DOE/NETL-2002/1164

Wabash River Coal Gasification

Repowering Project: A DOE Assessment

January 2002

U.S. Department of Energy

National Energy Technology Laboratory

P.O. Box 880, 3610 Collins Ferry Road

Morgantown, WV 26507-0880

and

P.O. Box 10940, 626 Cochrans Mill Road

Pittsburgh, PA 15236-0940

website: www.netl.doe.gov
2

Disclaimer

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

agency of the United States Government. Neither the United States

Government nor any agency thereof, nor any of their employees,

makes any warranty, express or implied, or assumes any legal liability

or responsibility for the accuracy, completeness, or usefulness of any

information, apparatus, product, or process disclosed, or represents

that its use would not infringe privately owned rights. Reference

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

trade name, trademark, manufacturer, or otherwise does not

necessarily constitute or imply its endorsement, recommendation, or

favoring by the United States Government or any agency thereof. The

views and opinions of authors expressed therein do not necessarily

state or reflect those of the United States Government or any agency

thereof.
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Contents

Executive Summary.........................................................................................................................5

I Introduction..............................................................................................................................10

II Project/Process Description....................................................................................................11

II.A Project Description ..................................................................................................11

II.B Need for the Technology Demonstration.................................................................14

II.C Promise of the Technology......................................................................................14

II.D Technology Description...........................................................................................14

II.D.1 Coal Handling............................................................................................14

II.D.2 Air-Separation Unit ...................................................................................15

II.D.3 E-GasTM Gasifier .......................................................................................15

II.D.4 Syngas Conditioning/Cleanup ...................................................................17

II.D.5 Power Block ..............................................................................................20

II.E Project Implementation ............................................................................................20

II.F Project Objective and Statement of Work................................................................21

III Technical and Environmental Review .................................................................................24

III.A Technical Results ...................................................................................................24

III.A.1 Air-Separation Unit ..................................................................................25

III.A.2 Coal Handling...........................................................................................26

III.A.3 Gasification ..............................................................................................27

III.A.4 Syngas Cooling and Particulate Removal ................................................27

III.A.5 Chloride Scrubbing System and COS Hydrolysis....................................28

III.A.6 Low-Temperature Heat Recovery and Syngas Humidification................28

III.A.7 Acid-Gas Removal, Sulfur Recovery, and Sour-Water Stripping............29

III.A.8 Power Block .............................................................................................29

III.A.9 Operations Feeding Petroleum Coke........................................................29

III.B Environmental Performance...................................................................................33

IV Market Analysis....................................................................................................................35

IV.A Market Size/Commercialization ............................................................................35

IV.B Economics ..............................................................................................................37

IV.B.1 Capital Costs ............................................................................................37

IV.B.2 Operating Costs........................................................................................37

IV.B.3 Cost of Electricity.....................................................................................37

V Conclusions............................................................................................................................39
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Abbreviations.................................................................................................................................40

References......................................................................................................................................41

Bibliography...................................................................................................................................42

List of Figures and Tables

Figure Page

1 Process Flow Diagram of WRCGR Project............................................................................... 12

2 Block-Flow Diagram of the WRCGR Project ........................................................................... 13

3 Simplified Block-Flow Diagram of Gasification Process.......................................................... 15

4 Schematic of E-GasTM Entrained-Flow Gasifier........................................................................ 16

5 Gasification Slag Handling ........................................................................................................ 17

6 Acid-Gas Removal..................................................................................................................... 18

7 Sulfur-Recovery Unit................................................................................................................. 19

8 Sour-Water Treatment Unit ....................................................................................................... 19

9 Power Block............................................................................................................................... 20

10 Worldwide Gasification Capacity.............................................................................................. 35

Table Page

1 Capital Costs for the WRCGR Project ...................................................................................... 21

2 Performance Summary............................................................................................................... 24

3 WRCGR Project Production Statistics ...................................................................................... 25

4 Fuel Properties ........................................................................................................................... 26

5 E-Gas Gasifier On-Stream Hours ........................................................................................... 27

6 Product Syngas Composition..................................................................................................... 28

7 Typical Fuel Analyses................................................................................................................ 30

8 Thermal Performance Summary for Operations With Petroleum Coke .................................... 31

9 Product Syngas Composition..................................................................................................... 32

10 E-GasTM -Based IGCC Capital Costs......................................................................................... 37

11 Basis for Economic Evaluations ............................................................................................... 38

12 Economics* of Power Generation by an IGCC Unit Using E-GasTM Technology.................... 38
5

Executive Summary

The U.S. Department of Energy (DOE) Clean Coal Technology (CCT) Program seeks to furnish

the energy marketplace with more efficient and environmentally benign coal utilization

technologies through demonstration projects. This document is a post-project assessment (PPA)

of one of the demonstration projects selected in Round IV of the CCT Program, the Wabash

River Coal Gasification Repowering (WRCGR) Project.

In July 1992, Destec Energy, Inc., and PSI Energy, Inc., entered into a cooperative agreement

with DOE to demonstrate an application of the Destec gasifier to repower a pulverized coal-fired

boiler using an integrated gasification combined-cycle (IGCC) system. The selected site for the

project was PSI Energy’s Wabash River power station in West Terre Haute, Indiana. Engineering

services were provided by Sargent & Lundy, Inc., and Dow Engineering Corp. The gasifier

technology used in this CCT project has been renamed E-GasTM Technology and is now owned

by Global Energy, Inc. DOE provided 50 percent of the total project funding (for capital and

operating costs during the demonstration period) of $438 million.

The Wabash River power station consists of six units that had a nameplate generating capacity of

973 MWe prior to the WRCGR Project. The oldest of the units, Unit 1, with a nominal rating of

99 MWe, was repowered with the E-GasTM Technology Gasifier and integrated with a new

192-MWe combustion turbine and a heat-recovery steam generator (HRSG). The main facilities

retained were the steam turbine and its auxiliaries and the coal-handling equipment. The unit’s

rating increased to 262 MWe (net) after repowering. In addition to demonstrating commercial

operation of the E-Gas Gasifier in a utility electrical grid, the goal was to demonstrate a

number of novel technical aspects of the project, including hot-particulate removal, hot-gas

cooling by steam generation, syngas recycle, carbonyl sulfide hydrolysis, slag-fines recycle, fluegas moisturization, and sulfur plant tail-gas recycle.

IGCC technology promises greater than 40-percent efficiency, fuel flexibility, and very low

pollutant emissions compared to pulverized-coal-fired plants. The electric utility industry has

typically been reluctant to embrace IGCC for power generation because the equipment and

operations are significantly different from what this industry is accustomed to using. The

perception has been that, compared with conventional coal-based power production, IGCC

systems are relatively complex, capital intensive, and present considerable risk for any utility

planning such an installation. The commercial demonstration of the E-Gas TM Gasifier

accomplished by this highly successful CCT project is helping dispel this perception and will

facilitate the market penetration of IGCC technology.

In the E-GasTM Technology process, coal is ground in a rod mill along with treated water and slag

fines recycled from the gasifier. Slurry from the rod mill is stored in an agitated tank from which

it is pumped to the gasifier. Ninety-five-percent oxygen from the air-separation unit (ASU) is

compressed and fed to the gasifier along with the coal.
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The E-GasTM Gasifier consists of two stages: a slagging first stage and an entrained-flow,

non-slagging second stage. In the first stage, the fuel slurry is partially combusted with oxygen at

nominal conditions of 2,600 °F and 400 psia. Oxygen and slurry are fed into the first stage

through two opposed mixing nozzles of proprietary design. The oxygen feed rate is controlled to

maintain the gasification temperature above the ash fusion point. Fluxes may be added prior to

the grinding stage to ensure that the slag is fluid at the first-stage temperature. Molten slag flows

to the bottom of the gasifier, where it is quenched and then removed for sale or disposal. The

gasifier is capable of handling a wide range of feedstocks.

In the E-GasTM Gasifier, the slurry feed is almost completely converted to a syngas consisting

primarily of hydrogen (H2), carbon monoxide (CO), carbon dioxide (CO2), and water (H2O).

Sulfur in the feed is converted to hydrogen sulfide (H2S) with a small amount of carbonyl sulfide

(COS). Nitrogen (N2) in the coal is converted to ammonia (NH3). In the second stage, additional

slurry, (but no additional oxygen), is injected and undergoes devolatilization and pyrolysis. These

endothermic reactions cool the syngas and increase its heating value because of the nature of the

products produced.

The hot syngas is cooled from 1,900 °F to approximately 700 °F in the syngas cooler, which

generates 1,600-psia steam. The cooled syngas is sent to a filter vessel containing porous candle

filters that remove in excess of 99.9 percent of the particulates. The particulate-free syngas is

further cooled and then water scrubbed to remove chlorides and volatile trace metals, and piped

to the COS hydrolysis unit, where COS is converted to H2S.

The syngas is then further cooled to 100 °F in the low-temperature heat-recovery unit. The

cooled syngas is sent to the acid-gas removal system, where most of the H2S and some CO2 are

removed. The essentially sulfur-free syngas is then moisturized, superheated, and sent to the

combustion turbine. Recovered acid gases are sent to the sulfur-recovery unit that produces

99.999-percent-pure sulfur. Greater than 98-percent sulfur recovery is achieved.

Preheated, moisturized syngas and compressed air are supplied to the combustion turbine that is

coupled to an air compressor. Hot exhaust gas from the turbine is sent to the HRSG, which

extracts heat from this gas to superheat the 1600-psia high-pressure (HP) steam from the syngas

cooler and to generate additional steam. The superheated steam, two thirds of which has been

generated in the syngas cooler, is directed to the throttle of the 1953 Westinghouse steam turbine.

