United States
Environmental Protection
Agency
Air and Energy Engineering
Research Laboratory
Research Triangle Park NC 27711
Research and Development
EPA/600/S7-90/017 Dec. 1990
&EPA Project Summary
Technoeconomic Appraisal of
Integrated Gasification
Combined-Cycle Power
Generation
Malcolm D. Fraser
A future competitive technology to
current pulverized-coal boilers
equipped with SO2 and NOX controls
is the integrated (coal) gasification
combined-cycle (IGCC) system,
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
(EPRI), 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, CA,
using Texaco's 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
IGCC systems, appear to be Texaco,
Dow, British Gas Corporation
(BGC)/Lurgi, and Shell. 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 comparisons
using generic cost and performance
data indicate similar electricity
generation costs for IGCC and
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.
This Project Summary was
developed by EPA's Air and Energy
Engineering Research Laboratory,
Research Triangle Park, NC, to
announce key findings of the research
project that is fully documented in a
separate report of the same title (see
Project Report ordering information at
back).
Background
Projections into the next century of
sulfur dioxide (SO2) and nitrogen oxide
(NOx) 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;
Printed on Recycled Paper
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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., Iow-N0x burners and flue gas
desulfurization (FGD)] is integrated (coal)
gasification combined-cycle (IGCC)
systems because of their potential for
increased thermal efficiency and very low
SO2 and NOX 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 authorized an
independent technical and economic
assessment of IGCC systems.
This study involved three tasks
corresponding to three main objectives:
(1) technical evaluation of IGCC
technologies and systems. (2) developing
cost and performance estimates and
comparing IGCC with competing coal-
burning technologies, and (3) evaluating
the potential future market for IGCC
application to new power generating
plants.
In an IGCC plant, coal is fed to a
gasifier, where it reacts with steam and
oxygen to 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 1090+°C
combustion turbine. The hot flue gas
(480-540°C) 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 doing so 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 Texaco's coal
gasification technology.
Cool Water Demonstration
IGCC Plant
The Cool Water Gasification Program
is an undertaking of a number of private
entities, led by EPRI, to design,
construct, and operate the nation's first
IGCC power plant to supply electricity to
a utility system. The demonstration plant,
consisting of commercial-scale
components and subsystems, is at the
Cool Water Generating Station of
Southern California Edison Company
(SCE) near Barstow, CA, 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 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 103
kg) of coal per day to a imedium-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 wt. %
sulfur. The program has also tested
Illinois No. 6 coal, containing 3.1 wt. %
sulfur, and Pittsburgh No. 8 coal,
containing 2.8 wt. % sulfur.
Gasifier performance at the Cool Water
plant has been better them originally
expected. Single-pass carbon
conversions have been greater than 98
wt. % 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% 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 to account for
differences in equipment and conditions
to coincide with an estimated 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 1
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.
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 (NSPS) are shown in Table 2.
The Cool Water plant's SO2 emissions
are typically 10 to 20% of the "allowable
levels under EPA's NSPS for coal-fired
power plants with stack-gas scrubbers.
Sulfur removal from the synthetic gas
(syngas) has ranged from 97 to 99%.
Overall sulfur recovery from the feed coal
is typically 97%. Stack emissions of NOX
and particulates have also averaged
about 10% of allowable levels under the
NSPS. NOX emissions are controlled by
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 hot
spot that developed there. The hot spot
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.
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Table 1. Adjustment of Copi Water Heat Rate and Comparison with Estimate for a Commercial Plant
- - .....;.""; i-iy ';-;;.' ;.-<- tef :-.£;;:: « '-' -; ?^fa/fl %0fW
:".".'"''.'.- ""'.:'- '.'.:."':.'- ..vJ":'.\"'.'" ;i.pi"%--'::r.J7-""""-.-:
-" -- -- - ' - '- "-' -'-, .-»- - '"" ""' - - --- '
- ."..'r .-.:--- -:': --:-^: -.-'-''"'.''-' _" I;!;";;;.-.''" -."r'r.r.
Cool Water Design Heat Rate , -"-.- ';-.-.-"; :;' : .1 ,.':;:.
