?/EPA
           United States
           Environmental Protection
           Agency
           Office of Air Quality
           Planning and Standards
           Research Triangle Park NC 27711
EPA-450/3-85-030
December 1985
           Air
An Analysis of the
Costs and Cost
Effectiveness of
Allowing SO2
Emission Credits
for Cogeneration
Systems

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                                 EPA-450/3-85-030
    An Analysis of the Costs and Cost
Effectiveness of Allowing SO2  Emission
    Credits for Cogeneration Systems
                       Prepared by:
                     Radian Corporation
                  Under Contract No. 68-02-3816
                       Prepared for:
              U.S. ENVIRONMENTAL PROTECTION AGENCY
                   Office of Air and Radiation
              Office of Air Quality Planning and Standards
              Emission Standards and "Engineering Division
              Research Triangle Park, North Carolina 27711

                      December 1985

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                                        DISCLAIMER

This report has been reviewed by the Office of Air Quality Planning and Standards, U.S. Environmental
Protection Agency, and approved for publication as received from the Radian Corporation. Approval does
not signify that the content necessarily reflect the views and policies of the U.S. Environmental Protection
Agency, nor does mention of trade names or commercial products constitute endorsement or recommenda-
tion for use. Copies of this report are available from the National Technical Information Services, 5285 Port
Royal  Road, Springfield, Virginia 22161

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                              TABLE OF CONTENTS



                                                                      Page

EXECUTIVE SUMMARY	  1


1.0  INTRODUCTION	  3


2.0  COGENERATION SYSTEM DESCRIPTIONS	  7


3.0  EMISSION CREDITS	 12


4.0  COST ANALYSIS	 17

     4.1  Steam Generator-Based Cogeneration Systems	 17

     4.2  Combined Cycle Cogeneration Systems	 25


5.0  REFERENCES	 37


APPENDIX A - MODEL CASES FOR COMBINED CYCLE COGENERATION SYSTEMS	A-l
APPENDIX B - SAMPLE CALCULATIONS FOR COMBINED CYCLE COGENERATION
             SYSTEM	 B-l

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                              EXECUTIVE SUMMARY

     A cost analysis was performed to assess the reasonableness of emission
credits for cogeneration facilities under new source performance standards
being developed to limit sulfur dioxide (802) emissions from industrial-
commercial-institutional steam generating units with heat input capacities
of greater than 100 million Btu/hour.  This analysis examined two common
types of cogeneration, steam generator-based cogeneration and combined cycle
systems.  The results of this analysis can be applied to all  types of
cogeneration units.
     This analysis considers two S02 regulatory alternatives:

     1)   Standards based on the use of low sulfur fuels.
     2)   Standards requiring a percent reduction in SOg emissions based on
          the use of flue gas desulfurization systems.

     The results of this analysis show that the average cost effectiveness
of standards based on low sulfur fuels for coal-fired steam generator-based
cogeneration units is less than $420/ton in all cases.  The average cost
effectiveness of standards requiring a percent reduction in SO^ emissions is
less than $640/ton.  The incremental cost effectiveness of not including an
                                                                  *
emission credit in standards based on the use of low sulfur fuels for
coal-fired steam generator-based cogeneration units varies from  $556/ton in
Region V to $83/ton in Region VIII.  The incremental cost effectiveness of
not including an emission credit in standards requiring a percent reduction
in S0« emissions for coal-fired steam generator-based cogeneration systems
varies from $273/ton in Region V to $500/ton in Region VIII.
     For oil-fired steam generator-based cogeneration units, the average
cost effectiveness of standards based on low sulfur fuels is less than
$510/ton.  The average cost effectiveness of standards requiring a percent
reduction in S02 emissions is less than $460/ton.  The incremental cost
effectiveness of not including an emission credit in standards based on the
use of low sulfur fuels for oil-fired steam generator-based cogeneration

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units is $581/ton.  The incremental  cost effectiveness of not including an
emission credit in standards requiring a percent reduction in S02 emissions
is $167/ton.  These results are generally representative of oil-fired steam
generator-based cogeneration systems in all  ten EPA regions.
     The analysis of fully-fired coal  combined cycle cogeneration units
shows that the average cost effectiveness of standards based on low sulfur
fuels is less than $413/ton in all  cases.  The average cost effectiveness of
standards requiring a percent reduction in S02 emissions is less than
$741/ton.  The incremental  cost effectiveness of not including an emission
credit in standards based on the use of low sulfur fuels for coal-fired
combined cycle cogeneration units varies from $550/ton in Region V to $0/ton
in Region VIII.  The incremental cost effectiveness of not including an
emission credit in standards requiring a percent reduction in SCL emissions
varies from $250/ton in Region V to $1000/ton in Region VIII.
     For oil-fired combined cycle cogeneration units, the average cost
effectiveness of standards  based on low sulfur fuels is less than $640/ton.
The average cost effectiveness of standards  requiring a percent reduction in
S02 emissions is less than  $1000/ton.   The incremental cost effectiveness of
not including an emission credit in standards based on the use of low sulfur
fuels for oil-fired combined cycle cogeneration units is $968/ton for
fully-fired systems and $640/ton for supplementary-fired systems.  The
                                                        «
incremental cost effectiveness of not including an emission credit in
standards requiring a percent reduction in S02 emissions is $333/ton for
fully-fired systems and $292/ton for supplementary-fired systems.  These
results are generally representative of oil-fired combined cycle
cogeneration systems in all ten EPA regions.

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                              1.0  INTRODUCTION

     This cost and cost effectiveness analysis was undertaken in conjunction
with efforts to develop sulfur dioxide (SO-) new source performance
standards for industrial-commercial-institutional steam generating units
with heat input capacities greater than 100 million Btu/hr.  In addition to
conventional systems for industrial steam generation, the analysis of new
source performance standards for SO- emissions control must also consider
other systems for steam generation that are currently being used in industry
and which are potential sources of SO- emissions,  degeneration systems are
one such set of systems and the evaluation of the impacts of alternative S02
emission control standards on these systems is the subject of this report.

Cogeneration Systems

     Cogeneration systems are defined as energy systems that simultaneously
produce both electrical (or mechanical) energy and thermal energy from the
same primary energy source.  Cogeneration systems are efficient
electric/thermal energy production technologies with a potential for local
and regional energy savings and emission reductions.
     Following adoption of the Public Utility Regulatory Policies Act of
1978 (PURPA), there has been increasing interest in the Cogeneration of
electricity at industrial, commercial, and institutional sites.  Under
PURPA, qualifying cogenerators can sell their excess electrical power
directly to electric utility companies who are obligated to purchase the
power at the utilities' avoided cost, making on-site Cogeneration
economically attractive in many cases.
     There are two general types of Cogeneration systems currently in
industrial use:  steam generator-based systems and combined cycle (or gas
turbine-based) Cogeneration systems.   Both systems are considered in this
report and the differences between them are explained in detail below.  Both
systems are efficient generators of electrical energy and steam, and
generally operate at a higher overall thermal efficiency than either an

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electric power plant or an industrial  steam generating unit alone.   As a
result, to generate equivalent amounts of electrical  and thermal  energy, the
total fuel used by a cogeneration facility would be less than the combined
total of fuel used at an utility steam generating unit to generate
electricity and the fuel used at an industrial  steam generating unit to
generate steam for space heat or process needs.

Emission Credits

     The potential for regional energy savings  through the use of a
cogeneration system, compared to the use of separate steam generating units
for electric power generation and industrial steam production, can range
from 5 percent to almost 30 percent depending on the specific industry using
the cogeneration system and the type of fuel used.  This reduced regional
fuel consumption can translate into regional air pollution emission
reductions under certain conditions.  For example, if a cogeneration system
reduces regional fuel use by 15 percent and displaces a utility steam
generating unit firing the same fuel and subject to the same emission
limitation, regional emissions would be similarly reduced by 15 percent.
     Because of this emission reduction potential, it has been suggested
that new source performance standards for industrial-commercial-
institutional steam generating units should include some type of "emission
credit" for the higher efficiencies achieved by cogeneration systems.  Such
a credit, according to its proponents, would reduce the cost of air
pollution control at a cogeneration site, result in equivalent regional
emissions, and encourage the use of cogeneration systems.
     If an emission credit were allowed for cogeneration systems, it would
adjust increase the emission limitation for cogeneration steam generating
units, offsetting any regional emission reduction that might occur from the
use  of the cogeneration system.  For example,  for a coal-fired steam
generating unit subject to an S(L emission limit of 516 ng/J (1.2 Ib/million
Btu) heat input,  a  15 percent emission credit  reflecting the potential
decrease  in  regional emissions would increase  the emission limit to 593 ng/J

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(1.38 lb/million Btu) heat input.  Similarly, for a coal-fired steam
generating unit subject to a percent reduction requirement of 70 or 90
percent, a 15 percent emissions credit would decrease the percent reduction
requirement to 65.5 or 88.5 percent, respectively.
     It may be quite difficult, however, to identify the appropriate
emission credit for specific cogeneration systems.  In cases where different
emission standards are applicable to the displaced fuel fired in a utility
steam generating unit and the fuel fired in the cogeneration system, or
where different fuels are fired in the utility steam generating unit than in
the cogeneration system, the environmental  and fuel use impacts of
cogeneration become less clear.  Where a new cogeneration system achieves
emission levels that are lower than those from the utility steam generating
units, a 15 percent regional energy savings may result in more than a 15
percent reduction in regional emissions.  Conversely, if the cogeneration
system results in emissions higher than the utility steam generating unit, a
15 percent regional energy savings may result in less than a 15 percent
emission reduction.  If hydroelectric or nuclear power generation capacity
is being replaced by cogeneration, regional emissions would increase.  Also
of importance to local emissions is the fact that a larger
industrial-commercial-institutional steam generating unit is used in the
cogeneration system than would otherwise be used.  Consequently, local
                           *
emissions at the cogeneration site increase in all cases.
     To assess the reasonableness of emission credits for cogeneration
systems, the cost effectiveness of S02 emission control associated with not
providing emission credits was examined.  This analysis compared the cost
effectiveness of S02 control among a conventional industrial-commercial -
institutional steam generating unit, a cogeneration steam generating unit
without emission credits, and a cogeneration steam generating unit with
emission credits, and calculated the incremental cost effectiveness of not
providing emission credits.

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Report Outline

     Detailed descriptions of the operation of both steam generator-based
and combined cycle cogeneration systems are presented in Section 2.   Section
3 discusses the rationale for emission credits and shows how the credits
were calculated for this analysis.  Section 4 presents the cost and cost
effectiveness results of the study.   Appendix A contains 8 model cases for
combined cycle cogeneration systems  and Appendix B contains sample
calculations.

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                2.0  COGENERATION SYSTEM PROCESS DESCRIPTIONS

Steam Generator-Based Cogeneration System

     In a steam generator-based cogeneration system, the simultaneous
production of electric power and process heat is achieved by supplying the
steam produced by an industrial-commercial-institutional steam generating
unit to a steam turbine for electric power generation and then recovering
process or space heat from the steam turbine exhaust.  The
industrial-commercial-institutional steam generating unit used for an
on-site cogeneration system would be small  enough that the total  fuel use
during cogeneration would be less than the combined total of the  fuel used
at a utility steam generating unit to generate electricity and the fuel  used
at an industrial steam generating unit to generate steam for space heat and
process needs.
     Figure 1 presents a comparison of the heat inputs and energy inputs for
an electrical generating system, a process-steam system, and a steam
generator-based cogeneration system.  This figure shows that the  steam
generator-based cogeneration consumes approximately 15 percent less fuel to
produce the same amount of energy as the electrical and steam generating
units combined.  Since part of the heat input to a cogeneration steam
generating unit is consumed to generate electricity, a steam generator-based
cogeneration system will have to fire 15 to 25 percent more fuel  than a
conventional steam generating unit to produce the same amount of  steam.   For
example, as shown in Figure 1, if the conventional steam generating unit
fires 150 million Btu per hour, then a steam generating unit based
cogeneration system would fire 183 million Btu per hour (150 million Btu/hr
* [2.75 barrel/2.25 barrel] = 183 million Btu/hr) to produce equivalent
amounts of steam.

