PA
United States
Environmental Protection
Agency
EPA-600/7-90-010
May 1990
Research and
Development
EMISSIONS AND COST
ESTIMATES FOR GLOBALLY
SIGNIFICANT ANTHROPOGENIC
COMBUSTION SOURCES OF
NOX. N2O. CH4, CO, AND CO2
Prepared for
Office of Policy, Planning, and Evaluation
Prepared by
Air and Energy Engineering Research
Laboratory
Research Triangle Park NC 27711
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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ABSTRACT
Emission factors for carbon dioxide (C02) , carbon monoxide
(CO) , methane (CH<) , nitrogen oxides (NOX) , and nitrous oxide
(N20) were developed for about 80 globally significant combustion
sources in 7 source categories — utility, industrial, fuel
production, transportation, residential, commercial, and
kilns/ovens/dryers. These factors were prepared for use by EPA
in estimating.global emissions of these gases for a Report to
Congress on policy options for stabilizing global climate.
Because of the lack of adequate international data, the emission
factors for most sources are based on U.S. performance, cost, and
emissions data. Data on C02, CO, and NOX were available for over
90 percent of the sources studied; on CH4, for about 80 percent;
on N20, for only about 10 percent. Emission factor quality
ratings were developed to indicate the overall adequacy of the
supporting data. Quality ratings ranged from "A" to "E", and "A"
being the best. Except for N20, the emission factors for the
gases covered the quality spectrum from A to E; all of the
emission factors for N20 were given an "E" rating. Evaluation of
the emission factors for the 7 source categories (taking the 5
gases as an aggregate for each category) showed that the
kilns/ovens/dryers category had the overall lowest quality
rating, with no factors given better than a "B" rating. Emission
factors for fuel production were somewhat better, but generally
of lower quality than those for the remaining 5 source
categories.
11
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TABLE OF CONTENTS
Section • Page
ABSTRACT . . ii
LIST OF FIGURES vi
LIST OF TABLES vii
1. INTRODUCTION AND SUMMARY 1
SCOPE 2
Anthropogenic Sources Included in the Study . . 2
Type of Data Collected 9
Data Quality 11
Report Format 11
SUMMARY 13
2. DATA REQUIREMENTS AND GENERAL TECHNICAL APPROACH .... 21
EMISSION FACTOR ESTIMATES 21
Energy Conversion Efficiency 22
Emission Factors 24
EMISSION FACTOR DATA QUALITY RATING 28
EMISSION CONTROLS PERFORMANCE ESTIMATES 32
Removal Efficiency 32
Emission Source Efficiency Penalty 33
Availability Date ............... 34
EMISSION SOURCE AND CONTROL COSTS 34
International Costing 34
Cost Data Requirements 35
Sources of Variation in Costing 36
111
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TABLE OF CONTENTS (Continued)
Section gage
3. UTILITY SOURCES AND CONTROLS .............. 37
DATA FOR EMISSION SOURCES ..... 37
Efficiency and Transmission Loss 37
Emission Factors ................ 43
Cost 45
UTILITY SOURCE EMISSION CONTROL TECHNOLOGIES .... 45
Efficiency Penalties 49
Removal Efficiencies . 50
Cost 51
4. INDUSTRIAL BOILER SOURCES AND CONTROLS ......... 53
SOURCES ........... .53
Efficiency .... ...... 53
Emission Factors ........ 55
Cost ............ .56
EMISSION CONTROL TECHNOLOGIES ..... 56
Efficiency Penalty ............... 60
Removal Efficiencies ..... 60
Costs ... ............ 60
5. KILNS, OVENS, AND DRYERS „ 62
SOURCES ..... 62
Efficiency ........ 62
Emission Factors 64
CONTROLS . 66
IV
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TABLE OF CONTENTS (Continued)
Section Page
6. FUEL PRODUCTION 69
SOURCE DESCRIPTIONS, EMISSION FACTORS AND
EFFICIENCY DATA 69
Oil Production Sources 72
Petroleum Refining ... 72
Oil Shale Retorting 74
Wellhead Venting ..... 75
Gas Production Sources 75
Pipeline Leaks 76
Transport/Compression Engine Emissions .... 76
Coal Production Sources 77
Active Coal Mines 77
Coal Drying 78
Coal Gasification 78
Coal Liquefaction 79
Wood-Related Sources 79
Efficiency Data 79
EMISSION CONTROL TECHNOLOGIES ..... 80
Emission Reduction Efficiency . . 80
Efficiency Penalty 87
Cost 88
7. MOBILE SOURCES AND CONTROL TECHNOLOGIES 90
MOBILE SOURCE EMISSIONS 90
Highway Source Emissions 90
Off-Highway Source Emissions 93
v
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TABLE OF CONTENTS (Continued)
Section Page,
MOBILE SOURCE EMISSION CONTROL TECHNOLOGIES .... 95
Emission Reduction Efficiency ... ...... 95
Cost ..... ....... .......... 97
8. RESIDENTIAL AND COMMERCIAL SOURCES AND CONTROLS .... 98
RESIDENTIAL SOURCES ....... ......... 98
Efficiency ........ ....... .... 98
Emission Factors ........ ........ 98
COMMERCIAL SOURCES ..... . ..... ..... 102'
Efficiency ........... ....... 102
Emission Factors ............... 105
RESIDENTIAL AND COMMERCIAL SOURCE EMISSION
CONTROL TECHNOLOGIES ....... ...... 106
Efficiency Penalty ...... ........ 106
Reduction Efficiency ..... ........ 107
Cost .................... . 107
REFERENCES ...................... 110
GLOSSARY ......... ...... . ..... 115
LIST OF FIGURES
Page
1 Distribution of all emission factor quality ratings . . 15
2 Percent of emission factors for each gas for which data
was not readily available . . ...... . ...... 16
3 Distribution of emission factor ratings by gas .... 17
4 Distribution of emission factor ratings by source ... 19
VI
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LIST OF TABLES
Table Page
1 Preliminary List of Combustion Sources of Greenhouse Gases 3
2 Revised List of Combustion Related Emission Sources ... 6
3 Combustion Emission Source Data Format 10
4 Emission Control Technology Data Format 12
5 Fuel Properties 26
6 Rating Considerations 30
7 Quality Ratings • 31
8 Utility Boiler Source Performance and Costs 38
9 Global Average Transmission Loss 41
10 Utility Plant Costs 46
11 Utility Emission Controls Performance and Costs .... 47
12 Utility Emission Control Costs 52
13 Industrial Boiler Source Performance and Costs .... 54
14 Industrial Boiler Source Costs 57
15 Industrial Boiler Emission Controls Performance and CostsSS
16 Industrial Boiler Emission Control Costs 61
17 Kilns, Ovens, and Dryers Source Performance 63
18 Kilns, Ovens, and Dryers Emission Controls- Performance and
Costs 67
19 Fuel Production Source Performance 70
20 Fuel Production Emission Controls Performance and Cost 81
21 Refinery Sources and Controls 85
22 Refinery Control Levels 86
23 Fuel Production Emission Control Cost 89
24 Mobile Source Performance 91
25 Mobile Source Emission Controls Performance and Cost . 96
vn
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LIST OF TABLES (Continued)
Table gage
26 Residential Source Performance ............ 99
27 Commercial Source Performance . . 103
28 Residential and Commercial Emission Controls Cost and
Performance 104
29 Residential and Commercial Emission Control Cost . . . 108
Vlll
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SECTION 1
INTRODUCTION AND SUMMARY
The U.S. Environmental Protection Agency (EPA) has been asked by Congress
under the National Climate Program Act to report on the environmental effects
of global climate change and the options available to the global community to
mitigate and adapt to potential global warming. The U.S. National Climate
Program established by the National Climate Program Act involves several
agencies and organizations engaged in interdisciplinary analysis of global
climate and related issues. Within EPA, several programs have been
established to perform the work necessary for supporting the National Climate
Program and to provide the analysis and assessments necessary for the reports
to Congress. EPA's Air and Energy Engineering Research Laboratory (AEERL) is
supporting the technical effort required to estimate a global greenhouse gas
emission inventory and to identify options to reduce these emissions. The
technical effort includes development of emission, efficiency, and cost
estimates for globally significant greenhouse gas emission sources and
development of performance and cost estimates for emission control
technologies.
Rapid expansion of global population and industrial activity have
dramatically increased the emissions of gases and pollutants that are referred
to as greenhouse gases. Greenhouse gases transmit solar radiation and absorb
infrared radiation, as does the glass in a greenhouse, and could result in
significant increases in the global average surface temperature. In the
report to Congress, several atmospheric trace gases are to be evaluated. The
gases considered are C02, CO, CH4, NOX, and N20, which are considered
greenhouse gases or are precursors for atmospheric chemical reactions that
produce greenhouse gases. The concentrations of these five gases are
currently increasing due to both anthropogenic and biogenic emission sources.
Anthropogenic emission sources include combustion and noncombustion
sources. The combustion of fossil fuels is generally considered the major
cause of increasing atmospheric C02 and CO concentrations. Fuel combustion is
also responsible for significant emissions of NOX, which consists of both NO
and N02. N02 and NO are not greenhouse gases, but they are precursors to the
formation of ozone, an active greenhouse gas in the troposphere. Although the
emissions of N20 from combustion are small on a mass basis when compared to
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the emissions of C02, N20 is over 250 times more effective than C02 in
adsorbing infrared radiation (Weiss, 1981).
The purpose of this effort is to develop emission factor estimates and
other data for combustion sources of greenhouse gases. The emission factors
developed for this report are intended for use in estimating a global emission
inventory of C02, CO, CH4, NOX, and N20. To provide options for stabilization
and reduction of emissions of these gases, emission control technologies are
identified for the combustion sources. The emission reduction capabilities of
emission control technologies can be incorporated into developing a global
emission inventory and into forecasting global emissions under various
scenarios.
SCOPE
This project is limited to the evaluation of significant combustion
sources of greenhouse gases. Only sources and controls for which data are
readily available are included in this report. Performance and cost estimates
for advanced combustion technologies and controls and for noncombustion
sources and controls were not included in this study.
Anthropogenic Sources Included in the Study
An initial list of roughly 90 combustion sources was developed as a
starting point for the collection of emission and control technology data.
This list is given in Table 1. After a review of the available literature and
discussions with various experts, the list was revised to roughly 80 sources,
given in Table 2.
The utility sources in Table 2 are the same as those in Table 1. The
industrial boiler category was modified because data were not readily
available for the population of high versus low efficiency boilers, nor were
emission factors readily available for industrial boilers categorized based on
efficiency. The different coal-fired industrial boiler technologies in
Table 1 are represented by a single coal-fired industrial boiler category in
Table 2. Distillate oil-fired boilers were not included in Table 2. Fired
heaters were added as part of the fuel production category because they are an
integral part of the petroleum refining process. The initial listing of
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TABLE 1. PRELIMINARY LIST OF COMBUSTION SOURCES OF GREENHOUSE GASES
Major Categories
Subcategories
Utilities
Industrial Boilers
Fuel Production
Gas - boiler
Gas - combined
Gas turbines
Residual oil
Distillate oil
Shale oil
Municipal waste
Municipal waste
cycle
mass feed
refuse-derived
fuel
Coal
Coal
Coal
Coal
Coal
Coal
Wood
- spreader stoker
fluid bed
fluid bed •
pulverized
pulverized
wall fired
cycle
combined
boiler
coal - cyclone
coal - tangential
Wood
Gas - low thermal efficiency
Gas - high thermal efficiency
Residual - low thermal efficiency
Residual - high thermal efficiency
Distillate - low thermal efficiency
Distillate - high thermal efficiency
Municipal waste
Refuse-derived fuel
Coal - fluid bed
Coal - spreader stoker - low thermal efficiency
Coal - spreader stoker high thermal efficiency
Coal - pulverized coal
Coal - mass stoker
Bagasse/agricultural waste
Gas production & refining
Oil production & refining - w/CH4 wastage
Oil production 4 refining - w/o CH4 wastage
Coal production & cleaning
Oil shale production & refining
Coal gasification - current technology
Coal gasification - advanced technology
Coal liquefaction
Charcoal production
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TABLE 1. (Continued)
Major Categories
Subcategories
Transportation
Residenti al/Commercial
Rail
Jet aircraft
Ship
Aviation gasoline
Gasoline - light duty - pre-control
Gasoline - light duty - post-control
Gasoline - heavy duty
Gasoline - light duty
Diesel -light duty
Diesel - heavy duty
Methanol - light duty .
Methane - light duty
Internal combustion engines - diesel
pipeline transportation
Internal combustion engines - gas
pipeline transportation
Gas turbines
Direct
Direct
Direct
Direct
Direct
Direct
Direct
Direct
Direct
Direct
Direct
Boilers
Boilers
Boilers
Boilers
Boilers
Boilers
Boilers
fired
fired
fired
fired
fired
fired
fired
fired
fired
fired
fired
wood
wood
pits
fireplace
wood stove -
gas heater -
g,as heater -
- oil - old
-oil - modern
- coal fireplace
- coal stove
-.coal central heat
- propane/butane
old/modern
old
modern (pulse)
wood
gas
residual oil
distillate oil
municipal waste
coal
shale
Waste reduction
Waste reduction
Waste reduction
Waste reduction
open burning
open burning
incineration
incineration
municipal waste
agricultural
low efficiency
high efficiency
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TABLE 1. (Continued)
Major Categories Subcategories
Heaters/Furnaces/Ki 1 ns/
Ovens/Dryers
High temperature
High temperature
High temperature
High temperature
High temperature
- distillate oil
- gas
- residual oil
- coal
- shale oil
Intermediate temperature - distillate oil
Intermediate temperature - gas
Intermediate temperature - residual oil
Intermediate temperature - coal
Intermediate temperature - shale oil
Low temperature - distillate oil
Low temperature - gas
Low temperature - residual oil
Low temperature - coal
Low temperature - shale oil
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TABLE 2. REVISED LIST OF COMBUSTION RELATED EMISSION SOURCES
UTILITY
Mass Feed
Refuse Derived Fuel
Natural Gas Boilers
Gas Turbine Combined Cycle - Natural Gas
Gas Turbine Simple Cycle - Natural Gas
Residual Oil Boilers
Distillate Oil Boilers
Shale Oil Boilers
Municipal Solid Waste
Municipal Solid Waste
Coal - Spreader Stoker
Coal - Fluidized Bed Combined Cycle
Coal - Fluidized Bed
Coal - Pulverized Coal Cyclone Furnace
Coal - Pulverized Coal Tangential Fired
Coal - Pulverized Coal Wall Fired
Wood-Fired Boilers
INDUSTRIAL
Coal-Fired Boilers
Residual Oil-Fired Boilers
Natural Gas-Fired Boilers
Wood-Fired Boilers
Bagasse/Agricultural Waste-Fired Boilers
Municipal Solid Waste - Mass burn
Municipal Solid Waste - Small modular
FUEL PRODUCTION
Natural Gas Refining
Catalyst Regeneration
Refinery - Natural Gas Waste Flared
Refinery - Natural Gas Waste Used
Coal Dryer
Oil Shale - Surface Retorting
Oil Shale - In-Situ Retorting
Lurgi Coal Gasification
Coal Liquefaction - Acid Gas
Charcoal Production
Waste Flare - Pure Methane
Waste Flare - Natural Gas
Fired Heater - Natural Gas
Fired Heater - Process Gas
Fired Heater - Distillate Oil
Fired Heater - Residual Oil
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TABLE 2. (Continued)
TRANSPQRTATTON
Rail
Jet Aircraft
Aviation—Gasoline
Ships
Light Duty Gasoline Vehicle
Heavy Duty Gasoline Vehicle
Light Duty Diesel Vehicle
Heavy Duty Diesel Vehicle
Light Duty Methanol Vehicle
Light Duty Compressed Natural Gas Vehicle
Internal Combustion Engine-Diesel (Pipeline)
Internal Combustion Engine — Natural Gas (Pipeline)
Gas Turbine - Natural Gas (Pipeline)
RESIDENTIAL
Wood Pits
Wood Fireplaces
Wood Stoves
Propane/Butane Furnace
Coal Hot Water Heater
Coal Furnaces
Coal Stoves
Distillate Oil Furnaces
Natural Gas Heaters
COMMERCIAL
Wood Boilers
Natural Gas Boilers
Residual Oil Boilers
Distillate Oil Boilers
Municipal Solid Waste Boilers
Coal Boilers
Shale Oil Boilers
Open burning - Municipal Solid Waste
Open burning - Agricultural
Incinerator - Multi-stage
Incinerator - Single Chamber
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TABLE 2. (Continued)
KILNS/OVENS/DRYERS
Kilns - Natural Gas (Cement or Lime Kiln)
Kilns - Oil (Cement or Lime Kiln)
Kilns - Coal (Cement or Lime Kiln)
Coke Oven - Coke Oven Gas
Dryer - Natural Gas
Dryer - Oil
Dryer - Coal
8
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transportation sources is unchanged in the revised listing with the exception
of the deletion of post-control light duty vehicles; the effect of control
technologies for light duty vehicles is estimated as part of the control
technology performance estimates. The original residential and commercial
category was divided into separate categories. The sources within these
categories for the original list are included in the revised list; however, no
data were readily available to distinguish the performance of old from modern
residential sources, so this distinction is not made in the revised table.
Insufficient data were readily available to justify the subdivision of kilns,
ovens, and dryers based on operating temperature, and no data were readily
available from which to estimate emissions of these sources from the
combustion of shale oil.
Type of Data Collected
Table 3 indicates the format of the source performance and cost data
presented in this report. The data for each of the emission sources include
the energy conversion efficiency for utility, industrial boiler, residential,
commercial, and fuel production sources, and for kilns, ovens, and dryers.
Plant costs were developed for utility and industrial boiler sources, and were
levelized on an energy input or energy output basis depending on the
availability of an efficiency estimate. Emission factors were developed on an
energy output basis for utility, industrial boiler, and commercial sources,
and for some other sources where applicable efficiency data were available.
Emission factors for the remaining sources were developed on an energy input
basis, with the exception of some fuel production sources, for which emission
factors were developed based on crude oil production. All of the combustion
technologies considered in this project are currently available.
For each emission source in Table 2, an effort was made to identify
applicable emission control technologies. Most of the control technologies
included in this report are currently available. However, some advanced
control technologies were included in this study to provide an option for more
stringent control of a specific greenhouse gas or, in the case of advanced
utility controls for C02, to provide an option for controlling a gas that
cannot be reduced by current methods.
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TABLE 3. COMBUSTION EMISSION SOURCE DATA FORMAT
Emission Source
Technology
Efficiency
(X)
Cost
(J/joule)
Emissions (kg/joule)
C02 CO CH^
H20 NOX
Applicable Control
Technology Codes
Utility eff. = Joule = energy Joule = energy delivered to
fuel heat value/ delivered to user. user except transportation
electricity and kiln/oven/dryer where
delivered to joule is fuel heating value.
user. Emissions = uncontrolled
emissions.
Industrial and $ = cost in 1985
residential eff. = excluding fuel costs.
fuel energy in/
energy delivered
to user.
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The general format of the control technology performance and cost data is
presented in Table 4. For control technologies, an efficiency penalty on the
combustion technology was estimated, as was the removal efficiency for the
five greenhouse gases considered in this study. Emission control costs were
developed on an energy input or energy output basis, depending on the basis
for the combustion technology cost. For each control technology, an
availability date was estimated.
The emission factors developed in this report represent sources without
control technologies. To calculate the baseline global emission inventory for
the regions of the world, appropriate controls can be applied to specific
source categories to represent the current application of control technologies
in some countries. This report does not attempt to identify which controls
should be applied to represent current control levels in different parts of
the world. This is the subject for a study in itself.
Data Quality
For each emission factor, a data quality rating was assigned to indicate
the relative quality of the emission factors within this database. The data
quality ratings can also be used to identify areas that could benefit from
additional research. A few of the factors that affect the quality of an
emission factor include the quality of the emission data, which are typically
available on the basis of mass of pollutant emitted per mass of fuel burned,
the quality of the fuel properties used to convert the emission factor to an
energy basis, and the quality of efficiency estimates used to convert the
emission factor to an end-use energy basis. The emission data may be subject
to variability due to variations in the design, operation, and maintenance at
specific sources. These factors were taken into consideration when assigning
emission factor ratings.
Report Format
A more complete discussion of the general approach used to develop
performance and cost estimates for combustion sources and emission control
technologies and of the basis for the emission factor quality ratings is given
in Section 2. Sections 3 through 8 present the performance and cost estimates
11
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TABLE 4. EMISSION CONTROL TECHNOLOGY DATA FORMAT
Control Device
Technology Code
Performance (X reduction)
trnciency Penalty* Cost Availability
(X) ($/joule) (date) C02 CO CH4 H20 NOX
Expressed as X of Cost = 1985 t
combustion device
efficiency
'Hay be a benefit in some cases.
