EPA- 600 / 7- SO- 017
September 1990
TECHNOECONOMIC APPRAISAL OF
INTEGRATED GASIFICATION
COMBINED-CYCLE
POWER GENERATION
Prepared by:
Malcolm D. Fraser
Science Applications International Corporation
1710 Goodridge Drive
McLean, Virginia 22102
EPA Contract Nos: 68-02-3893, Work Assignment 30
and 68-02-4397, Work Assignment 24
Work Assignment Manager:
Julian W. Jones
Air and Energy Engineering Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
Prepared for:
Office of Research and Development
U.S. Environmental Protection Agency
Washington, DC 20460
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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ABSTRACT
A future competitive technology to current pulverized-coal boilers
equipped with S02 and N0X controls is integrated (coal) gasification combined-
cycle (IGCC) systems, because of its potential for increased thermal
efficiency and very low emission rates. However, IGCC is not yet a proven
commercial technology; this fact will influence the rate of market penetration
of IGCC and its possible impact on future emissions. Several private firms,
working with the Electric Power Research Institute, have demonstrated the
first IGCC plant to supply electricity to a U.S. utility system at Southern
California Edison Co.'s Cool Water Generating Station near Barstow,
California, using the Texaco coal gasification process. This demonstration
has provided significant data for process improvements and has indicated the
basic operability of combined chemical process/power generation technology.
However, remaining technical questions include: operability of the Texaco
gasifier at full throughput; materials of construction; plant operation over
an extended period of time with high-sulfur Eastern coal; and plant
availability/reliability. The most significant gasification technologies, in
terms of potential application to ICCC systems, appear to be Texaco, Dow,
British Gas Corporation (BGC)/Lurgi, and Shell. One advantage of IGCC systems
is the potential for phased construction of partial plant capacity to more
closely match the currently slow electricity demand growth. Simple
comparisons using generic cost and performance data indicate similar
electricity generation costs for IGCC versus competing technologies. The
projected market of about 57,000 MW for new gas turbines from 1990 to 2010
should provide significant opportunity for phased IGCC systems.
ii
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TABLE OP CONTENTS
Section Page
Abstract ii
List of Figures v
List of Tables vi
Acknowledgements vii
Executive Summary E-l
1.0 Introduction 1-1
1.1 Background 1-1
1.2 Purpose and Objectives of Study 1-2
1.3 Methodology 1-2
1.4 Description of Generic Integrated Gasification Combined-
Cycle (IGCC) System 1-4
2.0 Cool Water Demonstration IGCC Plant 2-1
2.1 Introduction 2-1
2.2 Project Objectives 2-2
2.3 Process Description and Plant Design 2-3
2.4 Plant Performance 2-10
2.4.1 Energy Efficiency (Heat Rate) 2-10
2.4.2 Environmental Characteristics 2-11
2.4.3 Summary of Operating Problems and Availability . . . 2-13
2.4.4 Load-Following Characteristics 2-17
2.5 Economics 2-20
3.0 Description of IGCC Technologies 3-1
3.1 Gasification Systems 3-1
3.1.1 Texaco 3-3
3.1.2 Dow 3-7
3.1.3 British Gas Corporation/Lurgi 3-9
3.1.4 Shell 3-13
3.1.5 Summary Comparison of Gasification Systems 3-16
3.2 Combined-Cycle Power Block Components 3-18
3.2.1 Gas Turbine 3-18
3.2.1.1 Advanced Turbines 3-20
3.2.1.2 NOx Emissions 3-20
iii
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TABLE OF CONTENTS (Continued)
Section Page
3.2.2 Heat Recovery Steam Generator 3-23
3.2.2.1 Unfired Generator 3-24
3.2.2.2 Generator with Supplementary Firing . . . 3-24
3.2.3 Steam Turbine 3-26
3.3 Design Studies of Commercial IGGG Plants 3-28
3.3.1 Technological Status of IGCC Plants 3-29
3.3.2 Energy Efficiency (Heat Rate) 3-29
3.3.3 Environmental Characteristics 3-33
3.3.3.1 Sulfur Removal 3-34
3.3.3.2 Nitrogen Oxides Emissions 3-36
3.3.3.3 Particulate Emissions 3-38
4.0 Economics of IGCC Systems 4-1
4.1 Cost Estimates for Commercial Plant Designs 4-1
4.2 Comparison with Other Power Generation Systems 4-2
4.3 Availability of IGCC Plants 4-9
4.4 Economics of IGCC in System Expansion Analyses 4-11
4.5 Phased Implementation of IGCC Power Plants 4-13
4.5.1 Unphased vs. Phased Capacity Addition 4-13
4.5.2 Effect of Phased Capacity Addition on
Capital Expenditures 4-14
4.5.3 Effect of Phased Capacity Addition on Cost
of Electricity 4-19
4.6 Repowering 4-22
4.7 Utility- and Site-Specif i.e. Studies 4-24
5.0 Future Potential Market for IGCC Systems 5-1
5.1 Utility Perceptions of IGCC and Factors Influencing
Penetration 5-1
5.2 Estimated Total Market for New Coal-Based Systems 5-3
5.3 Future Potential Market for IGCC Systems 5-5
6.0 Conclusions and Recommendations 6-1
6.1 Conclusions 6-1
6.2 Recommendations 6-3
References R-l
iv
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LIST OF FIGURES
Figure Page
E-l. Generalized Block Flow Diagram of Coal Gasification Integrated
with Combined-Cycle Electric Power Generation E-2
E-2. Capital Investment Estimates for Single 500-MW Units .... E-14
1-1. Generalized Block Flow Diagram of Coal Gasification Integrated
with Combined-Cycle Electric Power Generation 1-5
2-1. Block Flow Diagram of Cool Water IGCC Demonstration .... 2-5
2-2. Flow Diagram of Syngas Coolers 2-16
3-1. Texaco Coal Gasification Process 3-4
3-2. British Gas Corporation/Lurgi Slagger Gasifier 3-10
3-3. Shell Coal Gasification Process Typical Flow Scheme .... 3-14
3-4. IGCC System Capacity vs. Ambient Temperature 3-27
4-1. Capital Investment Estimates for Single 500-MW Units .... 4-4
4-2. Unphased Capacity Addition 4-15
4-3. Phased Capacity Addition 4-15
4-4. Unphased IGCC Plant 4-16
4-5. Phased IGCC Plant Phasing Sequence 4-16
v
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LIST OF TABLES
Table Page
E-l. Adjustment of Cool Water Heat Rate and Comparison with
Estimate for a Commercial Plant E-5
E-2. Heat Recovery Steam Generator (HRSG) Stack Emissions from the
Cool Water Plant E-7
E-3. Status of Second-Generation Gasification Technologies for
IGCC Systems E-ll
E-4. Summary of Comparative Costs and Performance Estimates for
PC and IGCC Plants E-15
2-1. Project Objectives of the Cool Water Demonstration Plant . . 2-4
2-2. Cool Water Clean Syngas Composition 2-8
2-3. Adjustment of Cool Water Heat Rate and Comparison with
Estimate for a Commercial Plant 2-12
2-4. Heat Recovery Steam Generator (HRSG) Stack Emissions from the
Cool Water Plant 2-14
2-5. Summary of Cool Water Plant Production Availability .... 2-18
3-1. Status of Second-Generation Gasification Technologies for
IGCC Systems 3-2
3-2. Important Characteristics of Advanced Gasification Techno-
logies Being Developed for IGCC Applications 3-17
3-3. Gas Turbine Performance Characteristic Comparison 3-21
3-4. Effect of Advanced vs. Current Turbine Model on Performance
and Costs of IGCC Designs 3-22
3-5. Comparison of IGCC Plant Designs from EPR1 Studies:
Technological Status of Plant Components 3-30
3-6. Comparison of IGCC Plant Designs from EPRI Studies: Energy
Efficiency 3-32
3-7. Cost and Performance Comparison Between Base and Deep
Sulfur Removal Designs--Shell-Based IGCC 3-37
4-1. Comparison of EPRI Cost Estimates for Power Generation
Technologies 4-3
4-2. Summary of Comparative Costs and Performance Estimates for
PC and IGCC Plants 4-5
vi
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LIST OF TABLES (Continued)
Table Page
4-3. Busbar Costing Methodology 4-7
4-4. Calculations of Levelized Cost of Electricity 4-8
4-5. Cost and Performance Summary for Phased IGCC Construction . 4-18
4-6. Summary of Economic Evaluation Results for Phased
Implementation of IGCC 4-21
5-1. Projections of Total Installed Power Generation Capacity by
Year from AUSM 5-4
vii
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ACKNOWLEDGMENTS
This study was performed within the Energy Technology Assessment
Division at Science Applications International Corporation. Isaac K.
Kwarteng participated in the study by performing literature research and
contributing to the final report. Linda Demuth was responsible for
manuscript preparation.
Thanks are due to Michael J. Gluckman, Electric Power Research
Institute, and Paul W. Dinkel, Cool Water Gasification Program, for
generously providing up-to-date information on IGCC technologies and the
Cool Water Plant.
The advice and guidance of Julian Jones, EPA project officer, and
Lowell Smith, EPA technical coordinator, are hereby gratefully
acknowledged.
viii
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EXECUTIVE SUMMARY
Background
Projections into the next century of SO2 and N0X emissions from U.S.
coal-based electric generating plants are significantly affected by the
many assumptions that must be made. These assumptions include the rate
at which existing coal-fired boilers will be retired, as opposed to being
overhauled for life extension purposes; the rate at which new coal-based
generating units will be built, either to replace retired capacity or to
increase generating capacity from current levels; and the technologies
that will be used in these new units. One technology that is emerging as
a future competitor to current pulverized-coal (PC) boilers equipped with
pollution control devices [e.g., low-NOx burners and flue gas desulfur-
ization (FGD)] is integrated (coal) gasification combined-cycle (IGCC)
systems because of their potential for increased thermal efficiency and
very low SO2 and N0X emission rates.
However, IGCC plants are not yet a proven commercial technology with
demonstrated benefits and reliably competitive costs. Thus, there are
technical risks associated with IGCC. Because these technical risks and
the perceived economics of IGCC will influence its actual rate of
penetration, and its possible impact on expected future emissions, the
EPA decided to have performed an independent technical and economic
assessment of IGCC systems.
This study involved three tasks corresponding to three main objectives.
The first task was to perform a technical evaluation of IGCC technologies
and systems. The second task was to develop cost and performance
estimates and compare IGCC with competing coal-burning technologies. The
last task was to evaluate the potential future market for IGCC
application to new power generation plants.
In an IGCC plant, shown as a generalized block flow diagram in Figure E-
1, coal is fed to a gasifier, where it reacts with steara and oxygen to
E-l
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COAL
SEPARATION
Water
Flue Gas
COAL
HANDLING
Oxygen
Steam
Boiler Feedwater
Saturated Steam
HEAT RECOVERY
STEAM
GENERATION
(HRSG)
GASIFICATION,
GAS COOLING,
AND SCRUBBING
ACID GAS
REMOVAL
Superheated
Steam
Steam tor
Reheat
Fteheatsd Steam
STEAM
TURBINE
Hot Turbine
Exhaust Gas
COMBUSTION
TURBINES
M
i
ro
Blowdown
or
¦Bleed"
Stream
Acid Gas
Air
WASTEWATER
Cooling
TREATMENT
Tower
SULFUR
RECOVERY
Plant Power
Requirements
Source: Reference 1. Copyright ©(1983) Electric Power Research Institute. Reprinted with permission.
Ash
Sulfur
Figure E-1. Generalized Block Flow Diagram of Coal Gasification Integrated
with Combined-Cycle Electric Power Generation.
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produce a hot raw fuel gas. The fuel gas is then cooled and purified to
remove particulates and acid gas (hydrogen sulfide). Elemental sulfur is
recovered from the acid gas. The clean fuel gas is burned in a 2000°+F
combustion turbine. The hot flue gas (900-1000°F) leaving the combustion
turbine is cooled by generating, superheating, and reheating steam in a
heat recovery steam generator. This steam is used in a steam turbine.
Power is generated from both the combustion turbines and the steam
turbines. The primary reason for integrating the gasification system
with the combined-cycle plant is that this design configuration
substantially improves the overall system energy efficiency or heat rate.
Although all components (i.e., gasifiers, gas coolers, acid gas removal
systems, combined cycles) included in an IGCC configuration have, in some
way, been demonstrated to operate at full commercial scale, they have
only recently been operated in unison in a complete system to generate
electric power. Integrated control and operation of such plants in a
commercial environment must be demonstrated on a large scale before the
majority of the electric utility industry will seriously consider
adopting IGCC systems for electric power generation. Taking a step
closer to this goal by resolving some of these Issues is one of the
central objectives of the Cool Water Gasification Program, an IGCC
demonstration based on the Texaco coal gasification technology.
Cool Water Demonstration IGCC Plant
The Cool Water Gasification Program (2,3,4,5,6) is an undertaking of a
number of private entities, led by the Electric Power Research Institute
(EPRI), to design, construct, and operate the nation's first IGCC power
plant to supply electricity to a utility system. The demonstration
plant, comprising commercial-scale components and subsystems, is located
at the Cool Water Generating Station of Southern California Edison
Company (SCE) near Barstow, California, about halfway between Los Angeles
and Las Vegas in the Mojave Desert. The Cool Water plant began
generating electricity on June 24, 1984, and is being operated by the
program for a 5-year demonstration period. It is the goal of the program
E-3
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to demonstrate the environmental and economic characteristics of an IGCC
power generation plant.
The Cool Water plant uses an entrained-bed, oxygen-blown Texaco gasifier
to convert 1000 tons (907 x 10^ kg) of coal per day to a medium-Btu
synthesis gas for power production. The net plant output is 90 to 100
MW, depending on operating conditions. The program coal is a specified
Utah run-of-mine coal with approximately 0.5 weight percent sulfur. The
program has also tested Illinois No.6 coal, containing 3.1 weight percent
sulfur, and Pittsburgh No. 8 coal, containing 2.8 weight percent sulfur.
Gasifier performance at the Cool Water plant has been better than
originally expected. Single-pass carbon conversions have been greater
than 98 weight percent when the plant is operated on Utah coal. Also,
the high carbon conversions are being attained at lower reaction
temperatures than originally expected. The lower gasification
temperatures have reduced oxygen costs and extended refractory life.
Actual oxygen consumption has been 6 percent lower than the design value.
Gasifier refractory life is presently estimated to be 3-year actual
versus a 1-year design value on low-sulfur Utah coal.
Plant heat rates have also been in line with the original projections of
11,300 Btu/kWh (11,920 kJ/kWh). The Cool Water plant's high heat rate is
the result of several early design decisions to reduce front-end project
costs for the IGCC demonstration. This heat rate has been adjusted by
EPRI (5) to account for differences in equipment and conditions to
coincide with Fluor's estimate of the heat rate for a commercial Texaco-
based IGCC plant of 9,010 Btu/kWh (9,500 kJ/kWh). The plant does not,
for example, use a reheat steam turbine, and the gas turbine is a less
efficient current version. Table E-l lists the main differences in
equipment and conditions between the Cool Water plant and an anticipated
commercial plant, and the effects on system performance. Equipment
sparing was also minimized.
E-4
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Table E-l. Adjustment of Cool Water Heat Rate and Comparison
with Estimate for a Commercial Plant
Cool Water Design
Heat Rate
Correction for
Reheat Steam Cycle
(Cool Water uses non-reheat steam cycle with lower steam temperature compared to commercial
design.)
Correction for Slurry 300 (316)
Concentration
(Cool Water uses 60% coal slurry feed versus 66-1/2% for commercial design.)
Correction for ISO* 230 (243)
Ambient Conditions for
Gas Turbine
(Cool Water heat rate is evaluated at 80°F versus 59°F ambient as a standard condition.)
Corrections for Oxygen 601 (634) 9,852 (10,392)
Purity, Saturator,
2020°F Gas Turbine
(Cool Water uses higher-pressure, purer oxygen than is necessary and a 1985°F turbine.)
Correction for Plant 356 (376) 9,496 (10,016) 9,490 (10,000)
Size
(Scaling up Cool Water to a commercial size would reduce plant auxiliary loads as a fraction of
gross power generation.)
Conection for 2300°F 486 (513) 9,010 (9,504) 9,009 (9,503)
Gas Turbine
Heat Rate
Adjustment
Btu/kWh
(kJ/kWh)
EPRI
Adjusted
Cool Water
Heat Rate
Btu/kWh
(kJ/kWh)
Fluor/EPRI
Estimated
Commercial
Plant Heat Rate
Btu/kWh
(kJ/kWh)
380 (401)
11,363 (11,986)
"ISO: International Standards Organization
Source: Reference 5.
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One major goal of the Cool Water demonstration plant is to obtain a
comprehensive package of data demonstrating the environmental
acceptability of the technology. Overall, the environmental performance
of the plant appears to be satisfactory during operations with all three
of the coals tested to date. The data on overall emissions from Cool
Water (based on results from continuous monitoring averaged over 3 to 6
hours when the plant was operating at full load) versus the U.S. EPA New
Source Performance Standards are shown in Table E-2. The Cool Water
plant's SC>2 emissions are typically 10 to 20 percent of the allowable
levels under EPA's New Source Performance Standards for coal-fired power
plants with stack-gas scrubbers. Sulfur removal from the syngas has
ranged from 97 to 99 percent. Overall sulfur recovery from the feed coal
is typically 97 percent. Stack emissions of N0X and particulates
have also averaged about 10 percent of allowable levels under the New
Source Performance Standards. N0X emissions are controlled by means of
steam injection or water saturation of the fuel gas prior to combustion
in the gas turbine.
The most significant operating problem to date has been the failure of
the radiant syngas cooler that occurred in December 1986. A crack
appeared in the top of the radiant cooler, apparently due to a hotspot
that developed in this area. The hotspot condition was attributed to
plugging in the crossover duct between the radiant and the convection
coolers, leading to maldistribution of the hot gas in the radiant cooler.
The crossover duct was redesigned to eliminate plugging, the cooler was
repaired, and the main gasifier went back in service in June 1987. While
the main gasifier was being repaired, the plant continued operating with
the backup quench gasifier.
The gasifier, heat recovery steam generator, and gas turbine have all
operated reliably. No changes in their fundamental designs are deemed
necessary as a result of being tested as components of an IGCC system at
Cool Water.
E-6
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Table E-2. Heat Recovery Steam Generator (HRSG) Stack
Emissions from the Cool Water Plant
Data in lb/MMBtu (kg/GJ)*
SUFCOc Pitts. #8
Permit 1985 111. #6 Source Federal
Limitb EPA Test EPA Test Test NSPSa
S02: 0.16 (0.68) 0.068 (.029) 0.122 (.052) 0.6£ (.257)
(High S)c
S02: 0.033 (0.14) 0.018 (.008) 0.24' (.103)
(Low S)°
NO* 0.13 (.056) 0.07 (.030) 0.004 (.002) 0.066 (.028) 0. 6f (.257)
CO 0.07 (.030) 0.004 (.002) 0.004 (.002) <0.002 (C.001) NSh
Particulates 0.01 (.004) 0.001 (C.001) 0.009 (.004) 0.009 (.004) 0.03 (.013)
a. 1 lb/MMBtu = (0.428 kg/Million kJ).
b. Emission limits from EPA permit (based on design estimates of plant emissions).
c. SUFCO: Southern Utah Fuels Co.
d. New Source Performance Standards for a coal-fired power plant burning equivalent
coal as Cool Water.
e. In the context of the Cool Water plant and its permit, high-sulfur coal is defined
as coal containing more than 0.7 wt. % S and less than 3.5 wt. % S. Low-sulfur coal
is defined as coal containing less than 0.7 wt. % S.
f. Emissions controlled to 0.6 lb/MMBtu.
g. 0.8 lb/MMBtu uncontrolled emissions x 0.3 for controlled emissions.
h. NS: no standard.
Source: Reference 5.
E-7
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The costs of the Cool Water Project--both capital, and operating and
maintenance costs--have been collected and assessed by the program, and
economic evaluations continue. The Cool Water plant is only a
demonstration project of commercial-scale components for a single train
and not a complete, up-to-date, commercial multi-train plant, using the
most advanced technology and operating in an independent commercial
environment. The plant receives financial backing from the U.S.
Synthetic Fuels Corporation in the form of price guarantees. Thus, Cool
Water costs provide only an indication of what potential costs might be
for a truly commercial plant.
As a result of the experience gained with the Cool Water project, a
second-generation demonstration IGCC plant similar to Cool Water could
probably be built at lower cost. This appears to be the case because no
problems were encountered whose solution required redesign or plant
modifications leading to increased costs. For example, it was learned
that the radiant syngas cooler was grossly overdesigned since it produces
over 90 percent of the total steam produced in the syngas coolers. A
smaller syngas cooler could lead to a more optimum cooler design
combination and lower costs.
The Cool Water operation is apparently a successful near commercial-scale
demonstration in every respect. However, because of various cost
constraints, the plant was never designed to compete economically and
requires financial guarantees to operate. On the other hand, the Cool
Water experience has provided significant data leading to process
improvements and indicating the basic operability and success of
combining chemical process technology with power generation. Cool Water
data, when extrapolated and analyzed, support the potential of IGCC
technologies.
Although the Cool Water plant has been successful, technical questions
must be resolved before utilities will embrace even Texaco-based IGCC
technology in a significant way. Some of these technical questions are:
E-8
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o Operability of the Texaco gasifier at full throughput
o Materials of construction
o Plant operation over an extended period of time with high-
sulfur Eastern coals
o Plant availability/reliability.
Only a successful demonstration designed to be couipetiLive in a commercial
environment with the advanced technology and operated over a satisfactorily
long runtime can resolve these questions.
Gasification Systems
It is possible Lo design an IGGC sysLem in a variety of configurations with a
number of different technologies to meet various objectives. The most
important technology choice influencing system performance and costs is,
however, the gasification technology. Several different Lypes of gasifiers
are actively being developed and are in different stages of demonstration.
EPRI has sponsored a series of design and cost-estimate studies that
illustraLe the merits of each technology and its recent status of development
(8,9,10). In addition, a comprehensive evaluation and comparison of coal
gasification technologies is available in the relatively recent literature
(1).
The most important gasification technologies (based on their state of
development), in terms of their near- or mid-term potential application to
IGGG systems, appear to be the following (7):
o Texaco
o Dow
o British Gas Corporation/Lurgi
o Shell.
E-9
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Other technologies have been evaluated for this application but appear to
be less well known or less developed, with fewer resources being
available to support their full development. Table E-3 compares the most
important gasification technologies in terms of their commercial and
development status.
The technological status of IGCC design is a function of the type of
gasification system. The several gasification technologies being
developed for IGCC application are in different stages of development
with different kinds and amounts of technical risk.
• Texaco-based systems are further along in being demonstrated
at commercial scale and so carry less risk, although certain
questions remain to be resolved.
• Less advanced in being demonstrated, the Shell gasifier is
still in the pilot-plant stage, and the BGC/Lurgi gasifier has
reached prototype size. Scale-up of these gasifiers to
commercial size may yet reveal serious problems requiring R&D
for their resolution.
• The Dow system is being demonstrated at commercial scale but
cannot be considered commercial because no information is
available on its operation and financial guarantees (from the
Synthetic Fuels Corporation) were apparently required to make
the technical and economic risks involved acceptable.
At this point in time, there do not appear to be any insurmountable
development requirements which might prevent IGCC technology from
achieving its technical potential.
Advanced Gas Turbines
Since the efficiency of gas turbines increases as the inlet gas
temperature is increased, recent developments in advanced materials and
designs have led to stationary turbines that operate at ever higher
temperatures. The current commercially available General Electric (GE)
MS7001F gas turbine has an operating temperature of 2300°F.
