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NASA Techskd Memorandum 82729 

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Performance and Op^ational Econcmiics 
Estimates for a Coal Gasification Combined- 
Cycle Cogeneration Powerplant 

Josq^ J. Naiiugar, Raymond K. Bums, and Annie J. Eadey 
Lewis Research OMer 
Ckvdand^ Ohio 




Joseph J. Nainiger, Raynond R. Burns, and Annie J. Easley 

National Aeronautics and Space Administration 
Lewis Research Center 
Cleveland, Ohio 


Performance and operating cost estimates were made for an integrated- 
gasifier, combined-cycle (IGCC) system assumed to be applied at the NASA Lewis 
Research Center to meet the steam and baseload electrical requirements. 

Because of the type of advanced-technology work being done at Lewis, such an 
IGCC cogeneration system could serve as a test bed for advanced-technology 
components in addition to meeting a large part of the Lewis energy require- 
ments* Lewis electrical loads vary significantly during a typical %ieek. 

The loads range from a minimum of approximately 5 NW during ireekends or non- 
workdays to a maximum of over 200 MU during the week when major facilities are 
in operation. The steam heating requirements vary from a summer base of 
2.27 kg/sec (18 000 Ib/hr) to over 12*6 kg/sec (100 000 Ib/hr) during the 
winter. IGCC systems with maximum electric power outputs of 20, 25, and 30 MW 
were analysed. These systems could supply the baseload electrical requirement 
of about 10 NW and, by extraction steam from the bottoming steam turbine, 
could supply all or most of the steam requirements throughout the year. The 
amounts and timing of additional electricity purchases from the utility and 
sales of excess electricity to the utility were determined. The resulting 
expenses for electricity purchases and revenue from electricity sales were 

then estimated by using an assumed electric utility rate structure model based 
on electricity rates approved by the Public Utilities Commission of Ohio 
(PUCO). The cogeneration system performance and operational economic results 
for these IGCC systems were compared with the fuel consumption and annual costs 
of purchased electricity and naf ^ral gas at Lewis without cogeneration. The 
sensitivity of the results to ''ogeneration system availability was examined. 
Also the assumed prices for fuel and electricity were parametrically varied to 
determine the sensitivity of tti«> results to these variables. 

Results indirate that, for Lewis' electric load profiles during a typical 
year, the IGCC systems studied would have excess electric generating capacity 
more than 75 percent of the year. Thirty to forty percent of this excess 
generation would occur during the utility's peak load periods, thereby indi- 
cating the potential to generate excess cogenerated power economically during 
these periods for sale to the utility. An IGCC system in the 20- to 30-HW 
size range operating 80 percent of the year could save about 2.1x10° MJ/yr 
(0.2x10^ NBtu/yr) of fuel energy, which is about 10 percent of the total 
fuel energy required to meet Lewis' steam and electrical requirements without 

cogener«tioQ. ilMximum fuel savings at peak steaa dMands could reach 17 per- 
cent with an overall IGCC energy utilisation of 62 percent. 

The use of an on-site IGCC cogeneration aystea would significantly reduce 
the annual expenditure for purchased electricity and natural gas* Although the 
operation of an IGCC systea would increase the site operation and aaintenance 
(O&N) costs and introduce on-site expenditures for coal, an overall annual 
operating cost savings of $1*9 million to $2*4 million (1985 costs expressed 
in 1980 dollars) was estimated for such a system operating 80 percent of the 
year* This is 21 to 26 percent of the estimated 1985 costs to purchase the 
total electrical requirement and to purchase natural gas to generate the 
required steam without cogeneration* The analysis indicates that an operating 
cost savings could be obtained even at relatively low IGCC system assumed 
availabilities* The potential cost savings also remained significant at low 
assumed values of the selling price for excess electricity generated by the 
IGCC* If such an IGCC cogeneration system were constructed at Lewis and used 
for testing advanced-technology components, this analysis indicates that there 
is a good potential that it could yield an operating cost savings* 


A conceptual design of an integrated coal gasification combined-cycle 
(IGCC) powerplant to supply the steam and baseload electrical requirements of 
the NASA Lewis Research Center was presented in reference 1* In that study a 
reference system was established to assess the technical feasibility, the 
environmental characteristics, and the capital cost of such a powerplant 
located at Lewis* Presently natural-gas-fired boilers provide the steam used 
at Lewis and electricity is purchased from a utility company* An on-site IGCC 
powerplant with the ability to meet Lewis' steam requirements by extracting 
low-pressure steam from the steam turbine would allow a significant reduction 
in natural gas use, substituting the use of Ohio high-sulfur coal in an envi- 
ronmentally attractive manner* Operation of the IGCC as a cogeneration system 
(i*e*, the extracted steam represents relatively lo%r-temperature heat rejected 
from the power system) would significantly improve the overall energy effi- 
ciency associated with supplying Lewis' steam and electrical requirements* 

In addition to meeting a large part of Lewis' energy requirements, the 
powerplant could be of significant benefit (1) by providing a Lewis on-site 
test bed for advanced-technology components, (2) by providing a major step 
toward acceptance of IGCC powerplants in utility service, and (3) by providing 
another option for industrial cogeneration using coal. 

This report summarizes the results of an analysis that was done at Lewis 
in parallel with the contracted study of reference 1* This analysis evaluated 
the performance and operational economics of such an on-site IGCC powerplant 
and compared these results with the fuel consumption and annual purchased 
electricity and natural gas costs at Lewis without cogeneration* 

Because of the research activities at Lewis the electric load require- 
ments vary considerably with time* Peak power demand levels exceeding 200 MW 
are reached during intervals of several hours when major research facilities 


are in operation. The load is generally reduced to 4 to 5 MW during non- 
irorkdaya. The a teas requireaent ia mainly for apace heating and variea 
directly with the ambient temperature. An IGCC po%rer ayatem aised to meet the 
range of ateam loads would not be able to meet the high peak electrical demands 
that frequently occur for several hours during a workday and trould have elec- 
tric generating capacity in excess of deaiand during other hours of a typical 
day. Because the peak power demands are of short duratiou, it would not be 
economical to site an on-site powerplant to meet these peak demands. 

Therefore the powerplants considered in this analysis, %rhich were sized more 
to meet the required range of steam loads, require the purchase of additional 
electricity from a utility during periods of peak demand and result in excess 
on-site electric generating capacity during other periods. An analysis of the 
operational economics for these powerplants must therefore include the effects 
of purchasing additional electricity during some time intervals and either 
operating at part power or selling excess electricity during other time inter- 
vals. This was not included in the study of reference 1. 

