TOPICAL REPORT NUMBER 7

The Wabash River

Coal Gasification

Repowering Project

A 262 MWe Commercial Scale

Integrated Gasification

Combined Cycle Power Plant

A report on a project conducted jointly under a

cooperative agreement between:

The United States Department of Energy

 and Wabash River Coal Gasification Project Joint Venture

NOVEMBER 1996
Cover Image: View of the Wabash

River Coal Gasification

Repowering project

with the Wabash River

and the flat terrain of

west central Indiana in

the background.

Preparation and printing of this document conforms to the general funding provisions of a

cooperative agreement between Destec Energy Inc., PSI Energy, Inc., and the U.S. Department of Energy. The funding contribution

of the industrial participant permitted inclusion

of multicolored artwork and photographs at no

additional expense to the U.S. Government.
The Wabash River

Coal Gasification

Repowering Project

Introduction and Executive Summary ........................................................ 2

Background ................................................................................................ 4

Participant .................................................................................................. 5

Project Description .................................................................................... 7

Process Description ................................................................................... 12

Schedule/Demonstration Milestones ........................................................ 15

Results ....................................................................................................... 17

Future ........................................................................................................ 18

Bibliography .............................................................................................. 19

Clean Coal Technology Program .............................................................. 20

Contacts ..................................................................................................... 21

 List of Acronyms and Abbreviations ....................................................... 22

TECHNOLOGY
Introduction and

Executive Summary

Coal is America’s most abundant fossil

fuel. Its combustion creates the steam that

produces 65 percent of this country’s electricity. The burning of coal, however, liberates two types of gases that have been

linked to the formation of acid rain: nitrogen oxides (NOX) and sulfur dioxide (SO2).

With the passage of each successive

piece of clean air legislation over the years,

the electric utility industry has been made

increasingly aware that it would eventually

have to reduce both types of emissions from

existing and new power plants to environmentally acceptable levels.

The Clean Coal Technology (CCT)

Demonstration Program is a government and

industry co-funded program to furnish the

U.S. energy marketplace with advanced,

more efficient and environmentally responsible coal-utilizing technologies.

A multi-phased effort consisting of five

separate solicitations was administered by

the U.S. Department of Energy (DOE).

Projects selected are a new generation of

innovative coal utilization processes that

are being demonstrated in "showcase"

projects conducted across the country.

These projects are on a scale sufficiently large to demonstrate commercial

worthiness and generate data for design,

construction, operation and technical/economic evaluation of full-scale commercial

applications.

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 technology that combines modern

coal gasification with gas turbine and steam

2

power generation technologies. Fuel gas

produced by a gasifier is cleaned and

burned in a gas turbine to produce electric

power. Heat recovered from the hot turbine’s exhaust produces steam that turns a

steam turbine generator to produce more

electricity.

IGCC power plants are environmentally

acceptable and easily sited. Atmospheric

emissions of pollutants are low. Water use

is lower than conventional coal-based generation because gas turbine units require no

cooling water, an especially important consideration in areas of limited water resources.

Due to their high efficiency, less coal is

used per megawatt-hour of output, causing

IGCC power plants to emit less carbon

dioxide (CO2) to the atmosphere, thereby

decreasing global warming concerns. Less

coal use also reduces disposal requirements

for ash or slag if there is no market for these

materials.

Repowering is an excellent application

for IGCC. Such applications utilize an

existing power plant site and are more

economical than greenfield applications.

Costs are lower because an existing steam

turbine is used, less site development is

required, and the permitting process is

accelerated.

Both greenfield and repowering IGCC

could provide the flexibility needed for

utility compliance planning for SO2

emissions in the next century. Providing

25 percent of coal-based electricity by

IGCC would result in emissions of less

than 0.4 million of the 11.8 million tons/yr

of SO2 allowable under the Clean Air Act

Amendments (CAAA).

Modularity and fuel flexibility are other

important attributes of IGCC power plants.

Before the gasifier is constructed, the combined cycle unit can be operated on other

fuels, such as natural gas or fuel oil, to provide early power. The size of gas turbine

units can be chosen to meet specific power

requirements. The ability to operate on

multiple fuels allows continued operation

of the gas turbine unit if the gasifier island

is shut down for maintenance or repairs, or

if warranted by fuel costs.

IGCC power plants use plentiful and

relatively inexpensive coal as their fuel. In

the United States there are several hundred

years of reserves, and use of coal helps to

reduce dependence on foreign oil.

IGCC has potential for significant reduction in capital costs over today’s technologies, per kW of generation. These, in part,

arise from higher possible efficiencies compared to today’s impressive IGCC values.