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for emission sources and control technologies within the utility, industrial
boiler, kilns, ovens, and dryers, fuel production, mobile source, and
residential and commercial categories. The specific methods used to develop
performance and cost estimates for each source category are discussed in the
appropriate section. The results of the study are summarized below.
SUMMARY
For this study, performance and cost estimates were developed for
globally significant combustion sources of C02, CO, CH4, NO,, and N20 and for
applicable emission control technologies. Although the intent of this work
was to develop globally representative estimates, international performance
and cost data were not readily available for most of the sources and controls.
In many cases, data were not available from which to estimate the emission
factors of all five of the gases for a given source; in particular, few data
are available from which to estimate emission factors for N20. The emission
factors for C02 were generally calculated from a carbon balance.
For most sources and control technologies, the performance and costs are
based on U.S. data. The emission data developed under various EPA projects
represent the most extensive, highest quality, and most accessible information
available from which to calculate source emission factors, efficiency, and
cost, as well as emission control removal efficiency, efficiency penalty, and
cost. Although data are available from the United Nations to estimate global
fuel consumption and in some cases energy conversion efficiency, the data
readily available from the United Nations Statistical Office and Environment
Programme are not suitable for a disaggregated analysis (i.e. few data are
available for specific combustion technologies). However, the United Nations
data can be used to estimate, for example, the overall energy conversion
efficiency of all utility sources in various geopolitical regions of the
world. The Organization for Economic Cooperation and Development (OECD) has
addressed global fuel consumption and environmental issues, but again the data
available from the OECD do not directly support the development of source
specific emission factors. The use of source-specific U.S. data was generally
required due to the absence of readily available data from international
sources; however, in many cases the U.S. data may be globally representative
of the energy-specific emissions of the five greenhouse gases considered in
this study.
13
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The emission factor quality ratings are summarized in Figures 1 through 4
to indicate the overall quality of this emission factor database. The
emission factors were given quality ratings from "A" to "E," with an "A" being
the best. Figure 1 indicates that the distribution of the ratings is fairly
even; roughly 35 percent of all emission factors have a rating of "B" or
higher, while about 39 percent of the emission factors have a rating of "D" or
lower.
Figure 2 shows the percentage of the total number of emission factors for
each of the-five gases for which data were not readily available. The figure
indicates that in general data were readily available for NOX and CO. For
nearly all sources it was possible to calculate C02 emission factors using a
carbon balance. The carbon balance generally accounts for the conversion of
carbon in the fuel to C02, CO, and CH4. In many cases, the emission factors
for C02 are orders of magnitude greater than for any other carbonaceous
species. Therefore, it was possible to estimate with reasonable accuracy C02
emission factors for many sources for which CO and/or CH4 emission factors
were not available. For this reason, the percent of C02 emission factors for
which data was not readily available is less than the percent of CO and CH4
emission factors for which data was not readily available.
Only limited data were readily available from which to estimate N20
emission factors. For approximately 90 percent of the sources included in
this study, data were not available from which to estimate an N20 emission
factor.
Figure 3 indicates the overall quality of the available emission factors
for each of the five gases. The N20 quality rating of "E" for all N20
emission factors reflects the lack of sufficient test data from which to
develop high quality emission factors. The emission factors for CH4, many of
which were estimated based on a percentage of total hydrocarbon emissions,
generally have lower ratings than CO and NOX emission factors. The emission
factors for CH4 tend to be smaller in magnitude compared to NOX or CO emission
factors. The distributions of ratings for NOX and CO emission factors are
fairly uniform. The emission factors for C02 were generally given higher
quality ratings than the other four gases, even though C02 emission factors
were generally calculated from a carbon balance. C02 represents the largest
14
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Source Emissions Rating Distribution
Total of all Groups and Compounds
A'3 (18.37.)
E's (24.2%)
D's (14.4%)
B's (17.07.)
C's (26.1%)
Figure 1. Distribution of all emission factor quality ratings
15
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100
en
90 -
40 —
8,
30 -
A
DL
20 -
10 —
CXX
CO
NOx
Emission Compounds
Figure 2. Percent of emission factors for each gas for which data was not readily available.
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V
en
o
-»J
c
0
u
i.
I)
Q.
100
90
80 -
70 -
60 -
50 -
40 -
30 -
20 -
10 -
0
Source Emissions Rating Distribution
by Emission Compound
C02
X
X
X
x
X
x
x
x
XI
CH4
N20
NOx
A's
B's
C's
D's
Figure 3. Distribution of emission factor ratings by gas.
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carbonaceous species emitted by most combustion processes by several orders of
magnitude; therefore, uncertainty associated with the emissions of CO, CH,, or
other carbonaceous species as gases or solids generally has a negligible
impact on the C02 emission factor estimate and on the C02 emission factor
rating.
Figure 4 shows the distribution of emission factor ratings for all gases
for each source category. Overall, the source categories with the best
emission factor ratings are also the most significant emission sources.
Utility and industrial boiler sources have the best overall ratings. N20
emission factors account for most of the "E" ratings for these two sources.
NOX and CO emission factors in these two categories generally have ratings of
"A" and "B". Most of the transportation sources CH4 and N20 emission factors
have a rating of "D" or lower. Kilns, ovens, and dryers noticeably have the
lowest overall emission factor quality rating; only C02 emission factors have
ratings as high as "B" and "C" in the kilns category. The emission factors
for fuel production sources are also generally of lower quality than for other
sources, with ratings of "C" and "D" evenly distributed for C02, NOX, CO, and
CH4 emission factors.
The cost estimates are sensitive to the assumptions made regarding
capacity factor when calculating annualized cost on an energy basis. Costs
are also sensitive to the size of the facility being costed. When possible,
reasonably representative source capacities were selected. However, in many
cases, cost information was readily available for only a single source
capacity. Costs vary considerably globally due to differences in labor costs,
financing methods, inflation, taxes, and regulations from one country to
another. The cost estimates should be regarded as rough estimates that
indicate the relative cost of one technology to another.
The emission factor quality ratings identify some areas that could
benefit from additional research. Many more test data are required before N20
emission factors can be developed for any sources with good confidence. The
applicability of U.S. data to develop globally representative emission
18
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V
o
*c
0
o
Q.
70
60
50 -
40
30 -
20 -
10
o
Source Emissions Katmg Distribution
by Source Group
Utility
A's
v\
X
x
X
x
x
x
X
x'
x
X
X
X
X
X
X
X
X
X
X
X
><
><
Industrial Transportation Residential
B's
C's
Conmercial
D's
Kilns/Ovens/
Dryers
Fuel Production
E's
Figure 4. Distribution of emission factor ratings by source.
-------
performance for emission sources from one region of the world to another would
indicate that emission source parameters should be estimated independently for
different regions of the world. Additional study, and possibly source
testing, may be required to fill gaps in the emission database and to improve
the quality of emission factors. The impact of control technologies on N20
emissions requires more testing.
Specific tasks for further development of this database could include
additional literature search, consultation with experts in the United States
and internationally, and source testing, including the impact of control
technologies on N20. Data from these activities could be used to improve the
accuracy of current estimates, provide data where data is currently not
included, and develop new emission source and control categories to account
for regional differences in performance and cost.
20
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SECTION 2
DATA REQUIREMENTS AND GENERAL TECHNICAL APPROACH
This section describes methods used to develop emission estimates and other
data for globally significant anthropogenic sources of C02, CO, CH4, NOX, and
N20. Where data were readily available, energy conversion efficiency, energy-
based emission factors, control technology performance and cost, and source
cost were estimated. Control technology performance parameters investigated
include the efficiency penalty on the energy conversion process, the removal
efficiency for each of the five gases, and the availability date of the
technology.
Specifically, an emission factor quality rating scheme was developed to
provide some insight into the accuracy of the emission factors. The rating
criteria are described in this section, as are the control performance
estimate and the method used to estimate costs for both emission sources and
controls.
This section presents only a general discussion of the approaches
commonly used to estimate emission and cost parameters. Additional details
specific to each parameter are discussed in Sections 3 through 8.
EMISSION FACTOR ESTIMATES
The emission factors developed in this report represent the
"uncontrolled" emissions from each source. The factors are usually presented
on a mass of pollutant per unit energy basis. In some cases, the energy
delivered to an end-user is used as the energy basis. The energy basis used
within each source category is appropriately noted in the following sections.
Many of the emission factors presented in this report were estimated from the
Compilation of Air Pollutant Emission Factors, referred to throughout this
report as AP-42 (U.S. EPA, 1985). The emission factors in AP-42 are generally
reported on the basis of mass pollutant per unit mass of fuel consumed. The
AP-42 mass-based basis emission factors were converted to an end-user energy
basis, where appropriate using the fuel heating value and source energy
conversion efficiency as follows:
EF = (AP-42 EF) x _i_ x _±_ (1)
HV EFF
21
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where:
EF = energy based emission factor (mass pollutant per unit energy
output).
AP-42 EF = AP-42 emission factor (mass pollutant per unit input fuel
mass or volume).
HV = fuel heating value (energy per unit fuel mass or volume).
EFF = energy conversion efficiency (fraction).
The calculation of an energy output-based emission factor requires that energy
conversion efficiency be estimated. The calculation of either an energy
output- or energy input-based emission factor from a mass basis factor both
require the fuel heating value.
The next two subsections discuss energy conversion efficiency, fuel
properties and energy basis emission factor development.
Energy Conversion Efficiency
Energy conversion efficiency is the ratio of energy output to energy
input for an energy conversion technology. The input to energy conversion
technologies included in this study is fuel energy. The output for a utility
plant is electricity, which can be measured either at the busbar or after
transmission and distribution. Utility efficiency data developed in this
study are based on electricity delivered to end-users after transmission. For
industrial boilers, the output is the incremental energy added to the boiler
feed water for steam generation. For a kiln, oven, dryer, or process heater,
the output is the thermal energy added to a material (e.g., for refinery
process heaters it is the amount of energy added to the feedstock).
Efficiencies were not developed for some emission sources because either
energy conversion efficiency data were unavailable or it was more
representative to develop emission factors on an energy input basis or a
per pound of product basis.
The utility end-user energy conversion efficiency includes the
multiplicative effects of boiler efficiency, thermal cycle efficiency,
turbine-generator efficiency, and transmission losses. For both utility and
industrial boiler sources, the factors that impact efficiency are the same;
these factors include boiler design, fuel type, maintenance, operation, age,
22
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size, utilization, altitude, and the presence of pollution control equipment.
Typically, boiler efficiency decreases with age, poor maintenance and
operation, decreasing size, increasing altitude, low loads, and addition of
pollution control equipment.
For most sources, data are not readily available from which to estimate
globally representative energy conversion efficiencies. Exceptions include
gas turbines, which are traded internationally, and utility sources, for which
the United Nations compiles fuel use and electricity generation data. The
United Nations data indicate that significant variations in the efficiency of
utility plant energy conversion in different regions of the world. However,
the United Nations data do not provide a breakdown of efficiency data for the
boiler types included in this study. Because of the limited availability of
this type of international efficiency data, efficiency estimates for most
sources are based on data for U.S. emission sources.
In general, the efficiency estimates based on U.S: data are reasonably
representative of the global average efficiency of new technology. Utility
plants, for example, are built internationally primarily by U.S., Japanese,
and European manufacturers and contractors, and generally have similar
performance (Wilmoth, J., Combustion Engineering, Windsor, CT, personal
communication, August 1987).
Estimates based on U.S. technology may not account for differences in
efficiency due to technology already present in various regions of the world,
which may have been poorly designed, built, operated, and maintained.
However, an analysis of data for eight countries indicates that, over time,
estimates applied globally based on U.S. efficiencies can be expected to
reasonably approximate the energy conversion efficiencies of the most
significant fuel consuming regions of the world.
Some technologies, such as industrial boilers, may be subject to more
global variability than utility boilers because they can be procured
domestically in many countries (Westsik, J., Bechtel Power Corporation, San
Francisco, CA, personal communication, August 1987). However, most industrial
regions of the world, which represent the largest fraction of fuel consumption
and combustion-related emissions, are likely to have boiler efficiencies
similar to those in the United States.
Although boiler efficiencies may be similar in the most significant fuel
consuming regions of the world, the efficiency of industrial fuel use per unit
of delivered product does vary significantly from country to country. For
23
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example, in 1976 the United States used 21 million Btu to produce one ton of
steel, whereas Germany used only 13 million Btu (Dean, 1980). The significant
variations in industrial efficiency suggest that boiler efficiency is only one
of many constraints on overall process efficiency, and that process fuel
requirements per unit product manufactured are subject to global variation.
However, because boilers are a significant emission source, and because of the
variation of fuel requirements for industrial processes, only boiler energy
requirements and emissions are included in this study.
The efficiency estimates developed for this work in general should be
regarded as reasonable, nominal values for well-maintained and well-operated
facilities. The energy conversion efficiencies are based on representative
U.S. data.
Emission Factors
This section discusses the methods used to estimate emission factors for
C02, CO, CH4, NOX, and N20. The sources of information for emissions of the
five gases will be discussed briefly, followed by discussion of the need for
fuel properties and efficiency to calculate energy based emission factors.
Emission factor estimates were derived based primarily on data available
in various EPA documents. Typically, emission data for NOX, CO, and CH4 were
available from AP-42, background information documents for New Source
Performance Standards, environmental assessment studies for various sources,
and from source test reports. No emission factors were available for N20,
although limited test data were available for several sources. C02 emission
factors were calculated from fuel properties and a carbon balance by assuming
that, in many cases, all fuel carbon is transformed into C02, CO, and CH4.
The emission factors developed in this study are for uncontrolled
emission sources. To estimate a global emission inventory, additional data
will be needed so that the global application of emission control technologies
can be simulated. Emission reduction and energy efficiency penalty data for
currently available and some advanced pollution control technologies were
developed as part of this study but no attempt was made to define the use of
these technologies around the world. The development of the control
24
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technology performance data will be discussed in more detail later in this
section.
The fuel properties required for this study include heating value and
weight percent of carbon in the fuel. The heating value is required to
convert emission factors available in AP-42 and other sources from a mass of
pollutant per mass fuel basis to a mass of pollutant per unit energy basis.
The carbon content of the fuel is required to calculate C02 emissions.
Table 5 includes the nominal heating values and carbon contents used for
16 different fuels considered in this study. Heating values and carbon
contents were selected based on representative U.S. values because detailed
global data were not readily available. Actual heating values and carbon
contents will vary from one region of the world to another for various fuels.
For example, based on an analysis of data from the International Energy Agency
(IEA) and lignite coal, average regional heating values vary from
approximately 7,500 Btu/lb for the Organization for Economic Cooperation and
Development (OECD) countries in Asia to nearly 10,900 Btu/lb for the continent
of Africa (WCRR, 1983). A value of 10,000 Btu/lb was selected as
representative of subbituminous/bituminous coals, which comprise roughly 65
percent of the world's accessible coal on a mass basis. The carbon content
for coal of 65 percent is based on an average of many subbituminous/
bituminous coals.
For utility and industrial boiler sources, emission factors were
calculated on the basis of mass of pollutant per unit energy output. These
calculations require both a fuel heating value and an energy conversion
efficiency. The general equation for this calculation was presented earlier
as Equation 1. For most other sources, emission factors are presented on a
mass of pollutant per fuel energy input basis. These emission factors are
typically calculated from a mass pollutant per mass (or volume) fuel emission
factor from AP-42 using the general expression:
EF = (AP-42 EF) x _1 (2)
HV
where:
EF = energy based emission factor (mass pollutant per unit energy
input)
25
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TABLE 5. FUEL PROPERTIES8
Fuel
GAS
Butane/Propane
Coke Oven Gas .
Methane (pure)
Natural Gas
Process Gas
LIQUID
Crude Shale Oil
Diesel/Distillate
Gasoline
Jet A
Methanol
Residual Oil
SOLID
Bagasse/Agric .
Charcoal
Coal
MSW
Wood
Heating Value
(MJ/kg)b
50.8
40.8
50.0
51.1
54.0
43.1
45.2
123 MJ/gal
43.2
59 MJ/gal
43.0
9.1
29.1
23.2
11.3
10.6
Carbon
(wt percent)
82.0
56.1
75.0
70.6
70.6
84.5
87.2
85.7
86.1
37.5
85.6
22.6
87.0
65.0
26.7
27.0
3 Heating value and carbon content values are intended to be nominal,
representative values. Actual fuel properties will vary.
b Unless otherwise indicated.
Sources: Babcock and Wilcox, 1978; Moscowitz, 1978; Perry and Chilton,
1973; Singer, 1981; UNEP, 1985; U.S. EPA, 1982a.
26
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AP-42 EF = AP-42 emission factor (mass pollutant per unit input fuel mass
or volume)
HV = fuel heating value (energy per unit fuel mass or volume)
For some fuel production sources, emissions are calculated based on a mass of
pollutant per unit of crude oil produced, using typical fuel consumption per
unit of crude oil produced for a specific technology (e.g., process heater).
The emission of C02 from a combustion source depends on the amount of
carbon entering the process in the fuel and the amount of carbon leaving the
process in various forms as part of the products of combustion. The carbon in
the fuel is converted to CO, C02, CH4, and other carbonaceous species that are
exhausted as part of the flue gas. Carbon is not generally retained in ash
formed during combustion (Singer, 1981). In most cases, the emission of C02
is orders of magnitude higher than that of any other carbonaceous species on a
mass basis. The general expression used to calculate C02 "emissions, including
both CO and CH4 in the carbon balance, is:
EFC02 = MWC02 %C_ x 1 - EFFCH,, - EFCO (3)
HV MWC MWCH4 MWCO
where:
EFC02 = C02 emission factor (g C02/GJ)
MWC02 = molecular weight of C02 (44 g/gmole)
%C = percent carbon in fuel, by weight (% fraction)
HV = fuel heating value (GJ/g)
MWC = molecular weight of carbon (12 g/gmole)
EFCH4 = CH4 emission factor (g CH4/GJ)
MWCH4 = molecular weight of CH4 (16 g/gmole)
EFCO = CO emission factor (g CO/GJ)
MWCO = molecular weight of CO (28 g/gmole)
In some cases, additional carbon-containing compounds were included in the
carbon balance. For example, methanol is emitted in significant quantities
from methanol-fueled automobiles, and was included in the carbon balance. The
27
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C02 emission factors presented in this report were calculated including both
CO and CH4 in the carbon balance, unless otherwise noted.
Nonmethane hydrocarbons were not included in the carbon balance. In some
cases, particularly for transportation sources, the emission of nonmethane
hydrocarbons is greater than that of methane, but the overall effect on the
C02 emission factor of neglecting nonmethane hydrocarbons in the carbon
balance is negligible because C02 emissions are always roughly two to three
orders of magnitude greater than hydrocarbon emissions. In several cases,
however, CO emissions represent a substantial fraction of the total CO and C02
emissions. For these reasons, the C02 emission factor, calculated based on a
carbon balance including CO and CH4, provides an accurate estimate of C02
emissions. The accuracy of the estimate is limited primarily by the quality
of the fuel property data.
EMISSION FACTOR DATA QUALITY RATING
Because the emission factors developed for this study were derived from a
variety of sources and generally required conversion from a mass to an energy
basis using fuel properties, a rating scheme was developed to consistently
characterize the quality of the emission factors. The rating scheme developed
for this work is similar to rating schemes used in AP-42. Some additional
considerations are included in the ratings because some of the emission
factors were derived from sources other than AP-42 and because additional
calculations were performed to estimate emission factors on an energy basis.
First, considerations relevant to emission factors calculated based on AP-42
data will be discussed, followed by a discussion of quality rating
considerations for factors derived from other sources. These discussions will
be followed by a summary of the rating scheme.
In the cases where emission factors are based on data obtained from
AP-42, the AP-42 emission factor quality rating, (generally "A" through "E,"
with "A" being the best) was adopted. These ratings were adjusted downward
if, in the judgment of the engineering staff, the use of fuel property data to
convert from a mass basis to an energy basis would degrade the quality of the
emission factor. For the cases where emission factors were calculated on an
energy output basis, the AP-42 rating was adjusted downward if the quality of
28
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the efficiency estimate was judged to reduce the quality of the emission
factor. In no case was an AP-42 emission rating increased.
Data obtained from sources other than AP-42 were evaluated based on the
quality and quantity of test data available from which to develop an emission
factor. A large quantity of data, obtained by EPA approved test methods, with
little scatter, would receive an initial rating "of "A", but could be adjusted
downward as for an AP-42 rating based on the quality of fuel or efficiency
data used in calculating an energy basis emission factor. The ratings for
factors other than AP-42 also were adjusted downward if significant variation
in emissions could be expected in the emission source population due to
variations in design, maintenance, and operation.
