# Cost and Performance Baseline for Fossil Energy Plants

DOE/NETL-2007/1281



# Volume 1: Bituminous Coal and Natural Gas to Electricity Final Report ( Original Issue Date, May 2007 

# )

Revision 1, August 2007

# Disclaimer

This report was prepared as an account of wo rk 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, complete ness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Refere nce therein to any specific comme rcial product, process, or service by trade name, trademark, manufactur er, or otherwise does not necessarily constitute or imply its endorsement, reco mmendation, or favoring by the United States Government or any agency thereof. The vi ews and opinions of aut hors expressed therein do not necessarily state or reflect those of th e United States Government or any agency thereof.

# Cost and Performance Baseline for Fossil Energy Plants

DOE/NETL-2007/1281

Volume 1: Bituminous Coal and Natural Gas to Electricity

Final Report (Original Issue Date, May 2007)
Revision 1, August 2007

NETL Contact:
Julianne M. Klara Senior Analyst Office of Systems, Analyses and Planning

Prepared by:

Research and Developme nt Solutions, LLC (RDS)

Mark C. Woods, Parsons Corporation Pamela J. Capicotto, Parsons Corporation

John L. Haslbeck, Parsons Corporation Norma J. Kuehn, Parsons Corporation Michael Matuszewski, formerly of Parsons Corporation Lora L. Pinkerton, Worl eyParsons Group, Inc.

Michael D. Rutkowski, Parsons Corporation Ronald L. Schoff, formerly of Parsons Corporation

Vladimir Vaysman, WorleyParsons Group, Inc.

National Energy Technology Laboratory www.netl.doe.gov

### This page intentionally left blankCost and Performance Baseline for Fossil Energy Plants


# NETL Viewpoint

Background The goal of Fossil Energy Research, Development and Demonstration (RD&D) is to ensure the availability of ultra-clean (“ze ro” emissions), abundant, low-cost, domestic electr icity and energy (including hydrogen) to fuel ec onomic prosperity and strength en energy security. A broad portfolio of technologies is being developed w ithin the Clean Coal Program to accomplish this objective. Ever increasing technol ogical enhancements are in va rious stages of the research “pipeline,” and multiple paths are being pursued to create a port folio of promising technologies for development, demonstration, and eventual de ployment. The technological progress of recent years has created a remarkable new opportunity for coal. Advances in technology are making it possible to generate power from fossil fuels with great improvements in th e efficiency of energy use while at the same time significantly reduci ng the impact on the environment, including the long-term impact of fossil energy use on the Eart h’s climate. The objective of the Clean Coal RD&D Program is to build on these advances an d bring these building bl ocks together into a new, revolutionary concept for future coal-based power and energy production. 

### Objective To establish baseline performance and cost es timates for today’s fossil energy plants, it is necessary to look at the current state of technology. Such a baseline can be used to benchmark the progress of the Fossil Energy RD&D portfolio. This study provides an accurate, independent assessment of the cost and performance for Pu lverized Coal Combustion (PC), Integrated Gasification Combined Cycles (IGCC), and Natura l Gas Combined Cycles (NGCC), all with and without carbon dioxide capture and storage assu ming that the plants use technology available today. 

### Approach The power plant configurations analyzed in this study were modeled using the ASPEN Plus modeling program. Performance and process limits were based upon published reports, information obtained from vendors and users of th e technology, cost and performance data from design/build utility projects, and/ or best engineering judgment. Capital and operating costs were estimated by WorleyParsons based on simulatio n results and through a combination of existing vendor quotes, scaled estimates from previous desi gn/build projects, or a co mbination of the two. O&M costs and the cost for tran sporting, storing and monitoring CO 2 

### in the cases with carbon capture were also estimated based on reference data and scaled estimates. Levelized cost of electricity (LCOE) was determined for all plants assuming investor owned utility financing. The initial results of this analysis were subjected to a significan t peer review by industry experts, academia and government research and regulatory agencies. Based on the feedback from these experts, the report was updated both in terms of technical content and revised costs. 

### Results This independent assessment of fossil energy plant cost and performance is considered to be the most comprehensive set of publicly available data to date. While input was sought from various technology vendors, the final assessment of performance and cost was determined independently, and may not represent the view of the technology vendors. The extent of

iCost and Performance Baseline for Fossil Energy Plants



### collaboration with technology vendors varied from case to case, with minimal or no collaboration obtained from some vendors. Selection of system components and plant configurations from the range of potential options and the curren t rapid escalation in labor and material costs made it a challenge to develop state-of-the-art confi gurations and cost estimates. The rigorous expert technical re view and systematic use of ex isting vendor quotes and project design/build data to develop the co st estimates in this report are believed to provide the most upto-date performance and costs available in the pub lic literature. Highlights of the study are the following:

• Coal-based plants using today’s technology are capable of producing electricity at relatively high efficiencies of about 39%, HHV (without capture) on bituminous coal and at the same time meet or exceed current environmental requirements for criteria pollutants.

• Capital cost (total plant cost) for the non-cap ture plants are as follows: NGCC, $554/kW; PC, $1,562/kW (average); IGCC, $1,841/kW (average ). With capture, capital costs are: NGCC, $1,172/kW; PC, $2,883/kW (avera ge); IGCC, $2,496/kW (average).

• At fuel costs of $1.80/ton of coal and $6.75/MM Btu of natural gas, the 20-year levelized cost of electricity for the non-capture plan ts are: 64 mills/kWh (average) for PC, 68 mills/kWh for NGCC, and 78 mills/kWh (average) for IGCC.

• When today’s technology for carbon capture an d sequestration is integrated into these new power plants, the resultant 20-year levelized COE including the cost of CO 2 

### transport, storage and monitoring is: 97 mills/kWh for NGCC; 106 mills/kWh (average) for IGCC; and 117 mills/kWh (average) for PC. The cost of transporting CO 2 

### 50 miles for storage in a geologic formation with over 30 years of monitoring is estimated to add about 4 mills/kWh. This represents only about 10% of the total carbon capture and sequestration costs.

• A sensitivity study on natural gas price reveals that the COE fo r IGCC is equal to that of NGCC at $7.73/MMBtu, and for PC, the COE is equivalent to NGCC at a gas price of $8.87/MMBtu. In terms of capacity factor, when the NGCC drops below 60 percent, such as in a peaking applic ation, the resulting COE is hi gher than that of an IGCC operating at baseload (80 pe rcent capacity factor).
Fossil Energy RD&D is aimed at improving the performance and cost of clean coal power systems including the development of new appr oaches to capture and sequester greenhouse gases. Improved efficiencies and reduced cost s are required to improve the competitiveness of these systems in today’s market and regulatory environment as well as in a carbon constrained scenario. The results of this analysis provide a starting point from which to measure the progress of RD&D achievements.

iiCost and Performance Baseline for Fossil Energy Plants



## TABLE OF CONTENTS Table of Contents .............................................................................................................. ........... iii List of Exhibits ............................................................................................................... ............. vii Acknowledgements ............................................................................................................... ..... xiii List of Acronyms and Abbreviations ....................................................................................... xiv Executive Summary.............................................................................................................. .........1 Performance .....................................................................................................................................3 Energy Efficiency ......................................................................................................................3 Water Use...................................................................................................................................6 Cost Results ................................................................................................................... ..................9 Total Plant Cost............................................................................................................... ...........9 Levelized Cost of Electricity (LCOE) .....................................................................................11 Cost of CO 2 

### Removed/Avoided ...............................................................................................16 Environmental Performance ...................................................................................................... ....18 1 Introduction......................................................................................................................25 2 General Evaluation Basis ................................................................................................29 2.1 Site Characteristics....................................................................................................... ......29 2.2 Coal Characteristics ....................................................................................................... ....30 2.3 Natural Gas Characteristics................................................................................................ 32 2.4 Environmental Targets...................................................................................................... .32 2.4.1 IGCC..................................................................................................................... .......35 2.4.2 PC....................................................................................................................... ..........36 2.4.3 NGCC ..................................................................................................................... .....37 2.4.4 Carbon Dioxide........................................................................................................... .38 2.5 Capacity Factor ............................................................................................................ ......39 2.6 Raw Water Usage ............................................................................................................ ..40 2.7 Cost Estimating Methodology ...........................................................................................41 2.8 IGCC Study Cost Estimates Co mpared to Industry Estimates ..........................................52 3 IGCC Power Plants..........................................................................................................57 3.1 IGCC Common Process Areas...........................................................................................57 3.1.1 Coal Receiving and Storage...............................................................................................57 3.1.2 Air Separation Unit (ASU) Choice and Integration...........................................................58 3.1.3 Water Gas Shift Reactors................................................................................................. ..62 3.1.4 Mercury Removal .......................................................................................................... ....62 3.1.5 Acid Gas Removal (AGR) Process Selection....................................................................63 3.1.6 Sulfur Recovery/Tail Gas Cleanup Process Selection.......................................................71 3.1.7 Slag Handling............................................................................................................ .........74 3.1.8 Power Island............................................................................................................. ..........75 3.1.9 Steam Generation Island.................................................................................................. ..80 3.1.10 Accessory Electric Plant ................................................................................................ ....83 3.1.11 Instrumentation and Control ............................................................................................. .83 3.2 General Electric Energy IGCC Cases................................................................................85 3.2.1 Gasifier Background ...................................................................................................... ....86 3.2.2 Process Description...................................................................................................... ......88 3.2.3 Key System Assumptions ..................................................................................................9 5 3.2.4 Sparing Philosophy ....................................................................................................... .....97

iiiCost and Performance Baseline for Fossil Energy Plants



### 3.2.5 Case 1 Performance Results............................................................................................... 97 3.2.6 Case 1 - Major Equipment List........................................................................................110 3.2.7 Case 1 - Cost Estimating................................................................................................. .118 3.2.8 Case 2 - GEE IGCC with CO 2 

### Capture ...........................................................................124 3.2.9 Case 2 Performance Results.............................................................................................12 8 3.2.10 Case 2 - Major Equipment List........................................................................................142 3.2.11 Case 2 - Cost Estimating................................................................................................ ..151 3.3 ConocoPhillips E-GasTM IGCC Cases .............................................................................157 3.3.1 Gasifier Background ...................................................................................................... ..157 3.3.2 Process Description...................................................................................................... ....159 3.3.3 Key System Assumptions ................................................................................................165 3.3.4 Sparing Philosophy ....................................................................................................... ...165 3.3.5 Case 3 Performance Results.............................................................................................16 7 3.3.6 Case 3 - Major Equipment List........................................................................................180 3.3.7 Case 3 - Costs Estimating Results ...................................................................................188 3.3.8 Case 4 - E-GasTM IGCC Power Plant with CO 2 

### Capture.................................................194 3.3.9 Case 4 Performance Results.............................................................................................19 9 3.3.10 Case 4 - Major Equipment List........................................................................................212 3.3.11 Case 4 - Cost Estimating Results.....................................................................................220 3.4 Shell Global Solutions IGCC Cases ................................................................................226 3.4.1 Gasifier Background ...................................................................................................... ..226 3.4.2 Process Description...................................................................................................... ....228 3.4.3 Key System Assumptions ................................................................................................235 3.4.4 Sparing Philosophy ....................................................................................................... ...237 3.4.5 Case 5 Performance Results.............................................................................................23 7 3.4.6 Case 5 - Major Equipment List........................................................................................250 3.4.7 Case 5 - Cost Estimating................................................................................................. .258 3.4.8 Case 6 - Shell IGCC Power Plant with CO 2 

### Capture.......................................................264 3.4.9 Case 6 Performance Results.............................................................................................26 9 3.4.10 Case 6 - Major Equipment List........................................................................................282 3.4.11 Case 6 - Cost Estimating................................................................................................ ..290 3.5 IGCC Case Summary.......................................................................................................296 4 Pulverized Coal Rankine Cycle Plants.........................................................................305 4.1 PC Common Process Areas .............................................................................................306 4.1.1 Coal and Sorbent Receiving and Storage.........................................................................306 4.1.2 Steam Generator and Ancillaries .....................................................................................306 4.1.3 NOx Control System....................................................................................................... .309 4.1.4 Particulate Control ...................................................................................................... .....310 4.1.5 Mercury Removal .......................................................................................................... ..310 4.1.6 Flue Gas Desulfurization ................................................................................................. 310 4.1.7 Carbon Dioxide Recovery Facility ..................................................................................313 4.1.8 Power Generation......................................................................................................... ....317 4.1.9 Balance of Plant ...............................................................................................................318 4.1.10 Accessory Electric Plant ................................................................................................ ..322 4.1.11 Instrumentation and Control ............................................................................................3 22 4.2 Subcritical PC Cases....................................................................................................... .323

ivCost and Performance Baseline for Fossil Energy Plants



### 4.2.1 Process Description...................................................................................................... ....323 4.2.2 Key System Assumptions ................................................................................................326 4.2.3 Sparing Philosophy ....................................................................................................... ...328 4.2.4 Case 9 Performance Results.............................................................................................32 8 4.2.5 Case 9 – Major Equipment List .......................................................................................336 4.2.6 Case 9 – Cost Estimating ................................................................................................. 344 4.2.7 Case 10 – PC Subcritical Unit with CO2 Capture ...........................................................350 4.2.8 Case 10 Performance Results...........................................................................................350 4.2.9 Case 10 – Major Equipment List .....................................................................................360 4.2.10 Case 10 – Cost Estimating ............................................................................................... 368 4.3 Supercritical PC cases......................................................................................................374 4.3.1 Process Description...................................................................................................... ....374 4.3.2 Key System Assumptions ................................................................................................377 4.3.3 Sparing Philosophy ....................................................................................................... ...378 4.3.4 Case 11 Performance Results...........................................................................................378 4.3.5 Case 11 – Major Equipment List .....................................................................................386 4.3.6 Case 11 – Costs Estimating Results.................................................................................394 4.3.7 Case 12 – Supercritical PC with CO2 Capture ................................................................400 4.3.8 Case 12 Performance Results...........................................................................................400 4.3.9 Case 12 – Major Equipment List .....................................................................................410 4.3.10 Case 12 – Cost Estimating Basis .....................................................................................418 4.4 PC Case Summary ...........................................................................................................424 5 Natural Gas Combined Cycle Plants............................................................................431 5.1 NGCC Common Process Areas.......................................................................................431 5.1.1 Natural Gas Supply System .............................................................................................431 5.1.2 Combustion Turbine ....................................................................................................... .431 5.1.3 Heat Recovery Steam Generator......................................................................................433 5.1.4 NOx Control System....................................................................................................... .433 5.1.5 Carbon Dioxide Recovery Facility ..................................................................................434 5.1.6 Steam Turbine............................................................................................................ ......436 5.1.7 Water and Steam Systems................................................................................................43 7 5.1.8 Accessory Electric Plant ................................................................................................. .439 5.1.9 Instrumentation and Control ............................................................................................43 9 5.2 NGCC Cases ................................................................................................................. ...440 5.2.1 Process Description...................................................................................................... ....440 5.2.2 Key System Assumptions ................................................................................................443 5.2.3 Sparing Philosophy ....................................................................................................... ...444 5.2.4 Case 13 Performance Results...........................................................................................445 5.2.5 Case 13 – Major Equipment List .....................................................................................452 5.2.6 Case 13 – Cost Estimating ...............................................................................................4 57 5.2.7 Case 14 – NGCC with CO2 Capture ...............................................................................463 5.2.8 Case 14 Performance Results..........................................................................................463 5.2.9 Case 14 Major Equipment List ........................................................................................472 5.2.10 Case 14 – Cost Estimating ............................................................................................... 478 5.3 NGCC Case Summary .....................................................................................................484

vCost and Performance Baseline for Fossil Energy Plants



### 6 Revision Control............................................................................................................. 489 7 References................................................................................................................... ....491

viCost and Performance Baseline for Fossil Energy Plants



## LIST OF EXHIBITS Exhibit ES-1 Case Descriptions................................................................................................ ......2 Exhibit ES-2 Cost and Performance Summary and Environmental Profile for All Cases .............4 Exhibit ES-3 Net Plant Efficiency (HHV Basis) ............................................................................5 Exhibit ES-4 Water Demand and Usage.........................................................................................8 Exhibit ES-5 Total Plant Cost................................................................................................. ......10 Exhibit ES-6 Economic Parameters Used to Calculate LCOE.....................................................11 Exhibit ES-7 LCOE By Cost Component.....................................................................................12 Exhibit ES-8 LCOE Sensitivity to Fuel Costs in Non-Capture Cases..........................................14 Exhibit ES-9 LCOE Sensitiv ity to Fuel Costs in CO 2 

### Capture Cases ..........................................14 Exhibit ES-10 LCOE Sensitivity to Capacity Factor....................................................................15 Exhibit ES-11 CO 2 

### Capture Costs ................................................................................................17 Exhibit ES-12 Study Environmental Targets................................................................................18 Exhibit ES-13 SO 2 

### , NOx and Particulate Emission Rates............................................................19 Exhibit ES-14 Mercury Emission Rates .......................................................................................20 Exhibit ES-15 CO 2 

### Emissions Normalized By Gross Output ......................................................23 Exhibit 1-1 Case Descriptions ................................................................................................. .....27 Exhibit 2-1 Site Ambient Conditions........................................................................................... .29 Exhibit 2-2 Site Characteristics .............................................................................................. ......29 Exhibit 2-3 Design Coal....................................................................................................... .........31 Exhibit 2-4 Natura l Gas Composition........................................................................................... 32 Exhibit 2-5 Standards of Performance fo r Electric Utility Steam Generating Units....................33 Exhibit 2-6 NSPS Mercury Emission Limits................................................................................34 Exhibit 2-7 Probability Distri bution of Mercury Concentrati on in the Illinois No. 6 Coal..........35 Exhibit 2-8 Environmenta l Targets for IGCC Cases ....................................................................35 Exhibit 2-9 Environmenta l Targets for PC Cases.........................................................................37 Exhibit 2-10 Environmenta l Targets for NGCC Cases.................................................................38 Exhibit 2-11 CO 2 

### Pipeline Specification ......................................................................................48 Exhibit 2-12 Deep, Saline Aquifer Specification .........................................................................49 Exhibit 2-13 Economic Parame nters for LCOE Calculation........................................................51 Exhibit 2-14 Parameter Assumpti ons for Capital Charge Factors................................................52 Exhibit 2-15 Financial Structure for Invest or Owned Utility High and Low Risk Projects.........52 Exhibit 3-1 Air Extracted from the Combus tion Turbine and Supplied to the ASU in NonCarbon Capture Cases ............................................................................................................60 Exhibit 3-2 Typical ASU Process Schematic ...............................................................................61 Exhibit 3-3 Flow Diagram for a Conventional AGR Unit............................................................65 Exhibit 3-4 Common Chemical Reag ents Used in AGR Processes .............................................66 Exhibit 3-5 Physical Solvent AGR Process Simplified Flow Diagram........................................67 Exhibit 3-6 Common Ph ysical Solvents Used in AGR Processes................................................68 Exhibit 3-7 Common Mixed Solven ts Used in AGR Processes...................................................69 Exhibit 3-8 Equilibrium Solubility Data on H 2 

### S and CO 2 

### in Various Solvents ...........................69 Exhibit 3-9 Typical Three- Stage Claus Sulfur Plant ....................................................................72 Exhibit 3-10 Advanced F Class Combusti on Turbine Performance Characteristics Using Natural Gas................................................................................................................... ..........75 Exhibit 3-11 Combustion Turb ine Typical Scope of Supply........................................................76

viiCost and Performance Baseline for Fossil Energy Plants



### Exhibit 3-12 Typical Fuel Specification for F-Class Machines....................................................78 Exhibit 3-13 Allowable Gas Fuel C ontaminant Level for F-Class Machines ..............................79 Exhibit 3-14 Case 1 Process Fl ow Diagram, GEE IGCC without CO 2 

### Capture ..........................90 Exhibit 3-15 Case 1 Stream Table, GEE IGCC without CO 2 

### Capture .........................................91 Exhibit 3-16 GEE IGCC Plant Study Configuration Matrix ........................................................95 Exhibit 3-17 Balance of Plant Assumptions .................................................................................96 Exhibit 3-18 Case 1 Plant Performance Summary .......................................................................98 Exhibit 3-19 Case 1 Air Emissions............................................................................................. ..99 Exhibit 3-20 Case 1 Carbon Balance..........................................................................................100 Exhibit 3-21 Case 1 Sulfur Balance............................................................................................100 Exhibit 3-22 Case 1 Water Balance............................................................................................1 01 Exhibit 3-23 Case 1 Coal Gasification a nd Air Separation Units Heat and Mass Balance Schematic ...................................................................................................................... .......103 Exhibit 3-24 Case 1 Syngas Cleanup Heat and Mass Balance Schematic .................................104 Exhibit 3-25 Case 1 Sulfur Recovery a nd Tail Gas Recycle Heat and Mass Balance Schematic ..................................................................................................................... ........105 Exhibit 3-26 Case 1 Combined-Cycle Power Generation Heat and Mass Balance Schematic ..106 Exhibit 3-27 Case 1 Steam and Feed water Heat and Mass Balance Schematic.........................107 Exhibit 3-28 Case 1 Overall Ener gy Balance (0°C [32°F] Reference).......................................109 Exhibit 3-29 Case 1 Total Plant Cost Summary .........................................................................119 Exhibit 3-30 Case 1 Total Plant Cost Details .............................................................................120 Exhibit 3-31 Case 1 Initial and Annual O&M Costs ..................................................................123 Exhibit 3-32 Case 2 Process Flow Diagram, GEE IGCC with CO 2 

### Capture .............................125 Exhibit 3-33 Case 2 Stream Table, GEE IGCC with CO 2 

### Capture ............................................126 Exhibit 3-34 Case 2 Plant Performance Summary .....................................................................130 Exhibit 3-35 Case 2 Air Emissions............................................................................................. 131 Exhibit 3-36 Case 2 Carbon Balance..........................................................................................132 Exhibit 3-37 Case 2 Sulfur Balance............................................................................................132 Exhibit 3-38 Case 2 Water Balance............................................................................................1 33 Exhibit 3-39 Case 2 Coal Gasification a nd Air Separation Units Heat and Mass Balance Schematic ...................................................................................................................... .......135 Exhibit 3-40 Case 2 Syngas Cleanup Heat and Mass Balance Schematic .................................136 Exhibit 3-41 Case 2 Sulfur Recovery a nd Tail Gas Recycle Heat and Mass Balance Schematic ..................................................................................................................... ........137 Exhibit 3-42 Case 2 Combined-Cycle Power Generation Heat and Mass Balance Schematic ..138 Exhibit 3-43 Case 2 Steam and Feed water Heat and Mass Balance Schematic.........................139 Exhibit 3-44 Case 2 Overall Ener gy Balance (0°C [32°F] Reference).......................................141 Exhibit 3-45 Case 2 Total Plant Cost Summary .........................................................................152 Exhibit 3-46 Case 2 Total Plant Cost Details .............................................................................153 Exhibit 3-47 Case 2 Initial and A nnual Operating and Maintenance Costs ...............................156 Exhibit 3-48 Case 3 Process Flow Diagram, E-GasTM IGCC without CO 2 

### Capture..................160 Exhibit 3-49 Case 3 Stream Table, E-GasTM IGCC without CO 2 

### Capture.................................161 Exhibit 3-50 CoP IGCC Plan t Study Configuration Matrix .......................................................166 Exhibit 3-51 Case 3 Plant Performance Summary .....................................................................168 Exhibit 3-52 Case 3 Air Emissions............................................................................................. 169 Exhibit 3-53 Case 3 Carbon Balance..........................................................................................170

viiiCost and Performance Baseline for Fossil Energy Plants



### Exhibit 3-54 Case 3 Sulfur Balance............................................................................................170 Exhibit 3-55 Case 3 Water Balance............................................................................................1 71 Exhibit 3-56 Case 3 Coal Gasification a nd Air Separation Unit Heat and Mass Balance Schematic ...................................................................................................................... .......173 Exhibit 3-57 Case 3 Syngas Cleanup Heat and Mass Balance Schematic .................................174 Exhibit 3-58 Case 3 Sulfur Recovery a nd Tail Gas Recycle Heat and Mass Balance Schematic ..................................................................................................................... ........175 Exhibit 3-59 Case 3 Combined Cycle Power Generation Heat and Mass Balance Schematic ..176 Exhibit 3-60 Case 3 Steam and Feed water Heat and Mass Balance Schematic.........................177 Exhibit 3-61 Case 3 Overall Ener gy Balance (0°C [32°F] Reference).......................................179 Exhibit 3-62 Case 3 Total Plant Cost Summary .........................................................................189 Exhibit 3-63 Total Plant Cost Details ......................................................................................... 190 Exhibit 3-64 Case 3 Initial and A nnual Operating and Maintenance Costs ...............................193 Exhibit 3-65 Case 4 Process Flow Diagram, E-GasTM IGCC with CO 2 

### Capture .......................195 Exhibit 3-66 Case 4 Stream Table, E-GasTM IGCC with CO 2 

### Capture ......................................196 Exhibit 3-67 Case 4 Plant Performance Summary .....................................................................200 Exhibit 3-68 Case 4 Air Emissions............................................................................................. 201 Exhibit 3-69 Case 4 Carbon Balance..........................................................................................202 Exhibit 3-70 Case 4 Sulfur Balance............................................................................................202 Exhibit 3-71 Case 4 Water Balance............................................................................................2 03 Exhibit 3-72 Case 4 Coal Gasification a nd Air Separation Unit Heat and Mass Balance Schematic ...................................................................................................................... .......205 Exhibit 3-73 Case 4 Syngas Cleanup Heat and Mass Balance Schematic .................................206 Exhibit 3-74 Case 4 Sulfur Recover a nd Tail Gas Recycle Heat and Mass Balance Schematic ..................................................................................................................... ........207 Exhibit 3-75 Case 4 Combined Cycle Power Generation Heat and Mass Balance Schematic ..208 Exhibit 3-76 Case 4 Steam and Feed water Heat and Mass Balance Schematic.........................209 Exhibit 3-77 Case 4 Overall Ener gy Balance (0°C [32°F] Reference).......................................211 Exhibit 3-78 Case 4 Total Plant Cost Summary .........................................................................221 Exhibit 3-79 Case 4 Total Plant Cost Details .............................................................................222 Exhibit 3-80 Case 4 Initial and A nnual Operating and Maintenance Costs ...............................225 Exhibit 3-81 Case 5 Process Flow Diagram, Shell IGCC without CO 2 

### Capture........................229 Exhibit 3-82 Case 5 Stream Table, Shell IGCC without CO 2 

### Capture.......................................230 Exhibit 3-83 Shell IGCC Plant Study Configuration Matrix......................................................236 Exhibit 3-84 Case 5 Plant Performance Summary .....................................................................238 Exhibit 3-85 Case 5 Air Emissions............................................................................................. 239 Exhibit 3-86 Case 5 Carbon Balance..........................................................................................240 Exhibit 3-87 Case 5 Sulfur Balance............................................................................................240 Exhibit 3-88 Case 5 Water Balance............................................................................................2 41 Exhibit 3-89 Case 5 Coal Gasification a nd Air Separation Unit Heat and Mass Balance Schematic ...................................................................................................................... .......243 Exhibit 3-90 Case 5 Syngas Cleanup Heat and Mass Balance Schematic .................................244 Exhibit 3-91 Case 5 Sulfur Recovery a nd Tail Gas Recycle Heat and Mass Balance Schematic ..................................................................................................................... ........245 Exhibit 3-92 Case 5 Combined Cycle Power Generation Heat and Mass Balance Schematic ..246 Exhibit 3-93 Case 5 Steam and Feed water Heat and Mass Balance Schematic.........................247

ixCost and Performance Baseline for Fossil Energy Plants



### Exhibit 3-94 Case 5 Overall Ener gy Balance (0°C [32°F] Reference).......................................249 Exhibit 3-95 Case 5 Total Plant Cost Summary .........................................................................259 Exhibit 3-96 Case 5 Total Plant Cost Details .............................................................................260 Exhibit 3-97 Case 5 Initial and A nnual Operating and Maintenance Costs ...............................263 Exhibit 3-98 Case 6 Process Flow Diagram, Shell IGCC with CO 2 

### Capture.............................265 Exhibit 3-99 Case 6 Stream Table, Shell IGCC with CO 2 

### Capture............................................266 Exhibit 3-100 Case 6 Plant Performance Summary ...................................................................270 Exhibit 3-101 Case 6 Air Emissions...........................................................................................2 71 Exhibit 3-102 Case 6 Carbon Balance........................................................................................272 Exhibit 3-103 Case 6 Sulfur Balance..........................................................................................272 Exhibit 3-104 Case 6 Water Balance..........................................................................................27 3 Exhibit 3-105 Case 6 Coal Gasification a nd Air Separation Unit Heat and Mass Balance Schematic ...................................................................................................................... .......275 Exhibit 3-106 Case 6 Syngas Cleanup Heat and Mass Balance Schematic ...............................276 Exhibit 3-107 Case 6 Sulfur Recovery and Tail Gas Recycle Heat and Mass Balance Schematic ..................................................................................................................... ........277 Exhibit 3-108 Case 6 Combined Cycle Power Generation Heat and Mass Balance Schematic ..................................................................................................................... ........278 Exhibit 3-109 Case 6 Steam and Feed water Heat and Mass Balance Schematic.......................279 Exhibit 3-110 Case 6 Overall Energy Balance (0°C [32°F] Reference).....................................281 Exhibit 3-111 Case 6 Total Plant Cost Summary .......................................................................291 Exhibit 3-112 Case 6 Total Plant Cost Details ...........................................................................292 Exhibit 3-113 Case 6 Initial and A nnual Operating and Maintenance Costs .............................295 Exhibit 3-114 Estimated Performanc e and Cost Results for IGCC Cases..................................296 Exhibit 3-115 TPC for IGCC Cases............................................................................................29 7 Exhibit 3-116 LCOE for IGCC Cases ........................................................................................298 Exhibit 3-117 Capacity Factor Sensitivity of IGCC Cases.........................................................299 Exhibit 3-118 Coal Price Sensitivity of IGCC Cases .................................................................300 Exhibit 3-119 Cost of CO 2 

### Captured and Avoided in IGCC Cases............................................300 Exhibit 3-120 Carbon Conversion Effi ciency and Slag Carbon Content ...................................301 Exhibit 3-121 Water Usage in IGCC Cases................................................................................303 Exhibit 4-1 Fluor Econamine FG Plus Typical Flow Diagram ..................................................314 Exhibit 4-2 CO2 Compresso r Interstage Pressures.....................................................................317 Exhibit 4-3 Case 9 Process Flow Diagra m, Subcritical Unit without CO2 Capture ..................324 Exhibit 4-4 Case 9 Stream Table, S ubcritical Unit without CO2 Capture .................................325 Exhibit 4-5 Subcritical PC Pl ant Study Configuration Matrix ...................................................326 Exhibit 4-6 Balance of Plant Assumptions .................................................................................327 Exhibit 4-7 Case 9 Plan t Performance Summary .......................................................................329 Exhibit 4-8 Case 9 Air Emissions.............................................................................................. .330 Exhibit 4-9 Case 9 Water Balance.............................................................................................. 331 Exhibit 4-10 Case 9 Heat and Mass Balance, Subcritical PC Boiler without CO2 Capture ......333 Exhibit 4-11 Case 9 Overall Ener gy Balance (0°C [32°F] Reference).......................................335 Exhibit 4-12 Case 9 Total Plant Cost Summary .........................................................................345 Exhibit 4-13 Case 9 Total Plant Cost Details .............................................................................346 Exhibit 4-14 Case 9 Initial and A nnual Operating and Maintenance Costs ...............................349 Exhibit 4-15 Case 10 Process Flow Diagra m, Subcritical Unit with CO2 Capture ...................351

xCost and Performance Baseline for Fossil Energy Plants



### Exhibit 4-16 Case 10 Stream Table, Subcritical Unit with CO2 Capture ...................................352 Exhibit 4-17 Case 10 Plant Performance Summary ....................................................................353 Exhibit 4-18 Case 10 Air Emissions...........................................................................................3 54 Exhibit 4-19 Case 10 Water Balance..........................................................................................35 5 Exhibit 4-20 Case 10 Heat and Mass Balan ce, Subcritical PC Boiler with CO2 Capture .........357 Exhibit 4-21 Case 10 Overall Energy Balance (0°C [32°F] Reference).....................................359 Exhibit 4-22 Case 10 Total Plant Cost Summary .......................................................................369 Exhibit 4-23 Case 10 Total Plant Cost Details ...........................................................................370 Exhibit 4-24 Case 10 Initial and A nnual Operating and Maintenance Costs .............................373 Exhibit 4-25 Case 11 Process Flow Diagra m, Supercritical Unit without CO2 Capture ...........375 Exhibit 4-26 Case 11 Stream Table, Supercritical Unit without CO2 Capture ..........................376 Exhibit 4-27 Supercritical PC Plant Study Configuration Matrix ..............................................377 Exhibit 4-28 Case 11 Plant Performance Summary ...................................................................379 Exhibit 4-29 Case 11 Air Emissions...........................................................................................3 80 Exhibit 4-30 Case 11 Water Balance..........................................................................................38 1 Exhibit 4-31 Case 11 Heat and Mass Balance, Supercritical PC Boiler without CO2 Capture .383 Exhibit 4-32 Case 11 Overall Energy Balance (0°C [32°F] Reference).....................................385 Exhibit 4-33 Case 11 Total Plant Cost Summary .......................................................................395 Exhibit 4-34 Case 11 Total Plant Cost Details ...........................................................................396 Exhibit 4-35 Case 11 Initial and A nnual Operating and Maintenance Costs .............................399 Exhibit 4-36 Case 12 Process Flow Diagra m, Supercritical Unit with CO2 Capture ................401 Exhibit 4-37 Case 12 Stream Table, Supercritical Unit with CO2 Capture ...............................402 Exhibit 4-38 Case 12 Plant Performance Summary ...................................................................403 Exhibit 4-39 Case 12 Air Emissions...........................................................................................4 04 Exhibit 4-40 Case 12 Water Balance..........................................................................................40 5 Exhibit 4-41 Case 12 Heat and Mass Balance, Supercritical PC Boiler with CO2 Capture ......407 Exhibit 4-42 Case 12 Overall Energy Balance (0°C [32°F] Reference).....................................409 Exhibit 4-43 Case 12 Total Plant Cost Summary .......................................................................419 Exhibit 4-44 Case 12 Total Plant Cost Details ...........................................................................420 Exhibit 4-45 Case 12 Initial and A nnual Operating and Maintenance Costs .............................423 Exhibit 4-46 Estimated Performance and Co st Results for Pulverized Coal Cases ...................424 Exhibit 4-47 Total Plant Cost for PC Cases................................................................................425 Exhibit 4-48 LCOE for PC Cases ...............................................................................................4 26 Exhibit 4-49 Sensitivity of LCOE to Capacity Factor for PC Cases ..........................................427 Exhibit 4-50 Sensitivity of LCOE to Coal Price for PC Cases...................................................427 Exhibit 4-51 Cost of CO2 Capt ured and Avoided in PC Cases..................................................428 Exhibit 4-52 Water Usage in PC Cases ......................................................................................430 Exhibit 5-1 Combustion Turbin e Typical Scope of Supply........................................................432 Exhibit 5-2 CO2 Compresso r Interstage Pressures.....................................................................437 Exhibit 5-3 Case 13 Process Flow Diagram, NGCC without CO2 Capture...............................441 Exhibit 5-4 Case 13 Stream Ta ble, NGCC without CO2 Capture..............................................442 Exhibit 5-5 NGCC Plant St udy Configuration Matrix ...............................................................443 Exhibit 5-6 NGCC Balan ce of Plant Assumptions.....................................................................444 Exhibit 5-7 Case 13 Plant Performance Summary .....................................................................445 Exhibit 5-8 Case 13 Air Emissions............................................................................................. 446 Exhibit 5-9 Case 13 Water Balance............................................................................................4 47

xiCost and Performance Baseline for Fossil Energy Plants



### Exhibit 5-10 Case 13 Heat and Mass Balance, NGCC without CO2 Capture ...........................449 Exhibit 5-11 Case 13 Overall Energy Balance (0°C [32°F] Reference).....................................451 Exhibit 5-12 Case 13 Total Plant Cost Summary .......................................................................458 Exhibit 5-13 Case 13 Total Plant Cost Details ...........................................................................459 Exhibit 5-14 Case 13 Initial and Annual Operating and Maintenance Cost Summary ..............462 Exhibit 5-15 Case 14 Process Flow Diagram, NGCC with CO2 Capture..................................464 Exhibit 5-16 - Case 14 Stream Table, NGCC with CO2 Capture ...............................................465 Exhibit 5-17 Case 14 Plant Performance Summary ...................................................................466 Exhibit 5-18 Case 14 Air Emissions...........................................................................................4 67 Exhibit 5-19 Case 14 Water Balance..........................................................................................46 7 Exhibit 5-20 Case 14 Heat and Mass Balance, NGCC with CO2 Capture.................................469 Exhibit 5-21 Case 14 Overall Energy Balance (0°C [32°F] Reference).....................................471 Exhibit 5-22 Case 14 Total Plant Cost Summary .......................................................................479 Exhibit 5-23 Case 14 Total Plant Cost Details ...........................................................................480 Exhibit 5-24 Case 14 Initial and Annual Operating and Maintena nce Cost Summary ..............483 Exhibit 5-25 Estimated Performanc e and Cost Results for NGCC Cases..................................484 Exhibit 5-26 TPC of NGCC Cases .............................................................................................485 Exhibit 5-27 LCOE of NGCC Cases ..........................................................................................485 Exhibit 5-28 Sensitivity of LCOE to Capacity Factor in NGCC Cases .....................................486 Exhibit 5-29 Sensitivity of LCOE to Fuel Price in NGCC Cases...............................................487 Exhibit 5-30 Water Usage in NGCC Cases ................................................................................488 Exhibit 6-1 Record of Revisions............................................................................................... ..489

xiiCost and Performance Baseline for Fossil Energy Plants



## ACKNOWLEDGEMENTS

This report was prepared by Research and Development Solutions, LLC (RDS) for the United States Department of Energy’s Na tional Energy Technology Laboratory . This work was completed under DOE NETL Contract Numb er DE-AC26-04NT41817. This work was performed under RDS Subtask 401.01.04, Activity 002. The authors wish to acknowledge the excellent contributions and cooperation of NETL st aff, particularly: Julianne Klara, NETL Technical Monitor
Daniel Cicero
Jared Ciferno Jeffrey Hoffmann
Patrick Le Sean Plasynski
Michael Reed Gary Stiegel Maria Vargas
John Wimer
John Winslow

xiiiCost and Performance Baseline for Fossil Energy Plants



## LIST OF ACRONYMS AND ABBREVIATIONS
AACE Association for the Advan cement of Cost Engineering AC Alternating current AEO Annual Energy Outlook AGR Acid gas removal ANSI American National Standards Institute ASU Air separation unit BACT Best available control technology BEC Bare erected cost BFD Block flow diagram Btu British thermal unit Btu/h British thermal unit per hour Btu/kWh British thermal unit per kilowatt hour Btu/lb British thermal unit per pound Btu/scf British thermal unit per standard cubic foot CAAA Clean Air Act Amendments of 1990 CAIR Clean Air Interstate Rule CAMR Clean Air Mercury Rule CCF Capital Charge Factor CDR Carbon Dioxide Recovery CF Capacity factor CFM Cubic feet per minute CFR Code of Federal Regulations CGE Cold gas efficiency cm Centimeter CO 2 

### Carbon dioxide COE Cost of electricity CoP ConocoPhillips COR Contracting Officer's Representative COS Carbonyl sulfide CRT Cathode ray tube CS Carbon steel CT Combustion turbine CTG Combustion Turbine-Generator CWT Cold water temperature dB Decibel DCS Distributed control system DI De-ionized Dia. Diameter DLN Dry low NOx DOE Department of Energy EAF Equivalent availability factor

xivCost and Performance Baseline for Fossil Energy Plants



### E-Gas TM 

### ConocoPhillips gasifier technology EIA Energy Information Administration EPA Environmental Protection Agency EPC Engineer/Procure/Construct EPRI Electric Power Research Institute EPCM Engineering/Procurement/Construction Management EU European Union ESP Electrostatic precipitator FD Forced draft FERC Federal Energy Regulatory Commission FG Flue gas FGD Flue gas desulfurization FOAK First of a kind FRP Fiberglass-reinforced plastic ft Foot, Feet ft, w.g. Feet of water gauge GADS Generating Availability Data System gal Gallon gal/MWh Gallon per megawatt hour GDP Gross domestic product GEE GE Energy gpm Gallons per minute gr/100 scf grains per one hundr ed standard cubic feet GT Gas turbine h Hour H 2 

### Hydrogen H 2 

### SO 4 

### Sulfuric acid HAP Hazardous air pollutant HCl Hydrochloric acid Hg Mercury HDPE High density polyethylene HHV Higher heating value hp Horsepower HP High pressure HRSG Heat recovery steam generator HSS Heat stable salts HVAC Heating, ventilati ng, and air conditioning HWT Hot water temperature Hz Hertz ICR Information Collection Request ID Induced draft IGVs Inlet guide vanes In. H 2 

### O Inches water

xvCost and Performance Baseline for Fossil Energy Plants



### In. Hga Inches mercury (absolute pressure) In. W.C. Inches water column IEEE Institute of Electrical and Electronics Engineers IGCC Integrated gasification combined cycle IGV Inlet guide vanes IOU Investor-owned utility IP Intermediate pressure IPM Integrated Planning Model IPP Independent power producer ISO International Standards Organization KBR Kellogg, Brown and Root, a subsidiary of Halliburton kg/GJ Kilogram per gigajoule kg/h Kilogram per hour kJ Kilojoules kJ/h Kilojoules per hour kJ/kg Kilojoules per kilogram KO Knockout kPa Kilopascal absolute kV Kilovolt kW Kilowatt kWe Kilowatts electric kWh Kilowatt-hour LAER Lowest Achievable Emission Rate lb Pound lb/h Pounds per hour lb/ft 2 

### Pounds per square foot lb/MMBtu Pounds per million British thermal units lb/MWh Pounds per megawatt hour lb/TBtu Pounds per trillion British thermal units LCOE Levelized cost of electricity LF Fn 

### Levelization factor for category n fixed operating cost LF Vn 

### Levelization factor for cate gory n variable operating cost LGTI Louisiana Gasification Technology, Inc. LHV Lower heating value LNB Low NOx burner LP Low pressure lpm Liters per minute m Meters m/min Meters per minute

m 3 

### /min Cubic meter per minute MAF Moisture and Ash Free MCR Maximum continuous rate MDEA Methyldiethanolamine

xviCost and Performance Baseline for Fossil Energy Plants



### MEA Monoethanolamine MHz Megahertz MJ/Nm 3 

### Megajoule per normal cubic meter MMBtu Million British thermal units (also shown as 10 6 

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

### Btu) per hour MMkJ Million kilojoules (also shown as 10 6 

### kJ) MMkJ/h Million kilojoules (also shown as 10 6 

### kJ) per hour MNQC Multi Nozzle Quiet Combustor MPa Megapascals MVA Mega volt-amps MWe Megawatts electric MWh Megawatt-hour MWt Megawatts thermal N/A Not applicable NAAQS National Ambient Air Quality Standards NEMA National Electrical Manufacturers Association NERC North American Elec tric Reliability Council NETL National Energy Technology Laboratory NFPA National Fire Protection Association NGCC Natural gas combined cycle Nm 3 

### Normal cubic meter NOx Oxides of nitrogen NSPS New Source Performance Standards NSR New Source Review O&M Operation and maintenance OC Fn 

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

### Category n variable operating cost for the initial year of operation OD Outside diameter OFA Overfire air OP/VWO Over pressure/valve wide open OSHA Occupational Safety a nd Health Administration OTR Ozone transport region PA Primary air PAC Powdered activated carbon PC Pulverized coal PF Power Factor PM Particulate matter PM 10 

### Particulate matter measuring 10 μ m or less POTW Publicly Owned Treatment Works ppm Parts per million ppmv Parts per million volume ppmvd Parts per million volume, dry PPS Polyphenylensulfide

xviiCost and Performance Baseline for Fossil Energy Plants



### PRB Powder River Basin coal region PSA Pressure Swing Adsorption PSD Prevention of Significant Deterioration psia Pounds per square inch absolute psid Pounds per square inch differential psig Pounds per square inch gage PTFE Teflon (Polytet rafluoroethylene) Qty Quantity RDS Research and Development Solutions, LLC RH Reheater scfh Standard cubic feet per hour scfm Standard cubi c feet per minute Sch. Schedule scmh Standard cubic meter per hour SCOT Shell Claus Off-gas Treating SCR Selective catalytic reduction SG Specific gravity SGC Synthesis gas cooler SGS Sour gas shift SIP State implementation plan SNCR Selective non-catalytic reduction SO 2 

### Sulfur dioxide SOx Oxides of sulfur SRU Sulfur recovery unit SS Stainless steel SS Amine SS Specialty Amine STG Steam turbine generator TCR Total capital requirement TEWAC Totally Enclosed Water-to-Air Cooled TGTU Tail gas treating unit Tonne Metric Ton (1000 kg) TPC Total plant cost TPD Tons per day TPH Tons per hour TPI Total plant investment TS&M Transport, storage and monitoring V-L Vapor Liquid portion of stream (excluding solids) vol% Volume percent WB Wet bulb wg Water gauge wt% Weight percent $/MMBtu Dollars per million British thermal units $/MMkJ Dollars per million kilojoule

xviiiCost and Performance Baseline for Fossil Energy Plants



## EXECUTIVE SUMMARY The objective of this report is to present an ac curate, independent assessment of the cost and performance of fossil energy power systems, speci fically integrated gasification combined cycle (IGCC), pulverized coal (PC), and natural gas combined cycle (NG CC) plants, using a consistent technical and economic approach that accurately reflects current market conditions for plants starting operation in 2010. This is Volume 1 of a three volume report. The three volume series consists of the following:

• Volume 1: Electricity production using bituminous coal for coal-based technologies

• Volume 2: Synthetic natural gas production a nd repowering using a va riety of coal types

• Volume 3: Electricity production fr om low rank coal (PC and IGCC) The cost and performance of the various fo ssil fuel-based technologies will most likely determine which combination of technologies will be utilized to meet th e demands of the power market. Selection of new generation tec hnologies will depend on many factors, including:

• Capital and operating costs

• Overall energy efficiency

• Fuel prices

• Cost of electricity (COE)

• Availability, reliability and environmental performance

• Current and potential regulati on of air, water, and solid waste discharges from fossilfueled power plants

• Market penetration of clean co al technologies that have ma tured and improved as a result of recent commercial-scale demonstrations under the Department of Energy’s (DOE’s) Clean Coal Programs Twelve power plant configurations were analyzed as listed in Exhibit ES-1 . The list includes six IGCC cases utilizing General Electric Energy (GEE), ConocoPhillips (CoP), and Shell gasifiers each with and without CO 2 

### capture; four PC cases, two subcritical and two supercritical, each with and without CO 2 

### capture; and two NGCC plants with and without CO 2 

### capture. Two additional cases were originally included in this study and involve pr oduction of synthetic natural gas (SNG) and the repower ing of an existing NGCC facility using SNG. The two SNG cases were subsequently moved to Volume 2 of th is report resulting in th e discontinuity of case numbers (1-6 and 9-14). The two SNG cases are now cases 2 and 2a in Volume 2. While input was sought from va rious 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 collabora tion with technology vendors vari ed from case to case, with minimal or no collaboration obtained from some vendors. The methodology included performing steady-state si mulations of the various technologies using the Aspen Plus (Aspen) modeling program. The resulting mass and energy balance data from the Aspen model were used to size major pieces of equipment. These equipment sizes formed the basis for cost estimating. Performance and pr ocess limits were based upon published reports,

1Cost and Performance Baseline for Fossil Energy Plants



### information obtained from vendors and users of the technology, performance data from design/build utility projects, an d/or best engineering judgement . Capital and operating costs were estimated by WorleyParsons based on simu lation results and through a combination of vendor quotes, scaled estimates from previous design/ build projects, or a comb ination of the two. Baseline fuel costs for this analysis were dete rmined using data from the Energy Information Administration’s (EIA) Annual En ergy Outlook (AEO) 2007. The fi rst year (2010) costs used are $1.71/MMkJ ($1.80/MMBtu) for coal (Illinois No. 6) and $6.40/MMkJ ($6.75/MMBtu) for natural gas, both on a higher heating valu e (HHV) basis and in 2007 U.S. dollars.
Exhibit ES-1 Case Descriptions

Case Unit Cycle Steam Cycle, psig/ ° F/ ° F Combustion Turbine Gasifier/Boiler Technology Oxidant H 2 S Separation/

Removal Sulfur Removal/ Recovery CO 2Separation

1 IGCC 1800/1050/1050 2 x Advanced F Class GEE Radiant Only 95 mol% O 2 Selexol Claus Plant

2 IGCC 1800/1000/1000 2 x Advanced F Class GEE Radiant Only 95 mol% O 2 Selexol Claus Plant Selexol 2 nd stage

3 IGCC 1800/1050/1050 2 x Advanced F Class CoP E-GasTM 95 mol% O 2 Refrigerated MDEA Claus Plant

4 IGCC 1800/1000/1000 2 x Advanced F Class CoP E-GasTM 95 mol% O 2 Selexol Claus Plant Selexol 2 nd stage

5 IGCC 1800/1050/1050 2 x Advanced F Class Shell 95 mol% O 2 Sulfinol-M Claus Plant

6 IGCC 1800/1000/1000 2 x Advanced F Class Shell 95 mol% O 2 Selexol Claus Plant Selexol 2 nd stage

-- -- -- -- -- -- -- -- --

-- -- -- -- -- -- -- -- --

9 PC 2400/1050/1050 Subcritical PC Air Wet FGD/ Gypsum

10 PC 2400/1050/1050 Subcritical PC Air Wet FGD/ Gypsum Amine Absorber

11 PC 3500/1100/1100 Supercritical PC Air Wet FGD/ Gypsum

12 PC 3500/1100/1100 Supercritical PC Air Wet FGD/ Gypsum Amine Absorber

13 NGCC 2400/1050/950 2 x Advanced F Class HRSG Air

14 NGCC 2400/1050/950 2 x Advanced F Class HRSG Air Amine Absorber


### All plant configurations are eval uated based on installation at a gr eenfield site. Since these are state-of-the-art plants, they will have higher effi ciencies than the averag e power plant population. Consequently, these plants would be expected to be near the top of the dispatch list and the study capacity factor is chosen to reflect the maximum availability demonstrated for the specific plant type, i.e. 80 percent for IGCC and 85 percent for PC and NGCC configurations. Since variations in fuel costs and other factors can influence di spatch order and capacity factor, sensitivity of

2Cost and Performance Baseline for Fossil Energy Plants

3 

### levelized COE to capacity factor is evaluated and presented later in this Executive Summary ( Exhibit ES-10 ) and in the body of the report. The nominal net plant output fo r this study is set at 550 MW. The actual net output varies between technologies because the combustion turbines in the IGCC and NGCC cases are manufactured in discrete sizes, but the boilers and steam turbines in the PC cases are readily available in a wide range of capaciti es. The result is that all of the PC cases have a net output of 550 MW, but the IGCC cases have net outputs ra nging from 517 to 640 MW. The range in IGCC net output is caused by the much hi gher auxiliary load imposed in the CO 2 

### capture cases, primarily due to CO 2 

### compression, and the need for extrac tion steam in the water-gas shift reactions, which reduces steam turbine output. Higher auxiliary load and extraction steam requirements can be accommodated in the PC case s (larger boiler and stea m turbine) but not in the IGCC cases where it is impossible to mainta in a constant net output from the steam cycle given the fixed input (combustion turbine). Likewise, the two NGC C cases have a net output of 560 and 482 MW because of the combustion turbine constraint.
Exhibit ES-2 shows the cost, performance and environm ental profile summary for all cases. The results are discussed below in the following order:

• Performance (efficiency and raw water usage)

• Cost (total plant cost and levelized cost of electricity)

• Environmental profile

PERFORMANCE

E NERGY 

### E FFICIENCY 

### The net plant efficiency (HHV basis) for all 12 cases is shown in Exhibit ES-3 . The primary conclusions that ca n be drawn are:

• The NGCC with no CO 2 

### capture has the highest net efficiency of the technologies modeled in this study with an efficiency of 50.8 percent.

• The NGCC case with CO 2 

### capture results in the highe st efficiency (43.7 percent) among all of the capture technologies.

• The NGCC with CO 2 

### capture results in an efficiency penalty of 7.1 absolute percent, relative to the non-capture cas e. The NGCC penalty is le ss than for the PC cases because natural gas is less carbon intens ive than coal, and there is less CO 2 

### to capture and to compress for equal net power outputs.

• The energy efficiency of the IGCC non-capture cases is as follows: the dry-fed Shell gasifier (41.1 percent), the slurry-fed, two-stage CoP gasi fier (39.3 percent) and the slurry-fed, single-stage GEE gasifier (38.2 percent).

• When CO 2 

### capture is added to the IGCC cases, th e energy efficiency of all three cases is almost equal, ranging from 31.7 percen t for CoP to 32.5 percent for GEE, with Shell intermediate at 32.0 percent.Cost and Performance Baseline for Fossil Energy PlantsExhibit ES-2 Cost and Performance Summaryand Environmental Profile for All CasesCase 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 9 Case 10 Case 11 Case 12 Case 13 Case 14CO2CaptureNo Yes No Yes No Yes No Yes No Yes No YesGross Power Output (kWe)770,350 744,960 742,510 693,840 748,020 693,555 583,315 679,923 580,260 663,445 570,200 520,090Auxiliary Power Requirement (kWe)130,100 189,285 119,140 175,600 112,170 176,42032,870 130,310 30,110 117,450 9,840 38,200Net Power Output (kWe)640,250 555,675 623,370 518,240 635,850 517,135 550,445 549,613 550,150 545,995 560,360 481,890Coal Flowrate (lb/hr)489,634 500,379 463,889 477,855 452,620 473,176 437,699 646,589 411,282 586,627 N/A N/ANatural Gas Flowrate (lb/hr)N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 165,182 165,182HHV Thermal Input (kWth)1,674,044 1,710,780 1,586,023 1,633,7711,547,493 1,617,772 1,496,479 2,210,668 1,406,161 2,005,660 1,103,363 1,103,363Net Plant HHV Efficiency (%)38.2% 32.5% 39.3% 31.7% 41.1% 32.0% 36.8% 24.9% 39.1% 27.2% 50.8% 43.7%Net Plant HHV Heat Rate (Btu/kW-hr)8,922 10,505 8,681 10,757 8,304 10,6749,276 13,724 8,72112,534 6,719 7,813Raw Water Usage, gpm4,003 4,579 3,757 4,135 3,792 4,563 6,212 12,187 5,44110,444 2,511 3,901Total Plant Cost ($ x 1,000)1,160,919 1,328,209 1,080,166 1,259,883 1,256,810 1,379,524 852,612 1,591,277 866,391 1,567,073 310,710 564,628Total Plant Cost ($/kW)1,813 2,390 1,733 2,431 1,977 2,668 1,549 2,895 1,575 2,870 554 1,172LCOE (mills/kWh)178.0 102.9 75.3 105.7 80.5 110.464.0 118.8 63.3 114.8 68.4 97.4CO2Emissions (lb/hr)1,123,781 114,476 1,078,144 131,328 1,054,221 103,041 1,038,110 152,975 975,370 138,681 446,339 44,634CO2Emissions (tons/year) @ CF13,937,728 401,124 3,777,815 460,175 3,693,990 361,056 3,864,884 569,524 3,631,301 516,310 1,661,720 166,172CO2Emissions (tonnes/year) @ CF13,572,267 363,896 3,427,196 417,466 3,351,151 327,546 3,506,185 516,667 3,294,280 468,392 1,507,496 150,750CO2Emissions (lb/MMBtu)197 19.6 199 23.6 200 18.7203 20.3 203 20.3 119 11.9CO2Emissions (lb/MWh)21,459 154 1,452 189 1,409 1491,780 225 1,681 209 783 85.8CO2Emissions (lb/MWh)31,755 206 1,730 253 1,658 199 1,886 278 1,773 254 797 93SO2Emissions (lb/hr)73 56 68 48 55 58 433 Negligible 407 Negligible Negligible NegligibleSO2Emissions (tons/year) @ CF1254 196 237 167 194 204 1,613 Negligible 1,514Negligible Negligible NegligibleSO2Emissions (tonnes/year) @ CF1231 178 215 151 176 185 1,463 Negligible 1,373Negligible Negligible NegligibleSO2Emissions (lb/MMBtu)0.0127 0.0096 0.0125 0.0085 0.0105 0.0105 0.0848 Negligible 0.0847 Negligible Negligible NegligibleSO2Emissions (lb/MWh)20.0942 0.0751 0.0909 0.0686 0.0739 0.0837 0.7426 Negligible 0.7007 Negligible Negligible NegligibleNOx Emissions (lb/hr)313 273 321 277 309 269 357 528 336 479 34 34NOx Emissions (tons/year) @ CF11,096 955 1,126 972 1,082 944 1,331 1,966 1,250 1,784 127 127NOx Emissions (tonnes/year) @ CF1994 867 1,021 882 982 856 1,207 1,783 1,134 1,618 115 115NOx Emissions (lb/MMBtu)0.055 0.047 0.059 0.050 0.058 0.049 0.070 0.070 0.070 0.070 0.009 0.009NOx Emissions (lb/MWh)20.406 0.366 0.433 0.400 0.413 0.388 0.613 0.777 0.579 0.722 0.060 0.066PM Emissions (lb/hr)41 41 38 40 37 39 66 98 62 89 Negligible NegligiblePM Emissions (tons/year) @ CF1142 145 135 139 131 137 247 365 232 331 Negligible NegligiblePM Emissions (tonnes/year) @ CF1129 132 122 126 119 125 224 331 211 300 Negligible NegligiblePM Emissions (lb/MMBtu)0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0130 0.0130 0.0130 0.0130 Negligible NegligiblePM Emissions (lb/MWh)20.053 0.056 0.052 0.057 0.050 0.057 0.114 0.144 0.107 0.134 Negligible NegligibleHg Emissions (lb/hr)0.0033 0.0033 0.0031 0.0032 0.0030 0.0032 0.0058 0.0086 0.0055 0.0078 Negligible NegligibleHg Emissions (tons/year) @ CF10.011 0.012 0.011 0.011 0.011 0.011 0.022 0.032 0.020 0.029 Negligible NegligibleHg Emissions (tonnes/year) @ CF10.010 0.011 0.010 0.010 0.010 0.010 0.020 0.029 0.019 0.026 Negligible NegligibleHg Emissions (lb/TBtu)0.571 0.571 0.571 0.571 0.571 0.571 1.14 1.14 1.14 1.14 Negligible NegligibleHg Emissions (lb/MWh)24.24E-06 4.48E-06 4.16E-06 4.59E-06 4.03E-06 4.55E-06 1.00E-05 1.27E-05 9.45E-06 1.18E-05 Negligible Negligible1Capacity factor is 80% for IGCC cases and 85% for PC and NGCC cases2Value is based on gross output3Value is based on net outputGEECoPShellIntegrated Gasification Combined CyclePulverized Coal BoilerNGCCPC Subcritical PC Supercritical Advanced F Class4Cost and Performance Baseline for Fossil Energy Plants538.2%32.5%39.3%31.7%41.1%32.0%36.8%24.9%39.1%27.2%50.8%43.7%0.0%10.0%20.0%30.0%40.0%50.0%60.0%

Efficiency, % (HHV Basis)GEE GEE w/CO2CaptureCoP CoP w/ CO2CaptureShell Shell w/CO2CaptureSubcriticalPCSubcriticalPC w/ CO2CaptureSupercriticalPCSupercriticalPC w/ CO2CaptureNGCC NGCC w/CO2CaptureExhibit ES-3 Net Plant Efficiency (HHV Basis)Cost and Performance Baseline for Fossil Energy Plants



### • Supercritical PC without CO 2 

### capture has an efficiency of 39.1 percent, which is nearly equal to the average of the thr ee non-capture IGCC technologies. Subcritical PC has an efficiency of 36.8 percent, which is the lowest of all the non-capture cases in the study.

• The addition of CO 2 

### capture to the PC cases (Fluor’s Econamine FG Plus process) has a much greater impact on efficiency than CO 2 

### capture in the IGCC cases. This is primarily because the low partial pressure of CO 2 

### in the flue gas from a PC plant requires a chemical absorption process rather than physical absorp tion. For chemical absorption processes, the regeneration require ments are much more energy intensive. Thus the energy penalty for both subcritica l and supercritical PC is 11.9 absolute percent resulting in post-capture effici encies of 24.9 percent and 27.2 percent, respectively.

W ATER 

### U SE 

### Three water values are presented for each technology in Exhibit ES-4 : water demand, internal recycle and raw water usage. Each value is normalized by net output. Demand is the amount of water required to satisfy a particular process (slurry, quench, FGD makeu p, etc.) and internal recycle is water available with in the process (boiler feedwate r blowdown, condensate, etc.). Raw water usage is the difference between demand and recycle, and it represents the overall impact of the process on the wa ter source, which in this study is considered to be 50 percent from groundwater (wells) and 50 pe rcent from a municipal source. All plants are equipped with evaporative cooling towers, and all process bl owdown streams are assumed to be treated and recycled to the cooling tower. The pr imary conclusions that can be drawn are:

• In all cases the primary water consumer is cooling tower makeup, which ranges from 71 to 99 percent of the total raw water usage.

• Among non-capture cases, NGCC requires the least amount of raw water makeup, followed by IGCC and PC. If an average raw water usage for the three IGCC cases and two PC cases is used, the relati ve normalized raw water usage for the technologies is 2.4:1.4:1.0 (P C:IGCC:NGCC). The relative results are as expected given the much higher steam turbine output in the PC cases which results in higher condenser duties, higher cooling water requ irements and ultimately higher cooling water makeup. The IGCC cases and the NGC C case have comparable steam turbine outputs, but IGCC requires additional water for coal slurry (GEE and CoP), syngas quench (GEE), humidification (CoP and Shel l), gasifier steam (Shell), and slag handling (all cases), which increases the IGCC water demand over NGCC.

• Among capture cases, the raw water requireme nt increases (relative to non-capture cases) much more dramatically for the PC and NGCC cases than for IGCC cases because of the large cooling water demand of the Econamine process which results in much greater cooling water makeup requirement s. If average water usage values are used for IGCC and PC cases, the relative normalized raw water usage for the technologies in CO 2 

### capture cases is 2.6:1.03:1.0 (PC:IGCC:NGCC). The NGCC CO 2 

### capture case still has the lowest water requirement, but the difference between it and the average of the three IGCC cases is minimal.

6Cost and Performance Baseline for Fossil Energy Plants

7 

### • CO 2 

### capture increases the average raw wa ter usage for all three technologies evaluated, but the increase is lowest for th e IGCC cases. The average normalized raw water usage for the three IGCC cases increa ses by about 37 percent due primarily to the need for additional water in the syngas to accomplish the water gas shift reaction and the increased auxiliary lo ad. With the addition of CO 2 

### capture, PC normalized raw water usage increases by 95 percent and NGCC by 81 percent. The large cooling water demand of the Econamine process drives this substantial increase for PC and NGCC.Cost and Performance Baseline for Fossil Energy Plants87.76.259.88.26.66.039.78.06.25.9610.88.811.411.324.722.210.09.921.619.14.54.59.28.1051015202530 Water, gpm/MW(net)GEE GEE w/CO2CaptureCoP CoP w/ CO2CaptureShell Shell w/CO2CaptureSubcriticalPCSubcriticalPC w/ CO2CaptureSupercriticalPCSupercriticalPC w/ CO2CaptureNGCC NGCC w/CO2CaptureWater DemandInternal RecycleRaw Water UsageExhibit ES-4 Water Demand and UsageCost and Performance Baseline for Fossil Energy Plants

9 

### COST RESULTS

T OTAL 

### P LANT 

### C OST 

### The total plant cost (TPC) for each technology wa s determined through a combination of vendor quotes, scaled estimates from previous design/buil d projects, or a combination of the two. TPC includes all equipment (complete with initial chem ical and catalyst loadin gs), materials, labor (direct and indirect), engineer ing and construction management, and contingencies (process and project). Owner’s costs are not included. The cost estimates carry an accuracy of ±30 percen t, consistent with the screening study level of design engineering applied to the various cases in this study. The value of the study lies not in the absolute accuracy of the individual case result s but in the fact that all cases were evaluated under the same set of technical and economic assump tions. This consistency of approach allows meaningful comparisons am ong the cases evaluated. Project contingencies were added to the E ngineering/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 con tingencies represent costs that are expected to occur. Each bare erected cost (BEC) account was evaluated agains t the level of estimate detail and field experience to determine project contin gency. Process contingency was added to cost account items that were deemed to be first-of-a -kind or posed significant risk due to lack of operating experience. The cost accounts that received a process contingency include:

• Slurry Prep and Feed – 5 percent on GE IGCC cases - systems are operating at approximately 800 psia as compared to 600 psia for the other IGCC cases.

• Gasifiers and Syngas Coolers – 15 percen t on all IGCC cases – next-generation commercial offering and integr ation with the power island.

• Two Stage Selexol – 20 percent on all IG CC capture cases – lack of operating experience at commercial scale in IGCC service.

• Mercury Removal – 5 percent on all IG CC cases – minimal commercial scale experience in IGCC applications.

• CO 2 

### Removal System – 20 percent on all PC/NGCC capture cases - post-combustion process unproven at commercial scal e for power plant applications.

• Combustion Turbine Generator – 5 percen t on all IGCC non-capture cases – syngas firing and ASU integration; 10 percent on all IGCC capture cases – high hydrogen firing.

• Instrumentation and Controls – 5 percen t on all IGCC accounts and 5 percent on the PC and NGCC capture cases – integration issues. The normalized total plant cost (T PC) for each technology is shown in Exhibit ES-5 . The following conclusions can be drawn:1,8132,3901,7332,4311,9772,6681,5492,8951,5752,8705541,17205001,0001,5002,0002,5003,0003,500

Total Plant Cost, $/kWGEE GEE w/ CO2CaptureCoP CoP w/ CO2CaptureShell Shell w/CO2CaptureSubcriticalPCSubcriticalPC w/ CO2CaptureSupercriticalPCSupercriticalPC w/ CO2CaptureNGCC NGCC w/CO2CaptureCost and Performance Baseline for Fossil Energy Plants10Exhibit ES-5 Total Plant CostCost and Performance Baseline for Fossil Energy Plants

11 

### • Among the non-capture cases, NGCC has th e lowest capital cost at $554/kW followed by PC with an average cost of $1,562/ kW and IGCC with an average cost of $1,841/kW. The average IGCC cost is 18 percen t greater than the average PC cost. The process contingency for the IGCC cases ranges from $44-51/kW while there is zero process contingency for the PC and NGCC non-capture cases. The differential between IGCC and PC is reduced to 15 percent when process contingency is eliminated.

• The three IGCC non-capture cases have a cap ital cost ranging from $1,733/kW (CoP) to $1,977/kW (Shell) with G EE intermediate at $1,813/kW.

• Among the capture cases, NGCC has the lowest capital cost, despite the fact that the capital cost of the NGCC capture case is mo re than double the cost of the non-capture case at $1,172/kW.

• Among the capture cases, the PC cases have th e highest capital cost at an average of $2,883/kW. The average capital cost for IGCC CO 2 

### capture cases is $2,496/kW, which is 13 percent less than the average of the PC cases. The process contingency for the IGCC capture cases ranges from $101-105/kW, for the PC cases from $99- 104/kW and $59/kW for the NGCC case. If pr ocess contingency is removed from the PC and IGCC cases, the cost of IGCC is 16 percent less than PC.

L EVELIZED 

### C OST OF 

### E LECTRICITY 

### (LCOE) The 20-year LCOE was calculated for each cas e using the economic parameters shown in Exhibit ES-6 . The cases were divided into two categor ies, representing high risk and low risk projects undertaken at investor owned utilities. High risk proj ects are those in which commercial scale operating experience is limited. The IGCC cas es (with and without CO 2 

### capture) and the PC and NGCC cases with CO 2 

### capture were considered to be high risk. The non-capture PC and NGCC cases were considered to be low risk.

Exhibit ES-6 Economic Parame ters Used to Calculate LCOE High Risk Low Risk Capital Charge Factor 0.175 0.164 Coal Levelization Factor 1.2022 1.2089 Natural Gas Levelization Factor 1.1651 1.1705 Levelization for all other O&M 1.1568 1.1618

The LCOE results are shown in Exhibit ES-7 with the capital cost, fixe d operating cost, variable operating cost and fuel cost shown sepa rately. In the capture cases the CO 2 

### transport, storage and monitoring (TS&M) costs are also shown as a separate bar segment. The following conclusions can be drawn:

• In non-capture cases, PC plants have the lowest LCOE (average 63.7 mills/kWh), followed by NGCC (68.4 mills/kWh) and IGCC (average 77.9 mills/kWh).78.0102.975.3105.780.5110.464.0118.863.3114.868.497.4020406080100120140160
LCOE, mills/kWhGEE GEE w/CO2CaptureCoP CoP w/ CO2CaptureShell Shell w/CO2CaptureSubcriticalPCSubcriticalPC w/ CO2CaptureSupercriticalPCSupercriticalPC w/ CO2CaptureNGCC NGCC w/CO2CaptureCO2 TS&M CostsFuel CostsVariable CostsFixed CostsCapital CostsCost and Performance Baseline for Fossil Energy Plants12Exhibit ES-7 LCOE By Cost ComponentCost and Performance Baseline for Fossil Energy Plants



### • In capture cases, NGCC plants have the lowest LCOE (97.4 mills/kWh), followed by IGCC (average 106.3 mills/kWh) and PC (average 116.8 mills/kWh).

• The LCOE for the three IG CC non-capture cases ranges from 75.3 mills/kWh (CoP) to 80.5 mills/kWh (Shell) with GEE in between at 78.0 mills/kWh. The study level of accuracy is insufficient to distinguish between the LCOE of the three IGCC technologies.

• Non-capture supercritical PC has an LCOE of 63.3 mills/kWh and subcritical PC is 64.0 mills/kWh, an insignificant difference given the level of accuracy of the study estimate.

• PC is the most expensive technology with CO 2 

### capture, 10 percent higher than IGCC and nearly 20 percent higher than NGCC.

• The capital cost component of LCOE is be tween 53 and 62 percent in all IGCC and PC cases. It represents only 18 percent of LCOE in the NGCC non-capture case and 28 percent in the CO 2 

### capture case.

• The fuel component of LCOE ranges from 21-25 percent for the IGCC cases and the PC CO 2 

### capture cases. For the PC non-capture cas es the fuel component varies from 30-32 percent. The fuel component is 78 percent of the total in the NGCC non-capture case and 63 percent in the CO 2 

### capture case.

• CO 2 

### transport, storage and monitoring is es timated to add 4 mills/kWh to the LCOE, which is less than 4 perecent of the total LCOE for all capture cases.
Exhibit ES-8 shows the LCOE sensitivity to fuel costs for the non-capture cases. The solid line is the LCOE of NGCC as a function of natural gas cost. The points on the line represent the natural gas cost that would be required to ma ke the LCOE of NGCC equal to PC or IGCC at a given coal cost. The coal prices shown ($1.35, $1.80 and $2.25/MMBtu) represent the baseline cost and a range of ±25 percen t around the baseline. As an example, at a coal cost of $1.80/MMBtu, the LCOE of PC equals NGCC at a natural gas price of $6.15/MMBtu.
Another observation from Exhibit ES-8 is that the LCOE of IGCC at a coal price of $1.35/MMBtu is greater than PC at a coal price of $2.25/MMBtu, due to the higher capital cost of IGCC and its relative insensitivity to fuel pri ce. For example, a decr ease in coal cost of 40 percent (from $2.25 to $1.35/MMBtu) results in an IGCC LCOE decrease of only 13 percent (82.5 to 73.2 mills/kWh). Fuel cost sensitivity is presented for the CO 2 

### capture cases in Exhibit ES-9 . Even at the lowest coal cost shown, the LCOE of NGCC is less than IGCC and PC at the ba seline natural gas price of $6.75/MMBtu. For the coal-based technologies at the baseline coal cost of $1.80/MMBtu to be equal to NGCC, the cost of natural ga s would have to be $7.73/MMBtu (IGCC) or $8.87/MMBtu (PC). Alternatively, for the LCOE of coal-based technologies to be equal to NGCC at the high end coal cost of $2.25/MMBtu, natural gas prices would have to be $8.35/MMBtu for IGCC and $9.65/MMBtu for PC.

13Cost and Performance Baseline for Fossil Energy Plants



### Exhibit ES-8 LCOE Sensitivity to Fuel Costs in Non-Capture Cases

40 50 60 70 80 90 100

3 4 5 6 7 8 91 0 1 1 Natural Gas Price, $/MMBtuLCOE, mills/kWh NGCC

PC w/ coal at $1.35/MMBtu

PC w/ coal at $1.80/MMBtu

PC w/ coal at $2.25/MMBtu

IGCC w/ coal at $1.35/MMBtu

IGCC w/ coal at $1.80/MMBtu

IGCC w/ coal at $2.25/MMBtu



### Exhibit ES-9 LCOE Sensitivity to Fuel Costs in CO 2 

### Capture Cases

40.0 50.0 60.0 70.0 80.0 90.0 100.0 110.0 120.0 130.0 140.0

3 4 5 6 7 8 91 0 1 1 Natural Gas Price, $/MMBtuLCOE, mills/kWh

NGCC
PC w/ coal at $1.35/MMBtu
PC w/ coal at $1.80/MMBtu
PC w/ coal at $2.25/MMBtu
IGCC w/ coal at $1.35/MMBtu
IGCC w/ coal at $1.80/MMBtu
IGCC w/ coal at $2.25/MMBtu

14Cost and Performance Baseline for Fossil Energy Plants



### The sensitivity of LCOE to capacity factor is shown for all technologies in Exhibit ES-10 . The subcritical and supercriti cal PC cases with no CO 2 

### capture are nearly identical so that the two curves appear as a single curve on the graph. The capacity factor is plotted from 40 to 90 percent. The baseline capacity factor is 80 percent for IGCC cases with no spare gasifier and is 85 percent for PC and NGCC cases. The curves plotted in Exhibit ES-10 for the IGCC cases assume that the capacity factor could be extended to 90 percent with no spar e gasifier. Similarly, the PC and NGCC curves assume that the cap acity factor could re ach 90 percent with no additional capital equipment.

Exhibit ES-10 LCOE Sensit ivity to Capacity Factor

0 50 100 150 200 250

0 10 20 30 40 50 60 70 80 90 100 Capacity Factor, %LCOE, mills/kWh GEE no capture CoP no capture Shell no capture GEE w/CO2 capture CoP w/CO2 capture Shell w/CO2 capture Sub PC no capture SC PC no capture Sub PC w/CO2 capture SC PC w/CO2 capture NGCC no capture NGCC w/CO2 capture Coal = $1.80/MMBtu Natural Gas = $6.75/MMBtu



### Technologies with high capital cost (PC and IGCC with CO 2 

### capture) show a greater increase in LCOE with decreased capacity fa ctor. Conversely, NGCC with no CO 2 

### capture is relatively flat because the LCOE is dominated by fuel charges whic h decrease as the capacity factor decreases. Conclusions that can be drawn from Exhibit ES-10 include:

• At a capacity factor below 72 percent NGCC has the lowest LCOE in the non-capture

cases.

• The LCOE of NGCC with CO 2 

### capture is the lowest of the capture technologies in the baseline study, and the advantage increases as capacity factor decreases. The relatively low capital cost component of NGCC accounts for the increased cost differential with decr eased capacity factor.

15Cost and Performance Baseline for Fossil Energy Plants

16 

### C OST OF 

### CO 2 

### R EMOVED 

### /A VOIDED



### The LCOE with CO 2 

### removal includes the costs of capture and compression as well as TS&M costs. The resulting removal and avoided costs are shown in Exhibit ES-11 for each of the six technologies modeled. The followi ng conclusions can be drawn: The cost of CO 2 

### capture was calculated in two ways, the cost of CO 2 

### removed and the cost of CO 2 

### avoided, as illustrated in Equa tions ES-1 and ES-2, respectively.

• CO 2 

### removal and avoided costs for the GEE IG CC plant are less than for the CoP and Shell IGCC plants. This is consistent w ith the efficiency changes observed when going from a non-capture to capture confi guration for the GEE IGCC plant. The GEE plant started with the lowest efficien cy of the IGCC plants but realized the smallest reduction in efficiency between the non-capture and cap ture configurations. • CO 2 

### removal and avoided costs for IGCC plants are less than NGCC plants because the baseline CO 2 

### emissions for NGCC plants ar e 46 percent less than for IGCC plants. Consequently, the normalized rem oval cost for NGCC plants is divided by a smaller amount of CO 2 

### . • CO 2 

### removal and avoided costs for IGCC plants are substantially less than for PC and NGCC because the IGCC CO 2 

### removal is accomplished prior to combustion and at elevated pressure using physical absorption. • The total cost of CO 2 

### avoided is $39/ton (average IGCC), $68/ton (average PC), and $83/ton (NGCC). • In non-capture cases NGCC at 40 percent capacity factor has the same LCOE as the average of the three IGCC cases at 72 percen t capacity factor further illustrating the relatively small impact of capacity factor on NGCC LCOE.

MWhtons removed CO MWh LCOE LCOE CostemovalR removalow removal with 

### /} { /$} {

2 / 

### −

= (ES-1)

MWhtons Emissions Emissions MWh LCOE LCOE Cost Avoided

removal with removalow removalow removal with 

### /} { /$} {

/ /



### − = − 

### (ES-2)2732324131424468456870830102030405060708090 $/ton, CO2GEE IGCC CoP IGCC Shell IGCC Subcritical PC Supercritical PC NGCCRemoval CostAvoided CostCost and Performance Baseline for Fossil Energy Plants17Exhibit ES-11 CO2Capture CostsCost and Performance Baseline for Fossil Energy Plants

18 

### ENVIRONMENTAL PERFORMANCE The environmental targets for each technology are summarized in Exhibit ES-12 . Emission rates of SO 2 

### , NOx and PM are shown graphically in Exhibit ES-13 , and emission rates of Hg are shown separately in Exhibit ES-14 because of the orders of ma gnitude difference in emission rate values. Targets were chosen on the basis of the environmental regulations that would most likely apply to plants built in 2010.
Exhibit ES-12 Study Environmental Targets

Technology
Pollutant IGCC PC NGCC

SO 2 

### 0.0128 lb/MMBtu 0.085 lb/MMBtu Negligible

NOx 15 ppmv (dry) @ 15% O 2 

### 0.070 lb/MMBtu 2.5 ppmv (dry) @ 15% O 2 

### PM (Filterable) 0.0071 lb/MMBtu 0.013 lb/MMBtu Negligible
Hg >90% capture 1.14 lb/TBtu N/A

Environmental targets were established fo r each of the technologies as follows:

• IGCC cases use the EPRI targets established in their CoalFleet for Tomorrow work as documented in the CoalFleet User Design Basis Specific ation for Coal-Based Integrated Gasification Combined Cycle (IGCC) Power Plants: Version 4

.

• PC and NGCC cases are based on be st available control technology. The primary conclusions th at can be drawn are:

• The NGCC baseline plant generates the lo west emissions, followed by IGCC and then PC.

• In NGCC cases, study assumptions result in zero emissions of SO 2 

### , PM and Hg. If the pipeline natural gas contained the maximum amount of sulfur allowed by EPA definition (0.6 gr/100 scf), SO 2 

### emissions would be 0.000839 kg/GJ (0.00195 lb/MMBtu).

• Based on vendor data it was assumed that dr y low NOx burners could achieve 25 ppmv (dry) at 15 percent O 2 

### and, coupled with a selective ca talytic reduction (SCR) unit that achieves 90 percent NOx reduction efficiency, would result in the environmental target of 2.5 ppmv (dry) at 15 percent O 2 

### for both NGCC cases.

• Based on vendor data it was assumed that Sele xol, Sulfinol-M and refrigerated MDEA could all meet the sulfur environmental ta rget, hence emissions of approximately 0.0128 lb/MMBtu in each of the IGCC non -capture cases. In the CO 2 

### capture cases, to achieve 95 percent CO 2 

### capture from the syngas, the sulfur removal is greater than in the noncapture cases resulting in emissions of approximately 0.0041 kg/GJ (0.0095 lb/MMBtu).Cost and Performance Baseline for Fossil Energy PlantsExhibit ES-13 SO2, NOx and Particulate Emission Rates0.000.020.040.060.080.100.12

Emissions, lb/MMBtuGEE GEE w/CO2CaptureCoP CoP w/ CO2CaptureShell Shell w/CO2CaptureSubcriticalPCSubcriticalPC w/ CO2CaptureSupercriticalPCSupercriticalPC w/ CO2CaptureNGCC NGCC w/CO2CaptureSO2NOxParticulate Matter19Cost and Performance Baseline for Fossil Energy Plants200.00.20.40.60.81.01.21.4 Hg Emissions, lb/TBtuGEE GEE w/CO2CaptureCoP CoP w/ CO2CaptureShell Shell w/CO2CaptureSubcriticalPCSubcriticalPC w/ CO2CaptureSupercriticalPCSupercriticalPC w/ CO2CaptureNGCC NGCC w/CO2CaptureExhibit ES-14 Mercury Emission RatesCost and Performance Baseline for Fossil Energy Plants



### • It was a study assumption that each IGCC tec hnology could meet the filterable particulate emission limit with the combination of technol ogies employed. In the case of Shell and CoP, this consists of cyclones, candle filters and the syngas scrubber. In the case of GEE particulate control consists of a water quench and syngas scrubber.

• Based on vendor data it was assumed that a combination of low NOx burners and nitrogen dilution could limit IGCC NOx emi ssions to the environmental target of 15 ppmv (dry) at 15 percent O 2 

### . The small variations in NOx emissions are due to small variations in combusti on turbine gas volumes.

• Based on vendor data it was assumed that 95 percent Hg removal could be achieved using carbon beds thus meeting the environmen tal target. The Hg emissions are reported in Exhibit ES-1 4 as lb/10 per trillion Btu to make th e values the same order of magnitude as the other reported values.

• It was a study assumption that the PC flue gas desulfurization (FGD) unit would remove 98 percent of the inlet SO 2 

### , resulting in the environmental target of 0.037 kg/GJ (0.085 lb/MMBtu). In the CO 2 

### capture cases, the Econamine system employs a polishing scrubber to reduce emissions to 10 ppmv entering the CO 2 

### absorber. Nearly all of the remaining SO 2 

### is absorbed by the Econamine solvent resulting in neglig ible emissions of SO 2 

### in those cases.

• In PC cases, it was a study assumption that a fabric filter would remove 99.9 percent of the entering particulate and that there is an 80/20 split between fly ash and bottom ash. The result is the environmental target of 0.006 kg/GJ (0.013 lb/MMBtu) of filterable particulate.

• In PC cases, it was a study assumption that NOx emissions exiting the boiler equipped with low NOx burners and overfire air woul d be 0.22 kg/GJ (0.50 lb/MMBtu) and that an SCR unit would further reduce the NOx by 86 percent, resulting in the environmental target of 0.030 kg/GJ (0.070 lb/MMBtu).

• In PC cases, it was a study assumption that the environmental target of 90 percent of the incoming Hg would be removed by the combina tion of SCR, fabric filter and wet FGD thus eliminating the need for activated carbon injection. The resulting Hg emissions for each of the PC cases are 4.92 x 10 -7 

### kg/GJ (1.14 lb/TBtu).
Carbon dioxide emissions are not currently regulated. Howeve r, since there is increasing momentum for establishing carbon limits, it was an objective of this study to examine the relative amounts of carbon capture achi evable among the six technologies. CO 2 

### emissions are presented in Exhibit ES-15 for each case, normalized by gross output. In the body of the report CO 2 

### emissions are presented on both a net and gross MWh basis. New Source Performance Standards (NSPS) contain emission limits for SO 2 

### and NOx on a lb/(gross) MWh basis. However, since CO 2 

### emissions are not currently regulate d, the potential future emission limit basis is not known and hence th e two reported values of CO 2 

### . The following conclusions can be drawn:

• In cases with no carbon capture, NGCC emits 55 percent less CO 2 

### than PC and 46 percent less CO 2 

### than IGCC per unit of gross output. The lower NGCC CO 2 

### emissions reflect the lower carbon intensit y of natural gas relative to coal. Based on the fuel

21Cost and Performance Baseline for Fossil Energy Plants

22 

### compositions used in this study, natural ga s contains 32 pounds of carbon per million Btu of heat input and coal contains 55 pounds per million Btu.

• The CO 2 

### reduction goal in this study was a nominal 90 percent in all cases. The result is that the controlled CO 2 

### emissions follow the same tre nd as the uncontro lled, i.e., the NGCC case emits less CO 2 

### than the IGCC cases which emit less than the PC cases.

• In the IGCC cases the nominal 90 percent CO 2 

### reduction was accomplished by adding sour gas shift (SGS) reactors to convert CO to CO 2 

### and using a two-stage Selexol process with a second stage CO 2 

### removal efficiency of up to 95 percent, a number that was supported by vendor quotes. In the GEE CO 2 

### capture case, two stages of SGS and a Selexol CO 2 

### removal efficiency of 92 percent were required, which resulted in 90.2 percent reduction of CO 2 

### in the syngas. The CoP capture case required three stages of SGS and 95 percent CO 2 

### capture in the Selexol process, which resulted in 88.4 percent reduction of CO 2 

### in the syngas. In the CoP case, th e capture target of 90 percent could not be achieved because of the high syngas methane content (3.5 vol% compared to 0.10 vol% in the GEE gasifier and 0.04 vol% in the Shell gasifier). The Shell capture case required two stages of SGS and 95 percent captu re in the Selexol process, which resulted in 90.8 percent reduction of CO 2 

### in the syngas.

• The CO 2 

### emissions in the three non-capture IGCC cas es are nearly identical. The slight difference reflects the relative efficiency be tween the three technol ogies. The emissions in the CO 2 

### capture cases are nearly identical for the Shell and GEE cases, but about 19 percent higher in the CoP case because of the high syngas CH 4 

### content discussed above.

• The PC and NGCC cases both assume that all of the carbon in the fuel is converted to CO 2 

### in the flue gas and that 90 percent is subsequently removed in the Econamine FG Plus process, which was also supported by a vendor quote.1,4591541,4521891,4091491,7802251,6812097838602004006008001,0001,2001,4001,6001,8002,000

CO 2 Emissions, lb/MWhGEE GEE w/CO2CaptureCoP CoP w/ CO2CaptureShell Shell w/CO2CaptureSubcriticalPCSubcriticalPC w/ CO2CaptureSupercriticalPCSupercriticalPC w/ CO2CaptureNGCC NGCC w/CO2CaptureCost and Performance Baseline for Fossil Energy Plants23Exhibit ES-15 CO2Emissions Normalized By Gross OutputCost and Performance Baseline for Fossil Energy Plants



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24Cost and Performance Baseline for Fossil Energy Plants



## 1 INTRODUCTION The objective of this report is to present an ac curate, independent assessment of the cost and performance of fossil energy power systems, speci fically integrated gasification combined cycle (IGCC), pulverized coal (PC), and natural gas combined cycle (NG CC) plants, in a consistent technical and economic manner that accurately re flects current market conditions for plants starting operation in 2010. This is Volume 1 of a three volume report. The three volume series consists of the following:

• Volume 1: Electricity production only using bi tuminous coal for coal-b ased technologies

• Volume 2: Synthetic natural gas production a nd repowering using a va riety of coal types

• Volume 3: Electricity production only from low rank coal (PC and IGCC) The cost and performance of the various fossil fuel-based technologies will largely determine which technologies will be utilized to meet the demands of the power market. Selection of new generation technologies will depe nd on many factors, including:

• Capital and operating costs

• Overall energy efficiency

• Fuel prices

• Cost of electricity (COE)

• Availability, reliability and environmental performance

• Current and potential regulati on of air, water, and solid waste discharges from fossilfueled power plants

• Market penetration of clean co al technologies that have ma tured and improved as a result of recent commercial-scale demonstrations under the Department of Energy’s (DOE) Clean Coal Programs Twelve different power plant desi gn configurations were analyzed. The configurations are listed in Exhibit 1-1 . The list includes six IGCC cases utiliz ing the General Elec tric Energy (GEE), ConocoPhillips (CoP), and Shell ga sifiers each with and without CO 2 

### capture, and six cases representing conventional technologies: PC-subcritical, PC-supercritical, and NGCC plants both with and without CO 2 

### capture. While input was sought fr om various technology vendors, the final assessment of performance and cost was de termined independently, and may not represent the views of the technology vendors. The extent of collaboration with technology vendors varied from case to case, with minimal or no collaboration obtained from some vendors. Cases 7 and 8 were originally in cluded in this study and involve production of synthetic natural gas (SNG) and the repowering of an existing NGCC facility using SNG. The two SNG cases were subsequently moved to Volume 2 of this report resulting in the discontinuity of case numbers (1-6 and 9-14). The two SNG cases are now cases 2 and 2a in Volume 2.

25Cost and Performance Baseline for Fossil Energy Plants

26 

### GENERATING UNIT CONFIGURATIONS A summary of plant configur ations considered in th is study is presented in Exhibit 1-1

. Components for each plant configuration are descri bed in more detail in the corresponding report sections for each case. The IGCC cases have different gross and net power outputs because of the gas turbine size constraint. The advanced F-cla ss turbine used to model the IGCC cases comes in a standard size of 232 MW when operated on syngas. Each case uses two combustion turbines for a combined gross output of 464 MW. In the combined cycle a heat recovery steam ge nerator extracts heat from the combustion turbine exhaust to power a steam turbine. However, the carbon capture cases consume more extraction steam than the non- capture cases, thus re ducing the steam turbine output. In addition, the capture cas es have a higher auxiliary lo ad requirement than non-capture cases, which serves to further reduce net plan t output. While the two combustion turbines provide 464 MW gross output in all six cases, the overall comb ined cycle gross output ranges from 694 to 770 MW, which results in a range of net output from 517 to 640 MW. The coal feed rate required to achieve the gross power output is also different betw een the six cases, ranging from 204,117 to 226,796 kg/h (450,000 to 500,000 lb/h). Similar to the IGCC cases, the NGCC cases do not have a common net power output. The NGCC system is again constrained by the ava ilable combustion turbine size, which is 185 MW for both cases (based on the same advanced F cl ass turbine used in the IGCC cases). Since the carbon capture case requires both a higher auxilia ry power load and a significant amount of extraction steam, which significan tly reduces the steam turbine output, the net output in the NGCC case is also reduced. All four PC cases have a net output of 550 MW. The boiler and steam tu rbine industry’s ability to match unit size to a custom specification has been commercially demonstrated enabling a common net output comparison of the PC cases in this study. The coal feed rate was increased in the carbon capture cases to increase the gr oss steam turbine output and account for the higher auxiliary load, resulting in a constant net output. The balance of this report is organized as follows:

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

• Chapter 3 describes the IGCC technologies m odeled and presents the results for the six IGCC cases.

• Chapter 4 describes the PC technologies modeled and presents the results for the four PC cases.

• Chapter 5 desribes the NGCC technologies m odeled and presents the results for the two NGCC cases.

• Chapter 6 contains the reference list.Cost and Performance Baseline for Fossil Energy Plants27Exhibit 1-1 Case DescriptionsCaseUnitCycleSteam Cycle,psig/°F/°FCombustionTurbineGasifier/BoilerTechnologyOxidantH2SSeparation/RemovalSulfurRemoval/RecoveryPM ControlNOxControlCO2Separa-tionCO2CaptureCO2Sequestra-tion1IGCC1800/1050/10502 xAdvancedF ClassGEE RadiantOnly95 mol%O2SelexolClaus PlantQuench, scrubberand AGR adsorberN2dilution2IGCC1800/1000/10002 xAdvancedF ClassGEE RadiantOnly95 mol%O2SelexolClaus PlantQuench, scrubberand AGR adsorberN2dilutionSelexol2ndstage90% (1)Off-Site3IGCC1800/1050/10502 xAdvancedF ClassCoP E-GasTM95 mol%O2RefrigeratedMDEAClaus PlantCyclone, barrierfilter and scrubberN2dilution4IGCC1800/1000/10002 xAdvancedF ClassCoP E-GasTM95 mol%O2SelexolClaus PlantCyclone, barrierfilter and scrubberN2dilutionSelexol2ndstage88% (1)Off-Site5IGCC1800/1050/10502 xAdvancedF ClassShell95 mol%O2Sulfinol-MClaus PlantCyclone, barrierfilter and scrubberN2dilution6IGCC1800/1000/10002 xAdvancedF ClassShell95 mol%O2SelexolClaus PlantCyclone, barrierfilter and scrubberN2dilutionSelexol2ndstage90% (1)Off-Site----------------------------------------------------9PC2400/1050/1050Subcritical PCAirWet FGD/GypsumBaghouseLNBw/OFAand SCR10PC2400/1050/1050Subcritical PCAirWet FGD/GypsumBaghouseLNBw/OFAand SCRAmineAbsorber90%Off-Site11PC3500/1100/1100Supercritical PCAirWet FGD/GypsumBaghouseLNBw/OFAand SCR12PC3500/1100/1100Supercritical PCAirWet FGD/GypsumBaghouseLNBw/OFAand SCRAmineAbsorber90%Off-Site13NGCC2400/1050/9502 xAdvancedF ClassHRSGAirLNB andSCR14NGCC2400/1050/9502 xAdvancedF ClassHRSGAirLNB andSCRAmineAbsorber90%Off-SiteNote (1) Defined as the percentage ofcarbon in the syngas that is captured;differences are explained in Chapter 3.Cost and Performance Baseline for Fossil Energy Plants



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28Cost and Performance Baseline for Fossil Energy Plants



## 2 GENERAL EVALUATION BASIS For each of the plant configurations in this st udy an AspenPlus 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 co st estimates. Performance and process limits were based upon published reports, informati on obtained from vendors and users of the technology, performance data from design/build utility projects, and/or best engineering judgement. Capital and operating costs were estimated by WorleyParsons based on simulation results and through a combination of vendor quotes , scaled estimates from previous design/buil projects, or a combination of the two. Ultimately a 20-year levelized cost of electricity (LCOE) was calculated for each of the cases and is report ed as the revenue requirement figure-of-merit. The balance of this chapter documents the desi gn basis common to all technologies, as well as environmental targets and cost assumptions used in the study. Technology specific design criteria are covered in subsequent chapters.

2.1 SITE CHARACTERISTICS All plants in this study are assumed to be located at a generic plant site in Midwestern USA, with ambient conditions and site characteristics as presented in Exhibit 2-1 and Exhibit 2-2 . The ambient conditions are the same as ISO conditions.

Exhibit 2-1 Site Ambient Conditions
Elevation, m (ft) 0 Barometric Pressure, MPa (psia) 0.10 (14.696) Design Ambient Temperature, Dry Bulb, °C ( ° F) 15 (59) Design Ambient Temperature, Wet Bulb, °C ( ° F) 11 (51.5) Design Ambient Relative Humidity, % 60

Exhibit 2-2 Site Characteristics

Location Greenfield, Midwestern USA Topography Level Size, acres 300 (PC/IGCC) 100 (NGCC) Transportation Rail Ash/Slag Disposal Off Site
Water Municipal (50%) / Groundwater (50%)
Access Land locked, having access by train and highway

CO 2 

### Storage Compressed to 15.3 MPa ( 2,215 psia), transported 80 kilometers (50 miles) an d sequestered in a saline formation at a depth of 1,239 meters (4,055 feet)

29Cost and Performance Baseline for Fossil Energy Plants



### The land area for PC and IGCC cases assumes 30 acr es are required for the plant proper and the balance provides a buffer of approximately 0.25 m iles to the fence line. The extra land could also provide for a rail loop if required. In the NGCC cases it was assumed the plant proper occupies about 10 acres l eaving a buffer of 0.15 miles to the plant fence line.

In all cases it was assumed that the steam turbine is enclosed in a turbine building and in the PC cases the boiler is also enclosed. The gasifier in the IGCC cases and the combustion turbines in the IGCC and NGCC cases are not enclosed. The following design parameters are considered s ite-specific, and are no t quantified for this study. Allowances for normal conditions and cons truction 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 COAL CHARACTERISTICS The design coal is Illinois No. 6 w ith characteristics presented in Exhibit 2-3 . The coal properties are from NETL’s Coal Quality Guidelines. [ 1 ] The first year cost of coal used in this st udy is $1.71/MMkJ ($1.80/MMBtu) (2010 cost of coal in 2007 dollars). The cost was determined usi ng the following information from the Energy Information Administration’s (EIA ) 2007 Annual Energy Outlook (AEO):

• The 2010 minemouth cost of coal in 2005 dollars, $35.23/tonn e ($31.96/ton), was obtained from Supplemental Table 113 of the EIA’s 2007 AEO for eastern interior high-sulfur bituminous coal.

• The delivery costs were assumed to be 25 pe rcent of the minemouth cost for eastern interior coal delivered to Illinois and surrounding states. [ 2 ]

• The 2010 delivered cost ($44.04/tonne [$39.95/ ton]) was escalated to 2007 dollars using the gross domestic product (GDP) chain-type price index from AEO 2007, resulting in a delivered 2010 price in 2007 dollars of $45.32/tonne ($41.11/ton) or $1.71/MMkJ ($1.80/MMBtu). [ 3 ] (Note: The conversion of $41.11/ton to dollars per million Btu results in $1.8049/MMBtu which was used in calculations, but only two decimal places are shown in the report.)

30Cost and Performance Baseline for Fossil Energy Plants



### Exhibit 2-3 Design Coal

Rank Bituminous
Seam Illinois No. 6 (Herrin)
Source Old Ben Mine Proximate Analysis (weight %) (Note A)
As Received Dry
Moisture 11.12 0.00
Ash 9.70 10.91
Volatile Matter 34.99 39.37
Fixed Carbon 44.19 49.72
Total 100.00 100.00
Sulfur 2.51 2.82 HHV, kJ/kg 27,113 30,506 HHV, Btu/lb 11,666 13,126 LHV, kJ/kg 26,151 29,544 LHV, Btu/lb 11,252 12,712 Ultimate Analysis (weight %)
As Received Dry
Moisture 11.12 0.00
Carbon 63.75 71.72 Hydrogen 4.50 5.06 Nitrogen 1.25 1.41
Chlorine 0.29 0.33
Sulfur 2.51 2.82
Ash 9.70 10.91 Oxygen (Note B) 6.88 7.75
Total 100.00 100.00 Notes: A. The proximate analysis assumes sulfur as volatile matter B. By difference

31Cost and Performance Baseline for Fossil Energy Plants



### 2.3 NATURAL GAS CHARACTERISTICS Natural gas is utilized as the main fuel in Cases 13 and 14 (NGCC with and without CO 2 

### capture), and its composition is presented in Exhibit 2-4 . [ 4 ]
Exhibit 2-4 Natural Gas Composition
Component Volume Percentage
Methane CH 4 

### 93.9
Ethane C 2 

### H 6 

### 3.2 Propane C 3 

### H 8 

### 0.7

n -Butane C 4 

### H 10 

### 0.4
Carbon Dioxide CO 2 

### 1.0 Nitrogen N 2 

### 0.8
Total 100.0
LHV HHV kJ/kg 47,764 52,970
MJ/scm 35 39
Btu/lb 20,552 22,792
Btu/scf 939 1,040 Note: Fuel composition is normalized and heating values are calculated The first year cost of natural gas used in this study is $6.40/MMkJ ( $6.75/MMBtu) (2010 cost of natural gas in 2007 dollars). The cost was determ ined using the following information from the EIA’s 2007 AEO:

• The 2010 national average deliver ed cost of natural gas to electric utilities in 2005 dollars, $6.07/MMkJ ($6.40/MMBtu), was obtained from the AEO 2007 reference case Table 13.

• The 2010 cost was escalated to 2007 dollars using the GDP chain-type price index from AEO 2007, resulting in a delive red 2010 price in 2007 dollars of $6.40/MMkJ ($6.75/MMBtu). [ 3 ]

2.4 ENVIRONMENTAL TARGETS The environmental targets for the study were cons idered on a technology- and fuel-specific basis. In setting the environmental ta rgets a number of factors were considered, including current emission regulations, regulation trends, results fr om recent permitting activities and the status of current best available co ntrol technology (BACT). The current federal regulation governing new fossil- fuel fired electric ut ility steam generating units is the New Source Performance Standards (NSPS) as amended in February 2006 and shown in Exhibit 2-5 , which represents the minimum level of control that would be required for a new

32Cost and Performance Baseline for Fossil Energy Plants



### fossil energy plant. [ 5 ] Stationary combustion turbine emission limits are further defined in 40 CFR Part 60, Subpart KKKK.

Exhibit 2-5 Standards of Performance for Electric Utility Steam Generating Units Built, Reconstructed, or Mo dified After February 28, 2005

New Units Reconstructed Units Modified Units

Emission

Limit % Reduction Emission Limit (lb/MMBtu) % Reduction Emission Limit (lb/MMBtu) % Reduction

PM 0.015 lb/MMBtu 99.9 0.015 99.9 0.015 99.8

SO 2 

### 1.4 lb/MWh 95 0.15 95 0.15 90

NOx 1.0 lb/MWh N/A 0.11 N/A 0.15 N/A

The new NSPS standards apply to units with the capacity to generate gr eater than 73 MW of power by burning fossil fuels, as well as cogenera tion units that sell more than 25 MW of power and more than one-third of their potential out put capacity to any util ity power distribution system. The rule also applies to combined cycl e, including IGCC plants, and combined heat and power combustion turbines that bur n 75 percent or more synthetic-coal gas. In cases where both an emission limit and a percent reduction are presen ted, the unit has the option of meeting one or the other. All limits with the unit lb/MWh are based on gross power output. Other regulations that could affect emissions limits from a new plant include the New Source Review (NSR) permitting process and Prevention of Significant Deterioration (PSD). The NSR process requires installation of emission control technology meeti ng either BACT determinations for new sources being located in areas meeting ambient air quality standards (attainment areas), or Lowest Achievable Emission Rate (LAER) te chnology for sources being located in areas not meeting ambient air quality standards (non-attainment areas). Environmental area designation varies by county and can be established only for a specific site location. Based on the Environmental Protection Agency (EPA) Green Book Non-attainment Area Map relatively few areas in the Midwestern U.S. are classified as “non-attainment” so the plant site for this study was assumed to be in an attainment area. [ 6 ] In addition to federal regulations, state and loca l jurisdictions can impose even more stringent regulations on a new facility. However, si nce each new plant has unique environmental requirements, it was necessary to apply some j udgment in setting the environmental targets for this study. The Clean Air Mercury Rule (CAMR) establis hed NSPS limits for Hg emissions from new pulverized coal-fired boilers based on coal type as well as for IGCC units independent of coal type. The NSPS limits, based on gross output, are shown in Exhibit 2-6 . [ 7 ] The applicable limit in this study is 20 x 10 -6 

### lb/MWh for both bituminous coal-fired PC boilers and for IGCC units.

33Cost and Performance Baseline for Fossil Energy Plants



### Exhibit 2-6 NSPS Mercury Emission Limits

Coal Type / Technology Hg Emission Limit

Bituminous 20 x 10 -6 

### lb/MWh
Subbituminous (wet units) 66 x 10 -6 

### lb/MWh
Subbituminous (dry units) 97 x 10 -6 

### lb/MWh
Lignite 175 x 10 -6 

### lb/MWh

Coal refuse 16 x 10 -6 

### lb/MWh

IGCC 20 x 10 -6 

### lb/MWh

The mercury content of 34 samples of Illinois No. 6 coal has an arithmetic mean value of 0.09 ppm (dry basis) with standard deviation of 0.06 based on coal samples shipped by Illinois mines. [ 8 ] Hence, as illustrated in Exhibit 2-7 , there is a 50 percent proba bility that the mercury content in the Illinois No. 6 co al would not exceed 0.09 ppm (dry basis). The coal mercury content for this study was assumed to be 0.15 ppm (dry) for all IGCC and PC cases, which corresponds to the mean plus one standard devi ation and encompasses ab out 84 percent of the samples. It was further assumed that all of the coal Hg enters the gas phase and none leaves with the bottom ash or slag. The current NSPS emission limits are provide d below for each technology along with the environmental targets for this study and the contro l technologies employed to meet the targets. In some cases, application of the control techno logy results in emissions that are less than the target, but in no case are the emi ssions greater than the target.

34Cost and Performance Baseline for Fossil Energy Plants



### Exhibit 2-7 Probability Distribution of Mercury Concentration in the Illinois No. 6 Coal

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

0.00 ppm Hg 0.05 ppm Hg 0.10 ppm Hg 0.15 ppm Hg 0.20 ppm Hg 0.25 ppm Hg 0.30 ppm Hg Mercury Concentraion in Coal, ppm dbProbability Illinois #6 Sample Will Be At or Below ValueP:\X_GEMSET\0_GEMSET Fuels Price Database\Rev.0 Fuels\[IllinoisNo6 Mercury.xls] Rev. 00 11/21/05 10:

Arithmetic Mean = 0.09 ppm db Standard Deviation = 0.06 ppm db



### 2.4.1 IGCC The IGCC environmental targets were chosen to match the Electric Power Research Institute’s (EPRI) design basis for their CoalFleet fo r Tomorrow Initiative and are shown in Exhibit 2-8 . [ 9 ] EPRI notes that these are design targets and are not to be used for permitting values.
Exhibit 2-8 Environmental Targets for IGCC Cases

Pollutant Environmental Target NSPS Limit 1 

### Control Technology

NOx 15 ppmv (dry) @ 15% O 2 

### 1.0 lb/MWh (0.116 lb/MMBtu) Low NOx burners and syngas nitrogen dilution

SO 2 

### 0.0128 lb/MMBtu 1.4 lb/MWh (0.162 lb/MMBtu) Selexol, MDEA or Sulfinol (depending on

gasifier technology)

Particulate Matter (Filterable) 0.0071 lb/MMBtu 0.015 lb/MMBtu Quench, water scrubber, and/or cyclones and candle filters (depending

on gasifier technology)

Mercury > 90% capture 20 x 10 -6 

### lb/MWh (2.3 lb/TBtu) Carbon bed

1 

### The value in parentheses is calculated based on an average heat rate of 8,640 Btu/kWh from the

three non-CO 2 

### capture gasifier cases.

35Cost and Performance Baseline for Fossil Energy Plants



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

### , and that value was used for all IGCC cases. [ 10
, 11 ] To achieve an environmental target of 0.0128 lb/MMBtu of SO 2 

### requires approximately 28 ppmv sulfur in the sweet syngas. The acid gas removal (AGR) process must have a sulfur capture efficiency of about 99.7 percent to reach the en vironmental target. Ve ndor data on each of the three AGR processes used in the non-capture cases indicate that this level of sulfur removal is possible. In the CO 2 

### capture cases, the two-stage Selexol process was designed for 95 percent CO 2 

### removal which results in a sulf ur capture of greater than 99.7 pe rcent, hence the lower sulfur emissions in the CO 2 

### capture cases. Most of the coal ash is removed from the gasifier as slag. The ash that remains entrained in the syngas is captured in the downstream equipmen t, including the syngas scrubber and a cyclone and either ceramic or metallic candle filters (C oP and Shell). The environmental target of 0.0071 lb/MMBtu filterable particulates can be achieve d with each combination of particulate control devices so that in each IGCC case it was assu med the environmental target was met exactly. The environmental target for mercury capture is gr eater than 90 percent. Based on experience at the Eastman Chemical plant, where syngas from a GEE gasifier is treate d, the actual mercury removal efficiency used is 95 percent. Sulfu r-impregnated activated carbon is used by Eastman as the adsorbent in the packed beds operated at 30°C (86°F) and 6.2 MPa (900 psig). Mercury removal between 90 and 95 percent has been repo rted 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. [ 12 ] Mercury removals of greater than 99 per cent 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 emi ssions which meets the environmental target and NSPS limits in all cases.

2.4.2 PC BACT was applied to each of the PC cases and the resulting emissions compared to NSPS limits and recent permit averages. Si nce the BACT results met or exceeded the NSPS requirements and the average of recent permits, they were used as the environmental targets as shown in Exhibit 2-9 . The average of recent permits is comprised of 8 units at 5 locations. The 5 plants include Elm Road Generating Station, Longview Power, Prairie State, Thoroughbred and Cross. It was assumed that LNBs and staged overf ire air (OFA) would limit NOx emissions to 0.5 lb/MMBtu and that selective ca talytic reduction (SCR) technology w ould be 86 percent efficient, resulting in emissions of 0.07 lb/MMBtu for all cases. The wet limestone scrubber was assumed to be 98 percent efficient which results in SO 2 

### emissions of 0.085 lb/MMBtu. Current technolo gy allows flue gas desulfurization (FGD) removal efficiencies in excess of 99 percent, but based on NSPS requirements and recent permit averages, such high removal efficiency is not necessary. The fabric filter used for particul ate control was assumed to be 99.8 percent efficient. The result is particulate emissions of 0.013 lb/MMBtu in all cases, which also exceeds NSPS and recent permit average requirements.

36Cost and Performance Baseline for Fossil Energy Plants



### Exhibit 2-9 Environmental Targets for PC Cases

Pollutant Environmental Target NSPS Limit Average of Recent Permits Control Technology

NOx 0.07 lb/MMBtu 1.0 lb/MWh (0.111 lb/MMBtu) 0.08 lb/MMBtu Low NOx burners, overfire air and SCR

SO 2 

### 0.085 lb/MMBtu 1.4 lb/MWh (0.156 lb/MMBtu) 0.16 lb/MMBtu Wet limestone scrubber

Particulate Matter (Filterable) 0.013 lb/MMBtu 0.015 lb/MMBtu 0.017 lb/MMBtu Fabric filter

Mercury 1.14 lb/TBtu 20 x 10 -6 

### lb/MWh (2.2 lb/TBtu) 2.49 lb/TBtu Co-benefit capture

Mercury control for PC cases was assumed to o ccur through 90 percent co-b enefit capture in the fabric filter and the wet FGD scrubber. EPA us ed a statistical method to calculate the Hg cobenefit capture from units using a “best de monstrated technology” approach, which for bituminous coals was considered to be a combinati on of a fabric filter an d an FGD system. The statistical analysis resu lted in a co-benef it capture estimate of 86.7 percent with an efficiency range of 83.8 to 98.8 percent. [ 13 ] EPA’s documentation for thei r Integrated Planning Model (IPM) provides mercury emission modification factors (EMF) ba sed on 190 combinations of boiler types and control technologies. The EMF is simply one minus the removal efficiency. For PC boilers (as opposed to cyclones, stokers, flui dized beds and ‘others’) with a fabric filter, SCR and wet FGD, the EMF is 0.1 which corresp onds to a removal efficiency of 90 percent. [ 14 ] The average reduction in total Hg emissions developed from EPA’s Information Collection Request (ICR) data on U.S. coal-fired boilers us ing bituminous coal, fabric filters and wet FGD is 98 percent. [ 15 ] The referenced sources bound the co-benefit Hg capture for bituminous coal units employing SCR, a fabric filter and a wet F GD system between 83.8 and 98 percent. Ninety percent was chosen as near the mi d-point of this range and it also matches the value used by EPA in their IPM. Since co-benefit capture alone exceeds the requ irements of NSPS and recent permit averages, no activated carbon injection is included in this study.

2.4.3 NGCC BACT was applied to the NGCC cases and the resulting emissions compared to NSPS limits. The NGCC environmental targets were chosen ba sed on reasonably obtainable limits given the control technologies employe d and are presented in Exhibit 2-10

.

37Cost and Performance Baseline for Fossil Energy Plants



### Exhibit 2-10 Environmental Targets for NGCC Cases

Pollutant Environmental Target 40 CFR Part 60, Subpart KKKK Limits Control Technology

NOx 2.5 ppmv @ 15% O 2 

### 15 ppmv @ 15% O 2 

### Low NOx burners and SCR

SO 2 

### Negligible 0.9 lb/MWh (0.135 lb/MMBtu) 1 

### Low sulfur content fuel

Particulate Matter (Filterable) N/A N/A N/A

Mercury N/A N/A N/A

1 

### Assumes a heat rate of 6,690 Btu/kWh.

Published vendor literature indicates that 25 ppmv NOx at 15 percent O 2 

### is achievable using natural gas and dry low NOx (DLN) technology. [ 16
, 17 ] The application of SCR with 90 percent efficiency further reduces NOx emissions to 2.5 ppmv, which was selected as the environmental target. For the purpose of this study, natural gas was assu med to contain a negligible amount of sulfur compounds, and therefore generate negligible sulfur emission s. The EPA defines pipeline natural gas as containing >70 percent methane by volume or having a gross calorific value of between 35.4 and 40.9 MJ/Nm 3 

### (950 and 1,100 Btu/scf) and having a total sulfur content of less than 13.7 mg/Nm 3 

### (0.6 gr/100 scf). [ 18 ] Assuming a sulfur content equal to the EPA limit for pipeline natural gas, resulting SO 2 

### emissions for the two NGCC cases in this study would be 21 tonnes/yr (23.2 tons/yr) at 85 percent capacity factor or 0.00084 kg/GJ (0.00195 lb/MMBtu). Thus for the purpose of this study, SO 2 

### emissions were considered negligible. The pipeline natural gas was assumed to contai n no particulate matter and no mercury resulting in no emissions of either.