The steam-turbine system is composed of HP, intermediate-pressure (IP), and low-pressure (LP)

power turbines and a generator. The IP steam from the HP turbine is reheated before being sent

to the IP turbine. Steam from the LP turbine exhausts to the surface condenser.

Demonstration tests were conducted feeding bituminous coal from the No. 6 Seam at Peabody’s

Hawthorn Mine and other local mines and sponge coke from delayed cokers at two different

refineries. Despite a successful startup, numerous operating problems impacted plant

performance during the first year, resulting in only a 22-percent availability factor. Frequent

failure of the ceramic filter elements accounted for nearly 40 percent of the downtime in the first

year. A high chloride content in the syngas contributed to exchanger-tube failures in the lowtemperature heat-recovery area, COS-hydrolysis-unit catalyst degradation, and mechanical failure
7

of the syngas recycle compressor in the first year, as well. Significant downtime was also

required to remove ash deposits in the downstream pipe spool of the gasifier, and the hightemperature heat-recovery unit. The slurry mixers experienced several failures, and the power

block contributed appreciable downtime.

The air-separation unit never met the full performance guarantees for simultaneous delivery of all

product streams. Oxygen production from the unit was sufficient to meet gasifier demands, but

nitrogen production did not meet the guarantees. Intermittent shutdowns of the main air

compressor halted the gasification process several times during initial operations. A number of

plant improvements were implemented to increase the availability of the air-separation unit.

Initially, the rod mill did not produce a fine enough grind, but this was corrected by adjusting the

rod loading in the mill. Also, a number of areas of localized erosion and corrosion were

identified throughout the slurry handling system. Where possible, hardened metal internal

coatings were applied, while in some cases, metallurgy had to be changed to improve equipment

life.

Natural-gas firing was used to heat the gasifier during startup and to keep it hot when problems

occurred. Natural gas was not used to fire the gas turbine. During the period from 1996 through

1998, there was a continual improvement in operations, so that in 1998 only about 15 percent of

total gasifier operating time was on natural gas. Problems associated with early gasifier

operations included ash deposition in various locations and degradation of the brick lining. These

problems were largely overcome by piping and operations changes and by using a different

refractory brick to line the gasifier. Another problem area was the slurry mixers. Operational

changes and installation of redesigned mixers improved this situation. Problems were also

encountered with taphole plugging, which can occur when a coal whose ash viscosity varies is

gasified without appropriate operating-temperature adjustments.

The particulate removal system was initially a significant source of problems, but a considerable

increase in performance occurred when the ceramic filter elements were replaced with metallic

elements. Design improvements to provide better flow distribution through the filter vessels were

also helpful.

Syngas humidification was performed prior to the combustion turbine to control combustion

temperature, reduce nitrogen oxides (NOX) formation, and improve efficiency. This system

operated efficiently and provided consistent product gas moisture content of approximately 20 to

23 percent throughout the demonstration period. Syngas composition remained relatively

constant, although coal composition varied. The acid-gas-removal system operated well for most

of the demonstration period, with removal efficiency generally holding above 98 percent.

During the demonstration period, the power block produced 4,125 GWh of electric power. In

general, the power block operated well until the first quarter of 1999, when the compressor

failed. This failure was unrelated to gasifier operations. The unit was replaced by a new

compressor from General Electric, which has operated successfully since its installation.
8

Tests were conducted with petroleum coke to demonstrate the flexibility of IGCC technology.

Petroleum coke has a low ash content and a high heating value, and its low fuel price can be used

to offset the higher capital cost of an IGCC unit. The plant switched from coal to 100-percent

as-received petroleum coke from November 17 through November 27, 1997, without interrupting

operations. Slag from an earlier coal test, with known ash flow characteristics, was added to the

coke as a fluxing agent. Trace metals in the petroleum coke, mainly vanadium and nickel, were

encapsulated in an inert slag that was non-leachable and safe for disposal or by-product use.

Steady operation at full load was achieved with 100-percent petroleum coke, while meeting all

environmental emissions criteria. Operation was maintained at approximately 90 percent of

gasifier capacity for most of the test to match the combustion-turbine fuel requirement. Plant

efficiency at 40.2 percent (high heating value (HHV)) was slightly improved compared to coal

operation. The composition of the cleaned syngas produced from coke was very similar to that

produced with bituminous coal. The overall conclusion from the petroleum coke test is that

operations with petroleum coke are not significantly different from operations with coal and that

the equipment and systems at Wabash River are adequate for this operation without modification.

Sulfur dioxide (SO2) emissions and NOX emissions were well below Clean Air Act requirements.

Plant by-products were pure sulfur and non-hazardous slag, both with active commercial

markets. Some environmental problems were encountered with water quality caused by the

condensation of arsenic, selenium, and cyanide from the syngas vapor into the process

wastewater. Investigations are underway to mitigate this problem by identifying the most

cost-effective, currently available technologies. Despite problems during the first 2 years of

operation, plant performance compared favorably with the design values.

Two potential markets exist for the E-GasTM Technology: new gasification projects and retrofits

of existing conventional coal-fired power-generating stations striving to meet tightening

environmental standards. By 2004, projected world gasification projects should amount to

30 GW, of which approximately 54 percent will be based on coal or petroleum coke. The EGasTM Technology, because of its successful demonstration in this project, could capture a

significant fraction of this market. The estimated capital cost (in year 2000 dollars) of a 262-

MWe power plant, based on E-GasTM Technology and built on a Greenfield site, is $1,275/kW

for a coal-fired unit and $1,150/kW for a petroleum coke-fired unit. These costs include the

gasifier, pollution control, ASU, and power block. The higher heating value and lower ash

content of petroleum coke results in lower capital costs with this fuel. Based on a heat rate of

8,250 Btu/kWh (HHV), the levelized cost of power is estimated to be 42.0 mills/kWh (constant

dollars) with coal and 29.3 mills/kWh with petroleum coke.

The WRCGR Project demonstrated the successful operation of the E-GasTM Technology at

commercial scale. For extended periods, the syngas produced was burned in a combustion

turbine to produce electric power. When integrated with well-designed auxiliary units, the EGasTM Gasifier emits very low levels of NOX, SO2, and particulates, and produces high-purity

elemental sulfur for sale as well as an inert vitreous slag for sale or disposal in a regular landfill.

Production of elemental sulfur eliminates the problem of disposing of large quantities of scrubber

sludge.
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The E-GasTM Gasifier operated successfully feeding both bituminous coal and petroleum coke,

thus demonstrating its ability to handle a wide range of feeds. The potential exists to use a variety

of opportunity fuels, such as municipal solid waste (MSW), refuse derived fuel (RDF), sewage

sludge, waste tires, etc., either alone or, more probably, cofired with coal. All the technical

objectives were achieved.

The success of this CCT project should not only advance the commercialization of the E-GasTM

Technology, but also increase acceptance of IGCC systems in general. Future replication of the

E-GasTM Gasifier will furnish the marketplace with an efficient and environmentally benign

technology capable of meeting today’s strict environmental standards.
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I Introduction

The goal of the U.S. Department of Energy (DOE) Clean Coal Technology Program (CCT) is to

furnish the energy marketplace with a number of advanced, more efficient, and environmentally

responsible coal utilization technologies through demonstration projects. These projects seek to

establish the commercial feasibility of the most promising advanced coal technologies that have

developed beyond the proof-of-concept stage.

This document serves as a DOE post-project assessment (PPA) of a project selected in CCT

Round IV, the Wabash River Coal Gasification Repowering (WRCGR) Project, as described in a

Report to Congress (U.S. Department of Energy 1992). Repowering consists of replacing an

existing coal-fired boiler with one or more clean coal technologies to achieve significantly

improved environmental performance. The desire to demonstrate utility repowering with a twostage, pressurized, oxygen-blown, entrained-flow, integrated gasification combined-cycle (IGCC)

system prompted Destec Energy, Inc., and PSI Energy, Inc., to form a joint venture and submit a

proposal for this project. In July 1992, the Wabash River Coal Gasification Repowering Project

Joint Venture (WRCGRPJV, the Participant) entered into a cooperative agreement with DOE to

conduct this project. The project was sited at PSI Energy’s Wabash River Generating Station,

located in West Terre Haute, Indiana. The purpose of this CCT project was to demonstrate IGCC

repowering using a Destec gasifier and to assess long-term reliability, availability, and

maintainability of the system at a fully commercial scale. DOE provided 50 percent of the total

project funding (for capital and operating costs during the demonstration period) of $438 million.

Construction for the demonstration project was started in July 1993. Pre-operational tests were

initiated in August 1995, and construction was completed in November 1995. Commercial

operation began in November 1995, and the demonstration period was completed in December

1999. The independent evaluation contained herein is based primarily on information provided in

Wabash’s Final Report (Dowd 2000), as well as other references and bibliographic sources.

Destec was acquired by NGC Corp. in 1997. NGC changed its name to Dynegy in 1998. In

December 1999, Global Energy, Inc. purchased Dynegy’s gasification assets, including the

Wabash River Syngas Facility and the Destec gasification technology, and renamed the process

the E-GasTM Technology. To be consistent with the current status, the gasifier will be referred to

as the E-GasTM Gasifier throughout the rest of this PPA.
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II Project/Process Description

II.A Project Description

The Wabash River Station consists of six units that had a total nameplate generating capacity of

973 MWe before the CCT repowering project on Unit 1, the oldest of the units. The E-GasTM

Technology Gasifier is integrated with a new 192-MWe General Electric MS-7001F (Frame

7FA) single-shaft combustion turbine and a heat-recovery steam generator (HRSG) for

repowering a Westinghouse steam-turbine generator (first operated in 1953 with a nominal rating

of 99 MWe). A process flow diagram of the WRCGR Project is shown in Figure 1. The

repowered Unit 1 has a generating capacity of 262 MWe (net).