The primary and secondary considerations used in developing the emission
factor quality ratings are summarized in Table 6. The primary considerations
involve evaluating the source and quality of the emission data. For AP-42
derived factors, the AP-42 rating is converted directly to an "A" through "E"
rating; for other data, an "A" through "E" rating is assigned based on the
quantity and quality of the emissions data as discussed. The secondary
considerations may result in reduction of the quality rating. The secondary
considerations, regardless of the source of the emission data, include process
variability, the quality of fuel properties used to convert to an energy
basis, and the quality of the efficiency estimate used to convert to an energy
output basis, where appropriate. Table 7 summarizes the guidelines for using
the primary and secondary considerations to assign ratings for each emission
factor. In some cases, emission factors may be assumed to be valid for more
than one source due to similarities between sources and lack of emission data
for one of the sources. A transfer of an emission factor from one technology
to another will generally result in an "E" rating because of the lack of data
for the source in question. An example is the use of data for residual oil
fired utility boilers to estimate emissions from shale oil-fired utility
boilers. The rating for the C02 emission factors includes assessment of the
impact on the C02 factor of possible variation in fuel properties, variation
in emissions of CO and CH4, and emissions of carbonaceous species not included
in the carbon balance.
Because these ratings are qualitative, they indicate only the relative
quality of the emission factors within this database and indicate areas that
could benefit from additional research. The ratings presented for each factor
29
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TABLE 6. RATING CONSIDERATIONS
Consideration
Description
PRIMARY CONSIDERATIONS FOR INITIAL RATING
• Data from AP-42 Use AP-42 rating as an initial rating.
• Data from other sources Evaluate quantity of data, test methods
used, and data scatter to assign an
initial rating.
0 Data for C02 estimates
SECONDARY CONSIDERATIONS
• Process variability
• Fuel properties
Efficiency
In addition to evaluating the quality of
fuel property data, evaluate the impact of
variation of emissions of all carbonaceous
species on variation of emissions.
Reduce initial rating if emissions are
subject to significant variation due to
variation in design or operation within a
source population.
Reduce initial rating if significant
variation can be expected in the fuel
properties used to calculate emission
factors, and/or fuel properties based on
limited data.
Reduce initial rating if efficiency
estimate is subject to significant
variation within a source population,
and/or efficiency estimates based on
1imited data.
Technology transfer
Use a low rating if emission factors for a
given source are assumed the same as
another source due to process
similarities.
30
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TABLE 7. QUALITY RATINGS3
Rating
A
B
C
0
E
i Confidence
Primary Considerations Secondary
High
High
Medium-High
Medium
Low-Medium
Considerations"
High
Medium
Low-High
Medium
High-Low
aThis table provides a general indication of the meaning of each rating,
but does not represent strict guidelines.
bSee Table 6.
31
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reflect the professional judgment of the engineering staff; these ratings
roughly indicate the accuracy with which the emission factors can be used to
estimate emissions from a large number of sources.
EMISSION CONTROLS PERFORMANCE ESTIMATES
For each emission source technology, an attempt was made to identify
emission control technologies that can be applied to reduce emissions of one
or more of the five gases considered in this study. For a few sources, no
control technologies could be readily identified, whereas for most sources,
such as fossil fuel-fired utility plants, many control technologies could be
identified. The performance parameters estimated for each control technology
include the removal efficiency for each of the five gases, the emission source
energy efficiency penalty associated with the energy requirements of the
control technology, and the availability date for the control technology.
Each of these parameters will be discussed separately in the following
subsections.
Removal Efficiency
The removal efficiency for a given pollutant was determined from accepted
values from the literature or from test data for technologies that are
currently under development. In general, typical efficiencies from other EPA
studies were used, where available. The removal efficiency is defined as
follows:
Uncontrolled Emissions - Controlled Emissions
Removal Efficiency = (4)
Uncontrolled Emissions
The removal efficiency may be either positive or negative. A positive removal
efficiency indicates that the pollutant is reduced, whereas a negative removal
efficiency indicates that the pollutant is increased. For example,
automobiles equipped with catalytic emission controls generally have lower CO
and NOX emission rates than automobiles without emission control; however, C02
emissions increase because CO is catalytically converted to C02, resulting in
a negative C02 removal efficiency. In many other cases, where CO emissions
32
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are a much smaller fraction of the total carbonaceous emissions for a source,
a decrease in CO emissions may result in only a negligible increase in C02
emissions.
The removal efficiencies were selected to be representative of reasonable
average maximum removal efficiencies. For example, selective catalytic
reduction may be capable of 90 percent NOX removal for sources burning very
low sulfur fuels; however, 80 percent NOX removal is a reasonable average
removal efficiency for a larger range of fuel and operating conditions, and is
therefore more representative of the global average emission reduction
achievable with this particular technology.
Emission Source Efficiency Penalty
Most emission control technologies impact the overall efficiency of the
emission source. Flue gas treatment systems, for example, create an
additional pressure drop in the flue gas exhaust system, which must be
overcome by an induced draft fan. The induced draft fan requires additional
electricity. Other control technologies may modify the combustion conditions
in a furnace, resulting in less than optimum combustion as a trade-off for
reduced emission of a particular pollutant. Where data were readily
available, these and other energy penalties due to control technologies were
estimated in terms of a percent penalty on the emission source efficiency.
The efficiency penalty can be represented by the following equation:
Uncontrolled Efficiency - Controlled Efficiency
Percent Penalty = (5)
Uncontrolled Efficiency
where "uncontrolled efficiency" is the efficiency of the emission source
without emission control, and "controlled efficiency" is the efficiency of the
emission source with the emission control technology. The efficiency penalty
can be either positive or negative. A negative penalty indicates an
improvement in source efficiency.
33
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Availability Date
For each control technology, an availability date was estimated. The
availability date indicates the first year in which a control technology was
or may reasonable be expected to be commercially available. For existing
commercially available technologies, the availability date is based on the
first mention of application of the technology in the literature. The
availability dates of advanced technologies currently under development are
based on engineering judgment or, in some cases, on the date that the
technologies are required due to emission regulations in the United States.
EMISSION SOURCE AND CONTROL COSTS
The basis for cost estimates for both emission sources and emission
control technologies are discussed in this section, as are the internationally
accepted constant dollar costing method. The data requirements for costs are
discussed below. Finally, key sources of variation for the costing are
discussed.
International Costing
The cost method of the International Union of Electricity Producers and
Distributors (UNIPEDE) is widely accepted as a means for making meaningful
international cost comparisons. Using a constant dollar approach, capital
costs are levelized over the economic life of a facility by using the real
escalation rate, which is simply the discount rate for borrowing money, the
effects of inflation and taxes, which are specific to each country, are
thereby excluded.
All costs are in 1985 constant dollars. The total annual cost includes
the annual capital charge and the operating, maintenance, and fuel costs. For
this study, fuel costs are excluded. The total annual costs developed using
this method are independent of future inflation rates.
34
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Cost Data
Costs are presented for utility and industrial boiler sources and for all
control technology categories. The data requirements for the costing includes
total capital cost, nonfuel annual costs, economic life, discount rate,
facility size or capacity, and capacity factor. The annual ized cost in
constant dollars is converted to an energy basis by dividing the cost by the
annual energy input for the source in question. For utility and industrial
boiler sources, the costs are calculating on an energy output basis using the
energy conversion efficiency discussed earlier. The general equation used to
develop the cost estimates is:
CC (CRF) + AC
Cost ($/J) = - (6)
CAP (CF) (8,760) (EFF)
where:
CC = capital cost (1985 dollars)
CRF = capital recovery factor
AC = annual non-fuel operating and maintenance costs (1985 dollars)
CAP = capacity (Joules/hr)
CF = capacity factor (fraction)
EFF = energy conversion efficiency (fraction)
The capital recovery factor is calculated from the equation:
CRF = - (7)
- 1
where:
i = discount rate (decimal)
n = economic life (years)
From Equation 6, it is apparent that the level ized cost on an energy
basis is sensitive to the choices made for capacity factor and source
capacity. Capacity factor in general will affect the annual operating costs.
35
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Variation in source capacity will change the levelized cost due to economy of
scale effects. The levelized cost is also sensitive to the capital recovery
factor. As seen in Equation 7, the assumptions regarding interest rate and
economic life will determine the capital recovery factor.
Sources of Variation in Costing
The costs developed for this study are based on representative U.S. costs
expressed in constant 1985 dollars. However, capital and operating costs for
a specific plant, both within the United States, and to an even greater extent
on a global scale, will be influenced by a number of factors, including:
construction and operating labor costs (productivity, skill level,
availability, wage rates),
fuel quality (heating value, ash content for coal),
site conditions (congestion, terrain, altitude, climate),
• plant capacity factor,
• financing costs (financing method, inflation, interest rates, length
of construction), and
• regulatory policies (environmental and utility commission policies).
A comparison of capital costs for coal-fired utility plants constructed in
industrialized countries (United States, western Europe, and Japan) revealed
variations of up to 50 percent, due in part perhaps to variations in currency
exchange rates (Verbeek and Gregory, 1986). For utility sources, plant
capacity factor varies significantly for fossil fuel-fired plants from
28 percent in South America to 59 percent in the USSR (United Nations, 1986).
The costs presented in this report are intended as indicative of the
relative costs of various technologies. Actual costs may vary significantly
from these values for a given facility due to site specific and regional
variations in construction costs, labor, financing, and regulations.
Therefore, these costs should be viewed as only approximately representative
of global cost estimates, and as such, great care should be taken in
qualifying any conclusions reached as a result of the use of these cost
estimates.
36
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SECTION 3
UTILITY SOURCES AND CONTROLS
As part of the utility category, performance and costs estimates were
developed for 15 utility plant technologies and for 9 emission control
technologies. The source and control technologies primarily include
conventional, commercially available technologies. The first part of this
section discusses the development of efficiency, emission factor, and cost
estimates for utility sources. A discussion of efficiency penalty, emission
reduction efficiency, and costs for utility emission control technologies
follows. A glossary of all abbreviated terms appearing in the tables of this
section appears at the end of this report.
DATA FOR EMISSION SOURCES
Table 8 summarizes the efficiency, emission factor, and cost estimates
developed for 15 utility plant technologies. These include natural gas,
distillate oil, residual oil, shale oil, coal, wood, and municipal solid waste
(MSW) combustion technologies. The efficiency for each technology is based on
the conversion of fuel energy to electricity delivered to the user. Costs are
1985 annualized costs based on the total electricity delivered to the user
over a period of 1 year. Uncontrolled emission factor estimates are reported
on the basis of grams of pollutant emitted per gigajoule of electricity
delivered to the user. To the right of each emission factor is the emission
factor quality rating. For each utility technology, appropriate control
technologies are identified by codes. The codes within parenthesis are
retrofit options.
Efficiency and Transmission Loss
The utility plant efficiency estimates reported in Table 8 represent the
conversion of fuel energy to electricity delivered to end-users through a
transmission and distribution system. Typically, power plant electrical
generation is measured at the busbar, which approximately represents the
boundary between the power plant and the electrical distribution system.
Additional losses in transformers, transmission wires, and other equipment are
37
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TABLE 8. UTILITY BOILER SOURCE PERFORMANCE AND COSTS
Emissions Factors (g/GJ delivered electricity) and
Data Quality Ratings (A - E)
Source
Efficiency Cost
(X) <$/J end-use)
CO
CO
CH.
NO
Controls
OJ
00
Natural Gas - Boilers 32.1 6.4E-09 150.000 A 53 A 0.4 C N/A 740 A
Gas Turbine Confined 42.0 4.3E-09 120,300 A 70 A 13 C
Cycle
Gas Turbine Sinple 26.4 1.0E-09 191,400 A 110 A 20 C
Cycle
Residual Oil Boilers 32.4 6.7E-09 230,000 A 43 A 2.2 A N/A 590 A
U1, U3. U8, U10,
U13, U18, (U19, U21,
U25, U26. U27)
N/A 400 A U14. U15
N/A 640 A U14. U15
U1, U4, U7« U10,
U12, U17, (U19, U22.
U24. U26, U27)
Distillate Oil
Boilers
32.4 6.7E-09 220,000 A 43 D 0.1 D N/A 200 D
U1. U4, U7, U10,
U12, U17, (U19, U22,
U24. U26. U27)
Shale Oil Boilers 32.4 6.7E-09 230,000 E 43 E 2.2 C N/A 590 E
U1. U4, U7, U10,
U12, U17. (U19, U22,
U24. U26, U27)
HSU - Mass Feed
18.7 3.8E-Oa 460,000 D 500 B N/A
HSU - Refuse Derived 18.7 3.8E-08 450,000 D N/A N/A
Fuel
N/A
N/A
710 B
N/A
U1
U1
-------
TABLE 8. (Continued)
Emissions Factors (g/GJ delivered electricity) and
Data Quality Ratings (A - E)
Source
Efficiency Cost
(X) (S/J end-use)
CO
CO
CH
N2°
NO
Controls
CJ
Coal-Spreader Stoker 31.0
Coal-Fluidized Bed 35.0
Combined Cycle
Coal-Fluidized Bed 31.4
Coal - Pulverized 31.3
Coal
CoaI-Tangentially 31.3
Fired
Coal - Pulverized Coal 31.3
Uall-Ftred
Wood-Fired Boilers
15.9
N/A 340,000 C 370 B 2.1 B 2.5 E 1,000 B U1, U2. U10, U11.
U16, (U19, U20, U27)
1.2E-08 290,000 C N/A
9.5E-09 330,000 C N/A
9.5E-09 330,000 C 42 B
1.8 C
2.0 C
2.0 B
9.5E-09 330.000 C 42
1.3E-08 590,000 C 8,800 D 88 E
N/A
N/A
2.5 E
N/A
770 C
2,600 C
9.5E-09 330,000 C 42 8 2.0 B 2.5 E 1.000 B
U10, U12, U16. (U27)
U10. U12, U16. (U27)
U9, U10, U11, U16,
(U27)
U1, U2. U6, U10,
U11, U16, (U19, U20,
U23. U26, U27)
2.0 B 2.5 E 1,400 B U1. U2. U5, U10,
U11, U16, (U19, U20,
U23, U26, U27)
N/A 670 C U1. U10, U11, (U19,
U27)
All costs in 1985 dollars.
Control codes in parenthesis indicate the retrofit emission control options. The controls are defined ibn Table 11.
-------
incurred in the distribution of electricity from the power plant to the end-
users.
To estimate the end-user energy conversion efficiency, first the busbar
efficiency was estimated; the busbar efficiency for each source was then
reduced to account for typical transmission losses using a global average
transmission loss. The development of busbar efficiency estimates will be
discussed separately for each emission source. The development of the
transmission loss estimate, which was applied to all utility sources, will be
discussed first.
The global average transmission loss as a percent of busbar generation
was determined by ranking the largest electricity generating nations and their
transmission losses. From this information, a generation-weighted
transmission loss was derived. Table 9 presents the top 11 electricity
generating countries, which represent nearly 75 percent of the world's total
generation. The rankings in Table 9 are based on U.N. data. The weighted
average loss is 8 percent. Therefore, a transmission efficiency of 92 percent
was applied to all busbar efficiencies to determine the net efficiency of
electricity production and distribution.
The efficiency estimates for natural gas-, distillate oil-, residual
oil-, and shale oil-fired boilers are all 32.4 percent conversion of fuel
energy to end-user electricity. The efficiency for these four fuels is
estimated to be the same because typically natural gas-fired and oil-fired
boilers have the same thermal efficiency. Boiler efficiency is estimated to
be 88 percent, based on 85 percent efficiency for a boiler without air preheat
and an additional 3 percentage points due to air preheat (U.S. EPA, 1982a;
Babcock and Wilcox, 1978). The boiler efficiency is limited by the combustion
efficiency, heat transfer losses within the boiler, and losses due to energy
exhausted in flue gas. The overall power plant efficiency is limited by the
boiler efficiency and by other factors. These factors include cycle losses
and auxiliary equipment. The cycle efficiency is limited by the maximum
theoretical efficiency for any heat engine. Additional losses in an actual
power plant cycle are introduced by inefficiencies in the turbine. Energy is
required to operate power plant auxiliary machinery such as fans and pumps,
which reduce the energy available for transmission. The busbar efficiency for
these four sources, after accounting for boiler efficiency, cycle efficiency,
and auxiliary power requirements, is 35.2 percent.
40
-------
TABLE 9. GLOBAL AVERAGE TRANSMISSION LOSS
Percent of World
Country Total Generation3
United States of America
Union of Soviet Socialtist
Republic
Japan
Canada
People's Republic of China
Federal Republic of Germany
France
United Kingdom
Italy
Brazil
India
TOTAL
26.7
16.1
7.0
4.7
4.1
4.1
3.3
3.0
1.9
1.9
1.8
74.6
Percent
Weight
36
22
9
6
6
6
4
4
3
3
2
100
Percent
Lossb
7.0
8.3
6.1
8.5
14.6
4.3
7.5
8.1
8.8
8.3
18.0
AVE = 8.0C
alncludes fossil fuel, hydroelectric, and nuclear generation.
Percent of busbar generation lost in transmission and distribution.
cWeighted average based on electrical generation.
Source: United Nations, 1986.
41
-------
A globally representative simple cycle gas turbine efficiency was
estimated based on projected international sales data for several gas turbine
models and a sales-weighted average of their respective efficiencies. Gas
turbine models with the highest projected sales included most General Electric
models, the Westinghouse 251 and 501, and models from Brown Boveri, Rolls
Royce, Avco, and Solar. The average efficiency for a simple cycle gas
turbine, including a transmission loss of 8 percent, is 26.4 percent. As a
check, this efficiency was compared to the 1985 U.S. national efficiency,
adjusted for transmission loss, of 26.2 percent, indicating that the estimate
derived from a global sales-weighted average is reasonable.
Busbar efficiencies for combined cycle gas turbines range from roughly
43 percent to 50 percent (Cohen et al., 1987). Assuming a representative
efficiency approximately in the middle of this range, an end-user energy
conversion efficiency of 42 percent was derived.
The efficiencies for coal boilers were estimated in a manner similar to
those for oil and gas boilers. For spreader stoker coal boilers, a boiler
efficiency of 81 percent was adjusted to 84 percent to account for air preheat
(Babcock and Wilcox, 1978). The utility boiler efficiency for pulverized coal
(PC) boilers, including cyclone, tangentially fired (TF), and wall-fired (WF)
units, is approximately 85 percent, including air preheat (Holstein, 1981).
From these boiler efficiencies, and from cycle losses and the typical energy
requirements for power plant auxiliaries as previously discussed, the busbar
efficiency was estimated to be 33.7 percent for spreader stoker units and 34.0
percent for the pulverized coal units. These values are equivalent to an end-
user energy conversion efficiencies of 31.0 percent and 31.3 percent,
respectively.
The busbar efficiency of coal-fired fluidized bed (FB) and fluidized bed
combined cycle (FBCC) plants are 34.1 percent and 38.0 percent, respectively.
The corresponding end-user energy conversion efficiencies, including
transmission loss, are 31.4 percent and 35.0 percent, respectively. The
busbar efficiency of municipal solid waste (MSW) mass feed-fired utility
plants is approximately 20.3 percent (EPRI, 1986). This efficiency, adjusted
for transmission loss, is 18.7 percent. No data were readily available for
MSW refuse derived fuel (RDF)-fired utility plants; the efficiency of the mass
feed unit was assumed to be representative of the efficiency of a RDF unit. A
typical efficiency for wood-fired utility plants is 17.3 percent at the
busbar, adjusted to 15.9 percent at the end-user (EPRI, 1986).
42
-------
Emission Factors
For many emission sources, the emission factors for NOX, CO, and CH< are
based on AP-42 emission factors converted to an energy output basis using the
appropriate fuel property data from Table 5 and the end-use energy conversion
efficiency from Table 8. The emissions sources for which AP-42 factors were
available for NOX, CO, and CH4 include natural gas, residual oil, distillate
oil, coal spreader stoker, pulverized coal cyclone, pulverized coal tangential
fired, and pulverized coal wall-fired boilers. The NOX, CO, and CH4 emission
factors for other sources will be discussed in more detail. Because emissions
of CO and CH4 for utility sources are generally negligible on a mass basis
compared to C02, the C02 emission factor was calculated only from the fuel
properties. The exception to this includes wood-fired boilers, for which CO
emissions were included in the carbon balance, and gas turbines, for which
both CO and CH4 were included.
The emission factors for N20 are estimated based on limited test data for
sources or fuels for which test data were available. Recent measurements have
shown that most of the existing N20 data were collected with procedures that
allow formation of N20 in sample containers awaiting analysis. Only those
measurements made with new procedures can be considered reliable at this time.
