EPA-650/2-74-041
May 1974
Environmental Protection Technology Series
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EPA-650/2-74-041
EFFECT OF GAS TURBINE EFFICIENCY
AND FUEL COST ON COST
OF PRODUCING ELECTRIC POWER
by
William H. Hedley
Monsanto Research Corporation
1515 Nicholas Road
Dayton, Ohio 45407
Contract No. 68-02-1320 (Task 2)
ROAP No. 21ADE-08
Program Element No. 1ABO13
EPA Task Officer: Gary J. Foley
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
May 1974
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This report has been reviewed by the Environmental Protection Agency
and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Agency,
nor does mention of trade names or commercial products constitute
endorsement or recommendation for use.
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TABLE OF CONTENTS
1. SUMMARY 1
2. INTRODUCTION 3
3. DESCRIPTION OF SYSTEM 5
4. COST DATA 7
5. COMMENTS ON COST DATA 17
6. RESEARCH NEEDS 23
7. COMMENTS ON THIS STUDY 29
REFERENCES 3!
ill
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SECTION 1
SUMMARY
Gas turbine efficiencies which will be needed to produce power
in a combined cycle gas turbine-steam turbine system (COGAS
system) at costs from 6 to 10 mils per kilowatt hour are tab-
ulated as a function of fuel cost from 40 to 100 cents per
million Btu. Improvements in gas turbine efficiency from 29
to 37 percent are envisioned over the next nine years, which
would result in combined cycle efficiencies from 42 to 5^
percent. The research improvements envisioned which would
improve the efficiency of the gas trubine are primarily those
which will increase the temperature at which the gas turbines
can operate. The level of effort needed to increase the oper-
ating temperatures at this rate is expected to be an additional
three to eight million dollars per year for research studies.
Combined with other work being done by the gas turbine manu-
facturers this effort could be expected to increase the turbine
inlet temperatures by an average of 90°P per year, which is
enough to increase gas turbine efficiency at the rate of almost
1$ per year.
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SECTION 2
INTRODUCTION
The purposes of this work are to present data on the costs of
fuel and of electric power produced by gas turbine systems as
a function of gas turbine efficiency. Since turbine efficiency
can be improved by developments which are currently envisioned,
it is also the purpose of this report to estimate the amount of
research effort and the elapsed time required to achieve various
levels of increased turbine efficiency.
An extensive study of the potential attractiveness of several
advanced power cycles for producing electric power was finished
in 1970 by United Aircraft Research Laboratories (ref. 1). In
these studies it was assumed that fossil fuels would be gasified
to produce a fuel with very low sulfur content which would then
be used with 1) conventional steam turbines, 2) gas turbines,
3) combined gas turbines and steam turbines, Jj) topping cycles,
such as a potassium system, 5) bottoming cycles, such as steam-
fluorocarbon systems, or 6) closed cycle gas turbine power systems
with inert gases, such as carbon dioxide or sulfur dioxide working
fluids, to produce power for electric utilities.
The most attractive systems of all were the combined gas turbine-
steam turbine power systems, which were referred to as combined
cycle or COGAS systems. Of five specific types of COGAS systems
evaluated, the waste heat recovery system was judged to be
superior to the exhaust fired system, the supercharged system,
the gas generator supercharged system, or the two pressure super-
charged system.
Robson, F. L., Giramonti, A. J., Lewis, G. P., and Gruber, G.,
"Technical and Economic Feasibility of Advanced Power Cycles
and Methods of Producing Non-Polluting Fuels for Utility Power
Stations," United Aircraft Research Laboratories, National Air
Pollution Control Administration, Contract CPA 822-69-llH,
Final Report, UARL Report J-970855-13, December 1970.
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SECTION 3
DESCRIPTION OF SYSTEM
The waste heat combined gas and steam turbine system (COGAS
system) consists of three subsystems; 1) a fuel gasification-
desulfurization subsystem, 2) a gas turbine subsystem, and
3) a steam turbine subsystem. The fuel gasification-desulfuriz-
ation system would consist of an air compressor, a gasifier, a
waste heat boiler, the desulfurization unit, and several heat
exchangers.
