Feasibility Study for an Integrated Gasification Combined Cycle Facility at a Texas Site

1014510

EPRI Project Manager G. Booras

ELECTRIC POWER RESEARCH INSTITUTE 3420 Hillview Avenue, Palo Alto, California 94304-1338 PO Box 10412, Palo Alto, California 94303-0813 USA

800.313.3774 650.855.2121 askepri@epri.com www.epri.com

Feasibility Study for an Integrated Gasification Combined Cycle Facility at a Texas Site 1014510

Technical Update, October 2006

Cosponsor CPS Energy 145 Navarro San Antonio, TX 78296

Project Manager J. Kosub

DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH INSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM:

(A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I) WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT, INCLUDING MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, OR (II) THAT SUCH USE DOES NOT INFRINGE ON OR INTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY'S INTELLECTUAL PROPERTY, OR (III) THAT THIS DOCUMENT IS SUITABLE TO ANY PARTICULAR USER'S CIRCUMSTANCE; OR

(B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER (INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY EPRI REPRESENTATIVE HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOUR SELECTION OR USE OF THIS DOCUMENT OR ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT.

ORGANIZATION(S) THAT PREPARED THIS DOCUMENT Burns & McDonnell Engineering Co. Inc.

This is an EPRI Technical Update report. A Technical Update report is intended as an informal report of continuing research, a meeting, or a topical study. It is not a final EPRI technical report.

NOTE For further information about EPRI, call the EPRI Customer Assistance Center at 800.313.3774 or e-mail askepri@epri.com.

Electric Power Research Institute and EPRI are registered service marks of the Electric Power Research Institute, Inc.

Copyright 2006 Electric Power Research Institute, Inc. All rights reserved.

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CITATIONS

This report was prepared by

Burns & McDonnell 9400 Ward Parkway Kansas City, MO 64114

Principal Investigator J. Schwarz

This report describes research sponsored by the Electric Power Research Institute (EPRI) and CPS Energy.

This publication is a corporate document that should be cited in the literature in the following manner:

Feasibility Study for an Integrated Gasification Combined Cycle Facility at a Texas Site. EPRI, Palo Alto, CA: 2006. 1014510.

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PRODUCT DESCRIPTION

Interest in integrated gasification combined-cycle technology (IGCC) has grown sharply since the passage of the Energy Policy Act in 2005. Many new projects are being planned since the AEP and Duke 600-MW IGCC plants were announced nearly two years ago. This report compares the cost and performance of IGCC with a supercritical pulverized coal plant (SCPC) based on lower-rank Powder River Basin (PRB) coal. IGCC options included 100% PRB and 50/50 PRB/petcoke cases. The addition of CO2 capture equipment also was evaluated as a retrofit for the 100% PRB IGCC and SCPC facilities.

Results & Findings The net plant heat rates for the IGCC and SCPC plants without CO2 capture are similar, with the 100% PRB IGCC case having a slightly worse heat rate while the PRB/petcoke blend IGCC case has a slightly better heat rate than the PRB-fired SCPC. IGCC has an advantage in terms of SO2, PM10, and mercury emissions, with NOx emissions being similar for both technologies. SCR was not included for the IGCC unit due to concerns that ammonium bisulfate (ABS) deposits could plug the finned heat transfer surfaces of the HRSG downstream of the SCR. In addition, IGCC technology consumes less water than SCPC technology. Capital costs for the IGCC cases are approximately 20% higher than the cost for the SCPC case. There is about a 2.5% capital cost savings for the 50/50 PRB/petcoke IGCC over the 100% PRB IGCC due to the higher heating value of the blended fuel (lower water and ash contents). The 100% PRB SCPC unit has the lowest busbar cost of all alternatives. Installation of CO2 capture equipment as a retrofit for both technologies results in a very significant decrease in plant output. IGCC net plant output decreases by approximately 25%, and the SCPC decrease in output is 29%. Likewise, the net plant heat rate of the facilities also increases by approximately 39% for the IGCC and 41% for the SCPC. Water consumption also is increased by approximately 23% for IGCC and 34% for SCPC. All these factors result in an increase of the levelized busbar cost by approximately 45% for the IGCC and 58% for the SCPC post-CO2 capture. SCPC technology still provides the lowest busbar cost after CO2 capture retrofit, although by less of a gap than pre-CO2 capture. The avoided cost of CO2 capture is less for an IGCC, implying that IGCC technology is the more economical choice for retrofit of CO2 capture technology.

Challenges & Objective(s) The Shell gasification process chosen for this application uses a dry-feed system, which has advantages over slurry-feed gasification processes for low-rank coal (for the non-CO2 capture case). However, the Shell gasification process produces syngas with higher concentrations of CO and less H2 than would be produced by a slurry-feed gasifier. When adding CO2 capture

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equipment to the Shell gasification process, more steam is required to convert the CO to CO2 and H2 than would be required for a slurry-feed gasifier. This situation results in less steam available to the steam turbine, which equates to less plant output for the CO2 capture case than may be seen if using a slurry-feed gasifier. If the objective of the owner is to capture CO2, then a slurry-feed gasifier may be a better choice than a dry-feed gasifier. Another option would be a water quench version of the Shell gasifier, which would require some additional development.

Applications, Values & Use In recent years, several factors have caused the cost of power projects to increase at a higher rate than in years past. World demand for many commodities has increased sharply, resulting in a 100-300% cost increase for some commodities, including steel (in particular, stainless or high-alloy steel), concrete, copper, oil, and nickel. The compounding effect of labor productivity, high labor rate escalation, commodity cost escalation, risk mitigation, and contractor markups results in much higher project costs for both IGCC and SCPC than may have been anticipated one or two years ago. It is important that owners who are planning to add new generation have access to the most recent cost and performance estimates.

EPRI Perspective This is the first EPRI study performed that evaluates CO2 capture as a retrofit to existing IGCC and SCPC units. Other EPRI studies have evaluated CO2 capture on new units specifically designed for and incorporating CO2 capture from the start. Additionally, this is the first detailed study performed by EPRI that evaluates IGCC and pulverized coal (PC) technology with CO2 capture when using a lower-rank, higher-moisture PRB coal. Other detailed studies performed by EPRI focused primarily on higher-rank bituminous coals (using slurry-feed gasifiers), where IGCC has been shown to provide a more distinct advantage.

Approach Burns & McDonnell was engaged by CPS Energy and EPRI to perform a feasibility study for a nominal 550-MW (net) IGCC facility to be located at a greenfield site in the Texas Gulf Coast region. The IGCC options were based on Shell coal gasification technology with GE 7FB gas turbines. EPRIs in-house computer model was used to estimate the performance of the Shell coal gasification process for both fuels. UOPs SELEXOL system was used as the basis for the IGCC CO2 capture technology, and Fluors Econamine FG Plus

SM system was used for SCPC

CO2 capture technology. This report provides screening-level capital cost, performance, operations and maintenance costs, availability factors, and emission rates for the two IGCC alternatives. The capital costs include many site and owner-specific items that are not normally included in EPRIs Technical Assessment Guide (TAG).

Keywords Integrated gasification combined cycle Pulverized coal CO2 capture PRB coal

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CONTENTS

1 EXECUTIVE SUMMARY ........................................................................................................1-1 Overview ...............................................................................................................................1-1 IGCC Options........................................................................................................................1-1 Deliverables...........................................................................................................................1-2 Results ..................................................................................................................................1-2 Current Market Conditions ....................................................................................................1-6 Limitations and Qualifications................................................................................................1-7

2 INTRODUCTION ....................................................................................................................2-1 Background ...........................................................................................................................2-1 Objectives .............................................................................................................................2-1 Status of the Technology.......................................................................................................2-2 Selection of Gasification Technology ....................................................................................2-2 Project Experience ................................................................................................................2-3 Fuel experience.....................................................................................................................2-4 Technical Approach and Data Sources.................................................................................2-4

3 STUDY CRITERIA..................................................................................................................3-1 Site Selection ........................................................................................................................3-1 Gas Turbine Selection...........................................................................................................3-1 Fuel Selection .......................................................................................................................3-1 Plant Capacity Selection .......................................................................................................3-3 Capacity Factor and Availability Factor Targets....................................................................3-4

4 PROCESS DESCRIPTION.....................................................................................................4-1 Gasification System Description............................................................................................4-1

Air Separation Unit (ASU).................................................................................................4-1 Gasifiers ...........................................................................................................................4-4

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Gasifier Performance Estimate by EPRI......................................................................4-5 Slag Handling ...................................................................................................................4-6 Fly Ash System.................................................................................................................4-7 Syngas Wash Towers.......................................................................................................4-7 COS / HCN Hydrolysis .....................................................................................................4-8 Syngas Cooling and Condensation ..................................................................................4-9 Mercury Removal ...........................................................................................................4-10 Acid Gas Removal (AGR)...............................................................................................4-10 Sulfur Recovery and Tail Gas Treating ..........................................................................4-13

