12/4/2009 Page 1

RETROFIT OPPORTUNITIES FOR PETCOKE GASIFICATION

WITH CO2 CAPTURE

Peter Kabatek, Vladimir Vaysman and Calvin Hartman

WorleyParsons Group, Reading PA, USA

ABSTRACT

This technical paper presents the results of a high-level screening study to evaluate thefeasibility, performance and costs for adding gasification of petcoke at an existing plant.Analyses carried out by various investigators, [1], [2] and [3], have evaluated the impact ofpetcoke gasification on new and existing power plants. The objective for this study was to assesstechnical and economic aspects of petcoke gasification with CO2 capture for EOR into anexisting integrated plant.

Petcoke feed to a GE technology solid feed quench gasifier system is presented, which capturesup to 5.5 million tons per year of carbon dioxide (CO2). The study focused on the petcokepreparation, air separation unit, gasification process and syngas treatment steps required,including those to meet the required CO2 quality specification.

The evaluation scope included: qualitative description of the technologies, including developingblock flow diagrams (BFD), heat and mass balances (HMB), estimating plant performance and acost summary, as well as the CO2 capture cost intensity ($/ton CO2).

ORGANIZATION

This paper is organized into the following sections.

Introduction Technology Evaluation Coal Blend Analysis Plant Configuration and Component Description Cost Estimate Performance Results (Petcoke) EPCM Schedule Availability and Reliability Conclusions and Recommendations

1 Gasification of Petcoke Using the E-Gas Technology at Wabash River, P. Amick, Global Energy Inc.; presented at the 2000Gasification Technologies Conference, San Francisco, CA, October 2000.

2 Opportunities for Petroleum Coke Gasification Under Tighter Sulfur Limits for Transportation Fuels, D. Gray and G. Tomlinson,presented at the 2000 Gasification Technologies Conference, San Francisco, CA, October 2000.

3 Update: IGCC Power Generation – Down but Not Out, S. Shelley, Chemical Engineering Progress, September 2008, p. 8-14.

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INTRODUCTION

A confidential project has been proposed to incorporate an industrial gasification project for anexisting facility, which consumes steam, electricity and natural gas. The objective of the projectis to decrease the energy costs and dependency on natural gas, which is the current main sourceof energy.

The proposed project is based on meeting this objective by gasification of petcoke and,potentially, blends of coals, to produce syngas. A portion of the syngas is to be used for a newcombustion turbine and the remainder will be used to produce synthetic natural gas (SNG) forthe existing facility. Steam from the heat recovery boiler and waste steam from the gasificationand methanation process will also be used by the facility.

The facility currently consumes approximately 1,700 MMBtu/hr of natural gas, of whichapproximately 70% is used to make power and steam, and approximately 30% is consumedelsewhere.

The proposed gasification unit is configured for the primary purpose of eliminating the import ofelectricity and natural gas, and providing all of the project’s energy needs. Net power generationfor export to the grid is unnecessary and undesirable due to low avoided cost of the local utility;however, because of the nature of the process, some excess power would be generatednevertheless.

Because the facility runs continuously, reliability and low total cost are essential. Therefore, theoperating concept is to provide multiple independent steam sources.

The scope of the study includes the following:

1. Prepare basis of design for the study.

2. Evaluate gasification technologies to determine the technology best suited for thegoals and criteria of the study.

3. Identify a commercially available petcoke suitable for SNG production.

4. Evaluate three blended coals to minimize commercial dependence on the basefuel petcoke.

5. Develop a gasification and SNG configuration that meets the study’s objectives.

6. Evaluate gasification, SNG and power-block island performance.

7. Prepare an equipment layout showing the plant configuration on the site diagram.

8. Determine availability and reliability of the proposed plant configuration.

9. Prepare a process description.

10. Determine makeup water requirement and feed rate for the design fuel.

11. Determine major emissions, hazardous wastes and plant discharges.

12. Determine interconnections with the existing site.

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13. Prepare an order-of-magnitude cost estimate (CAPEX/OPEX) and assesincremental cost increase for CO2 compression (± 50% level of accuracy).

14. Prepare an indicative EPCM project schedule.

During the course of the study, after the initial technology screening, it was decided that thestudy would proceed with a single technology, that being GE Quench gasification, rather thanmaintaining and evaluating alternative technologies. The study was completed on that basis. Itshould be noted that, as found in the initial screening, there are several alternate gasificationtechnologies that are suitable for this application.

TECHNOLOGY EVALUATION

WorleyParsons employed a screening process that weighed the various gasification technologiesagainst the project drivers. The weighing factors and parameters were developed withconsideration of the project’s specific requirements. Screening input came from WorleyParsons’in-house data and experience, coupled with recent efforts of the project’s goals and requirements.