Efficiency improvements are expected

to result from design improvements which

increase overall steam and thermal integration, use of higher firing temperature gas

turbines, and other technology enhancements such as hot-gas cleanup. Other

contributors to reduced capital costs are:

economies of scale, reduced engineering

costs, and improvements resulting from

operating experience.

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
Executive Summary

The Wabash River Coal Gasification

Repowering Project (the Project) was selected in September 1991 by DOE as a

CCT Program Round IV demonstration

project. Demonstration of this advanced

IGCC power plant was initiated in

December, 1995.

The Participant is Wabash River Coal

Gasification Repowering Project Joint

Venture, formed in 1990 by Destec Energy

Inc. (Destec), of Houston, Texas and PSI

Energy, Inc. (PSI), of Plainfield, Indiana.

They formed this joint venture to demonstrate coal gasification repowering of an

existing PSI generating unit. The Cooperative Agreement with the DOE was signed

in July 1992.

The Project is located at PSI’s Wabash

River Generating Station near West Terre

Haute, Indiana. It is demonstrating utility

repowering with a Destec two-stage, oxygen-blown gasification system, including

advancements in the technology relevant

to the use of high-sulfur bituminous coal.

The Project demonstrates the integration of Destec’s gasification process

with a combined cycle unit based on an

advanced General Electric gas turbine

generator to repower a refurbished steam

turbine generator. Now in commercial

operation, the Project is the world’s

largest single-train IGCC power plant.

Local Indiana high-sulfur coal is processed

to produce 262 MWe (net) of clean, lowcost, energy efficient baseload capacity.

A Destec gasifier in this IGCC power

plant converts coal to a synthetic fuel gas

that is cleaned of impurities and burned in

a combined cycle unit to produce electricity. At least 98 percent of sulfur contaminants are removed. Sulfur is recovered

and sold, as is the slag by-product of gasification. Emissions are lower than from

conventional power plants operating on

high sulfur coal.

The efficiency of the Wabash River

IGCC power plant is a 20 percent improvement over the pre-project derated

condition of the repowered steam turbine.

This facility has the lowest capital cost in

terms of $/kW of all past and current

IGCC demonstration plants.

Due to the high gasifier operating

temperature, only a single gasifier is

needed to process the 2544 tons of coal

per day required for the Wabash River

Coal Gasification Repowering Project.

The repowered power plant is designed to be efficient, with a heat rate of

about 9030 Btu/kWh (37.8 percent

efficiency), higher heating value basis.

The capital cost, including startup costs, is

$417 million, or about $1585/kW.

The demonstration period began in

December 1995, when the facility satisfied

performance requirements specified by the

lending institution and the commercial

agreement between the Participants. Detailed performance, operating and maintenance data will be gathered during the

three-year test period to demonstrate the

effectiveness and economic viability of

the technology in a commercial utility

environment.

For its role in hosting, funding, and

operating this "next-millenium" power

plant, PSI, Destec and DOE were awarded

Power magazine’s 1996 Powerplant award.

3
 The Wabash River

 Coal Gasification

Repowering Project

Background

Coal gasification has been used worldide for many years. Primitive coal gasifiation provided town gas more than 100

years ago, and a gasification industry produced coal-based transportation fuels for

Germany in World War 11.

Today, in Tennessee, a U.S. gasification

technology proven in a CCT Round I program is used for methanol production. The

Dakota Gasification plant in North Dakota

produces synthetic natural gas and chemicals based on an advanced German gasification technology. Overseas, a major chemical

and transportation fuel industry exists in

The Republic of South Africa, mostly based

upon advanced German gasification technologies. And an IGCC power plant is operation in The Netherlands.

4

Advanced gasification and IGCC

technology development began in the

U.S. about 25 years ago, the stimuli being

the desire for: (1) development of a coalbased replacement for natural gas and

oil due to shortages and price increases;

and (2) more efficient, clean, coal-based

power plants.

Modem 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 Dow Chemical Company initiated

development of its coal gasification technology in the early 1970s when it sought

a low cost replacement for natural gas fuel

for gas turbine generator units at its chlor

alkali plants. After a development program

involving several pilot plants, the 2400 ton
per day Louisiana Gasification Technology, Inc.(LGTI)

facility was built at Dow’s

Plaquemine, Louisiana plant.

Ownership of the technology

and LGTI was transferred

from Dow when Destec was

formed by Dow in 1989.

The facility was operated for

about eight years and accumulated about 34,000 hours

of operating experience.

Gas turbines for power

generation have been one

of the consequences of jet

aircraft engine development. They have been increasingly used by electric

utilities and by the end of

1994, gas turbines contributed about 12 percent

(59,600 MWe) to the fossil

fuel-based generating capability of U.S. electric utilities.