Sulfur Recovery Units (SRU) .....................................................................................4-13 Tail Gas Treating Unit (TGTU)...................................................................................4-15 Tail Gas Compression ...............................................................................................4-16 Thermal Oxidizer........................................................................................................4-16

Sour Water Stripping ......................................................................................................4-16 Syngas Saturation ..........................................................................................................4-17

Power Block Description .....................................................................................................4-17 Gas Turbines ..................................................................................................................4-17 Heat Recovery Steam Generators (HRSG)....................................................................4-18 Steam Turbine ................................................................................................................4-18 Steam Condenser...........................................................................................................4-19 Steam System ................................................................................................................4-19 Condensate System .......................................................................................................4-19 Feedwater System..........................................................................................................4-19 Natural Gas System .......................................................................................................4-19

Balance of Plant ..................................................................................................................4-20 Coal Handling .................................................................................................................4-20

100% PRB Option......................................................................................................4-20 50% PRB / 50% Petcoke Option................................................................................4-20

Cooling System ..............................................................................................................4-20 Auxiliary Boiler................................................................................................................4-21 Buildings .........................................................................................................................4-21 Water Treatment.............................................................................................................4-21

Raw Water/Service Water..........................................................................................4-22 Demineralized Water .................................................................................................4-23

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Wastewater ................................................................................................................4-23 Sanitary Drains ..........................................................................................................4-23

Flare ...............................................................................................................................4-23 Fire Protection ................................................................................................................4-23 Plant Drains ....................................................................................................................4-24 Electrical Systems ..........................................................................................................4-24

Auxiliary Power Supply ..............................................................................................4-24 Generator and Excitation ...........................................................................................4-25 Switchyard .................................................................................................................4-25 Essential AC and DC Power Supply ..........................................................................4-26 Freeze Protection ......................................................................................................4-26

5 TERMINAL POINTS ...............................................................................................................5-1 General .................................................................................................................................5-1 Site Access ...........................................................................................................................5-1 Rail Siding .............................................................................................................................5-1 Sanitary Waste......................................................................................................................5-1 Natural Gas ...........................................................................................................................5-1 Raw Water Supply.................................................................................................................5-1 Wastewater Discharge ..........................................................................................................5-2 Electrical Interface.................................................................................................................5-2

6 IGCC PERFORMANCE ESTIMATES ....................................................................................6-1 Performance Estimate Assumptions .....................................................................................6-1 Performance Estimate Results..............................................................................................6-1

7 IGCC CAPITAL COST ESTIMATES......................................................................................7-1 Capital Cost Estimate Assumptions ......................................................................................7-1 Indirect Construction Costs (Included in EPC Cost)..............................................................7-2 Owner Indirect Costs.............................................................................................................7-3 Costs not included.................................................................................................................7-4 Capital Cost Results..............................................................................................................7-4

8 IGCC OPERATIONS AND MAINTENANCE..........................................................................8-1 O&M Assumptions.................................................................................................................8-1 O&M Exclusions....................................................................................................................8-2

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O&M Results .........................................................................................................................8-2

9 IGCC AVAILABILITY .............................................................................................................9-1 General .................................................................................................................................9-1 Assumptions and Clarifications .............................................................................................9-1 Availability Factor ..................................................................................................................9-1

10 IGCC EMISSIONS ESTIMATES ........................................................................................10-1 General ...............................................................................................................................10-1

11 SUPERCRITICAL PC ESTIMATES ...................................................................................11-1 General ...............................................................................................................................11-1 SCPC Capital Cost Assumptions ........................................................................................11-1 SCPC Capital Cost Results.................................................................................................11-2 SCPC Performance Assumptions .......................................................................................11-4 SCPC Performance Estimate Results.................................................................................11-4 SCPC O&M Cost Assumptions ...........................................................................................11-5 SCPC O&M Exclusions.......................................................................................................11-5 SCPC O&M Results ............................................................................................................11-5 SCPC Emission Rates ........................................................................................................11-6 Availability Factor ................................................................................................................11-8

12 ECONOMIC ANALYSIS .....................................................................................................12-1 General ...............................................................................................................................12-1 Assumptions........................................................................................................................12-1 Economic Analysis ..............................................................................................................12-3 Sensitivity Analysis..............................................................................................................12-5

13 CO2 CAPTURE ...................................................................................................................13-1 General ...............................................................................................................................13-1 IGCC CO2 Capture ..............................................................................................................13-3

IGCC Modifications for CO2 Capture ..............................................................................13-4 Sour Shift ...................................................................................................................13-4 Syngas Cooling and Condensation............................................................................13-5 Acid Gas Removal (AGR)..........................................................................................13-5

IGCC Impacts from CO2 Capture....................................................................................13-5

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IGCC Performance CO2 Capture ............................................................................13-5 IGCC Capital Cost CO2 Capture .............................................................................13-7 IGCC Operations and Maintenance CO2 Capture...................................................13-7 IGCC Emissions CO2 Capture ................................................................................13-9 IGCC Pre-Investment Options for CO2 Capture.......................................................13-10

SCPC CO2 Capture ...........................................................................................................13-10 SCPC Modifications for CO2 Capture ...........................................................................13-12 SCPC Impacts from CO2 Capture.................................................................................13-13

SCPC Performance CO2 Capture .........................................................................13-13 SCPC Capital Cost CO2 Capture ..........................................................................13-14 SCPC Operations and Maintenance CO2 Capture................................................13-15 SCPC Emissions CO2 Capture .............................................................................13-17 SCPC Pre-Investment Options for CO2 Capture......................................................13-17

CO2 Capture Economics....................................................................................................13-18

14 OTHER CONSIDERATIONS..............................................................................................14-1 Byproduct Sales ..................................................................................................................14-1 Co-Production .....................................................................................................................14-1 Plant Degradation................................................................................................................14-2 Lignite Gasification..............................................................................................................14-2

15 SUMMARY .........................................................................................................................15-1

A PROCESS FLOW DIAGRAMS............................................................................................. A-1

B SITE LAYOUT DRAWINGS.................................................................................................. B-1

C WATER MASS BALANCE DIAGRAMS............................................................................... C-1

D ELECTRICAL ONE-LINE DIAGRAMS................................................................................. D-1

E CAPITAL COST DETAIL ...................................................................................................... E-1

F HEAT BALANCE DIAGRAMS...............................................................................................F-1

G O&M COST DETAIL............................................................................................................. G-1

H SYSTEM OF INTERNATIONAL UNITS CONVERSION TABLE ......................................... H-1

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LIST OF FIGURES

Figure 4-1 Gasification Block Flow Diagram..............................................................................4-1 Figure 4-2 Generic ASU Process Flow Diagram .......................................................................4-4 Figure 4-3 SELEXOL Process Flow Diagram ..........................................................................4-12 Figure 4-4 Block Flow Diagram Sulfur Recovery and Tail Gas Treating...............................4-13 Figure 12-1 20-Year Levelized Busbar Cost (2006 US Dollars) ..............................................12-3 Figure 12-2 Breakout of 20-Year Levelized Busbar Cost (2006 US Dollars) ...........................12-4 Figure 12-3 Sensitivity Analysis SCPC Unit 100% PRB Coal............................................12-5 Figure 12-4 Sensitivity Analysis IGCC 50% PRB Coal / 50% Petcoke..............................12-6 Figure 12-5 Sensitivity Analysis IGCC 100% PRB Coal ....................................................12-6 Figure 13-1 CO2 Storage Supply Curve for North America......................................................13-3 Figure 13-2 Fluor EFG+ Block Flow Diagram........................................................................13-11 Figure 14-1 Products from Syngas ..........................................................................................14-2