In this analysis, operation of the IGCC powerplant is considered on an 
hour-by-hour basis for a typical year. It is assumed that the powerplant is 
operated with constant coal input and that the steam turbine extraction rate 
is varied to meet the Lewis steam requirements. If the resulting electric 
power output of the IGCC powerplant is less than the electric power require- 
ment, the difference between the required power and that generated by the 
powerplant is purchased from the utility. If the powerplant electric power 
output exceeds the requirement, the excess electrical generation is sold to 
the utility. The amounts of electricity that are purchased and sold are 
determined, and the time of the day and the day of the week during which this 
would occur are identified. This information is necessary to realistically 
estimate the costs associated with the purchase and sale of the electric power 
since, in general, the rate for electricity purchased from a utility by an 
industrial customer depends on such things as the amount used, the amount used 
relative to the peak demand, and the timing of the usage. These influences 
have been included in this analysis by using published electricity rates and 
rate structures as a model for the assumptions made for the prices of elec- 
tricity purchased or sold* Furthermore these assumed prices, and those assumed 
for coal and natural gas, were parametrically varied to determine the sensitiv- 
ity of the results to these assumptions. Also the IGCC powerplant size was 
parametrically varied since this would have a significant effect on the amounts 
and timing of electricity purchases and sales and hence on the operational 
economics . 


The Lewis steam requirements are mainly for space heating and generally 
vary directly with ambient temperature* Saturated steam is required at a 
pressure of 0.87 MPa (125 psia). In figure 1 a steam load duration curve for 
a typical year at the Lewis site is shown. The steam requirement is shown as 
a function of the number of hours at that load or higher. A peak steam load of 
about 12.6 kg/sec (100 000 Ib/hr) is typically reached on the coldest winter 
day and the steam generation and distribution system is generally operated at 
a minimum output of about 2.27 kg/sec (18 000 Ib/hr) independent of ambient 


tevperature. Steam loads above 7.56 kg/sec (60 000 Ib/hr) occur only about 
700 hours (or 8 percent) of a typical year. The annual average steam load for 
this example year vas about 4.66 kg/sec (37 000 Ib/hr). 

The Lewis electric load is dependent on the scheduling of major test 
facilities and varies considerably %rit» time. The actual electric load'* 
variations for one week in 1979 are shown in figure 2. As indicated, facili* 
ties are generally scheduled so that the highest electric loads occur at night 
during the local utility's off-peak hou>.s. %yhen the capacity is available Lad 
the cost of electricity is lowest. The utility's peak hours are defined as 
7:00 a.m. to 10:00 p.m. on weekdays and 7:00 a.m. to 10:00 a.m. on Saturday and 
are indicated in the figure* During 1979. electric loads typically ranged up 
to 40 MW during the utility's peak hours. Because the major facilities require 
so much power and are not operated continuously, the Lewis average load is 
relatively small as compared with the peak load (i.e.. the load factor is low). 

The electric load duration curves for 1979 and 1980 are shown in figure 
3(a). The electric load duration curves for these two years are very similar. 
Therefore the electrical data for 1979 were taken as being typical of the Lewis 
requirements and used in this analysis. The average load for both years was 
about 18 MW. The maximum load exceeded 200 MW so that the load factor ws' less 
than 0.09. The load exceeded 30 MW about 600 hours per year (or 7 percent of 
the time) and exceeded 25 MW about 1300 hours per year (or 17 percent of the 
time). Half of the time the load was below 10 MW. 

These characteristics of the Lewis load are the result of the specific 
nature of the electrical requirements for the test facilities and the avail- 
ability and cost of electricity from the local utility* The total cost of 
generating and distributing electricity depends on the capacity of the equip- 
ment that must be made available as well as on the amount of electricity 
generated. Thus utility rates for industrial customers include a demand 
charge that is proportional to the customer's peak power demand and an energy 
charge that is proportional to the amount of energy used. Furthermore these 
rates are structured to encourage customers to manage their loads to keep the 
load factor (average load relative to peak load) as high as possible. But. as 
just discussed. Lewis' load factor is unavoidably low because of the electri- 
cal requirement characteristics of the research facilities (i.e*. large 
electrical requirements for relatively short time periods). Therefore, during 
the example years 1979 and 1980. the Lewis contract with the local utility 
required prior approval from the utility for power levels used above a speci- 
fied value. This value, which was 24 MW. satisfied the baseload and a rela- 
tively modest amount of power for smaller test facilities. Generally, the 
larger power-consuming facilities were scheduled during the utility's off-peak 
hours when more generating capacity was available and the rate charged for 
electricity was lower. This is more clearly illustrated in figures 3(b) and 
(c). where electric load duration curves are sho%m for the utility's peak and 
off-peak hours, respectively. During peak hours (fig. 3(b)) the maximum elec- 
trical demand was only 37 MW and exceeded 23 MW only about 330 hours out of 
4100 hours (about 13 percent of the time). During off-peak hours (fig* 3(c)) 
the maximum electrical demand was more than 200 MW and exceeded 23 MW about 
1030 hours out of 4700 hours (about 22 percent). Also note that the electric 
load during off-peak hours was less than 10 MW for about two-thirds of the 


time since many off-peak hours correspond to weekends and holidays %rhen elec- 
trical requirements are low. A further description of the utility rate struc- 
ture used in this analysis is presented later in this report. 


A schematic of the integrated-gasifier, combined-cycle (IGCC) system is 
shown in figure 4. Gasifier air is extracted from the gas turbine compressor 
and further pressurised in a motor-driven boost ccxopressor. The hot, raw low- 
Btu gas from the gasifier passes through a cyclone separator and is cooled 
before further cleanup. The cooled gas passes through additional cyclone 
separators and a venturi scrubber to remove particulates and then to a Holmes- 
Stretford desulfurization system, where H 2 S in the fuel gas is removed and 
converted into elemental sulfur for disposal. The clean fuel gas is then 
reheated in the raw-gas cooler before injection into the gas turbine combustor. 
Electricity is produced by the gas turbine-generator, and heat from the gas 
turbine exhaust is recovered in a heat-recovery steam generator (HRSG), where 
steam turbine throttle steam is raised. Gasifier steam and additional throttle 
steam are raised in the raw-gas cooler* This throttle steam is c<»nbined with 
that produced in the HRSG, and the total is expanded in the steam turbine- 
generator, where additional electricity is produced. Steam required fot 
heating at Lewis is extracted from the steam turbine at 0.87 HPa (125 psia). 