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          1 barrel of oil  to produce 600 kWh electricity.


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         systems A and B combined.
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     (D)  Combined cycle cogeneration system  requires the equivalent of 2-1/2
         barrels of oil to generate the same amount of energy as systems
         A and B combined.
Figure 1.  Conventional electrical and process  steam systems  compared with
steam generator-based and  combined  cycle  cogeneration systems.
                                            8

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Combined Cycle (or Gas Turbine-Based) Cogeneration System

     A typical combined cycle cogeneration system consists of a gas turbine
which discharges its hot exhaust flue gas to a steam generating unit.  The
steam generating unit recovers the heat from the gas turbine exhaust.  In
industrial applications, the shaft power produced by the gas turbine is used
for direct mechanical drive (including electric power generation) and the
steam produced by the heat recovery steam generating unit is used for
process heat.
     Figure 1 also shows that the combined cycle cogeneration system
consumes approximately 23 percent less fuel to produce the same amount of
energy as the electrical and steam generating units combined.  As before,
part of the heat input to this cogeneration system is consumed to generate
electricity.  Thus a combined cycle cogeneration system will have to fire 10
to 40 percent more fuel than a conventional steam generating unit to produce
the same amount of steam.  Using the example in Figure 1, if the
conventional unit fires 150 million Btu/hr, then a combined cycle
cogeneration system would fire 167 million Btu/hr (150 million Btu/hr *
[2.50 barrel/2.25 barrel] = 167 million Btu/hr) to produce equivalent
amounts of steam.
     Steam generating units used in combined cycle systems fall into one of
three categories, depending on how much fuel is fired in the steam
generating unit:  unfired, supplementary-fired and fully-fired.  Figure 2
presents a flow diagram for each of these combined cycle configurations.  In
the unfired arrangement, the gas turbine exhaust supplies all of the heat
input to the steam generating unit (i.e., no fuel is fired in the steam
generating unit).  In the supplementary-fired combined cycle system, the gas
turbine provides  approximately 70 percent of the heat input to the steam
generating unit,  with the remaining 30 percent being supplied by the fuel
fired in the steam generating unit.  For a fully-fired arrangement, the gas
turbine exhaust provides approximately 25 percent of the heat input to the
steam generating  unit, with the remaining 75 percent being supplied by fuel
fired in the steam generating unit.

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                                    GENERATOR MEFFICIENCY
                        OAS TURSME
                          EXHAUST
HEAT RECOVERY
STEAM
GENERATING
UNIT
8TfAM.s

MDUSTRIAL
PROCESS
  (A) Unfired combined cycle unit.
                                   GENERATOR MtmCKNCY
                                                       ILKCTRICtTY
                        OAS TURBINE   HEAT RECOVERY
                         EXHAUST  A.      STCAM

                                      GENERATING
                                          UNIT
STEAM.
MDUSTRIAL

 PROCESS
  (B) Fully-fired combined cycle unit.
                                   GENERATOR MEFNCKNCY
                                       GENERATOR
                                                       ELECTIIietTV
NEAT RECOVERY
STEAM
GENERATING
UNIT
•TEAM.
i

                                                            MOUSTRIAL

                                                            PROCESS
  (C) Supplementary-fired combined cycle unit.
Figure 2.   Combined  Cycle  Cogeneration Systems.
                                       10

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     The heat recovery steam generating unit in unfired and supplementary-
fired combined cycle systems is typically a modular finned-tube heat
exchanger.  In the unfired arrangement, the gas turbine exhaust is supplied
directly to the finned-tube heat exchanger.  For the supplementary-fired
arrangement, a limited amount of fuel  is combusted in a grid burner in the
turbine exhaust duct to raise the temperature of the exhaust gases before
they reach the heat exchanger.  Finned-tube heat exchangers are limited to
gas inlet temperatures of approximately 1400°F.  Thus the amount of
supplementary fuel that can be fired is limited.  Also, because of potential
fouling problems, only "clean" fuels such as natural gas or oil can be used
in supplementary-fired combined cycle  systems.
     In a fully-fired combined cycle system, the heat recovery steam
generating unit is a conventional water-wall steam generating unit and the
gas turbine exhaust is used to provide preheated combustion air to the steam
generating unit.  The term "fully-fired" indicates that the steam generating
unit uses all the available oxygen in  the gas turbine exhaust for
combustion.  Fully-fired combined cycle systems can theoretically fire coal,
oil, or natural gas.  However, coal  has not been used as a fuel in the steam
generating unit of combined cycle systems because natural gas and oil-fired
steam generating units have lower capital costs and they are less
complicated, easier to operate, and  require less maintenance than an
equivalent sized coal-fired steam generating unit.
     In summary, the current generation of combined cycle systems fire
gaseous or liquid fuels in both the  gas turbine and the steam generating
unit.  At this time, coal is not used  in combined cycle systems.  However,
coal-firing in the steam generating  unit of a fully-fired combined cycle
system may become a viable option.
                                      11

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                            3.0  EMISSION CREDITS

     As discussed in Section 1.0, cogeneration can potentially reduce
regional energy consumption by 5 to almost 30 percent depending on the
specific industry using the cogeneration system and the type of fuel fired.
This reduced fuel consumption could translate into regional air pollution
emission reductions.  For example, if a cogeneration system reduces fuel use
by 15 percent and displaces a utility steam generating unit firing the same
fuel and subject to the same emission limitations, regional air pollution
emissions would similarly be reduced by 15 percent.
     Because of this emission reduction potential, the question has been
raised as to whether new source performance standards for industrial-
commercial -institutional steam generating units should include some type of
"emission credit" for the higher efficiencies achieved by cogeneration
systems.  An emission credit would reduce the annualized cost of control of
a cogeneration steam generating unit.  However, if an emission credit is
granted for cogeneration systems, it would increase the emission limitation
for cogeneration steam generating units, offsetting any regional emission
reduction that might occur from the use of a cogeneration system.
     Table 1 illustrates how an emission credit for cogeneration systems
could be incorporated into standards based on the use of low sulfur fuel or
standards requiring a percent reduction in emissions.  As shown in this
table, if standards for steam generating units based on the use of low
sulfur fuel limited S02 emissions to 1.2 Ib/million Btu heat input for
coal-fired units and to 0.8 Ib/million Btu heat input for oil-fired units,  a
30 percent cogeneration emission credit would increase these emission limits
to 1.56 Ib/million Btu and 1.04 Ib/million Btu heat input, respectively.
     Fuel pricing data are not available for low sulfur fuels that could
meet emission levels of 1.56 Ib/million Btu heat input for coal and 1.04
ID/million Btu heat input for oil.  Pricing data are available, however, for
low sulfur fuels capable of meeting an emission limit of 1.7 Ib/million Btu
and 1.6 Ib/million Btu heat input for coal  and oil, respectively.   Thus,
this analysis assumed a cogeneration emission credit of 42 percent for
                                     12

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               TABLE 1.  CALCULATION OF STEAM GENERATOR-BASED

                        COGENERATION EMISSION CREDIT
A.   For a standard based on the use of low sulfur fuel  (e.g., 1.2
     lb/million Btu) an emission credit would allow the  steam generating
     unit operator to burn a higher sulfur fuel.

          S02 Emission Limit = 1.2 ID/million Btu

          regeneration Steam Generating Unit S0?  Emission Limit
               with 30 Percent Emission Credit -
               1.2 lb/million Btu x 1.3/1.0 = 1.56 lb/million Btu


B.   For a standard requiring a specific percent  reduction (e.g., 90
     percent), an emission credit would allow the steam  generating unit to
     operate its flue gas desulfurization system  at a lower percent removal

          S02 Percent Reduction Requirement = 90  Percent

          S02 Emissions Permitted = 100 Percent - 90 Percent = 10 Percent

          Cogeneration Steam Generating Unit S02  Emission Limit
               with 30 Percent Emission Credit:
               10 Percent x 1.3/1.0 = 13 Percent

          Cogeneration Steam Generating Unit S02  Percent Reduction
          Requirement with 30 Percent Emission Credit =
               100 Percent - 13 Percent = 87 Percent.
                                     13

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coal-fired steam generating units and 100 percent for oil-fired steam
generating units in order to use available fuel  pricing data.
     For a standard requiring a 90 percent reduction in S02 emissions from
steam generating units, a 30 percent cogeneration emission credit reduces
this percent reduction requirement to 87 percent.  Thus, percent reduction
requirements of 90 and 87 percent were examined to determine whether an
emission credit for cogeneration systems under standards requiring a percent
reduction in SO^ emissions is reasonable.

Combined Cycle Cogeneration Systems

     Table 2 demonstrates how an emission credit for combined cycle
cogeneration systems could be incorporated into standards based on the use
of low sulfur fuel or standards requiring a percent reduction in S0£
emissions for steam generating units.  The magnitude of the cogeneration
emission credit is determined by dividing the total heat input (steam
generating unit fuel + gas turbine exhaust) into the steam generating unit
by the heat input of the fuel fired in the steam generating unit.  For
fully-fired combined cycle systems, the resulting emission credit is in the
range of 30 to 35 percent, depending on whether coal or oil is fired in the
steam generating unit.  For supplementary-fired combined cycle systems, the
emission credit is around 210 percent, since most of the heat input to the
steam generating unit is provided by the gas turbine exhaust.
     As discussed earlier in the steam generator-based cogeneration section,
the cogeneration emission credit was increased in several cases to reflect
available fuel pricing data.  As a result, for standards based on the use of
low sulfur fuel, the combined cycle cogeneration analysis assumed emission
credits of:

1)   42 percent for fully-fired coal combined cycle steam generating units
     (i.e., 1.7 ID/million Btu emission limit),
                                      14

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    TABLE 2.  CALCULATION OF COMBINED CYCLE COGENERATION EMISSION CREDIT
A.   For a standard based on the use of low sulfur coal, (e.g., 1.2
     ID/million Btu) an emission credit would allow the steam generating
     unit to fire  a higher sulfur coal.

     S02 Emission Ceiling = 1.2 Ib/million Btu

     S02 Emission Limit With Emission Credit =

          1.2 Ib/million Btu x (   Total Heat Input	 }
                                 Steam Generating Unit
                                    Fuel Heat Input

     where Total Heat Input = Steam Generating Unit Fuel Heat Input +
                              Gas Turbine Exhaust Heat Input

     Example:  For a combined cycle cogeneration unit with a steam
          generating unit fuel heat input of 100 million Btu/hour
          and a gas turbine exhaust heat input of 37 million Btu/hour,

     S02 Emission Limit with Emission Credit =

          1.2 Ib/million Btu x 137 mil]1on Btu/hr = 1.64 Ib/million Btu
                               100 million Btu/hr

B.   For a standard requiring a percent reduction in S0? emissions, (e.g.,
     90 percent) an emission credit would allow the steam generating unit to
     operate the flue gas desulfurization system at a lower percent removal.

