WABASH RIVER COAL

GASIFICATION REPOWERING PROJECT

PROJECT PERFORMANCE SUMMARY

CLEAN COAL TECHNOLOGY DEMONSTRATION PROGRAM

JULY 2002

WABASH RIVER COAL GASIFICATION REPOWERING PROJECT JOINT VENTURE

DOE/FE-0448
Disclaimer

This report was prepared using publicly available

information, including the Final Technical Report and other

reports prepared pursuant to a cooperative agreement with

the U.S. Department of Energy. Neither the United States

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Reference herein to any specific commercial product,

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or reflect those of the United States Government or any

agency thereof.
WABASH RIVER COAL

GASIFICATION REPOWERING PROJECT

WABASH RIVER COAL GASIFICATION REPOWERING PROJECT JOINT VENTURE

PROJECT PERFORMANCE SUMMARY

CLEAN COAL TECHNOLOGY DEMONSTRATION PROGRAM

ADVANCED ELECTRIC POWER GENERATION
2

WABASH RIVER COAL GASIFICATION

REPOWERING PROJECT

OVERVIEW

This project is part of the U.S. Department of Energy’s (DOE) Clean Coal

Technology Demonstration Program (CCTDP) established to address energy and environmental concerns related to coal use. DOE sought cost-shared

partnerships with industry through five nationally competed solicitations to

accelerate commercialization of the most promising advanced coal-based

power generation and pollution control technologies. The CCTDP, valued at

over five billion dollars, has significantly leveraged federal funding by forging

effective partnerships founded on sound principles. For every federal dollar

invested, CCTDP participants have invested two dollars. These participants

include utilities, technology developers, state governments, and research organizations. The project presented here was one of nine selected from 33

proposals submitted in September 1991 in response to the CCTDP’s fourth

solicitation.

In this project, the then gasification technology owner, Destec Energy, Inc.

(later acquired by Dynegy and then Global Energy), forged a joint venture

with a major utility, PSI Energy, Inc. (now owned by Cinergy Corporation), to

pioneer commercial introduction of integrated gasification combined-cycle

(IGCC) power generation technology. In 1992, the resultant Wabash River

Coal Gasification Repowering Project Joint Venture (WRCGRP) embarked

on a demonstration of Global Energy’s E-GasTM gasification technology in an

IGCC mode at 262-MWe scale — then, the world’s largest single-train IGCC.

Seven years later, the project culminated with the unit successfully competing

in Cinergy’s system for base-load power and carrying the distinction of being

one of the cleanest coal-based power systems in the world.

The project repowered a 1950s vintage pulverized coal-fired plant, transforming the plant from an approximately 33% efficient, 90-MWe unit operating

on unscrubbed compliance coal into an approximately 40% efficient, 262-

MWe unit meeting or surpassing current and projected emissions standards.

Moreover, the technology operates efficiently on a range of coals, as well as

petroleum coke (a refinery waste); produces high-value byproducts in lieu of

solid wastes; and provides the potential for co-production of chemicals and

clean fuels.

Accolades for accomplishments have been bestowed on the project by both

the power industry and the public over the course of the demonstration. Recognized was the foresight and engineering expertise necessary to introduce a

new approach to power generation and to also integrate many new technical

advances. For example, the project used one of General Electric’s (GE) initial

production Frame 7FA high-temperature gas turbines and was the first to operate it on synthesis gas (syngas). Power magazine presented the project the 1996

Powerplant Award and induction to the Power Plant Hall of Fame Award in

2000, and the State of Indiana conferred the Indiana Governor’s Award for

Excellence in Recycling.

Global Energy’s E-GasTM

gasification technology

represents a new approach

to meeting 21st century

domestic and global energy

and environmental

demands. The technology

offers the potential for nearzero pollutant emissions,

significant gains in

efficiency, fuel and product

flexibility; and enables

carbon dioxide capture and

separation for recycle or

sequestration.
3

THE PROJECT

Round IV of the CCTDP placed particular emphasis on

advanced power generation systems that could provide

capacity additions without exceeding existing and projected

emissions caps, as well as major efficiency gains to counter

global climate change concerns. In response, PSI Energy

and Destec Energy developed a project to introduce gasification-based power generation with the primary goal

of integrating the system into the utility grid in baseload

commercial service. More specifically, the project set out

to displace the 40-year old, 90-MWe pulverized coal-fired

Unit 1 at PSI Energy’s Wabash River Generating Station

with an ultra-clean, highly efficient 262-MWe (net) integrated gasification combined-cycle system.