Error! No table of figures entries found

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LIST OF TABLES

Table 1-1 Executive Summary Table (Table 1 of 2) ..................................................................1-3 Table 1-2 Executive Summary Table (Table 2 of 2) ..................................................................1-4 Table 2-1 IGCC Facilities Past and Current............................................................................2-4 Table 3-1 Fuel Analyses ............................................................................................................3-3 Table 4-1 ASU Material Balances..............................................................................................4-3 Table 4-2 Summary of Gasifier Modeling Results .....................................................................4-6 Table 4-3 Assumed Raw Water Quality..................................................................................4-22 Table 6-1 IGCC Performance Summary....................................................................................6-2 Table 7-1 IGCC Capital Cost Estimate Summary (2006 US Dollars) ........................................7-5 Table 8-1 IGCC O&M Summary (2006 US Dollars)...................................................................8-3 Table 10-1 IGCC Target Emission Rates ................................................................................10-2 Table 11-1 550 MW (Net) SCPC Capital Cost Estimate Summary (2006 US Dollars) ............11-3 Table 11-2 550 MW (Net) SCPC Performance Summary........................................................11-4 Table 11-3 550 MW (Net) SCPC O&M Summary (2006 US Dollars) ......................................11-6 Table 11-4 500 MW (Net) SCPC Emissions Estimates ...........................................................11-8 Table 13-1 CO2 Purity Specification.........................................................................................13-2 Table 13-2 IGCC Performance Impacts from CO2 Capture .....................................................13-6 Table 13-3 IGCC Capital Cost Additions for CO2 Capture Retrofit...........................................13-7 Table 13-4 IGCC O&M Impacts from CO2 Capture..................................................................13-8 Table 13-5 IGCC Emissions Impacts from CO2 Capture .........................................................13-9 Table 13-6 SCPC Performance Impacts from CO2 Capture ..................................................13-14 Table 13-7 SCPC Capital Cost Additions for CO2 Capture Retrofit........................................13-15 Table 13-8 SCPC O&M Impacts from CO2 Capture...............................................................13-16 Table 13-9 SCPC Emissions Impacts from CO2 Capture ......................................................13-17 Table 13-10 CO2 Capture Busbar Costs ...............................................................................13-18 Table 15-1 Summary Table (1 of 2) .........................................................................................15-2 Table 15-2 Summary Table (2 of 2) .........................................................................................15-3

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ACRONYMS, ABBREVIATIONS, AND SYMBOLS

F degrees Fahrenheit 106 million $ dollars (U.S.) $/kW dollars per kilowatt $/kW-yr dollars per kilowatt-year $/MMBtu dollars per million British thermal unit $/MWh dollars per megawatt-hour $/ton dollars per ton $/yr dollars per year % percent ABS ammonium bisulfate AC alternating current AGR acid gas removal ALPC Air Liquide Process and Construction ASU air separation unit BOP balance of plant Btu British thermal unit Btu/kWh British thermal unit(s) per kilowatt-hour CF capacity factor CIT compressor inlet temperature CO carbon monoxide CO2 carbon dioxide COS carbonyl sulfide CPS CPS Energy DC direct current DCS distributed control system DSF deep saline formations ECBM Enhanced coal bed methane (recovery) EFG+ Econamine FG PlusSM (Fluor CO2 capture system) EOR enhanced oil recovery EPA Environmental Protection Agency EPC engineer-procure-construct EPRI Electric Power Research Institute FGCU Flue Gas Conditioning Unit FGD flue gas desulfurization ft foot (feet) gal gallon(s) GE General Electric GIS geographic information system GSU generator step-up (transformer) GTG gas turbine generator H2 hydrogen H2O water H2S hydrogen sulfide HCN hydrogen cyanide Hg mercury

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HHV higher heating value HP high pressure hr hour HRSG heat recovery steam generator HVAC heating, ventilation, and air conditioning IGCC integrated gasification combined cycle in inch(es) IOU investor owned utility kPa kilopascal(s) kV kilovolt(s) kW kilowatt(s) kWh kilowatt-hour lb pound(s) lb/hr pound per hour lb/MMBtu pound(s) per million British thermal units lb/MWh pound(s) per megawatt-hour LHV lower heating value lit liter(s) LP low pressure LTGC low temperature gas cooling LTSA long term service agreement LV low voltage m

3 cubic meters

MCC motor control center MEA monoethanolamine (solvent) MHI Mitsubishi Heavy Industries MM million MMBtu million Btu MMcf million cubic feet MP medium pressure Mt metric ton MV medium voltage MW megawatts MWh megawatt-hour N2 nitrogen NAAQS National Ambient Air Quality Standards NaOH Sodium Hydroxide NFPA National Fire Protection Association NH3 ammonia NO

x nitrous oxide

O&M operations and maintenance PC pulverized coal PCM power control module ppmv part(s) per million by volume ppmvd part(s) per million by volume (dry) ppmvd @ 15% O2 part(s) per million by volume (dry) corrected to 15% oxygen PPT power potential transformer PRB Powder River Basin (coal) psia pound(s) per square inch (atmospheric) psig pound(s) per square inch (gauge) S sulfur SCPC supercritical pulverized coal SCR selective catalytic reduction SO2 sulfur dioxide SO3 sulfur trioxide SRU sulfur recovery unit STG steam turbine generator STPD short tons per day

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SWS sour water stripper TGTU tail gas treatment unit TPD ton(s) per day TTD terminal temperature difference UPS uninterruptible power supply U.S. United States V volt(s) v% percent by volume vol volume wt weight wt% percent by weight yr year(s)

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CERTIFICATION PAGE

Electric Power Research Institute & CPS Energy

Feasibility Study for an Integrated Combined Cycle Facility at a Texas Site

NUMBER DOCUMENT DESCRIPTION OF PAGES

Report/Appendices Findings of IGCC Feasibility Study 221

CERTIFICATION(S)

1-1

1 EXECUTIVE SUMMARY

Overview

Integrated gasification combined cycle (IGCC) technology has been the source of much interest in the world of advanced coal-fired generation. IGCC technology provides a bridge between the two mature technologies of coal gasification and combined cycle technology by producing a medium-Btu value syngas from coal or other solid fuel and firing it in a modified conventional gas turbine as part of a combined cycle application.

Burns & McDonnell was engaged by CPS Energy (Owner) and EPRI to perform a feasibility study for IGCC technology to be located at a greenfield Texas Gulf Coast location.

IGCC Options

Due to the availability of petroleum coke (petcoke) and PRB coal in the area, two IGCC options were evaluated:

Option 1 100% PRB

Option 2 50% PRB / 50% Petcoke (% by weight)

For this evaluation, a 2x1 (two gas turbine/HRSG trains and 1 steam turbine) configuration was selected. The IGCC facility consists of the following major equipment:

1 high-pressure air separation unit (ASU) with 2x50% main air compressors and nitrogen compressors, utilizing a portion of air extracted from the gas turbine compressors at lower ambient temperatures (air-side integration).

2 Shell gasifiers. 1 SELEXOLTM acid gas removal (AGR) system. 2 sulfur recovery units (SRU). 1 tail gas treating unit (TGTU). 2 General Electric (GE) 7FB gas turbine generators (GTG).

Executive Summary

1-2

2 heat recovery steam generators (HRSG). 1 steam turbine generator (STG). Balance of plant (BOP).

Deliverables

This report provides screening level capital cost, performance, operations and maintenance (O&M) costs, availability factors, and emission rates for the two IGCC alternatives defined above. As a part of creating this information Burns & McDonnell also generated process flow diagrams, layout drawings, water mass balances, and electrical one-line diagrams.

Another objective of this study was to compare IGCC technology to supercritical pulverized coal (SCPC) technology using steam conditions of 3500 psig/1050F/1050F. Therefore capital cost, performance, O&M costs, availability factors, and emission rates were also developed for a SCPC Unit firing 100% PRB coal with a net output of 550 MW. This information was used to create a 20-year levelized busbar cost to determine the overall cost of generation for the three alternatives.

The addition of CO2 capture equipment was also evaluated as a retrofit for the 100% PRB IGCC and SCPC facilities. UOPs SELEXOL system was used as the basis for the IGCC CO2 capture technology and Fluors Econamine FG PlusSM system was used for SCPC CO2 capture technology. Capital cost, performance, O&M, and emission rates were developed and used to calculate a 20-year levelized busbar cost for both technologies.

Results

A summary table is provided in Table 1-1 and Table 1-2.