2.4.4 C ARBON 

### D IOXIDE 

### Carbon dioxide (CO 2 

### ) is not currently regulated. Howeve r, the possibility exists that carbon limits will be imposed in the future and this study examines cases that include a reduction in CO 2 

### emissions. Because the form of emission li mits, should they be imposed, is not known, CO 2 

### emissions are reported on both a lb/(gross) MWh and lb/(net) MWh basis in each capture case emissions table.
For the IGCC cases that have CO 2 

### capture, the basis is a nominal 90 percent removal based on carbon input from the coal and excluding carbon th at exits the gasifier with the slag. The minimum number of water gas shift reacto rs was used with a maximum Selexol CO 2 

### removal efficiency of 95 percent (based on a vendor quote) to achieve an overall CO 2 

### removal efficiency of 90 percent. Once the number of shift reactors was determined, the Selexol removal efficiency was decreased from 95 percent if possible while s till meeting the 90 percent overall target. In the

38Cost and Performance Baseline for Fossil Energy Plants



### case of the E-GasTM gasifier, CO 2 

### capture is limited to 88.4 percent because of the relatively high methane content in the syngas that is not converted to CO 2 

### in the shift reactors.
For PC and NGCC cases that have CO 2 

### capture, it is assumed that all of the fuel carbon is converted to CO 2 

### in the flue gas. CO 2 

### is also generated from limestone in the FGD system, and 90 percent of the CO 2 

### exiting the FGD absorber is subse quently captured using the Econamine FG Plus technology.
The cost of CO 2 

### capture was calculated in two ways, the cost of CO 2 

### removed and the cost of CO 2 

### avoided, as illustrated in Equations 1 and 2, re spectively. The cost of electricity in the CO 2 

### capture cases includes transport, storage a nd monitoring (TS&M) as well as capture and compression.

(1) MWhtons removed CO MWh LCOE LCOE CostemovalR removalow removal with 

### /} { /$} {

2 / 

### −

=

(2) MWhtons Emissions Emissions MWh LCOE LCOE Cost Avoided

removal with removalow removalow removal with 

### /} { /$} {

/ /



### − −

=



### 2.5 CAPACITY FACTOR This study assumes that each new plant would be dispatched any time it is available and would be capable of generating maximum capacity wh en online. Therefore capacity factor and availability are equal. The availability for PC and NGCC cases was determined using the Generating Availability Data System (GADS) from the North American Electric Reliability Council (NERC). [ 19 ] Since there are only two operating IGCC plants in North America, the same database was not useful for determining IG CC availability. Rather, input from EPRI and their work on the CoalFleet for Tomorrow Initiative was used. NERC defines an equivalent availability factor (EAF ), which is essentially a measure of the plant capacity factor assuming there is always a demand for the output. The EAF accounts for planned and scheduled derated hours as we ll as seasonal derated hours. As such, the EAF matches this study’s definition of capacity factor. The average EAF for coal-fired plants in the 400-599 MW size range was 84.9 percent in 2004 and averaged 83.9 percent from 2000-2004. Given that many of the plants in this size range are older, the EAF was rounded up to 85 percent and that value was used as the PC plant capacity factor. The average EAF for NGCC plants in the 400-5 99 MW size range was 84.7 percent in 2004 and averaged 82.7 percent from 2000-2004. Using the same rationale as for PC plants, the EAF was rounded up to 85 percent and that value was al so used as the NGCC plant capacity factor.
EPRI examined the historical forced and sche duled outage times for IGCCs and concluded that the reliability factor (which looks at forced or unscheduled outa ge time only) for a single train IGCC (no spares) would be about 90 percent. [ 20 ] To get the availability factor, one has to

39Cost and Performance Baseline for Fossil Energy Plants



### deduct the scheduled outage time. In reality th e scheduled outage time differs from gasifier technology-to-gasifier technology, but the differences are relatively small and would have minimal impact on the capacity factor, so for this study it was assumed to be constant at a 30-day planned outage per year (or two 15-day outages). The planned outage would amount to 8.2 percent of the year, so the availability factor would be (90 percent - 8 .2 percent), or 81.2 percent. There are four operating IGCC’s wo rldwide that use a solid feed stock and are primarily power producers (Polk, Wabash, Buggenum and Puerto llano). A 2006 report by Higman et al. examined the reliability of these IGCC power ge neration units and concluded that typical annual on-stream times are around 80 percent. [ 21 ] The capacity factor 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. Given the results of the EPRI st udy and the Higman paper, a capacity factor of 80 percent was chosen for IGCC wi th no spare gasifier required.
The addition of CO 2 

### capture to each technology was assumed not to impact the capacity factor. This assumption was made to enable a comparis on based on the impact of capital and variable operating costs only. Any reduction in assumed ca pacity factor would further increase the LCOE for the CO 2 

### capture cases.

2.6 RAW WATER USAGE 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 blowdown a nd condensate from syngas or flue gas (in CO 2 

### capture cases) was applied to offset the wa ter demand. The difference between demand and recycle is raw water usage. Raw water makeup was assumed to be provided 50 percent by a publicly owned treatment works (POTW) and 50 percent from groundwater. Raw wa ter usage is defined as the water metered from a raw water source and used in the plant pr ocesses for any and all pu rposes, such as cooling tower makeup, boiler feedwater makeup, slurry preparation makeup, ash handling makeup, syngas humidification, quench system makeup, and FGD system makeup. Usage represents the overall impact of the pr ocess on the water source. The largest consumer of raw water in all cases is cooling tower makeup. It was assumed that all cases utilized a mechanical draft, evaporative cooling tower, and all pr ocess blowdown streams were assumed to be treated and recycled to th e cooling tower. The design ambient wet bulb temperature of 11°C (51.5°F) ( Exhibit 2-1 ) was used to achieve a cooling water temperature of 16°C (60°F) using an approach of 5°C (8.5°F). The cooling water range was assumed to be 11°C (20°F). The cooling tower makeup rate was determined using the following [ 22 ]:

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

• Drift losses of 0.001 percent of th e circulating water flow rate

• Blowdown losses were calculated as follows:

o Blowdown Losses = Evaporat ive Losses / (Cycles of Concentration - 1) Where cycles of concentration is a measure of water quality, and a mid-range value of 4 was chosen for this study.

40Cost and Performance Baseline for Fossil Energy Plants



### The water balances presented in subsequent se ctions include the wate r demand of the major water consumers within the process, the amount provided by internal recy cle, and by difference, the amount of raw water required.

2.7 COST ESTIMATING METHODOLOGY The Total Plant Cost (TPC) and Operation and Ma intenance (O&M) costs for each of the cases in the study were estimated by WorleyParsons Group Inc. (WorleyParsons). The estimates carry an accuracy of ±30 percent, consistent with the screening study level of information available for the various study power technologies. WorleyParsons used an in-house database and con ceptual estimating models for the capital cost and O&M cost estimates. Costs were further ca librated using a combination of adjusted vendorfurnished and actual cost data from recent design and design/build projects. The capital costs for each cost account were reviewed by comparing individual accounts across all of the other cases and technologies to ensure an accurate representati on of the relative cost differences between the cases and accounts. All capital and O&M costs are presented as “o vernight costs” expr essed in December 2006 dollars. In this study the first year of plant co nstruction is assumed to be 2007, and the resulting LCOE is expressed in year 2007 dollars. Th e capital and operating costs in December 2006 dollars were treated as a January 2007 year cost throughout the report without escalation. In this report December 2006 dollars and January 2007 dollars are consider ed to be equal. Capital costs are presented at the TPC level. TPC includes:

• Equipment (complete with initial ch emical and catalyst loadings),

• Materials,

• Labor (direct and indirect),

• Engineering and construction management, and

• Contingencies (process and project).
Owner’s costs are excluded. 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 th e advantage of grouping all reas onably allocable components of a system or process so they are included in th e specific system account. (This would not be the case had a facility, area, or commodity account structure been chosen instead).
Non-CO 2 

### Capture Plant Maturity The case estimates provided includ e technologies at diffe rent commercial maturity levels. The estimates for the non-CO 2 

### -capture PC and NGCC cases repr esent well-developed commercial technology or “n th 

### plants.” The non-capture IGCC cases are also based on commercial offerings, however, there have been very limited sale s of these units so far. These non-CO 2 

### -capture IGCC plant costs are less mature in the learning curve, and the costs listed reflect the “next commercial offering” level of cost rather than mature n th 

### -of-a-kind cost. Thus, each of these cases reflects the expected cost for the next commercial sale of each of these respective technologies.

41Cost and Performance Baseline for Fossil Energy Plants



### CO 2 

### Removal Maturity The post-combustion CO 2 

### removal technology for the PC and NGCC capture cases is immature technology. This technology remains unproven at commercial scale in power generation applications. The pre-combustion CO 2 

### removal technology for the IGCC capture cases has a stronger commercial experience base. Pre-combustion CO 2 

### removal from syngas streams has been proven in chemical processes with similar conditions to that in IGCC plants, but has not been demonstrated in IGCC applications. While no commercial IGCC plant yet uses CO 2 

### removal technology in commercial service, ther e are currently IGCC plants with CO 2 

### capture well along in the planning stages. Contracting Strategy The estimates are based on an Engineering/ Procurement/Construction Management (EPCM) approach utilizing multiple subcontracts. This approach provides the Owner with greater control of the project, while minimizing, if not eliminatin g most of the risk premiums typically included in an Engineer/Procure/Construc t (EPC) contract price. In a traditional lump sum EPC contract, the Co ntractor assumes all risk for performance, schedule, and cost. However, as a result of current market conditions, EPC contractors appear more reluctant to assume that overall level of risk. Rather, the 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 a rrangements, it is reflected in the project cost. In today’s market, Contractor pr emiums 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 cost effective approach for the Owner. While the Owner retains the risks, the risks become reduced with time, as there is better scope defi nition at the time of contract award(s). Estimate Scope The estimates represent a complete power plan t facility on a generic site. Site-specific considerations such as unusua l soil conditions, special seismi c zone requirements, or unique local conditions such as accessibility , local regulatory requirements, et c. are not considered in the estimates. The estimate boundary limit is defined as the total plant facility within the “fence line” including coal receiving and water supply system, but termin ating at the high voltage side of the main power transformers. The single excepti on to the fence line limit is in the CO 2 

### capture cases where costs are included for TS&M of the CO 2 

### . Labor costs are based on Merit Shop (non-union), in a competitive bidding environment. Capital Costs WorleyParsons developed the capital cost estimate s 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 Worley Parsons as part of a commercial power plant design base of experience for similar equipmen t in the company’s range of power and process projects. A reference bottoms-up estimate for each major component provides the basis for the

42Cost and Performance Baseline for Fossil Energy Plants



### estimating models. This provides a basis for subsequent comparisons and easy modification when comparing between speci fic case-by-case variations. Key equipment costs for each of the cases were calibrated to reflect recent quotations and/or purchase orders for other ongoing in-house power or process projects. Thes e include, but are not limited to the following equipment:

• Pulverized Coal Boilers

• Combustion Turbine Generators

• Steam Turbine Generators

• Circulating Water Pumps and Drivers

• Cooling Towers

• Condensers

• Air Separation Units (partial)

• Main Transformers

• Econamine FG Plus CO 2 

### Capture Process (quote provided specifically for this project) Other key estimate considerations include the following:

• Labor costs are based on Midwest, Merit Shop. Costs would need to be re-evaluated for projects at different locations or for projects employing union labor.

• 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 incentive s 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. Current indications are that re gional craft shortages are likely over the next several years. The types and amounts of incentives will va ry based on project location and timing relative to other work. The cost impact resulting from an in adequate local work force can be significant.

• The estimates are based on a greenfield site.

• The site is considered to be Seismic Zone 1, relatively level, and free from hazardous materials, archeological artifacts, or exce ssive 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 founda tion loads.

• Costs are limited to within the “fence line,” terminating at the high voltage side of the main power transformers with the excep tion of costs included for TS&M of CO 2 

### in all capture cases.

43Cost and Performance Baseline for Fossil Energy Plants



### • Engineering and Construction Management were estimated as a percent of bare erected cost; 10 percent for IGCC and PC technologies , and 9 percent for NGCC technologies. These costs consist of all home office engine ering and procurement services as well as field construction management costs. Site staffing generally in cludes a construction manager, resident engineer, scheduler, a nd personnel for project controls, document control, materials management, site safety and field inspection.

• All capital costs are presen ted as “Overnight Costs” in December 2006 dollars. As previously mentioned, December 2006 a nd January 2007 dollars are considered equivalent in this report. Escalation to pe riod-of-performance is specifically excluded.
Price Escalation A significant change in power plan t cost occurred in re cent years due to th e significant increases in the pricing of equipment and bulk materials. This estimate includes these increases. All vendor quotes used to develop these estimates were received within the last two years. The price escalation of vendor quotes incorporated a ve ndor survey of actual and projected pricing increases from 2004 through the third quarter of 2006 that WorleyParsons conducted for a recent project. The results of that survey were used to validate/recalibrate the corresponding escalation factors used in the conceptual estimating models. Cross-comparisons In all technology comparison studie s, the relative differences in costs are often more significant than the absolute level of TPC. This require s cross-account comparison between technologies to review the consistency of the di rection of the costs. As noted above, the capital costs were reviewed and compared across a ll of the cases, accounts, and t echnologies to ensure that a consistent representation of th e relative cost differences is reflected in the estimates. In performing such a comparison, it is important to reference the technica l parameters for each specific item, as these are the basis for establis hing the costs. Scope or assumption differences can quickly explain any apparent anomalies. There are a number of cases where differences in design philosophy occur. Some key examples are:

• The combustion turbine account in the G EE IGCC cases includes a syngas expander which is not required for the CoP or Shell cases.

• The combustion turbines for the IGCC capture cas es include an additional cost for firing a high hydrogen content fuel.

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

### -capture and non-CO 2 

### -capture cases, resulting in a significant differential in thermal duty between the syngas coolers for the two cases.
Exclusions The capital cost estimate includes all anticipated costs for equipm ent and materials, installation labor, professional services (Engi neering and Construction Management), and contingency. The following items are excluded from the capital costs:

• Escalation to period-of-performance

44Cost and Performance Baseline for Fossil Energy Plants



### • Owner’s costs – including, but not limited to land acquisition and right-of-way, permits and licensing, royalty allowances, economic development, project development costs, allowance for funds-used-during constructi on, legal fees, Owner’s engineering, preproduction costs, furnishings, Owner’s contingency, etc.

• All taxes, with the exception of payroll taxes

• Site specific considerations – including butnot limited to seismic zone, accessibility, local regulatory requirements, excessive rock, piles, laydown space, etc.

• Labor incentives in excess of a 5-day/10-hour work week

• Additional premiums associated with an EPC contracting approach
Contingency Both the project contingency and process continge ncy costs represent costs that are expected to be spent in the development and execution of the project that are not yet fully reflected in the design. It is industry practice to include proj ect contingency in the TPC to cover project uncertainty and the cost of any additional equi pment that would result during detailed design. Likewise, the estimates include process conti ngency to cover the cost of any additional equipment that would be required as a re sult of continued technology development. Project Contingency Project contingencies were added to each of the capital accounts to cover project uncertainty and the cost of any additional equipment that co uld result from detailed design. The project contingencies represent costs that are expected to occur. Each bare erected cost account was evaluated against the level of estimate detail, fi eld experience, and the basis for the equipment pricing to define proj ect contingency. The capital cost estimates associ ated with the plant designs in this study were derived from various sources which include prior conceptual designs and actual desi gn and construction of both process and power plants.
The Association for the Advancement of Cost E ngineering (AACE) Intern ational recognizes five classes of estimates. On the surface, the level of project definition of the cases evaluated in this study would appear to fall under an AACE Interna tional Class 5 Estimate, associated with less than 2 percent project definition, and based on preliminary design methodology. However, the study cases are actually more in line with the AACE International Class 4 Estimate, which is associated with equipment factoring, parametric modeling, historical re lationship factors, and broad unit cost data. Based on the AACE International contingency guidelines as presented in NETL’s "Quality Guidelines for Energy System Studies" it would appear that the overall project contingencies for the subject cases should be in th e range of 30 to 40 percent. [ 4 ] However, such contingencies are believed to be too high when the basis for the cost numbers is considered. The costs have been extrapolated from an extensive data base of project costs (est imated, quoted, and actual), based on both conceptual and detailed designs for the va rious technologies. This information has been used to calibrate the costs in the current st udies, thus improving the quality of the overall estimates. As such, the overall project continge ncies should be more in the range of 15 to 20 percent based on the specific te chnology; with the PC and NGCC cas es being at the lower end of

45Cost and Performance Baseline for Fossil Energy Plants



### the range, and the IGCC cases at the higher end, and the capture cases be ing higher than the noncapture cases. Process Contingency Process contingency is intended to compensate for un certainties arising as a result of the state of technology development. Process contingencies have been applie d to the estimates as follows:

• Slurry Prep and Feed – 5 percent on GE IGCC cases - systems are operating at approximately 800 psia as compared to 600 psia for the other IGCC cases

• Gasifiers and Syngas Coolers – 15 percen t on all IGCC cases – next-generation commercial offering and integration with the power island

• Two Stage Selexol – 20 percent on all IG CC capture cases - unproven technology at commercial scale in IGCC service

• Mercury Removal – 5 percent on all IG CC cases – minimal commercial scale experience in IGCC applications

• CO 2 

### Removal System – 20 percent on all PC/NGCC capture cases - post-combustion process unproven at commercial scal e for power plant applications

• Combustion Turbine Generator – 5 percen t on all IGCC non-capture cases – syngas firing and ASU integration; 10 percent on all IGCC capture cases – high hydrogen firing.

• Instrumentation and Controls – 5 percen t on all IGCC accounts and 5 percent on the PC and NGCC capture cases – integration issues AACE International provides standards for proc ess contingency relative to technology status; from commercial technology at 0 to 5 percent to new t echnology with little or no test data at 40 percent. The process continge ncies as applied in this study are consistent with the AACE International standards. All contingencies included in the TPC, both project and process, represent costs that are expected to be spent in the development and execution of the project. Operations and Maintenance (O&M) The production costs or operating costs and related maintenance expenses (O&M) pertain to those charges associated with operating and maintaining the powe r plants over their expected life. These costs include:

• Operating labor

• Maintenance – material and labor

• Administrative and support labor

• Consumables

• Fuel

• Waste disposal

• Co-product or by-product cred it (that is, a negative cost for any by-products sold)

46Cost and Performance Baseline for Fossil Energy Plants



### There are two components of O&M costs; fi xed O&M, which is independent of power generation, and variable O&M, which is proportional to power generation. Operating Labor Operating labor cost was determined based on of the number of operators required for each specific case. The average base labor rate us ed to determine annual cost is $33/hr. The associated labor burden is estimated at 30 percent of the base labor rate.
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 sec tion. The exception to this is the maintenance cost for the combustion turbines, which is calculated as a functi on of operating hours.
It should be noted that a detailed analysis considering each of th e individual gasifier components and gasifier refractor y life is beyond the scope of this study. However, to address this at a high level, the maintenance factors applied to the gasifiers vary between the individual gasifier technology suppliers. The gasifier maintenance factors used for this study are as follows:

• GE – 10 percent on all gasifier components

• CoP and Shell – 7.5 percent on the gasifier and related components, and 4.5 percent on the syngas cooling. Administrative and Support Labor Labor administration and overhead charges are asse ssed at rate of 25 percent of the burdened operation and maintenance 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 and sorbent were taken from technology-specific heat and mass balance diagrams developed for ea ch plant application. Other consumables were evaluated on the basis of the quantity required using reference data. The quantities for initial fills and daily consumables were calc ulated on a 100 percent operating capacity basis. The annual cost for the daily co nsumables was then adjusted to incorporate the annual plant operating basis, or capacity factor. 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 cost s were determined/evaluated sim ilarly to the consumables. In this study both slag from the IGCC cases and fly ash and bottom ash from the PC cases are considered a waste with a disposal cost of $17.03/tonne ($15.45/ton). The carbon used for mercury control in the IGCC cases is consider ed a hazardous waste with disposal cost of $882/tonne ($800/ton).

47Cost and Performance Baseline for Fossil Energy Plants



### Co-Products and By-Products By-product quantities were also determined simila rly to the consumables. However, due to the variable marketability of these by-products, spec ifically gypsum and sulfur, no credit was taken for their potential salable value. Nor were any of the technologi es penalized for their potential disposal cost. That is, for this evaluation, it is assu med that the by-product or co-product value simply offset disposal costs, for a net zero in operating costs. It should be noted that by-product credits and/or disposal costs c ould 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 wh ether or not added capital should be included in the plant costs to produce a pa rticular co-product. Ash and sl ag are both potential by-products in certain markets, and in the absence of activ ated carbon injection in the PC cases, the fly ash would remain uncontaminated and have potential marketability. However, as stated above, the ash and slag are considered wastes in th is study with a concomitant disposal cost.
CO 2 

### Transport, Storage and Monitoring
For those cases that feature CO 2 

### capture, the capital and operating costs for CO 2 

### transport, storage and monitoring (TS&M) were indepe ndently estimated by the National Energy Technology Laboratory (NETL). Those costs were converted to a le velized cost of electricity (LCOE) and combined with the plant capital an d operating costs to produce an overall LCOE. The TS&M costs were levelized over a twenty-year period using the methodology described in the next subsection of this report.
CO 2 

### TS&M costs were estimated based on the following assumptions:

• CO 2 

### is supplied to the pipeline at the plan t fence line at a pressure of 15.3 MPa (2,215 psia). The CO 2 

### product gas composition varies in the cases presented, but is expected to meet the specification described in Exhibit 2-11 . [ 23 ]

Exhibit 2-11 CO 2 

### Pipeline Specification

Parameter Units Parameter Value

Inlet Pressure MPa (psia) 15.3 (2,215)

Outlet Pressure MPa (psia) 10.4 (1,515) Inlet Temperature °C (°F) 26 (79)

N 2 

### Concentration ppmv < 300

O 2 

### Concentration ppmv < 40

Ar Concentration ppmv < 10

• The CO 2 

### is transported 80 kilometers (50 miles) via pipeline to a geologic sequestration field for injection into a saline formation.

• The CO 2 

### is transported and injected as a superc ritical fluid in orde r to avoid two-phase flow and achieve maximum efficiency. [ 24 ] The pipeline is assumed to have an outlet

48Cost and Performance Baseline for Fossil Energy Plants



### pressure (above the supercritical pres sure) of 10.4 MPa (1,515 psia) with no recompression along the way. Accordingly, CO 2 

### flow in the pipeline was modeled to determine the pipe diameter that results in a pressure drop of 4.8 MPa (700 psi) over an 80 kilometer (50 mile) pipeline length. [ 25 ] (Although not explored in this study, the use of boost compressors and a smaller pipeline diameter could possibl y reduce capital costs for sufficiently long pipelines.) The diameter of the injection pipe will be of sufficient size that frictional lo sses during injection are mini mal and no booster compression is required at the well-head in order to ach ieve an appropriate down-hole pressure.

• The saline formation is at a depth of 1,239 meters (4,055 ft) and has a permeability of 22 millidarcy (a measure of permeability defined as roughly 10 -12 

### Darcy) and formation pressure of 8.4 MPa (1,220 psig). [ 23 ] This is considered an average storage site and requires roughly one injection well for each 9,360 tonnes (10,320 short tons) of CO 2 

### injected per day. [ 23 ] The assumed aquifer char acteristics are tabulated in Exhibit 2-12

. Exhibit 2-12 Deep, Saline Aquifer Specification

Parameter Units Base Case

Pressure MPa (psi) 8.4 (1,220)

Thickness m (ft) 161 (530)
Depth m (ft) 1,236 (4,055)
Permeability md 22
Pipeline Distance km (miles) 80 (50)
Injection Rate per Well tonne (ton) CO 2 

### /day 9,360 (10,320)

For CO 2 

### transport and storage, capital and O&M co sts were assessed usin g metrics from a 2001 Battelle report. [ 24 ] These costs were scaled from the 1999- year dollars described in the report to Dec-2006-year dollars using U.S. Bureau of Labor Statistics (BLS) Producer Price Indices for the oil and gas industry and the Chemical Engineering Plant Cost Index. Project and process contingencies of thirty and twenty percent, resp ectively, were applied to the Battelle costs to cover additional costs that are expected to aris e from: i) developing a more detailed project definition, and ii) using technologies that have not been well-demons trated to date in a similar commercial application.
For CO 2 

### monitoring, costs were assessed using metrics for a saline formation “enhanced monitoring package” as reported in a 2004 Inte rnational Energy Agen cy (IEA) report. [ 26 ] The IEA report presented costs for two types of salin e formations: those with low and high residual gas saturations. The reported monitoring cost s were higher for saline formations with low residual gas saturation, and those co sts were used as the basis fo r this report. The IEA report calculated the present value of life-cycle monitori ng costs using a ten per cent discount rate. The present value cost included the initial capital cost for monitoring as well as O&M costs for

49Cost and Performance Baseline for Fossil Energy Plants



### monitoring over a period of eighty years (a thirty-year injection period followed by fifty years of post-injection monitoring). For this study, the present value reported in th e IEA report was adjusted from Nov-2004-year dollars to Dec-2006-year dollars using U.S. BL S Producer Price Indices for the oil and gas industry. Project and process cont ingencies of thirty and thirty-f ive percent, respectively, were applied to the IEA value to cover additional costs that are expected to arise as described above. The resulting metric used for this report is a present valu e of $0.176 per metric ton of CO 2 

### stored over a thirty-year injection period. In accordance with the IEA’s present-value, life-cycle methodology, this report levelized monitoring costs over a twenty-yea r period by simply applying a cap ital charge factor to the present value of life-cycle monitoring costs (10 percent discount rate). This approach is representative of a scenar io in which the power plan t owner establishes a “CO 2 

### Monitoring Fund” prior to plant startup that is equal to the present value of life-cycle monitoring costs. Establishing such a fund at the ou tset could allay concerns about th e availability of funds to pay for monitoring during the post-inje ction period, when the plant is no longer operati ng. While it is recognized that other, more nuanced, approach es could be taken to le velizing eighty years of monitoring costs over a twenty-y ear period, the approach applie d in this report was chosen because it is simple to describe and should result in a conservative (i.e., higher) estimate of the funds required. Levelized Cost of Electricity The revenue requirement method of performing an economic analysis of a prospective power plant has been widely used in th e electric utility indus try. This method permits the incorporation of the various dissimilar components for a potentia l new plant into a single value that can be compared to various alternatives. The revenue re quirement figure-of-merit in this report is cost of electricity (COE) levelized over a 20 year period and expresse d in mills/kWh (numerically equivalent to $/MWh). The 20-year LCOE was calculated us ing a simplified model derived from the NETL Power Systems Financial Model. [ 27 ] The equation used to calcul ate LCOE is as follows:

(CCF P )(TPC) + [(LF F1 )(OC F1 ) + (LF F2 )(OC F2 ) + ...] + (CF)[(LF V1 )(OC V1 ) + (LF V2 )(OC V2 ) + ...] LCOE P = (CF)(MWh)



### where

LCOE P 

### = levelized cost of elec tricity over P years, $/MWh P = levelization period (e.g., 10, 20 or 30 years) CCF = capital charge factor fo r a levelization period of P years TPC = total plant cost, $

LF Fn 

### = levelization factor for category n fixed operating cost
OC Fn 

### = category n fixed operating cost for the in itial year of operation (but expressed in “first-year-of-construc tion” year dollars) CF = plant capacity factor

50Cost and Performance Baseline for Fossil Energy Plants



### LF Vn 

### = levelization factor for cate gory n variable operating cost
OC Vn 

### = category n variable operati ng cost at 100 percent capacity factor for the initial year of operation (but expressed in “first -year-of-construction” year dollars) MWh = annual net megawatt-hours of power generated at 100 percent capacity factor All costs are expressed in “first-year-of-construc tion” year dollars, and the resulting LCOE is also expressed in “first-year-of-c onstruction” year dollars. In th is study the first year of plant construction is assumed to be 2007, and the resulting LCOE is expressed in year 2007 dollars. The capital cost in December 2006 dollars was treated as a 2007 year cost.
In CO 2 

### capture cases, the LCOE for TS&M costs was added to the LCOE calculated using the above equation to generate a total cost including CO 2 

### capture, sequestration and subsequent monitoring. Although their useful life is usua lly well in excess of thirty y ears, a twenty-year levelization period is typically used for larg e energy conversion plants and is the levelization period used in this study. The technologies modeled in this study were di vided into one of two categories for calculating LCOE: investor owned utility (I OU) high risk and IOU low risk. All IGCC cases as well as PC and NGCC cases with CO 2 

### capture are considered high ri sk. The non-capture PC and NGCC cases are considered low risk. The resulting cap ital charge factor and levelization factors are shown in Exhibit 2-13

.
Exhibit 2-13 Economic Paramenters for LCOE Calculation

High Risk Low Risk Nominal Escalation, % 1



### Capital Charge Factor 0.175 0.164 N/A

Coal Levelization Factor 1.2022 1.2089 2.35

Natural Gas Levelization Factor 1.1651 1.1705 1.96

General O&M Levelization Factor 1.1568 1.1618 1.87

1 

### Nominal escalation is the real escalation plus the general annua l average inflation rate of 1.87

percent. The economic assumptions used to derive the capital charge f actors are shown in Exhibit 2-14

. The difference between the high risk and low risk categories is mani fested in the debt-to-equity ratio and the weighted cost of capital. The values used to generate the cap ital charge factors and levelization factors in this study are shown in Exhibit 2-15

.

51Cost and Performance Baseline for Fossil Energy Plants



### Exhibit 2-14 Parameter Assumpti ons for Capital Charge Factors

Parameter Value

Income Tax Rate 38% (Effectiv e 34% Federal, 6% State) Repayment Term of Debt 15 years Grace Period on Debt Repayment 0 years
Debt Reserve Fund None Depreciation 20 years, 150% declining balance Working Capital zero for all parameters
Plant Economic Life 30 years
Investment Tax Credit 0% Tax Holiday 0 years Start-Up Costs (% of EPC) 1 

### 2% All other additional capital costs ($) 0
EPC escalation 0%
Duration of Construction 3 years

1 

### EPC costs equal total plant costs less contingencies

Exhibit 2-15 Financial Structure for Invest or Owned Utility High and Low Risk Projects
Type of Security % of Total Current (Nominal) Dollar Cost Weighted Current (Nominal) Cost After Tax Weighted Cost of Capital
Low Risk
Debt 50 9% 4.5% 2.79% Equity 50 12% 6% 6%
Total 11% 8.79% High Risk
Debt 45 11% 4.95% 3.07% Equity 55 12% 6.6% 6.6%
Total 11.55% 9.67%

2.8 IGCC STUDY COST ESTIMATES CO MPARED TO INDUSTRY ESTIMATESThe estimated TPC for IGCC cases in this study ranges from $1,733kW to $1,977/kW for nonCO 2 

### capture cases and $2,390/kW to $2,668/kW for cap ture cases. Plant size ranges from 623 - 636 MW (net) for non-capture cases and 517 - 556 MW (net) for capture cases.

52Cost and Performance Baseline for Fossil Energy Plants



### Within the power industry there are several power producers interested in pursuing construction of an IGCC plant. While these projects are still in the relatively early stages of development, some cost estimates have been published. Published estimates tend to be limited in detail, leaving it to the reader to speculate as to what is contained within the estimate. Published estimates for gasification plants consisting of two gasifier trains range from $2,206/ k W to $3,175/ k W. [ 28
, 29 ] Corresponding plant sizes range from 600 - 680 MW. Since none of the published estimates state that CO 2 

### capture is included, it is assu med that they do not include CO 2 

### capture or compression equipment. In comparing costs published in this study to those published by industry, it is important to recognize that the estimates containe d in this study are based on a ve ry specific set of criteria for the purpose of comparing the variou s technologies. Site specific costs and owner’s costs are not included in this report. Excluding these costs is appropriate for a government-sponsored analysis as owner's costs often include va rying levels of profits depending on the current market. For example, there is presently a shortage of qua lified EPC companies for constructing new power plants, so these companies can demand a very hi gh price for their services. Endorsing these historically high rates as being reasonable, or even attempting to predict them, especially since it may represent a very short-lived market imbalance, is not an appropriate role for the government. These costs, however, are generally in cluded in industry-published estimates.
Differences in Cost Estimates Project Scope For this report, the scope of work is generally limited to work inside the project “fence line”. For outgoing power, the scope stops at the high side terminals of the Generator Step-up Transformers (GSU’s). Some typical examples of items outside the fenceline include:

• New access roads and railroad tracks

• Upgrades to existing roads to accommodate increased traffic

• Makeup water pipe outside the fenceline

• Landfill for on-site waste (slag) disposal

• Natural gas line for backup fuel provisions

• Plant switchyard

• Electrical transmission lines & substation Estimates in this report are based on a generi c mid-western greenfield site having “normal” characteristics. Accordingly, the estimates do not address items such as:

• Piles or caissons

• Rock removal

• Excessive dewatering

• Expansive soil considerations

• Excessive seismic considerations

• Extreme temperature considerations

• Hazardous or contaminated soils

• Demolition or relocation of existing structures

• Leasing of offsite land for parking or laydown

53Cost and Performance Baseline for Fossil Energy Plants



### • Busing of craft to site

• Costs of offsite storage This report is based on a reasonably “standard” plant. No unusual or extraordinary process equipment is included such as:

• Excessive water treatment equipment

• Air-cooled condenser

• Automated coal reclaim

• Zero Liquid Discharge equipment

• Selective catalytic reduction catalyst For non-capture cases, which are likely the mo st appropriate compar ison against industry published estimates, this report is based on plant equipment sized for non-capture only. None of the equipment is sized to accommodate a future conversion to CO 2 

### capture.
Labor This report is based on Merit Shop (non-union) labor. If a project is to use Union labor, there is a strong likelihood that overall labor costs will be greater than those estimat ed in this report. This report is based on a 50 hour work week, with an adequate local supply of skilled craft labor. No additional incentives such as per-diems or bonuses have been included to attract and retain skilled craft labor. The construc tion industry is currently experien cing severe shortages in craft labor. Accordingly, published costs likel y include any anticipated labor premiums. Contracting Methodology The estimates in this report are based on a co mpetitively bid, multiple subcontract approach, often referred to as EPCM. Accordingly, the esti mates do not include premiums associated with an EPC approach. It is belie ved that, given current market conditions, the premium charged by an EPC contractor could be as much as 30 percent or more over an EPCM approach.
Escalation
All of the estimates included in this report are base d on December, 2006 “overnight” costs. No escalation has been added to reflect period of pe rformance dollars. Overall project duration for plants of this type could be as much as five years or more.
Owner’s Costs
Owner’s costs are excluded from the estimates in this report. Owner’s costs as a percentage of TPC can vary dramatically. Conceivably, owner’s cost s can range from 15 to 25 percent of TPC. Typical Owner’s costs include, but are not limited to, the following:

• Permits and licensing ( other than construction permits )

• Land acquisition / Rights of way costs

• Economic development

• Project development costs

• Legal fees

• Owner’s Engineering / Project a nd Construction Management Staff

54Cost and Performance Baseline for Fossil Energy Plants



### • Plant operators during startup

• Electricity consumed during startup

• Fuel and reagents consumed during startup

• Transmission interconnections and upgrades

• Taxes ( other than EPCM payroll taxes )

• Operating spare parts

• Furnishings for new office, warehouse and laboratory

• Financing costs
Most if not all of these cost elements are likely included in published es timates. The addition of these elements to this report woul d explain most, if not all, of the disparities between estimates in the report and published costs.

55Cost and Performance Baseline for Fossil Energy Plants



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56Cost and Performance Comparison of Fossil Energy Power Plants

57 

## 3 IGCC POWER PLANTS Six IGCC power plant configurations were evaluated and the results are presented in this section. Each design is based on a market-ready technology that is assumed to be commercially available to support startup in 2010. The six cases are based on the GEE gasifier, the CoP E-GasTM gasifier a nd the Shell gasifier, each with and without CO 2 

### capture. As discussed in Section 1, the net output for the six cases varies because of the constraint imposed by th e fixed gas turbine output and the high auxiliary loads imparted by the CO 2 

### capture process.
The combustion turbine is based on an advanced F-class design. The HRSG/steam turbine cycle is 12.4 MPa/566°C/566°C (1800 psig/1050°F/1050°F) for all of the non-CO 2 

### capture cases and 12.4 MPa/538°C/538°C (1800 psig/1000°F/1000°F) for all of the CO 2 

### capture cases. The capture cases have a lower main and reheat steam temperature primarily because the turbine firing temperature is reduced to allow for a part s life equivalent to NG CC operation with a highhydrogen content fuel, which results in a lower turbine exhaust temperature. The evaluation scope included developing heat and mass balances and estimating plant performance. Equipment lists were develope d 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 that is common to all IGCC cases, a nd case specific informa tion is subsequently presented in Sections 3.2, 3.3 and 3.4.

3.1 IGCC COMMON PROCESS AREAS The IGCC cases have process areas which are comm on to each plant configuration such as coal receiving and storage, oxygen supply, gas cl eanup, 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 backgr ound information. Where there is case-specific performance information, the performance features are presented in the relevant case sections.

3.1.1 C OAL 

### R ECEIVING AND 

### S TORAGE 

### The function of the Coal Receiving and Storage sy stem is to unload, convey, prepare, and store the coal delivered to the plant. The scope of the system is from the trestle bottom dumper and coal receiving hoppers up to and including the slide ga te valves at the outlet of the coal storage silos. Coal receiving and storage is identical for all six IGCC cases; however, coal preparation and feed are gasifier-specific. Operation Description – The coal is delivered to the site by 100-car unit trains comprised of 91 tonne (100 ton) rail cars. Th e unloading is done by a trestle bo ttom dumper, which unloads the coal into two receiving hoppers. Coal from each hopper is fed directly into a vibratory feeder. The 8 cm x 0 (3" x 0) coal from the feeder is discharged onto a belt conveyor. Two conveyors with an intermediate transfer tower are assumed to convey the coal to the coal stacker, which transfer the coal to either the long-term storage pile or to the reclaim area. The conveyor passes under a magnetic plate separator to remove tramp iron and then to the reclaim pile.
The reclaimer loads the coal into two vibrator y feeders located in the reclaim hopper under the pile. The feeders transfer the coal onto a belt co nveyor that transfers the coal to the coal surgeCost and Performance Comparison of Fossil Energy Power Plants

58 

### bin located in the crusher tower. The coal is reduced in size to 3 cm x 0 (11⁄4" x 0) by the crusher. A conveyor then transfers the coal to a transfer tower. In the transfer tower the coal is routed to the tripper, which loads the coal into one of three silos. Two sampling systems are supplied: the as-received sampling system and the as-fired sampling system. Data from the analyses are used to support the reliabl e and efficient operation of the plant.

3.1.2 A IR 

### S EPARATION 

### U NIT 

### (ASU) C HOICE AND 

### I NTEGRATION 

### In order to economically and efficiently suppor t IGCC projects, air separation equipment has been modified and improved in response to prod uction requirements and the consistent need to increase single train output. “Elevated pressu re” air separation designs have been implemented that result in distillation column operating pre ssures that are about twice as high as traditional plants. In this study, the main air compressor discharge pressure was set at 1.3 MPa (190 psia) compared to a traditional ASU plant operati ng pressure of about 0.7 MPa (105 psia). [ 30] For IGCC designs the elevated pressure ASU proce ss minimizes power consumption and decreases the size of some of the equipment items. When the air supply to the ASU is integrated with the gas turbine, the ASU operates at or near the supply pressure from the gas turbine’s air compressor. Residual Nitrogen Injection The residual nitrogen that is available after gasifier oxygen and nitrogen requirements have been met is often compressed and sent to the gas turbine. Since all pr oduct streams are being compressed, the ASU air feed pressure is optimi zed to reduce the total power consumption and to provide a good match with available compressor frame sizes. Increasing the diluent flow to the gas turbine by injecting residual nitr ogen from the ASU can have a number of benefits, depending on the design of the gas turbine:

• Increased diluent increases mass flow through the turbine, thus increasing the power output of the gas turbine while maintaini ng optimum firing temperatures for syngas operation. This is particular ly beneficial for locations where the ambient temperature and/or elevation are high and the gas turb ine would normally operate at reduced output.

• By mixing with the syngas or by being injected directly into the combustor, the diluent nitrogen lowers the firing temperature (relati ve to natural gas) and reduces the formation of NOx. In this study, the ASU nitrogen pr oduct was used as the primary di luent with a design target of reducing the syngas lower heati ng value (LHV) to 4.5-4.8 MJ/Nm 3 

### (120-128 Btu/scf). If the amount of available nitrogen was not sufficient to meet this target, additional dilution was provided through syngas humidificat ion, and if still more dilution was required, the third option was steam injection.
Air Integration Integration between the ASU and the combustion tu rbine can be practiced by extracting some, or all, of the ASU’s air requirement from the gas turbine. Medium Btu syngas streams result in a higher mass flow than natural gas to provide the sa me heat content to the gas turbine. Some gas turbine designs may need to extract air to main tain stable compressor or turbine operation in response to increased fuel flow rates. Other gas turbines may balance air extraction againstCost and Performance Comparison of Fossil Energy Power Plants

59 

### injection of all of the av ailable nitrogen from the ASU. The amount of air extracted can also be varied as the ambient temperatur e changes at a given site to optimize year-round performance. An important aspect of air-integ rated designs is the need to e fficiently recover the heat of compression contained in the air extracted from th e gas turbine. Extraction air temperature is normally in the range 399 - 454°C (750 - 850°F), and must be cooled to th e last stage main air compressor discharge temperature prior to admissi on to the ASU. High-le vel recovery from the extracted air occurs by transferring heat to the nitr ogen stream to be injected into the gas turbine with a gas-to-gas heat exchanger.
Elevated Pressure ASU Experience in Gasification The Buggenum, Netherlands unit built for Demkolec was the first elevated-pressure, fully integrated ASU to be constructed. It was designed to produce up to 1,796 tonnes/day (1,980 TPD) of 95 percent purity oxygen for a She ll coal-based gasifica tion unit that fuels a Siemens V94.2 gas turbine. In normal operation at the Buggenum plant the ASU receives all of its air supply from and sends all re sidual nitrogen to the gas turbine. The Polk County, Florida ASU for the Tampa El ectric 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 gas turbine. All of the nitrogen produced in the ASU is used in the gas turbin e. The original design did not allow for air extraction from the combustion turbine. After a combustion turbine 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. [ 31]
ASU Basis For this study, air integration is used for the non-carbon capture cases only. In the carbon capture cases, once the syngas is diluted to the target heating value, all of the available combustion air is required to maintain mass fl ow through the turbine and hence maintain power output.
The amount of air extracted from the gas turbine in the non-capture cases is determined through a process that includes th e following constraints:

• The combustion turbine output must be maintained at 232 MW.

• The diluted syngas must meet heating valu e requirements specified by a combustion turbine vendor, which ranged from 4.5-4.8 MJ/Nm 3 

### (120-128 Btu/scf) (LHV). Meeting the above constraints resu lted in different levels of air extraction in the three non-carbon capture cases as shown in Exhibit 3-1. It was not a goal of this project to optimize the integration of the combustion turbine and the AS U, although several recent papers have shown that providing 25-30 percent of the ASU air fr om the turbine compre ssor provides the best balance between maximizing plant output and efficiency without co mpromising plant availability or reliability. [ 32, 33]Cost and Performance Comparison of Fossil Energy Power Plants

60 

### Exhibit 3-1 Air Extracted fr om the Combustion Turbine a nd Supplied to the ASU in NonCarbon Capture Cases

Case No. 1 3 5

Gasifier GEE CoP Shell
Air Extracted from Gas Turbine, % 4.1 4.9 6.7
Air Provided to ASU, % of ASU Total 15.7 22.3 31.0

Air Separation Plant Process Description [ 34] The air separation plant is designe d to produce 95 mole percent O 2 

### for use in the gasifier. The plant is designed with two production trains, on e for each gasifier. The air compressor is powered by an electric motor. Nitrogen is also recovered, compressed, a nd used as dilution in the gas turbine combustor. A process schematic of a typical ASU is shown in Exhibit 3-2. The air feed to the ASU is supplied from two sour ces. A portion of the air is extracted from the compressor of the gas turbine (non-CO 2 

### capture cases only). The remaining 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 in tercooling between each stage. Air from the stand-alone compressor is combined with the extraction ai r, and the combined stream is cooled and fed to an adsorbent-ba sed pre-purifier system. The adsorbent removes water, carbon dioxide, and C 4 

### + saturated hydrocarbons in the air. After passing through the adsorption beds, the air is filtered with a dust filter to remove any adsorbent fines that may be present. Downstream of the dust filter a sm all 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 direct ion countercurrent to the normal airflow. The nitrogen is heated ag ainst extraction steam (1.7 MPa [250 ps ia]) in a shell and tube heat exchanger. The regeneration nitrogen drives off the adsorbed contaminants. Following regeneration, the heated bed is cooled to near normal operating temperature by passing a cool nitrogen stream through the adsorbent beds. Th e bed is re-pressurized with air and placed on stream so that the current on-st ream bed(s) can be regenerated. The air from the pre-purifier is th en split into three stre ams. About 70 percent of the air is fed directly to the cold box. About 25 percent of the air is compresse d in an air booster compressor. This boosted air is then cooled in an aftercooler against cooli ng water in the first stage and against chilled water in the second stage before it is fed to the cold box. The chiller utilizes low pressure process steam at 0.3 MPa (50 psia). Th e remaining 5 percent of the air is fed to a turbine-driven, single-stage, centrif ugal booster compressor. This st ream is cooled in a shell and tube aftercooler against cooling wate r before it is fed to the cold box.
All three air feeds are co oled in the cold box to cryogenic te mperatures against returning product oxygen and nitrogen streams in plate-and-fin heat exchangers. The large air stream is fedCost and Performance Comparison of Fossil Energy Power Plants

61 

### directly to the first di stillation column to begi n the separation process. The second largest air stream is liquefied against boili ng liquid oxygen before it is fed to the distillation columns. The third, smallest air stream is fed to the cryogeni c 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 distilla tion columns as a liquid and is pressurized by a cryogenic pump. The pressurized liquid oxygen is th en vaporized against the high-pr essure air feed before being warmed to ambient temperature. The gaseous oxygen exits the cold box and is fed to the centrifugal compressor with inte rcooling between each stage of compression. The compressed oxygen is then fed to the gasification unit. Nitrogen is produced from the cold box at two pressure levels. Low-pressure nitrogen is split into two streams. The majority of the low-pr essure nitrogen is compressed and fed to the gas turbine as diluent nitrogen. A sm all portion of the nitrogen is used as the regeneration gas for the pre-purifiers and recombined with the diluent nitroge n. A high-pressure n itrogen stream is also produced from the cold box and is further compre ssed before it is also supplied to the gas turbine.
Exhibit 3-2 Typical ASU Process Schematic

Air Air Filter Main Air Compressor
CWS

CWR Steam Cond.

1st Stage DCA 2nd Stage DCA Prepurifiers Booster Air Compressor

Turbine Air Booster Regen Heater Steam

Cond. Regeneration Nitrogen

Regen. N2 Blower

Liq. Oxygen Pump Turbine Cryogenic Air Separation Unit

Single Train

GT Nitrogen HP Oxygen Oxygen Compressor

GT Nitrogen Compressor

Chiller Air from Gas Turbine

CWS

CWR

1 2

15 12

10

3 5 7

6

8 9Cost and Performance Comparison of Fossil Energy Power Plants

62 

### 3.1.3 W ATER 

### G AS 

### S HIFT 

### R EACTORS 

### Selection of Technology - In the cases with CO 2 

### separation and capture , the gasifier product must be converted to hydrogen-ri ch syngas. The first step is to convert most of the syngas carbon monoxide (CO) to hydrogen and CO 2 

### by reacting the CO with water over a bed of catalyst. The H 2 

### O:CO molar ratio in th e shift reaction, shown be low, is adjusted to approximately 2: 1 by the addition of steam to the syngas stream thus promoting a high conversion of CO. In the cases without CO 2 

### separation and capture, CO shift convertors are not required.
Water Gas Shift: CO + H 2 

### O ↔ CO 2 

### + H 2


### The CO shift converter can be located either upstream of the acid gas removal step (sour gas shift) or immediately downstream (sweet gas shift). If the CO converter is located downstream of the acid gas removal, then the metallurgy of th e unit is less stringent but additional equipment must be added to the process. Products from the gasifier are humidified with steam or water and contain a portion of the water va por necessary to meet the water- to-gas criteria at the reactor inlet. If the CO converter is located downstream of the acid gas removal, then the gasifier product would first have to be cooled and the fr ee 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 lo cated upstream of the ac id gas removal step, no additional equipment is required. This is becau se 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 acid gas removal unit and is referred to as sour gas shift (SGS). Process Description - The SGS consists of two paths of pa rallel fixed-bed reactors arranged in series. Two reactors in series are used in each parallel path to achieve sufficient conversion to meet the 90 percent CO 2 

### capture target in the Shell and GEE gasifier cases. In the CoP case, a third shift reactor is added to each path to increase the CO conversion. Even with the third reactor added, CO 2 

### capture is only 88.4 percent in the CoP case because of the relatively high amount of CH 4 

### present in the syngas. Cooling is provided between the se ries of reactors to control the exothermic temperature rise. The parallel set of reactors is required due to the high gas ma ss flow rate. In all three CO 2 

### capture cases the heat exchanger after the first SGS reactor is used to vaporize water that is then used to adjust the syngas H 2 

### O:CO ratio to 2:1 on a molar basis. The heat exchanger after the second SGS reactor is used to ra ise IP steam which then passes through the reheater section of the HRSG in the GEE and CoP cases, and is used to preheat the syngas prior to the first SGS reactor in the Shell case. Approximately 96 pe rcent conversion of the CO is achieved in the GEE and Shell cases, and about 98 percent conversion is achieved in the CoP case.

3.1.4 M ERCURY 

### R EMOVAL 

### An IGCC power plant has the potential of removi ng 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 combustion so that syngas volumes are much smaller than flue gas volumes in comparable PC cases. A concep tual design for a carbon bed adsorption system was developed for mercury control in the IGCC pl ants being studied. Data on the performance of carbon bed systems were obtained from the Eastman Chemical Company, which uses carbonCost and Performance Comparison of Fossil Energy Power Plants

63 

### beds at its syngas facility in Kingsport, Tennessee.[ 12] The coal mercury content (0.15 ppm dry) and carbon bed removal efficiency (95 percent) were discussed pr eviously in Section 2.4. IGCCspecific design considerati ons are discussed below.
Carbon Bed Location – The packed carbon bed vessels are located upstream of the sulfur recovery unit and syngas enters at a temperature near 38°C (100°F) . Consideration was given to locating the beds further upstream befo re the COS hydrolysis unit (in non-CO 2 

### capture cases) at a temperature near 204°C (400°F). However, wh ile the mercury removal efficiency of carbon has been found to be relatively insensitive to pres sure variations, temperature adversely affects the removal efficiency. [ 35] Eastman Chemical also operates their beds ahead of their sulfur recovery unit at a temper ature of 30°C (86°F). [ 12] Consideration was also given to locating the beds downstream of the sulfur recovery unit (SRU). However, it was felt that removing the mercury and other contaminants before the sulfur recovery unit would enhance the performance of the SRU and increase the life of the various solvents.
Process Parameters – An empty vessel basis gas residence time of approximately 20 seconds was used based on Eastman Chemical’s experience. [ 12] 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 [ 35] and was selected for this application. The bed density of 30 lb/ft 3 

### was based on the Calgon Carbon Corporation HGR-P sulfurimpregnated pelletized activated carbon. [ 36] These parameters determined the size of the vessels and the amount of carbon required. Each gasifier train has one mercury removal bed and there are two gasifier trains in each IGCC case, resulting in two carbon beds per case. Carbon Replacement Time – Eastman Chemicals replaces its bed every 18 to 24 months. [ 12] However, bed replacement is not because of me rcury loading, but for ot her reasons including:

• A buildup in pressure drop

• A buildup of water in the bed

• A buildup of other contaminants For this study a 24 month carbon replacement cycle was assumed. Under these assumptions, the mercury loading in the bed would build up to 0.6 - 1.1 weight percent (wt %). Mercury capacity of sulfur-impregnated carbon can be as high as 20 wt%. [ 37] The mercury laden carbon is considered to be a hazardous waste, and the disp osal cost estimate refl ects this categorization.

3.1.5 A CID 

### G AS 

### R EMOVAL 

### (AGR) P ROCESS 

### S ELECTION 

### Gasification of coal to generate power produces a syngas that must be treated prior to further utilization. A portion of the treatment consists of acid gas removal (AGR) and sulfur recovery. The environmental target for these IGCC cases is 0.0128 lb SO 2 

### /MMBtu, which requires that the total sulfur content of the syngas be reduced to less than 30 ppmv. This includes all sulfur species, but in particular the total of COS and H 2 

### S, thereby resulting in stack gas emissions of less than 4 ppmv SO 2 

### .Cost and Performance Comparison of Fossil Energy Power Plants

64 

### COS Hydrolysis The use of COS hydrolysis pretreatment in the f eed to the acid gas re moval process provides a means to reduce the COS concentration. This method was first commercially proven at the Buggenum plant, and was also used at bot h the Tampa Electric and Wabash River IGCC projects. Several catalyst manuf acturers including Haldor Topsoe and Porocel offer a catalyst that promotes the COS hydrolysis reaction. The non-carbon capture COS hydrolysis reactor designs are based on information from Porocel. In cases with carbon captu re, the SGS reactors reduce COS to H 2 

### S as discussed in Section 3.1.3. The COS hydrolysis reaction is equimolar with a slightly exothermic heat of reaction. The reaction is represented as follows.
COS + H 2 

### O ↔ CO 2 

### + H 2 

### S Since the reaction is exothermic, higher conversi on is achieved at lower temperatures. However, at lower temperatures the reacti on kinetics are slower. Based on th e feed gas for this evaluation, Porocel recommended a temperature of 177 to 204°C (350 to 400°F). Since the exit gas COS concentration is criti cal to the amount of H 2 

### S that must be removed with the AGR process, a retention time of 50-75 seconds was used to achieve 99.5 percen t conversion of the COS. The Porocel activated alumina-based catalyst, design ated as Hydrocel 640 catalyst, promotes the COS hydrolysis reaction without promoting reaction of H 2 

### S and CO to form COS and H 2 

### . Although the reaction is exothermic, the heat of reaction is dissipated among the large amount of non-reacting components. Therefore, the reaction is essentially isothermal. The product gas, now containing less than 4 ppmv of COS, is cooled prior to entering the mercury removal process and the AGR.

Sulfur Removal Hydrogen sulfide removal generally consists of absorption by a regenerable solvent. The most commonly used technique is based on countercurr ent contact with the so lvent. Acid-gas-rich solution from the absorber is stripped of its acid gas in a regenerator, usually by application of heat. The regenerated lean solution is then cool ed and recirculated to the top of the absorber, completing the cycle. Exhibit 3-3 is a simplified diagram of the AGR process. [ 38] There are well over 30 AGR processes in common commercial use throughout the oil, chemical, and natural gas industries. However, in a 2002 report by SFA Pacific a list of 42 operating and planned gasifiers shows that only six AGR processes are repr esented: Rectisol, Sulfinol, methyldiethanolamine (MDEA), Selexol, a queous di-isoproponal (ADIP) amine and FLEXSORB. [ 40] These processes can be separated into three general types: chemical reagents, physical solvents, and hybrid solvents.Cost and Performance Comparison of Fossil Energy Power Plants

65 

### Exhibit 3-3 Flow Diagram fo r a Conventional AGR Unit

Treated

Gas

Cooler

Lean Solvent L/R Exchanger

Rich Solvent Absorber

Lean Solvent Pump Reboiler Stripper Acid Gas Condenser

Feed Gas Treated Gas

Cooler

Lean Solvent L/R Exchanger

Rich Solvent Absorber

Lean Solvent Pump Reboiler Stripper Acid Gas Condenser

Feed Gas



### Chemical Solvents Frequently used for acid gas removal, chemical solvents are more suitable than physical or hybrid solvents for applications at lower operating pressures. Th e chemical nature of acid gas absorption makes solution loading and circulation less dependent on the acid gas partial pressure. Because the solution is aqueous, co-absorption of hydrocarbons is minimal. In a conventional amine unit, the chemical solvent reacts exothermi cally with the acid gas constituents. They form a weak chemical bond that can be broken, releasi ng the acid gas and regenerating the solvent for

reuse. In recent years MDEA, a tertiary amine, has ac quired a much larger share of the gas-treating market. Compared with primary and secondary amines, MDEA has supe rior capabilities for selectively removing H 2 

### S in the presence of CO 2 

### , is resistant to degrad ation by organic sulfur compounds, has a low tendency for corrosion, has a re latively low circulation rate, and consumes less energy. Commercially availa ble are several MDEA-based solv ents that are formulated for high H 2 

### S selectivity. Chemical reagents are used to remove the acid gases by a reversible chemical reaction of the acid gases with an aqueous solution of various al kanolamines or alkaline salts in water. Exhibit 3-4 lists commonly used chemical reagents along with principal licensors that use them in their processes. The process consists of an abso rber and regenerator, which are connected by a circulation of the chemical reagent aqueous solu tion. The absorber contacts the lean solution with the main gas stream (at pressure) to remove the acid gases by absorption/ reaction with the chemical solution. The acid-gas-rich solution is reduced to low pressu re and heated in the stripper to reverse the reactions and strip the acid gas. The aci d-gas-lean solution leaves the bottom of the regenerator stri pper and is cooled, pumped to the required pressure and recirculated back to the absorber. For some am ines, a filter and a separate reclaiming section (not shown) are needed to remove undesirable reaction byproducts.Cost and Performance Comparison of Fossil Energy Power Plants

66 

### Exhibit 3-4 Common Chemical Re agents Used in AGR Processes Chemical Reagent Acronym Process Licensors Using the Reagent Monoethanolamine MEA Dow, Exxon, Lurgi, Union Carbide Diethanolamine DEA Elf, Lurgi Diglycolamine DGA Texaco, Fluor

Triethanolamine TEA AMOCO Diisopropanolamine DIPA Shell

Methyldiethanolamine MDEA BASF, Dow, Elf, Snamprogetti, Shell, Union Carbide, Coastal Chemical

Hindered amine Exxon

Potassium carbonate “hot pot” Eickmeyer, Exxon, Lurgi, Union Carbide

Typically, the absorber temperat ure is 27 to 49°C (80 to 120°F) for amine processes, and the regeneration temperature is th e boiling point of th e solutions, generally 104 to 127°C (220 to 260°F). The liquid circulation ra tes can vary widely, depending on the amount of acid gas being captured. However, the most suitable processes are those that will dissolve 2 to 10 scf acid gas per gallon of solution circulated. Steam consum ption can vary widely also: 0.7 to 1.5 pounds per gallon of liquid is typical, with 0.8 to 0.9 being a typical “good” value. Case 3, which utilizes the chemical solvent MDEA, uses 0.88 po unds of steam per gallon of liquid. The steam conditions are 0.45 MPa (65 psia) and 151°C (304°F). The major advantage of these system s is the ability to remove acid gas to low levels at low to moderate H 2 

### S partial pressures.
Physical Solvents Physical solvents involve absorpti on of acid gases into certain or ganic solvents that have a high solubility for acid gases. As the name imp lies, physical solvents involve only the physical solution of acid gas – the acid gas loading in the solvent is proportional to the acid gas partial pressure (Henry’s Law). Physical solvent abso rbers are usually operated at lower temperatures than is the case for chemical solvents. The solu tion step occurs at high pressure and at or below ambient temperature while the regeneration step (dissolution) occurs by pressure letdown and indirect stripping with low-pre ssure 0.45 MPa (65 psia) steam. It is generally accepted that physical solvents become increasingly economical, a nd eventually superior to amine capture, as the partial pressure of acid gas in the syngas increases. The physical solvents are regenerated by multista ge flashing to low pressures. Because the solubility of acid gases increases as the temperat ure decreases, absorption is generally carried out at lower temperatures, and re frigeration is often required. Most physical solvents are capable of removi ng organic sulfur compounds. Exhibiting higher solubility of H 2 

### S than CO 2 

### , they can be designed for selective H 2 

### S or total acid gas removal. InCost and Performance Comparison of Fossil Energy Power Plants

67 

### applications where CO 2 

### capture is desired the CO 2 

### is flashed off at va rious pressures, which reduces the compression work and parasitic pow er load associated with sequestration. Physical solvents co-absorb heavy hydrocar bons from the feed stream. Since heavy hydrocarbons cannot be recovered by flash regeneration, they are stripped along with the acid gas during heated regeneration. These hydrocarbon losses result in a loss of valuable product and may lead to CO 2 

### contamination. Several physical solvents that use anhydrous organic solvents ha ve been commercialized. They include the Selexol process, which uses dimet hyl ether of polyethylen e glycol as a solvent; Rectisol, with methanol as the solvent; Purisol, which uses N-methyl-2-pyrrolidone (NMP) as a solvent; and the propylene-carbonate process. Exhibit 3-5 is a simplified flow diagram for a phys ical reagent type acid gas removal process. [ 38] Common physical solvent processes, along with their licensors, are listed in Exhibit 3-6.
Exhibit 3-5 Physical Solvent AG R Process Simplified Flow Diagram

Treated

Gas

Cooler

Lean Solvent L/R Exchanger Rich Solvent

Feed Gas Absorber

Lean Solvent Pump Reboiler Stripper Acid Gas Condenser

Flash Gas Treated

Gas

Cooler

Lean Solvent L/R Exchanger Rich Solvent

Feed Gas Absorber

Lean Solvent Pump Reboiler Stripper Acid Gas Condenser

Flash Gas



### Hybrid Solvents Hybrid solvents combine the high treated-gas pur ity offered by chemical solvents with the flash regeneration and lower energy re quirements of physical solven ts. Some examples of hybrid solvents are Sulfinol, Flexsorb PS, and Ucarsol LE.
Sulfinol is a mixture of sulfol ane (a physical solvent), diis opropanolamine (DIPA) or MDEA (chemical solvent), and water. DIPA is used when total acid gas removal is specified, while MDEA provides for selective removal of H 2 

### S.Cost and Performance Comparison of Fossil Energy Power Plants

68 

### Exhibit 3-6 Common Physical So lvents Used in AGR Processes

Solvent Solvent/Process Trade Name Process LicensorsDimethyl ether of polyethylene glycol Selexol UOP

Methanol Rectisol Linde AG and Lurgi

Methanol and toluene Rectisol II Linde AG N—methyl pyrrolidone Purisol Lurgi Polyethylene glycol and dialkyl ethers Sepasolv MPE BASF

Propylene carbonate Fluor Solvent Fluor Tetrahydrothiophenedioxide Sulfolane Shell Tributyl phosphate Estasolvan Uhde and IFP

Flexsorb PS is a mixture of a hindered amine and an organic solvent. Physically similar to Sulfinol, Flexsorb PS is very st able and resistant to chemical degradation. High treated-gas purity, with less th an 50 ppmv of CO 2 

### and 4 ppmv of H 2 

### S, can be achieved. Both Ucarsol LE701, for selective removal, and LE-702, for total acid gas removal, are formulated to remove mercaptans from feed gas. Mixed chemical and physical solvents combine the features of both systems. The mixed solvent allows the solution to absorb an appreciable am ount of gas at high pressure. The amine portion is effective as a reagent to remove the acid gas to low levels when high purity is desired. Mixed solvent processes generally operate at absorber temperatures similar to those of the amine-type chemical solvents and do not require re frigeration. They also retain some advantages of the lower steam requirements typical of the physical solvents. Common mixed chemical and physical solvent processes, along with their licensors, are listed in Exhibit 3-7. The key advantage of mixed solvent processes is their apparent ability to remove H 2 

### S and, in some cases, COS to meet very stringen t purified gas specifications. Exhibit 3-8 shows reported equilib rium solubility data for H 2 

### S and CO 2 

### in various representative solvents [ 38]. The solubility is expressed as standa rd cubic feet of gas per gallon liquid per atmosphere gas partial pressure. The figure illustrates the relative solubilities of CO 2 

### and H 2 

### S in different solvents and the effects of temperature. More importa ntly, it shows an order of ma gnitude higher solubility of H 2 

### S over CO 2 

### at a given temperature, which gives rise to the selective absorption of H 2 

### S in physical solvents. It also illustrates that the acid gas so lubility in physical solvents increases with lower solvent temperatures.Cost and Performance Comparison of Fossil Energy Power Plants

69 

### Exhibit 3-7 Common Mixed Solv ents Used in AGR Processes

Solvent/Chemical Reagent Solvent/Process Trade Name Process Licensors

Methanol/MDEA or diethylamine Amisol Lurgi

Sulfolane/MDEA or DIPA Sulfinol Shell Methanol and toluene Selefining Snamprogetti
(Unspecified) /MDEA FLEXSORB PS Exxon

Exhibit 3-8 Equilibrium Solubility Data on H 2 

### S and CO 2 

### in Various SolventsCost and Performance Comparison of Fossil Energy Power Plants

70 

### The ability of a process to selectively absorb H 2 

### S may be further enhanced by the relative absorption rates of H 2 

### S and CO 2 

### . Thus, some processes, besides using equilibrium solubility differences, will use absorption rate differen ces between the two acid gases to achieve selectivity. This is particularly true of the amine processes where the CO 2 

### and H 2 

### S absorption rates are very different.

CO 2 

### Capture A two-stage Selexol process is us ed for all IGCC capture cases in this study. A brief process description follows. Untreated syngas enters the first of two absorbers where H 2 

### S is preferentially removed using loaded solvent from the CO 2 

### absorber. The gas exiting the H 2 

### S absorber passes through the second absorber where CO 2 

### is removed using first flash regenerated, chilled solvent followed by thermally regenerated solvent added near the t op of the column. The treated gas exits the absorber and is sent either dir ectly to the combustion turbine or is partially humidified prior to entering the combustion turbine. A portion of th e gas can also be used for coal drying, when required. The amount of hydrogen recovered from the syngas st ream is dependent on the Selexol process design conditions. In this st udy, hydrogen recovery is 99.4 percen t. The minimal hydrogen slip to the CO 2 

### sequestration stream maximizes the overall plant efficiency. The Selexol plant cost estimates are based on a plant designed to rec over this high percentage of hydrogen. For model simplification, a nominal recovery of 100 per cent was used with th e assumption that the additional 0.6 percent hydrogen se nt to the combustion turbine w ould have a negligible impact on overall system performance.
The CO 2 

### loaded solvent exits the CO 2 

### absorber and a portion is sent to the H 2 

### S absorber, a portion is sent to a reabsorber and the remainder is sent to a series of flash drums for regeneration. The CO 2 

### product stream is obtained from the three flash drums, and after flash regeneration the solvent is chilled and returned to the CO 2 

### absorber. The rich solvent exiting the H 2 

### S absorber is combined with the rich solvent from the reabsorber and the combined stream is heated using the lean solvent from the stripper . The hot, rich solvent enters the H 2 

### S concentrator and partially flashes. The remaining li quid contacts nitrogen from the ASU and a portion of the CO 2 

### along with lesser amounts of H 2 

### S and COS are stripped from the rich solvent. The stripped gases from the H 2 

### S concentrator are sent to the reabsorber where the H 2 

### S and COS that were co-stripped in the concentr ator are transferred to a stream of loaded solvent from the CO 2 

### absorber. The clean gas from the reabsorber is combined with the clean gas from the H 2 

### S absorber and sent to the combustion turbine. The solvent exiting the H 2 

### S concentrator is sent to the stri pper 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 an d returned as reflux to the stripper or exported as necessary to maintain the proper water conten t of the lean solvent. The acid gas from the stripper is sent to the Claus pl ant for further processing. The lean solvent exiting the stripper is first cooled by providing heat to the rich solvent, then furthe r cooled by exchange with the product gas and finally chilled in the lean ch iller before returning to the top of the CO 2 

### absorber.Cost and Performance Comparison of Fossil Energy Power Plants

71 

### AGR/Gasifier Pairings There are numerous commercial AGR processes that could meet the sulfur environmental target of this study. The most frequently used AGR systems (Selexol, Sulfi nol, MDEA, and Rectisol) have all been used with the Shell and GE gasifi ers in various applications. Both existing E-Gas gasifiers use MDEA, but could in theory use any of the existing AGR technologies. [ 38] The following selections were made for the AGR process in non-CO 2 

### capture cases:

• GEE gasifier: Selexol was chosen based on th e GE gasifier operat ing at the highest pressure (815 psia versus 615 psia for CoP and Shell) which favors the physical solvent used in the Selexol process.

• CoP gasifier: Refrigerated MDEA was chosen because the two operating E-Gas gasifiers use MDEA and because CoP lists MDEA as th e selected AGR process on their website. [ 39] Refrigerated MDEA was chosen ove r conventional MDEA because the sulfur emissions environmental target chosen is just outside of the range of conventional (higher temperature) MDEA.

• Shell gasifier: The Sulfinol process was chos en for this case because it is a Shell owned technology. While the Shell gasifier can and ha s been used with other AGR processes, it was concluded the most likely pairing would be with the Sulfinol process. The two-stage Selexol process is used in all thre e cases that require carbon capture. According to the previously referenced SFA Paci fic report, “For future IGCC with CO 2 

### removal for sequestration, a two-stage Selexol process presen tly appears to be the preferred AGR process – as indicated by ongoing engineeri ng studies at EPRI and various engineering firms with IGCC interests.” [ 40]

3.1.6 S ULFUR 

### R ECOVERY 

### /T AIL 

### G AS 

### C LEANUP 

### P ROCESS 

### S ELECTION 

### Currently, most of the world’s sulfur is produced from the acid gases coming from gas treating. The Claus process remains the mainstay for sulf ur recovery. Conventi onal three-stage Claus plants, with indirect rehe at and feeds with a high H 2 

### S content, can approach 98 percent sulfur recovery efficiency. However, since environm ental regulations have become more stringent, sulfur recovery plants are requi red to recover sulfur with over 99.8 percent efficiency. To meet these stricter regulations, the Claus proce ss underwent various modifications and add-ons. 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 tail gas treating unit (TGTU) process.

The Claus Process The Claus process converts H 2 

### S to elemental sulfur via the following reactions:
H 2 

### S + 3/2 O 2 

### ↔ H 2 

### O + SO 2 

### 2H 2 

### S + SO 2 

### ↔ 2H 2 

### O + 3S The second reaction, the Claus reaction, is e quilibrium limited. The overall reaction is:
3H 2 

### S + 3/2 O 2 

### ↔ 3H 2 

### O + 3SCost and Performance Comparison of Fossil Energy Power Plants

72 

### The sulfur in the vapor phase exists as S 2 

### , S 6 

### , and S 8 

### molecular species, with the S 2 

### predominant at higher temperatures, and S 8 

### predominant at lower temperatures. A simplified process flow diagram of a typi cal three-stage Claus plant is shown in Exhibit 3-9. [ 40] One-third of the H 2 

### S is burned in the furnace with oxygen from the air to give sufficient SO 2 

### to react with the remaining H 2 

### S. Since these reactions are highly exothermic, a waste heat boiler that recovers this heat to generate high-p ressure steam usually follows the furnace. Sulfur is condensed in a condenser that follows the high -pressure steam recovery section. Low-pressure steam is raised in the condenser . The tail gas from the first condenser then goes to several catalytic conversion stages, usuall y 2 to 3, where the remaining sulf ur is recovered via the Claus reaction. Each catalytic stage cons ists 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.
Claus Plant Sulfur Recovery Efficiency The Claus reaction is equilibrium limited, and su lfur 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 1093 to 1427°C (2000 to 2600°F), and as the temperature decreases, convers ion increases dramatically.
Exhibit 3-9 Typical Three- Stage Claus Sulfur Plant

Claus plant sulfur recovery effi ciency depends on many factors:

• H 2 

### S concentration of the feed gas

• Number of catalytic stages

• Gas reheat methodCost and Performance Comparison of Fossil Energy Power Plants

73 

### In order to keep Claus plant re covery efficiencies approaching 94 to 96 percent for feed gases that contain about 20 to 50 percent H 2 

### S, a split-flow design is often used. In this version of the Claus plant, part of the feed gas is bypassed ar ound the furnace to the first catalytic stage, while the rest of the gas is oxidized in the furnace to mostly SO 2 

### . This results in a more stable temperature in the furnace.
Oxygen-Blown Claus Large diluent streams in the feed to the Claus plant, such as N 2 

### from combustion air, or a high CO 2 

### 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 pl ant and to obtain stable temperatures in the furnace for dilute H 2 

### S 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 in crease flame temperatures of low H 2 

### S content gases. The process has also been used to provide the capac ity and operating flexibility for sulfur plants where the feed gas is variable in flow and com position such as often found in refineries. The application of the process has now been extended to grass roots installations, even for rich H 2 

### S feed streams, to provide operating flexibility at lower costs than would be the case for conventional Claus units. At least four of the 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 1593 to 1649°C (2900 to 3000°F) as the enrichment moves beyond 40 to 70 vol percent O 2 

### in the oxidant feed stream. Alt hough oxygen enrichment has many benefits, its primary benefit for lean H 2 

### S feeds is a stable furnace temperat ure. Sulfur recovery is not significantly enhanced by oxygen enrichment. B ecause the IGCC process already requires an ASU, the oxygen-blown Claus plan t was chosen for all cases.
Tail Gas Treating In many refinery and other conventional Clau s applications, tail ga s treating involves the removal of the remaining sulfur compounds from ga ses exiting the sulfur r ecovery unit. Tail gas from a typical Claus process, whether a conventi onal Claus or one of the extended versions of the process, usually contains sma ll but varying quantities of COS, CS 2 

### , H 2 

### S, SO 2 

### , and elemental sulfur vapors. In addition, there may be H 2 

### , CO, and CO 2 

### in the tail gas. In order to remove the rest of the sulfur compounds from the tail gas, all of the sulfur-bearing species must first be converted to H 2 

### S. Then, the resulting H 2 

### S is absorbed into a solvent and the clean gas vented or recycled for further processing. The clean gas resulting from the hydrolysis step can undergo further cleanup in a dedicated abso rption unit or be integrated with an upstream AGR unit. The latter option is particularly su itable with physical absorption solv ents. The approach of treating the tail gas in a dedicated amine absorption unit a nd recycling the resulti ng acid gas to the Claus plant is the one used by the Sh ell Claus Off-gas Treating (SCOT) process. With tail gas treatment, Claus plants can achieve overall re moval efficiencies in excess of 99.9 percent. In the case of IGCC applications, the tail ga s from the Claus plant can be catalytically hydrogenated and then recycled back into th e system with the choice of location being technology dependent, or it can be treated with a SCOT-type process. In the two GEE gasifier cases the Claus plant tail gas is hydrogenated, water is separated, the tail gas is compressed and returned to the Selexol process for further treat ment. GEE experience at the Polk Power StationCost and Performance Comparison of Fossil Energy Power Plants

74 

### is not relevant to this study sin ce the acid gas is converted to sulfur ic acid rather than sulfur and the tail gas, containing 150-250 ppm SO 2 

### , is discharged through a dedicated stack. [ 41] In the two CoP cases the tail gas is treated in the sa me manner as in the GEE cases except that the recycle endpoint is the gasifier rather than the AGR process. This method is the same as practiced at the CoP Wabash River plant. [ 42] The two recycle point s were chosen based on conversations with the gasifi er technology vendors. In the two Shell cases the Claus tail gas is cata lytically hydrogenated a nd then treated in an amine-based tail gas cleanup process. The bulk of the H 2 

### S in the tail gas is captured and recycled back to the Claus plant inlet gas str eam. The sweet gas from the TGTU is combined with a slipstream of clean syngas and the combined stream is com busted in an incinerator. The hot, inert gases from the incinerato r are used to dry the feed coal and then vented to atmosphere. Since the Shell Puertollano plant uses a combina tion of natural gas combustion and IP steam to dry their coal, their tail gas treatment procedure is different than employed in this study. The Claus plant tail gas is hydrogenated and recycled , but the recycle endpoint is not specified. [ 43]

Flare Stack A self-supporting, refractory-lined, carbon steel flare stack is typi cally provided to combust and dispose of unreacted gas during startup, shutdown, and upset conditions. However, in all six IGCC cases a flare stack was provided for syngas dumping during startup, shutdown, etc. This flare stack eliminates the need for a separate Claus plant flare.

3.1.7 S LAG 

### H ANDLING 

### The slag handling system conveys, stores, and di sposes 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 peasized fragments. A slag/water slurry that is be tween 5 and 10 percent solids leaves the gasifier pressure boundary through either a proprietary pressure letdown device (CoP) or through the use of lockhoppers (GEE and Shell) to a series of dewatering bins. The general aspects of slag ha ndling are the same for all thre e technologies. The slag is dewatered, the water is clarified a nd recycled and the dried slag is transferred to a storage area for disposal. The specifics of slag handling vary among the gasificati on technologies regarding how the water is separated and the end uses of the water recycle streams. In this study the slag bins were sized for a nominal holdup capacity of 72 hours of full-load operation. At periodic intervals, a convoy of slag-hauling trucks will transit the unloading station underneath the hopper and re move a quantity of slag for disposal. Approximately ten truckloads per day are required to remove th e total quantity of slag produced by the plant operating at nominal rated power. While the slag is suitable fo r use as a component of road paving mixtures, it was assumed in this study that the slag would be landfilled at a specified cost just as the ash from the PC boiler cases is assu med to be landfilled at the same per ton cost.Cost and Performance Comparison of Fossil Energy Power Plants

75 

### 3.1.8 P OWER 

### I SLAND



### Combustion Turbine The gas turbine generator selected for this applic ation is representative of the advanced F Class turbines. This machine is an axial flow, single s pool, and constant speed un it, with variable inlet guide vanes. The turbine incl udes advanced bucket cooling t echniques, compressor aerodynamic design and advanced alloys, enabling a higher fi ring temperature than the previous generation machines. The standard production version of this machine is fired with natural gas and is also commercially offered for use with IGCC derived syngas, although only earl ier versions of the turbine are currently operating on syngas. For the purposes of th is study, it was assumed that the advanced F Class turbine will be commercially available to support a 2010 startup date on both conventional and high hydrogen content syngas representative of the cases with CO 2 

### capture. High H 2 

### fuel combustion issues like flame stabilit y, flashback and NOx formation were assumed to be solved in the time frame needed to suppor t deployment. However, because these are firstof-a-kind applications, process co ntingencies were included in the cost estimates as described in Section 2.7. Performance typical of an advanced F class turbine on natural gas at ISO conditions is presented in Exhibit 3-10.

Exhibit 3-10 Advanced F Class Combustion Turbine Performance Characteristics Using Natural Gas

Advanced F Class Firing Temperature Class, °C ( ° F) 1371+ (2500+) Airflow, kg/s (lb/s) 431 (950)
Pressure Ratio 18.5 NOx Emissions, ppmv 25 Simple Cycle Output, MW 185 Combined cycle performance Net Output, MW 280 Net Efficiency (LHV), % 57.5 Net Heat Rate (LHV), kJ/kWh (Btu/kWh) 6,256 (5,934)

In this service, with syngas from an IGCC plan t, the machine requires some modifications to the burner and turbine nozzles in order to prope rly combust the low-Btu gas and expand the combustion products in the turb ine section of the machine.
The modifications to the machine include some re design of the original can-annular combustors. A second modification involves increasing the no zzle areas of the turbine to accommodate the mass and volume flow of low-Btu fuel gas combus tion products, which are increased relative to those produced when firing natural gas. Othe r modifications include rearranging the various auxiliary skids that support the machine to accommodate the spatial requirements of the plant general arrangement. The generator is a standard hydrogen-cooled machine with static exciter.Cost and Performance Comparison of Fossil Energy Power Plants

76 

### Combustion Turbine Package Scope of Supply The combustion turbine (CT) is typically supp lied in several fully shop-fabricated modules, complete with all mechanical, el ectrical and control systems as required for CT operation. Site CT installation involves module in ter-connection, and linking CT m odules to the plant systems. The CT package scope of supply for combined cy cle application, while pr oject specific, does not vary much from project-to-project. The typical scope of suppl y is presented in Exhibit 3-11.
Exhibit 3-11 Combustion Turbine Typical Scope of Supply
System System Scope

1.0 ENGINE ASSEMBLY Coupling to Generator, Dry Chemical Exhaust Bearing Fire Protection System, Insulation Blankets, Pl atforms, Stairs and Ladders

1.1 Engine Assembly with Bedplate Variable Inlet Guide, Vane System Compressor, Bleed System, Purge Air System, Bearing Seal Sir System, Com bustors, Dual Fuel Nozzles Turbine Rotor Air Cooler

1.2 Walk-in acoustical enclosure HVAC, Lighting, and Low Pressure CO 2 

### Fire Protection System

2.0 MECHANICAL PACKAGE HVAC and Lighting, Air Compressor for Pneumatic System, Low Pressure CO 2 

### Fire Protection System

2.1 2.2 Lubricating Oil System and Control Oil System Lube Oil Reservoir, Accumulators, 2x100% AC Driven Oil Pumps DC Emergency Oil Pump with Starter, 2 x100% Oil Coolers, D uplex Oil Filter, Oil Temperature and Pressure Control Valves, Oil Vapor Exhaust Fans and Demister Oil Heaters Oil Interconne ct Piping (SS and CS) Oil System Instrumentation Oil for Flushing and First Filling

3.0 ELECTRICAL PACKAGE HVAC and Lighting, AC and DC Moto r Control Centers, Generator Voltage Regulating Cabinet, Genera tor Protective Relay Cabinet, DC Distribution Panel, Battery Charger, Digital Control System with Local Control Panel (all control and monitori ng functions as well as data logger and sequence of events recorde r), Control System Valves and Instrumentation Communication link for interface with plant DCS Supervisory System, Bentley Nevada Vibration Monitoring System, Low Pressure CO 2 

### Fire Protection System, Cabl e Tray and Conduit Provisions for Performance Testing including Test Ports, Thermowells, Instrumentation and DCS interface cards

4.0 INLET AND EXHAUST SYSTEMS Inlet Duct Trash Screens, Inlet Duct and Silencers, Self Cleaning Filters, Hoist System For Filter Maintenance, Evaporative Cooler System, Exhaust Duct Expansion Joint, Exhaust Silen cers Inlet and Exhaus t Flow, Pressure and Temperature Ports and Instrumentation

5.0 FUEL SYSTEMSCost and Performance Comparison of Fossil Energy Power Plants

77 

### System System Scope

5.1 Fuel Syngas System Gas Valves Including Vent, Throttle and Trip Valves Gas Filter/Separator Gas Supply Instruments and Instrument Panel

5.2 Backup Fuel System Specific to backup fuel type

6.0 STARTING SYSTEM Enclosure, Starting Motor or Static Start Sy stem, Turning Gear and Clutch Assembly, Starting Clutch Torque Converter

7.0 GENERATOR Static or Rotating Exciter (Excitation tr ansformer to be included for a static system), Line Termination Enclosure w ith CTs, VTs, Surge Arrestors, and Surge Capacitors, Neutral Cubicle with CT, Neutral Tie Bus, Grounding Transformer, and Secondary Resistor , Generator Gas Dryer, Seal Oil System (including Defoaming Tank, Rese rvoir, Seal Oil Pump, Emergency Seal Oil Pump, Vapor Extractor, a nd Oil Mist Eliminator), Generator Auxiliaries Control Enclosure, Genera tor Breaker, Iso-Phase bus connecting generator and breaker, Grounding System Connectors

7.1 Generator Cooling TEWAC System (including circulation system, interconnecting piping and controls), or Hydrogen Cooling System (including H 2 

### to Glycol and Glycol to Air heat exchangers, liquid le vel detector circulation system, interconnecting piping and controls)

8.0 Miscellaneous Interconnecting Pipe, Wire, Tubing a nd Cable, Instrument Air System Including Air Dryer, On Line and Off Line Water Wash System, LP CO 2 

### Storage Tank, Drain System, Drain Tanks, Coupling, Coupling Cover and Associated Hardware

CT Firing Temperature Control Issue for Low Calorific Value Fuel A gas turbine when fired on low calorific value s yngas has the potential to increase power output due to the increase in flow rate through the turbine. The higher turbine flow and moisture content of the combustion products can contribute to overheating of turbine components, affect rating criteria for the parts lives, and require a reduction in synga s firing temperatures (compared to the natural gas firing) to maintain design metal temperature. [ 44] Uncontrolled syngas firing temperature could result in more than 50 percent life cycle reduc tion of stage 1 buckets. Control systems for syngas applications include provi sions to compensate for these effects by maintaining virtually constant generation output for the range of the specified ambient conditions. Inlet guide vanes (I GV) and firing temperature are us ed to maintain the turbine output at the maximum torque ra ting, producing a flat rating up to the IGV full open position. Beyond the IGV full open position, flat output may be extended to higher ambient air temperatures by steam/nitrogen injection. In this study the firing temperature (defined as inlet rotor temperature) using natural gas in NGCC applications is 1399°C (2550°F) while th e firing temperature in the non-capture IGCC cases is 1343-1354°C (2450-2470°F) and in the CO 2 

### capture cases is 1318-1327°C (2405-Cost and Performance Comparison of Fossil Energy Power Plants

78 

### 2420°F). The further reduction infiring temperature in the CO 2 

### capture cases is done to maintain parts life as the H 2 

### O content of the combustion products increases from 8-10 volume percent (vol%) in the no n-capture cases to 14-16 vol% in the capture cases. The decrease in temperature also results in the lowe r temperature steam cycle in the CO 2 

### capture cases (538°C/538°C [1000°F/1000°F] versus 566°C/566° C [1050°F/1050°F] for non-capture cases).
Combustion Turbine Syngas Fuel Requirements. Typical fuel specifications and contaminant leve ls for successful combustion turbine operation are provided in reference [ 45] and presented for F Class machines in Exhibit 3-12 and Exhibit 3-13. The vast majority of published CT performance information is specific to natural gas operation. Turbine performan ce using syngas requires vendor i nput as was obtained for this study.
Exhibit 3-12 Typical Fuel Specification for F-Class Machines

Max Min
LHV, kJ/m 3 

### (Btu/scf) None 3.0 (100) Gas Fuel Pressure, MPa (psia) 3.1 (450)

Gas Fuel Temperature, °C ( ° F) (1) Varies with gas pressure (2) Flammability Limit Ratio, Rich-to-Lean, Volume Basis (3) 2:2.1

Sulfur (4)

Notes:

1. The maximum fuel temperature is defined in reference [ 46] 2. To ensure that the fuel gas supply to the gas turbine is 100 percent free of liquids the minimum fuel gas temperature must meet the required superheat over the respective dew point. This requirement is independent of the hydrocarbon and moisture concentration. Superheat calcula tion shall be performed as described in GEI-4140G [ 45]. 3. Maximum flammability ratio limit is not de fined. Fuel with flammability ratio significantly larger than those of na tural gas may require start-up fuel 4. The quantity of sulfur in syngas is not limited by specification. Experience has shown that fuel sulfur levels up to 1 pe rcent by volume do not significantly affect oxidation/corrosion rates.

Normal Operation Inlet air is compressed in a single spool compresso r to a pressure ratio of approximately 16:1. This pressure ratio was vendor specified and le ss than the 18.5:1 ratio used in natural gas applications. The majority of compressor disc harge air remains on-board the machine and passes to the burner section to support combustion of the syngas. Compressed air is also used in burner,Cost and Performance Comparison of Fossil Energy Power Plants

79 

### transition, and film cooling services. About 4-7 percent of the compresso r air is extracted and integrated with the air supply of the ASU in non-carbon capture cas es. It may be technically possible to integrate the CT and ASU in CO 2 

### capture cases as well; however, in this study integration was considered only for non-carbon capture cases.

Exhibit 3-13 Allowable Gas Fuel Co ntaminant Level for F-Class Machines
Fuel Limit, ppmw
Turbine Inlet Flow/Fuel Flow Turbine Inlet Limit, ppbw 50 12 4
Lead 20 1.0 0.240 .080
Vanadium 10 0.5 0.120 0.040
Calcium 40 2.0 0.480 0.160 Magnesium 40 2.0 0.480 0.160
Sodium + Potassium Na/K = 28 (1) 20 1.0 0.240 0.080
Na/K = 3 10 0.5 0.120 0.40
Na/K ≤ 1 6 0.3 0.072 0.024 Particulates Total (2) 600 30 7.2 2.4
Above 10 microns 6 0.3 0.072 0.024

Notes: 1. Na/K=28 is nominal sea salt ratio 2. The fuel gas delivery system shall be desi gned to prevent generation or admittance of solid particulate to the gas turbine gas fuel system
Pressurized syngas is combusted in several ( 14) parallel diffusion combustors and syngas dilution is used to limit NOx formation. As described in Section 3.1.2 nitrogen from the ASU is used as the primary diluent followed by syngas humidification and finally by steam dilution, if necessary, to achieve an LHV of 4.5-4.8 MJ/Nm 3 

### (120-128 Btu/scf). The advantages of using nitrogen as the primary diluent include:

• Nitrogen from the ASU is already partia lly compressed and using it for dilution eliminates wasting the compression energy.

• Limiting the water content reduces the need to de-rate firing temperatur e, particularly in the high-hydrogen (CO 2 

### capture) cases. There are some disadvantages to using nitrogen as the primar y diluent, and these include:

• There is a significant auxiliary power requireme nt to further compress the large nitrogen flow from the ASU pressures of 0.4 and 1.3 MP a (56 and 182 psia) to the CT pressure of 3.2 MPa (465 psia).Cost and Performance Comparison of Fossil Energy Power Plants

80 

### • The low quality heat used in the syngas humidification process does not provide significant benefit to the pro cess in other applications.

• Nitrogen is not as efficient as water in limiting NOx emissions It is not clear that one dilution method provides a significant advantage over the other. However, in this study nitrogen was chosen as the prim ary diluent based on sugges tions by turbine industry experts during peer re view of the report. Hot combustion products are expanded in the thr ee-stage turbine-expander. Given the assumed ambient conditions, back-end loss, and HRSG pressure drop, the CT exhaust temperature is nominally 599°C (1110°F) for non-CO2 capture ca ses and 566°C (1050°F) for capture cases. Gross turbine power, as measur ed prior to the generator te rminals, is 232 MW. The CT generator is a standard hydrogen-cool ed machine with static exciter.

3.1.9 S TEAM 

### G ENERATION 

### I SLAND


### Heat Recovery Steam Generator The heat recovery steam generator (HRSG) is a horizontal gas flow, drum-type, multi-pressure design that is matched to the characteristics ofthe gas turbine exhaust gas when firing mediumBtu gas. High-temperature flue gas exiting the CT is conveyed through th e HRSG to recover the large quantity of thermal energy that remains. Flue gas travel s through the HRSG gas path and exits at 132°C (270°F) for all six IGCC cases. The high pressure (HP) drum produces steam at main steam pressure, while the intermediate pressure (IP) drum produces process steam and turbine dilution steam, if required. The HRSG drum pressures are nominally 12.4/2.9 MPa ( 1800/420 psia) for the HP/IP turbine sections, respectively. In addition to generating and superheating steam, the HRSG performs reheat duty for the cold/hot reheat steam for the steam turbine, provides condensate and feedwater heating, and also provides deaeration of the condensate.
Natural circulation of steam is accomplished in the HRSG by util izing differences in densities due to temperature differences of the steam. The natural circulation HRSG provides the most cost-effective and reliable design. The HRSG drums include moisture separators, inte rnal baffles, and piping for feedwater/steam. All tubes, including economizer s, superheaters, and headers and drums, are equipped with drains. Safety relief valves are furnished in order to comply with appropriate codes and ensure a safe work place. Superheater, boiler, and economizer sections are supported by shop-assembled structural steel. Inlet and outlet duct is provided to route the gases from the gas tu rbine outlet to the HRSG inlet and the HRSG outlet to the stack. A diverter va lve is included in the in let duct to bypass the gas when appropriate. Suitable expa nsion joints ar e also included.

Steam Turbine Generator and Auxiliaries The steam turbine consists of an HP section, an IP section, and one double-flow low pressure (LP) section, all connected to the generator by a common shaft. The HP and IP sections areCost and Performance Comparison of Fossil Energy Power Plants

81 

### contained in a single-span, opposed -flow casing, with the double-flow LP section in a separate casing. The LP turbine has a last st age bucket length of 76 cm (30 in). Main steam from the HRSG and gasifier island is combined in a header, and then passes through the stop valves and control valves and ente rs the turbine at either 12.4 MPa/566°C (1800 psig/1050°F) for the non-carbon capture cases, or 12.4 MPa/538°C (1800 psig/1000°F) for the carbon capture cases. The steam initially enters th e turbine near the middle of the high-pressure span, flows through the turbine, and returns to th e HRSG for reheating. The reheat steam flows through the reheat stop valves and intercept valv es and enters the IP section at 2.6 to 2.9 MPa/566°C (375 to 420 psig/1050°F) for the non -carbon capture cases or 2.6 to 2.9 MPa/538°C (375 to 420 psig/1000°F) for the carbon capture cas es. After passing thro ugh the IP section, the steam enters a crossover pipe, wh ich transports the steam to the LP section. The steam divides into two paths and flows thr ough the LP sections, exhausting downward into the condenser. Turbine bearings are lubricated by a closed-loop, water-cooled, pressurized oil system. The oil is contained in a reservoir located below the turbine floor. During st artup or unit trip an emergency oil pump mounted on the reservoir pumps the oil. When the turbine reaches 95 percent of synchronous speed, the main pump mounted on the turbine shaft pumps oil. The oil flows through water-cooled heat exchangers prior to entering th e bearings. The oil then flows through the bearings and returns by gr avity to the lube oil reservoir. Turbine shafts are sealed against air in-leak age or steam blowout using a modern positive pressure variable clearance shaf t sealing design arrangement conn ected to a low-pressure steam seal system. During startup, seal steam is pr ovided from the main steam line. As the unit increases load, HP turbine gland leakage provide s the seal steam. Pre ssure-regulating valves control the gland header pressure and dump any excess steam to the condenser. A steam packing exhauster maintains a vacuum at the outer gla nd seals to prevent leak age of steam into the turbine room. Any steam collected is condensed in the packing exhauster and returned to the condensate system. The generator is a hydrogen-c ooled synchronous type, generati ng power at 24 kV. A static, transformer type exciter is provi ded. The generator is cooled w ith a hydrogen gas recirculation system using fans mounted on the generator roto r shaft. The heat absorbed by the gas is removed as it passes over finned t ube gas coolers mounted in the st ator frame. Gas is prevented from escaping at the rotor shafts by a closed-loop o il seal system. The oil se al system consists of storage tank, pumps, filters, and pressure controls, all skid-mounted. The steam turbine generator is controlled by a triple-redundant, microprocessor-based electrohydraulic control system. The system provides di gital control of the unit in accordance with programmed control algorithms, color CRT operato r interfacing, and datalink interfaces to the balance-of-plant DCS, and incor porates on-line repair capability.
Condensate System The condensate system transfers condensate from the condenser hotwell to the deaerator, through the gland steam condenser, gasifi er, and the low-temperature econom izer section in the HRSG. The system consists of one main condenser; two 50 percent capacity, motor-driven, vertical condensate pumps; one gland steam condenser; a nd a low-temperature tube bundle in the HRSG. Condensate is delivered to a common discharge h eader through separate pump discharge lines, each with a check valve and a gate valve. A common minimum flow recirculation lineCost and Performance Comparison of Fossil Energy Power Plants

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### discharging to the condenser is provided to main tain minimum flow requirements for the gland steam condenser and the condensate pumps.
Feedwater System The function of the feedwater system is to pump the various feedwa ter streams from the deaerator storage tank in the HRSG to the re spective steam drums. Two 50 percent capacity boiler feed pumps are provided for each of three pressure levels, HP, IP, and LP. Each pump is provided with inlet and outlet isolation valv es, and outlet check valve. Minimum flow recirculation to prevent overhea ting and cavitation of the pumps during startup and low loads is provided by an automatic recirculation valve and a ssociated piping that discharges back to the deaerator storage tank. Pneumatic flow control valves contro l the recirculation flow. The feedwater pumps are supplied with instru mentation to monitor and alarm on low oil pressure, or high bearing temperature. Feedwa ter pump suction pressu re and temperature are also monitored. In addition, the suction of each boiler feed pump 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 synthesis gas cooler (SGC) and HRSG from the HRSG superheat er outlet to the HP turbine stop valves. The function of the reheat system is to convey st eam from the HP turbine exhaust to the HRSG reheater, and to the turb ine reheat stop valves. Main steam at approximately 12.4 MPa/566°C (1800 psig/1050°F) (non-carbon capture cases) or 12.4 MPa/538°C (1800 psig/1000°F) (carbon capture cases) exits the HRSG superheater through a motor-operated stop/check valve and a motor-opera ted gate valve, and is routed to the HP turbine. Cold reheat steam at approximately 3.1 to 3.4 MPa/341°C (450 to 500 psia/645°F) exits the HP turbine, flows through a motor-operated isol ation gate valve, to the HRSG reheater. Hot reheat steam at approximatel y 2.9 to 3.2 MPa/566°C (420 to 467 psia/1050°F) for non-carbon capture cases and 2.9 MPa/538°C (420 psia/1000° F) for carbon capture cases exits the HRSG reheater through a motor-operated gate valv e and is routed to the IP turbines. Steam piping is sloped from the HRSG to the drip pots located near the steam turbine for removal of condensate from the steam lines. Conde nsate collected in the drip pots and in lowpoint drains is discharged to the condenser through the drain system. Steam flow is measured by means of flow nozzl es in the steam piping. The flow nozzles are located upstream of any branch c onnections on the main headers. Safety valves are installed to comply with a ppropriate codes and to ensure the safety of personnel and equipment.
Circulating Water System The circulating water system is a closed-cycle cooling water system that supplies cooling water to the condenser to condense the main turbine exhaust steam. The system also supplies cooling water to the AGR plant as required, and to the au xiliary cooling system. The auxiliary cooling system is a closed-loop process that utilizes a higher quality water to remove heat from compressor intercoolers, oil cooler s and other ancillary equipment a nd transfers that heat to theCost and Performance Comparison of Fossil Energy Power Plants

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### main circulating cooling water system in plate a nd frame heat exchangers. The heat transferred to the circulating water in the condenser and othe r applications is removed by a mechanical draft cooling tower. The system consists of two 50 percent capacity ve rtical circulating water pumps, a mechanical draft evaporative cooling tower, and carbon st eel cement-lined interconnecting piping. The pumps are single-stage vertical pum ps. The piping system is equipped with butterfly isolation valves and all required expansion joints. The cooling tower is a multi-cell wood frame counterflow mechanical draft cooling tower. The condenser is a single-pass, horizontal type with divided wate r boxes. There are two separate circulating water circuits in each box. One-half of the condenser can be removed from service for cleaning or for plugging tubes. This can be done during normal operation at reduced load. The condenser is equipped with an air extracti on system to evacuate the condenser steam space for removal of non-condensable gases during stea m turbine operation and to rapidly reduce the condenser pressure from atmosphe ric pressure before unit start up and admission of steam to the condenser.
Raw Water, Fire Protection, a nd 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 plan t boundary provide the necessary pressure. The fire protection system provi des water under pressure to the fire hydrants, hose stations, and fixed water suppression system within the buildin gs and structures. The system consists of pumps, underground and abovegroun d supply piping, distribution pi ping, hydrants, hose stations, spray systems, and deluge spray systems. On e 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 qual ity demineralized water for makeup to the HRSG cycle, for steam injection ahead of the water gas shift reactors in CO 2 

### capture cases, and for injection steam to the auxiliary boiler for control of NOx emissions, if required. The cycle makeup system consists of two 100 per cent trains, each with a full-capacity activated carbon filter, primary cation exchanger, primary an ion exchanger, mixed bed exchanger, recycle pump, and regeneration equipment. The equipmen t is skid-mounted and in cludes a control panel and associated piping, valv es, and instrumentation.

3.1.10 A CCESSORY 

### E LECTRIC 

### P LANT 

### The accessory electric plant consists of switchgear and control equipment, generator equipment, station service equipment, conduit and cable trays, and wire and cab le. It also includes the main power transformer, all required foundations, and standby equipment.

3.1.11 I NSTRUMENTATION AND 

### C ONTROL 

### An integrated plant-wide distri buted control system (DCS) is provided. The DCS is a redundant microprocessor-based, functionally distributed control system. Th e control room houses an array of multiple video monitor (CRT) and keyboard un its. The CRT/keyboard units are the primaryCost and Performance Comparison of Fossil Energy Power Plants

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### interface between the generating process and opera tions personnel. The DCS incorporates plant monitoring and control functions fo r all the major plant equipment. The DCS is designed to be operational and accessible 99.5 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 au tomation routines available. The exception to this, and an important facet of the control system for gasificat ion, is the critical controller system, which is a part of the license package from the gasifier su pplier 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 stoich iometric, temperatureand pressure-dependent reaction. The critical controller utilizes a redundant microprocessor executing calculations and dynamic controls at 10 0- to 200-millisecond intervals. The enhanced execution speeds as well as evolved predictive cont rols allow the critical controller to mitigate process upsets and maintain the reactor operation within a stable set of operating parameters.Cost and Performance Comparison of Fossil Energy Power Plants

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### 3.2 GENERAL ELECTRIC ENERGY IGCC CASES
This section contains an eval uation of plant designs for Cases 1 and 2, which are based on the GEE gasifier in the “radiant only” configuration. GEE offers three design configurations [ 47]:

• Quench: In this configuration, the hot syngas exiting the gasifier pa sses through a pool of water to quench the temperature to less th an 260°C (500°F) before entering the syngas scrubber. It is the simplest and lowest capital cost design, but also the least efficient.

• Radiant Only: In this configur ation, the hot syngas exiting the gasifier passes through a radiant syngas cooler where it is cooled from about 1316°C (2400°F) to 816°C (1500°F), then through a water quench where the syngas is further cooled to about 204°C (400°F) prior to entering the syngas scrubber. Rela tive to the quench conf iguration, the radiant only design offers increased output, higher e fficiency, improved reliability/availability, and results in the lowest cost of electricity. This confi guration was chosen by GEE and Bechtel for the design of their reference plant.

• Radiant-Convective: In this configuration, the hot syngas exiting the gasifier passes through a radiant syngas cooler where it is cooled from about 1316°C (2400°F) to 760°C (1400°F), then passes over a pool of water wher e particulate is removed but the syngas is not quenched, then through a convective syngas cooler where the synga s is further cooled to about 371°C (700°F) prior to entering additio nal heat exchangers or the scrubber. This configuration has the highest ove rall efficiency, but at the ex pense of highest capital cost and the lowest availability. This is the configuration used at Tampa Electric’s Polk Power Station. Note that the radiant only c onfiguration includes a water que nch and, based on functionality, would be more appropriately name d radiant-quench. The term radian t only is used to distinguish it from the radiant-convective configuration. Si nce radiant only is the terminology used by GEE, it will be used thr oughout this report.
The balance of Section 3.2 is organized as follows:

• Gasifier Background provides information on the development and status of the GEE gasification technology.

• Process and System Description provides an overview of the technology operation as applied to Case 1. The systems that are comm on to all gasifiers were covered in Section 3.1 and only features that are unique to Case 1 are discus sed further in this section.

• Key Assumptions is a summary of study and modeling assumptions re levant to Cases 1 and 2.

• Sparing Philosophy is provided for both Cases 1 and 2.

• Performance Results provides the main m odeling results from Case 1, including the performance summary, environmental performan ce, carbon balance, sulfur balance, water balance, mass and energy balance diagra ms and mass and energy balance tables.

• Equipment List provides an itemized list of major equipment for Case 1 with account codes that correspond to the cost acc ounts in the Cost Estimates section.

• Cost Estimates provides a summary of capital and operating costs for Case 1.Cost and Performance Comparison of Fossil Energy Power Plants

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### • Process and System Description, Perform ance Results, Equipment List and Cost Estimates are repeated for Case 2.

3.2.1 G ASIFIER 

### B ACKGROUND 

### Development and Current Status [ 48] – Initial development of the GEE gasification technology (formerly licensed by Texaco and th en ChevronTexaco) was conducted in the 1940s at Texaco’s Montebello, Califor nia laboratories. From 1946 to 1954 the Montebello pilot plant produced synthesis gas (hydrogen and carbon monoxi de) by partial oxidation of a variety of feedstocks, including natural gas, oil, asphalt, co al tar, and coal. From 1956 to 1958, coal was gasified in a 91 tonne/day (100 TPD) Texaco coal gasifier at the Olin Ma thieson Chemical Plant in Morgantown, West Virginia, fo r the production of ammonia. The oil price increases and supply disruptions of the 1970s renewed interest in the Texaco partial-oxidation process for gasi fication of coal or other solid opportunity fuels. Three 14 tonne/day (15 TPD) pilot plants at the Montebello laboratories have been used to test numerous coals. Two larger pilot plants were also built. The first gasified 150 tonne/day (165 TPD) of coal and was built to test synthesis gas genera tion by Rührchemie and Rührkohle at Oberhausen, Germany, and included a synthesis gas cooler. The second gasified 172 tonne/day (190 TPD) of coal using a quench-only gasifier cooler and was built to make hydrogen at an existing TVA ammonia plant at Muscle Shoals, Alabama. Th ese two large-scale pilot plants successfully operated for several years during the 1980s and tested a number of process variables and numerous coals. The first commercial Texaco coal gasificati on plant was built for Tennessee Eastman at Kingsport, Tennessee, and started up in 1983. To da te, 24 gasifiers have b een built in 12 plants for coal and petroleum coke. Several of the pl ants require a hydrogen- rich gas and therefore directly water quench the raw gas to add the water for shifting the CO to H 2 

### , and have no synthesis gas coolers. The Cool Water plant was the first commercial-s cale Texaco coal gasifi cation project for the electric utility industry. This facility gasified 907 tonne/d ay (1,000 TPD) (dry basis) of bituminous coal and generated 120 MW of electri city by IGCC operation. In addition, the plant was the first commercial-sized Texaco gasifier used with a synthesis gas c ooler. The Cool Water plant operated from 1984 to 1989 and was a succe ss in terms of operability, availability, and environmental performance. The Tampa Electric IGCC Clean Coal Technolog y Demonstration Project built on the Cool Water experience to demonstrate the use of the Texaco coal ga sification process in an IGCC plant. The plant utilizes approximately 2,268 tonn e/day (2,500 TPD) of coal in a single Texaco gasifier to generate a net of approximately 250 MW e 

### . The syngas is cooled in a hightemperature radiant heat exchanger, generati ng high-pressure steam, and further cooled in convective heat exchangers (the radiant-convectiv e configuration). The pa rticles in the cooled gas are removed in a water-based scrubber. Th e cleaned gas then enters a hydrolysis reactor where COS is converted to H 2 

### S. After additional cooling, the syngas is sent to a conventional AGR unit, where H 2 

### S is absorbed by reaction with an amine solvent. H 2 

### S is removed from the amine by steam stripping and sent to a sulfuric acid plant. The cl eaned gas is sent to a General Electric MS 7001FA combustion turbine.Cost and Performance Comparison of Fossil Energy Power Plants

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### The Delaware Clean Energy Project is a coke ga sification and combustion turbine repowering of an existing 130 MW coke-fired boiler cogeneration power plant at the Motiva oil refinery in Delaware City, Delaware. The Texaco coal ga sification process was modified to gasify 1,814 tonne/day (2,000 TPD) of this low- quality petroleum coke. The pl ant is designed to use all the fluid petroleum coke generate d at Motiva’s Delaware City Plant and produce a nominal 238,136 kg/h (525,000 lb/h) of 8.6 MPa (1250 psig) steam, and 120,656 kg/h (266,000 lb/h) of 1.2 MPa (175 psig) steam for export to the refinery and the use/sale of 120 MW of electrical power. Environmentally, these new facilities help satisfy tighter NO x 

### and SO 2 

### emission limitations at the Delaware City Plant. Gasifier Capacity – The largest GEE gasifier is the unit at Tampa Electric, which consists of the radiant-convective confi guration. The daily coal-handling ca pacity of this unit is 2,268 tonnes (2,500 tons) of bituminous coal. The dry gas production rate is 0.19 million Nm 3 

### /h (6.7 million scfh) with an energy content of about 1,897 milli on kJ/h (HHV) (1,800 million Btu/h). This size matches the F Class combustion turbines that are used at Tampa. Distinguishing Characteristics – A key advantage of the GEE coal gasification technology is the extensive operating experience at full commercial scale. Furthermore, Tampa Electric is an IGCC power generation facility, operated by conv entional electric utility staff, and is environmentally one of the cleanes t coal-fired power plants in th e world. The GEE gasifier also operates at the highest pressure of the three ga sifiers in this study, 5.6 MPa (815 psia) compared to 4.2 MPa (615 psia) for CoP and Shell. Entrained-flow gasifiers have fundamental environmental advantages over fluidized-bed and moving-bed gasifiers. They pr oduce no hydrocarbon liquids, and the only solid waste is an inert slag. The relatively high H 2 

### /CO ratio and CO 2 

### content of GEE gasification fuel gas helps achieve low nitrogen oxide (NO x 

### ) and CO emissions in even th e higher-temperature advanced combustion turbines. The key disadvantages of the GEE coal gasificati on technology are the limited refractory life, the relatively high oxygen requirements and high waste heat recovery duty (synthesis gas cooler design). As with the other en trained-flow slagging gasifier s, the GEE process has this disadvantage due to its high operating temperature. The disadvantage is magnified in the singlestage, slurry feed design. The quench design si gnificantly reduces the capital cost of syngas cooling, while innovative heat integration main tains good overall thermal efficiency although lower than the synthesis gas c ooler design. Another disadvanta ge of the GEE process is the limited ability to economically handle low-rank coals relative to moving-bed and fluidized-bed gasifiers or to entrained-flow ga sifiers with dry feed. For slur ry fed entrained gasifiers using low-rank coals, developers of tw o-stage slurry fed gasifiers clai m advantages over single-stage slurry fed. Important Coal Characteristics – The slurry feeding system and the recycle of process condensate water as the principal slurrying liqui d make low levels of ash and soluble salts desirable coal characteristics for use in the G EE coal gasification process. High ash levels increase the ratio of water-to-carbon in th e feed slurry, thereby increasing the oxygen requirements. The slurry feeding also favors the use of high-rank coals, such as bituminous coal, since their low inherent moisture content increase s the moisture-free solids content of the slurry and thereby reduces oxy gen requirements.Cost and Performance Comparison of Fossil Energy Power Plants

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### 3.2.2 P ROCESS 

### D ESCRIPTION 

### In this section the overall GEE gasification proces s is described. The system description follows the block flow diagram (BFD) in Exhibit 3-14 and stream numbers reference the same Exhibit. The tables in Exhibit 3-15 provide stream compositions, temperature, pressure, enthalpy and flow rates for the numbered streams in the BFD.
Coal Grinding and Slurry Preparation Coal receiving and handling is common to all cases and was covered in Section 3.1.1. The receiving and handling subsystem ends at the coal silo. Coal is then fed onto a conveyor by vibratory feeders located below each silo. The c onveyor feeds the coal to an inclined conveyor that delivers the coal to the rod mill feed hoppe r. The feed hopper provides a surge capacity of about two hours and contains two hopper outlets. Each hopper outlet discharges onto a weigh feeder, which in turn feeds a rod mill. Each rod mill is sized to process 55 percent of the coal feed requirements of the gasifier. The rod mill gr inds the coal and wets it with treated slurry water transferred from the slurry water tank by the slurry water pumps. The coal slurry is discharged through a trommel screen into the r od mill discharge tank, and then the slurry is pumped to the slurry storage tanks. The dry solids concentration of the final slurry is 63 percent. The Polk Power Station operates at a slurry concentration of 62- 68 percent using bituminous coal and CoP presented a paper showing the slurry con centration of Illinois No. 6 coal as 63 percent. [ 41, 49] The coal grinding system is equipped with a dust suppression system consisting of water sprays aided by a wetting agent. The degree of dust suppression required depends on local environmental regulations. All of the tanks are equipped with verti cal agitators to keep the coal slurry solids suspended. The equipment in the coal grinding and slurry pr eparation system is fabricated of materials appropriate for the abrasive environment presen t in the system. The tanks and agitators are rubber lined. The pumps are either rubber-lined or hardened metal to minimize erosion. Piping is fabricated of high-density polyethylene (HDPE).

Gasification This plant utilizes two gasificat ion trains to process a total of 5,331 tonnes/day (5,876 TPD) of Illinois No. 6 coal. Each of the 2 x 50 percen t gasifiers operates at maximum capacity. The largest operating GEE gasifier is the 2,268 tonne/day (2,500 TPD) unit at Polk Power Station. However, that unit operates at about 2.8 MPa (400 psia). The gasifier in this study, which operates at 5.6 MPa (815 psia), will be able to process more coal and maintain the same gas residence time. The slurry feed pump takes suction from the slurry run tank, and the discharg e is sent to the feed injector of the GEE gasifier (stream 6). Oxyge n from the ASU is vented during preparation for startup and is sent to the feed injector duri ng normal operation. The air separation plant supplies 4,560 tonnes/day (5,025 TPD) of 95 mole percent oxygen to the gasifiers (stream 5) and the Claus plant (stream 3). Carbon conversion in the gasifier is assumed to be 98 percent including a fines recycle stream. The gasifier vessel is a refract ory-lined, high-pressure combusti on chamber. The coal slurry feedstock and oxygen are fed through a fuel injector at the top of the gasifier vessel. The coalCost and Performance Comparison of Fossil Energy Power Plants

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### slurry and the oxygen react in the gasi fier at 5.6 MPa (815 psia) and 1,316°C (2,400 ° F) to produce syngas. The syngas consists primarily of hydrogen a nd carbon monoxide, with lesser amounts of water vapor and carbon dioxide, and small amounts of h ydrogen sulfide, carbonyl sulfide, methane, argon, and nitrogen. The heat in the gasifier liquefies coal ash. Hot syngas and molten solids from the reactor flow downward into a radian t heat exchanger where the syngas is cooled.
Raw Gas Cooling/Particulate Removal Syngas is cooled from 1,316°C (2,400°F) to 593°C (1,100°F) in the radiant synthesis gas cooler (SGC) (stream 8) and the molten slag solidifies in the process. The solids collect in the water sump at the bottom of the gasifier and are re moved periodically using a lock hopper system (stream 7). The waste heat from this cooling is used to generate high-pressure steam. Boiler feedwater in the tubes is saturated, and then st eam and water are separated in a steam drum. Approximately 528,118 kg/h (1,164,300 lb/h) of sa turated steam at 13.8 MPa (2,000 psia) is produced. This steam then forms part of the gene ral heat recovery system that provides steam to the steam turbine. The syngas exiting the radiant cool er is directed downwards by a dip tube into a water sump. Most of the entrained solids are separated from the syngas at the bottom of the dip tube as the syngas goes upwards through the water. The syng as exits the quench chamber saturated at a temperature of 210°C (410°F). The slag handling system removes solids from th e gasification process equipment. These solids consist of a small amount of unc onverted carbon and essentially a ll of the ash contained in the feed coal. These solids are in the form of gl ass, which fully encapsulates any metals. Solids collected in the water sump below the radiant synthesis gas cooler are removed by gravity and forced circulation of water from the lock hopper circulating pump. The fine solids not removed from the bottom of the quench water sump remain entrained in the water circulating through the quench chamber. In order to limit the amount of solids recycled to the quench chamber, a continuous blowdown stream is removed from the bottom of the syngas quench. The blowdown is sent to the vacuum flash drum in the black water flash section. The circulating quench water is pumped by circulating pumps to the quench gasifier.
Syngas Scrubber/Sour Water Stripper Syngas exiting the water quench passes to a syng as scrubber where a water wash is used to remove remaining chlorides and particulate. Th e syngas exits the scrubb er still saturated at 199°C (390°F) (stream 9). The sour water stripper removes NH 3 

### , SO 2 

### , and other impurities from the scrubber and other waste streams. The stripper consists of a sour drum that accumulates sour water from the gas scrubber and condensate from synthesis gas coolers. Sour water from the drum flows to the sour stripper, which consists of a pack ed column with a steam-heated re boiler. Sour gas is stripped from the liquid and sent to the sulfur recovery unit. Remaini ng water is sent to wastewater treatment.Cost and Performance Comparisonof Fossil Energy Power Plants90Exhibit 3-14 Case 1 ProcessFlow Diagram, GEE IGCC without CO2CaptureCost and Performance Comparisonof Fossil Energy Power Plants91Exhibit 3-15 Case 1 Stream Table, GEE IGCC without CO2Capture123456A7 8 9 10 11 12V-L Mole FractionAr 0.0094 0.0065 0.0360 0.0023 0.0320 0.0000 0.0000 0.0079 0.0067 0.0067 0.0092 0.0092CH40.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0010 0.0008 0.0008 0.0011 0.0011CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3442 0.2922 0.2922 0.3992 0.3992CO20.0003 0.0015 0.0000 0.0000 0.0000 0.0000 0.0000 0.1511 0.1276 0.1278 0.1780 0.1780COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0002 0.0000 0.0000 0.0000H20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3349 0.2849 0.2849 0.3935 0.3935H2O0.0104 0.0496 0.0000 0.0000 0.0000 1.0000 0.0000 0.1429 0.2726 0.2724 0.0012 0.0012H2S0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0061 0.0062 0.0069 0.0069N20.7722 0.8978 0.0140 0.9924 0.0180 0.0000 0.0000 0.0089 0.0076 0.0076 0.0103 0.0103NH30.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0017 0.0014 0.0014 0.0006 0.0006O20.2077 0.0445 0.9500 0.0053 0.9500 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000SO20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000V-L Flowrate (lbmol/hr)53,342 13,347 277 36,897 12,736 14,199 0 51,296 60,278 60,278 43,585 43,585V-L Flowrate (lb/hr) 1,539,150 371,000 8,942 1,035,410 409,853 255,589 0 1,046,880 1,206,760 1,206,760 904,411 904,411Solids Flowrate (lb/hr) 0 0 0 0 0 435,187 53,746 0 0 0 0 0Temperature (°F) 233 58 90 385 206 141 410 1100 390 390 107 107Pressure (psia) 190.1 16.4 125.0 460.0 980.0 1050.0 797.7 799.7 792.7 782.7 742.7 732.7Enthalpy (BTU/lb)B55.6 16.6 12.5 87.8 37.7 --- 1,710 535.5 400.3 400.3 27.4 27.4Density (lb/ft3)0.738 0.085 0.683 1.424 4.416 --- --- 0.975 1.740 1.718 2.534 2.500Molecular Weight 28.85 27.80 32.23 28.06 32.18 --- --- 20.41 20.02 20.02 20.75 20.75A - Solids flowrate includes dry coal; V-L flowrate includes slurry water and water from coalB - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparisonof Fossil Energy Power Plants92Exhibit 3-15 Case 1 Stream Table(continued)13 14 15 16 17 18 19 20 21 22 23V-L Mole FractionAr 0.0000 0.0000 0.0188 0.0097 0.0097 0.0059 0.0097 0.0094 0.0094 0.0091 0.0091CH40.0000 0.0000 0.0764 0.0012 0.0012 0.0169 0.0012 0.0000 0.0000 0.0000 0.0000CO 0.0000 0.0000 0.0003 0.4195 0.4195 0.0814 0.4195 0.0000 0.0000 0.0000 0.0000CO20.3803 0.0000 0.6066 0.1414 0.1414 0.5518 0.1414 0.0003 0.0003 0.0859 0.0859COS 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000H20.0000 0.0000 0.0126 0.4164 0.4164 0.0532 0.4164 0.0000 0.0000 0.0000 0.0000H2O0.0200 0.0000 0.0020 0.0009 0.0009 0.0000 0.0009 0.0104 0.0104 0.0668 0.0668H2S0.3576 0.0000 0.0103 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000N20.2106 0.0000 0.2728 0.0110 0.0110 0.2908 0.0110 0.7722 0.7722 0.7337 0.7337NH30.0313 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000O20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2077 0.2077 0.1045 0.1045SO20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000Total 1.0000 0 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000V-L Flowrate (lbmol/hr)863 0 860 40,704 40,704 3,978 40,704 242,899 9,914 297,284 297,284V-L Flowrate (lb/hr) 30,839 0 31,584 795,458 795,458 140,512 795,458 7,008,680 286,060 8,694,000 8,694,000Solids Flowrate (lb/hr) 0 12,235 0 0 0 0 0 0 0 0 0Temperature (°F) 120 358 100 112 460 151 380 59 811 1115 270Pressure (psia) 30.0 24.9 368.0 719.0 714.0 460.0 460.0 14.7 234.9 15.2 15.2Enthalpy (BTU/lb)B31.1 -99.5 16.1 30.3 162.2 27.1 131.2 13.5 200.0 327.2 103.2Density (lb/ft3)0.172 329.192 2.252 2.289 1.414 2.481 0.998 0.076 0.497 0.026 0.057Molecular Weight 35.73 256.53 36.74 19.54 19.54 35.33 19.54 28.85 28.85 29.24 29.24B - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparison of Fossil Energy Power Plants

93 

### COS Hydryolysis, Mercury Removal and Acid Gas Removal Syngas exiting the scrubber (stream 9) passe s through a COS hydrolysis reactor where about 99.5 percent of the COS is converted to CO 2 

### and H 2 

### S (Section 3.1.5). The gas exiting the COS reactor (stream 10) passes through a series of h eat exchangers and knockout drums to lower the syngas temperature to 39°C (103°F) and to separate entrained water. The cooled syngas (stream 11) then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.4). Cool, particulate-free synthesis ga s (stream 12) enters the Selexol absorber unit at approximately 5.1 MPa (733 psia) and 39°C (103°F). In this absorber, H 2 

### S is preferentially removed from the fuel gas stream along with smaller amounts of CO 2 

### , COS and other gases such as hydrogen. The rich solution leaving the bottom of the absorber is heated against the lean solvent returning from the regenerator before entering the H 2 

### S concentrator. A portion of the non-sulfur bearing absorbed gases is driven from the solvent in the H 2 

### S concentrator using N 2 

### from the ASU as the stripping medium. The temperature of the H 2 

### S concentrator overhead stream is reduced prior to entering the reabsorber wh ere a second stage of H 2 

### S absorption occurs. The rich solvent from the reabsorber is combined with the rich solvent from the absorber and sent to the stripper where it is regenerated through the in direct application of thermal energy via condensation of lowpressure steam in a reboiler. The stripper acid gas stream (stream 13), consisting of 36 percent H 2 

### S and 38 percent CO 2 

### (with the balance mostly N 2 

### ), is then sent to the Claus unit. The secondary sweet fuel gas stream from the r eabsorber is compressed to 3.2 MPa (460 psia) (stream 18) and combined with the primary sweet syngas after the expans ion turbine (stream 19).