Challenges included extending E-GasTM previous experience, solely with low-sulfur subbituminous coals, to

high-sulfur bituminous coals indigenous to Indiana. Technical advancements had to be integrated to accommodate

differences in ash behavior and the need for high-capacity sulfur capture and conversion. At the very high sulfur

levels anticipated (up to 5.9% sulfur), carbonyl sulfide

(COS) becomes an issue — yet, there was no direct experience to draw on for COS removal from syngas. Also,

to meet efficiency goals in a repowering application required a high degree of integration between the gasification

heat recovery system, heat recovery steam generator

(HRSG), and existing reheat steam turbine. Efficiency

goals also prompted use of a newly introduced high-efficiency gas turbine produced by GE — the Frame 7FA —

which had never operated before on syngas.

Additionally, the project set tough environmental performance targets. Despite planned use of 5.9% sulfur coal,

the WRCGRP set SO2 emission targets at one-sixth of

the allowable emissions under the Clean Air Act Amendments of 1990 (CAAA). NOx emission targets were consistent with levels projected for ozone non-attainment areas. Furthermore, barrier filters for turbine protection

were to render particulate emissions essentially non-existent.

Lastly, integration with the utility grid required an annual

availability factor of over 70% — a target of 75% was

established. To achieve established performance targets

and to evaluate and document major process component

and subsystem performance, the WRCGRP mounted a

four year demonstration campaign, which systematically

addressed and successfully met the technical challenges.

Project Sponsor

Wabash River Coal Gasification Repowering Project Joint

Venture

Team Member Functions

PSI Energy, Inc. — host

Destec Energy, Inc. (now Global Energy) — engineer and

gas plant operator

Location

West Terre Haute, Vigo County, IN (PSI Energy’s Wabash

River Generating Station, Unit No. 1)

Technology

Integrated gasification combined-cycle (IGCC) using

Global Energy’s two-stage, pressurized, oxygen-blown,

entrained-flow gasification system — E-GasTM technology

The technology was developed by Dow Chemical

Company and transferred to Destec, a partially held

subsidiary of Dow. In 1997, NGC/Dynegy acquired

Destec. In 1999, Global Energy acquired Dynegy’s

gasification assets and technology.

Plant Capacity/Production

296 MWe (gross), 262 MWe (net)

Fuel

Illinois Basin bituminous coal

Petroleum coke

Demonstration Duration

December 1995 - December 1999

Project Funding

Total Project Cost

DOE

Project Sponsor

$438,200,000

219,100,000

219,100,000
4

THE TECHNOLOGY

E-GasTM technology features a pressurized, oxygen-blown, continuous-slagging, two-stage, entrained-flow gasifier.

Coal (or petroleum coke) is milled with water in a rod mill to form a 60/40 percent by weight coal/water slurry. An air

separation unit provides 95% pure oxygen that is combined with the slurry in mixer nozzles and is injected into the first

stage of the gasifier. In the first stage, the slurry, along with recycled char, undergoes a partial oxidation reaction at

400 psig. The resultant 2,600oF temperature causes rapid gasification of the coal (or petroleum coke) and the ash to

melt and flow. The fluid ash flows through a taphole at the bottom of the first stage into a water quench, forming an

inert vitreous slag.

Raw syngas from the first stage flows into a vertical second stage reactor, where additional slurry (without oxygen)

is introduced. The coal (or petroleum coke) devolatilizes, pyrolyzes, and partly gasifies by reaction with steam. These

reactions enhance the heating value of the syngas, and the endothermic reactions and water evaporation reduce the

syngas temperature to about 1,900oF. Reducing the temperature in this manner improves process efficiency and

eliminates the need for a large, expensive radiant heat exchanger. Syngas exiting the gasifier is cooled to 700oF in a

cooler, which is a vertical fire-tube boiler. This high-temperature heat-recovery unit (HTHRU) produces highpressure (1,600 psia) saturated steam.