Executive Summary

1-3

Table 1-1 Executive Summary Table (Table 1 of 2)

Base Cases CO2 Capture CasesIGCC SCPC IGCC SCPC

Case 100% PRB 50% PRB / 50% Petcoke 100% PRB 100% PRB IGCC 100% PRBFuel

PRB (% wt.) 100% 50% 100% 100% 100%Petcoke (% wt.) 0% 50% 0% 0% 0%PRB (% heat input) 100% 36% 100% 100% 100%Petcoke (% heat input) 0% 64% 0% 0% 0%HHV (Btu/lb) 8,156 11,194 8,156 8,156 8,156

Capital Cost (2006 USD)EPC Capital Cost $1,318,980,000 $1,287,540,000 $1,072,580,000 $179,220,000 (Note 1) $269,430,000 (Note 1)Owner's Costs $155,240,000 $139,500,000 $129,760,000 $17,960,000 (Note 1) $26,570,000 (Note 1)Total Project Cost $1,474,220,000 $1,427,040,000 $1,202,340,000 $197,180,000 (Note 1) $296,000,000 (Note 1)EPC Capital Cost, $/kW (73F Ambient) $2,390 $2,330 $1,950 $3,630 (Note 1) $3,440 (Note 1)Total Project Cost, $/kW (73F Ambient) $2,670 $2,580 $2,190 $4,040 (Note 1) $3,840 (Note 1)

Performance43F Dry Bulb, 40F Wet Bulb

Gross Plant Output, MW 736.6 734.2 623.3 Not Evaluated Not EvaluatedAuxiliary Load, MW 137.4 137.2 65.4 Not Evaluated Not EvaluatedNet Plant Output, MW 599.2 597.0 557.8 Not Evaluated Not EvaluatedNet Plant Heat Rate, Btu/kWh (HHV) 9,090 8,950 9,030 Not Evaluated Not Evaluated

73F Dry Bulb, 69F Wet BulbGross Plant Output, MW 709.9 711.1 614.5 630.1 521.4Auxiliary Load, MW 156.8 158.0 64.5 216.8 131.6Net Plant Output, MW 553.0 553.0 550.0 413.3 389.8Net Plant Heat Rate, Btu/kWh (HHV) 9,220 9,070 9,150 12,800 12,910

93F Dry Bulb, 77F Wet BulbGross Plant Output, MW 681.5 682.6 613.2 Not Evaluated Not EvaluatedAuxiliary Load, MW 153.2 154.5 64.4 Not Evaluated Not EvaluatedNet Plant Output, MW 528.4 528.2 548.8 Not Evaluated Not EvaluatedNet Plant Heat Rate, Btu/kWh (HHV) 9,350 9,210 9,170 Not Evaluated Not Evaluated

O&M Cost (2006 USD)Fixed O&M, $/kW-yr $25.19 $25.19 $20.68 $34.74 $31.19Variable O&M, $/MWh $5.95 $5.66 $4.60 $8.55 $6.97Total O&M Cost, $/Year (85% CF) $38,426,700 $37,245,400 $30,209,800 $40,661,400 $32,563,000

Availability Factor 85% 85% 90% Not Evaluated Not Evaluated

Economic AnalysisCapacity Factor 85% 85% 85% N/A N/A20-year levelized busbar cost, $/MWh (2006 Real $) $45.03 $40.89 $39.28 $65.41 $62.00Avoided CO2 Cost, $/Mt CO2 avoided N/A N/A N/A $26.28 $29.64

Notes:1) CO2 Capture capital costs are based on retrofit of the existing IGCC or PC facilities as provided in the base case alternatives. $/kW values reflect total installed cost to date (including original costs provided in the base case) divided by net plant output with CO2 capture.

Executive Summary

1-4

Table 1-2 Executive Summary Table (Table 2 of 2)

Base Cases CO2 Capture CasesIGCC SCPC IGCC SCPC

Case 100% PRB 50% PRB / 50% Petcoke 100% PRB 100% PRB IGCC 100% PRBNOx Emissions

lb/MMBtu (HHV) 0.063 0.062 0.050 0.061 0.045ppmvd @ 15% O2 15 15 N/A 15 N/Alb/MWh (net) 0.581 0.562 0.458 0.781 0.581

SO2 Emissionslb/MMBtu (HHV) 0.019 0.023 0.060 0.004 0.0003lb/MWh (net) 0.173 0.210 0.549 0.051 0.003

PM10 Emissions (front half)lb/MMBtu (HHV) 0.007 0.007 0.015 0.007 0.015lb/MWh (net) 0.065 0.065 0.137 0.090 0.194

COlb/MMBtu (HHV) 0.037 0.036 0.150 0.035 (Note 1) 0.150ppmvd 25 25 N/A 25 (Note 1) N/Alb/MWh (net) 0.337 0.337 1.373 0.448 (Note 1) 1.937

CO2lb/MMBtu (HHV) 215 213 215 22 22lb/MWh (net) 1,985 1,934 1,967 276 278

Hg% Removal 90% 90% 70% 90% 70%lb/TBtu (HHV) 0.778 0.496 2.315 0.778 2.315lb/MWh (net) 7.17E-06 4.50E-06 2.12E-05 9.96E-06 2.99E-05

Plant Cooling Requirements, MMBtu/hr (@ 73F) 2,141 2,179 2,490 2,101 3,330Steam Cycle Cooling Requirement, MMBtu/hr 1,480 1,480 2,300 1,120 1,354BOP Auxiliary Cooling Requirement, MMBtu/hr 661 699 190 981 1,976

Total Plant Makeup Water RequirementGPM (@ 73F) 4,980 5,231 5,800 6,147 7,757Acre-ft/year (@ 85% CF) 6,830 7,170 7,950 8,430 10,640

Notes:1) GE is currently in the process of developing tools to accurately predict CO emissions for high hydrogen fuels. It is estimated that CO emissions will be less than shown for IGCC CO2 capture technology, however to what extent is unknown at this time.

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The capital costs are based on mid-2006 overnight EPC costs. Escalation through a commercial operation date (COD) is not included. Additionally, sales tax, interest during construction, financing fees, and transmission lines or upgrades are not included in the capital cost estimates.

As can be seen SCPC technology provides the lowest capital cost, best efficiency, and lowest O&M when comparing the two 100% PRB options. Additionally, the 100% PRB SCPC unit has the lowest busbar cost of all alternatives.

The heat rate for the fuel blended IGCC case is slightly better than 100% PRB SCPC technology (with the exception of the 93F case); however firing petcoke in a PC unit is also possible, although not specifically evaluated for this report. Petcoke firing in a conventional PC boiler is typically limited to approximately 20% (by heat input) due to the low volatiles present in the fuel which can create flame stability issues. Firing 20% petcoke in the PC boiler will result in approximately 1% improvement in heat rate over that shown for the PC unit, thus closing the gap, if not eliminating any performance benefit of the IGCC.

IGCC has an advantage in terms of SO2, PM10, and mercury emissions, however using the emissions allowance costs provided in Chapter 8, these lower emissions are not enough to overcome the capital cost and performance differences between the technologies.

The IGCC evaluated has higher NOx emission rates than for the SCPC unit. This is because an

SCR was not included for the IGCC unit due to concerns that ammonium bisulfate (ABS) deposits could plug and corrode the heat transfer surfaces of the HRSG downstream of the SCR. Additionally, if an SCR were used, a larger AGR and SRU would be required to lower the sulfur content of the syngas (to reduce particulate formation from the excess ammonia with SO2/SO3 in the flue gas) resulting in increased capital cost. For these reasons, an SCR was not included; however subsequent evaluations should be performed to evaluate the cost/benefit/technological risk tradeoff. If an SCR were used, NO

x emissions could be reduced to levels below that

provided for the SCPC unit.

IGCC technology consumes less water than SCPC technology. This is primarily due to the steam turbine output of the IGCC being less than half that of the SCPC unit. Although the steam condenser duty is less for the IGCC, the auxiliary cooling requirements of the IGCC are higher than the SCPC unit (primarily due to the ASU cooling requirement), resulting in about a 15% overall lower cooling tower duty and water consumption.

The installation of CO2 capture equipment as a retrofit for both of these technologies results in a very significant decrease in plant output. The IGCC net plant output decreases by approximately 25% and the SCPC decrease in output is 29%. Likewise, the net plant heat rate of the facilities also increases by approximately 39% for the IGCC and 41% for the SCPC. Water consumption is also increased by approximately 23% for IGCC and 34% for SCPC.

All of these factors result in an increase of the 20-year levelized busbar cost by approximately 45% for the IGCC and 58% for the SCPC post CO2 capture. SCPC technology still provides the lowest busbar cost after CO2 capture retrofit, although by less of a gap than pre-CO2 capture. The avoided cost of CO2 capture is less for an IGCC implying that IGCC technology is the more economical choice for retrofit of CO2 capture technology (if you owned both an existing IGCC

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plant and SCPC plant and were going to retrofit only one, you would choose the IGCC), however the lower initial capital cost (pre-capture) of SCPC technology still results in an overall lower busbar cost for SCPC technology.

This is the first EPRI study performed that evaluates CO2 capture as a retrofit to existing IGCC and SCPC units. Other EPRI studies have evaluated CO2 capture on new units specifically designed for and incorporating CO2 capture from the start vs. new units that are not designed with CO2 capture in mind. This study attempts to answer the question of what are the impacts from adding CO2 capture to an existing SCPC or IGCC plant at a later date.

