

Syngas

Quench

Cooler

Syngas to Scrubber

SH

Steam

4

1

6 10

3

13

5

2

Quench Water

15

Lock Hopper

Vent

170,146 W

340,292 W

181.3 T

815.0 P

13.5 H

11

340,292 W

60.0 T

149.7 P

1.8 H

14

556,880 W

SH

Steam

SH

Steam

2,406,768 W

499.7 T

564.7 P

493.7 H

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Sour Gas

Sour Water

Water

Steam

CO2

Tail Gas/

Flue Gas

24 Pilot Fuel

2,540 W

176.8 T

740.0 P

101.1 H

1,082,350 W

65.2 T

815.0 P

2,014.4 H

Coal 

Dryer

Coal Dryer 

Incinerator

Incinerator Fan

Combustion Air

Syngas

Synthesis Gas

Coal Dryer

Stack Gas

23

9

7

8

35

223,464 W

59.0 T

14.7 P

13.3 H

912,204 W

272,542 W

74.2 T

14.9 P

29.1 H

14,028 W

87.0 T

469.6 P

37.1 H

12

HP

BFW
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

97

Exhibit 4-13 Case 1 Gas Cleanup Heat and Mass Balance

Mercury 

Removal

Knock

Out

Raw Syngas Drum

to Scrubber

Sour

Drum

To Water Treatment

Makeup Water

Catalytic

Reactor

Beds

High

Temperature

Shift

Blowdown

From

ASU LP CO2

Shift

Steam

HP BFW

Syngas

Coolers

Sour

Stripper

Two-Stage

Selexol

Clean Gas

CO2

Acid Gas

Syngas

Scrubber Condensate

To Deaerator Condensate

585,682 W

550.0 T

600.0 P

1,270.5 H

2,329,375 W

418.4 T

544.7 P

434.9 H

2,406,768 W

499.7 T

564.7 P

493.7 H

2,329,375 W

360.8 T

554.7 P

412.1 H

2,295,714 W

94.1 T

469.7 P

19.1 H

769,007 W

87.0 T

469.6 P

37.1 H

66,204 W

119.0 T

23.7 P

39.5 H

1,120,211 W

64.8 T

135.0 P

3.4 H

935,051 W

339.3 T

115.0 P

339.2 H

2,915,056 W

516.6 T

519.7 P

435.3 H

752,440 W

87.0 T

469.6 P

37.1 H

24,003 W

5,032 W

293.0 T

65.0 P

1,036.0 H

10,665 W

90.0 T

125.0 P

11.6 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ILLINOIS NO. 6 SNG PLANT

CASE 1

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 1

GAS CLEANUP

DWG. NO.

BL-HMB-CS-1-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

2 OF 3

Sour Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 308 MWE

AUXILIARY LOAD: 216 MWE

NET PLANT POWER: 92 MWE

SNG PRODUCTION: 7,169 MSCF/HR

1,983,586 W

418.4 T

544.7 P

434.9 H

345,789 W

22

20

15

33

CO2

Tail Gas/

Flue Gas

16

17

19

345,789 W

418.9 T

534.7 P

434.7 H

2,284,798 W

95.0 T

479.7 P

19.5 H

High Temperature

Methanation Reactor

Pre-heater

Tail Gas Cleanup Unit

3

21

CO2 to Lock

Hoppers

Vented

CO2 Product

Claus Plant

Tail 

Gas

Furnace

Sulfur

32

31

HP CO2

30

894,215 W

60.0 T

135.0 P

3.8 H

566,288 W

60.0 T

149.7 P

1.8 H

340,292 W

60.0 T

149.7 P

1.8 H

Syngas to

Methanation

Boost

Compressor

2,540 W

Pilot Fuel

to Gasifier

2,540 W

176.8 T

740.0 P

101.1 H

24 25

Condensate

from Methnation

HT Shift

Pre-heater 57,897 W

450.0 T

12.3 P

517.0 H

34

10,916 W

70.0 T

474.5 P

-5.9 H

Tail Gas

Compressor

COS Hydrolysis

18

Incinerator Fuel

23

To Coal Dryer

35

14,028 W

87.0 T

469.6 P

37.1 H

272,542 

W

74.2 T

14.9 P

29.1 H
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

98

Exhibit 4-14 Case 1 Methanation and Power Block Heat and Mass Balance

Steam Seal 

Regulator

65 PSIA Header

Steam Injection

To Gasifier

Make-up

Gland

Steam

Condenser

Condensate to Preheating

Condensate

Pump

2,564,903 W

101.1 T

1.0 P

69.1 H

774,218 W

1,663,785 W

1,050.0 T

1,814.7 P

1,510.4 H

2,564,903 W

102.5 T

120.0 P

70.8 H

1,400 W

1,400 W

212.0 T

14.7 P

179.9 H

136,831 W

650.0 T

740.0 P

1,316.8 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ILLINOIS NO. 6 SNG PLANT

CASE 5

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 1

METHANATION AND POWER BLOCK

DWG. NO.

BL-HMB-CS-1-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 308 MWE

AUXILIARY LOAD: 216 MWE

NET PLANT POWER: 92 MWE

SNG PRODUCTION: 7,169 MSCF/HR

Flue Gas

Deaerator

HT Reactor

LP TURBINE GENERATOR HP

TURBINE IP

TURBINE

HOT WELL

AIR-COOLED 

CONDENSER CONDENSER

IP Pump

To Shift Steam

Production

LP Pump

250 PSIA

Attemperating Water

HP Pump

Recycle

Compressor

Syngas from

Selexol Unit

Knock

Out

Drum

Molecular 

Sieve 

Purification 

Unit

Multistage 

Intercooled 

SNG 

Compressor

Clean Up

HT Reactor Reator

Purification

Off-Gas

SNG

Product

Condensate to

Sour Drum

Reactor

Pre-heater

IP BFW

SH Shift Steam

IP/LP BFW

IP/LP Steam IP Steam IP BFW

36

37

1,712,037 W

752,440 W

87.0 T

469.6 P

37.1 H

25

572.0 T

447.5 P

631.3 H

587.8 T

475.0 P

640.4 H

572.0 T

464.6 P

567.8 H

1,290.3 T

457.5 P

1,103.4 H

2,114,905 W

1,035.6 T

436.8 P

971.4 H

392.0 T

426.8 P

583.3 H

655.4 T

416.1 P

782.6 H

335.0 T

406.1 P

413.2 H

428,046 W

95.0 T

396.1 P

18.1 H

114,489 W

95.0 T

20.1 P

21.0 H 313,557 W

95.0 T

381.0 P

20.6 H

95.0 T

899.5 P

5.7 H

799,492 W

278.9 T

450.0 P

248.5 H

672,549 W

235,000 W

298.0 T

65.0 P

1,178.6 H

1,543,774 W

501.9 T

65.0 P

1,283.0 H

IP BFW

14,034 W

278.8 T

379.0 P

248.2 H

26

27 28 29

10,910 W

657.8 T

18.0 P

1,362.5 H

To Syngas Cooler SH Steam from Syngas Cooler

Reheater

(Syngas Cooler)

P-640

Attemperation

Water

1,607,011 W

994.4 T

501.4 P

1,516.9 H

21,128 W
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

99

Exhibit 4-15 Case 2 Gasifier and ASU Heat and Mass Balance

Claus Tail Gas

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ILLINOIS NO. 6 SNG PLANT

W/ CO2 CAPTURE

CASE 2

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 2

ASU AND GASIFICATION

DWG. NO.

BL-HMB-CS-2-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

PAGES

1 OF 3

Ambient Air

Intercooled

Air Compressor

Elevated

Pressure

ASU

Intercooled

Oxygen Compressor

Milled Coal

ASU

Vent

Slag

Removal

Slag

GROSS PLANT POWER: 311 MWE

AUXILIARY LOAD: 262 MWE

NET PLANT POWER: 49 MWE

SNG PRODUCTION: 7,163 MSCF/HR

Dried Coal Coal

Feeding

Steam

CO2 to Lock Hoppers

Boost

Compressor

Siemens Gasifier

964,752 W

3,250,240 W

59.0 T

14.7 P

13.3 H

724,742 W

90.0 T

125.0 P

11.6 H

136,831 W

650.0 T

740.0 P

1,316.8 H

1,849,838 W

2,732.0 T

604.7 P

1,135.4 H

96,625 W

ENG UNITS

To Claus Plant

10,688 W

90.0 T

125.0 P

11.6 H

2,501,083 W

74.4 T

16.4 P

13.1 H

326,368 W

290.0 T

14.7 P

358.2 H

273,820 W

2,324.7 T

14.7 P

806.5 H

Syngas

Quench

Cooler

Raw Syngas

to Scrubber

SH

Steam

1

6 10

3

13

5

2

Quench Water

15

6,787 W

340,292 W

179.4 T

815.0 P

11.8 H

11

340,292 W

165.5 T

750.0 P

9.5 H

14

556,684 W

SH

Steam

SH

Steam

2,406,522 W

499.7 T

564.7 P

493.6 H

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Sour Gas

Sour Water

Water

Steam

CO2

Tail Gas/

Flue Gas

24 Pilot Fuel

2,540 W

176.8 T

740.0 P

100.9 H

1,082,350 W

Coal 

Dryer

Coal Dryer 

Incinerator

Incinerator Fan

Combustion Air

Syngas

Synthesis Gas

Coal Dryer

Stack Gas

23

9

7

8

35

224,625 W

59.0 T

14.7 P

13.3 H

912,204 W

35,132 W

123.0 T

14.9 P

103.4 H

14,063 W

87.0 T

469.6 P

37.1 H

12

HP Vent to

CO2 Compressor

Lock Hopper

Atmospheric Vent

LP Vent to

CO2 Compressor

135,586 W 27,773 W

4

HP

BFW
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

100

Exhibit 4-16 Case 2 Gas Cleanup Heat and Mass Balance

SNG Purification

Off Gas

Mercury 

Removal

Knock

Out

Raw Syngas Drum

to Scrubber

Sour

Drum

To Water Treatment

Makeup Water

Catalytic

Reactor

Beds

High

Temperature

Shift

Blowdown

From

ASU

Shift

Steam

HP BFW

Syngas

Coolers

Sour

Stripper

Two-Stage

Selexol

Clean Gas

CO2

Acid Gas

Syngas

Scrubber Condensate

To Deaerator Condensate

585,098 W

550.0 T

600.0 P

1,270.5 H

2,329,035 W

418.4 T

544.7 P

434.8 H

2,406,522 W

499.7 T

564.7 P

493.6 H

2,329,035 W

360.8 T

554.7 P

412.0 H

2,294,540 W

94.1 T

469.7 P

19.1 H

769,577 W

87.0 T

469.6 P

37.1 H

66,130 W

119.0 T

23.7 P

39.5 H

340,292 W

165.5 T

750.0 P

9.5 H

934,234 W

339.3 T

115.0 P

339.2 H

2,914,132 W

516.7 T

519.7 P

435.4 H

752,974 W

87.0 T

469.6 P

37.1 H

24,010 W

5,180 W

292.0 T

65.0 P

1,006.8 H

10,688 W

90.0 T

125.0 P

11.6 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ILLINOIS NO. 6 SNG PLANT

W/ CO2 CAPATURE

CASE 2

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 2

GAS CLEANUP

DWG. NO.

BL-HMB-CS-2-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

2 OF 3

Sour Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 311 MWE

AUXILIARY LOAD: 262 MWE

NET PLANT POWER: 49 MWE

SNG PRODUCTION: 7,163 MSCF/HR

1,980,527 W

418.4 T

544.7 P

434.8 H

348,508 W

22

20

15

33

CO2

Tail Gas/

Flue Gas

16

17

19

348,508 W

419.0 T

534.7 P

434.6 H

2,283,630 W

95.0 T

479.7 P

19.5 H

High Temperature

Methanation Reactor

Pre-heater

Tail Gas Cleanup Unit

3

21

CO2 to

Sequestration

CO2 to

Lock Hoppers

Claus Plant

Tail 

Gas

Furnace

Sulfur

32

31

1,395,138 

W

90.0 T

2,215.0 P

-92.9 H

Syngas to

Methanation

Boost

Compressor

2,540 W

Pilot Fuel

to Gasifier

2,540 W

176.8 T

740.0 P

100.9 H

24

25

Condensate

from Methnation

HT Shift

Pre-heater 57,988 W

450.0 T

12.3 P

516.9 H

34 10,910 W

70.0 T

474.5 P

-5.9 H

COS Hydrolysis

18

Incinerator Fuel

23

To Coal Dryer

27

35

14,063 W

87.0 T

469.6 P

37.1 H

35,132 W

123.0 T

14.9 P

103.4 H

Multistage 

Intercooled CO2

Compressor

30

HP CO2

LP Lock

Hopper Vent HP Lock

Hopper Vent

LP CO2

116,328 W

95.0 T

20.1 P

20.8 H

27,773 W

135,586 W

701,234 W

83.4 T

149.7 P

6.7 H

1,037,286 W

51.9 T

16.7 P

Tail Gas 6.5 H

Compressor
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

101

Exhibit 4-17 Case 2 Methanation and Power Block Heat and Mass Balance

Steam Seal 

Regulator

65 PSIA Header

Steam Injection

To Gasifier

Make-up

Gland

Steam

Condenser

Condensate to Preheating

Condensate

Pump

2,582,704 W

101.1 T

1.0 P

69.1 H

773,525 W

1,676,488 W

1,050.0 T

1,814.7 P

1,510.4 H

2,582,704 W

102.5 T

120.0 P

70.7 H

1,400 W

1,400 W

212.0 T

14.7 P

179.9 H

136,831 W

650.0 T

740.0 P

1,316.8 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ILLINOIS NO. 6 SNG PLANT

W/ CO2 CAPTURE

CASE 2

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 2

METHANATION AND POWER BLOCK

DWG. NO.

BL-HMB-CS-2-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 311 MWE

AUXILIARY LOAD: 262 MWE

NET PLANT POWER: 49 MWE

SNG PRODUCTION: 7,163 MSCF/HR

Flue Gas

Deaerator

HT Reactor

LP TURBINE GENERATOR HP

TURBINE IP

TURBINE

HOT WELL

AIR-COOLED 

CONDENSER CONDENSER

IP Pump

To Shift Steam

Production

LP Pump

250 PSIA

Attemperating Water

HP Pump

Recycle

Compressor

Syngas from

Selexol Unit

Knock

Out

Drum

Molecular 

Sieve 

Purification 

Unit

Multistage 

Intercooled 

SNG 

Compressor

Clean Up

HT Reactor Reator

Purification Off-Gas

(To CO2 Compressor)

SNG

Product

Condensate to

Sour Drum

Reactor

Pre-heater

SH Steam from

Syngas Cooler

IP BFW

SH Shift

Steam

IP/LP BFW

IP/LP Steam IP Steam IP BFW

36

37

1,725,670 W

752,974 W

87.0 T

469.6 P

37.1 H

25

572.0 T

447.5 P

629.7 H

587.8 T

475.0 P

638.8 H

572.0 T

464.6 P

566.5 H

1,290.2 T

457.5 P

1,101.1 H

2,118,638 W

1,035.8 T

436.8 P

969.2 H

392.0 T

426.8 P

581.4 H

655.0 T

416.1 P

780.0 H

335.0 T

406.1 P

412.8 H

429,662 W

95.0 T

396.1 P

18.1 H

116,328 W

95.0 T

20.1 P

20.8 H 313,334 W

95.0 T

381.0 P

20.6 H

95.0 T

899.5 P

5.7 H

788,093 W

288.8 T

450.0 P

258.6 H

672,225 W

239,143 W

298.0 T

65.0 P

1,178.6 H

1,558,124 W

500.0 T

65.0 P

1,282.1 H

IP BFW

13,827 W

288.7 T

379.0 P

258.3 H

26

27 28 29

10,912 W

657.6 T

18.0 P

1,362.4 H

To Syngas Cooler

Attemperation

Water

To Gasifier

Reheater

(Syngas Cooler)

1,620,752 W

991.8 T

501.4 P

1,515.5 H

21,860 W
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

102

Exhibit 4-18 Cases 1 and 2 Energy Balance

HHV Sensible + Latent Power Total

Case 1 Case 2 Case 1 Case 2 Case 1 Case 2 Case 1 Case 2

Heat In, GJ/hr (MMBtu/hr)

Coal 11,874 

(11,255)

11,874 

(11,255) 12.1 (11.5) 12.1 (11.5) 0 (0) 0 (0) 11,887 (11,266) 11,887 (11,266)

ASU Air 0 (0) 0 (0) 48.7 (46.2) 49.6 (47.0) 0 (0) 0 (0) 49 (46) 50 (47)

Raw Water Makeup 0 (0) 0 (0) 102.0 (96.7) 101.4 (96.1) 0 (0) 0 (0) 102 (97) 101 (96)

Auxiliary Power 0 (0) 0 (0) 0.0 (0.0) 0.0 (0.0) 779 (738) 944 (894) 779 (738) 944 (894)

Totals 11,874 

(11,255)

11,874 

(11,255) 162.9 (154.4) 163.1 (154.6) 779 (738) 944 (894) 12,816 (12,147) 12,981 (12,304)

Heat Out, GJ/hr (MMBtu/hr)

ASU Intercoolers 0 (0) 0 (0) 325 (308) 325 (308) 0 (0) 0 (0) 325 (308) 325 (308)

ASU Vent 0 (0) 0 (0) 34.7 (32.9) 34.7 (32.9) 0 (0) 0 (0) 35 (33) 35 (33)

Slag 46 (43) 46 (43) 79.1 (75.0) 79.1 (75.0) 0 (0) 0 (0) 125 (118) 125 (118)

Coal Drying Stack Gas 0 (0) 0 (0) 123.3 (116.8) 123.3 (116.9) 0 (0) 0 (0) 123 (117) 123 (117)

Sulfur 101 (96) 101 (96) 1.2 (1.2) 1.2 (1.2) 0 (0) 0 (0) 102 (97) 102 (97)

Auxiliary Cooling Loads 0 (0) 0 (0) 882 (836) 842 (798) 0 (0) 0 (0) 882 (836) 842 (798)

CO2 0 (0) 0 (0) 6.5 (6.1) -136.7 (-129.6) 0 (0) 0 (0) 6 (6) -137 (-130)

Cooling Tower Blowdown 0 (0) 0 (0) 40.6 (38.5) 40.3 (38.2) 0 (0) 0 (0) 41 (38) 40 (38)

SNG 7,272 

(6,892)

7,266 

(6,887) 1.9 (1.8) 1.9 (1.8) 0 (0) 0 (0) 7,274 (6,894) 7,268 (6,888)

SNG Purification Off-Gas 0 (0) 0 (0) 3 (2) 3 (2) 0 (0) 0 (0) 3 (2) 3 (2)

Condenser 0 (0) 0 (0) 1,710 (1,621) 1,727 (1,637) 0 (0) 0 (0) 1,710 (1,621) 1,727 (1,637)

Process Losses* 0 (0) 0 (0) 1,082 (1,026) 1,410 (1,336) 0 (0) 0 (0) 1,082 (1,026) 1,410 (1,336)

Power 0 (0) 0 (0) 0.0 (0.0) 0.0 (0.0) 1,109 

(1,051)

1,118 

(1,060) 1,109 (1,051) 1,118 (1,060)

Totals 7,418 

(7,031)

7,412 

(7,026) 4,289 (4,065) 4,450 (4,218) 1,109 (1,051)

1,118 

(1,060) 12,816 (12,147) 12,981 (12,304)

* Includes other energy losses not explicitly accounted for in the model.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

103

4.1.5

Major equipment items for the Siemens gasifier SNG plant without and with carbon 

sequestration using Illinois No. 6 coal are shown in the following tables. The accounts used in 

the equipment list correspond to the account numbers used in the cost estimates in Section 

Cases 1 and 2 Equipment Lists

4.1.6. 

In general, the design conditions include a 10 percent contingency for flows and heat duties and 

a 21 percent contingency for heads on pumps and fans.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

104

ACCOUNT 1 COAL HANDLING

Equipment 

No. Description Type Operating Qty. Spares Case 1 DesignCondition

Case 2 Design 

Condition

1

Bottom Trestle 

Dumper and 

Receiving Hoppers

N/A 2 0 181 tonne (200 ton) 181 tonne (200 ton)

2 Feeder Belt 2 0 572 tonne/hr (630 tph) 572 tonne/hr (630 tph)

3 Conveyor No. 1 Belt 1 0 1,134 tonne/hr 

(1,250 tph)

1,134 tonne/hr 

(1,250 tph)

4 Transfer Tower No. 1 Enclosed 1 0 N/A N/A

5 Conveyor No. 2 Belt 1 0 1,134 tonne/hr 

(1,250 tph)

1,134 tonne/hr 

(1,250 tph)

6 As-Received Coal 

Sampling System Two-stage 1 0 N/A N/A

7 Stacker/Reclaimer Traveling, 

linear 1 0 1,134 tonne/hr(1,250 tph)

1,134 tonne/hr

(1,250 tph)

8 Reclaim Hopper N/A 2 1 91 tonne (100 ton) 91 tonne (100 ton)

9 Feeder Vibratory 2 1 363 tonne/hr (400 tph) 363 tonne/hr (400 tph)

10 Conveyor No. 3 Belt w/ 

tripper 1 0 726 tonne/hr (800 tph) 726 tonne/hr (800 tph)

11 Crusher Tower N/A 1 0 N/A N/A

12 Coal Surge Bin w/ 

Vent Filter Dual outlet 2 0 363 tonne (400 ton) 363 tonne (400 ton)

13 Crusher Impactor 

reduction 2 0 8 cm x 0 - 3 cm x 0(3" x 0 - 1-1/4" x 0)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

14 As-Fired Coal 

Sampling System

Swing 

hammer 1 1 N/A N/A
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

105

Equipment 

No. Description Type Operating Qty. Spares Case 1 DesignCondition

Case 2 Design 

Condition

15 Conveyor No. 4 Belt 

w/tripper 1 0 726 tonne/hr (800 tph) 726 tonne/hr (800 tph)

16 Transfer Tower No. 2 Enclosed 1 0 N/A N/A

17 Conveyor No. 5 Belt w/ 

tripper 1 0 726 tonne/hr (800 tph) 726 tonne/hr (800 tph)

18 Coal Silo w/ Vent 

Filter and Slide Gates Field erected 3 0 1,633 tonne (1,800 ton) 1,633 tonne (1,800 ton)

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

1 Feeder Vibratory 6 0 82 tonne/hr (90 tph) 82 tonne/hr (90 tph)

2 Conveyor No. 6 Belt 

w/tripper 3 0 163 tonne/hr (180 tph) 163 tonne/hr (180 tph)

3 Roller Mill Feed 

Hopper Dual Outlet 3 0 318 tonne (350 ton) 318 tonne (350 ton)

4 Weigh Feeder Belt 6 0 82 tonne/hr (90 tph) 82 tonne/hr (90 tph)

5 Pulverizer Rotary 6 0 82 tonne/hr (90 tph) 82 tonne/hr (90 tph)

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

1 Demineralized Water 

Storage Tank

Vertical, 

cylindrical, 

outdoor

3 0 635,949 liters 

(168,000 gal)

635,949 liters 

(168,000 gal)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

106

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

2 Condensate Pumps Vertical 

canned 2 1

10,751 lpm @ 91 m H2O

(2,840 gpm @ 300 ft 

H2O)

10,826 lpm @ 91 m H2O

(2,860 gpm @ 300 ft 

H2O)

3 Deaerator Horizontal 

spray type 2 0 806,034 kg/hr (1,777,000 lb/hr)

806,487 kg/hr 

(1,778,000 lb/hr)

4 Intermediate Pressure 

Feedwater Pump

Horizontal 

centrifugal, 

single stage

2 1

6,359 lpm @ 341 m H2O

(1,680 gpm @ 1120 ft 

H2O)

6,322 lpm @ 335 m H2O

(1,670 gpm @ 1100 ft 

H2O)

5 High Pressure 

Feedwater Pump

Barrel type, 

multi-stage, 

centrifugal

2 1

HP water: 7,419 lpm @ 

1,676 m H2O (1,960 

gpm @ 5,500 ft H2O)

HP water: 7,457 lpm @ 

1,676 m H2O (1,970 

gpm @ 5,500 ft H2O)

6 Auxiliary Boiler

Shop 

fabricated, 

water tube

1 0

18,144 kg/hr, 2.8 MPa, 

343°C

(40,000 lb/hr, 400 psig, 

650°F)

18,144 kg/hr, 2.8 MPa, 

343°C

(40,000 lb/hr, 400 psig, 

650°F)

7 Service Air 

Compressors

Flooded 

Screw 3 1 28 m3

/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

8 Instrument Air Dryers Duplex, 

regenerative 3 1 28 m3

/min (1,000 scfm) 28 m3/min (1,000 scfm)

9 Closed Cycle Cooling 

Heat Exchangers

Plate and 

frame 2 0 664 GJ/hr (629 MMBtu/hr)

642 GJ/hr (608 

MMBtu/hr) each

10 Closed Cycle Cooling 

Water Pumps

Horizontal 

centrifugal 2 1

238,102 lpm @ 21 m 

H2O

(62,900 gpm @ 70 ft 

H2O)

230,153 lpm @ 21 m 

H2O

(60,800 gpm @ 70 ft 

H2O)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

107

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

11 Engine-Driven Fire 

Pump

Vertical 

turbine, 

diesel 

engine

1 1

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft 

H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft 

H2O)

12 Fire Service Booster 

Pump

Two-stage 

horizontal 

centrifugal

1 1 2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

13 Raw Water Pumps

Stainless 

steel, single 

suction

2 1

7,533 lpm @ 18 m H2O

(1,990 gpm @ 60 ft 

H2O)

7,457 lpm @ 18 m H2O

(1,970 gpm @ 60 ft 

H2O)

14 Ground Water Pumps

Stainless 

steel, single 

suction

4 1 3,748 lpm @ 268 m H2O

(990 gpm @ 880 ft H2O)

3,748 lpm @ 268 m H2O

(990 gpm @ 880 ft H2O)

15 Filtered Water Pumps

Stainless 

steel, single 

suction

2 1

6,095 lpm @ 49 m H2O

(1,610 gpm @ 160 ft 

H2O)

6,095 lpm @ 49 m H2O

(1,610 gpm @ 160 ft 

H2O)

16 Filtered Water Tank Vertical, 

cylindrical 2 0 2,933,694 liter (775,000 gal)

2,929,909 liter 

(774,000 gal)

17 Makeup Water 

Demineralizer

Anion, 

cation, and 

mixed bed

2 0 2,688 lpm (710 gpm) 2,688 lpm (710 gpm)

18 Liquid Waste 

Treatment System 1 0 10 years, 24-hour storm 10 years, 24-hour storm
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

108

ACCOUNT 4 GASIFIER, ASU, AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

1 Gasifier

Pressurized 

dry-feed, 

entrained 

bed

6 0

1,905 tonne/day, 4.2 

MPa

(2,100 tpd, 615 psia)

1,905 tonne/day, 4.2 

MPa

(2,100 tpd, 615 psia)

2 Synthesis Gas Cooler

Convective 

spiralwound tube 

boiler

6 0 200,034 kg/hr

(441,000 lb/hr)

200,034 kg/hr

(441,000 lb/hr)

3

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical

upflow 6 0 200,034 kg/hr(441,000 lb/hr)

200,034 kg/hr

(441,000 lb/hr)

4 Raw Gas Coolers

Shell and 

tube with 

condensate 

drain

12 0 415,491 kg/hr

(916,000 lb/hr)

415,491 kg/hr

(916,000 lb/hr)

5 Raw Gas Knockout 

Drum

Vertical 

with mist 

eliminator

3 0

380,110 kg/hr, 35°C, 

3.3 MPa

(838,000 lb/hr, 95°F, 

485 psia)

379,657 kg/hr, 35°C,

3.3 MPa

(837,000 lb/hr, 95°F, 

485 psia)

6 Flare Stack

Selfsupporting, 

carbon steel, 

stainless 

steel top, 

pilot ignition

3 0 400,068 kg/hr (882,000 

lb/hr) syngas

400,068 kg/hr (882,000 

lb/hr) syngas
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

109

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

7 ASU Main Air 

Compressor

Centrifugal, 

multi-stage 3 0

7,391 m3/min 

@ 1.3 MPa

(261,000 scfm 

@ 190 psia)

7,391 m3/min 

@ 1.3 MPa

(261,000 scfm 

@ 190 psia)

8 Cold Box Vendor 

design 3 0

2,903 tonne/day

(3,200 tpd) of 

99% purity oxygen

2,903 tonne/day

(3,200 tpd) of 

99% purity oxygen

9 Oxygen Compressor Centrifugal, 

multi-stage 3 0

1,472 m3/min 

(52,000 scfm)

Suction - 0.9 MPa 

(130 psia)

Discharge - 5.1 MPa 

(740 psia)

1,472 m3/min 

(52,000 scfm)

Suction - 0.9 MPa 

(130 psia)

Discharge - 5.1 MPa 

(740 psia)

10 Coal Feed System 

CO2 Compressor

Centrifugal, 

multi-stage 3 0

510 m3/min 

(18,000 scfm)

Suction - 1.0 MPa 

(150 psia)

Discharge - 5.7 MPa 

(820 psia)

510 m3/min 

(18,000 scfm)

Suction - 5.2 MPa 

(750 psia)

Discharge - 5.7 MPa 

(820 psia)

ACCOUNT 5A SYNGAS CLEANUP

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

1 Mercury Adsorber Sulfated 

carbon bed 3 0

380,110 kg/hr

(838,000 lb/hr)

35°C (95°F)

3.3 MPa (480 psia)

379,657 kg/hr

(837,000 lb/hr)

35°C (95°F)

3.3 MPa (480 psia)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

110

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

2 Zinc Oxide Guard 

Bed Fixed bed 1 0 450 Nm3

/min

(15,891 acfm)

450 Nm3/min

(15,877 acfm)

3 Sulfur Plant Claus type 2 0 144 tonne/day (158 tpd) 144 tonne/day (158 tpd)

4 COS Hydrolysis 

Reactor

Fixed bed, 

catalytic 3 0

57,606 kg/hr

(127,000 lb/hr)

216°C (420°F)

3.7 MPa (540 psia)

58,060 kg/hr

(128,000 lb/hr)

216°C (420°F)

3.7 MPa (540 psia)

5 Water Gas Shift 

Reactor

Fixed bed, 

catalytic 3 0

427,284 kg/hr

(942,000 lb/hr)

232°C (450°F)

3.7 MPa (540 psia)

426,830 kg/hr

(941,000 lb/hr)

232°C (450°F)

3.7 MPa (540 psia)

6 Shift Reactor Heat 

Recovery Exchanger

Shell and 

Tube 3 0

Exchanger 1: 45 GJ/hr 

(43 MMBtu/hr)

Exchanger 2: 81 GJ/hr 

(77 MMBtu/hr)

Exchanger 3: 18 GJ/hr 

(17 MMBtu/hr)

Exchanger 1: 45 GJ/hr 

(43 MMBtu/hr)

Exchanger 2: 81 GJ/hr 

(77 MMBtu/hr)

Exchanger 3: 18 GJ/hr 

(17 MMBtu/hr)

7 Acid Gas Removal 

Plant

Two-stage 

Selexol 3 0

381,925 kg/hr

(842,000 lb/hr)

34°C (94°F)

3.2 MPa (470 psia)

381,471 kg/hr

(841,000 lb/hr)

34°C (94°F)

3.2 MPa (470 psia)

8 Tail Gas Treatment 

Unit

Proprietary 

amine, 

absorber/stri

pper

2 0

11,552 kg/hr

(25,467 lb/hr)

49°C (120°F)

0.1 MPa (10.6 psia)

11,570 kg/hr

(25,508 lb/hr)

49°C (120°F)

0.1 MPa (10.6 psia)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

111

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

9 Tail Gas Treatment 

Incinerator N/A 2 0

59,021 kg/hr

(130,120 lb/hr)

23°C (74°F)

0.1 MPa (14.9 psia)

59,021 kg/hr

(130,120 lb/hr)

23°C (74°F)

0.1 MPa (14.9 psia)

10 Tail Gas Recycle 

Compressor Centrifugal 2 1 2,807 kg/hr @ 03.3 MPa(6,189 lb/hr @ 475 psia)

2,806 kg/hr @ 03.3 MPa

(6,186 lb/hr @ 475 psia)

ACCOUNT 5A SNG PRODUCTION/METHANATION SYSTEM

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

1 Methanation Reactor 

Preheater 

Shell and 

Tube 3 0 95 GJ/hr (90 MMBtu/hr) 95 GJ/hr (90 MMBtu/hr)

2 Methanation Reactor 

1

Fixed Bed, 

catalytic 3 0

476,726 kg/hr

(1,051,000 lb/hr)

699°C (1,290°F)

3.2 MPa (460 psia)

477,633 kg/hr

(1,053,000 lb/hr)

699°C (1,290°F)

3.2 MPa (460 psia)

3 Methanation Reactor 

Intercooler 1

Shell and 

Tube 3 0 413 GJ/hr (391 MMBtu/hr)

413 GJ/hr (391 

MMBtu/hr)

4 Methanation Reactor 

Intercooler 2

Shell and 

Tube 3 0 111 GJ/hr (105 MMBtu/hr)

111 GJ/hr (105 

MMBtu/hr)

5 Methanation Reactor 

2

Fixed Bed, 

catalytic 3 0

125,191 kg/hr

(276,000 lb/hr)

560°C (1040°F)

3.1 MPa (450 psia)

125,191 kg/hr

(276,000 lb/hr)

560°C (1040°F)

3.1 MPa (450 psia)

6 Methanation Reactor 

Intercooler 3

Shell and 

Tube 3 0 29 GJ/hr (28 MMBtu/hr) 29 GJ/hr (28 MMBtu/hr)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

112

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

7 Methanation Reactor 

3

Fixed Bed, 

catalytic 3 0

125,191 kg/hr

(276,000 lb/hr)

349°C (660°F)

3.0 MPa (430 psia)

125,191 kg/hr

(276,000 lb/hr)

343°C (650°F)

3.0 MPa (430 psia)

8 Methanation Reactor 

Intercooler 4

Shell and 

Tube 3 0 41 GJ/hr (39 MMBtu/hr) 41 GJ/hr (39 MMBtu/hr)

9 Methanation Reactor 

Intercooler 5

Shell and 

Tube 3 0 66 GJ/hr (63 MMBtu/hr) 66 GJ/hr (62 MMBtu/hr)

10 SNG Purification 

Condenser 1

Shell and 

Tube 3 0 55 GJ/hr (52 MMBtu/hr) 55 GJ/hr (52 MMBtu/hr)

11 SNG Purification 

Condenser 2

Shell and 

Tube 3 0 33 GJ/hr (31 MMBtu/hr) 33 GJ/hr (32 MMBtu/hr)

12 Methanation Recycle 

Compressor Centrifugal 3 1

8,668 m3/min 

(306,100 scfm)

Suction - 3.1 MPa 

(448 psia)

Discharge - 3.3 MPa 

(475 psia)

8,668 m3/min 

(306,100 scfm)

Suction - 3.1 MPa 

(448 psia)

Discharge - 3.3 MPa 

(475 psia)

13 Molecular Sieve 

Purification Reactor Fixed bed 6 0

39,463 kg/hr

(87,000 lb/hr)

129°C (265°F)

2.8 MPa (401 psia)

39,463 kg/hr

(87,000 lb/hr)

129°C (265°F)

2.8 MPa (401 psia)

14 SNG Product 

Compressor

Centrifugal, 

Multi-staged 3 1

1,240 m3/min

(43,800 scfm)

2.6 MPa (381 psia)

6.2 MPa (899 psia)

1,240 m3/min

(43,800 scfm)

2.6 MPa (381 psia)

6.2 MPa (899 psia)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

113

ACCOUNT 5B CO2 COMPRESSION

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

1 CO2 Compressor

Integrally 

geared, 

multi-stage 

centrifugal

4 0 N/A

1,572 m3/min 

@ 15.3 MPa

(55,500 scfm 

@ 2,215 psia)

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

1 Combustion Turbine N/A N/A N/A N/A N/A

2 Combustion Turbine 

Generator N/A N/A N/A N/A N/A

ACCOUNT 7 DUCTING & STACK

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

1 Stack

CS plate, 

type 409SS 

liner

1 0 76 m (250 ft) high x 3.0 

m (10 ft) diameter

76 m (250 ft) high x

2.8 m (9 ft) diameter
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

114

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

1 Steam Turbine Commercially 

available 1 0

324 MW 12.4 

MPa/566°C (1800 psig/ 

1050°F)

327 MW 12.4 

MPa/566°C (1800 psig/ 

1050°F)

2 Steam Turbine 

Generator

Hydrogen cooled, 

static excitation 1 0 360 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase

360 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase

3 Surface 

Condenser

Single pass, 

divided waterbox 

including vacuum 

pumps

1 0

1,878 GJ/hr (1,780 

MMBtu/hr), Condensing 

temperature 16°C 

(60°F), Ambient 

temperature 11°C (20°F)

1,899 GJ/hr (1,800 

MMBtu/hr), Condensing 

temperature 16°C 

(60°F), Ambient 

temperature 11°C (20°F)

4 Air-cooled 

Condenser --- N/A N/A N/A N/A

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

1 Circulating Water 

Pumps Vertical, wet pit 2 1 624,593 lpm @ 30 m(165,000 gpm @ 100 ft)

620,808 lpm @ 30 m

(164,000 gpm @ 100 ft)

2 Cooling Tower

Evaporative, 

mechanical 

draft, multi-cell

1 0

11°C (51.5°F) wet bulb / 

16°C (60°F) CWT / 

27°C (80°F) HWT / 

3,492 GJ/hr (3,310 

MMBtu/hr) heat duty

11°C (51.5°F) wet bulb / 

16°C (60°F) CWT / 

27°C (80°F) HWT / 

3,461 GJ/hr (3,280 

MMBtu/hr) heat duty
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

115

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

1 Slag Quench Tank Water bath 6 0 151,416 liters

(40,000 gal)

151,416 liters

(40,000 gal)

2 Slag Crusher Roll 6 0 8 tonne/hr (9 tph) 8 tonne/hr (9 tph)

3 Slag Depressurizer Proprietary 6 0 8 tonne/hr (9 tph) 8 tonne/hr (9 tph)

4 Slag Receiving Tank Horizontal, 

weir 6 0 90,850 liters (24,000 gal) 90,850 liters (24,000 gal)

5 Black Water 

Overflow Tank

Shop 

fabricated 6 41,640 liters (11,000 gal) 41,640 liters (11,000 gal)

6 Slag Conveyor Drag chain 6 0 8 tonne/hr (9 tph) 8 tonne/hr (9 tph)

7 Slag Separation 

Screen Vibrating 6 0 8 tonne/hr (9 tph) 8 tonne/hr (9 tph)

8 Coarse Slag 

Conveyor Belt/bucket 6 0 8 tonne/hr (9 tph) 8 tonne/hr (9 tph)

9 Fine Ash Settling 

Tank

Vertical, 

gravity 6 0 132,489 liters (35,000 gal)

132,489 liters (35,000 

gal)

10 Fine Ash Recycle 

Pumps

Horizontal 

centrifugal 6 3 38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

11 Grey Water Storage 

Tank Field erected 6 0 41,640 liters (11,000 gal) 41,640 liters (11,000 gal)

12 Grey Water Pumps Centrifugal 6 3

151 lpm @ 433 m H2O

(40 gpm @ 1,420 ft 

H2O)

151 lpm @ 433 m H2O

(40 gpm @ 1,420 ft 

H2O)

13 Slag Storage Bin Vertical, 

field erected 6 0 544 tonne (600 tons) 544 tonne (600 tons)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

116

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

14 Unloading Equipment Telescoping 

chute 2 0 100 tonne/hr (110 tph) 100 tonne/hr (110 tph)

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

1 STG Step-up 

Transformer Oil-filled 1 0 24 kV/345 kV, 360 MVA, 3-ph, 60 Hz

24 kV/345 kV, 360 

MVA, 3-ph, 60 Hz

2 Auxiliary 

Transformer Oil-filled 1 1 24 kV/4.16 kV, 239 MVA, 3-ph, 60 Hz

24 kV/4.16 kV, 289 

MVA, 3-ph, 60 Hz

3 Low Voltage 

Transformer

Dry 

ventilated 1 1 4.16 kV/480 V, 36 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 43 

MVA, 3-ph, 60 Hz

4

STG Isolated Phase 

Bus Duct and Tap 

Bus

Aluminum, 

self-cooled 1 1 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz

5 Medium Voltage 

Switchgear Metal clad 1 1 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz

6 Low Voltage 

Switchgear

Metal 

enclosed 1 0 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz

7 Emergency Diesel 

Generator

Sized for 

emergency 

shutdown

1 0 750 kW, 480 V, 3-ph, 60 

Hz

750 kW, 480 V, 3-ph, 60 

Hz
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

117

ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment 

No.

Descriptio

n Type Operating Qty. Spares Case 1 Design Condition

Case 2 Design 

Condition

1

DCS -

Main 

Control

Monitor/keyboard; 

Operator printer (laser 

color); Engineering 

printer (laser B&W)

1 0

Operator 

stations/printers and 

engineering 

stations/printers

Operator 

stations/printers and 

engineering 

stations/printers

2 DCS -

Processor

Microprocessor with 

redundant input/output 1 0 N/A N/A

3 DCS - Data 

Highway Fiber optic 1 0 Fully redundant, 25% spare

Fully redundant, 25% 

spare
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

118

4.1.6

The cost estimating methodology was described previously in Section 

Cases 1 and 2 Cost Estimating

2.8.

The TPC organized by cost account; owner’s costs; TOC; and initial and annual O&M costs for 

the SNG plant without sequestration using Illinois No. 6 coal (Case 1) are shown in Exhibit 4-19

and Exhibit 4-20. The same data for the SNG plant with carbon sequestration using Illinois No. 

6 coal (Case 2) are shown in Exhibit 4-21, and Exhibit 4-22.

The estimated TOC of the SNG plant without carbon sequestration is 3.24 billion dollars and 

with carbon sequestration is 3.31 billion dollars. Project and process contingencies represent 

11.9 and 3.9 percent for the non-sequestration case and 11.9 and 3.8 percent for the sequestration 

case. The FYCOP is $19.27/MMBtu for the non-sequestration case and $20.95/MMBtu for the

carbon sequestration case as shown in Exhibit ES-6.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

119

Exhibit 4-19 Case 1 Total Plant Cost Details

Client: USDOE/NETL Report Date: 2010-Feb-18

Project: Cost & Performance Baseline for Fossil Energy Plants Vol.2

Case: Case 1 - Siemens Quench SNG Production w/o CO2

Plant Size: 91.65 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $5,729 $0 $2,800 $0 $0 $8,529 $764 $0 $1,859 $11,152

1.2 Coal Stackout & Reclaim $7,404 $0 $1,795 $0 $0 $9,198 $806 $0 $2,001 $12,005

1.3 Coal Conveyors & Yd Crush $6,883 $0 $1,776 $0 $0 $8,659 $760 $0 $1,884 $11,303

1.4 Other Coal Handling $1,801 $0 $411 $0 $0 $2,212 $194 $0 $481 $2,886

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $4,054 $10,138 $0 $0 $14,192 $1,360 $0 $3,110 $18,662

SUBTOTAL 1. $21,817 $4,054 $16,919 $0 $0 $42,790 $3,884 $0 $9,335 $56,009

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $92,942 $0 $13,543 $0 $0 $106,485 $9,671 $0 $23,231 $139,387

2.2 Prepared Coal Storage & Feed $4,402 $1,053 $690 $0 $0 $6,146 $526 $0 $1,334 $8,006

2.3 Dry Coal Injection System $144,878 $1,681 $13,455 $0 $0 $160,014 $13,782 $0 $34,759 $208,555

2.4 Misc.Coal Prep & Feed $2,421 $1,762 $5,282 $0 $0 $9,464 $870 $0 $2,067 $12,401

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $9,409 $7,725 $0 $0 $17,135 $1,587 $0 $3,744 $22,466

SUBTOTAL 2. $244,643 $13,906 $40,695 $0 $0 $299,244 $26,435 $0 $65,136 $390,814

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $3,562 $1,655 $2,008 $0 $0 $7,225 $653 $0 $1,576 $9,454

3.2 Water Makeup & Pretreating $832 $87 $465 $0 $0 $1,385 $132 $0 $455 $1,971

3.3 Other Feedwater Subsystems $3,867 $1,169 $1,913 $0 $0 $6,949 $631 $0 $1,516 $9,096

3.4 Service Water Systems $476 $981 $3,404 $0 $0 $4,861 $474 $0 $1,601 $6,936

3.5 Other Boiler Plant Systems $2,556 $991 $2,455 $0 $0 $6,002 $569 $0 $1,314 $7,885

3.6 FO Supply Sys & Nat Gas $102 $210 $188 $0 $0 $500 $48 $0 $110 $658

3.7 Waste Treatment Equipment $1,164 $0 $710 $0 $0 $1,873 $182 $0 $617 $2,673

3.8 Misc. Power Plant Equipment $1,721 $230 $884 $0 $0 $2,836 $274 $0 $933 $4,042

SUBTOTAL 3. $14,281 $5,323 $12,026 $0 $0 $31,631 $2,964 $0 $8,121 $42,715

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $325,844 $0 $150,858 $0 $0 $476,702 $42,340 $71,505 $88,582 $679,129

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $238,715 $0 w/equip. $0 $0 $238,715 $23,139 $0 $26,185 $288,039

4.4 LT Heat Recovery & FG Saturation $49,590 $0 $18,374 $0 $0 $67,963 $6,510 $0 $14,895 $89,369

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $2,333 $950 $0 $0 $3,283 $315 $0 $719 $4,317

4.7 CO2 Solid Feed System Compressors $10,520 $2,525 $3,787 $0 $0 $16,832 $1,683 $0 $3,703 $22,218

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $21,143 $12,064 $0 $0 $33,207 $3,040 $0 $9,062 $45,309

SUBTOTAL 4. $624,669 $26,001 $186,032 $0 $0 $836,702 $77,027 $71,505 $143,146 $1,128,380

TOTAL PLANT COST SUMMARY 

Contingencies
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

120

Exhibit 4-19 Case 1 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $125,892 $0 $106,823 $0 $0 $232,715 $22,506 $46,543 $60,353 $362,116

5A.2 Elemental Sulfur Plant $16,274 $3,243 $20,996 $0 $0 $40,513 $3,935 $0 $8,890 $53,338

5A.3 Mercury Removal $2,454 $0 $1,868 $0 $0 $4,322 $417 $216 $991 $5,947

5A.4a Shift Reactors $10,461 $0 $4,211 $0 $0 $14,672 $1,407 $0 $3,216 $19,294

5A.4b COS Hydrolysis $1,988 $0 $2,596 $0 $0 $4,583 $446 $0 $1,006 $6,035

5A.5 Methanation $28,050 $11,220 $16,830 $0 $0 $56,100 $5,610 $5,610 $13,464 $80,784

5A.6 SNG Purification & Compression $19,850 $7,940 $11,910 $0 $0 $39,700 $3,970 $0 $8,734 $52,404

5A.7 Fuel Gas Piping $0 $1,753 $1,228 $0 $0 $2,981 $276 $0 $652 $3,909

5A.9 Process Interconnects $0 $12,000 $18,000 $0 $0 $30,000 $3,000 $0 $6,600 $39,600

5A.10 HGCU Foundations $0 $1,776 $1,145 $0 $0 $2,920 $268 $0 $957 $4,145

5A.11 Zinc Oxide Guard Bed $793 $0 $146 $0 $0 $939 $94 $0 $207 $1,239

SUBTOTAL 5A. $205,762 $37,932 $185,752 $0 $0 $429,446 $41,930 $52,369 $105,068 $628,812

 5B CO2 COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.2 Syngas Expander $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $480 $343 $0 $0 $823 $72 $0 $179 $1,074

7.4 Stack $1,814 $0 $682 $0 $0 $2,496 $239 $0 $274 $3,009

7.9 HRSG,Duct & Stack Foundations $0 $364 $349 $0 $0 $713 $66 $0 $234 $1,013

SUBTOTAL 7. $1,814 $844 $1,373 $0 $0 $4,032 $378 $0 $686 $5,096

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $31,384 $0 $5,672 $0 $0 $37,056 $3,557 $0 $4,061 $44,674

8.2 Turbine Plant Auxiliaries $178 $0 $520 $0 $0 $698 $68 $0 $77 $843

8.3 Condenser & Auxiliaries $5,445 $0 $1,666 $0 $0 $7,111 $680 $0 $779 $8,570

8.4 Steam Piping $5,365 $0 $3,774 $0 $0 $9,139 $785 $0 $2,481 $12,405

8.9 TG Foundations $0 $1,125 $1,901 $0 $0 $3,026 $287 $0 $994 $4,307

SUBTOTAL 8. $42,372 $1,125 $13,534 $0 $0 $57,031 $5,377 $0 $8,392 $70,800

Contingencies
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

121

Exhibit 4-19 Case 1 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $8,833 $0 $1,607 $0 $0 $10,440 $994 $0 $1,715 $13,149

9.2 Circulating Water Pumps $2,343 $0 $91 $0 $0 $2,434 $204 $0 $396 $3,034

9.3 Circ.Water System Auxiliaries $186 $0 $27 $0 $0 $213 $20 $0 $35 $268

9.4 Circ.Water Piping $0 $7,768 $2,014 $0 $0 $9,782 $884 $0 $2,133 $12,800

9.5 Make-up Water System $440 $0 $629 $0 $0 $1,069 $103 $0 $234 $1,406

9.6 Component Cooling Water Sys $917 $1,097 $780 $0 $0 $2,794 $262 $0 $611 $3,667

9.9 Circ.Water System Foundations $0 $2,850 $4,844 $0 $0 $7,694 $729 $0 $2,527 $10,951

SUBTOTAL 9. $12,719 $11,715 $9,992 $0 $0 $34,426 $3,197 $0 $7,652 $45,274

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $36,268 $0 $35,772 $0 $0 $72,040 $6,980 $0 $7,902 $86,922

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $818 $0 $890 $0 $0 $1,708 $166 $0 $281 $2,154

10.7 Ash Transport & Feed Equipment $1,097 $0 $265 $0 $0 $1,362 $127 $0 $223 $1,712

10.8 Misc. Ash Handling Equipment $1,694 $2,076 $620 $0 $0 $4,390 $418 $0 $721 $5,529

10.9 Ash/Spent Sorbent Foundation $0 $72 $91 $0 $0 $163 $15 $0 $54 $232

SUBTOTAL 10. $39,877 $2,148 $37,637 $0 $0 $79,662 $7,706 $0 $9,181 $96,549

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $446 $0 $441 $0 $0 $887 $85 $0 $97 $1,069

11.2 Station Service Equipment $5,293 $0 $477 $0 $0 $5,770 $532 $0 $630 $6,933

11.3 Switchgear & Motor Control $9,786 $0 $1,780 $0 $0 $11,566 $1,073 $0 $1,896 $14,535

11.4 Conduit & Cable Tray $0 $4,546 $14,997 $0 $0 $19,543 $1,890 $0 $5,358 $26,792

11.5 Wire & Cable $0 $8,686 $5,707 $0 $0 $14,393 $1,046 $0 $3,860 $19,298

11.6 Protective Equipment $0 $855 $3,112 $0 $0 $3,967 $387 $0 $653 $5,008

11.7 Standby Equipment $330 $0 $322 $0 $0 $652 $62 $0 $107 $821

11.8 Main Power Transformers $8,795 $0 $182 $0 $0 $8,977 $682 $0 $1,449 $11,108

11.9 Electrical Foundations $0 $198 $518 $0 $0 $716 $69 $0 $235 $1,020

SUBTOTAL 11. $24,651 $14,285 $27,537 $0 $0 $66,472 $5,825 $0 $14,286 $86,583

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $539 $0 $360 $0 $0 $899 $85 $45 $154 $1,183

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $358 $0 $229 $0 $0 $587 $56 $29 $134 $806

12.7 Computer & Accessories $5,727 $0 $183 $0 $0 $5,910 $542 $296 $675 $7,423

12.8 Instrument Wiring & Tubing $0 $2,901 $5,930 $0 $0 $8,831 $749 $442 $2,505 $12,527

12.9 Other I & C Equipment $4,270 $0 $2,073 $0 $0 $6,343 $597 $317 $1,089 $8,346

SUBTOTAL 12. $10,894 $2,901 $8,776 $0 $0 $22,571 $2,029 $1,129 $4,558 $30,286

Contingencies
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

122

Exhibit 4-19 Case 1 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $147 $3,143 $0 $0 $3,290 $327 $0 $1,085 $4,702

13.2 Site Improvements $0 $2,615 $3,476 $0 $0 $6,091 $601 $0 $2,008 $8,700

13.3 Site Facilities $4,687 $0 $4,946 $0 $0 $9,632 $950 $0 $3,175 $13,756

SUBTOTAL 13. $4,687 $2,762 $11,564 $0 $0 $19,013 $1,877 $0 $6,267 $27,158

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

14.2 Steam Turbine Building $0 $2,691 $3,834 $0 $0 $6,525 $600 $0 $1,069 $8,194

14.3 Administration Building $0 $870 $630 $0 $0 $1,500 $134 $0 $245 $1,879

14.4 Circulation Water Pumphouse $0 $160 $90 $0 $0 $250 $22 $0 $41 $312

14.5 Water Treatment Buildings $0 $696 $679 $0 $0 $1,375 $124 $0 $225 $1,724

14.6 Machine Shop $0 $445 $305 $0 $0 $750 $67 $0 $123 $939

14.7 Warehouse $0 $726 $464 $0 $0 $1,190 $105 $0 $194 $1,489

14.8 Other Buildings & Structures $0 $528 $411 $0 $0 $940 $84 $0 $205 $1,229

14.9 Waste Treating Building & Str. $0 $1,181 $2,258 $0 $0 $3,439 $321 $0 $752 $4,511

SUBTOTAL 14. $0 $7,297 $8,671 $0 $0 $15,968 $1,456 $0 $2,853 $20,277

TOTAL COST $1,248,184 $130,294 $560,509 $0 $0 $1,938,987 $180,084 $125,003 $384,680 $2,628,754

Owner's Costs

Preproduction Costs

6 Months All Labor $21,523

1 Month Maintenance Materials $3,796

1 Month Non-fuel Consumables $816

1 Month Waste Disposal $577

25% of 1 Months Fuel Cost at 100% CF $3,362

2% of TPC $52,575

Total $82,649

Inventory Capital

60 day supply of fuel and consumables at 100% CF $28,184

0.5% of TPC (spare parts) $13,144

Total $41,328

Initial Cost for Catalyst and Chemicals $16,342

Land $900

Other Owner's Costs $394,313

Financing Costs $70,976

Total Overnight Costs (TOC) $3,235,262

TASC Multiplier 1.201

Total As-Spent Cost (TASC) $3,885,549

Contingencies
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

123

Exhibit 4-20 Case 1 Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 1 - Siemens Quench SNG Production w/o CO2 MWe-net: 92

SNG (MMbtu/hr): 6892 Capacity Factor (%): 90

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 2.0 2.0

 Operator 12.0 12.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 3.0 3.0

 TOTAL-O.J.'s 18.0 18.0

Annual Cost Annual Unit Cost

$ $/MMBtu

Annual Operating Labor Cost $7,102,696 $0.131

Maintenance Labor Cost $27,333,527 $0.503

Administrative & Support Labor $8,609,056 $0.158

Property Taxes and Insurance $52,575,070 $0.968

TOTAL FIXED OPERATING COSTS $95,620,348 $1.760

VARIABLE OPERATING COSTS

$/MMBtu

Maintenance Material Cost $41,000,290 $0.75453

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water(/1000 gallons) 0 5,162 1.08 $0 $1,834,102 $0.03375