In these calculations it has been assumed that a low temperature
gasification process would be used, of the amine or potassium
carbonate type, and the gas fed to the gas turbine subsystem at
a temperature betweeen 100 and 230°F. Whether or not this heat
is supplied to the gas turbine system in the form of sensible
heat or as chemical energy makes no difference to the gas turbine
subsystem performance per million Btu's supplied since the
chemical energy will be converted to thermal energy as a part
of the gas turbine subsystem and the temperatures achievable
will be greater than the system is able to utilize.
The gas turbine subsystem will consist of the fuel burner, an
air compressor, power turbine, and electric generator. The
steam turbine subsystem will consist of a steam boiler, a
steam turbine, an electrical generator and condenser, and
pumps. A simplified diagram showing the gas turbine and steam
turbine subsystems is given in Figure 1 (ref. 2).
2. Giramonti, A. J., "Advanced Power Cycles for Connecticut
Electric Utility Station," UARL Report L-971090-2,
January 1972.
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FUEL
AIR
CT\
COMPRESSOR
STEAM
BOILER
TO STACK
BURNER
COMPRESSOR
TURBINE
POWER TURBINE
L_
PUMP
ELECTRIC GENERATOR
ELECTRIC GENERATOR
Figure 1. Gas Turbine, Steam Turbine Combined Cycle Power System
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SECTION 4
COST DATA
The electric power costs to be calculated In this study are bus
bar power costs in mils per kilowatt hour for COGAS systems.
These are to include all of the costs of electric power genera-
tion, but do not include any costs of ditribution. The bus bar
power cost can be thought of as consisting of three principal
factors; the fuel cost, the plant operating cost, and capital
charges. We are to assume various fuel costs for the gasified
desulfurized fuel as a parameter in this study.
These fuel costs are to include; the capital charges for the
gasification and desulfurization subsystem, the cost of fuel to
this subsystem, and the operating costs for it. Since these
factors are included in the fuel cost to the gas turbine and
steam turbine sybsystems, we need only to calculate fuel usage
and figures on the capital and operating costs of these two
subsystems in order to calculate the bus bar power cost.
The capital costs for the gas turbine and steam turbine sub-
systems include; the cost of the major equipment items, such
as the compressor, electric generator, and burner for the gas
turbine subsystem, and the steam boiler, steam turbine, electric
generator, and condenser for the steam turbine subsystem. They
also Include miscellaneous plant equipment and interest during
construction as well as land and buildings. Pieces of miscel-
laneous station equipment include; miscellaneous electrical
equipment, fuel tanks and fuel storage, fuel unloading and trans-
fer equipment, and wet-cooling towers, and were estimated to cost
10$ of the cost for land, buildings, and major Installed equip-
ment items. The interest during construction was assumed to be
10% of the total cost of these same items plus the cost of the
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miscellaneous plant equipment. A graph of capital cost for these
systems as a function of gas turbine efficiency is shown in '
Figure 2 (ref. 3)- The capital charges were figured as being
17% of the capital cost, and an 80$ on-stream factor was assumed.
The operating costs for these systems must cover the cost of
plant labor, maintenance, and supplies. These costs were esti-
mated as being 1.0 mil per kilowatt hour.
In order to calculate the fuel costs for these combined systems,
we must first relate the gas turbine efficiency to the overall
system efficiency for both the gas and steam turbines. Figure 3
shows a correlation between combined cycle efficiency and gas
turbine efficiency (ref. 3, 4).
To perform calculations for this report, we first selected a gas
turbine efficiency in the range of interest. Based upon present
state-of-the-art turbine technology, which allows use of gas
temperatures as hot as 1800°F, we can postulate gas turbine
efficiencies in the range of 29.5%. By 1976, if an aggressive
R&D program is followed, it appears possible that inlet tempera-
tures of 2200°F and gas turbine efficiencies of 32% are feasible.
