TOPICAL REPORT NUMBER 20 SEPTEMBER 2000

The Wabash River

Coal Gasification Repowering Project

An Update
TOPICAL REPORT NUMBER 20 SEPTEMBER 2000

The Wabash River

Coal Gasification

Repowering Project

A report on a project conducted jointly under

a cooperative agreement between:

The U.S. Department of Energy

and Wabash River Coal Gasification Project Joint Venture

A 262 MWe Commercial Scale

Integrated Gasification

Combined Cycle Power Plant

An Update
View of the Wabash

River Coal Gasification

Repowering project with

the Wabash River and

the flat terrain of west

central Indiana in the

background.

Cover image:
The Wabash River

Coal Gasification

Repowering Project

Executive Summary........................................................................................... 1

Background........................................................................................................ 2

Integrated Gasification Combined-Cycle .......................................................... 2

Project Description ............................................................................................ 4

Power Plant Description .................................................................................... 7

Cost/Schedule .................................................................................................. 12

Project Objective ............................................................................................. 13

Plant Modifications/Improvements ................................................................. 13

Results ............................................................................................................. 14

Awards ............................................................................................................. 15

Commercial Applications ................................................................................ 15

Future Developments....................................................................................... 16

Market Potential .............................................................................................. 17

Conclusions ..................................................................................................... 18

Bibliography .................................................................................................... 22

Contacts for CCT Projects and U.S. DOE CCT Program ............................... 23

List of Acronyms and Abbreviations .............................................................. 24
1

Executive Summary

The Clean Coal Technology (CCT)

Demonstration Program is a government

and industry co-funded effort to demonstrate a new generation of innovative coal

utilization processes in a series of facilities

built across the country. These projects are

conducted on a commercial scale to prove

technical feasibility and provide the information required for future applications.

The goal of the CCT Program is to

furnish the marketplace with a number

of advanced, more efficient coal-based

technologies that meet strict environmental standards. These technologies

will mitigate the economic and environmental barriers that limit the full utilization of coal, thereby reducing dependence

on foreign oil.

To achieve this goal, beginning in

1985, a multi-phased effort consisting of

five separate solicitations has been administered by the U.S. Department of Energy’s

(DOE) National Energy Technology Laboratory (NETL), formerly the Federal Energy Technology Center. Projects selected

through these solicitations have demonstrated technology options with the potential to meet the needs of energy markets

while satisfying relevant environmental

requirements.

This report discusses the Wabash River

Coal Gasification Repowering Project. In

this project, coal is gasified in an oxygenblown, entrained-flow gasifier with continuous slag removal and a dry particulate

removal system. The resulting synthesis

gas is used to fuel a gas combustion turbine generator, whose exhaust is integrated

with a heat recovery steam generator to

drive a refurbished steam turbine generator. The gasifier uses technology initially

developed by Dow (the Destec Gasification Process) and now offered commercially by Global Energy Inc. as the

E-GASTM technology.

This demonstration was completed

in December 1999, having achieved all of

its objectives. The facility built for this

project is located at PSI Energy’s Wabash

River Generating Station near West Terre

Haute, Indiana. Sulfur removal exceeds

97%. Sulfur is recovered and sold, as is

the slag byproduct of gasification.

The Wabash River CCT project

successfully demonstrated commercial

application of the E-GASTM coal gasification technology in conjunction with

electric power generation. Operating

time exceeded 15,000 hours, with over

1.5 million tons of coal processed and

about 4 million MWh of power produced. The combustion turbine generated 192 MWe and the repowered steam

turbine generated 104 MWe. With the

system’s parasitic load of 34 MWe, net

power production was 262 MWe, which

met the target goal. Carbon conversion

exceeded 95%. The plant operated successfully on baseload dispatch in the PSI

power grid, and continues to operate as a

privately owned facility providing power

to PSI Energy.

Gasification is an environmentally

superior means of utilizing domestic coal

resources for power production. It also offers the opportunity to use lower quality,

less expensive feedstocks such as petroleum coke. Operation on petroleum coke

was also demonstrated at Wabash River.

Emissions of SO2 and NOx were far

below regulatory requirements. SO2 emissions averaged about 0.1 lb/million Btu,

compared with the allowable limit of 1.2

lb/million Btu. NOx emissions were 0.15

lb/million Btu, which met the current target for coal-fired power generation plants.

Particulate emissions were less than the

detectable limit. The Wabash River facility is one of the cleanest coal-based

power plants in the world.

IGCC Advantages

• A Clean Environment

• High Efficiency

• Low Cost Electricity

• Potential for Low Capital Costs

• Repowering of Existing Plants

• Modularity

• Fuel Flexibility

• Phased Construction

• Low Water Use

• Low CO2 Emissions

• Public Acceptability
2

The Wabash River

Coal Gasification

Repowering Project

Background

The Clean Coal Technology (CCT)

Demonstration Program, sponsored by

the U.S. Department of Energy (DOE)

and administered by the National Energy

Technology Laboratory (NETL), has

been conducted since 1985 to develop

innovative, environmentally friendly

coal utilization processes for the world

energy marketplace.

The CCT Program, which is co-funded

by industry and government, involves

a series of commercial-scale demonstration projects that provide data for design,

construction, operation, and technical/

economic evaluation of full-scale applications. The goal of the CCT Program

is to enhance the utilization of coal as

a major energy source.

The CCT Program has also opened

a channel to policy-making bodies by providing data from cutting-edge technologies

to aid in formulating regulatory decisions.

DOE and the participants in several CCT

projects have provided the Environmental

Protection Agency (EPA) with data to help

establish targets for nitrogen oxide (NOx)

emissions from coal-fired boilers subject to

compliance under the 1990 Clean Air Act

Amendments (CAAA).

Integrated Gasification

Combined-Cycle

Among the technologies being demonstrated in the CCT Program is Integrated Gasification Combined-Cycle (IGCC). IGCC is an

innovative electric power generation process

that combines modern coal gasification with

gas turbine and steam power generation technologies. IGCC is one of the most efficient

and cleanest of available technologies for coalbased electric power generation. This technology offers high system efficiencies compared

with conventional pulverized-coal power generation, reduced costs, and very low pollution

levels.

IGCC power plants offer excellent environmental performance. Gasification breaks down

virtually any carbon-based feedstock into its

basic constituents, enabling the separation of

pollutants to produce clean gas for efficient

electricity generation. As a result, atmospheric

emissions of pollutants are very low.

Due to their high efficiency, less coal is

used, causing IGCC power plants to emit less

carbon dioxide (CO2) to the atmosphere,

thereby decreasing concerns about climate

change. Less coal use also results in less ash

requiring disposal.

Modularity and fuel flexibility are important attributes of IGCC power plants. The
3

combined-cycle unit can be operated on

other fuels, such as natural gas or fuel oil,

before the gasifier is constructed, to provide

early power. The size of gas turbine units

can be chosen to meet specific power requirements. Ability to operate on multiple

fuels also permits continued operation of

the gas turbine unit if the gasifier island is

shut down for maintenance or repairs, or if

warranted by changes in fuel costs.