For this analysis it has been assumed that the gasifier-cleanup system and the 
gas turbine always operate at full design capacity. The rate of steam 
extraction from the steam turbine is varied with the steam demand, leading to 
variations in the system total electric power output as a result of the steam 
turbine power variations. When the system is down for maintenance, or when 
the steam demand exceeds the steam turbine maximum extraction rate, a natural- 
gas-fired supplementary boiler is used to supply the total steam requirement 
or to make up the difference between the required amount and that roduced by 
the power system. An alternative to using natural gas would be to size the 
gasifier slightly larger and produce extra fuel gas for use in the supplemen- 
tary boiler. However, an alternat'^e fuel like natural gas would still be 
needed when the gasifier was not operating. 

The IGCC system parameters for this analysis are shown in table I. The 
gas turbine parameters reflect state-of-the-art conditions. The relatively 
low steam turbine throttle conditions were selected because of the relatively 
low gas turbine exhaust temperature and small steam turbine size. The gasi- 
fier is the air-blown Westinghouse fluid bed selected for study in reference 
1. The gasifier operating pressure is sufficiently above the gas turbine 
combustor pressure to overcome gasifier and cleanup pressure losses and the 
pressure loss that results when the fuel gas is injected into the combustor. 

The heating value of the clean fuel gas is as shown* Particulate emissions 
are kept low through efficient removal of particulates from the fuel gas by 
the combination of cyclones and a venturi scrubber. The low SO^ emissions 
are a result of H 2 S removal from the fuel gas in a Holmes-Stretford unit, 
where elemental sulfur is recovered for disposal in a solid cake form. The 
low NOj^ emissions are due to the low-flame temperature from the combustion 
of the low-Btu fuel gas. 


Based on the IGCC system schematic shown in figure 4 and the IGCC system 
parameters listed in table I, a heat and mass balance for the IGCC cogenera- 
tion powerplant was calculated for a range of steam extraction rates. The 
IGCC system power output as a function of the steam extraction rate is shown 
in figure 3 for the three system capacities that were analyzed. The 20-> 25-« 
and 30-MW system capacities refer to the design power output of the system when 
no steam is extracted fr<xn the steam turbine. These system capacities cover a 
range from the size considered in reference 1» which is near the annual average 
electrical requirement (20 MV), to an IGCC capacity of 30 MV, which satifies 
the maximum steam requirement. For this size range the IGCC system efficiency 
at any given extraction rate is assumed to be the same. The extraction rate 
is expressed in terms of the percent of steam turbine throttle flow, with the 
maximum extraction rate assumed to be 88 percent. The electric power output 
decreases with an increasing amount of steam extraction as the steam turbine 
electric power output decreases. The power output at the maximum steam extrac- 
tion is 25 percent lower than the maximum output at zero steam extraction. The 
range of Lewis steam requirements is indicated on the abscissa. As shown, the 
30-MV IGCC system can satisfy the maximum Lewis steam requirement. The 20- and 
25-MV systems cannot and require the use of a supplementary boiler. 


The technical assumptions used in this analysis are as follows: 

(1) The gasifier-cleanup system and the gas turbine operate at constant power. 

(2) Steam is extracted from the steam turbine to match Lewis' steam 

(3) Electricity is purchased and sold as required. 

(4) A 8 upple« 4 entary boiler is used when the steam requirement exceeds maximum 
cogeneration system steam extraction. 

(5) A supplementary boiler is used for the entire steam requirement when the 
cogeneration system is down. 

(6) Ambient temperature variations are not included in performance 

(7) Cogeneration system downtime is equally probable at all loads. 

As mentioned previously, the gasifier-cleanup system and the gas turbine are 
assumed to operate at constant, full-design-point conditions, while the steam 
turbine extraction rate follows the steam demand. If the Lewis electrical 
demand is greater than the amount of electricity produced ly the power system, 
additional electricity is assumed to be purchased frr^m Lhe utility company. 

If electrical demand is less than the amount of eletricity produced on-site, 
excess electricity is assumed to be sold to the utility company. An obvious 
alternative assumption would be to turn down the on-site system so that excess 


paver is not generated. This ^as not considered in this preliminary analysis. 
When the steam requirements exceed the maximum amount of steam that can be 
extracted from the steam turbine, a supplementary boiler firing natural gas 
makes up the difference. Also, idien the IGCC system is down for maintenance 
or repair, the supplementary boiler supplies the entire steam requirement. 

The supplementary boiler is therefore sized to meet the maximum Lewis steam 
load (12,6 kg/sec, 100 000 Ib/hr). Ambient temperature variations were not 
considered in the power system performance (13** C (39^ P) ambient temperature 
was assumed for all calculations). For calculation purposes the time that the 
IGCC system is assumed to be down is equally distributed throughout the year 
(i,e,, is equally probable at all loads). 

The price for electricity assumed in this analysis is based on utility 
rates for large industrial users approved by the Public Utilities Commission 
of Ohio (PUCO), The values for various charges in effect as of June 1980 
corresponding to this rate structure were escalated to 1983 (assumed to be the 
date of plant startup) by using Department of Energy projections (ref, 2), 

These assumed 1983 costs are expressed in 1980 dollars. 

It was further assumed that a contract with the utility company would be 
of the same form as previous contracts. This would allow for a contractually 
fixed demand charge. All purchased power requirements above the power level 
that corresponds to the fixed demand charge would require utility company 
approval. The assumed rates are shown in table II, The power level for the 
fixed contract demand (PCD) charge was assumed to be 24 MW in the situation 
without cogeneration. In the 30-^ IGCC cogeneration case the PCD power level 
was assumed to be 3 MV, which is the minimum peak demand level to qualify for 
the large industrial customer rate. In the other cogeneration cases the PCD 
power level was taken as the difference between 24 MW and the minimum power 
output of the on-site IGCC system, (The PCD power level in these cases is 
then greater than 5 MW,) The PCD charge covers the utility's costs for making 
available the generating capacity to provide power up to the PCD power level 
at any time during the billing period. In addition to this charge, an energy 
charge is made as a function of the amount used. The energy charge for elec- 
tricity used at power levels below the PCD power is based on a declining block 
structure. The size of the energy consumption blocks is expressed in terms of 
the PCD power as shown in table II, The first energy consumption block extends 
up to 113 kW-hr per PCD power. The PCD charge is applied to this block and no 
additional energy charge is made. The energy charges for the succeeding two 
consumption blocks are also shown in table II, 

As previously sho%m in figure 3, the Lewis electrical requirement often 
exceeds the PCD power level. For energy used at power levels above the PCD 
power, energy charges are assumed to depend on whether energy is purchased 
during the utility's peak or off-peak hours. During utility peak hours the 
charge corresponds to the overall effective cost of the electricity purchased 
during that billing period at power levels below the PCD power. During 

utility off-peak hours the enersy charge equals the charae applied to the 
third energy consumption block (>420 kW-hr per PCD power). 