By 1982 inlet temperatures of 2600°F and overall system effici-
encies of 37% for gas turbines seem feasible. Selecting specific
gas turbine efficiencies over this range, we then calculate the
capital cost for the system using Figure 2.
3. Robson, F. L., Chief, Utility Power Systems, United Aircraft
Research Laboratories, East Hartford, Connecticut, personal
communication, 13 August 13, 1973.
4. Giramonti, A. J., Senior Systems Engineer, United Aircraft
Research Laboratories, East Hartford, Connecticut, personal
communication, 13 August 1973.
8
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160
CO
O
O
a.
03
O
CD
o
>~,
o
"S
c
lo
E
o
O
140
130
120
1
1
1
30 32 34 36
Gas Turbine Efficiency, percent
38
Figure 2. Capital Cost of Gas Turbine and Steam Turbine
Subsystems as a Function of Gas Turbine Efficiency,
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40
35 40
Gas Turbine Efficiency, percent
45
50
Figure 3.
Combined Cycle Efficiency as a Function
of Gas Turbine Efficiency
10
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The capital charges in mils per kilowatt hour are then found by
multiplying the capital cost in dollars per kilowatt by 1000 mils
per dollar times fl ylo^hr times Q an times 17%. This yields a
factor of 0.02^26 for converting capital costs in dollars per
kilowatt to capital charges in mils per kilowatt hour. We then
add a constant factor of 1.0 mil per kilowatt hour for operating
cost .
The cost of fuel per kilowatt hour is found by multiplying the
cost of fuel in dollars per million Btu times 3,^13 Btu's per
kilowatt hour times 1 over the overall system efficiency times
1000 mils per dollar.
The overall system efficiencies are found by the use of Figure 3
By adding up these three components of cost we obtain a bus bar
power cost in mils per kilowatt hour. Calculations for gas
turbine efficiencies of 29, 31, 33, 35, and 37% are shown in
Table 1 as a function of the fuel cost in cents per million
Btu's.
The data in Table 1 were graphed in Figure 4 where power cost is
plotted against gas turbine efficiency with fuel cost in cents
per million Btu's plotted as a parameter. Using Figure 4 we are
then able to pick off specific values of gas turbine efficiency
which gives specified values of bus bar power cost in mils per
kilowatt hour at selected fuel costs in cents per million Btu's.
These figures are shown in Table 2. In cases where the present
gas turbine efficiency is more than sufficient to achieve the
bus bar power cost for that given fuel cost, an entry of <29% is
made in .Table 2 to indicate that this bus bar power cost is
achievable with present state-of-the-art units. In cases where
the bus bar power costs cannot be achieved for that specific
11
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Table 1
COST FACTORS FOR COGAS SYSTEMS AS
A FUNCTION OF GAS TURBINE EFFICIENCY
Gas Turbine Efficiency, %
Capital Cost, $M
Capital Charges, mils/KWH
Operating & Maintenance
Cost, mils/KWH
Combined Cycle Efficiency, %
Fuel Cost, mils/KWH
for fuel at:
40<|:/M Btu
50 " "
60 "
70 "
80 " "
90 " "
100 " "
Power Cost mils/KWH
for fuel at:
40
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CO
1-1
H
CO
O
o
PS
U
O
13
12
11
10
9
8
7
6
100
90
80
70
60
50
FUEL COST
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Table 2
GAS TURBINE EFFICIENCIES TO YIELD VARIOUS
BUS BAR POWER COSTS AS A FUNCTION OF FUEL COST
Bus
6
HO
50
Fuel Cost 60
37
>37
>37
>37
>37
>37
>37
Bar
7
34.
>37
>37
>37
>37
>37
>37
Power Cost,
8
0 29.5
34.7
36.5
>37
>37
>37
>37
Mils/KWH
2
<29 <
29.1 <
31.3 <
34.3
>37
>37
>37 >
10_
29
29
29
30.4
33.0
36.2
37
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fuel cost, by any gas turbine efficiency presently planned
(above 37/O, >37% is inserted in that space to indicate this.
