EPA-600/2-75-046
September 1975
Environmental Protection Technology Series
NQX COMBUSTION CONTROL METHODS AND
COSTS FOR STATIONARY SOURCES
Summary Study
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Industrial Environmental Research Laboratory
Office of Research and Development
U.S. Environmental Protection Agency
Research Triangle Park, N.C. 27711
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EPA-600/2-75-046
NO COMBUSTION CONTROL
x
METHODS AND COSTS FOR
STATIONARY SOURCES
Summary Study
by
A.B. Shimizu, R.J. Schreiber, H. B. Mason,
G.G. Poe, andS.B. Youngblood
Aerotherm Division, Acurex Corporation
485 Clyde Avenue
Mountain View, California 94040
Contract No. 68-02-1318, Task 12
ROAPNo. 21BCC
Program Element No. 1AB014
EPA Project Officer: David G. Lachapelle
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
September 1975
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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
five series. These five broad categories were established to
facilitate further development and application of environmental
technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in
related fields. The five series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY STUDIES series. This series describes research
performed to develop and demonstrate instrumentation, equipment
and methodology to repair or prevent environmental degradation from
point and non-point sources of pollution. This work provides the
new or improved technology required for the control and treatment
of pollution sources to meet environmental quality standards.
EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental Protection Agency,
and approved for publication. Approval does not signify that the contents
necessarily reflect the views and policies of the Agency, nor does mention of
trade names or commercial products constitute endorsement or recommendation
for use.
This document is available to the public through the National
Technical Information Service, Springfield, Virginia 22161.
ii
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ABSTRACT
This report summarizes the technology, user experience and cost for NOX con-
trol from stationary combustion sources. The significant sources are characterized
by equipment type, fuel consumption and annual mass emission of NOX. Stationary
sources emit 11.7 x 106 TPY (1972) of which 98% is due to fuel combustion ranked as
follows: coal, 37%; gas, 36%; oil, 25%. The most significant source sector is
utility boilers with 49% of stationary emissions. The technology for NOX control
by combustion modification, fuel modification, flue gas treatment and use of alter-
nate processes is summarized. Combustion modifications are identified as the most
advanced and effective technique for near and far term NOX control. Available capi-
tal and differential operating costs are given for NOX control in utility boilers
by combustion modification and flue gas treatment. NOX control by combustion is an
order of magnitude lower in capital cost than NOX or SOX control by flue gas treat-
ment. Cost data for remaining equipment types is sparse and the need is cited for
the open dissemination on a standardized basis of data on field tests of NOX control
techniques.
iii
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ACKNOWLEDGMENT
Aerotherm extends its appreciation for the valuable assistance provided by
the following Individuals and their organizations: Mr. Wes Pepper and Mr. James
Mulloy of the Los Angeles Department of Water and Power; Mr. Jim Peregoy of the
Pacific Gas and Electric Co.; Mr. Jack Johnston of the Babcock and Milcox Co.; and
Mr. Bill Nurick of Rocketdyne Corp. Thanks are also in order to Mr. David G.
Lachapelle and Mr. Wade Ponder of the Control Systems Lab of the EPA.
This study was performed for the Combustion Research Section of the Control
Systems Laboratory, U.S. Environmental Protection Agency. D. G. Lachapelle was the
task officer. The Aerotherm Project Manager was Dr. Larry W. Anderson. The study
was performed during the months January through May 1975.
1v
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TABLE OF CONTENTS
Section Page
1 INTRODUCTION 1
2 CHARACTERIZATION OF NOX EMISSIONS AND FUEL USAGE FOR
STATIONARY SOURCES
3
2.1 1972 NOX Emission Estimates, Emission Factors, and
Fuel Usage by Application Sector 3
2.2 Summary of 1972 Stationary Source NOX Emissions ]3
2.3 NOX Emission Trends and Projections '3
3 SUMMARY OF STATIONARY SOURCE NOX CONTROL TECHNIQUES 23
3.1 Combustion Modification 23
3.1.1 Utility Boilers 25
3.1.2 Industrial Boilers 28
3.1.3 Internal Combustion Engines 29
3.1.4 Space Heating 46
3.2 Fuel Modification 52
3.2.1 Fuel Switching 52
3.2.2 Fuel Additives 53
3.2.3 Fuel Denitrifi cation 53
3.3 Alternate Processes 54
3.3.1 Fluidi zed Bed Combustion 54
3.3.2 Catalytic Combustion 55
3.4 Flue Gas Treatment of NOX 56
4 COSTS OF NOX CONTROL METHODS 61
4.1 Utility Boilers 61
4.1.1 Costs of NOX Control by Combustion Modification 61
4.1.2 Costs of S02 Control by Flue Gas Treatment 72
4.1.3 Costs of NOX Control by Flue Gas Treatment 72
4.2 Commercial and Industrial Boilers 75
4.3 Internal Combustion Engines 76
4.3.1 Reciprocating 1C Engines 76
4.3.2 Gas Turbines 80
4.4 Commercial and Residential Heating 89
4.5 Additional Cost Data Requirements 91
4.5.1 Utility Boilers 91
4.5.2 Industrial Boilers 93
4.5.3 Internal Combustion Engines 93
4.5.4 Space Heating 94
Appendix A 97
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vi
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LIST OF ILLUSTRATIONS
Figure Page
2-1 Stationary sources of NOX emissions. 4
2-2 Summary of 1972 stationary source NOX emissions. 15
2-3 Nationwide NOX emission trends 1940 -1972 (Reference 2-4). 17
2-4 Stationary source NOX emission trends. 18
3-1 NOX emissions from small gas turbines without NOX controls. 41
3-2 NOX emissions from large gas turbines without NOX controls. 42
3-3 NOX emissions from gas turbines having NOX controls and
operating on liquid fuels. 47
3-4 NOX emissions from gas turbines having NOX controls and
operating on gaseous fuels. 48
4-1 1973 installed equipment costs of NOX control methods for new
tangentially, coal-fired units (included in initial design). 63
4-2 1973 installed equipment costs of NOX control methods for
existing tangentially, coal-fired units (heating surface
changes not included). 64
4-3 Effect of NOX emissions level on fuel penalty (Reference 4-15). 84
vii
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LIST OF TABLES
Table Page
2-1 Summary of emissions, emission factors, and fuel usage by
equipment categories for steam generation - utility boilers. 6
2-2 Summary of emissions, emission factors, and fuel usage by
equipment categories for steam generation — industrial
boilers. 7
2-3 Summary of emissions, emission factors, and fuel usage by
equipment category for commercial boilers. 9
2-4 Summary of emissions, emission factors, and fuel usage by
equipment category for space heating, residential heaters. 10
2-5 Summary of emissions, emission factors, and fuel usage by
equipment category for internal combustion engines. 11
2-6 Summary of emissions for industrial process heating
equipment. 12
2-7 Summary of emissions for incineration. 12
2-8 Summary of emissions for non-combustion sources. 12
2-9 Summary of total NOX emissions from fuel user sources
(1972) (Ref. 1). 14
2-10 Summary of fuel usage* 1972 (Ref. 1). 14
2-11 Comparisons of NOX emissions. 16
2-12 Fuel consumption comparisons. 16
2-13 Nationwide NOX emissions projected to 1990 assuming the
present statutory program. 19
2-14 Nationwide emissions of NOX from electric power generation
projected to 1990 for two policy options. 21
3-1 Evaluation of NOX control techniques. 23
3-2 Summary of combustion modification techniques for large
boilers'- 26
3-3 Categorization of stationary reciprocating engines
applications and emission factors. 31
3-4 Summary of combustion modification techniques for
reciprocating 1C engines. 33
3-5 Normalized percent reductions of NOX. 35
3-6 Control techniques for truck size diesel engines (<50tt hp)
to meet 1975 California 10 gm/hp-hr NOX and HC level*. 37
3-7a 1975 vehicle emission limits.
38
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LIST OF TABLES (Continued)
Table Page
3-7b Emission control techniques for automotive gasoline
engines. 38
3-8 Emission control systems for conventional gasoline I.C.
engines (adapted from Reference 3-18). 39
3-9 Gas turbine — summary of existing technology — combustion
modifications. 43
3-10 Typical emission levels from commercial and residential
heating. 49
3-11 Comparison of mean emissions for cyclic runs on residential
oil-fired units. 51
4-1 1974 estimated investment costs for low excess air
firing on existing boilers needing modifications. 65
4-2 1974 installed equipment costs for existing residual oil-fired
utility boilers. 67
4-3 LADWP estimated installed 1973 capital costs for NOX
reduction techniques on gas and oil-fired utility boilers. 68
4-4 1973 differential operating costs of NOX control methods for
new tangentially, coal-fired units (single furnace). 70
4-5 Impact of NOX control techniques on major utility boiler
components. 71
4-6 1975 installed equipment costs for utility boiler flue gas
S02 removal. 73
4-7 1975 differential operating costs for utility boiler flue
gas S0£ removal. 74
4-8 Differential costs for NOX control techniques for large
bore engines. 78
4-9 Typical baseline costs for large (>100 hp/cyl) engines. 79
4-10 Typical control costs for diesel fueled engines used in
heavy duty (>6000 Ib) 81
4-11 Estimates of sticker prices for emissions hardware from 1966
uncontrolled vehicles to 1976 dual-catalyst systems (Reference
4-14). 82
4-12 Water injection investment cost (San Diego Gas and Electric). 86
4-13 Water/steam injection cost as a function of power plant size. 86
4-14 1974 estimated costs of NOX controls for small gas turbines
(Reference 4-16). 87
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LIST OF TABLES (Concluded)
Table Page
4-15 1974 estimated costs of wet NOX controls for large gas
turbines (Reference 4-16). 88
4-16 Cost-effectiveness summary (Reference 4-16). 90
4-17 Typical costs of gas fired space heating units (Reference 4-17). 92
A-l Estimated 1972 NOX emissions from stationary sources -
ranking of NOX emissions by equipment type and firing type. 98
XI
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xi i
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SECTION I
INTRODUCTION
Oxides of nitrogen (NOV) are currently emitted at a rate in excess of 20 mil-
/\
lion tons per year. Over 98 percent of man-made NO emissions result from fuel
A
combustion with the majority due to stationary sources. Combustion generated oxides
of nitrogen are emitted predominantly as nitric oxide, NO, a relatively harmless
gas, but one which is rapidly converted in the atmosphere to the toxic nitrogen
dioxide, N02- N02 is deleterious to human respiratory functions and, with sustained
exposure, can promote an increased incidence of respiratory ailments. Additionally,
N02 is an important constituent in the chemistry of photochemical smog. The N0/N02
conversion in the atmosphere promotes the formation of the oxidant ozone, 03, which
subsequently combines with airborne hydrocarbons to form the irritant peroxyacyl-
nitrates (PAN). N02 is also a precursor in the formation of nitrate aerosols, the
health effects of which are under study by the EPA.
Under provisions of the 1970 Clean Air Act, the Environmental Protection
Agency promulgated a National Ambient Air Quality Standard for N02 of 100ygm/m3
annual average. To achieve and maintain this standard, the Clean Air Act mandated I
a 90 percent reduction in mobile source emissions and, for stationary sources,
provided for standards of performance for new stationary sources and state implemen-
tation plans or local regulations for new or existing sources. Standards of per-
formance for new sources have been promulgated as follows:
Gas Oil Coal
Steam generators
> 250 x 106Btu/hr 0.2 lb/106Btu 0.3 lb/106Btu 0.7 lb/106Btu
(~160 ppm) (-225 ppm) (-500 ppm)
Nitric Add Plants 3 Ib N02/ton acid
Standards of performance for stationary gas turbine and stationary internal combus-
tion engines are 1n preparation and may be promulgated in 1975. Work on definition
of a standard for intermediate sized industrial boilers 1s expected to begin 1n
late 1975. The most stringent local standards are 1n effect in Los Angeles County
as follows:
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New Steam Generators: 140 Ib NtWhr
Existing Steam Generators
(>1775 x 106 Btu/hr): 125 ppm (gas)
Stationary source NOX emissions can be controlled, in principal, through fuel
modification, flue gas treatment, modification of operating conditions, or use of
alternate processes. NOX formation is kinetically rate controlled and, as opposed
to SOX formation, is dominated by combustion conditions. Accordingly, combustion
modification has proven to be the most effective and readily implemented short and
long term technique for NO control. The basis of combustion modification is to
A
alleviate conditions in the primary flame zone which are favorable to NOX formation.
Control development is therefore closely related to specific equipment/fuel types.
By contrast, SOX emissions are largely dependent on fuel sulfur content and are
relatively insensitive to combustion conditions, and thus SO control development
A
has focused on flue gas treatment.
NO control techniques were initially developed for the major point sources,
A
utility and large industrial boilers, beginning with gas and oil fired units and
with subsequent treatment of coal fired units. Current emphasis is on development
of combined, advanced controls for new and existing large boilers, and on generation
of low NO design concepts for area sources such as small industrial boilers and
A
commercial and residential heating systems. The available control technology is
currently being extensively applied to retrofit of existing field units and design
of new units. In light of user experience, there is currently a need to compile
and disseminate results on NO control methods and costs.
A
The objective of this study is to summarize the status of stationary source
combustion control technology with emphasis on control costs. This was accomplished
through compilation and standardization of data from control system users and from
EPA-funded contracts. Section 2 characterizes stationary NOX sources, emission rates
and fuel consumption both by major application sector and by individual equipment
types. The available NO control techniques are reviewed in Section 3. Evaluations
A
of control effectiveness and limitations are made for techniques which have been
extensively tested. Cost data corresponding to the major control techniques are
summarized in Section 4. SO control cost data for comparable equipment types are
A
summarized for comparison.
The corresponding cost-effectiveness of each control technique is not explicitly
treated. At this time, such an analysis would not be meaningful due to the wide
range of effectiveness of a given control technique even on identical equipment
types.
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SECTION 2
CHARACTERIZATION OF N0y EMISSIONS AND FUEL USAGE FOR
STATIONARY SOURCES
This section presents a- summary of the most recent stationary source uncon-
trolled NOV emission estimates and associated emission factors for 137 major equip-
/\
ment/fuel combinations in the U.S. Equipment categories are separated by application
sector (e.g., industrial boilers, space heaters) and by fuels. In addition, N0x
emission trends for the years 1940 - 1972 and projections to the year 1990 are dis-
cussed.
Emission estimates by application sectors are presented in Section 2.1,
il summaries follow
presented in Section 2.3.
national summaries follow in Section 2.2. NOV emission trends and projections are
A
2.1 1972 NOM EMISSION ESTIMATES, EMISSION FACTORS, AND FUEL USAGE BY
APPLICATION SECTOR
A comprehensive survey of 1972 NOX emission estimates from stationary sources
has recently been completed by Aerotherm (Reference 2-1) which updates and expands
upon the previous inventories of ESSO (Reference 2-2), EPA (Reference 2-3), and
The National Academy of Sciences (Reference 2-4). The present inventory includes
137 individual equipment type/fuel combinations from eight separate application
sectors.
An overview of stationary sources of NO emissions is provided in Figure 2-1.
The first division is by application and the second by sector. To illustrate
the scope of stationary sources, the sector column has been more thoroughly detailed.
These six applications encompass all major sources and the cited sectors include
all those of importance within each sector. Steam generation is by far the largest
application on a capacity basis for both utility and industrial equipment while
space heating is the largest application by number of installations. Internal com-
bustion engines (both reciprocating and gas turbines) in the petroleum and re-
lated products industries have generally been limited to pipeline pumping and gas
compressor applications. Process heating data are not readily available, but the
main source appears to be fluid catalytic crackers in the petroleum refineries and
the drying and curing ovens in the broad-ranging ceramics industry. Incineration by
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APPLICATION
SECTOR
EQUIPMENT TYPES
— PRIME HOVER
STATIONARY
SOURCES OF*
STEAM
GENERATION
SPACE
HEATIKG
PROCESS
HEATING
'—•BOM-COnBUST ION
EUC POMER
GENERATION
FIELD ERECTED
HATERTUBE BOILERS
WTERTUBE BOILERS I"" "EtD WKTW
INDUSTRIAL _J "-PACKAGED
PROCESS STEAM I
•— i
F1RETUBE BOILERS
_, RECIPROCATING
CUC POWER GEN. |~" |C ENGINES
OIL AND GAS I
• PIPE LINE PUHPING—j
NAT GAS PROCESSING I
1— GAS TURBINES
RESIDENTIAL
COnCRCIAL
FURNACES
BOILERS
HATERTUBE
FIRETUBE
CAST IRON.
r—
INCINERATION I
INDUSTRIAL
_ PETROLEUM
REFINING
— METALLURGICAL •
• FLUID CATALYTIC CRACKERS
|— HEATING AND ANNEALING OVENS
• COKE OVEN UNOERFIRE
. OPEN HEARTH FURNACE
SINTERING OVEN
i— KILNS
FURNACES
»
r— NITRIC ACID
SULFURIC ACID
— EXPLOSIVES
Figure 2-1. Stationary sources of NO Emissions
A
CERAMICS
INDUSTRY
GLASS
' MICKS
CEMENT
CHEMICAL
IMHUFACTURERS
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both the municipal and industrial sectors is a small but noticeable source, primarily
in urban areas. Noncombustion sources remain largely within the area of chemical
manufacture, more specifically nitric and sulfuric acids and explosives.
The equipment types of greatest importance are shown next. While these
equipment categories do not include all the possible variations or hybrid units, the
bulk of the equipment is included in the breakdown.
Emission and fuel consumption* estimates for each application as shown in
Figure 2-1 are presented in the following order:
Table
t Utility Boilers 2-1
• Industrial Boilers 2-2
• Commercial Steam Space Heating 2-3
• Residential Space Heating 2-4
• Internal Combustion Engines 2-5
t Process Heating 2-6
• Incineration 2-7
• Noncombustion 2-8
Steam generation is separated into its two major components, electric power
utility boilers and industrial process steam boilers, by virtue of the distinct
differences in the two equipment types and the previous division in technology
efforts. The space heating application has been divided into commercial steam units
and residential heating units for obvious reasons of equipment differences.
Although NOX control strategies are developed around a multitude of variables,
the total annual NOX emissions of each equipment type play an important role. A nu-
merical ranking by annual NO production for all of the above equipment types is pre-
J\
sented in the appendix.
Nominal heating values were assumed
Coal - 12,000 Btu/lb coal
Oil - 140,000 Btu/gal oil
Gas - 1,000 Btu/scf gas
Conversion of emission factors to fuel units given Ib NOV/106 Btu to obtain:
Ib N09/ton coal multiply by 24
Ib NO^/103 gal oil multiply by 140
Ib NOg/lO6 scf gas multiply by 1,000
All NO emissions are calculated on an N02 basis, i.e., a molecular weight of 46.
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Table 2-T. SUMMARY OF EMISSIONS, EMISSION FACTORS, AND FUEL USAGE BY EQUIPMENT CATEGORIES
FOR STEAM GENERATION - UTILITY BOILERS
Equipment Type
Field Erected Watertube Boilers
Field Erected Watertube Boiler
Stoker
Firing Type
Tangential Firing
Horizontally Opposed
Wall Firing
Front Wall Firing
Vertical Firing
Cyclone
Spreader
Underfeed
Fuel
Coal
Oil
Gas
Coal, Dry Bottom
Coal, Wet Bottom
Oil
Gas
Coal, Dry Bottom
Coal, Wet Bottom
Oil
Gas
Coal, Dry Bottom
Coal, Wet Bottom
Oil
Coal
Coal
Fuel Typea
Bituminous
Lignite
Distillate
Residual
-
Bituminous
Lignite
Bituminous
Lignite
Distillate
Residual
-
Bituminous
Lignite
Bituminous
Lignite
Distillate
Residual
-
Anthracite
Bituminous
Lignite
Bituminous
Lignite
Distillate
Residual
-
-
NOX106TPY
1.388
0.014
0.007
0.177
0.153
0.412
0.004
0.306
0.009
0.011
0.271
0.568
0.412
0.004
0.302
0.008
0.011
0.271
0.393
0.010
0.127
0.001
0.730
0.009
0.001
0.019
0.037
0.016
LBNOx/106Btuc
Emission Factor
0.75
0.75
0.357
0.357
0.3
0.75
0.75
1.25
1.25
0.75
0.75
0.70
0.75
0.75
1.25
1.25
0.75
0.75
0.70
0.75
0.75
0.75
1.60
1.60
0.75
0.75
0.625
0.625
Fuel Usage
10U dtu/Yr
3702
37.3
41.3
992.1
1021
1099
10.7
490
14.4
30.2
723.5
1622
1099
10.7
483
12.8
30.2
723.5
1123
26.7
338.7
2.67
912.5
11.3
2.67
50.7
118.0
50.6
Numerical
Ranking
2
78
99
15
19
5
108
10
76
81
11
4
6
110
10
96
82
12
7
85
22
128
3
89
129
64
47
73
3NO2 basis
''Uncontrolled basis
cLignite includes sub-bituminous - Residual includes crude oil
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Table 2-2. SUMMARY OF EMISSIONS,
FOR STEAM GENERATION
EMISSION FACTORS, AND FUEL USAGE BY EQUIPMENT CATEGORIES
- INDUSTRIAL BOILERS
Equipment Type
Field Erected Watertube Boilers
>100MMBtu/hr
Field Erected Watertube Boilers
10-100 MM Btu/hr
Field Erected Watertube Boilers
Stokers
Packaged Watertube Bent Tube
Straight Tube (Obsolete)
Firing Type
Tangential Firing
Horizontally Opposed
Wall Firing
Front Wall Firing
Vertical Firing
Cyclone
Wall Firing
Spreader
Underfeed
Overfeed
General, Not Classified
Wall Firing
Fuel
Coal
Oil
Gas
Coal, Dry Bottom
Coal, Wet Bottom
Oil
Gas
Coal, Dry Bottom
Coal, Wet Bottom
Oil
Gas
Coal, Dry Bottom
Coal, Wet Bottom
Oil
Oil
Gas
Coal
Coal
Coal
Coal
Coal
Oil
Gas
Fuel Type*
-
Residual
Natural
Process
-
-
Residual
Natural
Process
-
-
Residual
Natural
Process
-
-
Residual
Distillate
Residual
Natural
Process
-
-
-
-
-
Distillate
Residual
Natural
Process
NOX 106 TPY
0.030
0.106
0.032
0.004
0.009
0.003
0.165
0.087
0.009
0.009
0.003
0.165
0.059
0.007
0.002
0.028
0.014
0.007
0.086
0.045
0.002
0.136
0.077
0.037
0.018
0.009
0.0156
0.2064
0.139
0.007
LBNOx/106Btu
Emission Factor
0.75
0.357
0.249
0.23
0.75
1.25
0.573
0.249
0.23
0.75
1.25
0.573
0.249
0.23
0.75
1.6
0.573
0.172
0.423
0.17
0.17
0.417
0.417
0.625
0.417
0.75
0.153
0.377
0.167
0.167
Fuel Usage
10'2 Btu
80.0
593.8
257.0
34.8
24.0
4.8
575.9
303.7
78.3
24.0
4.8
575.9
205.9
60.7
5.3
35.0
48.9
81.4
406.6
529.4
23.5
435.2
246.4
118.4
57.6
24.0
203.9
1095.0
1664.7
83.8
Numerical
Ranking
52
28
51
108
90
112
18
31
92
91
112
17
36
102
119
55
79
100
32
41
122
21
33
48
67
93
27
13
20
101
'Process gas includes coke oven gas and blast furnace gas.