Chemicals

MU & WT Chem. (lb) 0 30,752 0.17 $0 $1,748,328 $0.03217

Carbon (Mercury Removal) (lb) 228,466 391 1.05 $239,928 $134,960 $0.00248

COS Catalyst (m3) 116 0 2,397.36 $277,521 $78,053 $0.00144

Water Gas Shift Catalyst (ft3) 5,515 4.72 498.83 $2,750,848 $773,676 $0.01424

ZnO Sorbent (ton) 150 0.51 12,574.00 $1,887,818 $2,123,795 $0.03908

Methanation Catalyst (ft3) 12,295 9.36 440.00 $5,410,004 $1,352,501 $0.02489

Selexol Solution (gal) 431,115 137 13.40 $5,776,182 $602,843 $0.01109

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip 3.75 131.27 $0 $161,773 $0.00298

Subtotal Chemicals $16,342,301 $6,975,929 $0.12838

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000

Supplemental Electricity (for consumption) (MW 0 0 61.60 $0 $0 $0.00000

Gases,N2 etc. (/100scf) 0 0 0.00 $0 $0 $0.00000

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 $0.00000

Subtotal Other $0 $0 $0.00000

Waste Disposal

Spent Mercury Catalyst (lb.) 0 391 0.42 $0 $53,599 $0.00099

Spent ZnO Sorbent (ton) 0 0.51 16.23 $0 $2,740 $0.00005

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 1,160 16.23 $0 $6,180,087 $0.11373

 Subtotal-Waste Disposal $0 $6,236,427 $0.11477

By-products & Emissions 

Sulfur (tons) 0 288 0.00 $0 $0 $0.00000

Supplemental Electricity (for sale) (MWh) 0 2,200 58.00 $0 -$41,908,979 -$0.77125

Subtotal By-Products $0 -$41,908,979 -$0.77125

TOTAL VARIABLE OPERATING COSTS $16,342,301 $14,137,770 $0.26018

Fuel (ton) 0 11,577 38.18 $0 $145,217,654 $2.67245
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

124

Exhibit 4-21 Case 2 Total Plant Cost Details

Client: USDOE/NETL Report Date: 2010-Feb-18

Project: Cost & Performance Baseline for Fossil Energy Plants Vol.2

Case: Case 2 - Siemens Quench SNG Production w/ CO2

Plant Size: 48.51 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $5,729 $0 $2,800 $0 $0 $8,529 $764 $0 $1,859 $11,152

1.2 Coal Stackout & Reclaim $7,404 $0 $1,795 $0 $0 $9,198 $806 $0 $2,001 $12,005

1.3 Coal Conveyors & Yd Crush $6,883 $0 $1,776 $0 $0 $8,659 $760 $0 $1,884 $11,303

1.4 Other Coal Handling $1,801 $0 $411 $0 $0 $2,212 $194 $0 $481 $2,886

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $4,054 $10,138 $0 $0 $14,192 $1,360 $0 $3,110 $18,662

SUBTOTAL 1. $21,817 $4,054 $16,919 $0 $0 $42,790 $3,884 $0 $9,335 $56,009

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $92,942 $0 $13,543 $0 $0 $106,485 $9,671 $0 $23,231 $139,387

2.2 Prepared Coal Storage & Feed $4,402 $1,053 $690 $0 $0 $6,146 $526 $0 $1,334 $8,006

2.3 Dry Coal Injection System $144,878 $1,681 $13,455 $0 $0 $160,014 $13,782 $0 $34,759 $208,555

2.4 Misc.Coal Prep & Feed $2,421 $1,762 $5,282 $0 $0 $9,464 $870 $0 $2,067 $12,401

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $9,409 $7,725 $0 $0 $17,135 $1,587 $0 $3,744 $22,466

SUBTOTAL 2. $244,643 $13,906 $40,695 $0 $0 $299,244 $26,435 $0 $65,136 $390,814

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 FeedwaterSystem $3,582 $1,664 $2,019 $0 $0 $7,265 $657 $0 $1,584 $9,506

3.2 Water Makeup & Pretreating $829 $87 $463 $0 $0 $1,378 $131 $0 $453 $1,962

3.3 Other Feedwater Subsystems $3,889 $1,176 $1,923 $0 $0 $6,988 $634 $0 $1,524 $9,146

3.4 Service Water Systems $474 $976 $3,389 $0 $0 $4,839 $472 $0 $1,593 $6,905

3.5 Other Boiler Plant Systems $2,545 $986 $2,444 $0 $0 $5,974 $567 $0 $1,308 $7,849

3.6 FO Supply Sys & Nat Gas $102 $210 $188 $0 $0 $500 $48 $0 $110 $658

3.7 Waste Treatment Equipment $1,158 $0 $707 $0 $0 $1,865 $182 $0 $614 $2,660

3.8 Misc. Power Plant Equipment $1,721 $230 $884 $0 $0 $2,836 $274 $0 $933 $4,042

SUBTOTAL 3. $14,299 $5,330 $12,016 $0 $0 $31,645 $2,965 $0 $8,120 $42,729

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $325,819 $0 $150,846 $0 $0 $476,665 $42,337 $71,500 $88,575 $679,077

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $238,715 $0 w/equip. $0 $0 $238,715 $23,139 $0 $26,185 $288,039

4.4 LT Heat Recovery & FG Saturation $49,540 $0 $18,356 $0 $0 $67,896 $6,504 $0 $14,880 $89,280

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $2,332 $949 $0 $0 $3,281 $315 $0 $719 $4,315

4.7 CO2 Solid Feed System Compressors $6,696 $1,607 $2,411 $0 $0 $10,713 $1,071 $0 $2,357 $14,142

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $21,143 $12,064 $0 $0 $33,207 $3,040 $0 $9,062 $45,309

SUBTOTAL 4. $620,771 $25,082 $184,626 $0 $0 $830,479 $76,405 $71,500 $141,779 $1,120,162

TOTAL PLANT COST SUMMARY 

Contingencies
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

125

Exhibit 4-21 Case 2 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $125,787 $0 $106,734 $0 $0 $232,521 $22,487 $46,504 $60,302 $361,815

5A.2 Elemental Sulfur Plant $16,277 $3,244 $21,000 $0 $0 $40,521 $3,936 $0 $8,891 $53,349

5A.3 Mercury Removal $2,453 $0 $1,867 $0 $0 $4,320 $417 $216 $991 $5,943

5A.4a Shift Reactors $10,448 $0 $4,205 $0 $0 $14,653 $1,405 $0 $3,212 $19,269

5A.4b COS Hydrolysis $1,999 $0 $2,611 $0 $0 $4,610 $448 $0 $1,012 $6,070

5A.5 Methanation $28,050 $11,220 $16,830 $0 $0 $56,100 $5,610 $5,610 $13,464 $80,784

5A.6 SNG Purification & Compression $19,850 $7,940 $11,910 $0 $0 $39,700 $3,970 $0 $8,734 $52,404

5A.7 Fuel Gas Piping $0 $1,752 $1,227 $0 $0 $2,979 $276 $0 $651 $3,907

5A.9 Process Interconnects $0 $12,000 $18,000 $0 $0 $30,000 $3,000 $0 $6,600 $39,600

5A.10 HGCU Foundations $0 $1,774 $1,144 $0 $0 $2,918 $268 $0 $956 $4,143

5A.11 Zinc Oxide Guard Bed $792 $0 $146 $0 $0 $938 $94 $0 $206 $1,239

SUBTOTAL 5A. $205,656 $37,931 $185,674 $0 $0 $429,261 $41,912 $52,330 $105,019 $628,522

 5B CO2 COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $34,256 $0 $20,173 $0 $0 $54,428 $5,240 $0 $11,934 $71,602

SUBTOTAL 5B. $34,256 $0 $20,173 $0 $0 $54,428 $5,240 $0 $11,934 $71,602

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.2 Syngas Expander $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.9 HRSG,Duct & Stack Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 7. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $31,587 $0 $5,484 $0 $0 $37,071 $3,557 $0 $4,063 $44,691

8.2 Turbine Plant Auxiliaries $173 $0 $504 $0 $0 $677 $66 $0 $74 $817

8.3 Condenser & Auxiliaries $5,488 $0 $1,616 $0 $0 $7,104 $679 $0 $778 $8,561

8.4 Steam Piping $5,591 $0 $3,933 $0 $0 $9,525 $818 $0 $2,586 $12,929

8.9 TG Foundations $0 $1,091 $1,844 $0 $0 $2,934 $278 $0 $964 $4,176

SUBTOTAL 8. $42,839 $1,091 $13,381 $0 $0 $57,310 $5,399 $0 $8,465 $71,174

Contingencies
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

126

Exhibit 4-21 Case 2 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $8,777 $0 $1,597 $0 $0 $10,373 $988 $0 $1,704 $13,065

9.2 Circulating Water Pumps $2,333 $0 $88 $0 $0 $2,421 $203 $0 $394 $3,018

9.3 Circ.Water System Auxiliaries $185 $0 $26 $0 $0 $212 $20 $0 $35 $267

9.4 Circ.Water Piping $0 $7,740 $2,007 $0 $0 $9,747 $881 $0 $2,125 $12,753

9.5 Make-up Water System $438 $0 $627 $0 $0 $1,065 $102 $0 $233 $1,401

9.6 Component Cooling Water Sys $914 $1,093 $778 $0 $0 $2,784 $261 $0 $609 $3,654

9.9 Circ.Water System Foundations $0 $2,834 $4,818 $0 $0 $7,652 $725 $0 $2,513 $10,891

SUBTOTAL 9. $12,647 $11,667 $9,940 $0 $0 $34,254 $3,181 $0 $7,614 $45,048

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $36,268 $0 $35,772 $0 $0 $72,040 $6,980 $0 $7,902 $86,922

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $818 $0 $890 $0 $0 $1,708 $166 $0 $281 $2,154

10.7 Ash Transport & Feed Equipment $1,097 $0 $265 $0 $0 $1,362 $127 $0 $223 $1,712

10.8 Misc. Ash Handling Equipment $1,694 $2,076 $620 $0 $0 $4,390 $418 $0 $721 $5,529

10.9 Ash/Spent Sorbent Foundation $0 $72 $91 $0 $0 $163 $15 $0 $54 $232

SUBTOTAL 10. $39,877 $2,148 $37,637 $0 $0 $79,662 $7,706 $0 $9,181 $96,549

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $435 $0 $431 $0 $0 $866 $83 $0 $95 $1,043

11.2 Station Service Equipment $5,740 $0 $517 $0 $0 $6,258 $577 $0 $683 $7,518

11.3 Switchgear & Motor Control $10,612 $0 $1,930 $0 $0 $12,542 $1,163 $0 $2,056 $15,761

11.4 Conduit & Cable Tray $0 $4,930 $16,263 $0 $0 $21,193 $2,050 $0 $5,811 $29,053

11.5 Wire & Cable $0 $9,419 $6,189 $0 $0 $15,608 $1,134 $0 $4,185 $20,927

11.6 Protective Equipment $0 $855 $3,112 $0 $0 $3,967 $387 $0 $653 $5,008

11.7 Standby Equipment $330 $0 $322 $0 $0 $652 $62 $0 $107 $821

11.8 Main Power Transformers $9,427 $0 $182 $0 $0 $9,609 $729 $0 $1,551 $11,889

11.9 Electrical Foundations $0 $198 $518 $0 $0 $716 $69 $0 $235 $1,020

SUBTOTAL 11. $26,544 $15,402 $29,464 $0 $0 $71,410 $6,254 $0 $15,377 $93,041

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $536 $0 $358 $0 $0 $894 $85 $45 $153 $1,177

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $356 $0 $228 $0 $0 $584 $55 $29 $134 $802

12.7 Computer & Accessories $5,696 $0 $182 $0 $0 $5,879 $540 $294 $671 $7,383

12.8 Instrument Wiring & Tubing $0 $2,885 $5,899 $0 $0 $8,784 $745 $439 $2,492 $12,460

12.9 Other I & C Equipment $4,247 $0 $2,062 $0 $0 $6,309 $594 $315 $1,083 $8,301

SUBTOTAL 12. $10,835 $2,885 $8,729 $0 $0 $22,450 $2,018 $1,123 $4,533 $30,124

Contingencies
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

127

Exhibit 4-21 Case 2 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $147 $3,143 $0 $0 $3,290 $327 $0 $1,085 $4,702

13.2 Site Improvements $0 $2,615 $3,476 $0 $0 $6,091 $601 $0 $2,008 $8,700

13.3 Site Facilities $4,687 $0 $4,946 $0 $0 $9,632 $950 $0 $3,175 $13,756

SUBTOTAL 13. $4,687 $2,762 $11,564 $0 $0 $19,013 $1,877 $0 $6,267 $27,158

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

14.2 Steam Turbine Building $0 $2,624 $3,738 $0 $0 $6,361 $585 $0 $1,042 $7,989

14.3 Administration Building $0 $870 $630 $0 $0 $1,500 $134 $0 $245 $1,879

14.4 Circulation Water Pumphouse $0 $160 $90 $0 $0 $250 $22 $0 $41 $312

14.5 Water Treatment Buildings $0 $693 $676 $0 $0 $1,368 $124 $0 $224 $1,716

14.6 Machine Shop $0 $445 $305 $0 $0 $750 $67 $0 $123 $939

14.7 Warehouse $0 $726 $464 $0 $0 $1,190 $105 $0 $194 $1,489

14.8 Other Buildings & Structures $0 $528 $411 $0 $0 $940 $84 $0 $205 $1,229

14.9 Waste Treating Building & Str. $0 $1,181 $2,258 $0 $0 $3,439 $321 $0 $752 $4,511

SUBTOTAL 14. $0 $7,227 $8,572 $0 $0 $15,798 $1,441 $0 $2,825 $20,064

TOTAL COST $1,278,871 $129,485 $579,389 $0 $0 $1,987,745 $184,716 $124,952 $395,583 $2,692,997

Owner's Costs

Preproduction Costs

6 Months All Labor $21,750

1 Month Maintenance Materials $3,847

1 Month Non-fuel Consumables $813

1 Month Waste Disposal $577

25% of 1 Months Fuel Cost at 100% CF $3,362

2% of TPC $53,860

Total $84,209

Inventory Capital

60 day supply of fuel and consumables at 100% CF $28,181

0.5% of TPC (spare parts) $13,465

Total $41,646

Initial Cost for Catalyst and Chemicals $16,327

Land $900

Other Owner's Costs $403,950

Financing Costs $72,711

Total Overnight Costs (TOC) $3,312,740

TASC Multiplier 1.201

Total As-Spent Cost (TASC) $3,978,601

Contingencies
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

128

Exhibit 4-22 Case 2 Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 2 - Siemens Quench SNG Production w/ CO2 MWe-net: 49

SNG (MMbtu/hr): 6886 Capacity Factor (%): 90

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 2.0 2.0

 Operator 12.0 12.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 3.0 3.0

 TOTAL-O.J.'s 18.0 18.0

Annual Cost Annual Unit Cost

$ $/MMBtu

Annual Operating Labor Cost $7,102,696 $0.131

Maintenance Labor Cost $27,697,722 $0.510

Administrative & Support Labor $8,700,105 $0.160

Property Taxes and Insurance $53,859,942 $0.992

TOTAL FIXED OPERATING COSTS $97,360,465 $1.793

VARIABLE OPERATING COSTS

$/MMBtu

Maintenance Material Cost $41,546,584 $0.76523

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water(/1000 gallons) 0 5,129 1.08 $0 $1,822,333 $0.03356

Chemicals

MU & WT Chem.(lb) 0 30,554 0.17 $0 $1,737,110 $0.03200

Carbon (Mercury Removal) (lb) 228,257 391 1.05 $239,709 $134,836 $0.00248

COS Catalyst (m3) 117 0 2,397.36 $279,597 $78,637 $0.00145

Water Gas Shift Catalyst (ft3) 5,505 4.71 498.83 $2,746,203 $772,369 $0.01423

ZnO Sorbent (ton) 150 0.51 12,574.00 $1,885,197 $2,120,847 $0.03906

Methanation Catalyst (ft3) 12,289 9.35 440.00 $5,407,162 $1,351,791 $0.02490

Selexol Solution (gal) 430,618 137 13.40 $5,769,523 $602,148 $0.01109

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip 3.75 131.27 $0 $161,817 $0.00298

Subtotal Chemicals $16,327,392 $6,959,555 $0.12819

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000

Supplemental Electricity (for consumption) (MW 0 0 61.60 $0 $0 $0.00000

Gases,N2 etc.(/100scf) 0 0 0.00 $0 $0 $0.00000

L.P. Steam(/1000 pounds) 0 0 0.00 $0 $0 $0.00000

Subtotal Other $0 $0 $0.00000

Waste Disposal

Spent Mercury Catalyst (lb.) 0 391 0.42 $0 $53,551 $0.00099

Spent ZnO Sorbent (ton) 0 0.51 16.23 $0 $2,737 $0.00005

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 1,160 16.23 $0 $6,180,087 $0.11383

 Subtotal-Waste Disposal $0 $6,236,374 $0.11487

By-products & Emissions 

Sulfur (tons) 0 288 0.00 $0 $0 $0.00000

Supplemental Electricity (for sale) (MWh) 0 1,164 58.00 $0 -$22,182,265 -$0.40857

Subtotal By-Products $0 -$22,182,265 -$0.40857

TOTAL VARIABLE OPERATING COSTS $16,327,392 $34,382,582 $0.63328

Fuel (ton) 0 11,577 38.18 $0 $145,217,654 $2.67471
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

129

4.2 SYNTHETIC NATURAL GAS AND AMMONIA CO-PRODUCTION USING 

ILLINOIS NO. 6 COAL

4.2.1

In this section the overall Siemens gasification process for producing SNG and ammonia 

production is described. All major process systems for coal handling and drying, gasifier, raw 

gas cooling/particulate removal, syngas scrubbing, and SNG production are the same as 

previously described for Cases 1 and 2. Only the major process areas for ammonia production 

and their subsequent integration with the SNG portion of the plant are described in this section. 

The process BFDs for the Illinois No. 6 coal non-sequestration and sequestration co-production 

cases are shown in 

Process Description

Exhibit 4-23 and Exhibit 4-25. The associated stream tables are shown in 

Exhibit 4-24 for the non-sequestration case and Exhibit 4-26 for the carbon sequestration case. 

Sour Gas Shift for Ammonia Production

Two SGS units are employed to maximize the hydrogen production necessary for ammonia 

synthesis and to reduce the amount of COS entering the AGR system. A H2O to CO ratio of 3.0

is maintained to drive the shift reaction to an approximate fractional conversion of 99 percent for 

CO. 

Following the water scrubber, approximately 24 percent of the total raw gas stream is utilized for 

ammonia production. This raw gas stream (stream 30) is combined with shift steam (stream 31) 

in the first reactor. The stream exiting the first reactor is cooled to 232°C (450°F) to help further 

drive the shift reaction in the second reactor. The shifted syngas exits the second reactor with 

nearly all the available carbon monoxide shifted to hydrogen.

Mercury Removal and Acid Gas Removal

Before the raw gas can be treated in the AGR process, it must be cooled to about 35°C (95°F). 

During this cooling sequence through a series of heat exchangers, most of the water vapor 

condenses. This water, which contains some NH3, is sent to the sour water stripper. The cooled 

syngas (stream 32) then passes through a carbon bed to remove 95 percent of the Hg (Section 

3.1.6).

The AGR process is a two stage Selexol process where H2S is removed in the first stage and CO2

is removed in the second stage of absorption. The process results in three product streams. A 

high hydrogen syngas (stream 34) is combined with the purge gas from the ammonia synthesis 

loop (stream 40) and sent to the PSA process. A CO2-rich stream is combined with the CO2-rich 

stream from the SNG production trains and either vented to the atmosphere in the nonsequestration case or compressed for sequestration in the carbon sequestration case. A portion of 

the CO2 product stream is withdrawn and further compressed to 5.62 MPa (815 psia) to provide 

the fluid for coal transport (stream 12). The acid gas stream (stream 43) is combined with its 

counterpart in the SNG production train (stream 42) and fed to the Claus plant (stream 44). In 

both cases, the acid gas contains nearly 40 percent H2S and nearly 50 percent CO2, with the 

balance primarily H2 and CO.

Pressure Swing Absorption

The PSA unit is used to purify the syngas stream entering the ammonia synthesis loop to 

acceptable levels of contaminants for the ammonia catalyst as described in Section 3.1.10.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

130

The high hydrogen syngas from the Selexol unit (stream 34) is combined with the ammonia 

purge gas (stream 40) and feed to the PSA unit at 3.24 MPa (470 psia) and 21°C (69°F). The 

PSA unit produces a 99 vol% H2 stream for ammonia synthesis (stream 37). Purge nitrogen 

(stream 35) enters the PSA beds from the ASU to increase the hydrogen recovery to 94 vol%. 

The tail gas from the PSA unit (stream 36) is sent to a waste heat recovery boiler.

Ammonia Synthesis Loop

The purified H2 stream from the PSA unit is combined with additional nitrogen from the ASU 

(stream 4) to maintain a 3:1 molar ratio of H2 to N2 entering the ammonia reactor. The combined 

stream is compressed to 13.62 MPa (1,975 psia) before being fed into the synthesis loop (stream 

38). The ammonia reactor converts H2 and N2 into NH3 at a pressure of 14.0 MPa (2,030 psia) 

due to further compression within the synthesis loop. The ammonia product is refrigerated to

−25°C (−13°F) and sent to storage vessels (stream 39). Approximately five percent of the 

maximum flow in the ammonia synthesis loop is treated in the PSA unit (stream 40) to keep 

concentrations of inerts such as CH4, Ar, and O2 from building up in the synthesis loop. The 

ammonia synthesis loop produces anhydrous ammonia with a purity of 99.5 wt%.

CO2 Compression, Claus Unit, Power Block

The process parameters are the same as previously discussed in Section 4.1.1. 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

131

Exhibit 4-23 Case 3 Block Flow Diagram, Bituminous Coal to SNG and Ammonia without Carbon Sequestration

PARTIAL RAW

GAS QUENCH

AND COOLING

WATER-GAS

SHIFT

REACTORS & 

GAS COOLING

WATER

SCRUBBER

ELEVATED

PRESSURE

ASU

SIEMENS

GASIFIER

MERCURY

REMOVAL

DUALSTAGE

SELEXOL

UNIT

CLAUS PLANT

COAL

DRYER

METHANATION

REACTORS

26

SNG 

PURIFICATION

28

SNG FOR

EXPORT

27 PURIFICATION

OFF-GAS

STEAM

TURBINE

49 50

PROCESS

STEAM

CONDENSATE

DRY GAS

PREP

SNG 

COMPRESSION

29

COS 

HYDROLYSIS

MERCURY

REMOVAL

DUALSTAGE

SELEXOL

UNIT

PSA

7 11

9

8

16

30

WATER-GAS

SHIFT

REACTORS & 

GAS COOLING

17

TAIL GAS

HYDROLYSIS AND

TREATMENT UNIT

AMMONIA

PRODUCTION

18

20

21

19

32 33 34 37 38

43

42

46 44

23

40

35

36 39

12

1

2 3

5

6

14

10

15

47

22

48

24

DRIED W COAL ET

COAL

TRANSPORT

CO2

COAL

DRYER

STACK

GAS

AIR TO ASU

VENT

GAS

SULFUR

PLANT

OXIDANT

GASIFIER

OXIDANT

SLAG

STEAM

QUENCH

WATER

AIR

TO SOUR WATER

STRIPPER

SHIFT

STEAM

WGS 

BYPASS

TO SOUR WATER

STRIPPER

31

SHIFT

STEAM

SULFUR

PRODUCT

CO2

VENT

45

PURGE GAS TO

WASTE HEAT

BOILER

AMMONIA

PRODUCT

AMMONIA

PURGE

RECYCLE

25

TO COAL

DRYING

25

4

NITROGEN

41

4 NITROGEN

TO AMMONIA PLANT

TRANSPORT

CO2

PURGE

NITROGEN

CLEAN

SYNGAS

12

LOCKHOPPER

VENT

13

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown. See H&MB diagram for more detail.

35 NITROGEN

TO PSA
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

132

Exhibit 4-24 Case 3 Stream Table, Bituminous Coal to SNG and Ammonia without Carbon Sequestration

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18

V-L Mole Fraction

Ar 0.0092 0.0101 0.0101 0.0000 0.0101 0.0000 0.0000 0.0092 0.0084 0.0064 0.0000 0.0001 0.0000 0.0000 0.0000 0.0020 0.0020 0.0020

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0081 0.0010 0.0000 0.0000 0.4205 0.4364 0.4364

CO2 0.0003 0.0005 0.0000 0.0000 0.0000 0.0000 0.0000 0.0003 0.1192 0.0916 0.0000 0.9781 0.1235 0.0000 0.0000 0.0399 0.0415 0.0415

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0005 0.0006 0.0006

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0121 0.6937 0.0000 0.0000 0.1971 0.2046 0.2046

H2O 0.0099 0.0044 0.0000 0.0000 0.0000 1.0000 0.0000 0.0099 0.1710 0.3627 0.0000 0.0014 0.0979 0.0000 1.0000 0.3295 0.3042 0.3042

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0058 0.0060 0.0060

N2 0.7732 0.9765 0.0004 1.0000 0.0004 0.0000 0.0000 0.7732 0.6234 0.4793 0.0000 0.0001 0.0171 0.0000 0.0000 0.0046 0.0047 0.0047

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.2074 0.0085 0.9895 0.0000 0.9895 0.0000 0.0000 0.2074 0.0780 0.0600 0.0000 0.0000 0.0668 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 51,682 36,441 151 3,127 10,369 3,442 0 3,538 4,396 5,718 0 3,559 14,094 0 14,055 53,960 39,309 5,856

V-L Flowrate (kg/hr) 1,491,391 1,025,161 4,845 87,594 332,612 62,017 0 102,084 125,819 149,636 0 154,233 158,471 0 253,210 1,095,758 801,642 119,422

Solids Flowrate (kg/hr) 0 0 0 0 0 0 437,263 0 0 0 413,446 0 332,092 43,794 0 0 0 0

Temperature (°C) 15 25 32 72 32 343 15 15 1,260 143 71 83 18 1,500 216 260 214 214

Pressure (MPa, abs) 0.10 0.11 0.86 3.24 0.86 5.10 0.10 0.10 0.10 0.10 0.10 5.62 5.62 4.24 8.274 3.89 3.76 3.76

Enthalpy (kJ/kg) 30.93 32.59 26.94 69.15 26.94 3,177.81 --- 30.93 1,853.88 826.48 --- 31.02 4,689.64 --- 1,017.873 1,152.07 1,014.68 1,014.68

Density (kg/m3) 1.2 1.3 11.0 31.6 11.0 20.1 --- 1.2 0.2 0.8 --- 99.3 28.4 --- 782.0 18.0 19.1 19.1

V-L Molecular Weight 28.857 28.132 32.078 28.013 32.078 18.015 --- 28.857 28.621 26.169 --- 43.334 11.244 --- 18.015 20.307 20.393 20.393

V-L Flowrate (lbmol/hr) 113,940 80,339 333 6,894 22,859 7,589 0 7,799 9,692 12,606 0 7,847 31,073 0 30,987 118,962 86,662 12,910

V-L Flowrate (lb/hr) 3,287,954 2,260,094 10,681 193,111 733,283 136,724 0 225,056 277,383 329,890 0 340,027 349,368 0 558,232 2,415,734 1,767,318 263,281

Solids Flowrate (lb/hr) 0 0 0 0 0 0 964,000 0 0 0 911,493 0 732,139 96,550 0 0 0 0

Temperature (°F) 59 76 90 162 90 650 59 59 2,300 290 160 181 65 2,732 420 500 418 418

Pressure (psia) 14.7 16.4 125.0 470.0 125.0 740.0 14.7 14.7 14.7 14.7 14.4 815.0 815.0 614.7 1,200.0 564.7 544.7 544.7

Enthalpy (Btu/lb) 13.3 14.0 11.6 29.7 11.6 1,366.2 --- 13.3 797.0 355.3 --- 13.3 2,016.2 --- 437.6 495.3 436.2 436.2

Density (lb/ft3) 0.076 0.080 0.685 1.973 0.685 1.257 --- 0.076 0.014 0.048 --- 6.197 1.775 --- 48.817 1.125 1.195 1.195

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

133

Exhibit 4-24 Case 3 Stream Table, Bituminous Coal to SNG and Ammonia without Carbon Sequestration (continued)

19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36

V-L Mole Fraction

Ar 0.0020 0.0000 0.0021 0.0021 0.0030 0.0030 0.0030 0.0105 0.0000 0.0120 0.0120 0.0020 0.0000 0.0018 0.0018 0.0029 0.0000 0.0072

CH4 0.0000 0.0000 0.0000 0.0000 0.0001 0.0001 0.0001 0.8302 0.0000 0.9496 0.9496 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0002

CO 0.4364 0.0000 0.1647 0.1642 0.2372 0.2372 0.2372 0.0000 0.0000 0.0000 0.0000 0.4364 0.0000 0.0037 0.0037 0.0061 0.0000 0.0166

CO2 0.0420 0.0000 0.3264 0.3284 0.0366 0.0366 0.0366 0.1253 0.9816 0.0021 0.0021 0.0415 0.0000 0.4192 0.4192 0.0530 0.0000 0.1443

COS 0.0000 0.0000 0.0001 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.2046 0.0000 0.4935 0.4919 0.7160 0.7160 0.7160 0.0070 0.0000 0.0080 0.0080 0.2046 0.0000 0.5636 0.5636 0.9309 0.0000 0.1939

H2O 0.3036 1.0000 0.0018 0.0018 0.0001 0.0001 0.0001 0.0023 0.0184 0.0000 0.0000 0.3042 1.0000 0.0017 0.0017 0.0001 0.0000 0.0004

H2S 0.0066 0.0000 0.0066 0.0067 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0060 0.0000 0.0057 0.0057 0.0000 0.0000 0.0000

N2 0.0047 0.0000 0.0049 0.0048 0.0071 0.0071 0.0071 0.0247 0.0000 0.0282 0.0282 0.0047 0.0000 0.0042 0.0042 0.0069 1.0000 0.6195

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0180

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 5,856 10,935 38,282 38,406 26,217 115 645 7,292 917 6,375 6,375 12,685 12,748 14,332 14,332 8,622 1,245 3,164

V-L Flowrate (kg/hr) 119,422 196,998 783,015 788,417 262,604 1,151 6,461 145,836 39,914 105,923 105,923 258,689 229,661 288,176 288,176 40,467 34,881 79,621

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 215 288 35 35 31 80 31 35 35 35 35 214 288 35 35 31 72 21

Pressure (MPa, abs) 3.69 4.14 3.31 3.24 3.24 5.10 3.24 2.73 0.14 2.627 6.202 3.756 4.137 3.37 3.3 3.238 3.241 0.138

Enthalpy (kJ/kg) 1,014.21 3,070.04 44.97 44.66 86.06 234.17 86.06 41.84 48.20 47.750 13.125 1,014.683 3,070.036 44.67 44.2 190.221 69.152 24.935

Density (kg/m3

) 18.8 18.2 26.8 26.4 12.7 17.0 12.7 22.6 2.4 17.9 44.7 19.1 18.2 27.1 26.5 5.9 31.6 1.4

V-L Molecular Weight 20.393 18.015 20.454 20.529 10.017 10.017 10.017 20.000 43.532 16.615 16.615 20.393 18.015 20.107 20.107 4.693 28.013 25.164

V-L Flowrate (lbmol/hr) 12,910 24,108 84,396 84,670 57,797 253 1,422 16,076 2,021 14,055 14,055 27,966 28,105 31,597 31,597 19,009 2,745 6,976

V-L Flowrate (lb/hr) 263,281 434,306 1,726,252 1,738,163 578,942 2,538 14,243 321,514 87,994 233,520 233,520 570,311 506,315 635,320 635,320 89,214 76,900 175,534

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 418 550 95 95 87 177 87 95 95 95 95 418 550 95 94 87 162 69

Pressure (psia) 534.7 600.0 479.7 469.7 469.6 740.0 469.6 396.1 20.1 381.0 899.5 544.7 600.0 489.2 479.2 469.6 470.0 20.0

Enthalpy (Btu/lb) 436.0 1,319.9 19.3 19.2 37.0 100.7 37.0 18.0 20.7 20.5 5.6 436.2 1,319.9 19.2 19.0 81.8 29.7 10.7

Density (lb/ft3) 1.172 1.135 1.675 1.647 0.792 1.063 0.792 1.409 0.148 1.116 2.789 1.195 1.135 1.690 1.657 0.371 1.973 0.089
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

134

Exhibit 4-24 Case 3 Stream Table, Bituminous Coal to SNG and Ammonia without Carbon Sequestration (continued)

37 38 39 40 41 42 43 44 45 46 47 48 49 50

V-L Mole Fraction

Ar 0.0013 0.0010 0.0005 0.0035 0.0000 0.0005 0.0005 0.0005 0.0000 0.0019 0.0000 0.0034 0.0000 0.0000

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0021 0.0480 0.0011 0.0350 0.0000 0.1014 0.0000 0.0060 0.0000 0.0000

CO2 0.0000 0.0000 0.0000 0.0000 0.9906 0.4323 0.5377 0.4614 0.0000 0.3385 0.9629 0.5672 0.0000 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0001 0.0017 0.0001 0.0012 0.0000 0.0005 0.0000 0.0000 0.0000 0.0000

H2 0.9905 0.7491 0.0030 0.7328 0.0030 0.0917 0.1024 0.0946 0.0000 0.0589 0.0005 0.2694 0.0000 0.0000

H2O 0.0000 0.0000 0.0000 0.0000 0.0041 0.0329 0.0314 0.0325 0.0000 0.4950 0.0059 0.1525 1.0000 1.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.3923 0.3264 0.3741 0.0000 0.0021 0.0306 0.0000 0.0000 0.0000

N2 0.0082 0.2499 0.0011 0.2448 0.0000 0.0006 0.0005 0.0006 0.0000 0.0008 0.0000 0.0014 0.0000 0.0000

NH3 0.0000 0.0000 0.9954 0.0190 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0009 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 9,704 12,831 4,898 3,001 13,431 657 252 909 0 1,058 124 604 40,998 76,214

V-L Flowrate (kg/hr) 22,125 109,719 83,324 26,398 587,552 22,772 8,966 31,738 0 28,599 5,403 17,274 738,585 1,373,008

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 10,893 0 0 0 0 0

Temperature (°C) 21 21 -25 -28 5 48 48 48 177 232 35 51 566 39

Pressure (MPa, abs) 3.238 13.614 13.048 3.238 0.115 0.163 0.163 0.163 0.119 0.085 3.272 0.103 12.512 0.827

Enthalpy (kJ/kg) 267.348 68.637 -1,408.059 -99.171 7.544 91.640 87.876 90.577 --- 1,168.962 -1.583 232.751 3,513.235 164.154

Density (kg/m3) 3.0 44.6 668.8 13.9 2.2 2.1 2.2 2.1 5,281.2 0.5 67.9 1.2 34.9 993.0

V-L Molecular Weight 2.280 8.551 17.010 8.796 43.745 34.656 35.628 34.925 --- 27.035 43.530 28.598 18.015 18.015

V-L Flowrate (lbmol/hr) 21,394 28,288 10,799 6,616 29,611 1,449 555 2,003 0 2,332 274 1,332 90,384 168,022

V-L Flowrate (lb/hr) 48,777 241,888 183,698 58,197 1,295,330 50,203 19,766 69,969 0 63,051 11,911 38,083 1,628,301 3,026,965

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 24,016 0 0 0 0 0

Temperature (°F) 69 70 -13 -19 42 119 119 119 351 450 95 123 1,050 102

Pressure (psia) 469.6 1,974.5 1,892.5 469.6 16.7 23.7 23.7 23.7 17.3 12.3 474.5 14.9 1,814.7 120.0

Enthalpy (Btu/lb) 114.9 29.5 -605.4 -42.6 3.2 39.4 37.8 38.9 --- 502.6 -0.7 100.1 1,510.4 70.6

Density (lb/ft3) 0.186 2.787 41.749 0.865 0.137 0.133 0.137 0.134 329.697 0.034 4.237 0.072 2.177 61.989
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

135

Exhibit 4-25 Case 4 Block Flow Diagram, Bituminous Coal to SNG and Ammonia with Carbon Sequestration

PARTIAL RAW

GAS QUENCH

AND COOLING

WATER-GAS

SHIFT

REACTORS & 

GAS COOLING

WATER

SCRUBBER

ELEVATED

PRESSURE

ASU

SIEMENS

GASIFIER

MERCURY

REMOVAL

DUALSTAGE

SELEXOL

UNIT

CLAUS PLANT

COAL

DRYER

METHANATION

REACTORS

26

SNG 

PURIFICATION

28

SNG FOR

EXPORT

27

PURIFICATION

OFF-GAS

TO CO2

COMPRESSION

STEAM

TURBINE

49 50

PROCESS

STEAM

CONDENSATE

DRY GAS

PREP

SNG 

COMPRESSION

29

COS 

HYDROLYSIS

MERCURY

REMOVAL

DUALSTAGE

SELEXOL

UNIT

PSA

7 11

9

8

16

30

WATER-GAS

SHIFT

REACTORS & 

GAS COOLING

17

TAIL GAS

HYDROLYSIS AND

TREATMENT UNIT

AMMONIA

PRODUCTION

18

20

21

19

32 33 34 37 38

43

42

46 44

23

CO2 COMPRESSION

40

35

36 39

12

28

41

1

2 3

5

6

14

10

15

47

22

48

24

DRIED

WET COAL

COAL

COAL

DRYER

STACK

GAS

AIR TO ASU

VENT

GAS

SULFUR

PLANT

OXIDANT

GASIFIER

OXIDANT

SLAG

STEAM

QUENCH

WATER

AIR

TO SOUR WATER

STRIPPER

SHIFT

STEAM

WGS 

BYPASS

TO SOUR WATER

STRIPPER

31

SHIFT

STEAM

SULFUR

PRODUCT

CO2

PRODUCT

45

PURGE GAS TO

WASTE HEAT

BOILER

AMMONIA

PRODUCT

AMMONIA

PURGE

RECYCLE

25

TO COAL

DRYING

25

4

NITROGEN

NITROGEN

REACTANT TO

AMMONIA PLANT

TRANSPORT

CO2

PURGE

NITROGEN

CLEAN

SYNGAS

TRANSPORT

CO2

12

LOCKHOPPER

VENT

13

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown. See H&MB diagram for more detail.

PURIFICATION

OFF-GAS

35

4

NITROGEN

TO PSA
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

136

Exhibit 4-26 Case 4 Stream Table, Bituminous Coal to SNG and Ammonia with Carbon Sequestration

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

V-L Mole Fraction

Ar 0.0092 0.0101 0.0101 0.0000 0.0101 0.0000 0.0000 0.0092 0.0084 0.0064 0.0000 0.0000 0.0000 0.0000 0.0000 0.0020 0.0020

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0032 0.0004 0.0000 0.0000 0.4206 0.4365

CO2 0.0003 0.0005 0.0000 0.0000 0.0000 0.0000 0.0000 0.0003 0.1204 0.0924 0.0000 0.9918 0.1242 0.0000 0.0000 0.0400 0.0415

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0005 0.0006

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0047 0.6936 0.0000 0.0000 0.1970 0.2044

H2O 0.0099 0.0044 0.0000 0.0000 0.0000 1.0000 0.0000 0.0099 0.1711 0.3635 0.0000 0.0001 0.0978 0.0000 1.0000 0.3295 0.3042

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0058 0.0060

N2 0.7732 0.9765 0.0004 1.0000 0.0004 0.0000 0.0000 0.7732 0.6227 0.4782 0.0000 0.0000 0.0172 0.0000 0.0000 0.0046 0.0047

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.2074 0.0085 0.9895 0.0000 0.9895 0.0000 0.0000 0.2074 0.0774 0.0595 0.0000 0.0000 0.0669 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 51,694 36,451 156 3,127 10,366 3,442 0 3,516 4,374 5,696 0 3,525 14,077 0 14,050 53,938 39,291

V-L Flowrate (kg/hr) 1,491,725 1,025,437 4,997 87,591 332,535 62,017 0 101,453 125,255 149,072 0 154,233 158,471 0 253,117 1,095,588 801,497

Solids Flowrate (kg/hr) 0 0 0 0 0 0 437,263 0 0 0 413,446 0 332,092 43,794 0 0 0

Temperature (°C) 15 25 32 117 32 343 15 15 1,265 143 71 82 18 1,500 216 260 214

Pressure (MPa, abs) 0.10 0.11 0.86 3.24 0.86 5.10 0.10 0.10 0.10 0.10 0.10 5.62 5.62 4.24 8.274 3.89 3.76

Enthalpy (kJ/kg) 30.93 32.59 26.94 117.12 26.94 3,177.81 --- 30.93 1,860.19 827.90 --- 27.40 4,694.27 --- 1,017.873 1,151.80 1,014.38

Density (kg/m3

) 1.2 1.3 11.0 27.9 11.0 20.1 --- 1.2 0.2 0.8 --- 101.4 28.5 --- 782.0 18.0 19.2

V-L Molecular Weight 28.857 28.132 32.078 28.013 32.078 18.015 --- 28.857 28.637 26.172 --- 43.759 11.257 --- 18.015 20.312 20.399

V-L Flowrate (lbmol/hr) 113,965 80,361 343 6,893 22,854 7,589 0 7,751 9,643 12,557 0 7,770 31,035 0 30,975 118,912 86,623

V-L Flowrate (lb/hr) 3,288,691 2,260,701 11,017 193,105 733,114 136,724 0 223,666 276,140 328,647 0 340,026 349,368 0 558,027 2,415,359 1,766,999

Solids Flowrate (lb/hr) 0 0 0 0 0 0 964,000 0 0 0 911,493 0 732,138 96,550 0 0 0

Temperature (°F) 59 76 90 242 90 650 59 59 2,308 290 160 179 65 2,732 420 500 418

Pressure (psia) 14.7 16.4 125.0 470.0 125.0 740.0 14.7 14.7 14.7 14.7 14.4 815.0 815.0 614.7 1,200.0 564.7 544.7

Enthalpy (Btu/lb) 13.3 14.0 11.6 50.4 11.6 1,366.2 --- 13.3 799.7 355.9 --- 11.8 2,018.2 --- 437.6 495.2 436.1

Density (lb/ft3) 0.076 0.080 0.685 1.739 0.685 1.257 --- 0.076 0.014 0.048 --- 6.328 1.779 --- 48.817 1.125 1.196

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

137

Exhibit 4-26 Case 4 Stream Table, Bituminous Coal to SNG and Ammonia with Carbon Sequestration (continued)

18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34

V-L Mole Fraction

Ar 0.0020 0.0020 0.0000 0.0021 0.0021 0.0030 0.0030 0.0030 0.0105 0.0000 0.0120 0.0120 0.0020 0.0000 0.0018 0.0018 0.0029

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0001 0.0001 0.8300 0.0000 0.9496 0.9496 0.0000 0.0000 0.0000 0.0000 0.0001

CO 0.4365 0.4365 0.0000 0.1647 0.1642 0.2372 0.2372 0.2372 0.0000 0.0000 0.0000 0.0000 0.4365 0.0000 0.0037 0.0037 0.0061

CO2 0.0415 0.0421 0.0000 0.3265 0.3285 0.0366 0.0366 0.0366 0.1255 0.9817 0.0022 0.0022 0.0415 0.0000 0.4193 0.4193 0.0530

COS 0.0006 0.0000 0.0000 0.0001 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0000

H2 0.2044 0.2044 0.0000 0.4933 0.4917 0.7160 0.7160 0.7160 0.0070 0.0000 0.0080 0.0080 0.2044 0.0000 0.5634 0.5634 0.9309

H2O 0.3042 0.3036 1.0000 0.0018 0.0018 0.0001 0.0001 0.0001 0.0023 0.0183 0.0000 0.0000 0.3042 1.0000 0.0017 0.0017 0.0001

H2S 0.0060 0.0066 0.0000 0.0066 0.0068 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0060 0.0000 0.0057 0.0057 0.0000

N2 0.0047 0.0047 0.0000 0.0049 0.0048 0.0071 0.0071 0.0071 0.0247 0.0000 0.0282 0.0282 0.0047 0.0000 0.0042 0.0042 0.0069

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 5,852 5,852 10,939 38,269 38,397 26,203 115 654 7,287 918 6,369 6,369 12,679 12,748 14,327 14,327 8,618

V-L Flowrate (kg/hr) 119,381 119,381 197,069 782,967 788,515 262,524 1,151 6,555 145,785 39,955 105,827 105,827 258,642 229,652 288,150 288,150 40,455

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 214 215 288 35 35 31 80 31 35 35 35 35 214 288 35 35 31

Pressure (MPa, abs) 3.76 3.69 4.14 3.31 3.24 3.24 5.10 3.24 2.73 0.14 2.627 6.202 3.756 4.137 3.37 3.3 3.238

Enthalpy (kJ/kg) 1,014.38 1,013.91 2,955.16 44.96 44.63 86.04 234.12 86.04 41.82 48.17 47.750 13.124 1,014.380 2,955.157 44.65 44.2 190.183

Density (kg/m3

) 19.2 18.8 18.2 26.8 26.4 12.7 17.0 12.7 22.6 2.4 17.9 44.7 19.2 18.2 27.1 26.6 5.9

V-L Molecular Weight 20.399 20.399 18.015 20.460 20.536 10.019 10.019 10.019 20.006 43.533 16.615 16.615 20.399 18.015 20.112 20 4.694

V-L Flowrate (lbmol/hr) 12,902 12,902 24,116 84,369 84,652 57,768 253 1,442 16,065 2,023 14,042 14,042 27,953 28,104 31,587 31,587 18,999

V-L Flowrate (lb/hr) 263,189 263,189 434,462 1,726,146 1,738,377 578,766 2,538 14,451 321,400 88,085 233,309 233,309 570,209 506,295 635,261 635,261 89,187

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 418 418 550 95 95 87 177 87 95 95 95 95 418 550 95 94 87

Pressure (psia) 544.7 534.7 600.0 479.7 469.7 469.6 740.0 469.6 396.1 20.1 381.0 899.5 544.7 600.0 489.2 479.2 469.6

Enthalpy (Btu/lb) 436.1 435.9 1,270.5 19.3 19.2 37.0 100.7 37.0 18.0 20.7 20.5 5.6 436.1 1,270.5 19.2 19.0 81.8

Density (lb/ft3

) 1.196 1.173 1.135 1.675 1.648 0.792 1.063 0.792 1.410 0.148 1.116 2.789 1.196 1.135 1.690 1.658 0.371
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

138

Exhibit 4-26 Case 4 Stream Table, Bituminous Coal to SNG and Ammonia with Carbon Sequestration (continued)

35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50

V-L Mole Fraction

Ar 0.0000 0.0072 0.0013 0.0010 0.0005 0.0035 0.0000 0.0005 0.0005 0.0005 0.0000 0.0020 0.0000 0.0035 0.0000 0.0000

CH4 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0166 0.0000 0.0000 0.0000 0.0000 0.0032 0.0477 0.0011 0.0349 0.0000 0.1032 0.0000 0.0057 0.0000 0.0000

CO2 0.0000 0.1443 0.0000 0.0000 0.0000 0.0000 0.9918 0.4296 0.5376 0.4594 0.0000 0.3331 0.9316 0.5770 0.0000 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0017 0.0001 0.0012 0.0000 0.0004 0.0001 0.0000 0.0000 0.0000

H2 0.0000 0.1938 0.9905 0.7490 0.0030 0.7324 0.0047 0.0910 0.1023 0.0941 0.0000 0.0588 0.0005 0.2585 0.0000 0.0000

H2O 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0001 0.0327 0.0314 0.0323 0.0000 0.4947 0.0059 0.1538 1.0000 1.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3962 0.3265 0.3770 0.0000 0.0020 0.0619 0.0001 0.0000 0.0000

N2 1.0000 0.6196 0.0082 0.2500 0.0011 0.2451 0.0000 0.0006 0.0005 0.0006 0.0000 0.0008 0.0000 0.0014 0.0000 0.0000

NH3 0.0000 0.0180 0.0000 0.0000 0.9954 0.0190 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0049 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 1,245 3,164 9,699 12,825 4,897 3,000 16,002 661 252 913 0 1,066 128 594 40,943 76,182

V-L Flowrate (kg/hr) 34,865 79,621 22,112 109,703 83,295 26,414 700,235 22,915 8,966 31,881 0 28,895 5,548 17,247 737,593 1,372,447

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0 10,895 0 0 0 0 0

Temperature (°C) 117 25 25 21 -25 -28 35 48 48 48 177 232 35 51 566 39

Pressure (MPa, abs) 3.241 0.138 3.238 13.614 13.048 3.238 15.272 0.163 0.163 0.163 0.119 0.085 3.272 0.103 12.512 0.827

Enthalpy (kJ/kg) 117.116 30.226 323.138 68.608 -1,408.062 -99.105 -209.042 91.358 87.862 90.375 --- 1,165.597 -1.733 229.322 3,513.235 164.155

Density (kg/m3) 27.9 1.4 2.9 44.7 668.7 13.9 779.4 2.1 2.2 2.1 5,281.0 0.5 67.5 1.2 34.9 993.0

V-L Molecular Weight 28.013 25.166 2.280 8.554 17.010 8.805 43.759 34.655 35.629 34.923 --- 27.098 43.222 29.027 18.015 18.015

V-L Flowrate (lbmol/hr) 2,744 6,975 21,382 28,275 10,795 6,614 35,278 1,458 555 2,013 0 2,351 283 1,310 90,263 167,953

V-L Flowrate (lb/hr) 76,865 175,535 48,749 241,854 183,634 58,232 1,543,753 50,520 19,766 70,286 0 63,702 12,231 38,023 1,626,113 3,025,728

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0 24,019 0 0 0 0 0

Temperature (°F) 242 77 77 70 -13 -19 95 119 119 119 351 450 95 123 1,050 102

Pressure (psia) 470.0 20.0 469.6 1,974.5 1,892.5 469.6 2,215.0 23.7 23.7 23.7 17.3 12.3 474.5 14.9 1,814.7 120.0

Enthalpy (Btu/lb) 50.4 13.0 138.9 29.5 -605.4 -42.6 -89.9 39.3 37.8 38.9 --- 501.1 -0.7 98.6 1,510.4 70.6

Density (lb/ft3) 1.739 0.087 0.183 2.788 41.749 0.866 48.656 0.133 0.137 0.134 329.679 0.034 4.214 0.073 2.177 61.989
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

139

4.2.2

System assumptions for Cases 3 and 4, Siemens gasifier using Illinois No. 6 coal with and 

without carbon sequestration, are compiled in 

Key System Assumptions

Exhibit 4-27.

Exhibit 4-27 Cases 3 and 4 Plant Study Configuration Matrix

Case Case 3 Case 4

Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O2:Coal Ratio, kg O2/kg dried coal 0.794 0.794

Carbon Conversion, % 99.5 99.5

Syngas HHV at Gasifier Outlet, 

kJ/Nm3 (Btu/scf) 10,237 (275) 10,237 (275)

Steam Cycle, MPa/°C (psig/°F) 12.4/566/536

(1800/1050/996)

12.4/566/537

(1800/1050/999)

Condenser Pressure, mm Hg

(in Hg) 51 (2.0) 51 (2.0)

Combustion Turbine N/A N/A

Gasifier Technology Siemens Siemens

Oxidant 99 vol% Oxygen 99 vol% Oxygen

Coal Illinois No. 6 Illinois No. 6

Coal Feed Moisture Content, % 11.12 11.12

COS Hydrolysis Reactor Yes Yes

Water Gas Shift Yes Yes

H2S Separation Selexol (1st Stage) Selexol (1st Stage)

Sulfur Removal, % 99.4 99.9

CO2 Separation Selexol (2nd Stage) Selexol (2nd Stage)

CO2 Sequestered, % N/A 69.0

Sulfur Recovery

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Methanation System Based on Haldor Topsoe 

TREMPTM Process

Based on Haldor Topsoe 

TREMPTM Process

Ammonia Synthesis Loop

Based on Haldor Topsoe 

S-300 reactor with KM1R 

catalyst

Based on Haldor Topsoe S300 reactor with KM1R 

catalyst

Particulate Control Scrubber and AGR 

Absorber

Scrubber and AGR 

Absorber

Mercury Control Carbon Bed Carbon Bed

NOx Control N/A N/A

Balance of Plant and Sparing Philosophy

The ammonia system feed and recycle compressors have 100 percent spares and the refrigeration 

unit is 2 x 50 percent. Consistent with other sections of the plant, non-rotating equipment is not 

spared in the ammonia plant.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

140

The remaining balance of plant assumptions and sparing philosophy are common to all cases and 

are presented in Section 4.1.

4.2.3

The Siemens SNG and ammonia co-production plant without and with carbon sequestration and 

using Illinois No. 6 coal produces a net SNG output of 42 Bscf/year (90 percent CF) and 2,204

TPD of ammonia. 

Cases 3 and 4 Performance Results

Overall performance for the two plants is summarized in Exhibit 4-28, which includes auxiliary 

power requirements and production values. The ASU accounts for approximately 55 percent of 

the total auxiliary load in the non-sequestration case and 44 percent in the sequestration case, 

distributed between the main air compressor, the oxygen compressor, and ASU auxiliaries. CO2

compression accounts for about 18 percent of the total auxiliary load for the sequestration case. 