Gas turbine and combined cycle generation capability in the U.S. increased by 23

percent over the period 1990-1994 even

though the total fossil-based generation capability increased by only one percent.

This increasing use is due to technology

advances, relatively low cost per kW and

shorter construction time than conventional generation. Advances in design and

materials have led to major increases in the

size and performance capability of gas turbine units.

Today’s IGCC is efficient because of

major improvements in coal gasification,

gas cleanup, and gas turbine technologies—

plus a high degree of system integration

that efficiently recovers and uses waste

heat. Atmospheric emissions are low due

to availability of proven technologies for

highly effective removal of sulfur and

other contaminants from the fuel gas. Advancements demonstrated in the CCT program are expected to result in still

better performance.

Participant

The Participant with DOE in this

project is Wabash River Coal Gasification Project Joint Venture. Destec

Energy, Inc. and PSI Energy, Inc. (PSI)

are the partners in this joint venture.

They have completed a Gasification

Services Agreement that contains the

commercial terms for development and

operation of the Project. PSI, the host

utility, is responsible for financing, constructing, and operating the power block

and Destec for financing, constructing,

and operating the gasification facility.

PSI is an investor owned utility whose

service area covers 69 of the 92 counties

The Wabash River lGCC power plant. The

gas cleanup system is on the left and the

combustion turbine/HRSG unit is in the

center. The Wabash River coal-steam

plant is in the background by the Wabash

River; repowered Unit 1 is on the left.

5
in Indiana. With Cincinnati Gas & Electric

Company, it is owned by CINergy Corp.

which was formed in October 1994.

CINergy is one of the twenty largest electric utilities in the U.S. PSI is participating

in this Project because it wants to demonstrate an alternative technology for new

units and repowering of existing units.

Destec is a major independent power

company that owns power generation and

coal gasification facilities which produce,

sell and market electricity, steam and synthetic fuel gas worldwide. Destec has operating and/or equity participation in over

5000 MWe of electric generation, much of

which was developed and constructed by

Destec. Dow formed and has a majority

interest in Destec.

Gasification Services

Agreement Provisions

PSI:

• Build, own and operate the

power generation facility

• Furnish Destec with a site,

coal, electric power, storm

water and wastewater facilities,

and other utilities and services

• Pay a monthly fee to Destec

for gasification services

Destec:

• Build, own and operate the

coal gasification facility

• Guarantee operating and

environmental performance

• Deliver syngas and steam to

the power generation facility

6

Destec is participating in the Project

because it wants to enhance the competitive position of its gasification technology.

It wishes to verify performance expectations and gain information about capital

and operating costs. It seeks to obtain

the data base and experience necessary to

meet commercial markets for this

technology.

Together, PSI and Destec seek to optimize the cost-effectiveness of the overall

system including individual system elements. They seek to optimize operating,

maintenance, and management disciplines,

and otherwise advance the technology.

New Generating Capacity Forecast

1994-2015

DOE projects that over the period 1994-2015, gas turbine and

combined-cycle based generation will be 78 percent (197,000

MWe) of the total new capacity additions of utility plus non-utility

generators (252,000 Me).

Source: U.S. Energy Information Administration, 1996
Project Description

This Project is demonstrating integration

of Destec’s gasification process with a GE

model MS 7001FA gas turbine generator,

a heat recovery steam generator (HRSG),

and the refurbished Unit 1 (of 6) steam

turbine generator of the Wabash River

Generating Station.

This IGCC power plant is expected to

function as a substantial element of PSI’s

plan to comply with the Clean Air Act

Amendments of 1990 (CAAA) with sulfur

dioxide (SO2) emissions as low as 0.02 lb/

million Btu of fuel. Emissions are expected

to be less than the CAAA Phase II limits

for the year 2000. The efficiency of the

repowered unit is expected to be about

20 percent better than its pre-project

derated condition.

Due to the anticipated low cost of electricity, CINergy plans to dispatch the output

of the Wabash River Coal Gasification

Repowering Project second behind its

hydro facilities.

The electric utility industry will benefit

from expected future improvements in the

Project technology. Experience gained

and improvements realized from this and

future projects will result in still better

power plant efficiency and lower operating

and maintenance costs. A proven power

plant technology will be available that is

highly efficient, reliable, environmentally

acceptable and cost effective.

Consumers and society will benefit

through low cost electricity and reduced

reliance on foreign energy sources. The

environment will benefit through low

emissions of atmospheric pollutants and

reduced emissions of greenhouse gases.

Destec will benefit as owner of the

gasification technology and potential

owner/operator of all or part of future

Destec-based IGCC power plants.

lGCC power plant. The Destec 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.