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Table 2-2. SUMMARY OF EMISSIONS,
FOR STEAM GENERATION
EMISSION FACTORS, AND FUEL USAGE BY EQUIPMENT CATEGORIES
- INDUSTRIAL BOILERS (Continued)
Equipment Type
Packaged Watertube Stoker
Packaged Firetube Scotch
Packaged Firetube Firebox
Packaged Firetube
Firebox Stoker
Packaged Firetube HRT
Packaged Firetube HRT
Stoker
Firing Type
Spreader
Underfeed
Overfeed
General, Not Classified
Wall Firing
Wall Firing
Spreader
Underfeed
Overfeed
Wall Firing
Spreader
Underfeed
Overfeed
Fuel
Coal
Coal
Coal
Coal
Oil
Gas
Oil
Gas
Coal
Coal
Coal
Oil
Gas
Coal
Coal
Coal
Fuel Type
—
-
—
-
Distillate
Residual
Natural
Process
Distillate
Residual
Natural
Process
—
-
-
. Distillate
Residual
'—
-
—
-
NOX106TPY
0.043
0.067
0.016
0.007
0.0156
0.1924
0.044
0.001
0.006
0.076
0.038
0.001
0.002
0.010
0.002
0.003
0.040
0.020
0.001
0.005
0.001
LBNOx/106Btu
Emission Factor
0.417
0.417
0.625
0.417
0.153
0.377
0.167
0.167
0.153
0.377
0.167
0.167
0.417
0.417
0.625
0.153
0.377
0.167
0.417
0.417
0.625
Fuel Usage
10" Btu
206.0
321.3
51.2
33.6
203.9
1021.0
526.9
12.0
78.4
403.2
455.1
12.0
9.6
48.0
6.4
39.2
212.2
239.5
4.8
24.0
3.2
Numerical
Ranking
43
35
75
98
76
14
42
133
104
34
46
132
120
86
119
113
45
63
130
107
131
-------
Table 2-3. SUMMARY OF EMISSIONS, EMISSION FACTORS, AND FUEL USAGE BY EQUIPMENT CATEGORY FOR COMMERCIAL BOILERS
Equipment Type
Packaged Firetube Scotch
Packaged Firetube Firebox
Packaged Firetube Firebox, Stoker
Packaged Firetube HRT
Packaged Firetube HRT, Stoker
Packaged Firetube, General,
Not Classified
Packaged Cast Iron Boilers
Packaged Watertube Coil
Packaged Watertube Firebox
Packaged Watertube General,
Not Classified
Firing Type
Wall Firing
Wall Firing
All Categories
Wall Firing
All Categories
Wall Firing
Stoker and Handfire
Wall Firing
Wall Firing
Wall Firing
Wall Firing
Fuel
Oil
Gas
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Fuel Type
Distillate
Residual
—
Distillate
Residual
...
-
Distillate
Residual
-
Distillate
Residual
-
-
Distillate
Residual
-
Distillate
Residual
-
Distillate
Residual
-
Distillate
Residual
-
NOX106TPY
0.0184
0.0452
0.036
0.0184
0.0452
0.036
0.018
0.0092
0.0226
0.018
0.009
0.0031
0.007
0.006
0.002
0.0092
0.0226
0.018
0.001
0.003
0.0024
0.0006
0.002
0.001
0.001
0.003
0.0024
LB NOX/106 Btu
Emission Factor
0.172
0.423
0.100
0.172
0.423
0.100
0.250
0.172
0.423
0.100
0.250
0.172
0.423
0.100
0.250
0.172
0.423
0.080
0.172
0.423
0.100
0.172
0.423
0.100
0.172
0.423
0.100
Fuel Usage
1012 Btu
214.0
214.0
720.0
214.0
214.0
720.0
144.0
107.0
107.0
360.0
72.0
36.0
33.1
120.0
16.0
107.0
107.0
450.0
11.6
14.2
48.0
6.98
20.0
11.6
14.2
48.0
Numerical
Ranking
65
39
49
66
40
50
71
87
62
68
94
111
98
103
121
88
61
20
125
114
116
134
123
127
126
115
117
-------
Table 2-4. SUMMARY OF EMISSIONS, EMISSION FACTORS, AND FUEL USAGE BY EQUIPMENT CATEGORY
FOR SPACE HEATING, RESIDENTIAL HEATERS
Equipment Type
Steam or Hot Water Heaters
Hot Air Furnaces
Floor, Wall, or Pipeless Heaters
Room Heater With Flue
Room Heater Without Flue
Firing Type
Fuel
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Fuel Type
Distillate
-
Distillate
-
Distillate
-
Distillate
--
Distillate
NOX 106 TPY
0.097
0.040
0.107
0.106
0.016
0.027
0.024
0.028
0.010
LB NOX/106 Btu
Emission Factor
0.114
0.082
0.114
0.082
0.114
0.082
0.114
0.082
0.082
Fuel Usage
10" Btu
1698.0
975.6
1873.0
2858.0
280.0
658.5
420.0
682.9
268.3
Numerical
Ranking
30
44
26
27
74
56
59
53
83
-------
Table 2-5. SUMMARY OF EMISSIONS, EMISSION FACTORS, AND FUEL USAGE BY EQUIPMENT CATEGORY
FOR INTERNAL COMBUSTION ENGINES
Equipment Type
Reciprocating Engines
Gas Turbines
Firing Type
Spark Ignition
Diesel
Fuel
Gas
Oil and Dual
Gas
Oil
Fuel Type
-
-
-
-
NOX 10* TRY
1.873
0.316
0.172
0.119
LBNOX/106 Btu
Emission Factor
3.66
2.69
0.57
0.84
Fuel Usage
10" Btu
1023.0
234.9
604.2
284.0
Numerical
Ranking
1
8
16
23
-------
Table 2-6. SUMMARY OF EMISSIONS FOR INDUSTRIAL PROCESS HEATING EQUIPMENT
Industry
Glass Manufacture
Petroleum Industry
Cement Industry
Steel and Iron Industries
Brick Manufacture
Application
Melting Furnaces
Fluid Catalytic Crackers
Drying Kilns
Coke Oven Underfire
Heating Annealing Ovens
Open Hearth Ovens
Sintering
Curing Ovens
Fuel
Oil
Gas
Oil
Gas
Oil
Gas
Coal
Gas
Oil
Gas
Oil
Gas
NOX 106 TRY
0.055
0.055
0.049
0.05
0.0165
0.047
0.055
0.0059
0.002
0.0036
0.025
0.024
0.0003
0.0003
Numerical Ranking
25
25
29
29
37
38
72
106
106
106
52
58
135
137
Table 2-7. SUMMARY OF EMISSIONS FOR INCINERATION
Industry
Incineration
Application
Industrial
Municipal
Fuel
NOX 106 TRY
0.023
0.019
Numercial Ranking
66
69
Table 2-8. SUMMARY OF EMISSIONS FOR NON-COMBUSTION SOURCES
Industry
Acid Manufacture
Explosive Manufacture
Application
Nitric
Sulfuric
Fuel
NOX 106 TRY
0.11
0.011
0.028
Numerical Ranking
24
80
54
-------
2.2 SUMMARY OF 1972 STATIONARY SOURCE NOX EMISSIONS
A summary of the 1972 NOV emissions by sector and fuel are presented 1n Tables
3\
2-9 and 2-10, respectively. The total of 11.665 million tons per year of NOX from
stationary sources 1s dominated by coal burning utility boilers (32.5 percent) and
gas fired reciprocating 1C engines (16.06 percent). Figure 2-2 graphically illus-
trates the relative magnitudes of each of the sectors. Examination of this chart
indicates that steam raising boilers (utility, Industrial and commercial) contribute
greater than 70 percent of the total uncontrolled stationary source NOX production.
Re-examination of the two primary sources of stationary NOX production - coal
fired utility boilers (32.5 percent) and gas fired reciprocating 1C engine (16.06
percent) - indicates that in terms of energy consumption, coal fired utility boilers
consume 19.7 percent but gas fired 1C engines consume only 2.4 percent of the
total energy used. While coal fired utility boilers are the greatest fuel user,
reciprocating 1C engines rank approximately 16th in fuel consumption. This
discrepancy is explained by the respective emission factors of each equipment type.
Utility boilers have an emission factor approximately one-fifth that of 1C engines.
This point illustrates the need for accurate and up-to-date emission factors.
Previous inventories are compared to present data in Tables 2-11 and 2-12.
Note that considerable differences exist in the manner in which sectors are
distinguished, particularly in the 1C engine category.
2.3 NOX EMISSION TRENDS AND PROJECTIONS
Nationwide NO emission trends from 1940 to 1972 as compiled by the EPA
A
(Reference 2-3) are illustrated in Figure 2-3. In general, stationary sources are
believed to comprise slightly more than 50 percent of the total NOV production,
A,
and this is shown to be a consistent assumption in the figure. Figure 2-4 compares
the EPA figures with the ESSO (Reference 2-2) estimates published in 1968. The
slight downward trend in 1971 of the EPA data is due to revised emission factors
and implementation of NOX controls on the West Coast. As can be seen from the
figure, 1972 emissions have already attained the 1978 ESSO estimates.
Projections for nationwide NO emissions have been made by the National
A
Academy of Sciences (Reference 2-4) based on several assumptions, including considera-
tion for various control options. These projections are presented in Table 2-13
assuming completion of the present stationary program. These estimates are considered
conservative since growth rates are historically greater than projected. Assumptions
made for these projections are:
• Most new electric power generation will be produced with nuclear reactors
• The stationary automotive regulations will remain in effect and be
achieved
13
-------
Table 2-9. SUMMARY OF TOTAL NOX EMISSIONS FROM FUEL USER SOURCES (1972) (Ref. 1 )
NOX Production 106 ton/yr (percent of total)
Sector
Gas
Coal
Oil
Totals By Sector
10* ton/yr Cumulativ
(percent of total) Percenta
1. Utility Boilers
2. 1C Engines
Reciprocating
Gas Turbines
3. Industrial Boilers
5. Process Heating
6. Non-Combustion
7. Incineration
Totals by Fuel
NO2 basis uncontrolled
1.114(9.55)
1.873 (16.06)
0.172(1.47)
0.495 (4.24)
4. Commercial/Residential
Heating 0.3308 (2.84)
3.788 (32.47) 0.768 (6.58)
0.515(4.41)
0.029 (0.25)
0.467 (4.00)
0.1855 (1.59) 0.0553 (0.47) 0.149 (1.28)
4.1703 (35.75) 4.3873 (37.61) 2.9174 (25.01)
5.670(48.61)
0.8268 (7.09)
0.3902 (3.35)
0.149(1.28)
0.041 (0.35)
11.665(100)
48.61
0.316(2.71)
0.119(1.02)
1 .098 (9.41 )
2.189 (18.77)
0.291 (2.49)
2.108(18.07)
67.38
69.87
87.94
95.03
98.38
99.66
100
Table 2-10. SUMMARY OF FUEL USAGE* 1972 (Ref. 1)
•v
Fuel Usage - 10" Btu/yr (percent of total)
1.
2.
3.
4.
5.
Utility Boilers
1C Engines
Reciprocating
Turbines
Industrial Boilers
Commercial Boilers
Residential Heating
Gas
3766(8.81)
1023 (2.4)
604 (1 .4)
4487 (10.5)
2486 (5.8)
5443 (12.7)
17,809(41.7)
Coal
8420(19.7)
—
—
1768(4.1)
232 (0.5)
—
10,420 (24.4)
Oil
2594(6.1)
235 (0.5)
284 (0.7)
5539(13.0)
1421 (3.3)
4446(10.4)
14,519 (34.0)
Total
14,780 (34.6)
1,258(2.94)
888(2.1)
11,794(27.6)
4,139 (9.7)
9,889(23.1)
42,748(100)
"'Excludes process fuel
14
-------
r— Incineration 0.4S
Noncombustion 1.3t
Gas Turbine 2.5%
Industrial Process
Heating 3.31
Commercial/
Residential
Space
Heatin
7.1
Industrial
Boilers
18.11
Utility Boilers
48.6%
Reciprocating
1C Engines
18.8X
Estimated NOX Emissions
Tons/Year
5.670.000
2,189.000
2,108.000
826.800
390.200
291.000
149.000
41.000
11.665,000
Source
Utility Boilers
Reciprocating 1C Engines
Industrial Boilers
Commercial/Residential Heating
Industrial Process Heating
Gas Turbines
Noncombustion
Incineration
TOTAL
Figure 2-2. Summary of 1972 stationary source NOX emissions,
15
-------
Table 2-11. COMPARISONS OF NOX EMISSIONS
10« TPY
Aerotherm
(1972)
Utility Boilers 5.67
1C Engines (2.48)
Reciprocating 2.19
Gas Turbines 0.29
Industrial Boilers 2.11
Commercial 0.36
Residential 0.47
Process Heating 0.39
Non-Combustion 0.149
Incineration 0.04
Other e
Total 1 1 .67
Included in industrial size boilers
Pipeline and gas plants only
clncluded in non-combustion
ESSO
(1970)
3.84
2.1 Ob
a
2.81
1.00
1.00
a
0.24
a
c
9.99
AP-115
(1970)
4.71
d
d
4.53
0.23
0.57
0.20
—
0.08
e
10.32
OAQPS
(1971)
5.38
d
d
3.90
0.586
0.586
a
0.20
0.04
10.11
AS/NEDS
(1973)
5.77
1.41
^ I Deluded in utility and industrial depending on use
eNot included in data
Table 2-1 2. FUEL
Utility Boilers
1C Engines
Reciprocating
Gas Turbine
Industrial Boilers
Commercial
Residential
CONSUMPTION COMPARISONS
MSST
(1972)
14.78
1.26
0.89
11.79
4.14
9.89 ,
101S Btu
OAQPS
(1971)
14.04
)
16.86 \
)
X
: ,2.2 j
AP-115
(1969)
12.14
16.11
11.57
Total
42.75
43.1
39.82
16
-------
• TouA EmMom
• Suttonwy Put) Combuitlon
RoadV*teiM
O Electricity Ctntritlon
A induftrM Ftnl Comtwitlon
O InduitrW PraeMi Uw»
1940
1960
1960
1968)1970 1972
1989
YEAR
Figure 2-3. Nationwide NO emission trends 1940 - 1972 (Reference 2-4)
17
-------
aooo
Figure 2-4. Stationary source NOY emission trends.
A
18
-------
TABLE 2-13. NATIONWIDE NOX EMISSIONS PROJECTED TO 1990 ASSUMING
THE PRESENT STATUTORY PROGRAM
Source Category
Stationary Fuel Combustion
Electric Generation
Industrial
Commercial -Institutional
Residential
Industrial Process Losses
Solid Waste Disposal
Transportation3
Road Vehicles
Gasoline
Diesel
Other
Miscellaneous
TOTAL
NOX
1972
12.27
5.94
5.39
0.65
0.29
2.88
0.18
8.45
7.48
6.59
0.89
0.97
0.59
24.37
Emissions
1980
15.96
8.16
6.73
0.76
0.31
3.91
0.22
8.47
7.14
5.97
1.17
1.33
0.74
29.30
(106 tons/year)
1985
16.82
8.20
7.46
0.84
0.32
4.72
0.25
7.49
5.89
4.30
1.59
1.60
0.87
30.15
1990
18.46
8.88
8.31
0.93
0.34
5.71
0.28
7.60
5.68
3.95
1.73
1.92
1.02
33.07
aAssumes a 4% annual VMT growth rate
Includes New York City Point sources assumed to
year
grow at 4% per
19
-------
• The 1940 - 1972 growth rate of NO emissions from industrial, commercial,
A
and institutional sources will be reduced over the next twenty years.
These estimates assume the completion of Project Independence, which depends strongly
on N0¥ free-nuclear power. Utility NOV generation would almost double if energy
A A
requirements were to be met only with coal, as shown in Table 2-14. The uncertainty
of projections of this nature is compounded by several trends beginning to emerge
due to recent energy shortages and fuel unavailability:
• There will be a significant increase in the utilization of coal and oil
in power generation, leading to an intensified NO problem.
A
• Industrial area sources may be switching to oil or coal if the energy
shortage continues, resulting in larger potential NO production.
A
t Greater emphasis on alternate fuels, the results of which are impossible
to quantify at this time.
• Home heating systems will become more efficient if the cost of fuel
continues to rise and this could result in increased NO emissions.
A
Other significant factors affecting future NOX emission include the following:
• Major technological developments in equipment design, fuels and
fuel treatment, combustion control and exhaust gas cleanup.
a Uncertainty concerning the future of nuclear energy as a major source
of electrical power.
• The degree to which NOV emissions will be regulated by both local and
A
federal restrictions.
20
-------
TABLE 2-14. NATIONWIDE EMISSIONS OF NOX FROM ELECTRIC POWER GENERATION
PROJECTED TO 1990 FOR TWO POLICY OPTIONS
ro
Year
1972
1980
1985
1990
Total
5.
8.
8.
8.
94
24
20
88
Project
a Coal
3.95
7.21
7.21
7.89
NOX
Emissions (106 tons/year)
Independence
Oil
0.85
0.52
0.52
0.52
Natural Gas
1.
0.
0.
0.
14
48
44
44
No New Nuclear Plants
After 1975
Total*
5.94
9.32
12.81
17.56
Coal
3.95
8.29
11.82
16.57
Built
Oil Natural Gas
0.
0.
0.
0.
85
52
52
52
1.14
0.48
0.44
0.44
aTotal contains 0.03 x 106 tons/year from gas turbines
Reference 2-4
-------
REFERENCES
2-1 Mason, H. B. and A. B. Shimizu, "Definition of the Maximum Stationary Source
Technology (MSST) Systems Program for NOX," (Draft Report) Aerotherm Final
Report 74-123, Acurex Corporation, Aerotherm Division, October 1974.
2-2 Bartok, W. et al., "Systems Study of Nitrogen Oxide Control Methods for
Stationary Sources -Vol. II, Prepared for National Air Pollution Control
Administration, NTIS Report No. PB-192-789, Esso Research and Engineering, 1969.
2-3 Cavender, 0. H. and D. S. Kircher and A. I. Hoffman, "Nationwide Air Pollutant
Emission Trends 1940 - 1972, "Pub. No. AP-115, Environmental Protection
Agency, Research Triangle Park, North Carolina, January 1973.
2-4 National Academy of Sciences, "Air Quality and Stationary Source Emission
Control," Prepared for the Committee on Public Works, United States Senate,
Serial No. 94-4, March 1975.
2-5 "OAQPS Data File of Nationwide Emissions - 1971," Office of Air Quality Plan-
ning and Standards, Environmental Protection Agency, May 1973.
2-6 Letter from Owen W. Dykema, Aerospace Corporation to Robert E. Hall, EPA of
11 March 1974, Reference 74-331O-OVID-5, Aerospace Corporation, Los Angeles,
California.
22
-------
SECTION 3
SUMMARY OF STATIONARY SOURCE NOV CONTROL TECHNIQUES
A
Combustion generated NOX results either from thermal fixation of atmospheric
nitrogen in the combustion air or, in the case of nitrogen-containing fuels such as
residual oil and coal, from conversion of chemically bound nitrogen in the fuel. In
both cases, NOX emissions for a given equipment type are dependent on the fuel and
on the combustion conditions in the primary flame zone. NOX control can accordingly
be approached through the following options.
• Modification of combustion conditions to suppress NO formation
A
• Modification or substitution of fuel
t Treatment of flue gas for NO removal
A
• Substitution of an alternate low NO combustion process
J\
Table 3-1 gives an overview of the status, limitations and applications of these
options.
In the near term, combustion modification is the most effective control option
for retrofit of existing equipment and improved low NO design of new equipment. In
A
the far term, substitution of alternate processes and use of clean fuels is likely to
contribute to the strategy for maintenance of air quality for NOY. Combustion modi-
A
fication used either with these advanced processes or with conventional fuels and
equipment is likely to remain the predominant strategy for NOX control. Supplemental
control by flue gas treatment may be effective in the far term to achieve control
levels beyond the limits of combustion modification.
3.1 COMBUSTION MODIFICATION
Thermal NO formation in continuous combustion devices is kinetically control-
A
led and exhibits a strong dependence on flame temperature, and to a lesser degree, on
local oxygen level. Suppression of thermal NO results from the following:
A
t Decreased flame temperature through dilution, modified stoichiometry, or
increased heat transfer
• Decreased oxygen level at peak temperature through dilution or modified
stoichiometry
23
-------
TABLE 3-1. EVALUATION OF NOX CONTROL TECHNIQUES
Technique
Combustion
Modification
Flue Gas
Treatment
Fuel
Switching
Fuel
Additives
Fuel
Denltrlflcatlon
Catalytic
Combustion '
Flu1d1zed Bed
Combustion
Principle of Operation
Suppress thermal NOX through re-
duced flame temperature, reduced
0» level; suppress fuel NOX
through delaying fue1/a1r mix-
Ing or reduced $2 1evo1 1" pri-
mary flame zone
Reduction of NO to Ng by cata-
lytic treatment; scrubbing or
absorption of NO or NOg
Simultaneous S0« and NO. con-
trol by conversion to clean
fuels; synthetic gas or oil
from coal; SRC; methanol;
hydrogen
Reduce or suppress NO by
catalytic action of fuel
additives
Removal of fuel nitrogen .com-
pounds by pretreatment
Heterogeneously catalyzed
reactions yields low combus-
tion temperature, low ther-
mal NOX
Coal combustion 1n solid bed
yields low temperature, low
NOX
Status of Development
Operational for point
sources; pilot-scale and
full scale studied on com-
bined modifications, opera-
tional problems and ad-
vanced design concepts for
area sources
Operational for concen-
trated effluents from ni-
tric add plants; pilot
scale feasibility studies
for conventional combus-
tion systems
Synthetic fuel plants In
pilot-scale stage; com-
mercial plants due by
mid 1980's
Inactive; preliminary
screening studies Indi-
cated poor effective-
ness
Oil desulfuHzatlon
yields partial denl-
tr1f1cat1on
Pilot-scale test beds for
catalyst screening,
feasibility studies
Pilot-scale study of at-
mospheric, pressurized
beds; focus on sulfur
retention devices
Limitations
Degree of control
limited by opera-
tional problems
High make-up ratio
of reducing agent or
absorbent; Interfer-
ence by fuel sulfur
or metallic compounds
Fuel cost differential
may exceed NOX, SOX,
control costs with
coal
Large make-up rate of
additive for signifi-
cant effect; presence
of additive as pollu-
tant
Effectiveness for coal
doubtful; no effect on
thermal NOX
Limited retrofit appli-
cations; requires clean
fuels
Fuel nitrogen conversion
may require control
(staging) may require
large make-up of lime-
stone sulfur absorbent
Applications
Near Term
Retrofit utility,
Industrial boilers,
gas turbines; Im-
proved designs
Non-combustion
sources (nitric
add plants)
Negligible use
Negligible use
Negligible use
Small space
heaters
Negligible use
Long Term
Optimized design area,
point sources
Possible supplement to
combustion modifications;
simultaneous SOX/NOX
removal
New point sources,
(combined cycle)
Convert area sources
(residential)
Not promising
Supplement to combustion
modification
Possible use for resi-
dential heating, small
boilers
Utility, Industrial boil-
ers beginning mid 70's;
possible combined cycle,
waste fuel application
-------
• Reduced residence time at peak temperature through controlled mixing
The detailed mechanisms for fuel nitrogen conversion are not fully understood but
empirical tests Indicate that delayed mixing of oxygen with the nitrogen bearing fuel
effectively suppresses 50 to 90 percent of fuel nitrogen conversion.
The technique developed to control NO by the above general principles are
A
strongly dependent on equipment characteristics such as combustion chamber configura-
tion, flame heat transfer, and fuel/air aerodynamics. The following subsections sum-
marize the status and prospects of combustion modifications for the major stationary
source combustion equipment types.