Consequently, the N20 data base is very small, consisting of measurements at
less than a dozen coal-fired power plants (Montgomery et al., 1989).
The emission factors for NOX and CO for natural gas-fired utility gas
turbines were available on an energy input basis (Shih et al., 1979).
Although the emission characteristics of simple cycle and combined cycle gas
turbines are the same on an energy input basis, they differ on an energy
output basis because of differences in efficiency. The emission factors for
NOX and CO were converted to an energy output basis using the gas turbine
efficiencies in Table 8. An emission factor for CH4 was available and was
converted from a mass to an energy basis using the heating value of natural
gas from Table 5 and the end-use efficiencies for gas turbines (Touchton
et al., 1982). The C02 emission factors for gas turbines were calculated
including both CO and CH4 in the carbon balance. N20 emissions were estimated
as approximately 5 percent of NOX emissions, based on tests for natural gas-
fired sources.
43
-------
Although no emission factors for utility distillate oil-fired
sources were available in AP-42, distillate oil utility emissions were
estimated based on the ratio of distillate oil industrial boiler
emissions to residual oil industrial boiler emissions multiplied by
the residual oil utility boiler emissions for NOX and CH4. For CO, the
emission factor was assumed to be the same as for residual oil utility
boilers since the AP-42 CO emission factors for industrial and
commercial residual and distillate oil boilers are all the" same. No
emission factors were readily available for shale oil-fired boilers.
The emissions of shale oil boilers were assumed to be the same as
those for residual oil-fired boilers because of similarities in the
fuel properties of both oil types.
For MSW mass burn boilers, the CO emission factor is based on 11
test measurements from sources in the United States, Japan, Germany,
Sweden, and Canada (Young et al., 1979). The NOX emission factor is
based on data for industrial mass burn facilities. No data were
readily available for CH, or N20 emissions for MSW boilers. No
emissions data was available for MSW RDF-fired boilers.
For fluidized bed boiler utility plants, the NOX emission factor is
based on test data (U.S. EPA, 1982b). CH4 emissions are assumed to be
the same as for other types of coal-fired boilers because AP-42 CH<
emission factors for all types of coal-fired utility boilers except
underfeed stokers are the same. No data were readily available for CO
emissions from fluidized bed boilers. The emission rate of N20 is
assumed to be roughly 25 percent of that for NOX, although it is likely
that, because fluidized bed boilers typically operate at lower
temperatures than other boiler types, N20 emission could differ
substantially from this estimate. For fluidized bed combined cycle
utility plants, no emission factors were readily available. However,
the CH4 emission factor was calculated by assuming that the emissions
on a mass bass are the same as for other coal boilers, and the C02
emission factor was calculated by carbon mass balance.
For wood-fired boilers, emission factors for industrial boilers
from AP-42 were used to calculate the end-use energy-based emission
factors for NOX, CO, and CH4.
44
-------
Cost
The basis for the costs in Table 8 is summarized in Table 10. These
costs are only approximately representative of. global, average costs, and, as
noted in Section 2, great care should be exercised in qualifying any
conclusions reached using these estimates. Table 10 presents the capacity,
total capital cost, annual costs, and economic life assumed in calculating the
levelized annual cost. For all utility sources, a capacity factor of 0.45 was
used, based on the average global utilization of installed electricity
generating capacity from U.N. statistics (United Nations, 1986).
Representative average source capacities were selected as the basis for the
cost estimates. However, in cases where costs were not available for an
average size plant, the cost estimates are based on a plant capacity for which
costs were readily available. The costs were converted to an end-user energy
basis using transmission efficiency for those costs that were available on a
busbar basis. All costs are in 1985 dollars and were annualized in constant
dollars in Table 8 using a discount rate of 5 percent and the economic life
indicated in the table.
UTILITY SOURCE EMISSION CONTROL TECHNOLOGIES
Emission control technologies for utility plants and their performance
and cost parameter estimates are summarized in Table 11. Table 11 includes
the control technology codes corresponding to Table 8. Table 11 also includes
the efficiency penalty due to each control technology, the levelized cost in
constant dollars on an end-use energy basis, the emission reduction for each
pollutant, and the estimated availability date.
Nine distinct control technologies are included in Table 11. One of the
technologies is an advanced technology for removing C02 from the utility plant
flue gas using an adsorption/regeneration technique and disposal of the C02 by
injection into evacuated salt mines or into the ocean. Although this
technology is not commercially proven, it is included to provide an option for
C02 control. Of course, another option for reducing C02 emission on an energy
output basis is improvement of the energy conversion efficiency associated
with the emission source. Although only nine technologies were evaluated for
utility emission controls, in many cases the performance or cost of these
45
-------
TABLE 10. UTILITY PLANT COSTS
cr>
Capacity
Source (HW)
Natural Gas Boiler
Gas Turbine Combined Cycle
Gas Turbine Simple Cycle
Residual Oil Boiler
b
Distillate Oil Boiler
b
Shale Oil Boiler
HSU - Mass Feed
HSU - RDF
Coal - FBCC
Coal - FB
c
Coal - Cyclone
Coal - TFC
Coal - WFC
Wood
300
220
75
300
300
300
45
45
500
500
300
300
300
24
Capital Cost
(* 10 )
320
150
30
340
340
340
200
200
780
660
410
410
.410
49
Annual Cost
<* 10 )
4.4
2.9
0.3
4.4
4.4
4.4
6.2
6.2
34
23
9.2
9.2
9.2
1.0
Life
Reference (years)
17 30
8 30
8 30
17 30
30
30
a 20
8 20
8 40
8 40
17 30
30
30
8 30
All costs in 1985 dollars.
b
Assumed same costs as for residual oil-fired boilers.
The costs for all PC boilers are assumed to be the same.
Source: Holstein, 1981.
-------
TABLE 11. UTILITY EMISSION CONTROLS PERFORMANCE AND COSTS
Technology
Low Excess Air
Overfire Air - Coal
Overfire Air - Gas
Overfire Air - Oil
Low NO Burner - Coal
X
Low NO Burner - Tf
X
Low NO Burner - Oil
X
Low NO Burner - Gas
X
Cyclone Contoustion
Modification
Ammonia Injection
SCR - Coal
SCR - Oil, AFBC
SCR - Gas
Water Injection -
Gas Turbine
Sirrple Cycle
Code
U1
U2
U3
U4
U5
U6
U7
US
U9
U10
U11
in 2
U13
UK
Efficiency
Loss
(X) ($/J
-0.5 2
0.5 7
1.25 7
0,5 7
0.25 2
0.25 6
0.25 2
0.25 2
0.5 1
0.5 5
1 1
1 1
b
Cost
End-Use)
-4E-12
.5E-12
.5E-12
.5E-12
.2E-11
-7E-11
.1E-11
.1E-11
.6E-10
.5E-10
.5E-09
.1E-09
1 7.1E-10
1 1.4E-10
Reduction
(X)
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
N/A
Negligible
Negligible
Negligible
Negligible
Negl igible
CO
Reduction
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
N/A
Negligible
8
6
8
Negligible
Reduction
(X)
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
N/A
Negligible
Negligible
Negligible
Negligible
Negl igible
V
Reduction
(X)
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
60
N/A
MO
Reduction
(X)
15
25
40
30
35
35
35
50
40
60
80
80
80
70
Date
Available
1970
1970
1970
1970
1980
1980
1980
1980
1990
1985
1985
1985
1985
1975
-------
TABLE 11. (Continued)
00
Technology
SCR - Gas Turbine
CO Scrubbing - Coal
CO Scrubbing - Oil
CO Scrubbing - Gas
Retrofit LEA
Retrofit OFA - Coal
Retrofit OFA - Gas
Retrofit OFA - Oil
Retrofit LNB - Coal
Retrofit LNB - Oil
Retrofit LNB - Gas
Burners Out of
Service (BOOS)
Retrofit SCR
Code
U15
U16
U17
U18
U19
U20
U21
U22
U23
U24
U25
U26
U27
Efficiency8
Loss
(X)
1
22.5
16.0
11.3
-0.5
0.5
1.25
0.5
0.25
0.25
0.25
0.5
b
Cost
($/J End-Use)
2.0E-09
5.0E-09
5.0E-09
5.0E-09
3.2E-12
7.2E-12
7.2E-12
7.2E-12
2.4E-11
5.4E-11
5.4E-11
0
Reduction
(X)
Negligible
90
90
90
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
CO CH
Reduction Reduction
(X) (X)
8 Negligible
N/A N/A
N/A N/A
N/A N/A
Negligible Negligible
Negligible Negligible
Negligible Negligible
Negligible Negligible
Negligible Negligible
Negligible Negligible
Negligible Negligible
Negligible Negligible
N20
Reduction
(X)
60
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
NO
Reduction
(X)
80
N/A
N/A
N/A
15
25
40
30
35
35
50
30
Date
Available
1985
2000
2000
2000
1970
1970
1970
1970
1980
1980
1980
1975
.
Efficiency loss as a percent of end-user energy conversion efficiency. Negative loss indicates an efficiency improvement.
All costs in 1985 dollars.
SCR = Selective catalytic reduction.
d
Retrofit SCR performance may be assumed to be the same as for a new SCR systems, but cost is a factor of 1.5 greater.
N/A = not available.
-------
technologies varies depending on the source to which they are applied.
Costs for several of the technologies were also evaluated on a retrofit
basis.
Efficiency penalties, emission reduction efficiencies, and costs are
discussed below.
Efficiency Penalties
The efficiency penalties for most technologies were taken directly from
the literature. It should be emphasized that the efficiency penalties are
nominal values and are likely to vary from one application to another. The
penalties for low excess air, overfire air, low NOX burners, and ammonia
injection are based on the efficiency penalty to an industrial boiler since
utility data were not readily available (Kim et al. , 1979).
Little detail was available for cyclone staged combustion modifications
(Thompson et al., 1987) . An efficiency penalty of 0.5 percent was assumed
as a rough estimate.
The efficiency penalty for selective catalytic reduction (SCR) is based
on an estimated increase in utility plant heat rate of roughly 0.8 percent
(Bauer and Spendle, 1984) . A nominal value of 1 percent penalty is assumed.
The efficiency penalty for gas turbine water injection is a function of
the water injection rate. For the control level considered, a 1 percent
efficiency penalty was selected as representative based on the required
water injection rate (U.S. EPA, 1987).
The efficiency penalties for the C02 scrubber are substantial and vary
depending on the fuel burned. The C02 scrubbing system results in a
significant penalty on the thermal cycle of the power plant because steam is
required for C02 regeneration; thermal energy is needed to remove C02 from
the solvent on which it is absorbed from the flue gas. In addition,
electricity is required to liquefy the C02 and to transport it via pipeline
to its ultimate disposal site. The electricity requirement for the
liquefaction and disposal depends only on the quantity of C02 requiring
disposal. The quantity is higher for coal on an energy basis because coal
has a higher ratio of carbon per unit heating value than does oil, and both
oil and coal have a higher ratio of carbon to unit heating value than does
natural gas. Therefore, the energy penalty for C02 removal at a coal-fired
power plant is higher than that for a natural gas-fired plant due to the
different properties of the two fuels (Steinberg et al., 1984).
49
-------
Removal Efficiencies
The removal efficiencies for low excess air, overfire air, and low NOX
burners are based on a review of several references. These technologies
generally impact only NO, emissions. Average maximum removal efficiencies
were selected; the efficiencies vary for overfire air and low NOX burners as
a function of the fuel fired. If operated properly, these technologies
generally do not significantly impact the emissions of CO, CH4, and C02. No
data were readily available for N20.
Little information was readily available on the NOX removal efficiency of
cyclone furnace combustion modifications since it is a relatively new
technology, and no data were readily available on the impact of cyclone
combustion modifications on other species. However, a nominal value of
40 percent NOX reduction is reported (Thompson et al., 1987).
On the average, ammonia injection is capable of 60 percent NOX removal.
No significant impact on the emissions of the other compounds is reported
(Kim et al., 1979) .
SCR can reduce emissions of N20, based on a test of a natural gas-fired
internal combustion engine. No data were available regarding the effect of
SCR on N20 in the flue gas of coal- or oil-fired sources. SCR also reduces
CO by a small percentage,but is primarily most effective in reducing NOX by
about 80 percent (Castaldini and Waterland, 1986) .
Gas turbine water injection is capable of over 70 percent NOX reduction.
Although water injection can impact the emissions of CO and CH4 to some
extent in specific applications, on the average, the impact is negligible.
The impact on C02 emissions is likely to be negligible in any case (U.S.
EPA, 1977a).
No data is available on the impact of the advanced concept C02 scrubbing
system on pollutants other than C02, for which the design removal efficiency
is 90 percent (Steinberg et al., 1984).
Burners out of service (BOOS) is a retrofit control option which can be
applied to wall-fired or tangentially fired boilers and is capable of about
30 percent NOX removal for coal, oil, or natural gas (Kim et al. , 1979).
50
-------
The basis for the annualized control technology costs in Table 11 is
presented in Table 12. Table 12 lists the emission source capacity, and the
control technology capital cost and nonfuel annual costs. All costs are in
1985 dollars, and the costs in Table 11 were levelized based on a capacity
factor of 0.45, an economic life of 30 years, and an interest rate of
5 percent. The factors used to calculate retrofit costs based on the costs
for new controls are included in the table.
Because in some cases costs were available only for a control technology
applied to sources of arbitrary capacities, it was not always possible to
develop control costs using the same source capacity as for the source
costs. Although the capacities of some sources and controls used for
costing do not match, developing costs on a consistent capacity basis would
have required effort beyond the scope of this project, and would have
required additional assumptions in many cases.
51
-------
TABLE 12. UTILITY EMISSION CONTROL COSTS
Technology
Low Excess Air (LEA)
Over-fire Air (OFA)
Low NO Burner (LNB)
x . . b
LNB - Tangential Firing
Cyclone Combustion
Modification
Ammonia Injection
SCR - CoalC
SCR - Oil, FBC
SCR - Gas
Water Injection - Gas
Turbine (Simple Cycle)
SCR - Gas Turbine
CO Scrubber
Retrofit LEA
Retrofit OFA
Retrofit LNB
Retrofit SCR
Source Category
6
2500 x 10 Btu/hr input
500 MU output
500 MU output
500 MU output
-
6
200 x 10 Btu/hr input
300 MU output
300 MU output
300 MU output
Q
400 x 10 Btu/hr input
6
400 x 10 Btu/hr input
Ratio of retrofit to new cost
Ratio of retrofit to new cost
Ratio of retrofit to new cost
Ratio of retrofit to new cost
Capital Cost
($1,000)
67
460
1,400
4,100
S20/KU
350
26,000
22,000
18,000
710
3,300
S673/KU
is 1.32
is 1.64
is 1.54
is 1.5
Annual Cost
($1,000)
3
23
69
210
$1/KU/yr
120
4,500
3,400
1,900
14
680
$45/KU/yr
aAU costs in 1985 dollars.
Assumed cost for low NO burners applied to tangentially fired furnaces to be three times the cost for other
low NO burners as an order-of-magnitude estimate.
CSCR costs calculated from an algorithm based on Bauer and Spendle, 1984.
Sources: Steinberg et al., 1984; U.S. EPA, 1977a.
-------
SECTION 4
INDUSTRIAL BOILER SOURCES AND CONTROLS
Performance and cost estimates were developed for seven industrial boiler
types and six industrial boiler emission control technologies. All of the
boilers and controls represent currently available technologies. This section
discusses source performance and cost estimates, as well as emission control
performance and cost estimates.
SOURCES
Table 13 summarizes the efficiency, cost, and emission factor estimates
developed for industrial boilers. Estimates were developed for sources
burning coal, residual oil, distillate oil, natural gas, wood, bagasse and
agricultural waste, and MSW. The efficiency is based on the conversion of
fuel energy to thermal energy for water to steam generation. The costs are
based on the annual energy delivered in generating steam. The emission
factors are reported on the basis of grams of pollutant emitted per gigajoule
of energy delivered to a steam user. The energy delivered to a steam user is
the difference between the thermal energy contained in the steam leaving the
industrial boiler and the thermal energy in the condensate water returning
from the user back to the boiler. To the right of each emission factor is the
corresponding quality rating. For each industrial boiler technology, the
appropriate control technologies are identified by codes.
Efficiency
The efficiency estimates in Table 13 represent the conversion of fuel
energy to the energy delivered to a steam user. The estimates are based on
information from NSPS background information documents for industrial boilers
(U.S. EPA, 1982a,b).
Most coal-fired industrial boilers in the United States are watertube
boilers. These may be pulverized coal or stoker designs. The efficiency of
coal-fired industrial boilers ranges from about 78 percent for underfeed
stokers to about 82 percent for pulverized coal-fired boilers. A value of 80
percent was selected as representative of coal-fired industrial boilers. Oil
53
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TABLE 13. INDUSTRIAL BOILER SOURCE PERFORMANCE AND COST
Emissions Factors (g/GJ delivered steam) and
Data Quality Ratings (A - E)
Source
Efficiency Cost
(X)
-------
fired and natural gas-fired watertube boilers generally have similar
efficiencies of roughly 85 percent (U.S. EPA, 1982a).
Spreader stoker designs are the most common for boilers firing wood waste
and typically have efficiencies of 65 to 70 percent. A value of 68 percent
was selected as representative. Spreader stoker boilers firing bagasse are
roughly 60 percent efficient. MSW mass feed boilers have an efficiency of
70 percent, whereas MSW small modular boilers have an efficiency of 55 percent
(U.S. EPA, 1982b).
Emission Factors
No N20 emission factors for industrial boilers have been provided since
all existing test data have recently been shown to be inaccurate.
For coal-fired industrial boilers, emission factors for NOX, CO, and CH4
were estimated from AP-42 emission factors for pulverized coal, spreader
stoker, overfeed stoker, and underfeed stoker industrial boilers. The
emission factors for these four boiler types were averaged for each of the
three pollutants based on the percent of the total U.S. coal-fired boiler
capacity represented by each source. Using a boiler population weighted
average approach, it is possible to represent the emissions of different coal
fired boiler types with a single set of emission factors. Pulverized coal
boilers comprised roughly 37 percent of the total based on capacity, whereas
spreader stoker, underfeed stoker, and overfeed stoker comprised 26 percent,
27 percent, and 10 percent of the total, respectively (U.S. EPA, 1982a). The
weighted average emission factors were converted from a mass to an input
energy basis using the coal heating value from Table 5 and then to an output
energy basis using the boiler efficiency from Table 13.
The NOX, CO, and CH4 emission factors for residual oil-, natural gas-, and
wood-fired boilers were taken from AP-42 and converted to an output energy
basis using the appropriate fuel heating values and boiler efficiencies.
For bagasse-fired boilers, no data were readily available from which to
develop a CH4 emission factor. The emission factor for CO on a mass basis was
assumed to be the same as for wood-fired industrial boilers. A NOX emission
factor based on energy input was available.
For MSW-fired units, the NOX emission factor is the same on an energy
input basis for small modular and mass-burn boilers (U.S. EPA, 1982b).
However, on an energy output basis the factors differ because the efficiency
55
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of mass burn units is estimated to be higher than that of small modular units.
The CO emission factors for both mass-burn and small modular MSW facilities
are based on test data (Shindler, 1987). No data were readily available for
CH4 emissions from MSW industrial boilers.
Cost
The basis for the cost estimates in Table 13 are summarized in Table 14.
Table 14 includes the boiler size in terms of inlet fuel energy, the capital
cost, and the non-fuel annual costs. These costs were levelized using an
economic life of 30 years, an interest rate of 5 percent, and a capacity
factor of 0.55. The costs are in 1985 dollars, and exclude fuel cost. As was
the case for utility sources, representative capacities were selected as the
basis for cost estimates unless limited availability of cost data required the
use of arbitrary capacities. Although the selection of capacity impacts the
energy-based cost due to economies of scale, the costs developed for this
project, as noted in Section 2, are intended to be approximately
representative. A more detailed cost analysis is beyond the scope of this
project.
EMISSION CONTROL TECHNOLOGIES
Emission control technologies for industrial boilers and their
performance and cost parameter estimates are summarized in Table 15. Table 15
includes the control technology code, efficiency penalty, cost, emission
reduction efficiency, and availability date.
Six different control technologies were evaluated. For many of these,
the cost, efficiency penalty, and emission reduction efficiency vary
significantly for different boilers. The efficiency penalty and emission
reduction efficiencies for low excess air, overfire air, low NOX burners,
ammonia injection, and selective catalytic reduction are discussed in
Section 3. The costs for these technologies applied to industrial boilers
differ, however, from costs for applications to utility boilers, primarily due
to economies of scale.