Claus Unit Acid gas from the first-stage stri pper of the Selexol unit is routed to the Claus plant. The Claus plant partially oxidizes the H 2 

### S in the acid gas to elemental sulfur. About 5,550 kg/h (12,235 lb/h) of elemental sulfur (stream 14) are r ecovered from the fuel gas stream. This value represents an overall sulfur rec overy efficiency of 99.6 percent. Acid gas from the Selexol unit is preheated to 232°C (450°F). A portion of the acid gas along with all of the sour gas from the stripper and oxygen from the ASU are fed to the Claus furnace. In the furnace, H 2 

### S is catalytically oxidized to SO 2 

### at a furnace temperature greater than 1,343°C (2,450°F), which must be maintained in or der to thermally decompose all of the NH 3 

### present in the sour gas stream. Following the thermal stage and condensation of su lfur, two reheaters and two sulfur converters are used to obtain a per-pass H 2 

### S conversion of approximately 99.7 percent. The Claus Plant tail gas is hydrogenated and recycled back to the Se lexol process (stream 15). In the furnace waste heat boiler, 8,772 kg/h (19,340 lb/h) of 3.6 MPa (525 psia) steam are generated. This steam is used to satisfy all Claus process preheating a nd reheating requirements as well as to produce some steam for the medium-pressure steam h eader. The sulfur condensers produce 0.34 MPa (50 psig) steam for the low-pressure steam header.

Power Block Clean syngas exiting the Selexol absorber is re-h eated (stream 17) using HP boiler feedwater and then expanded to 3.2 MPa (460 psia) using an expansion turbine (stream 19). A second clean gas stream from the Selexol reabsorber is co mpressed and combined with stream 19. The combined syngas stream is further diluted with nitrogen from the ASU (stream 4) and enters theCost and Performance Comparison of Fossil Energy Power Plants

94 

### advanced F Class CT burner. The CT compressor provides combustion air to the burner and also 16 percent of the air requirements in the ASU (stream 21). The exhaust gas exits the CT at 602°C (1,115°F) (stream 22) and enters the HRSG where additional heat is recovered until the flue gas exits the HRSG at 132°C (270°F) (stream 23) and is discharged through the plant stack. The steam raised in the HRSG is used to pow er an advanced, commercially available steam turbine using a 12.4 MPa/566°C/566°C ( 1800 psig/1050°F/1050°F) steam cycle.
Air Separation Unit (ASU) The elevated pressure ASU was described in Section 3.1.2. In Case 1 the air separation unit (ASU) is designed to produce a nominal output of 4,560 tonnes/day (5,025 TPD) of 95 mole percent O 2 

### for use in the gasifier (str eam 5) and Claus plant (stream 3). The plant is designed with two production trains. The air compressor is powered by an el ectric motor. Approximately 11,270 tonnes/day (12,425 TPD) of nitrogen are also recovered, compressed, and used as dilution in the gas turbine combustor (stream 4). About 4.1 percent of the ga s turbine air is used to supply approximately 16 percent of the ASU air requirements (stream 21).

Balance of Plant Balance of plant items we re covered in Sections 3.1.9, 3.1.10 and 3.1.11.Cost and Performance Comparison of Fossil Energy Power Plants

95 

### 3.2.3 K EY 

### S YSTEM 

### A SSUMPTIONS 

### System assumptions for Cases 1 and 2, GEE IGCC with and without CO 2 

### capture, are presented in Exhibit 3-16.

Exhibit 3-16 GEE IGCC Plant Study Configuration Matrix

Case 1 2 Gasifier Pressure, MPa (psia) 5.6 (815) 5.6 (815)
O 2 

### :Coal Ratio, kg O 2 

### /kg dry coal 0.95 0.95 Carbon Conversion, % 98 98 Syngas HHV at SGC Outlet, kJ/Nm 3 

### (Btu/scf) 8,210 (226) 8,210 (226)
Steam Cycle, MPa/°C/°C (psig/ ° F/ ° F) 12.4/566/566 (1800/1050/1050) 12.4/538/538 (1800/1000/1000) Condenser Pressure, mm Hg (in Hg) 51 (2.0) 51 (2.0)

Combustion Turbine 2x Advanced F Class (232 MW output each) 2x Advanced F Class (232 MW output each) Gasifier Technology GEE Radiant Only GEE Radiant Only Oxidant 95 vol% Oxygen 95 vol% Oxygen Coal Illinois No. 6 Illinois No. 6 Coal Slurry Solids Conent, % 63 63 COS Hydrolysis Yes Occurs in SGS Sour Gas Shift No Yes
H 2 

### S Separation Selexol Selexol 1 st 

### Stage Sulfur Removal, % 99.6 99.6

Sulfur Recovery Claus Plant with Tail Gas Recycle to Selexol/

Elemental Sulfur Claus Plant with Tail Gas Recycle to Selexol/

Elemental Sulfur

Particulate Control Water Quench, Scrubber, and AGR Absorber Water Quench, Scrubber, and AGR Absorber Mercury Control Carbon Bed Carbon Bed

NOx Control MNQC (LNB) and N 2 

### Dilution MNQC (LNB) and N 2 

### Dilution
CO 2 

### Separation N/A Selexol 2 nd 

### Stage
CO 2 

### Capture N/A 90.2% from Syngas
CO 2 

### Sequestration N/A Off-site Saline FormationCost and Performance Comparison of Fossil Energy Power Plants

96 

### Balance of Plant – Cases 1 and 2 The balance of plant assumptions are co mmon to all cases and are presented in Exhibit 3-17.
Exhibit 3-17 Balance of Plant Assumptions Cooling system Recirculating Wet Cooling Tower Fuel and Other storage Coal 30 days Slag 30 days Sulfur 30 days Sorbent 30 days Plant Distribution Voltage Motors below 1 hp 110/220 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 and Gas Turbine Generators 24,000 volt Grid Interconnection Voltage 345 kV Water and Waste Water

Makeup Water The water supply is 50 percen t 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 equipm ent 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 wastew ater is recycled to the cooling tower basin. Blowdown is treated for chloride and metals, and discharged.Cost and Performance Comparison of Fossil Energy Power Plants

97 

### 3.2.4 S PARING 

### P HILOSOPHY 

### The sparing philosophy for Cases 1 and 2 is pr ovided 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. The plant design consists of the following major subsystems:

• Two air separation units (2 x 50%)

• Two trains of slurry preparation and slurry pumps (2 x 50%)

• Two trains of gasification, in cluding gasifier, sy nthesis gas cooler, quench and scrubber (2 x 50%).

• Two trains of syngas clean-up process (2 x 50%).

• Two trains of Selexol acid gas removal, single -stage in Case 1 and two-stage in Case 2, (2 x 50%) and one Claus-based sulfur recovery unit (1 x 100%).

• Two combustion turbine/HRSG tandems (2 x 50%).

• One steam turbine (1 x 100%).

3.2.5 C ASE 

### 1 P ERFORMANCE 

### R ESULTS 

### The plant produces a net output of 640 MWe at a net plant efficiency of 38.2 percent (HHV basis). GEE has reported a net plant effiency of 38.5 percent for their reference plant, and they also presented a range of efficiencies of 38.5-40 percent depending on fuel type. [ 50, 51] Typically the higher efficiencies result from fuel blends that include petroleum coke. Overall performance for the plant is summarized in Exhibit 3-18 which includes auxiliary power requirements. The ASU accounts for over 79 percent of the auxiliary load between the main air compressor, the nitrogen compressor, the oxygen co mpressor and ASU auxiliaries. The cooling water system, including the circulating water pumps and the cooling tower fan, accounts for over 4 percent of the auxilia ry load, and the BFW pumps account fo r an additional 3.5 percent. All other individual auxiliary loads are less than 3 percent of the total.Cost and Performance Comparison of Fossil Energy Power Plants

98 

### Exhibit 3-18 Case 1 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Gas Turbine Power 464,300 Sweet Gas Expander Power 7,130 Steam Turbine Power 298,920 TOTAL POWER, kWe 770,350 AUXILIARY LOAD SUMMARY, kWe Coal Handling 450 Coal Milling 2,280 Coal Slurry Pumps 740 Slag Handling and Dewatering 1,170 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 60,070 Oxygen Compressor 11,270 Nitrogen Compressor 30,560 Claus Plant Tail Gas Recycle Compressor 1,230 Boiler Feedwater Pumps 4,590 Condensate Pump 250 Flash Bottoms Pump 200 Circulating Water Pumps 3,710 Cooling Tower Fans 1,910 Scrubber Pumps 300 Selexol Unit Auxiliaries 3,420 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 200 Miscellaneous Balance of Plant (Note 1) 3,000 Transformer Loss 2,650 TOTAL AUXILIARIES, kWe 130,100 NET POWER, kWe 640,250 Net Plant Efficiency, % (HHV) 38.2 Net Plant Heat Rate (Btu/kWh) 8,922 CONDENSER COOLING DUTY 10 6 

### kJ/h (10 6 

### Btu/h) 1,705 (1,617) CONSUMABLES As-Received Coal Feed, kg/h (lb/h) 222,095 (489,634) Thermal Input, kWt 1,674,044 Raw Water Usage, m 3 

### /min (gpm) 15.2 (4,003) Note 1: Includes plant control systems, ligh ting, HVAC and miscellaneous low voltage loadsCost and Performance Comparison of Fossil Energy Power Plants

99 

### Environmental Performance The environmental targets for emissions of Hg, NOx, SO 2 

### and particulate matter were presented in Section 2.4. A summary of the plant ai r emissions for Case 1 is presented in Exhibit 3-19.

Exhibit 3-19 Case 1 Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) @ 80% capacity factor kg/MWh (lb/MWh)

SO 2 

### 0.005 (0.0127) 231 (254) 0.043 (0.094) NO X 

### 0.024 (0.055) 994 (1,096) 0.184 (0.406) Particulates 0.003 (0.0071) 129 (142) 0.024 (0.053)
Hg 0.25x10 -6 

### (.57x10 -6 

### ) 0.010 (0.011) 1.9x10 -6 

### (4.2x10 -6 

### )

CO 2 

### 85 (197) 3,572,000 (3,938,000) 662 (1,459)

CO 2 1 

### 796 (1,755)
1 

### CO 2 

### emissions based on net power instead of gross power

The low level of SO 2 

### emissions is achieved by capture of the sulfur in the gas by the Selexol AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel gas down to a level of less than 30 ppmv. This re sults in a concentration in the flue gas of less than 4 ppmv. The H 2 

### S-rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Cl aus plant tail gas is hydrogenated to convert all sulfur species to H 2 

### S and then recycled back to the Selexol proce ss, thereby eliminating the need for a tail gas treatment unit.
NO X 

### emissions are limited by nitrogen d ilution of the syngas to 15 ppmvd (as NO 2 

### @15 percent O 2 

### ). Ammonia in the syngas is removed with pr ocess condensate prior to the low-temperature AGR process and ultimately destroyed in th e Claus plant burner. This helps lower NO X 

### levels as well. Particulate discharge to the atmosphere is lim ited to extremely low values by the use of the syngas quench in addition to the syngas scr ubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only. Ninety five percent of the mercury is capture d from the syngas by an activated carbon bed. CO 2 

### emissions represent the uncontro lled discharge from the process. The carbon balance for the plant is shown in Exhibit 3-20. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in th e air is not neglected here since the AspenPlus model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, as dissolved CO 2 

### in the wastewater blowdown stream, and as CO 2 

### in the stack gas and ASU vent ga s. Carbon in the wastewater bl owdown stream is calculated by difference to close the material balance.Cost and Performance Comparison of Fossil Energy Power Plants

100 

### Exhibit 3-20 Case 1 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) Coal 141,585 (312,142) Slag 2,843 (6,267) Air (CO 2 

### ) 529 (1,165) Stack Gas 139,020 (306,486) ASU Vent 111 (245) Wastewater 141 (310) Total 142,114 (313,307) Total 142,114 (313,307)

Exhibit 3-21 shows the sulfur balances for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output incl udes the sulfur recovered in the Claus plant, dissolved SO 2 

### in the wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible, and the sulfur content of the blowdown stream is calculated by difference to close the material balance. The to tal sulfur capture is re presented by the following fraction: (Sulfur byproduct/Sulfur in the coal) or (12,235/12,290) or 99.6 percent

Exhibit 3-21 Case 1 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) Coal 5,575 (12,290) Elemental Sulfur 5,550 (12,235) Stack Gas 16 (36) Wastewater 8 (19) Total 5,575 (12,290) Total 5,575 (12,290)

Exhibit 3-22 shows the overall water balance for the plant. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the total amount of water required for a particular process. Some water is recovered within the process, primarily as syngas condens ate, and that water is re-used as internal recycle. Raw water makeup is the difference between wate r demand and internal recycle.Cost and Performance Comparison of Fossil Energy Power Plants

101 

### Exhibit 3-22 Case 1 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle,

m 3 

### /min (gpm) Raw Water Makeup,

m 3 

### /min (gpm)
Slurry 1.5 (402) 1.5 (402) 0
Slag Handling 0.5 (140) 0 0.5 (140)
Quench/Scrubber 2.1 (561) 1.6 (427) 0. 5 ( 134 )
BFW Makeup 0.2 (49) 0 0.2 (49)
Cooling Tower Makeup 14.4 (3,805) 0.5 (125) 13.9 (3,680)

Total 18.7 (4,957) 3.6 (954) 15.2 (4,0 03 )

Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-23 through Exhibit 3-27:

• Coal gasification and air separation unit

• Syngas cleanup

• Sulfur recovery and tail gas recycle

• Combined cycle power generation

• Steam and feedwater An overall plant energy balance is provided in tabular form in Exhibit 3-28. The power out is the combined combustion turbine, steam turbine and expander power prior to generator losses. The power at the generator terminals (shown in Exhibit 3-18) is calculated by multiplying the power out by a combined genera tor efficiency of 98.2 percent.
The heat and material balances shown in these figures are shown in U.S. standard units. The following factors can be used for conversion to SI units. The same conversions apply to all cases but are shown only once for Case 1. P, absolute pressure, psia, multiply by 6.895 x10 -3 

### = MPa (megapascals)

° F, temperature, ( ° F minus 32) divided by 1.8 = ° C (Centigrade) H, enthalpy, Btu/lb, multiply H by 2.3260 = kJ/kg (kilojoules/kilogram) W, total plant flow, lb/h, multiply W by 0.4536 = kg/h (kilogram/hour) Heat rate, Btu/kWh, multiply Btu/kWh by 1.0551 = kJ/kWh (kilojoules/kilowatt-hour)Cost and Performance Comparison of Fossil Energy Power Plants

102 

### This page intentionally left blankCost and Performance Comparisonof Fossil Energy Power Plants103Exhibit 3-23 Case 1 Coal Gasification and AirSeparation Units Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants104Exhibit 3-24 Case 1 Syngas Cleanup Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants105Exhibit 3-25 Case 1 Sulfur Recovery and Tail Gas Recycle Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants106Exhibit 3-26 Case 1 Combined-Cycle PowerGeneration Heat andMass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants107Exhibit 3-27 Case 1 Steam and Feedwater Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants108This page intentionally left blankCost and Performance Comparison of Fossil Energy Power Plants



### 109 Exhibit 3-28 Case 1 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total
Heat In (MMBtu/hr) Coal 5,712.1 4.8 5,716.8 ASU Air 20.8 20.8 CT Air 94.6 94.6 Water 2.9 2.9 Auxiliary Power 444.0 444.0 Totals 5,712.1 123.1 444.0 6,279.2 Heat Out (MMBtu/hr) ASU Intercoolers 228.0 228.0 ASU Vent 6.1 6.1 Slag 88.3 3.6 91.9 Sulfur 48.7 (1.2) 47.5 Tail Gas Compressor Intercoolers 4.4 4.4
HRSG Flue Gas 896.8 896.8 Condenser 1,617.0 1,617.0 Process Losses (1) 710.8 710.8 Power 2,676.7 2,676.7 Totals 137.0 3,465.5 2,676.7 6,279.2 (1) Process Losses are calculated by differen ce and reflect various gasification, turbine, HRSG and other heat and work losses. Aspe n flowsheet balance is within 0.5 percent.Cost and Performance Comparison of Fossil Energy Power Plants



### 110 3.2.6 C ASE 

### 1

- M AJOR 

### E QUIPMENT 

### L IST 

### Major equipment items for the GEE gasifier with no CO 2 

### capture are shown in the following tables. The accounts used in the equipment lis t correspond to the account numbers used in the cost estimates in Section 3.2.7. In general, the design c onditions include a 10 percent contingency for flows and heat duties and a 21 pe rcent contingency for heads on pumps and fans.
ACCOUNT 1 COAL HANDLING

Equipment No. Description Type Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0
3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0
5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0
8 Reclaim Hopper N/A 2 1
9 Feeder Vibratory 2 1
10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0

12 Coal Surge Bin w/ Vent Filte r Dual outlet 2 0

13 Crusher Impactor reduction 2 0

14 As-Fired Coal Sampling System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0

17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 3 0 N/A

363 tonne/h (400 tph)

816 tonne (900 ton)

45 tonne (50 ton)
181 tonne/h (200 tph)

8 cm x 0 - 3 cm x 0 (3" x 0 - 1-1/4" x 0) 363 tonne/h (400 tph)

181 tonne (200 ton) N/A

N/A

363 tonne/h (400 tph)

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph) N/A
1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)
1,134 tonne/h (1,250 tph)Cost and Performance Comparison of Fossil Energy Power Plants



### 111 ACCOUNT 2 COAL PREPARATION AND FEED
Equipment No. Description Type Operating Qty. Spares

1 Feeder Gravimetric 3 0
2 Conveyor No. 6 Belt w/tripper 1 0
3 Rod Mill Feed Hopper Dual Outlet 1 0
4 Weigh Feeder Belt 2 0
5 Rod Mill Rotary 2 0

6 Slurry Water Storage Tank with Agitator Field erected 2 0

7 Slurry Water Pumps Centrifugal 2 2

10 Trommel Screen Coarse 2 0

11 Rod Mill Discharge Tank with Agitator Field erected 2 0

12 Rod Mill Product Pumps Centrifugal 2 2

13 Slurry Storage Tank with Agitator Field erected 2 0

14 Slurry Recycle Pumps Centrifugal 2 2

15 Slurry Product Pumps Positive displacement 2 2 172 tonne/h (190 tph)

2,650 lpm (700 gpm) 5,337 lpm (1,410 gpm) 946,361 liters (250,000 gal) 118 tonne/h (130 tph)

320,248 liters (84,600 gal)

2,650 lpm (700 gpm)

833 lpm (220 gpm) 118 tonne/h (130 tph)

302,835 liters (80,000 gal) Design Condition

82 tonne/h (90 tph)
245 tonne/h (270 tph)
490 tonne (540 ton)Cost and Performance Comparison of Fossil Energy Power Plants



### 112 ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 2 0

2 Condensate Pumps Vertical canned 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multistage, centrifugal 2 1

7 Auxiliary Boiler Shop fabricated, water tube 1 0

8 Service Air Compressors Flooded Screw 2 1

9 Instrument Air Dryers Duplex, regenerative 2 1

10 Closed Cycle Cooling Heat Exchangers Plate and frame 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 2 1

12 Engine-Driven Fire Pump Vertical turbine, diesel engine 1 1

13 Fire Service Booster Pump Two-stage horizontal centrifugal 1 1

14 Raw Water Pumps Stainless steel, single suction 2 1

15 Filtered Water Pumps Stainless steel, single suction 2 1

16 Filtered Water Tank Vertical, cylindrical 2 0

17 Makeup Water Demineralizer Anion, cation, and mixed bed 2 0

18 Liquid Waste Treatment System 1 0 1,931 lpm @ 283 m H2O (510 gpm @ 930 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C (40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) Design Condition

745,732 liters (197,000 gal)

7,079 lpm @ 110 m H2O (1,870 gpm @ 360 ft H2O)

514,828 kg/h (1,135,000 lb/h)

IP water: 1,893 lpm @ 223 m H2O (500 gpm @ 730 ft H2O) HP water: 6,890 lpm @ 1,890 m

H2O (1,820 gpm @ 6,200 ft H2O)

2,498 lpm @ 49 m H2O (660 gpm @ 160 ft H2O) 28 m3/min (1,000 scfm)

58 MMkJ/h (55 MMBtu/h) each
20,820 lpm @ 21 m H2O (5,500 gpm @ 70 ft H2O) 3,785 lpm @ 88 m H2O (1,000 gpm @ 290 ft H2O)

2,650 lpm @ 64 m H2O (700 gpm @ 210 ft H2O) 8,593 lpm @ 18 m H2O (2,270 gpm @ 60 ft H2O)

1,211,341 liter (320,000 gal)

189 lpm (50 gpm)

10 years, 24-hour storm 2 1 5 High Pressure Feedwater Pump No. 1 Barrel type, multistage, centrifugalCost and Performance Comparison of Fossil Energy Power Plants



### 113 ACCOUNT 4 GASIFIER, ASU AND ACC ESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY
Equipment No. Description Type Operating Qty. Spares

1 Gasifier Pressurized slurry-feed, entrained bed 2 0

2 Synthesis Gas Cooler Vertical downflow radiant heat exchanger with outlet quench chamber 2 0

3 Syngas Scrubber Including Sour Water Stripper Vertical upflow 2 0

4 Raw Gas Coolers Shell and tube with condensate drain 6 0

5 Raw Gas Knockout Drum Vertical with mist eliminator 2 0

6 Flare Stack Self-supporting, carbon steel, stainless steel top, pilot ignition 2 0

7 ASU Main Air Compressor Centrifugal, multistage 2 0

8 Cold Box Vendor design 2 0

9 Oxygen Compressor Centrifugal, multistage 2 0

10 Nitrogen Compressor Centrifugal, multistage 2 0

11 Nitrogen Boost Compressor Centrifugal, multistage 2 0

12 Extraction Air Heat Exchanger Gas-to-gas, vendor design 2 0 566 m3/min @ 2.3 MPa (20,000 scfm @ 340 psia) 71,214 kg/h, 433°C, 1.6 MPa (157,000 lb/h, 811°F, 235 psia)

330,216 kg/h (728,000 lb/h)
syngas
5,267 m3/min @ 1.3 MPa (186,000 scfm @ 190 psia)
2,540 tonne/day (2,800 tpd) of 95% purity oxygen
1,246 m3/min @ 7.1 MPa (44,000 scfm @ 1,030 psia) 3,058 m3/min @ 3.4 MPa (108,000 scfm @ 490 psia) Design Condition

2,903 tonne/day, 5.6 MPa (3,200 tpd, 815 psia)

274,424 kg/h (605,000 lb/h)

330,216 kg/h (728,000 lb/h)

301,186 kg/h (664,000 lb/h)

218,178 kg/h, 39°C, 5.2 MPa (481,000 lb/h, 103°F, 753 psia)Cost and Performance Comparison of Fossil Energy Power Plants



### 114 ACCOUNT 5A SYNGAS CLEANUP
Equipment No. Description Type Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon bed 2 0

2 Sulfur Plant Claus type 1 0

3 COS Hydrolysis Reactor Fixed bed, catalytic 2 0

4 Acid Gas Removal Plant Selexol 2 0

5 Hydrogenation Reactor Fixed bed, catalytic 1 0

6 Tail Gas Recycle Compressor Centrifugal 1 1 183 m3/min @ 3.0 MPa (6,480 scfm @ 430 psia) 225,436 kg/h (497,000 lb/h) 42°C (107°F) 5.1 MPa (733 psia)

19,504 kg/h (43,000 lb/h) 232°C (450°F) 0.2 MPa (25 psia) Design Condition

225,436 kg/h (497,000 lb/h) 42°C (107°F) 5.1 MPa (743 psia)

147 tonne/day (162 tpd)

301,186 kg/h (664,000 lb/h) 199°C (390°F) 5.5 MPa (793 psia)



### ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES
Equipment No. Description Type Operating Qty. Spares

1 Gas Turbine Advanced F class 2 0

2 Gas Turbine Generator TEWAC 2 0

3 Sweet Syngas Expansion Turbine/Generator Turbo expander 2 0 Design Condition

232 MW

260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase
198,447 kg/h (437,500 lb/h) Delta P: 2.1 MPa (310 psi)

Power output: 3,980 kW



### ACCOUNT 7 HRSG, DUCTING, AND STACK

Equipment No. Description Type Operating Qty. Spares

1 Stack CS plate, type 409SS liner 1 0 Design Condition

76 m (250 ft) high x 8.3 m (27 ft) diameter

Main steam - 388,803 kg/h, 12.4 MPa/566°C (857,162 lb/h, 1,800 psig/1,050°F) 2 0 2 Heat Recovery Steam Generator Drum, multi-pressure with economizer section and integral deaerator Reheat steam - 382,124 kg/h, 2.9 MPa/566°C (842,437 lb/h, 420 psig/1,050°F)Cost and Performance Comparison of Fossil Energy Power Plants



### 115 ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitiation 1 0

3 Steam Bypass One per HRSG 2 0

4 Surface Condenser Single pass, divided waterbox including
vacuum pumps 1 0 315 MW 12.4 MPa/566°C/566°C (1800 psig/ 1050°F/1050°F)

1,876 MMkJ/h (1,780 MMBtu/h) heat duty, Inlet

water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 350 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase

50% steam flow @ design steam conditions Design Condition



### ACCOUNT 9 COOLING WATER SYSTEM
Equipment No. Description Type Operatin g Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 1 0 Design Condition
370,973 lpm @ 30 m (98,000 gpm @ 100 ft)
11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT 2,066 MMkJ/h (1,960 MMBtu/h) heat loadCost and Performance Comparison of Fossil Energy Power Plants



### 116 ACCOUNT 10 SLAG RECOVERY AND HANDLING
Equipment No. Description Type Operating Qty. Spares

1 Slag Quench Tank Water bath 2 0
2 Slag Crusher Roll 2 0
3 Slag Depressurizer Lock Hopper 2 0
4 Slag Receiving Tank Horizontal, weir 2 0
5 Black Water Overflow Tank Shop fabricated 2 0
6 Slag Conveyor Drag chain 2 0
7 Slag Separation Screen Vibrating 2 0
8 Coarse Slag Conveyor Belt/bucket 2 0
9 Fine Ash Settling Tank Vertical, gravity 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 2 2

11 Grey Water Storage Tank Field erected 2 0

12 Grey Water Pumps Centrifugal 2 2

13 Slag Storage Bin Vertical, field erected 2 0

14 Unloading Equipment Telescoping chute 1 0 249,839 liters (66,000 gal)

76 lpm @ 14 m H2O (20 gpm @ 46 ft H2O)

998 tonne (1,100 tons)

109 tonne/h (120 tph) 79,494 liters (21,000 gal)

303 lpm @ 564 m H2O (80 gpm @ 1,850 ft H2O) 166,559 liters (44,000 gal)

14 tonne/h (15 tph)
14 tonne/h (15 tph)
14 tonne/h (15 tph) 79,494 liters (21,000 gal) Design Condition

257,410 liters (68,000 gal)
14 tonne/h (15 tph)
14 tonne/h (15 tph)Cost and Performance Comparison of Fossil Energy Power Plants



### 117 ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type Operating Qty. Spares

1 CTG Transformer Oil-filled 2 0

3 Auxiliary Transformer Oil-filled 1 1

4 Low Voltage Transformer Dry ventilated 1 1

5 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 2 0

6 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 1 0

7 Medium Voltage Switchgear Metal clad 1 1

8 Low Voltage Switchgear Metal enclosed 1 1

9 Emergency Diesel Generator Sized for emergency shutdown 1 0 Design Condition

24 kV/345 kV, 260 MVA, 3-ph, 60 Hz

2 STG Transformer Oil-filled 24 kV/345 kV, 200 MVA, 3-ph, 60 Hz 1 0

24 kV/4.16 kV, 142 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 21 MVA, 3-ph, 60 Hz

750 kW, 480 V, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz



### ACCOUNT 12 INSTRUMENTATION AND CONTROLS

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) 1 0

3 DCS - Data Highway Fiber optic 1 0 Design Condition

Operator stations/printers and engineering stations/printers

2 DCS - Processor Microprocessor with redundant input/output N/A 1 0

Fully redundant, 25% spareCost and Performance Comparison of Fossil Energy Power Plants



### 118 3.2.7 C ASE 

### 1

- C OST 

### E STIMATING 

### The cost estimating methodology was desc ribed previously in Section 2.6. Exhibit 3-29 shows the total plant capital cost summary organized by cost account and Exhibit 3-30 shows a more detailed breakdown of the capital costs. Exhibit 3-31 shows the ini tial and annual O&M costs. The estimated TPC of the GEE gasifier with no CO 2 

### capture is $1,813/kW. Process contingency represents 2.5 percent of the TP C and project contingency repres ents 13.3 percent. The 20-year LCOE is 78.0 mills/kWhCost and Performance Comparisonof Fossil Energy Power Plants119Exhibit 3-29 Case 1 Total Plant Cost SummaryClient:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 01 - GEE Radiant Only IGCC w/o CO2Plant Size:640.3 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING $13,505 $2,518 $10,582 $0 $0$26,606$2,410 $0 $5,803$34,819$542 COAL & SORBENT PREP & FEED $23,112 $4,213 $13,999 $0 $0$41,324$3,748 $1,500 $9,315$55,887$873 FEEDWATER & MISC. BOP SYSTEMS $9,975 $8,740 $9,353 $0 $0$28,067$2,620 $0 $6,893$37,580$594 GASIFIER & ACCESSORIES4.1 Syngas Cooler Gasifier System $101,906 $0 $56,569 $0 $0$158,475$14,508 $21,881 $29,920$224,784$3514.2 Syngas Cooler(w/ Gasifier - 4.1 ) w/4.1 $0 w/4.1 $0 $0$0$0 $0 $0$0$04.3 ASU/Oxidant Compression $152,787 $0 w/equip. $0 $0$152,787$14,542 $0 $16,733$184,063$2874.4-4.9 Other Gasification Equipment $12,116 $11,603 $12,827 $0 $0$36,546$3,471 $0 $8,277$48,294$75SUBTOTAL 4 $266,809 $11,603 $69,396 $0 $0 $347,808 $32,521 $21,881 $54,930 $457,140 $7145A Gas Cleanup & Piping $46,447 $4,978 $47,184 $0 $0$98,610$9,456 $89 $21,825$129,980$2035BCO2REMOVAL & COMPRESSION$0 $0 $0 $0 $0$0$0 $0 $0$0$06 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator $82,000 $0 $5,071 $0 $0$87,072$8,192 $4,354 $9,962$109,578$1716.2-6.9 Combustion Turbine Other $5,440 $752 $1,598 $0 $0$7,791$733 $0 $1,539$10,063$16SUBTOTAL 6 $87,441 $752 $6,670 $0 $0 $94,862 $8,925 $4,354 $11,501 $119,642 $1877 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator $34,012 $0 $4,840 $0 $0$38,851$3,667 $0 $4,252$46,771$737.2-7.9 Ductwork and Stack $3,127 $2,201 $2,922 $0 $0$8,249$762 $0 $1,465$10,476$16SUBTOTAL 7 $37,138 $2,201 $7,761 $0 $0 $47,101 $4,429 $0 $5,717 $57,247 $898 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $29,570 $0 $5,065 $0 $0$34,635$3,319 $0 $3,795$41,750$658.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,895 $1,003 $7,554 $0 $0$19,452$1,756 $0 $4,243$25,451$40SUBTOTAL 8 $40,465 $1,003 $12,619 $0 $0 $54,087 $5,075 $0 $8,039 $67,201 $1059 COOLING WATER SYSTEM $7,199 $7,656 $6,445 $0 $0$21,301$1,957 $0 $4,774$28,032$4410 ASH/SPENT SORBENT HANDLING SYS $14,077 $7,868 $14,278 $0 $0$36,223$3,463 $0 $4,274$43,960$6911 ACCESSORY ELECTRIC PLANT $23,161 $10,196 $20,591 $0 $0$53,947$4,678 $0 $11,201$69,826$10912 INSTRUMENTATION & CONTROL $9,437 $1,767 $6,335 $0 $0$17,538$1,616 $877 $3,351$23,382$3713 IMPROVEMENTS TO SITE $3,211 $1,892 $7,981 $0 $0$13,084$1,285 $0 $4,311$18,681$2914 BUILDINGS & STRUCTURES $0 $6,373 $7,450 $0 $0$13,823$1,257 $0 $2,462$17,541$27TOTAL COST $581,977 $71,760 $240,644 $0 $0 $894,382 $83,439 $28,701 $154,397 $1,160,919 $1,813TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants120Exhibit 3-30 Case 1 Total Plant Cost DetailsClient:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 01 - GEE Radiant Only IGCC w/o CO2Plant Size:640.3 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING1.1 Coal Receive & Unload $3,547 $0 $1,751 $0 $0 $5,298 $474 $0 $1,154 $6,926 $111.2 Coal Stackout & Reclaim $4,583 $0 $1,123 $0 $0 $5,706 $500 $0 $1,241 $7,447 $121.3 Coal Conveyors $4,261 $0 $1,111 $0 $0 $5,372 $472 $0 $1,169 $7,012 $111.4 Other Coal Handling $1,115 $0 $257 $0 $0 $1,372 $120 $0 $298 $1,790 $31.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.9 Coal & Sorbent Hnd.Foundations $0 $2,518 $6,341 $0 $0 $8,859 $844 $0 $1,941 $11,643 $18SUBTOTAL 1. $13,505 $2,518 $10,582 $0 $0 $26,606 $2,410 $0 $5,803 $34,819 $542 COAL & SORBENT PREP & FEED2.1 Coal Crushing & Drying incl w/2.3 incl. w/ 2.3 incl. w/ 2.3 incl. w/ 2.3 $0 $0 $0 $0 $0 $0 $0 $02.2 Prepared Coal Storage & Feed $1,515 $361 $240 $0 $0 $2,116 $181 $0 $459 $2,757 $42.3 Slurry Prep & Feed $20,764 $0 $9,236 $0 $0 $30,000 $2,719 $1,500 $6,844 $41,063 $642.4 Misc.Coal Prep & Feed $833 $603 $1,837 $0 $0 $3,273 $300 $0 $715 $4,288 $72.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.9 Coal & Sorbent Feed Foundation $0 $3,249 $2,686 $0 $0 $5,936 $548 $0 $1,297 $7,780 $12SUBTOTAL 2. $23,112 $4,213 $13,999 $0 $0 $41,324 $3,748 $1,500 $9,315 $55,887 $873 FEEDWATER & MISC. BOP SYSTEMS3.1 FeedwaterSystem $3,484 $6,058 $3,201 $0 $0 $12,743 $1,176 $0 $2,784 $16,703 $263.2 Water Makeup & Pretreating $532 $55 $297 $0 $0 $884 $83 $0 $290 $1,258 $23.3 Other Feedwater Subsystems $1,924 $652 $587 $0 $0 $3,164 $283 $0 $689 $4,136 $63.4 Service Water Systems $306 $625 $2,172 $0 $0 $3,104 $300 $0 $1,021 $4,426 $73.5 Other Boiler Plant Systems $1,646 $632 $1,567 $0 $0 $3,845 $360 $0 $841 $5,046 $83.6 FO Supply Sys & Nat Gas $306 $577 $539 $0 $0 $1,421 $136 $0 $311 $1,868 $33.7 Waste Treatment Equipment $739 $0 $453 $0 $0 $1,192 $116 $0 $392 $1,700 $33.8 Misc. Equip.(cranes,AirComp.,Comm.) $1,038 $139 $537 $0 $0 $1,715 $165 $0 $564 $2,444 $4SUBTOTAL 3. $9,975 $8,740 $9,353 $0 $0 $28,067 $2,620 $0 $6,893 $37,580 $594 GASIFIER & ACCESSORIES4.1 Syngas Cooler Gasifier System $101,906 $0 $56,569 $0 $0 $158,475 $14,508 $21,881 $29,920 $224,784 $3514.2 Syngas Cooler(w/ Gasifier - 4.1 ) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.3 ASU/Oxidant Compression $152,787 $0 w/equip. $0 $0 $152,787 $14,542 $0 $16,733 $184,063 $2874.4 Scrubber & Low Temperature Cooling $9,253 $7,518 $7,846 $0 $0 $24,617 $2,346 $0 $5,393 $32,356 $514.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.6 Other Gasification Equipment $2,863 $1,359 $2,689 $0 $0 $6,911 $661 $0 $1,514 $9,087 $144.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $04.9 Gasification Foundations $0 $2,726 $2,292 $0 $0 $5,018 $463 $0 $1,370 $6,851 $11SUBTOTAL 4. $266,809 $11,603 $69,396 $0 $0 $347,808 $32,521 $21,881 $54,930 $457,140 $714TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants121Exhibit 3-30 Case 1 Total Plant Costs (Continued)Client:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 01 - GEE Radiant Only IGCC w/o CO2Plant Size:640.3 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material LaborSales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW5A GAS CLEANUP & PIPING5A.1 Single Stage Selexol $33,056 $0 $28,354 $0 $0 $61,411 $5,895 $0 $13,461 $80,767 $1265A.2 Elemental Sulfur Plant $9,860 $1,957 $12,731 $0 $0 $24,548 $2,367 $0 $5,383 $32,299 $505A.3 Mercury Removal $1,016 $0 $774 $0 $0 $1,790 $172 $89 $410 $2,461 $45A.4 COS Hydrolysis $2,515 $0 $3,286 $0 $0 $5,801 $560 $0 $1,272 $7,633 $125A.5 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.6 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.7 Fuel Gas Piping $0 $1,942 $1,338 $0 $0 $3,280 $299 $0 $716 $4,294 $75A.9 HGCU Foundations $0 $1,079 $701 $0 $0 $1,780 $163 $0 $583 $2,527 $4SUBTOTAL 5A. $46,447 $4,978 $47,184 $0 $0 $98,610 $9,456 $89 $21,825 $129,980 $2035B CO2 REMOVAL & COMPRESSION5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator $82,000 $0 $5,071 $0 $0 $87,072 $8,192 $4,354 $9,962 $109,578 $1716.2 Syngas Expander $5,440 $0 $760 $0 $0 $6,200 $585 $0 $1,018 $7,803 $126.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.9 Combustion Turbine Foundations $0 $752 $838 $0 $0 $1,591 $148 $0 $522 $2,260 $4SUBTOTAL 6. $87,441 $752 $6,670 $0 $0 $94,862 $8,925 $4,354 $11,501 $119,642 $1877 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator $34,012 $0 $4,840 $0 $0 $38,851 $3,667 $0 $4,252 $46,771 $737.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07.3 Ductwork $0 $1,579 $1,144 $0 $0 $2,723 $239 $0 $592 $3,555 $67.4 Stack $3,127 $0 $1,175 $0 $0 $4,302 $409 $0 $471 $5,182 $87.9 HRSG,Duct & Stack Foundations $0 $622 $602 $0 $0 $1,225 $114 $0 $401 $1,739 $3SUBTOTAL 7. $37,138 $2,201 $7,761 $0 $0 $47,101 $4,429 $0 $5,717 $57,247 $898 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $29,570 $0 $5,065 $0 $0 $34,635 $3,319 $0 $3,795 $41,750 $658.2 Turbine Plant Auxiliaries $204 $0 $467 $0 $0 $670 $65 $0 $74 $809 $18.3 Condenser & Auxiliaries $5,181 $0 $1,496 $0 $0 $6,678 $634 $0 $731 $8,042 $138.4 Steam Piping $5,510 $0 $3,883 $0 $0 $9,393 $801 $0 $2,549 $12,744 $208.9 TG Foundations $0 $1,003 $1,707 $0 $0 $2,711 $256 $0 $890 $3,856 $6SUBTOTAL 8. $40,465 $1,003 $12,619 $0 $0 $54,087 $5,075 $0 $8,039 $67,201 $1059 COOLING WATER SYSTEM9.1 Cooling Towers $4,704 $0 $1,034 $0 $0 $5,738 $543 $0 $942 $7,223 $119.2 Circulating Water Pumps $1,481 $0 $95 $0 $0 $1,575 $135 $0 $257 $1,967 $39.3 Circ.Water System Auxiliaries $122 $0 $17 $0 $0 $139 $13 $0 $23 $175 $09.4 Circ.Water Piping $0 $5,160 $1,316 $0 $0 $6,476 $573 $0 $1,410 $8,460 $139.5 Make-up Water System $299 $0 $424 $0 $0 $723 $69 $0 $158 $949 $19.6 Component Cooling Water Sys $594 $711 $502 $0 $0 $1,808 $167 $0 $395 $2,370 $49.9 Circ.Water System Foundations& Structures $0 $1,785 $3,057 $0 $0 $4,842 $457 $0 $1,590 $6,889 $11SUBTOTAL 9. $7,199 $7,656 $6,445 $0 $0 $21,301 $1,957 $0 $4,774 $28,032 $4410 ASH/SPENT SORBENT HANDLING SYS10.1 Slag Dewatering & Cooling $11,592 $6,392 $12,995 $0 $0 $30,979 $2,968 $0 $3,395 $37,341 $5810.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.6 Ash Storage Silos $562 $0 $612 $0 $0 $1,174 $113 $0 $193 $1,480 $210.7 Ash Transport & Feed Equipment $759 $0 $182 $0 $0 $941 $87 $0 $154 $1,182 $210.8 Misc. Ash Handling Equipment $1,164 $1,427 $426 $0 $0 $3,017 $285 $0 $495 $3,798 $610.9 Ash/Spent Sorbent Foundation $0 $49 $62 $0 $0 $112 $10 $0 $37 $159 $0SUBTOTAL 10. $14,077 $7,868 $14,278 $0 $0 $36,223 $3,463 $0 $4,274 $43,960 $69TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants122Exhibit 3-30 Case 1 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 01 - GEE Radiant Only IGCC w/o CO2Plant Size:640.3 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW11 ACCESSORY ELECTRIC PLANT11.1 Generator Equipment $921 $0 $918 $0 $0 $1,839 $175 $0 $201 $2,215 $311.2 Station Service Equipment $3,646 $0 $342 $0 $0 $3,988 $379 $0 $437 $4,804 $811.3 Switchgear & Motor Control $6,967 $0 $1,277 $0 $0 $8,245 $764 $0 $1,351 $10,360 $1611.4 Conduit & Cable Tray $0 $3,315 $10,762 $0 $0 $14,077 $1,346 $0 $3,856 $19,279 $3011.5 Wire & Cable $0 $6,088 $4,095 $0 $0 $10,184 $744 $0 $2,732 $13,660 $2111.6 Protective Equipment $0 $640 $2,427 $0 $0 $3,067 $300 $0 $505 $3,872 $611.7 Standby Equipment $218 $0 $222 $0 $0 $441 $43 $0 $72 $556 $111.8 Main Power Transformers $11,408 $0 $142 $0 $0 $11,550 $875 $0 $1,864 $14,288 $2211.9 Electrical Foundations $0 $153 $404 $0 $0 $557 $53 $0 $183 $793 $1SUBTOTAL 11. $23,161 $10,196 $20,591 $0 $0 $53,947 $4,678 $0 $11,201 $69,826 $10912 INSTRUMENTATION & CONTROL12.1 IGCC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $012.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $012.4 Other Major Component Control $932 $0 $648 $0 $0 $1,580 $152 $79 $272 $2,082 $312.5 Signal Processing Equipment W/12.7 $0 W/12.7 $0 $0 $0 $0 $0 $0 $0 $012.6 Control Boards,Panels & Racks $214 $0 $143 $0 $0 $357 $34 $18 $82 $491 $112.7 Computer & Accessories $4,969 $0 $166 $0 $0 $5,135 $487 $257 $588 $6,466 $1012.8 Instrument Wiring & Tubing $0 $1,767 $3,697 $0 $0 $5,464 $463 $273 $1,550 $7,751 $1212.9 Other I & C Equipment $3,322 $0 $1,681 $0 $0 $5,002 $480 $250 $860 $6,592 $10SUBTOTAL 12. $9,437 $1,767 $6,335 $0 $0 $17,538 $1,616 $877 $3,351 $23,382 $3713 Improvements to Site13.1 Site Preparation $0 $101 $2,169 $0 $0 $2,270 $224 $0 $748 $3,242 $513.2 Site Improvements $0 $1,792 $2,399 $0 $0 $4,190 $412 $0 $1,381 $5,983 $913.3 Site Facilities $3,211 $0 $3,413 $0 $0 $6,624 $650 $0 $2,182 $9,457 $15SUBTOTAL 13. $3,211 $1,892 $7,981 $0 $0 $13,084 $1,285 $0 $4,311 $18,681 $2914 Buildings & Structures14.1 Combustion Turbine Area $0 $221 $127 $0 $0 $348 $31 $0 $76 $454 $114.2 Steam Turbine Building $0 $2,410 $3,479 $0 $0 $5,888 $540 $0 $964 $7,393 $1214.3 Administration Building $0 $802 $590 $0 $0 $1,392 $124 $0 $227 $1,743 $314.4 Circulation Water Pumphouse $0 $158 $85 $0 $0 $243 $21 $0 $40 $304 $014.5 Water Treatment Buildings $0 $423 $418 $0 $0 $842 $76 $0 $138 $1,055 $214.6 Machine Shop $0 $411 $285 $0 $0 $695 $62 $0 $114 $871 $114.7 Warehouse $0 $663 $434 $0 $0 $1,097 $97 $0 $179 $1,373 $214.8 Other Buildings & Structures $0 $397 $313 $0 $0 $710 $63 $0 $155 $929 $114.9 Waste Treating Building & Str. $0 $888 $1,719 $0 $0 $2,607 $242 $0 $570 $3,419 $5SUBTOTAL 14. $0 $6,373 $7,450 $0 $0 $13,823 $1,257 $0 $2,462 $17,541 $27TOTAL COST $581,977 $71,760 $240,644 $0 $0 $894,382 $83,439 $28,701 $154,397 $1,160,919 $1,813TOTAL PLANT COST SUMMARYCost and Performance Comparison of Fossil Energy Power Plants

123 

### Exhibit 3-31 Case 1 Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006 Case 01 - GEE Radiant Only IGCC w/o CO2 Heat Rate-net(Btu/kWh): 8,922 MWe-net: 640 Capacity Factor: (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 33.00 $/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 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 15.0 15.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $5,637,060 $8.804 Maintenance Labor Cost $12,434,373 $19.421 Administrative & Support Labor $4,517,858 $7.056 TOTAL FIXED OPERATING COSTS $22,589,291 $35.282 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $23,111,454 $0.00515

Consumables Consumption Unit Initial Initial /Day Cost Cost
Water(/1000 gallons) 0 5,874 1.03 $0 $1,766,592 $0.00039

Chemicals MU & WT Chem.(lb) 122,480 17,497 0.16 $20,185 $841,987 $0.00019 Carbon (Mercury Removal) (lb) 59,493 81 1.00 $59,493 $23,652 $0.00001 COS Catalyst (m3) 410 0.28 2,308.40 $946,446 $189,160 $0.00004 Water Gas Shift Catalyst(ft3) 0 0 475.00 $0 $0 $0.00000 Selexol Solution (gal) 378 54 12.90 $4,877 $203,424 $0.00005 MDEA Solution (gal) 0 0 0.96 $0 $0 $0.00000 Sulfinol Solution (gal) 0 0 9.68 $0 $0 $0.00000 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. 2.21 125.00 $0 $80,745 $0.00002 Subtotal Chemicals $1,031,000 $1,338,968 $0.00030

Other Supplemental Fuel(MBtu) 0 0 0.00 $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 81 0.40 $0 $9,499 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Bottom Ash(ton) 0 645 15.45 $0 $2,909,636 $0.00065 Subtotal-Waste Disposal $0 $2,919,135 $0.00065

By-products & Emissions Sulfur(tons) 0 147 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $1,031,000 $29,136,149 $0.00649

Fuel(ton) 176,276 5,876 42.11 $7,422,978 $72,250,323 $0.01610Cost and Performance Comparison of Fossil Energy Power Plants

124 

### 3.2.8 C ASE 

### 2

- GEE IGCC WITH 

### CO 2 

### C APTURE 

### Case 2 is configured to pr oduce electric power with CO 2 

### capture. The plant configuration is the same as Case 1, namely two gasifier trains, tw o advanced F Class turb ines, two HRSGs and one steam turbine. The gross power output from the plant is constrained by the capacity of the two combustion turbines, and since the CO 2 

### capture process increases the auxiliary load on the plant, the net output is significantly reduced relative to Case 1. The process description for Case 2 is similar to Case 1 with several notable exceptions to accommodate CO 2 

### capture. A BFD and stream tables for Case 2 are shown in Exhibit 3-32 and Exhibit 3-33, respectively. Instead of repeating the entire process description, only differences from Case 1 are reported here.

Gasification The gasification process is the same as Case 1 wi th the exception that total coal feed to the two gasifiers is 5,448 tonnes/day (6,005 TPD) (stream 6) and th e ASU provides 4,635 tonnes/day (5,110 TPD) of 95 percent oxygen to the gasifi er and Claus plant (streams 3 and 5).
Raw Gas Cooling/Particulate Removal Raw gas cooling and particulate removal are th e same as Case 1 with the exception that approximately 548,122 kg/h (1,208,400 lb/h) of sa turated steam at 13.8 MPa (2,000 psia) is generated in the radiant SGCs.
Syngas Scrubber/Sour Water Stripper
No differences from Case 1.
Sour Gas Shift (SGS) The SGS process was described in Section 3.1.3. In Case 2 steam (stream 10) is added to the syngas exiting the scrubber to adjust the H 2 

### O:CO molar ratio to 2:1 prior to the first SGS reactor. The hot syngas exiting the first stage of SGS is used to generate the steam th at is added in stream 10. A second stage of SGS results in 96 pe rcent overall conversion of the CO to CO 2 

### . The warm syngas from the second stage of SGS (stream 11 ) is cooled to 232°C (450°F) by producing IP steam that is sent to the reh eater in the HRSG. The SGS catal yst also serves to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. Following the second SGS cooler the syngas is further cooled to 39°C (103°F) prior to the mercury removal beds.
Mercury Removal and Acid Gas Removal Mercury removal is the same as in Case 1. The AGR process in Case 2 is a two stage Selexol process where H 2 

### S is removed in the first stage and CO 2 

### in the second stage of absorption as previously described in Section 3.1.5. The process results in three product streams, the clean syngas, a CO 2 

### -rich stream and an acid gas feed to the Claus plant. The acid gas (stream 17) contains 41 percent H 2 

### S and 45 percent CO 2 

### with the balance primarily N 2 

### . The CO 2 

### -rich stream is discussed further in the CO 2 

### compression section.Cost and Performance Comparisonof Fossil Energy Power Plants125Exhibit 3-32 Case 2 ProcessFlow Diagram, GEE IGCC with CO2CaptureGASTURBINECOMBUSTORTURBINECOOLINGAIRQUENCH ANDSYNGASSCRUBBERGASCOOLINGBFW HEATING& KNOCKOUTSHIFTREACTORSELEVATEDPRESSUREASUGEE GASIFIERSECTION(RADIANTCOOLER)SOURWATERSTRIPPERMERCURYREMOVALDUALSTAGESELEXOLUNITCLAUSPLANTHRSGAMBIENTAIRSYNGASEXPANDERHYDROGENATIONREACTOR ANDGASCOOLERCO2COMPRESSION158910111213151718191667234202122AIR TOASUCOALSLURRYSLAGSHIFTSTEAMWATERRECYCLETOPROCESSDEMANDNOTE: WATER FROMTAILGASCOOLER MODELED,BUT NOT SHOWNNITROGENDILUENTSYNGASCLEANGASCO2STREAMSCO2PRODUCTSULFURTAILGASRECYCLE TOSELEXOLNOTE: TAILGASBOOSTCOMPRESSOR MODELED,BUT NOT SHOWNFLUEGASSTACKGASCO2PURIFICATIONOFF-GASVENTGASCLAUSPLANTOXIDANT2XADVANCEDF CLASSGASTURBINESYNGASH/PREHEAT14CLAUSPLANTOXIDANTSTEAMTURBINE274.7 MWe6.3 MWe464.0 MWeCost and Performance Comparisonof Fossil Energy Power Plants126Exhibit 3-33 Case 2 Stream Table, GEE IGCC with CO2Capture123456A7 8 9 10 11V-L Mole FractionAr 0.0094 0.0089 0.0360 0.0024 0.0320 0.0000 0.0000 0.0079 0.0062 0.0000 0.0051CH40.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0010 0.0008 0.0000 0.0006CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3442 0.2666 0.0000 0.0090CO20.0003 0.0023 0.0000 0.0000 0.0000 0.0000 0.0000 0.1511 0.1166 0.0000 0.3113COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000H20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3349 0.2594 0.0000 0.4305H2O0.0108 0.0836 0.0000 0.0000 0.0000 1.0000 0.0000 0.1429 0.3365 1.0000 0.2317H2S0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0056 0.0000 0.0048N20.7719 0.8367 0.0140 0.9922 0.0180 0.0000 0.0000 0.0089 0.0069 0.0000 0.0058NH30.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0017 0.0013 0.0000 0.0011O20.2076 0.0685 0.9500 0.0054 0.9500 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000SO20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000V-L Flowrate (lbmol/hr)64,331 8,321 214 42,780 13,015 14,511 0 52,422 67,674 13,313 80,987V-L Flowrate (lb/hr) 1,855,930 229,617 6,904 1,200,560 418,847 261,198 0 1,069,860 1,343,900 239,846 1,583,740Solids Flowrate (lb/hr) 0 0 0 0 0 444,737 54,925 0 0 0 0Temperature (°F) 232 60 90 385 206 141 410 1,100 410 615 519Pressure (psia) 190.6 16.4 145.0 460.0 980.0 1,050.0 797.7 799.7 797.7 875.0 777.2Enthalpy (BTU/lb)B55.6 18.0 12.5 87.8 37.7 --- 1,710 535.5 474.7 1275.0 433.3Density (lb/ft3)0.741 0.087 0.792 1.424 4.416 --- --- 0.975 1.697 1.367 1.447Molecular Weight 28.849 27.594 32.229 28.063 32.181 --- --- 20.409 19.858 18.015 19.555A - Solids flowrate includes dry coal; V-L flowrate includes slurry water and water from coalB - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparisonof Fossil Energy Power Plants127Exhibit 3-33Case 2 Stream Table (continued)12 13 14 15 16 17 18 19 20 21 22V-L Mole FractionAr 0.0067 0.0067 0.0111 0.0111 0.0000 0.0000 0.0000 0.0182 0.0094 0.0092 0.0092CH40.0008 0.0008 0.0022 0.0022 0.0000 0.0000 0.0000 0.0577 0.0000 0.0000 0.0000CO 0.0117 0.0117 0.0190 0.0190 0.0000 0.0000 0.0000 0.0003 0.0000 0.0000 0.0000CO20.4057 0.4057 0.0448 0.0448 1.0000 0.4488 0.0000 0.6784 0.0003 0.0085 0.0085COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0000 0.0000 0.0000 0.0000H20.5609 0.5609 0.9095 0.9095 0.0000 0.0000 0.0000 0.0170 0.0000 0.0000 0.0000H2O0.0009 0.0009 0.0000 0.0000 0.0000 0.0394 0.0000 0.0005 0.0108 0.1226 0.1226H2S0.0054 0.0054 0.0000 0.0000 0.0000 0.4102 0.0000 0.0228 0.0000 0.0000 0.0000N20.0075 0.0075 0.0134 0.0134 0.0000 0.0807 0.0000 0.2051 0.7719 0.7527 0.7527NH30.0003 0.0003 0.0000 0.0000 0.0000 0.0203 0.0000 0.0000 0.0000 0.0000 0.0000O20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2076 0.1071 0.1071SO20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000V-L Flowrate (lbmol/hr)62,118 62,118 38,323 38,323 23,493 855 0 576 243,972 307,285 307,285V-L Flowrate (lb/hr) 1,243,070 1,243,070 198,981 198,981 1,033,930 31,703 0 21,951 7,038,470 8,438,010 8,438,010Solids Flowrate (lb/hr) 0 0 0 0 0 0 12,514 0 0 0 0Temperature (°F) 103 103 100 386 155 120 373 95 59 1,052 270Pressure (psia) 736.7 726.7 696.2 460.0 2,214.7 30.5 25.4 776.1 14.7 15.2 15.2Enthalpy (BTU/lb)B28.0 28.0 91.4 480.6 -46.5 39.7 -96.5 14.0 13.8 361.5 148.2Density (lb/ft3)2.443 2.410 0.602 0.263 30.975 0.184 --- 4.966 0.076 0.026 0.053Molecular Weight 20.012 20.012 5.192 5.192 44.010 37.082 --- 38.086 28.849 27.460 27.460B - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparison of Fossil Energy Power Plants

128 

### CO 2 

### Compression and Dehydration
CO 2 

### from the AGR process is generated at three pr essure levels. The LP stream is compressed from 0.15 MPa (22 psia) to 1.1 MPa (160 psia) and then combined w ith the MP stream. The HP stream is combined between compressor stages at 2.1 MPa (300 psia). The combined stream is compressed from 2.1 MPa (300 psia) to a superc ritical condition at 15.3 MPa (2215 psia) using a multiple-stage, intercooled compre ssor. During compression, the CO 2 

### stream is dehydrated to a dewpoint of -40oC (-40°F) with triethylene glycol. The raw CO 2 

### stream from the Selexol process contains over 93 percent CO 2 

### with the balance primarily nitrogen. For modeling purposes it was assumed that the impurities were separated from the CO 2 

### and combined with the clean syngas stream from the Selexol process. The pure CO 2 

### (stream 16) is transported to the plant fence line and is sequestration ready. CO 2 

### TS&M costs were estimated using the methodology described in Section 2.7.

Claus Unit The Claus plant is the same as Case 1 with the following exceptions:

• 5,676 kg/h (12,514 lb/h) of sulfur (stream 18) are produced

• The waste heat boiler generates 13,555 ( 29,884 lb/h) of 4.0 MPa (575 psia) steam of which 9,603 kg/h (21,172 lb/h) is available to the medium pressure steam header.

Power Block Clean syngas from the AGR plant is combined with a small amount of clean gas from the CO 2 

### compression process (stream 14) and heated to 4 65°F using HP boiler feedwater before passing through an expansion turbine. The clean syngas (stream 15) is diltuted with nitrogen (stream 4) and then enters the CT burner. There is no integr ation between the CT and the ASU in this case. The exhaust gas (stream 21) exits the CT at 567°C (1052°F) and enters the HRSG where additional heat is recovered. The flue gas exit s the HRSG at 132°C (270°F) (stream 22) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced commercially available steam turbine using a 12.4 MPa/538°C/538°C (1800 psig/1000°F/1000°F) steam cycle.
Air Separation Unit The same elevated pressure ASU is used in Case 2 and produces 4,635 tonnes/day (5,110 TPD) of 95 mole percent oxygen and 13,070 tonnes/da y (14,410 TPD) of nitrogen. There is no integration between the ASU and the combustion turbine.

3.2.9 C ASE 

### 2 P ERFORMANCE 

### R ESULTS 

### The Case 2 modeling assumptions were presented previously in Section 3.2.3. The plant produces a net output of 556 MW at a net plant efficiency of 32.5 percent (HHV basis). Overall performance for the entire plant is summarized in Exhibit 3-34 which includes auxiliary power requirements. The ASU accounts for nearly 64 percent of the auxiliary load between the main air compressor, the nitr ogen compressor, the oxygen compressor and ASU auxiliaries. The two-st age Selexol process and CO 2 

### compression account for an additional 24 percent of the auxiliary power load. The BF W pumps and cooling water system (circulatingCost and Performance Comparison of Fossil Energy Power Plants

129 

### water pumps and cooling tower fan) comprise over 5 percent of the load, leaving 7 percent of the auxiliary load for all other systems.Cost and Performance Comparison of Fossil Energy Power Plants

130 

### Exhibit 3-34 Case 2 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Gas Turbine Power 464,010 Sweet Gas Expander Power 6,260 Steam Turbine Power 274,690 TOTAL POWER, kWe 744,960 AUXILIARY LOAD SUMMARY, kWe Coal Handling 460 Coal Milling 2,330 Coal Slurry Pumps 760 Slag Handling and Dewatering 1,200 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 72,480 Oxygen Compressor 11,520 Nitrogen Compressor 35,870 Claus Plant Tail Gas Recycle Compressor 990 CO 2 

### Compressor 27,400 Boiler Feedwater Pumps 4,580 Condensate Pump 265 Flash Bottoms Pump 200 Circulating Water Pumps 3,580 Cooling Tower Fans 1,850 Scrubber Pumps 420 Selexol Unit Auxiliaries 17,320 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 200 Miscellaneous Balance of Plant (Note 1) 3,000 Transformer Loss 2,760 TOTAL AUXILIARIES, kWe 189,285 NET POWER, kWe 555,675 Net Plant Efficiency, % (HHV) 32.5 Net Plant Heat Rate (Btu/kWh) 10,505 CONDENSER COOLING DUTY 10 6 

### kJ/h (10 6 

### Btu/h) 1,509 (1,431) CONSUMABLES As-Received Coal Feed, kg/h (lb/h) 226,968 (500,379) Thermal Input, kWt 1,710,780 Raw Water Usage, m 3 

### /min (gpm) 8.7 (4,578) Note 1: Includes plant control systems, ligh ting, HVAC and miscellaneous low voltage loadsCost and Performance Comparison of Fossil Energy Power Plants

131 

### Environmental Performance The environmental targets for emissions of Hg, NOx, SO2, and particulate matter were presented in Section 2.4. A summary of the plant ai r emissions for Case 2 is presented in Exhibit 3-35.

Exhibit 3-35 Case 2 Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (tons/year) @ 80% capacity factor kg/MWh (lb/MWh)

SO 2 

### 0.004 (0.010) 178 (196) 0.034 (0.075) NO X 

### 0.020 (0.047) 867 (955) 0.166 (0.366) Particulates 0.003 (0.0071) 132 (145) 0.025 (0.056) Hg 0.25x10 -6 

### (0.57x10 -6 

### ) 0.011 (0.012) 2.0x10 -6 

### (4.5x10 -6 

### ) CO 2 

### 8.4 (19.6) 364,000 (401,000) 70 (154)
CO 2 1 

### 93 (206)

1 

### CO 2 

### emissions based on net power instead of gross power
The low level of SO 2 

### emissions is achieved by capture of the sulfur in the gas by the two-stage Selexol AGR process. As a resu lt of achieving the 90 percent CO 2 

### removal target, the sulfur compounds are removed to an extent that exceeds the environmental target in Section 2.4. The clean syngas exiting the AGR process has a sulf ur concentration of approximately 23 ppmv. This results in a concentration in the flue gas of less than 3 ppmv. The H 2 

### S-rich regeneration gas from the AGR system is fed to a Claus plant, pr oducing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H 2 

### S and then recycled back to the Selexol process, thereby eliminating the need for a tail gas treatment unit.
NO X 

### emissions are limited by nitrog en dilution to 15 ppmvd (as NO 2 

### @15 percent O 2 

### ). Ammonia in the syngas is removed with proce ss condensate prior to th e low-temperature AGR process. This helps lower NO X 

### levels as well. Particulate discharge to the atmosphere is lim ited to extremely low values by the use of the syngas quench in addition to the syngas scr ubber 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. Ninety percent of the CO 2 

### from the syngas is captured in the AGR system and compressed for sequestration. The carbon balance for the plant is shown in Exhibit 3-36. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in th e air is not neglected here since the AspenPlus model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, as dissolved CO 2 

### in the wastewater blowdown stream, and as CO 2 

### in the stack gas, ASU vent gas, and the captured CO 2 

### product. Carbon in the wastewater blowdown stream is calculated by difference to cl ose the material balance. The carbon capture efficiency is defined as the amount of carbon in the CO 2 

### product stream relative to the amount of carbon in the coal less carbon cont ained in the slag, represented by the following fraction:Cost and Performance Comparison of Fossil Energy Power Plants

132 

### (Carbon in CO 2 

### Product)/[(Carbon in the Coal)-(Carbon in Slag)] or 281,981/(318,992-6,404) *100 or 90.2 percent

Exhibit 3-36 Case 2 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) Coal 144,692 (318,992) Slag 2,905 (6,404) Air (CO 2 

### ) 495 (1,091) Stack Gas 14,162 (31,221) CO 2 

### Product 127,904 (281,981)

ASU Vent 103 (228) Wastewater 113 (249) Total 145,187 (320,083) Total 145,187 (320,083)

Exhibit 3-37 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output incl udes the sulfur recovered in the Claus plant, dissolved SO 2 

### in the wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible, and the sulfur content of the blowdown stream is calculated by difference to close the material balance. The to tal sulfur capture is re presented by the following fraction: (Sulfur byproduct/Sulfur in the coal) or (12,514/12,560) or 99.6 percent

Exhibit 3-37 Case 2 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) Coal 5,697 (12,560) Elemental Sulfur 5,676 (12,514) Stack Gas 13 (28) Wastewater 8 (18) Total 5,697 (12,560) Total 5,697 (12,560)

Exhibit 3-38 shows the overall water balance for the plant. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the total amount of water required for a particular process. Some water is recovered within the process, primarily as syngas condens ate, and that water is re-used as internal recycle. Raw water makeup is the difference between wa ter demand and internal recycle.Cost and Performance Comparison of Fossil Energy Power Plants

133 

### Exhibit 3-38 Case 2 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle,

m 3 

### /min (gpm) Raw Water Makeup,

m 3 

### /min (gpm)
Slurry 1.6 (411) 1.6 (411) 0
Slag Handling 0.5 (143) 0 0.5 (143)
Quench/Scrubber 2.5 (665) 1.2 (315) 1.3 (350)
Shift Steam 1.8 (479) 0 1.8 (479)
BFW Makeup 0.2 (45) 0 0.2 (45)
Cooling Tower Makeup 13.9 (3,679) 0.4 (118) 13.5 (3,561)

Total 20.5 (5,422) 3.2 (844) 17.3 (4,578)

Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-39 through Exhibit 3-43:

• Coal gasification and air separation unit

• Syngas cleanup

• Sulfur recovery and tail gas recycle

• Combined cycle power generation

• Steam and feedwater An overall plant energy balance is presented in tabular form in Exhibit 3-44. The power out is the combined combustion turbine, steam turbine and expander power prior to generator losses. The power at the generator terminals (shown in Exhibit 3-34) is calculated by multiplying the power out by a combined genera tor efficiency of 98.3 percent.Cost and Performance Comparison of Fossil Energy Power Plants

134 

### This page intentionally left blankCost and Performance Comparisonof Fossil Energy Power Plants135Exhibit 3-39 Case 2 Coal Gasification and AirSeparation Units Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants136Exhibit 3-40 Case 2 Syngas Cleanup Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants137Exhibit 3-41 Case 2 Sulfur Recovery and Tail Gas Recycle Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants138Exhibit 3-42 Case 2 Combined-Cycle PowerGeneration Heat andMass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants139Exhibit 3-43 Case 2 Steam and Feedwater Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants140This page intentionally left blankCost and Performance Comparison of Fossil Energy Power Plants

141 

### Exhibit 3-44 Case 2 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total
Heat In (MMBtu/hr) Coal 5,837.4 4.9 5,842.3 ASU Air 25.6 25.6 CT Air 96.9 96.9 Water 13.3 13.3 Auxiliary Power 646.0 646.0 Totals 5,837.4 140.7 646.0 6,624.1 Heat Out (MMBtu/hr) ASU Intercoolers 269.0 269.0 ASU Vent 4.1 4.1 Slag 90.2 3.7 93.9 Sulfur 49.8 (1.2) 48.6 Tail Gas Compressor Intercoolers 3.5 3.5

CO 2 

### Compressor Intercoolers 138.0 138.0

CO 2 

### Product (48.1) (48.1) HRSG Flue Gas 1,250.1 1,250.1 Condenser 1,431.0 1,431.0 Process Losses 847.4 847.4 Power 2,586.5 2,586.5 Totals 140.0 3,897.5 2,586.5 6,624.1 (1) Process Losses are calculated by differen ce and reflect various gasification, turbine, HRSG and other heat and work losses. Aspe n flowsheet balance is within 0.5 percent.Cost and Performance Comparison of Fossil Energy Power Plants

142 

### 3.2.10 C ASE 

### 2

- M AJOR 

### E QUIPMENT 

### L IST 

### Major equipment items for the GEE gasifier with CO 2 

### capture are shown in the following tables. The accounts used in the equipment list correspo nd to the account numbers used in the cost estimates in Section 3.2.11. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
ACCOUNT 1 COAL HANDLING

Equipment No. Description Type Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0
3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0
5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0
8 Reclaim Hopper N/A 2 1
9 Feeder Vibratory 2 1
10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor reduction 2 0

14 As-Fired Coal Sampling System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0

17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 3 0 N/A

372 tonne/h (410 tph)

816 tonne (900 ton)

45 tonne (50 ton)
191 tonne/h (210 tph)

8 cm x 0 - 3 cm x 0 (3" x 0 - 1-1/4" x 0) 372 tonne/h (410 tph)

191 tonne (210 ton) N/A

N/A

372 tonne/h (410 tph)

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph) N/A
1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)
1,134 tonne/h (1,250 tph)Cost and Performance Comparison of Fossil Energy Power Plants

143 

### ACCOUNT 2 COAL PREPARATION AND FEED
Equipment No. Description Type Operating Qty. Spares

1 Coal Feeder Gravimetric 3 0
2 Conveyor No. 6 Belt w/tripper 1 0
3 Rod Mill Feed Hopper Dual Outlet 1 0
4 Weigh Feeder Belt 2 0
5 Rod Mill Rotary 2 0

6 Slurry Water Storage Tank with Agitator Field erected 2 0

7 Slurry Water Pumps Centrifugal 2 2

10 Trommel Screen Coarse 2 0

11 Rod Mill Discharge Tank with Agitator Field erected 2 0

12 Rod Mill Product Pumps Centrifugal 2 2

13 Slurry Storage Tank with Agitator Field erected 2 0

14 Slurry Recycle Pumps Centrifugal 2 2

15 Slurry Product Pumps Positive displacement 2 2 172 tonne/h (190 tph)

2,726 lpm (720 gpm) 5,451 lpm (1,440 gpm) 984,215 liters (260,000 gal) 127 tonne/h (140 tph)

327,441 liters (86,500 gal)

2,726 lpm (720 gpm)

871 lpm (230 gpm) 127 tonne/h (140 tph)

306,621 liters (81,000 gal) Design Condition

82 tonne/h (90 tph)
254 tonne/h (280 tph)
499 tonne (550 ton)Cost and Performance Comparison of Fossil Energy Power Plants

144 

### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT
Equipment No. Description Type Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 3 0

2 Condensate Pumps Vertical canned 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multistage, centrifugal 2 1

7 Auxiliary Boiler Shop fabricated, water tube 1 0

8 Service Air Compressors Flooded Screw 2 1

9 Instrument Air Dryers Duplex, regenerative 2 1

10 Closed Cylce Cooling Heat Exchangers Plate and frame 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 2 1

12 Engine-Driven Fire Pump Vertical turbine, diesel engine 1 1

13 Fire Service Booster Pump Two-stage horizontal centrifugal 1 1

14 Raw Water Pumps Stainless steel, single suction 2 1

15 Filtered Water Pumps Stainless steel, single suction 2 1

16 Filtered Water Tank Vertical, cylindrical 2 0

17 Makeup Water Demineralizer Anion, cation, and mixed bed 2 0

18 Liquid Waste Treatment System 1 0 1,363 lpm @ 707 m H2O (360 gpm @ 2320 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C (40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) Design Condition

1,037,211 liters (274,000 gal)

7,457 lpm @ 91 m H2O (1,970 gpm @ 300 ft H2O)

544,311 kg/h (1,200,000 lb/h)

IP water: 1,817 lpm @ 223 m H2O (480 gpm @ 730 ft H2O) HP water: 6,662 lpm @ 1,890 m H2O (1,760 gpm @ 6,200 ft H2O)

3,710 lpm @ 49 m H2O (980 gpm @ 160 ft H2O) 28 m3/min (1,000 scfm)

58 MMkJ/h (55 MMBtu/h) each
20,820 lpm @ 21 m H2O (5,500 gpm @ 70 ft H2O) 3,785 lpm @ 88 m H2O (1,000 gpm @ 290 ft H2O)

2,650 lpm @ 64 m H2O (700 gpm @ 210 ft H2O) 9,615 lpm @ 18 m H2O (2,540 gpm @ 60 ft H2O)

1,786,728 liter (472,000 gal)

1,173 lpm (310 gpm)

10 years, 24-hour storm 2 1 5 High Pressure Feedwater Pump No. 1 Barrel type, multistage, centrifugalCost and Performance Comparison of Fossil Energy Power Plants

145 

### ACCOUNT 4 GASIFIER, ASU AND ACC ESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY
Equipment No. Description Type Operating Qty. Spares

1 Gasifier Pressurized slurry-feed, entrained bed 2 0

2 Synthesis Gas Cooler Vertical downflow radiant heat exchanger with outlet quench chamber 2 0

3 Syngas Scrubber Including Sour Water Stripper Vertical upflow 2 0

4 Raw Gas Coolers Shell and tube with condensate drain 6 0

5 Raw Gas Knockout Drum Vertical with mist eliminator 2 0

6 Flare Stack Self-supporting, carbon steel, stainless steel top, pilot ignition 2 0

7 ASU Main Air Compressor Centrifugal, multistage 2 0

8 Cold Box Vendor design 2 0

9 Oxygen Compressor Centrifugal, multistage 2 0

10 Nitrogen Compressor Centrifugal, multistage 2 0

11 Nitrogen Boost Compressor Centrifugal, multistage 2 0 595 m3/min @ 2.3 MPa (21,000 scfm @ 340 psia) 335,205 kg/h (739,000 lb/h)
syngas 6,343 m3/min @ 1.3 MPa (224,000 scfm @ 190 psia)
2,540 tonne/day (2,800 tpd) of 95% purity oxygen
1,274 m3/min @ 7.1 MPa (45,000 scfm @ 1,030 psia) 3,625 m3/min @ 3.4 MPa (128,000 scfm @ 490 psia) Design Condition

2,994 tonne/day, 5.6 MPa (3,300 tpd, 815 psia)

280,774 kg/h (619,000 lb/h)

335,205 kg/h (739,000 lb/h)

395,079 kg/h (871,000 lb/h)

297,103 kg/h, 38°C, 5.2 MPa (655,000 lb/h, 100°F, 747 psia)Cost and Performance Comparison of Fossil Energy Power Plants

146 

### ACCOUNT 5A SOUR GAS SHIF T AND SYNGAS CLEANUP
Equipment No. Description Type Operatin g Qty. Spares

1 Mercury Adsorber Sulfated carbon bed 2 0

2 Sulfur Plant Claus type 1 0

3 Water Gas Shift Reactors Fixed bed, catalytic 4 0

4 Shift Reactor Heat Recovery Exhchangers Shell and Tube 4 0

5 Acid Gas Removal Plant Two-stage Selexol 2 0

6 Hydrogenation Reactor Fixed bed, catalytic 1 0

7 Tail Gas Recycle Compressor Centrifugal 1 0 Exchanger 1: 148 MMkJ/h (140 MMBtu/h) Exchanger 2: 32 MMkJ/h (30 MMBtu/h)

11,431 kg/h @ 6.4 MPa (25,200 lb/h @ 930 psi) 395,079 kg/h (871,000 lb/h) 232°C (450°F) 5.5 MPa (798 psia)

310,258 kg/h (684,000 lb/h) 39°C (103°F) 5.0 MPa (727 psia)

15,513 kg/h (34,200 lb/h) 232°C (450°F) 0.2 MPa (25 psia) Design Condition

310,258 kg/h (684,000 lb/h) 39°C (103°F) 5.1 MPa (737 psia)

150 tonne/day (165 tpd)



### ACCOUNT 5B CO 2 

### COMPRESSION

Equipment No. Description Type Operating Qty. Spares

1 CO2 Compressor Integrally geared, multistage centrifugal 4 1 Design Condition
1,157 m3/min @ 15.3 MPa (40,859 scfm @ 2,215 psia)Cost and Performance Comparison of Fossil Energy Power Plants

147 

### ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES
Equipment No. Description Type Operating Qty. Spares

1 Gas Turbine Advanced F class 2 0

2 Gas Turbine Generator TEWAC 2 0

3 Syngas Expansion Turbine/Generator Turbo expander 2 0 Design Condition

232 MW
260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 49,641 kg/h (109,440 lb/h)

4.8 MPa (691 psia) Inlet 3.2 MPa (460 psia) Outlet



### ACCOUNT 7 HRSG, DUCTING, AND STACK

Equipment No. Description Type Operating Qty. Spares

1 Stack CS plate, type 409SS liner 1 0 Design Condition

76 m (250 ft) high x 8.5 m (28 ft) diameter

Main steam - 376,049 kg/h, 12.4 MPa/538°C (829,045 lb/h, 1,800 psig/1,000°F) 2 0 2 Heat Recovery Steam Generator Drum, multi-pressure with economizer section and integral deaerator Reheat steam - 381,590 kg/h, 2.9 MPa/538°C (841,261 lb/h, 420 psig/1,000°F)Cost and Performance Comparison of Fossil Energy Power Plants

148 

### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitiation 1 0

3 Steam Bypass One per HRSG 2 0

4 Surface Condenser Single pass, divided waterbox including
vacuum pumps 1 0 330 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase

50% steam flow @ design steam conditions Design Condition

298 MW 12.4 MPa/538°C/538°C (1800 psig/ 1000°F/1000°F)

1,676 MMkJ/h (1,590 MMBtu/h) heat duty, Inlet

water temperature 16°C (60°F), Water temperature rise 11°C (20°F)



### ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 1 0 Design Condition
359,617 lpm @ 30 m (95,000 gpm @ 100 ft) 11°C (51.5°F) wet bulb / 16°C

(60°F) CWT / 27°C (80°F) HWT 2,003 MMkJ/h (1,900 MMBtu/h) heat dutyCost and Performance Comparison of Fossil Energy Power Plants

149 

### ACCOUNT 10 SLAG RECOVERY AND HANDLING
Equipment No. Description Type Operating Qty. Spares

1 Slag Quench Tank Water bath 2 0
2 Slag Crusher Roll 2 0
3 Slag Depressurizer Lock Hopper 2 0
4 Slag Receiving Tank Horizontal, weir 2 0
5 Black Water Overflow Tank Shop fabricated 2 0
6 Slag Conveyor Drag chain 2 0
7 Slag Separation Screen Vibrating 2 0
8 Coarse Slag Conveyor Belt/bucket 2 0
9 Fine Ash Settling Tank Vertical, gravity 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 2 2

11 Grey Water Storage Tank Field erected 2 0

12 Grey Water Pumps Centrifugal 2 2

13 Slag Storage Bin Vertical, field erected 2 0

14 Unloading Equipment Telescoping chute 1 0 253,625 liters (67,000 gal)

76 lpm @ 14 m H2O (20 gpm @ 46 ft H2O)

998 tonne (1,100 tons)

118 tonne/h (130 tph) 83,280 liters (22,000 gal)

303 lpm @ 564 m H2O (80 gpm @ 1,850 ft H2O) 170,345 liters (45,000 gal)

14 tonne/h (15 tph)
14 tonne/h (15 tph)
14 tonne/h (15 tph) 79,494 liters (21,000 gal) Design Condition

261,195 liters (69,000 gal)
14 tonne/h (15 tph)
14 tonne/h (15 tph)Cost and Performance Comparison of Fossil Energy Power Plants

150 

### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type Operating Qty. Spares

1 CTG Transformer Oil-filled 2 0

3 Auxiliary Transformer Oil-filled 1 1

4 Low Voltage Transformer Dry ventilated 1 1

5 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 2 0

6 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 1 0

7 Medium Voltage Switchgear Metal clad 1 1

8 Low Voltage Switchgear Metal enclosed 1 1

9 Emergency Diesel Generator Sized for emergency shutdown 1 0 Design Condition

24 kV/345 kV, 260 MVA, 3-ph, 60 Hz

2 STG Transformer Oil-filled 24 kV/345 kV, 110 MVA, 3-ph, 60 Hz 1 0

24 kV/4.16 kV, 207 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 31 MVA, 3-ph, 60 Hz

750 kW, 480 V, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz



### ACCOUNT 12 INSTRUMENTATION AND CONTROL

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) 1 0

3 DCS - Data Highway Fiber optic 1 0 1 0

Fully redundant, 25% spare Design Condition

Operator stations/printers and engineering stations/printers

2 DCS - Processor Microprocessor with redundant input/output N/ACost and Performance Comparison of Fossil Energy Power Plants

151 

### 3.2.11 C ASE 

### 2

- C OST 

### E STIMATING 

### The cost estimating methodology was desc ribed previously in Section 2.6. Exhibit 3-45 shows the total plant cost summary organized by cost account and Exhibit 3-46 shows a more detailed breakdown of the capital costs. Exhibit 3-47 shows the initial and annual O&M costs. The estimated TPC of the GEE gasifier with CO 2 

### capture is $2,390/kW. Process contingency represents 4.2 percent of the TP C and project contingency repres ents 13.6 percent. The 20-year LCOE, including CO 2 

### TS&M costs of 3.9 mills/kWh, is 102.9 mills/kWh.Cost and Performance Comparisonof Fossil Energy Power Plants152Exhibit 3-45 Case 2 Total Plant Cost SummaryClient:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 02 - GEE Radiant Only IGCC w/ CO2Plant Size:555.7 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING $13,688 $2,552 $10,726 $0 $0$26,966$2,443 $0 $5,882$35,291$642 COAL & SORBENT PREP & FEED $23,455 $4,274 $14,205 $0 $0$41,934$3,803 $1,522 $9,452$56,712$1023 FEEDWATER & MISC. BOP SYSTEMS $10,144 $8,686 $9,657 $0 $0$28,487$2,661 $0 $7,040$38,188$694 GASIFIER & ACCESSORIES4.1 Syngas Cooler Gasifier System $103,362 $0 $57,380 $0 $0$160,742$14,715 $22,192 $30,349$227,999$4104.2 Syngas Cooler(w/ Gasifier - 4.1 ) w/4.1 $0 w/4.1 $0 $0$0$0 $0 $0$0$04.3 ASU/Oxidant Compression $157,723 $0 w/equip. $0 $0$157,723$15,012 $0 $17,274$190,009$3424.4-4.9 Other Gasification Equipment $12,297 $11,735 $12,985 $0 $0$37,018$3,516 $0 $8,381$48,914$88SUBTOTAL 4 $273,383 $11,735 $70,365 $0 $0 $355,484 $33,243 $22,192 $56,003 $466,922 $8405A Gas Cleanup & Piping $79,047 $4,945 $70,370 $0 $0$154,363$14,797 $22,231 $38,475$229,866$4145BCO2REMOVAL & COMPRESSION$17,712 $0 $10,865 $0 $0$28,577$2,732 $0 $6,262$37,572$686 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator $88,000 $0 $5,325 $0 $0$93,325$8,779 $9,332 $11,144$122,580$2216.2-6.9 Combustion Turbine Other $5,270 $752 $1,575 $0 $0$7,598$715 $0 $1,508$9,820$18SUBTOTAL 6 $93,270 $752 $6,900 $0 $0 $100,922 $9,494 $9,332 $12,651 $132,400 $2387 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator $32,193 $0 $4,581 $0 $0$36,774$3,471 $0 $4,025$44,270$807.2-7.9 Ductwork and Stack $3,222 $2,268 $3,011 $0 $0$8,501$785 $0 $1,510$10,795$19SUBTOTAL 7 $35,415 $2,268 $7,592 $0 $0 $45,275 $4,256 $0 $5,534 $55,065 $998 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $28,444 $0 $4,847 $0 $0$33,291$3,190 $0 $3,648$40,130$728.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,439 $943 $7,306 $0 $0$18,688$1,684 $0 $4,109$24,481$44SUBTOTAL 8 $38,883 $943 $12,153 $0 $0 $51,979 $4,875 $0 $7,757 $64,611 $1169 COOLING WATER SYSTEM $7,074 $7,437 $6,229 $0 $0$20,740$1,905 $0 $4,628$27,273$4910 ASH/SPENT SORBENT HANDLING SYS $14,265 $7,973 $14,470 $0 $0$36,708$3,509 $0 $4,331$44,548$8011 ACCESSORY ELECTRIC PLANT $23,997 $11,838 $23,440 $0 $0$59,275$5,162 $0 $12,496$76,933$13812 INSTRUMENTATION & CONTROL $10,469 $1,960 $7,028 $0 $0$19,457$1,793 $973 $3,718$25,942$4713 IMPROVEMENTS TO SITE $3,318 $1,956 $8,248 $0 $0$13,522$1,328 $0 $4,455$19,305$3514 BUILDINGS & STRUCTURES $0 $6,410 $7,441 $0 $0$13,851$1,259 $0 $2,474$17,583$32TOTAL COST $644,121 $73,729 $279,690 $0 $0 $997,540 $93,261 $56,251 $181,157 $1,328,209 $2,390TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants153Exhibit 3-46 Case 2 Total Plant Cost DetailsClient:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 02 - GEE Radiant Only IGCC w/ CO2Plant Size:555.7 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING1.1 Coal Receive & Unload $3,595 $0 $1,775 $0 $0 $5,370 $481 $0 $1,170 $7,020 $131.2 Coal Stackout & Reclaim $4,645 $0 $1,138 $0 $0 $5,783 $507 $0 $1,258 $7,548 $141.3 Coal Conveyors $4,319 $0 $1,126 $0 $0 $5,445 $478 $0 $1,185 $7,107 $131.4 Other Coal Handling $1,130 $0 $260 $0 $0 $1,390 $122 $0 $302 $1,815 $31.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.9 Coal & Sorbent Hnd.Foundations $0 $2,552 $6,427 $0 $0 $8,979 $856 $0 $1,967 $11,801 $21SUBTOTAL 1. $13,688 $2,552 $10,726 $0 $0 $26,966 $2,443 $0 $5,882 $35,291 $642 COAL & SORBENT PREP & FEED2.1 Coal Crushing & Drying incl w/2.3 incl. w/ 2.3 incl. w/ 2.3 incl. w/ 2.3 $0 $0 $0 $0 $0 $0 $0 $02.2 Prepared Coal Storage & Feed $1,537 $366 $244 $0 $0 $2,146 $184 $0 $466 $2,796 $52.3 Slurry Prep & Feed $21,073 $0 $9,373 $0 $0 $30,446 $2,760 $1,522 $6,946 $41,674 $752.4 Misc.Coal Prep & Feed $845 $612 $1,863 $0 $0 $3,320 $304 $0 $725 $4,350 $82.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.9 Coal & Sorbent Feed Foundation $0 $3,296 $2,725 $0 $0 $6,021 $555 $0 $1,315 $7,892 $14SUBTOTAL 2. $23,455 $4,274 $14,205 $0 $0 $41,934 $3,803 $1,522 $9,452 $56,712 $1023 FEEDWATER & MISC. BOP SYSTEMS3.1 FeedwaterSystem $3,396 $5,905 $3,119 $0 $0 $12,420 $1,146 $0 $2,713 $16,280 $293.2 Water Makeup & Pretreating $577 $60 $322 $0 $0 $960 $91 $0 $315 $1,365 $23.3 Other Feedwater Subsystems $1,875 $636 $573 $0 $0 $3,084 $276 $0 $672 $4,031 $73.4 Service Water Systems $333 $679 $2,358 $0 $0 $3,370 $326 $0 $1,109 $4,805 $93.5 Other Boiler Plant Systems $1,787 $686 $1,701 $0 $0 $4,173 $391 $0 $913 $5,478 $103.6 FO Supply Sys & Nat Gas $306 $577 $539 $0 $0 $1,421 $136 $0 $311 $1,868 $33.7 Waste Treatment Equipment $802 $0 $492 $0 $0 $1,294 $125 $0 $426 $1,845 $33.8 Misc. Equip.(cranes,AirComp.,Comm.) $1,068 $144 $553 $0 $0 $1,765 $170 $0 $581 $2,516 $5SUBTOTAL 3. $10,144 $8,686 $9,657 $0 $0 $28,487 $2,661 $0 $7,040 $38,188 $694 GASIFIER & ACCESSORIES4.1 Syngas Cooler Gasifier System $103,362 $0 $57,380 $0 $0 $160,742 $14,715 $22,192 $30,349 $227,999 $4104.2 Syngas Cooler(w/ Gasifier - 4.1 ) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.3 ASU/Oxidant Compression $157,723 $0 w/equip. $0 $0 $157,723 $15,012 $0 $17,274 $190,009 $3424.4 Scrubber & Low Temperature Cooling $9,391 $7,629 $7,963 $0 $0 $24,983 $2,381 $0 $5,473 $32,838 $594.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.6 Other Gasification Equipment $2,907 $1,380 $2,730 $0 $0 $7,017 $671 $0 $1,538 $9,226 $174.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.9 Gasification Foundations $0 $2,726 $2,292 $0 $0 $5,018 $463 $0 $1,370 $6,851 $12SUBTOTAL 4. $273,383 $11,735 $70,365 $0 $0 $355,484 $33,243 $22,192 $56,003 $466,922 $840TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants154Exhibit 3-46 Case 2 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 02 - GEE Radiant Only IGCC w/ CO2Plant Size:555.7 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW5A GAS CLEANUP & PIPING5A.1 Double Stage Selexol $59,515 $0 $51,050 $0 $0 $110,564 $10,614 $22,113 $28,658 $171,950 $3095A.2 Elemental Sulfur Plant $10,010 $1,987 $12,925 $0 $0 $24,922 $2,403 $0 $5,465 $32,790 $595A.3 Mercury Removal $1,340 $0 $1,020 $0 $0 $2,360 $226 $118 $541 $3,245 $65A.4 Shift Reactors $8,183 $0 $3,380 $0 $0 $11,563 $1,101 $0 $2,533 $15,196 $275A.5 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.6 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.7 Fuel Gas Piping $0 $1,862 $1,283 $0 $0 $3,146 $287 $0 $686 $4,119 $75A.9 HGCU Foundations $0 $1,096 $712 $0 $0 $1,808 $166 $0 $592 $2,565 $5SUBTOTAL 5A. $79,047 $4,945 $70,370 $0 $0 $154,363 $14,797 $22,231 $38,475 $229,866 $4145B CO2 REMOVAL & COMPRESSION5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05B.2 CO2 Compression & Drying $17,712 $0 $10,865 $0 $0 $28,577 $2,732 $0 $6,262 $37,572 $68SUBTOTAL 5B. $17,712 $0 $10,865 $0 $0 $28,577 $2,732 $0 $6,262 $37,572 $686 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator $88,000 $0 $5,325 $0 $0 $93,325 $8,779 $9,332 $11,144 $122,580 $2216.2 Syngas Expander $5,270 $0 $737 $0 $0 $6,007 $567 $0 $986 $7,560 $146.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.9 Combustion Turbine Foundations $0 $752 $838 $0 $0 $1,591 $148 $0 $522 $2,260 $4SUBTOTAL 6. $93,270 $752 $6,900 $0 $0 $100,922 $9,494 $9,332 $12,651 $132,400 $2387 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator $32,193 $0 $4,581 $0 $0 $36,774 $3,471 $0 $4,025 $44,270 $807.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07.3 Ductwork $0 $1,627 $1,179 $0 $0 $2,806 $246 $0 $610 $3,663 $77.4 Stack $3,222 $0 $1,211 $0 $0 $4,433 $422 $0 $485 $5,340 $107.9 HRSG,Duct & Stack Foundations $0 $641 $620 $0 $0 $1,262 $117 $0 $414 $1,792 $3SUBTOTAL 7. $35,415 $2,268 $7,592 $0 $0 $45,275 $4,256 $0 $5,534 $55,065 $998 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $28,444 $0 $4,847 $0 $0 $33,291 $3,190 $0 $3,648 $40,130 $728.2 Turbine Plant Auxiliaries $195 $0 $449 $0 $0 $645 $63 $0 $71 $778 $18.3 Condenser & Auxiliaries $4,788 $0 $1,407 $0 $0 $6,195 $588 $0 $678 $7,461 $138.4 Steam Piping $5,455 $0 $3,844 $0 $0 $9,299 $793 $0 $2,523 $12,616 $238.9 TG Foundations $0 $943 $1,605 $0 $0 $2,548 $240 $0 $837 $3,625 $7SUBTOTAL 8. $38,883 $943 $12,153 $0 $0 $51,979 $4,875 $0 $7,757 $64,611 $1169 COOLING WATER SYSTEM9.1 Cooling Towers $4,602 $0 $1,012 $0 $0 $5,614 $531 $0 $922 $7,067 $139.2 Circulating Water Pumps $1,448 $0 $92 $0 $0 $1,540 $132 $0 $251 $1,923 $39.3 Circ.Water System Auxiliaries $119 $0 $17 $0 $0 $136 $13 $0 $22 $172 $09.4 Circ.Water Piping $0 $5,063 $1,292 $0 $0 $6,354 $563 $0 $1,383 $8,300 $159.5 Make-up Water System $320 $0 $454 $0 $0 $774 $73 $0 $170 $1,017 $29.6 Component Cooling Water Sys $584 $698 $493 $0 $0 $1,775 $164 $0 $388 $2,327 $49.9 Circ.Water System Foundations& Structures $0 $1,676 $2,870 $0 $0 $4,546 $429 $0 $1,492 $6,467 $12SUBTOTAL 9. $7,074 $7,437 $6,229 $0 $0 $20,740 $1,905 $0 $4,628 $27,273 $4910 ASH/SPENT SORBENT HANDLING SYS10.1 Slag Dewatering & Cooling $11,749 $6,479 $13,172 $0 $0 $31,400 $3,008 $0 $3,441 $37,849 $6810.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.6 Ash Storage Silos $569 $0 $619 $0 $0 $1,188 $114 $0 $195 $1,498 $310.7 Ash Transport & Feed Equipment $768 $0 $184 $0 $0 $953 $88 $0 $156 $1,196 $210.8 Misc. Ash Handling Equipment $1,178 $1,444 $432 $0 $0 $3,054 $289 $0 $501 $3,844 $710.9 Ash/Spent Sorbent Foundation $0 $50 $63 $0 $0 $113 $11 $0 $37 $161 $0SUBTOTAL 10. $14,265 $7,973 $14,470 $0 $0 $36,708 $3,509 $0 $4,331 $44,548 $80TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants155Exhibit 3-46 Case 2 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 02 - GEE Radiant Only IGCC w/ CO2Plant Size:555.7 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW11 ACCESSORY ELECTRIC PLANT11.1 Generator Equipment $903 $0 $900 $0 $0 $1,803 $171 $0 $197 $2,172 $411.2 Station Service Equipment $4,284 $0 $402 $0 $0 $4,686 $445 $0 $513 $5,644 $1011.3 Switchgear & Motor Control $8,187 $0 $1,501 $0 $0 $9,687 $897 $0 $1,588 $12,172 $2211.4 Conduit & Cable Tray $0 $3,895 $12,645 $0 $0 $16,540 $1,581 $0 $4,530 $22,652 $4111.5 Wire & Cable $0 $7,154 $4,812 $0 $0 $11,966 $875 $0 $3,210 $16,050 $2911.6 Protective Equipment $0 $640 $2,427 $0 $0 $3,067 $300 $0 $505 $3,872 $711.7 Standby Equipment $215 $0 $219 $0 $0 $434 $42 $0 $71 $547 $111.8 Main Power Transformers $10,409 $0 $139 $0 $0 $10,548 $799 $0 $1,702 $13,048 $2311.9 Electrical Foundations $0 $149 $395 $0 $0 $544 $52 $0 $179 $775 $1SUBTOTAL 11. $23,997 $11,838 $23,440 $0 $0 $59,275 $5,162 $0 $12,496 $76,933 $13812 INSTRUMENTATION & CONTROL12.1 IGCC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $012.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $012.4 Other Major Component Control $1,034 $0 $719 $0 $0 $1,752 $169 $88 $301 $2,310 $412.5 Signal Processing Equipment W/12.7 $0 W/12.7 $0 $0 $0 $0 $0 $0 $0 $012.6 Control Boards,Panels & Racks $238 $0 $159 $0 $0 $396 $38 $20 $91 $545 $112.7 Computer & Accessories $5,513 $0 $184 $0 $0 $5,697 $540 $285 $652 $7,174 $1312.8 Instrument Wiring & Tubing $0 $1,960 $4,102 $0 $0 $6,062 $514 $303 $1,720 $8,599 $1512.9 Other I & C Equipment $3,685 $0 $1,864 $0 $0 $5,550 $533 $277 $954 $7,314 $13SUBTOTAL 12. $10,469 $1,960 $7,028 $0 $0 $19,457 $1,793 $973 $3,718 $25,942 $4713 Improvements to Site13.1 Site Preparation $0 $104 $2,242 $0 $0 $2,346 $231 $0 $773 $3,350 $613.2 Site Improvements $0 $1,851 $2,479 $0 $0 $4,330 $425 $0 $1,427 $6,182 $1113.3 Site Facilities $3,318 $0 $3,527 $0 $0 $6,845 $672 $0 $2,255 $9,773 $18SUBTOTAL 13. $3,318 $1,956 $8,248 $0 $0 $13,522 $1,328 $0 $4,455 $19,305 $3514 Buildings & Structures14.1 Combustion Turbine Area $0 $221 $127 $0 $0 $348 $31 $0 $76 $454 $114.2 Steam Turbine Building $0 $2,290 $3,307 $0 $0 $5,597 $514 $0 $917 $7,028 $1314.3 Administration Building $0 $833 $612 $0 $0 $1,446 $129 $0 $236 $1,810 $314.4 Circulation Water Pumphouse $0 $156 $84 $0 $0 $240 $21 $0 $39 $301 $114.5 Water Treatment Buildings $0 $460 $454 $0 $0 $914 $82 $0 $149 $1,146 $214.6 Machine Shop $0 $426 $296 $0 $0 $722 $64 $0 $118 $904 $214.7 Warehouse $0 $688 $450 $0 $0 $1,139 $101 $0 $186 $1,426 $314.8 Other Buildings & Structures $0 $412 $325 $0 $0 $738 $66 $0 $161 $964 $214.9 Waste Treating Building & Str. $0 $922 $1,785 $0 $0 $2,707 $252 $0 $592 $3,550 $6SUBTOTAL 14. $0 $6,410 $7,441 $0 $0 $13,851 $1,259 $0 $2,474 $17,583 $32TOTAL COST $644,121 $73,729 $279,690 $0 $0 $997,540 $93,261 $56,251 $181,157 $1,328,209 $2,390TOTAL PLANT COST SUMMARYCost and Performance Comparison of Fossil Energy Power Plants

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### Exhibit 3-47 Case 2 Initial and A nnual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006 Case 02 - GEE Radiant Only IGCC w/ CO2 Heat Rate-net(Btu/kWh): 10,505 MWe-net: 556 Capacity Factor: (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 33.00 $/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 10.0 10.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 16.0 16.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,012,864 $10.820 Maintenance Labor Cost $13,432,424 $24.172 Administrative & Support Labor $4,861,322 $8.748 TOTAL FIXED OPERATING COSTS $24,306,610 $43.741 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $24,602,924 $0.00632

Consumables Consumption Unit Initial Initial /Day Cost Cost
Water(/1000 gallons) 0 6,594 1.03 $0 $1,983,139 $0.00051

Chemicals MU & WT Chem.(lb) 137,493 19,642 0.16 $22,659 $945,198 $0.00024 Carbon (Mercury Removal) (lb) 84,811 116 1.00 $84,811 $33,872 $0.00001 COS Catalyst (m3) 0 0 2,308.40 $0 $0 $0.00000 Water Gas Shift Catalyst(ft3) 6,288 4.30 475.00 $2,986,800 $596,410 $0.00015 Selexol Solution (gal) 504 72 12.90 $6,502 $271,232 $0.00007 MDEA Solution (gal) 0 0 0.96 $0 $0 $0.00000 Sulfinol Solution (gal) 0 0 9.68 $0 $0 $0.00000 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 2.25 125.00 $0 $82,125 $0.00002 Subtotal Chemicals $3,100,772 $1,928,837 $0.00050

Other Supplemental Fuel(MBtu) 0 0 0.00 $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) 0 116 0.40 $0 $13,603 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Bottom Ash(ton) 0 659 15.45 $0 $2,973,464 $0.00076 Subtotal-Waste Disposal $0 $2,987,067 $0.00077

By-products & Emissions 0 0 0.00 $0 $0.00000 Sulfur(tons) 0 150 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $3,100,772 $31,501,967 $0.00809

Fuel(ton) 180,143 6,005 42.11 $7,585,825 $73,835,368 $0.01896Cost and Performance Comparison of Fossil Energy Power Plants

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### 3.3 CONOCOPHILLIPS E-GAS TM 

### IGCC CASES
This section contains an eval uation of plant designs for Cases 3 and 4, which are based on the ConocoPhillips (CoP) E-GasTM gasifier. Cases 3 and 4 are very similar in terms of process, equipment, scope and arrangement, except that Case 4 includes sour gas shift reactors, CO 2 

### absorption/regeneration and compression/transpor t systems. There are no provisions for CO 2 

### removal in Case 3. The balance of this section is organi zed in an analogous manner to Section 3.2:

• Gasifier Background

• Process System Description for Case 3

• Key Assumptions for Cases 3 and 4

• Sparing Philosophy for Cases 3 and 4

• Performance Results for Case 3

• Equipment List for Case 3

• Cost Estimates for Case 3

• Process and System Description, Performance Re sults, Equipment List and Cost Estimate for Case 4

3.3.1 G ASIFIER 

### B ACKGROUND 

### Dow Chemical (the former principal stockho lder of Destec Energy, which was bought by Global Energy, Inc., the gasifier business that was purch ased by ConocoPhillips) is a major producer of chemicals. They began coal gasification deve lopment work in 1976 with bench-scale (2 kg/h [4 lb/h]) reactor testing. Important fundamental data were obtained for conversion and yields with various coals and operating conditions. This work led to the construc tion of a pilot plant at Dow’s large chemical complex in Plaquemine, Lo uisiana. The pilot pl ant was designed for a capacity of 11 tonnes/day (12 TPD) (dry lignite ba sis) and was principall y operated with air as the oxidant. The plant also operated with oxyge n at an increased cap acity of 33 tonnes/day (36 TPD) (dry lignite basis). This pilot plant operated from 1978 through 1983. Following successful operation of the pilot plant, Dow built a larger 499 tonnes/day (550 TPD) (dry lignite basis) gasifier at Plaquemine. In 1984, Dow Chemical and the U.S. Synthetic Fuels Corporation (SFC) announced a pric e guarantee contract which allo wed the building of the first commercial-scale Dow coal gasification unit. The Louisiana Gasifica tion Technology, Inc. (LGTI) plant, sometimes called the Dow Synga s Project, was also located in the Dow Plaquemine chemical complex. The plant ga sified about 1,451 tonnes/day (1,600 TPD) (dry basis) of subbituminous coal to generate 184 MW (gross) of combined-cycle electricity. To ensure continuous power output to the petroc hemical complex, a minimum of 20 percent of natural gas was co-fired w ith the syngas. LGTI was operated from 1987 through 1995. In September 1991, DOE selected the Wabash Rive r coal gasification repowering project, which used the Destec Energy process, for funding unde r the Clean Coal Technology Demonstration Program. The project was a joint venture of De stec and Public Service of Indiana (PSI Energy, Inc.). Its purpose was to repower a unit at PS I’s Wabash River station in West Terre Haute,Cost and Performance Comparison of Fossil Energy Power Plants

158 

### Indiana to produce 265 MW of net power from local high-sulfur b ituminous coal. The design of the project gasifier was based on the Destec LGTI gasifier. Experience ga ined in that project provided significant input to the design of th e Wabash River coal gasification facility and eliminated much of the risk associated with scale-up and process variables. Gasifier Capacity – The gasifier originally develope d by Dow is now known as the CoP EGasTM gasifier. The daily coal-handling capacity of the E-Gas gasifier operating at Plaquemine was in the range of 1,270 tonnes (1,400 tons) (m oisture/ash-free [MAF] basis) for bituminous coal to 1,497 tonnes (1,650 tons) for lign ite. The dry gas production rate was 141,600 Nm 3 

### /h (5 million scf/h) with an energy content of about 1,370 MMkJ/h (1,300 MMBtu/h) (HHV). The daily coal-handling capacity of the gasifier at Wabash River is about 1,678 tonnes (1,850 tons) (MAF basis) for high-sulfur bituminous coal. The dry gas producti on rate is about 189,724 Nm 3 

### /h (6.7 million scf/h) with an energy c ontent of about 1,950 MMkJ/h (1,850 MMBtu/h) (HHV). This size matches the combustion turbine, which is a GE 7FA. With increased power and fuel gas turbine demand, the gasifier coal feed increases proportionately. CoP has indicate d that the gasifier can read ily handle the increased demand. Distinguishing Characteristics - A key advantage of the CoP co al gasification technology is the current operating experience with subbituminous coal at full commercial scale at the Plaquemine plant and bituminous coal at the Wabash plant. The two-stage operation improves the efficiency, reduces oxygen requirements, and enables more eff ective operation on slurry feeds relative to a single stage gasifier. The fire-t ube SGC used by E-Gas has a lower capital cost than a water-tube design, an added advantage for the CoP technology at this time. However, this experience may spur other developers to try fire-tube designs. Entrained-flow gasifiers have fundamental environmental advantages over fluidized-bed and moving-bed gasifiers. They pr oduce no hydrocarbon liquids, and the only solid waste is an inert slag. The key disadvantages of the CoP coal gasifica tion technology are the re latively short refractory life and the high waste heat rec overy (SGC) duty. As with the other entrained-flow slagging gasifiers, these disadvantages result from high op erating temperature. However, the two-stage operation results in a quenched syngas that is higher in CH 4 

### content than other gasifiers. This becomes a disadvantage in CO 2 

### capture cases since the CH 4 

### passes through the SGS reactors without change, and is also not separated by th e AGR thus limiting the amount of carbon that can be captured. Important Coal Characteristics

- The slurry feeding system and the recycle of process condensate water as the principal slurrying liqui d make low levels of ash and soluble salts desirable coal characteristics for use in the E-Ga sTM coal gasification process. High ash levels increase the ratio of water to carbon in the coal in the feed slurry, th ereby increasing the oxygen requirements. Soluble salts affect the proces sing cost and amount of water blowdown required to avoid problems associated with excessive bu ildup of salts in the sl urry water recycle loop.
Bituminous coals with lower inhe rent moisture improve the sl urry concentration and reduce oxygen requirements. The two-stage operation redu ces the negative impact of low-rank coal use in slurry feed, entrained-flow gasification. Lo w to moderate ash fusi on-temperature coals are preferred for slagging gasifiers. Coals with high ash fusion temperat ures may require flux addition for optimal gasification operation.Cost and Performance Comparison of Fossil Energy Power Plants

159 

### 3.3.2 P ROCESS 

### D ESCRIPTION 

### In this section the overall CoP gasification proces s is described. The system description follows the BFD in Exhibit 3-48 and stream numbers referen ce the same Exhibit. The tables in Exhibit 3-49 provide process data for the numbered streams in the BFD.
Coal Grinding and Slurry Preparation Coal receiving and handling is common to all cases and was covered in Section 3.1.1. The receiving and handling subsystem e nds at the coal silo. Coal gr inding and slurry preparation is similar to the GEE cases but re peated here for completeness.
Coal from the coal silo is fe d onto a conveyor by vibratory feeder s located below each silo. The conveyor feeds the coal to an inclined conveyor that delivers the coal to the rod mill feed hopper. The feed hopper provides a surge capacity of ab out two hours and contains two hopper outlets. Each hopper outlet discharges onto a weigh feeder, wh ich in turn feeds a rod mill. Each rod mill is sized to process 55 percent of the coal feed re quirements of the gasifier. The rod mill grinds the coal and wets it with treated slurry water tr ansferred from the slurry water tank by the slurry water pumps. The coal slurry is discharged through a tr ommel screen into th e rod mill discharge tank, and then the slurry is pumped to the slurry storage tanks. The dry solids concentration of the final slurry is 63 percent. The Polk Power Station operates at a slu rry concentration of 62-68 percent using bituminous coal and CoP presented a paper showing the slu rry concentration of Illinois No. 6 coal as 63 percent. [ 41, 49] The coal grinding system is equipped with a dust suppression system consisting of water sprays aided by a wetting agent. The degree of dust suppression required depends on local environmental regulations. All of the tanks are equipped with verti cal agitators to keep the coal slurry solids suspended. The equipment in the coal grinding and slurry pr eparation system is fabricated of materials appropriate for the abrasive environment presen t in the system. The tanks and agitators are rubber lined. The pumps are either rubber-lined or hardened metal to minimize erosion. Piping is fabricated of high-density polyethylene (HDPE).