     S02 Percent Reduction Requirement Without Emission Credit = 90 percent

     S02 Emissions Level Permitted = 100-90 = 10 percent

     S02 Percent Reduction Requirement with Emission Credit =

          100 - [10 Percent x   Total  Heat Input	-,
                              Steam Generating Unit
                                 Fuel  Heat Input

     where Total Heat Input = Steam Generating Unit Fuel  Heat Input +
                              Gas Turbine Exhaust Heat Input

     Example:  For a combined cycle cogeneration unit with a steam
          generating unit fuel heat input of 100 million Btu/hour
          and a gas turbine exhaust heat input of 37 million Btu/hour,

     Percent Reduction Requirement With Emission Credit =

          100 Percent - [10 Percent x 137 m111ion Btu/hr] = 86 percent
                                      100 million Btu/hr
                                     15

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2)   100 percent for fully-fired oil  combined cycle steam generating units
     (i.e., 1.6 Ib/million Btu emission limit), and

3)   275 percent for supplementary-fired oil  combined cycle steam generating
     units (i.e., 3.0 Ib/million Btu  emission limit).

For standards requiring a percent reduction in 862 emissions,  the emission
credits examined were:

1)   40 percent for fully-fired coal  combined cycle steam generating units
     (i.e., 86 percent S02 reduction),

2)   30 percent for fully-fired oil  combined  cycle steam generating  units
     (i.e., 87 percent S02 reduction), and

3)   215 percent for supplementary-fired oil  combined cycle steam generating
     units (i.e., 69 percent S02 reduction).
                                     16

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                             4.0  COST ANALYSIS

     This analysis examines the reasonableness of emission credits for
cogeneration facilities under two regulatory alternatives for S02 new source
performance standards:

     1)   Standards based on the use of low sulfur fuels.

     2)   Standards requiring a percent reduction in S02 emissions based on
          the use of flue gas desulfurization systems.

     All costs presented in this analysis are in January 1983 dollars and
all flue gas desulfurization costs are based on sodium scrubbing technology.
Information obtained on paper, chemical, and petroleum refining industry
cogeneration systems show that these facilities usually operate at an annual
capacity factor of about 0.9.   Consequently, an annual capacity factor of
0.9 was assumed in this analysis.
     Regions V and VIII were selected for analysis of the coal-fired
cogeneration steam generating units in this report - Region V because coal
prices in that region are considered representative of those in the majority
of the regions, and Region VIII because it has significantly lower coal
                             2
prices than any other region.   Oil-fired cogeneration steam generating
units were examined for Region V only because the premium price for a low
sulfur oil compared to a high sulfur oil is essentially constant for all
        2
regions.   Table 3 presents the regional coal and oil prices for all ten EPA
regions.

4.1  Steam Generator-Based Cogeneration Systems

Coal-Fired Steam Generating Units

     Tables 4 and 5 present the results of this analysis for coal-fired
cogeneration steam generating units in Regions V and VIII, respectively.  As
                                     17

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                            TABLE  3.   REGIONAL  FUEL  PRICES  IN  $/MILLION  BTU (JANUARY  1983  $)a'b»c
00
                'Reference 2.
                b
Fuel Type
COAL
Bituminous
B
0
E
F
G
H
Subbi luminous
B
0
£
RESIDUAL OIL ,
0.8 Ib S02/10°
NATURAL GAS
Sulfur Content
(Ib S02/10° Btu)


0.80
1.08
1.67
2.50
3.33
>l

O.BO
1.08
1.67

BTUe 0



- 1.08
- 1.67
- 2.50
- 3.33
- 5.0
.00

- 1.08
- 1.67
- 2.50

.80
-
d 1


3.76
3.71
3.65
3.46
3.16
3.26

-
-
-

5.50
5.83
II


3.52
3.45
3.30
3.13
2.82
2.85

-
-
-

5.49
5.79
HI


3.14
2.94
2.85
2.75
2.42
2.39

-
-
-

5.49
5.73
IV


3.19
2.98
2.96
2.88
2.80
2.62

-
-
-

5.46
6.02
REGION
V VI


3.32
3.18
3.08
2.93
2.67
2.50

3.38
3.34
3.30

5.63
5.88


3.34
3.21
3.20
3.19
3.09
2.96

3.49
3.39
3.32

5.49
5.41
VII


3.14
3.08
3.04
2.92
2.62
2.47

2.74
2.69
2.72

5.60
5.45
VIII


1.99
1.86
1.87
.
_
-

1.40
1.39
1.28

5.29
4.91
IX


2.80
2.82
2.77
„
.
-

2.84
2.74
2.65

5.11
5.44
X


3.18
2.97
2.84

_
-

2.66
2.60
2.09

5.07
5.57
                 1990 levelized fuel  prices in January 1983 dollars.
                cTo convert J/106 Btu to $/kJ. multiply by 0.947.
                dTo convert lb/106 Btu to ng/J. multiply by 430.
                "Subtract  SO.69/106 Btu for 3.0 lb,SO?/106 Btu oil; subtract JO.36/106 Btu  for 1.6 Ib SO-/106 Btu oil; add
                  $0.34/10° Btu for  0.3 Ib S02/10° Btu oil.                                        e

-------
                    TABLE  4.  COST AND COST EFFECTIVENESS OF S02  CONTROL FOR CONVENTIONAL
                        AND COGENERATIOM COAL-FIRED  STEAM GENERATING UNITS  IN REGION  Va
Steam Generating Unit
Conventional Unit (150 million Btu/hr)
Regulatory Baseline (2.5 Ib/million Btu)
Low Sulfur Fuel (1.2 Ib/million Btu)
Percent Reduction (90 Percent)
Cogeneration Unit U/0 Credit (180 million Btu/hr)
Regulatory Baseline (2.5 Ib/million Btu)
Low Sulfur Fuel (1.2 Ib/million Btu)
Percent Reduction (90 Percent)
Cogeneration Unit U/Credit (180 million Btu/hr)
Regulatory Baseline (2.5 Ib/mlllion Btu)
Low Sulfur Fuel (1.7 Ib/million Btu)d
Percent Reduction (87 Percent)*
Fuel Type,
(Ib S02/m1llion Btu)

2.10
0.95
5.54

2.10
0.95
5.54

2.10
1.45
5.54
Annual 1 zed
Costs,
$1000/yr

8,710
8,990
9,260

10,088
10,430
10.720

10.088
10,230
10.690
Annual
Emissions,
(tpy)

1,240
560
250

1.490
670
300

1.490
1,030
410
Average
Cost b
Effectiveness,
($/ton)

_
412
556

.
417
531

309
558
Incremental
Cost
Effectiveness,
($/ton)

—
—
871

_
.
784

742
aBased on a  capacity factor of 0.9.
 Compared to regulatory baseline.
cCompared to less stringent alternative.
 mh a 30 percent emission credit, a  low sulfur coal emission limit of 516 ng SO?/J (1.2 Ib S0,/m1111on Btu) would increase to 671 ng SO /J
 (1.56 Ib  S02/million Btu).  Pricing data are not available, however, for a coal  Capable of meeting this emission  limit.  Therefore, this2
 analysis  assumed an emission credit of 42 percent in order to use available pricing data for a  coal meeting a 731 ng 50,/J (1 7 Ib
 S02/mill1on Btu) emission limit.                                                                                 2
eBased on  a 30 percent emission credit.
 Average uncontrolled SO- emissions.

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l\3
O
                           TABLE  5.   COST  AND  COST  EFFECTIVENESS  OF S02 CONTROL  FOR  CONVENTIONAL
                            AND COGENERATION COAL-FIRED  STEAM  GENERATING UNITS  IN REGION  VIII3
Steam Generating Unit
Conventional Unit (150 million Btu/hr)
Regulatory Baseline (2.5 Ib/mlllion Btu)
Low Sulfur Fuel (1.2 Ib/million Btu)
Percent Reduction (90 Percent)
Cogeneratlon Unit W/0 Credit (180 million Btu/hr)
Regulatory Baseline (2.5 Ib/million Btu)
Low Sulfur Fuel (1.2 Ib/million Btu)
Percent Reduction (90 Percent)
Cogeneratlon Unit U/Credlt (180 million Btu/hr)
Regulatory Baseline (2.5 Ib/million Btu)
Low Sulfur Fuel (1.7 Ib/million Btu)d
Percent Reduction (87 Percent)6
Fuel Type,
(Ib S02/million Btu)

2.10
0.95
0.95

2.10
0.95
0.95

2.10
1.45
0.95
Annual 1 zed
Costs,
$1000/yr

6,710
6,860
7,480

7,680
7,860
8,570

7,680
7,830
8,560
Annual
Emissions,
(tpy)

1,240
560
40

1,490
670
50

1,490
1.030
70
Average
Cost h
Effectiveness,
($/ton)

-
221
642

-
220
618

-
326
620
Incremental
Cost
Effectiveness,
($/ton)

-
-
1,192

-
-
1,145

-
-
760
        aBased on a  capacity factor of 0.9.
        Compared to regulatory baseline.
        ""Compared to less stringent alternative.
        dWith a 30 percent emission credit, a low sulfur coal  emission limit of 516 ng S02/J (1.2 Ib S02/m1llion Btu) would increase to 671 ng S02/J
         (1.56 Ib S09/m1111on Btu).  Pricing data are not available, however, for a coal capable of meeting this emission limit.  Therefore, this
         analysis assumed an emission credit of 42 percent in  order to use available pricing data for a coal meeting a 731 ng S02/J (1.7 Ib
         S02/mil11on Btu) emission limit.
        eBased on a  30 percent emission credit.
        fAverage uncontrolled S0? emissions.

-------
shown, the cost effectiveness of S02 control for standards based on the use
of low sulfur coal are similar for a conventional  steam generating unit, a
cogeneration steam generating unit without an emission credit, and a
cogeneration unit with an emission credit.  For example, the average cost
effectiveness of SO^ emission control in Region V is $412/ton for a
conventional steam generating unit; $417/ton for a cogeneration unit without
an emission credit; and $309/ton for a cogeneration unit with an emission
credit.  Similarly, in Region VIII the average cost effectiveness of
emission control is $221/ton for a conventional steam generating unit;
$220/ton for a cogeneration unit without an emission credit; and $326/ton
for a cogeneration unit with an emission credit.
     The same is true for the cost effectiveness of SO^ control for
standards requiring a percent reduction in emissions from coal-fired steam
generating units.  The incremental cost effectiveness of S02 emission
control associated with standards requiring a percent reduction in emissions
over standards based on the use of low sulfur fuels in Region V is $871/ton
for a conventional steam generating unit; $784/ton for a cogeneration unit
without an emission credit; and $742/ton for a cogeneration unit with an
emission credit.  Similarly, in Region VIII the incremental cost
effectiveness of emission control is $l,192/ton for a conventional steam
generating unit; $l,145/ton for a cogeneration unit without an emission
credit; and $760/ton for a cogeneration unit with  an emission credit.
     The significant reduction in the incremental  cost effectiveness of
emission control for standards requiring a percent reduction in Region VIII
for a cogeneration steam generating unit with an emission credit compared to
the incremental cost effectiveness without an emission credit is due to
price differentials between coals fired under the  low sulfur coal
alternative.  The emission credit would permit the firing of a higher sulfur
and lower cost coal in the cogeneration steam generating unit.  In Region
VIII, the cost savings achieved by firing a higher sulfur coal are minor
(approximately $30,000 per year) due to a small difference in price.  The
annual emissions, however, increase by some 360 tons per year.  The lowering
of the percent reduction requirement from 90 to 87 percent due to the
                                     21

-------
cogeneration emission credit results in a negligible reduction in costs and
only a minor increase in emissions.  As a result, the incremental emissions
reduction of a percent reduction standard over a low sulfur coal  standard is
much greater for a cogeneration steam generating unit with an emissions
credit than without an emissions credit, which translates to a significantly
lower incremental cost effectiveness value.
     In Region V, the annualized costs (i.e., fuel  prices) and emissions
vary in roughly the same proportion so that  similar incremental cost
effectiveness values are observed for cogeneration  steam generating units
with and without an emission credit.
     As shown in Table 6j the incremental cost effectiveness of not
providing emission credits with standards based on  the use of low sulfur
coal is $556/ton in Region V and $83/ton in  Region  VIII.  Similarly, the
incremental cost effectiveness of not providing emission credits  with
standards requiring a percent reduction in emission is only $273/ton in
Region V and $500/ton in Region VIII.