56
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TABLE 14. INDUSTRIAL BOILER SOURCE COSTS3
f. Capacity Capital Cost Annual Cost
Fuel (10° Btu/hr input) ($1,000) ($1,000)
Natural Gas 100 2,400 455
Distillate Oil 100 2,440 455
Residual Oil 100 2,420 455
Coal 100 9,000 865
Wood 30 2,950 460
aCosts in 1985 dollars.
Excludes fuel costs.
Source: U.S. EPA, 1982a.
57
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TABLE 15. INDUSTRIAL BOILER EMISSION CONTROLS PERFORMANCE AND COSTS
Technology
Lou Excess Air
Overfire Air - Coal
Overfire Air - Gas
Overfire Air - Oil
Low NO Burner - Coal
X
Low NO Burner -OH
X
Co Low NO Burner - Gas
X
Flue Gas Recirculat ton
Ammonia Injection
SCR - Coal
SCR - Oil. AFBC
SCR - Gas
Retrofit LEA
Retrofit OFA - Coal
Retrofit OFA - Gas
Retrofit OFA - Oil
Code
11
12
13
14
15
16
17
18
19
110
111 '
112
113
IK
115
116
Efficiency CO
Loss Cost Reduction
(X) ($/J End-Use) (X)
-0.5
0.5
1.25
0.5
0.25
0.25
0.25
0.5
0.5
1
1
1
-0.5
0.5
1.25
0.5
6.8E-12
4.4E-12
4.4E-12
4.4E-12
1.5E-11
3.5E-11
3.5E-11
1.1E-10
1.8E-10
1.1E-09
5.8E-10
2.0E-10
9.0E-12
7.2E-12
7.2E-12
7.2E-12
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negt igible
CO
Reduction
(X)
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
a
a
a
Negligible
Negligible
Negligible
Negligible
CH4
Reduction
(X)
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
N.,0
Reduction
(X)
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
60
N/A
N/A
N/A
N/A
NO
Reduction
(X)
15
25
40
30
35
35
50
40
60
ao
80
80
15
25
40
30
Date
Available
1970
1970
1970
1970
1980
1980
1980
1975
1985
1985
1985
1985
1970
1970
1970
1970
-------
TABLE 15. (Continued)
Technology
Retrofit LNB - Coal
Retrofit LNB - Oil
Retrofit LNB - Gas
Efficiency CO
a b 2
Loss Cost Reduction
Code (X) ($/J End-Use) (X)
117 0.25 2.4E-11 Negligible
118 0.25 5.4E-11 Negligible
119 0.25 5.4E-11 Negligible
CO
Reduction
(X)
Negligible
Negligible
Negligible
CH NO
H 2
Reduction Reduction
(X) (X)
Negligible N/A
Negligible N/A
Negligible N/A
NO
X
Reduction Date
(X) Available
35 I960
35 1980
50 1980
All costs in 1985 dollars.
en
io
N/A = not available.
-------
Efficiency Penalty
For a more complete discussion of efficiency penalties, which are assumed
the same as for utility boilers, see Section 3. The efficiency penalties for
the industrial boiler emission control technologies were taken directly from
the literature for low excess air, overfire air, low NOX burners, and ammonia
injection as discussed for utility sources. The efficiency penalty for SCR
was estimated in the same manner as for utility sources.
Flue gas recirculation has roughly a 0.5 percent impact on industrial
boiler efficiency (Kim et al., 1979).
Removal Efficiencies
The removal efficiencies for low excess air, overfire air, low NOX
burners, ammonia injection, and SCR are estimated to be the same for
industrial boilers as for utility boilers, as discussed in Section 3. Flue
gas recirculation is capable of about 40 percent reduction of NOX for oil- and
gas-fired boilers. No impact was reported for CO or hydrocarbons (Kim et al.,
1979).
Costs
The boiler size, capital cost, and nonfuel annual costs assumed to
calculate each of the control technology costs are summarized in Table 16.
These costs are in 1985 dollars and were levelized using an economic life of
30 years, an interest rate of 5 percent, and a capacity factor of 0.55. In
all cases, the same capacity factor was used for industrial boiler emission
source and controls. It was not possible in all cases to use the same source
category in the cost estimates for a particular source and the corresponding
control, due to limited availability of data.
60
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TABLE 16. INDUSTRIAL BOILER EMISSION CONTROL COSTS
Technology
Low Excess Air
Overfire Air
Low NO Burner
LNB - Coal
Flue Gas Recirculation
Anmonia Injection
SCR - Coalb
SCR - Oilb
SCR - Gas
Retrofit LEA
Retrofit OFA
Retrofit LNB
Source Category
(10 8tu/hr input)
100
1,090
100
1,530
100
200
100
750
100
Ratio of retrofit to new cost
Ratio of retrofit to neu cost
Ratio of retrofit to new cost
Capital Cost
($1,000)
67
168
124
1,270
39
350
2,600
8,900
445
is 1.32
is 1.64
is 1.54
Annual Cost
($1,000)
1.2
8.4
6.2
64
40
120
121
3,700
58
All costs in 1985 dollars.
SCR costs calculated from an algorithm based on Bauer and Spendle, 1984; other data from
Kim et al., 1979.
61
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SECTION 5
KILNS, OVENS, AND DRYERS
Performance estimates were developed for seven sources and five controls
as part of the kilns, ovens, and dryers category. The sources include lime/
cement kilns, coke ovens, and dryers. Control technologies were identified
for these sources. This section discusses the development of efficiency and
emission factor estimates for kilns, ovens, and dryers. The dryers discussed
in this section exclude coal dryers, which are discussed with other fuel
production emission sources in Section 6. Performance and cost parameters for
emission control technologies for these sources are also discussed in this
section.
SOURCES
The performance parameters for each of the sources included in this
category are summarized in Table 17. Indicated in the table are some of the
industries in which these emission sources are commonly found. A range of
values for the thermal efficiency of kilns and dryers is given. The emission
factors are given in grams of pollutant emitted per gigajoule (g/GJ) of input
fuel energy for these emission sources. The emission factor quality rating is
given to the right of each emission factor. The appropriate control
technologies for each source are noted by control code in the last column of
the table.
Efficiency
The thermal efficiency of a kiln or dryer is the percent of the input
fuel energy that is used to heat the material charge within the kiln. Kiln
efficiencies range from about 45 percent to 80 percent, but typically are
within 65 percent to 75 percent. Dryer efficiencies range from about
30 percent to 65 percent depending on the temperature at which drying occurs.
The overall efficiency of an industrial facility containing a kiln or dryer
can be improved by recovering the waste heat from the kiln or dryer for use in
other equipment (Perry and Chilton, 1973).
62
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TABLE 17. KILNS. OVENS, AND DRYERS SOURCE PERFORMANCE
Thermal
E f f i c i ency
Industry Source (X)
Cement, Lime Kilns -Natural Gas 65-75
Cement, Lime Kilns - Oil 65-75
Cement, Lime Kilns - Coal 65-75
Coking, Steel Coke Oven N/A
Chem. Processes, Dryer - Natural Gas 30-65
<*» Uood. Aschalt.
Emissions Factors (g/GJ input energy) and
Data Quality Ratings (A - E)
CO CO CH NO NO
2 i> 2 x
176,000 C 75 E IE N/A 1000 E
196,000 C 75 E 1 E N/A 500 D
228,000 C 75 E 1 E N/A 500 D
50,000 C 200 E 1 E N/A N/A
51,000 B 10 E 1 E N/A 52 E
Controls
K1. K2, K4, K5
K1, K2, K4, K5
K1, K2, K4. K5
K3
K1, K2
Copper, Phosphate
Chem. Processes, Dryer - Oil
Uood, Asphalt,
Copper, Phosphate
Chem. Processes, Dryer - Coal
Uood, Asphalt,
Copper, Phosphate
30-65
70,000 B
15 E
30-65 102,000 B 170 E
1 E N/A 160 E K1, K2
1 E N/A 215 E K1, K2
Control codes are defined in Table 18.
-------
To calculate energy-specific emission factors in some cases it is
necessary to convert emission factors from a per unit product to an energy
basis. Although the thermal efficiency indicates the percent of the input
fuel energy that is used to heat the process feed material, a more useful
parameter for converting emission factors from a product to an energy basis is
the product unit-specific energy requirement. The product unit-specific
energy requirement is the amount of energy required to produce one ton of
product. For lime and cement kilns, the fuel energy requirement varies
significantly depending on whether the process is wet, dry, or involves a
precalciner or preheater. A typical range of energy requirements for either
lime or cement kilns is roughly 3 MMBtu/ton to 9 MMBtu/ton of cement clinker
or quicklime. The lower values are typical of dry processes, and the higher
values are typical of wet processes. No data were readily available for the
global distribution of wet, dry, and precalciner kiln facilities; a nominal
value of 5 MMBtu/ton quicklime or cement clinker was selected as
representative of all kilns (Muehlberg and Shepard, 1977).
For coke ovens, a nominal value of 2.78 MMBTU of fuel energy per ton of
coke was used (Katari and Gerstle, 1977).
Emission Factors
The emission factors for kilns are based on a review of test data. No
data were readily available for the emissions from coke ovens due to fuel
combustion. No data were readily available for emissions from dryers;
however, the emissions from dryers were assumed to be the same as for
industrial and small boilers, primarily because it is assumed that the
combustion conditions in the dryer combustor and in small boilers are similar.
The emissions from cement and lime kilns include C02 from the calcination
of calcium carbonate in limestone and C02 from fuel combustion. The amount of
C02 evolved from calcination on an energy input basis is sensitive both to the
amount of carbon contained in the kiln feed per ton of product produced and to
the fuel energy required to produce a ton of product. For lime kilns, the
amount of C02 evolved per ton of feed may range from roughly 870 to 960 Ib,
depending on whether the limestone has a low .magnesium content. Dolomitic
limestone, which contains roughly 30 to 45 percent magnesium carbonate, has
higher C02 emissions from calcination (Doumas et al., 1977). For the purpose
of estimating emissions for lime kilns, a nominal value of 900 Ib C02 per ton
64
-------
of limestone feed is assumed. Converting to a product basis, roughly 1640
Ib of C02 is emitted per ton of quicklime product, based on a requirement of
1.8 tons of feed per ton of product.
For cement, which has a slightly lower calcination C02 emission rate than
does lime, a value of 790 Ib C02 per ton of feed is used, based on the
assumption that 90 percent 'of the feed limestone is calcium carbonate. This
emission rate is equivalent to 1310 Ib C02 per ton of cement clinker.
Using the nominal energy requirement of 5 MMBtu per ton of product, the
energy basis C02 emission rate from calcination is 113,000 g/GJ for cement
kilns and 141,000 g/GJ for lime kilns. A value of 125,000 g/GJ differs by
about 10 percent from the nominal values for cement and lime and is used in
this analysis as a representative emission rate for calcination for both
types of kilns.
The emission of C02 from fuel combustion in kilns was calculated for coal,
residual oil, and natural gas using the fuel properties in- Table 5, and is
included, along with the emission rate from calcination, in the total C02
emission factors in Table 17. Because C02 emissions from lime and cement
kilns are extremely high compared to other combustion sources, CO and CH4
emissions were not included in the carbon balance.
The emissions of NOX, CO, and CH4 in kilns are subject to variability due
to differences in fuel properties, kiln system design, and operating
parameters. Data on emission factors are limited and include test data from
both lime and cement kilns. Data were available for a rotary lime kiln, and
dry, wet, and precalciner process cement kilns. However, the quality and
quantity of the data did not justify developing separate emission factor
estimates for different kiln configurations and processes. To develop
nominal estimates for this project, values from several tests were simply
averaged to estimate representative, order-of-magnitude emission factors.
For coal-fired kilns, 10 data points were averaged to obtain a rough
estimate of 500 g NOX per GJ of input fuel energy. The data ranged from
about 200 ng/J to 600 ng/J. For oil, an average of four data points yielded
the same result. For natural gas, a review of six data points, ranging from
about 400 to 800 ng/J, resulted in an approximate estimate of 1000 g/GJ for
NOX, with a range of about 300 to 1,600 ng/J. The emission factor for CO
for all fuels was assumed to be approximately 75 g/GJ, which represents a
reasonable upper bound on the CO emissions for most kilns, although a few
appear to have higher emissions (Tidona et al., 1983; Benson and Hunter,
1986) .
65
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The CH, emissions for kilns were estimated in the same manner as those for
dryers by reviewing data from AP-42 for industrial and small boilers. These
factors, converted to an energy input basis using the fuel properties from
Table 5, ranged from 0.65 g/GJ for coal to 1.3 g/GJ for natural gas.
Because these emission factors are small and are similar in value, the
emission of CH4 is estimated to be roughly 1 g/GJ for all fuels.
The NOX and CO emission factors for dryers were similarly estimated from
AP-42 emission factors for industrial and small boilers.
Coke ovens typically burn coke oven gas. No data were readily available
for the continuous emissions from coke ovens due to combustion of coke oven
gas. However, data are available in AP-42 for the emissions of CO and NOX
during charging of coal and pushing of coke in the coke oven. The emissions
of NOX from this aspect of coke production are low compared to other
sources, and are likely to be insignificant compared to NOX emissions from
combustion of coke oven gas. CO emissions, however, are significant from
the charging process, and the estimate in Table 17 is calculated from the
mass basis emission rate from AP-42 and the nominal value of 2.78 MMBtu of
fuel energy per ton of coke. The C02 emission rate is calculated based on
the properties of coke oven gas in Table 5.
CONTROLS
Several control technologies applicable to kilns, ovens, and dryers are
shown in Table 18. Table 18 includes the control technology code, the
thermal efficiency penalty, the cost excluding fuel on an energy input
basis, the removal efficiency for each pollutant, and the availability date.
Both low excess air and low NOX burners are applicable to kilns and
dryers. The cost of low excess air is based on an oxygen analyzer and
control system for a 300 MMBtu/hr heat input kiln operating 8,000 hours per
year. The efficiency penalty of -6.4 percent reflects the increased thermal
efficiency obtained with low excess air operation, due to a reduction in the
flue gas volume flow rate. Typically, low excess air does not result in
significant increases in emissions of CO for moderate levels of NOX control;
therefore, negligible impacts are assumed for all species except NOX. The
66
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TABLE 18. KILNS. OVENS, AND DRYERS EMISSION CONTROLS PERFORMANCE AND COSTS
Technology
LEA - Kilns, Dryers
LNB - Kilns, Dryers
SCR - Coke Oven
Nitrogen Injection
Fuel Staging
Efficiency
Loss
Code (X)
K1 -6.4
K2 0
K3 1
KA N/A
K5 N/A
CO CO CH
a 2 4
Cost Reduction Reduction Reduction
(S/J Input)
-------
cost of low NO, burners is based on the difference in cost between standard
and low NO, burners for a 300 MMBTU/hr heat input kiln. As for low excess
air, the impact on all species except NOX is negligible when kilns are
operated correctly (Carter and Benson, 1984) .
Selective catalytic reduction has been applied to coke ovens in Japan.
Costs for SCR applied to coke ovens were not readily available. As an
order-of-magnitude estimate, it was assumed that the cost of SCR on a unit
energy basis for an internal combustion engine approximates the cost of SCR
for a coke oven. The removal efficiencies for SCR have previously been
discussed in Section 3.2 (Ando, 1983) .
Two advanced technologies for kilns were identified. Both nitrogen
injection and fuel staging technologies are in the development phase. The
only information readily available was the impact of these two technologies
on NOX. Nitrogen injection may be capable of roughly 30 percent NOX removal,
whereas fuel staging may be able to achieve 50 percent NOX reduction (EPRI,
1986). No information was readily available for the effect of these two
technologies on other pollutants.
68
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SECTION 6
FUEL PRODUCTION
This section includes most major sources of greenhouse gases that are
emitted in the production of coal, oil, gas, and wood fuels. In general, the
key sources included here are: coal mining and processing operations, oil and
gas drilling and transport operations, oil refining, oil shale and coal
liquefication production operations, and charcoal production. Since oil
refining operations include a large and diverse number of individual sources,
a composite emission factor was developed based on a "model refinery"
configuration. Use of this single factor can simplify the emissions
estimating procedure in global models.
SOURCE DESCRIPTIONS, EMISSION FACTORS AND EFFICIENCY DATA
Table 19 summarizes the emission factors and efficiency data for key fuel
production sources. As the table shows, several significant sources of
greenhouse gases exist in the fuel production industry. These sources are
organized in the table and in the remainder of this section by fuel type as
listed below:
Oil Production Sources
petroleum refining
oil shale retorting
wellhead venting
. Gas Production Sources
gas transmission systems
• Coal Production Sources
active mines
coal drying
coal gasification
coal liquefication
. Wood-Related Sources
charcoal production
Brief process descriptions and a discussion of emission factor
development procedures used for each category are discussed in the next four
69
-------
TABLE 19. FUEL PRODUCTION SOURCE PERFORMANCE
Source Efficiency
(X)
Gas Refining N/A
Petroleun Refining N/A
Coal Cleaning N/A
Oil Shale-Surface 78
Oil Shale - In-situ 60
Lurgi Gasification 65
Liquefaction Acid 66
Gas
Emissions Factors and
Data Quality Ratings (A - E)
b
CO CO CH NO NO Controls
2 4 2 x
N/A Negligible D Negligible D N/A Negligible D
23,400 0 1730 D 0.948 0 N/A 49 0 See Table 21
g/bbl crude g/bbl crude g/bbl crude g/bbl crude
4,719 B N/A N/A N/A 37 C
g/ton coal mined g/ton coal mined
15,000 C 17 C 23 C N/A 61 C F1
g/GJ out g/GJ out g/GJ out g/GJ out
1,500 C 0.6 C 8.6 C N/A 20 C F1.F2.F3,F5,F6
g/GJ out g/GJ out g/GJ out g/GJ out
56,000 D MC N/A N/A 150 C F8
g/GJ out g/GJ out g/GJ out
23,000 C 2.5 C N/A N/A trace C
g/GJ out g/GJ out
-------
TABLE 19. (Continued)
Emissions Factors and
a
Data Quality Ratings (A - E)
Source Efficiency CO
(X)
Charcoal Production N/A 66,000 E
g/GJ out
Natural Gas N/A 486 D
Transmission g/GJ out
Active Coal Mines N/A N/A
Natural Gas Leaks N/A N/A
Natural Gas Vented N/A N/A
b
CO CH NO NO Controls
42 x
5,800 D 1,700 0 N/A 410 D F9
g/GJ out g/GJ out g/GJ out
2.4 0 2.5 D N/A 10.6 0 F22.F23.F24
g/GJ out g/GJ out g/GJ out
N/A 4,920 D N/A N/A
g/ton coal mined
N/A 5.72 E N/A N/A
g/m gas marketed
N/A 0.57 E N/A N/A
g/m gas marketed
For a discussion of the emission factor data quality ratings, see Section 2.
Control codes are defined in Table 20.
N/A = Not available.
-------
subsection, followed by presentation of available energy efficiency data for
all sources covered.
Oil Production Sources
Petroleum refininq--
The petroleum refining industry converts crude oil from wells into products
such as liquefied petroleum gas, gasoline, kerosene, diesel and aviation fuel,
fuel oils, and lubricating oils. Configurations of refineries and types of
processes used within refineries may vary widely on a global scale. However,
basic refinery processes may be categorized generally as:
separation processes (such as distillation),
conversion processes (such as cracking, reforming, alkylation, and
coking),
treating processes (such as hydrodesulfurization and hydrotreating),
and
• feedstock and product handling.
Fugitive hydrocarbon emissions from feedstock and product handling operations,
such as valves, flanges, pump and compressor seals, and transfer operations
consist mainly of hydrocarbons and are not within the scope of this study.
Several different emission sources exist within each of these process
areas, so a single "model refinery" emission factor was developed to simplify
the global modeling effort for the Reports to Congress. First, the major
sources of greenhouse gases in most refineries were identified (U.S. EPA,
1985). These major sources are:
vacuum distillation,
catalytic cracking,
• thermal cracking, and
process heaters.
Emissions from viscosity-breaking (visbreaking) and delayed and fluidized
cooling processes may be significant. However, data were not readily
available for these process emissions so they were not included here. An
emissions factor for a "model refinery" was developed by aggregating the
72
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emissions from three of these four major sources. For some of these
sources, process emissions were weighted based on the sources' occurrence
and use within the industry. Key assumptions and data associated with
estimating emissions from each source are listed below.
Vacuum Distillation—Emissions result from the column condensers.
Uncontrolled CH, emissions for column condensers on a per barrel crude
basis were drawn from AP-42 hydrocarbon emissions tables (U.S. EPA,
1985) . A statement was made at the bottom of the table that less than
1 percent of the hydrocarbon emissions were CH4; 1 percent was assumed.