As we can see from this table, the combined cycle does not offer
any realistic hope of achieving bus bar power as low as 6 mils
per kilowatt hour, even at very low fuel costs. However, bus
bar power costs in the range of 7 to 10 mils per kilowatt hour
are definitely achievable using these systems.
15
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SECTION 5
COMMENTS ON COST DATA
Since cost estimates are usually sensitive to the basic assump-
tions made, an effort has been made to check some of the
assumptions which will significantly affect the costs calculated
in the previous section. The factors checked include present
system efficiency, reasonableness of inlet temperatures, capital
costs, capital charges, interest during construction, and opera-
ting costs. This section also defines the items that are
assumed to be in the fuel system and hence are considered to
be included in the fuel cost.
A certain amount of checking of the basic assumptions made in
the United Aircraft calculations was done by consulting with
Mr. Robert L. North, plant superintendent of the South Meadow
Station of Hartford Electric Light Company (ref. 5) and
Mr. Howard Keyton, chief mechanical engineer of the Dayton
Power and Light Company (ref. 6). Mr. North has a 13 megawatt
prototype, two 22 megawatt units, and four 49 megawatt units
of the gas turbine type. These systems are not coupled with
steam turbines, but are used independently, primarily for
topping power and for emergency operations. Mr. North was
present during a test run when a unit was performance tested
for acceptance at a rating of 36.5 megawatts. The fuel usage
during this test run was 12,370 Btu's per kilowatt hour which
gives an overall efficiency of 27.6??. This efficiency is rather
close to the 29-5£ figure suggested by United Aircraft as being
the state of the art for l800°P inlet temperatures.
North, L., Plant Superintendent, South Meadow Station, Hartford
Electric Light Company, Hartford, Connectlcult, personal commun-
ication, 13 August 1973.
Keyton, H., Chief Mechanical Engineer, Dayton Power & Light Co.,
Dayton, Ohio, personal communication, 15 August 1973.
17
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That the gas turbine efficiency would increase from 29.5% to 32%
to 37% as the gas turbine inlet temperatures increase from l800°F
to 2200°P to 2600°P seems reasonable. Based upon turbine exit
gas temperatures of 1100°F) the Carnot efficiencies for inlet
temperatures of 1800, 2200, and 2600°F are 31.0, 41.6, and 1*9.0%
respectively. The Carnot efficiency, therefore, is increasing
even more rapidly than the predicted gas turbine efficiencies.
The capital costs expected for COGAS systems in the 200 to 260
megawatt range have been evaluated extensively by Dayton Power
& Light Company. According to Mr. Howard Keyton, their evalua-
tion of five systems from three different manufacturers showed
that the capital cost in this size range varied from $160 to
$180 per kilowatt (1976 dollars) and that the heating rate for
these units ranged from 8100 to 8800 Btu's per kilowatt. The
figure of $161 per kilowatt for the present state-of-the-art
COGAS system quoted earlier obviously falls in this range. The
heating rate of 8100 Btu's per kilowatt corresponds to an overall
system efficiency of 42.1/2, which compares quite closely with the
41.4% predicted for a 29-5$ gas turbine efficiency as shown in
Figure 2. Since this study was completed by Dayton Power &
Light only recently, it was concluded that the figures on overall
system efficiency and on capital cost represent the state-of the-
art in the gas turbine industry rather well.
When asked about the percentage used to allow for amortization
of the capital costs, Mr. Keyton said that a factor of 17.15$
reflects Dayton Power & Light's recent experience. This factor
allows for depreciation, interest, and taxes, and compares very
well with the 17$ used in the calculations in this report. .
18
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Dayton Power & Light has recently spent 7-7 million dollars in
interest on an 81.5 million dollar installation, and they have
estimated that they would spend 10.4 million dollars in interest
on a 111 million dollar installation which is contemplated.
These factors worked out to an interest payment of S.^%. Consid-
ering the rising interest rate, IQ% has been used in these
calculations.
The most controversial item in the cost estimate is the 1.0 mil
per kilowatt allowance for operation and maintenance. According
to Mr. Keyton, the labor to operate gas turbines is virtually
non-existent since they can be started remotely by pushing a
button and need only very cursory surveillance while operating.