Oil-Fired Steam Generating Units

     Table 7 summarizes the cost effectiveness of S02 control for oil-fired
steam generating units.  As shown, for both  conventional steam generating
units and cogeneration steam generating units without emission credits, the
lowest cost option to comply with a standard based  on the use of  low sulfur
fuel is to purchase a high sulfur oil and use flue  gas desulfurization.
With a cogeneration emission credit, however, a higher sulfur and lower cost
oil may be fired in the steam generating unit to meet a low sulfur fuel
standard.  In this case, it is less expensive to fire a low sulfur oil  than
to fire a high sulfur oil and use flue gas desulfurization.
     For standards based on the use of low sulfur oil, the average cost
effectiveness of S02 control for a conventional steam generating  unit is
$510/ton, compared with $494/ton for a cogeneration steam generating unit
without an emission credit and $442/ton for  a cogeneration steam  generating
unit with an emission credit.
                                     22

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                       TABLE 6.   INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING AN  EMISSION  CREDIT


                                    FOR COAL-FIRED COGENERATION STEAM GENERATING UNITS
ro
co


Low Sulfur Fuel Standard
With Emission Credit (1.7 lb/106 Btu)
Without Emission Credit (1.2 lb/106 Btu)
Percent Reduction Standard
With Emission Credit (87% FGD)
Without Emission Credit (90S FGD)

Annual izcd
Cost
JlOOO/yr

10,230
10,430

10.690
10,720
REGION V
Annual
Emissions,
(tpy)

1,030
670

410
300
REGION VIII
Incremental Cost
Effectiveness
($/ton)

-
556

-
273
Annualized
Cost
$1000/yr

7,830
7,860

8,560
8,570
Annual
Emissions,
(tpy)

1,030
670

70
50
Incremental Cost
Effectiveness
($/ton)

-
83

-
500

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ro
                         TABLE 7.  COST AND COST EFFECTIVENESS OF  S02  CONTROL FOR CONVENTIONAL
                                  AND COGENERATION  OIL-FIRED STEAM GENERATING UNITS3



Steam Generating Unit
Conventional Unit (150 million Btu/hr)
Regulatory Baseline (3.0 Ib/million Btu)
Low Sulfur Fuel (0.8 Ib/million Btu)e
Percent Reduction (90 Percent)
Cogeneration Unit M/0 Credit (1BO million Btu/hr)
Regulatory Basel ine (3.0 Ib/million Btu)
Low Sulfur Fuel (0.8 Ib/million Btu)e
Percent Reduction (90 Percent)
Cogeneration Unit W/Credit (180 million Btu/hr)
Regulatory Baseline (3.0 Ib/million Btu)
Low Sulfur Fuel (1.6 Ib/million Btu)f
Percent Reduction (87 Percent)9
'Assumes a capacity factor of 0.9.
Average uncontrolled S0« emissions.
cCompared to regulatory baseline.
Compared to less stringent alternative.
elt is less expensive to fire a high sulfur oil [1
reduction than to purchase a low sulfur oil [344

k
Fuel Tyoe,
(Ib S02/10° Btu)

3.0
3.0/731 FGD
3.0/90% FGD

3.0
3.0/73% FGD
3.0/90% FGD

3.0
1.6
3.0/87% FGD




,291 ng SO,/J (3 Ib
ng S02/J (6.8 Ib S0»
With a 30 percent emission credit, a low sulfur oil emission limit of
(1.04 Ib SO./milllon Btu). Pricing data are not available, however,

Annual ized

Annual
Costs, Emissions,
$1000/yr

7,190
7,860
7,940

8.490
9,270
9,360

8.490
8.930
9.350




S(L/mill1on Btu)]
/million Btu)].
344 ng S02/J (0.8
for a coal capable
(tpy)

1,770
455
135

2.130
550
160

2,130
1,135
220




and install
Average
Cost
Effectiveness
($/ton)

-
510
459

-
494
442

_
442
450




an FGD system to
Incremental
r Cost A
. Effectiveness,
($/ton)

_
_
250

_
-
231

„
_
459




achieve 73 percent
Ib S02/m1111on Btu) would Increase to 447 ng .SO-/J
of meeting this emission limit. Therefore, this
analysis assumed an emission credit of 100 percent in order to use available pricing data for a coal meeting a 688
Cfi /millirtn RtiM amice-inn limit
ng S02/J (1.6 Ib
         t
       9Based on a 30 percent emission credit.

-------
     For standards requiring a percent reduction in S02 emissions, the
incremental cost effectiveness of emission control  over standards based on
the use of low sulfur fuel is $250/ton for a conventional steam generating
unit; $231/ton for a cogeneration unit without an emission credit; and
$459/ton for a cogeneration unit with an emission credit.
     As shown in Table 8, the incremental cost effectiveness of not
providing emission credits is $581/ton for standards based on the use of low
sulfur fuel and $167/ton for standards requiring a  percent reduction in 502
emissions.

4.2  Combined Cycle Cogeneration Systems

Coal-Fired Steam Generating Units

     Tables 9 and 10 present the cost effectiveness of S02 control for a
fully-fired coal combined cycle steam generating unit in Regions V and VIII,
respectively.  For comparison, the cost effectiveness of SO^ control for a
conventional steam generating unit and a mixed fuel-fired steam generating
unit (natural gas/coal) is also included.  Mixed fuel-fired units are
included in the analysis since, like combined cycle cogeneration units, a
portion of the heat input to the steam generating unit comes from nonsulfur-
bearing fuels (in this case natural  gas).  The annualized costs for mixed
fuel-fired steam generating units are higher than those for other units in
Tables 9 and 10 because the cost of natural gas has been included along with
coal fuel costs.  However, since natural gas does not contribute to S02
emissions and cost effectiveness values depend on cost differences between
alternatives, the average and incremental cost effectiveness values cited in
the tables are not influenced by the inclusion of natural gas costs.
     It should also be noted that, for a percent reduction requirement in
Region VIII, the fuel  prices in this region are such that it is less
expensive to fire a low sulfur coal  and use flue gas desulfurization (FGD)
than to fire a higher sulfur coal and apply an FGD  system.  This is because
the delivered price of low sulfur subbituminous coal is well below the price
                                     25

-------
  TABLE  8.   INCREMENTAL  COST  EFFECTIVENESS OF WITHHOLDING  EMISSION CREDITS

              FOR OIL-FIRED COGENERATION  STEAM GENERATING  UNITS

Annual ized
Cost
$1000/yr
Annual
Emissions
(tpy)
Incremental Cost3
Effectiveness
($/ton)
Low Sulfur Fuel  Standard

  With Emission  Credit
  (1.6 lb/10° Btu)

  Without Emission Credit
  (0.8 lb/106 Btu)

Percent Reduction Standard
                               8,930
                               9,270'
1,135
  5501
 Compared  to  less  stringent  alternative.
581
With Emission Credit
(87% FGD/3.0 lb/10° Btu)
Without Emission Credit
(90% FGD/3.0 lb/10b Btu)
9,350
9,360
220
160
167
'Based  on  firing  a  high  sulfur  oil  [1,291  ng  S02/J  (3.0  Ib S02/million  Btu)]
 and  using an  FGD system to  achieve 73  percent  reduction.
                                     26

-------
 TABLE  9.    COST AND  COST  EFFECTIVENESS  OF  S02  CONTROL  FOR STANDARD  BOILERS  AND
             COMBINED  CYCLE COAL-FIRED  STEAM  GENERATING UNITS IN  REGION Va

                                              Fully-Fired  Coal
Fuel Type.h
Stem Generating Unit (Ib SOj/mlllion Stul
Conventional Unit (100 Million Btu/hr)
Regulatory Baseline (2.5 Ib/mllllon Btu)
Low Sulfur Fuel (1.2 Ib/m1111on Btu)
Percent Reduction (90 Percent)
Mixed Fuel Unit (137 pillion Btu/hr)
Regulatory Baseline (2.5 Ib/mllllon Btu)
low Sulfur Fuel (1.7 Ib/mllllon Btu)
Percent Reduction (90 Percent)

2.10
0.95
5.54

2.10/NG
0.95 NG
5.54 NG
Steam
Generating Gas Turbine
Unit Enhaust Annuallzed
Heat Input Neat Input Costs,
(10B Btu/hr) (10B Btu/hr) (11000/yr)

100 2 ,430
2.620
2.850

137 . 4.1409
4.3309
4.590'
Annual Average Cost Incremental Cost
Emissions Effectiveness Effectiveness
(tpy) ($/ton)c ($/tonr

830
370 413
170 636

830
370 413
170 68?

-
-
1.150

-
-
1,300
Combined Cycle Unit U/0 Credit (137 million Btu/hr)
Regulatory Baseline (2.S Ib/m1ll1on Btu)
Low Sulfur Fuel (1.2 Ib/mllllon Btu)
Percent Reduction (90 Percent)
Combined Cycle Unit W/CredU (137 Billion Btu/hr)
Regulatory Baseline (2.S Ib/mllllon Btu)
lo* Sulfur Fuel (1.7 Ib/nUHon Btu)'
Percent Reduction (86 Percent)'
2.10
0.95
5.54

2.10
1.45
5.54
100 37 2 ,430
2,620
2,880

100. 37 2.430
2,510
2.860
830
370 413
170 68?

830
S70 308
250 741
-
-
1,300

-
-
J.094
*Bised on a capacity factor of 0.9.

 Annual cost Includes only the cost of fuel  fired plus the annua!1«d cost of SOj control device and does not include other steam generating unit
 annualIzed costs.

'Compared to regulatory baseline.

 Compared to less stringent alternative.

e8ased on the heat  Input supplied by the gas turbine e»haust.  Credit Is calculated as 137/100, or 37 percent.  This would translate Into an
 mission limit of  706 ng SO./J  (1.64 Ib SO./milllon Btu).  Pricing data are not available, however, for a coal capable of Meeting this mission
 limit.  Therefore, this analysis assumed an emission credit of 42 percent in order to use available pricing data for a coal meeting a 731 ng
 $0?/J (1.7 Ib SXymiUion Btu)  emission limit.

 Based on a 40 percent emission  credit.

'Annuallzed costs for mlled fuel-fired steam generating units are higher than those for other units e«*mined because the cost of naturjl gas
 fuel has been Included along with coal fuel costs.