An additional benefit of IGCC is product

flexibility, permitting production of alternatives such as chemicals or transportation fuels. Market forces, which are replacing

regulatory structures, are resulting in expanded IGCC applications. As a result of

both feedstock and product flexibility, traditional steam-powered electricity generation

using single feedstocks is being supplanted by

more versatile integrated technologies.

IGCC power plants use plentiful and relatively inexpensive coal as their fuel. In the

United States there are several hundred years

of coal reserves, and use of coal helps to reduce dependence on foreign oil.

Four IGCC demonstration projects are

included in the CCT Program: (1) the Piñon

Pine IGCC Power Project, (2) the Tampa

Electric Integrated Gasification CombinedCycle Project, (3) the Wabash River Coal

Gasification Repowering Project, and (4)

the Kentucky Pioneer Energy Project. This

Topical Report describes the Wabash River

Project.

IGCC power plant. The gasifier structure,

gas cleanup system, and sulfur recovery

plant are on the left. Gas turbine auxiliary

fuel tanks are in the center. Right center is

the GE MS 7001FA gas turbine and HRSG.

The pipe rack exiting the HRSG passes

under the bridge to the building containing the repowered steam turbine.
4

Project Description

The Wabash River Project was selected

by DOE in September 1991 as a CCT Program Round IV demonstration project.

Construction was started in July 1993 and

commercial operation began in November

1995. The demonstration was completed in

December 1999.

The Wabash River Project demonstrated use of the Global Energy E-GASTM

coal gasification process to fuel a combustion turbine generator, whose exhaust is

integrated with a heat recovery steam generator (HRSG) to drive a steam turbine

generator. Sulfur removal exceeds 97%.

Elemental sulfur is recovered and sold,

as is the slag byproduct of gasification.

New Generating Capacity Forecast

1998–2020

Source: U.S. Energy Information Administration, 1999

The demonstration facility is located

at the Wabash River Generating Station

near West Terre Haute, Indiana, owned

and operated by PSI Energy, Inc. of

Plainfield, Indiana.

The power block consists of an advanced General Electric MS 7001 FA

gas turbine unit that produces 192 MWe

(gross), a Foster Wheeler HRSG, and a

1953 vintage Westinghouse reheat steam

turbine. The steam turbine, which was

refurbished as part of this CCT project,

produces an additional 104 MWe (gross).

Parasitic power is 34 MWe, giving a total

power output of 262 MWe (net).

Project Participant

The Participant in the CCT project was

Wabash River Coal Gasification Project

Joint Venture, formed in 1990 by Destec

Energy, Inc. of Houston, Texas and PSI

Energy. PSI is an investor-owned utility

whose service area covers 69 of the 92

counties in Indiana. Along with Cincinnati

Gas & Electric Company, PSI is owned by

Cinergy Corporation, which was formed in

October 1994. Cinergy is one of the largest

electric utilities in the United States.

In 1997, Destec was purchased by

Houston-based NGC Corporation, which

changed its name to Dynegy, Inc. in 1998.

In December 1999, Global Energy Inc.

completed the purchase of Dynegy’s gasification assets and technology. The purchase included Dynegy’s syngas facility

at the Wabash River Coal Gasification

Repowering Project as well as the right,

title and interest in Dynegy’s proprietary

gasification technology, including its gasification-related patents. The sale also included the rights to Dynegy’s gasification

projects in development.

The gasification technology, originally

developed by the Dow Chemical Company, was first applied to power applications at its Plaquemine, Louisiana

chemicals complex. The technology was

140

120

100

80

60

40

20

0

Combustion Renewables

Turbines

Combined

Cycle

Fossil

Steam

Capacity, GWe
5

later transferred to Destec, a partially held

subsidiary of Dow Chemical.

Global Energy will license the gasification process under a new name, E-GASTM

Technology, reflecting the efficiency,

economy, and superior environmental

performance of this process. A newly created Global Energy subsidiary, Gasification Engineering Corporation, plans to

market the E-GASTM technology worldwide from offices in Houston, Texas.

Global Energy is a founding member

of the Washington, D.C.-based Gasification Technologies Council along with several leading industrial companies. Global

Energy is focused on gasification technology projects designed to improve environmental and economic results for the power,

refining, chemical, and pulp and paper

industries. The company has more than

2,000 MWe of project activity in development, construction and operation in the

United States and the United Kingdom, with

business development interests worldwide.

Project Subcontractors

Sargent & Lundy provided engineering services to PSI for the design

and procurement of modifications to

the existing station, the new power

block equipment, and system integration. PSI managed the initial site work

for both facilities, and the construction

and startup of the power island block,

including a water treatment facility,

control building and coal handling

system modifications.

Dow Engineering Company provided engineering services to Destec

for the design and procurement of the

gasification plant and the system integration interface to PSI. Destec developed the project, performed the process

design work, and managed construction of the gasification island facilities,

including a control, administration and

maintenance building and the air separation plant, one of the largest such facilities in North America.

Air separation unit during construction
6

Site Description

The CCT demonstration site is located in

a predominantly rural area on the Wabash

River near West Terre Haute, Indiana.

PSI’s Wabash River Station was originally

a mine mouth plant, and much of the new

facility is built over areas that were shaft

mined in the early 20th century.

The area immediately surrounding the

site includes the Wabash River to the east,

woodlands and agricultural areas, a reclaimed strip mine, and residential areas

about 0.2 miles to the southwest and 1.5

miles to the north. The site is about eight

miles north of downtown Terre Haute.

There are no nearby wilderness areas or

national or state parks.

The coal gasification repowering facility is located immediately northwest of

PSI’s Wabash Generating Station on land

donated by the Peabody Coal Company.

The 15-acre plot containing the gasification island, air separation unit, water

treatment facility, and gas turbine-HRSG

tandem is adjacent to the existing station.

New wastewater and storm water ponds

are located nearby in an area previously

used as an ash pond.

Coal Supply

The Wabash River IGCC Power Plant

is designed to use a range of local coals

with a maximum sulfur content of 5.9%

(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 Units 2-6 of the existing station.

Alternative feedstocks, including petroleum coke and blends of coal and coke,

were tested during the three-year demonstration period.

Project Management PSI Energy, Inc.

Engineer Sargent & Lundy

Construction Management PSI Energy, Inc.

Gas Turbine Vendor General Electric Company

HRSG Vendor Foster Wheeler Energy Corp.

Project Management Destec Engineering, Inc.

Engineer Dow Engineering Co.

Construction Management Destec Engineering, Inc.

Gasification Vessel Vendor Nooter Corp.

Syngas Cooler Vendor Deutsche Babcock-Borsig

Air Separation Unit Vendor Liquid Air Engineering Corp.

Project Team

Combined Cycle Facility

Gasification Facility

General Electric model MS 7001FA gas turbine
7

Power Plant

Description

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. LGTI 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 and process variables.