3.1.1 Utility Boilers
Utility boilers, due to their importance as NO sources and their control
J\
flexibility, are the most extensively modified stationary equipment type. The selec-
tion and Implementation of effective NOV controls for given utility boilers 1s unique-
A
ly dependent on the furnace characteristics, fuel/air handling systems and control
systems, and to the occurance of operational problems which may result from combustion
modifications. The following discussion is therefore not intended to provide appli-
cation guidelines, but rather to give a broad overview and evaluation of tested pro-
cedures .
Table 3-2 summarizes the status of combustion modification technology for NO
J\
control in utility boilers. The references cited in the table are the basis for the
remainder of the discussion in this section. The table also lists typical values of
controlled emissions for the major modification techniques and the two major firing
types, tangential firing and wall firing. For reference, the range of uncontrolled
emissions (ppm at 3 percent 02) for these firing types are as follows (Reference 3-11):
Tangential
Wall firing
Gas
100 - 350
130 - 950
Oil
100 - 350
200 - 550
Coal
300 - 600
400 - 900
Low excess air (LEA) firing is the most widely used technique for control of
both thermal and fuel NOV. LEA is also effective for increasing unit thermal effic-
/\
iency. Its use is limited by the increase in smoke or CO emissions which occur at
low levels of excess air. Also, for certain primarily eastern coals, the localized
reducing conditions in the lower furnace which result from LEA firing can produce
accelerated fireside corrosion and slagging. Low excess air firing 1s typically the
first technique Implemented as part of a control program and is normally Included when
other techniques are used. The minimum excess air level achievable when other con-
trols, such as staging, are used 1s typically higher than when LEA 1s applied singly.
25
-------
TABLE 3-2. SUMMARY OF COMBUSTION MODIFICATION TECHNIQUES FOR LARGE BOILERS1
Technique
Staged combus-
tion with tan-
gential firing
Staged combus-
tion with wall
firing
Flue gas re-
circulation
Low excess air
firing
Principle of Operation
Lower nozzles operated
fuel rich yielding re-
duced 02 level 1n pri-
mary zone and suppres-
sion of thermal and
and fuel NOX
Biased burner firing
or oversize air ports
reduces 02 level 1n
primary flame zone
and suppresses ther-
mal and fuel NOX
Recycled flue gas re-
duces primary flame
temperature and sup-
presses thermal NOX
NOX control through
reduced 02 level 1n
primary flame zone
Emission Rates (NOx)
N02 basis @ 3% 022
Gas: 100-150 ppm
011: 125-225 ppm
Coal: 200-300 ppm
Gas: 200-300 ppm
Oil: 250-350 ppm
Coal : 350-450 ppm
Gas: 80-120 ppm
(tangential)
250-350 ppm
(wall firing)
011: 150-220 ppm
(tangential )
250-350 ppm
(wall firing)
Gas: 200-250 ppm
(tangential)
300-350
(wall firing)
Oil: 200-250
(tangential)
300-350
(wall firing)
Coal : 350-450
(tangential )
450-600
(wall firing)
Limitations
Fouling of convec-
tlve section; poor
primary stage Ig-
nition; soot for-
mation; possible
load reduction
Corrosion with
coal firing, foul-
1ng of convectlve
section, boiler
Reduced effect
with coal, heavy
oils; flame In-
stability
Unburned hydro-
carbons, CO em-
missions, at low
levels of excess
air; Increased
fouling
Existing
Applications
Retrofit of
utility
boilers,
large In-
dustrial
boilers
Retrofit of
utility
boilers,
large In-
dustrial
boilers
Retrofit of
gas and dis-
tillate oil
utility
boilers
Routine use
1n utility
boilers;
limited use
in indus-
trial
boilers
Applications Planned
for Next 5 Years
Inclusion of over-
fire air ports 1n
new unit design
Inclusion of over-
fire air ports 1n
new unit design
Inclusion in design
of large industrial
boilers
Application to com-
mercial and Indus-
trial boilers as
part of energy con-
servation programs
Reference
(3-1M3-7)
(3-4)-(3-8)
(3-4)-(3-8)
(3-l)-(3-8)
'Combined modifications are excluded; the NOX control with combined modifications 1s generally less than the additive effects of the
modifications applied singly.
2 Emission rates cited are nominal values for average unit capacity and operating conditions; the range of available data 1s much
wider than the values reported.
ro
01
-------
TABLE 3-2. (Concluded)
Technique
Low air pre-
heat
Water
Injection
New burner
designs
Principle of Operation
Reduced combustion air
temperature yields low-
er flame temperature
and lower NOX
Reduced flame tempera-
ture, possible emul?
sttth- Affect
Controlled mixing of
fuel/air yields con-
trol of thermal, fuel
NOX
Emission Rates (N0«)
NOz Basis @ 3% 02?
—
Gas: 150-200 ppm
011: 200-250 ppm
Coal: 450-550 ppm
Limitations
Reduced plant
thermal effi-
ciency
Reduced thermal
efficiency;
severe opera-
tional problems
with high level
of water Injec-
tion
NOX control
through retro-
fit constrained
by firebox con-
figuration
Existing
Applications
—
Applications Planned
for Next 5 Years
—
Inclusion in new unit
design for utility
and Industrial
boilers
Reference
(3-1),(3-6)
(3-9), (3-10)
-------
Staging is a very effective technique for control of both thermal and fuel NO .
A
By this approach, biased burner firing or overfire air ports are used to control the
mixing of the fuel with the combustion air. The resulting fuel rich regions in the
primary flame zone are cooled by flame radiation heat transfer prior to completion of
combustion with the remaining combustion air. Thus, although the overall fuel/air
mixture is near-stoichiometric, the primary NO forming region of the flame is oper-
A
ated at a non-stoichiometric, low NO condition. NO control effectiveness with
/\ A
staging depends on burner or primary stage stoichiometry which in turn is limited by
convective section fouling, unburned hydrocarbon emission or poor ignition character-
istics which occur at excessively rich operation. An additional limitation of fire-
side corrosion may arise with the firing of some coals and heavy oils.
Advanced burner design is an alternate method for thermal and fuel NOV reduc-
A
tion through controlled mixing of fuel and air. With modified burner design, the
basic NO control principles underlying staging and flue gas recirculation can be
J\
incorporated internal to the furnace thereby avoiding some of the operational prob-
lems normally associated with external staging or F6R. Advanced burner designs are
particularly attractive for application to new units where the burner can be matched
to the firebox configuration.
Flue gas recirculation (F6R) has been implemented to a limited extent for con-
trol of thermal NO with the firing of natural gas and oil. FGR does not appear to
A
be effective for control of fuel NO emissions. Thermal NO reductions achievable by
A A
FGR are limited by the occurance of flame instability and boiler rumble at high levels
of recirculated flue gas.
Two additional control techniques, water injection and reduced air preheat,
to control thermal NO by reduction of the primary zone fit
A
are not widely used due to adverse impact on thermal efficiency.
serve to control thermal NO by reduction of the primary zone flame temperature, but
A
3.1.2 Industrial Boilers
As discussed in Section 2 and Appendix A, the industrial boiler source category
consists of a diversity of design types over a wide capacity range. The largest field
erected watertube units (>250 M Btu/hr) are similar in design to the smaller utility
boilers. For these, NO control technology is well developed and is essentially the
A
same as discussed above for utility boilers, For firetube boilers and the smaller
watertube boilers, NO control technology is in the formative stages due primarily
A
to the lack of regulatory incentive, For these small units, the NO control flexi-
A
bility in terms of number of burners, fuel/air handling system, and control systems
are much more limited than for utility boilers. With fewer NOX control options avail-
able, retrofit control development and implementation becomes a far more individual
process for each particular unit. With this situation, the NO control cost
A
28
-------
effectiveness for new unit design is expected to far exceed that for retrofit of
existing units.
Field test experience for NO controls in industrial boilers is due largely
A
to a continuing EPA funded study by KVB Engineering, Reference 3-12. The initial,
complete, phase of the study involved emission characterization and testing of minor
fine tuning modification for 75 boiler/burner/fuel combinations. The final, ongoing,
phase of the study is focusing on testing more elaborate modifications on a fewer
number of units. The range of uncontrolled base load emissions from the first phase
of the study were'224-800 ppm, 100-619 ppm, and 50-375 ppm for coal, oil and gas
units respectively. During the first phase, a number of boilers were tested for NOX
reduction response to low excess air firing and off-stoichiometric combustion. LEA
was most effective for coal-fired stokers and oil-fired watertube units. The fire-
tube boilers and gas-fired watertube units generally showed less NO reduction from
/\
LEA firing. For multiburner units, off-stoichiometric combustion was achieved by
adjusting burner stoichiometry or by taking burners out of service. This resulted
in NO emission reduction of up to 40 percent. For stoker units, off-stoichiometric
A
combustion was achieved by modification of existing overfire air ports. This result-
ed in NOV reductions up to 25 percent.
A
3.1.3 Internal Combustion Engines
This section discusses state-of-the-art NOY control techniques for recipro-
A
eating and gas turbine 1C engines. It is emphasized that no nationwide and few local
regulations exist at the present time and as a result, few of the controls discussed
have seen extensive application even though research studies have found them effec-
tive. Reciprocating 1C engines are presented in Section 3.1.3.1 and gas turbines are
treated in Section 3.1.3.2,
3.1.3.1 Reciprocating 1C Engines
Although stationary reciprocating engines account for nearly 20 percent of the
NO from stationary sources, there are presently no regulations for gaseous emissions
from these engines. Emission reduction techniques for stationary engines, however,
have been investigated by many manufacturers, and numerous studies have reported emis-
sion control techniques for automotive diesel and gasoline fueled engines. Emissions
control research by manufacturers of stationary engines indicate several techniques
currently available to the user. In addition, control techniques for automotive appli-
cations could be adapted to stationary applications.
Reference 3-13 provides a good overview of emissions from stationary engines,
particularly large bore engines used in the oil and gas Industry and for electric
power generation. Reference 3-14 summarizes automotive technology available for
stationary engines. Reference 3-15 1s currently being completed and will repre-
sent the most comprehensive study of stationary reciprocating engines to date.
29
-------
The stationary reciprocating engine industry has a multitude of applications
and, therefore, discussions of emission reductions are more meaningful if the engines
are subdivided into four characteristic groups, by size and fuel, that roughly corres-
pond to their applications. Table 3-3 lists these groups and their principal appli-
cations, load factors, utilization, and typical emission levels. As Table 3-3 indi-
cates, these engines display a wide range of emission potential depending on their
design (2 or 4 stroke, naturally aspirated, turbocharged, aftercooled, open or divi-
ded chamber, etc.), fuel burned (natural gas, diesel oil, gasoline) and application.
Basically, NO control techniques must reduce emissions for a broad range of
A
operating conditions ranging from rated load, continuous operation, to variable load,
lower utilization applications. In general, large natural gas spark ignition engines
have the highest NO emission factors and can significantly contribute to NO emissions
A X
when the engine is installed in gas compressor applications and runs continuously at
rated load. Gasoline engines, in contrast, frequently operate at lower loads (less
than 50 percent of rated) and produce substantially higher levels of CO and HC. NO
A
control techniques for these engines often involve HC and CO control since these
emissions frequently increase as NO is reduced. Note that divided chamber diesel-
A
fueled engines produce low levels of NO (accompanied by greater fuel comsumption
A
than open chamber designs) and that all diesel-fueled engines have relatively small
HC and CO emissions (less than 3 gm/hp-hr and 10 gm/hp-hr respectively).
The following paragraphs will discuss NO control techniques in general and
A
then specific NOV reductions, by engine group, will be tabulated. (A lack of emission
A-
data precludes any discussion of natural gas engines less than 100 hp/cylinder).
Section 4.3 will present typical control costs associated with emissions control for
these engine categories.
Table 3-4 summarizes the principle combustion control techniques for recipro-
cating engines. These stategies may require adjustment of the engine operating con-
ditions, addition of hardware, or a combination of both. Retard, air-to-fuel ratio
change, derating, decreased inlet air temperature, or combinations of these controls
appear to be the most viable control techniques in the near term, Nevertheless, there
is some uncertainty regarding maintenance and durability of these techniques because,
in the absence of regulation, very little data exists for controlled engines outside
of laboratory studies, particularly for large non-automotive engines. In general,
fuel consumption increases as large as 10 percent are the most immediate consequence
of the application of these techniques (excluding inlet air cooling). These controls
involve essentially operational adjustments with the exception of derating which would
require additional units to compensate for the decreased horsepower and inlet manifold
air cooling (addition of heat exchanger and pump).
30
-------
TABLE 3-3. CATEGORIZATION OF STATIONARY RECIPROCATING ENGINE'S APPLICATIONS AND EMISSION FACTORS
Engine Category
DEMA, large bore
high power. Natu-
ral gas, dlesel
and dual fueled
Medium bore, natu-
ral gas engines
Small and medium
bore dlesel
fueled
Gasoline engines
Size
>100 hp/cyl
(>500 but <100 hp/cyl
\<500 hp
<100 hp/cyl
or <1000 hp
Small, 20 hp
Medium, 20-200 hp
Large, 100-500 hp
Speed, rpm
( high, >600
<1200 < medium, >300
( low, <300
/ >1200 but <1800
I >1800
/ medium, >1200
I high, >1800
>3000
j >1800
Principal Applications
Gas compression
Electric generation
— base load
— standby
Gas compression
Irrigation pumping
Portable compressors,
welders, pumps
Electric generators
— continuous
— standby
Lawn and garden,
small construction
equipment
Portable compressors,
welders, pumps, elec-
tric generators
(remote)
Load Factor3
0.8
0.8
0.8
0.8
0.8
<0.5
0.8
0.8
0.25
0.5
Utilization, hr/yr
>6000
>6000
<200
>6000
200-2000
500
500-1000
<200
50
500-1000
aPercent of engine rated load
-------
TABLE 3-3. (Concluded)
CO
ro
Engine Capacity
DEMA, large bore
high power. Natu-
ral gas, diesel
and dual fueled
Medium bore, natu-
ral gas engines
Small and medium
bore diesel fueled
Gasoline engines
Gas: 2 & 4 stroke, NA, BS, TC
Diesel: 2 & 4 stroke, NA, BS, TC
Dual Fuel: 2 & 4 stroke, NA, BS, TC
Gas: 2 & 4 stroke, NA, TC, TCID
Open Chamber6
- 2 stroke, BS
- 2 stroke, TC
— 4 stroke, NA
- 4 stroke, TC
Divided Chamber0
- 4 stroke, NA
-4 stroke, TC
Small 2 and 4 stroke, NAd
4 stroke, NAc
- rated load
— 23 mode composite cycle
Emissions (gm/hp-hr)e
NOX
13-22
8-19
8-15
12-20
12-17
8-9
5-17
9-16
2-4
4-5
5.6
9-16
8-14
CO
<10
<8,
<7
<10
<10
<5
<10
<5
-------
TABLE 3-
-------
While exhaust gas recirculation (E6R) exhibits effective reduction of NO ,
/\
this technique will require additional development due to fouling of flow passages
and increased smoke levels (vary EGR rate with load). In general, EGR is cooled in
order to be effective and, hence, fouling arises. This technique has not been field
tested for large engines, and has been rejected by one manufacturer of heavy duty
diesel truck engines and limited by another manufacturer to potential application in
turbocharged engines (no after-cooling) and naturally aspirated engines with full
load EGR cut-off to prevent excessive smoke (> 10 percent opacity).* EGR, however,
has been applied successfully in combination with other techniques (e.g., retard) in
gasoline fueled automobile engines (Reference 3-14).
Water induction, similarly, has serious maintenance and durability problems
associated with mineral deposit buildup and oil degradations. Despite demineraliza-
tion of the water and increased oil changes, the control problems associated with
engine start-up and shutdown and the necessity of a raw water source have led manu-
facturers to reject this technique.
Combustion chamber modifications such as pre-combustion and stratified chambers
have demonstrated large NO reductions, but also incur substantial fuel comsumption
x\
increases (5 to 8 percent more than open chamber designs). With the rapid increases
in the price of diesel fuel and gasoline, manufacturers have been reluctant to imple-
ment this technique. In fact, one manufacturer of divided chamber engines is vigor-
ously pursuing development of low emission open chamber engines.
Table 3-5 gives emission reductions achieved by large bore engines for retard,
air/fuel ratio changes, derating, and cooled inlet manifold air temperature (MAT).
This table includes only those techniques from Table 3-4 which could be readily ap-
plied by the user. These reductions are based on results obtained from engines test-
ed in manufacturers laboratories, therefore, some uncertainty exists concerning dura-
bility and maintenance over longer periods of operation. In general, the greatest
NOY reductions are accompanied by the largest fuel consumption increases, which is a
J\
direct result of reducing peak combustion temperatures and, thus, decreasing thermal
efficiency.
Numerous investigations have studied control techniques to reduce NO in diesel-
A
fueled automotive truck applications, and many of these studies are summarized in Ref-
erence 3-14. Retard, turbocharging, aftercooling, derating and combinations of these
controls are techniques that are currently utilized by manufacturers to meet California
heavy duty vehicle (> 6000 Ib) emission limits for diesel-fueled engines.
Based on information supplied by manufacturers to Reference 3-15,
^Based on published reports and information supplied by manufacturers to Reference 3-15.
34
-------
TABLE 3-5. NORMALIZED PERCENT REDUCTIONS OF NO,
FOR LARGE BORE 1C ENGINES
OJ
01
Baseline*
Retard
A1r-to-Fuel
Derate
MAT
Gas
2
BS
15.2
2.5
0.19
6.2
0.9
TC
13.2
3.1
4.5
2.6
1.3
4
NA
17.7-21.5
1.5
1.8
0.25-1.3
—
TC
12.8-22.1
4.1-0.6
3.3
0.34-1.9
0.4-0.9
Dual Fuel
2
TC
8.8
9.1
1.7
—
1.3
4
TC
7.8-12.7
1.5-6-3
2.4-2.5
0.01-0.94
0.6-0.8
Diesel
2
BS
13.2-19.1
6.9
—
0.84-0.92
0
TC
10.8-14.5
5.3-5.7
—
—
0.2-0.4
4
TC
10.0-11.4
2.7-4.4
0.17
0.1-0.3
Baseline data 1n gm/bhp-hr, all other data 1n percent NOX reduction/unit control. Unit control 1s 1° retard,
1 percent air flow Increase, 1 percent derating, or 1°F air temperature decrease.
Brake Specific Fuel Consumption (bsfc), Percent Increase
For Large Bore 1C Engines
Retard
A1 r-to-Fuel
Derate
MAT
5.2
2.0
2.6
1.3
4.3
1.5
6.1
0.5
3.6
1.0
8.2*
—
1.2
2.3
1.1*
0
3.4
2.6
7.0*
0.4
1.0*
1.9
—
+0.5
—
—
3.4*
—
3.3*
—
—
1.6
2.2*
—
9.6
0
Average value.
-------
Table 3-6 lists five examples of NO control techniques currently implemented
J\
by manufacturers to meet the 1975 California 10 gm/hp-hr NO + HC emission level.
J\
Manufacturers indicate that greater reductions will require increasing degrees of
these controls (and additional fuel penalties) or application of techniques that are
currently undeveloped or which will need further development to overcome maintenance,
control, and durability problems. Such controls include E6R, water injection, and
NO reduction catalysts.
A
Gasoline engine manufacturers, in response to Federal and State regulations,
have also conducted considerable research of emission control techniques to reduce
NOX as well as HC and CO levels. Efforts in this area have been directed at reducing
emissions to meet
1) Federal and California heavy duty vehicle (> 6000 Ib) limits
2) Federal and California passenger car emissions limits.
Table 3-7a lists Federal and State emission limits, and Table 3-7b lists the various
controls that are used in several combinations by manufacturers to meet these limits.
Table 3-8 gives specific examples of control techniques recently applied to meet
Federal light vehicle emission limits.
Based on the preceding discussions, potential NO emissions reductions for
J\
stationary reciprocating engines can be summarized as follows:
0 Controls such as retard, air-to-fuel ratio change, turbocharging, inlet
air cooling (or increased aftercooling), derating and combinations of these
controls have been demonstrated to be effective and could be applied with
no required lead time for development, fuel penalties, however, accompany
these techniques and may exceed 5 percent of the uncontrolled consumption.
t Exhaust gas recirculation, water induction, catalytic conversion and pre-
combustion or stratified charge techniques involve some lead time to develop
as well as time to address maintenance and control problems,
• NO control technology for automotive applications can be adapted to sta-
A
tionary engines; however, NOV reductions and attendant fuel penalties for
/\
automotive applications are closely related to the load cycle, which in
some cases may differ from stationary applications.
• Viable control techniques may involve an operational adjustment, hardware
addition, or a combination of both.
• Additional research is necessary to
- Establish controlled levels for gaseous-fueled engines <100 hp/cylinder
- Establish controlled levels for medium-powered diesel and gasoline
engines based on stationary application load cycles
- Supplement the limited emissions data available for large bore engines
with field tested results.
36
-------
TABLE 3-6. CONTROL TECHNIQUES FOR TRUCK SIZE DIESEL ENGINES (<500 HP)
TO MEET 1975 CALIFORNIA 10 GM/HP-HR NOX AND HC LEVEL*
t*i
Control
Retard, modify fuel
system and turbo-
charger
Retard, modify fuel
system and turbo-
charger, add after-
cooler
Add turbocharger and
aftercooler §
Retard §
(Naturally aspirated
version)
Pre-combustion
chamber
Bsfc Increase
3
3
2
0
3
5-8
Source
Information supplied to
Reference 3-15 by
manufacturers
Information supplied to
Reference 3-15 by
manufacturers
Information supplied to
Reference 3-15 by
manufacturers
Information supplied to
Reference 3-15 by
manufacturers
Information supplied to
Reference 3-15 by
manufacturers
Based on Federal 13 mode composite cycle
'''Bsfc = brake specific fuel consumption
^Stationary versions of this engine would require a cylinder head with
4 exhaust valves rather than existing 2 valves.
-------
TABLE 3-7a. 1975 VEHICLE EMISSION LIMITS
Passenger Car,
gm/nri (gm/hp-hr)*
California
Federal
Light duty truck,
gm/nri
California
Federal
Heavy duty vehicles,
gm/hp-hr
California
Federal
NOX
2.0 (4.4)
3.1 (6.8)
2.0 (4.4)
3.1 (6.8)
HC
0.9 (2.0)
1.5 (3.3)
2.0 (4.4)
2.0 (4.4)
10
16
CO
9 (19.6)
15 (32.8)
20 (43.7)
20 (43.7)
30
40
Emission limits are estimated in gm/hp-hr from gm/mile assuming
an average speed of 24 mph requiring 11 bhp for the 7 mode com-
posite cycle. See Reference 3-17.
TABLE 3-7b. EMISSION CONTROL TECHNIQUES FOR AUTOMOTIVE GASOLINE ENGINES
Control
NOX:
Rich or lean A/F ratio
Ignition timing retard
Exhaust gas recirculation
(5 to 10 percent)
Catalytic converters
(reduction)
Increase exhaust back pressure
Stratified combustion
HC, CO:
Thermal reactor
Catalytic converter (oxidation)
Exhaust manifold air injection
Positive crankcase ventilation
Comment
Increased bsfc, HC, and CO
Increased bsfc, HC, and CO,
amount of control limited by
potential exhaust valve damage
Increased bsfc and maintenance
related to fouling, smoking
limits degree of control
In developmental stage
Increase bsfc
Requires different cylinder head,
increased bsfc.
Very effective in reducing HC, CO
Requires periodic catalyst
element replacement
Increased bsfc to power air pump
Reduces HC evaporative losses
38
-------
TABLE 3-8. EMISSION CONTROL SYSTEMS FOR CONVENTIONAL
GASOLINE I.C. ENGINES (ADAPTED FROM
REFERENCE 3-18)
Number
0
1
2
3
Year
1972
1973 Federal
1975 Federal
1975 Calif.
System
EM°^
EM° + El + FC + AI + EGR
EM° + El + 1C + QHI + AI + EGR
EM° + El + 1C + QHI + EGR + AI + OC
Fuel Penalty %^
-
7 ± 3
5 ± 2
8 ± 2
(?)