The Shell gasification process chosen for this application utilizes a dry-feed system, which has advantages over slurry-feed gasification processes for low rank coal (for the non-CO2 capture case). The Shell gasifiers produce syngas with higher concentrations of CO and less H2 than would be produced by a slurry-feed gasifier. When adding CO2 capture equipment to the Shell gasification process, more steam is required to convert the CO to CO2 and H2 than would be required for a slurry-feed gasifier. This results in less steam available to the steam turbine, which equates to less plant output for the CO2 capture case than may be seen if using a slurry-feed gasifier. If the objective of the Owner is to capture CO2, then a slurry-feed gasifier may be a better choice than a dry-feed gasifier.

Additionally, this is the first detailed study performed by EPRI that evaluates IGCC and PC technology with CO2 capture when using a lower rank, higher moisture PRB coal. Other detailed studies performed by EPRI focused primarily on higher rank bituminous coals (using slurry-feed gasifiers), where IGCC has been shown to provide a more distinct advantage.

The performance information provided by UOP and Fluor for the CO2 capture equipment is different from data obtained for other recently published studies. A resolution of the differences is outside the scope of this project, however it is anticipated that the differences are related to the CO2 purity that was specified for this project. It should be noted that none of the technologies (IGCC, SCPC, or CO2 capture) evaluated in this study were optimized to provide the best cost-to-benefit ratio (i.e. lowest busbar cost). The designs used as the basis for this evaluation are just one of many possible configurations that should be further optimized in the future.

Changes in market conditions, improvements in IGCC technology, different fuel specifications, or CO2 purity specifications could be enough to swing the economics in favor of IGCC. Therefore, it is recommended that utilities consider IGCC technology for future generation needs. However, based on the results and design basis used in this study, SCPC provides the lowest busbar cost of the three alternatives at this time.

Current Market Conditions

In recent years, several factors have caused the cost of power projects to increase at a higher rate than in years past. Specifically in the Gulf Coast area, the destruction of Hurricane Katrina has resulted in a large labor demand for reconstruction efforts. In order to meet labor requirements, much of the construction labor force has been pulled from out of state, resulting in a construction labor shortage across the country (in an industry that was already in high demand). The high demand for qualified labor has resulted in job-hopping for many workers. The result is that

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labor productivity has been very poor compared to that of just a few years ago, yet the cost of construction labor is increasing at a rapid rate.

In addition to Hurricane Katrina rebuilding projects, engineering firms and construction contractors are very busy with new power generation projects and air pollution control projects designed to clean up SO2 and NOx emissions from older coal-fired units. This increased demand results in increased contingency, overhead, and profit levels for contractors. Some clients have even had challenges finding qualified contractors that are willing to bid on their projects.

Beyond labor issues, the world demand for many commodities has also increased sharply, due in large part to Chinas economic growth. This high demand has resulted in a 100-300% cost increase for some commodities including steel (in particular stainless or high alloy steel), concrete, copper, oil, and nickel resulting in increased equipment costs and vendor markups.

The compounding effect of labor productivity, high labor rate escalation, commodity cost escalation, risk mitigation, and contractor markups results in much higher project costs than may have been anticipated one or two years ago.

Limitations and Qualifications

The estimates and projections prepared by Burns & McDonnell relating to construction costs, performance, and O&M are based on our experience, qualifications, and judgment as a professional consultant. Since Burns & McDonnell has no control over weather, cost, and availability of labor, materials, and equipment, labor productivity, unavoidable delays, economic conditions, government regulations and laws (including interpretation thereof), competitive bidding and market conditions or other factors affecting such estimates or projections, Burns & McDonnell does not guarantee that actual rates, costs, performance, etc., will not vary from the estimates and projections prepared herein.

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2 INTRODUCTION

Background

CPS Energy, located in San Antonio, Texas, is the nations largest municipally owned energy company providing both electricity and natural gas to its customers. In December of 2005, CPS Energy agreed to fund an IGCC study, as part of a settlement during the air permitting process for a new pulverized coal plant. Under the terms of the agreement, the IGCC study scope compares SCPC and IGCC technologies at a generic site in Texas. CPS Energy also agreed to make the report available to the public. This study provides typical decision support input for a power plant investment decision for a generic municipally-owned utility. The study includes generic investment decision information such as, cost of capital, forecasted fuel costs, etc. The study does not include competitive, sensitive CPS Energy power plant investment decision information.

CPS Energy contacted Burns & McDonnell to perform a technical and economic feasibility study for a nominal 550 MW 2x1 IGCC unit.

Objectives The primary objectives of this study were to provide screening-level information for use in evaluating a 2x1 IGCC facility to be located at a generic Texas Gulf Coast site. This information consists primarily of capital cost, performance, and O&M cost estimates.

To achieve these objectives, Burns & McDonnell provided a conceptual design for the facility, consisting of preliminary process design, overall plant heat balances, preliminary process flow diagrams, preliminary electrical one-line diagrams, and preliminary site layout drawings. This information was then used to establish the plant preliminary capital cost estimate.

Once the conceptual design information was produced, IGCC technology was compared to conventional coal fired SCPC technology in a pro forma economic analysis to determine which technology resulted in the lowest busbar cost of the facility.

Additionally, the impacts of adding CO2 capture as a retrofit to the IGCC and SCPC technologies were evaluated. The impacts for performance, capital cost, O&M, emissions, and levelized busbar cost were determined.

If any of the technologies presented in this report are of interest to the Owner, it is recommended this feasibility study be followed up with more detailed studies to further define the project and

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to tailor the information for a specific site. These follow-on studies should include gasifier and gas turbine manufacturer involvement.

Status of the Technology

Conventional combined cycle technology is a proven technology that has been used for many years in the power industry. Similarly, gasification technology is a proven technology that has been used extensively in the chemical industry to produce products such as ammonia and hydrogen. IGCC technology combines these two proven technologies by producing a medium-Btu value syngas from coal or other solid fuel (petcoke) and firing it in a modified conventional gas turbine as part of a combined cycle application.

When combining these two technologies, high levels of integration between the two processes are often required to increase plant efficiency and to make IGCC competitive with other coal-fired electric power generation technologies. This integration is created by using heat exchangers to capture heat produced in the gasification process and utilizing it to increase the output and efficiency of the steam cycle, yet at the same time increasing the complexity of the plant.

IGCC projects generally utilize conventional equipment (gas turbines, heat exchangers, compressors), that when combined with the complexity of integration into an IGCC facility, has led to less than desirable availability factors and forced outage rates in the past. It has generally been the failure of this conventional equipment that has lead to the poor reliability and availability of the existing IGCC facilities. It is anticipated that advancements in IGCC design and increased IGCC operational experience are expected to improve availability and lower the forced outage rates for IGCC technology.

Development of the IGCC technology truly commenced in the 1970s during the energy crisis. Research and development during this timeframe led to the construction of the Texaco Cool Water facility in California, and the LGTI facility in Louisiana. Both of these facilities have been decommissioned. Experiences and lessons learned from these facilities were brought forward during the 1990s with the development of the Polk and the Wabash IGCC facilities. Ongoing operation of these two facilities in the United States and the Buggenum and Puertollano facilities in Europe continue to help improve the future generation of IGCC facilities.

Selection of Gasification Technology

Burns & McDonnell was requested to perform a cursory evaluation of the gasification technologies available, and select a technology to be used as a basis for this study. Focus was given only to the major technologies that currently have commercial IGCC offerings in the United States. This consists of GE, ConocoPhillips, and Shell gasification technologies.

GE and ConocoPhillips use slurry-feed gasifiers, whereas Shell uses a dry-feed gasifier. Slurry-feed gasifiers typically work well on high rank bituminous coals. When utilizing PRB as a feedstock, however, the slurry has a lower concentration due to the high inherent moisture content of the PRB coal. As a result of feeding less dense slurry to the gasifier, the cold gas

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efficiency decreases and oxygen consumption increases, typically resulting in decreased performance.

GE has several gasifiers operating in the United States and worldwide. The GE gasification technology is an oxygen-blown slurry-feed entrained flow gasifier. Most of the operating GE gasifiers are the quench design. Their IGCC offering is the radiant design intended to maximize the steam production for power generation. The GE gasification process works well on bituminous coal and/or petcoke, and they are currently working on a design for PRB, with the intention of having a commercial offering toward the end of 2006. GE was approached about participating in this study, and due to their current workload, declined to participate.

ConocoPhillips has an operating, full commercial scale gasifier at the Wabash IGCC facility. Their process is a 2-stage oxygen-blown slurry-feed entrained flow gasifier. At the LGTI IGCC facility, which was decommissioned in 1995, ConocoPhillips gasified over 3.7 million tons of PRB. ConocoPhillips was also approached about participating in this study, and due to their current workload, declined to participate.