The major cost for gas turbines to date has been in maintenance.
At Dayton Power and Light maintenance costs for gas turbines
have averaged 3-6 mils per kilowatt for one type of unit, and
1.3 mils per kilowatt for another which has yet to have its first
major overhaul. Another utility, in New York state, experienced
a maintenance cost for gas turbines ranging from 3 to 5 mils per
kilowatt.
Mr. North stated that the maintenance cost on their gas turbines
was initially only 0.52 mil per kilowatt hour, when they were
running at 1800°P. This figure, however, rose considerably as
temperatures were boosted to 1900°F to get increased power from
the turbines. This gives credibility that l800°P is truly
achievable today, but this is very near the limit of the capa-
bility of existing gas turbines. Mr. North also stated that
these turbines had an availability of 99-3$ and that they had a
start-up reliability of 93.15? over a period of 7,831 start-ups.
The reasons for high maintenance costs for gas turbines are
1) the units have not been designed with minimum maintenance
cost in mind, 2) the units have been pushed fairly hard in many
19
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cases, stretching the maximum use temperatures and increasing the
wear on them, and 3) the fuels used often do not meet the manu-
facturer's specifications. Clean fuels with a minimum of partic-
ulate inclusion are definitely recommended for gas turbines, yet
they are occasionally fed fuels containing particulates or corro-
sive materials such as salt water. The manufacturers are making
strenuous efforts to design the next generation of gas turbines
so that they will have markedly less maintenance requirements,
and hopefully the overall combined system maintenance cost can
be kept down near 1 mil per kilowatt.
According to Mr. Keyton, the figures on maintenance cost for six
different installations of steam turbines varied from 0.6 to
1.0 mil per kilowatt, with the newer units having the lower
figure. Since the maintenance costs for the steam turbine sub-
system will be averaged in with those for the gas turbine sub-
system, the latter could run over 1.0 mil/KWH and still have
this figure as an average for the combined cycle plant. Based
upon Mr. North's experience and the probable improvement in
system reliability expected with further design modifications
by the manufacturers, I have decided to accept 1.0 mil/KWH as
reasonable.
The numbers given in the previous section have been generated
from previous studies at United Aircraft Research Laboratories
which were not specifically oriented along the objectives of
this task. The numbers in this report have been pulled together
from previous studies and are logically consistent within them-
selves, but are not comparable with other turbine efficiency
numbers from other sources, unless exactly the same basic
assumptipns are used. For instance, higher gas turbine effi-
ciencies can be obtained for a given inlet temperature if one
wishes to maximize the gas turbine efficiency rather than
maximize the overall combined cycle power plant efficiency.
20
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Another major simplification made in this study is that many
of the design criteria and cost factors were held constant
during these studies to simplify them. In more exhaustive
accurate calculations, one would optimize the COGAS system
over a range of conditions for each inlet turbine temperature
and fuel cost combination. This was not done in this case.
In practice, when the COGAS systems are designed, the gasifica-
tion system is thoroughly integrated with the gas turbine and
steam turbine subsystems. As a result of this integration, it
is not always easy to determine exactly which pieces of equip-
ment and what system power costs should be charged against the
gasification and desulfurization system, and which ones should
be charged against the two power-producing subsystems. In this
study we have assumed that the capital and operating costs of
the air compressor to supply air for the gasification system
would be charged to the fuel cost.
Since the capital cost of this compressor is $20 to $25 per kilowatt,
and its power consumption is likely to be 6 to S% of the total
power station power output, this is a highly significant cost item
and it is important that its effect be included in the cost of
fuel in cents per million Btu's. There are additional heat ex-
changers for fuels over and above the waste heat boiler, which
are also included in the fuel cost. Also, due to the incremental
cost for flow of steam from the gasification process, one should
add additional costs for the superheater steam turbine generator
set, condenser, and deaerator of the steam turbine subsystem to
the fuel cost. This additional capacity in this subsystem could
add as much as $30 per kilowatt to its capital cost.