Reduction Factors v '
HC<3>
1 ± 0.:375
1.35 ± 0.30
0.65 ± 0.15
0.18 ± 0.05
co<3>
1 ± 0.375
1.0 ± 0.23
0.55 ± 0.15
0.15 ± 0.03
NOX(3)
1 ± 20
0.6 ± 0.10
0.6 ± 0.10
0.6 ± 0.10
System ...
Deterioration^ '
L
L
L
M (HC, CO)
L (NOX)
to
10
^'1972 baseline engine: modifications Included 1n the baseline engine configuration are retard, lean air-to-fuel, and reduced
compression ratio.
Component Identification
EM - Engine modifications; retard, air-to-fuel, compression ratio
El - Electronic Ignition
FC - Fast choke
QHI - Quick heat Intake
AI - Exhaust manifold air injection
EGR - Exhaust gas recirculation
1C - Improved carburet ion
OC - Oxidizing catalyst
(^
Reduction factor defined as:
SlSt™ based on ^ dn'v1ng cycle'
(^
emissions data taken using or corrected to 1975 CVS-CH test procedure
Deterioration of present systems; L = 10X, M = 10 - 30%, H = 30*
-------
3.1.3.2 Gas Turbines
Although gas turbines contributed only an estimated 2.5 percent of the annual
stationary source NOX emissions in 1972, they comprise a very rapidly growing indus-
try with increasing application in
• Intermediate and base load power generation
• Pipeline pumping
• Natural gas compressors
• On-site electrical generation
Combustion modification strategies for gas turbines differ from those of boil-
ers since turbines operate at a lean A/F ratio with the stoichiometry determined pri-
marily by the allowable turbine inlet air temperature. The turbine combustion zone
is nearly adiabatic and flame cooling for NOX control is achieved through dilution
rather than radiation cooling. The majority of NOX formation in gas turbines is
believed to occur in the primary mixing zone, where locally hot stoichiometric flame
conditions exist. The strategy to NOX control in gas turbines is to alleviate the
high temperature stoichiometric regions through improved premixing, primary zone
mixing and downstream dilution.
Typical NO emissions from gas turbines are illustrated on Figures 3-1 and 3-2
J\
for small and large units, respectively (Reference 3-19). Also imposed on these fig-
ures are the San Diego County standards for NO emissions for non-mobile units greater
than 50 million Btu heat input: 75 ppm NO at 15 percent oxygen for liquid fuels and
A
42 ppm NOV at 15 percent oxygen for gaseous fuels (Reference 3-20). As seen in the
A
figures, very few units meet these standards in the uncontrolled state.
Combustion modifications for gas turbines are classified into wet and dry
techniques of which only wet methods, i.e., water or steam injection, presently pro-
vide substantial reductions. As yet, no combination of dry methods has been success-
ful in reducing emissions below a typical standard of 75 ppm NOX at 15 percent oxy-
gen. Presently available wet and dry methods for NOX reduction are aimed at either
reducing peak flame temperature or reducing residence time at peak flame temperatures
or both. These techniques, along with their reduction potential and future prospects,
are shown in Table 3-9.
Wet techniques, water or steam injection, are the most effective methods yet
developed with reduction potentials as high as 90 percent for gas and 70 percent for
oil fuels. With wet control, water or steam is introduced into the primary zone by
either premixing with the fuel prior to injection into the combustion zone, by injec-
tion into the primary air stream, or by direct injection into the primary zone. The
effectiveness of each method is strongly dependent on atomization efficiency and
primary zone residence time. In the case of water injection, peak flame temperatures
40
-------
250
5 200
8
ISO
100
A
A
T
O GAS-FIRED UNITS
£ OIL-FIRED UNITS
NOTE: DATA NOT ADJUSTED FOR
GAS TURBINE EFFICIENCY
so
]l>1d I San Diego
gaseous) County Standards
o.s
i.o
1.5
2.0 2.5
TURBINE SIZE. MW
3.0
3.5
4.0
Figure 3-1. NOX emissions from small gas turbines without NOX controls..
Reference 3-19.
-------
ro
S
I
o ,„
>< 100
SO
A
O
10
IS
20
O GAS-FIRED UNITS
A OIL-FIRED UNITS
NOTE: DATA NOT ADJUSTED FOR
GAS TURBINE EFFICIENCY
liquid
'gaseous
San Diego
County
Standards
25
TURBINE SIZE. MW
30
35
45
Figure 3-2. NOX emissions from large gas turbines without NOX controls,
Reference 3-19.
-------
TABLE 3-9, GAS TURBINE - SUMMARY OF EXISTING TECHNOLOGY - COMBUSTION MODIFICATIONS
Modification
Wet Controls
Water Injection
Steam Injection
Methods of
Injection
Preralx prior to
Injection Into
combustion zone
Injecting Into
primary air
stream
Direct Injec-
tion Into pri-
mary zone
Dry Controls
Lean Out Pri-
mary Zone
Increase Mass
Flowrate
Earlier Quench
with Secondary
A1r
Approach to
NOX Control
Lower peak flame temp
by utilization of
heat capacity and
heat of vaporization
Lower peak flame temp
by utilization of
heat capacity of
steam
lower peak flame temp
Reduce residence time
at peak temperatures
Reduce residence time
Reduction
Potential
To 90%
(50-70% oil)
(60-902 gas)
To 90%
(50-70* oil)
(60-90% gas)
10-20%
To 15%
To 15%
Near Term
To date, most effective
measure and only which
meets San Diego stan-
dard
To date, most effective
measure and only which
meets many San Diego
standards
Attractive option, re-
quires additional con-
trols to meet standards
Attractive option 1f
feasible
Minor combustor modi-
fication used present-
ly with wet controls
Far Term
Not seen as attractive
long term solution,
second priority to dry
controls
Like water Injection,
unattractive long term
solution
As noted above, all
wet techniques are
considered Interim
methods and will even-
tually yield to more
effective, less ex-
pensive, more effi-
cient dry methods
Generally seen as an
option to be Incor-
porated Into new low
NOX designs
Not an attractive long
term option due to In-
flexibility
An attractive concept
to be employed in
advanced combustors
Additional Comnents
Reduces efficiency, Increases capital
costs up to 10%. Operating costs as
low as 1% depending on usage. Hin-
dered by requirement for "clean"
water supply. Ineffective In reducing
fuel NOX.
Increases overall efficiency by In-
creasing flowrate. Installation and
operating costs same as water Injec-
tion. Requires high pressure steam.
Ineffective 1n reducing fuel NOX.
In all cases, the effectiveness Is
strongly dependent upon both atoml-
zatlon efficiency and primary zone
residence time.
Decrease 1n power output, less control
over flame stabilization
Increase In shaft speed constant
torque
An attractive option both for near
term minor combustor modifications
and for Incorporation Into new de-
signs. Limited by flowrates and
Incomplete comustlon
Refs.
3-14
3-19
3-21
3-22
3-14
3-19
3-22
3-19
3-14
3-19
3-20
-------
TABLE 3-9, (CONCLUDED)
Modification
A1r Blast or
Air Assist
Atomlzation
Reduce Inlet
Preheat
(Regenerative)
Other HI nor
Combustor Modi-
fications and
Retrofit
Exhaust Gas
Rec1rculat1on
Approach to
NOX Control
Reduce peak flame temp
by Increasing mixing
thereby reducing local
A/F ratio
Reduce peak flame temp
Reduce peak flame temp
through premlxlng,
secondary air Injec-
tion, primary zone
flow redrculatlon
Reduce peak flame
temperatures
Reduction
Potential
To 38%
Combined
To 38%
Near Term
Considered a minor
combustor mod
Not attractive due to
thermal efficiency
reduction
Attractive near term
as an Interim solu-
tion
Option has seen use in
minor combustor modi-
fications
Far Term
Promising method to be
Incorporated Into new
low NOX design
Not attractive for long
term solution
An attractive option
for future design
with Internal com-
bustors
Additional Comments
Generally considered a major retro-
fit.
Reduces efficiency.
In general reduces efficiency while
reducing NO.. Require additional
controls and greater downtime.
Reduced efficiency requires additional
control s .
Refs.
3-19
3-19
3-19
3-19
-------
are reduced through the vaporization of the water and the relatively high heat capa-
city of steam. Steam Injection reduces peak flame temperature by using only the heat
capacity of steam. Although NOV reduction Is quite effective, numerous difficulties
A
offer Incentive to the development of dry controls. The future of wet control does
not appear promising based on the following inherent problems:
t High capital and operating costs
• Requirements for "clean" water or high pressure steam
• Hardware requirements increase plant size
t Delivery system hardware resulting in increased failure potential and
overhaul/maintenance time
0 Uncertainty regarding long term control effects on turbine.
Although no combination of presently available dry controls has the reduction
potential of the wet methods, many dry techniques are used in conjunction with water
or steam injection, particularly on the larger units. On the smaller units, dry con-
trols may be sufficient to meet standards. The dry controls now available are:
• Lean out primary zone — Reduces NO levels up to 20 percent by lowering
A
peak flame temperatures. This option allows less control over flame sta-
bilization and reduces power output but is an attractive control to be
built into future low NO combustors.
1 A
0 Increase mass flow rate — With possible NO reductions up to 15 percent,
A
this control reduces residence time at peak flame temperature. This con-
trol essentially increases the turbine speed at constant torque and is
not feasible in many applications.
• Earlier quench with secondary air -— This is a minor combustor modifica-
tion which entails upstream movement of the dilution holes to reduce resi-
dence time at peak temperatures. This is a promising control which is
generally employed in advanced combustor research,
t Reduce inlet air preheat — A control applicable only to regenerative
cycle units is not attractive due to reduction in efficiency.
• Air blast and air assist atomization — Use of high pressure air to im-
prove atomization and mixing requires replacement of injectors and addition
of high pressure air equipment, This control is considered an excellent
candidate for incorporation into new low NO design combustors.
A
• Exhaust gas recirculation — With a possible NOX reduction of 30 percent,
EGR is a promising dry control for future design and has limited applica-
tion 1n some on-Hne units, EGR requires extensive retrofit relative to
other dry controls and also requires a distinct set of controls for the
EGR system.
45
-------
Other minor combustor modifications are generally aimed at improving favori
able internal flow patterns in the primary zone and fuel/air premlxing. The bulk of
these modifications are combustor-specific and investigated by the manufacturer. In
general, any combination of dry controls has not exceeded 40 percent NOV reduction
J\
and as such are insufficient controls for the larger units. Since dry techniques
approach NOX reduction differently than do wet controls, their effects are additive
and consequently frequently used together. Figures 3-3 and 3-4 illustrate the effect
of dry and wet controls used separately and in combination for both liquid and gas-
eous fuels (Reference 3-19). The figures show dry controls to be inadequate to meet
San Diego Standards where wet controls are sufficient while the combination is even
more effective.
Future NOX control in gas turbines is directed toward dry techniques with
emphasis on combustor design. Medium term (1979-1985) combustor designs incorporate
improved atomization methods or prevaporization and a premixing chamber prior to ig-
nition. Favored techniques are a high degree of recirculation in the primary zone
followed by rapid quenching with secondary air. These developmental combustors are
projected to attain emission levels of 20 ppm NOX at 15 percent oxygen.
3.1.4 Space Heating
Residential and commercial space heating contributes an estimated 7.1 percent
of the total annual stationary source NO emissions. This figure is magnified by
A
two important considerations: the bulk of these emissions are produced during the
winter heating season and the majority of the units are located in or near urban areas.
In addition to NO , several equally significant pollutants are generated by these
units: carbon monoxide (CO), unburned hydrocarbons (HC), and smoke. Boilers for
commercial heating range in size from 10 to 300 boiler horsepower (-0.35 to 10 M
Btu/hr) while residential heaters range in capacity from 75,000 to 300,000 Btu/hr.
Recent studies by Battelle (Reference 3-23) have determined typical emissions from
these equipment groups. These are presented in Table 3-10. Although the variation
of emission levels was found to be dependent upon boiler size, design, burner type,
burner age, operating conditions, etc., the effect of fuel type was found to be of
greatest importance as conversion of 40 to 60 percent of the fuel nitrogen to NO
A
was indicated.
Presently available emission reduction techniques for space heating units are
limited to
• Tuning — the best adjustment in terms of the smoke-C02 relationship that
can be achieved by normal cleanup, nozzle replacement, simple sealing and
adjustment with the benefit of field instruments.
46
-------
itv
100
80
NO, CONCENTRATION
, g S S
FACILITY
POWER OUTPUT
CONTROL TYPE
1 1 1 g T I 1 1 1 1 1 III
j*l ^______
o y
n
— O -fy- AVERAGE —
O
O €> EPA TEST METHODS
O OTHER TEST METHODS
0 0
liquid fuel standard (San Diego) _ NOTF. N0 AFMIISTMFNT FOR GAS
0 TURBINE EFFICIENCY
n o
_ -V- ° -
* *
* e
"" 0 ~
O
0
1 1 1 1 1 1 1 1 1 1 1 III
S E G3 -G2 0 T F G3 11 L2 0 Gl G3 G2
0^ 7J 174 18^ J2.5 18 20
DRY WET WET+DRY
Figure 3-3. NOX emissions from gas turbines having NOX controls and operating on liquid fuels,
Reference 3-19.
-------
1ZU
100
NO, CONCENTRATION
S S
40
20
g
FACILITY
POWER OUTPUT
CONTROL TYPE
1(1 III III
O.
KEY
— O -E- AVERAGE ~~
-B-
|J O EPA TEST METHODS
n O OTHER TEST METHODS
O
0 NOTE: NO ADJUSTMENT FOR GAS
TURBINE EFFICIENCY
_ 0 _
gaseous fuel standard (San Diego} r>
o ^ ??
O -J-»-
y
iii iii iii
S G3 G2 T P G3 G3 G2 XI
0.2 17.5 19 2.5 13 17J 17.5 17-20 25
DRY WET DRY+WET
Figure 3-4. NOX emissions from gas turbines having NOX controls and operating on gaseous fuels,
Reference 3-19.
-------
TABLE 3-10. TYPICAL EMISSION LEVELS FROM COMMERCIAL AND RESIDENTIAL HEATING, REFERENCE 3-23.
vo
Unit
Residential
Residential
Commercial
Commercial
Commercial
Commercial
Commercial
Commercial
Fuel
Gas
No. 2 Oil
Gas
No. 2 Oil
No. 4 Oil
LSR*
No. 5 Oil
No. 6 Oil
Emission Concentration @ 3% 02* dry basis
NOX as N02
70
115
80
100
390
260
290
415
CO
15
65
20
4
7
3
16
10
HC
3
13
9
3
3
5
4
5
Bacharach Smoke
0
3.0
0.2
0.9
2.6
2.9
3.0
3.9
Low Sulfur Residual Oil (-1% S)
-------
• Unit replacement — installation of a new, more advanced unit
• Burner replacement — installation of a new low-emission burner
The Battelle study indicates that the combination of tuning and unit replace-
ment has a beneficial effect on all pollutants with the exception of NOV. In the
3\
sampling, units considered in "poor" condition were replaced and all others were
tuned, resulting in reductions in smoke, CO, HC and filterable particulate by 59, 81,
90 and 24 percent respectively, with no change in NO levels. This testing was car-
}\
ried out on oil-fired units only, but Hall (Reference 3-24) determined that gas-fired
units exhibit emission levels similar to an equivalent size high pressure atomizing
gun oil burner. Table 3-11 shows mean emission levels prior to and after replacement
and tuning. Although tuning and replacement have been shown to have little effect on
NOX levels, yearly inspection accompanied by one of these techniques is highly recom-
mended since other pollutant levels are so greatly reduced.
Significant emission reduction can be affected by burner replacement. Battelle
found this procedure to produce significantly lower levels of CO and filterable parti-
culate and slightly lower levels of HC and NOX believed to be due only to improved
burner designs. In general, recently developed burners have not demonstrated the
ability to consistently reduce NO levels while many, in improving combustion effic-
J\
iency and reducing other pollutant levels, actually increase NO emissions over the
J\
standard burner. A number of commercially available burners were tested by Hall
(Reference 3-25) wherein pollutant levels were determined under operating conditions.
Combustion-improving devices yielded higher NOV levels than the standard, but demon-
A
strated a potential for reducing levels of one or more pollutants and for improving
combustion efficiency. Flame retention burners were shown to be capable of operating
at low excess air levels, resulting in increased combustion efficiency with accompanied
reduction in emission levels with the exception of NO . During this testing, one de-
A
vice was demonstrated to reduce NO levels appreciably. Although the reduction mech-
A
anism is unknown, further studies are underway to define critical parameters in burner
design. Both the combustion improving devices and flame retention burners utilized
the conventional high pressure atomizing gun nozzles. Several other experimental and
commercially available burners not employing the high pressure atomization gun were
tested. Of these, only the "blue flame" burners showed substantial NOX reduction but
also demonstrated higher than baseline levels of CO, HC and smoke. Future develop-
ments will include mechanisms for simultaneous reductions for all pollutants by way
of advanced burner design and further development of integrated low-emission units
for replacement and new installations. Present development by Rocketdyne (Reference
3-26) indicate progress into the prototype stages on the integrated unit.
By way of summary, the available means for reducing pollutant levels from
residential and commercial space heating units do not consistently reduce NO levels
50
-------
TABLE 3-11. COMPARISON OF MEAN EMISSIONS FOR CYCLIC RUNS ON RESIDENTIAL OIL-FIRED UNITS
Units Mean Mean Emission Factors, lb/1000 gal
in Smoke Filterable
Units Condition Sample9 No.b CO HC NOX Paniculate
Mean Values From Phase I and II Battelle/API/EPA Investigation:
All units
(71
—• All units, except
those in need of
reolacement
As-Found
Tuned
As-Found
Tuned
32
33
29
30
(c)
(0
3.2
1.3
>22.1
>16.4
7.8
4.3
5.7
3.0
0.72
0.57
19.4
19.5
19.6
19.5
2.9
2.3
2.4
2.2
-------
but are beneficial to CO, HC, smoke and filterable participates. While tuning has
no effect on NOX levels, unit or burner replacement can demonstrate slight reductions
due to more advanced design techniques.
3.2 FUEL MODIFICATION
Knowledge of the important role that the fuel plays in the formation of NO
x
»1
modification options are fuel switching, denitrification, and use of fuel additives.
identifies fuel modification as an obvious NO reduction strategy. The major fuel
A
3.2.1 Fuel Switching
This method usually entails the conversion of the combustion system to the
use of a fuel with a reduced nitrogen content (to suppress fuel NO ) or to one that
A
burns at a lower temperature (to reduce thermal NOX). Sulfur control is usually a
dominant cost incentive for fuel switching. Natural gas firing is an attractive NO
A
control strategy because of the absence of fuel NO in addition to the flexibility
A^
it provides for the implementation of combustion modification techniques. Despite
the superior cost-effectiveness of gas-fired NO control, the economic considerations
in fuel selection are dominated by the current clean fuel shortage. Indeed, the trend
is toward the use of coal for electric power generation and larger industrial processes.
On a short-term basis, fuel switching to natural gas or low nitrogen oil is not a pro-
mising option.
A promising long-range option is the use of clean synthetic fuels derived from
coal. Candidate fuels include lower Btu gas (100 to 800 Btu/scf) and synthetic oil.
Process and economic evaluations of the use of these fuels for power generation are
being performed by the United States EPA, ERDA, the American Gas Association, and the
Electric Power Research Institute. Two alternatives for utilizing low and intermed-
iate Btu gases are firing in a conventional boiler or in a combined gas and steam
turbine power generation cycle. For both systems, economic considerations favor
placement of both the gasifier and the power cycles at the coal minehead. The most
extensive use of these systems would probably be for replacement of older conventional
units upon their retirement.
The NO emissions from lower Btu gas-fired units are expected to be low due to
reduced flame temperatures corresponding to the lower heating value of the fuel. The
effects of NO formation of the molecular nitrogen and the intermediate fuel nitrogen
A
compounds, such as ammonia, in the lower Btu gas have not yet been determined and
require further study.
The feasibility of synthetic fuel firing as a NOX control option is contingent
on the cost tradeoff between synthetic fuel production and the total control costs
for NO , SO and particulates in conventional coal firing. There is preliminary
A A
52
-------
evidence that gasification may be more costly than flue gas cleaning of conventional
systems (Reference 3-27).
3.2.2 Fuel Additives
In principle, additives to the fuel could reduce NO emissions through one or
a combination of the following effects:
• Reduction of flame temperature through increased thermal radiation or
dilution
• Catalytic reduction or decomposition of NO to N2
• Reduction of local concentrations of atomic oxygen
In 1971, Martin, et al., tested 206 fuel additives in an oil-fired experimen-
tal furnace, and 4 additives in an oil-fired packaged boiler. None of the additives
tested reduced NO emissions but some additives containing nitrogen increased NO for-
mation (Reference 3-28).
In another investigation of fuel additives, Shaw tested 70 additives in a gas
turbine combustor and found that only metallic compounds that promoted the catalytic
decomposition of NO to N« had a significant effect on NO emissions. Average reduc-
tions of 15 to 30 percent were achieved with the addition of 0.5 percent (by weight)
of iron, cobalt, manganese, and copper compounds, The use of these additives for
controlling NOV is not attractive, however, due to added cost, serious operational
A
difficulties and the presence of the additives, as a pollutant, in the exhaust gas
(Reference 3-29).
An indirect reduction of NO could result from the use of additive metals in-
3\
tended to prevent boiler tube fouling. The excess air level in oil-fired boilers is
frequently set sufficiently high to prevent tube fouling. Use of additives could
allow the lowering of excess air levels which in turn would reduce NOX formation.
The emission reduction from this method, however, is quite limited and the cost-
effectiveness is likely to be poor (References 3-30 and 3-31).
3.2.3 Fuel Denitrification
Fuel denitrification of coal or heavy oils could in principle be used to con-
trol the components of NOV emission due to conversion of fuel bound nitrogen. The
ft
most likely use of this concept would be to supplement combustion modifications im-
plemented for thermal NO control. Current technology for denitrification is limited
A
to the side benefits of fuel pretreatment to remove other pollutants. There is pre-
liminary data to indicate that marginal reductions in fuel nitrogen result from oil
desulfurizatlon (Reference 3-32) and from chemical cleaning or solvent refining of
coal for ash and sulfur removal (Reference 3-33). The low denitrification efficiency
53
-------
of these processes does not make them attractive solely on the basis of NOX control.
They may prove cost effective, however, on the basis of total environmental impact.
3.3 ALTERNATE PROCESSES
For new combustion systems, the combustion control technology derived from
retrofit of existing units can be incorporated, together with new concepts not appli-
cable for retrofit, into designs optimized for low NO production. The flexibility
A
of this approach yields potentially lower costs and higher effectiveness relative to
retrofitting existing units. Alternatively, the economics of the utilization of
lower quality fuels necessitated by the clean fuels shortage may dictate the selec-
tion of alternate combustion process concepts.
The most popular alternate concepts appear to be fluidized bed combustion and
catalytic combustion, both of which are currently being investigated by various agen-
cies and organizations. These processes are described briefly below.
3.3.1 Fluidized Bed Combustion
Suggested advantages of fluidized bed combustion compared to conventional
boilers are:
• Compact size yielding low capital cost, modular construction, factory
assembly, and low heat transfer area
• Higher thermal efficiency yielding lower thermal pollution
t Lower combustion temperature (1400°F to 1800°F) yielding less fouling
and corrosion
• Potentially efficient sulfur control
• Applicable to a wide range of low-grade fuels including char from synthe-
tic fuels processes
• Adaptable to a high efficiency gas-steam turbine combined power genera-
tion cycle (References 3-34, 3-35 and 3-36)
The feasibility of the FBC for power generation depends in part on the following:
development of efficient methods for regeneration and recycling of the dolomite/
limestone materials used for sulfur absorption and removal; obtaining complete com-
bustion through flyash recycle or an effective carbon burnup cell; development of a
hot-gas particulate removal process to permit use of the combustion products in a
combined-cycle gas turbine without excessive blade erosion.