WorleyParsons utilized computer modeling (using programs, such as ASPEN Plus™, ProMax™,GateCycle™, etc.), supplemented by in-house information, to provide relative projectinformation enabling the appropriate decisions required.

Technology evaluations included key processes, such as shift configuration, acid gas removal(AGR) and methanation approach. The process selection focused on striking a balance betweenplant CAPEX/OPEX and the project drivers. Primary project drivers included meeting theproject’s energy needs; high reliability through parallel operation with the existing powerhouse;low cost; and commercial experience with the fuel.

GASIFIER SELECTED FOR EVALUATION

It was decided to limit the study to a single technology, the GE Quench technology, as thistechnology provides a “fit” due to its extensive experience with petcoke, flexibility with size andrelatively low capital cost. It was further noted that the risks involved with using a gasifierwithout petcoke experience were too great. Selection of the GE Quench gasifier was agreedupon for the purposes of performing this study only, with the stipulation that a more rigorousanalysis be performed prior to selecting the final technology for commercial consideration.

COAL BLEND ANALYSIS

Petcoke is the primary fuel being used. Alternate coals are evaluated to determine the amount ofcoal that can be blended with petcoke without exceeding a degradation of more than 10% ofsyngas production from the gasifier, utilizing GE Quench.

Ultimate fuel analyses for the petcoke and blended coals (PRB-Utah, Illinois #6 and WesternAppalachian) are indicated below.

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Exhibit 1 – Petcoke and Coal Ultimate Analyses

Ultimate Analyses of Petcoke and Coals

Petcoke1Western

AppalachiaIllinois

#6

Power RiverBasin

(Wyoming)

Carbon 81.14% 72.23% 63.36% 49.87%

Hydrogen 2.05% 4.78% 4.36% 3.48%

Nitrogen 0.98% 1.37% 1.33% 0.66%

Chlorine 0.01% 0.09% 0.17% 0.01%

Oxygen 1.75% 5.12% 6.97% 12.21%

Ash 0.57% 7.09% 9.21% 4.78%

Sulfur 5.72% 2.32% 3.13% 0.32%

Moisture 7.80% 7.00% 11.47% 29.03%

Total 100% 100% 100% 100%

HHV(Btu/lb)(as fired basis)

12,932 13,000 11,500 8,567

Volatiles - 38.94% 40.36% 44.43%

Fixed carbon - 53.44% 49.25% 48.85%

Note 1: WorleyParsons recommends utilizing petcoke (and other solid fuels) withrelatively low nitrogen values (< 1.5% dry). At higher values of nitrogen, the HHVof the SNG may be diluted below the minimum value required for pipeline qualitygas based on the gas specification used.

The results indicate that approximately 100% of the Illinois 6 coal and the Western Appalachiacoal can be processed without exceeding 10% degradation of the syngas produced. The amountof PRB that can be produced is minimal before degradation limit is exceeded.More importantly, blending of any of these coals, even in small amounts, reduces the SNGproduction, resulting in no net export and less than minimum SNG to the power plant as shownbelow.

Therefore, only petcoke can be used when meeting all steam, syngas and SNG demands. Anadditional gasifier would need to be added to make use of the alternate coals and still meet theplant demands. Alternatively, the deficit SNG could be bought as natural gas from the pipeline.

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Exhibit 2 - Process Summary for Coal Blends

100%Petcoke

WesternAppalachia Illinois No. 6 PRB

Petcoke, lb/hr 227,722 0 5,000 205,000

Coal, lb/hr 0 215,020 231,914 7,989

Sour Syngas, MMBtu/hr, HHV 2,142 2,027 1,927 1,926

Sour Syngas, MMBtu/hr, LHV 2,012 1,873 1,776 1,796

Fraction of Sour Syngas to Shift 0.775 0.645 0.60 0.670

SNG, Btu/scf 856 950 949 954

SNG, MMBtu/hr, HHV 770 704 629 634

SNG to Others, MMBtu/hr 570 570 570 570

SNG to Power Block, MMBtu/hr 200 200 200 200

SNG Net, MMBtu/hr 0 (66) (141) (136)

Illinois No. 6 is used for sizing coal handling equipment, because it requires the highest flow rateof all the coals for the same amount of SNG produced. On the other hand, petcoke is used forsizing the process and gas side equipment, because of the greater amount of sulfur contentcritical to sizing the AGR and sulfur removal equipment. This combination provides the greatestflexibility in allowing a range of coals to be used.

While Illinois No. 6 and petcoke were used for sizing criteria, Western Appalachia coal is thepreferred coal to blend with petcoke. It requires the least amount of SNG to be imported and lesscoal used than Illinois No. 6.

PLANT CONFIGURATION AND COMPONENT DESCRIPTION

Major process areas are as follows.