The new and existing coal handling facilities, interconnections, and other auxiliaries that make

up the Wabash IGCC repowering project (Figure 2) include:

Coal handling and feed system (coal receiving, stockpiling, and slurry preparation).

Air-separation unit (ASU).

E-GasTM oxygen-blown, entrained-flow, two-stage gasifier, capable of operating on a variety

of feedstocks, including high-sulfur bituminous coal and petroleum coke.

Syngas cleanup system to remove particulates, ammonia, chlorides, and sulfur compounds.

Sulfur-recovery unit (SRU), which produces high-purity elemental sulfur.

Combustion turbine/generator system that burns the syngas and generates electric power.

HRSG that recovers heat from the combustion turbine exhaust and generates steam that is

then sent to a steam turbine/generator.

The WRCGR Project is designed to use a range of local coals with a maximum sulfur content of

5.9 percent (dry basis) and a higher heating value of 13,500 Btu/lb (moisture- and ash-free). The

coal selected for initial operation was a high-sulfur Midwestern bituminous from the No. 6 seam

at Peabody’s Hawthorn Mine in Indiana. Coal for the project is stored apart from the compliance

coal burned in the other units. Alternative feedstocks, including petroleum coke and blends of

coal and coke, were tested during the demonstration period.

In addition to the original JV members, Sargent & Lundy provided engineering services to PSI,

and Dow Engineering & Construction Services (DE&CS) provided engineering services to

Destec.
12

Figure 1. Process Flow Diagram of WRCGR Project
13

Air

Separation

Unit

E-GASTM Gasifier

Syngas Cooler

Particulate/Char

Removal

Low Temperature Heat RecoveryChloride and Ammonia Removal

Moisturization

Rod Mill

Coal

Stockpile

& Reclaim

Coal

Receiving

H2 S Removal

Sulfur

Recovery

Heat Recovery

Steam Generator

Combustion Turbine

Generator

Existing

New Facilities

In-Plant

Use

33

MW

Net

Power

262

MW

192

MW

Coal Coal

Coal

Slurry

Air Nitrogen

Oxygen

Water

Treatment

Sour

Water

Water

Purge

LiquidSulfur

FlueGas

Treated

Water

Recycle

Slag

Fines Slag

Syngas

Steam

Turbine/Generator

High Pressure Saturated Steam

Syngas

Figure 2. Block-Flow Diagram of the WRCGR Project
14

II.B Need for the Technology Demonstration

One of the objectives of the CCT Program is to advance the commercialization of coalgasification technology. The electric-utility industry has been reluctant to utilize coal gasifiers,

because these units are significantly different from the kinds of plants this industry typically

operates. IGCC systems offer the possibility of improved efficiency and reduced emissions from

coal-based power production; however, at the time of the solicitation in 1991, these systems were

perceived as complex, capital intensive, high-risk installations. In order for this new technology

to penetrate the marketplace, it would have to be successfully demonstrated at a commercial, or

near-commercial scale. Thus, the demonstration provided by this CCT project is critical to the

further commercialization of the E-GasTM Technology and the acceptance of IGCC technology in

general.

II.C Promise of the Technology

The promise of this technology is to provide a technique for power production that has greater

than 40-percent efficiency, fuel-flexibility, and very low pollutant emissions. Gasification of the

fuel before combustion permits the use of combined-cycle power generation with its inherently

higher efficiency. Furthermore, the gasifier can accept many different materials as feedstock,

including coal, low-value materials like petroleum coke, or materials that may have a negative

value, like sewage sludge.

Finally, the technology inherently has low emissions compared to pulverized coal (PC)-fired

plants. During the gasification process, sulfur in the feed is converted to hydrogen sulfide (H2S),

and nitrogen in the feed is converted to ammonia (NH3). Both substances are easily scrubbed

from the product syngas. The H2S is converted to high-purity elemental sulfur, a bulk commodity

that is readily marketable. Because all the nitrogen in the fuel is converted to NH3, which is

removed before the syngas is burned, no fuel nitrogen oxides (NOX) are produced (fuel NOX is a

major source of NOX emissions from PC-fired boilers); and, by controlling the temperature in the

combustion turbine, thermal NOX is reduced.

II.D Technology Description

II.D.1 Coal Handling

Coal, with a 2-in. maximum top size, is delivered by rail and placed in a storage pile. The coal is

transferred from the storage pile to a conveyor. The coal goes to a hopper that empties onto a

weigh belt feeder, which feeds a rod mill. In the rod mill, the coal is mixed with treated water

and slag fines recycled from the gasifier. A fluxing agent is sometimes added at the coal mine

before shipment to adjust the fusion temperature of the coal ash. Slurry from the rod mill is

stored in an agitated tank, with sufficient capacity to maintain gasifier operation during routine
15

maintenance of the weigh belt feeder and rod mill. First- and second-stage gasifier feed pumps

supply slurry to the gasifier.

II.D.2 Air-Separation Unit

The ASU provides the oxygen required by the gasifier. The ASU consists of a three-stage

centrifugal air compressor (including interstage coolers), an air chiller, a pressure-swing

adsorption system, air-separation cold box, a three-stage, radial turbo oxygen compressor, and a

nitrogen handling and storage system. Compressed air is cooled to approximately 40 °F and sent

to molecular sieve adsorbers that remove moisture, carbon dioxide (CO2), and contaminants. The

dry, CO2-free air is sent to the cryogenic distillation system (cold box) to separate the liquid air

into its component elements and concentrate the oxygen. The resulting oxygen with 95-percent

purity is compressed and fed to the gasifier. A small portion of the nitrogen produced by the ASU

is high purity (99.9 percent) and is used for purging and inert blanketing. The rest of the nitrogen,

containing 1- to 2-percent oxygen, is used for air chilling and then vented to the atmosphere.

II.D.3 E-GasTM Gasifier

The design of the project gasifier was based on Destec’s Louisiana Gasification Technology, Inc.,

(LGTI) gasifier, which was similar in size and operating characteristics. The LGTI gasifier was

operated for more than 34,000 hours from April 1987 through November 1995. Experience

gained in that project provided significant input to the design of the Wabash River coal

gasification facility and eliminated much of the risk associated with scale-up.

Figure 3 is a simplified block flow diagram of the entire gasification area. The E-GasTM Gasifier

(Figure 4) consists of two stages: a slagging first stage; and an entrained-flow, non-slagging

second stage. The first stage is a horizontal, refractory-lined vessel in which carbonaceous fuel is

partially combusted with oxygen at an elevated temperature and pressure (2600 °F, 400 psia).

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16

The gasifier is initially heated with natural gas and then switched to coal slurry. Oxygen and

preheated slurry are fed to two opposed, proprietary-design mixing nozzles, one on each end of

the horizontal section of the gasifier. The oxygen feed rate is controlled to maintain the

gasification temperature above the ash fusion point. Under gasifier conditions, the feed is almost

completely converted to a gas consisting primarily of hydrogen (H2), carbon monoxide (CO),

carbon dioxide (CO2), and water (H2O).

Figure 4. Schematic of E-GasTM Entrained-Flow Gasifier
17

Coal-ash and any added flux form a molten slag that flows continuously through a tap hole in the

floor of the horizontal section into a quench water bath. The solidified slag that exits from the

bottom of the quench section is crushed and flows through a continuous removal system as a

slag/water slurry (Figure 5). The slurry flows to a dewatering bin, where the bulk of the slag

settles out, while the overflow goes to a settler for removal of the remaining fines. The clarified

water is cooled and returned to the gasifier quench section. To improve carbon utilization, the

slurry of fine particles from the bottom of the settler is recycled to the slurry preparation area.

The dewatered slag is loaded onto trucks or rail cars for sale or disposal.

OXYGEN

RECYCLED

TAIL GAS

GASIFIER

FROM

SULFUR

RECOVERY

HEATER

COAL

SLURRY

SLAG

CRUSHER

PUMP

SLAG

DEWATERING

HOT RAW

SYNGAS

TO

SYNGAS

COOLING

FROM

PARTICULATE

REMOVAL

CHAR

SLAG

PRODUCT

TO STORAGE

OR MARKET

PRESSURE LETDOWN

COOLER

Figure 5. Gasification Slag Handling

Raw syngas from the first stage of the gasifier flows up into a vertical, refractory-lined,

second-stage vessel, where additional slurry, but no additional oxygen, is injected. The injected

fuel undergoes devolatilization and pyrolysis that both cools the syngas (because these reactions

are endothermic) and increases its heating value (because of the nature of the products produced).

In addition, water reacts with some of the carbon to produce CO and H2. Unreacted char is

carried overhead with the syngas that leaves the gasifier at 1,900 °F.

II.D.4 Syngas Conditioning/Cleanup

The hot syngas exiting the gasifier is cooled from a nominal 1,900 °F to approximately 700 °F in

the syngas cooler, a vertical firetube heat-recovery boiler system with the hot syngas on the tube

side. The syngas cooler generates 1,600 psia steam (compared to 600 psia steam generation in

Destec’s LGTI facility). The cooled syngas is sent to the particulate-removal system containing a

large number of porous candle filter elements that remove more than 99.9 percent of the

particulates. The filter elements are periodically back-pulsed with high-pressure syngas to
18

remove built-up cake. Char cake dislodged from the filter elements falls to the bottom of the

vessel and is pneumatically transferred to the first stage of the gasifier by high-pressure syngas.

The particulate free syngas is further cooled and then water scrubbed with sour water (i.e.,

sulfur-containing water condensed from the syngas) to remove chlorides and volatile trace

metals. The scrubbed syngas goes to the COS hydrolysis unit, where COS is converted to H2S.

The syngas is then cooled to 100 °F before being sent to the acid-gas removal (AGR) system.