E-10
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Table E-3. Status of Second-Generation Gasification Technologies for IGCC Systems
Process Type
Texaco Entrained Flow
Dow Entrained Flow
BGC/Lurgi - Slagging Fixed Bed
Shell Entrained Flow
Date of
Operating Units Operation
• Cool Water, 2 x 1000-TPD Coal: 117-MWe IGCC 1984
• UBE, Japan; 4 x 500-TPD 1984
• Tennessee Eastman; 2 x 900-TPD 1983
• Ruhrchemie, Germany; 1 x 800-TPD 1986
• 160-MWe IGCC at Plaquemine, LA 1987
2 x 2400-TPD Gasifiers
• 600-TPD Unit at Westfield, Scotland 1986
• 250-TPD Pilot Plant in Texas 1987
Source: Reference 7. Electric Power Research Institute. Reprinted with permission.
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This model recently replaced Model MS7001E, which operated at 2000'1F. This new
turbine incorporates the latest technology in the compressor, combustion system,
and turbine designs.
The only emissions currently controlled with the Federal New Source Performance
Standards (NSPS) for gas turbines are NOx emissions. For utility turbines
generating more than 9 MW (30 MW thermal), N0X generation is restricted to 75 ppm
(12). The older model MS7001E gas turbine in an IGCC setting generated about
40 ppm, while the newer Model MS7001F generates about 50 ppm of NOx (8) .
Environmental Characteristics
Sulfur removal and recovery i3 an integral part of IGCC and, in fact, is one of
the inherent advantages of IGCC over other coal-based electric generation
technologies. Direct coal combustion requires removal of sulfur as S02 in a
dilute flue gas stream at low pressure. The costs for flue gas desulfurization
are relatively high, compared to the costs of sulfur removal from coal gases.
IGCC, on the other hand, involves the removal of sulfur principally as H?S plus
some COS from the high-pressure, medium-Btu fuel gas produced in the coal
gasifiers. The H2S is removed from the coal gas and then converted to elemental
sulfur. This removal and recovery is relatively cheap and extremely efficient.
Furthermore, numerous H2S removal and sulfur recovery processes are commercially
used throughout the oil, chemical, and natural gas industries.
E-12
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IGCC designs all have excellent environmental characteristics compared to other
power generation systems, in terms of S02, N0X, particulate emissions, and solid
wastes, and there are solid technical reasons for IGCC's environmental
superiority.
Economics of IGCC Systems
The most recent and detailed cost estimates readily available in the literature
for commercial IGCC plant designs appear to be the costs developed in EPRI's most
recent series of IGCC design studies for the three major systems being developed
[Texaco (8), BGC/Lurgi (9), and Shell (10)]. To facilitate comparative studies
of these IGCC designs and different power generation technologies, EPRI has
examined the original figures and made certain adjustments to bring all the costs
to a common basis expressed in common dollars at a common location. The
resultant figures are published in the latest version of EPRI's Technical
Assessment Guide (TAG) (13).
Other estimates showing ranges of capital costs for IGCC and other technologies
are presented in Figure E-2. The cost ranges in this figure were developed by
EPRI (14) on the basis of estimates from a number of recent studies. Performance
estimates and costs adjusted to January 1987 dollars are shown in Table E-4 for
PC plants and the three IGCC designs. These cost estimates indicate that the
capital costs for IGCC systems appear to be within the same range as the capital
costs for conventional PC plants and for AFBC. Because capital cost estimates,
especially for new immature technologies that do not have long commercial
histories, are not precise and are often optimistic, this conclusion is the only
one that can be drawn from these generic data. In a specific situation utility-
and site-specific factors must be considered to determine which technology is
more economic. The capital costs for the three IGCC designs show a significant
range that is dependent upon gasification technology and design.
E-13
-------
Capital Cost - Constant 1985 $/kW
2000
1600
1200
800 —
400
%
$
IGCC PC AFBC
Source: Reference 14 (Reproduced with permission from the Annual Review of Energy, Volume II, © 1986, by Annual Reviews, Inc.)
Phased
IGCC
Figure E-2. Capital Investment Estimates for Single 500-MW Units.
AFBC Has One 200-MW Unit Case.
-------
Table E-4. Summary of Comparative Costs and Performance Estimates for PC and IGCC Plants
Capacity - 500 MWe; Illinois #6 Coal; Constant January 1987 Dollars
Reference
Coal-Fired
Steam Plant
Texaco
Partial
Oxidation
Shell Coal
Gasification
Process
BGC Lurgi
Slagging
Gasifier
Sulfur Removal, %
90
95-97
90-99
95-97
NOx Emission, ppmva
150
50-75
50-75
50-75
Heat Rate, Btu/kWh
9,850
9,010
8,720
8,660
Total Capital, $/kWb
1,390
1,540
1,490
1,300
Levelized Cost of Electricity
54.9
52.7
50.8
48.9
at 65% capacity factor, mills/kWh
(a) 15% Excess Oz, Heat Rate Corrected; 2300°F Combustion Turbine for IGCC Plants.
(b) Includes working capital, start-up costs, spare parts, land, royalties, and allowance of funds used during construction; all IGCC
plants rated at 88°F.
Source: Reference 13. Electric Power Research Institute. Reprinted with permission.
-------
Another means of comparing power generation technologies is to compare
the cost of the electricity generated. This comparison is usually done
via "busbar costing methodology" to compute a levelized cost of
electricity (COE) over the life of the plant. The levelized cost of
electricity is shown in Table E-4 as calculated by EPRI. These values
show a consistently lower COE for IGCC than for conventional PC under the
limited range of assumptions made. However, these differences in the
value of the COE between PC and IGCC are not significant and, by
themselves, would not be enough incentive for a utility to invest in an
IGCC system, which is perceived at this point as technically risky
compared to PC.
One of the advantages of IGCC systems is that they can be highly modular
(i.e., contain several parallel trains of gasification and gas turbine
components). Therefore IGCC plants can be constructed in relatively
small increments (200 MW to 250 Mtf), resulting in the important
capability for a utility of conserving capital. The modular
characteristic of IGCC systems also leads to high potential equivalent
availabilities. This characteristic also leads to capital conservation
(by reducing reserve margin requirements) and results in lower revenue
requirements as plants can be dispatched at higher capacity factors.
Another advantage of IGCC's modularity is that IGCC can be added in
phases of partial capacity to more closely match load growth (14,15).
There appears to be an economic incentive to add capacity in phases when
net present values of expenditures are compared. Phased capacity
addition also appears to offer other benefits compared to unphased
capacity addition. These benefits include increased flexibility, the
ability to recover from sudden and unforeseen changes in load demand,
reduction in, and deferral of, "at-risk" capital, and earlier entry of
capital into the rate base.
The value of phased capacity addition may be seen by comparing the net
present value of capital expenditures for all phases with the net present
E-16
-------
value of capital expenditures for an unphased plant. In a recent study (15) the
net present value of capital expenditures was calculated for each of three load
growth scenarios (5 years, 7 years, and 10 years) for adding the capacity of one
unphased IGCC Plant. Savings due to phased capacity addition ranged between
about $200/kw and $400/kW for these examples.
On the basis of simple comparisons using generic cost and performance data, the
economics of IGCC and competing technologies are very comparable, the most
economic choice being determined by utility- and site-specific factors (16). To
obtain more detailed information on the effects of these factors on the potential
cost-competitiveness of IGCC, the Utility Coal Gasification Association (UCGA)
and EPRI are each sponsoring a series of utility-specific studies. The results
of these studies should support more definitive conclusions on the economics of
IGCC and its acceptability to utilities.
Seven such UCGA studies have been concluded and organized into a report (17).
Six of these studies included IGCC and conventional PC plants among the
alternatives considered, and five of 3ix found phased IGCC to be more attractive
economically than conventional PC plants. Three of these five even found
unphased IGCC to be more attractive, the other two not making this comparison.
The sixth study concluded that PC was more attractive than unphased IGCC.
Site-specific and cost studies of IGCC show sufficient potential for a number of
utilities to begin preliminary planning studies for IGCC (e.g., 18). However,
since little additional baseload capacity must be implemented now, many utilities
are waiting to see how IGCC and the various gasification technologies continue
to develop before seriously considering the technology.
E-17
-------
Potential Future Market for IGCC Systems
Projections of the total installed power generation capacity of various
types of systems were obtained from base runs of the Advanced Utility
Simulation Model (AUSM) . According to these projections, made with the
EPA interim base case scenario, the total installed capacity for coal-
steam plants will increase by 200,000 MW and gas turbine capacity by
57,000 MW from 1990 to 2010.
The potential application of IGCC systems in this future power generation
market will be influenced by a variety of factors. The most important
factors may be a satisfactory commercial demonstration of IGCC and IGCC's
cost-competitiveness. Utilities must have adequate incentive to accept
the technical risk associated with IGCC's lack of a long operating
history. The situation that appears to provide the most economic
incentive is the concept of phased implementation. As explained above,
phased implementation provides a number of benefits in addition to lower
overall revenue requirements, and it is possible that IGCC will be
implemented initially via this path.
Thus, since phased implementation begins with purchasing combustion
turbines initially to provide peaking capacity, it is suggested that the
estimated market for gas turbines may provide a clue to the potential
initial market for IGCC. The projected market of about 57,000 MW for new
gas turbines from 1990 to 2010 should provide significant opportunity for
phased IGCC systems. When the cost of natural gas rises sufficiently to
make coal-derived gas cost-competitive, gasification systems and steam
turbines could be added to form complete IGCC plants. Thus, some of this
future peaking capacity could gradually evolve into IGCC baseload
capacity that would satisfy part of the anticipated market for new coal-
steam plants. Additional opportunities for application of IGCC include
repowering of existing coal-fired steam plants and complete IGCC plants
that might be built as an unphased capacity addition in competition with
conventional PC or other technologies such as AFBC.
E-18
-------
Conclusions
The following conclusions were reached as the result of this study:
1. IGCC designs all have excellent environmental characteristics compared
to other power generation systems, in terms of S02, N0„, particulate
emissions, and solid wastes.
2. The several gasification technologies being developed for IGCC
application (Texaco, Shell, BGC/Lurgi, Dow) are in different stages of
development with different kinds and amounts of technical risk.
3. The Cool Water plant, a Texaco-based system, is apparently a very
successful near commercial-scale demonstration for a Western low-sulfur
coal under baseload conditions. Because of various cost constraints,
the plant was never designed to compete economically and requires
financial guarantees to operate. However, Cool Water data, when
extrapolated and analyzed, support the future potential of IGCC
technologies.
4. Nevertheless, several technical questions remain to be resolved before
utilities will embrace even Texaco-based IGCC technology in a
significant way, such as:
- Operability of the Texaco ga3ifier at full throughput
Materials of construction
Plant operation for at least a year with high-sulfur Eastern coals
Plant availability/reliability.
Only a successful commercial demonstration with advanced technology,
operated over a satisfactorily long runtime, can resolve these
questions.
E-19
-------
5. A number of utilities have conducted preliminary planning studies for
IGCC. However, many utilities are waiting to see how IGCC and the
various gasification technologies develop before seriously considering
the technology. Many feel that oil and gas prices must increase
sufficiently relative to that of coal before coal gasification will be
economically competitive.
6. Phased implementation may give IGCC significant economic advantages.
However, a utility must have access to oil or natural gas to be able
to take advantage of phased implementation, and must be prepared to
assume the economic risk of increased reliance on natural gas or oil.
7. Simple cost comparisons of IGCC with competing technologies indicate
that capital costs may all be within the same range. The higher energy
efficiency of IGCC may result in a slightly lower levelized costs under
a limited range of assumptions.
Recommendations
As the result of this technoeconomic appraisal of IGCC power generation, the
following recommendations are made:
1. Because of the significant work which is currently being done to
evaluate IGCC systems, it would be desirable to follow up this current
appraisal with periodic updates and analyses.
2. Because utility attitudes, perceptions, and requirements are of
paramount importance in determining the potential implementation of
IGCC, it would be desirable that more extensive discussions be held
with utilities regarding IGCC.
E-20
-------
3. It is also desirable that the potential role of IGCC in repowering be
examined in detail. However, site-specific conditions are particularly
important, arid studies being conducted by EPRI could be an imporLant
future source of information regarding the repowering potential of
IGCC.
4. Since phased implementation is an importaiiL concepL affecting the
potential employment of IGGC, it would be desirable to incorporate
phased implementation into EPA utility models.
E-21
-------
REFERENCES
1. Synthetic Fuels Associates, Inc.f "Coal Gasification Systems: A Guide
to Status, Applications, and Economics,™ EPRI Report AP-3109, June
1983.
2. Bechtel Power Corporation et al., "Cool Water Gasification Program:
First Annual Progress Report," EPRI Report AP-2487, July 1982.
3. Cool Water Coal Gasification Program et al., "Cool Water Coal
Gasification Program: Fourth Annual Progress Report," EPRI Report AP-
4 832, October 1986.
4. Clark, Wayne N. and Vernon R. Shorter, "Cool Water: Mid-Term
Performance Assessment," Sixth Annual EPRI Coal Gasification
Contractors' Conference, Palo Alto, October 15-16,. 1986.
5. Clark, Wayne N., "Cool Water: Economically Competitive and
Environmentally Superior Electrical Power Production," Benelux
Association of Energy Economists' Symposium, the Hague, Netherlands,
April 22, 1987.
6. Personal communications, Paul Dinkel, Cool Water Coal Gasification
Program, to Malcolm Eraser, SAIC, August 7 and October 5, 1987.
7. Holt, N.A., "Worldwide Gasification - An Overview", in Proceedings of
the Second International Conference on Coal-Fired Plants, November 2-4,
1988, EPRI Report GS-6422 Vol. 1, Undated.
8. Fluor Engineers, Inc., "Cost and Performance for Commercial
Applications of Texaco-Based Gasification-Combined-Cycle Plants," EPRI
Report AP-3486, Vols. 1 and 2, April 1984.
9. Ralph M. Parsons Company, "Evaluation of the British Gas Corporation/
Lurgi Slagging Gasifier in Gasification-Combined-Cycle Power
Generation," EPRI Report AP-3980, March 1985.
10. Fluor Engineers, Inc., "Shell-Based Gasification-Combined-Cycle Power
Plant Evaluations," EPRI Report AP-3129, June 1983.
11. Personal communication, R. 0. Anderson, Combined-Cycle Technology
Turbine Projects Department, GE, to Isaac Kwarteng, SAIC, August 25,
1987.
12. KVB, Inc., "Guidebook for the Use of Synfuels in Electric Utility
Combustion Systems," Vol. 2, Coal-Derived Gases, EPRI Report AP-3348,
January 1985.
13. EPRI, "TAG™ - Technical Assessment Guide," EPRI Report No. P-6587-L,
Vol. 1, November 1989.
14. Alpert, S.B. and M.J. Gluckman, in Annual Review of Energy-1986,
Vol. 11, pp. 315-355, Annual Reviews, Inc., Palo Alto, CA, 1986.
E-22
-------
REFERENCES (Continued)
15. Snyder, William G. and Michael J. Giuckman, "Phased implementation of Coal
Gasifi cati on-Couibined-Cycle Power," Proceedings, Fifth Annual EPRI
Contractors' Conference on Coal Gasification, Palo Alto, October 30-31, 1985,
EPRI Report AP-4680, July 1986.
16. Minderman, David J. et al. , "1GCC Site-Specific Evaluation Addressing Generic
Study Limitations," Proceedings, Fifth Annual EPRI Contractors' Conference on
Coal Gasification, Palo Alto, October 30-31, 1985, EPRI Report AP-4680, July
1986.
17. Utility Coal Gasification Association and EPRI, "Economics of Phased
Gasification Combined-Cycle Plants: Utility Results," EPRI Report No. AP-
5466-SR, November 1987.
18. Scherer, S. M., "PEPCO's Early Planning for a Phased Coal Gasification
Combined-Cycle Plant," Proceedings, Conference on Coal Gasification Systems
and Synthetic Fuels for Power Generation, San Francisco, April 14-18, 1985,
Vol. 1, EPRI Report AP-4257-SR, December 1985.
E-23
-------
-------
1.0 INTRODUCTION
1.1 Background
Projections into the next century of SO2 and N0X emissions from U.S. coal-
based electric generating plants are significantly affected by the many
assumptions which must be made. These assumptions, among others, include
the rate at which existing coal-fired boilers will be retired, as opposed
to being overhauled for life extension purposes; the rate at which new
coal-based generating units will be built, either to replace retired
capacity or to increase generating capacity from current levels; and the
technologies which will be used in these new units. The two technologies
which are emerging as future competitors to current pulverized-coal (PC)
boilers equipped with pollution control devices [e.g., low-N0x burners and
flue gas desulfurization (FGD)] are fluidized-bed combustion (FBC) boilers
and integrated (coal) gasification combined-cycle (IGCC) systems.
It has been suggested that, because of its potential for increased thermal
efficiency and very low SO2 and N0X emission rates, IGCC would be the
"technology of choice" for most future new electric generating capacity.
In addition, it has been suggested that the potential advantages to IGCC
will cause a number of current PC boilers to be retired and their capacity
replaced by IGCC plants at the end of the boilers' "normal" life (e.g., 35-
40 years), or perhaps even earlier if IGCC costs are sufficiently low.
This action, if taken, could result in drastic reductions in U.S. SO2 and
N0X emissions in the early part of the 21st century.
However, IGCC plants are not yet a proven commercial technology with
demonstrated benefits and reliably competitive costs. Technical risks are
therefore associated with IGCC, based upon the current status of its
technology. Because these technical risks and the perceived economics of
IGCC will influence its actual rate of penetration, and the possible impact
of IGCC upon expected future emissions, the EPA decided to have performed
an independent technical and economic assessment of IGCC systems.
1-1
-------
1.2 Purpose and Objectives of Study
The purpose of this study was to perform an independent technical and
economic assessment of IGCC technologies and systems. The three main
objectives of the study consisted of: 1) a technical assessment focused on
the technical risks associated with IGCC, based on the current status of
the technologies that it employs; 2) an economic evaluation considering the
comparative economics of IGCC versus its "competition" for new coal-fired
power plants; and 3) an evaluation of the potential future market for IGCC
application to new power generation plants.
1.3 Methodology
The effort in this study was organized around three tasks corresponding to
the three main objectives. The first task was to perform a technical
evaluation of IGCC technologies and systems.
The first part of the technical evaluation task was devoted to gathering
information on the status of IGCC technology. On the basis of the gathered
information, a technical assessment was made of the equipment and processes
involved to identify and evaluate areas requiring significant research and
development. Particular attention in this assessment was paid to the heat
recovery systems--the syngas coolers and the steam generators. Also given
close attention was the likelihood of simultaneously achieving the energy
efficiency and pollution control goals for this technology. An evaluation
was made of the risks involved in overcoming current technical problems
associated with making IGCC systems fully commercial. This evaluation
formed the basis for estimating the effects of future R&D on IGCC cost and
performance estimates.
Sources of information on IGCC technology which were accessed to meet these
objectives included:
1-2
-------
• Previous assessments of IGCC systems such as
Report on "New Electric Power Technologies," OTA, July 1985
Reports on studies sponsored by the Electric Power Research
Institute (EPRI)
• Technology developers and vendors.
Although previously published information was the primary source, visits
were made to EPRI and the Cool Water facility to obtain up-to-date
information on the progress of R&D on IGCC systems. Technology developers
and vendors were also contacted as appropriate to fill gaps in the
available information.
For the economic evaluation task, comparative cost and performance
estimates were collected for IGCC, atmospheric fluidized-bed combustion
(AFBC), and conventional PC boilers (with low-NOx combustion and FGD).
Applications of these technologies were examined by comparing the cost and
performance of new plants based on these technologies. The ranges of the
cost and performance of IGCC were considered in this comparison to provide
bounds on the IGCC results. Capital costs are presented in $/kW, and
annual costs (including capital carrying charges) are in mills/kWh.
Required input data on the costs of IGCC were delivered for incorporation
within the Advanced Utility Simulation Model (AUSM). The incorporation of
such data within the model was not, however, part of this work assignment.
The required data for characterization of a technology for AUSM include:
• Planned outages
• Unplanned outage including partial deratings
• Heat rate
• Construction period and cost fraction by year
• Lifetime
• Size
• Nonfuel annual O&M
• Fixed annual costs
1-3
-------
• Total construction cost (total plant cost/overnight
construction).
Ranges of costs are supplied, but the data are not regionalized. Other
needed information includes:
• Restrictions on fuel use: ash, heat content, sulfur content
• Emissions factors: sulfur retention, sludge production, SO2,
N0X, TSP.
Additionally, representative cases taken from the literature of comparisons
of IGCC with other technologies are shown to illustrate IGCC technology's
potential penetration of the utility industry.
The objective of the third task was to estimate the potential future market
for IGCC in the coal-based power generating market. This evaluation of the
IGCC market was based upon considering the estimated total market for new
coal-based generating capacity. This latter quantity, as a function of
time, was obtained from the Advanced Utility Simulation Model run with the
interim EPA base case scenario. These data were already available from
another project. Utility attitudes regarding IGCC were assessed by
communicating with a number of utilities involved in the Utility Coal
Gasification Association.
1.4 Description of Generic Integrated Gasification Combined-Cycle (IGCC)
System
Figure 1-1 is a generalized block flow diagram showing the key process
steps in an IGCC system (1).
Coal is fed to the gasifier where it reacts with steam and oxygen to
produce a hot raw fuel gas, which is cooled and purified to remove
particulates and acid gas (hydrogen sulfide). Elemental sulfur is
recovered from the acid gas. The clean fuel gas is burned in a 2000°F
combustion turbine. The hot flue gas (900-1000°F) leaving the combustion
1-4
-------
COAL
SEPARATION
Water
Flue Gas
Ln
COAL
HANDLING
Oxygen
Steam
Boiler Feedwater
Saturated Steam
HEAT RECOVERY
STEAM
GENERATION
(HRSG)
GASIFICATION,
GAS COOLING,
AND SCRUBBING
ACID GAS
REMOVAL
Superheated
Steam
Steam for
Fteheat
Fteheated Steam
STEAM
TURBINE
Hot Turbine
Exhaust Gas
COMBUSTION
TUR8INES
Blowdown
or
"Bleed"
Stream
Acid Gas
Air
WASTEWATER
Cooling
TREATMENT
Tower
SULFUR
RECOVERY
Plant Power
Requirements
Source: Reference 1. Copyright ©(1983) Electric Power Research Institute. Reprinted with permission.
Ash
Sulfur
Figure 1-1. Generalized Block Flow Diagram of Coal Gasification Integrated
with Combined-Cycle Electric Power Generation.
-------
turbine is cooled by generating, superheating, and reheating steam in a
heat recovery steam generator. This steam is utilized in a steam turbine.
Power is generated from both the combustion turbines and the steam
turbines.
Integration of the coal gasification and the combined-cycle facilities is
conducted primarily through the plant steam system. A large quantity of
saturated, high-pressure steam is generated in the coal gasification
system. This saturated steam is then superheated and reheated in the heat
recovery steam generator (HRSG), recovering combustion turbine exhaust
heat. The primary purpose for integrating the gasification system with the
combined-cycle plant is that this design configuration substantially
improves the overall system energy efficiency or heat rate. IGCC appears
to be a practical means for combining the high efficiency and operability
of combined-cycle systems with the low cost and ready availability of coal
as the fuel.
Although all components included in an IGCC configuration have, in some
way, been demonstrated to operate at full commercial scale (i.e.,
gasifiers, gas coolers, acid gas removal systems, combined cycles), they
have only recently been operated in unison in a complete system to
generate electric power. Integrated control and operation of such plants
in a commercial environment must be demonstrated on a large scale before
the majority of the electric utility industry will seriously consider
adopting IGCC systems for electric power generation. Taking a step closer
to this goal by resolving some of these issues is one of the central
objectives of the Cool Water Gasification Program.