Catalytic and Thermal Cracking—Two main types of catalytic cracking are
fluidized bed and moving bed (Thermofor)R catalytic cracking (FCC and
TCC). Emission points are the catalyst regenerator. Carbon monoxide,
CH,,, and NOX emissions were given on a per barrel (bbl) of cracker feed
basis for both os these processes (U.S. EPA, 1980). A ratio of 0.289 bbl
catalytic cracker feed per bbl crude oil was used to convert the emission
factor to a refinery crude feed basis. This ratio was obtained from a
typical refinery 'flow diagram (U.S. EPA, 1980).
Since not all individual refineries contain both FCC and TCC catalytic
cracking processes, U.S. refinery flow data were used to estimate the
relative weight of these process emissions. In 1979, 94 percent of the
U.S. total catalytic cracker feed entered FCC units, and 5 percent
entered TCC units. The remaining 1 percent entered Houdriflow" (HCC)
units for which emissions data were unavailable. Emissions from each
cracker type were assigned relative weights using this 95-5 split to
yield a "weighted" emission factor.
Process Heaters—Process heaters are perhaps the largest source of
emissions within a refinery and are used in a number of different process
areas. These areas were first identified and then the fraction of the
total refinery feed to each of these areas was estimated based on a flow
diagram for a typical U.S. refinery and shown below (U.S. EPA, 1980) .
73
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Process Areas Fraction of Refinery Flow to Heaters
with Heaters (bbl feed/bbl crude)
Atmospheric distillation 1.0
Vacuum distillation .420
Delayed choking .170
Visbreaking -170 (assumed value)
FCC -284
Hydrocracking .057
Gas/Oil hydrodesulfurization .035
Hydrotreating .057 (assumed value)
Catalytic reforming .201
Alkylation .066
Isomerization .008
Hydrodesulfurization .066 (assumed value)
Process heater emission factors for oil- and gas-fired heaters were
available on a pounds of pollutant per barrel of process heater feed basis
(U.S. EPA, 1980). They were then assigned weights according to their natural
gas-residual oil fraction of occurrence: refineries generally use natural gas
to fuel 90 percent of their heaters and residual oil to fire the remaining
10 percent. These factors were next normalized to a per barrel of crude feed
into the refinery using the factors listed above. The C02 emission factors
for the fired heaters are based only on the fuel properties of natural gas and
residual oil; i.e., CO and CH4 are neglected in the carbon balance. C02
calculated for these two fuels was assigned weights using the 90 to 10 percent
split described above.
Finally, the weighted process heater factors for the process areas listed
above were summed to yield total process heater emissions for a typical
refinery.
Oil Shale Retortinq--
Emissions factors are reported for surface and in situ oil shale
retorting, which is the removal of shale oil from its shale matrix by heating
with combustion, either above or below ground, respectively (UNEP, 1985).
Some of the released shale oil is used for the combustion in this process, and
the combustion gases are vented.
The emission factors in Table 19 for C02, CO, CH4, and NOX for surface and
in situ shale retorting are based on the total estimated emissions from a
50,000 bbl/day plant, converted to an energy basis using the heating value of
crude shale oil from Section 2 (Table 5). The CH4 emission factor for both
74
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sources was assumed to be the same as the total hydrocarbon emission factor
because CH4 comprises most of the hydrocarbon emissions from retorting (UNEP,
1985).
Wellhead Ventinq--
With rising gas prices, the volume of vented gas in the United States has
fallen steadily since 1960. However, some venting of gas at the wellhead
continues in the United States, usually involving gas brought up with
associated oil which is not economically recoverable. Maintenance and
unscheduled downtime also result in the need to vent or flare gas.
Methane emissions from vented natural gas pose a similar problem to that
of natural gas leaks in that data on the breakdown between natural gas vented
and natural gas flared at the wellhead are not readily available. In the
United States, 0.4 percent of the total gas production in 1985 was flared or
vented (AGA, 1986). Most States that have a gas production industry require
that gas be flared rather than vented; thus, the American Gas Association
estimates that at least about 0.1 percent of the total gas produced in the
United States is vented (AGA, 1986). Assuming 88.3 volume percent CH4 in
natural gas, this corresponds to 0.572 grams of methane vented per cubic meter
of marketed natural gas. Again, the U.S. percentage of natural gas vented at
the wellhead may not reflect the global situation. One source indicates that
"the lack of markets and infrastructure for using natural gas as a fuel leads
to massive flaring at oil fields in some remote locations" (Marland and Rotty,
1984).
Gas Production Sources
Compared to oil related sources, there are relatively few sources of
emissions in gas production. However, the few sources that do exist are not
insignificant with regard to their total emissions. Gas transmission system
leaks, and pipeline compression/transport engine emissions are the major
sources. Acid gas flares at gas refining facilities are a potentially
significant source of C02 but few data were available with which to calculate
C02 emissions. Emissions of other gases from gas refining are negligible,
according to AP-42.
75
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Pipeline Leaks--
In gas transmission pipeline systems, greenhouse gas emissions occur from
two main sources:
* pipeline system leaks, and
transport/compression engines.
Gas pipeline systems leak methane emissions to the atmosphere, primarily from
valves, flanges, and corroded transmission lines. No firm data can be found
on the amount of natural gas leaked or lost. Lost and unaccounted for gas is
about 2 percent of marketed gas production in the United States each year, but
this includes gas unallocated due to meter inaccuracies, theft, and
temperature and/or pressure differences. It is estimated that unallocated gas
accounts for 50 percent or more of the unaccounted for gas in the United
States. Thus a conservative estimate of gas leaked would be 1 percent of
marketed gas production. Assuming that 88.3 percent (by volume) of this
natural gas is methane, the amount of CH4 leaked into the atmosphere would be
0.883 percent of the marketed gas production. This corresponds to 5.72 grams
of methane leaked per cubic meter of marketed natural gas, using the assumed
density of 647.7 grams/m3.
Because data are not readily available for global methane leaks, it is
not known whether methane loss for the United States is a valid gauge for
world methane loss.
Transport/Compression Engine Emissions--
Emissions from internal combustion engines and gas turbines in the
pipeline/transport system occur as a result of burning fossil fuels and the
emission specie is primarily C02. The NOX, CO, and hydrocarbon emission
factors for natural gas internal combustion engines and gas turbines and
diesel internal combustion engines used in pipelines are available on an
energy input basis (Shih et al., 1979). A CH4 emission factor for internal
combustion engines was determined by assuming that 10 percent of total
hydrocarbon emissions from diesel-fueled engines is methane and 80 percent of
total hydrocarbon emissions from natural gas fueled engines is methane (U.S.
EPA, 1977b). The emission factor for CH4 from a natural gas-fired gas turbine
is taken directly from test data. The C02 emission factors for internal
76
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combustion engines and gas turbines are based on carbon balances including
CO and CH4 using appropriate fuel properties from Section 2 (Table 5).
The emissions for the natural gas, internal combustion engines and gas
turbines and diesel internal combustion engines were then aggregated
according to their use (Shih et al., 1979). Natural gas pipelines use
approximately 3 percent of the gas transmitted to run the compressor engines
(Shih et al., 1979; Marland and Rotty, 1984).
Coal Production Sources
Active Coal Mines—
Methane present within coal seams may be liberated when the seams are
penetrated to mine the coal. Methane is vented in a fairly pure form from
active coal mines. Current literature outlines various ways to estimate the
amount vented based on an emission factor of cubic meters of methane per ton
of coal mined. Some authors give one general emission factor, whereas
others present different factors for the different grades of coal mined:
anthracite, bituminous, subbituminous, and lignite. Some vented methane is
used onsite in coal-drying, for example, and it is not clear whether the
various literature estimates include this methane or not. It was assumed
here that the emission factors reported in the literature estimate only what
is vented to the atmosphere. If this is incorrect, factors presented in
this report may be slightly overestimated.
Emission factors for methane from active coal mines from several current
references are summarized here:
CHa Emission Factor Reference
6.25 nrVton bituminous and anthracite coal mined Marland and Rotty, 1984
2.5 mVton subbituminous coal mined
1.25 mVton lignite
6.2-15.6 mVton bituminous and anthracite coal Byrer et al., 1987;
mined Boykins et al. , 1981
<6.2 mVton subbituminous and lignite coal mined
18-19 mVton coal mined Crutzen, 1987;
U.S. DOE, 1987
77
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Based on engineering judgment, a reasonable "middle-of-the-road" value appears
to be 7.6 m3/ton coal mined. With an assumed density of 647.7 grams/cubic
meter, the emission factor on a mass basis is 4,922 grams CH4 per ton of coal
mined.
Coal Drving--
The drying of coal can be accomplished with a fluidized bed dryer, in
which coal is suspended and dried above a perforated plate by rising hot coat
combustion gases. Data were not available for flash and multilouvered dryers.
Uncontrolled dryer exhaust emissions were taken from AP-42 on the basis of
a ton of coal dried. The C02 emission factor was calculated from ten data
points for the C02 concentration in the exhaust gas from coal dryers and the
corresponding flue gas flowrates. Dryer exhaust gases are the only source of
greenhouse gases in a coal drying process. Since not all coal mined requires
drying, these emissions were weighted by the ratio of tons of coal dried per
ton of coal mined. To calculate this factor, 1975 U.S. coal cleaning market
data were used. Of the coal mined, 49.3 percent underwent a cleaning
operation (U.S. DOE, 1987).
Coal Gasification--
Gasification, in simple terms, is the combination of coal and steam to
form CO, H2, and CH4. The heat to drive the gasification process is
maintained by coal combustion. A Lurgi gasifier, which contains a counter-
current moving bed of coal and steam, is used as the basis for the emission
factors presented in Table 19. Reported emission factors are for an entire
Lurgi plant.
The emission factors for Lurgi gasification were calculated from data on
estimated annual emissions from a 250 x 109 Btu/day Lurgi plant (U.S. EPA,
1978). The C02 emission factor was calculated with a carbon balance by
balancing the input coal carbon with the output synthesis gas carbon (which
was reported as roughly 65 percent of the synthesis gas) and the output carbon
contained in the CO emissions. The input coal was calculated based on a daily
output of 250 x 109 Btu, the process efficiency reported in Table 19, and the
coal heating value presented in Section 2 (Table 5).
78
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Coal Liquef ar> •! on —
Liquefaction processes produce usable liquid products from coal. A major
source of emissions from liquefaction processes is the acid gas flare that
burns a vent stream of reaction by-products.
The C02, CO, and NOX emission factors for coal liquefaction are based on
emissions data for the Synthoil*, H-Coal*, and Exxon Donor Solvent* Processes
(Parker and Dykstra, 1978) . The Synthoil* process has four product streams
(product oil, light fuel oil, liquid by-products, and by-products gas) and
the H-Coal* and Exxon Donor Solvent* each had three product streams
(naphthas, fuel gas, and heavy oils). Product flow rates and heating values
of these products were given for each of the three processes. These were
used to convert the emissions from a mass to an energy output basis.
Wood-Related Sources
The production of charcoal is performed by a controlled combustion of
wood in a kiln or continuous furnace. Emissions result from the wood
combustion flue gases. The emission factors for CO, CH<, and NOX from
charcoal production were readily available, and were converted to an energy
basis using the estimated heating value of charcoal from Section 2 (Table 5)
(Moscowitz, 1978) . The C02 was calculated by a carbon balance using the
following: carbon in wood (reported as roughly 50 percent), carbon out in
CO and CH4, and carbon out in produced charcoal (roughly 87 percent). It
was assumed the remaining carbon is available for C02 formation.
Efficiency Data
The efficiencies for surface and in situ oil shale retorting are
estimates of the percent of shale oil recovered from shale during the
retorting process. The estimate for the surface retort conversion
efficiency, 78 percent, is based on an average of the Paraho Direct, Paraho
Indirect, and TOSCO II retort conversion efficiencies. The estimate for the
in-situ retorting conversion efficiency, 60 percent, is based on a single in
situ retorting conversion efficiency value (U.S. EPA, 1980).
The efficiency for coal liquefaction is an average of the overall thermal
efficiencies for three liquefaction processes; Synthoil*, H-Coal9, and Exxon
Donor Solvent* Processes. The overall thermal efficiency is defined in this
79
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content as the ratio of the heating value of all products and by- products to
the heating value of all input feed materials (Parker and Dykstra, 1978).
This average is 66 percent.
The efficiency for Lurgi gasification is the coal-to-product gas thermal
efficiency, which is defined as the ratio of the heat content of coal to the
heat content in the product gas. This value is 65 percent (U.S. EPA, 1978).
The efficiency for pipeline gas turbine is based on conversion of fuel
energy to shaft horsepower. The efficiency of 34 percent for internal
combustion engines is based on a typical heat rate of 7500 Btu/hp-hr, which is
a commonly assumed heat rate from AP-42.
EMISSION CONTROL TECHNOLOGIES
Emission control technology performance and cost estimates are presented
in Table 20. For each of the control technologies, Table 20 includes a
control technology code, efficiency penalty, levelized cost on an energy or
production basis, emission reduction efficiency, and availability date. The
following sections describe each of the categories of data separately. For
the model oil refinery discussed previously, a combination of these
technologies is applied.
Emission Reduction Efficiency
For several of the fuel production emission sources, limited information
was available from which to identify the applicability of control technologies
and, in many instances, data were not available from which to estimate the
emission reduction efficiencies for various control technologies. Therefore,
the removal efficiencies for some controls were assumed to be the same for
fuel production sources as for similar sources to which they are applied.
This technology transfer was assumed for CO boilers, afterburners, FGR
retrofits, SCR retrofits, Nonselective catalytic reduction (NSCR) retrofits,
SCA, LEA, and SCA used in conjunction with LEA.
Recall that a single emission factor is used to represent a "model
refinery" and that factor includes the emissions associated with many
different sources within the refinery. In order to quantify the impact of
80
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TABLE 20. FUEL PRODUCTION EMISSION CONTROLS PERFORMANCE AND COST
CD
Efficiency
a
Loss
Technology Code (X)
Selective Catalytic F1 N/A
Reduction (SCR)
LEA F2 N/A
Two Stage Combustion F3 N/A
Water Injection FA 1
Fast Heat Release F5 N/A
NH Injection F6 N/A
High Tenperature F7 N/A
Regeneration
CO Boiler F8 N/A
Afterburner F9 N/A
FGR Retrofit - 0.0. F10 0.5
FGR Retrofit - Gas F11 0.5
CO CO
Cost Reduction Reduction
(1985 $) (X) (X)
N/A Negligible Negligible
N/A Negligible Negligible
N/A Negligible Negligible
6.4E-11 Negligible Negligible
$/J input
N/A Negligible Negligible
1.6E-13 Negligible Negligible
$/J output
N/A N/A 99
N/A N/A 99
J1.B7/ton -1 90
dry wood
0.036 $/ N/A N/A
bbl crude
0.036 $/ N/A N/A
bbl crude
CH NO
A 2
Reduction Reduction
(X) (X)
Negligible N/A
Negligible N/A
Negligible N/A
Negligible N/A
Negligible N/A
Negligible N/A
N/A N/A
100 N/A
N/A N/A
N/A N/A
N/A N/A
NO
Reduction
(X)
60
15
30
70
10
60
N/A
-125
N/A
38
57
Date
Available
1999
1985
1985
1965
1985
1985
1985
1985
1985
1985
1983
-------
TABLE 20. (Continued)
CO
Technology
SCR Retrofit - Gas
SCR Retrofit - D.O.
SCR Retrofit - R.O.
SNCR-NH Retrofit
SCA - Gas
SCA - R.O.
LEA - Gas
LEA - R.O.
LEA & SCA - Gas
Efficiency CO CO CH NO NO
Loss Cost Reduction Reduction Reduction Reduction Reduction
Code (X) (1985 $) (X) (X) (X) (X) (X)
F12 1 0.424 $/ N/A N/A N/A N/A 69
bbl crude
F13 1 0.424 */ N/A N/A N/A N/A 78
bbl crude
F14 1 0.424 $/ N/A N/A N/A N/A 90
bbl crude
F15 0.5 0.069 $/ N/A N/A N/A N/A 53
bbl crude
F16 -0.3 0.006 »/ N/A N/A N/A N/A 60
bbl crude
F17 -0.8 0.056 $/ N/A N/A N/A N/A 34
bbl crude
F18 -3.9 0.019 S/ N/A N/A N/A N/A 15
bbl crude
F19 -4.2 0.019 $/ N/A N/A N/A N/A 28
bbl crude
F20 -6.7 0.078 $/ N/A N/A N/A N/A 71
bbl crude
Date
Available
1983
1979
1979
1979
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TABLE 20. (Continued)
Efficiency CO CO CH NO
Loss Cost Reduction Reduction Reduction Reduction
Technology Code (X) (1985 $) (X) (X) (X) (X)
LEA & SCA - R.O. f21 -6.7 0.078 $/ N/A N/A N/A M/A
bbl crude
Pre-Stratified Charge F22 -3 3.9E-11 Negligible -20 -50 N/A
$/J input
Non-Selective Cat. Red F23 7 2.8E-10 Negligible 15 40 70
$/J input
Selective Catalytic Red. f24 1 9.5E-10 Negligible 8 Negligible 60
S/J input
NO
x
Reduction Date
(X) Available
53 1979
80 1987
90 1984
80 1985
CD
CO
A negative efficiency loss indicates an improvement in efficiency.
N/A - not available.
-------
adding controls to these many different sources, a composite emission
reduction efficiency factor was developed. The reduction efficiencies for
NOX, C02, CO, and CH, for the "model refinery" were calculated by applying a
wide range of control technologies to the individual emission sources.
These sources, which were .described previously, are shown with a listing of
all potentially applicable control technologies in Table 21. The emissions
from individual sources after control were summed and compared to the sum of
all uncontrolled sources to calculate a refinery-wide reduction efficiency.
Two control scenarios for the model petroleum refinery were investigated.
Level I represents a well-controlled refinery, and Level 2 represents a
baseline-controlled refinery. The controls chosen for these two levels are
shown in Table 22. For Level 1, refinery-wide C02, CO, CH4, and NOX
reduction efficiencies are -111.5, 99.0, 100, and 53 percent, respectively.
For Level 2, refinery-wide C02, CO, CH4, and NOX reduction efficiencies are
-111.5, 98.8, 43.2, and 12.2 percent, respectively. The C02 reduction
efficiency increases by 11 percent for both levels because CO and CH4
destroyed creates additional C02.
Several technologies are potentially applicable to oil shale retorting
for NOX control, but are not commercially proven with this source (Ando,
1973; U.S. EPA, 1983). Caution should be exercised when conceptually
applying these technologies to retorting. They included: SCR, LEA, two-
stage combustion, and lowering the combustion temperature with a fast heat
release. Estimated NOX removal efficiencies are reported in Table 20.
A CO boiler can be applied downstream of several fuel production emission
sources such as Lurgi gasification for heat recovery. Although CO boilers
result in roughly 100 percent CO emission reduction, they are a source of
NOX and C02. For control of CO emissions from charcoal production, an
afterburner can be used. The roughly 90 percent decreased in CO using an
afterburner is accompanied by a slight increase in C02 emissions (Waterland
et al., 1982; Kimet al., 1979).
The emission reduction for Prestratified Charge (PSC) and NSCR applied to
turbines or internal combustion (1C) engines in pipeline systems is based on
limited test data. PSC is capable of about 80 percent NOX reduction on
average, but may result in increases in emissions of CO and CH4 (Benson and
Hunter, 1986). NSCR is capable of 90 percent NOX reduction on average, and
also reduces CO, CH4, and N20, according to limited test data. Although CO
84
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TABLE 21. REFINERY SOURCES AND CONTROLS
Applicable Control Technologies by Technology Code1
Sources
CO,
CO
CH4
NO.
Vacuum Distillation
Catalytic Cracking
Process Heaters
Oil
Natural Gas
F8
F7, F8
F8
F8
F8
F8
F14, F15, F17,
F19, F21
Fll, F12, F16,
F20
*See Table 20 for code descriptions.
85
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TABLE 22. REFINERY CONTROL LEVELS'
Sources
Vacuum Distillation NOX
Vacuum Distillation CO
Catalytic Cracking NOX
Catalytic Cracking CO
Process Heaters Natural Gas NOX
Process Heaters Natural Gas CO
Process Heaters Residual Oil NOX
Process Heaters Residual Oil CO
Level 1
Well Controlled
None
F8
None
F8
F12
F8
F14
F8
Level 2
Baseline
None
F8
F8
F8
F18
None
F19
None
*See Table 20 for code descriptions.
86
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and CH4 emissions are reduced, the increase in C02 emissions is not
significant (Castaldini and Waterland, 1986).
Efficiency Penalty
The efficiency penalty for flue gas recirculation applied to fired
heaters (control codes F10 and Fll) was assumed to be the same as the
penalty for industrial boilers. The efficiency penalty for SCR and ammonia
injection applied to fired heaters was assumed to be the same as the penalty
for industrial boilers. The basis of these estimates is discussed in more
detail in Section 4.