During cooling, water condenses and dissolves most of the NH3, along with some CO2 and H2S.

This water is sent to the sour-water treatment unit.

The AGR system (Figure 6) contacts the sour syngas with methyldiethanolamine (MDEA) in an

absorption column to remove most of the H2S and some of the CO2. The essentially sulfur-free

syngas is moisturized and then superheated and sent to the combustion turbine. The MDEA is

regenerated in an H2S stripper column, with the concentrated H2S stream being sent to the SRU.

›——‘¤‹ Õ—ÀŒ

Õ«“ŸflÕ

ÿ ÕÓ

flfiÕ—Œfi¤Œ

ÿ ÕÓ

ÕÃŒ×––¤Œ

‘—... Ã¤”–¤ŒflÃÀŒ¤

ÿ¤flÃ Œ¤›— ¤Œ«

›——‘¤Œ

Õ...¤¤Ã Õ«“ŸflÕ

fl›×‹ ŸflÕ

Õ«“ŸflÕ

”—×ÕÃÀŒ×ÆflÃ×—“

ÕÀ‘⁄ÀŒ

Œ¤›— ¤Œ«

Õ—ÀŒ ...flÃ¤Œ

ÃŒ¤flÃ”¤“Ã

›—Ó

‘¤fl“ fl”×“¤

Œ×›ÿ fl”×“¤

fl”×“¤ ›Œ—ÕÕ

¤»›ÿfl“Ÿ¤Œ

Figure 6. Acid-Gas Removal

In the SRU (Figure 7), the acid gas from the stripper and the H2S/CO2 stripped from the sour

water are mixed with oxygen and fed to a furnace where one third of the H2S is oxidized to SO2.

A waste-heat boiler recovers heat before a condenser cools the gas to recover the first increment

of sulfur. Offgas from the condenser passes through a series of heaters, catalytic reactors, and

sulfur condensers, which produce 99.999-percent pure sulfur for sale. Offgas from the SRU,

consisting mainly of nitrogen (N2), CO2, and H2O, with traces of sulfur compounds, is

catalytically hydrogenated to convert all the sulfur species to H2S. The gas, cooled to condense

most of the water, is then recycled to the E-GasTM Gasifier. This processing scheme allows

greater than 98- percent sulfur recovery overall.
19

Dissolved gases are stripped from the sour water in a two-step process (Figure 8). First, CO2 and

most of the H2S are removed in a steam stripper. The offgas from the steam stripper is sent to the

SRU. The water from the bottom of the steam stripper is split into two streams. Most of the water

is recycled to slurry preparation with any water not needed for slurry preparation being sent to an

ammonia stripper. The stripped ammonia is dissolved in the water being sent to slurry

preparation, and the treated water is stored for reuse or discharge. Reuse of water within the plant

minimizes water consumption and discharge of pollutants.

×“ –‘fl“Ã

ÀÕ¤

ÕÃ¤fl”

›—“‹¤“Õ¤Œ

...flÕÃ¤

ÿ¤flÃ

Œ¤›— ¤Œ«

—»«Ÿ¤“

›ÿÏ —Œ

Õ«“ŸflÕ

fl›×‹

ŸflÕ

—»«Ÿ¤“

ÕÀ––‘«

fl›×‹ ŸflÕ

Œ¤”— fl‘

›—“‹¤“ÕflÃ¤ ›—”fi×“¤‹

›«›‘¤

ÿ¤flÃ¤Œ

›flÃ«‘«ÕÃ

fi¤‹

ŸflÕ×⁄×›flÃ×—“ Œ¤›«›‘¤‹

Ãfl×‘ŸflÕ

›—”–Œ¤ÕÕ—Œ

ÕÀ‘⁄ÀŒ

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›‘flÀÕ –Œ—›¤ÕÕ

ÕÀ‘⁄ÀŒ

Ãfl“’ ›flŒ

Œ¤fl›Ã×—“

⁄ÀŒ“fl›¤

Figure 7. Sulfur-Recovery Unit

fl›×‹ ŸflÕ

Œ¤”— fl‘

‘—... Ã¤”–¤ŒflÃÀŒ¤

ÿ¤flÃ Œ¤›— ¤Œ«

Õ—ÀŒ

...flÃ¤Œ

›—Ó

›—Ó

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fl””—“×fl flfiÕ—Œfi¤Œ

fl””—“×fl

 fl–—Œ

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“ÿÌ

Õ‘ÀŒŒ«

...flÃ¤Œ

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–Œ¤–flŒflÃ×—“

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Ãfl“’Õ

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...flÃ¤Œ ‹×Õ›ÿflŒŸ¤

Figure 8. Sour-Water Treatment Unit
20

II.D.5 Power Block

Preheated, moisturized syngas and compressed air are supplied to the combustor of the

combustion turbine. The hot gas leaving the combustor flows to the turbine, which drives a

generator and air compressor. Hot exhaust gas from the turbine is sent to the HRSG. The HRSG

superheats the 1,600-psia HP steam produced by the gasifier, reheats the IP steam, and generates

HP steam, as shown in Figure 9. About two-thirds of the steam-turbine throttle steam is actually

generated in the gasification-facility syngas cooler.

The steam-turbine system is composed of HP, IP, and low-pressure (LP) power turbines and a

generator. The IP steam from the HP turbine is reheated before being sent to the IP turbine.

Steam from the LP turbine exhausts to the surface condenser. Process heat from the gasifier is

used to preheat the condensate from the steam turbine condenser before it is returned to the

HRSG.

COMBUSTION

TURBINE

AIR

FROM

SYNGAS

MOISTURIZATION

HOT PRODUCT

SYNGAS

EXHAUST

GAS

TO

STACK

WARM

CONDENSATE FROM

LOW TEMPERATURE

HEAT RECOVERY

HEAT RECOVERY

STEAM GENERATOR

CONDENSER

COLD

CONDENSATE

TO

LOW TEMPERATURE

HEAT RECOVERY

THREE STAGE

STEAM TURBINE

BOILER

FEED WATER

TO

SYNGAS

COOLING

FEEDWATER

RETURN

SUPERHEATED

HPSTEAM

SATURATED

HP STEAM

FROM

SYNGAS

COOLING

Figure 9. Power Block

II.E Project Implementation

Destec acted as the general contractor for the gasifier and related facilities. PSI acted as general

contractor for the power block. Detailed design engineering and procurement was subcontracted

to DE&CS for the gasifier and to Sargent & Lundy for the power block. The ASU was

subcontracted to Liquid Air Engineering Corporation (Air Liquide) as a turnkey contract. Capital

costs (1994 dollars) for the project are given in Table 1.
21

Table 1. Capital Costs for the WRCGR Project

Cost Element $ Million

Syngas Facility

Engineering and Project Management 27.3

Equipment Procurement 84.5

Construction 106.1

Construction Management 8.1

ASU 32.8

Preoperations Management 21.7

Power Block 136.1

Total 416.6

These costs include conceptual, process, and detailed engineering; environmental permitting;

equipment procurement; project management; construction management; construction and

start-up; and hiring and training operating personnel. Not included are fuel supply, interest paid

during construction, financing fees, and license fees. Based on a design capacity of 262 MWe

(net), installed cost was $1,590/kW. The project was designed to achieve very low SOX

emissions; this added approximately $100/kW to the capital cost. Other factors that increased

costs were inclement weather, equipment delivery problems, subcontract problems, and start-up

problems. An additional $14 million was spent during the first 2 years of operation to improve

plant performance.The project included a spare gasifier so that operations could continue during

the periodic rebricking of one of the gasifier vessels.

II.F Project Objective and Statement of Work

The major project objective was to demonstrate utility repowering with a two-stage, pressurized,

oxygen-blown, entrained-flow IGCC system, including advancements in the technology relevant

to the use of high-sulfur bituminous coal, and to assess long-term reliability, availability, and

maintainability at a commercial scale. Another goal was to evaluate the performance of all major

process components, including the coal slurry feed system, the gasifier, the gas cleanup system,

the modified combustion turbine utilizing medium-Btu gas, and the repowered steam turbine.

The Cooperative Agreement puts this in slightly different words, stating that the objective of this

project was “to demonstrate an advanced coal gasification combined-cycle (CGCC) system based

on Destec Energy, Inc.’s two-stage entrained flow gasification technology. The CGCC system

will utilize high-sulfur bituminous coal, not to exceed 5.9 percent sulfur (dry basis), to produce

high efficiency, cost competitive, and environmentally compliant electric power. The CGCC
22

system will also provide data on the performance of all major subsystems, including coal slurry

feed system, oxygen-blown two-stage entrained-flow coal gasifier, coal gas cleanup system,

modifications to an advanced combustion turbine to utilize medium-Btu coal gas as fuel, and the

repowered steam turbine to provide a combined-cycle system.” The project had the following

specific technology demonstration goals:

Use integrated coal gasification combined-cycle technology to repower a 1950s-vintage coalfired power-generating unit.

Achieve high energy efficiency and superior environmental performance while using highsulfur bituminous coal.

Operate an IGCC facility in a utility electrical grid.

Apply hot/dry-particulate removal at full commercial scale.

Use syngas recycle to provide fuel and process flexibility, while maintaining high efficiency.

Demonstrate high-pressure cooling of hot, raw syngas by producing 1,600 psia steam.

Use a dedicated oxygen plant producing 95-percent oxygen to increase overall project

efficiency by decreasing the power required for production of oxygen.

Integrate the gasification facility with a heat-recovery steam generator to optimize both

efficiency and operating costs.

Apply a carbonyl-sulfide hydrolysis system to achieve high sulfur removal.

Demonstrate operation of the slag-fines recycle system, which enhances carbon conversion

and results in higher quality by-product slag by recycling the slag by-product stream to the

gasifier.