Correction for Reheat Steam Cycle 1 ,:. .^ --.;.., ;--,,-;
(Cool Water uses' non-reheat steam cycle with lower steam" temperature
compared to commercial design.) ;
Correction for Slurry Concentration
CCoo/ IVater uses 60% coa/ s/ony feed versus 66.5% for commercial
design) -- -' - -: ,....:,. ... . ... , , ;,,-. .,..-:,
Correction for ISO* Ambient Conditions for Gas Turbine
(Cool Water heat rate is evaluated at27"C versus J5°C ambient as a
standard condition.) , '
Corrections for Oxygen Purity, Saturator, 1105" C Gas Turbine
(Cool Water uses higher-pressure, purer oxygen than is necessary and
a 1085" C turbine.) .'...:,. ; ,
Correction for Plant Size .'
(Scaling up Coot Water to a commercial size would reduce plant
auxiliary loads as a fraction of gross power generation.)
Correction for 1260°C Gas Turbine
hM'kWh) ,^_;^
fieajt Rate ''Adjustment
- -~ - :. ;.--. -,: --
,,,:.'.. ..;'j ir ?!;!-.;-;
-,::,38p(401)
, ' ----- - -
-300' (31 6)' '-
230(243)
601 (634)
356(376)
486(513) -
* International Standards Organization. : : \...'
Table 2. Heat Recovery Steam Generator (HRSG) Stack Emissions from the Cool Water Plant
Datainlb/l06Btu(kg/GJ)
' ' SUFCO9 1985
Permit Limit3 EPA Test 111. No. 6 EPA Test
SO2 O.r6(0.68>
(HighS)°
SO2 0.33 (0.14) 0.018 (0.008)
(LowS)<= . - ,
NOX 6.13(0.056) 0.07(0.030)
CO 0.07(0.030) 0.004(0.002)
Particulates - 0.0-1 (6.004) 0.001 (<0.001)
0.068 (0.029)
0.004 (0.002)
0.004(0.002)
0.009(0.004)
it. -* - * rt'H ,,, -.
ZPRiAdiustedCool1
-Water Heat Rate
i-:i 1,363 (11, 986)
-'. " : ::!".:. :. . .. .?. ... ' . .
: -.:.:.'.': :,.;. /.
9,852 (1 0,392)
9,496(10,016)
9,010(9,504)
"' Pitts. No. 8
Source Test
0.122 (0.052)
0.066 (0.028)
<0.002 (<0.001)
0.009(0.004)
; Estimated
Commercial Plant
Heat Rate
9,490(10,000)
9,009 (9,503)
Federal NSPS"
0.6<*C0.257)
0.240(0.103)
0.6(1(0.257)
NSf
0.03 (0.013)
a Emission limits from EPA permit (based on design estimates of plant emissions).
>New Source Performarice Standards for a coal-fired power plant burning equivalent coal as Cool Water.
0 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.
d Emissions controlled to 0.6 Ib/TO6 Btu.
e0.8 lb/106 Btu uncontrolled emissions x 0.03 for controlled emissions. :
* NS: no standard. ;
s Southern Utah Fuels Co.
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.
The costs of the Cool Water Project-
capital, operating, and maintenance
costs have been collected and
assessed by the program, and economic
evaluations continue. The Cool Water
plant is a demonstration project of
commercial-scale components for only 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, 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% 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:
Operability of the Texaco gasifier at full
throughput.
Materials of construction.
Plant operation over an extended
period of time 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.
Gasification Systems
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 that illustrate the
merits of each technology arid its recent
status of development. In addition, a
comprehensive evaluation and
comparison of coal gasification
technologies is available in the relatively
recent literature.
The most important gasification
technologies (based on their state of
development), in terms of their near- or
mid-term potential application to IGCC
systems, appear to be Texaco, Dow,
British Gas Corporation/Lurgi, and Shell.
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 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) Model MS7001F gas turbine has an
operating temperature of 1260°C. This
model recently replaced Model
MS7001E, which operated at 1095°C.
This new turbine incorporates the latest
technology in the compressor,
combustion system, and turbine designs.
The only emissions currently controlled
with the Federal 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. 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.
Environmental Characteristics
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 generating
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, compared to the costs of
sulfur removal from coal gases. 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.