1-6
-------
2.0 COOL WATER DEMONSTRATION IGCC PLANT
2.1 Introduction
The Cool Water Gasification Program (2,3,4,5,6) is an undertaking of a
number of private entities to design, construct, and operate the nation's
first IGCC power plant to supply electricity to a utility system. The
demonstration plant, comprising commercial-scale components and subsystems,
is located at the Cool Water Generating Station of Southern California
Edison Company (SCE) near Barstow, California, about halfway between Los
Angeles and Las Vegas in the Mojave Desert. Organizations presently
sharing in the funding of the $300 million effort are EPRI, SCE, Texaco
Inc., Bechtel Power Corporation, General Electric Company (GE), Japan Cool
Water Program Partnership (JCWP), the Empire State Electric Energy Research
Corporation (ESEERCO), and the Sohio Alternate Energy Development Company.
The plant utilizes an oxygen-blown Texaco gasifier that is sized to convert
1000 tons of Utah coal per day to a medium-Btu syngas. After particulate
and sulfur removal, the syngas is used to fuel a GE combined-cycle unit
that comprises a slightly modified Frame-7 combustion turbine-electric
generator, a heat recovery steam generator (HRSG), and a steam turbine-
electric generator. The net plant output, after serving auxiliary loads
and accounting for power supplied to an "over-the-fence" air separation
unit providing the oxygen needed for gasification, is 90 to 100 MW,
depending on operating conditions.
Detailed engineering for the plant began in February 1980. The engineer-
constructor Bechtel Power Corporation began construction in December 1981,
immediately after project funding was secured. Construction of the plant
was completed ahead of schedule and under budget on April 30, 1984. The
Cool Water plant began producing electricity for the grid on June 24, 1984,
and is being operated by the Program for a five-year commercial-
demonstration period. SCE, a Cool Water partner and the host utility,
has an option to purchase the plant in June 1989 for continued design-
life operations. The final capital cost of the plant was $263 million.
2-1
-------
It is the goal of the Cool Water Gasification Program to demonstrate the
environmental and economic characteristics of an integrated gasification
combined-cycle power generation plant on such a scale and in a time frame
that will lead to widespread commercial acceptance by the late 1980s.
2.2 Project Objectives
For almost 30 years in a large number of plants worldwide, Texaco has
licensed commercially its Synthesis Gas Generation Process for use with
oil or natural gas feed. The Texaco Coal Gasification Process, which was
derived from this oil partial oxidation technology, has received greatly
increased emphasis recently and has been extensively tested on the small
and large pilot-plant scale. Specifically, a wide range of coals and other
solid feedstocks have been processed in Texaco's 15-ton-per-day Montebello
(Los Angeles) unit over the last decade, and Ruhrchemie, a West German
chemical firm, has successfully operated a 165-ton-per-day Texaco gasifier
at Oberhausen since 1978. This latter unit has logged over 10,000 hours of
operation, including runs of about 500 hours each on Pittsburgh No. 8,
Illinois No. 6, and Utah coal (the Cool Water design coal). One of the
main objectives of the Cool Water project is to identify and rectify scale-
up problems that might occur with operation of the gasification process at
the 1000-ton-per-day level; i.e., resulting from a six-fold increase in
size.
Essentially, all of the other elements of the IGCC system have individually
been operated successfully in one application or another at the size used
for Cool Water. However, some of the process segments--e.g., the sulfur-
removal facilities and the air separation unit--have traditionally been
required to operate almost exclusively at only a steady-state level.
Furthermore, the degree and number of direct.interrelationships among the
various components of the IGCC system have been rarely present in existing
conventional practice. A key goal of the project has been to verify the
operability and controllability of the overall heavily integrated system in
both steady-state and load-following modes and under startup, shutdown, and
emergency conditions.
2-2
-------
Equipment and system reliability is another area specifically addressed at
Cool Water to provide important failure rate and repair data. Efficiency
and costs are being evaluated to confirm or, if necessary, to correct
projections for commercial plants. Extensive monitoring of environmental
performance is also being carried out in compliance with the project permit
conditions and to develop information for future planning. To demonstrate
the feedstock flexibility of the gasification process, several coals,
including both Eastern and Western varieties, are being tested. During the
course of operations, detailed operating, maintenance, and safety
procedures, which can be applied to future plants, are being developed and
refined.
In short, it is the intent of the parties in the Cool Water project to
obtain a comprehensive package of real plant data on a near-commercial
scale. Table 2-1 summarizes the project objectives of the Cool Water
plant.
2.3 Process Description and Plant Design
The Cool Water plant utilizes an entrained-bed, oxygen-blown Texaco
gasifier to convert 1000 tons (907 x 10^ kg) of coal per day to a medium-
Btu synthesis gas. After particulate and sulfur removal, the gas is
combusted in a gas turbine to produce electricity. In addition, steam is
produced by recovering heat from the hot product gas in syngas coolers and
from gas turbine exhaust gas in the heat recovery steam generator (HRSG).
Steam from both sources is combined and superheated in the HRSG and then
utilized in a steam turbine for production of additional electricity. A
simplified block flow diagram of the process is shown in Figure 2-1.
The Program coal is a specified Utah run-of-mine coal with approximately
0.5 weight percent sulfur. The Program has also tested two high-sulfur
Eastern coals. Illinois No.6 coal, containing 3.1 weight percent sulfur,
and Pittsburgh No. 8 coal, containing 2.8 weight percent sulfur, were run
in early 1986 without encountering any notable problems during the
relatively short run times of approximately one month each.
2-3
-------
Table 2-1. Project Objectives of the Cool Water Demonstration Plant
• Demonstration of acceptable system and equipment
performance at a commercial scale
• Confirmation of system compliance with environmental
criteria
• Verification of controllability of the integrated plant
under all operating conditions, including steady-state,
load-following, startup, shutdown and emergency
• Assessment of equipment and system reliability
• Demonstration of feedstock flexibility
• Preparation of operating, maintenance, safety and
training procedures which could be applied to future
plants
¦ Development of a complete economic and technical data
base for use in commercial application decision-making
and future plant designs
Source: Reference 2. Copyright (1982) Electric Power Research
Institute. Reprinted with permission.
2-4
-------
NJ
i
Ui
Oxygan
1000 Ions/Day
Coal
O
Condensate
Recycle Unconverted
Coal ft Water
Particulate
Scrubbing
ft SolMIng
Cooled
Slack Oaa
Boiler Fttdwilw
Bollei Feedwalar Ileal
Exchange Is Not Sliown
Superheated Slaam
r-
HRSG
PWVN
Saturated
Steam
I
J
Steam
Turbine
Cleue
Plant
Tall Oaa
Treating
M2S
Steem
Sulfur
Removal
1
Saturalor
Stdluf
Clean Venl
Qaa to
Incinerator
Alternate
lo Existing
UnM «l Boiler
©4
-------
Coal is delivered to the plant by rail in unit trains, bottom-dropped from
each hopper car, and conveyed to storage. The coal is stored in two 6000-
ton (5433 x 10^ kg) storage silos. Coal is transferred from the silos to
live storage in the coal grinding area. An inerting gas system is used in
the silos. The unloading facility and all conveyors are enclosed and
equipped with dust collection and suppression equipment to minimize
fugitive dust emissions.
In the coal grinding area coal is combined with recycled water from the
gasification plant and pulverized in a wet rod mill. Rod mill slurry is
then transferred to one of three slurry storage tanks from which the coal
slurry is delivered to the gasifier. Slurry concentrations at the plant
have typically ranged from 60 to 66 percent solids.
The coal-water slurry is combined with oxygen in a specially developed
burner and fed into the refractory-lined gasifier. The partial oxidation
reactions take place in the gasifier at 600 psig (4.1 MPa) and
at temperatures well in excess of 2000°F (1090°C). A medium-Btu synthesis
gas consisting mainly of CO, H2, CO2, and steam is produced. Fuel-bound
nitrogen is converted to nitrogen gas with some ammonia formed. Fuel-bound
sulfur is reduced to H2S with a small amount of COS formed.
The gas contains molten slag, some unconverted carbon and fine flyash. The
hot gas is cooled in waste heat boilers, first in a radiant syngas cooler
where 1600-psig (11.0 MPa) saturated steam is produced. The molten slag
droplets solidify and drop into a water sump at the bottom of the vessel
where a lockhopper is used for slag removal. The raw syngas is then cooled
further in a convection syngas cooler. Additional 1600-psig (11.0 MPa)
saturated steam is produced in the convection cooler's evaporator section,
and boiler feedwater is preheated in its economizer section.
Raw syngas is then routed to the particulate scrubbing and settling area
where essentially all of the fine particulate material is removed in a
carbon scrubber by direct scrubbing with water. Flyash water from the
radiant cooler sump in the waste heat boiler area, and the carbon scrubber
2-6
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is routed to a settler where solids and water are separated. The settler
bottoms containing the solids (unconverted coal) are recycled to the coal
grinding unit.
Syngas from the carbon scrubber is then cooled to 100°F (38°C) by
successive heat exchange with saturator circulating water, steam turbine
condensate, air and cooling water. The cooled syngas flows to sulfur
removal and an acid gas removal unit where the sulfur compounds are
removed. Table 2-2 shows a typical composition of the clean fuel gas.
The clean fuel gas goes to a saturator where the gas is reheated by direct
contact with hot water. The water saturation provides the moisture
required to control N0X formation in the gas turbine. The saturated fuel
gas is then superheated against economized boiler feedwater. The
saturator/clean gas heater system provides N0X control while providing a
useful means of recovering low-level heat from the gasification plant and
HRSG.
The superheated clean fuel gas flows to the gas turbine where it is
combusted with air. Steam injection is also provided, as a backup to the
saturator, for N0X control. The turbine drives an electric generator
producing approximately 65 of electric power.
The hot exhaust gas from the turbine is cooled in the HRSG by producing
1450-psig (10.0 KPa) superheated steam at 950°F (510°G). The HRSG is
composed of three sections: superheater, evaporator and economizer. The
saturated steam raised in the HRSG evaporator is combined with saturated
steam from the syngas coolers and routed to the superheater. The cooled
flue gas is discharged to the atmosphere through the HRSG stack.
Superheated steam from the HRSG is utilized in the steam turbine, which
drives an electric generator producing approximately 55 MW of electric
power.. The steam turbine is a condensing type.
2-7
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Table 2-2. Cool Water Clean Syngas Composition
Component Mol % (Dry Basis')
CO 42.5
H2 38.2
C02 18.6
CH4 0.3
Ar & N2 0.4
II2S & COS 50 PPM
Source: Reference 4. Copyright (1986) Electric Power Research InsLiLule.
Reprinted with permission.
2-8
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The plant generates 117 MW of gross electricity at 13.8 kV. Approxi-
mately 6 MW of electric power is drawn through the plant's auxiliary
transformer for internal use. The balance of the plant electrical output
is transmitted to the existing 220-kV grid through the plant's main
transformer.
The reduction of fuel-bound sulfur to H2S and COS during gasification is
one key to IGCC's environmental performance. The plant uses acid gas
removal, sulfur recovery, and tail gas treating technologies, utilized for
years by the chemical industry, to remove the sulfur compounds from the
fuel gas prior to combustion and to recover the sulfur compounds as
saleable elemental sulfur. The plant uses a Selexol®- unit for acid gas
removal, a Claus unit for sulfur recovery, and a modified SCOT unit for
tail gas treating.
The plant is designed to process a range of coals with sulfur contents from
0.35 to 3.5 weight percent. The removal of H2S and COS remains at a
constant 97 percent in the Selexol^ unit, while the coal sulfur content
changes. The plant uses a modified SCOT unit to increase H2S concentra-
tions to a level acceptable for the Claus unit. The plant's Claus unit
processes acid gases from as low as 20 volume percent H2S to as high as 60
volume percent H2S.
The liquid sulfur produced at the Claus unit is stored and then pumped to
the buyer's truck F.O.B. at the plant.
Oxygen is supplied to the gasifier from an "across the fence" cryogenic air
separation plant which also provides the plant's nitrogen requirements.
The oxygen plant typically draws 17 MW of electric power.
Raw and demineralized water are supplied from SCE's adjacent Cool Water
Generating Station.
2-9
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2.4 Plant Performance
2.4.1 Energy Efficiency (Heat Rate)
Gasifier performance at Cool Water has been better than originally expected
on a commercial scale. Single-pass carbon conversions have been greater
than 98 weight percent when the plant is operated on Utah coal. Single-
pass carbon conversion on Illinois No. 6 coal averaged 96.5 weight percent.
Single-pass carbon conversions have been high enough that the slag screen
classifier, intended to separate fine high-carbon-content slag for recycle
to the gasifier, has not been utilized. Settler bottoms are still being
recycled to the gasifier and increase overall conversions by 0.5 weight
percent above single-pass conversion values.
The high carbon conversions are also being attained at lower reaction
temperatures than originally expected. The lower gasification temperatures
have lowered oxygen costs and extended refractory life. Actual oxygen
consumption has been 6 percent lower than the design value. Gasifier
refractory life is presently estimated to be three-year actual versus a
one-year design value on low-sulfur Utah coal.
Plant heat rates have also been in line with the original projections of
11,300 Btu/kWh (11,920 kJ/kWh). The overall plant heat rate is calculated
from the equation below:
Overall Plant _ Coal Energy Input (HHV)
Heat Rate /Gross Power\ /Plant Auxiliary^ /Oxygen Plants
\Production / \ Power / \ Power I
The plant has conducted partial load tests at 70 percent of the design
plant throughput. Carbon conversions decreased slightly and heat rates
increased approximately 16 percent at the partial load.
The Cool Water plant has a high heat rate of 11,300 Btu/kWh (11,920 kJ/kWh)
on a higher-heating-value (HHV) basis as a result of several early design
decisions to reduce front-end project costs for the IGCC demonstration.
2-10
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This heat rate has been adjusted by EPRI(5) to account for differences in
equipment, operating conditions, and anticipated performance to compare
with Fluor's estimate of the heat rate for a commercial Texaco-based IGCC
plant design of 9,010 Btu/kWh (9,500 kJ/kWh). The plant does not, for
example, use a reheat steam turbine, and the gas turbine is a less
efficient current version. Table 2-3 lists the main differences in
equipment and conditions between the Cool Water plant and an anticipated
commercial plant, and the effects on system performance.
2.4.2 Environmental Characteristics
One major goal of the Cool Water demonstration plant is to obtain a
comprehensive package of data demonstrating the environmental acceptability
of the technology. An environmental monitoring program was developed to
meet this objective, and this program will produce a comprehensive
environmental data base which can be used for permitting and operating
future similar plants. Environmental monitoring during plant commissioning
included sampling and analysis of both internal process streams and streams
discharged from the plant, as well as ambient monitoring. The complete set
of environmental data obtained during plant commissioning can be found in
Reference 3. Extensive environmental monitoring continues to be performed
throughout the demonstration period, including plant operation on the
design Utah coal and alternate coals.
The plant was designed to burn coals with a range of sulfur content from
0.35 to 3.5 percent by weight to prove that the technology is capable of
efficiently converting most sub-bituminous and bituminous coal reserves.
Thus far, coal from three United States' coal seams has been tested: a
typical Western seam with 0.5 weight percent sulfur; Pittsburgh No. 8, an
Eastern coal with a 2.8 weight percent sulfur; and Illinois No. 6, a Mid-
western coal with a 3.5 percent sulfur content. The program has committed
to test up to eight different coal feedstocks, depending upon the number of
nominations made by its partners.
2-11
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Table 2-3. Adjustment of Cool Water Heat Rate and Comparison
with Estimate for a Commercial Plant
Heat Rate
Adjustment
Btu/kWh
(kJ/kWh)
EPRI
Adjusted
Cool Water
Heat Rate
Btu/kWh
(kJ/kWh)
Fluor/EPRI
Estimated
Commercial
Plant Heat Rate
Btu/kWh
(kJ/kWh)
Cool Water Design
Heat Rate
11,363 (11,986)
Correction for 380 (401)
Reheat Steam Cycle
(Cool Water uses non-reheat steam cycle with lower steam temperature compared to commercial
design.)
Concentration for Slurry 300 (316)
Concentration
(Cool Water uses 60% coal slurry feed versus 66-1/2% for commercial design.)
Correction for ISO4 230 (243)
Ambient Conditions for
Gas Turbine
(Cool Water heat rate is evaluated at 80°F versus 59°F ambient as a standard condition.)
Corrections for Oxygen 601 (634) 9,852(10,392)
Purity, Saturator,
2020°F Gas Turbine
(Cool Water uses higher-pressure, purer oxygen than is necessary and a 1985°F turbine.)
Correction for Plant 356 (376) 9,496(10,016) 9,490(10,000)
Size
(Scaling up Cool Water to a commercial size would reduce plant auxiliary loads as a fraction of
gross power generation.)
Correction for 2300°F 486 (513) 9,010 (9,504) 9,009 (9,503)
Gas Turbine
"ISO: International Standards Organization
Source: Reference 5.
2-12
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The data on overall emissions from Cool Water (based on results from
continuous monitoring averaged over 3 to 6 hours when the plant was
operating at full load) versus the U.S. EPA New Source Performance
Standards are shown in Table 2-4. The Cool Water plant's SO2 emissions
are typically 10 to 20 percent of the allowable levels under EPA's New
Source Performance Standards for coal-fired power plants with stack-gas
scrubbers. Sulfur removal from the syngas has ranged between 97 and 99
percent. Overall sulfur recovery from the feed coal is typically 97
percent. These sulfur compounds are converted to an elemental sulfur of
99+ percent purity, which is sold on the commercial market.
Stack emissions of NOx and particulates have also averaged about 10 percent
of allowable levels under the New Source Performance Standards. N0X
emissions are controlled by means of steam injection or water saturation of
the fuel gas prior to combustion in the gas turbine. Saturation is the
principal method used at Cool Water. Saturation controls N0X emissions to
very low levels, using low-level process heat. The high-quality steam
conserved is routed to the steam turbine, thereby improving plant
performance.
The slag from the gasifier has passed the RCRA Extraction Procedure
Toxicity Test for selected metals and the State of California Department of
Health Services leachate metal parameters and toxicity testing. Based on
these criteria, the slag appears to be nonhazardous [the slag from the two
runs with high-sulfur coals also appears to have passed these tests and to
be nonhazardous (6)]. The Cool Water plant is currently pursuing markets
for this slag as either filler or abrasive material.
2.4.3 Summary of Operating Problems and Availability
The gasifier at Cool Water was first fired on May 7, 1984. Plant
commissioning was completed 47 days later, and the plant began producing
electricity to begin its five-year demonstration period on June 24, 1984.
2-13
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Table 2-4. Heat Recovery Steam Generator (HRSG) Stack
Emissions from the Cool Water Plant
Data in lb/MMBtu (kg/GJ)a
S02:
(High Sr
S02:
(Low S)c
NOx
CO
Particulates
Permit
Limitb
0.16 (0.68)
SUFCO
1985
EPA Test
111. #6
EPA Test
Pitts. #8
Source
Test
0.033 (0.14) 0.018 (.008)
0.13 (.056) 0.07 (.030) 0.004 (.002) 0.066 (.028)
0.07 (.030) 0.004 (.002) 0.004 (.002) <0.002 (<.001)
0.01 (.004) 0.001 (<.001) 0.009 (.004) 0.009 (.004)
Federal
NSPSd
0.068 (.029) 0.122 (.052) 0.64r (.257)
0.24g (.103)
0.6f (.257)
NSh
0.03 (.013)
a. 1 lb/MMBtu = (0.428 kg/Million kJ).
b. Emission limits from EPA permit (based on design estimates of plant emissions).
c. SUFCO: Southern Utah Fuels Co.
d. New Source Performance Standards for a coal-fired power plant burning equivalent coal as Cool
Water.
e. In the context of the Cool Water plant and its permit, high-sulfur coal is defined as coal
containing more than 0.7 wt. % S and less than 3.5 wt. % S. Low-sulfur coal is defined as coal
containing less than 0.7 wt. % S.
f. Emissions controlled to 0.6 lb/MMBtu.
g. 0.8 lb/MMBtu uncontrolled emissions x 0.3 for controlled emissions.
h. NS: no standard.
Source: Reference 5.
2-14
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The latest available progress report (3) contains an analysis of startup
problems, but little information appears to have been published about
operating problems since that period. During startup no single area stood
out as a significant weakness. Process control items accounted for 10 of
the 21 notable shutdown causes during startup, but the control problems
were very diverse in nature.
The primary cause of shutdowns to date has been equipment failures (4).
Only 16 percent of the shutdowns have been process related (all but three
of the process related shutdowns were caused by plugging in coal slurry
lines and fly ash slurry lines). The plant has had three scheduled outages
for inspections and repairs. Improvements and minor process modifications
were also made during these outages. Piping layout changes have signifi-
cantly reduced plugging problems in the gasification plant.
The most significant problem to date has been the failure of the radiant
syngas cooler which occurred in December 1986. A crack appeared in the top
of the radiant cooler (see flow diagram in Figure 2-2), apparently due to a
hotspot which developed in this area. A thermocouple which was supposed to
monitor shell temperature in this part of the cooler failed and did not
give notice of the hotspot condition to shut the unit down. The hotspot
condition was attributed to plugging in the crossover duct between the
radiant and the convection coolers, leading to maldistribution of the hot
gas in the radiant cooler. The crossover duct was redesigned to eliminate
plugging, the cooler was repaired, and the main gasifier went back in
service in June 1987. While the syngas cooler was being repaired, the
plant kept operating with the backup quench gasifier. Only a period of
continued operation without problems will indicate if the redesign and
repair of the syngas cooler was successful in eliminating this particular
plugging problem.
The gasifier, heat recovery steam generator, and gas turbine have all
operated reliably. No changes in their fundamental designs are deemed to
be necessary as a result of being tested as components of an IGCC system.
2-15
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^SV«»C*S CQGUR1
kSTEAM OftUM
Crack in Top
Due to Hotspot*"^
Plugging in
'Crossover Duct
LOCK-
SGCClftCuurtaG
SlAG
sue CONViVORS. SAMHiNI WEMH ICLT
Figure 2-2. Flow Diagran of Syngas Coolers
2-16
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Table 2-5 summarizes plant production and availability. If Cool Water were
a full-size multi-train commercial production facility, the on-stream and
capacity factors shown would be regarded as low. However, as a single-
train demonstration system, Cool Water's operation is turned on and off and
changed for various tests--different feed coals, modes of control, plant
modifications, data collection, etc.--so that these quantitative factors
cannot be taken as representative of the operation of a commercial IGCC
facility in a commercial environment.
Since about July 1, 1987, after the main gasifier has come back on-stream
after being repaired, the mainstream and capacity factors have been about
85-90 percent (6). It is a goal of the Program to achieve a 60-percent
overall capacity factor for the plant for the five-year demonstration
period.
Although Cool Water's availability cannot be taken as representative of a
full-scale commercial plant, the availability/reliability statistics for
plant components being generated at Cool Water are being considered in
updated availability analyses for commercial-plant designs (see Section
4.2).
2.4.4 Load-Following Characteristics
One of the objectives of the Cool Water demonstration is to test the load-
following characteristics of an IGCC in utility service. At Cool Water the
plant load/pressure control, which is a part of the integrated station
control, performs the functions of adjusting the power output of the
combined-cycle plant in response to changes in load demand, and regulating
the fuel gas pressure at the discharge of the fuel plant. This control is
accomplished by coordinating the fuel gas production of the fuel plant with
the consumption of the fuel by the combined-cycle power plant and requires
that the plant load/pressure control interface with and coordinate the
operation of the gasifier and power plant equipment.
2-17
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Table 2-5. Summary of Cool Water Plant Production Availability
Third
Quarter Current
1987 Cumulative8
Gasifier Operation, hours 2,032 18,233
Coal Gasified, dry tons 84,720 740,325
Gross Electrical Production, MWh 232,999 1,796,390
On-Stream Factor, percent 92.0 63.6
Capacity Factor, percent 90.2 53.6
(a) Cumulative since Production Commencement Date, 6/24/84 through 9/30/87.