21
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SECTION 6
RESEARCH NEEDS
It is apparent from examining the figures in Figure 3 that con-
siderable gains in an overall system efficiency are possible if
higher inlet turbine temperatures could be utilized in gas
turbines. Unfortunately, much of the technology which in the
past has been used as a basis for developing higher operating
temperatures for gas turbines has come out of military and
aerospace R&D programs, which now have been drastically cut
back. The key areas which need further development are either
better materials or better cooling methods in order to achieve
the higher temperatures while retaining the necessary "creep"
resistance and corrosion resistance to keep the turbine working
effectively.
Over the past decade, the rate of rise of inlet turbine tempera-
tures which have been utilized has risen at a nearly linear rate
of approximately 70°F per year. This is shown in Figure 5
(ref. 2). In order to sustain and even slightly increase this
rate of increase to 90°F per year, it will require an investment
of three to five million dollars per year of of seed money from
some governmental source. Since this is not forthcoming from
the Department of Defense or NASA, another source is needed.
This fund of three to five million dollars per year, it should
be noted, should be spent with one prime contractor and should
be spent over a period of several years to insure that the work
started is actually brought to an effective fruition. This
program should start at the lower level of funding and increase
to the five million dollar figure. Since it takes four years
for a gas turbine to be developed after the research on which
23
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3600
INDUSTRIAL APPLICATIONS
1990
Figure 5. Progression of Estimated Gas Turbine Inlet Temperatures
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it is based is available, reaching the goal of 2600°F, which is
scheduled for 1982, would require that this investment start now
and continue until the year 1978. This research program would
include work both on cooling methods, and on new materials, such
as ceramics having higher temperature capabilities.
The efficiency of a gas turbine is directly related to the
inlet temperature of the turbine section. To insure long life-
times, metal temperatures of rotating components should be kept
to 1500°P or lower. Current techniques use high-pressure air
bled from the compressor to cool the turbine blades. Such
techniques allow temperatures of over 2200°F to be attained,
but higher temperatures could require air flows beyond the
capability of available bleed flows, i.e. the performance
benefits of bleed flow cooling are outweighed by the perfor-
mance degradation due to the high flow of bleed air which is
unavailable to do work.
The use of water to cool the blades would not cause performance
degradation and could actually contribute some work. There are
several alternative methods of water cooling available and the
merits of these systems should be evaluated.
As an alternative to various cooling techniques to keep material
temperature to 1500°F, ceramics operating at temperatures of
2000°F+ could result in higher turbine operating conditions
without associated cooling penalties. Ceramics could be used
in burners, seals, nozzles, and eventually blades. Currently,
several research programs are being carried out in this area,
but applications may be difficult to implement in larger size
gas turbines.
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In addition to these studies on directly finding ways to increase
the operating temperatures, tests also ought to be run on the
utilization of low Btu fuel in gas turbines. Analytical studies
should identify any additional hardware problems which will need
work to implement the use of this low Btu gas at the higher tem-
peratures in gas turbines.
Although preliminary rig-type tests have been made on the com-
bustion of fuel gases varying from 100 to 140 Btu/scf, much
remains to be done before such combustion systems can be commer-
cially realized. A series of analytical and experimental tests
on high pressure combustion rigs, and on the formation of NOx
from combusting low-Btu gas, needs to be carried out. Burner
can modifications must be identified and suitably redesigned
cans should be fabricated and run on a full-scale engine.
A series of analytical studies of advanced power cycle concepts
should be carried out with the objective of identifying specific
hardware development programs. Such studies could be extensions
of current EPA-sponsored efforts or could be in new areas. For
example, a current EPA-sponsored study deals with integrating
coal gasifiers, low- and high-temperature cleanup processes,
and combined-cycle systems. Part of this study is devoted to
identifying the areas of technology needing exploration in
order to realize the advantages of the integrated system. There
will be a need to further analyze the various technology areas
identified in order to define actual programs needed to bring
the required areas to commercial realization.