In addition to the demand and energy charges, a fuel charge is uniformly 
applied to all electricity purchas i. The fuel charge shown in table II is 


based on the fuel charge for June 1980 escalated to 1985 costs and expressed 
in 1980 dollars* 

In the cogeneration cases it was anticipated that there would be a cost 
to the utility company asssociated with the capability to supply additional 
power when the cogeneration system is down for maintenance or repair. In this 
analysis this standby charge shown in table II is assumed to be applied to the 
difference between the FCD power levels for the noncogeneration and the co- 
generation cases* The assumed charge for this standby capacity is also based 
on utility rates approved by the PUCO for large industrial users and is shown 
in the table* Finally, discounts typical of those given to large industrial 
curjto^ers who use high-voltage power and supply transforming and switching 
equipment were assumed. These amount to slightly over 3 percent of the total 
electricity bill* Using the assumptions in table II, the effective cost of 
electricity used at power levels less than the FCD power is shown in figure 6 
as a function of the amount purchased during a monthly billing period. The 
amount purchased is shown on the abscissa per unit of FCD power* As shown, 
the effective cost of electricity decreases with increased amounts of elec- 
tricity purchased under the FCD power level, with the effective COE approach- 
ing t0*04/kW-hr for large amounts of purchased electricity. 

The prices assumed for coal and natural gas, taken from reference 2, are 
shown in table III. Also shown in table III is the overall average cost of 
electricity for the noncogeneration case and for each cogeneration case* 

These average costs of electricity are presented here to show the effects of 
the assumed rate structure (as described in table II) when combined with the 
steam and electric load data displayed in figures 1 and 3, respectively, and 
the IGCC performance shown in figure 5. These calculations are described 
later in the report. The average electricity prices shown in table III are 
higher for the cogeneration cases than for the noncogeneration case because 
of the decreased amount of purchased electricity and the additional standby 
charge* The price for electricity sold to the utility was assumed to be the 
sum of the fuel charge and the energy charge for the third energy consumption 
block (>420 kW-hr per FCD power) shown in table II for electricity purchased 
below the FCD power level* Also shown in table III are ranges over which each 
price was parametrically varied. 


As shown in figure 3, the performance of the IGCC system varies with the 
amount of steam extracted to meet the Lewis steam load. The IGCC performance 
data as a function of steam extraction rate were combined with the steam and 
electric load demand curves shown in figures 1 and 3 to calculate the annual 
consumpti m of coal for the IGCC system and the annual natural gas consumption 
for the supplementary boiler* The amounts of electricity purchased and sold 
annually, along with the corresponding amounts of fuel used or displaced at 
the utility site, were also calculated. 

The Lewis electrical and steam demands are independent of each other* 
Therefore it was assumed that all combinations of electric and steam loads are 
encountered during a year* At each value of electric load the corresponding 


steam loads were determined from the steam load duration curve expressed as a 
percentage of the year spent at that load or higher. These calculations were 
made by approximating each of the load curves by a series of discrete time 
steps. A computer code was used to calculate the values of fuel consumption 
and of electricity purchases and/or sales in each discrete time interval and 
to sum these values over a year. The timing of the electricity purchases and 
sales with respect to the utility's peak and off-peak hours and workdays or 
nonworkdays was determined by usin^ load duration curves for those particular 
time periods. 

From the calculated fuel energy usages and the assumed fuel prices pre- 
viously shown in table III, the annual expenditures for fuel for both the 
noncogeneration and cogeneration cases were calculated* Also, by using the 
amounts and timing of electricity purchases and sales with the assumed elec- 
tricity rate structure previously described, the respective expenditures for 
electricity purchases in the noncogeneration and cogeneration cases and 
revenues for electricity sales to the utility in the cogeneration cases were 
determined. Operation and maintenance (O&M) costs for the noncogeneration 
case were based on actual Lewis boiler operation data; O&M costs for the co- 
generation cases were calculated from estimates in reference 1. From these 
calculations the total annual operating costs for the noncogeneration and 
cogeneration cases were calculated. 

The relative capital costs of the cogeneration systems were estinuted 
by assuming that capital costs are proportional to the ratio of cogeneration 
system maximum electric power output capacities raised to the 0.7 power. By 
using these relative capital costs and the operating cost savings, first-year 
relative payback periods (defined as capital cost relative to first year 
operating cost savings) were calculated for the three cogeneration cases. 

These payback periods are relative to a base payback period. The base was 
assuned to be the 20-MW cogeneration case using the fuel and electricity price 
assumptions shown in table III. 


As previously shown in figure 5, the electric power output from the IGCC 
cogeneration system varies as the amount of steam extracted from the steam 
turbine is changed to meet Lewis' steam demand. Likewise, Lewis' electrical 
demand varies over a wide range, as shown in figure 3. This results in situa- 
tions when the electrical requiremen** exceeds the amount of electricity pro- 
duced by the IGCC system, and additional electricity must be purchased. At 
different times, the electrical requirements are less than the amount of 
electricity that can be produced by the cogeneration system, and the excess 
electrical production is sold to the utility. This is illustrated in figure 
7, where the average power output of the 23-MW IGCC system is superimposed on 
the Lewis electric load duration curve. Also shown are the amounts of elec* 
tricity sold and purchased. The range of cogeneration system power outputs 
indicated in the figure represents the variation in electric power output that 
corresponds to the variation in the steam turbine extraction rates that would 
be encountered. Th^^ figure illustrates that, if th3 cogeneration system 
operated 100 percent of the time, the sale of excess electricity to the 


utility could occur more than 75 percent of the year, with up to 19 MW avail' 
able for 8<«le* The purchase of electricity would occur about 20 percent of 
the time when higher power levels are required* 

The amounts of electricity purchased and sold annually are shown as a 
function of cogeneration system size in figure 8. In addition to the total 
amount of electricity sold, the amounts sold during the utility's peak and 
off'peak hours are also displayed* The results were obtained by assuming tl ^ 
the cogeneration system operates 80 percent of the year and is down 20 per. 
of the time for maintenance and/or repair* At 80 percent availability, an 
equal amount of electricity is annually purchased and sold for an IGCC system 
size of 25*6 MW* The amount of electricity sold increases and the amount of 
electricity purchased decreases with increasing cogeneration system size* 

This implies higher revenue from the sale of electricity and lower costs for 
the purchase of electricity with increasing cogeneration system size* An 
important point illustrated in figure 8 is that for the 1979 and 1980 elec- 
tric load requirements a significant fraction of the excess power generating 
capacity would occur during the utility's peak hours* This would increase the 
chances that the excess generating capacity could be economically used. The 
generation of this excess electricity would be more fuel efficient than the 

generation of electricity at the utility because of the waste heat recovery 

from the IGCC cogeneration system* Much of the excess generating capacity 
during utility off-peak hours wo Id occur during weekends and holidays* If 
the revenue from electricity sales is relatively low during these periods, an 
option would be to operate the IGCC system at lover capacities. 