The AGR process accounts for about 11 percent and 9 percent of the auxiliary load for the nonsequestration and sequestration cases, respectively. The ammonia production process accounts 

for about 16 percent and 13 percent of the auxiliary load for the non-sequestration and 

sequestration cases, respectively. All other individual auxiliary loads are less than 3 percent of 

the total.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

141

Exhibit 4-28 Cases 3 and 4 Plant Performance Summary

POWER SUMMARY 

(Gross Power at Generator Terminals, kWe) Case 3 Case 4

Steam Turbine Power 292,300 292,300

TOTAL POWER, kWe 292,300 292,300

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 700 700

Coal Milling 4,500 4,500

Slag Handling 1,140 1,140

Air Separation Unit Auxiliaries 1,000 1,000

Air Separation Unit Main Air Compressor 121,610 121,640

Oxygen Compressor 16,750 16,740

Nitrogen Compressor 9,570 9,570

CO2 Solid Feed System Compressors 4,980 240

SNG Compressors 4,680 4,680

Methanation Plant Recycle Compressor 4,390 4,390

Ammonia Plant Compressors 26,290 26,610

Ammonia Plant Refrigeration System 15,590 15,580

Gasifier Pilot Fuel Compressor and Incinerator Air Blower 300 300

CO2 Compressor N/A 56,650

Boiler Feedwater Pumps 5,170 5,170

Condensate Pump 500 500

Quench Water Pump 640 640

Circulating Water Pump 6,200 6,220

Ground Water Pumps 670 680

Cooling Tower Fans 3,610 3,620

Scrubber Pumps 1,000 1,000

Acid Gas Removal 29,050 29,050

Steam Turbine Auxiliaries 100 100

Claus Plant/TGTU Auxiliaries 250 250

Claus Plant TG Recycle Compressor 310 320

Miscellaneous Balance of Plant2 3,000 3,000

Transformer Losses 1,600 1,740

TOTAL AUXILIARIES, kWe 263,600 316,030

NET POWER, kWe 28,700 -23,730

SNG Production Rate, MNm3/hr (Mscf/hr) 150.9 (5,333) 150.8 (5,328)

Ammonia Production Rate, kg/hr (lb/hr) 83,324 (183,698) 83,295 (183,634)

Conversion Efficiency (HHVproduct/HHVcoal), % 61.5% 61.4%

Coal Feed Flow Rate, kg/hr (lb/hr) 437,263 (964,000) 437,263 (964,000)

Thermal Input1, kWth 3,295,885 3,295,885

Condenser Cooling Duty, GJ/hr (MMBtu/hr) 1,772 (1,680) 1,772 (1,680)

Raw Water Withdrawal, m3/min (gpm) 28.1 (7,434) 28.2 (7,458)

Raw Water Consumption, m3/min (gpm) 22.6 (5,979) 22.7 (5,997)

1 - HHV of Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)

2 - Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

142

Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 

2.5. A summary of the plant air emissions for Cases 3 and 4 is presented in Exhibit 4-29.

Exhibit 4-29 Cases 3 and 4 Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

90% capacity factor

Case 3 Case 4 Case 3 Case 4

SO2

0.010 

(0.023)

0.0002 

(0.0006) 920 (1,014) 23 (26)

NOX Negligible Negligible Negligible Negligible

Particulates 0.003 

(0.0071)

0.003 

(0.0071) 286 (315) 286 (315)

Hg 2.46E-7 

(5.71E-7)

2.46E-7 

(5.71E-7)

0.023 

(0.025)

0.023 

(0.025)

CO2

63.0 

(146.5) 4.1 (9.5) 5,891,839 (6,494,641)

384,029 

(423,320)

The low level of SO2 emissions in Case 4 is achieved by capture of the sulfur in the gas by the 

two-stage Selexol AGR process and co-sequestration with the CO2 product. The clean syngas 

exiting the AGR process has a sulfur concentration of approximately 5 ppmv in both cases. The 

H2S-rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental 

sulfur. The Claus plant tail gas is treated using an amine based system to capture most of the 

remaining sulfur. The clean syngas from the TGTU is combined with a slipstream of clean 

syngas from the Selexol process, passed through an incinerator, and the hot, inert incinerator 

offgas is used to dry coal prior to being vented to the atmosphere. The higher sulfur emissions in 

Case 3 are due to the sulfur contained in the CO2-rich stream from the Selexol process, which is 

vented rather than sequestered.

NOX emissions are negligible because no CT is used for power generation.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a syngas 

scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent 

filterable particulate only.

Ninety five percent of mercury is captured from the syngas by an activated carbon bed. CO2

emissions represent the uncontrolled (Case 3) and controlled (Case 4) discharge from the 

process.

The carbon balance for the two cases is shown in Exhibit 4-30. The carbon input to the plant 

consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not used in the 

carbon capture equation below, but it is not neglected in the balance since Aspen accounts for air 

components throughout. Carbon leaves the plant as unburned carbon in the slag, 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

143

Exhibit 4-30 Cases 3 and 4 Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Case 3 Case 4 Case 3 Case 4

Coal 278,732 

(614,499)

278,732 

(614,499) Slag 1,394 (3,072) 1,394 (3,072)

Air (CO2) 228 (503) 228 (503)

SNG 

Purification 

Off-Gas

10,810 

(23,832) N/A

ASU Vent 203 (447) 203 (447)

SNG 72,874 

(160,660)

72,809 

(160,517)

CO2 Selexol 

Vent

160,170 

(353,115) N/A

CO2 Lock 

Hopper Vent

21,082 

(46,477) 840 (1,852)

CO2 Product N/A 191,257 

(421,650)

Stack 6,294 

(13,876)

6,324 

(13,942)

PSA Purge 

Gas

6,133 

(13,521)

6,132 

(13,519)

Total 278,961 

(615,003)

278,960 

(615,003) Total 278,961 (615,003)

278,960 

(615,003)

CO2 in the stack gas, waste heat boiler gas, ASU vent gas, SNG product, and the CO2 product 

(either vented or sequestered). The carbon capture efficiency is presented in two distinct ways. 

The first way defines capture as the amount of carbon in the CO2 product for sequestration 

relative to the amount of carbon in the coal less carbon contained in the slag, and is represented 

by the following fraction:

(Carbon in Product for Sequestration)/[(Carbon in the Coal)-(Carbon in Slag)] or

Non sequestration (Case 3)

(421,650)/(614,499-3,072)*100 = 69.0% (Case 4)

The second way does not penalize the production facility for the carbon converted to SNG

product, as the end use of the SNG is unknown. In a carbon constrained scenario, the SNG may 

or may not be used in a scenario where CCS is implemented. For this method, the burden of 

carbon mitigation falls on the end-user. The following fraction represents this scenario: 

[(Carbon in Product for Sequestration) + (Carbon in SNG Product)]/[(Carbon in the Coal)-

(Carbon in Slag)] or

(0 + 160,660)/(614,499 – 3,072)*100 = 26.3% (Case 3)

(421,650 + 160,517)/(614,499-3,072)*100 = 95.2% (Case 4)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

144

Exhibit 4-31 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur in the SNG 

product, sulfur emitted in the stack gas, and sulfur co-sequestered with the CO2 product (Case 4 

only). Sulfur in the slag is considered negligible. The total sulfur capture is represented by the 

following fraction:

(Sulfur byproduct + Sulfur in CO2 product)/Sulfur in the coal or 

(24,016 + 0)/24,162 = 99.4 percent (Case 3)

(24,019 + 128)/24,162 = 99.9 percent (Case 4)

Exhibit 4-31 Cases 3 and 4 Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Case 3 Case 4 Case 3 Case 4

Coal 10,960 

(24,162)

10,960 

(24,162)

Elemental 

Sulfur

10,893 

(24,016)

10,895 

(24,019)

SNG 4 (9) 4 (9)

Ammonia 0 (0) 0 (0)

CO2 Vent 

Streams/Stack 61 (134) 2 (4)

CO2 Product N/A 58 (128)

PSA Purge 

Gas 1 (3) 1 (3)

Total 10,960 

(24,162)

10,960 

(24,162) Total 10,960 (24,162)

10,960 

(24,162)

Exhibit 4-32 shows the overall water balance for the plant. Water demand represents the total 

amount of water required for a particular process. Some water is recovered within the process, 

primarily as syngas condensate, and is re-used as internal recycle. The difference between 

demand and recycle is raw water withdrawal. Raw water withdrawal is defined as the water 

removed from the ground or diverted from a surface-water source for use in the plant and was 

assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water 

withdrawal can be represented by the water metered from a raw water source and used in the 

plant processes for any and all purposes, such as cooling tower makeup, BFW makeup, quench 

system makeup, and slag handling makeup. The difference between water withdrawal and 

process water discharge is defined as water consumption and can be represented by the portion 

of the raw water withdrawn that is evaporated, transpired, incorporated into products or 

otherwise not returned to the water source from which it was withdrawn. Water consumption 

represents the net impact of the plant process on the water source balance.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

145

Exhibit 4-32 Cases 3 and 4 Water Balance

Case 3 Case 4

Water Demand, m3/min (gpm)

Slag Handling 0.95 (251) 0.95 (251)

Quench/Wash 4.2 (1,116) 4.2 (1,116)

Condenser Makeup 8.5 (2,258) 8.5 (2,258)

 Gasifier Steam 1.0 (273) 1.0 (273)

 Shift Steam 7.1 (1,881) 7.1 (1,882)

 BFW Makeup 0.39 (103) 0.39 (103)

Cooling Tower 24.1 (6,371) 24.2 (6,396)

Total 37.8 (9,996) 37.9 (10,021)

Internal Recycle, m3/min (gpm)

Slag Handling 0.95 (251) 0.95 (251)

Quench/Wash 4.2 (1,116) 4.2 (1,116)

Condenser Makeup 0.0 (0) 0.0 (0)

Cooling Tower 4.5 (1,195) 4.5 (1,196)

 Water from Coal Drying 0.0 (0) 0.0 (0)

 BFW Blowdown 0.39 (103) 0.39 (103)

 SWS Blowdown 0.85 (224) 0.85 (224)

 SWS Excess 3.3 (868) 3.3 (869)

Total 9.7 (2,563) 9.7 (2,563)

Raw Water Withdrawal, m3/min (gpm)

Slag Handling 0.0 (0) 0.0 (0)

Quench/Wash 0.0 (0) 0.0 (0)

Condenser Makeup 8.5 (2,258) 8.5 (2,258)

 Gasifier Steam 1.0 (273) 1.0 (273)

 Shift Steam 7.1 (1,881) 7.1 (1,882)

 BFW Makeup 0.39 (103) 0.39 (103)

Cooling Tower 19.6 (5,176) 19.7 (5,200)

Total 28.1 (7,434) 28.2 (7,458)

Process Water Discharge, m3/min (gpm)

SWS Blowdown 0.08 (22) 0.08 (22)

Cooling Tower Blowdown 5.4 (1,433) 5.4 (1,438)

Total 5.5 (1,455) 5.5 (1,461)

Raw Water Consumption, m3/min (gpm)

Slag Handling 0.0 (0) 0.0 (0)

Quench/Wash 0.0 (0) 0.0 (0)

SWS Blowdown -0.08 (-22) -0.08 (-22)

Condenser Makeup 8.5 (2,258) 8.5 (2,258)

Cooling Tower 14.2 (3,743) 14.2 (3,761)

Total 22.6 (5,979) 22.7 (5,997)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

146

Exhibit 4-33 Case 3 Gasification and ASU Heat and Mass Balance

N2 Reactant

N2 to NH3 Plant

Claus Tail Gas

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ILLINOIS NO. 6 SNG

AND AMMONIA PLANT

CASE 3

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 3

ASU AND GASIFICATION

DWG. NO.

BL-HMB-CS-3-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

PAGES

1 OF 4

Ambient Air

Intercooled

Air Compressor

Elevated

Pressure

ASU

Intercooled

Oxygen Compressor

Milled Coal

ASU

Vent

Slag

Removal

Slag

GROSS PLANT POWER: 292 MWE

AUXILIARY LOAD: 264 MWE

NET PLANT POWER: 29 MWE

SNG PRODUCTION: 5,333 MSCF/HR

NH3 PRODUCTION: 183,698 LB/HR

Dried Coal Coal

Feeding

Steam

CO2 to Lock Hoppers

Boost

Compressor

Siemens Gasifier

964,000 W

3,287,954 W

59.0 T

14.7 P

13.3 H

733,283 W

90.0 T

125.0 P

11.6 H

733,283 W

186.1 T

740.0 P

29.4 H

136,724 W

650.0 T

740.0 P

1,316.8 H

96,550 W

ENG UNITS

To Claus Plant

10,681 

W

90.0 T

125.0 P

11.6 H

2,260,094 W

76.5 T

16.4 P

14.0 H

329,890 W

290.0 T

14.7 P

355.3 H

277,383 W

2,300.1 T

14.7 P

797.0 H

Syngas

Quench

Cooler

Raw Syngas

to Scrubber

SH

Steam

5

1

7 11

3

14

6

2

Quench Water

16

Lock Hopper

Vent

170,013 W

340,027 W

181.2 T

815.0 P

13.3 H

12

340,027 W

60.0 T

149.7 P

1.7 H

15

558,232 W

SH

Steam

SH

Steam

2,415,734 W

499.7 T

564.7 P

495.3 H

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Sour Gas

Sour Water

Water

Steam

CO2

Tail Gas/

Flue Gas

24 Pilot Fuel

2,538 W

176.8 T

740.0 P

100.7 H

1,081,506 W

65.1 T

815.0 P

2,016.2 H

Coal 

Dryer

Coal Dryer 

Incinerator

Incinerator Fan

Combustion Air

Syngas

Synthesis Gas

Coal Dryer

Stack Gas

25

10

8

9

48

225,056 W

59.0 T

14.7 P

13.3 H

911,493 W

38,083 W

123.0 T

14.9 P

100.1 H

14,243 W

87.0 T

469.6 P

37.0 H

13

193,111 W

162.0 T

470.0 P

29.7 H

4

N2 for PSA Purge

35

76,900 W

162.0 T

470.0 P

29.7 H

N2 Compressor

HP

BFW
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

147

Exhibit 4-34 Case 3 Gas Cleanup Heat and Mass Balance

Mercury 

Removal

Knock

Out

Drum

Raw Syngas

to Scrubber

Sour

Drum

To Water Treatment

Makeup Water

Catalytic

Reactor

Beds

High

Temperature

Shift

Blowdown

From

ASU

LP CO2

Shift

Steam

HP BFW

Syngas

Coolers

Sour

Stripper

Two-Stage

Selexol

Clean Gas

CO2

Acid Gas

Syngas

Scrubber

Condensate

To Deaerator Condensate

434,306 W

550.0 T

600.0 P

1,270.5 H

1,767,318 W

417.8 T

544.7 P

436.2 H

2,415,734 W

499.7 T

564.7 P

495.3 H

2,337,629 W

361.6 T

554.7 P

414.1 H

1,738,163 W

94.6 T

469.7 P

19.2 H

578,942 W

87.0 T

469.6 P

37.0 H

50,203 W

119.0 T

23.7 P

39.4 H

1,295,330 W

41.5 T

16.7 P

3.2 H

1,117,815 W

339.3 T

115.0 P

339.2 H

562,160 W

87.0 T

469.6 P

37.0 H

24,016 W

6,416 W

291.1 T

65.0 P

973.8 H

10,681 W

90.0 T

125.0 P

11.6 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ILLINOIS NO. 6 SNG

AND AMMONIA PLANT

CASE 3

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 3

GAS CLEANUP

DWG. NO.

BL-HMB-CS-3-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

2 OF 4

Sour Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 292 MWE

AUXILIARY LOAD: 264 MWE

NET PLANT POWER: 29 MWE

SNG PRODUCTION: 5,333 MSCF/HR

NH3 PRODUCTION: 183,698 LB/HR

1,504,037 W

263,281 W

23

21

16

46

CO2

Tail Gas/

Flue Gas

17

18

20

263,281 W

418.3 T

534.7 P

436.0 H

1,726,252 W

95.0 T

479.7 P

19.3 H

High Temperature

Methanation Reactor

Pre-heater

Tail Gas Cleanup Unit

3

22

CO2 to Lock

Hoppers

Vented

CO2 Product

Claus Plant

Tail 

Gas

Furnace

Sulfur

45

42

HP CO2

41

1,002,155 W

42.0 T

16.7 P

3.7 H

633,202 W

60.0 T

149.7 P

1.7 H

340,027 W

60.0 T

149.7 P

1.7 H

Syngas to

Methanation

Boost

Compressor

2,538 W

Pilot Fuel

to Gasifier

2,538 W

176.8 T

740.0 P

100.7 H

24

Condensate

from Methnation

63,051 W

450.0 T

12.3 P

502.6 H

47

11,911 W

95.0 T

474.5 P

-0.7 H

Tail Gas

Compressor

COS Hydrolysis

19

Incinerator Fuel

25

To Coal Dryer

48

14,243 W

87.0 T

469.6 P

37.0 H

38,083 W

123.0 T

14.9 P

100.1 H

To NH3 Production

30

570,311 W

417.8 T

544.7 P

436.2 H

2,201,624 W

506.6 T

519.7 P

430.1 H

From NH3

Plant AGR Unit

43

19,766 W

119.0 T

23.7 P

37.8 H

44

69,969 W

119.0 T

23.7 P

38.9 H

CO2 from NH3 Plant

AGR Unit

526,339 W

60.0 T

135.0 P

2.8 H

From NH3 Plant

Knockout Drum
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

148

Exhibit 4-35 Case 3 Methanation and Power Block Heat and Mass Balance

Steam Seal 

Regulator

65 PSIA Header

Steam Injection

To Gasifier Make-up

Gland

Steam

Condenser

Condensate to Preheating

Condensate

Pump

3,026,965 W

101.1 T

1.0 P

69.1 H

1,128,953 W

1,628,301 W

1,050.0 T

1,814.7 P

1,510.4 H

3,026,965 W

102.4 T

120.0 P

70.6 H

1,400 W

1,400 W

212.0 T

14.7 P

179.9 H

136,724 W

650.0 T

740.0 P

1,316.8 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ILLINOIS NO. 6 SNG

AND AMMONIA PLANT

CASE 3

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 3

METHANATION AND POWER BLOCK

DWG. NO.

BL-HMB-CS-3-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 4

Sour Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 292 MWE

AUXILIARY LOAD: 264 MWE

NET PLANT POWER: 29 MWE

SNG PRODUCTION: 5,333 MSCF/HR

NH3 PRODUCTION: 183,698 LB/HR

Flue Gas

Deaerator

HT Reactor

LP TURBINE GENERATOR HP

TURBINE IP

TURBINE

HOT WELL

AIR-COOLED 

CONDENSER CONDENSER

IP Pump

To Shift Steam

Production

LP Pump

250 PSIA

Attemperating Water

HP Pump

Recycle

Compressor

Syngas from

Selexol Unit

Knock

Out

Drum

Molecular 

Sieve 

Purification 

Unit

Multistage 

Intercooled 

SNG 

Compressor

Clean Up

HT Reactor Reator

Purification

Off-Gas

SNG

Product

Condensate to

Sour Drum

Reactor

Pre-heater

SH Steam from

Syngas Cooler

IP BFW

SH Shift Steam

IP/LP BFW

IP/LP Steam IP Steam IP BFW

49

50

1,676,540 W

562,160 W

87.0 T

469.6 P

37.0 H

572.0 T

447.5 P

629.2 H

587.7 T

475.0 P

638.2 H

572.0 T

464.6 P

566.5 H

1,286.4 T

457.5 P

1,096.8 H

1,599,984 W

1,031.0 T

436.8 P

964.6 H

392.0 T

426.8 P

580.9 H

649.6 T

416.1 P

774.9 H

335.0 T

406.1 P

412.1 H

321,514 W

95.0 T

396.1 P

18.0 H

95.0 T

20.1 P

20.7 H 233,520 W

95.0 T

381.0 P

20.5 H

233,520 W

95.0 T

899.5 P

5.6 H

1,128,263 W

278.6 T

450.0 P

248.2 H

835,485 W

571,473 W

298.0 T

65.0 P

1,178.6 H

1,314,630 W

503.2 T

65.0 P

1,283.6 H

IP BFW

14,459 W

278.5 T

379.0 P

247.9 H

26

27 28 29

10,910 W

658.0 T

18.0 P

1,362.6 H

105,137 W To Shift Steam

550.0 T

600.0 P

1,255.0 H

P-753

To Syngas Cooler

Reheater

(Syngas Cooler)

Attemperation

Water

1,380,249 W

996.3 T

501.4 P

1,517.9 H

21,656 W
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

149

Exhibit 4-36 Case 3 Ammonia Production Heat and Mass Balance

Ammonia

Product

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ILLINOIS NO. 6 SNG

AND AMMONIA PLANT

CASE 3

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 3

AMMONIA PRODUCTION

DWG. NO.

BL-HMB-CS-3-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

CO2

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

4 OF 4

Ammonia 

Process Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 292 MWE

AUXILIARY LOAD: 264 MWE

NET PLANT POWER: 29 MWE

SNG PRODUCTION: 5,333 MSCF/HR

NH3 PRODUCTION: 183,698 LB/HR

Ammonia

Radial Bed

Reactor

Superheater

Recycle

Compressor

Final

Reheater

Recycle

Loop Heater

Ammonia

Flash Tank

Ammonia

Flash Tank

IP Steam

1,024,695 W

650.0 T

2,030.0 P

504.2 H

1,024,695 W

949.5 T

1,955.0 P

711.0 H

1,024,695 W

720.0 T

1,954.0 P

527.0 H

1,024,695 W

73.5 T

1,948.0 P

-2.4 H

1,024,695 W

420.9 T

2,035.0 P

316.5 H 1,024,695 W

241,888 W

193,111 W

162.0 T

470.0 P

29.7 H

1,024,695 W

-13.3 T

1,892.5 P

-42.8 H

39

IP Boiler Recycle

Loop Heater

BFW

Makeup

Compressor Shifted Syngas

Liquid NH3

Cooler

Purge Gas

Liquid NH3

Cooler

4

38

40

37

48,777 W

69.2 T

469.6 P

114.9 H

183,698 W

-13.3 T

1,892.5 P

-605.4 H

58,197 W

-19.2 T

469.6 P

-42.6 H

Shift Reactor 1

Shift Steam

506,315 W

550.0 T

600.0 P

1,270.5 H

570,311 W

417.8 T

544.7 P

436.2 H

31

30

Shift Reactor 2

Syngas

Coolers

Mercury 

Removal

Two-Stage

Selexol

Clean Gas

CO2

Acid Gas

PSA Unit

Acid Gas to

Claus Plant

43

CO2 Product

Purge Nitrogen

WHB

WHB Combustion

Air Fan

WHB Stack Gas

Flue Gas

35

76,900 W

162.0 T

470.0 P

1,076,627 W 29.7 H

450.0 T

534.2 P

643.3 H

32

635,320 W

95.0 T

489.2 P

19.2 H

33

635,320 W

94.2 T

479.2 P

19.0 H

34

89,214 W

87.0 T

469.6 P

81.8 H

36

175,534 W

69.2 T

20.0 P

10.7 H

124,353 W

59.0 T

16.2 P

10.6 H

299,887 W

325.0 T

15.7 P

169.4 H

BFW

Steam/Water

Mixture

19,766 W

119.0 T

23.7 P

37.8 H

526,339 W

60.0 T

135.0 P

2.8 H

Knockout

Drum

Condensate

To Sour Drum
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

150

Exhibit 4-37 Case 4 Gasification and ASU Heat and Mass Balance

N2 Reactant

N2 to NH3 Plant

Claus Tail Gas

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ILLINOIS NO. 6 SNG

AND AMMONIA PLANT

W/ CO2 CAPTURE

CASE 4

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 4

ASU AND GASIFICATION

DWG. NO.

BL-HMB-CS-4-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

PAGES

1 OF 4

Ambient Air

Intercooled

Air Compressor

Elevated

Pressure

ASU

Intercooled

Oxygen Compressor

Milled Coal

ASU

Vent

Slag

Removal

Slag

GROSS PLANT POWER: 292 MWE

AUXILIARY LOAD: 316 MWE

NET PLANT POWER: -24 MWE

SNG PRODUCTION: 5,328 MSCF/HR

NH3 PRODUCTION: 183,634 LB/HR

Dried Coal Coal

Feeding

Steam

CO2 to Lock Hoppers

Boost

Compressor

Siemens Gasifier

964,000 W

3,288,691 W

59.0 T

14.7 P

13.3 H

733,114 W

90.0 T

125.0 P

11.6 H

733,114 W

186.1 T

740.0 P

29.4 H

136,724 W

650.0 T

740.0 P

1,316.8 H

96,550 W

ENG UNITS

To Claus Plant

11,017 

W

90.0 T

125.0 P

11.6 H

2,260,701 W

76.5 T

16.4 P

14.0 H

328,647 W

290.0 T

14.7 P

355.9 H

276,140 W

2,308.2 T

14.7 P

799.7 H

Syngas

Quench

Cooler

Raw Syngas

to Scrubber

SH

Steam

5

1

7 11

3

14

6

2

Quench Water

16

Lock Hopper

Vent

6,782 W

340,026 W

179.4 T

815.0 P

11.8 H

12

340,026 W

165.5 T

750.0 P

9.5 H

15

558,027 W

SH

Steam

SH

Steam

2,415,359 W

499.7 T

564.7 P

495.2 H

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Sour Gas

Sour Water

Water

Steam

CO2

Tail Gas/

Flue Gas

24 Pilot Fuel

2,538 W

176.8 T

740.0 P

100.7 H

1,081,506 W

64.7 T

815.0 P

2,018.2 H

Coal 

Dryer

Coal Dryer 

Incinerator

Incinerator Fan

Combustion Air

Syngas

Synthesis Gas

Coal Dryer

Stack Gas

25

10

8

9

48

223,666 W

59.0 T

14.7 P

13.3 H

911,493 W

38,023 W

123.0 T

14.9 P

98.6 H

14,451 W

87.0 T

469.6 P

37.0 H

13

193,105 W

242.0 T

470.0 P

50.4 H

4

N2 for PSA Purge 35 76,865 W

242.0 T

470.0 P

50.4 H

N2 Compressor

HP

BFW
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

151

Exhibit 4-38 Case 4 Gas Cleanup Heat and Mass Balance

Mercury 

Removal

Knock

Out

Drum

Raw Syngas

to Scrubber

Sour

Drum

To Water Treatment

Makeup Water

Catalytic

Reactor

Beds

High

Temperature

Shift

Blowdown

From

ASU

Shift

Steam

HP BFW

Syngas

Coolers

Sour

Stripper

Two-Stage

Selexol

Clean Gas

CO2

Acid Gas

Syngas

Scrubber

Condensate

To Deaerator Condensate

434,462 W

550.0 T

600.0 P

1,270.5 H

1,766,999 W

417.8 T

544.7 P

436.1 H

2,415,359 W

499.7 T

564.7 P

495.2 H

2,337,208 W

361.6 T

554.7 P

414.0 H

1,738,377 W

94.6 T

469.7 P

19.2 H

578,766 W

87.0 T

469.6 P

37.0 H

50,520 W

119.0 T

23.7 P

39.3 H

1,117,862 W

339.3 T

115.0 P

339.2 H

561,777 W

87.0 T

469.6 P

37.0 H

24,019 W

6,417 W

291.1 T

65.0 P

973.8 H

11,017 W

90.0 T

125.0 P

11.6 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ILLINOIS NO. 6 SNG

AND AMMONIA PLANT

W/ CO2 CAPTURE

CASE 4

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 4

GAS CLEANUP

DWG. NO.

BL-HMB-CS-4-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

2 OF 4

Sour Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 292 MWE

AUXILIARY LOAD: 316 MWE

NET PLANT POWER: -24 MWE

SNG PRODUCTION: 5,328 MSCF/HR

NH3 PRODUCTION: 183,634 LB/HR

1,503,810 W

263,189 W

23

21

16

46

CO2

Tail Gas/

Flue Gas

17

18

20

263,189 W

418.3 T

534.7 P

435.9 H

1,726,146 W

95.0 T

479.7 P

19.3 H

High Temperature

Methanation Reactor

Pre-heater

Tail Gas Cleanup Unit

3

22

Claus Plant

Tail 

Gas

Furnace

Sulfur

45

42

Syngas to

Methanation

Boost

Compressor

2,538 W

Pilot Fuel

to Gasifier

2,538 W

176.8 T

740.0 P

100.7 H

24

Condensate

from Methnation

63,702 W

450.0 T

12.3 P

501.1 H

47

12,231 W

95.0 T

474.5 P

-0.7 H

Tail Gas

Compressor

COS Hydrolysis

19

Incinerator Fuel

25

To Coal Dryer

48

14,451 W

87.0 T

469.6 P

37.0 H

38,023 W

123.0 T

14.9 P

98.6 H

To NH3 Production

30

570,209 W

417.8 T

544.7 P

436.1 H

2,201,461 W

506.7 T

519.7 P

430.1 H

From NH3

Plant AGR Unit

43

19,766 W

119.0 T

23.7 P

37.8 H

44

70,286 W

119.0 T

23.7 P

38.9 H

From NH3 Plant

Knockout Drum

SNG Purification

Off Gas

340,026 W

165.5 T

750.0 P

9.5 H

CO2 to 

Sequestration

CO2 to

Lock Hoppers

1,543,753 W

95.0 T

2,215.0 P

-89.9 H

27

41

LP Lock

Hopper Vent HP Lock

Hopper Vent

LP CO2

27,751 W

135,480 W

768,698 W

81.4 T

149.7 P

6.2 H

1,118,018 W

49.8 T

16.7 P

5.7 H

HP CO2

CO2 from NH3 Plant

526,308 W

60.0 T

135.0 P

2.8 H

95.0 T

20.1 P

20.7 H
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

152

Exhibit 4-39 Case 4 Methanation and Power Block Heat and Mass Balance

Steam Seal 

Regulator

65 PSIA Header

Steam Injection

To Gasifier

Make-up

Gland

Steam

Condenser

Condensate to Preheating

Condensate

Pump

3,025,728 W

101.1 T

1.0 P

69.1 H

1,129,574 W

1,626,113 W

1,050.0 T

1,814.7 P

1,510.4 H

3,025,728 W

102.4 T

120.0 P

70.6 H

1,400 W

1,400 W

212.0 T

14.7 P

179.9 H

136,724 W

650.0 T

740.0 P

1,316.8 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ILLINOIS NO. 6 SNG

AND AMMONIA PLANT

W/ CO2 CAPTURE

CASE 4

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 4

METHANATION AND POWER BLOCK

DWG. NO.

BL-HMB-CS-4-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 4

Sour Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 292 MWE

AUXILIARY LOAD: 316 MWE

NET PLANT POWER: -24 MWE

SNG PRODUCTION: 5,328 MSCF/HR

NH3 PRODUCTION: 183,634 LB/HR

Flue Gas

Deaerator

HT Reactor

LP TURBINE GENERATOR HP

TURBINE IP

TURBINE

HOT WELL

AIR-COOLED 

CONDENSER CONDENSER

IP Pump

To Shift Steam

Production

LP Pump

250 PSIA

Attemperating Water

HP Pump

Recycle

Compressor

Syngas from

Selexol Unit

Knock

Out

Drum

Molecular 

Sieve 

Purification 

Unit

Multistage 

Intercooled 

SNG 

Compressor

Clean Up

HT Reactor Reator

Purification

Off-Gas

SNG

Product

Condensate to

Sour Drum

Reactor

Pre-heater

SH Steam from

Syngas Cooler

IP BFW

SH Shift Steam

IP/LP BFW

IP/LP Steam IP Steam IP BFW

49

50

1,674,411 W

561,777 W

87.0 T

469.6 P

37.0 H

572.0 T

447.5 P

629.0 H

587.7 T

475.0 P

638.1 H

572.0 T

464.6 P

566.3 H

1,286.5 T

457.5 P

1,096.6 H

1,598,903 W

1,031.1 T

436.8 P

964.4 H

392.0 T

426.8 P

580.7 H

649.6 T

416.1 P

774.7 H

335.0 T

406.1 P

412.1 H

321,400 W

95.0 T

396.1 P

18.0 H

95.0 T

20.1 P

20.7 H 233,309 W

95.0 T

381.0 P

20.5 H

233,309 W

95.0 T

899.5 P

5.6 H

1,129,561 W

278.6 T

450.0 P

248.2 H

835,387 W

571,489 W

298.0 T

65.0 P

1,178.6 H

1,312,757 W

505.5 T

65.0 P

1,284.8 H

IP BFW

14,394 W

278.5 T

379.0 P

247.9 H

26

27 28 29

10,908 W

658.3 T

18.0 P

1,362.7 H

105,776 W To Shift Steam

550.0 T

600.0 P

1,255.0 H

To Syngas Cooler

Attemperation

Water

1,377,381 W

999.5 T

501.4 P

1,519.6 H

21,706 W
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

153

Exhibit 4-40 Case 4 Ammonia Production Heat and Mass Balance

N2 Reactant

Ammonia

Product

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ILLINOIS NO. 6 SNG

AND AMMONIA PLANT

W/ CO2 CAPTURE

CASE 4

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 4

AMMONIA PRODUCTION

DWG. NO.

BL-HMB-CS-4-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

CO2

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

4 OF 4

Ammonia 

Process Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 292 MWE

AUXILIARY LOAD: 316 MWE

NET PLANT POWER: -24 MWE

SNG PRODUCTION: 5,328 MSCF/HR

NH3 PRODUCTION: 183,634 LB/HR

Ammonia

Radial Bed

Reactor

Superheater

Recycle

Compressor

Final

Reheater

Recycle

Loop Heater

Ammonia

Flash Tank

Ammonia

Flash Tank

IP Steam

1,025,099 W

650.0 T

2,030.0 P

503.8 H

1,025,099 W

949.5 T

1,955.0 P

710.4 H

1,025,099 W

720.0 T

1,954.0 P

526.6 H

1,025,099 W

73.5 T

1,948.0 P

-2.4 H

1,025,099 W

420.9 T

2,035.0 P

316.2 H 1,025,099 W

241,854 W

193,105 W

242.0 T

470.0 P

50.4 H

1,025,099 W

-13.3 T

1,892.5 P

-42.8 H

39

IP Boiler Recycle

Loop Heater

BFW

Makeup

Compressor Shifted Syngas

Liquid NH3

Cooler

Purge Gas

Liquid NH3

Cooler

38

40

37

48,749 W

77.1 T

469.6 P

138.9 H

183,634 W

-13.3 T

1,892.5 P

-605.4 H

58,232 W

-19.2 T

469.6 P

-42.6 H

Shift Reactor 1

Shift Steam

506,295 W

550.0 T

600.0 P

1,270.5 H

570,209 W

417.8 T

544.7 P

436.1 H

31

30

Shift Reactor 2

Syngas

Coolers

Mercury 

Removal

Two-Stage

Selexol

Clean Gas

CO2

Acid Gas

PSA Unit

Acid Gas to

Claus Plant

43

CO2 Product

Purge Nitrogen

WHB

WHB Combustion

Air Fan

WHB Stack Gas

Flue Gas

35

76,865 W

242.0 T

470.0 P

1,076,504 W 50.4 H

450.0 T

534.2 P

643.3 H

32

635,261 W

95.0 T

489.2 P

19.2 H

33

635,261 W

94.2 T

479.2 P

19.0 H

34

89,187 W

87.0 T

469.6 P

81.8 H

36

175,535 W

77.1 T

20.0 P

13.0 H

124,191 W

59.0 T

16.0 P

10.6 H

299,726 W

325.0 T

15.5 P

169.4 H

4

BFW

Steam/Water

Mixture

19,766 W

119.0 T

23.7 P

37.8 H

526,308 W

60.0 T

135.0 P

2.8 H

Knockout

Drum

Condensate

To Sour Drum
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

154

Exhibit 4-41 Cases 3 and 4 Energy Balance

HHV Sensible + Latent Power Total

Case 3 Case 4 Case 3 Case 4 Case 3 Case 4 Case 3 Case 4

Heat In, GJ/hr (MMBtu/hr)

Coal 11,865 

(11,246)

11,865 

(11,246) 12.1 (11.5) 12.1 (11.5) 0 (0) 0 (0) 11,877 (11,257)

11,877 

(11,257)

ASU Air 0 (0) 0 (0) 50.7 (48.0) 50.7 (48.0) 0 (0) 0 (0) 51 (48) 51 (48)

Raw Water Makeup 0 (0) 0 (0) 105.8 (100.3) 106.2 (100.6) 0 (0) 0 (0) 106 (100) 106 (101)

Auxiliary Power 0 (0) 0 (0) 0.0 (0.0) 0.0 (0.0) 949 (899) 1,138 

(1,078) 949 (899) 1,138 (1,078)

Totals 11,865 

(11,246)

11,865 

(11,246) 168.6 (159.8) 168.9 (160.1) 949 (899) 1,138 (1,078)

12,983 

(12,305)

13,172 

(12,484)

Heat Out, GJ/hr (MMBtu/hr)

ASU/NH3 Intercoolers 0 (0) 0 (0) 405 (384) 412 (390) 0 (0) 0 (0) 405 (384) 412 (390)

ASU Vent 0 (0) 0 (0) 33 (32) 33 (32) 0 (0) 0 (0) 33 (32) 33 (32)

Slag 46 (43) 46 (43) 79 (75) 79 (75) 0 (0) 0 (0) 125 (118) 125 (118)

Coal Drying Stack Gas 0 (0) 0 (0) 123.7 (117.2) 123.4 (117.0) 0 (0) 0 (0) 124 (117) 123 (117)

Sulfur 101 (96) 101 (96) 1.2 (1.2) 1.2 (1.2) 0 (0) 0 (0) 102 (97) 102 (97)

CO2 Intercoolers 0 (0) 0 (0) 0.0 (0.0) 345 (327) 0 (0) 0 (0) 0 (0) 345 (327)

CO2 0 (0) 0 (0) 4.4 (4.2) -146 (-139) 0 (0) 0 (0) 4 (4) -146 (-139)

Cooling Tower Blowdown 0 (0) 0 (0) 40 (38) 40 (38) 0 (0) 0 (0) 40 (38) 40 (38)

SNG 5,409 (5,127) 5,404 (5,122) 1.4 (1.3) 1.4 (1.3) 0 (0) 0 (0) 5,410 (5,128) 5,405 (5,123)

SNG Purification Off-Gas 0 (0) 0 (0) 2 (2) 0 (0) 0 (0) 0 (0) 2 (2) 0 (0)

Ammonia 1,871 (1,773) 1,870 (1,773) -117 (-111) -117 (-111) 0 (0) 0 (0) 1,754 (1,662) 1,753 (1,661)

Ammonia WHB Off-Gas 0 (0) 0 (0) 54 (51) 54 (51) 0 (0) 0 (0) 54 (51) 54 (51)

Condenser 0 (0) 0 (0) 1,777 (1,684) 1,776 (1,684) 0 (0) 0 (0) 1,777 (1,684) 1,776 (1,684)

Auxiliary Cooling Loads 0 (0) 0 (0) 700 (664) 707 (670) 0 (0) 0 (0) 700 (664) 707 (670)

Process Losses* 0 (0) 0 (0) 1,400 (1,327) 1,390 (1,317) 0 (0) 0 (0) 1,400 (1,327) 1,390 (1,317)

Power 0 (0) 0 (0) 0.0 (0.0) 0.0 (0.0) 1,052 (997) 1,052 (997) 1,052 (997) 1,052 (997)

Totals 7,426 (7,039) 7,421 (7,034) 4,504 (4,269) 4,699 (4,454) 1,052 (997) 1,052 (997) 12,983 

(12,305)

13,172 

(12,484)

* Includes other energy losses not explicitly accounted for in the model.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

155

4.2.4

Major equipment items for the Siemens gasifier SNG and ammonia co-production plant without 

and with carbon sequestration using Illinois No. 6 coal are shown in the following tables. The 

accounts used in the equipment list correspond to the account numbers used in the cost estimates 

in Section 

Cases 3 and 4 Equipment Lists

4.2.5. In general, the design conditions include a 10 percent contingency for flows 

and heat duties and a 21 percent contingency for heads on pumps and fans.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

156

ACCOUNT 1 COAL HANDLING

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition

Case 4 Design 

Condition

1

Bottom Trestle 

Dumper and 

Receiving Hoppers

N/A 2 0 181 tonne (200 ton) 181 tonne (200 ton)

2 Feeder Belt 2 0 572 tonne/hr (630 tph) 572 tonne/hr (630 tph)

3 Conveyor No. 1 Belt 1 0 1,134 tonne/hr

(1,250 tph)

1,134 tonne/hr

(1,250 tph)

4 Transfer Tower No. 

1 Enclosed 1 0 N/A N/A

5 Conveyor No. 2 Belt 1 0 1,134 tonne/hr

(1,250 tph)

1,134 tonne/hr

(1,250 tph)

6 As-Received Coal 

Sampling System Two-stage 1 0 N/A N/A

7 Stacker/Reclaimer Traveling, 

linear 1 0 1,134 tonne/hr(1,250 tph)

1,134 tonne/hr

(1,250 tph)

8 Reclaim Hopper N/A 2 1 91 tonne (100 ton) 91 tonne (100 ton)

9 Feeder Vibratory 2 1 363 tonne/hr (400 tph) 363 tonne/hr (400 tph)

10 Conveyor No. 3 Belt w/ 

tripper 1 0 726 tonne/hr (800 tph) 726 tonne/hr (800 tph)

11 Crusher Tower N/A 1 0 N/A N/A

12 Coal Surge Bin w/ 

Vent Filter Dual outlet 2 0 363 tonne (400 ton) 363 tonne (400 ton)

13 Crusher Impactor 

reduction 2 0 8 cm x 0 - 3 cm x 0(3" x 0 - 1-1/4" x 0)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

14 As-Fired Coal 

Sampling System

Swing 

hammer 1 1 N/A N/A
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

157

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition

Case 4 Design 

Condition

15 Conveyor No. 4 Belt 

w/tripper 1 0 726 tonne/hr (800 tph) 726 tonne/hr (800 tph)

16 Transfer Tower No. 

2 Enclosed 1 0 N/A N/A

17 Conveyor No. 5 Belt w/ 

tripper 1 0 726 tonne/hr (800 tph) 726 tonne/hr (800 tph)

18

Coal Silo w/ Vent 

Filter and Slide 

Gates

Field 

erected 3 0 1,633 tonne (1,800 ton) 1,633 tonne (1,800 ton)

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition

Case 4 Design 

Condition

1 Feeder Vibratory 6 0 82 tonne/hr (90 tph) 82 tonne/hr (90 tph)

2 Conveyor No. 

6

Belt 

w/tripper 3 0 163 tonne/hr (180 tph) 163 tonne/hr (180 tph)

3 Roller Mill 

Feed Hopper Dual Outlet 3 0 318 tonne (350 ton) 318 tonne (350 ton)

4 Weigh Feeder Belt 6 0 82 tonne/hr (90 tph) 82 tonne/hr (90 tph)

5 Pulverizer Rotary 6 0 82 tonne/hr (90 tph) 82 tonne/hr (90 tph)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

158

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment

No. Description Type Operating Qty. Spares Case 3 Design Condition

Case 4 Design 

Condition

1

Demineralized 

Water Storage 

Tank

Vertical, 

cylindrical, 

outdoor

3 0 726,799 liters (192,000 

gal)

726,799 liters (192,000 

gal)

2 Condensate 

Pumps

Vertical 

canned 2 1

12,681 lpm @ 91 m H2O

(3,350 gpm @ 300 ft 

H2O)

12,681 lpm @ 91 m H2O

(3,350 gpm @ 300 ft 

H2O)

3 Deaerator Horizontal 

spray type 2 0 920,793 kg/hr (2,030,000 lb/hr)

920,793 kg/hr 

(2,030,000 lb/hr)

4

Intermediate 

Pressure 

Feedwater 

Pump

Horizontal 

centrifugal, 

single stage

2 1

8,479 lpm @ 341 m H2O

(2,240 gpm @ 1120 ft 

H2O)

8,517 lpm @ 341 m H2O

(2,250 gpm @ 1120 ft 

H2O)

5

High Pressure 

Feedwater 

Pump

Barrel type, 

multi-stage, 

centrifugal

2 1

HP water: 7,268 lpm @ 

1,676 m H2O (1,920 gpm 

@ 5,500 ft H2O)

HP water: 7,230 lpm @ 

1,676 m H2O (1,910 gpm 

@ 5,500 ft H2O)

6 Auxiliary Boiler

Shop 

fabricated, 

water tube

1 0

18,144 kg/hr, 2.8 MPa, 

343°C

(40,000 lb/hr, 400 psig, 

650°F)

18,144 kg/hr, 2.8 MPa, 

343°C

(40,000 lb/hr, 400 psig, 

650°F)

7 Service Air 

Compressors

Flooded 

Screw 3 1 28 m3

/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

8 Instrument Air 

Dryers

Duplex, 

regenerative 3 1 28 m3

/min (1,000 scfm) 28 m3/min (1,000 scfm)

9

Closed Cycle 

Cooling Heat 

Exchangers

Plate and 

frame 2 0 608 GJ/hr(576 MMBtu/hr) each

615 GJ/hr 

(583 MMBtu/hr)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

159

Equipment

No. Description Type Operating Qty. Spares Case 3 Design Condition

Case 4 Design 

Condition

10

Closed Cycle 

Cooling Water 

Pumps

Horizontal 

centrifugal 2 1

218,040 lpm @ 21 m 

H2O

(57,600 gpm @ 70 ft 

H2O)

220,690 lpm @ 21 m 

H2O

(58,300 gpm @ 70 ft 

H2O)

11 Engine-Driven 

Fire Pump

Vertical 

turbine, 

diesel 

engine

1 1

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft 

H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft 

H2O)

12 Fire Service 

Booster Pump

Two-stage 

horizontal 

centrifugal

1 1 2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

13 Raw Water 

Pumps

Stainless 

steel, single 

suction

2 1 7,798 lpm @ 18 m H2O

(2,060 gpm @ 60 ft H2O)

7,836 lpm @ 18 m H2O

(2,070 gpm @ 60 ft H2O)

14 Ground Water 

Pumps

Stainless 

steel, single 

suction

6 1 2,612 lpm @ 268 m H2O

(690 gpm @ 880 ft H2O)

2,612 lpm @ 268 m H2O

(690 gpm @ 880 ft H2O)

15 Filtered Water 

Pumps

Stainless 

steel, single 

suction

2 1

7,647 lpm @ 49 m H2O

(2,020 gpm @ 160 ft 

H2O)

7,647 lpm @ 49 m H2O

(2,020 gpm @ 160 ft 

H2O)

16 Filtered Water 

Tank

Vertical, 

cylindrical 2 0 3,660,493 liter (967,000 gal)

3,660,493 liter 

(967,000 gal)

17 Makeup Water 

Demineralizer

Anion, 

cation, and 

mixed bed

5 0 1,703 lpm (450 gpm) 1,703 lpm (450 gpm)

18

Liquid Waste 

Treatment 

System

1 0 10 years, 24-hour storm 10 years, 24-hour storm
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

160

ACCOUNT 4 GASIFIER, ASU, AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment 

No. Description Type Operating Qty.

Spare

s Case 3 Design Condition Case 4 Design Condition

1 Gasifier

Pressurized dryfeed, entrained 

bed

6 0 1,905 tonne/day, 4.2 MPa

(2,100 tpd, 615 psia)

1,905 tonne/day, 4.2 MPa

(2,100 tpd, 615 psia)

2 Synthesis Gas 

Cooler

Convective 

spiral-wound 

tube boiler

6 0 200,941 kg/hr

(443,000 lb/hr)

200,941 kg/hr

(443,000 lb/hr)

3

Syngas 

Scrubber 

Including Sour

Water Stripper

Vertical upflow 6 0 200,941 kg/hr

(443,000 lb/hr)

200,941 kg/hr

(443,000 lb/hr)

4 Raw Gas 

Coolers

Shell and tube 

with condensate 

drain

12 0 414,583 kg/hr

(914,000 lb/hr)

414,583 kg/hr

(914,000 lb/hr)

5

Raw Gas 

Knockout 

Drum

Vertical with 

mist eliminator 3 0

287,124 kg/hr, 35°C, 

3.3 MPa

(633,000 lb/hr, 95°F, 

485 psia)

287,124 kg/hr, 35°C, 

3.3 MPa

(633,000 lb/hr, 95°F, 

485 psia)

6 Flare Stack

Self-supporting, 

carbon steel, 

stainless steel 

top, pilot 

ignition

3 0 401,883 kg/hr (886,000 

lb/hr) syngas

401,883 kg/hr (886,000 

lb/hr) syngas

7 ASU Main Air 

Compressor

Centrifugal, 

multi-stage 3 0 7,476 m3

/min @ 1.3 MPa

(264,000 scfm @ 190 psia)

7,476 m3/min @ 1.3 MPa

(264,000 scfm @ 190 psia)

8 Cold Box Vendor design 3 0 2,994 tonne/day (3,300 

tpd) of 99% purity oxygen

2,994 tonne/day (3,300 

tpd) of 99% purity oxygen
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

161

Equipment 

No. Description Type Operating Qty.

Spare

s Case 3 Design Condition Case 4 Design Condition

9 Oxygen 

Compressor

Centrifugal, 

multi-stage 3 0

1,501 m3/min 

(53,000 scfm)

Suction - 0.9 MPa 

130 psia)

Discharge - 5.1 MPa 

(740 psia)

1,501 m3/min 

(53,000 scfm)

Suction - 0.9 MPa 

(130 psia)

Discharge - 5.1 MPa 

(740 psia)

10

Coal Feed 

System CO2

Compressor

Centrifugal, 

multi-stage 3 0

510 m3

/min (18,000 scfm)

Suction - 1.0 MPa 

(150 psia)

Discharge - 5.7 MPa 

(820 psia)

510 m3/min (18,000 scfm)

Suction - 5.2 MPa 

(750 psia)

Discharge - 5.7 MPa 

(820 psia)

ACCOUNT 5A SYNGAS CLEANUP

Equipment 

No. Description Type Operating Qty.

Spare

s Case 3 Design Condition Case 4 Design Condition

1 Mercury 

Adsorber

Sulfated carbon 

bed 3 0

392,811 kg/hr

(866,000 lb/hr)

35°C (95°F)

3.3 MPa (480 psia)

392,811 kg/hr

(866,000 lb/hr)

35°C (95°F)

3.3 MPa (480 psia)

2 Zinc Oxide 

Guard Bed Fixed bed 1 0 335 Nm3

/min

(11,827 acfm)

335 Nm3/min

(11,817 acfm)

3 Sulfur Plant Claus type 2 0 144 tonne/day (159 tpd) 144 tonne/day (159 tpd)

4

SNG Plant 

COS 

Hydrolysis 

Reactor

Fixed bed, 

catalytic 2 0

65,771 kg/hr

(145,000 lb/hr)

216°C (420°F)

3.7 MPa (540 psia)

65,771 kg/hr

(145,000 lb/hr)

216°C (420°F)

3.7 MPa (540 psia)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

162

Equipment 

No. Description Type Operating Qty.

Spare

s Case 3 Design Condition Case 4 Design Condition

5

SNG Plant 

Water Gas 

Shift Reactor

Fixed bed, 

catalytic 2 0

483,529 kg/hr

(1,066,000 lb/hr)

232°C (450°F)

3.7 MPa (540 psia)

483,529 kg/hr

1,066,000 lb/hr)

232°C (450°F)

3.7 MPa (540 psia)

6

Shift Reactor 

Heat Recovery 

Exchanger

Shell and Tube 2 each 0

Exchanger 1: 34 GJ/hr 

(32 MMBtu/hr)

Exchanger 2: 61 GJ/hr 

(57 MMBtu/hr)

Exchanger 3: 17 GJ/hr 

(16 MMBtu/hr)

Exchanger 1: 34 GJ/hr 

(32 MMBtu/hr)

Exchanger 2: 61 GJ/hr 

(57 MMBtu/hr)

Exchanger 3: 17 GJ/hr 

(16 MMBtu/hr)

7

Ammonia 

Plant Water 

Gas Shift 

Reactors

Fixed bed, 

catalytic 2 0

268,527 kg/hr

(592,000 lb/hr)

249°C (480°F)

3.7 MPa (540 psia)

268,527 kg/hr

(592,000 lb/hr)

249°C (480°F)

3.7 MPa (540 psia)

8

Ammonia 

Plant Shift 

Reactor Heat 

Recovery 

Exchanger

Shell and Tube 1 0 227 GJ/hr (215 MMBtu/hr) 227 GJ/hr (215 MMBtu/hr)

9 Acid Gas 

Removal Plant

Two-stage 

Selexol 3 0

394,625 kg/hr

(870,000 lb/hr)

35°C (95°F)

3.2 MPa (470 psia)

394,625 kg/hr

(870,000 lb/hr)

35°C (95°F)

3.2 MPa (470 psia)

10 Tail Gas 

Treatment Unit

Proprietary 

amine, 

absorber/strippe

r

2 0

12,561 kg/hr (27,692 lb/hr)

49°C (120°F)

0.1 MPa (10.6 psia)

12,625 kg/hr (27,833 lb/hr)

49°C (120°F)

0.1 MPa (10.6 psia)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

163

Equipment 

No. Description Type Operating Qty.