 Average uncontrolled SO, missions.
                                                          27

-------
   TABLE  10.    COST  AND  COST EFFECTIVENESS  OF  S02  CONTROL  FOR  STANDARD BOILERS AND
          COMBINED  CYCLE  COAL-FIRED STEAM GENERATING  UNITS  IN EPA REGION  VIII3
                                                 Fully-Fired Coal
Fuel Type."
Steam Generating Unit (Ib SO^/milllon Btu)
Conventional Unit (100 Million Btu/hr)
Regulatory (asellne (2.5 1b/m1111on Btu)
Loo Sulfur Fuel (1.2 Ib/m1ll1on Stu)
Percent Reduction (90 Percent)
Mixed Fuel Unit (137 Million Btu/hr)
Regulatory Baseline (2.S Ib/ntlllon Btu)
Low Sulfur Fuel (1.2 Ib/mllllon Btu)
Percent Reduction (90 Percent)

2.10
0.9S
0.95

2.10/NG
0.9S/NG
0.95/HG
Steam
Generating Gas Turbine
Unit t»haust Annual ized
Heal Input Heat Input Costs,
(10B Btu/hr) (10* Btu/hr) (JlOOO/yr)

100 - 1,101
1.100
1,570

137 - 2.4409
2.5309
3.0209
Annual Average Cost Incremental Cost
Emissions Effectiveness Effectiveness
(tpy) (J/ton)c ($/ton)B

830
370 196
30 700

830
370 196
30 725

.
.
1,38;

.
.
1.4*1
Combined Cycle Unit U/0 Credit (137 million Btu/hr)
Regulatory Baseline (2.S Ib/mllllon Btu)
Low Sulfur Fuel (1.2 Ib/mllllon Btu)
Percent Reduction (9X1 Percent)
Contained Cycle Unit If/Credit (137 Billion Btu/hr)
Regulatory Baseline (2.S Ib/mlllion Btu)
Low Sulfur Fuel (1.7 Ib/ailllton Btu)e
Percent Reduction (86 Percent)*
2.10
0.95
0.95

2.10
1.45
0.9S
100 37 1 .010
1,100
1.600

100 37 1.010
1.100
1,590
830
370 196
30 738

830
570 346
40 734
-
-
1,471

-
-
924
'Based on a capacity factor of 0.9.
^Annual cost  Includes only the cost of fuel fired plus the annuallzed cost of  SOj control device and does not Include other steam generating unu
 annualIzed costs.
 cConpjred to  regulatory baseline.
 Compared to  less stringent alternative.
'Based on the heat Input supplied by the gas turbine exhaust.  Credit Is calculated as 137/100, or 37 percent. TMs would translate Into an
 emission limit of 706 ng SO-/J  (1.64 Ib S0,/m1111on Btu).  Pricing data are not available, however, for a coal capable of meeting this emission
 limit.  Therefore, this analysis assumed ah emission credit of 42 percent In order to use available pricing data for a coal meeting a 731 ng
 S02/J (1.7 Ib SOg/mUllon Btu)  emission limit.
 Based on a 40 percent emission  credit.
^Annuallzed costs for mixed fuel-fired steam generating units  are higher than those for other units examined because the cost of natural gas
 fuel has been Included along with coal fuel costs.
 Average uncontrolled SOj Missions.
                                                             28

-------
of higher sulfur bituminous coals.   Although some higher sulfur content
subbituminous coals are available in the region,  the added operating and
maintenance costs associated with the FGD system  (due to higher sulfur
loadings) outweigh the small price  advantage these coals enjoy over low
sulfur coal.  This low sulfur subbituminous coal  is the lowest cost fuel to
fire in this region even when a percent reduction requirement is in force.
In Region V, on the other hand, it  is less expensive to fire a high sulfur
coal and apply FGD to meet a percent reduction in emissions requirement.
     As shown, the cost effectiveness of S02 control for standards  based on
the use of low sulfur coal are similar for a conventional steam generating
unit, a mixed fuel-fired steam generating unit, a combined cycle
cogeneration steam generating unit  without an emission credit, and  a
combined cycle cogeneration steam generating unit with an emission  credit.
For example, the average cost effectivness of SO,, emission control  in Region
V is $413/ton for a conventional steam generating unit; $413/ton for a mixed
fuel-fired steam generating unit; $413/ton for a  combined cycle cogeneration
unit without an emission credit; and $308/ton for a combined cycle
cogeneration unit with an emission  credit.  Similarly, in Region VIII the
average cost effectiveness of emission control is $196/ton for a
conventional steam generating unit; $196/ton for  a mixed fuel-fired unit;
$196/ton for a combined cycle cogeneration unit without an emission credit;
and $346/ton for a combined cycle cogeneration unit with an emission credit.
     The same is true for the cost  effectiveness  of SCL control for
standards requiring a percent reduction in emissions from steam generating
units.  The incremental cost effectiveness of emission control associated
with standards requiring a percent  reduction in emissions over standards
based on the use of low sulfur fuels in Region V  is $1,ISO/ton for  a
conventional steam generating unit; $l,300/ton for a mixed fuel-fired unit;
$l,300/ton for a combined cycle cogeneration unit without an emission
credit; and $l,094/ton for a combined cycle cogeneration unit with  an
emission credit.  Similarly, in Region VIII the incremental cost
effectiveness of emission control is $l,382/ton for a conventional  steam
generating unit; $l,441/ton for a mixed fuel-fired unit; $l,471/ton for a
                                      29

-------
combined cycle cogeneration unit without an emission credit; and $924/ton
for a combined cycle cogeneration unit with an emission credit.
     As discussed previously under coal-fired steam generator-based
cogeneration systems, the small fuel price differential in Region VIII
between medium sulfur and low sulfur coals, gives rise to a significant
difference in the average cost effectiveness values cited above for
standards based on the use of the low sulfur fuel when comparing combined
cycle cogeneration systems operating with and without an emissions credit.
This fuel price behavior also explains the lower incremental cost
effectiveness value for standards requiring a percent reduction in emissions
over standards based on the use of low sulfur fuel in this region for
combined cycle cogeneration units operating with an emission credit versus
units operating without a credit.
     As shown in Table 11, the incremental cost effectiveness of not
providing emission credits with standards based on the use of low sulfur
coal is $550/ton in Region V and $0/ton in Region VIII.  Again, this
difference is due entirely to the difference in fuel price between medium
and low sulfur coal in these regions.
     The incremental cost effectiveness of not providing emission credits
with standards requiring a percent reduction in emissions is $250/ton in
Region V and $1000/ton in Region VIII.  Table 11 shows that there is very
little difference in annualized costs for combined'cycle cogeneration steam
generating units meeting a percent reduction standard with an emission
credit or without a credit.  However, as noted above, combined cycle
cogeneration units will fire high sulfur coal (5.54 Ib/million Btu) in
Region V to meet the percent reduction requirement and low sulfur coal (0.95
ID/million Btu) in Region VIII.  The emission credit reduces the percent
reduction requirement from 90 to 86 percent, or 4 percent.  The difference
in S02 emissions is minimal when applied to low sulfur coal in Region VIII
but is magnified when applied to high sulfur coal in Region V.  As a result,
the emissions reduction between a standard percent requiring a reduction in
emissions with an emissions credit and the same standard without a credit is
much smaller in Region VIII than Region V.  Since cost differences are
                                     30

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                           TABLE 11.  INCREMENTAL COST EFFECTIVENESS OF NOT  PROVIDING AN
                                     EMISSION CREDIT FOR COMBINED CYCLE UNITS
                                                 Fully-Fired Coal
CO


Low Sulfur Fuel Standard
With Emission Credit (1.7 lb/106 Btu)
Without Emission Credit (1.2 lb/106 Btu)
Percent Reduction Standard
With Emission Credit (86% FGD)
Without Emission Credit (90% FGD)

Annual ized
Cost
$1000/yr

2,510
2,620

2,860
2,880
REGION V
Annual
Emissions,
(tpy)

570
370

250
170

Incremental Cost
Effectiveness
($/ton)

-
550

-
250

Annual 1 zed
Cost
. $1000/yr

1,100
1,100

1,590
1,600
REGION VIII
Annual
Emissions.
(tpy)

570
370

40
30

Incremental Cost
Effectiveness
($/ton)

-
0

-
1,000

-------
roughly equal, the overall result is a higher incremental cost effectiveness
value in Region VIII as compared to Region V.

Oil-Fired Units

     Table 12 summarizes the cost effectiveness of S02 control for
fully-fired and supplementary-fired oil-fired combined cycle systems and
conventional oil-fired steam generating units.  For standards based on the
use of low sulfur fuels, the average cost effectiveness of S02 control is
$640/ton for a conventional steam generating unit; $640/ton for a mixed
fuel-fired steam generating unit; $640/ton for a fully-fired combined cycle
steam generating unit without an emission credit; and $455/ton for a
fully-fired combined cycle steam generating unit with an emission credit.
For standards requiring a percent reduction in S(L emissions, the
incremental cost effectiveness of S02 control over standards based on the
use of low sulfur fuels is $44/ton for a conventional steam generating unit;
$87/ton for a mixed fuel-fired steam generating unit; $130/ton for a
fully-fired combined cycle steam generating unit without an emission credit;
and $628/ton for a fully-fired combined cycle steam generating unit with an
emission credit.
     The cost effectiveness of S02 control is generally higher for
supplementary-fired combined cycle steam generating units than for
fully-fired combined cycle steam generating units, particularly in the case
of standards requiring a percent reduction in S02 emissions, regardless of
whether or not emission credits are provided.  As shown in Table 12, for
standards based on the use of low sulfur fuels the average cost
effectiveness of S02 control is $640/ton for a mixed fuel-fired steam
generating unit; $640/ton for a supplementary-fired combined cycle steam
generating unit without an emission credit, and $0/ton for a
supplementary-fired steam generating unit with an emission credit.  With an
emission credit, the credit is so large that no emission reduction is
required beyond the regulatory baseline.  As a result, the cost
effectiveness is $0/ton.
                                     32

-------
       TABLE  12.    COST  AND  COST  EFFECTIVENESS  OF  S02  CONTROL  FOR CONVENTIONAL  AND

               COMBINED  CYCLE  OIL-FIRED  STEAM  GENERATING  UNITS   IN  EPA  REGION  Va
                                                             Steam
                                                           Generating    Gas Turbine
                                                              Unit
Steam Generating Unit
Conventional Unit (100 million Btu/hr)
Regulatory Baseline (3.0 Ib/million Btu)
low Sulfur Fuel (0.8 Ib/m1ll1on Btu)
Percent Reduction (90 Percent)
Fully- Fired
Nixed Fuel Unit (129 •illlon Btu/hr)
Regulatory Baseline (3.0 Ib/mllllon Btu)
low Sulfur Fuel (0.8 Ib/million Btu)
Percent Reduction (90 Percent)
Combined Cycle Unit W/0 Credit (129 million
Regulatory Baseline (3.0 Ib/m1ll1on Btu)
low Sulfur Fuel (0.8 Ib/mlllton Btu)
Percent Reduction (90 Percent)
Fuel Type,
(Ib S0;/m111ion Btu)

3.0
0.8
3.0/901 FGO


3.0/NG
0.8/NG
3.0/NG
Btu/hr)
3.0
0.8
3.0/901 FGD
Heat Input Heat Input Costs,
(10° Btu/hr) (10° Btu/hr) ($1000/yr)

100 - 3,890
4.440
4.450


129 - 5.240J
5.790J
S.810J

100 29 3,890
4,440
4,470
Emissions
(tpy)

1.180
320
90


1.180
320
90

1,180
320
90
Effectiveness
($/ton)r

_
640
514


.
640
523

.
640
532
Effectiveness
(I/ton)"

„
„
44


_
,
67

.
„
130
Combined Cycle Unit W/Credlt (129 million Btu/hr)
Regulatory Baseline (3.0 Ib/mllHon Btu)
Low Sulfur Fuel (1.6 Ib/mllllon Btu)f
Percent Reduction (87 Percent)9
Supplementary -Fired
M1>ed Fuel Unit (313 million Btu/hr)
Regulatory Baseline (3.0 Ib/mllllon Btu)
low Sulfur Fuel (0.8 Ib/m1llion Btu)
Percent Reduction (90 Percent)
Combined Cycle Unit W/0 Credit (313 million
Regulatory Baseline (3.0 Ib/m1ll1on Btu)
low Sulfur Fuel (0.8 tb/mllUon Btu)
Percent Reduction (90 Percent)
3.0
1.6
3.0/871 FGO


3.0/NG
0.8/NG
3.0/NG
Btu/hr)
3.0
0.8
3.0/901 FGD
100 29 3.890
4.140
4,460


313 - 13.770"1
14.320*
14 ,460^

100 213 3,890
4.440
4.810
1,180
630
120


1,180
320
90

1,180
320
90
,
455
538


_
640
633

-
640
844
.
.
628


.
.
609

.
.
1,609
Combined Cycle Unit M/Credit (313 million "Btu/hr)
Regulatory Baseline (3.0 Ib/oilMon Btu)
Low Sulfur Fuel (3.0 Ib/mllllon Btu)h
Percent Reduction (69 Percent)'
3.0
3.0
3.0/691 FGO
100 213 3,890
3.890
4,740
1.180
1.180
330
.
0
1.000
.
.
1,000
*Based on a capacity factor of 0.9.