Coal Handling and Feed Preparation Air Separation Unit Gasification Sour Shift COS Hydrolysis Gas Cooling Selexol Acid Gas Removal Methanation Claus Unit Power Block, including a single Combustion Turbine and low pressure Steam Turbine Balance of Plant

The Power Block also includes all other support units, such as water treatment, cooling towers,switchyard, flare and other utilities required for the facility’s operation.

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COAL HANDLING AND FEED PREPARATION

The coal is unloaded at a new barge facility and transported to an active coal pile. The as-received coal is first milled to the required size. In order to prepare the coal for GE’s gasifier,the milled coal is mixed with water recycled from the black water system, in effect creating a65% (by weight) suspended solids slurry. This slurry is then pumped to the required feedpressure and continuously fed to the gasifier.

AIR SEPARATION UNIT

The Air Separation Unit (ASU) is a cryogenic process that provides 99% pure oxygen forgasifier operations. High-purity oxygen is required to minimize the percentage of inert speciesin the produced SNG.

In the ASU, ambient air is first filtered to remove particulates. A centrifugal inter-cooledcompressor is used to pressurize the air. Cold compressed air is fed to molecular sieve units toremove CO2, H2O and any hydrocarbons. A second filter removes entrained molecular sieveparticles. Dry air is fed to the coldbox heat exchangers and is cooled, while product streams areheated. Some of the compressed, dry air is expanded to provide refrigeration and is then fed tothe low pressure column for distillation. The main feed air stream is fed to the high-pressurecolumn where it is separated by distillation into crude oxygen and pure nitrogen. The crudeoxygen is then fed to the low-pressure column and the nitrogen is liquefied for reflux in bothcolumns. Product oxygen is withdrawn from the low pressure column and treated before it isfinally supplied to the gasifier.

GASIFICATION

Gasifier performance was modeled in AspenPlus™ with a combination of inputs from project-specific vendor information and WorleyParsons experience base. Methods and assumptions usedin the modeling process produced an estimated characterization of the gas produced by theapplied gasification technology.

In gasification, coal is reacted in a reducing atmosphere. The fuel is partially oxidized in high-purity oxygen from the ASU. Sulfur present in the fuel predominantly combines with hydrogenand forms hydrogen sulfide, H2S. Ash agglomerates into a liquid slag due to the hightemperature of the gasification reactor and is cooled and removed from the process as a glassysolid. The end product is a synthesis gas comprised mainly of CO, CO2, H2 and H2O.The GE Quench gasifier is an entrained-flow gasifier. The crude product syngas is cooled andscrubbed by a quench system.

A beneficial effect of the quench and gas scrubbing process is that the raw syngas containssufficient moisture for the downstream sour shift reaction. A modest volume of dirty black wateris also created in the process. Preliminary water treatment removes bulk solids and dissolvedgases from the water.

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SOUR SHIFT, COS HYDROLYSIS AND GAS COOLING

Syngas generated during gasification must be adjusted to a H2-to-CO ratio slightly greater than3:1 for optimum performance in the methanation stage. First, a feed-product exchanger heats thesyngas entering the shift reactor. Once reacted, the syngas temperature has increased to a levelcapable of generating high-pressure (HP) steam. Residual heat is used for feedwater heating,generation of low pressure steam or is removed by circulating cooling water.

Cooled raw syngas is combined with the shifted syngas and is cooled below its dew point. Thestream is moderately superheated with waste heat from the shift reaction before being processedin a COS hydrolysis reactor. Hydrolysis is essential for the downstream Selexol unit toadequately remove the sulfur. Following the hydrolysis reactor, as the gas is cooled in stages,water is condensed out of the gas phase. At the higher-temperature end of the cooling process,the process condensate is clean and is recycled back to the quench water system. Lower-temperature process condensate absorbs significant levels of sour gases and must be treated in adegassing column, along with grey water from the gasifier.

MERCURY REMOVAL

Cooled and shifted syngas is reheated slightly to vaporize any entrained mist then passed througha bed of activated carbon impregnated with sulfur, which captures most of the trace mercury inthe syngas and other metals. Mercury removal is expected to be at least 90%.

SOUR WATER STRIPPER

A sour water drum accumulates sour water from the gas scrubber system and condensate fromthe low temperature syngas coolers. Sour water from the drum flows to the sour stripper, whichis a packed column with a steam-heated reboiler. Sour gas, generally comprising CO2, H2S andwater vapor, stripped from the liquid, is sent to the Claus unit. Liquid from the sour waterstripper is sent to an ammonia stripper where most of the ammonia is removed and sent to theClaus unit. Finally, a blowdown stream of the filtered and degassed water is taken to wastewatertreatment to control the chloride level in the system. The remaining water is returned to the gasscrubber system.