Gasification This plant utilizes two gasificat ion trains to process a total of 5,050 tonnes/day (5,567 TPD) of Illinois No. 6 coal. Each of the 2 x 50 percen t gasifiers operate at maximum capacity. The EGasTM two-stage coal gasification technology f eatures an oxygen-blow n, entrained-flow, refractory-lined gasifi er with continuous slag removal. A bout 78 percent of the total slurry feed is fed to the first (or bottom) stage of the gasifi er. All oxygen for gasificati on is fed to this stage of the gasifier at a pressure of 4.2 MPa (615 psia). This stage is best described as a horizontal cylinder with two horizontally opposed burners. The highly exothermic gasification/oxidation reactions take place rapidly at temp eratures of 1,316 to 1,427°C (2,400 to 2,600 ° F). The hot raw gas from the first stage enters the second (top) stag e, which is a vertical cylinder perpendicular to the first stage. The remaining 22 percent of coal slurry is injected into this hot raw gas. The endothermic gasification/devolatilization reaction in this stage reduces the final gas temperature to about 1,010°C (1,850 ° F). Total slurry to both stag es is shown as stream 6 in Exhibit 3-48.Cost and Performance Comparisonof Fossil Energy Power Plants160Exhibit 3-48 Case 3 Process Flow Diagram, E-GasTM IGCC without CO2CaptureCost and Performance Comparisonof Fossil Energy Power Plants161Exhibit 3-49 Case 3 StreamTable, E-GasTM IGCC without CO2Capture123456A7 8 9 10 11V-L Mole FractionAr 0.0092 0.0262 0.0360 0.0024 0.0320 0.0000 0.0000 0.0080 0.0080 0.0092 0.0092CH40.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0400 0.0400 0.0457 0.0457CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3851 0.3851 0.4403 0.4403CO20.0003 0.0090 0.0000 0.0000 0.0000 0.0000 0.0000 0.1468 0.1473 0.1685 0.1685COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0000 0.0000H20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2738 0.2738 0.3134 0.3134H2O0.0099 0.2756 0.0000 0.0004 0.0000 1.0000 0.0000 0.1251 0.1246 0.0018 0.0018H2S0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0079 0.0084 0.0092 0.0092N20.7732 0.4638 0.0140 0.9919 0.0180 0.0000 0.0000 0.0102 0.0102 0.0117 0.0117NH30.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0026 0.0026 0.0002 0.0002O20.2074 0.2254 0.9500 0.0054 0.9500 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000SO20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000V-L Flowrate (lbmol/hr)41,839 1,917 242 40,619 10,830 13,452 0 55,289 55,289 48,292 38,633V-L Flowrate (lb/hr) 1,207,360 51,005 7,811 1,139,740 348,539 242,145 0 1,196,610 1,196,610 1,070,040 856,032Solids Flowrate (lb/hr) 0 0 0 0 0 412,305 47,201 0 0 0 0Temperature (°F) 235 70 90 385 191 140 1,850 400 401 103 103Pressure (psia) 190.0 16.4 125.0 460.0 740.0 850.0 850.0 554.7 544.7 504.7 494.7Enthalpy (BTU/lb)B55.7 26.8 12.5 88.0 34.4 --- 1,120 241.5 241.4 25.0 25.0Density (lb/ft3)0.735 0.104 0.683 1.424 3.412 --- --- 1.302 1.277 1.852 1.815Molecular Weight 28.857 26.613 32.229 28.060 32.181 --- --- 21.643 21.643 22.158 22.158A - Solids flowrate includes dry coal; V-L flowrate includes slurry water and water from coalB - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparisonof Fossil Energy Power Plants162Exhibit 3-49 Case 3 Stream Table Continued12 13 14 15 16 17 18 19 20 21 22V-L Mole FractionAr 0.0095 0.0088 0.0088 0.0000 0.0000 0.0059 0.0092 0.0094 0.0094 0.0088 0.0088CH40.0471 0.0434 0.0434 0.0001 0.0000 0.0000 0.0383 0.0000 0.0000 0.0000 0.0000CO 0.4544 0.4189 0.4189 0.0014 0.0000 0.0910 0.0003 0.0000 0.0000 0.0000 0.0000CO20.1513 0.1395 0.1395 0.7034 0.0000 0.4812 0.8551 0.0003 0.0003 0.0822 0.0822COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000H20.3235 0.2982 0.2982 0.0010 0.0000 0.0186 0.0097 0.0000 0.0000 0.0000 0.0000H2O0.0019 0.0798 0.0798 0.0000 0.0000 0.3490 0.0023 0.0108 0.0108 0.0718 0.0718H2S0.0000 0.0000 0.0000 0.2941 0.0000 0.0068 0.0140 0.0000 0.0000 0.0000 0.0000N20.0120 0.0111 0.0111 0.0000 0.0000 0.0454 0.0710 0.7719 0.7719 0.7360 0.7360NH30.0002 0.0002 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000O20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2076 0.2076 0.1012 0.1012SO20.0000 0.0000 0.0000 0.0000 0.0000 0.0017 0.0000 0.0000 0.0000 0.0000 0.0000Total 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000V-L Flowrate (lbmol/hr)37,428 40,600 40,600 1,205 0 1,596 1,021 243,395 12,038 298,016 298,016V-L Flowrate (lb/hr) 806,593 863,729 863,729 49,4390 50,953 42,010 7,021,820 347,293 8,678,000 8,678,000Solids Flowrate (lb/hr) 0 0 0 0 11,591 0 0 0 0 0 0Temperature (°F) 99 266 385 187 368 320 251 59 811 1,111 270Pressure (psia) 494.2 484.2 479.2 30.0 24.9 24.9 804.1 14.7 234.9 15.2 15.2Enthalpy (BTU/lb)B24.2 153.9 197.6 33.3 -97.5 288.6 49.1 13.8 200.3 330.6 106.9Density (lb/ft3)1.776 1.324 1.125 0.177 --- 0.095 4.340 0.076 0.497 0.026 0.057Molecular Weight 21.550 21.274 21.274 41.022 --- 31.929 41.154 28.849 28.849 29.119 29.119B - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparison of Fossil Energy Power Plants

163 

### The syngas produced by the CoP gasifier is highe r in methane content than either the GEE or Shell gasifier. The two stage design allows fo r improved cold gas efficiency and lower oxygen consumption, but the quenched second stage allows some CH 4 

### to remain. The syngas CH 4 

### concentration exiting the gasifier in Case 3 is 3.9 vol% (compare d to 0.10 vol% in Case 1 [GEE] and 0.04 vol% in Case 5 [Shell] ). The relatively high CH 4 

### concentration impacts CO 2 

### capture efficiency as discussed further in Section 3.3.8.
Raw Gas Cooling/Particulate Removal The 1,010°C (1,850 ° F) raw coal gas from the second stage of the gasifier is cooled to 371°C (700°F) in the waste heat recovery (synthesis gas cooler) unit, which consis ts of a fire-tube boiler and convective superheating and economizing sections . Fire-tube boilers cost markedly less than comparable duty water-tube boilers. This is be cause of the large savi ngs in high-grade steel associated with containing the hot high-pressu re synthesis gas in re latively small tubes. The coal ash is converted to molten slag, whic h flows down through a tap hole. The molten slag is quenched in water and removed through a propr ietary continuous-pressure letdown/dewatering system (stream 7). Char is produced in the second gasifier stage and is recycled to the hotter first stage, to be gasified. The cooled gas from the SGC is cleaned of remaining particulate via a cyclone collector followed by a ceramic candle filter. Recycled syngas is used as the pulse gas to clean the candle filters. The recovered fines are pneumatically retu rned to the first stage of the gasifier. The combination of recycled char and recycled pa rticulate results in hi gh overall carbon conversion (99.2 percent used in this study). Following particulate removal, additional heat is removed from the syngas to provide syngas reheat prior to the COS reactor and to generate steam for the LP st eam header. In this manner the syngas is cooled to 166°C (330°F) prior to the syngas scrubber.
Syngas Scrubber/Sour Water Stripper Syngas exiting the second of the two low temp erature heat exchangers passes to a syngas scrubber where a water wash is used to remove chlorides and particulate. The syngas exits the scrubber saturated at 152°C (305°F). The sour water stripper removes NH 3 

### , SO 2 

### , and other impurities from the scrubber and other waste streams. The stripper consists of a sour drum that accumulates sour water from the gas scrubber and condensate from synthesis gas coolers. Sour water from the drum flows to the sour stripper, which consists of a pack ed column with a steam-heated re boiler. Sour gas is stripped from the liquid and sent to the sulfur recovery unit. Remaini ng water is sent to wastewater treatment.
COS Hydryolysis, Mercury Removal and Acid Gas Removal Syngas exiting the scrubber is reheated to 400°F and enters a COS hydrolys is reactor (stream 8). About 99.5 percent of the COS is converted to CO 2 

### and H 2 

### O (Section 3.1.5). The gas exiting the COS reactor (stream 9) passes through a series of heat exchangers and knockout drums to lower the syngas temperature to 39°C (103°F) and to se parate entrained water. The cooled syngas (stream 10) then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.4).Cost and Performance Comparison of Fossil Energy Power Plants

164 

### Cool, particulate-free synthesis gas (stream 11) enters the absorber unit at approximately 3.4 MPa (495 psia) and 39°C (103°F). In the absorber, H 2 

### S is preferentially removed from the fuel gas stream by contact with MDEA. The ab sorber column is operated at 27°C (80°F) by refrigerating the lean MDEA solvent. The lower temperature is required to achieve an outlet H 2 

### S concentration of less than 30 ppmv in the sweet syngas. The stripper acid gas stream (stream 15), consisting of 29 percent H 2 

### S and 70 percent CO 2 

### , is sent to the Claus unit. The acid gas is combined with the sour water stripper off gas a nd introduced into the Clau s plant burner section.

Claus Unit Acid gas from the MDEA unit is preheated to 232°C (450°F). A portion of the acid gas along with all of the sour gas from the stripper and oxygen from the ASU are fed to the Claus furnace. In the furnace, H 2 

### S is catalytically oxidized to SO 2 

### at a furnace temperature of 1,316°C (2,400°F), which must be maintained in or der to thermally decompose all of the NH 3 

### present in the sour gas stream. Following the thermal stage and condensation of su lfur, two reheaters and two sulfur converters are used to obtain a per-pass H 2 

### S conversion of approximately 99.5 percent. The Claus Plant tail gas is hydrogenated and recycled back to the ga sifier (stream 18). In the furnace waste heat boiler, 14,710 kg/h (32,430 lb/h) of 4 .0 MPa (575 psia) steam is generated. This steam is used to satisfy all Claus process preheati ng and reheating requirements as well as to provide some steam to the medium-pressure steam header. The su lfur condensers produce 0.34 MPa (50 psig) steam for the low-pressure steam header. A flow rate of 5,258 kg/h (11,591 lb/h) of elemental sulfur (stream 16) is recovered from the fuel gas stream. This value represents an overall sulfur recovery efficiency of 99.5 percent.

Power Block Clean syngas exiting the MDEA absorber (stream 12) is partially humidified (stream 13) because there is not sufficient nitrogen from the ASU to pr ovide the level of diluti on required to reach the target syngas heating value. The moisturized sy ngas stream is reheated (stream 14), further diluted with nitrogen from the ASU (stream 4) and enters the advanced F Class combustion turbine (CT) burner. The CT compressor prov ides combustion air to the burner and also 22 percent of the total ASU air re quirement (stream 20). The exha ust gas exits the CT at 599°C (1,111°F) (stream 21) and enters the HRSG where additional heat is reco vered until the flue gas exits the HRSG at 132°C (270°F) (stream 22) a nd is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced, commercially available steam turbine using a 12.4 MPa/566°C/566°C (1800 psig/1050°F/1050°F) steam cycle.
Air Separation Unit (ASU) The elevated pressure ASU was described in Section 3.1.2. In Case 3 the ASU is designed to produce a nominal output of 3,880 tonnes/da y (4,275 TPD) of 95 mole percent O 2 

### for use in the gasifier (stream 5) and Claus pl ant (stream 3). The plant is de signed with two production trains. The air compressor is powere d by an electric motor. Approximately 12,410 tonnes/day (13,680 TPD) of nitrogen are also recovered, compressed, and used as dilution in the gas turbine combustor (stream 4). About 4.9 percent of the ga s turbine air is used to supply approximately 22 percent of the ASU air requirements (stream 20).Cost and Performance Comparison of Fossil Energy Power Plants

165 

### Balance of Plant Balance of plant items we re covered in Sections 3.1.9, 3.1.10 and 3.1.11.

3.3.3 K EY 

### S YSTEM 

### A SSUMPTIONS 

### System assumptions for Cases 3 and 4, CoP IGCC with and without CO 2 

### capture, are compiled in Exhibit 3-50.

Balance of Plant – Cases 3 and 4 The balance of plant assumptions are common to all cases and we re presented previously in Exhibit 3-17.

3.3.4 S PARING 

### P HILOSOPHY 

### The sparing philosophy for Cases 3 and 4 is pr ovided 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. The plant design consists of the following major subsystems:

• Two air separation units (2 x 50%)

• Two trains of slurry preparation and slurry pumps (2 x 50%)

• Two trains of gasification, incl uding gasifier, synthesis gas cooler, cyclone, and barrier filter (2 x 50%).

• Two trains of syngas clean-up process (2 x 50%).

• Two trains of refrigerated MDEA acid gas ga s removal in Case 3 and two-stage Selexol in Case 4 (2 x 50%),

• One train of Claus-based sulfur recovery (1 x 100%).

• Two combustion turbine/HRSG tandems (2 x 50%).

• One steam turbine (1 x 100%).Cost and Performance Comparison of Fossil Energy Power Plants

166 

### Exhibit 3-50 CoP IGCC Plant Study Configuration Matrix

Case 3 4 Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)
O 2 

### :Coal Ratio, kg O 2 

### /kg dry coal 0.85 0.85 Carbon Conversion, % 99.2 99.2 Syngas HHV at MDEA Outlet, kJ/Nm 3 

### (Btu/scf) 11,131 (299) 12,918 (347)
Steam Cycle, MPa/°C/°C (psig/ ° F/ ° F) 12.4/566/566 (1800/1050/1050) 12.4/538/538 (1800/1000/1000) Condenser Pressure, mm Hg (in Hg) 51 (2.0) 51 (2.0)

Combustion Turbine 2x Advanced F Class (232 MW output each) 2x Advanced F Class (232 MW output each) Gasifier Technology CoP E-GasTM CoP E-GasTM Oxidant 95 vol% Oxygen 95 vol% Oxygen
Coal Illinois No. 6 Illinois No. 6 Coal Slurry Solids Conent, % 63 63 COS Hydrolysis Yes Occurs in SGS
Sour Gas Shift No Yes
H 2 

### S Separation Refrigerated MDEA Selexol 1 st 

### Stage Sulfur Removal, % 99.5 99.7

Sulfur Recovery Claus Plant with Tail Gas Recycle to Gasifier/

Elemental Sulfur Claus Plant with Tail Gas Recycle to Gasifier/

Elemental Sulfur

Particulate Control Cyclone, Candle Filter, Scrubber, and AGR Absorber Cyclone, Candle Filter, Scrubber, and AGR Absorber Mercury Control Carbon Bed Carbon Bed

NOx Control MNQC (LNB), N 2 

### Dilution and Humidification MNQC (LNB), N 2 

### Dilution and Humidification

CO 2 

### Separation N/A Selexol 2 nd 

### Stage
CO 2 

### Capture N/A 88.4% from Syngas
CO 2 

### Sequestration N/A Off-site Saline FormationCost and Performance Comparison of Fossil Energy Power Plants

167 

### 3.3.5 C ASE 

### 3 P ERFORMANCE 

### R ESULTS 

### The plant produces a net output of 623 MWe at a net plant efficiency of 39.3 percent (HHV basis). CoP recently reported the same efficiency for their gasifi er using Illinois No. 6 coal and an amine based AGR. [ 49] Overall performance for the entire plant is summarized in Exhibit 3-51 which includes auxiliary power requirements. The ASU accounts for ove r 76 percent of the to tal auxiliary load distributed between the main air compressor, the oxygen compressor, the nitrogen compressor, and ASU auxiliaries. The cooling water syst em, including the circulating water pumps and cooling tower fan, accounts for over 4 percent of the auxiliary load, and the BFW pumps account for an additional 3.6 percent. All other individual auxiliary loads are less than 3 percent of the total.Cost and Performance Comparison of Fossil Energy Power Plants

168 

### Exhibit 3-51 Case 3 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Gas Turbine Power 464,030 Steam Turbine Power 278,480 TOTAL POWER, kWe 742,510 AUXILIARY LOAD SUMMARY, kWe Coal Handling 440 Coal Milling 2,160 Coal Slurry Pumps 570 Slag Handling and Dewatering 1,110 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 47,130 Oxygen Compressor 8,240 Nitrogen Compressor 34,680 Syngas Recycle Blower 2,130 Tail Gas Recycle Blower 1,760 Boiler Feedwater Pumps 4,280 Condensate Pump 220 Flash Bottoms Pump 200 Circulating Water Pumps 3,350 Cooling Tower Fans 1,730 Scrubber Pumps 70 SS Amine Unit Auxiliaries 3,230 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 200 Miscellaneous Balance of Plant (Note 1) 3,000 Transformer Loss 2,540 TOTAL AUXILIARIES, kWe 119,140 NET POWER, kWe 623,370 Net Plant Efficiency, % (HHV) 39.3 Net Plant Heat Rate (Btu/kWh) 8,681 CONDENSER COOLING DUTY 10 6 

### kJ/h (10 6 

### Btu/h) 1,468 (1,393) CONSUMABLES As-Received Coal Feed, kg/h (lb/h) 210,417 (463,889) Thermal Input, kWt 1,586,023 Raw Water Usage, m 3 

### /min (gpm) 14.2 (3,757) Note 1: Includes plant control systems, ligh ting, HVAC and miscellaneous low voltage loadsCost and Performance Comparison of Fossil Energy Power Plants

169 

### Environmental Performance The environmental targets for emissions of Hg, NOx, SO 2 

### and particulate matter were presented in Section 2.4. A summary of the plant ai r emissions for Case 3 is presented in Exhibit 3-52.

Exhibit 3-52 Case 3 Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 80% capacity factor kg/MWh (lb/MWh)

SO 2 

### 0.0054 (0.0125) 215 (237) 0.041 (0.091) NO X 

### 0.026 (0.059) 1,021 (1,126) 0.196 (0.433) Particulates 0.003 (0.0071) 122 (135) 0.023 (0.052)
Hg 0.25x10 -6 

### (0.57x10 -6 

### ) 0.010 (0.011) 1.9x10 -6 

### (4.2x10 -6 

### )

CO 2 

### 85.7 (199) 3,427,000 (3,778,000) 659 (1,452)

CO 2 1 

### 785 (1,730)

1 

### CO 2 

### emissions based on net power instead of gross power
The low level of SO 2 

### in the plant emissions is achieved by capture of the sulfur in the gas by the refrigerated Coastal SS Amine AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel gas down to a leve l of less than 30 ppmv. This results in a concentration in the flue gas of less than 4 ppmv. The H 2 

### S-rich regeneration gas from the AGR system is fed to a Claus plant, producing el emental sulfur. The Claus plant tail gas is hydrogenated to convert a ll sulfur species to H 2 

### S and then recycled back to the gasifier, thereby eliminating the need for a tail gas treatment unit.
NO X 

### emissions are limited by the use of nitrogen dilution (primarily) and humidification (to a lesser extent) to 15 ppmvd (as NO 2 

### @ 15 percent O 2 

### ). Ammonia in the syngas is removed with process condensate prior to the low-temperatur e AGR process and destroyed in the Claus plant burner. This helps lower NO X 

### levels as well. Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only. Ninety five percent of the mercury is capture d from the syngas by an activated carbon bed. CO 2 

### emissions represent the uncontro lled discharge from the process. The carbon balance for the plant is shown in Exhibit 3-53. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in th e air is not neglected here since the Aspen model accounts for air components th roughout. Carbon leaves the plant as unburned carbon in the slag, as dissolved CO 2 

### in the wastewater blowdown stream, and CO 2 

### in the stack gas and ASU vent gas. Carbon in the wastewater blowdown stream is calculated by difference to close the material balance.Cost and Performance Comparison of Fossil Energy Power Plants

170 

### Exhibit 3-53 Case 3 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) Coal 134,141 (295,729) Slag 1,006 (2,218) Air (CO 2 

### ) 465 (1,026) Stack Gas 133,374 (294,039) ASU Vent 94 (207) Wastewater 132 (291) Total 134,606 (296,755) Total 134,606 (296,755)

Exhibit 3-54 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output incl udes the sulfur recovered in the Claus plant, dissolved SO 2 

### in the wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible, and the sulfur content of the blowdown stream is calculated by difference to close the material balance. The to tal sulfur capture is re presented by the following fraction: (Sulfur byproduct/Sulfur in the coal) or (11,591/11,644) or 99.5 percent

Exhibit 3-54 Case 3 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) Coal 5,281 (11,644) Elemental Sulfur 5,257 (11,591) Stack Gas 15 (34) Wastewater 9 (19) Total 5,281 (11,644) Total 5,281 (11,644)

Exhibit 3-55 shows the overall water balance for the plant. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the total amount of water required for a particular process. Some water is recovered within the process, primarily as syngas condens ate, and that water is re-used as internal recycle. Raw water makeup is the difference between wa ter demand and internal recycle.Cost and Performance Comparison of Fossil Energy Power Plants

171 

### Exhibit 3-55 Case 3 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle,

m 3 

### /min (gpm) Raw Water Makeup,

m 3 

### /min (gpm)
Slurry 1.4 (381) 1.1 (292) 0.3 (89)
Slag Handling 0.5 (123) 0 0.5 (123)
Syngas Humidifier 0.5 (133) 0 0.5 (133)
BFW Makeup 0.2 (40) 0 0.2 (40)
Cooling Tower Makeup 13.0 (3,442) 0.3 (70) 12.7 (3,372)

Total 15.6 (4,119) 1.4 (362) 14.2 (3,757)

Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-56 through Exhibit 3-60:

• Coal gasification and air separation unit

• Syngas cleanup

• Sulfur recovery and tail gas recycle

• Combined cycle power generation

• Steam and feedwater An overall plant energy balance is provided in tabular form in Exhibit 3-61. The power out is the combined combustion turbine and steam turbin e power prior to generator losses. The power at the generator terminals (shown in Exhibit 3-51) is calculated by multiplying the power out by a combined generator efficiency of 98.3 percent.Cost and Performance Comparison of Fossil Energy Power Plants

172 

### This page intentionally left blankCost and Performance Comparisonof Fossil Energy Power Plants173Exhibit 3-56 Case 3 Coal Gasification and AirSeparation Unit Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants174Exhibit 3-57 Case 3 Syngas Cleanup Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants175Exhibit 3-58 Case 3 Sulfur Recovery and Tail Gas Recycle Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants176Exhibit 3-59 Case 3 Combined Cycle PowerGeneration Heat andMass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants177Exhibit 3-60 Case 3 Steam and Feedwater Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants178This page intentionally left blankCost and Performance Comparison of Fossil Energy Power Plants

179 

### Exhibit 3-61 Case 3 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total
Heat In (MMBtu/hr) Coal 5,411.7 4.5 5,416.2 ASU Air 15.9 15.9 CT Air 96.7 96.7 Water 4.3 4.3 Auxiliary Power 406.5 406.5 Totals 5,411.7 121.3 406.5 5,939.6 Heat Out (MMBtu/hr) ASU Intercoolers 203.0 203.0 ASU Vent 1.4 1.4 Slag 31.3 21.6 52.9 Sulfur 46.2 (1.1) 45.0 Tail Gas Compressor Intercoolers 6.3 6.3
HRSG Flue Gas 928.0 928.0 Condenser 1,393.0 1,393.0 Process Losses 732.1 732.1 Power 2,577.9 2,577.9 Totals 77.5 3,284.2 2,577.9 5,939.6 (1) Process Losses are calculated by differen ce and reflect various gasification, turbine, HRSG and other heat and work losses. Aspe n flowsheet balance is within 0.5 percent.Cost and Performance Comparison of Fossil Energy Power Plants

180 

### 3.3.6 C ASE 

### 3

- M AJOR 

### E QUIPMENT 

### L IST 

### Major equipment items for the CoP gasifier with no CO 2 

### capture are shown in the following tables. The accounts used in the equipment lis t correspond to the account numbers used in the cost estimates in Section 3.3.7. In general, the design c onditions include a 10 percent contingency for flows and heat duties and a 21 pe rcent contingency for heads on pumps and fans.
ACCOUNT 1 COAL HANDLING

Equipment No. Description Type Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0
3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0
5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0
8 Reclaim Hopper N/A 2 1
9 Feeder Vibratory 2 1
10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor reduction 2 0

14 As-Fired Coal Sampling System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0

17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 3 0 N/A

345 tonne/h (380 tph)

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph) N/A
1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)
1,134 tonne/h (1,250 tph)

45 tonne (50 ton)
172 tonne/h (190 tph)

8 cm x 0 - 3 cm x 0 (3" x 0 - 1-1/4" x 0) 345 tonne/h (380 tph)

172 tonne (190 ton) N/A

N/A

345 tonne/h (380 tph)

816 tonne (900 ton)Cost and Performance Comparison of Fossil Energy Power Plants

181 

### ACCOUNT 2 COAL PREPARATION AND FEED
Equipment No. Description Type Operating Qty. Spares

1 Feeder Vibratory 3 0
2 Conveyor No. 6 Belt w/tripper 1 0
3 Rod Mill Feed Hopper Dual Outlet 1 0
4 Weigh Feeder Belt 2 0
5 Rod Mill Rotary 2 0

6 Slurry Water Storage Tank with Agitator Field erected 2 0

7 Slurry Water Pumps Centrifugal 2 2

10 Trommel Screen Coarse 2 0

11 Rod Mill Discharge Tank with Agitator Field erected 2 0

12 Rod Mill Product Pumps Centrifugal 2 2

13 Slurry Storage Tank with Agitator Field erected 2 0

14 Slurry Recycle Pumps Centrifugal 2 2

15 Slurry Product Pumps Positive displacement 2 2 Design Condition

82 tonne/h (90 tph)
236 tonne/h (260 tph)
463 tonne (510 ton)
118 tonne/h (130 tph)

303,592 liters (80,200 gal)

2,536 lpm (670 gpm) 795 lpm (210 gpm) 118 tonne/h (130 tph)

283,908 liters (75,000 gal)

163 tonne/h (180 tph)

2,536 lpm (670 gpm) 5,072 lpm (1,340 gpm) 908,506 liters (240,000 gal)Cost and Performance Comparison of Fossil Energy Power Plants

182 

### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 2 0

2 Condensate Pumps Vertical canned 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multistage, centrifugal 2 1

7 Auxiliary Boiler Shop fabricated, water tube 1 0

8 Service Air Compressors Flooded Screw 2 1

9 Instrument Air Dryers Duplex, regenerative 2 1

10 Closed Cylce Cooling Heat Exchangers Plate and frame 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 2 1

12 Engine-Driven Fire Pump Vertical turbine, diesel engine 1 1

13 Fire Service Booster Pump Two-stage horizontal centrifugal 1 1

14 Raw Water Pumps Stainless steel, single suction 2 1

15 Filtered Water Pumps Stainless steel, single suction 2 1

16 Filtered Water Tank Vertical, cylindrical 2 0

17 Makeup Water Demineralizer Anion, cation, and mixed bed 2 0

18 Liquid Waste Treatment System 1 0 2 1 5 High Pressure Feedwater Pump No. 1 Barrel type, multistage, centrifugal

715,448 liter (189,000 gal)

151 lpm (40 gpm)

10 years, 24-hour storm 1,476 lpm @ 49 m H2O (390 gpm @ 160 ft H2O) 28 m3/min (1,000 scfm)

58 MMkJ/h (55 MMBtu/h) each
20,820 lpm @ 21 m H2O (5,500 gpm @ 70 ft H2O) 3,785 lpm @ 107 m H2O (1,000 gpm @ 350 ft H2O)

2,650 lpm @ 76 m H2O (700 gpm @ 250 ft H2O) 7,912 lpm @ 18 m H2O (2,090 gpm @ 60 ft H2O) 1,325 lpm @ 283 m H2O (350 gpm @ 930 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C (40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) Design Condition

1,101,563 liters (291,000 gal)

6,132 lpm @ 91 m H2O (1,620 gpm @ 300 ft H2O)

463,118 kg/h (1,021,000 lb/h)

IP water: 909 lpm @ 390 m H2O (240 gpm @ 1,280 ft H2O) HP water: 6,511 lpm @ 1,890 m

H2O (1,720 gpm @ 6,200 ft H2O)Cost and Performance Comparison of Fossil Energy Power Plants

183 

### ACCOUNT 4 GASIFIER, ASU AND ACC ESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION
Equipment No. Description Type Operating Qty. Spares

1 Gasifier Pressurized two-stage, slurry-feed entrained bed 2 0

2 Synthesis Gas Cooler Fire-tube boiler 2 0

3 Synthesis Gas Cyclone High efficiency 2 0

4 Candle Filter Pressurized filter with pulse-jet cleaning 2 0

5 Syngas Scrubber Including Sour Water Stripper Vertical upflow 2 0

6 Raw Gas Coolers Shell and tube with condensate drain 6 0

7 Raw Gas Knockout Drum Vertical with mist eliminator 2 0

8 Saturation Water Economizers Shell and tube 2 0

9 Fuel Gas Saturator Vertical tray tower 2 0

10 Saturator Water Pump Centrifugal 2 2

11 Synthesis Gas Reheater Shell and tube 2 0

12 Flare Stack Self-supporting, carbon steel, stainless steel top, pilot ignition 2 0

13 ASU Main Air Compressor Centrifugal, multistage 2 0

14 Cold Box Vendor design 2 0

15 Oxygen Compressor Centrifugal, multistage 2 0

16 Nitrogen Compressor Centrifugal, multistage 2 0

17 Nitrogen Boost Compressor Centrifugal, multistage 2 0

18 Extraction Air Heat Exchanger Gas-to-gas, vendor design 2 0 metallic filters

298,464 kg/h (658,000 lb/h)

275,784 kg/h (608,000 lb/h)

266,259 kg/h, 39°C, 3.6 MPa (587,000 lb/h, 103°F, 515 psia) Design Condition

2,812 tonne/day, 4.2 MPa (3,100 tpd, 615 psia)

304,361 kg/h (671,000 lb/h)

291,660 kg/h (643,000 lb/h) Design efficiency 90%

275,784 kg/h (608,000 lb/h)
201,395 kg/h, 130°C, 3.3 MPa (444,000 lb/h, 266°F, 484 psia) 4,543 lpm @ 201 m H2O (1,200 gpm @ 660 ft H2O)
215,457 kg/h (475,000 lb/h)

481 m3/min @ 2.3 MPa (17,000 scfm @ 340 psia) 86,636 kg/h, 433°C, 1.6 MPa (191,000 lb/h, 811°F, 235 psia)

298,464 kg/h (658,000 lb/h)
syngas 4,134 m3/min @ 1.3 MPa (146,000 scfm @ 190 psia)
2,177 tonne/day (2,400 tpd) of 95% purity oxygen
1,076 m3/min @ 5.1 MPa (38,000 scfm @ 740 psia) 3,540 m3/min @ 3.4 MPa (125,000 scfm @ 490 psia)Cost and Performance Comparison of Fossil Energy Power Plants

184 

### ACCOUNT 5 SYNGAS CLEANUP
Equipment No. Description Type Operatin g Qty. Spares

1 Mercury Adsorber Sulfated carbon bed 2 0

2 Sulfur Plant Claus type 1 0

3 COS Hydrolysis Reactor Fixed bed, catalytic 2 0

4 Acid Gas Removal Plant MDEA 2 0

5 Hydrogenation Reactor Fixed bed, catalytic 1 0

6 Tail Gas Recycle Compressor Centrifugal 1 0 Design Condition

234,054 kg/h (516,000 lb/h) 39°C (103°F) 3.4 MPa (495 psia)

139 tonne/day (153 tpd)

298,464 kg/h (658,000 lb/h) 204°C (400°F) 3.8 MPa (555 psia)

21,772 kg/h @ 6.6 MPa (48,000 lb/h @ 950 psia) 213,642 kg/h (471,000 lb/h) 39°C (103°F) 3.3 MPa (485 psia)

25,401 kg/h (56,000 lb/h) 232°C (450°F) 0.2 MPa (25 psia)



### ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES
Equipment No. Description Type Operating Qty. Spares

1 Gas Turbine Advanced F class 2 0

2 Gas Turbine Generator TEWAC 2 0 Design Condition

232 MW
260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase



### ACCOUNT 7 HRSG, ST ACK AND DUCTING

Equipment No. Description Type Operating Qty. Spares

1 Stack CS plate, type 409SS liner 1 0

2 0 2 Heat Recovery Steam Generator Drum, multi-pressure with economizer section and integral deaerator Reheat steam - 361,875 kg/h, 2.9 MPa/566°C (797,796 lb/h, 420 psig/1,050°F) Design Condition

76 m (250 ft) high x 8.3 m (27 ft) diameter

Main steam - 368,554 kg/h, 12.4 MPa/566°C (812,522 lb/h, 1,800 psig/1,050°F)Cost and Performance Comparison of Fossil Energy Power Plants

185 

### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitiation 1 0

3 Steam Bypass One per HRSG 2 0

4 Surface Condenser Single pass, divided waterbox including
vacuum pumps 1 0 293 MW 12.4 MPa/566°C/566°C (1800 psig/ 1050°F/1050°F)

1,613 MMkJ/h (1,530 MMBtu/h), Inlet water temperature 16°C (60°F),

Water temperature rise 11°C (20°F) 330 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase

50% steam flow @ design steam conditions Design Condition



### ACCOUNT 9 COOLING WATER SYSTEM
Equipment No. Description Type Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 1 0 Design Condition
336,904 lpm @ 30 m (89,000 gpm @ 100 ft) 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT, 1,876 MMkJ/h (1,780 MMBtu/h) heat dutyCost and Performance Comparison of Fossil Energy Power Plants

186 

### ACCOUNT 10 SLAG RECOVERY AND HANDLING
Equipment No. Description Type Operating Qty. Spares

1 Slag Quench Tank Water bath 2 0
2 Slag Crusher Roll 2 0
3 Slag Depressurizer Proprietary 2 0
4 Slag Receiving Tank Horizontal, weir 2 0
5 Black Water Overflow Tank Shop fabricated 2
6 Slag Conveyor Drag chain 2 0
7 Slag Separation Screen Vibrating 2 0
8 Coarse Slag Conveyor Belt/bucket 2 0
9 Fine Ash Settling Tank Vertical, gravity 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 2 2

11 Grey Water Storage Tank Field erected 2 0

12 Grey Water Pumps Centrifugal 2 2

13 Grey Water Recycle Heat Exchanger Shell and tube 2 0

14 Slag Storage Bin Vertical, field erected 2 0

15 Unloading Equipment Telescoping chute 1 0 Design Condition

223,341 liters (59,000 gal)
12 tonne/h (13 tph)
12 tonne/h (13 tph)
147,632 liters (39,000 gal)

12 tonne/h (13 tph)
12 tonne/h (13 tph)
12 tonne/h (13 tph) 68,138 liters (18,000 gal)

219,556 liters (58,000 gal)

38 lpm @ 14 m H2O (10 gpm @ 46 ft H2O)

816 tonne (900 tons)

100 tonne/h (110 tph) 71,923 liters (19,000 gal)

265 lpm @ 433 m H2O (70 gpm @ 1,420 ft H2O)

15,876 kg/h (35,000 lb/h)Cost and Performance Comparison of Fossil Energy Power Plants

187 

### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type Operating Qty. Spares

1 CTG Transformer Oil-filled 2 0

3 Auxiliary Transformer Oil-filled 1 1

4 Low Voltage Transformer Dry ventilated 1 1

5 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 2 0

6 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 1 0

7 Medium Voltage Switchgear Metal clad 1 1

8 Low Voltage Switchgear Metal enclosed 1 1

9 Emergency Diesel Generator Sized for emergency shutdown 1 0 750 kW, 480 V, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz 1 0

24 kV/4.16 kV, 130 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 19 MVA, 3-ph, 60 Hz Design Condition

24 kV/345 kV, 260 MVA, 3-ph, 60 Hz

2 STG Transformer Oil-filled 24 kV/345 kV, 190 MVA, 3-ph, 60 Hz



### ACCOUNT 12 INSTRUMENTATION AND CONTROLS

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) 1 0

3 DCS - Data Highway Fiber optic 1 0 Design Condition

Operator stations/printers and engineering stations/printers

2 DCS - Processor Microprocessor with redundant input/output N/A 1 0

Fully redundant, 25% spareCost and Performance Comparison of Fossil Energy Power Plants

188 

### 3.3.7 C ASE 

### 3

- C OSTS 

### E STIMATING 

### R ESULTS 

### The cost estimating methodology was desc ribed previously in Section 2.6. Exhibit 3-62 shows the total plant capital cost summary organized by cost account and Exhibit 3-63 shows a more detailed breakdown of the capital costs. Exhibit 3-64 shows the ini tial and annual O&M costs. The estimated TPC of the CoP gasifier with no CO 2 

### capture is $1,733/kW. Process contingency represents 2.5 percent of the TP C and project contingency is 13.3 percent. The 20-year LCOE is 75.3 mills/kWh.Cost and Performance Comparisonof Fossil Energy Power Plants189Exhibit 3-62 Case 3 Total Plant Cost SummaryClient:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 03 - ConocoPhillips IGCC w/o CO2Plant Size:623.4 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING $13,060 $2,435 $10,233 $0 $0$25,728$2,088 $0 $5,563$33,379$542 COAL & SORBENT PREP & FEED $22,211 $4,065 $13,559 $0 $0$39,835$3,200 $0 $8,607$51,642$833 FEEDWATER & MISC. BOP SYSTEMS $9,148 $7,886 $8,644 $0 $0$25,678$2,149 $0 $6,278$34,105$554 GASIFIER & ACCESSORIES4.1 Gasifier, Syngas Cooler & Auxiliaries $90,425 $0 $55,527 $0 $0$145,952$11,971 $21,893 $26,972$206,789$3324.2 Syngas Cooling (w/4.1) w/4.1 $0 w/4.1 $0 $0$0$0 $0 $0$0$04.3 ASU/Oxidant Compression $137,711 $0 w/equip. $0 $0$137,711$11,743 $0 $14,945$164,399$2644.4-4.9 Other Gasification Equipment $18,487 $8,580 $11,695 $0 $0$38,763$3,285 $0 $9,043$51,091$82SUBTOTAL 4 $246,624 $8,580 $67,222 $0 $0 $322,427 $26,999 $21,893 $50,961 $422,279 $6775A Gas Cleanup & Piping $50,895 $4,805 $38,080 $0 $0$93,780$8,032 $104 $20,588$122,504$1975BCO2REMOVAL & COMPRESSION$0 $0 $0 $0 $0$0$0 $0 $0$0$06 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator $82,000 $0 $5,071 $0 $0$87,071$7,338 $4,354 $9,876$108,639$1746.2-6.9 Combustion Turbine Other $0 $684 $762 $0 $0$1,446$121 $0 $470$2,037$3SUBTOTAL 6 $82,000 $684 $5,833 $0 $0 $88,517 $7,459 $4,354 $10,346 $110,676 $1787 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator $33,926 $0 $4,828 $0 $0$38,754$3,277 $0 $4,203$46,234$747.2-7.9 Ductwork and Stack $3,123 $2,198 $2,918 $0 $0$8,239$682 $0 $1,450$10,371$17SUBTOTAL 7 $37,049 $2,198 $7,745 $0 $0 $46,992 $3,959 $0 $5,653 $56,604 $918 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $28,109 $0 $4,930 $0 $0$33,039$2,837 $0 $3,588$39,463$638.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,092 $953 $7,185 $0 $0$18,229$1,473 $0 $3,969$23,671$38SUBTOTAL 8 $38,201 $953 $12,115 $0 $0 $51,268 $4,310 $0 $7,556 $63,135 $1019 COOLING WATER SYSTEM $6,760 $7,303 $6,124 $0 $0$20,187$1,661 $0 $4,492$26,340$4210 ASH/SPENT SORBENT HANDLING SYS $18,173 $1,373 $9,021 $0 $0$28,568$2,437 $0 $3,382$34,386$5511 ACCESSORY ELECTRIC PLANT $22,608 $9,796 $19,825 $0 $0$52,229$4,054 $0 $10,733$67,016$10812 INSTRUMENTATION & CONTROL $9,358 $1,752 $6,282 $0 $0$17,391$1,436 $870 $3,296$22,992$3713 IMPROVEMENTS TO SITE $3,155 $1,860 $7,843 $0 $0$12,858$1,132 $0 $4,197$18,186$2914 BUILDINGS & STRUCTURES $0 $6,209 $7,240 $0 $0$13,449$1,095 $0 $2,378$16,922$27TOTAL COST $559,240 $59,898 $219,767 $0 $0 $838,905 $70,010 $27,220 $144,031 $1,080,166 $1,733TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants190Exhibit 3-63 Total Plant Cost DetailsClient:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 03 - ConocoPhillips IGCC w/o CO2Plant Size:623.4 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING1.1 Coal Receive & Unload $3,430 $0 $1,693 $0 $0 $5,123 $411 $0 $1,107 $6,641 $111.2 Coal Stackout & Reclaim $4,432 $0 $1,086 $0 $0 $5,517 $433 $0 $1,190 $7,141 $111.3 Coal Conveyors $4,120 $0 $1,074 $0 $0 $5,195 $409 $0 $1,121 $6,724 $111.4 Other Coal Handling $1,078 $0 $249 $0 $0 $1,327 $104 $0 $286 $1,717 $31.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.9 Coal & Sorbent Hnd.Foundations $0 $2,435 $6,132 $0 $0 $8,566 $731 $0 $1,860 $11,157 $18SUBTOTAL 1. $13,060 $2,435 $10,233 $0 $0 $25,728 $2,088 $0 $5,563 $33,379 $542 COAL & SORBENT PREP & FEED2.1 Coal Crushing & Drying incl w/2.3 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.2 Prepared Coal Storage & Feed $1,462 $348 $232 $0 $0 $2,042 $157 $0 $440 $2,638 $42.3 Slurry Prep & Feed $19,945 $0 $8,962 $0 $0 $28,908 $2,310 $0 $6,244 $37,462 $602.4 Misc.Coal Prep & Feed $804 $582 $1,772 $0 $0 $3,158 $259 $0 $684 $4,101 $72.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.9 Coal & Sorbent Feed Foundation $0 $3,135 $2,592 $0 $0 $5,727 $473 $0 $1,240 $7,441 $12SUBTOTAL 2. $22,211 $4,065 $13,559 $0 $0 $39,835 $3,200 $0 $8,607 $51,642 $833 FEEDWATER & MISC. BOP SYSTEMS3.1 FeedwaterSystem $3,088 $5,369 $2,836 $0 $0 $11,293 $934 $0 $2,445 $14,672 $243.2 Water Makeup & Pretreating $502 $52 $280 $0 $0 $834 $71 $0 $271 $1,176 $23.3 Other FeedwaterSubsystems $1,705 $578 $521 $0 $0 $2,804 $225 $0 $606 $3,634 $63.4 Service Water Systems $289 $590 $2,049 $0 $0 $2,928 $254 $0 $955 $4,137 $73.5 Other Boiler Plant Systems $1,553 $596 $1,478 $0 $0 $3,626 $305 $0 $786 $4,717 $83.6 FO Supply Sys & Nat Gas $299 $565 $527 $0 $0 $1,391 $119 $0 $302 $1,812 $33.7 Waste Treatment Equipment $697 $0 $427 $0 $0 $1,124 $98 $0 $367 $1,588 $33.8 Misc. Equip.(cranes,AirComp.,Comm.) $1,015 $136 $526 $0 $0 $1,678 $145 $0 $547 $2,369 $4SUBTOTAL 3. $9,148 $7,886 $8,644 $0 $0 $25,678 $2,149 $0 $6,278 $34,105 $554 GASIFIER & ACCESSORIES4.1 Gasifier, Syngas Cooler & Auxiliaries(E-GAS)$90,425 $0 $55,527 $0 $0 $145,952 $11,971 $21,893 $26,972 $206,789 $3324.2 Syngas Cooling ( w/ 4.1) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.3 ASU/Oxidant Compression $137,711 $0 w/equip. $0 $0 $137,711 $11,743 $0 $14,945 $164,399 $2644.4 LT Heat Recovery & FG Saturation $18,487 $0 $6,956 $0 $0 $25,443 $2,191 $0 $5,527 $33,160 $534.5 Misc. Gasification Equipment w/4.1 & 4.2 w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $04.6 Other Gasification Equipment $0 $1,142 $465 $0 $0 $1,607 $137 $0 $349 $2,092 $34.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $04.9 Gasification Foundations $0 $7,439 $4,275 $0 $0 $11,713 $957 $0 $3,168 $15,838 $25SUBTOTAL 4. $246,624 $8,580 $67,222 $0 $0 $322,427 $26,999 $21,893 $50,961 $422,279 $677TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants191Exhibit 3-63 Total Plant Cost Details (continued)Client:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 03 - ConocoPhillips IGCC w/o CO2Plant Size:623.4 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material LaborSales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW5A GAS CLEANUP & PIPING5A.1 MDEA-LT AGR $34,245 $0 $16,003 $0 $0 $50,248 $4,291 $0 $10,908 $65,447 $1055A.2 Elemental Sulfur Plant $11,411 $2,265 $14,734 $0 $0 $28,410 $2,454 $0 $6,173 $37,037 $595A.3 Mercury Removal $1,177 $0 $897 $0 $0 $2,074 $178 $104 $471 $2,827 $55A.4 COS Hydrolysis $3,651 $0 $4,771 $0 $0 $8,422 $728 $0 $1,830 $10,980 $185A.5 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.6 Blowback Gas Systems $410 $230 $130 $0 $0 $770 $65 $0 $167 $1,002 $25A.7 Fuel Gas Piping $0 $1,161 $800 $0 $0 $1,961 $160 $0 $424 $2,546 $45A.9 HGCU Foundations $0 $1,149 $746 $0 $0 $1,895 $155 $0 $615 $2,666 $4SUBTOTAL 5A. $50,895 $4,805 $38,080 $0 $0 $93,780 $8,032 $104 $20,588 $122,504 $1975B CO2 REMOVAL & COMPRESSION5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator $82,000 $0 $5,071 $0 $0 $87,071 $7,338 $4,354 $9,876 $108,639 $1746.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.9 Combustion Turbine Foundations $0 $684 $762 $0 $0 $1,446 $121 $0 $470 $2,037 $3SUBTOTAL 6. $82,000 $684 $5,833 $0 $0 $88,517 $7,459 $4,354 $10,346 $110,676 $1787 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator $33,926 $0 $4,828 $0 $0 $38,754 $3,277 $0 $4,203 $46,234 $747.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07.3 Ductwork $0 $1,577 $1,143 $0 $0 $2,719 $214 $0 $587 $3,520 $67.4 Stack $3,123 $0 $1,174 $0 $0 $4,296 $366 $0 $466 $5,129 $87.9 HRSG,Duct & Stack Foundations $0 $622 $601 $0 $0 $1,223 $102 $0 $397 $1,722 $3SUBTOTAL 7. $37,049 $2,198 $7,745 $0 $0 $46,992 $3,959 $0 $5,653 $56,604 $918 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $28,109 $0 $4,930 $0 $0 $33,039 $2,837 $0 $3,588 $39,463 $638.2 Turbine Plant Auxiliaries $198 $0 $455 $0 $0 $654 $57 $0 $71 $782 $18.3 Condenser & Auxiliaries $4,660 $0 $1,421 $0 $0 $6,082 $517 $0 $660 $7,259 $128.4 Steam Piping $5,233 $0 $3,687 $0 $0 $8,920 $682 $0 $2,400 $12,002 $198.9 TG Foundations $0 $953 $1,621 $0 $0 $2,574 $217 $0 $837 $3,629 $6SUBTOTAL 8. $38,201 $953 $12,115 $0 $0 $51,268 $4,310 $0 $7,556 $63,135 $1019 COOLING WATER SYSTEM9.1 Cooling Towers $4,397 $0 $967 $0 $0 $5,364 $455 $0 $873 $6,692 $119.2 Circulating Water Pumps $1,383 $0 $86 $0 $0 $1,469 $113 $0 $237 $1,819 $39.3 Circ.Water System Auxiliaries $116 $0 $17 $0 $0 $132 $11 $0 $22 $165 $09.4 Circ.Water Piping $0 $4,910 $1,253 $0 $0 $6,163 $489 $0 $1,330 $7,982 $139.5 Make-up Water System $284 $0 $403 $0 $0 $688 $58 $0 $149 $895 $19.6 Component Cooling Water Sys $579 $693 $490 $0 $0 $1,762 $146 $0 $382 $2,290 $49.9 Circ.Water System Foundations& Structures $0 $1,699 $2,909 $0 $0 $4,608 $389 $0 $1,499 $6,497 $10SUBTOTAL 9. $6,760 $7,303 $6,124 $0 $0 $20,187 $1,661 $0 $4,492 $26,340 $4210 ASH/SPENT SORBENT HANDLING SYS10.1 Slag Dewatering & Cooling $15,861 $0 $7,828 $0 $0 $23,688 $2,024 $0 $2,571 $28,283 $4510.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.6 Ash Storage Silos $523 $0 $569 $0 $0 $1,092 $94 $0 $178 $1,365 $210.7 Ash Transport & Feed Equipment $706 $0 $169 $0 $0 $876 $72 $0 $142 $1,090 $210.8 Misc. Ash Handling Equipment $1,083 $1,327 $397 $0 $0 $2,807 $238 $0 $457 $3,502 $610.9 Ash/Spent Sorbent Foundation $0 $46 $58 $0 $0 $104 $9 $0 $34 $147 $0SUBTOTAL 10. $18,173 $1,373 $9,021 $0 $0 $28,568 $2,437 $0 $3,382 $34,386 $55TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants192Exhibit 3-63 Total Plant Cost Details (continued)Client:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 03 - ConocoPhillips IGCC w/o CO2Plant Size:623.4 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW11 ACCESSORY ELECTRIC PLANT11.1 Generator Equipment $901 $0 $899 $0 $0 $1,800 $153 $0 $195 $2,148 $311.2 Station Service Equipment $3,498 $0 $328 $0 $0 $3,827 $326 $0 $415 $4,568 $711.3 Switchgear & Motor Control $6,686 $0 $1,226 $0 $0 $7,911 $657 $0 $1,285 $9,853 $1611.4 Conduit & Cable Tray $0 $3,181 $10,327 $0 $0 $13,508 $1,157 $0 $3,666 $18,331 $2911.5 Wire & Cable $0 $5,842 $3,930 $0 $0 $9,772 $640 $0 $2,603 $13,015 $2111.6 Protective Equipment $0 $624 $2,365 $0 $0 $2,989 $262 $0 $488 $3,739 $611.7 Standby Equipment $215 $0 $218 $0 $0 $433 $37 $0 $71 $541 $111.8 Main Power Transformers $11,308 $0 $138 $0 $0 $11,446 $776 $0 $1,833 $14,056 $2311.9 Electrical Foundations $0 $149 $394 $0 $0 $543 $46 $0 $177 $766 $1SUBTOTAL 11. $22,608 $9,796 $19,825 $0 $0 $52,229 $4,054 $0 $10,733 $67,016 $10812 INSTRUMENTATION & CONTROL12.1 IGCC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $012.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $012.4 Other Major Component Control $924 $0 $643 $0 $0 $1,566 $135 $78 $267 $2,047 $312.5 Signal Processing Equipment W/12.7 $0 W/12.7 $0 $0 $0 $0 $0 $0 $0 $012.6 Control Boards,Panels & Racks $212 $0 $142 $0 $0 $354 $31 $18 $80 $483 $112.7 Computer & Accessories $4,928 $0 $164 $0 $0 $5,092 $432 $255 $578 $6,357 $1012.8 Instrument Wiring & Tubing $0 $1,752 $3,666 $0 $0 $5,418 $412 $271 $1,525 $7,626 $1212.9 Other I & C Equipment $3,294 $0 $1,666 $0 $0 $4,960 $426 $248 $845 $6,480 $10SUBTOTAL 12. $9,358 $1,752 $6,282 $0 $0 $17,391 $1,436 $870 $3,296 $22,992 $3713 Improvements to Site13.1 Site Preparation $0 $99 $2,132 $0 $0 $2,231 $197 $0 $728 $3,156 $513.2 Site Improvements $0 $1,761 $2,357 $0 $0 $4,118 $362 $0 $1,344 $5,824 $913.3 Site Facilities $3,155 $0 $3,354 $0 $0 $6,509 $572 $0 $2,124 $9,206 $15SUBTOTAL 13. $3,155 $1,860 $7,843 $0 $0 $12,858 $1,132 $0 $4,197 $18,186 $2914 Buildings & Structures14.1 Combustion Turbine Area $0 $221 $127 $0 $0 $348 $27 $0 $75 $451 $114.2 Steam Turbine Building $0 $2,309 $3,334 $0 $0 $5,643 $464 $0 $916 $7,024 $1114.3 Administration Building $0 $793 $583 $0 $0 $1,375 $110 $0 $223 $1,708 $314.4 Circulation Water Pumphouse $0 $156 $84 $0 $0 $240 $19 $0 $39 $298 $014.5 Water Treatment Buildings $0 $399 $395 $0 $0 $794 $64 $0 $129 $987 $214.6 Machine Shop $0 $406 $281 $0 $0 $687 $55 $0 $111 $853 $114.7 Warehouse $0 $655 $428 $0 $0 $1,083 $86 $0 $175 $1,345 $214.8 Other Buildings & Structures $0 $392 $310 $0 $0 $702 $56 $0 $152 $910 $114.9 Waste Treating Building & Str. $0 $877 $1,698 $0 $0 $2,575 $214 $0 $558 $3,348 $5SUBTOTAL 14. $0 $6,209 $7,240 $0 $0 $13,449 $1,095 $0 $2,378 $16,922 $27TOTAL COST $559,240 $59,898 $219,767 $0 $0 $838,905 $70,010 $27,220 $144,031 $1,080,166 $1,733TOTAL PLANT COST SUMMARYCost and Performance Comparison of Fossil Energy Power Plants

193 

### Exhibit 3-64 Case 3 Initial and A nnual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006 Case 03 - ConocoPhillips 600MW IGCC w/o CO2 Heat Rate-net(Btu/kWh): 8,681 MWe-net: 623 Capacity Factor: (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 33.00 $/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 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 15.0 15.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $5,637,060 $9.043 Maintenance Labor Cost $11,924,540 $19.129 Administrative & Support Labor $4,390,400 $7.043 TOTAL FIXED OPERATING COSTS $21,951,999 $35.215 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $22,346,706 $0.00512

Consumables Consumption Unit Initial Initial /Day Cost Cost
Water(/1000 gallons) 0 5,410.08 1.03 $0 $1,627,136 $0.00037

Chemicals MU & WT Chem.(lb) 112,811 16,116 0.16 $18,591 $775,520 $0.00018 Carbon (Mercury Removal) (lb) 84,449 116 1.00 $84,449 $33,872 $0.00001 COS Catalyst (m3) 375 0.26 2,308.40 $865,651 $173,030 $0.00004 Water Gas Shift Catalyst(ft3) 0 0 475.00 $0 $0 $0.00000 Selexol Solution (gal.) 0 0 12.90 $0 $0 $0.00000 MDEA Solution (gal) 280 40 8.38 $2,345 $97,820 $0.00002 Sulfinol Solution (gal) 0 0 9.68 $0 $0 $0.00000 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. 2.10 125.00 $0 $76,650 $0.00002 Subtotal Chemicals $971,037 $1,156,892 $0.00026

Other Supplemental Fuel(MBtu) 0 0 0.00 $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) 0 116 0.40 $0 $13,603 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Bottom Ash(ton) 0 566 15.45 $0 $2,555,311 $0.00058 Subtotal-Waste Disposal $0 $2,568,914 $0.00059

By-products & Emissions Sulfur(tons) 0 139 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $971,037 $27,699,648 $0.00634

Fuel(ton) 166,992 5,566 42.11 $7,032,052 $68,445,302 $0.01567Cost and Performance Comparison of Fossil Energy Power Plants

194 

### 3.3.8 C ASE 

### 4

- E-G AS 

### TM IGCC P OWER 

### P LANT WITH 

### CO 2 

### C APTURE 

### This case is configured to produce electric power with CO 2 

### capture. The plant configuration is the same as Case 3, namely two gasifier trains , two advanced F class turbines, two HRSGs and one steam turbine. The gross power output from the plant is constrained by the capacity of the two combustion turbines, and since the CO 2 

### capture and compression process increases the auxiliary load on the plant, the net output is significantly reduced relative to Case 3. The process description for Case 4 is similar to Case 2 with several notable exceptions to accommodate CO 2 

### capture. A BFD and stream tables for Case 4 are shown in Exhibit 3-65 and Exhibit 3-66, respectively. Instead of repeating the entire process description, only differences from Case 3 are reported here.
Coal Preparation and Feed Systems
No differences from Case 3.

Gasification The gasification process is the same as Case 3 wi th the exception that total coal feed to the two gasifiers is 5,203 tonnes/day (5,735 TPD) (stream 6) and th e ASU provides 4,000 tonnes/day (4,420 TPD) of 95 mole percent oxygen to the gasifier and Claus plant (streams 5 and 3).
Raw Gas Cooling/Particulate Removal Raw gas cooling and particulate removal are th e same as Case 3 with the exception that approximately 483,170 kg/h (1,065,206 lb/h) of sa turated steam at 13.8 MPa (2,000 psia) is generated in the SGC.
Syngas Scrubber/Sour Water Stripper
No differences from Case 3.
Sour Gas Shift (SGS) The SGS process was described in Section 3.1.3. In Case 4 steam (stream 8) is added to the syngas exiting the scrubber to adjust the H 2 

### O:CO molar ratio to approximately 2:1 prior to the first WGS reactor. The hot syngas exiting the first stage of SGS is used to generate a portion of the steam that is added in stream 8. Two more st ages of SGS (for a tota l of three) result in 97.6 percent overall conversion of the CO to CO 2 

### . The syngas exiting the final stage of SGS still contains 2.4 vol% CH 4 

### which is subsequently oxidized to CO 2 

### in the CT and limits overall carbon capture to 88.4 percent. The warm syngas from the second stage of SGS is cooled to 232°C (450°F) by producing IP steam that is sent to the reheater in the HRSG. The SGS catalyst also serves to hydrolyze COS thus eliminating th e need for a separate COS hydrolysis reactor. Following the third stage of SGS, the syngas is further cooled to 35°C (95°F) prior to the mercury removal beds.
Mercury Removal and Acid Gas Removal Mercury removal is the same as in Case 3.Cost and Performance Comparisonof Fossil Energy Power Plants195Exhibit 3-65 Case 4 Process Flow Diagram, E-GasTM IGCC with CO2CaptureCost and Performance Comparisonof Fossil Energy Power Plants196Exhibit 3-66 Case 4 StreamTable, E-GasTM IGCC with CO2Capture123456A7 8 9 10 11V-L Mole FractionAr 0.0092 0.0263 0.0360 0.0023 0.0320 0.0000 0.0000 0.0000 0.0051 0.0065 0.0065CH40.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0238 0.0302 0.0302CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0052 0.0067 0.0067CO20.0003 0.0092 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3214 0.4122 0.4122COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000H20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.4116 0.5275 0.5275H2O0.0099 0.2713 0.0000 0.0004 0.0000 1.0000 0.0000 1.0000 0.2185 0.0014 0.0014H2S0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0051 0.0058 0.0058N20.7732 0.4665 0.0140 0.9919 0.0180 0.0000 0.0000 0.0000 0.0073 0.0094 0.0094NH30.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0019 0.0004 0.0004O20.2074 0.2266 0.9500 0.0054 0.9500 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000SO20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000V-L Flowrate (lbmol/hr)55,654 1,969 278 41,984 11,156 25,799 0 31,642 91,106 71,043 56,835V-L Flowrate (lb/hr) 1,606,000 52,498 8,944 1,178,060 359,031 249,436 0 570,044 1,827,120 1,465,320 1,172,260Solids Flowrate (lb/hr) 0 0 0 0 0 424,717 48,622 0 0 0 0Temperature (°F) 242 70 90 385 191 140 1,850 615 457 93 93Pressure (psia) 190.0 16.4 125.0 460.0 740.0 850.0 850.0 600.0 516.0 481.0 471.0Enthalpy (BTU/lb)B57.3 26.7 12.5 88.0 34.4 --- 1,120 1300.1 384.8 24.1 24.1Density (lb/ft3)0.729 0.103 0.683 1.424 3.412 --- --- 0.937 1.052 1.672 1.638Molecular Weight 28.86 26.67 32.23 28.06 32.18 --- --- 18.02 20.05 20.63 20.63A - Solids flowrate includes dry coal; V-L flowrate includes slurry water and water from coalB - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparisonof Fossil Energy Power Plants197Exhibit 3-66Case 4 Stream Table (Continued)12 13 14 15 16 17 18 19 20 21V-L Mole FractionAr 0.0109 0.0093 0.0093 0.0000 0.0000 0.0000 0.0205 0.0094 0.0089 0.0089CH40.0508 0.0436 0.0436 0.0000 0.0000 0.0000 0.0880 0.0000 0.0000 0.0000CO 0.0112 0.0096 0.0096 0.0000 0.0000 0.0000 0.0003 0.0000 0.0000 0.0000CO20.0243 0.0208 0.0208 1.0000 0.4321 0.0000 0.6024 0.0003 0.0097 0.0097COS 0.0000 0.0000 0.0000 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000H20.8888 0.7620 0.7620 0.0000 0.0000 0.0000 0.0215 0.0000 0.0000 0.0000H2O0.0001 0.1427 0.1427 0.0000 0.0554 0.0000 0.0006 0.0108 0.1350 0.1350H2S0.0000 0.0000 0.0000 0.0000 0.4035 0.0000 0.0180 0.0000 0.0000 0.0000N20.0139 0.0119 0.0119 0.0000 0.0774 0.0000 0.2486 0.7719 0.7429 0.7429NH30.0000 0.0000 0.0000 0.0000 0.0312 0.0000 0.0000 0.0000 0.0000 0.0000O20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2076 0.1035 0.1035SO20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000V-L Flowrate (lbmol/hr)33,733 39,346 39,346 22,257 813 47 628 242,512 308,662 308,662V-L Flowrate (lb/hr) 162,487 263,603 263,603979,537 29,677 11,954 22,868 6,996,340 8,438,000 8,438,000Solids Flowrate (lb/hr) 0 0 0 0 0 11,954 0 0 0 0Temperature (°F) 99 299 385 156 120 375 95 59 1052 270Pressure (psia) 468.5 458.5 453.5 2214.7 30.5 25.4 767.5 14.7 15.2 15.2Enthalpy (BTU/lb)B97.3 699.4 795.2 -46.0 48.7 -96.2 14.5 13.8 372.8 157.8Density (lb/ft3)0.376 0.378 0.335 30.793 0.179--- 4.692 0.076 0.026 0.053Molecular Weight 4.82 6.70 6.70 44.01 36.49 --- 36.39 28.85 27.34 27.34B - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparison of Fossil Energy Power Plants

198 

### The AGR process in Case 4 is a two stage Selexol process where H 2 

### S is removed in the first stage and CO 2 

### in the second stage of absorption as previously described in Section 3.1.5. The process results in three product streams, the clean syngas, a CO 2 

### -rich stream and an acid gas feed to the Claus plant. The acid gas (stream 16) contains 40 percent H 2 

### S and 43 percent CO 2 

### with the balance primarily N 2 

### . The CO 2 

### -rich stream is discussed further in the CO 2 

### compression section.

CO 2 

### Compression and Dehydration
CO 2 

### from the AGR process is generated at three pr essure levels. The LP stream is compressed from 0.15 MPa (22 psia) to 1.1 MPa (160 psia) and then combined w ith the MP stream. The HP stream is combined between compressor stages at 2.1 MPa (300 psia). The combined stream is compressed from 2.1 MPa (300 psia) to a superc ritical condition at 15.3 MPa (2215 psia) using a multiple-stage, intercooled compre ssor. During compression, the CO 2 

### stream is dehydrated to a dewpoint of -40oC (-40°F) with triethylene glycol. The raw CO 2 

### stream from the Selexol process contains over 93 percent CO 2 

### with the balance primarily nitrogen. For modeling purposes it was assumed that the impurities were separated from the CO 2 

### and combined with the clean syngas stream from the Selexol process. The pure CO 2 

### (stream 15) is transported to the plant fence line and is sequestration ready. CO 2 

### TS&M costs were estimated using the methodology described in Section 2.7.

Claus Unit The Claus plant is the same as Case 3 with the following exceptions:

• 5,423 kg/h (11,955 lb/h) of sulfur (stream 17) are produced

• The waste heat boiler generates 17,296 kg/h ( 38,131 lb/h) of 4.0 MPa (585 psia) steam, which provides all of the Claus plant process needs and provides some additional steam to the medium pressure steam header.

Power Block Clean syngas from the AGR plant is combined with a small amount of clean gas from the CO 2 

### compression process (stream 12) and partially hu midified because the nitrogen available from the ASU is insufficient to provide adequate diluti on. The moisturized syngas is reheated (stream 14) to 196°C (385°F) using HP boiler feedwater, diltuted with nitrogen (stream 4), and then enters the CT burner. There is no integration between the CT and the ASU in this case. The exhaust gas (stream 20) exits the CT at 567°C (1052°F) and enters the HRSG where additional heat is recovered. The flue gas exits the HRSG at 132°C (270°F) (stream 21) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced commercially available steam turbine using a 12.4 MPa/538°C/538°C (1800 psig/1000°F/1000°F) steam cycle.
Air Separation Unit The elevated pressure ASU is the same as in other cases and produces 4,000 tonnes/day (4,420 TPD) of 95 mole percent oxygen and 12,830 tonnes/da y (14,140 TPD) of nitrogen. There is no integration between the ASU and the combustion turbine.Cost and Performance Comparison of Fossil Energy Power Plants

199 

### 3.3.9 C ASE 

### 4 P ERFORMANCE 

### R ESULTS 

### The Case 4 modeling assumptions were presented previously in Section 3.3.3. The plant produces a net output of 518 MWe at a net plant efficiency of 31.7 percent (HHV basis). Overall performance for the entire plant is summarized in Exhibit 3-67 which includes auxiliary power requirements. The ASU accounts for nearly 62 percent of the auxiliary load between the main air compressor, the nitr ogen compressor, the oxygen compressor and ASU auxiliaries. The two-st age Selexol process and CO 2 

### compression account for an additional 23 percent of the auxiliary power load. The BF W pumps and cooling water system (circulating water pumps and cooling tower fan) comprise near ly 6 percent of the loa d, leaving 9 percent of the auxiliary load fo r all other systems.Cost and Performance Comparison of Fossil Energy Power Plants

200 

### Exhibit 3-67 Case 4 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Gas Turbine Power 464,000 Steam Turbine Power 229,840 TOTAL POWER, kWe 693,840 AUXILIARY LOAD SUMMARY, kWe Coal Handling 440 Coal Milling 2,230 Coal Slurry Pumps 580 Slag Handling and Dewatering 1,140 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 62,760 Oxygen Compressor 8,490 Nitrogen Compressor 36,330 Syngas Recycle Blower 3,400 Tail Gas Recycle Blower 1,090 CO 2 

### Compressor 25,970 Boiler Feedwater Pumps 5,340 Condensate Pump 270 Flash Bottoms Pump 200 Circulating Water Pumps 3,020 Cooling Tower Fans 1,560 Scrubber Pumps 70 Double Stage Selexol Unit Auxiliaries 14,840 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 200 Miscellaneous Balance of Plant (Note 1) 3,000 Transformer Loss 2,570 TOTAL AUXILIARIES, kWe 175,600 NET POWER, kWe 518,240 Net Plant Efficiency, % (HHV) 31.7 Net Plant Heat Rate (Btu/kWh) 10,757 CONDENSER COOLING DUTY 10 6 

### kJ/h (10 6 

### Btu/h) 1,224 (1,161) CONSUMABLES As-Received Coal Feed, kg/h (lb/h) 216,752 (477,855) Thermal Input, kWt 1,633,771 Raw Water Usage, m 3 

### /min (gpm) 15.6 (4,135) Note 1: Includes plant control systems, ligh ting, HVAC and miscellaneous low voltage loadsCost and Performance Comparison of Fossil Energy Power Plants

201 

### Environmental Performance The environmental targets for emissions of Hg, NO X 

### , SO 2 

### , CO 2 

### and particulate matter were presented in Section 2.4. A summ ary of the plant air emissions for Case 4 is presented in Exhibit 3-68.

Exhibit 3-68 Case 4 Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (tons/year) 80% capacity factor kg/MWh (lb/MWh)

SO 2 

### 0.004 (0.0085) 151 (167) 0.031 (0.069)
NO X 

### 0.021 (0.050) 882 (972) 0.181 (0.400)

Particulates 0.003 (0.0071) 126 (139) 0.026 (0.057)

Hg 0.25x10 -6 

### (0.57x10 -6 

### ) 0.010 (0.011) 2.1x10 -6 

### (4.6x10 -6 

### )
CO 2 

### 10.1 (23.6) 417,000 (460,000) 86 (189)

CO 2 1 

### 115 (253)

1 

### CO 2 

### emissions based on net power instead of gross power

The low level of SO 2 

### emissions is achieved by capture of the sulfur in the gas by the two-stage Selexol AGR process. The CO 2 

### capture target results in the sulfur compounds being removed to a greater extent than required in the environmental targets of Section 2.4. The clean syngas exiting the AGR process has a sulfur concentrati on of approximately 22 ppmv. This results in a concentration in the flue gas of less than 3 ppmv. The H 2 

### S-rich regeneration gas from the AGR system is fed to a Claus plant, producing el emental sulfur. The Claus plant tail gas is hydrogenated to convert a ll sulfur species to H 2 

### S, and then recycled back to the gasifier, thereby eliminating the need for a tail gas treatment unit.
NO X 

### emissions are limited by the use of humidifi cation and nitrogen dilution to 15 ppmvd (NO 2 

### @ 15 percent O 2 

### ). Ammonia in the syngas is removed w ith process condensate prior to the lowtemperature AGR process and ultimately destroyed in the Claus plant burner. This helps lower NO X 

### levels as well. Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only. Ninety five percent of mercury is captured from the syngas by an activated carbon bed. Ninety five percent of the CO 2 

### from the syngas is captured in the AGR system and compressed for sequestration. Because of the relatively high CH 4 

### content in the syngas, th is results in an overall carbon removal of 88.4 percent. The carbon balance for the plant is shown in Exhibit 3-69. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected in theCost and Performance Comparison of Fossil Energy Power Plants

202 

### carbon balance below since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, as dissolved CO 2 

### in the wastewater blowdown stream, and CO 2 

### in the stack gas, ASU vent gas and the captured CO 2 

### product. Carbon in the wastewater blowdown stream is calculated by difference to close the material balance. The carbon capture efficiency is define d as the amount of carbon in the CO 2 

### product stream relative to the amount of carbon in the coal less carbon contained in the slag, represented by the following fraction: (Carbon in Product for Sequestration)/[(Car bon in the Coal)-(Carbon in Slag)] or 267,147/(304,632-2,285) *100 or 88.4 percent

Exhibit 3-69 Case 4 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) Coal 138,180 (304,632) Slag 1,037 (2,285) Air (CO 2 

### ) 488 (1,077) Stack Gas 16,246 (35,817) CO 2 

### Product 121,176 (267,147)

ASU Vent 99 (218) Wastewater 110 (242)

Total 138,668 (305,709) Total 138,668 (305,709)

Exhibit 3-70 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output incl udes the sulfur recovered in the Claus plant, dissolved SO 2 

### in the wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible, and the sulfur content of the blowdown stream is calculated by difference to close the material balance. The to tal sulfur capture is re presented by the following fraction: (Sulfur byproduct/Sulfur in the coal) or (11,954/11,994) or 99.7 percent

Exhibit 3-70 Case 4 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) Coal 5,440 (11,994) Elemental Sulfur 5,422 (11,954) Stack Gas 11 (24) Wastewater 7 (16) Total 5,440 (11,994) Total 5,440 (11,994)

Exhibit 3-71 shows the overall water balance for the plant. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the total amount of water required for a particular process. Some water is recovered within theCost and Performance Comparison of Fossil Energy Power Plants

203 

### process, primarily as syngas condens ate, and that water is re-used as internal recycle. Raw water makeup is the difference between wa ter demand and internal recycle.

Exhibit 3-71 Case 4 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle,

m 3 

### /min (gpm) Raw Water Makeup,

m 3 

### /min (gpm)
Slurry 1.5 (392) 1.5 (392) 0
Slag Handling 0.5 (126) 0.5 (126) 0
Humidifier 0.8 (219) 0.8 (219) 0
Shift Steam 4.3 (1,140) 0 4.3 (1,140)
BFW Makeup 0.2 (46) 0 0.2 (46)
Cooling Tower Makeup 11.7 (3,098) 0.6 (149) 11.1 (2,949)

Total 19.0 (5,021) 3.4 (886) 15.6 (4,135)

Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-72 through Exhibit 3-76:

• Coal gasification and air separation unit

• Syngas cleanup

• Sulfur recovery and tail gas recycle

• Combined cycle power generation

• Steam and feedwater An overall plant energy balance is provided in tabular form in Exhibit 3-77. The power out is the combined combustion turbine and steam turbin e power prior to generator losses. The power at the generator terminals (shown in Exhibit 3-67) is calculated by multiplying the power out by a combined generator efficiency of 98.4 percent.Cost and Performance Comparison of Fossil Energy Power Plants

204 

### This page intentionally left blankCost and Performance Comparisonof Fossil Energy Power Plants205Exhibit 3-72 Case 4 Coal Gasification and AirSeparation Unit Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants206Exhibit 3-73 Case 4 Syngas Cleanup Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants207Exhibit 3-74 Case 4 Sulfur Recover and TailGas Recycle Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants208Exhibit 3-75 Case 4 Combined Cycle PowerGeneration Heat andMass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants209Exhibit 3-76 Case 4 Steam and Feedwater Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants210This page intentionally left blankCost and Performance Comparison of Fossil Energy Power Plants

211 

### Exhibit 3-77 Case 4 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total
Heat In (MMBtu/hr) Coal 5,575.1 4.7 5,579.8 ASU Air 21.1 21.1 CT Air 96.3 96.3 Water 16.9 16.9 Auxiliary Power 599.2 599.2 Totals 5,575.1 138.9 599.2 6,313.2 Heat Out (MMBtu/hr) ASU Intercoolers 240.9 240.9 ASU Vent 1.4 1.4 Slag 32.2 22.2 54.4 Sulfur 47.6 (1.1) 46.4 Tail Gas Compressor Intercoolers 3.9 3.9

CO 2 

### Compressor Intercoolers 130.7 130.7

CO 2 

### Product (45.1) (45.1) HRSG Flue Gas 1,335.7 1,335.7 Condenser 1,161.0 1,161.0 Process Losses 980.4 980.4 Power 2,403.5 2,403.5 Totals 79.8 3,830.0 2,403.5 6,313.2 (1) Process Losses are calculated by differen ce and reflect various gasification, turbine, HRSG and other heat and work losses. Aspe n flowsheet balance is within 0.5 percent.Cost and Performance Comparison of Fossil Energy Power Plants

212 

### 3.3.10 C ASE 

### 4

- M AJOR 

### E QUIPMENT 

### L IST 

### Major equipment items for the CoP gasifier with CO 2 

### capture are shown in the following tables. The accounts used in the equipment list correspo nd to the account numbers used in the cost estimates in Section 3.3.11. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
ACCOUNT 1 COAL HANDLING

Equipment No. Description Type Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0
3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0
5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0
8 Reclaim Hopper N/A 2 1
9 Feeder Vibratory 2 1
10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor reduction 2 0

14 As-Fired Coal Sampling System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0

17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 3 0 N/A

354 tonne/h (390 tph)

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph) N/A
1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)
1,134 tonne/h (1,250 tph)

45 tonne (50 ton)
181 tonne/h (200 tph)

8 cm x 0 - 3 cm x 0 (3" x 0 - 1-1/4" x 0) 354 tonne/h (390 tph)

181 tonne (200 ton) N/A

N/A

354 tonne/h (390 tph)

816 tonne (900 ton)Cost and Performance Comparison of Fossil Energy Power Plants

213 

### ACCOUNT 2 COAL PREPARATION AND FEED
Equipment No. Description Type Operating Qty. Spares

1 Feeder Vibratory 3 0
2 Conveyor No. 6 Belt w/tripper 1 0
3 Rod Mill Feed Hopper Dual Outlet 1 0
4 Weigh Feeder Belt 2 0
5 Rod Mill Rotary 2 0

6 Slurry Water Storage Tank with Agitator Field erected 2 0

7 Slurry Water Pumps Centrifugal 2 2

10 Trommel Screen Coarse 2 0

11 Rod Mill Discharge Tank with Agitator Field erected 2 0

12 Rod Mill Product Pumps Centrifugal 2 2

13 Slurry Storage Tank with Agitator Field erected 2 0

14 Slurry Recycle Pumps Centrifugal 2 2

15 Slurry Product Pumps Positive displacement 2 2 Design Condition

82 tonne/h (90 tph)
236 tonne/h (260 tph)
481 tonne (530 ton)
118 tonne/h (130 tph)

312,678 liters (82,600 gal)

2,612 lpm (690 gpm)

833 lpm (220 gpm) 118 tonne/h (130 tph)

295,264 liters (78,000 gal)

172 tonne/h (190 tph)

2,612 lpm (690 gpm) 5,224 lpm (1,380 gpm) 946,361 liters (250,000 gal)Cost and Performance Comparison of Fossil Energy Power Plants

214 

### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 3 0

2 Condensate Pumps Vertical canned 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multistage, centrifugal 2 1

7 Auxiliary Boiler Shop fabricated, water tube 1 0

8 Service Air Compressors Flooded Screw 2 1

9 Instrument Air Dryers Duplex, regenerative 2 1

10 Closed Cylce Cooling Heat Exchangers Plate and frame 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 2 1

12 Engine-Driven Fire Pump Vertical turbine, diesel engine 1 1

13 Fire Service Booster Pump Two-stage horizontal centrifugal 1 1

14 Raw Water Pumps Stainless steel, single suction 2 1

15 Filtered Water Pumps Stainless steel, single suction 2 1

16 Filtered Water Tank Vertical, cylindrical 2 0

17 Makeup Water Demineralizer Anion, cation, and mixed bed 2 0

18 Liquid Waste Treatment System 1 0 2 1 5 High Pressure Feedwater Pump No. 1 Barrel type, multistage, centrifugal

1,968,429 liter (520,000 gal)

2,574 lpm (680 gpm)

10 years, 24-hour storm 4,088 lpm @ 49 m H2O (1,080 gpm @ 160 ft H2O)

28 m3/min (1,000 scfm)

58 MMkJ/h (55 MMBtu/h) each
20,820 lpm @ 21 m H2O (5,500 gpm @ 70 ft H2O) 3,785 lpm @ 107 m H2O (1,000 gpm @ 350 ft H2O)

2,650 lpm @ 76 m H2O (700 gpm @ 250 ft H2O) 8,707 lpm @ 18 m H2O (2,300 gpm @ 60 ft H2O) 2,006 lpm @ 283 m H2O (530 gpm @ 930 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C (40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) Design Condition

2,237,196 liters (591,000 gal)
7,874 lpm @ 91 m H2O (2,080 gpm @ 300 ft H2O)

577,877 kg/h (1,274,000 lb/h)

IP water: 1,476 lpm @ 223 m H2O (390 gpm @ 730 ft H2O) HP water: 6,587 lpm @ 1,890 m

H2O (1,740 gpm @ 6,200 ft H2O)Cost and Performance Comparison of Fossil Energy Power Plants

215 

### ACCOUNT 4 GASIFIER, ASU AND ACC ESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION
Equipment No. Description Type Operating Qty. Spares

1 Gasifier Pressurized two-stage, slurry-feed entrained bed 2 0

2 Synthesis Gas Cooler Fire-tube boiler 2 0

3 Synthesis Gas Cyclone High efficiency 2 0

4 Candle Filter Pressurized filter with pulse-jet cleaning 2 0

5 Syngas Scrubber Including Sour Water Stripper Vertical upflow 2 0

6 Raw Gas Coolers Shell and tube with condensate drain 8 0

7 Raw Gas Knockout Drum Vertical with mist eliminator 2 0

8 Saturation Water Economizers Shell and tube 2 0

9 Fuel Gas Saturator Vertical tray tower 2 0

10 Saturator Water Pump Centrifugal 2 2

11 Synthesis Gas Reheater Shell and tube 2 0

12 Flare Stack Self-supporting, carbon steel, stainless steel top, pilot ignition 2 0

13 ASU Main Air Compressor Centrifugal, multistage 2 0

14 Cold Box Vendor design 2 0

15 Oxygen Compressor Centrifugal, multistage 2 0

16 Nitrogen Compressor Centrifugal, multistage 2 0

17 Nitrogen Boost Compressor Centrifugal, multistage 2 0 metallic filters

299,825 kg/h (661,000 lb/h)

455,861 kg/h (1,005,000 lb/h)

351,988 kg/h, 38°C, 5.1 MPa (776,000 lb/h, 100°F, 737 psia) Design Condition

2,903 tonne/day, 4.2 MPa (3,200 tpd, 615 psia)

326,133 kg/h (719,000 lb/h)

313,433 kg/h (691,000 lb/h) Design efficiency 90%

455,861 kg/h (1,005,000 lb/h)
62,596 kg/h, 149°C, 3.2 MPa (138,000 lb/h, 300°F, 458 psia) 3,785 lpm @ 15 m H2O (1,000 gpm @ 50 ft H2O)
65,771 kg/h (145,000 lb/h)

510 m3/min @ 2.3 MPa (18,000 scfm @ 340 psia) 299,825 kg/h (661,000 lb/h)
syngas 5,493 m3/min @ 1.3 MPa (194,000 scfm @ 190 psia)
2,177 tonne/day (2,400 tpd) of 95% purity oxygen
1,104 m3/min @ 5.1 MPa (39,000 scfm @ 740 psia) 3,653 m3/min @ 3.4 MPa (129,000 scfm @ 490 psia)Cost and Performance Comparison of Fossil Energy Power Plants

216 

### ACCOUNT 5A SOUR GAS SHIF T AND SYNGAS CLEANUP
Equipment No. Description Type Operatin g Qty. Spares

1 Mercury Adsorber Sulfated carbon bed 2 0

2 Sulfur Plant Claus type 1 0

3 Water Gas Shift Reactors Fixed bed, catalytic 6 0

4 Shift Reactor Heat Recovery Exhchangers Shell and Tube 4 0

5 Acid Gas Removal Plant Two-stage Selexol 2 0

6 Hydrogenation Reactor Fixed bed, catalytic 1 0

7 Tail Gas Recycle Compressor Centrifugal 1 0 Design Condition

320,690 kg/h (707,000 lb/h) 34°C (93°F) 3.3 MPa (481 psia)

143 tonne/day (158 tpd)

Exchanger 1: 148 MMkJ/h (140 MMBtu/h) Exchanger 2: 32 MMkJ/h (30 MMBtu/h)

11,975 kg/h @ 6.4 MPa (26,400 lb/h @ 930 psia) 455,861 kg/h (1,005,000 lb/h) 232°C (450°F) 3.9 MPa (562 psia)

292,567 kg/h (645,000 lb/h) 35°C (95°F) 3.2 MPa (471 psia)

17,100 kg/h (37,700 lb/h) 232°C (450°F) 0.2 MPa (25 psia)



### ACCOUNT 5B CO 2 

### COMPRESSION

Equipment No. Description Type Operating Qty. Spares

1 CO2 Compressor Integrally geared, multistage centrifugal 4 1 Design Condition
1,096 m3/min @ 15.3 MPa (38,715 scfm @ 2,215 psia)



### ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES
Equipment No. Description Type Operating Qty. Spares

1 Gas Turbine Advanced F class 2 0

2 Gas Turbine Generator TEWAC 2 0 Design Condition

232 MW
260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phaseCost and Performance Comparison of Fossil Energy Power Plants

217 

### ACCOUNT 7 HRSG, DUCTING, AND STACK

Equipment No. Description Type Operating Qty. Spares

1 Stack CS plate, type 409SS liner 1 0

2 0 2 Heat Recovery Steam Generator Drum, multi-pressure with economizer section and integral deaerator Reheat steam - 304,874 kg/h, 2.9 MPa/538°C (672,132 lb/h, 420 psig/1,000°F) Design Condition

76 m (250 ft) high x 8.5 m (28 ft) diameter

Main steam - 372,086 kg/h, 12.4 MPa/538°C (820,307 lb/h, 1,800 psig/1,000°F)



### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitiation 1 0

3 Steam Bypass One per HRSG 2 0

4 Surface Condenser Single pass, divided waterbox including
vacuum pumps 1 0 280 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase

50% steam flow @ design steam conditions Design Condition

251 MW 12.4 MPa/538°C/538°C (1800 psig/ 1000°F/1000°F)

1,392 MMkJ/h (1,320 MMBtu/h), Inlet water temperature 16°C (60°F),

Water temperature rise 11°C (20°F)Cost and Performance Comparison of Fossil Energy Power Plants

218 

### ACCOUNT 9 COOLING WATER SYSTEM
Equipment No. Description Type Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 1 0 Design Condition
302,835 lpm @ 30 m (80,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT, 1,687 MMkJ/h (1,600 MMBtu/h) heat duty



### ACCOUNT 10 SLAG RECOVERY AND HANDLING
Equipment No. Description Type Operating Qty. Spares

1 Slag Quench Tank Water bath 2 0
2 Slag Crusher Roll 2 0
3 Slag Depressurizer Proprietary 2 0
4 Slag Receiving Tank Horizontal, weir 2 0
5 Black Water Overflow Tank Shop fabricated 2
6 Slag Conveyor Drag chain 2 0
7 Slag Separation Screen Vibrating 2 0
8 Coarse Slag Conveyor Belt/bucket 2 0
9 Fine Ash Settling Tank Vertical, gravity 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 2 2

11 Grey Water Storage Tank Field erected 2 0

12 Grey Water Pumps Centrifugal 2 2

13 Grey Water Recycle Heat Exchanger Shell and tube 2 0

14 Slag Storage Bin Vertical, field erected 2 0

15 Unloading Equipment Telescoping chute 1 0 Design Condition

230,912 liters (61,000 gal)
12 tonne/h (13 tph)
12 tonne/h (13 tph)
151,418 liters (40,000 gal)

12 tonne/h (13 tph)
12 tonne/h (13 tph)
12 tonne/h (13 tph) 71,923 liters (19,000 gal)

227,126 liters (60,000 gal)

38 lpm @ 14 m H2O (10 gpm @ 46 ft H2O)

907 tonne (1,000 tons)

100 tonne/h (110 tph) 71,923 liters (19,000 gal)

265 lpm @ 433 m H2O (70 gpm @ 1,420 ft H2O)

15,876 kg/h (35,000 lb/h)Cost and Performance Comparison of Fossil Energy Power Plants

219 

### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type Operating Qty. Spares

1 CTG Transformer Oil-filled 2 0

3 Auxiliary Transformer Oil-filled 1 1

4 Low Voltage Transformer Dry ventilated 1 1

5 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 2 0

6 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 1 0

7 Medium Voltage Switchgear Metal clad 1 1

8 Low Voltage Switchgear Metal enclosed 1 1

9 Emergency Diesel Generator Sized for emergency shutdown 1 0 750 kW, 480 V, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz 1 0

24 kV/4.16 kV, 191 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 29 MVA, 3-ph, 60 Hz Design Condition

24 kV/345 kV, 260 MVA, 3-ph, 60 Hz

2 STG Transformer Oil-filled 24 kV/345 kV, 80 MVA, 3-ph, 60 Hz



### ACCOUNT 12 INSTRUMENTATION AND CONTROLS

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) 1 0

3 DCS - Data Highway Fiber optic 1 0 Design Condition

Operator stations/printers and engineering stations/printers

2 DCS - Processor Microprocessor with redundant input/output N/A 1 0

Fully redundant, 25% spareCost and Performance Comparison of Fossil Energy Power Plants

220 

### 3.3.11 C ASE 

### 4

- C OST 

### E STIMATING 

### R ESULTS 

### The cost estimating methodology was desc ribed previously in Section 2.6. Exhibit 3-78 shows the total plant capital cost summary organized by cost account and Exhibit 3-79 shows a more detailed breakdown of the capital costs. Exhibit 3-80 shows the initia l and annual O&M costs. The estimated TPC of the CoP gasifier with CO 2 

### capture is $2,431/kW. Process contingency represents 4.3 percent of the TP C and project contingency repres ents 13.7 percent. The 20-year LCOE, including CO 2 

### TS&M costs of 4.1 mills/kWh, is 105.7 mills/kWh.Cost and Performance Comparisonof Fossil Energy Power Plants221Exhibit 3-78 Case 4 Total Plant Cost SummaryClient:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 04 - ConocoPhillips IGCC w/ CO2Plant Size:518.2 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING $13,303 $2,480 $10,424 $0 $0$26,207$2,127 $0 $5,667$34,000$662 COAL & SORBENT PREP & FEED $22,651 $4,146 $13,827 $0 $0$40,624$3,263 $0 $8,777$52,665$1023 FEEDWATER & MISC. BOP SYSTEMS $9,371 $7,975 $8,947 $0 $0$26,292$2,201 $0 $6,451$34,944$674 GASIFIER & ACCESSORIES4.1 Gasifier, Syngas Cooler & Auxiliaries $93,113 $0 $57,142 $0 $0$150,256$12,324 $22,538 $27,768$212,885$4114.2 Syngas Cooling ( w/ 4.1) w/4.1 $0 w/4.1 $0 $0$0$0 $0 $0$0$04.3 ASU/Oxidant Compression $142,779 $0 w/equip. $0 $0$142,779$12,175 $0 $15,495$170,449$3294.4-4.9 Other Gasification Equipment $24,864 $8,707 $14,165 $0 $0$47,736$4,057 $0 $11,002$62,795$121SUBTOTAL 4 $260,756 $8,707 $71,307 $0 $0 $340,771 $28,555 $22,538 $54,265 $446,129 $8615A Gas Cleanup & Piping $81,314 $4,446 $69,562 $0 $0$155,321$13,338 $21,481 $38,231$228,370$4415BCO2REMOVAL & COMPRESSION$17,010 $0 $10,435 $0 $0$27,445$2,351 $0 $5,959$35,754$696 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator $88,000 $0 $5,325 $0 $0$93,325$7,865 $9,333 $11,052$121,575$2356.2-6.9 Combustion Turbine Other $0 $684 $762 $0 $0$1,446$121 $0 $470$2,037$4SUBTOTAL 6 $88,000 $684 $6,087 $0 $0 $94,771 $7,986 $9,333 $11,522 $123,611 $2397 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator $32,356 $0 $4,604 $0 $0$36,960$3,125 $0 $4,009$44,094$857.2-7.9 Ductwork and Stack $3,222 $2,268 $3,011 $0 $0$8,501$703 $0 $1,496$10,700$21SUBTOTAL 7 $35,577 $2,268 $7,615 $0 $0 $45,461 $3,829 $0 $5,505 $54,794 $1068 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $25,224 $0 $4,105 $0 $0$29,328$2,518 $0 $3,185$35,030$688.2-8.9 Turbine Plant Auxiliaries and Steam Piping $9,243 $828 $6,527 $0 $0$16,598$1,338 $0 $3,645$21,581$42SUBTOTAL 8 $34,466 $828 $10,632 $0 $0 $45,926 $3,856 $0 $6,829 $56,611 $1099 COOLING WATER SYSTEM $6,318 $6,821 $5,729 $0 $0$18,867$1,553 $0 $4,194$24,614$4710 ASH/SPENT SORBENT HANDLING SYS $18,516 $1,396 $9,191 $0 $0$29,103$2,482 $0 $3,445$35,031$6811 ACCESSORY ELECTRIC PLANT $23,064 $11,396 $22,575 $0 $0$57,035$4,450 $0 $11,923$73,409$14212 INSTRUMENTATION & CONTROL $10,183 $1,906 $6,836 $0 $0$18,925$1,562 $946 $3,586$25,021$4813 IMPROVEMENTS TO SITE $3,208 $1,891 $7,974 $0 $0$13,073$1,151 $0 $4,267$18,490$3614 BUILDINGS & STRUCTURES $0 $6,066 $6,992 $0 $0$13,057$1,063 $0 $2,319$16,439$32TOTAL COST $623,738 $61,009 $268,131 $0 $0 $952,878 $79,766 $54,298 $172,940 $1,259,883 $2,431TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants222Exhibit 3-79 Case 4 Total Plant Cost DetailsClient:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 04 - ConocoPhillips IGCC w/ CO2Plant Size:518.2 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING1.1 Coal Receive & Unload $3,493 $0 $1,725 $0 $0 $5,218 $418 $0 $1,127 $6,764 $131.2 Coal Stackout & Reclaim $4,514 $0 $1,106 $0 $0 $5,620 $441 $0 $1,212 $7,274 $141.3 Coal Conveyors $4,197 $0 $1,094 $0 $0 $5,291 $416 $0 $1,141 $6,849 $131.4 Other Coal Handling $1,098 $0 $253 $0 $0 $1,351 $106 $0 $291 $1,749 $31.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.9 Coal & Sorbent Hnd.Foundations $0 $2,480 $6,246 $0 $0 $8,726 $745 $0 $1,894 $11,365 $22SUBTOTAL 1. $13,303 $2,480 $10,424 $0 $0 $26,207 $2,127 $0 $5,667 $34,000 $662 COAL & SORBENT PREP & FEED2.1 Coal Crushing & Drying incl w/2.3 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.2 Prepared Coal Storage & Feed $1,491 $355 $236 $0 $0 $2,082 $160 $0 $448 $2,690 $52.3 Slurry Prep & Feed $20,340 $0 $9,140 $0 $0 $29,480 $2,356 $0 $6,367 $38,204 $742.4 Misc.Coal Prep & Feed $820 $593 $1,807 $0 $0 $3,221 $265 $0 $697 $4,182 $82.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.9 Coal & Sorbent Feed Foundation $0 $3,197 $2,644 $0 $0 $5,841 $483 $0 $1,265 $7,588 $15SUBTOTAL 2. $22,651 $4,146 $13,827 $0 $0 $40,624 $3,263 $0 $8,777 $52,665 $1023 FEEDWATER & MISC. BOP SYSTEMS3.1 FeedwaterSystem $3,088 $5,369 $2,836 $0 $0 $11,293 $934 $0 $2,445 $14,672 $283.2 Water Makeup & Pretreating $537 $56 $300 $0 $0 $893 $76 $0 $290 $1,259 $23.3 Other Feedwater Subsystems $1,705 $578 $521 $0 $0 $2,804 $225 $0 $606 $3,634 $73.4 Service Water Systems $309 $632 $2,194 $0 $0 $3,135 $272 $0 $1,022 $4,428 $93.5 Other Boiler Plant Systems $1,662 $638 $1,582 $0 $0 $3,882 $326 $0 $842 $5,050 $103.6 FO Supply Sys & Nat Gas $299 $565 $527 $0 $0 $1,391 $119 $0 $302 $1,812 $33.7 Waste Treatment Equipment $746 $0 $457 $0 $0 $1,203 $104 $0 $392 $1,700 $33.8 Misc. Equip.(cranes,AirComp.,Comm.) $1,024 $138 $531 $0 $0 $1,693 $146 $0 $552 $2,390 $5SUBTOTAL 3. $9,371 $7,975 $8,947 $0 $0 $26,292 $2,201 $0 $6,451 $34,944 $674 GASIFIER & ACCESSORIES4.1 Gasifier, Syngas Cooler & Auxiliaries(E-GAS)$93,113 $0 $57,142 $0 $0 $150,256 $12,324 $22,538 $27,768 $212,885 $4114.2 Syngas Cooling ( w/ 4.1 w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.3 ASU/Oxidant Compression $142,779 $0 w/equip. $0 $0 $142,779 $12,175 $0 $15,495 $170,449 $3294.4 LT Heat Recovery & FG Saturation $24,864 $0 $9,355 $0 $0 $34,219 $2,946 $0 $7,433 $44,598 $864.5 Misc. Gasification Equipment w/4.1 & 4.2 w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $04.6 Other Gasification Equipment $0 $1,157 $471 $0 $0 $1,629 $139 $0 $354 $2,121 $44.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $04.9 Gasification Foundations $0 $7,550 $4,339 $0 $0 $11,889 $972 $0 $3,215 $16,075 $31SUBTOTAL 4. $260,756 $8,707 $71,307 $0 $0 $340,771 $28,555 $22,538 $54,265 $446,129 $861TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants223Exhibit 3-79 Case 4 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 04 - ConocoPhillips IGCC w/ CO2Plant Size:518.2 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW5A GAS CLEANUP & PIPING5A.1 Double Stage Selexol $57,451 $0 $49,279 $0 $0 $106,730 $9,179 $21,346 $27,451 $164,707 $3185A.2 Elemental Sulfur Plant $9,709 $1,927 $12,535 $0 $0 $24,170 $2,088 $0 $5,252 $31,510 $615A.3 Mercury Removal $1,531 $0 $1,166 $0 $0 $2,697 $232 $135 $613 $3,676 $75A.4 Shift Reactors $12,213 $0 $4,919 $0 $0 $17,133 $1,461 $0 $3,719 $22,312 $435A.5 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.6 Blowback Gas Systems $410 $230 $130 $0 $0 $770 $65 $0 $167 $1,002 $25A.7 Fuel Gas Piping $0 $1,150 $793 $0 $0 $1,943 $159 $0 $420 $2,522 $55A.9 HGCU Foundations $0 $1,138 $739 $0 $0 $1,878 $154 $0 $609 $2,641 $5SUBTOTAL 5A. $81,314 $4,446 $69,562 $0 $0 $155,321 $13,338 $21,481 $38,231 $228,370 $4415B CO2 REMOVAL & COMPRESSION5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05B.2 CO2 Compression & Drying $17,010 $0 $10,435 $0 $0 $27,445 $2,351 $0 $5,959 $35,754 $69SUBTOTAL 5B. $17,010 $0 $10,435 $0 $0 $27,445 $2,351 $0 $5,959 $35,754 $696 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator $88,000$0 $5,325 $0 $0 $93,325 $7,865 $9,333 $11,052 $121,575 $2356.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.9 Combustion Turbine Foundations $0 $684 $762 $0 $0 $1,446 $121 $0 $470 $2,037 $4SUBTOTAL 6. $88,000 $684 $6,087 $0 $0 $94,771 $7,986 $9,333 $11,522 $123,611 $2397 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator $32,356 $0 $4,604 $0 $0 $36,960 $3,125 $0 $4,009 $44,094 $857.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07.3 Ductwork $0 $1,627 $1,179 $0 $0 $2,806 $221 $0 $605 $3,632 $77.4 Stack $3,222 $0 $1,211 $0 $0 $4,433 $378 $0 $481 $5,292 $107.9 HRSG,Duct & Stack Foundations $0 $641 $620 $0 $0 $1,262 $105 $0 $410 $1,777 $3SUBTOTAL 7. $35,577 $2,268 $7,615 $0 $0 $45,461 $3,829 $0 $5,505 $54,794 $1068 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $25,224 $0 $4,105 $0 $0 $29,328 $2,518 $0 $3,185 $35,030 $688.2 Turbine Plant Auxiliaries $168 $0 $385 $0 $0 $553 $48 $0 $60 $662 $18.3 Condenser & Auxiliaries $4,112 $0 $1,235 $0 $0 $5,348 $455 $0 $580 $6,382 $128.4 Steam Piping $4,962 $0 $3,497 $0 $0 $8,459 $647 $0 $2,276 $11,382 $228.9 TG Foundations $0 $828 $1,409 $0 $0 $2,237 $189 $0 $728 $3,154 $6SUBTOTAL 8. $34,466 $828 $10,632 $0 $0 $45,926 $3,856 $0 $6,829 $56,611 $1099 COOLING WATER SYSTEM9.1 Cooling Towers $4,081 $0 $897 $0 $0 $4,978 $422 $0 $810 $6,210 $129.2 Circulating Water Pumps $1,284 $0 $77 $0 $0 $1,361 $104 $0 $220 $1,685 $39.3 Circ.Water System Auxiliaries $108 $0 $15 $0 $0 $123 $10 $0 $20 $154 $09.4 Circ.Water Piping $0 $4,606 $1,175 $0 $0 $5,781 $459 $0 $1,248 $7,488 $149.5 Make-up Water System $301 $0 $427 $0 $0 $729 $62 $0 $158 $949 $29.6 Component Cooling Water Sys $544 $650 $459 $0 $0 $1,653 $137 $0 $358 $2,148 $49.9 Circ.Water System Foundations& Structures $0 $1,564 $2,678 $0 $0 $4,242 $358 $0 $1,380 $5,981 $12SUBTOTAL 9. $6,318 $6,821 $5,729 $0 $0 $18,867 $1,553 $0 $4,194 $24,614 $4710 ASH/SPENT SORBENT HANDLING SYS10.1 Slag Dewatering & Cooling $16,165 $0 $7,978 $0 $0 $24,143 $2,063 $0 $2,621 $28,826 $5610.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.6 Ash Storage Silos $532 $0 $579 $0 $0 $1,111 $96 $0 $181 $1,387 $310.7 Ash Transport & Feed Equipment $718 $0 $172 $0 $0 $890 $73 $0 $145 $1,108 $210.8 Misc. Ash Handling Equipment $1,101 $1,350 $403 $0 $0 $2,854 $242 $0 $464 $3,560 $710.9 Ash/Spent Sorbent Foundation $0 $47 $59 $0 $0 $106 $9 $0 $34 $149 $0SUBTOTAL 10. $18,516 $1,396 $9,191 $0 $0 $29,103 $2,482 $0 $3,445 $35,031 $68TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants224Exhibit 3-79 Case 4 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 04 - ConocoPhillips IGCC w/ CO2Plant Size:518.2 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW11 ACCESSORY ELECTRIC PLANT11.1 Generator Equipment $866 $0 $864 $0 $0 $1,730 $147 $0 $188 $2,065 $411.2 Station Service Equipment $4,122 $0 $387 $0 $0 $4,509 $384 $0 $489 $5,381 $1011.3 Switchgear & Motor Control $7,876 $0 $1,444 $0 $0 $9,320 $773 $0 $1,514 $11,608 $2211.4 Conduit & Cable Tray $0 $3,748 $12,166 $0 $0 $15,914 $1,363 $0 $4,319 $21,596 $4211.5 Wire & Cable $0 $6,883 $4,630 $0 $0 $11,512 $754 $0 $3,067 $15,333 $3011.6 Protective Equipment $0 $624 $2,365 $0 $0 $2,989 $262 $0 $488 $3,739 $711.7 Standby Equipment $208 $0 $211 $0 $0 $419 $36 $0 $68 $524 $111.8 Main Power Transformers $9,992 $0 $132 $0 $0 $10,124 $687 $0 $1,622 $12,432 $2411.9 Electrical Foundations $0 $142 $376 $0 $0 $518 $44 $0 $169 $730 $1SUBTOTAL 11. $23,064 $11,396 $22,575 $0 $0 $57,035 $4,450 $0 $11,923 $73,409 $14212 INSTRUMENTATION & CONTROL12.1 IGCC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $012.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $012.4 Other Major Component Control $1,005 $0 $699 $0 $0 $1,705 $147 $85 $291 $2,227 $412.5 Signal Processing Equipment W/12.7 $0 W/12.7 $0 $0 $0 $0 $0 $0 $0 $012.6 Control Boards,Panels & Racks $231 $0 $154 $0 $0 $385 $33 $19 $88 $525 $112.7 Computer & Accessories $5,362 $0 $179 $0 $0 $5,541 $470 $277 $629 $6,918 $1312.8 Instrument Wiring & Tubing $0 $1,906 $3,990 $0 $0 $5,896 $448 $295 $1,660 $8,299 $1612.9 Other I & C Equipment $3,584 $0 $1,813 $0 $0 $5,398 $464 $270 $920 $7,052 $14SUBTOTAL 12. $10,183 $1,906 $6,836 $0 $0 $18,925 $1,562 $946 $3,586 $25,021 $4813 Improvements to Site13.1 Site Preparation $0 $101 $2,167 $0 $0 $2,268 $200 $0 $740 $3,209 $613.2 Site Improvements $0 $1,790 $2,397 $0 $0 $4,187 $368 $0 $1,367 $5,922 $1113.3 Site Facilities $3,208 $0 $3,410 $0 $0 $6,618 $582 $0 $2,160 $9,360 $18SUBTOTAL 13. $3,208 $1,891 $7,974 $0 $0 $13,073 $1,151 $0 $4,267 $18,490 $3614 Buildings & Structures14.1 Combustion Turbine Area $0 $221 $127 $0 $0 $348 $27 $0 $75 $451 $114.2 Steam Turbine Building $0 $2,058 $2,971 $0 $0 $5,030 $414 $0 $816 $6,260 $1214.3 Administration Building $0 $814 $598 $0 $0 $1,412 $113 $0 $229 $1,753 $314.4 Circulation Water Pumphouse $0 $153 $82 $0 $0 $235 $18 $0 $38 $291 $114.5 Water Treatment Buildings $0 $427 $423 $0 $0 $850 $69 $0 $138 $1,057 $214.6 Machine Shop $0 $417 $289 $0 $0 $705 $56 $0 $114 $876 $214.7 Warehouse $0 $672 $440 $0 $0 $1,112 $88 $0 $180 $1,381 $314.8 Other Buildings & Structures $0 $403 $318 $0 $0 $721 $58 $0 $156 $934 $214.9 Waste Treating Building & Str. $0 $900 $1,744 $0 $0 $2,644 $220 $0 $573 $3,437 $7SUBTOTAL 14. $0 $6,066 $6,992 $0 $0 $13,057 $1,063 $0 $2,319 $16,439 $32TOTAL COST $623,738 $61,009 $268,131 $0 $0 $952,878 $79,766 $54,298 $172,940 $1,259,883 $2,431TOTAL PLANT COST SUMMARYCost and Performance Comparison of Fossil Energy Power Plants

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### Exhibit 3-80 Case 4 Initial and A nnual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006 Case 04 - ConocoPhillips IGCC w/ CO2 Heat Rate-net(Btu/kWh): 10,757 MWe-net: 518 Capacity Factor: (%): 80 OPERATING & MAINTENANCE LABOR

Operating Labor Operating Labor Rate(base): 33.00 $/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 10.0 10.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 16.0 16.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,012,864 $11.602 Maintenance Labor Cost $13,171,520 $25.416 Administrative & Support Labor $4,796,096 $9.255 TOTAL FIXED OPERATING COSTS $23,980,481 $46.273 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $24,211,567 $0.00667

Consumables Consumption Unit Initial Initial /Day Cost Cost
Water(/1000 gallons) 0 5,954 1.03 $0 $1,790,845 $0.00049

Chemicals MU & WT Chem.(lb) 124,161 17,737 0.16 $20,462 $853,547 $0.00024 Carbon (Mercury Removal) (lb) 128,090 175 1.00 $128,090 $51,100 $0.00001 COS Catalyst (m3) 0 0 2,308.40 $0 $0 $0.00000 Water Gas Shift Catalyst(ft3) 11,053 7.57 475.00 $5,250,175 $1,049,363 $0.00029 Selexol Solution (gal.) 462 66 12.90 $5,960 $248,630 $0.00007 MDEA Solution (gal) 0 0 0.96 $0 $0 $0.00000 Sulfinol Solution (gal) 0 0 9.68 $0 $0 $0.00000 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. 2.16 125.00 $0 $78,840 $0.00002 Subtotal Chemicals $5, 404,687 $2,281,480 $0.00063

Othe r Supplemental Fuel(MBtu) 0 0 0.00 $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 Othe r $0 $0 $0.00000

Waste Disposal Spent Mercury Catalyst (lb) 0 175 0.40 $0 $20,522 $0.00001 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Bottom Ash(ton) 0 583 15.45 $0 $2,632,348 $0.00072 Subtotal-Waste Disposal $0 $2,652,870 $0.00073

By-products & Emissions Sulfur(tons) 0 143 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $5,404,687 $30,936,762 $0.00852

Fuel(ton) 172,030 5,734 42.11 $7,244,210 $70,510,306 $0.01941Cost and Performance Comparison of Fossil Energy Power Plants

226 

### 3.4 SHELL GLOBAL SOLUTIONS IGCC CASES
This section contains an eval uation of plant designs for Cases 5 and 6, which are based on the Shell Global Solutions (Shell) gasi fier. Cases 5 and 6 are very similar in terms of process, equipment, scope and arrangement, except that Case 6 employs a syngas quench and includes sour gas shift reactors, CO 2 

### absorption/regeneration and comp ression/transport systems. There are no provisions for CO 2 

### removal in Case 5. The balance of this section is organize d in an analogous manner to Sections 3.2 and 3.3:

• Gasifier Background

• Process System Decscription for Case 5

• Key Assumptions for Cases 5 and 6

• Sparing Philosophy for Cases 5 and 6

• Performance Results for Case 5

• Equipment List for Case 5

• Cost Estimates For Case 5

• Process and System Description, Performance Re sults, Equipment List and Cost Estimate for Case 6

3.4.1 G ASIFIER 

### B ACKGROUND 

### Development and Current Status – Development of the Shell ga sification process for partial oxidation of oil and gas began in the early 1950s . More than 75 commercial Shell partialoxidation plants have been built worldwide to convert a variety of hydrocarbon liquids and gases to carbon monoxide and hydrogen.
Shell Internationale Petroleum Maatschappij B.V. began work on coal gasification in 1972. The coal gasifier is significantly different than the oil and gas gasifiers develo ped earlier. A pressurized, entrained-flow, slaggi ng coal gasifier was built at Shell’s Amsterdam laboratories. This 5 tonnes/day (6 TPD) process devel opment unit has operated for approximately 12,000 hours since 1976. A larger 150 tonnes/day (165 TPD) pilot plant was built at Shell’s Hamburg refinery in Hamburg, Germany. This larger unit operated for approximately 6,000 hours from 1978 to 1983, and successfully ga sified over 27,216 tonnes (30,000 tons) of coal. From 1974 until mid-1981, Heinrich Koppers Gm bH (now Krupp Koppers) cooperated with Shell in the development work for the coal gasification technol ogy at the 150 tonnes/day (165 TPD) pilot plant in Hamburg. Krupp Koppers is the licensor of the commercially proven Koppers-Totzek coal gasification technology, an entrained-flow slaggi ng gasification system operated at atmospheric pressure. In June 1981, the partnership between Shell and Krupp Koppers was terminated. Since that time, this gasification technology has been developed solely by Shell as the Shell Coal Gasification Process. Krupp Koppers continued its own deve lopment of a similar pressurized, dry feed, entrained-flow gasification technology called PRENFLO. Krupp Koppers has built and successfully operated a small 45 tonnes/day (50 TP D) PRENFLO pilot plant at Fuerstenhausen,Cost and Performance Comparison of Fossil Energy Power Plants

227 

### Germany. In 2000 Shell and Krupp Uhde agreed to join forces again in gasification and jointly offer the Shell coal gasification process. Based on the experience it gained with the Hamb urg unit, Shell built a de monstration unit at its oil refinery and chemical complex in Deer Par k, Texas, near Houston. This new unit, commonly called SCGP-1 (for Shell Coal Gasification Plant- 1), was designed to gasify bituminous coal at the rate of 227 tonnes/day (250 TPD) and to gasify high-moisture, high-ash lignite at the rate of 363 tonnes/day (400 TPD). The relatively small difference in size between the Hamburg and Deer Park units reflects design changes and improvements. The Deer Park demonstration plant operated succ essfully after startup in July 1987. Before the end of the program in 1991, after 15,000 hours of operation, 18 different feedstocks were gasified at the plant, includi ng domestic coals ranging from ligni te to high-sulfur bituminous, three widely traded foreign coals, and petroleu m coke. The Deer Park unit produced superheated high-pressure steam in the waste he at recovery boiler. The plant al so had facilities for extensive environmental monitoring and for sidestream testing of several AGR processes, including Sulfinol-D, Sulfinol-M, highly loaded MDEA, and various wast ewater treatment schemes. In spring 1989, Shell announced that its technology had been select ed for the large commercialscale Demkolec B.V. IGCC plant at Buggenum, n ear Roermond, in The Netherlands. This plant generates 250 MW of IGCC electricity with a single Shell gasifier consuming 1,814 tonnes/day (2,000 TPD) (dry basis) of coal. The pl ant was originally owned and operated by Samenwerkende Electriciteits-Produ ctiebedrijven NV (SEP), a consor tium of Dutch utilities, and began operation in 1994. In 2000 the plant wa s purchased by Nuon. Shell was extensively involved in the design, startup, and in itial operation of this plant. A key feature of this design is the use of extraction air from the combustion tu rbine air compressor to feed the oxygen plant. Gasifier Capacity – The large gasifier operating in The Netherlands has a bituminous coalhandling capacity of 1,633 tonnes/day (1,800 TPD) and produces dry gas at a rate of 158,575 Nm 3 

### /h (5.6 million scf/h) with an energy c ontent of about 1,792 MMkJ/h (1,700 MMBtu/h) (HHV). This gasifier was sized to match the fuel gas require ments for the Siemens/Kraftwerk Union V-94.2 combustion turbine and could easily be scaled up to match advanced F Class turbine requirements. Distinguishing Characteristics – The key advantage of the She ll coal gasification technology is its lack of feed coal limitati ons. One of the major achieveme nts of the Shell development program has been the successful gasification of a wi de variety of coals ranging from anthracite to brown coal. The dry pulverized feed system developed by Shell uses all coal types with essentially no operating and design modifications (provide d the drying pulverizers are appropriately sized). The dry fed Shell gasi fier also has the a dvantage of lower oxygen requirement than comparable slurry fed entrained flow gasifiers. Entrained-flow slagging gasifier s have fundamental environmen tal advantages over fluidizedbed and moving-bed gasifiers. They produce no hydrocarbon liquids, and th e only solid waste is an inert slag. The dry feed en trained-flow gasifiers also have minor environmental advantages over the slurry feed entrained-flow gasifiers. They produce a higher H 2 

### S/CO 2 

### ratio acid gas, which improves sulfur recovery and lessens some of the gray water pr ocessing and the fixedsalts blowdown problems associ ated with slurry feeding.Cost and Performance Comparison of Fossil Energy Power Plants

228 

### A disadvantage of the Shell coal gasificati on technology is the high waste heat recovery (synthesis gas cooler) duty. As with the other slagging gasifiers, the Shell process has this disadvantage due to its high operating temperature. The ability to feed dry solids minimizes the oxygen requirement and makes the Shell gasifier so mewhat more efficient than entrained flow gasifiers employing slurry feed syst ems. The penalty paid for this increase in efficiency is a coal feed system that is more costly and operationall y more complex. Demonstration of the reliability and safety of the dry coal feeding system was essential for the successful development of the Shell technology. The high operating temperat ure required by all entr ained-flow slagging processes can result in relatively high capital and maintenance cost s. However, the Shell gasifier employs a cooled refractory, which requires fewer changeouts than an uncooled refractory. Life of a water wall is determined by metallurgy and temperature and can provide a significant O&M cost benefit over refractory lined gasifiers. Important Coal Characteristics – Characteristics desirable for coal considered for use in the Shell gasifier include moderate ash fusion temper ature and relatively low as h content. The Shell gasifier is extremely flexible; it can handle a wide variety of different co als, including lignite. High-ash fusion-temperature coals may require flux addition for optimal gasifier operation. The ash content, fusion temperature, and compos ition affect the required gasifier operating temperature level, oxygen requirements, heat re moval, slag management, and maintenance. However, dry feeding reduces the negative effect s of high ash content re lative to slurry feed gasifiers.