Coal is slurried with water and fed, along

with 95% oxygen from the air separation

plant, to the first stage of the gasifier. Partial

combustion of the coal maintains a temperature of about 2500°F (1371°C). Most of the

coal reacts chemically with steam to produce raw fuel gas. The ash melts and flows

out of the bottom of the vessel as slag. Additional coal/water slurry added to the

second gasification stage undergoes

devolatilization, pyrolysis, and partial

gasification to cool the raw gas and enhance its heating value.

The raw gas is further cooled, producing steam for power generation. In this

project, the steam is generated at a pressure of about 1,600 psia, whereas

Dynegy’s LGTI facility operated at

about 600 psia. The Wabash River syngas

cooler has met expectations with respect

to thermal performance and durability.

Particles contained in the gas are removed by candle filters and recycled to

the first stage for gasification of residual

carbon. Only a single gasifier vessel is required to process the 2544 tons/day of

coal feed, although two vessels, each of

100% capacity, were installed.

The particle-free gas is further cooled,

scrubbed to remove chlorides, and passed

through a catalyst bed that converts carbonyl sulfide (COS) to H2S. Sulfur contaminants are removed by conventional

processing using an amine solvent. Highquality sulfur (99.99% pure) is recovered

and sold off-site for agricultural applications. The slag byproduct of gasification

can be sold for use in road paving and

roof shingles.

Emissions, lb/MWh SO2 NOx CO PM-10 VOC

Pre-Repowering Unit 1 Boiler 38.2 9.3 0.64 0.85 0.03

IGCC 1.35 1.09 0.37 ND* 0.02

Emissions, lb/million Btu SO2 NOx CO PM-10 VOC

Pre-Repowering Unit 1 Boiler 3.1 0.8 0.05 0.07 0.003

IGCC 0.10 0.15 0.03 ND* 0.003

IGCC atmospheric emissions are significantly lower than those from the pre-IGCC repowered boiler.

The consequence is a marked improvement in air quality.

* non-detectable

Emissions from Wabash River IGCC Plant
8

The cleaned gas is moisturized to aid

in control of NOx emissions and fed to a

General Electric model MS 7001FA gas

turbine, where it is combusted to generate

electricity. Moisturization reduces the

amount of steam injection required for

NOx control.

Advanced gas turbine design allows for

the combustion of syngas at a firing temperature of 2350°F (1222°C), which is

significantly higher than previously demonstrated. Wabash River features the first

“F” machine to operate on syngas. Blade

temperatures are monitored on a real time

basis, using optical pyrometry.

Gas turbine exhaust heat is recovered in

the HRSG to produce steam for generation

of more electricity. Repowering of the existing steam turbine involved upgrading

the unit to accommodate the increased

steam flow generated by the HRSG. Flue

gas is emitted to the atmosphere through

a 225-ft stack.

Environmental Considerations

Expected environmental impacts of

the CCT project were analyzed by DOE

according to National Environmental

Policy Act (NEPA) requirements. PSI,

Destec and two environmental consulting

firms prepared a detailed environmental

information volume which provided inputs

to an Environmental Assessment for this

project. A favorable NEPA assessment

resulted in DOE issuing a Finding of No

Significant Impact in May 1993.

Required federal, state and local environmental permits and approvals were

obtained. A process and environmental

monitoring program was established in

compliance with permitting requirements.

The plant was designed to substantially

outperform the CAAA emission standards,

which include an SO2 limit of 1.2 lb/million Btu of fuel input and a NOx limit of

0.15 lb/million Btu. As discussed subsequently, demonstrated emissions are far

lower than these target values. Compared

• A single operating high throughput coal gasifier.

• Hot/dry particulate removal and

recycle that enhances system efficiency.

• Production of steam in an HRSG

at a pressure of 1,600 psia.

• Continuous slag removal from

the gasifier.

• Integration of the gasification facility with the HRSG to optimize efficiency and operating costs.

• Carbonyl sulfide hydrolysis, allowing a high level of sulfur removal.

• Recycle of waste water to minimize makeup water requirements.

• Recycle of sulfur removal unit tailgases to the gasifier to further reduce emissions.

Advanced Features of the Gasifier Island
9

Process Flow Diagram

The gas cleanup system removes H2S

from the fuel gas; sulfur is recovered as

a by-product and sold. Ammonia is also

removed and recycled to the gasifier.

Heat Recovery

Steam Generator

Generator

Steam Turbine

Fuel-Gas

Preheat

Steam

Fuel Gas

Fuel-Gas

Cooler

Particulate

Removal

Hot

Candle

Filter

Fuel Gas

High Pressure Steam

Sulfur

Removal &

Recovery

Char

Liquid Sulfur

Byproduct

Flue Gas

to Stack

Fuel

Gas

Air

Combustor

Steam

Generator

Gas Turbine

Hot

Exhaust

Gas

Steam Feed Water

Second

Stage

Coal

Slurry

Oxygen

(from Air

Separation

Plant)

First

Stage

Slag/Water

Slurry

Slag

Quench

Water

E-GasTM

Entrained-Flow

Gasifier

Slag By-product
10

Coal Gasification

The E-GASTM two-stage coal

gasification technology features an

oxygen-blown, entrained-flow, refractory-lined gasifier with continuous slag removal. The first stage

operates at about 2500°F and 400

psig. The actual operating temperature depends upon the specific coal used. A 60/40 wt % coal/

water slurry is combined with oxygen and injected into the gasifier.

Oxygen of 95% purity is supplied

by a turnkey, dedicated air separation unit. The coal undergoes partial combustion, releasing heat

that causes the gasification reactions to proceed very rapidly and

the ash to melt and flow.

The molten ash exits through

a taphole at the bottom of the first

stage into a water quench, forming an inert vitreous slag which is

sold for various construction applications.

The raw synthesis gas (syngas)

flows upward into the second

stage, a vertical refractory-lined

vessel, where added slurry reacts

with the hot coal gas exiting the

first stage. The coal devolatilizes,

pyrolyzes and partly gasifies by

reaction with steam.

In the second stage, (1) the

heating value of the syngas is increased, and (2) evaporation of

water and endothermic (heat consuming) chemical reactions cause

the temperature of the crude

syngas to be reduced to about

1900°F (1038°C). Use of the

second stage of gasification as

a method for both heating value

enhancement and raw syngas

cooling eliminates the need for a large,

expensive radiant heat exchanger that

would otherwise be required, and creates a more efficient system than otherwise would be obtainable.

The raw product gas exits the gasifier at 1900°F and is further cooled in

a firetube boiler, producing high-pressure (1600 psia) saturated steam.

Gas Cleanup

Flyash and remaining char particles

in the gas are removed by a hot metallic candle filter system and recycled

to the first stage gasifier for gasification of residual carbon. Filter system

operation was first tested at full scale

at LGTI, and the design was advanced

at the demonstration facility.