Cogeneration performance can be expressed in terms of the fuel savings, 
both at the site being cogenerated and at the utility company site as a result 
of on-site electrical production with waste heat recovery from the cogenera- 
tion system* An example of this is shown in figure 9, where the fuel savings 
are shown for the ?3-MW IGCC system at the Lewis site as a function of the 
site steam and electrical requirements* The fuel savings are shown as a per- 
centage of the total fuel that would be used at the Lewis and utility sites to 

produce the same amount of electricity and steam in a noncogeneration situa- 
tion. This is the fuel savings parameter used in reference 3* The fuel 
energy savings obtained at any time during the year would fall within this 
cogeneration performance envelope for this particular IGCC system* The top 
line of this envelope corresponds to the fuel savings achieved jhen the power 
output of the IGCC system is greater than or equal to the site electrical 
requirements* Whenever the site electrical requirements excee’ the output of 
the IGCC and additional power must be purchased trom the utility, the fuel 
savings are lower and fall within the envelope. For a given site steam re- 
quirement the fuel energy savings decrease as the site electrical requirement 
increases* The lowest value of fuel energy savings is given by the lower 
boundary of the performance envelope, corresponding to the periods of maximum 
Lewis electric power requirement. The fuel energy savings are highest when 
the steam requirements are highest because of the greater opportunity for 
waste heat recovery from the IGCC system. The maximum value of fuel energy 
savings occur at a site steam requirement slightly above 10*08 kg/sec 
(80 000 Ib/hr), which corresponds to the maximtun amount of steam extraction 
from the 23-MW IGCC system. The fuel energy savings do not increase with 
steam demands greater than this since a supplementary boiler is required to 


raise the additional steam. Thus the largest instantaneous fuel energy savings 
would be realized at high site steam requirements with simultaneously low 
power requirements, corresponding to a cold winter nonworkday or a cold winter 
workday when research and testing power requirements are relatively low. The 
fuel energy savings could reach almost 17 percent with an overall energy 
utilization, defined as the useful power plu<^ heat divided by the fuel input, 
of about 62 percent. Conversely, the smallest instantaneous fuel energy 
savings would be achieved at low site steam requirements with high power 
requirements, corresponding to the running of large electricity-consuming 
facilities in the summer. Note that the difference in fuel energy savings 
between these two extremes is substantial. 

The annual fuel use rates and cogeneration fuel savings are shown in 
table IV. These were calculated by combining the instantaneous performance, 
as indicated in figure 5, with the load profiles of figures 1 and 3. The co- 
generation results assume an IGCC system availability of 80 percent and an 
overall utility electrical efficiency (including transmission losses) of 
32 percent. In the noncogeneration system, natural gas is used in the on-site 
boiler to meet the steam requirements and all the electricity required is pur- 
chased from the utility company. The utility fuel, which is dominantly coal, 
is assumed to be all coal in table IV. As shown, the natural gas use is sub- 
stantially reduced in the cogeneration cases. In the 30-MW IGCC cogeneration 
case the amount of natural gas use shown is required for a supplementary boiler 
to meet the steam requirements only when the IGCC system is down for mainten- 
ance or repair. For the 20- and 25-MW IGCC cogeneration cases, an additional 
amount of natural gas is needed to meet the peak steam requirements, which 
exceed the steam turbine extraction limit* As discussed earlier, at times the 
cogeneration cases require the purchase of electricity from the utility (when 
the power demands are high or when the IGCC is not operating), and at other 
times the cogeneration cases involve the generation and sale of excess elec- 
tricity to the utility. The coal required at the utility site for the 
purchased power and the coal that could be displaced at the utility site 
because of the excess power generated at the Lewis site are shown in table 
IV. When this is combined with the coal input to the IGCC system, it is evi- 
dent that the total coal use in the cogeneration cases slightly exceeds the 
coal use in the noncogeneration case. However, the reduction in natural gas 
consumption exceeds the increase in coal use, and there results a net fuel 
savings as shown in the last column. As the IGCC size increases, the amount 
of total coal use (including coal used at the utility) and natural gas use 
decreases, resulting in a greater fuel energy savings. 

The data in table IV are sensitive to the assumed IGCC system avail- 
ability, as illustrated in figure 10. As stated earlier, it has been assumed 
that the IGCC system is operated at full design coal input whenever it is 
available for operation, so that the capacity factor equals the assumed avail- 
ability. Also it has been assumed that the probability of the cogeneration 
system being down is equally likely throughout the year. In figure 10(a) the 
annual fuel energy savings are expressed *n dimensional terms. As expected, 
the annual savings increase with increasing cogeneration system availability. 

As shown in figur® 10(a) the 2.41xlO®-MJ/yr (2.29xlO^-MBtu/yr) fuel 
savings shown in table IV for the 30-MW IGCC cogeneration case would increase 
to 3.02x10® MJ/yr (2*86x10^ MBtu/yr) if the IGCC operated continuously at 


full capability for the entire year. In figure 10(b) the fuel savings ere 
shown as a percentage of the amount of fuel that would have been required 
without cogeneration to produce the same amount of power and heat as produced 
with cogeneration. The CTAS definition of fuel energy savings has been used 
(ref. 3). Thus the noncogeneration fuel use in this definition includes, in 
addition to the boiler fuel, the utility system fuel that would be needed to 
generate power equal to the Lewis site requirements plus the excess generation 
of the cogeneration case* At a cogeneration system availability of 80 per- 
cent, the total fuel energy savings for the three IGCC system sizes amount to 
approximately 7*5 percent of the noncogeneration fuel erergy use. If the 
fuel savings were expressed only as a percentage of the sum of the 
4.45x10® MJ/yr (4.22x10^ t'ltu/yr) of natural gas used and the 18.02x10® MJ/yr 
(17.08x105 MBtu/yr) of utility fuel needed to meet only the Lewis site 
needs, the fuel savings at 80 percent T JC availability would range from 9.2 
to 10.7 percent. 