Source: Reference 6.
2-18
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Three different configurations of the plant load/pressure controls were
provided for in the integrated plant controls for the purpose of achieving
the best overall plant response to load-changing conditions. The controls
are designed for operation in any one of the three modes, and these modes
may be selected, balanced and initiated while the plant is in operation. A
brief description of each control mode follows.
In the turbine-lead mode, changes in plant power output are initiated by
changing the plant load set point. This set-point change causes the fuel
flow to the gas turbine to change first to satisfy the new load
requirement. This action is followed by a change in the gas fuel produc-
tion to maintain the required fuel plant pressure. Subsequently, the
recovered waste heat of the plant changes and causes a change in the steam
turbine output power.
In the gasifier-lead mode, changes in plant power output are also initiated
by changing the plant load set point. In this case, the change causes the
fuel gas production to change first. This action is followed by a gas
turbine fuel flow change to maintain the required fuel plant pressure. The
changing waste heat of the plant results in subsequent changes in the steam
turbine power. This action continues until the new load demand for the
plant is met.
In the coordinated mode of operation, changes in the plant load set point
simultaneously cause the gasifier and gas turbine to make load changes with
follow-up action to control the pressure of the fuel gas plant. It is felt
that this mode is the most promising for overall plant response to handle
fast load-changing conditions.
Initial dynamic testing of the Cool Water Plant has been conducted to
assess its load-following capability. Even at this early stage of testing,
the results indicate that the plant can meet most utilities' daily load-
following requirements. Further improvements are planned.
2-19
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Load change demands were applied to the overall plant megawatt controller
set point. This controller in turn asked for an increase in fuel flow to
the gasifier at a rate limit of 8 percent per minute. The oxygen plant
automatically responded to the change in demand, and the power plant
responded to the increased availability of syngas and steam. This
arrangement is referred to as the gasifier-lead mode. No manual operator
intervention was required.
The largest and fastest load change requested was a 20 percent increase in
plant power output at 8 percent per minute. The plant responded at a
maximum rate of 3.5 percent per minute and at an average rate of 2.2
percent per minute from the time the demand increase was initiated until
the plant output reached the desired set point. Utility daily load-
following requirements are usually cited at 10 percent to 50 percent load
changes at 1 percent to 3 percent per minute. The test results were
comfortably within this range, so that the plant has been shown to meet
normal daily load-following requirements.
Further testing is planned in the gasifier-lead mode, and the coordinated
control mode in which rate change demands are simultaneously applied to the
gasifier and the combined-cycle power plant. Based on the test results
from the gasifier-lead mode, Cool Water expects both the coordinated
control mode and improved controller tuning in the gasifier-lead mode to
provide an even faster overall plant response.
The dynamic tests described above were concerned only with testing the
plant's dynamic response characteristics. It would also be of interest to
determine the effect of extensive cycling over a period of time on plant
reliability and maintenance. Such information will be needed by utilities
for predicting costs as a function of plant operating mode.
2.5 Economics
The costs of the Cool Water Project--both capital cost and O&M costs--have
been collected and assessed by the Program, and economic evaluations
2-20
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continue. Due to the demonstration nature of the plant and the constraints
surrounding its design and operation, the costs are not directly indicative
of the costs of a commercial IGCC plant. However, preliminary analysis by
the Program indicates that production costs continue to decrease as more
experience is gained in plant operation, and these operating costs provide
insight into projected commercial production costs.
In the design of the plant, capital costs were minimized in every way
possible without impacting the overall project objectives. Because of this
decision to reduce front-end capital costs at the expense of later
operating efficiency and electricity production costs, the plant was
designed for a high heat rate of 11,300 Btu/kWh (see Section 2.4.1 and
Table 2-3). The plant does not, for example, use a reheat steam turbine,
which was not shelf-available for a 100-MW facility. Equipment sparing
which would be done for a commercial plant was minimized, thereby
penalizing plant availability.
The Program claims to have analyzed Cool Water's final capital costs of
$263 million to determine unique and first-of-a-kind expenses which would
not be incurred in future commercial plants. This reconciliation of
capital costs, after including capital costs for an air separation plant
and other equipment required for commercial operation, produced an adjusted
figure of $232 million. This adjusted figure, it is claimed, compares well
with EPRI cost estimates for a 360-MW commercial plant^- (5).
Cool Water's O&M costs are higher than those estimated for a fully
commercial plant because of a number of items, such as short-term coal and
oxygen contracts negotiated at premium prices, test and demonstration
1 A capital cost of $232 million for a 100-MW plant scaled up to 360 MW
with a capacity exponent of 0.67 (a value found to be reasonable for this
size range of IGCC plants (1)) produces a cost of $547 million or
$1520/kW, which is certainly within the range of capital cost estimates
for commercial IGCC plant designs. The use of a capacity exponent to
adjust cost estimates to a different plant capacity is an extrapolation
technique subject to a great deal of variability but is frequently used
to relate different cost estimates at different capacities.
2-21
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objectives requiring significant manpower and operational burdens, extra
environmental monitoring, and numerous lesser atypical items associated
with this first-of-a-kind demonstration. The Program is in the process of
analyzing its O&M costs to identify those costs which would not be typical
and reconciling them with estimates for a commercial plant. The
preliminary results of these economic evaluations indicate that actual
total Cool Water production (O&M) costs adjusted for commercial plant scale
and operation are about 2.6 cents/kWh(5).
The Cool Water plant is only a demonstration project of commercial-scale
components and not a complete up-to-date commercial plant, using the most
advanced technology and operating in an independent commercial environment.
The plant receives financial backing from the U.S. Synthetic Fuels
Corporation in the form of price guarantees. Thus, Cool Water costs
provide only an indication of what potential costs might be for a truly
commercial plant, and the question might well be raised how these costs
might change in the future as the result of the Cool Water experience.
Frequently, when a technology is scaled up to commercial size, unforeseen
changes in design and plant modifications are found to be required as the
result of operating experience, increasing capital and O&M costs from the
original estimates.
As a result of the experience gained with the Cool Water project, a second-
generation IGCC plant similar to Cool Water could probably be built at
lower cost. This appears to be the case because no problems were
encountered whose solution required redesign or plant modifications leading
to increased costs. Rather, most of what was learned would probably lead
to lowered costs. For example, it was learned that the radiant syngas
cooler was grossly overdesigned since it produces over 90 percent of the
total steam produced in the syngas coolers. A smaller radiant syngas
cooler could lead to a more optimum cooler design combination and lower
costs. A list of such improvements (6) includes:
• overdesigned radiant syngas cooler
• longer-than-expected gasifier refractory life
2-22
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• ash recycle system not needed
• cage mill not needed for crushing feed coal
• availability of a new combination gasifier burner used for both
maintenance and operation
• lower-than-expected gasification temperatures
• lower oxygen consumption
• elimination of plugging problems.
Since many plant components are either standard commercial equipmenL or perhaps
only somewhat modified versions, the lack of significant plant modifications
being necessary should not be surprising.
This is not to say that all IGCC design issues have been resolved as the result
of Cool Water. QuesLions about materials of construction and corrosion remain
to be resolved, although corrosion data arc being obtained by means of material
coupons inserted inLo the system. The use of maLerial coupons is an initial kind
of corrosion testing, and Lhe effect of special material requirements on planL
cost is not known at this point. Plant operations over an extended period of
time with high-sulfur coal may cause some problems to surface. The capacity of
the Texaco gasifier remains to be demonstrated. It is claimed that the Cool
Water gasifier has a capacity of perhaps up to 1500 tons per day, but Cool
WaLer's operating permit limiLs the feed rate to 1008 tons per day, leaving the
plant's estimated capacity limit untesLed aL this time. In addition, operation
of the gasifier and the plant at full throughput may cause some unexpected
problems.
2-23
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I
I
I
I
-------
3.0 DESCRIPTION OF IGGC TECHNOLOGIES
3.1 Gasification Systens
It is possible to design an IGCC system in a variety of configurations with
a number of different technologies to meet various objectives. The most
important technology choice influencing system performance and costs is,
however, the gasification technology. Several different types of gasifiers
are actively being developed and are in different stages of demonstration.
EPRI has sponsored a series of design and cost-estimate studies which serve
to illustrate the merits of each technology and its recent status of
development. In addition, a comprehensive evaluation and comparison of
coal gasification technologies is available in the relatively recent
literature (1).
The most important gasification technologies, in terms of their near- or
mid-term potential application to IGCC systems, appear to be the following
(7):
• Texaco
• Dow
• British Gas Corporation/Lurgi
• Shell
Other technologies have been evaluated for this application but appear to
be lesser known or less developed with fewer resources being available to
support their full development. These other technologies include:
• KRW
• Kilngas
Table 3-1 compares these gasification technologies in terms of their com-
mercial and development status. The table shows the sizes of the most
significant pilot plants involved in the technologies' development,
including the current plants up to commercial-scale plants, if any.
3-1
-------
Table 3-1. Status of Second-Generation Gasification Technologies for IGCC Systems
Process
Texaco
Type
Entrained Flow
Operating Units
• Cool Water; 2 x 1000-TPD Coal: 117-MWe IGCC
• UBE, Japan; 4 x 500-TPD
• Tennessee Eastman; 2 x 900-TPD
• Ruhrchemie, Germany; 1 x 800-TPD
Date of
Operation
1984
1984
1983
1986
Dow
Entrained Flow
160-MWe IGCC at Plaquemine, LA
2 x 2400-TPD Gasifiers
1987
BGC/Lurgi - Slagging Fixed Bed
• 600-TPD Unit at Vestfield, Scotland
1986
V Shell
(S3
Entrained Flow
250-TPD Pilot Plant in Texas
1987
Allis-Chalmers
Rotating Kiln
KRW
Fluidized Bed
H.T. Winkler
Fluidized Bed
U-Gas
Fluidized Bed
Sumitomo - KHD
Molten Iron
Source: Reference 7. Electric Power Research Institute. Reprinted with permission.
-------
In the subsections which follow, each of the more important gasification
technologies is described, including design features, performance, and
limitations. Because the design of the rest of the gasification plant
depends upon the particular gasifier, the discussion also includes the
heat-recovery system and the gas-cleanup system as well.
The last subsection is a summary comparison of gasification technologies.
A summary table in this subsection compares the design features and the
performance of the various coal gasifiers being developed for electric
power production in IGCC plants.
3.1.1 Texaco
The Texaco coal gasification process is currently being demonstrated in the
1000-TPD, 100-MWe Cool Water Demonstration IGCC Plant (Section 2). Figure
3-1 is a sketch of the pressurized, downflow, entrained Texaco gasifier(l).
The feed coal is crushed and slurried in a wet rod mill. The slurry water
consists of recycled condensate from raw gas cooling together with make-up
water. Carbon that is not converted in the gasifier can be recovered and
recycled to the gasifier feed via the slurrying operation.
The coal/water slurry is pumped into the gasifier burner together with
oxygen. The gasification takes place rapidly at temperatures in excess of
2300°F under which conditions the coal is converted primarily to H2, CO and
CO2 with no liquid hydrocarbons being found in the gas. The water in the
coal slurry not only serves to convey the coal to the gasifier, but also
moderates the gasifier temperature so that excessively high temperatures
are not experienced.
The crude raw gas leaving the gasifier at 2300°F-2700°F contains a small
quantity of unburned carbon and a significant portion of molten ash.
Depending on the design of the IGCC, this gas stream would be either
directly quenched in water (to cool the gas and remove solidified ash
particles) or cooled in radiant/convection boilers for sensible heat
3-3
-------
Oxidant
High P»assura
Staam
! Convactlon
f~ ~ ~1 Cooiar
Coal
Mill
Gas
Scrubbar
I J
Slurry
Tank
Slurry
Pump
Lock
Hoppar
Slag lo
Disposal
To Disposal
Slag
Scraan
Recycla Solids
lo Mill or Tank
Source: Reference 1. Copyright (1983) Electric Power Research
Institute. Reprinted with permission.
Figure 3-1. Texaco Coal Gasification Process.
3-4
-------
recovery (via high-pressure saturated-steam generation) prior to water
scrubbing.
The relatively high oxygen requirement of the Texaco gasifier and the large
amount of steam produced in the gas coolers per unit of coal gasified are
typical of entrained-flow gasifiers which operate at extremely high
temperatures to achieve high carbon conversion and slagging of the ash.
Operation at these high temperatures eliminates the occurrence of
hydrocarbon liquids in the product gas.
The "cold gas efficiency" (ratio of sulfur-free fuel gas heat content to
feed coal heat content) for the Texaco gasifier is typically in the range
of 77 percent. Although this efficiency is higher than that of other
gasifiers, it is still low due to the large quantity of sensible heat in
the high-temperature raw gas. This sensible heat is transferred to steam
in the gas coolers. If the energy content of the high-pressure steam is
added to that of the fuel gas, the efficiency of the Texaco gasifier is on
the order of 95 percent.
As the Texaco gasifier is fed with a coal/water slurry, the ratio of
chemical to sensible heat in the product gas as well as the oxygen
consumption of the gasifier depends very strongly on the water content of
the coal slurry feed. As the water requirement for producing a pumpable
coal slurry increases, the oxygen requirement of the gasifier will
increase, the amount of chemical heat (fuel value) of the gas will
decrease, and the amount of steam generation in the raw gas coolers will
increase. It is therefore critical to the economic operation of the Texaco
gasification system to produce high-solids-content coal slurries. Slurry
concentrations in excess of 60 percent by weight dry solids are highly
desirable.
Advantages of the Texaco coal gasification technology include:
• More extensive operating experience than other demonstration
gasifiers
3-5
-------
• Use of a slurry system for coal feed for reliable high-pressure
operation
• A relatively high yield of hydrogen and carbon monoxide (an
advantage for some applications)
• A product gas that is low in methane content
• A product gas that is free of tars and other hydrocarbon liquids
• The flexibility to handle a wide range of coals and petroleum
cokes, the only restriction being the poorer economics of low
slurry concentration.
A unique feature of the Texaco gasifier is the use of a system that feeds
coal in a water slurry. This type of system is found to provide high coal-
feed reliability, a critically important factor for pressurized entrained-
flow gasifiers. Principally because of the slurry feed system, the Texaco
gasifier can be operated at substantially higher pressures than other
entrained gasifiers. High operating pressure leads to an increased gas
production capability per gasifier or fewer gasifiers per plant of a given
size. High operating pressure also permits use of economical sulfur
removal physical absorption processes like Selexol and Rectisol.
Disadvantages of the Texaco coal gasification technology include:
• A high oxygen requirement
• A limited ability to economically handle low-rank coals because of
the water slurry feed system
• High-temperature operation leading to potentially high maintenance
costs for the gasifier and high-temperature gas cooling equipment.
Entrained-flow slagging gasifiers have relatively high oxygen requirements
due to their high operating temperature. Oxygen consumption of the Texaco
system can be greater than that of other entrained-flow gasifiers because
of the energy required to vaporize the water in the slurry feed. The
ability to produce and pump a high-solids-content coal slurry significantly
reduces the oxygen requirement and consequently increases the overall
gasification efficiency. As a result, low-rank coals such as lignite are
generally not considered for use in the Texaco process as it has not yet
3-6
-------
been demonstrated that they can produce high-solids-content slurries in
water.
The high operating temperature required by all entrained-flow slagging
devices such as the Texaco gasifier results in the potential for relatively
high maintenance costs for the gasifier and the high-temperature gas
cooling equipment. Gasifier refractory change-outs in less than two years
of operation might not be unexpected. Potential plugging, fouling and
corrosion of boiler tubes by hot gases containing fly ash, hydrogen
sulfide, carbon, etc., must be anticipated and, indeed, have occurred in
the Cool Water Plant. The relative severity of these problems, which will
always be present, will be a strong function of the particular ash and coal
characteristics.
3.1.2 Dow
Another entrained-flow type of gasifier and gasification system for IGCC
power generation, which is being developed almost entirely with private
funds, is the Dow gasifier. Little public information is available about
this system because of its privately funded proprietary nature. However, a
commercial-scale system has been built and is now in operation. The system
developer, the Dow Chemical Company, has had a great deal of experience
with power generation in general and combined-cycle gas turbine systems in
particular.
A recent paper in the literature (8) provides some description of the Dow
Syngas Project, which includes an IGCC based upon the Dow gasification
technology.
In the mid-70's Dow decided to base its future energy needs on coal as the
lowest cost, most readily available energy source in place of natural gas.
Dow also selected gasification as the best technology for utilizing coal,
expanding its gasification studies and its program to develop this
technology. Dow also recognized that the most available source of solid
fuels for its Gulf Coast operations was the large deposits of lignite in
3-7
-------
east Texas and northwest Louisiana. Since the late 70's, Dow has conducted
an extensive research and development program to develop a process with a
focus on the efficient conversion of low-rank coals to raedium-Btu syngas.
The Dow Gasification Process utilizes a pressurized, entrained-flow,
slagging, slurry-fed, two-stage, upflow gasifier with a continuous slag
removal system. The process includes a unique heat-recovery system which
provides high efficiency on low-rank coals. The process produces mediura-
Btu syngas suitable for fueling combined-cycle power units. The oxygen and
slurry feeds are carefully controlled, utilizing special temperature
sensing devices, to maintain the temperature at the desired point. The
gasifier system operates in such a manner that essentially no tars are
produced and the sulfur in the coal is almost totally converted to hydrogen
sulfide. In addition to the unique heat-recovery system, additional heat
is recovered by a conventional heat-recovery boiler in the form of high-
pressure steam.
Because Dow's initial use for gasification is to fuel power-generating gas
turbines, reliability has been given a very high priority. The process
includes a continuous slag-removal system based upon a unique technique
that eliminates high-maintenance, problem-prone lockhoppers. Dow also has
a novel slurry feed technology, special temperature monitoring devices, and
other operating reliability features. Of special significance, a computer-
controlled instrumentation system allows on-stream switching of the fuel to
the gas turbines.
The Dow Syngas Project is a commercial coal gasification plant that uses
Dow-developed coal gasification technology to convert coal into medium-Btu
syngas for use in combined-cycle gas turbines generating electricity and
steam. The project, which has required a total commitment in excess of
$300 million, feeds about 2400 tons per day of low-rank coal and produces
30 billion Btu per day of synthetic gas. The synthetic gas output is
equivalent to 155 megawatts of electric power after supplying the total
project power requirements. The project is located within Dow's existing
3-8
-------
petrochemical manufacturing site near Plaquemine, Louisiana, and will be
fully integrated with existing power-generating units.
The Dow Chemical Company is the single sponsor of the project. Dow
designed, built, and operates the entire facility and consumes the syngas
product. The project has a price guarantee commitment from the Synthetic
Fuels Corporation of up to §620 million over a ten-year period which
commenced with plant startup in early 1987.
Although no more information appears to be available about this project,
particularly on the operation of the plant, EPRI has had some access to
information under a secrecy agreement and regards the Dow technology as an
important contender, both technically and economically, in the gasification
competition (7).
3.1.3 British Gas Corporation/Lurgi
British Gas Corporation has recently begun to operate an eight-foot
diameter gasifier at its Westfield, Scotland, facility which will gasify
600 TPD of feed coal. Figure 3-2 is a sketch of the pressurized moving-bed
BGC/Lurgi slagging gasifier (1). This gasification technology is very
similar to the conventional Dry Ash Lurgi gasifier. As the name implies,
the key difference is that the slagging gasifier slags the coal ash,
whereas the conventional Lurgi does not. There is a substantial advantage
to slagging the ash since the steam requirement is reduced to only about
15% of that for the conventional Lurgi when gasifying bituminous coal.
Coal with a size distribution of 2 inches by zero and up to 35 weight
percent minus 1/4 inch is fed to the top of the gasifier through a
lockhopper. The coal reacts while moving downward through the gasifier.
The coal ash is removed from the bottom of the gasifier as molten slag
through a slag tap, then quenched in water and removed via a lockhopper.
Steam and oxygen are injected through tuyeres at the bottom of the bed and
react with the coal as the gases move up through the bed. This counter-
current action results in a wide temperature difference between the top and
3-9
-------
OAL LOCK HCPPCff
COAkO»ST««UtOP
GASOTEft
WATER JACKET
SLAG TAP HOLE
SLAG OUCNCH VESSEL
SLAG LOCK HUWEW
Of VOL AT) UZATION
-490 mis
GAS OUTLET
too p to 1300*
anO Shift
~ TUYEHE3 c + H
'DOOfto iroof
jrooT
STEAM, OXVOEN
INLET
ROTACTOB* LINING
QUENCH
-------
the bottom of the gasifier with reaction zones similar to those in the
conventional Lurgi gasifier. The solids entrained in the raw product gas
and hydrocarbon byproducts such as tars and oils, naphtha and phenols can
be recycled to the top of the gasifier and/or reinjected into the gasifier
at the tuyeres where they are gasified. Additional coal fines can also be
fed through the tuyeres.
The raw gas produced by the BGC/Lurgi slagging gasifier has some important
differences when compared with the raw gas from the conventional Lurgi
gasifier. The amount of water vapor, CO2, and CH^ is lower while the CO
content is higher. These changes are due to the substantially lower steam
consumption of the slagging gasifier. Recycle of the tar and oil in the
slagging gasifier increases the gas yield.
The cold gas efficiency (defined as the ratio of sulfur-free gas heat
content to feed coal heat content) is high (about 88 percent). Additional
energy credits for the light hydrocarbon liquids increase the efficiency to
about 90 percent. The small quantity of medium-pressure jacket steam is
insufficient to supply the total enthalpy of the steam feed to the
gasifier, although it could contribute a substantial part of it.
Advantages of the BGC/Lurgi slagging coal gasification technology include:
• The large inventory of fuel makes the gasifier inherently
safe, and gas production can be maintained for a considerable
period of time before gas-making has to cease should the coal
supply be interrupted
• Extensive operating experience on a large scale
• Low oxygen and steam demand
• High "cold gas efficiency"
• Ability to handle caking bituminous coals.
Low oxygen.requirements and high "cold gas" efficiency are inherent to all
moving-bed gasifiers because of the countercurrent operation. However, the
3-11
-------
BGC/Lurgi slagging gasifier is more efficient than most moving-bed
gasifiers because of its low steam consumption.
Disadvantages of the BGC/Lurgi technology include:
• Limited experience in handling coal with very high fines content
» Production of liquid hydrocarbons and waste liquor
• Limited experience with low-rank coals
• Slag management.
Moving-bed gasifiers have inherent problems in handling very large amounts
of coal fines. Excessive fines in the feed coal can be entrained in the
raw gas and will ultimately be deposited in the condensed tar, particularly
for non-caking coals, although this dust-containing tar is normally
recycled to the gasifier. For all coals, excessive fines in the bed can
disrupt flow patterns leading to operational problems. Coals with up to 35
weight percent minus 1/4 inch fines have been successfully gasified in the
British Gas/Lurgi slagging gasifier.
The generation of hydrocarbon liquids and wastewater creates process
operating, handling, and disposal problems, but the presence of these
liquids in heat-exchange equipment downstream of the gasifier reduces
corrosion problems. Also, the condensing of these liquids removes
virtually all particulates from the gas. Recycle of the tar, oils and
phenolic wastes to the gasifier through the tuyeres could significantly
reduce handling problems created by these byproducts. The low steam
requirements of the BGC/Lurgi gasifier relative to the Dry Ash Lurgi
significantly reduce handling problems created by these byproducts. The
low steam requirements of the BGC/Lurgi gasifier relative to the Dry Ash
Lurgi significantly reduce the amount of wastewater produced. Furthermore,
it has been demonstrated that a substantial quantity of the wastewater can
be fed back to the gasifier through the tuyeres, reducing both steam
requirements and the volume of effluent to be treated.
3-12
-------
Finally, management of molten slag in the base of a fixed bed and removal
of that slag through the tap hole are critical operating factors.
Effective molten slag handling requires advanced refractories and careful
heat flux control.