 Average uncontrolled S0? emissions.

 Annual cost Includes only the cost of fuel fired plus the annuallzed cost of SO, control device and does not Include other steam generating unit
 annuallzed costs.                                                        '

 Compared to regulatory baseline.

•Compared to less stringent alternative.

 Based on the heat  Input supplied by  the gas turbine exhaust.  Credit Is calculated as 129/100, or 29 percent.  This would translate Into an
 emission 11»U of  443 ng SO./J (1.03 Ib S0./m1l11on Btu).  Pricing data are not available,  however, for an oil  capable of meeting this emission
 limit.  Therefore, this analysis assumed an emission credit of 100 percent In order to use  available pricing data for an oil meeting a 688 ng
 SOj/J (1.6 Ib SOj/mllllon Btu) emission limit.

9Based on a 30 percent emission credit.

 Based on the heat  Input supplied by  the gas turbine exhaust.  Credit Is calculated as 313/100, or 213 percent.  This would translate into in
 emission limit of  1,076 ng SO-/J (2.S Ib SO./mllllon Btu).  Pricing data are not available, however, for an oil capable of meeting this
 emission limit. Therefore,  this analysis assumed an emission credit of 275 percent in order to use available pricing data for an oil meeting
 a 1,291 ng SO;/J (3.0 Ib SOj/million Btu) emission limit.

 Based on a 210 percent emission credit.

^Annuallzed costs for mixed fuel-fired steam generating units are higher than those for other units examined because the cost of natural gas
 fuel  has been Included along with coal fuel costs.
                                                               33

-------
     For standards requiring a percent reduction in S02 emissions, the
incremental cost effectiveness of SCL control  over standards based on the
use of low sulfur fuels is $609/ton for a mixed fuel-fired steam generating
unit; $l,609/ton for a supplementary-fired steam generating unit without an
emission credit; and $l,000/ton for a supplementary-fired steam generating
unit with an emission credit.
     This difference in the cost effectiveness of S(L control between
fully-fired and supplementary-fired steam generating units reflects the fact
that the analysis assumes combustion of natural gas in the gas turbine.
Since natural gas contains little or no sulfur, the gas turbine exhaust
contains little or no Stk.
     As discussed earlier, in  a supplementary-fired combined cycle steam
generating unit the heat input of the gas turbine exhaust represents about
70 percent of the total heat input to the steam generating unit.
Consequently, assuming the gas turbine fires natural gas, the gas turbine
exhaust acts as a "diluent", significantly increasing the volume of the flue
gases from the steam generating unit without increasing the S02 emissions
contained in these flue gases.  In a fully-fired combined cycle system, the
heat input of the gas turbine  exhaust only represents about 30 percent of
the total heat input to the steam generating unit and the "diluent" effect
of the gas turbine exhaust is  not as significant.  Consequently, assuming
the gas turbine fires natural  gas, the cost effectiveness of S02 control is
higher for supplementary-fired combined cycle  steam generating units than
for fully-fired combined cycle steam generating units.
     If, however, the analysis had assumed that oil was combusted in the gas
turbine, rather than natural gas, the difference in the cost effectiveness
of SOp control between supplementary-fired and fully-fired combined cycle
steam generating units would narrow.  If, for example, the analysis had
assumed oil of the same sulfur content was combusted in the gas turbine as
in the steam generating unit (which probably represents a more realistic
assumption) there would be no  difference in the cost effectiveness of S02
control between supplementary-fired and fully-fired combined cycle steam
                                      34

-------
generating units, other than that which might exist due to "economies of
scale".
     In fact, since the analysis kept the heat input from the fuel  fired  in
the steam generating unit constant, the supplementary-fired steam generating
unit is much larger than the fully-fired steam generating unit.   As a
result, due to "economies of scale", under standards requiring a percent
reduction in S02 emissions, the analysis would indicate that the cost
effectiveness of SOo control is lower for a supplementary-fired  combined
cycle steam generating unit than for a fully-fired combined cycle steam
generating unit.
     Table 13 summarizes the incremental cost effectiveness of SOg  control
associated with not providing emission credits for fully-fired and
supplementary-fired oil-fired combined cycle steam generating units.   For
standards based on the use of low sulfur fuels, the incremental  cost
effectiveness of S02 control is $968/ton for a fully-fired steam generating
unit and $640/ton for a supplementary-fired steam generating unit.   For
standards requiring a percent reduction in S02 emissions, the incremental
cost effectiveness of not providing emission credits is $333/ton for a
fully-fired steam generating unit and $292/ton for a supplementary-fired
steam generating unit.
                                      35

-------
TABLE 13.  INCREMENTAL COST EFFECTIVENESS OF ALLOWING VERSUS NOT

            PROVIDING EMISSION CREDITS FOR OIL-FIRED

                COMBINED CYCLE COGENERATION UNITS
                        Annualized
                          Cost
                        $1000/yr
 Annual
Emissions
 (tpy)
Incremental  Cost
 Effectiveness
    ($/ton)
Fully-Fired

Low Sulfur Fuel Standard
  With Emission Credit
  (1.2 lb/106 Btu)

  Without Emission Credit
  (0.8 lb/105 Btu)

Percent Reduction Standard
  With Emission Credit
  (87% FGD/3.0 lb/105 Btu)

  Without Emission
  (90% FGD/3.0 lb/105 Btu)

Supplementary-Fi red

Low Sulfur Fuel Standard
  With Emission Credit
  (3.0 lb/105 Btu)

  Without Emission Credit
  (0.8 lb/10D Btu)

Percent Reduction Standard
  With Emission Credit
  (69% FGD/3.0 lb/105 Btu)

  Without Emission Credit
  (90% FGD/3.0 lb/105 Btu)
                          4,140


                          4,440



                          4,460


                          4,470
                          3,890


                          4,440



                          4,740


                          4,810
    630


    320



    120


     90
  1,180


    320



    330


     90
      968
      333
      640
      292
                                36

-------
5.0  REFERENCES
1.   Resource Planning Associates, Inc.   The Potential  for Industrial
     Cogeneration Development by 1990 -  Final  Report.   (Prepared for U.S.
     Department of Energy), Cambridge, MA.   July 31,  1981.  pp.  B.9-B.14.

2.   Laughlin, J. H., J.  A. Maddox, and  S.  C.  Margerum.  (Radian
     Corporation).  S02 Cost Report.   Prepared for U.S. Environmental
     Protection Agency, Research Triangle Park, N. C.   EPA Contract No.
     68-02-3816.  August  10, 1984.  p. 2-24.
                                     37

-------
                    APPENDIX A



MODEL CASES FOR COMBINED CYCLE COGENERATION SYSTEMS
                        A-l

-------
         TABLE A-l.   MODEL  CASES  FOR  FULLY-FIRED  OIL  COMBINED CYCLE COST ANALYSIS - REGION V

Regulation
Baseline fi
0.8 lb/10° Btu ,.
90% FGD/0.6 Ib 10b Btu
Baseline K
1.2 lb/10° Btu f.
90% FGD/0.6 lb/10° Btu
Basel ineafi
0.8 lb/10D Btua
41,430 ,.
90% FGD/0.6 lb/10° Btua
Baseline ,• .
1.2 lb/10b BtuD
41,430 6 .
87% FGD/0.8 lb/10° BtuD
Boiler Fuel
Unit Type (lb/10° Btu)
Standard Oil -Fired
Boiler

Mixed Fuel Boiler


Fully-Fired Oil
Combined CycU (MA-1)C


Fully-Fired Oil
Combined Cycle (MA-1)C


3.0
0.8
0.3
3.0/NG
1.6/NG
3.0/NG
3.0
0.8

3.0
3.0
1.6

3.0
Boiler
Heat Input
(10° Btu/hr)
100
100
100
129
129
129
100
100

100
100
100

100
Gas Turbines Flue Gas
Exhaust Flowrate
(10b Btu/hr) (acfm)
.
-
-
—
_
-
29
29

29
29
29

29
30,120
30,120
30,120
39,180
39,180
39,180
41,430
41 ,430

41,430
41,430
41,430

41,430
 Combined cycle system without  heat  input  credit.
 Combined cycle system with  heat  input  credit.
'Refers  to the model  plant in Reference 1.

-------
               TABLE A-2.  MODEL CASES FOR FULLY-FIRED COAL COMBINED CYCLE COST ANALYSIS  -  REGION  V
i
CO

Regulation
Baseline fi
1.2 lb/10° Btu f.
90% FGD/0.6 Ib 10° Btu
Baseline fi
1.2 lb/10° Btu K
90% FGD/0.6 lb/10° Btu
Baseline3.
1.2 lb/10b Btua f-
90% FGD/0.6 lb/10° Btua
Baseline ,- .
1.2 lb/10° BtuD K .
86% FGD/0.8 lb/10° BtuD
Unit Type
Standard Coal -Fired
Boiler

Mixed Fuel Boiler


Fully-Fired Coal
Combined Cycle
(MF-4A)C
Fully-Fired Coal
Combined Cycle
(MF-4A)C
Boiler Fuel
E-bit
B-bit
H-bit
E-bit/NG
D-bit/NG
H-bit/NG
E-bit
B-bit
H-bit
E-bit
D-bit
H-bit
Boiler
Heat Input
(106 Btu/hr)
100
100
100
137
137
137
100
100
100
100
100
100
Gas Turbines
Exhaust
(10b Btu/hr)

_
-
_m
_
-
37
37
37
37
37
37
Flue Gas
Flowrate
(acfm)
36,760
36,740
36,780
48,530
48,460
48,490
51,720
51,720
51,720
51,720
51,720
51,720
        Combined cycle system without heat input credit.
        Combined cycle system with heat input credit.
       cRefers to the model plant in Reference 1.