The study on the use of low Btu fuel would require an expendi-
ture of .two million dollars over a two to three year period.
The analytical study to identify further problems would be a
two or four man year study costing on the order of $100,000
to $200,000 over a one year period.
26
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The above comments on research needs were suggested by Dr. Robson
and Mr. Giramonti of United Aircraft (ref. 3, 4). These recommen-
dations were reviewed with a representative of General Electric
Company, Mr. Donald R. Plumley (ref. 7). Mr. Plumley basically
agreed rather closely with the United Aircraft suggestions. He
suggested that the present state-of-the-art temperature can be
throught of as being approximately l850°P, and that gas turbine
efficiencies of 31% and temperatures of 2600°F are definitely
reasonable goals for ultimate achievement at the end of the
decade.
The programs to develop water cooling of turbine blades and inves-
tigate the use of ceramics were heartily endorsed by Mr. Plumley.
He did suggest, however, that the amounts of money to be invested
in them might well need to be in the four to eight million dollar
range per year. Mr. Plumley suggested that some work could be
included on finding metals with creep and corrosion resistance
adequate for turbine usage above 1500°F, although the improve-
ments in these materials might be small compared to the effect
of finding ceramics which would operate at 2600°F. He also
suggested that work might profitably be done on finding ways
to increase the pressure ratio since gas turbines operating at
higher temperatures have a tendency to be more efficient if
higher pressures are also used.
Mr. Plumley pointed out that this program did not include any
studies on fabrication technology for these materials at higher
temperatures. This is an additional area in which monies could
be profitably expended, although there is a tendency for all of
the manufacturers to do their own work in this area. Develop-
ment work of this type tends to be expensive,- however, and more
monies could be profitably spent in the development of gas
turbines by funding fabrication studies.
7. Plumley, D.R., Manager, Operations Planning, Gas Turbines
Products Division, General Electric Co., Schenectady, N.Y.
personal communication, 17 August 1973.
27
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Mr. Plumley reported that studies on combustion of low Btu fuel
gases and analytical studies on integration of the subsystems
in the COGAS system are currently being made by his company and
also by Westinghouse, and government programs funded at this
time in these areas would therefore probably be too late as far
as they were concerned.
In general Mr. Plumley agreed that the principal research areas
suggested by Dr. Robson and Mr. Giramonti were the ones which
needed work, that government funding would be necessary to bring
about the improved efficiencies they envision as possible, and
that the amounts of money to be spent should be several million
dollars per year for several years to have a high probability
of reaching gas turbine efficiencies of 37% within 10 years.
28
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SECTION 7
COMMENTS ON THIS STUDY
The above analysis of research needs has focused only on the
gas turbine subsystem. Since the steam turbine subsystem has
already been developed very well, no further research is needed
in this area. The same is not true, however, of the gasifica-
tion and desulfurization systems. Investment in sizable research
programs to advance gas turbine subsystem technology to higher
efficiencies has some desirability even without coal gasifica-
tion desulfurization systems, in that the higher efficiency of
the combined cycles would reduce the amount of fuel burned per
kilowatt hour produced by as much as one-third, hence reducing
pollution produced. However, to get pollution levels down to
those desired in the EPA standards, it would be necessary also
to continue to push coal gasification and desulfurization sys-
tems which could work with these gas turbine systems. The
cost of these continuing developments in coal gasification and
desulfurization will probably be much greater than that needed
for research on gas'turbine efficiency improvement.
The task order for this work suggested a range of fuel costs
from 30 to 70 cents per million Btu's. Discussions with
Dr. Paul Spaite indicated that gasified desulfurized fuels
would probably be more expensive than this (ref. 8), so we
increased the range of fuel costs to *iO to 100 cents/106 Btu
for this study. When these systems are finally developed
however, there is no guarantee that fuel costs will not exceed
one dollar per million Btu's. Calculations could be made for
higher fuel costs if so desired, based on the. methods used in
this report.
8. Spaite, P., Consultant to EPA, Cincinnati, Ohio, personal
communication, 6 August 1973.