7
Project Subcontractors

Project Team

 Combined Cycle Facility

 Project Management PSI Energy, Inc.

 Engineer Sargent & Lund

 Construction Management PSI Energy, Inc.

 Gas Turbine Vendor General Electric Company

 HRSG Vendor Foster Wheeler Energy Corp.

Gasification Facility

 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.

Wabash River gasifier/combustion turbine/HRSG train during construction.

The pipe rack, foreground, connects to the repowered steam turbine Unit 1.

8

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 interface to Destec.

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 gasification island

facilities, including a control, administration and maintenance building and one

of the largest air separation facilities in

North America.

Site Description

The site is located in a predominantly

rural area on the Wabash River near West

Terre Haute, Vigo County, Indiana. PSI’s

Wabash River station was originally a

mine mouth power plant, and much of the

new facility is actually built over areas

that were shaft mined earlier this 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.

The new coal gasification repowering

facilities are 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 on a hill overlooking the existing
lGCC Emissions are Substantially Less Than Pre-Repowering Values

Emissions, lb/Megawatt-hour SO2 NOX CO PM PM-10 voc

Pre-Repowering Unit 1 Boiler 38.2 9.3 0.64 0.85 0.85 0.03

lGCC 0.21 0.75 0.47 0.07 0.06 0.02

Emissions, lb/Million Btu SO2 NOX CO PM PM-10 voc

Pre-Repowering Unit 1 Boiler 3.1 0.8 0.05 0.07 0.07 0.003

lGCC 0.02 0.08 0.05 0.01 0.01 0.003

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

The consequence is an improvement in air quality

station. New wastewater and storm water

ponds are located nearby in an area previously used as an ash pond.

Environmental

Expected environmental impacts of the

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 DOE’s development of 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

have been obtained. A process and

environmental monitoring program has

been established in compliance with

requirements.

The plant is designed to substantially

outperform emission standards for the

year 2000 established by the CAAA. The

Destec gasification technology removes at

least 98 percent of the sulfur in the coal.

Compared to previous operation of the

steam turbine, carbon dioxide (CO2)

emissions are reduced by approximately

20 percent on a per kilowatt-hour basis.

Even though power generation from

the project is almost three times that of

the original unit, emissions are reduced

because of IGCC operation.

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

percent (dry basis) and a higher heating

value of over 13,500 l3tuAb (MAF). The

coal selected for initial operation is a high

sulfur midwestern bituminous from the

number 6 seam at Peabody’s Hawthorn

Mine in Indiana. It is stored apart from

Coal Properties

Moisture 5-18%

Ash (as received) 5-15%

Sulfur (dry) 2.3-5.9%

Ash Fusion Temperature 1000-2500°F

Heating Value (MAF) Over 13,500 Btu/Ib

(higher heating value basis)

9
Advanced Features

of the

Gasifier Island

• 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.

• 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.

10

the compliance coal burned in Units 2-6

of the existing station.

Alternative feedstocks may be tested

for up to 60 days each year of the threeyear demonstration period.

Review of Technology

The design of the Wabash River Coal

Gasification Repowering Project gasifier is

based on that of Destec’s LGTI gasifier,

which is similar in size and operating

characteristics to the Project gasifier.

LGTI was operated for more than

34,000 hours from April 1987 through

November 1995. Experience gained provided significant input to the design of the

Wabash River coal gasification facility

and eliminates much of the risk associated

with scaleup and process variables.

A coal/water slurry feed is prepared

and, with oxygen, fed to the first stage of

the Destec 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, with production of

steam for power generation.

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 per day of coal required

for operation of the IGCC

power plant although two

vessels, each of 100 percent

capacity, have been installed.

The particle-free gas is further cooled

to ambient temperature and at least 98 percent of sulfur contaminants are removed

by a proven technology. High quality

sulfur (over 99.9 percent pure) is recovered and sold for agricultural applications.

The slag by-product of gasification can be

used for applications such as road paving

and roof shingles.

The heating value of the cleaned fuel

gas is approximately 285 Btu/SCF (dry

basis). The cleaned gas is moisturized to

aid in control of NOX emissions, heated

and fed to General Electric's model MS

7001FA gas turbine where it is combusted.

Gas turbine exhaust heat is recovered in an

HRSG to produce steam for production of

electricity. Flue gas is emitted to the

atmosphere via a 225 foot stack.

(text continues on page 14)

Typical Operational

Characteristics

Fuel Gas Burn Rate 442,000 lb/hr

 Gas Turbine Output 192,000 kW

NOX Control Steam 111,260 lb/hr

Exhaust Gas Rate 3,775,000 lb/hr

Exhaust Gas Temperature 1,100°F

Main Steam Flow 732,200 lb/hr

Reheat Steam Flow 560,000 lb/hr

Steam Turbine Generator Output 104,990 kW

Auxiliary Power 35,380 kW

Net Plant Output 261,610 kW

Net Plant Heat Rate, HHV 9030 Btu/kWh

Water Makeup 535 gpm
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.