SELEXOL ACID GAS REMOVAL

The purpose of the Selexol unit is to remove H2S and CO2 from the cool shifted syngasproducing a sweet syngas, H2S rich acid gas, and CO2 product. In two columns, Selexol solventis contacted with the sour syngas to first remove H2S and then CO2. Captured CO2 is thenremoved from the solvent through staged pressure flashes. High and low pressure CO2 streamsare generated for further external compression. Finally, H2S is stripped from the solvent in aregeneration column. Acid gas generated by this stripping process is sent to the Claus unit.Sweet syngas is passed through a sulfur guard bed to polish any remaining H2S. Methanationcatalysts are poisoned by sulfur, and it is essential to minimize the level of H2S in their feed.

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METHANATION

The methanation process produces SNG by converting CO and H2 to CH4 and H2O. Sweetsyngas enters the methanation process and is mixed with recompressed product from the firstmethanation reactor. Heat is supplied to the feed stream in a feed-product heat exchanger. In thefirst fixed-bed catalytic reactor, a large portion of the incoming CO is converted into CH4.Effluent gas is cooled and both HP and MP steam is generated. A slipstream of cooled gas isrecompressed and routed back to the first reactor for temperature control.

Cooled product from the first methanation reactor is directed to the second methanation reactorwhere more CO is converted to CH4. Water is removed before the final reactor in order to obtainan adequate SNG higher heating value. A feed-product heat exchanger cools the effluent fromthe second stage while heating the feed to the third stage. Additional heat resulting from watercondensation is used for feedwater heating, generation of low pressure steam, or removed bycirculating cooling water. The final methanation reactor converts the remaining CO to CH4.Produced SNG is cooled with heat being captured in the steam cycle or lost to cooling water.Before firing in the on-site gas turbines or being directed to the pipeline, the gas is dehydrated ina triethylene glycol (TEG) unit.

CLAUS UNIT

Claus units recover more than 99% of the incoming gaseous sulfur in the form of elementalsulfur via a Claus reaction furnace and three catalytic sulfur converter stages. Acid gas streamsgenerated throughout are combined in the Claus reaction furnace. Oxygen from the ASU is usedas the oxidant in the reaction furnace where H2S is reacted to form SO2 and elemental sulfur.Exhaust is passed through a waste heat boiler generating medium pressure (MP) steam.Remaining SO2 and H2S in the exhaust is converted to sulfur and water in the three catalyticconverter stages. Prior to each converter, a sulfur condenser cools down the gas stream so thatany elemental sulfur generated condenses out and is pumped to a sulfur surge pit. Eachcondenser also generates low pressure (LP) steam. Internally generated MP steam is thenconsumed to reheat the gas before the next catalytic converter. Liquid sulfur leaving the ClausUnit is pumped to a sulfur storage tank.

TAIL GAS TREATING

Tail gas from the Claus process contains small quantities of COS, CS2, SO2 and elemental sulfurvapors. In addition, there may be H2, CO and CO2 in the tail gas. To fully recover the sulfurspecies, tail-gas from the final sulfur condenser is routed to a hydrogenation reactor that convertsthese sulfur species to H2S. The hydrogenerator effluent gas is then indirectly cooled and thenquenched in a contact cooler with a caustic-water mixture. LP steam is generated in the tail gascooler. Processed tail gas leaving the contact cooler is compressed and recycled back to theSelexol Unit. Recapture of the H2S is a particularly suitable option when physical absorptionsolvents such as Selexol are utilized.

CO2 COMPRESSION AND DEHYDRATION

As discussed, Selexol generates CO2 at two pressure levels. For the purpose of this study, thecaptured CO2 is not compressed and sequestered, but rather it is vented. Should a requirement

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and opportunity to sequester the CO2 at a later date be identified, then additional compressionequipment would be required. Prior to being routed to the vent, the CO2 stream is subjected to aliquid scavenger that reacts with trace amounts of regulated pollutants.

POWER BLOCK

The core of the power block is made up of one syngas-fired GE 7EA gas turbine operating with aHRSG, which sends the steam it produces to process, and a low pressure steam turbine, whichtakes in excess process steam. Electricity is generated to meet facility demands and exported tothe power grid.

Condensate and steam systems for the power block are integrated with the syngas and SNGprocess. Saturated steam generated in the SNG process is directed to the appropriate drum onthe three-pressure HRSG. Superheat is applied to the steam before it is used for powergeneration in a steam turbine.

BALANCE OF PLANT

Raw water and demineralized water are supplied from the facility. Incoming effluent would beprocessed for makeup to the facilities cooling towers and steam cycle. Cooling tower blowdownand wastewater generated by both the SNG process and power block are collected, treated tomeet local limitations, and combined for discharge from the facility.

FLARE SYSTEM

The facility is equipped with an elevated flare. The flare system disposes of waste gasesgenerated by the gasification process during startup and shutdown. Relief valves in thegasification process discharge into a common header where liquids are separated in a knockoutdrum before the flare system. An integrated ignition system, complete with multiple pilotburners and monitoring instrumentation is capable of instantaneous ignition and maintaining astable burn throughout the period of waste gas flow.