In table V the amount of electricity purchased or sold per year is sho%m 
for the noncogeneration case and the three cogeneration cases. These values 
assume a cogeneration power system availability of 80 percent* The amount of 
electricity purchased is categorized according to whether it was purchased at 
power levels below or above the FCD power level, whether it was purchased when 
the cogeneration system was operating, and whether it was purchased during the 
utility's peak or off-peak hours. Electricity that is sold is categorized 
according to whether it is sold during the utility's peak or off-peak hours or 
sold during Lewis workdays or nonworkdays* As shown, most of the electricity 
purchased in the noncogeneration Cr-se is purchased below the assumed 24-MW FCD 
power level. Most of the electricity purchased at higher power levels is pur- 
chased durii^g utility off-peak hours. This was previously illustrated in 
figures 2 anc 3. For the co<teneration cases about half of the purchased elec- 
tricity is required at power levels below the FCD power level. Most of the 
electricity purchased below the FCD power level is piichased when the IGCC 
cogeneration system is *iown for maintenance or repair. For the cogeneration 
cases most of the elec icity purchased at power levels above the FCD power 
level is purchased during off-peak hours. Significantly 30 to 40 percent of 
the ei .tricity sold to the utility is sold during their peak hours. 

In table VI the annual costs and revenues for the purchased and sold 
electricity of table V are shown for the noncogeneration and cogeneration 
cases. The costs for purchased electricity are categorized as in table V. 

The revenues for electricity sold to the utility are not categorized as in 
tsbic V because only one price was assumed for electricity sold to the utility 
regardless of when it is sold. In practice, it would be expected that the 
price paid by the utility for electricity sold to them during peak hours would 
be higher than that paid for electricity sold to them during off-peak hours. 

The stardby charges represent a large portion of the total cost for purchased 
electricity for the cogeneration cases. As shown previously in table III, the 
price charged for electricity purchased from the utility in the cogeneration 
cases was assumed to be greater than that paid for electricity sold bacx to the 
utility. Thus for the 30-MW cogeneration case the revenue from the electricity 


sold to the utility is less than the cost for purchased electricity even 
though, as shovn in table V, the amount of electricity sold is considerably 
more than that purchased. The total expense for purchased electricity 
decreases and the revenue from sold electricity increases with increasing IGCC 
system size. 

The operating cost summary for the noncogeneration and cogeneration cases 
is shorn in table VII. The costs are expressed as 1985 costs in 1980 dollars. 
The tvo largest operating expenses in the noncogeneration case, the costs for 
natural gas and purchased electricity, are substantially reduced in the 
cogeneration cases. As shoim, the bigger the IGCC cogeneration system, the 
lover is the expense for purchased electricity, and the higher is the revenue 
from excess power generation. But on-site cogeneration systems will have 
higher OAN expenses and will incur an additional expense f>r coal. The 0AM 
cost estimates shown for the IGCC cogeneration cases %#ere based on estimates 
from reference 1. Because of the greater amounts of coal used, the on-site 
coal expenses are higher than the expense for natural gas in the noncogenera- 
tion case. But as shoim, the net effect xs a reduction in tots) operating 
expenses for the cogeneration cases as compared with the noncogeneration case. 
Also the total operating costs for the cogeneration cases decrease as the 
cogeneration system size increases. The operating costs sho%m for the 
cogeneration cases correspond to cjst savings of 21 to 26 percent relative to 
the operating cost for the noncogeneration case. 

The results shown in table VII assume an on-site cogeneration system 
availability of 80 percent. The variation in first-year operating cost savings 
as a function of cogeneration system availability is shown in figure 11. As 
expected, the first-year operating costs are sensitive to cogeneration system 
availability, with operating cost savings increasing as availability increases. 
Another potentially key assumption made to calculate the results shown in 
tables VI and VII concerns the standby charge paid to the utility for the 
purchase of electricity when the on-site cogeneration system is down. In 
figure 11(a), operating cost savings are shown with the assumption that the 
sum of the FCD power level in the cogeneration case and the standby power 
level equals the FCD power level in the noncogeneration case. The resulting 
24 MW would allow ''business as usual" operation when the cogeneration system 
is down for maintenance. In figure 11(b), the first-year operating cost 
savings are shown with the assumption that the sum of the FCD power level and 
the standby power level equals 12 MW. This assumption implies a curtailment 
of research facility operation when the cogeneration system is down and 
yields a decrease in the standby charge paid to the utility, with a resulting 
substantial increase in the operating cost savings relative to those shown in 
figure 11(a). The operating cost savings shown in both figures 11(a) and (b) 
are a significant percentage of the total operating costs of the noncogen- 
eration case. 

Another key assumption made in tables VI and VII and figure 11 i. the 
price obtained for excess electricity sold to the utility. The operating cost 
savings «hown in figure 11 were calculated by using an assumed electricity 
selling price of i0.0311/kW-hr. The effect of variations in thr selling price 
on the operating cost savings for the three cogeneration cases is shown in 
figure 12. The selling price is varied from a minimum of $0.022/kW-hr, 


corresponding to only the fuel cherge in the aseuaed electrical rate etructure, 
to a aaxiaum of t0.042/kW-hr» which ie the average price for purchased electri- 
city in the noncogeneration case* As shown» the 30-MW IGCC is the most sensi- 
tive to changes in the selling price because it produces the largest aaount of 
excess electricity* The 30-MW IGCC has the largest first-year operating cost 
savings over the range of selling prices considered* 


Cost coaparisons presented to this point have included only the first-year 
operating cost savings of the dif ferent-sixe cogeneration systeas* The rela- 
tive economic attractiveness of the dif ferent-sixe systems depends on the com- 
parison of the operating cost savings and the required capital investment* To 
examine this in a simplified manner, relative payback periods were calculated* 
These relative payback periods would be expected to be very sensitive to the 
values assumed for electricity, natural gas, and coal prices* Therefore the 
sensitivity of the relative payback periods to changes in each of these 
assumptions was examined. 

The relative payback periods for the three cogeneration cases are shown 
in figure 13 as a function of electricity price* The electricity prices for 
the noncogeneration and cogeneration cases and the excess electricity selling 
price were varied by the same percentage simultaneously* At the base elec- 
tricity price, the 20-MV cogeneration system has the best payback period* For 
electricity prices of about 16 percent or more above the base price, the 30-MW 
cogeneration system achieves the most attractive payback* 

The relative payback period as a function of variations only in the sell- 
ing price of excess electricity is shown in figure 14* For a selling price 

less than i0*0338/kW-hr, the lowest payback period is achieved with the 20-MW 
system* At selling prices greater than $0.0338/kW-hr, the 30-MW system 
achieves the lowest payback period* 

Figure 15 shows the relative payback period as a function of the natural 
gas price. The payback periods decrease with increasing natural gas price 
since, in cogeneration, the operating cost savings are largely a result of 
avoiding the purchase of natural gas for steam generation* At natural gas 
prices less than i4*00/MBtu, the 30-MW system has the best payback* At natu- 
ral gas prices greater than $4*00/MBtu, the 20-MW system has the best payback* 