Cooled syngas passes through a hot candle filter that removes the flyash and char and recycles it to the first stage

gasifier. Dry filtration is used, as opposed to wet methods, to meet efficiency targets. The filter uses metallic candle

filters that were further developed and refined during the course of the demonstration. The metallic filters replaced

the ceramic filters originally used.

The syngas is further cooled in a series of heat exchangers, water-scrubbed to remove chlorides, and passed through

a catalyst that hydrolyzes COS to hydrogen sulfide (H2S). The H2S is then removed in the acid gas removal system

using methyldiethanolamine (MDEA) absorber/stripper columns. A sulfur recovery unit, based on the Claus process,

partially oxidizes the H2S and converts it to pure sulfur and steam. Syngas, devoid of acid gases, is then preheated,

moisturized and piped to the power block, where it is combusted in a GE MS7001FA high-temperature gas turbine.

The HRSG uses both the gas turbine exhaust energy and the saturated steam from the HTHRU to provide superheated steam to an existing 1952 vintage Westinghouse reheat steam turbine. The steam turbine is designed to

produce 104 MWe, and together with the 192 MWe gas turbine, the plant design output is 296 MWe gross, with

a 34-MWe auxiliary load (262 MWe net).

Syngas

Syngas

Cooler

Syngas

Syngas

Preheat
5

RESULTS SUMMARY

ENVIRONMENTAL

• The SO2 capture efficiency was greater than 99%,

keeping SO2 emissions consistently below 0.1 lb/106 Btu

and reaching as low as 0.03 lb/106

 Btu. Sulfur-based

pollutants were transformed into 99.99+% pure sulfur, a highly valued product. A total of 33,388 tons of

sulfur were produced during the demonstration.

• NOx emissions were 0.15 lb/106

 Btu, which meets 2003

target emission limits for ozone non-attainment areas,

or 1.09 lb/ MWh, which outperforms New Source Performance Standards (NSPS) of 1.6 lb/ MWh.

Particulate emissions were below detectable limits, and

carbon monoxide emissions, averaging 0.05 lb/106 Btu,

were well within industry standards.

• Coal ash was converted to a low-carbon vitreous slag,

impervious to leaching and valued as an aggregate in

construction or as a grit for abrasives and roofing

materials. Trace metals from petroleum coke were captured and encased in the vitreous slag.

OPERATIONAL

• Over the course of the demonstration, the IGCC unit

operated on coal for over 15,000 hours, processed over

1.5 million tons of coal, and produced over 23 trillion

Btu of syngas and 4 million MWh of electricity.

• A number of problems were overcome and improvements were made over the course of the demonstration,

bringing average gasification block availability up to

70% in 1999, and reaching as high as 77% during a 9

month period in 1998-1999. The plant demonstrated

stable operation on the utility grid in a baseload dispatch mode.

• Ash deposition on the second stage gasifier walls and

fire-tube boiler inlet was corrected by using a less tenacious refractory material and modifying the hot gas

path flow geometry and velocity. An effective mechanical cleaning system for the fire-tube boiler was

developed. Improvements in rod mill operation and

burner design reduced slag carbon content from 10%

to 5%.

• Particulate filtration system problems were remedied

by replacing ceramic candle filters with metallic candle

elements and improving flow distribution to, and backpulse cleaning of, the filter elements.

• Installation of a wet chloride scrubber eliminated early

poisoning of the COS hydrolysis catalyst and chloride

stress corrosion cracking of low temperature heat exchanger tubes. Also, a COS catalyst less prone to

poisoning was installed. Acid gas removal performance

was successfully improved by expanding the capacity

of the heat stable salt removal system.

• With few exceptions, the combustion turbine and its

related components operated as expected over the

course of the project. In 1999, however, a catastrophic

failure of the air compressor rotor and stator occurred,

unrelated to operation on syngas. Other minor incidents involved the combustion turbine expansion

bellows, solenoid valves in the syngas purge lines, and

fuel nozzles.