The flare system is designed to support planned and emergency flaring events. Examples ofplanned flaring events would be gasifier startup, shutdown and ramping. Waste gas generatedduring planned flaring events would be treated to reduce environmental impact. Flaring ofuntreated waste gases will be limited to emergency events which could occur as a result of upsetoperating conditions.

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Exhibit 3 - Configuration Matrix

The resulting configuration is shown in Exhibit 4. It consist of coal handling; coal storage;slurry preparation; quench gasification; syngas scrubbing; high temperature cooling; airseparation unit; shift; low temperature gas cooling; double stage selexol; methanation;combustion turbine; heat recovery boiler; sulfur recovery; sour water treatment system; blackwater system; steam turbine; condenser; cooling tower; water treatment; and support systems.

The plant is integrated with the steam production of the power plant.

Case GE Gasifier

Combustion Turbine GE-7EA

Gasifier Technology GE Quench

Operating pressure/temperature 950 psig/2,600°F

Carbon conversion 98%

Raw gas temperature before it enters the quench 2,600°F

Raw gas temperature downstream from the quench 465°F

ASU Cryogenic

Oxygen purity, mol-percent 99

Design pressure, psig 985

Capacity sizing Based on Gasifier and Claus plant demand

Combustion turbine integration 0% extracted

Nitrogen Dilution Yes

Fuel Petcoke or Petcoke-Coal blend

Fuel Feed Slurry

H2S Separation Selexol 1st Stage

Sulfur Removal (min) 99%

Sulfur Recovery Claus plant/ Elemental Sulfur Purity 99.9% (Min)

CO2 Separation Selexol 2nd Stage

CO2 Capture (min) 70%

CO2 Sequestration Not Included

Steam Cycle

Throttle pressure 125 psig

Throttle temperature 525°F

Condenser pressure 2.5 in Hg

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Exhibit 4 - Configuration Block

AirDilution Nitrogen

Air Flue Gas

ProcessO2 Condensate

CO2O2 to SRU Vent SNG

SweetSyngas

Syngas

Make-Up Slag Slurry Sour Acid TailWater Quench Stripped Water Gas Gas

Water Water

SulfurSlag Product

Blowdown Waste Water

Bottoms

Slurry Water Sour Gas

Sour Gas

Scrubber

CokeHandling

Blending

CoalHandling

SlurryPrep.

BlackWater

System

WWT

Methanation

SWS

ASU

Shift /COSLTGC

SRU

Double-Stage

Selexol

GE 7EA HRSG

QuenchGasification &Syngas Scrub.

COST ESTIMATE

In this study, WorleyParsons used a factored performance approach for the cost estimates. Usingproject-specific gasification performance information and costs from in-house data,WorleyParsons adjusted the costs based on a review of past estimates and other in-house dataand then applied a factor based on the WorleyParsons performance estimates. The EPCM costestimate and O&M costs are in the range of ±50%, both of which are in 2009 USD.

Exhibit 5 - Total Plant Cost is Based on the Following Assumptions

Estimate Basis 2009

Contract Type EPCM

Labor Non-union

Construction Week 50 hours

Construction Overtime Spot overtime (approximately 3%)

Site Size 100 acres

Site Condition Level

Foundations Piles as required

Coal Storage 8 Days of Enclosed storage

Slag Disposal Byproduct Sale/Off Site

Water Supply River Water

Start Up Fuel Natural Gas

Gas Tie-In At Site Boundary

Water Tie-in At Site Boundary

Off Site Road Access Assumed in place

Cooling Method Wet cooling tower system

Power Tie-In Dead end tower on site included

Typical Owner’s Cost Not included

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Exhibit 6 - Gasification Island Configuration/Design Redundancy

SystemQuantity/Capacity

Comments

Air Separation Unit (100% Aircompression supplied)

1x100%95 mol% purity O2, liquid O2 pump system, Nitrogenavailable for GTG dilution, 8-12 hour of single trainoxygen storage for operational purposes

Gasifiers 3 x 33.3%GE Quench; Gasifier Pressure set to meet SyngasRequirements to GTCC

Methanation Unit 1 x 100%

Sulfur Recovery 1 x 100% Elemental Sulfur

Sour Shift and Gas Cooling 1 x 100% Double-stage shift

Acid Gas Removal 1 x 100% Selexol

Exhibit 7 - Power Island Configuration and Design Redundancy

System Quantity/Capacity

Combustion Turbine Generator (CTG) 1 x 100% GE 7EA, 90 MW

Heat Recovery Steam Generator (HRSG) w/SCR 1 x 100%

Steam Turbine Generator (STG) 1 x 100%, 24 MW

The EPCM capital cost and operating costs are shown in Exhibit 8. The total capital cost is $831million 2009 US dollars. Of this, 43% is allocated to the gasifier, ASU and gas cleaning; 15%for contingency; and 11% for engineering, construction management and startup. The largestcost for a single component is the ASU, at 16% of the total cost. Some projects are consideringpurchasing the ASU on a “purchase-over the fence” basis, where the ASU is owned and operatedby a contracted entity.