The potential for reduced NOX emissions with fluidized bed combustion is cur-
rently under investigation in several EPA-funded projects. Preliminary tests with
pilot scale units indicate that emission levels well within the EPA standard of
54
-------
0.7 Ib N02/106 Btu for new coal-fired units can be achieved (References 3-34 and 3-35).
At the operational temperatures of the fluidized bed, the rate of formation of thermal
NOX is very low and nearly all NOX emitted results from conversion of fuel nitrogen.
The fuel nitrogen content in the coals used in the pilot tests was not given, so these
results cannot be generalized.
Several of the pilot scale units have been tested for the effects of operation-
al variables on NOX emissions. BCURA has reported preliminary evidence that their
pressurized fluidized bed yields lower emissions than their atmospheric unit (Refer-
ence 3-36). The bed temperature has little effect on NOX emissions in the range from
1400°F to 1800°F, but operation with excess air increases NO significantly. Argonne
A
and Exxon have suggested that operation with two-stage combustion may be effective
for NOX control in the firing of high nitrogen content coals (References 3-35 and
3-37). Exxon suggests that two-stage combustion could have the additional advantage
of increasing the efficiency of the sulfur removal process.
From a NOX control standpoint, fluidized bed combustion is regarded as a medium
risk concept because the economic feasibility of the basic process and NO control
J\
techniques have not been fully established relative to conventional boilers or low
Btu gas combined-cycle units.
3.3.2 Catalytic Combustion
Catalytic combustion refers to those concepts in which combustion occurs in
close proximity to a solid surface. The interest in the concept arises from the low
pollutant emission characteristics, in particular N0y, which result from the combus-
3\
tion process occurring at reduced temperatures. In the catalytic combustor, reduced
combustion temperatures are achieved by operation with very lean or very rich fuel/air
mixtures, or by high heat transfer from the catalyst surface. The catalyst promotes
chemical reactions, which, at the catalyst temperature (1600°F to 2000°F) would other-
wise proceed too slowly for sustained combustion. Combustion is usually supported on
a porous ceramic plate, and radiation is the dominant heat transfer mechanism.
Collection of background information and an assessment of the applicability
of catalytic combustion concepts to gas turbines and utility boilers was performed
by the Aerospace Corporation (Reference 3-38). This report concluded that catalytic
concepts may be applicable to gas turbines, but that a retrofit to a utility boiler
was impractical. The report also indicated that only gases and light, sulfur-free
hydrocarbon liquids are appropriate as catalytic combustion fuels, due to system re-
quirements and catalyst poisoning potentials.
An ongoing EPA effort has as its goal the assessment of the feasibility of
applying catalytic concepts to area sources, including industrial boilers, commercial
and residential heating systems, and industrial process heating units. The compila-
tion of information on all aspects of this program, including fuels and equipment
-------
characterization and trade-off analyses between retrofit and new design strategies,
is currently being performed under several EPA-sponsored programs. Catalytic com-
bustion is a promising long-term concept for clean fuel combustion in area sources,
but much research and development work must be done before it becomes commercially
available on a wide scale.
3.4 FLUE GAS TREATMENT OF NOX
There exists to date no fully developed flue gas treatment process for con-
trolling nitrogen oxides. However, several potential candidate processes do exist,
but which have not been adequately demonstrated on a coal-fired boiler as yet. Many
of these candidate processes remove both S09 and NO :
£ /\
• The Shell/UOP CuO adsorption process, in addition to removing S02, has
been found to remove approximately 60 to 70 percent of the nitrogen oxides
as well. This process has been successfully demonstrated on several oil-
fired units, and is currently being tested on a slipstream from a coal-
fired boiler (Reference 3-39)
• The Chiyoda Thoroughbred 102 process is similar to the 101 desulfurization
process, except that now both S02 and NOX are removed in a single absorber
after the NO is oxidized to NO,,. At the present time, research on the
102 process is being conducted with bench scale and pilot plants, whereas
the 101 process has been successfully demonstrated on many oil-fired units
throughout Japan (Reference 3-40).
• The Bergbau-Forschung/Foster Wheeler process utilizes a char adsorption
system for S02 removal and simultaneously removes a maximum of about 50
percent of the NO . A pilot plant unit on a coal-fired boiler in West
A
Germany was in operation from 1968 to 1970, and a demonstration unit is
currently under construction on a coal-fired boiler in the United States
(Reference 3-41).
A number of S02 wet scrubbing processes (e.g., lime/limestone, magnesia,
sodium carbonate) have also been shown to remove a small portion (generally about
10 percent and usually never more than 20 percent) of the NOX from power plant flue
gases; however, these processes cannot be considered as primary flue gas treatment
systems for NOX control.
Several other candidate processes, not included in the above categories, also
appear to be technically feasible NOX control methods. Most of these are catalytic
processes which are still in the early stages of research and development. Work on
these process schemes has been confined to either laboratory or pilot scale studies,
and has not included work on coal-fired units as yet. Many of these processes are
56
-------
discussed in a report by TRW (Reference 3-42). Some of these are described below.
• Various compounds have shown some potential for catalytic decomposition
of NOX to nitrogen and oxygen, but they have not been tested on actual
power plant flue gases as yet. A major concern with this scheme is find-
ing an efficient catalyst which remains effective under actual operating
conditions.
• Two pilot plant studies on the selective catalytic reduction of NO by
A
ammonia are currently underway in Japan and in the United States. Labor-
atory studies indicate that noble metal catalysts are "poisoned" by SO ,
A
while non-noble metal catalysts are efficient only at very high tempera-
tures. Preliminary results from the pilot plant work show that 90 percent
NOX removal can be achieved with some noble metal catalysts and SOg-free
flue gas.
• Non-selective catalytic reduction appears to be a potential candidate
only for simultaneous NO -SO abatement. Several possible process schemes
A A
have been proposed with either hydrogen, carbon monoxide or hydrocarbons
as reductants, and one pilot plant scale study has been conducted in Japan
with good results. High temperatures, however, are needed here for the
catalysts to be effective, and several hazardous compounds have been iden-
tified as by-products from some of the process schemes.
Another NOX flue gas treatment process involves the use of molecular sieves.
However, since water does interfere in the absorption process, molecular sieves can-
not be used to clean combustion generated pollutants but can and have been used to
remove NO from tail gases from non-combustion sources, namely nitric acid plants.
57
-------
REFERENCES FOR SECTION 3
3-1 Blakeslee, C. E. and Burbach, H. E., "Controlling NOX Emissions from Steam
Generation," JAPCA, Volume 23, No. 1, January 1973, p. 37.
3-2 Blakeslee, C. E., "Reduction of NO Emissions by Combustion Modifications to
a Gas-Fired 250-MW Tangential Firea Utility Boiler," presented at Conference
on Natural Gas Research and Technology, Atlanta, Georgia, June 5-7, 1972.
3-3 Habelt, W. W. and Selker, A. P., "Operating Procedures and Prediction for NO
Control in Steam Power Plants," presented at Central States Section of the
Combustion Institute, Spring Meeting, March 1974.
x
3-4 Hollinden, G. A., "NOX Control at TVA Coal-Fired Steam Plants," Proceedings of
Third National Symposium. ASME Air Pollution Control Division, April 24, 1973.
3-5 Bartok, W., et al., "Systematic Field Study of NOX Emission Control Methods
for Utility Boilers," Esso R & E, Report GRV 46, No. 71, December 31, 1971.
3-6 Jain, L. K., et al., "State of the Art for Controlling NOX Emissions, Part I:
Utility Boilers," EPA-R2-72-072a, September 1972.
3-7 Crawford, A. R., et al., "Field Testing: Application of EPA's Combustion Pro-
gram for Control of Nitrogen Oxide Emissions for Stationary Sources," presented
at the Southeast APCA Meeting, Raleigh, North Carolina, September 19, 1972.
3-8 Barr, W. H., "Nitric Oxide Control — A Program of Significant Accomplishments,"
ASME Paper 72-WA/PWR-13.
3-9 Krippene, B. C., "Burner and Boiler Alterations for NOX Control," Central States
Section, The Combustion Institute, Madison, Wisconsin, March 1974.
3-10 Heap, M. P., et al., "Burner Design Principles for Minimum NOX Emissions,"
EPA Coal Combustion Seminar, Research Triangle Park, North Carolina, EPA 650/
273-021, June 1973, p. 141.
3-11 Lachapelle, D. G., Bowen, J. S. and Stern, R. P., "Overview of Environmental
Protection Agency's NOX Control Technology for Stationary Combustion Sources,"
presented at 67th Annual Meeting of AIChE, December 4, 1974.
3-12 Cato, G. A., et al., "Field Testing: Applications of Combustion Modification to
Control Pollutant Emissions from Industrial Boilers — Phase I," EPA-650/2-74-078-a,
October 1974.
3-13 McGowin, C. R., "Stationary Internal Combustion Engines in the United States,"
EPA-R2-73-210, April 1973.
3-14 Aerospace Corporation, "Assessment of the Applicability of Automotive Emission
Control Technology to Stationary Engines," EPA-650/2-74-051, July 1974.
3-15 Aerotherm Division, Acurex Corporation, "Standards Support Document for New
Stationary Reciprocating Internal Combustion Engines," EPA Contract No. 68-
03-1318, Task No. 7 (in preparation).
3-16 Springer, K. J., and Hare, C. T., "Exhaust Emissions from Uncontrolled Vehicles
and Related Equipment Using Internal Combustion Engines, Part 4 -Small Air-
Cooled Spark Ignition Utility Engines," APTO 1493, May 1973.
3-17 Bascom, R. C., and Hass, G. C., "A Status Report on Development of the 1973
California Emissions Standards," SAE Paper 700671, August 1970.
58
-------
3-18 Calspan Corporation, "Technical Evaluation of Emission Control Approaches and
Economics of Emission Reduction Requirements for Vehicles Between 6,000 and
14,000 Pounds GVW," EPA-460/3-73-005, November 1973.
3-19 Durkee, K., Noble, E. A., Collins, F., and Marsland, D., "Draft of Standard
Supports Document for an Investigation of the Best System of Emission Reduc-
tion for Stationary Gas Turbines," EPA, Office of Air Quality Planning and
Standards, Research Triangle Park, North Carolina, August 1974.
3-20 Rule 68, San Diego County Air Pollution District.
3-21 Shaw, H., "The Effects of Water, Pressure and Equivalence Ratio on Nitric Oxide
Production in Gas Turbines," ASME Paper 73-WA/GT-l,
3-22 Hilt, M. B. and Johnson, R. H., "Nitric Oxide Abatement in Heavy Duty Gas
Turbine Combustion by Means of Aerodynamic and Water Injection," ASME Paper
72-GT-53,
3-23 Barrett, R. E., Miller, S. E., and Locklin, D. W., "Field Investigation of
Emission from Combustion Equipment for Space Heating," Report EPA-R2-73-084a,
Prepared by Battene Memorial Institute, Columbus, Ohio, July 1973.
3-24 Hall, R. E., et al., "Status of EPA's Combustion Research Program for Residen-
tial Heating Equipment," presented at the 67th APCA Annual Meeting, June 1974.
3-25 Hall, R. E., Wasser, J. H., and Berkau, E. A., "A Study of Air Pollutant
Emissions from Residential Heating Systems," Report EPA-650/2-74-003, Environ-
mental Protection Agency, Research Triangle Park, North Carolina, January 1974.
3-26 Nurrick, W., Rocketdyne Corporation, Los Angeles, California, Personal Communi-
cation, June 1975.
3-27 Waitzman, D. A., et al., "Evaluation of Fixed Bed Low Btu Gasification Systems
for Retrofitting Power Plants," EPRI Report 203-1, February 1975.
3-28 Martin, G. B., Pershing, D. W., Berkau, E. E., "Effects of Fuel Additives on
Air Pollutant Emissions from Distillate Oil-Fired Furnaces," EPA, Office of
Air Programs, AP-87, June 1971.
3-29 Shaw, H., "Reduction of Nitrogen Oxide Emissions from a Gas Turbine Combustor
by Fuel Modifications," ASME Transactions, Journal of Engineering for Power,
Volume 95, No. 4, October 1973.
3-30 Kukin, I., "Additives Can Clean Up Oil-Fired Furnaces," Environmental Science
and Technology, Volume 2, No. 7, July 1973.
3-31 Lee, G. K., et al., "An Investigation of Fuel-Oil Additives to Prevent Super-
heater Slagging in Naval Boilers," Proc, of American Power Conference, Vol. 26,
1974.
3-32 Barrett, R. E., et al., "Field Investigation of Emissions from Combustion
Equipment for Space Heating," EPA Report R2-73-084a, June 1973.
3-33 Frey, D. J., "De-ashed Coal Combustion Study," Combustion Engineering Inc.,
October 1964. Prepared for Office of Coal Research.
3-34 Robinson, E. B., et al., "Characterization and Control of Gaseous Emissions
from Coal-Fired Fluidized-Bed Boilers," Pope, Evans, and Robbins Interim Re-
port, Division of Process Control Engineering, NAPCA, October 1970.
3-35 Jonke, A. A., et al., "Pollution Control Capabilities of Fluidized-Bed Combus-
tion," Air Pollution and Its Control, AIChE, 1972.
59
-------
3-36 National Coal Board, London, England, Fluidized Combustion Control Group,
"Reduction of Atmospheric Pollution, Appendix 3, Experiments with the
271M Combustor, (Task III)," Prepared for EPA, September 1971.
3-37 Haramons, 6. A., Nutkis, M. S., and Skopp, A., "Studies of NOX and SOX Control
Techniques in a Regenerative Limestone Fluidized Bed Coal Combustion Process,"
Esso R&E Company, Prepared under Contract CPA 70-19 for Division of Process
Control Engineering, Office of Air Programs, NAPCA, Interim Report, January 1,
1971 to June 1, 1971.
3-38 Roessler, W. U., et al., "Investigation of Surface Combustion Concepts for NOX
Control in Utility Boilers and Stationary Gas Turbines," EPA-650/2-73-014,
August 1973.
3-39 Pohlenz, J. B., "The Shell Flue Gas Desulfurization Process," presented at
EPA Flue Gas Desulfurization Symposium, Atlanta, Georgia, November 4-7, 1974.
3-40 Idemura, H., "Simultaneous SOo and NOX Removal Process for Flue Gas," Chemical
Economy and Energy Review, Volume 6, No. 8, pp. 22-26, August 1974.
3-41 Habib, Y., and Bischoff, W. F., :Dry System for Flue Gas Cleanup," Oil and
Gas Journal, pp. 53-55, February 24, 1975.
3-42 Koutsoukos, E. P., et al, "Assessment of Catalysts for Control of NOX from
Stationary Power Plants, Phase I", Volume 1, EPA-650/2-75-001-2, January 1975.
60
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SECTION 4
COSTS OF NOX CONTROL METHODS
The previous section briefly described the major techniques for controlling NOX emis-
sions from stationary sources. Of the three possible NOX reduction strategies, precombustion,
post-combustion, and combustion control, the latter has proven to be the most effective by
both research programs and practical demonstrations. A number of classical combustion control
techniques are currently available for use on a wide variety of stationary sources. The
choice between these options will be based both on NOX suppression success and added cost.
The former topic has been extensively treated in this and other studies. The costs incurred
by such controls, however, have been less well reported. The cost of implementing combustion
modification techniques is basically the sum of the initial capital cost, annual capital cost,
and annual operating cost (which includes any cost savings). This section of the report will
summarize available information on the economics of these control methods, and identify areas
where such data fs lacking.
4.1 UTILITY BOILERS
The following discussion will center on the costs of reducing NOX from utility boilers
by combustion modification. To put such costs in perspective, the economics of flue gas
treatment methods for the removal of NOX and SOX are also presented.
4.1.1 Costs of NOx Control by Combustion Modification
Much of the pioneering work on evaluating the cost effectiveness of combustion modifi-
cation in full-scale combustion equipment has been performed on utility boilers. Correspond-
ingly, the related costs of these modifications have been, relative to other source types,
fairly well documented for this sector. One of the earliest efforts of this kind was attempted
by Esso Research Labs in 1969 (Reference 4-1). Based on estimates for the capital, annual,
and operating costs, the Esso report presented the results of a cost effectiveness study pef-
formed for NOX control on utility boilers by means of combustion modification. Since 1969,
however, it has been revealed that a wide variation 1n the effectiveness of the control tech-
niques among boilers exists. This problem will require that future cost-effectiveness evalu-
ations be done on an individual boiler basis.
Data from Combustion Engineering
The most recent cost data were published by Blakeslee (Reference 4-2) for new
and existing tangential, coal-fired utility boilers. These data are summarized in
61
-------
Figures 4-1 and 4-2. The cost range curves were derived from estimates developed under an
EPA-sponsored contract involving the reduction of NOX from both new and existing tangentially,
coal-fired utility boilers.
Four possible methods for reducing NOX emission levels were evaluated. These included
overfire air, gas recirculation to the secondary air ducts, gas recirculation to the coal
pulverizer/primary air system and furnace water injection. The cost trends for these methods
were projected over a unit size range of 125 to 750 MW.
Two levels of cost are established. The first is for new unit designs, Figure 4-1,
with heating surfaces adjusted to compensate for the resultant changes in heat transfer dis-
tribution and rates. The second level of cost, Figure 4-2, applies to existing units with no
change in heating surface as these changes must be calculated on an individual unit basis.
For both cases, the costs shown are in 1973 dollars, and except where otherwise noted are
estimated on a ± 10 percent basis.
It is readily observed that the cost ranges for existing units vary more widely than
for new units. This is due to the variations in unit design and construction which can
either hinder or aid the installation of a given NOX control system.
At approximately 60 MW, single cell-fired boilers reach a practical size limit and
divided furnace designs are utilized. As a divided tangentially-fired furnace has double the
firing corners of a single cell furnace, the costs increase significantly.* It should be kept
in mind that although these cost data for utility boilers were developed for tangentially coal-
fired boilers, it is felt that the range of costs presented should be generally applicable to
wall-fired boilers burning coal. Additionally, it is intuitively felt that the cost for simi-
lar combustion modification on gas and oil-fired utility boilers should be no higher than for
the coal-fired units.
The cost of reducing low excess air was not investigated since there is generally no
significant additional cost for modern units or units in good condition. However, some
older units may require modifications such as altering the windbox by addition of division
plates, separate dampers and operators, fuel valving, air register operators, instrumentation
for fuel and air flow and automatic combustion controls.
Data from EPA
Table 4-1 shows estimated investment costs for low excess air (LEA) firing on utility
boilers requiring modifications (Reference 4-4). These costs can vary depending on the
actual extent of the required modification and are only provided as guidelines. As unit size
increases, the cost per KW decreases since the larger units typically have inherently greater
flexibility and may require less extensive modification.
The use of low excess air firing reportedly increases boiler efficiency by 0.5 to 2
percent, in addition to savings resulting from decreased maintenance and operating costs.
Consequently, any investment costs can be offset in fuel and operating expenses.
62
-------
106Btu
JL 3.0
KM
600
700
Windbox Gas
Recirculation
Overfire Air
Combined Overfire
Air and Wind-
Gas Re-
circulation
V=-Gas
Recircula-
tion thru Mills
Windbox Water
Injection
800
UNIT SIZE
(MW)
Figure 4-1. 1973 installed equipment costs of NOX control methods for new
tangentially, coal-fired units (included in initial design).
*Based on: 5400 hrs/yr at rated MW and net plant heat rate
of 10" Btu/KWhr (Reference 4-3).
63
-------
106Btu
11
10
9
8
7
6
5
4
3
2
1
0
13
6.0
5.0
4.0
3.0
Windbox Gas
Recirculation
Overflre A1r
Combined Overflre
Air and Windbox
Gas Recirculation
^-^^x/ s y^T3^^^
-1- 3.ol 1 f—^-*^*/l / / / ^?—I Gas Recirculation
Thru Mills
Water Injection
Including Fan &
Duct Changes
Water Injection Without
Fan & Duct Changes
Unit Size
(MW)
Figure 4-2. 1973 installed equipment costs of NOX control methods for existing
tangentially, coal-fired units (heating surface changes not Included).
PG4E Portrero #3 *Based on 5400 hrs/yr at rated MW and net plant heat rate of 10" Btu/fcwhr
PG&E Plttsburg #7 (Reference 4-2).
64
-------
TABLE 4-1. 1974 ESTIMATED INVESTMENT COSTS FOR LOW EXCESS
AIR FIRING ON EXISTING BOILERS NEEDING MODIFICATIONS
Unit Size
(NH)
1000
750
500
250
120
Investment Cost
($/KW)
Gas and Oil
0.12
0.16
0.21
0.33
0.53
Coal
0.48
0.51
0.55
0.64
0.73
65
-------
Data from the Pacific Gas and Electric Co.
As an example of the manner in which the costs for combustion modification may vary
among individual existing units, several case studies are presented in Table 4-2. The fig-
ures shown are the costs incurred by the Pacific Gas and Electric Company during a program
to bring six units into compliance with local NOX emission regulations. For the most part,
the conversions involved the combination of windbox flue gas recirculation and overfire air
ports (Reference 4-5). These data are plotted on Figure 4-2. It is observed that the points
lie somewhat above the appropriate band of costs. The one-year difference between the base
costing years is a partial explanation for this lack of correlation.
Data from the Los Angeles Department of Hater and Power
Another West Coast electric utility company, the Los Angeles Department of Mater and
Power (LADWP), has had extensive experience in implementing NO control techniques on its
A
gas and oil-fired boilers. The techniques currently utilized by the Department include the
biased firing, or "burners out of service" (BOOS) method, overfire air/NOY ports, and low
A
excess air. The use of the latter technique, when combined with BOOS or overfire air, is
limited. Although the units are operated with the lowest excess air possible, it has been
found that when LEA is combined with other reduction methods, excess air levels must be
increased beyond those normally required.
The Department's data indicate a unit efficiency decrease of approximately one percent
attributable to BOOS operation. As has been found by other operators, LEA tended to increase
efficiency slightly: a one percent decrease in excess oxygen increased efficiency by about
0.25 percent. Properly retrofitted, overfire air had no effect on efficiency.
The NO control costs incurred by LADWP are shown in Table 4-3 for four different
A
units. The figures for the BOOS techniques reflect the R&D costs that necessarily precede
the retrofit. All costs include the labor required to implement the control methods, and
are, therefore, installed equipment costs. The very low expense associated with overfire
air on the B&W 235 MW unit is due to the base year of the estimate (1964 - 1965) and to the
fact that this modification was included in the original boiler design.
The overfire air costs for the B&W 350 MW unit lie in the low range of the appropri-
ate band of costs in Figure 4-2. The LADWP boilers were, for the most part, modified without
much difficulty, and the associated costs probably represent the lower limits of the costs
for the three N0¥ reduction techniques implemented (Reference 4-6).
A
Data from the Babcock and Mil cox Co.
An additional indication that including NOX controls on newly designed units is more
economical than installing them on existing units comes from the Babcock and Wilcox Company.
Their designers have estimated that NOX control-related equipment (FGR and overfire air ports)
will account for about $2 of the total boiler cost per KW (Reference 4-7).