ECONOMIC

• The capital cost of the demonstration unit was

$1,590/kW in 1994 dollars. The capital cost for an

equivalent sized greenfield commercial configuration

with an 8,250 Btu/kWh heat rate was estimated to be

$1,250–1,300/kW in year 2000 dollars for a coal-fueled unit and $1,100–1,200/kW for a petroleum

coke-fueled unit (due to reducing the size and eliminating some equipment).

Gasifier structure
6

OPERATIONAL PERFORMANCE

Table 1 summarizes the production statistics for the project.

Over the four-year demonstration period starting in November

1995, the plant operated on coal for more than 15,000 hours

and processed over 1.5 million tons of coal to produce more

than 23 trillion Btu of syngas. For several of the months,

syngas production exceeded one trillion Btu. By the end of

the demonstration, the 262-MWe IGCC unit had captured

and produced 33,388 tons of sulfur.

TABLE 1. WRCGRP PRODUCTION STATISTICS

41,000a

184,382

392,822

561,495

369,862

1,549,561

171,613

820,624

1,720,229

2,190,393

1,480,908

6,383,767

71,000a

449,919

1,086,877

1,513,629

1,003,853

4,125,278

559

3,299

8,521

12,452

8,557

33,388

505

1,902

3,885

5,279

3,496

15,067

230,784

2,769,685

6,232,545

8,844,902

5,813,151

23,891,067

On Coal

(Hr)

Start-up 1995

1996

1997

1998

1999b

Overall

Coal

Processed

(tons)

On Spec.

Gas

(106 Btu)

Steam

Produced

(103 lb)

Power

Produced

(MWh)

Sulfur

Produced

Time Period (tons)

FIGURE 1. PROJECT, SYNGAS BLOCK, AND POWER BLOCK AVAILABILITY

a

Estimated

b

The combustion turbine was unavailable from 3/14/99 through 6/22/99.

0%

20%

40%

60%

80%

100%

1996 1997 1998 1999

Project Availability Syngas Availability Power Block Availability
7

Figure 1 shows how the reliability of the technology advanced during the demonstration. The continuous

improvement trend for the gasification block, where the

majority of the novel technology resides, is encouraging

and is expected to continue. During the third quarter of

1999, the gasification block produced a record 2.7 trillion

Btu of syngas and operated continuously without any interruption for 54 days. Over the last year of the demonstration,

the gasification block achieved 70% availability and

achieved as high as 77% availability over one nine-month

period in 1998–1999. The project and power block availability values for 1999 are skewed by the 100-day

downtime experienced as a result of a combustion turbine compressor failure unrelated to operation on syngas.

At the time of this report, the unit continues to operate as

part of the utility power generation system, competing

with Cinergy’s alternatives for peak and off-peak power.

Competitive market-based pricing allows the syngas facility to run at base-load in Cinergy’s system.

WRCGRP’s efforts resulted in all goals and objectives of

the project being met and in unanticipated successes as

well. While fuel changes were not planned, the system

operated effectively, without modification or incident, on

petroleum coke (petcoke) and on blends and combinations of bituminous coals that sometimes changed daily.

This performance proved the fuel flexibility of the system, which had previously processed lignite and

subbituminous coals during its development. While processing over 18,000 tons of high-sulfur petcoke during

demonstration in 1997, the unit produced 350 billion Btu

of syngas, demonstrated enhanced thermal efficiency, and

encountered negligible tar production and no problem in

handling the increased dry char particulate production.

Table 2 summarizes the coal and petcoke characteristics

and plant performance on these fuels.