IGCC designs all have excellent
environmental characteristics compared
to other power generation systems, in
terms of S02, NOX, and 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
-------
Table 3. Status of Second-Generation Gasification Technologies for IGCC Systems
Process Type Operating Units
Date of Operation
Texaco
Dow
BGC/Lurgi - Slagging
Shell
Entrained Flow Cool Water; 2 x WOO-TPD<> Coal: 117-MWe IGCC
UBE, Japan; 4 x 500-TPD
. .-_. , Tennessee Eastman; 2 x 900-TPD
fluhrchemie, Germany; 1 x 800-TPD
Entrained Flow 160-MWe IGCC at Plaquemine, LA
2 x 2400-TPD Gasifiers
Fixed Bed 600-TPD Unit at Westfield, Scotland
Entrained Flow 250-TPD Pilot Plant in Texas
1984
1984
1983
1986
1987
1986
1987
1 TPD = 907 kg/day.
major systems being developed (Texaco,
BGC/Lurgi, and Shell). 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.
Performance estimates and costs
adjusted to January 1987 dollars are
shown in Table 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.
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 COEs
calculated by EPRI are consistently lower
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 to be 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 to 250 MW), 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. 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 value of
capital expenditures for an unphased
plant. In a recent study, the net present
value of capital expenditures was
calculated for each of three load growth
scenarios (5, 7, and 10 years) for adding
the capacity of one unphased IGCC plant.
Savings due to phased capacity addition
ranged between about $200 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. 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.
Six of these 'studies included IGCC and
'conventional PC plants among the
alternatives considered, and five of the
six found phased IGCC to be more
attractive economically than conventional
PC plants. Three of the five found even
unphased IGGC to be .more attractive; the
other two did not make this comparison.
The sixth-study concluded that PC was
more attractive; than unphased IGCC.
Site-specific arid 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.
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
EPA's Advanced Utility Simulation Model
(AUSM). According to these projections,
made with EPA's 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. .',,
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Table 4. Summary of Comparative Costs and Performance Estimates for PC and IGCC plants :
Capacity500 MWe; Illinois #6 Coal; Constant January 1987 Dollars
*.-..'
Reference Coal-Fired,
Steam Plant
Sulfur Removal, %
NOX Emission, pprnv*
Heat Rate. BtulMJh>>
Total Capital, $lkWc
Levellzed Cost of Electricity at 65% capacity
factor, millslkWh
90
150
, 9,850
1,390
54.9
Texaco Partial Shell Coal
Oxidation Gasification Process
95-97
50-75
9,010
1,540
52.7 '
90-99
50-75
8,720
1,490
50.8
,_ -IL
BGC/Lurgi Slagging
Gasifier
95-97
50-75 '"-
8,660
1,300
48.9
* 15% Excess O2, Heat Rate Corrected; 1260°C Combustion Turbine for IGCC Plants.
»1 BtufkWH - 1.055 kJ/kWh.
"Includes working capital, start-up costs, spare parts, land, royalties, and allowance for funds used during construction (AFUDCall IGCC plants
rated at 31°C.
The potential application of IGCC
systems in this future power generation
market will be influenced by a variety of
factors, the most important of which 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 technblogies
such as atmospheric iluid^bed
combustion (AFBC).
Conclusions
The following conclusions were
reached as a result of this study:
1. IGCC designs all have excellent
environmental characteristics
compared to other power
generation systems, in terms of
SOa, NOX, 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.
I
3. The Cool Water plant, a Texaco-
based system, is apparently a very
successful near-commercial-scale
demonstration for 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
Texacp-based IGCC technology in
a significant way, such as:
Operability of the Texaco gasifier
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.
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 slightly lower
levelized costs under a limited
range of assumptions.
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Recommendations
This technoeconomic appraisal of
IGCC power generation led to the
following recommendations:
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.
3. It is also desirable that the potential
role of IGCC in repowering be
examined in detail. However, site-
specific conditions are particularly
important, and studies being
conducted by EPRI could be an
important future 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 incorporate
phased implementation into EPA
utility models.
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M. Fraser is with Science Applications International Corporation, McLean, VA
22102.
Julian W. Jones is the EPA Project Officer (see below).
The complete report, entitled "Technoeconomic Appraisal of Integrated
Gasification Combined-Cycle Power Generation," (Order No. PB 90-272
071 IAS; Cost: $23.00, subject to change) will be available only from:
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at:
Air and Energy Engineering Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
United States
Environmental Protection
Agency
Center for Environmental Research
Information
Cincinnati OH 45268
BULK RATE
POSTAGE & FEES PAID
EPA
PERMIT No. G-35
Official Business
Penalty for Private Use $300
EPA/600/S7-90/017
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