The efficiency penalty for staged combustion air is taken to be -0.3
percent for gas-fired heaters and -0.6 percent for residual oil-fired
heaters, which shows a net gain in efficiency. It is assumed that low
excess air also improves the efficiency of refinery gas-fired heaters by 3.9
percent, and enhances the efficiency of residual oil-fired heaters by 4.2
percent (Benson and Hunter, 1986) . These levels can be achieved only if the
proper air level is attained and maintained. A combination of staged
combustion air and low excess air improves efficiency by 6.7 percent for
refinery gas-fired heaters and residual oil-fired heaters (Benson and
Hunter, 1986) .
PSC is essentially a combustion modification to internal combustion
engines that stratifies the fuel/air mixture prior to injection in the
cylinders, thereby promoting heterogenous firing of the fuel/air mixture.
This results in temperature control that limits NOX formation. Typically,
PSC (control code F22) results in approximately a 3 percent decrease in
brake-specific fuel consumption when operated at full load (ASME, 1986) .
NSCR requires rich-burn operation of an internal combustion engine, which
increases brake-specific fuel consumption by about 7 percent (Benson and
Hunter, 1986). SCR requires electricity to operate the ammonia injection
equipment. A nominal efficiency penalty of 1 percent is assumed.
Efficiency penalties for emission control technologies applied to the
remaining sources were not readily available.
87
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Cost
For most controls for which costs were available, the costs were
calculated from the data in Table 23, which presents the capital and annual
cost for six technologies applied to sources of a given size. For the
purposes of this study, the costs for a given technology were assumed to be
approximately the same for different fuels. This may result in some
inaccuracy in cost estimates. Data for individual fuels were not readily
available. The capital costs in Table 23 were levelized using a capital
recovery factor of 0.277 for low excess air and staged combustion air, and a
capital recovery factor of 0.143 for the other controls, and a capacity factor
of 0.6. The costs levelized on the basis of energy input to the fired heaters
were converted to a per barrel crude basis by using the typical heat
requirement per barrel of crude oil discussed above.
The costs for PSC, NSCR, and SCR are based on a 600 hp engine with a heat
rate of 7500 Btu/hp-hr, operating 90 percent of the year. Although the
capital costs for PSC and NSCR are similar, NSCR has higher maintenance costs.
The cost of SCR applied to an internal combustion engine is roughly the same
as the cost of SCR applied to a gas turbine, on an energy input basis. The
costs for the gas turbine were developed for a 400 MMBtu/hr input gas turbine
operating 90 percent of the year.
The cost for the afterburner control technology in Table 20 is based on a
$700,000 capital cost for a 7.5 ton/hour capacity wood charcoal furnace (U.S.
EPA, 1979). The cost was levelized using a 5 percent interest rate over
30 years and a capacity factor of 0.55.
-------
TABLE 23. FUEL PRODUCTION EMISSION CONTROL COST
Technology
Source
Capacity
(MMBTU/hr)
Capital
Cost
($1,000)
Annual
Cost
(51,000)
Flue Gas Recirculation
(Retrofit)
SCR (Retrofit)
Ammonia Injection
(Retrofit)
Staged Combustion Air
Low Excess Air
SCA and LEA
150
150
150
55
55
55
256
2,970
380
54
44
98
17
252
55
21
0.2
21
89
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SECTION 7
MOBILE SOURCES AND CONTROL TECHNOLOGIES
Emission factors were developed for six highway and four off-highway
transportation technologies. Eight control technologies for several of these
sources were identified, and performance and cost estimates were developed.
The emission factors and •controls cost, reduction efficiency, and availability
date are discussed in this section.
MOBILE SOURCE EMISSIONS
Table 24 summarizes the emission factors developed for mobile sources.
The emission factors are based on the mass of pollutant emitted per gigajoule
of fuel energy input. Included in Table 24 are the emission factors for each
of the five gases considered in this study. To the right of each emission
factor is its quality rating. The last column indicates by code the
applicable control technologies.
The emission sources in Table 24 can be categorized into highway and off-
highway sources. Highway sources include light duty gasoline vehicles (LDGV),
heavy duty gasoline vehicles (HDGV), light duty diesel vehicles (LDDV), heavy
duty diesel vehicles (HDDV), and light duty vehicles fueled with compressed
natural gas (CNG) and methanol. The off-highway sources include both jet and
gasoline-fueled aircraft, railroad locomotives, and ships.
Highway Source Emissions
Emission factors for NOX and CO were calculated on an energy input basis
for light and heavy duty gasoline- and diesel-fueled vehicles. These emission
factors are based on data obtained from Mobiles, a FORTRAN model for the
assessment of the impact of highway sources on air pollution containing an
extensive database of emission factors and fuel economy (EPA, 1984). The
Mobiles database has been extensively reviewed, and includes also emission
factors for vehicles with and without emission controls. The emission factors
on an energy input basis can be assumed to be similar from one region of the
world to another for uncontrolled vehicles.
90
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TABLE 24. MOBILE SOURCE PERFORMANCE
Emissions Factors (g/GJ energy input)
Source
Rail
Jet Aircraft
Avi at ion- - Gaso I i ne
Ships
Light Duty
Heavy Duty
Light Duty
Heavy Duty
Light Duty
Light Duty
Gasoline Vehicle
Gasoline Vehicle
Diesel Vehicle
Diesel Vehicle
Methanol Vehicle
Compressed NG Veh.
co2
69,900
72,800
35,900
70,000
54,900
41,100
73,750
73,300
53,000
50,200
B
B
C
B
A
A
A
A
B
B
CO
570
120
23,500
320
10,400
19,100
340
600
8,500
4
C
C
D
C
B
B
B
B
E
E
-4
13
2
60
20
36
60
2
a
15
120
and Data Quality Ratings (A - E)
D
E
E
D
C
C
D
D
E
E
N20
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
-x
1,640
290
80
830
400
740
300
1,200
130
140
C
D
D
C
B
B
B
B
E
E
Controls8
T1, T2, T3
T4, T5, T6
T7
T8
aControl codes are defined in Table 25.
-------
Light duty vehicles correspond to passenger cars and light trucks, whereas
heavy duty vehicles correspond to various sizes of heavy duty trucks. The
emission factors for diesel and gasoline vehicles in Table 24 represent
uncontrolled emissions. For the purpose of this study, the emission factors
are assumed not to vary with time. A change in emissions can be effected by
switching from one level of control to another.
The emission factors for CH4 for light and heavy duty diesel and gasoline-
fueled vehicles are based on AP-42 federal test procedure (FTP) methane
offsets. These offsets are CH4 emission factors, which are given in units of
grams CH4 per mile traveled. The values for methane offsets representing
emissions from vehicles driven at low altitudes were converted to energy-
based CH4 emission factors using fuel consumption data from the Mobiles study.
The low altitude methane offsets were assumed to be more representative of
global average CHA emission factors than the high altitude methane offsets
from AP-42. The vehicular emissions of CH4 have generally decreased in the
United States due to the application of increasingly stringent emission
control technologies. Therefore, to represent emissions from uncontrolled
motor vehicles, the LDGV methane offset for 1967 and prior was used to
estimate the LDGV CH4 emission factor. Emission controls were first required
for LDGV in the United States beginning in 1968. Similarly, for HDGV, LDDV,
and HDDV, the methane offsets for 1977, 1984, and 1986 and prior were used,
respectively, to estimate CH4 emission factors. These offsets either predate
the required application of emission controls in the United States for their
respective vehicle classes, or they are unchanged from the offsets for
vehicles without emission controls.
C02 emissions were calculated using a carbon balance including the CO and
CH4 emission factors and the properties of gasoline and diesel fuel from
Table 5. The balances include the fuel carbon as an input, and the emission
of C02, CO, and CH4 in the output.
Limited emission test data for N20 are available for diesel- and gasoline-
fueled vehicles (Smith and Black, 1980). However, recently discovered
problems with sampling methods for N20 cast doubt on this existing data base.
Consequently, no N20 emission factors are presented here.
For methanol-fueled light duty vehicles, emissions data were readily
available from tests for only two vehicles, a Ford Escort and a Volkswagen
Rabbit. The tests were done using the FTP, and the tests of the Ford Escort
92
-------
included tests without a catalyst, which are the basis for the emission
factors in Table 24. The CO, CH4, and NOX emission factors for light
duty methanol vehicles are based on the test data for the Ford Escort.
The C02 emission factor was calculated including CO, CH4, and CH3OH in
the carbon balance, using the properties of methanol from Table 5. No
data were readily available for N20 emissions from methanol-fueled
vehicles (Smith and Urban, 1982).
The emission factors for light duty compressed natural gas vehicles
are based on an average of emissions from a 1980 Dodge Diplomat and a
1979 Chevrolet Impala during FTP tests. Emissions of CH4, CO, and NOX
were measured, as was fuel consumption. The C02 emission factor was
calculated based on CO and CH4, using the technique outlined in
Section 2, and the properties of natural gas from Table 5. The emission
factors for natural gas-fired vehicles are based on tests of only two
vehicles, and should be regarded only as rough estimates (Pennings,
1981) .
Off-Highway Source Emissions
The emission factors for rail transportation in Table 24 for NOX and
CO represent a weighted average of emissions of line haul and switching
locomotives in the United States. The CH4 emission factor is based on a
weighted average total hydrocarbon emission factor. Line haul
locomotives comprise 80.1 percent of all locomotives, the rest being
switching locomotives (Ingalls, 1985). The emission factor for methane
is based on 10 percent of the emission factor for total hydrocarbons;
for diesel engines, over 90 percent of total hydrocarbon emissions are
nonmethane hydrocarbons (U.S. EPA, 1977b). No data were available for
N20 emissions from railroad locomotives. The C02 emission factor was
calculated based on the properties of diesel fuel and a carbon balance
including CO and CH4.
A single engine was selected from which to calculate the jet aircraft
emission factors in Table 24. Emission factors for several engine
models are available in AP-42; however, information was not readily
available from which to calculate a weighted emission factor for all
aircraft. The emission factors for jet aircraft are based on the JT8D17
engine manufactured by Pratt and Whitney, which is used on the Boeing
727, Boeing 737, and the McDonnell Douglas DC9. Jet aircraft emissions
93
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are usually calculated to approximate the emissions occurring near an
airport, based on a typical landing and takeoff (LTO) cycle. For a
commercial carrier jet, the typical LTO cycle includes 19.0 minutes in
taxi and idle before takeoff, 0.7 minutes during takeoff, 2.2 minutes in
climbout, 4.0 minutes in approach, and 7.0 minutes in taxi and idle
after landing. During takeoff, the engine is operated at 100 percent
power, during climbout the engine is operated at 75 to 90 percent of
full power, and during approach the engine is operated at 30 to 40
percent of full power. Emission factors for each engine in AP-42
include emissions during idle, takeoff, approach, and climbout. From
these factors, and from fuel consumption data for each of these four
modes, emission factors were developed that reflect the average emission
throughout a modified landing and takeoff cycle.
To approximate the emissions for an entire flight, the LTO cycle was
modified to include additional time during climbout and approach. The
time spent in climbout and approach was increased by approximately 30
minutes each to represent a one-hour flight. The effect of this
modification on the average emission factors is to decrease CO and CH4i
increase NOX, and slightly decrease C02. The emission factors for CO and
NOX were calculated directly from the AP-42 data, using the modified LTO
cycle. Emissions of CH4 are based on 10 percent of the total
hydrocarbon emission factor calculated using the modified LTO cycle. No
data were available for the emission of N20 from jet aircraft engines.
The C02 emission factor was calculated using the properties of Jet A
fuel and a carbon balance as described in Section 2, including CO and
CH4.
The emissions for gasoline-fueled aircraft were calculated in a manner
similar to that for jet aircraft. The 0-200 engine, used on Cessna
aircraft, was selected as a representative engine for gasoline-fueled
piston engine aircraft. The emission factors for this engine are
available in AP-42. The LTO cycle for general aviation piston aircraft
is 12.0 minutes taxi and idle before takeoff, 0.3 minutes during
takeoff, 5.0 minutes during climbout, 6.0 minutes during approach, and
4.0 minutes during taxi and idle after landing. This LTO cycle was
extended approximately 15 minutes for both climbout and approach to
represent a one-half hour flight.
94
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The emission factors for NOX and CO calculated directly from the
emission factors from AP-42 using the modified LTO cycle. The emission
factor for CH4 is based on 10 percent of the AP-42 emission factor for
total hydrocarbons. No data were readily available for N20 emissions
from gasoline aviation engines. The C02 emission factor is based on the
properties of gasoline and a carbon balance including CO and CH4.
The emissipn factors for ships are based on the factors in AP-42 for
commercial motorships. The emission factors for NOX/ CO, and total
hydrocarbons are based on values for river, coastal, and Great Lakes
shipping. The emission factor for CH4 is based on 10 percent of the AP-
42 emission factor for total hydrocarbons. The C02 emission factor was
calculated from the properties of diesel fuel and a carbon balance as
described in Section 2, including CO and CH4.
MOBILE SOURCE EMISSION CONTROL TECHNOLOGIES
No emission control technologies were readily identified for rail,
aviation, and shipping sources. Several technologies were identified
and selected for light and heavy duty gasoline and diesel vehicles.
These emission control technologies, and their cost, emission reduction
efficiencies, and availability dates are given in Table 25.
The emission data listed in Table 25 for highway vehicles are
different from other control technologies presented in this report in
that they represent comparisons of vehicles with controls to vehicles
without controls. The emission reduction efficiencies for highway
source controls were estimated by comparing the emissions of vehicles
without controls to the emissions of vehicles with controls. The
reduction efficiencies for these controls may therefore be different
from reduction efficiencies derived by comparing "before and after"
emission rates of a single vehicle tested without, and then with, an
add-on or combustion modification control.
Emission Reduction Efficiency
The emission reduction efficiencies for the eight control technologies
applied to highway sources were estimated by comparing the energy
specific emissions of vehicles with controls to vehicles without
controls. These estimates are based on data obtained using Mobiles.
95
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TABLE 25. MOBILE SOURCE EMISSION CONTROLS PERFORMANCE AND COSTS
CTl
CO CO CH NO NO
Cost Reduction Reduction Reduction Reduction Reduction
Technology Code ($/J End-Use) (X) (X) (X) (X) (X)
LOGV Engine Control T1 N/A -11 36 Negligible N/A 8
LDGV Oxidation Catalyst T2 2.0E-10 -17 57 33 -2300 23
LDGV 3 Way Catalyst T3 2.0E-10 -23 78 44 -3400 44
HDGV Engine Control T4 N/A -25 35 52 N/A 31
HDGV Oxidation Catalyst T5 2.0E-10 -66 90 70 N/A 33
HDGV 3 Way Catalyst T6 2.0E-10 -71 97 69 N/A 41
LDDV Lou NO Control T7 N/A Negligible 11 -16 N/A 24
X
HDDV Lou NO Control T8 N/A Negligible 8 Negligible N/A 41
X
Date
Available
1968
1975
1980
1978
1985
1998
1985
1987
a
All costs in 1985 dollars.
N/A = not available.
-------
Data for NOX and CO were available on an energy-specific basis for each
level of control. Data for CH4 were available from the AP-42 methane
offsets discussed above. These offsets were applied to various control
levels by comparing the years for which the offsets are valid to the
years for which various control technologies were required. For
example, in 1967 and before, no controls were required for LDGV. Engine
controls were required from 1968 to 1974, oxidation catalysts were
required from 1975 to 1979, and three-way catalysts were required
beginning in 1980. The appropriate methane offsets for these years from
AP-42 were used for each of the control levels. The effect of controls
on C02 emissions was determined by calculating the C02 emission factor
for each control level, using a carbon balance including CO and CH4, and
comparing the C02 emission factor with controls to the emission factor
without controls.
Most tests suggest that N20 emission from catalyst-equipped LDGV are
within a range of 50 to 100 mg/mile. As previously discussed, the N20
emissions of uncontrolled LDGV, based on a single data point, are
roughly 5 mg/mile. Catalysts may promote the partial oxidation of
nitrogen to N20. For LDGV, the effect of catalysts on N20 was estimated
by assuming an emission rate of 5 mg/mile for vehicles without controls
and 100 mg/mile for vehicles with catalyst controls. These emission
rates were converted to an energy basis using the same fuel consumption
data as for the other pollutants. A comparison of the energy-specific
emission factors for N20 with and without catalyst control resulted in
the estimates in Table 25 for LDGV oxidation and three way catalysts.
Insufficient information was available for HDGV to justify a similar
comparison (Smith and Black, 1980).
Cost
The cost for a catalyst was assumed to be roughly $100 for LDGV. This
cost was annualized over 10 years assuming 10,000 miles driven per year
at 20 miles per gallon. No difference in cost was assumed between
oxidation and three-way catalysts. The cost of catalysts for heavy duty
vehicles was assumed to be the same on an energy-specific basis.
97
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SECTION 8
RESIDENTIAL AND COMMERCIAL SOURCES AND CONTROLS
Efficiency and emission factor estimates were developed for nine
residential emission sources and 11 commercial emission sources. For both
residential and commercial sources, performance and cost estimates were
developed for applicable control technologies. This section presents the
performance estimates for residential sources. Commercial source efficiency
and emission estimates are also discussed as are emission control technologies
for both residential and commercial sources. A glossary of terms used in the
tables of section appears at the end of this report.
RESIDENTIAL SOURCES
Table 26 presents the efficiencies and emission factors for nine
residential emission sources. These sources burn wood, propane and butane,
coal, distillate oil, and natural gas. Included in Table 26 is the
efficiency, energy input emission factors (unless otherwise noted), emission
factor quality rating, and appropriate control codes.
Efficiency
The efficiency of residential sources is the percent of the input energy
converted to thermal energy for an end-use. Efficiency data was readily
available for only three of the residential emission sources: wood stoves,
distillate oil' furnaces, and gas heaters. These are the only sources with
emission factors reported on an energy output basis. The efficiency of
standard wood stoves is estimated to be 50 percent; the efficiency of standard
distillate oil furnaces is estimated to be 75 percent; and the efficiency of
standard natural gas heaters is estimated to be 70 percent (Castaldini et al.,
1981).
Emission Factors
The emission factors for NOX, CO, and CH4 for residential sources, unless
otherwise noted, were taken directly from AP-42 and converted to an energy
98
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TABLE 26. RESIDENTIAL SOURCE PERFORMANCE
Source
Efficiency
(X)
CO
Emissions Factors (g/GJ energy input) and
Data Quality Ratings (A - E)
CO
CH
"2°
NO
Controls
Wood Pits
Uood Fireplaces
Uood Stoves
Coal Furnaces
N/A
N/A
50
Propane/Butane Furnaces N/A
Coal Hot Water Heaters N/A
N/A
Coal Stoves N/A
Distillate Oil Furnaces 75
Gas Heaters 70
26,000 C
32,000 C
70,000° C
60,000 A
103,000 C
102,000 C
99,000 C
83,000a A
71,000° A
4,700 B
5,700 0
17,600° D
9 C
17 B
460 C
3,400 B
178 B
13a B
190 B
N/A
70° E
1 C
N/A
N/A
N/A
7 B
I8 E
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
140 B
110 D
190° D
42 C
150 B
220 C
170 B
65 B
6ia B
Rl. R2
R6 - R10, R1B - R24
R11 - R17
Emission factor units are g/GJ energy output.
Control codes are defined in Table 28.
-------
input basis using the appropriate fuel heating value from Table 5. Emission
factors for wood stoves, distillate oil furnaces, and natural gas heaters were
converted to an energy output basis using both the fuel heating value and the
energy conversion efficiency discussed earlier. No data were available from
which to estimate N20 emissions from residential sources. The C02 emission
factor for residential wood-fired sources was calculated using a method that
accounts for the carbon retained in fly ash during the inefficient combustion
typical of these emission sources. For the other emission sources, the C02
emission factor was calculated using the methods of Section 2.
The NOX, CO, and CH4 emission factors for wood pits were estimated based on
AP-42 emission factors for open burning of forest residues. It was assumed
that these factors are applicable as emission factors for the open burning of
wood. The heating value used for wood for these calculations was 14.8 MJ/kg,
which is more representative of the lower moisture content wood burned in
residential sources than the heating value in Table 5, applicable to wood-
fired boilers. Because a significant amount of carbon is released from
natural draft wood combustion in the form of nonmethane organics (e.g.
polycylic organic matter, alkanes, aldehydes, ketones, etc.) or retained in
the ash, a carbon balance approach for estimating C02 as described in
Section 2 is not applicable.