TABLE 2. FUEL/PRODUCT CHARACTERISTICS

AND PLANT PERFORMANCE

Fuel Analysis

15.2

12.0

32.9

39.9

1.9

10,536

7.0

0.3

12.4

80.3

5.2

14,282

Moisture, %

Ash, %

Volatile Matter, %

Fixed Carbon, %

Sulfur, %

HHV, Btu/lb

Component

Typical

Coal

Petroleum

Coke

Product Syngas Analysis

Component

Typical

Coal

Petroleum

Coke

1.9

0.6

15.8

45.3

34.4

1.9

68

277

1.9

0.6

15.4

48.6

33.2

0.5

69

268

Plant Performance

Throughput, tons/day

Syngas Output, 106 Btu/hr

Gas Turbine, MWe

Steam Turbine, MWe

Parasitic Load, MWe

Net Power, MWe

Plant Efficiency (HHV), %

Sulfur Removal, %

2,550

1,780

192

105

35

262

37.8*

>98

Design

Coal

Actual

Coal

Actual

Petcoke

2,450

1,690

192

96*

36

252

39.7*

>99

2,000

1,690

192

96*

36

252

40.2*

>99

Nitrogen, Vol %

Argon, Vol %

CO2

, Vol %

CO, Vol %

H2

, Vol %

CH4

, Vol %

Total Sulfur, ppmv

HHV, Btu/SCF

*Lower steam turbine output resulted from feedwater

heater failure. Thermal efficiency numbers are corrected

for this failure.
8

In carrying out the successful four year campaign to engineer the demonstration unit into a viable commercial

unit, the WRCGRP encountered a broad range of problems, including the usual quality control and nuisance

problems. Summarized here are some of the major challenges overcome and important lessons learned. They are

presented topically in the order in which the system or

component appears in the process.

Air Separation Unit (ASU). The 2,060 ton per day Liquid Air Engineering Corp. (LAEC) ASU failed to display

the high availability characteristic of industrial ASUs, fell

short of targeted nitrogen production levels, and exceeded

power consumption targets. Poor weatherproofing of key

components, quality control problems, and a poorly designed instrumentation system contributed to downtime.

The largest ASU downtime item was the inlet guide vane

actuator system, which ultimately had to be replaced with

a new design. Failure to meet targeted nitrogen production and power consumption initially resulted in higher than

expected operating and maintenance costs for power and

imported nitrogen. However, nitrogen conservation measures adopted during startup reduced consumption. A

lesson learned is that ASUs using batch type air purification, such as the LAEC unit, must reduce capacity during

the transition of adsorber beds from adsorption to regeneration. This temporary reduced capacity should be taken

into account when sizing equipment.

Coal Handling. The coal delivery system for the gasifier performed well, although several upgrades were

made. These upgrades included hardening or metallurgically altering components to better resist erosion and

corrosion, and modifying the slurry tank agitator to reduce localized buildups. Moreover, the rod mill rod charge

was adjusted to provide optimum particle size distribution

for flow and for carbon conversion in the gasifier.

Gasification. Efficient operation of the gasifier requires that

first stage temperatures are hot enough to ensure molten

slag flows from the taphole, but not so hot that refractory

damage results. Striking this balance continues to be a challenge because direct temperature measurements proved to

be unreliable. Operators had to rely heavily upon indirect

observations to control temperature. After five taphole plugging events following feedstock changes, investigators

developed feed-specific guidelines to prevent further problems.

Ash deposition problems plagued early operations. Ash

deposits formed on the walls of the second stage gasifier

and downstream piping. As deposits built up, they forced

the plant off line by either inducing unacceptable pressure differentials or breaking free and plugging

downstream lines or HTHRU tubes. Drawing upon computational fluid dynamic modeling, the problem was

corrected by: (1) using a refractory in the second stage

resistant to tenacious ash bonds and having reduced thickness to lower gas flow velocity; (2) replacing the

Wabash River Generating Station IGCC plant — gasifier and gas cleanup to left and gas turbine and HRSG to right
9

refractory lined pipe spool between the gasifier and

HTHRU with a smooth, continuous transition spool to

eliminate high velocity impact zones; and (3) installing a

screen at the HTHRU inlet to catch any remaining deposits.

The slurry mixers that serve to mix and inject the coal/

water/oxygen into the first stage gasifier proved to be a

reliability challenge given the abrasive characteristics of

the coal coupled with the hostile environment of high temperatures and slag. After early struggles to maintain

reasonable performance, a breakthrough was made by

redesigning the mixer throat and face. The redesign

doubled mixer life and, along with earlier rod mill adjustments, reduced carbon in the slag from 10% to 5%.