3.1.4 Shell
The Shell gasifier (1) is a dry-feed, pressurized, upflow, entrained
slagging gasifier as shown in the sketch in Figure 3-3. The feed coal is
pulverized and dried, and then pressurized in lockhoppers. It is fed into
the gasifier by dense phase conveying with a transport gas. The coal
reacts with oxygen at temperatures in excess of 2500°F to produce
principally H2 and CO with very little CO2 and no liquid hydrocarbons. The
high-temperature gasification process converts the ash into molten slag,
which runs down the cooled, refractory-lined wall of the gasifier into a
water bath where it solidifies and is removed through a lockhopper as a
slurry in water.
The crude raw gas leaving the gasifier at 2500°F - 3000°F contains a small
quantity of unbumed carbon and a significant fraction of molten ash. To
make the ash non-sticky, the hot gas leaving the reactor is quenched with
cold recycle gas. Further cooling takes place in the waste-heat recovery
section, consisting of radiant and convective cells, where high-pressure
saturated steam is generated prior to water scrubbing. Alternatively, the
hot gas can be quenched with water to cool the gas and remove solidified
particles.
The Shell gasifier has the relatively high oxygen and low steam require-
ments and the large amount of energy recovered in the gas coolers per unit
of coal gasified which are typical of entrained-flow gasifiers operating at
extremely high temperatures to achieve high carbon conversion. Operation at
this high temperature eliminates the occurrence of hydrocarbon liquids and
methane in the product gas.
3-13
-------
QUENCH CAS GAS
COAL
BFW
SCRUBBERS
STEAM
WAS
HEA
BO I
-ER
RAW GAS
COAL
CYCLONE
REACTOR
SLURRY
WATER
BLEED
0,/STEAM
0,/STEAM
FLY SLAG
RECYCLE
SLAG
Source: Reference 1. Copyright (1983) Electric Power Research Institute. Reprinted with permission.
Figure 3-3. Shell Coal Gasification Process Typical Flow Scheme.
-------
The "cold gas efficiency" (ratio of sulfur-free fuel gas heat content to
feed coal heat content) of the Shell gasifier is about 80 percent. This
efficiency is higher than that of the Texaco system due to the reduced
oxygen consumption and lower CO2 generation which result from the Shell dry
coal feeding system. If the energy content of the high-pressure steam
generated in the gasifier jacket and the gas coolers is added to that of
the fuel gas, and if the energy for coal drying and steam feed to the
gasifier is deducted, the overall efficiency of the Shell gasifier would
increase to 94 percent.
Advantages of the Shell coal gasification technology include:
• Ability to gasify all ranks of coal
• Ability to gasify fines
• Relatively high yield of hydrogen and carbon monoxide (an
advantage for some applications)
• A product gas that is free of tars and other hydrocarbon liquids.
The dry pulverized feed system developed by Shell enables all coal types to
be used. Feeding dry coal at pressure reduces the oxygen consumption
(relative to a water slurry feed system) thereby increasing "cold gas
efficiency" and decreasing CO2 generation. However, it is likely that the
dry coal feed system will limit the economic maximum operating pressure of
the Shell system to levels that are lower than those achievable with a
slurry feed system. The low CO2 production also reduces the cost and
complexity of acid gas removal and sulfur recovery.
Disadvantages of the Shell coal gasification technology include:
• Relatively high oxygen requirement
• High-temperature operation leading to potentially high maintenance
costs for the gasifier and the high-temperature gas cooling
equipment
• Potential operating difficulties due to the pressurized dry coal
feed system.
3-15
-------
As with the other entrained slagging gasifiers, the Shell device has a
relatively high oxygen consumption due to the high operating temperature.
The ability to feed dry solids minimizes the oxygen requirement and makes
the Shell gasifier somewhat more efficient than a gasifier employing a
slurry feed system. The penalty paid for this small increase in efficiency
is a system which could be operationally more sensitive. Demonstration of
the reliability and safety of the dry coal feeding system at large scale is
essential for the successful development of the Shell technology. The
gasifier employs a cooled refractory which should result in longer periods
between change-outs than could be expected with uncooled refractory.
Potential plugging, fouling, and corrosion of boiler tubes by hot gases
containing fly ash, hydrogen sulfide, carbon, etc., must be anticipated.
3.1.5 Summary Comparison of Gasification Systems
Table 3-2 shows the important characteristics of the more advanced
gasification technologies being developed for IGCG applications.
Three of the four gasifiers shown are entrained-flow types and have the
similar characteristics of a hot product gas which must be cooled for heat
recovery, hydrocarbon-free product gas, and high carbon conversion. The
oxygen requirement is affected by the type of feed system -- either slurry
or dry feed, but more oxygen is required than in the moving-bed type of
gasifier. The reduced oxygen requirement for the Shell gasifier leads to a
lower CC>2 content in the product gas and lower acid gas removal costs. The
dry feed system of the Shell gasifier leads to a potentially lower maximum
operating pressure, which influences system costs.
Potential maintenance costs, equipment reliability, and corrosion are all
common technical issues with entrained-flow gasifiers. There appears to be
little difference in system performance among the entrained-flow gasifiers.
The major differences appear to be concerned with mechanical design and
operation of the system. Which system appears to be best in these areas,
leading to high reliability and low O&M costs, will be determined only from
3-16
-------
Table 3-2. I portent Characteristics of Advanced Gasification Technologies Being Developed for IGCC Applications
Gasifier Type
Feed Coal
Size
Acceptability of fines
Acceptability of caking coal
Preferred coal rank
Feed System
Operating Characteristics
Flow in gasifier
Gas composition
Carbon conversion
Exit gas temperature
Oxygen requirement
Steam requirement
Efficiency, percent
Cold gas
OveralI
Pressure
Key parameters
Gas cooling
Texaco
Entrained-flow
Pulverized (-100 mesh)
Unlimited
Yes
Any
(Difficulty feeding
lignite)
Coal/water slurry
Downflow
H2. CO, COj
No hydrocarbons
High
>2300°F
High
Low
77
95
High (600 psig)
Solids content
of feed slurry
Radiant and convective
coolers
Dow
Entrained-flow
Slurry
Upflow
No tars
Pressurized
BGC/Lurgi SIagger
Moving-bed
Coarse (-2 inch)
<35 percent (-1/4 inch)
Yes (with modifications)
High
Dry feed, lockhopper
Coal downflow,
gas upflow
Some CH4
Tars and oils
800-1200 F
Low
Low
88
90
Pressurized
Waste-heat boiler
Key Distinguishing
Characteristics
Key Technical Issues
Large amount of
sensible heat energy
in hot raw gas
Potential maintenance
costs, reliability of gas
coolers, and corrosion
Hydrocarbon liquids
in the raw gas
Utilization of
fines and hydrocarbons
Shell
Entrained-flow
Pulverized
Unlimited
Yes
Any
Dry feed, gas transport
Upflow
H2, CO
Little C02
No hydrocarbons
High
>2300 F
Moderate
Low
80
94
Moderate (350 psig)
Cold gas quench
Radiant and convective
coolers
Large amount of sensible
heat energy in hot raw gas
Potential maintenance
costs, reliability of gas
coolers and dry feeding
system, and corrosion
-------
a comparison of operating data from commercial-scale units, once they have
been built and operated for a sufficient length of time.
The BGC/Lurgi gasifier is a moving bed, which has distinctly different
characteristics from the entrained-flow type. The dry feed system may have
difficulties handling a wide variety of caking U.S. coals. The limit on
coal fines in the feed is another potential limitation of the technology.
The necessity to handle and satisfactorily recycle hydrocarbons presents
system design problems, although operating Dry Ash Lurgi systems appear to
perform satisfactorily in this regard. With its relatively low gas product
temperature the BGC/Lurgi gasifier does sidestep the problems involved in
recovering heat from very hot raw gas, and gasifier cold gas efficiency is
very high.
3.2 Combined-Cycle Power Block Conponents
The combined-cycle power block, which is the other major part of an IGCC
plant besides the gasification system, generally consists of parallel
trains of gas turbine generators, heat recovery steam generators (HRSGs),
and a steam turbine generator with its associated condenser, deaerator,
condensate pumps and boiler feedwater (BFW) supply pumps. The energy in
the gas turbine exhaust is recovered in the HRSGs for use in the steam
generator.
3.2.1 Gas Turbine
Driving electric generators, gas turbines have been used to satisfy both
peaking and reserve loads of the utility industry due to their quick-
starting capability and low capital cost. In such applications gas
turbines fire either gaseous (natural gas) or liquid (light distillate oil)
fuels. The relatively poor thermal efficiency of gas turbines and the
restrictions on the use of such prime fuels by the Fuel Use Act of 1978,
however, make gas turbines economically unattractive for baseload
applications.
3-18
-------
With the exception of the ongoing Cool Water Project, there Ls limited experience
on running gas turbines with coal.-derived gases Tor base! oad utiliLy
applications. In the Cooi Water Project a modified older version of the
commercially available General Electric (GE) MS7001E gas turbine with a firing
temperature of around 1900°F is being used as part of the combined cycle.
Several features were added to the gas turbine to adapt it to the IGCC
environment, including fuel delivery arid combustion sysLerus capable of liaridling
the syngas generated in the Texaco oxygen-blown coal gasifier, and a control
system expanded to accommodate the increased number of operating modes and
contingencies (9).
The efficiency of the gas turbine increases with decreasing ambient air
temperature and increasing turbine inlet temperature. As the ambient air
temperature decreases, the air density increases, and since the combustion air
compressor capacity is limited by suction volume, Lhe mass flow through the
turbine increases. Thus, gas turbines are rated according to their power output
at specified ambient conditions--the international Standard Organization (ISO)
reference conditions (1) of 59°F, 14.7 psia and 60 percent relative humidity --
when firing a specified fuel. Increasing the turbine inlet temperature increases
its simple-cycle efficiency, as in any heat engine.
3-19
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3.2.1.1 Advanced Turbines. Since the efficiency of gas turbines increases as
the inlet gas temperature is increased, recent developments in advanced materials
and designs have led to stationary turbines which operate at ever higher
temperatures. The current commercially available General Electric (GE) Model
MS7 001F gas turbine has an operating temperature of 2300°F. This model recently
replaced Model MS7001E, which operated at 2000°F. This new turbine incorporates
the latest technology in the compressor, combustion system, and turbine designs.
A combined-cycle power plant built on this turbine is said to be the most
efficient fossil-fuel power generation system currently designed.
Gas turbines in baseload applications have achieved availabilities which compare
closely with the best electric power generation units, i.e., diesel and hydro-
power generation units (1). These advanced turbines are expected to achieve at
least comparable availabilities after the usual problems associated with the
introduction of new turbines, such as vibration, combustion instabilities, and
rotor dynamics, have been corrected, typically within the first two year3 (10).
The expected performance of the MS7001F in comparison with the MS7001EA gas
turbine when operating with an exhaust gas pressure for a typical combined-cycle
HRSG is shown in Table 3-3.
The potential availability of this advanced turbine gives IGCC a significant
increase in estimated performance at decreased cost. Table 3-4 shows a
comparison of IGCC designs with the current turbine and the advanced turbine, and
the effects on heat rate and costs.
3.2.1.2 NO. Emissions. The only emissions currently controlled with the Federal
New Source Performance Standards (NSPS) for gas turbines are NOx emissions. For
utility turbines generating more than 9 MW (30 MW thermal), NOx generation is
restricted to 75 ppm (12). The MS7001E gas turbine in an IGCC setting generated
about 40 ppm while the next-generation turbine (MS7 001F) is estimated to generate
about 50 ppm of NOx (Table 3-4), based on analysis and laboratory data from test
combustor rigs.
3-20
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Table 3-3. Gas Turbine Performance Characteristic Comparison
MS7001EA MS7001F
Power - kW (Net)
78,770
136,770
Net Heat Rate - Btu/kWh-LHV*
10,830
10,310
Air Flow - lb/sec
633.3
890.0
Specific Power - kW/(lb/sec)
124.4
154.1
Exhaust Gas Temperature - °F
999
1,111
Conditions
o Ambient air conditions: 59°F, 14.7 psia
o Inlet Pressure: -3.5 in. WG
o Exhaust Pressure: 15 in. WG
o Fuel: Natural Gas
*LHV=Lower Heating Value
Source: Reference 11.
3-21
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Table 3-4. Effect of Advanced Vs. Current Turbine Model on
Performance and Costs of IGCC Designs
Basis: Texaco-Based Radiant Plus IGCC Design IGCC Design
Convective IGCC Design" With Advanced With Current
Turbine Turbine
Gasification
Coal Feed, tons/day (dry) 4,984 4,545
Power Generation
Gas Turbine Power, MW
Steam Turbine Power, MW
Gross Output, MW
Net Output, MW
Environmental
Water Consumption, gpm/MW
Sulfur Dioxide Emissions, tons S02/MW-yr.
NOx Emissions, ppmv dry, 15% 02 Ref.
Heat Rate Corrected
Economics
Total Plant Investment, $/kW 1272 1399
Net Plant Heat Rate, Btu/kWh 9009 9490
Levelized COE at 75% CF, mills/k.Wh 41.7 45.3
a. At 59°F Ambient Rating
b. General Electric Estimate. Heat rate correction based on Gas Turbine Combustor Performance on
Synthetic Fuels, Vol. 2, p. 5-2. Palo Alto, California: Electric Power Research Institute. June 1981,
AP-1623.
Source: Reference 13. Copyright (1984) Electric Power Research Institute. Reprinted with permission.
407
273
680
589
346
247
593
510
6.1
11.0
49b
6.6
11.6
41
3-22
-------
N0X generation in a gas turbine is affected by the flame temperature, and
the heating value and composition of the gas. In addition, the N0X
generation rate increases with the square root of the absolute pressure
The control of N0X generation in gas turbines firing conventional fuel (12)
is achieved by water or steam injection. Although this method increases
the power output from the gas turbine, its disadvantages are (a) decrease
in fuel economy caused by the loss of heat of vaporization of the water
which remains in the flue gases after they exit the turbine, (b) expensive
purified water must be used to prevent turbine corrosion and deposits, and
(c) life of combustor parts are shortened. New combustion hardware is also
under development to control N0X generation in gas turbines.
In IGCCs, however, the fuel is saturated with water in a contacting tower,
and heated in the gasification section to avoid condensation, before being
injected into the gas turbine's combustion chamber. Also, in an IGCC waste
heat is recovered from the turbine exhaust in the HRSG, thus mitigating the
decrease in fuel economy caused by the water vapor in the turbine exhaust.
3.2.2 Heat Recovery Steam Generator
Recovery of the heat in the gas-turbine exhaust is the overall function of
the heat recovery steam generator (HRSG) in an IGCC system. This heat
recovery improves the thermal efficiency in the combined-cycle power
generation process. The recovered heat in the form of generated steam is
used to drive the steam turbine generator. Additional steam can also be
generated in the HRSG by increasing the temperature of the turbine exhaust
via the combustion of additional fuel in this gas stream.
Thus, two broad categories of combined-cycle designs may be considered,
depending on how the steam generator is used in conjunction with the gas
turbine. These categories are:
Gas turbine plus unfired steam generator, and
Gas turbine plus supplementary-fired steam generator.
3-23
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3.2.2 Heat Recovery Steam Generator
Recovery of the heat in the gas-turbine exhaust is the overall function of the
heat recovery steam generator (HRSG) in an 1GCC system. This heat recovery
improves the thermal efficiency in the combined-cycle power generation process.
The recovered heat in the form of generated steam is used to drive the steam
turbine generator. Additional steam c:an also be generated in Lhe HRSG by
increasing the temperature of the turbine exhaust via the combustion of
additional fuel in this gas stream.
Thus, two broad categories of combined-cycle designs may be considered, depending
on how the steam generator is used in conjunction with the gas turbine. These
categories are:
o Gas turbine plus unfired steam generator, and
o Gas Lurbine plus supplementary-fired steam generator.
3.2.2.1 Unfired Generator. In this concept, an HRSG is installed at the
discharge of the gas turbine to recover the energy in the gas turbine exhaust and
supply steam to the steam turbine. All the syngas fuel is fired in the gas
turbine, and the steam generator depends entirely on the gas turbine exhaust for
its heat. The HRSC typically carries out three heat recovery functions in three
separate sections: (a) preheating boiler feedwater Ln an economizer, (b)
generating saturated steam in an evaporator, and (c) superheating the saturated
steam.
In an IGCC system compared to a standard combined-cycle operation, the HRSC has
the added function of superheating the saturated steam produced from the syngas
coolers. Although this additional steam makes the HRSG design somewhat more
complex in an ICCC, no additional operating difficulties appear to occur as a
result. At Cool Water the HRSG has nuL been responsible for any plant shutdown
and apparently has not experienced any unusual problems.
In a conventional combined-cycle plant the HRSG is a major source of equipment
failures and plant shutdowns. The typical method of operating the coinbl ried-cycl e
system appears to be the major cause. The system is cycled too much, and
operation of the HRSG and the steam turbine cannot be changed or "ramped" as
rapidly as that of the gas turbine. Dow Chemical Company apparently gets better
3-24
-------
availability with its combined-cycle plants (7), but this situation may simply
be the result of a chemical plant's steadier pov/er demand compared to that of a
typical uLility.
3.2.2.2 Generator with Supplementary Firing. The gas-Lurbine exhaust contains
from 16 to 18 percent oxygen, and this oxygen may be used to support further
combustion. Therefore, a modification of the straight-forward application
described above is the use of a supplementary firing system located in the
connecting duct between the gas turbine and the steam generator. The amount of
fuel added and the amount of oxygen in the gas-turbine exhaust consumed in the
firing system are usually limiLed by a maximum temperature for the gas (about
1300°F) entering the sLeam generator. The higher-temperature gas entering the
HRSG produces a larger quantity of steam for the steam turbine and a higher plant
power output.
The use of supplementary firing in the HRSG can give an IGCC plant a high degree
of design and operating flexibility not available with pulverized coal-fired
steam plants. Because of the ambient temperature sensitivity of the gas
turbines, which produce more power at a lower heat rate as ambient temperature
decreases, the gasification section of the plant can be either:
1. Sized to fully load the gas turbines at a low ambient temperature,
resulting in excess gas production capacity at higher temperatures.
2. Sized to provide the required amount of fuel gas at some high ambient
temperature with the result that the gas turbines would be only partly
loaded aL lower temperatures.
The latter option could be of interest: to a summer peaking utility, and would,
of course, result in a lower capital investment than the first option. Even with
this latter option, additional power could be generated when needed in the winter
by augmenting the coal-derived fuel gas with natural gas.
In an IGCC power plant the fuel (gas) making capability is relatively unaffected
by ambient conditions in contrast to the. gas turbine's fuel power output. Thus,
in an IGCC system i.n which the gasifier is designed to provide Lhe required
amount of gas to the gas turbine at low ambient temperatures, the gasifier output
can be held essentially constant as ambient temperature increases, while the gas
3-25
-------
turbine's power output decreases. The excess fuel produced can be fired in the
duct between the gas turbine and the IIRSG. This supplementary firing of the HRSG
enables a substantial fraction of the potential reduction in the power plant's
power output due to increased ambient temperatures to be recovered. Nevertheless,
this capability Lo recover capacity at high ambienL temperatures with
supplementary firing does result in an increase in Lhc overall system heat rate
since some fraction of the fuel from the gasifier is used in the steam cycle
only. This characteristic of IGCC systems is shown in Figure 3-4 for the design
of a Texaco-based IGCC system.
The difference between the two curves in Figure 3-4, with and without
supplemental firing, can be considered to be a relatively low-capital-cost, low-
fucl-cost intermediate-to-peak load cycling option that can be dispatched
separately from the baseload operating mode. The incremental O&M plus fuel costs
for this supplemental firing "wedge" indicate that cycling power produced by the
supplemental firing option has the potential to be significantly lower in cost
than the equivalent power generated by disLillate- or natural gas-fired advanced
combined-cycle plants. This newly identified cycling capability of
supplementally fired IGCC plants provides maximum incremental capacity and
lowest-cost elecLricity at high ambient temperatures--when this type of cycling
capacity is most useful to summer peaking utilities (13).
General Electric's experience with both utifired and supplementary-fired HRSGs for
various applications has been extensive over many years. The number of problems
and their magnitude apparently have been minimal (13).
3.2.3 Steam Turbine
AparL from the use of water power, nearly all Lhe electrical baseload in Lhe
United States is provided by generators driven by steam turbines. There are two
main types of steam turbines: non-condensing (or open cycle) and condensing
(closed cycle). In non-condensing turbines the exhaust steam leaving the turbine
is either used as process steam or discharged to the atmosphere. Fresh feedwater
from an outside source must be supplied continuously to the steam generator to
compensate for water lost as steam. A condensing turbine, on the other hand, is
part of a closed cycle; the exhaust sLeam is condensed, and the water produced,
together with water formed in the turbine, supplies the feedwater for the
generator.
3-26
-------
620
>
u
a
a
_ 580
e
!«
£
540
Supplemental
Firing
660 £58 MW
8,974
Btu/kWh
— _ 636 MW
—CM_
If"— •>» i
l9,284 ^
Btu/kWh
=6.10 MW-
9,675""®
Btu/kWh
589 MW
No Supplemental
Firing
9,
Btu/kWh
9,175
Btu/kWh
40 50 60 70
Ambient Temperature, °F
Source: Reference 13. Copyright (1984) Electric Power Research
Institute. Reprinted with permission.
Figure 3-4. IGCC System Capacity vs. Anbient Temperature for Texaco-Based
System with 2200°F Turbine Radiant Plus Convective Design.
3-27
-------
Most steam turbines are of the condensing type because they have advantages
other than conserving feedwater. Both the temperature and the pressure of
the exhaust steam are lower than for a non-condensing system. Thus
condensing turbines have higher thermal efficiencies. Non-condensing
turbines are often called backpressure turbines because the exhaust steam
leaving the turbine has a significant pressure rather than the low pressure
in a condensing turbine.
Depending on the particular combined-cycle design, the steam turbine can
either be condensing or non-condensing. In addition, the turbine can
either be a reheat or a non-reheat turbine. In a reheat turbine superheat
is added to the turbine steam flow in one or more stages before the steam
is exhausted. The steam turbine in an IGCC system presents no design or
operating problems, and commercially available equipment may be used
without modification. A reheat turbine is usually assumed in design
studies to maintain a high overall efficiency for the plant. A non-reheat
turbine was installed at the Cool Water plant to save on capital cost.
3.3 Design Studies of Coimercial IGCC Plants
The Electric Power Research Institute has sponsored a series of recent
design studies to determine the potential applicability of IGCC power
plants for future use by the U.S. electric utility industry. These
engineering and economic evaluations have been made on a number of
different IGCC systems designed around second-generation coal gasification
processes. The results of these studies of the IGCC concept have shown
potentially attractive energy efficiencies and economics.
In this section information is compiled from these studies on the projected
performance of commercial IGCC plants to illustrate the technological
status of the technologies involved, the range of energy efficiencies (heat
rates) to be expected from the different designs, and their environmental
performance.
3-28
-------
3.3.1 Technological Status of IGCC Systems
The technological status of the major plant components in the IGCC system
designs studied by EPRI is summarized in Table 3-5. With the exception of
the gasification systems (see Section 3.1.5), most of the equipment used in
these designs are proven and commercially available. In addition, the
high-temperature gas cooling equipment (the radiant and convective syngas
coolers) in the Texaco designs has been installed in the Cool Water demon-
stration project while Shell has yet to demonstrate its designs on a
commercial scale.
3.3.2 Energy Efficiency (Heat Rate)
Table 3-6 shows a comparison of the energy efficiencies of the three IGCC
systems which are the subjects of EPRI design studies. The major
difference between these systems is that the Texaco and BGC/Lurgi systems
are designed for nominal 500-MW plants rated at 59°F, using advanced gas
turbines (2200°F firing temperature), while the Shell design at 88°F for a
nominal 1000-MW plant is based on the currently available gas turbine
(2000°F firing temperature).