11
Process Description

Destec Coal Gasification

The Destec two-stage coal gasification

technology features an oxygen-blown,

entrained flow, continuous slagging, refractory lined gasifier. The first stage operates

at about 2,500°F and 400 psia. The actual

operating temperature depends upon the

specific coal used. A 60/40 weight percent

coal/water slurry is combined with oxygen

and injected into the gasifier. The coal undergoes partial combustion, releasing heat

that causes the coal 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. Oxygen of 95 percent purity is supplied by a

turnkey, dedicated air separation unit.

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 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 IGCC

system.

Only a single gasifier is required to process the 2544 tons per day of coal re-quired

for operation of the IGCC power plant, although two vessels, each of 100 percent

capacity, have been installed.

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

in parallel convection heat exchangers,

producing high pressure (1600 psia) saturated steam.

Gas Cleanup

Gas cleanup equipment in an IGCC

power plant is relatively inexpensive compared to flue gas cleanup in a conventional

coal-steam power plant. Smaller equipment

is required because a much smaller volume

of gas is cleaned.

The gas volume is smaller because the

coal gas is still pressurized before cleaning

and subsequent combustion. In contrast, the

volume of flue gas from a coal-steam power

plant is greater because the fuel has been

combusted at atmospheric pressure before

the flue gas is cleaned.

Flyash and remaining char particles in the

gas exiting the second stage are removed by

a hot 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

level of their removal for the power plant to

achieve the low design level of SO2

emissions. H2S is removed by an acid gas

removal system; however, because COS is

not readily removable it is first catalytically

converted to H2S in a hydrolysis unit.

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.

The cooled syngas flows to the acid gas

removal absorber column where H2S is removed by a solvent, methyldiethanol amine

(MDEA), to produce clean syngas. 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 a 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, thereby retaining this sulfur

compound within the system.

The particle-free gas is further cooled to

near ambient temperature, and over 98

percent of sulfur contaminants are removed

by conventional sulfur recovery technology.

High quality sulfur (over 99.99 percent

pure) is recovered and sold. The slag

by-product of gasification is sold for

agricultural and construction applications.

Water Treatment and Recycle

In the water treatment system, dissolved

gaseous contaminants are removed. The

CO2 and H2S are removed first and 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 and discharged to the pond for

subsequent discharge to the river through

the permitted discharge point.

12
Typical Clean Syngas Composition

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 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

754,000lb/hr of high pressure steam at 1010°F

543°) and 600,820 lb/hr of reheat steam at

1010° (543°) when the gas turbine operates on

syngas.

The repowered steam turbine unit No. 1,

originally installed in 1952, was derated from

105 MWe to 90 MWe when a reduction in coal

consumption was necessary to reduce stack

emissions. The unit was refurbished to accept

the increased steam flows and pressures

associated with the combined cycle operation.

Output has been restored to 105 MWe.

The auxiliary load for the Project is 35

MWe. This consists of power to operate the

air separation unit, motors, pumps, and other

electrical requirements.

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 foot stack.

(After final moisturization—as delivered to gas turbine)

Component Volume

 Percent

H2 28

CO 38

CO2 10

CH4 1

N2 1

H2O 22

Sulfur compounds 100 ppmv

Higher heating value, dry 285 Btu/SCF

Lower heating value, dry 223 Btu/SCF

Simplified Destec Gasification Chemistry

First Stage

C (coal) + O2 CO2 + Heat

C (coal) + H2O (steam) H2 + CO

2S (coal) + H2 + CO COS + H2S

Second Stage

C (coal) + Heat Cracked devolatilization

 products (CDP)

CDP + H2O H2 + CO + CH4

C(coal) + H2O H2 + CO

2S + H2 + CO COS + H2S

13
Destec Two-Stage Entrained Flow Gasifier

14

Project Efficiency and Cost

The repowered power plant is quite

efficient, having a design heat rate of about

9030 Btu/kWh (37.8 percent efficiency),

higher heating value basis.

The total cost for the Project is approximately $438 million, including escalation,

environmental and permitting costs, startup

costs, license fees and demonstration programs. Costs are equally shared by DOE

and the joint venture. Repowering the

Unit 1 steam turbine and reusing ancillaries from the existing plant has saved the

Project about $30-$40 million.