Spare

s Case 3 Design Condition Case 4 Design Condition

11

Tail Gas 

Treatment 

Incinerator

N/A 2 0

69,200 kg/hr

(152,561 lb/hr)

24°C (75°F)

0.1 MPa (14.9 psia)

68,890 kg/hr

(151,877 lb/hr)

24°C (74°F)

0.1 MPa (14.9 psia)

12

Tail Gas 

Recycle 

Compressor

Centrifugal 2 0 3,060 kg/hr @ 3.3 MPa

(6,746 lb/hr @ 475 psia)

3,139 kg/hr @ 3.3 MPa

(6,920 lb/hr @ 475 psia)

ACCOUNT 5A SNG PRODUCTION/METHANATION SYSTEM

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition Case 4 Design Condition

1

Methanation 

Reactor 

Preheater 

Shell and 

Tube 2 0 106 GJ/hr (101 MMBtu/hr) 106 GJ/hr (100 MMBtu/hr)

2 Methanation 

Reactor 1

Fixed Bed, 

catalytic 2 0

539,321 kg/hr

(1,189,000 lb/hr)

699°C (1,290°F)

3.2 MPa (460 psia)

538,868 kg/hr

(1,188,000 lb/hr)

699°C (1290°F)

3.2 MPa (460 psia)

3

Methanation 

Reactor 

Intercooler 1

Shell and 

Tube 2 0 462 GJ/hr (437 MMBtu/hr) 461 GJ/hr (437 MMBtu/hr)

4

Methanation 

Reactor 

Intercooler 2

Shell and 

Tube 2 0 125 GJ/hr (119 MMBtu/hr) 125 GJ/hr (119 MMBtu/hr)

5 Methanation 

Reactor 2

Fixed Bed, 

catalytic 2 0

140,160 kg/hr

(309,000 lb/hr)

554°C (1,030°F)

3.1 MPa (450 psia)

140,160 kg/hr

(309,000 lb/hr)

554°C (1,030°F)

3.1 MPa (450 psia)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

164

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition Case 4 Design Condition

6

Methanation 

Reactor 

Intercooler 3

Shell and 

Tube 2 0 33 GJ/hr (31 MMBtu/hr) 33 GJ/hr (31 MMBtu/hr)

7 Methanation 

Reactor 3

Fixed Bed, 

catalytic 2 0

140,160 kg/hr

(309,000 lb/hr)

343°C (650°F)

3.0 MPa (430 psia)

140,160 kg/hr

(309,000 lb/hr)

343°C (650°F)

3.0 MPa (430 psia)

8

Methanation 

Reactor 

Intercooler 4

Shell and 

Tube 2 0 45 GJ/hr (43 MMBtu/hr) 45 GJ/hr (43 MMBtu/hr)

9

Methanation 

Reactor 

Intercooler 5

Shell and 

Tube 2 0 73 GJ/hr (70 MMBtu/hr) 73 GJ/hr (69 MMBtu/hr)

10

SNG 

Purification 

Condenser 1

Shell and 

Tube 2 0 62 GJ/hr (59 MMBtu/hr) 62 GJ/hr (59 MMBtu/hr)

11

SNG 

Purification 

Condenser 2

Shell and 

Tube 2 0 37 GJ/hr (35 MMBtu/hr) 37 GJ/hr (35 MMBtu/hr)

12

Methanation 

Recycle 

Compressor

Centrifugal 2 1

9,781 m3/min 

(345,400 scfm)

Suction - 3.1 MPa 

(448 psia)

Discharge - 3.3 MPa 

(475 psia)

9,772 m3/min 

(345,100 scfm)

Suction - 3.1 MPa 

(448 psia)

Discharge - 3.3 MPa 

(475 psia)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

165

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition Case 4 Design Condition

13

Molecular 

Sieve 

Purification 

Reactor

Fixed bed 8 0

22,226 kg/hr (49,000 lb/hr)

129°C (265°F)

2.8 MPa (401 psia)

22,226 kg/hr (49,000 lb/hr)

129°C (265°F)

2.8 MPa (401 psia)

14 SNG Product 

Compressor

Centrifugal, 

Multistaged2 1

1,385 m3/min

(48,900 scfm)

2.6 MPa (381 psia)

6.2 MPa (900 psia)

1,382 m3/min

(48,800 scfm)

2.6 MPa (381 psia)

6.2 MPa (900 psia)

ACCOUNT 5A AMMONIA SYNTHESIS LOOP

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition Case 4 Design Condition

1

Ammonia 

Converter 

Preheater 1

Shell and 

Tube 1 0

511,199 kg/hr

(1,127,000 lb/hr)

76°C (169°F)

13.4 MPa (1,949 psia)

107 MMBtu/hr

511,652 kg/hr

(1,128,000 lb/hr)

76°C (169°F)

13.4 MPa (1,949 psia)

107 MMBtu/hr

2

Ammonia 

Converter 

Preheater 2

Shell and 

Tube 1 0

511,199 kg/hr

(1,127,000 lb/hr)

250°C (482°F)

13.4 MPa (1,949 psia)

278 MMBtu/hr

511,652 kg/hr

(1,128,000 lb/hr)

250°C (482°F)

13.4 MPa (1,949 psia)

278 MMBtu/hr

3

Ammonia 

Converter 

Preheater 3

Shell and 

Tube 1 0

511,199 kg/hr

(1,127,000 lb/hr)

382°C (720°F)

14.0 MPa (2,035 psia)

212 MMBtu/hr

511,652 kg/hr

(1,128,000 lb/hr)

382°C (720°F)

14.0 MPa (2,035 psia)

211 MMBtu/hr
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

166

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition Case 4 Design Condition

4

Ammonia 

Synthesis 

Loop 

Superheater

Shell and 

Tube 1 0

511,199 kg/hr

(1,127,000 lb/hr)

510°C (949°F)

13.5 MPa (1,955 psia)

154 MMBtu/hr

511,652 kg/hr

(1,128,000 lb/hr)

510°C (949°F)

13.5 MPa (1,955 psia)

153 MMBtu/hr

5

Ammonia 

Synthesis 

Loop BFW 

Heater

Shell and 

Tube 1 0

511,199 kg/hr

(1,127,000 lb/hr)

416°C (780°F)

13.5 MPa (1,955 psia)

54 MMBtu/hr

511,652 kg/hr

(1,128,000 lb/hr)

416°C (780°F)

13.5 MPa (1,955 psia)

54 MMBtu/hr

6 Ammonia 

Converter

Haldor 

Topsoe S300 Radial 

Flow

1 0

511,199 kg/hr

1,127,000 lb/hr)

510°C (949°F)

14.0 MPa (2,030 psia)

511,652 kg/hr

1,128,000 lb/hr)

510°C (949°F)

14.0 MPa (2,030 psia)

7 Refrigeratio

n System

AmmoniaBased 2 0 26,025 kW refrigeration 

(7,400 tons refrigeration)

26,025 kW refrigeration 

(7,400 tons refrigeration)

8

Primary 

Ammonia 

Separator

Refrigerated 1 0

602,824 kg/hr

(1,329,000 lb/hr)

-25°C (-13°F)

13.3 MPa (1,928 psia)

603,278 kg/hr

(1,330,000 lb/hr)

-25°C (-13°F)

13.3 MPa (1,928 psia)

9 Purge 

Separator Refrigerated 1 0

35,834 kg/hr (79,000 lb/hr)

-25°C (-13°F)

13.4 MPa (1,948 psia)

35,834 kg/hr (79,000 lb/hr)

-25°C (-13°F)

13.4 MPa (1,948 psia)

10

Ammonia 

System 

Feed 

Compressor

Centrifugal, 

MultiStaged1 1

5,573 m3/min

(196,800 scfm)

Suction - 3.24MPa 

(470 psia)

Discharge - 13.6 MPa 

(1,975 psia)

5,570 m3/min

(196,700 scfm)

Suction - 3.24MPa 

(470 psia)

Discharge - 13.6 MPa 

(1,975 psia)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

167

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition Case 4 Design Condition

11

Ammonia 

System 

Recycle 

Compressor

Centrifugal 1 1

22,999 m3/min

(812,200 scfm)

Suction - 13.0 MPa 

(1,892 psia)

Discharge - 14.0 MPa 

(2,035 psia)

22,990 m3/min

(811,900 scfm)

Suction - 13.0 MPa 

(1,892 psia)

Discharge - 14.0 MPa 

(2,035 psia)

12

Pressure 

Swing 

Absorption 

System

Fixed bed 1 0

8 MM SCMD

(280 MM SCFD)

21°C (69°F)

3.2 MPa (470 psia)

8 MM SCMD

(280 MM SCFD)

25°C (77°F)

3.2 MPa (470 psia)

13

Ammonia 

Storage 

Vessel

Cylindrical, 

Refrigerated 2 0

32,683 tonnes

(36,000 tons)

Stored at -23°C (-10°F)

0.1 MPa (15 psia)

32,683 tonnes

(36,000 tons)

Stored at -23°C (-10°F)

0.1 MPa (15 psia)

14 Waste Heat 

Boiler

Shop 

fabricated, 

water tube

1 0

149,685 kg/hr

(330,000 lb/hr)

1012°C (1,853°F)

0.1 MPa (20 psia)

149,685 kg/hr

(330,000 lb/hr)

1014°C (1,857°F)

0.1 MPa (20 psia)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

168

ACCOUNT 5B CO2 COMPRESSION

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition

Case 4 Design 

Condition

1 CO2

Compressor

Integrally geared, 

multi-stage 

centrifugal

4 0 N/A

1,739 m3/min @ 15.3 

MPa (61,400 scfm @ 

2,215 psia)

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition

Case 4 Design 

Condition

1 Combustion

Turbine N/A N/A N/A N/A N/A

2

Combustion

Turbine 

Generator

N/A N/A N/A N/A N/A

ACCOUNT 7 DUCTING & STACK

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition

Case 4 Design 

Condition

1 Stack

CS plate, 

type 409SS 

liner

1 0 76 m (250 ft) high x 3.0 

m (10 ft) diameter

76 m (250 ft) high x 2.4 

m (8 ft) diameter
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

169

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition

Case 4 Design 

Condition

1 Steam 

Turbine

Commercially 

available 1 0

308 MW 12.4 

MPa/566°C (1800 psig/ 

1050°F)

308 MW 12.4 

MPa/566°C (1800 psig/ 

1050°F)

2

Steam 

Turbine 

Generator

Hydrogen 

cooled, static 

excitation

1 0 340 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase

340 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase

3 Surface 

Condenser

Single pass, 

divided 

waterbox 

including 

vacuum pumps

1 0

1,952 GJ/hr 

(1,850 MMBtu/hr), 

Inlet water temperature 

16°C (60°F), 

Water temperature rise 

11°C (20°F)

1,952 GJ/hr 

(1,850 MMBtu/hr), 

Condensing temperature 

16°C (60°F), Ambient 

temperature 11°C (20°F)

4 Air-cooled 

Condenser --- N/A N/A N/A N/A

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition

Case 4 Design 

Condition

1 Circulating 

Water Pumps

Vertical, wet 

pit 2 1 620,808 lpm @ 30 m

(164,000 gpm @ 100 ft)

624,593 lpm @ 30 m

(165,000 gpm @ 100 ft)

2 Cooling 

Tower

Evaporative, 

mechanical 

draft, multicell

1 0

11°C (51.5°F) wet bulb / 

16°C (60°F) CWT / 

27°C (80°F) HWT /

3,461 GJ/hr (3,280 

MMBtu/hr) heat duty

11°C (51.5°F) wet bulb / 

16°C (60°F) CWT / 

27°C (80°F) HWT / 

3,482 GJ/hr (3,300 

MMBtu/hr) heat duty
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition Case 4 Design Condition

1

Slag 

Quench 

Tank

Water bath 6 0 151,416 liters (40,000 gal) 151,416 liters (40,000 gal)

2 Slag 

Crusher Roll 6 0 8 tonne/hr (9 tph) 8 tonne/hr (9 tph)

3

Slag 

Depressuriz

er

Proprietary 6 0 8 tonne/hr (9 tph) 8 tonne/hr (9 tph)

4

Slag 

Receiving 

Tank

Horizontal, 

weir 6 0 90,850 liters (24,000 gal) 90,850 liters (24,000 gal)

5

Black Water 

Overflow 

Tank

Shop 

fabricated 6 0 41,640 liters (11,000 gal) 41,640 liters (11,000 gal)

6 Slag 

Conveyor Drag chain 6 0 8 tonne/hr (9 tph) 8 tonne/hr (9 tph)

7

Slag 

Separation 

Screen

Vibrating 6 0 8 tonne/hr (9 tph) 8 tonne/hr (9 tph)

8 Coarse Slag 

Conveyor Belt/bucket 6 0 8 tonne/hr (9 tph) 8 tonne/hr (9 tph)

9

Fine Ash 

Settling 

Tank

Vertical, 

gravity 6 0 132,489 liters (35,000 gal) 132,489 liters (35,000 gal)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

171

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition Case 4 Design Condition

10

Fine Ash 

Recycle 

Pumps

Horizontal 

centrifugal 6 3 38 lpm @ 14 m H2O(10 gpm @ 46 ft H2O)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

11

Grey Water 

Storage 

Tank

Field 

erected 6 0 41,640 liters (11,000 gal) 41,640 liters (11,000 gal)

12 Grey Water 

Pumps Centrifugal 6 3 151 lpm @ 433 m H2O

(40 gpm @ 1,420 ft H2O)

151 lpm @ 433 m H2O

(40 gpm @ 1,420 ft H2O)

13 Slag Storage 

Bin

Vertical, 

field erected 6 0 544 tonne (600 tons) 544 tonne (600 tons)

14 Unloading 

Equipment

Telescoping 

chute 2 0 100 tonne/hr (110 tph) 100 tonne/hr (110 tph)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

172

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition

Case 4 Design 

Condition

1 STG Step-up 

Transformer Oil-filled 1 0 24 kV/345 kV, 340 MVA, 3-ph, 60 Hz

24 kV/345 kV, 340 

MVA, 3-ph, 60 Hz

2 Auxiliary 

Transformer Oil-filled 1 1 24 kV/4.16 kV, 291 MVA, 3-ph, 60 Hz

24 kV/4.16 kV, 349 

MVA, 3-ph, 60 Hz

3 Low Voltage 

Transformer

Dry 

ventilated 1 1 4.16 kV/480 V, 44 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 52 

MVA, 3-ph, 60 Hz

4

STG Isolated 

Phase Bus 

Duct and Tap 

Bus

Aluminum, 

self-cooled 1 0 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz

5

Medium 

Voltage 

Switchgear

Metal clad 1 1 24 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz

6 Low Voltage 

Switchgear

Metal 

enclosed 1 1 4.16 kV, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz

7

Emergency 

Diesel 

Generator

Sized for 

emergency 

shutdown

1 0 750 kW, 480 V, 3-ph, 60 

Hz

750 kW, 480 V, 3-ph, 60 

Hz
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment 

No. Description Type Operating Qty. Spares Case 3 Design Condition

Case 4 Design 

Condition

1 DCS - Main 

Control

Monitor/keyboard; 

Operator printer 

(laser color); 

Engineering printer 

(laser B&W)

1 0

Operator 

stations/printers and 

engineering 

stations/printers

Operator 

stations/printers and 

engineering 

stations/printers

2 DCS -

Processor

Microprocessor 

with redundant 

input/output

1 0 N/A N/A

3 DCS - Data 

Highway Fiber optic 1 0 Fully redundant, 25% spare

Fully redundant, 25% 

spare
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

174

4.2.5

The cost estimating methodology was described previously in Section 

Cases 3 and 4 Cost Estimating

2.8.

The TPC organized by cost account, owner’s costs, TOC, and initial and annual O&M costs for 

the SNG and ammonia co-production plant without sequestration using Illinois No. 6 coal (Case 

3) are shown in Exhibit 4-42 and Exhibit 4-43, respectively. The same data for the SNG and 

ammonia co-production plant with sequestration using Illinois No. 6 coal (Case 4) are shown in 

Exhibit 4-44 and Exhibit 4-45.

The estimated TOC of the co-production plant without carbon sequestration is 3.74 billion 

dollars and with carbon sequestration is 3.83 billion dollars. Project and process contingencies 

represent 11.7 and 3.3 percent for both the non-sequestration and sequestration cases. The 

FYCOP for SNG is $15.82/MMBtu for the non-sequestration case and $17.85/MMBtu for the 

sequestration case, with a consequential selling price of ammonia of $799/ton and $828/ton for 

the non-sequestration and sequestration cases respectively, as shown in Exhibit ES-6.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

175

Exhibit 4-42 Case 3 Total Plant Cost Details

Client: USDOE/NETL Report Date: 2010-Feb-18

Project: Cost & Performance Baseline for Fossil Energy Plants Vol.2

Case: Case 3 - Siemens Quench SNG & Ammonia Production w/o CO2

Plant Size: 28.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $5,727 $0 $2,798 $0 $0 $8,525 $764 $0 $1,858 $11,146

1.2 Coal Stackout & Reclaim $7,400 $0 $1,794 $0 $0 $9,194 $806 $0 $2,000 $12,000

1.3 Coal Conveyors & Yd Crush $6,880 $0 $1,775 $0 $0 $8,655 $760 $0 $1,883 $11,298

1.4 Other Coal Handling $1,800 $0 $411 $0 $0 $2,211 $193 $0 $481 $2,885

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $4,052 $10,133 $0 $0 $14,185 $1,360 $0 $3,109 $18,653

SUBTOTAL 1. $21,806 $4,052 $16,911 $0 $0 $42,769 $3,882 $0 $9,330 $55,982

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $92,894 $0 $13,536 $0 $0 $106,430 $9,666 $0 $23,219 $139,315

2.2 Prepared Coal Storage & Feed $4,400 $1,053 $690 $0 $0 $6,143 $525 $0 $1,334 $8,002

2.3 Dry Coal Injection System $144,803 $1,681 $13,448 $0 $0 $159,932 $13,775 $0 $34,741 $208,448

2.4 Misc.Coal Prep & Feed $2,420 $1,761 $5,279 $0 $0 $9,459 $869 $0 $2,066 $12,394

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $9,405 $7,721 $0 $0 $17,126 $1,586 $0 $3,742 $22,454

SUBTOTAL 2. $244,517 $13,899 $40,674 $0 $0 $299,090 $26,421 $0 $65,102 $390,613

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $3,508 $1,630 $1,977 $0 $0 $7,115 $643 $0 $1,552 $9,310

3.2 Water Makeup & Pretreating $854 $89 $477 $0 $0 $1,421 $135 $0 $467 $2,023

3.3 Other Feedwater Subsystems $3,808 $1,151 $1,884 $0 $0 $6,843 $621 $0 $1,493 $8,958

3.4 Service Water Systems $489 $1,006 $3,493 $0 $0 $4,988 $487 $0 $1,643 $7,118

3.5 Other Boiler Plant Systems $2,623 $1,016 $2,519 $0 $0 $6,158 $584 $0 $1,348 $8,091

3.6 FO Supply Sys & Nat Gas $102 $210 $188 $0 $0 $500 $48 $0 $110 $658

3.7 Waste Treatment Equipment $1,194 $0 $728 $0 $0 $1,922 $187 $0 $633 $2,742

3.8 Misc. Power Plant Equipment $1,721 $230 $883 $0 $0 $2,834 $274 $0 $932 $4,040

SUBTOTAL 3. $14,298 $5,334 $12,150 $0 $0 $31,782 $2,980 $0 $8,177 $42,939

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $326,034 $0 $150,944 $0 $0 $476,977 $42,364 $71,547 $88,633 $679,521

4.2 Syngas Cooling w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $250,140 $0 w/equip. $0 $0 $250,140 $24,246 $0 $27,439 $301,825

4.4 LT Heat Recovery & FG Saturation $55,465 $0 $20,551 $0 $0 $76,016 $7,282 $0 $16,660 $99,958

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $2,332 $949 $0 $0 $3,282 $315 $0 $719 $4,315

4.7 CO2 Solid Feed System Compressors $10,514 $2,523 $3,785 $0 $0 $16,822 $1,682 $0 $3,701 $22,205

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $21,135 $12,059 $0 $0 $33,194 $3,039 $0 $9,058 $45,291

SUBTOTAL 4. $642,153 $25,990 $188,288 $0 $0 $856,431 $78,928 $71,547 $146,210 $1,153,115

TOTAL PLANT COST SUMMARY 

Contingencies
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

176

Exhibit 4-42 Case 3 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $128,808 $0 $109,297 $0 $0 $238,105 $23,027 $47,621 $61,751 $370,504

5A.2 Elemental Sulfur Plant $16,279 $3,245 $21,003 $0 $0 $40,527 $3,937 $0 $8,893 $53,357

5A.3 Mercury Removal $2,499 $0 $1,902 $0 $0 $4,401 $425 $220 $1,009 $6,056

5A.4a Shift Reactors $11,793 $0 $4,747 $0 $0 $16,540 $1,586 $0 $3,625 $21,751

5A.4b COS Hydrolysis $1,494 $0 $1,951 $0 $0 $3,445 $335 $0 $756 $4,536

5A.5 Methanation $21,900 $8,760 $13,140 $0 $0 $43,800 $4,380 $4,380 $10,512 $63,072

5A.6 SNG Purification & Compression $17,050 $6,820 $10,230 $0 $0 $34,100 $3,410 $0 $7,502 $45,012

5A.7 Fuel Gas Piping $0 $1,749 $1,225 $0 $0 $2,974 $276 $0 $650 $3,900

5A.8 Ammonia Production $171,774 $44,276 $88,551 $0 $0 $304,601 $30,460 $0 $50,259 $385,320

5A.9 Process Interconnects $0 $18,400 $27,600 $0 $0 $46,000 $4,600 $0 $10,120 $60,720

5A.10 HGCU Foundations $0 $1,771 $1,142 $0 $0 $2,913 $268 $0 $954 $4,135

5A.11 Zinc Oxide Guard Bed $664 $0 $122 $0 $0 $786 $79 $0 $173 $1,038

SUBTOTAL 5A. $372,262 $85,021 $280,911 $0 $0 $738,194 $72,782 $52,221 $156,204 $1,019,401

 5B CO2 COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.2 Syngas Expander $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $503 $359 $0 $0 $863 $76 $0 $188 $1,126

7.4 Stack $1,814 $0 $682 $0 $0 $2,496 $239 $0 $274 $3,009

7.9 HRSG,Duct & Stack Foundations $0 $364 $349 $0 $0 $713 $66 $0 $234 $1,013

SUBTOTAL 7. $1,814 $867 $1,390 $0 $0 $4,071 $381 $0 $695 $5,147

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $30,291 $0 $5,224 $0 $0 $35,514 $3,408 $0 $3,892 $42,814

8.2 Turbine Plant Auxiliaries $163 $0 $482 $0 $0 $645 $63 $0 $71 $780

8.3 Condenser & Auxiliaries $5,594 $0 $1,578 $0 $0 $7,172 $685 $0 $786 $8,643

8.4 Steam Piping $5,482 $0 $3,856 $0 $0 $9,338 $802 $0 $2,535 $12,675

8.9 TG Foundations $0 $1,043 $1,764 $0 $0 $2,807 $266 $0 $922 $3,995

SUBTOTAL 8. $41,530 $1,043 $12,905 $0 $0 $55,477 $5,225 $0 $8,206 $68,908

Contingencies
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

177

Exhibit 4-42 Case 3 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $8,777 $0 $1,597 $0 $0 $10,373 $988 $0 $1,704 $13,065

9.2 Circulating Water Pumps $2,333 $0 $85 $0 $0 $2,417 $203 $0 $393 $3,013

9.3 Circ.Water System Auxiliaries $185 $0 $26 $0 $0 $212 $20 $0 $35 $267

9.4 Circ.Water Piping $0 $7,740 $2,007 $0 $0 $9,747 $881 $0 $2,125 $12,753

9.5 Make-up Water System $450 $0 $643 $0 $0 $1,093 $105 $0 $239 $1,437

9.6 Component Cooling Water Sys $914 $1,093 $778 $0 $0 $2,784 $261 $0 $609 $3,654

9.9 Circ.Water System Foundations $0 $2,834 $4,818 $0 $0 $7,652 $725 $0 $2,513 $10,891

SUBTOTAL 9. $12,658 $11,667 $9,953 $0 $0 $34,278 $3,183 $0 $7,619 $45,080

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $36,250 $0 $35,754 $0 $0 $72,004 $6,977 $0 $7,898 $86,879

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $817 $0 $889 $0 $0 $1,707 $166 $0 $281 $2,153

10.7 Ash Transport & Feed Equipment $1,096 $0 $265 $0 $0 $1,361 $127 $0 $223 $1,711

10.8 Misc. Ash Handling Equipment $1,693 $2,075 $620 $0 $0 $4,388 $418 $0 $721 $5,526

10.9 Ash/Spent Sorbent Foundation $0 $72 $91 $0 $0 $163 $15 $0 $54 $232

SUBTOTAL 10. $39,857 $2,147 $37,618 $0 $0 $79,623 $7,702 $0 $9,177 $96,502

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $420 $0 $416 $0 $0 $836 $80 $0 $92 $1,007

11.2 Station Service Equipment $5,754 $0 $519 $0 $0 $6,272 $578 $0 $685 $7,536

11.3 Switchgear & Motor Control $10,637 $0 $1,935 $0 $0 $12,572 $1,166 $0 $2,061 $15,799

11.4 Conduit & Cable Tray $0 $4,941 $16,302 $0 $0 $21,243 $2,055 $0 $5,824 $29,122

11.5 Wire & Cable $0 $9,441 $6,203 $0 $0 $15,645 $1,137 $0 $4,195 $20,977

11.6 Protective Equipment $0 $855 $3,111 $0 $0 $3,965 $387 $0 $653 $5,005

11.7 Standby Equipment $330 $0 $322 $0 $0 $651 $62 $0 $107 $821

11.8 Main Power Transformers $9,274 $0 $182 $0 $0 $9,456 $718 $0 $1,526 $11,700

11.9 Electrical Foundations $0 $197 $518 $0 $0 $716 $68 $0 $235 $1,019

SUBTOTAL 11. $26,415 $15,435 $29,506 $0 $0 $71,356 $6,251 $0 $15,378 $92,985

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $536 $0 $358 $0 $0 $893 $85 $45 $153 $1,176

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $356 $0 $228 $0 $0 $584 $55 $29 $134 $802

12.7 Computer & Accessories $5,694 $0 $182 $0 $0 $5,876 $539 $294 $671 $7,380

12.8 Instrument Wiring & Tubing $0 $2,884 $5,896 $0 $0 $8,780 $745 $439 $2,491 $12,454

12.9 Other I & C Equipment $4,245 $0 $2,061 $0 $0 $6,306 $593 $315 $1,082 $8,297

SUBTOTAL 12. $10,830 $2,884 $8,725 $0 $0 $22,439 $2,017 $1,122 $4,531 $30,110

Contingencies
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

178

Exhibit 4-42 Case 3 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $147 $3,142 $0 $0 $3,289 $326 $0 $1,085 $4,700

13.2 Site Improvements $0 $2,614 $3,474 $0 $0 $6,089 $601 $0 $2,007 $8,696

13.3 Site Facilities $4,685 $0 $4,944 $0 $0 $9,629 $949 $0 $3,173 $13,751

SUBTOTAL 13. $4,685 $2,761 $11,560 $0 $0 $19,006 $1,877 $0 $6,265 $27,148

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

14.2 Steam Turbine Building $0 $2,530 $3,604 $0 $0 $6,134 $564 $0 $1,005 $7,703

14.3 Administration Building $0 $870 $630 $0 $0 $1,500 $134 $0 $245 $1,879

14.4 Circulation Water Pumphouse $0 $160 $90 $0 $0 $250 $22 $0 $41 $312

14.5 Water Treatment Buildings $0 $785 $766 $0 $0 $1,552 $140 $0 $254 $1,945

14.6 Machine Shop $0 $445 $305 $0 $0 $750 $67 $0 $123 $939

14.7 Warehouse $0 $762 $487 $0 $0 $1,249 $111 $0 $204 $1,564

14.8 Other Buildings & Structures $0 $528 $411 $0 $0 $940 $84 $0 $205 $1,228

14.9 Waste Treating Building & Str. $0 $1,299 $2,483 $0 $0 $3,782 $353 $0 $827 $4,961

SUBTOTAL 14. $0 $7,379 $8,777 $0 $0 $16,156 $1,474 $0 $2,902 $20,532

TOTAL COST $1,432,827 $178,481 $659,367 $0 $0 $2,270,675 $213,101 $124,890 $439,797 $3,048,463

Owner's Costs

Preproduction Costs

6 Months All Labor $23,796

1 Month Maintenance Materials $4,247

1 Month Non-fuel Consumables $819

1 Month Waste Disposal $577

25% of 1 Months Fuel Cost at 100% CF $3,359

2% of TPC $60,969

Total $93,767

Inventory Capital

60 day supply of fuel and consumables at 100% CF $28,158

0.5% of TPC (spare parts) $15,242

Total $43,400

Initial Cost for Catalyst and Chemicals $16,303

Land $900

Other Owner's Costs $457,269

Financing Costs $82,309

Total Overnight Costs (TOC) $3,742,411

TASC Multiplier 1.201

Total As-Spent Cost (TASC) $4,494,636

Contingencies
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

179

Exhibit 4-43 Case 3 Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 3 - Siemens Quench SNG & Ammonia Production w/o CO2 MWe-net: 29

SNG (MMbtu/hr): 5,126 mmonia (lb/hr): 183,698 Capacity Factor (%): 90

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate (base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 Skilled Operator 2.0 2.0

 Operator 13.0 13.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 3.0 3.0

 TOTAL-O.J.'s 19.0 19.0

Annual Cost

$

Annual Operating Labor Cost $7,497,290

Maintenance Labor Cost $30,575,935

Administrative & Support Labor $9,518,306

Property Taxes and Insurance $60,969,265

TOTAL FIXED OPERATING COSTS $108,560,796

VARIABLE OPERATING COSTS

Maintenance Material Cost $45,863,903

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water(/1000 gallons) 0 5,352 1.08 $0 $1,901,899

Chemicals

MU & WT Chem. (lb) 0 31,889 0.17 $0 $1,812,954

Carbon (Mercury Removal) (lb) 234,445 401 1.05 $246,207 $138,492

COS Catalyst (m3) 88 0.1 2,397.36 $210,486 $59,199

Water Gas Shift Catalyst (ft3) 8,501 7.5 498.83 $4,240,751 $1,222,008

ZnO Sorbent (ton) 113 0.4 12,574.00 $1,419,605 $1,597,055

Methanation Catalyst (ft3) 9,191 6.99 440.00 $4,044,122 $1,011,030

Selexol Solution (gal) 449,546 143 13.40 $6,023,125 $630,285

SCR Catalyst (m3) 0 0 0.00 $0 $0

Aqueous Ammonia (ton) 0 0 0.00 $0 $0

Ammonia Catalyst (ft3) 69.74 0.6 1,701.00 $118,628 $314,201

Claus Catalyst (ft3) w/equip 3.75 131.27 $0 $161,850

Subtotal Chemicals $16,302,923 $6,947,076

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0

Supplemental Electricity (for consumption) (MWh) 0 0 61.60 $0 $0

Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0

Subtotal Other $0 $0

Waste Disposal

Spent Mercury Catalyst (lb.) 0 401 0.42 $0 $55,002

Spent ZnO Sorbent (ton) 0 0.39 16.23 $0 $2,061

Flyash (ton) 0 0 0.00 $0 $0

Slag (ton) 0 1,159 16.23 $0 $6,175,272

 Subtotal-Waste Disposal $0 $6,232,335

By-products & Emissions 

Sulfur (tons) 0 288 0.00 $0 $0

Supplemental Electricity (for sale) (MWh) 0 689 58.00 $0 -$13,123,706

Subtotal By-Products $0 -$13,123,706

TOTAL VARIABLE OPERATING COSTS $16,302,923 $47,821,506

Fuel (ton) 0 11,568 38.18 $0 $145,104,505
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

180

Exhibit 4-44 Case 4 Total Plant Cost Details

Client: USDOE/NETL Report Date: 2010-Feb-18

Project: Cost & Performance Baseline for Fossil Energy Plants Vol.2

Case: Case 4 - Siemens Quench SNG & Ammonia Production w/ CO2

Plant Size: -23.73 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $5,727 $0 $2,798 $0 $0 $8,525 $764 $0 $1,858 $11,146

1.2 Coal Stackout & Reclaim $7,400 $0 $1,794 $0 $0 $9,194 $806 $0 $2,000 $12,000

1.3 Coal Conveyors & Yd Crush $6,880 $0 $1,775 $0 $0 $8,655 $760 $0 $1,883 $11,298

1.4 Other Coal Handling $1,800 $0 $411 $0 $0 $2,211 $193 $0 $481 $2,885

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $4,052 $10,133 $0 $0 $14,185 $1,360 $0 $3,109 $18,653

SUBTOTAL 1. $21,806 $4,052 $16,911 $0 $0 $42,769 $3,882 $0 $9,330 $55,982

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $92,894 $0 $13,536 $0 $0 $106,430 $9,666 $0 $23,219 $139,315

2.2 Prepared Coal Storage & Feed $4,400 $1,053 $690 $0 $0 $6,143 $525 $0 $1,334 $8,002

2.3 Dry Coal Injection System $144,803 $1,681 $13,448 $0 $0 $159,932 $13,775 $0 $34,741 $208,448

2.4 Misc.Coal Prep & Feed $2,420 $1,761 $5,279 $0 $0 $9,459 $869 $0 $2,066 $12,394

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $9,405 $7,721 $0 $0 $17,126 $1,586 $0 $3,742 $22,454

SUBTOTAL 2. $244,517 $13,899 $40,674 $0 $0 $299,090 $26,421 $0 $65,102 $390,613

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $3,504 $1,629 $1,975 $0 $0 $7,109 $642 $0 $1,550 $9,301

3.2 Water Makeup & Pretreating $856 $89 $478 $0 $0 $1,424 $136 $0 $468 $2,028

3.3 Other Feedwater Subsystems $3,805 $1,150 $1,882 $0 $0 $6,837 $621 $0 $1,492 $8,949

3.4 Service Water Systems $490 $1,009 $3,501 $0 $0 $5,000 $488 $0 $1,646 $7,134

3.5 Other Boiler Plant Systems $2,629 $1,019 $2,525 $0 $0 $6,172 $585 $0 $1,352 $8,109

3.6 FO Supply Sys & Nat Gas $102 $210 $188 $0 $0 $500 $48 $0 $110 $658

3.7 Waste Treatment Equipment $1,197 $0 $730 $0 $0 $1,927 $188 $0 $634 $2,749

3.8 Misc. Power Plant Equipment $1,721 $230 $883 $0 $0 $2,834 $274 $0 $932 $4,040

SUBTOTAL 3. $14,303 $5,336 $12,163 $0 $0 $31,803 $2,982 $0 $8,184 $42,968

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $326,007 $0 $150,932 $0 $0 $476,939 $42,361 $71,541 $88,626 $679,467

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $250,140 $0 w/equip. $0 $0 $250,140 $24,246 $0 $27,439 $301,825

4.4 LT Heat Recovery & FG Saturation $55,463 $0 $20,550 $0 $0 $76,013 $7,281 $0 $16,659 $99,953

4.5 Misc. Gasification Equipment w/4.1 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $2,332 $949 $0 $0 $3,280 $315 $0 $719 $4,314

4.7 CO2 Solid Feed System Compressors $6,692 $1,606 $2,409 $0 $0 $10,707 $1,071 $0 $2,356 $14,134

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $21,135 $12,059 $0 $0 $33,194 $3,039 $0 $9,058 $45,291

SUBTOTAL 4. $638,302 $25,072 $186,899 $0 $0 $850,274 $78,312 $71,541 $144,856 $1,144,983

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

181

Exhibit 4-44 Case 4 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $128,808 $0 $109,297 $0 $0 $238,105 $23,027 $47,621 $61,751 $370,504

5A.2 Elemental Sulfur Plant $16,281 $3,245 $21,005 $0 $0 $40,531 $3,937 $0 $8,894 $53,361

5A.3 Mercury Removal $2,499 $0 $1,901 $0 $0 $4,400 $425 $220 $1,009 $6,054

5A.4a Shift Reactors $11,791 $0 $4,746 $0 $0 $16,537 $1,585 $0 $3,625 $21,747

5A.4b COS Hydrolysis $1,493 $0 $1,950 $0 $0 $3,443 $335 $0 $756 $4,533

5A.5 Methanation $21,900 $8,760 $13,140 $0 $0 $43,800 $4,380 $4,380 $10,512 $63,072

5A.6 SNG Purification & Compression $17,050 $6,820 $10,230 $0 $0 $34,100 $3,410 $0 $7,502 $45,012

5A.7 Fuel Gas Piping $0 $1,749 $1,224 $0 $0 $2,973 $276 $0 $650 $3,898

5A.8 Ammonia Production $171,733 $44,261 $88,523 $0 $0 $304,517 $30,452 $0 $50,245 $385,214

5A.9 Process Interconnects $0 $18,400 $27,600 $0 $0 $46,000 $4,600 $0 $10,120 $60,720

5A.10 HGCU Foundations $0 $1,771 $1,142 $0 $0 $2,912 $268 $0 $954 $4,134

5A.11 Zinc Oxide Guard Bed $664 $0 $122 $0 $0 $786 $79 $0 $173 $1,038

SUBTOTAL 5A. $372,219 $85,005 $280,881 $0 $0 $738,105 $72,773 $52,221 $156,189 $1,019,288

 5B CO2 COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $38,073 $0 $22,420 $0 $0 $60,493 $5,824 $0 $13,263 $79,581

SUBTOTAL 5B. $38,073 $0 $22,420 $0 $0 $60,493 $5,824 $0 $13,263 $79,581

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.2 Syngas Expander $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.9 HRSG,Duct & Stack Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 7. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $30,291 $0 $5,224 $0 $0 $35,514 $3,408 $0 $3,892 $42,814

8.2 Turbine Plant Auxiliaries $163 $0 $482 $0 $0 $645 $63 $0 $71 $779

8.3 Condenser & Auxiliaries $5,594 $0 $1,580 $0 $0 $7,174 $685 $0 $786 $8,645

8.4 Steam Piping $5,477 $0 $3,853 $0 $0 $9,329 $801 $0 $2,533 $12,663

8.9 TG Foundations $0 $1,043 $1,764 $0 $0 $2,807 $266 $0 $922 $3,995

SUBTOTAL 8. $41,524 $1,043 $12,902 $0 $0 $55,470 $5,224 $0 $8,204 $68,897
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

182

Exhibit 4-44 Case 4 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $7,345 $0 $1,603 $0 $0 $8,949 $853 $0 $1,470 $11,272

9.2 Circulating Water Pumps $2,343 $0 $85 $0 $0 $2,427 $204 $0 $395 $3,026

9.3 Circ.Water System Auxiliaries $186 $0 $27 $0 $0 $213 $20 $0 $35 $268

9.4 Circ.Water Piping $0 $7,768 $2,014 $0 $0 $9,782 $884 $0 $2,133 $12,800

9.5 Make-up Water System $451 $0 $644 $0 $0 $1,095 $105 $0 $240 $1,440

9.6 Component Cooling Water Sys $917 $1,097 $780 $0 $0 $2,794 $262 $0 $611 $3,667

9.9 Circ.Water System Foundations $0 $2,845 $4,836 $0 $0 $7,680 $728 $0 $2,523 $10,931

SUBTOTAL 9. $11,242 $11,710 $9,989 $0 $0 $32,940 $3,056 $0 $7,407 $43,403

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $36,250 $0 $35,754 $0 $0 $72,004 $6,977 $0 $7,898 $86,879

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $817 $0 $889 $0 $0 $1,707 $166 $0 $281 $2,153

10.7 Ash Transport & Feed Equipment $1,096 $0 $265 $0 $0 $1,361 $127 $0 $223 $1,711

10.8 Misc. Ash Handling Equipment $1,693 $2,075 $620 $0 $0 $4,388 $418 $0 $721 $5,526

10.9 Ash/Spent Sorbent Foundation $0 $72 $91 $0 $0 $163 $15 $0 $54 $232

SUBTOTAL 10. $39,857 $2,147 $37,618 $0 $0 $79,623 $7,702 $0 $9,177 $96,502

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $420 $0 $416 $0 $0 $836 $80 $0 $92 $1,007

11.2 Station Service Equipment $6,219 $0 $560 $0 $0 $6,780 $625 $0 $740 $8,145

11.3 Switchgear & Motor Control $11,498 $0 $2,091 $0 $0 $13,589 $1,260 $0 $2,227 $17,076

11.4 Conduit & Cable Tray $0 $5,341 $17,620 $0 $0 $22,961 $2,221 $0 $6,295 $31,477

11.5 Wire & Cable $0 $10,205 $6,705 $0 $0 $16,910 $1,228 $0 $4,535 $22,673

11.6 Protective Equipment $0 $855 $3,111 $0 $0 $3,965 $387 $0 $653 $5,005

11.7 Standby Equipment $330 $0 $322 $0 $0 $651 $62 $0 $107 $821

11.8 Main Power Transformers $9,977 $0 $182 $0 $0 $10,159 $771 $0 $1,639 $12,569

11.9 Electrical Foundations $0 $197 $518 $0 $0 $716 $68 $0 $235 $1,019

SUBTOTAL 11. $28,443 $16,598 $31,524 $0 $0 $76,565 $6,703 $0 $16,524 $99,792

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $532 $0 $355 $0 $0 $888 $84 $44 $152 $1,169

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $353 $0 $227 $0 $0 $580 $55 $29 $133 $797

12.7 Computer & Accessories $5,657 $0 $181 $0 $0 $5,838 $536 $292 $667 $7,333

12.8 Instrument Wiring & Tubing $0 $2,866 $5,858 $0 $0 $8,724 $740 $436 $2,475 $12,375

12.9 Other I & C Equipment $4,218 $0 $2,048 $0 $0 $6,266 $590 $313 $1,075 $8,244

SUBTOTAL 12. $10,761 $2,866 $8,669 $0 $0 $22,296 $2,004 $1,115 $4,502 $29,917
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

183

Exhibit 4-44 Case 4 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $147 $3,142 $0 $0 $3,289 $326 $0 $1,085 $4,700

13.2 Site Improvements $0 $2,614 $3,474 $0 $0 $6,089 $601 $0 $2,007 $8,696

13.3 Site Facilities $4,685 $0 $4,944 $0 $0 $9,629 $949 $0 $3,173 $13,751

SUBTOTAL 13. $4,685 $2,761 $11,560 $0 $0 $19,006 $1,877 $0 $6,265 $27,148

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

14.2 Steam Turbine Building $0 $2,530 $3,604 $0 $0 $6,134 $564 $0 $1,005 $7,703

14.3 Administration Building $0 $870 $630 $0 $0 $1,500 $134 $0 $245 $1,879

14.4 Circulation Water Pumphouse $0 $160 $90 $0 $0 $250 $22 $0 $41 $312

14.5 Water Treatment Buildings $0 $787 $768 $0 $0 $1,555 $140 $0 $254 $1,950

14.6 Machine Shop $0 $445 $305 $0 $0 $750 $67 $0 $123 $939

14.7 Warehouse $0 $762 $487 $0 $0 $1,249 $111 $0 $204 $1,564

14.8 Other Buildings & Structures $0 $528 $411 $0 $0 $940 $84 $0 $205 $1,228

14.9 Waste Treating Building & Str. $0 $1,299 $2,483 $0 $0 $3,782 $353 $0 $827 $4,961

SUBTOTAL 14. $0 $7,381 $8,778 $0 $0 $16,159 $1,474 $0 $2,903 $20,536

TOTAL COST $1,465,733 $177,872 $680,989 $0 $0 $2,324,594 $218,235 $124,877 $451,906 $3,119,611

Owner's Costs

Preproduction Costs

6 Months All Labor $24,443

1 Month Maintenance Materials $4,391

1 Month Non-fuel Consumables $1,890

1 Month Waste Disposal $577

25% of 1 Months Fuel Cost at 100% CF $3,359

2% of TPC $62,392

Total $97,052

Inventory Capital

60 day supply of fuel and consumables at 100% CF $28,163

0.5% of TPC (spare parts) $15,598

Total $43,761

Initial Cost for Catalyst and Chemicals $16,321

Land $900

Other Owner's Costs $467,942

Financing Costs $84,230

Total Overnight Costs (TOC) $3,829,817

TASC Multiplier 1.201

Total As-Spent Cost (TASC) $4,599,610
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

184

Exhibit 4-45 Case 4 Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 4 - Siemens Quench SNG & Ammonia Production w/ CO2 MWe-net: -24

SNG (MMbtu/hr): 5,122 mmonia (lb/hr): 183,634 Capacity Factor (%): 90

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate (base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 Skilled Operator 2.0 2.0

 Operator 13.0 13.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 3.0 3.0

 TOTAL-O.J.'s 19.0 19.0

Annual Cost

$

Annual Operating Labor Cost $7,497,290

Maintenance Labor Cost $31,612,112

Administrative & Support Labor $9,777,351

Property Taxes and Insurance $62,392,230

TOTAL FIXED OPERATING COSTS $111,278,983

VARIABLE OPERATING COSTS

Maintenance Material Cost $47,418,169

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water(/1000 gallons) 0 5,370 1.08 $0 $1,908,039

Chemicals

MU & WT Chem.(lb) 0 31,991 0.17 $0 $1,818,807

Carbon (Mercury Removal) (lb) 234,364 401 1.05 $246,122 $138,444

COS Catalyst (m3) 88 0.1 2,397.36 $210,355 $59,162

Water Gas Shift Catalyst (ft3) 8,499 7.5 498.83 $4,239,732 $1,221,706

ZnO Sorbent (ton) 115 0.4 12,574.00 $1,442,149 $1,622,417

Methanation Catalyst (ft3) 9,183 6.99 440.00 $4,040,718 $1,010,180

Selexol Solution (gal) 449,563 143 13.40 $6,023,353 $630,308

SCR Catalyst (m3) 0 0 0.00 $0 $0

Aqueous Ammonia (ton) 0 0 0.00 $0 $0

Ammonia Catalyst (ft3) 69.74 0.6 1,701.00 $118,628 $314,201

Claus Catalyst (ft3) w/equip 3.75 131.27 $0 $161,869

Subtotal Chemicals $16,321,057 $6,977,094

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0

Supplemental Electricity (for consumption) (MW 0 570 61.60 $0 $11,524,579

Gases, N2 etc.(/100scf) 0 0 0.00 $0 $0

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0

Subtotal Other $0 $11,524,579

Waste Disposal

Spent Mercury Catalyst (lb.) 0 401 0.42 $0 $54,983

Spent ZnO Sorbent (ton) 0 0.39 16.23 $0 $2,094

Flyash (ton) 0 0 0.00 $0 $0

Slag (ton) 0 1,159 16.23 $0 $6,175,271

 Subtotal-Waste Disposal $0 $6,232,347

By-products & Emissions 

Sulfur (tons) 0 288 0.00 $0 $0

Supplemental Electricity (for sale) (MWh) 0 0 58.00 $0 $0

Subtotal By-Products $0 $0

TOTAL VARIABLE OPERATING COSTS $16,321,057 $74,060,228

Fuel (ton) 0 11,568 38.18 $0 $145,104,475
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

185

5.

5.1 SYNTHETIC NATURAL GAS PRODUCTION USING ROSEBUD PRB COAL

LOW RANK COAL CASES

5.1.1

In this section the overall Siemens gasification process for SNG production using Montana 

Rosebud PRB coal is described. The plant configurations are similar to Cases 1 and 2, with the 

exception of the coal type utilized and coal drying method. Only the major process areas that 

differ from Cases 1 and 2 are described below. Since the carbon content of the subbituminous 

coal used is lower than that of the bituminous coal, the coal feed rate is significantly increased. 

The process BFDs for the PRB coal non-sequestration and sequestration cases are shown in 

Process Description

Exhibit 5-1 and Exhibit 5-3. The associated stream tables are shown in Exhibit 5-2 for the nonsequestration case and Exhibit 5-4 for the sequestration case. 

The WTA coal drying process includes a water-heated-, horizontal-, rotary-kiln coal pre-heater, a 

fluidized bed coal dryer and a water-cooled-, horizontal-, rotary-kiln coal cooler. The moisture 

driven from the coal in the fluid bed dryer passes through a baghouse for particulate removal and 

then is split into two streams. The smaller of the two streams is compressed and used as the 

fluidizing medium in the coal dryer. The bulk of the removed moisture is compressed to 

approximately 0.77 MPa (112 psia) and the temperature is raised to about 406°C (763°F) in the 

process. The high temperature vapor passes through internal coils in the dryer to provide the 

heat to drive off the coal moisture and then exits the dryer as liquid water. The warm water is 

used in the coal pre-heater before being used as cooling tower makeup water (stream 7). The 

vapor compressor consumes the vast majority of the WTA process auxiliary load. 

Coal Drying
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

186

Exhibit 5-1 Case 5 Block Flow Diagram, Subbituminous Rosebud PRB Coal to SNG without Carbon Sequestration

PARTIAL RAW

GAS QUENCH

AND COOLING

WATER-GAS

SHIFT REACTORS

& GAS COOLING

WATER

SCRUBBER

ELEVATED

PRESSURE

ASU

SIEMENS

GASIFIER

MERCURY

REMOVAL

DUALSTAGE

SELEXOL

UNIT

CLAUS

PLANT

1

AIR TO ASU

2 3

VENT

GAS

SULFUR

PLANT

OXIDANT

4

8

11

GASIFIER

OXIDANT

DRIED

COAL

SLAG

14

28

29

HYDROGENATION

REACTOR

30

CLEAN

GAS

SULFUR

PRODUCT

SYNGAS

WTA

COAL

DRYER

6

WET

COAL

7

5

13

TO SOUR

WATER

STRIPPER

STEAM

27

17

16

CO2

VENT

SHIFT

STEAM

WATER

31

12

QUENCH

WATER

15

18

METHANATION

REACTORS

23

SNG 

PURIFICATION

25

SNG FOR

EXPORT

24 PURIFICATION

OFF-GAS

20

21

22 PILOT

FUEL

WGS 

BYPASS

STEAM

TURBINE

32 33

PROCESS

STEAM

CONDENSATE

19

SNG 

COMPRESSION 26

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown. See H&MB diagram for more detail.

9

LOCKHOPPER

VENT

TRANSPORT

CO2

10

9 TRANSPORT

CO2
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

187

Exhibit 5-2 Case 5 Stream Table, Subbituminous Rosebud Coal to SNG without Carbon Sequestration

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

V-L Mole Fraction

Ar 0.0093 0.0091 0.0101 0.0101 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0020 0.0021 0.0021 0.0021 0.0000

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0001 0.0001 0.0001 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0106 0.0014 0.0000 0.0000 0.4342 0.4497 0.4497 0.4497 0.0000

CO2 0.0003 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.9765 0.1307 0.0000 0.0000 0.0560 0.0580 0.0580 0.0580 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0002 0.0002 0.0002 0.0002 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0113 0.6295 0.0000 0.0000 0.1836 0.1901 0.1901 0.1901 0.0000

H2O 0.0064 0.0026 0.0000 0.0000 1.0000 0.0000 1.0000 0.0000 0.0013 0.0985 0.0000 1.0000 0.3188 0.2945 0.2945 0.2945 1.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0022 0.0023 0.0023 0.0023 0.0000

N2 0.7759 0.9803 0.0004 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0096 0.0000 0.0000 0.0029 0.0030 0.0030 0.0030 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.2081 0.0076 0.9895 0.9895 0.0000 0.0000 0.0000 0.0000 0.0000 0.1302 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 51,342 40,633 74 10,414 2,754 0 6,669 0 4,090 15,275 0 12,518 52,503 50,698 6,569 44,129 15,436

V-L Flowrate (kg/hr) 1,483,532 1,143,127 2,361 334,053 49,619 0 120,139 0 177,211 202,764 0 225,516 1,102,187 1,069,647 138,592 931,055 278,087

Solids Flowrate (kg/hr) 0 0 0 0 0 571,223 0 451,084 0 336,925 48,199 0 0 0 0 0 0

Temperature (°C) 6 26 32 32 343 6 34 71 76 18 1,427 216 260 214 214 214 288

Pressure (MPa, abs) 0.09 0.11 0.86 0.86 5.10 0.10 0.60 0.09 5.62 5.62 4.24 8.27 3.89 3.756 3.76 3.76 4.14

Enthalpy (kJ/kg) 15.71 30.53 26.94 26.94 3,177.81 --- 152.37 --- 22.14 3,807.88 --- 1,017.87 1,091.95 959.483 959.48 959.48 3,070.04

Density (kg/m3) 1.1 1.3 11.0 11.0 20.1 --- 985.3 --- 103.2 33.8 --- 782.0 18.6 19.8 19.8 19.8 18.2

V-L Molecular Weight 28.895 28.133 32.078 32.078 18.015 --- 18.015 --- 43.330 13.275 --- 18.015 20.993 21.099 21.099 21.099 18.015

V-L Flowrate (lbmol/hr) 113,190 89,581 162 22,959 6,072 0 14,702 0 9,017 33,675 0 27,598 115,750 111,769 14,482 97,287 34,031

V-L Flowrate (lb/hr) 3,270,629 2,520,163 5,205 736,460 109,392 0 264,861 0 390,684 447,019 0 497,178 2,429,905 2,358,168 305,544 2,052,624 613,077

Solids Flowrate (lb/hr) 0 0 0 0 0 1,259,331 0 994,470 0 742,793 106,261 0 0 0 0 0 0

Temperature (°F) 42 78 90 90 650 42 92 160 168 64 2,600 420 500 417 417 417 550

Pressure (psia) 13.0 16.4 125.0 125.0 740.0 13.8 86.7 13.5 815.0 815.0 614.7 1,200.0 564.7 544.7 544.7 544.7 600.0

Enthalpy (Btu/lb) 6.8 13.1 11.6 11.6 1,366.2 --- 65.5 --- 9.5 1,637.1 --- 437.6 469.5 412.5 412.5 412.5 1,319.9

Density (lb/ft3) 0.070 0.080 0.685 0.685 1.257 --- 61.508 --- 6.441 2.111 --- 48.817 1.162 1.238 1.238 1.238 1.135

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

188

Exhibit 5-2 Case 5 Stream Table, Subbituminous Rosebud Coal to SNG without Carbon Sequestration (continued)

18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33

V-L Mole Fraction

Ar 0.0021 0.0021 0.0031 0.0031 0.0031 0.0109 0.0000 0.0126 0.0126 0.0000 0.0007 0.0000 0.0016 0.0022 0.0000 0.0000

CH4 0.0001 0.0001 0.0001 0.0001 0.0001 0.8283 0.0000 0.9595 0.9595 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.1606 0.1589 0.2361 0.2361 0.2361 0.0000 0.0000 0.0000 0.0000 0.0024 0.0594 0.0000 0.0851 0.0073 0.0000 0.0000

CO2 0.3487 0.3537 0.0405 0.0405 0.0405 0.1364 0.9832 0.0024 0.0024 0.9909 0.5950 0.0000 0.4846 0.7989 0.0000 0.0000

COS 0.0001 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0018 0.0000 0.0003 0.0000 0.0000 0.0000

H2 0.4812 0.4779 0.7156 0.7156 0.7156 0.0064 0.0000 0.0075 0.0075 0.0024 0.1138 0.0000 0.0549 0.1856 0.0000 0.0000

H2O 0.0018 0.0017 0.0001 0.0001 0.0001 0.0023 0.0168 0.0000 0.0000 0.0042 0.0413 0.0000 0.3702 0.0009 1.0000 1.0000

H2S 0.0025 0.0025 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1873 0.0000 0.0014 0.0041 0.0000 0.0000

N2 0.0030 0.0030 0.0045 0.0045 0.0045 0.0156 0.0000 0.0180 0.0180 0.0000 0.0005 0.0000 0.0007 0.0010 0.0000 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0012 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 50,536 51,104 33,915 149 33,766 9,681 1,323 8,358 8,358 12,415 684 0 803 568 43,734 60,796

V-L Flowrate (kg/hr) 1,066,602 1,087,054 342,281 1,508 340,773 195,747 57,660 138,086 138,086 543,371 24,191 0 24,674 20,452 787,876 1,095,261

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0 0 4,095 0 0 0 0

Temperature (°C) 35 34 31 80 31 35 35 35 35 5 48 175 232 21 566 33

Pressure (MPa, abs) 3.34 3.27 3.24 5.10 3.24 2.77 0.14 2.627 6.202 0.115 0.16 0.1 0.085 3.341 12.512 0.827

Enthalpy (kJ/kg) 42.82 41.44 85.34 232.30 85.34 40.71 46.43 47.903 12.710 7.664 101.63 --- 845.516 -8.120 3,495.174 120.842

Density (kg/m3) 28.0 27.8 12.8 17.2 12.8 23.2 2.4 17.8 44.5 2.2 2.2 5,285.9 0.6 56.5 34.9 995.1

V-L Molecular Weight 21.106 21.271 10.092 10.092 10.092 20.220 43.574 16.522 16.522 43.766 35.361 --- 30.719 36.012 18.015 18.015

V-L Flowrate (lbmol/hr) 111,414 112,666 74,770 329 74,440 21,342 2,917 18,425 18,425 27,371 1,508 0 1,771 1,252 96,416 134,033

V-L Flowrate (lb/hr) 2,351,455 2,396,544 754,601 3,325 751,276 431,548 127,119 304,428 304,428 1,197,927 53,332 0 54,397 45,090 1,736,970 2,414,637

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0 0 9,028 0 0 0 0

Temperature (°F) 95 94 87 177 87 95 95 95 95 42 119 347 450 69 1,050 91

Pressure (psia) 484.7 474.7 469.6 740.0 469.6 401.1 20.1 381.0 899.5 16.7 23.7 17.3 12.3 484.5 1,814.7 120.0

Enthalpy (Btu/lb) 18.4 17.8 36.7 99.9 36.7 17.5 20.0 20.6 5.5 3.3 43.7 --- 363.5 -3.5 1,502.7 52.0

Density (lb/ft3) 1.751 1.733 0.798 1.071 0.798 1.446 0.148 1.110 2.778 0.137 0.136 330 0.039 3.528 2.177 62.123
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

189

Exhibit 5-3 Case 6 Block Flow Diagram, Subbituminous Rosebud Coal to SNG with Carbon Sequestration

PARTIAL RAW

GAS QUENCH

AND COOLING

WATER-GAS

SHIFT REACTORS

& GAS COOLING

WATER

SCRUBBER

ELEVATED

PRESSURE

ASU

SIEMENS

GASIFIER

MERCURY

REMOVAL

DUALSTAGE

SELEXOL

UNIT

CLAUS

PLANT

1

AIR TO ASU

2 3

VENT

GAS

SULFUR

PLANT

OXIDANT

4

11

GASIFIER

OXIDANT

SLAG

14

28

29

HYDROGENATION

REACTOR

30

CLEAN

GAS

SULFUR

PRODUCT

SYNGAS

5

13

TO SOUR

WATER

STRIPPER

STEAM

27

17

16

CO2

PRODUCT

SHIFT

STEAM

31

12

QUENCH

WATER

15

18

METHANATION

REACTORS

23

SNG 

PURIFICATION

25

SNG FOR

EXPORT

24

PURIFICATION

OFF-GAS TO CO2

COMPRESSION

20

21

P 22 ILOT

FUEL

WGS 

BYPASS

9

STEAM

TURBINE

32 33

PROCESS

STEAM

CONDENSATE

19

SNG 

COMPRESSION 26

CO2 

COMPRESSION

24

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown. See H&MB diagram for more detail.