The BGC/Lurgi system has the best overall net heat rate with about 75
percent of the gross power generated in the gas turbine section. The
higher proportion of gross power generated by the gas turbine is a
reflection of the higher cold gas efficiency of the BGC/Lurgi gasifier. By
this means the combustion gas for the gas turbine contains a higher
proportion of the coal's energy content, and the steam for the steam
turbine a lower proportion. The BGC/Lurgi design also has a much lower
fraction of parasitic power consumption, a reflection of the smaller oxygen
requirement.
The Texaco and Shell systems exhibit essentially the same performance in
terms of the percentages of the gross power generated in the gas and steam
turbine sections. These two designs also have the same fraction of
parasitic power consumption. The Shell design includes power recovery and
3-29
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Table 3-5. Comparison of IGCC Plant Designs froa EPSI Studies: Technological Status of Plant Components
MAJOR PLANT SECTION
1. Coal Handling
2. Fine Coal Agglomeration
3. Coal Feed
4. Oxidant Feed
5. Gasification
(See Section 3.1)
o
6. Gas Cooling
a) High temperature
i>
ii>
b) Low Temperature
7. Particulate Removal
TEXACO
Commercially available
equipment
Not applicable
66.5 wt% Coal/water slurry
Conmercially available
equipment
Cryogenic air separation
plant
Commercially available
Oxygen-blown entrained flow
gasifier
Commercially proven for
liquid hydrocarbons
Limited experience with
coal (up to 900 t/d)
1650-t/d gasifier under
construction in Japan
Unconventional radiant and
convective syngas coolers
for steam generation
Tested in 165-t/d plant and
installed at Cool Water
Plant
Direct water quenching
Conmercially available and
conventional heat exchange
equipment
Scrubbers
Proven and conmercially
available
SYSTEM
BGC/LURGI
Conmercially available
equipment
Pelletization
Ongoing, using current
state-of-the-art process
Dry coal fed by conveyor
Conmercially available
equipment
Cryogenic air separation
plant
Conmercially available
Oxygen-blown moving-bed
siagger gasifier
6-ft. diameter gasifier
demonstrated
8-ft. diameter gasifier
being tested in Scotland
Quenching by circulated
and injected gas liquor
Current state-of-the-art
equipment
Wash cooler equipped
with hydraulically driven
scrapper
Current state-of-the-art
equipment
SHELL
Conmercially available
equipment
Not applicable
Dry pulverized coal in
hot nitrogen gas
Conmercially available
equipment
Cryogenic air separation
plant
Conmercially available
Oxygen-blown entrained-flow
gasifier
165-t/d pilot plant tested
without commercial experience
Unconventional radiant
and convective boilers
for steam generation
Similar but smaller equipment
tested in 165-t/d pilot
plant
By heating vacuum condensate
and further cooling in trim
cooler
Commercially available
equipment
Cyclone and scrubbers
Commercially available
-------
Table 3-5. Comparison of IGCC Plant Designs fr
-------
Table 3-6. Comparison of IGCC Plant Designs from EPRI Studies: Energy Efficiency
Ambient Temperature
POWER SYSTEM
Moisture in Fuel Gas, Ut.X
Gas Turbine Inlet
Temperature, °F
Gas Turbine Exhaust
Temperature, °F
Steam Conditions,
psig/°F/°F
Gas Turbine Power, MW (% Gross)
Steam Turbine Power, MW (% Gross)
Oxygen Plant Power, MW (% Gross)
Plant Power Consulted, MW (% Gross)
Net Plant Power Output, MW (% Gross)
Feed Coat, HHV, 106 Btu/hr.
Net Heat Rate, Btu/kWh
Overall System Efficiency
(Coal-> Power), X of Coal HHV
ENVIRONMENTAL
Sulfur Removal, X
SO2 Emissions, lb/10^Btu
N0X Emissions, 15% O2
Ref, Heat Rate Corrected,
ppm V (dry)
lb/10 Btu
References:
Copyright
Electric Power
Research Institute
TEXACO
59
28.2
2200
970
1450/997/1000
407 (59.9)
272 (40.1)
91 (13.4)
589 (86.6)
5306
9009
37.9
95
0.28
49
0.13
BGCC/LURGI
59
28
2200
1050
1800/950/900
390 (74.9)
131 (25.1)
11.4 (2.2)
509 (97.8)
4407
8661
39.4
94.4
0.34
13
(1984)
49
0.13
14
(1985)
SHELL
88
30
2000
970
1450/900/900
771 (59.3)
528 (40.6)
1.4 (0.1)
178 (13.7)
1122 (86.3)
10304
9182
37.2
90
Not Available
Not Available
Not Available
15
(1983)
Reprinted with permission.
-------
generation in the oxygen plant because the oxygen is needed at a moderate
rather than a high pressure.
As more is learned about IGCC systems, more efficient designs are evolving.
As a result of site-specific studies (see Section 4.7), Texaco-based
designs are being developed which have heat rates less than 9000 Btu/kWh
(7).
3.3.3 Environmental Characteristics
One of the most compelling reasons for the development of IGCC systems for
electric power generation is their capability of operating in an environ-
mentally acceptable manner. Coal gasification appears to offer a practical
means of utilizing coal while at the same time meeting stringent environ-
mental control requirements. Although the type and severity of environmen-
tal control problems vary with the gasification process, routine operations
in existing plants have demonstrated success in cleaning up the most diffi-
cult streams.
For example, synthesis gas streams have been cleaned sufficiently for use
in processes which require virtually total removal of sulfur compounds
because sulfur-sensitive catalysts are used. Processes from which the raw
gas leaves the gasifier at relatively low temperatures give the most
difficult wastewater problems because the wastewater contains tars and
phenols produced in the gasifier; yet such wastewaters have been adequately
purified using conventional technology. Solid waste disposal problems
appear to be no more difficult (perhaps less so) than those faced by
conventional coal-fired power plants.
Estimates of amounts of typical effluent streams from coal-based power
plants of various types indicate that IGCC plants should produce less SO2,
N0X, and solid wastes than either conventional pulverized-coal plants or
atmospheric fluidized-bed combustors (7). In addition to the reduced
amounts of these effluents, IGCC plants require significantly less water
than pulverized coal-fired steam plants as approximately 60 percent of the
3-33
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power in IGCC systems is generated by combustion turbines, which require no
cooling water. IGCC plants also require less land than pulverized coal-
fired steam plants.
This section presents a discussion of the environmental control charac-
teristics of IGCC plants (1,16).
3.3.3.1 Sulfur Removal. Sulfur removal and recovery is an integral part
of IGCC and, in fact, is one of the inherent advantages of IGCC over other
coal-based electric generation technologies. Direct coal combustion
requires removal of sulfur as SO2 in a dilute flue gas stream at low
pressure. The costs for flue gas desulfurization are relatively high.
IGCC, on the other hand, involves the removal of sulfur principally as H2S
plus some COS from the high-pressure medium-BTU fuel gas produced in the
coal gasifiers. The H2S is removed from the coal gas and then converted to
elemental sulfur. This removal and recovery is relatively cheap and
extremely efficient. Furthermore, numerous H2S removal and sulfur recovery
processes are commercially used throughout the oil, chemical and natural
gas industries.
The reasons why sulfur removal and recovery in IGCC is cheap and efficient
include:
• Reduced forms of sulfur appearing in coal-derived synthesis gas
(H2S, COS) are easier to remove than SO2
• Concentration of sulfur compounds in syngas is higher than that of
SO2 in flue gas
• Syngas pressure is much higher than atmospheric pressure
• Syngas volumetric flow rate is much less (about 0.5 percent) than
that of flue gas
• The process for sulfur removal is separated from the combustion
process, leading to more effective conditions.
Sulfur removal and recovery in coal gasification usually involves three
distinct processes:
3-34
-------
• Acid gas removal
• Sulfur removal
• Tail gas treating.
Acid gas is a name commonly used for CO2, H2S and COS. These compounds can
easily be removed from raw coal gas by solvent absorption processes. For
IGCC application it is desirable to utilize acid gas removal processes
which selectively remove more H2S than CO2. The use of such processes
reduces the cost of both the acid gas removal and sulfur recovery by
increasing the l^S-to-CC^ ratio in the recovered acid gas. Furthermore,
the CO2 left in the fuel gas improves the power output of the combustion
turbine. Commonly used acid gas removal processes for this application
include methyldiethanolamine (MDEA), Selexol^, or Sulfinol-M^.
Sulfur recovery involves converting the H2S into elemental sulfur by the
following reactions: H2S + 3/2 O2 - H2O + SO2
2H2S + S02 - 2H20 + 3/2 S2
This is almost exclusively accomplished by using the classic Claus process.
The first oxidation reaction is fast and takes place in a high-temperature
furnace type reactor. The second reaction is relatively slow and requires
several stages of catalytic reactors. The gas is cooled to condense and
remove sulfur and is then reheated between reactors. Sulfur recovery in a
Claus plant is usually between 94 percent and 98 percent depending on the
H2S concentration in the feed and the plant configuration.
Tail gas treating processes are designed to recover the small amount of
sulfur not recovered by the Claus plant. This process first involves
catalytic hydrogenation into H2S of all the sulfur compounds leaving the
Claus unit. This H2S is converted to sulfur by wet oxidation (such as the
Beavon/Stretford process) or by recycle of the H2S back to the Claus plant
following solvent absorption (such as the SCOT process).
As indicated above, there are a number of commercially proven processes
which might be considered for sulfur removal and recovery in an IGCC plant.
3-35
-------
Work has been done recently to assess new, improved processes in this area
and to identify the most technically attractive process alternatives for
simplifying gas treating and sulfur recovery for IGCC plants (16).
In any case sulfur removal and recovery in IGCC systems does not appear to
comprise a significant capital cost, even at very high levels of removal.
Table 3-7 shows cost estimates for the sulfur removal and recovery areas
for a Shell-based IGCC. Cost estimates in terms of total capital
requirements are shown for different levels of sulfur removal. Depending
on the desired level of sulfur removal, different processes might be
selected, and Table 3-7 shows that a more suitable process choice can lead
to a more cost-effective system. For the Shell process, in which the
gasifier is operated at a lower pressure (350 psig) than that of the Texaco
process (600 psig), a combined chemical/physical acid removal process such
as Sulfinol-M®- is probably more cost-effective than the purely physical
absorption of the Selexol^ process.
This and other recent studies indicate that very high sulfur removals can
be achieved in IGCC systems at reasonable cost.
3.3.3.2 Nitrogen Oxides Emissions. Nitrogen oxides (N0X) are not formed
to any appreciable extent in the reducing atmosphere of coal gasification.
Although gasification itself or subsequent chemical synthesis would pose no
N0X emission problem, use of the gas as fuel for combustion does face N0X
limitations. NSPS limitations for all coal-derived fuels burned to produce
steam for electric power generation are 0.5 lb/million Btu.
The use of medium-Btu gas in a gas turbine or combined-cycle system would
be comparable with burning natural gas except for the increased volume of
fuel gas with its lower heating value. Because the Cool Water plant is in
an environmentally sensitive geographical area, the State Energy Commission
and the EPA PSD permits for the plant limit N0X emissions to 140 lb/hr.
This is less than 0.14 lb/million Btu heat input to the plant. To meet
this stringent limitation, fuel gas saturation (adding moisture to the
medium-Btu fuel gas) or direct steam injection to the gas turbine is used
3-36
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Table 3-7. Cost and Performance Conparison Between Base and
Deep Sulfur Removal Designs--Shell-Based IGCC
ILLINOIS NO. 6 COAL (MID-1981 DOLLARS)
CASE DESIGNATION
Sulfur Removal, %
Acid Gas Removal Process
Net Plant Power, MW
Total Plant Investment, $/kW
EXSC-I
90.0
SELEX0LR
1,122.17
EXSC-I/D
99.7
SULFINOL-MR
1,119.04
Coal Handling
73.
98
74.
19
Oxidant Feed
179.
38
179.
89
Gasification & Ash Handling
258.
36
258.
98
Gas Cooling
7.
.83
7.
,85
Acid Gas Removal
31.
.06
10.
.38
Sulfur Recovery
14.
.55
16.
,23
Tail Gas
21.
.85
9.
.91
Steam, Condensate and BFW
7.
.26
7.
.04
Process Condensate Treating
3.
.63
3.
.64
Combined Cycle
417,
.67
417,
.00
General Facilities
78
.83
79
.99
Initial Catalysts & Chemicals
13
.96
13
.54
99.7
SELEX0LR
1,117.99
Total
1,108.35
1,078.64
1,119.71*
Total Capital Requirement**:
$/kW
Net Plant Heat Rate, Btu/kWh
1,263
9,182
1,230
9,208
1,277
9,217
*Detailed breakdown of Total Plant Investment not available in reference.
**Total Capital Requirement - Total Plant Investment + Royalties + Startup
Costs -t- Working Capital + Land + Allowance
for Funds During Construction.
Source: Reference 15. Copyright (1983) Electric Power Research Institute.
Reprinted with permission.
3-37
-------
to reduce potential emissions by 70 percent. The low N0X emissions are a
major improvement compared with direct firing of coal.
3.3.3.3 Particulate Emissions. Synthesis gas produced by the gasification
of coal and by other means is routinely cleaned of particulates for feeding
to catalyst beds for chemical synthesis. In these processes particulates
are removed to a far greater extent for catalyst protection than would be
necessary to comply with environmental control requirements. Of more
concern are the fugitive emissions from feed lockhoppers, coal handling,
and coal storage systems. In this regard, the Texaco gasifier has an
advantage over other systems because coal is fed as a water slurry.
For control of particulate matter in the syngas produced in the gasifier,
coal gasification systems have the considerable advantages that the gas
cleaning is accomplished at high pressure with a much smaller volumetric
flow rate compared to combustion systems. Scrubbing with water is
accomplished with great efficiency under these circumstances.
Two other factors related to particulate control should be mentioned (17).
First, a large fraction of the mineral content of the coal is deposited as
slag on the ceramic liner in the gasifier, whence it runs off, falling
through the radiant boiler into a quench tank. Second, because the
pulverized coal is much coarser than in conventional coal-fired combustion
systems, and because the char reaction temperature is lower, the mean size
of these droplets is much larger, which greatly facilitates their removal
in the scrubber.
To limit fugitive emissions at the Cool Water plant, coal is received and
handled in enclosed equipment, using no open coal pile.
3-38
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4.0 ECONOMICS OF IGCC SYSTEMS
The discussion in this section is concerned with economic evaluation of
IGCC systems. Data were collected from the literature on cost estimates
for IGCC plants as well as costs of competing technologies. These basic
data are shown in the first subsection, and economic evaluations and
comparisons are discussed in the second subsection. Besides basic costs,
the economic evaluation of power generation systems is also influenced by
system availability. The third subsection is concerned with the
availability of IGCC. Other subsections discuss additional types of more
complex economic analyses which have been suggested to quantify certain
perceived benefits of IGCC. These concepts include system expansion
analyses and phased implementation. Finally, utilities and EPRI are
sponsoring site-specific studies which evaluate IGCC in particular
situations; although results are not yet widely available, these studies
are also discussed here.
4.1 Cost Estimates for Commercial Plant Designs
The most recent and the most detailed cost estimates readily available in
the literature for commercial IGCC plant designs appear to be the costs
developed in EPRI's most recent series of IGCC design studies for the three
major systems being developed: Texaco (13), BGC/Lurgi (14), and Shell
(15). As developed originally, the cost estimates in these studies are
based on different dollars (different time bases) and were done by
different contractors using different estimating methods and databases. To
facilitate comparative studies of different power generation technologies,
including the variety of IGCC designs, EPRI has examined the original
figures and made certain adjustments to bring all the costs to a common
basis expressed in common dollars at a common location. The resultant
figures are published in the latest version of EPRI's Technical Assessment
Guide (TAG) (18).
4-1
-------
To facilitate comparing the costs and other attributes of IGGC systems and the
competing technologies of conventional pulveriz,ed-coal plants and atmospheric
fluidized-bed combustion, the data from TAG (18) are presented in Table 4-1. It
shou] d be noted that these cost figures are estimated for mature fifth-of-a-kind
plants and that the estimates carry uncertainties indicative of the state of
technology development.
Other data showing ranges of capital costs for IGCC and other technologies are
presented in Figure 4-1. The cost ranges (low and high values for each system)
in this figure were developed by EPRI (1.9) on the basis of estimates from a
number of recent studies. Performance estimates and costs adjusted to January
1987 dollars are shown in Table h-2 for PC plants and the three IGCC
designs (18). The estimates for the Shell design in this table have been
adjusted to include the effect of using the advanced gas turbine instead of the
conventional turbine assumed in the original study (15).
4.2 Comparison with Other Power Generation Systems
The currently available estimates of the capital costs of IGCC systems may be
compared with the costs for competing power generation technologies in Tables 4-1
and 4-2, and in Figure 4-1. The costs for PC plants are hard data while the
costs for the immature technologies are only estimates. These estimates indicate
that the capital costs for IGGC systems appear to be within the same range as the
capital costs for conventional PC plants and for AFBC. Because capital cost
estimates, especially for new immature technologies which do not have long
commercial histories, are not precise and are often optimistic, this conclusion
is the only one which can be drawn from these generic estimates. In a specific
situation, utility- and site-specific factors need to be considered to determine
which technology is more economic. The capital costs in Table 4-1 for the three
IGCC designs using the advanced turbine show a significant range which is
dependent upon gasification technology and design.
Another means of comparing power generation technologies is to compare
the cost of the electricity generated. This comparison is usually done via
4-2
-------
Table 4-1. Conparison of EPRI Cost Estimates for Power Generation Technologies
BGC SLAGGER COMBINED CYCLE (ADVANCED TURBINE)
TEXACO GASIFICATION COMBINED CYCLE (ADVANCED TURBINE)
TEXACO GASIFICATION COMBINED CYCLE (CUR TURBINE) RAD&CONV*
SHELL GASIFICATION COMBINED CYCLE 99.7% SULFUR REMOVAL (CUR TURBINE)
ATMOSPHERIC FLUIDIZED BED
COAL-STEAM WITH WET LIMESTONE FGD SUBCR1TICAL
Region: East/West Central Bituminous Coal
Unit Size, MW
Plant Capital Cost, $/kW based on
Plant Size of (no. of units x unit size)
Total Plant Cost, Dec 1984 %
Total Cash Expended (mixed year $)
AFDC (interest during construction)
Total Plant Investment (includes AFDC)
Startup, Inventory, Land
Total Capital Requirement, Hypothetical
Jan 1985 In-Service (includes AFDC)
Operation and Maintenance Costs
1985 Costs in Dec 1984 $
Fixed, $/kW-yr
Incremental, mills/kWh:
Variable
Consumables
Net Heat Rate, Btu/kWh
Full Load
75% Load
50% Load
25% Load
Average Annual
Unit Availability
Planned Outage Rate, %
Equivalent Unplanned Outage Rate, %
Equivalent Availability, %
Average Daily Unavailability, ADU, %
Duty Cycle
Minimum Load, % ...
Preconst, License, & Design Time, Years
Idealized Plant Construction Time, Years
Unit Life, Years
500
500
1 x 500
1 x 500
1142
1096
1049
1006
202
194
1251
1200
70
74
1321
1274
24.0
20.0
2.3
1.9
3.2
4.6
9850
9710
9950
-
10450
-
12570
-
10060
10000
11.5
11.5
19.5
16.4
71.2
74.0
8.6
0.5
BASE
BASE
25
35
4
4
4
4
40
40
RAD & CONV*
500
500
600
x 500
1 x 500
1 x 600
1359
1411
1306
1284
1333
1233
160
166
154
1444
1499
1387
74
77
71
1518
1576
1458
30.6
31.8
28.8
2.9
3.0
2.7
0.5
0.2
0.2
9190
9490
9010
9350
9630
9150
9650
9980
9550
10350
10700
10300
9460
9775
9280
3.8
3.8
3.8
13.9
13.5
12.8
82.8
83.2
83.9
12.6
12.2
11.4
BASE
BASE
BASE
16
16
16
4
4
4
3
3
3
30
30
30
1
QUENCH
600
1 x
600
1156
1092
136
1228
69
1297
25.4
2.4
0.2
9920
10100
10500
11350
10220
3.8
12.3
84.4
10.9
BASE
16
4
3
30
500
x 500
1075
1014
127
1141
63
1204
27.2
3.5
0.8
8660
8800
9200
9900
8920
3.8
14.4
82.3
10.3
BASE
20
4
3
30
•Radiation and convection syngas coolers.
Source: Reference 18. Copyright (1986) Electric Power Research Institute. Reprinted with permission.
-------
Capital Cost - Constant 1985 $/kW
2000
1880
1680
1600
1570
1460
1300
1265
1320
1200
1200
980
920
900
800
400
CD
O)
CJ)
O
IGCC
PC
AFBC
Phased
IGCC
Source: Reference 19 (Reproduced with permission from the Annual Review of Energy, Volume 11, © 1986, by Annual Reviews, Inc.)
Figure 4-1. Capital Investment Estimates for Single 500-MW Units.
AFBC Has One 200-MW Unit Case.
-------
Table 4-2. Summary of Comparative Costs and Performance Estimates for PC and IGCC Plants
Capacity - 500 MWE; Illinois #6 Coal; Constant January 1987 Dollars
REFERENCE
COAL-FIRED
STEAM PLANT
TEXACO
PARTIAL
OXIDATION
SHELL COAL
GASIFICATION
PROCESS
BGC/LURGI
SLAGGING
GASIFIER
Sulfur Removal, %
90
95-97
90-99
95-97
NOx Emission, ppmva
150
50-75
50-75
50-75
Heat Rate, Btu/kWh
9,850
9,010
8,720
8,660
Total Capital, $/kWb
1,390
1,540
1,490
1,300
Levelized Cost of Electricity
at 65% capacity factor, mills/kWh
54.9
52.7
50.8
48.9
a. 15% Excess 02, Heat Rate Corrected; 2300°F Combustion Turbine for IGCC Plants.
b. Includes working capital, start-up costs, spare parts, land, royalties, and allowance of funds used during construction; all IGCC
plants rated at 88°F.
Source: Reference 18. Electric Power Research Institute. Reprinted with permission.
-------
"busbar costing methodology" to compute a levelized cost of electricity
(COE) over the life of the plant. The COE can be computed either in
current dollars or in constant dollars. Busbar costing methodology is
outlined in Table 4-3; further details can be found in the TAG (18).
The levelized cost of electricity is shown in Table 4-2 as calculated by
EPRI. These values show a consistently lower COE for IGCC than for
conventional PC under the limited range of assumptions made. For two of
the IGCC designs, Texaco and Shell, lower O&M and fuel costs apparently
more than compensate for higher fixed charges to result in a lower total
COE. However, by themselves these differences in the value of the COE
between PC and IGCC would probably not be enough incentive for a utility to
invest in an IGCC system, which is perceived at this point as technically
risky compared to PC, all other things being equal. It would probably
require an estimated cost advantage of 20 percent in the COE to give a
utility adequate incentive to invest in IGCC at this point in its
development (7).
It is instructive to look at the breakdown of the COE into its various
components. Table 4-4 shows the results of calculating the COE in constant
1987 dollars with the TAG data in Table 4-1. Like the results in Table 4-
2, the COEs for the IGCC designs appear to be slightly less than the COE
for PC. The COE for AFBC is less than the COEs for PC and the Texaco IGCC
with syngas cooling. Again, like the results in Table 4-2, the differences
in the COE are not great enough to be significant.
In addition, it should be noted that in the COE calculation the fuel cost
is a highly variable factor. If the fuel cost assumed is low enough, the
relative positions and the comparison of the COE values in Table 4-4 can be
changed. A sensitivity analysis would determine the importance of the
various factors which influence the COE.