The “sour” gas leaving the particulate filter system consists mostly of

hydrogen (H2), carbon dioxide (CO2),

carbon monoxide (CO), water (H2O),

nitrogen (N2), and smaller quantities

of methane (CH4), carbonyl sulfide

(COS), hydrogen sulfide (H2S), and

ammonia (NH3).

H2S and COS are at concentrations

of hundreds of parts per million, requiring a high degree of removal for the

power plant to achieve the low design

level of SO2 emissions. H2S is removed

in an acid gas removal system; however, because COS is not readily

removable it is first catalytically converted to H2S by hydrolysis.

The sour gas is cooled to about

100°F (38°C) before H2S is removed.

The cooling is accomplished by several

heat exchangers, where water in the

syngas condenses; the condensate

contains NH3 and some of the H2S and

CO2. The condensate is sent to water

treatment.

Acid Gas Removal

The cooled syngas flows to the

acid gas removal absorber column,

where H2S is removed by a solvent,

methyldiethanol amine (MDEA). The

solvent plus H2S and some of the CO2

flows to the H2S stripper, where the

pressure is reduced and steam stripping removes the gases, which then

flow to the sulfur recovery system.

The “lean” amine is recycled.

Sulfur Recovery

In a series of catalytic stages, a

Claus sulfur recovery unit converts

H2S removed from the fuel gas to sulfur. Part of the H2S is burned in the

thermal stage to produce SO2, which

reacts with the remaining H2S to produce elemental sulfur and water.

Unreacted H2S is compressed and

recycled to the gasifier.

The particle-free gas is further

cooled to near ambient temperature,

and over 97% of the sulfur in the

coal is removed by conventional

recovery technology. High-quality

sulfur (> 99.99% pure) is recovered

and sold for agricultural applications.

Water Treatment and Recycle

In the water treatment system, dissolved gaseous contaminants are removed. The CO2 and H2S are removed

first and then recycled to sulfur recovery. NH3, which is removed in a second column, is combined with the

resultant water and recycled for coal/

water slurry preparation. Excess water

is treated with activated carbon and

discharged to the pond for subsequent

discharge to the river through the permitted discharge point. The NH3 content

of the effluent is below the permit level.

Process Description
11

Power Block

Key elements of the combined cycle

power block are the General Electric MS

7001FA high-temperature gas turbine/

generator, the heat recovery steam generator (HRSG), and the repowered steam

turbine. The MS 7001FA is a dual-fuel

machine (syngas for operations and No.

2 fuel oil for startup), capable of producing 192 MWe. The gas turbine is currently being converted to use natural gas

as a secondary fuel instead of fuel oil.

The advanced gas turbine technology

incorporates redesigned air compressor

and turbine stages, higher firing temperatures, and a higher pressure ratio. The

HRSG is a single drum design capable

of superheating 754,000 lb/hr of highpressure steam at 1010°F (543°C) and

600,820 lb/hr of reheat steam at 1010°F

(543°C) when the gas turbine operates

on syngas.

The repowered steam turbine unit

number 1, originally installed in 1953, had

been derated from 104 MWe to 90 MWe

when reduced coal consumption was

necessary to reduce stack emissions. As

part of the CCT project, the unit was refurbished to accept the increased steam

flows and pressures associated with the

combined-cycle operation. Output has

been restored to 104 MWe.

Parasitic electric consumption is 34

MWe, consisting of power to operate the

air separation unit, motors, pumps, and

other requirements of the project. Total

net power production is 262 MWe.

The cleaned gas is moisturized to aid

in control of NOx emissions and fed to

the gas turbine, where it is combusted.

Gas turbine exhaust heat is recovered to

produce steam for production of electricity. Flue gas is emitted to the atmosphere

via a 225-ft stack.

Air Separation Unit

A conventional air separation unit

provides 95% pure oxygen for the

gasifier operation.

Slag By-product

Second

Stage

Coal

Slurry

Fuel Gas

Oxygen

(from Air

Separation

Plant)

First

Stage

Slag/Water

Slurry

Slag

Quench

Water

Char

E-GasTM

Entrained-Flow

Gasifier
12

with previous operation of the steam turbine, CO2 emissions are reduced by approximately 20% on a per kWh basis.

Even though power generation at

Wabash River is almost three times that

of the original unit, total emissions are

a fraction of the pre-repowering values

as a result of IGCC operation.

Cost/Schedule

Project Cost

The total cost of the Wabash River

Project was $438 million, including construction and operation during the four

year demonstration period. The DOE provided $219 milion (50%) of the total cost.

Capital investment for a commercial unit

of this size would be considerably lower

than this figure.

Project Schedule

The cooperative agreement between

Wabash River and DOE was signed in

July 1992. Construction started in July

1993, and operation began in November

1995. The demonstration was completed

in January 2000.

Construction

Construction activities in the first year

were hampered by unusually severe

weather. To stay on schedule, 7-day construction schedules were employed. Peak

construction activity brought over 1,000

workers to the site daily. Support from

local labor unions and contractors was

critical to maintaining the project schedule.

Product Syngas Analysis

Analysis Typical Coal Petroleum Coke

Nitrogen, vol % 1.9 1.9

Argon, vol % 0.6 0.6

CO2, vol % 15.8 15.4

CO, vol % 45.3 48.6

H2, vol % 34.4 33.2

CH4, vol % 1.9 0.5

Total Sulfur, ppmv 68 69

HHV, Btu/SCF 277 268

Fuel Analysis

Component Typical Coal Petroleum Coke

Moisture, % 15.2 7.0

Ash, % 12.0 0.3

Volatile Matter, % 32.8 12.4

Fixed Carbon, % 39.9 80.4

Sulfur, % 1.9 5.2

HHV (as received), Btu/lb 10,536 14,282

Production Statistics

From startup in 1995 through project completion at end of 1999

Operating time on coal, hours 15,067

Coal processed, 106 tons 1.55

Syngas produced, 1012 Btu 23.9

Steam produced, 106 lb 6.38

Power produced, 106 MWh 3.91

Sulfur produced, 103 tons 33.4

Equivalent SO2 captured, 103 lb 133.4
13

Turnover and Commissioning

A detailed turnover/commissioning

plan was developed and implemented for

each facility by separate teams of construction and operating personnel. Initially, the combined cycle facility was

tested alone, on No. 2 distillate. Gas turbine roll occurred on June 8, 1995 and

synchronization to the grid occurred on

June 21. Various startup problems were

identified and corrected.

Commercial operation of the gasification facility was achieved November 18,

1995. Barely four months into the demonstration period, in mid-February 1996,

the facility was operated continuously for

over 12 consecutive days with all parameters at acceptable levels. The gasifier

achieved 100% capacity and produced

the most syngas ever from a single-train

gasification plant during this period. The

gas turbine also achieved 100% of rated

load on syngas by generating 192 MWe

of power.

Project Objective

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.

Plant Modifications/

Improvements

Initial operations were hampered by

several problems, most of which have been

addressed successfully.