Demonstrate fuel-gas moisturization, which uses low-level heat to reduce steam injection

required for NOX control.

Demonstrate sour-water treatment and tail-gas recycling to increase efficiency and reduce

waste water and emissions.

Utilize an advanced gas turbine design to allow for the combustion of syngas and higher

firing temperature configurations.

Utilize saturated steam from the gasification-facility HRU to operate a steam turbine.

Repower the existing steam turbine by upgrading the unit to accept increased steam flows

generated by the HRSG.
23

The Statement of Work (SOW) is broken down into three phases: Phase I—Design and

Permitting; Phase II—Construction, Installation, and Startup; and Phase III—Operation, Data

Collection, Evaluation, and Disposition. This PPA is primarily concerned with Phase III and does

not deal with the other phases in any detail. Phase III included operation and demonstration of the

installed system. The main area of interest was to assess the performance of the E-GasTM

Gasifier, but other systems, such as gas cleanup, heat recovery, and power generation were also

critical to the success of the project.

The SOW stated that the Participant was responsible for the operation, modification,

maintenance, data collection, and evaluation of the plant. In addition, performance and

environmental data that establish the operational characteristics of the overall plant and major

subsystems were to be collected and provided to DOE. The Participant was also responsible for

providing all required reports.

The SOW specifies a 3-year demonstration period “during which Participant will implement

plans and programs to operate, maintain, monitor, evaluate, and improve both the subject

technology and the plans and programs themselves.” Key demonstration-period goals were to

Incorporate the E-GasTM Gasifier-based IGCC power plant into the PSI system as a reliable

and effective element of its baseload-generation capability.

Demonstrate the operability, effectiveness, and economic viability of this technology on a

commercial scale and in a commercial utility environment.

Optimize the effectiveness of the overall system and to otherwise advance the technology.

Obtain the data base and experience base necessary to meet and advance the commercial

markets for this technology.

The SOW summarized the following ten areas: (1) Specification for Acceptance Testing;

(2) Gasification Facility Operating Discipline Program; (3) Power Block Operating Discipline

Program; (4) Gasification Facility Maintenance Plan and Program; (5) Power Block Maintenance

Plan and Program; (6) Data Acquisition System; (7) Program Regarding Operating

Characteristics; (8) Environmental Monitoring Plan; (9) Plan to Test Alternative Feedstocks; and

(10) Plan for DOE Communications. The SOW did not specifically define any set of conditions

under which the gasification plant would operate; it merely stated that the date for

commencement of commercial operations would occur after the plant had operated for

100 consecutive hours at 80 percent of the production rate specified in the Gasification Services

Agreement (GSA). There was also a requirement that the gasifier operate for 100 consecutive

hours at 100 percent of the GSA specified production rate.

The SOW also set the Demonstration Coal as bituminous coal from the No. 6 Seam at Peabody’s

Hawthorn Mine. However, the Participant had the option to substitute an alternative feedstock

for a maximum of 60 days, once per year during the 3-year demonstration period. The choice of

the alternative feedstock was not specified, but was left up to the Participant
24

III Technical And Environmental Review

III.A Technical Results

Within a short time after startup, both the gasification and combined-cycle plants successfully ran

at capacity and within environmental parameters. However, numerous operating problems

impacted plant performance the first year, resulting in an availability of only 22 percent. Frequent

failure of the ceramic filter elements accounted for nearly 40 percent of the downtime. Another

problem was the high chloride content in the syngas; this contributed to exchanger tube failures

in the low-temperature heat-recovery area, COS hydrolysis catalyst degradation, and mechanical

failure of the syngas recycle compressor. Significant downtime was required to remove ash

deposits that created high system pressure drops in the gasifier downstream pipe spool and the

high temperature heat-recovery unit (HTHRU). The slurry mixers experienced several failures,

and the power block also contributed appreciable downtime.

The foregoing problems were either eliminated or significantly reduced by the end of the second

operating year. In 1997, the facility availability was 44 percent, and by 1998 the availability had

improved to 60 percent. During the third year of the demonstration period, a second Illinois No. 6

coal was fed to the facility, as well as a blend of the two coals.

Despite reliability issues during the first 2 years of operation, the actual performance of the plant,

while feeding coal compared, favorably with design, as shown in Table 2.

Table 2. Performance Summary

Performance Criterion Design Actual

Syngas Capacity, Mbtu/h 1,780 1,690 (1,825 max)

Combustion Turbine Capacity, MW 192 192

Steam Turbine Capacity, MW 105 96

Auxiliary Power, MW 35.4 36

Net Power, MW 262 252

Plant Heat Rate, Btu/kWh 9,030 8,900

Syngas Heating Value, Btu/SCF (HHV) 280 275-280

Syngas Sulfur Content, ppmv <100 <100

Sulfur Removal Efficiency, % >98 >99

SO2 Emissions, lb/MBtu <0.2 <0.1 (0.03)
25

The plant demonstrated a maximum production capacity of 1,825 million Btu per hour (MBtu/h),

but the combustion turbine only required 1,690 Mbtu/h (approximately 1.2 trillion Btu/month) or

less, depending on ambient temperature, at full load. As shown in Table 2, the power output of

the steam turbine fell short of the design value. This was caused by a reduction in throttle steam

to the steam turbine, made necessary by increased steam consumption in the deaerator (the result

of an error in the design of the feedwater heater). Modifications to the HRSG feedwater heater

will be required to increase steam production and bring steam turbine output up to design. With

this modification, the overall plant heat rate will drop to 8,650 Btu/kWh. The ASU did not meet

the guaranteed power requirement specification, which accounts for the somewhat higher than

design auxiliary power requirement.

The greatest monthly output achieved during the demonstration period was achieved in

September 1999, when 1,204,573 MBtu of gas were produced. Several other months came close

to this level, with over 1 trillion Btu of gas being produced during March, April, October, and

November 1998. During the third quarter of 1999, 2,712,107 MBtu were produced. Key

production statistics for the demonstration period are presented in Table 3.

Table 3. WRCGR Project Production Statistics

Time

Period

Time

on Coal,

hours

Coal

Processed,

tons

Gas

Produced,

MBtu

Steam

Produced,

103lb

Power

Produced,

MWh

Sulfur

Produced,

tons

1995 505 ~41,000 230,784 171,613 ~71,000 559

1996 1,902 184,382 2,769,685 820,624 449,919 3,299

1997 3,885 392,822 6,232,545 1,720,229 1,086,877 8,521

1998 5,279 561,495 8,844,902 2,190,393 1,513,629 12,452

1999* 3,496 369,862 5,813,151 1,480,908 1,003,853 8,557

Overall 15,067 1,549,561 23,891,067 6,383,767 4,125,278 33,388

* Combustion turbine unavailable from March 14, 1999 through June 22, 1999. Production in

1999 would have been the same as in 1998, if the combustion turbine had not been out of service

for 3 months. Performance of various parts of the system are discussed in the following sections.

III.A.1 Air-Separation Unit

Although oxygen production is a well proven technology and the ASU should have achieved a

high level of performance and availability, a number of problems were encountered with this

unit. Early in 1996, the ASU was modified to provide additional nitrogen gas for equipment

purging and other uses. Although these modifications were successful in increasing nitrogen

production, the ASU never achieved the full performance guarantees for simultaneous delivery of

all product streams. Because of the frequent plant interruptions in the early years, the supply of

nitrogen was still inadequate and had to be supplemented by outside purchases, which increased

operating costs. Through a series of process improvements and operating changes, nitrogen usage
26

was significantly decreased from a 1997 high of 15 trucks per month (9x106ft3) down to two

trucks per month (1.2x106ft3).

Oxygen production during 1997 was sufficient to meet the demands of the gasifier. Total annual

production was approximately 328,000 tons of 95-percent purity oxygen. Since there is no

oxygen storage capability at the facility, a malfunction of the main air compressor caused a

shutdown of the gasification process caused by the inability to supply oxygen to the slurry

mixers. In 1998, oxygen production increased to over 442,000 tons. A number of plant

improvements were implemented to increase ASU availability.

III.A.2 Coal Handling

In separate tests, two different coals, plus a blend of the two, and petroleum coke were fed to the

gasifier during the demonstration period. The average properties of these fuels are shown in

Table 4.

Table 4. Fuel Properties

Fuel

Hawthorn

Coal

Miller

Creek

Coal

Hawthorn/

Miller

Creek Blend

Petroleum

Coke

Ultimate Analysis, wt% (dry)

Carbon 69.98 71.36 69.66 87.49

Hydrogen 4.65 4.69 4.85 2.74

Nitrogen 1.28 1.38 1.44 0.99

Oxygen 8.18 7.05 8.48 3.09

Sulfur 2.61 3.45 2.95 5.17

Ash 13.30 12.07 12.62 0.52

Water, wt% as received 14.60 16.50 15.30 7.00

Heating Value, Btu/lb (HHV)

As Received 10,730 10,765 10,645 14,282

Dry 12,567 12,890 12,566 15,353

The gasifier is capable of handling feedstocks with a relatively wide range of characteristics;

however, variations too far from the design-basis coal could reduce syngas and steam production.

Also, if undetected, sudden changes in feedstock composition can cause problems; therefore,

feedstock analyses were followed closely. When petroleum coke was gasified, coal slag was

added as a fluxing agent.

A rod mill is used, rather than a hammer mill, because in the E-GasTM Gasifier, the fuel is fed as

an aqueous slurry. Initially, the rod mill did not produce a fine enough grind, but this was

corrected by adjusting the rod loading in the mill. Also, a number of areas of localized erosion

and corrosion were identified throughout the slurry handling system. Where possible, hardened

metal internal coatings were applied, while in some cases metallurgy had to be changed to
27

improve equipment life. Another problem was foreign objects in the coal, which led to poor

performance of the rod mill, resulting in downstream problems. This situation was resolved by

improved quality control of the feed coal by the coal providers, and by the addition of magnetic

separators on the belt feeder to remove tramp iron.