In EPRI's opinion simple busbar costing methodology may not adequately
represent the total economic impact of IGCC used for capacity addition to a
4-6
-------
Table 4-3. Busbar Costing Methodology
COE, MILLS - FIXED CHARGES + FIXED O&M + VARIABLE O&M + FUEL COST
KWH
FIXED CHARGES, MILLS - (S/KW) (l+INFLATION^CFCR') (1000')
KWH (8760)(ACF)
FIXED O&M COST, MILLS = ($/KW-YR)(1+INFLATION)2(LEVEL.FACTORl)(1000)
KWH (8760)(ACF)
VARIABLE O&M COST, MILLS = (MILLS/KWH)(l+INFLATION)2(LEVEL.FACTORl)
KWH
FUEL COST, MILLS - (HEAT RATE. BTU/KWH) (FUEL COST. S/106BTU) (l+ESCALATIONt^LEVEL. FACTQR2H1000)
KWH lO5
FCR - levelized fixed charge rate over plant lifetime, in constant or current dollars
(1+Inflation)2 - effect of inflation over two years to adjust January 1985 costs in Table 4-1 to
January 1987 costs
(1+Escalation)'2 - effect of escalation of fuel costs over two years from January 1985 to January 1987
Level.Factor 1 - levelization factor for discounting over 30 years, in constant or current dollars
Level.Factor 2 - levelization factor for fuel escalation over 30 years, in constant or current dollars
ACF = Annual capacity factor
-------
Table 4-4. Calculations of Levelized Cost of Electricity
Constant 1987 Dollars
Texaco IGCC
PC with
Limestone FGD
AFBC
Rad.+Conv.
Gas Cooline
Ouench
BGC/Lurei
Fixed Charge
25.35
24.45
27.98
24.89
23.11
Fixed O&M
4.47
3.73
5.37
4.73
5.07
Variable O&M
5.83
6.70
3.08
2.76
4.56
Fuel Cost
18.33
18.22
16.91
18.62
16.25
Total, mills/kWh
53.98
53.10
53.34
51.00
48.99
Assumptions: East/West Central location, bituminous coal, 1 500-600 MW unit, ACF - 65 percent,
annual average heat rate used, data from Table 4-1.
Economic Factors: Two years of inflation @ 3 percent since 1985, fixed carrying charge factor =
0.103, fuel cost (Jan. 1985)* - $1.55/10^ Btu, escalation for fuel - 0.8% above inflation, real
discount rate - 6.1 percent.
* It should be noted that fuel cost is a highly variable factor depending on coal type, source
location, point of use, etc. The value used here is the cost recommended by EPRI (18) for a
representative coal for technology comparisons at the common West Central location on which all
of the other costs are based. This value is based on the price required for coal from a new
mine when brought to market under a new contract. Actual 1985 prices were generally lower due
to depressed market conditions.
-------
utility power generation system. For example, busbar costing methodology does
not consider the effect of IGCC's potentially higher availability.
4.3 Availability of IGCC Plants
One of the advantages of IGCC systems is that they can be highly modular (i.e.,
contain several parallel trains of gasification and gas turbine components).
This modular characteristic of IGCC systems is perceived by EPRI to lead to high
potential equivalent availabilities. This characteristic also leads to capital
conservation (by reducing reserve margin requirements) as well as lower revenue
requirements as plants can be dispatched at higher capacity factors.
To evaluate a new generating technology such as IGCC, the electric utility
planner must have estimates not only for the plant performance and cost, but also
for the expected plant availability. Because the planner may be evaluating a
number of design and operational alternatives in the IGCC plant, availability
measures for each alternative would be required to properly assess the options.
EPRI has sponsored a number of detailed availability analyses of commercial IGCC
designs. Better estimates of availability for some of the components within the
IGCC have recently become available, and greater definition has been achieved in
the off-design performance of the components within the IGCC and of the
interactions between these components in their off-design condition.
To make use of this information, a recent project has just been concluded (20),
with the following objectives:
• To develop availability estimates for mature commercial IGCCs
employing the most current component reliability data and
performance data
• To evaluate the availability implications of various
operational and design alternatives
• To develop scheduled maintenance plans for a commercial,
multi-train IGCC
4-9
-------
• To provide a basis for future work in the area of IGCC
availability as improved estimates become available, particularly
from the Cool Water plant.
The IGCC design which served as a basis for these availability analyses was
the Texaco-based plant described in Reference 13. This IGCC plant
consisted of four gasification trains incorporating the Texaco coal
gasification technology, and three combustion turbine trains. From this
reference design a number of other baseline and sensitivity cases were
developed with the objective of assessing the impact of various design and
operational alternatives on the overall plant availability.
The "Baseline IGCC" case in this study assumed that the plant would operate
without either supplemental firing or backup fuel firing. The plant full-
load capacity was 598 MW. The results from an analysis of the baseline
IGCC operation suggested an expected plant equivalent forced outage rate
(EFOR) of 9.6 percent. When a relatively optimistic scheduled outage rate
(SOR) of 4.7 percent was employed, the resulting plant equivalent
availability [equal to (1-EFOR)(1-SOR)] was shown to be 86.2 percent. A
pessimistic scheduled outage rate of 9.0 percent changed the equivalent
availability estimate to 82.3 percent. The "expected" estimate would
probably lie somewhere between these two values.
These latest estimates of the availability of IGCC plants can be compared
to those estimates in the EPRI Technical Assessment Guide (18), which are
based on earlier assessments and are shown in Table 4-1. As the result of
this latest analysis, the estimated equivalent forced outage rate for a
baseline IGCC plant (Texaco-based, including radiant and convection
coolers) has decreased from 12.8 percent to 9.6 percent, and the plant
equivalent availability has changed from 83.9 to the range of 82.3 to 86.2
percent, depending on the scheduled maintenance plan and the scheduled
outage rate (between 9.0 and 4.7 percent, respectively).
The conclusion from this comparison of availability estimates is that the
latest data on the operation of IGCC plant components have not changed
4-10
-------
earlier estimates very much. It should be kept in mind that these
availability figures for IGCC plants are calculated estimates and not hard
data. Also, these figures were calculated using component data from non-
IGCC systems, and these data may not adequately represent the effects on
reliability of component interactions within IGCC systems. As more
component reliability and maintenance data become available, particularly
from the Cool Water plant as well as from other sources, more availability
analyses will undoubtedly be conducted to develop improved estimates.
4.4 Economics of IGCC in System Expansion Analyses
When costs of electricity produced by different types of electric power
plants are compared, the cost of electricity is commonly calculated in
mills per kilowatt-hour using busbar costing methodology, as explained
above. However, this approach does not consider different plant
performance characteristics, such as changes in relative unit capacity
factors with time, reliability, availability, or unit capacity changes
with temperature; performance and characteristics of other units on a
system; or system load shape characteristics and changes.
Recent studies have been sponsored by EPRI (21j22) to perform thirty-year
generation system expansion analyses on the EPRI West Central Regional
System from 1991-2020 to:
• Estimate differences in system costs of electricity when the
system is expanded alternatively with conventional pulverized
coal-steam (PC) units and with IGCC units with and without
supplemental firing^-, and to compare these differences with those
calculated from busbar costing methodology.
• Estimate system reserve requirement savings due to the postulated
higher reliability of IGCC units.
1 The IGCC units have spare gas-making capacity. When this capacity is
available, it can be used to fire the heat recovery steam generator in
the combined-cycle plant.
4-11
-------
• Estimate relative capacity factors of conventional coal-steam and
IGCC units.
The purpose of one of these studies (22 ) was to derive full system benefits
of BGC/Lurgi IGCC plants compared to conventional pulverized coal-steam
(PC) plants, using the most current data regarding costs and performance of
both plant types. The conventional coal data used for this study were
compatible with the 1986 TAG data (18) . The Lurgi IGCC data were obtained
from EPRI Report AP-3980 (14), which describes in detail the operation and
design of the IGCC unit with and without supplemental firing.
In this study the project methodology consisted of a thirty-year, utility-
system-oriented assessment of the present worth of the revenue required
(PWRR) from 1991 through 2020 of optimal generation expansion plans on the
EPRI West Central Regional System. The PWRR methodology incorporates the
characteristics of existing utility system generation and utility load
shape, as well as characteristics of the new expansion units. EPRI's
Electric Generation Expansion Analysis System (EGEAS) was used for
performing the optimization analysis, and ZECO's production costing program
(PRODCOST) was used for performing the detailed production costing
calculations.
The system expansion results from this study indicated that significantly
different amounts of capacity additions and different levelized electricity
production quantities resulted from the IGCC and conventional coal
expansions. The results also indicated a greater cost advantage for IGCC
over conventional PC in terms of the COE for the power produced than that
calculated from busbar costing methodology. Similar conclusions were
reported in the previous study of this type based on Texaco gasifiers (20).
However, the results from system expansion studies of this type are highly
dependent upon the set of technical and economic assumptions used in the
analysis. Such a study is very specific for the utility which is modeled,
and great care must be taken in setting up the model and interpreting the
results. Sensitivity analyses should also be done as a part of the
4-12
-------
analysis to determine the influence of the assumptions and to evaluate the
validity of the conclusions accordingly.
For example, in the studies cited above (21, 22), the major reason for the
large advantage for IGCC units was a major displacement of oil generation
from the system. Also, the studies were done when crude oil prices were
high. For these reasons the results from these two studies do not appear
to be reasonable or broadly applicable.
4.5 Phased Implementation of IGCC Power Plants
In the past addition of new plant capacity in the utility industry tended
toward increasingly larger plant sizes. This trend was justified by
substantial growth and a desire to benefit from economies-of-scale.
However, in recent years, the utility industry has been projecting growth
at a reduced rate and reevaluating its planning strategies. Low growth and
high interest rates have shifted the emphasis in planning towards mini-
mizing capital requirements by deferring new investment. Low growth rates
provide an incentive for the utility industry to build smaller plants,
which generally carry the penalty of higher cost per unit of capacity.
4.5.1 Unphased vs. Phased Capacity Addition
The use of phased capacity addition (23) is one method that may be used to
provide small capacity increments (phases) at unit costs representative of
larger plants. If this method is properly applied, the performance of the
final plant (all phases together) is identical to that of the plant built
in a single phase. Constant-dollar capital cost for the phased plant would
be slightly greater than that of the unphased plant. There appears,
however, to be an economic incentive to add capacity in phases when net
present values of expenditures are compared. Phased capacity addition also
appears to offer other benefits compared to unphased capacity addition.
These benefits include increased flexibility, the ability to recover from
sudden and unforeseen changes in load demand, reduction in, and deferral
of, "at-risk" capital, and earlier entry of capital into the rate base.
4-13
-------
Phased capacity addition makes it possible to match load growth more
closely than has been possible with large unphased plants, as can be seen
by comparing Figures 4-2 and 4-3.
Figure 4-2 represents unphased capacity addition, where capacity is added
in a single increment. On this figure the diagonal line represents the
projected total system load plus reserve requirements for a utility, while
the horizontal lines represent total system generating capacity at a given
point in time. As the system load grows over time, the total load
approaches the total generating capacity of the existing system. At the
intersection of the system load and system capacity lines, the utility must
increase capacity. For unphased capacity addition, this increment is
assumed to be sufficiently large for overall efficiency to be high and cost
per unit of capacity to be low. Following the capacity increment, the
system capacity greatly exceeds the system load. The area between the new
system capacity line and the system load, represented by the shaded
portion, is excess capacity.
By contrast, the use of phased capacity addition is illustrated on Figure
4-3. The same total increase in capacity is effected by adding small
increments sequentially as needed. As can be seen by comparing the two
figures, phased capacity addition makes it possible to match capacity
addition to load growth, and to defer capital spending until it is
required. Excess capacity is reduced. Capital expenditures are deferred,
contributing to a lower cost of electricity. By comparison with unphased
capacity addition, it can be seen that "at-risk" capital is reduced and
deferred.
4.5.2 Effect of Phased Capacity Addition on Capital Expenditures
A hypothetical example of an unphased IGCC plant is shown in simplified
form in Figure 4-4. The gasification plant uses three gasifiers and is
sized to provide sufficient turbine fuel to fully load two advanced gas
turbines at the summer ambient temperature. Radiant syngas coolers within
4-14
-------
mojictio
'CA»*CiTY
RiOUIRfMCNTS
f
TMf
Source: Reference 23. Copyright (1986) Electric Power Research Institute.
Reprinted with permission.
Figure 4-2. Unphased Capacity Addition.
s
MU! 1
»»«i
WKXltCtlO
CAPACITY
MIQUMCMENTS
caht*l
€XHN0
-------
CO *U
GASIFICATION
PtANT
MIS .
2 AOVANCEO
OAS TURBINES
HEAT
RECOVERY
STEAM CYCLE
ru*ti»l
*utl
*
$T(M
i
\
NET CAPACITY
ADDITION
3UMW
Source: Reference 2 4. Copyright (1986) Electric Power Research Institute,
Reprinted with permission.
Figure 4-4. Unphased IGCC Plant.
ruMiM ?uti
HEAT
RECOVERY *
STEAM CVCLC
»«ASt 3 AOOiTiON
'HtSIl
TUMiM FUCl
ADVANCED
GASTURSINI
1<*1| | AOOiTiON
AOVAMCED
OAl TURtINf
MAU I AOOlTlQN
GASPICATtON
KANT
^HAMlAOOtTlOM
NIT CAPACITY
PNAM ADQlTtON
104 MW
104 MW
t54 MW
362 MW
Source: Reference 2^. Copyright (1986) Electric Power Research Institute.
Reprinted with permission.
Figure 4-5. Phased IGCC Plant Phasing Sequence.
4-16
-------
the gasification plant provide steam to the heat recovery steam cycle,
which generates additional steam by recovery of heat from the gas turbine
exhaust. The steam cycle uses a single reheat-type condensing steam
turbine. Gross power generated includes 134 MW from each gas turbine and
153 MW from the steam turbine. Internal power consumption is 59 MW, giving
a net power-generating capacity of 362 MW for the facility. Based on the
higher heating value (HHV) of the feed coal, the plant exhibits a heat rate
of 9600 Btu/kWh.
One possible sequence of capacity addition for the phased 1GCC plant is
shown in Figure 4-5. Phase 1 consists of a single simple-cycle gas turbine
power plant. Since the addition of the gasification plant is deferred until
a later phase, a conventional turbine fuel, such as natural gas or
distillate oil, is used. Capacity addition in the second phase consists of
a second simple-cycle gas turbine. The coal gasification plant and the
heat recovery steam cycle are added in Phase 3. In this phase the gas
turbines are modified to accept the coal-derived fuel. The performance of
the final plant after the addition of Phase 3 is identical to that of the
unphased IGCC plant--362 MW net power at a 9600 Btu/kWh heat rate.
A summary of the capital cost and plant performance estimates for these two
IGCC plants from a recent reference (24) is shown in Table 4-5. Capital
costs are expressed in terms of constant dollars (basis January 1984) per
unit of capacity. These costs represent cumulative total plant investment
(TPI) for a given scenario at an Illinois location but do not include
allowances for interest during construction or other costs (e.g., owner's
costs). Comparison of the estimates shown indicates that no performance
penalty is incurred due to phased capacity addition, while only a slight
(one percent) cost penalty is incurred. Since each phase is assumed to be
built as a separate facility, certain minor diseconomies are encountered.
The value of phased capacity addition may be seen by comparing the net
present value of capital expenditures for all phases with the net present
value of capital expenditures for an unphased plant. In a recent study
(23 ) the net present value of capital expenditures was calculated for each
4-17
-------
Table 4-5. Cost and Performance Sunmary for Phased IGCC Construction
(January 1984 Dollars)
FIRST PHASE
Capacity Type
Rating Temp.
Capacity
Heat Rate,
Btu/kWh
Total Plant
Investment
SECOND PHASE
Capacity Type
Rating Temp.
Cumulative Capac.
Heat Rate,
Btu/kWh
Cumulative Total
Pl8nt Investment
THIRD PHASE
Capacity Type
Rating Temp.
Cumulative Capac.
Heat Rate,
Btu/kWh
Cumulative Total
Plant Investment
FINAL PHASE
Capacity Type
Rating Temp,
emulative Capac.
Heat Rate,
8tu/kUh
emulative Total
Plant Investment
Unphased
IGCC Plant
IGCC
88 F
362 MW
9,600
1308$/kW
Phased
IGCC Plant
Adv GTh
88 F
104 HW
11,900
241$/kW
Adv GTH
88 F
208 HW
11,900
230$/kW
IGCC
88 F
362 MW
9,600
1321$/kW
Separate
Steam
Cycle Phase
Phased IGCC Plant1,2
Steam
Turbine *
Retrofit
Adv GT
88 F
104 MW
11,900
241$/kW
Adv GTh
88 F
208 MW
11,900
230S/kW
Combined Cycle
88 F
310 MW
8,000
498$/kW
IGCC
88 F
362 MW
9,600
1343$/kW
Adv GT*
88 F
104 MW
11,900
242$/kW
Adv GT
88 F
208 MW
11,900
231$/kW
IGCC
88 F
357 MW
9,800
1142$/kW
Radiant and
Convective
Coolers
Adv GTh
88 F
104 MW
11,900
241$/kW
Adv GT
88 F
208 MW
11,900
230$/kW
IGCC
88 F
360 MW
9,000
1382$/kW
N0TES:(1)The fuel type used in all but the final phase is natural gas; the fuel used in the final phase is coal.
(2)Except where noted, the major plant design bases are as follows: Advanced Gas Turbines, Illinois No. 6 Coal,
Radiant Only Syngas Cooling, Reheat Steam Cycle.
(3)Once-through lake water cooling and an Ohio site (a more expensive construction site) assuned for this case.
(4)Advanced gas turbine.
Sauce: Reference 24: Copyright (1986) Electric Power Research Institute. Reprinted with permission.
-------
of three load growth scenarios (five years, seven years, and ten years) for
adding the capacity of one unphased IGCC plant. Construction schedules,
together with capital costs for each phase, were used to estimate a cash
flow centroid for each case. These centroids showed deferral of
expenditures relative to the unphased IGCC plant case of four years, five
years, and seven years, respectively. With a value of six percent assumed
for the real cost of money, savings due to phased capacity addition ranged
between about $200/kW and $400/kW for these examples.
The real value of the phased capacity addition concept would, of course,
depend on the specific application and would necessarily consider all
costs, not just capital-related costs. A complete analysis would also
consider the possible need to replace the peaking capacity absorbed by the
phased IGCC plant and the resulting effect on capital requirements. Since
each utility system is different, it is not possible to generalize the
actual savings that may be realized by using this concept. However, it is
apparent that phased capacity addition may have the potential to provide
cost savings over more traditional approaches.
4.5.3 Effect of Phased Capacity Addition on Cost of Electricity
To estimate the savings that could potentially be gained by the use of
phased capacity addition, an economic evaluation was also performed in this
study (2.3 ). The evaluation was based on comparing the costs of electricity
estimated from annual revenue requirements calculated for an unphased and a
phased IGCC plant capacity addition. This method allows an approximate
comparison of the two capacity addition scenarios, but does not account for
any changes in revenue requirements for the balance of the utility system.
The true value of phased capacity addition is dependent on the specific
characteristics of all plants on a particular utility system, the daily and
seasonal variations in load for that system, and the projected growth of
the system.
Cost-of-electricity calculations were carried out (23) assuming load growth
at a rate sufficient to fully load a new 362-Mtf plant in ten years. This
4-19
-------
rate corresponded to slightly more than 30 MW of new load growth each year.
Linear growth over existing system capacity was assumed, starting in the
year 1990. Based on this growth, Phases 1, 2, and 3 were required to be
on-line in the years 1990, 1993, and 1996, respectively, while the unphased
IGCC plant was required to be on-line in the year 1990.
The economic comparison of unphased IGCC plant with phased IGCC plant
capacity addition requires that assumptions be made regarding plant
operation; i.e., annual capacity factor. The simplest assumption is that
new capacity is dispatched to provide exactly that power increment
represented by new system growth. This operating scenario was named the
"Match Load Growth" scenario. This assumption, in effect, defeats the
utility dispatch system by isolating this new capacity and new growth from
the existing generation system and load demand.
Possibly, a more likely scenario is to allow new capacity to operate at an
annual capacity factor which might be attainable on a system. In this
scenario, it was assumed that IGCC capacity is dispatched at a high
capacity factor (85 percent) and that simple-cycle combustion turbine
capacity is dispatched at a low capacity factor (5 percent). This
operating scenario, named the "Constant Capacity Factor" scenario, does not
capture the effect of changes in revenue requirements for the balance of
the utility system.
The cost of electricity was estimated using a method which calculates
yearly revenue requirements. Capital and operating costs were estimated
for each phase of the phased IGCC plant case and for the unphased IGCC
plant case. The economic indicator chosen for comparison purposes was
described as a pseudo-levelized cost of electricity (COE). Since multiple
phases were present in the evaluation and the net power generated annually
was varied in some scenarios, this COE was defined as the net present value
of the total revenue requirements divided by the number of net kilowatt-
hours produced over the life of the scenario. This indicator is expressed
in terms of mills/kWh (1984 dollars) in Table 4-6. The results indicate a
9 to 16 percent savings in COE for the phased IGCC plant case.
4-20
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Table 4-6. Sunmary of Econoaic Evaluation Results
for Phased Implementation of IGCC
Operating Scenario
Match Load Growth
Constant Capacity Factor
Cost of Electricity, Mills/kWh
Unohased IGCC Phased IGCC
44.9
43.8
40.9
36.7
Source: Reference 23 . Copyright (1986) Electric Power Research
Institute. Reprinted with permission.
4-21
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Examination of the results shows that the capacity factor assumption has
little effect on the COE for the unphased IGCC plant. However for the
phased IGCC plant, expensive fuel is used in the early phases, and
inexpensive fuel is used in the final phase. In this scenario, the early
phase dispatch assumption has a great effect on the overall revenue
requirements, since matching the load growth curve requires that a
substantial amount of power be generated using the expensive fuel.
Papers have appeared in the literature recently (25) explaining the concept
and the advantages of phased capacity addition or phased implementation,
and EPRI has published a guidebook with basic information about phased IGCC
systems as a resource for utility planners (24).
4.6 Repowering
In a retrofit situation IGCC can conceivably be used to repower steam
turbines at an existing station with a coal-gas fired combustion turbine
topping cycle (26). In a potential retrofit situation the boiler may be
considered wornout and in need of replacing, but the steam turbine could
have a significant remaining service life, particularly in conjunction with
an equipment life extension program. Depending on the steam conditions
used in the available turbine, capital cost savings from repowering can
result in a significant lowering of the cost of electricity (COE) compared
to that of a new "greenfield" unit (i.e., a complete new power generation
plant built from the ground up, starting with a "green field"). If,
however, the existing steam cycle substantially deviates from the optimal
steam conditions for IGCC operation, the deterioration in heat rate may
more than offset capital cost savings. The complex interaction of capital
cost, system heat rate, and operating costs and its effects on the overall
economics of an IGCC retrofit require an in-depth evaluation to determine
the optimal reuse of existing equipment.
General potential advantages of making use of the existing steam turbine
and other facilities in a retrofit include (26):
4-22
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• Reduces the capital cost from that of a new "greenfield" facility.
• Does not require opening up a new site.
• The high SO2 removal rate may allow for "bubbling" the entire
plant, thus reducing environmental expenditures for other units.
In one study described in the literature (26), capital savings resulting
from reuse of existing facilities more than offset the increase in heat
rate caused by the use of existing steam turbines. While the heat rates
for the simple retrofit designs were found to be about 400 Btu/kWh greater
than for the corresponding greenfield designs, the capital costs were
estimated to decrease by about $200/kW. For equivalent plant configur-
ations the COE was reduced by approximately 8 percent over that for the
greenfield site. The additional cost of adding topping turbines and
associated reheat capability to the retrofit designs was offset by an
improved heat rate, resulting in over 1 mill/kWh reduction in COE at a
given capacity factor.