HTHRU (Syngas Cooler). Despite improvements in design and operating conditions to reduce fouling, routine

removal of deposits from the HTHRU boiler tubes is required at scheduled outages. Cleaning is needed to prevent

reduction of heat transfer effectiveness and thus ensure

the integrity of downstream temperature sensitive components, such as filter elements. The deposits are

particularly hard and tenacious, which prompted maintenance personnel to develop a special tool. Standard

mechanical cleaning methods proved to be ineffective and

chemical methods expensive and time consuming. The

solution was an adaptation of a core drill to bore out the

tubes.

Particulate Removal. The particulate removal system

accounted for nearly 40% of the total downtime in the

first year of operation. A concerted effort on the part of

a team dedicated to resolving the underlying problems

has resulted in bringing the system up to acceptable performance levels and making the prospects for future

performance bright.

In early operation, many ceramic tie-rod type candle filter

elements sustained sufficient damage, both during installation and in service, to cause breakthrough of particulate

matter, which overwhelmed the secondary safeguard system. Failures strongly suggested that the long slender,

relatively brittle ceramic candles could not readily adjust to

either dimensional discontinuities introduced through the

mounting hardware or thermal gradients induced in service.

The frequent start-ups and shutdowns experienced in the

early operating period likely exacerbated the problem.

A change to metallic candle elements in late 1996 immediately improved system reliability. The switch to metallic

candles, however, introduced the challenge of overcoming corrosion. Filter blinding, a problem with ceramic filters, Coal receiving and handling area
10

remained a problem with metallic filters. Metallurgical advancements made significant inroads into solving the

corrosion problem. The advancements were aided by

installation of a slipstream test apparatus to evaluate effectiveness of new filter elements, as well as mounting

hardware. Blinding problems were significantly reduced

by: (1) modifying the gas distribution in the filter vessel to

even out flow and eliminate localized high-velocity channeling; and (2) improving operation and control of the

back-pulse cleaning system.

Operational experience pointed out the importance of

having safeguard devices (SGD) integrated with each filter element to prevent catastrophic breakthrough of

particulate matter. SGDs are essentially packings that are

designed to offer little flow resistance during normal operation and plug when subjected to high dust loadings.

The team working on the particulate removal system developed such devices and, due to their success, the SGDs

displaced the secondary filter system.

Low Temperature Heat Recovery/COS Hydrolysis. In

the early stages of operation, extensive tube failures occurred in the low temperature heat recovery system, and

the COS hydrolysis catalysts incurred poisoning. Investigation revealed the root cause to be chloride induced stress

corrosion cracking of the exchanger tubes and chloride

and trace metal poisoning of the COS catalyst. Integration of a chloride scrubber, which was accomplished in

the first year of operation, eliminated the chloride problem. As a result of the catalyst poisoning incident,

investigators sought a more durable catalyst and, through

slipstream testing, identified and adopted a new catalyst

material, which appears to have the desired 5-year life.

Gas cleanup system

Acid Gas Removal. Acid gas removal improvement efforts focused on the MDEA reclaim unit, the most costly

piece of equipment in the system and one having direct

impact on sulfur removal. Early actions included (1) structural modification of the canisters containing the ion

exchange resin to prevent dissolution, and (2) changes to

the solution designed to remove unwanted heat stable salts

from the ion exchange resin. Heat stable salt buildup persisted, however, requiring frequent and costly on-site

vacuum distillation or solution replacement. In the last year

of operation, the problem was resolved by increasing system capacity with a supplemental amine storage tank.

WRCGRP suggests future MDEA reclaim designs be

simplified to reduce capital and maintenance costs. They

found the continuous-feed, rotating canister design unnecessarily complex and difficult to maintain. A suggested

system is a three cell unit swapping flow from online,

regeneration, and stand-by resin beds using automated

block valves.

Combustion Turbine. With few exceptions, the combustion turbine and its related components operated as

expected over the course of the project. In 1999, however, a catastrophic failure of the air compressor rotor

and stator occurred. Apparently other gas turbines operating on natural gas experienced similar events. General

Electric concluded that this failure was not related to operation on syngas. An upgraded compressor unit was

installed. Other minor occurrences prompted improvements in other areas. These include: (1) redesign and

replacement of expansion bellows between the syngas

module and the turbine to eliminate flow sleeve cracking;

(2) redesign and replacement of solenoid valves in the

syngas purge lines; and (3) replacement of fuel nozzles to

remedy combustor liner cracking.