III.A.3 Gasification

At startup, the gasifier and downstream equipment were heated by natural-gas burners. During

the transition to coal operation, both coal and natural gas were fed to the gasifier. Because of its

low pressure and low flow rate, syngas generated during heat-up operations was not suitable for

fueling the combustion turbine. Natural gas was also fired in the gasifier during standby

operations. Natural gas was not fired in the combustion turbine. The number of hours on natural

gas and on coal are shown in Table 5. Time on natural gas includes the total hours required to

heat the gasifier and associated equipment, the transition time to full coal operation, and hot

standby time. During the period from 1996 through 1998, there was a continual improvement in

operations.

Table 5. E-Gas Gasifier On-Stream Hours

Year 1996 1997 1998 1999

Time on Natural Gas, hours 1,990 1,490 976 933

Time on Coal, hours 1,902 3,885 5,278 3,496

Problems associated with gasifier operations included ash deposition in various locations and

erosion of the brick lining. These problems were largely overcome by piping and operating

procedure changes and by using a different refractory brick to line the gasifier. Problems with the

slurry mixers.were improved by operational changes and installation of redesigned mixers.

Problems were also encountered with taphole plugging, which can occur when a coal with

varying ash viscosity is gasified without adding appropriate operating-temperature adjustments.

III.A.4 Syngas Cooling and Particulate Removal

Ash deposition in the HTHRU and associated equipment was of great concern during early

operations. Thermal cycling in the hot-gas path was a leading cause of plugging which occurs

because of spalling (flaking off) of ash deposits in upstream equipment and piping. Solids

accumulation at the tubesheet caused tube plugging and high differential pressures. As plugging

of some tubes occurred, the velocity of the solids-laden gas through the remaining open tubes

became high enough to cause erosion. To help control ash deposition in the tubes of the HTHRU,

a boiler inlet screen was installed to prevent large particles from reaching the tubesheet.

Although fouling of the boiler tubes continued to be a concern that was not fully resolved, an

improved mechanical tube-cleaning procedure and modified operating conditions reduced the

problem to manageable proportions so that tube cleaning was required only every 6 months to a

year.
28

The particulate-removal system was initially a significant source of problems, but a considerable

increase in performance occurred when the ceramic filter elements were replaced with metallic

elements. Design improvements to provide better flow distribution through the filter vessels also

helped.

III.A.5 Chloride Scrubbing System and COS Hydrolysis

The efficiency of the COS-hydrolysis unit decreased during the first 2 years because of catalyst

poisoning by trace metals and chlorides and the loss of surface area caused by overheating. After

replacement with a catalyst that was more poison resistant and installation of a chloride

scrubbing system (CSS), the unit achieved a consistent COS concentration of 10 ppm in the gas

leaving the hydrolysis unit.

The CSS was installed to remove chlorides and other impurities from the syngas. Initially, some

problems were observed caused by ammonia accumulation in the CSS, where hot syngas was

scrubbed with sour water that absorbed both ammonia and chlorides. This resulted in sour water

being sent to the sour-water receiver and then recycled back to the CSS. To avoid operational

problems and provide an ammonia purge from the system, a blowdown stream was taken from

the sour-water tank and sent directly to the sour-water system.

III.A.6 Low-Temperature Heat Recovery and Syngas Humidification

The syngas is humidified prior to being sent to the combustion turbine to control combustion

temperature, reduce NOX formation, and improve efficiency. Syngas humidification operated

efficiently and provided consistent product gas moisture content of approximately 20 to 23

percent throughout the demonstration period. Product syngas quality remained high (above 250

Btu/scf), as shown in Table 6.

Table 6. Product Syngas Composition

Year 1996 1997 1998 1999

Concentration Low High Low High Low High Low High

Hydrogen, % 32.87 34.21 32.90 34.40 32.71 33.82 32.31 33.44

Carbon Dioxide, % 14.89 17.13 16.60 16.90 14.92 16.06 15.25 16.22

Carbon Monoxide, % 42.34 46.03 42.20 46.70 44.25 46.73 44.44 46.31

Methane, % 1.26 1.99 1.04 2.02 1.91 2.29 1.88 2.17

Hydrogen Sulfide, ppmv 17.28 83.36 43.08 106.50 23.48 107.2 86.32 106.0

Carbonyl Sulfide, ppmv 36.26 162.13 22.59 111.80 9.03 36.63 11.36 24.22

Heat of Combustion,

Btu/scf (HHV) 256 280 254 283 268 284 267 280
29

Syngas composition remained relatively constant during the demonstration period, even though

coal composition changed. As discussed above, once problems with the COS removal system

were resolved, COS levels remained low.

The low-temperature heat-recovery unit (LTHRU) initially had a problem with chloride stress

corrosion cracking of the stainless steel exchanger tubes, but replacement of the tubes with more

corrosion resistant materials and addition of the CSS essentially eliminated this problem.

III.A.7 Acid-Gas Removal, Sulfur Recovery, and Sour-Water Stripping

The AGR system operated well for most of the demonstration period, with removal efficiency

generally holding above 98 percent. The only significant drop in efficiency occurred during a

short period, when problems were encountered with the MDEA reclaim unit, which removes

heat-stable salts. A vacuum distillation to remove heat-stable salts was performed during the

fourth quarter of 1997. The distillation effectively restored the H2S-removal efficiency of the

amine solution. A number of process improvements were implemented during the demonstration

period, which improved the operation and reliability of the reclaim unit and overall AGR system.

After some initial modifications, the SRU performed well. Generally, over 95 percent of the

sulfur fed to the SRU was recovered as high-purity sulfur. The tail gas from the SRU was

recycled to the gasifier to enhance overall sulfur recovery. Based on the sulfur in the feed to the

gasifier, overall sulfur recovery was typically in the range of 97.5 to 98.5 percent.

Except for a few minor upsets, the sour-water stripping system operated very well. The volume

of treated water sent to disposal was typically about 10,000 gal/h.

III.A.8 Power Block

During the demonstration period, the power block produced a total of 4,125 GWh of electric

power. In general, the power block operated well until the first quarter of 1999, when the

compressor rotor failed. The compressor was replaced by a new upgrade unit from General

Electric, which has operated successfully since its installation.

III.A.9 Operations Feeding Petroleum Coke

Petroleum coke is a by-product of the refining industry. In the refinery, heavy materials that

cannot be distilled are frequently sent to a coking unit, where pyrolysis produces a light fraction

that can be incorporated into the refinery’s slate of standard products (gasoline, diesel, etc.). The

material left behind, referred to as petroleum coke, has a low hydrogen/carbon ratio and may be

high in sulfur, but it has a low ash content (Table 4). Petroleum coke typically has a low

economic value and is sometimes just piled up at the refinery. As the world’s crude oil supply

becomes heavier (i.e., contains a larger fraction of high boiling components), the production of

petroleum coke should increase, and it should become more attractive as a fuel.
30

Because of the flexibility of IGCC technology, petroleum coke is an opportunity fuel for these

systems. Petroleum coke’s low ash content and high heating value make it an attractive fuel, and

its low fuel price can be used to offset the higher capital cost of an IGCC unit. Other potential

opportunity fuels include coal fines, sewage sludge, MSW, RDF, waste tires, etc. Most of these

materials would be co-fired as a mixture with coal, or with coal being fired to the first stage and

the opportunity fuel being fired to the second stage.

A test period operating with petroleum coke was conducted as part of the WRCGR Project. The

purpose of this test was to utilize petroleum coke as the primary feed, while operating in a typical

power plant environment. Preparatory work included analysis of coke properties and ash

characteristics, bench-scale reactivity testing, determination of grinding and slurrying

characteristics, computer simulations of process and thermal performance, an industrial hygiene

review, and development of coke/flux blending equipment.

About 18,000 tons of sponge coke from a delayed coker were processed from November 17 to

November 27, 1997. The plant switched from coal to 100-percent, as-received, petroleum coke

without interrupting operations. The coke had a sulfur content of 5 percent, which is well within

the sulfur design limit of the Wabash River plant. Laboratory ash composition and ash fusion

analyses indicated that slag from petroleum coke would be difficult to remove at typical gasifier

operating temperatures. Therefore, prior to slurry preparation, slag from an earlier coal run, with

known ash flow characteristics, was added to the feed as a fluxing agent. In the gasifier, trace

metals in the petroleum coke, mainly vanadium and nickel, are encapsulated in the slag that is

inert, non-leachable, and safe for non-hazardous disposal or use. Properties of the coke compared

to a typical coal are shown in Table 7.

Table 7. Typical Fuel Analyses

Property Typical Coal Petroleum Coke

Proximate Analysis

Moisture, % 15.2 7.0

Ash, % 12.0 0.3

Volatiles, % 32.9 12.4

Fixed Carbon, % 39.9 80.3

Sulfur, % 1.9 5.2

Metals in Ash

NiO, % of ash Trace 11.8

V2O5, % of ash Trace 28.4

Heating Value, Btu/lb (as received) 10,536 14,282
31

Operations were generally steady during the period feeding petroleum coke, although the plant

shut down twice for brief periods, once because of a problem with the slurry feed pump and once

caused by a problem with the dry char particulate filtration system. Neither was related to the

change in feed. Operation at full load was achieved with 100-percent petroleum coke while

meeting all environmental emissions criteria. For most of the test, operation was maintained at

approximately 90 percent of gasifier capacity to match the combustion turbine fuel requirement,

which was somewhat lower than that guaranteed by the turbine manufacturer. Overall plant

efficiency at 40.2 percent (HHV) was slightly improved during petroleum coke operations (Table

8).