The 15% contingency is recommended, because of the conceptual status of this estimate. Theorder-of-magnitude cost for a spare gasifier is $90 million, installed. This cost is not included inthe EPCM cost estimate.

The operating costs are estimated to be approximately $38 million, of which half is fixed andhalf is variable. The estimated costs are averages and will vary year to year. The average costsinclude major maintenance that is required, such as CT gas path replacement and other long termmaintenance issues.

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Exhibit 8- Total EPC Plant Cost/Operating Summary

Total Plant Cost Summary (1,000 USD)Case: Gasification w/SNG Production

Plant Size: 240.0 Equivalent MW, net

Item/DescriptionEquipment

Cost

Material

Cost

Direct

Labor

Bare Erected

CostCoal & Sorbent Prep. & Feed,

Feedwater & Misc. Systems $47,300 $15,100 $26,800 $89,200Gasifier & Accessories, incl. ASU &

Assoc. Equipment $211,600 $5,100 $46,300 $263,000Gas Cleanup & Piping, incl. CO2

Removal $56,800 $8,400 $42,400 $107,600Combustion Turbine w/ Accessories,

HRSG, Ducting & Stack, Steam Turbine

Generator $65,100 $2,200 $7,100 $74,400

Balance of Plant Systems (Note 1) $41,300 $18,600 $34,000 $93,900Subtotal Bare Erected Cost $422,100 $49,400 $156,600 $628,100

Engineering, CM & Startup @15% $94,200Subtotal $722,300Contingency @15% $108,300Total Plant Cost $830,600

(1) Includes Cooling Water System for Gasification, Ash/Spent Sorbent Handling System, Accessory Electric Plant,

Instrumentation & Control, Improvements to Site, and Buildings & Structures.

Initial & Annual O&M Cost Summary (1,000 USD)

Fixed Operating Costs Annual CostOperating, Maintenance, Admin, & Support Labor Cost $19,000Total Fixed Operating Costs $19,000

Variable Operating Costs Initial Cost Annual CostMaintenance Material Cost - $16,100Water $0 $700Chemicals $1,400 $1,700Waste Disposal $0 $400Total Variable Operating Costs $1,400 $18,900

Total Initial & Annual O&M Costs $1,400 $37,900

CO2 COMPRESSION AND DEHYDRATION

As stated earlier, in the process of making syngas for methanation and power, the CO2 isseparated and vented, but is not compressed and dehydrated for sequestration, such as for EOR.An estimate has been made of the compression and dehydration capital cost for this project,using WorleyParsons’ in-house data. Thus the cost of CO2 compression and dehydration isapproximately $55.1 million, for a total plant cost of $885.7 million, or 1.066 times that withoutCO2 capture and dehydration.

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PERFORMANCE RESULTS (PETCOKE)

The performance of the proposed three 450 cu ft GE Quench gasifiers is shown in Exhibit 9.The impact on performance as a result of ambient temperature variation is minimal. Because ofthe split flow of the syngas to the CT or the methanation unit, either power or SNG productionwill be impacted, depending on the operation decision of how to split the syngas. In either case,performance variation is approximately 5% from seasonal variation in ambient conditions.

Exhibit 9 - Performance Summary

PARAMETER(1)

Petcoke FlowPetcoke Heat Input, HHVOxygen FlowSlag Flow

CO2 CapturedCO2 Recovered in AGR

Sweet Syngas Flow to Gas TurbineNitrogen Injection FlowHeat Input to Gas Turbine, HHVHeat Input to Gas Turbine, LHVPower Output

Sweet Syngas FlowSNG Product FlowSNG Heating Value, HHVSNG to Other Users, HHVSNG to Existing Power House, HHVSNG Available to Export, HHVSNG Heating Value, HHV

Sulfur ProductSlag

Notes:(1) Total for three operating 450 cu ft GE quench units, all other units are single trains.(2) ISO Conditions.

4,997 lb/hr156 STPD

Claus Plant956 Btu/scf25 MMBtu/hr

200 MMBtu/hr570 MMBtu/hr795 MMBtu/hr435 STPD932 STPD

Methanation90 MWe

922 MMBtu/hr1,050 MMBtu/hr

274,009 lb/hr

Gas Turbine81,995 lb/hr

90 %

Acid Gas Removal (AGR) and CO2 Recovery5,603 STPD

6,817 lb/hr2,835 STPD

GEE Quench Gasifier

VALUE(2)

UNITS

2,945 MMBtu/hr2,733 STPD

Estimated gas turbine exhaust pollutant emissions are shown in Exhibit 10.