Demonstration

Project Costs

Demonstration

Project Cost $438.2 million

U.S. DOE $219.1 million

Participant $219.1 million

Demonstration project costs

include permitting, engineering

procurement, and construction,

startup and pre-operations

costs for the gasification, air

separation and power generation facilities. Operating costs

(except coal) during the threeyear demonstration period are

also included. The total capital

cost of the IGCC power plant,

including startup, is $417 million.
Schedule/Demonstration

Milestones

Project Schedule

DOE’s involvement in the Project extends

over almost eight years, beginning June 1,

1991 with the definition of the scope in the

Participant’s proposal and concluding March

1, 1999 with the completion of the three-year

demonstration period. The IGCC power plant

will be operated for a total of 25 years.

Construction

Construction of foundations and steel erection commenced in September 1993 and

was complete in October 1995. Construction

activities in the first year were hampered by

unusually severe weather conditions. To stay

on schedule, both PSI and Destec selectively

employed seven-day construction schedules.

Peak construction activity brought over

1,300 workers to the site daily. Support from

local labor unions and contractors was

critical to maintaining the Project schedule.

Major equipment began arriving in

early 1994 and all major pieces were in

place by August. By mid-June 1995

virtually all of the 157 subsystems were

turned over to operations personnel.

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.

The first gasifier run (23 hours) took place

without significant problems on August 25,

1995. First gas turbine operation on syngas

took place October 3, 1995. Commercial

operation of the gasification facility was

Wabash River Coal Gasification Repowering Project site during early construction.

Same view as above-well into construction.

15
Selected Achievements

achieved November 18, 1995, kicking off the

planned 25 year operating life of the facility.

Barely four months into the demonstration

period, in mid-February 1996, the Wabash River

Coal Gasification Repowering Project was operated continuously for over 12 consecutive days

with all parameters at acceptable levels. The

gasifier achieved 100 percent capacity for the

first time and produced the most syngas ever

from a single train gasification plant. The gas

turbine also achieved 100 percent of rated load

on syngas by generating 192 MWe.

Objectives

PSI’s major objectives involve making this

facility an effective part of their baseload capacity, and to demonstrate the operability,

effectiveness and economic viability of the

technology on a commercial scale and in a

commercial environment. PSI desires to maintain or improve the dispatch status of the facility, while managing costs. PSI will separately

track its operating and maintenance (O&M)

costs according to labor, material, and fuel,

capital expenditures, major overhaul expenditures, and preventable recurring costs.

May 1991 Clean Coal IV Proposal Submitted

September 1991 Project Selected

May 1993 Environmental Permitting Completed

September 1993 Construction Started

June 1995 CT/CC Synchronized on Fuel Oil

August 1995 First Gasifier Run

October 1995 CT/CC Synchronized on Syngas

November 1995 Completed Initial Testing

Started Commercial Operation

December 1995 Started Demonstration Period

February 1996 Achieved 100% Capacity

General Electric model MS 7001FA Gas Turbine.

16

Destec will closely monitor the performance

of key subsystems and components. In addition, Destec plans to manage the gasifier island

for continuous improvement, setting the stage

and creating a standard for operation of the

next Destec gasification facility.

Other focuses of the demonstration are to

show operation on the PSI grid, demonstrate

the operability of the thermal integration between the gasification and power blocks,

define the boundaries of operability of the

overall plant, and establish a baseline for

O&M costs.

Together, the Participants will monitor the

facility’s ability to meet the requirements of its

commercial environment. Monitoring includes startup and shutdown times and costs,

ramp rates on load changes, turndown ratios,

stability of the plant at various loads, optimization of maintenance cycles, factors that degrade
performance, and verification of dynamic

system response and controls.

Since dispatch status is a function of

both environmental and cost performance,

the information representing such performance will be evaluated. Finally, since

coal is the single largest energy cost component, PSI will continually pursue the

lowest cost coal which meets the quality

requirements.

Results

The Wabash River facility began commercial operation in November 1995. This

section gives production statistics for the

gasification and combined cycle facilities

through October 1996.

Operations of most of the process units

in the IGCC facility have met or exceeded

expectations. The gas turbine generator’s

fuel consumption at design output is well

below the design guarantee, causing the

plant heat rate to be improved over design.

The gasification facility has demonstrated

outputs of up to 103% of design.

Sulfur emission rates of less than 0.1 lb/

million Btu (coal input basis) have been

consistently demonstrated, which are better

than the plant design point of 0.2 lb/ million

Btu and greatly surpass the 1.2 lb/ million

Btu guideline for the year 2000 as set by the

CAAA.

In the gasification plant, the slurry

preparation, gasification, high temperature

heat recovery, acid gas removal and continuous slag handling systems have all

functioned well. The combustion turbine,

steam turbine and water treatment system at

the power generation facility have also

operated satisfactorily.