Table 8. Thermal Performance Summary for Operations With Petroleum Coke

Performance Criteria Design Coal Actual Coal Petroleum Coke

Nominal Throughput, ton/day 2550 2450 2000

Syngas Production, Mbtu/h 1780 1690 1690

Combustion Turbine, MWe 192 192 192

Steam Turbine, MWe 105 96 96

Auxiliary Power, MWe 35 36 36

Net Generation, MWe 262 252 252

Plant Efficiency, % (HHV) 37.8 39.7 40.2

Sulfur Removal Efficiency, % >98 >99 >99

No problems were encountered in grinding the petroleum coke. Slurry with a solids content of

approximately 66 percent and good flow characteristics for pumping was consistently produced.

Additional rods were added to the rod mill midway through the test to further reduce the particle

size of the slurry, but this had no significant effect on the solids content.

Laboratory tests prior to on-line operation indicated that the petroleum coke would be much less

reactive than coal. Initially, an average carbon conversion of about 97.5 percent was achieved

with petroleum coke; however, following the addition of the grinding rods, which reduced the

particle size, overall carbon conversion improved to over 99 percent.

Based on laboratory ash fusion and high-temperature slag viscosity tests, flux addition in the

range of 5 to 10 tons of slag per 100 tons of petroleum coke was targeted for the test; but near the

end of the test, to increase efficiency and reduce slag production, the flux ratio was reduced to

about 2 tons/100 tons. No slag-tapping problems were encountered during the test.

Composition of the cleaned syngas was very similar to that produced when feeding bituminous

coal, as shown in Table 9.
32

Table 9. Product Syngas Composition

Fuel Typical Coal Petroleum Coke

Nitrogen, vol % 1.9 1.9

Argon, vol % 0.6 0.6

Carbon Dioxide, vol % 15.8 15.4

Carbon Monoxide, vol % 45.3 48.6

Hydrogen, vol % 34.4 33.2

Methane, vol % 1.9 0.5*

Total Sulfur, ppmv 68 69

Heating Value, Btu/scf (HHV) 277 268

* Because of limited data on petroleum coke, this value needs further verification.

The ash from the petroleum coke contained about 12-percent NiO and 28-percent V2O5. Nickel

and vanadium are often of great concern in utility boiler operations. Vanadium-pentoxide has

been found to aggressively attack boiler tubes. Process samples from solid, liquid, and gas

streams were taken at various points in order to quantify trace metal contents. About 80 percent

of the nickel and 99 percent of the vanadium were captured in the silicate matrix of the slag and

rendered inactive in an inert, non-leaching solid, as confirmed by a Toxicity Characteristic

Leaching Procedure (TCLP) environmental leachate test. Some nickel was found in ash deposits.

Liquid and gas streams contained less than 1 ppm nickel and vanadium. Trace metals should not

be a problem when feeding petroleum coke.

The refractory wear rate, even at the elevated temperatures required for petroleum coke

operations, was similar to that observed when feeding coal. No adverse impact on the metallurgy

of the equipment was observed. Analysis of test coupons placed throughout the system indicated

that corrosion was not much different than with coal. In particular, the metallic filters showed

approximately the same corrosion rates as with coal. Ash deposition at the boiler inlet was

slightly higher than normal, especially when temperatures in the second stage were increased. No

additional deposits were noted in other areas.

Because of the lower reactivity of the petroleum coke, char loading to the dry char particulate

removal filters was higher than with coal, but no filtration problems caused by the higher solids

loading were observed. Sampling of the syngas at the gasifier outlet showed negligible amounts

of tar.

As expected, both H2S and COS levels in the raw syngas were much higher during the petroleum

coke test; however, total sulfur in the product syngas was maintained at a level similar to that for

coal operations. No problems were encountered with sulfur removal or recovery; the COS

catalyst performed well, and no adverse impact on the catalyst was detected.
33

The overall conclusion from the petroleum coke test is that operations with petroleum coke are

not significantly different than operations with coal and that the equipment and systems at

Wabash River are adequate for this operation without modification.

III.B Environmental Performance

The WRCGR Project was designed to demonstrate that retrofitting a coal

gasification/combustion turbine system to an existing electrical generating unit could, while

feeding a high-sulfur (up to 5.9 percent) coal, achieve pollutant emissions levels commensurate

with current and upcoming environmental regulations, especially those contained in the Clean

Air Act Amendments of 1990 (CAAA). The project also included environmental compliance

with the air and water pollution requirements specified in the Indiana Department of

Environmental Management's (IDEM) Title V Operating Permits Program.

IGCC plants use gasifiers to convert various carbon-based feedstocks to syngas (a mixture of H2

and CO). The hot syngas is cooled and cleaned of particulates, sulfur, and other contaminants by

technologies that are commonly used in natural-gas purification and oil refining. As a result,

atmospheric emissions of pollutants are very low. The syngas is combusted in a high-efficiency

gas turbine/generator unit. Heat from the exhaust gas is extracted to produce steam to drive a

steam turbine. Because IGCC plants operate at higher efficiencies, and because pollutants are

readily removed from the syngas, these systems emit less pollution per unit of energy than

conventional fossil-energy fueled power plants.

By repowering a 1950s-vintage coal-fired boiler/steam turbine unit with an advanced gasification

system, WRCGR Project personnel were able to economically and efficiently reduce

environmental pollution. The operation of this full-scale CCT demonstration project did not, in

general, increase the volume or composition of plant emissions, but rather significantly reduced

pollutant levels, including sulfur dioxide (SO2), NOX, particulates, CO2, and air toxics compared

to baseline emissions before refurbishment. Average emissions were 0.1 lb/MBtu for SO2, which

is less than one-tenth of the permitted limits. Emission rates as low as 0.03 lb/MBtu have been

achieved. NOX emissions are 0.15 lb/MBtu, which meets the target for 2003 specified under Title

I of the CAAA. Particulate emissions were less than the detectable limit. CO emissions, at 0.40

lb/MBtu, were half that of the pre-repowering emission rate, and well below permitted limits.

For SO2, the New Source Performance Standards (NSPS) for fossil-fuel-fired electric generating

units call for 1.2 lb/MBtu of heat input and 90-percent reduction from the uncontrolled emissions

rate. The SO2 emissions rate for Wabash River of 0.1 lb/MBtu represents a reduction of 97

percent; therefore, both criteria were met. For NOX, the NSPS has been revised to an outputbased regulation, at 1.6 lb/MWh of electric power generated. The Wabash River emissions figure

of 1.09 lb/MWh meets this criterion. For particulate matter, the NSPS is 0.03 lb/MBtu. With

particulate emissions below the detectable limit, Wabash River meets this requirement. CO2

emissions were reduced by approximately 20 percent on a per kWh basis. The facility also

reduced waste by producing two useful by-products, high-purity sulfur and non-hazardous slag,
34

which could be marketed to commercial and industrial users. Recycling water for reuse further

emphasized the positive environmental characteristics of the project.

The only environmental problem encountered related to water quality. Results showed that

condensation of arsenic, selenium, and cyanide from the syngas vapor stream created elevated

levels of these materials in the process wastewater, causing the plant to be out of permit

compliance. The project is under an Administrative Order from IDEM to achieve compliance by

September 2001. Investigations are underway to mitigate this problem by identifying the most

cost-effective, currently available technologies. Approaches under consideration include

chemical precipitation, bio-remediation, reverse osmosis, and evaporation. The additional cost

and complexity of these potential solutions should be factored into any planned replication of this

CCT coal gasification repowering technology.
35

IV Market Analysis

IV.A Market Size/Commercialization

The total of all gasification projects, including those projected to start up by 2004, is a little over

30,000 equivalent megawatts, according to the 1999 World Gasification Survey. This survey is a

database of all the gasification projects in the world on all fuels (natural gas, coal, petroleum

coke, biomass) and producing all products (power, hydrogen, heat, and chemicals). Of the

installed capacity, a little more than half (approximately 54 percent) is coal- or petroleum cokebased. The survey shows that there has been a significant increase in gasification activity in the

past decade. In particular, the majority of the recent increase in installed gasification capacity is

fueled by coal or petroleum coke. Of the 16,500 MW of solid fueled capacity, nearly half (43

percent) has started up, or is starting up, in the 10-year period ending in 2004 (Figure 10).

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One impetus for this growth is the increased costs for environmental compliance with

conventional PC-fired units, the drive to improve efficiencies, the availability of low-cost

alternative feedstocks, and the need to utilize indigenous coal in areas without access to natural

gas. The maturation of gasification technologies through completion of several large-scale

demonstration projects has made this technology a popular and viable alternative to conventional

combustion technologies
36

In addition to generating power, the IGCC process can also be modified to produce value-added

chemicals or transportation fuels from coal by chemical processing of the gas produced, as

opposed to using the gas to drive a combustion turbine. It may be that the near-term market niche

for IGCC lies not only in the production of electricity, but also in the generation of multiple

products, where electricity, steam, and chemicals are economically bundled as products from a

fully integrated complex.

General Electric Company (GE) reported (Todd 1998) that about 5,000 MW of gasification

projects for power generation have proceeded to the point of placing orders for combustion

turbines. Many of these projects include coproduction facilities for production of hydrogen

and/or chemicals. GE is also in discussions with various refiners, developers, and others about

projects totaling another 50,000 MW. This indicates a significant market for gasification

technology in the near future, bolstered by trends of rising energy prices and tightening

environmental controls. The E-GasTM Technology, caused by its successful demonstration in the

WRCGR Project, should be in a good position to capture a significant fraction of this market.

Indications are that many new domestic gasification projects will be refinery-based, utilizing

petroleum coke and other low-cost refinery by-products to produce power, steam, hydrogen, and

chemicals for the refinery and additional power for internal use or export. Global Energy has

prepared the E-GasTM Technology for these applications through a petroleum-coke operational

test program at the Wabash River facility.