66
-------
TABLE 4-2. 1974 INSTALLED EQUIPMENT COSTS FOR EXISTING RESIDUAL OIL-FIRED UTILITY BOILERS
Unit Name
Pittsburg
#7
Pittsburg
#5 and #6
»
Contra Costa
#6 and #7
Portrero #3
Design Type
CE Tangentially-
fired, divided
•
B&W Opposed-fired
,
B&W Opposed-fired
RHey Turbo-fired
Year
on- Line
1972
1964
1965
1972
Capacity
(MW)
735
330 (each)
330(each)
300
Modification
Cost
($106)
4
5. 6 (both)
4.112(both)
2.5
$/KW
5.4
8.5
6.2
8.3
Type of Modification
Windbox FGR, Overfire Air
• 2 new 5000 HP FGR fans
• FGR ducting
• NOX port installation
• No new burner safeguard system; exist-
ing computerized 02 system
Windbox FGR, Overfire Air
t Transferred two FGR fans from other
units
• FGR ducting
• New hopper
• NOX port installation; one for each
burner column
• New burner safeguard system: computer,
NOx control board, Og controls on
dampers, flame scanners
Windbox FGR, Overfire Air
• New FGR fans (one each)
• Nominal amount of new ducting to
windbox
• NOX port installation
Windbox FGR, Overfire Air
• New FGR fan
• NOX port installation, nominal amount
of ducting
• New burner safeguard system, NOX con-
trol board, computer
at
-------
TABLE 4-3. LADWP ESTIMATED INSTALLED 1973 CAPITAL COSTS FOR
NOX REDUCTION TECHNIQUES ON GAS AND OIL-FIRED
UTILITY BOILERS
Unit
Capacity
(MW)
180
235
235
350
Unit
Type
C.E. tangen-
tial ly-fired
C.E. tangen-
tial ly-fired
B&W Opposed-
fired
B&W Opposed-
fired
NOx Reduction
Technique
BOOS
LEA
BOOS
LEA
BOOS
Overfire air
LEA
BOOS
Overfire Air
LEA
Implementation
Method
Retrofit
Retrofit
Retrofit
Retrofit
Retrofit
Original Design
Retrofit
Retrofit
Retrofit
Retrofit
Estimated
Cost
($)
60,000
25,000
65,000
25,000
65,000
14,000*
25,000
230,000
87,000
25,000
$/KW
0.33
0.14
0.28
0.11
0.28
0.06
0.11
0.66
0.25
0.07
*1964-65 base year
68
-------
Operating Cost Data
In addition to the Increased capital costs resulting from including a NOX reduction
system in a unit design, the increased unit operating costs must be considered. These dif-
ferential operating costs were defined for 100, 450, and 750 MW new design units and are
shown in Table 4-4 (Reference 4-2). The equipment costs shown are determined from Figure 4-1.
It should be noted that although the total annual cost increases with boiler size, the oper-
ating cost on a KWHR basis declines.
To put these operating costs in perspective, they can be compared to the "average"
generating costs shown in at the bottom of Table 4-4. Except for the case of water injection,
the differential in operating cost is below one percent even for flue gas recirculation.
Again, inflation factors must be applied to this 1973 cost data to bring it up to date.
Although the variance in coal price is wider at present than ever before, a reasonable average
value is taken to be $1.00/106 Btu. This causes a commensurate increase in the additional
annual fuel cost for water injection (Reference 4-8).
Summary
By way of summary, Table 4-5 gives the impact on major system components, efficiency,
and capacity when employing the major N0« control techniques. The relative changes in unit
design or efficiency are shown to increase (or require addition) by a plus (+) or a decrease
(-). If the item is unchanged, or is altered to a negligible extent, it is indicated by a
zero (0). Heat transfer surfaces remain unchanged in all cases (Reference 4-4).
The following are the major economic considerations that the boiler operator or
designer may be faced with (Reference 4-2):
t The lowest cost method for reducing NOX emission levels on new and existing
units is the incorporation of an overfire air system. Minimal additional costs
are involved.
• For most utility boilers, the second lowest cost NOX control method appears to
be the biased firing, or the "burners out of service" technique (BOOS). Although
lowering excess air (LEA) alone is less expensive than BOOS, one utility company
has found that when LEA is implemented concurrently with other control techniques,
the excess air levels must be increased beyond those normally required.
• Gas recirculation is significantly more costly to implement than overfire air
and requires additional fan power. In existing units, the necessity to reduce
unit capacity to maintain acceptable gas velocities through the boiler convec-
tive sections may impose an additional penalty.
t For coal-fired units, gas recirculation to the coal pulverizers would cost'ap-
proximately 15 percent less than windbox FGR; however, this may require in-
creased excess air to maintain adequate combustion. FGR 1s not particularly
effective 1n reducing NOX from coal-fired systems.
69
-------
TABLE 4-4. 1973 DIFFERENTIAL OPERATING COSTS OF NOX CONTROL METHODS FOR NEW TANGENTIALLY, COAL-FIRED UNITS (SINGLE FURNACE)
Control Method WM2W)
MW Rating 100 450 750
Equipment Costs3 10'$ 31 63 90
Annual Fixed Charge5 10'$ 5 10 14
Additional Annual Fuel
Costc io'$
Additional Annual Fan
Power Costa 10'$
Total Annual Cost6 10*$ 5 10 14
Operating Cost M111s/KWHRf Q.009 0.004 0.003 0
Notes:
aDe!1vered and erected equipment costs (+. 10% accuracy)
b5400 HR/YR at rated MW and net plant heat rate of 9400
G50*/10sBtu coal cost.
d$250/HP fan power cost, or $40/HP per year.
6 Annual fixed charge rate of 16%.
Operating costs are ± 10*.
9Does not Include cost of water piping 1n plant or cost
Wlndbox rn«K4»,n™ Coal Mill
Flue Gas Trfi «H » F1ue Gas
Redrc. (30X) of ] and z Redrc. (17*)
100 450 750 100 450 750 100 450 750
350 1185 1650 375 1248 1800 300 1015 1425
56 190 264 60 200 288 48 162 228
.__ -„- --- ... ... --- --- --- ---
21 95 158 21 95 158 22 100 166
77 285 422 81 295 446 70 262 394
.143 0.117 0.104 0.150 0.121 0.110 0.130 0.108 0.097
. Excluding contingency and Interest during construction.
Btu/KWHR
of makeup water.
Water
Injection
100 450 750
160 560 825
26 90 132
147 660 1099
13 58 97
186 808 1328
0.344 0.332 0.3279
Base unit operating costs* for coal fired power plants excluding SOg removal systems.
Unit Size MW 100 450 750
Operating Cost MILLS/KWHR 16.2 13.5 12.6
^Includes 1973 Capital costs, labor, maintenance, fuel costs +20% contingency + 17% Interest during construction.
-------
TABLE 4-5. IMPACT OF NOX CONTROL TECHNIQUES ON MAJOR UTILITY BOILER COMPONENTS
System
Component
Forced Draft
Fan Size
Secondary A1r
Ducts
Wind box Size
FGR Fan
FGR Ducts
Dust
Collectors
Coal
Pulverizers
Convective
Surface
Superheat
Surface
Reheat
Surface
Economizer
Surface
Boiler -
Efficiency
Capacity
O.A.a
+
0
0
N/Ae
N/A
0
0
0
0
-
0
0
0
a. Overfire air system
New
Unit Design
Sec. . Prim
FGRb a+b FGRC
0
+
+
. +
+
+
0
+
-
-
+
0
0
+ +
+ 0
+ +
+ +
+ +
+ +
0 0
+ +
-
-
+ +
0 0
0 0
Mater
Inj.d
0 or +
0
0
N/A
N/A
0
0
+
-
-
+
—
0
Existing
O.A.a
0 or +
0
0 or +
N/A
N/A
0
0 or +
N/A
N/A
N/A
N/A
0
0
Sec.
FGRb
0
•f
+
+
+
*
0
N/A
N/A
N/A
N/A
0
-
a+b
0 or
+
+
+
+
+
0 or
N/A
N/A
N/A
N/A
0
-
Units
Prim.
FGRC
+ +
0
+
+
+
*
+ 0
N/A
N/A
N/A
N/A
0
-
d. Water injection to the firing
b. Flue gas red rail at1 on through the secondary e. Not
air duct and windbox
compartments
c. Flue gas recirculation to
(primary air) of the
coal
the transport
Mater
Inj.d
0
0
0
N/A
N/A
0
0
N/A
N/A
N/A
N/A
—
-
zone
applicable
f. Average heat rate
air
, Btu/KWH
pulverizers (mils)
-------
• Water injection involves low initial equipment costs, but due to high operating
costs resulting from losses in unit efficiencies, it is the least desirable of the
systems evaluated. This method may also require reduced capacity.
• In general, the cost of applying any of the control methods to an existing unit
will be approximately twice that of a new unit design.
t Attention must be given to the base year in which control cost estimates were made.
The most recent figures on comparative electric power equipment costs from the
Marshall and Swift Equipment Cost Index (1974) indicate that such costs have in-
creased 19 percent from 1972 and 16 percent from 1973. It is safely estimated
that such costs will be correspondingly higher in 1975.
4.1.2 Costs of S02 Control by Flue Gas Treatment
Tables 4-6 and 4-7 contain capital and operating costs for five S02 control processes -
lime slurry scrubbing, limestone slurry scrubbing, magnesia scrubbing, sodium carbonate
scrubbing and catalytic oxidation (Reference 4-9). These five processes represent the most
advanced technology to date and have been proposed as the initial systems for full scale
installation. The effect of varying the sulfur content of the fuel on estimated costs is
relatively small. For an increase (or decrease) of one percent in the sulfur content of the
fuel, one must add (or subtract) 3-7 $/KW to the capital costs in Table 4-6 and 0.1 - 0.5 mils/
KWHR to the operating costs in Table 4-8 (except for the catalytic oxidation process, where
these incremental capital and operating costs are negligible).
It is instructive to compare these S02 control costs to the previously discussed costs
for control of NOX by combustion modification techniques. Figures 4-1 and 4-2 show that the
installed equipment costs incurred by implementing NOX reduction techniques are, for the most
part, an order of magnitude less than the costs of flue gas SOX removal equipment. A simi-
lar difference appears between operating costs (Table 4-4 vs. Table 4-7). The major portion
of the high S02 control system operating cost is the 15 percent of the total capital investment
as part of the annual indirect costs.
The estimated costs of other developed S02 control processes are comparable to those
shown in Tables 4-6 and 4-7. However, those processes which were found to be less effective
in removing sulfur oxides from flue gases or whose costs were estimated to be prohibitively
high are not included there. Possible future candidate processes (e.g., the Shell/UOP pro-
cess, the Chiyoda Thoroughbred 101 process, the Bergbau-Forschung process) appear to have
estimated costs somewhere in the range of costs given in Tables 4-6 and 4-7; however, these
candidate processes are still under development and have not as yet been fully demonstrated
on coal-fired boilers.
4.1.3 Costs of NOX Control by Flue Gas Treatment
Since most of the processes discussed in Section 3.4 are still in the early stages of
development, definitive costs are not available; however, preliminary cost estimates Indicate
72
-------
TABLE 4-6. 1975s INSTALLED EQUIPMENT COSTS FOR UTILITY BOILER FLUE GAS S02 REMOVAL
Unit Type
Coal -fired new units
(3.5% s in coal)
Coal -fired existing
units (3.5% S in coal)
Oil-fired new units
(2.5% S in oil)
Oil-fired existing unit
(2.5% S in oil)
Unit
Size
(MW)
200
500
1000
200
500
1000
200
500
1000
500
Costs include:
Lime Slurry
Scrubbing!*
$/KW
74
56
41
81
65
48
59
45
33
55
$/106BtuC
1.37
1.04
.76
1.50
1.20
.89
1.09
.83
.61
1.02
On-site solids
disposal of
CaS03/CaS04
Limestone
Slurry
Scrubbing!1
$/KW
81
63
48
71
58
44
51
39
29
46
$/106BtuC
1.50
1.17
.89
1.31
1.07
.81
.94
.72
.54
.85
On-site solids
disposal of
CaS03/CaS04
Magnesia
Scrubbing"
$/KW
89
66
49
90
65
49
55
40
30
51
$/106BtuC
1.65
1.22
.91
1.67
1.20
.91
1.02
.74
.56
.94
Regeneration
of S02 and
conversion to
H2S04
Sodium
Carbonate
Scrubbing!)
$/KW
101
76
58
108
78
60
65
48
36
61
$/106BtuC
1.87
1.41
1.07
2.00
1.44
1.11
1.20
.89
.67
1.13
Conversion to
Na2S04 and re-
generation of
S02/conversion
to elemental
sulfur
Catalytic
Oxidationb
$/KW
123
108
88
111
95
79
81
71
58
83
$/106BtuC
2.28
2.00
1.63
2.06
1.76
1.46
1.50
1.31
1.07
1.54
Particulate re-
moval before
flue gas enters
converter and
conversion to
H2S04
Note: aMid 1974 costs plus 25% escalation
"Ninety percent S0« removal assumed
cBased on 5400 hr/yr at rated MW and a net plant heat rate of 10"Btu/KWhr (Reference 4-3)
CO
-------
TABLE 4-7. 1975 DIFFERENTIAL OPERATING COSTS* FOR UTILITY BOILER FLUE GAS S02 REMOVAL
Unit Type
Coal -fired new
units (3.5% S
in coal)
Coal -fired
existing units
(3.5% S in coal)
Oil-fired new
units (2.5% S
in oil)
Oil-fired
existing unit
(2.5% S in oil)
Unit
Size
200
500
1000
200
500
1000
200
500
1000
500
Lime
Slurry
Scrubbing0
106$/yr
3.7
7.1
11.1
4.2
8.5
13.5
3.0
6.1
9.5
7.0
Mi1s/KwHrc
2.6
2.0
1.6
3.0
2.5
1.9
2.1
1.8
1.3
2.0
Limestone
Slurry
Scrubbing0
106$/yr
3.5
6.9
10.7
3.5
7.1
11.5
2.5
5.0
8.1
5.9
Mi1s/KwHrc
2.5
2.0
1.5
2.5
2.1
1.6
1.8
1.4
1.2
1.7
Magnesia
Scrubbing0
106$/yr
4.3
8.3
12.9
4.6
8.6
13.9
2.9
5.5
8.7
6.6
Mils/KwHrc
3.1
2.3
1.9
3.2
2.5
2.0
2.1
1.5
1.3
1.9
Sodium
Carbonate
Scrubbing0
106$/yr
5.3
10.3
16.3
6.6
13.1
22.3
3.8
7.4
12.2
9.1
Mils/KwHrc
3.8
2.9
2.3
4.7
3.7
3.2
2.8
2.1
1.8
2.6
Catalytic
Oxidation0
106$/yr
4.0
8.5
13.4
5.5
11.8
20.5
2.7
5.4
8.5
10.6
Mils/KwHrc
2.9
2.4
1.9
4.0
3.3
3.0
1.9
1.5
1.2
3.1
Note: aCosts exclude credit for byproducts (See Table 4-5.); includes 15 percent of total capital investment as part of annual indirect costs.
90 percent S02 removal assumed
cBased on 5400 Hr/Yr at rated MM and a net plant heat rate of 10" Btu/KwHr (Reference 4-3)
-------
that the capital and operating costs for the first three processes mentioned in Section 3.4
are comparable to those given in Tables 4-6 and 4-7:
• Equipment and operating costs for the Shell/UOP process are estimated to be very
close to those of the sodium carbonate process.
• Both capital and operating costs for the Chiyoda 101/102 process have been esti-
mated to be quite high (comparable to the highest costs in Tables 4-6 and 4-7).
• Estimates of the capital charges for the Bergbau-Forschung system show them to be
in the mid-range of values given in Table 4-6, whereas operating costs for this
system are estimated to be very high.
Preliminary cost analyses on some of the catalytic processes have been made by TRW
(Reference 4-10); however, those costs seem to be highly optimistic estimates, considering
the embryonic stage of development of these processes.
4.2 COMMERCIAL AND INDUSTRIAL BOILERS
Devices in this source sector include all boilers with a capacity greater than 106
Btu/hr and up to utility boiler size. These boilers provide process steam for industrial
applications (watertube design) and steam and hot water for comfort air heating and cooling
in commercial applications (firetube and small watertube).
Cost data for combustion modifications on these types of equipment are virtually non-
existent. Only the most broadly-based estimates are available to the boiler owner and oper-
ator at the present time. The most recent information of this kind was published by Bartz,
et al., in 1974 (Reference 4-11).
In Reference 4-11, the authors estimated that many boilers presently exceeding EPA
New Source Performance Standards (NSPS) could be modified to emit lower nitrogen oxides for
about $10,000 per boiler. For boilers with multiple burners this would probably be accom-
plished by reducing excess air and by staging the combustion process. This latter method,
accounting for the largest portion of the total cost, would be implemented by removing from
1/4 to 1/3 of the burners from service. Air flow would be maintained through the out-of-
service burners while the fuel flow to the remaining burners would be increased sufficiently
to maintain a constant total fuel flow. The burner tips on oil-fired boilers are usually
enlarged. Consequently, the active burners would then be supplied with insufficient air to
react with all the fuel, leading to the classical off-stoichiometric, or staged, combustion
condition.
In the case of boilers with one burner, this modification can be implemented by in-
stalling overfire air ports which bypass the burner between the windbox and the boiler. These
ports would carry 20 to 30 percent of the total air flow to the furnace volume. Again, the
cost of such an installation may be of the order of $10,000 per boiler. As for multiple
burner boilers, lowering excess air is assumed to entail negligible capital costs.
75
-------
If for the $10,000 capital cost estimate the maintenance and operational charges are
assumed to be small and the capital cost is annualized at 20 percent, the annual charge will
be $2,000. As a result of applying such modifications it is estimated that the emissions
from this category of boilers burning only natural gas could be reduced by 50 percent, the
emissions from those able to burn both gas and oil could be dropped by 35 percent, and the
emissions from those burning oil only could be reduced by 20 percent.
Research and development, including field testing and application of ML control
methods to this equipment cateogry, is still in its early stages. More accurate cost esti-
mates for these techniques are being developed as part of on-going and planned EPA studies.
4.3 INTERNAL COMBUSTION ENGINES
Cost estimates of N0« control tecniques for internal combustion engines are presented
in this section. Since few of these techniques have actually been implemented in full scale
operation, costs are derived first from any actual cost data available and secondly from
estimates based on equipment costs, overhaul and maintenance increases, fuel consumption
penalties, etc. Reciprocating engines are discussed immediately following and gas turbines
conclude the section.
4.3.1 Reciprocating 1C Engines
This section will outline costs to control N0« emissions for control techniques read-
ily available to users of stationary reciprocating engines. As discussed earlier, stationary
engines are unregulated for gaseous pollutants and, consequently, little data is available
for field-tested controlled engines, particularly for large (> 500 hp) engines. Sufficient
data exists, however, to give order of magnitude NOX control costs for the following engine
categories:
• Large (> 100 hp/cyl) natural gas, dual fuel, and diesel fueled engines.
• Small to medium (< 100 hp/cyl) diesel fueled engines
t Gasoline fueled engines (16-500 hp)
Costs for large (> 100 hp/cyl) stationary engines, whose emissions and potential reduc-
tions are presented in Section 3.1.3.1 can be estimated based on Reference 4-12 and informa-
tion supplied to Reference 4-13. These costs, however, relate to emission reduction achieved
by engines tested in laboratories rather than field installations. Reference 4-12 indicates,
nevertheless, that these data are representative.
In contrast to the large stationary engines, more published data exists for smaller
(< 500 hp) gasoline and diesel engines which must meet State (California) and Federal emission
limits for mobile applications. Stationary engines in this size range are versions of these
mobile engines. Therefore, costs can be estimated based on a technology transfer from mobile
applications to stationary service, keeping in mind that in some cases mobile duty cycles
76
-------
(variable load) can differ from stationary duty cycles (rated load) and, hence, costs (e.g.,
fuel penalties) associated with a control technique used in a stationary application may vary
from the mobile case.
Control costs for the three categories discussed above may include:
• Initial cost increases for control hardware and/or equipment associated with a
particular control (e.g., larger radiatior for manifold air cooling or more engines
as a result of derating)
t Operating cost increases which are either increased fuel consumption and/or
increased maintenance associated with NOX control system, and
• Combinations of initial and operating cost increases
4.3.1.1 Control Costs for Large (> 100 hp/cyl) Bore Engines
Table 4-8 lists differential cost considerations for control techniques available to
users of large stationary engines. Cost differentials presented in Table 4-8 may be related
to actual installations using baseline data presented in Table 4-9. In practice, these fig-
ures vary depending on the application, but, in general, these figures are representative of
the majority of applications. Basically, these controls involve an operating adjustment with
the exception of derating and manifold air cooling which would require hardware additions.
Derating is not a viable technique for existing installations unless additional units may be
added to satisfy total power requirements. These techniques are summarized as follows:
Control Cost Impact
retard increased fuel consumption
air-to-fuel changes increased fuel consumption
derate fuel penalty, additional hardware, and in-
creased maintenance associated with additional
units
manifold air cooling increased cost to enlarge cooling system, and
increased maintenance for cooling tower water
treatment
combinations of above initial, fuel, and maintenance
control techniques increases as appropriate
The impact of the above control costs may vary considerably given the following con-
siderations:
• Standby (< 200 hr/yr) application control costs are primarily a result of initial
cost increases due to an emission control, whereas continuous service (> 6000 hr/yr)
control costs are largely a function of fuel consumption penalties.
77
-------
TABLE 4-«, DIFFERENTIAL COSTS FOR HOX CONTROL TECWIQUES FOR LARGE BORE ENGINES
CO
Control
Retard
Air-to-fuel
Derate
Cooled inlet
•aiilfold air temperature
Initial
Increase by
bmep (uncontrolled)/
bmep (controlled)
Increase 1-2
percent of basic
price
Fuel
-bsfc increase
-bsfc Increase
-bsfc increase
Maintenance
Increase by
ratio of bmep
-20 percent
Comments
Maintenance nay be
required for early
replacement of valves.
Increased initial +
Maintenance for
additional units to
supply total hp require-
nt.
Increased maintenance
for cooling tower
Mater treatment.
-------
TABLE 4-9. TYPICAL BASELINE COSTS FOR LARGE (>100 HP/CYL) ENGINES*
Costs
1. Initial ,b $/hp
2. Maintenance i
$/hp-hr
3. Fuel and lube,
$/hp-hr
Total Operating,
2 + 3
Gas
130
0.003
0.008
0.011
Dual Fuel
130
0.003
0.0077
0.0107
Diesel
130
0.003
0.0173
0.0203
Based on Reference (4-12) and Information supplied to
.Reference (4-13) by manufacturers.
"includes basic engine and cooling system.
Reference 4-13.
79
-------
t Controls which require additional hardware with no associated fuel penalty (e.g.,
manifold air-cooling) may be more cost effective in continuous service (> 6000)
hr/yr) than operating adjustments which impose a fuel penalty (e.g., retard, or air-
to-fuel change).
• The price of fuel can affect the impact of a control which incurs a fuel penalty.
For example, a control which imposes a fuel penalty of 5 percent for both gas and
diesel engines has more impact on the diesel fueled engine because diesel oil
costs $2.20/106 Btu compared to $1.00/10S for natural gas. This impact may dimi-
nish if gas prices increase or gas prices increase more rapidly than oil prices
(either is likely).
4.3.1.2 Control Costs for Small and Medium Gasoline and Diesel Fueled Engines
Control costs for these engines can be characterized by those incurred to meet State
and Federal emission limits for automotive vehicles. Again, these costs consist of initial
purchase price increases for control hardware and increased operating costs (fuel and mainte-
nance cost increases).
Table 4-10 lists typical costs for techniques implemented for 1975 diesel fueled truck
engines. These costs are presented to indicate order of magnitude effects. More research is
required to relate specific emission control reductions to initial and operating cost in-
creases for stationary engine applications.