3.4.2 P ROCESS 

### D ESCRIPTION 

### In this section the overall Shell gasification process for Case 5 is described. The system description follows the BFD in Exhibit 3-81 and stream numbers reference the same Exhibit. The tables in Exhibit 3-82 provide process data for the numbered streams in the BFD.
Coal Preparation and Feed Systems Coal receiving and handling is common to all cases and was covered in Section 3.1.1. The receiving and handling subsystem ends at the coal silo. The Shell process uses a dry feed system which is sensitive to the coal moisture content. Coal moisture consists of two parts, surface moisture and inherent moisture. For coal to flow smoothly through the lock hoppers, the surface moisture must be removed. The Illinois No. 6 co al used in this study contains 11.12 percent total moisture on an as-received basis (stream 9). It was assumed that the coal must be dried to 5 percent moisture to allow for smooth fl ow through the dry feed system (stream 10). The coal is simultaneously crushed and dried in the coal mill then delivered to a surge hopper with an approximate 2-hour capacity. The drying medium is provided by combining the off-gas from the Claus plant TGTU and a slipstream of clean syngas (stream 8) and passing them through an incinerator. The incinerator flue gas, with an oxygen content of 6 vol%, is then used to dry the coal in the mill. The coal is drawn from the surge hoppers and fe d through a pressurization lock hopper system to a dense phase pneumatic conveyor, which uses nitr ogen from the ASU to convey the coal to the gasifiers.Cost and Performance Comparisonof Fossil Energy Power Plants229Exhibit 3-81 Case 5 ProcessFlow Diagram, Shell IGCC without CO2CaptureCost and Performance Comparisonof Fossil Energy Power Plants230Exhibit 3-82 Case 5 Stream Table, Shell IGCC without CO2Capture123456789A10A11 12 13V-L Mole FractionAr 0.0094 0.0263 0.0360 0.0024 0.0360 0.0000 0.0000 0.0105 0.0000 0.0000 0.0000 0.0097 0.0097CH40.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0004 0.0000 0.0000 0.0000 0.0004 0.0004CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.6151 0.0000 0.0000 0.0000 0.5716 0.5716CO20.0003 0.0091 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0211 0.0211COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.00000.0000 0.0000 0.0000 0.0000 0.0000 0.0007 0.0007H20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3122 0.0000 0.0000 0.0000 0.2901 0.2901H2O0.0104 0.2820 0.0000 0.0004 0.0000 1.0000 0.0000 0.0014 1.0000 1.0000 0.0000 0.0364 0.0364H2S0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0081 0.0081N20.7722 0.4591 0.0140 0.9918 0.0140 0.0000 1.0000 0.0599 0.0000 0.0000 0.0000 0.0585 0.0585NH30.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0033 0.0033O20.2077 0.2235 0.9500 0.0054 0.9500 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000SO20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.00001.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000V-L Flowrate (lbmol/hr)37,250 1,938 225 38,900 10,865 2,424 2,019 447 2,796 1,165 0 75,202 40,232V-L Flowrate (lb/hr) 1,074,830 51,432 7,250 1,091,540350,168 43,673 56,553 8,949 50,331 20,982 0 1,548,350 828,347Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0402,289 402,289 45,315 0 0Temperature (°F) 232 70 90 385 518 650 560 124 59 215 2,600 1,635 398Pressure (psia) 190.6 16.4 125.0 460.0 740.0 740.0 815.0 516.7 14.7 14.7 614.7 614.7 574.7Enthalpy (BTU/lb)B55.3 26.8 12.5 88.0 107.7 1311.5 132.2 33.1 11,676 --- 1,167 619.8 160.2Density (lb/ft3)0.741 0.104 0.683 1.424 2.272 1.1192.086 1.651 --- --- --- 0.563 1.286Molecular Weight 28.854 26.545 32.229 28.060 32.229 18.015 28.013 20.011 --- --- --- 20.589 20.589A - Solids flowrate includes dry coal; V-L flowrate includes slurry water and water from coalB - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparisonof Fossil Energy Power Plants231Exhibit 3-82 Case 5 Stream Table, Shell IGCC without CO2Capture (continued)14 15 16 17 18 19 20 21 22 23 24 25 26V-L Mole FractionAr 0.0097 0.0101 0.0101 0.0105 0.0086 0.0086 0.0003 0.0000 0.0041 0.0094 0.0094 0.0088 0.0088CH40.0004 0.0004 0.0004 0.0004 0.0003 0.0003 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000CO 0.5699 0.5940 0.5940 0.6151 0.5080 0.5080 0.0112 0.0000 0.0674 0.0000 0.0000 0.0000 0.0000CO20.0217 0.0226 0.0226 0.0006 0.0005 0.0005 0.6315 0.0000 0.4947 0.0003 0.0003 0.0755 0.0755COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000H20.2893 0.3015 0.3015 0.3122 0.2579 0.2579 0.0062 0.0000 0.0179 0.0000 0.0000 0.0000 0.0000H2O0.0387 0.0015 0.0015 0.0014 0.1752 0.1752 0.0042 0.0000 0.3199 0.0108 0.0108 0.0847 0.0847H2S0.0088 0.0091 0.0091 0.0000 0.0000 0.0000 0.2596 0.0000 0.0015 0.0000 0.0000 0.0000 0.0000N20.0583 0.0608 0.0608 0.0599 0.0494 0.0494 0.0870 0.0000 0.0898 0.7719 0.7719 0.7277 0.7277NH30.0032 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000O20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2076 0.2076 0.1033 0.1033SO20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0045 0.0000 0.0000 0.0000 0.0000Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000V-L Flowrate (lbmol/hr)40,353 38,715 38,715 36,914 44,695 44,695 1,353 0 2,088 248,660 16,712 302,092 302,092V-L Flowrate (lb/hr) 830,529 801,076 801,076 738,696 878,868 878,868 53,431 0 67,836 7,173,720 482,146 8,728,000 8,728,000Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 11,307 0 0 0 0 0Temperature (°F) 351 95 95 124 312 385 124 344 280 59 811 1,105 270Pressure (psia) 549.7 529.7 519.7 516.7 465.0 460.0 60.0 23.6 23.6 14.7 234.9 15.2 15.2Enthalpy (BTU/lb)B146.2 22.6 22.6 33.1 269.4 301.3 21.9 -102.1 255.2 13.8 200.3 340.0 116.4Density (lb/ft3)1.300 1.841 1.807 1.651 1.111 0.998 0.378 --- 0.097 0.076 0.497 0.026 0.056Molecular Weight 20.581 20.692 20.692 20.011 19.664 19.664 39.490 --- 32.491 28.849 28.849 28.892 28.892B - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparison of Fossil Energy Power Plants

232 

### Gasifier There are two Shell dry feed, pressurized, upflow, entrained, slagging gasifiers, operating at 4.2 MPa (615 psia) and processing a total of 4,927 tonnes/day (5,431 TPD) of as-received coal. Coal reacts with oxygen and steam at a temper ature of 1427°C (2600°F) to produce principally hydrogen and carbon monoxide with lit tle carbon dioxide formed. The gasifier includes a refractory-lined water wall that is also protecte d by molten slag that solidifies on the cooled walls.
Raw Gas Cooling/Particulate Removal High-temperature heat recovery in each gasifier train is accomp lished in three steps, including the gasifier jacket, which cools the syngas by maintaining the reaction temperature at 1427°C (2600°F). The product gas from th e gasifier is cooled to 891 ° C (1635 ° F) by adding cooled recycled fuel gas to lower the temperature be low the ash melting point. Gas (stream 12) then goes through a raw gas cooler, which lo wers the gas temperature from 891 ° C (1635 ° F) to 316 ° C (600 ° F), and produces high-pressure steam for use in the steam cycle. The syngas is further cooled to 203°C (398°F) (stream 13) by heating wa ter that is used to humidify the sweet syngas prior to the combustion turbine. After passing through the raw gas cooler, the syngas passes through a cyclone and a raw gas candle filter where a majority of the fine particle s are removed and returned to the gasifier with the coal fuel. The filter consists of an array of ceramic candle elements in a pressure vessel. Fines produced by the gasification system are reci rculated to extinction. 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 fo r disposal (stream 11). Lockhoppers are used to reduce the pressure of the solids from 4.2 to 0.1 MPa (615 to 15 psia). The syngas scrubber removes additional particulate matter further downstream.
Quench Gas Compressor About 45 percent of the raw gas from the filter is recycled back to the gasifier as quench gas. A single-stage compressor is utilized to boost the pr essure of a cooled fuel gas stream from 4.0 MPa (575 psia) to 4.2 MPa (615 psia ) to provide quench gas to cool the gas stream from the gasifier.
Syngas Scrubber/Sour Water Stripper The raw synthesis gas exiting the ceramic particulate filter at 203 ° C (398 ° F) (stream 13) then enters the scrubber for removal of chlorides and remaining part iculate. The quench scrubber washes the syngas in a counter-current flow in two packed beds. The syngas leaves the scrubber saturated at a temperature of 110 ° C (230oF). The quench scrubber re moves essentially all traces of entrained particles, principally unconverted carbon, slag, and metals. The bottoms from the scrubber are sent to the slag remova l and handling system for processing. The sour water stripper removes NH 3 

### , SO 2 

### , and other impurities from the waste stream of the scrubber. The sour gas stripper consists of a so ur drum that accumulates sour water from the gas scrubber and condensate from synthesis gas coolers. Sour water from the drum flows to the sour stripper, which consists of a pack ed column with a steam-heated re boiler. Sour gas is strippedCost and Performance Comparison of Fossil Energy Power Plants

233 

### from the liquid and sent to the sulfur recovery unit. Remaini ng water is sent to wastewater treatment.
COS Hydrolysis, Mercury Removal and Acid Gas Removal
H 2 

### S and COS are at significant concentrations, re quiring removal for the power plant to achieve the low design level of SO 2 

### emissions. H 2 

### S is removed in an acid ga s removal process; however, because COS is not readily removable, it is first catalytical ly converted to H 2 

### S in a COS hydrolysis unit. Following the water scrubber, the gas is reheated to 177 ° C (350 ° F) and fed to the COS hydrolysis reactor. The COS in the sour gas is hydrolyzed with steam over a catalyst bed to H 2 

### S, which is more easily removed by the AGR solvent. Before the raw fuel gas can be treated in the AGR process (stream 14), it mu st be cooled to about 35 ° C (95 ° F). During this cooling through a series of heat exchangers, part of the water va por condenses. This wate r, which contains some NH 3 

### , is sent to the sour water stripper. The cooled syngas (stream 15) then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.4). The Sulfinol process, developed by Shell in the early 1960s, is a combination process that uses a mixture of amines and a physical solvent. The solvent consists of an aqueous amine and sulfolane. Sulfinol-D uses diisopropanolamine (DIPA), while Sulfinol-M uses MDEA. The mixed solvents allow for better solvent loadings at high acid gas part ial pressures and higher solubility of COS and organic su lfur compounds than straight a queous amines. Sulfinol-M was selected for this application. The sour syngas is fed directly into an HP cont actor. The HP contactor is an absorption column in which the H 2 

### S, COS, CO 2 

### , and small amounts of H 2 

### and CO are removed from the gas by the Sulfinol solvent. The overhead gas stream from the HP contactor is then washed with water in the sweet gas scrubber before l eaving the unit as the feed gas to the su lfur polishing unit.
The rich solvent from the bottom of the HP c ontactor flows through a hydraulic turbine and is flashed in the rich solvent flash vessel. The flashed gas is then scrubbed in the LP contactor with lean solvent to remove H 2 

### S and COS. The overhead from the LP contactor is flashed in the LP KO drum. This gas can be used as a util ity fuel gas, consis ting primarily of H 2 

### and CO, at 0.8 MPa (118 psia) and 38 ° C (101 ° F). The solvent from the bottom of the LP contactor is returned to the rich solvent flash vessel. Hot, lean solvent in the lean/rich solvent exchan ger then heats the flashed rich solvent before entering the stripper. Th e stripper strips the H 2 

### S, COS, and CO 2 

### from the solvent at low pressure with heat supplied through the st ripper reboiler. The acid gas st ream to sulfur recovery/tail gas cleanup is recovered as the flash gas from the st ripper accumulator. The lean solvent from the bottom of the stripper is cooled in the lean/rich solvent exchanger and the lean solvent cooler. Most of the lean solvent is pumped to the HP contactor. A small amount goes to the LP contactor. The Sulfinol process remove s essentially all of the CO 2 

### along with the H 2 

### S and COS. The acid gas fed to the SRU contains 26 vol% H 2 

### S and 63 vol% CO 2 

### . The CO 2 

### passes through the SRU, the TGTU and ultimately is vented through th e coal dryer. Since the amount of CO 2 

### in the syngas is small initially, this doe s not have a significant effect on the mass flow reaching the gasCost and Performance Comparison of Fossil Energy Power Plants

234 

### turbine. However, the costs of the sulfur rec overy/tail gas cleanup are hi gher than for a sulfur removal process producing an acid gas str eam with a higher sulfur concentration.

Claus Unit The sulfur recovery unit is a Claus bypass type sulfur recovery unit utilizing oxygen (stream 3) instead of air and followed by an amine-based SCOT tail gas unit. The Claus plant produces molten sulfur (stream 21) by reacting approximately one third of the H 2 

### S in the feed to SO 2 

### , then reacting the H 2 

### S and SO 2 

### to sulfur and water. The comb ination 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 re duces the overall cost of the sulfur recovery plant. The sulfur plant produces approximately 123 tonnes/day (136 TPD) of elemental sulfur. Feed for this case consists of acid gas from bot h the acid gas cleanup unit (stream 20) and a vent stream from the sour water stripper in the gasifier section. Vent gas from the tail gas treatment unit is combined with a slipstream of clean syngas (str eam 8), passed through an incinerator, and the hot, nearly inert incinerator off gas is used to dry coal before being ve nted to the atmosphere. In the furnace waste heat boiler, 12,283 kg/h (27,080 lb/h) of 3.6 MPa (525 psia) steam are generated. This steam is used to satisfy all Claus process preheating and reheating requirements as well as to provide some steam to the medium -pressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) steam for the low-pressure steam header.

Power Block Clean syngas exiting the Sulfinol absorber (s tream 17) is humidified because there is not sufficient nitrogen from the ASU to provide th e level of dilution required. The moisturized syngas (stream 18) is reheated (stream 19), furt her diluted with nitrogen from the ASU (stream 4) and steam, and enters the advanced F Cl ass combustion turbine (CT) burner. The CT compressor provides combustion air to the burner a nd also 31 percent of the air requirements in the ASU (stream 24). The exhaust gas exits th e CT at 596°C (1,105°F) (stream 25) and enters the HRSG where additional heat is recovered unti l the flue gas exits the HRSG at 132°C (270°F) (stream 26) and is discharged through the plant st ack. The steam raised in the HRSG is used to power an advanced, commercially available steam turbine using a 12.4 MPa/566°C/566°C (1800 psig/1050°F/1050°F) steam cycle.
Air Separation Unit (ASU) The ASU is designed to produce a nominal out put of 3,900 tonnes/day (4,290 TPD) of 95 mole percent O 2 

### for use in the gasifier (stream 5) and sulf ur recovery unit (stream 3). The plant is designed with two production trains . The air compressor is powe red by an electric motor. Approximately 11,900 tonnes/day (13,100 TPD) of n itrogen are also recovered, compressed, and used as dilution in the gas turbin e combustor. About 6.7 percent of the gas turbine air is used to supply approximately 31 percent of the ASU air requirements.

Balance of Plant Balance of plant items we re covered in Sections 3.1.9, 3.1.10 and 3.1.11.Cost and Performance Comparison of Fossil Energy Power Plants

235 

### 3.4.3 K EY 

### S YSTEM 

### A SSUMPTIONS 

### System assumptions for Cases 5 and 6, Shell IGCC with and without CO 2 

### capture, are compiled in Exhibit 3-83.

Balance of Plant – Cases 5 and 6 The balance of plant assumptions are common to all cases and we re presented previously in Exhibit 3-17.Cost and Performance Comparison of Fossil Energy Power Plants

236 

### Exhibit 3-83 Shell IGCC Plant Study Configuration Matrix

Case 5 6 Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)
O 2 

### :Coal Ratio, kg O 2 

### /kg dry coal 0.827 0.827 Carbon Conversion, % 99.5 99.5 Syngas HHV at Gasifier Outlet, kJ/Nm 3 

### (Btu/scf) 10,610 (285) 10,610 (285)
Steam Cycle, MPa/°C/°C (psig/ ° F/ ° F) 12.4/566/566 (1800/1050/1050) 12.4/538/538 (1800/1000/1000) Condenser Pressure, mm Hg (in Hg) 51 (2.0) 51 (2.0)

Combustion Turbine 2x Advanced F Class (232 MW output each) 2x Advanced F Class (232 MW output each) Gasifier Technology Shell Shell Oxidant 95 vol% Oxygen 95 vol% Oxygen
Coal Illinois No. 6 Illinois No. 6 Coal Feed Moisture Content, % 5 5 COS Hydrolysis Yes Occurs in SGS
Sour Gas Shift No Yes
H 2 

### S Separation Sulfinol-M Selexol 1 st 

### Stage Sulfur Removal, % 99.5 99.7

Sulfur Recovery Claus Plant with Tail Gas Treatment / Elemental Sulfur Claus Plant with Tail Gas Treatment / Elemental Sulfur

Particulate Control Cyclone, Candle Filter, Scrubber, and AGR Absorber Cyclone, Candle Filter, Scrubber, and AGR Absorber Mercury Control Carbon Bed Carbon Bed

NOx Control MNQC (LNB), N 2 

### Dilution, Humidification and steam dilution MNQC (LNB), N 2 

### Dilution and Humidification

CO 2 

### Separation N/A Selexol 2 nd 

### Stage
CO 2 

### Capture N/A 90.8% from Syngas
CO 2 

### Sequestration N/A Off-site Saline FormationCost and Performance Comparison of Fossil Energy Power Plants

237 

### 3.4.4 S PARING 

### P HILOSOPHY 

### The sparing philosophy for Cases 5 and 6 is pr ovided 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. The plant design consists of the following major subsystems:

• Two air separation units (2 x 50%)

• Two trains of coal drying and dry feed systems (2 x 50%)

• Two trains of gasification, incl uding gasifier, synthesis gas cooler, cyclone, and barrier filter (2 x 50%).

• Two trains of syngas clean-up process (2 x 50%).

• Two trains of Sulfinol-M acid gas gas removal in Case 5 and two-stage Selexol in Case 6 (2 x 50%),

• One train of Claus-based sulfur recovery (1 x 100%).

• Two combustion turbine/HRSG tandems (2 x 50%).

• One steam turbine (1 x 100%).

3.4.5 C ASE 

### 5 P ERFORMANCE 

### R ESULTS 

### The plant produces a net output of 636 MWe at a net plant efficiency of 41.1 percent (HHV basis). Shell has reported expected efficienci es using bituminous coal of around 44-45 percent (HHV basis), although this va lue excluded the net power impact of coal drying. [ 52] Accounting for coal drying would reduce the efficiency by only about 0.5-1 per centage points so the efficency results for the Shell ca se are still lower in this study than reported by the vendor. Overall performance for the entire plant is summarized in Exhibit 3-84 which includes auxiliary power requirements. The ASU accounts for ove r 76 percent of the to tal auxiliary load distributed between the main air compressor, the oxygen compressor, the nitrogen compressor, and ASU auxiliaries. The cooling water syst em, including the circulating water pumps and cooling tower fan, accounts for over 4 percent of the auxiliary load, and the BFW pumps account for an additional 3.6 percent. All other individual auxiliary loads are less than 3 percent of the total.Cost and Performance Comparison of Fossil Energy Power Plants

238 

### Exhibit 3-84 Case 5 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Gas Turbine Power 464,030 Steam Turbine Power 283,990 TOTAL POWER, kWe 748,020 AUXILIARY LOAD SUMMARY, kWe Coal Handling 430 Coal Milling 2,110 Slag Handling 540 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 41,630 Oxygen Compressor 10,080 Nitrogen Compressor 37,010 Syngas Recycle Compressor 1,650 Incinerator Air Blower 160 Boiler Feedwater Pumps 4,670 Condensate Pump 230 Flash Bottoms Pump 200 Circulating Water Pumps 3,150 Cooling Tower Fans 1,630 Scrubber Pumps 120 Sulfinol Unit Auxiliaries 660 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Miscellaneous Balance of Plant (Note 1) 3,000 Transformer Loss 2,550 TOTAL AUXILIARIES, kWe 112,170 NET POWER, kWe 635,850 Net Plant Efficiency, % (HHV) 41.1 Net Plant Heat Rate (Btu/kWh) 8,306 CONDENSER COOLING DUTY 10 6 

### kJ/h (10 6 

### Btu/h) 1,401 (1,329) CONSUMABLES As-Received Coal Feed, kg/h (lb/h) 205,305 (452,620) Thermal Input, kWt 1,547,493 Raw Water Usage, m 3 

### /min (gpm) 14.4 (3,792) Note 1: Includes plant control systems, ligh ting, HVAC and miscellaneous low voltage loadsCost and Performance Comparison of Fossil Energy Power Plants

239 

### Environmental Performance The environmental targets for emissions of emissions of Hg, NOx, SO 2 

### and particulate matter were presented in Section 2.4. A summary of the plant air emissions for Case 5 is presented in Exhibit 3-85.

Exhibit 3-85 Case 5 Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 80% capacity factor kg/MWh (lb/MWh)

SO 2 

### 0.0053 (0.0124) 209 (230) 0.040 (0.088) NO X 

### 0.025 (0.058) 982 (1,082) 0.187 (0.413) Particulates 0.003 (0.0071) 119 (131) 0.023 (0.050) Hg 0.25x10 -6 

### (0.57x10 -6 

### ) 0.010 (0.011) 1.8x10 -6 

### (4.0x10 -6 

### )

CO 2 

### 85.9 (200) 3,351,000 (3,694,000) 639 (1,409)

CO 2 1 

### 752 (1,658)

1 

### CO 2 

### emissions based on net power instead of gross power

The low level of SO 2 

### emissions is achieved by capture of th e sulfur in the gas by the Sulfinol-M AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel gas down to a level of less than 30 ppmv. This re sults in a concentration in the flue gas of less than 4 ppmv. The H 2 

### S-rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is treated using an amine based system to capture most of the remaining sulfur. The cl eaned gas from the tail gas treatment unit is combined with a slipstream of clean syngas, pa ssed through an incinerator, and the hot, inert incinerator offgas is used to dry coal pr ior to being vented to atmosphere. The SO 2 

### emissions in Exhibit 3-85 include both the stack em issions and the coal dryer emissions.
NO X 

### emissions are limited by the use of nitrogen dilution, humidification and steam dilution to 15 ppmvd (as NO 2 

### @ 15 percent O 2 

### ). Ammonia in the syngas is removed with process condensate prior to the low-temperature AGR pro cess and destroyed in th e Claus plant burner. This helps lower NO X 

### levels as well. Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only. Ninety five percent of the mercury is capture d from the syngas by an activated carbon bed. CO 2 

### emissions represent the uncontro lled discharge from the process. The carbon balance for the plant is shown in Exhibit 3-86. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in th e air is not neglected here since the Aspen model accounts for air components th roughout. Carbon leaves the plant as unburned carbon in the slag, as dissolved CO 2 

### in the wastewater blowdown stream, and as CO 2 

### in the stackCost and Performance Comparison of Fossil Energy Power Plants

240 

### gas, ASU vent gas and coal dryer vent gas. Carbon in the wastewater blowdown stream is calculated by difference to close the material balance.

Exhibit 3-86 Case 5 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) Coal 130,882 (288,545) Slag 656 (1,446) Air (CO 2 

### ) 471 (1,039) Stack Gas 124,162 (273,731) ASU Vent 96 (212) Coal Dryer 6,252 (13,783) Wastewater 187 (412) Total 131,353 (289,584) Total 131,353 (289,584)

Exhibit 3-87 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output incl udes the sulfur recovered in the Claus plant, dissolved SO 2 

### in the wastewater blowdown stream, sulfur in the coal dr ying gas, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible , and the sulfur content of the blowdown stream is calculated by difference to close the material bala nce. The total sulfur capture is represented by the following fraction: (Sulfur byproduct/Sulfur in the coal) or (11,307/11,361) or 99.5 percent

Exhibit 3-87 Case 5 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) Coal 5,153 (11,361) Elemental Sulfur 5,129 (11,307) Stack Gas 14 (30) Coal Dryer Vent 1 (3) Wastewater 9 (21) Total 5,153 (11,361) Total 5,153 (11,361)

Exhibit 3-88 shows the overall water balance for the plant. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the total amount of water required for a particular process. Some water is recovered within the process, primarily as syngas condens ate, and that water is re-used as internal recycle. Raw water makeup is the difference between wa ter demand and internal recycle.Cost and Performance Comparison of Fossil Energy Power Plants

241 

### Exhibit 3-88 Case 5 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle,

m 3 

### /min (gpm) Raw Water Makeup,

m 3 

### /min (gpm)
Gasifier Steam 0.3 (87) 0 0.3 (87)
Humidifier 1.1 (293) 0 1.1 (293)
Slag Handling 0.5 (118) 0.5 (118) 0
Scrubber 0.2 (61) 0 0.2 (61)
CT Steam Dilution 0.5 (132) 0 0.5 (132)
BFW Makeup 0.2 (39) 0 0.2 (39)
Cooling Tower Makeup 12.2 (3,233) 0.2 (54) 12.0 (3,180)

Total 15.0 (3,963) 0.7 (171) 14.3 (3,792)

Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-89 through Exhibit 3-93:

• Coal gasification and air separation unit

• Syngas cleanup

• Sulfur recovery and tail gas recycle

• Combined cycle power generation

• Steam and feedwater An overall plant energy balance is provided in tabular form in Exhibit 3-61. The power out is the combined combustion turbine and steam turbin e power prior to generator losses. The power at the generator terminals (shown in Exhibit 3-84) is calculated by multiplying the power out by a combined generator efficiency of 98.3 percent.Cost and Performance Comparison of Fossil Energy Power Plants

242 

### This page intentionally left blankCost and Performance Comparisonof Fossil Energy Power Plants243Exhibit 3-89 Case 5 Coal Gasification and AirSeparation Unit Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants244Exhibit 3-90 Case 5 Syngas Cleanup Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants245Exhibit 3-91 Case 5 Sulfur Recovery and Tail Gas Recycle Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants246Exhibit 3-92 Case 5 Combined Cycle PowerGeneration Heat andMass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants247Exhibit 3-93 Case 5 Steam and Feedwater Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants248This page intentionally left blankCost and Performance Comparison of Fossil Energy Power Plants

249 

### Exhibit 3-94 Case 5 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total
Heat In (MMBtu/hr) Coal 5,280.2 4.4 5,284.6 ASU Air 14.5 14.5 CT Air 98.8 98.8 Incinerator Air 1.2 1.2 Water 9.4 9.4 Auxiliary Power 382.7 382.7 Totals 5,280.2 128.4 382.7 5,791.3 Heat Out (MMBtu/hr) ASU Intercoolers 171.4 171.4 ASU Vent 1.4 1.4 Slag 20.4 32.5 52.9 Sulfur 45.0 (1.2) 43.8 Dryer Stack Gas 53.1 53.1 HRSG Flue Gas 1015.9 1,015.9 Condenser 1,329.0 1,329.0 Process Losses 526.1 520.2 Power 2,597.6 2,597.6 Totals 65.4 3,128.3 2,597.6 5,791.3 (1) Process Losses are calculated by differen ce and reflect various gasification, turbine, HRSG and other heat and work losses. Aspe n flowsheet balance is within 0.5 percent.Cost and Performance Comparison of Fossil Energy Power Plants

250 

### 3.4.6 C ASE 

### 5

- M AJOR 

### E QUIPMENT 

### L IST 

### Major equipment items for the Shell gasifier with no CO 2 

### capture are shown in the following tables. The accounts used in the equipment lis t correspond to the account numbers used in the cost estimates in Section 3.4.7. In general, the design c onditions include a 10 percent contingency for flows and heat duties and a 21 pe rcent contingency for heads on pumps and fans.
ACCOUNT 1 COAL HANDLING

Equipment No. Description Type Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0
3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0
5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0
8 Reclaim Hopper N/A 2 1
9 Feeder Vibratory 2 1
10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor reduction 2 0

14 As-Fired Coal Sampling System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0

17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 3 0 N/A

336 tonne/h (370 tph)

726 tonne (800 ton)

45 tonne (50 ton)
172 tonne/h (190 tph)

8 cm x 0 - 3 cm x 0 (3" x 0 - 1-1/4" x 0) 336 tonne/h (370 tph)

172 tonne (190 ton) N/A

N/A

336 tonne/h (370 tph)

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph) N/A
1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)
1,134 tonne/h (1,250 tph)Cost and Performance Comparison of Fossil Energy Power Plants

251 

### ACCOUNT 2 COAL PREPARATION AND FEED
Equipment No. Description Type Operating Qty. Spares

1 Feeder Vibratory 3 0
2 Conveyor No. 6 Belt w/tripper 1 0
3 Roller Mill Feed Hopper Dual Outlet 1 0
4 Weigh Feeder Belt 2 0
5 Coal Drying and Pulverization Rotary 2 0 109 tonne/h (120 tph)
109 tonne/h (120 tph)

Design Condition

73 tonne/h (80 tph)
227 tonne/h (250 tph)
454 tonne (500 ton)Cost and Performance Comparison of Fossil Energy Power Plants

252 

### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT
Equipment No. Description Type Operatin g Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 2 0

2 Condensate Pumps Vertical canned 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multistage, centrifugal 2 1

7 Auxiliary Boiler Shop fabricated, water tube 1 0

8 Service Air Compressors Flooded Screw 2 1

9 Instrument Air Dryers Duplex, regenerative 2 1

10 Closed Cylce Cooling Heat Exchangers Plate and frame 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 2 1

12 Engine-Driven Fire Pump Vertical turbine, diesel engine 1 1

13 Fire Service Booster Pump Two-stage horizontal centrifugal 1 1

14 Raw Water Pumps Stainless steel, single suction 2 1

15 Filtered Water Pumps Stainless steel, single suction 2 1

16 Filtered Water Tank Vertical, cylindrical 2 0

17 Makeup Water Demineralizer Anion, cation, and mixed bed 2 0

18 Liquid Waste Treatment System 1 0 151 lpm @ 302 m H2O (40 gpm @ 990 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C (40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) Design Condition

590,529 liters (156,000 gal)

6,360 lpm @ 91 m H2O (1,680 gpm @ 300 ft H2O)

443,160 kg/h (977,000 lb/h)

IP water: 1,060 lpm @ 223 m H2O (280 gpm @ 730 ft H2O) HP water: 7,344 lpm @ 1,890 m

H2O (1,940 gpm @ 6,200 ft H2O)

1,590 lpm @ 49 m H2O (420 gpm @ 160 ft H2O) 28 m3/min (1,000 scfm)

58 MMkJ/h (55 MMBtu/h) each
20,820 lpm @ 21 m H2O (5,500 gpm @ 70 ft H2O) 3,785 lpm @ 107 m H2O (1,000 gpm @ 350 ft H2O)

2,650 lpm @ 76 m H2O (700 gpm @ 250 ft H2O) 7,987 lpm @ 18 m H2O (2,110 gpm @ 60 ft H2O)

768,445 liter (203,000 gal)

151 lpm (40 gpm)

10 years, 24-hour storm 2 1 5 High Pressure Feedwater Pump No. 1 Barrel type, multistage, centrifugalCost and Performance Comparison of Fossil Energy Power Plants

253 

### ACCOUNT 4 GASIFIER, ASU AND ACC ESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION
Equipment No. Description Type Operatin g Qty. Spares

1 Gasifier Pressurized dry-feed, entrained bed 2 0

2 Synthesis Gas Cooler Convective spiralwound tube boiler 2 0

3 Synthesis Gas Cyclone High efficiency 2 0

4 Candle Filter Pressurized filter with pulse-jet cleaning 2 0

5 Syngas Scrubber Including Sour Water Stripper Vertical upflow 2 0

6 Raw Gas Coolers Shell and tube with condensate drain 6 0

7 Raw Gas Knockout Drum Vertical with mist eliminator 2 0

8 Saturation Water Economizers Shell and tube 2 0

9 Fuel Gas Saturator Vertical tray tower 2 0

10 Saturator Water Pump Centrifugal 2 2

11 Synthesis Gas Reheater Shell and tube 2 0

12 Flare Stack Self-supporting, carbon steel, stainless steel top, pilot ignition 2 0

13 ASU Main Air Compressor Centrifugal, multistage 2 0

14 Cold Box Vendor design 2 0

15 Oxygen Compressor Centrifugal, multistage 2 0

16 Nitrogen Compressor Centrifugal, multistage 2 0

17 Nitrogen Boost Compressor Centrifugal, multistage 2 0

18 Extraction Air Heat Exchanger Gas-to-gas, vendor design 2 0 481 m3/min @ 2.3 MPa (17,000 scfm @ 340 psia) 120,202 kg/h, 433°C, 1.6 MPa (265,000 lb/h, 811°F, 232 psia)

206,838 kg/h (456,000 lb/h)
syngas 3,681 m3/min @ 1.3 MPa (130,000 scfm @ 190 psia)
2,177 tonne/day (2,400 tpd) of 95% purity oxygen
1,076 m3/min @ 5.1 MPa (38,000 scfm @ 740 psia) 3,540 m3/min @ 3.4 MPa (125,000 scfm @ 490 psia) 207,292 kg/h (457,000 lb/h)
219,085 kg/h, 154°C, 3.2 MPa (483,000 lb/h, 309°F, 465 psia) 2,650 lpm @ 12 m H2O (700 gpm @ 40 ft H2O)
219,085 kg/h (483,000 lb/h) Design Condition

2,722 tonne/day, 4.2 MPa (3,000 tpd, 615 psia)

386,461 kg/h (852,000 lb/h)

207,292 kg/h (457,000 lb/h) Design efficiency 90%

metallic filters

206,838 kg/h (456,000 lb/h)

276,238 kg/h (609,000 lb/h)

200,488 kg/h, 35°C, 3.7 MPa (442,000 lb/h, 95°F, 530 psia)Cost and Performance Comparison of Fossil Energy Power Plants

254 

### ACCOUNT 5 SYNGAS CLEANUP
Equipment No. Description Type Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon bed 2 0

2 Sulfur Plant Claus type 1 0

3 COS Hydrolysis Reactor Fixed bed, catalytic 2 0

4 Acid Gas Removal Plant Sulfinol 2 0

5 Tail Gas Treatment Unit Proprietary amine, absorber/stripper 1 0

6 Tail Gas Treatment Incinerator N/A 1 0 30,255 kg/h (66,700 lb/h) 49°C (120°F) 0.1 MPa (16.4 psia) 200,034 kg/h (441,000 lb/h) 51°C (124°F) 3.6 MPa (520 psia)

64 MMkJ/h (61 MMBtu/h) Design Condition

200,034 kg/h (441,000 lb/h) 35°C (95°F) 3.7 MPa (530 psia)

135 tonne/day (149 tpd)

207,292 kg/h (457,000 lb/h) 177°C (350°F) 3.9 MPa (560 psia)



### ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment No. Description Type Operating Qty.

1 Gas Turbine Advanced F class 2

2 Gas Turbine Generator TEWAC 2 Design Condition

232 MW
260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase



### ACCOUNT 7 HRSG, DUCTING AND STACK

Equipment No. Description Type Operating Qty. Spares

1 Stack CS plate, type 409SS liner 1 0 Design Condition

76 m (250 ft) high x 8.4 m (28 ft) diameter

Main steam - 414,742 kg/h, 12.4 MPa/566°C (914,348 lb/h, 1,800 psig/1,050°F) 2 0 2 Heat Recovery Steam Generator Drum, multi-pressure with economizer section and integral deaerator Reheat steam - 384,205 kg/h, 3.1 MPa/566°C (847,027 lb/h, 452 psig/1,050°F)Cost and Performance Comparison of Fossil Energy Power Plants

255 

### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitiation 1 0

3 Steam Bypass One per HRSG 2 0

4 Surface Condenser Single pass, divided waterbox including
vacuum pumps 1 0 Design Condition

299 MW 12.4 MPa/566°C/566°C (1800 psig/ 1050°F/1050°F)

1,539 MMkJ/h (1,460 MMBtu/h), Inlet water temperature 16°C (60°F),

Water temperature rise 11°C (20°F) 330 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase

50% steam flow @ design steam conditions



### ACCOUNT 9 COOLING WATER SYSTEM
Equipment No. Description Type Operatin g Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 1 0 Design Condition
314,192 lpm @ 30 m (83,000 gpm @ 100 ft) 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 1760 MMkJ/h (1670 MMBtu/h) heat dutyCost and Performance Comparison of Fossil Energy Power Plants

256 

### ACCOUNT 10 SLAG RECOVERY AND HANDLING
Equipment No. Description Type Operating Qty. Spares

1 Slag Quench Tank Water bath 2 0
2 Slag Crusher Roll 2 0
3 Slag Depressurizer Lock Hopper 2 0
4 Slag Receiving Tank Horizontal, weir 2 0
5 Black Water Overflow Tank Shop fabricated 2
6 Slag Conveyor Drag chain 2 0
7 Slag Separation Screen Vibrating 2 0
8 Coarse Slag Conveyor Belt/bucket 2 0
9 Fine Ash Settling Tank Vertical, gravity 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 2 2

11 Grey Water Storage Tank Field erected 2 0

12 Grey Water Pumps Centrifugal 2 2

13 Slag Storage Bin Vertical, field erected 2 0

14 Unloading Equipment Telescoping chute 1 0 211,985 liters (56,000 gal)

38 lpm @ 14 m H2O (10 gpm @ 46 ft H2O)

816 tonne (900 tons)

91 tonne/h (100 tph) 68,138 liters (18,000 gal)

227 lpm @ 433 m H2O (60 gpm @ 1,420 ft H2O) 140,061 liters (37,000 gal)

11 tonne/h (12 tph)
11 tonne/h (12 tph)
11 tonne/h (12 tph) 68,138 liters (18,000 gal) Design Condition

215,770 liters (57,000 gal)
11 tonne/h (12 tph)
11 tonne/h (12 tph)Cost and Performance Comparison of Fossil Energy Power Plants

257 

### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type Operating Qty. Spares

1 CTG Transformer Oil-filled 2 0

3 Auxiliary Transformer Oil-filled 1 1

4 Low Voltage Transformer Dry ventilated 1 1

5 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 2 0

6 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 1 0

7 Medium Voltage Switchgear Metal clad 1 1

8 Low Voltage Switchgear Metal enclosed 1 1

9 Emergency Diesel Generator Sized for emergency shutdown 1 0 Design Condition

24 kV/345 kV, 260 MVA, 3-ph, 60 Hz

2 STG Transformer Oil-filled 24 kV/345 kV, 200 MVA, 3-ph, 60 Hz 1 0

24 kV/4.16 kV, 124 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 19 MVA, 3-ph, 60 Hz

750 kW, 480 V, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz



### ACCOUNT 12 INSTRUMENTATION AND CONTROLS

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) 1 0

3 DCS - Data Highway Fiber optic 1 0 Design Condition

Operator stations/printers and engineering stations/printers

2 DCS - Processor Microprocessor with redundant input/output N/A 1 0

Fully redundant, 25% spareCost and Performance Comparison of Fossil Energy Power Plants

258 

### 3.4.7 C ASE 

### 5

- C OST 

### E STIMATING



### Costs Results The cost estimating methodology was desc ribed previously in Section 2.6. Exhibit 3-95 shows the total plant capital cost summary organized by cost account and Exhibit 3-96 shows a more detailed breakdown of the capital costs. Exhibit 3-97 shows the ini tial and annual O&M costs. The estimated TPC of the Shell gasifier with no CO 2 

### capture is $1,977/kW. Process contingency represents 2.6 percent of the TP C and project contingency repres ents 13.7 percent. The 20-year LCOE is 80.5 mills/kWh.Cost and Performance Comparisonof Fossil Energy Power Plants259Exhibit 3-95 Case 5 Total Plant Cost SummaryClient:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 05 - Shell IGCC w/o CO2Plant Size:635.9 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct IndirectTax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING $12,864 $2,398 $10,080 $0 $0$25,343$2,296 $0 $5,528$33,166$522 COAL & SORBENT PREP & FEED $101,770 $8,108 $17,105 $0 $0$126,983$11,023 $0 $27,601$165,607$2603 FEEDWATER & MISC. BOP SYSTEMS $9,612 $8,441 $8,983 $0 $0$27,035$2,523 $0 $6,636$36,194$574 GASIFIER & ACCESSORIES4.1 Gasifier, Syngas Cooler & Auxiliaries $133,051 $0 $58,510 $0 $0$191,560$17,125 $26,889 $36,009$271,583$4274.2 Syngas Cooling (w/4.1) w/4.1 $0 w/4.1 $0 $0$0$0 $0 $0$0$04.3 ASU/Oxidant Compression $135,222 $0 w/equip. $0 $0$135,222$12,870 $0 $14,809$162,901$2564.4-4.9 Other Gasification Equipment $15,596 $8,787 $10,765 $0 $0$35,147$3,316 $0 $8,369$46,833$74SUBTOTAL 4 $283,868 $8,787 $69,274 $0 $0 $361,929 $33,312 $26,889 $59,188 $481,317 $7575A Gas Cleanup & Piping $52,340 $6,552 $37,224 $0 $0$96,117$9,164 $82 $21,477$126,839$1995BCO2REMOVAL & COMPRESSION$0 $0 $0 $0 $0$0$0 $0 $0$0$06 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator $82,000 $0 $5,071 $0 $0$87,071$8,191 $4,354 $9,962$109,578$1726.2-6.9 Combustion Turbine Other $0 $684 $762 $0 $0$1,446$135 $0 $474$2,055$3SUBTOTAL 6 $82,000 $684 $5,833 $0 $0 $88,517 $8,326 $4,354 $10,436 $111,632 $1767 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator $34,073 $0 $4,848 $0 $0$38,921$3,674 $0 $4,260$46,855$747.2-7.9 Ductwork and Stack $3,174 $2,235 $2,996 $0 $0$8,405$776 $0 $1,494$10,675$17SUBTOTAL 7 $37,247 $2,235 $7,844 $0 $0 $47,326 $4,450 $0 $5,753 $57,529 $908 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $28,510 $0 $4,862 $0 $0$33,372$3,198 $0 $3,657$40,227$638.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,015 $966 $7,277 $0 $0$18,258$1,646 $0 $4,035$23,939$38SUBTOTAL 8 $38,525 $966 $12,138 $0 $0 $51,630 $4,844 $0 $7,692 $64,166 $1019 COOLING WATER SYSTEM $6,512 $7,397 $6,140 $0 $0$20,049$1,841 $0 $4,525$26,415$4210 ASH/SPENT SORBENT HANDLINGSYS $17,384 $1,343 $8,631 $0 $0$27,357$2,605 $0 $3,274$33,236$5211 ACCESSORY ELECTRIC PLANT $21,331 $6,784 $19,452 $0 $0$47,567$4,373 $0 $9,764$61,704$9712 INSTRUMENTATION & CONTROL $9,443 $1,768 $6,339 $0 $0$17,551$1,617 $878 $3,354$23,399$3713 IMPROVEMENTS TO SITE $3,166 $1,866 $7,871 $0 $0$12,903$1,268 $0 $4,251$18,422$2914 BUILDINGS & STRUCTURES $0 $6,247 $7,291 $0 $0$13,537$1,231 $0 $2,414$17,182$27TOTAL COST $676,062 $63,575 $224,205 $0 $0 $963,842 $88,874 $32,202 $171,892 $1,256,810 $1,977TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants260Exhibit 3-96 Case 5 Total Plant Cost DetailsClient:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 05 - Shell IGCC w/o CO2Plant Size:635.9 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING1.1 Coal Receive & Unload $3,378 $0 $1,668 $0 $0 $5,046 $452 $0 $1,100 $6,598 $101.2 Coal Stackout & Reclaim $4,365 $0 $1,069 $0 $0 $5,435 $477 $0 $1,182 $7,094 $111.3 Coal Conveyors $4,059 $0 $1,058 $0 $0 $5,117 $449 $0 $1,113 $6,679 $111.4 Other Coal Handling $1,062 $0 $245 $0 $0 $1,307 $114 $0 $284 $1,705 $31.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.9 Coal & Sorbent Hnd.Foundations $0 $2,398 $6,040 $0 $0 $8,438 $804 $0 $1,848 $11,091 $17SUBTOTAL 1. $12,864 $2,398 $10,080 $0 $0 $25,343 $2,296 $0 $5,528 $33,166 $522 COAL & SORBENT PREP & FEED2.1 Coal Crushing & Drying $38,663 $2,310 $5,692 $0 $0 $46,666 $4,033 $0 $10,140 $60,838 $962.2 Prepared Coal Storage & Feed $1,831 $436 $290 $0 $0 $2,557 $219 $0 $555 $3,332 $52.3 Dry Coal Injection System $60,268 $706 $5,655 $0 $0 $66,630 $5,747 $0 $14,475 $86,852 $1372.4 Misc.Coal Prep & Feed $1,007 $729 $2,220 $0 $0 $3,956 $363 $0 $864 $5,182 $82.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.9 Coal & Sorbent Feed Foundation $0 $3,927 $3,247 $0 $0 $7,174 $662 $0 $1,567 $9,403 $15SUBTOTAL 2. $101,770 $8,108 $17,105 $0 $0 $126,983 $11,023 $0 $27,601 $165,607 $2603 FEEDWATER & MISC. BOP SYSTEMS3.1 FeedwaterSystem $3,370 $5,859 $3,095 $0 $0 $12,325 $1,137 $0 $2,692 $16,154 $253.2 Water Makeup & Pretreating $505 $53 $282 $0 $0 $839 $79 $0 $276 $1,194 $23.3 Other Feedwater Subsystems $1,861 $631 $568 $0 $0 $3,060 $274 $0 $667 $4,000 $63.4 Service Water Systems $291 $594 $2,063 $0 $0 $2,948 $285 $0 $970 $4,203 $73.5 Other Boiler Plant Systems $1,563 $600 $1,487 $0 $0 $3,650 $342 $0 $799 $4,791 $83.6 FO Supply Sys & Nat Gas $300 $567 $529 $0 $0 $1,397 $134 $0 $306 $1,836 $33.7 Waste Treatment Equipment $702 $0 $430 $0 $0 $1,132 $110 $0 $372 $1,614 $33.8 Misc. Equip.(cranes,AirComp.,Comm.) $1,020 $137 $528 $0 $0 $1,685 $162 $0 $554 $2,402 $4SUBTOTAL 3. $9,612 $8,441 $8,983 $0 $0 $27,035 $2,523 $0 $6,636 $36,194 $574 GASIFIER & ACCESSORIES4.1 Gasifier, Syngas Cooler & Auxiliaries $133,051 $0 $58,510 $0 $0 $191,560 $17,125 $26,889 $36,009 $271,583 $4274.2 Syngas Cooling (w/4.1) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.3 ASU/Oxidant Compression $135,222 $0 w/equip. $0 $0 $135,222 $12,870 $0 $14,809 $162,901 $2564.4 LT Heat Recovery & FG Saturation $15,596 $0 $5,868 $0 $0 $21,464 $2,063 $0 $4,705 $28,232 $444.5 Misc. Gasification Equipment w/4.1 & 4.2 w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $04.6 Other Gasification Equipment $0 $910 $371 $0 $0 $1,281 $122 $0 $281 $1,684 $34.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $04.9 Gasification Foundations $0 $7,876 $4,526 $0 $0 $12,402 $1,131 $0 $3,383 $16,917 $27SUBTOTAL 4. $283,868 $8,787 $69,274 $0 $0 $361,929 $33,312 $26,889 $59,188 $481,317 $757TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants261Exhibit 3-96 Case 5 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 05 - Shell IGCC w/o CO2Plant Size:635.9 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct IndirectTax Cost $ H.O.& Fee Process Project $ $/kW5A GAS CLEANUP & PIPING5A.1 Sulfinol Sustem $38,450 $0 $17,968 $0 $0 $56,417 $5,378 $0 $12,359 $74,154 $1175A.2 Elemental Sulfur Plant $9,353 $1,856 $12,076 $0 $0 $23,285 $2,246 $0 $5,106 $30,636 $485A.3 Mercury Removal $926 $0 $705 $0 $0 $1,631 $156 $82 $374 $2,243 $45A.4 COS Hydrolysis $2,564 $0 $3,351 $0 $0 $5,916 $571 $0 $1,297 $7,784 $125A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $05A.5 Blowback Gas Systems $1,047 $176 $99 $0 $0 $1,323 $125 $0 $289 $1,737 $35A.6 Fuel Gas Piping $0 $2,272 $1,566 $0 $0 $3,838 $350 $0 $837 $5,025 $85A.9 HGCU Foundations $0 $2,248 $1,460 $0 $0 $3,708 $339 $0 $1,214 $5,261 $8SUBTOTAL 5A. $52,340 $6,552 $37,224 $0 $0 $96,117 $9,164 $82 $21,477 $126,839 $1995B CO2 REMOVAL & COMPRESSION5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator $82,000 $0 $5,071 $0 $0 $87,071 $8,191 $4,354 $9,962 $109,578 $1726.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.9 Combustion Turbine Foundations $0 $684 $762 $0 $0 $1,446 $135 $0 $474 $2,055 $3SUBTOTAL 6. $82,000 $684 $5,833 $0 $0 $88,517 $8,326 $4,354 $10,436 $111,632 $1767 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator $34,073 $0$4,848 $0 $0 $38,921 $3,674 $0 $4,260 $46,855 $747.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07.3 Ductwork $0 $1,603 $1,191 $0 $0 $2,794 $246 $0 $608 $3,648 $67.4 Stack $3,174 $0 $1,193 $0 $0 $4,367 $415 $0 $478 $5,261 $87.9 HRSG,Duct & Stack Foundations $0$632 $611 $0 $0 $1,243 $115 $0 $408 $1,766 $3SUBTOTAL 7. $37,247 $2,235 $7,844 $0 $0 $47,326 $4,450 $0 $5,753 $57,529 $908 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $28,510 $0 $4,862 $0 $0 $33,372 $3,198 $0 $3,657 $40,227 $638.2 Turbine Plant Auxiliaries $196 $0 $450 $0 $0 $646 $63 $0 $71 $779 $18.3 Condenser & Auxiliaries $4,511 $0 $1,442 $0 $0 $5,952 $565 $0 $652 $7,169 $118.4 Steam Piping $5,308 $0 $3,741 $0 $0 $9,048 $772 $0 $2,455 $12,276 $198.9 TG Foundations $0 $966 $1,645 $0 $0 $2,611 $246 $0 $857 $3,714 $6SUBTOTAL 8. $38,525 $966 $12,138 $0 $0 $51,630 $4,844 $0 $7,692 $64,166 $1019 COOLING WATER SYSTEM9.1 Cooling Towers $4,206 $0 $924 $0 $0 $5,130 $486 $0 $842 $6,458 $109.2 Circulating Water Pumps $1,317 $0 $79 $0 $0 $1,397 $119 $0 $227 $1,743 $39.3 Circ.Water System Auxiliaries $117 $0 $17 $0 $0 $134 $13 $0 $22 $169 $09.4 Circ.Water Piping $0 $4,978 $1,270 $0 $0 $6,248 $553 $0 $1,360 $8,162 $139.5 Make-up Water System $288 $0 $409 $0 $0 $697 $66 $0 $153 $916 $19.6 Component Cooling Water Sys $582 $697 $492 $0 $0 $1,771 $164 $0 $387 $2,322 $49.9 Circ.Water System Foundations& Structures$0 $1,723 $2,949 $0 $0 $4,672 $441 $0 $1,534 $6,646 $10SUBTOTAL 9. $6,512 $7,397 $6,140 $0 $0 $20,049 $1,841 $0 $4,525 $26,415 $4210 ASH/SPENT SORBENT HANDLING SYS10.1 Slag Dewatering & Cooling $15,123 $0 $7,464 $0 $0 $22,587 $2,154 $0 $2,474 $27,215 $4310.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.6 Ash Storage Silos $511 $0 $557 $0 $0 $1,068 $103 $0 $176 $1,346 $210.7 Ash Transport & Feed Equipment $691 $0 $166 $0 $0 $856 $79 $0 $140 $1,075 $210.8 Misc. Ash Handling Equipment $1,059 $1,298 $388 $0 $0 $2,745 $259 $0 $451 $3,454 $510.9 Ash/Spent Sorbent Foundation $0 $45 $57 $0 $0 $102 $10 $0 $33 $145 $0SUBTOTAL 10. $17,384 $1,343 $8,631 $0 $0 $27,357 $2,605 $0 $3,274 $33,236 $52TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants262Exhibit 3-96 Case 5 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 05 - Shell IGCC w/o CO2Plant Size:635.9 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW11 ACCESSORY ELECTRIC PLANT11.1 Generator Equipment $905 $0 $902 $0 $0 $1,808 $172 $0 $198 $2,177 $311.2 Station Service Equipment $3,411 $0 $320 $0 $0 $3,732 $354 $0 $409 $4,495 $711.3 Switchgear & Motor Control $6,519 $0 $1,195 $0 $0 $7,714 $715 $0 $1,264 $9,693 $1511.4 Conduit & Cable Tray $0 $310 $10,070 $0 $0 $10,380 $1,259 $0 $2,910 $14,549 $2311.5 Wire & Cable $0 $5,697 $3,832 $0 $0 $9,529 $697 $0 $2,556 $12,782 $2011.6 Protective Equipment $0 $627 $2,378 $0 $0 $3,005 $294 $0 $495 $3,793 $611.7 Standby Equipment $215 $0 $219 $0 $0 $434 $42 $0 $71 $548 $111.8 Main Power Transformers $10,280 $0 $139 $0 $0 $10,419 $789 $0 $1,681 $12,889 $2011.9 Electrical Foundations $0 $150 $396 $0 $0 $546 $52 $0 $179 $777 $1SUBTOTAL 11. $21,331 $6,784 $19,452 $0 $0 $47,567 $4,373 $0 $9,764 $61,704 $9712 INSTRUMENTATION & CONTROL12.1 IGCC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $012.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $012.4 Other Major Component Control $932 $0 $649 $0 $0 $1,581 $152 $79 $272 $2,084 $312.5 Signal Processing Equipment W/12.7 $0 W/12.7 $0 $0 $0 $0 $0 $0 $0 $012.6 Control Boards,Panels & Racks $214 $0 $143 $0 $0 $357 $34 $18 $82 $492 $112.7 Computer & Accessories $4,973 $0 $166 $0 $0 $5,139 $487 $257 $588 $6,471 $1012.8 Instrument Wiring & Tubing $0 $1,768 $3,700 $0 $0 $5,468 $464 $273 $1,551 $7,756 $1212.9 Other I & C Equipment $3,324 $0 $1,682 $0 $0 $5,006 $480 $250 $860 $6,597 $10SUBTOTAL 12. $9,443 $1,768 $6,339 $0 $0 $17,551 $1,617 $878 $3,354 $23,399 $3713 Improvements to Site13.1 Site Preparation $0 $99 $2,139 $0 $0 $2,238 $221 $0 $738 $3,197 $513.2 Site Improvements $0 $1,767 $2,366 $0 $0 $4,132 $406 $0 $1,361 $5,900 $913.3 Site Facilities $3,166 $0 $3,366 $0 $0 $6,532 $641 $0 $2,152 $9,325 $15SUBTOTAL 13. $3,166 $1,866 $7,871 $0 $0 $12,903 $1,268 $0 $4,251 $18,422 $2914 Buildings & Structures14.1 Combustion Turbine Area $0 $221 $127 $0 $0 $348 $31 $0 $76 $454 $114.2 Steam Turbine Building $0 $2,337 $3,373 $0 $0 $5,710 $524 $0 $935 $7,169 $1114.3 Administration Building $0 $794 $584 $0 $0 $1,379 $123 $0 $225 $1,727 $314.4 Circulation Water Pumphouse $0 $157 $84 $0 $0 $241 $21 $0 $39 $301 $014.5 Water Treatment Buildings $0 $402 $398 $0 $0 $800 $72 $0 $131 $1,003 $214.6 Machine Shop $0 $407 $282 $0 $0 $689 $61 $0 $112 $862 $114.7 Warehouse $0 $657 $430 $0 $0 $1,086 $96 $0 $177 $1,360 $214.8 Other Buildings & Structures $0 $393 $310 $0 $0 $704 $63 $0 $153 $920 $114.9 Waste Treating Building & Str. $0 $879 $1,703 $0 $0 $2,582 $240 $0 $564 $3,386 $5SUBTOTAL 14. $0 $6,247 $7,291 $0 $0 $13,537 $1,231 $0 $2,414 $17,182 $27TOTAL COST $676,062 $63,575 $224,205 $0 $0 $963,842 $88,874 $32,202 $171,892 $1,256,810 $1,977TOTAL PLANT COST SUMMARYCost and Performance Comparison of Fossil Energy Power Plants

263 

### Exhibit 3-97 Case 5 Initial and A nnual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006 Case 05 - Shell IGCC w/o CO2 Heat Rate-net(Btu/kWh): 8,306 MWe-net: 636 Capacity Factor: (%): 80 OPERATING & MAINTENANCE LABOR

Operating Labor Operating Labor Rate(base): 33.00 $/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 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 15.0 15.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $5,637,060 $8.865 Maintenance Labor Cost $12,260,125 $19.281 Administrative & Support Labor $4,474,296 $7.037 TOTAL FIXED OPERATING COSTS $22,371,481 $35.184 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $22,850,084 $0.00513

Consumables Consumption Unit Initial Initial /Day Cost Cost
Water(/1000 gallons) 0 5,460 1.03 $0 $1,642,294 $0.00037

Chemicals MU & WT Chem.(lb) 113,862 16,266 0.16 $18,764 $782,745 $0.00018 Carbon (Mercury Removal) (lb) 72,509 99 1.00 $72,509 $28,908 $0.00001 COS Catalyst (m3) 1 0.19 2,308.40 $3,042 $126,875 $0.00003 Water Gas Shift Catalyst(ft3) 0 0 475.00 $0 $0 $0.00000 Selexol Solution (gal.) 0 0 12.90 $0 $0 $0.00000 MDEA Solution (gal) 0 0 0.96 $0 $0 $0.00000 Sulfinol Solution (gal) 525 75 9.68 $5,080 $211,900 $0.00005 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. 2.05 125.00 $0 $74,825 $0.00002 Subtotal Chemicals $99,395 $1,225,254 $0.00027

Othe r Supplemental Fuel(MBtu) 0 0 0.00 $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 99 0.40 $0 $11,609 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Bottom Ash(ton) 0 544 15.45 $0 $2,453,209 $0.00055 Subtotal-Waste Disposal $0 $2,464,819 $0.00055

By-products & Emissions Sulfur(tons) 0 136 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $99,395 $28,182,450 $0.00632

Fuel(ton) 162,977 5,433 42.11 $6,862,984 $66,799,712 $0.01499Cost and Performance Comparison of Fossil Energy Power Plants

264 

### 3.4.8 C ASE 

### 6

- S HELL 

### IGCC P OWER 

### P LANT WITH 

### CO 2 

### C APTURE 

### This case is configured to produce electric power with CO 2 

### capture. The plant configuration is the same as Case 5, namely two Shell gasifier trains, two advanced F class turbines, two HRSGs and one steam turbine. The gross power output is constrained by th e capacity of the two combustion turbines, and since the CO 2 

### capture and compression process increases the auxiliary load on the plant, the net output is significantly reduced relative to Case 5 (517 MW versus 636 MW). The process description for Case 6 is similar to Case 5 with several notable exceptions to accommodate CO 2 

### capture. A BFD and stream tables for Case 6 are shown in Exhibit 3-98 and Exhibit 3-99, respectively. Instead of repeating the entire process description, only differences from Case 5 are reported here. Coal Preparation and Feed Systems
No differences from Case 5.
Gasification The gasification process is the same as Case 5 with the following exceptions:

• The syngas exiting the gasifier (stream 12) is quenched to 399°C (750°F) with water rather than recycled syngas to provide a por tion of the water require d for water gas shift

• Total coal feed (as-received) to the tw o gasifiers is 5,151 tonnes/day (5,678 TPD) (stream 9)

• The ASU provides 4,070 tonnes/day (4,480 TPD) of 95 mole percent oxygen to the gasifier and Claus pl ant (streams 5 and 3) Raw Gas Cooling/Particulate Removal Following the water quench and particulate removal the syngas is cooled to 260°C (500°F) prior to the syngas scrubber (stream 13) by vapor izing HP BFW and pr e-heating IP BFW. Syngas Scrubber/Sour Water Stripper Syngas exits the scrubber at 204°C (400°F). Sour Gas Shift (SGS) The SGS process was described in Section 3.1.3. In Case 6 the syngas after the scrubber is reheated to 285°C (545°F) and then steam (stream 14) is added to adjust the H 2 

### O:CO molar ratio to approximately 2:1 prior to the first SGS reactor . The hot syngas exiting the first stage of SGS is used to generate the steam that is added in stream 14. One more stage of SGS (for a total of two) results in 95.6 percent overa ll conversion of the CO to CO 2 

### . The warm syngas from the second stage of SGS is cooled to 241°C (465°F) by preheating the syngas pr ior to the first stage of SGS. The SGS catalylst also serves to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. Following the second stag e of SGS, the syngas is further cooled to 35°C (95°F) prior to the mercury removal beds. Mercury Removal and Acid Gas Removal Mercury removal is the same as in Case 5Cost and Performance Comparisonof Fossil Energy Power Plants265Exhibit 3-98 Case 6 ProcessFlow Diagram, Shell IGCC with CO2CaptureCost and Performance Comparisonof Fossil Energy Power Plants266Exhibit 3-99 Case 6 Stream Table, Shell IGCC with CO2Capture123456789A10A11 12 13 14V-L Mole FractionAr 0.0094 0.0263 0.0360 0.0024 0.0360 0.0000 0.0000 0.0102 0.0000 0.0000 0.0000 0.0097 0.0052 0.0000CH40.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0004 0.0000 0.0000 0.0000 0.0004 0.0002 0.0000CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0265 0.0000 0.0000 0.0000 0.5716 0.3070 0.0000CO20.0003 0.0091 0.0000 0.0000 0.0000 0.0000 0.0000 0.0211 0.0000 0.0000 0.0000 0.0211 0.0113 0.0000COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0007 0.0004 0.0000H20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.8874 0.0000 0.0000 0.0000 0.2901 0.1558 0.0000H2O0.0104 0.2820 0.0000 0.0004 0.0000 1.0000 0.0000 0.0001 1.0000 1.0000 0.0000 0.0364 0.4826 1.0000H2S0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0081 0.0043 0.0000N20.7722 0.4591 0.0140 0.9918 0.0140 0.0000 1.0000 0.0543 0.0000 0.0000 0.0000 0.0585 0.0314 0.0000NH30.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0033 0.0018 0.0000O20.2077 0.2235 0.9500 0.0054 0.9500 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000SO20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000Total 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 1.0000V-L Flowrate (lbmol/hr)56,388 2,025 230 40,650 11,358 2,534 2,110 491 2,923 1,218 0 42,059 78,325 11,679V-L Flowrate (lb/hr) 1,627,030 53,746 7,428 1,140,640 366,070 45,657 59,121 2,651 52,617 21,935 0 865,967 1,519,300 210,400Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 420,559 420,559 47,374 0 0 0Temperature (°F) 238 70 90 385 518 750 560 121 59 215 2,595 2,595 500 750Pressure (psia) 190.0 16.4 125.0 460.0 740.0 740.0 815.0 469.6 14.7 14.7 614.7 604.7 564.7 825.0Enthalpy (BTU/lb)B56.9 26.8 11.4 88.0 107.7 1409.5 132.2 113.8 --- --- --- 1012.8 665.9 1,368.5Density (lb/ft3)0.732 0.104 0.688 1.424 2.272 1.027 2.086 0.407 --- --- --- 0.378 1.064 1.145Molecular Weight 28.854 26.545 32.229 28.060 32.229 18.015 28.013 5.399 --- --- --- 20.589 19.397 18.015A - Solids flowrate includes dry coal; V-L flowrate includes water from coalB - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparisonof Fossil Energy Power Plants267Exhibit 3-99 Case 6 Stream Table (Continued)15 16 17 18 19 20 21 22 23 24 25 26 27V-L Mole FractionAr 0.0046 0.0064 0.0064 0.0102 0.0099 0.0099 0.0000 0.0000 0.0000 0.0074 0.0094 0.0091 0.0091CH40.0002 0.0002 0.0002 0.0004 0.0004 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000CO 0.2697 0.0166 0.0166 0.0265 0.0256 0.0256 0.0000 0.0000 0.0000 0.0792 0.0000 0.0000 0.0000CO20.0100 0.3771 0.3771 0.0211 0.0204 0.0204 1.0000 0.3526 0.0000 0.2293 0.0003 0.0063 0.0063COS 0.0003 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0003 0.0000 0.0000 0.0000H20.1369 0.5547 0.5547 0.8874 0.8584 0.8584 0.0000 0.0000 0.0000 0.0417 0.0000 0.0000 0.0000H2O0.5455 0.0014 0.0014 0.0001 0.0327 0.0327 0.0000 0.0502 0.0000 0.4003 0.0108 0.1258 0.1258H2S0.0038 0.0050 0.0050 0.0000 0.0000 0.0000 0.0000 0.3122 0.0000 0.0013 0.0000 0.0000 0.0000N20.0276 0.0385 0.0385 0.0543 0.0526 0.0526 0.0000 0.2845 0.0000 0.2379 0.7719 0.7513 0.7513NH30.0016 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000O20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2076 0.1075 0.1075SO20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0026 0.0000 0.0000 0.0000Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000V-L Flowrate (lbmol/hr)89,158 63,376 63,376 39,127 40,448 40,448 22,707 1,017 0 1,603 244,799 308,019 308,019V-L Flowrate (lb/hr) 1,714,460 1,249,470 1,249,470 211,226 235,031 235,031 999,309 35,657 0 42,962 7,062,330 8,438,000 8,438,000Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 11,825 0 0 0 0Temperature (°F) 574 95 95 121 213 385 156 124 352 280 59 1,051 270Pressure (psia) 544.7 482.6 472.6 469.6 453.9 448.9 2,214.7 60.0 23.6 23.6 14.7 15.2 15.2Enthalpy (BTU/lb)B767.7 25.6 25.6 113.8 327.0 535.7 -46.4 37.9 -100.6 362.5 13.8 364.1 150.8Density (lb/ft3)0.944 1.598 1.565 0.407 0.365 0.288 30.929 0.343 329.618 0.080 0.076 0.026 0.053Molecular Weight 19.229 19.715 19.715 5.399 5.811 5.811 44.010 35.063 256.528 26.798 28.849 27.394 27.394B - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparison of Fossil Energy Power Plants

268 

### The AGR process in Case 6 is a two stage Selexol process where H 2 

### S is removed in the first stage and CO 2 

### in the second stage of absorption. The pr ocess results in thr ee product streams, the clean syngas (stream 18), a CO 2 

### -rich stream and an acid gas feed to the Claus plant (stream 22). The acid gas contains 31 percent H 2 

### S and 35 percent CO 2 

### with the balance primarily N 2 

### . The CO 2 

### -rich stream is discussed further in the CO 2 

### compression section.

CO 2 

### Compression and Dehydration
CO 2 

### from the AGR process is generated at three pr essure levels. The LP stream is compressed from 0.15 MPa (22 psia) to 1.1 MPa (160 psia) and then combined w ith the MP stream. The HP stream is combined between compressor stages at 2.1 MPa (300 psia). The combined stream is compressed from 2.1 MPa (300 psia) to a superc ritical condition at 15.3 MPa (2215 psia) using a multiple-stage, intercooled compre ssor. During compression, the CO 2 

### stream is dehydrated to a dewpoint of -40oC (-40°F) with triethylene glycol. The raw CO 2 

### stream from the Selexol process contains over 93 percent CO 2 

### with the balance primarily nitrogen. For modeling purposes it was assumed that the impurities were separated from the CO 2 

### and combined with the clean syngas stream from the Selexol process. The pure CO 2 

### (stream 21) is transported to the plant fence line and is sequestration ready. CO 2 

### TS&M costs were estimated using the methodology described in Section 2.7.

Claus Unit The Claus plant is the same as Case 5 with the following exceptions:

• 5,364 kg/h (11,825 lb/h) of sulfur (stream 23) are produced

• The waste heat boiler generates 14,099 kg/h ( 31,082 lb/h) of 4.7 MPa (679 psia) steam, which provides all of the Claus plant process needs and provides some additional steam to the medium pressure steam header.

Power Block Clean syngas from the AGR plant is combined with a small amount of clean gas from the CO 2 

### compression process (stream 18) and partially hu midified because the nitrogen available from the ASU is insufficient to provide adequate dilution. The moisturized syngas is reheated to 196°C (385°F) using HP boiler feedwater, diluted with nitrogen (stream 4) , and then enters the CT burner. The exhaust gas (stream 26) exits the CT at 566°C (1051°F) and enters the HRSG where additional heat is recove red. The flue gas exits the HR SG at 132°C (270°F) (stream 27) and is discharged through the plant stack. The st eam raised in the HRSG is used to power an advanced commercially available stea m turbine using a 12.4 MPa/538°C/538°C (1800 psig/1000°F/1000°F) steam cycle. There is no inte gration between the CT and the ASU in this

case. Air Separation Unit The same elevated pressure ASU is used as in Case 5 and produces 4,070 tonnes/day (4,480 TPD) of 95 mole percent oxygen and 12,420 tonnes/da y (13,690 TPD) of nitrogen. There is no integration between the ASU and the combustion turbine.Cost and Performance Comparison of Fossil Energy Power Plants

269 

### Balance of Plant Balance of plant items we re covered in Sections 3.1.9, 3.1.10 and 3.1.11.

3.4.9 C ASE 

### 6 P ERFORMANCE 

### R ESULTS 

### The Case 6 modeling assumptions were presented previously in Section 3.4.3. The plant produces a net output of 517 MWe at a net plant efficiency of 32.0 percent (HHV basis). Overall performance for the plant is summarized in Exhibit 3-100 which includes auxiliary power requirements. The ASU accounts for approximately 64 percent of the auxiliary load between the main air compressor, the nitrogen compressor, the oxygen compressor and ASU auxiliaries. The two-stage Selexol process and CO 2 

### compression account for an additional 25 percent of the auxiliary power load. The BFW and circulating wate r system (circulating water pumps and cooling tower fan) comprise about 5 percent of the load, leaving 6 percent of the auxiliary load fo r all other systems.Cost and Performance Comparison of Fossil Energy Power Plants

270 

### Exhibit 3-100 Case 6 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Gas Turbine Power 463,630 Steam Turbine Power 229,925 TOTAL POWER, kWe 693,555 AUXILIARY LOAD SUMMARY, kWe Coal Handling 440 Coal Milling 2,210 Slag Handling 570 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 62,970 Oxygen Compressor 10,540 Nitrogen Compressor 38,670 Syngas Recycle Compressor 0 Incinerator Air Blower 160 CO 2 

### Compressor 28,050 Boiler Feedwater Pumps 3,290 Condensate Pump 310 Flash Bottoms Pump 200 Circulating Water Pumps 3,440 Cooling Tower Fans 1,780 Scrubber Pumps 390 Double Stage Selexol Unit Auxiliaries 15,500 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Miscellaneous Balance of Plant (Note 1) 3,000 Transformer Loss 2,550 TOTAL AUXILIARIES, kWe 176,420 NET POWER, kWe 517,135 Net Plant Efficiency, % (HHV) 32.0 Net Plant Heat Rate (Btu/kWh) 10,674 CONDENSER COOLING DUTY 10 6 

### kJ/h (10 6 

### Btu/h) 1,465 (1,390) CONSUMABLES As-Received Coal Feed, kg/h (lb/h) 214,629 (473,176) Thermal Input, kWt 1,617,772 Raw Water Usage, m 3 

### /min (gpm) 17.3 (4,563) Note 1: Includes plant control systems, ligh ting, HVAC and miscellaneous low voltage loadsCost and Performance Comparison of Fossil Energy Power Plants

271 

### Environmental Performance The environmental targets for emissions of Hg, NO X 

### , SO 2 

### , CO 2 

### and particulate matter were presented in Section 2.4. A summ ary of the plant air emissions for Case 6 is presented in Exhibit 3-101.

Exhibit 3-101 Case 6 Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 80% capacity factor kg/MWh (lb/MWh)

SO 2 

### 0.0045 (0.0105) 185 (204) 0.038 (0.084) NO X 

### 0.021 (0.049) 856 (944) 0.176 (0.388) Particulates 0.003 (0.0071) 125 (137) 0.026 (0.057) Hg 0.25x10 -6 

### (0.57x10 -6 

### ) 0.010 (0.011) 2.1x10 -6 

### (4.5x10 -6 

### ) CO 2 

### 8.0 (18.7) 328,000 (361,000) 67.4 (149)

CO 2 1 

### 90.4 (199)

1 

### CO 2 

### emissions based on net power instead of gross power

The low level of SO 2 

### emissions is achieved by capture of the sulfur in the gas by the two-stage Selexol AGR process. The CO 2 

### capture target results in the sulfur compounds being removed to a greater extent than required in the environmental targets of Section 2.4. The clean syngas exiting the AGR process has a sulfur concentrati on of approximately 22 ppmv. This results in a concentration in the flue gas of about 3 ppmv. The H 2 

### S-rich regeneration gas from the AGR system is fed to a Claus plant, producing elemen tal sulfur. The tail gas treatment unit removes most of the sulfur from the Claus tail gas, which is recycled to the Claus unit inlet. The clean gas from the tail gas treatment unit is sent to the coal dryer prior to being vented to atmosphere.
NO X 

### emissions are limited by the use of nitroge n dilution and humidification to 15 ppmvd (as NO 2 

### @ 15 percent O 2 

### ). Ammonia in the syngas is removed with process condensate prior to the low-temperature AGR process and subsequently dest royed in the Claus plant burner. This helps lower NO X 

### levels as well. Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only. Ninety five percent of mercury is captured from the syngas by an activated carbon bed. Ninety five percent of the CO 2 

### from the syngas is captured in the AGR system and compressed for sequestration. Because not all of the CO is converted to CO 2 

### in the shift reactors, the overall CO 2 

### removal is 90.2 percent. The carbon balance for the plant is shown in Exhibit 3-102. The carbon input to the plant consists of carbon in the air in a ddition to carbon in the coal. Carbon in the air is not used in the carbon capture equation below, but it is not ne glected in the balance since the Aspen model accounts for air components throughout. Carbon leav es the plant as unburned carbon in the slag,Cost and Performance Comparison of Fossil Energy Power Plants

272 

### as dissolved CO 2 

### in the wastewater blowdown stream, and CO 2 

### in the stack gas, coal dryer vent gas, ASU vent gas and the captured CO 2 

### product. Carbon in the wast ewater blowdown stream is calculated by difference to close the material balance. The car bon capture efficiency is defined as the amount of carbon in the CO 2 

### product stream relative to th e amount of carbon in the coal less carbon contained in the slag, repr esented by the following fraction: (Carbon in Product for Sequestration)/[(Car bon in the Coal)-(Carbon in Slag)] or 272,478/(301,649-1,511) *100 or 90.8 percent

Exhibit 3-102 Case 6 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) Coal 136,826 (301,649) Slag 685 (1,511) Air (CO 2 

### ) 500 (1,102) Stack Gas 10,610 (23,390) CO 2 

### Product 123,595 (272,478)

ASU Vent 101 (222) Coal Dryer 2,137 (4,712) Wastewater 198 (438) Total 137,326 (302,751) Total 137,326 (302,751)

Exhibit 3-103 shows the sulfur bala nce for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output in cludes the sulfur recovered in the Claus plant, dissolved SO 2 

### in the wastewater blowdown stream, sulfur emitted in the st ack gas and sulfur from the tail gas unit that is vented through the coal dryer. Sulfur in th e slag is considered ne gligible, and the sulfur content of the blowdown stream is calculated by difference to close the material balance. The total sulfur capture is repres ented by the following fraction: (Sulfur byproduct/Sulfur in the coal) or (11,825/11,877) or 99.6 percent

Exhibit 3-103 Case 6 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) Coal 5,387 (11,877) Elemental Sulfur 5,364 (11,825)

Stack Gas 12 (27) Dryer Gas 1 (2) Wastewater 10 (23) Total 5,387 (11,877) Total 5,387 (11,877)

Exhibit 3-104 shows the overall water balance for the plant. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand representsCost and Performance Comparison of Fossil Energy Power Plants

273 

### the total amount of water required for a particular process. Some water is recovered within the process, primarily as syngas condens ate, and that water is re-used as internal recycle. Raw water makeup is the difference between wa ter demand and internal recycle.

Exhibit 3-104 Case 6 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle,

m 3 

### /min (gpm) Raw Water Makeup,

m 3 

### /min (gpm)
Gasifier Steam 0.3 (91) 0 0.3 (91)
Shift Steam 1.6 (420) 0 1.6 (420)
Humidifier 0.3 (67) 0.3 (67) 0
Slag Handling 0.4 (123) 0.4 (123) 0
Quench/Scrubber 4.9 (1,306) 2.6 (693) 2.3 (612)
BFW Makeup 0.2 (45) 0 0.2 (45)
Cooling Tower Makeup 13.4 (3,528) 0.5 (133) 12.9 (3,395)

Total 21.1 (5,581) 3.8 (1,017) 17.3 (4,564)

Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-105 through Exhibit 3-109:

• Coal gasification and air separation unit

• Syngas cleanup

• Sulfur recovery and tail gas recycle

• Combined cycle power generation

• Steam and feedwater An overall plant energy balance is provided in tabular form in Exhibit 3-110. The power out is the combined combustion turbine and steam turbin e power prior to generator losses. The power at the generator terminals (shown in Exhibit 3-100) is calculated by multiplying the power out by a combined generator efficiency of 98.4 percent.Cost and Performance Comparison of Fossil Energy Power Plants

274 

### This page intentionally left blankCost and Performance Comparisonof Fossil Energy Power Plants275Exhibit 3-105 Case 6 Coal Gasification and AirSeparation Unit Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants276Exhibit 3-106 Case 6 Syngas Cleanup Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants277Exhibit 3-107 Case 6 Sulfur Recovery and Tail Gas Recycle Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants278Exhibit 3-108 Case 6 Combined Cycle PowerGeneration Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants279Exhibit 3-109 Case 6 Steam and Feedwater Heat and Mass Balance SchematicCost and Performance Comparisonof Fossil Energy Power Plants280This page intentionally left blankCost and Performance Comparison of Fossil Energy Power Plants

281 

### Exhibit 3-110 Case 6 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total
Heat In (MMBtu/hr) Coal 5,520.2 4.6 5,524.8 ASU Air 22.0 22.0 CT Air 97.2 97.2 Incinerator Air 1.3 1.3 Water 23.2 23.2 Auxiliary Power 602.0 602.0 Totals 5,520.2 148.4 602.0 6,270.5 Heat Out (MMBtu/hr) ASU Intercoolers 222.8 222.8 ASU Vent 1.4 1.4 Slag 21.3 33.9 55.2 Sulfur 47.1 (1.2) 45.9 Dryer Stack Gas 59.5 59.5 CO 2 

### Compressor Intercoolers 115.4 115.4

CO 2 

### Product (46.4) (46.4) HRSG Flue Gas 1,273.3 1,273.3 Condenser 1,390.0 1,390.0 Process Losses 748.8 748.8 Power 2,404.6 2,404.6 Totals 68.4 3,797.5 2,404.6 6,270.5 (1) Process Losses are calculated by differen ce and reflect various gasification, turbine, HRSG and other heat and work losses. Aspe n flowsheet balance is within 0.5 percent.Cost and Performance Comparison of Fossil Energy Power Plants

282 

### 3.4.10 C ASE 

### 6

- M AJOR 

### E QUIPMENT 

### L IST 

### Major equipment items for the Shell gasifier with CO 2 

### capture are shown in the following tables. The accounts used in the equipment list correspo nd to the account numbers used in the cost estimates in Section 3.4.11. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
ACCOUNT 1 COAL HANDLING

Equipment No. Description Type Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0
3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0
5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0
8 Reclaim Hopper N/A 2 1
9 Feeder Vibratory 2 1
10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor reduction 2 0

14 As-Fired Coal Sampling System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0

17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 3 0 N/A

354 tonne/h (390 tph)

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph) N/A
1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)
1,134 tonne/h (1,250 tph)

45 tonne (50 ton)
181 tonne/h (200 tph)

8 cm x 0 - 3 cm x 0 (3" x 0 - 1-1/4" x 0) 354 tonne/h (390 tph)

181 tonne (200 ton) N/A

N/A

354 tonne/h (390 tph)

816 tonne (900 ton)Cost and Performance Comparison of Fossil Energy Power Plants

283 

### ACCOUNT 2 COAL PREPARATION AND FEED
Equipment No. Description Type Operating Qty. Spares

1 Feeder Vibratory 3 0
2 Conveyor No. 6 Belt w/tripper 1 0
3 Roller Mill Feed Hopper Dual Outlet 1 0
4 Weigh Feeder Belt 2 0
5 Coal Drying and Pulverization Rotary 2 0 118 tonne/h (130 tph)
118 tonne/h (130 tph)

Design Condition

82 tonne/h (90 tph)
236 tonne/h (260 tph)
472 tonne (520 ton)Cost and Performance Comparison of Fossil Energy Power Plants

284 

### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT
Equipment No. Description Type Operatin g Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 3 0

2 Condensate Pumps Vertical canned 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multistage, centrifugal 2 1

7 Auxiliary Boiler Shop fabricated, water tube 1 0

8 Service Air Compressors Flooded Screw 2 1

9 Instrument Air Dryers Duplex, regenerative 2 1

10 Closed Cylce Cooling Heat Exchangers Plate and frame 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 2 1

12 Engine-Driven Fire Pump Vertical turbine, diesel engine 1 1

13 Fire Service Booster Pump Two-stage horizontal centrifugal 1 1

14 Raw Water Pumps Stainless steel, single suction 2 1

15 Filtered Water Pumps Stainless steel, single suction 2 1

16 Filtered Water Tank Vertical, cylindrical 2 0

17 Makeup Water Demineralizer Anion, cation, and mixed bed 2 0

18 Liquid Waste Treatment System 1 0 2 1 5 High Pressure Feedwater Pump No. 1 Barrel type, multistage, centrifugal

1,048,567 liter (277,000 gal)

1,060 lpm (280 gpm)

10 years, 24-hour storm 4,353 lpm @ 49 m H2O (1,150 gpm @ 160 ft H2O)

28 m3/min (1,000 scfm)

58 MMkJ/h (55 MMBtu/h) each
20,820 lpm @ 21 m H2O (5,500 gpm @ 70 ft H2O) 3,785 lpm @ 107 m H2O (1,000 gpm @ 350 ft H2O)

2,650 lpm @ 76 m H2O (700 gpm @ 250 ft H2O) 9,577 lpm @ 18 m H2O (2,530 gpm @ 60 ft H2O) 3,975 lpm @ 283 m H2O (1,050 gpm @ 930 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C (40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) Design Condition

927,433 liters (245,000 gal)

8,631 lpm @ 91 m H2O (2,280 gpm @ 300 ft H2O)

603,732 kg/h (1,331,000 lb/h)

IP water: 1,173 lpm @ 223 m H2O (310 gpm @ 730 ft H2O) HP water: 4,580 lpm @ 1,890 m

H2O (1,210 gpm @ 6,200 ft H2O)Cost and Performance Comparison of Fossil Energy Power Plants

285 

### ACCOUNT 4 GASIFIER, ASU AND ACC ESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY AND FUEL GAS SATURATION
Equipment No. Description Type Operating Qty. Spares

1 Gasifier Pressurized dry-feed, entrained bed 2 0

2 Synthesis Gas Cooler Convective spiralwound tube boiler 2 0

3 Synthesis Gas Cyclone High efficiency 2 0

4 Candle Filter Pressurized filter with pulse-jet cleaning 2 0

5 Syngas Scrubber Including Sour Water Stripper Vertical upflow 2 0

6 Raw Gas Coolers Shell and tube with condensate drain 6 0

7 Raw Gas Knockout Drum Vertical with mist eliminator 2 0

8 Saturation Water Economizers Shell and tube 2 0

9 Fuel Gas Saturator Vertical tray tower 2 0

10 Saturator Water Pump Centrifugal 2 2

11 Synthesis Gas Reheater Shell and tube 2 0

12 Flare Stack Self-supporting, carbon steel, stainless steel top, pilot ignition 2 0

13 ASU Main Air Compressor Centrifugal, multistage 2 0

14 Cold Box Vendor design 2 0

15 Oxygen Compressor Centrifugal, multistage 2 0

16 Nitrogen Compressor Centrifugal, multistage 2 0

17 Nitrogen Boost Compressor Centrifugal, multistage 2 0 metallic filters

375,121 kg/h (827,000 lb/h)

713,048 kg/h (1,572,000 lb/h)

312,072 kg/h, 35°C, 3.4 MPa (688,000 lb/h, 95°F, 488 psia) Design Condition

2,812 tonne/day, 4.2 MPa (3,100 tpd, 615 psia)

379,204 kg/h (836,000 lb/h)

375,121 kg/h (827,000 lb/h) Design efficiency 90%

427,738 kg/h (943,000 lb/h)
58,513 kg/h, 101°C, 3.2 MPa (129,000 lb/h, 213°F, 470 psia) 4,164 lpm @ 21 m H2O (1,100 gpm @ 70 ft H2O)
58,513 kg/h (129,000 lb/h)

510 m3/min @ 2.3 MPa (18,000 scfm @ 340 psia) 375,121 kg/h (827,000 lb/h)
syngas 5,550 m3/min @ 1.3 MPa (196,000 scfm @ 190 psia)
2,268 tonne/day (2,500 tpd) of 95% purity oxygen
1,133 m3/min @ 5.1 MPa (40,000 scfm @ 740 psia) 3,710 m3/min @ 3.4 MPa (131,000 scfm @ 490 psia)Cost and Performance Comparison of Fossil Energy Power Plants

286 

### ACCOUNT 5 SYNGAS CLEANUP
Equipment No. Description Type Operatin g Qty. Spares

1 Mercury Adsorber Sulfated carbon bed 2 0

2 Sulfur Plant Claus type 1 0

3 Water Gas Shift Reactors Fixed bed, catalytic 4 0

4 Shift Reactor Heat Recovery Exhchangers Shell and Tube 4 0

5 Acid Gas Removal Plant Two-stage Selexol 2 0

6 Tail Gas Treatment Unit Proprietary amine, absorber/stripper 1 0

7 Tail Gas Treatment Incinerator N/A 1 0 Design Condition

311,618 kg/h (687,000 lb/h) 35°C (95°F) 3.3 MPa (483 psia)

142 tonne/day (156 tpd)

Exchanger 1: 211 MMkJ/h (200 MMBtu/h) Exchanger 2: 63 MMkJ/h (60 MMBtu/h)

17,645 kg/h (38,900 lb/h) 49°C (120°F) 0.1 MPa (16.4 psia) 427,738 kg/h (943,000 lb/h) 302°C (575°F) 3.8 MPa (545 psia)

311,618 kg/h (687,000 lb/h) 51°C (124°F) 3.3 MPa (473 psia)

67 MMkJ/h (64 MMBtu/h)



### ACCOUNT 5B CO 2 

### COMPRESSION

Equipment No. Description Type Operating Qty. Spares

1 CO2 Compression Integrally geared, multistage centrifugal 4 1 Design Condition
1,119 m3/min @ 15.3 MPa (39,500 scfm @ 2,215 psia)



### ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES
Equipment No. Description Type Operating Qty. Spares

1 Gas Turbine Advanced F class 2 0

2 Gas Turbine Generator TEWAC 2 0 Design Condition

232 MW
260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phaseCost and Performance Comparison of Fossil Energy Power Plants

287 

### ACCOUNT 7 HRSG, DUCTING, AND STACK

Equipment No. Description Type Operating Qty. Spares

1 Stack CS plate, type 409SS liner 1 0

2 0 2 Heat Recovery Steam Generator Drum, multi-pressure with economizer section and integral deaerator Reheat steam - 289,050 kg/h, 2.9 MPa/538°C (637,245 lb/h, 420 psig/1,000°F) Design Condition

76 m (250 ft) high x 8.5 m (28 ft) diameter

Main steam - 258,851 kg/h, 12.4 MPa/538°C (570,667 lb/h, 1,800 psig/1,000°F)



### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitiation 1 0

3 Steam Bypass One per HRSG 2 0

4 Surface Condenser Single pass, divided waterbox including
vacuum pumps 1 0 270 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase

50% steam flow @ design steam conditions Design Condition

242 MW 12.4 MPa/538°C/538°C (1800 psig/ 1000°F/1000°F)

1,613 MMkJ/h (1,530 MMBtu/h), Inlet water temperature 16°C (60°F),

Water temperature rise 11°C (20°F)Cost and Performance Comparison of Fossil Energy Power Plants

288 

### ACCOUNT 9 COOLING WATER SYSTEM
Equipment No. Description Type Operatin g Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 1 0 Design Condition

344,475 lpm @ 30 m (91,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 1,919 MMkJ/h (1,820

MMBtu/h) heat duty



### ACCOUNT 10 SLAG RECOVERY AND HANDLING
Equipment No. Description Type Operating Qty. Spares

1 Slag Quench Tank Water bath 2 0
2 Slag Crusher Roll 2 0
3 Slag Depressurizer Lock Hopper 2 0
4 Slag Receiving Tank Horizontal, weir 2 0
5 Black Water Overflow Tank Shop fabricated 2
6 Slag Conveyor Drag chain 2 0
7 Slag Separation Screen Vibrating 2 0
8 Coarse Slag Conveyor Belt/bucket 2 0
9 Fine Ash Settling Tank Vertical, gravity 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 2 2

11 Grey Water Storage Tank Field erected 2 0

12 Grey Water Pumps Centrifugal 2 2

13 Slag Storage Bin Vertical, field erected 2 0

14 Unloading Equipment Telescoping chute 1 0 Design Condition

227,126 liters (60,000 gal)
12 tonne/h (13 tph)
12 tonne/h (13 tph)
147,632 liters (39,000 gal)

12 tonne/h (13 tph)
12 tonne/h (13 tph)
12 tonne/h (13 tph) 68,138 liters (18,000 gal)

219,556 liters (58,000 gal)

38 lpm @ 14 m H2O (10 gpm @ 46 ft H2O)

816 tonne (900 tons)

100 tonne/h (110 tph) 71,923 liters (19,000 gal)

265 lpm @ 433 m H2O (70 gpm @ 1,420 ft H2O)Cost and Performance Comparison of Fossil Energy Power Plants

289 

### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type Operating Qty. Spares

1 CTG Transformer Oil-filled 2 0

3 Auxiliary Transformer Oil-filled 1 1

4 Low Voltage Transformer Dry ventilated 1 1

5 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 2 0

6 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 1 0

7 Medium Voltage Switchgear Metal clad 1 1

8 Low Voltage Switchgear Metal enclosed 1 1

9 Emergency Diesel Generator Sized for emergency shutdown 1 0 750 kW, 480 V, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz 1 0

24 kV/4.16 kV, 193 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 29 MVA, 3-ph, 60 Hz Design Condition

24 kV/345 kV, 260 MVA, 3-ph, 60 Hz

2 STG Transformer Oil-filled 24 kV/345 kV, 70 MVA, 3-ph, 60 Hz



### ACCOUNT 12 INSTRUMENTATION AND CONTROLS

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) 1 0

3 DCS - Data Highway Fiber optic 1 0 Design Condition

Operator stations/printers and engineering stations/printers

2 DCS - Processor Microprocessor with redundant input/output N/A 1 0

Fully redundant, 25% spareCost and Performance Comparison of Fossil Energy Power Plants

290 

### 3.4.11 C ASE 

### 6

- C OST 

### E STIMATING 

### The cost estimating methodology was desc ribed previously in Section 2.6. Exhibit 3-111 shows the total plant capital cost summary organized by cost account and Exhibit 3-112 shows a more detailed breakdown of the capital costs. Exhibit 3-113 shows the initi al and annual O&M costs. The estimated TPC of the Shell gasifier with CO 2 

### capture is $2,668/kW. The gasifier in Case 6 is slightly larger than Case 5, but the syngas cooler is much sma ller in Case 6 (because of the quench configuration), which results in a lower overa ll cost for the Gasifier Account in Case 6. Process contingency represents 3.8 percent of the TPC and project contingency represents 14.0 percent. The 20-year LCOE, including CO 2 

### TS&M costs of 4.1 mills /kWh, is 110.4 mills/kWh.Cost and Performance Comparisonof Fossil Energy Power Plants291Exhibit 3-111 Case 6 Total Plant Cost SummaryClient:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 06 - Shell IGCC w/ CO2Plant Size:517.1 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING $13,222 $2,465 $10,360 $0 $0$26,046$2,360 $0 $5,681$34,087$662 COAL & SORBENT PREP & FEED $104,780 $8,348 $17,611 $0 $0$130,739$11,350 $0 $28,418$170,507$3303 FEEDWATER & MISC. BOP SYSTEMS $8,804 $7,082 $8,709 $0 $0$24,596$2,304 $0 $6,179$33,079$644 GASIFIER & ACCESSORIES4.1 Gasifier, Syngas Cooler & Auxiliaries $102,271 $0 $44,114 $0 $0$146,384$13,107 $20,012 $27,635$207,139$4014.2 Syngas Cooling (w/4.1) w/4.1 $0 w/4.1 $0 $0$0$0 $0 $0$0$04.3 ASU/Oxidant Compression $144,337 $0 w/equip. $0 $0$144,337$13,738 $0 $15,808$173,883$3364.4-4.9 Other Gasification Equipment $25,903 $9,641 $15,020 $0 $0$50,564$4,796 $0 $11,764$67,123$130SUBTOTAL 4 $272,511 $9,641 $59,134 $0 $0 $341,285 $31,641 $20,012 $55,207 $448,145 $8675A Gas Cleanup & Piping $80,918 $4,433 $69,321 $0 $0$154,672$14,826 $22,300 $38,565$230,362$4455BCO2REMOVAL & COMPRESSION$17,265 $0 $10,209 $0 $0$27,475$2,626 $0 $6,020$36,121$706 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator $88,000 $0 $5,325 $0 $0$93,325$8,779 $9,332 $11,144$122,580$2376.2-6.9 Combustion Turbine Other $0 $684 $762 $0 $0$1,446$135 $0 $474$2,055$4SUBTOTAL 6 $88,000 $684 $6,087 $0 $0 $94,771 $8,914 $9,332 $11,618 $124,635 $2417 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator $32,181 $0 $4,579 $0 $0$36,760$3,470 $0 $4,023$44,253$867.2-7.9 Ductwork and Stack $3,222 $2,268 $3,041 $0 $0$8,531$788 $0 $1,516$10,835$21SUBTOTAL 7 $35,402 $2,268 $7,620 $0 $0 $45,291 $4,258 $0 $5,539 $55,087 $1078 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $24,587 $0 $4,106 $0 $0$28,693$2,750 $0 $3,144$34,587$678.2-8.9 Turbine Plant Auxiliaries and Steam Piping $8,905 $828 $6,089 $0 $0$15,822$1,435 $0 $3,347$20,604$40SUBTOTAL 8 $33,492 $828 $10,195 $0 $0 $44,515 $4,184 $0 $6,491 $55,191 $1079 COOLING WATER SYSTEM $6,933 $7,764 $6,432 $0 $0$21,129$1,940 $0 $4,752$27,821$5410 ASH/SPENT SORBENT HANDLING SYS $17,865 $1,375 $8,869 $0 $0$28,109$2,676 $0 $3,363$34,149$6611 ACCESSORY ELECTRIC PLANT $22,955 $8,041 $22,625 $0 $0$53,621$4,967 $0 $11,178$69,766$13512 INSTRUMENTATION & CONTROL $10,193 $1,908 $6,843 $0 $0$18,945$1,746 $947 $3,620$25,258$4913 IMPROVEMENTS TO SITE $3,207 $1,890 $7,973 $0 $0$13,070$1,284 $0 $4,306$18,660$3614 BUILDINGS & STRUCTURES $0 $6,095 $7,021 $0 $0$13,117$1,192 $0 $2,349$16,657$32TOTAL COST $715,547 $62,824 $259,009 $0 $0 $1,037,381 $96,266 $52,591 $193,286 $1,379,524 $2,668TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants292Exhibit 3-112 Case 6 Total Plant Cost DetailsClient:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 06 - Shell IGCC w/ CO2Plant Size:517.1 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING1.1 Coal Receive & Unload $3,472 $0 $1,714 $0 $0 $5,186 $464 $0 $1,130 $6,781 $131.2 Coal Stackout & Reclaim $4,487 $0 $1,099 $0 $0 $5,586 $490 $0 $1,215 $7,291 $141.3 Coal Conveyors $4,171 $0 $1,087 $0 $0 $5,259 $462 $0 $1,144 $6,865 $131.4 Other Coal Handling $1,091 $0 $252 $0 $0 $1,343 $118 $0 $292 $1,753 $31.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.9 Coal & Sorbent Hnd.Foundations $0 $2,465 $6,207 $0 $0 $8,672 $826 $0 $1,900 $11,399 $22SUBTOTAL 1. $13,222 $2,465 $10,360 $0 $0 $26,046 $2,360 $0 $5,681 $34,087 $662 COAL & SORBENT PREP & FEED2.1 Coal Crushing & Drying $39,807 $2,378 $5,861 $0 $0 $48,046 $4,152 $0 $10,440 $62,638 $1212.2 Prepared Coal Storage & Feed $1,885 $449 $299 $0 $0 $2,633 $226 $0 $572 $3,430 $72.3 Dry Coal Injection System $62,051 $727 $5,823 $0 $0 $68,601 $5,917 $0 $14,904 $89,421 $1732.4 Misc.Coal Prep & Feed $1,037 $750 $2,286 $0 $0 $4,073 $373 $0 $889 $5,336 $102.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.9 Coal & Sorbent Feed Foundation $0 $4,043 $3,343 $0 $0 $7,386 $681 $0 $1,614 $9,681 $19SUBTOTAL 2. $104,780 $8,348 $17,611 $0 $0 $130,739 $11,350 $0 $28,418 $170,507 $3303 FEEDWATER & MISC. BOP SYSTEMS3.1 FeedwaterSystem $2,575 $4,477 $2,365 $0 $0 $9,417 $869 $0 $2,057 $12,344 $243.2 Water Makeup & Pretreating $575 $60 $321 $0 $0 $955 $90 $0 $314 $1,359 $33.3 Other Feedwater Subsystems $1,422 $482 $434 $0 $0 $2,338 $209 $0 $509 $3,057 $63.4 Service Water Systems $331 $676 $2,347 $0 $0 $3,354 $324 $0 $1,104 $4,782 $93.5 Other Boiler Plant Systems $1,779 $682 $1,693 $0 $0 $4,154 $389 $0 $909 $5,452 $113.6 FO Supply Sys & Nat Gas $300 $567 $529 $0 $0 $1,397 $134 $0 $306 $1,837 $43.7 Waste Treatment Equipment $798 $0 $489 $0 $0 $1,288 $125 $0 $424 $1,836 $43.8 Misc. Equip.(cranes,AirComp.,Comm.) $1,024 $138 $530 $0 $0 $1,692 $163 $0 $557 $2,412 $5SUBTOTAL 3. $8,804 $7,082 $8,709 $0 $0 $24,596 $2,304 $0 $6,179 $33,079 $644 GASIFIER & ACCESSORIES4.1 Gasifier, Syngas Cooler & Auxiliaries $102,271 $0 $44,114 $0 $0 $146,384 $13,107 $20,012 $27,635 $207,139 $4014.2 Syngas Cooling (w/4.1) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.3 ASU/Oxidant Compression $144,337 $0 w/equip. $0 $0 $144,337 $13,738 $0 $15,808 $173,883 $3364.4 LT Heat Recovery & FG Saturation $25,903 $0 $9,746 $0 $0 $35,649 $3,426 $0 $7,815 $46,890 $914.5 Misc. Gasification Equipment w/4.1 & 4.2 w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $04.6 Other Gasification Equipment $0 $1,589 $647 $0 $0 $2,236 $213 $0 $490 $2,938 $64.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $04.9 Gasification Foundations $0 $8,052 $4,627 $0 $0 $12,679 $1,157 $0 $3,459 $17,295 $33SUBTOTAL 4. $272,511 $9,641 $59,134 $0 $0 $341,285 $31,641 $20,012 $55,207 $448,145 $867TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants293Exhibit 3-112 Case 6 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 06 - Shell IGCC w/ CO2Plant Size:517.1 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW5A GAS CLEANUP & PIPING5A.1 Double Stage Selexol $59,698 $0 $51,207 $0 $0 $110,905 $10,647 $22,181 $28,747 $172,480 $3345A.2 Elemental Sulfur Plant $9,156 $1,817 $11,821 $0 $0 $22,794 $2,198 $0 $4,999 $29,991 $585A.3 Mercury Removal $1,346 $0 $1,025 $0 $0 $2,371 $227 $119 $543 $3,260 $65A.4 Shift Reactors $8,816 $0 $3,551 $0 $0 $12,367 $1,177 $0 $2,709 $16,253 $315A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $05A.5 Blowback Gas Systems $1,903 $320 $180 $0 $0 $2,403 $226 $0 $526 $3,155 $65A.6 Fuel Gas Piping $0 $1,154 $795 $0 $0 $1,949 $178 $0 $425 $2,552 $55A.9 HGCU Foundations $0 $1,142 $741 $0 $0 $1,883 $172 $0 $617 $2,672 $5SUBTOTAL 5A. $80,918 $4,433 $69,321 $0 $0 $154,672 $14,826 $22,300 $38,565 $230,362 $4455B CO2 REMOVAL & COMPRESSION5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05B.2 CO2 Compression & Drying $17,265 $0 $10,209 $0 $0 $27,475 $2,626 $0 $6,020 $36,121 $70SUBTOTAL 5B. $17,265 $0 $10,209 $0 $0 $27,475 $2,626 $0 $6,020 $36,121 $706 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator $88,000 $0 $5,325 $0 $0 $93,325 $8,779 $9,332 $11,144 $122,580 $2376.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.9 Combustion Turbine Foundations $0 $684 $762 $0 $0 $1,446 $135 $0 $474 $2,055 $4SUBTOTAL 6. $88,000 $684 $6,087 $0 $0 $94,771 $8,914 $9,332 $11,618 $124,635 $2417 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator $32,181 $0 $4,579 $0 $0 $36,760 $3,470 $0 $4,023 $44,253 $867.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07.3 Ductwork $0 $1,627 $1,209 $0 $0 $2,836 $249 $0 $617 $3,702 $77.4 Stack $3,222 $0 $1,211 $0 $0 $4,433 $422 $0 $485 $5,340 $107.9 HRSG,Duct & Stack Foundations $0 $641 $620 $0 $0 $1,262 $117 $0 $414 $1,792 $3SUBTOTAL 7. $35,402 $2,268 $7,620 $0 $0 $45,291 $4,258 $0 $5,539 $55,087 $1078 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $24,587 $0 $4,106 $0 $0 $28,693 $2,750 $0 $3,144 $34,587 $678.2 Turbine Plant Auxiliaries $168 $0 $385 $0 $0 $554 $54 $0 $61 $668 $18.3 Condenser & Auxiliaries $4,661 $0 $1,421 $0 $0 $6,082 $577 $0 $666 $7,325 $148.4 Steam Piping $4,076 $0 $2,873 $0 $0 $6,949 $593 $0 $1,886 $9,428 $188.9 TG Foundations $0 $828 $1,410 $0 $0 $2,238 $211 $0 $735 $3,184 $6SUBTOTAL 8. $33,492 $828 $10,195 $0 $0 $44,515 $4,184 $0 $6,491 $55,191 $1079 COOLING WATER SYSTEM9.1 Cooling Towers $4,467 $0 $981 $0 $0 $5,448 $516 $0 $895 $6,858 $139.2 Circulating Water Pumps $1,405 $0 $88 $0 $0 $1,494 $128 $0 $243 $1,864 $49.3 Circ.Water System Auxiliaries $124 $0 $18 $0 $0 $141 $13 $0 $23 $178 $09.4 Circ.Water Piping $0 $5,260 $1,342 $0 $0 $6,602 $584 $0 $1,437 $8,624 $179.5 Make-up Water System $322 $0 $456 $0 $0 $777 $74 $0 $170 $1,021 $29.6 Component Cooling Water Sys $615 $736 $520 $0 $0 $1,871 $173 $0 $409 $2,453 $59.9 Circ.Water System Foundations& Structures $0 $1,768 $3,027 $0 $0 $4,795 $452 $0 $1,574 $6,822 $13SUBTOTAL 9. $6,933 $7,764 $6,432 $0 $0 $21,129 $1,940 $0 $4,752 $27,821 $5410 ASH/SPENT SORBENT HANDLING SYS10.1 Slag Dewatering & Cooling $15,549 $0 $7,674 $0 $0 $23,223 $2,215 $0 $2,544 $27,981 $5410.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.6 Ash Storage Silos $524 $0 $570 $0 $0 $1,094 $105 $0 $180 $1,379 $310.7 Ash Transport & Feed Equipment $707 $0 $170 $0 $0 $877 $81 $0 $144 $1,101 $210.8 Misc. Ash Handling Equipment $1,085 $1,329 $397 $0 $0 $2,811 $266 $0 $462 $3,539 $710.9 Ash/Spent Sorbent Foundation $0 $46 $58 $0 $0 $104 $10 $0 $34 $148 $0SUBTOTAL 10. $17,865 $1,375 $8,869 $0 $0 $28,109 $2,676 $0 $3,363 $34,149 $66TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants294Exhibit 3-112 Case 6 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:05-Apr-07Project:Bituminous Baseline StudyCase:Case 06 - Shell IGCC w/ CO2Plant Size:517.1 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW11 ACCESSORY ELECTRIC PLANT11.1 Generator Equipment $866 $0 $863 $0 $0 $1,729 $164 $0 $189 $2,083 $411.2 Station Service Equipment $4,130 $0 $388 $0 $0 $4,518 $429 $0 $495 $5,442 $1111.3 Switchgear & Motor Control $7,893 $0 $1,447 $0 $0 $9,340 $865 $0 $1,531 $11,735 $2311.4 Conduit & Cable Tray $0 $376 $12,191 $0 $0 $12,567 $1,524 $0 $3,523 $17,614 $3411.5 Wire & Cable $0 $6,897 $4,639 $0 $0 $11,536 $843 $0 $3,095 $15,474 $3011.6 Protective Equipment $0 $627 $2,378 $0 $0 $3,005 $294 $0 $495 $3,793 $711.7 Standby Equipment $208 $0 $211 $0 $0 $419 $40 $0 $69 $529 $111.8 Main Power Transformers $9,858 $0 $132 $0 $0 $9,990 $757 $0 $1,612 $12,358 $2411.9 Electrical Foundations $0 $142 $376 $0 $0 $518 $49 $0 $170 $737 $1SUBTOTAL 11. $22,955 $8,041 $22,625 $0 $0 $53,621 $4,967 $0 $11,178 $69,766 $13512 INSTRUMENTATION & CONTROL12.1 IGCC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $012.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $012.4 Other Major Component Control $1,006 $0 $700 $0 $0 $1,706 $164 $85 $293 $2,249 $412.5 Signal Processing Equipment W/12.7 $0 W/12.7 $0 $0 $0 $0 $0 $0 $0 $012.6 Control Boards,Panels & Racks $231 $0 $154 $0 $0 $386 $37 $19 $88 $531 $112.7 Computer & Accessories $5,368 $0 $179 $0 $0 $5,547 $526 $277 $635 $6,985 $1412.8 Instrument Wiring & Tubing $0 $1,908 $3,994 $0 $0 $5,902 $500 $295 $1,674 $8,372 $1612.9 Other I & C Equipment $3,588 $0 $1,815 $0 $0 $5,403 $518 $270 $929 $7,121 $14SUBTOTAL 12. $10,193 $1,908 $6,843 $0 $0 $18,945 $1,746 $947 $3,620 $25,258 $4913 Improvements to Site13.1 Site Preparation $0 $101 $2,167 $0 $0 $2,267 $223 $0 $747 $3,238 $613.2 Site Improvements $0 $1,790 $2,396 $0 $0 $4,186 $411 $0 $1,379 $5,976 $1213.3 Site Facilities $3,207 $0 $3,410 $0 $0 $6,617 $650 $0 $2,180 $9,446 $18SUBTOTAL 13. $3,207 $1,890 $7,973 $0 $0 $13,070 $1,284 $0 $4,306 $18,660 $3614 Buildings & Structures14.1 Combustion Turbine Area $0 $221 $127 $0 $0 $348 $31 $0 $76 $454 $114.2 Steam Turbine Building $0 $2,059 $2,972 $0 $0 $5,031 $462 $0 $824 $6,316 $1214.3 Administration Building $0 $814 $598 $0 $0 $1,412 $126 $0 $231 $1,768 $314.4 Circulation Water Pumphouse $0 $153 $82 $0 $0 $235 $21 $0 $38 $294 $114.5 Water Treatment Buildings $0 $457 $452 $0 $0 $909 $82 $0 $149 $1,140 $214.6 Machine Shop $0 $416 $289 $0 $0 $705 $63 $0 $115 $883 $214.7 Warehouse $0 $672 $440 $0 $0 $1,112 $98 $0 $182 $1,392 $314.8 Other Buildings & Structures $0 $403 $318 $0 $0 $721 $64 $0 $157 $942 $214.9 Waste Treating Building & Str. $0 $900 $1,744 $0 $0 $2,644 $246 $0 $578 $3,467 $7SUBTOTAL 14. $0 $6,095 $7,021 $0 $0 $13,117 $1,192 $0 $2,349 $16,657 $32TOTAL COST $715,547 $62,824 $259,009 $0 $0 $1,037,381 $96,266 $52,591 $193,286 $1,379,524 $2,668TOTAL PLANT COST SUMMARYCost and Performance Comparison of Fossil Energy Power Plants

295 

### Exhibit 3-113 Case 6 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006 Case 06 - Shell IGCC w/ CO2 H eat Rate-net(Btu/kWh): 10,674 MWe-net: 517 Capacity Factor: (%): 80 OPERATING & MAINTENANCE LABOR

Operating Labor Operating Labor Rate(base): 33.00 $/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 10.0 10.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 16.0 16.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,012,864 $11.627 Maintenance Labor Cost $12,084,712 $23.369 Administrative & Support Labor $4,524,394 $8.749 TOTAL FIXED OPERATING COSTS $22,621,970 $43.745 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $22,581,355 $0.00623

Consumables Consumption Unit Initial Initial /Day Cost Cost
Water(/1000 gallons) 0 6,551 1.03 $0 $1,970,146 $0.00054

Chemicals MU & WT Chem.(lb) 136,592 19,513 0.16 $22,510 $939,005 $0.00026 Carbon (Mercury Removal) (lb) 130,280 178 1.00 $130,280 $51,976 $0.00001 COS Catalyst (m3) 0 0 0.96 $0 $0 $0.00000 Water Gas Shift Catalyst(ft3) 6, 922 4.74 475.00 $3,287,950 $657,438 $0.00018 Selexol Solution (gal.) 469 67 12.90 $6,051 $252,397 $0.00007 MDEA Solution (gal) 0 0 0.96 $0 $0 $0.00000 Sulfinol Solution (gal) 0 0 9.68 $0 $0 $0.00000 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. 2.14 125.00 $0 $78,110 $0.00002 Subtotal Chemicals $3,446,791 $1,978,926 $0.00055

Other Supplemental Fuel(MBtu) 0 0 0.00 $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) 0 178 0.40 $0 $20,874 $0.00001 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Bottom Ash(ton) 0 568 15.45 $0 $2,561,970 $0.00071 Subtotal-Waste Disposal $0 $2,582,844 $0.00071

By-products & Emissions Sulfur(tons) 0 142 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $3,446,791 $29,113,271 $0.00803

Fuel(ton) 170,338 5,678 42.11 $7,172,945 $69,816,668 $0.01926Cost and Performance Comparison of Fossil Energy Power Plants

296 

### 3.5 IGCC CASE SUMMARY The performance results of the six IGCC plan t configurations modeled in this study are summarized in Exhibit 3-114.
Exhibit 3-114 Estimated Performan ce and Cost Results for IGCC Cases

Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 CO 2 Capture No Yes No Yes No Yes Gross Power Output (kW e ) 770,350 744,960 742,510 693,840 748,020 693,555 Auxiliary Power Requirement (kW e ) 130,100 189,285 119,140 175,600 112,170 176,420 Net Power Output (kW e ) 640,250 555,675 623,370 518,240 635,850 517,135 Coal Flowrate (lb/hr) 489,634 500,379 463,889 477,855 452,620 473,176 Natural Gas Flowrate (lb/hr) N/A N/A N/A N/A N/A N/A HHV Thermal Input (kW th ) 1,674,044 1,710,780 1,586,023 1,633,771 1,547,493 1,617,772 Net Plant HHV Efficiency (%) 38.2% 32.5% 39.3% 31.7% 41.1% 32.0% Net Plant HHV Heat Rate (Btu/kW-hr) 8,922 10,505 8,681 10,757 8,304 10,674 Raw Water Usage, gpm 4,003 4,579 3,757 4,135 3,792 4,563 Total Plant Cost ($ x 1,000) 1,160,919 1,328,209 1,080,166 1,259,883 1,256,810 1,379,524 Total Plant Cost ($/kW) 1,813 2,390 1,733 2,431 1,977 2,668 LCOE (mills/kWh) 1 78.0 102.9 75.3 105.7 80.5 110.4 CO 2 Emissions (lb/MWh) 2 1,459 154 1,452 189 1,409 149 CO 2 Emissions (lb/MWh) 3 1,755 206 1,730 253 1,658 199 SO 2 Emissions (lb/MWh) 2 0.0942 0.0751 0.0909 0.0686 0.0878 0.0837 NOx Emissions (lb/MWh) 2 0.406 0.366 0.433 0.400 0.413 0.388 PM Emissions (lb/MWh) 2 0.053 0.056 0.052 0.057 0.050 0.057 Hg Emissions (lb/MWh) 2 4.24E-06 4.48E-06 4.16E-06 4.59E-06 4.03E-06 4.55E-06

1 Based on an 80% capacity factor
2 Value is based on gross output
3 Value is based on net output GEE CoP Shell Integrated Gasification Combined Cycle



### The TPC of the six IGCC cases is shown in Exhibit 3-115. The following observations are made with the caveat that the differences between cases are less than the estimate accuracy (± 30 percent). However, all cases are evaluated using a common set of technical and economic assumptions allowing meaningful comparisons among the cases:

• CoP has the lowest capital cost among the non-capture cases. The E-Gas technology has several features that lend it to being lower cost, such as:

o The firetube syngas cooler is much sm aller and less expensive than a radiant section. E-Gas can use a firetube boile r because the two-stage design reduces the gas temperature (slurry quench) a nd drops the syngas temperature into a range where a radiant cooler is not needed.

o The firetube syngas cooler sits next to the gasifier instead of above or below it which reduces the height of the main gasifier structure. The E-Gas proprietary slag removal system, used instead of lock hoppers below the gasifier, also contributes to the lower structure height.
The TPC of the GEE gasifier is about 5 per cent greater than CoP and Shell is about 12 percent higher.Cost and Performance Comparison of Fossil Energy Power Plants

297 

### Exhibit 3-115 TPC for IGCC Cases

1,813 2,390

1,733 2,431

1,977 2,668

0 500 1,000 1,500 2,000 2,500 3,000Total Plant Cost, $/kW

GEE GEE w/ CO2 Capture CoP CoP w/ CO2 Capture Shell Shell w/ CO2 Capture



### • The GEE gasifier is the lo w cost technology in the CO 2 

### capture cases, with CoP about 2 percent higher and Shell about 12 percent higher. The greates t uncertainty in all of the capital cost estimates is for the Shell capture case which is based on a water quench process (instead of syngas r ecycle) that has been propos ed by Shell in a patent application. [ 53] However, to date there have be en no commercial applications of this configuration.

• The ASU cost represents on average 14 percent of the TPC (range from 12.6-15.8 percent). The ASU cost includes oxyge n and nitrogen compression, and in the noncapture cases, also includes the cost of the combustion turbine extraction air heat exchanger. With nitrogen dilution used to the maximum extent possible, nitrogen compression costs are significant.

• The capital cost premium for adding CO 2 

### capture averages 36 percent ($2,496/kW versus $1,841/kW). The 20-year LCOE is shown for the IGCC cases in Exhibit 3-116.Cost and Performance Comparison of Fossil Energy Power Plants

298 

### Exhibit 3-116 LCOE for IGCC Cases

78.0 102.9

75.3 105.7

80.5 110.4

0 20 40 60 80 100 120 140LCOE, mills/kWh

GEE GEE w/ CO2 Capture CoP CoP w/ CO2 Capture Shell Shell w/ CO2 Capture CO2 TS&M Costs Fuel Costs Variable Costs Fixed Costs Capital Costs



### The following observations can be made:

• The LCOE is dominated by capital costs, at le ast 57 percent of the total in all cases.

• In the non-capture cases the CoP gasifier has the lowest LCOE, but the differential with Shell is reduced (compared to the TPC) primar ily because of the higher efficiency of the Shell gasifier. The Shell LCOE is 7 percen t higher than CoP (compared to 12 percent higher TPC). The GEE gasifier LCOE is about 3.5 percent higher than CoP.