The relative payback period as a function of coal price is shown in fig- 
ure 16* At coal prices less than il.26/MBtu, the 30 MW system has the lowest 
payback* At coal prices greater than tl.26/*MBtu, the 20-MW system has the 
lowest payback* 

The data presented in figures 13 to 16 indicate that the 20-MW cogenera- 
tion system has the lowest payback period at the base fuel and electricity 
prices* At higher electricity prices and lower coal and natural gas prices, 
the 30-MW system has the lowest payback period* A more detailed analysis, 
including the effects of escalating electricity and fuel prices and using more 


detailed capital cost estimates, is required to determine the best system sise 
on an economic has is • 


Levis' electric loads vary from a minimum of about 5 HW to a siaximum of 
over 200 HU, vith an annual average of about 18 IW. The steam heating re- 
quir»ent varies from a base of about 2.27 kg/ sec (18 000 Ib/hr) to over 
12*6 kg/sec (100 000 lb/hr)« Integrated-gasifier, combined-cycle (IGCC) 
cogeneration systesis vith maximum electric outputs of 20, 23, and 30 MW %iere 
analyzed for potential application at the Levis site. These systesis could 
supply the baseload electric requirement and, by extraction of steam from the 
bottoming steam turbine, could supply all or most of the heating requirement* 
The 20-MW-capacity system could supply the steam for all but the peak require- 
ments above 8.82 kg/sec (70 000 Ib/hr), %rhich occur during 3 percent of the 
year* The 30-MW-capacity system is just big enough to meet the maximum steam 
requiresient* Because the pover output of these systems at the point of maxi- 
mum steam extraction is about 23 percent lover than the maximum output at zero 
steam extraction, the electric generating capability is a function of the 
steam heating load* The electricity needed to meet the very high pover re- 
quirements of the major research facilities vould have to be purchased, vhile 
at other periods of a typical day the on-site IGCC system would have excess 
generating capacity* For load profiles typical of 1979 and 1980, the IGCC 
system could have excess generating capacity during more than 73 percent of 
the year* It is significant that from 30 to 40 percent of the excess elec- 
tricity would be generated during the utility's peak load period (between 
7:00 a.m* and 10:00 p*m*)* Thus there is potential for economical use of this 
generating capacity* Generating this excess electricity in a cogeneration 
system is more fuel efficient than generating electricity at the utility 
because of the waste heat recovery from the cogeneration system* Of the 
excess electricity generated during the utility's off-peak hours, more than 
60 percent occurs during weekends, when a practical option might be to turn 
down the powerplant to meet only site requirements* 

For loads that were typical in 1979 and 1980, a 20- to 30-MW IGCC co- 
generation system, operating for 80 percent of the year, could save about 
2*1x10® MJ/yr (0.2x10® MBtu/yr) of energy. This is about 10 percent of 
the total fuel energy required to meet the steam and electrical requirement 
without cogeneration in 1979 or 1980* Because both the electric and steam 
loads vary so much during the year, the fuel savings achieved at any time also 
vary considerably. Because of the higher degree of IGCC system waste heat 
utilization, the highest instantaneous fuel savings percentages are achieved 
during the time of peak heating needs in the winter* At the peak steam demand 
the fuel savings could reach about 17 percent with an overall IGCC energy 
utilization (i.e., useful power plus heat divided by the fuel input) of about 
62 percent. 

Since an on-site IGCC cogeneration system coulu supply the baseload elec- 
trical requirement and most of the steam requirement, the annual expenditure 
for purchased electricity and natural gas could be significantly reduced. 

Even when this is weighed against the increased site O&M costs and the coal 


costs to operate the IGCC systea» a net overall annual operating cost savings 
could be achieved. Assuming that the IGCC cogeneration system operated 
80 percent of the year» the annual savings estimated for the 20- to 30-NW IGCC 
systems analysed range from il.9 million to $2.4 million, expressed in terms 
of 1980 dollars for 1985 operation. This is 21 to 26 percent of the estimated 
cost to provide the total steam and electrical requireisents in 1985 without 
cogeneration. The estimated savings were found to be significant for wide 
ranges of assumed prices for fuels and purchased electricity, prices of excess 
electricity sold to the utility, and the IGCC powerplant availability. The 
estimates for the purchase and selling prices of electricity were based on a 
typical rate structure for industrial customers. In using such a model, the 
resulting estimates for the overall average unit price for purchased elec- 
tricity were always higher for the cogeneration cases than for the non- 
cogeneration case^ The reason is that less electricity is purchased in the 
cogeneration cases and the desiand charges relative to energy charges are more 
significant. Also in the cogeneration cases it was assumed that a standby 
charge would be paid to the utility so that, when the IGCC system is down, 
enough power could be purchased to maintain business as usual. The estismte 
for this charge alone exceeds tl million per year. Another assumption that 
has a significant effect on the results is the selling price for excess elec- 
tricity. This was varied over a wide range extending down to relatively low 
values, and the potential cost savings remained significant. 

If an IGCC cogeneration system were constructed at the NASA Lewis 
Research Center and used for testing advanced-technology components, this 
analysis indicates that there is a good potential that il operation could be 
economical, in spite of the relatively unfavorable characteristics of the 
electric and steam loads as compared with potential industrial applications. 

In addition, the estimates of operating cost savings remain positive down to 
relatively low assumed IGCC system availabilities. Although the IGCC system 
has not been considered in detail from the perspective of investment, 
simple relative payback periods for the 20-, 23-, and 30-K ICCC systems were 
compared in this analysis. Although the estimated operating cos': savings for 
the 30-NW system are higher, the 20-NW system has a better relative payback 
period for the base price assumptionsr The relative payback periods were 
estimated on the basis of a simple scaling assumption for the capital cost 
variation with system capacity. 



!• Bloomfield, Harvey S.; et al: Conceptual Design Study of a Coal 

Gasification Combined-Cycle Poverplant for Industrial Cogeneration. 

NASA TM-81687, 1981. 

2. Borg, Steve; and Moden, Robert: Historic and Forecasted Energy Prices by 

U.S. Department of Energy Region and Fuel Type for Three Macroeconomic 
Scenarios and One Imported Oil Price Escalation Scenario. 

DOE/EIA-0102/27, Department of Energy, 1978. 

3. Bama, Gerald J«; Burns, Raymond R. ; and Sagerman, Gary D. : Cogeneration 

Technology Alternatives Study (CTAS), Volume I - Summary. NASA TM-81400, 
1980. (D(»/NASA/1062-80/4.) 



Gas turbine: 

Turbine inlet teaperature, "C (*F) 
Coaoressor pressure ratio ...» 