Although the gasifier and slag handling

facilities have performed well, carbon content in the slag was initially higher than desired, about 10%. Improvements in rod

mill operation and installation of a new

burner resulted in increased carbon conversion, reducing the carbon content of the

slag to below 5%. The new burner design

also improved burner life and greatly reduced the time required to change out

burners.

Problems were experienced initially

with syngas cooling, particulate removal,

and hydrolysis of COS. Ash deposition at

the inlet to the firetube boiler was corrected by modifying the hot gas path flow

geometry and velocity. There was significant breakthrough of particulates in the

barrier filter system, primarily due to

movement and breakage of the ceramic

candle filter elements. Replacing the ceramic elements with metallic candles remedied this problem.

Poisoning of the COS hydrolysis catalyst by chlorides and metals led to early replacement of the catalyst. This problem

has been addressed successfully by installation of a wet chloride scrubber system

and introduction of a different catalyst.

A new method of mechanically cleaning

boiler tubes was developed, resulting in reduced corrosion and decreased filter blinding. Acid gas removal performance was

improved significantly by expanding the

capacity of the system for removing heatstable salts from the circulating amine solution.

The combustion turbine system required

improvements in several areas. The expansion bellows between the syngas module

and the turbine required redesign and replacement to eliminate cracking in the flow

sleeves. Solenoid valves in the syngas

purge lines have been redesigned and replaced. Cracking of the combustor liners

was remedied by replacement of the fuel

nozzles. Failure of the air compressor rotor

and stator of the combustion turbine assembly resulted in a prolonged shutdown

in 1999; causes for this failure are under

investigation but have been determined to

be unrelated to syngas operation.

Gasifier structure
14

Results

Operation

Upon completion of the demonstration

program on January 1, 2000, the Wabash

River Project had processed over 1.5 million tons of coal, producing about 4 million

MWh of electric power. Overall thermal efficiencies were 39.7% on coal and 40.2%

on petroleum coke (HHV basis). Plant

availability averaged 70% in 1998-99,

reaching as high as 77% on a 9 month average. The plant demonstrated stable operation on the utility grid, successfully

operating on baseload dispatch in the PSI

system.

The employees for the project were

hired for and function with the flexible

worker concept, in that there is only one

job classification on site. All employees

have been trained to work multiple disciplines.

Emissions

Environmental performance was excellent. Average emissions are 0.1 lb/million

Btu for SO2, which is less than one-tenth of

the permitted limit. Emission rates as low

as 0.03 lb/million Btu have been achieved.

NOx emissions are 0.15 lb/million Btu,

which meets the target for 2003 specified

under Title I of the CAAA. Particulate

emissions are less than the detectable limit.

Cost and Efficiency Targets for IGCC

Year Capital Cost, $/kW Efficiency, % (HHV)

2000 1,250 42

2008 1,000 52

2015 850 >60

DOE’s Vision 21

For SO2, the New Source Performance

Standards (NSPS) for fossil-fuel fired electric generating units call for 1.2 lb/million

Btu of heat input and 90% reduction from

the uncontrolled emissions rate. The SO2

emissions rate for Wabash River of 0.1 lb/

million Btu represents a reduction of 97%;

therefore, both criteria are amply met. For

NOx, the NSPS has recently been revised

to an output-based regulation, at 1.6 lb/

MWh of electric power generated. The

Wabash River emissions figure of 1.09 lb/

MWh meets this criterion as well as the

former limit of 0.15 lb/million Btu. For

particulate matter, the NSPS is 0.03 lb/million Btu. With particulate emissions below

the detectable limit, Wabash River clearly

meets this requirement.

High-quality elemental sulfur (99.99%

pure) is recovered and sold. From startup

through the end of 1999, the Wabash River

project produced over 33,000 tons of marketable sulfur.

The COS hydrolysis system proved

effective at achieving a conversion efficiency of 98%, allowing a high percentage

of sulfur removal from the system. Syngas

sulfur content has been well below the gas

turbine manufacturer’s requirements.

Repayment

Upon completion of the sale of the

Wabash River IGCC facility and the

Destec/Dynegy gasification technology

to Global Energy, the Participants provided

a $550,000 repayment to DOE on the technology sale. This represents the single

largest repayment to date under the CCT

Program, bringing total repayments to

slightly over $1.3 million. While that represents only a small fraction of DOE’s $1.8

billion investment in the $5.3 billion CCT

Program, the advances in gasification technology and increasing utilization in both

power and refining markets promise to

bring further repayment, as CCTs are

commercialized.
15

Awards

In their September/October 1996

issue, Power Magazine editors named

the Wabash River Project as one of five

Powerplant award winners for 1996–the

fourth time since 1991 that a DOE-sponsored CCT project had been cited for this

prestigious award. Power described the

Wabash Project as demonstrating “a technology to bridge the millennium...being

proven under the rigors of commercial

service.” The Powerplant awards are

given annually to recognize “leadership

in the application of fresh ideas and new

technology and equipment to minimize

environmental impact and maximize

efficiency.” Power revisited Wabash

in March 2000 by naming it to the

magazine’s “Power Plant Hall of Fame.”

The Wabash River plant has also

earned the Indiana Governor’s Award

for Excellence in Recycling.

Sargent & Lundy, engineer for the combined-cycle facility, won the American

Consulting Engineers Council’s 1996

Engineering Excellence Award.

Commercial

Applications

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. Such plants are

Five Powerplant Awards Presented to CCT

Projects by Power Magazine

• Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa

Electric Company) - 1997

• Wabash River Coal Gasification Repowering Project (Cinergy

Corporation/PSI Energy Inc.) - 1996

• Demonstration of Innovative Applications of Technology for the CT-121

FGD Process (Southern Company Services, Inc.) - 1994

• Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on

the Lake, L.P.) - 1993

• Tidd PFBC Demonstration Project (The Ohio Power Company) - 1991

envisioned in forward-thinking concepts such

as the DOE’s “Vision 21” initiative.

In 1999, DOE selected a team led by Global Energy Inc. to evaluate producing power

and methanol from an E-GASTM plant fueled

with coal and petroleum coke or other feedstocks. In this scenario, coal is gasified to

generate feedstock for a liquid phase methanol plant, using the LPMEOHTM process developed by Air Products and Chemicals, Inc.

Unreacted syngas flows to a combined-cycle

unit for power production. If the concept is

feasible, the team will develop an engineering package for a demonstration plant to be

built at the Wabash River site.

In the past, the manufacture of syngas to

produce chemicals has been the dominant

market for IGCC technology. Worldwide,

syngas-to-chemical applications currently

include 89 projects, accounting for over

18,000 MWth. Power generation, which currently accounts for approximately 11,000

MWth, is growing quickly and represents

most of the recent and planned capacity

additions, with 20 new projects planned to

generate over 10,000 MWth. Much of this

growth is in gasification-based power generation at oil refineries.
16

Future Developments

Demonstrated results of the Wabash

River project are expected to establish

the design basis for future power plants.