Shell currently has three coal gasifiers operating worldwide. Two started up this year in China and the Shell gasifier is used at the NUON IGCC facility in the Netherlands. Eleven other Shell coal gasifiers are currently under construction in China. The Shell coal gasification process is an oxygen-blown dry-feed entrained flow gasifier that is suitable for PRB gasification. The dry-feed system of the Shell gasifier also likely provides some performance benefits over slurry-feed gasifiers when designing for low-rank coals such as PRB. Shell was approached about participating in the study and also declined to participate directly, but agreed to allow EPRI to perform modeling of their gasification system and supply the results to Burns & McDonnell.

Based on the likely performance benefits associated with the Shell process for PRB coal, it was agreed that the Shell gasification process would be used as the basis for this evaluation.

It should be noted that all of the gasification technologies described above perform differently and have different O&M requirements. The GE and ConocoPhillips gasifiers are refractory lined, whereas the Shell gasifier has a steam tube membrane wall. The refractory lined gasifiers require a periodic replacement of the refractory due to wear in the high slag flow areas, whereas the membrane wall tubes require little maintenance. Also, the Shell process is a dry-feed, versus slurry-feed for the GE and ConocoPhillips processes. Due to the higher concentrations of water, the syngas from the GE and ConocoPhillips gasifiers has higher concentrations of CO2 and H2 and the syngas from the Shell process has a higher concentration of CO.

Project Experience Table 2-1 shows the current and previous IGCC facilities that were developed in the United States and in Europe. All of the United States facilities were developed with funding assistance from the Department of Energy.

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Table 2-1 IGCC Facilities Past and Current

Facility Owner Capacity (MW) Commercial Operation

Date

Gasifier Manufacturer Status

Puertollano Elcogas 321 1998 Prenflo Operating Polk

County Tampa Electric 252 1996 GE Operating

Wabash River PSI Energy 262 1995 Conoco Phillips Operating

Buggenum NUON 254 1994 Shell Operating Pinon Pine Sierra Pacific 99 1997 KRW Decommissioned

LGTI Dow Chemical 160 1987 Conoco Phillips Decommissioned

Cool Water Texaco 125 1984 GE Decommissioned

Fuel experience

Within the United States, relatively little IGCC experience exists with PRB as the feedstock. As noted previously, between 1987 and 1995, the LGTI facility gasified over 3.7 million tons of PRB. This represents the majority of the United States operating experience with PRB gasification.

There has been significant operating experience with petcoke. Petcoke lends itself well to gasification due to the higher heating content, low moisture, and low ash. However, petcoke does have significantly higher sulfur content. Due to the trace metals in the petcoke, either a fluxant or coal needs to be blended with the petcoke to enable the ash to flow out of the slagging gasifiers. Currently, the fuel for the Polk IGCC facility is a blend of coal and petcoke, and petcoke is being utilized at the Wabash IGCC facility.

Shell has processed both PRB coal and petcoke during the early 1990s at a 250 tpd demonstration plant at Shells Deer Park, TX refinery. Shell has reported a cold gas efficiency of 78.0% with 99.7% carbon conversion and 99.9% sulfur capture during 297 hours of tests on PRB and 78.9% cold gas efficiency with 99.5% carbon conversion and 99.8% sulfur capture during 169 hours of operations on petcoke.

Technical Approach and Data Sources

As noted above, the Shell coal gasification process was selected for this study. EPRI provided the gasifier yield and thermal performance for the gasification plant (up to the wash column inlet). Burns & McDonnell performed the preliminary design of the low temperature gas cooling and scrubbing section, COS/HCN catalyst section, AGR, SRUs, TGTU, power block, and balance of plant. The following vendors were used to provide additional information:

UOP provided an equipment list and performance information for the SELEXOL unit.

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Air Liquide Process and Construction (ALPC) provided cost and performance information for the ASU.

Sud-Chemie provided cost and performance information for the COS/HCN catalyst. NUCON provided cost and performance information for the mercury removal bed. Fluor provided cost, performance, and emissions information for the Econamine FG Plus

Plant (EFG+) for SCPC CO2 capture.

The information provided herein does not represent a thorough performance or cost optimization. Further optimizations (capital cost investment vs. performance, emissions, or O&M benefits) can be performed that would likely improve the busbar cost of all technologies (SCPC, IGCC, and CO2 capture).

3-1

3 STUDY CRITERIA

Site Selection

The site for this project is based on a generic greenfield site located in the Texas Gulf Coast.

The ambient conditions used as the design basis of this study are the 2% dry bulb (dry bulb temperature is exceeded 2% of the year), average dry bulb, and 95% dry bulb (dry bulb temperature is exceeded 95% of the year)

The ambient conditions are as follows:

2% Dry Bulb: 93F with coincident wet bulb temperature of 77F. Average Dry Bulb: 73F with coincident wet bulb temperature of 69F. 95% Dry Bulb: 43F with coincident wet bulb temperature of 40F.

The finished grade of the site is assumed to be 100 ft. Additional assumptions about the site can be found in Chapter 7.0

Gas Turbine Selection

The gas turbines selected as the basis for this project are GE 7FB gas turbines. EPRI and Burns & McDonnell have access to more readily available information for GEs 7FB gas turbines than from other manufacturers. Also, GE has much experience with syngas operation, having accumulated over 300,000 hours of operation on syngas; however GE has no operating experience with firing syngas in the 7FB. Although GE has this significant syngas operating experience, other gas turbine manufacturers are able to offer similar gas turbines that should result in a comparable result.

Fuel Selection

PRB fuel is currently utilized by several utilities in Texas. This low-sulfur coal has proven to be an economical choice for generation in Texas.

Additionally, petcoke, a byproduct of the refining process, has proven to be an economical fuel alternative for other generating facilities across the nation. Refineries are typically eager to

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remove this byproduct from their site; therefore petcoke is relatively inexpensive from the refinery. The expense of petcoke is dictated by transportation costs from the refinery to the power plant. The prospect of petcoke firing is typically limited by the following factors:

1) Projects planning to fire petcoke are typically located near refineries that produce coke as a byproduct.

2) The quantity of petcoke is typically only available in sufficient quantities to supply a part of the overall heat input to a large power facility.

3) Firing 100% petcoke in a PC unit is only achievable using a special down-fired boiler. Conventional designed PC units are limited to approximately 20% petcoke firing due to the low volatiles in the coal.

Therefore, petcoke is typically blended with other fuels when used in large scale power generation.

Because this project is located in the Texas Gulf Coast, petcoke should be available as an alternate fuel source from nearby refineries. Therefore, two independent IGCC options were evaluated for this project:

Option 1 100% PRB Coal Option 2 50% PRB Coal / 50% Petcoke (% by weight)

Fuel analyses are provided in Table 3-1.

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Table 3-1 Fuel Analyses

100% PRB 100% Petcoke 50% PRB / 50% Petcoke

PRB (% wt.) 100% 0% 50%Petcoke (% wt.) 0% 100% 50%PRB (% heat input) 100% 0% 36.40%Petcoke (% heat input) 0% 100% 63.60%HHV (Btu/lb) 8,156 14,231 11,194

Proximate Analysis (% wt.) Moisture 30.24 4.83 17.53 Volatile Matter 31.39 10.60 21.00 Fixed Carbon 33.05 84.44 58.74 Ash 5.32 0.13 2.73

Ultimate Analysis (% wt.) Carbon 48.18 83.62 65.88 Hydrogen 3.31 3.02 3.17 Nitrogen 0.70 0.85 0.78 Chlorine 0.01 0.01 0.01 Sulfur 0.37 6.60 3.49 Oxygen 11.87 0.94 6.41 Ash 5.32 0.13 2.73 Moisture 30.24 4.83 17.53 Total 100.00 100.00 100.00

Mercury (ppm) 0.091 0.05 0.07

Ash Fusion TemperaturesReducing Atmosphere

Initial Deformation 2150F 2800+F N/ASoftening 2170F 2800+F N/AHemispherical 2190F 2800+F N/AFluid 2210F 2800+F N/A

Oxidizing AtmosphereInitial Deformation 2220F 2,505F N/ASoftening 2240F 2,597F N/AHemispherical 2260F 2,610F N/AFluid 2280F 2,611F N/A

Plant Capacity Selection

The largest IGCC facility that has been constructed in the United States is a 1x1 (one gasification/gas turbine/HRSG train and one steam turbine). Currently, 2x1 IGCC technology is the primary focus of IGCC development by both manufacturers and developers due to improved economies of scale. It is possible to improve the economies of scale of an IGCC facility further by adding an additional gasification/gas turbine/HRSG train (3x1 facility). However due to a general aversion to risk in the industry, it is unlikely that a 3x1 IGCC facility will be developed until 2x1 IGCC technology has been proven successfully in the United States. Therefore, a 2x1 IGCC facility is the basis of this study.