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Finally, it should be repeated that the figures in this study
are based upon many assumptions. These assumptions have been
checked as well as possible within the limited time available,
and they seem reasonable. These calculations, however, have
not been optimized for each individual condition, hence these
costs should not be used for detailed comparisons with other
cost figures on similar systems.
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REFERENCES
1. Robson, P. L., Giramonti, A. J., Lewis, G. P., and Gruber, G.,
"Technical and Economic Feasibility of Advanced Power Cycles
and Methods of Producing Non-Polluting Fuels for Utility
Power Stations," United Aircraft Research Laboratories,
National Air Pollution Control Administration, Contract
CPA 822-69-114, Final Report, UARL Report J-970855-13,
December 1970.
2. Giramonti, A. J., "Advanced Power Cycles for Connecticut
Electric Utility Station," UARL Report L-971090-2,
January 1972.
3- Robson, F. L., Chief, Utility Power Systems, United Aircraft
Research Laboratories, East Hartford, Connecticut, personal
communication, 13 August 13, 1973.
4. Giramonti, A. J., Senior Systems Engineer, United Aircraft
Research Laboratories, East Hartford, Connecticut, personal
communication, 13 August 1973.
5. North R. L., Plant Superintendent, South Meadow Station,
Hartford Electric Light Company, Hartford, Connecticut,
personal communication, 13 August 1973.
6. Keyton, H., Chief Mechanical Engineer, Dayton Power and
Light Company, Dayton, Ohio, personal communication,
15 August 1973.
7. Plumley, D. R., Manager, Operations Planning, Gas Turbines
Products Division, General Electric Co., Schenectady,
New York, personal communication, 17 August 17, 1973.
8. Spaite, P., Consultant to EPA, Cincinnati, Ohio, personal
communication, 6 August 1973.
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TECHNICAL REPORT DATA
(Please rrail liiuructions on the reverse before completing)
I. REPORT NO.
EPA-650/2-74-041
2.
I. RECIPIENT'S ACCESSION-NO.
;. TITLE ANOSUBTITLE
Effect of Gas Turbine Efficiency and Fuel Cost on
Cost of Producing Electric Power
5. REPORT DATE
May IS 74
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
William H. Hedley
8. PERFORMING ORGANIZATION REPORT NO.
MRC-DA-434
I. PERFORMING ORGANIZATION NAME AND ADDRESS
Monsanto Research Corporation
1515 Nicholas Road
Dayton, Ohio 45407
10. PROGRAM ELEMENT NO.
1AB013; ROAP 21ADE-08
11. CONTRACT/GRANT NO.
68-02-1320 (Task 2)
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
NERC-RTP, Control Systems Laboratory
Research Triangle Park, N. C. 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; Through 8/17/73
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
The report gives results of a study of the effect of gas turbine efficiency and
fuel cost on the cost of producing electric power. It indicates that combining gas and
steam turbines (COGAS systems) can increase overall power generation efficiency.
It tabulates gas turbine efficiencies which must be achieved to produce power at costs
of 6-10 mills per kWh, as a function of fuel costs of 40-100 cents per million Btu.
Improved gas turbine efficiency of 29-37 percent is seen over the next 9 years,
resulting in combined cycle efficiencies of 42-54 percent. Improved research
envisioned, which would improve gas turbine efficiency, is primarily that which will
increase gas turbine operating temperature. The level of effort needed to increase
operating temperatures at this rate is expected to be an additional $3-8 million per
year for research. Combined with other work by gas turbine manufacturers , this
effort could be expected to increase turbine inlet temperatures by an average of
90°F per year, which is enough to increase gas turbine efficiency at the rate of
almost 1 percent per year.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Gas Turbine Power
Generation
Gas Turbines
Temperature
Steam Turbines
Steam Electric
Power Generation
Electric Power
Generation
Cost Effectiveness
Air Pollution Control
Stationary Sources
Gas Turbine Temperatur
Combined Cycle
COGAS Systems
Fuel Costs
13B
10A
13G
14A
3. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (Thit Report)
Unclassified
21. NO. OF PAGES
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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