8

DRIED

COAL

WTA

COAL

DRYER

6

WET

COAL

7

WATER

9

LOCKHOPPER

TRANSPORT

CO2

10

VENT

PURIFICATION

OFF-GAS

TRANSPORT

CO2
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

190

Exhibit 5-4 Case 6 Stream Table, Subbituminous Rosebud PRB Coal to SNG with Carbon Sequestration

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

V-L Mole Fraction

Ar 0.0093 0.0091 0.0101 0.0101 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0020 0.0021 0.0021 0.0021 0.0000

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0001 0.0001 0.0001 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0041 0.0005 0.0000 0.0000 0.4343 0.4497 0.4497 0.4497 0.0000

CO2 0.0003 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.9914 0.1316 0.0000 0.0000 0.0561 0.0581 0.0581 0.0581 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0002 0.0002 0.0002 0.0002 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0043 0.6293 0.0000 0.0000 0.1833 0.1898 0.1898 0.1898 0.0000

H2O 0.0064 0.0026 0.0000 0.0000 1.0000 0.0000 1.0000 0.0000 0.0001 0.0985 0.0000 1.0000 0.3189 0.2946 0.2946 0.2946 1.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0022 0.0023 0.0023 0.0023 0.0000

N2 0.7759 0.9803 0.0004 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0096 0.0000 0.0000 0.0029 0.0030 0.0030 0.0030 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.2081 0.0076 0.9895 0.9895 0.0000 0.0000 0.0000 0.0000 0.0000 0.1304 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 51,336 40,628 73 10,413 2,754 0 6,669 0 4,049 15,254 0 12,514 52,479 50,673 6,564 44,109 15,439

V-L Flowrate (kg/hr) 1,483,363 1,142,996 2,343 334,032 49,619 0 120,139 0 177,211 202,764 0 225,439 1,102,088 1,069,598 138,555 931,043 278,144

Solids Flowrate (kg/hr) 0 0 0 0 0 571,223 0 451,084 0 336,925 48,199 0 0 0 0 0 0

Temperature (°C) 6 26 32 32 343 6 34 71 75 18 1,427 216 260 214 214 214 288

Pressure (MPa, abs) 0.09 0.11 0.86 0.86 5.10 0.09 0.55 0.09 5.62 5.62 4.24 8.27 3.89 3.756 3.76 3.76 4.14

Enthalpy (kJ/kg) 15.71 30.53 26.94 26.94 3,177.81 --- 152.81 --- 18.45 3,812.95 --- 1,017.87 1,091.75 959.191 959.19 959.19 3,070.04

Density (kg/m3) 1.1 1.3 11.0 11.0 20.1 --- 985.2 --- 105.5 33.9 --- 782.0 18.6 19.8 19.8 19.8 18.2

V-L Molecular Weight 28.895 28.133 32.078 32.078 18.015 --- 18.015 --- 43.764 13.292 --- 18.015 21.001 21.108 21.108 21.108 18.015

V-L Flowrate (lbmol/hr) 113,177 89,570 161 22,957 6,072 0 14,702 0 8,927 33,630 0 27,588 115,695 111,715 14,472 97,244 34,038

V-L Flowrate (lb/hr) 3,270,256 2,519,876 5,166 736,415 109,392 0 264,860 0 390,684 447,019 0 497,007 2,429,689 2,358,061 305,462 2,052,598 613,203

Solids Flowrate (lb/hr) 0 0 0 0 0 1,259,331 0 994,470 0 742,793 106,261 0 0 0 0 0 0

Temperature (°F) 42 78 90 90 650 42 93 160 166 64 2,600 420 500 417 417 417 550

Pressure (psia) 13.0 16.4 125.0 125.0 740.0 13.0 80.3 12.7 815.0 815.0 614.7 1,200.0 564.7 544.7 544.7 544.7 600.0

Enthalpy (Btu/lb) 6.8 13.1 11.6 11.6 1,366.2 --- 65.7 --- 7.9 1,639.3 --- 437.6 469.4 412.4 412.4 412.4 1,319.9

Density (lb/ft3

) 0.070 0.080 0.685 0.685 1.257 --- 61.501 --- 6.587 2.116 --- 48.817 1.162 1.238 1.238 1.238 1.135

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

191

Exhibit 5-4 Case 6 Stream Table, Subbituminous Rosebud PRB Coal to SNG with Carbon Sequestration (continued)

18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33

V-L Mole Fraction

Ar 0.0021 0.0021 0.0031 0.0031 0.0031 0.0109 0.0000 0.0126 0.0126 0.0001 0.0007 0.0000 0.0016 0.0022 0.0000 0.0000

CH4 0.0001 0.0001 0.0001 0.0001 0.0001 0.8276 0.0000 0.9590 0.9590 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.1606 0.1589 0.2361 0.2361 0.2361 0.0000 0.0000 0.0000 0.0000 0.0041 0.0594 0.0000 0.0846 0.0074 0.0000 0.0000

CO2 0.3490 0.3540 0.0406 0.0406 0.0406 0.1367 0.9833 0.0024 0.0024 0.9914 0.5957 0.0000 0.4861 0.7981 0.0000 0.0000

COS 0.0001 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0018 0.0000 0.0003 0.0000 0.0000 0.0000

H2 0.4810 0.4777 0.7155 0.7155 0.7155 0.0069 0.0000 0.0080 0.0080 0.0043 0.1139 0.0000 0.0552 0.1871 0.0000 0.0000

H2O 0.0017 0.0017 0.0001 0.0001 0.0001 0.0023 0.0167 0.0000 0.0000 0.0001 0.0410 0.0000 0.3696 0.0009 1.0000 1.0000

H2S 0.0025 0.0025 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1869 0.0000 0.0014 0.0033 0.0000 0.0000

N2 0.0030 0.0030 0.0045 0.0045 0.0045 0.0155 0.0000 0.0180 0.0180 0.0000 0.0005 0.0000 0.0007 0.0009 0.0000 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 50,513 51,082 33,890 149 33,740 9,680 1,326 8,354 8,354 15,652 683 0 802 569 43,615 60,862

V-L Flowrate (kg/hr) 1,066,572 1,087,014 342,095 1,508 340,587 195,732 57,763 137,969 137,969 684,975 24,177 0 24,640 20,441 785,734 1,096,442

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0 0 4,098 0 0 0 0

Temperature (°C) 35 34 31 80 31 35 35 35 35 35 48 175 232 21 566 33

Pressure (MPa, abs) 3.38 3.31 3.24 5.10 3.24 2.77 0.14 2.627 6.202 15.272 0.163 0.12 0.1 3.341 12.512 0.827

Enthalpy (kJ/kg) 42.63 41.26 85.32 232.24 85.32 40.72 46.40 47.945 12.775 -208.887 101.201 --- 844.6 -8.013 3,513.235 138.901

Density (kg/m3) 28.4 28.1 12.8 17.2 12.8 23.2 2.4 17.8 44.5 778.9 2.2 5,286.0 0.6 56.4 34.9 995.1

V-L Molecular Weight 21.115 21.280 10.094 10.094 10.094 20.221 43.574 16.515 16.515 43.764 35.372 --- 31 35.955 18.015 18.015

V-L Flowrate (lbmol/hr) 111,362 112,615 74,714 329 74,384 21,340 2,922 18,418 18,418 34,506 1,507 0 1,768 1,253 96,154 134,177

V-L Flowrate (lb/hr) 2,351,389 2,396,455 754,191 3,325 750,866 431,516 127,346 304,170 304,170 1,510,111 53,301 0 54,322 45,065 1,732,248 2,417,240

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0 0 9,034 0 0 0 0

Temperature (°F) 95 94 87 177 87 95 95 95 95 95 119 347 450 69 1,050 91

Pressure (psia) 489.7 479.7 469.6 740.0 469.6 401.1 20.1 381.0 899.5 2,215.0 23.7 17.3 12.3 484.5 1,814.7 120.0

Enthalpy (Btu/lb) 18.3 17.7 36.7 99.8 36.7 17.5 19.9 20.6 5.5 -89.8 43.5 --- 363.1 -3.4 1,510.4 59.7

Density (lb/ft3

) 1.770 1.752 0.799 1.072 0.799 1.446 0.148 1.110 2.776 48.625 0.136 329.997 0.039 3.520 2.177 62.123
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

192

5.1.2

System assumptions for Cases 5 and 6, Siemens gasifier using Rosebud PRB coal with and 

without carbon sequestration, are compiled in 

Key System Assumptions

Exhibit 5-5.

Exhibit 5-5 Cases 5 and 6 Plant Study Configuration Matrix

Case Case 5 Case 6

Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O2:Coal Ratio, kg O2/kg dry coal 0.731 0.731

Carbon Conversion, % 99.9 99.9

Syngas HHV at Gasifier Outlet, 

kJ/Nm3 (Btu/scf) 9,746 (263) 9,746 (263)

Steam Cycle, MPa/°C/°C

(psig/°F/°F)

12.4/566/539 

(1800/1050/1002)

12.4/566/539 

(1800/1050/1002)

Condenser Pressure, mm Hg

(in Hg) 36 (1.4) 36 (1.4)

CT N/A N/A

Gasifier Technology Siemens Siemens

Oxidant 99 vol% Oxygen 99 vol% Oxygen

Coal Rosebud PRB Rosebud PRB

Coal Feed Moisture Content, % 25.77 25.77

COS Hydrolysis Reactor No No

WGS Yes Yes

H2S Separation Selexol (1st Stage) Selexol (1st Stage)

Sulfur Removal, % 98.5 99.9

CO2 Separation Selexol (2nd Stage) Selexol (2nd Stage)

CO2 Sequestration, % N/A 65.8

Sulfur Recovery

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Methanation System Haldor Topsoe TREMPTM 

Process

Haldor Topsoe TREMPTM 

Process

Particulate Control Scrubber and AGR 

Absorber

Scrubber and AGR 

Absorber

Mercury Control Carbon Bed Carbon Bed

NOx Control N/A N/A

Balance of Plant and Sparing Philosophy

The balance of plant assumptions and sparing philosophy are common to all cases and are 

presented in Section 4.1.3.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

193

5.1.3

The Siemens SNG plant without and with carbon sequestration and using Rosebud PRB coal 

produces a net output of 61 Bscf/year at 100 percent capacity. 

Cases 5 and 6 Performance Results

Overall performance for the two plants is summarized in Exhibit 5-6, which includes auxiliary 

power requirements and production values. The ASU accounts for approximately 59 percent of 

the total auxiliary load in non-sequestration case and 49 percent in the sequestration case, 

distributed between the main air compressor, the oxygen compressor, and ASU auxiliaries. CO2

compression accounts for about 19 percent in the sequestration case. The AGR process accounts 

for approximately 12 percent and 10 percent of the auxiliary load for the non-sequestration and 

sequestration cases, respectively. The WTA coal drying process accounts for 8 percent in the 

non-sequestration case and 7 percent in the sequestration case. All other individual auxiliary 

loads are less than 3 percent of the total. Both Case 5 and Case 6 are net power producers, but 

the net power production of Case 6 is very small. This is due to the auxiliary power required for 

CO2 compression. 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

194

Exhibit 5-6 Cases 5 and 6 Plant Performance Summary

POWER SUMMARY 

(Gross Power at Generator Terminals, kWe) Case 5 Case 6

Steam Turbine Power 302,000 302,000

TOTAL POWER, kWe 302,000 302,000

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 840 840

Coal Milling 5,870 5,870

Slag Handling 1,250 1,250

WTA Coal Dryer Compressor 20,050 20,060

WTA Coal Dryer Auxiliaries 880 880

Air Separation Unit Auxiliaries 1,000 1,000

Air Separation Unit Main Air Compressor 124,170 124,160

Oxygen Compressor 21,250 21,250

CO2 Compressor 0 56,730

CO2 Solid Feed System Compressor 5,580 270

SNG Compressors 6,040 6,040

Methanation Plant Recycle Compressor 4,720 4,650

Gasifier Pilot Fuel Compressor 60 60

Boiler Feedwater Pumps 5,020 5,020

Condensate Pump 400 400

Quench Water Pump 570 570

Circulating Water Pump 4,550 5,190

Ground Water Pumps 440 500

Cooling Tower Fans 2,970 3,380

Air Cooled Condenser Fans 3,640 3,630

Scrubber Pumps 980 980

Acid Gas Removal 30,240 30,250

Steam Turbine Auxiliaries 100 100

Claus Plant/TGTU Auxiliaries 250 250

Claus Plant TG Recycle Compressor 2,120 2,130

Miscellaneous Balance of Plant2 3,000 3,000

Transformer Losses 1,580 1,730

TOTAL AUXILIARIES, kWe 247,570 300,190

NET POWER, kWe 54,430 1,810

SNG Production Rate, MNm3/hr (Mscf/hr) 197.9 (6,992) 197.8 (6,989)

Capacity Factor 90% 90%

Net Exported Power Efficiency (HHV) 1.7% 0.1%

SNG Conversion Efficiency (HHVproduct/HHVcoal), % 63.1% 63.1%

Coal to SNG Product Yield, MNm3

SNG/tonnecoal 

(MscfSNG/toncoal) 0.33 (11.1) 0.33 (11.1)

Coal Feed Flow Rate, kg/hr (lb/hr) 571,223 (1,259,331) 571,223 (1,259,331)

Thermal Input,

1 kWth 3,160,745 3,160,745

Condenser Cooling Duty, GJ/hr (MMBtu/hr) 1,614 (1,530) 1,625 (1,540)

Raw Water Withdrawal, m3/min (gpm) 18.4 (4,853) 20.9 (5,509)

Raw Water Consumption, m3/min (gpm) 14.3 (3,783) 16.2 (4,291)

1 - HHV of Rosebud PRB coal is 19,920 kJ/kg (8,564 Btu/lb)

2 - Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

195

Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 

2.5. A summary of the plant air emissions for Cases 5 and 6 is presented in Exhibit 5-7.

Exhibit 5-7 Cases 5 and 6 Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

90% capacity factor

Case 5 Case 6 Case 5 Case 6

SO2

0.009 

(0.022)

0.000 

(0.000) 840 (926) 0 (0)

NOX Negligible Negligible Negligible Negligible

Particulates 0.003 

(0.0071)

0.003 

(0.0071) 274 (302) 274 (302)

Hg 1.51E-7 

(3.51E-7)

1.51E-7 

(3.51E-7)

0.014 

(0.015)

0.014 

(0.015)

CO2 60.3 (140.3) 0.3 (0.7) 5,412,955 

(5,966,762)

27,781 

(30,624)

The low level of SO2 emissions in Case 6 is achieved by capture of the sulfur in the gas by the 

two-stage Selexol AGR process and co-sequestration with the CO2 product. Because the WTA 

coal drying process does not include combustion of SNG, there are no SO2 emissions associated 

with drying. Just as in the non-capture cases, the SO2 emissions are significantly less than the 

environmental targets of Section 2.5. The clean syngas exiting the AGR process has a sulfur 

concentration of approximately 2 ppmv in both cases. The H2S-rich regeneration gas from the 

AGR system is fed to a Claus plant, producing elemental sulfur. The tail gas is hydrogenated 

and recycled to the AGR unit. The higher sulfur emissions in Case 5 are due to the sulfur 

contained in the CO2-rich stream from the Selexol process, which is vented rather than 

sequestered.

NOX emissions are negligible because no CT is used for power generation.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a syngas 

scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent 

filterable particulate only.

Ninety five percent of mercury is captured from the syngas by an activated carbon bed. 

CO2 emissions represent the uncontrolled (Case 5) and controlled (Case 6) discharge from the 

process. The carbon balance for the two cases is shown in Exhibit 5-8. 

The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. 

Carbon in the air is not used in the carbon capture equation below, but it is not neglected in the 

balance since Aspen accounts for air components throughout. Carbon leaves the plant as 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

196

unburned carbon in the slag, ASU vent gas, SNG product, and the CO2 product (either vented or 

sequestered). The carbon capture efficiency is presented in two distinct ways. The first way 

defines capture as the amount of carbon in the CO2 product for sequestration relative to the 

amount of carbon in the coal less carbon contained in the slag, and is represented by the 

following fraction:

(Carbon in Product for Sequestration)/[(Carbon in the Coal)-(Carbon in Slag)] or

Non sequestration (Case 5)

(412,575)/(630,524-3,153)*100 = 65.8% (Case 6)

Exhibit 5-8 Cases 5 and 6 Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Case 5 Case 6 Case 5 Case 6

Coal 286,001 

(630,524)

286,001 

(630,524) Slag 1,430 (3,153)

1,430 

(3,153)

Air (CO2) 202 (446) 202 (446)

SNG 

Purification 

Off-Gas

15,627 

(34,452) 0 (0)

ASU Vent 202 (446) 202 (446)

SNG 96,555 

(212,866)

96,464 

(212,667)

CO2 Vent 148,142 

(326,598)

187,141 

(412,575)

CO2 Feed 

Vent

24,247 

(53,455) 966 (2,129)

Total 286,203 

(630,969)

286,203 

(630,969) Total 286,203 (630,969)

286,203 

(630,969)

The second way does not penalize the production facility for the carbon converted to SNG

product, as the end use of the SNG is unknown. In a carbon constrained scenario, the SNG may 

or may not be used in a scenario where CCS is implemented. For this method, the burden of 

carbon mitigation falls on the end-user. This method is represented by the following fraction: 

[(Carbon in Product for Sequestration) + (Carbon in SNG Product)]/[(Carbon in the Coal)-

(Carbon in Slag)] or

(0 + 212,866)/(630,524 – 3,153)*100 = 33.9% (Case 5)

(412,575 + 212,866)/(630,524-3,153)*100 = 99.7% (Case 6)

Exhibit 5-9 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

197

stack gas, sulfur co-sequestered with the CO2 product, and sulfur remaining in the SNG product. 

Sulfur in the slag is considered negligible. The total sulfur capture is represented by the 

following fraction:

(Sulfur byproduct + Sulfur in CO2 product)/Sulfur in the coal or

(9,028 + 0)/9,161 = 98.5% (Case 5)

(9,033 + 123)/9,161 = 99.9% (Case 6)

Exhibit 5-9 Cases 5 and 6 Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Case 5 Case 6 Case 5 Case 6

Coal 4,155 (9,161) 4,155 (9,161) Elemental 

Sulfur

4,095 

(9,028) 4,097 (9,033)

SNG 2 (4) 2 (4)

CO2 Vent 

Streams/Stack 58 (128) 0.3 (1)

CO2 Product N/A 56 (123)

Total 4,155 (9,161) 4,155 (9,161) Total 4,155 

(9,161) 4,155 (9,161)

Exhibit 5-10 shows the overall water balance for the plant. Water demand represents the total 

amount of water required for a particular process. Some water is recovered within the process, 

primarily as syngas condensate, and is re-used as internal recycle. The difference between 

demand and recycle is raw water withdrawal. Raw water withdrawal is defined as the water 

removed from the ground or diverted from a surface-water source for use in the plant and was 

assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water 

withdrawal can be represented by the water metered from a raw water source and used in the 

plant processes for any and all purposes, such as cooling tower makeup, BFW makeup, quench 

system makeup, and slag handling makeup. The difference between water withdrawal and 

process water discharge is defined as water consumption and can be represented by the portion 

of the raw water withdrawn that is evaporated, transpired, incorporated into products or 

otherwise not returned to the water source from which it was withdrawn. Water consumption 

represents the net impact of the plant process on the water source.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

198

Exhibit 5-10 Cases 5 and 6 Water Balance

Case 5 Case 6

Water Demand, m3/min (gpm)

Slag Handling 1.04 (276) 1.04 (276)

Quench/Wash 3.8 (994) 3.8 (994)

Condenser Makeup 5.7 (1,507) 5.7 (1,507)

 Gasifier Steam 0.83 (219) 0.83 (219)

 Shift Steam 4.6 (1,226) 4.6 (1,226)

 BFW Makeup 0.23 (62) 0.23 (62)

Cooling Tower 17.7 (4,679) 20.2 (5,334)

Total 28.2 (7,456) 30.7 (8,111)

Internal Recycle, m3/min (gpm)

Slag Handling 1.04 (276) 1.04 (276)

Quench/Wash 3.8 (994) 3.8 (994)

Condenser Makeup 0.0 (0) 0.0 (0)

Cooling Tower 5.0 (1,332) 5.0 (1,332)

 Water from Coal Drying 2.0 (530) 2.0 (530)

 BFW Blowdown 0.23 (62) 0.23 (62)

 SWS Blowdown 0.69 (183) 0.69 (183)

 SWS Excess 2.1 (558) 2.1 (558)

Total 9.9 (2,602) 9.8 (2,602)

Raw Water Withdrawal, m3/min (gpm)

Slag Handling 0.0 (0) 0.0 (0)

Quench/Wash 0.0 (0) 0.0 (0)

Condenser Makeup 5.7 (1,507) 5.7 (1,507)

 Gasifier Steam 0.83 (219) 0.83 (219)

 Shift Steam 4.6 (1,226) 4.6 (1,226)

 BFW Makeup 0.23 (62) 0.23 (62)

Cooling Tower 12.7 (3,347) 15.1 (4,002)

Total 18.4 (4,853) 20.9 (5,509)

Process Water Discharge, m3/min (gpm)

SWS Blowdown 0.07 (18) 0.07 (18)

Cooling Tower Blowdown 4.0 (1,052) 4.5 (1,200)

Total 4.1 (1,071) 4.6 (1,218)

Raw Water Consumption, m3/min (gpm)

Slag Handling 0.0 (0) 0.0 (0)

Quench/Wash 0.0 (0) 0.0 (0)

SWS Blowdown -0.07 (-18) -0.07 (-18)

Condenser Makeup 5.7 (1,507) 5.7 (1,507)

Cooling Tower 8.7 (2,295) 10.6 (2,803)

Total 14.3 (3,783) 16.2 (4,291)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

199

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 5-11 through 

Exhibit 5-16:

• Coal gasification and ASU

• Syngas cleanup (including sulfur recovery and tail gas recycle)

• Methanation, SNG purification, SNG compression, and power cycle

An overall plant energy balance is provided in tabular form in Exhibit 5-17 for the two cases. 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

200

Exhibit 5-11 Case 5 Gasification and ASU Heat and Mass Balance

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ROSEBUD PRB SNG PLANT

CASE 5

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 5

ASU AND GASIFICATION

DWG. NO.

BL-HMB-CS-5-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

PAGES

1 OF 3

Ambient Air

Intercooled

Air Compressor

Elevated

Pressure

ASU

Intercooled

Oxygen Compressor

Milled Coal

ASU

Vent

Slag

Removal

Slag

GROSS PLANT POWER: 302 MWE

AUXILIARY LOAD: 248 MWE

NET PLANT POWER: 54 MWE

SNG PRODUCTION: 6,992 MSCF/HR

Dried Coal

Coal

Feeding

Steam

CO2 to Lock Hoppers

Boost

Compressor

Siemens Gasifier

1,259,331 W

3,270,629 W

42.0 T

13.0 P

6.8 H

736,460 W

90.0 T

125.0 P

11.6 H

736,460 W

516.2 T

740.0 P

107.1 H

109,392 W

650.0 T

740.0 P

1,316.8 H

1,932,727 W

2,600.0 T

604.7 P

1,064.7 H

106,261 W

ENG UNITS

To Claus Plant

5,205 W

90.0 T

125.0 P

11.6 H

WTA

Dryer

Vapor 

Compressor

Condensate 

to Cooling Tower

2,520,163 W

78.1 T

16.4 P

13.1 H

264,861 W

225.0 T

13.8 P

1,160.0 H

264,861 W

92.3 T

86.7 P

16.1 H

Syngas

Quench

Cooler

Raw Syngas

to Scrubber

SH

Steam

4

7

1

6 8

3

11

5

2

Quench Water

13

Lock Hopper

Vent

195,342 W

390,684 W

168.0 T

815.0 P

9.5 H

9

390,684 W

60.0 T

149.7 P

1.7 H

12

497,178 W

SH

Steam

SH

Steam

2,429,905 W

499.7 T

564.7 P

469.5 H

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Sour Gas

Sour Water

Water

Steam

CO2

Tailgas

21 Pilot Fuel

3,325 W

176.7 T

740.0 P

99.9 H

1,189,812 W

64.5 T

815.0 P

1,637.1 H

994,470 W

10

HP

BFW
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

201

Exhibit 5-12 Case 5 Gas Cleanup Heat and Mass Balance

Mercury 

Removal

Knock

Out

Raw Syngas Drum

to Scrubber

Sour

Drum

To Water Treatment

Makeup Water

Catalytic

Reactor

Beds

High

Temperature

Shift

Blowdown

From

ASU LP CO2

Shift

Steam

HP BFW

Syngas

Coolers

Sour

Stripper

Two-Stage

Selexol

Clean Gas

CO2

Acid Gas

Syngas

Scrubber Condensate

To Deaerator Condensate

613,077 W

550.0 T

600.0 P

1,270.5 H

2,358,168 W

416.6 T

544.7 P

412.5 H

2,429,905 W

499.7 T

564.7 P

469.5 H

2,358,168 W

358.9 T

554.7 P

390.4 H

2,396,544 W

93.8 T

474.7 P

17.8 H

754,601 W

87.0 T

469.6 P

36.7 H

53,332 W

119.0 T

23.7 P

43.7 H

1,197,927 W

41.6 T

16.7 P

3.3 H

914,108 W

339.3 T

115.0 P

339.2 H

2,971,245 W

527.0 T

524.7 P

426.8 H

751,276 W

87.0 T

469.6 P

36.7 H

9,028 W

4,888 W

293.4 T

65.0 P

1,042.1 H

5,205 W

90.0 T

125.0 P

11.6 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ROSEBUD PRB SNG PLANT

CASE 5

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 5

GAS CLEANUP

DWG. NO.

BL-HMB-CS-5-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

2 OF 3

Sour Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 302 MWE

AUXILIARY LOAD: 248 MWE

NET PLANT POWER: 54 MWE

SNG PRODUCTION: 6,992 MSCF/HR

2,052,624 W

416.6 T

544.7 P

412.5 H

305,544 W

20

18

13

30

CO2

Tailgas

14

15

16

17

2,971,245 W

862.6 T

534.7 P

572.3 H

2,351,455 W

95.0 T

484.7 P

18.4 H

High Temperature

Methanation Reactor

Pre-heater

Tail Gas Cleanup Unit

3

19

CO2 to Lock

Hoppers

Vented

CO2 Product

9

Claus Plant

Tail 

Gas

Furnace

Sulfur

29

28

HP CO2

27

972,924 W

42.0 T

16.7 P

3.7 H

615,687 W

60.0 T

149.7 P

1.7 H

390,684 W

168.0 T

815.0 P

9.5 H

Syngas to

Methanation

Boost

Compressor

3,325 W

Pilot Fuel

to Gasifier

3,325 W

176.7 T

740.0 P

99.9 H

21

22

Condensate

from Methnation

HT Shift

Pre-heater 54,397 W

450.0 T

12.3 P

363.5 H

31

45,090 W

69.3 T

484.5 P

-3.5 H

Tail Gas

Compressor
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

202

Exhibit 5-13 Case 5 Methanation and Power Block Heat and Mass Balance

Steam Seal 

Regulator

65 PSIA Header

Steam Injection

To Gasifier

Make-up

Gland

Steam

Condenser

Condensate to Preheating

Condensate

Pump

2,414,637 W

90.0 T

0.7 P

57.9 H

772,976 W

1,736,970 W

1,050.0 T

1,814.7 P

1,510.4 H

2,414,637 W

91.5 T

120.0 P

59.7 H

1,400 W

1,400 W

212.0 T

14.7 P

179.9 H

109,392 W

650.0 T

740.0 P

1,316.8 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ROSEBUD PRB SNG PLANT

CASE 5

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 5

METHANATION AND POWER BLOCK

DWG. NO.

BL-HMB-CS-5-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 302 MWE

AUXILIARY LOAD: 248 MWE

NET PLANT POWER: 54 MWE

SNG PRODUCTION: 6,992 MSCF/HR

Flue Gas

Deaerator

HT Reactor

LP TURBINE GENERATOR HP

TURBINE IP

TURBINE

HOT WELL

AIR-COOLED 

CONDENSER CONDENSER

IP Pump

To Shift Steam

Production

LP Pump

250 PSIA

Attemperating Water

HP Pump

Recycle

Compressor

Syngas from

Selexol Unit

Knock

Out

Drum

Molecular 

Sieve 

Purification 

Unit

Multistage 

Intercooled 

SNG 

Compressor

Clean Up

HT Reactor Reator

Purification

Off-Gas

SNG

Product

Condensate to

Sour Drum

Reactor

Pre-heater

SH Steam from

Syngas Cooler

IP BFW

SH Shift Steam

IP/LP BFW

IP/LP Steam IP Steam IP BFW

32

33

1,782,683 W

751,276 W

87.0 T

469.6 P

36.7 H

22

572.0 T

452.5 P

628.3 H

584.8 T

475.0 P

635.5 H

572.0 T

469.6 P

565.2 H

1,285.3 T

462.5 P

1,092.7 H

2,135,970 W

1,029.8 T

441.8 P

959.9 H

392.0 T

431.8 P

578.8 H

644.0 T

421.1 P

767.4 H

335.0 T

411.1 P

406.7 H

431,548 W

95.0 T

401.1 P

17.5 H

127,119 W

95.0 T

20.1 P

20.0 H 304,428 W

95.0 T

381.0 P

20.6 H

95.0 T

899.5 P

5.5 H

663,330 W

281.3 T

450.0 P

250.9 H

589,382 W

115,800 W

298.0 T

65.0 P

1,178.6 H

1,513,947 W

507.3 T

65.0 P

1,285.7 H

IP BFW

17,173 W

281.2 T

379.0 P

250.7 H

23

24 25 26

10,914 W

658.5 T

18.0 P

1,362.8 H

To Syngas Cooler

Reheater

(Syngas Cooler)

1,593,354 W

1,001.9 T

501.4 P

1,520.9 H

17,384 W

Attemperation

Water
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

203

Exhibit 5-14 Case 6 Gasification and ASU Heat and Mass Balance

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ROSEBUD PRB SNG PLANT

W/ CO2 CAPTURE

CASE 6

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 6

ASU AND GASIFICATION

DWG. NO.

BL-HMB-CS-6-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

PAGES

1 OF 3

Ambient Air

Intercooled

Air Compressor

Elevated

Pressure

ASU

Intercooled

Oxygen Compressor

Milled Coal

ASU

Vent

Slag

Removal

Slag

GROSS PLANT POWER: 302 MWE

AUXILIARY LOAD: 300 MWE

NET PLANT POWER: 2 MWE

SNG PRODUCTION: 6,989 MSCF/HR

Dried Coal

Coal

Feeding

Steam

CO2 to Lock Hoppers

Boost

Compressor

Siemens Gasifier

1,259,331 W

3,270,256 W

42.0 T

13.0 P

6.8 H

736,415 W

90.0 T

125.0 P

11.6 H

736,415 W

516.2 T

740.0 P

107.1 H

109,392 W

650.0 T

740.0 P

1,366.2 H

1,932,682 W

2,600.0 T

604.7 P

1,064.4 H

106,261 W

ENG UNITS

To Claus Plant

5,166 W

90.0 T

125.0 P

11.6 H

2,519,876 W

78.1 T

16.4 P

13.1 H

Syngas

Quench

Cooler

Raw Syngas

to Scrubber

SH

Steam

4

1

6 8

3

11

5

2

Quench Water

13

7,792 W

390,684 W

166.3 T

815.0 P

7.9 H

9

390,684 W

152.5 T

750.0 P

5.7 H

12

497,007 W

SH

Steam

SH

Steam

2,429,689 W

499.7 T

564.7 P

469.4 H

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Sour Gas

Sour Water

Water

Steam

CO2

Tail Gas/

Flue Gas

21 Pilot Fuel

264,860 W

92.5 T

80.3 P

65.7 H

1,189,812 W

WTA Coal 

Dryer

Synthesis Gas

994,470 W

10

HP Vent to

CO2 Compressor

LP Vent to

CO2 Compressor

155,664 W 31,886 W

Condensate to

Cooling Tower

3,325 W

176.7 T

740.0 P

99.8 H

Vapor Compressor

264,861 W

225.0 T

13.0 P

1,209.5 H

Lock Hopper

Atmospheric Vent

7

HP

BFW
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

204

Exhibit 5-15 Case 6 Gas Cleanup Heat and Mass Balance

SNG Purification

Off Gas

Mercury 

Removal

Knock

Out

Raw Syngas Drum

to Scrubber

Sour

Drum

To Water Treatment

Makeup Water

Catalytic

Reactor

Beds

High

Temperature

Shift

Blowdown

From

ASU

Shift

Steam

HP BFW

Syngas

Coolers

Sour

Stripper

Two-Stage

Selexol

Clean Gas

CO2

Acid Gas

Syngas

Scrubber Condensate

To Deaerator Condensate

613,203 W

550.0 T

600.0 P

1,270.5 H

2,358,061 W

416.6 T

544.7 P

412.4 H

2,429,689 W

499.7 T

564.7 P

469.4 H

2,358,061 W

358.9 T

554.7 P

390.3 H

2,396,455 W

93.8 T

479.7 P

17.7 H

754,191 W

87.0 T

469.6 P

36.7 H

53,301 W

119.0 T

23.7 P

43.5 H

390,684 W

152.5 T

750.0 P

5.7 H

913,699 W

339.3 T

115.0 P

339.2 H

2,971,264 W

485.7 T

519.7 P

409.2 H

750,866 W

87.0 T

469.6 P

36.7 H

9,034 W

4,889 W

293.4 T

65.0 P

1,041.6 H

5,166 W

90.0 T

125.0 P

11.6 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ROSEBUD PRB SNG PLANT

W/ CO2 CAPTURE

CASE 6

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 6

GAS CLEANUP

DWG. NO.

BL-HMB-CS-6-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

2 OF 3

Sour Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 302 MWE

AUXILIARY LOAD: 300 MWE

NET PLANT POWER: 2 MWE

SNG PRODUCTION: 6,989 MSCF/HR

2,052,598 W

416.6 T

544.7 P

412.4 H

20

18

13

30

CO2

Tail Gas/

Flue Gas

14

15

17

305,462 W

2,351,389 W

95.0 T

489.7 P

18.3 H

High Temperature

Methanation Reactor

Pre-heater

Tail Gas Cleanup Unit

3

19

CO2 to

Sequestration

CO2 to

Lock Hoppers

Claus Plant

Tail 

Gas

Furnace

Sulfur

29

28

1,510,111 

W

95.0 T

2,215.0 P

-89.8 H

Syngas to

Methanation

Boost

Compressor

3,325 W

Pilot Fuel

to Gasifier

3,325 W

176.7 T

740.0 P

99.8 H

21

22

Condensate

from Methnation

HT Shift

Pre-heater 54,322 W

450.0 T

12.3 P

363.1 H

31

45,065 W

69.3 T

484.5 P

-3.4 H

24

Multistage 

Intercooled CO2

Compressor

27

HP CO2

LP Lock

Hopper Vent HP Lock

Hopper Vent

LP CO2

127,346 W

95.0 T

20.1 P

19.9 H

31,886 W

155,664 W

771,490 W

66.4 T

149.7 P

3.0 H

1,132,369 W

49.0 T

16.7 P

Tail Gas 5.6 H

Compressor

16
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

205

Exhibit 5-16 Case 6 Methanation and Power Block Heat and Mass Balance

Steam Seal 

Regulator

65 PSIA Header

Steam Injection

Make-up

Gland

Steam

Condenser

Condensate to Preheating

Condensate

Pump

2,417,240 W

90.0 T

0.7 P

57.9 H

773,069 W

1,732,248 W

1,050.0 T

1,814.7 P

1,510.4 H

2,417,240 W

91.5 T

120.0 P

59.7 H

1,400 W

1,400 W

212.0 T

14.7 P

179.9 H

109,392 W

650.0 T

740.0 P

1,366.2 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

ROSEBUD PRB SNG PLANT

W/ CO2 CAPTURE

CASE 6

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 6

METHANATION AND POWER BLOCK

DWG. NO.

BL-HMB-CS-6-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 302 MWE

AUXILIARY LOAD: 300 MWE

NET PLANT POWER: 2 MWE

SNG PRODUCTION: 6,989 MSCF/HR

Flue Gas

Deaerator

HT Reactor

LP TURBINE GENERATOR HP

TURBINE IP

TURBINE

HOT WELL

AIR-COOLED 

CONDENSER CONDENSER

IP Pump

To Shift Steam

Production

LP Pump

250 PSIA

Attemperating Water

HP Pump

Recycle

Compressor

Syngas from

Selexol Unit

Knock

Out

Drum

Molecular 

Sieve 

Purification 

Unit

Multistage 

Intercooled 

SNG 

Compressor

Clean Up

HT Reactor Reator

Purification Off-Gas

(To CO2 Compressor)

SNG

Product

Condensate to

Sour Drum

Reactor

Pre-heater

SH Steam from

Syngas Cooler

IP BFW

SH Shift Steam

IP/LP BFW

IP/LP Steam IP Steam IP BFW

32

33

1,778,199 W

750,866 W

87.0 T

469.6 P

36.7 H

22

572.0 T

452.5 P

627.1 H

584.8 T

475.0 P

634.4 H

572.0 T

469.6 P

563.5 H

1,290.2 T

462.5 P

1,095.1 H

2,097,593 W

1,035.4 T

441.8 P

962.5 H

392.0 T

431.8 P

577.6 H

650.6 T

421.1 P

770.9 H

335.0 T

411.1 P

406.7 H

431,516 W

95.0 T

401.1 P

17.5 H

127,346 W

95.0 T

20.1 P

19.9 H 304,170 W

95.0 T

381.0 P

20.6 H

95.0 T

899.5 P

5.5 H

667,733 W

281.3 T

450.0 P

250.9 H

592,296 W

120,000 W

298.0 T

65.0 P

1,178.6 H

1,512,257 W

507.4 T

65.0 P

1,285.7 H

IP BFW

17,206 W

281.1 T

379.0 P

250.6 H

23

24 25 26

10,914 W

658.6 T

18.0 P

1,362.8 H

To Syngas Cooler

P-647

Attemperation

Water

To Gasifier

Reheater

(Syngas Cooler)

1,591,756 W

1,002.1 T

501.4 P

1,521.0 H

17,722 W
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

206

Exhibit 5-17 Cases 5 and 6 Energy Balance

HHV Sensible + Latent Power Total

Case 5 Case 6 Case 5 Case 6 Case 5 Case 6 Case 5 Case 6

Heat In, GJ/hr (MMBtu/hr)

Coal 11,379 

(10,785)

11,379 

(10,785) 5.8 (5.5) 5.8 (5.5) 0 (0) 0 (0) 11,385 (10,790)

11,385 

(10,790)

ASU Air 0 (0) 0 (0) 23.3 (22.1) 23.3 (22.1) 0 (0) 0 (0) 23 (22) 23 (22)

Raw Water Makeup 0 (0) 0 (0) 25.6 (24.2) 29.0 (27.5) 0 (0) 0 (0) 26 (24) 29 (27)

Auxiliary Power 0 (0) 0 (0) 0.0 (0.0) 0.0 (0.0) 891 (845) 1,081 

(1,024) 891 (845) 1,081 (1,024)

Totals 11,379 

(10,785)

11,379 

(10,785) 54.7 (51.9) 58.2 (55.1) 891 (845) 1,081 (1,024)

12,325 

(11,682)

12,518 

(11,864)

Heat Out, GJ/hr (MMBtu/hr)

ASU Intercoolers 0 (0) 0 (0) 325 (308) 325 (308) 0 (0) 0 (0) 325 (308) 325 (308)

ASU Vent 0 (0) 0 (0) 34.9 (33.1) 34.9 (33.1) 0 (0) 0 (0) 35 (33) 35 (33)

Slag 47 (44) 47 (44) 81.4 (77.1) 81.4 (77.1) 0 (0) 0 (0) 128 (122) 128 (122)

Sulfur 38 (36) 38 (36) 0.5 (0.4) 0.5 (0.4) 0 (0) 0 (0) 38 (36) 38 (36)

CO2 Intercoolers 0 (0) 0 (0) 0.0 (0.0) 343.7 (325.8) 0 (0) 0 (0) 0 (0) 344 (326)

CO2 0 (0) 0 (0) 2.0 (1.9) -143.1 (-135.6) 0 (0) 0 (0) 2 (2) -143 (-136)

Cooling Tower Blowdown 0 (0) 0 (0) 22.2 (21.0) 25.3 (24.0) 0 (0) 0 (0) 22 (21) 25 (24)

SNG 7,163 (6,789) 7,158 (6,784) 1.8 (1.7) 1.8 (1.7) 0 (0) 0 (0) 7,165 (6,791) 7,160 (6,786)

SNG Purification Off-Gas 0 (0) 0 (0) 3 (3) 0 (0) 0 (0) 0 (0) 3 (3) 0 (0)

Condenser 0 (0) 0 (0) 1,618 (1,533) 1,620 (1,536) 0 (0) 0 (0) 1,618 (1,533) 1,620 (1,536)

Non-Condenser Cooling 

Tower Loads* 0 (0) 0 (0) 902 (855) 1,224 (1,160) 0 (0) 0 (0) 902 (855) 1,224 (1,160)

Process Losses* 0 (0) 0 (0) 1,000 (947) 674 (639) 0 (0) 0 (0) 1,000 (947) 674 (639)

Power 0 (0) 0 (0) 0.0 (0.0) 0.0 (0.0) 1,087 

(1,030)

1,087 

(1,030) 1,087 (1,030) 1,087 (1,030)

Totals 7,248 (6,870) 7,243 (6,865) 3,989 (3,781) 4,188 (3,969) 1,087 

(1,030)

1,087 

(1,030)

12,325 

(11,682)

12,518 

(11,864)

* Includes other energy losses not explicitly accounted for in the model
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

207

5.1.4

Major equipment items for the Siemens gasifier SNG plant without and with carbon 

sequestration using PRB coal are shown in the following tables. The accounts used in the 

equipment list correspond to the account numbers used in the cost estimates in Section 

Cases 5 and 6 Equipment Lists

5.1.5. In 

general, the design conditions include a 10 percent contingency for flows and heat duties and a 

21 percent contingency for heads on pumps and fans.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

208

ACCOUNT 1 COAL HANDLING

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition

Case 6 Design 

Condition

1

Bottom Trestle 

Dumper and 

Receiving Hoppers

N/A 2 0 181 tonne (200 ton) 181 tonne (200 ton)

2 Feeder Belt 2 0 572 tonne/hr (630 tph) 572 tonne/hr (630 tph)

3 Conveyor No. 1 Belt 1 0 1,134 tonne/hr

(1,250 tph)

1,134 tonne/hr

(1,250 tph)

4 Transfer Tower No. 

1 Enclosed 1 0 N/A N/A

5 Conveyor No. 2 Belt 1 0 1,134 tonne/hr (1,250 

tph)

1,134 tonne/hr (1,250 

tph)

6 As-Received Coal 

Sampling System Two-stage 1 0 N/A N/A

7 Stacker/Reclaimer Traveling, 

linear 1 0 1,134 tonne/hr (1,250 tph)

1,134 tonne/hr (1,250 

tph)

8 Reclaim Hopper N/A 2 1 118 tonne (130 ton) 118 tonne (130 ton)

9 Feeder Vibratory 2 1 472 tonne/hr (520 tph) 472 tonne/hr (520 tph)

10 Conveyor No. 3 Belt w/ 

tripper 1 0 943 tonne/hr (1,040 tph) 943 tonne/hr (1,040 tph)

11 Crusher Tower N/A 1 0 N/A N/A

12 Coal Surge Bin w/ 

Vent Filter Dual outlet 2 0 472 tonne (520 ton) 472 tonne (520 ton)

13 Crusher Impactor 

reduction 2 0 8 cm x 0 - 3 cm x 0(3" x 0 - 1-1/4" x 0)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

14 As-Fired Coal 

Sampling System

Swing 

hammer 1 1 N/A N/A
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

209

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition

Case 6 Design 

Condition

15 Conveyor No. 4 Belt 

w/tripper 1 0 943 tonne/hr (1,040 tph) 943 tonne/hr (1,040 tph)

16 Transfer Tower No. 

2 Enclosed 1 0 N/A N/A

17 Conveyor No. 5 Belt w/ 

tripper 1 0 943 tonne/hr (1,040 tph) 943 tonne/hr (1,040 tph)

18

Coal Silo w/ Vent 

Filter and Slide 

Gates

Field 

erected 3 0 2,087 tonne (2,300 ton) 2,087 tonne (2,300 ton)

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition

Case 6 Design 

Condition

1 Feeder Vibratory 6 0 109 tonne/hr (120 tph) 109 tonne/hr (120 tph)

2 Conveyor No. 

6 Belt w/tripper 3 0 209 tonne/hr (230 tph) 209 tonne/hr (230 tph)

3 Roller Mill 

Feed Hopper Dual Outlet 3 0 417 tonne (460 ton) 417 tonne (460 ton)

4 Weigh Feeder Belt 6 0 109 tonne/hr (120 tph) 109 tonne/hr (120 tph)

5 Pulverizer Rotary 6 0 109 tonne/hr (120 tph) 109 tonne/hr (120 tph)

6 Coal Dryer 

Feed Hopper

Vertical 

Hopper 3 0 417 tonne (460 ton) 417 tonne (460 ton)

7 Coal Preheater

Water Heated 

Horizontal 

Rotary Kiln

3 0

Coal feed: 209 tonne/hr

(230 tph)

Heat duty: 23.3 GJ/hr 

(22.1 MMBtu/hr)

Coal feed: 209 tonne/hr

(230 tph)

Heat duty: 23.3 GJ/hr 

(22.1 MMBtu/hr)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

210

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition

Case 6 Design 

Condition

8 Coal Dryer

Fluidized Bed 

with Internal 

Coils

3 0

Coal feed: 209 tonne/hr

(230 tph)

Heat duty: 117 GJ/hr 

(111 MMBtu/hr)

Bed diameter: 14.9 m 

(49 ft)

Coal feed: 209 tonne/hr

(230 tph)

Heat duty: 117 GJ/hr 

(111 MMBtu/hr)

Bed diameter: 14.9 m 

(49 ft)

9 Steam 

Compressor

Reciprocating, 

Multi-Stage 3 0

878 m3/min 

(30,990 scfm)

Suction - 0.10 MPa 

(13.8 psia)

Discharge - 0.77 MPa 

(112 psia)

878 m3/min 

(30,990 scfm)

Suction - 0.09 MPa 

(13 psia)

Discharge - 0.73 MPa 

(105 psia)

10 Dryer Exhaust 

Filter Hot Baghouse 3 0

Steam - 44,044 kg/hr 

(97,100 lb/hr)

Temperature - 107°C 

(225°F)

Steam - 44,044 kg/hr 

(97,100 lb/hr)

Temperature - 107°C 

(225°F)

11 Dry Coal 

Cooler

Water Cooled 

Horizontal 

Rotary Kiln

3 0

165 tonne/hr (182 tph)

Heat duty - 10 GJ/hr 

(9 MMBtu/hr)

165 tonne/hr (182 tph)

Heat duty - 10 GJ/hr 

9 MMBtu/hr)

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition Case 6 Design Condition

1

Demineralized 

Water Storage 

Tank

Vertical, 

cylindrical, 

outdoor

3 0 605,666 liters 

(160,000 gal)

605,666 liters 

(160,000 gal)

2 Condensate 

Pumps

Vertical 

canned 2 1 10,107 lpm @ 91 m H2O(2,670 gpm @ 300 ft H2O)

10,107 lpm @ 91 m H2O

(2,670 gpm @ 300 ft H2O)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

211

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition Case 6 Design Condition

3 Deaerator Horizontal 

spray type

2 0 769,293 kg/hr 

(1,696,000 lb/hr)

770,200 kg/hr 

(1,698,000 lb/hr)

4

Intermediate 

Pressure 

Feedwater 

Pump

Horizontal 

centrifugal, 

single stage

2 1

5,413 lpm @ 341 m H2O

(1,430 gpm @ 1,120 ft 

H2O)

5,451 lpm @ 341 m H2O

(1,440 gpm @ 1,120 ft 

H2O)

5

High Pressure 

Feedwater 

Pump

Barrel type,

multi-stage, 

centrifugal

2 1

HP water: 7,722 lpm @ 

1,676 m H2O (2,040 gpm 

@ 5,500 ft H2O)

HP water: 7,684 lpm @ 

1,676 m H2O (2,030 gpm 

@ 5,500 ft H2O)

6 Auxiliary Boiler

Shop 

fabricated, 

water tube

1 0

18,144 kg/hr, 2.8 MPa, 

343°C

(40,000 lb/hr, 400 psig, 

650°F)

18,144 kg/hr, 2.8 MPa, 

343°C

(40,000 lb/hr, 400 psig, 

650°F)

7 Service Air 

Compressors

Flooded 

Screw 3 1 28 m3

/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

8 Instrument Air 

Dryers

Duplex, 

regenerative 3 1 28 m3

/min (1,000 scfm) 28 m3/min (1,000 scfm)

9

Closed Cycle 

Cooling Heat 

Exchangers

Plate and 

frame 2 0 675 GJ/hr (639 MMBtu/hr) each

852 GJ/hr (808 MMBtu/hr) 

each

10

Closed Cycle 

Cooling Water 

Pumps

Horizontal 

centrifugal 2 1 241,888 lpm @ 21 m H2O(63,900 gpm @ 70 ft H2O)

305,483 lpm @ 21 m H2O

(80,700 gpm @ 70 ft H2O)

11 Engine-Driven 

Fire Pump

Vertical 

turbine, 

diesel engine

1 1 3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

212

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition Case 6 Design Condition

12 Fire Service 

Booster Pump

Two-stage 

horizontal 

centrifugal

1 1 2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

13 Raw Water 

Pumps

Stainless 

steel, single 

suction

2 1 5,110 lpm @ 18 m H2O

(1,350 gpm @ 60 ft H2O)

5,792 lpm @ 18 m H2O

(1,530 gpm @ 60 ft H2O)

14 Ground Water 

Pumps

Stainless 

steel, single 

suction

3 1 3,407 lpm @ 268 m H2O

(900 gpm @ 880 ft H2O)

3,861 lpm @ 268 m H2O

(1,020 gpm @ 880 ft H2O)

15 Filtered Water 

Pumps

Stainless 

steel, single 

suction

2 1 5,905 lpm @ 49 m H2O

(1,560 gpm @ 160 ft H2O)

5,905 lpm @ 49 m H2O

(1,560 gpm @ 160 ft H2O)

16 Filtered Water 

Tank

Vertical, 

cylindrical 2 0 2,831,488 liter (748,000 gal)

2,831,488 liter (748,000 

gal)

17 Makeup Water 

Demineralizer

Anion, 

cation, and 

mixed bed

4 0 1,401 lpm (370 gpm) 1,401 lpm (370 gpm)

18

Liquid Waste 

Treatment 

System

1 0 10 years, 24-hour storm 10 years, 24-hour storm
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

213

ACCOUNT 4 GASIFIER, ASU, AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition Case 6 Design Condition

1 Gasifier

Pressurized dryfeed, entrained 

bed

6 0 2,540 tonne/day, 4.2 MPa

(2,800 tpd, 615 psia)

2,540 tonne/day, 4.2 MPa

(2,800 tpd, 615 psia)

2 Synthesis 

Gas Cooler

Convective 

spiral-wound 

tube boiler

6 0 201,849 kg/hr

(445,000 lb/hr)

201,849 kg/hr

(445,000 lb/hr)

3

Syngas 

Scrubber 

Including 

Sour Water 

Stripper

Vertical upflow 6 0 201,849 kg/hr

(445,000 lb/hr)

201,849 kg/hr

(445,000 lb/hr)

4 Raw Gas 

Coolers

Shell and tube 

with condensate 

drain

12 0 423,655 kg/hr

(934,000 lb/hr)

423,655 kg/hr

(934,000 lb/hr)

5

Raw Gas 

Knockout 

Drum

Vertical with 

mist eliminator 3 0

390,997 kg/hr, 35°C, 

3.4 MPa

(862,000 lb/hr, 95°F, 

490 psia)

390,997 kg/hr, 35°C, 

3.4 MPa

(862,000 lb/hr, 95°F, 

495 psia)

6 Flare Stack

Self-supporting, 

carbon steel, 

stainless steel 

top, pilot 

ignition

3 0 404,151 kg/hr

(891,000 lb/hr) syngas

404,151 kg/hr

(891,000 lb/hr) syngas

7

ASU Main 

Air 

Compressor

Centrifugal, 

multi-stage 3 0 7,419 m3

/min @ 1.3 MPa

(262,000 scfm @ 190 psia)

7,419 m3/min @ 1.3 MPa

(262,000 scfm @ 190 psia)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

214

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition Case 6 Design Condition

8 Cold Box Vendor design 3 0 2,994 tonne/day (3,300 

tpd) of 99% purity oxygen

2,994 tonne/day (3,300 

tpd) of 99% purity oxygen

9 Oxygen 

Compressor

Centrifugal, 

multi-stage 3 0

1,501 m3/min 

(53,000 scfm)

Suction - 0.9 MPa 

(130 psia)

Discharge - 5.1 MPa 

(740 psia)

1,501 m3/min 

(53,000 scfm)

Suction - 0.9 MPa 

(130 psia)

Discharge - 5.1 MPa 

(740 psia)

10

CO2 Solid 

Feed System 

Compressor

Centrifugal, 

multi-stage 3 0

595 m3/min (21,000 scfm)

Suction - 1.0 MPa 

(150 psia)

Discharge - 5.7 MPa 

(820 psia)

595 m3/min (21,000 scfm)

Suction - 5.2 MPa 

(750 psia)

Discharge - 5.7 MPa 

(820 psia)

ACCOUNT 5A SYNGAS CLEANUP

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition Case 6 Design Condition

1 Mercury 

Adsorber

Sulfated carbon 

bed 3 0

390,997 kg/hr

(862,000 lb/hr) 

35°C (95°F) 

3.3 MPa (485 psia)

390,997 kg/hr

(862,000 lb/hr) 

35°C (95°F) 

3.4 MPa (490 psia)

2 ZnO Guard 

Bed

Fixed bed 444 Nm3/min

(15,684 acfm)

444 Nm3/min

(15,672 acfm)

3 Sulfur Plant Claus type 2 0 54 tonne/day (60 tpd) 54 tonne/day (60 tpd)

4 Water Gas 

Shift Reactor

Fixed bed, 

catalytic 3 0

443,160 kg/hr

(977,000 lb/hr) 

232°C (450°F) 

3.7 MPa (540 psia)

443,160 kg/hr

(977,000 lb/hr) 

232°C (450°F) 

3.7 MPa (540 psia)
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Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition Case 6 Design Condition

5

Shift Reactor 

Heat 

Recovery 

Exchanger

Shell and Tube 3 each 0

Exchanger 1: 62 GJ/hr 

(58 MMBtu/hr) 

Exchanger 2: 82 GJ/hr 

(78 MMBtu/hr) 

Exchanger 3: 17 GJ/hr 

(16 MMBtu/hr)

Exchanger 1: 62 GJ/hr 

(58 MMBtu/hr) 

Exchanger 2: 82 GJ/hr 

(78 MMBtu/hr) 

Exchanger 3: 17 GJ/hr 

(16 MMBtu/hr)

6

Acid Gas 

Removal 

Plant

Two-stage 

Selexol 3 0

398,708 kg/hr

(879,000 lb/hr) 

34°C (94°F) 

3.3 MPa (475 psia)

398,708 kg/hr

(879,000 lb/hr) 

34°C (94°F) 

3.3 MPa (480 psia)

7 Hydrogenati

on Reactor

Fixed bed, 

catalytic 2 0

13,571 kg/hr (29,919 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

13,555 kg/hr (29,883 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

8

Tail Gas 

Recycle 

Compressor

Centrifugal 2 0

11,284 kg/hr (24,878 lb/hr) 11,279 kg/hr (24,865 lb/hr)