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The plant capacity for this project is dictated by the capacity of the gas turbines coupled with the available energy that can be recovered from the gas turbine and gasification process. For this project, the 2x1 IGCC facility has a nominal net plant output of 550 MW.

Capacity Factor and Availability Factor Targets

Capacity Factor (CF) is defined as the actual MWh produced in a year divided by the maximum possible MWh produced in a year. Generally, capacity factors for units are dictated by economic issues. Lower production cost technologies operate at base load (capacity factors above 70%), whereas higher production cost technologies tend to operate as peaker plants or for serving an intermediate load (operating throughout the day and ramping down at night).

The large capital and operating expenditure (yet lower fuel cost) of a coal plant are typically only justified by operating the unit at base load. Due to the increase of natural gas prices and limited base load resources, capacity factors of conventional PC plants are typically at 85% or higher. The O&M estimates and economic evaluation provided in this study assume a capacity factor of 85%, with a 100% load factor (operating 85% of the time at full load and off-line the other 15% of the time).

The Availability Factor (AF) is defined as the sum of service hours and reserved shut down hours divided by the total hours per year. Essentially, it is the percentage of hours in a year that the plant is available to operate.

Some IGCC facilities have been evaluated with a spare gasifier to increase availability factors and allow increased operational flexibility. It was decided that the increased operating and capital expenses of the spare gasifier are not justified for this project at this time. The resulting availability factor is approximately 85% for the IGCC technologies evaluated.

Additional information on plant availability factors can be found in Chapter 9.0.

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4 PROCESS DESCRIPTION

Gasification System Description

For this report, the Gasification System refers to all of the equipment required to make syngas. This includes the ASU, gasifiers, slag handling, candle filters, wash towers, COS/HCN hydrolysis, mercury removal, syngas cooling and condensation, AGR, SRUs, tail gas treatment, sour water stripping, and syngas saturation. Process flow diagrams are included in Appendix A for reference. A block flow diagram is provided in Figure 4-1.

Figure 4-1 Gasification Block Flow Diagram

Air Separation Unit (ASU) Atmospheric air is dried and then cryogenically distilled in the ASU to produce 95% oxygen and several nitrogen steams. The air separation unit selected for this study is a high-pressure ASU, meaning that the columns all operate at a higher pressure than a conventional low-pressure ASU. The selection of an HP or LP ASU depends primarily on the amount of nitrogen required under

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pressure vs. the oxygen requirement. Because of the large nitrogen requirement, the primary benefit of the HP ASU is the reduced power requirement for N2 compression.

The majority of the oxygen produced in the ASU is supplied at high pressure (780 psia) for use in the gasifiers. A small amount of low pressure oxygen is used as the oxidant in the SRU.

Uses for the nitrogen streams are as follows:

High pressure (1089 psia) N2 with 0.1% O2 is used for conveying the fuel into the gasifier and other purposes in the gasification block.

Medium pressure (480 psia) N2 with 2% O2 is used as diluent in the gas turbines for NOx control.

Low pressure (140 psia) N2 with 2% O2 is used for regeneration of the molecular sieve driers and miscellaneous purges.

Cryogenic pumps are used to supply the high pressure nitrogen and oxygen streams to the gasifier. The cryogenic pumps were chosen because of their lower auxiliary power consumption and lower cost than gas compression. Additionally, pumping liquid O2 is generally viewed to be safer than compression of gaseous O2. The high-pressure liquid oxygen and nitrogen are then vaporized prior to the gasifier. The medium pressure and low pressure nitrogen streams are pressurized by nitrogen compressors.

The ASU scope includes storage of high-pressure, high-purity nitrogen equivalent to 12 hours of production in liquid form. Additionally, 20 minutes of production as gas is available at pressure to provide nitrogen during the period of time that back-up liquid vaporization comes on line. The back-up system is to be designed to deliver high pressure nitrogen within 10 minutes after being activated.

The material balances around the ASU for the 100% PRB cases (43F and 93F) are provided in Table 4-1, which are used to set the design requirements of the ASU. Since very little difference exists between the ASU for the 100% PRB case and the 50% PRB / 50% petcoke case, the same ASU design was used for both options. Additionally, Figure 4-2 provides a block flow diagram for a generic ASU.

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Table 4-1 ASU Material Balances

Case 93F PRB Coal

Stream Ambient Air GT Air Total Air In Total Dry Air O2 Product Conveying HP To Process LP Misc Sieve Regen. Remaining N2 to GTlb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr

H2O 1,390 1 1,392 1,392O2 11,057 11 11,068 11,068 10,383 2 4 2 187 490 677N2 41,211 41 41,252 41,252 164 1,930 4,000 1,555 9,164 24,439 33,603Ar 492 0 492 492 383 1.9 4.1 1.6 9 93 102Total 54,150 54 54,204 52,812 10,930 1,934 4,008 1,559 9,360 25,021 35,773% O2 20.4% 20.4% 20.4% 21.0% 95.0% 0.1% 0.1% 0.1% 2.0% 2.0% 1.9%

Temp, F 93 810 382 280 280 56 56 56 453Pres. psia 15 218 760 1068 1068 140 140 140 290Total lb/hr 1,552,965 1,547 1,554,511 1,529,437 352,142 54,206 112,353 43,692 263,066 703,991 992,132

Case 43F PRB Coal

Stream Ambient Air GT Air Total Air In Total Dry Air O2 Product Conveying HP To Process LP Misc Sieve Regen. Remaining N2 to GTlb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr

H2O 253 168 422 422O2 7,281 4,854 12,135 12,135 11,360 2 4 2 187 580 767N2 27,138 18,092 45,230 45,230 179 1,930 4,000 1,555 9,164 28,402 37,566Ar 323 216 539 539 419 1.9 4.1 1.6 9 103 113Total 34,996 23,330 58,326 57,904 11,958 1,934 4,008 1,559 9,360 29,085 38,867% O2 20.8% 20.8% 20.8% 21.0% 95.0% 0.1% 0.1% 0.1% 2.0% 2.0% 2.0%

Temp, F 93 810 382 280 280 56 56 56 453Pres. psia 15 218 760 1068 1068 140 140 140 290Total lb/hr 1,010,697 673,785 1,684,482 1,676,887 385,263 54,206 112,353 43,692 263,066 818,321 1,088,982

Note: The air provided by the GTG (stream 2) is cooled to ambient temperature by heat exchange with steam cycle condensate and auxiliary cooling water prior to being sent to the ASU. The N2 to the gas turbine (stream 11) is heated from ~350F at the discharge of the final stage of compression to 453F using IP boiler feedwater as the heat source prior to the gas turbine.

The following major equipment items are included: Main air compressor and booster air compressor (2 trains x 50%). Nitrogen compressor (2 x 50%). Cryogenic oxygen pumps (2 x 100%). Cryogenic nitrogen pumps (2 x 100%) for high pressure N2. Cold box. Switching valves, driers and regeneration heater. MV and LV Switchgear and MCC. Transformers from 13.8 KV. Liquid N2 storage and associated backup vaporizer. Electrical / control room. Commissioning spares.

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Figure 4-2 Generic ASU Process Flow Diagram

Additionally, heat exchangers are provided to cool the extracted air from the gas turbine to ambient temperature prior to the ASU and to heat the nitrogen from the ASU to the gas turbine. These costs are not included in the ASU cost provided by ALPC, however they are included in the BOP costs.

Gasifiers

The gasification plant for this project is comprised of two Shell oxygen-blown entrained-flow gasifiers, each capable of supplying enough syngas for operation of one gas turbine at full load. Each gasification train is comprised of coal milling and drying equipment, coal pressurization lockhopper, high pressure oxygen and coal feed systems, gasifier vessel, slag removal system, syngas cooling, syngas recycle compressor, and particulate removal systems.

The Shell gasifier uses a dry-coal feed system. This system requires the feedstock moisture content to be reduced to approximately 5% prior to injection to the gasifier. Therefore, coal drying equipment is required which utilizes syngas (or natural gas during startup) to drive off the excess moisture in the fuel. The coal dryer is combined with the coal milling equipment in a vertical roller mill which pulverizes the coal to the required consistency. The dried and pulverized coal is raised above the gasifier operating pressure in a set of lockhoppers and conveyed to the gasifier using high pressure nitrogen. PRB fuel is highly reactive and has a high potential for spontaneous combustion; consequently the oxygen concentration in the milling/drying and coal feeding systems is minimized via the injection of nitrogen at various locations. A detailed evaluation of the operation of the coal dryer relative the PRB fuel was not performed.