• In the capture cases the variation in LCOE is small, however the order of the GEE and CoP gasifiers is reversed. The range is from 102.9 mills/kWh for GEE to 110.4 mills/kWh for Shell with CoP intermed iate at 105.7 mills/kWh. The LCOE CO 2 

### capture premium for the IGCC cases averages 36 percent (range of 32 to 40 percent).

• The CO 2 

### TS&M LCOE component comprises less than 4 percent of the total LCOE in all capture cases. The effect of capacity factor and coal price on LCOE is shown in Exhibit 3-117 and Exhibit 3-118, respectively. The assumption implicit in Exhibit 3-117 is that each gasifi er technology can achieve a capacity factor of up to 90 percent with no additional capit al equipment. The cost differential between technologies decreases as capacity factor increases. At low ca pacity factor the capital cost differential is more magnified and the spread between technologies increases slightly.Cost and Performance Comparison of Fossil Energy Power Plants

299 

### Exhibit 3-117 Capacity Fact or Sensitivity of IGCC Cases

0 50 100 150 200 250

0 10 20 30 40 50 60 70 80 90 100 Capacity Factor, %LCOE, mills/kWh

GEE No Capture
GEE w/CO2 Capture
CoP No Capture
CoP w/CO2 Capture
Shell No Capture
Shell w/CO2 Capture Coal price of $1.80/MMBtu for all cases



### LCOE is relatively insensitive to fuel costs for the IGCC cases as shown in Exhibit 3-118. A tripling of coal price from 1 to $3/MMBtu results in an average LCOE increase of only about 26- 31 percent for all cases. As presented in Section 2.4 the cost of CO 2 

### capture was calculated in two ways, CO 2 

### removed and CO 2 

### avoided. The results for the IG CC carbon capture cases are shown in Exhibit 3-119. The cost of CO 2 

### removed averages $30/ton for the th ree IGCC cases with a range of $27- $32/ton. The CoP and Shell gasifier cases have near ly identical results but for different reasons. In the CoP case the cost per ton of CO 2 

### removed is higher than GEE primarily because it has the lowest CO 2 

### removal efficiency due to the higher syngas CH 4 

### content. The Shell case is higher than GEE because it has the highest LCOE of the three gasifiers.
The cost of CO 2 

### avoided averages $39/ton with a ra nge of $32-$42/ton. The cost of CO 2 

### avoided follows the same trends as CO 2 

### removed for the same reasons.Cost and Performance Comparison of Fossil Energy Power Plants

300 

### Exhibit 3-118 Coal Price Sensitivity of IGCC Cases

0 20 40 60 80 100 120 140

0 0.5 1 1.5 2 2.5 3 3.5 4 Coal Price, $/MMBtuLCOE, mills/kWh

GEE No Capture
GEE w/CO2 Capture
CoP No Capture
CoP w/CO2 Capture
Shell No Capture
Shell w/CO2 Capture Capacity factor of 80% for all cases



### Exhibit 3-119 Cost of CO 2 

### Captured and Avoided in IGCC Cases

27 32 32 41

31 42

0 5 10 15 20 25 30 35 40 45$/ton, CO2

GEE IGCC CoP IGCC Shell IGCC CO2 Removal Cost

CO2 Avoided CostCost and Performance Comparison of Fossil Energy Power Plants

301 

### The following observations can be ma de regarding plant performance:

• In the non-carbon capture cases the dry fed Shell gasifier has the highest net plant efficiency (41.1 percent), followed by the two-st age CoP slurry fed ga sifier (39.3 percent) and the single-stage GEE gasifi er (38.2 percent). The abso lute values of the GEE and CoP gasifiers are close to the re ported values per the vendors. [ 50, 51] The Shell efficiency is slightly lower than reported by the vendor in other recent presentations. [ 52]

• In the carbon capture cases the efficiency of the three gasifiers is nearly equal, ranging from 31.7 to 32.5 percent.

• The dry fed Shell gasifier experiences the la rgest energy penalty ( 9.1 percent) primarily because addition of the steam required for th e water gas shift reaction is provided as quench water to reduce the syngas temperat ure from 1427°C (2600°F) to 399°C (750°F). Quench to 399°C (750°F) reduces the amount of heat recovered in the syngas cooler relative to the non-capture cas e where syngas recycle reduces the temperature to only 891°C (1635°F) prior to the cooler. The CO 2 

### capture scheme used in this study for the Shell process is similar to one described in a recent Shell pa tent application. [ 53]

• The CoP process experiences the second larg est energy penalty (7.6 percent) primarily because, like the Shell case, a significant am ount of water must be added to the syngas for the SGS reactions.

• The energy penalty for the GEE gasifier with CO 2 

### capture is 5.7 percent. The smaller energy penalty results from the large amount of water already in the syngas from the quench step prior to SGS. While the quench lim its the efficiency in the non-capture case, it is the primary reason that the net efficiency is slightly greater than CoP and Shell in the CO 2 

### capture case.

• The assumed carbon conversion efficiency in th is study for the three gasifiers results in differing amount of carbon in the slag. Exhibit 3-120 shows carbon conversion and slag carbon content. Carbon capture efficiency is reported based on the amount of carbon entering the system with the coal less the carbon exiting the gasifier with the slag.

Exhibit 3-120 Carbon Conversion E fficiency and Slag Carbon Content

Gasifier Vendor Carbon Conversion, % Slag Carbon Content, wt%

GEE 98.0 11.66

CoP 99.2 4.70

Shell 99.5 3.19

• Particulate emissions and Hg emissions are es sentially the same for all six IGCC cases. The environmental target for particulat e emissions is 0.0071 lb/MMBtu, and it was assumed that the combination of particulate control used by each technology could meet this limit. Similarly, the carbon beds used for mercury control were uniformly assumed to achieve 95 percent removal. The small va riation in Hg emissions is due to a similar small variation in coal feed rate among the si x cases. In all case s the Hg emissions areCost and Performance Comparison of Fossil Energy Power Plants

302 

### substantially below the N SPS requirement of 20 x 10 -6 

### lb/MWh. Had 90 percent been chosen for the Hg removal efficiency, all si x cases would still have had emissions less than half of the NSPS limit.

• Based on vendor data, it was assumed that the advanced F class turbine would achieve 15 ppmv NOx emissions at 15 percent O 2 

### for both “standard” synga s in the non-capture cases and for high hydrogen syngas in the CO 2 

### capture cases. The NOx emissions are slightly lower in the three capture cases (compared to non- capture) because of the lower syngas volume generated in high hydrogen syngas cases.

• The environmental target for SO 2 

### emissions is 0.0128 lb/MMBtu. Vendor quotes confirmed that each of the AGR processes, Selexol, refrigerated MDEA and Sulfinol-M, could meet the limit. The two-stage Se lexol process used for each of the CO 2 

### capture cases resulted in lower SO 2 

### emissions because the unit was designed to meet the CO 2 

### removal requirement. The CoP gasifier has the lowest SO 2 

### emissions among CO 2 

### capture cases because of maximizing CO 2 

### capture to compensate for the higher CH 4 

### concentration in the CoP raw syngas. Water demand, internal recycle a nd water usage, all no rmalized by net output, are presented in Exhibit 3-121. The following observations can be made:

• Raw water usage for all cases is dominat ed by cooling tower makeup requirements, which accounts for 84-92 percent of raw water usage in non-capture cases and 71-78 percent in CO 2 

### capture cases.

• Normalized water demand for the GEE non-captu re case is 17 per cent higher than the CoP non-capture case and 24 percent higher th an the Shell non-capture case primarily because of the large quench water requirement . However, because much of the quench water is subsequently recovered as condens ate as the syngas is cooled, the raw water usage of the GEE process is only 3.7 percent higher than Co P and 4.8 percent higher than Shell.

• The Shell non-capture case has the lowest normalized water demand, but is approximately equal to CoP in normalized ra w water usage because very little water is available to recover for internal recycle in the Shell system. The GEE normalized raw water usage is slightly higher than CoP a nd Shell primarily because the larger steam turbine output leads to higher co oling tower makeup requirements.

• The normalized water demand for the three CO 2 

### capture cases varies by only 11 percent from the highest to the lowest. The vari ation between cases is small because each technology requires approximately the same amo unt of water in the syngas prior to the shift reactors. The difference in technologies is where and how the water is introduced. Much of the water is introduced in the quenc h sections of the GEE and Shell cases while steam is added in the CoP case.

• The normalized raw water usage in the CO 2 

### capture cases also show s little variation with CoP the lowest, GEE only 3.3 percent higher and Shell about 10 percent higher. The main reason for the lower CoP water requirement is less cooling tower makeup is required because a significant amount of ex traction steam is used for the SGS shift reaction.Cost and Performance Comparison of Fossil Energy Power Plants

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### Exhibit 3-121 Water Usage in IGCC Cases

7.7

6.3 9.8

8.2

6.6 6.0 9.7

8.0

6.2 6.0 10.8

8.8

0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0Water, gpm/MW(net)

GEE GEE w/CO2 Capture CoP CoP w/ CO2 Capture Shell Shell w/ CO2 Capture Water Demand
Internal Recycle
Raw Water UsageCost and Performance Comparison of Fossil Energy Power Plants

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### This page intentionally left blankCost and Performance Comparison of Fossil Energy Power Plants

305 

## 4 PULVERIZED COAL R ANKINE CYCLE PLANTS Four pulverized coal-fired (PC) Rankine cycle power plant configuratio ns were evaluated and the results are presented in this section. Each design is based on a market-ready technology that is assumed to be commercially available in time to support a 2010 start up date. All designs employ a one-on-one configurati on comprised of a state-of-the art pulverized coal steam generator firing Illinois No. 6 co al and a steam turbine.
The PC cases are evaluated with and without carbon capture on a common 550 MWe net basis. The designs that include carbon captu re have a larger gross unit si ze to compensate for the higher auxiliary loads. The constant net output sizi ng basis is selected b ecause it provides for a meaningful side-by-side comparison of the results . The boiler and steam turbine industry ability to match unit size to a custom specification has been commercially demonstrated enabling common net output comparison of the PC cases in this study. As discussed in Section 3, this was not possible in the IGCC cases because of the fixed output from the combustion turbine. However, the net output from the PC cases fall s in the range of outputs from the IGCC cases, which average 530 MW for CO 2 

### capture cases and 630 MW for non-capture cases. Steam conditions for the Rankine cycle cases we re selected based on a survey of boiler and steam turbine original equipment manufacturers (O EM), who were asked for the most advanced steam conditions that they would guarantee for a commercial project in th e US with subcritical and supercritical PC units rated at nominal 550 MWe net capacities and firing Illinois No. 6 coal [ 54]. Based on the OEM responses, the follo wing single-reheat st eam conditions were selected for the study:

3⁄4 For subcritical cycle cases (9 and 10) – 16.5 MPa/566°C/566°C (2400 psig/1050°F/1050°F)
3⁄4 For supercritical cases (11 and 12) – 24.1 MPa/593°C/593°C (3500 psig/1100°F/1100°F) While the current DOE program for the ultra supe rcritical cycle materials development targets 732°C/760°C (1350oF/1400oF) at 34 .5 MPa (5000 psi) cycle conditions to be available by 2015, and a similar Thermie program in the European Union (EU) has targeted 700°C/720°C (1292oF/1328oF) at about 29.0 MPa (4200 psi) [ 55], steam temperature selection for boilers depends upon fuel corrosiveness. Most of th e contacted OEMs were of the opinion that the steam conditions in this range would be limited to low sulfur coal applications (such as PRB). Their primary concern is that elevated temperat ure operation while firing high sulfur coal (such as Illinois No. 6) would result in an exponential increase of the material wastage rates of the highest temperature portions of th e superheater and reheater due to coal ash corrosion, requiring pressure parts replacement outages approximately ev ery 10 or 15 years. This cost would offset the value of fuel savings and emissions re duction due to the higher efficiency. The availability/reliability of the more exotic materials required to support the elevated temperature environment for high sulfur/chlorine applicatio ns, while extensively demonstrated in the laboratory [ 56], has not been commercially demonstrate d. In addition, the three most recently built supercritical units in North America have steam cycles similar to this study’s design basis, namely Genesee Phase 3 in Canada, which started operations in 2004 (25.0 MPa/570°C/568°C [3625 psia/1058°F/1054°F]), Council Bluffs 4 in the United States, which is currently under construction (25.4 MPa/566°C/593°C [3690 psia/ 1050°F/1100°F]), and Oak Creek 1 and 2, which are currently under construction (24.1 MPa/566°C [3500 psig/1050°F]).Cost and Performance Comparison of Fossil Energy Power Plants

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### The evaluation basis details, including site ambient conditions, fuel composition and the emissions control basis, are provid ed in Section 2 of this report.

4.1 PC COMMON PROCESS AREAS The PC cases have process areas which are comm on to each plant configuration such as coal receiving and storage, emissions control technologies, power generation, etc. As detailed descriptions of these process areas in each cas e section would be burdensome and repetitious, they are presented in this sect ion for general background information. The performance features of these sections are then presen ted in the case-specific sections.

4.1.1 C OAL AND 

### S ORBENT 

### R ECEIVING AND 

### S TORAGE 

### The function of the coal portion of the Coal a nd Sorbent Receiving and Storage system for PC plants is identical to the IGCC facilities. It is to provide the equipment required for unloading, conveying, preparing, and stor ing the fuel delivered to the plant. The scope of the system is from the trestle bottom dumper and coal receiving hoppers up to the coal storage silos. The system is designed to support short-term operation at th e 5 percent over pressure/valves wide open (OP/VWO) condition (16 hours) and long-term oper ation of 90 days or more at the maximum continuous rating (MCR). The scope of the sorbent receiving and storag e system includes truck roadways, turnarounds, unloading hoppers, conveyors and the day storage bin. Operation Description - The coal is delivered to the site by 100-car unit trains comprised of 91 tonne (100 ton) rail cars. Th e unloading is done by a trestle bo ttom dumper, which unloads the coal into two receiving hoppers. Coal from each hopper is fed directly into a vibratory feeder. The 8 cm x 0 (3" x 0) coal from the feeder is discharged onto a belt conveyor. Two conveyors with an intermediate transfer tower are assumed to convey the coal to the coal stacker, which transfer the coal to either the long-term storage pile or to the reclaim area. The conveyor passes under a magnetic plate separator to remove tr amp iron and then to the reclaim pile. Coal from the reclaim pile is fed by two vibr atory feeders, located under the pile, onto a belt conveyor, which transfers the coal to the coal surge bin located in the crusher tower. The coal is reduced in size to 2.5 cm x 0 (1" x 0) by the coal crushers. The coal is then transferred by conveyor to the transfer tower. In the transfer to wer the coal is routed to the tripper that loads the coal into one of the six boiler silos. Limestone is delivered to the site using 23 tonne (25 ton) trucks. The trucks empty into a below grade hopper where a feeder transfers the limestone to a conveyor for delivery to the storage pile. Limestone from the storage pile is transferre d to a reclaim hopper and conveyed to a day bin.

4.1.2 S TEAM 

### G ENERATOR AND 

### A NCILLARIES 

### The steam generator for the subcritical PC plants is a drum-type, wall-fired, balanced draft, natural circulation, totally enclosed dry bottom furnace, with superheater, reheater, economizer and air-heater. The steam generator for the supercritical plan ts is a once-through, spiral-wound, Benson-boiler, wall-fired, balanced draft type unit with a water-cooled dry bottom furnace. It includes superheater, reheater, ec onomizer, and air heater.Cost and Performance Comparison of Fossil Energy Power Plants

307 

### It is assumed for the purposes of this study that the power plant is design ed to be operated as a base-loaded unit but with some consideration fo r daily or weekly cycling, as can be cost effectively included in the base design. The combustion systems for both subcritical a nd supercritical steam conditions are equipped with LNBs and OFA. It is assumed for the purposes of this study th at the power plant is designed for operation as a base-load unit. Scope The steam generator comprises the following for both subcritical and supercritical PCs:
3⁄4 Drum-type evaporator (subcritical only) 3⁄4 Economizer 3⁄4 Overfire air system

3⁄4 Once-through type steam generator (supercritical only) 3⁄4 Spray type desuperheater 3⁄4 Forced draft (FD) fans

3⁄4 Startup circuit, including integral separators (supercritical only) 3⁄4 Soot blower system 3⁄4 Primary air (PA) fans

3⁄4 Water-cooled furnace, dry bottom 3⁄4 Air preheaters (Ljungstrom type) 3⁄4 Induced draft (ID) fans

3⁄4 Two-stage superheater 3⁄4 Coal feeders and pulverizers
3⁄4 Reheater 3⁄4 Low NOx Coal burners and light oil ignitors/ warmup system
The steam generator operates as follows:
Feedwater and Steam For the subcritical steam system feedwater en ters the economizer, recovers heat from the combustion gases exiting the steam generator, and then passes to the boiler drum, from where it is distributed to the water wall circuits encl osing the furnace. After passing through the lower and upper furnace circuits and steam drum in sequence, the steam passes through the convection enclosure circuits to the pr imary superheater and then to the secondary superheater. The steam then exits the steam generator en route to the HP turbine. Steam from the HP turbine returns to the steam generator as cold reheat and returns to the IP turbine as hot reheat. For the supercritical steam syst em feedwater enters the bottom header of the economizer and passes upward through the economizer tube ba nk, through stringer t ubes which support the primary superheater, and discharg es to the economizer outlet head ers. From the outlet headers, water flows to the furnace hopper inlet headers via external downcomers. Water then flows upward through the furnace hopper and furnace wall tube s. From the furnace, water flows to the steam water separator. During low load operatio n (operation below the Benson point), the waterCost and Performance Comparison of Fossil Energy Power Plants

308 

### from the separator is returned to the economizer inlet with the boiler recirculating pump. Operation at loads above the Benson point is once through. Steam flows from the separator through the furnace roof to the convection pass enclosure walls, primary superheater, through the fi rst stage of water attemperation, to the furnace platens. From the platens, the steam flows through the sec ond stage of attemperation and then to the intermediate superheater. The steam then flows to the final superheater and on to the outlet pipe terminal. Two stages of spray attemperation are used to provide tight temperature control in all high temperature sections during rapid load changes. Steam returning from the turbine passes thr ough the primary reheater surface, then through crossover piping containing inter-stage attempera tion. The crossover piping feeds the steam to the final reheater banks and then out to the turbine. Inter-stage at temperation is used to provide outlet temperature control during load changes.
Air and Combustion Products
Combustion air from the FD fans is heated in Ljungstrom type air preheaters, recovering heat energy from the exhaust gases exi ting the boiler. This air is di stributed to the burner windbox as secondary air. Air for conveying pulverized coal to the burners is supplied by the PA fans. This air is heated in the Ljungstrom type air preheater s to permit drying of the pulverized coal, and a portion of the air from the PA fans bypasses the air preheaters to be used for regulating the outlet coal/air temperature leaving the mills. The pulverized coal and air mixture flows to the coal nozzles at vari ous elevations of the furnace. The hot combustion products rise to the top of the boiler and pass through the superheater and reheater sections. The gases then pass through th e economizer and air preheater. The gases exit the steam generator at this point and flow to th e SCR reactor, fabric filter, ID fan, FGD system, and stack.
Fuel Feed
The crushed Illinois No. 6 bituminous coal is fed through feeders to each of the mills (pulverizers), where its size is reduced to approximately 72% passing 200 mesh and less than 0.5% remaining on 50 mesh [ 57]. The pulverized coal exits each mill via the coal piping and is distributed to the coal nozzles in the fu rnace walls using air supplied by the PA fans.
Ash Removal The furnace bottom comprises several hoppers, with a clinker grinder under each hopper. The hoppers are of welded steel cons truction, lined with refractory. The hopper design incorporates a water-filled seal trough around the upper periphery for cooling and sealing. Water and ash discharged from the hopper pass through the clinker grinder to an ash sluice system for conveyance to hydrobins, where the ash is dewatered before it is transferred to trucks for offsite disposal. The description of the balance of the bottom ash handling system is presented in Section 4.1.9. The steam generator incorporates fl y ash hoppers under the economizer outlet and air heater outlet.
Burners A boiler of this capacity employs approximately 24 to 36 coal nozzles arranged at multiple elevations. Each burner is de signed as a low-NOx configurat ion, with staging of the coalCost and Performance Comparison of Fossil Energy Power Plants

309 

### combustion to minimize NOx formation. In additi on, overfire air nozzles ar e provided to further stage combustion and thereby minimize NOx formation. Oil-fired pilot torches are provided for each coal burner for ignition, warm-up and flame stabilization at startup and low loads.
Air Preheaters Each steam generator is furnished with two ve rtical-shaft Ljungstrom regenerative type air preheaters. These units are driven by electric motors through gear reducers.
Soot Blowers The soot-blowing system utilizes an array of 50 to 150 retractable nozzles and lances that clean the furnace walls and convection surfaces with je ts of high-pressure steam. The blowers are sequenced to provide an effective cleaning cycl e depending on the coal qua lity and design of the furnace and convection surfaces. Electric motors drive the soot blowers through their cycles.

4.1.3 NO X 

### C ONTROL 

### S YSTEM 

### The plant is designed to achieve the envir onmental target of 0.07 lb NOx/MMBtu. Two measures are taken to reduce the NOx. The firs t is a combination of low-NOx burners and the introduction of staged overfire air in the boiler. The low-NOx burners and overfire air reduce the emissions to about 0.5 lb/MMBtu.
The second measure taken to reduce the NOx emi ssions is the installation of an SCR system prior to the air heater. SCR uses a mmonia and a catalyst to reduce NOx to N 2 

### and H 2 

### O. The SCR system consists of three subsystems: r eactor vessel, ammonia storage and injection, and gas flow control. The SCR system is desi gned for 86 percent reducti on with 2 ppmv ammonia slip at the end of the catalyst life. This, al ong with the low-NOx burners, achieves the emission limit of 0.07 lb/MMBtu. The SCR capital costs are included with the boiler co sts, as is the cost for the initial load of catalyst. Selective non-catalytic reduction (SNCR) was considered for this application. However, with the installation of the low-NOx burners and overfi re air system, the boiler exhaust gas contains relatively small amounts of NOx, which makes re moval of the quantity of NOx with SNCR to reach the emissions limit of 0.07 lb /MMBtu difficult. SNCR works better in applications that contain medium to high quantities of NOx and requi re removal efficiencies in the range of 40 to 60 percent. SCR, because of the catalyst used in the reaction, can achieve higher efficiencies with lower concentrations of NOx. SCR Operation Description The reactor vessel is designed to allow proper retention time for the ammonia to contact the NOx in the boiler exhaust gas. Amm onia is injected into the gas im mediately prior to entering the reactor vessel. The catalyst contained in the reactor vessel enhances the reaction between the ammonia and the NOx in the gas. Catalysts cons ist of various active materials such as titanium dioxide, vanadium pentoxide, and tungsten trioxi de. The operating range for vanadium/titaniumbased catalysts is 260°C (500 ° F) to 455°C (850 ° F). The boiler is equipped with economizer bypass to provide flue gas to the reactors at th e desired temperature duri ng periods of low flowCost and Performance Comparison of Fossil Energy Power Plants

310 

### rate, such as low load operation. Also incl uded with the reactor vessel is soot-blowing equipment used for cleaning the catalyst. The ammonia storage and injection system consists of the unloading facilities, bulk storage tank, vaporizers, dilution air sk id, and injection grid. The flue gas flow control consists of ductwork, dampers, and flow straightening devices required to route the boiler exhaust to the SCR reactor an d then to the air heater. The economizer bypass and associated dampers for low load temperature control are also included.

4.1.4 P ARTICULATE 

### C ONTROL 

### The fabric filter (or baghouse) consists of two separate single-stage, in-line, multi-compartment units. Each unit is of high (0.9-1.5 m/min [3-5 ft /min]) air-to-cloth rati o design with a pulse-jet on-line cleaning system. The ash is collected on the outside of the bags, which are supported by steel cages. The dust cake is removed by a pulse of compressed air. The bag material is polyphenylensulfide (PPS) with intrinsic Teflon (PTFE) coating [ 58]. The bags are rated for a continuous temperature of 180°C (356°F) and a peak temperature of 210°C (410°F). Each compartment contains a number of gas passa ges with filter bags, and heated ash hoppers supported by a rigid steel casing. The fabric fi lter is provided with n ecessary control devices, inlet gas distribution devices, in sulators, inlet and outlet nozzles , expansion joints, and other items as required.

4.1.5 M ERCURY 

### R EMOVAL 

### Mercury removal is based on a coal Hg conten t of 0.15 ppmd. The basis for the coal Hg concentration was discussed in Section 2.4. The combination of pollution control technologies used in the PC plants, SCR, fabric filters a nd FGD, result in significant co-benefit capture of mercury. The SCR promotes the oxidation of el emental mercury, which in turn enhances the mercury removal capability of the fabric filter and FGD unit. Th e mercury co-benefit capture is assumed to be 90 percent for this combination of control technologies as described in Section 2.4. Co-benefit capture alone is sufficient to m eet current NSPS mercury limits so no activated carbon injection is included in the PC cases.

4.1.6 F LUE 

### G AS 

### D ESULFURIZATION 

### The FGD system is a wet limestone forced oxida tion positive pressure absorber non-reheat unit, with wet-stack, and gypsum production. The functi on of the FGD system is to scrub the boiler exhaust gases to remove the SO 2 

### prior to release to the environm ent, or entering into the Carbon Dioxide Removal (CDR) facility. Sulfur removal efficiency is 98 percent in the FGD unit for all cases. For Cases 10 and 12 with CO 2 

### capture, the SO 2 

### content of the scrubbed gases must be further reduced to approximately 10 ppmv to mi nimize formation of amine heat stable salts during the CO 2 

### absorption process. The CDR unit includes a polishing scrubber to reduce the flue gas SO 2 

### concentration from about 38 ppmv at the FGD exit to the require d 10 ppmv prior to the CDR absorber. The scope of the FGD system is from the outlet of the ID fans to the stack inlet (Cases 9 and 11) or to th e CDR process inlet (Cases 10 and 12). The system description is divided into three sections:

• Limestone Handling and Reagent Preparation

• FGD ScrubberCost and Performance Comparison of Fossil Energy Power Plants

311 

### • Byproduct Dewatering Reagent Preparation System The function of the limestone reag ent preparation system is to grind and slurry the limestone delivered to the plant. The scope of the system is from the day bin up to the limestone feed system. The system is designed to support continuous baseload operation. Operation Description - Each day bin supplies a 100 per cent capacity ball mill via a weigh feeder. The wet ball mill accepts the limestone and grinds the limestone to 90 to 95 percent passing 325 mesh (44 microns). Water is added at the inlet to the ball mill to create limestone slurry. The reduced limestone slurry is then di scharged into a mill slurry tank. Mill recycle pumps, two per tank, pump the limestone water slurry to an assembly of hydrocyclones and distribution boxes. The slurry is classified into several st reams, based on suspended solids content and size distribution. The hydrocyclone underflow with oversized limestone is directed back to the mill for further grinding. The hydrocyclone overflow with correc tly sized limestone is routed to a reagent storage tank. Reagent di stribution pumps direct slurry from the tank to the absorber module.
FGD Scrubber The flue gas exiting the air preheater section of the boiler passes through one of two parallel fabric filter units, then through the ID fans and into the one 100 percent capacity absorber module. The absorber module is designed to op erate with counter-curre nt flow of gas and reagent. Upon entering the bottom of the absorber ve ssel, the gas stream is subjected to an initial quenching spray of reagent. The gas flows upward through the spray zone, which provides enhanced contact between gas and reagent. Multiple spray elevations with header piping and nozzles maintain a consistent reagent concentra tion in the spray zone. Continuing upward, the reagent-laden gas passes through several levels of moisture separators. These consist of chevron-shaped vanes that dir ect the gas flow through several abrupt changes in direction, separating the entrained droplets of liquid by inertial effects. The scrubbed flue gas exits at the top of the absorber vessel and is routed to the plant stack or CDR process. The scrubbing slurry falls to the lower portion of the absorber vessel, which contains a large inventory of liquid. Oxidation ai r is added to promote the oxidati on of calcium sulfite contained in the slurry to calcium sulfat e (gypsum). Multiple agitators operate continuously to prevent settling of solids and enhance mi xture of the oxidation air and th e slurry. Recirculation pumps recirculate the slurry from the lower portion of the absorber vessel to the spray level. Spare recirculation pumps are provided to en sure availability of the absorber. The absorber chemical equilibrium is maintained by continuous makeup of fresh reagent, and blowdown of byproduct solids via the bleed pumps. A spare bleed pump is provided to ensure availability of the absorber. The byproduct solids are routed to the byproduct dewatering system. The circulating slurry is m onitored for pH and density. This FGD system is designed for wet stack opera tion. Scrubber bypass or reheat, which may be utilized at some older facilities to ensure th e exhaust gas temperature is above the saturation temperature, is not employed in this refere nce plant design because new scrubbers have improved mist eliminator efficien cy, and detailed flow modeling of the flue interior enables the placement of gutters and drains to intercept mois ture that may be present and convey it to aCost and Performance Comparison of Fossil Energy Power Plants

312 

### drain. Consequently, raising the exhaust gas te mperature above the FGD discharge temperature of 57°C (135°F) (non-CO 2 

### capture cases) or 32°C (89°F) (CO 2 

### capture cases) is not necessary. Byproduct Dewatering The function of the byproduct dewate ring system is to dewater the bleed slurry from the FGD absorber modules. The dewatering process se lected for this plan t is gypsum dewatering producing wallboard grade gypsum. The scope of the system is from the bleed pump discharge connections to the gypsum storage pile. Operation Description - The recirculating reagent in the FGD absorber vessel accumulates dissolved and suspended solids on a con tinuous basis as byproducts from the SO 2 

### absorption process. Maintenance of the quality of the recirculating sl urry requires that a portion be withdrawn and replaced by fresh reagent. Th is is accomplished on a continuous basis by the bleed pumps pulling off byproduct solids and the reagent distribution pumps supplying fresh reagent to the absorber. Gypsum (calcium sulfate) is produced by the injection of oxygen into the calcium sulfite produced in the absorber tower sump. The bleed from the absorber contains approximately 20 wt% gypsum. The absorber slurry is pumped by an absorber bleed pump to a primary dewatering hydrocyclone cluster. The primary hydrocyclone performs two process functions. The first function is to dewater the slurry from 20 wt% to 50 wt% solids. The second function of the primary hydrocyclone is to perform a CaCO 3 

### and CaSO 4 

### •2H 2 

### O separation. This process ensures a limestone stoichiome try in the absorber vessel of 1.10 and an overall limestone stoichiometry of 1.05. This system reduces the overall operating cost of the FGD system. The underflow from the hydrocyclone flows into the f ilter feed tank, from which it is pumped to a horizontal belt vacuum filter. Two 100 percen t filter systems are pr ovided for redundant capacity. Hydrocyclones The hydrocyclone is a simple and reliable devi ce (no moving parts) designed to increase the slurry concentration in one step to approximate ly 50 wt%. This high slurry concentration is necessary to optimize operation of the vacuum belt filter. The hydrocyclone feed enters tangentially and ex periences centrifugal mo tion so that the heavy particles move toward the wall and flow out the bottom. Some of the lighter particles collect at the center of the cyclone and flow out the top. The underflow is thus concentrated from 20 wt% at the feed to 50 wt%. Multiple hydrocyclones are used to process the bleed stream from the absorber. The hydrocyclones are configured in a cluster with a common feed header. The system has two hydrocyclone clusters, each with five 15 cm (6 in ch) diameter units. Four cyclones are used to continuously process the bleed stream at de sign conditions, and one cyclone is spare. Cyclone overflow and underflow ar e collected in separate lau nders. The overflow from the hydrocyclones still contains a bout 5 wt% solids, consisting of gypsum, fly ash, and limestone residues and is sent back to the absorber. Th e underflow of the hydrocyclones flows into the filter feed tank from where it is pumped to the horizontal belt vacuum filters.Cost and Performance Comparison of Fossil Energy Power Plants

313 

### Horizontal Vacuum Belt Filters The secondary dewatering system consists of horizontal vacuum belt filters. The preconcentrated gypsum slurry (50 wt%) is pumped to an overflow pan thro ugh which the slurry flows onto the vacuum belt. As the vacuum is pulled, a layer of cake is formed. The cake is dewatered to approximately 90 wt% solids as the be lt travels to the discharge. At the discharge end of the filter, the filter cloth is turned over a roller where the solids are dislodged from the filter cloth. This cake falls through a chute onto the pile prior to the final byproduct uses. The required vacuum is provided by a vacuum pump. Th e filtrate is collected in a filtrate tank that provides surge volume for use of the filtrate in gr inding the limestone. Filtrate that is not used for limestone slurry preparation is returned to the absorber.

4.1.7 C ARBON 

### D IOXIDE 

### R ECOVERY 

### F ACILITY 

### A Carbon Dioxide Recovery (CDR) facility is us ed in Cases 10 and 12 to remove 90 percent of the CO 2 

### in the flue gas exiting the FGD unit, pur ify it, and compress it to a supercritical condition. The flue gas ex iting the FGD unit contains about 1 percent more CO 2 

### than the raw flue gas because of the CO 2 

### liberated from the limestone in the FGD absorber vessel. The CDR is comprised of the flue gas supply, SO 2 

### polishing, CO 2 

### absorption, solvent stripping and reclaiming, and CO 2 

### compression and drying.

The CO 2 

### absorption/stripping/solvent reclaim proce ss for Cases 10 and 12 is based on the Fluor Econamine FG Plus technology. [ 59] A typical flowsheet is shown in Exhibit 4-1. The Econamine FG Plus process uses a formulati on of monoethanolamine (M EA) and a proprietary inhibitor to recover CO 2 

### from the flue gas. This process is designed to recover high-purity CO 2 

### from low-pressure streams that contain oxygen, such as flue gas from co al-fired power plants, gas turbine exhaust gas, and other waste gases. The Econamine process used in this study differs from previous studies, including the 2004 IEA study, [ 59] in the following ways:

• The complexity of the control and operati on of the plant is significantly decreased

• Solvent consumption is decreased

• Hard to dispose waste from the plant is eliminated The above are achieved at the expense of a slig htly higher steam requirement in the stripper (3,556 kJ/kg [1,530 Btu/lb] versus 3,242 kJ/kg [1,395 Btu/lb] used in the IEA study). [ 60]Cost and Performance Comparisonof Fossil Energy Power Plants314Exhibit 4-1 Fluor Econamine FGPlus Typical Flow DiagramCost and Performance Comparison of Fossil Energy Power Plants

315 

### SO 2 

### Polishing and Flue Gas Cooling and Supply To prevent the accumulation of heat stable sa lts, the incoming flue gas must have an SO 2 

### concentration of 10 ppmv or less. The ga s exiting the FGD system passes through an SO 2 

### polishing step to achieve this objective. The polishing step consists of a non-plugging, lowdifferential-pressure, spray-baffle-type scrubbe r using a 20 wt% solution of sodium hydroxide (NaOH). A removal efficiency of about 75 percent is necessary to reduce SO 2 

### emissions from the FGD outlet to 10 ppmv as required by the Econamine process. The polishing scrubber proposed for this application has been demons trated in numerous industrial applications throughout the world and can achieve removal e fficiencies of over 95 percent if necessary.
The polishing scrubber also serves as the flue gas cooling system. Cooling water from the PC plant is used to reduce the temperature and hence moisture content of the saturated flue gas exiting the FGD system. Flue gas is cooled beyond the CO 2 

### absorption process requirements to 32°C (90°F) to account for the subsequent flue ga s temperature increase of about 17°C (30°F) in the flue gas blower. Downstream from the Polishi ng Scrubber flue gas pressure is boosted in the Flue Gas Blowers by approximately 0.014 MPa (2 psi) to overcome pressure drop in the CO 2 

### absorber tower.
Circulating Water System Cooling water is provided from the PC plant circ ulating water system a nd returned to the PC plant cooling tower. The CDR f acility requires a significant amount of cooling water for flue gas cooling, water wash cooling, absorber intercoolin g, reflux condenser duty, reclaimer cooling, the lean solvent cooler, and CO 2 

### compression interstage cooling. The cooling water requirements for the CDR facility in the two PC capture cases range from 1,514,180-1,703,450 lpm (400,000- 450,000 gpm), which greatly exceeds the PC pl ant cooling water requirement of 719,235- 870,650 lpm (190,000-230,000 gpm).

CO 2 

### Absorption The cooled flue gas enters the bottom of the CO 2 

### Absorber and flows up through the tower countercurrent to a stream of lean MEA-ba sed solvent called Econamine FG Plus. Approximately 90 percent of the CO 2 

### in the feed gas is absorbed into the lean solvent, and the rest leaves the top of the absorb er section and flows into the water wash section of the tower. The lean solvent enters the top of the absorber, absorbs the CO 2 

### from the flue gases and leaves the bottom of the absorber with the absorbed CO 2 

### .
Water Wash Section
The purpose of the Water Wash section is to minimize solvent losses due to mechanical entrainment and evaporation. The flue gas from the top of the CO 2 

### Absorption section is contacted with a re-circulating stre am of water for the removal of mo st of the lean solvent. The scrubbed gases, along with unrecovere d solvent, exit the top of the wash section for discharge to the atmosphere via the vent stack. The water st ream from the bottom of the wash section is collected on a chimney tray. A portion of the wate r collected on the chimne y tray spills over to the absorber section as water makeup for the am ine with the remainder pumped via the Wash Water Pump and cooled by the Wash Water Cool er, and recirculated to the top of the CO 2Cost and Performance Comparison of Fossil Energy Power Plants

316 

### Absorber. The wash water level is maintained by water makeup from the Wash Water Makeup Pump.
Rich/Lean Amine Heat Exchange System
The rich solvent from the bottom of the CO 2 

### Absorber is preheated by the lean solvent from the Solvent Stripper in the Rich Lean Solvent Exchanger. The heated rich solvent is routed to the Solvent Stripper for removal of the absorbed CO 2 

### . The stripped solvent from the bottom of the Solvent Stripper is pumped via th e Hot Lean Solvent Pumps through the Rich Lean Exchanger to the Solvent Surge Tank. Prior to entering the Solvent Surge Tank, a slipstream of the lean solvent is pumped via the Solvent Filter F eed Pump through the Solvent Filter Package to prevent buildup of contaminants in the solution. From the Solvent Surge Ta nk the lean solvent is pumped via the Warm Lean Solvent Pumps to the Lean Solvent Cooler fo r further cooling, after which the cooled lean solvent is returned to the CO 2 

### Absorber, completing the circulating solvent circuit.
Solvent Stripper The purpose of the Solvent Stripper is to separate the CO 2 

### from the rich solvent feed exiting the bottom of the CO 2 

### Absorber. The rich solvent is colle cted on a chimney tray below the bottom packed section of the Solvent Stripper and rout ed to the Solvent Stripper Reboilers where the rich solvent is heated by steam, stripping the CO 2 

### from the solution. Steam is provided from the LP section of the steam turbine and is be tween 0.9-1.2 MPa (130-170 psia) and 366-396°C (690- 745°F) for the two PC cases. The hot wet vapor from the top of the stripper containing CO 2 

### , steam, and solvent vapor, is partially condensed in the Solvent Stripper Condenser by cross exchanging the hot wet vapor with cooling water. The partially condensed stream then flows to the Solvent Stripper Reflux Drum where the vapor and liquid are separated. The uncondensed CO 2 

### -rich gas is then delivered to the CO 2 

### product compressor. The condensed liquid from the Solvent Stripper Reflux Drum is pumped via the Solvent Stripper Reflux Pumps where a portion of condensed overhead liquid is used as make- up water for the Water Wash section of the CO 2 

### Absorber. The rest of the pumped liquid is routed back to the Solvent Stripper as reflux, which aids in limiting the amount of solvent va pors entering the stripp er overhead system.
Solvent Stripper Reclaimer A small slipstream of the lean solvent from th e Solvent Stripper bottoms is fed to the Solvent Stripper Reclaimer for the removal of high-boi ling nonvolatile impurities (heat stable salts - HSS), volatile acids and iron products from the circulating solvent so lution. The solvent bound in the HSS is recovered by reacti on with caustic and heating with steam. The solvent reclaimer system reduces corrosion, foaming and fouling in the solvent system. The reclaimed solvent is returned to the Solvent Stripper and the spent solvent is pumped via the Solvent Reclaimer Drain Pump to the Solvent Reclaimer Drain Tank.
Steam Condensate Steam condensate from the Solvent Stripper Re claimer accumulates in the Solvent Reclaimer Condensate Drum and is level controlled to the Solvent Reboiler Condensate Drum. Steam condensate from the Solvent Stripper Reboilers is also collected in the Solvent Reboiler Condensate Drum and returned to the the steam cycle between boiler feed water heaters 4 and 5 via the Solvent Reboiler Condensate Pumps.Cost and Performance Comparison of Fossil Energy Power Plants

317 

### Corrosion Inhibitor System A proprietary corrosion inhibitor is continuously inject ed into the CO 2 

### Absorber rich solvent bottoms outlet line, the Solvent Stripper bottoms outlet line and the Solvent Stripper top tray. This constant injection is to help co ntrol the rate of corrosion throughout the CO 2 

### recovery plant system.
Gas Compression and Drying System In the compression section, the CO 2 

### is compressed to 15.3 MPa (2,215 psia) by a six-stage centrifugal compressor. The discharge pressures of the stages were balanced to give reasonable power distribution and discharge temperatures across the various stages as shown in Exhibit 4-2.

Exhibit 4-2 CO 2 

### Compressor Interstage Pressures

Stage Outlet Pressure, MPa (psia)
1 0.36 (52)
2 0.78 (113)
3 1.71 (248)
4 3.76 (545)
5 8.27 (1,200)
6 15.3 (2,215)

Power consumption for this large compressor was estimated assuming an isentropic efficiency of 84 percent. During compression to 15.3 MPa (2 ,215 psia) in the multiple-stage, intercooled compressor, the CO 2 

### stream is dehydrated to a dewpoint of - 40oC (-40°F) with trie thylene glycol. The virtually moisture-free supercritical CO 2 

### stream is delivered to the plant battery limit as sequestration ready. CO 2 

### TS&M costs were estimated and included in LCOE using the methodology described in Section 2.7.

4.1.8 P OWER 

### G ENERATION 

### The steam turbine is designed for long-term opera tion (90 days or more) at MCR with throttle control valves 95 percent open. It is also capable of a short- term 5 percent OP/VWO condition (16 hours). For the subcritical cases, the steam turbine is a tandem compound type, consisting of HP-IP-two LP (double flow) sections enclosed in three casings, designed for condensing single reheat operation, and equipped with non-automatic extrac tions and four-flow exhaust. The turbine drives a hydrogen-cooled generator. The turb ine has DC motor-operated lube oil pumps, and main lube oil pumps, which are driven off the turbine shaft [ 61 

### ]. The exhaust pressure is 50.8 cmCost and Performance Comparison of Fossil Energy Power Plants

318 

### (2 in) Hg in the single pressure condenser. There are seven extr action points. The condenser is two-shell, transverse, single pressure with divided waterbox for each shell. The steam-turbine generator systems for the supe rcritical plants are similar in design to the subcritical systems. The differences include st eam cycle conditions and eight extractions points versus seven for the subcritical design. Turbine bearings are lubricated by a closed-loop, water-cooled pressurized oil system. Turbine shafts are sealed against air in-leakage or st eam blowout using a labyr inth gland arrangement connected to a low-pressure steam seal system. The generator stator is cooled with a closed-loop water system consisting of circulating pumps, shell and tube or plat e and frame type heat exchangers, filters, and deionizers, all skid-mount ed. The generator rotor is cooled with a hydrogen gas recirculation system using fans mounted on the generator rotor shaft. Operation Description - The turbine stop valves, contro l valves, reheat stop valves, and intercept valves are controlled by an electro-hyd raulic control system. Main steam from the boiler passes through the stop valves and contro l valves and enters the turbine at 16.5 MPa/566°C (2400 psig/1050oF) for the subcritica l cases and 24.1MPa /593°C (3500psig/1100°F)for the supercritical cases. The steam initially enters the turbine near the middle of the highpressure span, flows through the turbine, and retu rns to the boiler for reheating. The reheat steam flows through the reheat st op valves and intercept valves and enters the IP section at 566°C (1050oF) in the subcritical cases and 593°C (1100°F) in the supercritical cases. After passing through the IP sec tion, the steam enters a crossover pi pe, which transports the steam to the two LP sections. The steam divides into four paths and flows through the LP sections exhausting downward into the condenser. The turbine is designed to opera te at constant inlet steam pre ssure over the enti re load range.

4.1.9 B ALANCE OF 

### P LANT 

### The balance of plant components co nsist of the condensate, feedwa ter, main and reheat steam, extraction steam, ash handling, ducting and stack, wa ste treatment and miscellaneous systems as described below.
Condensate The function of the condensate sy stem is to pump condensate from the condenser hotwell to the deaerator, through the gland steam condenser and the LP feedwater heaters. Each system consists of one main condenser; two variable speed electric motor-dri ven vertical condensate pumps each sized for 50 percent capacity; one gla nd steam condenser; four LP heaters; and one deaerator with storage tank. Condensate is delivered to a common discharg e header through two separate pump discharge lines, each with a check valve a nd a gate valve. A common mini mum flow recirculation line discharging to the condenser is provided downstream of the gla nd steam condenser to maintain minimum flow requirements for the gland steam condenser and the condensate pumps. LP feedwater heaters 1 through 4 are 50 percent capacity, parallel flow, and are located in the condenser neck. All remaining feedwater heater s are 100 percent capacity shell and U-tube heat exchangers. Each LP feedwater heater is provi ded with inlet/outlet isolation valves and a full capacity bypass. LP feedwater heater drains casc ade down to the next lowest extraction pressure heater and finally discharge into the condenser. Pneumatic level control valves control normalCost and Performance Comparison of Fossil Energy Power Plants

319 

### drain levels in the heaters. High heater le vel dump lines dischargi ng to the condenser are provided for each heater for turbine water induct ion protection. Pneumatic level control valves control dump line flow.
Feedwater The function of the feedwater system is to pum p the feedwater from the deaerator storage tank through the HP feedwater heaters to the economizer. One turbin e-driven boiler feedwater pump sized at 100 percent capacity is provided to pum p feedwater through the HP feedwater heaters. One 25 percent motor-driven boiler feedwater pu mp is provided for startup. The pumps are provided with inlet and outlet isolation valves, an d individual minimum fl ow recirculation lines discharging back to the deaerator storage tank. The recirculation flow is controlled by automatic recirculation valves, which are a combination ch eck valve in the main line and in the bypass, bypass control valve, and flow sensing element. The suction of the boiler feed pump is equipped with startup strainers, which ar e utilized during initial start up and following major outages or system maintenance. Each HP feedwater heater is provided with inlet/outlet isolation valves and a full capacity bypass. Feedwater heater drains cascade down to the next lowest extracti on pressure heater and finally discharge into the deaerator. Pneumatic le vel control valves control normal drain level in the heaters. High heater leve l dump lines discharging to the condenser are provided for each heater for turbine water induction protection. Du mp line flow is controlled by pneumatic level control valves. The deaerator is a horizontal, spra y tray type with internal dir ect contact stainless steel vent condenser and storage tank. The boiler feed pum p turbine is driven by main steam up to 60 percent plant load. Above 60 percent load, extraction from the IP turbine exhaust (1.05 MPa/395°C [153 psig/743°F]) provides steam to the boiler feed pump steam turbine.
Main and Reheat Steam The function of the main steam system is to convey main steam from the boiler superheater outlet to the HP turbine stop valv es. The function of the reheat system is to convey steam from the HP turbine exhaust to the boiler reheater and from the boiler reheater outlet to the IP turbine stop valves.
Main steam exits the boiler s uperheater through a motor-operate d stop/check valve and a motoroperated gate valve and is routed in a single line feeding the HP turbine. A branch line off the IP turbine exhaust feeds the boiler feed water pump turbine during unit operation starting at approximately 60 percent load. Cold reheat steam exits the HP turbine, flows through a motor-operated is olation gate valve and a flow control valve, and enters the boiler reheater. Hot reheat steam exits the boiler reheater through a motor-operated gate valve and is routed to the IP turbine. A branch connection from the cold reheat piping supplies st eam to feedwater heater 7.Cost and Performance Comparison of Fossil Energy Power Plants

320 

### Extraction Steam
The function of the extr action steam system is to convey st eam from turbine extraction points through the following routes:
3⁄4 From HP turbine exhaust (cold reheat) to heater 7
3⁄4 From IP turbine extraction to heat er 6 and the deaerator (heater 5)
3⁄4 From LP turbine extraction to heaters 1, 2, 3, and 4 The turbine is protected from ove rspeed on turbine trip, from flas h steam reverse flow from the heaters through the extraction piping to the turbine. This protection is provided by positive closing, balanced disc non-return valves located in all extraction lin es except the lines to the LP feedwater heaters in the condens er neck. The extrac tion non-return valves are located only in horizontal runs of piping and as cl ose to the turbine as possible. The turbine trip signal automati cally trips the non -return valves through relay dumps. The remote manual control for each he ater level control system is used to release the non-return valves to normal check valve service when required to restart the system. Circulating Water System It is assumed that the plant is serviced by a public water facility a nd has access to groundwater for use as makeup cooling water with minimal pret reatment. All filtration and treatment of the circulating water are conducted on site. A mechan ical draft, wood frame, counter-flow cooling tower is provided for the circulating water he at sink. Two 50 percent circulating water pumps are provided. The circulating water system provides cooling water to the condenser, the auxiliary cooling water system, and the CDR facility in capture cases. The auxiliary cooling water system is a closed-l oop system. Plate and frame heat exchangers with circulating water as the c ooling medium are provided. This system provides cooling water to the lube oil coolers, turbine generator, boile r feed pumps, etc. All pumps, vacuum breakers, air release valves, instruments, controls, etc. are included for a complete operable system. The CDR system in Cases 10 and 12 requires a su bstantial amount of c ooling water that is provided by the PC plant circulat ing water system. The additiona l cooling load imposed by the CDR is reflected in the significan tly larger circulating water pu mps and cooling tower in those

cases. Ash Handling System The function of the ash handling system is to provide the equipment required for conveying, preparing, storing, and disposing of the fly as h and bottom ash produced on a daily basis by the boiler. The scope of the syst em is from the baghouse hoppers, air heater and economizer hopper collectors, and bottom ash hoppers to the hydrobins (for bottom ash) and truck filling stations (for fly ash). The system is designed to s upport short-term operation at the 5 percent OP/VWO condition (16 hours) and long-term operation at the 100 percent guarantee point (90 days or more). The fly ash collected in the baghouse and the air h eaters is conveyed to the fly ash storage silo. A pneumatic transport system using low-pressure air from a blower pr ovides the transport mechanism for the fly ash. Fly ash is discharg ed through a wet unloader, which conditions the fly ash and conveys it through a telescopic unl oading chute into a truck for disposal.Cost and Performance Comparison of Fossil Energy Power Plants

321 

### The bottom ash from the boiler is fed into a clinke r grinder. The clinker grinder is provided to break up any clinkers that may form. From the clinker grinders the bottom ash is sluiced to hydrobins for dewatering and offsite removal by truck. Ash from the economizer hoppers and pyrites (reject ed from the coal pulverizers) is conveyed using water to the economizer/pyrit es transfer tank. This material is then sluiced on a periodic basis to the hydrobins. Ducting and Stack One stack is provided with a single fiberglass -reinforced plastic (FRP ) liner. The stack is constructed of reinforced concrete. The stack is 152 m (500 ft) high fo r adequate particulate dispersion. Waste Treatment/Miscellaneous Systems An onsite water treatment facility treats all r unoff, cleaning wastes, blowdown, and backwash to within the U.S. EPA standards for suspended solids, oil and grease, pH, and miscellaneous metals. Waste treatment equipment is housed in a separate building. The waste treatment system consists of a water collection basin, three raw waste pumps, an acid neutralization system, an oxidation system, flocculation, clarif ication/thickening, and sludge dewatering. The water collection basin is a s ynthetic-membrane-lined earthen basin, which collects rainfall runoff, maintenance cleaning wa stes, and backwash flows. The raw waste is pumped to the treatment system at a controlled rate by the raw waste pumps. The neutralization system neutra lizes the acidic wastewater w ith hydrated lime in a two-stage system, consisting of a lime storage silo/lime slur ry makeup system, dry lime feeder, lime slurry tank, slurry tank mixer, and lime slurry feed pumps. The oxidation system consists of an air compress or, which injects air thro ugh a sparger pipe into the second-stage neutralization tank. The flocculation tank is fi berglass with a variable speed agitator. A polymer dilution and feed system is al so provided for floccula tion. The clarifier is a plate-type, with the sludge pumped to the dewate ring system. The sludge is dewatered in filter presses and disposed offsite. Trucking and disposal costs are included in the cost estimate. The filtrate from the sludge dewatering is returned to the raw waste sump. Miscellaneous systems consisting of fuel oil, serv ice air, instrument air, and service water are provided. A storage tank provide s a supply of No. 2 fuel oil us ed for startup and for a small auxiliary boiler. Fuel oil is de livered by truck. All truck roadwa ys and unloading stations inside the fence area are provided.Cost and Performance Comparison of Fossil Energy Power Plants

322 

### Buildings and Structures Foundations are provided for the support structures, pumps, tanks, and other plant components. The following buildings are in cluded in the design basis:

3⁄4 Steam turbine building 3⁄4 Fuel oil pump house 3⁄4 Guard house

3⁄4 Boiler building 3⁄4 Coal crusher building 3⁄4 Runoff water pump house

3⁄4 Administration and service building 3⁄4 Continuous emissions monitoring building 3⁄4 Industrial waste treatment building

3⁄4 Makeup water and pretreatment building 3⁄4 Pump house and electrical equipment building 3⁄4 FGD system buildings

4.1.10 A CCESSORY 

### E LECTRIC 

### P LANT 

### The accessory electric plant consists of switchgear and control equipment, generator equipment, station service equipment, conduit and cable trays, and wire and cab le. It also includes the main power transformer, required foundations, and standby equipment.

4.1.11 I NSTRUMENTATION AND 

### C ONTROL 

### An integrated plant-wide control and monito ring DCS is provided. The DCS is a redundant microprocessor-based, functionally distributed system. The control room houses an array of multiple video monitor and keyboard units. Th e monitor/keyboard units are the primary interface between the generating process and opera tions personnel. The DCS incorporates plant monitoring and control functions for all the major plant equipment. The DCS is designed to provide 99.5 percent availability. The plant e quipment and the DCS are designed for automatic response to load changes from minimum load to 100 percent. Startup a nd shutdown routines are implemented as supervised manual, with opera tor selection of modular automation routines available.Cost and Performance Comparison of Fossil Energy Power Plants

323 

### 4.2 SUBCRITICAL PC CASES
This section contains an eval ution of plant designs for Case s 9 and 10 which are based on a subcritical PC plant with a nomin al net output of 550 MWe. Both plants use a single reheat 16.5 MPa/566°C/566°C (2400 psig/1050 ° F/1050 ° F) cycle. The only difference between the two plants is that Case 10 includes CO 2 

### capture while Case 9 does not.
The balance of Section 4.2 is organized as follows:

• Process and System Description provides an overview of the technology operation as applied to Case 9. The systems that are comm on to all PC cases were covered in Section 4.1 and only features that are unique to Case 9 are discus sed further in this section.

• Key Assumptions is a summary of study and modeling assumptions re levant to Cases 9 and 10.

• Sparing Philosophy is provided for both Cases 9 and 10.

• Performance Results provides the main m odeling results from Case 9, including the performance summary, environmental performance, water balance, mass and energy balance diagrams and energy balance table.

• Equipment List provides an itemized list of major equipment for Case 9 with account codes that correspond to the cost acc ounts in the Cost Estimates section.

• Cost Estimates provides a summary of capital and operating costs for Case 9.

• Process and System Description, Perform ance Results, Equipment List and Cost Estimates are discussed for Case 10.

4.2.1 P ROCESS 

### D ESCRIPTION 

### In this section the subcri tical PC process without CO 2 

### capture is described. The system description follows the block flow diagram (BFD) in Exhibit 4-3 and stream numbers reference the same Exhibit. The tables in Exhibit 4-4 provide process data for the numbered streams in the BFD. Coal (stream 6) and primary air (stream 4) ar e introduced into the bo iler through the wall-fired burners. Additional combustion air, including the overfire air, is provided by the forced draft fans (stream 2). The boiler operate s at a slight negative pressure so air leakage is into the boiler, and the infiltration air is accounted for in stream 5. Flue gas exits the boiler through the SCR reactor (stream 8) and is cooled to 177°C (350°F) in the combustion air preheater (not shown) before passing through a fabric filter for particulate removal (stream 10). An ID fan increases th e flue gas temperature to 188°C (370°F) and provides the motive force for the flue gas (stream11) to pass through the FGD unit. FGD inputs and outputs include makeup water (stream 13), oxidation air (stream 14), limestone slurry (stream 12) and product gypsum (stream 15). The clean, saturated flue gas exiting the FGD unit (stream 16) passes to the plant stack and is discharged to atmosphere.Cost and Performance Comparisonof Fossil Energy Power Plants324Exhibit 4-3 Case 9 Process FlowDiagram, Subcritical Unit without CO2CaptureCost and Performance Comparison of Fossil Energy Power Plants

325 

### Exhibit 4-4 Case 9 Stream Table, Subcritical Unit without CO 2 

### Capture

1 2 3 4 56 7 8 V-L Mole Fraction Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 CO 2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 N 2 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 O 2 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 V-L Flow (lb mol /hr) 114,117 114,117 35,055 35,055 2,636 0 0 160,576

V-L Flow (lb/hr) 3,293,060 3,293,060 1,011,590 1,011,590 76,071 0 0 4,775,980 Solids Flowrate 0 0 0 0 0 437,699 8,489 33,954 Temperature (°F) 59 66 59 78 59 78 350 350

Pressure (psia) 14.70 15.25 14.70 16.14 14.70 14.70 14.40 14.40 Enthalpy (BTU/lb) A 13.1 14.9 13.1 17.7 13.1 11,676 51.4 135.7

Density (lb/ft 3 ) 0.08 0.08 0.08 0.08 0.08 -- -- 0.05 Avg. Molecular Weight 28.86 28.86 28.86 28.86 28.86 -- -- 29.74

9 10 11 12 13 14 15 16 V-L Mole Fraction Ar 0.0000 0.0087 0.0087 0.0000 0.0000 0.0092 0.0000 0.0079 CO 2 0.0000 0.1450 0.1450 0.0000 0.0000 0.0003 0.0014 0.1317 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0000 0.0870 0.0870 1.0000 1.0000 0.0099 0.9978 0.1725 N 2 0.0000 0.7324 0.7324 0.0000 0.0000 0.7732 0.0007 0.6644 O 2 0.0000 0.0247 0.0247 0.0000 0.0000 0.2074 0.0000 0.0234 SO 2 0.0000 0.0021 0.0021 0.0000 0.0000 0.0000 0.0000 0.0000 Total 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flow (lb mol /hr) 0 160,576 160,576 5,701 26,948 1,901 15,077 179,211

V-L Flow (lb/hr) 0 4,775,980 4,775,980 102,702 485,483 54,846 272,302 5,122,540 Solids Flowrate 33,954 0 0 43,585 0 0 67,754 0

Temperature (°F) 350 350 370 59 59 59 135 135

Pressure (psia) 14.20 14.20 15.26 14.70 14.70 14.70 14.70 14.70 Enthalpy (BTU/lb) A 51.4 136.3 141.5 -- 32.4 13.1 88.0 139.1

Density (lb/ft 3 ) -- 0.05 0.05 62.62 62.62 0.08 39.65 0.07 Avg. Molecular Weight -- 29.74 29.74 18.02 18.02 28.86 18.06 28.58 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparison of Fossil Energy Power Plants

326 

### 4.2.2 K EY 

### S YSTEM 

### A SSUMPTIONS 

### System assumptions for Cases 9 and 10, subcritical PC w ith and without CO 2 

### capture, are compiled in Exhibit 4-5.
Exhibit 4-5 Subcritical PC Plan t Study Configuration Matrix

Case 9 w/o CO 2 

### Capture Case 10 w/CO 2 

### Capture
Steam Cycle, MPa/°C/°C (psig/°F/°F) 16.5/566/566 (2400/1050/1050) 16.5/566/566 (2400/1050/1050) Coal Illinois No. 6 Illinois No. 6 Condenser pressure, mm Hg (in Hg) 50.8 (2) 50.8 (2) Boiler Efficiency, % 89 89 Cooling water to condenser, °C (oF) 16 (60) 16 (60) Cooling water from condenser, °C (oF) 27 (80) 27 (80) Stack temperature, °C (°F) 57 (135) 32 (89)

SO 2 

### Control Wet Limestone Forced Oxidation Wet Limestone Forced Oxidation FGD Efficiency, % (A) 98 98 (B, C)

NOx Control LNB w/OFA and SCR LNB w/OFA and SCR SCR Efficiency, % (A) 86 86 Ammonia Slip (end of catalyst life), ppmv 2 2

Particulate Control Fabric Filter Fabric Filter Fabric Filter efficiency, % (A) 99.8 99.8 Ash Distribution, Fly/Bottom 80% / 20% 80% / 20% Mercury Control Co-benefit Capture Co-benefit Capture Mercury removal efficiency, % (A) 90 90 CO 2 

### Control N/A Econamine FG Plus CO 2 

### Capture, % (A) N/A 90

CO 2 

### Sequestration N/A Off-site Saline Formation A. Removal efficiencies are based on the flue gas content B. An SO 2 

### polishing step is included to meet mo re stringent SOx content limits in the flue gas (< 10 ppmv) to reduce forma tion of amine heat stable salts during the CO 2 

### absorption process C. SO 2 

### exiting the post-FGD polishing step is absorbed in the CO 2 

### capture process making stack emissions negligibleCost and Performance Comparison of Fossil Energy Power Plants

327 

### Balance of Plant – Cases 9 and 10 The balance of plant assumptions are co mmon to all cases and are presented in Exhibit 4-6.
Exhibit 4-6 Balance of Plant Assumptions Cooling system Recirculating Wet Cooling Tower Fuel and Other storage Coal 30 days Ash 30 days Gypsum 30 days Limestone 30 days Plant Distribution Voltage Motors below 1 hp 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 and Gas Turbine generators 24,000 volt

Grid Interconnection voltage 345 kV Water and Waste Water Makeup Water The water supply is 50 percen t from a local Publicly Owned Treatment Works (POTW) and 50 percent from groundwater, and is assumed to be in sufficient quantities to meet plant makeup requirements. Makeup for potable, process, and de-ionized (DI) water is drawn from municipal sources. Process Wastewater 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 is sized for 5.68 cubic meters per day (1,500 gallons per day) Water Discharge Most of the proce ss wastewater is recycled to the cooling tower basin. Blowdown will be treated for chloride and metals, and discharged.Cost and Performance Comparison of Fossil Energy Power Plants

328 

### 4.2.3 S PARING 

### P HILOSOPHY 

### Single trains are used throughout the design with exceptions wher e equipment capacity requires an additional train. There is no redundancy othe r than normal sparing of rotating equipment. The plant design consists of the following major subsystems:

• One dry-bottom, wall-fired PC subcritical boiler (1 x 100%)

• Two SCR reactors (2 x 50%)

• Two single-stage, in-line, multi-comp artment fabric filters (2 x 50%)

• One wet limestone forced oxidation pos itive pressure absorber (1 x 100%)

• One steam turbine (1 x 100%)

• For Case 10 only, two parallel Econamine FG Plus CO 2 

### absorption systems, with each system consisting of two absorbers, stri ppers and ancillary equipment (2 x 50%)

4.2.4 C ASE 

### 9 P ERFORMANCE 

### R ESULTS 

### The plant produces a net output of 550 MWe at a net plant efficiency of 36.8 percent (HHV basis). Overall performance for the plant is summarized in Exhibit 4-7 which includes auxiliary power requirements.Cost and Performance Comparison of Fossil Energy Power Plants

329 

### Exhibit 4-7 Case 9 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) TOTAL (STEAM TURBINE) POWER, kWe 583,315 AUXILIARY LOAD SUMMARY, kWe (Note 1) Coal Handling and Conveying 420 Limestone Handling & Reagent Preparation 950 Pulverizers 2,980 Ash Handling 570 Primary Air Fans 1,390 Forced Draft Fans 1,770 Induced Draft Fans 7,590 SCR 60 Baghouse 100 FGD Pumps and Agitators 3,170 Amine System Auxiliaries N/A CO 2 

### Compression N/A Condensate Pumps 1,390 Miscellaneous Balance of Plant (Note 2) 2,000 Steam Turbine Auxiliaries 400 Circulating Water Pumps 5,440 Cooling Tower Fans 2,810 Transformer Loss 1,830 TOTAL AUXILIARIES, kWe 32,870 NET POWER, kWe 550,445 Net Plant Efficiency (HHV) 36.8% Net Plant Heat Rate (Btu/kWh) 9,276 CONDENSER COOLING DUTY 10 6 

### kJ/h (10 6 

### Btu/h) 2,656 (2,520) CONSUMABLES As-Received Coal Feed, kg/h (lb/h) 198,537 (437,699) Limestone Sorbent Feed, kg/h (lb/h) 19,770 (43,585) Thermal Input, kWt 1,496,479 Makeup water, m 3 

### /min (gpm) 23.5 (6,212) Notes: 1. Boiler feed pump s are steam turbine driven 2. Includes plant control systems, li ghting, HVAC and miscellanous low voltage loadsCost and Performance Comparison of Fossil Energy Power Plants

330 

### Environmental Performance The environmental targets for emissions of Hg, NOx, SO 2 

### and particulate matter were presented in Section 2.4. A summary of the plant ai r emissions for Case 9 is presented in Exhibit 4-8.

Exhibit 4-8 Case 9 Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)

SO 2 

### 0.037 (0.085) 1,463 (1,613) 0.337 (0.743) NO X 

### 0.030 (0.070) 1,331 (1,207) 0.278 (0.613) Particulates 0.006 (0.013) 224 (247) 0.052 (0.114)
Hg 0.49 x 10 -6 

### (1.14 x 10 -6 

### ) 0.020 (0.022) 4.5 x 10 -6 

### (10.0 x 10 -6 

### )

CO 2 

### 87.5 (203) 3,506,000 (3,865,000) 807 (1,780)

CO 2 1 

### 855 (1,886)

1 

### CO 2 

### emissions based on net power instead of gross power

SO 2 

### emissions are controlled using a wet limestone forced oxidation scrubber that achieves a removal efficiency of 98 percent. The byproduct cal cium sulfate is dewatered and stored on site. The wallboard grade material can potentially be marketed and sold, but since it is highly dependent on local market conditions, no byproduct credit was taken. The saturated flue gas exiting the scrubber is vent ed through the plant stack.
NOx emissions are controlled to about 0.5 lb/10 6 

### Btu through the use of LNBs and OFA. An SCR unit then further reduces the NOx c oncentration by 86 per cent to 0.07 lb/10 6 

### Btu.
Particulate emissions are controlled using a pulse jet fabric filter wh ich operates at an efficiency of 99.8 percent. Co-benefit capture results in a 90 per cent reduction of mercury emissions. CO 2 

### emissions represent the uncontro lled discharge from the process.
Exhibit 4-9 shows the overall water balance fo r the plant. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent) . The water usage represents only the contribution of raw water makeup. In so me cases the water demand is greater than raw water makeup because of internal water recycle streams. For example, the boiler feedwater blowdown stream is re-used as makeup to the cooling tower, thus reducing the raw water requirement by that amount.Cost and Performance Comparison of Fossil Energy Power Plants

331 

### Exhibit 4-9 Case 9 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle,

m 3 

### /min (gpm) Raw Water Makeup,

m 3 

### /min (gpm)
FGD Makeup 2.4 (625) 0 2.4 (625)
BFW Makeup 0.3 (74) 0 0.3 (74)
Cooling Tower Makeup 21.2 (5,587) 0.3 (74) 20.9 (5,513)
Total 23.9 (6,286) 0.3 (74) 23.6 (6,212)

Heat and Mass Balance Diagrams A heat and mass balance diagram is shown for the Case 9 PC boiler, the FGD unit and steam cycle in Exhibit 4-10. An overall plant energy balance is provided in tabular form in Exhibit 4-11. The power out is the steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 4-7) is calculated by multiplying th e power out by a generator efficiency of 98.6 percent.Cost and Performance Comparison of Fossil Energy Power Plants

332 

### This page intentionally left blankCost and Performance Comparisonof Fossil Energy Power Plants333Exhibit 4-10 Case 9 Heat and Mass Balance, Subcritical PC Boiler without CO2CaptureCost and Performance Comparisonof Fossil Energy Power Plants334This page intentionally left blankCost and Performance Comparison of Fossil Energy Power Plants

335 

### Exhibit 4-11 Case 9 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total
Heat In (MMBtu/hr) Coal 5,106.2 4.3 5,110.5 Ambient Air 56.5 56.5 Infiltration Air 1.0 1.0 Limestone 64.8 64.8 FGD Oxidant 0.7 0.7 Water 19.0 19.0 Auxiliary Power 112.2 112.2 Totals 5,106.2 146.4 112.2 5,364.7 Heat Out (MMBtu/hr) Bottom Ash 0.4 0.4 Fly Ash 1.7 1.7 Flue Gas Exhaust 712.5 712.5 Gypsum Slurry 29.9 29.9 Condenser 2,520.0 2,520.0 Process Losses (1) 80.5 80.5 Power 2,019.6 2,019.6 Totals 0.0 3,345.1 2,019.6 5,364.7 (1) Process Losses are calculated by difference a nd reflect various boiler, turbine, and other heat and work losses. Aspen flowsh eet balance is within 0.5 percent.Cost and Performance Comparison of Fossil Energy Power Plants

336 

### 4.2.5 C ASE 

### 9

– M AJOR 

### E QUIPMENT 

### L IST 

### Major equipment items for the s ubcritical PC plant with no CO 2 

### capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 4.2.6. In general, the design c onditions include a 10 percent contingency for flows and heat duties and a 21 pe rcent contingency for heads on pumps and fans.
ACCOUNT 1 COAL AND SORBENT HANDLING

Equipment No. Description Type Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0 3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0 5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling System Two-stage 1 0
7 Stacker/Reclaimer Traveling, linear 1 0 8 Reclaim Hopper N/A 2 1 9 Feeder Vibratory 2 1 10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0 12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor reduction 2 0

14 As-Fired Coal Sampling System Swing hammer 1 1
15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0
17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 3 0

19 Limestone Truck Unloading Hopper N/A 1 0

20 Limestone Feeder Belt 1 0
21 Limestone Conveyor No. L1 Belt 1 0
22 Limestone Reclaim Hopper N/A 1 0

23 Limestone Reclaim Feeder Belt 1 0 24 Limestone Conveyor No. L2 Belt 1 0 25 Limestone Day Bin w/ actuator 2 0 36 tonne (40 ton)

82 tonne/h (90 tph)
82 tonne/h (90 tph)

263 tonne (290 ton)

18 tonne (20 ton) 64 tonne/h (70 tph) 64 tonne/h (70 tph) 726 tonne (800 ton) N/A
327 tonne/h (360 tph)

N/A 45 tonne (50 ton) 163 tonne/h (180 tph)

8 cm x 0 - 3 cm x 0 (3" x 0 - 1-1/4" x 0) 327 tonne/h (360 tph)

163 tonne (180 ton) N/A

327 tonne/h (360 tph)

Design Condition

181 tonne (200 ton)

N/A
1,134 tonne/h (1,250 tph) N/A 1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph) 1,134 tonne/h (1,250 tph)Cost and Performance Comparison of Fossil Energy Power Plants

337 

### ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED
Equipment No. Description Type Operating Qty. Spares

1 Coal Feeder Gravimetric 6 0

2 Coal Pulverizer Ball type or equivalent 6 0

3 Limestone Weigh Feeder Gravimetric 1 1
4 Limestone Ball Mill Rotary 1 1

5 Limestone Mill Slurry Tank with Agitator N/A 1 1

6 Limestone Mill Recycle Pumps Horizontal centrifugal 1 1

7 Hydroclone Classifier 4 active cyclones in a 5 cyclone bank 1 1

8 Distribution Box 2-way 1 1

9 Limestone Slurry Storage Tank with Agitator Field erected 1 1

10 Limestone Slurry Feed Pumps Horizontal centrifugal 1 1 469,395 liters (124,000 gal) 336 lpm @ 12 m H2O (370 gpm @ 40 ft H2O)

N/A

236 lpm @ 9 m H2O (260 gpm @ 30 ft H2O) 82 lpm (90 gpm) per cyclone

83,280 liters (22,000 gal) Design Condition

36 tonne/h (40 tph)

36 tonne/h (40 tph)

22 tonne/h (24 tph) 22 tonne/h (24 tph)Cost and Performance Comparison of Fossil Energy Power Plants

338 

### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 2 0

2 Condensate Pumps Vertical canned 1 1

3 Deaerator and Storage Tank Horizontal spray type 1 0

4 Boiler Feed Pump and Steam Turbine Drive Barrel type, multistage, centrifugal 1 1

6 LP Feedwater Heater 1A/1B Horizontal U-tube 2 0

7 LP Feedwater Heater 2A/2B Horizontal U-tube 2 0

8 LP Feedwater Heater 3A/3B Horizontal U-tube 2 0

9 LP Feedwater Heater 4A/4B Horizontal U-tube 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 1 0

11 HP Feedwater Heater 7 Horizontal U-tube 1 0

12 Auxiliary Boiler Shop fabricated, water tube 1 0

13 Fuel Oil System No. 2 fuel oil for light off 1 0

14 Service Air Compressors Flooded Screw 2 1

15 Instrument Air Dryers Duplex, regenerative 2 1

16 Closed Cycle Cooling Heat Exchangers Shell and tube 2 0

17 Closed Cycle Cooling Water Pumps Horizontal centrifugal 2 1

18 Engine-Driven Fire Pump Vertical turbine, diesel engine 1 1

19 Fire Service Booster Pump Two-stage horizontal centrifugal 1 1

20 Raw Water Pumps Stainless steel, single suction 2 1

21 Filtered Water Pumps Stainless steel, single suction 2 1

22 Filtered Water Tank Vertical, cylindrical 1 0

23 Makeup Water Demineralizer Multi-media filter, cartridge filter, RO membrane assembly, electrodeionization unit 1 1

24 Liquid Waste Treatment System -- 1 0 Design Condition

1,112,920 liters (294,000 gal)

25,741 lpm @ 335 m H2O (6,800 gpm @ 1,100 ft H2O) 1,852,020 kg/h (4,083,000 lb/h) 5 min. tank 31,041 lpm @ 2,499 m H2O (8,200 gpm @ 8,200 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C (40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 762,036 kg/h (1,680,000 lb/h)

762,036 kg/h (1,680,000 lb/h)

762,036 kg/h (1,680,000 lb/h)

762,036 kg/h (1,680,000 lb/h)

1,850,659 kg/h (4,080,000 lb/h)
1,850,659 kg/h (4,080,000 lb/h)

1,135,632 liter (300,000 gal)

53 MMkJ/h (50 MMBtu/h) each
20,820 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O)

28 m3/min (1,000 scfm)

1,540,675 liter (407,000 gal)

606 lpm (160 gpm)

10 years, 24-hour storm 0 5 Startup Boiler Feed Pump, Electric Motor Driven Barrel type, multistage, centrifugal 9,085 lpm @ 2,499 m H2O (2,400 gpm @ 8,200 ft H2O) 1

3,785 lpm @ 88 m H2O (1,000 gpm @ 290 ft H2O)

2,650 lpm @ 64 m H2O (700 gpm @ 210 ft H2O) 13,098 lpm @ 43 m H2O (3,460 gpm @ 140 ft H2O)

1,590 lpm @ 49 m H2O (420 gpm @ 160 ft H2O)Cost and Performance Comparison of Fossil Energy Power Plants

339 

### ACCOUNT 4 BOILER AND ACCESSORIES
Equipment No. Description Type Operatin g Qty. Spares

1 Boiler Subcritical, drum wall-fired, low NOx burners, overfire air 1 0

2 Primary Air Fan Centrifugal 2 0

3 Forced Draft Fan Centrifugal 2 0

4 Induced Draft Fan Centrifugal 2 0

5 SCR Reactor Vessel Space for spare layer 2 0

6 SCR Catalyst -- 3 0

7 Dilution Air Blower Centrifugal 2 1

8 Ammonia Storage Horizontal tank 5 0

9 Ammonia Feed Pump Centrifugal 2 1 142 m3/min @ 108 cm WG (5,000 scfm @ 42 in. WG)
155,203 liter (41,000 gal)

30 lpm @ 91 m H2O (8 gpm @ 300 ft H2O) 1,191,589 kg/h, 25,301 m3/min @ 90 cm WG (2,627,000 lb/h, 893,500 acfm @ 36 in. WG)
2,381,363 kg/h (5,250,000 lb/h)

-- Design Condition

1,850,659 kg/h steam @ 16.5 MPa/566°C/566°C (4,080,000 lb/h steam @ 2,400 psig/1,050°F/1,050°F)

252,198 kg/h, 3,455 m3/min @

123 cm WG (556,000 lb/h, 122,000 acfm @ 48 in. WG)
821,457 kg/h, 11,248 m3/min @

47 cm WG (1,811,000 lb/h, 397,200 acfm @ 19 in. WG)Cost and Performance Comparison of Fossil Energy Power Plants

340 

### ACCOUNT 5 FLUE GAS CLEANUP
Equipment No. Description Type Operatin g Qty. Spares

1 Fabric Filter Single stage, highratio with pulsejet online cleaning system 2 0

2 Absorber Module Counter-current
open spray 1 0

3 Recirculation Pumps Horizontal centrifugal 5 1

4 Bleed Pumps Horizontal centrifugal 2 1

5 Oxidation Air Blowers Centrifugal 2 1

6 Agitators Side entering 5 1

7 Dewatering Cyclones Radial assembly, 5 units each 2 0

8 Vacuum Filter Belt Horizontal belt 2 1

9 Filtrate Water Return Pumps Horizontal centrifugal 1 1

10 Filtrate Water Return Storage Tank Vertical, lined 1 0

11 Process Makeup Water Pumps Horizontal centrifugal 1 1 187 m3/min @ 0.3 MPa (6,620 acfm @ 37 psia)

34 tonne/h (37 tph) of 50 wt % slurry 4,278 lpm (1,130 gpm) at 20 wt% solids

50 hp

1,060 lpm (280 gpm) per cyclone

644 lpm @ 12 m H2O (170 gpm @ 40 ft H2O)

416,399 lpm (110,000 gal)

2,612 lpm @ 21 m H2O (690 gpm @ 70 ft H2O) Design Condition

1,191,589 kg/h (2,627,000 lb/h) 99.8% efficiency

40,295 m3/min (1,423,000 acfm)

140,061 lpm @ 64 m H2O (37,000 gpm @ 210 ft H2O)



### ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES
N/A

ACCOUNT 7 HRSG, DUCTING & STACK

Equipment No. Description Type Operating Qty. Spares

1 Stack Reinforced concrete with FRP liner 1 0 Design Condition

152 m (500 ft) high x 5.8 m (19 ft) diameterCost and Performance Comparison of Fossil Energy Power Plants

341 

### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitation 1 0

3 Surface Condenser Single pass, divided waterbox including
vacuum pumps 1 0 610 MW 16.5 MPa/566°C/566°C (2400 psig/ 1050°F/1050°F)

2,920 MMkJ/h (2,770 MMBtu/h), Inlet water temperature 16oC (60oF),

Water temperature rise 11oC (20oF) 680 MVA @ 0.9 p.f., 24 kV, 60 Hz Design Condition



### ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 2 1

2 Cooling Tower Evaporative, mechanical draft, multi-cell 1 0 Design Condition

545,104 lpm @ 30.5 m (144,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT 3,036 MMkJ/h (2,880 MMBtu/h) heat loadCost and Performance Comparison of Fossil Energy Power Plants

342 

### ACCOUNT 10 ASH/SPENT SORBEN T RECOVERY AND HANDLING
Equipment No. Description Type Operating Qty. Spares

1 Economizer Hopper (part of boiler scope of supply) -- 4 0

2 Bottom Ash Hopper (part of boiler scope of supply) -- 2 0

3 Clinker Grinder -- 1 1

4 Pyrites Hopper (part of pulverizer scope of supply included with boiler) -- 6 0

5 Hydroejectors -- 12

6 Economizer /Pyrites Transfer Tank -- 1 0

7 Ash Sluice Pumps Vertical, wet pit 1 1

8 Ash Seal Water Pumps Vertical, wet pit 1 1

9 Hydrobins -- 1 1

10 Baghouse Hopper (part of baghouse scope of supply) -- 24 0

11 Air Heater Hopper (part of boiler scope of supply) -- 10 0

12 Air Blower -- 1 1

13 Fly Ash Silo Reinforced
concrete 2 0

14 Slide Gate Valves -- 2 0

15 Unloader -- 1 0

16 Telescoping Unloading Chute -- 1 0 151 lpm (40 gpm)

--

--

-- --

16 m3/min @ 0.2 MPa

(550 scfm @ 24 psi)

499 tonne (1,100 ton)

91 tonne/h (100 tph) --

--
151 lpm @ 17 m H2O (40 gpm @ 56 ft H2O)

7,571 lpm @ 9 m H2O (2000 gpm @ 28 ft H2O) -- Design Condition

--

--
4.5 tonne/h (5 tph)Cost and Performance Comparison of Fossil Energy Power Plants

343 

### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type Operating Qty. Spares

1 STG Transformer Oil-filled 1 0

2 Auxiliary Transformer Oil-filled 1 1

3 Low Voltage Transformer Dry ventilated 1 1

4 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 1 0

5 Medium Voltage Switchgear Metal clad 1 1

6 Low Voltage Switchgear Metal enclosed 1 1

7 Emergency Diesel Generator Sized for emergency shutdown 1 0 24 kV/4.16 kV, 35 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 5 MVA, 3-ph, 60 Hz Design Condition
24 kV/345 kV, 650 MVA, 3-ph, 60 Hz

750 kW, 480 V, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz



### ACCOUNT 12 INSTRUMENTATION AND CONTROL

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) 1 0

3 DCS - Data Highway Fiber optic 1 0 1 0

Fully redundant, 25% spare Design Condition

Operator stations/printers and engineering stations/printers

2 DCS - Processor Microprocessor with redundant input/output N/ACost and Performance Comparison of Fossil Energy Power Plants

344 

### 4.2.6 C ASE 

### 9

– C OST 

### E STIMATING 

### The cost estimating methodology was desc ribed previously in Section 2.6. Exhibit 4-12 shows the total plant capital cost summary organized by cost account and Exhibit 4-13 shows a more detailed breakdown of the capital costs. Exhibit 4-14 shows the ini tial and annual O&M costs.
The estimated TPC of the subc ritical PC boiler with no CO 2 

### capture is $1,548/kW. No process contingency is included in this case because a ll elements of the technology are commercially proven. The project contingency is 11.2 percen t of the TPC. The 20-year LCOE is 64.0 mills/kWhCost and Performance Comparisonof Fossil Energy Power Plants345Exhibit 4-12 Case 9 Total Plant Cost SummaryClient:USDOE/NETLReport Date:09-May-07Project:Bituminous Baseline StudyCase:Case 9 - Subcritical PC w/o CO2Plant Size:550.4 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING $16,102 $4,348 $9,748 $0 $0$30,198$2,706 $0 $4,936$37,840$692 COAL & SORBENT PREP & FEED $10,847 $629 $2,750 $0 $0$14,227$1,247 $0 $2,321$17,795$323 FEEDWATER & MISC. BOP SYSTEMS $37,503 $0 $18,011 $0 $0$55,514$5,071 $0 $9,963$70,548$1284 PC BOILER4.1 PC Boiler & Accessories $127,763 $0 $82,570 $0 $0$210,334$20,391 $0 $23,072$253,797$4614.2 SCR (w/4.1) $0 $0 $0 $0 $0$0$0 $0 $0$0$04.3 Open $0 $0 $0 $0 $0$0$0 $0 $0$0$04.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0$0$0 $0 $0$0$0SUBTOTAL 4 $127,763 $0 $82,570 $0 $0 $210,334 $20,391 $0 $23,072 $253,797 $4615 FLUE GAS CLEANUP $83,756 $0 $28,598 $0 $0$112,354$10,675 $0 $12,303$135,332$2466 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator N/A $0 N/A $0 $0$0$0 $0 $0$0$06.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0$0$0 $0 $0$0$0SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0$0$0 $0 $0$0$07.2-7.9 HRSG Accessories, Ductwork and Stack $17,476 $1,006 $11,965 $0 $0$30,447$2,787 $0 $4,336$37,570$68SUBTOTAL 7 $17,476 $1,006 $11,965 $0 $0 $30,447 $2,787 $0 $4,336 $37,570 $688 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $47,000 $0 $6,220 $0 $0$53,220$5,095 $0 $5,832$64,147$1178.2-8.9 Turbine Plant Auxiliaries and Steam Piping $22,612 $1,045$12,107 $0 $0$35,764$3,134 $0 $5,418$44,316$81SUBTOTAL 8 $69,612 $1,045 $18,328 $0 $0 $88,984 $8,230 $0 $11,249 $108,463 $1979 COOLING WATER SYSTEM $11,659 $6,571 $11,683 $0 $0$29,913$2,792 $0 $4,499$37,204$6810 ASH/SPENT SORBENT HANDLING SYS $4,383 $138 $5,829 $0 $0$10,350$985 $0 $1,166$12,502$2311 ACCESSORY ELECTRIC PLANT $15,802 $6,032 $17,773 $0 $0$39,607$3,506 $0 $5,366$48,479$8812 INSTRUMENTATION & CONTROL $8,006 $0 $8,413 $0 $0$16,419$1,503 $0 $2,204$20,126$3713 IMPROVEMENTS TO SITE $2,833 $1,629 $5,752 $0 $0$10,214$1,003 $0 $2,243$13,460$2414 BUILDINGS & STRUCTURES $0 $22,304 $21,358 $0 $0$43,662$3,934 $0 $11,899$59,495$108TOTAL COST $405,742 $43,703 $242,779 $0 $0 $692,224 $64,830 $0 $95,558 $852,612 $1,549TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants346Exhibit 4-13 Case 9 Total Plant Cost DetailsClient:USDOE/NETLReport Date:09-May-07Project:Bituminous Baseline StudyCase:Case 9 - Subcritical PC w/o CO2Plant Size:550.4 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING1.1 Coal Receive & Unload $3,308 $0 $1,527 $0 $0 $4,834 $432 $0 $790 $6,056 $111.2 Coal Stackout & Reclaim $4,275 $0 $979 $0 $0 $5,254 $460 $0 $857 $6,571 $121.3 Coal Conveyors $3,975 $0 $968 $0 $0 $4,943 $433 $0 $806 $6,183 $111.4 Other Coal Handling $1,040 $0 $224 $0 $0 $1,264 $110 $0 $206 $1,581 $31.5 Sorbent Receive & Unload $133 $0 $40 $0 $0 $173 $15 $0 $28 $217 $01.6 Sorbent Stackout & Reclaim $2,145 $0 $397 $0 $0 $2,542 $221 $0 $414 $3,177 $61.7 Sorbent Conveyors $765 $165 $190 $0 $0 $1,119 $97 $0 $182 $1,399 $31.8 Other Sorbent Handling $462 $108 $245 $0 $0 $815 $72 $0 $133 $1,020 $21.9 Coal & Sorbent Hnd.Foundations $0 $4,076 $5,178 $0 $0 $9,254 $865 $0 $1,518 $11,637 $21SUBTOTAL 1. $16,102 $4,348 $9,748 $0 $0 $30,198 $2,706 $0 $4,936 $37,840 $692 COAL & SORBENT PREP & FEED2.1 Coal Crushing & Drying $1,900 $0 $374 $0 $0 $2,274 $198 $0 $371 $2,843 $52.2 Coal Conveyor to Storage $4,864 $0 $1,073 $0 $0 $5,936 $519 $0 $968 $7,424 $132.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.5 Sorbent Prep Equipment $3,645 $156 $765 $0 $0 $4,566 $398 $0 $745 $5,708 $102.6 Sorbent Storage & Feed $439 $0 $170 $0 $0 $609 $54 $0 $99 $763 $12.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.9 Coal & Sorbent Feed Foundation $0 $473 $369 $0 $0 $842 $78 $0 $138 $1,057 $2SUBTOTAL 2. $10,847 $629 $2,750 $0 $0 $14,227 $1,247 $0 $2,321 $17,795 $323 FEEDWATER & MISC. BOP SYSTEMS3.1 FeedwaterSystem $15,086 $0 $5,277 $0 $0 $20,363 $1,787 $0 $3,322 $25,472 $463.2 Water Makeup & Pretreating $4,700 $0 $1,511 $0 $0 $6,211 $582 $0 $1,359 $8,152 $153.3 Other Feedwater Subsystems $4,982 $0 $2,114 $0 $0 $7,095 $632 $0 $1,159 $8,887 $163.4 Service Water Systems $928 $0 $501 $0 $0 $1,429 $133 $0 $312 $1,873 $33.5 Other Boiler Plant Systems $5,826 $0 $5,699 $0 $0 $11,525 $1,081 $0 $1,891 $14,498 $263.6 FO Supply Sys & Nat Gas $248 $0 $305 $0 $0 $552 $51 $0 $91 $694 $13.7 Waste Treatment Equipment $3,168 $0 $1,815 $0 $0 $4,982 $483 $0 $1,093 $6,558 $123.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,566 $0 $790 $0 $0 $3,356 $322 $0 $736 $4,414 $8SUBTOTAL 3. $37,503 $0 $18,011 $0 $0 $55,514 $5,071 $0 $9,963 $70,548 $1284 PC BOILER4.1 PC Boiler & Accessories $127,763 $0 $82,570 $0 $0 $210,334 $20,391 $0 $23,072 $253,797 $4614.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 4. $127,763 $0 $82,570 $0 $0 $210,334 $20,391 $0 $23,072 $253,797 $461TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants347Exhibit 4-13 Case 9 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:09-May-07Project:Bituminous Baseline StudyCase:Case 9 - Subcritical PC w/o CO2Plant Size:550.4 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW5 FLUE GAS CLEANUP5.1 Absorber Vessels & Accessories $58,310 $0 $12,562 $0 $0 $70,872 $6,708 $0 $7,758 $85,337 $1555.2 Other FGD $3,043 $0 $3,451 $0 $0 $6,494 $626 $0 $712 $7,831 $145.3 Bag House & Accessories $16,683 $0 $10,596 $0 $0 $27,279 $2,609 $0 $2,989 $32,877 $605.4 Other Particulate Removal Materials $1,129 $0 $1,209 $0 $0 $2,338 $225 $0 $256 $2,819 $55.5 Gypsum Dewatering System $4,591 $0 $780 $0 $0 $5,372 $508 $0 $588 $6,467 $125.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 5. $83,756 $0 $28,598 $0 $0 $112,354 $10,675 $0 $12,303 $135,332 $2466 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $06.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $07.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07.3 Ductwork $8,649 $0 $5,645 $0 $0 $14,295 $1,249 $0 $2,332 $17,875 $327.4 Stack $8,826 $0 $5,169 $0 $0 $13,995 $1,337 $0 $1,533 $16,866 $317.9 Duct & Stack Foundations $0 $1,006 $1,151 $0 $0 $2,157 $201 $0 $472 $2,830 $5SUBTOTAL 7. $17,476 $1,006 $11,965 $0 $0 $30,447 $2,787 $0 $4,336 $37,570 $688 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $47,000 $0 $6,220 $0 $0 $53,220 $5,095 $0 $5,832 $64,147 $1178.2 Turbine Plant Auxiliaries $335 $0 $718 $0 $0 $1,054 $102 $0 $116 $1,271 $28.3 Condenser & Auxiliaries $7,062 $0 $2,211 $0 $0 $9,272 $880 $0 $1,015 $11,168 $208.4 Steam Piping $15,215 $0 $7,516 $0 $0 $22,731 $1,897 $0 $3,694 $28,322 $518.9 TG Foundations $0 $1,045 $1,663 $0 $0 $2,708 $255 $0 $592 $3,555 $6SUBTOTAL 8. $69,612 $1,045 $18,328 $0 $0 $88,984 $8,230 $0 $11,249 $108,463 $1979 COOLING WATER SYSTEM9.1 Cooling Towers $8,335 $0 $2,730 $0 $0 $11,065 $1,051 $0 $1,212 $13,328 $249.2 Circulating Water Pumps $1,938 $0 $127 $0 $0 $2,065 $177 $0 $224 $2,466 $49.3 Circ.Water System Auxiliaries $516 $0 $69 $0 $0 $585 $55 $0 $64 $704 $19.4 Circ.Water Piping $0 $4,162 $3,969 $0 $0 $8,131 $749 $0 $1,332 $10,212 $199.5 Make-up Water System $458 $0 $607 $0 $0 $1,065 $101 $0 $175 $1,341 $29.6 Component Cooling Water Sys $412 $0 $326 $0 $0 $738 $69 $0 $121 $928 $29.9 Circ.Water System Foundations& Structures $0 $2,409 $3,855 $0 $0 $6,265 $590 $0 $1,371 $8,225 $15SUBTOTAL 9. $11,659 $6,571 $11,683 $0 $0 $29,913 $2,792 $0 $4,499 $37,204 $6810 ASH/SPENT SORBENT HANDLING SYS10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.6 Ash Storage Silos $583 $0 $1,798 $0 $0 $2,381 $232 $0 $261 $2,874 $510.7 Ash Transport & Feed Equipment $3,800 $0 $3,869 $0 $0 $7,669 $725 $0 $839 $9,234 $1710.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.9 Ash/Spent Sorbent Foundation $0 $138 $163 $0 $0 $301 $28 $0 $66 $395 $1SUBTOTAL 10. $4,383 $138 $5,829 $0 $0 $10,350 $985 $0 $1,166 $12,502 $23TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants348Exhibit 4-13 Case 9 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:09-May-07Project:Bituminous Baseline StudyCase:Case 9 - Subcritical PC w/o CO2Plant Size:550.4 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW11 ACCESSORY ELECTRIC PLANT11.1 Generator Equipment $1,527 $0 $250 $0 $0 $1,777 $165 $0 $146 $2,088 $411.2 Station Service Equipment $2,671 $0 $914 $0 $0 $3,585 $343 $0 $295 $4,222 $811.3 Switchgear & Motor Control $3,174 $0 $544 $0 $0 $3,717 $344 $0 $406 $4,468 $811.4 Conduit & Cable Tray $0 $2,038 $6,935 $0 $0 $8,973 $859 $0 $1,475 $11,306 $2111.5 Wire & Cable $0 $3,696 $7,305 $0 $0 $11,002 $927 $0 $1,789 $13,718 $2511.6 Protective Equipment $252 $0 $894 $0 $0 $1,146 $112 $0 $126 $1,384 $311.7 Standby Equipment $1,178 $0 $28 $0 $0 $1,206 $114 $0 $132 $1,452 $311.8 Main Power Transformers $7,000 $0 $166 $0 $0 $7,166 $544 $0 $771 $8,481 $1511.9 Electrical Foundations $0 $298 $737 $0 $0 $1,035 $98 $0 $227 $1,360 $2SUBTOTAL 11. $15,802 $6,032 $17,773 $0 $0 $39,607 $3,506 $0 $5,366 $48,479 $8812 INSTRUMENTATION & CONTROL12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $012.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $012.4 Other Major Component Control $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $012.5 Signal Processing Equipment W/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.6 Control Boards,Panels & Racks $410 $0 $256 $0 $0 $666 $64 $0 $109 $839 $212.7 Distributed Control System Equipment $4,139 $0 $754 $0 $0 $4,893 $466 $0 $536 $5,895 $1112.8 Instrument Wiring & Tubing $2,287 $0 $4,638 $0 $0 $6,924 $590 $0 $1,127 $8,641 $1612.9 Other I & C Equipment $1,170 $0 $2,766 $0 $0 $3,935 $383 $0 $432 $4,750 $9SUBTOTAL 12. $8,006 $0 $8,413 $0 $0 $16,419 $1,503 $0 $2,204 $20,126 $3713 IMPROVEMENTS TO SITE13.1 Site Preparation $0 $48 $959 $0 $0 $1,007 $99 $0 $221 $1,328 $213.2 Site Improvements $0 $1,581 $1,978 $0 $0 $3,559 $349 $0 $782 $4,690 $913.3 Site Facilities $2,833 $0 $2,815 $0 $0 $5,648 $554 $0 $1,240 $7,442 $14SUBTOTAL 13. $2,833 $1,629 $5,752 $0 $0 $10,214 $1,003 $0 $2,243 $13,460 $2414 BUILDINGS & STRUCTURES14.1 Boiler Building $0 $8,070 $7,192 $0 $0 $15,261 $1,371 $0 $4,158 $20,790 $3814.2 Turbine Building $0 $11,680 $11,031 $0 $0 $22,711 $2,045 $0 $6,189 $30,945 $5614.3 Administration Building $0 $555 $594 $0 $0 $1,149 $104 $0 $313 $1,566 $314.4 Circulation Water Pumphouse $0 $159 $128 $0 $0 $287 $26 $0 $78 $391 $114.5 Water Treatment Buildings $0 $620 $518 $0 $0 $1,138 $102 $0 $310 $1,550 $314.6 Machine Shop $0 $371 $253 $0 $0 $624 $55 $0 $170 $849 $214.7 Warehouse $0 $251 $256 $0 $0 $507 $46 $0 $138 $691 $114.8 Other Buildings & Structures $0 $205 $177 $0 $0 $383 $34 $0 $104 $521 $114.9 Waste Treating Building & Str. $0 $393 $1,209 $0 $0 $1,603 $151 $0 $439 $2,193 $4SUBTOTAL 14. $0 $22,304 $21,358 $0 $0 $43,662 $3,934 $0 $11,899 $59,495 $108TOTAL COST $405,742 $43,703 $242,779 $0 $0 $692,224 $64,830 $0 $95,558 $852,612 $1,549TOTAL PLANT COST SUMMARYCost and Performance Comparison of Fossil Energy Power Plants

349 

### Exhibit 4-14 Case 9 Initial and A nnual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006 Case 9 - Subcritical PC w/o CO 2 Heat Rate-net(Btu/kWh): 9,276 MWe-net: 550 Capacity Factor: (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 33.00 $/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 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL-O.J.'s 14.0 14.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $5,261,256 $9.558 Maintenance Labor Cost $5,602,943 $10.179 Administrative & Support Labor $2,716,050 $4.934 TOTAL FIXED OPERATING COSTS $13,580,249 $24.672 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $8,404,415 $0.00205

Consumables Consumption Unit Initial Initial /Day Cost Cost
Water(/1000 gallons) 0 4,472.64 1.03 $0 $1,429,266 $0.00035

Chemicals MU & WT Chem.(lb) 151,553 21,650 0.16 $24,976 $1,106,970 $0.00027 Limestone (ton) 3,661 523 20.60 $75,419 $3,342,699 $0.00082 Carbon (Mercury Removal) (lb) 0 0 0.00 $0 $0 $0.00000 MEA Solvent (ton) 0 0 2,142.40 $0 $0 $0.00000 NaOH (tons) 0 0 412.96 $0 $0 $0.00000 H2SO4 (tons) 0 0 132.15 $0 $0 $0.00000 Corrosion Inhibitor 0 0 0.00 $0 $0 $0.00000 Activated Carbon(lb) 0 0 1.00 $0 $0 $0.00000 Ammonia (28% NH3) ton 550 79 123.60 $67,984 $3,013,146 $0.00074 Subtotal Chemicals $168,379 $7,462,815 $0.00182

Other Supplemental Fuel(MBtu) 0 0 0.00 $0 $0 $0.00000 SCR Catalyst(m3) w/equip. 0.47 5,500.00 $0 $794,147 $0.00019 Emission Penalties 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $794,147 $0.00019

Waste Disposal Flyash (ton) 0 102 15.45 $0 $488,290 $0.00012 Bottom Ash(ton) 0 407 15.45 $0 $1,953,046 $0.00048 Subtotal-Waste Disposal $0 $2,441,336 $0.00060

By-products & Emissions Gypsum (tons) 0 823 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $168,379 $20,531,979 $0.00501

Fuel(ton) 157,562 5,252 42.11 $6,634,942 $68,616,356 $0.01674Cost and Performance Comparison of Fossil Energy Power Plants

350 

### 4.2.7 C ASE 

### 10

– PC S UBCRITICAL 

### U NIT WITH 

### CO 2 

### C APTURE 

### The plant configuration for Case 10, subcritical PC, is the same as Case 9 with the exception that the Econamine FG Plus technology was added for CO 2 

### capture. The nominal net output was maintained at 550 MW by increasing the boiler si ze and turbine/generator size to account for the greater auxiliary load imposed by the CDR fac ility. Unlike the IGCC cases where gross output was fixed by the available size of the combustion turbines, the PC cases utilize boilers and steam turbines that can be procured at nearly a ny desired output making it possible to maintain a constant net output. The process description for Case 10 is essentially the same as Case 9 with one notable exception, the addition of CO 2 

### capture. A BFD and stream tables for Case 10 are shown in Exhibit 4-15 and Exhibit 4-16, respectively. Since the CDR faci lity process description was provided in Section 4.1.7, it is not repeated here.

4.2.8 C ASE 

### 10 P ERFORMANCE 

### R ESULTS 

### The Case 10 modeling assumptions were presented previously in Section 4.2.2. The plant produces a net output of 550 MW at a net plant efficiency of 24.9 percent (HHV basis). Overall plant performance is summarized in Exhibit 4-17 which includes auxiliary power requirements. The CDR facility, including CO 2 

### compression, accounts for over half of the auxiliary plant load. The circ ulating water system (circulati ng water pumps and cooling tower fan) accounts for over 15 percent of the auxiliar y load, largely due to the high cooling water demand of the CDR facility.Cost and Performance Comparisonof Fossil Energy Power Plants351Exhibit 4-15 Case 10 Process FlowDiagram, Subcritical Unit with CO2CaptureFORCEDDRAFTFANSBAGHOUSEFGDINDUCEDDRAFTFANSSTACK GASSTACKGYPSUMLIMESTONESLURRYOXIDATIONAIRMAKEUPWATERBOTTOMASHCOALFEEDINFILTRATIONAIR812PRIMARYAIRFANS346579FLYASH10111314121516AIRCOMBUSTIONPRODUCTSWATERCOAL/ASHSOLID/WATERSLURRYLEGENDPULVERIZEDCOALBOILERSCRECONAMINEFG+171821CO2COMPRESSOR1920CO2PRODUCTREBOILERSTEAMCONDENSATERETURNCO2HPTURBINEIPTURBINELP TURBINECONDENSERFEEDWATERHEATERSYSTEM679.9 MWeMAINSTEAMCOLDREHEATHOTREHEATBOILERFEEDWATERCost and Performance Comparisonof Fossil Energy Power Plants352Exhibit 4-16 Case 10 Stream Table, Subcritical Unit with CO2Capture1 2 3 4 5 6 7 8 9 10 11V-L Mole FractionAr 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087CO20.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1448 0.0000 0.1448 0.1448H20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000H2O0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0869 0.0000 0.0869 0.0869N20.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7325 0.0000 0.7325 0.7325O20.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0250 0.0000 0.0250 0.0250SO20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000V-L Flowrate (lbmol/hr)168,844 168,844 51,867 51,867 3,894 0 0 237,558 0 237,558 237,558V-L Flowrate (lb/hr) 4,872,330 4,872,330 1,496,7301,496,730 112,375 0 0 7,065,320 0 7,065,320 7,065,320Solids Flowrate (lb/hr) 0 0 0 0 0 646,589 12,540 50,159 50,159 0 0Temperature (°F) 59 66 59 78 59 78 350 350 350 350 370Pressure (psia) 14.7 15.3 14.7 16.1 14.7 14.7 14.4 14.4 14.2 14.2 15.3Enthalpy (BTU/lb)A13.1 14.9 13.1 17.7 13.1 11,676 51.4 135.7 51.4 136.3 141.5Density (lb/ft3)0.08 0.08 0.08 0.08 0.08 -- -- 0.05 -- 0.05 0.05Molecular Weight 28.86 28.86 28.86 28.86 28.86 -- -- 29.74 -- 29.74 29.7412 13 14 15 16 17 18 19 20 21V-L Mole FractionAr 0.0000 0.0000 0.0092 0.0000 0.0079 0.0000 0.0000 0.0000 0.0000 0.0107CO20.0000 0.0000 0.0003 0.0014 0.1314 0.0000 0.0000 0.9856 1.0000 0.0176H20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000H2O1.0000 1.0000 0.0099 0.9978 0.1725 1.0000 1.0000 0.0144 0.0000 0.0458N20.0000 0.0000 0.7732 0.0007 0.6644 0.0000 0.0000 0.0000 0.0000 0.8940O20.0000 0.0000 0.2074 0.0000 0.0237 0.0000 0.0000 0.0000 0.0000 0.0319SO20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000V-L Flowrate (lbmol/hr)8,120 40,086 2,816 22,176 265,166 110,756 110,756 31,826 31,369 197,020V-L Flowrate (lb/hr) 146,287 722,155 81,276 400,501 7,578,830 1,995,300 1,995,3001,388,770 1,380,530 5,535,170Solids Flowrate (lb/hr) 63,956 0 0 99,659 0 0 0 0 0 0Temperature (°F) 59 59 59 135 135 743 367 69 124 89Pressure (psia) 14.7 14.7 14.7 14.7 14.7 167.7 167.7 23.5 2,215.0 14.7Enthalpy (BTU/lb)A--- 32.4 13.1 88.0 143.6 1397.7 340.1 13.7 -70.8 45.7Density (lb/ft3)62.62 62.62 0.08 40.44 0.07 0.24 54.94 0.18 40.76 0.07Molecular Weight 18.02 18.02 28.86 18.06 28.58 18.02 18.02 43.64 44.01 28.09A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparison of Fossil Energy Power Plants

353 

### Exhibit 4-17 Case 10 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) TOTAL (STEAM TURBINE) POWER, kWe 679,923 AUXILIARY LOAD SUMMARY, kWe (Note 1) Coal Handling and Conveying 520 Limestone Handling & Reagent Preparation 1,400 Pulverizers 4,400 Ash Handling 840 Primary Air Fans 2,060 Forced Draft Fans 2,620 Induced Draft Fans 11,180 SCR 80 Baghouse 100 FGD Pumps and Agitators 4,680 Amine System Auxiliaries 23,500 CO 2 

### Compression 51,610 Condensate Pumps 1,210 Miscellaneous Balance of Plant (Note 2) 2,000 Steam Turbine Auxiliaries 400 Circulating Water Pumps 14,060 Cooling Tower Fans 7,270 Transformer Loss 2,380 TOTAL AUXILIARIES, kWe 130,310 NET POWER, kWe 549,613 Net Plant Efficiency (HHV) 24.9% Net Plant Heat Rate (Btu/kWh) 13,724 CONDENSER COOLING DUTY 10 6 

### kJ/h (10 6 

### Btu/h) 2,318 (2,199) CONSUMABLES As-Received Coal Feed, kg/h (lb/h) 293,288 (646,589) Limestone Sorbent Feed, kg/h (lb/h) 29,010 (63,956) Thermal Input, kWt 2,210,668 Makeup water, m 3 

### /min (gpm) 53.4 (14,098) Notes: 1. Boiler feed pumps are steam turbine driven 2. Includes plant control systems, lighti ng, HVAC and miscellanous low voltage loadsCost and Performance Comparison of Fossil Energy Power Plants

354 

### Environmental Performance The environmental targets for emissions of Hg, NOx, SO 2 

### , and particulate matter were presented in Section 2.4. A summary of the plant ai r emissions for Case 10 is presented in Exhibit 4-18.