Improvements in both performance and

costs are likely based upon experience

gained in this project. As the technology

continues to mature and power plant

sizes increase, costs are expected to

decrease further. Performance improvements are expected as a result of enhancements in gasifier system and gas

turbine technology.

Cumulative Worldwide Gasification Capacity and Growth

Operation of the Wabash River IGCC

continues even though the CCT demonstration period has ended. The facility provides syngas to the PSI power plant under

a market based agreement that allows the

power produced from the syngas to compare favorably year-round to PSI’s alternate sources for on-peak and off-peak

power.

Future operation will continue to include coal as a feedstock, but will also

feature opportunity fuels such as low cost

petroleum coke. Introduction of biomass

feedstocks is also being evaluated. Potential new products for the syngas facility,

methanol for instance, are also being

evaluated.

MWth syngas

70,000

60,000

50,000

40,000

30,000

20,000

10,000

0

Note: 1 MWth=3,413,000 Btu/hr

Planned

Real

1970

1972

1974

1976

1978

1980

1982

1984

1986

1988

1990

1992

1994

1996

1998

2000

2002

2004
17

Design Actual Fuel

Coal

Coal Petroleum

Coke

Throughput, tons/day 2550 2450 2000

Syngas capacity, million Btu/hr 1780 1690 1690

Combustion turbine output, MWe 192 192 192

Steam turbine output, MWe 105 96 96

Parasitic power, MWe 35 36 36

Net power generation, MWe* 262 261 261

Overall thermal efficiency (HHV basis), % 37.8 39.7 40.2

*Failure of a feedwater heater at the combined cycle facility has resulted in

less steam available to the steam turbine generator, reducing its output. The

net power and thermal efficiency numbers shown in the table are corrected for

this abnormal operation.

Market Potential

A number of factors are converging that

contribute to the growth of gasificationbased power generation worldwide. These

factors include advances in gasification

technology; improved efficiency and reduced cost of gas turbines; fuel flexibility,

permitting use of lower quality, lower cost

feedstocks; and deregulation of the power

industry. This growth adds to an already

important role gasification technologies

have played in the production of chemicals

and transportation fuels.

Currently there are over 160 existing or

planned gasification projects worldwide,

representing a total of more than 410 gasifiers with a combined syngas output of

over 60,000 MWth. Conversion of all of

this syngas to electricity by means of

IGCC equates to over 33,000 MWe of

power equivalent. Of the total worldwide

capacity, gasification facilities currently

operating or under construction account for

about 130 plants with a total capacity of

about 43,000 MWth. The current annual

growth in gasification is about 3,000

MWth of syngas, or about 7% of the total

operating worldwide capacity. Planned

projects indicate that this growth will

likely continue through the next five years,

mostly in Western Europe, Asia, Australia,

and North America.

At present, the use of syngas to produce

chemicals is the dominant market for

IGCC technology worldwide. Power generation is gaining quickly, and represents

most of the recent and planned capacity

additions. Much of this growth is in gasification-based power generation at oil refineries.

Throughout the United States, there are

over 95,000 MWe of existing coal-fired

utility boilers that are more than 30 years

of age. Many of these plants are without

air pollution controls and are candidates

for repowering with IGCC. Repowering

these plants with IGCC systems would improve plant energy efficiencies and reduce

SO2, NOx, CO2, and particulate emissions.

Similar opportunities exist in foreign markets. The Wabash River CCT Project represents a prime example of repowering an

older power plant with IGCC. Gasification

is also experiencing increased utilization

in refineries, where it can utilize low cost

feedstocks like petroleum coke and other

bottom-of-the-barrel products to produce

power, steam and hydrogen.

IGCCs offer the advantages of modularity, rapid and staged on-line generation

capability, high efficiency, flexibility, environmental controllability, and reduced

use of land and natural resources. For these

reasons, IGCC technology is a strong contender in the market for new electric power

generation, and coproduction of power,

chemicals and fuels will become increasingly viable in a deregulated market.

Thermal Performance
18

Project Milestones

July 1990 Wabash River Joint Venture Project formed by Destec Energy and PSI Energy

May 1991 CCT IV proposal submitted to DOE by Wabash River Joint Venture

September 1991 CCT project selected by DOE

July 1992 Cooperative Agreement awarded

May 1993 Environmental permitting completed

July 1993 Construction started

October 1994 Cinergy Corporation formed, merging PSI with Cincinnati Gas & Electric Co.

August 1995 First gasifier run

November 1995 Construction completed and commercial operation started

February 1996 Achieved 100% capacity

June 1997 Destec Energy purchased by NGC Corporation (renamed Dynegy Inc. in 1998)

September 1998 Completed 14 months of OSHA recordable-free operation

September 1998 Began operation with blended feeds of coal and petroleum coke

December 1999 Dynegy’s gasification facility and technology purchased by Global Energy Inc.

December 1999 4 year demonstration completed

Conclusions

The Wabash River CCT project has

successfully demonstrated commercial application of the E-GASTM coal gasification

process in conjunction with electric power

generation. Power production met the target goal of 262 MWe (net). Carbon burnout

exceeds 95%, and emissions of SO2, NOx

and particulates are far below regulatory

requirements. Overall thermal efficiency

is about 20% higher than that of the station prior to repowering.

The Wabash River gasification facility

is the largest single-train gasification plant

currently in operation in the Western hemisphere. Along with other IGCC projects

demonstrated in the CCT Program, it is

one of the cleanest coal-based power generation facilities in the world.
19

Project Accomplishments

• World’s largest commercial single-train coal gasification combined-cycle plant when built.

• Successfully demonstrated IGCC technology to repower a 1950’s-vintage coal-fired power plant.

The repowered steam turbine operates as an integral part of the steam cycle.

• Repowering the existing steam turbine involved upgrading to accept increased steam flows. Required

modifications to refurbish and boost the capacity of the steam turbine have proven successful.

• Wabash River features the first “F” machine to operate on syngas. Advanced gas turbine design

allows for the use of higher firing temperature (2350 °F).

• The hot raw gas is cooled by producing steam at a pressure of up to 1,600 psia, compared with previous operation at about 600 psia.

• Syngas recycle provides fuel and process flexibility while maintaining high efficiency.

• The IGCC system delivers 262 MWe (net) to the Cinergy/PSI grid. Operation on the grid is stable.

Successfully operates on baseload dispatch.

• Overall thermal efficiency is 39.7%, which is about 20% higher than the existing station before

repowering.

• High-sulfur (2.0 to 3.5 %) bituminous coal and 5.5% sulfur petcoke is used successfully for power

generation.

• Use of COS hydrolysis, sour water treatment, and tail gas recycling technologies enables the project

to be the cleanest coal-fired power plant in the world.

• Product syngas sulfur content is well below the gas turbine manufacturer’s requirements.