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The fuel and high pressure oxygen react in the gasifier at high temperatures (2,700 F) and approximately 560 psia to produce syngas. The gasifier, operating in an oxygen deficient (reducing) atmosphere, is designed to operate at conditions suitable to promote reactions which produce a synthesis gas (syngas) and slag. The syngas produced in the gasifiers is rich in hydrogen, carbon monoxide, and water. There are also lesser amounts of several components including carbon dioxide, hydrogen sulfide, carbonyl sulfide, methane, argon, and nitrogen.

The gasifier vessel walls are cooled using water-wall membranes that produce medium-pressure (MP) steam at approximately 650 psia. The syngas is quenched by recycle of cooled, particulate-free syngas to ~1,700F. The syngas then passes to the syngas cooler which also uses medium pressure feedwater as a cooling medium. Heat from the syngas is transferred to the feedwater resulting in the generation of medium pressure saturated steam that is transferred to the HRSG in the power block for superheating and re-introduced to the steam turbine as hot reheat steam. After being partially cooled in the syngas cooler, the syngas passes through a candle filter to remove entrained solids from the syngas. Additionally the syngas is passed through a water wash scrubber which is primarily used to remove fine particulate, chlorides, and any other water-soluble compounds (see Syngas Wash Towers section below).

Alternatively, HP steam can be generated in the syngas cooler, however this greatly increases the cost of the syngas cooler and associated piping (alloy materials vs. carbon steel), resulting in ~$60-$70 million increase in total project cost. Shell claims that the use of HP steam generation in the syngas cooler can result in a 1.5% improvement in IGCC efficiency; however this option was viewed as cost prohibitive at this stage of the project. It is recommended that this option be evaluated in more detail at a later developmental stage of the project.

Gasifier Performance Estimate by EPRI

EPRI used its internal IGCC modeling tool, which uses a Gibbs Free Energy Minimization approach to estimating gasifier product composition and temperature. EPRI relied heavily on the performance data Shell published in a 2004 Gasification Technologies Conference paper to set the inputs for the gasifier model. That paper presented performance estimates for the Shell coal gasification process on a generic Powder River Basin coal and on a 50/50 mixture of PRB and petcoke. One difference between the Shell design premises and those used by EPRI was the purity of the oxygen feed stream. Shell assumed it was 99 v% O2, while EPRI chose 95 v% as several engineering studies have shown that to be the optimal value for IGCCs producing power only.

A summary of the main inputs and outputs from the gasifier performance model at the 43F ambient condition is provided in Table 4-2.

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Table 4-2 Summary of Gasifier Modeling Results

100% PRB 50% PRB / 50% Petcoke

Model Inputs O2/coal feed ratio (95v% O2) lb/lb-coal1 0.771 0.881 Steam/coal lb/lb-coal1 0.034 0.104 N2/coal lb/lb-coal

1 0.110 0.107

Syngas Exit Pressure psia 574 574 Heat Flux to Gasifier Wall %coal HHV 0.6 1.4 Carbon Conversion % 99.5 99.0 Model Results Syngas Exit Temperature F 2732 2913 Gasifier Wall Steam Production MMBtu/hr 32.7 74.8 Syngas Exit Composition CH4 %vol 0.019 0.018 CO %vol 59.91 64.85 CO2 %vol 2.66 1.10 COS %vol 0.013 0.110 H2 %vol 26.78 25.23 H2S %vol 0.168 1.21 H2O %vol 4.13 1.65 HCN %vol 0.005 0.011 NH3 %vol 0.005 0.003 N2 %vol 5.33 4.80 AR %vol 0.97 1.02 O2 Feed Rate lb/hr 377,816 364,983 Steam Feed Rate lb/hr 16,688 42,939 N2 for Coal Conveying lb/hr 54,069 44,371 Coal Feed Rate lb/hr 490,171 414,125 Coal Feed Rate2 MMBtu/hr 5,444.3 5,340.7 Unquenched Syngas Flow Rate lb/hr 901,760 850,367 Syngas Production Rate2 MMBtu/hr 4,561.7 4,453.4 Flyslag (overhead) Production lb/hr 10,084 6,185 Slag (bottom) Production lb/hr 26,900 9,866 Cold Gas Efficiency3 % 83.8 83.4 1 As fed coal basis (dried to 5 wt% H2O)

2 HHV basis

3 As fed coal HHV basis only, energy value of feed steam and dryer fuel not included

Slag Handling

Slag formed in the coal gasification process flows to the bottom of the gasifier. This slag is quenched in a slag bath that is located within the gasifier vessel. Water is circulated through the slag bath to recover the heat from the slag. The hot slag water is cooled with a heat exchanger.

The cooled slag settles to a slag accumulator and lockhopper vessel. Once the slag has settled to the lockhopper vessel, the valves between the slag accumulator and lockhopper vessel are closed. The lockhopper provides a transition between the pressurized gasifier and the atmospheric slag dewatering system. Once isolated from the gasifier, the lockhopper is depressurized and the

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valves are opened at the outlet of the lockhopper vessel. The slag and water mixture are then discharged to the slag dewatering system. This lockhopper system operates in batch mode continually to remove slag from the gasifier as it is accumulated.

The slag from the outlet of the lockhopper is dewatered using a submerged scraper conveyor. The slag slurry water from the bottom of the submerged scraper conveyor is pumped to a clarifier where the clean slag slurry water is recycled to the lockhopper and the fines are collected and re-injected into the gasifier. The coarse slag from the outlet of the submerged scraper conveyor is conveyed to a slag storage pile. The coarse slag can then be landfilled or sold to market. The glassy, inert slag produced in the Shell gasifier is very low in carbon content which makes the slag attractive for sale.

Fly Ash System

After the syngas cooler, the syngas passes through first a cyclone and then ceramic candle filters that remove particulate matter (flyash) from the syngas. Similar to removing the slag from the gasifier, the flyash is removed from the cyclone and candle filter vessels with a batch process using lockhoppers. The coarse flyash that was removed by the cyclone can be recycled to the coal mill if it contains a significant amount of unconverted carbon. Otherwise, the coarse flyash along with the finer flyash collected by the candle filters is temporarily stored on site and either landfilled or sold to cement manufacturers or to other markets for flyash.

Syngas Wash Towers

Raw syngas flows from the candle filter to the syngas wash towers where the syngas is washed with water. The purpose of the water wash is twofold: 1) to recover any particulates that pass through the candle filters and 2) to recover chlorides that dissolve in the wash water and remove them from the system at concentration less than 300 ppm (to avoid corrosion of the carbon steel tower and piping). The wash water is primarily fresh demineralized water to which recycled water streams from the saturator water circulation loop (a purge stream) and the sour water stripper bottoms are added.

The water streams from the bottom of the syngas wash towers flow to a common system consisting of several operations:

The first step is a flash at 7 psia. Liquid from the flash is cooled with make-up demineralized water used for syngas saturation before being filtered and sent to the cooling tower as make-up water.

Solids recovered from the filtration mentioned above (particulates not removed by the candle filters) are sent to the coal pile. The amount of solids is estimated at only 110 lb/day.

Vapor from the 7 psia flash is condensed under vacuum using an air cooler. Liquid condensed in the air cooler is separated from the small amount of vapor and is

pumped to the sour water stripper.

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Vacuum conditions in the condensate drum are maintained by a steam jet ejector. Effluent from the ejector flows to the sour water stripper.

This design was generated by Burns & McDonnell in absence of detailed design information by Shell and does not represent Shells standard syngas scrubbing and sour water treatment design. It is recommended that the design of this system be evaluated in detail in conjunction with Shell at a later development stage of the project.

The syngas wash system consists of the following equipment:

Syngas wash tower (one tower for each of two parallel trains). Recovered water flash drum (one common drum for two parallel trains). Recovered wash water pumps (one common pump with a full spare for two parallel trains). Recovered wash water exchanger (one common exchanger for two parallel trains). Recovered wash water filters (one common filter with a full spare for two parallel trains). Flashed water condenser (one common air cooler for two parallel trains). Flash water condensate drum (one common drum for two parallel trains). Flashed water steam ejector (one common ejector for two parallel trains). Flashed water condensate pumps (one common pump with a full spare for two parallel

trains).

Washed syngas flows to the COS/HCN hydrolysis reactors.

COS / HCN Hydrolysis

The syngas contains trace amounts of carbonyl sulfide (COS) and hydrogen cyanide (HCN) and relatively large amounts of both H2 and H2O. Hydrolysis of COS is required because the AGR removal step (SELEXOL) only removes about 50% of the COS fed to AGR. The quantity of COS present in the raw syngas is such that if not hydrolyzed the concentration of COS alone in the feed to the gas turbines would be 60 ppmv for the 100% PRB case and 480 ppmv for the 50% PRB / 50% petcoke case compared to the required 30 ppmv level for COS plus H2S. The use of catalytic hydrolysis reduces the contribution of COS in th