Exhibit 4-18 Case 10 Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)

SO 2 

### Negligible Negligible Negligible NO X 

### 0.030 (0.070) 1,783 (1,966) 0.352 (0.777) Particulates 0.006 (0.013) 331 (365) 0.065 (0.144)
Hg 0.49 x 10 -6 

### (1.14 x 10 -6 

### ) 0.029 (0.032) 5.8 x 10 -6 

### (12.7 x 10 -6 

### )

CO 2 

### 8.7 (20) 517,000 (570,000) 102 (225)

CO 2 1 

### 126 (278)

1 

### CO 2 

### emissions based on net power instead of gross power

SO 2 

### emissions are controlled using a wet limestone forced oxidation scrubber that achieves a removal efficiency of 98 percent. The byproduct cal cium sulfate is dewatered and stored on site. The wallboard grade material can potentially be marketed and sold, but since it is highly dependent on local market conditions, no byproduct credit was taken. The SO 2 

### emissions are further reduced to 10 ppmv using an NaOH based polishing scrubber in the CDR facility. The remaining low concentration of SO 2 

### is essentially completely removed in the CDR absorber vessel resulting in negligible SO 2 

### emissions.
NOx emissions are controlled to about 0.5 lb/10 6 

### Btu through the use of LNBs and OFA. An SCR unit then further reduces the NOx c oncentration by 86 per cent to 0.07 lb/10 6 

### Btu.
Particulate emissions are controlled using a pulse jet fabric filter wh ich operates at an efficiency of 99.8 percent. Co-benefit capture results in a 90 percent reduction of mercury emissions. Ninety percent of the CO 2 

### in the flue gas is removed in CDR facility.
Exhibit 4-19 shows the overall water balance for the plant. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent) . The water usage represents only the contribution of raw water makeup. In some cases the actual consumption is greater than raw water makeup because of internal water recycl e streams. For example, the boiler feedwater blowdown stream and condensate from cooling the fl ue gas prior to the CDR facility are re-used as makeup to the cooling tower, thus reduc ing the raw water requirement by that amount.Cost and Performance Comparison of Fossil Energy Power Plants

355 

### Exhibit 4-19 Case 10 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle,

m 3 

### /min (gpm) Raw Water Makeup,

m 3 

### /min (gpm)
FGD Makeup 3.5 (926) 0 3.5 (926)
BFW Makeup 0.4 (109) 0 0.4 (109)
Cooling Tower Makeup 47.5 (12,543) 5.3 (1,390) 42.2 (11,152)
Total 51.4 (13,578) 5.3 (1,390) 46.1 (12,187)

Heat and Mass Balance Diagrams A heat and mass balance diagram is shown for th e Case 10 PC boiler, the FGD unit, CDR system and steam cycle in Exhibit 4-20. An overall plant energy balance is provided in tabular form in Exhibit 4-21. The power out is the steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 4-17) is calculated by multiplying th e power out by a generator efficiency of 98.4 percent. The Econamine process heat out stream represents heat rejected to cooling water and ultimately to ambient via the cooling tower. The sa me is true of the condenser heat out stream. The CO 2 

### compressor intercooler load is included in the Econamine process heat out stream.Cost and Performance Comparison of Fossil Energy Power Plants

356 

### This page intentionally left blankCost and Performance Comparisonof Fossil Energy Power Plants357Exhibit 4-20 Case 10 Heat and MassBalance, Subcritical PC Boiler with CO2CaptureCost and Performance Comparisonof Fossil Energy Power Plants358This page intentionally left blankCost and Performance Comparison of Fossil Energy Power Plants

359 

### Exhibit 4-21 Case 10 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total
Heat In (MMBtu/hr) Coal 7,543.1 6.3 7,549.4 Ambient Air 83.6 83.6 Infiltration Air 1.5 1.5 Limestone 96.0 96.0 FGD Oxidant 1.1 1.1 Raw Water Makeup 161.8 161.8 Auxiliary Power 472.3 472.3 Totals 7,543.1 350.2 472.3 8,365.6 Heat Out (MMBtu/hr) Bottom Ash 0.6 0.6 Fly Ash 2.6 2.6 Flue Gas Exhaust 253.0 253.0 CO 2 

### Product (96.8) (96.8) Condenser 2,200.0 2,200.0 Econamine Process 3514.7 3514.7 Cooling Tower Blowdown 73.1 73.1 Gypsum Slurry 3.1 3.1 Process Losses (1) 56.0 56.0 Power 2,359.2 2,359.2 Totals 0.0 6,006.4 2,359.2 8,365.6 (1) Process Losses are calculated by difference a nd reflect various boiler, turbine, and other heat and work losses. Aspen flowsh eet balance is within 0.5 percent.Cost and Performance Comparison of Fossil Energy Power Plants

360 

### 4.2.9 C ASE 

### 10

– M AJOR 

### E QUIPMENT 

### L IST 

### Major equipment items for the subcritical PC plant with CO 2 

### capture are shown in the following tables. The accounts used in the equipment lis t correspond to the account numbers used in the cost estimates in Section 4.2.10. In general, the design c onditions include a 10 percent contingency for flows and heat duties and a 21 pe rcent contingency for heads on pumps and fans.
ACCOUNT 1 FUEL AND SORBENT HANDLING

Equipment No. Description Type Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0 3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0 5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0
8 Reclaim Hopper N/A 2 1
9 Feeder Vibratory 2 1
10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0 12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor reduction 2 0

14 As-Fired Coal Sampling System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0
17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 3 0

19 Limestone Truck Unloading Hopper N/A 1 0

20 Limestone Feeder Belt 1 0
21 Limestone Conveyor No. L1 Belt 1 0
22 Limestone Reclaim Hopper N/A 1 0

23 Limestone Reclaim Feeder Belt 1 0
24 Limestone Conveyor No. L2 Belt 1 0
25 Limestone Day Bin w/ actuator 2 0 36 tonne (40 ton)

118 tonne/h (130 tph)
118 tonne/h (130 tph)

381 tonne (420 ton)

27 tonne (30 ton)
100 tonne/h (110 tph)
100 tonne/h (110 tph) 1,089 tonne (1,200 ton) N/A

481 tonne/h (530 tph)

N/A 64 tonne (70 ton)
245 tonne/h (270 tph)

8 cm x 0 - 3 cm x 0 (3" x 0 - 1-1/4" x 0) 481 tonne/h (530 tph)

245 tonne (270 ton) N/A

481 tonne/h (530 tph)

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph) N/A 1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph) 1,134 tonne/h (1,250 tph)Cost and Performance Comparison of Fossil Energy Power Plants

361 

### ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED
Equipment No. Description Type Operating Qty. Spares

1 Coal Feeder Gravimetric 6 0

2 Coal Pulverizer Ball type or equivalent 6 0

3 Limestone Weigh Feeder Gravimetric 1 1
4 Limestone Ball Mill Rotary 1 1

5 Limestone Mill Slurry Tank with Agitator N/A 1 1

6 Limestone Mill Recycle Pumps Horizontal centrifugal 1 1

7 Hydroclone Classifier 4 active cyclones in a 5 cyclone bank 1 1

8 Distribution Box 2-way 1 1

9 Limestone Slurry Storage Tank with Agitator Field erected 1 1

10 Limestone Slurry Feed Pumps Horizontal centrifugal 1 1 688,950 liters (182,000 gal) 490 lpm @ 12m H2O (540 gpm @ 40 ft H2O)

N/A

345 lpm @ 9m H2O (380 gpm @ 30 ft H2O) 127 lpm (140 gpm) per cyclone

121,134 liters (32,000 gal) Design Condition

54 tonne/h (60 tph)

54 tonne/h (60 tph)

32 tonne/h (35 tph) 32 tonne/h (35 tph)Cost and Performance Comparison of Fossil Energy Power Plants

362 

### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 2 0

2 Condensate Pumps Vertical canned 1 1

3 Deaerator and Storage Tank Horizontal spray type 1 0

4 Boiler Feed Pump and Steam Turbine Drive Barrel type, multistage, centrifugal 1 1

6 LP Feedwater Heater 1A/1B Horizontal U-tube 2 0

7 LP Feedwater Heater 2A/2B Horizontal U-tube 2 0

8 LP Feedwater Heater 3A/3B Horizontal U-tube 2 0

9 LP Feedwater Heater 4A/4B Horizontal U-tube 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 1 0

11 HP Feedwater Heater 7 Horizontal U-tube 1 0

12 Auxiliary Boiler Shop fabricated, water tube 1 0

13 Fuel Oil System No. 2 fuel oil for light off 1 0

14 Service Air Compressors Flooded Screw 2 1

15 Instrument Air Dryers Duplex, regenerative 2 1

16 Closed Cycle Cooling Heat Exchangers Shell and tube 2 0

17 Closed Cycle Cooling Water Pumps Horizontal centrifugal 2 1

18 Engine-Driven Fire Pump Vertical turbine, diesel engine 1 1

19 Fire Service Booster Pump Two-stage horizontal centrifugal 1 1

20 Raw Water Pumps Stainless steel, single suction 2 1

21 Filtered Water Pumps Stainless steel, single suction 2 1

22 Filtered Water Tank Vertical, cylindrical 1 0

23 Makeup Water Demineralizer Multi-media filter, cartridge filter, RO membrane assembly, electrodeionization unit 1 1

24 Liquid Waste Treatment System -- 1 0 2,730,629 kg/h (6,020,000 lb/h)
2,730,629 kg/h (6,020,000 lb/h)

1,135,632 liter (300,000 gal) Design Condition

1,639,096 liters (433,000 gal)

22,334 lpm @ 335 m H2O (5,900 gpm @ 1,100 ft H2O) 2,730,629 kg/h (6,020,000 lb/h) 5 min. tank

3,785 lpm @ 88 m H2O (1,000 gpm @ 290 ft H2O)

2,650 lpm @ 64 m H2O (700 gpm @ 210 ft H2O) 29,602 lpm @ 43 m H2O (7,820 gpm @ 140 ft H2O) 45,804 lpm @ 2,499 m H2O (12,100 gpm @ 8,200 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C (40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 662,246 kg/h (1 ,460,000 lb/h)

662,246 kg/h (1 ,460,000 lb/h)

662,246 kg/h (1 ,460,000 lb/h)

662,246 kg/h (1 ,460,000 lb/h)

2,377,257 liter (628,000 gal)

1,098 lpm (290 gpm)

10 years, 24-hour storm 2,461 lpm @ 49 m H2O (650 gpm @ 160 ft H2O) 0 5 Startup Boiler Feed Pump, Electric Motor Driven Barrel type, multistage, centrifugal 13,628 lpm @ 2,499 m H2O (3,600 gpm @ 8,200 ft H2O) 1

53 MMkJ/h (50 MMBtu/h) each
20,820 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O)

28 m3/min (1,000 scfm)Cost and Performance Comparison of Fossil Energy Power Plants

363 

### ACCOUNT 4 BOILER AND ACCESSORIES
Equipment No. Description Type Operatin g Qty. Spares

1 Boiler Subcritical, drum wall-fired, low NOx burners, overfire air 1 0

2 Primary Air Fan Centrifugal 2 0

3 Forced Draft Fan Centrifugal 2 0

4 Induced Draft Fan Centrifugal 2 0

5 SCR Reactor Vessel Space for spare layer 2 0

6 SCR Catalyst -- 3 0

7 Dilution Air Blower Centrifugal 2 1

8 Ammonia Storage Horizontal tank 5 0

9 Ammonia Feed Pump Centrifugal 2 1 210 m3/min @ 108 cm WG (7,400 acfm @ 42 in. WG)
230,912 liter (61,000 gal) 44 lpm @ 91 m H2O (12 gpm @ 300 ft H2O) 1,762,662 kg/h, 37,427 m3/min @ 90 cm WG (3,886,000 lb/h, 1,321,700 acfm @ 36 in. WG)
3,524,417 kg/h (7,770,000 lb/h)

-- Design Condition

2,730,629 kg/h steam @ 16.5 MPa/566°C/566°C (6,020,000 lb/h steam @ 2,400 psig/1,050°F/1,050°F)

373,307 kg/h, 5,111 m3/min @

123 cm WG (823,000 lb/h, 180,500 acfm @ 48 in. WG)
1,215,629 kg/h, 16,642 m3/min @ 47 cm WG (2,680,000 lb/h, 587,700 acfm @ 19 in. WG)Cost and Performance Comparison of Fossil Energy Power Plants

364 

### ACCOUNT 5 FLUE GAS CLEANUP
Equipment No. Description Type Operatin g Qty. Spares

1 Fabric Filter Single stage, highratio with pulsejet online cleaning system 2 0

2 Absorber Module Counter-current
open spray 1 0

3 Recirculation Pumps Horizontal centrifugal 5 1

4 Bleed Pumps Horizontal centrifugal 2 1

5 Oxidation Air Blowers Centrifugal 2 1

6 Agitators Side entering 5 1

7 Dewatering Cyclones Radial assembly, 5 units each 2 0

8 Vacuum Filter Belt Horizontal belt 2 1

9 Filtrate Water Return Pumps Horizontal centrifugal 1 1

10 Filtrate Water Return Storage Tank Vertical, lined 1 0

11 Process Makeup Water Pumps Horizontal centrifugal 1 1 278 m3/min @ 0.3 MPa (9,800 acfm @ 42 psia)

50 tonne/h (55 tph) 50 wt % slurry 6,284 lpm (1,660 gpm) at 20 wt% solids

50 hp

1,590 lpm (420 gpm) per cyclone

946 lpm @ 12 m H2O (250 gpm @ 40 ft H2O)

643,525 lpm (170,000 gal)

3,861 lpm @ 21 m H2O (1,020 gpm @ 70 ft H2O) Design Condition

1,762,662 kg/h (3,886,000 lb/h) 99.8% efficiency

59,607 m3/min (2,105,000 acfm)

208,199 lpm @ 64 m H2O (55,000 gpm @ 210 ft H2O)



### ACCOUNT 5B CARBON DIOXIDE RECOVERY

Equipment No. Description Type Operating Qty. Spares

1 Econamine FG Plus Amine-based CO2 capture technology 2 0

2 CO2 Compressor Integrally geared, multi-stage centrifu g al 2 0 Design Condition
1,890,575 kg/h (4,168,000 lb/h) 20.2 wt % CO2 inlet concentration 344,408 kg/h @ 15.3 MPa (759,289 lb/h @ 2,215 psia)Cost and Performance Comparison of Fossil Energy Power Plants

365 

### ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES
N/A

ACCOUNT 7 HRSG, DUCTING & STACK

Equipment No. Description Type Operating Qty. Spares

1 Stack Reinforced concrete with FRP liner 1 0 Design Condition

152 m (500 ft) high x 6.1 m (20 ft) diameter



### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitation 1 0

3 Surface Condenser Single pass, divided waterbox including
vacuum pumps 1 0 800 MVA @ 0.9 p.f., 24 kV, 60 Hz Design Condition

720 MW 16.5 MPa/566°C/566°C (2400 psig/ 1050°F/1050°F)

2,551 MMkJ/h (2,420 MMBtu/h), Inlet water temperature 16oC (60oF),

Water temperature rise 11oC (20oF)



### ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 4 2

2 Cooling Tower Evaporative, mechanical draft, multi-cell 1 0 Design Condition

704,092 lpm @ 30.5 m (186,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT 6,821 MMkJ/h (6,470 MMBtu/h) heat loadCost and Performance Comparison of Fossil Energy Power Plants

366 

### ACCOUNT 10 ASH/SPENT SORBEN T RECOVERY AND HANDLING
Equipment No. Description Type Operating Qty. Spares

1 Economizer Hopper (part of boiler scope of supply) -- 4 0

2 Bottom Ash Hopper (part of boiler scope of supply) -- 2 0

3 Clinker Grinder -- 1 1

4 Pyrites Hopper (part of pulverizer scope of supply included with boiler) -- 6 0

5 Hydroejectors -- 12

6 Economizer /Pyrites Transfer Tank -- 1 0

7 Ash Sluice Pumps Vertical, wet pit 1 1

8 Ash Seal Water Pumps Vertical, wet pit 1 1

9 Hydrobins -- 1 1

10 Baghouse Hopper (part of baghouse scope of supply) -- 24 0

11 Air Heater Hopper (part of boiler scope of supply) -- 10 0

12 Air Blower -- 1 1

13 Fly Ash Silo Reinforced
concrete 2 0

14 Slide Gate Valves -- 2 0

15 Unloader -- 1 0

16 Telescoping Unloading Chute -- 1 0 265 lpm (70 gpm)

--

--

-- --

23 m3/min @ 0.2 MPa

(810 scfm @ 24 psi)

771 tonne (1,700 ton)

136 tonne/h (150 tph) --

--
265 lpm @ 17 m H2O (70 gpm @ 56 ft H2O)

7,571 lpm @ 9 m H2O (2000 gpm @ 28 ft H2O) -- Design Condition

--

--
6.4 tonne/h (7 tph)Cost and Performance Comparison of Fossil Energy Power Plants

367 

### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type Operating Qty. Spares

1 STG Transformer Oil-filled 1 0

2 Auxiliary Transformer Oil-filled 1 1

3 Low Voltage Transformer Dry ventilated 1 1

4 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 1 0

5 Medium Voltage Switchgear Metal clad 1 1

6 Low Voltage Switchgear Metal enclosed 1 1

7 Emergency Diesel Generator Sized for emergency shutdown 1 0 24 kV/4.16 kV, 140 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 21 MVA, 3-ph, 60 Hz Design Condition
24 kV/345 kV, 650 MVA, 3-ph, 60 Hz

750 kW, 480 V, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz



### ACCOUNT 12 INSTRUMENTATION AND CONTROL

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) 1 0

3 DCS - Data Highway Fiber optic 1 0 Design Condition

Operator stations/printers and engineering stations/printers

2 DCS - Processor Microprocessor with redundant input/output N/A 1 0

Fully redundant, 25% spareCost and Performance Comparison of Fossil Energy Power Plants

368 

### 4.2.10 C ASE 

### 10

– C OST 

### E STIMATING 

### The cost estimating methodology was desc ribed previously in Section 2.6. Exhibit 4-22 shows the total plant capital cost summary organized by cost account and Exhibit 4-23 shows a more detailed breakdown of the capital costs. Exhibit 4-24 shows the ini tial and annual O&M costs.
The estimated TPC of the s ubcritical PC boiler with CO 2 

### capture is $2,888/kW. Process contingency represents 3.6 percent of the TPC a nd project contingency repr esents 12.6 percent. The 20-year LCOE, including CO 2 

### TS&M costs of 4.3 mills/kWh, is 118.8 mills/kWh.Cost and Performance Comparisonof Fossil Energy Power Plants369Exhibit 4-22 Case 10 Total Plant Cost SummaryClient:USDOE/NETLReport Date:09-May-07Project:Bituminous Baseline StudyCase:Case 10 - Subcritical PC w/ CO2Plant Size:549.6 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING $20,525 $5,540 $12,420 $0 $0$38,485$3,449 $0 $6,290$48,223$882 COAL & SORBENT PREP & FEED $13,990 $807 $3,544 $0 $0$18,342$1,608 $0 $2,992$22,942$423 FEEDWATER & MISC. BOP SYSTEMS $53,307 $0 $25,510 $0 $0$78,817$7,217 $0 $14,343$100,377$1834 PC BOILER4.1 PC Boiler & Accessories $167,758 $0 $108,417 $0 $0$276,176$26,774 $0 $30,295$333,245$6064.2 SCR (w/4.1) $0 $0 $0 $0 $0$0$0 $0 $0$0$04.3 Open $0 $0 $0 $0 $0$0$0 $0 $0$0$04.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0$0$0 $0 $0$0$0SUBTOTAL 4 $167,758 $0 $108,417 $0 $0 $276,176 $26,774 $0 $30,295 $333,245 $6065 FLUE GAS CLEANUP $109,618 $0 $37,721 $0 $0$147,340$14,000 $0 $16,134$177,474$3235BCO2REMOVAL & COMPRESSION$243,432 $0 $74,100 $0 $0$317,532$30,138 $56,039 $80,742$484,450$8816 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator N/A $0 N/A $0 $0$0$0 $0 $0$0$06.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0$0$0 $0 $0$0$0SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0$0$0 $0 $0$0$07.2-7.9 HRSG Accessories, Ductwork and Stack $19,363 $1,062 $13,228 $0 $0$33,653$3,074 $0 $4,824$41,551$76SUBTOTAL 7 $19,363 $1,062 $13,228 $0 $0 $33,653 $3,074 $0 $4,824 $41,551 $768 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $52,758 $0 $6,989 $0 $0$59,747$5,720 $0 $6,547$72,014$1318.2-8.9 Turbine Plant Auxiliaries and Steam Piping $26,773 $1,170 $15,006 $0 $0$42,949$3,737 $0 $6,617$53,303$97SUBTOTAL 8 $79,532 $1,170 $21,995 $0 $0 $102,697 $9,457 $0 $13,163 $125,317 $2289 COOLING WATER SYSTEM $21,405 $11,272 $20,092 $0 $0$52,768$4,916 $0 $7,834$65,518$11910 ASH/SPENT SORBENT HANDLING SYS $5,440 $171 $7,234 $0 $0$12,844$1,223 $0 $1,448$15,515$2811 ACCESSORY ELECTRIC PLANT $20,789 $10,729 $30,669 $0 $0$62,187$5,554 $0 $8,642$76,384$13912 INSTRUMENTATION & CONTROL $9,150 $0 $9,615 $0 $0$18,765$1,718 $938 $2,635$24,056$4413 IMPROVEMENTS TO SITE $3,201 $1,840 $6,500 $0 $0$11,541$1,133 $0 $2,535$15,210$2814 BUILDINGS & STRUCTURES $0 $24,892 $23,781 $0 $0$48,672$4,385 $0 $7,959$61,016$111TOTAL COST $767,510 $57,483 $394,827 $0 $0 $1,219,819 $114,645 $56,977 $199,835 $1,591,277 $2,895TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants370Exhibit 4-23 Case 10 Total Plant Cost DetailsClient:USDOE/NETLReport Date:09-May-07Project:Bituminous Baseline StudyCase:Case 10 - Subcritical PC w/ CO2Plant Size:549.6 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING1.1 Coal Receive & Unload $4,213 $0 $1,944 $0 $0 $6,158 $550 $0 $1,006 $7,714 $141.2 Coal Stackout & Reclaim $5,445 $0 $1,246 $0 $0 $6,692 $586 $0 $1,092 $8,369 $151.3 Coal Conveyors $5,062 $0 $1,233 $0 $0 $6,296 $552 $0 $1,027 $7,875 $141.4 Other Coal Handling $1,324 $0 $285 $0 $0 $1,610 $141 $0 $263 $2,013 $41.5 Sorbent Receive & Unload $170 $0 $52 $0 $0 $221 $20 $0 $36 $277 $11.6 Sorbent Stackout & Reclaim $2,741 $0 $508 $0 $0 $3,249 $283 $0 $530 $4,061 $71.7 Sorbent Conveyors $978 $210 $242 $0 $0 $1,431 $124 $0 $233 $1,788 $31.8 Other Sorbent Handling $591 $138 $313 $0 $0 $1,042 $92 $0 $170 $1,304 $21.9 Coal & Sorbent Hnd.Foundations $0 $5,192 $6,596 $0 $0 $11,787 $1,102 $0 $1,933 $14,823 $27SUBTOTAL 1. $20,525 $5,540 $12,420 $0 $0 $38,485 $3,449 $0 $6,290 $48,223 $882 COAL & SORBENT PREP & FEED2.1 Coal Crushing & Drying $2,458 $0 $484 $0 $0 $2,942 $257 $0 $480 $3,678 $72.2 Coal Conveyor to Storage $6,292 $0 $1,388 $0 $0 $7,680 $672 $0 $1,253 $9,605 $172.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.5 Sorbent Prep Equipment $4,677 $201 $981 $0 $0 $5,859 $510 $0 $955 $7,324 $132.6 Sorbent Storage & Feed $563 $0 $218 $0 $0 $782 $69 $0 $128 $979 $22.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.9 Coal & Sorbent Feed Foundation $0 $607 $473 $0 $0 $1,080 $99 $0 $177 $1,357 $2SUBTOTAL 2. $13,990 $807 $3,544 $0 $0 $18,342 $1,608 $0 $2,992 $22,942 $423 FEEDWATER & MISC. BOP SYSTEMS3.1 FeedwaterSystem $20,059 $0 $7,016 $0 $0 $27,075 $2,376 $0 $4,418 $33,869 $623.2 Water Makeup & Pretreating $8,410 $0 $2,704 $0 $0 $11,114 $1,042 $0 $2,431 $14,588 $273.3 Other Feedwater Subsystems $6,624 $0 $2,810 $0 $0 $9,434 $841 $0 $1,541 $11,816 $213.4 Service Water Systems $1,660 $0 $896 $0 $0 $2,556 $237 $0 $559 $3,352 $63.5 Other Boiler Plant Systems $7,807 $0 $7,637 $0 $0 $15,444 $1,449 $0 $2,534 $19,426 $353.6 FO Supply Sys & Nat Gas $271 $0 $333 $0 $0 $605 $56 $0 $99 $760 $13.7 Waste Treatment Equipment $5,668 $0 $3,247 $0 $0 $8,915 $864 $0 $1,956 $11,734 $213.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,808 $0 $865 $0 $0 $3,674 $353 $0 $805 $4,832 $9SUBTOTAL 3. $53,307 $0 $25,510 $0 $0 $78,817 $7,217 $0 $14,343 $100,377 $1834 PC BOILER4.1 PC Boiler & Accessories $167,758 $0 $108,417 $0 $0 $276,176 $26,774 $0 $30,295 $333,245 $6064.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 4. $167,758 $0 $108,417 $0 $0 $276,176 $26,774 $0 $30,295 $333,245 $606TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants371Exhibit 4-23 Case 10 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:09-May-07Project:Bituminous Baseline StudyCase:Case 10 - Subcritical PC w/ CO2Plant Size:549.6 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost CostDirect Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW5 FLUE GAS CLEANUP5.1 Absorber Vessels & Accessories $75,926$0 $16,357 $0 $0 $92,284 $8,734 $0 $10,102 $111,120 $2025.2 Other FGD $3,962 $0 $4,493 $0 $0 $8,456 $815 $0 $927 $10,197 $195.3 Bag House & Accessories $22,462 $0$14,266 $0 $0 $36,728 $3,513 $0 $4,024 $44,265 $815.4 Other Particulate Removal Materials $1,520 $0 $1,628 $0 $0 $3,148 $303 $0 $345 $3,796 $75.5 Gypsum Dewatering System $5,747 $0 $977 $0 $0 $6,724 $635 $0 $736 $8,096 $155.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 5. $109,618 $0 $37,721 $0 $0 $147,340 $14,000 $0 $16,134 $177,474 $3235BCO2REMOVAL & COMPRESSION5B.1CO2Removal System$214,986 $0 $65,208 $0 $0 $280,194 $26,593 $56,039 $72,565 $435,391 $7925B.2CO2Compression & Drying$28,446 $0 $8,892 $0 $0 $37,338 $3,545 $0 $8,177 $49,059 $89SUBTOTAL 5B. $243,432 $0 $74,100 $0 $0$317,532 $30,138 $56,039 $80,742 $484,450 $8816 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $06.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $07.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07.3 Ductwork $10,045 $0 $6,556 $0 $0 $16,601 $1,450 $0 $2,708 $20,758 $387.4 Stack $9,318 $0 $5,457 $0 $0$14,775 $1,412 $0 $1,619 $17,805 $327.9 Duct & Stack Foundations $0 $1,062 $1,215 $0 $0 $2,278 $212 $0 $498 $2,988 $5SUBTOTAL 7. $19,363 $1,062 $13,228$0 $0 $33,653 $3,074 $0 $4,824 $41,551 $768 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $52,758 $0 $6,989 $0 $0 $59,747 $5,720 $0 $6,547 $72,014 $1318.2 Turbine Plant Auxiliaries $375 $0 $804 $0 $0 $1,179 $114 $0 $129 $1,423 $38.3 Condenser & Auxiliaries $6,425 $0 $2,475 $0 $0 $8,900 $847 $0 $975 $10,721 $208.4 Steam Piping $19,973 $0 $9,866 $0 $0 $29,839 $2,490 $0 $4,849 $37,179 $688.9 TG Foundations $0 $1,170 $1,861 $0 $0 $3,031 $285 $0 $663 $3,979 $7SUBTOTAL 8. $79,532 $1,170 $21,995 $0$0 $102,697 $9,457 $0 $13,163 $125,317 $2289 COOLING WATER SYSTEM9.1 Cooling Towers $14,689 $0 $4,810 $0 $0 $19,499 $1,852 $0 $2,135 $23,485 $439.2 Circulating Water Pumps $4,326 $0 $310 $0 $0 $4,636 $397 $0 $503 $5,536 $109.3 Circ.Water System Auxiliaries $912 $0 $122 $0 $0 $1,034 $98 $0 $113 $1,245 $29.4 Circ.Water Piping $0 $7,355 $7,015 $0 $0 $14,370 $1,324 $0 $2,354 $18,048 $339.5 Make-up Water System $749 $0 $993 $0 $0 $1,742 $165 $0 $286 $2,193 $49.6 Component Cooling Water Sys $728 $0 $575 $0 $0 $1,304 $122 $0 $214 $1,640 $39.9 Circ.Water System Foundations& Structures $0 $3,917 $6,267 $0 $0 $10,185 $959 $0 $2,229 $13,372 $24SUBTOTAL 9. $21,405 $11,272 $20,092 $0 $0 $52,768 $4,916 $0 $7,834 $65,518 $11910 ASH/SPENT SORBENT HANDLING SYS10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.6 Ash Storage Silos $723 $0 $2,231 $0 $0 $2,954 $288 $0 $324 $3,566 $610.7 Ash Transport & Feed Equipment $4,716 $0 $4,801 $0 $0 $9,517 $900 $0 $1,042 $11,458 $2110.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.9 Ash/Spent Sorbent Foundation $0 $171 $203 $0 $0 $373 $35 $0 $82 $490 $1SUBTOTAL 10. $5,440 $171 $7,234 $0 $0 $12,844 $1,223 $0 $1,448 $15,515 $28TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants372Exhibit 4-23 Case 10 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:09-May-07Project:Bituminous Baseline StudyCase:Case 10 - Subcritical PC w/ CO2Plant Size:549.6 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW11 ACCESSORY ELECTRIC PLANT11.1 Generator Equipment $1,672 $0 $274 $0 $0 $1,946 $180 $0 $159 $2,285 $411.2 Station Service Equipment $4,842 $0 $1,658 $0 $0 $6,499 $622 $0 $534 $7,655 $1411.3 Switchgear & Motor Control $5,754 $0 $986 $0 $0 $6,740 $624 $0 $736 $8,100 $1511.4 Conduit & Cable Tray $0 $3,695 $12,573 $0 $0 $16,268 $1,557 $0 $2,674 $20,498 $3711.5 Wire & Cable $0 $6,702 $13,245 $0 $0 $19,947 $1,681 $0 $3,244 $24,872 $4511.6 Protective Equipment $253 $0 $898 $0 $0 $1,152 $113 $0 $126 $1,391 $311.7 Standby Equipment $1,268 $0 $30 $0 $0 $1,298 $123 $0 $142 $1,563 $311.8 Main Power Transformers $7,000 $0 $185 $0 $0 $7,185 $546 $0 $773 $8,504 $1511.9 Electrical Foundations $0 $332 $821 $0 $0 $1,153 $110 $0 $253 $1,515 $3SUBTOTAL 11. $20,789 $10,729 $30,669 $0 $0 $62,187 $5,554 $0 $8,642 $76,384 $13912 INSTRUMENTATION & CONTROL12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $012.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $012.4 Other Major Component Control $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $012.5 Signal Processing Equipment W/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.6 Control Boards,Panels & Racks $469 $0 $292 $0 $0 $761 $73 $38 $131 $1,003 $212.7 Distributed Control System Equipment $4,731 $0 $861 $0 $0 $5,592 $533 $280 $640 $7,045 $1312.8 Instrument Wiring & Tubing $2,613 $0 $5,301 $0 $0 $7,914 $674 $396 $1,348 $10,331 $1912.9 Other I & C Equipment $1,337 $0 $3,161 $0 $0 $4,498 $438 $225 $516 $5,677 $10SUBTOTAL 12. $9,150 $0 $9,615 $0 $0 $18,765 $1,718 $938 $2,635 $24,056 $4413 IMPROVEMENTS TO SITE13.1 Site Preparation $0 $54 $1,084 $0 $0 $1,138 $112 $0 $250 $1,500 $313.2 Site Improvements $0 $1,786 $2,235 $0 $0 $4,022 $395 $0 $883 $5,300 $1013.3 Site Facilities $3,201 $0 $3,181 $0 $0 $6,382 $626 $0 $1,402 $8,410 $15SUBTOTAL 13. $3,201 $1,840 $6,500 $0 $0 $11,541 $1,133 $0 $2,535 $15,210 $2814 BUILDINGS & STRUCTURES14.1 Boiler Building $0 $8,723 $7,774 $0 $0 $16,497 $1,481 $0 $2,697 $20,676 $3814.2 Turbine Building $0 $12,815 $12,103 $0 $0 $24,918 $2,244 $0 $4,074 $31,236 $5714.3 Administration Building $0 $613 $657 $0 $0 $1,270 $115 $0 $208 $1,592 $314.4 Circulation Water Pumphouse $0 $281 $227 $0 $0 $508 $45 $0 $83 $636 $114.5 Water Treatment Buildings $0 $1,110 $926 $0 $0 $2,036 $182 $0 $333 $2,551 $514.6 Machine Shop $0 $410 $279 $0 $0 $689 $61 $0 $113 $863 $214.7 Warehouse $0 $278 $282 $0 $0 $560 $51 $0 $92 $702 $114.8 Other Buildings & Structures $0 $227 $196 $0 $0 $423 $38 $0 $69 $530 $114.9 Waste Treating Building & Str. $0 $435 $1,336 $0 $0 $1,771 $167 $0 $291 $2,229 $4SUBTOTAL 14. $0 $24,892 $23,781 $0 $0 $48,672 $4,385 $0 $7,959 $61,016 $111TOTAL COST $767,510 $57,483 $394,827 $0 $0 $1,219,819 $114,645 $56,977 $199,835 $1,591,277 $2,895TOTAL PLANT COST SUMMARYCost and Performance Comparison of Fossil Energy Power Plants

373 

### Exhibit 4-24 Case 10 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006 Case 10 - Subcritical PC w/ CO2 Heat Rate-net(Btu/kWh): 13,724 MWe-net: 550 Capacity Factor: (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 33.00 $/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 11.3 11.3 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL-O.J.'s 16.3 16.3 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,138,007 $11.168 Maintenance Labor Cost $10,295,213 $18.732 Administrative & Support Labor $4,108,305 $7.475 TOTAL FIXED OPERATING COSTS $20,541,525 $37.375 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $15,442,820 $0.00377

Consumables Consumption Unit Initial Initial /Day Cost Cost
Water(/1000 gallons) 0 10,151 1.03 $0 $3,243,688 $0.00079

Chemicals MU & WT Chem.(lb) 343,946 49,135 0.16 $56,682 $2,512,244 $0.00061 Limestone (ton) 5,372 767 20.60 $110,669 $4,905,029 $0.00120 Carbon (Mercury Removal) (lb) 0 0 0.00 $0 $0 $0.00000 MEA Solvent (ton) 1,174 1.67 2,142.40 $2,515,178 $1,108,686 $0.00027 NaOH (tons) 82 8.18 412.96 $33,863 $1,048,541 $0.00026 H2SO4 (tons) 79 7.91 132.15 $10,440 $324,224 $0.00008 Corrosion Inhibitor 0 0 0.00 $162,300 $7,730 $0.00000 Activated Carbon(lb) 0 1,992 1.00 $0 $618,018 $0.00015 Ammonia (28% NH3) ton 813 116 123.60 $100,439 $4,451,615 $0.00109 Subtotal Chemicals $2,989,571 $14,976,086 $0.00366

Other Supplemental Fuel(MBtu) 0 0 0.00 $0 $0 $0.00000 SCR Catalyst(m3) w/equip. 0.68 5,500.00 $0 $1,168,014 $0.00029 Emission Penalties 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $1,168,014 $0.00029

Waste Disposal Flyash (ton) 0 144 15.45 $0 $690,819 $0.00017 Bottom Ash(ton) 0 577 15.45 $0 $2,763,393 $0.00068 Subtotal-Waste Disposal $0 $3,454,212 $0.00084

By-products & Emissions Gypsum (tons) 0 1,196 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $2,989,571 $38,284,819 $0.00936

Fuel(ton) 232,764 7,759 42.11 $9,801,707 $101,365,989 $0.02477Cost and Performance Comparison of Fossil Energy Power Plants

374 

### 4.3 SUPERCRITICAL PC CASES
This section contains an eval ution of plant designs for Cases 11 and 12 which are based on a supercritical PC plant with a nominal net output of 550 MWe. Both plants use a single reheat 24.1 MPa/593°C/593°C (3500 psig/1100 ° F/1100 ° F) cycle. The only difference between the two plants is that Case 12 includes CO 2 

### capture while Case 11 does not.
The balance of Section 4.3 is organized in an analogous manner to the subcrtical PC section:

• Process and System Description for Case 11

• Key Assumptions for Cases 11 and 12

• Sparing Philosophy for Cases 11 and 12

• Performance Results for Case 11

• Equipment List for Case 11

• Cost Estimates for Case 11

• Process and System Description, Perform ance Results, Equipment List and Cost Estimates for Case 12

4.3.1 P ROCESS 

### D ESCRIPTION 

### In this section the supercritical PC process without CO 2 

### capture is described. The system description is nearly identical to the subcritical PC case without CO 2 

### capture but is repeated here for completeness. The description follo ws the block flow diagram (BFD) in Exhibit 4-25 and stream numbers reference the same Exhibit. The tables in Exhibit 4-26 provide process data for the numbered streams in the BFD. Coal (stream 6) and primary air (stream 4) ar e introduced into the bo iler through the wall-fired burners. Additional combustion air, including the overfire air, is provided by the forced draft fans (stream 2). The boiler operate s at a slight negative pressure so air leakage is into the boiler, and the infiltration air is accounted for in stream 5. Flue gas exits the boiler through the SCR reactor (stream 8) and is cooled to 177°C (350°F) in the combustion air preheater (not shown) before passing through a fabric filter for particulate removal (stream 10). An ID fan increases th e flue gas temperature to 188°C (370°F) and provides the motive force for the flue gas (stream 11) to pass through the FGD unit. FGD inputs and outputs include makeup water (stream 13), oxidation air (stream 14), limestone slurry (stream 12) and product gypsum (stream 15). The clean, saturated flue gas exiting the FGD unit (stream 16) passes to the plant stack and is discharged to atmosphereCost and Performance Comparisonof Fossil Energy Power Plants375Exhibit 4-25 Case 11 Process FlowDiagram, Supercritical Unit without CO2CaptureCost and Performance Comparison of Fossil Energy Power Plants

376 

### Exhibit 4-26 Case 11 Stream Table, Supercritical Unit without CO 2 

### Capture

1 2 3 4 567 8 V-L Mole Fractions Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 CO 2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 N 2 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 O 2 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 V-L Flow (lb mol /hr) 107,211 107,211 32,934 32,934 2,477 0 0 150,861

V-L Flow (lb/hr) 3,093,780 3,093,78 0 950,376 950,376 71,480 0 0 4,487,030 Solids Flowrate 0 0 0 0 0 411,282 7,976 31,905 Temperature (°F) 59 66 59 78 59 59 350 350

Pressure (psia) 14.70 15.25 14.70 16.14 14.70 14.70 14.40 14.40 Enthalpy (BTU/lb) A 13.1 14.9 13.1 17.7 13.1 11,676 51.4 135.6

Density (lb/ft 3 ) 0.08 0.08 0.08 0.08 0.08 --- --- 0.05 Avg. Molecular Weight 28.86 28.86 28.86 28.86 28.86 --- --- 29.74

9 10 11 12 13 14 15 16 V-L Mole Fractions Ar 0.0000 0.0087 0.0087 0.0000 0.0000 0.0092 0.0000 0.0080 CO 2 0.0000 0.1450 0.1450 0.0000 0.0000 0.0003 0.0016 0.1326 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0000 0.0870 0.0870 1.0000 1.0000 0.0099 0.9976 0.1669 N 2 0.0000 0.7324 0.7324 0.0000 0.0000 0.7732 0.0008 0.6690 O 2 0.0000 0.0247 0.0247 0.0000 0.0000 0.2074 0.0000 0.0235 SO 2 0.0000 0.0021 0.0021 0.0000 0.0000 0.0000 0.0000 0.0000 Total 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 V-L Flow (lb mol /hr) 0 150,861 150,861 5,111 24,381 1,705 14,140 167,129

V-L Flow (lb/hr) 0 4,487,030 4,487,0 30 92,067 439,223 49,200 255,432 4,789,380 Solids Flowrate 31,905 0 0 40,819 0 0 63,529 0 Temperature (°F) 350 350 370 59 60 59 134 134

Pressure (psia) 14.20 14.20 15.26 14.70 14.70 14.70 14.70 14.70 Enthalpy (BTU/lb) A 51.4 136.2 141.5 --- 33.3 13.1 87.0 139.1

Density (lb/ft 3 ) --- 0.05 0.05 62.62 62.59 0.08 36.10 0.07 Avg. Molecular Weight --- 29.74 29.74 18.02 18.02 28.86 18.06 28.66 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparison of Fossil Energy Power Plants

377 

### 4.3.2 K EY 

### S YSTEM 

### A SSUMPTIONS 

### System assumptions for Cases 11 and 12, supercritical PC with and without CO 2 

### capture, are compiled in Exhibit 4-27.
Exhibit 4-27 Supercritical PC Pl ant Study Configuration Matrix

Case 11 w/o CO 2 

### Capture Case 12 w/CO 2 

### Capture
Steam Cycle, MPa/°C/°C (psig/°F/°F) 24.1/593/593 (3500/1100/1100) 24.1/593/593 (3500/1100/1100) Coal Illinois No. 6 Illinois No. 6 Condenser pressure, mm Hg (in Hg) 50.8 (2) 50.8 (2) Boiler Efficiency, % 89 89 Cooling water to condenser, °C (oF) 16 (60) 16 (60) Cooling water from condenser, °C (oF) 27 (80) 27 (80) Stack temperature, °C (°F) 57 (135) 32 (89)

SO 2 

### Control Wet Limestone Forced Oxidation Wet Limestone Forced Oxidation FGD Efficiency, % (A) 98 98 (B, C)

NOx Control LNB w/OFA and SCR LNB w/OFA and SCR SCR Efficiency, % (A) 86 86 Ammonia Slip (end of catalyst life), ppmv 2 2

Particulate Control Fabric Filter Fabric Filter Fabric Filter efficiency, % (A) 99.8 99.8 Ash Distribution, Fly/Bottom 80% / 20% 80% / 20% Mercury Control Co-benefit Capture Co-benefit Capture Mercury removal efficiency, % (A) 90 90 CO 2 

### Control N/A Econamine FG Plus CO 2 

### Capture, % (A) N/A 90

CO 2 

### Sequestration N/A Off-site Saline Formation A. Removal efficiencies are based on the flue gas content B. An SO 2 

### polishing step is included to meet mo re stringent SOx content limits in the flue gas (< 10 ppmv) to reduce forma tion of amine heat stable salts during the CO 2 

### absorption process C. SO 2 

### exiting the post-FGD polishing step is absorbed in the CO 2 

### capture process making stack emissions negligibleCost and Performance Comparison of Fossil Energy Power Plants

378 

### Balance of Plant – Cases 11 and 12 The balance of plant assumptions are common to all cases and we re presented previously in Exhibit 4-6.

4.3.3 S PARING 

### P HILOSOPHY 

### Single trains are used throughout the design with exceptions wh ere equipment capacity requires an additional train. There is no redundancy othe r than normal sparing of rotating equipment. The plant design consists of the following major subsystems:

• One dry-bottom, wall-fired PC supercritical boiler (1 x 100%)

• Two SCR reactors (2 x 50%)

• Two single-stage, in-line, multi-comp artment fabric filters (2 x 50%)

• One wet limestone forced oxidation pos itive pressure absorber (1 x 100%)

• One steam turbine (1 x 100%)

• For Case 12 only, two parallel Econamine FG Plus CO 2 

### absorption systems, with each system consisting of two absorbers, stri ppers and ancillary equipment (2 x 50%)

4.3.4 C ASE 

### 11 P ERFORMANCE 

### R ESULTS 

### The plant produces a net output of 550 MWe at a net plant efficiency of 39.1 percent (HHV basis). Overall performance for the plant is summarized in Exhibit 4-28 which includes auxiliary power requirements.Cost and Performance Comparison of Fossil Energy Power Plants

379 

### Exhibit 4-28 Case 11 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) TOTAL (STEAM TURBINE) POWER, kWe 580,260 AUXILIARY LOAD SUMMARY, kWe (Note 1) Coal Handling and Conveying 410 Limestone Handling & Reagent Preparation 890 Pulverizers 2,800 Ash Handling 530 Primary Air Fans 1,310 Forced Draft Fans 1,660 Induced Draft Fans 7,130 SCR 50 Baghouse 100 FGD Pumps and Agitators 2,980 Econamine FG Plus Auxiliaries N/A CO 2 

### Compression N/A Miscellaneous Balance of Plant (Note 2) 2,000 Steam Turbine Auxiliaries 400 Condensate Pumps 790 Circulating Water Pumps 4,770 Cooling Tower Fans 2,460 Transformer Loss 1,830 TOTAL AUXILIARIES, kWe 30,110 NET POWER, kWe 550,150 Net Plant Efficiency (HHV) 39.1% Net Plant Heat Rate (Btu/kWh) 8,721 CONDENSER COOLING DUTY, 10 6 

### kJ/h (10 6 

### Btu/h) 2,314 (2,195) CONSUMABLES As-Received Coal Feed, kg/h (lb/h) 186,555 (411,282) Limestone Sorbent Feed, kg/h (lb/h) 18,515 (40,819) Thermal Input, kWt 1,406,161 Makeup Water, m 3 

### /min (gpm) 20.6 (5,441) Notes: 1. Boiler feed pumps are steam turbine driven 2. Includes plant control systems, lighti ng, HVAC and miscellanous low voltage loadsCost and Performance Comparison of Fossil Energy Power Plants

380 

### Environmental Performance The environmental targets for emissions of Hg, NOx, SO 2 

### and particulate matter were presented in Section 2.4. A summary of the plant ai r emissions for Case 11 is presented in Exhibit 4-29.

Exhibit 4-29 Case 11 Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)

SO 2 

### 0.036 (0.085) 1,373 (1,514) 0.318 (0.701) NO X 

### 0.030 (0.070) 1,134 (1,250) 0.263 (0.579) Particulates 0.006 (0.013) 211 (232) 0.049 (0.107)
Hg 0.49 x 10 -6 

### (1.14 x 10 -6 

### ) 0.018 (0.020) 4.3 x 10 -6 

### (9.4 x 10 -6 

### )

CO 2 

### 87.5 (203) 3,295,000 (3,632,000) 763 (1,681)

CO 2 1 

### 804 (1,773)

1 

### CO 2 

### emissions based on net power instead of gross power

SO 2 

### emissions are controlled using a wet limestone forced oxidation scrubber that achieves a removal efficiency of 98 percent. The byproduct cal cium sulfate is dewatered and stored on site. The wallboard grade material can potentially be marketed and sold, but since it is highly dependent on local market conditions, no byproduct credit was taken. The saturated flue gas exiting the scrubber is vent ed through the plant stack.
NOx emissions are controlled to about 0.5 lb/10 6 

### Btu through the use of LNBs and OFA. An SCR unit then further reduces the NOx c oncentration by 86 per cent to 0.07 lb/10 6 

### Btu.
Particulate emissions are controlled using a pulse jet fabric filter wh ich operates at an efficiency of 99.8 percent. Co-benefit capture results in a 90 per cent reduction of mercury emissions. CO 2 

### emissions represent the uncontro lled discharge from the process.
Exhibit 4-30 shows the overall water balance for the plant. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent) . The water usage represents only the contribution of raw water makeup. In so me cases the water demand is greater than raw water makeup because of internal water recycle streams. For example, the boiler feedwater blowdown stream is re-used as makeup to the cooling tower, thus reducing the raw water requirement by that amount.Cost and Performance Comparison of Fossil Energy Power Plants

381 

### Exhibit 4-30 Case 11 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle,

m 3 

### /min (gpm) Raw Water Makeup,

m 3 

### /min (gpm)
FGD Makeup 2.1 (546) 0 2.1 (546)
BFW Makeup 0.3 (73) 0 0.3 (73)
Cooling Tower Makeup 18.5 (4,895) 0.3 (73) 18.2 (4,822)
Total 20.9 (5,514) 0.3 (73) 20.6 (5,441)

Heat and Mass Balance Diagrams A heat and mass balance diagram is shown for the Case 11 PC boiler, the FGD unit and steam cycle in Exhibit 4-31. An overall plant energy balance is provided in tabular form in Exhibit 4-32. The power out is the steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 4-28) is calculated by multiplying th e power out by a generator efficiency of 98.4 percent.Cost and Performance Comparison of Fossil Energy Power Plants

382 

### This page intentionally left blankCost and Performance Comparisonof Fossil Energy Power Plants383Exhibit 4-31 Case 11 Heat and Mass Balance, Supercritical PC Boiler without CO2CaptureCost and Performance Comparisonof Fossil Energy Power Plants384This page intentionally left blankCost and Performance Comparison of Fossil Energy Power Plants

385 

### Exhibit 4-32 Case 11 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total
Heat In (MMBtu/hr) Coal 4,798.0 4.0 4,802.0 Ambient Air 53.1 53.1 Infiltration Air 0.9 0.9 Limestone 61.0 61.0 FGD Oxidant 0.6 0.6 Water 17.6 17.6 Auxiliary Power 102.0 102.0 Totals 4,798.0 137.3 102.0 5,037.3 Heat Out (MMBtu/hr) Bottom Ash 0.4 0.4 Fly Ash 1.6 1.6 Flue Gas Exhaust 666.1 666.1 Gypsum Slurry 27.7 27.7 Condenser 2,195.0 2,195.0 Process Losses (1) 135.1 135.1 Power 2,011.4 2,011.4 Totals 0.0 3,025.9 2,011.4 5,037.3 (1) Process Losses are calculated by difference a nd reflect various boiler, turbine, and other heat and work losses. Aspen flowsh eet balance is within 0.5 percent.Cost and Performance Comparison of Fossil Energy Power Plants

386 

### 4.3.5 C ASE 

### 11

– M AJOR 

### E QUIPMENT 

### L IST


### Major equipment items for the supercritical PC plant with no CO 2 

### capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 4.3.6. In general, the design c onditions include a 10 percent contingency for flows and heat duties and a 21 pe rcent contingency for heads on pumps and fans.
ACCOUNT 1 FUEL AND SORBENT HANDLING

Equipment No. Description Type Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0
3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0
5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0
8 Reclaim Hopper N/A 2 1
9 Feeder Vibratory 2 1
10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor reduction 2 0

14 As-Fired Coal Sampling System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0
17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 3 0

19 Limestone Truck Unloading Hopper N/A 1 0

20 Limestone Feeder Belt 1 0
21 Limestone Conveyor No. L1 Belt 1 0
22 Limestone Reclaim Hopper N/A 1 0

23 Limestone Reclaim Feeder Belt 1 0
24 Limestone Conveyor No. L2 Belt 1 0
25 Limestone Day Bin w/ actuator 2 0 36 tonne (40 ton)

82 tonne/h (90 tph)
82 tonne/h (90 tph)

245 tonne (270 ton)

18 tonne (20 ton)
64 tonne/h (70 tph)
64 tonne/h (70 tph) 726 tonne (800 ton) N/A

308 tonne/h (340 tph)

N/A 36 tonne (40 ton)
154 tonne/h (170 tph)

8 cm x 0 - 3 cm x 0 (3" x 0 - 1-1/4" x 0) 308 tonne/h (340 tph)

154 tonne (170 ton) N/A

308 tonne/h (340 tph)

Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph) N/A
1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)
1,134 tonne/h (1,250 tph)Cost and Performance Comparison of Fossil Energy Power Plants

387 

### ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED
Equipment No. Description Type Operating Qty. Spares

1 Coal Feeder Gravimetric 6 0

2 Coal Pulverizer Ball type or equivalent 6 0

3 Limestone Weigh Feeder Gravimetric 1 1
4 Limestone Ball Mill Rotary 1 1

5 Limestone Mill Slurry Tank with Agitator N/A 1 1

6 Limestone Mill Recycle Pumps Horizontal centrifugal 1 1

7 Hydroclone Classifier 4 active cyclones in a 5 cyclone bank 1 1

8 Distribution Box 2-way 1 1

9 Limestone Slurry Storage Tank with Agitator Field erected 1 1

10 Limestone Slurry Feed Pumps Horizontal centrifugal 1 1 439,111 liters (116,000 gal) 308 lpm @ 12m H2O (340 gpm @ 40 ft H2O)

N/A

218 lpm @ 9m H2O (240 gpm @ 30 ft H2O) 82 lpm (90 gpm) per cyclone

75,709 liters (20,000 gal) Design Condition

36 tonne/h (40 tph)

36 tonne/h (40 tph)

20 tonne/h (22 tph) 20 tonne/h (22 tph)Cost and Performance Comparison of Fossil Energy Power Plants

388 

### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment No. Description Type Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 2 0

2 Condensate Pumps Vertical canned 1 1

3 Deaerator and Storage Tank Horizontal spray type 1 0

4 Boiler Feed Pump and Steam Turbine Drive Barrel type, multistage, centrifugal 1 1

6 LP Feedwater Heater 1A/1B Horizontal U-tube 2 0

7 LP Feedwater Heater 2A/2B Horizontal U-tube 2 0

8 LP Feedwater Heater 3A/3B Horizontal U-tube 2 0

9 LP Feedwater Heater 4A/4B Horizontal U-tube 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 1 0

11 HP Feedwater Heater 7 Horizontal U-tube 1 0

12 HP Feedwater heater 8 Horizontal U-tube 1 0

13 Auxiliary Boiler Shop fabricated, water tube 1 0

14 Fuel Oil System No. 2 fuel oil for light off 1 0

15 Service Air Compressors Flooded Screw 2 1

16 Instrument Air Dryers Duplex, regenerative 2 1

17 Closed Cycle Cooling Heat Exchangers Shell and tube 2 0

18 Closed Cycle Cooling Water Pumps Horizontal centrifugal 2 1

19 Engine-Driven Fire Pump Vertical turbine, diesel engine 1 1

20 Fire Service Booster Pump Two-stage horizontal centrifugal 1 1

21 Raw Water Pumps Stainless steel, single suction 2 1

22 Filtered Water Pumps Stainless steel, single suction 2 1

23 Filtered Water Tank Vertical, cylindrical 1 0

24 Makeup Water Demineralizer Multi-media filter, cartridge filter, RO membrane assembly, electrodeionization unit 1 1

25 Liquid Waste Treatment System -- 1 0 Design Condition

1,097,778 liters (290,000 gal)

23,091 lpm @ 213 m H2O (6,100 gpm @ 700 ft H2O) 1,828,433 kg/h (4,031,000 lb/h) 5 min. tank 30,662 lpm @ 3,475 m H2O (8,100 gpm @ 11,400 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C (40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 689,461 kg/h (1,520,000 lb/h)

689,461 kg/h (1,520,000 lb/h)

689,461 kg/h (1,520,000 lb/h)

689,461 kg/h (1,520,000 lb/h)

1,827,979 kg/h (4,030,000 lb/h)
1,827,979 kg/h (4,030,000 lb/h)

1,135,632 liter (300,000 gal)

1,377,901 liter (364,000 gal)

606 lpm (160 gpm)

10 years, 24-hour storm 1,438 lpm @ 49 m H2O (380 gpm @ 160 ft H2O) 0 5 Startup Boiler Feed Pump, Electric Motor Driven Barrel type, multistage, centrifugal 9,085 lpm @ 3,475 m H2O (2,400 gpm @ 11,400 ft H2O) 1

53 MMkJ/h (50 MMBtu/h) each
20,820 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 1,827,979 kg/h (4,030,000 lb/h)

28 m3/min (1,000 scfm)

3,785 lpm @ 88 m H2O (1,000 gpm @ 290 ft H2O)

2,650 lpm @ 64 m H2O (700 gpm @ 210 ft H2O) 11,470 lpm @ 43 m H2O (3,030 gpm @ 140 ft H2O)Cost and Performance Comparison of Fossil Energy Power Plants

389 

### ACCOUNT 4 BOILER AND ACCESSORIES
Equipment No. Description Type Operatin g Qty. Spares

1 Boiler Supercritical, drum, wall-fired, low NOx burners, overfire air 1 0

2 Primary Air Fan Centrifugal 2 0

3 Forced Draft Fan Centrifugal 2 0

4 Induced Draft Fan Centrifugal 2 0

5 SCR Reactor Vessel Space for spare layer 2 0

6 SCR Catalyst -- 3 0

7 Dilution Air Blower Centrifugal 2 1

8 Ammonia Storage Horizontal tank 5 0

9 Ammonia Feed Pump Centrifugal 2 1 133 m3/min @ 108 cm WG (4,700 acfm @ 42 in. WG)
147,632 liter (39,000 gal)

28 lpm @ 91 m H2O (7 gpm @ 300 ft H2O) 1,119,467 kg/h, 23,769 m3/min @ 90 cm WG (2,468,000 lb/h, 839,400 acfm @ 36 in. WG)
2,240,749 kg/h (4,940,000 lb/h)

-- Design Condition

1,827,979 kg/h steam @ 24.1 MPa/593°C/593°C (4,030,000 lb/h steam @ 3,500 psig/1,100°F/1,100°F)

237,229 kg/h, 3,245 m3/min @

123 cm WG (523,000 lb/h, 114,600 acfm @ 48 in. WG)
772,015 kg/h, 10,568 m3/min @

47 cm WG (1,702,000 lb/h, 373,200 acfm @ 19 in. WG)Cost and Performance Comparison of Fossil Energy Power Plants

390 

### ACCOUNT 5 FLUE GAS CLEANUP
Equipment No. Description Type Operatin g Qty. Spares

1 Fabric Filter Single stage, highratio with pulsejet online cleaning system 2 0

2 Absorber Module Counter-current
open spray 1 0

3 Recirculation Pumps Horizontal centrifugal 5 1

4 Bleed Pumps Horizontal centrifugal 2 1

5 Oxidation Air Blowers Centrifugal 2 1

6 Agitators Side entering 5 1

7 Dewatering Cyclones Radial assembly, 5 units each 2 0

8 Vacuum Filter Belt Horizontal belt 2 1

9 Filtrate Water Return Pumps Horizontal centrifugal 1 1

10 Filtrate Water Return Storage Tank Vertical, lined 1 0

11 Process Makeup Water Pumps Horizontal centrifugal 1 1 168 m3/min @ 0.3 MPa (5,930 acfm @ 42 psia)

32 tonne/h (35 tph) 50 wt % slurry 4,013 lpm (1,060 gpm) at 20 wt% solids

50 hp

1,022 lpm (270 gpm) per cyclone

606 lpm @ 12 m H2O (160 gpm @ 40 ft H2O)

416,399 lpm (110,000 gal)

2,271 lpm @ 21 m H2O (600 gpm @ 70 ft H2O) Design Condition

1,119,467 kg/h (2,468,000 lb/h) 99.8% efficiency

37,662 m3/min (1,330,000 acfm)

132,490 lpm @ 64 m H2O (35,000 gpm @ 210 ft H2O)



### ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES
N/A

ACCOUNT 7 HRSG, DUCTING & STACK

Equipment No. Description Type Operating Qty. Spares

1 Stack Reinforced concrete with FRP liner 1 0 Design Condition

152 m (500 ft) high x 5.8 m (19 ft) diameterCost and Performance Comparison of Fossil Energy Power Plants

391 

### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitation 1 0

3 Surface Condenser Single pass, divided waterbox including
vacuum pumps 1 0 680 MVA @ 0.9 p.f., 24 kV, 60 Hz Design Condition

610 MW 24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F)

2,541 MMkJ/h (2,410 MMBtu/h), Inlet water temperature 16oC (60oF),

Water temperature rise 11oC (20oF)



### ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 2 1

2 Cooling Tower Evaporative, mechanical draft, multi-cell 1 0 Design Condition

476,966 lpm @ 30.5 m (126,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT 2,657 MMkJ/h (2,520 MMBtu/h) heat loadCost and Performance Comparison of Fossil Energy Power Plants

392 

### ACCOUNT 10 ASH/SPENT SORBEN T RECOVERY AND HANDLING
Equipment No. Description Type Operating Qty. Spares

1 Economizer Hopper (part of boiler scope of supply) -- 4 0

2 Bottom Ash Hopper (part of boiler scope of supply) -- 2 0

3 Clinker Grinder -- 1 1

4 Pyrites Hopper (part of pulverizer scope of supply included with boiler) -- 6 0

5 Hydroejectors -- 12

6 Economizer /Pyrites Transfer Tank -- 1 0

7 Ash Sluice Pumps Vertical, wet pit 1 1

8 Ash Seal Water Pumps Vertical, wet pit 1 1

9 Hydrobins -- 1 1

10 Baghouse Hopper (part of baghouse scope of supply) -- 24 0

11 Air Heater Hopper (part of boiler scope of supply) -- 10 0

12 Air Blower -- 1 1

13 Fly Ash Silo Reinforced
concrete 2 0

14 Slide Gate Valves -- 2 0

15 Unloader -- 1 0

16 Telescoping Unloading Chute -- 1 0 151 lpm (40 gpm)

--

--

-- --

14 m3/min @ 0.2 MPa

(510 scfm @ 24 psi)

499 tonne (1,100 ton)

91 tonne/h (100 tph) --

--
151 lpm @ 17 m H2O (40 gpm @ 56 ft H2O)

7,571 lpm @ 9 m H2O (2000 gpm @ 28 ft H2O) -- Design Condition

--

--
3.6 tonne/h (4 tph)Cost and Performance Comparison of Fossil Energy Power Plants

393 

### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type Operating Qty. Spares

1 STG Transformer Oil-filled 1 0

2 Auxiliary Transformer Oil-filled 1 1

3 Low Voltage Transformer Dry ventilated 1 1

4 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 1 0

5 Medium Voltage Switchgear Metal clad 1 1

6 Low Voltage Switchgear Metal enclosed 1 1

7 Emergency Diesel Generator Sized for emergency shutdown 1 0 24 kV/4.16 kV, 10 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 5 MVA, 3-ph, 60 Hz Design Condition
24 kV/345 kV, 640 MVA, 3-ph, 60 Hz

750 kW, 480 V, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz



### ACCOUNT 12 INSTRUMENTATION AND CONTROL

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) 1 0

3 DCS - Data Highway Fiber optic 1 0 1 0

Fully redundant, 25% spare Design Condition

Operator stations/printers and engineering stations/printers

2 DCS - Processor Microprocessor with redundant input/output N/ACost and Performance Comparison of Fossil Energy Power Plants

394 

### 4.3.6 C ASE 

### 11

– C OSTS 

### E STIMATING 

### R ESULTS 

### The cost estimating methodology was desc ribed previously in Section 2.6. Exhibit 4-33 shows the total plant capital cost summary organized by cost account and Exhibit 4-34 shows a more detailed breakdown of the capital costs. Exhibit 4-35 shows the ini tial and annual O&M costs. The estimated TPC of the supe rcritical PC boiler with no CO 2 

### capture is $1,574/kW. No process contingency was included in this case because all elements of the technology are commercially proven. The project contingency is 10.7 percen t of the TPC. The 20-year LCOE is 63.3 mills/kWh.Cost and Performance Comparisonof Fossil Energy Power Plants395Exhibit 4-33 Case 11 Total Plant Cost SummaryClient:USDOE/NETLReport Date:09-May-07Project:Bituminous Baseline StudyCase:Case 11 - Supercritical PC w/o CO2Plant Size:550.2 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING $15,481 $4,183 $9,376 $0 $0$29,040$2,602 $0 $4,746$36,389$662 COAL & SORBENT PREP & FEED $10,405 $603 $2,638 $0 $0$13,646$1,196 $0 $2,226$17,068$313 FEEDWATER & MISC. BOP SYSTEMS $40,107 $0 $18,856 $0 $0$58,963$5,369 $0 $10,462$74,795$1364 PC BOILER4.1 PC Boiler & Accessories $148,766 $0 $83,888 $0 $0$232,654$22,535 $0 $25,519$280,708$5104.2 SCR (w/4.1) $0 $0 $0 $0 $0$0$0 $0 $0$0$04.3 Open $0 $0 $0 $0 $0$0$0 $0 $0$0$04.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0$0$0 $0 $0$0$0SUBTOTAL 4 $148,766 $0 $83,888 $0 $0 $232,654 $22,535 $0 $25,519 $280,708 $5105 FLUE GAS CLEANUP $78,075 $0 $26,700 $0 $0$104,775$9,955 $0 $11,473$126,203$2296 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator N/A $0 N/A $0 $0$0$0 $0 $0$0$06.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0$0$0 $0 $0$0$0SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0$0$0 $0 $0$0$07.2-7.9 HRSG Accessories, Ductwork and Stack $16,653 $959 $11,402 $0 $0$29,013$2,656 $0 $4,132$35,801$65SUBTOTAL 7 $16,653 $959 $11,402 $0 $0 $29,013 $2,656 $0 $4,132 $35,801 $658 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $48,728 $0 $6,532 $0 $0$55,260$5,291 $0 $6,055$66,606$1218.2-8.9 Turbine Plant Auxiliaries and Steam Piping $23,094 $1,042 $12,656 $0 $0$36,792$3,213 $0 $5,619$45,625$83SUBTOTAL 8 $71,822 $1,042 $19,188 $0 $0 $92,052 $8,504 $0 $11,675 $112,231 $2049 COOLING WATER SYSTEM $11,816 $6,553 $11,613 $0 $0$29,981$2,799 $0 $4,503$37,283$6810 ASH/SPENT SORBENT HANDLING SYS $4,232 $133 $5,628 $0 $0$9,992$951 $0 $1,126$12,069$2211 ACCESSORY ELECTRIC PLANT $15,533 $5,832 $17,190 $0 $0$38,556$3,411 $0 $5,217$47,183$8612 INSTRUMENTATION & CONTROL $8,069 $0 $8,480 $0 $0$16,549$1,515 $0 $2,222$20,285$3713 IMPROVEMENTS TO SITE $2,827 $1,625 $5,741 $0 $0$10,194$1,001 $0 $2,239$13,434$2414 BUILDINGS & STRUCTURES $0 $21,560 $20,672 $0 $0$42,232$3,805 $0 $6,906$52,943$96TOTAL COST $423,786 $42,490 $241,370 $0 $0 $707,646 $66,300 $0 $92,445 $866,391 $1,575TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants396Exhibit 4-34 Case 11 Total Plant Cost DetailsClient:USDOE/NETLReport Date:09-May-07Project:Bituminous Baseline StudyCase:Case 11 - Supercritical PC w/o CO2Plant Size:550.2 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING1.1 Coal Receive & Unload $3,183 $0 $1,469 $0 $0 $4,652 $415 $0 $760 $5,827 $111.2 Coal Stackout & Reclaim $4,113 $0 $942 $0 $0 $5,055 $442 $0 $825 $6,322 $111.3 Coal Conveyors $3,824 $0 $932 $0 $0 $4,756 $417 $0 $776 $5,949 $111.4 Other Coal Handling $1,001 $0 $216 $0 $0 $1,216 $106 $0 $198 $1,521 $31.5 Sorbent Receive & Unload $127 $0 $39 $0 $0 $166 $15 $0 $27 $208 $01.6 Sorbent Stackout & Reclaim $2,056 $0 $381 $0 $0 $2,437 $212 $0 $397 $3,047 $61.7 Sorbent Conveyors $734 $158 $182 $0 $0 $1,073 $93 $0 $175 $1,341 $21.8 Other Sorbent Handling $443 $103 $235 $0 $0 $781 $69 $0 $128 $978 $21.9 Coal & Sorbent Hnd.Foundations $0 $3,922 $4,982 $0 $0 $8,904 $832 $0 $1,460 $11,197 $20SUBTOTAL 1. $15,481 $4,183 $9,376 $0 $0 $29,040 $2,602 $0 $4,746 $36,389 $662 COAL & SORBENT PREP & FEED2.1 Coal Crushing & Drying $1,823 $0 $359 $0 $0 $2,182 $190 $0 $356 $2,728 $52.2 Coal Conveyor to Storage $4,668 $0 $1,030 $0 $0 $5,698 $498 $0 $929 $7,125 $132.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.5 Sorbent Prep Equipment $3,493 $150 $733 $0 $0 $4,376 $381 $0 $714 $5,470 $102.6 Sorbent Storage & Feed $421 $0 $163 $0 $0 $584 $52 $0 $95 $731 $12.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.9 Coal & Sorbent Feed Foundation $0 $453 $353 $0 $0 $807 $74 $0 $132 $1,013 $2SUBTOTAL 2. $10,405 $603 $2,638 $0 $0 $13,646 $1,196 $0 $2,226 $17,068 $313 FEEDWATER & MISC. BOP SYSTEMS3.1 FeedwaterSystem $17,490 $0 $5,725 $0 $0 $23,214 $2,033 $0 $3,787 $29,034 $533.2 Water Makeup & Pretreating $4,278 $0 $1,376 $0 $0 $5,654 $530 $0 $1,237 $7,420 $133.3 Other Feedwater Subsystems $5,404 $0 $2,293 $0 $0 $7,697 $686 $0 $1,257 $9,641 $183.4 Service Water Systems $844 $0 $456 $0 $0 $1,300 $121 $0 $284 $1,705 $33.5 Other Boiler Plant Systems $6,403 $0 $6,264 $0 $0 $12,667 $1,188 $0 $2,078 $15,933 $293.6 FO Supply Sys & Nat Gas $247 $0 $304 $0 $0 $551 $51 $0 $90 $692 $13.7 Waste Treatment Equipment $2,883 $0 $1,652 $0 $0 $4,535 $439 $0 $995 $5,969 $113.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,558 $0 $788 $0 $0 $3,346 $321 $0 $733 $4,400 $8SUBTOTAL 3. $40,107 $0 $18,856 $0 $0 $58,963 $5,369 $0 $10,462 $74,795 $1364 PC BOILER4.1 PC Boiler & Accessories $148,766 $0 $83,888 $0 $0 $232,654 $22,535 $0 $25,519 $280,708 $5104.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 4. $148,766 $0 $83,888 $0 $0 $232,654 $22,535 $0 $25,519 $280,708 $510TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants397Exhibit 4-34 Case 11 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:09-May-07Project:Bituminous Baseline StudyCase:Case 11 - Supercritical PC w/o CO2Plant Size:550.2 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW5 FLUE GAS CLEANUP5.1 Absorber Vessels & Accessories $54,227 $0 $11,683 $0 $0 $65,910 $6,238 $0 $7,215 $79,363 $1445.2 Other FGD $2,830 $0 $3,209 $0 $0 $6,039 $582 $0 $662 $7,283 $135.3 Bag House & Accessories $15,654 $0 $9,942 $0 $0 $25,596 $2,448 $0 $2,804 $30,849 $565.4 Other Particulate Removal Materials $1,059 $0 $1,134 $0 $0 $2,194 $211 $0 $241 $2,646 $55.5 Gypsum Dewatering System $4,304 $0 $732 $0 $0 $5,036 $476 $0 $551 $6,063 $115.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 5. $78,075 $0 $26,700 $0 $0 $104,775 $9,955 $0 $11,473 $126,203 $2296 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $06.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $07.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07.3 Ductwork $8,242 $0 $5,379 $0 $0 $13,621 $1,190 $0 $2,222 $17,033 $317.4 Stack $8,411 $0 $4,925 $0 $0 $13,336 $1,274 $0 $1,461 $16,071 $297.9 Duct & Stack Foundations $0 $959 $1,097 $0 $0 $2,056 $192 $0 $449 $2,697 $5SUBTOTAL 7. $16,653 $959 $11,402 $0 $0 $29,013 $2,656 $0 $4,132 $35,801 $658 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $48,728 $0 $6,532 $0 $0 $55,260 $5,291 $0 $6,055 $66,606 $1218.2 Turbine Plant Auxiliaries $334 $0 $716 $0 $0 $1,050 $102 $0 $115 $1,268 $28.3 Condenser & Auxiliaries $6,405 $0 $2,204 $0 $0 $8,610 $818 $0 $943 $10,370 $198.4 Steam Piping $16,354 $0 $8,078 $0 $0 $24,433 $2,039 $0 $3,971 $30,443 $558.9 TG Foundations $0 $1,042 $1,658 $0 $0 $2,699 $254 $0 $591 $3,544 $6SUBTOTAL 8. $71,822 $1,042 $19,188 $0 $0 $92,052 $8,504 $0 $11,675 $112,231 $2049 COOLING WATER SYSTEM9.1 Cooling Towers $8,669 $0 $2,702 $0 $0 $11,371 $1,079 $0 $1,245 $13,695 $259.2 Circulating Water Pumps $1,765 $0 $111 $0 $0 $1,876 $160 $0 $204 $2,239 $49.3 Circ.Water System Auxiliaries $515 $0 $69 $0 $0 $583 $55 $0 $64 $702 $19.4 Circ.Water Piping $0 $4,150 $3,958 $0 $0 $8,108 $747 $0 $1,328 $10,183 $199.5 Make-up Water System $457 $0 $605 $0 $0 $1,062 $101 $0 $174 $1,337 $29.6 Component Cooling Water Sys $411 $0 $324 $0 $0 $735 $69 $0 $121 $924 $29.9 Circ.Water System Foundations& Structures $0 $2,403 $3,844 $0 $0 $6,247 $588 $0 $1,367 $8,202 $15SUBTOTAL 9. $11,816 $6,553 $11,613 $0 $0 $29,981 $2,799 $0 $4,503 $37,283 $6810 ASH/SPENT SORBENT HANDLING SYS10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.6 Ash Storage Silos $563 $0 $1,735 $0 $0 $2,298 $224 $0 $252 $2,774 $510.7 Ash Transport & Feed Equipment $3,669 $0 $3,735 $0 $0 $7,403 $700 $0 $810 $8,914 $1610.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.9 Ash/Spent Sorbent Foundation $0 $133 $158 $0 $0 $291 $27 $0 $64 $381 $1SUBTOTAL 10. $4,232 $133 $5,628 $0 $0 $9,992 $951 $0 $1,126 $12,069 $22TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants398Exhibit 4-34 Case 11 Total Plant Cost Details(Continued)Client:USDOE/NETLReport Date:09-May-07Project:Bituminous Baseline StudyCase:Case 11 - Supercritical PC w/o CO2Plant Size:550.2 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW11 ACCESSORY ELECTRIC PLANT11.1 Generator Equipment $1,524 $0 $249 $0 $0 $1,773 $164 $0 $145 $2,083 $411.2 Station Service Equipment $2,578 $0 $882 $0 $0 $3,460 $331 $0 $284 $4,075 $711.3 Switchgear & Motor Control $3,063 $0 $525 $0 $0 $3,588 $332 $0 $392 $4,312 $811.4 Conduit & Cable Tray $0 $1,967 $6,693 $0 $0 $8,660 $829 $0 $1,423 $10,913 $2011.5 Wire & Cable $0 $3,568 $7,051 $0 $0 $10,619 $895 $0 $1,727 $13,241 $2411.6 Protective Equipment $243 $0 $861 $0 $0 $1,104 $108 $0 $121 $1,333 $211.7 Standby Equipment $1,176 $0 $28 $0 $0 $1,204 $114 $0 $132 $1,450 $311.8 Main Power Transformers $6,950 $0 $165 $0 $0 $7,116 $541 $0 $766 $8,422 $1511.9 Electrical Foundations $0 $297 $735 $0 $0 $1,032 $98 $0 $226 $1,356 $2SUBTOTAL 11. $15,533 $5,832 $17,190 $0 $0 $38,556 $3,411 $0 $5,217 $47,183 $8612 INSTRUMENTATION & CONTROL12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $012.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $012.4 Other Major Component Control $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $012.5 Signal Processing Equipment W/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.6 Control Boards,Panels & Racks $413 $0 $258 $0 $0 $671 $65 $0 $110 $846 $212.7 Distributed Control System Equipment $4,172 $0 $760 $0 $0 $4,932 $470 $0 $540 $5,942 $1112.8 Instrument Wiring & Tubing $2,305 $0 $4,674 $0 $0 $6,979 $594 $0 $1,136 $8,710 $1612.9 Other I & C Equipment $1,179 $0 $2,787 $0 $0 $3,966 $386 $0 $435 $4,788 $9SUBTOTAL 12. $8,069 $0 $8,480 $0 $0 $16,549 $1,515 $0 $2,222 $20,285 $3713 IMPROVEMENTS TO SITE13.1 Site Preparation $0 $48 $958 $0 $0 $1,005 $99 $0 $221 $1,325 $213.2 Site Improvements $0 $1,578 $1,974 $0 $0 $3,552 $349 $0 $780 $4,681 $913.3 Site Facilities $2,827 $0 $2,809 $0 $0 $5,637 $553 $0 $1,238 $7,428 $14SUBTOTAL 13. $2,827 $1,625 $5,741 $0 $0 $10,194 $1,001 $0 $2,239 $13,434 $2414 BUILDINGS & STRUCTURES14.1 Boiler Building $0 $7,843 $6,990 $0 $0$14,833 $1,332 $0 $2,425 $18,590 $3414.2 Turbine Building $0 $11,220 $10,597 $0$0 $21,817 $1,964 $0 $3,567 $27,348 $5014.3 Administration Building $0 $554 $594 $0 $0 $1,147 $104 $0 $188 $1,439 $314.4 Circulation Water Pumphouse $0 $159 $128 $0 $0 $286 $26 $0 $47 $359 $114.5 Water Treatment Buildings $0 $565 $471 $0 $0 $1,036 $93 $0 $169 $1,299 $214.6 Machine Shop $0 $370 $252 $0 $0 $623 $55 $0 $102 $780 $114.7 Warehouse $0 $251 $255 $0 $0 $506 $46 $0 $83 $635 $114.8 Other Buildings & Structures $0 $205 $177 $0 $0 $382 $34 $0 $62 $479 $114.9 Waste Treating Building & Str. $0 $393 $1,208 $0 $0 $1,601 $151 $0 $263 $2,015 $4SUBTOTAL 14. $0 $21,560 $20,672 $0 $0 $42,232 $3,805 $0 $6,906 $52,943 $96TOTAL COST $423,786 $42,490 $241,370 $0 $0 $707,646 $66,300 $0 $92,445 $866,391 $1,575TOTAL PLANT COST SUMMARYCost and Performance Comparison of Fossil Energy Power Plants

399 

### Exhibit 4-35 Case 11 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006 Case 11 - Supercritical PC w/o CO2 Heat Rate-net(Btu/kWh): 8,721 MWe-net: 550 Capacity Factor: (%): 85 OPERATING & MAINTENANCE LABOR

Operating Labor Operating Labor Rate(base): 33.00 $/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 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL-O.J.'s 14.0 14.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $5,261,256 $9.563 Maintenance Labor Cost $5,818,574 $10.576 Administrative & Support Labor $2,769,958 $5.035 TOTAL FIXED OPERATING COSTS $13,849,788 $25.175 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $8,727,862 $0.00213

Consumables Consumption Unit Initial Initial /Day Cost Cost
Water(/1000 gallons) 0 3,918 1.03 $0 $1,251,873 $0.00031

Chemicals MU & WT Chem.(lb) 132,743 18,963 0.16 $21,876 $969,578 $0.00024 Limestone (ton) 3,429 490 20.60 $70,633 $3,130,564 $0.00076 Carbon (Mercury Removal) (lb) 0 0 1.00 $0 $0 $0.00000 MEA Solvent (ton) 0 0 2,142.40 $0 $0 $0.00000 NaOH (tons) 0 0 412.96 $0 $0 $0.00000 H2SO4 (tons) 0 0 132.15 $0 $0 $0.00000 Corrosion Inhibitor 0 0 0.00 $0 $0 $0.00000 Activated Carbon(lb) 0 0 1.00 $0 $0 $0.00000 Ammonia (28% NH3) ton 517 74 123.60 $63,883 $2,831,382 $0.00069 Subtotal Chemicals $156,392 $6,931,524 $0.00169

Other Supplemental Fuel(MBtu) 0 0 0.00 $0 $0 $0.00000 SCR Catalyst(m3) w/equip. 0.44 5,500.00 $0 $747,563 $0.00018 Emission Penalties 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $747,563 $0.00018

Waste Disposal Flyash (ton) 0 96 15.45 $0 $458,782 $0.00011 Bottom Ash(ton) 0 383 15.45 $0 $1,835,187 $0.00045 Subtotal-Waste Disposal $0 $2,293,969 $0.00056

By-products & Emissions Gypsum (tons) 0 739 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $156,392 $19,952,791 $0.00487

Fuel(ton) 148,057 4,935 42.11 $6,234,675 $64,476,927 $0.01574Cost and Performance Comparison of Fossil Energy Power Plants

400 

### 4.3.7 C ASE 

### 12

– S UPERCRITICAL 

### PC WITH 

### CO 2 

### C APTURE 

### The plant configuration for Case 12, supercritical PC, is the same as Case 11 with the exception that the Econamine FG Plus CDR technology was added for CO 2 

### capture. The nominal net output is maintained at 550 MW by increasing the boiler size and turbine/generator size to account for the greater auxiliar y load imposed by the CDR fa cility. Unlike the IGCC cases where gross output was fixed by th e available size of the combustion turbines, the PC cases utilize boilers and steam turbines that can be procured at nearly any desired output making it possible to maintain a constant net output. The process description for Case 12 is essent ially the same as Case 11 with one notable exception, the addition of CO 2 

### capture. A BFD and stream tables for Case 12 are shown in Exhibit 4-36 and Exhibit 4-37, respectively. Since the CD R facility process description was provided in Section 4.1.7, it is not repeated here.

4.3.8 C ASE 

### 12 P ERFORMANCE 

### R ESULTS 

### The Case 12 modeling assumptions were presented previously in Section 4.3.2. The plant produces a net output of 546 MW at a net plant efficiency of 27.2 percent (HHV basis). Overall plant performance is summarized in Exhibit 4-38 which includes auxiliary power requirements. The CDR facility, including CO 2 

### compression, accounts for over 58 percent of the auxiliary plant load. The circ ulating water system (circulati ng water pumps and cooling tower fan) accounts for over 15 percent of the auxiliar y load, largely due to the high cooling water demand of the CDR facility.Cost and Performance Comparisonof Fossil Energy Power Plants401Exhibit 4-36 Case 12 Process FlowDiagram, Supercritical Unit with CO2CaptureFORCEDDRAFTFANSBAGHOUSEFGDINDUCEDDRAFTFANSSTACK GASSTACKGYPSUMLIMESTONESLURRYOXIDATIONAIRMAKEUPWATERBOTTOMASHCOALFEEDINFILTRATIONAIR812PRIMARYAIRFANS346579FLYASH10111314121516AIRCOMBUSTIONPRODUCTSWATERCOAL/ASHSOLID/WATERSLURRYLEGENDPULVERIZEDCOALBOILERSCRECONAMINEFG+171821CO2COMPRESSOR1920CO2PRODUCTREBOILERSTEAMCONDENSATERETURNCO2HPTURBINEIPTURBINELP TURBINECONDENSERFEEDWATERHEATERSYSTEM663.4 MWeMAINSTEAMCOLDREHEATHOTREHEATBOILERFEEDWATERCost and Performance Comparisonof Fossil Energy Power Plants402Exhibit 4-37 Case 12 Stream Table, Supercritical Unit with CO2Capture1 2 3 4 5 6 7 8 9 10 11V-L Mole FractionsAr 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087CO20.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450H20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000H2O0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870N20.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324O20.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247SO20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000V-L Flow (lbmol/hr)153,570 153,570 47,175 47,175 2,650 0 0 215,146 0 215,146 215,146V-L Flow (lb/hr) 4,431,560 4,431,560 1,361,330 1,361,330 76,466 0 0 6,399,090 0 6,399,090 6,399,090Solids Flowrate 0 0 0 0 0 586,627 11,377 45,507 45,507 0 0Temperature (°F) 59 66 59 78 59 59 350 350 350 350 370Pressure (psia) 14.70 15.25 14.70 16.14 14.70 14.70 14.40 14.40 14.20 14.20 15.26Enthalpy (BTU/lb)A13.1 14.9 13.1 17.7 13.1 11,676 51.4 135.6 51.4 136.2 141.5Density (lb/ft3)0.08 0.08 0.08 0.08 0.08 --- --- 0.05 --- 0.05 0.05Avg. Molecular Weight 28.86 28.86 28.86 28.86 28.86 --- --- 29.74 --- 29.74 29.7412 13 14 15 16 17 18 19 20 21V-L Mole FractionAr 0.0000 0.0000 0.0092 0.0000 0.0080 0.0000 0.0000 0.0000 0.0000 0.0109CO20.0000 0.0000 0.0003 0.0015 0.1326 0.0000 0.0000 0.9862 1.0000 0.0180H20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000H2O1.0000 1.0000 0.0099 0.9977 0.1668 1.0000 1.0000 0.0138 0.0000 0.0281N20.0000 0.0000 0.7732 0.0008 0.6690 0.0000 0.0000 0.0000 0.0000 0.9109O20.0000 0.0000 0.2074 0.0000 0.0235 0.0000 0.0000 0.0000 0.0000 0.0320SO20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000V-L Flowrate (lbmol/hr)7,537 34,486 2,535 20,128 238,453 100,792 100,792 28,856 28,458 175,090V-L Flowrate (lb/hr) 135,788 621,279 73,155 363,564 6,833,360 1,815,800 1,815,800 1,259,600 1,252,440 4,951,450Solids Flowrate (lb/hr) 58,054 0 0 90,446 0 0 0 0 0 0Temperature (°F) 59 60 59 135 135 692 348 69 124 74Pressure (psia) 14.70 14.70 14.70 15.20 15.20 130.86 130.86 23.52 2215.00 14.70Enthalpy (BTU/lb)A--- 33.3 13.1 88.0 139.4 1373.8 319.5 11.4 -70.8 29.6Density (lb/ft3)62.62 62.59 0.08 39.94 0.07 0.19 55.67 0.18 40.76 0.07Molecular Weight 18.02 18.02 28.86 18.06 28.66 18.02 18.02 43.65 44.01 28.28A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparison of Fossil Energy Power Plants

403 

### Exhibit 4-38 Case 12 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) TOTAL (STEAM TURBINE) POWER, kWe 663,445 AUXILIARY LOAD SUMMARY, kWe (Note 1) Coal Handling and Conveying 490 Limestone Handling & Reagent Preparation 1,270 Pulverizers 3,990 Ash Handling 760 Primary Air Fans 1,870 Forced Draft Fans 2,380 Induced Draft Fans 10,120 SCR 70 Baghouse 100 FGD Pumps and Agitators 4,250 Econamine FG Plus Auxiliaries 21,320 CO 2 

### Compression 46,900 Miscellaneous Balance of Plant (Note 2) 2,000 Steam Turbine Auxiliaries 400 Condensate Pumps 630 Circulating Water Pumps 12,260 Cooling Tower Fans 6,340 Transformer Loss 2,300 TOTAL AUXILIARIES, kWe 117,450 NET POWER, kWe 545,995 Net Plant Efficiency (HHV) 27.2% Net Plant Heat Rate (Btu/kWh) 12,534 CONDENSER COOLING DUTY, 10 6 

### kJ/h (10 6 

### Btu/h) 1,884 (1,787) CONSUMABLES As-Received Coal Feed, kg/h (lb/h) 266,090 (586,627) Limestone Sorbent Feed, kg/h (lb/h) 26,333 (58,054) Thermal Input, kWt 2,005,660 Makeup Water, m 3 

### /min (gpm) 46.0 (12,159) Notes: 1. Boiler feed pumps are steam turbine driven 2. Includes plant control systems, lighti ng, HVAC and miscellanous low voltage loadsCost and Performance Comparison of Fossil Energy Power Plants

404 

### Environmental Performance The environmental targets for emissions of Hg, NOx, SO 2 

### , and particulate matter were presented in Section 2.4. A summary of the plant ai r emissions for Case 12 is presented in Exhibit 4-39.

Exhibit 4-39 Case 12 Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)

SO 2 

### Negligible Negligible Negligible NO X 

### 0.030 (0.070) 1,618 (1,784) 0.328 (0.722) Particulates 0.006 (0.013) 300 (331) 0.061 (0.134)
Hg 0.49 x 10 -6 

### (1.14 x 10 -6 

### ) 0.026 (0.029) 5.3 x 10 -6 

### (11.8 x 10 -6 

### ) CO 2 

### 8.7 (20) 468,000 (516,000) 95 (209)
CO 2 1 

### 115 (254)

1 

### CO 2 

### emissions based on net power instead of gross power

SO 2 

### emissions are controlled using a wet limestone forced oxidation scrubber that achieves a removal efficiency of 98 percent. The byproduct cal cium sulfate is dewatered and stored on site. The wallboard grade material can potentially be marketed and sold, but since it is highly dependent on local market conditions, no byproduct credit was taken. The SO 2 

### emissions are further reduced to 10 ppmv using a NaOH based polishing scrubber in the CDR facility. The remaining low concentration of SO 2 

### is essentially completely removed in the CDR absorber vessel resulting in negligible SO 2 

### emissions.
NOx emissions are controlled to about 0.5 lb/10 6 

### Btu through the use of LNBs and OFA. An SCR unit then further reduces the NOx c oncentration by 86 per cent to 0.07 lb/10 6 

### Btu.
Particulate emissions are controlled using a pulse jet fabric filter wh ich operates at an efficiency of 99.8 percent. Co-benefit capture results in a 90 percent reduction of mercury emissions. Ninety percent of the CO 2 

### in the flue gas is removed in CDR facility.
Exhibit 4-40 shows the overall water balance for the plant. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent) . The water usage represents only the contribution of raw water makeup. In so me cases the water demand is greater than raw water makeup because of internal water recycle streams. For example, the boiler feedwater blowdown stream and condensate recovered fr om cooling the flue gas prior to the CO 2 

### absorber are re-used as makeup to the cooling tower, t hus reducing the raw water requirement by that amount.Cost and Performance Comparison of Fossil Energy Power Plants

405 

### Exhibit 4-40 Case 12 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle,

m 3 

### /min (gpm) Raw Water Makeup,

m 3 

### /min (gpm)
FGD Makeup 2.9 (779) 0 2.9 (779)
BFW Makeup 0.4 (105) 0 0.4 (105)
Cooling Tower Makeup 41.2 (10,885) 5.0 (1,324) 36.2 (9,561)
Total 44.5 (11,769) 5.0 (1,324) 39.5 (10,444)

Heat and Mass Balance Diagrams A heat and mass balance diagram is shown for th e Case 12 PC boiler, the FGD unit, CDR system and steam cycle in Exhibit 4-41. An overall plant energy balance is provided in tabular form in Exhibit 4-42. The power out is the steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 4-38) is calculated by multiplying th e power out by a generator efficiency of 98.5 percent. The Econamine process heat out stream represents heat rejected to cooling water and ultimately to ambient via the cooling tower. The sa me is true of the condenser heat out stream. The CO 2 

### compressor intercooler load is included in the Econamine process heat out stream.Cost and Performance Comparison of Fossil Energy Power Plants

406 

### This page intentionally left blankCost and Performance Comparisonof Fossil Energy Power Plants407Exhibit 4-41 Case 12 Heat and Mass Balance, Supercritical PC Boiler with CO2CaptureCost and Performance Comparisonof Fossil Energy Power Plants408This page intentionally left blankCost and Performance Comparison of Fossil Energy Power Plants

409 

### Exhibit 4-42 Case 12 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total
Heat In (MMBtu/hr) Coal 6,843.6 5.7 6,849.3 Ambient Air 76.1 76.1 Infiltration Air 1.0 1.0 Limestone 87.1 87.1 FGD Oxidant 1.0 1.0 Raw Water Makeup 136.4 136.4 Auxiliary Power 424.2 424.2 Totals 6,843.6 307.3 424.2 7,575.0 Heat Out (MMBtu/hr) Bottom Ash 0.6 0.6 Fly Ash 2.3 2.3 Flue Gas Exhaust 229.1 229.1 CO 2 

### Product (88.7) (88.7) Condenser 1,787.0 1,787.0 Econamime Process 3154.6 3154.6 Cooling Tower Blowdown 63.3 63.3 Gypsum Slurry 2.8 2.8 Process Losses (1) 124.5 124.5 Power 2,299.5 2,299.5 Totals 0.0 5,275.6 2,299.5 7,575.0 (1) Process Losses are calculated by difference a nd reflect various boiler, turbine, and other heat and work losses. Aspen flowsh eet balance is within 0.5 percent.Cost and Performance Comparison of Fossil Energy Power Plants

410 

### 4.3.9 C ASE 

### 12

– M AJOR 

### E QUIPMENT 

### L IST 

### Major equipment items for the supercritical PC plant with CO 2 

### capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 4.3.10. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
ACCOUNT 1 FUEL AND SORBENT HANDLING

Equipment No. Description Type Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 2 0

2 Feeder Belt 2 0
3 Conveyor No. 1 Belt 1 0

4 Transfer Tower No. 1 Enclosed 1 0 5 Conveyor No. 2 Belt 1 0

6 As-Received Coal Sampling System Two-stage 1 0

7 Stacker/Reclaimer Traveling, linear 1 0 8 Reclaim Hopper N/A 2 1 9 Feeder Vibratory 2 1 10 Conveyor No. 3 Belt w/ tripper 1 0

11 Crusher Tower N/A 1 0 12 Coal Surge Bin w/ Vent Filter Dual outlet 2 0

13 Crusher Impactor reduction 2 0

14 As-Fired Coal Sampling System Swing hammer 1 1

15 Conveyor No. 4 Belt w/tripper 1 0

16 Transfer Tower No. 2 Enclosed 1 0
17 Conveyor No. 5 Belt w/ tripper 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 3 0

19 Limestone Truck Unloading Hopper N/A 1 0

20 Limestone Feeder Belt 1 0
21 Limestone Conveyor No. L1 Belt 1 0
22 Limestone Reclaim Hopper N/A 1 0

23 Limestone Reclaim Feeder Belt 1 0
24 Limestone Conveyor No. L2 Belt 1 0
25 Limestone Day Bin w/ actuator 2 0 Design Condition

181 tonne (200 ton)

N/A

1,134 tonne/h (1,250 tph) N/A 1,134 tonne/h (1,250 tph)

572 tonne/h (630 tph)
1,134 tonne/h (1,250 tph)

54 tonne (60 ton) 218 tonne/h (240 tph)

8 cm x 0 - 3 cm x 0 (3" x 0 - 1-1/4" x 0) 435 tonne/h (480 tph)

218 tonne (240 ton) N/A

435 tonne/h (480 tph)

998 tonne (1,100 ton) N/A

435 tonne/h (480 tph)

N/A

36 tonne (40 ton)

109 tonne/h (120 tph)
109 tonne/h (120 tph)

345 tonne (380 ton)

18 tonne (20 ton)
91 tonne/h (100 tph)
91 tonne/h (100 tph)Cost and Performance Comparison of Fossil Energy Power Plants

411 

### ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED
Equipment No. Description Type Operating Qty. Spares

1 Coal Feeder Gravimetric 6 0

2 Coal Pulverizer Ball type or equivalent 6 0

3 Limestone Weigh Feeder Gravimetric 1 1
4 Limestone Ball Mill Rotary 1 1

5 Limestone Mill Slurry Tank with Agitator N/A 1 1

6 Limestone Mill Recycle Pumps Horizontal centrifugal 1 1

7 Hydroclone Classifier 4 active cyclones in a 5 cyclone bank 1 1

8 Distribution Box 2-way 1 1

9 Limestone Slurry Storage Tank with Agitator Field erected 1 1

10 Limestone Slurry Feed Pumps Horizontal centrifugal 1 1 109,778 liters (29,000 gal) Design Condition

45 tonne/h (50 tph)

45 tonne/h (50 tph)

29 tonne/h (32 tph) 29 tonne/h (32 tph)

624,598 liters (165,000 gal) 445 lpm @ 12m H2O (490 gpm @ 40 ft H2O)

N/A

308 lpm @ 9m H2O (340 gpm @ 30 ft H2O) 109 lpm (120 gpm) per cycloneCost and Performance Comparison of Fossil Energy Power Plants

412 

### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment No. Description Type Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 2 0

2 Condensate Pumps Vertical canned 1 1

3 Deaerator and Storage Tank Horizontal spray type 1 0

4 Boiler Feed Pump and Steam Turbine Drive Barrel type, multistage, centrifugal 1 1

6 LP Feedwater Heater 1A/1B Horizontal U-tube 2 0

7 LP Feedwater Heater 2A/2B Horizontal U-tube 2 0

8 LP Feedwater Heater 3A/3B Horizontal U-tube 2 0

9 LP Feedwater Heater 4A/4B Horizontal U-tube 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 1 0

11 HP Feedwater Heater 7 Horizontal U-tube 1 0

12 HP Feedwater heater 8 Horizontal U-tube 1 0

13 Auxiliary Boiler Shop fabricated, water tube 1 0

14 Fuel Oil System No. 2 fuel oil for light off 1 0

15 Service Air Compressors Flooded Screw 2 1

16 Instrument Air Dryers Duplex, regenerative 2 1

17 Closed Cycle Cooling Heat Exchangers Shell and tube 2 0

18 Closed Cycle Cooling Water Pumps Horizontal centrifugal 2 1

19 Engine-Driven Fire Pump Vertical turbine, diesel engine 1 1

20 Fire Service Booster Pump Two-stage horizontal centrifugal 1 1

21 Raw Water Pumps Stainless steel, single suction 2 1

22 Filtered Water Pumps Stainless steel, single suction 2 1

23 Filtered Water Tank Vertical, cylindrical 1 0

24 Makeup Water Demineralizer Multi-media filter, cartridge filter, RO membrane assembly, electrodeionization unit 1 1

25 Liquid Waste Treatment System -- 1 0 28 m3/min (1,000 scfm)

3,785 lpm @ 88 m H2O (1,000 gpm @ 290 ft H2O)

2,650 lpm @ 64 m H2O (700 gpm @ 210 ft H2O) 25,514 lpm @ 43 m H2O (6,740 gpm @ 140 ft H2O)

2,120 lpm @ 49 m H2O (560 gpm @ 160 ft H2O) 0 5 Startup Boiler Feed Pump, Electric Motor Driven Barrel type, multistage, centrifugal 13,249 lpm @ 3,475 m H2O (3,500 gpm @ 11,400 ft H2O) 1

53 MMkJ/h (50 MMBtu/h) each
20,820 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 2,612,695 kg/h (5,760,000 lb/h)

2,040,353 liter (539,000 gal)

1,022 lpm (270 gpm)

10 years, 24-hour storm 43,911 lpm @ 3,475 m H2O (11,600 gpm @ 11,400 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C (40,000 lb/h, 400 psig, 650°F)

28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 557,919 kg/h (1,230,000 lb/h)

557,919 kg/h (1,230,000 lb/h)

557,919 kg/h (1,230,000 lb/h)

557,919 kg/h (1,230,000 lb/h)

2,612,695 kg/h (5,760,000 lb/h)
2,612,695 kg/h (5,760,000 lb/h)

1,135,632 liter (300,000 gal) Design Condition

1,570,958 liters (415,000 gal)

18,927 lpm @ 213 m H2O (5,000 gpm @ 700 ft H2O) 2,614,963 kg/h (5,765,000 lb/h) 5 min. tankCost and Performance Comparison of Fossil Energy Power Plants

413 

### ACCOUNT 4 BOILER AND ACCESSORIES
Equipment No. Description Type Operatin g Qty. Spares

1 Boiler Supercritical, drum, wall-fired, low NOx burners, overfire air 1 0

2 Primary Air Fan Centrifugal 2 0

3 Forced Draft Fan Centrifugal 2 0

4 Induced Draft Fan Centrifugal 2 0

5 SCR Reactor Vessel Space for spare layer 2 0

6 SCR Catalyst -- 3 0

7 Dilution Air Blower Centrifugal 2 1

8 Ammonia Storage Horizontal tank 5 0

9 Ammonia Feed Pump Centrifugal 2 1 1,596,647 kg/h, 33,898 m3/min @ 90 cm WG (3,520,000 lb/h, 1,197,100 acfm @ 36 in. WG)
3,193,294 kg/h (7,040,000 lb/h)

-- Design Condition

2,612,695 kg/h steam @ 24.1 MPa/593°C/593°C (5,760,000 lb/h steam @ 3,500 psig/1,100°F/1,100°F)

339,741 kg/h, 4,650 m3/min @

123 cm WG (749,000 lb/h, 164,200 acfm @ 48 in. WG)
1,105,406 kg/h, 15,135 m3/min @ 47 cm WG (2,437,000 lb/h, 534,500 acfm @ 19 in. WG)

190 m3/min @ 108 cm WG (6,700 acfm @ 42 in. WG)
208,199 liter (55,000 gal) 40 lpm @ 91 m H2O (11 gpm @ 300 ft H2O)Cost and Performance Comparison of Fossil Energy Power Plants

414 

### ACCOUNT 5 FLUE GAS CLEANUP
Equipment No. Description Type Operatin g Qty. Spares

1 Fabric Filter Single stage, highratio with pulsejet online cleaning system 2 0

2 Absorber Module Counter-current
open spray 1 0

3 Recirculation Pumps Horizontal centrifugal 5 1

4 Bleed Pumps Horizontal centrifugal 2 1

5 Oxidation Air Blowers Centrifugal 2 1

6 Agitators Side entering 5 1

7 Dewatering Cyclones Radial assembly, 5 units each 2 0

8 Vacuum Filter Belt Horizontal belt 2 1

9 Filtrate Water Return Pumps Horizontal centrifugal 1 1

10 Filtrate Water Return Storage Tank Vertical, lined 1 0

11 Process Makeup Water Pumps Horizontal centrifugal 1 1 Design Condition

1,596,647 kg/h (3,520,000 lb/h) 99.8% efficiency

52,160 m3/min (1,842,000 acfm)

181,701 lpm @ 64 m H2O (48,000 gpm @ 210 ft H2O)

250 m3/min @ 0.3 MPa (8,820 acfm @ 42 psia)

45 tonne/h (50 tph) 50 wt % slurry 5,716 lpm (1,510 gpm) 20 wt% solids

50 hp

1,438 lpm (380 gpm) per cyclone

871 lpm @ 12 m H2O (230 gpm @ 40 ft H2O)

567,816 lpm (150,000 gal)

3,255 lpm @ 21 m H2O (860 gpm @ 70 ft H2O)



### ACCOUNT 5C CARBON DIOXIDE RECOVERY

Equipment No. Description Type Operating Qty. Spares

1 Econamine FG Plus Amine-based CO2 capture technology 2 0

2 CO2 Compressor Integrally geared, multi-stage centrifu g al 2 0 Design Condition
1,704,602 kg/h (3,758,000 lb/h) 20.4 wt % CO2 inlet concentration 312,453 kg/h @ 15.3 MPa (688,840 lb/h @ 2,215 psia)Cost and Performance Comparison of Fossil Energy Power Plants

415 

### ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES
N/A

ACCOUNT 7 HRSG, DUCTING & STACK

Equipment No. Description Type Operating Qty. Spares

1 Stack Reinforced concrete with FRP liner 1 0 Design Condition

152 m (500 ft) high x 5.5 m (18 ft) diameter



### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitation 1 0

3 Surface Condenser Single pass, divided waterbox including
vacuum pumps 1 0 780 MVA @ 0.9 p.f., 24 kV, 60 Hz Design Condition

700 MW 24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F)

2,077 MMkJ/h (1,970 MMBtu/h), Inlet water temperature 16oC (60oF),

Water temperature rise 11oC (20oF)



### ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 4 2

2 Cooling Tower Evaporative, mechanical draft, multi-cell 1 0 Design Condition

613,241 lpm @ 30.5 m (162,000 gpm @ 100 ft)

11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT 5,914 MMkJ/h (5,610 MMBtu/h) heat loadCost and Performance Comparison of Fossil Energy Power Plants

416 

### ACCOUNT 10 ASH/SPENT SORBEN T RECOVERY AND HANDLING
Equipment No. Description Type Operating Qty. Spares

1 Economizer Hopper (part of boiler scope of supply) -- 4 0

2 Bottom Ash Hopper (part of boiler scope of supply) -- 2 0

3 Clinker Grinder -- 1 1

4 Pyrites Hopper (part of pulverizer scope of supply included with boiler) -- 6 0

5 Hydroejectors -- 12

6 Economizer /Pyrites Transfer Tank -- 1 0

7 Ash Sluice Pumps Vertical, wet pit 1 1

8 Ash Seal Water Pumps Vertical, wet pit 1 1

9 Hydrobins -- 1 1

10 Baghouse Hopper (part of baghouse scope of supply) -- 24 0

11 Air Heater Hopper (part of boiler scope of supply) -- 10 0

12 Air Blower -- 1 1

13 Fly Ash Silo Reinforced
concrete 2 0

14 Slide Gate Valves -- 2 0

15 Unloader -- 1 0

16 Telescoping Unloading Chute -- 1 0 Design Condition

--

--
5.4 tonne/h (6 tph)

--

--
227 lpm @ 17 m H2O (60 gpm @ 56 ft H2O)

7,571 lpm @ 9 m H2O (2000 gpm @ 28 ft H2O) --

227 lpm (60 gpm)

--

--

-- --

21 m3/min @ 0.2 MPa

(730 scfm @ 24 psi)

680 tonne (1,500 ton)

127 tonne/h (140 tph)Cost and Performance Comparison of Fossil Energy Power Plants

417 

### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type Operating Qty. Spares

1 STG Transformer Oil-filled 1 0

2 Auxiliary Transformer Oil-filled 1 1

3 Low Voltage Transformer Dry ventilated 1 1

4 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 1 0

5 Medium Voltage Switchgear Metal clad 1 1

6 Low Voltage Switchgear Metal enclosed 1 1

7 Emergency Diesel Generator Sized for emergency shutdown 1 0 750 kW, 480 V, 3-ph, 60 Hz 24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz 24 kV/4.16 kV, 128 MVA, 3-ph, 60 Hz

4.16 kV/480 V, 19 MVA, 3-ph, 60 Hz Design Condition
24 kV/345 kV, 640 MVA, 3-ph, 60 Hz



### ACCOUNT 12 INSTRUMENTATION AND CONTROL

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) 1 0

3 DCS - Data Highway Fiber optic 1 0 1 0

Fully redundant, 25% spare Design Condition

Operator stations/printers and engineering stations/printers

2 DCS - Processor Microprocessor with redundant input/output N/ACost and Performance Comparison of Fossil Energy Power Plants

418 

### 4.3.10 C ASE 

### 12

– C OST 

### E STIMATING 

### B ASIS 

### The cost estimating methodology was desc ribed previously in Section 2.6. Exhibit 4-43 shows the total plant capital cost summary organized by cost account and Exhibit 4-44 shows a more detailed breakdown of the capital costs. Exhibit 4-45 shows the ini tial and annual O&M costs.
The estimated TPC of the s ubcritical PC boiler with CO 2 

### capture is $2,868/kW. Process contingency represents 3.5 percent of the TPC a nd project contingency repr esents 12.4 percent. The 20-year LCOE, including CO 2 

### TS&M costs of 3.9 mills/kWh, is 114.8 mills/kWh.Cost and Performance Comparisonof Fossil Energy Power Plants419Exhibit 4-43 Case 12 Total Plant Cost SummaryClient:USDOE/NETLReport Date:09-May-07Project:Bituminous Baseline StudyCase:Case 12 - Supercritical PC w/ CO2Plant Size:546.0 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING $19,316 $5,215 $11,691 $0 $0$36,222$3,246 $0 $5,920$45,389$832 COAL & SORBENT PREP & FEED $13,126 $758 $3,326 $0 $0$17,210$1,508 $0 $2,808$21,527$393 FEEDWATER & MISC. BOP SYSTEMS $54,477 $0 $25,648 $0 $0$80,126$7,317 $0 $14,428$101,870$1874 PC BOILER4.1 PC Boiler & Accessories $190,969 $0 $107,678 $0 $0$298,647$28,927 $0 $32,757$360,332$6604.2 SCR (w/4.1) $0 $0 $0 $0 $0$0$0 $0 $0$0$04.3 Open $0 $0 $0 $0 $0$0$0 $0 $0$0$04.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0$0$0 $0 $0$0$0SUBTOTAL 4 $190,969 $0 $107,678 $0 $0 $298,647 $28,927 $0 $32,757 $360,332 $6605 FLUE GAS CLEANUP $101,747 $0 $34,963 $0 $0$136,710$12,990 $0 $14,970$164,670$3025BCO2REMOVAL & COMPRESSION$229,832 $0 $69,851 $0 $0$299,683$28,443 $52,879 $76,201$457,207$8376 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator N/A $0 N/A $0 $0$0$0 $0 $0$0$06.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0$0$0 $0 $0$0$0SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0$0$0 $0 $0$0$07.2-7.9 HRSG Accessories, Ductwork and Stack $17,889 $981 $12,221 $0 $0$31,091$2,840 $0 $4,457$38,388$70SUBTOTAL 7 $17,889 $981 $12,221 $0 $0 $31,091 $2,840 $0 $4,457 $38,388 $708 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $53,763 $0 $7,192 $0 $0$60,956$5,836 $0 $6,679$73,471$1358.2-8.9 Turbine Plant Auxiliaries and Steam Piping $26,923 $1,148 $14,942 $0 $0$43,013$3,724 $0 $6,698$53,436$98SUBTOTAL 8 $80,687 $1,148 $22,134 $0 $0 $103,969 $9,561 $0 $13,377 $126,907 $2329 COOLING WATER SYSTEM $21,479 $11,200 $19,881 $0 $0$52,559$4,900 $0 $7,796$65,255$12010 ASH/SPENT SORBENT HANDLING SYS $5,154 $162 $6,854 $0 $0$12,169$1,158 $0 $1,371$14,699$2711 ACCESSORY ELECTRIC PLANT $20,196 $10,240 $29,287 $0 $0$59,723$5,331 $0 $8,288$73,343$13412 INSTRUMENTATION & CONTROL $9,195 $0 $9,662 $0 $0$18,857$1,726 $943 $2,648$24,174$4413 IMPROVEMENTS TO SITE $3,162 $1,818 $6,421 $0 $0$11,402$1,120 $0 $2,504$15,026$2814 BUILDINGS & STRUCTURES $0 $23,760 $22,735 $0 $0$46,495$4,189 $0 $7,603$58,287$107TOTAL COST $767,230 $55,282 $382,352 $0 $0 $1,204,865 $113,256 $53,822 $195,130 $1,567,073 $2,870TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants420Exhibit 4-44 Case 12 Total Plant Cost DetailsClient:USDOE/NETLReport Date:09-May-07Project:Bituminous Baseline StudyCase:Case 12 - Supercritical PC w/ CO2Plant Size:546.0 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material LaborSales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING1.1 Coal Receive & Unload $3,967 $0 $1,831 $0 $0 $5,797 $518 $0 $947 $7,262 $131.2 Coal Stackout & Reclaim $5,126 $0 $1,174 $0 $0 $6,300 $551 $0 $1,028 $7,879 $141.3 Coal Conveyors $4,766 $0 $1,161 $0 $0 $5,927 $520 $0 $967 $7,414 $141.4 Other Coal Handling $1,247 $0 $269 $0 $0 $1,516 $132 $0 $247 $1,895 $31.5 Sorbent Receive & Unload $160 $0 $49 $0 $0 $208 $18 $0 $34 $260 $01.6 Sorbent Stackout & Reclaim $2,576 $0 $477 $0 $0 $3,053 $266 $0 $498 $3,817 $71.7 Sorbent Conveyors $919 $198 $228 $0 $0 $1,345 $116 $0 $219 $1,680 $31.8 Other Sorbent Handling $555 $129 $294 $0 $0 $979 $87 $0 $160 $1,225 $21.9 Coal & Sorbent Hnd.Foundations $0 $4,888 $6,210 $0 $0 $11,097 $1,037 $0 $1,820 $13,955 $26SUBTOTAL 1. $19,316 $5,215 $11,691 $0 $0 $36,222 $3,246 $0 $5,920 $45,389 $832 COAL & SORBENT PREP & FEED2.1 Coal Crushing & Drying $2,305 $0 $454 $0 $0 $2,759 $241 $0 $450 $3,449 $62.2 Coal Conveyor to Storage $5,901 $0 $1,301 $0 $0 $7,203 $630 $0 $1,175 $9,007 $162.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.5 Sorbent Prep Equipment $4,391 $188 $922 $0 $0 $5,501 $479 $0 $897 $6,878 $132.6 Sorbent Storage & Feed $529 $0 $205 $0 $0 $734 $65 $0 $120 $919 $22.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.9 Coal & Sorbent Feed Foundation $0 $570 $444 $0 $0 $1,014 $93 $0 $166 $1,274 $2SUBTOTAL 2. $13,126 $758 $3,326 $0 $0 $17,210 $1,508 $0 $2,808 $21,527 $393 FEEDWATER & MISC. BOP SYSTEMS3.1 FeedwaterSystem $22,090 $0 $7,230 $0 $0 $29,320 $2,567 $0 $4,783 $36,670 $673.2 Water Makeup & Pretreating $7,572 $0 $2,435 $0 $0 $10,007 $938 $0 $2,189 $13,134 $243.3 Other Feedwater Subsystems $6,826 $0 $2,896 $0 $0 $9,722 $866 $0 $1,588 $12,176 $223.4 Service Water Systems $1,495 $0 $807 $0 $0 $2,301 $214 $0 $503 $3,018 $63.5 Other Boiler Plant Systems $8,357 $0 $8,175 $0 $0 $16,533 $1,551 $0 $2,713 $20,796 $383.6 FO Supply Sys & Nat Gas $267 $0 $329 $0 $0 $596 $55 $0 $98 $749 $13.7 Waste Treatment Equipment $5,103 $0 $2,923 $0 $0 $8,027 $778 $0 $1,761 $10,565 $193.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,768 $0 $853 $0 $0 $3,621 $348 $0 $794 $4,762 $9SUBTOTAL 3. $54,477 $0 $25,648 $0 $0 $80,126 $7,317 $0 $14,428 $101,870 $1874 PC BOILER4.1 PC Boiler & Accessories $190,969 $0 $107,678 $0 $0 $298,647 $28,927 $0 $32,757 $360,332 $6604.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 4. $190,969 $0 $107,678 $0 $0 $298,647 $28,927 $0 $32,757 $360,332 $660TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants421Exhibit 4-44 Case 12 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:09-May-07Project:Bituminous Baseline StudyCase:Case 12 - Supercritical PC w/ CO2Plant Size:546.0 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW5 FLUE GAS CLEANUP5.1 Absorber Vessels & Accessories $70,491 $0 $15,186 $0 $0 $85,677 $8,109 $0 $9,379 $103,165 $1895.2 Other FGD $3,679 $0 $4,172 $0 $0 $7,850 $756 $0 $861 $9,467 $175.3 Bag House & Accessories $20,751 $0 $13,179 $0 $0 $33,931 $3,245 $0 $3,718 $40,894 $755.4 Other Particulate Removal Materials $1,404 $0 $1,504 $0 $0 $2,908 $280 $0 $319 $3,507 $65.5 Gypsum Dewatering System $5,422 $0 $922 $0 $0 $6,344 $599 $0 $694 $7,638 $145.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 5. $101,747 $0 $34,963 $0 $0 $136,710 $12,990 $0 $14,970 $164,670 $3025BCO2REMOVAL & COMPRESSION5B.1CO2Removal System$202,944 $0 $61,453 $0 $0 $264,397 $25,093 $52,879 $68,474 $410,843 $7525B.2CO2Compression & Drying$26,888 $0 $8,398 $0 $0 $35,286 $3,350 $0 $7,727 $46,363 $85SUBTOTAL 5. $229,832 $0 $69,851 $0 $0 $299,683 $28,443 $52,879 $76,201 $457,207 $8376 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $06.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $07.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07.3 Ductwork $9,280 $0 $6,057 $0 $0 $15,337 $1,340 $0 $2,501 $19,178 $357.4 Stack $8,609 $0 $5,041 $0 $0 $13,650 $1,304 $0 $1,495 $16,450 $307.9 Duct & Stack Foundations $0 $981 $1,123 $0 $0 $2,104 $196 $0 $460 $2,760 $5SUBTOTAL 7. $17,889 $981 $12,221 $0 $0 $31,091 $2,840 $0 $4,457 $38,388 $708 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $53,763 $0 $7,192 $0 $0 $60,956 $5,836 $0 $6,679 $73,471 $1358.2 Turbine Plant Auxiliaries $368$0 $789 $0 $0 $1,158 $112 $0 $127 $1,397 $38.3 Condenser & Auxiliaries $5,563 $0 $1,956 $0 $0 $7,519 $715 $0 $823 $9,057 $178.4 Steam Piping $20,992 $0 $10,369 $0 $0 $31,362 $2,617 $0 $5,097 $39,076 $728.9 TG Foundations $0 $1,148 $1,827 $0 $0 $2,975 $280 $0 $651 $3,906 $7SUBTOTAL 8. $80,687 $1,148 $22,134 $0 $0 $103,969 $9,561 $0 $13,377 $126,907 $2329 COOLING WATER SYSTEM9.1 Cooling Towers $15,181 $0 $4,731 $0 $0 $19,911 $1,890 $0 $2,180 $23,982 $449.2 Circulating Water Pumps $3,928 $0 $285 $0 $0 $4,213 $361 $0 $457 $5,031 $99.3 Circ.Water System Auxiliaries$907 $0 $121 $0 $0 $1,028 $97 $0 $112 $1,237 $29.4 Circ.Water Piping $0 $7,315 $6,977 $0 $0 $14,292 $1,317 $0 $2,341 $17,950 $339.5 Make-up Water System $740 $0 $981 $0 $0 $1,721 $163 $0 $283 $2,167 $49.6 Component Cooling Water Sys $723 $0 $571 $0 $0 $1,294 $121 $0 $212 $1,628 $39.9 Circ.Water System Foundations& Structures $0 $3,884 $6,215 $0 $0 $10,099 $951 $0 $2,210 $13,260 $24SUBTOTAL 9. $21,479 $11,200 $19,881 $0 $0 $52,559 $4,900 $0 $7,796 $65,255 $12010 ASH/SPENT SORBENT HANDLING SYS10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $010.6 Ash Storage Silos $685 $0 $2,113 $0 $0 $2,799 $273 $0 $307 $3,379 $610.7 Ash Transport & Feed Equipment $4,468 $0 $4,548 $0 $0 $9,016 $853 $0 $987 $10,856 $2010.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.9 Ash/Spent Sorbent Foundation $0 $162 $192 $0 $0 $354 $33 $0 $77 $464 $1SUBTOTAL 10. $5,154 $162 $6,854 $0 $0 $12,169 $1,158 $0 $1,371 $14,699 $27TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants422Exhibit 4-44 Case 12 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:09-May-07Project:Bituminous Baseline StudyCase:Case 12 - Supercritical PC w/ CO2Plant Size:546.0 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material LaborSales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW11 ACCESSORY ELECTRIC PLANT11.1 Generator Equipment $1,647 $0 $270 $0 $0 $1,917 $178 $0 $157 $2,251 $411.2 Station Service Equipment $4,617 $0 $1,581 $0 $0 $6,197 $593 $0 $509 $7,299 $1311.3 Switchgear & Motor Control $5,487 $0 $940 $0 $0 $6,427 $595 $0 $702 $7,724 $1411.4 Conduit & Cable Tray $0 $3,523 $11,989 $0 $0 $15,512 $1,485 $0 $2,549 $19,546 $3611.5 Wire & Cable $0 $6,390 $12,630 $0 $0 $19,020 $1,603 $0 $3,093 $23,716 $4311.6 Protective Equipment $243 $0 $861 $0 $0 $1,104 $108 $0 $121 $1,333 $211.7 Standby Equipment $1,253 $0 $30 $0 $0 $1,282 $121 $0 $140 $1,544 $311.8 Main Power Transformers $6,950 $0 $182 $0 $0 $7,132 $542 $0 $767 $8,441 $1511.9 Electrical Foundations $0 $326 $806 $0 $0 $1,133 $108 $0 $248 $1,488 $3SUBTOTAL 11. $20,196 $10,240 $29,287 $0 $0 $59,723 $5,331 $0 $8,288 $73,343 $13412 INSTRUMENTATION & CONTROL12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $012.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $012.4 Other Major Component Control $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $012.5 Signal Processing Equipment W/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.6 Control Boards,Panels & Racks $471 $0 $294 $0 $0 $765 $74 $38 $131 $1,008 $212.7 Distributed Control System Equipment $4,754 $0 $866 $0 $0 $5,620 $535 $281 $644 $7,080 $1312.8 Instrument Wiring & Tubing $2,626 $0 $5,327 $0 $0 $7,953 $677 $398 $1,354 $10,382 $1912.9 Other I & C Equipment $1,343 $0 $3,176 $0 $0 $4,520 $440 $226 $519 $5,704 $10SUBTOTAL 12. $9,195 $0 $9,662 $0 $0 $18,857 $1,726 $943 $2,648 $24,174 $4413 IMPROVEMENTS TO SITE13.1 Site Preparation $0 $53 $1,071 $0 $0 $1,124 $111 $0 $247 $1,482 $313.2 Site Improvements $0 $1,765 $2,208 $0 $0 $3,973 $390 $0 $873 $5,236 $1013.3 Site Facilities $3,162 $0 $3,142 $0 $0 $6,305 $619 $0 $1,385 $8,308 $15SUBTOTAL 13. $3,162 $1,818 $6,421 $0 $0 $11,402 $1,120 $0 $2,504 $15,026 $2814 BUILDINGS & STRUCTURES14.1 Boiler Building $0 $8,384 $7,472 $0 $0 $15,857 $1,424 $0 $2,592 $19,873 $3614.2 Turbine Building $0 $12,152 $11,477 $0 $0 $23,629 $2,128 $0 $3,864 $29,621 $5414.3 Administration Building $0 $608 $651 $0 $0 $1,259 $114 $0 $206 $1,579 $314.4 Circulation Water Pumphouse $0 $279 $225 $0 $0 $503 $45 $0 $82 $631 $114.5 Water Treatment Buildings $0 $999 $834 $0 $0 $1,833 $164 $0 $300 $2,297 $414.6 Machine Shop $0 $406 $277 $0 $0 $683 $61 $0 $112 $855 $214.7 Warehouse $0 $275 $280 $0 $0 $555 $50 $0 $91 $696 $114.8 Other Buildings & Structures $0 $225 $194 $0 $0 $419 $38 $0 $69 $525 $114.9 Waste Treating Building & Str. $0 $431 $1,325 $0 $0 $1,756 $166 $0 $288 $2,210 $4SUBTOTAL 14. $0 $23,760 $22,735 $0 $0 $46,495 $4,189 $0 $7,603 $58,287 $107TOTAL COST $767,230 $55,282 $382,352 $0 $0 $1,204,865 $113,256 $53,822 $195,130 $1,567,073 $2,870TOTAL PLANT COST SUMMARYCost and Performance Comparison of Fossil Energy Power Plants

423 

### Exhibit 4-45 Case 12 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006 Case 12 - Supercritical PC w/ CO2 Heat Rate-net(Btu/kWh): 12,534 MWe-net: 546 Capacity Factor: (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 33.00 $/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 11.3 11.3 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL-O.J.'s 16.3 16.3 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,138,007 $11.242 Maintenance Labor Cost $10,271,860 $18.813 Administrative & Support Labor $4,102,467 $7.514 TOTAL FIXED OPERATING COSTS $20,512,333 $37.569 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $15,407,790 $0.00379

Consumables Consumption Unit Initial Initial /Day Cost Cost
Water(/1000 gallons) 0 8,755 1.03 $0 $2,797,790 $0.00069

Chemicals MU & WT Chem.(lb) 296,665 42,381 0.16 $48,890 $2,166,895 $0.00053 Limestone (ton) 4,877 697 20.60 $100,457 $4,452,382 $0.00110 Carbon (Mercury Removal) (lb) 0 0 1.00 $0 $0 $0.00000 MEA Solvent (ton) 1,065 1.51 2,142.40 $2,281,656 $1,004,996 $0.00025 NaOH (tons) 74 7.36 412.96 $30,559 $942,457 $0.00023 H2SO4 (tons) 72 7.18 132.15 $9,515 $294,213 $0.00007 Corrosion Inhibitor 0 0 0.00 $147,250 $7,000 $0.00000 Activated Carbon(lb) 657,450 1,800 1.00 $657,450 $558,450 $0.00014 Ammonia (28% NH3) ton 813 116 123.60 $100,439 $4,451,615 $0.00109 Subtotal Chemicals $3,376,216 $13,878,007 $0.00341

Other Supplemental Fuel(MBtu) 0 0 0.00 $0 $0 $0.00000 SCR Catalyst(m3) w/equip. 0.62 5,500.00 $0 $1,058,976 $0.00026 Emission Penalties 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $1,058,976 $0.00026

Waste Disposal Flyash (ton) 0 137 15.45 $0 $654,409 $0.00016 Bottom Ash(ton) 0 546 15.45 $0 $2,617,579 $0.00064 Subtotal-Waste Disposal $0 $3,271,988 $0.00080

By-products & Emissions Gypsum (tons) 0 1,085 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $3,376,216 $36,414,550 $0.00896

Fuel(ton) 211,183 7,039 42.11 $8,892,927 $91,967,691 $0.02262Cost and Performance Comparison of Fossil Energy Power Plants

424 

### 4.4 PC CASE SUMMARY The performance results of th e four PC plant configurati ons modeled in this study are summarized in Exhibit 4-46.
Exhibit 4-46 Estimated Performance and Cost Results for Pulverized Coal Cases

Case 9 Case 10 Case 11 Case 12 CO 2 Capture No Yes No Yes Gross Power Output (kW e ) 583,315 679,923 580,260 663,445 Auxiliary Power Requirement (kW e ) 32,870 130,310 30,110 117,450 Net Power Output (kW e ) 550,445 549,613 550,150 545,995 Coal Flowrate (lb/hr) 437,699 646,589 411,282 586,627 Natural Gas Flowrate (lb/hr) N/A N/A N/A N/A HHV Thermal Input (kW th ) 1,496,479 2,210,668 1,406,161 2,005,660 Net Plant HHV Efficiency (%) 36.8% 24.9% 39.1% 27.2% Net Plant HHV Heat Rate (Btu/kW-hr) 9,276 13,724 8,721 12,534 Raw Water Usage, gpm 6,212 12,187 5,441 10,444 Total Plant Cost ($ x 1,000) 852,612 1,591,277 866,391 1,567,073 Total Plant Cost ($/kW) 1,549 2,895 1,575 2,870 LCOE (mills/kWh) 1 64.0 118.8 63.3 114.8 CO 2 Emissions (lb/MWh) 2 1,780 225 1,681 209 CO 2 Emissions (lb/MWh) 3 1,886 278 1,773 254 SO 2 Emissions (lb/MWh) 2 0.7426 Negligible 0.7007 Negligible NOx Emissions (lb/MWh) 2 0.613 0.777 0.579 0.722 PM Emissions (lb/MWh) 2 0.114 0.144 0.107 0.134 Hg Emissions (lb/MWh) 2 1.00E-05 1.27E-05 9.45E-06 1.18E-05

1 Based on an 85% capacity factor
2 Value is based on gross output
3 Value is based on net output Pulverized Coal Boiler PC Subcritical PC Supercritical



### The TPC for each of the PC cases is shown in Exhibit 4-47. The following observations can be made:

• The TPC of the non-capture supercritical PC case is only incremen tally greater than subcritical PC (less than 2 percent). The TPC of supercritical PC with CO 2 

### capture is 0.9 percent less than subcritical PC.

• The capital cost penalty for adding CO 2 

### capture in the subcritical case is 87 percent and in the supercritical case is 82 percent. The Econamine FG Plus cost includes a process contingency of approximately $100/kW in both the subcritical and supercritical cases. Eliminating the process contingency results in a CO 2 

### capture cost penalty of 76 and 80 percent for the supercritical and subcritical PC cases, respectively. In addition to the high cost of the Econamine process, there is a si gnificant increase in the cost of the cooling towers and circulating water pumps in the CO 2 

### capture cases because of the larger cooling water demand discussed previously. In addition, the gross output of the two PC plants increases by 97 MW (subcritical) and 83 MW (supercritical) to maintain the netCost and Performance Comparison of Fossil Energy Power Plants

425 

### output at 550 MW. The increased gross output results in higher coal flow rate and consequent higher costs for all cost accounts in the estimate.