• Acid gas treatment removes over 99% of the sulfur in the syngas, with overall sulfur recovery at better

than 97%. Sulfur byproduct is 99.99% pure.

• SO2 emissions are 0.03-0.10 lb/million Btu, less than one-tenth of the CAAA limit for 2000.

• Fuel gas moisturization reduces steam injection required for NOx control.

• NOx emissions are 0.15 lb/million Btu, meeting the Title I CAAA target for 2003.

• Particulate emissions are less than the detectable limit.

• Sour water treatment and tail gas recycling allow more complete recycling of combustible elements,

thereby increasing efficiency and reducing wastewater and emissions.

• Cinergy/PSI employees function as flexible workers. Only one job classification on site. All employees

trained to work multiple disciplines.

• Integration of the steam turbine, gas turbine and other systems with Westinghouse WDPF distributed

control system and GE Mark V controls was a first in the PSI system.

• An on-site simulator sponsored by EPRI was installed for use in operator and maintenance training.

• Optical pyrometry is used to monitor gas turbine blade temperatures on a real time basis.

• Named to Power Magazine’s “Power Plant Hall of Fame.”
20

The Clean Coal Technology Program

The Clean Coal Technology (CCT)

Program is a unique partnership between the federal government and

industry that has as its primary goal

the successful introduction of new

clean coal utilization technologies into

the energy marketplace. With its roots

in the acid rain debate of the 1980s,

the program is on the verge of meeting

its early objective of broadening the

range of technological solutions available to eliminate acid rain concerns

associated with coal use. Moreover,

the program has evolved and has been

expanded to address the need for new,

high-efficiency power-generating technologies that will allow coal to continue to be a fuel option well into the

21st century.

Begun in 1985 and expanded in

1987 consistent with the recommendation of the U.S. and Canadian Special

Envoys on Acid Rain, the program has

been implemented through a series

of five nationwide competitive solicitations. Each solicitation has been

associated with specific government

funding and program objectives. After

five solicitations, the CCT Program

comprises a total of 38 projects

located in 18 states with a capital

investment value of over $5 billion.

DOE’s share of the total project costs

is about $2 billion, or approximately 34

percent of the total. The projects’ industrial participants (i.e., the non-DOE

participants) are providing the

remainder—nearly $4 billion.

Clean coal technologies being demonstrated under the CCT Program are

establishing a technology base that

will enable the nation to meet more

stringent energy and environmental

goals. Most of the demonstrations are

being conducted at commercial scale,

in actual user environments, and

under circumstances typical of commercial operations. These features

allow the potential of the technologies

to be evaluated in their intended commercial applications. Each application

addresses one of the following four

market sectors:

• Advanced electric power

generation

• Environmental control devices

• Coal processing for clean fuels

• Industrial applications

Given its programmatic success,

the CCT Program serves as a model

for other cooperative government/

industry programs aimed at introducing new technologies into the

commercial marketplace.
21

Coal gasification has been

used for many years. Primitive

coal gasification provided town

gas worldwide more than 100

years ago, and a gasification

industry produced coal-based

transportation fuels for Germany

in World War II.

Today, coal gasification is

seeing increasing use. In the

U.S., a Texaco gasifier is utilized

in commercial operation at the

Tennessee Eastman chemical

plant in Kingsport, Tennessee

to produce synthesis gas for production of methanol. The Dakota

Gasification plant in North Dakota

produces substitute natural gas

and chemicals based on an advanced World War II gasification

technology.

Overseas, a major chemical

and transportation fuel industry

exists in The Republic of South

Africa, mostly based upon advancements of World War II gasification technologies. An IGCC

power plant is in operation in The

Netherlands. There are several

German gasifiers that are commercially available. Texaco gasifiers are in commercial operation,

or planned operation, in the

People’s Republic of China

and other nations.

Advanced gasification and IGCC

technology development began in

the U.S. in the 1960s, the stimuli being the desire for (1) development of

coal-based replacements for natural

gas and oil due to shortages and

price increases; and (2) more efficient, clean coal-based power

plants. Modern IGCC technology is

a response of U.S. government and

industry to these needs. Such systems use advanced pressurized coal

gasifiers to produce a fuel for gas

turbine-based electric power generation; the hot-gas turbine exhaust

produces steam to generate additional electricity.

The first commercial scale use

of a gasifier in a U.S. IGCC project

was the Cool Water Project in California, which was based upon the

Texaco coal gasification technology.

The Cool Water Project, which received major support from the U.S.

Synthetic Fuels Corporation, Southern California Edison Company,

EPRI (formerly the Electric Power

Research Institute), and others, was

instrumental in proving the feasibility

of IGCC, including their exceptional

environmental performance.

Gas turbines for power generation

have been one of the consequences

of jet aircraft engine development.

Initially utilized for peaking purposes

by utilities, their reliability, efficiency

and output have improved to the extent that they now also provide intermediate and baseload electric power.

It is projected that gas turbines and

IGCCs will contribute significantly to

future increases in power generation.

Today’s IGCC is efficient because

of major improvements that have

taken place in coal gasification and

gas turbine technologies, and a high

degree of system integration that efficiently recovers and uses waste heat.

Gas cleanup in an IGCC power

plant is relatively inexpensive compared with flue gas cleanup in conventional coal-fired steam power

plants. Smaller equipment is required

because a much smaller volume of

gas is cleaned. This results from the

fact that contaminants are removed

from the pressurized fuel gas before

combustion. In contrast, the volume

of flue gas from a coal-steam power

plant is much greater because of the

presence of nitrogen diluent from the

air and because the flue gas is

cleaned at atmospheric pressure.

Atmospheric emissions are very

low due to proven technologies for

highly effective removal of sulfur and

other contaminants from the syngas.

Advancements being demonstrated

in the CCT program are expected

to result in still better efficiencies.

Coal Gasification
22

Bibliography

Comprehensive Report to Congress, “Wabash

River Coal Gasification Repowering Project,”

proposed by Wabash River Coal Gasification

Project Joint Venture, June 1992.

D.G. Sundstrom, “The Wabash River Coal Gasification Repowering Project,” First Annual

Clean Coal Technology Conference (Cleveland

OH), September 1992.

P. Amick et al., “Wabash River Coal Gasification Repowering Project,” Twelfth Annual Gasification and Gas Stream Cleanup Conference

(Morgantown WV), September 1992.

Clean Coal Today, “Promise of Coal Gasification Power Draws 400 Representatives to

Wabash River Site,” p. 4, Summer 1993.

P. Amick and J. Cook, “The Wabash River

Coal Gasification Repowering Project Update,”

Second Annual Clean Coal Technology Conference (Atlanta GA), September 1993.

Clean Coal Today, “Largest U.S. Single Train

IGCC Facility,” pp. 4–5, Winter 1993/1994.

J.J. Cook and L.A. Lednicky, “The Wabash

River Coal Gasification Repowering Project—

An Investment in the Future,” Third Annual

Clean Coal Technology Conference (Chicago

IL), September 1994.