-------
       TABLE A-3.  MODEL CASES FOR FULLY-FIRED COAL COMBINED CYCLE COST ANALYSIS - REGION VII
Regulation
Baseline fi
1.2 lb/10D Btu f.
90% FGD/0.6 Ib 10° Btu
Baseline fi
1.2 lb/10° Btu f.
90% FGD/0.6 lb/10° Btu
Basel ine3,-
1.2 lb/10° Btua K
90% FGD/0.6 lb/10° Btua
Baseline fi .
1.2 lb/10° BtuD f- .
86% FGD/0.8 lb/10° BtuD
Unit Type
Standard Coal -Fired
Boiler

Mixed Fuel Boiler


Fully-Fired Coal
Combined Cycle
(MG-2)C
Fully-Fired Coal
Combined Cycle
(MG-2)C
Boiler Fuel
E-bit
B-bit
B-bit
E-bit/NG
D-bit/NG
B-bit/NG
E-bit
B-bit
B-bit
E-bit
D-bit
B-bit
Boiler
Heat Input
(10° Btu/hr)
100
100
100
137
137
137
100
100
100
100
100
100
Gas Turbines
Exhaust
(10° Btu/hr)

_
-
_
_
-
37
37
37
37
37
37
Flue Gas
Flowrate
(acfm)
38 ,845
38,650
38,845
50,565
50,565
50,370
53,390
53,390
53,390
53,390
53,390
53,390
 Combined cycle system without heat  input credit.
Combined cycle system with  heat  input credit.
'Refers  to model  plant in  Reference  1.

-------
             TABLE A-4.  MODEL  CASES  FOR SUPPLEMENTAL-FIRED OIL COMBINED CYCLE COST ANALYSIS - REGION V
Ol
Regulation
Baseline fi
0.8 lb/105 Btu ,
90% FGD/0.6 Ib 10° Btu
Baseline fi
0.8 lb/10° Btu ,
90% FGD/0.6 lb/10° Btu
Basel ineafi
0.8 Ib/HT Btua K
90% FGD/0.6 lb/10° Btua
Baseline K .
3.0 lb/10b BtuD f. .
69% FGD/0.8 lb/10b BtuD
Unit Type
Standard Oil -Fired
Boiler

Mixed Fuel Boiler


Suppl emental -Fi red
Oil Combined Cycle

Suppl emental -Fired
Oil Combined Cycle

Boiler Fuel
(lb/100 Btu)
3.0
0.8
0.3
3.0/NG
1.6/NG
3.0/NG
3.0
0.8
3.0
3.0
3.0
3.0
Boiler
Heat Input
(10° Btu/hr)
100
100
100
313
313
313
100
100
100
100
100
100
Gas Turbines
Exhaust
(10° Btu/hr)

^
-
—
..
-
29
29
29
29
29
29
Flue Gas
Flowrate
(acfm)
30,120
30,120
30,120
97,590
97,590
97,590
278,470
278,470
278,470
278,470
278,470
278,470
        aCombined cycle system without heat input credit.
         Combined cycle system with heat input credit.

-------
              APPENDIX B
SAMPLE CALCULATIONS FOR COMBINED CYCLE
         COGENERATION SYSTEMS
                  B-l

-------
                                 APPENDIX 8
                              TABLE OF CONTENTS
I.    Foreword
II.   Combustion Calculations - Fully-Fired Combined Cycle
                               Steam Generating Unit
     A.    Fuel  Requirement
     B.    Air Requirement
          1.    Theoretical Air
          2.    Total  Air
     C.    Products of Combustion
III.  Sample Calculations - Combined Cycle Model Plant With Fully-Fired
                           Steam Generating unit
     A.    Given
     B.    Fuel  Use
          1.    Gas Turbine
          2.    Boiler
     C.    Heat Input  From .Gas Turbine
     D.    Gas Flows
          1.    Steam  Generating Unit Firebox Inlet
          2.    Steam  Generating Unit Firebox Exhaust (to Economizer)
          3.    Economizer Exhaust
                                      B-2

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I.   Foreword

     In order to determine the cost of S02 control for combined cycle
systems, the steam generating unit flue gas flowrate had to be calculated.
The following calculations demonstrate the procedures used to complete the
mass and energy balances for a fully-fired coal combined cycle system.  The
detailed calculations yield a flue gas flowrate of 49,670 acfm compared to a
flowrate of 51,720 acfm for the scaled-down 250 million Btu/hr boiler in the
utility combined cycle report.   The scaled-down version is 4 percent higher
than the flow calculated in detail.
     In comparison to a mixed fuel-fired steam generating unit these
scaled-down flowrates appeared reasonable for the coal cases.  However, the
scaled down flowrate for the oil combined cycle cases is significantly
higher than the mixed fuel-fired steam generating unit flowrates.  After
referring back to the utility report we discovered that the utility
flowrates were incorrectly based on 35 percent excess air (like coal-fired
steam generating units) rather than 10 percent excess air.  Therefore, the
flowrates shown for the oil combined cycle cases is high.  However,
flowrates or the supplementary oil-fired units are correct since the flue
gas flowrate from these units does not depend on a set excess air.   The
annual cost of S02 control is the cost of the fuel fired in the steam
generating unit plus the annualized cost of SO^ control device.

II.  Combustion Calculations — Fully-Fired Combined Cycle
     Steam Generating Unit

     The gas flows through a fully-fired (stoichiometrically-fired) steam
generating unit are reasonably homogeneous.  However, as with the gas
turbine, it is easier to assume that they are composed of discrete
components.   The flow diagram of Figure B-l shows the flow constituents.
The inlet gas flows are theoretical air, excess air, and in-leakage air.
The exhaust gases are composed of theoretical steam generating unit exhaust,
                                     B-3

-------
                                                                                            5.62 in-leakage
                                                                                            air (wet)
CO
I
Theoretical
Gas Turbine
Exhaust (wet)

Total Air (wet)
^ ,


^^


Steam
Generating
Unit
Firebox

1027 It/million Btu /
13.416 scf/million Btu



i
Fuel
Bituminous Coal

(

^-

Theoretical
Gas Turbine
Exhaust (wet)

Total Firebox
Exhaust (wet)


^-


Economizer

^-
^
f • " P-
1095 Ib/million Btu
14.042 scf/million Btu
Theoretical
Gas Turbine
Exhaust (wet)

Total Steam
Generating Unit
Firebox Exhaust

Leakage Air

                                         100 million Btu/hour
              Figure  B-l.  Flow diagram of a fully-fired combined cycle system.

-------
excess air, and in-leakage air.  For these calculations, only flow through
the steam generating unit firebox is discussed.  All in-leakage air is
assumed to occur downstream of the firebox.  It is assumed that 35 percent
excess air will be used to ensure complete combustion and the steam
generating unit is fired with bituminous coal.

A.  Fuel Requirement

     The fuel selected for the sample steam generating unit is a bituminous
                                        2
coal with the following characteristics:

          Heating Value	11,800 Btu/1 b
          Composition C	64.80 percent by weight
                      Hp	4.43 percent by weight
                      N2	1.30 percent by weight
                      S	3.54 percent by weight
                    H20	8.79 percent by weight
                    Ash	10.58 percent by weight
                                           100.00 percent by weight

B.  Air Requirement

     The total air requirement of a boiler has two components, theoretical
air and excess air.  The theoretical is the air actually consumed during 100
percent combustion of the fuel and the excess air is the additional amount
required to ensure that complete combustion takes place.

     1.  Theoretical Air - Theoretical air requirements are set by the
composition of the fuel.  The air requirements for combustion of the fuel
constituents are developed in Table B-l, using the mass rate of the fuel
constituent and its combustion constant in air.  As shown, the total
theoretical air requirement is:
                                     B-5

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                TABLE B-l.   STEAM GENERATING UNIT COMBUSTION CALCULATIONS THEORETICAL AIR REQUIREMENTS'

                                    (USING WEIGHT METHOD, ASSUMING BITUMINOUS COAL)
CO
I
Fuel
Constitu
C
H2
°2
S
H20
Ash
Combustion Constants
(Ibs/lbs Constituent)
111 timatp Anal v^i t A*: Fi rprt . — 	 - 	
lent (Weight Percent) Op Air
64.80 2.66 11.53
4.43 7.94 34.34
6.56
1.30
3.54 1.00 4.29
8.79
10.58
100.0
Less 02 in Fuel (deduct)
Theoretical Air Requirements
Total Ai
(1.35
r Requirements Assuming 35 Percent Excess Air
x Theoretical Air)
Excess Air (11.962 - 8.861)
Theoretical Air Required
for Combustion
(Ibs Air/lbs Fuel)
7.471
1.521
-
0.152
-
_
9.1443
-0.283a
8.861
11.962
3.101
         Air equivalent of  02  in  fuel

-------
          Theoretical Air.   = 8.861 Ibs air/lb fuel

     2.  Total Air - The steam generating unit is assumed to operate with 35
percent excess air.  Thus:

          Total Air.   = 135% x 8.861 = 11.962 Ibs air/lb fuel

but ambient air contains water vapor.  The moisture content of  air at
standard conditions (60 percent R.H. and 80°F) is 0.013 Ib water/lb air2,
so:
          Total  Airwet = 11.962 + [0.013 x 11.962]
                       = 12.12 Ibs air/lb fuel
or, in terms of heat input:
          Total  Airwfit = 12.12 Ibs air/lb fuel  x 106 . 1Q27 lbs/1(J6
                          11,800 Btu/lb fuel
     Air obeys the perfect gas laws, so one mole of air has a volume of 379
  3                                      3
ft  at standard temperature and pressure.    Thus:
          Total Airyol = Total  Airm x     Molar Volume
                                      Molecular Wt.  of Air
               - _1027_ Ib x 379 ft3/mol   . 13>41g scf/1Q6
                 10° Btu       29 Ib/mol
C.  Products of Combustion

     The products of perfect combustion of a fuel  are C02  and H20.   In
addition, the exhaust gases contain the other constituents of the air and
fuel, in either reacted or non-reacted form.
                                     B-7

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     Combustion Calculations - Combustion calculations for solid fuels are
usually performed on a weight basis.  The combustion product calculations,
are shown in Table 2.  The flue gas produced by complete combustion of the
fuel in 35 percent excess air is:
or,
     Steam Generating Unit Flue Gasm » 12.9188 Ibs air/1b fuel

     Steam Generating Unit Flue Gasm =
          12.9188 Ib x  Ib fuel    = 1094.8 lbs/106 Btu
           Ib Fuel11,800 Btu

The molecular weight (MW) of the steam generating unit flue gas is the sum
of the combustion products of steam generating unit combustion, which is
determined from Table B-2 as follows:

Product of      Fuel Analysis         Molecular        Fuel Analysis
Combustion     Weight percent           Weight         mole percent
  C02          2.372 Ibs/lb fuel      44.01  Ib/mol    0.0539 moles/lb fuel
  H20          0.554 Ibs/lb fuel      18.02  Ib/mol    0.0308 moles/lb fuel
  S02          0.071 Ibs/lb fuel      64.06  Ib/mol    0.0011 moles/lb fuel
  02           0.718 Ibs/lb fuel      32.0   Ib/mol    0.0224 moles/lb fuel
  N2           9.204 Ibs/lb fuel      28.02  Ib/mol    0.329  moles/lb fuel
              12.919 Ibs/lb fuel                       0.4372 moles/lb fuel
The molecular weight of the steam generating unit flue gas is thus:
          _ Weight of Combustion Products
        ^
            Moles of Combustion Products
             12.9188 Ibs/lb fuel   = 29.55 Ib/mol
             0.4372 moles/lb fuel
     The steam generating unit flue gases are assumed to obey the perfect
gas law.  The volume of the steam generating unit flue gases are therefore:
                                     B-8

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00
I
10
                 TABLE B-2.   STEAM GENERATING  UNIT  COMBUSTION  CALCULATIONS  —  PRODUCTS  OF COMBUSTION3

                                                 (USING WEIGHT METHOD)
Ultimate Analysis,
As-Fired Product of Combustion Constant Combustion Products
Constituent (lb/100 Ib Fuel) Combustion (Ib Product/lb Constituent) (Ib/lb Fuel)
Fuel:
'C 64.80 C02 3.66
H2 4.43 H20 8.94
02 6.56 -b
N2 1.30 N2 1.0
S 3.54 S02 2.0
H~0 8.79 H90 1.0
£. C.
Ash 10.58 -c -c
100.0
Air:d
02 204. (Theoretical) -b
72. (Excess) 02 1.0
N0 920.
1196.