Table 4-11 gives control hardware costs to meet gasoline-fueled passenger vehicle
emission limits through 1976. Note that cost increases correspond to increasingly more com-
plex controls to meet more stringent emission limits.
Figure 4-3 illustrates the effect of various control techniques on fuel economy. Fuel
cost increases can be easily derived from typical gasoline costs, presently $0.45 - 0.55/
gallon. In addition to this operating expense, control techniques utilizing catalysts and
EGR require periodic maintenance.
Manufacturers, in addition, incur certification costs for gasoline and diesel fueled
engines which must meet State and Federal regulations. These costs are passed on to the
user in the form of increased initial costs. Manufacturers of diesel fueled engines report
these costs range from $50,000 to $100,000 for a particular engine family. This can result
in a $125 cost per engine based on a low sales volume family .
4.3.2 Gas Turbines
This section discusses the economic considerations for reducing NOX emissions from
stationary gas turbines by way of combustion modification. Cost considerations for exhaust
Based on information supplied by manufacturers to Reference 4-13.
80
-------
TABLE 4-10. TYPICAL CONTROL COSTS FOR DIESEL FUELED ENGINES USED IN HEAVY DUTY (>6000 LB)
Vehicles3
Initial
engine $30-50/hp
baseline
cooling system 8-14% engine
turbocharger $3/hp
aftercooler 6-10% engine
EGR $2-3/hp
Operating
Fuel: Fuel penalties range from 3 to 8 percent for various techniques.
Typical present fuel cost: $0.35/gallon #2 diesel or $1.75 -
2.25/1O6 Btu
Maintenance: EGR system will require periodic cleaning. Note that turbocharged,
aftercooled engines require additional maintenance for the turbo-
charger and aftercooler compared to a similarly rated naturally
aspirated version.
Based on information supplied to Reference 4-13 by manufacturers.
81
-------
TABLE 4-11.
ESTIMATES OF STICKER PRICES FOR EMISSIONS
HARDWARE FROM 1966 UNCONTROLLED VEHICLES
TO 1976 DUAL-CATALYST SYSTEMS (REFERENCE 4-14).
Model
Year
1966
1968
1970
1971-
1972
1973
Configuration
PCV-Crank Case
Fuel Evaporation
System
Carburetor Air/Fuel Ratio
Compression Ratio
Ignition Timing
Transmission Control
System
Total 1970
Anti-Dieseling
Solenoid
Thermo Air Valve
Choke Heat By-Pass
Assembly Liae Tests,
Calif (1/10 vol)
Total 1971-72
OSAC (Spark Advance
Control)
Transmission Changes
(some models)
Induction Hardened Valve
Seats (4 and 6 cyl)
EGR (11 - 14%)
Exhaust Recirculation
Air Pump — Air
Injection System
Quality Audit, Assembly
Line (1/10 vol)
Total 1973
Typical Hardware
Value
Added
1.90
9.07
0.61
1.24
0.61
2.49
3.07
2.49
2.74
0. 18
0.48
0.63
0.72
5.48
27. 16
0.23
List
Price
2.85
14.25
0.95
1.90
0.95
3.80
4.75
3.80
4.18
0.57
0.95
0.95
1.90
9.50
43.32
0.38
Excise
Tax
0. 15
0.75
0.05
0. 10
0.05
0.20
0.25.
0.20
0.22
0.03
0.05
0.05
0. 10
0.50
2.28
0.02
Sticker
Price
3.00
15.00
1.00
2.00
1.00
4.00
8.00
5.00
4.00
4.40
0.60
14.00
1.00
1.00
2.00
10.00
45.60
0.40
60.00
82
-------
TABLE 4-11. (Continued)
Model
Year
1974
1975
1976
Configuration
Induction Hardened
Valve Seat V-8
Some Proportional EGR
(1/10 vol at $52)
Precision Cams, Bores.
and Pistons
Pretest Engines —
Emissions
Calif. Catalytic Converter
System (I/ 10 vol at $64)
Total 1974
Proportional EGR
(acceleration-
deceleration)
New Design Carburetor
with Altitude
Compensation
Hot Spot Intake Manifold
Electric Choke (element)
Electronic Distributor
(pointless)
N«w Timing Control
Catalytic — Oxidizing-
Converter
Pellet Charge (6 Ib at
$2/lb)
Cooling System Changes
Underhood Temperature
Materials
Body Revisions
Welding Presses
Assembly Line Changes
End of Line Test
Go/No-Go
Quality Emission Test
Total 1975
2 NO Catalytic Converters2
Electronic Control2
Sensors2
Total 1976
Typical Hardware
Value
Added
0.72
3.21
2.44
1.80
4.02
20.07
7.52
2.87
2.67
4.35
!.49
18.86
12.00
1. 17
0.63
0.67
0. 13
1.85
1.22
22.00
28.00
3.00
List
Price
1.90
4.94
3.80
2.85
6.08
30.02
14.25
4.75
4.75
9.50
2.S5
34.20
20.52
1.90
0.95
1.90
0.95
2.85
1.90
37.05
47.50
5.70
Excise
Tax
0. 10
0.26
0.20
0. 15
0.32
1.58
0.75
0.25
0.25
0.50
0.15
1.80
1.08
0. 10
0.05
0. 10
0.05 '
0. 15
0. 10
1.95
2.50
0.30
Sticker
Price
2.00
5.20
4.00
3.00
6.40
20.60
31.60
15.00
5. 0*0
5.00
10.00
3.00
36.00
21.60
2.00
1.00
2.00
1.00
3.00
2.00
138.20
39.00
50.00
6.00
134.00
a!976 moat common configuration
83
-------
NOX - GM/MI.
(DETERMINED ON
CVS TEST)
1.5 -
1.0
0.5
0 10 20 30 40
FUEL ECONOMY - % LOSS FROM BASELINE CVS
§
I
LTR
LTR
LTR
LTR
RTR
RTR
RTR
RTR
SYSTEM AND SOURCE
+ EGR (ETHYL PLYMOUTH)
*
EGR ETHYL PLYMOUTH)
EGR ETHYL PONTIAC)
EGR ETHYL PONTIAC)
EGR DUPONT CKEV)
EGR RECENT OUPOKT SYSTEM)
EGR ESSO PAM)
EGR (ESSO RAM)
RTR + EGR + HC/CO CAT CONV
(FORD "MAXIMUM EFFORT" VEH)
RTR * EGR + HC/CO CAT CC.'IV
(FORD "MAXIMUM EFFORT" VEH)
RTR + EGR + HC/CO CAT CONV
(FORD "MODIFIED MAX EFFORT" VEH)
RTR + EGR (CHRYSLER)
HC/CO CAT CONV + EGR
(FORD PACK "B")
DUAL CAT CONV + EGR
(FORD PACK "C")
GENERAL CORRELATION
DRIVING SCHEDULE
CITY
CITY - EXPRESSWAY
CITY
CITY - EXPRESSWAY
CARB CAR POOL
NOT SPECIFIED
TURNPIKE
CITY
CITY - SUBURBAN
CVS CHASSIS DYNA
CVS CHASSIS DYNA
NOT SPECIFIED
CVS CHASSIS DYNA
CVS CHASSIS DYNA
ESTIMATED FOR ADDITION OF NOX CATALYST
BED AT 75 PERCENT EFFICIENCY
I
I
I
S 10 IB 20 25 30
PERCENT SFC INCREASE (OVER UNCONTROLLED VEHICLE)
35
Figure 4-3.*
Effect of N0y emissions level on fuel penalty.
(Reference 4-15)
-------
gas cleanup are not presented since that technique is not considered a viable means of NOX
reduction for stationary units.
The most recent cost studies on NOX controls for gas turbines have been performed by
Aerospace (Reference 4-14) and EPA (Reference 4-16). In the absense of any nationwide limi-
tation on NOx emission levels, very little data exist relative to actual costs. The smaller
capacity gas turbines, as was previously cited, may very well be capable of NOX levels below
proposed standards without the installation of wet controls, whereas the larger units almost
universally will require either water or steam injection and possibly some minor combustor
modifications.
As input to the Aerospace study, San Diego Gas and Electric provided their investment
costs for water injection retrofit to three units as presented in Table 4-12. These costs
are based on a baseline investment cost of an uncontrolled simple cycle turbine of about
$80-100/Kw and an operational cost of 20-24 mils/kw hour for intermediate loads (6000
hours per year; fuel costs of 80tf/106Btu). In this example, the incremental investment
costs for water injection can be as high as 10% for the 20 MW plant and as low as 6% for
the 49 and 81 MW plants. Investment and operating costs for steam injection are generally
accepted to be higher than water injection unless superheated steam is available on-site.
A comparison of investment and operating costs for both water and steam injection as a func-
tion of turbine size is presented in Table 4-13. Wet control costs are seen to be prohibitive
for the turbines of smaller size but, in general, wet controls will not be required by these
units to effectively reduce emission levels below proposed standards. Noting that operating
costs decrease as a function of both turbine size and load factor, it is conceivable that the
base loading with a 65 MW unit operational cost could be as low as 2.5%.
A more extensive breakdown of the costs for wet and dry controls has been assembled
by EPA in support of proposed emission standards. Table 4-14 presents the cost of N0« con-
trol for small gas turbines. The table illustrates the cost of dry controls for two units,
a 350 hp and a 3500 hp unit, and the cost of wet controls for the 3500 hp turbine. Although
it is assumed that most of the smaller capacity units will be sufficiently controlled by
dry control to exclude the use of wet controls, it is not certain that the larger capacity
small turbines (50 M Btu) will not require water or steam injection; therefore, estimates
are included for both methods of control. Operating costs vary from 17% for the standby
350 hp turbine to a low of 1.3% for the 8000 hr/year 3500 hp dry controlled unit. Table
4-15 presents similar cost estimates for large gas turbines equipped with water injection.
Again these are costs provided by San Diego Gas & Electric to EPA. Costs here do not in-
clude on-site personnel since controls were designed to operate automatically on the gener-
ally unattended turbine.
85
-------
TABLE 4-12. WATER INJECTION INVESTMENT COST
(SAN DIEGO GAS AND ELECTRIC)
Control System
Combustor modifications
including water injection
nozzles
Water injection pumps and
water regulation system
Associated piping and
water storage facilities
Water treatment equipment
General expenses including
engineering, administration,
testing taxes
TOTAL
Gas Turbine Size
20 MW
$1 .00/kw
$3.54/kw
$1 .72/kw
$0.90/kw
$1.15/kw
$8.31/kw
49 MW
$0.86/kw
$2.88/kw
$1 .05/kw
$0.47/kw
$0.82/ kw
$6.07/kw
81 MW
$1 .047 kw
$3.10/kw
$0.87/ kw
$0.47/kw
$0.57/kw
$6. 05/kw
TABLE 4-13. WATER/STEAM INJECTION COST AS A
FUNCTION OF POWER PLANT SIZE
MW Output
0.26 (350 hp)
2.90 (3900 hp)
20.00
33.00
65.00
Investment
Cost,
Percent
Baseline
Water
100.0
18.0
10.0
7.3
7.3
Steam
150.0
24.0
12.0
10.6
10.6
Operational
Cost,
Percent
Baseline
Water
55.0
6.5
6.0
5.7
5.7
Steam
165
32
—
—
—
*For peaking gas turbine, 1000 hour/year
86
-------
23
TABLE 4-14. 1974 ESTIMATED COSTS OF NOX CONTROLS FOR SMALL
GAS TURBINES (REFERENCE 4-16)
Size, hp 350 3,500 3,500
Purchase cost (PC), uncontrolled
Total installed cost (TIC), 1.3xPC
Total capital investment (TCI), 1.25XTIC
Control increment, percent
TCI, controlled
Unit investment, controlled, $/hp
Heat rate, Btu/hph
Equivalent hours duty per year
Fuel @ $0.91/MBtuC
Fixed charges, uncontrolled
Total annual cost, uncontrolled
Utilities6
Incremental fixed charges
Total annual cost, controlled
Control cost, percent-
8,800
11,400
14,300
Dry 20
17,200
49
12,000
1003 8,000b
380 30,600
2,600 2,600
3,000 33,200
520 520
3,500 33,700
17 1.6
110,000
143,000
178,800
Dry 12
200,000
57
11,000
100 8,000
3,500 280,300
32,200 32,200
35,700 312,500
3,900 3,900
39,600 316,400
11 1.3
110,000
143,000
178,800
Wet 25
224,000
64
11,000
100 8,000
3,500 280,300
32,200 32,200
35,700 312,500
12 1,000
8,000 8,000
43,700 321,500
22 2.9
Notes:
As in emergency service, including readiness tests
As in pipeline service
°In the pipeline application, fuel from the line would be much less expensive
Carrying charges 17 percent, maintenance 1 percent
eRaw water, regeneration chemicals, and power together assumed $1/1000 gallon
-------
TABLE 4-15. 1974 ESTIMATED COSTS OF WET NOX
GAS TURBINES (REFERENCE 4-16)
CONTROLS FOR LARGE
Size, MW
Capital costs in thousands of dollars:
Total capital Investment (TCI)a, uncontrolled
Equivalent hours duty per year
Water/ fuel ratio h
Control increment, percent
TCI, controlled
Unit investment, controlled, $/kw
Annuali zed costs in thousands of dollars:
Heat rate, Btu/kwh
Fuel @ $0.91/MBtu d
Fixed charges, uncontrolled
Total annual cost, uncontrolled
Utilitiese
Incremental fixed charges
Total annual cost, controlled
Incremental annual cost, percent
8000
0.5
10.0
3120
125
2260
504
2764
9
57
2830
2.3
Notes: aApply1ng to the 25 MW case, the 1970 Federal Power
25
2800
1000
0.5
8.5
3040
121
12400
282
504
786
1
43
830
5.6
Survey datum of
5 percent compounded, and assuming a weak economy of scale for the
Wet controls Include an Injection system sized for
peak injection
1000
0.8
9.5
3070
123
282
504
786
2
49
837
6.5
4000
0.5
3.9
27000
104
11070
4670
15740
40
180
15960
1.4
$85/kw, escalating
larger case.
rate.
cln the 8000-hour case representing a pipeline compressor, fuel from the line would be
Carrying charges 17 percent, maintenance 1 percent
eRaw water, regeneration chemicals, power and sewerage together at
$1/1000 gallons.
4x65
26000
1000
0.5
3.5
26900
103
11700
2770
4670
7440
10
160
7610
2.3
from 1968
much less
1000
0.8
3.9
27000
104
2770
4670
7440
16
180
7640
2.6
to 1974 at
expensive.
-------
A cost effectiveness summary 1s presented in Table 4-16 and illustrates the relation-
ship between control costs and resultant NOX levels. Note that using the given reduction
assumptions, the 3500 hp unit with dry controls only would not meet the present San Diego
County standards of 42 and 75 ppm NOX @15 percent oxygen for gas and liquid fuels, respectively.
In summary, the primary economic considerations in controlling NOX from gas turbines
are:
• Wet controls are by far the most expensive means of NOX control, but they are
presently the only adequate means for the large units (> 50M Btu).
• Dry controls are the most desirable in terms of cost but alone are applicable only
to the smaller units (< 50M Btu). These controls may not be sufficient for those
units approaching 50M Btu in size.
• Incremental operating costs decrease as loading factor and size Increase. Incre-
ments as low as 1.3% are shown.
4.4 COMMERCIAL AND RESIDENTIAL HEATING
This section discusses the economic considerations in reducing bulk emissions from
both commercial and residential space heating units for the three presently applicable stra-
tegies presented in Section 3.1.4:
t Tuning
• Burner replacement
t Unit replacement
A scan of several service organizations across the country indicates that the tuning
procedure consists of cleaning, leak detection, sealing, and flame adjustment using the "eye-
ball" technique. None of the service companies contacted offered the instrumented tuning
described in Section 3.1.4, but some were aware of this method and believed it would be avail-
able in the near future at a substantially higher cost than the present service. The pre-
sently available tuning procedure costs a minimum of $45 for the average residential unit
while cost increases with unit size, necessary replacement parts, and abnormal time require-
ments .
Burner replacement in residential units is considered an uncommon practice by service-
men since new burner costs, installation labor cost and furnace life expectation on the order
of 10 to 15 years make burner replacement very costly. New burners cost a minimum of $35, and
when added to total installation costs (labor and adjustment) at approximately $20 per hour
for two hours minimum, the burner replacement costs at least $75. Burner replacement in some
cases may not be effective in reducing emissions and, in fact, could possible increase pol-
lutant production if furnace-burner compatibility is not determined prior to installation.
This amount would not seem to be cost effective for residential units, but the emergence of
89
-------
TABLE 4-16. COST-EFFECTIVENESS SUMMARY (REFERENCE 4-16)
10
o
Scale
350 hp
3500 hp
3500 hp
25 MM
4x65 MM
Fuel
Gas
Oil
Gas
Oil
Oil
Gas
Oil
Gas
Oil
NO/ Concentration, ppmv
Uncontrol 1 ed Control 1 eda
60 42
90 68
70 49
110 83
110 37b
W/F = 0.5 0.8
160 54 36
220 74 50
200 67 45
260 88 59
Method
Dry
Dry
Dry
Dry
Wet
Wet
Wet
Wet
Wet
Incremental Unit Cost
1.6% in pumping service
1.3% in pumping service
2.9% in pumping service
W/F = 0.5
5.6% to 6.5%
in peaking service
2.3% to 2.6%
in peaking service
Notes:
a Assuming 25 percent reduction for oil, 30 percent for gas, with dry controls.
Assuming 25 percent, attributable to the dry controls incorporated with wet controls, compounded by
further reductions of 55 percent at W/F = 0.5, 70 percent at W/F = 0.8.
b At W/F = 0.5
-------
new low emission burners and the promulgation of NOX emission restrictions could make this
the most attractive control alternative. Commercial burner replacement is a more common
practice owing to the characteristically higher unit costs and the longer life expectancies.
Unit replacement strictly for emission control is not cost effective; however, esti-
mates for replacement are included for units in poor condition or units in need of extensive
repair. Table 4-17 provides estimates for residential and commercial unit replacement costs.
4.5 ADDITIONAL COST DATA REQUIREMENTS
While this report has attempted to present general cost estimates of NOX control tech-
niques for the primary stationary source equipment categories, there exists a further require-
ment for the collection of a substantially more extensive data base from which estimates can
be made. The utility boiler category comprises the bulk of published cost information since
this equipment type bore the initial thrust of NOX control technology. Only recently have
the remaining equipment categories been subject to pilot or full scale testing, and therefore
extensive cost data is not yet available. This section indicates the equipment categories
and which equipment types therein require further generation of economic data for future NO
control cost estimates. An important point to remember is that all published economic data
no matter how extensively presented, will only provide general guidelines to those decision
makers considering the implementation of the various control techniques. Actual costs must
be determined on a unit-by-unit basis.
4.5.1 Utility Boilers
A relatively large quantity of data on the economics of NOX control technology presently
exists for utility boilers. However, this information is generally diffuse in nature since
it is derived from many sources. In addition, much of the potentially valuable cost figures
are proprietary, residing with individual electric utility companies. Further insight into
the cost-effectiveness of modifying a utility boiler combustion process will be gained by
satisfying the following requirements:
• Compilation of more complete information on the costs of installing a flue gas
recirculation system on "typical" existing units for all three conventional fuels.
• Acquisition of additional data on the installed equipment costs of off-stoichio-
metric combustion techniques.
• Acquisition of information on all aspects of differential operating costs associated
with each control technique.
t Preparation of "case studies" of individual utility companies that have used com-
bustion modification techniques in order to give a profile of user experiences.
91
-------
TABLE 4-17. TYPICAL COSTS OF GAS FIRED SPACE HEATING UNITS
(REFERENCE 4-17)
Capacity
35,000 Btu
65,000
100,000
300,000
750,000
Floor Furnaces
225-245
270-290
-
-
-
Forced Air*
-
395-450
460-530
670-780
-
Space Heaters
380 suspended
450 suspended
925 floor
2400 floor
5150 floor
*Add }$% for oil or coal firing.
92
-------
4.5.2 Industrial Boilers
As for most of the other equipment types, there is a general lack of cost data associ-
ated with combustion modification techniques implemented on industrial-size boilers. It is
anticipated that this data base will be augmented by ongoing EPA-sponsored boiler field tests.
At this time, however, the information gaps are large. In order to present a more complete
picture of the feasibility of combustion modification techniques to the boiler operator and/
or owner, the following cost data must be generated:
• For multiburner boilers, the installed equipment costs of off-stoichiometric com-
bustion techniques and the applicability and installed equipment costs of a flue
gas recirculation system
• The installed equipment costs of low excess air firing on all boiler types
• Differential operating costs (e.g., increased fuel consumption) of all techniques
implemented on all applicable boiler types
4.5.3 Internal Combustion Engines
This equipment sector consists of both reciprocating 1C engines and gas turbines. In
contrast to reciprocating engines which have such a diversity of equipment combinations, gas
turbine equipment combinations are relatively uncomplicated. In view of this difference,
reciprocating engine economics are generally presented in terms of engine capacity and/or fuel
where gas turbines are discussed by equipment type and/or capacity.
4.5.3.1 Reciprocating Engines
Further cost analyses for reciprocating 1C engines are recommended in the following
capacity/fuel combinations:
• DEMA (> 100 hp/cyl)
- present cost estimates derive from the manufacturers experimental in-house units;
future data must be compiled from field units particularly regarding cost and
control tradeoff in the retrofit unit
— Cost data must be generated first for specific controls and then for various con-
trol combinations and their relationship to control effectiveness
• Mid-Power Engines - almost no cost data for stationary units in this capacity range
exists at the present time
- the bulk of the cost information deals with diesel fueled truck applications
however the contrasting load cycles and less restrictive packaging requirements
of stationary installations do not lend to accurate cost data transfer. Data
must be generated from stationary units.
93
-------
-gas fueled units require the entire cost analyses spectrum as essentially no
data exist for stationary installations.
— individual and combinations of control cost data versus control effectiveness
must be determined for all equipment categories.
• Small Gasoline Engines - here again, little data exist for stationary application
and cost transfer from mobile units is not effective. Essentially all economic
aspects of control costs must be investigated in this capacity/fuel range.
4.5.3.2 Gas Turbines
Gas turbine cost data, although more complete than those of reciprocating engines, is
lacking in the following areas:
• Utility Applications
— specific cost data exist on wet control techniques from an actual on-site appli-
cation but typical costs cannot be assumed from one installation. As wet con-
trols come Into more common usage, detailed cost analyses must be undertaken..
— No on-site cost data exist for dry controls in utility turbines.
0 Equipment Classifications
— open cycle turbines encompass the majority of any existing economic data.
Further information is required for on-site wet controls and a complete cost
analysis is needed for dry controls as they emerge.
— Regenerative cycle turbines again require economic data covering the entire
range of applicable controls.
-Combined cycle installations are just recently gaining in popularity and conse-
quently cost information is scarce.
— As wet and dry controls become more common, control cost-control effectiveness
relationships must be determined for all classes of equipment.
4.5.4 Space Heating
The space heating sector cost data base for NOX control techniques suffers from lack of
control implementation in the commercial heating segment and absence of viable NOX control
techniques in the residential segment.
• Commercial Space Heating
- some cost information from industrial boilers may be applicable on the upper
capacity range but contrasting duty cycles Introduce uncertainty in the cost
data transfer.
94
-------
— detailed economic analyses are recommended for all aspects of commercial space
heating NOX control.
Residential Space Heating — the present control strategy within the sector is the
overall reduction of unit emissions since compatible NOX controls remain to be de-
veloped. Cost analyses must be performed for the present strategies until specific
NOX controls emerge.
95
-------
REFERENCES
4-1 Bartok, W., et al.. "Systems Study of Nitrogen Oxide Control Methods for Stationary
Sources -Volume II," Prepared for NAPCA, NTIS No. PB 192-789, 1969.