P.A. Pritchard and G.J. Starheim, “Turbine Developments for IGCC Applications,” Eleventh

Annual International Pittsburgh Coal Conference (Pittsburgh PA), v. 2, pp. 1543–1550, September 1994.

U.S. Department of Energy, Wabash River Coal

Gasification Repowering Project, Public Design

Report, DOE/MC29310-5260, July 1995.

M.R. Woodruff, “Wabash River Project Moves

into Commercial Operation,” Fourth Annual

Clean Coal Technology Conference (Denver

CO), September 1995.

Clean Coal Today, “O’Leary Heralds Wabash

Startup,” pp. 1–2, Winter 1995/1996.

Clean Coal Today, “Wabash Plant Begins Operating,” pp. 1–3, Spring 1996.

“Startup of Large-Scale Projects Casts Spotlight

on IGCC,” Power, June 1996.

“Compare Air-Blown to Oxygen-Blown Gasification,” Power, June 1996.

E.J. Troxclair et al., “Wabash River Coal Gasification Repowering Project—Early Commercial Operating Experience,” Thirteenth Annual

International Pittsburgh Coal Conference

(Pittsburgh PA), v. 1, p. 436, September 1996.

“Wabash Proves Out Next-Generation Gasifier,

Next-Century Power Plant,” Power, pp. 34–40,

September/October 1996.

Topical Report No. 7, “The Wabash River Coal

Gasification Repowering Project,” U.S. DOE,

November 1996.

E.J. Troxclair and J. Stultz, “Wabash River Coal

Gasification Repowering Project—First Year

Operation Experience,” Fifth Annual Clean

Coal Technology Conference (Tampa FL),

January 1997.

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Engineering, May 1997.

“IGCC Technology Offers Fuel Diversity,

Coproduction for Competitive Generation,”

Power Engineering, September 1997.

“IGCC Offers Diversity for Competitive Generation,” Power Engineering, November 1997.

C.G. Keeler and J. Stultz, “Operating Experience at Wabash River Coal Gasification Repowering Project,” Sixth Clean Coal Technology

Conference (Reno NV), April 1998.

“Preparing for the Millennium,” Power Engineering, November 1998.

S.L. Douglas, “Wabash River in its Fourth Year

of Commercial Operation,” Seventh Clean Coal

Technology Conference (Knoxville TN), June

1999.

C.G. Keeler, “Wabash River in its Fourth Year

of Commercial Operation,” 1999 Gasification

Technology Conference (San Francisco CA),

October 1999.

“IGCC Gathers Pace,” Power Engineering,

November 1999.

U.S. Department of Energy, Energy Information Administration, “Annual Energy Outlook

2000 with Projections to 2020,” December

1999.

“Cleaning Up on Economics,” Power Engineering, December 1999.

U.S. Department of Energy and the Gasification

Technologies Council, “Gasification—Worldwide Use and Acceptance,” January 2000.

“Merchant Power Projects Push for Competitive Edge,” Power, pp. 32-39, January/February

2000.

Clean Coal Today, “Wabash River Coal Gasification Repowering Project Completes Fourth

Year of Commercial Operation,” pp. 1-3,

Spring 2000.

P. Amick, “Commercial Operation of the

Wabash River Coal Gasification Repowering

Project,” Electric Power 2000 (Cincinnati OH),

April 2000.

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Technology Demonstration Program,

Program Update,” April 2000.

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Repowering Project—Final Technical

Report, September 2000.
23

Contacts for CCT Projects

and U.S. DOE CCT Program

Participant Contact

Phil Amick

Vice President, Commercial

 Development

Global Energy Inc.

1000 Louisiana St., Suite 1550

Houston TX 77002

(713) 374-7252

pramick@globalenergyinc.com

U.S. Department of Energy Contacts

Victor Der

Director, Office of Power Systems

U.S. Department of Energy, FE-24

Germantown MD 20874-1290

(301) 903-2700

(301) 903-2713 fax

victor.der@hq.doe.gov

Leo E. Makovsky

Project Manager

National Energy Technology

 Laboratory

P.O. Box 10940

Pittsburgh PA 15236-0940

(412) 386-5814

(412) 386-4775 fax

leo.makovsky@netl.doe.gov

Robert C. Porter

Director, Office of Communication

U.S. Department of Energy, FE-5

1000 Independence Ave SW

Washington DC 20585

(202) 586-6503

(202) 586-5146 fax

robert.porter@hq.doe.gov

Otis Mills Jr.

Public Information Office

U.S. Department of Energy

National Energy Technology

Laboratory

P.O. Box 10940

Pittsburgh PA 15236-0940

(412) 386-5890

(412) 386-6195 fax

otis.mills@netl.doe.gov

This report is available on the Internet

at U.S. DOE, Office of Fossil Energy’s home page: www.fe.doe.gov

and on the Clean Coal Technology Compendium home page:

www.lanl.doe.gov/projects/cctc

To Receive Additional

Information

To be placed on the Department

of Energy’s distribution list for future

information on the Clean Coal Technology Program, the demonstration

projects it is financing, or other Fossil

Energy Programs, please contact:
24

List of Acronyms and Abbreviations

Btu .................................................................................................................. British thermal unit

CAAA .................................................................................. Clean Air Act Amendments of 1990

CCT ......................................................................................................... Clean Coal Technology

CH4 ................................................................................................................................... methane

CO.......................................................................................................................carbon monoxide

CO2 .........................................................................................................................carbon dioxide

COS ......................................................................................................................carbonyl sulfide

DOE ................................................................................................... U.S. Department of Energy

EPA ................................................................................ U.S. Environmental Protection Agency

EPRI ....................................................................formerly the Electric Power Research Institute

HRSG ............................................................................................ heat recovery steam generator

H2S ..................................................................................................................... hydrogen sulfide

IGCC ............................................................................... integrated gasification combined-cycle

kWh .......................................................................................................................... kilowatt hour

LGTI ............................................................................. Louisiana Gasification Technology, Inc.

LPMEOHTM................................................................................. Liquid Phase Methanol process

MWe ................................................................................................. megawatts of electric power

MWh .......................................................................................................................megawatt hour

MWth........................................... megawatts of thermal power (1 MWth = 3.413 x 106 Btu/hr)

ND .......................................................................................................................... non-detectable

NETL ............................................................................ National Energy Technology Laboratory

NH3 .................................................................................................................................. ammonia

NOx ....................................................................................................................... nitrogen oxides

NSPS ................................................................................... New Source Performance Standards

O2 ........................................................................................................................................ oxygen

PM ..................................................................................................................... particulate matter

ppmv .................................................................................................. parts per million by volume

psia............................................................................pressure, pounds per square inch (absolute)

psig .............................................................................. pressure, pounds per square inch (gauge)

SO2 .......................................................................................................................... sulfur dioxide

syngas ....................................................................................................................... synthesis gas

vol %................................................................................................................. percent by volume

wt % ................................................................................................................... percent by weight