The early operation has been marked by

significant problems in certain process units.

As expected, the areas of the newest technology have produced the majority of the

downtime for the plant. At the gasification

Early Performance

Design Actual

Plant Heat Rate, Btu/kWh (HHV) 9030 8910

Combustion Turbine Output, MWe 192 192

Steam Turbine Output, MWe 105 96

Auxiliary Power, MWe 35 36

Net Power Output, MWe 262 252

Sulfur Removal Efficiency, % >98 >99

Production Statistics through October 1996

Gasification Plant Production Statistics

First Coal Gasified August 17, 1995

Total Gasifier Hours on Coal 2035

Total Syngas Produced—106

Btu (dry) 2,838,628

Total Coal Processed—tons 189,233

Highest Capacity Demonstrated—106

 Btu/hr (HHV) 1825

% Nameplate 103%

Longest Continuous Coal Run—hours 253

Cold Gas Efficiency—percent >74

Combined Cycle Plant Production Statistics

First Syngas to Combustion Turbine (CT) October 3, 1995

Total CT Hours 2536

Total CT Hours on Syngas 1061

MWh Produced on Syngas 175,269

Highest CT Capacity Demonstrated—MWe 192

% Nameplate 100%

Longest Continuous Syngas Operation—hours 151

17
Air Separation Unit (foreground).

Destec gasifier structure under

construction (upper right).

18

facility, problems in the

particulate removal

system have resulted in

repeated outages, constituting the majority of

the plant’s downtime,

and prompting modifications to this process

area. The gasification

facility has also seen

downtime due to metallurgical problems in the

low temperature heat

recovery systems.

The power generation facility has had few

major problem areas

since the start of commercial operation,

although the gas turbine

HRSG will require

some modifications to

allow the plant to

achieve its best efficiency point.

Feedwater heating problems have required use of a portion of the high

pressure steam for direct condensate

heating in the deaerator rather than power

production in the steam turbine. This has

caused the maximum net output in the first

eight months to be 252 MWe, instead of

the design value of 262 MWe. The plant

is expected to achieve the rated output

when this problem is corrected.

The plant heat rate, already about one

and one half percent better than the design

point, is expected to improve to the 8600–

8700 Btu/kWh range (39–40 percent efficiency), higher heating value basis, when

plant systems are optimized.

Future

Results of the Wabash River Coal Gasification Repowering Project are expected

to establish the basis for future power

plants based upon the demonstrated technologies. Improvements in both performance and costs based upon experience

gained in this project are likely. As the

technology matures and power plant sizes

increase, costs are expected to decrease

further, and performance to improve. The

performance improvements will stem from

gasifier system enhancements, improved

overall steam conditions and thermal

integration, use of commercially available

hot-gas cleanup, and advances in gas

turbine technology.

Destec and DOE estimate that future

IGCC greenfield power plants based upon

mature and improved technology will cost

$1000–$1350/kW (1995 basis), and will

have a heat rate in the range of 7000–7500

Btu/kWh (46–49 percent efficiency),

higher heating value basis. Costs will be

further reduced if an existing steam turbine

is repowered and existing site infrastructure utilized.
Bibliography

Amick, P. and Cook, J., "The Wabash

River Coal Gasification Repowering

Project Update," U.S. DOE Second

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

Amick, P. et al., "Wabash River Coal

Gasification Repowering Project,"

Twelfth Annual Gasification and Gas

Stream Cleanup Conference (Morgantown WV), September 1992.

Clean Coal Today, "Largest U.S. Single

Train IGCC Facility," pp. 4-5, Winter

1993/1994.

Clean Coal Today, "O’Leary Heralds

Wabash Startup," pp. 1-2, Winter

1995/1996.

Clean Coal Today, "Promise of Coal Gasification Power Draws 400 Representatives

to Wabash River Site," p.4, Summer 1993.

Clean Coal Today, "Wabash Plant Begins

Operations," pp. 1-3, Spring 1996.

Cook, J.J. and Lednicky, L.A., "The

Wabash River Coal Gasification Repowering Project-An Investment in the

Future," U.S. DOE Third Annual Clean

Coal Technology Conference (Chicago

IL), September 6-8, 1994.

Energy Information Administration,

Office of Integrated Analysis and Forecasting, Annual Energy Outlook 1996

with Projections to 2015, DOE/EIA0383(96), January 1996.

Makansi, J., "Wabash Proves Out NextGeneration Gasifier, Next-Century Power

Plant," Power, pp. 34–40, September/

October 1996

Power, "IGCC Takes a Bold Leap

Forward," pp. 81–84, April 1996.