HRSG. The HRSG experienced an abnormal number of

tube leaks attributed primarily to piping circuits being supported from the bottom rather than hung from the ceiling.

Supporting at the bottom limited movement of the piping

and induced stress at tube bends during expansion and

contraction. Moreover, superheater and reheat section

header expansion joints failed due to interference with

penthouse roof panels upon heat up.
11

ENVIRONMENTAL

PERFORMANCE

The COS hydrolysis and MDEA acid gas removal systems combined to achieve an average SO2

 emission rate

of 0.1 lb/106 Btu, with interim emission rates reaching as

low as 0.03 lb/106

 Btu. This represents a 99% reduction

of the potential SO2 emissions based on the sulfur content of the design coal. The CAAA year 2000 standards

for SO2

 control serve to underscore the dramatic sulfur

reduction achieved. These standards limit SO2 emissions

to 1.2 lb/106

 Btu of heat input and a sliding scale requiring

70–90% reduction from the uncontrolled emissions rate,

which generally works out to about 0.6 lb/106

 Btu for

high sulfur bituminous coals.

Moreover, the sulfur captured is transformed into 99.99+%

pure sulfur — a salable product. Over the four year demonstration period, 33,388 tons of pure sulfur were produced,

contributing to the economy rather than environmental

concerns.

There are two regulatory drivers for low NOx emissions

applicable to projects such as the WRCGRP: (1) recently

revised NSPS for NOx of 1.6 lb/MWh based on power

output rather than heat input, and (2) NOx emission limits

of 0.15 lb/106 Btu to be met in 2003 by existing power

sources in 22 eastern states and the District of Columbia.

WRCGRP readily complies with both standards. Moisturizing the syngas in combination with steam injection in

the gas turbine easily sustained NOx emission rates of

0.15 lb/106 Btu and 1.09 lb/MWh.

Existing standards for particulate matter at the time of the

project limited total particulate emissions to 0.03 lb/106 Btu.

Monitoring was required for particulate matter in the range

of 10 microns or less (PM10) to address National Ambient Air Quality Standards (NAAQS). The NAAQS underwent a subsequent revision towards the end of the

project to address fines in the respirable range of 2.5 microns or less (PM2.5). As this report is released, a national PM2.5 monitoring program is underway to establish

non-attainment areas and to attribute PM2.5 levels to

sources. Sulfates and nitrates derived from SO2 and NOx

emissions become a concern, as well as flyash, for particulate matter in this size range. These factors combine

to make E-GasTM technology an important power generation option for the future — particulate emissions are

below the detectable limit and SO2 and NOx precursors

to PM2.5 are extremely low.

Carbon monoxide emissions averaged 0.05 lb/106

 Btu,

essentially the same as the displaced plant and well within

industry standards.

The ash component of the coal is transformed into a lowcarbon vitreous slag, impervious to leaching and valued

as an aggregate in construction or as a grit for abrasives

and roofing materials. Slag fines are recycled to the gasifier to enhance carbon recovery. Also, trace metal

constituents in petroleum coke are effectively captured

in the slag produced.

Air toxics monitoring proved that airborne hazardous air

pollutants (HAPS) are not a problem with the IGCC plant.

This was not surprising given that particulate emissions

were below detectable limits and that HAPS largely associate with particulate matter. Even mercury, which

adopts a vapor phase and often escapes capture, presented no problem, with emissions ranging from

0.0002–0.0009 pounds per hour. Some volatile trace elements fully or partially partitioned into the gas phase and

ended up in the condensed vapor stream, leaving the process via the waste water stream. Arsenic, selenium, and

cyanide built up in the waste water, which required post

project action to correct. WRCGRP identified two options showing promise — evaporation and reverse osmosis

— with evaporation finally selected to ensure removal of

certain speciation of trace metals.

Steam lines from HRSG
12

ECONOMIC PERFORMANCE

The overall cost of the IGCC demonstration plant was

$417 million, which equates to about $1,590/kW in 1994

dollars. Costs include engineering, environmental permitting, equipment procurement, project and construction

management, construction and start-up, and hiring and

training personnel. Costs exclude fuel supply, interest during

construction, financing fees, and license fees.