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Exhibit 10 - Estimated Gas Turbine Exhaust Pollutant Emissions

A. Operation Description Units Value1. Fuel Type H2 Rich Syngas

2. Operating Plant Load % 1003. Ambient Temperature °F 604. Plant Total Heat Input (Three Gasifiers), HHV MMBtu/hr 2,9455. Gas Turbine Heat Input, HHV MMBtu/hr 1,068

B. Estimated GT Exhaust Gas Emissionslb/MMBtu 0.005ppmvd @ 15% O2 3.5lb/hr 14.8lb/MMBtu 0.022ppmvd @ 15% O2 25lb/hr 65.4lb/MMBtu 0.0013ppmvd @ 15% O2 2.5lb/hr 3.7

SO2 Emission lb/MMBtu 0.0004lb/hr 1.1lb/MMBtu 0.0037lb/hr 10.8

1.2. Emissions rate, in lb/MMBtu provided, is based on Plant Total Heat Input basis.3. HRSG Stack NOx emissions are based on SCR removal rate of 80%.4. Pollutant emissions at the GT exhaust are based on values provided by GE Energy.

5.

6.

7. Approximately 10% of SO2 is assumed to convert to SO3 at the HRSG exhaust end.

3. VOC Emission

SO2 and condensable particulate emissions are based on H2S concentration of less than 0.0005%

in the syngas.Particulate emissions include the front end (filterables) and back end (condensables) values

including Ammonium Sulfates.

Notes:

4.

5. Particulate Emissions

Cooling tower emissions are not included.

1. NOx Emissions (post SCR)

2. CO Emission

EPCM SCHEDULE

Shown in Exhibit 11 is a typical EPCM schedule for gasification. The schedule includes a FEEDdesign period of 18 months, and 60 months construction schedule including FEED.Designations “H1” and “H2” represent the first half of the year and the second half of the year,respectively.

Permitting is assumed to require 18 months and run concurrent with the FEED design.Construction is started upon the Permit approval.

The schedule will vary depending upon contract strategies, permitting and financing. A periodof 52 to 64 months is a reasonable range.

12/4/2009 Page 16

Exhibit 11 - EPCM Schedule

AVAILABILITY AND RELIABILITY

Availability and reliability were evaluated for major process areas. In this analysis, availabilityis defined as a piece of equipment’s readiness to perform its function on demand, whereasreliability is defined as a piece of equipment’s level of operation at design performance and loadwhen considering component or system failures.

Overall, with the process configuration chosen, an availability of 87.4%, with a correspondingreliability of 91.6%, can be expected. If a fourth gasifier were to be added, the availability of theprocess would increase to 89.5% and the reliability would increase to 93.0%.

The reliability of steam and electricity generation from the complete facility is 100%, as a resultof multiple independent backup sources.

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CONCLUSIONS AND RECOMMENDATIONS

Gasifiers – There are a number of possible gasifiers that could technically perform the requiredduty for this project including gasifiers from GE, BGL, Shell, Siemens and ConocoPhillips. Dueto the project’s preference, GE’s gasification technology was selected for this feasibility study.It is recommended, if this project proceeds to the next phase, that a more rigorous gasificationstudy of all the gasification technologies be performed before a final selection is made.

Configuration – The configuration selected is capable of providing all of the project’srequirements for steam, syngas, SNG and power with little excess in syngas and SNG. However,there still remains excess low pressure steam, which necessitates adding a steam turbine to avoidwasting the energy from this steam. The addition of a steam turbine generates excess power. Afurther study is recommended to investigate alternative measures to use or reduce this excess LPsteam. One approach might be to eliminate the added steam turbine cycle with its extra cost ofapproximately $35 million and excess power of 24 MW and condense the excess steam. Thesteam turbine was included in this study to obtain a conservative cost estimate.

The configuration meets the pipeline specification, provided the nitrogen content in petcoke isless than 1.1%, along with the required SNG production, but with very little margin. Additionalanalysis is recommended to evaluate means of increasing this margin economically.

Reliability – The configuration considered steam production reliability as a high priority. Thehigh reliability of steam supply is a result of fuel flexibility, reliable equipment and backupoperation by the client existing power boilers that were integrated into the configuration of thegasification facility.

Costs – The plant capital cost is estimated to be $831 million, within an accuracy of ±50%,excluding owner’s costs. Annual operating costs amount to $38 million (±50%). Areas of costreduction could include eliminating the steam turbine and either venting the steam or condensingand re-using it, looking at alternative AGR technologies, investigating a lease or purchase of theoxygen supply and performing a more detailed cost analysis, including obtaining vendorproposals and contractor input for construction costs. The operating costs assume averagestaffing of 15. Resource sharing maintenance and operations personnel, equipment andconsumables could lower this cost.

While CO2 compression and dehydration was not required as part of this study, including it inthe project is estimated to increase the plant capital cost by 6.6% to approximately $886 million.