C02 emission factors for conventional wood stoves were derived from
emission tests done for Omni Environmental Services Certification Reports for
the Oregon Department of Environmental Quality. Both CO and C02 were
measured, and for the emission tests reviewed, the ratio of the C02/C0
emission rates was approximately 4.0. This factor was applied to the CO
emission rates obtained from AP-42 to derive an estimate of C02 emissions from
conventional wood stoves. Similarly, emission tests on appliances with air to
fuel ratios characteristic of fireplaces were found to have C02/C0 ratios in
the range of 5 to 6. Therefore, a factor of 5.5 was applied to the CO
emission rates for fireplaces and open burning to derive an estimate of the
C02 rates. The C02 emission factor calculated in this manner is significantly
lower than an emission factor calculated using the carbon balance method
described in Section 2 and accounts for the carbon emitted as non-methane &
organics and retained in solids formed during combustion. It should be
emphasized that this method of estimating C02 is a rough, order-of-magnitude
100
-------
estimate, more appropriate for natural draft wood combustion sources that
exhibit incomplete combustion.
The energy input-based emission factors for wood fireplaces were
determined from AP-42 factors for NOX and CO from fireplaces, using the same
heating value as-for wood pits. No emission factor for CH4 was readily
available. The C02 emission factor was calculated using a C02 to CO mass
ratio of 5.5 using the same method as for wood pits.
The emission factors for wood stoves were converted to an energy output
basis using the estimated efficiency of 50 percent and a heating value for
wood of 14.8 MJ/kg as discussed. The emission factors for NOX, CO, and CH4
were calculated from AP-42 emission factors. The C02 emission factor was
calculated in the same manner as for wood pits, using a C02 to CO mass ratio
of 4.
The energy input-based emission factors for CO, CH4, and NOX were
calculated for propane/butane heaters and furnaces by averaging AP-42 emission
factors for butane and propane heaters. The AP-42 factors were converted to
an energy input basis using the average heating value for butane and propane
from Table 5. The emission factor for C02 was calculated using the carbon
balance method of Section 2; however, CO and CH4 emissions are negligible and
were not included in the carbon balance.
The coal-fired hot water boiler NOX and CO emission factors were both
calculated from an average of six data points and were converted from a mass
to an energy input basis using the heating value for coal from Table 5 (Hughes
and DeAngelis, 1982). Emission data for CH4 were not readily available. The
C02 emission factor was estimated based on the heating value and carbon
content of coal. The emission factors for coal furnaces were determined in
the same manner as for coal-fired hot water boilers, except that the NOX and
CO emission factors are based on an average of four data points, and the C02
balance includes CO.
The CO emission factor for coal-fired stoves is based on an average of
three emission factors for bituminous coal and one emission factor for
anthracite coal, converted to an energy input basis using the heating value
for coal in Table 5 (Truesdale and Cleland, 1982). An emission factor for CH4
was not readily available. The emission factor for NOX is based on an average
of emissions data from two sources (Truesdale and Cleland, 1982). Emission of
101
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CO was accounted for in estimating the C02 emission factor, using the carbon
balance technique described in Section 2.
The CO, NOX, and CH4 emission factors for distillate oil furnaces were
estimated on an energy output basis from AP-42 emission factors, the heating
value for distillate oil from Table 5, and the efficiency for distillate oil
furnaces from Table 26. The C02 emission factor was calculated based only the
carbon content of distillate oil from Table 5; CO and CH4 have a negligible
impact on the C02 emission factor.
Finally, the CO, CH4, and NOX emission factors for natural gas heaters are
based on emission factors for commercial natural gas-fired space heaters
(Truesdale and Cleland, 1982). These factors were converted to an energy
output basis using the natural gas heating value and the efficiency of natural
gas-fired space heaters. The C02 emission factor was calculated only from the
properties of natural gas.
COMMERCIAL SOURCES
As part of the commercial sources category, 11 energy conversion
technologies were evaluated for efficiency and emissions. These sources
include technologies for burning wood, natural gas, residual oil, distillate
oil, MSW, coal, shale oil, and agricultural wastes.
The efficiency and emission factors for each source are presented in
Table 27. To the right of each emission factor is the emission factor quality
rating. The last column contains the code for control technologies, which are
presented in Table 28.
Efficiency
Efficiency estimates were developed for all commercial emission sources
with the exception of open burning and incineration sources. These sources
are not generally intended for energy conversion; instead, they are used for
waste disposal. Because generally no energy is recovered from the open
burning or incineration of waste, and because the combustion of these wastes
is for the purpose of waste disposal, the emission factors for these sources
are in terms of amount of pollutant emitted per unit mass of waste.
102
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TABLE 27. COMMERCIAL SOURCE PERFORMANCE
Source
Wood Boilers
Gas Boilers
Residual Oil Boilers
o
**» Distillate Oil Boil.
HSU Boilers
Coal Boilers
Shale Oil Boilers
Open burning - HSU
Open burning-Agric.
Inciner.-high effic.
Inciner.-Lou effic.
Emissions Factors (g/GJ end-use energy) and
Data Quality Ratings (A - E)
Efficiency CO CO CH NO NO Controls*
(X) *
67.5 138,000 C 280 D 21 E 6 E 47 C R25
80.9 61.800 A 10.6 A 1 .4 D 2.7 E 53 A R25, R26, R28, R30
84.9 86.000 A 19 A 1 .8 A 52 E 183 A R25, R27. R29
82.8 85,000 B 18 A 0.8 A 18 E 74 A R25, R26, R28, R30
55.0 157,000 D 32 B N/A N/A 800 C R25
75.9 135,000 C 244 E 13 E 74 E 295 E R25. R27, R29
84.9 86.000 E 19 E 1.8 E 52 E 208 E R25, R27, R29
n/appl 900 kg/Mg C 42 kg/Mg C 6.5 kg/Mg C N/A 3 kg/Mg C
n/appl 1,570 kg/Mg C 58 kg/Mg C 9 kg/Mg C N/A N/A
n/appl 970 kg/Mg C 5 kg/Mg B N/A N/A 1.5 kg/Mg B
n/appl 960 kg/Mg C 10 kg/Mg B N/A N/A 1 kg/Hg B
Control codes are defined in Table 28.
-------
TABLE 28. RESIDENTIAL AND COMMERCIAL EMISSION CONTROLS COST AND PERFORMANCE
Technology
Catalytic Woods tove
Non-Catalytic MCS
Flame Ret. Burn. Hd.
Contr. Mix. Burn. Hd
Integr. Furn. Syst.
Biueray Burn. /Furn.
M.A.N. Burner
Radiant Screens
Secondary Air Baffle
Surface Comb. Burner
Amana HTM
Modulating Furnace
Pulse Combustor
Catalytic Combustor
Replace Worn Units
Tuning, Seas. Maint.
Red. Excess. Firing
Red Fir w/ new ret b
Pos. Chimney Dampers
Inc. therm, anticip.
Night therm, cutback
Low Excess Air
Flue Gas Recirculat.
Over- fire Air
Over- fire Air
Low NOx Burners
Low NOx Burners
Code
R1
R2
R6
R7
R8
R9
R10
R11
R12
R13
RU
R15
R16
R17
R18
R19
R20
R21
R22
R23
R24
R25
R26
R27
R28
R29
R30
Efficiency
Loss
(X)
-44
-30
-9
-7
-12
-12
-13
-7
N/A
N/A
-21
-7
-36
-29
N/A
-2
-19
-40
-8
-1
-15
-0.8
0.6
1
1
0.6
0.6
Cost
(S/J End-Use)
N/A
N/A
1.5E-11
1.3E-11
6.9E-11
2.8E-11
N/A
N/A
N/A
N/A
5.1E-11
4.4E-11
9.7E-11
4.8E-11
2.5E-10
1.0E-10
1.3E-11
8.3E-11
5.7E-11
minimal
minimal
-7.0E-09
N/A
N/A
N/A
N/A
N/A
"2
Reduction
(X)
-35
-6
neg
neg
neg
neg
N/A
neg
neg
neg
neg
N/A
N/A
N/A
neg
neg
neg
neg
neg
neg
neg
N/A
N/A
N/A
N/A
N/A
N/A
CO
Reduction
(X)
90
15
28
43
13
74
N/A
62
16
55
-55
N/A
N/A
N/A
65
16
14
14
11
43
17
N/A
N/A
N/A
N/A
N/A
N/A
CH4
Reduction
(X)
90
50
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N.,0
Reduction
(X)
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
NO
Reduction
(X)
-27
-5
N/A
44
69
84
71
55
40
79
79
32
47
86
N/A
N/A
N/A
N/A
N/A
N/A
N/A
15
50
20
30
40
50
Date
Available
1985
1985
1980
1970
1975
1970
1970
1980
1980
-------
Efficiencies for the other sources will be discussed in the order in which they
appear in Table 26.
Efficiency data were not readily available for commercial wood-fired
boilers; an efficiency for industrial wood-fired boilers of 67.5 percent was
assumed applicable. The efficiency of commercial boilers is taken to be 80.9
percent for natural gas based on an average of 16 data points. For residual
oil boilers, the efficiency is 84.9 percent based on an average of 13 points.
Distillate oil-fired boilers are assumed to have an efficiency of 82.8 percent
based an average of 5 points. Based on an average of nine points, coal-fired
commercial boilers are assumed to have an efficiency of 75.9 percent. An
efficiency of 55 percent, based on small modular incinerators with heat
recovery, is assumed for MSW commercial boilers (Shindler, 1987) . The
efficiency of shale oil-fired commercial boilers is assumed to be the same as
that for residual oil-fired boilers.
Emission Factors
The emission factors for NOX, CO, and CH< were taken directly from AP-42 and
converted to energy units, except for open burning and incineration, using the
appropriate heating value from Table 5 and efficiency from Table 26, except
where noted. The emissions of N20 were estimated to be 5 percent of NOX
emissions for natural gas, 25 percent for oil and coal, and 13 percent for
wood, as discussed in previous sections for utility and industrial boilers. No
data were available for emissions of N20 from MSW or agricultural waste. C02
emission factors are calculated only from fuel properties using the technique
outlined in Section 2 except for open burning and incineration. Both CO and
CH4 included in the carbon balance for open burning, and CO was included in the
carbon balance for incineration.
The emission factor for CO for wood-fired boilers is taken from a the NAPAP
emission inventory (Shindler, 1987) . For MSW-fired commercial boilers, the
emission factor for CO is assumed to be the same as for industrial small
modular MSW-fired boilers. No data were available for the emission of CH4 from
MSW boilers, or from open burning or incineration of waste. The NO* emission
factor for MSW-fired boilers is based on the emission factor for solid waste-
fired controlled air units in AP-42.
For coal-fired boilers, the emission factors for NOX, CO, and CH4 were
calculated using a U.S. population-weighted average of AP-42 emission factors
for overfeed stoker, underfeed stoker, and spreader stoker coal-fired boilers.
These three firing types comprise 33 percent of the total U.S. commercial
boiler capacity (Devitt et al., 1979). Emission factors for firetube and cast
105
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iron industrial boilers, which comprise most of the remaining capacity, were
not readily available.
As a rough estimate, the emission factors for shale oil-fired boilers were
assumed to be the same as those for residual oil-fired boilers.
The NOX, CO, and CH, emission factors for open burning of MSW were taken
directly from AP-42 factors. The C02 emission factor was calculated including
both CO and CH, in the carbon balance using the method outlined in Section 2.
In a similar manner, the emission factors for open burning of agricultural
waste were derived; however, an emission factor for NOX was not readily
available. The CO and CH, emission factors are based on the "unspecified"
field crops category in AP-42. Since carbon contents for various field crops
were unavailable except for bagasse, an average carbon content of 46 percent
for dry bagasse was used to calculate a C02 emission factor (U.S. EPA, 1982b) .
Both CO and CH4 were included in the carbon balance as discussed in Section 2.
Emission data for CH4 from incinerators firing MSW were not readily
available. The C02 emission factors for both multi-stage and single chamber
incinerators are based on the carbon content of MSW and a carbon balance
including CO.
RESIDENTIAL AND COMMERCIAL SOURCE EMISSION CONTROL TECHNOLOGIES
Table 28 includes 27 control technologies, the first 21 of which are
applicable to residential emission sources, and the last 6 of which are
applicable to commercial sources. Table 28 includes the code for each
technology, the efficiency penalty, the emission reduction efficiency for each
pollutant, and the availability date.
Efficiency Penalty
Most of the controls for residential sources result in an increase in the
combustion efficiency of the sources to which they are applied. Catalytic wood
stoves and noncatalytic modified combustion wood stoves have efficiency
increases of 44 and 30 percent, respectively, over conventional wood stoves.
Low excess air, flue gas recirculation, overfire air, and low NOX burners may
be applied to several of the commercial emission sources. Low excess air
typically results in about a 0.8 percent increase in efficiency, whereas the
other controls typically decrease the source efficiency as indicated in
Table 28 (Castaldini et al., 1981). All other controls in Table 28 for which
efficiency penalty information was readily available result in an increase in
the source thermal efficiency (Castaldini et al., 1981).
106
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Reduction Efficiency
Unless otherwise noted, the reduction efficiencies for each control
technology were estimated from Castaldini et al. (1981). For most of the
control technologies, the CO reduction (or increase) does not significantly
impact the emission factor for C02. An entry of "negligible" for the C02
emission factor indicates that C02 emissions, based on a carbon balance, do not
vary more than 0.05 percent from the original value due to the application of
the control technology.
The catalytic and noncatalytic modified combustion wood stove technologies
significantly impact the emissions of NOX, CH4, and CO (U.S. EPA, 1982b). The
emission of C02 for these sources is also significantly impacted. The increase
in the emission of C02 for these two controls was estimated by assuming that
the CO reduced by the controls is converted to C02.
The only emission reduction data readily available for low excess air, flue
gas recirculation, overfire air, and low NOX burners applied to commercial
sources were the reduction efficiency for NOX (U.S. EPA, 1982b).
Cost
The basis for the annualized control technology costs presented in Table 28
is given in Table 29. Table 29 includes the capacity of the source for which
control costs were calculated, the capital cost, and the annual cost of the
control. These costs were annualized using a life of 15 years, and an interest
rate of 10 percent. All control costs were converted to an energy output basis
using the appropriate source efficiency from Table 26. All costs exclude fuel
except for low excess air (R25), for which nonfuel costs were not readily
available.
107
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TABLE 29. RESIDENTIAL AND COMMERCIAL EMISSION CONTROL COST
Technology
Flame Retention Burners
Controlled Mix Burner Hood
Integrated Furnace System
Blueray Burner/Furnace
Amana HTM
Modulating Furnace
Pulse Combustor
Catalytic Combustor
Replace Worn Units
Tuning
Reduced Excessive Firing
Source
Capacity
29.3 kW
29.3 kW
29.3 kW
29.3 kW
29.3 kW
29.3 kW
29.3 kW
29.3 kW
29.3 kW
29.3 kW
29.3 kW
Capital
Cost ($)
75
62
363
145
290
218
653
290
1,196
--
75
Annual
Cost (S)
--
--
--
--
--
--
...
--
--
71
Firing Capacity -
Conventional Burner
Reduced Excessive Firing
Capacity - New Retention
Burner
•Positive Chimney Dampers
Low Excess Air
29.3 kW
29.3 kW
2.9 MW
558
290
7,000
Source: Castaldini et al., 1981; Truesdale and Cleland, 1982.
108
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Perry, R., and C. Chilton (1973) Chemical Engineers' Handbook. McGraw-Hill
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110
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Shindler, Peter (1987) Municipal Waste Combustion Study: Emissions Data Base
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Singer, J. (1981) Combustion: Fossil Power Systems. Combustion Engineering,
Windsor, CT.
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112
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GLOSSARY
Agric
AFBC
AP-42
bbl crude
well
BOOS
C
Cat Mod. Comb. Stove
Coal-FB Comb Cycl
Coal - PC Cyclone
Comb.
Contr. Mix. Burn. Hd.
CF
CNG
CRT
Distil. Oil
FBC
Effic.
FGR
Fir.
Flame Ret. Burn. Hd.
FTP
Gas Turbine Comb. C.
Gas Turbine Simp. C.
GJ
HC
Agricultural
Atmospheric Fluidized Bed Combustion
Compilation of Air Pollutant Emission Factors
Vols. I and II. U.S. EPA AP-42
Barrels (42 gallons) of crude oil from oil
Burners Out of Service
Carbon
Catalytic Modified Combustion Stove
Coal - Fluidized Bed Combined Cycle
Coal - Pulverized Coal Cyclone
Combustion
Controlled Mixing Burner Head
Capacity Factor
Compressed Natural Gas
Capital Recovery Factor
Distillate Oil
Fluidized Bed Combustion
Efficiency
Flue Gas Recirculation
Firing
Flame Retention Burner Head
Federal Test Procedure
Gas Turbine Combined Cycle
Gas Turbine Simple Cycle
Giga Joule (109 Joules)
Hydrocarbons
113
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GLOSSARY (Continued)
HDDV
HDGV
1C Engine
Inc. therm, anticip.
Inciner. - high effic,
Inciner. - low effic.
In-Situ Retorting
HV =
LDDV
LDGV
LEA
LNB
MSW
MW
N/A
NAPAP
neg
Night therm, cutback
NSCR
OFA
Oil Shale Retorting
Pos. Chimney Dampers
PSC
RDF
Heavy Duty Diesel Vehicle
Heavy Duty Gasoline Vehicle
Internal Combustion Engine
Increased Thermostat Anticipator Setting
High Efficiency Incinerators
Low Efficiency Incinerators
Underground process for removing shale oil
from shale
Heating Value (Higher)
Light Duty Diesel Vehicle
Light Duty Gasoline Vehicle
Low Excess Air
Low NOX Burner
Municipal Solid Waste
Megawatt
Not Available
Criteria Pollutant Emission Factors for the 1985
NAPAP Emissions Inventory. EPA-600/7-87-015
Negligible
Night Thermostat Cutback
Non-Selective Catalytic Reduction
Overfire Air
The process for extracting shale oil from the
shale with heat
Positive Chimney Dampers
Pre-Stratified Charge
Refuse Derived Fuels
114
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GLOSSARY (Continued)
Red. Fir w/new ret b.
Retrof.
Refinery CH4 Used
Refin. Nat. Gas
SCR
SNCR
TF
THC
Tuning, Seas. Maint.
Reduced excessive firing capacity with new
retention burner
Retrofit
Oil refinery scenario in which natural gas
from wells is routed to heat generation
Refinery Natural Gas
Selective Catalytic Reduction
Selective Non-Catalytic Reduction
Tangentially Fired Coal Fired Boiler
Total Hydrocarbons
Tuning and Seasonal Maintenance
115
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TECHNICAL REPORT DATA
(Please read IttOructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-90-010
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
Emissions and Cost Estimates for Globally Significant
Anthropogenic Combustion Sources of NOX, N2O,
CO, and CO?
5. REPORT DATE
May 1990
6. PERFORMING ORGANIZATION CODE
7Stephen D. Piccot, Jennifer A. Buzun, and
8. PERFORMING ORGANIZATION REPORT NO
H. Christopher Frey
9. PERFORMING ORGANIZATION NAME AND ADDRESS
10. PROGRAM ELEMENT NO.
Radian Corporation
P. O. Box 13000 •
Research Triangle Park, North Carolina 27709
11; CONTRACT/GRANT NO.
68-02-4288, Task 38
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final; 4/87 - 1/90
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES AEERL project officer is Julian W. Jones,
541-2489.
Mail Drop 62, 919 /
is. ABSTRACT
repOrt discusses the development of emission factors for CO2, CO,
CH4, NCx, and N2C for about 80 globally significant combustion sources in seven
source categories: utility, industrial, fuel production, transportation, residential,
commercial, and kilns /ovens /dryers. Because of the lack of adequate international
data, the emission factors for most sources are based on U.S. performance, cost,
and emissions data. Data on CO2, CO, and NOx were available for over £>0% of the
sources studied; on CH4, for about 80%; and on N2O, for only about 10%. Emission
factor quality ratings were developed to indicate the overall adequacy of the suppor-
ting data. Quality ratings ranged from A to E, with A the best. Except for N2O, the
emission factors for the gases covered the quality spectrum from A to E: all of the
emission factors for N2O were rated E. Evaluation of the emission factors for the
seven source categories (taking the five gases as an aggregate for each category)
showed that the kilns /ovens /dryers category had the lowest overall quality rating;
no factors rated better than E. Emission factors for fuel production were some-
what better, but generally of lower quality than for the remaining five source cate-
gories.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Emission
Cost Estimates
Combustion
Carbon Dioxide
Carbon Monoxide
Methane
Nitrogen Oxides
Nitrogen Oxide
Pollution Control
Stationary Sources
Emission Factors
13 E
14G
05A,14A
21B
07B
07C
B. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
124
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
116
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