ACCOUNT 5B CO2 COMPRESSION

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition

Case 6 Design 

Condition

1 CO2

Compressor

Integrally geared, 

multi-stage 

centrifugal

4 0 N/A

1,699 m3/min @ 15.3 

MPa (60,000 scfm @ 

2,215 psia)
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ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition

Case 6 Design 

Condition

1 Combustion

Turbine N/A N/A N/A N/A N/A

2

Combustion

Turbine 

Generator

N/A N/A N/A N/A N/A

ACCOUNT 7 DUCTING & STACK

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition

Case 6 Design 

Condition

1 Stack CS plate, type 

409SS liner 1 0 76 m (250 ft) high x2.1 m (7 ft) diameter

76 m (250 ft) high x

0.6 m (2 ft) diameter

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition

Case 6 Design 

Condition

1 Steam 

Turbine

Commercially 

available 1 0

318 MW 12.4 MPa/

/566°C (1800 psig/ 

1050°F)

318 MW 12.4 MPa/

566°C (1800 psig/ 

1050°F)

2

Steam 

Turbine 

Generator

Hydrogen 

cooled, static 

excitation

1 0

350 MVA @ 0.9 p.f.,

24 kV, 60 Hz, 3-phase

350 MVA @ 0.9 p.f.,

24 kV, 60 Hz, 3-phase
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Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition

Case 6 Design 

Condition

3 Surface 

Condenser

Single pass, 

divided 

waterbox 

including 

vacuum pumps

1 0

886 GJ/hr 

(840 MMBtu/hr), 

Condensing temperature 

32°C (90°F), I

nlet water temperature 

9°C (48°F), 

Water temperature rise 

11°C (20°F)

886 GJ/hr 

(840 MMBtu/hr), 

Condensing temperature 

32°C (90°F), 

Inlet water temperature 

9°C (48°F), 

Water temperature rise 

11°C (20°F)

4 Air-cooled 

Condenser --- 1 0

886 GJ/hr 

(840 MMBtu/hr), 

Condensing temperature 

32°C (90°F), 

Ambient temperature 

6°C (42°F)

886 GJ/hr 

(840 MMBtu/hr), 

Condensing temperature 

32°C (90°F), 

Ambient temperature 

6°C (42°F)

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition

Case 6 Design 

Condition

1 Circulating 

Water Pumps

Vertical, wet 

pit 2 1 454,249 lpm @ 30 m(120,000 gpm @ 100 ft)

518,601 lpm @ 30 m

(137,000 gpm @ 100 ft)

2 Cooling 

Tower

Evaporative, 

mechanical 

draft, multicell

1 0

3°C (37°F) wet bulb / 

9°C (48°F) CWT / 20°C

(68°F) HWT / 2,543 

GJ/hr (2,410 MMBtu/hr) 

heat duty

3°C (37°F) wet bulb / 

9°C (48°F) CWT / 20°C

(68°F) HWT / 2,901 

GJ/hr (2,750 MMBtu/hr) 

heat duty
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ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition Case 6 Design Condition

1 Slag Quench 

Tank Water bath 6 0 170,344 liters (45,000 gal) 170,344 liters (45,000 gal)

2 Slag Crusher Roll 6 0 9 tonne/hr (10 tph) 9 tonne/hr (10 tph)

3 Slag 

Depressurizer Proprietary 6 0 9 tonne/hr (10 tph) 9 tonne/hr (10 tph)

4 Slag Receiving 

Tank

Horizontal, 

weir 6 0 102,206 liters (27,000 gal) 102,206 liters (27,000 gal)

5 Black Water 

Overflow Tank

Shop 

fabricated 6 0 45,425 liters (12,000 gal) 45,425 liters (12,000 gal)

6 Slag Conveyor Drag chain 6 0 9 tonne/hr (10 tph) 9 tonne/hr (10 tph)

7

Slag 

Separation 

Screen

Vibrating 6 0 9 tonne/hr (10 tph) 9 tonne/hr (10 tph)

8 Coarse Slag 

Conveyor Belt/bucket 6 0 9 tonne/hr (10 tph) 9 tonne/hr (10 tph)

9 Fine Ash 

Settling Tank

Vertical, 

gravity 6 0 143,846 liters (38,000 gal) 143,846 liters (38,000 gal)

10 Fine Ash 

Recycle Pumps

Horizontal 

centrifugal 6 3 38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

11 Grey Water 

Storage Tank Field erected 6 0 45,425 liters (12,000 gal) 45,425 liters (12,000 gal)

12 Grey Water 

Pumps Centrifugal 6 3 151 lpm @ 433 m H2O

(40 gpm @ 1,420 ft H2O)

151 lpm @ 433 m H2O

(40 gpm @ 1,420 ft H2O)

13 Slag Storage 

Bin

Vertical, field 

erected 6 0 635 tonne (700 tons) 635 tonne (700 tons)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition Case 6 Design Condition

14 Unloading 

Equipment

Telescoping 

chute 2 0 109 tonne/hr (120 tph) 109 tonne/hr (120 tph)

ACCOUNT 11 SNG PRODUCTION/METHANATION SYSTEM

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition Case 6 Design Condition

1

Methanation 

Reactor 

Preheater 

Shell and 

Tube 3 0 95 GJ/hr (90 MMBtu/hr) 95 GJ/hr (90 MMBtu/hr)

2 Methanation 

Reactor 1

Fixed Bed, 

catalytic 3 0

480,354 kg/hr

(1,059,000 lb/hr) 

699°C (1,290°F) 

3.2 MPa (470 psia)

474,004 kg/hr

(1,045,000 lb/hr) 

699°C (1,290°F) 

3.2 MPa (470 psia)

3

Methanation 

Reactor 

Superheater 1

Shell and 

Tube 3 0 433 GJ/hr (410 MMBtu/hr) 431 GJ/hr (408 MMBtu/hr)

4

Methanation 

Reactor 

Intercooler 2

Shell and 

Tube 3 0 86 GJ/hr (82 MMBtu/hr) 85 GJ/hr (81 MMBtu/hr)

5 Methanation 

Reactor 2

Fixed Bed, 

catalytic 3 0

124,738 kg/hr

(275,000 lb/hr) 

554°C (1,030°F) 

3.1 MPa ( psia)

124,738 kg/hr

(275,000 lb/hr) 

560°C (1,040°F) 

3.1 MPa ( psia)

6

Methanation 

Reactor 

Intercooler 3

Shell and 

Tube 3 0 29 GJ/hr (28 MMBtu/hr) 29 GJ/hr (28 MMBtu/hr)
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Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition Case 6 Design Condition

7 Methanation 

Reactor 3

Fixed Bed, 

catalytic 3 0

124,738 kg/hr

(275,000 lb/hr) 

338°C (640°F) 

3.0 MPa (440 psia)

124,738 kg/hr

(275,000 lb/hr) 

343°C (650°F) 

3.0 MPa (440 psia)

8

Methanation 

Reactor 

Intercooler 4

Shell and 

Tube 3 0 39 GJ/hr (37 MMBtu/hr) 40 GJ/hr (38 MMBtu/hr)

9

Methanation 

Reactor 

Intercooler 5

Shell and 

Tube 3 0 66 GJ/hr (62 MMBtu/hr) 66 GJ/hr (62 MMBtu/hr)

10 SNG Purification 

Condenser 1

Shell and 

Tube 3 0 54 GJ/hr (51 MMBtu/hr) 54 GJ/hr (51 MMBtu/hr)

11 SNG Purification 

Condenser 2

Shell and 

Tube 3 0 33 GJ/hr (31 MMBtu/hr) 33 GJ/hr (31 MMBtu/hr)

12

Methanation 

Recycle 

Compressor

Centrifugal 3 1

8,634 m3/min 

(304,900 scfm)

Suction - 3.1 MPa 

(453 psia)

Discharge - 3.3 MPa 

475 psia)

8,506 m3/min 

(300,400 scfm)

Suction - 3.1 MPa 

(453 psia)

Discharge - 3.3 MPa 

(475 psia)

13

Molecular Sieve 

Purification 

Reactor

Fixed bed 6 0

35,834 kg/hr (79,000 lb/hr)

35°C (95°F) 

2.8 MPa (401 psia)

35,834 kg/hr (79,000 lb/hr)

35°C (95°F) 

2.8 MPa (401 psia)

14 SNG Product 

Compressor

Centrifugal, 

Multi-staged 3 1

1,209 m3/min

(42,700 scfm) 

2.6 MPa (381 psia) 

6.2 MPa (900 psia)

1,209 m3/min

(42,700 scfm) 

2.6 MPa (381 psia) 

6.2 MPa (900 psia)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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ACCOUNT 12 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition

Case 6 Design 

Condition

1 STG Step-up 

Transformer Oil-filled 1 0 24 kV/345 kV, 350 MVA, 3-ph, 60 Hz

345 kV/24 kV, 350 

MVA, 3-ph, 60 Hz

2 Auxiliary 

Transformer Oil-filled 1 1 24 kV/4.16 kV, 273 MVA, 3-ph, 60 Hz

24 kV/4.16 kV, 332 

MVA, 3-ph, 60 Hz

3 Low Voltage 

Transformer

Dry 

ventilated 1 1 4.16 kV/480 V, 41 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 50 

MVA, 3-ph, 60 Hz

4

STG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, 

self-cooled 1 0 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz

5 Medium Voltage 

Switchgear Metal clad 1 1 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz

6 Low Voltage 

Switchgear

Metal 

enclosed 1 1 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz

7 Emergency Diesel 

Generator

Sized for 

emergency 

shutdown

1 0 750 kW, 480 V, 3-ph, 60 

Hz

750 kW, 480 V, 3-ph, 60 

Hz
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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ACCOUNT 13 INSTRUMENTATION AND CONTROLS

Equipment 

No. Description Type Operating Qty. Spares Case 5 Design Condition

Case 6 Design 

Condition

1 DCS - Main 

Control

Monitor/keyboard; 

Operator printer 

(laser color); 

Engineering printer 

(laser B&W)

1 0

Operator 

stations/printers and 

engineering 

stations/printers

Operator 

stations/printers and 

engineering 

stations/printers

2 DCS -

Processor

Microprocessor 

with redundant 

input/output

1 0 N/A N/A

3 DCS - Data 

Highway Fiber optic 1 0 Fully redundant, 25% spare

Fully redundant, 25% 

spare
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

223

5.1.5

The cost estimating methodology was described previously in Section 

Cases 5 and 6 Cost Estimating

2.8.

The TPC organized by cost account; owner’s costs; TOC; and initial and annual O&M costs for 

the SNG plant without sequestration using Montana Rosebud PRB coal (Case 5) are shown in 

Exhibit 5-18 and Exhibit 5-19, respectively. The same data for the SNG plant with sequestration 

using Montana Rosebud PRB coal (Case 6) are shown in Exhibit 5-20 and Exhibit 5-21.

The estimated TOC of the SNG plant without carbon sequestration is 3.35 billion dollars and 

with carbon sequestration is 3.44 billion dollars. Project and process contingencies represent 

12.0 and 3.7 percent for both cases. The FYCOP is $19.15/MMBtu for the non-sequestration 

case and $21.01/MMBtu for the sequestration case as shown in Exhibit ES-6.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

224

Exhibit 5-18 Case 5 Total Plant Cost Details

Client: USDOE/NETL Report Date: 2010-Feb-18

Project: Cost & Performance Baseline for Fossil Energy Plants Vol.2

Case: Case 5 - Siemens Quench SNG Production w/o CO2

Plant Size: 54.43 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $6,758 $0 $3,303 $0 $0 $10,061 $901 $0 $2,192 $13,155

1.2 Coal Stackout & Reclaim $8,733 $0 $2,117 $0 $0 $10,851 $951 $0 $2,360 $14,162

1.3 Coal Conveyors & Yd Crush $8,120 $0 $2,095 $0 $0 $10,215 $897 $0 $2,222 $13,334

1.4 Other Coal Handling $2,124 $0 $485 $0 $0 $2,609 $228 $0 $567 $3,405

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $4,782 $11,959 $0 $0 $16,741 $1,605 $0 $3,669 $22,015

SUBTOTAL 1. $25,736 $4,782 $19,958 $0 $0 $50,477 $4,582 $0 $11,012 $66,071

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $110,813 $0 $16,147 $0 $0 $126,960 $11,530 $0 $27,698 $166,188

2.2 Prepared Coal Storage & Feed $5,249 $1,256 $823 $0 $0 $7,328 $627 $0 $1,591 $9,545

2.3 Dry Coal Injection System $172,735 $2,005 $16,042 $0 $0 $190,781 $16,432 $0 $41,443 $248,656

2.4 Misc.Coal Prep & Feed $2,886 $2,100 $6,297 $0 $0 $11,284 $1,037 $0 $2,464 $14,785

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $11,219 $9,211 $0 $0 $20,429 $1,892 $0 $4,464 $26,786

SUBTOTAL 2. $291,682 $16,580 $48,520 $0 $0 $356,782 $31,518 $0 $77,660 $465,959

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $3,669 $1,705 $2,068 $0 $0 $7,441 $673 $0 $1,623 $9,737

3.2 Water Makeup & Pretreating $631 $66 $353 $0 $0 $1,050 $100 $0 $345 $1,494

3.3 Other Feedwater Subsystems $3,983 $1,204 $1,970 $0 $0 $7,157 $650 $0 $1,561 $9,368

3.4 Service Water Systems $361 $744 $2,581 $0 $0 $3,685 $360 $0 $1,213 $5,258

3.5 Other Boiler Plant Systems $1,938 $751 $1,861 $0 $0 $4,549 $432 $0 $996 $5,977

3.6 FO Supply Sys & Nat Gas $102 $210 $188 $0 $0 $500 $48 $0 $110 $658

3.7 Waste Treatment Equipment $882 $0 $538 $0 $0 $1,420 $138 $0 $468 $2,026

3.8 Misc. Power Plant Equipment $1,679 $225 $862 $0 $0 $2,765 $267 $0 $910 $3,942

SUBTOTAL 3. $13,244 $4,904 $10,420 $0 $0 $28,568 $2,667 $0 $7,225 $38,460

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $324,959 $0 $150,456 $0 $0 $475,415 $42,226 $71,312 $88,343 $677,295

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $241,072 $0 w/equip. $0 $0 $241,072 $23,367 $0 $26,444 $290,883

4.4 LT Heat Recovery & FG Saturation $50,885 $0 $18,854 $0 $0 $69,739 $6,680 $0 $15,284 $91,704

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $2,286 $930 $0 $0 $3,216 $308 $0 $705 $4,229

4.7 CO2 Solid Feed System Compressors $11,668 $2,800 $4,200 $0 $0 $18,668 $1,867 $0 $4,107 $24,642

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $24,156 $13,784 $0 $0 $37,940 $3,473 $0 $10,353 $51,766

SUBTOTAL 4. $628,583 $29,242 $188,224 $0 $0 $846,050 $77,921 $71,312 $145,236 $1,140,519

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

225

Exhibit 5-18 Case 5 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $129,739 $0 $110,087 $0 $0 $239,827 $23,194 $47,965 $62,197 $373,183

5A.2 Elemental Sulfur Plant $8,452 $1,685 $10,905 $0 $0 $21,041 $2,044 $0 $4,617 $27,702

5A.3 Mercury Removal $2,420 $0 $1,841 $0 $0 $4,261 $412 $213 $977 $5,863

5A.4 Shift Reactors $10,589 $0 $4,262 $0 $0 $14,851 $1,424 $0 $3,255 $19,529

5A.5 Methanation $27,900 $11,160 $16,740 $0 $0 $55,800 $5,580 $5,580 $13,392 $80,352

5A.6 SNG Purification & Compression $19,150 $7,660 $11,490 $0 $0 $38,300 $3,830 $0 $8,426 $50,556

5A.7 Fuel Gas Piping $0 $1,711 $1,198 $0 $0 $2,910 $270 $0 $636 $3,815

5A.9 Process Interconnects $0 $12,000 $18,000 $0 $0 $30,000 $3,000 $0 $6,600 $39,600

5A.10 HGCU Foundations $0 $1,733 $1,117 $0 $0 $2,850 $262 $0 $934 $4,046

5A.11 Zinc Oxide Guard Bed $787 $0 $145 $0 $0 $932 $93 $0 $205 $1,230

SUBTOTAL 5A. $199,036 $35,949 $175,786 $0 $0 $410,771 $40,108 $53,758 $101,239 $605,876

 5B CO2 COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.2 Syngas Expander $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $334 $238 $0 $0 $572 $50 $0 $124 $746

7.4 Stack $1,465 $0 $550 $0 $0 $2,015 $193 $0 $221 $2,429

7.9 HRSG,Duct & Stack Foundations $0 $293 $282 $0 $0 $575 $54 $0 $189 $818

SUBTOTAL 7. $1,465 $627 $1,070 $0 $0 $3,162 $297 $0 $534 $3,993

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $30,976 $0 $5,362 $0 $0 $36,338 $3,487 $0 $3,982 $43,807

8.2 Turbine Plant Auxiliaries $170 $0 $494 $0 $0 $664 $65 $0 $73 $802

8.3a Condenser & Auxiliaries $3,219 $0 $1,583 $0 $0 $4,802 $461 $0 $526 $5,790

8.3b Air Cooled Condenser $29,498 $0 $5,914 $0 $0 $35,412 $3,541 $0 $7,791 $46,744

8.4 Steam Piping $5,733 $0 $4,033 $0 $0 $9,765 $839 $0 $2,651 $13,255

8.9 TG Foundations $0 $1,069 $1,806 $0 $0 $2,875 $273 $0 $944 $4,092

SUBTOTAL 8. $69,595 $1,069 $19,192 $0 $0 $89,856 $8,666 $0 $15,968 $114,489
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

226

Exhibit 5-18 Case 5 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $7,073 $0 $1,287 $0 $0 $8,360 $796 $0 $1,373 $10,530

9.2 Circulating Water Pumps $1,875 $0 $87 $0 $0 $1,961 $165 $0 $319 $2,445

9.3 Circ.Water System Auxiliaries $154 $0 $22 $0 $0 $176 $17 $0 $29 $221

9.4 Circ.Water Piping $0 $6,417 $1,664 $0 $0 $8,081 $730 $0 $1,762 $10,573

9.5 Make-up Water System $348 $0 $498 $0 $0 $846 $81 $0 $185 $1,113

9.6 Component Cooling Water Sys $757 $906 $645 $0 $0 $2,308 $216 $0 $505 $3,029

9.9 Circ.Water System Foundations $0 $2,356 $4,005 $0 $0 $6,360 $603 $0 $2,089 $9,052

SUBTOTAL 9. $10,207 $9,679 $8,206 $0 $0 $28,092 $2,608 $0 $6,263 $36,963

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $38,544 $0 $38,016 $0 $0 $76,559 $7,418 $0 $8,398 $92,375

10.2 Gasifier Ash Depressurization w/10.1 $0 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 $0 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $862 $0 $938 $0 $0 $1,800 $175 $0 $296 $2,271

10.7 Ash Transport & Feed Equipment $1,156 $0 $279 $0 $0 $1,435 $134 $0 $235 $1,805

10.8 Misc. Ash Handling Equipment $1,786 $2,188 $654 $0 $0 $4,628 $440 $0 $760 $5,828

10.9 Ash/Spent Sorbent Foundation $0 $76 $96 $0 $0 $172 $16 $0 $56 $245

SUBTOTAL 10. $42,348 $2,265 $39,982 $0 $0 $84,594 $8,183 $0 $9,746 $102,524

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $428 $0 $424 $0 $0 $852 $81 $0 $93 $1,026

11.2 Station Service Equipment $5,579 $0 $503 $0 $0 $6,082 $561 $0 $664 $7,307

11.3 Switchgear & Motor Control $10,315 $0 $1,876 $0 $0 $12,191 $1,131 $0 $1,998 $15,319

11.4 Conduit & Cable Tray $0 $4,792 $15,807 $0 $0 $20,598 $1,992 $0 $5,648 $28,238

11.5 Wire & Cable $0 $9,155 $6,015 $0 $0 $15,170 $1,102 $0 $4,068 $20,340

11.6 Protective Equipment $0 $830 $3,021 $0 $0 $3,851 $376 $0 $634 $4,861

11.7 Standby Equipment $323 $0 $315 $0 $0 $639 $61 $0 $105 $804

11.8 Main Power Transformers $9,154 $0 $177 $0 $0 $9,331 $708 $0 $1,506 $11,545

11.9 Electrical Foundations $0 $192 $503 $0 $0 $695 $67 $0 $228 $990

SUBTOTAL 11. $25,800 $14,968 $28,640 $0 $0 $69,408 $6,079 $0 $14,945 $90,432

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $528 $0 $353 $0 $0 $881 $83 $44 $151 $1,160

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $351 $0 $225 $0 $0 $576 $54 $29 $132 $791

12.7 Computer & Accessories $5,617 $0 $180 $0 $0 $5,797 $532 $290 $662 $7,280

12.8 Instrument Wiring & Tubing $0 $2,845 $5,816 $0 $0 $8,661 $735 $433 $2,457 $12,286

12.9 Other I & C Equipment $4,188 $0 $2,034 $0 $0 $6,221 $585 $311 $1,068 $8,185

SUBTOTAL 12. $10,684 $2,845 $8,608 $0 $0 $22,137 $1,990 $1,107 $4,470 $29,703
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

227

Exhibit 5-18 Case 5 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $144 $3,080 $0 $0 $3,224 $320 $0 $1,063 $4,607

13.2 Site Improvements $0 $2,563 $3,406 $0 $0 $5,969 $589 $0 $1,967 $8,525

13.3 Site Facilities $4,593 $0 $4,846 $0 $0 $9,439 $931 $0 $3,111 $13,481

SUBTOTAL 13. $4,593 $2,707 $11,332 $0 $0 $18,632 $1,840 $0 $6,141 $26,613

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

14.2 Steam Turbine Building $0 $2,580 $3,675 $0 $0 $6,255 $576 $0 $1,025 $7,855

14.3 Administration Building $0 $870 $630 $0 $0 $1,500 $134 $0 $245 $1,879

14.4 Circulation Water Pumphouse $0 $160 $90 $0 $0 $250 $22 $0 $41 $312

14.5 Water Treatment Buildings $0 $527 $515 $0 $0 $1,042 $94 $0 $170 $1,307

14.6 Machine Shop $0 $445 $305 $0 $0 $750 $67 $0 $123 $939

14.7 Warehouse $0 $726 $464 $0 $0 $1,190 $105 $0 $194 $1,489

14.8 Other Buildings & Structures $0 $521 $406 $0 $0 $927 $83 $0 $202 $1,212

14.9 Waste Treating Building & Str. $0 $1,165 $2,226 $0 $0 $3,391 $316 $0 $741 $4,448

SUBTOTAL 14. $0 $6,994 $8,311 $0 $0 $15,304 $1,396 $0 $2,741 $19,441

TOTAL COST $1,322,974 $132,611 $568,248 $0 $0 $2,023,833 $187,854 $126,177 $403,179 $2,741,044

Owner's Costs

Preproduction Costs

6 Months All Labor $21,718

1 Month Maintenance Materials $3,840

1 Month Non-fuel Consumables $575

1 Month Waste Disposal $634

25% of 1 Months Fuel Cost at 100% CF $1,749

2% of TPC $54,821

Total $83,337

Inventory Capital

60 day supply of fuel and consumables at 100% CF $14,910

0.5% of TPC (spare parts) $13,705

Total $28,615

Initial Cost for Catalyst and Chemicals $15,381

Land $900

Other Owner's Costs $411,157

Financing Costs $74,008

Total Overnight Costs (TOC) $3,354,442

TASC Multiplier 1.201

Total As-Spent Cost (TASC) $4,028,684
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Exhibit 5-19 Case 5 Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 5 - Siemens Quench SNG Production w/o CO2 MWe-net: 54

SNG (MMbtu/hr): 6789 Capacity Factor (%): 90

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 2.0 2.0

 Operator 12.0 12.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 3.0 3.0

 TOTAL-O.J.'s 18.0 18.0

Annual Cost Annual Unit Cost

$ $/MMBtu

Annual Operating Labor Cost $7,102,696 $0.133

Maintenance Labor Cost $27,646,499 $0.516

Administrative & Support Labor $8,687,299 $0.162

Property Taxes and Insurance $54,820,873 $1.024

TOTAL FIXED OPERATING COSTS $98,257,367 $1.836

VARIABLE OPERATING COSTS

$/MMBtu

Maintenance Material Cost $41,469,749 $0.77474

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water(/1000 gallons) 0 3,494 1.08 $0 $1,241,581 $0.02320

Chemicals

MU & WT Chem. (lb) 0 20,817 0.17 $0 $1,183,517 $0.02211

Carbon (Mercury Removal) (lb) 223,863 383 1.05 $235,094 $132,241 $0.00247

COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000

Water Gas Shift Catalyst (ft3) 5,564 4.76 498.83 $2,775,453 $780,596 $0.01458

ZnO Sorbent (ton) 58 0.20 12,574.00 $723,651 $814,107 $0.01521

Methanation Catalyst (ft3) 12,183 9.27 440.00 $5,360,314 $1,340,078 $0.02504

Selexol Solution (gal) 469,206 149 13.40 $6,286,534 $656,108 $0.01226

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip 1.53 131.27 $0 $66,023 $0.00123

Subtotal Chemicals $15,381,047 $4,972,671 $0.09290

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000

Supplemental Electricity (for consumption) (MW 0 0 61.60 $0 $0 $0.00000

Gases,N2 etc. (/100scf) 0 0 0.00 $0 $0 $0.00000

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 $0.00000

Subtotal Other $0 $0 $0.00000

Waste Disposal

Spent Mercury Catalyst (lb.) 0 383 0.42 $0 $52,520 $0.00098

Spent ZnO Sorbent (ton) 0 0.20 16.23 $0 $1,051 $0.00002

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 1,275 16.23 $0 $6,796,412 $0.12697

 Subtotal-Waste Disposal $0 $6,849,982 $0.12797

By-products & Emissions 

Sulfur (tons) 0 108 0.00 $0 $0 $0.00000

Supplemental Electricity (for sale) (MWh) 0 1,306 58.00 $0 -$24,889,315 -$0.46498

Subtotal By-Products $0 -$24,889,315 -$0.46498

TOTAL VARIABLE OPERATING COSTS $15,381,047 $29,644,668 $0.55382

Fuel (ton) 0 15,112 15.22 $0 $75,540,499 $1.41125
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

229

Exhibit 5-20 Case 6 Total Plant Cost Details

Client: USDOE/NETL Report Date: 2010-Feb-18

Project: Cost & Performance Baseline for Fossil Energy Plants Vol.2

Case: Case 6 - Siemens Quench SNG Production w/ CO2

Plant Size: 1.81 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $6,758 $0 $3,303 $0 $0 $10,061 $901 $0 $2,192 $13,155

1.2 Coal Stackout & Reclaim $8,733 $0 $2,117 $0 $0 $10,851 $951 $0 $2,360 $14,162

1.3 Coal Conveyors & Yd Crush $8,120 $0 $2,095 $0 $0 $10,215 $897 $0 $2,222 $13,334

1.4 Other Coal Handling $2,124 $0 $485 $0 $0 $2,609 $228 $0 $567 $3,405

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $4,782 $11,959 $0 $0 $16,741 $1,605 $0 $3,669 $22,015

SUBTOTAL 1. $25,736 $4,782 $19,958 $0 $0 $50,477 $4,582 $0 $11,012 $66,071

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $110,813 $0 $16,147 $0 $0 $126,960 $11,530 $0 $27,698 $166,188

2.2 Prepared Coal Storage & Feed $5,249 $1,256 $823 $0 $0 $7,328 $627 $0 $1,591 $9,545

2.3 Dry Coal Injection System $172,735 $2,005 $16,042 $0 $0 $190,781 $16,432 $0 $41,443 $248,656

2.4 Misc.Coal Prep & Feed $2,886 $2,100 $6,297 $0 $0 $11,284 $1,037 $0 $2,464 $14,785

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $11,219 $9,211 $0 $0 $20,429 $1,892 $0 $4,464 $26,786

SUBTOTAL 2. $291,682 $16,580 $48,520 $0 $0 $356,782 $31,518 $0 $77,660 $465,959

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $3,662 $1,702 $2,064 $0 $0 $7,428 $671 $0 $1,620 $9,719

3.2 Water Makeup & Pretreating $690 $72 $386 $0 $0 $1,148 $109 $0 $377 $1,635

3.3 Other Feedwater Subsystems $3,976 $1,202 $1,966 $0 $0 $7,144 $649 $0 $1,559 $9,351

3.4 Service Water Systems $395 $814 $2,824 $0 $0 $4,032 $393 $0 $1,328 $5,753

3.5 Other Boiler Plant Systems $2,120 $822 $2,036 $0 $0 $4,978 $472 $0 $1,090 $6,540

3.6 FO Supply Sys & Nat Gas $102 $210 $188 $0 $0 $500 $48 $0 $110 $658

3.7 Waste Treatment Equipment $965 $0 $589 $0 $0 $1,554 $151 $0 $512 $2,217

3.8 Misc. Power Plant Equipment $1,679 $225 $862 $0 $0 $2,765 $267 $0 $910 $3,942

SUBTOTAL 3. $13,589 $5,046 $10,915 $0 $0 $29,550 $2,761 $0 $7,504 $39,816

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $324,934 $0 $150,445 $0 $0 $475,379 $42,223 $71,307 $88,336 $677,245

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $241,072 $0 w/equip. $0 $0 $241,072 $23,367 $0 $26,444 $290,883

4.4 LT Heat Recovery & FG Saturation $50,884 $0 $18,854 $0 $0 $69,738 $6,680 $0 $15,284 $91,702

4.5 Misc. Gasification Equipment w/4.1 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.6 Other Gasification Equipment $0 $2,285 $930 $0 $0 $3,215 $308 $0 $705 $4,228

4.7 CO2 Solid Feed System Compressors $7,427 $1,782 $2,674 $0 $0 $11,883 $1,188 $0 $2,614 $15,685

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $24,156 $13,784 $0 $0 $37,940 $3,473 $0 $10,353 $51,766

SUBTOTAL 4. $624,317 $28,224 $186,685 $0 $0 $839,226 $77,240 $71,307 $143,736 $1,131,508

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

230

Exhibit 5-20 Case 6 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $129,739 $0 $110,087 $0 $0 $239,826 $23,194 $47,965 $62,197 $373,182

5A.2 Elemental Sulfur Plant $8,455 $1,685 $10,909 $0 $0 $21,049 $2,045 $0 $4,619 $27,713

5A.3 Mercury Removal $2,401 $0 $1,827 $0 $0 $4,229 $408 $211 $970 $5,818

5A.4 Shift Reactors $10,434 $0 $4,200 $0 $0 $14,633 $1,403 $0 $3,207 $19,243

5A.5 Methanation $27,400 $10,960 $16,440 $0 $0 $54,800 $5,480 $5,480 $13,152 $78,912

5A.6 SNG Purification & Compression $19,150 $7,660 $11,490 $0 $0 $38,300 $3,830 $0 $8,426 $50,556

5A.7 Fuel Gas Piping $0 $1,710 $1,198 $0 $0 $2,908 $270 $0 $635 $3,813

5A.9 Process Interconnects $0 $12,000 $18,000 $0 $0 $30,000 $3,000 $0 $6,600 $39,600

5A.10 HGCU Foundations $0 $1,732 $1,117 $0 $0 $2,848 $262 $0 $933 $4,043

5A.11 Zinc Oxide Guard Bed $786 $0 $145 $0 $0 $931 $93 $0 $205 $1,229

SUBTOTAL 5A. $198,366 $35,747 $175,412 $0 $0 $409,525 $39,984 $53,657 $100,944 $604,110

 5B CO2 COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $36,117 $0 $21,269 $0 $0 $57,386 $5,525 $0 $12,582 $75,493

SUBTOTAL 5B. $36,117 $0 $21,269 $0 $0 $57,386 $5,525 $0 $12,582 $75,493

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.2 Syngas Expander $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.9 HRSG, Duct & Stack Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 7. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $30,976 $0 $5,362 $0 $0 $36,338 $3,487 $0 $3,982 $43,807

8.2 Turbine Plant Auxiliaries $169 $0 $494 $0 $0 $663 $65 $0 $73 $801

8.3a Condenser & Auxiliaries $3,219 $0 $1,583 $0 $0 $4,802 $461 $0 $526 $5,790

8.3b Air Cooled Condenser $29,498 $0 $5,914 $0 $0 $35,412 $3,541 $0 $7,791 $46,744

8.4 Steam Piping $5,722 $0 $4,025 $0 $0 $9,747 $837 $0 $2,646 $13,230

8.9 TG Foundations $0 $1,069 $1,806 $0 $0 $2,875 $273 $0 $944 $4,092

SUBTOTAL 8. $69,584 $1,069 $19,184 $0 $0 $89,837 $8,664 $0 $15,963 $114,464
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

231

Exhibit 5-20 Case 6 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $7,758 $0 $1,411 $0 $0 $9,169 $873 $0 $1,506 $11,549

9.2 Circulating Water Pumps $2,057 $0 $87 $0 $0 $2,143 $180 $0 $349 $2,672

9.3 Circ.Water System Auxiliaries $166 $0 $24 $0 $0 $190 $18 $0 $31 $240

9.4 Circ.Water Piping $0 $6,948 $1,801 $0 $0 $8,749 $791 $0 $1,908 $11,448

9.5 Make-up Water System $376 $0 $537 $0 $0 $913 $88 $0 $200 $1,200

9.6 Component Cooling Water Sys $820 $981 $698 $0 $0 $2,499 $234 $0 $547 $3,280

9.9 Circ.Water System Foundations $0 $2,550 $4,335 $0 $0 $6,884 $653 $0 $2,261 $9,798

SUBTOTAL 9. $11,177 $10,479 $8,893 $0 $0 $30,549 $2,836 $0 $6,802 $40,187

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $38,544 $0 $38,016 $0 $0 $76,559 $7,418 $0 $8,398 $92,375

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $862 $0 $938 $0 $0 $1,800 $175 $0 $296 $2,271

10.7 Ash Transport & Feed Equipment $1,156 $0 $279 $0 $0 $1,435 $134 $0 $235 $1,805

10.8 Misc. Ash Handling Equipment $1,786 $2,188 $654 $0 $0 $4,628 $440 $0 $760 $5,828

10.9 Ash/Spent Sorbent Foundation $0 $76 $96 $0 $0 $172 $16 $0 $56 $245

SUBTOTAL 10. $42,348 $2,265 $39,982 $0 $0 $84,594 $8,183 $0 $9,746 $102,524

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $428 $0 $424 $0 $0 $852 $81 $0 $93 $1,026

11.2 Station Service Equipment $6,060 $0 $546 $0 $0 $6,606 $609 $0 $721 $7,936

11.3 Switchgear & Motor Control $11,203 $0 $2,037 $0 $0 $13,240 $1,228 $0 $2,170 $16,638

11.4 Conduit & Cable Tray $0 $5,204 $17,168 $0 $0 $22,372 $2,164 $0 $6,134 $30,670

11.5 Wire & Cable $0 $9,943 $6,533 $0 $0 $16,476 $1,197 $0 $4,418 $22,092

11.6 Protective Equipment $0 $830 $3,021 $0 $0 $3,851 $376 $0 $634 $4,861

11.7 Standby Equipment $323 $0 $315 $0 $0 $639 $61 $0 $105 $804

11.8 Main Power Transformers $9,866 $0 $177 $0 $0 $10,043 $762 $0 $1,621 $12,425

11.9 Electrical Foundations $0 $192 $503 $0 $0 $695 $67 $0 $228 $990

SUBTOTAL 11. $27,880 $16,169 $30,724 $0 $0 $74,773 $6,544 $0 $16,125 $97,443

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $525 $0 $351 $0 $0 $876 $83 $44 $150 $1,152

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $349 $0 $223 $0 $0 $572 $54 $29 $131 $786

12.7 Computer & Accessories $5,579 $0 $179 $0 $0 $5,758 $529 $288 $657 $7,232

12.8 Instrument Wiring & Tubing $0 $2,826 $5,778 $0 $0 $8,604 $730 $430 $2,441 $12,205

12.9 Other I & C Equipment $4,160 $0 $2,020 $0 $0 $6,180 $581 $309 $1,061 $8,131

SUBTOTAL 12. $10,613 $2,826 $8,550 $0 $0 $21,989 $1,977 $1,099 $4,440 $29,505
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

232

Exhibit 5-20 Case 6 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $144 $3,080 $0 $0 $3,224 $320 $0 $1,063 $4,607

13.2 Site Improvements $0 $2,563 $3,406 $0 $0 $5,969 $589 $0 $1,967 $8,525

13.3 Site Facilities $4,593 $0 $4,846 $0 $0 $9,439 $931 $0 $3,111 $13,481

SUBTOTAL 13. $4,593 $2,707 $11,332 $0 $0 $18,632 $1,840 $0 $6,141 $26,613

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

14.2 Steam Turbine Building $0 $2,580 $3,675 $0 $0 $6,255 $576 $0 $1,025 $7,855

14.3 Administration Building $0 $870 $630 $0 $0 $1,500 $134 $0 $245 $1,879

14.4 Circulation Water Pumphouse $0 $160 $90 $0 $0 $250 $22 $0 $41 $312

14.5 Water Treatment Buildings $0 $577 $563 $0 $0 $1,140 $103 $0 $186 $1,430

14.6 Machine Shop $0 $445 $305 $0 $0 $750 $67 $0 $123 $939

14.7 Warehouse $0 $726 $464 $0 $0 $1,190 $105 $0 $194 $1,489

14.8 Other Buildings & Structures $0 $521 $406 $0 $0 $927 $83 $0 $202 $1,212

14.9 Waste Treating Building & Str. $0 $1,165 $2,226 $0 $0 $3,391 $316 $0 $741 $4,448

SUBTOTAL 14. $0 $7,043 $8,359 $0 $0 $15,403 $1,405 $0 $2,757 $19,564

TOTAL COST $1,356,002 $132,937 $589,783 $0 $0 $2,078,723 $193,059 $126,063 $415,413 $2,813,258

Owner's Costs

Preproduction Costs

6 Months All Labor $21,702

1 Month Maintenance Materials $3,836

1 Month Non-fuel Consumables $630

1 Month Waste Disposal $634

25% of 1 Months Fuel Cost at 100% CF $1,749

2% of TPC $56,265

Total $84,817

Inventory Capital

60 day supply of fuel and consumables at 100% CF $14,989

0.5% of TPC (spare parts) $14,066

Total $29,055

Initial Cost for Catalyst and Chemicals $16,334

Land $900

Other Owner's Costs $421,989

Financing Costs $75,958

Total Overnight Costs (TOC) $3,442,310

TASC Multiplier 1.201

Total As-Spent Cost (TASC) $4,134,215
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

233

Exhibit 5-21 Case 6 Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 6 - Siemens Quench SNG Production w/ CO2 MWe-net: 2

SNG (MMbtu/hr): 6784 Capacity Factor (%): 90

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 2.0 2.0

 Operator 12.0 12.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 3.0 3.0

 TOTAL-O.J.'s 18.0 18.0

Annual Cost Annual Unit Cost

$ $/MMBtu

Annual Operating Labor Cost $7,102,696 $0.133

Maintenance Labor Cost $27,620,931 $0.516

Administrative & Support Labor $8,680,907 $0.162

Property Taxes and Insurance $56,265,151 $1.052

TOTAL FIXED OPERATING COSTS $99,669,685 $1.863

VARIABLE OPERATING COSTS

$/MMBtu

Maintenance Material Cost $41,431,397 $0.77459

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water(/1000 gallons) 0 3,966 1.08 $0 $1,409,411 $0.02635

Chemicals

MU & WT Chem.(lb) 0 23,631 0.17 $0 $1,343,498 $0.02512

Carbon (Mercury Removal) (lb) 221,425 379 1.05 $232,533 $130,800 $0.00245

COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000

Water Gas Shift Catalyst (ft3) 7,553 6.47 498.83 $3,767,548 $1,059,623 $0.01981

ZnO Sorbent (ton) 57 0.20 12,574.00 $721,842 $812,073 $0.01518

Methanation Catalyst (ft3) 12,102 9.21 440.00 $5,324,846 $1,331,211 $0.02489

Selexol Solution (gal) 469,270 149 13.40 $6,287,392 $656,198 $0.01227

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip 1.53 131.27 $0 $66,058 $0.00124

Subtotal Chemicals $16,334,162 $5,399,462 $0.10095

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000

Supplemental Electricity (for consumption) (MW 0 0 61.60 $0 $0 $0.00000

Gases,N2 etc.(/100scf) 0 0 0.00 $0 $0 $0.00000

L.P. Steam(/1000 pounds) 0 0 0.00 $0 $0 $0.00000

Subtotal Other $0 $0 $0.00000

Waste Disposal

Spent Mercury Catalyst (lb.) 0 379 0.42 $0 $51,948 $0.00097

Spent ZnO Sorbent (ton) 0 0.20 16.23 $0 $1,048 $0.00002

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 1,275 16.23 $0 $6,796,412 $0.12706

 Subtotal-Waste Disposal $0 $6,849,407 $0.12805

By-products & Emissions 

Sulfur (tons) 0 108 0.00 $0 $0 $0.00000

Supplemental Electricity (for sale) (MWh) 0 43 58.00 $0 -$827,662 -$0.01547

Subtotal By-Products $0 -$827,662 -$0.01547

TOTAL VARIABLE OPERATING COSTS $16,334,162 $54,262,014 $1.01446

Fuel (ton) 0 15,112 15.22 $0 $75,540,499 $1.41228
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

234

5.2 SYNTHETIC NATURAL GAS PRODUCTION USING NORTH DAKOTA 

LIGNITE COAL

5.2.1

In this section the overall Siemens gasification process for SNG production using NDL coal is 

described. The plant configurations are similar to Cases 5 and 6, with the exception of the coal 

type utilized. Since the carbon content of the lignite coal used is lower than that of the 

bituminous coal and subbituminous, the coal feed rate is significantly increased. The process 

BFDs for the lignite coal non-sequestration and sequestration cases are shown in 

Process Description

Exhibit 5-22

and Exhibit 5-24. The associated stream tables are shown in Exhibit 5-23 for the nonsequestration case and Exhibit 5-25 for the sequestration case.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

235

Exhibit 5-22 Case 7 Block Flow Diagram, North Dakota Lignite Coal to SNG without Carbon Sequestration

PARTIAL RAW

GAS QUENCH

AND COOLING

WATER-GAS

SHIFT REACTORS

& GAS COOLING

WATER

SCRUBBER

ELEVATED

PRESSURE

ASU

SIEMENS

GASIFIER

MERCURY

REMOVAL

DUALSTAGE

SELEXOL

UNIT

CLAUS

PLANT

1

AIR TO ASU

2 3

VENT

GAS

SULFUR

PLANT

OXIDANT

4

10

GASIFIER

OXIDANT

SLAG

13

27

28

HYDROGENATION

REACTOR

29

CLEAN

GAS

SULFUR

PRODUCT

SYNGAS

12

TO SOUR

WATER

STRIPPER

16

15

CO2

VENT

SHIFT

STEAM

30

11

QUENCH

WATER

14

17

METHANATION

REACTORS

22

SNG 

PURIFICATION

24

SNG FOR

EXPORT

23 PURIFICATION

OFF-GAS

19

20

PILOT 21

FUEL

WGS 

BYPASS

STEAM

TURBINE

31 32

PROCESS

STEAM

CONDENSATE

18

SNG 

COMPRESSION 25

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown. See H&MB diagram for more detail.

7

DRIED

COAL

WTA

COAL

DRYER

5

WET

COAL

6

WATER

8

LOCKHOPPER

TRANSPORT

CO2

9

VENT

8

TRANSPORT

CO2

26
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

236

Exhibit 5-23 Case 7 Stream Table, North Dakota Lignite Coal to SNG without Carbon Sequestration

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

V-L Mole Fraction

Ar 0.0093 0.0091 0.0101 0.0101 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0021 0.0022 0.0022 0.0022 0.0000 0.0022

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0097 0.0013 0.0000 0.0000 0.4252 0.4405 0.4405 0.4405 0.0000 0.1549

CO2 0.0003 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.9785 0.1363 0.0000 0.0000 0.0718 0.0744 0.0744 0.0744 0.0000 0.3705

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0003 0.0003 0.0003 0.0003 0.0000 0.0001

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0103 0.5349 0.0000 0.0000 0.1607 0.1665 0.1665 0.1665 0.0000 0.4644

H2O 0.0064 0.0026 0.0000 0.0000 0.0000 1.0000 0.0000 0.0013 0.1899 0.0000 1.0000 0.3344 0.3103 0.3103 0.3103 1.0000 0.0018

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0024 0.0025 0.0025 0.0025 0.0000 0.0027

N2 0.7759 0.9803 0.0004 0.0004 0.0000 0.0000 0.0000 0.0000 0.0088 0.0000 0.0000 0.0032 0.0033 0.0033 0.0033 0.0000 0.0033

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.2081 0.0076 0.9895 0.9895 0.0000 0.0000 0.0000 0.0000 0.1288 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 52,805 41,791 79 10,707 0 10,782 0 5,042 18,101 0 12,568 51,888 50,077 5,789 44,288 14,233 49,085

V-L Flowrate (kg/hr) 1,525,805 1,175,700 2,547 343,453 0 194,238 0 218,763 269,759 0 226,410 1,125,307 1,092,655 126,310 966,345 256,405 1,074,648

Solids Flowrate (kg/hr) 0 0 0 0 709,841 0 515,603 0 355,226 71,414 0 0 0 0 0 0 0

Temperature (°C) 6 26 32 32 4 33 71 76 18 1,427 216 260 215 215 215 288 35

Pressure (MPa, abs) 0.09 0.11 0.86 0.86 0.10 0.35 0.09 5.62 5.62 4.24 8.27 3.89 3.756 3.76 3.76 4.14 3.34

Enthalpy (kJ/kg) 15.71 30.53 26.94 26.94 --- 147.56 --- 21.89 4,183.74 --- 1,017.87 1,092.44 964.077 964.08 964.08 3,070.04 40.47

Density (kg/m3) 1.1 1.3 11.0 11.0 --- 986.2 --- 103.4 42.2 --- 782.0 19.3 20.5 20.5 20.5 18.2 29.2

V-L Molecular Weight 28.895 28.133 32.078 32.078 --- 18.015 --- 43.389 14.903 --- 18.015 21.687 21.820 21.820 21.820 18.015 21.894

V-L Flowrate (lbmol/hr) 116,415 92,133 175 23,605 0 23,770 0 11,115 39,906 0 27,707 114,394 110,400 12,762 97,638 31,378 108,214

V-L Flowrate (lb/hr) 3,363,825 2,591,975 5,614 757,185 0 428,222 0 482,290 594,716 0 499,149 2,480,878 2,408,892 278,465 2,130,426 565,276 2,369,194

Solids Flowrate (lb/hr) 0 0 0 0 1,564,932 0 1,136,710 0 783,138 157,442 0 0 0 0 0 0 0

Temperature (°F) 42 78 90 90 40 91 160 168 65 2,600 420 500 418 418 418 550 95

Pressure (psia) 13.0 16.4 125.0 125.0 13.8 50.3 13.5 815.0 815.0 614.7 1,200.0 564.7 544.7 544.7 544.7 600.0 484.7

Enthalpy (Btu/lb) 6.8 13.1 11.6 11.6 --- 63.4 --- 9.4 1,798.7 --- 437.6 469.7 414.5 414.5 414.5 1,319.9 17.4

Density (lb/ft3) 0.070 0.080 0.685 0.685 --- 61.569 --- 6.457 2.635 --- 48.817 1.203 1.282 1.282 1.282 1.135 1.822

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

237

Exhibit 5-23 Case 7 Stream Table, North Dakota Lignite Coal to SNG without Carbon Sequestration (continued)

18 19 20 21 22 23 24 25 26 27 28 29 30 31 32

V-L Mole Fraction

Ar 0.0022 0.0034 0.0034 0.0034 0.0118 0.0000 0.0138 0.0138 0.0000 0.0007 0.0000 0.0016 0.0024 0.0000 0.0000

CH4 0.0000 0.0000 0.0000 0.0000 0.8145 0.0000 0.9559 0.9559 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.1532 0.2348 0.2348 0.2348 0.0000 0.0000 0.0000 0.0000 0.0017 0.0543 0.0000 0.0861 0.0065 0.0000 0.0000

CO2 0.3756 0.0444 0.0444 0.0444 0.1478 0.9845 0.0026 0.0026 0.9925 0.5987 0.0000 0.4846 0.8126 0.0000 0.0000

COS 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0019 0.0000 0.0003 0.0000 0.0000 0.0000

H2 0.4610 0.7121 0.7121 0.7121 0.0059 0.0000 0.0069 0.0069 0.0016 0.1041 0.0000 0.0507 0.1663 0.0000 0.0000

H2O 0.0018 0.0001 0.0001 0.0001 0.0023 0.0155 0.0000 0.0000 0.0041 0.0394 0.0000 0.3691 0.0009 1.0000 1.0000

H2S 0.0028 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2003 0.0000 0.0014 0.0103 0.0000 0.0000

N2 0.0033 0.0051 0.0051 0.0051 0.0176 0.0000 0.0207 0.0207 0.0000 0.0005 0.0000 0.0007 0.0009 0.0000 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0054 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 49,657 31,944 183 31,762 9,214 1,363 7,851 7,851 11,969 701 0 820 572 40,826 56,932

V-L Flowrate (kg/hr) 1,095,675 327,418 1,874 325,544 189,733 59,420 130,313 130,313 524,399 25,095 0 25,423 21,027 735,487 1,025,654

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0 4,382 0 0 0 0

Temperature (°C) 34 31 80 31 35 35 35 35 5 48 175 232 21 566 33

Pressure (MPa, abs) 3.27 3.24 5.10 3.24 2.77 0.14 2.627 6.202 0.115 0.16 0.1 0.085 3.341 12.512 0.827

Enthalpy (kJ/kg) 39.13 83.91 228.57 83.91 39.74 45.04 47.668 12.706 7.673 98.02 --- 836.767 -9.442 3,495.174 121.037

Density (kg/m3) 28.9 13.0 17.4 13.0 23.6 2.4 17.9 44.7 2.2 2.2 5,285.7 0.6 58.2 34.9 995.1

V-L Molecular Weight 22.065 10.250 10.250 10.250 20.592 43.606 16.597 16.597 43.812 35.777 --- 30.993 36.771 18.015 18.015

V-L Flowrate (lbmol/hr) 109,475 70,425 403 70,022 20,314 3,004 17,309 17,309 26,388 1,546 0 1,808 1,261 90,005 125,515

V-L Flowrate (lb/hr) 2,415,550 721,834 4,131 717,703 418,290 130,998 287,291 287,291 1,156,103 55,324 0 56,047 46,356 1,621,472 2,261,180

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0 9,660 0 0 0 0

Temperature (°F) 94 87 177 87 95 95 95 95 42 119 347 450 69 1,050 92

Pressure (psia) 474.7 469.6 740.0 469.6 401.1 20.1 381.0 899.5 16.7 23.7 17.3 12.3 484.5 1,814.7 120.0

Enthalpy (Btu/lb) 16.8 36.1 98.3 36.1 17.1 19.4 20.5 5.5 3.3 42.1 --- 359.7 -4.1 1,502.7 52.0

Density (lb/ft3) 1.803 0.811 1.088 0.811 1.473 0.148 1.115 2.789 0.137 0.137 330 0.039 3.636 2.177 62.122
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

238

Exhibit 5-24 Case 8 Block Flow Diagram, North Dakota Lignite to SNG with Carbon Sequestration

PARTIAL RAW

GAS QUENCH

AND COOLING

WATER-GAS

SHIFT REACTORS

& GAS COOLING

WATER

SCRUBBER

ELEVATED

PRESSURE

ASU

SIEMENS

GASIFIER

MERCURY

REMOVAL

DUALSTAGE

SELEXOL

UNIT

CLAUS

PLANT

1

AIR TO ASU

2 3

VENT

GAS

SULFUR

PLANT

OXIDANT

4

10

GASIFIER

OXIDANT

SLAG

13

27

28

HYDROGENATION

REACTOR

29

CLEAN

GAS

SULFUR

PRODUCT

SYNGAS

12

TO SOUR

WATER

STRIPPER

26

16

15

CO2

PRODUCT

SHIFT

STEAM

30

11

QUENCH

WATER

14

17

METHANATION

REACTORS

22

SNG 

PURIFICATION

24

SNG FOR

EXPORT

23

PURIFICATION

OFF-GAS TO CO2

COMPRESSION

19

20

PILOT 21

FUEL

WGS 

BYPASS

8

STEAM

TURBINE

31 32

PROCESS

STEAM

CONDENSATE

18

SNG 

COMPRESSION 25

CO2 

COMPRESSION

23

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown. See H&MB diagram for more detail.