Capital cost estimates for a new 262-MWe greenfield

IGCC plant incorporating lessons learned, technology improvements, and a heat rate of 8,250 Btu/kWh are

$1,250–1,300/kW (year 2000 dollars) for a coal-fueled

unit and $1,100–1,200/kW (year 2000 dollars) for a petroleum coke-fueled unit. In designing for petroleum coke,

some equipment can be reduced in size and some can be

eliminated.

Annual fuel costs for the Wabash project ranged from

$15.3–19.2 million, with an annual availability of 75%

and using high-sulfur bituminous coal ranging from

$1.00–1.25/106

 Btu ($22–27/ton). Non-fuel operations

and maintenance (O&M) costs for the syngas facility (excluding the power block) was 6.8% of installed capital

based on 75% availability. O&M costs include operating

labor and benefits, technical and administrative support

on- and off-site, maintenance, chemicals, waste disposal,

operating services and supplies, and 5% of the total O&M

cost for betterments. Projected O&M costs for a mature

IGCC facility (including the power block) are 5.2% of

installed capital costs.

Economic analyses showed that a coal-fueled Wabash

River style IGCC required power pricing of $34–42/MWh

for a 12% internal rate of return (IRR), depending on a reasonable range of capital and O&M

costs and availability. For a similar petroleum

coke-fueled plant and 12% IRR, the estimated

power pricing requirements are $24–30/MWh,

again depending on a reasonable range of capital and O&M costs and availability.

COMMERCIAL APPLICATIONS

At the end of the demonstration in December 1999, Global Energy, Inc. purchased the gasification assets and

technology from Dynegy. Global Energy is marketing the

technology under the name E-GasTM. The project is continuing to operate in commercial service as Wabash River

Energy, Ltd., a subsidiary of Global Energy.

The immediate future for E-GasTM technology appears

to lie with both foreign and domestic application where

low-cost feedstocks such as petroleum coke can be used

and co-production options are afforded — bundled production of steam, fuels, chemicals, and electricity.

Integration or association with refinery operations are examples.

In the longer term, the technology has application for repowering the aging fleet of existing domestic coal-fired

boilers, and new foreign and domestic coal-fueled capacity additions. Factors favoring increased use of IGCC over

time are continued improvement in IGCC cost and performance, projected increases in price differentials

between coal and gas, and continued importance placed

on displacement of petroleum in chemicals and fuels production.

The potential sales of this technology are reflected

in Figure 2, which is based on data developed by SFA

Pacific, Inc. that shows the cumulative worldwide gasification capacity and growth.

FIGURE 2. CUMULATIVE WORLDWIDE

GASIFICATION CAPACITY AND GROWTH
CONTACTS

Phil Amick, (713) 374-7252

Global Energy, Inc.

1000 Louisiana St., Suite 3800

Houston, TX 77002

Fax (713) 374-7279

pramick@globalenergyinc.com

George Lynch, DOE/HQ, (301) 903-9434

Leo E. Makovsky, NETL, (412) 386-5814

REFERENCES

1. Wabash River Coal Gasification Repowering Project: Final Technical Report. August

2000. Wabash River Coal Gasification Project Joint Venture. Available in PDF format at

http://www.lanl.gov/projects/cctc/

2. Wabash River Coal Gasification Repowering Project-An Update: Topical Report Number

20. September 2000. Available in PDF format at http://www.lanl.gov/projects/cctc/

3. Wabash River Coal Gasification Repowering Project: Topical Report Number 7.

November 1996. Available in PDF format at http://www.lanl.gov/projects/cctc/

4. Wabash River Coal Gasification Repowering Project: Public Design Report. July 1995.

Available in PDF format at http://www.lanl.gov/projects/cctc/

5. Environmental Monitoring Plan Report, 1999 Annual Report, Volume 1. Available in PDF

format at http://www.lanl.gov/projects/cctc/

6. Comprehensive Report to Congress on the Clean Coal Technology Program: Wabash

River Coal Gasification Repowering Project. June 1992. Available in PDF format at

http://www.lanl.gov/projects/cctc/
U.S. Department of Energy

Assistant Secretary for Fossil Energy

Washington, DC 20585