Retrofit Opportunities for Petcoke Gasification with CO2 Capture

Authors: Peter Kabatek, Vladimir Vaysman, Calvin Hartman

POWER-GEN International 2009

Session TitleInnovations in Gasification and IGCC

December 9, 2009

Las Vegas Convention Center, Las Vegas, Nevada

Presentation Outline

Introduction & Study Objectives

Technology Evaluation

Coal Blend Analysis

Plant Configuration & Component Description

Cost Estimate

Summary of Results

Conclusions

Introduction & Study Objectives

Study to add petcoke gasification to existing facility

Purpose to evaluate project configuration, cost and blending impacts (not to select a final technology)

Facility consumes steam, electricity & natural gas

Decrease dependency on outside energy

Investigate blending coals with petcoke

From syngas, make power, steam, and SNG

Drivers: reliability, low cost, and commercial experience

Technology Evaluation

Compared gasification technologies

Qualitative: technical, commercial, & Quantitative analyses

Key processes: shift, AGR, and methanation

Major design criteria:

Gasification status at a commercial level

Low capital and operating cost

First priority is steam production, second is SNG, and third is power

Unit size (smaller multiple units preferred)

Fuel (petcoke and fuel flexibility)

Technology Evaluation (continued)

Found several technologies suitable for this application

GE (Quench and Radiant Quench), ConocoPhillips, Shell, BGL, and Siemens

Project chose GE Quench as good “fit” with drivers (reliability, low cost, and especially commercial experience)

Coal Blend Analysis

Compared blending 3 coals with petcoke

Western Appalachia, Illinois #6, PRB

10% degradation of syngas production limit

PRB can’t be used, but the other two can

Illinois #6 has the highest feed rate

Petcoke has the highest syngas rate

Coal Blend Analysis (continued)

Ultimate Analyses of Petcoke and CoalPetcoke West. Illinois PRB

Appalachia #6 (Wyoming)Carbon 81.1% 72.2% 63.4% 49.9%Hydrogen 2.05% 4.78% 4.36% 3.48%Nitrogen 0.98% 1.37% 1.33% 0.66%Chlorine 0.01% 0.09% 0.17% 0.01%Oxygen 1.75% 5.12% 6.97% 12.2%Ash 0.57% 7.09% 9.21% 4.78%Sulfur 5.72% 2.32% 3.13% 0.32%Moisture 7.80% 7.00% 11.5% 29.0%

HHV (Btu/lb) 12,932 13,000 11,500 8,567

Plant Configuration

AirDilution Nitrogen

Air Flue Gas

ProcessO2 Condensate

CO2O2 to SRU Vent SNG

SweetSyngas

Syngas

Make-Up Slag Slurry Sour Acid Tail Water Quench Stripped Water Gas Gas

Water Water

Sulfur Slag Product

Blowdown Waste Water

Scrubber Bottoms

Slurry Water Sour Gas

Sour Gas

Coke Handling

Blending

Coal Handling

Slurry Prep.

Black Water

System

WWT

Methanation

SWS

ASU

Shift / COS LTGC

SRU

Double-Stage

Selexol

GE 7EA HRSG

Quench Gasification & Syngas Scrub.

Component Description

Petcoke/coal handling & feed prep.

ASU

Gasification, quench & syngas scrubbing

Shift, COS hydrolysis & gas cooling

Selexol AGR

Methanation

Power block

Cost Estimate

Budgetary (±50%) capital & operating cost estimate

3 x 450 cu ft GE gasifier trains; 1 train of all else

$831 million total plant installed cost

$38 million initial & annual O&M cost

$55 million adder for CO2 compression/dehydration

$90 million adder for 4th spare gasifier

Performance Summary

Petcoke feed: 2,733 STPD

O2 feed: 2,835 STPD

CO2 capture: 5,603 STPD

Power: 90 MWe

SNG product: 435 STPD

Sulfur product: 156 STPD

Syngas change from seasonal temp. variation, about 5%

Summary of Results

EPCM schedule: 60 mo, including 18 mo FEED

Availability (readiness to perform on demand) 87.4%

Reliability (operation at design performance) 91.6%

Spare gasifier increases to 89.5% and 93.0%

Demonstrated feasibility of petcoke gasification retrofit of plant for power, steam, and SNG

CO2 capture inherent with process, but CO2 not at sequestration conditions

Acknowledgement

WorleyParsons Group, Inc.

Michael DeLallo

Vladimir Vaysman

Calvin Hartman

Satish Gadde

Jay White

Process engineers

Mechanical engineers

Electrical engineers

Cost estimators

Admin staffContact Information:Contact Information:

Peter KabatekPeter Kabatek

610610--855855--23292329

peter.kabatek@worleyparsons.competer.kabatek@worleyparsons.com

Questions? Thank You!