1094 (^000) 

SteaiP cycle: 

Throttle conditions, MPa/*C (psia/’F) 4.?9/399 (61S/7SO) 

Condenser pressure, H>a (in. Hq abs) 0.013 (4.0) 

Process steam extraction pressure, MPa Cpsta) 0.87 (Ub) 


Type Uestinghouse fluid bed <a1r blown) 

Derating pressure, H>a (psia) 1.98 (784) 

Low-Btu-pas higher healing value, MO/kq (Btu/lb) S.lSl (2716) 

Cleanup system: 

Particulate removal Cyclones and venturi scrubber 

Desulfurization Holmes- Stretford unit 

Specific emissions, kg/MJ (Ib/MBtu): 

SO* 4.30x10-? (0.1) 

MO* 4.30x10“^ (0.1) 

Particulates 7.31x10-7 (0.0017) 

[1986 prices in 1980 dollars.] 

Fixed-contract-demand (FCO) power level, MM: 

Noncoqeneration case 24.0 

Cogeneration cases 

70-MN IGCC 9.0 

25-HM IGCC 6.3 

30-HM IGCC 6.0 

FCO charge per demand power, |/kW-month: 

Up to 6-MM demand 6.64 

6 MW to FCO power 6.17 

En**rgy charqe, S/kM-hr; 

Energy purchased at power < FCO power 

^115 kW-hr per FCO power Covered by FCD charge 

116 to 420 kM-hr per FCD power , 0.0146 

>420 kM-hr per FCD power 0.0098 

Energy purchased at power > FCD power: 

During utility peak hours Cost of electricity purchased 

in above category 

During utility off-peak hours 0.0098 

Fuel charqe. F/kW-hr 0.0723 

Standby power, MW: 


26-MW IGCC 18.7 

30-»Ai IGCC 19.0 

Standby charge per standby power, S/kW-month 6.92 

Discounts, S/month per kW FCO power 0.30 

[1986 prices in 1980 dollar* .] 


Nonco9enerat1on case 


CopeneratloA cases^ | 


zo m 


30 m 

Electricity. MW-hr | 


Below FCO power level 


Below FCD power level 




Syste« on 

0. 14*10^ 

Svsteai off 




Over FCO power level 

Over FCO power level 

Peak h^rs 


Peak hours 




Off-peak hours 


Off peak hours 









Peakhours : 

-0. 2^x10^ 





Off-peak hours: 














-0. 60x10^ 




Total net 




®Base<t on coQoneration svsten a%a^la^Hity of 80 percent. 


Noncooenerat Ion case 


Cogeneration cases® | 



20 m 

75 MW 

30 m 

Electricity cost, dollars 

Costs for 

Below FfO power level 

S. 37x10^ 

Below FCP power level 
Systew on 
System off 







standby charge 




Over FCn power level 
Peak hours 
Off-peak hours 



Over FfP power level 
Peak hours 
Off-peak hours 










Revenues for 
sold electricity 






Total net cost 


1. 95x106 


•Based on 
**Based on 
f Based on 
‘^Based on 

coqenerat^on svsten availability of BO percent, 
U.OB.PM Standby power reoulretnent. 

18.7UHW standby power recu1rea*ent . 

19.00-^A( standby power requlrewent. 


[I98S costs In 1980 dollars.] 

ation case 

Cogeneration cases® | 

70 MW 

25 MW 

30 MW 

Natural gas costs, dollars 




Operation and maintenance 




costs, dollars 
Coal cost, dollars 
Cost of purchased elec- 








tricity, dollars 
Revenue from electricity 






?. 37.10* 



•Based on cogeneration systen availability of 80 percent. 

steam requirements^ Ifafhr 

Time, hr 

Figure I, - Steam load duration curve at Lewis site for typical year. 

Day of week 

Figure 2. - Actual lewis electric toad time variation for example week (August 197gi. 


[0 Utility comtwoy oTf-peak hours, 
figure >. * ifmi% electric loed duration curves. 


Steam turbine extraction rate. Ibfh*' 

Figure 5. - PoiNer output as a function of steam turbine extraction rates for 
different IGCC cogeneration system sizes. 

Electricity purchased below FCO power level per month, KW-hrfldM 

Figure 6. * Cost of electricity put chased at power levels below fixed contract 
demand (FCDI power as a function of electricity purchased U986 costs 
expressed in 1980 dollars). 


Figure 1 , - Lewis annual electric load duration curve showing amounts of electricity 
purchased and sold with 25-MW IGCC cogeneration system. 







Total electricity 



Electricity sold 
during utility 
off-peak periods 

Electricity soM 
during utility 
peak periods 


Power system size. MW 

Figure 8. - Electricity purchased or sold per year as j function of IGCC ation 
system size (80 percent power system availability). 

IGCC Site 

I ^ ^ ^ ^ ^ 1 , 

0 20 40 bO 80 100 12 QkUK 

Si ^team requirements. hr 

Figure 9. * Instantaneous fuel savings as a function of site steam and 
electrical requlremsnts tor 25-MW IGCC cogeneration system at 
Lewis site. 

(a) Annual energy savings in joules (M6tu). 

.8 .9 1.0 

Power systefD availability 

(b) Annual fuel savings in percent of nongeneration fuel use. 

Figure la - Annual fuel energy savings as a function of IGCC cogeneration system 
availability for various cogeneration system sizes at Lewis site. 


it)) K'O pow«r l«v«l « \Undt>v pow«r - V MM. 

)i 9 ur« 11 hrst v^r op#rjting vi«t sJvirH]s «s j functton at UH'C 
vO)#n#rj()on vy^lont 4V4ii4blltrv for vjriou^ uoyentcftion sy^tam 






^ f 


K'P pOMr#r 

♦ \Undbv al- 

i; MM 
- J4MM 

) ii«i i h«rg# 
iCQtnvrittCM'i jtHl 





/ « 


pf u« 

1 ! 





IV H' 0* » 

spfittig prut ill tlAtrklty, tkM hr 

liyuit W hi>t v«4r i|>*ri(ing vo^t \jfving> i> « fuivtion ci %ell«ng prk.# 
at fffitfktty <k>( ( (.og«n#rilttM) ADpMLvrrO. 

1 1 - RtMlivt p^iytta j function of r«t«ttv« •Itctrkity pnc« for 
IGCC cogtnoratfon systom. 







S«lttno prict oi c^ifitrliltv. 

f i^urt 14. fttlMIvo piyUct is i functkin of •lKtrk;itv soflin^ prlci for tGCC co- 
g«< miration systom. 

I tot rmturil 

! ^ pricf 

I i I 1 I 

J 4 > 6 ? 

Ntturil to pf H^t. 

\ iqurt IN Rtitdvt ptyto J fundion o( tourti to ^ 
IGCC coqtntrtllon svsttm 

tot ioti