7

DRIED

COAL

WTA

COAL

DRYER

5

WET

COAL

6

WATER

8

LOCKHOPPER

TRANSPORT

CO2

9

VENT

TRANSPORT

CO2

PURIFICATION

OFF-GAS
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

239

Exhibit 5-25 Case 8 Stream Table, North Dakota Lignite Coal to SNG with Carbon Sequestration

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

V-L Mole Fraction

Ar 0.0093 0.0091 0.0101 0.0101 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0021 0.0022 0.0022 0.0022 0.0000 0.0022

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0037 0.0005 0.0000 0.0000 0.4252 0.4406 0.4406 0.4406 0.0000 0.1549

CO2 0.0003 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.9921 0.1371 0.0000 0.0000 0.0720 0.0746 0.0746 0.0746 0.0000 0.3708

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0003 0.0003 0.0003 0.0003 0.0000 0.0001

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0039 0.5346 0.0000 0.0000 0.1604 0.1663 0.1663 0.1663 0.0000 0.4642

H2O 0.0064 0.0026 0.0000 0.0000 0.0000 1.0000 0.0000 0.0001 0.1900 0.0000 1.0000 0.3344 0.3103 0.3103 0.3103 1.0000 0.0018

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0024 0.0025 0.0025 0.0025 0.0000 0.0027

N2 0.7759 0.9803 0.0004 0.0004 0.0000 0.0000 0.0000 0.0000 0.0088 0.0000 0.0000 0.0032 0.0033 0.0033 0.0033 0.0000 0.0033

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.2081 0.0076 0.9895 0.9895 0.0000 0.0000 0.0000 0.0000 0.1289 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 52,781 41,772 75 10,706 0 10,782 0 4,996 18,078 0 12,563 51,861 50,047 5,784 44,263 14,236 49,057

V-L Flowrate (kg/hr) 1,525,100 1,175,157 2,411 343,429 0 194,238 0 218,763 269,759 0 226,325 1,125,197 1,092,505 126,252 966,253 256,473 1,074,531

Solids Flowrate (kg/hr) 0 0 0 0 709,841 0 515,603 0 355,226 71,414 0 0 0 0 0 0 0

Temperature (°C) 6 26 32 32 4 33 71 75 18 1,427 216 260 215 215 215 288 35

Pressure (MPa, abs) 0.09 0.11 0.86 0.86 0.10 0.35 0.09 5.62 5.62 4.24 8.27 3.89 3.756 3.76 3.76 4.14 3.38

Enthalpy (kJ/kg) 15.71 30.53 26.94 26.94 --- 147.56 --- 18.43 4,187.50 --- 1,017.87 1,092.18 963.754 963.75 963.75 2,937.10 40.27

Density (kg/m3) 1.1 1.3 11.0 11.0 --- 986.2 --- 105.6 42.3 --- 782.0 19.3 20.5 20.5 20.5 18.2 29.5

V-L Molecular Weight 28.895 28.133 32.078 32.078 --- 18.015 --- 43.785 14.922 --- 18.015 21.696 21.830 21.830 21.830 18.015 21.904

V-L Flowrate (lbmol/hr) 116,361 92,091 166 23,603 0 23,770 0 11,015 39,856 0 27,697 114,334 110,335 12,750 97,584 31,386 108,153

V-L Flowrate (lb/hr) 3,362,271 2,590,777 5,316 757,131 0 428,222 0 482,290 594,716 0 498,960 2,480,636 2,408,561 278,337 2,130,224 565,427 2,368,935

Solids Flowrate (lb/hr) 0 0 0 0 1,564,932 0 1,136,710 0 783,138 157,442 0 0 0 0 0 0 0

Temperature (°F) 42 78 90 90 40 91 160 166 64 2,600 420 500 418 418 418 550 95

Pressure (psia) 13.0 16.4 125.0 125.0 13.8 50.3 13.5 815.0 815.0 614.7 1,200.0 564.7 544.7 544.7 544.7 600.0 489.7

Enthalpy (Btu/lb) 6.8 13.1 11.6 11.6 --- 63.4 --- 7.9 1,800.3 --- 437.6 469.6 414.3 414.3 414.3 1,262.7 17.3

Density (lb/ft3

) 0.070 0.080 0.685 0.685 --- 61.569 --- 6.593 2.642 --- 48.817 1.204 1.282 1.282 1.282 1.135 1.842

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

240

Exhibit 5-25 Case 8 Stream Table, North Dakota Lignite Coal to SNG with Carbon Sequestration (continued)

18 19 20 21 22 23 24 25 26 27 28 29 30 31 32

V-L Mole Fraction

Ar 0.0022 0.0034 0.0034 0.0034 0.0118 0.0000 0.0138 0.0138 0.0001 0.0007 0.0000 0.0016 0.0023 0.0000 0.0000

CH4 0.0000 0.0000 0.0000 0.0000 0.8138 0.0000 0.9552 0.9552 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.1532 0.2348 0.2348 0.2348 0.0000 0.0000 0.0000 0.0000 0.0037 0.0545 0.0000 0.0832 0.0072 0.0000 0.0000

CO2 0.3758 0.0444 0.0444 0.0444 0.1479 0.9845 0.0026 0.0026 0.9921 0.6020 0.0000 0.4928 0.8058 0.0000 0.0000

COS 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0019 0.0000 0.0003 0.0000 0.0000 0.0000

H2 0.4609 0.7121 0.7121 0.7121 0.0065 0.0000 0.0077 0.0077 0.0039 0.1045 0.0000 0.0519 0.1788 0.0000 0.0000

H2O 0.0017 0.0001 0.0001 0.0001 0.0023 0.0155 0.0000 0.0000 0.0001 0.0393 0.0000 0.3670 0.0009 1.0000 1.0000

H2S 0.0028 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1964 0.0000 0.0015 0.0041 0.0000 0.0000

N2 0.0033 0.0051 0.0051 0.0051 0.0176 0.0000 0.0207 0.0207 0.0000 0.0005 0.0000 0.0007 0.0009 0.0000 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 49,634 31,923 183 31,740 9,214 1,364 7,850 7,850 15,705 698 0 813 576 40,673 58,897

V-L Flowrate (kg/hr) 1,095,450 327,218 1,874 325,344 189,670 59,465 130,205 130,205 687,644 24,974 0 25,168 20,919 732,739 1,061,040

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0 4,385 0 0 0 0

Temperature (°C) 34 31 80 31 35 35 35 35 35 48 175 232 21 566 33

Pressure (MPa, abs) 3.31 3.24 5.10 3.24 2.77 0.14 2.627 6.202 15.272 0.16 0.1 0.085 3.306 12.512 0.827

Enthalpy (kJ/kg) 38.97 83.90 228.55 83.90 39.77 45.02 47.726 12.794 -209.181 97.84 --- 834.709 -8.186 3,495.174 120.935

Density (kg/m3) 29.2 13.0 17.4 13.0 23.6 2.4 17.8 44.6 780.4 2.2 5,286.1 0.6 56.4 34.9 995.1

V-L Molecular Weight 22.071 10.250 10.250 10.250 20.586 43.607 16.587 16.587 43.785 35.794 --- 30.956 36.297 18.015 18.015

V-L Flowrate (lbmol/hr) 109,424 70,378 403 69,975 20,313 3,006 17,306 17,306 34,623 1,538 0 1,792 1,271 89,669 129,845

V-L Flowrate (lb/hr) 2,415,054 721,392 4,131 717,261 418,150 131,097 287,053 287,053 1,515,996 55,059 0 55,485 46,119 1,615,412 2,339,194

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0 9,667 0 0 0 0

Temperature (°F) 94 87 177 87 95 95 95 95 95 119 347 450 69 1,050 91

Pressure (psia) 479.5 469.6 740.0 469.6 401.1 20.1 381.0 899.5 2,215.0 23.7 17.3 12.3 479.5 1,814.7 120.0

Enthalpy (Btu/lb) 16.8 36.1 98.3 36.1 17.1 19.4 20.5 5.5 -89.9 42.1 --- 358.9 -3.5 1,502.7 52.0

Density (lb/ft3

) 1.822 0.811 1.089 0.811 1.473 0.148 1.114 2.787 48.716 0.137 330 0.039 3.524 2.177 62.123
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

241

5.2.2

System assumptions for Cases 7 and 8, Siemens gasifier using NDL coal with and without

carbon sequestration, are compiled in 

Key System Assumptions

Exhibit 5-26.

Exhibit 5-26 Cases 7 and 8 Plant Study Configuration Matrix

Case Case 7 Case 8

Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O2:Coal Ratio, kg O2/kg dry coal 0.657 0.657

Carbon Conversion, % 99.9 99.9

Syngas HHV at Gasifier Outlet, 

kJ/Nm3 (Btu/scf) 9,350 (251) 9,350 (251)

Steam Cycle, MPa/°C/°C

(psig/°F/°F)

12.4/566/536 

(1800/1050/997)

12.4/566/536 

(1800/1050/997)

Condenser Pressure, mm Hg

(in Hg) 36 (1.4) 36 (1.4)

Combustion Turbine N/A N/A

Gasifier Technology Siemens Siemens

Oxidant 99 vol% Oxygen 99 vol% Oxygen

Coal ND Lignite ND Lignite

Coal Feed Moisture Content, % 36.08 36.08

COS Hydrolysis No No

Water Gas Shift Yes Yes

H2S Separation Selexol (1st Stage) Selexol (1st Stage)

Sulfur Removal, % 98.5 99.9

CO2 Separation Selexol (2nd Stage) Selexol (2nd Stage)

CO2 Sequestration, % N/A 67.2

Sulfur Recovery

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Claus Plant with Tail Gas 

Treatment / Elemental 

Sulfur

Methanation System Based on Haldor Topsoe 

TREMPTM Process

Based on Haldor Topsoe 

TREMPTM Process

Particulate Control Scrubber and AGR 

Absorber

Scrubber and AGR 

Absorber

Mercury Control Carbon Bed Carbon Bed

NOx Control N/A N/A

Balance of Plant and Sparing Philosophy

The balance of plant assumptions and sparing philosophy are common to all cases and are 

presented in Section 4.1.3.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

242

5.2.3

The Siemens SNG plant without and with carbon sequestration and using NDL coal produces a 

net output of 52 Bscf/year at 90 percent capacity. The HHV conversion efficiency of both the 

non-sequestration case and the sequestration case is 61.5 percent.

Cases 7 and 8 Performance Results

Overall performance for the two plants is summarized in Exhibit 5-27, which includes auxiliary 

power requirements and production values. The ASU accounts for approximately 58 percent of 

the total auxiliary load in non-sequestration case and 48 percent in the sequestration case, 

distributed between the main air compressor, the oxygen compressor, and ASU auxiliaries. CO2

compression accounts for about 19 percent of the auxiliary load in Case 8. The AGR process 

accounts for about 12 percent and 10 percent of the auxiliary load for the non-sequestration and 

sequestration cases, respectively. The WTA coal drying process accounts for 10 percent in the 

non-sequestration case and 8 percent in the sequestration case. All other individual auxiliary 

loads are less than 3 percent of the total. 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

243

Exhibit 5-27 Cases 7 and 8 Plant Performance Summary

POWER SUMMARY 

(Gross Power at Generator Terminals, kWe) Case 7 Case 8

Steam Turbine Power 305,800 310,500

TOTAL POWER, kWe 305,800 310,500

AUXILIARY LOAD SUMMARY, kWe

Coal Handling 990 990

Coal Milling 7,300 7,300

Slag Handling 1,860 1,860

WTA Coal Dryer Compressor 25,020 25,020

WTA Coal Dryer Auxiliaries 880 880

Air Separation Unit Auxiliaries 1,000 1,000

Air Separation Unit Main Air Compressor 127,710 127,650

Oxygen Compressor 21,850 21,850

CO2 Compressor 0 58,880

CO2 Solid Feed System Compressor 6,880 330

SNG Compressors 5,680 5,680

Methanation Plant Recycle Compressor 4,420 4,340

Gasifier Pilot Fuel Compressor 80 80

Boiler Feedwater Pumps 4,700 4,730

Condensate Pump 370 390

Quench Water Pump 570 570

Circulating Water Pump 4,550 5,250

Ground Water Pumps 400 460

Cooling Tower Fans 2,790 3,420

Air Cooled Condenser Fans 3,440 3,820

Scrubber Pumps 940 940

Acid Gas Removal 31,200 31,200

Steam Turbine Auxiliaries 100 100

Claus Plant/TGTU Auxiliaries 250 250

Claus Plant TG Recycle Compressor 2,130 2,150

Miscellaneous Balance of Plant2 3,000 3,000

Transformer Losses 1,630 1,790

TOTAL AUXILIARIES, kWe 259,740 313,930

NET POWER, kWe 46,060 -3,430

SNG Production Rate, MNm3/hr (Mscf/hr) 185.9 (6,568) 185.9 (6,568)

Capacity Factor 90% 90%

Net Exported Power Efficiency (HHV) 1.5% -0.1%

SNG Conversion Efficiency (HHVproduct/HHVcoal), % 61.5% 61.5%

Coal to SNG Product Yield, MNm3

SNG/tonnecoal 

(MscfSNG/toncoal) 0.25 (8.4) 0.25 (8.4)

Coal Feed Flow Rate, kg/hr (lb/hr) 709,841 (1,564,932) 709,841 (1,564,932)

Thermal Input,

1 kWth 3,034,796 3,034,796

Condenser Cooling Duty, GJ/hr (MMBtu/hr) 1,635 (1,550) 1,699 (1,610)

Raw Water Withdrawal, m3/min (gpm) 16.7 (4,421) 19.4 (5,131)

Raw Water Consumption, m3/min (gpm) 12.7 (3,350) 14.8 (3,901)

1 - HHV of NDL coal is 15,391 kJ/kg (6,617 Btu/lb)

2 - Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

244

Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 

2.5. A summary of the plant air emissions for Cases 7 and 8 is presented in Exhibit 5-28.

Exhibit 5-28 Cases 7 and 8 Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

90% capacity factor

Case 7 Case 8 Case 7 Case 8

SO2

0.010 

(0.024)

0.000 

(0.000) 886 (977) 0 (0)

NOX Negligible Negligible Negligible Negligible

Particulates 0.003 

(0.0071)

0.003 

(0.0071) 263 (290) 263 (290)

Hg 2.41E-7 

(5.60E-7)

2.41E-7 

(5.60E-7)

0.021 

(0.023)

0.021 

(0.023)

CO2

63.2 

(147.0) 0.4 (0.9) 5,443,126 (6,000,019)

34,303 

(37,813)

The low level of SO2 emissions in Case 8 is achieved by capture of the sulfur in the gas by the 

two-stage Selexol AGR process and co-sequestration with the CO2 product. Because the WTA 

coal drying process does not include combustion of SNG, there are no SO2 emissions associated 

with drying. The clean syngas exiting the AGR process has a sulfur concentration of 

approximately 2 ppmv in both cases. The H2S-rich regeneration gas from the AGR system is fed 

to a Claus plant, producing elemental sulfur. The tail gas is hydrogenated and recycled to the 

AGR system. The higher sulfur emissions in Case 7 are due to the sulfur contained in the CO2-

rich stream from the Selexol process, which is vented rather than sequestered.

NOX emissions are negligible because no CT is used for power generation.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a syngas 

scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent 

filterable particulate only.

Ninety five percent of mercury is captured from the syngas by an activated carbon bed. CO2

emissions represent the uncontrolled (Case 7) and controlled (Case 8) discharge from the 

process.

The carbon balance for the two cases is shown in Exhibit 5-29. The carbon input to the plant 

consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not used in the 

carbon capture equation below, but it is not neglected in the balance since Aspen accounts for air 

components throughout. Carbon leaves the plant as unburned carbon in the slag, CO2 in the 

stack gas, ASU vent gas, SNG product, and the CO2 product (either vented or sequestered). 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

245

Exhibit 5-29 Cases 7 and 8 Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Case 7 Case 8 Case 7 Case 8

Coal 280,768 

(618,988)

280,768 

(618,988) Slag 1,404 (3,095)

1,404 

(3,095)

Air (CO2) 208 (458) 208 (458)

SNG 

Purification 

Off-Gas

16,113 

(35,522) 0 (0)

ASU Vent 208 (458) 208 (458)

SNG 90,390 

(199,276)

90,309 

(199,098)

CO2 Vent 142,939 

(315,126)

187,863 

(414,167)

CO2 Feed 

Vent

29,923 

(65,969)

1,192 

(2,628)

Stack N/A 0 (0)

Total 280,976 

(619,447)

280,976 

(619,447) Total 280,976 (619,447)

280,976 

(619,447)

The carbon capture efficiency is presented in two distinct ways. The first way defines capture as 

the amount of carbon in the CO2 product for sequestration relative to the amount of carbon in the 

coal less carbon contained in the slag, and is represented by the following fraction:

(Carbon in Product for Sequestration)/[(Carbon in the Coal)-(Carbon in Slag)] or

Non sequestration (Case 7)

(414,167)/(618,988 – 3,095)*100 = 67.2% (Case 8)

The second way does not penalize the production facility for the carbon converted to SNG

product, as the end use of the SNG is unknown. In a carbon constrained scenario, the SNG may 

or may not be used in a scenario where CCS is implemented. For this method, the burden of 

carbon mitigation falls on the end-user. This method is represented by the following fraction: 

[(Carbon in Product for Sequestration) + (Carbon in SNG Product)]/[(Carbon in the Coal)-

(Carbon in Slag)] or

(0 + 199,276)/(618,988 – 3,095)*100 = 32.4% (Case 7)

(414,167 + 199,098)/(618,988 – 3,095)*100 = 99.6% (Case 8)

Exhibit 5-30 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur in the SNG 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

246

product, sulfur emitted in the stack gas, and sulfur co-sequestered with the CO2 product. Sulfur 

in the slag is considered negligible. The total sulfur capture is represented by the following 

fraction:

(Sulfur byproduct + Sulfur in CO2 product)/Sulfur in the coal or 

(9,660 + 0)/9,803 = 98.5 percent (Case 7) 

(9,667 + 130)/9,803 = 99.9 percent (Case 8)

Exhibit 5-30 Cases 7 and 8 Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Case 7 Case 8 Case 7 Case 8

Coal 4,447 (9,803) 4,447 (9,803) Elemental 

Sulfur

4,382 

(9,660)

4,385 

(9,667)

SNG 2 (5) 2 (5)

CO2 Vent 

Streams/Stack 63 (138) 0.4 (1)

CO2 Product N/A 59 (130)

Total 4,447 (9,803) 4,447 (9,803) Total 4,447 

(9,803)

4,447 

(9,803)

Exhibit 5-31 shows the overall water balance for the plant. Water demand represents the total 

amount of water required for a particular process. Some water is recovered within the process, 

primarily as syngas condensate, and is re-used as internal recycle. The difference between 

demand and recycle is raw water withdrawal. Raw water withdrawal is defined as the water 

removed from the ground or diverted from a surface-water source for use in the plant and was 

assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water 

withdrawal can be represented by the water metered from a raw water source and used in the 

plant processes for any and all purposes, such as cooling tower makeup, BFW makeup, quench 

system makeup, and slag handling makeup. The difference between water withdrawal and 

process water discharge is defined as water consumption and can be represented by the portion 

of the raw water withdrawn that is evaporated, transpired, incorporated into products or 

otherwise not returned to the water source from which it was withdrawn. Water consumption 

represents the net impact of the plant process on the water source.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

247

Exhibit 5-31 Cases 7 and 8 Water Balance

Case 7 Case 8

Water Demand, m3/min (gpm)

Slag Handling 1.5 (409) 1.5 (409)

Quench/Wash 3.8 (998) 3.8 (998)

Condenser Makeup 4.5 (1,189) 4.5 (1,191)

 Gasifier Steam 0.0 (0) 0.0 (0)

 Shift Steam 4.3 (1,131) 4.3 (1,131)

 BFW Makeup 0.22 (59) 0.23 (60)

Cooling Tower 17.7 (4,683) 20.4 (5,392)

Total 27.6 (7,279) 30.2 (7,990)

Internal Recycle, m3/min (gpm)

Slag Handling 1.5 (409) 1.5 (409)

Quench/Wash 3.8 (998) 3.8 (998)

Condenser Makeup 0.0 (0) 0.0 (0)

Cooling Tower 5.5 (1,451) 5.5 (1,452)

 Water from Coal Drying 3.2 (856) 3.2 (856)

 BFW Blowdown 0.22 (59) 0.23 (60)

 SWS Blowdown 0.67 (177) 0.67 (177)

 SWS Excess 1.4 (359) 1.4 (359)

Total 10.8 (2,858) 10.8 (2,859)

Raw Water Withdrawal, m3/min (gpm)

Slag Handling 0.0 (0) 0.0 (0)

Quench/Wash 0.0 (0) 0.0 (0)

Condenser Makeup 4.5 (1,189) 4.5 (1,191)

 Gasifier Steam 0.0 (0) 0.0 (0)

 Shift Steam 4.3 (1,131) 4.3 (1,131)

 BFW Makeup 0.22 (59) 0.23 (60)

Cooling Tower 12.2 (3,232) 14.9 (3,940)

Total 16.7 (4,421) 19.4 (5,131)

Process Water Discharge, m3/min (gpm)

SWS Blowdown 0.07 (18) 0.07 (18)

Cooling Tower Blowdown 4.0 (1,053) 4.6 (1,213)

Total 4.1 (1,071) 4.7 (1,230)

Raw Water Consumption, m3/min (gpm)

Slag Handling 0.0 (0) 0.0 (0)

Quench/Wash 0.0 (0) 0.0 (0)

SWS Blowdown -0.07 (-18) -0.07 (-18)

Condenser Makeup 4.5 (1,189) 4.5 (1,191)

Cooling Tower 8.2 (2,179) 10.3 (2,728)

Total 12.7 (3,350) 14.8 (3,901)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

248

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 5-32 through 

Exhibit 5-37:

• Coal gasification and ASU

• ,Syngas cleanup (including sulfur recovery and tail gas recycle)

• Methanation, SNG purification, SNG compression and power cycle

An overall plant energy balance is provided in tabular form in Exhibit 5-38 for the two cases. 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

249

Exhibit 5-32 Case 7 Gasification and ASU Heat and Mass Balance

Raw Syngas

to Scrubber

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

LIGNITE SNG PLANT

CASE 7

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 7

ASU AND GASIFICATION

DWG. NO.

BL-HMB-CS-7-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

PAGES

1 OF 3

Ambient Air

Intercooled

Air Compressor

Elevated

Pressure

ASU

Intercooled

Oxygen Compressor

Milled Coal

ASU

Vent

Slag

Removal

Slag

GROSS PLANT POWER: 306 MWE

AUXILIARY LOAD: 260 MWE

NET PLANT POWER: 46 MWE

SNG PRODUCTION: 6,568 MSCF/HR

Dried Coal

Coal

Feeding

CO2 to Lock Hoppers

Boost

Compressor

Siemens Gasifier

1,564,932 W

3,363,825 W

42.0 T

13.0 P

6.8 H

757,185 W

90.0 T

125.0 P

11.6 H

757,185 W

516.2 T

740.0 P

107.1 H

1,981,729 W

2,600.0 T

604.7 P

1,051.8 H

157,442 W

ENG UNITS

To Claus Plant

5,614 W

90.0 T

125.0 P

11.6 H

WTA

Dryer

Vapor 

Compressor

Condensate 

to Cooling Tower

2,591,975 W

78.1 T

16.4 P

13.1 H

428,222 W

225.0 T

13.8 P

1,160.0 H

428,222 W

90.5 T

50.3 P

14.0 H

Syngas

Quench

Cooler

SH

Steam

4

6

1

5 7

3

10

2

Quench Water

12

Lock Hopper

Vent

241,145 W

482,290 W

168.0 T

815.0 P

9.4 H

8

482,290 W

60.0 T

149.7 P

1.7 H

11

499,149 W

SH

Steam

SH

Steam

2,480,878 W

499.7 T

564.7 P

469.7 H

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Sour Gas

Sour Water

Water

Steam

CO2

Tailgas

20 Pilot Fuel

4,131 W

176.6 T

740.0 P

98.3 H

1,377,855 W

64.9 T

815.0 P

1,798.7 H

1,136,710 W

9

HP

BFW
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

250

Exhibit 5-33 Case 7 Gas Cleanup Heat and Mass Balance

Mercury 

Removal

Knock

Out

Raw Syngas Drum

to Scrubber

Sour

Drum

To Water Treatment

Makeup Water

Catalytic

Reactor

Beds

High

Temperature

Shift

Blowdown

From

ASU LP CO2

Shift

Steam

HP BFW

Syngas

Coolers

Sour

Stripper

Two-Stage

Selexol

Clean Gas

CO2

Acid Gas

Syngas

Scrubber Condensate

To Deaerator Condensate

565,276 W

550.0 T

600.0 P

1,270.5 H

2,408,892 W

418.3 T

544.7 P

414.5 H

2,480,878 W

499.7 T

564.7 P

469.7 H

2,408,892 W

362.9 T

554.7 P

393.7 H

2,415,550 W

93.8 T

474.7 P

16.8 H

721,834 W

87.0 T

469.6 P

36.1 H

55,324 W

119.0 T

23.7 P

42.1 H

1,156,103 W

41.7 T

16.7 P

3.3 H

883,166 W

339.3 T

115.0 P

339.2 H

2,974,167 W

534.6 T

524.7 P

419.6 H

717,703 W

87.0 T

469.6 P

36.1 H

9,660 W

4,769 W

293.1 T

65.0 P

1,032.4 H

5,614 W

90.0 T

125.0 P

11.6 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

LIGNITE SNG PLANT

CASE 7

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 7

GAS CLEANUP

DWG. NO.

BL-HMB-CS-7-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

2 OF 3

Sour Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 306 MWE

AUXILIARY LOAD: 260 MWE

NET PLANT POWER: 46 MWE

SNG PRODUCTION: 6,568 MSCF/HR

2,130,426 W

418.3 T

544.7 P

414.5 H

278,465 W

19

17

12

29

CO2

Tailgas

13

14

15

16

2,974,167 W

863.9 T

534.7 P

559.6 H

2,369,194 W

95.0 T

484.7 P

17.4 H

High Temperature

Methanation Reactor

Pre-heater

Tail Gas Cleanup Unit

3

18

CO2 to Lock

Hoppers

Vented

CO2 Product

Claus Plant

Tail 

Gas

Furnace

Sulfur

28

27

HP CO2

26

1,003,639 W

42.0 T

16.7 P

3.5 H

634,754 W

60.0 T

149.7 P

1.7 H

482,290 W

60.0 T

149.7 P

1.7 H

Syngas to

Methanation

Boost

Compressor

4,131 W

Pilot Fuel

to Gasifier

4,131 W

176.6 T

740.0 P

98.3 H

20

21

Condensate

from Methnation

HT Shift

Pre-heater 56,047 W

450.0 T

12.3 P

359.7 H

30

46,356 W

69.1 T

484.5 P

-4.1 H

Tail Gas

Compressor
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

251

Exhibit 5-34 Case 7 Methanation and Power Block Heat and Mass Balance

Steam Seal 

Regulator

65 PSIA Header

Steam Injection

To Gasifier

Make-up

Gland

Steam

Condenser

Condensate to Preheating

Condensate

Pump

2,261,180 W

90.0 T

0.7 P

57.9 H

612,684 W

1,621,472 W

1,050.0 T

1,814.7 P

1,510.4 H

2,261,180 W

91.5 T

120.0 P

59.8 H

1,400 W

1,400 W

212.0 T

14.7 P

179.9 H

0 W

--- T

--- P

0.0 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

LIGNITE SNG PLANT

CASE 7

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 7

METHANATION AND POWER BLOCK

DWG. NO.

BL-HMB-CS-7-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 306 MWE

AUXILIARY LOAD: 260 MWE

NET PLANT POWER: 46 MWE

SNG PRODUCTION: 6,568 MSCF/HR

Flue Gas

Deaerator

HT Reactor

LP TURBINE GENERATOR HP

TURBINE IP

TURBINE

HOT WELL

AIR-COOLED 

CONDENSER CONDENSER

IP Pump

To Shift Steam

Production

LP Pump

250 PSIA

Attemperating Water

HP Pump

Recycle

Compressor

Syngas from

Selexol Unit

Knock

Out

Drum

Molecular 

Sieve 

Purification 

Unit

Multistage 

Intercooled 

SNG 

Compressor

Clean Up

HT Reactor Reator

Purification

Off-Gas

SNG

Product

Condensate to

Sour Drum

Reactor

Pre-heater

SH Steam from

Syngas Cooler

IP BFW

SH Shift Steam

IP/LP BFW

IP/LP Steam IP Steam IP BFW

31

32

1,647,925 W

717,703 W

87.0 T

469.6 P

36.1 H

21

572.0 T

452.5 P

620.4 H

584.8 T

475.0 P

627.6 H

572.0 T

469.6 P

557.7 H

1,283.5 T

462.5 P

1,077.8 H

2,026,054 W

1,028.0 T

441.8 P

945.4 H

392.0 T

431.8 P

570.0 H

639.2 T

421.1 P

752.2 H

335.0 T

411.1 P

402.9 H

418,290 W

95.0 T

401.1 P

17.1 H

130,998 W

95.0 T

20.1 P

19.4 H 287,291 W

95.0 T

381.0 P

20.5 H

95.0 T

899.5 P

5.5 H

622,454 W

282.3 T

450.0 P

251.9 H

618,290 W

71,800 W

298.0 T

65.0 P

1,178.6 H

1,564,780 W

504.1 T

65.0 P

1,284.1 H

IP BFW

17,391 W

282.1 T

379.0 P

251.6 H

22

23 24 25

10,917 W

658.1 T

18.0 P

1,362.6 H

To Syngas Cooler

Reheater

(Syngas Cooler)

1,646,541 W

997.4 T

501.4 P

1,518.5 H
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

252

Exhibit 5-35 Case 8 Gasification and ASU Heat and Mass Balance

Raw Syngas

to Scrubber

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

LIGNITE SNG PLANT

W/ CO2 CAPTURE

CASE 8

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 8

ASU AND GASIFICATION

DWG. NO.

BL-HMB-CS-8-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

PAGES

1 OF 3

Ambient Air

Intercooled

Air Compressor

Elevated

Pressure

ASU

Intercooled

Oxygen Compressor

Milled Coal

ASU

Vent

Slag

Removal

Slag

GROSS PLANT POWER: 311 MWE

AUXILIARY LOAD: 314 MWE

NET PLANT POWER: -3 MWE

SNG PRODUCTION: 6,567 MSCF/HR

Dried Coal

Coal

Feeding

CO2 to Lock Hoppers

Boost

Compressor

Siemens Gasifier

1,564,932 W

3,362,271 W

42.0 T

13.0 P

6.8 H

757,131 W

90.0 T

125.0 P

11.6 H

757,131 W

516.2 T

740.0 P

107.1 H

1,981,675 W

2,600.0 T

604.7 P

1,051.4 H

157,442 W

ENG UNITS

To Claus Plant

5,316 W

90.0 T

125.0 P

11.6 H

2,590,777 W

78.1 T

16.4 P

13.1 H

Syngas

Quench

Cooler

SH

Steam

4

1

5 7

3

10

2

Quench Water

12

9,620 W

482,290 W

166.3 T

815.0 P

7.9 H

8

482,290 W

152.5 T

750.0 P

5.7 H

11

498,960 W

SH

Steam

SH

Steam

2,480,636 W

499.7 T

564.7 P

469.6 H

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Sour Gas

Sour Water

Water

Steam

CO2

Tail Gas/

Flue Gas

20 Pilot Fuel

428,222 W

90.5 T

50.3 P

63.4 H

1,377,855 W

WTA Coal 

Dryer

Synthesis Gas

1,136,710 W

9

HP Vent to

CO2 Compressor

LP Vent to

CO2 Compressor

192,163 W 39,362 W

Condensate to

Cooling Tower

4,131 W

176.6 T

740.0 P

98.3 H

Vapor Compressor

428,222 W

225.0 T

13.8 P

1,209.4 H

Lock Hopper

Atmospheric Vent

6

HP

BFW
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

253

Exhibit 5-36 Case 8 Gas Cleanup Heat and Mass Balance

SNG Purification

Off Gas

Mercury 

Removal

Knock

Out

Raw Syngas Drum

to Scrubber

Sour

Drum

To Water Treatment

Makeup Water

Catalytic

Reactor

Beds

High

Temperature

Shift

Blowdown

From

ASU

Shift

Steam

HP BFW

Syngas

Coolers

Sour

Stripper

Two-Stage

Selexol

Clean Gas

CO2

Acid Gas

Syngas

Scrubber Condensate

To Deaerator Condensate

565,427 W

550.0 T

600.0 P

1,270.5 H

2,408,561 W

418.3 T

544.7 P

414.3 H

2,480,636 W

499.7 T

564.7 P

469.6 H

2,408,561 W

362.9 T

554.7 P

393.5 H

2,415,054 W

93.8 T

479.5 P

16.8 H

721,392 W

87.0 T

469.6 P

36.1 H

55,059 W

119.0 T

23.7 P

42.1 H

482,290 W

152.5 T

750.0 P

5.7 H

882,744 W

339.3 T

115.0 P

339.2 H

2,973,988 W

494.0 T

519.7 P

402.7 H

717,261 W

87.0 T

469.6 P

36.1 H

9,667 W

4,779 W

293.1 T

65.0 P

1,030.0 H

5,316 W

90.0 T

125.0 P

11.6 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

LIGNITE SNG PLANT

W/ CO2 CAPTURE

CASE

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 8

GAS CLEANUP

DWG. NO.

BL-HMB-CS-8-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

2 OF 3

Sour Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 311 MWE

AUXILIARY LOAD: 314 MWE

NET PLANT POWER: -3 MWE

SNG PRODUCTION: 6,567 MSCF/HR

2,130,224 W

418.3 T

544.7 P

414.3 H

19

17

12

29

CO2

Tail Gas/

Flue Gas

13

14

16

278,337 W

2,368,935 W

95.0 T

489.7 P

17.3 H

High Temperature

Methanation Reactor

Pre-heater

Tail Gas Cleanup Unit

3

18

CO2 to

Sequestration

CO2 to

Lock Hoppers

Claus Plant

Tail 

Gas

Furnace

Sulfur

28

27

1,515,996 

W

95.0 T

2,215.0 P

-89.9 H

Syngas to

Methanation

Boost

Compressor

4,131 W

Pilot Fuel

to Gasifier

4,131 W

176.6 T

740.0 P

98.3 H

20

21

Condensate

from Methnation

HT Shift

Pre-heater 55,485 W

450.0 T

12.3 P

358.9 H

30 46,119 W

69.3 T

479.5 P

-3.5 H

23

Multistage 

Intercooled CO2

Compressor

26

HP CO2

LP Lock

Hopper Vent HP Lock

Hopper Vent

LP CO2

131,097 W

95.0 T

20.1 P

19.4 H

39,362 W

192,163 W

827,001 W

67.4 T

149.7 P

3.1 H

1,174,224 W

49.1 T

16.7 P

Tail Gas 5.4 H

Compressor

15
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

254

Exhibit 5-37 Case 8 Methanation and Power Block Heat and Mass Balance

Steam Seal 

Regulator

65 PSIA Header

Steam Injection

Make-up

Gland

Steam

Condenser

Condensate to Preheating

Condensate

Pump

2,339,194 W

90.0 T

0.7 P

57.9 H

613,556 W

1,615,412 W

1,050.0 T

1,814.7 P

1,510.4 H

2,339,194 W

91.5 T

120.0 P

59.8 H

1,400 W

1,400 W

212.0 T

14.7 P

179.9 H

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

DOE/NETL

LIGNITE SNG PLANT

W/ CO2 CAPTURE

CASE 8

HEAT AND MATERIAL FLOW DIAGRAM

COST AND PERFORMANCE BASELINE VOL. 2

CASE 8

METHANATION AND POWER BLOCK

DWG. NO.

BL-HMB-CS-8-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

F TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

GROSS PLANT POWER: 311 MWE

AUXILIARY LOAD: 314 MWE

NET PLANT POWER: -3 MWE

SNG PRODUCTION: 6,567 MSCF/HR

Flue Gas

Deaerator

HT Reactor

LP TURBINE GENERATOR HP

TURBINE IP

TURBINE

HOT WELL

AIR-COOLED 

CONDENSER CONDENSER

IP Pump

To Shift Steam

Production

LP Pump

250 PSIA

Attemperating Water

HP Pump

Recycle

Compressor

Syngas from

Selexol Unit

Knock

Out

Drum

Molecular 

Sieve 

Purification 

Unit

Multistage 

Intercooled 

SNG 

Compressor

Clean Up

HT Reactor Reator

Purification Off-Gas

(To CO2 Compressor)

SNG

Product

Condensate to

Sour Drum

Reactor

Pre-heater

SH Steam from

Syngas Cooler

IP BFW

SH Shift Steam

IP/LP BFW

IP/LP Steam IP Steam IP BFW

31

32

1,641,772 W

717,261 W

87.0 T

469.6 P

36.1 H

21

572.0 T

452.5 P

619.2 H

584.8 T

475.0 P

626.4 H

572.0 T

469.6 P

555.6 H

1,289.9 T

462.5 P

1,081.3 H

1,979,439 W

1,036.0 T

441.8 P

949.3 H

392.0 T

431.8 P

568.5 H

648.7 T

421.1 P

757.3 H

335.0 T

411.1 P

402.9 H

418,150 W

95.0 T

401.1 P

17.1 H

131,097 W

95.0 T

20.1 P

19.4 H 287,053 W

95.0 T

381.0 P

20.5 H

95.0 T

899.5 P

5.5 H

700,960 W

280.6 T

450.0 P

250.1 H

621,739 W

152,521 W

298.0 T

65.0 P

1,178.6 H

1,561,200 W

504.1 T

65.0 P

1,284.1 H

IP BFW

17,527 W

280.4 T

379.0 P

249.9 H

22

23 24 25

10,917 W

658.1 T

18.0 P

1,362.6 H

To Syngas Cooler

Reheater

(Syngas Cooler)

1,643,779 W

997.4 T

501.4 P

1,518.5 H
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

255

Exhibit 5-38 Cases 7 and 8 Energy Balance

HHV Sensible + Latent Power Total

Case 7 Case 8 Case 7 Case 8 Case 7 Case 8 Case 7 Case 8

Heat In, GJ/hr (MMBtu/hr)

Coal 10,925 

(10,355)

10,925 

(10,355) 6.3 (6.0) 7.9 (7.5) 0 (0) 0 (0) 10,932 (10,361) 10,933 (10,363)

ASU Air 0 (0) 0 (0) 24.0 (22.7) 24.0 (22.7) 0 (0) 0 (0) 24 (23) 24 (23)

Raw Water Makeup 0 (0) 0 (0) 18.6 (17.6) 27.0 (25.6) 0 (0) 0 (0) 19 (18) 27 (26)

Auxiliary Power 0 (0) 0 (0) 0.0 (0.0) 0.0 (0.0) 935 (886) 1,130 (1,071) 935 (886) 1,130 (1,071)

Totals 10,925 

(10,355)

10,925 

(10,355) 48.9 (46.4) 58.9 (55.8) 935 (886) 1,130 (1,071) 11,909 (11,288) 12,114 (11,482)

Heat Out, GJ/hr (MMBtu/hr)

ASU Intercoolers 0 (0) 0 (0) 334 (317) 334 (317) 0 (0) 0 (0) 334 (317) 334 (317)

ASU Vent 0 (0) 0 (0) 35.9 (34.0) 35.9 (34.0) 0 (0) 0 (0) 36 (34) 36 (34)

Slag 46 (44) 46 (44) 120.5 (114.2) 120.5 (114.2) 0 (0) 0 (0) 167 (158) 167 (158)

Sulfur 41 (38) 41 (39) 0.5 (0.5) 0.5 (0.5) 0 (0) 0 (0) 41 (39) 41 (39)

CO2 Intercoolers 0 (0) 0 (0) 0 (0) 351.7 (333.4) 0 (0) 0 (0) 0 (0) 352 (333)

CO2 0 (0) 0 (0) 2.4 (2.3) -143.8 (-136.3) 0 (0) 0 (0) 2 (2) -144 (-136)

Cooling Tower 

Blowdown 0 (0) 0 (0) 21.6 (20.5) 25.6 (24.2) 0 (0) 0 (0) 22 (20) 26 (24)

SNG 6,703 (6,353) 6,699 (6,349) 1.7 (1.6) 1.7 (1.6) 0 (0) 0 (0) 6,705 (6,355) 6,700 (6,351)

SNG Purification 

Off-Gas 0 (0) 0 (0) 3 (3) 3 (3) 0 (0) 0 (0) 3 (3) 3 (3)

Condenser 0 (0) 0 (0) 1,631 (1,546) 1,703 (1,614) 0 (0) 0 (0) 1,631 (1,546) 1,703 (1,614)

Non-Condenser

Cooling Loads 0 (0) 0 (0) 879 (833) 1,194 (1,131) 0 (0) 0 (0) 879 (833) 1,194 (1,131)

Process Losses* 0 (0) 0 (0) 989 (938 586 (555) 0 (0) 0 (0) 989 (938) 586 (555)

Power 0 (0) 0 (0) 0.0 (0.0) 0.0 (0.0) 1,101 (1,043) 1,118 (1,059) 1,101 (1,043) 1,118 (1,059)

Totals 6,790 (6,435) 6,785 (6,431) 4,019 (3,809) 4,211 (3,991) 1,101 (1,043) 1,118 (1,059) 11,909 (11,288) 12,114 (11,482)

* Includes other energy losses not explicitly accounted for in the model.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

256

5.2.4

Major equipment items for the Siemens gasifier SNG plant without and with carbon 

sequestration using NDL coal are shown in the following tables. The accounts used in 

the equipment list correspond to the account numbers used in the cost estimates in 

Section 

Cases 7 and 8 Equipment Lists

5.2.5. In general, the design conditions include a 10 percent contingency for 

flows and heat duties and a 21 percent contingency for heads on pumps and fans.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

257

ACCOUNT 1 COAL HANDLING

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition

Case 8 Design 

Condition

1

Bottom Trestle 

Dumper and 

Receiving Hoppers

N/A 2 0 181 tonne (200 ton) 181 tonne (200 ton)

2 Feeder Belt 2 0 572 tonne/hr (630 tph) 572 tonne/hr (630 tph)

3 Conveyor No. 1 Belt 1 0 1,134 tonne/hr

(1,250 tph)

1,134 tonne/hr

(1,250 tph)

4 Transfer Tower No. 

1 Enclosed 1 0 N/A N/A

5 Conveyor No. 2 Belt 1 0 1,134 tonne/hr

(1,250 tph)

1,134 tonne/hr

(1,250 tph)

6 As-Received Coal 

Sampling System Two-stage 1 0 N/A N/A

7 Stacker/Reclaimer Traveling, 

linear 1 0 1,134 tonne/hr(1,250 tph)

1,134 tonne/hr

(1,250 tph)

8 Reclaim Hopper N/A 2 1 145 tonne (160 ton) 145 tonne (160 ton)

9 Feeder Vibratory 2 1 590 tonne/hr (650 tph) 590 tonne/hr (650 tph)

10 Conveyor No. 3 Belt w/ 

tripper 1 0 1,170 tonne/hr (1,290 tph)

1,170 tonne/hr (1,290 

tph)

11 Crusher Tower N/A 1 0 N/A N/A

12 Coal Surge Bin w/ 

Vent Filter Dual outlet 2 0 590 tonne (650 ton) 590 tonne (650 ton)

13 Crusher Impactor 

reduction

2 0 8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)

8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

258

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition

Case 8 Design 

Condition

14 As-Fired Coal 

Sampling System

Swing 

hammer

1 1 N/A N/A

15 Conveyor No. 4 Belt 

w/tripper

1 0 1,170 tonne/hr

(1,290 tph)

1,170 tonne/hr

(1,290 tph)

16 Transfer Tower No. 

2 Enclosed 1 0 N/A N/A

17 Conveyor No. 5 Belt w/ 

tripper

1 0 1,170 tonne/hr

(1,290 tph)

1,170 tonne/hr

(1,290 tph)

18

Coal Silo w/ Vent 

Filter and Slide 

Gates

Field 

erected

3 0

2,631 tonne (2,900 ton) 2,631 tonne (2,900 ton)

ACCOUNT 2 COAL PREPARATION AND FEED

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition

Case 8 Design 

Condition

1 Feeder Vibratory 6 0 127 tonne/hr (140 tph) 127 tonne/hr (140 tph)

2 Conveyor No. 

6 Belt w/tripper 3 0 263 tonne/hr (290 tph) 263 tonne/hr (290 tph)

3 Roller Mill 

Feed Hopper Dual Outlet 3 0 517 tonne (570 ton) 517 tonne (570 ton)

4 Weigh Feeder Belt 6 0 127 tonne/hr (140 tph) 127 tonne/hr (140 tph)

5 Pulverizer Rotary 6 0 127 tonne/hr (140 tph) 127 tonne/hr (140 tph)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

259

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition

Case 8 Design 

Condition

6 Coal Dryer 

Feed Hopper

Vertical 

Hopper 3 0 517 tonne (570 ton) 517 tonne (570 ton)

7 Coal Preheater

Water Heated 

Horizontal 

Rotary Kiln

3 0

Coal feed: 263 tonne/hr

(290 tph)

Heat duty: 32.1 GJ/hr 

(30.5 MMBtu/hr)

Coal feed: 263 tonne/hr

(290 tph)

Heat duty: 32.1 GJ/hr 

(30.5 MMBtu/hr)

8 Coal Dryer

Fluidized Bed 

with Internal 

Coils

3 0

Coal feed: 263 tonne/hr

(290 tph)

Heat duty: 186 GJ/hr 

(177 MMBtu/hr)

Bed diameter: 16.5 m 

(54 ft)

Coal feed: 263 tonne/hr

(290 tph)

Heat duty: 186 GJ/hr 

(177 MMBtu/hr)

Bed diameter: 16.5 m 

(54 ft)

9 Steam 

Compressor

Reciprocating, 

Multi-Stage 3 0

1,419 m3/min 

(50,110 scfm)

Suction - 0.10 MPa 

(13.8 psia)

Discharge - 0.52 MPa 

(75.3 psia)

1,419 m3/min 

(50,110 scfm)

Suction - 0.10 MPa 

(13.8 psia)

Discharge - 0.52 MPa 

(75.3 psia)

10 Dryer Exhaust 

Filter Hot Baghouse 3 0

Steam - 71,214 kg/hr 

(157,000 lb/hr)

Temperature - 107°C 

(225°F)

Steam - 71,214 kg/hr 

(157,000 lb/hr)

Temperature - 107°C 

(225°F)

11 Dry Coal 

Cooler

Water Cooled 

Horizontal 

Rotary Kiln

3 0

189 tonne/hr (208 tph)

Heat duty - 12 GJ/hr (11 

MMBtu/hr)

189 tonne/hr (208 tph)

Heat duty - 12 GJ/hr (11 

MMBtu/hr)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

260

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition Case 8 Design Condition

1

Demineralized 

Water Storage 

Tank

Vertical, 

cylindrical, 

outdoor

3 0 575,383 liters 

(152,000 gal)

590,524 liters 

(156,000 gal)

2 Condensate 

Pumps

Vertical 

canned 2 1 9,464 lpm @ 91 m H2O(2,500 gpm @ 300 ft H2O)

9,804 lpm @ 91 m H2O

(2,590 gpm @ 300 ft H2O)

3 Deaerator Horizontal 

spray type 2 0 732,098 kg/hr (1,614,000 lb/hr)

751,603 kg/hr 

(1,657,000 lb/hr)

4

Intermediate 

Pressure 

Feedwater 

Pump

Horizontal 

centrifugal, 

single stage

2 1

5,375 lpm @ 341 m H2O

(1,420 gpm @ 1120 ft 

H2O)

5,716 lpm @ 341 m H2O

(1,510 gpm @ 1120 ft 

H2O)

5

High Pressure 

Feedwater 

Pump

Barrel type, 

multi-stage, 

centrifugal

2 1

HP water: 7,117 lpm @ 

1,676 m H2O (1,880 gpm 

@ 5,500 ft H2O)

HP water: 7,117 lpm @ 

1,676 m H2O (1,880 gpm 

@ 5,500 ft H2O)

6 Auxiliary 

Boiler

Shop 

fabricated, 

water tube

1 0

18,144 kg/hr, 2.8 MPa, 

343°C

(40,000 lb/hr, 400 psig, 

650°F)

18,144 kg/hr, 2.8 MPa, 

343°C

(40,000 lb/hr, 400 psig, 

650°F)

7 Service Air 

Compressors

Flooded 

Screw 3 1 28 m3

/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig)

8 Instrument Air 

Dryers

Duplex, 

regenerative 3 1 28 m3

/min (1,000 scfm) 28 m3/min (1,000 scfm)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

261

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition Case 8 Design Condition

9

Closed Cycle 

Cooling Heat 

Exchangers

Plate and 

frame 2 0 667 GJ/hr (632 MMBtu/hr) each

840 GJ/hr (796 MMBtu/hr) 

each

10

Closed Cycle 

Cooling Water 

Pumps

Horizontal 

centrifugal 2 1 239,238 lpm @ 21 m H2O

(63,200 gpm @ 70 ft H2O)

301,319 lpm @ 21 m H2O

(79,600 gpm @ 70 ft H2O)

11 Engine-Driven 

Fire Pump

Vertical 

turbine, diesel 

engine

1 1 3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft H2O)

12 Fire Service 

Booster Pump

Two-stage 

horizontal 

centrifugal

1 1 2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O)

13 Raw Water 

Pumps

Stainless 

steel, single 

suction

2 1 4,656 lpm @ 18 m H2O

(1,230 gpm @ 60 ft H2O)

5,413 lpm @ 18 m H2O

(1,430 gpm @ 60 ft H2O)

14 Ground Water 

Pumps

Stainless 

steel, single 

suction

3 1 3,104 lpm @ 268 m H2O

(820 gpm @ 880 ft H2O)

3,596 lpm @ 268 m H2O

(950 gpm @ 880 ft H2O)

15 Filtered Water 

Pumps

Stainless 

steel, single 

suction

2 1 5,527 lpm @ 49 m H2O

(1,460 gpm @ 160 ft H2O)

5,527 lpm @ 49 m H2O

(1,460 gpm @ 160 ft H2O)

16 Filtered Water 

Tank

Vertical, 

cylindrical 2 0 2,649,788 liter (700,000 gal)

2,653,574 liter (701,000 

gal)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

262

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition Case 8 Design Condition

17 Makeup Water 

Demineralizer

Anion, cation, 

and mixed 

bed

4 0 1,287 lpm (340 gpm) 1,287 lpm (340 gpm)

18

Liquid Waste 

Treatment 

System

1 0 10 years, 24-hour storm 10 years, 24-hour storm

ACCOUNT 4 GASIFIER, ASU, AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition Case 8 Design Condition

1 Gasifier

Pressurized 

dry-feed, 

entrained bed

6 0 3,084 tonne/day, 4.2 MPa

(3,400 tpd, 615 psia)

3,084 tonne/day, 4.2 MPa

(3,400 tpd, 615 psia)

2 Synthesis Gas 

Cooler

Convective 

spiral-wound 

tube boiler

6 0 206,385 kg/hr (455,000 

lb/hr)

206,385 kg/hr (455,000 

lb/hr)

3

Syngas 

Scrubber 

Including Sour 

Water Stripper

Vertical 

upflow 6 0 206,385 kg/hr (455,000 lb/hr)

206,385 kg/hr (455,000 

lb/hr)

4 Raw Gas 

Coolers

Shell and tube 

with

condensate 

drain

12 0 424,109 kg/hr

(935,000 lb/hr)

424,109 kg/hr

(935,000 lb/hr)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

263

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition Case 8 Design Condition

5

Raw Gas 

Knockout 

Drum

Vertical with 

mist 

eliminator

3 0

394,172 kg/hr, 35°C, 

3.4 MPa

(869,000 lb/hr, 95°F, 

490 psia)

394,172 kg/hr, 35°C, 

3.4 MPa

(869,000 lb/hr, 95°F, 

495 psia)

6

Saturation 

Water 

Economizers

Shell and tube 3 0 494,869 kg/hr

(1,091,000 lb/hr)

494,416 kg/hr

(1,090,000 lb/hr)

7 Flare Stack

Selfsupporting, 

carbon steel, 

stainless steel 

top, pilot 

ignition

3 0 412,769 kg/hr (910,000 

lb/hr) syngas

412,769 kg/hr (910,000 

lb/hr) syngas

8 ASU Main Air 

Compressor

Centrifugal, 

multi-stage 3 0 7,646 m3

/min @ 1.3 MPa

(270,000 scfm @ 190 psia)

7,646 m3/min @ 1.3 MPa

(270,000 scfm @ 190 psia)

9 Cold Box Vendor 

design 3 0 3,084 tonne/day (3,400 tpd) of 99% purity oxygen

3,084 tonne/day (3,400 

tpd) of 99% purity oxygen

10 Oxygen 

Compressor

Centrifugal, 

multi-stage 3 0

1,557 m3/min 

(55,000 scfm)

Suction - 0.9 MPa 

(130 psia)

Discharge - 5.1 MPa 

(740 psia)

1,557 m3/min 

(55,000 scfm)

Suction - 0.9 MPa 

(130 psia)

Discharge - 5.1 MPa 

(740 psia)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

264

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition Case 8 Design Condition

11

Coal Feed 

System CO2

Compressor

Centrifugal, 

multi-stage 3 0

736 m3/min (26,000 scfm)

Suction - 1.0 MPa 

(150 psia)

Discharge - 5.7 MPa 

(820 psia)

736 m3/min (26,000 scfm)

Suction - 5.2 MPa 

(750 psia)

Discharge - 5.7 MPa 

(820 psia)

ACCOUNT 5A SYNGAS CLEANUP

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition Case 8 Design Condition

1 Mercury 

Adsorber

Sulfated 

carbon bed 3 0

394,172 kg/hr

(869,000 lb/hr) 

35°C (95°F) 

3.3 MPa (485 psia)

394,172 kg/hr

(869,000 lb/hr) 

35°C (95°F) 

3.4 MPa (490 psia)

2 ZnO Guard Bed Fixed bed 1 0 418 Nm3/min

(14,750 acfm)

417 Nm3/min

(14,740 acfm)

3 Sulfur Plant Claus type 2 0 58 tonne/day (64 tpd) 58 tonne/day (64 tpd)

4 Water Gas Shift 

Reactor

Fixed bed, 

catalytic 3 0

448,149 kg/hr

(988,000 lb/hr) 

232°C (450°F) 

3.7 MPa (540 psia)

448,149 kg/hr

(988,000 lb/hr) 

232°C (450°F) 

3.7 MPa (540 psia)

5

Shift Reactor 

Heat Recovery 

Exchanger

Shell and 

Tube 3 each 0

Exchanger 1: 61 GJ/hr 

(58 MMBtu/hr) 

Exchanger 2: 77 GJ/hr 

(73 MMBtu/hr) 

Exchanger 3: 17 GJ/hr 

(16 MMBtu/hr)

Exchanger 1: 61 GJ/hr 

(58 MMBtu/hr) 

Exchanger 2: 77 GJ/hr 

(73 MMBtu/hr) 

Exchanger 3: 17 GJ/hr 

(16 MMBtu/hr)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

265

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition Case 8 Design Condition

6 Acid Gas 

Removal Plant

Two-stage 

Selexol 3 0

401,883 kg/hr

(886,000 lb/hr) 

34°C (94°F) 

3.3 MPa (475 psia)

401,883 kg/hr

(886,000 lb/hr) 

34°C (94°F) 

3.3 MPa (480 psia)

7 Hydrogenation 

Reactor

Fixed bed, 

catalytic 2 0

13,982 kg/hr (30,826 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

13,842 kg/hr (30,517 lb/hr)

232°C (450°F) 

0.1 MPa (12.3 psia)

8

Tail Gas 

Recycle 

Compressor

Centrifugal 2 0 11,601 kg/hr @ 3.3 MPa 

(25,575 lb/hr @ 485 psia)

11,542 kg/hr @ 3.3 MPa

(25,445 lb/hr @ 485 psia)

ACCOUNT 5B CO2 COMPRESSION

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition Case 8 Design Condition

1 CO2

Compressor

Integrally geared, 

multi-stage 

centrifugal

4 0 N/A 1,705 m3

/min @ 15.3 MPa

(60,200 scfm @ 2,215 psia)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

266

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES 

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition

Case 8 Design 

Condition

1 Combustion

Turbine N/A N/A N/A N/A N/A

2

Combustion

Turbine 

Generator

N/A N/A N/A N/A N/A

ACCOUNT 7 DUCTING & STACK

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition

Case 8 Design 

Condition

1 Stack CS plate, type 

409SS liner 1 0 76 m (250 ft) high x2.2 m (7 ft) diameter

76 m (250 ft) high x 0.7 

m (2 ft) diameter

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition

Case 8 Design 

Condition

1 Steam 

Turbine

Commercially 

available 1 0

322 MW 12.4 MPa/

566°C (1800 psig/ 

1050°F)

327 MW 12.4 MPa/

566°C (1800 psig/

1050°F)

2

Steam 

Turbine 

Generator

Hydrogen 

cooled, static 

excitation

1 0 360 MVA @ 0.9 p.f.,

24 kV, 60 Hz, 3-phase

360 MVA @ 0.9 p.f.,

24 kV, 60 Hz, 3-phase
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

267

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition

Case 8 Design 

Condition

3 Surface 

Condenser

Single pass, 

divided 

waterbox 

including 

vacuum pumps

1 0

897 GJ/hr 

(850 MMBtu/hr), 

Condensing temperature 

32°C (90°F), 

Inlet water temperature 

8°C (47°F), 

Water temperature rise 

11°C (20°F)

939 GJ/hr 

(890 MMBtu/hr), 

Condensing temperature 

32°C (90°F), 

Inlet water temperature 

9°C (48°F), 

Water temperature rise 

11°C (20°F)

4 Air-cooled 

Condenser --- 1 0

897 GJ/hr 

(850 MMBtu/hr), 

Condensing temperature 

32°C (90°F), 

Ambient temperature 

4°C (40°F)

939 GJ/hr 

(890 MMBtu/hr), 

Condensing temperature 

32°C (90°F), 

Ambient temperature 

6°C (42°F)

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition

Case 8 Design 

Condition

1 Circulating 

Water Pumps

Vertical, wet 

pit 2 1 458,035 lpm @ 30 m(121,000 gpm @ 100 ft)

526,172 lpm @ 30 m

(139,000 gpm @ 100 ft)

2 Cooling 

Tower

Evaporative, 

mechanical 

draft, multicell

1 0

2°C (36°F) wet bulb / 

8°C (47°F) CWT / 19°C

(67°F) HWT / 2,543 

GJ/hr (2,410 MMBtu/hr) 

heat duty

3°C (37°F) wet bulb / 

9°C (48°F) CWT / 20°C

(68°F) HWT / 2,933 

GJ/hr (2,780 MMBtu/hr) 

heat duty
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

268

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition Case 8 Design Condition

1 Slag Quench 

Tank Water bath 6 0 249,837 liters (66,000 gal) 249,837 liters (66,000 gal)

2 Slag Crusher Roll 6 0 13 tonne/hr (14 tph) 13 tonne/hr (14 tph)

3 Slag 

Depressurizer Proprietary 6 0 13 tonne/hr (14 tph) 13 tonne/hr (14 tph)

4 Slag Receiving 

Tank

Horizontal, 

weir 6 0 151,416 liters (40,000 gal) 151,416 liters (40,000 gal)

5 Black Water 

Overflow Tank

Shop 

fabricated 6 0 68,137 liters (18,000 gal) 68,137 liters (18,000 gal)

6 Slag Conveyor Drag chain 6 0 13 tonne/hr (14 tph) 13 tonne/hr (14 tph)

7

Slag 

Separation 

Screen

Vibrating 6 0 13 tonne/hr (14 tph) 13 tonne/hr (14 tph)

8 Coarse Slag 

Conveyor Belt/bucket 6 0 13 tonne/hr (14 tph) 13 tonne/hr (14 tph)

9 Fine Ash 

Settling Tank

Vertical, 

gravity 6 0 211,983 liters (56,000 gal) 211,983 liters (56,000 gal)

10 Fine Ash 

Recycle Pumps

Horizontal 

centrifugal 6 3 38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

38 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O)

11 Grey Water 

Storage Tank Field erected 6 0 68,137 liters (18,000 gal) 68,137 liters (18,000 gal)

12 Grey Water 

Pumps Centrifugal 6 3 227 lpm @ 433 m H2O

(60 gpm @ 1,420 ft H2O)

227 lpm @ 433 m H2O

(60 gpm @ 1,420 ft H2O)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

269

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition Case 8 Design Condition

13 Slag Storage 

Bin

Vertical, field 

erected 6 0 907 tonne (1,000 tons) 907 tonne (1,000 tons)

14 Unloading 

Equipment

Telescoping 

chute 2 0 163 tonne/hr (180 tph) 163 tonne/hr (180 tph)

ACCOUNT 11 SNG PRODUCTION/METHANATION SYSTEM

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition Case 8 Design Condition

1

Methanation 

Reactor 

Preheater 

Shell and 

Tube 3 0 90 GJ/hr (85 MMBtu/hr) 90 GJ/hr (85 MMBtu/hr)

2 Methanation 

Reactor 1

Fixed Bed, 

catalytic 3 0

456,314 kg/hr

(1,006,000 lb/hr)

693°C (1,280°F)

3.2 MPa (470 psia)

448,603 kg/hr

(989,000 lb/hr)

699°C (1,290°F)

3.2 MPa (470 psia)

3

Methanation 

Reactor 

Intercooler 1

Shell and 

Tube 3 0 381 GJ/hr (362 MMBtu/hr) 380 GJ/hr (360 MMBtu/hr)

4

Methanation 

Reactor 

Intercooler 2

Shell and 

Tube 3 0 104 GJ/hr (99 MMBtu/hr) 102 GJ/hr (97 MMBtu/hr)

5 Methanation 

Reactor 2

Fixed Bed, 

catalytic 3 0

119,295 kg/hr

(263,000 lb/hr)

554°C (1030°F)

3.1 MPa (450 psia)

119,295 kg/hr

(263,000 lb/hr)

560°C (1040°F)

3.1 MPa (450 psia)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

270

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition Case 8 Design Condition

6

Methanation 

Reactor 

Intercooler 3

Shell and 

Tube 3 0 27 GJ/hr (26 MMBtu/hr) 27 GJ/hr (26 MMBtu/hr)

7 Methanation 

Reactor 3

Fixed Bed, 

catalytic 3 0

119,295 kg/hr

(263,000 lb/hr)

338°C (640°F)

3.0 MPa (440 psia)

119,295 kg/hr

(263,000 lb/hr)

343°C (650°F)

3.0 MPa (440 psia)

8

Methanation 

Reactor 

Intercooler 4

Shell and 

Tube 3 0 36 GJ/hr (34 MMBtu/hr) 38 GJ/hr (36 MMBtu/hr)

9

Methanation 

Reactor 

Intercooler 5

Shell and 

Tube 3 0 61 GJ/hr (58 MMBtu/hr) 61 GJ/hr (58 MMBtu/hr)

10

SNG 

Purification 

Condenser 1

Shell and 

Tube 3 0 51 GJ/hr (49 MMBtu/hr) 51 GJ/hr (49 MMBtu/hr)

11

SNG 

Purification 

Condenser 2

Shell and 

Tube 3 0 31 GJ/hr (30 MMBtu/hr) 31 GJ/hr (30 MMBtu/hr)

12

Methanation 

Recycle 

Compressor

Centrifugal 3 1

8,084 m3/min 

(285,500 scfm)

Suction - 3.1 MPa 

(453 psia)

Discharge - 3.3 MPa 

(475 psia)

7,926 m3/min 

(279,900 scfm)

Suction - 3.1 MPa 

(453 psia)

Discharge - 3.3 MPa 

(475 psia)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

271

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition Case 8 Design Condition

13

Molecular 

Sieve 

Purification 

Reactor

Fixed bed 6 0

34,927 kg/hr (77,000 lb/hr)

35°C (95°F)

2.8 MPa (401 psia)

34,927 kg/hr (77,000 lb/hr)

35°C (95°F)

2.8 MPa (401 psia)

14 SNG Product 

Compressor

Centrifugal, 

Multi-staged 3 1

1,136 m3/min

(40,100 scfm)

2.6 MPa (381 psia)

6.2 MPa (900 psia)

1,136 m3/min

(40,100 scfm)

2.6 MPa (381 psia)

6.2 MPa (900 psia)

ACCOUNT 12 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition

Case 8 Design 

Condition

1 STG Step-up 

Transformer Oil-filled 1 0 24 kV/345 kV, 360 MVA, 3-ph, 60 Hz

345 kV/24 kV, 360 

MVA, 3-ph, 60 Hz

2 Auxiliary 

Transformer Oil-filled 1 1 24 kV/4.16 kV, 287 MVA, 3-ph, 60 Hz

24 kV/4.16 kV, 347 

MVA, 3-ph, 60 Hz

3 Low Voltage 

Transformer

Dry 

ventilated 1 1 4.16 kV/480 V, 43 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 52 

MVA, 3-ph, 60 Hz

4

STG Isolated 

Phase Bus 

Duct and Tap 

Bus

Aluminum, 

self-cooled 1 0 24 kV, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz

5

Medium 

Voltage 

Switchgear

Metal clad 1 1 4.16 kV, 3-ph, 60 Hz 4.16 kV, 3-ph, 60 Hz
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

272

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition

Case 8 Design 

Condition

6 Low Voltage 

Switchgear

Metal 

enclosed 1 1 480 V, 3-ph, 60 Hz 480 V, 3-ph, 60 Hz

7

Emergency 

Diesel

Generator

Sized for 

emergency 

shutdown

1 0 750 kW, 480 V, 3-ph, 

60 Hz

750 kW, 480 V, 3-ph, 

60 Hz

ACCOUNT 13 INSTRUMENTATION AND CONTROLS

Equipment 

No. Description Type Operating Qty. Spares Case 7 Design Condition

Case 8 Design 

Condition

1 DCS - Main 

Control

Monitor/keyboard; 

Operator printer 

(laser color); 

Engineering printer 

(laser B&W)

1 0

Operator 

stations/printers and 

engineering 

stations/printers

Operator 

stations/printers and 

engineering 

stations/printers

2 DCS -

Processor

Microprocessor 

with redundant 

input/output

1 0 N/A N/A

3 DCS - Data 

Highway Fiber optic 1 0 Fully redundant, 25% spare

Fully redundant, 

25% spare
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

273

5.2.5

The cost estimating methodology was described previously in Section 

Cases 7 and 8 Cost Estimating

2.8.