2.37
0.40
0.0
0.013
0.071
0.088

_
2.94

0.0
0.72
9.2
9.92
         Assuming 35 percent excess air.


         Assumes 02 consumed during combustion.


         "Ash is not included as a product of combustion for the purposes of this calculation.


         N2 in air = 76.85 weight percent, 02 in air = 23.15 weight percent.

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     Steam Generating Unit Flue Gasu x  Ho1a1  Vo1ume
                                       MW of Flue Gas
          - 1094 8 Ibs x 379 ft3/mol    . 1
              10° Btu    29.55 Ib/mol

III.  Sample Calculations ~ Combined  Cycle Model Plant with Fully-Fired
      Steam Generating .Unit

     The sample model plant is a combined-cycle plant having a fully-fired
steam generating unit fired at 100 million Btu/hr with bituminous coal.  The
combustion air requirements of the steam generating unit are exactly matched
by the excess air content of the turbine exhaust.

A.  Given

     Steam generating unit heat input  (from fuel)      100 million Btu/hr
     Heating value of steam generating unit fuel
       (bituminous coal)                               11,800 Btu/lb
     Gas temperature entering steam generating unit
       firebox6                                          1000° F
     Gas temperature entering steam generating unit
       firebox and economizer                            700° F
     Gas temperature entering steam generating unit
       at economizer exit                                300°F
     Heat content of gas turbine exhaust               621,051 lb/106 Btu1
     Gas turbine excess air                            1774.1 lb/106 Btu1
     Steam generating unit air                         1027 lb/10  Btu
                                                          (See II. B. 2)

B.   Fuel Use

     1.  Gas Turbine - The excess air (EA) in the gas turbine exhaust
exactly matches the total air (TA) requirements of the steam generating unit
                                     B-10

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 (no gas turbine exhaust bypass and no supplementary source of combustion
 air):

     Gas Turbine Excess Air = Steam Generating Unit Total Air
     Gas Turbine Excess Air = 177?'1 1b x Gas Turbine Heat Input
                               10° Btu
     Steam Generating Unit Total Air = 102I 1b x Steam Generating Unit
                                        10  Btu     Heat Input
 Therefore, for a Steam Generating Unit Heat Input of = 100 million Btu/hr:
     Gas Turbine Heat Input =  1027 lb/106cBtu  x 100 MM Btu/hr
                              1774.1 lb/10D Btu
                            =57.9 million Btu/hr

     2.  Boiler - The heat input to the sample steam generating unit is 100
MM Btu/hr of a bituminous coal with a heating value of 11,800 Btu/lb, so:
     Steam Generating Unit Fuel, .Steam Generating Unit Value
                                      Fuel Heating Value
                                 = 100 x 106 Btu/hr ,
                                    11,800 Btu/lb
 C.  Heat Input From Gas Turbine

     The heat input of the gas turbine exhaust entering the steam generating
unit firebox is 621,051 Btu/10  Btu  and the gas turbine heat input is 57.9
MM Btu/hr, so the heat input to the sample steam generating unit is:
     621 f1 Btu x 57.9 million Btu - 35.96 million Btu/hr
       10° Btu            hr
                                     B-ll

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D.   Gas Flows

     1.  Steam Generating Unit Firebox Inlet - The total air requirements of
the sample fully-fired steam generating unit is assumed to exactly match the
gas turbine excess air (no gas turbine exhaust bypass and no supplementary
combustion air).  Thus, the presence of the theoretical gas turbine exhaust
gas increases total gas flow through the steam generating unit firebox.

     Steam Generating Unit Total Air = Gas Turbine Excess Air

     The steam generating unit air requirement is 1027 Ib/million Btu
(see II. B. 2) and the steam generating unit fuel input is 100 million Btu/hr:
     Steam Generating Unit Air = 10jj7 1b x 10° ™"i™ Btu „ 102>700 lb/nr
                                 10° Btu          hr

Also:  Steam Generating Unit Inlet Gas = Total Gas Turbine Exhaust1
Therefore:  Steam Generating Unit Gas _  Total Gas Turbine Exhaust
            Steam Generating Unit Air     Gas Turbine Excess Air
            Steam Generating Unit Gas _  275.8 lb/106 Btu to Gas Turbine
               102,700 Ib/hr            1774.1 lb/106 Btu to Gas Turbine
            Steam Generating Unit   yr.^ o
                 Inlet Gas =        «*/•« x 102,700 = 147,488 Ib/hr
                                    1774.1

The theoretical gas turbine (G.T.) exhaust contribution to this total  is:
     G.T. Theoretical Exhaust = Steam Generating Unit Inlet Gas -
                                Steam Generating Unit Total Air
     G.T. Theoretical Exhaust = 147,488 Ib/hr - 102,700 Ib/hr = 44,788 Ib/hr

     As noted earlier, the gas flow into the firebox of a combined cycle
steam generating unit is the gas turbine exhaust and the gas turbine excess
                                     B-12

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air, which is also the steam generating unit total  air requirement.  The
molecular weigl
its volume is:
molecular weight of the gas turbine theoretical  exhaust is 27.5 Ib/mol  ,  so
     G.T. Theoretical Exhaust  , = G.T. Theoretical  Exhaust  x
             molar volume       44,788 Ib/hr   379 ft3/mol     QCQn f f
          	  =	x	= yoou sctm
          MW of G.T. Exhaust     60 min/hr     29.53 Ib/mol

The steam generating unit total air volume is 13,416 scf/10  Btu (see
II.B.2).
     Steam Generating Unit Air  , = 13'4*6 scf x 10° m1111on Btu - 22,360 scfm
                              V01     10° Btu         60 min/hr

The volume of the total  gas flow entering the steam generating unit firebox
is thus:

     Steam Generating Unit Gasyol = G.T. Theoretical Exhausty +
     Steam Generating Unit Total Air = 9580 scfm + 22,360 scfm = 31,940 scfm

At 1000°F, the density correction factor is 0.36 , so:

     Steam Generating Unit Inlet  = 31>94° scfm = 88,722 acfm § 1000°F
                                v      0.36

     2.  Steam Generating Unit Firebox Exhaust (to Economizer) - The total
exhaust gas from the steam generating unit firebox is the sum of the inputs:

     Steam Generating Unit Inlet Gas	147,488 Ib/hr
     Steam Generating Unit Fuel	+8475  Ib/hr (see II.B.2.)
     Steam Generating Unit (Firebox)
        Exhaust Gas	155,963 Ib/hr
                                     B-13

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The steam generating unit flue gas component of this total is:

     Steam Generating Unit Exhaust Gas	155,963 Ib/hr
     Theoretical Gas Turbine Exhaust	-44,788 Ib/hr
     Steam Generating Unit Flue Gasm	111,175 Ib/hr

The volume of the steam generating unit flue gas is 14,042 scf/106 Btu
(see II.A.3)

     Steam Generating Unit Gas  = 14'?42 scf x 10° mi11ion Btu/hr = 23,403 scfm
                                   10° Btu       60 min/hr

And the total volume of gas leaving the steam generating unit firebox is:
     Steam Generating Unit Exhaust Gasv = Steam Generating Unit Flue Gas  +
     G.T. Theoretical Exhaust = 23,403 scfm + 9580 scfm = 32,983 scfm
     At 700°F the density correction is 0.467, so:
          Steam Generating Unit Exhaust Gas  = 32>983 scfm
                                           v    0.46
                                             = 71,702 acfm @ 700°F

     3.  Economizer Exhaust - All in-leakage of air to the combined cycle
steam generating unit is assumed to occur in the economizer.   The amount of
leakage is assumed to be 5.6 percent of the inlet gas to the boiler, or:

     In-leakage Airm = 0.056 x 31,940 scfm = 1,789 scfm
     Thus, the total gas flow from the economizer is:
                                     B-14

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                                              Mass            Volume
     Steam Generating Unit Exhaust Gas	155,963  Ib/hr     32,983 scfm
     In-leakage Air	+  8,259  Ib/hr   + 1,789 scfm
     Economizer Exhaust	164,222  Ib/hr     34,772  scfm
At 300°F, the density correction factor is  0.70  , so:
     Economizer Exhaust = 34>772 scfm = 49,679 acfm 9  300°F
                             0.70
                                     B-15

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APPENDIX B REFERENCES
1.   Utility Combined Cycle Report, Appendix B.
2.   Taken From Background Information Document,  Fossil  Fuel  Boilers,  pp.
     3-26.
3.   Steam, 37th Edition, p.  4-9.
4,   Steam, 37th Edition, p.  4-5,  6.
5.   Steam, 37th Edition, p.  4-8.
6,   Steam, 37th Edition, p.  4-2.
7.   EPRI FP-862, Combustion  Turbine Repowering  of Reheat Steam Power
     Plants, Dated 8/78, p. 3-40.
8.   AP-40, Air Pollution Engineering Manual, 2nd Edition, p.  58.
                                      B-16

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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO. 2.
4. TITLE AND SUBTITLE
An Analysis of the Costs and Cost Effectiveness of
Allowing SC"2 Emission Credits for Cogene ration Systems
7. AUTHOR(S)
Radian Corporation
Research Triangle Park, North Carolina 27709
9. PERFORMING ORGANIZATION NAME ANO ADDRESS
Office of Air Quality Planning and Standards
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
12. SPONSORING AGENCY NAME AND ADDRESS
DAA for Air Quality Planning and Standards
Office of Air and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
December 1985
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-3816
13. TYPE Of REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
EPA/200/04
15. SUPPLEMENTARY NOTES
       This  document discusses the results of a cost analysis  that  was  performed to
  assess the reasonableness of emission credits for cogeneration  facilities under
  new source performance standards limiting SO;? emissions  from industrial-commercial -
  institutional  steam generating units.  Emission credits  would allow a cogeneration
  system to  achieve  a lower percent reduction in emissions or  to  meet a higher emission
  limit in proportion to the increased overall efficiency  achieved  by the  cogeneration
  system.  The  analysis examined two common types of cogeneration,  steam generator-
  based and  combined cycle systems, and analyzed the incremental  cost effectiveness
  of not providing emission credits versus providing emission  credits for two
  regulatory alternatives:  standards based on the use  of  low  sulfur fuels and
  standards  requiring a percent reduction in S0£ emissions.
17.
                               KEY WORDS AND DOCUMENT ANALYSIS
                  DESCRIPTORS
                                             b.lOENTIFIERS/OPEN ENDED TERMS  C. COSATI Field/Group
 Air  pollution
 Pollution  control
 Standards  of performance
 Fossil  fuel-fired  industrial boilers
 Combined cycle cogeneration systems
 Steam generator-based cogeneration systems
 Fossil fuel-fired
   industrial boilers
 Air pollution control
 Cogeneration systems
   13 B
 8. DISTRIBUTION STATEMENT

  Release  unlimited.
19. SECURITY CLASS (ThisReport)
    Unclassified
21. NO. OF PAGES
     58
                                             20. SECURITY CLASS (Thispage)
                                                 Unclassified
                          22. PRICE
EPA Form 2220-1 (Rev. 4-77)   PREVIOUS EDITION is OBSOLETE

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