4-2 Blakeslee, C. E., A. P. Selker, "Program for Reduction of NOX from Tangential Coal-
Fired Boilers, Phase I," Environmental Protection Technology Series, EPA-650/2-73-005,
August 1973.
4-3 National Coal Association, "Steam Electric Plant Factors," 1130 17th NW, Washington,
D.C., 1972.
4-4 Lachapelle, D. G., J. S. Bowen, R. D. Stern, "Overview of the Environmental Protection
Agency's NOX Control Technology for Stationary Combustion Sources," Presented at 67th
Annual Meeting, AIChE, December 1974.
4-5 Interview of Mr. J. Peregoy of the Pacific Gas and Electric Company, 17 Beale St., San
Francisco, CA., February, 1975.
4-6 Letter from the Los Angeles Department of Water and Power, May 5, 1975.
4-7 Telephone interview of Mr. J. Johnston, The Babcock and Wilcox Co., San Francisco, CA.,
March 3, 1975.
4-8 "Weekly Energy Report," January 6, 1973.
4-9 McGlamery, G. G., R. L. Torstrick, "Cost Comparisons of Flue Gas Desulfurization Systems,"
Presented at EPA's Flue Gas Desulfurization Symposium, Atlanta, Georgia, November, 1974.
4-10 Koutsoukos, E. P., et al., "Assessment of Catalysts for Control of NOx from Stationary
Power Plants, Phase I, Volume I — Final Report," Environmental Protection Technology
Series, EPA-650/2-75-001a, January, 1975.
4-11 Bartz, D. R., et al.. "Control of Oxides of Nitrogen from Stationary Sources in the
South Coast Air Basin," prepared for the California Air Resources Board, September, 1974.
4-12 The American Society of Mechanical Engineers (ASME), "Power Costs, 1974 Report on Diesel
and Gas Engines," March 1974.
4-13 Acurex Corporation, Preparation of a Standards Support Document for New Stationary
Reciprocating Internal Combustion Engines, EPA Contract No. 68-02-1318, Task No. 7.
4-14 Aerospace Corporation, "Assessment of the Applicability of Automotive Emission Control
Technology to Stationary Engines," p. 5-23, EPA-650/2-74-051, July 1974.
4-15 Calspan Corporation, "Technical Evaluation of Emission Control Approaches and Economics
of Emission Reduction Requirements for Vehicles Between 6000 and 14000 Pounds GVW,"
EPA-460/3-73-005, November 1973.
4-16 Durkee, K., E. A. Noble, F. Collins and D. Marsland, "Draft of Standards Support Docu-
ment for an Investigation of the Best System of Emission Reduction for Stationary Gas
Turbines," Office of Air Quality Planning and Standards, Environmental Protection Agency,
Research Triangle Park, North Carolina, August 1974.
4-17 Marshall Valuation Service, Marshall and Swift Publication Co., Los Angeles, California.
96
-------
APPENDIX A
A numerical ranking by NOX production is presented for the 137 equipment/fuel combi-
nations as discussed in Section 2.1. Estimates are believed to be fairly accurate for the
top 30 or so sources which comprise greater than 80 percent of the total emissions. The pro-
portionate error undoubtedly increases whicle progressing to the minor sources so that the
numerical ranking of the very minor sources is qualitative at best.
The sources at the end of the list were not given numerical rankings because they are
regarded as negligible, or emission data was not available. Mixed fuel firing is included in
the not available category even though its use is prevalent. This is because fuel consumption
data is reported in terms of constituent fuel only without regard to whether it is fired
singly or mixed with another fuel. A number of other equipment/fuel types could be listed in
the negligible category.
It is emphasized that a high source placement in the emission rankings does not neces-
sarily mean that individual units are high emitters. Rather, the sources may have relatively
low emission factors, but a high placement due to the large number of installed units of that
type. Such is the case, for example, for tangential coal fired utility boilers. These units
are of a fairly standard design and were not subdivided into design types, as was necessary
for wall fired utility boilers. It is also emphasized that sources on this list are con-
fined to controllable types of processes and exclude such things as forest fires and open
burning.
Rankings are presented in the following Table A-l.
97
-------
Table A-1., ESTIMATED 1972 NOX EMISSIONS FROM STATIONARY SOURCES
RANKING OF NOX EMISSIONS BY EQUIPMENT TYPE AND FIRING TYPE
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
23r-
Sector/Equipment Type/Fuel
1C Engines, Spark Ignition, Gas Fired
Utility Boiler, Tangential Firing, Bituminous Coal
Utility Boiler, Cyclone Firing, Bituminous Coal
Utility Boiler, Horizontally Opposed Wall Firing, Gas
Utility Boiler, Horizontally Opposed Wall Firing, Dry
Bottom, Bituminous Coal
Utility Boiler, Front Wall Firing, Dry Bottom,
Bituminous Coal
Utility Boiler, Front Wall Firing, Gas
1C Engine, Diesel, Oil and Dual Fuels
Utility Boiler, Horizontally Opposed Wall Firing, Wet
Bottom Bituminous Coal
Utility Boiler, Front Wall Firing, Wet Bottom,
Bituminous Coal
Utility Boiler, Horizontally Opposed Wall Firing,
Residual Oil
Utility Boiler, Front Wall Firing, Residual Oil
Industrial Boiler, Bent Tube Wall Fired Packaged
Watertube, Residual Oil
Industrial Boiler, Firetube Wall Fired Packaged Scotch,
Residual Oil
Utility Boiler, Tangential Firing, Residual Oil
Gas Turbines, Gas Fired
Industrial Boiler, Front Wall Firing Field Erected
Watertube, Residual Oil
Industrial Boiler, Horizontally Opposed Wall Firing
Field Erected Watertube, Residual Oil
Utility Boiler, Tangential Firing, Gas
Industrial Boiler, Bent Tube Wall Fired Packaged
Watertube, Gas
Industrial Boiler, Stoker, Spreader Field Erected
Watertube, Coal
Utility Boiler, Vertical Firing, Bituminous Coal
Gas Turbine, Oil Fired
EstTPYxlO6
1.873
1.388
0.730
0.568
0.412
0.412
0.393
0316
0306
0302
0.271
0.271
0.2064
0.1924
0.177
0.172
0.165
0.165
0.153
0.139
0.136
0.127
0.119
Percent
of Total
16.06
11.90
6.26
4.87
3.53
3.53
337
2.71
2.62
2.59
232
232
1.77
1.65
1.52
1.47
1.41
1.41
131
1.19
1.17
1.09
1.02
Cumulative
Percent
27.96
34.22
39.09
42.62
46.15
49.52
52.23
54.85
• 57.44
59.76
62.08
63.85
65.50
67.02
68.49
69.90
7131
72.62 .
73.81
74.98
76.07
77.09
98
-------
Table A-1. ESTIMATED 1972 NOX EMISSIONS FROM STATIONARY SOURCES -
RANKING OF NOX EMISSIONS BY EQUIPMENT TYPE AND FIRING TYPE (Continued)
24.
25.
26.
27.
28.
29.
30.
31.
32.
33.
34.
35.
36.
37.
38.
39.
40.
41.
42.
43.
44.
Sector/Equipment Type/Fuel
Nitric Acid Production
Process Heating, Glass Manufacture
Residential Heating, Hot Air Furnace, Distillate Oil
Residential Heating, Hot Air Furnace, Gas
Industrial Boiler, Tangential Firing, Field Erected
Watertube, Residual Oil
Petroleum Catalytic Crackers (FCC)
Residential Heating, Steam or Hot Water, Distillate Oil
Industrial Boiler, Horizontally Opposed Wall Firing
Field Erected Watertube, Gas
Industrial Boiler, Bent Tube Wall Fired Field Erected
Watertube, Residual Oil
Industrial Boiler, Stoker, Underfeed, Field Erected
Watertube, Coal
Industrial Boiler, Firetube Wall Fired Packaged Fire
Box, Residual Oil
Industrial Boiler, Stoker, Underfeed, Packaged
Watertube, Coal
Industrial Boiler, Front Wall Firing, Field Erected
Watertube, Gas
Process Heating, Cement Kilns, Coal Fired
Process Heating, Cement Kilns, Gas Fired
Commercial Boiler, Firetube Wall Fired Packaged
Scotch, Residual Oil
Commercial Boiler, Firetube Wall Fired Packaged
Firebox, Residual Oil
Industrial Boiler, Bent Tube Wall Fired Field Erected
Watertube, Gas
Industrial Boiler, Firetube Wall Fired Packaged Scotch,
Gas
Industrial Boiler, Stoker Spreader Packaged Watertube,
Coal
Residential Heating, Steam or Hot Water, Gas
Est.TPYx106
0.11
0.11
0.107
0.106
0.106
0.099
0.097
0.087
0.086
0.077
0.076
0.067
0.059
0.055
0.047
0.0452
0.0452
0.045
0.044
0.043
0.040
Percent
of Total
0.94
0.94
0.92
0.91
0.91
0.85
0.83
0.75
0.74
0.66
0.65
0.57
0.51
0.475
0.40
0.39
0.39
0.39
0.38
0.37
0.34
Cumulative
Percent
78.03
78. 97
78.89
80.80
81.71
82.56
83.39
84.14
84.88
85.54
86.19
86.76
87.27
87.75
88.15
88.54
88.93
89.32
89.70
90.07
90.41
99
-------
Table A-1. ESTIMATED 1972 NOX EMISSIONS FROM STATIONARY SOURCES -
RANKING OF NOX EMISSIONS BY EQUIPMENT TYPE AND FIRING TYPE (Continued)
45.
46.
47.
48.
49.
50.
51.
52.
53.
54.
55.
56.
57.
58.
59.
60.
61.
62.
63.
64.
65.
Sector/Equipment Type/Fuel
Industrial Boiler, Firetube Wall Fired Packaged HRT,
Residual Oil
Industrial Boiler, Firetube Wall Fired Packaged
Firebox, Gas
Utility Boiler, Stoker, Spreader, Coal
Industrial Boiler, Stoker, Overfeed, Field Erected
Watertube, Coal
Commercial Boiler, Firetube Wall Fired Packaged
Scotch, Gas
Commercial Boiler, Firetube Wall Fired Packaged
Firebox, Gas
Industrial Boiler, Tangential Firing Field Erected
Watertube Gas
Industrial Boiler, Tangential Firing Field Erected
Watertube, Coal
Residential Heating, Room Heater With Flue, Gas
Explosive Manufacture
Industrial Boiler, Cyclone Field Erected Watertube,
Coal
Residential Heating, Floor, Wall or Pipeless Heaters,
Gas
Iron and Steel Industry, Open Hearth Furnace
Iron and Steel Industry, Sintering
Residential Heating, Room Heater With Flue,
Distillate Oil
Incineration, Industrial
Commercial Boiler, Firetube, Wall Fired Cast Iron,
Residual Oil
Commercial Boiler, Firetube Wall Fired HRT,
Residual Oil
Industrial Boiler, Firetube Wall Fired Packaged HRT,
Gas
Utility Boiler, Cyclone, Residual Oil
Commercial Boiler, Firetube Wall Fired Packaged
Est.TPYx106
0.040
0.038
0.037
0.037
0.036
0.036
0.032
0.030
0.028
0.028
0.028
0.027
0.025
0.024
0.024
0.023
0.0226
0.0226
0.020
0.019
Percent
of Total
0.34
0.33
0.32
0.32
0.31
0.31
0.27
0.26
0.24
0.24
0.24
0.23
0.21
0.21
0.21
0.20
0.19
0.19
0.17
0.16
Cumulative
Percent
90.75
91.07
91.40
91.72
92.03
92.34
92.61
92.87
93.11
93.35
93.59
93.82
94.03
94.24
94.45
94.65
94.84
95.03
95.20
95.36
Scotch, Distillate Oil
0.0184
0.16
95.52
100
-------
Table A-1. ESTIMATED 1972 NOX EMISSIONS FROM STATIONARY SOURCES -
RANKING OF NOX EMISSIONS BY EQUIPMENT TYPE AND FIRING TYPE (Continued)
66.
67.
68.
69.
70.
71.
72.
73.
74.
75.
76.
77.
78.
79.
80.
81.
82.
83.
84.
85.
Sector/Equipment Type/Fuel
Commercial Boiler, Firetube Wall Fired Firebox,
Distillate Oil
Industrial Boiler, Stoker General, Field Erected
Watertube, Coal
Commercial Boiler, Firetube Wall Fired HRT, Gas
Incineration, Municipal
Commercial Boiler, Wall Fired Cast Iron, Gas
Commercial Boiler, Firetube, Stoker, Miscellaneous,
Firebox, Coal
Process Heating, Cement Kilns, Oil
Utility Boiler, Stoker Underfeed, Coal
Residential Heating, Floor, Wall or Pipeless Heater,
Distillate Oil
Industrial Boiler, Stoker, Overfeed, Packaged Water-
tube, Coal
Industrial Boiler, Firetube Wall Fired Packaged Scotch,
Distillate Oil
Industrial Boiler, Wall Fired Packaged Watertube,
Distillate OH
Utility Boiler, Tangential Firing, Lignite Coal
Industrial Boiler, Cyclone Field Erected Watertube,
Residual Oil
Sulfuric Acid Production
Utility Boiler, Horizontally Opposed Wall Firing,
Distillate Oil
Utility Boiler, Front Wall Firing, Distillate Oil
Residential Heating, Room Heater Without Flue, Gas
Residential Heating, Room Heater Without Flue,
Distillate Oil
Utility Boiler, Vertical Firing, Anthracite Coal
Est.TPYx106
0.0184
0.018
0.018
0.018
0.018
0.018
0.0165
0.016
0.016
0.016
0.0156
0.0156
0.014
0.014
0.011
0.011
0.011
0.011
0.010
0.010
Percent
of Total
0.16
0.15
0.15
0.15
0.15
0.15
0.14
0.14
0.14
0.14
0.13
0.13
0.12
0.12
0.094
0.094
0.094
0.094
0.086
0.086
Cumulative
Percent
95.68
95.83
95.98
96.13
96.28
96.43
96.57
96.71
96.85
96.99
97.12
97.25
97.37
97.49
97.58
97.67
97.76
97.86
97.95
98.03
86. Industrial Boiler, Firetube Stoker Underfeed Packaged
Firebox, Coal 0.010 0.086 98.12
87. Commercial Boiler, Firetube, Wall Fired HRT,
Distillate Oil 0.0092 0.079 98.20
101
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Table A-1. ESTIMATED 1972 NOX EMISSIONS FROM STATIONARY SOURCES -
RANKING OF NOX EMISSIONS BY EQUIPMENT TYPE AND FIRING TYPE (Continued)
Percent Cumulative
Sector/Equipment Type/Fuel Est. TPYxlO6 of Total Percent
88.
89.
90.
91.
92.
93.
94.
95.
96.
97.
98.
99.
100.
101.
102.
103.
104.
105.
106.
Commercial Boiler, Wall Fired Cast Iron,
Distillate Oil
Utility Boiler, Cyclone, Lignite Coal
Industrial Boiler, Horizontally Opposed Wall Firing,
Dry Bottom Field Erected Watertube, Coal
Industrial Boiler, Front Wall Fired Dry Bottom
Field Erected Watertube, Coal
Industrial Boiler, Opposed Wall Firing Field Erected
Watertube, Process Gas
Industrial Boiler, Wall Fired Packaged Watertube,
Coal
Commercial Boiler, Firetube, Stoker, Miscellaneous,
HRT,Coal
Utility Boiler, Horizontally Opposed Wall Firing,
Wet Bottom, Lignite Coal
Utility Boiler, Front Wall Fired, Wet Bottom,
Lignite Coal
Commercial Boilers, Firetube, Miscellaneous,
Residual Oil
Industrial Boiler, Stoker, Miscellaneous, Packaged
Watertube, Coal
Utility Boiler, Tangential Firing, Distillate Oil
Industrial Boiler, Bent Tube, Wall Fired Field Erected
Watertube, Distillate Oil
Industrial Boiler, Wall Fired Packaged Watertube,
Process Gas
Industrial Boiler, Front Wall Fired Field Erected
Watertube, Process Gas
Commercial Boiler, Firetube, Miscellaneous, Gas
Industrial Boiler, Firetube Wall Fired Packaged
Firebox, Distillate Oil
Process Heating, Coke Oven Underfire
Process Heating, Heating, Annealing Ovens
0.0092
0.009
0.009
0.009
0.009
0.009
0.009
0.008
0.008
0.0075
0.007
0.007
0.007
0.007
0.007
0.006
0.006
0.0059
0.0056
0.079
0.077
0.077
0.077
0.077
0.077
0.077
0.069
0.069
0.064
0.060
0.060
0.060
0.060
0.060
0.051
0.051
0.051
0.048
98.28
98.35
98.43
98.51
98.59
98.66
98.74
98.81
98.88
98.94
99.00
99.06
99.12
99.18
99.24
99.29
99.34
99.39
99.44
107. Industrial Boiler, Firetube, Stoker, Underfeed,
Packaged HRT, Coal 0.005 0.043 99.49
102
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Table A-1. ESTIMATED 1972 NOX EMISSIONS FROM STATIONARY SOURCES -
RANKING OF NOX EMISSIONS BY EQUIPMENT TYPE AND FIRING TYPE (Continued)
Percent Cumulative
Sector/Equipment Type/Fuel Est. TPYxlO6 of Total Percent
108.
109.
110.
111.
112.
113.
114.
115.
116.
117.
118.
119.
120.
121.
122.
123.
124.
125.
126.
127.
Industrial Boiler, Tangential Firing Field Erected
Watertube, Process Gas
Utility Boiler, Horizontally Opposed Wall Firing,
Dry Bottom, Lignite Coal
Utility Boiler, Front Wall Fired, Dry Bottom,
Lignite Coal
Commercial Boiler, Firetube, Miscellaneous,
Distillate Oil
Industrial Boiler, Front Wall Firing, Wet Bottom
Field Erected Watertube, Coal
Industrial Boiler, Horizontally Opposed Wall Firing,
Wet Bottom Field Erected Watertube, Coal
Industrial Boiler, Firetube Wall Fired Packaged HRT,
Distillate Oil
Commercial Boiler, Watertube Wall Fired Coil,
Residual Oil
Commercial Boiler, Watertube, Miscellaneous,
Residual Oil
Commercial Boiler, Watertube Wall Fired Coil, Gas
Commercial Boiler, Watertube, Miscellaneous, Gas
Industrial Boiler, Vertical Firing Field Erected Water-
tube, Coal
Industrial Boiler, Firetube Stoker, Overfeed Packaged
Firebox, Coal
Industrial Boiler, Firetube, Stoker, Spreader, Packaged
Firebox, Coal
Commercial Boiler, Firetube, Miscellaneous, Coal
Industrial Boiler, Bent Tube Wall Fired Field Erected
Watertube, Process Gas
Commercial Boiler, Watertube Wall Fired Firebox,
Residual Oil
Process Heating, Brick Curing Gas
Commercial Boiler, Watertube Wall Fired Coil,
Distillate Oil
Commercial Boiler, Watertube, Other, Distillate Oil
0.004
0.004
0.004
0.0031
0.003
0.003
0.003
0.003
0.003
0.0024
0.0024
0.002
0.002
0.002
0.002
0.002
0.002
0.0014
0.001
0.001
0.034
0.034
0.034
0.027
0.026
0.026
0.026
0.026
0.026
0.021
0.021
0.017
0.017
0.017
0.017
0.017
0.017
0.012
0.009
0.009
99.52
99.55
99.59
99.61
99.64
99.67
99.69
99.72
99.74
99.77
99.79
99.80
99.82
99.84
99.85
99.87
99.89
99.9
99.91
99.92
103
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Table A-1. ESTIMATED 1972 NOX EMISSIONS FROM STATIONARY SOURCES -
RANKING OF NOX EMISSIONS BY EQUIPMENT TYPE AND FIRING TYPE (Continued)
128.
129.
130.
131.
132.
133.
134.
135.
136.
137.
Sector/Equipment Type/Fuel
Commercial Boiler, Watertube Wall Fired Firebox,
Gas
Utility Boiler, Vertical Firing, Lignite Coal
Utility Boiler, Cyclone, Distillate Oil
Industrial Boiler, Firetube Stoker, Spreader,
Packaged HRT, Coal
Industrial Boiler, Firetube Stoker, Overfeed,
Packaged HRT, Coal
Industrial Boiler, Firetube Wall Fired Packaged
Firebox, Process Gas
Industrial Boiler, Firetube Wall Fired Packaged
Scotch, Process Gas
Commercial Boiler, Watertube, Wall Fired Firebox,
Distillate Oil
Process Heating, Brick Curing, Oil
Process Heating, Brick Curing, Coal
Total Controllable
Est.TPYx106
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.0006
0.0003
0.0003
11.6648
Percent
of Total
0.009
0.009
0.009
0.009
0.009
0.009
0.009
0.005
0.003
0.003
100
Cumulative
Percent
99.93
99.94
99.95
99.95
99.96
99.97
99.98
99.99
99.99
100
100
UNRANKED SOURCES - EMISSION NEGLIGIBLE OR NOT AVAILABLE
Utility Boiler, Tangentially Fired Wet Bottom, Coal Fired
Utility Boiler, Mixed Fuel Fired
Utility Boiler, Gas Fired Cyclone
Industrial Boiler, Mixed Fuel Fired
Industrial Boiler, Liquid Waste Fired
Industrial Boiler, Solid Waste Fired
Industrial Boiler, Sub-Bituminous or Lignite Fired
Boilers, Anthracite Coal Fired
Boilers, Synthetic Fuel From Coal, Low Btu Gas, SRC
Fluidized Bed Boilers
Stationary 1C Engines, Gasoline Fired
Combined Gas/Steam Turbine Cycles
MHD Power Generation
Residential Units, Coal Fired
Residential Units, Bottled Gas
All Wood Fired Equipment
Minor Industrial Process Equipment
104
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/2-75-046
2.
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
NOx Combustion Control Methods and Costs for
Stationary Sources--Summary Study
6. REPORT DATE
September 1975
6. PERFORMING ORGANIZATION CODE
7.AUTHOR(S)A B.shimizu, R.J.Schreiber, H.B. Mason,
G. G. Poe, and S. B. Youngblood
8. PERFORMING ORGANIZATION REPORT NO
75-153
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Aerotherm Division, Acurex Corporation
485 Clyde Avenue
Mountain View, CA 94040
10. PROGRAM ELEMENT NO.
1AB014: ROAP 21BCC
11. CONTRACT/GRANT NO.
68-02-1318, Task 12
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final; 8/74-4/75
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16.ABSTRACTTne repOrfsummarj[zes the technology, user experience, and cost for NOx
control from stationary combustion sources. It characterizes significant sources
by equipment type, fuel consumption, and annual mass emission of NOx. It summar-
izes NOx control technology by combustion modification, fuel modification, flue gas
treatment, and use of alternate processes. It identifies combustion modifications
as the most advanced and effective technique for near- and far-term NOx control. It
gives available capital and differential operating costs for NOx control in utility
boilers by combustion modification and flue gas treatment. Combustion control of
NOx is an order of magnitude lower in capital cost than NOx or SOx control by flue
gas treatment. Cost data for remaining equipment types is sparse and the need is
cited for open dissemination on a standardized basis of data on field tests of NOx
control techniques.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATl Field/Group
Air Pollution Heating Equipment
Nitrogen Oxides
Combustion Control Operating Costs
Boilers
Internal Combustion
Engines
Gas Turbines
Air Pollution Control
Stationary Sources
Control Costs
Emission Factors
NOx Reduction
Flue Gas Treatment
Residential Heaters
13B
07B
21B
ISA
21G
13G
14A,05A
8. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)'
Unclassified
21. NO. OF PAGES
117
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (t-73)
105
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