An example of the costs involved in a steam turbine retrofit case compared
to the costs of a new 1GGC plant is shown in Table 4-5. The final-phase
IGCC plant in the retrofit case made use of existing steam cycle equipment
at that site. The existing steam system used a non-reheat steam cycle with
heat rejected to lake water. Integration of the gas turbines and coal
gasification plant with this steam system yielded a heat rate of 9800
Btu/kWh and a total plant investment of $1142/kW. The final phase plant
capacity of 357 MW is the net capacity of the system, including the
existing steam turbines. A detailed economic evaluation would be necessary
to decide if the lower capital cost more than justified the higher plant
heat rate, which would increase fuel cost.
It must be emphasized that the results from any repowering study are
specifically applicable only to the particular generating system, coal
resources, and site. The results do not necessarily extend to other cases.
Repowering must be evaluated within a specific utility's framework to
arrive at meaningful conclusions regarding the viability of IGCC as a
repowering option.
4-23
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4.7 Utility- and Site-Specific Studies
On the basis of simple comparisons using generic cost and performance
estimates, the economics of IGCC and competing technologies are very
comparable, the most economic choice being determined by utility- and site-
specific factors (26). To obtain more detailed information on the effect
of these factors on the potential cost-competitiveness of IGCC, the Utility
Coal Gasification Association (UCGA) and EPRI are each sponsoring a series
of utility-specific studies. The results of these studies should support
more definitive conclusions on the economics of IGCC and its acceptability
to utilities.
The UCGA is a private informal organization comprised of some 40-45
utilities. The UCGA is organized to collect and disseminate information on
coal gasification to its members. Thirty-six of the members are U.S.
utilities representing 60 percent of U.S. electrical power production
capacity (5). Many UCGA members are involved in one phase or another of
studies which might lead to the eventual deployment of an IGCC plant.
Seven such UCGA studies have been concluded and organized into a report
( 27) • Six of these studies included IGCC and conventional PC plants among
the alternatives considered, and five of these six found phased IGCC to be
more attractive than conventional PC plants. Three of these five even
found unphased IGCC to be more attractive, the other two not making this
comparison. The sixth study concluded that PC was more attractive than
unphased IGCC.
Papers on other utility-sponsored studies have already appeared in the
literature <26. >28 ) indicating that IGCC can be very competitive with
conventional PC plants in specific situations. In both papers phased IGCC
is compared with conventional PC plants with FGD. Reference 26 also
mentions reviewing AFBC and compressed-air energy storage, as well as
repowering with IGCC.
4-24
-------
EPRI is sponsoring a series of approximately 15 utility site-specific
studies to learn more about IGCC's competitiveness. The studies will
include all four leading gasification processes as well as the KRW process.
Repowering will be the subject of interest in at least three studies.
Phase 1 of the studies will involve developing cost and performance
estimates, and Phase 2 will be concerned with expansion analyses.
The results of all of these utility-specific studies should provide
valuable guidance concerning utility perceptions of the performance and
economics of IGCC evaluated in utility situations.
4-25
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5.0 FUTURE POTENTIAL MARKET FOR IGCC SYSTEMS
5.1 Utility Perceptions of IGCC and Factors Influencing Penetration
During the course of this study, several utilities were contacted on an
informal basis to obtain general information regarding utilities'
perceptions of IGCC and its state of development. It was felt that this
information would be useful in evaluating utilities' attitudes towards IGCC
since their attitudes would be very important in determining the potential
rate of penetration of IGCC into the power generation marketplace. Some of
this information about the state of development of IGCC has already been
presented in other parts of this report. The sample of utilities contacted
was not large, and no attempt was made to conduct an all encompassing
survey. However, the utilities' perceptions of the status of IGCC were
fairly uniform; the major difference lay in utilities' attitudes and
acceptance of the perceived technical risks involved in IGCC.
The utilities contacted reported the following thoughts on the status of
IGCC. (Information on these perceptions available elsewhere in this report
is indicated as a section reference.)
• As successful as Cool Water appears to be, it is not a commercial
plant. (Section 2.0)
• It may be worthwhile to wait to see the results of scale-up work
with other gasification systems besides Texaco. For example,
Shell's dry coal feed system is of interest and is seen as a
possible advantage. (Section 3.1)
• The advanced turbine is necessary for IGCC to attain a high
efficiency, and it requires demonstration. (Section 3.2.1)
• Cool Water's capacity factor is too low up to the present time
and heat rate too high to impress utilities with the technology.
(Section 2.4)
• Longer runs with high-sulfur coal are needed to prove out the
technology with this feedstock. (Section 2.0)
5-1
-------
• Economics of IGGC are not sufficiently attractive; the economic
evaluation of EPRI Report AP-3486 (13) should perhaps be redone.
(Section 4.0)
• More cycling of the operation should be done to test out the
system as a utility would use it. (Section 2.4.4)
• Not all utilities can take advantage of phased implementation.
(Section 4.5)
• Operating data are not certain enough to predict costs and
maintenance needs; more recent operating data have not yet been
published. (Section 2.5)
• Although there is no doubt that IGCC is environmentally
attractive, is this technology necessary? (Section 3.3)
• More and larger-scale demonstrations are needed to prove the
technology. (Section 3.1)
• Utility operating personnel are leery of chemical process
operations. (It should be noted that Cool Water is operated by
utility operators, who have apparently readily adapted to
chemical process operations.)
• No specific R&D needs to be done; present effort should be
continued at the same pace. (Section 2.5)
Utilities appear to agree that IGCC is presently risky, technically and
economically. However, there appear to be some utilities who are
sufficiently impressed with the potential advantages of IGCC, as supported
by extrapolations of the Cool Water data, and with phased implementation to
do planning studies to use the technology.
A number of factors can potentially influence the penetration of IGCC
systems into the commercial sector. These factors include:
• Price of Coal. If the price of coal continues to be low,
utilities will have no incentive to choose IGCC over less
efficient conventional pulverized coal-fired plants.
• Prices and Availability of Alternate Fuels. Oil and gas have
generally been used in combined-cycle power plants to handle peak
5-2
-------
loads. Recent reductions in prices and increased availability of
oil and gas have encouraged utilities to continue using these
fuels. If premium fuels continue to be available at competitive
prices, the near-term application of IGCG systems will be
limited.
• Information fron IGCC Demonstrations. Several IGCC systems are
being or are going to be demonstrated (e.g., Cool Water by
Texaco, Placquemine by Dow, and Deer Park by Shell) over the next
few years. The information and the confidence to be derived from
these demonstrations will be used to develop better IGCC designs
with improved performance. A larger base of operating experience
with IGCC will give utilities more confidence in the technology.
• Projected Costs. With improvements in the design and performance
of IGCC system components, the overall cost may decrease to
enhance IGCC's competitiveness over other systems such as
fluidized-bed combustion and conventional PC boilers with FGD.
• Actions of Other Utilities. The U.S. electric utility industry
in general is not interested in new generation capacity at this
time since over estimation of load growth during the 1970s has
led to an over-capacity situation. For this reason utilities may
find it more advantageous to continue to operate the current
coal-fired boilers than to build new replacement plants.
5.2 Estimated Total Market for New Coal-Based Systems
Projections of the total installed power generation capacity of various
types of systems have been obtained from base runs of the Advanced Utility
Simulation Model (AUSM). This output from AUSM run with the EPA interim
base case scenario is shown in Table 5-1 for the entire U.S. This table
shows the projected total installed capacity by year of various types of
power generation systems. The bottom line shows the change in total
installed capacity from 1990 to 2010 for each type.
According to these projections, the total installed capacity for coal-steam
plants will increase over this period by 200,000 MW, gas turbine capacity
5-3
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Tabic 5-1. PROJECTIONS OF U.S. TOTAL INSTALLED POWER
GENERATION CAPACITY BY YEAR FROM AUSM
Figures in MW
Coal Oil Oil 6as Gas Hydro* Total*
Year Steal Steaa Turbine Steal Turbine Nuclear Capacity Capacity
1988
II
H
•
•
•
1
1
I
II
II
II
II
tl
II
II
II
II
1981
1982
261631
65822
26312
95582
20703
57593
72904
599746
1983
270772
63831
26327
95109
20849
62358
73514
612760
1984
278729
62739
26372
94732
20973
66541
74893
624179
1985
285519
61300
26385
94328
21124
72937
74588
636682
1986
291456
61157
26411
93982
21316
81150
74982
650454
1987
296019
60581
26595
93640
21569
88482
75337
662222
1988
299857
60185
26765
93254
21889
95164
74377
671491
1989
303748
59851
26944
92926
22203
101886
73677
681155
1990
307968
59704
27092
92744
22496
105383
72981
688367
1991
313455
59554
27198
92571
27011
106528
72297
698614
1992
319240
59443
27235
92415
32354
107232
71B85
789884
1993
325688
59446
27225
92354
38369
10768S
73823
724590
1994
3323B9
59449
27173
92299
45271
107948
760e?
740538
1995
337945
59480
27174
92490
53174
108465
78442
757171
1996
343834
59506
27251
92631
57043
108958
80856
770078
1997
349646
59557
27331
92730
60319
109207
82994
781784
1998
354739
59473
27364
92812
63492
109457
83808
791145
1999
361067
59353
27340
92870
65713
109686
84097
880127
2009
368368
59231
27177
92685
67410
109661
84378
808902
2801
375360
59197
26368
92457
69386
109460
84653
816881
2082
383012
59226
25494
92277
71150
109003
85898
825261
2003
391517
59311
24056
92203
73388
108199
85622
834295
2084
481870
59451
22368
92213
75518
106745
86172
843538
2005
413894
59610
19751
92177
76872
104511
86542
852557
2806
427382
59563
17362
91963
77755
101192
86968
862897
2017
444478
59268
14487
91165
78817
96156
87289
871580
2808
464362
58930
11928
90075
78743
98513
87483
881946
2009
485524
58530
9428
88711
78756
84635
87613
893198
2010
507559
58051
7811
87226
79011
78715
87798
906163
Total Change 199,591 -1,653 -19,281 -5,518 56,515 -26,668 14,809 217,796
-------
will increase by 57,000 MW, and hydro by 15,000 MW. Oil-steam, oil-
turbine, gas-steam, and nuclear will all decrease, according to this model.
The net increase of total installed capacity of all types is estimated to
be 218,000 MW.
5.3 Future Potential Market for IGCC Systems
As described in Section 5.1 above, penetration of IGCC into the power
generation market will be influenced by a variety of factors. The most
important factors may be a satisfactory commercial demonstration and IGCC's
cost-competitiveness. If utilities are to accept the technical risk
associated with IGCC because it lacks a long operating history, adequate
economic incentive is required. This incentive is provided in the concept
of phased implementation. As explained in Section 4.5 above, phased
implementation may provide a number of benefits in addition to potentially
lower overall revenue requirements, and it is possible that IGCC will be
implemented initially via this path.
Thus, since phased implementation begins with purchasing combustion
turbines initially to provide peaking capacity, it is suggested that the
estimated market for gas turbines may provide a clue to the potential
initial market for IGCC. The EPA interim base model results (see Table
5-1) projects a market of about 57,000 MW for new gas turbines from 1990 to
2010.
This new gas turbine capacity should provide significant opportunity for
phased IGCC systems. When the cost of natural gas rises sufficiently to
make coal-derived gas cost-competitive, gasification systems and steam
turbines could be added to form complete IGCC plants. Thus, some of this
future peaking capacity could gradually evolve into IGCC baseload capacity
which would satisfy part of the anticipated market for new coal-steam
5-5
-------
plants. As gas turbines would be taken out of peaking service by being
modified to burn syngas for baseload generation, new gas turbines would
perhaps have to be added to maintain the required peaking capacity.
Additional opportunities for application of IGCC include repowering of
existing coal-fired steam plants and complete IGCC plants which might be
built as an unphased capacity addition in competition with conventional PC
or other technologies such as AFBC.
5-6
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6.0 CONCHJSIONS AND RECOMMENDATIONS
6.1 Conclusions
Conclusions concerning the technoeconomic status of IGCC power generation
systems, reached as the result of this study, are as follows.
1. IGCC designs all have excellent environmental characteristics compared
to other power generation systems, in terms of SC>2, N0X, particulate
emissions, and solid wastes, and there are solid technical reasons for
IGCC's environmental superiority.
2. The technological status of IGCC designs is a function of the type of
gasification system. The several gasification technologies being
developed for IGCC application are in different stages of development
with different kinds and amounts of technical risk.
Texaco-based systems are further along in being demonstrated at
commercial scale and so carry less risk although certain questions
remain to be resolved.
Less advanced in being demonstrated, the Shell gasifier is still in
the pilot-plant stage, and the BGC/Lurgi gasifier has reached the
prototype size. Scale-up of these gasifiers to commercial size may
yet reveal serious problems requiring R&D for their resolution.
- The Dow system is being demonstrated at commercial scale but cannot
be considered commercial because no information is available on its
operation and financial guarantees (from the Synthetic Fuels
Corporation) were apparently required to make the technical and
economic risks involved acceptable.
At this point in time, there do not appear to be any insurmountable
development problems which might prevent IGCC technology from
achieving its technical potential.
6-1
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3. The Cool Water operation is apparently a very successful near
commercial-scale demonstration for a Western low-sulfur coal under
baseload conditions. Because of various cost constraints, the plant
was never designed to compete economically and requires financial
guarantees to operate. However, the Cool Water experience has
provided significant data leading to process improvements and
indicating the basic operability and success of combining chemical
process technology with power generation. Cool Water data, when
extrapolated and analyzed, supports the future potential of IGCC
technologies.
4. Although the Cool Water plant has been successful, technical questions
remain to be resolved before utilities will embrace even Texaco-based
IGCC technology in a significant way. Some of the significant
questions are:
- Operability of the Texaco gasifier at full throughput
Materials of construction
Plant operation over an extended period of time (perhaps at least a
year) with high-sulfur Eastern coals
Plant availability/reliability.
Only a successful demonstration designed to be competitive in a
commercial environment with the advanced technology and operated over
a satisfactorily long runtime can resolve these questions.
5. Site-specific and cost studies of IGCC show sufficient potential to a
number of utilities for them to begin preliminary planning studies for
IGCC. However, since little additional baseload capacity must be
implemented now, many utilities are waiting to see how IGCC and the
various gasification technologies continue to develop before seriously
considering the technology. Many feel that the prices of oil and gas
must increase sufficiently relative to that of coal before coal
gasification will be economically competitive.
6. Phased implementation may give IGCC significant economic advantages.
However, a utility must have access to oil or natural gas to be able
6-2
-------
to take advantage of phased implementation. Not all utilities do, nor
are they prepared to assume the economic risk of increased reliance on
natural gas or oil.
7. Simple cost comparisons of IGCG with competing technologies indicate
that capital costs may all be within the same range. The higher
energy efficiency of IGGG may result in a slightly lower levelized GOE
under a limited range of assumptions. Utility-specific and site-
specific factors determine which technology is most economic in a
particular situation.
8. System expansion analyses show that IGCC may have advantages such as a
higher annual capacity factor and a higher availability, which reduces
reserve margin requirements. However, these advantages are strongly
dependent upon the set of technical and economic assumptions used in
the analysis.
6.2 Reconmendations
As the result of this technoeconomic appraisal of IGCC power generation,
the following recommendations are made to continue this type of analysis
and keep up-to-date in this rapidly evolving technology.
1. Because of the significant work which is currently being done to
evaluate IGCC systems, it would be desirable that the EPA follow-up
this current appraisal with periodic--perhaps annual--updates and
analyses to make sure that the latest and best information is included
in its planning activities. Significant work and significant current
sources which could be evaluated in the coming year include:
EPRI Coal Gasification Conference
- UCGA Site-Specific Studies
EPRI Site-Specific Studies
Continuing Operation of Cool Water.
6-3
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2. Because utility attitudes, perceptions, and requirements are of
paramount importance in determining the potential implementation of
IGCC, it would be desirable that more extensive discussions be held
with utilities regarding IGCC.
3. It is also desirable that the potential role of IGCC in repowering be
examined in detail. It appears that IGCC could be considered for this
application. However, site-specific conditions are particularly
important, and the UCGA site-specific studies to be published by EPRI
could be an important source of information regarding the repowering
potential of IGCC.
4. Since phased implementation is an important concept affecting the
potential employment of IGCC, it would be desirable to model phased
implementation and include it in EPA's AUSM.
6-4
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REFERENCES
1. Synthetic Fuels Associates, Inc., "Goal Gasification Systems: A Guide to
Status, Applications, and Economics," EPRI Report AP-3109, June 1983.
2. Bechtel Power Corporation et al. , "Cool Water Gasification Program: First
Annual Progress Report," EPRI Report AP-2487, July 1982.
3. Cool Water Coal Gasification Program et al. , "Cool Water Coal Gasification
Program: Fourth Annual Progress Report," EPRI Report AP-4832, October
1986.
4. Clark, Wayne N. and Vernon R. Shorter, "Cool Water: Mid-Term Performance
Assessment," Sixth Annual EPRI Coal Gasification Contractors' Conference,
Palo Alto, October 15-16, 1986.
5. Clark, Wayne N. , "Cool Water: Economically Competitive and
Environmentally Superior Electrical Power Production," Benelux Association
of Energy Economists' Symposium, the Hague, Netherlands, April 22, 1987.
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Program, to Malcolm Fraser, SAIC, August 7 and October 5, 1987.
7. Holt, N.A. , "Worldwide Gasification - An Overview", in Proceedings of the
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for Power Generation, San Francisco, April 14-18, 1985, Vol. 1, EPRI
Report AP-4257-SR, December 1985.
9. Rib, D. M. and D. R. Plumley, "Experience at Cool Water with General
Electric Combined-Cycle Equipment," Proceedings, Conference on Coal
Gasification Systems and Synthetic Fuels for Power Generation, San
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1985.
10. Personal communication, R. 0. Anderson, Combined-Cycle Technology Turbine
Projects Department, GE, to Isaac Kwarteng, SAIC, August 25, 1987.
11. Tomlinson, L. 0. et al. , "GE MS7001F Stag Combined-Cycle Power Plant,"
Proceedings of the American Power Conference, April 1987.
12. KVB, Inc., "Guidebook for the Use of Synfuels in Electric Utility
Combustion Systems," Vol. 2, Coal-Derived Gases, EPRI Report AP-3348,
January 1985.
13. Fluor Engineers, Inc., "Cost and Performance for Commercial Applications
of Texaco-Based Gasification-Combined-Gycle Plants," EPRI Report AP-3486,
Vols. 1 and 2, April 1984.
R-l
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REFERENCES (Continued)
14. Ralph M. Parsons Company, "Evaluation of the British Gas Corporation/
Lurgi Slagging Gasifier in Gasification-Combined-Cycle Power Generation,"
EPR1 Report AP-3980, March 1985.
15. Fluor Engineers, Inc., "Shell-Based Gasification-Combined-Cycle Power
Plant Evaluations," EPRI Report AP-3129, June 1983.
16. Simbeck, Dale R. and Frank E, Biasca, "Comparison of Alternative Fuel Gas
Sulfur Removal and Recovery Processes," Proceedings, Fifth Annual EPRI
Contractors' Conference on Coal Gasification, Palo Alto, October 30-31,
1985, EPRI Report AP-4680, July 1986.
17. Stanford University, "Radiation Heat Transfer in Coal Gasification
Systems," EPRI Report AP-4213, October 1985.
18. EPRI, "TAC™ - Technical Assessment Guide," EPRI Report No. P-658/-L,
Vol. 1., November 1989.
19. Alpert, S.B. and M.J. Gluckinan, in Annual Review of Energy-1986, Vol. 11,
pp. 315-355, Annual Reviews, Inc., Palo Alto, CA, 1986.
20. ARINC Research Corporation, "Availability Analysis of a Integrated
Gasification-Combined-Cycle," EPRI Report AP-52/6, June 198/.
21. Zaininger Engineering Company, inc., "Capacity Factors and Costs of
Electricity for Conventional Coal and Gasification-Combined-Cycle Power
Plants," EPRI Report AP-3551, June 1984.
22. Zaininger Engineering Company, Inc., "System Expansion Analysis: A
Comparison of Conventional. Coal and British Gas Corporation/Lurgi
Gasification-Combined-Cycle Power Plants," EPRI Report AP-4673, July 1986.
23. Snyder, William G. and Michael J. Gluckman, "Phased Implementation of Goal
Gasification-Combined-Cycle Power," Proceedings, Fifth Annual EPRI
Contractors' Conference on Coal Gasification, Palo Alto, October 30-31,
1985, EPRI Report AP-4680, July 1986.
24. Fluor Engineers, Inc., "Planning Data Book for Gasification-Combined-Cycle
Plants: Phased Capacity Additions," EPRI Report AP-4395, January 1986.
25. Spencer, Dwain F. and Peter H. Ben^.iger, "Coal Gasification Combined-Cycle
Power Plants: A Versatile Clean Coal Technology for the 1990's," Public
Utilities Fortnightly. July 24, 1986, pp. 16-23.
26. Minderman, David J. et al., "IGCC Site-Specific Evaluation Addressing
Generic Study Limitations," Proceedings, Fifth Annual EPRI Contractors'
Conference on Coal Gasification, Palo Alto, October 30-31, 1985, EPRI
Report AP-4680, July 1986.
R-2
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REFERENCES (Continued)
27. Utility Coal Gasification Association and EPRI, "Economics of Phased
Gasification Combined-Cycle Plants: Utility Results," EPRI Report No. AP-
5466-SR, November 1987.
28. Seherer, S. M. , "PEPCO's Early Planning for a Phased Coal Gasification
Combined-Cycle Plant," Proceedings, Conference on Coal Gasification
Systems and Synthetic Fuels for Power Generation, San Francisco, April 14-
18, 1985, Vol. 1, EPRI Report AP-4257-SR, December 1985.
R-3
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before compter'
1. REPORT NO. 2.
EPA- 600 / 7~ 90-017
3- PB90-272071
4. TITLE AND SUBTITLE
Technoeconomic Appraisal of Integrated Gasification
Combined-Cycle Power Generation
5. REPORT DATE
September 1990
6. PERFORMING ORGANIZATION CODE
7. AUTHOFUS)
Malcolm D. Praser
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Science Applications International Corporation
1710 Goodridge Drive
McLean, Virginia 22102
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-3893, Task 30; and
68-02-4397, Task 24
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final: 6/87 - 11/89
14. SPONSORING AGENCY CODE
EPA/600/13
15.supplementary notes _&EERL project officer is Julian W. Jones, Mail Drop 62, 919/541-
2489.
1®. abstract-phe report is a technoeconomic appraisal of the integrated (coal) gasifica-
tion combined-cycle (IGCC) system. Although not yet a proven commercial technol-
ogy' 1GCC is a future competitive technology to current pulverized-coal boilers
equipped with SC2 and NCx controls, because of its potential for increased thermal
efficiency and very low emission rates. However, its not yet being proven commer-
cially will influence its rate of market penetration and its possible impact on future
emissions. The first IGCC plant to supply electricity to a U.S. utility system has
been demonstrated at Southern California Edison's Cool Water Generating Station
near Earstow, CA, using Texaco's coal gasification process. This demonstration has
provided significant data for process improvements and has indicated the basic oper-
ability of combined chemical process/power generation technology. However, remai-
ning technical questions include: plant operation over an extended period with high-
sulfur eastern coal; operability of the Texaco gasifier at full throughput; materials
of construction; and plant availability/reliability. One advantage of IGCC systems
is their potential for phased construction of partial plant capacity to more closely
match the currently slow electricity demand growth. Simple comparisions indicate
similar electricity generation costs for IGCC and competing technologies.
17. KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. cosati Field/Gioup
Pollution
Coal Gasification
Boilers
Electric Power Generation
Gas Turbines
Pollution Control
Stationary Sources
13 H
13II
13 A
10 A
13 G
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
137
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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