Exhibit 4-47 Total Plant Cost for PC Cases

1,549 2,895

1,575 2,870

0 500 1,000 1,500 2,000 2,500 3,000Total Plant Cost, $/kW

Subcritical PC Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2 Capture



### The LCOE is shown for the four PC cases in Exhibit 4-48. The following observations can be made:

• Capital costs represent the largest fraction of LC OE in all cases, but particularly so in the CO 2 

### capture cases. Fuel cost is the sec ond largest component of LCOE, and capital charges and fuel costs combined represent a bout 83 percent of the total in all cases.

• In the non-capture case the slight increase in capit al cost in the superc ritical case is more than offset by the efficiency gain so that th e LCOE for supercritical PC is 1 percent less than subcritical despite having a nearly 2 percent higher TPC.

• In the CO 2 

### capture case, the cost differential betw een subcritical and supercritical PC is negligible (less than 1 percent), but the s upercritical PC has a 3 percent lower LCOE because of the higher efficiency.Cost and Performance Comparison of Fossil Energy Power Plants

426 

### Exhibit 4-48 LCOE for PC Cases

64.0 118.8

63.3 114.8

0 20 40 60 80 100 120 140LCOE, mills/kWh

Subcritical PC Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2 Capture CO2 TS&M Costs Fuel Costs Variable Costs Fixed Costs Capital Costs



### The sensitivity of LCOE to capacity factor is shown in Exhibit 4-49. Implicit in the curves is the assumption that an efficiency of greater than 85 percent can be achieved without the expenditure of additional capital. Th e subcritical and superc ritical cases with no CO 2 

### capture are nearly identical making it difficult to distinguish between the two lines. The LCOE increases more steeply at low capacity factor because the relatively high capital component is spread over fewer kilowatt-hours of generation. The sensitivity of LCOE to coal price is shown in Exhibit 4-50. As in the IGCC cases, the LCOE in the PC cases is relativ ely insensitive to coal price. As presented in Section 2.4 the cost of CO 2 

### capture was calculated in two ways, CO 2 

### removed and CO 2 

### avoided. The results for the PC carbon capture cases are shown in Exhibit 4-51.
The cost of CO 2 

### captured and avoided is nearly identical for the subcritical and supercritical PC cases. The avoided cost is significantly higher th an the captured cost because the gross output of the capture case is 83-96 MW higher than the non-capture case which reduces the amount of CO 2 

### avoided between cases.Cost and Performance Comparison of Fossil Energy Power Plants

427 

### Exhibit 4-49 Sensitivity of LCOE to Capacity Factor for PC Cases

0 50 100 150 200 250 300

0 10 20 30 40 50 60 70 80 90 100 Capacity Factor, %LCOE, mills/kWh Subcritical No Capture

Subcritical w/CO2 Capture

Supercritical No Capture

Supercritical w/CO2 Capture

Coal price is $1.80/MMBtu for all cases



### Exhibit 4-50 Sensitivity of LC OE to Coal Price for PC Cases

0 20 40 60 80 100 120 140 160

0 0.5 1 1.5 2 2.5 3 3.5 4 Fuel Price, $/MMBtuLCOE, mills/kWh

Subcritical No Capture

Subcritical w/CO2 Capture

Supercritical No Capture

Supercritical w/CO2 Capture Capacity Factor is 85 percent for all casesCost and Performance Comparison of Fossil Energy Power Plants

428 

### Exhibit 4-51 Cost of CO 2 

### Captured and Avoided in PC Cases

44 68

45 68

0 10 20 30 40 50 60 70 80$/ton, CO2

Subcritical PC Supercritical PC CO2 Removal Cost

CO2 Avoided Cost



### The following observations can be made rega rding plant performance with reference to Exhibit 4-46:

• The efficiency of the supercritical PC plant is 2.3 percentage points higher than than the equivalent subcritical PC plant (39.1 percent compared to 36.8 percent). The efficiencies are comparable to those reported in othe r studies once steam cycle conditions are considered. For example, in an EPA study [ 62] comparing PC and IGCC plant configurations the subcritical PC plant using bituminous coal had an efficiency of 35.9 percent with a steam cycle of 16.5 MPa/ 538°C/538°C (2400 psig/1000°F/1000°F). The higher steam cycle temperature in this study 566°C/566°C (1050°F/1050°F) results in a higher net efficiency. The same study reporte d a supercritical plant efficiency of 38.3 percent with a steam cycle of 24.1 MP a/566°C/566°C (3500 psig/1050°F/1050°F). Again, the more aggressive steam conditions in this study, 593°C/593°C (1100°F/1100°F) resulted in a higher net efficiency. Similar results from an EPRI study using Il linois No. 6 coal were reported as follows [ 63]:

o Subcritical PC efficiency of 35.7 percent with a steam cycle of 16.5 MPa/538°C/538°C (2400 psig/1000°F/1000°F).

o Supercritical PC efficiency of 38.3 percent with a steam cycle of 24.8 MPa/593°C/593°C (3600 psig/1100°F/1100°F).Cost and Performance Comparison of Fossil Energy Power Plants

429 

### • The addition of CO 2 

### capture to the two PC cases results in the same absolute efficiency impact, namely an 11.9 percentage point decreas e. The efficiency is negatively impacted by the large auxiliary loads of the Econamine process and CO 2 

### compression, as well as the large increase in cooling water requireme nt, which increases th e circulating water pump and cooling tower fan auxiliary loads. The auxiliary load increases by 97 MW in the subcritical PC case and by 87 MW in the supercritical PC case.

• NOx, PM and Hg emissions are the same for all four PC cases on a heat input basis because of the environmental target assumpti ons of fixed removal efficiencies for each case (86 percent SCR efficiency, 99.8 percen t baghouse efficiency and 90 percent cobenefit capture). The emissions on a mass ba sis or normalized by gross output are higher for subcritical cases than superc ritical cases and are higher for CO 2 

### capture cases than non-capture cases because of th e higher efficiencies of s upercritical PC and non-capture PC cases.

• SO 2 

### emissions are likewise constant on a heat input basis for the non-capture cases, but the Econamine process polishing scrubber and absorber vessel resu lt in negligible SO 2 

### emissions in CO 2 

### capture cases. The SO 2 

### emissions for subcritical PC are higher than supercritical on a mass basis and when normali zed by gross output because of the lower efficiency.

• Uncontrolled CO 2 

### emissions on a mass basis are greater for subcritical PC compared to supercritical because of the lower efficienc y. The capture cases result in a 90% reduction of CO 2 

### for both subcritical and supercritical PC.

• Raw water usage for all cases is dominat ed by cooling tower makeup requirements, which accounts for about 89 percent of raw wa ter in non-capture cases and 92 percent of raw water in CO 2 

### capture cases. The amount of raw water usage in the CO 2 

### capture cases is greatly increased by the cooling water requirements of the Econamine process. Cooling water is required to:

o Reduce the flue gas temperature from 57°C (135°F) (FGD exit temperature) to 32°C (89°F) (Econamine absorber operat ing temperature), which also requires condensing water from the flue gas that comes saturated from the FGD unit.

o Remove the heat input by the stri pping steam to cool the solvent

o Remove the heat input from th e auxiliary electric loads

o Remove heat in the CO 2 

### compressor intercoolers The normalized water demand, internal recy cle and raw water us age are shown in Exhibit 4-52 for each of the PC cases. The onl y internal recycle stream that affects the overall balance in the non-capture cases is the boiler feedwater blowdown stream which is recycled to the cooling tower as makeup water. In the CO 2 

### capture cases, additional water is recovered from the flue gas as it is cooled to the absorber te mperature of 32°C (89°F). The condensate is treated and also used as cooling tower makeup.Cost and Performance Comparison of Fossil Energy Power Plants

430 

### Exhibit 4-52 Water Usage in PC Cases

11.4 11.3 24.7

22.2

10.0 9.9 21.6

19.1

0.0 5.0 10.0 15.0 20.0 25.0 30.0Water, gpm/MW(net)

Subcritical PC Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2 Capture Water Demand
Internal Recycle
Raw Water UsageCost and Performance Comparison of Fossil Energy Power Plants

431 

## 5 NATURAL GAS COMBINED CYCLE PLANTS Two natural gas combined cycle (NGCC) power plant configurations we re evaluated and are presented in this section. Each design is based on a market-rea dy technology that is assumed to be commercially available in time to support a 20 10 start up date. Each design consists of two advanced F class combustion tu rbine generators (CTG), two HRSG’s and one steam turbine generator (STG) in a multi-s haft 2x2x1 configuration.
The NGCC cases are evaluated with and wit hout carbon capture on a common thermal input basis. The NGCC designs that include CDR have a smaller plan t net output resulting from the additional CDR facility auxiliary loads. Like in the IGCC cases, the sizes of the NGCC designs were determined by the output of the commercia lly available combustion turbine. Hence, evaluation of the NGCC designs on a common net output basis was not possible. The Rankine cycle portion of both designs uses a single reheat 16.5 MPa/566°C/510°C (2400 psig/1050 ° F/950 ° F) steam cycle. A more aggressive steam cycle was considered but not chosen because there are very few HRSGs in operation that would support such conditions. [ 54]

5.1 NGCC COMMON PROCESS AREAS The two NGCC cases are nearly identical in configuration with the exception that Case 14 includes CO 2 

### capture while Case 13 does not. The pr ocess areas that are common to the two plant configurations are pr esented in this section.

5.1.1 N ATURAL 

### G AS 

### S UPPLY 

### S YSTEM 

### It was assumed that a natural gas main with ad equate capacity is in cl ose proximity (within 16 km [10 miles]) to the site fence line and that a suitable right of way is available to install a branch line to the site. For the purposes of th is study it was also assumed that the gas will be delivered to the plant custody transfer point at 3.0 MPa (435 psig) and 38°C (100oF), which matches the advanced F Class fuel system requi rements. Hence, neither a pressure reducing station with gas preheating (to prevent mois ture and hydrocarbon conde nsation), nor a fuel booster compressor are required. A new gas metering station is assumed to be a dded on the site, adjacent to the new combustion turbine. The meter may be of the rate-of-flow type, with input to the plant computer for summing and recording, or may be of the positive di splacement type. In either case, a complete time-line record of gas consumption rate s and cumulative consumption is provided.

5.1.2 C OMBUSTION 

### T URBINE 

### The combined cycle plant is based on two CTG’s. The combustion turbine generator is representative of the advanced F Class turbines with an ISO base rating of 184,400 kW when firing natural gas. [ 64] This machine is an axial flow, single spool, constant speed unit, with variable inlet guide vanes and dry LNB combustion system. Each combustion turbine generator is provided with inlet air filtration systems; inlet silencers; lube and control oil systems including cooling; electric motor starting systems; acoustical enclosures including heating and ventilation; control systems includ ing supervisory, fire protection, and fuel systems. No back up fuel was envisioned for this project.Cost and Performance Comparison of Fossil Energy Power Plants

432 

### The CTG is typically supplied in several full y shop-fabricated modules , complete with all mechanical, electrical, and cont rol systems required for CTG oper ation. Site CTG installation involves module interconnection and linking CTG modules to the plant systems. The CTG package scope of supply for combined cycle appl ication, while project specific, does not vary much from project-to-project. A typi cal scope of supply is presented in Exhibit 5-1.

Exhibit 5-1 Combustion Turb ine Typical Scope of Supply

System System Scope

ENGINE ASSEMBLY Coupling to Generator, Dry Chemical Exhaust Bearing Fire Protection System, Insulation Blankets, Platforms, Stairs and Ladders Engine Assembly with Bedplate Variable Inlet Guide Vane System, Comp ressor, Bleed System, Purge Air System, Bearing Seal Air System, Combustors, Dual Fuel Nozzles, Turbine Rotor Cooler Walk-in acoustical enclosure HVAC, Lighting, and Low Pressure CO 2 Fire Protection System

MECHANICAL PACKAGE HVAC and Lighting, Air Compressor fo r Pneumatic System, Low Pressure CO 2 Fire Protection System

Lubricating Oil System and Control Oil System Lube Oil Reservoir, Accumulators, 2x1 00% AC Driven Oil Pumps, DC Emergency Oil Pump with Starter, 2x100% Oil Cooler s, Duplex Oil Filter, Oil Temperature and Pressure Control Valves, Oil Vapor Exhaus t Fans and Demister, Oil Heaters, Oil Interconnect Piping (SS and CS), Oil System Instrumentation, Oil for Flushing and First Filling

ELECTRICAL PACKAGE HVAC and Lighting, AC and DC Motor Control Centers, Generator Voltage Regulating Cabinet, Generator Protective Relay Cabinet, DC Distribution Panel, Battery Charger, Digital Control System with Local Control Panel (all control and monitoring functions as well as data logger and sequence of events recorder), Control System Valves and Instrumentatio n Communication link for interface with plant DCS Supervisory System, Bentley Nevada Vibration Monitoring System, Low Pressure CO 2 Fire Protection System, Cable Tray and Conduit Provisions for Performance Testing including Test Port s, Thermowells, Instrumentation and DCS interface cards

INLET AND EXHAUST SYSTEMS Inlet Duct Trash Screens, Inlet Duct and Silencers, Self Cleaning Filters, Hoist System For Filter Maintenance, Evapor ative Cooler System, Exhaust Duct Expansion Joint, Exhaust Silencers Inle t and Exhaust Flow, Pressure and Temperature Ports and Instrumentation FUEL SYSTEMS

N. Gas System Gas Valves Including Vent, Throttle and Trip Valves, Gas Filter/Separator, Gas Supply Instruments and Instrument Panel STARTING SYSTEM Enclosure, Starting Motor or Static Start System, Turning Gear and Clutch Assembly, Starting Clutch, Torque Converter

GENERATOR Static or Rotating Exciter (Excitation transformer to be included for a static system), Line Termination Enclosure with CTs, VTs, Surge Arrestors, and Surge Capacitors, Neutral Cubicle with CT, Neutral Tie Bus, Grounding Transformer, and Secondary Resistor, Generator Gas Dryer, Seal Oil System (including Defoaming Tank, Reservoir, Seal Oil Pump, Emergenc y Seal Oil Pump, Vapor Extractor, and Oil Mist Eliminator), Gener ator Auxiliaries Control En closure, Generator Breaker, Iso-Phase bus connecting generator an d breaker, Grounding System Connectors

Generator Cooling TEWAC System (including circulation syst em, interconnecting piping and controls), or Hydrogen Cooling System (including H 2 to Glycol and Glycol to Air heat exchangers, liquid level detector circulation system, interconnecting piping and controls)

MISCELLANEOUS Interconnecting Pipe, Wire, Tubing and Cable Instrument Air System Including Air Dryer On Line and Off Line Water Wash System LP CO 2 Storage Tank Drain System Drain Tanks Coupling, Coupling Cover and Associated HardwareCost and Performance Comparison of Fossil Energy Power Plants

433 

### The generators would typically be provided with the combustion turbine package. The generators are assumed to be 24 kV, 3-phase, 60 hertz, constructed to meet American National Standards Institute (ANSI) and National El ectrical Manufacturers Association (NEMA) standards for turbine-driven synchronous generators . The generator is tota lly enclosed, water-air cooled (TEWAC), complete with excitation system, cooling, and protective relaying.

5.1.3 H EAT 

### R ECOVERY 

### S TEAM 

### G ENERATOR 

### The HRSG is configured with HP, IP, and LP steam drums, and superheater, reheater, and economizer sections. The HP drum is supplied with feedwater by the HP boiler feed pump to generate HP steam, which passes to the superhea ter section for heating to 566°C (1050°F). The IP drum is supplied with feedwater from an inters tage bleed on the HP boiler feed pump. The IP steam from the drum is superheated to 482°C (900°F) and mixed with hot reheat steam from the reheat section at 510°C (950oF) and a portion of HP steam also at 510°C (950oF). The combined flows are admitted into the IP section of the stea m turbine. The LP drum provides steam to the integral deaerator, and also to the LP turbine.
The economizer sections heat condensate and feed water (in separate tube bundles). The HRSG tubes are typically comprised of bare surface and/or finned tubi ng or pipe material. The hightemperature portions are type P 91 or P22 ferritic alloy materia l; the low-temperature portions (< 399°C [750°F]) are carbon steel. Each HRSG exhausts directly to the stack, which is fabricated from carbon steel plate materials and li ned with Type 409 stainless steel. The stack for the NGCC cases is assumed to be 46 m (150 ft ) high, and the cost is included in the HRSG account.

5.1.4 NO X 

### C ONTROL 

### S YSTEM 

### This reference plant is designed to achi eve 2.5 ppmvd NOx emissions (expressed as NO 2 

### and referenced to 15 percent O 2 

### ). Two measures are taken to redu ce the NOx. The first is a dry low NOx burner in the CTG. The dry LNB burners are a low NOx design and reduce the emissions to about 25 ppmvd (referenced to 15 percent O 2 

### ). [ 65]
The second measure taken to reduce the NOx emi ssions was the installation of a SCR system. SCR uses ammonia and a catalyst to reduce NOx to N 2 

### and H 2 

### O. The SCR system consists of reactor, and ammonia supply and storage system . The SCR system is designed for 90 percent reduction while firing natural gas. This along with the dry LNB achieves the emission limit of 2.5 ppmvd (referenced to 15 percent O 2 

### ). Operation Description - The SCR reactor is located in th e flue gas path inside the HRSG between the high pressure and intermediate pressu re sections. The SCR reactor is equipped with one catalyst layer consisting of catalyst modules st acked in line on a supporti ng structural frame. The SCR reactor has space for installation of an a dditional layer. Ammonia is injected into the gas immediately prior to entering the SCR reactor. The ammonia injection grid is arranged into several sections, and consists of multiple pipe s with nozzles. Ammoni a flow rate into each injection grid section is cont rolled taking into account imbala nces in the flue gas flow distribution across the HRSG. The catalyst co ntained in the reactor enhances the reaction between the ammonia and the NOx in the gas. Th e catalyst consists of various active materials such as titanium dioxide, vanadium pentoxide, an d tungsten trioxide. The optimum inlet flue gas temperature range for th e catalyst is 260°C (500 ° F) to 343°C (650 ° F).Cost and Performance Comparison of Fossil Energy Power Plants

434 

### The ammonia storage and injection system consists of the unloading facilities, bulk storage tank, vaporizers, and dilution air skid.

5.1.5 C ARBON 

### D IOXIDE 

### R ECOVERY 

### F ACILITY


### A CDR facility is used in Case 14 to remove 90 percent of the CO 2 

### in the flue gas exiting the HRSG, purify it, and compress it to a supercritical condition. It is assumed that all of the carbon in the natural gas is converted to CO 2 

### . The CDR is comprised of flue gas supply, CO 2 

### absorption, solvent stripping and reclaiming, and CO 2 

### compression and drying.
The CO 2 

### absorption/stripping/solvent reclaim pr ocess for Case 14 is based on the Fluor Econamine FG Plus technology as pr eviously described in Section 4.1.7 with the exception that no SO 2 

### polishing step is required in the NGCC case. If the pipeline natural gas used in this study contained the maximum amount of sulfur allowed per EPA specifications (0.6 gr S/100 scf), the flue gas would contain 0.4 ppmv of SO 2 

### , which is well below the limit where a polishing scrubber would be required (10 ppmv). A descripti on of the basic process st eps is repeated here for completeness with minor modifications to re flect application in an NGCC system as opposed to PC.
Flue Gas Cooling and Supply The function of the flue gas cooling and supply syst em is to transport flue gases from the HRSG to the CO 2 

### absorption tower, and condition flue gas pr essure, temperature and moisture content so it meets the requirements of the Econamine process. Temperature and hence moisture content of the flue gas exiting the HRSG is reduced in the Direct Contact Flue Gas Cooler, where flue gas is cooled using cooling water. The water condensed from the flue gas is collected in the bottom of the Direct Contact Flue Gas Cooler section and re-circulated to the top of th e Direct Contact Flue Ga s Cooler section via the Flue Gas Circulation Water Cooler , which rejects heat to the pl ant circulating water system. Level in the Direct Contact Flue Gas Cooler is controlled by di recting the excess water to the cooling water return line. In the Direct Contact Flue Gas Cool er, flue gas is cooled beyond the CO 2 

### absorption process requirements to 33°C (91°F) to account for the subsequent flue gas temperature increase of 14°C (25°F) in the fl ue gas blower. Downstream from the Direct Contact Flue Gas Cooler flue ga s pressure is boosted in the fl ue gas blowers by approximately 0.01 MPa (2 psi) to overcome pressure drop in the CO 2 

### absorber tower.
Circulating Water System Cooling water is provided from the NGCC plant ci rculating water system and returned to the NGCC plant cooling tower. The CDR facility requi res a significant amount of cooling water for flue gas cooling, water wash cooling, absorber intercooling, reflux c ondenser duty, reclaimer cooling, the lean solvent cooler, and CO 2 

### compression interstage cool ing. The cooling water requirements for the CDR facility in the NGCC capture case is about 681,380 lpm (180,000 gpm), which greatly exceeds the NGCC plant cooling water requirement of about 227,125 lpm (60,000 gpm).Cost and Performance Comparison of Fossil Energy Power Plants

435 

### CO 2 

### Absorption The cooled flue gas enters the bottom of the CO 2 

### Absorber and flows up through the tower countercurrent to a stream of lean MEA-ba sed solvent called Econamine FG Plus. Approximately 90 percent of the CO 2 

### in the feed gas is absorbed into the lean solvent, and the rest leaves the top of the absorb er section and flows into the water wash section of the tower. The lean solvent enters the top of the absorber, absorbs the CO 2 

### from the flue gases and leaves the bottom of the absorber with the absorbed CO 2 

### .
Water Wash Section The purpose of the Water Wash section is to minimize solvent losses due to mechanical entrainment and evaporation. The flue gas from the top of the CO 2 

### Absorption section is contacted with a re-circulating stre am of water for the removal of mo st of the lean solvent. The scrubbed gases, along with unrecovere d solvent, exit the top of the wash section for discharge to the atmosphere via the vent stack. The water st ream from the bottom of the wash section is collected on a chimney tray. A portion of the wate r collected on the chimne y tray spills over to the absorber section as water makeup for the am ine with the remainder pumped via the Wash Water Pump and cooled by the Wash Water Cool er, and recirculated to the top of the CO 2 

### Absorber. The wash water level is maintained by water makeup from the Wash Water Makeup Pump.
Rich/Lean Amine Heat Exchange System
The rich solvent from the bottom of the CO 2 

### Absorber is preheated by the lean solvent from the Solvent Stripper in the Rich Lean Solvent Exchanger. The heated rich solvent is routed to the Solvent Stripper for removal of the absorbed CO 2 

### . The stripped solvent from the bottom of the Solvent Stripper is pumped via th e Hot Lean Solvent Pumps through the Rich Lean Exchanger to the Solvent Surge Tank. Prior to entering the Solvent Surge Tank, a slipstream of the lean solvent is pumped via the Solvent Filter F eed Pump through the Solvent Filter Package to prevent buildup of contaminants in the solution. From the Solvent Surge Ta nk the lean solvent is pumped via the Warm Lean Solvent Pumps to the Lean Solvent Cooler fo r further cooling, after which the cooled lean solvent is returned to the CO 2 

### Absorber, completing the circulating solvent circuit.
Solvent Stripper The purpose of the Solvent Stripper is to separate the CO 2 

### from the rich solvent feed exiting the bottom of the CO 2 

### Absorber. The rich solvent is colle cted on a chimney tray below the bottom packed section of the Solvent Stripper and rout ed to the Solvent Stripper Reboilers where the rich solvent is heated by steam, stripping the CO 2 

### from the solution. Steam is provided from the LP section of the steam turbine at about 0.47 MPa (68 psia) and 291°C (555°F). The hot wet vapor from the top of th e stripper containing CO 2 

### , steam, and solvent vapor, is partially condensed in the Solvent Stripper Condenser by cross exchanging the hot wet vapor with cooling water. The partially condensed stream then flow s to the Solvent Stripper Reflux Drum where the vapor and liquid are sepa rated. The uncondensed CO 2 

### -rich gas is then delivered to the CO 2 

### product compressor. The condensed liquid from the Solvent Stripper Reflux Drum is pumped via the Solvent Stripper Reflux Pumps where a por tion of condensed overhead liquid is used as make-up water for the Water Wash section of the CO 2 

### Absorber. The rest of the pumped liquid isCost and Performance Comparison of Fossil Energy Power Plants

436 

### routed back to the Solvent Stripper as reflux, wh ich aids in limiting the amount of solvent vapors entering the stripper overhead system.
Solvent Stripper Reclaimer A small slipstream of the lean solvent from th e Solvent Stripper bottoms is fed to the Solvent Stripper Reclaimer for the removal of high-boi ling nonvolatile impurities (heat stable salts – HSS), volatile acids and iron products from the circulating solvent so lution. The solvent bound in the HSS is recovered by reacti on with caustic and heating with steam. The solvent reclaimer system reduces corrosion, foaming and fouling in the solvent system. The reclaimed solvent is returned to the Solvent Stripper and the spent solvent is pumped via the Solvent Reclaimer Drain Pump to the Solvent Reclaimer Drain Tank.
Steam Condensate Steam condensate from the Solvent Stripper Re claimer accumulates in the Solvent Reclaimer Condensate Drum and level controlled to th e Solvent Reboiler Condensate Drum. Steam condensate from the Solvent Stripper Reboilers is also collected in the Solvent Reboiler Condensate Drum and returned to the steam cy cle just downstream of the deaerator via the Solvent Reboiler Condensate Pumps. Corrosion Inhibitor System A proprietary corrosion inhibitor is continuously inject ed into the CO 2 

### Absorber rich solvent bottoms outlet line, the Solvent Stripper bottoms outlet line and the Solvent Stripper top tray. This constant injection is to help co ntrol the rate of corrosion throughout the CO 2 

### recovery plant system.
Gas Compression and Drying System In the compression section, the CO 2 

### is compressed to 15.3 MPa (2,215 psia) by a six-stage centrifugal compressor. The discharge pressures of the stages were balanced to give reasonable power distribution and discharge temperatures across the various stages as shown in Exhibit 5-2.
Power consumption for this large compressor was estimated assuming an isentropic efficiency of 84 percent. During compression to 15.3 MPa (2 ,215 psia) in the multiple-stage, intercooled compressor, the CO 2 

### stream is dehydrated to a dewpoint of -40oC (-40°F) with triethylene glycol. The virtually moisture-free supercritical CO 2 

### stream is delivered to the plant battery limit as sequestration ready. CO 2 

### TS&M costs were estimated and included in LCOE using the methodology described in Section 2.7.

5.1.6 S TEAM 

### T URBINE 

### The steam turbine consists of an HP section, an IP section, and one doubl e-flow LP section, all connected to the generator by a co mmon shaft. The HP and IP sections are contained in a single span, opposed-flow casing, with the double-flow LP section in a separate casing. Main steam from the boiler passes through the st op valves and control valves and enters the turbine at 16.5 MPa/566°C (2400 psig/1050°F). The steam initially enters the turbine near the middle of the high-pressure span, flows through the turbine, and retu rns to the HRSG for reheating. The reheat steam flows through the reh eat stop valves and interc ept valves and enters the IP section at 2.3 MPa/510°C (328 psia/950°F) . After passing through the IP section, theCost and Performance Comparison of Fossil Energy Power Plants

437 

### steam enters a cross-over pipe, which transports the steam to the LP section. A branch line equipped with combined stop/intercept valves co nveys LP steam from the HRSG LP drum to a tie-in at the cross-over line. The steam divides into two paths and flows through the LP sections exhausting downward into the condenser.

Exhibit 5-2 CO 2 

### Compressor Interstage Pressures

Stage Outlet Pressure, MPa (psia)
1 0.36 (52)
2 0.78 (113)
3 1.71 (248)
4 3.76 (545)
5 8.27 (1,200)
6 15.3 (2,215)

Turbine bearings are lubricated by a closed-loop, water-cooled pressurized oil system. Turbine shafts are sealed against air in-leakage or steam blowout using a modern positive pressure variable clearance shaf t sealing design arrangement connect ed to a low-pressure steam seal system. The generator is a hydrogen-cooled s ynchronous type, generating power at 24 kV. A static, transformer type exciter is provided. The generator is cooled with a hydrogen gas recirculation system using fans mounted on th e generator rotor shaft. The steam turbine generator is controlled by a triple-redundant microprocessor-ba sed electro-hydraulic control system. The system provides digital control of the unit in accordance with programmed control algorithms, color monitor/operator interfacing, and datalink interfaces to the balance-of-plant distributed control system (DCS), and in corporates on-line repair capability.

5.1.7 W ATER AND 

### S TEAM 

### S YSTEMS 

### Condensate The function of the condensate sy stem is to pump condensate from the condenser hotwell to the deaerator, through the gland steam condenser; and the low-temperature economizer section in the HRSG. The system consists of one main condenser; two 50 percent capacity, motor-driven vertical multistage condensate pumps (total of two pump s for the plant); one gland steam condenser; condenser air removal vacuum pumps, condensat e polisher, and a low-temperature tube bundle in the HRSG. Condensate is delivered to a common discharg e header through two separate pump discharge lines, each with a check valve a nd a gate valve. A common mini mum flow recirculation lineCost and Performance Comparison of Fossil Energy Power Plants

438 

### discharging to the condenser is provided to main tain minimum flow requirements for the gland steam condenser and the condensate pumps.
Feedwater The function of the feedwater (FW) system is to pump the various feedwater streams from the deaerator storage tank in the HRSG to the re spective steam drums. One 100 percent capacity motor-driven feed pump is provided per each HRSG (total of two pumps for the plant). The FW pumps are equipped with an interstage takeoff to provide IP and LP feedwater. Each pump is provided with inlet and outlet isolation valves, ou tlet check valves, and individual minimum flow recirculation lines discharging back to the deae rator storage tank. The recirculation flow is controlled by pneumatic flow control valves. In addition, the suctions of the boiler feed pumps are equipped with startup strainers, which are utilized during initial startup and following major outages or system maintenance. Steam System The steam system is comprised of main, reheat, intermediate, and low-pressure steam systems. The function of the main steam system is to convey main steam from the HRSG superheater outlet to the HP turbine stop valv es. The function of the reheat system is to convey steam from the HP turbine exhaust to the HRSG reheater an d from the HRSG reheater outlet to the turbine reheat stop valves.
Main steam exits the HRSG s uperheater through a motor-operate d stop/check valve and a motoroperated gate valve, and is routed to the HP turbine. Cold reheat steam exits the HP turbine, and fl ows through a motor-operate d isolation gate valve to the HRSG reheater. Hot reheat steam exits at the HRSG reheater through a motor-operated gate valve and is routed to the IP turbines. Circulating Water System The function of the circulating water system is to supply coo ling water to condense the main turbine exhaust steam, for the auxiliary cooling sy stem and for the CDR facility in Case 14. The system consists of two 50 percent capacity vert ical circulating water pum ps (total of two pumps for the plant), a mechanical draft evaporative cooling tower, and inte rconnecting piping. The condenser is a single pass, horizontal type with divided water boxes. There are two separate circulating water circuits in each box. One-half of the condenser can be removed from service for cleaning or plugging tubes. This can be done during normal operation at reduced load. The auxiliary cooling system is a closed loop sy stem. Plate and frame heat exchangers with circulating water as the cooling medium are provided. The system provides cooling water to the following systems:
1. Combustion turbine generator lube oil coolers
2. Combustion turbine ge nerator air coolers
3. Steam turbine generator lube oil coolers
4. Steam turbine generator hydrogen coolers
5. Boiler feed water pumps
6. Air compressorsCost and Performance Comparison of Fossil Energy Power Plants

439 

### 7. Generator seal oil c oolers (as applicable)
8. Sample room chillers
9. Blowdown coolers
10. Condensate extraction pump-motor coolers The CDR system in Case 14 requires a substantia l amount of cooling water that is provided by the NGCC plant circulating water system. The additional cooling load imposed by the CDR is reflected in the significantly larger circulati ng water pumps and cooling tower in that case. Buildings and Structures
Structures assumed for NGCC cases can be summarized as follows:
1. Generation Building housing the STG
2. Circulating Water Pump House
3. Administration / Office / Control Room / Maintenance Building
4. Water Treatment Building
5. Fire Water Pump House

5.1.8 A CCESSORY 

### E LECTRIC 

### P LANT 

### The accessory electric plant consists of all switchgear and control equipment, generator equipment, station service equipm ent, conduit and cable trays, wire , and cable. It also includes the main transformer, required foundations and standby equipment.

5.1.9 I NSTRUMENTATION AND 

### C ONTROL 

### An integrated plant-wide DCS is provided. The DCS is a redundant microprocessor-based, functionally distributed system. The control room houses an array of video monitors and keyboard units. The monitor/keyboard units ar e the primary interface between the generating process and operations personnel. The DCS incor porates plant monitoring and control functions for all the major plant equipment. The DCS is designed to provide 99.5 percent availability. The plant equipment and the DCS are designed fo r automatic response to load changes from minimum load to 100 percent. Startup and shutdown routines are implemented as supervised manual procedures with operato r selection of modular auto mation routines available.Cost and Performance Comparison of Fossil Energy Power Plants

440 

### 5.2 NGCC CASES
This section contains an eval ution of plant designs for Case s 13 and 14. These two cases are similar in design and are based on an NGCC plant w ith a constant thermal input. Both plants use a single reheat 16.5 MPa/566°C/510°C (2400 psig/1050 ° F/950 ° F) cycle. The only difference between the two plants is that Case 14 includes CO 2 

### capture while Case 13 does not.
The balance of Section 5.2 is organized as follows:

• Process and System Description provides an overview of the technology operation as applied to Case 13. The systems that are common to all NGCC cases were covered in Section 5.1 and only features that ar e unique to Case 13 are di scussed further in this section.

• Key Assumptions is a summary of study and modeling assumptions re lavant to Cases 13 and 14.

• Sparing Philosophy is provided for both Cases 13 and 14.

• Performance Results provides the main m odeling results from Case 13, including the performance summary, environmental performance, water balance, mass and energy balance diagrams and energy balance table.

• Equipment List provides an itemized list of major equipment for Case 13 with account codes that correspond to the cost acc ounts in the Cost Estimates section.

• Cost Estimates provides a summary of capital and operating costs for Case 13.

• Process and System Description, Perform ance Results, Equipment List and Cost Estimates are reported for Case 14.

5.2.1 P ROCESS 

### D ESCRIPTION 

### In this section the NGCC process without CO 2 

### capture is described. The system description follows the block flow diagram (BFD) in Exhibit 5-3 and stream numbers reference the same Exhibit. The tables in Exhibit 5-4 provide process data for the numbered streams in the BFD. The BFD shows only one of the two combustion tu rbine/HRSG combinations , but the flow rates in the stream table are the total for two systems. Ambient air (stream 1) and natural gas (stream 2) are combined in the dry LNB, which is operated to control the rotor inle t temperature at 1399°C (2550°F). The flue gas exits the turbine at 631°C (1167°F) (stream 3) and passes into th e HRSG. The HRSG generates both the main steam and reheat steam for the steam turbine. Flue gas exits the HRSG at 104°C (220°F) and passes to the plant stackCost and Performance Comparisonof Fossil Energy Power Plants441Exhibit 5-3 Case 13 ProcessFlow Diagram, NGCC without CO2CaptureCost and Performance Comparison of Fossil Energy Power Plants

442 

### Exhibit 5-4 Case 13 Stream Table, NGCC without CO 2 

### Capture

123 4 V-L Mole Fraction

Ar 0.0092 0.0000 0.0089 0.0089 CH 4 0.0000 0.9390 0.0000 0.0000 C 2 H 6 0.0000 0.0320 0.0000 0.0000 C 3 H 8 0.0000 0.0070 0.0000 0.0000 C 4 H 10 0.0000 0.0040 0.0000 0.0000 CO 2 0.0003 0.0100 0.0405 0.0405 H 2 O 0.0099 0.0000 0.0869 0.0869 N 2 0.7732 0.0080 0.7430 0.7430 O 2 0.2074 0.0000 0.1207 0.1207 SO 2 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 V-L Flowrate (lb mol /hr) 120,220 4,793 250,304 250,304 V-L Flowrate (lb/hr) 3,469,190 82,591 7,103,560 7,103,560 Temperature (°F) 59 100 1,167 220 Pressure (psia) 14.7 450.0 15.2 15.2 Enthalpy (BTU/lb) A 13.1 34.4 360.5 106.6 Density (lb/ft 3 ) 0.076 1.291 0.025 0.059 Molecular Weight 28.857 17.232 28.380 28.380 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparison of Fossil Energy Power Plants

443 

### 5.2.2 K EY 

### S YSTEM 

### A SSUMPTIONS 

### System assumptions for Cases 13 and 14, NGCC with and without CO 2 

### capture, are compiled in Exhibit 5-5.

Exhibit 5-5 NGCC Plant St udy Configuration Matrix

Case 13 w/o CO 2 

### Capture Case 14 w/CO 2 

### Capture
Steam Cycle, MPa/°C/°C (psig/°F/°F) 16.5/566/510 (2400/1050/950) 16.5/566/510 (2400/1050/950) Fuel Natural Gas Natural Gas Fuel Pressure at Plant Battery Limit MPa (psig) 3.1 (450) 3.1 (450)
Condenser Pressure, mm Hg (in Hg) 50.8 (2) 50.8 (2) Cooling Water to Condenser, °C (oF) 16 (60) 16 (60) Cooling Water from Condenser , °C (oF) 27 (80) 27 (80) Stack Temperature, °C (°F) 104 (220) 29 (85) SO 2 

### Control Low Sulfur Fuel Low Sulfur Fuel NOx Control LNB and SCR LNB and SCR SCR Efficiency, % (A) 90 90 Ammonia Slip (End of Catalyst Life), ppmv 10 10

Particulate Control N/A N/A Mercury Control N/A N/A CO 2 

### Control N/A Econamine FG Plus CO 2 

### Capture, % (A) N/A 90

CO 2 

### Sequestration N/A Off-site Saline Formation A. Removal efficiencies are based on the flue gas content

Balance of Plant – Cases 13 and 14 The balance of plant assumptions are comm on to both NGCC cases and are presented in Exhibit 5-6.Cost and Performance Comparison of Fossil Energy Power Plants

444 

### Exhibit 5-6 NGCC Balance of Plant Assumptions Cooling System Recirculating Wet Cooling Tower Fuel and Other Storage Natural Gas Pipeline supply at 3.1 MPa (450 psia) and 38°C (100°F) Ash N/A Gypsum N/A Limestone N/A Plant Distribution Voltage Motors below 1 hp 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 and Gas Turbine generators 24,000 volt

Grid Interconnection voltage 345 kV Water and Waste Water Makeup Water The water supply is 50 percen t from a local Publicly Owned Treatment Works (POTW) and 50 percent from groundwater, and is assumed to be in sufficient quantities to meet plant makeup requirements. Makeup for potable, process, and de-ionized (DI) water is drawn from municipal sources. Process Wastewater 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 is sized for 5.68 cubic meters per day (1,500 gallons per day) Water Discharge Most of the proce ss wastewater is recycled to the cooling tower basin. Blowdown is treated for chloride and metals, and discharged.

5.2.3 S PARING 

### P HILOSOPHY 

### Dual trains are used to accommodate the si ze of commercial gas turbines. There is no redundancy other than normal sparing of rotating equipment. The plant design consists of the following major subsystems:

• Two advanced F class combustion turbine generators (2 x 50%)

• Two 3-pressure reheat HRSGs with self supporting stacks and SCR systems (2 x 50%)

• One 3-pressure reheat, triple-admissi on steam turbine generator (1 x 100%)Cost and Performance Comparison of Fossil Energy Power Plants

445 

### • Two trains of Econamine FG Plus CO 2 

### capture (2 x 50%) (Case 14 only)

5.2.4 C ASE 

### 13 P ERFORMANCE 

### R ESULTS 

### The plant produces a net output of 560 MW at a net plant efficien cy of 50.8 percent (HHV basis). Overall plant performance is summarized in Exhibit 5-7 which includes auxiliary power requirements.
Exhibit 5-7 Case 13 Plant Performance Summary
POWER SUMMARY (Gross Power at Generator Terminals, kWe) Gas Turbine Power 370,170 Steam Turbine Power 200,030 TOTAL POWER, kWe 570,200 AUXILIARY LOAD SUMMARY, kWe Condensate Pumps 130 Boiler Feedwater Pumps 2,970 Miscellaneous Balance of Plant (Note 1) 500 Gas Turbine Auxiliaries 700 Steam Turbine Auxiliaries 100 Amine System Auxiliaries N/A
CO 2 

### Compression N/A Circulating Water Pumps 2,450 Cooling Tower Fans 1,260 Transformer Loss 1,730 TOTAL AUXILIARIES, kWe 9,840 NET POWER, kWe 560,360 Net Plant Efficiency (HHV) 50.8% Net Plant Heat Rate (Btu/kWh) 6,719 CONDENSER COOLING DUTY, 10 6 

### kJ/h (10 6 

### Btu/h) 1,162 (1,102)
CONSUMABLES Natural Gas, kg/h (lb/h) 74,926 (165,182) Thermal Input, kWt (HHV) 1,103,363 Raw Water Usage, m 3 

### /min (gpm) 9.5 (2,512)
Notes: 1. Includes plant control systems, lighting, HVA C, and miscellaneous low voltage loadsCost and Performance Comparison of Fossil Energy Power Plants

446 

### Environmental Performance The environmental targets for emissions of NOx, SO 2 

### and particulate matter were presented in Section 2.4. A summary of the plant air emissions for Case 13 is presented in Exhibit 5-8.

Exhibit 5-8 Case 13 Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)

SO 2 

### Negligible Negligible Negligible NO X 

### 0.004 (0.009) 115 (127) 0.027 (0.060)

Particulates Negligible Negligible Negligible

Hg Negligible Negligible Negligible

CO 2 

### 51 (119) 1,507,000 (1,662,000) 355 (783)

CO 2 1 

### 361 (797)

1 

### CO 2 

### emissions based on net power instead of gross power
The operation of the modern, state-of-the-art ga s turbine fueled by natural gas, coupled to a HRSG, results in very low levels of NOx emissions and negligible levels of SO 2 

### , particulate and Hg emissions. As noted in Section 2.4, if th e fuel contains the maximum amount of sulfur compounds allowed in pipeline natural gas, the NGCC SO 2 

### emissions would be 21 tonnes/yr (23 tons/yr) at 85 percent cap acity factor, or 0.00195 lb/MMBtu. The low level of NOx production (2.5 ppmvd at 15 percent O 2 

### ) is achieved by utilizing a dry LNB coupled with an SCR system.
CO 2 

### emissions are reduced relative to those pr oduced by burning coal given the same power output because of the higher heat content of natura l gas, the lower carbon in tensity of gas relative to coal, and the higher overall e fficiency of the NGCC plant relative to a coal-fired plant.
Exhibit 5-9 shows the overall water balance fo r the plant. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent) . The water usage represents only the contribution of raw water makeup. In so me cases the water demand is greater than raw water makeup because of internal water recycle streams. For example, the boiler feedwater blowdown stream is re-used as makeup to the cooling tower, thus reducing the raw water requirement by that amount.Cost and Performance Comparison of Fossil Energy Power Plants

447 

### Exhibit 5-9 Case 13 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle,

m 3 

### /min (gpm) Raw Water Makeup,

m 3 

### /min (gpm)
BFW Makeup 0.1 (23) 0 0.1 (23)
Cooling Tower Makeup 9.5 (2,511) 0.1 (23) 9.4 (2,488)
Total 9.6 (2,534) 0.1 (23) 9.5 (2,511)

Heat and Mass Balance Diagrams A heat and mass balance diagram is shown for the NGCC in Exhibit 5-10. An overall plant energy balance is provided in tabular form in Exhibit 5-11. The power out is the combined combustion turbine and steam turbin e power prior to generator losses. The power at the generator terminals (shown in Exhibit 5-7) is calculated by multiplying the power out by a combined generator effici ency of 98.4 percent.Cost and Performance Comparison of Fossil Energy Power Plants

448 

### This page intentionally left blankCost and Performance Comparisonof Fossil Energy Power Plants449Exhibit 5-10 Case 13 Heat and Mass Balance, NGCC without CO2CaptureCost and Performance Comparisonof Fossil Energy Power Plants450This page intentionally left blankCost and Performance Comparison of Fossil Energy Power Plants

451 

### Exhibit 5-11 Case 13 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total
Heat In (MMBtu/hr) Natural Gas 3,764.8 5.7 3,770.5 Ambient Air 91.1 91.1 Water 0.3 0.3 Auxiliary Power 33.6 33.6 Totals 3,764.8 97.1 33.6 3,895.5 Heat Out (MMBtu/hr) Flue Gas Exhaust 757.5 757.5 Condenser 1,102.0 1,102.0 Process Losses (1) 58.7 58.7 Power 1,977.3 1,977.3 Totals 0.0 1,918.2 1,977.3 3,895.5 (1) Process Losses are calculated by difference a nd reflect various boiler, turbine, and other heat and work losses. Aspen flowsh eet balance is within 0.5 percent.Cost and Performance Comparison of Fossil Energy Power Plants

452 

### 5.2.5 C ASE 

### 13

– M AJOR 

### E QUIPMENT 

### L IST 

### Major equipment items for the NGCC plant with no CO 2 

### capture are shown in the following tables. The accounts used in the equipment lis t correspond to the account numbers used in the cost estimates in Section 5.2.6. In general, the design c onditions include a 10 percent contingency for flows and heat duties and a 21 pe rcent contingency for heads on pumps and fans.

ACCOUNT 1 COAL AND SORBENT HANDLING
N/A

ACCOUNT 2 FUEL AND SORBENT PREPARATION AND FEED
Equipment No. Description Type Operating Qty. Spares

1 Gas Pipeline Underground, coated carbon steel, wrapped cathodic protection 16 km (10 mile) 0

2 Gas Metering Station -- 1 0 Design Condition

56 m3/min @ 3.1 MPa (1,991 acfm @ 450 psia) 41 cm (16 in) standard wall pipe

56 m3/min (1,991 acfm)Cost and Performance Comparison of Fossil Energy Power Plants

453 

### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 2 0

2 Condensate Pumps Vertical canned 2 1

4 Auxiliary Boiler Shop fabricated, water tube 1 0

5 Service Air Compressors Flooded Screw 2 1

6 Instrument Air Dryers Duplex, regenerative 2 1

7 Closed Cycle Cooling Heat Exchangers Plate and frame 2 0

8 Closed Cycle Cooling Water Pumps Horizontal centrifugal 2 1

9 Engine-Driven Fire Pump Vertical turbine, diesel engine 1 1

10 Fire Service Booster Pump Two-stage horizontal centrifugal 1 1

11 Raw Water Pumps Stainless steel, single suction 2 1

12 Filtered Water Pumps Stainless steel, single suction 2 1

13 Filtered Water Tank Vertical, cylindrical 1 0

14 Makeup Water Demineralizer Multi-media filter, cartridge filter, RO membrane assemblyand electrodeionization unit 1 0

15 Liquid Waste Treatment System 1 0 1

143,847 liter (38,000 gal)

341 lpm (90 gpm)

10 years, 24-hour storm 3,785 lpm @ 107 m H2O (1,000 gpm @ 350 ft H2O)

2,650 lpm @ 76 m H2O (700 gpm @ 250 ft H2O) 5,300 lpm @ 18 m H2O (1,400 gpm @ 60 ft H2O)

151 lpm @ 49 m H2O (40 gpm @ 160 ft H2O)

13 m3/min (450 scfm)

15,520 lpm @ 21 m H2O (4,100 gpm @ 70 ft H2O) 2 HP water: 4,088 lpm @ 2,103 m

H2O (1,080 gpm @ 6,900 ft H2O) IP water: 114 lpm @ 274 m H2O (30 gpm @ 900 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C (40,000 lb/h, 400 psig, 650°F)

13 m3/min @ 0.7 MPa (450 scfm @ 100 psig) LP water: 681 lpm @ 9.1 m H2O (180 gpm @ 30 ft H2O) Design Condition

696,521 liters (184,000 gal)

4,883 lpm @ 85 m H2O (1,290 gpm @ 280 ft H2O)

40 MMkJ/hr (38 MMBtu/hr) 3 Boiler Feedwater Pump Horizontal, split case, multi-stage, centrifugal, with interstage bleed for IP and LP feedwaterCost and Performance Comparison of Fossil Energy Power Plants

454 

### ACCOUNT 4 GASIFIER, BOILER AND ACCESSORIES
N/A

ACCOUNT 5 FLUE GAS CLEANUP
N/A

ACCOUNT 6 COMBUSTION TURBIN E GENERATORS AND AUXILIARIES
Equipment No. Description Type Operating Qty. Spares

1 Gas Turbine Advanced F class w/ dry low-NOx burner 2 0

2 Gas Turbine Generator TEWAC 2 0 Design Condition

185 MW

210 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase



### ACCOUNT 7 WASTE HEAT BOILER, DUCTING, AND STACK

Equipment No. Description Type Operating Qty. Spares

1 Stack CS plate, type 409SS liner 2 0

3 SCR Reactor Space for spare layer 2 0

4 SCR Catalyst -- 1 layer 0

5 Dilution Air Blowers Centrifugal 2 1

6 Ammonia Feed Pump Centrifugal 2 1

7 Ammonia Storage Tank Horizontal tank 1 0 2 0 2 Heat Recovery Steam Generator Drum, multi-pressure with economizer section and integral deaerator Reheat steam - 231,539 kg/h, 2.3 MPa/510°C (510,456 lb/h, 335 psig/950°F) Design Condition

46 m (150 ft) high x 5.2 m (17 ft) diameter

Main steam - 240,660 kg/h, 16.5 MPa/566°C (530,564 lb/h, 2,400 psig/1,050°F)

1,773,548 kg/h (3,910,000 lb/h) Space available for an additional catalyst layer 21 m3/min @ 91 cm WG (750 scfm @ 36 in WG)

3.8 lpm @ 82 m H2O (1 gpm @ 270 ft H2O)

87,065 liter (23,000 gal)Cost and Performance Comparison of Fossil Energy Power Plants

455 

### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type Operating Qty. Spares

1 Steam Turbine Tandem compound,HP, IP, and twoflow LP turbines 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitation 1 0

3 Steam Bypass One per HRSG 2 0

4 Surface Condenser Single pass, divided waterbox including
vacuum pumps 1 0 211 MW 16.5 MPa/566°C/510°C (2400 psig/ 1050°F/950°F)

1,276 MMkJ/hr, (1,210 MMBtu/hr), Inlet water temperature 16°C (60°F),

Water temperature rise 11°C (20°F) 230 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase

50% steam flow @ design steam conditions Design Condition



### ACCOUNT 9 COOLING WATER SYSTEM
Equipment No. Description Type Operatin g Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 1 0 Design Condition
246,054 lpm @ 30.5 m (65,000 gpm @ 100 ft)
11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT 1,365 MMkJ/hr (1,295 MMBtu/hr) heat load



### ACCOUNT 10 ASH/SPENT SORBEN T RECOVERY AND HANDLING
N/ACost and Performance Comparison of Fossil Energy Power Plants

456 

### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type Operating Qty. Spares

1 CTG Transformer Oil-filled 2 0

3 Auxiliary Transformer Oil-filled 1 1

4 Low Voltage Transformer Dry ventilated 1 1

5 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 2 0

6 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 1 0

7 Medium Voltage Switchgear Metal clad 1 1

8 Low Voltage Switchgear Metal enclosed 1 1

9 Emergency Diesel Generator Sized for emergency shutdown 1 0 2 STG Transformer Oil-filled 1 0

24 kV/4.16 kV, 09 MVA, 3-ph, 60 Hz Design Condition
24 kV/345 kV, 210 MVA, 3-ph, 60 Hz 24 kV/345 kV, 220 MVA, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz 4.16 kV/480 V, 1 MVA, 3-ph, 60 Hz

750 kW, 480 V, 3-ph, 60 Hz



### ACCOUNT 12 INSTRUMENTATION AND CONTROL

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) 1 0

3 DCS - Data Highway Fiber optic 1 0 2 DCS - Processor Microprocessor with redundant input/output N/A 0

Fully redundant, 25% spare Design Condition

Operator stations/printers and engineering stations/printers

1Cost and Performance Comparison of Fossil Energy Power Plants

457 

### 5.2.6 C ASE 

### 13

– C OST 

### E STIMATING 

### The cost estimating methodology was desc ribed previously in Section 2.6. Exhibit 5-12 shows the total plant capital cost summary organized by cost account and Exhibit 5-13 shows a more detailed breakdown of the capital costs. Exhibit 5-14 shows the ini tial and annual O&M costs.
The estimated TPC of the NGCC with no CO 2 

### capture is $554/kW. No process contingency was included in this case because all elements of the technology are commercially proven. The project contingency is 10.7 percent of TPC. The 20-year LCOE is 68.4 mills/kWh.Cost and Performance Comparisonof Fossil Energy Power Plants458Exhibit 5-12 Case 13 Total Plant Cost SummaryClient:USDOE/NETLReport Date:10-May-07Project:Bituminous Baseline StudyCase:Case 13 - NGCC w/o CO2Plant Size:560.4 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING $0 $0 $0 $0 $0$0$0 $0 $0$0$02 COAL & SORBENT PREP & FEED $0 $0 $0 $0 $0$0$0 $0 $0$0$03 FEEDWATER & MISC. BOP SYSTEMS $21,803 $4,553 $6,567 $0 $0$32,923$2,758 $0 $5,693$41,374$744 GASIFIER & ACCESSORIES4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0$0$0 $0 $0$0$04.2 Syngas Cooling $0 $0 $0 $0 $0$0$0 $0 $0$0$04.3 ASU/Oxidant Compression $0 $0 w/equip. $0 $0$0$0 $0 $0$0$04.4-4.9 Other Gasification Equipment $0 $0 $0 $0 $0$0$0 $0 $0$0$0SUBTOTAL 4 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05 Gas Cleanup & Piping $0 $0 $0 $0 $0$0$0 $0 $0$0$05BCO2REMOVAL & COMPRESSION$0 $0 $0 $0 $0$0$0 $0 $0$0$06 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator $72,000 $0 $4,588 $0 $0$76,589$6,456 $0 $8,304$91,349$1636.2-6.9 Combustion Turbine Other $0 $681 $709 $0 $0$1,390$116 $0 $301$1,807$3SUBTOTAL 6 $72,000 $681 $5,298 $0 $0 $77,979 $6,571 $0 $8,606 $93,156 $1667 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator $32,000 $0 $4,200 $0 $0$36,200$3,060 $0 $3,926$43,186$777.2-7.9 SCR System, Ductwork and Stack $1,177 $881 $1,044 $0 $0$3,101$263 $0 $544$3,908$7SUBTOTAL 7 $33,177 $881 $5,244 $0 $0 $39,301 $3,323 $0 $4,470 $47,094 $848 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $22,464 $0 $3,675 $0 $0$26,139$2,244 $0 $2,838$31,222$568.2-8.9 Turbine Plant Auxiliaries and Steam Piping $8,415 $755 $5,340 $0 $0$14,511$1,171 $0 $2,151$17,834$32SUBTOTAL 8 $30,880 $755 $9,016 $0 $0 $40,651 $3,415 $0 $4,989 $49,055 $889 COOLING WATER SYSTEM $5,474 $4,330 $3,883 $0 $0$13,686$1,128 $0 $2,107$16,921$3010 ASH/SPENT SORBENT HANDLING SYS $0 $0 $0 $0 $0$0$0 $0 $0$0$011 ACCESSORY ELECTRIC PLANT $15,227 $3,466 $7,567 $0 $0$26,261$1,986 $0 $3,074$31,321$5612 INSTRUMENTATION & CONTROL $5,308 $555 $4,596 $0 $0$10,459$884 $0 $1,301$12,643$2313 IMPROVEMENTS TO SITE $1,635 $888 $4,384 $0 $0$6,907$608 $0 $1,503$9,017$1614 BUILDINGS & STRUCTURES $0 $3,920 $4,225 $0 $0$8,145$661 $0 $1,321$10,127$18TOTAL COST $185,504 $20,029 $50,779 $0 $0 $256,312 $21,334 $0 $33,064 $310,710 $554TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants459Exhibit 5-13 Case 13 Total Plant Cost DetailsClient:USDOE/NETLReport Date:10-May-07Project:Bituminous Baseline StudyCase:Case 13 - NGCC w/o CO2Plant Size:560.4 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material LaborSales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING1.1 Coal Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.2 Coal Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.3 Coal Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.4 Other Coal Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.9 Coal & Sorbent Hnd.Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 1. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02 COAL & SORBENT PREP & FEED2.1 Coal Crushing & Drying incl w/2.3 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.2 Prepared Coal Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.3 Slurry Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.9 Coal & Sorbent Feed Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 2. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $03 FEEDWATER & MISC. BOP SYSTEMS3.1 FeedwaterSystem $2,501 $2,609 $2,147 $0 $0 $7,256 $597 $0 $1,178 $9,030 $163.2 Water Makeup & Pretreating $1,459 $152 $761 $0 $0 $2,373 $201 $0 $515 $3,088 $63.3 Other Feedwater Subsystems $1,151 $390 $328 $0 $0 $1,869 $150 $0 $303 $2,321 $43.4 Service Water Systems $174 $355 $1,151 $0 $0 $1,679 $145 $0 $365 $2,190 $43.5 Other Boiler Plant Systems $1,167 $448 $1,037 $0 $0 $2,652 $222 $0 $431 $3,305 $63.6 FO Supply Sys & Nat Gas $13,960 $483 $421 $0 $0 $14,864 $1,251 $0 $2,417 $18,533 $333.7 Waste Treatment Equipment $524 $0 $300 $0 $0 $824 $71 $0 $179 $1,074 $23.8 Misc. Equip.(cranes,AirComp.,Comm.) $869 $117 $421 $0 $0 $1,406 $121 $0 $306 $1,833 $3SUBTOTAL 3. $21,803 $4,553 $6,567 $0 $0 $32,923 $2,758 $0 $5,693 $41,374 $744 GASIFIER & ACCESSORIES4.1 Gasifier, Syngas Cooler & Auxiliaries(E-GAS$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.2 Syngas Cooling ( w/ 4.1 w/4.1 $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $04.3 ASU/Oxidant Compression $0 $0 w/equip. $0 $0 $0 $0 $0 $0 $0 $04.4 LT Heat Recovery & FG Saturation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $04.6 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.8 Major Component Rigging $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.9 Gasification Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 4. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants460Exhibit 5-13 Case 13 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:10-May-07Project:Bituminous Baseline StudyCase:Case 13 - NGCC w/o CO2Plant Size:560.4 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW5A GAS CLEANUP & PIPING5A.1 Double Stage Selexol $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.2 Elemental Sulfur Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.3Mercury Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.4 Shift Reactors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.6 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.7 Fuel Gas Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.9 HGCU Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05B CO2 REMOVAL & COMPRESSION5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator $72,000 $0 $4,588 $0 $0 $76,589 $6,456 $0 $8,304 $91,349 $1636.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.9 Combustion Turbine Foundations $0 $681 $709 $0 $0 $1,390 $116 $0 $301 $1,807 $3SUBTOTAL 6. $72,000 $681 $5,298 $0 $0 $77,979 $6,571 $0 $8,606 $93,156 $1667 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator $32,000 $0 $4,200 $0 $0 $36,200 $3,060 $0 $3,926 $43,186 $777.2 SCR System $1,177 $494 $694 $0 $0 $2,365 $202 $0 $385 $2,952 $57.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07.9 HRSG,Duct & Stack Foundations $0 $386 $349 $0 $0 $736 $61 $0 $159 $956 $2SUBTOTAL 7. $33,177 $881 $5,244 $0 $0 $39,301 $3,323 $0 $4,470 $47,094 $848 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $22,464 $0 $3,675 $0 $0 $26,139 $2,244 $0 $2,838 $31,222 $568.2 Turbine Plant Auxiliaries $153 $0 $352 $0 $0 $505 $44 $0 $55 $604 $18.3 Condenser & Auxiliaries $4,112 $0 $1,053 $0 $0 $5,165 $439 $0 $560 $6,164 $118.4 Steam Piping $4,150 $0 $2,733 $0 $0 $6,884 $524 $0 $1,111 $8,519 $158.9 TG Foundations $0 $755 $1,202 $0 $0 $1,957 $165 $0 $424 $2,547 $5SUBTOTAL 8. $30,880 $755 $9,016 $0 $0 $40,651 $3,415 $0 $4,989 $49,055 $889 COOLING WATER SYSTEM9.1 Cooling Towers $3,850 $0 $525 $0 $0 $4,375 $370 $0 $474 $5,219 $99.2 Circulating Water Pumps $1,122 $0 $67 $0 $0 $1,189 $91 $0 $128 $1,409 $39.3 Circ.Water System Auxiliaries $93 $0 $12 $0 $0 $105 $9 $0 $11 $125 $09.4 Circ.Water Piping $0 $2,752 $656 $0 $0 $3,409 $270 $0 $552 $4,230 $89.5 Make-up Water System $228 $0 $302 $0 $0 $529 $45 $0 $86 $661 $19.6 Component Cooling Water Sys $181 $217 $143 $0 $0 $541 $45 $0 $88 $674 $19.9 Circ.Water System Foundations& Structures $0 $1,361 $2,177 $0 $0 $3,538 $298 $0 $767 $4,603 $8SUBTOTAL 9. $5,474 $4,330 $3,883 $0 $0 $13,686 $1,128 $0 $2,107 $16,921 $3010 ASH/SPENT SORBENT HANDLING SYS10.1 Slag Dewatering & Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.6 Ash Storage Silos $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.7 Ash Transport & Feed Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.9 Ash/Spent Sorbent Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 10. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants461Exhibit 5-13 Case 13 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:10-May-07Project:Bituminous Baseline StudyCase:Case 13 - NGCC w/o CO2Plant Size:560.4 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW11 ACCESSORY ELECTRIC PLANT11.1 Generator Equipment $2,320 $0 $1,405 $0 $0 $3,724 $314 $0 $303 $4,342 $811.2 Station Service Equipment $1,115 $0 $98 $0 $0 $1,213 $103 $0 $99 $1,415 $311.3 Switchgear & Motor Control $1,421 $0 $243 $0 $0 $1,664 $138 $0 $180 $1,983 $411.4 Conduit & Cable Tray $0 $695 $2,110 $0 $0 $2,805 $240 $0 $457 $3,502 $611.5 Wire & Cable $0 $2,128 $1,338 $0 $0 $3,467 $225 $0 $554 $4,245 $811.6 Protective Equipment $0 $519 $1,838 $0 $0 $2,356 $206 $0 $256 $2,819 $511.7 Standby Equipment $95 $0 $90 $0 $0 $185 $16 $0 $20 $221 $011.8 Main Power Transformers $10,277 $0 $140 $0 $0 $10,416 $707 $0 $1,112 $12,236 $2211.9 Electrical Foundations $0 $124 $306 $0 $0 $430 $37 $0 $93 $560 $1SUBTOTAL 11. $15,227 $3,466 $7,567 $0 $0 $26,261 $1,986 $0 $3,074 $31,321 $5612 INSTRUMENTATION & CONTROL12.1 IGCC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $012.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $012.4 Other Major ComponentControl $675 $0 $439 $0 $0 $1,114 $96 $0 $181 $1,391 $212.5 Signal Processing Equipment W/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.6 Control Boards,Panels & Racks $202 $0 $126 $0 $0 $328 $28 $0 $53 $409 $112.7 Computer & Accessories $3,228 $0 $101 $0 $0 $3,329 $283 $0 $361 $3,973 $712.8 Instrument Wiring & Tubing $0 $555 $1,085 $0 $0 $1,640 $124 $0 $265 $2,028 $412.9 Other I & C Equipment $1,203 $0 $2,845 $0 $0 $4,049 $353 $0 $440 $4,842 $9SUBTOTAL 12. $5,308 $555 $4,596 $0 $0 $10,459 $884 $0 $1,301 $12,643 $2313 Improvements to Site13.1 Site Preparation $0 $87 $1,757 $0 $0 $1,845 $163 $0 $401 $2,409 $413.2 Site Improvements $0 $801 $1,002 $0 $0 $1,803 $159 $0 $392 $2,353 $413.3 Site Facilities $1,635 $0 $1,624 $0 $0 $3,259 $287 $0 $709 $4,255 $8SUBTOTAL 13. $1,635 $888 $4,384 $0 $0 $6,907 $608 $0 $1,503 $9,017 $1614 Buildings & Structures14.1 Combustion Turbine Area $0 $212 $113 $0 $0 $325 $26 $0 $53 $403 $114.2 Steam Turbine Building $0 $1,855 $2,503 $0 $0 $4,357 $357 $0 $707 $5,422 $1014.3 Administration Building $0 $429 $294 $0 $0 $723 $57 $0 $117 $898 $214.4 Circulation Water Pumphouse $0 $143 $72 $0 $0 $215 $17 $0 $35 $267 $014.5 Water Treatment Buildings $0 $317 $293 $0 $0 $610 $49 $0 $99 $758 $114.6 Machine Shop $0 $372 $241 $0 $0 $613 $49 $0 $99 $761 $114.7 Warehouse $0 $240 $147 $0 $0 $387 $31 $0 $63 $480 $114.8 Other Buildings & Structures $0 $72 $53 $0 $0 $125 $10 $0 $20 $155 $014.9 Waste Treating Building & Str. $0 $281 $509 $0 $0 $791 $66 $0 $128 $985 $2SUBTOTAL 14. $0 $3,920 $4,225 $0 $0 $8,145 $661 $0 $1,321 $10,127 $18TOTAL COST $185,504 $20,029 $50,779 $0 $0 $256,312 $21,334 $0 $33,064 $310,710 $554TOTAL PLANT COST SUMMARYCost and Performance Comparison of Fossil Energy Power Plants

462 

### Exhibit 5-14 Case 13 Initial and Annual Operating and Maintenance Cost Summary

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006 Case 13 - NGCC w/o CO2 Heat Rate-net(Btu/kWh): 6,719 MWe-net: 560 Capacity Factor: (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 33.00 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total
Skilled Operator 1.0 1.0 Operator 2.0 2.0 Foreman 1.0 1.0 Lab Tech's, etc. 1.0 1.0 TOTAL-O.J.'s 5.0 5.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $1,879,020 $3.353 Maintenance Labor Cost $2,521,575 $4.500 Administrative & Support Labor $1,100,149 $1.963 TOTAL FIXED OPERATING COSTS $5,500,743 $9.816 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $3,782,362 $0.00091

Consumables Consumption Unit Initial Initial /Day Cost Cost
Water(/1000 gallons) 0 1,808 1.03 $0 $577,734 $0.00014

Chemicals MU & WT Chem.(lb) 75,397 10,771 0.16 $12,425 $550,716 $0.00013 Carbon (Mercury Removal) (lb.) 0 0 1.00 $0 $0 $0.00000 COS Catalyst (lb) 0 0 0.60 $0 $0 $0.00000 MEA Solvent (ton) 0 0 2,142.40 $0 $0 $0.00000 Activated Carbon(lb) 0 0 1.00 $0 $0 $0.00000 Corrosion Inhibitor 0 0 0.00 $0 $0 $0.00000 SCR Catalyst (m3) w/equip. 0.08 5,500.00 $0 $140,093 $0.00003 Ammonia (28% NH3) ton 55 8 190.00 $10,438 $462,620 $0.00011 Subtotal Chemicals $22,863 $1,153,429 $0.00028

Other Supplemental Fuel(MBtu) 0 0 0.00 $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 0 0.00 $0 $0 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Bottom Ash(ton) 0 0 0.00 $0 $0 $0.00000 Subtotal-Waste Disposal $0 $0 $0.00000

By-products & Emissions Sulfur(tons) 0 0 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $22,863 $5,513,526 $0.00132

Fuel(MMBtu) 2,710,842 90,361 6.75 $18,298,186 $189,233,740 $0.04535Cost and Performance Comparison of Fossil Energy Power Plants

463 

### 5.2.7 C ASE 

### 14

– NGCC WITH 

### CO 2 

### C APTURE 

### The plant configuration for Case 14 is the same as Case 13 with the exception that the Econamine FG Plus CDR t echnology was added for CO 2 

### capture. The nominal net output decreases to 482 MW because, like the IGCC cases, the combustion turbine fixes the output and the CDR facility significantly increases the auxiliary power load. The process description for Case 14 is essent ially the same as Case 13 with one notable exception, the addition of CO 2 

### capture. A BFD and stream tables for Case 14 are shown in Exhibit 5-15 and Exhibit 5-16, respectively. Since the CD R facility process description was provided in Section 4.1.7, it is not repeated here.

5.2.8 C ASE 

### 14 P ERFORMANCE 

### R ESULTS 

### The Case 14 modeling assumptions were presented previously in Section 5.2.2. The plant produces a net output of 482 MW at a net plant efficiency of 43.7 percent (HHV basis). Overall plant performance is summarized in Exhibit 5-17 which includes auxiliary power requirements. The CDR facility, including CO 2 

### compression, accounts for over 64 percent of the auxiliary plant load. The circ ulating water system (circulati ng water pumps and cooling tower fan) accounts for nearly 20 percent of the auxili ary load, largely due to the high cooling water demand of the CDR facility.Cost and Performance Comparisonof Fossil Energy Power Plants464Exhibit 5-15 Case 14 Process Flow Diagram, NGCC with CO2CaptureCost and Performance Comparisonof Fossil Energy Power Plants465Exhibit 5-16 - Case 14 Stream Table, NGCC with CO2Capture123456789V-L Mole FractionAr 0.0092 0.0000 0.0089 0.0089 0.0098 0.0000 0.0000 0.0000 0.0000CH40.0000 0.9390 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000C2H60.0000 0.0320 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000C3H80.0000 0.0070 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000C4H100.0000 0.0040 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000CO20.0003 0.0100 0.0405 0.0405 0.0045 0.9767 1.0000 0.0000 0.0000H2O0.0099 0.0000 0.0869 0.0869 0.0339 0.0233 0.0000 1.0000 1.0000N20.7732 0.0080 0.7430 0.7430 0.8188 0.0000 0.0000 0.0000 0.0000O20.2074 0.0000 0.1207 0.1207 0.1330 0.0000 0.0000 0.0000 0.0000SO20.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000V-L Flowrate (lbmol/hr)120,220 4,793 125,152 250,304 227,129 9,347 9,130 34,122 34,122V-L Flowrate (lb/hr) 3,469,190 82,591 3,551,780 7,103,560 6,448,730 405,714 401,794 614,710 614,710Temperature (°F) 59 100 1,167 283 85 69 124 555 300Pressure (psia) 14.7 450.0 15.2 15.2 14.7 23.5 2,214.7 67.5 67.5Enthalpy (BTU/lb)A13.1 34.4 360.5 122.6 36.1 11.2 -70.8 1309.6 270.3Density (lb/ft3)0.08 1.29 0.02 0.05 0.07 0.18 40.75 0.11 57.28Molecular Weight 28.86 17.23 28.38 28.38 28.39 43.40 44.01 18.02 18.02A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Comparison of Fossil Energy Power Plants

466 

### Exhibit 5-17 Case 14 Plant Performance Summary
POWER SUMMARY (Gross Power at Generator Terminals, kWe) Gas Turbine Power 370,170 Steam Turbine Power 149,920 TOTAL POWER, kWe 520,090 AUXILIARY LOAD SUMMARY, kWe Condensate Pumps 60 Boiler Feedwater Pumps 2,920 Miscellaneous Balance of Plant (Note 1) 500 Gas Turbine Auxiliaries 700 Steam Turbine Auxiliaries 100 Amine System Auxiliaries 9,580 CO 2 

### Compression 15,040 Circulating Water Pumps 5,040 Cooling Tower Fans 2,600 Transformer Loss 1,660 TOTAL AUXILIARIES, kWe 38,200 NET POWER, kWe 481,890 Net Plant Efficiency (HHV) 43.7% Net Plant Heat Rate (Btu/kWh) 7,813 CONDENSER COOLING DUTY, 10 6 

### kJ/h (10 6 

### Btu/h) 550 (522)
CONSUMABLES Natural Gas kg/h (lb/h) 74,926 (165,182) Thermal Input, kWt (HHV) 1,103,363 Raw Water Usage, m 3 

### /min (gpm) 17.7 (4,680)

Notes:
1. Includes plant control systems, lighti ng, HVAC and miscellaneous low voltage loadsCost and Performance Comparison of Fossil Energy Power Plants

467 

### Environmental Performance The environmental targets for emissions of NOx, SO 2 

### and particulate matter were presented in Section 2.4. A summary of the plant air emissions for Case 14 is presented in Exhibit 5-18.

Exhibit 5-18 Case 14 Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)

SO 2 

### Negligible Negligible Negligible NO X 

### 0.004 (0.009) 115 (127) 0.030 (0.066) Particulates Negligible Negligible Negligible Hg Negligible Negligible Negligible CO 2 

### 5.1 (12) 151,000 (166,000) 39 (86)
CO 2 1 

### 42 (93)

1 

### CO 2 

### emissions based on net power instead of gross power
The operation of the modern, state-of-the-art ga s turbine fueled by natural gas, coupled to a HRSG, results in very low levels of NOx emissions and negligible levels of SO 2 

### , particulate and Hg emissions. As noted in Section 2.4, if th e fuel contains the maximum amount of sulfur compounds allowed in pipeline natural gas, the NGCC SO 2 

### emissions would be 21 tonnes/yr (23 tons/yr) at 85 percent cap acity factor, or 0.00195 lb/MMBtu. The low level of NOx production (2.5 ppmvd at 15 percent O 2 

### ) is achieved by utilizing a dry LNB coupled with an SCR system. Ninety percent of the CO 2 

### in the flue gas is removed in CDR facility.
Exhibit 5-19 shows the overall water balance for the plant. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent) . The water usage represents only the contribution of raw water makeup. In so me cases the water demand is greater than raw water makeup because of internal water recycle streams. For example, the boiler feedwater blowdown stream and condensate recovere d from the flue gas prior to the CO 2 

### absorber are reused as makeup to the cooling tower, thus re ducing the raw water requirement by that amount.

Exhibit 5-19 Case 14 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle,

m 3 

### /min (gpm) Raw Water Makeup,

m 3 

### /min (gpm)
BFW Makeup 0.1 (23) 0 0.1 (23)
Cooling Tower Makeup 16.6 (4,395) 2.0 (518) 14.7 (3,877)
Total 16.7 (4,418) 2.0 (518) 14.8 (3,900)Cost and Performance Comparison of Fossil Energy Power Plants

468 

### Heat and Mass Balance Diagrams A heat and mass balance diagram is shown for the NGCC in Exhibit 5-20. An overall plant energy balance is provided in tabular form in Exhibit 5-21. The power out is the combined combustion turbine and steam turbin e power prior to generator losses. The power at the generator terminals (shown in Exhibit 5-17) is calculated by multiplying the power out by a combined generator efficiency of 98.3 percen t. The Econamine process heat out stream represents heat rejected to c ooling water and ultimately to ambi ent via the cooling tower. The same is true of the condenser heat out stream. The CO 2 

### compressor intercooler load is included in the Econamine process heat out stream.Cost and Performance Comparisonof Fossil Energy Power Plants469Exhibit 5-20 Case 14 Heatand Mass Balance, NGCC with CO2CaptureCost and Performance Comparisonof Fossil Energy Power Plants470This page intentionally left blankCost and Performance Comparison of Fossil Energy Power Plants

471 

### Exhibit 5-21 Case 14 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total
Heat In (MMBtu/hr) Natural Gas 3,764.8 5.7 3,770.5 Ambient Air 91.1 91.1 Raw Water Makeup 49.7 49.7 Auxiliary Power 125.3 125.3 Totals 3,764.8 146.5 125.3 4036.6 Heat Out (MMBtu/hr) Flue Gas Exhaust 232.7 232.7 Condenser 522.0 522.0 Econamine Process 1463.8 1463.8 Cooling Tower Blowdown 25.1 25.1 CO 2 

### Product (28.4) (28.4) Process Losses (1) 17.1 17.1 Power 1,804.4 1,804.4 Totals 0.0 2,232.2 1,804.4 4,036.6 (1) Process Losses are calculated by difference a nd reflect various boiler, turbine, and other heat and work losses. Aspen flowsh eet balance is within 0.5 percent.Cost and Performance Comparison of Fossil Energy Power Plants

472 

### 5.2.9 C ASE 

### 14 M AJOR 

### E QUIPMENT 

### L IST 

### Major equipment items for the NGCC plant with CO 2 

### capture are shown in the following tables. The accounts used in the equipment list correspo nd to the account numbers used in the cost estimates in Section 5.2.10. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 COAL AND SORBENT HANDLING
N/A

ACCOUNT 2 FUEL AND SORBENT PREPARATION AND FEED
Equipment No. Description Type Operating Qty. Spares

1 Gas Pipeline Underground, coated carbon steel, wrapped cathodic protection 16 km (10 mile) 0

2 Gas Metering Station -- 1 0 Design Condition

56 m3/min @ 3.1 MPa (1,990 acfm @ 450 psia) 41 cm (16 in) standard wall pipe

56 m3/min (1,990 acfm)Cost and Performance Comparison of Fossil Energy Power Plants

473 

### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 2 0

2 Condensate Pumps Vertical canned 2 1

4 Auxiliary Boiler Shop fabricated, water tube 1 0

5 Service Air Compressors Flooded Screw 2 1

6 Instrument Air Dryers Duplex, regenerative 2 1

7 Closed Cycle Cooling Heat Exchangers Plate and frame 2 0

8 Closed Cycle Cooling Water Pumps Horizontal centrifugal 2 1

9 Engine-Driven Fire Pump Vertical turbine, diesel engine 1 1

10 Fire Service Booster Pump Two-stage horizontal centrifugal 1 1

11 Raw Water Pumps Stainless steel, single suction 2 1

12 Filtered Water Pumps Stainless steel, single suction 2 1

13 Filtered Water Tank Vertical, cylindrical 1 0

14 Makeup Water Demineralizer Multi-media filter, cartridge filter, RO membrane assemblyand electrodeionization unit 1 0

15 Liquid Waste Treatment System 1 0 1

166,559 liter (44,000 gal)

379 lpm (100 gpm)

10 years, 24-hour storm 3,785 lpm @ 107 m H2O (1,000 gpm @ 350 ft H2O)

2,650 lpm @ 76 m H2O (700 gpm @ 250 ft H2O) 10,978 lpm @ 18 m H2O (2,900 gpm @ 60 ft H2O)

174 lpm @ 49 m H2O (46 gpm @ 160 ft H2O)

13 m3/min (450 scfm)

15,520 lpm @ 21 m H2O (4,100 gpm @ 70 ft H2O) 2 HP water: 3,937 lpm @ 2,103 m

H2O (1,040 gpm @ 6,900 ft H2O) IP water: 757 lpm @ 274 m H2O (200 gpm @ 900 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C (40,000 lb/h, 400 psig, 650°F)

13 m3/min @ 0.7 MPa (450 scfm @ 100 psig) LP water: 303 lpm @ 09 m H2O (80 gpm @ 30 ft H2O)

Design Condition

348,261 liters (92,000 gal)

2,309 lpm @ 85 m H2O (610 gpm @ 280 ft H2O)

40 MMkJ/hr (38 MMBtu/hr) 3 Boiler Feedwater Pump Horizontal, split case, multi-stage, centrifugal, with interstage bleed for IP and LP feedwaterCost and Performance Comparison of Fossil Energy Power Plants

474 

### ACCOUNT 4 GASIFIER, BOILER AND ACCESSORIES
N/A

ACCOUNT 5B CARBON DIOXIDE RECOVERY

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 Econamine FG Plus Amine-based carbon dioxide capture system 2 0

2 Carbon Dioxide Compression System Integrally geared, multistage centrifugal 2 0 Design Condition Flue gas flow rate: 1,772,187 kg/h (3,907,000 lb/h), Inlet CO2

concentration: 6.3 wt%

100,698 kg/h @ 15.3 MPa (222,000 lb/h @ 2,215 psia)



### ACCOUNT 6 COMBUSTION TURBIN E GENERATORS AND AUXILIARIES
Equipment No. Description Type Operating Qty. Spares

1 Gas Turbine Advanced F class w/ dry low-NOx burner 2 0

2 Gas Turbine Generator TEWAC 2 0 Design Condition

185 MW

210 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phaseCost and Performance Comparison of Fossil Energy Power Plants

475 

### ACCOUNT 7 WASTE HEAT BOILER, DUCTING, AND STACK

Equipment No. Description Type Operating Qty. Spares

1 Stack CS plate, type 409SS liner 2 0

3 SCR Reactor Space for spare layer 2 0

4 SCR Catalyst -- 1 layer 0

5 Dilution Air Blowers Centrifugal 2 1

6 Ammonia Feed Pump Centrifugal 2 1

7 Ammonia Storage Tank Horizontal tank 1 0 2 0 2 Heat Recovery Steam Generator Drum, multi-pressure with economizer section and integral deaerator Reheat steam - 223,433 kg/h, 2.3 MPa/510°C (492,585 lb/h, 335 psig/950°F) Design Condition

46 m (150 ft) high x 4.5 m (15 ft) diameter

Main steam - 232,553 kg/h, 16.5 MPa/566°C (512,691 lb/h, 2,400 psig/1,050°F)

1,610,255 kg/h (3,550,000 lb/h) Space available for an additional catalyst layer 21 m3/min @ 91 cm WG (750 scfm @ 36 in WG)

3.8 lpm @ 82 m H2O (1 gpm @ 270 ft H2O)

87,065 liter (23,000 gal)



### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type Operating Qty.

1 Steam Turbine Tandem compound,HP, IP, and twoflow LP turbines 1

2 Steam Turbine Generator Hydrogen cooled, static excitation 1

3 Steam Bypass One per HRSG 2

4 Surface Condenser Single pass, divided waterbox including
vacuum pumps 1 180 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase

50% steam flow @ design steam conditions Design Condition

158 MW 16.5 MPa/566°C/510°C (2400 psig/ 1050°F/950°F)

601 MMkJ/hr, (570 MMBtu/hr), Inlet water temperature 16°C (60°F),

Water temperature rise 11°C (20°F)Cost and Performance Comparison of Fossil Energy Power Plants

476 

### ACCOUNT 9 COOLING WATER SYSTEM
Equipment No. Description Type Operatin g Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 1 0 Design Condition
503,464 lpm @ 30.5 m (133,000 gpm @ 100 ft)
11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT 2,393 MMkJ/hr (2,270 MMBtu/hr) heat load



### ACCOUNT 10 ASH/SPENT SORBEN T RECOVERY AND HANDLING
N/A

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type Operating Qty. Spares

1 CTG Transformer Oil-filled 2 0

3 Auxiliary Transformer Oil-filled 1 1

4 Low Voltage Transformer Dry ventilated 1 1

5 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 2 0

6 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 1 0

7 Medium Voltage Switchgear Metal clad 1 1

8 Low Voltage Switchgear Metal enclosed 1 1

9 Emergency Diesel Generator Sized for emergency shutdown 1 0 2 STG Transformer Oil-filled 1 0

24 kV/4.16 kV, 41 MVA, 3-ph, 60 Hz Design Condition
24 kV/345 kV, 210 MVA, 3-ph, 60 Hz 24 kV/345 kV, 130 MVA, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz 4.16 kV/480 V, 6 MVA, 3-ph, 60 Hz

750 kW, 480 V, 3-ph, 60 HzCost and Performance Comparison of Fossil Energy Power Plants

477 

### ACCOUNT 12 INSTRUMENTATION AND CONTROL

E q ui p ment No. Description Type O p eratin g Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) 1 0

3 DCS - Data Highway Fiber optic 1 0 1 0

Fully redundant, 25% spare Design Condition

Operator stations/printers and engineering stations/printers

2 DCS - Processor Microprocessor with redundant input/output N/ACost and Performance Comparison of Fossil Energy Power Plants

478 

### 5.2.10 C ASE 

### 14

– C OST 

### E STIMATING 

### The cost estimating methodology was desc ribed previously in Section 2.6. Exhibit 5-22 shows the total plant capital cost summary organized by cost account and Exhibit 5-23 shows a more detailed breakdown of the capital costs. Exhibit 5-24 shows the ini tial and annual O&M costs.
The estimated TPC of the NGCC with CO 2 

### capture is $1,169/kW. Process contingency represents 5.0 percent of the TP C and project contingency repres ents 13.3 percent. The 20-year LCOE, including CO 2 

### TS&M costs of 2.9 mills/kWh, is 97.4 mills/kWh.Cost and Performance Comparisonof Fossil Energy Power Plants479Exhibit 5-22 Case 14 Total Plant Cost SummaryClient:USDOE/NETLReport Date:10-May-07Project:Bituminous Baseline StudyCase:Case 14 - NGCC w/ CO2Plant Size:481.9 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost CostDirect Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING $0 $0 $0 $0 $0$0$0 $0 $0$0$02 COAL & SORBENT PREP & FEED $0 $0 $0 $0 $0$0$0 $0 $0$0$03 FEEDWATER & MISC. BOP SYSTEMS $23,544 $4,970 $8,285 $0 $0$36,798$3,088 $0 $6,473$46,360$964 GASIFIER & ACCESSORIES4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0$0$0 $0 $0$0$04.2 Syngas Cooling $0 $0 $0 $0 $0$0$0 $0 $0$0$04.3 ASU/Oxidant Compression $0 $0 w/equip. $0 $0$0$0 $0 $0$0$04.4-4.9 Other Gasification Equipment $0 $0 $0 $0 $0$0$0 $0 $0$0$0SUBTOTAL 4 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05 Gas Cleanup & Piping $0 $0 $0 $0 $0$0$0 $0 $0$0$05BCO2REMOVAL & COMPRESSION$121,446 $0 $35,469 $0 $0$156,915$13,337 $27,564 $39,563$237,380$4936 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator $72,000 $0 $4,588 $0 $0$76,588$6,456 $0 $8,304$91,348$1906.2-6.9 Combustion Turbine Other $0 $681 $709 $0 $0$1,390$116 $0 $301$1,807$4SUBTOTAL 6 $72,000 $681 $5,298 $0 $0 $77,979 $6,571 $0 $8,606 $93,156 $1937 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator $32,000 $0 $4,200 $0 $0$36,200$3,060 $0 $3,926$43,186$907.2-7.9 SCR System, Ductwork and Stack $1,177 $881 $1,044 $0 $0$3,101$263 $0 $544$3,908$8SUBTOTAL 7 $33,177 $881 $5,244 $0 $0 $39,301 $3,323 $0 $4,470 $47,094 $988 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $19,753 $0 $3,134 $0 $0$22,887$1,964 $0 $2,485$27,336$578.2-8.9 Turbine Plant Auxiliaries and Steam Piping $7,020 $606 $4,906 $0 $0$12,532$1,003 $0 $1,902$15,437$32SUBTOTAL 8 $26,772 $606 $8,041 $0 $0 $35,419 $2,967 $0 $4,387 $42,774 $899 COOLING WATER SYSTEM $8,060 $6,365 $5,482 $0 $0$19,908$1,638 $0 $3,040$24,585$5110 ASH/SPENT SORBENT HANDLING SYS $0 $0 $0 $0 $0$0$0 $0 $0$0$011 ACCESSORY ELECTRICPLANT $15,809 $5,267 $9,893 $0 $0$30,969$2,356 $0 $3,779$37,104$7712 INSTRUMENTATION & CONTROL $6,914 $723 $5,986 $0 $0$13,622$1,151 $681 $1,772$17,227$3613 IMPROVEMENTS TO SITE $1,643 $893 $4,406 $0 $0$6,942$611 $0 $1,511$9,063$1914 BUILDINGS & STRUCTURES $0 $3,885 $4,066 $0 $0$7,952$644 $0 $1,289$9,886$21TOTAL COST $309,365 $24,270 $92,170 $0 $0 $425,805 $35,687 $28,245 $74,891 $564,628 $1,172TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants480Exhibit 5-23 Case 14 Total Plant Cost DetailsClient:USDOE/NETLReport Date:10-May-07Project:Bituminous Baseline StudyCase:Case 14 - NGCC w/ CO2Plant Size:481.9 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW1 COAL & SORBENT HANDLING1.1 Coal Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.2 Coal Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.3 Coal Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.4 Other Coal Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $01.9 Coal & Sorbent Hnd.Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 1. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02 COAL & SORBENT PREP & FEED2.1 Coal Crushing & Drying incl w/2.3 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.2 Prepared Coal Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.3 Slurry Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $02.9 Coal & Sorbent Feed Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 2. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $03 FEEDWATER & MISC. BOP SYSTEMS3.1 FeedwaterSystem $2,425 $2,530 $2,082 $0 $0 $7,037 $579 $0 $1,142 $8,758 $183.2 Water Makeup & Pretreating $2,271 $237 $1,185 $0 $0 $3,692 $312 $0 $801 $4,805 $103.3 Other Feedwater Subsystems $1,116 $378 $318 $0 $0 $1,813 $145 $0 $294 $2,252 $53.4 Service Water Systems $270 $552 $1,791 $0 $0 $2,613 $226 $0 $568 $3,407 $73.5 Other Boiler Plant Systems $1,815 $696 $1,614 $0 $0 $4,126 $346 $0 $671 $5,143 $113.6 FO Supply Sys & Nat Gas $13,946 $458 $399 $0 $0 $14,803 $1,246 $0 $2,407 $18,456 $383.7 Waste Treatment Equipment $815 $0 $467 $0 $0 $1,282 $111 $0 $279 $1,671 $33.8 Misc. Equip.(cranes,AirComp.,Comm.) $885 $119 $428 $0 $0 $1,432 $124 $0 $311 $1,866 $4SUBTOTAL 3. $23,544 $4,970 $8,285 $0 $0 $36,798 $3,088 $0 $6,473 $46,360 $964 GASIFIER & ACCESSORIES4.1 Gasifier, Syngas Cooler & Auxiliaries(E-GAS$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.2 Syngas Cooling ( w/ 4.1 w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.3 ASU/Oxidant Compression $0 $0 w/equip. $0 $0 $0 $0 $0 $0 $0 $04.4 LT Heat Recovery & FG Saturation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $04.6 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04.8 Major Component Rigging $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $04.9 Gasification Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 4. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants481Exhibit 5-23 Case 14 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:10-May-07Project:Bituminous Baseline StudyCase:Case 14 - NGCC w/ CO2Plant Size:481.9 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW5A GAS CLEANUP & PIPING5A.1 Double Stage Selexol $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.2 Elemental Sulfur Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.3Mercury Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.4 Shift Reactors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.6 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.7 Fuel Gas Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05A.9 HGCU Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05B CO2 REMOVAL & COMPRESSION5B.1 CO2 Removal System $106,600 $0 $31,220 $0 $0 $137,821 $11,715 $27,564 $35,420 $212,519 $4415B.2 CO2 Compression & Drying $14,846 $0 $4,248 $0 $0 $19,094 $1,623 $0 $4,143 $24,860 $52SUBTOTAL 5. $121,446 $0 $35,469 $0$0 $156,915 $13,337 $27,564 $39,563 $237,380 $4936 COMBUSTION TURBINE/ACCESSORIES6.1 Combustion Turbine Generator $72,000$0 $4,588 $0 $0 $76,588 $6,456 $0 $8,304 $91,348 $1906.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06.9 Combustion Turbine Foundations $0 $681 $709 $0 $0 $1,390 $116 $0 $301 $1,807 $4SUBTOTAL 6. $72,000 $681 $5,298 $0 $0 $77,979 $6,571 $0 $8,606 $93,156 $1937 HRSG, DUCTING & STACK7.1 Heat Recovery Steam Generator $32,000 $0 $4,200 $0 $0 $36,200 $3,060 $0 $3,926 $43,186 $907.2 SCR System $1,177 $494 $694 $0 $0 $2,365 $202 $0 $385 $2,952 $67.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $07.9 HRSG,Duct & Stack Foundations $0 $386 $349 $0 $0 $736 $61 $0 $159 $956 $2SUBTOTAL 7. $33,177 $881 $5,244 $0 $0 $39,301 $3,323 $0 $4,470 $47,094 $988 STEAM TURBINE GENERATOR8.1 Steam TG & Accessories $19,753$0 $3,134 $0 $0 $22,887 $1,964 $0 $2,485 $27,336 $578.2 Turbine Plant Auxiliaries $135 $0 $303 $0 $0 $438 $38 $0 $48 $524 $18.3 Condenser & Auxiliaries $2,643 $0 $845 $0 $0 $3,488 $297 $0 $378 $4,163 $98.4 Steam Piping $4,242 $0 $2,794 $0 $0 $7,036 $535 $0 $1,136 $8,707 $188.9 TG Foundations $0 $606 $964 $0 $0 $1,570 $132 $0 $341 $2,043 $4SUBTOTAL 8. $26,772 $606 $8,041 $0 $0 $35,419 $2,967 $0 $4,387 $42,774 $899 COOLING WATER SYSTEM9.1 Cooling Towers $5,487 $0 $749 $0 $0 $6,236 $527 $0 $676 $7,439 $159.2 Circulating Water Pumps $1,832 $0 $117 $0 $0 $1,949 $149 $0 $210 $2,308 $59.3 Circ.Water System Auxiliaries $141 $0 $19 $0 $0 $160 $14 $0 $17 $191 $09.4 Circ.Water Piping $0 $4,191 $999 $0 $0 $5,191 $411 $0 $840 $6,442 $139.5 Make-up Water System $325 $0 $430 $0 $0 $755 $64 $0 $123 $942 $29.6 Component Cooling Water Sys $276 $330 $218 $0 $0 $824 $68 $0 $134 $1,026 $29.9 Circ.Water System Foundations& Structures $0 $1,844 $2,950 $0 $0 $4,794 $404 $0 $1,040 $6,238 $13SUBTOTAL 9. $8,060 $6,365 $5,482$0 $0 $19,908 $1,638 $0 $3,040 $24,585 $5110 ASH/SPENT SORBENT HANDLING SYS10.1 Slag Dewatering & Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.5 Other Ash Rrecovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.6 Ash Storage Silos $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.7 Ash Transport & Feed Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010.9 Ash/Spent Sorbent Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SUBTOTAL 10. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0TOTAL PLANT COST SUMMARYCost and Performance Comparisonof Fossil Energy Power Plants482Exhibit 5-23 Case 14 Total Plant Cost Details (Continued)Client:USDOE/NETLReport Date:10-May-07Project:Bituminous Baseline StudyCase:Case 14 - NGCC w/ CO2Plant Size:481.9 MW,netEstimate Type:ConceptualCost Base (Dec)2006 ($x1000)Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COSTNo. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW11 ACCESSORY ELECTRIC PLANT11.1 Generator Equipment $2,198 $0$1,331 $0 $0 $3,529 $298 $0 $287 $4,114 $911.2 Station Service Equipment $1,829 $0 $160 $0 $0 $1,989 $169 $0 $162 $2,321 $511.3 Switchgear & Motor Control $2,330 $0 $399 $0 $0 $2,729 $226 $0 $296 $3,251 $711.4 Conduit & Cable Tray $0 $1,140 $3,460 $0 $0 $4,600 $393 $0 $749 $5,743 $1211.5 Wire & Cable $0 $3,490 $2,194 $0 $0 $5,685 $369 $0 $908 $6,962 $1411.6 Protective Equipment $0 $520 $1,844 $0 $0 $2,364 $207 $0 $257 $2,828 $611.7 Standby Equipment $91 $0 $86 $0 $0 $177 $15 $0 $19 $211 $011.8 Main Power Transformers $9,361 $0 $131 $0 $0 $9,492 $644 $0 $1,014 $11,150 $2311.9 Electrical Foundations $0 $116 $287 $0 $0 $403 $34 $0 $87 $525 $1SUBTOTAL 11. $15,809 $5,267 $9,893 $0 $0 $30,969 $2,356 $0 $3,779 $37,104 $7712 INSTRUMENTATION & CONTROL12.1 IGCC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $012.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $012.4 Other Major Component Control $879 $0 $572 $0 $0 $1,451 $125 $73 $247 $1,896 $412.5 Signal Processing Equipment W/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $012.6 Control Boards,Panels & Racks $263 $0 $164 $0 $0 $427 $37 $21 $73 $557 $112.7 Computer & Accessories $4,205 $0 $131 $0 $0 $4,336 $368 $217 $492 $5,413 $1112.8 Instrument Wiring & Tubing $0 $723 $1,413 $0 $0 $2,136 $161 $107 $361 $2,764 $612.9 Other I & C Equipment $1,568 $0 $3,706 $0 $0 $5,273 $460 $264 $600 $6,597 $14SUBTOTAL 12. $6,914 $723 $5,986 $0 $0 $13,622 $1,151 $681 $1,772 $17,227 $3613 Improvements to Site13.1 Site Preparation $0 $88 $1,766 $0 $0 $1,854 $164 $0 $404 $2,421 $513.2 Site Improvements $0 $805 $1,007 $0 $0 $1,812 $159 $0 $394 $2,366 $513.3 Site Facilities $1,643 $0 $1,633 $0 $0 $3,276 $288 $0 $713 $4,277 $9SUBTOTAL 13. $1,643 $893 $4,406 $0 $0 $6,942 $611 $0 $1,511 $9,063 $1914 Buildings & Structures14.1 Combustion Turbine Area $0 $222 $119 $0 $0 $341 $27 $0 $55 $423 $114.2 Steam Turbine Building $0 $1,593 $2,149 $0 $0 $3,742 $307 $0 $607 $4,656 $1014.3 Administration Building $0 $437 $300 $0 $0 $736 $59 $0 $119 $914 $214.4 Circulation Water Pumphouse $0 $167 $84 $0 $0 $250 $20 $0 $40 $310 $114.5 Water Treatment Buildings $0 $484 $447 $0 $0 $931 $75 $0 $151 $1,157 $214.6 Machine Shop $0 $379 $245 $0 $0 $624 $49 $0 $101 $775 $214.7 Warehouse $0 $245 $150 $0 $0 $394 $31 $0 $64 $489 $114.8 Other Buildings & Structures $0 $73 $54 $0 $0 $127 $10 $0 $21 $158 $014.9 Waste Treating Building & Str. $0 $287 $519 $0 $0 $805 $67 $0 $131 $1,003 $2SUBTOTAL 14. $0 $3,885 $4,066 $0 $0 $7,952 $644 $0 $1,289 $9,886 $21TOTAL COST $309,365 $24,270 $92,170 $0 $0 $425,805 $35,687 $28,245 $74,891 $564,628 $1,172TOTAL PLANT COST SUMMARYCost and Performance Comparison of Fossil Energy Power Plants

483 

### Exhibit 5-24 Case 14 Initial and Annual Operating and Maintenance Cost Summary

INITIAL & ANNUAL O&M EXPENSES Cost Base (Dec) 2006 Case 14 - NGCC w/ CO2 Heat Rate-net(Btu/kWh): 7,813 MWe-net: 482 Capacity Factor: (%): 85 OPERATING & MAINTENANCE LABOR

Operating Labor Operating Labor Rate(base): 33.00 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total
Skilled Operator 1.0 1.0 Operator 3.3 3.3 Foreman 1.0 1.0 Lab Tech's, etc. 1.0 1.0 TOTAL-O.J.'s 6.3 6.3 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $2,378,839 $4.936 Maintenance Labor Cost $4,034,866 $8.373 Administrative & Support Labor $1,603,426 $3.327 TOTAL FIXED OPERATING COSTS $8,017,131 $16.637 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $6,052,299 $0.00169

Consumables Consumption Unit Initial Initial /Day Cost Cost
Water(/1000 gallons) 0 3,370.32 1.00 $0 $1,045,642 $0.00029

Chemicals MU & WT Chem.(lb) 140,555.73 20,079.39 0.16 $21,888 $970,101 $0.00027 Carbon (Mercury Removal) (lb.) 0.00 0.00 1.00 $0 $0 $0.00000 COS Catalyst (lb) 0.00 0.00 0.60 $0 $0 $0.00000 MEA Solvent (ton) 342.00 0.48 2,142.40 $732,701 $319,046 $0.00009 Activated Carbon(lb) 210,384.00 576.00 1.00 $210,384 $178,704 $0.00005 Corrosion Inhibitor 1.00 0.00 0.00 $47,000 $2,250 $0.00000 SCR Catalyst (m3) w/equip. 0.08 5,500.00 $0 $140,093 $0.00004 Ammonia (28% NH3) ton 54.94 7.85 190.00 $10,438 $462,620 $0.00013 Subtotal Chemicals $1,022,410 $2,072,814 $0.00058

Other Supplemental Fuel(MBtu) 0.00 0.00 0.00 $0 $0 $0.00000 Gases,N2 etc.(/100scf) 0.00 0.00 0.00 $0 $0 $0.00000 L.P. Steam(/1000 pounds) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal Other $0 $0 $0.00000

Waste Disposal Spent Mercury Catalyst (lb.) 0.00 0.00 0.00 $0 $0 $0.00000 Flyash (ton) 0.00 0.00 0.00 $0 $0 $0.00000 Bottom Ash(ton) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal-Waste Disposal $0 $0 $0.00000

By-products & Emissions Sulfur(tons) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $1,022,410 $9,170,755 $0.00256

Fuel(MMbtu) 2,710,805 90,360 6.75 $18,297,932 $189,231,113 $0.05274Cost and Performance Comparison of Fossil Energy Power Plants

484 

### 5.3 NGCC CASE SUMMARY The performance results of th e two NGCC plant configurations modeled in this study are summarized in Exhibit 5-25.
Exhibit 5-25 Estimated Performan ce and Cost Results for NGCC Cases

Case 13 Case 14 CO 2 Capture No Yes Gross Power Output (kW e ) 570,200 520,090 Auxiliary Power Requirement (kW e ) 9,840 38,200 Net Power Output (kW e ) 560,360 481,890 Coal Flowrate (lb/hr) N/A N/A Natural Gas Flowrate (lb/hr) 165,182 165,182 HHV Thermal Input (kW th ) 1,103,363 1,103,363 Net Plant HHV Efficiency (%) 50.8% 43.7% Net Plant HHV Heat Rate (Btu/kW-hr) 6,719 7,813 Raw Water Usage, gpm 2,511 3,901 Total Plant Cost ($ x 1,000) 310,710 564,628 Total Plant Cost ($/kW) 554 1,172 LCOE (mills/kWh) 1 68.4 97.4 CO 2 Emissions (lb/MWh) 2 783 85.8 CO 2 Emissions (lb/MWh) 3 797 93 SO 2 Emissions (lb/MWh) 2 Negligible Negligible NOx Emissions (lb/MWh) 2 0.060 0.066 PM Emissions (lb/MWh) 2 Negligible Negligible Hg Emissions (lb/MWh) 2 Negligible Negligible

1 Based on an 85% capacity factor
2 Value is based on gross output
3 Value is based on net output NGCC Advanced F Class



### The TPC for the two NGCC cases is shown in Exhibit 5-26. The capital cost of the non-capture case, $554/kW, is the lowest of all technologies studied by at least 64 pe rcent. Addition of CO 2 

### capture more than doubles the capital cost, but NGCC with capture is s till the leas t capital intensive of all the cap ture technologies by at least 51 pe rcent. The process contingency included for the Econamine process totals $57 /kW, which represents 5 percent of TPC. The LCOE for NGCC cases is heavily dependent on the price of natu ral gas as shown in Exhibit 5-27. The fuel component of LCOE repres ents 78 percent of the to tal in the non-capture case and 63 percent of the total in the CO 2 

### capture case. Because LCOE has a small capital component, it is less sensitive to capacity factor than the more capital intensive PC and IGCC cases. The decrease in net kilo watt-hours produced is nearly o ffset by a corresponding decrease in fuel cost. The CO 2 

### TS&M component of LCOE is only 3 percent of the total in the CO 2 

### capture case.Cost and Performance Comparison of Fossil Energy Power Plants

485 

### Exhibit 5-26 TPC of NGCC Cases

554 1,172

0 200 400 600 800 1,000 1,200 1,400Total Plant Cost, $/kW

NGCC NGCC w/ CO2 Capture



### Exhibit 5-27 LCOE of NGCC Cases

68.4 97.4

0 20 40 60 80 100 120LCOE, mills/kWh

NGCC NGCC w/ CO2 Capture CO2 TS&M Costs Fuel Costs Variable Costs Fixed Costs Capital CostsCost and Performance Comparison of Fossil Energy Power Plants

486 

### The sensitivity of NGCC to cap acity factor is shown in Exhibit 5-28. Unlike the PC and IGCC case, NGCC is relatively insensitive to capacity fact or but highly sensitive to fuel cost as shown in Exhibit 5-29. A 33 percent incr ease in natural gas price (fro m $6 to $8/MMBtu) results in a LCOE increase of 25 percent in the non- capture case and 20 percent in the CO 2 

### capture case. Because of the higher ca pital cost in the CO 2 

### capture case, the impact of fuel price changes is slightly diminished. As presented in Section 2.4 the cost of CO 2 

### capture was calculated in two ways, CO 2 

### removed and CO 2 

### avoided. In the NGCC case the cost of CO 2 

### removed is $70/ton and the cost of CO 2 

### avoided is $83/ton. The high co st relative to PC and IGCC tec hnologies is mainly due to the much smaller amount of CO 2 

### generated by NGCC and therefore captured in the Econamine process. Exhibit 5-28 Sensitivity of LCOE to Capacity Factor in NGCC Cases

0 20 40 60 80 100 120 140 160 180

0 10 20 30 40 50 60 70 80 90 100 Capacity Factor, %LCOE, mills/kWh

NGCC No Capture

NGCC w/CO2 Capture Natural gas price is $6.75/MMBtu in all cases



### The following observations can be made regard ing plant performance with reference to Exhibit 5-25:

• The efficiency of the NGCC case with no CO 2 

### capture is 50.8 per cent (HHV basis). Gas Turbine World provides estimated performan ce for an advanced F class turbine operated on natural gas in a combined cycle mode, a nd the reported efficiency is 57.5 percent (LHV basis). [ 66] Adjusting the result from this study to an LHV basis results in an efficiency of 56.3 percent.Cost and Performance Comparison of Fossil Energy Power Plants

487 

### Exhibit 5-29 Sensitivity of LCOE to Fuel Price in NGCC Cases

0 20 40 60 80 100 120 140

0 2 4 6 8 10 12 Natural Gas Price, $/MMBtuLCOE, mills/kWh NGCC No Capture

NGCC w/CO2 Capture

Capacity factor is 85 percent for all cases



### • The efficiency penalty to add CO 2 

### capture in the NGCC case is 7.1 percentage points. The efficiency reduction is caused primarily by the auxiliary loads of the Econamine system and CO 2 

### compression as well as the signi ficantly increased cooling water requirement, which increases the auxiliary load of the circulating water pumps and the cooling tower fan. CO 2 

### capture results in a 28 MW increase in auxiliary load compared to the non-capture case.

• The energy penalty for NGCC is less th an PC (7.1 percentage points for NGCC compared to 11.9 percentage points for PC) mainly because natural gas has a lower carbon intensity than coal. In the PC cases, about 589,670 kg/h (1.3 million lb/h) of CO 2 

### must be captured and compressed while in the NGCC case only about 181,437 kg/h (400,000 lb/h) is captured and compressed.

• A study assumption is that the natural ga s contains no PM or Hg, resulting in negligible emissions of both.

• This study also assumes that the natural gas contains no sulfur compounds, resulting in negligible emissions of SO 2 

### . As noted previously in the report, if the natural gas contained the maximum allowable amount of sulfur per EPA’s pipeline natural gas specification, the resulting SO 2 

### emissions would be 21 t onnes/yr (23 tons/yr), or 0.00195 lb/MMBtu.Cost and Performance Comparison of Fossil Energy Power Plants

488 

### • NOx emissions are identical for the two NG CC cases on a heat input and mass basis. This is a result of the fixed output from the gas turbine (25 ppmv at 15 percent O 2 

### ) and the fixed efficiency of the SCR (90 percent). The normalized water demand, internal recy cle and raw water us age are shown in Exhibit 5-30 for the NGCC cases. The following observations can be made:

• Normalized water demand increases 103 pe rcent and normalized raw water usage 81 percent in the CO 2 

### capture case. The high coolin g water demand of the Econamine process results in a large increase in cooling tower makeup requirements.

• Cooling tower makeup comprises over 99 pe rcent of the raw wa ter usage in both NGCC cases. The only internal recycle stream in the non- capture case is the boiler feedwater blowdown, which is recycled to the cooling tower. In the CO 2 

### capture case condensate is recovered from the flue gas as it is cooled to the absorber temperature of 32°C (89°F) and is also recycled to the cooling tower.
Exhibit 5-30 Water Usage in NGCC Cases

4.5 4.5 9.2

8.1

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0Water, gpm/MW(net)

NGCC NGCC w/ CO2 Capture Water Demand
Internal Recycle
Raw Water UsageCost and Performance Comparison of Fossil Energy Power Plants

489 

## 6 REVISION CONTROL The initial issue of this report was made public on May 15, 2007. Subsequent to the issue date, updates have been made to various report sections . These additions were made for clarification and aesthetic purposes and to corr ect an error made in determin ing the Econamine cooling water requirement in the PC and NGCC CO 2 

### capture cases. The water balances and water usage comparison exhibits were updated accordingly. In addition, the PC and NGCC energy balance tables contained errors which have been corrected in this version of the report. None of the changes affect the conclu sions previously drawn. Exhibit 6-1 contains information added, changed or deleted in successive revisions.

Exhibit 6-1 Record of Revisions

Revision Number Revision Date Description of Change Comments

Added disclaimer to Executive Summary and Introduction Disclaimer involves clarification on extent of participation of technology vendors.

Removed reference to Cases 7 and 8 in Exhibits ES-1 and 1-1. SNG cases moved to Volume 2 of this report as explained in the Executive Summary and Section 1.

Added Section 2.8 Explains differences in IGCC TPC estimates in this study versus costs reported by other

sources.

Added Exhibit ES-14 Mercury emissions are now shown in a separate exhibit from SO 2 

### , NOx and PM because of the different y-axis scale.

Corrected PC and NGCC CO 2 

### capture case water balances The Econamine process cooling water requirement for the PC and NGCC CO 2 

### capture cases was overstated and has been revised.

Replaced Exhibits ES-4, 3-121, 4-52 and 5-30 The old water usage figures were in gpm (absolute) and in the new figures the water numbers are normalized by net plant output. 1 8/ 23 /07

Update Selexol process description Text was added to Section 3.1.5 to describe how H 2 

### slip was handled in the models.Cost and Performance Comparison of Fossil Energy Power Plants

490 

### Revision Number Revision Date Description of Change Comments

Revised PC and NGCC CO 2 

### capture case energy balances (Exhibits 4-21, 4-42 and 5-21) The earlier version of the energy balances improperly accounted for the Econamine process heat losses. The heat removed from the Econamine process is rejected to the cooling tower.

Corrected Exhibit 5-11 and Exhibit 5-21 Sensible heat for combustion air in the two NGCC cases was for only one of the two combustion turbines – corrected to account for both turbinesCost and Performance Comparison of Fossil Energy Power Plants

491 

## 7 REFERENCES

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492 

### 16 Gleitz, Robert, “Advanced GT Tec hnology”, GE Power Systems, July 2003 17 Eldrid, Roberta, Kaufman, Lynda and Marks, Paul, “The 7FB: The Next Evolution of the F Gas Turbine”, GER-4194, April 2001
18 “Resolution of “Natural Ga s” and “Pipeline Natural Gas” Definition Issues, EPA’s Clean Air Market Programs, http://www.epa.gov/airmarkt/monitoring/gasdef/
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20 “ 

### Evaluation of Alternative IGCC Plant Designs for High Availability and Near Zero Emissions: RAM Analysis and Impact of SCR,” EPRI, Palo Alto, CA, 2005, 1010461 21 Higman, Christopher, DellaVilla, Sal, and St eele, Bob, “The Reliability of Integrated Gasification Combined Cycle (IGCC) Po wer Generation Units, Achema 2006, May 2006 22 Cooling Tower Fundamentals , ed. John C. Hensley, 2nd Edition, The Marley Cooling Tower Company, Mission, Kansas, 1985
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### Storage and Sink Enhancement Options, Tennessee Valley Authority, NETL and EPRI, December 2002
24 Smith, Lawrence A., Gupta, Neeraj, Sass, Bruce M. and Bubenik, Thomas A., “Engineering and Economic Assessment of Carbon Dioxide Sequestration in Saline Formations,” Battelle Memorial Institute, 2001
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