The TPC organized by cost account; owner’s costs; TOC; and initial and annual O&M costs for 

the SNG plant without sequestration using NDL coal (Case 7) are shown in Exhibit 5-39 and 

Exhibit 5-40, respectively. The same data for the SNG plant with sequestration using NDL coal 

(Case 8) are shown in Exhibit 5-41 and Exhibit 5-42.

The estimated TOC of the SNG plant without carbon sequestration using NDL coal is 

3.50 billion dollars and with carbon sequestration is 3.60 billion dollars. Project and process 

contingencies represent 12.0 and 3.6 percent for both cases. The FYCOP is $21.27/MMBtu 

for the non-sequestration case and $23.24/MMBtu for the sequestration case as shown in 

Exhibit ES-6.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

274

Exhibit 5-39 Case 7 Total Plant Cost Details

Client: USDOE/NETL Report Date: 2010-Feb-18

Project: Cost & Performance Baseline for Fossil Energy Plants Vol.2

Case: Case 7 - Siemens Quench SNG Production w/o CO2

Plant Size: 46.06 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $7,733 $0 $3,779 $0 $0 $11,512 $1,031 $0 $2,509 $15,052

1.2 Coal Stackout & Reclaim $9,993 $0 $2,423 $0 $0 $12,415 $1,088 $0 $2,701 $16,204

1.3 Coal Conveyors & Yd Crush $9,291 $0 $2,397 $0 $0 $11,688 $1,026 $0 $2,543 $15,256

1.4 Other Coal Handling $2,431 $0 $555 $0 $0 $2,985 $261 $0 $649 $3,896

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $5,472 $13,683 $0 $0 $19,155 $1,836 $0 $4,198 $25,189

SUBTOTAL 1. $29,447 $5,472 $22,836 $0 $0 $57,755 $5,243 $0 $12,600 $75,598

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $127,899 $0 $18,636 $0 $0 $146,535 $13,308 $0 $31,969 $191,811

2.2 Prepared Coal Storage & Feed $6,058 $1,450 $950 $0 $0 $8,457 $723 $0 $1,836 $11,017

2.3 Dry Coal Injection System $199,367 $2,314 $18,515 $0 $0 $220,197 $18,965 $0 $47,832 $286,994

2.4 Misc.Coal Prep & Feed $3,331 $2,424 $7,268 $0 $0 $13,024 $1,197 $0 $2,844 $17,065

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $12,948 $10,631 $0 $0 $23,579 $2,184 $0 $5,153 $30,916

SUBTOTAL 2. $336,655 $19,136 $56,001 $0 $0 $411,792 $36,377 $0 $89,634 $537,802

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $3,463 $1,610 $1,952 $0 $0 $7,025 $635 $0 $1,532 $9,192

3.2 Water Makeup & Pretreating $591 $62 $330 $0 $0 $982 $94 $0 $323 $1,399

3.3 Other Feedwater Subsystems $3,760 $1,137 $1,860 $0 $0 $6,757 $613 $0 $1,474 $8,845

3.4 Service Water Systems $338 $696 $2,415 $0 $0 $3,449 $337 $0 $1,136 $4,921

3.5 Other Boiler Plant Systems $1,814 $703 $1,742 $0 $0 $4,258 $404 $0 $932 $5,594

3.6 FO Supply Sys & Nat Gas $102 $210 $188 $0 $0 $500 $48 $0 $110 $658

3.7 Waste Treatment Equipment $826 $0 $504 $0 $0 $1,329 $129 $0 $438 $1,896

3.8 Misc. Power Plant Equipment $1,639 $219 $841 $0 $0 $2,700 $261 $0 $888 $3,848

SUBTOTAL 3. $12,532 $4,636 $9,832 $0 $0 $27,001 $2,521 $0 $6,832 $36,353

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $325,384 $0 $150,649 $0 $0 $476,033 $42,281 $71,405 $88,458 $678,176

4.2 Syngas Cooling w/4.1 w/4.1 w/ 4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $246,271 $0 w/equip. $0 $0 $246,271 $23,871 $0 $27,014 $297,156

4.4 LT Heat Recovery & FG Saturation $51,285 $0 $19,002 $0 $0 $70,288 $6,733 $0 $15,404 $92,425

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $2,261 $920 $0 $0 $3,182 $305 $0 $697 $4,184

4.7 CO2 Solid Feed System Compressors $13,665 $3,280 $4,919 $0 $0 $21,863 $2,186 $0 $4,810 $28,860

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $26,928 $15,365 $0 $0 $42,293 $3,872 $0 $11,541 $57,706

SUBTOTAL 4. $636,605 $32,469 $190,856 $0 $0 $859,930 $79,248 $71,405 $147,925 $1,158,507

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

275

Exhibit 5-39 Case 7 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $130,462 $0 $110,700 $0 $0 $241,162 $23,323 $48,232 $62,543 $375,260

5A.2 Elemental Sulfur Plant $8,844 $1,763 $11,410 $0 $0 $22,017 $2,139 $0 $4,831 $28,986

5A.3 Mercury Removal $2,366 $0 $1,800 $0 $0 $4,166 $402 $208 $955 $5,732

5A.4 Shift Reactors $10,266 $0 $4,132 $0 $0 $14,398 $1,380 $0 $3,156 $18,934

5A.5 Methanation $26,500 $10,600 $15,900 $0 $0 $53,000 $5,300 $5,300 $12,720 $76,320

5A.6 SNG Purification & Compression $18,600 $7,440 $11,160 $0 $0 $37,200 $3,720 $0 $8,184 $49,104

5A.7 Fuel Gas Piping $0 $1,631 $1,142 $0 $0 $2,773 $257 $0 $606 $3,636

5A.9 Process Interconnects $0 $12,000 $18,000 $0 $0 $30,000 $3,000 $0 $6,600 $39,600

5A.10 HGCU Foundations $0 $1,651 $1,065 $0 $0 $2,716 $250 $0 $890 $3,856

5A.11 Zinc Oxide Guard Bed $758 $0 $140 $0 $0 $898 $90 $0 $198 $1,185

SUBTOTAL 5A. $197,795 $35,085 $175,449 $0 $0 $408,330 $39,861 $53,741 $100,683 $602,614

 5B CO2 COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.2 Syngas Expander $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $335 $239 $0 $0 $573 $50 $0 $125 $748

7.4 Stack $1,465 $0 $550 $0 $0 $2,015 $193 $0 $221 $2,429

7.9 HRSG,Duct & Stack Foundations $0 $293 $282 $0 $0 $575 $54 $0 $189 $818

SUBTOTAL 7. $1,465 $628 $1,071 $0 $0 $3,164 $297 $0 $534 $3,995

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $31,248 $0 $5,416 $0 $0 $36,664 $3,518 $0 $4,018 $44,200

8.2 Turbine Plant Auxiliaries $169 $0 $498 $0 $0 $668 $66 $0 $73 $807

8.3a Condenser & Auxiliaries $3,246 $0 $1,521 $0 $0 $4,767 $458 $0 $522 $5,747

8.3b Air Cooled Condenser $29,744 $0 $5,963 $0 $0 $35,707 $3,571 $0 $7,855 $47,133

8.4 Steam Piping $5,463 $0 $3,843 $0 $0 $9,306 $799 $0 $2,526 $12,632

8.9 TG Foundations $0 $1,078 $1,823 $0 $0 $2,901 $275 $0 $953 $4,129

SUBTOTAL 8. $69,869 $1,078 $19,065 $0 $0 $90,013 $8,687 $0 $15,949 $114,648
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

276

Exhibit 5-39 Case 7 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $7,073 $0 $1,287 $0 $0 $8,360 $796 $0 $1,373 $10,530

9.2 Circulating Water Pumps $1,885 $0 $87 $0 $0 $1,973 $166 $0 $321 $2,460

9.3 Circ.Water System Auxiliaries $155 $0 $22 $0 $0 $177 $17 $0 $29 $222

9.4 Circ.Water Piping $0 $6,449 $1,672 $0 $0 $8,121 $734 $0 $1,771 $10,626

9.5 Make-up Water System $329 $0 $471 $0 $0 $800 $77 $0 $175 $1,052

9.6 Component Cooling Water Sys $761 $911 $648 $0 $0 $2,320 $217 $0 $507 $3,044

9.9 Circ.Water System Foundations $0 $2,356 $4,005 $0 $0 $6,360 $603 $0 $2,089 $9,052

SUBTOTAL 9. $10,204 $9,715 $8,191 $0 $0 $28,111 $2,610 $0 $6,266 $36,987

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $49,571 $0 $48,892 $0 $0 $98,463 $9,540 $0 $10,800 $118,804

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $1,072 $0 $1,167 $0 $0 $2,239 $217 $0 $368 $2,825

10.7 Ash Transport & Feed Equipment $1,438 $0 $347 $0 $0 $1,785 $167 $0 $293 $2,245

10.8 Misc. Ash Handling Equipment $2,221 $2,722 $813 $0 $0 $5,756 $548 $0 $946 $7,250

10.9 Ash/Spent Sorbent Foundation $0 $95 $119 $0 $0 $214 $20 $0 $70 $304

SUBTOTAL 10. $54,303 $2,817 $51,338 $0 $0 $108,458 $10,492 $0 $12,477 $131,427

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $431 $0 $427 $0 $0 $858 $82 $0 $94 $1,034

11.2 Station Service Equipment $5,673 $0 $511 $0 $0 $6,184 $570 $0 $675 $7,429

11.3 Switchgear & Motor Control $10,487 $0 $1,907 $0 $0 $12,394 $1,150 $0 $2,032 $15,576

11.4 Conduit & Cable Tray $0 $4,872 $16,071 $0 $0 $20,943 $2,026 $0 $5,742 $28,711

11.5 Wire & Cable $0 $9,308 $6,116 $0 $0 $15,424 $1,120 $0 $4,136 $20,681

11.6 Protective Equipment $0 $826 $3,006 $0 $0 $3,832 $374 $0 $631 $4,837

11.7 Standby Equipment $317 $0 $309 $0 $0 $626 $60 $0 $103 $789

11.8 Main Power Transformers $9,424 $0 $172 $0 $0 $9,596 $728 $0 $1,549 $11,872

11.9 Electrical Foundations $0 $186 $489 $0 $0 $675 $65 $0 $222 $962

SUBTOTAL 11. $26,332 $15,192 $29,008 $0 $0 $70,533 $6,174 $0 $15,184 $91,890

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $520 $0 $347 $0 $0 $867 $82 $43 $149 $1,141

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $345 $0 $221 $0 $0 $566 $54 $28 $130 $778

12.7 Computer & Accessories $5,524 $0 $177 $0 $0 $5,701 $523 $285 $651 $7,160

12.8 Instrument Wiring & Tubing $0 $2,798 $5,720 $0 $0 $8,518 $722 $426 $2,417 $12,083

12.9 Other I & C Equipment $4,118 $0 $2,000 $0 $0 $6,118 $576 $306 $1,050 $8,050

SUBTOTAL 12. $10,507 $2,798 $8,465 $0 $0 $21,770 $1,957 $1,088 $4,396 $29,211
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

277

Exhibit 5-39 Case 7 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $141 $3,021 $0 $0 $3,162 $314 $0 $1,043 $4,519

13.2 Site Improvements $0 $2,514 $3,341 $0 $0 $5,855 $578 $0 $1,930 $8,362

13.3 Site Facilities $4,505 $0 $4,754 $0 $0 $9,259 $913 $0 $3,051 $13,223

SUBTOTAL 13. $4,505 $2,655 $11,115 $0 $0 $18,276 $1,804 $0 $6,024 $26,104

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

14.2 Steam Turbine Building $0 $2,599 $3,703 $0 $0 $6,302 $580 $0 $1,032 $7,914

14.3 Administration Building $0 $870 $630 $0 $0 $1,500 $134 $0 $245 $1,879

14.4 Circulation Water Pumphouse $0 $160 $90 $0 $0 $250 $22 $0 $41 $312

14.5 Water Treatment Buildings $0 $494 $482 $0 $0 $975 $88 $0 $160 $1,223

14.6 Machine Shop $0 $445 $305 $0 $0 $750 $67 $0 $123 $939

14.7 Warehouse $0 $726 $464 $0 $0 $1,190 $105 $0 $194 $1,489

14.8 Other Buildings & Structures $0 $514 $400 $0 $0 $914 $82 $0 $199 $1,195

14.9 Waste Treating Building & Str. $0 $1,149 $2,196 $0 $0 $3,346 $312 $0 $732 $4,389

SUBTOTAL 14. $0 $6,957 $8,270 $0 $0 $15,227 $1,389 $0 $2,725 $19,341

TOTAL COST $1,390,220 $138,640 $591,498 $0 $0 $2,120,358 $196,659 $126,234 $421,228 $2,864,478

Owner's Costs

Preproduction Costs

6 Months All Labor $22,173

1 Month Maintenance Materials $3,941

1 Month Non-fuel Consumables $615

1 Month Waste Disposal $937

25% of 1 Months Fuel Cost at 100% CF $1,559

2% of TPC $57,290

Total $86,515

Inventory Capital

60 day supply of fuel and consumables at 100% CF $13,495

0.5% of TPC (spare parts) $14,322

Total $27,817

Initial Cost for Catalyst and Chemicals $17,540

Land $900

Other Owner's Costs $429,672

Financing Costs $77,341

Total Overnight Costs (TOC) $3,504,262

TASC Multiplier 1.201

Total As-Spent Cost (TASC) $4,208,619
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

278

Exhibit 5-40 Case 7 Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 7 - Siemens Quench SNG Production w/o CO2 MWe-net: 46

SNG (MMbtu/hr): 6353 Capacity Factor (%): 90

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 2.0 2.0

 Operator 12.0 12.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 3.0 3.0

 TOTAL-O.J.'s 18.0 18.0

Annual Cost Annual Unit Cost

$ $/MMBtu

Annual Operating Labor Cost $7,102,696 $0.142

Maintenance Labor Cost $28,373,931 $0.566

Administrative & Support Labor $8,869,157 $0.177

Property Taxes and Insurance $57,289,567 $1.144

TOTAL FIXED OPERATING COSTS $101,635,351 $2.029

VARIABLE OPERATING COSTS

$/MMBtu

Maintenance Material Cost $42,560,897 $0.84968

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water(/1000 gallons) 0 3,183 1.08 $0 $1,131,059 $0.02258

Chemicals

MU & WT Chem. (lb) 0 18,964 0.17 $0 $1,078,164 $0.02152

Carbon (Mercury Removal) (lb) 216,740 371 1.05 $227,614 $128,033 $0.00256

COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000

Water Gas Shift Catalyst (ft3) 10,021 8.58 498.83 $4,998,731 $1,405,893 $0.02807

ZnO Sorbent (ton) 63 0.22 12,574.00 $792,321 $891,361 $0.01779

Methanation Catalyst (ft3) 11,443 8.71 440.00 $5,035,097 $1,258,774 $0.02513

Selexol Solution (gal) 484,076 154 13.40 $6,485,766 $676,901 $0.01351

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip 1.63 131.27 $0 $70,246 $0.00140

Subtotal Chemicals $17,539,529 $5,509,373 $0.10999

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000

Supplemental Electricity (for consumption) (MW 0 0 61.60 $0 $0 $0.00000

Gases,N2 etc. (/100scf) 0 0 0.00 $0 $0 $0.00000

L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 $0.00000

Subtotal Other $0 $0 $0.00000

Waste Disposal

Spent Mercury Catalyst (lb.) 0 371 0.42 $0 $50,848 $0.00102

Spent ZnO Sorbent (ton) 0 0.22 16.23 $0 $1,150 $0.00002

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 1,889 16.23 $0 $10,069,904 $0.20103

 Subtotal-Waste Disposal $0 $10,121,902 $0.20207

By-products & Emissions 

Sulfur (tons) 0 116 0.00 $0 $0 $0.00000

Supplemental Electricity (for sale) (MWh) 0 1,105 58.00 $0 -$21,061,948 -$0.42048

Subtotal By-Products $0 -$21,061,948 -$0.42048

TOTAL VARIABLE OPERATING COSTS $17,539,529 $38,261,284 $0.76384

Fuel (ton) 0 18,779 10.92 $0 $67,361,980 $1.34480
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

279

Exhibit 5-41 Case 8 Total Plant Cost Details

Client: USDOE/NETL Report Date: 2010-Feb-18

Project: Cost & Performance Baseline for Fossil Energy Plants Vol.2

Case: Case 8 - Siemens Quench SNG Production w/ CO2

Plant Size: -3.43 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $7,733 $0 $3,779 $0 $0 $11,512 $1,031 $0 $2,509 $15,052

1.2 Coal Stackout & Reclaim $9,993 $0 $2,423 $0 $0 $12,415 $1,088 $0 $2,701 $16,204

1.3 Coal Conveyors & Yd Crush $9,291 $0 $2,397 $0 $0 $11,688 $1,026 $0 $2,543 $15,256

1.4 Other Coal Handling $2,431 $0 $555 $0 $0 $2,985 $261 $0 $649 $3,896

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $5,472 $13,683 $0 $0 $19,155 $1,836 $0 $4,198 $25,189

SUBTOTAL 1. $29,447 $5,472 $22,836 $0 $0 $57,755 $5,243 $0 $12,600 $75,598

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $127,899 $0 $18,636 $0 $0 $146,535 $13,308 $0 $31,969 $191,811

2.2 Prepared Coal Storage & Feed $6,058 $1,450 $950 $0 $0 $8,457 $723 $0 $1,836 $11,017

2.3 Dry Coal Injection System $199,367 $2,314 $18,515 $0 $0 $220,197 $18,965 $0 $47,832 $286,994

2.4 Misc.Coal Prep & Feed $3,331 $2,424 $7,268 $0 $0 $13,024 $1,197 $0 $2,844 $17,065

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $12,948 $10,631 $0 $0 $23,579 $2,184 $0 $5,153 $30,916

SUBTOTAL 2. $336,655 $19,136 $56,001 $0 $0 $411,792 $36,377 $0 $89,634 $537,802

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $3,454 $1,605 $1,947 $0 $0 $7,006 $633 $0 $1,528 $9,168

3.2 Water Makeup & Pretreating $656 $69 $367 $0 $0 $1,092 $104 $0 $359 $1,555

3.3 Other Feedwater Subsystems $3,750 $1,134 $1,855 $0 $0 $6,739 $612 $0 $1,470 $8,821

3.4 Service Water Systems $376 $774 $2,685 $0 $0 $3,834 $374 $0 $1,262 $5,470

3.5 Other Boiler Plant Systems $2,016 $781 $1,936 $0 $0 $4,733 $449 $0 $1,036 $6,218

3.6 FO Supply Sys & Nat Gas $102 $210 $188 $0 $0 $500 $48 $0 $110 $658

3.7 Waste Treatment Equipment $918 $0 $560 $0 $0 $1,477 $144 $0 $486 $2,108

3.8 Misc. Power Plant Equipment $1,639 $219 $841 $0 $0 $2,700 $261 $0 $888 $3,848

SUBTOTAL 3. $12,911 $4,792 $10,379 $0 $0 $28,081 $2,625 $0 $7,140 $37,845

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $325,357 $0 $150,637 $0 $0 $475,994 $42,277 $71,399 $88,451 $678,121

4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $246,271 $0 w/equip. $0 $0 $246,271 $23,871 $0 $27,014 $297,156

4.4 LT Heat Recovery & FG Saturation $51,285 $0 $19,002 $0 $0 $70,287 $6,733 $0 $15,404 $92,424

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $2,260 $920 $0 $0 $3,180 $305 $0 $697 $4,182

4.7 CO2 Solid Feed System Compressors $8,698 $2,087 $3,131 $0 $0 $13,916 $1,392 $0 $3,062 $18,369

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $26,928 $15,365 $0 $0 $42,293 $3,872 $0 $11,541 $57,706

SUBTOTAL 4. $631,611 $31,276 $189,055 $0 $0 $851,942 $78,449 $71,399 $146,169 $1,147,958

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

280

Exhibit 5-41 Case 8 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 5A GAS CLEANUP & PIPING

5A.1 Double Stage Selexol $130,462 $0 $110,700 $0 $0 $241,162 $23,323 $48,232 $62,543 $375,261

5A.2 Elemental Sulfur Plant $8,848 $1,764 $11,416 $0 $0 $22,028 $2,140 $0 $4,834 $29,001

5A.3 Mercury Removal $2,347 $0 $1,786 $0 $0 $4,134 $399 $207 $948 $5,687

5A.4 Shift Reactors $10,263 $0 $4,131 $0 $0 $14,393 $1,380 $0 $3,155 $18,928

5A.5 Methanation $26,350 $10,540 $15,810 $0 $0 $52,700 $5,270 $5,270 $12,648 $75,888

5A.6 SNG Purification & Compression $18,600 $7,440 $11,160 $0 $0 $37,200 $3,720 $0 $8,184 $49,104

5A.7 Fuel Gas Piping $0 $1,630 $1,141 $0 $0 $2,772 $257 $0 $606 $3,634

5A.9 Process Interconnects $0 $12,000 $18,000 $0 $0 $30,000 $3,000 $0 $6,600 $39,600

5A.10 HGCU Foundations $0 $1,651 $1,064 $0 $0 $2,715 $249 $0 $889 $3,854

5A.11 Zinc Oxide Guard Bed $758 $0 $140 $0 $0 $897 $90 $0 $197 $1,185

SUBTOTAL 5A. $197,628 $35,024 $175,348 $0 $0 $408,000 $39,828 $53,709 $100,604 $602,141

 5B CO2 COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $37,246 $0 $21,934 $0 $0 $59,180 $5,698 $0 $12,976 $77,853

SUBTOTAL 5B. $37,246 $0 $21,934 $0 $0 $59,180 $5,698 $0 $12,976 $77,853

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.2 Syngas Expander $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.9 HRSG,Duct & Stack Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 7. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $31,587 $0 $5,482 $0 $0 $37,069 $3,557 $0 $4,063 $44,689

8.2 Turbine Plant Auxiliaries $171 $0 $504 $0 $0 $675 $66 $0 $74 $815

8.3a Condenser & Auxiliaries $3,352 $0 $1,548 $0 $0 $4,899 $470 $0 $537 $5,907

8.3b Air Cooled Condenser $30,717 $0 $6,158 $0 $0 $36,875 $3,687 $0 $8,112 $48,675

8.4 Steam Piping $5,449 $0 $3,833 $0 $0 $9,283 $797 $0 $2,520 $12,600

8.9 TG Foundations $0 $1,090 $1,843 $0 $0 $2,934 $278 $0 $964 $4,175

SUBTOTAL 8. $71,275 $1,090 $19,369 $0 $0 $91,735 $8,857 $0 $16,270 $116,862
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

281

Exhibit 5-41 Case 8 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $7,817 $0 $1,422 $0 $0 $9,239 $880 $0 $1,518 $11,637

9.2 Circulating Water Pumps $2,078 $0 $88 $0 $0 $2,166 $182 $0 $352 $2,700

9.3 Circ.Water System Auxiliaries $168 $0 $24 $0 $0 $192 $18 $0 $32 $242

9.4 Circ.Water Piping $0 $7,009 $1,817 $0 $0 $8,826 $798 $0 $1,925 $11,548

9.5 Make-up Water System $360 $0 $515 $0 $0 $875 $84 $0 $192 $1,150

9.6 Component Cooling Water Sys $827 $990 $704 $0 $0 $2,521 $236 $0 $551 $3,309

9.9 Circ.Water System Foundations $0 $2,566 $4,363 $0 $0 $6,929 $657 $0 $2,276 $9,862

SUBTOTAL 9. $11,250 $10,565 $8,933 $0 $0 $30,748 $2,855 $0 $6,845 $40,448

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $49,571 $0 $48,892 $0 $0 $98,463 $9,540 $0 $10,800 $118,804

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $1,072 $0 $1,167 $0 $0 $2,239 $217 $0 $368 $2,825

10.7 Ash Transport & Feed Equipment $1,438 $0 $347 $0 $0 $1,785 $167 $0 $293 $2,245

10.8 Misc. Ash Handling Equipment $2,221 $2,722 $813 $0 $0 $5,756 $548 $0 $946 $7,250

10.9 Ash/Spent Sorbent Foundation $0 $95 $119 $0 $0 $214 $20 $0 $70 $304

SUBTOTAL 10. $54,303 $2,817 $51,338 $0 $0 $108,458 $10,492 $0 $12,477 $131,427

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $435 $0 $430 $0 $0 $866 $83 $0 $95 $1,043

11.2 Station Service Equipment $6,156 $0 $555 $0 $0 $6,711 $619 $0 $733 $8,062

11.3 Switchgear & Motor Control $11,381 $0 $2,070 $0 $0 $13,451 $1,248 $0 $2,205 $16,903

11.4 Conduit & Cable Tray $0 $5,287 $17,441 $0 $0 $22,728 $2,198 $0 $6,231 $31,157

11.5 Wire & Cable $0 $10,101 $6,637 $0 $0 $16,738 $1,216 $0 $4,489 $22,443

11.6 Protective Equipment $0 $807 $2,936 $0 $0 $3,743 $366 $0 $616 $4,724

11.7 Standby Equipment $317 $0 $309 $0 $0 $626 $60 $0 $103 $789

11.8 Main Power Transformers $10,063 $0 $172 $0 $0 $10,234 $776 $0 $1,652 $12,662

11.9 Electrical Foundations $0 $186 $489 $0 $0 $675 $65 $0 $222 $962

SUBTOTAL 11. $28,352 $16,381 $31,039 $0 $0 $75,772 $6,629 $0 $16,345 $98,747

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $516 $0 $345 $0 $0 $860 $81 $43 $148 $1,133

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $343 $0 $220 $0 $0 $562 $53 $28 $129 $772

12.7 Computer & Accessories $5,483 $0 $176 $0 $0 $5,659 $519 $283 $646 $7,107

12.8 Instrument Wiring & Tubing $0 $2,778 $5,678 $0 $0 $8,456 $717 $423 $2,399 $11,995

12.9 Other I & C Equipment $4,088 $0 $1,985 $0 $0 $6,074 $571 $304 $1,042 $7,991

SUBTOTAL 12. $10,430 $2,778 $8,403 $0 $0 $21,611 $1,943 $1,081 $4,364 $28,998
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

282

Exhibit 5-41 Case 8 Total Plant Cost Details (continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $141 $3,021 $0 $0 $3,162 $314 $0 $1,043 $4,519

13.2 Site Improvements $0 $2,514 $3,341 $0 $0 $5,855 $578 $0 $1,930 $8,362

13.3 Site Facilities $4,505 $0 $4,754 $0 $0 $9,259 $913 $0 $3,051 $13,223

SUBTOTAL 13. $4,505 $2,655 $11,115 $0 $0 $18,276 $1,804 $0 $6,024 $26,104

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

14.2 Steam Turbine Building $0 $2,623 $3,737 $0 $0 $6,360 $585 $0 $1,042 $7,987

14.3 Administration Building $0 $870 $630 $0 $0 $1,500 $134 $0 $245 $1,879

14.4 Circulation Water Pumphouse $0 $160 $90 $0 $0 $250 $22 $0 $41 $312

14.5 Water Treatment Buildings $0 $549 $535 $0 $0 $1,084 $98 $0 $177 $1,359

14.6 Machine Shop $0 $445 $305 $0 $0 $750 $67 $0 $123 $939

14.7 Warehouse $0 $726 $464 $0 $0 $1,190 $105 $0 $194 $1,489

14.8 Other Buildings & Structures $0 $514 $400 $0 $0 $914 $82 $0 $199 $1,195

14.9 Waste Treating Building & Str. $0 $1,149 $2,196 $0 $0 $3,346 $312 $0 $732 $4,389

SUBTOTAL 14. $0 $7,036 $8,358 $0 $0 $15,394 $1,404 $0 $2,752 $19,550

TOTAL COST $1,425,614 $139,022 $614,108 $0 $0 $2,178,744 $202,203 $126,189 $434,199 $2,941,335

Owner's Costs

Preproduction Costs

6 Months All Labor $22,166

1 Month Maintenance Materials $3,939

1 Month Non-fuel Consumables $767

1 Month Waste Disposal $937

25% of 1 Months Fuel Cost at 100% CF $1,559

2% of TPC $58,827

Total $88,196

Inventory Capital

60 day supply of fuel and consumables at 100% CF $13,457

0.5% of TPC (spare parts) $14,707

Total $28,164

Initial Cost for Catalyst and Chemicals $16,258

Land $900

Other Owner's Costs $441,200

Financing Costs $79,416

Total Overnight Costs (TOC) $3,595,468

TASC Multiplier 1.201

Total As-Spent Cost (TASC) $4,318,158
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Exhibit 5-42 Case 8 Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case 8 - Siemens Quench SNG Production w/ CO2 MWe-net: -3

SNG (MMbtu/hr): 6349 Capacity Factor (%): 90

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant 

 Skilled Operator 2.0 2.0

 Operator 12.0 12.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 3.0 3.0

 TOTAL-O.J.'s 18.0 18.0

Annual Cost Annual Unit Cost

$ $/MMBtu

Annual Operating Labor Cost $7,102,696 $0.142

Maintenance Labor Cost $28,362,952 $0.567

Administrative & Support Labor $8,866,412 $0.177

Property Taxes and Insurance $58,826,693 $1.175

TOTAL FIXED OPERATING COSTS $103,158,753 $2.061

VARIABLE OPERATING COSTS

$/MMBtu

Maintenance Material Cost $42,544,428 $0.84994

Consumables Consumption Unit Initial Fill 

 Initial Fill /Day Cost Cost

Water(/1000 gallons) 0 3,694 1.08 $0 $1,312,704 $0.02622

Chemicals

MU & WT Chem.(lb) 0 22,010 0.17 $0 $1,251,314 $0.02500

Carbon (Mercury Removal) (lb) 214,355 367 1.05 $225,110 $126,624 $0.00253

COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000

Water Gas Shift Catalyst (ft3) 7,580 6.49 498.83 $3,780,914 $1,063,382 $0.02124

ZnO Sorbent (ton) 61 0.21 12,574.00 $772,815 $869,417 $0.01737

Methanation Catalyst (ft3) 11,347 8.64 440.00 $4,992,625 $1,248,156 $0.02494

Selexol Solution (gal) 484,145 154 13.40 $6,486,691 $676,998 $0.01352

SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000

Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000

Claus Catalyst (ft3) w/equip 1.63 131.27 $0 $70,295 $0.00140

Subtotal Chemicals $16,258,155 $5,306,187 $0.10601

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000

Supplemental Electricity (for consumption) (M 0 82 61.60 $0 $1,665,795 $0.03328

Gases,N2 etc.(/100scf) 0 0 0.00 $0 $0 $0.00000

L.P. Steam(/1000 pounds) 0 0 0.00 $0 $0 $0.00000

Subtotal Other $0 $1,665,795 $0.03328

Waste Disposal

Spent Mercury Catalyst (lb.) 0 367 0.42 $0 $50,289 $0.00100

Spent ZnO Sorbent (ton) 0 0.21 16.23 $0 $1,122 $0.00002

Flyash (ton) 0 0 0.00 $0 $0 $0.00000

Slag (ton) 0 1,889 16.23 $0 $10,069,904 $0.20117

 Subtotal-Waste Disposal $0 $10,121,315 $0.20220

By-products & Emissions 

Sulfur (tons) 0 116 0.00 $0 $0 $0.00000

Supplemental Electricity (for sale) (MWh) 0 0 58.00 $0 $0 $0.00000

Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $16,258,155 $60,950,429 $1.21765

Fuel (ton) 0 18,779 10.92 $0 $67,361,980 $1.34574
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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6.

6.1 PERFORMANCE

SUMMARY

The nominal thermal input for the Siemens gasifier used for all cases in this study is 500 MW, 

but actual input varies with coal type. The bituminous coal cases in this study had a thermal 

input of 549 MW per gasifier, the PRB cases 527 MW and the lignite cases 506 MW. For the 

co-production cases, a portion of the syngas was used to produce 2,000 tonnes/day (2,204

tons/day) of ammonia with the remaining syngas producing approximately 1.2 BNm3

/year (42

Bscf/year) of SNG at 90 percent CF.

The performance summaries for all cases are shown in Exhibit 6-1. The HHV efficiencies are 

shown in Exhibit 6-2. The higher and lower heating values (LHVs) of the SNG production are 

shown in Exhibit 6-3.

• The cases using PRB coal have the highest net conversion efficiency at 63.1 percent and 

the highest SNG product heating value at 973 Btu/scf (HHV) and 876 Btu/scf (LHV). 

The lower nitrogen content of the lower rank PRB and lignite coals aids in boosting the 

HHV of the SNG end-product, and consequently the net conversion efficiency. 

• The remaining six cases have essentially constant conversion efficiency (61.3 to 61.5 

percent). The addition of carbon sequestration has only a minimal impact on conversion 

efficiency. The sequestration impact is seen in the reduced available export power 

relative to the non-sequestration case.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Exhibit 6-1 Performance, Emissions, and Cost Results

PERFORMANCE Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 7 Case 8

CO2 Sequestration No Yes No Yes No Yes No Yes

SNG Production (Bscf/year)1 57 56 42 42 55 55 52 52

Ammonia Production (TPD)1 N/A N/A 2,204 2,204 N/A N/A N/A N/A

HHV Conversion Efficiency, % 61.4% 61.3% 61.5% 61.4% 63.1% 63.1% 61.5% 61.5%

Gross Power Output (kWe) 308,000 310,600 292,300 292,300 302,000 302,000 305,800 310,500

Auxiliary Power Requirement (kWe) 216,350 262,090 263,600 316,030 247,570 300,190 259,740 313,930

Net Power Output (kWe) 91,650 48,510 28,700 -23,730 54,430 1,810 46,060 -3,430

Coal Flowrate (lb/hr) 964,752 964,752 964,000 964,000 1,259,331 1,259,331 1,564,932 1,564,932

HHV Thermal Input (kWth) 3,298,455 3,298,455 3,295,885 3,295,885 3,160,745 3,160,745 3,034,796 3,034,796

Raw Water Withdrawal (gpm) 7,169 7,123 7,434 7,458 4,853 5,509 4,421 5,131

Process Water Discharge (gpm) 1,462 1,451 1,455 1,461 1,071 1,218 1,071 1,230

Raw Water Consumption (gpm) 5,708 5,672 5,979 5,997 3,783 4,291 3,350 3,901

CO2 Emissions (lb/MMBtu)2 128 5 147 10 140 0.7 147 0.9

SO2 Emissions (lb/MMBtu)2 0.0274 0.0003 0.0229 0.0006 0.0218 0.0000 0.0239 0.0000

NOx Emissions (lb/MMBtu)2 Negligible Negligible Negligible Negligible Negligible Negligible Negligible Negligible

PM Emissions (lb/MMBtu)2 0.007 0.007 0.007 0.007 0.007 0.007 0.007 0.007

Hg Emissions (lb/MMBtu)2 5.71E-07 5.71E-07 5.71E-07 5.71E-07 3.51E-07 3.51E-07 5.60E-07 5.60E-07

COST

Total Plant Cost ($ x 1,000) 2,628,754 2,692,997 3,048,463 3,119,611 2,741,044 2,813,258 2,864,478 2,941,335

Total Overnight Cost ($ x 1,000) 3,235,262 3,312,740 3,742,411 3,829,817 3,354,442 3,442,310 3,504,262 3,595,468

Total As-spent Capital ($ x 1,000) 3,885,549 3,978,601 4,494,636 4,599,610 4,028,684 4,134,215 4,208,619 4,318,158

SNG FYCOP ($/MMBtu)1 19.27 20.95 15.82 17.85 19.15 21.01 21.27 23.24

 CO2 TS&M Costs 0.00 0.91 0.00 1.29 0.00 0.96 0.00 1.03

 Fuel Costs 2.67 2.67 1.89 1.89 1.41 1.41 1.34 1.35

 Variable Costs 1.03 1.04 0.79 0.82 1.02 1.03 1.18 1.18

 Fixed Costs 1.76 1.79 1.41 1.45 1.84 1.86 2.03 2.06

 Electricity Costs -0.77 -0.41 -0.17 0.15 -0.46 -0.02 -0.42 0.03

 Capital Costs 14.58 14.94 11.90 12.25 15.34 15.76 17.13 17.59

Ammonia FYCOP3 ($/ton) - - 799 828 - - - - 1

 Based on a capacity factor of 90 percent for all cases

2

 Based on coal thermal input

3

 Ammonia price is correlated to historic natural gas costs

SNG Only

Illinois No. 6 Coal Rosebud PRB North Dakota Lignite

SNG Only SNG and Ammonia SNG Only
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

287

Exhibit 6-2 Net Plant Conversion Efficiency (HHV)

Exhibit 6-3 SNG Heating Values

61.4% 61.3% 61.5% 61.4%

63.1% 63.1%

61.5% 61.5%

0%

10%

20%

30%

40%

50%

60%

70%

SNG Illinois 6 SNG Illinois 6 

w/ Capture

SNG/NH3

Illinois 6

SNG/NH3 

Illinois 6 w/ 

Capture

SNG PRB SNG PRB w/ 

Capture

SNG Lignite SNG Lignite w/ 

Capture

% Conversion Efficiency (HHV Basis)

964 964 964 964 973 973 970 969

867 867 867 867 876 876 873 872

0

200

400

600

800

1,000

1,200

SNG Illinois 6 SNG Illinois 6 w/ 

Capture

SNG/NH3

Illinois 6

SNG/NH3 Illinois 

6 w/ Capture

SNG PRB SNG PRB w/ 

Capture

SNG Lignite SNG Lignite w/ 

Capture

SNG Heating Value (Btu/scf)

HHV

LHV
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

288

6.2 ECONOMICS

The TOCs are shown in Exhibit 6-4. For reference, Total As-spent Capital (TASC) is also 

shown. TASC is the sum of TOC, escalation during the capital expenditure period, and interest 

on debt during the capital expenditure period. Observations related to TOC include:

• In the SNG only cases, the TOC is lowest for the Illinois No. 6 cases followed by the 

PRB cases, and then by the lignite cases.

• The TOC increase to add carbon sequestration is approximately 2.4 percent for the 

Illinois No. 6 SNG only case, 2.4 percent for the co-production case, 2.6 percent for the 

PRB coal SNG only case, and 2.6 percent for the SNG only lignite case.

• The TOC is increased by 16 percent with the addition of ammonia co-production for both 

the Illinois No. 6 coal non-sequestration and sequestration cases.

• The lignite cases have 4 percent higher TOC compared to the PRB cases.

The FYCOPs are shown in Exhibit 6-5. The FYCOP components and SNG/ammonia product 

revenues are shown in tabular form in Exhibit 6-6. The following observations can be made:

• The FYCOP is dominated by capital charges in all cases. For the SNG only cases, the 

capital charges (which include owner’s costs) range from 71 to 81 percent of the total. 

For the co-production cases, the capital costs are 75 and 69 percent of the FYCOP for the 

non-sequestration and sequestration cases, respectively.

• The fuel cost component is highest for the Illinois No. 6 coal cases. For the SNG only 

cases the fuel represents 13 percent of the total cost for Illinois No. 6 coal, 7 percent for 

PRB coal, and 6 percent for lignite coal.

• The TS&M component is relatively minor for all cases, ranging from 4 percent to 7

percent.
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

289

Exhibit 6-4 Total Overnight Cost and Total As-spent Capital

1,939 1,988 2,271 2,325 2,024 2,079 2,120 2,179

180 185

213 218

188 193 197 385 202 396

440 452

403 415 421 125 125 434

125 125

126 126 126 126 607 620

694 710

613 629 640 654

3,235 3,313

3,742 3,830

3,354 3,442 3,504 3,595

3,886 3,979

4,495 4,600

4,029 4,134 4,209 4,318

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC

SNG Illinois 6 SNG Illinois 6 w/ 

Capture

SNG/NH3

Illinois 6

SNG/NH3 Illinois 6 

w/ Capture

SNG PRB SNG PRB w/ 

Capture

SNG Lignite SNG Lignite w/ 

Capture

Capital Cost, $1,000,000

TASC

Owner's Cost

Process Contingency

Project Contingency

Home Office Expense

Bare Erected Cost
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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Exhibit 6-5 First Year Cost of Production

Exhibit 6-6 First Year Cost of Production Components

14.58 14.94

11.90 12.25

15.34 15.76 17.13 17.59

1.76 1.79

1.41 1.45

1.84 1.86

2.03 2.06

1.03 1.04

0.79 0.82

1.02 1.03

1.18 1.18

2.67 2.67

1.89 1.89

1.41 1.41

1.34 1.35 0.91

1.29

0.96

1.03

19.27

20.95

15.82

17.85

19.15

21.01 21.27

23.24

-5

0

5

10

15

20

25

30

35

40

SNG Illinois 6 SNG Illinois 6 w/ 

Capture

SNG/NH3

Illinois 6

SNG/NH3 Illinois 6 

w/ Capture

SNG PRB SNG PRB w/ 

Capture

SNG Lignite SNG Lignite w/ 

Capture

FYCOP, $/MMBtu

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs

Electricity Revenue/Cost

FYCOP Component1

SNG 

Bituminous 

No Capture 

(Case 1)

SNG 

Bituminous 

w/ Capture 

(Case 2)

SNG and 

Ammonia 

Bituminous 

No Capture 

(Case 3)

SNG and 

Ammonia 

Bituminous 

w/ Capture 

(Case 4)

SNG 

PRB 

No Capture 

(Case 5)

SNG 

PRB 

w/ Capture 

(Case 6)

SNG 

Lignite 

No Capture 

(Case 7)

SNG 

Lignite 

w/ Capture 

(Case 8)

Capital, $/MMBtu 14.58 14.94 11.90 12.25 15.34 15.76 17.13 17.59

Fixed O&M, $/MMBtu 1.76 1.79 1.41 1.45 1.84 1.86 2.03 2.06

Variable O&M, 

$/MMBtu 1.03 1.04 0.79 0.82 1.02 1.03 1.18 1.18

Fuel, $/MMBtu 2.67 2.67 1.89 1.89 1.41 1.41 1.34 1.35

Electricity, $/MMBtu -0.77 -0.41 -0.17 0.15 -0.46 -0.02 -0.42 0.03

CO2 TS&M, $/MMBtu 0.00 0.91 0.00 1.29 0.00 0.96 0.00 1.03

Total, $/MMBtu 19.27 20.95 15.82 17.85 19.15 21.01 21.27 23.24

SNG First Year 

Revenues, MM$ 1,047 1,137 639 721 1,025 1,124 1,065 1,163

Ammonia First Year 

Revenues, MM$ - - 578 599 - - - -

1

 Based on heating value of SNG
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

291

The impact of various levels of CO2 tax on the FYCOP of SNG as well as the FYCOP of 

ammonia in the co-production cases is shown in Exhibit 6-7. In the co-production cases 

the cost of ammonia varies with the cost of SNG according to the following relationship:

Cases without sequestration are shown as solid lines while those with sequestration are 

shown as dashed lines. Taxation of plant CO2 emissions causes a significant increase in 

FYCOP in the non-sequestration cases while the increase is greatly diminished in the 

sequestration cases. It should be noted that end-use CO2 emissions from the SNG 

product are not accounted for. 

Exhibit 6-7 shows that a carbon tax of $15-20/ton of CO2 is required to make SNG 

produced in a sequestration case less expensive than that produced in the corresponding 

non-sequestration case for SNG only cases. The carbon cost must increase to about 

$25/ton before the same is true in the co-production case.

Exhibit 6-7 Impact of CO2 Tax on FYCOP

6.3 CARBON DIOXIDE EMISSIONS/MITIGATION

Carbon dioxide emissions are not currently regulated nationwide; however, there is 

increasing momentum for establishing carbon limits. CO2 emissions are presented in 

Exhibit 6-8 for each case, normalized by coal thermal input to enable comparison 

between the technology types (SNG only versus co-production). The following 

conclusions can be drawn:

0

5

10

15

20

25

30

35

40

45

50

0 10 20 30 40 50 60 70 80 90 100

SNG FY COP ($/MMBtu)

CO2 Tax ($/ton)

Case 7 SNG

Case 1 SNG

Case 5 SNG

Case 3 SNG 

Case 8 SNG

Case 2 SNG

Case 6 SNG

Case 4 SNG

Non-capture cases

Capture cases
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

292

• In cases with no carbon sequestration, the SNG only case using bituminous coal 

emits 12 percent less CO2 than the co-production case, 13 percent less than the 

lignite case, and 8 percent less than the PRB case. 

• The CO2 emissions for the SNG only non-sequestration cases are proportional to 

the carbon intensity of the design coal. Based on fuel compositions used in this 

study, bituminous coal contains 55 pounds of carbon per million Btu, PRB and 

lignite coal contain 58 and 60 pounds per million Btu, respectively.

• The normalized CO2 emissions in the sequestration cases are lower for the low 

rank coal cases largely because the coal drying method utilized does not require 

the burning of syngas. The normalized CO2 emissions for the Illinois No. 6 coproduction cases (both non-sequestration and sequestration) are higher than the 

equivalent SNG only cases because more CO2 is produced in the shift section of 

the ammonia plant due to the hydrogen requirements for ammonia production that 

is not subsequently captured.

Exhibit 6-8 CO2 Emissions Normalized by Thermal Input

6.4 RAW WATER WITHDRAWAL AND CONSUMPTION

Water withdrawal, process discharge, and water consumption are shown in Exhibit 6-9

for each case. The primary conclusions that can be drawn are:

• In all cases, the primary water consumer is cooling tower makeup, which ranges 

from 60 to 80 percent of the total raw water withdrawal.

128.4

4.9

146.5

9.5

140.3

0.7

147.0

0.9

0

100

200

SNG Illinois 6 SNG Illinois 6 w/ 

Capture

SNG/NH3

Illinois 6

SNG/NH3 Illinois 

6 w/ Capture

SNG PRB SNG PRB w/ 

Capture

SNG Lignite SNG Lignite w/ 

Capture

CO2 Emissions (lb/MMBtu)
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

293

• The SNG and ammonia co-production cases (Cases 3 and 4) consume 

approximately 5 percent more water than the SNG only cases using bituminous 

coal (Cases 1 and 2). This is largely due to the excess shift steam required to 

produce the hydrogen necessary for ammonia production.

• For the SNG only non-sequestration cases, the case using lignite coal requires the 

least amount of water withdrawal followed by the cases using PRB coal and 

bituminous coal. The relative raw water withdrawal for the SNG only cases is 

1.6:1.1:1.0 (bituminous:PRB:lignite). The trend for the SNG only cases with

carbon sequestration is 1.4:1.1:1.0 (bituminous:PRB:lignite).

Exhibit 6-9 Raw Water Withdrawal and Consumption

7.2 7.1 7.4 7.5

4.9

5.5

4.4

5.1

5.7 5.7 6.0 6.0

3.8

4.3

3.4

3.9

0

2

4

6

8

10

12

SNG Illinois 6 SNG Illinois 6 w/ 

Capture

SNG/NH3

Illinois 6

SNG/NH3 

Illinois 6 w/ 

Capture

SNG PRB SNG PRB w/ 

Capture

SNG Lignite SNG Lignite w/ 

Capture

Water, gpm x 1,000

Water Withdrawal

Process Discharge

Water Consumption
Cost and Performance Baseline for Coal-to-SNG and Ammonia (Volume 2)

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7.

1 Cost Estimation Methodology for NETL Assessments of Power Plant 

Performance, April 2011, 

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