The E-GasTM Technology is also being readied for coproduction applications through other

studies and cooperative evaluation programs, some of which are taking place under DOE

sponsored projects. Optimizing plant performance and improving the operating life of certain

components of the plant is also being thoroughly investigated.

Global Energy expects that the E-GasTM Technology, as demonstrated at the Wabash River

facility on both coal and petroleum coke feedstocks, will be utilized in a significant portion of

new solid fuel-based gasification facilities. Because of excellent environmental performance, the

E-GasTM Gasifier should be well suited to refinery-based applications utilizing petroleum coke in

areas that are not in compliance with air emissions standards.

The potential market for repowering with the E-GasTM Technology includes many existing utility

boilers fueled by coal, oil, or natural gas. In addition to cost-effective reductions of SO2 and NOX

emissions attainable by using gasification technology, net plant heat rate is improved as a direct

result of the combined-cycle feature of the technology, which integrates a combustion topping

cycle with a steam bottoming cycle. This technology is suitable for repowering applications and

can be applied to any existing steam cycle located at plants with enough land area to

accommodate coal handling and storage, and gasification and power facilities.

Somewhat further in the future, as the price of other forms of energy (particularly natural gas)

increases domestically, and as existing conventional coal-fired power-generating stations strive

to meet future environmental regulations, a market should develop in the United States for
37

repowering 1960s- and 1970s-vintage coal plants and natural gas-fired combined-cycle plants.

The E-GasTM Technology should be well positioned for these applications.

IV.B Economics

IV.B.1 Capital Costs

Based on a study by Nexant LLC, the estimated capital cost of a 262-MWe power plant built on a

greenfield site and incorporating all the information learned from operation of the Wabash

facility would be $1,275/kW ( in 2000 dollars). Heat rate for this facility would be 8,250

Btu/kWh (HHV). If petroleum coke was used instead of coal, the estimated capital cost would

drop to $1,150/kW. These estimates are shown in Table 10.

Table 10. E-GasTM -Based IGCC Capital Costs

Fuel Coal Petroleum Coke

Capital Investment, $ million

Gasifier 560 435

ASU 140 140

Power Block 575 575

Total 1,275 1,150

IV.B.2 Operating Costs

As stated above, the estimated heat rate for the plant is 8,250 Btu/kWh. If the facility feeds

medium-to-high-sulfur Midwestern coal at $1.25/MBtu, then the fuel cost per kWh is 10.3 mills.

The Final Report (Dowd 2000) estimates the yearly non-fuel operating costs at 5.2 percent of

installed capital costs. Thus, for an installed capital cost of $1,275/kW, non-fuel operating costs

would be 10 mills/kWh at a 75-percent operating factor.

IV.B.3 Cost of Electricity

The basis for the economics of the E-GasTM Technology-based, combined-cycle, power-plant

project are given in Table 11.

The cost of electricity using these parametric values is given in Table 12 on both a current-dollar

and constant-dollar basis. The levelized costs are considerably reduced when feeding petroleum

coke instead of coal, because the higher heating value and reduced ash will decrease solids

handling and maintenance costs. Also, fuel costs are much lower, since petroleum coke may be

only 15 to 25 percent the cost of coal.
38

Table 11. Basis for Economic Evaluations

Economic Parameter Coal Petroleum Coke

Generating Capacity, MWe (net) 270 271

Plant Heat Rate, Btu/kWh (HHV) 8,910 8,790

Plant Capital Cost, $/kW 1275 1,150

Plant Operating Cost, % of capital 5.2 4.5

Capacity Factor, % 75 80

Fuel Cost, $/ton 20 5

Fuel Heating Value, Btu/lb 10,500 14,500

Table 12. Economics* of Power Generation by an IGCC Unit Using E-GasTM Technology

Coal Base, $106 Current Dollars Constant Dollars

Factor Mills/kWh Factor Mills/kWh

Capital Charge 344.3 0.160 31.05 0.124 24.06

Fixed O&M Cost 17.9 1.314 13.26 1.000 10.09

Variable Operating Cost 13.9 1.314 10.27 1.000 7.81

Levelized Cost of Power 54.58 41.96

Petroleum Coke

Capital Charge 311.7 0.160 26.26 0.124 20.35

Fixed O&M Cost 14.0 1.314 9.70 1.000 7.38

Variable Operating Cost 2.9 1.314 1.99 1.000 1.52

Levelized Cost of Power 37.95 29.25

* Estimation based on information from Participant’s Final Report.
39

V Conclusions

The WRCGR Project successfully demonstrated that the E-GasTM Technology can be operated

for extended periods of time and produce syngas of sufficient heating value to be burned in a

combustion turbine for the production of electricity. All the technical goals were met. Although

the E-GasTM Technology has been demonstrated and used to repower an existing PC-fired boiler,

at the completion of the Demonstration Project in December 1999, there were some areas where

additional improvements were desirable to increase availability and reduce operating costs such

as improving slurry-mixer reliability and decreasing trace compound concentrations in the

wastewater. Although the particulate-removal system was not a significant problem at the end of

the Demonstration, improved candle filters would be desirable. Also, coal ash composition must

be carefully monitored so that changes in the feed coal do not lead to tap hole plugging. Because

the E-Gas gasifier has continued to operate since the completion of the Demonstration Project,

additional information on performance may be available from Global Energy, the current owner

of the technology.

When coupled with well-designed auxiliary units, the E-GasTM Technology emits very low levels

of pollution. This is because nitrogen in the fuel leaves the gasifier as ammonia, and sulfur in the

fuel leaves the gasifier as hydrogen sulfide. Ammonia is easily scrubbed from the syngas using a

water wash, and can be recovered for sale or converted to nitrogen gas and water. Thus, fuel NOX

production is negligible. Furthermore, combustion temperatures in the combustion turbine are

lower than in typical PC-fired boilers, so that thermal NOX production is also lower. The H2S in

the syngas is easily removed using any of a number of commercially available acid-gas removal

processes. The recovered H2S can then be converted to very pure sulfur for sale. This is a much

more efficient procedure than trying to scrub SO2 from flue gas, and also avoids the problem of

disposing of large quantities of scrubber sludge.

The gasifier was operated successfully on both bituminous coal and on petroleum coke, thus

demonstrating its ability to handle a wide range of feeds. The potential exists to use a variety of

fuels of opportunity, such as MSW, RDF, sewage sludge, waste tires, etc., either alone or, more

likely, cofired with coal.

Interest in IGCC is continuing to grow because of its improved efficiency and reliability. The

E-GasTM Gasifier seems well positioned to supply a significant portion of this market. Future

replication of the E-GasTM Gasifier will furnish the marketplace with an efficient and

environmentally benign technology capable of meeting today’s strict environmental standards.

The continued operation of the Wabash facility demonstrates the successful completion of this

project.
40

Abbreviations

AGR acid-gas removal

Air Liquide Liquid Air Engineering Corporation

ASU air-separation unit

CAAA Clean Air Act Amendments of 1990

CCT Clean Coal Technology

CGCC coal gasification combined-cycle

CO carbon monoxide

CO2 carbon dioxide

COS carbonyl sulfide

cold box cryogenic distillation system

CSS chloride-scrubbing system

DOE U.S. Department of Energy

DE&CS Dow Engineering & Construction Services

GE General Electric Company

GSA Gasification Services Agreement

H2 hydrogen

HP high-pressure

HHV high heating value

HRSG heat-recovery steam generator

H2S hydrogen sulfide

HTHRU high-temperature heat-recovery unit

IDEM Indiana Department of Environmental Management

IP intermediate pressure

IGCC integrated gasification combined-cycle

LGTI Louisiana Gasification Technology, Inc.

LP low-pressure

LTHRU low-temperature heat-recovery unit

MDEA methyldiethanolamine

MSW municipal solid waste

NH3 ammonia

NOX nitrogen oxides

NSPS New Source Performance Standards

PPA post-project assessment

PC pulverized coal

RDF refuse-derived fuel

SOW Statement of Work

SO2 sulfur dioxide

SRU sulfur-recovery unit

TCLP Toxicity Characteristic Leaching Procedure

WRCGR Wabash River Coal Gasification Repowering

WRCGRPJV Wabash River Coal Gasification Repowering Project Joint Venture
41

References

Dowd, Roy A. 2000. Wabash River Coal Gasification Repowering Project—Final Technical

Report. Global Energy .

Todd, Doug. 1998. New Markets for CCT’s. Paper presented at Sixth Clean Coal Technology

Conference, April 28-May 1, Reno, Nevada.

U.S. Department of Energy. 1992. Comprehensive Report to Congress—Clean Coal Technology

Demonstration Project—Wabash River Coal Gasification Repowering Project. DOE/FE-0257P.

Springfield VA. National Technical Information Service.
42

Bibliography

Amick, Phil. 2000.Commercial Operation of the Wabash River Coal Gasification Repowering

Project. Paper presented at Electric Power 2000 conference, April, Cincinnati, Ohio.

Dowd, Roy A. 1996. Wabash River Coal Gasification Repowering Project—Annual Technology

Report January-December 1996. Global Energy.

Dowd, Roy A. 1997. Wabash River Coal Gasification Repowering Project—Annual Technology

Report January-December 1997. Global Energy.

Dowd, Roy A. 1998. Wabash River Coal Gasification Repowering Project—Annual Technology

Report January-December 1998. Global Energy.

U. S. Department of Energy. 1996. The Wabash River Coal Gasification Repowering Project.

Clean Coal Technology Topical Report Number 7. November.

U. S. Department of Energy 2000. The Wabash River Coal Gasification Repowering Project—

An Update. Clean Coal Technology Topical Report Number 20. September.