Pritchard, P.A. and Starheim, G.J., "Turbine Developments for IGCC Applications," Eleventh Annual International

Pittsburgh Coal Conference (Pittsburgh

PA), v. 2, pp. 1543-1550, September 1994.

Stambler, I., "Progress in IGCC and Advanced Cycles Outlined at EPRI Meeting,"

Gas Turbine World, pp. 16–23, January/

February 1996

Sundstrom, D.G., "The Wabash River

Coal Gasification Repowering Project,"

U.S. DOE First Annual Clean Coal

Technology Conference Proceedings

(Cleveland OH), September 22-24. 1992.

Swanekamp, R., "Startup of Large-Scale

Projects Casts Spotlight on IGCC,"

Power, pp. 59-68, June 1996.

Troxclair, E.J. 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.

U.S. Department of Energy, Clean Coal

Technology Demonstration Program—

Program Update 1995, pp. 6-4, 7-28, 7-29,

DOE/FE-0346, April 1996.

U.S. Department of Energy, "Wabash

River Coal Gasification Repowering

Project," Comprehensive Report to Congress, Clean Coal Technology Program,

DOE/FE-0257P, June 1992.

U.S. Department of Energy, Integrated

Gasification Combined Cycle, Brochure,

Morgantown Energy Technology Center,

1993

U.S. Department of Energy, Wabash River

Coal Gasification Repowering Project,

DOE/MC29310-3840, January 1994.

U.S. Department of Energy, Wabash River

Coal Gasification Repowering Project,

Public Design Report, DOE/MC29310-

5260, July 1995.

Woodruff, M.R., "Wabash River Project

Moves into Commercial Operation,"

U.S. DOE Fourth Annual Clean Coal

Technology Conference (Denver CO),

September 1995.

19
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 40 projects located in 18

states with a capital investment

value of nearly $6.0 billion. DOE’s

share of the total project costs is

about $2.0 billion, or approximately

34 percent of the total. The projects’

industrial participants (i.e., the nonDOE participants) are providing the

remainder—nearly $4.0 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.
Contacts

Project Team Members

Destec Energy, Inc.

PSI Energy, Inc.

U.S. Department of Energy

Phil Amick

Manager of Gasification Projects

Destec Energy, Inc.

2500 City West Boulevard

Houston, TX 77210-4411

(713) 735-4178

(713) 735-4837 fax

amick@destec.attmail.com

Jack Stultz

Plant Operations

Manager-Repowering

PSI Energy, Inc.

445 Bolton Road

West Terre Haute, IN 47885

(812)535-2451

(812) 535-2480 fax

gjstultz@cinergy.com

George E. Lynch

Portfolio Manager for

Gasification Power Systems

U.S. Department of Energy

Office of Coal & Power Systems

FE-221/27OCC

19901 Germantown Road

Germantown, MD 20874-1290

(301) 903-9434

(301) 903-9438 fax

george.lynch@hq.doe.gov

Gary A. Nelkin

Project Manager

U.S. Department of Energy

Federal Energy Technology Center

P.O. Box 880

Morgantown, WV 26507-0880

(304) 285-4216

(304) 285-4403 fax

gnelki@metc.doe.gov

Charles M. Zeh

IGCC Product Manager

U.S. Department of Energy

Federal Energy Technology Center

P.O. Box 880

Morgantown, WV 26507-0880

(304) 285-4265

(304) 285-4403 fax

czeh@metc.doe.gov

To be placed on the Department of Energy’s distribution list for future information on the Clean Coal Technology

Program and the demonstration projects it is financing, or on other Fossil Energy Programs, please contact:

Victor Der, FE-73

Director, Office of Power Systems

U.S. DOE, Office of Fossil Energy

1000 Independence Avenue

Washington, DC 20585

(301) 903-2700

(301) 903-2713 fax

victor.der@hq.doe.gov

This report is available on the Internet

at www.lanl.gov/projects/cctc

21
List of Acronyms and Abbreviations

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

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

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

CT ............................................................................................. combustion turbine

EIA ..................................................................... U.S. Energy Information Agency

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

gpm .............................................................................................gallons per minute

HHV ........................................................................................higher heating value

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

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

kW .............................................................................................................. kilowatt

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

lb/hr ............................................................................................... pounds per hour

MAF ......................................................................................moisture and ash free

MDEA .................................................................................methyldiethanol amine

MWe ............................................................................................megawatt electric

MWh ...............................................................................................megawatt hours

O&M ............................................................................. operating and maintenance

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

PM-10 .............................. particulate matter less than 10 micrometers in diameter

psia ........................................................................pounds per square inch absolute

SCF ............................................................................................standard cubic feet

 VOC.............................................................................. volatile organic compounds

22